United States Office of Water 

Environmental Protection Washington, DC 20460 April 2013 

Agency 

 Incremental Costs and 

Pollutant Removals for the 

Proposed Effluent 

Limitations Guidelines and 

Standards for the Steam 

Electric Power Generating 

Point Source Category 
Appendix 

Table of Contents 

Page 

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

CHAPTER 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

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

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

3.1.1 Industry Factors ................................................................................................... 3-1

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

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

3.1.4 FGD Wastewater Loadings .................................................................................. 3-2

3.1.5 Combustion Residual Landfill Leachate Loadings .............................................. 3-2

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

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

3.4 EPA Detailed Study Ash Surface Impoundment Sampling Data ............................. 3-4

3.5 Industry- and State-Submitted Monitoring Data ...................................................... 3-5

3.6 Electric Power Research Institute (EPRI) PISCES Reports ..................................... 3-5

3.7 Permit Application Data ........................................................................................... 3-6

3.8 EPA 1982 Technical Development Document ......................................................... 3-6

3.9 Protection of Confidential Business Information ..................................................... 3-7

3.10 References ................................................................................................................. 3-9

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

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

4.1.1 FGD Wastewater .................................................................................................. 4-1

4.1.2 Fly Ash and Bottom Ash Transport Water .......................................................... 4-3

4.1.3 Leachate ............................................................................................................... 4-5

4.2 Wastestream Population and Characteristics for Costing ......................................... 4-7

4.2.1 FGD Wastewater .................................................................................................. 4-7

4.2.2 Fly Ash ................................................................................................................. 4-7

4.2.3 Bottom Ash ........................................................................................................ 4-10

4.2.4 Leachate ............................................................................................................. 4-11

4.3 Pollutant Concentrations ......................................................................................... 4-11

4.4 Plant Characteristics ............................................................................................... 4-12

4.4.1 Retirements and Conversions ............................................................................ 4-12

4.4.2 FGD Treatment-in-Place Input .......................................................................... 4-13

4.4.3 High Flow FGD Treatment Systems .................................................................. 4-13

4.5 Combustion Residual Disposal ............................................................................... 4-15
Table of Contents 

Table of Contents (Continued) 

Page 

iii 

4.5.1 Combustion Residual Landfills.......................................................................... 4-15

4.5.2 Combustion Residual Surface Impoundments ................................................... 4-15

CHAPTER 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 ................................................................................... 5-3

5.2.3 O&M Cost Methodology ..................................................................................... 5-3

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

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

5.2.3.3 Sample Shipping Cost ................................................................................ 5-6

5.2.3.4 Sample Analysis Cost ................................................................................. 5-6

5.3 Transportation Cost Methodology ............................................................................ 5-7

5.3.1 Technology Description ....................................................................................... 5-7

5.3.2 Cost Inputs ........................................................................................................... 5-8

5.3.3 Cost Methodology ................................................................................................ 5-8

5.3.3.1 On-Site Transportation Cost Methodology ................................................ 5-8

5.3.3.2 Off-Site Transportation Cost Methodology ............................................... 5-9

5.4 Disposal Cost Methodology ................................................................................... 5-10

5.4.1 Technology Description ..................................................................................... 5-10

5.4.2 Cost Inputs ......................................................................................................... 5-10

5.4.3 Cost Methodology .............................................................................................. 5-10

5.4.3.1 On-Site Disposal Cost Methodology ........................................................ 5-10

5.4.3.2 Off-Site Disposal Cost Methodology ....................................................... 5-12

5.5 Surface Impoundment Operation Costs Methodology ........................................... 5-12

5.5.1 Technology Description ..................................................................................... 5-13

5.5.2 Input Table ......................................................................................................... 5-13

5.5.3 Cost Methodology .............................................................................................. 5-14

5.5.3.1 Impoundment O&M Costs ....................................................................... 5-14

5.5.3.2 Impoundment Unitized O&M Costs ........................................................ 5-18

5.5.3.3 Earthmoving Unitized O&M Costs .......................................................... 5-19

5.5.3.4 Impoundment and Earthmoving Capacity Factors ................................... 5-21

5.5.3.5 Surface Impoundment Earthmoving Recurring Costs ............................. 5-21

5.6 Surface Impoundment BMP Costs Methodology ................................................... 5-21

5.6.1 Results and Summary of Costs .......................................................................... 5-22

5.7 References ............................................................................................................... 5-22

CHAPTER 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 .................... 6-6
Table of Contents 

Table of Contents (Continued) 

Page 

iv 

6.1.6 Capital Cost Methodology ................................................................................... 6-7

6.1.6.1 Purchased Equipment Costs: Pumps .......................................................... 6-9

6.1.6.2 Purchased Equipment Costs: Tanks ......................................................... 6-14

6.1.6.3 Purchased Equipment Costs: Chemical Feed Systems ............................ 6-33

6.1.6.4 Purchased Equipment Costs: Mixers ........................................................ 6-43

6.1.6.5 Purchased Equipment Costs: Solids Contact Clarifiers ........................... 6-51

6.1.6.6 Purchased Equipment Costs: Filter Presses ............................................. 6-54

6.1.6.7 Purchased Equipment Costs: Gravity Sand Filters .................................. 6-56

6.1.6.8 Purchased Equipment Installation Cost .................................................... 6-60

6.1.6.9 Building Cost ............................................................................................ 6-60

6.1.6.10 Land Cost ................................................................................................. 6-61

6.1.6.11 Site Preparation Cost ................................................................................ 6-61

6.1.6.12 Engineering Cost ...................................................................................... 6-62

6.1.6.13 Construction Expenses ............................................................................. 6-62

6.1.6.14 Other Contractors’ Fees ........................................................................... 6-63

6.1.6.15 Contingency Fees ..................................................................................... 6-63

6.1.7 O&M Cost Methodology ................................................................................... 6-64

6.1.7.1 Operating Labor Cost ............................................................................... 6-64

6.1.7.2 Maintenance Labor Cost .......................................................................... 6-64

6.1.7.3 Maintenance Materials Cost ..................................................................... 6-65

6.1.7.4 Chemical Purchase Cost ........................................................................... 6-66

6.1.7.5 Energy Cost .............................................................................................. 6-71

6.1.8 Sludge Disposal Cost ......................................................................................... 6-82

6.1.9 Mercury Analyzer Cost Methodology ............................................................... 6-83

6.1.9.1 Technology Description ........................................................................... 6-84

6.1.9.2 Population Costed .................................................................................... 6-84

6.1.9.3 Capital Cost Methodology ....................................................................... 6-84

6.1.9.4 O&M Cost Methodology ......................................................................... 6-86

6.1.9.5 Recurring Cost Methodology ................................................................... 6-87

6.1.10 Compliance Monitoring Cost ............................................................................. 6-87

6.1.11 Impoundment Operation Cost ............................................................................ 6-87

6.1.12 FGD System Outage Costs ................................................................................ 6-87

6.1.13 Results and Summary of Costs .......................................................................... 6-88

6.2 Biological Treatment .............................................................................................. 6-88

6.2.1 Technology Description ..................................................................................... 6-88

6.2.2 Population Costed .............................................................................................. 6-90

6.2.3 Credit for Biological Treatment in Place ........................................................... 6-90

6.2.4 Input Table ......................................................................................................... 6-91

6.2.5 Capital Cost Methodology ................................................................................. 6-91

6.2.5.1 Purchased Equipment Costs: Biological Treatment System Cost ............ 6-92

6.2.5.2 Purchased Equipment Costs: Heat Exchanger Cost ................................. 6-93

6.2.5.3 Purchased Equipment Costs: Backwash Recycle Pumps Cost ................ 6-96

6.2.5.4 Purchased Equipment Installation Cost .................................................... 6-96

6.2.5.5 Plant Overhead Engineering Cost ............................................................ 6-98
Table of Contents 

Table of Contents (Continued) 

Page 

v 

6.2.6 O&M Cost Methodology ................................................................................... 6-99

6.2.6.1 Operating Labor Cost ............................................................................... 6-99

6.2.6.2 Maintenance Labor Cost ........................................................................ 6-100

6.2.6.3 Maintenance Materials Cost ................................................................... 6-100

6.2.6.4 Chemical Purchase Cost ......................................................................... 6-100

6.2.6.5 Energy Cost ............................................................................................ 6-101

6.2.7 Sludge Disposal Cost ....................................................................................... 6-104

6.2.8 Mercury Analyzer Cost .................................................................................... 6-104

6.2.9 Compliance Monitoring Cost ........................................................................... 6-104

6.2.10 Surface Impoundment Operation Cost ............................................................. 6-104

6.2.11 FGD System Outage Costs .............................................................................. 6-104

6.2.12 Results and Summary of Costs ........................................................................ 6-105

6.3 Vapor-Compression Evaporation ......................................................................... 6-105

6.3.1 Technology Description ................................................................................... 6-105

6.3.2 Population Costed ............................................................................................ 6-106

6.3.3 Credit for Vapor-Compression Evaporation Treatment in Place ..................... 6-107

6.3.4 Input Table ....................................................................................................... 6-107

6.3.5 Capital Cost Methodology ............................................................................... 6-107

6.3.5.1 Purchased Equipment Costs: Brine Concentrator and Crystallizer Cost 6-108

6.3.5.2 Purchased Equipment Costs: Softening Equipment Cost ...................... 6-108

6.3.5.3 Purchased Equipment Installation Cost .................................................. 6-108

6.3.6 O&M Cost Methodology ................................................................................. 6-109

6.3.6.1 Operating Labor Cost ............................................................................. 6-109

6.3.6.2 Maintenance Labor Cost ........................................................................ 6-110

6.3.6.3 Maintenance Materials Cost ................................................................... 6-110

6.3.6.4 Chemical Purchase Cost ......................................................................... 6-110

6.3.6.5 Energy Cost ............................................................................................ 6-111

6.3.7 Sludge Disposal Cost ....................................................................................... 6-112

6.3.8 Mercury Analyzer Cost .................................................................................... 6-113

6.3.9 Compliance Monitoring Cost ........................................................................... 6-113

6.3.10 Surface Impoundment Operation Cost ............................................................. 6-113

6.3.11 FGD System Outage Costs .............................................................................. 6-113

6.3.12 Results and Summary of Costs ........................................................................ 6-114

6.4 References ............................................................................................................. 6-114

CHAPTER 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 .................................... 7-4

7.1.4 Input Table ........................................................................................................... 7-4

7.1.5 Capital Cost Methodology ................................................................................... 7-6

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

7.1.5.2 Purchased Equipment Cost: Silo ................................................................ 7-8
Table of Contents 

Table of Contents (Continued) 

Page 

vi 

7.1.5.3 Purchased Equipment Cost: Pugmill ........................................................ 7-11

7.1.5.4 Purchased Equipment Installation Cost .................................................... 7-12

7.1.5.5 Engineering Costs .................................................................................... 7-14

7.1.6 O&M Cost Methodology ................................................................................... 7-16

7.1.6.1 Conveyance O&M Costs: Operating Labor ............................................. 7-16

7.1.6.2 Conveyance O&M Costs: Maintenance Labor ........................................ 7-17

7.1.6.3 Conveyance O&M Costs: Energy Cost .................................................... 7-18

7.1.6.4 Conveyance O&M Costs: Maintenance Materials ................................... 7-20

7.1.6.5 Conveyance O&M Costs: Maintenance Outage ...................................... 7-21

7.1.6.6 Storage O&M Costs: Operating Labor ..................................................... 7-21

7.1.6.7 Storage O&M Costs: Maintenance Labor ................................................ 7-23

7.1.6.8 Storage O&M Costs: Energy Cost ........................................................... 7-23

7.1.6.9 Storage O&M Costs: Maintenance Materials .......................................... 7-25

7.1.7 Fly Ash Disposal Cost ....................................................................................... 7-26

7.1.8 Impoundment Operation Costs .......................................................................... 7-27

7.1.9 Recurring Costs .................................................................................................. 7-27

7.1.10 Fly Ash Outage Costs ........................................................................................ 7-30

7.1.11 Results and Summary of Costs .......................................................................... 7-30

7.2 Vactor Truck Collection ......................................................................................... 7-30

7.2.1 Technology Description ..................................................................................... 7-30

7.2.2 Population Costed .............................................................................................. 7-30

7.2.3 Input Table ......................................................................................................... 7-31

7.2.4 Capital Cost Methodology ................................................................................. 7-31

7.2.4.1 Total Capital Cost: Vactor Conveyance Equipment ................................ 7-31

7.2.4.2 Total Capital Cost: Vactor Engineering Costs ......................................... 7-31

7.2.5 O&M Cost Methodology ................................................................................... 7-32

7.2.5.1 Total O&M Costs: Vactor Conveyance O&M Cost ................................ 7-33

7.2.5.2 Total O&M Costs: Vactor Storage O&M Cost ........................................ 7-33

7.2.6 Fly Ash Disposal Cost ....................................................................................... 7-34

7.2.7 Impoundment Operation Costs .......................................................................... 7-34

7.2.8 Fly Ash Outage Costs ........................................................................................ 7-35

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

7.3 References ............................................................................................................... 7-35

CHAPTER 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 ...................... 8-4

8.1.4.2 MDS Engineering Cost .............................................................................. 8-5

8.1.5 O&M Cost Methodology ..................................................................................... 8-6

8.1.5.1 MDS Conveyance O&M Costs: Operating Labor ..................................... 8-6

8.1.5.2 MDS Conveyance O&M Costs: Maintenance Labor ................................. 8-7
Table of Contents 

Table of Contents (Continued) 

Page 

vii 

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

8.1.5.4 MDS Conveyance O&M Costs: Maintenance Materials ......................... 8-10

8.1.5.5 MDS Storage O&M Cost: Operating Labor ............................................ 8-11

8.1.5.6 MDS Storage O&M Costs: Maintenance Labor ...................................... 8-11

8.1.5.7 MDS Storage O&M Costs: Energy Cost .................................................. 8-12

8.1.5.8 MDS Storage O&M Costs: Maintenance Materials ................................. 8-13

8.1.5.9 Wet Sluicing O&M Costs: Operating Labor ............................................ 8-14

8.1.5.10 Wet Sluicing O&M Costs: Maintenance Labor ....................................... 8-15

8.1.5.11 Wet Sluicing O&M Costs: Energy Cost .................................................. 8-16

8.1.5.12 Wet Sluicing O&M Costs: Maintenance Materials .................................. 8-18

8.1.6 MDS Results ...................................................................................................... 8-18

8.2 Remote Mechanical Drag System .......................................................................... 8-18

8.2.1 Technology Description ..................................................................................... 8-18

8.2.2 Population Costed .............................................................................................. 8-19

8.2.3 Input Table ......................................................................................................... 8-20

8.2.4 Capital Cost Methodology ................................................................................. 8-20

8.2.4.1 Remote MDS Purchased Equipment Cost: Conveyance Equipment ....... 8-20

8.2.4.2 Remote MDS Purchase Equipment Cost: Recycle Pump ........................ 8-21

8.2.4.3 Remote MDS Purchased Equipment Cost: Chemical Feed System ........ 8-22

8.2.4.4 Remote MDS Purchase Equipment Installation Cost .............................. 8-24

8.2.4.5 Remote MDS Engineering Cost ............................................................... 8-24

8.2.5 O&M Cost Methodology ................................................................................... 8-25

8.2.5.1 Remote MDS Conveyance O&M Costs: Mechanical Drag System ........ 8-25

8.2.5.2 Remote MDS Conveyance O&M Costs: Chemical Purchase Cost ......... 8-25

8.2.5.3 Remote MDS Conveyance O&M Costs: Energy Cost ............................. 8-26

8.2.5.4 Remote MDS Storage O&M Costs .......................................................... 8-28

8.2.6 Remote MDS Results ......................................................................................... 8-29

8.3 Bottom Ash Disposal Cost ...................................................................................... 8-29

8.4 Impoundment Operation Costs ............................................................................... 8-30

8.5 One-Time Costs ...................................................................................................... 8-30

8.6 Bottom Ash Outage Costs ...................................................................................... 8-31

8.7 Recurring Costs ...................................................................................................... 8-31

8.8 Selection of Dry Bottom Ash Handling Technology ............................................. 8-32

8.9 Results and Summary of Costs ............................................................................... 8-32

8.10 References ............................................................................................................... 8-33

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

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

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

9.3 Treatment in Place .................................................................................................... 9-3

9.4 Input Table ................................................................................................................ 9-3

9.5 Capital Cost Methodology ........................................................................................ 9-4

9.5.1 Purchased Equipment Costs: Leachate Transport Pump ..................................... 9-4

9.5.2 Purchased Equipment Costs: Leachate Transport Piping .................................... 9-5

9.6 O&M Cost Methodology .......................................................................................... 9-6
Table of Contents 

Table of Contents (Continued) 

Page 

viii 

9.7 Mercury Analyzer Cost ............................................................................................. 9-7

9.8 Sludge Transportation and Disposal Costs ............................................................... 9-7

9.9 Compliance Monitoring Cost ................................................................................... 9-7

9.10 Surface Impoundment Operation Costs .................................................................... 9-7

9.11 Results and Summary of Costs ................................................................................. 9-7

9.12 References ................................................................................................................. 9-8

CHAPTER 10 POLLUTANT LOADINGS AND REMOVALS METHODOLOGY ...................................... 10-1

10.1 General Methodology for Estimating Pollutant Removals ..................................... 10-2

10.2 Wastestream Characterization and Data Sources ................................................... 10-3

10.2.1 FGD Wastewater Characterization .................................................................... 10-4

10.2.1.1 Baseline FGD Wastewater Characterization ............................................ 10-5

10.2.1.2 Baseline and Post-Compliance One-Stage Chemical Precipitation 

Characterization ..................................................................................... 10-10

10.2.1.3 Baseline and Post-Compliance One-Stage Chemical Precipitation and 

Biological Treatment Characterization .................................................. 10-11

10.2.1.4 Baseline and Post-Compliance One-Stage Chemical Precipitation and 

Vapor-Compression Evaporation Characterization ............................... 10-12

10.2.2 Ash Impoundment Wastewater Characterization ............................................ 10-13

10.2.3 Combustion Residual Leachate Wastewater Characterization ........................ 10-15

10.3 Wastewater Flow Rates for Pollutant Loadings ................................................... 10-16

10.3.1 FGD Wastewater Flow Rates for Pollutant Loadings ...................................... 10-16

10.3.2 Ash Transport Water Flow Rates for Pollutant Loadings ................................ 10-16

10.3.3 Combustion Residual Landfill Leachate Flow Rates for Pollutant Loadings.. 10-17

10.4 Baseline and Post-Compliance Pollutant Loadings and TWPE Results .............. 10-17

10.4.1 FGD Wastewater Loadings and TWPE ........................................................... 10-18

10.4.2 Ash Transport Water Loadings and TWPE ..................................................... 10-19

10.4.3 Combustion Residual Landfill Leachate Loadings and TWPE ....................... 10-22

10.5 References ............................................................................................................. 10-22

CHAPTER 11 SUMMARY OF COSTS AND POLLUTANT REMOVALS BY REGULATORY OPTION ....... 11-1

CHAPTER 12 EVALUATION OF COST AND POLLUTANT REMOVAL ESTIMATES ............................ 12-1

12.1 Verifying Cost Data against acceptance Specifications ......................................... 12-1

12.2 Verifying Analytical Data against acceptance Specifications ................................ 12-2

12.3 Developing and Checking the Cost and Loadings Models ..................................... 12-3

12.4 Evaluating Cost Estimate Quality ........................................................................... 12-4

12.5 References ............................................................................................................... 12-5

APPENDIX .................................................................................................................................... A-1 
Appendix 

List of Tables 

Page 

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

Options ............................................................................................................................. 1-2

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

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

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

5-1. Compliance Monitoring Labor Requirements .................................................................... 5-24

5-2. Compliance Monitoring Sampling Materials ..................................................................... 5-24

5-3. Compliance Monitoring Sample Analysis .......................................................................... 5-25

5-4. Capital Costs of 7-Acre Landfill Expansion from CH2MHILL ......................................... 5-25

5-5. O&M Costs of 7-Acre Landfill Expansion from CH2MHILL ........................................... 5-25

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

of Nonhardening Ash without Water Reuse .................................................................. 5-26

5-7. Calculated Unitized Cost Values for Impoundment Operating Costs ................................ 5-26

5-8. Cost Factors Relative to 500 MW Plant ............................................................................. 5-27

6-1. Expected FGD Wastewater Characteristics for Design of the Biological Treatment 

Stage ............................................................................................................................. 6-122

10-1. POTW Removals ............................................................................................................ 10-25

10-2. Data Sets Used in the Loadings Calculations ................................................................. 10-26

10-3. Average Effluent Concentration of FGD Surface Impoundments ................................. 10-27

10-4. Characteristics of FGD Blowdown at EPRI Sites P, R, and S ....................................... 10-28

10-5. Characteristics of FGD Blowdown at EPRI Sites T, U, and Y ...................................... 10-30

10-6. Average Effluent Concentration of One-Stage Chemical Precipitation System ............ 10-32

10-7. Average Effluent Concentration of One-Stage Chemical Precipitation System With 

Biological Treatment ................................................................................................... 10-33

10-8. Average Effluent Concentration of One-Stage Chemical Precipitation System With 

Vapor-Compression Evaporation ................................................................................. 10-34

10-9. Average Effluent Concentration of Ash Surface Impoundment Systems ...................... 10-35

10-10. Average Untreated Landfill Leachate Concentrations ................................................. 10-36

10-11. Industry-Level FGD Wastewater Loadings for All Units ............................................ 10-37

10-12. Industry-Level FGD Wastewater Loadings Based on Oil-Fired Units and Units 50 

MW or Less Not Installing Technology Basis ............................................................. 10-37

10-13. FGD Wastewater Pollutant Removals for All Units .................................................... 10-38
List of Tables 

List of Tables (Continued)

Page 

x 

10-14. FGD Wastewater Pollutant Removals Based on Oil-Fired Units and Units 50 MW 

or Less Not Installing Technology Basis ..................................................................... 10-38

10-15. Percent Loadings for Fly Ash and Bottom Ash in Combined Ash Surface 

Impoundments .............................................................................................................. 10-39

10-16. Industry-Level Baseline Ash Impoundment Loadings by Type of Impoundment ....... 10-39

10-17. Fly Ash and Bottom Ash Pollutant Removals for All Units ........................................ 10-40

10-18. Fly Ash and Bottom Ash Pollutant Removals Based on Oil-Fired Units and Units 

50 MW or Less Not Installing Technology Basis ........................................................ 10-40

10-19. Industry-Level Combustion Residual Landfill Leachate Loadings for All Units ........ 10-40

10-20. Industry-Level Combustion Residual Landfill Leachate Loadings Based on OilFired Units and Units 50 MW or Less Not Installing Technology Basis .................... 10-40

10-21. Combustion Residual Leachate Loadings Removals for All Units .............................. 10-41

10-22. Combustion Residual Leachate Loadings Removals Based on Oil-Fired Units and 

Units 50 MW or Less Not Installing Technology Basis .............................................. 10-41

11-1. Treatment Technologies Basis by Regulatory Option ...................................................... 11-2

11-2. Cost of Implementation by Regulatory Option for All Units ........................................... 11-3

11-3. Cost of Implementation by Regulatory Option Based on Oil-Fired Units and Units 

50MW or Less Not Installing Technology Basis ........................................................... 11-3

11-4. Estimated Pollutant Removals by Regulatory Option for All Units ................................ 11-3

11-5. Estimated Pollutant Removals by Regulatory Option Based on Oil-Fired Units and 

Units 50 MW or Less Not Installing Technology Basis ................................................ 11-4

12-1. Pollution Control Technology Cost Data Acceptance Criteria ........................................ 12-7

12-2. Monitoring Data Acceptance Criteria............................................................................... 12-7

12-3. Evaluation of Monitoring Data for Use in Loadings Analysis ......................................... 12-8

12-4. Cost Estimate Quality Specifications ............................................................................... 12-9
List of Figures 

xi 

List of Figures 

Page

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

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

2-2. Steam Electric Cost Model Flow Chart for Fly Ash and Bottom Ash Transport Water ...... 2-6

6-1. One-Stage Chemical Precipitation Treatment .................................................................. 6-115

6-2. Solubilities of Metal Hydroxides and Sulfides as a Function of pH ................................ 6-116

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

Pretreatment) ................................................................................................................ 6-117

6-4. Mean Maximum Daily Temperature for July ................................................................... 6-118

6-5. Location of Plants Incurring Heat Exchanger Costs ........................................................ 6-119

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

Vapor-Compression Evaporation ................................................................................. 6-120

6-7. Process Flow Diagram for a Vapor-Compression Evaporation System (System to 

Follow Chemical Precipitation Pretreatment) .............................................................. 6-121

8-1. Mechanical Drag System ...................................................................................................... 8-2

8-2. Remote Mechanical Drag System ...................................................................................... 8-19
Chapter 1 – Introduction 

1-1 

CHAPTER 1 

INTRODUCTION 

The Clean Water Act (CWA) establishes a structure for regulating discharges of 

pollutants to surface waters of the United States. As part of the implementation of the CWA, 

EPA issues effluent limitations guidelines and standards (ELGs) for industrial dischargers. EPA 

first issued ELGs for the Steam Electric Power Generating Point Source Category in 1974 with 

subsequent revisions in 1977 and 1982. EPA completed a detailed study of the industry in 2009 

and determined that the current regulations have not kept pace with the significant changes that 

have occurred in this industry over the last three decades; therefore, EPA is revising the existing 

ELGs. 

This report describes the methodologies used to estimate engineering compliance costs 

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

that make up the regulatory options considered by EPA. 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, EPA has assembled a supplementary document titled 

Supplemental Costs and Loadings Documentation (DCN SE01825). 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 in telephone contact 

reports); 

 Equipment specifications provided by vendors; and 

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

curves. 

Table 1-1 lists the regulatory options EPA considered for the steam electric industry to 

control pollutant discharges from the following wastestreams generated by power plants: 

 Wastewater generated from wet flue gas desulfurization (FGD) systems; 

 Fly ash transport water from wet fly ash handling systems; 

 Bottom ash transport water from wet bottom ash handling systems ;

 Leachate from landfills and surface impoundments containing combustion residuals; 1 

 Flue gas mercury control wastewater generated from activated carbon injection 

mercury control systems; 

 Gasification wastewater generated from integrated-gasification combined cycle 

(IGCC) power plants; and 

 

1

 EPA did not calculate compliance costs to treat leachate generated from impoundments containing combustion residuals 

because EPA believes that plants will comply with the leachate limit by recycling the leachate back to the impoundment from 

which it was generated. 
Chapter 1 – Introduction 

1-2 

 Nonchemical metal cleaning wastes generatd from cleaning metal process equipment 

without chemical cleaning compounds. 

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

Options 

Wastestream Technology Option 

Regulatory Option Report 

Chaptera 

1 3a 2 3b 3 4a 4 5 

FGD Wastewater 

Chemical Precipitation X X X X X X X 

6,10 Biological Treatment X X X X X 

Vapor-Compression 

Evaporation X 

Fly Ash Transport 

Water Dry Fly Ash Handling X X X X X 7,10 

Bottom Ash 

Transport Water 

Dry Bottom Ash 

Handling/Closed Loop X X X 8,10 

Leachate Chemical Precipitation X X 9,10 

Gasification 

Wastewater 

Vapor-Compression 

Evaporation X X X X X X X NA 

Flue Gas Mercury 

Control Wastes Dry Handling X X X X X NA 

Nonchemical Metal 

Cleaning Wastesb Chemical Precipitation NA 

Other Plant-Level Costs 

 Solids Transportation X X X X X X X X 5 

 Solids Disposal X X X X X X X X 5 

 Impoundments X X X X X X X X 5 

 Compliance Monitoring X X X X X X X X 5 

NA – Not applicable. EPA did not estimate compliance costs for these wastestreams for reasons described in Section 

9.2 of the Technical Development Document for the Proposed Effluent Limitations Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category (DCN SE01964). 

a

 Chapters 5-9 of this document include more detailed descriptions of the cost methodologies for these technology 

options and Chapter 10 provides a more detailed description of the estimated pollutant removals for each 

technology. 

For five of the regulatory options (Options 1, 2, 3, 4, and 5), EPA estimated plant-specific 

compliance costs for each of the individual treatment technologies that comprise the regulatory 

options using the methodology described in this report. These technology-specific costs, broken 

down into capital and operating 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, the baseline year for this 

rulemaking. Note that the compliance costs calculated for this rulemaking are incremental, 

meaning they represent the costs expected to be incurred as a result of plants revising existing 

operations to match those that form the bases of the proposed regulatory options. 

For the same five options, EPA also estimated plant-specific baseline and postcompliance pollutant loadings associated with each of the individual treatment technologies that 
Chapter 1 – Introduction 

1-3 

comprise the regulatory options, and then summed them as appropriate to calculate industrylevel baseline and post-compliance pollutant loadings for each of the five regulatory options. 

EPA then estimated the pollutant removals associated with the five 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 proposed regulatory options. 

EPA then used the cost and pollutant removal model outputs for Options 1, 2, 3, 4, and 5 

to estimate the costs and pollutant removals for Options 3a, 3b, and 4a. The methodologies EPA 

used to generate the costs and pollutant removals for Options 3a and 3b are described in the 

memorandum entitled, “Memorandum to the Rulemaking Record: Methodologies for Estiamting 

Costs and Pollutant Removals for Steam Electric ELG Regulatory Options 3a and 3b” (DCN 

SE03881). The methodologies EPA used to generate the costs and pollutant removals for Option 

4a are described in the memorandum entitled, “Memorandum to the Rulemaking Record: 

Methodologies for Estimating Costs and Pollutant Removals for Steam Electric ELG Regulatory 

Option 4a” (DCN SE03834). The remainder of this report describes the costs and pollutant 

removals as they relate to the individual wastestreams or Options 1, 2, 3, 4, and 5. 

The following information is described in this report: 

 Chapter 2 describes the structure of the costs and loadings models; 

 Chapter 3 discusses the data sources used to generate the costs, loadings, and 

pollutant removal estimates; 

 Chapter 4 discusses the costs and loadings models inputs; 

 Chapter 5 describes the general cost methodology used to estimate compliance costs 

and common cost elements; 

 Chapter 6 describes the cost methodology for treating FGD wastewater; 

 Chapter 7 describes the cost methodology for eliminating the discharge of fly ash 

transport water; 

 Chapter 8 describes the cost methodology for eliminating the discharge of bottom ash 

transport water; 

 Chapter 9 describes the cost methodology for treating combustion residual leachate; 

 Chapter 10 describes the methodologies used to estimate pollutant loadings and 

removals; 

 Chapter 11 summarizes costs and pollutant loadings and removals by regulatory 

option; and 

 Chapter 12 describes EPA’s evaluation of the cost and pollutant removal estimates. 
Chapter 2 – Structure of Costs and Pollutant Loadings Models 

2-1 

CHAPTER 2 

STRUCTURE OF COSTS AND POLLUTANT LOADINGS 

MODELS 

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

Steam Electric effluent limitations guidelines and standards (ELGs). The first model calculates 

plant-specific engineering 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 chapter describes the structure 

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

of the chapter. 

2.1 COST MODEL

To generate industry incremental compliance cost estimates for the steam electric 

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, located at the end of this chapter, present flow diagram of the cost model. 

The cost model can be grouped into four main components: 

 Plant-Specific Input Data; 

 Industry Assumptions/Factors; 

 Technology Cost Modules; and 

 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 five regulatory options 

considered by EPA. Both tables are presented at the end of the chapter. 

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 

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

ash or leachate compliance costs. 
Chapter 2 – Structure of Costs and Pollutant Loadings Models 

2-2 

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

 FGD data – plant-level indication that a wet FGD system is present and the plantlevel FGD wastewater flow rate; 

 Fly ash data – amount of wet fly ash generated, amount of transport water generated, 

number of operating days, 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, 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 leachate is collected and/or treated; 

 Surface impoundment data – plant-level indication that a combustion residual 

impoundment is present and whether leachate is collected and/or treated; and 

 Treatment-in-place data – plant-specific data for plants already operating relevant 

treatment systems, such as chemical precipitation, biological treatment, and vaporcompression evaporation, including the type of equipment at the plant and its 

capacity. 

Chapter 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 plant 

specific. 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 operating 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; and 

 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 

Chapter 5. 

2.1.3 Technology Cost Modules

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

listed below: 

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

anoxic/anaerobic biological treatment system; 
Chapter 2 – Structure of Costs and Pollutant Loadings Models 

2-3 

 One-Stage Chemical Precipitation – calculates capital and O&M costs associated with 

the one-stage chemical precipitation system used as the basis for the technology 

option; 

 Vapor-Compression Evaporation – calculates capital and O&M costs associated with 

the vapor-compression evaporation system used as the basis for the technology 

option; 

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

the dry fly ash handling system used as the basis for the technology option; 

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

associated with a dry or closed-loop recycle bottom ash handling systems used as the 

basis for the technology option; 

 Transportation – calculates O&M costs associated with transporting FGD solid waste, 

ash, and/or landfill leachate solid waste to an on- or off-site landfill; 

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

and/or landfill leachate solid waste in an on- or off-site landfill; 

 Impoundment Operation – calculates O&M and recurring costs associated with 

operating and maintaining an on-site impoundment; and 

 Impoundment BMP Costs – calculates the annualized costs associated with BMP for 

combustion residual impoundments. 

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

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

appendix (see Chapters 6, 7, 8 and 9 for more details) and by regulatory option in Chapter 11. 

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 

loadings associated with the discharge of FGD wastewater, fly and bottom ash transport water, 
Chapter 2 – Structure of Costs and Pollutant Loadings Models 

2-4 

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

following components: 

 Input table; 

 Baseline concentration data sets; 

 Technology option concentration data sets (where applicable); and 

 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, and 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 

sampling data used to calculate the average pollutant concentrations for each wastewater 

evaluated with and without the control afforded by the proposed 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 is zero. The average baseline 

and technology option 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 post-compliance pollutant loadings in both pounds and toxic-weighted pound 

equivalents (TWPE).2

 See Chapter 10 for more detail on the loadings calculation methodology 

and results for each technology option. 

 

2

 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. 
Chapter 2 – Structure of Costs and P

2-5 

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

2-7 

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

Technology Option 

Technology Cost Module 

One-Stage 

Chemical 

Precipitation 

Biological 

Treatment 

VaporCompression 

Evaporation 

Dry Fly Ash 

Handling 

Dry Bottom Ash 

Handling

a

Compliance 

Monitoring 

Ttti

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   Leachate Wastewater Treatment: Chemical Precipitation    Leachate Wastewater Treatment: Chemical Precipitation + Biological Treatment     

Note: EPA did not estimate costs for gasification wastewater, flue gas mercury control wastewater, or nonchemical metal cleaning wasta The technology cost module is called “Dry Bottom Ash Handling” module, but it includes a technology option that is a closed-loop re
Chapter 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 

Reg

1 2 

FGD Wastewater 

Chemical Precipitation   

Biological Treatment  Vapor-Compression Evaporation 

Fly Ash Transport Water Dry Fly Ash Handling Bottom Ash Transport Water Dry Bottom Ash Handlinga Leachate Chemical Precipitation Gasification Wastewaterb Vapor-Compression Evaporation   Flue Gas Mercury Control Wastesb Zero Discharge Nonchemical Metal Cleaning Wasteb Chemical Precipitation   

Other Costs Not Specific to Wastestream 

 Solids Transportation    Solids Disposal    Impoundments    Compliance Monitoring   

Note: EPA did not estimate costs for gasification wastewater, flue gas mercury control wastewater, or nonchemical metal cleaning wasta The technology cost module is called the “Dry Bottom Ash Handling” module, but it includes a technology option that is a closed-loop b EPA did not estimate costs for gasification wastewater, flue gas mercury control wastewater, or nonchemical metal cleaning wastes; t

create technology cost modules for theses wastestreams. However, these wastestreams are still considered in the regulatory options and in the table with the appropriate technology option.
Chapter 3 – Data Sources 

3-1 

CHAPTER 3 

DATA SOURCES 

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

the proposed Steam Electric effluent limitations guidelines and standards (ELGs). EPA used 

these data to develop the industry profile, identify plant-specific operations, determine baseline 

and post-compliance wastewater characteristics, estimate compliance costs, estimate baseline 

and post-compliance pollutant loadings, and estimate pollutant removals associated with the 

regulatory options. This chapter discusses the data sources used to estimate the compliance costs 

and pollutant loadings and removals estimates for the proposed Steam Electric ELGs. All tables 

and figures referenced in this chapter are presented at the end of the chapter. 

3.1 STEAM ELECTRIC TECHNICAL QUESTIONNAIRE DATABASE

The principal source of information and data used in developing the ELGs is the industry 

response to the survey distributed by EPA under the authority of section 308 of the Clean Water 

Act (CWA). EPA distributed the Questionnaire for the Steam Electric Power Generating 

Effluent Guidelines (Steam Electric Survey) to 733 power plants in the summer of 2010. The 

Steam Electric Survey obtained the following types of information from the steam electric 

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; and 

 Nuclear power operations. 

ERG used the responses from the 733 plants to develop a database that contained all the 

responses to the survey. For more information on the development of the Steam Electric Survey, 

see Section 3 of the Technical Development Document for the Proposed Effluent Limitations 

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

(DCN SE01964). The remainder of this section describes the data used in the calculation of 

compliance costs and pollutant loadings estimates. 

3.1.1 Industry Factors

EPA developed specific industry factors to use in the cost equations detailed in Chapters 

5, 6, 7, 8, and 9 based on evaluation and analysis of the Steam Electric Survey data. For example, 

many of the operating 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 survey. EPA also 

developed many of the direct and indirect capital cost factors used in the cost model from survey 
Chapter 3 – Data Sources 

3-2 

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 survey responses. The use of 

survey data to derive industry assumptions/factors is described within the costing methodology 

in Chapters 5, 6, 7, 8, and 9 and documented in the Supplemental Costs and Loadings 

Documentation (DCN SE01825). 

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, type of generating unit, generating unit operating hours per day, and 

technologies currently in place. The specific plant characteristic used to calculate compliance 

costs for each treatment technology are detailed in the input table sections of Chapters 6, 7, 8, 

and 9. 

3.1.3 Ash Transport Water Loadings

EPA used responses to the Steam Electric Survey to identify the population of plants that 

operate wet fly and/or bottom ash handling systems and discharge the wastewater to surface 

water or a publicly-owned treatment works (POTW). For this population of plants, EPA used 

survey responses to identify the flow rate of the fly ash and bottom ash transport water, 

determine whether the waters are combined for treatment, and calculate the amount of treated 

ash transport water that is recycled by the plant. EPA also used Steam Electric Survey data to 

estimate fly ash and bottom ash transport water pollutant loadings as described further in 

Sections 4.1.2 and 10.3.2. 

3.1.4 FGD Wastewater Loadings

EPA used responses to the Steam Electric Survey to identify the population of plants that 

operate wet FGD scrubbers and discharge the wastewater to surface water or a POTW. For this 

population of plants, EPA used 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 10.3.1. 

3.1.5 Combustion Residual Landfill Leachate Loadings

EPA used responses to the Steam Electric Survey to identify the population of plants that 

collect and discharge leachate from landfills containing combustion residuals to surface water or 

a POTW. For this population of plants, EPA used survey responses to identify the flow rate of 

the landfill leachate and calculate the amount of landfill leachate that is recycled by the plant. 

EPA also used Steam Electric Survey data to characterize the landfill leachate wastestream as 

well as to estimate the leachate pollutant loadings as described further in Sections 4.1.3 and 

10.3.3. 
Chapter 3 – Data Sources 

3-3 

3.2 TECHNOLOGY VENDOR DATA

EPA obtained data regarding the technologies used in the industry from technology 

vendors through presentations, conferences, meetings, and email and phone contacts. The data 

collected informed the development of the 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 vapor-compression evaporation 

wastewater treatment systems. 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; and 

 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 and/or 

eliminating ash transport water; 

 Equipment and demolition required to convert wet sluicing fly ash and bottom ash 

handling systems to an alternate ash handling system, including equipment that can 

be reused as part of the conversion from a wet to a dry/closed-loop recycle handling 

system; 3

 Outage time required to install or convert to the different types of ash handling 

systems; 

 O&M costs; 

 Equipment and installation capital costs; 

 Dry ash storage specifications; and 

 System energy requirements. 

3.3 FIELD SAMPLING PROGRAM

EPA conducted an international sampling program at steam electric power plants to 

collect wastewater data characterization and treatment performance data associated with FGD 

 

3

 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 bach and therefore, are not 

completely dry systems. 
Chapter 3 – Data Sources 

3-4 

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 the Agency (i.e., CWA 308 monitoring program). 

EPA conducted sampling activities at the following selected plants: 

 Duke Energy Carolina’s Belews Creek Steam Station; 

 We Energies’ Pleasant Prairie Power Plant; 

 Duke Energy’s Miami Fort Station; 

 Duke Energy Carolina’s Allen Steam Station; 

 Mirant Mid-Atlantic, LLC’s Dickerson Generating Station; 

 RRI Energy’s Keystone Generating Station; and 

 Allegheny Energy’s Hatfield’s Ferry Power Station. 

All of the selected plants operate chemical precipitation wastewater treatment systems to 

treat their FGD wastewater. Belews Creek, Allen, and Dickerson also operate biological 

treatment systems to further treat the effluent from chemical precipitation treatment. EPA also 

conducted a sampling episode at Enel’s Federico II Power Plant (Brindisi), located in Brindisi, 

Italy. The Brindisi plant operates a chemical precipitation treatment system followed by a vaporcompression evaporation system. EPA also required an additional four plants to participate in the 

CWA 308 monitoring program and collect four consecutive days of samples to characterize 

specific wastestreams for which EPA did not have existing data. The following plants were 

selected: 

 Tampa Electric Company’s Polk Station (integrated gasification combined cycle 

(IGCC) generating unit); 

 Wabash Valley Power Association’s Wabash River Station (IGCC generating unit); 

 Appalachian Power Company’s Mountaineer Plant (carbon capture system); and 

 Kansas City Power and Light’s Iatan Station (vapor-compression system). 

For more information on the field sampling program, see Section 3 of the Technical 

Development Document for the Proposed Effluent Limitations Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category (DCN SE01964). 

3.4 EPA DETAILED STUDY ASH SURFACE IMPOUNDMENT 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 
Chapter 3 – Data Sources 

3-5 

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 of concern 

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 combined surface impoundment (receiving both fly ash and bottom ash wastewater). 

3.5 INDUSTRY- AND STATE-SUBMITTED MONITORING DATA

In addition to monitoring data submitted in the Steam Electric Survey and data collected 

during the EPA sampling program, EPA requested long-term self-monitoring data from Duke 

Energy’s Belews Creek Steam Station and Allen Steam Station to support the evaluation of BAT 

FGD wastewater treatment systems [Duke Energy, 2011a and 2011b]. The data included effluent 

concentrations for mercury, selenium, and several other metals achieved by the chemical 

precipitation and the biological treatment portions of the FGD wastewater treatment systems 

over a 3-year period. 

Additionally, EPA coordinated with the state of North Carolina to obtain long-term 

characterization data from Progress Energy Carolinas’ Roxboro Steam Electric Plant for the 

FGD wastewater treatment influent, FGD impoundment effluent, and biological treatment 

effluent, as well as ash impoundment effluent data. 

3.6 ELECTRIC POWER RESEARCH INSTITUTE (EPRI) PISCES REPORTS

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. 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. 

For each of the seven sites sampled, EPA reviewed the reports to determine the 

characteristics of the ash impoundments (e.g., type of wastestreams entering the impoundment 

and pollutant concentrations present). 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 & combined ash impoundment; and 

 Site G – Combined ash impoundment. 
Chapter 3 – Data Sources 

3-6 

Based on its review of the reports, EPA used the average pollutant concentrations, as 

reported, representing the overflow from the ash impoundments for all seven plants. EPA 

included the average pollutant concentration for each pollutant for each of the eight 

impoundments in the data set used to calculate ash transport water loadings. Chapter 10 provides 

more detail on the calculation of ash transport water loadings. 

3.7 PERMIT APPLICATION DATA

During the detailed study, EPA coordinated efforts with the Utility Water Act Group 

(UWAG), an industry trade association, to create a database of selected National Pollutant 

Discharge Elimination System (NPDES) Form 2C data from UWAG’s member companies. 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 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. 

EPA matched pollutant data from the NPDES Form 2C database to data in responses to 

Parts A and D of the Steam Electric Survey by NPDES permit number and outfall number to 

determine which outfalls contained fly, bottom, or combined ash transport water. For those 

NPDES permit IDs in the Form 2C database that did not match information from the survey 

responses, EPA conducted a manual search to generate a crosswalk between the Form 2C 

NPDES permit number and the reported NPDES permit numbers in the survey responses. After 

the NPDES permit numbers were matched, EPA correlated the outfalls in the Form 2C database 

to those reported in the survey using the following hierarchy: 

 Outfall numbers that matched exactly; 

 Outfall numbers matched by hand to correct for minor formatting discrepancies (e.g., 

“Outfall 001” vs. “001”); and 

 Matching outfall descriptions. 

EPA used the information from Parts A and D of the survey responses to calculate the 

percent contribution of the ash transport water streams to the total outfall flow rate. For each of 

the 27 outfalls in the Form 2C database for which more than 75 percent of its flow is from ash 

transport water (fly, bottom, or the combination of the two), EPA included the average pollutant 

concentrations in the ash concentrations data set. 

3.8 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 
Chapter 3 – Data Sources 

3-7 

TDD”) presents the results of studies of the steam electric industry that EPA conducted when 

previously revising the Steam Electric ELGs. This document contains findings, conclusions, and 

recommendations on control and treatment technology relating to discharges from steam electric 

power plants. The 1982 TDD included three separate tables that contained ash impoundment 

characterization data. EPA used data from all three tables (described below) to populate the ash 

concentrations data set. The Agency 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. 

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. Each of these 11 data sets were 

included in the ash concentrations data set as one data point per impoundment and pollutant. 

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; therefore, EPA included the same number of records of the average 

concentrations in the ash concentrations data set as the number of impoundments that were used 

to calculate the average. For example, EPA included four separate records of the average fly ash 

pollutant concentrations from Table V-33 in the ash concentrations data set because the table 

listed the four impoundments that were used to calculate the average concentrations presented. 

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. EPA included the average effluent pollutant concentration 

for each plant in the ash concentrations data set. 

3.9 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 this 

report. Additionally, EPA has withheld CBI, as well as some data not claimed as CBI but which 

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. The Agency’s approach to CBI protection 

ensures that the data in the public docket both explain the basis for the proposed rule and provide 

the opportunity for public comment, 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 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 
Chapter 3 – Data Sources 

3-8 

general, there are three different types of CBI cost values that were redacted from the nonCBI 

version of this report: 

 Plant-specific operating characteristics used as input values to estimate costs and 

loadings. Generally, EPA collected the plant-specific operating characteristics from 

plant responses to the Questionnaire for the Steam Electric Power Generating 

Effluent Guidelines (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 were claimed CBI. 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. 

 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 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 nonCBI 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 are described 

throughout this report. In general, EPA used all the data available for a specific cost 

element, including both CBI and nonCBI 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 

nonCBI data (i.e., the cost factor is CBI deducible). EPA’s methodology for 

determining CBI-deducible data is described in the following paragraphs. 

Where an aggregated output includes totals summed from both CBI and non-CBI data, 

the CBI responses may be deducible. 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. 

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 did not 

make any CBI claims on the data. The breakdown of respondents at the plant and 

company level is as shown: 
Chapter 3 – Data Sources 

3-9 

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 nonCBI 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 were 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. 

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 nonCBI version of this report. 

3.10 REFERENCES

1. Duke Energy. 2011a. Industry Provided Sampling Data from Duke Energy's Allen Steam 

Station. (17 August). DCN SE01809. 

2. Duke Energy. 2011b. Industry Provided Sampling Data from Duke Energy's Belews 

Creek Steam Station. (17 August). DCN SE01808. 
Chapter 4 – Development of Model Inputs 

4-1 

CHAPTER 4 

DEVELOPMENT OF MODEL INPUTS 

This chapter describes in detail 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; and 

 Plant characteristics. 

All tables and figures referenced in this chapter are presented at the end of the chapter. 

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 landfill leachate. Pollutant loadings are calculated by 

multiplying a specific pollutant-level concentration by a wastewater flow rate. 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 

information from the Questionnaire for the Steam Electric Power Generating Effluent 

Guidelines (Steam Electric Survey). 

4.1.1 FGD Wastewater

EPA used data from the Steam Electric Survey to identify the population of plants that 

discharge FGD wastewater to surface water (or a publicly owned treatment works (POTW)) and 

the type of treatment equipment each plant currently has in place. To develop this “FGD Input 

Table,” EPA used information from Part B of the Steam Electric Survey (Flue Gas 

Desulfurization (FGD) Systems). A copy of the “FGD Input Table” is located in the appendix. 

EPA identified a total of 117 plants that operate wet FGD systems and discharge FGD 

wastewater. 

EPA used the information from Part B Section 1 (General FGD System Information), to 

identify those plants that 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 

completely recycles the water back to the FGD system; or 

 The plant reuses all the FGD wastewater with no potential of later discharge to 

surface water or POTW. 
Chapter 4 – Development of Model Inputs 

4-2 

For each plant included in the “FGD Input Table”, EPA also identified a plant-level FGD 

wastewater flow rate in gallons per day (gpd). For plants operating more than one FGD system, 

the sum of the purge rates for the individual FGD systems was included in the “FGD Input 

Table”. For each FGD system currently operating, EPA used the purge rate reported in Part B 

Section 5 (FGD Wastewater Generation), as the basis for the cost models. For current FGD 

systems that did not provide a FGD wastewater flow rate in Part B Section 5 (27 plants), EPA 

developed a methodology to estimate the purge flow based on other data provided in the Steam 

Electric Survey. Using information from plants that did report an FGD wastewater flow, EPA 

established a relationship between the wastewater flow rate and the amount of coal burned at 

generating units serviced by wet FGD systems. EPA noted that this relationship was dependent 

upon the type of coal burned by these generating units; and as a result calculated a value for the 

FGD 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 27 plants using Equation 

4-1. 

 FGD Wastewater Flow (gpd) = TonsofCoalBurned × MedianGPDperTonofCoal (4-1) 

where: 

TonsofCoalBurned = The reported tons of coal burned per year by the 

steam electric units serviced by the FGD system. Data 

from Part A Section 8 (Fuel Usage by Steam Electric 

Generating Unit), and 

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 (DCN SE01825.A53) for the 

discussion on the development of Equation 4-1 and the development of the median FGD 

wastewater flow per ton of coal burned. 

For each plant planning 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 calculate a plant-level FGD wastewater flow rate in gallons per day, assuming 

the system operates 24 hours per day. In two cases, plants did not provide a design flow rate for 

planned FGD systems or reported that it was not yet known. To account for the lack of flow rate 

data provided in the survey responses, EPA developed a methodology for estimating the FGD 

wastewater flow rate for planned FGD systems. 

EPA first developed a relationship between the generating unit capacity (megawatts 

(MW)) and tons of coal burned per day using data from each coal-fired steam electric generating 

unit based on the type of coal burned: 
Chapter 4 – Development of Model Inputs 

4-3 

Bituminous Coal

 Coal Burned per Day (tons) = 0.0014 × Capacity2

 + 5.7189 × Capacity + 606.1 (4-2) 

Subbituminous Coal

Coal Burned per Day (tons) = 7.4416 × Capacity1.0685 (4-3)

Lignite Coal

 Coal Burned per Day (tons) = 2.9109 × Capacity + 9570.8 (4-4) 

Any Combination of Two or More Coal Types

Coal Burned per Day (tons) = 9.6541 × Capacity0.9858 (4-5) 

where: 

Capacity = The reported generating capacity of the steam electric 

unit in MW from Part A Section 6 (Steam Electric 

Generating Unit Information). 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A54) for the 

discussion on the development of Equations 4-2 through 4-5. 

Using Equations 4-2 through 4-5, EPA calculated the amount of coal burned per day for 

each steam electric unit not providing the information in Part A Section 6 (Steam Electric 

Generating Unit Information). The amount of coal burned per year was calculated by multiplying 

the amount of coal burned per day by the number of days the unit operated in 2009, reported in 

Part A Section 6. All units missing the number of days of operation, or planned steam electric 

generating units not reporting days of operation, were all baseload type units. EPA used the 

median number of days of operation, 311 days, for all baseload units. EPA used the estimated 

amount of coal burned per year to calculate an FGD wastewater flow rate, in gpd, for the two 

planned FGD systems not reporting a design flow. 

4.1.2 Fly Ash and Bottom Ash Transport Water

EPA used data from the Steam Electric Survey to identify the population of surface 

impoundments that receive fly ash, bottom ash, or combined ash transport water and that 

discharge to surface waters. To develop this “Ash Transport Water Input Table,” EPA used the 

information from the Steam Electric Survey to identify those plants that discharge all or some of 

their ash transport water and how much of that ash transport water is being discharged. A copy of 

the input table is included in the appendix. EPA identified a total of 248 plants that discharge ash 

transport water from 269 discrete outfalls. 

EPA populated the “Ash Transport Water Input Table” using the following steps: 
Chapter 4 – Development of Model Inputs 

4-4 

 Identify surface impoundments that discharge to surface waters based on Part D 

Section 3.2 (Ponds/Impoundment System or Wastewater Treatment System Effluent 

Flows); 

 Determine if those surface impoundments receive any ash transport water based on 

Part D Section 3.1 (Ponds/Impoundment System or Wastewater Treatment System 

Influent Flows); and 

 EPA supplemented 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 further reviewed the 

process flow diagrams to help identify whether any ash transport water enters the specific surface 

impoundment and whether any amount of recycle occurs. 

For each surface impoundment included in the “Ash Transport Water Input Table,” EPA 

also identified the flow rate associated with the fly ash transport water, bottom ash transport 

water, or combined ash transport water. Data included in the Steam Electric Survey do not 

include impoundment discharges broken out by type of waste; as a result, EPA used the data 

available from the survey to calculate the amount of ash transport water discharged from each 

impoundment. EPA used the following hierarchy to populate the “Ash Transport Water Input 

Table” with ash transport water effluent flow rates for all impoundments indicating that 100 

percent of the influent is discharged: 

 Influent flow rates to the surface impoundment reported in Part D; 

 Ash transport water flow rates reported in Part C; or 

 Percent contributions of ash transport water to a plant outfall multiplied by the total 

outfall flow rate reported in Part A Section 2. 

For combined ash surface impoundments, EPA combined the fly ash transport water and 

bottom ash transport water flow rates to calculate a combined ash transport water flow rate for 

the surface impoundment for the purposes of the “Ash Transport Water Input Table;” therefore, 

each ash surface impoundment that discharges has only one entry in the “Ash Transport Water 

Input Table.” 

For surface impoundments that do not discharge 100 percent of the influent, EPA used 

information from other parts of the Steam Electric Survey to estimate the amount of evaporation 

or recycle achieved by each plant. EPA used data from Parts D, C, and A to calculate the 

percentage of ash transport recycled within the ash sluice system and the percentage of transport 

water discharged to surface water or POTWs. In cases where data from the various survey 

sections were not in agreement, EPA further reviewed the water balance diagram to help identify 

the level of recycle. 

Plants do not generate ash transport water constantly 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 
Chapter 4 – Development of Model Inputs 

4-5 

discharging over 365 days. Using Steam Electric Survey data, EPA identified the number of days 

that the ash transport water was reported to be transferred to the surface impoundment or 

generated from the ash handling system. To account for the number of days of generation, EPA 

calculated a normalized daily flow rate using Equation 4-6.4

 Flow Rate (gpd) = Impoundment Transport Water Flow × Days Genrated / 365 Days (4-6) 

where: 

Impoundment 

Transport Water Flow 

= The reported ash transport water flow rate discharged 

from each surface impoundment in gallons/day, and 

Days Generated = The reported number of days that ash transport water is 

generated/transferred to the ash surface impoundment. 

4.1.3 Leachate

EPA used data from the Steam Electric Survey to identify the population of 

active/inactive landfills containing combustion residuals that collect leachate and discharge to 

surface waters. To develop this “Landfill Leachate Input Table,” EPA used the information from 

Part A Section 4 (Landfills) of the survey along with information from Part A Section 2.2 

(Outfall Information) and water balance diagrams to identify the landfills that collect and 

discharge leachate to surface water. A copy of the “Landfill Leachate Input Table” is located in 

the appendix. EPA identified a total of 102 plants that collect and discharge leachate from 114 

landfills containing combustion residuals. 

Plants reported their collected leachate volumes in Part F Section 3.1 (Landfill 

Management Practices) of the Steam Electric Survey. Because only a subset of plants were 

required to complete Part F, EPA had specific landfill leachate volumes from 18 plants. For each 

of these 18 plants, EPA calculated the ratio of the landfill acreage associated with the collected 

leachate and the total active/inactive landfill acres at the plant reported in Part C Section 1 (Ash 

Generation) of the survey. EPA then determined the median value and applied this value to 

plants that reported collecting landfill 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 leachate is collected (referred to as 

leachate acreage). EPA developed separate estimates for active and inactive landfills as follows: 

Active Landfills

 Leachate Acreage (acre) = 0.75 × Landfill Acreage (4-7) 

 

4

 The approach of normalizing the flow based on the number of days generating ash transport water may underestimate the 

loadings. Even when ash transport water is not transferred to the ash impoundment the impoundment will continue to discharge, 

although at a lower flow rate, because other contributions (e.g., rainfall) will continue to feed the impoundment and will likely 

become contaminated from the ash contained in the impoundment. 
Chapter 4 – Development of Model Inputs 

4-6 

Inactive Landfills

 Leachate Acreage (acre) = 0.05 × Landfill Acreage (4-8) 

where: 

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 (DCN SE01825.A62) for the 

discussion on the development of Equations 4-7 and 4-8. 

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 containing combustion residuals that collect 

leachate and the amount of 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 leachate, the median leachate discharge rate was 887 gpd per acre. 

EPA used the following hierarchy to estimate the landfill leachate flow rate for the 

“Landfill Leachate Input Table:” 

 EPA used the volume of 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 

survey (Landfill Management Practices) and multiplied by the median leachate 

discharge rate per acre (887 gpd/acre). The specific data from the Steam Electric 

Survey used to calculate this value can be found in the Supplemental Costs and 

Loadings Documentation (DCN SE01825.A62). 

 Leachate Volume (gpd) = 887 × Leachate Acreage (4-9) 

 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

 Leachate Volume (gpd) = 887 × 0.75 × Leachate Acreage (4-10) 

Inactive Landfills

 Leachate Volume (gpd) = 887 × 0.05 × Leachate Acreage (4-11) 

where: 

Leachate Acreage = Total acreage of landfills containing combustion 

residual at the plant that collect leachate, a percentage 
Chapter 4 – Development of Model Inputs 

4-7 

of the total landfill acres at the plant (see Equations 4-7 

and 4-8). 

During review of the landfill leachate volumes, EPA also investigated the frequency of 

leachate collection for the 18 plants with complete Part F Section 3.1 data. The median 

frequency of leachate collection was 365 days per year. EPA used this value to convert the 

leachate volumes from gallons per day to gallons per year prior to populating the “Landfill 

Leachate Input Table.” 

EPA identified two plants that did not provide landfill acreage data in Part C Section 1 of 

the Steam Electric Survey. To estimate the landfill leachate flow rate for these two plants, EPA 

used the median leachate volume from plants providing data in Part F Section 3.1 of the survey. 

The average plant-level 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. 

4.2 WASTESTREAM POPULATION AND CHARACTERISTICS FOR COSTING

For each plant discharging FGD wastewater and/or combustion residual landfill leachate 

and all plants operating wet fly or bottom ash handling systems, EPA estimated a compliance 

cost to treat wastewater or eliminate the discharge of ash transport water entirely.5 EPA 

estimated compliance costs associated with installing a wastewater treatment system to treat 

FGD wastewater and landfill leachate. The methodology for estimating treatment system costs is 

based on the flow of wastewater through the system. For FGD wastewater and landfill leachate, 

EPA used the same input table 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. These costs are based on the amount and type of ash generated by each plant. The 

following sections describe what population of plants incurs fly ash and bottom ash compliance 

costs and the specific plant and generating unit-level characteristics needed to estimate these 

costs. 

4.2.1 FGD Wastewater

EPA used the same input data for both costing and loadings associated with discharging 

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 to identify the population of plants that 

would incur costs under the proposed regulatory options. 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 

 

5

 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. 
Chapter 4 – Development of Model Inputs 

4-8 

Plant Operation) of the survey . to identify what costing elements of the fly ash system would be 

appropriate for each plant. 

EPA assessed the costs for converting to a dry fly ash handling system on a steam electric 

generating unit level. EPA examined survey data for each generating unit utilizing fly ash 

transport water and applied a hierarchal method to determine the appropriate fly ash cost 

elements for each generating unit. First, units were flagged as “No_cost” if the unit falls into any 

of the following subsets: 

 Retired generating units, that responded “Yes” to Question A6-1 in Table A-8. 

 Generating units that did not operate in 2009, indicated by a “No” response to 

Question A6-1 in Table A-8.6

 Generating units at a plant that did not receive Part C of the survey (i.e., Version 4 

plants: gas-fired plants, gas-combined cycle plants, and nuclear power plants, and 

those plants kicking out of the survey in Part A), which are not expected to produce 

ash. 

 Generating units that did not report fly ash generation, either by responding “No” to 

Question C1-1 or not completing a copy of Part C Section 2.1. 

 Generating units that reported fly ash generation in Table C-2 and reported dry 

handling only. These units reported all of their fly ash generation as dry conveyed, 

did not select wet sluicing (hydraulic) in Table C-2, and responding “No” to C2-2. 

 Generating units that indicated both wet and dry fly ash handling by responding 

“Yes” to Question C2-10. The units must also have reported 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 Question C2-10 and indicated that use of the wet fly ash handling system 

will end before 1/1/2014 in Question C2-13. 

 Generating units that indicated both wet and dry fly ash handling by responding 

“Yes” to 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 will incur all associated fly ash cost elements (i.e., conveyance costs, 

silo costs, pugmill costs, and transportation/disposal costs). These units were flagged as 

”All_cost” and identified using the following criteria: 

 

6

 Although these units may still have the capability to operate, EPA assumes that the company will retire these units instead of

investing money for ash handling conversions. 
Chapter 4 – Development of Model Inputs 

4-9 

 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). 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-2.7

All generating units that were not categorized as ‘No_cost” or “All_cost” have both wet 

and dry fly ash handling capabilities, and therefore should only require partial fly ash cost 

elements to convert to a completely dry fly ash handling system. These units were flagged for 

costing based on the responses to Questions C2-11 and C2-12.

 Generating units were identified as needing conveyance costs if the respondent 

selected “Install/increase the capacity of the dry fly ash conveying equipment” in 

response to Question C2-12. 

 Generating units were identified as needing silo costs if the respondent selected either 

“Increase the capacity of the silo(s)” or “Increase the number of the silos” in response 

to Question C2-12. 

 Generating units were identified as needing pugmill costs any time a unit was 

identified as needing a silo cost. Additionally, 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 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 C2-12, 

or if the respondent selected “Wet fly ash handling system operated during times in 

which the dry fly ash was not marketable” in response to Question C2-11. 

Additionally, a unit was identified as needing transportation/disposal costs any time it 

was identified as needing a silo or pugmill cost. 

For all generating units included in this partial costs category that handled the fly ash 

both wet and dry in 2009, EPA evaluated 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. 

EPA identified 78 plants, corresponding to 197 generating units, discharging fly ash 

transport water that would incur costs to eliminate the discharge of fly ash transport water. Of 

these, 12 plants, corresponding to 27 generating units, are oil-fired units or small units with a 

capacity less than or equal to 50 megawatts. For all 197 generating units, EPA identified the 

 

7

 Although the plants indicated that these 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 units. 
Chapter 4 – Development of Model Inputs 

4-10 

specific fly ash cost elements needed, and collected the other necessary input data (i.e., unit-level 

wet fly ash production (in tons per day and days per year), operating days, capacity (in MW), and 

fly ash transport water flow rate (in gpd)). 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 appendix. 

4.2.3 Bottom Ash 

EPA used data from the Steam Electric Survey to identify the population of 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 survey. to identify what costing elements of the bottom ash system would 

be appropriate for each plant. 

Costs for converting to a system that eliminates the discharge of bottom ash transport 

water are assessed on a steam electric generating unit level. EPA examined survey data for each 

generating unit utilizing bottom ash transport water and applied a hierarchal method to determine 

the most appropriate bottom ash cost elements for each unit. First, generating units were flagged 

as “No_cost” if the unit falls into any of the following subsets: 

 Retired generating units that responded “Yes” to A8-1 in Table A-8. 

 Generating units that did not operate in 2009, those responding “No” to A8-1 in Table 

A-8.8 

 Generating units at a plant not completing Part C of the survey (i.e., Version 4 plants: 

gas-fired plants, gas-combined cycle plants, and nuclear power plants, and those 

plants kicking out of the survey in Part A), which are not expected to produce ash. 

 Generating units not reporting bottom ash generation, either by responding “No” to 

C3-1 or not completing a copy of Part C Section 3.1. 

 Generating units \reporting bottom ash generation in Table C-18 but not reporting the 

use of wet sluicing. These units did not select “Wet sluicing” in Table C-18, and 

selected “No” in response to C3-3. 

 Generating units reporting 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 Question C3-16 and responding in the “Other” field for 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 Question C3-16 and reporting that use of the wet bottom ash handling 

system will end before 1/1/2014 in Question C3-19. 

 

8

 Although these units may still have the capability to operate, EPA assumes that the company will retire these units instead of

investing money for ash handling conversions. 
Chapter 4 – Development of Model Inputs 

4-11 

 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 units that required a conversion to a system that eliminates the 

discharge of bottom ash transport water. These units were identified using the following criteria: 

 Generating units selecting “Wet sluicing” in Table C-18 and not reporting any dry 

handling capabilities (Mechanical drag system, Dry vacuum system, Dry pressure 

system). 

 Generating units selecting “Other” were handled on an individual basis to determine 

whether the response indicated a wet or dry handling system. 

Further, EPA identified plants operating wet sluicing systems where the majority of the 

bottom ash transport water is recycled. For generating units that responded “Yes” to Question 

C3-5 and “Immediately recycled back to plant process” to Question C3-10, EPA evaluated the 

amount of transport water actually discharged. EPA identified plants that discharged only a small 

amount (10 percent) of total bottom ash transport water 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. 

EPA identified 226 plants, corresponding to 581 generating units, discharging bottom ash 

transport water that would incur costs to eliminate the discharge of the bottom ash transport 

water. Of these, 13 plants, corresponding to 53 generating units, are oil-fired units or small units 

with a capacity less than or equal to 50 megawatts. For all 581 generating units, EPA identified 

the specific cost elements that apply to the unit, and collected the other necessary input data (e.g., 

capacity (in MW), the operating days, and the bottom ash transport water rate (in gpd)). 

Additionally, EPA identified a subset of plants (27 plants, corresponding to 53 generating units) 

discharging only a small percentage of their bottom ash transport water. For all 53 generating 

units, EPA assigned these units bottom ash management 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 appendix. 

4.2.4 Leachate

EPA used the same input data for both costing and loadings associated with discharging 

landfill leachate. For details on the “Landfill Leachate Input Table” see Section 4.1.3. 

4.3 POLLUTANT CONCENTRATIONS

EPA calculated analyte-level pollutant loadings for each of the technology options 

considered as part of the Steam Electric effluent limitation guidelines and standards (ELGs). 

Chapter 10 discusses 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, and publicly available sources. Chapter 10 discusses pollutant 

loadings for each of the wastestreams considered for regulation: 
Chapter 4 – Development of Model Inputs 

4-12 

 FGD wastewater; 

 Fly ash transport water; 

 Bottom ash transport water; 

 Impoundment and Landfill leachate; 

 Flue gas mercury control wastewater; 

 Gasification wastewater; and 

 Nonchemical metal cleaning waste. 

For each wastestream, EPA describes the pollutant concentrations used to calculate 

analyte-level loadings for each technology option. 

4.4 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 removals associated with the proposed Steam Electric ELGs. The Agency used 

information gathered through the Steam Electric Survey on current ash handling techniques and 

FGD wastewater treatment technologies to identify which plants would be affected by revisions 

to the Steam Electric ELGs. EPA also used plant characteristics identified in the Steam Electric 

Survey and publicly available data from operating companies and technology vendors to 

determine how plants are already currently operating, or plan to be operating by 2014, compared 

to the proposed bases for the technology options. EPA analyzed plants for possible existing FGD 

treatment and ash handling practices to account for existing treatment when calculating 

compliance costs and estimating baseline pollutant loadings. 

4.4.1 Retirements and Conversions

The steam electric industry is a dynamic industry where changes are occurring 

frequently, in terms of plants adding new air pollution controls or making changes to existing ash 

handling systems. Because of these changes, EPA attempted to account for planned changes in 

the cost and loadings analysis. Therefore, where EPA had information regarding a plant planning 

to retire generating units, convert fuels to eliminate producing combustion residual waste, 

upgrade FGD or leachate wastewater treatment systems, or convert one or more units to a dry fly 

ash or bottom ash handling system, EPA excluded these units from the cost and loadings analysis 

because the planned modifications would lead to compliance with the proposed ELGs. 

EPA identified 30 plants as retiring, or converting, at least one generating unit by 2014. 

These units were excluded from the cost and loadings analysis. EPA is also aware of several 

plants planning system level modifications to FGD wastewater treatment, leachate treatment, 

and/or fly ash and bottom ash handling that will enable them to comply with the proposed ELGs. 

Some plants are installing vapor-compression evaporation systems to treat their FGD wastewater 

while other plants are converting impoundment-based wet sluicing systems to closed-loop 

recycle systems and eliminating the discharge of ash transport water. These units were also 

excluded from the costs and loadings analysis. A list of all units removed from the costs and 

loadings analysis as a result of retiring, converting fuels, or treatment upgrades is included in the 
Chapter 4 – Development of Model Inputs 

4-13 

“Changes to Industry Profile for Steam Electric Generating Units for the Steam Electric Effluent 

Guidelines Proposed Rule” (DCN SE02033). 

4.4.2 FGD Treatment-in-Place Input

In addition to identifying each plant’s total FGD wastewater flow rate, EPA also 

documented plants with treatment-in-place for the three FGD wastewater technology options. 

The “Treatment-In-Place Input Table” includes data on each plant’s current level of treatment for 

its FGD wastewater. For plants currently treating the FGD wastewater using one-stage chemical 

precipitation, anoxic/anaerobic biological treatment, or vapor–compression evaporation system, 

EPA assessed credit for these treatment systems as part of the costs and loadings models. More 

detail on how treatment in place is assessed for both costs and loadings is located in Sections 

6.1.3 and 10.2.1 and also in the Supplemental Costs and Loadings Documentation (DCN 

SE01825). Below is a list of the plant identification numbers for those plants identified as having 

some amount of treatment in place for each type of technology.9

FGD Wastewater Technology Plants With Treatment in Place

Chemical Precipitation 00103, 00771, 01236, 01381, 01402, 02079, 02268, 02297 ,02383, 

02536, 02550, 03095, 03146, 03196, 03200, 03265, 03709, 03831, 

04122, 04237, 04533, 04543, 04679, 05015, 05318, 05477, 05570, 

06283, 06377, 06616, 07256, 07785, 07884, 08308, 08353, 08661, 

09161, 09225, 09671, 09805, 09948 

Anoxic/Anaerobic Biological 

Treatment 

02550, 04543, 06689, 08661, 09391 

Vapor-Compression Evaporation 00217 

4.4.3 High Flow FGD Treatment Systems

EPA categorized 12 plants with an average 24-hour plant-level FGD wastewater flow rate 

greater than 1,000 gpm as a “high flow” plant. For these high flows, EPA believes it would be 

more cost efficient for a plant to implement additional recycle within the FGD system with a 

lower overall FGD treatment flow rate, rather than design and 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 design 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 the FGD wastewater and the amount of recycle that can be 

accommodated. 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 provided in Part B Section 4 (Flue Gas Desulfurization Systems – Wet FGD 

System Information). 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. As a result, EPA identified any system operating below 80 

 

9

 EPA acknowledges that plants discharging FGD wastewater will continue to upgrade and/or install new treatment systems. EPA 

will reassess the list of plants and level of treatment in place assessed to plants discharging FGD wastewater prior to the final 

rule. 
Chapter 4 – Development of Model Inputs 

4-14 

percent of the maximum design level threshold as having the potential to recycle some FGD 

wastewater. Five of the 12 high flow plants were identified as having the potential to implement 

some level of FGD wastewater recycle. 

EPA then calculated a new FGD treatment flow rate and the flow of the FGD recycle 

stream for these five plants. The new FGD treatment flow rate was calculated based on the 

number of recycle passes a given system can accommodate without exceeding 80 percent of the 

maximum chlorides limit. EPA used Equations 4-12 and 4-13 to calculate the new FGD 

treatment flow rate. For more discussion on how these equations were developed, see the 

Supplemental Costs and Loadings Documentation (DCN SE01825.A55). 

Additional Recycle Passes = (Max Design Cl Level × 0.8 – Operating Cl Level)/ Operating Cl 

 Level (4-12)

New FGD Treatment Flow = Current FGD Treatment Flow / (1+ 

 Additional Recycle Passes) (4-13)

where: 

Max Design Cl Level = Maximum design chloride concentration based on the 

material of constructed of the FGD scrubber as 

reported in Part B Section 2 of the Steam Electric 

Survey, 

Operating Cl Level = Operating chloride concentration of the FGD scrubber 

as reported in Part B Section 2 of the Steam Electric 

Survey, 

Current FGD Treatment 

Flow 

= Current FGD wastewater treatment flow rate as 

reported in the Steam Electric Survey, and 

Additional Recycle 

Passes 

= Number of additional scrubber passes that can be 

achieved based on operating chloride concentration 

(see Equation 4-12). 

The flow of the recycle stream was calculated as the differential between the current FGD 

treatment flow and the new discharge flow. 

Included as part of the “High Flow FGD Input Table” is a flag to identify which plants 

operate a dedicated FGD surface impoundment. EPA determined it to be cost prohibitive for 

these high flow plants to install equalization tanks versus continuing to operate a surface 

impoundment. It is likely that these plants will use the dedicated impoundment in place of the 

equalization tanks and routesome of the impoundment effluent to the FGD wastewater treatment 

system, while the remainder is recycled to the FGD system, which will increase the chlorides 

level in the system to within 80 percent of the maximum design chlorides level. EPA identified 

seven of these 12 high flow plants with a dedicated FGD surface impoundment. These plants will 

not incur a cost for equalization tanks in Section 6.1.6.2. 
Chapter 4 – Development of Model Inputs 

4-15 

EPA developed a “High Flow FGD Input Table” to hold plant-specific information on the 

12 high flow plants. The data held in this input table include the current FGD wastewater flow or 

original purge flow rate (gpd) and the calculated recycle stream flow (gpd) for the five FGD 

recycle plants. Additionally, the “High Flow FGD Input Table” contains a flag identifying which 

plant operates a dedicated FGD surface impoundment. The “High Flow FGD Input Table” is 

included in the appendix. Chapter 6 provides detail on how costs for these high flow plants were 

estimated. 

4.5 COMBUSTION RESIDUAL DISPOSAL

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 ash handling, FGD wastewater treatment, and landfill leachate treatment. Costs 

associated with transportation and disposal of combustion residuals are based on whether plants 

utilize an on-site or offsite-landfill. Section 4.5.1 provides more detail on the input table 

associated with transportation and disposal costs. Costs associated with surface impoundment 

operation are based on whether plants operate an impoundment containing specific types of 

combustion residuals. Section 4.5.2 provides more detail on the input table associated with 

surface impoundment operation costs. 

4.5.1 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 

determines the type of transport and disposal costs (e.g., 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 proposed ELGs in the on-site landfill. If a plant 

does not have a currently operating on-site landfill, EPA assumed that the plant would dispose of 

the additional wastes at an off-site landfill. 

4.5.2 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 residual wastes. The 

“Surface Impoundment Input Table” designates the specific combustion residual waste (i.e., 

FGD solids, fly ash, and/or bottom ash) stored at surface impoundments located at the plant. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-1 

CHAPTER 5 

GENERAL METHODOLOGY, TERMINOLOGY, AND 

COMMON COST ELEMENTS 

EPA estimated the capital and annual operating and maintenance (O&M) costs associated 

with implementing treatment technologies for each technology option under consideration. 

Additionally, EPA estimated costs for specific recurring cost elements that are not incurred on an 

annual basis. Therefore, EPA included additional 3-, 5-, 6-, and 10-year recurring cost elements 

in the compliance cost methodology. Section 5.1 provides further detail on the components 

included in the capital and O&M costs. 

Certain capital and O&M costs, such as transportation and disposal of solids, are 

applicable to more than one technology option. For example, the cost methodology for disposing 

of combustion residual solid waste in a landfill is the same for each type of waste. Thus, EPA 

was able to use the same cost module for these costs for the different technology options, varying 

the input values and factors (i.e., type, amount, and density of waste) as appropriate depending 

on the technology option and wastestream (flue gas desulfurization (FGD), fly ash, or bottom 

ash). These common cost elements that utilize the same cost module for more than one 

technology option include compliance monitoring, transportation and disposal of solid waste 

(e.g., FGD wastewater treatment solids, fly ash, and bottom ash), operation and maintenance of 

combustion residual surface impoundments, and best management practices (BMPs) for 

combustion residual surface impoundments. See Sections 5.2 through 5.6 for more details 

regarding these specific cost elements. All tables and figures referenced in this chapter are 

presented at the end of the chapter. 

5.1 GENERAL COST METHODOLOGY AND TERMINOLOGY

To estimate the compliance costs for the technology options, EPA evaluated both direct 

and indirect capital costs and O&M costs. These costs were estimated using data obtained from 

treatment technology vendors and responses to the Questionnaire for the Steam Electric Power 

Generating Effluent Guidelines (Steam Electric Survey). 

Capital costs are defined as a one-time expense incurred to bring a project to an operable 

status. These types of expenses include equipment, land, and buildings. EPA used the following 

cost components to estimate capital costs associated with each technology option, as appropriate: 

 Direct Capital Costs 

- Purchased equipment – the cost of all equipment needed for the treatment or 

handling system, including pumps, clarifiers, silos, sumps, tanks, reactors, filters, 

and various other items. 

- Equipment installation – the cost to install all of the purchased equipment, 

including piping, instrumentation/calibration, electrical equipment, mechanical 

equipment, structural supports, insulation, and paint. 

- Buildings –the cost associated with constructing structures to house treatment or 

handling system equipment, operator rooms, or other operations associated with 

the system. This element includes costs associated with building plumbing, 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-2 

heating, ventilation, dust collection, air conditioning, lighting, telephones, 

intercoms, painting, sprinklers, and fire alarms. 

- Site preparation – the cost associated with site clearing, demolition, grading, 

roads, walking areas, and fences. 

- Land –the cost for the purchase of all necessary property and survey fees. 

 Indirect Capital Costs 

- Engineering contracts –the cost for process design and general engineering, cost 

engineering, consulting fees, supervision, and inspections. 

- Contingency –the cost that may result from incomplete design, unforeseen and 

unpredictable conditions, or the complexity and uncertainties involved in cost 

estimating at a conceptual level. 

- Construction –the cost for temporary construction offices, roads, 

communications, fencing, construction tools and equipment, permits, taxes, and 

insurance. 

The specific capital cost elements evaluated for each technology option are detailed in the 

following chapters. 

Operating and maintenance costs include all costs associated with operating and 

maintaining the system on a day-to-day basis. These types of expenses include labor, materials, 

energy, and chemicals. EPA used the following cost components to estimate O&M costs 

associated with each technology option, as appropriate: 

 Operating labor – the labor costs for plant staff to operate the treatment or handling 

system. 

 Maintenance labor – the labor costs for plant staff to maintain the treatment or 

handling system. 

 Maintenance materials – the costs associated with routine replacement of materials 

and equipment due to consumption or wear and tear. 

 Energy –the cost for the energy used to operate equipment associated with the system, 

including pumps, mixers, and other equipment. 

 Chemicals –the cost for all chemical additives used in the treatment or handling 

system. 

The specific O&M cost elements evaluated for each technology option are detailed in the 

following chapters. 

In addition to one-time capital costs and annual O&M costs, EPA also evaluated 

recurring costs that occur less frequently than once a year. These recurring costs include 

expenses for items that need to be purchased every few years. EPA assessed recurring costs for 

equipment purchased every 3, 5, 6 or 10 years based on the requirements of the technology 

option. These cost elements are listed separately in each cost output and are detailed in the 

appropriate technology option chapters. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-3 

5.2 COMPLIANCE MONITORING COST METHODOLOGY

Where a regulatory option would establish requirements for pollutants not currently 

regulated in the existing ELGs, EPA calculated plant-level compliance monitoring costs for 

plants to sample and analyze their discharges to assess their compliance with proposed effluent 

limitations. Compliance monitoring costs include costs for sampling and analysis of FGD 

wastewater and leachate effluent discharges. Note that there are no compliance monitoring costs 

for the conversion from wet fly ash and bottom ash systems to dry systems because these 

conversions eliminate the discharge of ash transport water. 

5.2.1 Monitoring Requirements

Monitoring requirements for FGD wastewater and leachate effluent discharges differ by 

treatment technology used:10

Chemical precipitation. For each plant that discharges FGD wastewater and/or leachate, 

EPA estimated costs for weekly analysis for arsenic and mercury. Costs are included as a 

chemical precipitation O&M cost. 

Chemical precipitation followed by biological treatment. For each plant that discharges 

FGD wastewater and/or leachate, EPA estimated costs for weekly analysis for arsenic, selenium, 

and mercury.11,12 Costs are included as a biological treatment O&M cost. 

Chemical precipitation followed by vapor-compression evaporation. For each plant that 

discharges FGD wastewater, EPA estimated costs for weekly analysis for arsenic, selenium, 

mercury, and total dissolved solids. Costs are considered as a vapor-compression evaporation 

O&M cost. 

5.2.2 Capital Cost Methodology

EPA did not include costs to purchase capital equipment for compliance monitoring 

associated with the proposed ELGs because power plants covered under the requirements of 40 

CFR 423 already own and/or operate sampling equipment for effluent monitoring. 

5.2.3 O&M Cost Methodology

Compliance monitoring O&M costs were calculated using Equation 5-1. 

 

10 EPA is proposing to set limits on arsenic, mercury, selenium, and total dissolved solids for IGCC wastewater. EPA will include

monitoring costs associated with these pollutants for the final rule. EPA expects these monitoring costs to be roughly 63,000 

dollars per plant. 

11 EPA is proposing to set limits on arsenic, selenium, mercury, and nitrate/nitrite for FGD wastewater under options based on 

biological treatment. EPA is also proposing to set limits on arsenic and mercury for landfill leachate under options based on 

chemical precipitation. In cases where FGD wastewater and leachate are treated using the same treatment system, the more 

stringent limits requirements will apply. As a result, plants discharging both FGD wastewater and leachate and FGD wastewater 

alone are assessed monitoring costs for arsenic, selenium, and mercury. Plants discharging only landfill leachate are assessed 

monitoring costs for arsenic and mercury. 

12 EPA is proposing to set limits on arsenic, selenium, mercury, and nitrate/nitrite for FGD wastewater under options based on 

biological treatment. EPA will include monitoring costs associated with nitrate/nitrite for the final rule. EPA expects these added 

monitoring costs to be approximately $1,664 per plant annually. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-4 

Compliance Monitoring Cost (2010$/yr) = Sampling Labor Cost + Sampling Materials Cost + 

 Sample Shipping Cost + Sample Analysis Cost (5-1) 

where: 

Sampling Labor Cost = The cost associated with the plant labor required to 

conduct the sampling activities (see Section 5.2.3.1), 

Sampling Material Cost = The cost of materials needed to collect and preserve the 

wastewater samples (see Section 5.2.3.2), 

Sample Shipping Cost = The cost of shipping the wastewater samples to the 

laboratory for analysis (see Section 5.2.3.3), and 

Sample Analysis Cost = The cost to analyze wastewater samples (see Section 

5.2.3.4). 

For plants that discharge both FGD wastewater and leachate, EPA calculated compliance 

monitoring costs for both wastestreams, based on the assumption that the wastewaters are 

generated at separate locations and are not commingled for discharge (i.e., 2 × Compliance 

Monitoring Cost (2010$/yr)). 

5.2.3.1 Sampling Labor Cost 

Sampling labor costs are those associated with plant personnel collecting and analyzing 

wastewater samples. EPA assumed that each wastestream would be sampled weekly, with two 

operators needed to collect the samples using the protocols in EPA Method 1669. EPA assumed 

that the operators would collect samples at only one location for each wastestream because the 

additional monitoring requirements associated with the proposed ELGs will only be applied at 

one location per wastestream. Table 5-1 (located at the end of the chapter) lists the estimated 

sample labor requirements (in hours per year (hr/yr)) overall and by task by type of plant staff. 

EPA calculated the sampling labor cost by multiplying the annual number of labor hours 

by the labor rate. EPA determined a wastewater treatment system operator labor rate of 

[Redacted] (2009$) based on the median operating labor rate reported in responses to Question 

D6-2 of the Steam Electric Survey by plants that operate FGD wastewater chemical precipitation 

treatment (with and without subsequent biological or vapor-compression evaporation 

treatment).13 EPA determined a plant environmental coordinator labor rate of $37.04/hr (2010$) 

based on the U.S. Bureau of Labor Statistics data for environmental engineers [U.S. Bureau of 

Labor Statistics, 2010]. As the operator labor rate was provided in 2009 dollars, the cost basis 

was adjusted to 2010 dollars using the 2009 and 2010 RSMeans Historical Cost Indices (180.1 

and 183.5, respectively) [RSMeans, 2011]. 

 

13 The wastewater operator labor rate of [Redacted] is the median FGD wastewater treatment operator labor rate 

based on survey data in 2009$. EPA will index the value appropriately with cost index data from RS Means for the 

final rule. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-5 

Sampling Labor Cost (2010$/yr) = (Operator Labor Rate × Operator Hours × 2010 Cost 

Index/2009 Cost Index) + (Environmental Coordinator Labor Rate × 

 Environmental Coordinator Hours) = [Redacted] (5-2) 

where: 

Operator Labor Rate = [Redacted] (2009$), 

Operator Hours = 364 hr/yr (see Table 5-1 located at the end of the 

chapter), 

Environmental 

Coordinator Labor Rate 

= $37.04/hr (2010$), 

Environmental 

Coordinator Hours 

= 18 hr/yr (see Table 5-1 located at the end of the 

chapter), 

2009 Cost Index = 180.1, and 

2010 Cost Index = 183.5. 

5.2.3.2 Sampling Material Cost 

Sampling material and supply costs are the costs associated with the materials and 

supplies, such as personal protective equipment, sampling containers, and other supplies, 

required for plant personnel to collect and analyze samples. Table 5-2 (located at the end of the 

chapter) provides a detailed list of sampling materials and their costs (in 2010$/sampling event). 

EPA estimated the annual sampling material cost by multiplying the sampling materials cost per 

sampling event by the number of sampling events per year. As all sampling material costs were 

provided by vendors in 2011 dollars, the cost basis was adjusted to 2010 dollars using the 2010 

and 2011 RSMeans Historical Cost Indices (183.5 and 185, respectively) [RSMeans, 2011]. 

Sampling Materials Cost (2010$/yr) = Sampling Materials Cost Per Event × Annual Number of 

Sampling Events × (2010 Cost Index/2011 Cost Index) = $22,194 or 

 $22,24614 (5-3) 

where: 

Sampling Materials 

Cost per Event 

= $430.30/sampling event (2011$), except vaporcompression evaporation, $431.30/sampling event 

(2011$), (see Table 5-2 located at the end of the 

chapter),15

Annual Number of 

Sampling Events 

= 52 sampling events/yr, 

 

14 Costs for chemical precipitation systems and biological treatment systems are $22,194 while costs for vaporcompression evaporation systems are $22,246. 

15 There are additional costs for the vapor-compression evaporation system because of the additional bottle needed 

to analyze for TDS. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-6 

2010 Cost Index = 183.5, and 

2011 Cost Index = 185. 

5.2.3.3 Sample Shipping Cost 

EPA estimated the costs for shipping the samples to laboratories using the cost of a 

sample shipment and the total number of sample shipments per year and that samples would be 

sent to two different laboratories, one for analysis of low-level mercury and one for analysis of 

other metals. EPA assumed that one of the laboratories would be able to analyze the samples for 

total dissolved solids and nitrate/nitrite. EPA assumed that each sample shipment to each 

laboratory would cost $40. As vendors provided sample shipping costs in 2011 dollars, the cost 

basis was adjusted to 2010 dollars using the 2010 and 2011 RSMeans Historical Cost Indices 

(183.5 and 185, respectively) [RSMeans, 2011]. EPA estimated sample shipment costs using the 

Equation 5-4. 

Sample Shipping Cost (2010$/yr) = Sample Shipment Cost × Number of Sample Shipments per 

Event × Annual Number of Sampling Events × (2010 Cost Index/2011 

 Cost Index) = $4,126 (5-4) 

where: 

Sampling Shipment Cost = $40/shipment (2011$), 

Number of Sample 

Shipments per Event 

= 2 per event, 

Annual Number of 

Sampling Events 

= 52 sampling events/yr, 

2010 Cost Index = 183.5, and 

2011 Cost Index = 185. 

Sampling Shipment Cost = $40/shipment (2011$), 

5.2.3.4 Sample Analysis Cost 

EPA calculated sample analysis costs using the cost of analyzing each sample that would 

be collected per sampling event and the number of sampling events per year. EPA based the 

sample analysis costs on the costs the Agency incurred during its field sampling program. Table 

5-3 (located at the end of the chapter) provides a detailed list of sample analyses and their costs 

(in 2010$/sampling event). EPA estimated the annual sample analysis cost by multiplying the 

sample analysis cost per sampling event by the number of sampling events per year as shown by 

the equation below. Because sample analysis costs were provided by vendors in 2011 dollars, the 

cost basis was adjusted to 2010 dollars using the 2010 and 2011 RSMeans Historical Cost 

Indices (183.5 and 185, respectively) [RSMeans, 2011]. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-7 

Sample Analysis Cost (2010$/yr) = Sample Analysis Cost Per Event × Annual 

Number of Sampling Events × (2010 Cost Index/2011 Cost Index) = $16,247 or $16,76316 (5-5) 

where: 

Sample Analysis Cost 

per Event 

= $315/sampling event (2011$), except vaporcompression evaporation, $325/sampling event 

(2011$), (see Table 5-3 located at the end of the 

Chapter),17

Annual Number of 

Sampling Events 

= 52 sampling events/yr, 

2010 Cost Index = 183.5, and 

2011 Cost Index = 185. 

5.3 TRANSPORTATION COST METHODOLOGY

Steam electric power plants can reuse, market/sell, or give away combustion residuals. 

Alternatively, plants can transport combustion residuals to a disposal site (e.g., landfill). For the 

proposed ELGs, EPA conservatively included costs for plants to transport all solid waste to a 

landfill because not all plants have the means to market/sell or give away the combustion 

residuals. For plants that are capable of marketing the combustion residuals, EPA’s estimated 

compliance costs will be overestimated for the following reasons: 

 The estimated compliance costs include costs for transporting the solid waste to an 

on- or off-site landfill, which may not be needed depending on location and timing of 

the beneficial reuse; and 

 The estimated compliance costs do not account for the additional revenue stream 

generated from selling the solid waste. 

5.3.1 Technology Description

All combustion residuals (i.e., fly ash, bottom ash, and FGD wastewater treatment solids) 

can be transported to on-site or off-site landfills in an open dump truck. For plants with existing 

on-site landfills already containing combustion residuals, EPA included costs to dispose of any 

additional combustion residuals resulting from compliance with the ELGs in an on-site landfill, 

by either expanding the existing landfill or building a new landfill to accommodate the additional 

waste. For plants that do not have existing on-site landfills (or their on-site landfills do not 

 

16 Costs for chemical precipitation systems and biological treatment systems are $16,247 while costs for vaporcompression evaporation systems are $16,763. 

17 There are additional costs for the vapor-compression evaporation system because of the additional analysis for 

TDS. Also note that the costs for the analysis of the metals is likely overestimated because during EPA’s sampling 

program, EPA analyzed for a suite of metals, but the plants will only be required to analyze for one or two of the 

metals (depending on wastestream), which should result in a reduced cost for the metals analyses. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-8 

contain combustion residuals), EPA included costs to dispose of the additional combustion 

residuals in an off-site non-hazardous landfill. 

5.3.2 Cost Inputs

EPA used Steam Electric Survey data to identify which plants have existing on-site 

landfills containing combustion residuals. For all plants identifying at least one open landfill 

containing combustion residuals in Part A Section 4 (Landfills) of the Steam Electric Survey, 

EPA estimated compliance costs for on-site transportation of ash and FGD solids. For all other 

plants (i.e., those without an open landfill containing combustion residuals), EPA estimated 

compliance costs for off-site transportation of the ash and FGD solids. The flags for whether a 

plant has an on-site or off-site landfill are contained in the “Transportation Input Table” within 

the cost model. 

EPA based plant-level compliance costs for transporting combustion residuals on the 

total amount of incremental waste generated at each plant associated with the proposed options. 

The technology cost modules associated with each treatment technology (i.e., fly ash, bottom 

ash, one-stage chemical precipitation, one-stage chemical precipitation with biological treatment, 

and one-stage chemical precipitation with vapor-compression evaporation) calculate the tonnage 

of incremental moisture-conditioned combustion residuals requiring disposal in a landfill at the 

plant level. See the discussion for the individual technology options for more detail on the solids 

generated by each treatment technology in Chapters 6, 7, 8, and 9. The output of these 

technology cost modules is used as the input for the transportation technology cost module. 

5.3.3 Cost Methodology

Both the on-site and off-site transportation cost methodologies use cost equations based 

on the dry tonnage of waste requiring disposal for each treatment technology. EPA used the 

following bulk density values to convert the wet tonnage values that are output from the 

individual technology cost modules to a dry tonnage value that could be used in the 

Transportation Cost Module: 

 EPA estimated the bulk density of FGD wastewater treatment solids to be 74.6 

pounds per cubic foot (estimated based on 50 percent density of water and 50 percent 

density of hydrated lime); and 

 EPA estimated the bulk density of fly ash and bottom ash to be 45 pounds per cubic 

foot (based on input from Clyde Bergemann Power Group (CBPG, formerly Delta 

Ducon) for dry ash).18

5.3.3.1 On-Site Transportation Cost Methodology 

EPA assumed that plants identified in the “Transportation Input Table” as having on-site 

landfills would continue to dispose of any additional combustion residual in the same on-site 

 

18 EPA made the following assumptions: the moisture of the fly ash as transported will be 13 percent, as determined 

from survey data (the median value reported in Table C-6) and the moisture of the bottom ash transported will be 20 

percent, as determined from survey data (the median value reported in Table C-23). 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-9 

landfill. EPA estimated transportation costs for plants with an on-site landfill using the estimated 

amount of solid waste (i.e., moistened fly ash, moistened bottom ash, and/or FGD wastewater 

treatment solids) and an on-site specific unitized cost value, in dollars per ton, based on 

information provided by EPA’s Office of Resource Conservation and Recovery (ORCR) 

developed using the Remedial Action Cost Engineering Requirements (RACER) software 

version 10.4. EPA used a cost of $3.257 in 2011 dollars per ton for transporting solid waste a 

distance of one mile one way to an on-site landfill. EPA confirmed ORCR’s assumption of a one 

mile one way transport distance is consistent with the median distance to an on-site landfill of 

1.3 miles reported by respondents to the Steam Electric Survey. EPA deflated this dollar per ton 

value to 2010 dollars using the 2010 and 2011 RSMeans Historical Cost Indices. Equation 5-6 

estimates the total cost for transporting combustion residual waste to an on-site landfill. 

 Total Cost (2010$) = Dry tons × 3.257 ($/ton) × (2010 Cost Index/2011 Cost Index) (5-6)

where: 

Dry tons = The dry volume of waste being transported to an onsite landfill in tons per year, 

2010 Cost Index = 183.5, and 

2011 Cost Index = 185. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A65) for 

details on the development of Equation 5-6.

5.3.3.2 Off-Site Transportation Cost Methodology 

EPA assumed that plants identified in the “Transportation Input Table” as not having an 

on-site landfill would dispose of any combustion residual in an off-site landfill. EPA used the 

RACER 2010 model to estimate the cost of transporting moistened fly ash, bottom ash, and/or 

FGD wastewater treatment solids. Using RACER, EPA calculated a cost of $9.234 in 2011 

dollars per ton to transport solid waste a one-way distance of 25 miles to an off-site landfill. EPA 

deflated this dollar per ton value to 2010 dollars using the 2010 and 2011 RSMeans Historical 

Cost Indices. Equation 5-7 estimates the total cost for transportation of solid waste to an off-site 

landfill. 

 Total Costs (2010$) = Dry tons × 9.234 ($/ton) × (2010 Cost Index / 2011 Cost Index) (5-7) 

where: 

Dry tons = The dry volume of waste being transported to an offsite landfill in tons per year, 

2010 Cost Index = 183.5, and 

2011 Cost Index = 185. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-10 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A65) for 

details on the development of Equation 5-7.

5.4 DISPOSAL COST METHODOLOGY

As described in Section 5.3.1, EPA conservatively determined costs for plants to dispose 

of combustion residuals requiring disposal in a landfill to comply with the ELGs. EPA estimated 

costs for on-site or off-site disposal based on the flags from the “Transportation Input Table.” To 

the extent plants are able to market/sell these residuals, EPA has overestimated the costs of 

disposal and has not accounted for revenue associated with other options. 

5.4.1 Technology Description

EPA estimated capital and O&M disposal costs for an on-site landfill. Capital costs 

include the construction of the landfill, liner, additional groundwater monitoring, leachate 

collection system, and closures associated with the expansion of an existing landfill. EPA used a 

unitized cost value (in dollar per ton) that represents the capital cost components for an onsite 

landfill and the estimated amount of solid waste produced from the implementation of 

technology options. EPA used a similar unitized cost approach to estimate the O&M costs based 

on the estimated amount of additional solid waste produced and a unitized cost value (in dollar 

per ton), that represents the costs associated with operating the landfill. The cost methodology 

addresses both capital costs and O&M costs associated with onsite disposal (see Section 5.4.3.1 

for more detail). 

Costs associated with off-site landfills are limited to the fee associated with using the 

landfill, also known as the tipping fee, which is discussed in more detail in Section 5.4.3.2. 

5.4.2 Cost Inputs

The cost inputs used to calculate on-site and off-site disposal costs are similar to those 

used in the transportation cost module. The flags for on-site or off-site landfill from the 

“Transportation Input Table” are used to determine what type of disposal cost each plant will be 

assessed. The dry waste tonnage for each wastestream, calculated in the transportation cost 

module, is also used as an input for the disposal costs. 

5.4.3 Cost Methodology

5.4.3.1 On-Site Disposal Cost Methodology 

The cost methodologies presented in this section discuss the capital and O&M costs 

associated with expanding an on-site landfill. EPA found that there was limited costing data 

associated with landfill construction/expansion provided in response to the Steam Electric 

Survey data. And for the limited data that was provided, EPA was unable to determine the 

specific elements that were included as part of the landfill construction/expansion. As a result, 

EPA used information from a 2009 planning-level cost estimate prepared by CH2MHILL for 

construction, operation, and closure costs associated with a 7-acre expansion of an existing 

landfill in Hilo, HI [CH2MHILL, 2009]. EPA used the cost estimate from the CH2MHILL study 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-11 

because it includes the most recent data in the most useful format. EPA searched for other 

costing data in the Steam Electric Survey and searched other publicly available data, but these 

sources did not include cost estimates to construct/expand a landfill that includes a liner, 

groundwater monitoring, and leachate collection. 

Capital Costs

In the cost estimate prepared by CH2MHILL, the capital costs include construction of the 

landfill, liner, additional groundwater monitoring, leachate collection system and closures. Table 

5-4 (located at the end of the chapter) summarizes the high and low capital costs included in the 

study. The costs presented in the CH2MHILL study represent a 7-acre expansion for an added 

capacity of 328,000 tons of solid waste. EPA calculated a high and low capital cost per ton of 

waste based on the data provided in the study. Capital costs for the landfill expansion ranged 

from $19.52 per ton to $28.85 per ton. 

Using the high cost estimates from the CH2MHILL study and the RSMeans Historical 

Cost Index to index costs from 2009 to 2010, EPA used Equation 5-8 to estimate the capital costs 

for disposing of additional solid waste in an on-site landfill. 

Total Capital Costs (2010$) = Dry tons × 28.85 ($/ton) × (2010 Cost Index / 2009 Cost 

 Index) (5-8) 

where: 

Dry tons = The dry volume of waste being transported to an offsite landfill in 2009 in tons, 

2010 Cost Index = 183.5, and 

2009 Cost Index = 180.1. 

O&M Costs

Similar to capital costs, EPA used the 2009 cost estimate from CH2MHILL to estimate 

the O&M costs associated with expanding a landfill. Table 5-5 (located at the end of the chapter) 

summarizes the high and low O&M costs included in the study. Using these costs along with the 

total added capacity of 328,000 tons of solid waste, EPA calculated a high and low O&M cost 

per ton of waste. O&M costs for the landfill expansion ranged from $6.12 per ton to $8.04 per 

ton. 

Using the high cost estimate from the study and the RSMeans Historical Cost Index to 

index costs from 2009 to 2010, EPA used Equation 5-9 to estimate O&M costs for disposing of 

additional combustion residual solid waste in an onsite landfill. 

Total O&M Costs (2010$) = Dry tons × 8.04 ($/ton) × (2010 Cost Index / 2009 Cost Index) (5-9) 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-12 

where: 

Dry tons = The dry volume of waste being transported to an offsite landfill in tons per year, 

2010 Cost Index = 183.5, and 

2009 Cost Index = 180.1. 

5.4.3.2 Off-Site Disposal Cost Methodology 

EPA assumed that plants not having an on-site combustion residual landfill will transport 

any additional solid waste to an off-site landfill. The tipping fees associated with disposal in 

these off-site landfills is generally assessed on a per-ton-of-waste basis. To estimate the cost 

incurred by each plant, EPA calculated a weighted average national tipping fee to apply to all 

plants expected to incur off-site disposal fees. EPA used state-level tipping fees and calculated a 

national weighted average based on the total combustion residual disposed in off-site landfills by 

each state as identified in the Steam Electric Survey, assuming all plants would likely dispose of 

their solid waste in the same state in which they are located. The cost for off-site disposal of 

solid waste was calculated to be $40.99 per ton in 2011 dollars. This value was indexed to 2010 

dollars using the RSMeans Historical Cost Indices. Equation 5-10 estimates the cost of disposing 

of additional solid waste in an offsite landfill. 

 Total Costs (2010$) = Dry tons × 40.99 ($/ton) × (2010 Cost Index / 2011 Cost Index)(5-10) 

where: 

Dry tons = The dry volume of waste being transported to an offsite landfill in tons per year, 

2010 Cost Index = 183.5, and 

2011 Cost Index = 185. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A66) for 

details on the development of Equation 5-10.

5.5 SURFACE IMPOUNDMENT OPERATION COSTS METHODOLOGY

Implementation of the technology options will reduce, and in some cases eliminate, the 

management of FGD wastewater, ash transport water, and combustion residuals in on-site 

impoundments. EPA therefore expects plants will experience cost savings in operating these 

impoundments. To calculate the incremental cost savings that may be realized under the 

technology options, EPA estimated the annual O&M and recurring costs associated with 

managing these wastewaters and combustion residuals in on-site impoundments. EPA estimated 

annual O&M and 10-year recurring costs associated with impoundment operations using the 

equations provided in this section. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-13 

5.5.1 Technology Description

To calculate the incremental compliance cost of the technology options, EPA estimated 

the annual O&M and recurring costs associated with managing these wastewaters and 

combustion residuals in on-site impoundments. Additionally, EPA estimated capital costs 

associated with some waste water discharges identified as new sources. See ERG’s 

memorandum “New Source Performance Standards (NSPS) Costing Memorandum” (DCN 

SE02129) for the specific new source capital cost equations associated with impoundment 

operations. 

Surface impoundments are designed to remove particles from wastewater using gravity 

sedimentation. Plants pump FGD slurry blowdown, fly ash transport water, and bottom ash 

transport water through pipes from the FGD scrubber, fly ash hoppers, and bottom ash hoppers, 

respectively, to surface impoundments for treatment. After the plant pumps the wastewater(s) to 

the impoundment, the combustion residual solids fall out of suspension and settle near the front 

end of the impoundment. The overflow from the impoundment is either discharged to surface 

water, transferred to a publicly owned treatment works (POTW), or recycled back to plant 

operations. Some plants operate a chemical addition system to adjust the pH prior to discharge or 

recycle. Many plants dredge the combustion residual solids in the impoundment for disposal in a 

landfill. Additionally, some plants use the combustion residual solids as part of the impoundment 

design (e.g., placing solids in stacks both dewater the solids and to redirect the flow of 

wastewater through an impoundment based on plant design). Plants use different types of 

earthmoving equipment to remove these solids from the impoundment (e.g., backhoe, front-end 

loader). 

For each technology option evaluated, EPA estimated the amount of wastewater or 

combustion residuals no longer expected to be managed in on-site impoundments and the 

associated cost savings. Impoundment O&M costs are the costs associated with operating the: 

 Wastewater transport system (i.e., pipelines, vacuum source) pumping the wastewater 

from the FGD scrubber or ash hoppers to the impoundment; 

 Impoundment site (i.e., general operation of the impoundment, removing/stacking of 

combustion residual materials, inspections); 

 Wastewater treatment system (e.g., pH control); and 

 Water recycle system at the impoundment (if applicable). 

Earthmoving O&M costs are the costs associated with operating the earthmoving 

equipment the operation of earthmoving equipment (i.e., backhoe) required for 

removing/stacking combustion residual materials at the impoundment site. EPA also identified 

recurring costs for earthmoving equipment associated with replacing the specific type of 

equipment (i.e., the backhoe). 

5.5.2 Input Table

EPA used Steam Electric Survey data to identify plants that have at least one 

impoundment, not designated as retired or planned, containing at least one type of combustion 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-14 

residual. Using data from the Steam Electric Survey, EPA flagged the specific type(s) of 

combustion residual(s) (e.g., FGD solids, fly ash, bottom ash) reported to be stored in 

impoundments at the plant. EPA calculated incremental impoundment operating costs for plants 

reporting at least one impoundment, containing combustion residuals, in Part A Section 3 

(Ponds/Impoundments) of the Steam Electric Survey. EPA calculated these costs as part of the 

total compliance costs for FGD wastewater, fly ash, and bottom ash. That is, incremental 

impoundment operating costs are included in the compliance cost estimates for each separate 

wastestream evaluated at the plant depending on the types of combustion residuals stored in the 

impoundment. For example, if a surface impoundment is flagged as containing FGD wastes and 

bottom ash, EPA estimated the amount of FGD solids and bottom ash solids are transferred to 

the impoundment (in tons) and evaluated impoundment savings for FGD solids as part of the 

FGD compliance cost estimates and evaluated impoundment savings for bottom ash as part of 

the bottom ash compliance cost estimates. The flags for the presence of one or more combustion 

residual impoundments are included in the “Surface Impoundment Input Table.” A copy of this 

input table is included in the appendix. 

EPA estimates plant-level costs for operating combustion residual impoundments based 

on the total amount of combustion residuals currently handled wet at the plant. EPA estimated 

the total amount of fly ash and bottom ash wastes using the total amount of wet ash conveyed in 

2009 using data in response to the Steam Electric Survey (Tables C-2 and C-18). EPA estimated 

the total amount of FGD solids handled wet using the FGD wastewater flow rate (in gallons per 

day (gpd)) and the average total suspended solids (TSS) concentration from EPA’s Field 

Sampling Program. See Section 5.5.3.1 for the specific equation used to estimate FGD solids in 

the wastewater. 

5.5.3 Cost Methodology 

EPA estimated the incremental impoundment and earthmoving O&M and recurring costs 

using information in reports summarizing 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 (1981) and U.S. EPA Full-Scaled Field Evaluation of Waste Disposal from Coalfired Electric Generating Plants (1985). EPA determined that a combination of the data 

presented in both studies could be used to estimate the O&M and recurring costs associated with 

operating a combustion residual impoundment. EPA selected both data sources to combine 

unitized cost (annual dollars per ton of ash) information with information on how costs vary 

based on plant size (megawatts (MW)). 

5.5.3.1 Impoundment O&M Costs 

EPA estimated the incremental impoundment O&M costs using Equation 5-11. 

Total O&M Impoundment Costs = (-1) x (Impoundment Operating O&M Costs + Impoundment 

 Earthmoving O&M Costs) (5-11) 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-15 

where: 

Impoundment 

Operating O&M Costs 

= Incremental impoundment operating costs, and 

Impoundment 

Earthmoving O&M 

Costs 

= O&M cost associated with the incremental 

earthmoving equipment required. 

Impoundment Operating O&M Costs 

EPA estimated the incremental impoundment operating costs for all applicable 

combustion residuals at the plant using the plant MW factor described in Section 5.5.3.4 and the 

calculated combined ash unitized cost values for impoundment operating costs described in 

Section 5.5.3.2 and presented in Table 5-7 (located at the end of the chapter). 

First, EPA calculated the plant-specific size factor, based on plant size in MW, and the 

plant-specific unitized cost. The values for these equations were developed using the two reports 

described in Section 5.5.3. The plant-specific size factor is calculated using Equation 5-26 and is 

used along with the impoundment operating unitized cost, discussed in Section 5.5.3.2, to 

calculate the plant-specific unitized cost using Equation 5-12. 

Plant-Specific Unitized Cost = (Impoundment Operating Unitized Cost) × (Plant MW 

 Factor) (5-12) 

where: 

Impoundment 

Operating Unitized 

Cost 

= The 2010 unitized annual cost to operate a combustion 

residual impoundment presented in Table 5-7 (located 

at the end of the chapter). EPA used the unitized cost 

value $7.35 per ton of combustion residual for all 

combustion residuals. See Section 5.5.3.2 for a more 

detailed description of the unitized cost values, and 

Plant MW Factor = Factor to adjust combination residual handling costs 

based on plant capacity. See Equation 5-26. 

Next, EPA calculated the incremental impoundment operating costs for each applicable 

type of combustion residual at the plant. For FGD impoundment operating costs, EPA estimated 

the amount of combustion residuals (in tons) using FGD wastewater flow, in gpd, and an average 

TSS concentration from EPA’s Field Sampling Program. 

Fly Ash Impoundment Operating Costs ($/yr)= (-1) x (Plant Specific Unitized Cost) × 

 (Conditioned Dry Fly Ash for Disposal) (5-13)

Bottom Ash Impoundment Operating Costs ($/yr)= (-1) x (Plant Specific Unitized Cost) × (Plant 

 Bottom Ash Tonnage) (5-14) 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-16 

FGD Impoundment Operating Costs ($/yr) = (-1) × (Plant Specific Unitized Cost) × [(FGD 

Wastewater Flow) × (Average TSS Concentration) × (3.785 L/gal) x (0.001 g/mg) × 

 (1.102 x 10-6 tons/g) x (365 dpy)] (5-15)

Total Impoundment Operating O&M Costs ($/yr)= Fly Ash Impoundment Operating Costs + 

 Bottom Ash Impoundment Operating Costs + FGD Impoundment Operating Costs (5-16) 

where: 

Conditioned Dry Fly 

Ash for Disposal 

= The total fly ash tonnage, dry basis, for each plant in 

tons per year (tpy). This value is calculated by 

multiplying the wet fly ash generation rate (in tons per 

day (tpd)) by the wet fly ash conveying days (in days 

per year (dpy)) for each unit, and then summing the 

unit level values to the plant level. These values are 

used in the transport and disposal fly ash methodology, 

as described in Section 7.1.7, 

Plant Bottom Ash 

Tonnage 

= The total bottom ash tonnage, dry basis, for each plant 

in tons per year. This value is calculated by multiplying 

the wet bottom ash generation rate (in tpd) by the wet 

bottom ash conveying days (in dpy) for each unit, and 

then summing the unit level values to the plant level. 

These values are used in the transport and landfill 

bottom ash methodology, as described in Section 8.3, 

FGD Wastewater Flow = FGD wastewater flow rate in gpd as reported in the 

Steam Electric Survey (see Section 4.1.1), and 

Average TSS 

Concentration 

= The average influent TSS concentration, in milligrams 

per liter (mg/L), for FGD wastewater treatment influent 

sampled as part of the EPA Steam Electric Rulemaking 

effort. These data also include long-term monitoring 

data from all applicable plants. The average FGD 

wastewater influent TSS concentration value is 16,513 

mg/L. 

Impoundment Earthmoving Equipment O&M Costs

EPA estimated the incremental earthmoving equipment costs for all applicable 

combustion residuals at the plant using the plant MW factor described in Section 5.5.3.4 and the 

calculated 2010 unitized cost value associated with a front-end loader described in Section 

5.5.3.3. 

First, EPA calculated the plant-specific size factor, based on plant size in MW, and the 

plant-specific unitized cost. The values for these equations were developed using the two reports 

described in Section 5.5. The plant-specific size factor is calculated using Equation 5-26 and is 

used along with the front-end loader unitized cost, discussed in Section 5.5.3.3, to calculate the 

plant-specific unitized cost using Equation 5-17. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-17 

Plant-Specific Front-End Loader Unitized Cost ($/ton) = (Front-End Loader 2010 Unitized 

 O&M Cost) × (Plant MW Factor) (5-17) 

where: 

Front-End Loader 2010 

Unitized O&M Cost 

= The 2010 unitized cost value that represents the 

operation and maintenance of the front-end loader used 

to redistribute ash at an impoundment. This value was 

calculated to be $2.49 $/ton, and 

Plant MW Factor = Factor to adjust combination residual handling costs 

based on plant capacity. See Equation 5-26. 

Next, EPA calculated the incremental earthmoving O&M costs for each applicable 

combustion residual at the plant. For FGD impoundment operating costs, EPA estimated the 

amount of combustion residuals (in tons) using the plant’s FGD wastewater flow, in gpd, and an 

average TSS concentration from EPA’s Field Sampling Program. 

Fly Ash Impoundment Earthmoving Costs = (-1) × (Plant-Specific Front-End Loader Unitized 

 Cost) × (Conditioned Dry Fly Ash for Disposal) (5-18) 

Bottom Ash Impoundment Earthmoving Costs = (-1) × (Plant-Specific Front-End Loader 

 Unitized Cost) × (Plant Bottom Ash Tonnage) (5-19) 

FGD Impoundment Earthmoving Costs = (-1) × (Plant-Specific Front-End Loader Unitized Cost) 

× [(FGD Wastewater Flow) x (Average TSS Concentration) × (3.785 L/gal) × (0.001 g/mg) × 

 (1.102 x 10-6 tons/g) × (365 dpy)] (5-20) 

Total Impoundment Earthmoving O&M Costs = Fly Ash Impoundment Operating Costs + 

 Bottom Ash Impoundment Operating Costs + FGD Impoundment Operating Costs (5-21) 

where: 

Conditioned Dry Fly 

Ash for Disposal 

= The total fly ash tonnage, dry basis, for each plant in 

tpy. This value is calculated by multiplying the wet fly 

ash generation rate (in tpd) by the wet fly ash 

conveying days (in dpy) for each unit, and then 

summing the unit level values to the plant level. These 

values are used in the transport and disposal fly ash 

methodology, as described in Section 7.1.7., 

Plant Bottom Ash 

Tonnage 

= The total bottom ash tonnage, dry basis, for each plant 

in tpy. This value is calculated by multiplying the wet 

bottom ash generation rate (in tpd) by the wet bottom 

ash conveying days (in dpy) for each unit, and then 

summing the unit-level values to the plant-level. These 

values are used in the transport and landfill bottom ash 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-18 

methodology, as described in Section 8.3, 

FGD Wastewater Flow = FGD wastewater flow rate in gpd as reported in the 

Steam Electric Survey (see Section 4.1.1), and 

Average TSS 

Concentration 

= The average influent TSS concentration, in milligrams 

per liter (mg/L), for FGD wastewater treatment influent 

sampled as part of the EPA Steam Electric Rulemaking 

effort. These data also include long-term monitoring 

data from all applicable plants. The average FGD 

wastewater influent TSS concentration value is 16,513 

mg/L. 

5.5.3.2 Impoundment Unitized O&M Costs 

This section explains how EPA calculated the impoundment operating unitized cost (in 

$/ton) used in the equations to estimate impoundment O&M costs described in Section 5.5.3.1. 

EPA calculated impoundment O&M costs using unitized cost data provided in U.S. EPA/TVA’s 

1981 study report. The 1981 U.S. EPA/TVA study is a report that compares capital and O&M 

costs for five different methods of ash disposal at a 500 MW coal-fired power plant. For the 

impoundment unitized cost values, EPA used the costs in the 1981 U.S. EPA/TVA study 

associated with the wet sluicing of ash to a surface impoundment without water recycle scenario 

described in the study [U.S. EPA/TVA, 1981]. EPA used the cost and ash tonnage data from the 

1981 study to calculate a unitized cost (dollar per ton) that includes costs for annual O&M only 

(excluding annualized capital costs, inflation, and discounts over time) based on combined ash 

tonnage. The study provides unitized costs associated with the following modular process areas: 

 Collection: includes the ash hoppers, a portion of the water supply systems, and the 

fly ash pneumatic systems including the vacuum producers; 

 Transportation: includes the air separators, a portion of the water supply systems, 

the ash pumps, the pipeline systems, trucks, the storage silos and moisturizers, the 

bottom ash dewatering bins, and the removal of ash from temporary impoundments; 

 Disposal Site: includes the impoundments and landfills, including all mobile 

equipment except that used to load and haul ash; and 

 Water Treatment and Recycle: includes the treatment systems, pumps and return 

lines, and the bottom ash water systems. 

For fly ash impoundments, EPA used the annual O&M data for all process areas 

excluding (1) collection. EPA excluded the collection process area because the operation and 

maintenance associated with ash will still occur even after implementation of the proposed rule 

(i.e., there is no cost savings). This unitized cost includes the annual O&M for conveying the fly 

ash from the hopper to the impoundment, and any wastewater treatment necessary for discharge. 

For bottom ash impoundments, EPA used the annual O&M data for all process areas 

excluding (1) collection and (2) transportation. EPA defines the conveyance portion of the 

system to include sluicing equipment, associated piping, and pumps in the Steam Electric 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-19 

Survey; the 1981 study defined these same process components as the transportation process 

area. EPA excluded the transportation process area based on the characteristics of the two 

technology operations evaluated for bottom ash, as described in the following paragraph. 

The two technology options EPA considered for bottom ash transport water include the 

mechanical drag system (MDS) and the remote MDS. Both systems use the same equipment for 

handling bottom ash. However, the remote MDS continues to operate the existing transportation 

portion of the wet sluicing system (i.e., pumps, pipeline systems) to transport the bottom ash 

sluice to a remote MDS, compared to the MDS that is located directly underneath the boiler and 

doesn’t require the use of the existing sluice system (see Sections 8.1.1 and 8.2.1). Because the 

main difference between the two technology options is the sluice system used to transport ash to 

the remote destination, EPA included a cost savings component for the MDS cost methodology 

to differentiate between the two technology options. Therefore, EPA did not include 

transportation as part of the impoundment operation cost estimates because: 

 The MDS cost methodology already estimates the O&M costs that are saved from 

eliminating the need for the wet sluicing system; and 

 The remote MDS still requires using the existing wet sluicing system to transport that 

bottom ash sluice to the remote destination. 

EPA did not account for reductions in the wet sluicing operations as part of the fly ash 

handling conversion methodology (i.e., the estimated cost reduction associated with the wet 

sluicing operations is not included in the fly ash conversion methodology (see Chapter 7); 

however, is included as part of the impoundment operation saving methodology); therefore, the 

cost savings associated with the conveyance portion of the fly ash handling system are included 

in the impoundment cost estimates. This is different than bottom ash because the estimation of 

the wet sluicing costs is included in the bottom ash conversion methodology (see Chapter 8) and 

is therefore removed from the impoundment operation savings for bottom ash. 

Table 5-6 (located at the end of the chapter) presents the re-calculated totals for annual 

costs. EPA combined the fly and bottom ash costs to determine a combined ash unitized cost for 

the impoundment savings calculations for fly ash, bottom ash, and FGD solids. Table 5-7 

(located at the end of the chapter) presents the fly, bottom, and combined unitized cost, 

calculated by dividing the revised total O&M costs by total ash tonnage. 

5.5.3.3 Earthmoving Unitized O&M Costs 

In addition to the impoundment operation unitized costs described in Section 5.5.3.2, 

EPA also estimated the costs associated with operating earthmoving equipment at combustion 

residual impoundments to scoop solids out of the influent channels, move the influent pipes to 

new locations, or build up the berms of the combustion residual impoundments. For the 

earthmoving unitized cost values, EPA used the costs with the holding pond and landfill scenario 

described in the 1981 U.S. EPA/TVA study [U.S. EPA/TVA, 1981]. EPA used this scenario 

because it includes costs for mobile equipment, defined as comprising all trucks and earthmoving 

equipment. The mobile equipment requirements are based on the quantity, moisture content, and 

bulk density of the ash and truck specifications and operating profiles established for the specific 

operating conditions. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-20 

Based on knowledge from site visits regarding removing combustion residuals from 

impoundments, EPA assumed that the front-end loader at the impoundment site was the most 

applicable piece of mobile equipment for removing combustion residuals. EPA also assumed that 

only one front-end loader per type of combustion residual would be purchased per plant that 

operates a combustion residual impoundment.19 For example, if a plant transfers both FGD solids 

and bottom ash to an impoundment (or two separate impoundments) and the plant is identified 

for FGD and/or bottom ash compliance costs, EPA assumed that the plant would have purchased 

two front-end loaders. Based on the 1981 U.S. EPA/TVA study, the 2010 capital cost of one 

front-end loader would be $402,687. EPA assumed that the life of a front-end loader is 10 years. 

Based on the modular annual revenue requirements (O&M) by type of equipment for the 

holding pond and landfill scenario in the 1981 study, the total direct costs for mobile equipment 

are $945,600 (1984 dollars) for 171,600 tons of ash. 20 Excluding the annualized capital charges 

(consistent with the impoundment operating costs methodology), the total indirect costs for 

mobile equipment are $450,400 (1984 dollars). 21, 22 Because there are no specific O&M costs 

per piece of mobile equipment, EPA estimated that the O&M cost associated with the front-end 

loader would be proportional to the percentage of the capital cost for the front-end loader 

compared to the total capital cost for all mobile equipment applicable to the holding pond and 

landfill scenario ($402,687/$2,936,960 = 13.7 percent). EPA then applied this percentage to the 

total O&M costs to determine a unitized cost value. EPA developed the earthmoving O&M 

unitized costs using Equations 5-22 through 5-25. 

 Total O&M ($) = $945,600 + $450,400 = $1,396,000 (5-22) 

 Front-End Loader O&M ($) = 0.137 × $1,396,000 = $191,252 (5-23) 

 Front-End Loader Unitized O&M Cost ($/ton) = $191,252 / 171,600 tons = $1.11/ton(5-24) 

Front-End Loader 2010 Unitized O&M Cost ($/ton) = $1.11/ton × 2010 Cost Index / 1984 Cost 

 Index = $2.49/ton (5-25) 

where: 

1984 Cost Index = 82.0, and 

2010 Cost Index = 183.5. 

 

19 EPA recognizes that some plants may have more than one front-end loader for combustion residuals removal, 

while other plants may not require any equipment to remove combustion residuals. 

20 Total direct costs include operating labor, diesel fuel, and maintenance. 

21 Total indirect costs include plant and administrative overhead. 

22 See Table B-6 of Economics of Ash Disposal at Coal-fired Power Plants (U.S. EPA, 1981) for more detailed 

information. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-21 

5.5.3.4 Impoundment and Earthmoving Capacity Factors 

Next, EPA calculated factors for estimating unitized costs for plants of different sizes, 

using data presented in EPA’s report Full-Scale Field Evaluation of Waste Disposal from Coalfired Electric Generating Plants [U.S. EPA, 1985]. The data EPA used from the 1985 study are 

presented in Table 5-8 (located at the end of the chapter), which presents the calculated cost 

factors relative to a 500 MW plant for fly ash and bottom ash. From these data, EPA calculated 

the average cost factor relative to the 500 MW plant to get a “combined ash calculated factor,” 

The calculated values are presented in the “Combined ($/ton)” rows. EPA determined the 

following equation to estimate cost factors for combustion residual handling based on plant size 

(MW). 

 Plant MW Factor = 7.569 × (Plant Size)-0.32 (5-26) 

where: 

Plant Size = Plant size in MW. For FGD costs, the MW value is the 

plant nameplate capacity from responses to Question 

A1-13 in the Steam Electric Survey. For fly and bottom 

ash, the MW value is the sum of the MW for the units 

incurring costs at the plant. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A68) for 

details on the development of Equation 5-26.

5.5.3.5 Surface Impoundment Earthmoving Recurring Costs 

Additionally, EPA calculated 10-year recurring costs associated with operating the 

earthmoving equipment (i.e., a backhoe or front-end loader). EPA calculated the total 10-year 

recurring costs by determining the cost and average expected life of a backhoe. EPA determined 

the 2010 cost of the earthmoving equipment to be $402,687, assumed that the expected life of a 

backhoe is 10 years, and assuming that each plant will operate one backhoe. 

5.6 SURFACE IMPOUNDMENT BMP COSTS METHODOLOGY

Although implementing the technology options will reduce, and in some cases eliminate, 

FGD wastewater, ash transport water, and combustion residuals managed in on-site surface 

impoundments, some surface impoundments may remain open. EPA is considering BMPs as part 

of all of the regulatory options evaluated for the proposed ELGs. To better inform this 

consideration, EPA calculated BMP costs for the impoundments that are expected to continue 

operating after complying with the ELGs. The BMPs include remedial actions (e.g., slope 

repairs, drawing down water levels, controlling vegetation) and increases in inspection frequency 

from 17 to 52 times annually. These management practices will help prevent future 

impoundment failures that have the potential to devastate the surrounding communities. 

To estimate impoundment BMP costs, which may be beyond the current state 

requirements, EPA reviewed the combustion residual impoundments at plants incurring 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-22 

compliance costs for FGD wastewater, fly ash transport water, and/or bottom ash transport water. 

For purposes of estimating BMP costs, EPA made some assumptions regarding the continued use 

of existing impoundments. Because these impoundments can contain multiple sources of 

combustion residuals, the probability that the impoundment will remain open depends on the 

regulatory option [ERG, 2013]. For example, if an impoundment contains FGD wastewater and 

bottom ash transport water, the impoundment would remain open based on the proposed 

Regulatory Option 3, which affects only FGD and fly ash transport wastewaters. EPA expects 

the probability that a plant may elect to close the impoundment to be high based on the proposed 

Regulatory Option 4, which affects all wastestreams of interest. Therefore, EPA estimated 

impoundment BMP costs for this impoundment for Regulatory Option 3; however, EPA 

estimated zero BMP costs for Regulatory Option 4. 

EPA estimated an annualized cost for each impoundment determined to remain open, 

based on the regulatory option. For each of these impoundments, EPA estimated that the 

remedial actions will require $10,000 annually per impoundment. EPA estimated the costs for 

the additional inspections based on information contained in Exhibit 3K of the Regulatory 

Impact Analysis for EPA’s Proposed RCRA Regulation of Coal Combustion Residues (CCR) 

Generated by the Electric Utility Industry [ORCR, 2010]. EPA used the information regarding 

the labor hours and labor rate for recording keeping and weekly inspections to estimate the costs 

of the additional inspections. Based on this information, EPA estimated that the additional 

inspections will cost approximately $3,000 annually. Therefore, the total annual cost per 

impoundment is approximately $13,000. 

5.6.1 Results and Summary of Costs

EPA calculated plant-level BMP costs for each of the five regulatory options being 

considered. The cost output includes the total number of surface impoundments at each plant that 

contain combustion residuals along with an indication of the number of impoundments closed 

under each regulatory option and the number of impoundments receiving BMP costs. The list of 

plant-level costs for implementing impoundment BMPs is included in the appendix. 

5.7 REFERENCES

1. CH2MHILL 2009. Planning-Level Cost Estimates for Landfill Options. Dan Pitzler and 

Cory Hinds. (27 March). DCN SE02954. 

2. Eastern Research Group (ERG). 2013. Memorandum to the Steam Electric Rulemaking 

Record: Pond Closure Analysis Memorandum. (19 April). DCN SE02125. 

3. The Envirobix Group, 2007. 2007 Chartwell Gate Price Survey Progress Report. The 

Envirobix Group. (9 April). DCN SE02012. 

4. RSMeans. 2011. Building Construction Cost Data, 69th Edition. DCN SE02952. 

5. U.S. Department of Labor, Bureau of Labor Statistics. 2010. May 2009 National 

Occupational Employment and Waste Estimates, United States. Washington, D.C. (May). 

DCN SE02024. 

6. U.S. EPA, 1985. Full-Scale Field Evaluation of Waste Disposal from Coal-fired Electric 

Generating Plants. (August). DCN SE02971. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-23 

7. U.S. EPA and Tennessee Valley Authority (TVA), 1981. Economics of Ash Disposal at 

Coal-fired Power Plants. (October). DCN SE02970.. 

8. U.S. EPA, Office of Resource Conservation and Recovery (ORCR). 2010. Regulatory 

Impact Analysis for EPA’s Proposed RCRA Regulation of Coal Combustion Residues 

(CCR) Generated by the Electric Utility Industry. Washington, D.C. (30 April). DCN 

SE02969. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-24 

Table 5-1. Compliance Monitoring Labor Requirements 

Task 

Number of Staff 

Required for 

Taska

Time Needed 

per Staff for 

Task 

(Hours/Task) 

Number of 

Events per 

Yearb

Total Time 

Needed 

(Hours/Yr) 

Set up composite sampler 2 0.75 52 78 

Collect 1st mercury manual composite sample 

(with field blank) 2 0.5 52 52 

Collect 2nd mercury manual composite 

sample 2 0.25 52 26 

Collect 3rd mercury manual composite sample 2 0.25 52 26 

Collect 4th mercury manual composite sample 2 0.25 52 26 

Collect arsenic/selenium sample from 

composite sampler 2 1 52 104 

Pack and ship samples to laboratory 1 1 52 52 

Review and report data 1 1.5 12 18 

Total wastewater treatment system operator (hours/yr): 

Total plant environmental coordinator (hours/yr): 

364

18

a

 EPA assumed that wastewater treatment system operators would perform all tasks except for reviewing and 

reporting data, which EPA assumed the plant environmental coordinator would perform. 

b EPA assumed all tasks would be performed weekly, except for reviewing and reporting data, which EPA assumed 

would be performed monthly. 

Table 5-2. Compliance Monitoring Sampling Materials 

Item 

Cost Per 

Item 

(2011$/Item) 

Number of Items 

Required Per 

Sampling Event 

Cost Per 

Sampling Event 

(2011$/Event) 

Tyvek coverall $5.50 2 $11 

Dust mask $0.50 2 $1 

Gloves (pair) $0.24 20 $4.80 

Mercury sample container (pre-cleaned, 250-mL glass) $3 2a $6 

Arsenic/selenium sample container (pre-cleaned, 500-mL 

plastic) $5 1 $5 

Total dissolved solids sample container (pre-cleaned, 1-L) $1 1b $1 

Shroud for mercury sample collection $1.50 4 $6 

Carboy (pre-cleaned, 10-L) $90 1 $90 

Field blank water (ASTM Type 1, 1-L) $12.50 1 $12.50 

Vented cap (pre-cleaned) $60 1 $60 

Composite sample pump-off cap (pre-cleaned) $38 1 $38 

Portable cleanbox (pre-cleaned) $30 1 $30 

T-splitter tubing set (pre-cleaned) $90 1 $90 

Composite sample pump-off tubing set (pre-cleaned) $70 1 $70 

Plastic tarp $3 2 $6 

Total sampling materials costs, other than vapor-compression evaporation 

(2011$/sampling event): 

Total sampling materials costs, vapor-compression evaporation (2011$/sampling event):

$430.30 

$431.30 

a Two sample containers are needed for sample and field blank analysis. 

b

 Applicable for vapor-compression evaporation effluent sampling only. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-25 

Table 5-3. Compliance Monitoring Sample Analysis 

Analysis 

Cost Per 

Analysis 

(2011$/Analysis) 

Number of Analysis 

Required Per Sampling 

Event 

Cost Per Sampling 

Event (2011$/Event) 

Mercury (EPA Method 1631E) $65 2a $130 

Arsenic and selenium (EPA Method 

200.8 with collision cell) $185 1 $185 

Total dissolved solids $10 1b $10 

Total sample analysis costs, other than vapor-compression evaporation 

(2011$/sampling event):

Total sample analysis costs, vapor-compression evaporation (2011$/sampling 

event):

$315 

$325 

a

 Two sample containers needed for sample and field blank analysis. 

b

 Applicable for vapor-compression evaporation effluent sampling only. 

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

Low (2009$) High (2009$) 

Expansion - Construction $3,200,160 $3,200,160 

Leachate treatment system (wetlands) construction $1,956,000 $4,847,000 

Landfill gas collection $47,000 $213,000 

Groundwater wells $45,000 $45,000 

Closure $1,156,000 $1,156,000 

Total Capital Cost $6,404,160 $9,461,160 

Source: CH2MHILL, 2009. 

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

Low (2009$) High (2009$) 

Landfill stormwater management $60,000 $0 

Leachate O&M $100,000 $200,000 

Leachate treatment upgrades (annual) $42,000 $103,000 

Added groundwater monitoring $23,000 $23,000 

Annual post closure care $277,000 $333,000 

Total O&M Cost $502,000 $659,000 

Source: CH2MHILL, 2009. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-26 

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

Ponding of Nonhardening Ash without Water Reuse 

Cost Category 

Fly Ash Modular Process Areas 

1,000 dollars (1984) 

Bottom Ash Modular 

Process Areas 

1,000 dollars (1984) 

2 3 4 

Revised 

Subtotal 3 4 

Revised 

Subtotal 

Direct Costs 

Operating labor 9.00 6.40 0.20 15.60 1.50 0.10 1.70

Process reagents 0.00 0.00 2.90 2.90 0.00 0.70 0.70

Water 5.50 0.00 0.00 5.50 0.00 0.00 0.00

Electricity 10.30 0.50 0.70 11.50 0.20 0.20 0.40

Process maintenance 57.00 0.00 4.00 61.00 0.00 1.00 1.00

Pond maintenance 0.00 177.00 0.00 177.00 44.00 0.00 44.00

Sampling and analysis 0.00 2.10 16.80 18.90 2.10 16.80 18.90

Total direct costs 81.80 186.00 24.60 292.40 47.80 18.80 66.60

Indirect Costs 

Plant and administration overheads 

(60% of total direct costs less water 

and electricity) 39.60 111.30 14.34 165.24 28.56 11.16 39.72

Total 

Total annual O&M cost 121.40 297.30 38.94 457.64 76.36 29.96 106.32

Source: U.S. EPA/TVA, 1981. 

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

Type of Cost 

Total O&M 

1984 $ 

Ash 

Tonnage 1984 Index 

1984 

Unitized 

Cost ($/ton) 2010 Index 

2010 

Unitized 

Cost ($/ton) 

Fly ash 457,640 137,280 82 3.33 183.5 7.46

Bottom ash 106,320 34,320 82 3.09 183.5 6.93

Combined ash 563,690 171,600 82 3.28 183.5 7.35

Source: U.S. EPA/TVA, 1981. 

Note: The costs presented in this table are the EPA-calculated unitized costs for the impoundment savings cost 

methodology; excluding the “collection” modular process area for fly ash and bottom ash and the “transportation” 

modular process area for bottom ash. 
Chapter 5 –General Methodology, Terminology, and Common Cost Elements 

5-27 

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

Type of Cost 

Plant Size 

(MW) 

Min Range 

1982 $ 

Max Range 

1982 $ 

Average 

1982 $ 

Average Cost 

Factor 

Relative to 

500 MW 

Plant 

Fly ash ($/ton) 250 15.7 28.9 22.3 1.27 

Fly ash ($/ton) 500 12.3 22.7 17.5 1 

Fly ash ($/ton) 1000 9.7 18.2 13.95 0.79 

Fly ash ($/ton) 2000 7.7 14.2 10.95 0.625 

Bottom ash ($/ton) 250 18.4 34.2 26.3 1.21 

Bottom ash ($/ton) 500 15.2 28.1 21.65 1 

Bottom ash ($/ton) 1000 12.1 22.4 17.25 0.79 

Bottom ash ($/ton) 2000 9.7 17.9 13.8 0.63 

Combined ash ($/ton) 250 NA NA NA 1.24 

Combined ash ($/ton) 500 NA NA NA 1 

Combined ash ($/ton) 1000 NA NA NA 0.797 

Combined ash ($/ton) 2000 NA NA NA 0.632 

Source: U.S. EPA, 1985. 

NA – Not applicable. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-1 

CHAPTER 6 

FGD WASTEWATER COST METHODOLOGY 

EPA estimated capital, operating and maintenance (O&M), 6-, and 10-year recurring 

costs associated with installing three technology options for FGD wastewater: 

 One-Stage Chemical Precipitation; 

 One-Stage Chemical Precipitation followed by Biological Treatment; and 

 One-Stage Chemical Precipitation followed by Vapor-Compression Evaporation. 

EPA estimated the chemical precipitation, biological treatment, and vapor-compression 

evaporation system costs separately, and then summed the costs generated by the appropriate 

technology cost modules to achieve the total technology option costs (i.e., the chemical 

precipitation costs were added to the biological treatment and vapor-compression evaporation 

costs to calculate the total costs for the technology option). This chapter presents the cost 

methodologies used for chemical precipitation (Section 6.1), biological treatment (Section 6.2), 

and vapor-compression evaporation (Section 6.3). All tables and figures referenced in this 

chapter are presented at the end of the chapter. 

6.1 CHEMICAL PRECIPITATION

EPA estimated capital and O&M costs associated with installing and operating a onestage chemical precipitation treatment system to treat flue gas desulfurization (FGD) wastewater, 

specifically designed and operated to remove mercury and arsenic (and other heavy metals). All 

costs are estimated in 2010 dollars. 

6.1.1 Technology Description

Chemical precipitation involves forming a separable solid substance from a solution, 

typically by converting the soluble constituents to insoluble forms. The precipitated solids are 

then removed from solution by flocculation followed by sedimentation and/or filtration. Figure 

6-1 at the end of this chapter shows a typical one-stage chemical precipitation process for metals 

removal for FGD wastewater. A chemical precipitant is added to the metal-containing water in a 

stirred reaction vessel. The dissolved metals are converted to an insoluble form by a chemical 

reaction between the soluble metal and the precipitant. Precipitation is caused by adding 

chemical precipitants that adjust the pH of the water to the minimum solubility of the target 

metal(s) (see Figure 6-2). 23 The suspended particles are then flocculated and settled in a clarifier. 

Multiple precipitants can remove metals in a variety of forms with differing solubilities (e.g., 

metal hydroxides and metal sulfides). Also, using multiple stages of precipitation and solids 

separation can be used to remove multiple target metals that exhibit minimum solubility at 

different pH levels. Filtration can also be used for wastewater polishing to remove remaining 

suspended metal precipitates. 

 

23 Figure 6-2 shows the minimum solubilities of common metals at various pH values. This figure was developed 

based on empirical studies using single metal solutions in reagent-free water. Minimum metal solubilities in 

complex wastewater may differ from those shown in Figure 6-2. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-2 

Hydroxide precipitation is the predominant type of chemical precipitation used by the 

steam electric industry for FGD wastewater treatment. Hydroxide precipitation typically involves 

using calcium hydroxide (lime) as the precipitant to convert dissolved metals to insoluble metal 

hydroxides. The reaction is illustrated by the following equation: 

Mn+ + 0.5nCa(OH)2 → M(OH)n + 0.5nCa2+ 

The effluent metals concentrations attained by hydroxide precipitation depend on the 

metals present, precipitant used, the reaction conditions (especially pH), and the presence of 

other materials that may inhibit or enhance precipitation. Specifically, to enhance precipitation, 

the steam electric power generating industry commonly adds the chemical reagent ferric chloride 

to induce iron coprecipitation, whereby dissolved metals and metal hydroxides are enmeshed by 

iron precipitates, improving their removal. While the mechanics of iron coprecipitation reactions 

are not understood in all cases, the following is an example reaction: 

Mn+ + FeCl3 + 3H2O → Fe(OH)3•M + 3H+

Some steam electric power plants use sulfide precipitation in addition to hydroxide 

precipitation. Sulfide precipitation typically uses organosulfide as the precipitant to convert 

dissolved metals to insoluble metal sulfides. The sulfide precipitation process can (for many 

metals) achieve lower effluent metals concentrations than hydroxide precipitation because metal 

sulfides often have lower solubility limits than metal hydroxides (see Figure 6-2). The sulfide 

precipitation reaction is illustrated by the following equation: 

Mn+ + 0.5nS2- → MS0.5n

EPA has based compliance cost estimates on a one-stage chemical precipitation 

technology to treat FGD wastewater generated by the steam electric industry, specifically 

designed and operated to remove the target metals mercury and arsenic, as well as other metals 

that are pollutants of concern (see Figure 6-1). This technology can be operated as either standalone metals treatment or for metals treatment preceding either biological treatment or vaporcompression evaporation. 

EPA based the design on an evaluation of the one-stage FGD chemical precipitation 

treatment systems operated by three steam electric power plants sampled by EPA whose effluent 

data were used to represent the best performance of FGD chemical precipitation. EPA used the 

performance data from these plants to develop Best Available Technology Economically 

Achievable (BAT) limitations and Best Available Demonstrated Control Technology (BADCT, 

also referred to as New Source Performance Standards (NSPS)) standards. For the purposes of 

the discussion in this document, these three plants are referred to as the “BAT plants” for the 

chemical precipitation technology option for FGD wastewater. Major components of the design 

basis for this technology include: 

 Equalization tank; 

 Reaction tank 1 for lime addition to a pH set point of 8.5 S.U. to 9.2 S.U.; 

 Reaction tank 2 for organosulfide addition; 
Chapter 6 - FGD Wastewater Cost Methodology 

6-3 

 Reaction tank 3 for ferric chloride addition; 

 Chemical feed systems; 

 Solids contact clarifier; 

 Sand filters; 

 Treated wastewater tank; 

 Sludge filter press; and 

 Sludge holding tank. 

6.1.2 Population Costed

Based on information from the Questionnaire for the Steam Electric Power Generating 

Effluent Guidelines (Steam Electric Survey), EPA identified 117 plants discharging FGD 

wastewater. 24 EPA estimated costs for these 117 plants to install a one-stage chemical 

precipitation system to treat their FGD wastewater. EPA identified plants that have announced 

plans to retire generating units prior to December 31, 2014 as described in Section 4.4.1. There 

are no conversion costs for plant that are already planned to retire prior to implementation of the 

Steam Electric effluent limitations guidelines and standards (ELGs). 

6.1.3 Credit for Chemical Precipitation Treatment in Place

EPA evaluated plant responses to the Steam Electric Survey for the 117 plants identified 

as discharging FGD wastewater to determine whether chemical precipitation technologies are 

currently in place to treat FGD wastewater. As appropriate, these plants were given credit for 

having “treatment in place” for any system elements that matched the chemical precipitation 

design basis. EPA estimated compliance costs for these plants for only the system elements they 

did not have in place. 

Based on a review of survey responses, EPA identified a total of 41 plants that either 

operated chemical precipitation systems FGD wastewater treatment in 2009, or planned to 

operate systems prior to January 1, 2014. EPA did not identify any plants planning to install and 

operate systems after January 1, 2014. For this analysis, EPA did not assign treatment in place 

credit for plants that (1) operated chemical precipitation systems to treat wastewaters other than 

FGD wastewater (e.g., chemical precipitation of metals cleaning wastewater), or (2) operated 

FGD wastewater treatment technologies other than chemical precipitation (e.g., solids settling in 

surface impoundments, solids separation technologies such as clarifiers without precipitation). 

EPA gave full treatment-in-place credit to the BAT plants and those plants with existing 

treatment beyond BAT. The only costs these plants are estimated to incur are compliance 

monitoring costs and costs for a mercury analyzer, described in Sections 5.2 and 6.1.9 

respectively. 

 

24 When the group of plants excluding oil-fired uints and units with a capacity of 50 MW or less is evaluated, the 

population of plants discharing FGD wastewater includes 116 plants. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-4 

For the remaining plants operating FGD chemical precipitation systems, EPA assessed 

each of the major equipment components using the general methodology listed below. Certain 

plant-specific deviations are described in the Supplemental Costs and Loadings Documentation 

(DCN SE01825.A82). 

 Equalization tank and mixer – The chemical precipitation design basis includes 

equalization with 24-hour residence time. EPA identified all plants with existing 

equalization tanks as having equalization in place; however, plants reporting less than 

24-hour residence time were assessed only partial credit (see the Equalization Tank 

Cost discussion within Section 6.1.6.2 for the partial credit methodology). 

 Reaction tanks and mixers – Treatment in place for reaction tanks was assessed as 

follows: 

- Plants currently adding lime (or alternative precipitant such as caustic), 

organosulfide, and ferric chloride received full treatment-in-place credit for 

reaction tanks, regardless of the number of existing reaction tanks. 

- Plants with three or more existing reaction tanks received full treatment-in-place 

credit for reaction tanks, regardless of current chemical addition. 

- Plants without lime or caustic addition were costed for reaction tank 1. 

- Plants without organosulfide or ferric chloride addition, and with fewer than three 

existing reaction tanks, were costed for reaction tanks 2 and/or 3. 

 Chemical feed systems (including chemical storage tanks) – Treatment-in-place credit 

for chemical feed systems was assessed as follows: 

- Plants currently adding chemicals included in the BAT design basis were assumed 

to have their respective chemical feed systems and received full treatment-inplace credit for these systems. 

- Plants that do not currently add organosulfide, but reported the capability to add 

organosulfide in response to Question D5-6 of the survey, received full treatmentin-place credit for an organosulfide feed system. 

- Plants that do not currently add lime (or alternative precipitant such as caustic) or 

ferric chloride were costed for these feed systems. 

- Plants that do not currently add polymer or acid were assumed not to need to add 

these chemicals for operation of their chemical precipitation systems and were not 

costed for these chemical feed systems. 

 Solids contact clarifier (including sludge pumps) – Plants with existing clarifier(s) 

were assumed to have adequate clarification treatment in place, regardless of the 

number, type, or capacity of the clarifiers. 

 Sand filters – Plants with existing sand or other gravity filtration were assumed to 

have adequate filtration treatment in place, regardless of the number, type, or capacity 

of the filters. 

 Treated wastewater tank – Plants with existing treated wastewater tank(s) were 

assumed to have adequate holding capacity, regardless of the number or capacity of 

the treated wastewater tanks. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-5 

 Sludge filter press (including feed/pressurization pumps) – Plants with existing sludge 

filter press(es) were assumed to have adequate sludge dewatering capability, 

regardless of the number, type, or capacity of the filter presses. 

 Sludge holding tank and mixer - Plants with existing sludge holding tanks were 

assumed to have adequate sludge holding capacity, regardless of the number or 

capacity of the sludge holding tanks. 

 Biological treatment or vapor-compression evaporation feed tank – Plants with 

existing biological treatment or vapor-compression evaporation were assumed to have 

adequate wastewater holding capacity in place, regardless of the number and capacity 

of these holding tanks. 

 Wastewater pumps – All plants operating chemical precipitation were assumed to 

have adequate wastewater pumps. 

EPA assumed that plants with existing FGD chemical precipitation would not incur 

additional incremental O&M costs as a result of any costed treatment upgrades. One exception is 

compliance monitoring costs, which were included for all plants. Another exception is chemical 

addition, which was assessed as follows: 

 Plants currently not adding lime (or alternative precipitant such as caustic), 

organosulfide, or ferric chloride were costed for the full target chemical dosage for 

these chemicals. 

 Plants that add organosulfide and/or ferric chloride, but in dosages less than the target 

chemical dosages, were costed for the incremental chemical addition required to 

achieve the target chemical dosage. The incremental chemical dosage required was 

calculated as the difference between the target chemical dosage and the current plant 

dosage. 

 Plants adding lime or alternative precipitant, regardless of dosage, were assumed to 

have adequate precipitant dosage. 

 Plants not currently adding polymer or acid were assumed not to need these 

chemicals for operation of their chemical precipitation systems. 

EPA did not estimate cost savings for plants considered to have treatment in place that 

“goes beyond” the technology options. For example, if EPA identified a plant with chemical 

dosage rates that exceed the required dosages for the technology option, EPA did not assume that 

the plant would reduce their chemical dosage rates and receive a corresponding cost savings. 

As discussed previously, some plants currently treat their FGD wastewater in surface 

impoundment systems. EPA’s cost estimates are based on the assumption that plants will redirect 

their FGD wastewater from the surface impoundment systems to a new tank-based chemical 

precipitation system. For plants identified as “high flow” FGD plants (see Section 4.4.3) and 

flagged in the input table as having dedicated FGD surface impoundments, EPA evaluated 

whether it would be cost effective for these plants to install equalization tanks to hold all of the 

FGD wastewater flow or to continue operating a dedicated FGD surface impoundment. For these 

high flow plants, EPA determined that continuing to operate an FGD surface impoundment 

would be more cost effective than installing equalization tanks for the full FGD wastewater flow. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-6 

Therefore, EPA assessed an equalization treatment in place credit for these high flow plants with 

dedicated FGD surface impoundments based on the assumption that the plants would continue to 

operate their surface impoundments. See the Supplemental Costs and Loadings Documentation 

(DCN SE01825.A56) for additional information. 

6.1.4 Input Table

As discussed in Section 4.1.1, EPA used survey data to identify which plants discharge or 

have the potential to discharge FGD wastewater and estimated FGD wastewater compliance 

costs for these plants. The “FGD Input Table” holds certain plant-specific data needed to 

calculate the technology option cost for all FGD wastewater treatment technologies. The “FGD 

Input Table” contains the following fields: 

 Plant_id: Survey Plant ID. 

 FGD_Wastewater_gpd: The flow rate of FGD wastewater at each plant in gallons 

per day. 

 CBI_FGD_Cost: Flag indicating that the resulting FGD cost estimate should be 

considered confidential business information (CBI). CBI flag is marked if any data 

used to populate the input table were marked as CBI by the plant. 

 Retired?: Flag indicating that the plant has identified that it will be retiring on or 

before 12/31/2014. 

The discussion of the “FGD Input Table” in Section 4.1.1 provides more detail on the 

methodology used to determine which plants discharge FGD wastewater and the plant-specific 

FGD wastewater flow rate. A copy of the “FGD Input Table” is included in the appendix. 

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

Certain variables are used throughout the chemical precipitation, biological treatment, 

and vapor-compression evaporation methodologies when estimating capital and O&M costs for 

plants. These key variables are defined and described below. 

 FGD Wastewater Flow GPM: Wastewater flow rate in gallons per minute (gpm) as 

provided by plants in response to Question B5-2 of the survey.25 This flow is used to 

size and cost the wastewater forwarding pumps that transfer FGD wastewater from 

the FGD system to the FGD treatment system equalization tank. 

 FGD Wastewater Flow GPD: Wastewater flow rate in gallons per day (gpd) as 

provided by plants in response to Question B5-2 of the survey. It is used to calculate 

FGD wastewater treatment flow, which is used throughout Section 6.1 of this report. 

FGD Wastewater Flow GPD is also used in Section 6.1.6.2 to size and cost the FGD 

treatment system equalization tank (assuming 24-hour equalization residence time) 

and in Section 6.1.7.1 to calculate the annual cost of operating labor for the FGD 

treatment system. 

 

25 Typical amount of FGD scrubber purge (or slurry discharge) sent to wastewater treatment or discharge. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-7 

 FGD Wastewater Treatment Flow GPM: Average plant flow rate after equalization 

in gpm. EPA calculated this flow rate assuming that the wastewater treatment plant 

operates 24 hours per day (hpd) and 365 days per year (dpy). It is calculated as FGD 

Wastewater Flow GPD/(24 hpd × 60 minutes per hour). This flow is used to size the 

majority of components in the FGD treatment system. Note that when estimating 

purchased equipment costs, EPA assumed a minimum FGD Wastewater Treatment 

Flow GPM of 20 gpm. 

 Capacity Factor: The capacity factor accounts for the difference between the 

maximum design flow rate and typical flow rate of the FGD wastewater treatment 

system (see Question D5-3 of the survey). That is, treatment systems are sized based 

on maximum design flow to accommodate expected variation in FGD wastewater 

treatment flow rates. EPA determined a median capacity factor of [Redacted] based 

on an assessment of the ratio of maximum design flow to typical flow at plants 

operating FGD wastewater chemical precipitation treatment systems, as calculated 

based on responses to Question D5-3 of the survey. See the Supplemental Costs and 

Loadings Documentation (DCN SE01825.A45) for additional information. 

 Sludge Factor: Ratio of the design sludge generation rate to the FGD Wastewater 

Treatment Flow GPM. After excluding obviously erroneous Steam Electric Survey 

responses, EPA selected a median factor of 0.4. See the Supplemental Costs and 

Loadings Documentation (DCN SE01825.A34) for additional information. 

 Miles: Miles transported for estimating freight costs of purchased equipment for the 

FGD treatment system. EPA assumed that equipment would need to be transported 

500 miles, on average. 

 Flatbed Truck Cost: The cost for a full equipment shipment via flatbed truck 

transported approximately 500 miles. EPA based this cost [Redacted] on information 

from Siemens. See the Supplemental Costs and Loadings Documentation (DCN 

SE01825.A41) for additional information. 

 Truck Weight Capacity: The maximum shipping weight a dry van truck can hold. 

EPA assumed a truck can transport shipments up to 45,000 lbs, based on information 

from FreightCenter.com . See the Supplemental Costs and Loadings Documentation

(DCN SE01825.A1) for additional information. 

6.1.6 Capital Cost Methodology

Total capital costs to treat FGD wastewater with one-stage chemical precipitation are 

obtained by adding the following cost elements: 

Total Capital Cost = Purchased Equipment Cost + Purchased Equipment Installation Cost + 

Building Cost + Land Cost + Site Preparation Cost + Engineering Cost + Construction Expenses 

+ Other Contractor Fees + Contingency Fees 

All costs were adjusted to 2010 dollars using the RSMeans Historical Cost Index. 

Purchased equipment costs for the one-stage chemical precipitation system include the 

following: 
Chapter 6 - FGD Wastewater Cost Methodology 

6-8 

 Purchase of treatment equipment to include: 

- Pumps, 

- Tanks, 

- Chemical feed systems, 

- Mixers, 

- Clarifiers, 

- Filter presses, and 

- Sand filter; 

 Purchase of associated ancillary equipment such as piping, valves, and controllers; 

and 

 Freight. 

EPA did not include costs for spare parts, but instead estimated duplicate costs or excess 

capacity for certain equipment such as pumps and sand filters. (EPA did estimate costs for 

replacement parts – see Maintenance Materials Cost in Section 6.1.7.3.) EPA also did not 

estimate sales tax based on the assumption that specialized chemical precipitation equipment is 

generally not purchased locally. Finally, EPA did not include costs for duties based on the 

assumption that equipment would not be imported from outside the United States. 

EPA estimated purchased equipment costs by requesting quotes from vendors for a 

variety of equipment sizes to accommodate FGD wastewater flow rates ranging from 

approximately 7 to 1,000 gpm and 10,000 to 1,000,000 gpd. Note, however, that EPA assumed a 

minimum FGD Wastewater Treatment Flow GPM of 20 gpm for the purpose of costing 

equipment only. 

For certain equipment, EPA performed regression analyses by plotting equipment 

cost/size data point pairs and developing an equation for the best curve fit. The cost equations 

calculated to fit the cost curves were most commonly polynomial, but may be linear, 

exponential, or logarithmic. For other equipment, EPA developed stepwise cost functions by 

assigning a set cost to each of multiple ranges of flow rates (e.g., cost X for flows ranging from 

A to B, cost Y for flows ranging from C to D, and so on). For yet other equipment, EPA 

developed cost functions based on cost per unit measure (e.g., cost per gallon for tanks) or cost 

per discrete unit (e.g., cost per discrete chemical feed points), which were calculated using 

information provided by vendors. Where appropriate, EPA used a combination of the methods 

described above. 

Freight costs are also included in the purchased equipment cost equations. Freight costs 

were either provided as separate costs by the vendor or calculated based on weight using 

FreightCenter.com. Full truck freight costs were obtained from FreightCenter.com (dry van truck 

freight) and Siemens (flatbed truck freight). FreightCenter.com indicated that the cost to ship a 

full dry van truckload a distance of 500 miles would be approximately $1,400 and that a typical 

truck can hold up to 45,000 pounds [ERG, 2013; See Appendix A1]. Siemens indicated that the 

flat bed truck freight cost is [Redacted] [ERG, 2013; See Appendix A41]. EPA assumed a typical 

transport distance of 500 miles, yielding a cost of [Redacted]. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-9 

Because vendors provided all equipment costs in 2011 dollars, EPA adjusted the cost 

basis to 2010 dollars using the 2010 and 2011 RSMeans Historical Cost Indices (183.5 and 185, 

respectively) [RSMeans, 2011]. 

6.1.6.1 Purchased Equipment Costs: Pumps 

EPA developed pump cost equations based on cost estimates provided by Weir Minerals 

[ERG, 2013; See Appendix A2]. Weir Minerals provided cost estimates for a variety of flow 

rates for each type of pump. Cost estimates include the cost for the equipment, accessories, 

motors, and V drive. All pumps are rubber-lined to accommodate the high chloride 

concentrations (2,000 to 40,000 parts per million (ppm)) present in FGD wastewater. EPA 

plotted cost vs. flow rate for each type of pump and developed best fit equations to calculate 

costs. 

EPA estimated pump freight costs based on weight and a shipping distance of 

approximately 500 miles using quotes from FreightCenter.com [ERG, 2013; See Appendix A7]. 

The freight costs were compared to the equipment costs and a pump freight factor was 

developed. Freight costs for pumps were equal to approximately 3 to 4 percent of purchase costs. 

EPA used a factor of 4 percent (i.e., Pump Freight Factor = 1.04). 

Total pump costs are obtained by adding costs for each type of pump as described by 

Equation 6-1. 

Total Pump Cost = Wastewater Feed Pump Cost + Wastewater Forwarding Pump Cost + Sludge 

Recycle/Transfer Pump Cost + Filter Press Feed/Pressurization Pump Cost + Treated 

Wastewater Discharge Pump Cost + Sump Pump Cost + Lime Slurry Transfer Pump 

 Cost (6-1) 

Wastewater Feed Pump Cost

EPA assumed that plants will use existing FGD wastewater feed pumps to move FGD 

wastewater from the FGD system to the equalization tank of the new chemical precipitation 

treatment system (or to the existing FGD wastewater impoundment, for certain high flow plants 

(see Section 4.4.3). Therefore, EPA assumed no capital or operating and maintenance costs were 

required for wastewater feed pumps. 

Wastewater Forwarding Pump Cost

EPA costed two 100 percent capacity skid-mounted, horizontal centrifugal pumps to 

move FGD wastewater from the equalization tank(s) to reaction tank 1. 

Wastewater Forwarding Pump Cost (2011$) = [2941 × ln(Capacity Factor × FGD Wastewater 

 Flow GPM) – 3090.1] × WWFPump Qty × Pump Freight Factor (6-2) 

where: 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], 
Chapter 6 - FGD Wastewater Cost Methodology 

6-10 

FGD Wastewater Flow 

GPM 

= FGD wastewater flow rate in gpm as reported in the 

Steam Electric Survey (see Section 6.1.5), 

WWFPump Qty = Number of wastewater forwarding pumps, 2, and 

Pump Freight Factor = Factor that accounts for freight cost as a percentage of 

purchase cost (see Section 6.1.6.1), 1.04. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A2 and 

SE01825.A3) for details on the development of Equation 6-2. 

Sludge Recycle/Transfer Pump Cost

EPA costed six sludge recycle/transfer pumps (two for each of two clarifiers (see Section 

6.1.6.5) and two for recycling sludge from the clarifiers to reaction tank 1) for each plant. These 

pumps are 100 percent capacity skid-mounted, rubber-lined, progressive cavity sludge 

recycle/transfer pumps. 

Sludge Recycle/Transfer Pump Cost (2011$) = [0.0841 × (Sludge Factor × FGD Wastewater 

Treatment Flow GPM)2 – 7.2394 × (Sludge Factor × FGD Wastewater Treatment Flow GPM) + 

 7683.8] × Sludge Pump Qty × Pump Freight Factor (6-3) 

where: 

Sludge Factor = Factor to estimate the sludge generation rate based on 

the FGD Wastewater Treatment Flow GPM (see 

Section 6.1.5), 0.4, 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpmnormalized for 24 

hpd operation (see Section 6.1.5), 

Sludge Pump Qty = Number of sludge recycle/transfer pumps, 6, and 

Pump Freight Factor = Factor that accounts for freight cost as a percentage of 

purchase cost (see Section 6.1.6.1), 1.04. 

Filter Press Feed/Pressurization Pump Cost

Filter press pump costs were not estimated separately but are instead included within the 

filter press purchase costs (see Section 6.1.6.6). EPA assumed one pump per filter press and 

costed three filter presses for each FGD wastewater treatment system. The filter press design 

structure is flexible to allow any pump to feed any press. 

Treated Wastewater Discharge Pump Cost

EPA costed two 100 percent capacity skid-mounted, horizontal centrifugal pumps to act 

as treated wastewater discharge pumps, carrying the wastewater out of the chemical precipitation 

system. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-11 

Treated Wastewater Discharge Pump Cost (2011$) = [0.0049 × (Capacity Factor × FGD 

Wastewater Treatment Flow GPM)2

 + 8.2408 × (Capacity Factor × FGD Wastewater Treatment 

 Flow GPM) + 7758.6] × Pump Freight Factor × Effluent Pump Qty (6-4) 

where: 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

Effluent Pump Qty = Number of treated wastewater discharge pumps, 2, and 

Pump Freight Factor = Factor that accounts for freight cost as a percentage of 

purchase cost (see Section 6.1.6.1), 1.04. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A2 and 

SE01825.A4) for details on the development of Equation 6-4. 

Sump Pump Cost

EPA costed two 100 percent capacity skid-mounted, sump pumps. 

Sump Pump Cost (2011$) = [15.799 × (Capacity Factor × FGD Wastewater Treatment Flow 

 GPM) + 7685.9] × Pump Freight Factor × Sump Pump Qty (6-5) 

where: 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

Sump Pump Qty = Number of sump pumps, 2, and 

Pump Freight Factor = Factor that accounts for freight cost as a percentage of 

purchase cost (see Section 6.1.6.1), 1.04. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A2 and 

SE01825.A5) for details on the development of Equation 6-5. 

Lime Slurry Transfer Pump Cost

The lime slurry feed system does not require lime slurry transfer pumps (see Section 

6.1.6.3). 
Chapter 6 - FGD Wastewater Cost Methodology 

6-12 

FGD Recycle Pump and Piping Cost

For “high flow” plants (see Section 4.4.3), EPA costed two 100 percent capacity skidmounted, horizontal centrifugal pumps (same pump type as the Wastewater Forwarding Pump) 

to move wastewater from the equalization tank(s) or surface impoundment system back to the 

FGD system.26 EPA costed these pumps for only those “high flow” plants identified as having an 

operating chloride concentration of less than 80 percent of the design concentration. 

FGD Recycle Pump Cost (2011$) = [2941 × ln(Capacity Factor × New FGD Treatment Flow) – 

 3090.1] × FGDRecPump Qty × Pump Freight Factor (6-6) 

where: 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], 

New FGD Treatment 

Flow 

= The flow rate of FGD wastewater recycled back to the 

FGD scrubber in gallons per minute (see Section 4.4.3 

and Equation 4-13), 

FGDRecPump Qty = Number of FGD recycle pumps, 2, and 

Pump Freight Factor = Factor that accounts for freight cost as a percentage of 

purchase cost (see Section 6.1.6.1), 1.04. 

EPA also costed each “high flow” plant implementing recycle for a length of fiberglass 

reinforced plastic (FRP) pipe to transport the FGD wastewater from the equalization tank or 

FGD surface impoundment back to the FGD system. The total cost of the piping is dependent on 

both the size and the length of piping needed. Pipe size is a step function based on FGD 

wastewater flow rate. Pipe length was determined using data from responses to the Steam 

Electric Survey. 

For “high flow” plants continuing to operate dedicated FGD surface impoundments, EPA 

used latitude and longitude data from responses to Questions A3-2 and A5-1 to calculate a 

distance from the center of the plant to the FGD surface impoundment identified in the survey. 

EPA assumed that the FGD system is located within the main plant area. From these plantspecific surface impoundment distances, EPA calculated the average distance to the FGD surface 

impoundment to be 4,481 feet. 

For “high flow” plants without a dedicated FGD surface impoundment, EPA assumed the 

FGD wastewater will be recycled from the equalization tanks back to the FGD system. To 

calculate this distance, EPA took an average of the distance between the FGD system and the 

wastewater treatment system, as reported in Part D Section 2 Question D2-7 

(Pond/Impoundment System and Wastewater Treatment System Identification) of the Steam 

 

26 Of the 12 “high flow” plants, seven operate dedicated FGD surface impoundments. As discussed in Section 4.4.3, 

EPA determined that it would be more cost effective for these plants to continue to operate these ponds in place of 

installing equalization tanks. EPA costed the remaining five “high flow” plants to install and operate equalization 

tanks. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-13 

Electric Survey. EPA calculated the average distance between the FGD system and the FGD 

wastewater treatment system to be 1,610 feet. 

EPA also estimated freight costs for the piping based on weight and a shipping distance 

of approximately 500 miles using quotes from FreightCenter.com. Freight costs were equal to 

approximately 8 percent of purchase costs (i.e., Freight Factor = 1.08). 

EPA used a step-wise function based on FGD recycle flow, pipe size, and pressure drop 

to calculate the total cost of piping from the equalization tank or FGD surface impoundment 

back to the FGD system. 

 For FGD recycle flow ≤ 158,400 gpd (2 inch pipe) 

- Pipe Cost (2011$) = $11.13 dollars per foot × PipeLength × PipeFreightFactor 

 For 158,400 gpd < FGD recycle flow ≤ 288,000 gpd (3 inch pipe) 

- Pipe Cost (2011$) = $15.40 dollars per foot × PipeLength × PipeFreightFactor 

 For 288,000 gpd < FGD recycle flow ≤ 576,000 gpd (4 inch pipe) 

- Pipe Cost (2011$) = $19.65 dollars per foot × PipeLength × PipeFreightFactor 

 For 576,000 gpd < FGD recycle flow ≤ 1,008,000 gpd (6 inch pipe) 

- Pipe Cost (201$) = $24.01 dollars per foot × PipeLength × PipeFreightFactor 

 For 1,008,000 gpd < FGD recycle flow ≤ 1,584,000 gpd (8 inch pipe) 

- Pipe Cost (2011$) = $31.20 dollars per foot × PipeLength × PipeFreightFactor 

 For 1,584,000 gpd < FGD recycle flow ≤ 2,880,000 gpd (10 inch pipe) 

- Pipe Cost (2011$) = $41.00 dollars per foot × PipeLength × PipeFreightFactor 

 For 2,880,000 gpd < FGD recycle flow ≤ 4,320,000 gpd (12 inch pipe) 

- Pipe Cost (2011$) = $51.81 dollars per foot × PipeLength × PipeFreightFactor 

where: 

FGD recycle flow = The flow rate of FGD wastewater recycled back to the 

scrubber in gpd, from the “High Flow FGD Input 

Table” (see Section 4.4.3), 

PipeLength = The length of pipe required based on the method of 

equalization (tank or existing FGD surface 

impoundment). Distance is 1,610 feet for an 

equalization tank and 4,481 feet for an existing FGD 

surface impoundment, and 

Pipe Freight Factor = Factor that accounts for freight cost as a percentage of 

purchase cost, 1.08. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A55) for 

details on the development of Equation 6-6 and the equations used to estimate pipe cost. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-14 

6.1.6.2 Purchased Equipment Costs: Tanks 

This section describes EPA’s development of cost equations for tanks, including 

wastewater and sludge tanks, and chemical storage and preparation tanks. EPA obtained tank 

costs for wastewater and sludge tanks constructed of FRP from Augusta Fiberglass and tanks 

constructed of carbon steel from Fisher Tank Company and Bendel Tank and Heat Exchanger 

Corporation. 

The cost model estimates costs for plants to install and operate wastewater and sludge 

tanks as required for the chemical precipitation treatment systems. Based on an evaluation of 

survey responses regarding wastewater treatment tank materials of construction, and in 

consideration of estimated costs, EPA assumed the equalization tank will be constructed of lined 

carbon steel while the reaction tanks, sludge tanks, effluent tanks, and feed tanks will be 

constructed of FRP. All tanks are open top designed to operate at atmospheric pressure and 

include ancillary equipment such as structural supports, ladders, access walkways, piping, and 

valves. Many of the tanks require mixers, which are costed separately in Section 6.1.6.4. 

EPA calculated tank sizes using wastewater flow rate and tank hydraulic residence time. 

EPA determined the target residence time for each tank based on an evaluation of the residence 

times of the tanks operated by the BAT plants. Tanks do not require a capacity factor because 

EPA’s evaluation of tank residence times for BAT plants accounts for excess capacity. 

FRP tank costs are primarily based on tank capacity. Additionally, the vendor (Augusta 

Fiberglass) indicated that, to account for nozzles, baffles, or other needed ancillary equipment, 

tank costs should be escalated by 15 percent, which EPA has included as a factor in 

Equations 6-7 and 6-8. 

For tanks from 10,000 to 50,000 gallons in volume: 

 Cost (2011$) = $1.25/gal × Tank Size × Ancillary Equipment Factor (6-7)

For tanks from 50,000 to 250,000 gallons in volume: 

 Cost (2011$) = $2/gal × Tank Size × Ancillary Equipment Factor (6-8) 

where: 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Tank Size = The size of the tank, in gallons, calculated by 

multiplying the FGD wastewater flow by the residence 

time required. Tank size equations specific to the type 

of tank (e.g., reaction tank 1) are provided in the 

description for each tank type, presented later in this 

section. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-15 

Augusta Fiberglass stated that tanks smaller than 10,000 gallons (which equates to a FGD 

wastewater treatment flow rate of 56 gpm) would need to be costed on a case-by-case basis. 

Augusta Fiberglass stated that the primary difference in costs between tanks 10,000 to 50,000 

gallons in size and 50,000 to 250,000 gallons in size is that the smaller size tanks can be shopfabricated and shop-erected while the larger tanks must be shop-fabricated and field-erected; 

therefore, EPA assumed tanks less than 10,000 gallons in size can also be shop-erected and can 

be costed using the same equation as for tanks 10,000 to 50,000 gallons in size. 

Augusta Fiberglass stated that the maximum feasible tank size for a shop-fabricated, 

field-erected tank is 250,000 gallons. Beyond this size, tanks must be built entirely at the plant, 

requiring the vendor to construct a shop on site as well. Therefore, in those cases where FRP 

tanks larger than 250,000 gallons are required, multiple tanks of equal size are costed using the 

same pricing as tanks 50,000 to 250,000 gallons in size. For example, for a plant requiring a 

260,000 gallon tank, two 130,000 gallon tanks are costed. 

Additionally, Augusta Fiberglass provided freight cost estimates in dollars per mile for 

certain tank sizes [ERG, 2013; See Appendix 10]. EPA developed a cost function based on the 

data provided to estimate freight costs based on tank volume. 

 Tank Freight Cost (2011$) = Miles × 0.0454 × (Tank Size)0.5481 (6-9)

where: 

Miles = Expected average tank shipping distance, in miles, 

between tank supplier and plant, 500, and 

Tank Size = The size of the tank, in gallons, calculated by 

multiplying FGD wastewater flow by the residence 

time of the tank. Tank size equations specific to the 

type of tank are provided in the descriptions for each 

tank type, presented later in this section. 

EPA obtained costs for shop-fabricated carbon steel tanks from Bendel Tank and Heat 

Exchanger Corporation (Bendel) and costs for field-fabricated carbon steel tanks from Fisher 

Tank Company. 

Bendel indicated the maximum size carbon steel tank that could be shop-fabricated is 

70,000 gallons [ERG, 2013; See Appendix 13]. EPA requested purchase and freight costs for 

tanks ranging in size from 2,000 gallons to 70,000 gallons. Based on information provided by 

Bendel, EPA developed Equations 6-10 and 6-11 for tank purchase and freight costs. 

 Tank Purchase Cost (2011$) = 0.9412 × Tank Size + 4117.6 (6-10) 

 Tank Freight Cost (2011$) = 0.064 × Tank Size + 522.06 (6-11)
Chapter 6 - FGD Wastewater Cost Methodology 

6-16 

where: 

Tank Size = The size of the tank, in gallons, calculated by 

multiplying the FGD wastewater flow by the residence 

time of the tank. Tank size equations specific to the 

type of tank are provided in the descriptions for each 

tank type, presented later in this section. 

Due to the corrosive nature of FGD wastewater, the carbon steel tanks require a liner and/or 

coating. EPA requested liner and coatings costs and information from TSE, Inc., a representative 

of Tnemec Company. The vendor recommended using Tnemec’s Series 61 Tneme-Liner system 

and provided an estimated installed cost of $8-10 per square foot of internal tank surface 

area[ERG, 2013; See Appendix 13]. The installed cost includes the cost of the material, surface 

preparation, and labor to install a multicoated epoxy lining system. Based on information from 

the liner and tank vendors, EPA developed an expression for the internal surface area of a tank 

based on the tank’s volume and multiplied this expression by the liner cost per square foot to 

develop a liner cost equation. To be conservative, EPA assumed a liner cost of $10 per square 

foot. EPA used Equation 6-12 to estimate liner costs. 

 Liner Cost (2011$) = Liner Cost Per Square Foot × 2.0885 × (Tank Size)0.6282 (6-12) 

where: 

Liner Cost Per Square 

Foot 

= The installed cost, in dollars, of Tnemec’s Series 61 

Tneme-Liner system per square foot of internal surface 

area of the tank, $10, and 

Tank Size = The size of the tank, in gallons, calculated by 

multiplying FGD wastewater flow by the residence 

time of the tank. Tank size equations specific to the 

type of tank are provided in the descriptions for each 

tank type, presented later in this section. 

The total cost for carbon steel tanks up to 70,000 gallons can be calculated as the sum of 

the tank purchase cost (Equation 6-10), tank freight cost (Equation 6-11), and liner cost 

(Equation 6-12). 

 Cost (2011$) = Tank Purchase Cost + Tank Freight Cost + Liner Cost (6-13) 

Cost (2011$) = (0.9412 × Tank Size + 4117.6) + (0.064 × Tank Size + 522.06) + [Liner Cost Per 

 Square Foot × 2.0885 × (Tank Size)0.6282] (6-14) 

where: 

Liner Cost Per Square 

Foot 

= The installed cost, in dollars, of Tnemec’s Series 61 

Tneme-Liner system per square foot of internal surface 
Chapter 6 - FGD Wastewater Cost Methodology 

6-17 

area of the tank, $10, and 

Tank Size = The size of the tank, in gallons, calculated by 

multiplying FGD wastewater flow by the residence 

time of the tank. Tank size equations specific to the 

type of tank are provided in the descriptions for each 

tank type, presented later in this section. 

Fisher Tank Company indicated that field-fabricated tank sizes range from 30,000 gallons 

to 10 million gallons. EPA requested costs for five tank sizes ranging from 30,000 gallons to 1.5 

million gallons. The cost estimates provided by Fisher Tank Company included all material, 

labor, and equipment necessary to design, supply, fabricate, transport, erect, and test the tanks at 

the plant site, as well as transportation [ERG, 2013; See Appendices 16 and 17]. Additionally, 

flake glass interior linings are included in the tank cost estimates. Based on the estimates 

provided, EPA developed Equation 6-15 for carbon steel tanks over 70,000 gallons in size. 

 Cost (2011$) = -6×10-8 × (Tank Size)2

 + 0.628 × (Tank Size) + 503999 (6-15) 

where: 

Tank Size = The size of the tank, in gallons, calculated by 

multiplying FGD wastewater flow by the residence 

time of the tank. Tank size equations specific to the 

type of tank are provided in the descriptions for each 

tank type, presented later in this section. 

Because the cost estimates provided already included transportation and liner costs, no 

additional terms are necessary. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A8 through 

A19, A81, and A85) for additional information regarding the development of the equations used 

to estimate the costs associated with FRP and steel tanks. 

Equalization Tank Cost

The purpose of the equalization tank is to accumulate wastewater to reduce wastewater 

variability and to optimize the size, effectiveness, and operating costs for the subsequent 

treatment units. The cost varies based on flow rate. The following equations are used to cost 

tanks with the specified ranges of FGD Wastewater Flow GPD (see Section 6.1.5 for a 

discussion of FGD Wastewater Flow GPD). The hydraulic residence time (HRT) for the 

equalization tank(s) is assumed to be one day (i.e., 24 hours). EPA costed lined carbon steel 

equalization tanks. 

Because lined carbon steel tanks can be provided in sizes up to 10 million gallons in 

volume, EPA assumed one equalization tank would be sufficient for all plants, with the 

exception of “high flow” plants (discussed in Section 4.4.3). 
Chapter 6 - FGD Wastewater Cost Methodology 

6-18 

EPA first calculated equalization tank size using the equations for carbon steel tanks 

described earlier in this section: 

Equalization Tank Size (gal) = FGD Wastewater Flow GPD × Equalization Tank HRT (6-16) 

where: 

FGD Wastewater Flow 

GPD 

= FGD wastewater flow rate in gpd as reported in the 

Steam Electric Survey (see Section 6.1.5), and 

Equalization Tank HRT = The hydraulic residence time of the equalization tank in 

days, 1. 

EPA then calculated the equalization tank cost based on the size of the tank. 

For tanks less than or equal to 70,000 gallons in size EPA estimated costs using Equation 

6-17. 

Equalization Tank Cost (2011$) = (0.9412 × Equalization Tank Size + 4117.6) + (0.064 × 

Equation Tank Size+ 522.06) + [Liner Cost Per Square Foot × 2.0885 × (Equalization Tank 

 Size)0.6282] (6-17)

where: 

Liner Cost Per Square 

Foot 

= The installed cost, in dollars, of Tnemec’s Series 61 

Tneme-Liner system per square foot of internal surface 

area of the tank, $10, and 

Equalization Tank Size = Equalization tank size, in gallons (see Equation 6-16). 

For tanks greater than 70,000 gallons in size EPA estimated costs using Equation 6-18. 

Equalization Tank Cost (2011$) = -6×10-8 × (Equalization Tank Size)2

 + 0.628 × 

 (Equalization Tank Size) + 503999 (6-18) 

where: 

Equalization Tank Size = Equalization tank size, in gallons (see Equation 6-16). 

For plants with equalization treatment in place, EPA first determined the residence time 

of their existing equalization equipment based on their response to Question D5-2 of the Steam 

Electric Survey. If their response is 24 hours or more equalization residence time, or if the plant 

did not report a residence time, then EPA assumed the plant has adequate equalization capacity. 

If their response was less than 24 hours equalization residence time, then EPA estimated costs 

for the additional equalization capacity needed using the cost equations listed above and 

substituting the variable “FGD Wastewater Flow GPD” with “Treatment In Place GPD” which is 
Chapter 6 - FGD Wastewater Cost Methodology 

6-19 

the amount of the FGD wastewater flow GPD that cannot be handled by the existing equalization 

equipment. Treatment In Place GPD is calculated using Equation 6-19. 

Treatment In Place GPD (gpd) = [(24 – Current HRT) / 24] × FGD Wastewater Flow GPD (6-19) 

where: 

Current HRT = Current chemical precipitation equalization residence 

time as reported in response to Question D5-2 of the 

Steam Electric Survey, in hours, and 

FGD Wastewater Flow 

GPD 

= FGD wastewater flow rate in gpd as reported in the 

Steam Electric Survey (see Section 6.1.5). 

Reaction Tank 1 Cost

EPA costed one FRP reaction tank 1 per plant, with a residence time of 3 hours (i.e., 180 

minutes) based on a review of the BAT plants. In reaction tank 1, the wastewater pH is raised 

using lime to precipitate the soluble metals as insoluble hydroxides and oxyhydroxides. The 

reaction tank also desaturates the gypsum in the wastewater, which prevents gypsum scale 

formation in the downstream wastewater treatment equipment. To desaturate the gypsum, some 

of the sludge from the downstream primary clarifier is recycled back to reaction tank 1 to 

provide seed crystals for gypsum nucleation. The cost varies based on flow rate. EPA created a 

step-wise function based on tank size (as described for FRP tanks earlier in this section) to 

estimate the cost for reaction tank 1. The following equations are used to cost tanks with the 

specified FGD wastewater flow rate ranges. 

The tank size breakpoint in the equations described for FRP tanks (Equation 6-7) is 

50,000 gallons. EPA then calculated the maximum flow rate, in gpm, that can be accommodated 

by a reaction tank 1 size of 50,000 gallons. 

 Reaction Tank 1 Breakpoint (gpm) = 50,000 gal / Reaction Tank 1 HRT = 278 gpm (6-20) 

where: 

Reaction Tank 1 HRT = The hydraulic residence time of Reaction Tank 1, in 

minutes, 180. 

Next, EPA calculated the size of reaction tank 1 using Equation 6-21. 

Reaction Tank 1 Size (gal) = FGD Wastewater Treatment Flow GPM × Reaction Tank 1 

 HRT (6-21) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 
Chapter 6 - FGD Wastewater Cost Methodology 

6-20 

Reaction Tank 1 HRT = The hydraulic residence time of reaction tank 1, in 

minutes, 180. 

Based on the FGD wastewater flow, the cost model then chooses which of the following 

equations to use to calculate the tank cost. The first term in the equation calculates the cost of the 

tank itself while the second term in the equation calculates freight costs. 

For FGD Wastewater Treatment Flow GPM less than or equal to the Reaction Tank 1 

Breakpoint GPM (i.e., tanks less than or equal to 50,000 gallons in size) EPA used Equation 

6-22. 

Reaction Tank 1 Cost (2011$) = $1.25/gal × Reaction Tank 1 Size × Ancillary Equipment Factor 

 + Miles × 0.0454 × (Reaction Tank 1 Size)0.5481 (6-22) 

where: 

Reaction Tank 1 Size = Reaction tank 1 size, in gallons (see Equation 6-21), 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Miles = Expected average tank shipping distance, in miles, 

between tank supplier and power plant, 500. 

For FGD Wastewater Treatment Flow GPM greater than the Reaction Tank 1 Breakpoint 

(i.e., tanks greater than 50,000 gallons in size) EPA used Equation 6-23. 

Reaction Tank 1 Cost (2011$) = $2/gal × Reaction Tank 1 Size × Ancillary Equipment Factor + 

 Miles × 0.0454 × (Reaction Tank 1 Size)0.5481 (6-23) 

where: 

Reaction Tank 1 Size = Reaction tank 1 size, in gallons (see Equation 6-21), 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Miles = Expected average tank shipping distance, in miles, 

between tank supplier and power plant, 500. 

Reaction Tank 2 Cost and Reaction Tank 3 Cost

EPA costed one FRP reaction tank 2 and one FRP reaction tank 3 per plant, each with a 

residence time of 1 hour based on a review of the BAT plants. In reaction tank 2, organosulfide 

is added, primarily to remove mercury and aid in the settling of precipitates. In reaction tank 3, 

ferric chloride is added to aid in precipitation of heavy metals. The cost varies based on flow 

rate. Both tanks are the same size as the residence times are the same. The following equations 

are used to cost tanks with the specified FGD wastewater flow rate ranges. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-21 

The tank size breakpoint in the equations described for FRP tanks (Equation 6-7) is 

50,000 gallons. EPA then calculated the maximum flow rate, in gpm, that can be accommodated 

by a reaction tank 2 size of 50,000 gallons. 

 Reaction Tank 2 Breakpoint (gpm) = 50,000 gal / Reaction Tank 2 HRT = 833 gpm (6-24) 

where: 

Reaction Tank 2 HRT = The hydraulic residence time of reaction tank 2, in 

minutes, 60. 

Next, EPA calculated reaction tank 2 size using Equation 6-25. 

Reaction Tank 2 Size (gal) = FGD Wastewater Treatment Flow GPM × Reaction Tank 2 

 HRT (6-25) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Reaction Tank 2 HRT = The hydraulic residence time of reaction tank 2, in 

minutes, 60. 

Based on the FGD wastewater flow, the cost model then chooses which of the following 

equations to use to calculate the tank cost. The first term in the equation calculates the cost of the 

tank itself while the second term in the equation calculates freight costs. 

For FGD Wastewater Treatment Flow GPM less than or equal to the Reaction Tank 2 

Breakpoint (i.e., tanks less than or equal to 50,000 gallons in size) EPA used Equation 6-26. 

Reaction Tank 2 Cost (2011$) = $1.25/gal × Reaction Tank 2 Size × Ancillary Equipment Factor 

 + Miles × 0.0454 × (Reaction Tank 2 Size)0.5481 (6-26) 

where: 

Reaction Tank 2 Size = Reaction tank 2 size, in gallons, (see Equation 6-25), 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Miles = Expected average tank shipping distance, in miles, 

between tank supplier and power plant, 500. 

For FGD Wastewater Treatment Flow GPM greater than Reaction Tank 2 Breakpoint 

(i.e., tanks greater than 50,000 gallons in size) EPA used Equation 6-27. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-22 

Reaction Tank 2 Cost (2011$) = $2/gal × Reaction Tank 2 Size × Ancillary Equipment Factor + 

 Miles × 0.0454 × (Reaction Tank 2 Size)0.5481 (6-27) 

where: 

Reaction Tank 2 Size = Reaction tank 2 size, in gallons, (see Equation 6-25), 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Miles = Expected average tank shipping distance, in miles, 

between tank supplier and power plant, 500. 

Reaction tank 3 is defined in the same way as reaction tank 2. EPA assumed that one FRP 

reaction tank 3 with a 1-hour (i.e., 60 minute) residence time would be sufficient for all of the 

plants. 

The tank size breakpoint in the equations described for FRP tanks (Equation 6-7) is 

50,000 gallons. EPA then calculated the maximum flow rate, in gpm, that can be accommodated 

by a reaction tank 3 size of 50,000 gallons. 

 Reaction Tank 3 Breakpoint (gpm) = 50,000 gal / Reaction Tank 3 HRT = 833gpm (6-28) 

where: 

Reaction Tank 3 HRT = The hydraulic residence time of reaction tank 3, in 

minutes, 60. 

 Next, EPA calculated reaction tank 3 size using Equation 6-29. 

Reaction Tank 3 Size (gal) = FGD Wastewater Treatment Flow GPM × Reaction Tank 3 

 HRT (6-29) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Reaction Tank 3 HRT = The hydraulic residence time of reaction tank 3, in 

minutes, 60. 

Based on the FGD wastewater flow, the cost model then chooses which of the following 

equations to use to calculate the tank cost. The first term in the equation calculates the cost of the 

tank itself while the second term in the equation calculates freight costs. 

For FGD Wastewater Treatment Flow GPM less than or equal to the Reaction Tank 3 

Breakpoint (i.e., tanks less than or equal to 50,000 gallons in size) EPA used Equation 6-30. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-23 

Reaction Tank 3 Cost (2011$) = $1.25/gal × Reaction Tank 3 Size × Ancillary Equipment Factor 

 + Miles × 0.0454 × (Reaction Tank 3 Size)0.5481 (6-30) 

where: 

Reaction Tank 3 Size = Reaction tank 3 size, in gallons, (see Equation 6-29), 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Miles = Expected average tank shipping distance, in miles, 

between tank supplier and power plant, 500. 

For FGD Wastewater Treatment Flow GPM greater than the Reaction Tank 3 Breakpoint 

(i.e., tanks greater than 50,000 gallons in size) EPA used Equation 6-31. 

Reaction Tank 3 Cost (2011$) = $2/gal × Reaction Tank 3 Size × Ancillary Equipment Factor + 

 Miles × 0.0454 × (Reaction Tank 3 Size)0.5481 (6-31) 

where: 

Reaction Tank 3 Size = Reaction tank 3 size, in gallons, (see Equation 6-29), 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Miles = Expected average tank shipping distance, in miles, 

between tank supplier and power plant, 500. 

Flash Mix Tank and Flocculation Tank Cost

The solids contact clarifier vendor indicated that a flash mix and flocculation tank is 

generally not required for polymer addition prior to the solids contact clarifier (i.e., polymer is 

added in line); therefore, EPA did not calculate costs for flash mix and flocculation tanks. Note 

that of the three BAT plants, one injects polymer in line, one adds polymer in a dedicated flash 

mix/splitter tank, and [Redacted]. 

Treated Wastewater Tank Cost

EPA costed one effluent tank per plant with a residence time of one hour, based on the 

BAT plants. EPA assumed that shop-built FRP tanks would serve as the treated wastewater tanks 

at all of the plants. The effluent tanks hold the treated wastewater prior to discharge or other 

reuse/recycling. For stand-alone chemical precipitation treatment systems, these tanks are located 

after chemical precipitation, at the end of the treatment system. For chemical precipitation 

followed by biological treatment or vapor-compression evaporation, these tanks are located at 

the end of the biological treatment or vapor-compression evaporation systems. The cost varies 

based on flow rate as shown in the following equations with the following GPM flow rate 

ranges. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-24 

Because the maximum size for shop-built FRP tanks is 50,000 gallons, multiple tanks are 

costed for plants with large flow rates requiring additional volume. 

Treated WW Tank Qty = Treated WW Tank HRT × FGD Wastewater Treatment Flow GPM / 

 50,000 gal (rounded up to the nearest whole number) (6-32) 

where: 

Treated WW Tank 

HRT 

= The hydraulic residence time of each treated 

wastewater tank, in minutes, 60, and 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5). 

Next, EPA calculated the size of each treated wastewater tank using Equation 6-33. 

Treated WW Tank Size (gal) = FGD Wastewater Treatment Flow GPM × Treated WW Tank 

 HRT / Treated WW Tank Qty (6-33) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

Treated WW Tank 

HRT 

= The hydraulic residence time of each treated 

wastewater tank , in minutes, 60, and 

Treated WW Tank Qty = The number of treated wastewater tanks, rounded up to 

the nearest whole number (see Equation 6-32). 

The cost model then calculates the cost of the tank itself (the first term in Equation 6-34), 

plus freight costs (the second term in Equation 6-34). 

Treated Wastewater Tank Cost (2011$) = [$1.25/gal × Treated WW Tank Size × Ancillary 

Equipment Factor + Miles × 0.0454 × (Treated WW Tank Size)0.5481] × Treated WW Tank 

 Qty (6-34) 

where: 

Treated WW Tank Size = Treated wastewater tank size, in gallons, (see Equation 

6-33), 

Treated WW Tank Qty = The number of treated wastewater tanks, rounded up to 

the nearest whole number, (see Equation 6-32), 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Miles = Expected average tank shipping distance, in miles, 
Chapter 6 - FGD Wastewater Cost Methodology 

6-25 

between tank supplier and power plant, 500. 

Sludge Holding Tank Cost

EPA costed one FRP sludge holding tank per plant, based on the BAT plants. The sludge 

tank receives sludge from the clarifiers. The cost varies based on flow rate. 

The tank size breakpoint in the equations described for FRP tanks (Equation 6-7) is 

50,000 gallons. EPA calculated the maximum flow rate, in gpm, that can be accommodated by a 

sludge holding tank size of 50,000 gallons. 

Sludge Holding Tank Breakpoint (gpm) = 50,000 gal / Sludge Holding Tank HRT = 417 

 gpm (6-35) 

where: 

Sludge Holding Tank 

HRT 

= Factor representing the ratio of sludge tank size to the 

FGD wastewater flow rate, 120. This factor is not a 

residence time; however, the factor is calculated in the 

same way as the wastewater tank residence times and 

its unit is minutes. 

Next, EPA calculated sludge holding tank size using Equation 6-36. 

Sludge Holding Tank Size (gal) = FGD Wastewater Treatment Flow GPM × Sludge Holding 

 Tank HRT (6-36) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Sludge Holding Tank 

HRT 

= Factor representing the ratio of sludge tank size to the 

FGD wastewater flow rate, in minutes, 120. 

Based on the FGD wastewater flow, the cost model then chooses which of the following 

equations to use to calculate the tank cost. The first term in the equation calculates the cost of the 

tank itself while the second term in the equation calculates freight costs. 

For FGD Wastewater Treatment Flow GPM less than or equal to the Sludge Holding 

Tank Breakpoint (i.e., tanks less than or equal to 50,000 gallons in size) EPA used Equation 

6-37. 

Sludge Holding Tank Cost (2011$) = $1.25/gal × Sludge Holding Tank Size × Ancillary 

 Equipment Factor + Miles × 0.0454 × (Sludge Holding Tank Size)0.5481 (6-37) 
Chapter 6 - FGD Wastewater Cost Methodology 

6-26 

where: 

Sludge Holding Tank 

Size 

= Sludge holding tank size, in gallons, calculated as 

described previously in this section, (see Equation 

6-36), 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Miles = Expected average tank shipping distance, in miles, 

between tank supplier and power plant, 500. 

For FGD Wastewater Treatment Flow GPM greater than the Sludge Holding Tank 

Breakpoint (i.e., tanks greater than 50,000 gallons in size) EPA used Equation 6-38. 

Sludge Holding Tank Cost (2011$) = $2/gal × Sludge Holding Tank Size × Ancillary Equipment 

 Factor + Miles × 0.0454 × (Sludge Holding Tank Size)0.5481 (6-38) 

where: 

Sludge Holding Tank 

Size 

= Sludge holding tank size, in gallons, calculated as 

described previously in this section, (see Equation 

6-36), 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Miles = Expected average tank shipping distance, in miles, 

between tank supplier and power plant, 500. 

Biological or Vapor-Compression Evaporation Treatment System Feed Tank Cost

When chemical precipitation treatment is followed by a biological or vapor-compression 

evaporation treatment system, EPA costed one additional FRP feed tank per plant with a 30-

minute residence time. EPA determined the design residence time of the feed tank based on an 

evaluation of feed tanks operated by two steam electric power plants sampled by EPA whose 

effluent data were used to represent the best performance of FGD biological treatment. This tank 

is located after chemical precipitation to hold the effluent from the chemical precipitation system 

and to act as a feed tank for the biological or vapor-compression evaporation treatment systems. 

The cost varies based on flow rate. 

The tank size breakpoint in the equations described for FRP tanks (Equation 6-7) is 

50,000 gallons. EPA then calculated the maximum flow rate, in gpm, that can be accommodated 

by a feed tank size of 50,000 gallons. 

Bio VC Feed Tank Breakpoint (gpm) = 50,000 gal / Bio VC Feed Tank HRT = 1,667 gpm (6-39) 
Chapter 6 - FGD Wastewater Cost Methodology 

6-27 

where: 

Bio VC Feed Tank 

HRT 

= The hydraulic residence time of the biological or 

vapor-compression evaporation treatment system feed 

tank, in minutes, 30. 

Next, EPA calculated the biological or vapor-compression evaporation feed tank size 

using Equation 6-40. 

Bio VC Feed Tank Size (gal) = FGD Wastewater Treatment Flow GPM × Bio VC Feed 

 Tank HRT (6-40) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

BioVC Feed Tank HRT = The hydraulic residence time of the biological or 

vapor-compression evaporation treatment system feed 

tank, in minutes, 30. 

Based on the FGD wastewater flow, the cost model chooses which of the following 

equations to use to calculate the tank cost. The first term in the equation calculates the cost of the 

tank itself while the second term in the equation calculates freight costs. 

For FGD Wastewater Flow GPM less than or equal to the Bio VC Feed Tank Breakpoint 

(i.e., tanks less than or equal to 50,000 gallons in size) EPA used Equation 6-41. 

Biological or Vapor-Compression Evaporation Treatment System Feed Tank Cost (2011$) = 

$1.25/gal × Bio VC Feed Tank Size × Ancillary Equipment Factor + Miles × 0.0454 × (Bio VC 

 Feed Tank Size)0.5481 (6-41) 

where: 

Bio VC Feed Tank Size = Biological or vapor-compression evaporation treatment 

system feed tank size, in gallons, (see Equation 6-40), 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Miles = Expected average tank shipping distance, in miles, 

between tank supplier and power plant, 500. 

For FGD Wastewater Treatment Flow GPM greater than the Bio VC Feed Tank 

Breakpoint (i.e., tanks greater than 50,000 gallons in size) EPA used Equation 6-42. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-28 

Biological or Vapor-Compression Evaporation Treatment System Feed Tank Cost (2011$) = 

$2/gal × Bio VC Feed Tank Size × Ancillary Equipment Factor + Miles × 0.0454 × (Bio VC 

 Feed Tank Size)0.5481 (6-42) 

where: 

Bio VC Feed Tank Size = Biological or vapor-compression evaporation treatment 

system feed tank size, in gallons, (see Equation 6-40), 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Miles = Expected average tank shipping distance, in miles, 

between tank supplier and power plant, 500. 

Filtrate Sump Cost

EPA included costs for plants to construct a concrete basin to act as a filtrate sump 

receiving filtrate from the filter presses and other miscellaneous floor drain wastewater from the 

wastewater treatment plant within the site preparation costs described in Section 6.1.6.11. 

Chemical Preparation and Storage Tanks

EPA estimated costs for plants to install and operate the chemical preparation and storage 

tanks required for chemical precipitation treatment systems. Based on input from vendors, EPA 

expects organosulfide and polymer to be delivered and stored onsite in totes and, therefore, 

organosulfide and polymer chemical storage tanks are not required.27 Ferric chloride and/or 

hydrochloric acid storage tanks are costed for those plants estimated to consume more than one 

275-gallon tote of either of these chemicals per day.28

EPA estimated the costs for chemical storage tanks based on the costs for FRP 

wastewater and sludge tanks provided by Augusta Fiberglass [ERG, 2013; See Appendix 23]. 

All tanks are designed to operate at atmospheric pressure. EPA requested that purchase costs 

provided by vendors also include ancillary equipment, such as structural supports, ladders, 

access walkways, piping, and valves. EPA requested vendor costs for varying sizes of chemical 

preparation and storage tanks appropriate for wastewater flow rates ranging from 7 to 700 gpm, 

and EPA created a cost function using costs obtained from the vendor to extrapolate or 

interpolate costs for each plant based on FGD wastewater flow rate. 

EPA assumed that shop-built FRP tanks would serve as the chemical storage tanks at all 

of the plants, except those expected to use totes for storage. Because the maximum size for shopbuilt FRP tanks is 50,000 gallons, EPA costed multiple tanks where more storage is needed. 

 

27 See Sections 6.1.6.3 and 6.1.7.4 for discussion of costing errors associated with EPA’s organosulfide and polymer 

purchase, freight, storage, and feed systems. 

28 EPA neglected to estimate costs for the purchase or lease of totes for plants assumed to store ferric chloride and 

hydrochloric acid onsite in totes. EPA estimates tote purchase costs would be $2,850 per plant for plants requiring 

totes for onsite storage of only one of the chemicals (i.e., ferric chloride or hydrochloric acid), and $5,700 per plant 

for plant requiring totes for onsite storage of both ferric chloride and hydrochloric acid. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-29 

EPA calculated the chemical storage tank sizes based on the chemical dosages (gallons of 

chemical added per gallon wastewater treated) and the amount of chemical the plant is expected 

to store on site (in days). EPA assumed that a plant will need to store 15 days worth of chemical 

on site (i.e., enough chemical to perform the needed chemical additions for 15 days, based on 

input from vendors). 

Note: see Section 6.1.6.3 (Chemical Feed Systems Cost) for a discussion of the chemical 

dose conversion factors used in the chemical storage tank cost equations. 

Lime Slurry Preparation and Storage Tank Cost. The lime slurry feed system for which 

the vendor provided costs includes a combined preparation and storage tank, as described in 

Section 6.1.6.3. Therefore, EPA did not develop separate cost equations for these tanks. 

Ferric Chloride Storage Tank Cost. EPA costed storage tanks for 35 percent 

concentration ferric chloride for plants with FGD wastewater flow rates greater than the trigger 

flow rate calculated as described below. The trigger flow rate is calculated assuming plants 

requiring more than one tote of ferric chloride per day would install a storage tank, while plants 

requiring less than one tote of ferric chloride per day would not install a storage tank. EPA used 

Equation 6-43 to calculate the ferric chloride trigger flow rate. 

FeCl3 Tank WW Flow Limit (gpm) = (Tote Volume × Totes Per Day / Min Per Day) / (Ferric 

 Chloride Dose × FeCl3 Dose Factor × Capacity Factor × Liter to Gallon Factor) (6-43) 

where: 

Tote Volume = The volume, in gallons, of a standard size chemical 

tote, 275, 

Totes Per Day = The maximum number of totes of chemical a plant 

requires per day above which a plant would install a 

chemical storage tank, 1, 

Min Per Day = Number of minutes per day, 1440, 

Ferric Chloride Dose = Amount of ferric chloride, in g/L, needed to treat the 

FGD wastewater in the chemical precipitation system 

as determined in Section 6.1.7.4, 

FeCl3 Dose Factor = Factor to convert dose from grams of neat chemical per 

liter of FGD wastewater to liters of chemical solution 

per liter of FGD wastewater. See the discussion for 

Liquid Feed Systems in Section 6.1.6.3 for further 

details, 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], and 
Chapter 6 - FGD Wastewater Cost Methodology 

6-30 

Liter to Gallon Factor = Unit conversion factor, equal to 1, which converts liters 

of chemical solution per liter of wastewater to gallons 

of chemical solution per gallon of wastewater. It is 

calculated as: 

ଷ.଻଼ହ ௅ ௪௔௦௧௘௪௔௧௘௥

௚௔௟ ௪௔௦௧௘௪௔௧௘௥

ൈ ௚௔௟ ௖௛௘௠௜௖௔௟ ௦௢௟ᇱ௡

ଷ.଻଼ହ ௅ ௖௛௘௠௜௖௔௟ ௦௢௟ᇱ௡. 

As described above, if the FGD Wastewater Treatment Flow GPM is less than the FeCl3 

Tank WW Flow Limit, EPA assumed that the plant will use totes to store the ferric chloride and, 

therefore, assumed no costs associated with a storage tank. If the FGD Wastewater Treatment 

Flow GPM is greater than the FeCl3 Tank WW Flow Limit, then EPA costed a storage tank 

using tank size and quantity. 

The tank quantity is calculated by dividing the required storage amount of FeCl3 by the 

maximum size for shop-built FRP tanks, as shown in Equation 6-44. 

FeCl3 Tank Qty = FeCl3 Rate × FeCl3 Storage Time /50,000 gal (rounded up to the nearest 

 whole number) (6-44) 

where: 

FeCl3 Rate = Ferric chloride volumetric addition rate in gph. See 

Ferric Chloride Feed System Cost in Section 6.1.6.3 for 

details, and 

FeCl3 Storage Time = The hours of supply of ferric chloride the plant stores 

on site. EPA assumed a plant would keep up to 15 

days’, or 360 hours’, worth of FeCl3 on site. 

FeCl3 Rate = Ferric chloride volumetric addition rate in gph. See 

Ferric Chloride Feed System Cost in Section 6.1.6.3 for 

details, and 

 Next, EPA calculated the FeCl3 tank size using Equation 6-45. 

 FeCl3 Tank Size (gal) = FeCl3 Rate × FeCl3 Storage Time / FeCl3 Tank Qty (6-45) 

where: 

FeCl3 Rate = Ferric chloride volumetric addition rate in gph. See 

Ferric Chloride Feed System Cost in Section 6.1.6.3 for 

details, 

FeCl3 Storage Time = The hours of supply of ferric chloride the plant stores 

on site. EPA assumed a plant would keep 15 days’, or 

360 hours’, worth of ferric chloride on site, and 
Chapter 6 - FGD Wastewater Cost Methodology 

6-31 

FECl3 Tank Qty = The number of FeCl3 storage tanks required, rounded 

up to the nearest whole number (see Equation 6-44). 

FeCl3 Rate = Ferric chloride volumetric addition rate in gph. See 

Ferric Chloride Feed System Cost in Section 6.1.6.3 for 

details, 

The tank(s) are then costed as follows. The first term in Equation 6-46 calculates the cost 

of the tank itself while the second term in Equation 6-46 calculates freight costs. 

Ferric Chloride Storage Tank Cost (2011$) = [$1.25/gal × FeCl3 Tank Size × Ancillary 

Equipment Factor + Miles × 0.0454 × (FeCl3 Rate × FeCl3 Storage 

 Time / FeCl3 Tank Qty)0.5481] × FeCl3 Tank Qty (6-46) 

where: 

FeCl3 Tank Size = FeCl3 tank size, in gallons (see Equation 6-45), 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Miles = Expected average tank shipping distance, in miles, 

between tank supplier and power plant, 500. 

Hydrochloric Acid Storage Tank Cost. EPA costed storage tanks for 32 percent 

concentration hydrochloric acid for plants with FGD wastewater flow rates greater than the 

trigger flow rate calculated as described below. The trigger flow rate is calculated assuming 

plants requiring more than one tote of hydrochloric acid per day would install a storage tank, 

while plants requiring less than one tote of hydrochloric acid per day would not install a storage 

tank. 

HCl Tank WW Flow Limit (gpm) = (Tote Volume × Totes Per Day / Min Per Day) / 

(Hydrochloric Acid Dose × HCl Dose Factor × Liter to Gallon Factor × Capacity Factor × Liter 

 to Gallon Factor) (6-47) 

where: 

Tote Volume = The volume, in gallons, of a standard size chemical 

tote, 275, 

Totes Per Day = The maximum number of totes of chemical a plant 

requires per day above which a plant would install a 

chemical storage tank, 1, 

Min Per Day = Number of minutes per day, 1440, 

Hydrochloric Acid 

Dose 

= Amount of hydrochloric acid, in g/L, needed to treat 

the FGD wastewater in the chemical precipitation 
Chapter 6 - FGD Wastewater Cost Methodology 

6-32 

system, as determined in Section 6.1.7.4, 

HCl Dose Factor = Factor to convert dose from grams of neat chemical per 

liter of FGD wastewater to liters of chemical solution 

per liter of FGD wastewater. See the discussion for 

Liquid Feed Systems in Section 6.1.6.3 for further 

details, 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], and 

Liter to Gallon Factor = Unit conversion factor, equal to 1, which converts liters 

of chemical solution per liter of wastewater to gallons 

of chemical solution per gallon of wastewater. It is 

calculated as: 

ݎ݁ݐܽݓ݁ݐݏܽݓ ܮ 3.785

݊Ԣ݈݋ݏ݈݃ܽ ݄݈ܿ݁݉݅ܿܽ  ൈ ݎ݁ݐܽݓ݁ݐݏܽݓ ݈݃ܽ

݊Ԣ݈݋ݏ ݄݈ܿ݁݉݅ܿܽ ܮ3.785 

As described above, if the FGD Wastewater Treatment Flow GPM is less than the HCl 

Tank WW Flow Limit, EPA assumed that the plant will use totes to store the hydrochloric acid 

and, therefore, assumed no costs associated with a storage tank. If the FGD Wastewater 

Treatment Flow GPM is greater than the HCl Tank WW Flow Limit, then EPA costed a storage 

tank using tank size and quantity. 

The tank quantity is calculated by dividing the required storage amount of HCl by the 

maximum size for shop-built FRP tanks. 

HCl Tank Qty = HCl Rate × HCl Storage Time/50,000 gal (rounded up to the nearest whole 

 number) (6-48) 

where: 

HCl Rate = Hydrochloric acid volumetric addition rate in gph. See 

Hydrochloric Acid Feed System Cost in Section 6.1.6.3 

for details, and 

HCl Storage Time = The hours of supply of hydrochloric acid the plant 

stores on site. EPA assumed a plant would keep 15 

days’, or 360 hours’, worth of hydrochloric acid on 

site. 

Next, EPA calculated the HCl tank size using Equation 6-49. 

 HCl Tank Size (gal) = HCl Rate × HCl Storage Time / HCl Tank Qty (6-49) 
Chapter 6 - FGD Wastewater Cost Methodology 

6-33 

where: 

HCl Rate = Hydrochlorice acid volumetric addition rate in gph. See 

Hydrochloric Acid Feed System Cost in Section 6.1.6.3 

for details, 

HCl Storage Time = The hours of supply of hydrochloric acid the plant 

stores on site. EPA assumed a plant would keep 15 

days’, or 360 hours’, worth of hydrochloric acid on 

site, and 

HCl Tank Qty = The number of HCl storage tanks required, rounded up 

to the nearest whole number (see Equation 6-48). 

The tank(s) are then costed as follows. The first term in Equation 6-50 calculates the cost 

of the tank itself while the second term in Equation 6-50 calculates freight costs. 

Hydrochloric Acid Storage Tank Cost (2011$) = [$1.25/gal × HCl Tank Size × Ancillary 

 Equipment Factor + Miles × 0.0454 × (HCl Tank Size)0.5481] × HCl Tank Qty (6-50) 

where: 

HCl Tank Size = HCl tank size, in gallons (see Equation 6-49), 

HCl Tank Qty = The number of HCl storage tanks required, rounded up 

to the nearest whole number (see Equation 6-48), 

Ancillary Equipment 

Factor 

= Factor that accounts for nozzles, baffles, and other 

ancillary equipment, 1.15, and 

Miles = Expected average tank shipping distance, in miles, 

between tank supplier and power plant, 500. 

6.1.6.3 Purchased Equipment Costs: Chemical Feed Systems 

EPA developed chemical feed system cost equations based on cost per feed point data 

provided by Enpro-Tech [ERG, 2013; See Appendices 20, 21, and 22]. Enpro-Tech provided the 

maximum reasonable addition rate that could be provided by each feed point and the cost for 

each feed point. EPA calculated the chemical addition rate required for each plant, and 

determined the number of feed points that would be required. EPA used the following equations 

to calculate the chemical addition rate (gpm) and the cost of feed systems. Note: each liquid feed 

system includes two 100 percent capacity pumps. 

The total cost for chemical feed systems is made up of the following cost elements: 

 Lime feed system cost, 

 Ferric chloride feed system cost, 

 Organosulfide feed system cost, 
Chapter 6 - FGD Wastewater Cost Methodology 

6-34 

 Polymer feed system cost, and 

 Hydrochloric acid feed system cost. 

Lime Feed System Cost

EPA obtained cost estimates from Enpro-Tech for their SiloPacTM lime feed system. Each 

lime slurry feed system includes one or more storage silo(s), a volumetric feeder, a control 

system, a mix tank, and two peristaltic slurry pumps. Solid hydrated lime is stored in the silos 

and processed into a 10 percent by-weight slurry within the system. 

The cost of the lime feed system is driven by the cost of the storage silos. EPA assumed 

each plant would keep up to 15 days’ worth of lime onsite. EPA developed an equation to 

calculate the required lime storage volume based on the dose, wastewater flow rate, and storage 

time. Using cost estimates provided by the vendor, EPA then developed an equation relating the 

cost of the lime feed to the required lime storage volume [ERG, 2013; See Appendices 20, 21, 

and 22]. EPA added $10,000 to the cost equation to account for freight and training, based on 

input from the vendor. 

EPA first calculated the mass addition rate of lime, in grams per minute, required to treat 

FGD wastewater (referred to as the Lime Dose Rate) using Equation 6-51. 

Lime Dose Rate (gpm) = Hydrated Lime Dose × FGD Wastewater Treatment Flow GPM × 

 Capacity Factor × 3.78 L/Gal (6-51) 

where: 

Hydrated Lime Dose = Amount of lime in, g/L, needed to treat the FGD 

wastewater in the chemical precipitation system, as 

determined in Section 6.1.7.4, 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation(see Section 6.1.5), and 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted]. 

Next, EPA calculated the volumetric addition rate of lime, in gpm, required to treat FGD 

wastewater (referred to as the Lime Volume Rate) using Equation 6-52. 

 Lime Volume Rate (gpm) = Lime Dose Rate / (1,000 g/kg × Lime Density × 3.78 L/gal)(6-52) 

where: 

Lime Dose Rate = The mass addition rate of lime, gpm, (see Equation 

6-51), and 

Lime Density = The density of lime, in kg/L, 0.5. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-35 

Next, EPA calculated the volume, in cubic feet, of the supply of lime the plant would 

store on site using Equation 6-53. 

 Lime Storage Volume (ft3

) = Lime Storage Time × Lime Volume Rate / 7.48 gal/ft3 (6-53) 

where: 

Lime Storage Time = The minutes of supply of lime the plant stores on site. 

EPA assumed a plant would keep 15 days’, or 21,600 

minutes’, worth of lime on site, and 

Lime Volume Rate = The volumetric addition rate of lime required to treat 

FGD wastewater, in gpm (see Equation 6-52). 

Finally, EPA calculated the cost of the lime slurry feed system using Equation 6-54. 

Lime Slurry Feed System Cost (2011$) = 0.0004 × (Lime Storage Volume)2 + 17.487 × Lime 

 Storage Volume + 193013 + Lime Feed Freight Cost (6-54) 

where: 

Lime Storage Volume = The supply of lime the plant stores on site, ft3, (see 

Equation 6-53)and 

Lime Feed Freight Cost = Cost for freight and training for the lime slurry feed 

system, $10,000. 

For liquid feed systems (i.e., chemical feed systems other than lime), a factor must be 

applied to convert the dose from grams of neat chemical per liter of FGD wastewater to liters of 

chemical solution per liter of FGD wastewater: 

Dose Conversion Factor 

L chemical sol'n

g neat chemical = 

1

Concentration g neat chemical

g chemical sol'n × Density kg chemical sol'n

L chemical sol'n × 1000 g chemical sol'nkg chemical sol'n

Using the dose conversion factor and chemical dose, EPA next calculated the volumetric 

addition rate for each liquid chemical using Equation 6-55. 

Volumetric Chemical Addition Rate (gpd) = Dose × Dose Factor × 3.785 L wastewater/gal 

wastewater × gal chemical/3.785 L chemical × FGD Wastewater Treatment Flow GPM × 

 Capacity Factor (6-55) 

where: 

Dose = Amount of chemical, in g/L, needed to treat the FGD 
Chapter 6 - FGD Wastewater Cost Methodology 

6-36 

wastewater in the chemical precipitation system, as 

determined in Section 6.1.7.4, 

Dose Factor = Factor to convert dose from grams of neat chemical per 

liter of FGD wastewater to liters of chemical solution 

per liter of FGD wastewater, 

FGD Wastewater Flow 

GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted]. 

The vendor also stated that typical liquid feed systems weigh no more than 500 pounds 

and have dimensions of approximately 3’x 3’x 5’. The vendor estimated freight for these systems 

would be approximately $300. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A24 and 

SE01825.A25) for more discussion on the development of Equations 6-51 through 6-55. 

Ferric Chloride Feed System Cost

EPA assumed a 35 percent concentration of ferric chloride in solution. 

The vendor stated for chemical addition rates less than 100 gallons per hour (gph), a 

system using small peristaltic pumps would be sufficient at a cost of $5,000 per system. For 

chemical addition rates greater than 100 gph, the vendor recommended a conservative cost 

estimate of $15,000 per feed point. While the vendor did not provide an upper limit for the 

chemical addition rate that can be handled by the larger feed system, EPA assumed an upper 

limit of 200 gph. For plants requiring chemical addition rates greater than 200 gph, EPA costed 

multiple feed points (systems). 

To calculate the cost for each feed point, EPA first calculated the dose conversion factor 

to convert the dose from grams of neat chemical per liter of FGD wastewater to liters of 

chemical solution per liter of FGD wastewater. 

 FeCl3 Dose Factor = 1/ (FeCl3 Concentration × FeCl3 Density × 1,000 g/kg) (6-56) 

where: 

FeCl3 Concentration = The concentration of ferric chloride in solution, 35 

percent (0.35), and 

FeCl3 Density = The density of ferric chloride solution, in kg/L, 1.41. 

EPA then calculated the volumetric addition rate, in gallons per hour, using Equation 

6-57. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-37 

FeCl3 Rate (gph) = Ferric Chloride Dose × FeCl3 Dose Factor × Liter to Gallon Factor × FGD 

 Wastewater Treatment Flow GPM × Capacity Factor × 60 min/hr (6-57) 

where: 

Ferric Chloride Dose = Amount of ferric chloride, in g/L, needed to treat the 

FGD wastewater in the chemical precipitation system, 

as determined in Section 6.1.7.4, 

FeCL3 Dose Factor = Factor to convert dose from grams of neat chemical per 

liter of FGD wastewater to liters of chemical solution 

per liter of FGD wastewater (see Equation 6-56), 

Liter to Gallon Factor = Unit conversion factor, equal to 1, which converts liters 

of chemical solution per liter of FGD wastewater to 

gallons of chemical solution per gallon of FGD 

wastewater. It is calculated as: 

3.785 L wastewater

gal wastewater × gal chemical sol'n

3.785 L chemical sol'n

FGD Wastewater 

Treatment Flow GPM= 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Next, EPA calculated the number of ferric chloride feed points (systems) using Equation 

6-58. 

 FeCl3 Feed Point Qty = FeCl3 Rate / 200 gph (rounded up to the nearest whole number) (6-58) 

where: 

FeCl3 Rate = Ferric chloride volumetric addition rate in gph (see 

Equation 6-57). 

The ferric chloride feed system cost was then calculated based on the volumetric addition 

rate. For FeCl3 rates less than or equal to 100 gph, EPA used Equation 6-59. 

Ferric Chloride Feed System Cost (2011$) = FeCl3 Feed Point Qty × ($5,000 + Liquid Feed 

 Freight Cost) (6-59) 

where: 

FeCl3 Feed Point Qty = The number of ferric chloride feed points required to 

treat FGD wastewater, rounded up to the nearest whole 

number (see Equation 6-58), and 

Liquid Feed Freight 

Cost 

= The freight cost for a liquid feed system, $300. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-38 

For FeCl3 rates greater than 100 gph, EPA used Equation 6-60 to calculate the ferric 

chloride feed system cost. 

Ferric Chloride Feed System Cost (2011$) = FeCl3 Feed Point Qty × ($15,000 + Liquid Feed 

 Freight Cost) (6-60) 

where: 

FeCl3 Feed Point Qty = The number of ferric chloride feed points required to 

treat FGD wastewater, rounded up to the nearest whole 

number (see Equation 6-58), and 

Liquid Feed Freight 

Cost 

= The freight cost for a liquid feed system, $300. 

Organosulfide Feed System Cost

EPA assumed a neat organosulfide concentration that is diluted to a 0.5 percent 

organosulfide solution within the feed system prior to addition to reactor tank 2.29

EPA assumed that the organosulfide feed system can handle up to 20 gpm of 

organosulfide solution at a cost of $15,000 per feed point (assumption transferred from vendor 

information for the polymer feed system discussed in this section). For plants requiring chemical 

addition rates greater than 20 gpm, EPA costed multiple feed points (systems). 

To calculate the cost for each feed point, EPA first calculated the dose conversion factor 

to convert the dose from grams of neat chemical per liter of FGD wastewater to liters of 

chemical solution per liter of FGD wastewater. 

 Sulfide Dose Factor = 1/ (Sulfide Concentration × Sulfide Density × 1,000 g/kg) (6-61) 

where: 

Sulfide Concentration = The concentration of organosulfide in solution, 0.5 

percent (0.005), and 

Sulfide Density = The density of organosulfide solution, in kg/L, 1.225. 

EPA then calculated the volumetric addition rate, in gpm, using Equation 6-62. 

Sulfide Rate (gpm) = Organosulfide Dose × Sulfide Dose Factor × Liter to Gallon Factor × 

 FGD Wastewater Treatment Flow GPM × Capacity Factor (6-62) 

 

29 EPA’s cost methodology is inconsistent in that this discussion of organosulfide feed systems assumes use of a 

liquid feed system while the chemical purchase cost discussion in Section 6.1.7.4 assumes purchase as a solid. For 

the final rule, EPA will reevaluate the organosulfide purchase, freight, storage, and feed system methodologies and 

revise them as appropriate. In the interim, EPA considers the magnitude of the current estimated costs to be 

appropriate. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-39 

where: 

Organosulfide Dose = Amount of organosulfide, in g/L, needed to treat the 

FGD wastewater in the chemical precipitation system, 

as determined in Section 6.1.7.4, 

Sulfide Dose Factor = Factor to convert dose from grams of neat chemical per 

liter of FGD wastewater to liters of chemical solution 

per liter of FGD wastewater (see Equation 6-61), 

Liter to Gallon Factor = Unit conversion factor, equal to 1, which converts liters 

of chemical solution per liter of FGD wastewater to 

gallons of chemical solution per gallon of FGD 

wastewater. It is calculated as: 

3.785 L wastewater

gal wastewater

× gal chemical sol'n

3.785 L chemical sol'n., 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted]. 

Next, EPA calculated the number of organosulfide feed points (systems) using Equation 

6-63. 

Sulfide Feed Point Qty = Organosulfide Rate / 20 gpm (rounded up to the nearest whole 

 number) (6-63) 

where: 

Organosulfide Rate = Organosulfide volumetric addition rate in gpm (see 

Equation 6-62). 

EPA calculated the organosulfide feed system cost based on the volumetric addition rate. 

Organosulfide Feed System Cost (2011$) = Sulfide Feed Point Qty × ($15,000 + Liquid Feed 

 Freight Cost) (6-64) 

where: 

Sulfide Feed Point Qty = The number of organosulfide feed points required to 

treat FGD wastewater, rounded up to the nearest whole 

number (see Equation 6-63), and 

Liquid Feed Freight 

Cost 

= The freight cost for a liquid feed system, $300. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-40 

Polymer Feed System Cost

EPA assumes a neat polymer concentration that is diluted to a 0.5 percent polymer 

solution within the feed system prior to addition to the solids contact clarifier.30

The vendor stated that a polymer feed system handling up to 20 gpm of polymer solution 

addition would cost $15,000 per feed point (system). For plants requiring chemical addition rates 

greater than 20 gpm, EPA costed multiple feed points. 

To calculate the cost for each feed point, EPA first calculated the dose conversion factor 

to convert the dose from grams of neat chemical per liter of FGD wastewater to liters of 

chemical solution per liter of FGD wastewater. 

Polymer Dose Factor = 1/ (Polymer Concentration × Polymer Density × 1,000 g/kg) (6-65) 

where: 

Polymer Concentration = The concentration of polymer in solution, 0.5 percent 

(0.005), and 

Polymer Density = The density of polymer solution, in kg/L, 1.04. 

EPA then calculated the volumetric addition rate, in gpm, using Equation 6-66. 

Polymer Rate (gpm) = Polymer Dose × Polymer Dose Factor × Liter to Gallon Factor × FGD 

 Wastewater Treatment Flow GPM × Capacity Factor (6-66) 

where: 

Polymer Dose = Amount of polymer, in g/L, needed to treat the FGD 

wastewater in the chemical precipitation system, as 

determined in Section 6.1.7.4, 

Polymer Dose Factor = Factor to convert dose from grams of neat chemical per 

liter of FGD wastewater to liters of chemical solution 

per liter of FGD wastewater (see Equation 6-65), 

Liter to Gallon Factor = Unit conversion factor, equal to 1, which converts liters 

of chemical solution per liter of FGD wastewater to 

gallons of chemical solution per gallon of FGD 

wastewater. It is calculated as: 

3.785 L wastewater

gal wastewater

× gal chemical sol'n

3.785 L chemical sol'n, 

 

30 EPA’s cost methodology is inconsistent in that this discussion of polymer feed systems assumes use of a liquid 

feed system while the chemical purchase cost discussion in Section 6.1.7.4 assumes purchase as a solid. For the final 

rule, EPA will reevaluate the polymer purchase, freight, storage, and feed system methodologies and revise them as 

appropriate. In the interim, EPA considers the magnitude of the current estimated costs to be appropriate. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-41 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted]. 

Next, EPA calculated the number of polymer feed points (systems) using Equation 6-67. 

Polymer Feed Point Qty = Polymer Rate / 20 gpm (rounded up to the nearest whole number) (6-67) 

where: 

Polymer Rate = Polymer volumetric addition rate in gpm (see Equation 

6-66). 

The polymer feed system cost was then calculated based on the volumetric addition rate 

using Equation 6-68. 

Polymer Feed System Cost (2011$) = Polymer Feed Point Qty × ($15,000 + Liquid Feed Freight 

 Cost) (6-68) 

where: 

Polymer Feed Point 

Qty 

= The number of polymer feed points required to treat 

FGD wastewater, rounded up to the nearest whole 

number (see Equation 6-67), and 

Liquid Feed Freight 

Cost 

= The freight cost for a liquid feed system, $300. 

Hydrochloric Acid Feed System Cost

EPA assumed a 32 percent concentration of hydrochloric acid in solution. 

This feed system will add hydrochloric acid to the system after final clarification (e.g., 

after the solids contact clarifier). The vendor stated that for chemical addition rates less than 100 

gph, a system using small peristaltic pumps would be sufficient at a cost of $5,000 per system. 

For chemical addition rates greater than 100 gph, the vendor recommended a conservative cost 

estimate of $15,000 per feed point. While the vendor did not provide an upper limit for the 

chemical addition rate that can be handled by the larger feed system, EPA assumed an upper 

limit of 200 gph. For plants requiring chemical addition rates greater than 200 gph, EPA costed 

multiple feed points (systems). 

To calculate the cost for each feed point, EPA first calculated the dose conversion factor 

to convert the dose from grams of neat chemical per liter of FGD wastewater to liters of 

chemical solution per liter of FGD wastewater. 

 HCl Dose Factor = 1/ (HCl Concentration × HCl Density × 1,000 g/kg) (6-69) 
Chapter 6 - FGD Wastewater Cost Methodology 

6-42 

where: 

HCl Concentration = The concentration of hydrochloric acid in solution, 32 

percent (0.32), and 

HCl Density = The density of hydrochloric acid solution, in kg/L, 

1.159. 

EPA then calculated the volumetric addition rate, in gallons per hour, using Equation 

6-70. 

HCl Rate (gph) = Hyrdochloric Acid Dose × HCl Dose Factor × Liter to Gallon Factor × FGD 

 Wastewater Treatment Flow GPM × Capacity Factor × 60 min/hr (6-70) 

where: 

Hydrochloric Acid 

Dose 

= Amount of hydrochloric acid, in g/L, needed to treat 

the FGD wastewater in the chemical precipitation 

system, as determined in Section 6.1.7.4), 

HCl Dose Factor = Factor to convert dose from grams of neat chemical per 

liter of FGD wastewater to liters of chemical solution 

per liter of FGD wastewater (see Equation 6-69), 

Liter to Gallon Factor = Unit conversion factor, equal to 1, which converts liters 

of chemical solution per liter of FGD wastewater to 

gallons of chemical solution per gallon of FGD 

wastewater. It is calculated as: 

3.785 L wastewater

gal wastewater

× gal chemical sol'n

3.785 L chemical sol'n, 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted]. 

Next, EPA calculated the number of hydrochloric acid feed points (systems) using 

Equation 6-71. 

 HCl Feed Point Qty = HCl Rate / 200 gph (rounded up to the nearest whole number) (6-71) 

where: 

HCl Rate = Hydrochloric acid volumetric addition rate in gph (see 

Equation 6-70). 

The hydrochloric acid feed system cost was then calculated based on the volumetric 

addition rate: 
Chapter 6 - FGD Wastewater Cost Methodology 

6-43 

For HCl rates less than or equal to 100 gph EPA used Equation 6-72. 

Hydrochloric Acid Feed System Cost (2011$) = HCl Feed Point Qty × ($5,000 + Liquid Feed 

 Freight Cost) (6-72) 

where: 

HCl Feed Point Qty = The number of hydrochloric acid feed points required 

to treat FGD wastewater, rounded up to the nearest 

whole number (see Equation 6-71), and 

Liquid Feed Freight 

Cost 

= The freight cost for a liquid feed system, $300. 

For HCl rates greater than 100 gph, EPA used Equation 6-73. 

Hydrochloric Acid Feed System Cost (2011$) = HCl Feed Point Qty × ($15,000 + Liquid Feed 

 Freight Cost) (6-73) 

where: 

HCl Feed Point Qty = The number of hydrochloric acid feed points required 

to treat FGD wastewater, rounded up to the nearest 

whole number (see Equation 6-71), and 

Liquid Feed Freight 

Cost 

= The freight cost for a liquid feed system, $300. 

6.1.6.4 Purchased Equipment Costs: Mixers 

EPA costed mixers for certain costed tanks, with one mixer per costed tank. EPA 

obtained vendor cost information for mixers based on an example plant’s information that was 

provided to the equipment vendor Philadelphia Mixing Solutions. See the Supplemental Costs 

and Loadings Documentation (DCN SE01825.A26 through SE01825.A29) for additional 

information. To calculate the mixer cost for each plant, EPA multiplied the plant’s tank size by 

cost factors it developed using the example plant and vendor cost information. For each plant, 

mixer costs are determined based on tank size therefore, no capacity factor is required. 

Freight costs for mixers are not available on a per-mixer basis. One flatbed truck is 

needed to ship all of the mixers required for the system. The freight cost estimate for one truck 

(lot of mixers) is [Redacted] [ERG, 2013; See Appendix 41]. 

Mixers Cost = Equalization Tank Mixer Cost + Reaction Tank 1 Mixer Cost + Reaction Tank 2 

Mixer Cost + Reaction Tank 3 Mixer Cost + Sludge Holding Tank Mixer Cost + Lime Slurry 

Preparation Tank Mixer Cost + Filtrate Sump Mixer Cost + Flatbed Truck Cost 

For each type of mixer, EPA first calculated the torque of the mixer based on the example 

plant’s data. Torque is calculated in pound force inch (lbf·in) using Equation 6-74. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-44 

Torque (lbf·in) = 33,000 (lbf·ft/min) × 12 in/ft × Mixer Horsepower (hp) / [2 × π × Mixer Speed 

 (rpm)] (6-74) 

EPA assumed the ratio of cost to torque and torque to volume would be constant for each 

type of mixer, regardless of size, based on engineering judgment. 

Equalization Tank Mixer Cost

As discussed in Section 6.1.6.2, EPA costed one equalization tank per plant; therefore, 

EPA also costed one equalization tank mixer per plant, other than “high flow” plants. To 

estimate mixer purchase costs, EPA first calculated the example plant’s equalization tank mixer 

torque. 

Example Plant Eq Mixer Torque (lbf·in) = 33,000 (lbf·ft/min) × 12 in/ft × Example Plant Eq 

 Mixer HP / (2 × π ×Example Plant Eq Mixer RPM) (6-75)

where: 

Example Plant Eq 

Mixer HP 

= The example plant’s equalization tank mixer’s 

horsepower, provided in documentation for the 

example plant, and

Example Plant Eq 

Mixer RPM 

= The example plant’s equalization tank mixer’s speed, 

in revolutions per minute (rpm), provided in 

documentation for the example plant. 

EPA then calculated the cost factors Cost Per Unit Torque and Torque Per Unit Volume 

based on cost data provided by the vendor for the example plant’s mixer and tank size. EPA 

assumed that these cost factors are valid for all equalization tank mixers, regardless of size, 

based on engineering judgment. 

Eq Mixer Cost per Torque ($/lbf·in) = Example Plant Eq Mixer Cost / Example Plant Eq Mixer 

 Torque (6-76) 

where: 

Example Plant Eq 

Mixer Cost 

= The cost of the equalization tank mixer used by the 

example plant (provided by equipment vendor), and 

Example Plant Eq 

Mixer Torque 

= The torque of the equalization tank mixer used by the 

example plant, (see Equation 6-75). 

Eq Mixer Torque per Volume (lbf·in/ft3

) = Example Plant Eq Mixer Torque / Example Plant Eq 

 Tank Size (6-77) 
Chapter 6 - FGD Wastewater Cost Methodology 

6-45 

where: 

Example Plant Eq Tank 

Size 

= The size, in gallons, of the example plant’s equalization 

tank, and 

Example Plant Eq 

Mixer Torque 

= The torque of the equalization tank mixer used by the 

example plant, (see Equation 6-75).

EPA then calculated the plant-specific equalization tank mixer cost by multiplying the 

plant-specific equalization tank size calculated previously (see the Equalization Tank Cost 

discussion in Section 6.1.6.2) by the equalization tank mixer cost factors. 

Equalization Tank Mixer Cost (2011$) = Equalization Tank Size × Eq Mixer Torque per Volume 

 × Eq Mixer Cost per Torque (6-78) 

where: 

Equation Tank Size = The calculated equalization tank size, (see Section 

6.1.6.2 and Equation 6-16), 

Eq Mixer Torque per 

Volume 

= The calculated torque per volume for the equalization 

tank mixer, (see Equation 6-77), and 

Eq Mixer Cost Per 

Torque 

= The calculated cost of the mixer per unit torque for the 

equalization tank mixer, (see Equation 6-76). 

Reaction Tank 1 Mixer Cost

EPA costed one reaction tank 1 (see Section 6.1.6.2) and, therefore, one reaction tank 1 

mixer for each plant. To calculate mixer costs, EPA first calculated the example plant’s reaction 

tank 1 mixer torque. 

Example Plant Rxn1 Mixer Torque (lbf·in) = 33,000 (lbf·ft/min) × 12 in/ft × Example Plant 

 Rxn1 Mixer HP / (2 × π × Example Plant Rxn1 Mixer RPM) (6-79)

where: 

Example Plant Rxn1 

Mixer HP 

= The example plant’s reaction tank 1 mixer’s 

horsepower, provided in documentation for the 

example plant, and

Example Plant Rxn1 

Mixer RPM 

= The example plant’s reaction tank 1 mixer’s speed, in 

rpm, provided in documentation for the example plant. 

EPA then calculated the cost factors Cost Per Unit Torque and Torque Per Unit Volume 

based on cost data provided by the vendor for the example plant’s mixer and tank size. EPA 

assumed that these cost factors are valid for all reaction tank 1 mixers, regardless of size, based 

on engineering judgment. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-46 

Rxn1 Mixer Cost per Torque ($/lbf·in) = Example Plant Rxn1 Mixer Cost / Example Plant Rxn1 

 Mixer Torque (6-80) 

where: 

Example Plant Rxn1 

Mixer Cost 

= The cost of the reaction tank 1 mixer used by the 

example plant (provided by equipment vendor), and 

Example Plant Rxn1 

Mixer Torque 

= The torque of the reaction tank 1 mixer used by the 

example plant, (see Equation 6-79).

Rxn1 Mixer Torque per Volume (lbf·in/ft3) = Example Plant Rxn1 Mixer Torque / Example 

 Plant Rxn1 Tank Size (6-81)

where: 

Example Plant Rxn1 

Tank Size 

= The size, in gallons, of the example plant’s reaction 

tank 1, and 

Example Plant Rxn1 

Mixer Torque 

= The torque of the reaction tank 1 mixer used by the 

example plant (see Equation 6-79).

EPA then calculated the plant-specific reaction tank 1 mixer cost by multiplying the 

plant-specific reaction tank 1 size calculated previously (see the Reaction Tank 1 Cost discussion 

in Section 6.1.6.2) by the reaction tank 1 mixer cost factors. 

Reaction Tank 1 Mixer Cost (2011$) = Reaction Tank 1 Size × Rxn1 Mixer Torque per Volume 

 × Rxn1 Mixer Cost per Torque (6-82) 

where: 

Reaction Tank 1 Size = The calculated reaction tank 1 size, (see Section 6.1.6.2 

and Equation 6-21), 

Rxn1 Mixer Torque per 

Volume 

= The calculated torque per volume for the reaction tank 

1 mixer, (see Equation 6-81), and 

Rxn1 Mixer Cost per 

Torque 

= The calculated cost of the mixer per unit torque for the 

reaction tank 1 mixer, (see Equation 6-80). 

Reaction Tank 2 Mixer Cost

EPA costed one reaction tank 2 (see Section 6.1.6.2) and, therefore, one reaction tank 2 

mixer for each plant. To calculate mixer costs, EPA first calculated the example plant’s reaction 

tank 2 mixer torque. 

Example Plant Rxn2 Mixer Torque (lbf·in) = 33,000 (lbf·ft/min) × 12 in/ft × Example Plant 

 Rxn2 Mixer HP / (2 × π × Example Plant Rxn2 Mixer RPM) (6-83)
Chapter 6 - FGD Wastewater Cost Methodology 

6-47 

where: 

Example Plant Rxn2 

Mixer HP 

= The example plant’s reaction tank 2 mixer’s 

horsepower, provided in documentation for the 

example plant, and

Example Plant Rxn2 

Mixer RPM 

= The example plant’s reaction tank 2 mixer’s speed, in 

rpm, provided in documentation for the example plant. 

EPA then calculated the cost factors Cost Per Unit Torque and Torque Per Unit Volume 

based on cost data provided by the vendor for the example plant’s mixer and tank size. EPA 

assumed that these cost factors are valid for all reaction tank 2 mixers, regardless of size, based 

on engineering judgment. 

Rxn2 Mixer Cost per Torque ($/lbf·in) = Example Plant Rxn2 Mixer Cost / Example Plant Rxn2 

 Mixer Torque (6-84) 

where: 

Example Plant Rxn2 

Mixer Cost 

= The cost of the reaction tank 2 mixer used by the 

example plant (provided by equipment vendor) , and 

Example Plant Rxn2 

Mixer Torque 

= The torque of the reaction tank 2 mixer used by the 

example plant, (see Equation 6-83).

Rxn2 Mixer Torque per Volume (lbf·in/ft3) = Example Plant Rxn2 Mixer Torque / Example 

Plant Rxn2 Tank Size (6-85)

where: 

Example Plant Rxn2 

Tank Size 

= The size, in gallons, of the example plant’s reaction 

tank 2, and 

Example Plant Rxn2 

Mixer Torque 

= The torque of the reaction tank 2 mixer used by the 

example plant, (see Equation 6-83).

EPA then calculated the plant-specific reaction tank 2 mixer cost by multiplying the 

plant-specific reaction tank 2 size calculated previously (see the Reaction Tank 2 Cost and 

Reaction Tank 3 Cost discussion in Section 6.1.6.2) by the reaction tank 2 mixer cost factors. 

Reaction Tank 2 Mixer Cost (2011$) = Reaction Tank 2 Size × Rxn2 Mixer Torque per Volume 

 × Rxn2 Mixer Cost per Torque (6-86) 

where: 

Reaction Tank 2 Size = The calculated reaction tank 2 size, (see Section 6.1.6.2 

and Equation 6-25), 
Chapter 6 - FGD Wastewater Cost Methodology 

6-48 

Rxn2 Mixer Torque per 

Volume 

= The calculated torque per volume for the reaction tank 

2 mixer, (see Equation 6-85), and 

Rxn2 Mixer Cost per 

Torque 

= The calculated cost of the mixer per unit torque for the 

reaction tank 2 mixer, (see Equation 6-84). 

Reaction Tank 3 Mixer Cost

EPA costed one reaction tank 3 (see Section 6.1.6.2) and, therefore, one Reaction Tank 3 

Mixer for each plant. To calculate mixer costs, EPA first calculated the example plant’s reaction 

tank 3 mixer torque. 

Example Plant Rxn3 Mixer Torque (lbf·in) = 33,000 (lbf·ft/min) × 12 in/ft × Example Plant 

 Rxn3 Mixer HP / (2 × π × Example Plant Rxn3 Mixer RPM) (6-87)

where: 

Example Plant Rxn3 

Mixer HP 

= The example plant’s reaction tank 3 mixer’s 

horsepower, provided in documentation for the 

example plant, and

Example Plant Rxn3 

Mixer RPM 

= The example plant’s reaction tank 3 mixer’s speed, in 

rpm, provided in documentation for the example plant. 

EPA then calculated the cost factors Cost Per Unit Torque and Torque Per Unit Volume 

based on cost data provided by the vendor for the example plant’s mixer and tank size. EPA 

assumed that these cost factors are valid for all reaction tank 3 mixers, regardless of size, based 

on engineering judgment. 

Rxn3 Mixer Cost per Torque ($/lbf·in) = Example Plant Rxn3 Mixer Cost / Example Plant Rxn3 

 Mixer Torque (6-88) 

where: 

Example Plant Rxn3 

Mixer Cost 

= The cost of the reaction tank 3 mixer used by the 

example plant (provided by equipment vendor), and 

Example Plant Rxn3 

Mixer Torque 

= The torque of the reaction tank 3 mixer used by the 

example plant, (see Equation 6-87). 

Rxn3 Mixer Torque per Volume (lbf·in/ft3

) = Example Plant Rxn3 Mixer Torque / Example 

 Plant Rxn3 Tank Size (6-89)

where: 

Example Plant Rxn3 

Tank Size 

= The size, in gallons, of the example plant’s reaction 

tank 3, and 
Chapter 6 - FGD Wastewater Cost Methodology 

6-49 

Example Plant Rxn3 

Mixer Torque 

= The torque of the reaction tank 3 mixer used by the 

example plant, (see Equation 6-87). 

EPA then calculated the plant-specific reaction tank 3 mixer cost by multiplying the 

plant-specific reaction tank 3 size calculated previously (see the Reaction Tank 2 Cost and 

Reaction Tank 3 Cost discussion in Section 6.1.6.2) by the reaction tank 3 mixer cost factors. 

Reaction Tank 3 Mixer Cost (2011$) = Reaction Tank 3 Size × Rxn3 Mixer Torque per Volume 

 × Rxn3 Mixer Cost per Torque (6-90)

where: 

Reaction Tank 3 Size = The calculated reaction tank 3 size, (see Section 6.1.6.2 

and Equation 6-29), 

Rxn3 Mixer Torque per 

Volume 

= The calculated torque per volume for the reaction tank 

3 mixer, (see Equation 6-89), and 

Rxn3 Mixer Cost per 

Torque 

= The calculated cost of the mixer per unit torque for the 

reaction tank 3 mixer, (see Equation 6-88). 

Sludge Holding Tank Mixer Cost

EPA costed one sludge holding tank (see Section 6.1.6.2) and, therefore, one sludge 

holding tank mixer for each plant. To calculate mixer costs, EPA first calculated the example 

plant’s sludge holding tank mixer torque. 

Example Plant Sldg Mixer Torque (lbf·in) = 33,000 (lbf·ft/min) × 12 in/ft × Example Plant Sldg 

 Mixer HP / (2 × π × Example Plant Sludge Mixer RPM) (6-91)

where: 

Example Plant Sldg 

Mixer HP 

= The example plant’s sludge holding tank mixer’s 

horsepower, provided in documentation for the 

example plant, and 

Example Plant Sldg 

Mixer RPM 

= The example plant’s sludge holding tank mixer’s 

speed, in rpm, provided in documentation for the 

example plant. 

EPA then calculated the cost factors Cost Per Unit Torque and Torque Per Unit Volume 

based on cost data provided by the vendor for the example plant’s mixer and tank size. EPA 

assumed these cost factors are valid for all sludge holding tank mixers, regardless of size, based 

on engineering judgment. 

Sldg Mixer Cost per Torque ($/lbf·in) = Example Plant Sldg Mixer Cost / Example Plant Sldg 

 Mixer Torque (6-92) 
Chapter 6 - FGD Wastewater Cost Methodology 

6-50 

where: 

Example Plant Sldg 

Mixer Cost 

= The cost of the sludge holding tank mixer used by the 

example plant (provided by equipment vendor), and 

Example Plant Sldg 

Mixer Torque 

= The torque of the sludge holding tank mixer used by 

the example plant, (see Equation 6-91).

Sldg Mixer Torque per Volume (lbf·in/ft3) = Example Plant Sldg Mixer Torque / Example Plant 

 Sldg Tank Size (6-93) 

where: 

Example Plant Sldg 

Tank Size 

= The size, in gallons, of the example plant’s sludge 

holding tank, and 

Example Plant Sldg 

Mixer Torque 

= The torque of the sludge holding tank mixer used by 

the example plant, (see Equation 6-91).

EPA then calculated the plant-specific sludge holding tank mixer cost by multiplying the 

plant-specific sludge holding tank size calculated previously (see the Sludge Holding Tank Cost 

discussion in Section 6.1.6.2) by the sludge holding tank mixer cost factors. 

Sludge Holding Tank Mixer Cost (2011$) = Sludge Holding Tank Size × Sldg Mixer Torque per 

 Volume × Sldg Mixer Cost per Torque (6-94) 

where: 

Sludge Holding Tank 

Size 

= The calculated sludge holding tank size, (see Section 

6.1.6.2 and Equation 6-36), 

Sldg Mixer Torque per 

Volume 

= The calculated torque per volume for the sludge 

holding tank mixer, (see Equation 6-93), and 

Sldg Mixer Cost per 

Torque 

= The calculated cost of the mixer per unit torque for the 

sludge holding tank mixer (see Equation 6-92). 

Lime Slurry Preparation Tank Mixer Cost

The lime slurry feed system for which the vendor provided costs includes associated 

mixer costs. See Section 6.1.6.3 for more details. 

Filtrate Sump Mixer Cost

EPA costed one filtrate sump (see Section 6.1.6.2) and, therefore, one filtrate sump mixer 

for each plant. The filtrate sump mixer cost is dependent on the size of the sump. EPA estimated 

sump size using information provided by a BAT plant that provided these design details in its 

Steam Electric Survey response. 

 Sump Size (gal) = Sump HRT × FGD Wastewater Treatment Flow GPM (6-95) 
Chapter 6 - FGD Wastewater Cost Methodology 

6-51 

where: 

Sump HRT = Factor representing the ratio of sump size to FGD 

wastewater treatment flow, in minutes. It is not a true 

residence time, because the majority of the wastewater 

will not reach the filtrate sump; however, the factor is 

calculated in the same way as the wastewater tank 

residence times. Its value is 132 minutes, and 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5). 

EPA assumed that the cost factors Torque Per Unit Volume and Cost Per Unit Torque for 

the filtrate sump are the same as those calculated for the equalization tank, because the filtrate 

sump contents are transferred to the equalization tank. Additionally, the purpose of the mixer in 

both the equalization tank and the filtrate sump is to keep solids suspended, as opposed to 

distributing chemicals and aiding in precipitation and flocculation as with the other tanks’ 

mixers. See the Equalization Tank Mixer Cost discussion in this section for detailed calculations. 

EPA then calculated the plant-specific sump mixer cost by multiplying the plant-specific 

sump size by the equalization tank mixer cost factors. 

Filtrate Sump Mixer Cost (2011$) = Sump Size × Eq Mixer Torque per Volume × Eq Mixer Cost 

 per Torque (6-96) 

where: 

Sump Size = The calculated sump size in gallons, (see Equation 

6-95), 

Eq Mixer Torque per 

Volume 

= The calculated torque per volume for the equalization 

tank mixer, (see Equation 6-77), and 

Eq Mixer Cost Per 

Torque 

= The calculated cost of the mixer per unit torque for the 

equalization tank mixer, (see Equation 6-76). 

6.1.6.5 Purchased Equipment Costs: Solids Contact Clarifiers 

EPA obtained vendor costs for solids contact clarifiers based on the clarifiers used by the 

BAT plants. EPA estimated the cost of two 75 percent capacity solids contact clarifiers to settle 

solids generated in the treatment system. EPA requested vendor costs for solids contact clarifiers 

appropriate for FGD wastewater flow rates ranging from 7 to 700 gpm. EPA requested that 

purchase costs also include ancillary equipment, such as structural supports, ladders, access 

walkways, piping, and valves. The vendors provided costs for solids contact clarifiers including 

internal equipment, but not including the clarifier tank. Walker Process Equipment provided 

costs for clarifier mechanisms suitable for flow rates under 100 gpm, and Siemens provided costs 

for clarifier mechanisms suitable for flow rates from 100 to 700 gpm [ERG, 2013; See 

Appendices 30 , 31, and 32]. Costs provided by Walker Process Equipment and Siemens are for 
Chapter 6 - FGD Wastewater Cost Methodology 

6-52 

all carbon steel equipment lined with epoxy. The majority of the plants sampled by EPA used 

clarifiers made of carbon steel or carbon steel lined with epoxy, while some used carbon steel 

lined with other materials. 

The total solids contact clarifier cost includes the following cost elements: 

 Clarifier Mechanism Cost, and 

 Clarifier Tank Cost. 

Clarifier Mechanism Cost

EPA developed a step-wise cost equation for the solids contact clarifiers. The cost 

equation used for a particular plant is chosen based on 75 percent of FGD Wastewater Treatment 

Flow GPM (see Section 6.1.5) multiplied by the capacity factor. For flow rates greater than 700 

gpm, EPA developed a cost function using the data available from Siemens. 

Freight costs are not available for the solids contact clarifier mechanism. EPA assumes 

that the flat freight cost of $3,000 previously obtained for another clarifier mechanism previously 

evaluated by EPA also applies to the solids contact clarifier mechanism. 

The cost equation used for each clarifier flow rate is identified below: 

Clarifier Flow (gpm) = 0.75 × FGD Wastewater Treatment Flow GPM × Capacity Factor (6-97)

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted]. 

 For Clarifier Flow ≤ 30 gpm: 

Clarifier Mechanism Cost (2011$) = ($65,000 + Clarifier Freight Cost) × Clarifier 

Qty 

 For 30 gpm < Clarifier Flow ≤ 75 gpm: 

Clarifier Mechanism Cost (2011$) = ($80,000 + Clarifier Freight Cost) × Clarifier 

Qty 

 For 75 gpm < Clarifier Flow ≤ 100 gpm: 

Clarifier Mechanism Cost (2011$) = ($118,000 + Clarifier Freight Cost) × Clarifier 

Qty 

 For 100 gpm < Clarifier Flow ≤ 140 gpm: 

Clarifier Mechanism Cost (2011$) = ($122,000 + Clarifier Freight Cost) × Clarifier 

Qty 

 
Chapter 6 - FGD Wastewater Cost Methodology 

6-53 

 For 140 gpm < Clarifier Flow ≤ 250 gpm: 

Clarifier Mechanism Cost (2011$) = ($130,000 + Clarifier Freight Cost) × Clarifier 

Qty 

 For 250 gpm < Clarifier Flow ≤ 350 gpm: 

Clarifier Mechanism Cost (2011$) = ($150,000 + Clarifier Freight Cost) × Clarifier 

Qty 

 For 350 gpm < Clarifier Flow ≤ 470 gpm: 

Clarifier Mechanism Cost (2011$) = ($162,000 + Clarifier Freight Cost) × Clarifier 

Qty 

 For 470 gpm < Clarifier Flow ≤ 550 gpm: 

Clarifier Mechanism Cost (2011$) = ($168,000 + Clarifier Freight Cost) × Clarifier 

Qty 

 For 550 gpm < Clarifier Flow ≤ 700 gpm: 

Clarifier Mechanism Cost (2011$) = ($185,000 + Clarifier Freight Cost) × Clarifier 

Qty 

For Clarifier Flow > 700 gpm, EPA used Equation 6-98. 

Clarifier Mechanism Cost (2011$) = (114.49 × Clarifier Flow + 105986 + Clarifier Freight 

 Cost) × Clarifier Qty (6-98)

where: 

Clarifier Flow = Flow rate of FGD wastewater through the clarifier in 

gpm (see Equation 6-97), 

Clarifier Qty = Number of solids contact clarifiers, 2, and 

Clarifier Freight Cost = Flat rate freight cost for solids contact clarifier 

delivery, $3,000. 

Solids Contact Clarifier Tank Cost

Walker Process Equipment provided the dimensions of the tank that would be appropriate 

for each clarifier [ERG, 2013; See Appendix 33]. EPA used this information to calculate the 

volume of each tank and develop a relationship between the required clarifier tank volume and 

the clarifier flow rate. EPA then used this volume to calculate the cost of a carbon steel tank to 

serve as the tank for each clarifier. EPA used the cost equations discussed in Section 6.1.6.2. 

First, EPA calculated the clarifier flow as described in Equation 6-97. 

Second, EPA calculated the required clarifier tank size using Equation 6-99, which was 

developed using information provided by the vendor [ERG, 2013; See Appendix 33]. 

 Clarifier Tank Size (gal) = 337.8 × Clarifier Flow + 6388.8 (6-99) 
Chapter 6 - FGD Wastewater Cost Methodology 

6-54 

Third, EPA applied the following cost equation developed in Section 6.1.6.2 for carbon 

steel tanks, Equation 6-13, using the clarifier tank size. 

For Clarifier Tank Size ≤ 70,000 gal: 

Clarifier Tank Cost (2011$) = [(0.9412 × Clarifier Tank Size + 4117.6) + (0.064 × Clarifier 

Tank Size + 522.06) + Liner Cost Per Square Foot × (2.0885 × Clarifier Tank Size0.6282)] × 

 Clarifier Qty (6-100) 

For Clarifier Tank Size > 70,000 gal: 

Clarifier Tank Cost (2011$) = (-6×10-08 × Clarifier Tank Size2 + 0.628 × Clarifier Tank Size + 

 503999) × Clarifier Qty (6-101) 

where: 

Liner Cost Per Square 

Foot 

= The installed cost, in dollars, of Tnemec’s Series 61 

Tneme-Liner system per square foot of internal surface 

area of the tank, $10, 

Clarifier Tank Size = Calculated clarifier tank size, in gallons, and 

Clarifier Qty = Number of solids contact clarifiers, 2. 

6.1.6.6 Purchased Equipment Costs: Filter Presses 

EPA requested vendor costs for varying sizes of filter presses assuming FGD wastewater 

flow rates through the system ranging from 7 to 700 gpm. EPA applied the sludge factor of 0.4 

(see Section 6.1.5) to the range of FGD wastewater flows, resulting in estimated design sludge 

flow rates of 2.8 to 280 gpm. Therefore, EPA requested filter press costs for this sludge flow rate 

range. Based on the data provided by Andritz Separation, EPA developed the following cost 

function to extrapolate and interpolate costs for each plant [ERG, 2013; See Appendix 35]. 

Included in the cost of each filter press is the cost of one filter press feed pump. For plants with 

FGD Wastewater Treatment Flow GPM of 350 gpm or less, EPA costed two 100 percent 

capacity, filter presses, each with a feed pump. For plants with FGD Wastewater Treatment Flow 

GPM greater than 350 gpm, EPA costed three 50 percent capacity, filter presses, each with a 

feed pump, for each plant. 

The vendor provided unit purchase cost information for three filter press sizes, by 

capacity: 25 cubic feet (small), 250 cubic feet (medium), and 350 cubic feet (large). Based on the 

weights of the empty filter presses, EPA assumed that one truck would be required to ship the 

smallest size filter press and two trucks would be required to ship a medium or large size filter 

press. Based on information from FreightCenter.com and Siemens, the freight cost for a full 

truck may range from $1,400 to [Redacted]. EPA compared the freight cost to the vendorprovided unit purchase costs of the filter presses to develop a filter press freight cost factor of 1 

percent. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-55 

For plants with an FGD wastewater flow less than or equal to 350 gpm, filter presses are 

costed using Equation 6-102. 

Filter Press Cost (2011$) = Filter Press Freight Factor × Filter Press Qty × (2382.1 × Sludge 

 Factor × FGD Wastewater Treatment Flow GPM + 173777) (6-102) 

where: 

Filter Press Qty = Number of filter presses; for plants with an FGD 

Wastewater Treatment Flow GPM less than or equal to 

350 gpm (see Section 6.1.5), 2, 

Filter Press Freight 

Factor 

= Factor that accounts for freight cost as a percentage of 

purchase cost, 1.01, 

Sludge Factor = Factor to estimate the sludge generation rate based on 

the FGD Wastewater Treatment Flow GPM (see 

Section 6.1.5), 0.4, and 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow in gpm normalized for 24 hpd 

operation (see Section 6.1.5). 

For plants with an FGD wastewater flow greater than 350 gpm, filter presses are costed 

using Equation 6-103. 

Filter Press Cost (2011$) = Filter Press Freight Factor × Filter Press Qty × [2.7768 × (Sludge 

Factor × FGD Wastewater Treatment Flow GPM)2

 + 394.03 × Sludge Factor × FGD Wastewater 

 Treatment Flow GPM + 195398] (6-103) 

where: 

Filter Press Qty = Number of filter presses. For plants with an FGD 

Wastewater Treatment Flow GPM greater than 350 

gpm (see Section 6.1.5), 3, 

Filter Press Freight 

Factor 

= Factor that accounts for freight cost as a percentage of 

purchase cost, 1.01, 

Sludge Factor = Factor to estimate the sludge generation rate based on 

the FGD Wastewater Treatment Flow GPM (see 

Section 6.1.5), 0.4, and 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow in gpm normalized for 24 hpd 

operation (see Section 6.1.5). 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A35 through 

SE01825.A38) for more details on the development of Equations 6-102 and 6-103. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-56 

6.1.6.7 Purchased Equipment Costs: Gravity Sand Filters 

EPA requested vendor costs for various sizes of continuous backwash gravity sand filters 

appropriate for FGD wastewater flow rates ranging from 7 to 700 gpm. EPA created a cost 

function using costs obtained from the vendor to interpolate costs for each plant. Siemens 

provided costs of their standard sized units. The cost model assigns costs using a step function 

based on the treatment system flow rate [ERG, 2013; See Appendix 39 and 40]. 

EPA costed at least two 100 percent capacity continuous backwash gravity sand filters 

per plant. Where more than two filters are needed to accommodate FGD wastewater flow 

(determined as described later in this section), EPA costed the quantity of filters equal to the 

number of filters needed to provide 200 percent capacity. 

Siemens indicated that one flat bed truck per unit would be required to transport the 

filters. The truck freight cost, as provided by the vendor, is [Redacted]. EPA assumed a transport 

distance of 500 miles, yielding a cost of [Redacted] per truck or [Redacted] per filter unit. 

Additionally, separate freight costs are incurred to transport sand. EPA calculated sand freight 

costs based on the amount of sand required for each filter and the truck costs and capacities 

calculated previously (see Section 6.1.5). 

For each plant, EPA first calculated the expected FGD wastewater design flow, in gpm, 

through the wastewater treatment system. 

Expected Design Flow (gpm) = Capacity Factor × FGD Wastewater Treatment Flow 

 GPM (6-104) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted]. 

Cost equations were selected based on the expected design flow. 

For plants where the expected design flow was less than or equal to 20 gpm, EPA used 

Equation 6-105. 

Continuous Backwash Gravity Sand Filters Cost (2011$) = ($68,000 × Sand Filter Qty) + 

(Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost / 

 Truck Weight Capacity) (6-105)

where: 

Sand Filter Qty = Number of sand filters; within this flow rate range, two 

sand filters are required, 
Chapter 6 - FGD Wastewater Cost Methodology 

6-57 

Sand Weight = Amount of sand, in lbs, required for each sand filter 

unit; for the unit associated with this flow rate range, 

[Redacted] of sand are required, 

Flatbed Truck Cost = The cost for a full equipment shipment via flatbed 

truck approximately 500 miles (see Section 6.1.5), 

[Redacted], and 

Truck Weight Capacity = The maximum shipping weight a dry van truck can 

hold (see Section 6.1.5), 45,000 lbs. 

For plants where the expected design flow was greater than 20 gpm and less than or equal 

to 100 gpm, EPA used Equation 6-106. 

Continuous Backwash Gravity Sand Filters Cost (2011$) = ($80,000 × Sand Filter Qty) + 

(Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost / 

 Truck Weight Capacity) (6-106) 

where: 

Sand Filter Qty = Number of sand filters; within this flow rate range, two 

sand filters are required, 

Sand Weight = Amount of sand, in lbs, required for each sand filter 

unit; for the unit associated with this flow rate range, 

[Redacted] of sand are required, 

Flatbed Truck Cost = The cost for a full equipment shipment via flatbed 

truck approximately 500 miles (see Section 6.1.5), 

[Redacted], and 

Truck Weight Capacity = The maximum shipping weight a dry van truck can 

hold (see Section 6.1.5), 45,000 lbs. 

For plants where the expected design flow was greater than 100 gpm and less than or 

equal to 200 gpm, EPA used Equation 6-107. 

Continuous Backwash Gravity Sand Filters Cost (2011$) = ($98,000 × Sand Filter Qty) + 

(Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost 

 /Truck Weight Capacity) (6-107) 

where: 

Sand Filter Qty = Number of sand filters; within this flow rate range, two 

sand filters are required, 

Sand Weight = Amount of sand, in lbs, required for each sand filter 

unit; for the unit associated with this flow rate range, 

[Redacted] of sand are required, 
Chapter 6 - FGD Wastewater Cost Methodology 

6-58 

Flatbed Truck Cost = The cost for a full equipment shipment via flatbed 

truck approximately 500 miles (see Section 6.1.5), 

[Redacted], and 

Truck Weight Capacity = The maximum shipping weight a dry van truck can 

hold (see Section 6.1.5), 45,000 lbs. 

For plants where the expected design flow was greater than 200 gpm and less than or 

equal to 300 gpm, EPA used Equation 6-108. 

Continuous Backwash Gravity Sand Filters Cost (2011$) = ($180,000 × Sand Filter Qty) + 

(Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost / 

 Truck Weight Capacity) (6-108) 

where: 

Sand Filter Qty = Number of sand filters; within this flow rate range, two 

sand filters are required, 

Sand Weight = Amount of sand, in lbs, required for each sand filter 

unit; for the unit associated with this flow rate range, 

[Redacted] of sand are required, 

Flatbed Truck Cost = The cost for a full equipment shipment via flatbed 

truck approximately 500 miles (see Section 6.1.5), 

[Redacted], and 

Truck Weight Capacity = The maximum shipping weight a dry van truck can 

hold (see Section 6.1.5), 45,000 lbs. 

For plants where the expected design flow was greater than 300 gpm and less than or 

equal to 500 gpm, EPA used Equation 6-109. 

Continuous Backwash Gravity Sand Filters Cost (2011$) = ($98,000 × Sand Filter Qty) + 

(Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost / 

 Truck Weight Capacity) (6-109) 

where: 

Sand Filter Qty = Number of sand filters; within this flow rate range, four 

sand filters are required, 

Sand Weight = Amount of sand, in lbs, required for each sand filter 

unit; for the unit associated with this flow rate range, 

[Redacted] of sand are required, 

Flatbed Truck Cost = The cost for a full equipment shipment via flatbed 

truck approximately 500 miles (see Section 6.1.5), 

[Redacted], and 
Chapter 6 - FGD Wastewater Cost Methodology 

6-59 

Truck Weight Capacity = The maximum shipping weight a dry van truck can 

hold (see Section 6.1.5), 45,000 lbs. 

For plants where the expected design flow was greater than 500 gpm and less than or 

equal to 700 gpm, EPA used Equation 6-110. 

Continuous Backwash Gravity Sand Filters Cost (2011$) = ($180,000 × Sand Filter Qty) + 

(Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost / 

 Truck Weight Capacity) (6-110) 

where: 

Sand Filter Qty = Number of sand filters; within this flow rate range, four 

sand filters are required, 

Sand Weight = Amount of sand, in lbs, required for each sand filter 

unit; for the unit associated with this flow rate range, 

[Redacted] of sand are required, 

Flatbed Truck Cost = The cost for a full equipment shipment via flatbed 

truck approximately 500 miles (see Section 6.1.5), 

[Redacted], and 

Truck Weight Capacity = The maximum shipping weight a dry van truck can 

hold (see Section 6.1.5), 45,000 lbs. 

Based on conversations with the vendor, for flow rates greater than 700 gpm, EPA 

assumed that the large size filter press is applicable for wastewater flows up to 350 gpm per filter 

when multiple units are used. Therefore, EPA developed Equation 6-111 to calculate the number 

of sand filters required 

Sand Filter Qty = 2 × Expected Design Flow / 350 gpm (rounded up to the nearest whole 

 number) (6-111) 

For plants where the expected design flow was greater than 700 gpm EPA used Equation 

6-112 to estimate sand filter costs. 

Continuous Backwash Gravity Sand Filters Cost (2011$) = ($180,000 × Sand Filter Qty) + 

(Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost / 

 Truck Weight Capacity) (6-112) 

where: 

Sand Filter Qty = Number of sand filters, 

Sand Weight = Amount of sand, in lbs, required for each sand filter 

unit; for the unit associated with this flow rate range, 

[Redacted] of sand are required, 
Chapter 6 - FGD Wastewater Cost Methodology 

6-60 

Flatbed Truck Cost = The cost for a full equipment shipment via flatbed 

truck approximately 500 miles (see Section 6.1.5), 

[Redacted], and 

Truck Weight Capacity = The maximum shipping weight a dry van truck can 

hold (see Section 6.1.5), 45,000 lbs. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A39 through 

SE01825.A42) for more detail on the development of Equations 6-104 through 6-112. 

6.1.6.8 Purchased Equipment Installation Cost 

EPA determined these direct costs by multiplying plant-purchased equipment costs by a 

factor. The factor was determined based on responses to Question D6-3 of the Steam Electric 

Survey. To develop this factor, EPA first calculated, for each plant that completed Question D6-

3 specific to FGD wastewater chemical precipitation treatment, the ratio of each plant’s 

purchased equipment installation costs to their purchased equipment cost. After calculating this 

ratio for all applicable responses, EPA selected the factor, [Redacted], as the median ratio. See 

the Supplemental Costs and Loadings Documentation (DCN SE01825.A43) for additional 

information. 

EPA used Equation 6-113 to calculate purchased equipment installation costs. 

Purchased Equipment Installation Cost (2010$) = Installation Factor × Purchased Equipment 

 Cost (6-113) 

where: 

Installation Factor = The median ratio over all the plants of each plant’s 

purchased equipment installation costs to their 

purchased equipment cost, [Redacted], and 

Purchased Equipment 

Cost 

= The total purchased equipment cost required to treat 

FGD wastewater with one-stage chemical precipitation 

(Sections 6.1.6.1 through 6.1.6.7). 

6.1.6.9 Building Cost 

EPA determined these direct costs by multiplying plant purchased equipment costs by a 

factor generated based on responses to Question D6-3 of the Steam Electric Survey. To develop 

this factor, EPA first calculated, for each plant that completed Question D6-3 specific to FGD 

wastewater chemical precipitation treatment, the ratio of each plant’s buildings costs to their 

purchased equipment cost. After calculating this ratio for all applicable responses, EPA selected 

the factor, [Redacted], as the median ratio. See the Supplemental Costs and Loadings 

Documentation (DCN SE01825.A43) for additional information. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-61 

Note that EPA considered whether plants located in the northern United States with cold 

winter temperatures are more likely to use buildings than plants located in the southern United 

States. However, EPA found no basis to differentiate building costs based on location. 

EPA used Equation 6-114 to calculate buildings costs. 

 Building Cost (2010$) = Building Factor × Purchased Equipment Cost (6-114) 

where: 

Building Factor = The median ratio over all the plants of each plant’s 

buildings costs to their purchased equipment cost, 

[Redacted], and 

Purchased Equipment 

Cost 

= The total purchased equipment cost required to treat 

FGD wastewater with one-stage chemical precipitation 

(Sections 6.1.6.1 through 6.1.6.7). 

6.1.6.10 Land Cost 

To assess the need for land costs, EPA reviewed the responses to Question D6-3 of the 

Steam Electric Survey for each plant that completed this question specific to FGD wastewater 

chemical precipitation treatment. Based on this review, EPA determined that of the 20 plants 

included in this dataset, [Redacted] reported either zero costs or did not report any costs for land. 

For the remaining [Redacted] plants, reported land costs were very low (approximately 1 percent 

of purchase equipment costs). Accordingly, EPA assumed zero costs for land. See the 

Supplemental Costs and Loadings Documentation (DCN SE01825.A43) for additional 

information. 

6.1.6.11 Site Preparation Cost 

EPA determined site preparation direct costs by multiplying plant purchased equipment 

costs by a factor generated based on responses to Question D6-3 of the Steam Electric Survey. 

To develop this factor, EPA first calculated, for each plant that completed Question D6-3 

specific to FGD wastewater chemical precipitation treatment, the ratio of each plant’s site 

preparation costs to their purchased equipment cost. After calculating this ratio for all applicable 

responses, EPA selected the factor, [Redacted], as the median ratio. See the Supplemental Costs 

and Loadings Documentation (DCN SE01825.A43) for additional information. 

EPA used Equation 6-115 to calculate site preparation costs. 

 Site Preparation Cost (2010$) = Site Prep Factor × Purchased Equipment Cost (6-115) 

where: 

Site Prep Factor = The median ratio over all the plants of each plant’s site 

preparation costs to their purchased equipment cost, 
Chapter 6 - FGD Wastewater Cost Methodology 

6-62 

[Redacted], and 

Purchased Equipment 

Cost 

= The total purchased equipment cost required to treat 

FGD wastewater with one-stage chemical precipitation 

(Sections 6.1.6.1 through 6.1.6.7). 

6.1.6.12 Engineering Cost 

EPA determined engineering costs by multiplying plant purchased equipment costs by a 

factor generated based on responses to Question D6-3 of the Steam Electric Survey. To develop 

this factor, EPA first calculated, for each plant that completed Question D6-3 for FGD 

wastewater chemical precipitation treatment, the ratio of the sum of each plant’s two engineering 

costs (Engineering Contract Firm Costs and Owner’s Overhead Engineering Costs) to their 

purchased equipment. After calculating this ratio for all applicable responses, EPA selected the 

factor, [Redacted], as the median ratio. See the Supplemental Costs and Loadings 

Documentation (DCN SE01825.A43) for additional information. 

EPA used Equation 6-116 to calculate engineering cost: 

 Engineering Cost (2010$) = Engineering Factor × Purchased Equipment Cost (6-116) 

where: 

Engineering Factor = The median ratio over all the plants of the sum of each 

plant’s two engineering costs and their purchased 

equipment cost, [Redacted], and 

Purchased Equipment 

Cost 

= The total purchased equipment cost required to treat 

FGD wastewater with one-stage chemical precipitation 

(Sections 6.1.6.1 through 6.1.6.7). 

6.1.6.13 Construction Expenses 

EPA determined construction expenses by multiplying plant purchased equipment costs 

by a factor generated based on responses to Question D6-3 of the Steam Electric Survey. To 

develop this factor, EPA first calculated, for each plant that completed Question D6-3 for FGD 

wastewater chemical precipitation treatment, the ratio of each plant’s construction costs to their 

purchased equipment cost. After calculating this ratio for all applicable responses, EPA selected 

the factor, [Redacted], as the median ratio. See the Supplemental Costs and Loadings 

Documentation (DCN SE01825.A43) for additional information. 

EPA used Equation 6-117 to calculate construction expenses. 

 Construction Expenses (2010$) = Construction Factor × Purchased Equipment Cost (6-117) 
Chapter 6 - FGD Wastewater Cost Methodology 

6-63 

where: 

Construction Factor = The median ratio over all the plants of the sum of each 

plant’s construction costs to their purchased equipment 

cost, [Redacted], and 

Purchased Equipment 

Cost 

= The total purchased equipment cost required to treat 

FGD wastewater with one-stage chemical precipitation 

(Sections 6.1.6.1 through 6.1.6.7). 

6.1.6.14 Other Contractors’ Fees 

EPA determined other contractor’s fees by multiplying plant purchased equipment costs 

by a factor generated based on responses to Question D6-3 of the Steam Electric Survey. To 

develop this factor, EPA first calculated, for each plant that completed Question D6-3 for FGD 

wastewater chemical precipitation treatment, the ratio of each plant’s other contractor’s fees to 

their purchased equipment cost. After calculating this ratio for all applicable responses, EPA 

selected the factor, [Redacted], as the median ratio. See the Supplemental Costs and Loadings 

Documentation (DCN SE01825.A43) for additional information. 

EPA used Equation 6-118 to calculate other contractor’s fees. 

 Other Contractor’s Fees (2010$) = Contractor Factor × Purchased Equipment Cost (6-118) 

where: 

Contractor Factor = The median ratio over all the plants of each plant’s 

other contractor’s fees to their purchased equipment 

cost, [Redacted], and 

Purchased Equipment 

Cost 

= The total purchased equipment cost required to treat 

FGD wastewater with one-stage chemical precipitation 

(Sections 6.1.6.1 through 6.1.6.7). 

6.1.6.15 Contingency Fees 

To assess the need for contingency fees, EPA reviewed the responses to Question D6-3 

of the Steam Electric Survey for each plant that completed this question specific to FGD 

wastewater chemical precipitation treatment. Based on this review, EPA determined that 90 

percent of the plants reported either zero costs or did not report any costs for contingencies. EPA 

assumed that contingency costs for the remaining 10 percent of plants are site-specific and not 

representative of the industry. Accordingly, EPA assumed zero costs for contingencies. See the 

Supplemental Costs and Loadings Documentation (DCN SE01825.A43) for additional 

information. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-64 

6.1.7 O&M Cost Methodology

O&M costs comprise all costs related to operating and maintaining the chemical 

precipitation wastewater treatment system. O&M costs include the sum of the following: 

 Operating Labor Cost, 

 Maintenance Labor Cost, 

 Maintenance Material Cost, 

 Chemical Purchase Cost, and 

 Energy Cost. 

6.1.7.1 Operating Labor Cost 

EPA calculated operating labor costs for each plant based on plant FGD Wastewater 

Flow GPD (see Section 6.1.5). To calculate costs, EPA developed Equation 6-119, provided 

below, relating operating labor cost to FGD wastewater flow using responses to Question D6-2 

of the Steam Electric Survey specific to FGD wastewater chemical precipitation treatment. See 

the Supplemental Costs and Loadings Documentation (DCN SE01825.A44) for additional 

information. As plant’s provided the operating labor cost in 2009 dollars, EPA adjusted the cost 

basis to 2010 dollars using the 2009 and 2010 RSMeans Historical Cost Indices (180.1 and 

183.5, respectively) [RSMeans, 2011]. 

Operating Labor Cost (2010$/yr) = 0.2719 × (FGD Wastewater Flow GPD × 365)0.7789 × 2010 

 Cost Index/2009 Cost Index (6-119) 

where: 

FGD Wastewater Flow 

GPD 

= FGD wastewater flow in gpd as reported in the Steam 

Electric Survey (see Section 6.1.5), 

2009 Cost Index = 180.1, and 

2010 Cost index = 183.5. 

6.1.7.2 Maintenance Labor Cost 

EPA calculated maintenance labor costs by multiplying plant FGD Wastewater 

Treatment Flow GPM (see Section 6.1.5) by two cost factors: Maintenance Labor Rate and 

Maintenance Labor Factor. EPA determined the cost factors based on responses to Question D6-

2 of the Steam Electric Survey specific to FGD wastewater chemical precipitation treatment. To 

develop the Maintenance Labor Rate, EPA selected the median reported maintenance labor rate, 

[Redacted]. To develop the Maintenance Labor Factor, EPA first calculated, for each plant that 

completed Question D6-2 for FGD wastewater chemical precipitation treatment, the ratio of the 

number of hours per year needed to maintain the chemical precipitation treatment systems and 

the plant’s annual FGD wastewater treatment flow. After calculating this ratio for all applicable 

responses, EPA selected the factor [Redacted] as the median ratio. See the Supplemental Costs 
Chapter 6 - FGD Wastewater Cost Methodology 

6-65 

and Loadings Documentation (DCN SE01825.A46) for additional information. As plants 

provided the maintenance labor rate in 2009 dollars, EPA adjusted the cost basis to 2010 dollars 

using the 2009 and 2010 RSMeans Historical Cost Indices (180.1 and 183.5, respectively) 

[RSMeans, 2011]. 

EPA used Equation 6-120 to calculate annual maintenance labor costs. 

Maintenance Labor Cost (2010$/yr) = (Maintenance Labor Rate × Maintenance Labor Factor × 

FGD Wastewater Treatment Flow GPM × Minutes Per Year/Million Gallon Factor) × (2010 

 Cost Index/2009 Cost Index) (6-120) 

where: 

Maintenance Labor 

Rate 

= The median cost, in dollars per hour, of a chemical 

precipitation system maintenance worker, [Redacted], 

Maintenance Labor 

Factor 

= Median hours per year per million gallons of FGD 

wastewater treated per year required to maintain the 

chemical precipitation system, [Redacted], 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow in gpm normalized for 24 hpd 

operation (see Section 6.1.5), 

Minutes Per Year = Factor to convert between minutes and years, 525,600 

min/yr, 

Million Gallon Factor = Factor to convert between millions of gallons and 

gallons, 1,000,000 gal/million gal, 

2009 Cost Index = 180.1, and 

2010 Cost index = 183.5. 

6.1.7.3 Maintenance Materials Cost 

EPA calculated maintenance materials costs by multiplying plant FGD Wastewater 

Treatment Flow GPM (see Section 6.1.5) by a cost factor. EPA determined the cost factor based 

on responses to Questions D6-2 of the Steam Electric Survey specific to FGD wastewater 

chemical precipitation treatment. To develop the factor, EPA first calculated, for each plant that 

completed Question D6-2 for FGD wastewater chemical precipitation treatment, the ratio of the 

maintenance materials costs per year and the plant’s annual FGD wastewater treatment flow. 

After calculating this ratio for all applicable responses, EPA selected the factor [Redacted] as the 

median ratio. See the Supplemental Costs and Loadings Documentation (DCN SE01825.46) for 

additional information. As plants provided the maintenance materials cost in 2009 dollars, EPA 

adjusted the cost basis to 2010 dollars using the 2009 and 2010 RSMeans Historical Cost Indices 

(180.1 and 183.5, respectively) [RSMeans, 2011]. 

EPA used Equation 6-121 to calculate annual maintenance materials costs. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-66 

Maintenance Materials Cost (2010$/yr) = (Maintenance Materials Factor × FGD Wastewater 

Treatment Flow GPM × Minutes Per Year/Million Gallon Factor) × (2010 Cost Index/2009 Cost 

 Index) (6-121) 

where: 

Maintenance Materials 

Factor 

= The cost, in dollars per year per million gallons of FGD 

wastewater treated per year, of maintenance materials 

for the chemical precipitation system, [Redacted], 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow in gpm normalized for 24 hpd 

operation (see Section 6.1.5), 

Minutes Per Year = Factor to convert between minutes and years, 525,600 

min/yr, 

Million Gallon Factor = Factor to convert between millions of gallons and 

gallons, 1,000,000 gal/million gal, 

2009 Cost Index = 180.1, and 

2010 Cost index = 183.5. 

6.1.7.4 Chemical Purchase Cost 

EPA estimated the chemical purchase costs by multiplying the chemical dosage rate 

(expressed in grams of chemical per liter of wastewater flow) by the plant flow rate and by the 

chemical cost (expressed in dollars per ton) for each treatment chemical required. EPA 

determined the chemical dosage rates based on the average chemical dosage rates used by the 

BAT plants during sampling, listed below [ERG, 2013; See Appendix 47]: 

 Hydrated lime is added to reaction tank 1 at a dosage of [Redacted]; 

 Organosulfide is added to reaction tank 2 at a dosage of [Redacted]; 

 Ferric chloride is added to reaction tank 3 at a dosage of [Redacted]; 

 Polymer is added inline prior to the solids contact clarifier at a dosage of [Redacted]; 

and 

 Hydrochloric acid is added prior to sand filtration at a dosage of [Redacted]. 

EPA obtained the following chemical purchase costs from chemical suppliers [ERG, 

2013; See Appendix 48]: 

 Hydrated lime at [Redacted] per ton; 

 Organosulfide at [Redacted] per ton;31,32

 

31 EPA’s cost methodology is inconsistent in that this discussion assumes organosulfide and polymer purchase as 

solids while the feed system discussion in Section 6.1.6.3 assumes injection as liquids. For the final rule, EPA will 
Chapter 6 - FGD Wastewater Cost Methodology 

6-67 

 Ferric chloride at [Redacted] per dry ton; 

 Polymer at [Redacted] per ton;31 and 

 Hydrochloric acid (32 percent) at [Redacted] per ton. 

EPA developed a weighted chemical freight cost of $62.79 per ton, based on the required 

quantities of the various chemicals and their densities, and freight cost information by weight 

from FreightCenter.com. See the Supplemental Costs and Loadings Documentation (DCN 

SE01825.A49) for additional information. 

As plants provided the chemical purchase costs in 2011 dollars, EPA adjusted the cost 

basis to 2010 dollars using the 2010 and 2011 RSMeans Historical Cost Indices (183.5 and 185, 

respectively) [RSMeans, 2011]. The annual chemical purchase cost is calculated by Equation 

6-122. 

Chemical Purchase Cost (2010$/yr) = (Hydrated Lime Cost + Organosulfide Cost + Ferric 

Chloride Cost + Polymer Cost + Hydrochloric Acid Cost) × 2010 Cost Index/2011 Cost 

 Index (6-122) 

The remainder of this section discusses the development of the purchase costs for each of 

the required treatment chemicals. 

Hydrated Lime Cost

Hydrated Lime Cost (2011$/yr) = Hydrated Lime Dose × (Hydrated Lime Unit Cost + Chemical 

Freight Cost) × FGD Wastewater Treatment Flow GPM × Liters Per Gallon × Minutes Per Year 

 / (Hydrated Lime Concentration × Grams Per Ton) (6-123) 

where: 

Hydrated Lime Dose = Amount of lime, in grams per liter, needed to treat the 

FGD wastewater in the chemical precipitation system, 

[Redacted], 

Hydrated Lime Unit 

Cost 

= Lime cost, in dollars per ton of lime, [Redacted], 

Chemical Freight Cost = The weighted cost per ton to ship the various chemicals 

needed to operate the chemical precipitation system to 

the plant, $62.79, 

FGD Wastewater = FGD wastewater flow in gpm normalized for 24 hpd 

 

reevaluate the organosulfide and polymer purchase, freight, storage, and feed system methodologies and revise them 

as appropriate. In the interim, EPA considers the magnitude of the current estimated costs to be appropriate. 

32 EPA inappropriately used bulk quantity rather than drum/bulk bag quantity organosulfide purchase costs. 

Correcting this error would double organosulfide purchase costs. EPA notes, however, that organosulfide represents 

only a small percentage of total chemical purchase costs. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-68 

Treatment Flow GPM operation (see Section 6.1.5), 

Hydrated Lime 

Concentration 

= Concentration of lime in the form it is purchased,100 

percent, 

Liters Per Gallon = Factor to convert between liters and gallons, 3.7854 

liters/gal, 

Minutes Per Year = Factor to convert between minutes and years, 525,600 

min/yr, and 

Grams Per Ton = Factor to convert between grams and tons, 907,185 

g/ton. 

Organosulfide Cost

Organosulfide Cost (2011$/yr) = Organosulfide Dose × (Organosulfide Unit Cost + Chemical 

Freight Cost) × FGD Wastewater Treatment Flow GPM × Liters Per Gallon × Minutes Per Year 

 / (Organosulfide Concentration × Grams Per Ton) (6-124) 

where: 

Organosulfide Dose = Amount of organosulfide, in grams per liter, needed to 

treat the FGD wastewater in the chemical precipitation 

system, [Redacted], 

Organosulfide Unit 

Cost 

= Organosulfide cost, in dollars per ton of organosulfide, 

[Redacted], 

Chemical Freight Cost = The weighted cost per ton to ship the various chemicals 

needed to operate the chemical precipitation system to 

the plant, $62.79, 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow in gpm normalized for 24 hpd 

operation (see Section 6.1.5), 

Organosulfide 

Concentration 

= Concentration of organosulfide in solution as 

purchased, 100 percent, 

Liters Per Gallon = Factor to convert between liters and gallons, 3.7854 

liters/gal, 

Minutes Per Year = Factor to convert between minutes and years, 525,600 

min/yr, and 

Grams Per Ton = Factor to convert between grams and tons, 907,185 

g/ton. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-69 

Ferric Chloride Cost

Ferric Chloride Cost (2011$/yr) = Ferric Chloride Dose × (Ferric Chloride Unit Cost + Chemical 

Freight Cost) × FGD Wastewater Treatment Flow GPM × Liters Per Gallon × Minutes Per Year 

 / (Ferric Chloride Concentration × Grams Per Ton) (6-125) 

where: 

Ferric Chloride Dose = Amount of ferric chloride, in grams per liter, needed to 

treat the FGD wastewater in the chemical precipitation 

system, [Redacted], 

Ferric Chloride Unit 

Cost 

= Ferric chloride cost, in dollars per ton of ferric chloride, 

[Redacted], 

Chemical Freight Cost = The weighted cost per ton to ship the various chemicals 

needed to operate the chemical precipitation system to 

the plant, $62.79, 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow in gpm normalized for 24 hpd 

operation (see Section 6.1.5), 

Ferric Chloride 

Concentration 

= Dry weight concentration of ferric chloride in 

solution,100 percent, 

Liters Per Gallon = Factor to convert between liters and gallons, 3.7854 

liters/gal, 

Minutes Per Year = Factor to convert between minutes and years, 525,600 

min/yr, and 

Polymer Cost

Polymer Cost (2011$/yr) = Polymer Dose × (Polymer Unit Cost + Chemical Freight Cost) ×

FGD Wastewater Treatment Flow GPM × Liters Per Gallon × Minutes Per Year / (Polymer 

 Concentration × Grams Per Ton) (6-126) 

where: 

Polymer Dose = Amount of polymer, in grams per liter, needed to treat 

the FGD wastewater in the chemical precipitation 

system, [Redacted], 

Polymer Unit Cost = Polymer cost, in dollars per ton of polymer, 

[Redacted], 

Chemical Freight Cost = The weighted cost per ton to ship the various chemicals 

needed to operate the chemical precipitation system to 

the plant, $62.79, 
Chapter 6 - FGD Wastewater Cost Methodology 

6-70 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow in gpm normalized for 24 hpd 

operation (see Section 6.1.5), 

Polymer Concentration = Concentration of polymer in solution as purchased,100 

percent, 

Liters Per Gallon = Factor to convert between liters and gallons, 3.7854 

liters/gal, 

Minutes Per Year = Factor to convert between minutes and years, 525,600 

min/yr, and 

Grams Per Ton = Factor to convert between grams and tons, 907,185 

g/ton. 

Hydrochloric Acid Cost

Hydrochloric Acid Cost (2011$/yr) = Hydrochloric Acid Dose × (Hydrochloric Acid Unit Cost + 

Chemical Freight Cost) × FGD Wastewater Treatment Flow GPM × Liters Per Gallon × Minutes 

 Per Year / (Hydrochloric Acid Concentration × Grams Per Ton) (6-127) 

where: 

Hydrochloric Acid 

Dose 

= Amount of hydrochloric acid, in grams per liter, needed 

to treat the FGD wastewater in the chemical 

precipitation system, [Redacted], 

Hydrochloric Acid Unit 

Cost 

= Hydrochloric acid cost, in dollars per ton of 

hydrochloric acid, [Redacted], 

Chemical Freight Cost = The weighted cost per ton to ship the various chemicals 

needed to operate the chemical precipitation system to 

the plant, $62.79, 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow in gpm normalized for 24 hpd 

operation (see Section 6.1.5), 

Hydrochloric Acid 

Concentration 

= Concentration of hydrochloric acid in solution as 

purchased, 32 percent, 

Liters Per Gallon = Factor to convert between liters and gallons, 3.7854 

liters/gal, 

Minutes Per Year = Factor to convert between minutes and years, 525,600 

min/yr, and 

Grams Per Ton = Factor to convert between grams and tons, 907,185 

g/ton. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-71 

6.1.7.5 Energy Cost 

EPA determined overall chemical precipitation energy requirements (in kilowatt hour 

(kWh)) by calculating the power requirements per day for each piece of equipment based on 

information, largely in the form of horsepower, provided by equipment vendors. EPA assumed 

24-hour-per-day operation of all treatment system equipment except the filter press. To calculate 

the annual energy requirements, EPA multiplied the daily requirements by 365 days per year. 

The total annual energy requirement is calculated using Equation 6-128. 

Annual Energy Requirement (kWh/yr) = (Wastewater Feed Pump Energy + Wastewater 

Forwarding Pump Energy + Sludge Recycle/Transfer Pumps Energy + Filter Press 

Feed/Pressurization Pumps Energy + Treated Wastewater Pumps Energy + Sump Pump Energy 

+ Lime Slurry Pump Energy + FGD Recycle Pump Energy + Lime Feed System Energy + Ferric 

Chloride Feed System Energy + Organosulfide Feed System Energy + Polymer Feed System 

Energy + Hydrochloric Acid Feed System Energy + Equalization Tank Mixer Energy + Reaction 

Tank 1 Mixer Energy + Reaction Tank 2 Mixer Energy + Reaction Tank 3 Mixer Energy + 

Sludge Holding Tank Mixer Energy + Lime Slurry Preparation Tank Mixer Energy + Filtrate 

Sump Mixer Energy + Solids Contact Clarifier Energy + Filter Press Energy + Sand Filters 

 Energy) × 365 Days Per Year (6-128) 

To calculate annual energy costs, EPA then multiplied the total annual energy 

requirement by the average national energy cost of 4.05 cents per kWh (2009$) as determined 

based on data reported by the U.S. Energy information Administration in Table 8.2 of the 

Electric Power Annual 2009 for fossil plants in the United States [U.S. DOE, 2011]. As the 

energy cost was provided in 2009 dollars, EPA adjusted the cost basis to 2010 dollars using the 

2009 and 2010 RSMeans Historical Cost Indices (180.1 and 183.5, respectively) [RSMeans, 

2011]. The chemical precipitation cost module outputs both overall energy requirements and 

energy costs to allow flexibility for further analyses of this cost element. 

Energy Cost (2010$/yr) = National Energy Cost × Annual Energy Requirement × (2010 Cost 

 Index/2009 Cost Index) (6-129) 

where: 

National Energy Cost = $0.0405/kWh (2009$), 

Annual Energy 

Requirement 

= Annual power requirements to operate all equipment 

required for chemical precipitation of FGD wastewater, 

in kWh/yr, 

2009 Cost Index = 180.1, and 

2010 Cost index = 183.5. 

For the purpose of estimating non-water quality environmental impacts, EPA also 

converted energy consumption in kWh/yr to energy load in MW using Equation 6-130. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-72 

Energy Load (MW) = Annual Energy Requirement / (24 hpd × 365 dpy × 1,000 

 kW/MW) (6-130) 

Pump electricity requirements are based on the horsepower (hp) of each pump motor. 

EPA developed equations predicting the horsepower of a pump motor based on the FGD 

wastewater flow. See the Supplemental Costs and Loadings Documentation (DCN 

SE01825.A50) for additional information. EPA converted horsepower to kilowatts and 

calculated kilowatt-hours assuming 24-hour operation. Where excess pumps are costed for 

redundancy, this excess capacity, placed in standby, is not considered in the electricity 

requirements. 

Tanks have no energy requirement. 

Regarding liquid chemical feed systems, Enpro-Tech indicated that each liquid chemical 

feed system (e.g., ferric chloride, polymer) requires at most a 1⁄2 hp motor. The liquid feed system 

energy requirement is calculated based on the horsepower of the required motor and the number 

of feed points required to treat the wastewater, as defined in Section 6.1.6.3. 

To calculate the mixer energy requirements, EPA assumed the mixer torque is 

proportional to mixer horsepower (see Section 6.1.6.4). EPA calculated the ratio of horsepower 

to torque for each of the example plant’s mixers. EPA multiplied this value by the plant-specific 

torque, calculated as the torque per volume, multiplied by the tank size. The detailed equations 

are defined below. Note that the mixer and tank size calculations are described in Sections 

6.1.6.4 and 6.1.6.2, respectively. 

Wastewater Feed Pump Energy

EPA assumed that plants will use existing FGD wastewater feed pumps to move FGD 

wastewater from the FGD system to the equalization tank of the new chemical precipitation 

treatment system (or to the existing FGD impoundment, for certain “high flow” plants (see 

Section 4.4.3). Therefore, EPA assumed there are no incremental energy requirements for these 

pumps. 

Wastewater Forwarding Pump Energy

The wastewater forwarding pump energy requirements are determined with Equation 

6-131. 

Wastewater Forwarding Pump Energy (kWh/day) = (0.0151 × Capacity Factor × FGD 

 Wastewater Treatment Flow GPM + 2.0191) × hp KW Factor × Operating Hours (6-131) 

where: 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 
Chapter 6 - FGD Wastewater Cost Methodology 

6-73 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Sludge Recycle/Transfer Pumps Energy

The sludge recycle and transfer pump energy requirements are based on the lime slurry 

pump energy requirements. Three sludge pumps are included in calculating energy requirements: 

one for each clarifier and one for sludge recycle. The sludge pump energy requirements are 

determined with Equation 6-132. 

Sludge Recycle/Transfer Pumps Energy (kWh/day) = (0.0205 × Sludge Factor × FGD 

Wastewater Treatment Flow GPM + 0.7831) × hp KW Factor × Operating Hours × 3 

 pumps (6-132) 

where: 

Sludge Factor = Factor to estimate the sludge generation rate based on 

the FGD Wastewater Treatment Flow GPM (see 

Section 6.1.5), 0.4, 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Filter Press Feed/Pressurization Pumps Energy

The energy requirements for filter press feed/pressurization pumps are included in the 

filter press electricity requirements. 

Treated Wastewater Discharge Pumps Energy

Where wastewater flow rates trigger the costing of multiple treated wastewater tanks, 

multiple pumps are costed. Note that the quantity of treated wastewater tanks is calculated in 

Section 6.1.6.2. The treated wastewater discharge pump energy requirements are determined 

using Equation 6-133. 

Treated Wastewater Pumps Energy (kWh/day) = (0.0182 × Capacity Factor × FGD Wastewater 

Treatment Flow GPM + 0.6031) × hp KW Factor × Operating Hours × Treated WW 

 Tank Qty (6-133) 
Chapter 6 - FGD Wastewater Cost Methodology 

6-74 

where: 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, 

Operating Hours = System operating hours per day, 24, and 

Treated WW Tank Qty = The number of treated wastewater tanks, rounded up to 

the nearest whole number (see Section 6.1.6.2 and 

Equation 6-32). 

Sump Pump Energy

The sump pump energy requirements are determined with Equation 6-134. 

Sump Pump Energy (kWh/day) = (0.0229 × Capacity Factor × FGD Wastewater Treatment 

 Flow GPM + 0.9268) × hp KW Factor × Operating Hours (6-134) 

where: 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Lime Slurry Pump Energy

Lime slurry pump energy requirements are included in the energy requirements of the 

lime feed system. 

FGD Recycle Pump Energy 

The FGD recycle pump energy requirements, associated with certain “high flow” plants 

(see Section 4.4.3), are determined using Equation 6-135. 

FGD Recycle Pump Energy (kWh/day) = (0.0151 × Capacity Factor × FGD Wastewater 

 Treatment Flow GPM + 2.0191) × hp KW Factor × Operating Hours (6-135) 
Chapter 6 - FGD Wastewater Cost Methodology 

6-75 

where: 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Lime Feed System Energy

EPA assumed that the lime feed system energy requirement is primarily pump energy 

consumption. Enpro-Tech indicated that a typical lime feed system includes slurry pumps with 

capacities of up to 40 to 60 gpm. EPA estimated a pump horsepower to be equal to that of one 

[Redacted] lime slurry pump, based on pump information provided by Weir Minerals [ERG, 

2013; See Appendix 6]. 

Lime Slurry Feed System Energy (kWh/day) = [Redacted] × hp KW Factor × Operating 

 Hours (6-136)

where: 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Ferric Chloride Feed System Energy

FeCl3 Feed System Energy (kWh/day) = FeCl3 Feed Point Qty × Feed hp × hp KW Factor × 

 Operating Hours (6-137) 

where: 

FeCl3 Feed Point Qty = The number of ferric chloride feed points required to 

treat FGD wastewater, rounded up to the nearest whole 

number (see Section 6.1.6.3 and Equation 6-58), 

Feed hp = The horsepower required by the motor used in a liquid 

feed system, 0.5 hp, 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-76 

Organosulfide Feed System Energy

Organosulfide Feed System Energy (kWh/day) = Sulfide Feed Point Qty × Feed hp × hp KW 

 Factor × Operating Hours (6-138) 

where: 

Sulfide Feed Point Qty = The number of organosulfide feed points required to 

treat FGD wastewater, rounded up to the nearest whole 

number (see Section 6.1.6.3 and Equation 6-63), 

Feed hp = The horsepower required by the motor used in a liquid 

feed system, 0.5 hp, 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Polymer Feed System Energy

Polymer Feed System Energy (kWh/day) = Polymer Feed Point Qty × Feed hp × hp KW Factor 

 × Operating Hours (6-139) 

where: 

Polymer Feed Point 

Qty 

= The number of polymer feed points required to treat 

FGD wastewater, rounded up to the nearest whole 

number (see Section 6.1.6.3 and Equation 6-67), 

Feed hp = The horsepower required by the motor used in a liquid 

feed system, 0.5 hp, 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Hydrochloric Acid Feed System Energy

HCl Feed System Energy (kWh/day) = HCl Feed Point Qty × Feed hp × hp KW Factor × 

 Operating Hours (6-140) 

where: 

HCl Feed Point Qty = The number of hydrochloric acid feed points required 

to treat FGD wastewater, rounded up to the nearest 

whole number (see Section 6.1.6.3 and Equation 6-71), 
Chapter 6 - FGD Wastewater Cost Methodology 

6-77 

Feed hp = The horsepower required by the motor used in a liquid 

feed system, 0.5 hp, 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Equalization Tank Mixer Energy

Eq Mixer HP (hp) = Eq Mixer Torque Per Volume × Equalization Tank Size × Example Plant Eq 

 Mixer HP / Example Plant Eq Mixer Torque (6-141) 

Equalization Tank Mixer Energy (kWh/day) = Eq Mixer HP × hp KW Factor × Operating 

 Hours (6-142) 

where: 

Eq Mixer Torque Per 

Volume 

= The calculated torque per volume for the equalization 

tank (see Section 6.1.6.4 and Equation 6-77), 

Equalization Tank Size = The calculated equalization tank size (see Section 

6.1.6.2 and Equation 6-16), 

Example Plant Eq 

Mixer HP 

= The example plant’s equalization tank mixer’s 

horsepower (see Section 6.1.6.4), 

Example Plant Eq 

Mixer Torque 

= The torque of the equalization tank mixer used by the 

example plant (see Section 6.1.6.4), 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Reaction Tank 1 Mixer Energy

Rxn1 Mixer HP (hp) = Rxn1 Mixer Torque Per Volume × Reaction Tank 1 Size × Example Plant 

 Rxn1 Mixer HP / Example Plant Rxn1 Mixer Torque (6-143) 

Reaction Tank 1 Mixer Energy (kWh/day) = Rxn1 Mixer HP × hp KW Factor × Operating 

 Hours (6-144) 

where: 

Rxn1 Mixer Torque Per 

Volume 

= The calculated torque per volume for the reaction tank 

1 mixer (see Section 6.1.6.4 and Equation 6-81), 

Reaction Tank 1 Size = The calculated reaction tank 1 size (see Section 6.1.6.2 

and Equation 6-21), 
Chapter 6 - FGD Wastewater Cost Methodology 

6-78 

Example Plant Rxn1 

Mixer HP 

= The example plant’s reaction tank 1 mixer’s 

horsepower (see Section 6.1.6.4), 

Example Plant Rxn1 

Mixer Torque 

= The torque of the reaction tank 1 mixer used by the 

example plant (see Section 6.1.6.4), 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Reaction Tank 2 Mixer Energy

Rxn2 Mixer HP (hp) = Rxn2 Mixer Torque Per Volume × Reaction Tank 2 Size × Example Plant 

 Rxn2 Mixer HP / Example Plant Rxn2 Mixer Torque (6-145) 

Reaction Tank 2 Mixer Energy (kWh/day) = Rxn2 Mixer HP × hp KW Factor × Operating 

 Hours (6-146) 

where: 

Rxn2 Mixer Torque Per 

Volume 

= The calculated torque per volume for reaction tank 2 

mixer (see Section 6.1.6.4 and Equation 6-85), 

Reaction Tank 2 Size = The calculated reaction tank 2 size (see Section 6.1.6.2 

and Equation 6-25), 

Example Plant Rxn2 

Mixer HP 

= The example plant’s reaction tank 2 mixer’s 

horsepower (see Section 6.1.6.4), 

Example Plant Rxn2 

Mixer Torque 

= The torque of the reaction tank 2 mixer used by the 

example plant (see Section 6.1.6.4), 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Reaction Tank 3 Mixer Energy

Rxn3 Mixer HP (hp) = Rxn3 Mixer Torque Per Volume × Reaction Tank 3 Size × Example Plant 

 Rxn3 Mixer HP / Example Plant Rxn3 Mixer Torque (6-147) 

Reaction Tank 3 Mixer Energy (kWh/day) = Rxn3 Mixer HP × hp KW Factor × Operating 

 Hours (6-148) 

where: 

Rxn3 Mixer Torque Per 

Volume 

= The calculated torque per volume for reaction tank 3 

(see Section 6.1.6.4 and Equation 6-89), 
Chapter 6 - FGD Wastewater Cost Methodology 

6-79 

Reaction Tank 3 Size = The calculated reaction tank 3 size (see Section 6.1.6.2 

and Equation 6-29), 

Example Plant Rxn3 

Mixer HP 

= The example plant’s reaction tank 3 mixer’s 

horsepower (see Section 6.1.6.4), 

Example Plant Rxn3 

Mixer Torque 

= The torque of the reaction tank 3 mixer used by the 

example plant (see Section 6.1.6.4), 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Sludge Holding Tank Mixer Energy

Sldg Mixer HP (hp) = Sldg Mixer Torque Per Volume × Sludge Holding Tank Size × Example 

 Plant Sldg Mixer HP / Example Plant Sldg Mixer Torque (6-149) 

Sludge Holding Tank Mixer Energy (kWh/day) = Sldg Mixer HP × hp KW Factor × Operating 

 Hours (6-150) 

where: 

Sldg Mixer Torque Per 

Volume 

= The calculated torque per volume for the sludge 

holding tank mixer (see Section 6.1.6.4 and Equation 

6-93), 

Sludge Holding Tank 

Size 

= The calculated sludge holding tank size (see Section 

6.1.6.2 and Equation 6-36), 

Example Plant Sldg 

Mixer HP 

= The example plant’s sludge holding tank mixer’s 

horsepower (see Section 6.1.6.4), 

Example Plant Sldg 

Mixer Torque 

= The torque of the sludge holding tank mixer used by 

the example plant (see Section 6.1.6.4), 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Lime Slurry Preparation Tank Mixer Energy

EPA did not cost lime slurry preparation tank mixers because mixers were included in the 

overall feed system cost. Because separate mixers were not required, EPA did not calculate lime 

slurry preparation tank mixer energy requirements. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-80 

Filtrate Sump Mixer Energy

Sump Mixer HP (hp) = Eq Mixer Torque Per Volume × Sump Size × Example Plant Eq Mixer 

 HP / Example Plant Eq Mixer Torque (6-151) 

Filtrate Sump Mixer Energy (kWh/day) = Sump Mixer HP × hp KW Factor × Operating 

 Hours (6-152) 

where: 

Eq Mixer Torque Per 

Volume 

= The calculated torque per volume for the equalization 

tank (see Section 6.1.6.4 and Equation 6-77), 

Sump Size = The calculated sump size in gallons (see Section 

6.1.6.4 and Equation 6-95), 

Example Plant Eq 

Mixer HP 

= The example plant’s equalization tanks mixer’s 

horsepower (see Section 6.1.6.4), 

Example Plant Eq 

Mixer Torque 

= The torque of the equalization tank mixer used by the 

example plant (see Section 6.1.6.4), 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Solids Contact Clarifiers Energy

EPA calculated energy requirements for two solids contact clarifiers per plant. The 

energy requirements include the mixer drive energy requirements and the scraper drive energy 

requirements. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A50) 

for additional information. 

The mixer drive horsepower ranges from 2 to 5 hp depending on the size of unit. EPA 

developed the following equation relating mixer drive horsepower to FGD wastewater flow. 

SC Mixer Drive hp (hp) = 0.005 × Capacity Factor × FGD Wastewater Treatment Flow GPM + 

 1.5 (6-153) 

where: 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], and 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5). 

The solids contact clarifier vendor indicated the scraper drive horsepower is 0.25 hp for 

the biggest clarifier. EPA assumed the scraper drive horsepower was the same for all units. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-81 

Solids Contact Clarifier Energy (kWh/day) = 2 × (SC Mixer Drive hp + Scraper Drive hp) × hp 

 KW Factor × Operating Hours (6-154) 

where: 

SC Mixer Drive hp = Horsepower of the solids contact clarifier mixer drive 

(see Equation 6-153), 

Scraper Drive hp = Horsepower of the solids contact clarifier scraper drive, 

0.25 hp, 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

Filter Press Energy

Andritz Separation provided electricity requirements for filter presses appropriate for 

three sludge flow rates. EPA developed Equation 6-155 based on the data provided to predict 

electricity requirements based on the average plant flow rate after equalization in gallons per 

minute. Andritz Separation costed filter presses assuming operation of 15 cycles per day where 

each cycle lasted 1.5 hours. Note that the quantity of filter presses is calculated in Section 

6.1.6.6. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A51) for 

additional information. 

Filter Press Energy (kWh/day) = Filter Press Qty × (0.047 × Sludge Factor × FGD Wastewater 

Treatment Flow GPM + 4.1937) × hp KW Factor × FP Cycles Per Day × FP Hours Per 

 Cycle (6-155) 

where: 

Filter Press Qty = Number of filter presses; based on the FGD 

Wastewater Treatment Flow GPM, (see Section 

6.1.6.6), 

Sludge Factor = Factor to estimate the sludge generation rate based on 

the FGD Wastewater Treatment Flow GPM (see 

Section 6.1.5), 0.4, 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, 

FP Cycles Per Day = The number of filter press cycles operated per day, 15, 

and 

FP Hours Per Cycle = The number of hours per filter press cycle, 1.5 hours. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-82 

Sand Filters Energy

The only major power requirement associated with sand filters is the motive air 

requirement of the process. It ranges from [Redacted] standard cubic feet per minute (scfm) at a 

minimal pressure of [Redacted] psi. This air can be supplied by air compressor systems that are 

in the [Redacted] hp range. Note that the quantity of sand filters is calculated in Section 6.1.6.7. 

Sand Filter Energy (kWh/day) = Sand Filter Qty × Filter hp × hp KW Factor × Operating 

 Hours (6-156) 

where: 

Sand Filter Qty = Number of sand filters; based on FGD Wastewater 

Treatment Flow GPM, (see Section 6.1.6.7), 

Filter hp = Horsepower of the air compressor system needed to 

fulfill the sand filter motive air requirements, 

[Redacted]. 

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, and 

Operating Hours = System operating hours per day, 24. 

6.1.8 Sludge Disposal Cost

EPA determined dewatered sludge generation rates for chemical precipitation treatment 

by multiplying a flow-normalized dewatered sludge generation rate (expressed in tpd/gpm) by 

the plant FGD wastewater flow rate. The flow-normalized dewatered sludge generation rate was 

determined based on responses to Question D3-2 of the Steam Electric Survey specific to FGD 

wastewater chemical precipitation treatment. EPA selected the median flow-normalized 

dewatered sludge generation rate, [Redacted] tons per day per gallon per minute of FGD 

wastewater flow. See the Supplemental Costs and Loadings Documentation (DCN SE01825.52) 

for additional information. EPA then calculated the annual sludge generation using Equation 

6-157. 

Annual Sludge Generation (tons/yr) = Sludge Generation Rate × FGD Wastewater Treatment 

 Flow GPM × 60 min/hr × 24 hr/day × 365 day/year (6-157) 

where: 

Sludge Generation Rate = Median sludge generation per FGD wastewater treated, 

in tons per day per gallon per minute of FGD 

wastewater flow, [Redacted], and 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5). 
Chapter 6 - FGD Wastewater Cost Methodology 

6-83 

Additionally, EPA calculated the bulk density of the sludge based on the composition of 

the sludge for use in calculating costs for transportation and disposal of chemical precipitation 

sludge. EPA assumed that 50 percent of the sludge would be water, and the remaining 50 percent 

would be an equal mix of gypsum, hydrated lime, and limestone. 

EPA calculated the bulk density using Equation 6-158. 

Sludge Bulk Density (lb/ft3) = 0.5 × Water Density + 0.5 × (Gypsum Density + Hydrated Lime 

 Density + Limestone Density)/3 (6-158) 

where: 

Water Density = The density of water in pounds per cubic foot, 62.4, 

Gypsum Density = The density of gypsum in pounds per cubic foot, 143.5, 

Hydrated Lime Density = The density of hydrated lime in pounds per cubic foot, 

30, and 

Limestone Density = The density of limestone in pounds per cubic foot, 87. 

The resulting sludge bulk density is 74.6 lb/ft3.

Sections 5.3 and 5.4 discuss costs for the transportation and disposal of sludge from the 

chemical precipitation system. 

6.1.9 Mercury Analyzer Cost Methodology

EPA estimated costs associated with installing and operating an analyzer to determine 

mercury concentrations in the treated effluent stream of the FGD wastewater and landfill 

leachate treatment systems. Based on site visits, untreated FGD wastewater can contain elevated 

mercury concentrations based on a variety of different plant operating characteristics. A properly 

designed and operated BAT system should be able to accommodate these elevated mercury 

concentrations and remain in compliance with the proposed ELGs. However, to ensure that the 

effluent discharged from the FGD wastewater system meet the proposed ELGs, EPA included 

costs for a mercury analyzer and extra equipment to analyze mercury in the discharge and 

recycle the discharge for further treatment if necessary. Using this equipment will allow plants to 

test the mercury in the effluent several times a day (at most 200 samples per week) and be 

provided with immediate feedback on the effluent quality of the treated water to ensure 

compliance with the ELGs. This mercury analyzer is meant as a process control aid and to 

provide extra assurance that the system is operating as designed. If the system is not operating as 

designed and wastewater is not in compliance, the plant can recycle the treated water back to the 

equalization tank and adjust the system (i.e., add additional chemicals) to further treat the 

wastewater to meet the proposed ELGs. This section discusses the technology, population 

costed, and the specific costs associated with installing and operating the mercury analyzer. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-84 

6.1.9.1 Technology Description 

EPA included the costs for a mercury analyzer in the overall costs for the chemical 

precipitation system for FGD wastewater and landfill leachate to monitor the concentration of 

mercury in the treated effluent stream. Along with the analyzer, EPA included costs for a pump 

and length of piping to route treated effluent from the effluent tank back to the equalization tank 

at the beginning of the wastewater treatment system.33 This approach will allow the plant to 

recycle any effluent that does not meet mercury effluent limits back through the treatment 

system. By monitoring the mercury effluent concentration, plants will be able to adjust chemical 

dosages and recycle flow to ensure effluent limits will not be exceeded. 

6.1.9.2 Population Costed 

EPA included the cost to install and operate a mercury analyzer for all plants discharging 

FGD wastewater and landfill leachate. The plants incurring costs for a mercury analyzer are the 

same set of plants incurring compliance monitoring costs associated with mercury. 

6.1.9.3 Capital Cost Methodology 

Capital costs associated with installing the mercury analyzer include the cost of the 

mercury analyzer, as well as the equipment needed to recycle off-specification effluent back to 

the beginning of the treatment system. This equipment includes a set of recycle pumps and a 

length of fiberglass-reinforced plastic pipe. 

Mercury Analyzer

EPA assessed each plant an initial capital cost to purchase the mercury analyzer prior to 

the start-up of the chemical precipitation system. Based on communication with Milestone, Inc, 

EPA estimates the cost of one mercury analyzer to be $85,307 in 2010 dollars. See the 

Supplemental Costs and Loadings Documentation (DCN SE01825.A67) for additional 

information. 

Recycle Pump 

EPA costed two 100 percent capacity, skid-mounted, horizontal centrifugal pumps to 

recycle treated effluent from the treated wastewater tank to the equalization tank. These pumps 

are modeled off the treated wastewater discharge pumps found in one-stage chemical 

precipitation (see Section 6.1.6.1 and Equation 6-4). 

Recycle Pump (2010$) = [0.0049 × (Capacity Factor × FGD Wastewater Treatment Flow GPM)2

+ 8.2408 × (Capacity Factor × FGD Wastewater Treatment Flow GPM) + 7758.6] × Pump 

 Freight Factor × Recycle Pump Qty × (Cost Index 2010/Cost Index 2011) (6-159) 

 

33 Typically, wastewater treatment systems are designed to include a pump and length of piping to route treated 

effluent from the effluent tank back to the equalization tank. Including this cost as part of the mercury analyzer cost 

estimate may be an overestimate. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-85 

where: 

Capacity Factor = Factor that accounts for design flow, [Redacted] (see 

Section 6.1.5), 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

Recycle Pump Qty = Number of treated wastewater recycle pumps, 2, 

Pump Freight Factor = Factor that accounts for freight cost as a percentage of 

purchase cost, 1.04 (See Section 6.1.6.1), 

Cost Index 2010 = 183.5, and 

Cost Index 2011 = 185. 

Recycle Piping

EPA costed a length of fiberglass-reinforced plastic pipe to span from the treated effluent 

tank back to the equalization tank. EPA used data from Question D2-7 of the Steam Electric 

Survey to determine the average footprint for an FGD wastewater treatment system. To 

conservatively estimate the piping distance, EPA assumed the total area to be a rectangle and that 

the piping would be run around the perimeter of the system from one corner to the corner 

diagonally opposite. Using this methodology, the average pipe length was determined to be 713 

feet. EPA developed Equation 6-160 to calculate the cost of the piping and adjusted the result to 

2010 dollars using cost indices from RSMeans. 

Piping Cost (2010$) = PipeCost × Distance × PipeFreightFactor × Cost Index2010/Cost Index 

 2011 (6-160) 

where: 

PipeCost = Cost of the fiberglass-reinforced plastic pipe in dollars 

per foot; see table below for values, 

Distance = 713 feet, 

PipeFreightFactor = Factor that accounts for freight cost as a percentage of 

purchase cost, 1.002, 

Cost Index 2010 = 183.5, and 

Cost Index 2011 = 185. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-86 

FGD Wastewater Flow Range (gpm) Pipe Cost ($/foot) 

0-125 2.09 

125-250 2.95 

250-450 3.96 

450-1,050 6.05 

1,050-1,850 8.03 

1,850-2,900 10.05 

2,900-4,150 12.02 

Source: FRPpiping.com. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A67) for 

additional information. 

6.1.9.4 O&M Cost Methodology 

O&M costs associated with the mercury analyzer include the cost of consumables needed 

to operate the analyzer, which include catalyst tubes and an amalgamator, as well as the cost of 

electricity to operate the recycle pumps. 

Mercury Analyzer Consumable Costs

Based on discussions with Milestone, Inc, a vendor of the mercury analyzer, EPA 

estimates that each plant will be able to analyze approximately 200 samples per week. Based on 

data from the vendor, this sampling frequency would result in replacing consumables once every 

quarter, or four times per year. EPA used Equation 6-161 to calculate the yearly cost associated 

with consumables for the mercury analyzer. See the Supplemental Costs and Loadings 

Documentation (DCN SE01825.A67) for additional information. 

Cost of Consumables (2010$/year) = Consumable Unit Cost × Consumable Frequency × (Cost 

 Index 2010/Cost Index 2011) (6-161) 

where: 

Consumable Unit Cost = $600 in 2011 dollars, 

Consumable Frequency = Four times per year, 

Cost Index 2010 = 183.5, and 

Cost Index 2011 = 185. 

Recycle Pump Electricity Cost

EPA assumed that only one recycle pump would be operating at any one time. Electricity 

costs for the recycle pump are modeled after the electricity requirements of the treated 

wastewater discharge pump for one-stage chemical precipitation (see Section 6.1.7.5 and 

Equation 6-132). Electricity requirements are calculated using Equation 6-162. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-87 

Recycle Pumps Elec (kWh/day) = (0.01820151 × Capacity Factor × FGD Wastewater Treatment 

 Flow GPM + 0.6031) × hp KW factor × Operating Hours (6-162) 

where: 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater treatment flow rate in gpm 

normalized for 24 hpd operation (see Section 6.1.5), 

hp KW factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp (see Section 6.1.7.5), and 

Operating Hours = System operating hours per day, 24. 

Electricity costs are calculated by multiplying the total electricity requirement in kWh by 

the average national energy cost of 4.05 cents per kWh (2009$) as determined based on data 

reported by the U.S. Energy Information Administration of the Electric Power Annual 2009 for 

fossil plants in the United States[U.S. DOE, 2011]. Equation 6-162 calculates the cost in 2009 

dollars is indexed to 2010 dollars using values from RSMeans [RS Means, 2011]. 

6.1.9.5 Recurring Cost Methodology 

Recurring costs refer to a cost incurred by the plant at some interval other than annually. 

While the mercury analyzer will be purchased as a capital cost element, before start-up of the 

wastewater treatment system, the analyzer will need to be replaced at six year intervals. EPA 

estimates the cost of one mercury analyzer to be $85,307 in 2010 dollars. See the Supplemental 

Costs and Loadings Documentation (DCN SE01825.A67) for additional information. 

6.1.10 Compliance Monitoring Cost

Section 5.2 discusses costs for compliance monitoring of chemical precipitation system 

effluent. 

6.1.11 Impoundment Operation Cost

Section 5.5 discusses cost savings associated with closing combustion residual surface 

impoundments. 

6.1.12 FGD System Outage Costs

EPA considered the impact of a plant outage required to install the chemical precipitation 

treatment system. Based on an evaluation of vendor and survey information, EPA determined 

that connecting the wastewater treatment system to the existing FGD system can be completed 

during regularly scheduled outages. The entire treatment system can be installed prior to a 

scheduled outage, and then the necessary tie-in can occur during a regularly scheduled outage. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-88 

Therefore, there are no costs for plant outages during installation of the chemical precipitation 

treatment system. 

6.1.13 Results and Summary of Costs

As described in Section 2.1.4, EPA’s cost model generated plant-level compliance costs 

for the one-stage 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, installation costs, operating labor, maintenance labor, and energy costs. The output also 

includes costs for the common cost elements described in Chapter 5. A list of the plant-level 

costs for the chemical precipitation technology option is included in the appendix. 

6.2 BIOLOGICAL TREATMENT

EPA estimated capital and O&M costs associated with installing a fixed-film 

anoxic/anaerobic biological treatment system to treat FGD wastewater. This system is designed 

to follow a chemical precipitation system (Section 6.1) that includes a biological treatment 

system feed tank (Section 6.1.6.2). The primary purpose of the biological treatment system is to 

remove selenium from the FGD wastewater; however, this technology is also effective in 

removing nitrates, sulfates, and other metals like mercury. All costs were estimated in 2010 

dollars. 

Throughout this section “FGD wastewater treatment flow” refers to the normalized FGD 

wastewater flow rate following wastewater equalization in the chemical precipitation system in 

gallons per minute. This flow rate is the FGD wastewater flow (gpd) converted to gallons per 

minute assuming 24 hour operation of the wastewater treatment system (see Section 6.1.5). 

6.2.1 Technology Description

EPA selected an anoxic/anaerobic biological system as the biological treatment design 

basis because of the system’s proven selenium removals of greater than 99 percent in FGD 

wastewater. Figure 6-3 (located at the end of this chapter) shows a typical two-stage biological 

treatment system for treating FGD wastewater. The system uses up-flow, fixed-film granular 

activated carbon (GAC) bed bioreactors, inoculated with a proprietary, site-specific mixture of 

bacterial cultures, through which the FGD wastewater passes. The bacterial cultures, maintained 

in an anoxic/anaerobic reductive environment, reduce dissolved selenium species (i.e., selenate 

and selenite) to particulate elemental selenium [Sonstegard, et al., 2008]. 34 This reaction is 

illustrated by the following equation: 

 SeO4

2- + Organic Carbon → SeO32- + Organic Carbon → Se0

 + CO2 +H2O 

Denitrifying organisms within the bioreactors reduce nitrate to nitrogen gas, which is 

released to the atmosphere as described by the equation below. A nutrient blend is added to the 

FGD wastewater to provide a carbon source for the denitrifying organisms. 

 

34 Oxidation reduction potential (ORP) drops across the system, ranging from +220 to +300 mV in the influent to -

200 to -300 mV in the effluent [Sonstegard, et al., 2008]. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-89 

 NO3

-

 + Organic Carbon → NO2

-

 + Organic Carbon → N2 + CO2 + H2O 

Reactor conditions also promote sulfide production, which results in sulfide precipitation 

of trace metals such as mercury, zinc, copper, nickel, lead, and others as shown by the following 

equation: 

H2S + M2 → MS + 2H+ 

where: 

M = Metal [Sonstegard, et al., 2008]. 

Elemental selenium and other precipitated metals accumulate within the biomatrix until 

the system is backwashed. During backwash, higher backwash flow fluidizes the bioreactor bed, 

releasing trapped solids, precipitated metals, and excess biomass into the backwash wastewater 

[Sonstegard, et al., 2008]. The backwash wastewater is then returned to the FGD wastewater 

chemical precipitation system, where the solids and precipitated metals are separated and 

removed with the chemical precipitation sludge. 

To estimate costs for this treatment technology, EPA first evaluated data from site visits, 

sampling episodes, and long-term monitoring data provided by industry to determine the average 

effluent quality of FGD wastewater after treatment with the BAT chemical precipitation system, 

as described in Section 6.1. These data are presented in Table 6-1 (located at the end of the 

chapter). EPA provided these data to a biological treatment system vendor, who then developed 

the specific anoxic/anaerobic biological treatment system design and system-level costs 

presented in this report based on their evaluation of these wastewater characteristics. The 

biological treatment system design developed by the vendor consists of a series of two 

bioreactors operating in parallel trains. The number of trains and the size of the bioreactors are 

dependent on plant-specific FGD wastewater flow rate. For flow rates greater than 40 gpm, the 

vendor provided costs for customized field-erected biological treatment systems. For flow rates 

less than 40 gpm, the vendor provided costs for a low-flow, pre-fabricated modular reactor. 

EPA costed the biological treatment system to be backwashed once a month with a 

vendor-recommended operating protocol of rotating backwash cycles weekly for the individual 

bioreactors. Staggering the backwash cycles eases handling and minimizes instantaneous 

wastewater flows through the system. Although backwashing occurs weekly, backwash 

wastewater is held in a tank to allow it to be slowly and continuously returned to the FGD 

wastewater chemical precipitation system. Equation 6-163 describes the estimated backwash 

flow generated, assuming the FGD wastewater characteristics in Table 6-1. 

 Backwash Flow (gpm) = [Redacted] × FGD Wastewater Treatment Flow GPM (6-163) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow in gpm normalized for 24 hpd 

operation (see Section 6.1.5). 
Chapter 6 - FGD Wastewater Cost Methodology 

6-90 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A57) for 

additional information on the derivation of Equation 6-159. 

The biological treatment system used to estimate costs operates at an optimal temperature 

of 95°F and a maximum temperature of 105°F. Based on site visits, sampling, and long-term 

monitoring data, FGD wastewater temperatures can be greater than 105°F, especially during the 

warmer seasons, in certain geographic locations, and may require cooling prior to entering the 

biological treatment system. Therefore, EPA included costs for a heat exchanger for certain 

southern plants determined to require cooling of FGD wastewater (see Section 6.2.5.2) [ERG, 

2013; See Appendix 57]. 

Major components of the design basis for the biological treatment system include: 

 Two bioreator tanks (i.e., two reactors in series per train); 

 Nutrient feed system and storage; 

 Backwash system and backwash wastewater tank; and 

 Heat exchangers (for certain southern plants). 

6.2.2 Population Costed

Based on information from the Steam Electric Survey, EPA identified 117 plants 

discharging FGD wastewater.35 EPA estimated costs for these 117 plants to install a one-stage 

chemical precipitation system with biological treatment to treat FGD wastewater. The population 

costed is the same as that described for FGD wastewater chemical precipitation. EPA identified 

plants that have announced plans to retire generating units prior to December 31, 2014 as 

described in Section 4.4.1. There are no conversion costs for plant that are already planned to 

retire prior to implementation of the ELGs. 

6.2.3 Credit for Biological Treatment in Place

EPA evaluated plant responses to the Steam Electric Survey to determine whether 

biological treatment for selenium removal is currently in place to treat FGD wastewater. As 

appropriate, these plants were given credit for having “treatment in place” to ensure that 

incremental costs associated with compliance with the technology options are accurately 

assessed. 

EPA assessed treatment in place credit for both portions of the treatment system, the 

chemical precipitation pretreatment portion and the biological treatment portion of the treatment 

system. Section 6.1.3 describes the treatment in place credit given to plants currently operating 

chemical precipitation treatment systems. Based on a review of responses to the Steam Electric 

Survey, EPA identified a total of five plants operating the biological treatment technology 

included in the basis for the biological treatment technology option for treating FGD 

 

35 When the group of plants excluding oil-fired units and units with a capacity of 50 MW or less is evaluated, the 

population of plants discharging FGD wastewater includes 116 plants. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-91 

wastewater.36 All five plants received full treatment-in-place credit for the biological treatment 

system. Only two of these plants operate BAT systems that include a chemical precipitation 

system followed by the anoxic/anaerobic biological treatment system targeting selenium 

removal. These two BAT plants also received full treatment-in-place credit for a one-stage 

chemical precipitation system. These BAT plants with complete one-stage chemical precipitation 

systems with biological treatment incur only compliance monitoring costs and the costs for a 

mercury analyzer (see Section 6.1.9) for the technology option including both chemical 

precipitation and biological treatment. The remaining three plants incur some level of 

incremental costs to either modify an existing chemical precipitation system to meet BAT or 

install a complete chemical precipitation system. 

6.2.4 Input Table

The biological treatment cost module uses data from the “FGD Input Table,” discussed in 

Section 6.1.4. One additional data field is included in the “FGD Input Table” for use in the 

biological treatment cost calculations, which is a ‘Heat_Exchanger_Cost’ flag. This flag 

identifies all plants that will be costed for a heat exchanger, as described in Section 6.2.5.2. 

A copy of the “FGD Input Table” used in the biological treatment module is included in 

the appendix. 

6.2.5 Capital Cost Methodology

Total capital costs were calculated for each plant as the sum of purchased equipment 

costs, installation costs, and plant engineering costs. 

Total Capital Costs = Purchased Equipment Cost + Purchased Equipment Installation 

Cost + Plant Overhead Engineering Cost 

EPA assumed zero land costs based on responses to the Steam Electric Survey indicating 

that plants incurred zero or very little expense (approximately 1 percent of purchased equipment 

costs) associated with acquiring land for FGD wastewater treatment systems. The costs provided 

by the biological treatment system vendor already include costs associated with other capital 

investments such as buildings, engineering and construction. As a result, EPA did not include 

additional incremental costs associated with these cost categories. 

ERG calculated purchased equipment capital costs for each plant as the sum of purchased 

equipment costs for the bioreactors and associated equipment, the heat exchanger (for applicable 

plants), and the backwash recycle pump. As all equipment costs were provided by vendors in 

2011 dollars, EPA adjusted the cost basis to 2010 dollars using the 2010 and 2011 RSMeans 

Historical Cost Indices (183.5 and 185, respectively) [RSMeans, 2011]. 

 

36 Through additional information collection during the rulemaking, EPA identified a sixth plant that operates a 

suspended-growth biological treatment system that targets the removal of selenium. This plant is incurring 

biological treatment costs for the biological treatment technology option because EPA has no performance data to 

show that the system can meet the proposed selenium limits. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-92 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A57) for 

additional information on the derivation of the equations used to estimate the plant-level capital 

cost. 

6.2.5.1 Purchased Equipment Costs: Biological Treatment System Cost 

The vendor provided cost curves and corresponding cost equations to estimate the plantlevel costs for the biological treatment system. These cost equations include the following cost 

components: 

 Two-stage bioreactor system (i.e., two reactors in series per train) with a 10-hour 

residence time for the system, operating 24 hours per day and 365 days per year. 

System-level costs include the following purchased equipment and associated 

ancillary equipment: 

- All process pumps, valves, and instruments, 

- Process and instrument compressed air system, valves, and lines, 

- Nutrient system, storage tank, and pumping, 

- Process piping and supports, 

- Concrete bioreactor tank walls and floor with epoxy-coated rebar and epoxy 

flake-glass coating, 

- Concrete backwash supply and backwash wastewater tank walls and floor with 

epoxy-coated rebar and epoxy flake-glass coating, 

- Concrete process and utility sump with pumps, 

- Support steel, access stairs, walkways, grating, handrails, 

 Process equipment building with HVAC (concrete floor, block structure with steel 

roof); 

 Engineering, commissioning, and project management labor (the project structure is 

executed by a consortium between the vendor and contractor with a balance of plant 

engineering as a sub-contractor); and 

 Construction equipment, materials, and labor. 

The biological treatment system cost equations apply to two different FGD wastewater 

treatment flow ranges: greater than or equal to 40 gpm (customized field-erected system) and 

less than 40 gpm (pre-fabricated modular reactor). 

For FGD Wastewater Treatment Flow GPM < 40 gpm EPA used Equation 6-164. 

 Biological Treatment Equipment Cost (2011$) = [Redacted] (6-164)

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater treatment flow in gpm normalized for 

24 hpd operation (see Section 6.1.5), and 
Chapter 6 - FGD Wastewater Cost Methodology 

6-93 

Backwash Flow = The backwash flow rate in gallons per minute (see 

Section 6.2.1and Equation 6-163). 

For FGD Wastewater Treatment Flow GPM ≥ 40 gpm EPA used Equation 6-165. 

 Biological Treatment Equipment Cost (2011$) = [Redacted] (6-165)

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Backwash Flow = The backwash flow rate in gallons per minute (see 

Section 6.2.1 and Equation 6-163). 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A57) for 

additional information on the derivation of Equations 6-164 and 6-165. 

6.2.5.2 Purchased Equipment Costs: Heat Exchanger Cost 

EPA estimated heat exchanger and related costs for facilities within set latitudinal and 

longitudinal coordinates. The coordinates were determined based on average ambient 

temperature data. EPA examined climate maps from the National Oceanic and Atmospheric 

Administration’s (NOAA’s) National Climate Data Center for average monthly maximum 

temperatures for the nation. Figure 6-4 (located at the end of this chapter) illustrates the national 

mean maximum daily temperatures for the month of July.37 Specifically, the red and dark red 

regions indicate average July temperatures of 90°F or greater. Based on these findings, EPA 

determined the following latitudinal and longitudinal coordinates encompassing a significant 

portion of the red shaded regions (also illustrated in shaded blue in Figure 6-5 located at the end 

of this chapter): 

 South of 35°0 ́0 ́ ́N; or 

 Between 35°0 ́0 ́ ́N and 40°37 ́30 ́ ́N and west of 108°0 ́0 ́ ́W; or 

 Between 35°0 ́0 ́ ́N and 40°37 ́30 ́ ́N and between 90°0 ́0 ́ ́W and 105°0 ́0 ́ ́W. 

EPA costed plants located within these coordinates (39 plants) for heat exchangers in 

conjunction with the biological treatment system. Those plants flagged as requiring a heat 

exchanger are identified in the “Heat Exchanger Input Table.” A copy of “Heat Exchanger Input 

Table” used in the biological treatment module is included in the appendix. 

Due to potentially high chlorides concentrations in FGD wastewater, several vendors, 

including WCR, Inc., Tranter, and Funke, recommended titanium plate and frame heat 

 

37 EPA examined similar maps for June, August, and September; however, July’s maximum temperatures were 

farthest reaching geographically and assumed to best capture geographical regions expected to experience ambient 

temperatures that may cause FGD scrubber purge wastewater temperatures to require cooling prior to biological 

treatment. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-94 

exchangers. EPA based heat exchanger cost equations on cost estimates provided by these heat 

exchanger vendors for a carbon steel frame heat exchanger consisting of 0.5 millimeter titanium 

plates. EPA included costs for one titanium plate and frame heat exchanger and two cooling 

water pumps. Cooling water cost equations are based on quotes by Sulzer for a single-stage 

process pump. 

EPA estimated cooling water requirements using heat transfer Equations 6-166 and 

6-167. 

 Q = mCpΔT (6-166) 

 Qh = Qc (6-167) 

where: 

Q = Amount of heat to dissipate from FGD wastewater by 

the cooling water, 

m = Mass flow rate of the FGD wastewater or cooling 

water, 

Cp = Specific heat capacity of the FGD wastewater or 

cooling water, 

ΔT = Temperature difference between the inlet and outlet, 

Qh = Amount of heat dissipated from the FGD wastewater 

(hot material), and 

Qc = Amount of heat absorbed by the cooling water (cold 

material). 

EPA calculated the cooling water flow rate required to cool the FGD wastewater based 

on the following assumptions: 

 FGD Wastewater 

- Temperature drop from Th1=120°F to Th2 = 95°F, 

- Specific heat capacity, Cph, of 0.85 Btu/lb-F, and 

- Density, ρh, 9.163 lb/gallon. 

 Cooling Water 

- Temperature increase from Tc1=70 °F to Tc2=85°F, 

- Specific heat capacity, Cpc, of 1 Btu/lb-F, and 

- Density, ρc, of 8.33 lb/gallon. 

Using these assumptions, EPA derived Equation 6-168 to estimate the cooling water flow 

rate as a function of FGD wastewater flow. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-95 

Cooling Water Flow Rate (gpm) = FGD Wastewater Treatment Flow GPM × ((Cph × (Th1 – Th2) 

 × ρh) / (Cpc × (Tc2 – Tc1) × ρc)) (6-168) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

Cph = Specific heat capacity of the FGD wastewater, 

Cpc = Specific heat capacity of the cooling water, 

Th1 = Initial temperature of the FGD wastewater, 

Th2 = Final temperature of the FGD wastewater, 

Tc1 = Initial temperature of the cooling water, 

Tc2 = Final temperature of the cooling water, 

ρh = The density of the FGD wastewater, and 

ρc = The density of the cooling water. 

EPA estimated the capital cost for the heat exchanger and cooling water pumps, 

applicable to each of the 39 plants identified as requiring FGD wastewater cooling. EPA also 

estimated freight costs for the cooling water pumps based on weight and a shipping distance of 

approximately 500 miles using quotes from FreightCenter.com [ERG, 2013; See Appendix 58]. 

Freight costs were equal to approximately 3 to 4 percent of purchase costs (i.e., Freight Factor = 

1.04). EPA also estimated the freight costs for the heat exchanger based on weights provided by 

the vendor. Heat exchanger freight costs were equal to approximately 5 percent of the purchased 

cost (HE_Freight_Factor =1.05). 

EPA calculated heat exchanger capital cost using Equation 6-169. 

HE Equipment Cost (2011$) = (0.0059 × (FGD Wastewater Treatment Flow GPM + Backwash 

Flow)2

 + 11.304 × (FGD Wastewater Treatment Flow GPM + Backwash Flow) + 2643.6) × 

 HE_Freight_Factor (6-169) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

Backwash Flow = The backwash flow rate in gallons per minute (see 

Section 6.2.1 and Equation 6-163), and 

HE_Freight_Factor = Factor that accounts for freight cost for the heat 

exchanger as a percentage of purchase cost, 1.05. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-96 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A58) for 

additional information on the derivation of Equation 6-169. 

EPA calculated cooling water pumps capital cost using Equation 6-170. 

Cooling Water Pump Cost (2011$) = (-0.0017 × (Cooling Water Flow)2 + 9.9408 × (Cooling 

 Water Flow) + 3392.8) × Pump Freight Factor × CW_Pump Qty) (6-170) 

where: 

Cooling Water Flow = The cooling water flow rate required in gallons per 

minute, (see Equation 6-168), 

Pump Freight Factor = Factor that accounts for freight cost as a percentage of 

purchase cost (see Section 6.1.5), 1.04, and 

CW_Pump Qty = Number of cooling water pumps, 2. 

6.2.5.3 Purchased Equipment Costs: Backwash Recycle Pumps Cost 

EPA estimated costs for two 100 percent capacity skid-mounted, horizontal centrifugal 

backwash recycle pumps to transfer the backwash wastewater from the backwash wastewater 

tank to the equalization tank in the chemical precipitation system. Cost estimates were provided 

by Weir Minerals and include the cost for pumps, accessories, motors and V drives. EPA 

estimated pump freight costs using the same freight factor as for the cooling water pumps. 

Backwash Recycle Pump Cost (2011$) = (0.0049 × (Backwash Flow)2

 + 8.2408 × (Backwash 

 Flow) + 7758.6) × Pump Freight Factor × BW_Pump Qty (6-171)

where: 

Backwash Flow = The backwash flow rate in gallons per minute (see 

Section 6.2.1 and Equation 6-163), 

Pump Freight Factor = Factor that accounts for freight cost as a percentage of 

purchase cost (see Section 6.1.5), 1.04, and 

BW_Pump Qty = Number of backwash recycle pumps, 2. 

6.2.5.4 Purchased Equipment Installation Cost 

EPA estimated installation capital costs for the biological treatment system for each plant 

using two different installation cost factors. The first factor (Bioreactor Installation Factor) was 

provided by the vendor and is specific to installation of the biological treatment system. The 

second factor (Plant Installation Factor) was determined based on responses to the Steam Electric 

Survey and applies to installation of the heat exchanger, cooling water pumps, and backwash 

recycle pumps. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-97 

Using these installation factors, EPA estimated biological treatment system installation 

capital costs for each plant using Equation 6-172. As vendors provided all equipment costs in 

2011 dollars, EPA adjusted the cost basis to 2010 dollars using the 2010 and 2011 RSMeans 

Historical Cost Indices (183.5 and 185, respectively) [RSMeans, 2011]. 

Installation Capital Cost (2010$) = [(Bioreactor Installation Factor × Biological Treatment 

Equipment Cost) + (Plant Installation Factor × {HE Equipment Cost + Cooling Water Pump 

 Cost + Backwash Recycle Pump Cost})] × (2010 Cost Index/2011 Cost Index) (6-172)

where: 

Bioreactor Installation 

Factor 

= Factor that accounts for cost to install the biological 

treatment system as a percentage of the biological 

treatment equipment cost, 

Biological Treatment 

Equipment Cost 

= Cost to purchase the equipment associated with the 

biological treatment system in 2011 dollars, 

Plant Installation Factor = Factor that accounts for cost to install heat exchanger, 

cooling water pump, and backwash recycle pump as a 

percentage of the purchased equipment cost, 

HE Equipment Cost = Capital cost associated with purchasing the heat 

exchanger in 2011 dollars, 

Cooling Water Pump 

Cost 

= Capital cost associated with purchasing the cooling 

water pump in 2011 dollars, 

Backwash Recycle 

Pump Cost 

= Capital cost associated with purchasing the backwash 

recycle pump in 2011 dollars, 

2010 Cost Index = 183.5, and 

2011 Cost Index = 185.

Bioreactor Installation Factor

Based on information provided by the biological treatment system vendor the bioreactor 

system installation cost factors vary by FGD wastewater flow range as listed below: 

For FGD wastewater treatment flow < 40 gpm EPA used Equation 6-173. 

 Bioreactor Installation Factor = [Redacted] (6-173) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Backwash Flow = The backwash flow rate in gallons per minute (see 

Section 6.2.1 and Equation 6-163). 
Chapter 6 - FGD Wastewater Cost Methodology 

6-98 

For FGD wastewater treatment flows from greater than or equal to 40 gpm to less than or 

equal to 1,000 gpm EPA used Equation 6-174. 

 Bioreactor Installation Factor = [Redacted] (6-174) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Backwash Flow = The backwash flow rate in gallons per minute (see 

Section 6.2.1 and Equation 6-159). 

For FGD wastewater treatment flows > 1,000 gpm EPA used Equation 6-175. 

 Bioreactor Installation Factor = [Redacted] (6-175)

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A57) for 

additional information on the derivation of Equations 6-173 through 6-175. 

Plant Installation Factor

EPA used the installation factor of [Redacted] developed for chemical precipitation 

treatment of FGD wastewater (see Section 6.1.6.8). 

6.2.5.5 Plant Overhead Engineering Cost 

The equipment capital cost equation does not include plant overhead engineering costs. 

Based on responses to the Steam Electric Survey for plants operating chemical precipitation or 

biological treatment of FGD wastewater, plant engineering overhead costs ranged from 1 to 10 

percent of the equipment costs (median = [Redacted]) [EPA, 2013; See Appendix 59]. EPA 

estimated plant overhead engineering cost as a fraction of the total purchased equipment cost 

using Equation 6-176. 

 Plant Overhead Engineering Cost (2010$) = [Redacted] × Biological Treatment Equipment 

 Capital Cost (6-176)

Equipment Capital Cost (2010$) = [Biological Treatment Equipment Cost + HE Equipment Cost 

+ Cooling Water Pump Cost + Backwash Recycle Pump Cost] × 

 (2010 Cost Index/2011 Cost Index) (6-177)

where: 

Biological Treatment 

Equipment Cost 

= Cost to purchase the equipment associated with the 

biological treatment system in 2011 dollars, 

HE Equipment Cost = Capital cost associated with purchasing the heat 
Chapter 6 - FGD Wastewater Cost Methodology 

6-99 

exchanger in 2011 dollars, 

Cooling Water Pump 

Cost 

= Capital cost associated with purchasing the cooling 

water pump in 2011 dollars, 

Backwash Recycle 

Pump Cost 

= Capital cost associated with purchasing the backwash 

recycle pump in 2011 dollars, 

2010 Cost Index = 183.5, and 

2011 Cost Index = 185.

6.2.6 O&M Cost Methodology

O&M costs associated with biological treatment for each plant include the following: 

 Operating labor cost, 

 Maintenance labor cost, 

 Maintenance materials cost, 

 Chemical purchase cost, 

 Energy cost, 

 Sludge disposal cost, and 

 Compliance monitoring cost. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A57 and 

SE01825.A60) for additional information on the derivation of the equations used to estimate the 

plant-level O&M cost for the biological treatment system. 

6.2.6.1 Operating Labor Cost 

The biological treatment system vendor provided a breakdown of tasks and labor required 

to operate and maintain the biological treatment system. For these data, EPA determined that 

0.4375 full-time equivalent (FTE) workers are required for system operation on all shifts [ERG, 

2013; See Appendix 57]. EPA determined an operating labor rate of [Redacted] (2010$) based 

on the median operating labor rate reported in response to Question D6-2 of the Steam Electric 

Survey by plants that operate FGD wastewater chemical precipitation treatment (with and 

without subsequent biological treatment). 38 Finally, EPA calculated operating labor costs for 

each plant by converting the number of FTE workers to annual number of hours worked, and 

then multiplying by the operating labor rate. 

Operating Labor Cost (2010$/yr) = Operating Labor Rate × Number of Workers × 24 hr/day × 

 365 day/yr (6-178) 

 

38 The median FGD wastewater treatment operator labor rate based on survey data is in 2009$. EPA will index the 

value appropriately with cost index data from RS Means for the final rule. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-100 

where: 

Operating Labor Rate = The median FGD wastewater treatment operator labor 

rate as reported in the Steam Electric Survey, 

[Redacted] (2010$),38 and 

Number of Workers = Number of FTEs associated with operating activities, 

0.4375 . 

6.2.6.2 Maintenance Labor Cost 

The biological treatment system vendor provided a breakdown of tasks and labor required 

to operate and maintain the biological treatment system. For these data, EPA determined that 

0.0625 FTE workers are required for system maintenance on all shifts [ERG, 2013; See 

Appendix 57]. EPA determined a maintenance labor rate of [Redacted] (2010$) based on the 

median maintenance labor rate reported in response to Question D6-2 of the Steam Electric 

Survey by plants that operate FGD wastewater chemical precipitation treatment (with and 

without subsequent biological treatment). Finally, EPA calculated maintenance labor costs for 

each plant by converting the number of FTE workers to annual number of hours worked, and 

then multiplying by the maintenance labor rate. 

Maintenance Labor Cost (2010$/yr) = Maintenance Labor Rate × Number of Workers × 24 

 hr/day × 365 day/yr (6-179) 

where: 

Maintenance Labor 

Rate 

= The median FGD wastewater treatment maintenance 

labor rate as reported in the Steam Electric Survey, 

[Redacted] (2010$), and 

Number of Workers = Number of FTEs associated with maintenance 

activities, 0.0625 FTE. 

6.2.6.3 Maintenance Materials Cost 

EPA developed Equation 6-180 to estimate the maintenance materials cost based on an 

evaluation of O&M costs reported in response to Question D6-2 of the Steam Electric Survey by 

plants that operate FGD wastewater chemical precipitation treatment (with and without 

subsequent biological treatment) [ERG, 2013; See Appendix 60]. 

Maintenance Material Cost (2010$/yr) = [Redacted] × (Energy Cost + Chemical Purchase Cost + 

 Operating Labor Cost + Maintenance Labor Cost) (6-180) 

6.2.6.4 Chemical Purchase Cost 

The biological treatment system vendor calculated the required nutrient dosage of 

[Redacted]. The vendor also provided an average nutrient cost of [Redacted]. EPA estimated 

nutrient purchase cost by multiplying the nutrient dosage rate by the FGD wastewater treatment 
Chapter 6 - FGD Wastewater Cost Methodology 

6-101 

flow rate and the nutrient cost [ERG, 2013; See Appendix 57]. As the vendor provided the 

nutrient cost in 2011 dollars, EPA adjusted the cost basis to 2010 dollars using the 2010 and 

2011 RSMeans Historical Cost Indices (183.5 and 185, respectively) [RSMeans, 2011]. 

Chemical Purchase Cost (2010$/yr) = Nutrient Cost × Nutrient Dosage × FGD Wastewater 

Treatment Flow GPM × 60 min/hr × 24 hr/day × 365 day/yr × (2010 Cost Index/2011 Cost 

 Index) (6-181) 

where: 

Nutrient Cost = Average nutrient cost, [Redacted], 

Nutrient Dosage = Amount of nutrients required per 1,000 gallons of FGD 

wastewater [Redacted], 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

2010 Cost Index = 183.5, and 

2011 Cost Index = 185. 

6.2.6.5 Energy Cost 

EPA determined overall biological treatment energy consumption (in kWh/yr) by 

calculating and summing the annual power consumption for each piece of equipment. EPA 

assumed continuous operation of all equipment. To calculate energy costs, EPA then multiplied 

the total annual energy requirement by the national energy cost of 4.05 cents per kWh (2009$) as 

determined based on data reported by the U.S. Energy information Administration in Table 8.2 

of the Electric Power Annual 2009 for fossil plants in the United States [U.S. DOE, 2011]. As 

the energy cost was provided in 2009 dollars, EPA adjusted the cost basis to 2010 dollars using 

the 2009 and 2010 RSMeans Historical Cost Indices (180.1 and 183.5, respectively) [RSMeans, 

2011]. 

Energy Cost (2010$/yr) = National Energy Cost × [Biological Treatment System Energy 

Consumption + BW Pump Energy Consumption + CW Pump Energy Consumption] × 

 (2010 Cost Index/2009 Cost Index) (6-182)

where: 

National Energy Cost = $0.0405/kWh (2009$), 

Biological Treatment 

System Energy 

Consumption 

= Energy consumption for the biological treatment 

system, kWh/yr, 

BW Pump Energy 

Consumption 

= Energy consumption for backwash recycle pumps, 

kWh/yr, 
Chapter 6 - FGD Wastewater Cost Methodology 

6-102 

CW Pump Energy 

Consumption 

= Energy consumption for cooling water pumps, kWh/yr, 

2009 Cost Index = 180.1, and 

2010 Cost Index = 183.5. 

For the purpose of estimating non-water quality environmental impacts, EPA also 

converted energy consumption in kWh/yr to energy load in MW using Equation 6-183. 

Energy Load (MW) = [Biological Treatment System Energy Consumption + BW Pump 

Energy Consumption + CW Pump Energy Consumption] / (24 hpd × 365 dpy) × 

 1 MW / 1000 kW (6-183)

where: 

Biological Treatment 

System Energy 

Consumption 

= Energy consumption for biological treatment system, 

kWh/yr, 

BW Pump Energy 

Consumption 

= Energy consumption for backwash recycle pumps, 

kWh/yr, 

CW Pump Energy 

Consumption 

= Energy consumption for cooling water pumps, kWh/yr, 

Biological Treatment System Energy

The biological treatment system vendor provided the system energy requirement of 

0.00036 kWh/gallon FGD wastewater treated [ERG, 2013; See Appendix 57]. EPA calculated 

the annual biological treatment system energy consumption using Equation 6-184. 

Biological Treatment System Energy Consumption (kWh/yr) = Biological System Requirement 

× (FGD Wastewater Treatment Flow GPM + Backwash Flow) × 60 min/hr × 24 hr/day × 

 365 day/yr (6-184)

where: 

Biological System 

Requirement 

= Biological treatment system energy requirement, 

0.00036 kWh/gallon FGD wastewater, 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), and 

Backwash Flow = The backwash flow rate in gallons per minute (see 

Section 6.2.1 and Equation 6-163). 
Chapter 6 - FGD Wastewater Cost Methodology 

6-103 

Pump Energy

Pump electricity consumption is based on the horsepower of each pump motor. EPA 

converted horsepower to kilowatts and calculated kilowatt-hours assuming 24 hour operation. As 

pump sets of two were costed for redundancy, pumps placed in standby were not considered in 

calculating electricity requirements. 

Based on data from the equipment vendor, backwashing occurs on a weekly basis as 

described in Section 6.2.1. To be conservative, EPA assumed that the backwash recycle pumps 

would operate continuously in some capacity, either to move backwash from the bioreactors to 

the backwash tank or to transfer the backwash from the tank to the chemical precipitation 

treatment system. 

BW Pump Energy Consumption (kWh/yr) = (0.0182 × Backwash Flow + 0.6031) × 

 hpKWfactor× BW OpPump Qty × 60 min/hr × 24 hr/day × 365 day/yr (6-185)

where: 

Backwash Flow = The backwash flow rate in gallons per minute (see 

Section 6.2.1 and Equation 6-163), 

hpKWfactor = 0.7456 KW/hp (to convert horsepower to kilowatts), 

and 

BW OpPump Qty = Number of backwash recycle pumps normally 

operating, 1. 

Based on operations at facilities with existing heat exchangers prior to biological 

treatment, heat exchangers are likely to be operated for only a portion of the year. Accordingly, 

EPA assumed that heat exchangers and their associated cooling water pumps would be operated 

six months of the year (an overestimate of the amount of time the heat exchanger would be 

needed based on available data). 

CW Pump Energy Consumption (kWh/yr) = (0.0165 × (Cooling Water Flow) + 1.9854) × 

 hpKWfactor × CW OpPump Qty × 60 min/hr × 24 hr/day × Operating Days (6-186) 

where: 

Cooling Water Flow = Cooling water flow rate in gallons per minute (see 

Section 6.2.5.2 and Equation 6-168), 

hpKWfactor = 0.7456 KW/hp (to convert horsepower to kilowatts), 

CW OpPump Qty = Number of cooling water pumps normally operating, 1, 

and 

Operating Days = Number of days heat exchanger will be operating, 183 

days/yr. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-104 

Heat Exchanger Energy

As cooling water and FGD wastewater are circulated through the heat exchanger via 

pumps, the heat exchanger itself does not consume energy. 

6.2.7 Sludge Disposal Cost

Sludge generated by the biological treatment system is contained within the backwash 

wastewater, which is recycled to the FGD wastewater chemical precipitation system and is 

ultimately removed with the chemical precipitation sludge. According to the biological treatment 

system vendor, the backwash water contains approximately [Redacted]. EPA used the equation 

provided by the vendor to estimate the annual amount of dry solids generated, assuming the FGD 

wastewater characteristics in Table 6-1 (located at the end of the chapter). The estimated 

composition of the solids is [Redacted] [ERG, 2013; See Appendix 57]. 

Backwash Dry Solids (tons/yr) = [Redacted] × 60 min/hr 

 × 24 hr/day × 365 day/year (6-187) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5). 

Sections 5.3 and 5.4 discuss costs for the transportation and disposal of sludge from the 

chemical precipitation system. 

6.2.8 Mercury Analyzer Cost

Section 6.1.9 discusses costs to install and operate a mercury analyzer and effluent 

recycle system. The mercury analyzer costs are incurred only once for an entire wastewater 

treatment system. Therefore, for plants expected to install a chemical precipitation and biological 

treatment system to meet the proposed ELGs, EPA included the cost for one mercury analyzer 

for the entire system. 

6.2.9 Compliance Monitoring Cost

Section 5.2 discusses costs for compliance monitoring of biological treatment effluent. 

6.2.10 Surface Impoundment Operation Cost

Section 5.5 discusses cost savings associated with closing combustion residual surface 

impoundments. 

6.2.11 FGD System Outage Costs

EPA considered the impact of a plant outage required to install the biological treatment 

system. Based on an evaluation of vendor and survey information, EPA determined that 

connecting the wastewater treatment system to the existing FGD system can be completed during 
Chapter 6 - FGD Wastewater Cost Methodology 

6-105 

regularly scheduled outages. The entire treatment system can be installed prior to a scheduled 

outage, and then the necessary tie-in can occur during a regularly scheduled outage. Therefore, 

there are no costs for plant outages during installation of the biological treatment system. 

6.2.12 Results and Summary of Costs

As described in Section 2.1.4, EPA’s cost model generated plant-level compliance costs 

for the one-stage chemical precipitation followed by biological treatment technology option. The 

cost output generated by the model includes a breakout of specific capital and O&M cost 

elements, including equipment costs, installation costs, operating labor, maintenance labor, and 

energy costs. The output also includes costs for the common cost elements described in Chapter 

5. A list of the plant-level costs for the chemical precipitation with biological treatment 

technology option is included in the appendix. 

6.3 VAPOR-COMPRESSION EVAPORATION

EPA estimated capital and O&M costs associated with installing a vapor-compression 

evaporation treatment system to treat FGD wastewater. This system is designed to follow a 

chemical precipitation system (Section 6.1) that includes a vapor-compression evaporation 

treatment system feed tank (Section 6.1.6.2). The purpose of the vapor-compression evaporation 

system is to concentrate the FGD wastewater contaminants (e.g., metals, dissolved nutrients) into 

a solid cake for disposal and generate a clean distillate stream, which can be reused in the plant 

process or discharged. All costs were estimated in 2010 dollars. 

Throughout this section “FGD wastewater treatment flow” refers to the normalized FGD 

wastewater flow rate following wastewater equalization in the chemical precipitation system in 

gallons per minute. This flow rate is the FGD wastewater (gpd) converted to gallons per minute 

assuming 24 hour operation of the wastewater treatment system (see Section 6.1.5). 

6.3.1 Technology Description

EPA used the design of the vapor-compression evaporation system based on information 

provided by vendors (GE and HPD), as well as information collected during EPA’s sampling 

visit at plants in Italy operating this technology. Figure 6-6 and Figure 6-7 (located at the end of 

this chapter) show a typical vapor-compression evaporation system for treatment of FGD 

wastewater. The system is designed to operate 24 hours per day and 365 days per year and 

includes the following major components: 

 Water softener to reduce calcium and magnesium; 

 Vapor-compression evaporation brine concentrator to reduce water volume by more 

than 80 percent of the influent flow; and 

 Forced-circulation crystallizer for further water recovery and brine concentration to 

produce a solid salt cake for disposal. 

Before entering the vapor-compression evaporation system, FGD wastewater is usually 

pretreated to remove calcium and magnesium salts, as shown in Figure 6-6. Excessive 

concentrations of calcium and magnesium salts in the FGD wastewater can pose difficulties for 
Chapter 6 - FGD Wastewater Cost Methodology 

6-106 

the forced-circulation crystallizer. To prevent this, plants can pretreat the FGD wastewater using 

chemical precipitation and a lime-softening process upstream of the brine concentrator. With 

water softening, the magnesium and calcium ions precipitate out of the wastewater and are 

replaced with sodium ions, producing an aqueous solution of sodium chloride that can be more 

effectively treated with a forced-circulation crystallizer [Shaw, 2008]. 

Figure 6-7 presents a process flow diagram for a vapor-compression evaporation system. 

When a vapor-compression evaporation system is used to treat FGD wastewater, the first step is 

to adjust the pH of the FGD wastewater to approximately 6.5 S.U. Additionally, some plants add 

an antiscalant to the wastewater prior to the evaporation system [ERG, 2012]. Following pH 

adjustment, the FGD wastewater goes through a heat exchanger to bring the wastestream to its 

boiling point. From the heat exchanger, the wastewater stream is sent to the deaerator, where the 

noncondensable materials such as carbon dioxide and oxygen, are vented to the atmosphere 

[ERG, 2012]. 

From the deaerator, the wastestream enters the sump of the brine concentrator. Brine 

from the sump is pumped to the top of the brine concentrator and enters the heat transfer tubes. 

While falling down the heat transfer tubes, part of the solution is vaporized and then compressed 

and comes in contact with the shell side of the brine concentrator (i.e., the outside of the tubes). 

With the temperature difference between the compressed vapor and the brine solution, the 

compressed vapor transfers heat to the brine solution, which flashes to a vapor, and the 

compressed vapor cools and condenses as distilled water [ERG, 2012]. 

The condensed vapor (i.e., distillate water) can be recycled back to the FGD process, 

used in other plant operations (e.g., boiler make-up water), or discharged. If the plant uses the 

distillate for other plant operations that generate a discharge stream (e.g., used as boiler make-up 

and ultimately discharged as boiler blowdown), then the FGD process/wastewater treatment 

system is not truly zero discharge. Therefore, operating a vapor-compression evaporation system 

does not guarantee that the FGD process/wastewater treatment system achieves zero discharge. 

The concentrated brine slurry from the brine concentrator tubes falls into the sump and is 

recycled with the feed (FGD wastewater) to the top of the brine concentrator. Typically, the plant 

continuously withdraws a small amount from the sump and transfers it to a final drying process. 

To prevent scaling within the brine concentrator caused by the gypsum in the FGD wastewater, 

the brine concentrator is seeded with calcium sulfate. The calcium salts preferentially precipitate 

onto the seed crystals instead of the tube surfaces of the brine concentrator. If the treatment 

system is preceded by chemical precipitation and softening, the brine concentrator can typically 

concentrate the FGD scrubber purge five to 10 times, which reduces the inlet FGD scrubber 

purge water volume by 80 to 90 percent [Shaw, 2008]. 

6.3.2 Population Costed

Based on information from the Steam Electric Survey, EPA identified 117 plants 

discharging FGD wastewater.39 EPA estimated costs for these 117 plants to install a one-stage 

 

39 When the group of plants excluding oil-fired units and units with a capacity of 50 MW or less is evaluated the 

population of plants discharging FGD wastewater includes 116 plants. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-107 

chemical precipitation system with vapor-compression evaporation to treat FGD wastewater. The 

population costed is the same as that described for FGD wastewater chemical precipitation and 

biological treatment. EPA identified plants that have announced plans to retire generating units 

prior to December 31, 2014 as described in Section 4.4.1. There are no conversion costs for plant 

that are already planned to retire prior to implementation of the ELGs. 

6.3.3 Credit for Vapor-Compression Evaporation Treatment in Place

EPA evaluated plant responses to the Steam Electric Survey to determine whether vaporcompression evaporation is currently in place for treatment of FGD wastewater. As appropriate, 

these plants were given credit for having “treatment-in-place” to ensure that incremental costs 

associated with compliance with the technology options are accurately assessed. 

EPA assessed treatment in place credit for both portions of the treatment system, the 

chemical precipitation pretreatment portion and the vapor compression evaporation portion of 

the treatment system. Section 6.1.3 describes the treatment in place credit given to plants 

currently operating chemical precipitation treatment systems. Based on a review of responses to 

the Steam Electric Survey, EPA identified one plant using vapor-compression evaporation to 

treat FGD wastewater.40 While this plant receives full treatment-in-place credit for the vaporcompression evaporation system the plant does not currently operate a complete one-stage 

chemical precipitation (see Section 6.1) as a pre-treatment step. This plant does incur 

incremental costs to modify the FGD wastewater treatment system to meet BAT. 

6.3.4 Input Table

The vapor-compression evaporation cost module uses data from the “FGD Input Table” 

(see Section 6.1.4). A copy of this input table is included in the appendix. 

6.3.5 Capital Cost Methodology

EPA calculated total capital costs for each plant as the sum of the purchased equipment 

costs and installation costs: 

Total Capital Costs = Purchased Equipment Costs + Purchased Equipment Installation Cost 

EPA assumed zero land costs based on responses to the Steam Electric Survey indicating 

that plants incurred zero or very little expense (approximately one percent of purchased 

equipment costs) associated with acquiring land for FGD wastewater treatment systems. EPA 

assumes that other capital costs associated with buildings, site preparation, engineering and 

construction are included in the costs provided by the vendors. 

EPA calculated purchased equipment capital costs for each plant as the sum of purchased 

equipment costs for the softener, brine concentrator, and crystallizer. As vendors provided all 

 

40 Through additional information collected during the rulemaking, EPA identified two additional plants that plan to 

install a vapor-compression evaporation system to treat FGD wastewater by 2014 when the rule is promulgated. 

EPA identified these systems after completing the compliance cost calculations; therefore, compliance cost 

estimates currently show a cost for these two plants. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-108 

equipment costs in 2009 dollars, EPA adjusted the cost basis to 2010 dollars using the 2010 and 

2009 RSMeans Historical Cost Indices (183.5 and 180.1, respectively) [RSMeans, 2011]. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.61) for 

additional information on the derivation of the equations used to estimate the plant-level capital 

cost of the vapor-compression evaporation system. 

6.3.5.1 Purchased Equipment Costs: Brine Concentrator and Crystallizer Cost 

GE and HPD provided cost data for purchasing brine concentrator and crystallizer 

equipment for two different flow rates [ERG, 2013; See Appendix 61]. Based on these data, EPA 

developed Equation 6-188 to estimate the cost of brine concentrator and crystallizer equipment. 

 Brine Concentrator & Crystallizer Equipment Cost (2009$) = [Redacted] (6-188) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5). 

6.3.5.2 Purchased Equipment Costs: Softening Equipment Cost 

According to HPD, FGD wastewater softening accounts for [Redacted] of the total 

purchased equipment costs for the vapor-compression evaporation system [ERG, 2013; See 

Appendix 61]. EPA developed Equation 6-189 to estimate the softening equipment costs based 

on this information. 

Softening Equipment Cost (2009$) = Softening Cost Factor × Brine Concentrator & Crystallizer 

 Equipment Cost (6-189) 

where: 

Softening Cost Factor = Factor to calculate the purchased cost of softening 

equipment based on the purchased cost of brine 

concentrator and crystallizer equipment, [Redacted], 

and 

Brine Concentrator & 

Crystallizer Equipment 

Cost 

= The cost associated with purchasing the brine 

concentrator and crystallizer equipment associated with 

the vapor-compression evaporation system in 2009 

dollars (see Equation 6-188). 

6.3.5.3 Purchased Equipment Installation Cost 

EPA developed Equation 6-190 to estimate capital cost equipment installation costs 

based on information provided by HPD and GE [ERG, 2013; See Appendix 61]. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-109 

Installation Cost (2010$) = Installation Cost Factor × [Brine Concentrator & Crystallizer 

Equipment Cost + Softening Equipment Cost] × (2010 Cost Index/2009 Cost Index) (6-190) 

where: 

Installation Cost Factor = Factor to calculate the installation cost based on the 

total purchased equipment cost, [Redacted], 

Brine Concentrator & 

Crystallizer Equipment 

Cost 

= Cost to purchase the brine concentrator and crystallizer 

equipment in 2009 dollars (see Equation 6-188), 

Softening Equipment 

Cost 

= Cost to purchase the softening equipment in 2009 

dollars (see Equation 6-189), 

2010 Cost Index = 183.5, and 

2009 Cost Index = 180.1. 

6.3.6 O&M Cost Methodology

O&M costs for each plant consist of all costs related to operating and maintaining the 

vapor-compression evaporation system. EPA calculated total O&M costs as the sum of the 

following O&M cost components: 

 Operating labor cost, 

 Maintenance labor cost, 

 Maintenance materials cost, 

 Chemical purchase cost, 

 Energy cost, 

 Sludge disposal cost, and 

 Compliance monitoring cost. 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A61) for 

additional information on the derivation of the equations used to estimate the plant-level O&M 

cost of the vapor-compression evaporation system. 

6.3.6.1 Operating Labor Cost 

Operating labor cost includes labor costs for plant staff to operate the vapor-compression 

evaporation system. EPA assumed one operator, 24 hours per day is required to operate the 

system based on observations during a site visit to a U.S. plant operating a vapor-compression 

evaporation system to treat FGD wastewater. EPA determined an operating labor rate of 

[Redacted] (2010$) based on the median operating labor rate reported in response to Question 

D6-2 of the survey by plants that operate FGD wastewater chemical precipitation treatment (with 
Chapter 6 - FGD Wastewater Cost Methodology 

6-110 

and without subsequent vapor-compression evaporation system treatment). 41 Finally, EPA 

calculated operating labor costs for each plant by converting the number of workers to annual 

number of hours worked, and then multiplying by the operating labor rate. 

Operating Labor Cost (2010$/yr) = Operating Labor Rate × Number of Workers × 24 hr/day × 

 365 day/yr (6-191) 

where: 

Operating Labor Rate = The median FGD wastewater treatment operator labor 

rate as reported in the Steam Electric Survey, 

[Redacted] (2010$), and 

Number of Workers = Number of FTEs associated with operating activities, 1. 

6.3.6.2 Maintenance Labor Cost 

Maintenance labor cost includes labor costs for plant staff to maintain the vaporcompression evaporation system. Vapor-compression evaporation system vendor information 

was insufficient for use in estimating maintenance labor costs; therefore, EPA used maintenance 

labor costs from chemical precipitation treatment of FGD wastewater (see Section 6.1.7.2 and 

Equation 6-120). 

6.3.6.3 Maintenance Materials Cost 

Vapor-compression evaporation system vendor information was insufficient for use in 

estimating maintenance materials costs; therefore, EPA used maintenance materials costs from 

chemical precipitation treatment of FGD wastewater (see Section 6.1.7.3 and Equation 6-121). 

6.3.6.4 Chemical Purchase Cost 

Chemical requirements for the vapor-compression evaporation system consist of soda ash 

used for wastewater softening. HPD provided cost data for chemical purchase for one flow rate 

[ERG, 2013; See Appendix 61]. EPA developed a weighted chemical freight cost of $60.57 per 

ton, based on the required quantities of the soda ash, its density, and freight cost information by 

weight from FreightCenter.com. EPA developed Equations 6-192 and 6-193 to estimate the 

chemical purchase cost. 

 Soda Ash Usage (lb/hr) = [Redacted] (6-192) 

Chemical Cost (2010$) = Soda Ash Usage × 1 ton/2,000lb × 24 hr/day × 365 day/yr × (Soda Ash 

 Cost + Chemical Freight) × (2010 Cost Index/2009 Cost Index) (6-193) 

 

41 The median FGD wastewater treatment operator labor rate based on survey data is in 2009$. EPA will index the 

value appropriately with cost index data from RS Means for the final rule. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-111 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

Soda Ash Cost = Cost of soda ash provided by vendor, [Redacted], 

Chemical Freight = $60.57 (2009$)/ton, 

2010 Cost Index = 183.5, and 

2009 Cost Index = 180.1. 

6.3.6.5 Energy Cost 

EPA calculated energy costs for each plant as the sum of energy costs for the softener, 

brine concentrator, and crystallizer. 

Energy Cost (2010$) = Brine Concentrator & Crystallizer Energy Cost + Softening Energy 

 Cost (6-194) 

Brine Concentrator & Crystallizer Energy

EPA calculated energy consumption (kWh) for the brine concentrator and crystallizer 

using Equation 6-195, which was developed from information provided by GE and HPD for two 

different flow rates [ERG, 2013; See Appendix 61]. 

 Brine Concentrator & Crystallizer Energy Consumption (kWh/yr) = [Redacted] (6-195) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5). 

Softening Energy

EPA calculated energy consumption (kWh) for FGD wastewater softening using 

Equation 6-196, which was developed based on information provided by HPD for one flow rate 

[ERG, 2013; See Appendix 61]. 

 Softening Energy Consumption (kWh/yr) = [Redacted] (6-196) 

where: 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5). 
Chapter 6 - FGD Wastewater Cost Methodology 

6-112 

To calculate energy costs, EPA multiplied energy consumption by the national average 

energy cost of 4.05 cents per kWh (2009$) as determined by the U.S. Energy Information 

Administration in Table 8.2 of the Electric Power Annual 2009 for fossil plants in the United 

States [U.S. DOE, 2011]. As the energy cost was provided in 2009 dollars, EPA adjusted the cost 

basis to 2010 dollars using the 2009 and 2010 RSMeans Historical Cost Indices (180.1 and 

183.5, respectively) [RSMeans, 2011]. 

Plant Energy Cost (2010$/yr) = [Brine Concentrator & Crystallizer Energy Consumption + 

Softening Energy Consumption] × National Energy Cost × (2010 Cost Index/2009 Cost 

 Index) (6-197) 

where: 

Brine Concentrator & 

Crystallizer Energy 

Consumption 

= Annual amount of energy consumed by the brine 

concentrator and crystallizer equipment in kWh, 

Softening Energy 

Consumption 

= Annual amount of energy consumed by the softening 

equipment in kWh, 

National Energy Cost = $0.0405/kWh in 2009 dollars, 

2010 Cost Index = 183.5, and 

2009 Cost Index = 180.1. 

For the purpose of estimating non-water quality environmental impacts, EPA also 

converted energy consumption in kWh/yr to energy load in MW using Equation 6-198. 

Energy Load (MW) = [Brine Concentrator & Crystallizer Energy Consumption + Softening 

 Energy Consumption] / (24 hpd × 365 dpy) × 1 MW / 1000 kW (6-198) 

where: 

Brine Concentrator & 

Crystallizer Energy 

Consumption 

= Annual amount of energy consumed by the brine 

concentrator and crystallizer equipment in kWh, and 

Softening Energy 

Consumption 

= Annual amount of energy consumed by the softening 

equipment in kWh. 

6.3.7 Sludge Disposal Cost

The vapor-compression evaporation system generates both softening sludge and 

crystallizer sludge. According to HPD, softening sludge and crystallizer sludge are generated at 

rates of 51.43 lb/hr and 17.14 lb/hr for each gpm of FGD wastewater flow [ERG, 2013; See 

Appendix 61]. Based on this information, EPA calculated sludge generation rates using 

Equations 6-199 and 6-200. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-113 

Softening Sludge (tons/yr) = Softening Sludge Factor × FGD Wastewater Treatment Flow GPM 

 × (1 ton/2,000 lb) × 24 hpd × 365 dpy (6-199) 

Crystallizer Sludge (tons/yr) = Crystallizer Sludge Factor × FGD Wastewater Treatment Flow 

 GPM × (1 ton/2,000 lb) × 24 hpd × 365 dpy (6-200) 

where: 

Softening Sludge = Amount of sludge generated annually by the softening 

equipment, 

Softening Sludge 

Factor 

= 51.43 lb/hr-gpm, 

FGD Wastewater 

Treatment Flow GPM 

= FGD wastewater flow rate in gpm normalized for 24 

hpd operation (see Section 6.1.5), 

Crystallizer Sludge = Amount of sludge generated annually by the 

crystallizer, and 

Crystallizer Sludge 

Factor 

= 17.14 lb/hr-gpm. 

Sections 5.3 and 5.4 discuss costs for the transportation and disposal of sludge from the 

chemical precipitation system. 

6.3.8 Mercury Analyzer Cost

Section 6.1.9 discusses costs to install and operate a mercury analyzer and effluent 

recycle system. The mercury analyzer costs are incurred only once for an entire wastewater 

treatment system. Therefore, for plants expected to install a chemical precipitation and vaporcompression evaporation system to meet the proposed ELGs, EPA included the cost for one 

mercury analyzer for the entire system. 

6.3.9 Compliance Monitoring Cost

Section 5.2 discusses costs for compliance monitoring of vapor-compression evaporation 

distillate effluent. 

6.3.10 Surface Impoundment Operation Cost

Section 5.5 discusses cost savings associated with closing combustion residual surface 

impoundments. 

6.3.11 FGD System Outage Costs

EPA considered the impact of a plant outage required to install the vapor-compression 

evaporation treatment system. Based on an evaluation of vendor and survey information, EPA 

determined that connecting the wastewater treatment system to the existing FGD system can be 
Chapter 6 - FGD Wastewater Cost Methodology 

6-114 

completed during regularly scheduled outages. The entire treatment system can be installed prior 

to a scheduled outage, and then the necessary tie-in can occur during a regularly scheduled 

outage. Therefore, there are no costs for plant outages during installation of the vaporcompression evaporation treatment system. 

6.3.12 Results and Summary of Costs

As described in Section 2.1.4, EPA’s cost model generated plant-level compliance costs 

for the one-stage chemical precipitation with vapor-compression evaporation technology option. 

The cost output generated by the model includes a breakout of specific capital and O&M cost 

elements, including equipment costs, installation costs, operating labor, maintenance labor, and 

energy costs. The output also includes costs for the common cost elements described in Chapter 

5. A list of the plant-level costs for the chemical precipitation with vapor-compression 

evaporation technology option is included in the appendix. 

6.4 REFERENCES

1. Eastern Research Group, Inc (ERG). 2012. Final Site Visit Notes and Sampling Episode 

Report for Enel’s Power Plants. (8 August). DCN SE02013. 

2. Eastern Research Group, Inc (ERG). 2013. Supplemental Costs and Loadings 

Documentation. (19 April). DCN SE01825. 

3. RSMeans. 2011. Building Construction Cost Data, 69th Edition. (January). DCN 

SE02952. 

4. Shaw, William A. 2008. “Benefits of Evaporating FGD Purge Water.” Power. (March). 

59-63. Available online at: 

http://www.powermag.com/powerweb/archive_article.asp?a=60-

F_WM&y=2008&m=march. Date accessed: March 14, 2008. EPA-HQ-OW-2006-0771-

1564. 

5. Sonstegard, J., et al. 2008. Full Scale Operation of GE ABMET® Biolocial Technology 

for the Removal of Selenium from FGD wastewaters. IWC-08-31. (January). DCN 

SE02955. 

6. U.S. Department of Energy (DOE). 2011. U.S. Department of Energy, Energy 

Information Administration (EIA). Electric Power Annual 2009. Washington, DC. (4 

January). DCN SE02023. 
Chapter 6 - FGD Wastewater Cost Methodology 

6-115 

Figure 6-1. One-Stage Chemical Precipitation Treatment
Chapter 6 – FGD Wastewater Cost Methodology 

6-116 

Figure 6-2. Solubilities of Metal Hydroxides and Sulfides as a Function of pH 
Chapter 6 – FGD Was

6-117 

Figure 6-3. Two-Stage Biological Treatment System (System to follow Chemical Precipitation Pr
Chapter 6 – FGD Was

6-118 

Figure 6-4. Mean Maximum Daily Temperature for July 

Source: NOAA/NESIS/NCDC Climate Maps of the United States 

http://cdo.ncdc.noaa.gov/cgi-bin/climaps/climaps.pl
Chapter 6 – FGD Was

6-119 

Figure 6-5. Location of Plants Incurring Heat Exchanger Costs 
Chapter 6 – FGD Was

6-120 

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

Evaporation 
Chapter 6 – FGD Was

6-121 

Figure 6-7. Process Flow Diagram for a Vapor-Compression Evaporation System (System to Follow Che

Pretreatment) 
Chapter 6 – FGD Wastewater Cost Methodology 

6-122 

Table 6-1. Expected FGD Wastewater Characteristics for Design of the Biological 

Treatment Stage 

Analyte Unit Average Min Max 

TOTAL 

Arsenic μg/L 3.45 1.8 6.4 

Mercury ng/L 12200 72.9 53300 

Selenium μg/L 873 87 2150 

DISSOLVED 

Arsenic μg/L 3.05 1.5 5.4 

Mercury ng/L 15800 ND 50000 

Selenium μg/L 871 86.5 2100 

CLASSICALS 

Biochemical Oxygen Demand mg/L 2.36 ND 7.4 

Chemical Oxygen Demand mg/L 224 79 455 

Total Suspended Solids mg/L 14.1 1.2 70.5 

Total Dissolved Solids mg/L 15800 7150 26000 

Sulfate mg/L 5000 1200 16000 

Nitrate Nitrite as N mg/L 58.6 13 160 

ND – Non-Detect 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-1 

CHAPTER 7 

FLY ASH TRANSPORT WATER COST METHODOLOGY 

Because of the development of ash handling systems that require little to no water, as 

well as the ability to market dry fly ash, plants have been converting handling operations on 

existing steam electric generating units from wet sluicing operations to systems that do not 

transport the ash with water. EPA estimated the capital, operating and maintenance (O&M), and 

10-year recurring costs associated with converting wet fly ash handling systems (specifically wet 

fly ash sluicing systems) to dry fly ash handling systems. EPA evaluated the following two 

technology options for fly ash transport water: 

 Dry vacuum fly ash handling system; and 

 Vactor truck collection system. 

The following sections describe the technology basis and methodology used to estimate 

the compliance costs associated with converting from wet fly ash handling systems to a dry 

vacuum ash handling system or a vactor truck collection system. Section 7.1 describes the 

methodology for converting to a dry vacuum fly ash handling system, and Section 7.2 describes 

the methodology for converting to a vactor truck collection system. 

7.1 CONVERSION OF WET FLY ASH HANDLING SYSTEMS TO DRY VACUUM FLY ASH 

HANDLING SYSTEMS

Plants operating wet fly ash handling systems use a vacuum created by water flowing through 

an eductor to draw the fly ash away from the hoppers. These water jet eductors, also known as 

venturi eductors, use the kinetic energy of the water to create the vacuum for the dry portion of the 

ash handling system. The ash is pulled to a separator/transfer tank, where it combines with the water 

flowing through the sluice pipes for transport to the ash impoundment. Plants usually have a sluice 

stream for each individual electrostatic precipitators (ESP) or set of hoppers, with the sluice water 

flowing continuously to maintain the necessary vacuum and prevent solids from settling in the 

piping. Alternatively, some plants use venturi-type wet scrubbers to remove fly ash. EPA estimated 

the costs required to retrofit wet fly ash handling systems and convert them to a dry vacuum fly ash 

handling system. EPA developed a costing approach for three separate portions of the system: 

 Conveyance. The portion of the fly ash handling system from the bottom of the 

collection hopper to the intermediate storage destination. The conveyance includes 

the mechanical exhauster, piping, valves, and filter-separators necessary to pull and 

convey ash from the bottom of the hopper. EPA calculated conveyance costs at the 

steam electric generating unit level. 

 Intermediate Storage. The destination to which the dry fly ash is conveyed from the 

bottom of the hopper. The intermediate storage contains the structure itself (e.g., the 

silo), including the vacuum equipment necessary to receive the ash from the 

conveyance lines, and the unloading equipment necessary for moisture conditioning 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-2 

prior to transportation and disposal.42 EPA calculated intermediate storage costs at the 

plant level. 

 Transportation/Disposal. The trucking equipment and operation that move the dry 

fly ash to its final destination (i.e., on-site or off-site landfill). EPA calculated 

transport/disposal costs at the plant level. 

EPA calculated total costs for each plant as the sum of the conveyance costs for each 

steam electric generating unit requiring fly ash handling conversion costs, as well as intermediate 

storage and transportation and disposal costs for the conversion of wet to dry fly ash handling. 

All costs were estimated in 2010 dollars. 

7.1.1 Technology Description

The dry vacuum fly ash handling system uses a mechanical exhauster to move air to 

entrain and convey dry fly ash particles away from the hoppers to storage silos. EPA based the 

design and cost of the replacement dry vacuum ash handling system on information collected 

from vendors (Clyde Bergemann Power Group (CBPG, formerly Delta Ducon) and United 

Conveyance Corporation), as well as information collected from industry through site visits and 

the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric 

Survey). 

Based on the information from CPBG, EPA estimated costs for a dry vacuum handling 

system including the following components: 

 Air inlet branch line valves; 

 Segregating branch line valves; 

 Hopper isolation valves; 

 Ash intake valves; 

 Large flange (LF) pipe for branch lines (two rows each); 

 LF pipe for header to silo; 

 Elbows: PERMA/flow IWB (90 Degree); 

 Elbows: PERMA/flow IWB (45 Degree); 

 Laterals: PERMA/flow IWB (45 Degree); 

 Couplings; 

 Pipe supports: 3 feet maximum to support steel; 

 Filter-Receiver: 

 Bag filter with specified cloth area, 

 Receiver tank with stone box inlet, 

 

42 Plants may have a silo; however, they may need to install the equipment for moisture-conditioning ash prior to 

unloading. Therefore, the intermediate storage costs are based on two cost indicators, one for the silo and one for the 

pugmill. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-3 

 Airlock with two PERMA/flo V valves, 

 Equalizing valve, 

 Broken bag detector, 

 Vacuum breaker; 

 Vacuum pumps: 

 Rated for specified ACFM at 15” Hg system vacuum and surge, 

 Motor, 

 Butterfly valves for selection, 

 Sound enclosure, and 

 Lot miscellaneous instrumentation and control. 

The specified sizing of the branch lines, elbows, laterals, couplings, valves, and motors 

differ based on the required size of the system. EPA determined the size of the system from the 

fly ash generation rate of each unit requiring a retrofit [ERG, 2013; See Appendix 69]. 

Using this system, the dry fly ash is conveyed to a steel or concrete silo of an appropriate 

size to hold three days’ worth of dry fly ash. EPA determined whether to use steel versus 

concrete silos for plants based on which material provided the more economical option. The steel 

silo includes the following components: 

 Steel silo; 

 Level indicators, manway, and jib crane; 

 Aeration system; and 

 Pugmill unloaders. 

The concrete silo includes the following components: 

 Concrete silo; 

 Jumpform concrete silo walls; 

 Roof; 

 Bin floor; 

 Equipment floor; 

 Aeration system; and 

 Pugmill unloaders. 

EPA assumed that the fly ash would be unloaded from the silo, moisture-conditioned, and 

disposed of in an on-site or off-site landfill. Pugmill unloaders mix dry ash and water to a desired 

moisture content while the ash is transferred from the silo to a transport vessel. EPA assumed 

that each silo would at least have two moisture conditioning unloaders for redundancy [ERG, 

2013; See Appendix 69]. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-4 

7.1.2 Population Costed

Based on information from the Steam Electric Survey, EPA identified 76 plants, 

corresponding to 194 units, discharging fly ash transport water without any plans to convert to 

dry handling or having the capacity to handle all the fly ash dry, from coal- and oil-fired 

units.43,44 EPA identified the units planning to convert to dry handling from responses in the 

Steam Electric Survey stating a planned conversion, the projected date for the conversion, and 

the end use of the wet sluicing system. Additionally, EPA identified plants that have announced 

plans to retire generating units or convert to dry fly ash handling prior to December 31, 2014, as 

described in Section 4.4.1. Finally, EPA identified units with enough capacity to handle all fly 

ash with a dry handling system from responses in the Steam Electric Survey stating that no 

modifications to the existing fly ash handling system would be required to handle all of the fly 

ash dry. There are no conversion costs for generating units that are already planned to be retired 

or converted to dry fly ash handling systems because the plant will convert/retire these units 

without the implementation of the Steam Electric effluent limitations guidelines and standards 

(ELGs). Additionally, there are no conversion costs for generating units that have both wet and 

dry fly ash handling systems where the dry system is capable of handling all of the fly ash 

because the plant would be capable of operating without the wet sluicing system. EPA estimated 

compliance costs for these 76 plants to convert wet sluicing systems to dry vacuum systems. 

7.1.3 Fly Ash Handling Equipment Reused in the Conversion

The conversion from wet to dry fly ash handling for a unit requires new equipment to 

pnuematically convey the ash; however, some pieces of the existing wet fly ash handling system 

can be retained for use with the dry vacuum ash handling system. Specifically, based on input 

from CPBG, EPA assumed that the existing vacuum hopper equipment and branch lines can be 

retained and therefore did not include costs for this equipment [ERG, 2013; See Appendix 69]. 

In addition, based on data from the Steam Electric Survey and site visits, EPA determined 

that a single steam electric generating unit may be equipped with both wet and dry handling 

capabilities. Therefore, depending on the equipment already operating at the plant, and the 

capacity of that equipment, complete conversion costs are not applicable to all steam electric 

generating units. As appropriate, plants with wet and dry handling systems were given credit for 

having this equipment at the plant and flagged in the “Fly Ash Input Table” accordingly (see 

Section 4.2.2). 

7.1.4 Input Table

As discussed in Section 4.2.2, EPA used data from the Steam Electric Survey to identify 

which plants operate one or more fly ash sluicing systems. These plants all incur some level of 

costs for converting to dry fly ash handling, except those plants that have the capacity to handle 

 

43 When the group of plants excluding oil-fired unts and units with a capacity of 50 MW or less is evaluated the 

population of plants discharing fly ash transport water includes 66 plants, corresponding to 170 units. 

44 EPA only includes those oil-fired units wet sluicing fly ash more than 100 days out of the year. Oil-fired units wet 

sluicing fly ash less than 100 days out of the year are included in the population described in Section 7.2.2. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-5 

both wet and dry ash. The “Fly Ash Input Table” holds all the input data needed to calculate the 

compliance costs for these plants. The “Fly Ash Input Table” contains the following fields: 

 Plant_id: Survey Plant ID. 

 Seunit_id: Survey Steam Electric (SE) Unit ID. 

 No_cost: Flag indicating that the unit will not incur costs for its fly ash system. 

 Conveyancecost: Flag indicating that the unit will require a fly ash conveyance 

retrofit. 

 Silocost: Flag indicating that the unit will require increased silo capacity 

 Pugmillcost: Flag indicating that the unit will require installation of pugmills for ash 

conditioning. 

 Market_landfill: Flag indicating that the unit operated a wet fly ash handling system 

because the fly ash was not marketable or respondent indicated that an increase in 

landfill capacity would be required to handle all of the fly ash dry. 

 Wet_tpd: The amount of fly ash handled wet in tons per day (tpd) (dry weight basis) 

from Table C-2. For units that handled fly ash wet in 2009 and did not report this 

value, it has been calculated by multiplying the tons of coal burned in the unit in 2009 

by 8 percent (assuming 10 percent ash content for the coal and 80 percent of ash 

generated is fly ash). This value is then divided by the number of days the unit 

operated in 2009, as reported in Table A-8, to get an estimate of the amount of wet fly 

ash handled wet in tons per day. 

 Wet_dpy: Number of days fly ash was conveyed wet in 2009 in days per year (dpy) 

from Table C-2. If the number of days was not reported, the number is assumed to be 

the same as the number of operating days. 

 Dry_tpy: The amount of fly ash handled dry in tpd (dry weight basis) from Table C2. 

 Dry_dpy: Number of days fly ash was conveyed dry in 2009 in dpy from Table C-2. 

 Unit_type: Type of unit, as indicated in Table A-8 (i.e., baseload, cycling, 

intermediate, and peaking). 

 Produce_hpd: Estimate of the number of hours per day (hpd) the unit operates. EPA 

assumed units identified as baseload, intermediate, or cycling in Table A-8 operate 24 

hpd and peaking units, as identified in Table A-8, operate 12 hpd. 

 Convey_hpd: Estimate of the number of hpd the unit conveys fly ash. EPA assumed 

all units convey fly ash 12 hpd. 

 Operating_days: Number of days the unit operated in 2009. Value populated from 

responses in Table A-8. If the number of days was not reported, the number is 

assumed to be the reported days per year of wet ash production in Table C-2. 

 MW: The unit capacity (in megawatts (MW)) from steam turbine capacity in Table 

A-8. 

 Retired?: Flag indicating that the plant has identified that it will be retiring on or 

before 12/31/2014. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-6 

 FlowRate_GPD: Fly ash sluice flow rate from Table C-3. 

Section 4.2.2 discusses the methodology used to determine the appropriate level of 

costing for each steam electric unit and the specific Steam Electric Survey questions. A copy of 

the “Fly Ash Input Table” is included in the appendix. 

7.1.5 Capital Cost Methodology

Total capital costs for each plant were calculated as the sum of the following purchased 

equipment costs and installation costs: 

 Purchased equipment costs, 

 Purchased equipment installation costs, 

 Plant overhead engineering costs, and 

 Fly ash disposal costs. 

Purchased equipment costs are the costs associated with purchasing all equipment to 

retrofit all generating units currently collecting fly ash with a wet sluicing system with a dry 

vacuum conveyance system. EPA calculated purchased equipment costs by summing the costs of 

dry vacuum conveyance system(s), the concrete or steel silo(s), silo aeration equipment, and 

pugmill(s). EPA calculated equipment costs for conveyance on a generating unit level and silo 

and pugmill equipment costs at a plant level. EPA estimated conveyance, silo, and pugmill 

equipment costs using a relationship between capital costs and wet fly ash generation rate 

obtained from industry vendors. 

EPA estimated installation capital costs for the fly ash handling conversion for each 

plant, including all system elements, using an installation factor determined from Steam Electric 

Survey data. EPA supplemented this information with cost data from industry vendors to 

determine an installation factor for the conveyance and intermediate storage system elements. 

EPA estimated the installation costs by applying the calculated factor to the purchased 

equipment cost. 

Plant overhead engineering costs were determined from Steam Electric Survey data. 

Based on survey responses, EPA calculated a median installation factor for the conveyance and 

intermediate storage system elements. EPA estimated the overhead costs by applying the 

calculated factor to the purchased equipment and installation costs. 

EPA calculated the amount of moisture-conditioned fly ash generated from the 

conversion using wet fly ash generation rates at the plant-level and an average moisture content 

of fly ash from the Steam Electric Survey, supplemented with vendor data. EPA used the 

moisture-conditioned fly ash tonnage to estimate the disposal costs (see Section 7.1.7). 

EPA assumed zero land costs based on data from site visits and discussions with plants 

who have already converted from wet fly ash handling to dry fly ash handling. EPA assumed that 

other capital costs associated with buildings, site preparation, engineering, and construction were 

included in the costs provided by the vendors. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-7 

7.1.5.1 Purchased Equipment Costs: Conveyance Equipment 

EPA estimated unit-level capital costs for the purchase of equipment to convert from a fly 

ash wet sluicing system to a dry vacuum system. EPA then summed these unit-level costs to 

calculate plant-level conveyance equipment costs. EPA made the assumptions listed below based 

on information obtained from vendors and survey responses: 

EPA costed 500 feet of conveyance from the generating unit to a silo(s). Based on a 

review of questionnaire responses, EPA found that 81 percent of dry vacuum systems (and 91 

percent of dry vacuum system retrofits) convey fly ash less than or equal to one tenth of a mile 

(approximately 500 feet). In addition, CBPG indicated conveyance distance does not 

significantly impact the overall cost of the system. 

EPA did not include costs for hopper and branch line equipment given that this 

equipment can be reused from existing fly ash wet sluicing systems, as described in Section 

7.1.3. 

EPA developed capacity factors to account for variability in fly ash generation rates. For 

base load, cycling, and intermediate generating units, EPA assumed a capacity factor of two; for 

peaking generating units, EPA assumed a capacity factor of four. 

EPA assumed a conveyance rate of 12 hpd for all generating units. 

EPA used vendor data to estimate costs for conveyance systems with fly ash conveyance 

rates up to a maximum of 50 tpd. If a conveyance rate for a unit was calculated to be greater than 

50 tpd, EPA costed multiple vacuum systems of equal size. 

The Supplemental Costs and Loadings Documentation (DCN SE01825.A70) contains 

more detail on the information obtained from vendors and the Steam Electric Survey used to 

estimate conveyance equipment costs. 

EPA determined the size and cost of conveyance equipment based on the unit fly ash 

conveyance rate (in tons per hour (tph)), which was calculated using Equation 7-1. 

Unit Wet Fly Ash Conveyance Rate (tph) = (Unit Wet Fly Ash Generation Rate × Maximum 

 Conveying Capacity Factor) / (Unit Conveying Time) (7-1) 

where: 

Unit Wet Fly Ash 

Generation Rate 

= Amount of wet fly ash produced by the generating unit 

in tpd (see Section 4.2.2), 

Maximum Conveying 

Capacity Factor 

= Factor to adjust capacity to account for variability in fly 

ash generation rates: 2 (for based 

load/cycling/intermediate units)4 (for peak units), and 

Unit Conveying Time = 12 hpd. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-8 

EPA accounted for the maximum conveying capacity factor to adjust the size of the 

costed fly ash handling system to handle the maximum amount of fly ash that may be generated 

at a given time based on the expected fluctuation in unit operations. 

EPA determined the number of dry vacuum systems to be costed, as well as the new unit 

fly ash conveyance rate based on the number of dry systems needed for the generating unit, using 

Equations 7-2 and 7-3. 

Number of Unit Vacuum Systems = Round Up (Unit Wet Fly Ash Conveyance Rate / 50 

 tph) (7-2) 

Recalculated Unit Wet Fly Ash Conveyance Rate (tph) = Unit Wet Fly Ash Conveyance Rate / 

 Number of Unit Vacuum Systems (7-3) 

where: 

Unit Wet Fly Ash 

Conveyance Rate 

= Amount of wet fly ash produced by the generating unit 

in tpd (see Section 4.2.2), and 

Number of Unit 

Vacuum Systems 

= The number of vacuum systems required (see Equation 

7-2). 

CBPG provided EPA with estimated costs for the purchase of equipment to convert wet 

fly ash conveyance systems to dry fly ash conveyance systems for various sized systems. From 

these data, EPA developed Equation 7-4 to estimate dry fly ash conveyance equipment cost. 

Unit-Level Dry Fly Ash Conveyance Equipment Capital Cost (2010$) = (9,791 × Recalculated 

Unit Wet Fly Ash Conveyance Rate + 23,372) × Number of Unit Vacuum Systems (7-4) 

where: 

Recalculated Unit Wet 

Fly Ash Conveyance 

Rate 

= Recalculated wet fly ash conveyance rate to evenly 

distribute wet fly ash among number of vacuum 

systems required (see Equation 7-3), and 

Number of Unit 

Vacuum Systems 

= The number of vacuum systems required (see Equation 

7-2). 

EPA calculated plant-level total conveyance equipment costs by summing the 

conveyance equipment cost for each generating unit. 

Conveyance Equipment Capital Cost (2010$) for Plant = ∑ Unit-Level Dry Fly Ash Conveyance 

 Equipment Capital Cost (7-5) 

7.1.5.2 Purchased Equipment Cost: Silo 

EPA estimated plant-level capital costs for purchasing equipment to provide dry fly ash 

storage capacity for the converted units based on Equation 7-6. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-9 

 Cost (2010$) for Plant = Silo Capital Cost + Other Equipment Silo Cost (7-6) 

EPA first assessed the need for additional storage capacity for each generating unit. EPA 

then summed the additional storage capacity required across all units and estimated the total 

additional storage required at the plant level. EPA made the assumptions listed below based on 

information obtained from vendors and Steam Electric Survey responses: 

 EPA costed silos constructed of steel or concrete and sized for three days (i.e., 72 

hours) of storage capacity to avoid the need to unload ash during weekends. 

 EPA assumed that plants will install the cheaper silo (steel or concrete) based on the 

amount of fly ash generated at the plant level. 

 EPA used a dry fly ash density of 45 lb/ft3. 

 EPA used vendor data to estimate costs for steel silos ranging in size up to a 

maximum of 80,000 ft3

 and concrete silos ranging in size up to a maximum of 12,800 

tons of dry fly ash (569,000 ft3 based on an ash density of 45 lbs/ ft3

). EPA did not 

cost silos with a storage capacity greater than 12,800 tons, based on cost information 

from Marietta Silos [ERG, 2013; See Appendix 71]. 

EPA determined the size and cost of additional storage capacity based on the sum of the 

unit fly ash generation rates (reported in the Steam Electric Survey, in tpd) for the generating 

units requiring additional storage. Using information from CBPG and Marietta Silos, EPA 

determined that steel silos are more cost effective for plants with a plant-level wet fly ash 

generation rate less than 60 tpd. EPA first estimated the number of steel silos required and their 

size using Equations 7-7, 7-8, and 7-9. 45

Steel Silo Size (ft3) = 2,000 lb/ton ⁄ Fly Ash Density × (Plant Wet Fly Ash Generation Rate × 3 

 days) (7-7) 

 Number of Steel Silos = Round Up (Steel Silo Size / 80,000 ft3

) (7-8) 

 Recalculated Steel Silo Size (ft3

) = Steel Silo Size / Number of Silos (7-9) 

where: 

Fly Ash Density = 45 lb/ft3

, and 

Plant Wet Fly Ash 

Generation Rate 

= Sum of the wet fly ash produced for all generating units 

at the plant in tpd. 

CBPG provided EPA with estimated costs for the purchase of various sized steel silos for 

temporary storage of fly ash. The costs include equipment for unloading and fluidizing the fly 

ash. From these data, EPA developed Equation 7-10 to estimate steel silo capital cost. 

 

45 The plant-level wet fly ash generation rate is equal to the sum of the unit fly ash generation rate for all units 

producing wet ash at the plant. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-10 

Steel Silo Capital Cost (2010$) = (14.81 × Recalculated Steel Silo Size + 10,089) × Number of 

 Steel Silos (7-10) 

where: 

Recalculated Steel Silo 

Size 

= Recalculated steel silo size to evenly distribute wet fly 

ash among number of silos required (see Equation 7-9), 

and 

Number of Steel Silos = Number of steel silos required (see Equation 7-8). 

Because vendor costs include unloading and fluidizing equipment, no additional silo 

equipment is required. 

EPA calculated concrete silo capital costs for plants with a plant-level wet fly ash 

generation rate greater than 60 tpd. EPA first estimated the number and size of concrete silos 

required using Equations 7-11, 7-12, and 7-13. 

 Concrete Silo Design Tonnage (tons) = Plant Wet Fly Ash Generation Rate × 3 days (7-11) 

 Number of Concrete Silos = Round Up (Concrete Silo Design Tonnage) / 12,800 tons(7-12) 

Recalculated Concrete Silo Size (tons) = Concrete Silo Design Tonnage / Number of Concrete 

 Silos (7-13) 

where: 

Plant Wet Fly Ash 

Generation Rate 

= Sum of the wet fly ash produced for all generating units 

at the plant in tpd. 

Marietta Silos provided EPA with estimated costs for the purchase of various sized 

concrete silos for temporary storage of fly ash, including costs for the concrete silo, walls, roof, 

bin floor, and equipment floor. From these data, EPA developed Equation 7-14 to estimate 

concrete silo capital costs. 

Concrete Silo Capital Cost (2010$) = [(0.005 × (Recalculated Concrete Silo Size)2

) + (519.8 × 

 Recalculated Concrete Silo Size) + 44,379] × Number of Concrete Silos (7-14) 

Because Marietta Silos’ concrete silo costs did not include any unloading and fluidizing 

equipment costs, EPA applied the unloading and fluidizing equipment costs from CBPG using 

Equation 7-15. 

Other Equipment Concrete Silo Cost (2010$) = [(173.3 × Recalculated Concrete Silo Size) + 

 52,105] × Number of Concrete Silos (7-15) 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-11 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A71) for more 

detail on the development of Equations 7-6 through 7-15. 

7.1.5.3 Purchased Equipment Cost: Pugmill 

EPA estimated plant-level capital costs for the purchase of pugmills to moisten the fly 

ash prior to disposal in landfills (i.e., the silos discussed in Section 7.1.5.2 are not designed for 

dry unloading of dry fly ash).46 EPA made the assumptions listed below in estimating plant-level 

capital costs for purchasing pugmills based on information obtained from vendors, site visits, and 

Steam Electric Survey responses: 

 EPA costed each silo for at least two pugmills for redundancy. 

 EPA assumed an ash unloading time of 16 hpd, five days per week (dpw). EPA based 

these times on observations during site visits of ash unloading during two shifts per 

day and no ash unloading over weekends. 

 EPA used vendor data from CPBG to cost pugmills with a maximum ash 

conditioning/unloading rate of 150 tph. If EPA estimated a pugmill would have an 

ash conditioning/unloading rate of greater than 150 tpd, EPA costed multiple 

pugmills of equal size. 

EPA determined the size and cost of pugmills based on the silo ash unloading rate (in 

tph), which was calculated using Equation 7-16. The pugmill capacity factor, 1.4, provides 

additional pugmill capacity to avoid having to unload ash during weekends (seven days/five 

days). 

Silo Ash Unloading Rate (tph) = Plant Wet Fly Ash Generation Rate / Number of Silos × 

 (Pugmill Capacity Factor) / Pugmill Operating Time (7-16) 

where: 

Plant Wet Fly Ash 

Generation Rate 

= Sum of the wet fly ash produced for all generating units 

at the plant in tpd (see Section 4.2.2), 

Number of Concrete or 

Steel Silos 

= Number of silos needed to storage three days worth of 

the wet ash that is convert to dry handling (see 

Equation 7-8), 

Pugmill Capacity 

Factor 

= Factor applied to the pugmill unloading time to allow 

for enough capacity to unload seven days worth of ash 

within five days, 1.4, and 

 

46 Since EPA has based its compliance cost estimates on the assumption that the fly ash will be disposed of in an onsite or off-site landfill, the ash silos are costed for a configuration that includes moisture conditioning of the ash as it 

is loaded into trucks. EPA did not include costs for dry unloading into vacuum trucks since ash loaded in this 

manner is too dry for landfill disposal. Should a plant choose to also install dry unloading capability for the fly ash 

and market its beneficial use and avoid landfill disposal, the costs for the dry unloading capability will be more than 

offset by the avoided landfill disposal costs and potential revenue associated with selling the ash for beneficial use. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-12 

Pugmill Operating 

Time 

= 16 hpd. 

EPA determined the number of pugmills to be costed using Equation 7-17, with a 

minimum of two pugmills costed. 

 Number of Pugmills = [Round Up (Silo Ash Unloading Rate / 150 tph)] (7-17) 

If Number of Pugmills ≥ 2, then Number of Pugmills = Number of Pugmills; if Number 

of Pugmills < 2, then Number of Pugmills = 2. 

CBPG indicated that the cost of a 150 tph pugmill is $245,000. Therefore, EPA 

calculated the pugmill capital costs using Equation 7-18. 

Pugmill Capital Cost (2010$) = (Number of Pugmills × $245,000) × Number of Concrete Silos 

 (or Number of Steel Silos) (7-18) 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A71) for more 

detail on the development of Equations 7-16 through 7-18. 

7.1.5.4 Purchased Equipment Installation Cost 

Purchased equipment installation includes the installation of all equipment, piping, 

instrumentation/calibration, electrical equipment, mechanical equipment, structural supports, 

insulation, and painting. EPA estimated installation capital costs for the conversion of wet fly ash 

handling systems for each plant by multiplying plant purchased equipment costs by installation 

cost factors developed from vendor and Steam Electric Survey cost data. 

To develop an installation cost factor for conveyance equipment, EPA evaluated 

responses to Question C2-34, Table C-11 (Purchased Equipment and Purchased Equipment 

Installation Costs) of the Steam Electric Survey. Specifically, EPA calculated the ratio of the 

purchased equipment installation cost and the purchased equipment costs; calculated ratios 

ranged from <0.1 to 7, with a median ratio of approximately 0.7. EPA also calculated installation 

cost ratios based on conveyance cost information provided by United Conveyance Corporation 

(UCC); these ratios ranged from 1 to 3. Based on this information, EPA selected a Conveyance 

Install Factor of 2 [ERG, 2013; See Appendix 70]. 

Using this conveyance installation cost factor, EPA estimated the installation costs for 

conveyance equipment using Equation 7-19. 

Conveyance Equipment Installation Capital Cost (2010$) = Conveyance Install Factor × 

 Conveyance Equipment Capital Cost (7-19) 

where: 

Conveyance Install 

Factor 

= Factor that accounts for installation cost as a 

percentage of purchase cost, 2, and 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-13 

Conveyance Equipment 

Capital Cost 

= Cost for purchasing conveyance equipment (see 

Section 7.1.5.1 and Equation 7-5). 

To develop an installation cost factor for storage equipment, EPA evaluated responses to 

Question C2-42, Table C-14 (Purchased Equipment and Purchased Equipment Installation Costs) 

of the Steam Electric Survey. Specifically, EPA calculated the ratio of the purchased equipment 

installation cost and the purchased equipment costs; calculated ratios ranged from <0.01 to 8.12, 

with a median ratio of [Redacted]. Although no vendor cost information was available 

specifically for storage equipment, EPA considered the calculated cost ratios derived from 

conveyance cost information provided by UCC (calculated ratios ranged from 1 to 3). Based on 

this information, EPA selected a Storage Install Factor of 2 [ERG, 2013; See Appendix 71]. 

Because the concrete silo costs from Marietta Silos include the installation of the 

concrete silo (i.e., a concrete silo cannot be constructed and shipped, it must be poured on site), 

the installation capital costs for concrete silos were calculated differently from the installation 

capital costs for steel silos. For the concrete silos, the installation costs were calculated excluding 

the concrete portion of the silo costs. 

EPA estimated the installation costs for a steel silo using Equation 7-20. 

Steel Silo Installation Capital Cost (2010$) = Storage Install Factor × [Steel Silo Capital Cost + 

 Pugmill Capital Cost] (7-20) 

where: 

Storage Install Factor = Factor that accounts for installation cost as a 

percentage of purchase cost, 2, 

Steel Silo Capital Cost = Cost for purchasing steel silos (see Section 7.1.5.2 and 

Equation 7-10), and 

Pugmill Capital Cost = Cost for purchasing pugmills (see Section 7.1.5.3 and 

Equation 7-18) 

EPA estimated the installation costs for a concrete silo using Equation 7-21. 

Concrete Silo Installation Capital Cost (2010$) = Storage Install Factor × [Other Equipment 

 Concrete Silo Capital Cost + Pugmill Capital Cost] (7-21) 

where: 

Storage Install Factor = Factor that accounts for installation cost as a 

percentage of purchase cost, 2, 

Other Equipment 

Concrete Silo Capital 

Cost 

= The unloading and fluidizing equipment costs for a 

concrete silo (see Section 7.1.5.2 and Equation 7-15), 

and 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-14 

Pugmill Capital Cost = Cost for purchasing pugmills (see Section 7.1.5.3 and 

Equation 7-18). 

EPA estimated installation capital costs for converting wet fly ash handling systems to 

dry fly ash systems by summing the costs associated with installing the conveyance equipment 

and the storage equipment. 

Total Installation Capital Cost (2010$) = (Conveyance Equipment Installation Capital Cost) + 

 (Storage Installation Capital Cost) (7-22) 

where: 

Conveyance Equipment 

Installation Capital 

Cost 

= Cost to install the conveyance equipment for a dry 

vacuum fly ash conversion, (see Equation 7-19), and 

Storage Installation 

Capital Cost 

= Cost to install the silo equipment for a dry vacuum fly 

ash conversion, which is equal to either the Steel Silo 

Installation Capital Cost, (see Equation 7-20), or the 

Concrete Silo Installation Capital Cost, (see Equation 

7-21), depending on which type of silo is installed for 

the unit. 

7.1.5.5 Engineering Costs 

EPA determined engineering overhead costs by multiplying the purchased and 

installation equipment costs by a factor for conveyance equipment and silo equipment. EPA 

determined these factors based on survey responses to Questions C2-34 (conveyance costs) and 

C2-42 (silo costs). To determine the Conveyance Overhead Factor, EPA calculated the 

percentage of engineering overhead costs to the total costs, provided in response to Question C2-

34 of the Steam Electric Survey, using Equation 7-23 [ERG, 2013; See Appendix 70]. 

Ratio = Engineering Overhead Conveyance Costs/(Total Capital Conveyance Costs – 

 Engineering Overhead Conveyance Cost) (7-23) 

where: 

Engineering Overhead 

Conveyance Costs 

= Engineering overhead costs for conveyance equipment 

provided in Question C2-34, and 

Total Capital 

Conveyance Costs 

= Capital costs for conveyance equipment provided in 

Question C2-34. 

EPA calculated the median ratio based on all responses, 0.02454, and used that as the 

Conveyance Overhead Factor. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-15 

To determine the Silo Overhead Factor, EPA calculated the ratio of engineering overhead 

costs to the total costs, provided in response to Question C2-42 of the Steam Electric Survey, 

using Equation7-24 [ERG, 2013; See Appendix 71]. 

Ratio = Engineering Overhead Silo Costs/(Total Capital Silo Costs – Engineering Overhead Silo 

 Cost) (7-24) 

where: 

Engineering Overhead 

Silo Costs 

= Engineering overhead costs for silos provided in 

Question C2-42, and 

Total Capital Silo Costs = Capital costs for silos provided in Question C2-42. 

EPA calculated the median ratio based on all responses, 0.0082, and used that as the Silo 

Overhead Factor. 

EPA used Equation 7-25 to estimate engineering overhead costs. 

Engineering Overhead Costs (2010$) = ([Conveyance Equipment Capital Cost + Conveyance 

Equipment Installation Capital Cost] × Conveyance Overhead Factor) + ([Silo Equipment 

 Capital Cost + Silo Equipment Installation Cost] × Silo Overhead Factor) (7-25) 

where: 

Conveyance Overhead 

Factor 

= Factor that accounts for engineering overhead costs as 

a percentage of purchase and installation costs for the 

conveyance portion of the system, 0.02454, 

Silo Overhead Factor = Factor that accounts for engineering overhead costs as 

a percentage of purchase and installation costs for the 

silo portion of the system, 0.0082, 

Conveyance Equipment 

Capital Cost 

= Cost for purchasing conveyance equipment (see 

Section 7.1.5.1 and Equation 7-5), 

Conveyance Equipment 

Installation Capital 

Cost 

= Cost for installing the conveyance equipment (see 

Section 7.1.5.4 and Equation 7-19), 

Silo Equipment Capital 

Cost 

= Cost for purchasing steel or concrete silos (see Section 

7.1.5.2 and Equations 7-10 or 7-14 and 7-15), and 

Silo Equipment 

Installation Cost 

= Cost for installing the steel or concrete silo (see Section 

7.1.5.4 and Equations 7-20 or 7-21). 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-16 

7.1.6 O&M Cost Methodology

O&M costs for each plant consist of all costs related to operating and maintaining the 

conveyance and storage equipment associated with the dry vacuum fly ash handling systems. 

EPA calculated total O&M costs as the sum of conveyance O&M costs and storage O&M costs. 

Total conveyance O&M costs for conveyance systems were calculated as the sum of the 

following O&M cost components: 

 Conveyance operating labor cost, 

 Conveyance maintenance labor cost, 

 Conveyance maintenance materials cost, 

 Conveyance maintenance outage cost, 

 Conveyance chemical purchase cost, and 

 Conveyance energy cost. 

Total storage O&M costs for dry fly ash storage systems were calculated as the sum of 

the following O&M cost components: 

 Storage operating labor cost, 

 Storage maintenance labor cost, 

 Storage maintenance materials cost, 

 Storage chemical purchase cost, and 

 Storage energy cost. 

7.1.6.1 Conveyance O&M Costs: Operating Labor 

The conveyance operating labor costs include labor costs for ash handling system 

operators to operate the conveyance systems. EPA estimated unit-level operating labor costs and 

then summed these unit-level costs to calculate plant-level operating labor costs. EPA calculated 

operating labor costs for each unit by multiplying the operating labor rate by the number of 

required operator hours per year. 

To determine the operating labor rate, EPA evaluated labor rates reported in response to 

Question C2-36, Table C-12 (Operating Labor Rate & Maintenance Labor Rate) of the Steam 

Electric Survey. Reported operating labor rates for generating units with dry vacuum systems 

ranged from [Redacted]/hr to $77.00/hr (median of $47.50/hr), while maintenance labor rates 

ranged from [Redacted]/hr to [Redacted]/hr (median of $41.54/hr). As conveyance system O&M 

may be performed by the same personnel, EPA selected an overall operating labor rate as the 

median of the entire Steam Electric Survey data set, $46.36/hr (2010$). EPA evaluated survey 

responses to Question C2-36, Table C-12 (Operating Labor Staffing/Consumption). Reported 

operator hours per day [Redacted] ranged from 0.2 to 35 hpd, with a median and average of 2.4 

and 6.2 hours per day, respectively. EPA selected the median value, 2.4 hpd, for use in the cost 

methodology [ERG, 2013; See Appendix 70]. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-17 

EPA calculated the unit operator hours per year using Equation 7-26. 

Conveyance Unit Operator Hours = Conveyance Unit Operator Hours per Day × 

 Number of Operating Days per Year × Number of Unit Vacuum Systems (7-26) 

where: 

Conveyance Unit 

Operator Hours per 

Day 

= Number of hours per day that the conveyance 

equipment is operated, 2.4 hpd, 

Number of Operating 

Days per Year 

= Number of days the generating unit is operated per year 

(see Section 4.2.2), and 

Number of Unit 

Vacuum Systems 

= Number of unit vacuum systems costed (see Section 

7.1.5.1 and Equation 7-2). 

EPA calculated the Conveyance Unit Operating Labor Cost using Equation 7-27. 

Conveyance Unit Operating Labor Cost (2010$/yr) = Conveyance Operating Labor Rate × 

 Conveyance Unit Operator Hours (7-27) 

where: 

Conveyance Operating 

Labor Rate 

= $46.36/hr (2010$), and 

Conveyance Unit 

Operator Hours 

= Number of hours per year that the conveyance 

equipment is operated, (see Equation 7-26). 

EPA estimated the total Conveyance Operating Labor Costs at the plant by summing the 

labor hours for all conveyance units at the plant using Equation 7-28. 

Conveyance Operating Labor Cost (2010$/yr) = ∑ Conveyance Unit Operating Labor Cost(7-28) 

7.1.6.2 Conveyance O&M Costs: Maintenance Labor 

The maintenance labor costs include labor costs for plant staff to maintain the 

conveyance systems. EPA estimated unit-level maintenance labor costs and then summed these 

unit-level costs to calculate plant-level maintenance labor costs. EPA calculated maintenance 

labor costs for each unit by multiplying the maintenance labor rate by the number of required 

maintenance hours per year. 

Because conveyance system O&M may be performed by the same personnel, EPA 

selected an overall operating and maintenance labor rate, as discussed in Section 7.1.6.6 

($46.36/hr). EPA calculated unit maintenance hours per year by multiplying the unit 

maintenance hours per year by the number of unit vacuum systems costed. EPA determined 

maintenance hours per year based on an evaluation of responses to Question C2-36, Table C-12 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-18 

(Maintenance Labor Staffing/Consumption) of the Steam Electric Survey. Reported maintenance 

hours per year [Redacted] ranged from 40 to 7,300 hours per year for ash handling system 

maintenance, with a median and average of 413 and 963 hours per year, respectively. EPA 

selected an overall unit maintenance hours per year as the median of the Steam Electric Survey 

data set, 413 hours per year [ERG, 2013; See Appendix 70]. EPA determined the number of unit 

vacuum systems costed as described in Section 7.1.5.1. 

EPA calculated the Conveyance Unit Maintenance Labor Cost using Equation 7-29. 

Conveyance Unit Maintenance Labor Cost (2010$/yr) = Conveyance Maintenance Labor Rate × 

 Conveyance Maintenance Hours × Number of Unit Vacuum Systems (7-29) 

where: 

Conveyance 

Maintenance Labor 

Rate 

= $46.36/hr (2010$), 

Conveyance 

Maintenance Hours 

= 413 hpy, and 

Number of Unit 

Vacuum Systems 

= Number of unit vacuum systems costed (see Section 

7.1.5.1 and Equation 7-2). 

EPA calculated the total Conveyance Maintenance Labor Costs per plant using Equation 

7-30. 

Conveyance Maintenance Labor Cost (2010$/yr) = ∑ Conveyance Unit Maintenance Labor 

 Cost (7-30) 

7.1.6.3 Conveyance O&M Costs: Energy Cost 

Fly ash conveyance systems require energy to operate the mechanical vacuum pumps that 

move air to entrain and convey dry fly ash particles away from the hoppers to the storage silos. 

EPA estimated vacuum pump energy consumption (in kilowatt hours per year (kWh/yr)) 

as a function of pump horsepower. EPA determined unit-level vacuum pump horsepower based 

on the recalculated unit fly ash conveyance rate (determined as described in Section 7.1.5.1 and 

Equation 7-3) using the following step function provided by CBPG [ERG, 2013; See Appendix 

69]: 

 For Recalculated Unit Wet Fly Ash Conveyance Rate ≤ 11 tph: 

- Vacuum Pump Horsepower = 75 hp 

 For Recalculated Unit Wet Fly Ash Conveyance Rate > 11 tph and ≤ 21 tph: 

- Vacuum Pump Horsepower = 125 hp 

 For Recalculated Unit Wet Fly Ash Conveyance Rate > 21 tph and ≤ 32 tph: 

- Vacuum Pump Horsepower = 200 hp 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-19 

 For Recalculated Unit Wet Fly Ash Conveyance Rate > 32 tph: 

- Vacuum Pump Horsepower = 250 hp 

EPA summed the unit-level energy requirements to calculate plant-level energy 

consumption using Equations 7-31 and 7-32. 

Conveyance Unit Energy Consumption (kWh/yr) = Vacuum Pump Horsepower × 0.745699 

kW/HP × Number of Pumps × Number of Unit Vacuum Systems × Unit Conveying Time × Unit 

 Operating Days (7-31)

where: 

Vacuum Pump 

Horsepower 

= Pump Horsepower for Recalculated Unit Fly Ash 

Conveyance Rate, 

Number of Pumps = Number of vacuum pumps required to operate the 

conveyance system, two, per input from CBPG, 

Number of Unit 

Vacuum Systems 

= Number of unit vacuum systems costed (see Section 

7.1.5.1 and Equation 7-2), 

Unit Conveying Time = 12 hpd, and 

Unit Operating Days = Number of days each generating unit operated per year 

(see Section 4.2.1). 

Conveyance Energy Consumption (kWh/yr) = ∑ Conveyance Unit Energy Consumption (7-32) 

To calculate energy costs, EPA multiplied the conveyance energy consumption by the 

average national energy cost of 4.05 cents per kWh (2009$), as determined based on data 

reported by the U.S. Energy Information Administration in Table 8.2 of the Electric Power 

Annual 2009 for fossil plants in the United States [U.S. DOE, 2011]. As the energy cost was 

provided in 2009 dollars, EPA adjusted the cost basis to 2010 dollars using the 2009 and 2010 

RSMeans Historical Cost Indices (180.1 and 183.5, respectively) [RSMeans, 2011]. 

Conveyance Energy Cost (2010$/yr) = National Energy Cost × Conveyance Energy 

 Consumption × (2010 Cost Index/2009 Cost Index) (7-33) 

where: 

National Energy Cost = $0.0405/kWh (2009$), 

Conveyance Energy 

Consumption 

= Plant-level energy consumption associated with the 

conveyance equipment, 

2009 Cost Index = 180.1, and 

2010 Cost Index = 183.5. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-20 

For the purpose of estimating non-water quality environmental impacts, EPA also 

converted energy consumption in kWh/yr to energy load in MW using Equation 7-34. 

Conveyance Unit Energy Load (MW) = Conveyance Unit Energy Consumption / (Unit 

 Conveying Time × Unit Operating Days) × 1 MW / 1000 kW (7-34)

where: 

Conveyance Unit 

Energy Consumption 

= The annual unit-specific energy consumption 

associated with conveyance in kWh/yr, 

Unit Conveying Time = 12 hpd, and 

Unit Operating Days = Number of days each generating unit operated per year 

(see Section 4.2.2). 

EPA summed the unit-level energy load for all units at the plant to calculate the plantlevel energy consumption. 

 Conveyance Energy Load for Plant (MW) = ∑ Conveyance Unit Energy Load (7-35) 

7.1.6.4 Conveyance O&M Costs: Maintenance Materials 

EPA included costs for maintenance materials, such as routine replacement of materials 

and equipment due to consumption or wear and tear. EPA developed Equation 7-36 to estimate 

maintenance material costs using the O&M costs reported in response to the Steam Electric 

Survey for generating units with dry vacuum systems. Specifically, EPA evaluated responses to 

Question C2-36, Table C-12 (Maintenance Materials) of the Steam Electric Survey, calculating 

the ratio of reported maintenance material costs to the total sum of operating labor, maintenance 

labor, energy, and other O&M costs. EPA selected the median ratio of 0.332 as the conveyance 

maintenance materials cost factor [ERG, 2013; See Appendix 70]. 

Conveyance Maintenance Materials Cost (2010$/yr) = Conveyance Maintenance Materials Cost 

Factor × (Conveyance Operating Labor Cost + Conveyance Maintenance Labor Cost + 

 Conveyance Energy Cost) (7-36) 

where: 

Conveyance 

Maintenance Materials 

Cost Factor 

= Factor that accounts for material costs as a percentage 

of O&M cost, 0.332, 

Conveyance Operating 

Labor Cost 

= Includes labor costs for ash handling system operators 

to operate the conveyance systems (see Section 7.1.6.1 

and Equation 7-28), 

Conveyance = Includes labor costs associated with maintaining the 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-21 

Maintenance Labor 

Cost 

conveyance systems (see Section 7.1.6.2 and Equation 

7-30), and 

Conveyance Energy 

Cost 

= Energy costs associated with operating the mechanical 

vacuum pumps (see Section 7.1.6.3 and Equation 

7-32). 

7.1.6.5 Conveyance O&M Costs: Maintenance Outage 

EPA considered the impact of plant outages required to maintain dry fly ash handling 

systems compared to wet fly ash handling systems. EPA reviewed responses to Question C2-24 

of the Steam Electric Survey regarding the number of outage days for all dry systems. Based on 

these data, EPA determined that for dry systems, there were 1.42 days of outage for 178,089 

days in operation, and for wet systems, there were 0.58 days of outage for 87,482 days in 

operation. EPA also compared the number of outage days to the number of operating days on a 

plant-level for all dry and wet systems and determined that the median number of outage days 

was zero for both the wet and dry systems. EPA concluded that the relative days of outage for a 

dry vacuum system is comparable to the relative days of outage for a wet system on an industryand plant-level basis. Therefore, there are no increased costs associated with maintenance 

outages for the dry vacuum systems, relative to wet sluicing systems. 

7.1.6.6 Storage O&M Costs: Operating Labor 

The storage operating labor costs include labor costs for ash handling system operators to 

operate the water trucks used for dust suppression and the fly ash intermediate storage systems. 

EPA calculated the storage operating labor cost using Equation 7-37. 

Storage Operating Labor Cost = Operating Labor Cost, Water Trucks + Operating Labor Cost, 

 Intermediate Storage Systems (7-37) 

Operating Labor Cost, Water Trucks

EPA calculated operating labor costs for operating water trucks for each plant by 

multiplying the operating labor rate by the number of required operator hours per day, the 

number of operating days per year, and the number of silos costed. To determine the operating 

labor rate, EPA selected the national average loaded labor rate of $18.47/hr (2009$) for industrial 

truck/tractor operators as reported by the U.S. Bureau of Labor Statistics [U.S. Bureau of Labor 

Statistics, 2010]. EPA determined operator hours per day based on an evaluation of responses to 

Question C2-44, Table C-15 (Operating Labor (Water Trucks Only) Staffing/Consumption) of 

the Steam Electric Survey. Reported operator hours per day to operate the water trucks 

[Redacted] ranged from [Redacted] hpd, with a median of [Redacted] hpd. EPA selected an 

overall unit operator hours per day as the median of the survey data set, [Redacted] hpd. EPA 

calculated the number of operating days per year as the number of calendar days generating units 

operated in 2009 on a plant-level as determined based on responses to Question A6-1, Table A-8 

(Steam Electric Units) of the survey, with a maximum of 260 days per year.47 The number of 

 

47 EPA’s analysis of maxing out the number of calendar days that generating units operated in 2009 at 260 days per 

year does not directly compare to the assumption that water trucks will only be operated on weekdays. For example, 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-22 

silos costed was determined as described in Section 7.1.5.2. As the labor rate was provided in 

2009 dollars, EPA adjusted the cost basis to 2010 dollars using the 2009 and 2010 RSMeans 

Historical Cost Indices (180.1 and 183.5, respectively) [RSMeans, 2011]. EPA calculated water 

truck operating labor costs using Equation 7-38 [ERG, 2013; See Appendix 71]. 

Operating Labor Costs, Water Trucks = Water Truck Operating Labor Rate x Water Truck 

Operator Hours per Day x Water Truck Operating Days per Year x Number of Silos (7-38) 

where: 

Water Truck Operating 

Labor Rate 

= National average loaded labor rate of $18.47/hr 

(2009$) for industrial truck/tractor operators as 

reported by the U.S. Bureau of Labor of Statistics, 

Water Truck Operator 

Hours per Day 

= The overall unit operator hours per day as the median 

of the survey data set, [Redacted], 

Water Truck Operating 

Days per Year 

= The plant-level number of calendar days generating 

units operated in 2009 as determined by the operating 

days for each generating unit at the plant (see Section 

4.2.2) with a maximum of 260 days per year, and 

Number of Silos = Number of silos, either steel or concrete, required to 

store the dry fly ash (see Section 7.1.5.2 and Equation 

7-8 or 7-12). 

Operating Labor Cost, Intermediate Storage Systems

EPA calculated operating labor costs to operate the fly ash intermediate storage systems 

for each plant by multiplying the operating labor rate by the number of required operator hours 

per year and the number of silos costed. To determine the operating labor rate, EPA evaluated 

labor rates reported in response to Question C2-44, Table C-15 (Operating Labor (All Other) 

Rate & Maintenance Labor Rate) of the Steam Electric Survey. Reported operating labor rates 

for operating fly ash silos ranged from $14.00/hr to $77.00/hr (median of $39.00/hr), while 

maintenance labor rates for maintaining fly ash silos ranged from $23.60/hr to $77.00/hr (median 

of $40.00/hr). As intermediate storage system O&M may be performed by the same personnel, 

EPA decided not to distinguish between O&M labor rates and instead selected an overall labor 

rate as the median of the entire questionnaire dataset, $40.00/hr (2010$). EPA calculated 

operating labor costs for the storage of fly ash using Equation 7-39 [ERG, 2013; See Appendix 

71]. 

Operating Labor Cost, Intermediate Storage Systems (2010$/yr) = Storage Operating Labor Rate 

 × Storage Operator Hours Per Year × Number of Silos (7-39) 

 

a plant may operate 260 days during the year, in which case EPA assumed that the water trucks were operating on 

all 260 weekdays. However, for any weekend day that the plant was operating, EPA expects that the water trucks 

weren’t really operating and therefore, EPA is likely overestimating the number of days that the water trucks 

operated for that plant. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-23 

where: 

Storage Operating 

Labor Rate 

= Storage labor rate, $40.00/hr (2010$), 

Storage Operator Hours 

Per Year 

= Number of hours a worker is needed to operate the 

intermediate storage equipment, 352 hpy, and 

Number of Silos = Number of silos, either steel or concrete, required to 

store the dry fly ash (see Section 7.1.5.2 and Equation 

7-8 or 7-12). 

7.1.6.7 Storage O&M Costs: Maintenance Labor 

Maintenance labor costs include labor costs for plant staff to maintain the intermediate 

storage systems. EPA calculated maintenance operating labor costs by multiplying the 

maintenance labor rate by the number of required maintenance hours per year and the number of 

silos costed. EPA selected a maintenance labor rate equal to the operating labor rate, as discussed 

in Section 7.1.6.6 ($40.00/hr). EPA determined maintenance hours per year based on responses 

to Question C2-44, Table C-15 (Maintenance Labor Staffing/Consumption) of the Steam Electric 

Survey. The reported maintenance hours per year for 33 silos ranged from [Redacted] to 

[Redacted] hours per year, with a median and average of 295 and 529 hours per year, 

respectively. EPA selected an overall unit maintenance hours per year as the median of the 

questionnaire data set, 295 hours per year [ERG, 2013; See Appendix 71]. EPA calculated the 

storage maintenance labor costs using Equation 7-40. 

Storage Maintenance Labor Cost (2010$/yr) = Storage Maintenance Labor Rate × Storage 

 Maintenance Hours Per Year × Number of Silos (7-40) 

where: 

Storage Maintenance 

Labor Rate 

= $40.00/hr (2010$) (see Section 7.1.6.6), 

Storage Maintenance 

Hours Per Year 

= Number of hours a worker is needed to maintain the 

intermediate storage system, 295 hpy, and 

Number of Silos = Number of silos, either steel or concrete, required to 

store the dry fly ash (see Section 7.1.5.2 and Equation 

7-8 or 7-12) 

7.1.6.8 Storage O&M Costs: Energy Cost 

Energy requirements for fly ash intermediate storage consist of the energy required to 

operate the pugmills for the costed silos. EPA used Equation 7-41 to estimate pugmill energy 

consumption (in kWh/yr) [ERG, 2013; See Appendix 71]. 

Energy Consumption, Intermediate Storage Systems (kWh/yr) = Pugmill Horsepower × 

0.745699kW/HP × Number of Pugmills × Operating Time × Operating Days (7-41)
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-24 

where: 

Pugmill Horsepower = 50 hp, based on assumption that a 150 tph pugmill 

conditioning fly ash with a density of 45 lb/ft3 requires 

50 hp, 

Number of Pugmills = Number of required pugmills (see Section 7.1.5.3 and 

Equation 7-17), 

Operating Time = Hours per day the pugmill is conditioning ash; EPA 

assumed ash conditioning is 16 hpd, and 

Operating Days = The plant-level number of calendar days generating 

units operated in 2009 as determined by the operating 

days for each generating unit (see Section 4.2.2) with a 

maximum of 260 days per year. 

To calculate energy costs, EPA multiplied the plant energy consumption by the national 

average energy cost of 4.05 cents per kWh (2009$), based on data reported by the U.S. Energy 

Information Administration in Table 8.2 of the Electric Power Annual 2009 for fossil plants in 

the United States [U.S. DOE, 2011]. As the energy cost was provided in 2009 dollars, EPA 

adjusted the cost basis to 2010 dollars using the 2009 and 2010 RSMeans Historical Cost Indices 

(180.1 and 183.5, respectively) [RSMeans, 2011]. 

Energy Cost, Intermediate Storage Systems (2010$/yr) = National Energy Cost × Energy 

Consumption, Intermediate Storage Systems × (2010 Cost Index/2009 Cost Index) (7-42) 

where: 

Energy Consumption, 

Intermediate Storage 

Systems 

= Annual energy consumed by the intermediate storage 

equipment (i.e., pugmills) in kWh/yr, 

National Energy Cost = $0.0405/kWh (2009$), 

2009 Cost Index = 180.1, and 

2010 Cost Index = 183.5. 

For the purpose of estimating non-water quality environmental impacts, EPA also 

converted energy consumption in kWh/yr to energy load in MW using Equation 7-43. 

Energy Load, Intermediate Storage Systems (MW) = Energy Consumption, Intermediate Storage 

 Systems / (Operating Time × Operating Days) × 1 MW / 1000 kW (7-43) 

where: 

Energy Consumption, = Annual energy consumed by the intermediate storage 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-25 

Intermediate Storage 

Systems 

equipment (i.e., pugmills) in kWh/yr, 

Operating Time = Hours per day the pugmill is conditioning ash; EPA 

assumed ash conditioning is 16 hpd, and 

Operating Days = The plant-level number of calendar days generating 

units operated in 2009 as determined by the operating 

days for each generating unit (see Section 4.2.2) with a 

maximum of 260 days per year. 

7.1.6.9 Storage O&M Costs: Maintenance Materials 

Maintenance materials costs include costs for routine material replacement, equipment 

replacement due to consumption or wear and tear, and fuel for the water trucks. EPA calculated 

Maintenance Materials Storage O&M Costs using Equation 7-44 

Maintenance Material Cost = Routine Maintenance Materials Cost + Water Truck Fuel 

 Cost (7-44) 

Routine Maintenance Materials Cost

EPA included costs for maintenance materials, such as routine material replacement and 

equipment replacement due to consumption or wear and tear. EPA developed Equation 7-45 to 

estimate maintenance material costs using the O&M costs reported in response to Question C2-

44, Table C-15 (Maintenance Materials) of the Steam Electric Survey. EPA calculated the ratio 

of reported maintenance material costs to the total sum of operating labor, maintenance labor, 

energy, and other O&M costs. EPA selected the median ratio of 0.20 as the maintenance 

materials cost factor [ERG, 2013; See Appendix 71]. 

Routine Maintenance Materials Cost (2010$/yr) = (Storage Maintenance Material Cost Factor × 

[Storage Operating Labor Cost + Storage Maintenance Labor Cost + 

 Storage Energy Cost]) (7-45) 

where: 

Storage Maintenance 

Material Cost Factor 

= Factor that accounts for materials cost as a percentage 

of O&M cost, 0.20, 

Storage Operating 

Labor Cost 

= Operating labor costs to operate the fly ash 

intermediate storage systems for each plant (see 

Section 7.1.6.6 and Equation 7-37), 

Storage Maintenance 

Labor Cost 

= Labor costs for plant staff to maintain the intermediate 

storage systems (see Section 7.1.6.7 and Equation 

7-40), and 

Energy Cost, 

Intermediate Storage 

Systems 

= Cost to operate the mechanical vacuum pumps (see 

Section 7.1.6.8 and Equation 7-42). 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-26 

Water Truck Fuel Costs

EPA used the Equation 7-46 to estimate the water truck fuel cost for the trucks spraying 

water around the silo and landfill area for dust control based on fuel cost data of $2.391/gal from 

the Regulatory Impact Analysis for EPA’s Proposed RCRA Regulation of Coal Combustion 

Residues (CCR) Generated by the Electric Utility Industry [ORCR, 2010]. EPA used the water 

truck operator hours per day and water truck operating days described in Section 7.1.6.6 for the 

water truck operating labor cost. EPA assumed that the water truck would travel a total of 3.6 

miles every hour based on distance to an on-site landfill, as discussed in Section 5.3.3.1. EPA 

estimated the average gas mileage, 7.5 miles/gallon, using data from a water truck vendor [ERG, 

2013; See Appendix 71]. The number of water trucks was determined using the methodology 

described in Section 7.1.9. 

Water Truck Fuel Cost (2010$/yr) = ([Water Truck Operator Hours Per Day × Water Truck 

Operating Days × Water Truck Distance Per Hour / Water Truck Gas Mileage × Water Truck 

 Fuel Cost] × Total Number of Additional Water Trucks) (7-46) 

where: 

Water Truck Operator 

Hours Per Day 

= [Redacted] (see Section 7.1.6.6), 

Water Truck Operating 

Days 

= Number of calendar days generating units operated in 

2009 on a plant level with a maximum of 260 days per 

year (see Section 7.1.6.6), 

Water Truck Distance 

Per Hour 

= 3.6 miles/hour, 

Water Truck Gas 

Mileage 

= 7.5 miles/gal, 

Water Truck Fuel Cost = $2.391/gal, and 

Total Number of 

Additional Water 

Trucks 

= Number of additional water trucks required for dust 

suppression at the plant (excluding those already 

onsite) for the additional ash handled dry after the 

conversion (see Section 7.1.9 and Equation 7-53). 

7.1.7 Fly Ash Disposal Cost

EPA determined the cost of dry fly ash disposal based on the amount of fly ash converted 

from wet handling to dry handling. Because EPA has costed the ash to be conditioned in the 

pugmills prior to disposal, EPA determined the final moisture content of the fly ash based on 

responses to Question C2-25, Table C-6 (Percent Moisture of the Fly Ash Entering the 

Destination) of the Steam Electric Survey. The average moisture content reported by plants that 

transport fly ash by truck to a landfill was 13 percent. Based on this information, EPA calculated 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-27 

the amount of fly ash to be disposed, accounting for ash conditioning, using Equation.7-47 

[ERG, 2013; See Appendix 72]. 

Conditioned Dry Fly Ash for Disposal (tons/yr) = [ ∑(Unit Wet Fly Ash Generation Rate × Unit 

 Operating Days) ] / (1 - Pugmill Moisture Content) (7-47) 

where: 

Unit Wet Fly Ash 

Generation Rate 

= Amount of wet fly ash produced by the generating unit 

in tpd (see Section 4.2.2), 

Unit Operating Days = Number of days each generating unit operated in 2009 

(see Section 4.2.2), and 

Pugmill Moisture 

Content 

= 13 percent. 

EPA also calculated conditioned fly ash density using Equation 7-48. 

Conditioned Dry Fly Ash Density = [(Pugmill Moisture Content) × (Density of Water)] + 

 [(Density of Fly Ash) × (1 – Pugmill Moisture Content)] = 47.3 lb/ft3 (7-48) 

where: 

Pugmill Moisture 

Content 

= 13 percent, 

Density of Water = 62.4 lb/ft3, and 

Density of Fly Ash = 45 lb/ft3 (dry weight). 

The conditioned fly ash density is used to calculate the amount of wet fly ash plants will 

need to transport and dispose of in a landfill. Sections 5.3 and 5.4 discuss costs for the 

transportation and disposal of the dry fly ash generated by converting wet fly ash handling 

systems to dry vacuum fly ash handling systems. 

7.1.8 Impoundment Operation Costs

Section 5.5 discusses cost savings associated with ceasing operation of combustion 

residual surface impoundments. 

7.1.9 Recurring Costs

EPA calculated 10-year recurring costs associated with operating the water trucks 

involved with dust control around the fly ash silo and landfills. EPA calculated the total 10-year 

recurring costs by determining the number of water trucks required for each plant based on ash 

tonnage, the cost of the water trucks, and the expected life of water trucks. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-28 

EPA determined the number of water trucks required at each plant based on the wet and 

dry fly ash tonnage generated at the plant. Because some plants operate both wet and dry 

handling systems, EPA used the dry fly ash tonnage at the plant to estimate the number of water 

trucks the plant already operates. The unit fly ash dry generation rate (in tpd) and dry conveying 

days (in dpy) were determined for each generating unit at each plant from the responses to 

Question C2-1, Table C-2 of the Steam Electric Survey. 

Plant-Level Dry Fly Ash (tons) = ∑ (Unit Dry Fly Ash Generation Rate x Dry Conveying 

 Days) (7-49) 

where: 

Unit Dry Fly Ash 

Generation Rate 

= The amount of dry fly ash produced by the generating 

unit in tpd (see Section 4.2.2), and 

Dry Conveying Days = The number of days dry fly ash was conveyed at each 

generating unit (see Section 4.2.2). 

EPA determined the number of water trucks the plant already operates based on the plantlevel dry fly ash (in tons, from Equation 7-49) using the step function shown in Equation 7-50, 

found in ORCR’s Regulatory Impact Analysis for EPA’s Proposed RCRA Regulation of Coal 

Combustion Residues (CCR) Generated by the Electric Utility Industry [ORCR, 2010]: 

 Number of Water Trucks at Plant = (7-50) 

 For Plant-Level Dry Fly Ash (tons) ≤ 391,000: 

Number of Water Trucks at Plant = One Truck 

 For Plant-Level Dry Fly Ash (tons) > 391,000 and ≤ 1,173,000: 

Number of Water Trucks at Plant = Two Trucks 

 For Plant-Level Dry Fly Ash (tons) > 1,173,000 and ≤ 1,955,000: 

Number of Water Trucks at Plant = Three Trucks 

 For Plant-Level Dry Fly Ash (tons) > 1,955,000: 

Number of Water Trucks at Plant = Four Trucks 

To determine the number of additional water trucks required for dust suppression, EPA 

calculated the total number of water trucks needed by the plant for all fly ash generated, wet and 

dry. EPA calculated the total fly ash tonnage using Equation 7-51 and determined the number of 

water trucks needed using the step function presented in Equation 7-52, which is similar to 

Equation 7-50. 

Plant-Level Total Fly Ash (tons) = Plant Level Dry Fly Ash (tons) + [Unit Wet Fly Ash 

 Generation Rate x Wet Conveying Days]) (7-51) 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-29 

where: 

Plant-Level Dry Fly 

Ash 

= The total dry fly ash tonnage (in a dry weight basis) 

generated at the plant on an annual basis (see Equation 

7-49), 

Unit Wet Fly Ash 

Generation Rate 

= The amount of wet fly ash produced by the generating 

unit in tpd (see Section 4.2.2), and 

Wet Conveying Days = The number of days wet fly ash is conveyed at each 

generating unit (see Section 4.2.2). 

 Number of Water Trucks Needed = (7-52) 

 For Plant-Level Total Fly Ash (tons) ≤ 391,000: 

Number of Water Trucks at Plant = One Truck 

 For Plant-Level Total Fly Ash (tons) > 391,000 and ≤ 1,173,000: 

Number of Water Trucks at Plant = Two Trucks 

 For Plant-Level Total Fly Ash (tons) > 1,173,000 and ≤ 1,955,000: 

Number of Water Trucks at Plant = Three Trucks 

 For Plant-Level Total Fly Ash (tons) > 1,955,000: 

Number of Water Trucks at Plant = Four Trucks 

After determining the number of trucks needed for all fly ash (wet and dry) generated at 

the plant, EPA subtracted the total number of water trucks the plant already operates from the 

total number of water trucks needed. EPA used Equations 7-53 and 7-54 to calculate the total 

recurring costs for water trucks at the plant-level. 

Total Number of Additional Water Trucks = Number of Water Trucks Needed – Number of 

 Water Trucks at Plant (7-53) 

Recurring Cost (2010$) = Total Number of Additional Water Trucks × Cost of Water 

 Truck (7-54) 

where: 

Cost of Water Truck = $104,500 (in 2010$). 

From vendor contact information, EPA determined that the average life of a water truck 

used for dust suppression is 10 years. Therefore, the recurring costs for the water trucks at the 

plant are estimated to be the total water truck costs, every 10 years. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-30 

7.1.10 Fly Ash Outage Costs

EPA considered the impact of a plant outage required to install the dry fly ash handling 

system. Based on an evaluation of vendor and survey information, EPA determined that 

connecting the fly ash handling system installations can be completed during regularly scheduled 

outages. The entire conveyance and storage systems can be constructed and installed prior to a 

scheduled outage, and then the necessary tie-in can occur during a regularly scheduled outage. 

Therefore, there are no costs for plant outages during installation of the dry fly ash handling 

system. 

7.1.11 Results and Summary of Costs

As described in Section 2.1.4, EPA’s cost model generated plant-level compliance costs 

for converting wet fly ash handling systems to dry vacuum systems. The cost output generated 

by the model includes a breakout of specific capital and O&M cost elements, including 

equipment costs, installation costs, operating labor, maintenance labor, and energy costs. The 

output also includes costs for the common cost elements. Chapter 5 discusses these common cost 

elements that include transportation and disposal of combustion residual. A list of the plant-level 

costs for the dry fly ash handling technology option is included in the appendix. 

7.2 VACTOR TRUCK COLLECTION

For oil-fired units that operate fewer than 100 days per year, EPA used a different 

approach for estimating capital and O&M costs because of the small amount of fly ash generated 

from these units. This approach included piping the fly ash away from the primary particulate 

collection system using a vactor truck operated by a third-party contractor. 

7.2.1 Technology Description

For oil-fired generating units that operate fewer than 100 days per year, EPA assumed a 

conversion identical to that reported by an oil-fired power plant in response to the Steam Electric 

Survey. This conversion consisted of installing a new piping system from the existing fly ash 

collection hoppers, underneath the electrostatic precipitator (ESP) or fabric filter (i.e., baghouse), 

to a roll-off vacuum container. During operation, ash accumulates in the existing fly ash 

collection hoppers. On an as needed basis (i.e., when the collection hoppers begin to reach 

capacity), a contract vendor uses a vactor truck vacuum pump to pull the fly ash stored in the 

collection hoppers through the new piping system into the roll-off vacuum container. The vendor 

then transports the roll-off vacuum container to an off-site landfill for ash disposal. 

7.2.2 Population Costed

[Redacted] oil-fired units at [Redacted] plants reported generating fly ash in 2009. Of 

these, [Redacted] wet sluiced their fly ash less than 100 days out of the year, discharged the fly 

ash sluice to surface water, and reported no plans to end or change operations. EPA estimated 

costs for converting these [Redacted] generating units from wet fly ash handling systems to a dry 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-31 

vactor truck system. 48 The remaining oil-fired units, those wet sluicing their ash more than 100 

days out of the year, are included in the population presented in Section 7.1.2. 

7.2.3 Input Table

Oil-fired units operating less than 100 days per year are included in the “Fly Ash Input 

Table” described in Section 7.1.4. The oil-fired units will be flagged in a separate field identified 

as ”Oil_fired” and the operating days for each generating unit are listed in the ”Operating Days” 

field. All other fields of data contained in the “Fly Ash Input Table” will be completed for the 

oil-fired units. A copy of the “Fly Ash Input Table” is located in the appendix. 

7.2.4 Capital Cost Methodology

EPA calculated total capital costs for each plant as the sum of the purchase and 

installation of the new pipe to convey dry fly ash from the fly ash collection hoppers to the rolloff vacuum container. EPA used Equation 7-55 to calculate the total capital cost. 

 Total Capital Cost = Vactor Conveyance Equipment Cost + Vactor Engineering Costs (7-55) 

7.2.4.1 Total Capital Cost: Vactor Conveyance Equipment 

EPA developed the conveyance capital cost equations based on total capital cost data 

provided in response to the Steam Electric Survey by one oil-fired power plant that converted 

from wet sluicing to a vactor truck system. EPA used Equation 7-56 to estimate conveyance 

costs for oil-fired units operating less than 100 days per year. 

Unit Vactor Conveyance Cost (2010$) = ($13,900/0.53 tpd) × (Unit Wet Fly Ash Generation 

 Rate) (7-56) 

where: 

Unit Wet Fly Ash 

Generation Rate 

= The amount of wet fly ash produced by the generating 

unit in tpd (see Section 4.2.2). 

EPA calculated plant-level vactor conveyance costs by summing the unit-level costs at 

each plant, according to Equation 7-57. 

 Plant Vactor Conveyance Cost (2010$) = ∑ Unit Vactor Conveyance Cost (7-57) 

7.2.4.2 Total Capital Cost: Vactor Engineering Costs 

Engineering costs include costs for process design and general engineering, cost 

engineering, consulting fees, supervision, and inspection. EPA assumed that the engineering 

costs incurred for oil-fired vactor truck conversions include the owner’s overhead engineering 

 

48 No plants are evaluated for this population when the group of plants excluding oil-fired unts and units with a 

capacity of 50 MW or less is evaluated. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-32 

costs. EPA determined engineering overhead costs by multiplying the purchased and installation 

equipment costs by a factor for conveyance equipment and silo equipment. EPA determined 

these factors based on responses to Questions C2-34 (conveyance costs) in the Steam Electric 

Survey. To determine the Conveyance Overhead Factor, EPA calculated the percentage of 

engineering overhead costs to the total costs provided in the survey responses using Equation 

7-58. 

Percentage = Engineering Overhead Costs / (Total Capital Conveyance Costs – 

 Engineering Overhead Cost) (7-58) 

where: 

Vactor Engineering 

Overhead Costs 

= Engineering overhead costs for vactor conveyance 

equipment provided in survey Question C2-34, and 

Total Capital Vactor 

Conveyance Costs 

= Capital costs for vactor conveyance equipment 

provided in survey Question C2-34. 

EPA calculated the median of all the percentages, 0.02454, and used that as the 

Conveyance Overhead Factor. 

EPA used Equation 7-59 to estimate engineering costs. 

Vactor Engineering Costs (2010$) = Plant Conveyance Capital Cost × Conveyance Overhead 

 Factor (7-59) 

where: 

Conveyance Overhead 

Factor 

= Factor that accounts for engineering overhead costs as 

a percentage of purchase and installation costs for the 

conveyance portion of the system, 0.02454, and 

Plant Conveyance 

Capital Cost 

= Cost for purchasing vactor conveyance equipment (see 

Section 7.2.4.1 and Equation 7-57). 

7.2.5 O&M Cost Methodology

EPA calculated total O&M costs for each plant as the sum of all costs related to operating 

and maintaining the conveyance and storage equipment required to convert wet fly ash handling 

systems to dry fly ash handling systems. EPA used Equation 7-60 to calculate the total O&M 

costs for oil-fired units operating less than 100 days per year. 

Total O&M Cost, Oil Units < 100 Days = Plant Vactor Conveyance O&M Cost + Plant Vactor 

 Storage O&M Cost (7-60) 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-33 

where: 

Plant Vactor 

Conveyance O&M Cost 

= Plant-level vactor conveyance O&M costs (see Section 

7.2.5.1), and 

Plant Vactor Storage 

O&M Cost 

= Plant-level vactor storage O&M costs (see Section 

7.2.5.2). 

7.2.5.1 Total O&M Costs: Vactor Conveyance O&M Cost 

Conveyance O&M costs consist of the contract vendor’s fee for annual collection of the 

dry fly ash into the roll-off vacuum container. EPA developed the O&M cost equations based on 

O&M cost data provided in response to the Steam Electric Survey by one oil-fired power plant 

that converted from wet sluicing to a vactor truck system. 

Unit Conveyance O&M Cost (2010$/yr) = ($75,105/0.53 tpd × 30 days) × Unit Wet Fly Ash 

 Generation Rate × Unit Operating Days (7-61) 

where: 

Unit Wet Fly Ash 

Generation Rate 

= The amount of wet fly ash produced by the generating 

unit in tpd (see Section 4.2.2), and 

Unit Operating Days = Number of days each generating unit operated in 2009 

(see Section 4.2.2). 

EPA calculated plant-level vactor conveyance O&M costs by summing the unit-level 

costs at each plant, according to Equation 7-62. 

 Plant Vactor Conveyance O&M Cost (2010$/yr) = ∑ Unit Conveyance O&M Cost (7-62) 

All other plant O&M costs associated with the dry fly ash conveyance are assumed to be 

captured by the vendor’s fee, negligible, or not applicable (i.e., operating labor, maintenance 

labor, maintenance materials, chemical purchase, and energy). 

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

Storage O&M costs consist of the rental fee for the roll-off vacuum container. EPA 

developed a roll-off vacuum container rental rate of $300 per week based on O&M cost data 

provided in response to the Steam Electric Survey by one oil-fired power plant that converted 

from wet sluicing to a storage vactor truck system. Also based on survey data, EPA assumed that 

each day of generating unit operation per year corresponds to one week of roll-off vacuum 

container rental, subject to a maximum of a full-year rental. The number of unit operating days 

per year was determined based on responses to Question A6-1, Table A-8 (Steam Electric Units) 

of the Steam Electric Survey. 

For Unit Operating Days ≤ 52 dpy, EPA used Equation 7-63 to calculate the storage 

O&M cost. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-34 

 Unit Vactor Storage O&M Cost (2010$) = $300 × Unit Operating Days (7-63) 

where: 

Unit Operating Days = Number of days each generating unit operated per year 

(see Section 4.2.2). 

For Unit Operating Days > 52 dpy, EPA used Equation 7-64 to calculate the storage 

O&M cost. 

 Unit Vactor Storage O&M Cost (2010$) = $300 × 52 (7-64) 

EPA calculated plant-level vactor storage O&M costs by summing the unit-level costs at 

each plant, according to Equation 7-65. 

 Plant Vactor Storage O&M Cost (2010$/yr) = ∑ Unit Vactor Storage O&M Cost (7-65) 

All other plant O&M costs associated with the dry fly ash storage are assumed to be 

captured by the rental fee, negligible, or not applicable (i.e., operating labor, maintenance labor, 

maintenance materials, chemical purchase, and energy). 

7.2.6 Fly Ash Disposal Cost

EPA estimated disposal capital costs for the dry fly ash generated by converting wet fly 

ash handling systems to a dry vactor truck collection system using the same methodology as that 

used for converting wet fly ash handling systems at coal-fired power plants as described in 

Section 7.1.7. However, because oil ash is never moisture conditioned with a pugmill unloader, 

EPA calculated the total amount of fly ash associated with oil units using Equation 7-66. 

Plant Wet Fly Ash Generation Rate (tons/yr) = ∑(Unit Wet Fly Ash Generation Rate × Wet 

 Conveying Days) (7-66) 

where: 

Unit Wet Fly Ash 

Generation Rate 

= Amount of wet fly ash produced by each generating 

unit in tpd, (see Section 4.2.2), and 

Wet Conveying Days = The number of days wet fly ash is conveyed at each 

generating unit (see Section 4.2.2). 

Sections 5.3 and 5.4 discuss costs for the transportation and disposal of dry fly ash 

generated by converting wet fly ash handling systems to dry vactor truck collection systems. 

7.2.7 Impoundment Operation Costs

Section 5.5 discusses cost savings associated with ceasing operation of combustion 

residual surface impoundments. 
Chapter 7– Fly Ash Transport Water Cost Methodology 

7-35 

7.2.8 Fly Ash Outage Costs

EPA considered the impact of a plant outage required to install the dry vactor truck 

collection system. Because these systems are only installed on units that operated less than 100 

days per year, EPA determined that piping system can be constructed and installed without 

interference to unit operations, and then the necessary tie-in can occur during a period of time 

when the unit is not operating. Therefore, there are no costs for plant outages during installation 

of the dry vactor truck collection system. 

7.2.9 Results and Summary of Costs

As described in Section 2.1.4, EPA’s cost model generated plant-level compliance costs 

for converting wet fly ash handling systems to dry vacuum systems. The cost output generated 

by the model includes a breakout of specific capital and O&M cost elements, including 

equipment costs, installation costs, operating labor, maintenance labor, and energy costs. The 

output also includes costs for the common cost elements. Chapter 5 discusses these common cost 

elements that include transportation and disposal of combustion residual.. A list of the plant-level 

costs for the dry fly ash handling technology option is included in the appendix. 

7.3 REFERENCES

1. Eastern Research Group, Inc (ERG). 2013. Supplemental Costs and Loadings 

Documentation. (19 April). DCN SE01825. 

2. RSMeans. 2011. Building Construction Cost Data, 69th Edition. (January). DCN 

SE02952.

3. U.S. Department of Energy (DOE). Energy Information Administration (EIA). Electric 

Power Annual 2009. Washington, DC. (4 January) DCN SE02023. 

4. U.S. Department of Labor, Bureau of Labor Statistics. 2010. May 2009 National 

Occupational Employment and Waste Estimates, United States. Washington, D.C. (May). 

DCN SE02953. 

5. U.S. EPA, Office of Resource Conservation and Recovery (ORCR). 2010. Regulatory 

Impact Analysis for EPA’s Proposed RCRA Regulation of Coal Combustion Residues 

(CCR) Generated by the Electric Utility Industry. Washington, D.C. (30 April). DCN 

SE02969. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-1 

CHAPTER 8 

BOTTOM ASH TRANSPORT WATER COST METHODOLOGY 

EPA evaluated the following two technology options for bottom ash transport water: 

 Mechanical drag system; and 

 Remote mechanical drag system. 

EPA estimated capital, operating and maintenance (O&M), three-year recurring, fiveyear recurring, and 10-year recurring costs associated with converting bottom ash handling 

systems from wet sluicing to a mechanical drag system or a remote mechanical drag system for 

generating units generating bottom ash. EPA selected these two systems as the basis for the dry 

and closed-loop recycle systems, respectively, based on system operation data from vendors and 

operation data from the Questionnaire for the Steam Electric Power Generating Effluent 

Guidelines (Steam Electric Survey). The compliance costs estimated by EPA include the 

conveyance system conversion, the additional required bottom ash storage, the transport and 

disposal of the bottom ash, and impoundment operation costs associated with the change in 

bottom ash handling. 

EPA estimated costs for both the mechanical drag system and remote mechanical drag 

system. The cost estimates reflect fully erected and commissioned systems, including equipment, 

controls, foundations, and field labor. EPA selected the technology associated with the lowest 

estimated annualized cost (at a plant level) for the combined system conversion, transport and 

disposal, and impoundment operation costs as the cost basis for the plant. All costs were 

estimated in 2010 dollars. 

8.1 MECHANICAL DRAG SYSTEM 

8.1.1 Technology Description

Plants operating wet bottom ash handling systems hydraulically convey (i.e., sluice with 

water) bottom ash from the grinders to either an ash impoundment or dewatering bin. In such a 

system, ash from the grinders is fed onto a conveying line where it is diluted into slurry and pumped 

to the ash impoundment or dewatering storage bins. 

Mechanical drag system (MDS) consists of a water bath trough located at the throat of 

the bottom of the boiler with a chain conveyor (a pair of chains with crossbars attached at regular 

intervals) that slowly moves along the trough, pushing the bottom ash solids to the end of the 

boiler. At the end of the boiler, the bottom ash drops onto an inclined conveyor that dewaters the 

solids and moves them out of the boiler to a nearby storage area. 

EPA based the design and cost for installation of an MDS or remote MDS on information 

collected from vendors, as well as information collected from the industry through site visits and 

the Steam Electric Survey. The MDS costs consist of a complete replacement system, as shown 

in Figure 8-1, from the boiler throat to and including a single semi-dry bottom ash storage silo 

located within 200 feet of the boiler [ERG, 2013; See Appendix 73]. This complete replacement 

system includes the water bath trough underneath the boiler and chain conveyor to remove the 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-2 

bottom ash solids, along with the single semi-dry bottom ash storage silo. The complete 

replacement also includes the demolition of the previously existing bottom of the boiler and wet 

sluicing system. 

Graphic re-printed with permission from United Conveyor Corporation [UCC, 2009]. 

Figure 8-1. Mechanical Drag System 

8.1.2 Population Costed

EPA evaluated MDS costs for each plant requiring conversion from wet bottom ash 

handling to dry or closed-loop bottom ash handling. Based on information from the Steam 

Electric Survey, EPA identified 253 plants, corresponding to 634 units, discharging bottom ash 

transport water, without any plans to convert to dry handling or having the capacity to handle all 

the bottom ash dry, from coal- and oil-fired units. 49 EPA identified the units planning to convert 

to dry handling or closed-loop recycle systems from responses in the Steam Electric Survey 

stating a planned conversion, the projected date for the conversion, and the end use of the wet 

sluicing system. Additionally, EPA identified plants that have announced plans to retire 

generating units or convert to dry or closed-loop recycle bottom ash handling prior to December 

31, 2014, as described in Section 4.4.1. Finally, EPA identified units with enough capacity to 

handle all bottom ash with a dry handling system from responses in the Steam Electric Survey 

stating that no modifications to the existing bottom ash handling system would be required to 

handle all of the bottom ash dry. There are no conversion costs for generating units that are 

already planned to be converted to dry or closed-loop recycle bottom ash handling systems 

because the plant will retire/convert the system without the implementation of the Steam Electric 

effluent limitations and guidelines (ELGs). Additionally, there are no conversion costs for 

generating units that have both wet and dry bottom ash handling systems where the dry system is 

capable of handling all of the bottom ash because the plant would be capable of operating 

without the wet sluicing system. EPA estimated compliance costs for these 634 generating units 

to convert wet sluicing systems to an MDS. 

 

49 When the group of plants excluding oil-fired unts and units with a capacity of 50 MW or less is evaluated the 

population of plants discharing bottom ash transport includes 240 plants, corresponding to 581 units. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-3 

8.1.3 Input Table

As discussed in Section 4.2.3, EPA used survey data to identify which plants discharge or 

have the potential to discharge bottom ash transport water. These plants all incur some level of 

cost for converting to dry bottom ash handling. The “Bottom Ash Input Table” holds all the input 

data needed to calculate the compliance costs for these plants. The “Bottom Ash Input Table” 

contains the following fields: 

 Plant_id: Survey Plant ID. 

 Seunit_id: Survey Steam Electric (SE) Unit ID.

 No_cost: Flag indicating that the unit will not incur costs for its bottom ash system.

 Cost: Flag indicating that the unit will incur costs for its bottom ash system. 

 Boiler_type: Type of boiler as indicated in Table C-18 (i.e., wet-bottom, drybottom). 

 Wet_tpd: The amount of bottom ash handled wet in tons per day (dry weight basis) 

from Table C-18. For units that handled bottom ash wet in 2009 and did not report 

this value, EPA calculated a value by multiplying the tons of coal burned in the unit 

in 2009, as reported in Table A-11, by two percent (assuming 10 percent ash content 

for the coal and 20 percent of ash generated is bottom ash). EPA then divided this 

value by the number of days the unit operated in 2009, as reported in Table A-8, to 

estimate the amount of bottom ash handled wet in tons per day (tpd). 

 Unit_type: Type of unit as indicated in Table A-8 (i.e., baseload, cycling, 

intermediate, or peaking). 

 Produce_hpd: Estimate of the number of hours per day (hpd) the unit operates. EPA 

assumed units identified as baseload, intermediate, or cycling in Table A-8 operate 24 

hpd and peaking units, as identified in Table A-8, operate 12 hpd. 

 Convey_hpd: Estimate of the number of hours per day the unit conveys bottom ash. 

EPA assumed units identified as baseload, intermediate, or cycling in Table A-8 

convey bottom ash six hpd and units identified as peaking convey bottom ash three 

hpd. For MDSs, EPA assumed bottom ash is conveyed continuously during operation, 

therefore, convey_hpd equals produce_hpd. 

 Operating_days: Number of days the unit operated in 2009. EPA populated this 

value from the days of operation in Table A-8. If days of operation were not reported, 

EPA assumed the operating days to be equal to the reported days per year under in 

Table C-18. 

 MW: The unit capacity (in megawatts (MW)) from Table A-8. 

 FlowRate_GPD: Bottom ash sluice flow rate from Table C-19. 

 Retired?: Flag indicating that the plant has identified that it will be retiring on or 

before 12/31/2014. 

The discussion of the “Bottom Ash Input Table” in Section 4.2.3 provides more detail on 

the methodology used to determine the appropriate level of costing for each steam electric unit. 

A copy of the “Bottom Ash Input Table” is included in the appendix. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-4 

8.1.4 Capital Cost Methodology

Capital costs for the MDS includes fully erected and commissioned systems, including 

equipment, controls, foundations, and field labor (e.g., installed equipment costs). The capital 

costs for the MDS do not include the costs for buildings or land because EPA assumed zero land 

costs based on data from site visits and discussions with plants who have already converted from 

wet bottom ash handling to dry bottom ash handling. EPA assumes that other capital costs 

associated with buildings, site preparation, engineering and construction are included in the costs 

provided by the vendors. 

EPA calculated capital costs for each plant as the sum of purchased and installed 

conveyance equipment costs for the MDS (including intermediate storage), plant-level 

engineering costs, and bottom ash disposal costs, as described by Equation 8-1. 

MDS Capital Cost (2010$) = Conveyance & Intermediate Storage Equipment Costs + Plant 

 Overhead Engineering Costs + Bottom Ash Disposal Costs (8-1) 

8.1.4.1 MDS Purchased Equipment Cost: Conveyance Equipment 

EPA estimated unit-level capital costs for purchase and installation of equipment to 

convert a wet sluicing system to a MDS. EPA then summed these unit-level costs to calculate 

plant-level conveyance and intermediate storage capital costs. EPA made the following 

assumptions based on information obtained from vendors and Steam Electric Survey responses: 

EPA costed the demolition of the existing bottom of the boiler and wet bottom ash 

sluicing system. 

EPA costed the MDS to remove bottom ash from the boiler to a semi-dry silo within 200 

feet of the boiler. EPA estimated costs for both the conveyance system and the semi-dry bottom 

ash storage silo. 

For units with a capacity of less than or equal to 500 MW, EPA costed the system for two 

50 horsepower (hp) motors; for units with greater than 500 MW capacity, EPA costed two 75 hp 

motors. 

The system design does not include operation as a closed-loop system (i.e., the water 

leaving the system with the bottom ash does not need to be collected, cooled, and returned to the 

system), thereby eliminating the need for a heat exchanger. 

Clyde Bergemann Power Group (CBPG, formerly Delta Ducon) provided cost data for 

the purchase and installation of equipment required for the conversion, from which EPA 

developed Equation 8-2 to estimate the MDS conveyance equipment cost. Because all installed 

equipment costs were provided in 2010 dollars, no adjustment of the cost basis was required. 

 MDS Conveyance Unit Capital Cost (2010$) = 20,083 × Capacity + 3,000,000 (8-2) 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-5 

where: 

Capacity = Generating unit capacity (see Section 4.2.3). 

EPA calculated the plant-level MDS conveyance capital cost by summing the unit-level 

costs at each plant, according to Equation 8-3. 

 Plant MDS Conveyance Capital Cost (2010$) = ∑ MDS Conveyance Unit Capital Cost (8-3) 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A74) for more 

detailed information on the development of Equations 8-2 and 8-3. 

8.1.4.2 MDS Engineering Cost 

Engineering costs include process design and general engineering, engineering consulting 

fees, supervision, and inspection. EPA determined engineering overhead costs by multiplying the 

purchased and installation equipment costs by a factor for conveyance and intermediate storage: 

Bottom Ash Engineering Factor. Because the MDS capital costs (i.e., Plant MDS Conveyance 

Capital Cost) include both conveyance and intermediate storage costs, EPA combined the factors 

for conveyance and intermediate storage. To determine the MDS Engineering Overhead Factor, 

EPA calculated the ratio of engineering overhead costs to the total costs provided in the Steam 

Electric Survey using Equation 8-4 [ERG, 2013; See Appendix 74]. 

Ratio = MDS Engineering Overhead Costs / (MDS Total Capital Costs – MDS Engineering 

 Overhead Cost) (8-4) 

EPA calculated the median ratio for all generating units that provided MDS costs in 

response to the Steam Electric Survey, 0.01765, and used that as the MDS Engineering Overhead 

Factor. 

EPA used Equation 8-5 to estimate engineering overhead costs. 

MDS Unit Engineering Cost (2010$) = MDS Conveyance Unit Capital Cost × MDS Engineering 

 Overhead Factor (8-5) 

where: 

MDS Conveyance Unit 

Capital Cost 

= Capital costs for purchase and installation of equipment 

to convert a wet sluicing system to an MDS (see 

Section 8.1.4.1 and Equation 8-2), and 

MDS Engineering 

Overhead Factor 

= EPA determined this factor based on responses to 

Questions C3-39 (conveyance costs) and C3-47 

(intermediate storage costs) in the Steam Electric 

Survey, 0.01765. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-6 

EPA calculated the plant-level MDS engineering cost by summing the unit-level costs at 

each plant, according to Equation 8-6. 

 Plant MDS Engineering Cost (2010$) = ∑ MDS Unit Engineering Cost (8-6)

8.1.5 O&M Cost Methodology

O&M costs consist of all costs related to operating and maintaining the conveyance and 

storage equipment associated with the MDS. Since the MDS does not require the operation of the 

existing wet sluicing equipment, EPA subtracted the estimated O&M costs associated with 

operating wet sluicing equipment from the O&M costs associated with operating the MDS. No 

chemical costs are associated with the MDS or wet sluicing system. EPA used Equation 8-7 to 

calculate total MDS O&M costs. 

MDS O&M Costs = MDS Conveyance O&M Costs + MDS Storage O&M Costs – Wet Sluicing 

 O&M Costs (8-7) 

EPA calculated the O&M costs associated with conveyance, storage, and wet sluicing 

using Equations 8-8, 8-9, 8-10. 

MDS Conveyance O&M Costs = MDS Conveyance Operating Labor Cost + MDS Conveyance 

Maintenance Labor Cost + MDS Conveyance Maintenance Materials Cost + MDS Conveyance 

 Energy Cost (8-8) 

MDS Storage O&M Costs = MDS Storage Operating Labor Cost + MDS Storage Maintenance 

 Labor Cost + MDS Storage Maintenance Materials Cost + MDS Storage Energy Cost (8-9) 

Wet Sluicing O&M Costs = Wet Sluicing Operating Labor Cost + Wet Sluicing Maintenance 

 Labor Cost + Wet Sluicing Maintenance Materials Cost + Wet Sluicing Energy Cost (8-10) 

All variables are defined in the following sections. 

8.1.5.1 MDS Conveyance O&M Costs: Operating Labor 

MDS conveyance operating labor cost includes labor costs for ash handling system 

operators to operate the conveyance systems (i.e., the MDS). EPA estimated unit-level operating 

labor costs and then summed these unit-level costs to calculate plant-level operating labor costs. 

EPA calculated operating labor costs for each unit by multiplying the operating labor rate by the 

number of required operator hours per year. 

EPA assumed that the same operator could be working on either the fly ash conveyance 

system or the bottom ash conveyance system; therefore, EPA used the overall fly ash operating 

labor rate, $46.36/hr (2010$), for both fly ash and bottom ash conveyance operating and 

maintenance costs. See Section 7.1.6.1 for details on how this rate was determined. EPA 

determined operator hours per day based on responses to Question C3-41, Table C-28 (Operating 

Labor Staffing/Consumption) of the Steam Electric Survey. The reported operator hours per day 

for [Redacted] units operating mechanical drag systems ranged from [Redacted] to [Redacted] 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-7 

hours per day, with a median and average of [Redacted] and [Redacted] hours per day, 

respectively. EPA selected an overall unit operator hours per day as the median of the survey 

data set, [Redacted] hours per day [ERG, 2013 See Appendix 75]. 

EPA calculated operator hours per year using Equation 8-11. 

MDS Unit Operator Hours per Year (hpy) = MDS Operator Hours per Day x Operating 

 Days (8-11) 

where: 

MDS Operator Hours 

per Day 

= Number of hours per day the MDS system requires an 

operator, [Redacted] hpd, and 

Operating Days = Number of days per year the generating unit operated 

in 2009 (see Section 4.2.3). 

EPA calculated the MDS Conveyance Unit Operating Labor Cost using Equation 8-12. 

MDS Conveyance Unit Operating Labor Cost (2010$/yr) = Operating Labor Rate × Unit MDS 

 Operator Hours Per Day × Operating Days (8-12) 

where: 

Operating Labor Rate = $46.36/hr (2010$), 

MDS Operator Hours 

Per Day 

= [Redacted] hpd, and 

Operating Days = Number of days per year the generating unit operated 

in 2009 (see Section 4.2.3). 

EPA estimated the total MDS Conveyance Operating Labor Costs at the plant by 

summing the labor costs for all MDS conveyance units at the plant using Equation 8-13. 

Plant MDS Conveyance Operating Labor Cost (2010$/yr) = ∑ MDS Conveyance Unit Operating 

 Labor Costs (8-13) 

8.1.5.2 MDS Conveyance O&M Costs: Maintenance Labor 

The maintenance labor costs include labor costs for plant staff to maintain the MDS 

conveyance systems. EPA estimated unit-level maintenance labor costs and then summed these 

unit-level costs to calculate plant-level maintenance labor costs. EPA calculated maintenance 

labor costs for each unit by multiplying the maintenance labor rate by the number of required 

maintenance hours per year. 

Because bottom ash system O&M may be performed by the same personnel, EPA 

selected an overall operating and maintenance labor rate, as discussed in Section 8.1.5.1 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-8 

($46.36/hr). EPA calculated unit maintenance hours per year using responses to Question C3-41, 

Table C-28 (Maintenance Labor Staffing/Consumption) of the Steam Electric Survey. Reported 

maintenance hours per year for [Redacted] generating units operating MDSs ranged from 

[Redacted] to [Redacted] hours per year for ash handling system maintenance, with a median and 

average of [Redacted] and [Redacted] hours per year, respectively. EPA selected an overall unit 

maintenance hours per year as the median of the Steam Electric Survey data set, [Redacted] 

hours per year [ERG, 2013; See Appendix 75]. 

MDS Conveyance Unit Maintenance Labor Cost (2010$/yr) = Maintenance Labor Rate × MDS 

 Maintenance Hours Per Year (8-14) 

where: 

Maintenance Labor 

Rate 

= $46.36/hr (2010$), and 

MDS Maintenance 

Hours Per Year 

= [Redacted] hpy. 

EPA estimated the total MDS Conveyance Maintenance Labor Costs at the plant by 

summing the labor costs for all MDS conveyance units at the plant using Equation 8-15. 

Plant MDS Conveyance Maintenance Labor Cost (2010$/yr) = ∑ MDS Conveyance Unit 

 Maintenance Labor Cost (8-15)

8.1.5.3 MDS Conveyance O&M Costs: Energy Cost 

MDS conveyance systems require energy to operate the chain conveyor that moves the 

bottom ash to the end of the boiler, and the inclined conveyor that dewaters the ash and moves it 

to the nearby storage area. Bottom ash conveyance energy consumption (in kilowatt hours per 

year (kWh/yr)) is a function of motor horsepower. EPA determined unit-level motor horsepower 

based on unit capacity in MW using the following step function provided by CPBG: 

 For Unit Capacity ≤ 500 MW: Motor Horsepower = 50 hp 

 For Unit Capacity > 500 MW: Motor Horsepower = 75 hp 

EPA estimated unit-level motor energy consumption and then summed these unit-level 

requirements to calculate plant-level energy consumption. Unit energy consumption was 

calculated by multiplying the motor horsepower by the conveying time and operating days. EPA 

assumed each system would have two motors for redundancy. Because the MDS is a continuous 

ash removal system, the conveying time is equal to the unit operating time. EPA assumed that 

base load, intermediate, and cycling units produce/convey bottom ash 24 hours per day, while 

peaking units produce/convey bottom ash 12 hours per day. EPA determined the type of unit 

(e.g., base load, peaking) based on data from the “Bottom Ash Input Table” (see Section 4.2.3) 

[ERG, 2013; See Appendix 73]. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-9 

MDS Conveyance Unit Energy Consumption (kWh/yr) = Motor Horsepower × 0.745699 

 kW/HP× MDS Conveying Time × Operating Days × Number of Motors (8-16)

where: 

Motor Horsepower = 50 hp (unit capacity ≤ 500 MW), 75 hp (unit capacity > 

500 MW), 

MDS Conveying Time = 24 hpd (base load, intermediate, cycling units), 12 hpd 

(peaking units), 

Operating Days = The number of days each generating unit operated in 

2009 (see Section 4.2.3), and 

Number of Motors = 2. 

EPA calculated the plant-level MDS conveyance energy consumption by summing the 

unit-level consumption at each plant, according to Equation 8-17. 

Plant MDS Conveyance Energy Consumption (kWh/yr) = ∑ MDS Conveyance Unit Energy 

 Consumption (8-17) 

To calculate energy costs, EPA multiplied the plant energy consumption by the average 

national energy cost of 4.05 cents per kWh (2009$) as determined based on data reported by the 

U.S. Energy Information Administration in Table 8.2 of the Electric Power Annual 2009 for 

fossil plants in the United States [U.S. DOE, 2011]. As the energy cost was provided in 2009 

dollars, EPA adjusted the cost basis to 2010 dollars using the 2009 and 2010 RSMeans Historical 

Cost Indices (180.1 and 183.5, respectively) [RSMeans, 2011]. 

Plant MDS Conveyance Energy Cost (2010$/yr) = National Energy Cost × Plant MDS 

 Conveyance Energy Consumption × (2010 Cost Index/2009 Cost Index) (8-18) 

where: 

National Energy Cost = $0.0405/kWh (2009$), 

Plant MDS Conveyance 

Energy Consumption 

= The energy consumed at the plant level by the 

operation of the motors used to operate the MDS 

conveyors, in kWh/yr, (see Equation 8-17), 

2009 Cost Index = 180.1, and 

2010 Cost Index = 183.5. 

For the purpose of estimating non-water quality environmental impacts, EPA also 

converted energy consumption in kWh/yr to energy load in MW using Equation 8-19. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-10 

MDS Conveyance Unit Energy Load (MW) = MDS Conveyance Unit Energy Consumption / 

 (MDS Conveying Time × Operating Days) × 1 MW / 1000 kW (8-19) 

where: 

MDS Unit Conveyance 

Energy Consumption 

= The energy consumed at the unit level by the operation 

of the motors used to operate the MDS conveyors, in 

kWh/yr, (see Equation 8-16), 

MDS Conveying Time = 24 hpd (base load, intermediate, cycling units); 12 hpd 

(peak units), and 

Operating Days = The number of days each generating unit operated in 

2009, (see Section 4.2.3). 

EPA estimated the total MDS Conveyance Energy Load at the plant by summing the 

energy load for all MDS conveyance units at the plant using Equation 8-20. 

 Plant MDS Conveyance Energy Load (MW) = ∑ MDS Conveyance Unit Energy Load(8-20) 

8.1.5.4 MDS Conveyance O&M Costs: Maintenance Materials 

EPA included costs for maintenance materials, such as routine replacement of materials 

and equipment due to consumption or wear and tear. EPA developed the equation below to 

estimate maintenance materials cost using the operating and maintenance costs reported in 

response to the Steam Electric Survey for generating units with MDSs. Specifically, EPA 

evaluated responses to Question C3-41, Table C-28 (Maintenance Materials) of the Steam 

Electric Survey, calculating the ratio of reported maintenance material costs to the total sum of 

operating labor, maintenance labor, energy, and other O&M costs. EPA selected the median 

ratio, [Redacted], as the maintenance materials cost factor [ERG, 2013; See Appendix 75]. 

MDS Conveyance Maintenance Material Cost (2010$/yr) = MDS Conveyance Maintenance 

Material Cost Factor × (Plant MDS Conveyance Operating Labor Cost + Plant MDS Conveyance 

 Plant Maintenance Labor Cost + Plant MDS Conveyance Energy Cost) (8-21) 

where: 

Plant MDS Conveyance 

Maintenance Material 

Cost Factor 

= Factor that accounts for materials cost as a percentage 

of O&M cost, [Redacted], 

Plant MDS Conveyance 

Operating Labor Cost 

= Includes labor costs for ash handling system operators 

to operate the MDS conveyance systems (see Section 

8.1.5.1 and Equation 8-13), 

Plant MDS Conveyance 

Maintenance Labor 

Cost 

= Includes labor costs associated with maintaining the 

MDS conveyance systems (see Section 8.1.5.2 and 

Equation 8-15), and 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-11 

Plant MDS Conveyance 

Energy Cost 

= Energy costs associated with operating the MDS (see 

Section 8.1.5.3 and Equation 8-18). 

8.1.5.5 MDS Storage O&M Cost: Operating Labor 

EPA calculated MDS storage operating labor costs to operate the bottom ash intermediate 

storage systems for each plant by multiplying the operating labor rate by the number of required 

operator hours per year. To determine the operating labor rate, EPA evaluated labor rates 

reported in response to Question C3-49, Table C-31 (Operating Labor Rate & Maintenance 

Labor Rate) of the Steam Electric Survey. Reported operating labor rates ranged from 

[Redacted]/hr to [Redacted]/hr (median rate of [Redacted]/hr), while maintenance labor rates 

ranged from [Redacted]/hr to [Redacted]/hr (median rate of [Redacted]/hr). As intermediate 

storage system O&M may be performed by the same personnel, EPA decided not to distinguish 

between operating and maintenance labor rates and instead selected an overall labor rate as the 

median of the entire survey dataset, [Redacted]/hr (2010$) [ERG, 2013; See Appendix 76]. 

EPA determined storage operator hours per year based on responses to Question C3-49, 

Table C-31 (Operating Labor (All Other) Staffing/Consumption) of the Steam Electric Survey. 

Reported operator hours per year for [Redacted] silos and other storage areas ranged from 

[Redacted] to [Redacted] hpy for ash storage operation, with a median of [Redacted] hpy. EPA 

selected an overall unit operator hours per year as the median of the questionnaire data set, 

[Redacted] hpy [ERG, 2013; See Appendix 76]. 

MDS Storage Operating Labor Cost (2010$/yr) = MDS Storage Operating Labor Rate × MDS 

 Storage Operator Hours (8-22) 

where: 

MDS Storage 

Operating Labor Rate 

= The labor rate associated with operating the MDS 

storage system, [Redacted]/hr, and 

MDS Storage Operator 

Hours 

= The number of hours per year an operator is needed to 

oversee the MDS storage system, [Redacted] hpy. 

8.1.5.6 MDS Storage O&M Costs: Maintenance Labor 

Maintenance labor costs include labor costs for plant staff to maintain the intermediate 

storage systems. EPA calculated maintenance labor costs by multiplying the maintenance labor 

rate by the number of required maintenance hours per year. EPA selected a maintenance labor 

rate equal to the operating labor rate (All Other) as discussed in Section 8.1.5.5 ([Redacted]/hr). 

EPA determined maintenance hours per year based on responses to Question C3-49, Table C-31 

(Maintenance Labor Staffing/Consumption) of the Steam Electric Survey. Reported maintenance 

hours per year for [Redacted] silos and other storage areas ranged from [Redacted] to [Redacted] 

hpy for storage maintenance, with a median [Redacted] hpy. EPA selected an overall unit 

maintenance hours per year as the median of the questionnaire data set, [Redacted] hpy. EPA 

calculated the maintenance labor for the MDS storage using Equation 8-23 [ERG, 2013; See 

Appendix 76]. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-12 

MDS Storage Maintenance Labor Cost (2010$/yr) = MDS Storage Maintenance Labor Rate × 

 MDS Storage Maintenance Hours (8-23) 

where: 

MDS Storage 

Maintenance Labor 

Rate 

= The labor rate associated with MDS storage, 

[Redacted]/hr, and 

MSD Storage 

Maintenance Hours 

= The annual number of hours spent conducting 

maintenance activities on MDS storage equipment, 

[Redacted] hpy. 

8.1.5.7 MDS Storage O&M Costs: Energy Cost 

Energy requirements for bottom ash intermediate storage consist of the energy required to 

operate the unloading pump for the costed silos. EPA determined unloading pump energy 

consumption (in kWh/yr) based on a pump horsepower of 50 hp, multiplied by the operating 

time and the operating days. 50 EPA assumed the plants unload the bottom ash from the silos 16 

hpd. The number of operating days per year was calculated as the number of calendar days 

generating units operated in 2009 from the “Bottom Ash Input Table” (see Section 4.2.3) 

summed to a plant-level, with a maximum of 260 dpy. EPA used Equation 8-24 to estimate 

unloading pump energy consumption (in kWh/yr) [ERG, 2013; See Appendix 73]. 

MDS Storage Energy Consumption (kWh/yr) = Unloading Pump Horsepower × 

0.745699 kW/HP × MDS StorageOperating Time × Operating Days (8-24)

where: 

Unloading Pump 

Horsepower 

= 50 hp, 

MDS Storage 

Operating Time 

= 16 hpy, and 

Operating Days = Number of days at least one generating unit operated at 

the plant, with a maximum of 260 days per year. 

To calculate energy costs, EPA multiplied the plant energy consumption by the average 

national energy cost of 4.05 cents per kWh (2009$), based on data reported by the U.S. Energy 

Information Administration in Table 8.2 of the Electric Power Annual 2009 for fossil plants in 

the United States [U.S. DOE, 2011]. As the energy cost was provided in 2009 dollars, EPA 

adjusted the cost basis to 2010 dollars using the 2009 and 2010 RSMeans Historical Cost Indices 

(180.1 and 183.5, respectively) [RSMeans, 2011]. 

 

50 Assumed the same horsepower provided for pugmills, in Section 7.1.6.8. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-13 

MDS Storage Energy Cost (2010$/yr) = National Energy Cost × MDS Storage Energy 

 Consumption × (2010 Cost Index/2009 Cost Index) (8-25) 

where: 

National Energy Cost = $0.0405/kWh (2009$), 

MDS Storage Energy 

Consumption 

= The annual energy consumption of the MDS storage 

equipment in kWh/yr, 

2009 Cost Index = 180.1, and 

2010 Cost Index = 183.5. 

For the purpose of estimating non-water quality environmental impacts, EPA also 

converted energy consumption in kWh/yr to energy load in MW using Equation 8-26. 

MDS Storage Energy Load (MW) = MDS Storage Energy Consumption / (MDS Storage 

 Operating Time × Unit Operating Days) × 1 MW / 1000 kW (8-26)

where: 

MDS Storage Energy 

Consumption 

= The annual energy consumption of the MDS storage 

equipment in kWh/yr 

MDS Storage 

Operating Time 

= 16 hpd, and 

Operating Days = Number of days at least one generating unit operated at 

the plant, with a maximum of 260 dpy. 

8.1.5.8 MDS Storage O&M Costs: Maintenance Materials 

Maintenance materials cost includes costs for routine replacement of materials and 

equipment due to consumption or wear and tear. EPA developed Equation 8-27 to estimate 

maintenance materials cost based on an evaluation of operating and maintenance costs reported 

in response to the Steam Electric Survey for plants with a silo or outdoor pile. Specifically, EPA 

evaluated responses to Question C3-49, Table C-31 (Maintenance Materials) of the Steam 

Electric Survey, calculating the ratio of reported maintenance material costs to the total sum of 

operating labor, maintenance labor, energy, and other O&M costs. EPA selected the median ratio 

of 0.962 as the maintenance materials cost factor. EPA calculated MDS Maintenance Materials 

Storage O&M Costs using Equation 8-27 [ERG, 2013; See Appendix 76]. 

MDS Maintenance Materials Storage Costs (2010$/yr) = MDS Maintenance Materials Cost 

Factor × (MDS Storage Operating Labor Cost + MDS Storage Maintenance Labor Cost + MDS 

 Storage Energy Cost) (8-27) 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-14 

where: 

MDS Maintenance 

Material Cost Factor 

= Factor that accounts for materials cost as a percentage 

of O&M cost, 0.962, 

MDS Storage 

Operating Labor Cost 

= Labor costs to operate the MDS intermediate storage 

systems for each plant (see Section 8.1.5.5 and 

Equation 8-21), 

MDS Storage 

Maintenance Labor 

Cost 

= Labor costs for plant staff to maintain the intermediate 

storage systems (see Section 8.1.5.6 and Equation 

8-22), and 

MDS Storage Energy 

Cost 

= Costs to operate the unloading pump for the costed silo 

(see Section 8.1.5.7 and Equation 8-24). 

8.1.5.9 Wet Sluicing O&M Costs: Operating Labor 

Operating labor cost includes labor costs for ash handling system operators to operate the 

wet sluicing conveyance systems. EPA estimated the unit-level operating labor costs and then 

summed these to calculate plant-level operating labor cost. EPA calculated an operating labor 

cost for each unit by multiplying the operating labor rate by the number of required operator 

hours per year. 

To determine the operating labor rate, EPA evaluated labor rates reported in response to 

Question C3-41, Table C-28 (Operating Labor Rate & Maintenance Labor Rate) of the Steam 

Electric Survey. Reported operating labor rates for generating units with wet sluicing systems 

ranged from $23.48/hr to $59.93/hr (median of $35.00/hr), while maintenance labor rates for 

generating units with wet sluicing systems ranged from $23.60/hr to $69.11/hr (median of 

$42.00/hr). Because O&M for the wet sluicing system may be performed by the same personnel, 

EPA decided not to distinguish between operating and maintenance labor rates and instead 

selected an overall labor rate as the median of the entire survey data set, $39.00/hr (2010$) 

[ERG, 2013; See Appendix 77]. 

The number of unit operator hours per year was calculated by multiplying the unit 

operator hours per day by the number of operating days per year for that unit. EPA determined 

operator hours per day based on responses to Question C3-41, Table C-28 (Operating Labor 

Staffing/Consumption) of the Steam Electric Survey. Reported operator hours per day for 10 

units operating wet sluicing systems ranged from [Redacted] to [Redacted] hours per day, with a 

median of 8 hpd. EPA selected an overall unit operator hours per day as the median of the survey 

dataset, 8 hpd. EPA determined the number of unit operating days per year based on data from 

the “Bottom Ash Input Table” (see Section 4.2.3) [ERG, 2013; See Appendix 77]. 

Wet Sluicing Unit Operating Labor Cost (2010$/yr) = Wet Sluicing Operating Labor Rate × Wet 

 Sluicing Operator Hours × Operating Days (8-28) 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-15 

where: 

Wet Sluicing Operating 

Labor Rate 

= $39.00/hr (2010$), 

Wet Sluicing Operator 

Hours 

= 8 hpd, and 

Operating Days = The number of days each generating unit operated in 

2009 (see Section 4.2.3). 

EPA calculated the plant-level wet sluicing operating labor by summing the unit-level 

wet sluicing operating labor costs according to Equation 8-29. 

Plant Wet Sluicing Operating Labor Cost (2010$/yr) = ∑ Wet Sluicing Unit Operating Labor 

 Cost (8-29) 

8.1.5.10 Wet Sluicing O&M Costs: Maintenance Labor 

Maintenance labor cost includes labor costs for plant staff to maintain the conveyance 

systems. EPA estimated unit-level maintenance labor costs and then summed these to calculate 

plant-level maintenance labor cost. EPA calculated a maintenance labor cost for each unit by 

multiplying the maintenance labor rate by the number of required maintenance hours per year. 

EPA selected a maintenance labor rate equal to the operating labor rate as discussed in 

Section 8.1.5.9 ($39.00/hr). EPA determined maintenance hours per year based on responses to 

Question C3-41, Table C-28 (Maintenance Labor Staffing/Consumption) of the Steam Electric 

Survey. Reported maintenance hours per year [Redacted] ranged from [Redacted] to [Redacted] 

hpy for ash handling system maintenance, with a median of 512 hpy. EPA selected an overall 

unit maintenance hours per year as the median of the survey data set, 512 hpy [ERG, 2013; See 

Appendix 77]. 

Wet Sluicing Unit Maintenance Labor Cost (2010$/yr) = Wet Sluicing Maintenance Labor Rate 

 × Wet Sluicing Maintenance Hours (8-30) 

where: 

Wet Sluicing 

Maintenance Labor 

Rate 

= $39.00/hr (2010$), and 

Wet Sluicing 

Maintenance Hours 

= 512 hpy. 

EPA calculated the plant-level wet sluicing maintenance labor by summing the unit-level 

wet sluicing maintenance labor costs according to Equation 8-31. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-16 

Plant Wet Sluicing Maintenance Labor Cost (2010$/yr) = ∑ Wet Sluicing Unit Maintenance 

 Labor Cost (8-31) 

8.1.5.11 Wet Sluicing O&M Costs: Energy Cost 

The energy requirements for wet bottom ash sluicing systems consist of the energy 

required to operate the sluice pump that provides sluice water to transport bottom ash from the 

grinders to either an ash impoundment or dewatering bin. Wet bottom ash conveyance energy 

consumption (in kWh/yr) is a function of pump horsepower. EPA estimated sluice unit pump 

horsepower using the same horsepower equation as that developed for sump pumps for chemical 

precipitation of flue gas desulfurization (FGD) wastewater (see Section 6.1.7.5). EPA calculated 

the pump horsepower using Equation 8-32. 

Sluice Unit Pump Horsepower (hp) = (0.022 × (Ash Sluice Flow Rate / 60 min/hr / 24 hpd) + 

 0.926 (8-32) 

where: 

Ash Sluice Flow Rate = Generating unit specific flow rate of bottom ash sluice 

water (see Section 4.2.3). 

EPA estimated unit-level pump energy consumption and then summed these unit-level 

requirements to calculate plant-level energy consumption using the equations listed below. Unit 

energy consumption was calculated by multiplying the pump horsepower by the conveying time 

and operating days. EPA assumed that base load, intermediate, and cycling units produce bottom 

ash 24 hours per day and convey ash six hours per day, while peaking units produce bottom ash 

12 hours per day and convey ash three hours per day. The type of unit (e.g., base load, peaking) 

and number of operating days per year for each unit costed were based on data found in the 

“Bottom Ash Input Table” (see Section 4.2.3). EPA used Equation 8-33 to estimate wet sluicing 

energy consumption (in kWh/yr). 

Wet Sluicing Unit Energy Consumption (kWh/yr) = Sluice Unit Pump Horsepower × 0.745699 

 kW/HP × Wet Sluicing Unit Conveying Time × Operating Days (8-33) 

where: 

Sluice Unit Pump 

Horsepower 

= Required horsepower to operate the sluice pump (see 

Equation 8-32), 

Wet Sluicing Unit 

Conveying Time 

= 6 hpd (base load, intermediate, cycling units);3 hpd 

(peak units), and 

Operating Days = The number of days each generating unit operated in 

2009 (see Section 4.2.3). 

EPA calculated the plant-level wet sluicing energy consumption by summing the unitlevel wet sluicing energy consumption according to Equation 8-34. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-17 

Plant Wet Sluicing Energy Consumption (kWh/yr) = ∑ Wet Sluicing Unit Energy 

 Consumption (8-34) 

To calculate energy costs, EPA multiplied the plant-level wet sluicing energy 

consumption by the average national energy cost of 4.05 cents per kWh (2009$) as determined 

based on data reported by the U.S. Energy Information Administration in Table 8.2 of the 

Electric Power Annual 2009 for fossil plants in the United States [U.S. DOE, 2011]. As the 

energy cost was provided in 2009 dollars, EPA adjusted the cost basis to 2010 dollars using the 

2009 and 2010 RSMeans Historical Cost Indices (180.1 and 183.5, respectively) [RSMeans, 

2011]. 

Wet Sluicing Energy Cost (2010$/yr) = National Energy Cost × Plant Wet Sluicing Energy 

 Consumption × (2010 Cost Index/2009 Cost Index) (8-35) 

where: 

National Energy Cost = $0.0405/kWh (2009$), 

Plant Wet Sluicing 

Energy Consumption 

= The annual amount of energy consumed by the MDS 

wet sluicing system, in kWh/yr, 

2009 Cost Index = 180.1, and 

2010 Cost Index = 183.5. 

For the purpose of estimating non-water quality environmental impacts, EPA also 

converted energy consumption in kWh/yr to energy load in MW using Equation 8-36. 

Wet Sluicing Unit Energy Load (MW) = Wet Sluicing Unit Energy Consumption / (Wet Sluicing 

 Unit Conveying Time × Operating Days) × 1 MW / 1000 kW (8-36) 

where: 

Wet Sluicing Unit 

Energy Consumption 

= The annual amount of energy consumed by the bottom 

ash wet sluicing system, in kWh/yr, 

Wet Sluicing Unit 

Conveying Time 

= 6 hpd (base load, intermediate, cycling units); 3 hpd 

(peak units), and 

Operating Days = The number of days each generating unit operated in 

2009 (see Section 4.2.3). 

EPA calculated the plant-level wet sluicing energy load by summing the unit-level wet 

energy load according to Equation 8-37. 

 Plant Wet Sluicing Energy Load (MW) = ∑ Wet Sluicing Unit Energy Load (8-37) 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-18 

8.1.5.12 Wet Sluicing O&M Costs: Maintenance Materials 

Wet sluicing maintenance materials cost includes costs for routine replacement of 

materials and equipment due to consumption or wear and tear. EPA developed the equation 

below to estimate the maintenance materials cost based on an evaluation of O&M costs reported 

in response to the Steam Electric Survey for generating units with wet sluicing bottom ash 

handling systems. Specifically, EPA evaluated survey responses to Question C3-41, Table C-28 

(Maintenance Materials) of the Steam Electric Survey, calculating the ratio of reported 

maintenance material costs to the total sum of operating labor, maintenance labor, energy, and 

other O&M costs. EPA selected the median ratio of 0.945 as the maintenance materials cost 

factor [ERG, 2013; See Appendix 77]. EPA calculated the Wet Sluicing Maintenance Materials 

Costs using Equation 8-38. 

Wet Sluicing Maintenance Material Costs (2010$/yr) = Wet Sluicing Maintenance Material Cost 

Factor × (Plant Wet Sluicing Operating Labor Cost + Plant Wet Sluicing Maintenance Labor 

 Cost + Wet Sluicing Energy Cost) (8-38) 

where: 

Wet Sluicing 

Maintenance Material 

Cost Factor 

= Factor that accounts for materials cost as a percentage 

of O&M cost, 0.945, 

Plant Wet Sluicing 

Operating Labor Cost 

= Labor costs to operate the wet sluicing conveyance 

system for each plant (see Section 8.1.5.9 and Equation 

8-29), 

Plant Wet Sluicing 

Maintenance Labor 

Cost 

= Labor costs for plant staff to maintain the wet sluicing 

conveyance system (see Section 8.1.5.10 and Equation 

8-31), and 

Wet Sluicing Energy 

Cost 

= Cost to operate the sluice pump (see Section 8.1.5.11 

and Equation 8-33). 

8.1.6 MDS Results

EPA estimated costs for all plants listed in the “Bottom Ash Input Table” to convert from 

wet bottom ash handling to MDS. A list of the plant-level costs for the MDS bottom ash 

handling technology option is included in the appendix. 

8.2 REMOTE MECHANICAL DRAG SYSTEM 

8.2.1 Technology Description

The remote MDS operates by sluicing the bottom ash to a water trough and sump located 

in an area away from the boiler where an MDS dewaters the ash and conveys it to storage. 

EPA based the design and cost of the replacement ash handling system on information 

collected from vendors (CBPG), as well as information collected from the industry through site 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-19 

visits and the Steam Electric Survey. The remote MDS consists of a complete system added onto 

the existing bottom ash slurry line. This remote MDS, as shown in Figure 8-2, consists of a 

single remote mechanical drag conveyor and a semi-dry storage silo. The remote MDS consists 

of a water bath tank, accepting the bottom ash sluice, and a drag chain conveyor. The existing 

slurry line is redirected to feed the remote MDS. EPA assumes the conveyor overflows into a 

single sump pit from which transport water will be recycled back to the boiler area. All bottom 

ash sluice water sent to the remote MDS will be recycled back to the process to achieve complete 

recycle. [ERG, 2013; See Appendix 78]. 

Graphic re-printed with permission from United Conveyor Corporation [UCC, 2012]. 

Figure 8-2. Remote Mechanical Drag System 

8.2.2 Population Costed

EPA evaluated remote MDS costs for each plant requiring conversion from wet bottom 

ash handling to dry or closed-loop recycle bottom ash handling. Based on information from the 

Steam Electric Survey, EPA identified 253 plants, corresponding to 634 units, discharging 

bottom ash transport water, without any plans to convert to dry handling or having the capacity 

to handle all the bottom ash dry, from coal- and oil-fired units. 51 EPA identified the units 

planning to convert to dry handling or closed-loop recycle systems from responses in the Steam 

Electric Survey stating a planned conversion, the projected date for the conversion, and the end 

use of the wet sluicing system. Additionally, EPA identified plants that have announced plans to 

retire generating units or convert to dry or closed-loop recycle bottom ash handling prior to 

December 31, 2014, as described in Section 4.4.1. Finally, EPA identified units with enough 

capacity to handle all bottom ash with a dry handling system from responses in the Steam 

Electric Survey stating that no modifications to the existing bottom ash handling system would 

 

51 When the group of plants excluding oil-fired unts and units with a capacity of 50 MW or less is evaluated the 

population of plants discharing bottom ash transport includes 240 plants, corresponding to 581 units. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-20 

be required to handle all of the bottom ash dry. There are no conversion costs for generating 

units that are already planned to be converted to dry bottom ash handling or closed-loop recycle 

systems because the plant will retire/convert the system without the implementation of the ELGs. 

Additionally, there are no conversion costs for generating units that have both wet and dry 

bottom ash handling systems where the dry system is capable of handling all of the bottom ash 

because the plant would be capable of operating without the wet sluicing system. EPA estimated 

compliance costs for these 634 generating units to convert to a remote MDS. 

8.2.3 Input Table

EPA used the same inputs as in the MDS methodology to estimate remote MDS costs. 

For more information on the specific input values, see Section 8.1.3. 

8.2.4 Capital Cost Methodology 

Capital costs for the remote MDS includes fully erected and commissioned systems, 

including equipment, controls, foundations, and field labor (e.g., installed equipment costs). The 

capital costs for the remote MDS do not include the costs for buildings or land because EPA 

assumed zero land costs based on data from site visits and discussions with plants who have 

already converted from wet bottom ash handling to dry or closed-loop recycle bottom ash 

handling. EPA assumed that other capital costs associated with buildings, site preparation, 

engineering, and construction were included in the costs provided by the vendors. 

EPA calculated plant-level capital costs as the sum of costs for purchased and installed 

conveyance equipment for the remote MDS (including intermediate storage), the recycle pump, 

the chemical feed system, and engineering overhead costs. The remote MDS capital cost is the 

sum of the following costs: 

 Conveyance equipment cost, 

 Recycle pump cost, 

 Chemical feed system cost, 

 Purchase equipment installation cost, and 

 Engineering cost. 

8.2.4.1 Remote MDS Purchased Equipment Cost: Conveyance Equipment 

EPA estimated unit-level capital costs for purchase and installation of equipment to 

convert a wet sluicing system to a remote MDS. EPA then summed these unit-level costs to 

calculate plant-level conveyance equipment costs. EPA made the following assumptions based 

on information obtained from vendors and Steam Electric Survey responses: 

The existing bottom of the boiler and wet bottom ash sluicing system will continue to be 

used. EPA costed moving of the sluice line to the new location of the remote MDS. 

EPA costed individual conveyor systems with a semi-dry bottom ash storage silo for each 

generating unit. (Note that this may overestimate compliance costs for the proposed rule because 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-21 

multiple units at a plant could use the same remote MDS which would result in lower overall 

costs.) 

EPA assumed the overflow from the remote MDS is equal to the ash sluice flow rate of 

the system. 

EPA costed the addition of hydrochloric acid (HCl) to the sump to decrease the pH of the 

overflow to neutral (7 S.U.).52 EPA did not include costs for installing a clarifier, assuming that 

any solids generated by pH adjustment will eventually be removed by the remote MDS 

conveyor. 

CBPG provided cost data for the purchase and installation of equipment required for the 

conversion, from which EPA developed the following remote MDS conveyance equipment cost 

equation. Since all installed equipment costs were provided in 2010 dollars, no adjustment of the 

cost basis was required. 

Remote MDS Unit Conveyance Equipment Cost (2010$) = 14,227 × Capacity + 

 2,000,000 (8-39)

where: 

Capacity = Generating unit capacity (see Section 4.2.3). 

EPA calculated the plant-level remote MDS conveyance equipment costs by summing 

the unit-level remote MDS conveyance equipment costs according to Equation 8-40. 

Plant Remote MDS Conveyance Equipment Cost (2010$) = ∑ Remote MDS Unit Conveyance 

 Equipment Cost (8-40) 

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A78) for 

details on the development of Equations 8-38 and 8-39. 

8.2.4.2 Remote MDS Purchase Equipment Cost: Recycle Pump 

EPA estimated the recycle pump costs using Equation 8-41, provided below. EPA 

assumed the same pump type and estimated costs using the same cost equation developed for 

sump pumps for chemical precipitation of FGD wastewater (see Section 6.1.6.1). Because pump 

costs were provided by vendors in 2011 dollars, EPA adjusted the cost basis to 2010 dollars 

using the 2010 and 2011 RSMeans Historical Cost Indices (183.5 and 185, respectively) 

[RSMeans, 2011]. 

Remote MDS Unit Recycle Pump Cost (2010$) = 15.79 × (Ash Sluice Flow Rate / 60 min/hr / 

24 hpd + 7,685) × Pump Quantity × Freight Factor × (2010 Cost Index/2011 Cost Index) (8-41) 

 

52 Not all systems will require chemical addition for pH control to operate as complete recycle; however, EPA 

estimated this cost for all remote MDS system installations. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-22 

where: 

Ash Sluice Flow Rate = The ash sluice flow rate for each generating unit, (see 

Section 4.2.3), 

Pump Quantity = 1 pump, 

Freight Factor = 1.04, 

2010 Cost Index = 183.5, and 

2011 Cost Index = 185. 

EPA calculated the plant-level remote MDS recycle pump cost by summing the unit-level 

remote MDS recycle pump cost according to Equation 8-42. 

Plant Remote MDS Recycle Pump Cost (2010$) = ∑ Remote MDS Unit Recycle Pump 

 Cost (8-42) 

8.2.4.3 Remote MDS Purchased Equipment Cost: Chemical Feed System 

EPA assumed the same HCl feed system and estimated costs using the same cost 

equations as those developed for chemical precipitation of FGD wastewater (see Section 6.1.6.3). 

EPA determined the size and cost of the feed system based on the chemical consumption, which 

was calculated based on chemical dosage. 

EPA calculated a chemical dosage of 0.000112 g of neat HCl/L of bottom ash sluice 

wastewater based on the amount of HCl needed to reduce bottom ash sluice wastewater pH from 

8.5 S.U. to 7 S.U. EPA determined the bottom ash sluice wastewater pH of 8.5 S.U. based on 

review of available data in five Electric Power Research Institute’s Plant Integrated Systems 

Chemical Emissions Studies (ERPI PICSES) reports. These reports indicated bottom ash sluice 

wastewater pH of less than 7 S.U. at two plants (pH ranged from 4.3 to 6.9 S.U.), neutral at one 

plant (pH ranged from 5.8 to 7.9 S.U.), and greater than 7 S.U. at two plants (pH ranged from 7.7 

to 9.4 S.U.). Based on this information, EPA assumed that bottom ash sluice wastewater is 

typically more basic than acidic, and EPA used the pH values from the plant with the highest pH 

to calculate the required chemical dosage. Due to plant-to-plant fluctuations in pH, some plants 

might need to reduce pH using acid while other might need to increase pH using sodium 

hydroxide (also known as caustic). Therefore, EPA’s estimated costs for an HCl feed system 

were assumed to represent a variety of pH adjustment scenarios that may be required at plants. 

To calculate unit chemical consumption, EPA converted the chemical dosage from grams 

of neat HCl to 32 percent HCl solution and then multiplied by the unit bottom ash sluice flow 

rate, as shown by Equations 8-43 and 8-44. 

Dose Conversion Factor (L/g) = 1 / (Concentration × Density × 1,000 g/kg) = 0.00270 L HCl 

 solution / g neat HCl (8-43)
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-23 

where: 

Concentration = 32 percent HCl solution, and 

Density = 1.159 kg/L for 32 percent HCl solution. 

Remote MDS Unit Chemical Consumption (gal/day) = Dose × Dose Conversion Factor × 3.785 

L of wastewater/gal of wastewater × 1 gal of chemical/3.785 L of chemical × Ash Sluice Flow 

 Rate (8-44) 

where: 

Dose = 0.000112 g of neat HCl/ L ash sluice wastewater, 

Dose Conversion 

Factor 

= 0.00270 L HCl solution/g neat HCl, and 

Ash Sluice Flow Rate = The ash sluice flow rate for each generating unit (see 

Section 4.2.3). 

Chemical feed system costs vary by unit chemical consumption, based on the ranges 

shown by Equations 8-45 and 8-46. EPA adjusted the chemical feed system costs provided by 

vendors in 2011 dollars to 2010 dollars using the 2010 and 2011 RSMeans Historical Cost 

Indices (183.5 and 185, respectively) [RSMeans, 2011]. 

For Remote MDS Unit Chemical Consumption ≤ 2,400 gpd, EPA used Equation 8-45. 

Remote MDS Unit Chemical Feed System Cost (2010$) = ($5,000 + Feed System Freight) × 

 (2010 Cost Index/2011 Cost Index) (8-45) 

For Remote MDS Unit Chemical Consumption > 2,400 gpd, EPA used Equation 8-46. 

Remote MDS Unit Chemical Feed System Cost (2010$) = ($15,000 + Feed System Freight) × 

 (2010 Cost Index/2011 Cost Index) (8-46) 

where: 

Feed System Freight = $300, 

2010 Cost Index = 183.5, and 

2011 Cost Index = 185. 

EPA calculated the plant-level remote MDS chemical feed system cost by summing the 

unit-level remote MDS chemical feed system cost according to Equation 8-47. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-24 

Plant Remote MDS Chemical Feed System Cost (2010$) = ∑ Remote MDS Unit Chemical Feed 

 System Cost (8-47) 

8.2.4.4 Remote MDS Purchase Equipment Installation Cost 

Purchased equipment installation includes the installation of all equipment, piping, 

instrumentation/calibration, electrical equipment, mechanical equipment, structural supports, 

insulation, and painting. EPA estimated installation capital costs for the purchased recycle pump 

and the chemical feed system. EPA assumed an installation cost factor for the remote MDS 

purchased equipment similar to that of fly ash, two times the purchase equipment costs for the 

recycle pump and chemical feed system (see Section 7.1.5.4). 

8.2.4.5 Remote MDS Engineering Cost 

Engineering costs include costs for process design and general engineering, cost 

engineering, consulting fees, supervision, and inspection. EPA assumed that the engineering 

costs incurred for bottom ash conversions include owner’s overhead engineering costs. EPA 

determined engineering overhead costs by multiplying the purchased and installation equipment 

costs by a factor for conveyance and intermediate storage. The factor was determined based on 

survey response to Questions C3-39 (conveyance costs) and C3-47 (intermediate storage costs). 

Because the remote MDS capital costs include both conveyance and intermediate storage, EPA 

combined the factors for conveyance and intermediate storage for a value of 0.01765 [ERG, 

2013; See Appendix 78]. 

EPA used Equations 8-48 and 8-49 to estimate plant-level engineering costs. 

Remote MDS Unit Capital Cost (2010$) = Remote MDS Unit Conveyance Equipment Cost + 

Remote MDS Unit Recycle Pump Cost + Remote MDS Unit Chemical Feed System Cost + 

 Remote MDS Unit Installation Cost (8-48) 

Remote MDS Unit Engineering Cost (2010$) = Remote MDS Unit Capital Cost × Remote MDS 

 Engineering Factor (8-49)

where: 

Remote MDS 

Engineering Factor 

= 0.01765, 

Remote MDS Unit 

Conveyance Equipment 

Cost 

= Cost of the conveyance equipment associated with each 

generating unit (see Section 8.2.4.1 and Equation 

8-39), 

Remote MDS Unit 

Recycle Pump Cost 

= Cost of the recycle pump for each generating unit (see 

Section 8.2.4.2 and Equation 8-41), 

Remote MDS Unit 

Chemical Feed System 

Cost 

= Cost associated with the chemical feed systems needed 

for each generating unit (see Section 8.2.4.3 and 

Equation 8-45 or 8-46), and 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-25 

Remote MDS Unit 

Installation Cost 

= The cost to install all remote MDS purchased 

equipment for each generating unit (see Section 

8.2.4.4). 

EPA calculated the plant-level remote MDS engineering cost by summing the unit-level 

remote MDS engineering cost according to Equation 8-50. 

 Remote MDS Engineering Cost (2010$) = ∑ Remote MDS Unit 

 Engineering Cost (8-50) 

8.2.5 O&M Cost Methodology 

O&M costs for each plant consist of all costs related to operating and maintaining the 

conveyance and storage equipment required to convert wet bottom ash handling systems to the 

remote MDS. 

EPA used Equation 8-51 to calculate total O&M costs for remote MDS. Because the 

remote MDS requires the continued operation of the existing wet sluicing equipment operated by 

plants, the estimated O&M costs associated with operating of the wet sluicing equipment were 

not subtracted from the O&M costs for the replacement remote MDS as a cost savings. 

Remote MDS O&M Costs = Remote MDS Conveyance O&M Cost + Remote MDS Storage 

 O&M Cost (8-51) 

Remote MDS conveyance O&M costs and remote MDS storage O&M costs are 

calculated using Equations 8-52 and 8-53. 

Remote MDS Conveyance O&M Costs = MDS Conveyance O&M Cost + Remote MDS O&M 

 Chemical Purchase Cost + Remote MDS O&M Energy Cost (8-52) 

 Remote MDS Storage O&M Costs = MDS Storage O&M Cost (8-53)

8.2.5.1 Remote MDS Conveyance O&M Costs: Mechanical Drag System 

The MDS conveyance O&M costs are presented in Sections 8.1.5.1 through 8.1.5.4. EPA 

has determined that all of these costs are applicable to plants installing remote MDSs. 

8.2.5.2 Remote MDS Conveyance O&M Costs: Chemical Purchase Cost 

The chemical requirement for remote MDSs consist of HCl added to the sump to 

decrease the pH of the overflow to neutral. HCl costs are a function of HCl consumption, 

calculated in gallons of 32 percent HCl solution in gpd, as described in Section 8.2.4.3, and 

converted to tons/year using Equation 8-54. 

Remote MDS Unit Chemical Consumption (tons/yr) = Remote MDS Unit Chemical 

Consumption × HCl Solution Density × 3.785 L/gal × 2.205 lb/kg × 1 ton/2,000 lb × Operating 

 Days (8-54) 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-26 

where: 

Remote MDS Unit 

Chemical Consumption 

= Amount of HCl consumed by the chemical feed system 

each day (see Section 8.2.4.3 and Equation 8-43), 

HCl Solution Density = 1.159 kg/L for 32 percent HCl solution, and 

Operating Days = The number of days each generating unit operated in 

2009, (see Section 4.2.3). 

To calculate chemical purchase costs, EPA multiplied HCl consumption by the sum of 

the chemical purchase and freight costs using Equation 8-55. EPA adjusted the chemical and 

freight costs that were provided by vendors in 2011 dollars to 2010 dollars using the 2010 and 

2011 RSMeans Historical Cost Indices (183.5 and 185, respectively) [RSMeans, 2011]. 

Remote MDS Unit Chemical Cost (2010$) = Remote MDS Unit Chemical Consumption × (HCl 

 Cost + HCl Freight Cost) × (2010 Cost Index/2011 Cost Index) (8-55) 

where: 

Remote MDS Unit 

Chemical Consumption 

= Amount of HCl consumed by the chemical feed system 

each day (see Section 8.2.4.3 and Equation 8-44), 

HCl Cost = [Redacted]/ton (2011$) (see Section 6.1.7.4), 

HCl Freight Cost = $65.91/ton in (2011$), 

2010 Cost Index = 183.5, and 

2011 Cost Index = 185. 

EPA calculated the plant-level remote MDS chemical cost by summing the unit-level 

remote MDS chemical cost according to Equation 8-56. 

 Remote MDS Chemical Cost (2010$/yr) = ∑ Remote MDS Unit Chemical Cost (8-56) 

8.2.5.3 Remote MDS Conveyance O&M Costs: Energy Cost 

Energy requirements unique to the remote MDS include the energy required to operate 

the pump that returns transport water from the sump pit back to the boiler area, and the energy 

required to operate the HCl feed pump. EPA determined this additional energy consumption (in 

kWh/yr) by calculating and summing the annual power consumption for these two pumps for 

each unit, and then summing these unit-level consumptions to calculate plant-level energy 

consumption using Equations 8-57through 8-59. 

Pump energy consumption (in kWh/yr) is a function of pump horsepower. EPA estimated 

sluice pump horsepower using the same horsepower equation as that developed for sump pumps 

for chemical precipitation of FGD wastewater (see Section 6.1.7.5). The ash sluice rate, in gpd, 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-27 

was determined for each generating unit at each plant from the responses to Question C3-3, 

Table C-19 (Average Sluice Water Flow Rate) of the Steam Electric Survey. 

Remote MDS Unit Sluice Pump Horsepower (hp) = 0.022 × (Ash Sluice Flow Rate / 60 min/hr / 

 24 hpd) + 0.926 (8-57) 

where: 

Ash Sluice Flow Rate = The ash sluice flow rate for each generating unit (see 

Section 4.2.3). 

For the HCl feed pump, EPA used the same horsepower as that developed for feed pumps 

for chemical precipitation of FGD wastewater, 0.5 hp (see Section 6.1.7.5). 

Remote MDS Unit Feed Pump Horsepower (hp) = 0.5 hp 

In calculating energy consumption, EPA assumed that baseload, intermediate, and 

cycling units produce bottom ash 24 hours per day and convey ash six hpd, and that peaking 

units produce bottom ash and convey ash three hpd. The type of unit and operating days per year 

for each unit costed is included in the “Bottom Ash Input Table” (see Section 4.2.3). 

Remote MDS Unit Energy Consumption (kWh/yr) = (Remote MDS Unit Sluice Pump 

Horsepower + Remote MDS Unit Feed Pump Horsepower) × 0.745699 kW/HP × Remote MDS 

 Unit Conveying Time × Operating Days (8-58) 

where: 

Remote MDS Unit 

Sluice Pump 

Horsepower 

= Horsepower required by the unit sluice pump (see 

Equation 8-57), 

Remote MDS Unit 

Feed Pump Horsepower 

= 0.5 hp, 

Remote MDS Unit 

Conveying Time 

= 6 hpd (baseload, intermediate, cycling units); 3 hpd 

(peaking units), and 

Operating Days = The number of days each generating unit operated in 

2009, (see Section 4.2.3). 

EPA calculated the plant-level remote MDS energy consumption by summing the unitlevel remote MDS energy consumption according to Equation 8-59. 

Plant Remote MDS Energy Consumption (kWh/yr) = ∑ Remote MDS Unit Energy 

 Consumption (8-59) 

To calculate energy costs, EPA multiplied the plant energy consumption by the average 

national energy cost of 4.05 cents per kWh (2009$) as determined based on data reported by the 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-28 

U.S. Energy information Administration in Table 8.2 of the Electric Power Annual 2009 for 

fossil plants in the United States [U.S. DOE, 2011]. As the energy cost was provided in 2009 

dollars, EPA adjusted the cost basis to 2010 dollars using the 2009 and 2010 RSMeans Historical 

Cost Indices (180.1 and 183.5, respectively) [RSMeans, 2011]. 

Remote MDS Energy Cost (2010$/yr) = National Energy Cost × Plant Remote MDS Energy 

 Consumption × (2010 Cost Index/2009 Cost Index) (8-60) 

where: 

National Energy Cost = $0.0405/kWh (2009$), 

Plant Remote MDS 

Energy Consumption 

= Annual amount of energy consumed by the remote 

MDS in kWh/yr (see Equation 8-59), 

2009 Cost Index = 180.1, and 

2010 Cost Index = 183.5. 

For the purpose of estimating non-water quality environmental impacts, EPA also 

converted energy consumption in kWh/yr to energy load in MW using Equation 8-61. 

Remote MDS Unit Energy Load (MW) = Remote MDS Unit Energy Consumption / (Remote 

 MDS Unit Conveying Time × Operating Days) × 1 MW / 1000 kW (8-61) 

where: 

Remote MDS Unit 

Energy Consumption 

= Annual amount of energy consumed by the remote 

MDS at each generating unit in kWh/yr, (see Equation 

8-58), 

Remote MDS Unit 

Conveying Time 

= 6 hpd (base load, intermediate, cycling units); 3 hpd 

(peaking units), and 

Operating Days = The number of days each generating unit operated in 

2009 (see Section 4.2.3). 

EPA calculated the plant-level remote MDS energy load by summing the unit-level 

remote MDS energy load according to Equation 8-62. 

 Remote MDS Energy Load (MW) = ∑ Remote MDS Unit Energy Load (8-62) 

8.2.5.4 Remote MDS Storage O&M Costs 

EPA determined that the storage O&M costs for remote MDSs are the same as those for 

MDSs, described in Sections 8.1.5.5 through 8.1.5.8. 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-29 

8.2.6 Remote MDS Results

EPA estimated costs for all plants listed in the “Bottom Ash Input Table” to convert from 

wet bottom ash handling to a remote MDS. A list of the plant-level costs for the remote MDS 

bottom ash handling technology is included in the appendix. 

8.3 BOTTOM ASH DISPOSAL COST

EPA determined the cost of dry bottom ash transportation and disposal based on bottom 

ash generation rates. However, bottom ash generation rates reported in the Steam Electric Survey 

are in tons per day on a dry weight basis, while bottom ash requiring disposal includes some 

moisture content, which increases the weight of the ash. EPA, therefore, determined the bottom 

ash moisture content to account for the increased weight. EPA determined the moisture content 

of the bottom ash based on responses to Question C3-32, Table C-23 (Percent Moisture of the 

Bottom Ash Entering the Destination) of the Steam Electric Survey. The average moisture 

content reported by plants that transport bottom ash by truck to a landfill was 20 percent. Based 

on this information, EPA developed Equation 8-63 to adjust the bottom ash generation rate to 

account for ash moisture. EPA determined the unit bottom ash generation rate (in tpd) for each 

generating unit at each plant from the survey responses to Question C3-2, Table C-18 (Typical 

Amount of Wet Conveyed Bottom Ash Produced (reported in tpd on a dry weight basis)). The 

number of unit operating days per year was determined based on responses to Question A6-1, 

Table A-8 (Steam Electric Units) of the Steam Electric Survey [ERG, 2013; See Appendix 79]. 

Dewatered Bottom Ash Generation Rate (tons/yr) = [ ∑(Unit Bottom Ash Generation Rate × 

 Operating Days) ] / (1 – Bottom Ash Moisture Content) (8-63) 

where: 

Unit Bottom Ash 

Generation Rate 

= The amount of wet bottom ash generated by each 

generating unit (see Section 4.2.3), 

Operating Days = The number of days each generating unit operated in 

2009 (see Section 4.2.3), and 

Bottom Ash Moisture 

Content 

= 20 percent. 

EPA also calculated dewatered bottom ash density using Equation 8-64. For this 

calculation, EPA assumed a bottom ash density of 45 lb/ft3

(dry weight), the same as that for dry 

fly ash. 

Dewatered Bottom Ash Density (lb/ft3

) = [(Bottom Ash Moisture Content) × (Density of Water)] 

 + [(Density of Bottom Ash) × (1 – Bottom Ash Moisture Content)] = 48.5 lb/ft3 (8-64) 

where: 

Bottom Ash Moisture 

Content 

= 20 percent, 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-30 

Density of Water = 62.4 lb/ft3, and 

Density of Bottom Ash = 45 lb/ft3 (dry weight). 

The dewatered bottom ash density was used to calculate the total tons of bottom ash that 

need to be transported and disposed of in a landfill. This value was used to calculate 

transportation and disposal costs. Sections 5.3 and 5.4 describe transportation and disposal costs 

for the dry bottom ash generated by the MDS or remote MDS. 

8.4 IMPOUNDMENT OPERATION COSTS

Section 5.5 describes cost savings associated with closing combustion residual surface 

impoundments. 

8.5 ONE-TIME COSTS

Based on data from plant site visits and information in the survey, EPA determined that 

some plants operated bottom ash wet sluicing systems as closed-loop recycle systems. EPA also 

determined that some plants recycle a majority of their bottom ash sluice but still discharge a 

small portion of bottom ash sluice water as emergency discharges or via other plant operations 

(e.g., re-used and discharged with FGD wastewater). For those plants recycling the majority of 

their bottom ash sluice, EPA assumed that a one-time engineering cost would be appropriate to 

completely close the bottom ash sluice recycle loop to eliminate the discharge of bottom ash 

transport water. 

To determine the plants that should receive the one-time bottom ash management cost, 

EPA reviewed bottom ash sluice recycle and discharge amounts reported in Part C Section 3.1, 

along with the water balance diagrams provided in the Steam Electric Survey. EPA identified the 

plants that should receive the one-time bottom ash management costs as those plants recycling 

more than 90 percent of their sluice or only discharging bottom ash sluice through emergency 

outfalls. Based on industry knowledge and contractor fees, EPA developed an estimate for a 

contractor to come on site and develop a plan for the plant to close up the bottom ash discharge. 

EPA assumed that the contractor will require a total of 200 hours to complete the plan, 

including two week-long trips to the plant. Therefore, EPA used Equations 8-65, 8-66, and 8-67 

to estimate these one-time costs: 

 Bottom Ash One-Time Cost (2010$) = Contractor Labor + Travel Cost (8-65) 

The contractor labor and travel costs were estimated using Equations 8-66 and 8-67. 

 Contractor Labor (2010$) = Number of Hours × Contractor Rate (8-66) 

where: 

Number of Hours = EPA estimated number of hours for the contractor to 

complete the plan, 200, and 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-31 

Contractor Rate = EPA estimate of the contractor rate, $100/hr. 

EPA estimated the travel costs for the two week-long trips using Equation 8-67. 

Travel Cost (2010$) = (Number of Travel Days × Hotel Cost × Escalation Rate) + (Number of 

 Travel Days × Food Cost) + (Number of Trips × Airfare Costs) (8-67) 

where: 

Number of Travel Days = Number of work days in a two week period, 10 days. 

Hotel Cost = The 2011 federal per diem rate for hotels based on 

standard continental United States (CONUS) rates, 

Escalation Rate = An escalation factor to account for potential increases 

in hotel costs based on location, 1.25 (i.e., 25 percent), 

Number of Travel Days = Total combined length of the trips in days, 14, 

Food Cost = The 2011 federal per diem rate for meals and 

incidentals based on standard CONUS rates, 

Number of Trips = EPA estimate of the number of trips required, two, and 

Airfare Costs = EPA estimate of the round trip airfare for the contractor 

to travel to the plant, $500. 

Based on these assumptions, EPA estimates that the total one-time costs for a plant to 

hire a contractor to close the discharge of a bottom ash recycle system would be $22,422. This 

estimate assumes no capital improvements. 

8.6 BOTTOM ASH OUTAGE COSTS

EPA considered the impact of a plant outage required to convert wet bottom ash handling 

systems to MDS and remote MDS. Based on an evaluation of vendor and survey information, 

EPA determined that most MDS and remote MDS installations can be completed during 

regularly scheduled outages. Specifically, for the 23 units that reported conversions to an MDS, 

only one required an outage outside a regularly scheduled outage to complete the installation. 

For remote MDSs, the entire system can be installed prior to a scheduled outage, and then the 

necessary tie-in can occur during a regularly scheduled outage. Therefore, there are no costs for 

plant outages during installation of the MDS or remote MDS. 

8.7 RECURRING COSTS

For both the MDS and remote MDS, the drag chain needs to be periodically replaced. 

Based on information provided by the UCC, the life of a drag chain varies from two to three 

years for the MDS to four to six years for the remote MDS [ERG, 2013; See Appendix 80]. 

Because the MDS drag chain is underneath the boiler and can potentially be damaged by large 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-32 

chunks of falling bottom ash, EPA assumed that the MDS drag chain would need to be replaced 

every three years. Because the remote MDS drag chain receives bottom ash slurry where the 

bottom ash has already undergone grinding, EPA assumed that the remote MDS drag chain 

would need to be replaced every five years. Based on cost information provided by UCC, EPA 

estimated drag chain replacement costs of $175,000 per unit, including labor and materials 

[ERG, 2013; See Appendix 80]. Plant-level drag chain replacement costs equal the sum of unitlevel replacement costs. 

8.8 SELECTION OF DRY BOTTOM ASH HANDLING TECHNOLOGY

For each plant requiring conversion from wet bottom ash handling to dry or closed-loop 

bottom ash handling, EPA evaluated the costs for both the MDS and remote MDS technologies 

and then selected the technology with the lowest total annualized cost. 

Cost annualization is a way of combining one-time costs (such as capital costs) and O&M 

costs (which are incurred every year) and spreading them out evenly over an analytical 

timeframe, creating a cost incurred each year for purposes of comparison. Cost annualization 

uses the following inputs: 1) the estimated costs (capital, O&M, one-time, periodic); 2) a 

discount rate that reflects the cost of capital to the affected plants; and 3) an assumed timeframe 

over which to annualize costs. EPA selected a 7 percent discount rate, which is the real (i.e., 

inflation rate factored out) cost of capital as estimated by the U.S. Office of Management and 

Budget [OMB, 2003] and which EPA generally uses in regulatory analyses in cases where the 

actual cost of capital is unknown. EPA selected a time frame of 20 years based on the expected 

operational life of the dry/closed-loop recycle bottom ash handling technology. 

EPA used Equations 8-68 and 8-69 to calculate total annualized costs for MDS and 

remote MDSs. 

For MDS, EPA used Equation 8-68. 

Total Annualized Cost (2010$/year) = (MDS Capital Cost × 7%/{1 – [1 / (1 + 7%)20]}) + MDS 

 O&M Cost +MDS Recurring Cost / 3 (8-68)

For Remote MDS EPA used Equation 8-69. 

Total Annualized Cost (2010$/year) = (Remote MDS Capital Cost × 7%/{1 – [1 / (1 + 7%)20]}) 

 + Remote MDS O&M Cost + MDS Recurring Cost / 5 (8-69)

8.9 RESULTS AND SUMMARY OF COSTS

As described in Section 2.1.4, EPA’s cost model generated plant-level compliance costs 

for converting wet bottom ash handling systems to an MDS or remote MDS. The cost output 

generated by the model includes a breakout of specific capital and O&M cost elements, 

including equipment costs, installation costs, operating labor, maintenance labor, and energy 

costs. The output also includes costs for the common cost elements. Chapter 5 discusses these 

common cost elements that include transportation and disposal of combustion residual. A list of 
Chapter 8 – Bottom Ash Transport Water Cost Methodology 

8-33 

the plant-level costs for the dry/closed-loop recycle bottom ash handling technology option is 

included in the appendix. 

8.10 REFERENCES

1. Eastern Research Group, Inc (ERG). 2013. Supplemental Costs and Loadings 

Documentation. (19 April). DCN SE01825. 

2. RSMeans. 2011. Building Construction Cost Data, 69th Edition. (January). DCN 

SE02952. 

3. United Conveyor Corporation (UCC). 2009. Wet-to-Dry Conversion: Bottom Ash & Fly 

Ash Systems. (January). DCN SE02042. 

4. United Conveyor Corporation (UCC). 2012. Remote SFC Bottom Ash Handling System. 

(27 November). DCN SE02968.A3. 

5. U.S. Department of Energy (DOE). 2011. Energy Information Administration (EIA). 

Electric Power Annual 2009. Washington, DC. (4 January). DCN SE02023. 

6. U.S. Office of Management and Budget (OMB). 2003. Circular A-4. (17 September). 

DCN SE03572. 
Chapter 9 – Combustion Residual Leachate Cost Methodology 

9-1 

CHAPTER 9 

COMBUSTION RESIDUAL LEACHATE COST 

METHODOLOGY 

Combustion residuals can include flue gas desulfurization (FGD) solids, fly ash, and/or 

bottom ash. EPA estimated capital and operating and maintenance (O&M) costs associated with 

installing and operating a one-stage chemical precipitation wastewater treatment system to treat 

combustion residual landfill leachate. Landfill leachate treatment options include one-stage 

chemical precipitation or one-stage chemical precipitation with biological treatment. EPA finds 

that plants with combustion residual leachate from surface impoundments will not incur costs 

associated with any proposed leachate requirements (see Section 9.1). Where a plant generates 

both landfill leachate and FGD wastewater, EPA evaluated the leachate compliance costs in 

conjunction with FGD wastewater treatment (i.e., those plants discharging leachate and FGD 

wastewater would use only one wastewater treatment system to treat the combined leachate and 

FGD wastewater flow).53 For plants that do not have FGD wastewater, however, EPA calculated 

the cost for a chemical precipitation to treat only the landfill leachate using the equations in 

Section 6.1 associated with one-stage chemical precipitation [ERG, 2012]. 

The following section describes the capital and O&M costs associated with treating 

combustion residual landfill leachate that are in addition to the equipment and O&M costs 

described in Sections 6.1 and 6.2 for chemical precipitation and biological treatment, 

respectively. 

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 one of the following two technology options: 

 One-stage chemical precipitation; and 

 One-stage chemical precipitation followed by biological treatment. 

Sections 6.1 and 6.2 detail EPA’s methodology for calculating plant specific costs for a 

one-stage chemical precipitation wastewater treatment system and a biological treatment system 

respectively, for the treatment of FGD wastewater. These same cost methodologies were used to 

generate plant-level costs for the treatment of landfill leachate. The equations presented in both 

sections were applied to the flow rate of 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. 

 

53 The technology option for combustion residual landfill leachate is one-stage chemical precipitation while the 

technology option for FGD wastewater is one-stage chemical precipitation followed by biological treatment. While 

the plant could technically meet the proposed leachate limitations and standards with only a one-stage chemical 

precipitation system, installing two separate treatment systems for the leachate and FGD wastewater would be more 

expensive than a single system that subjects leachate to both chemical precipitation and biological treatment. 
Chapter 9 – Combustion Residual Leachate Cost Methodology 

9-2 

EPA acknowledges that landfills can be located some distance away from the plant. 

According to survey data, the average onsite landfill is 1.3 miles from the plant center. As a 

result, EPA estimated costs for all plants to install a series of pumps and piping to transport 

landfill leachate from the landfill where it is collected to the main plant area (i.e., 1.3 miles away, 

where the wastewater treatment system is most likely located). 54 Sections 9.5 and 9.6 provide 

more detail on the methodology used to estimate capital equipment and O&M costs associated 

with the additional equipment needed to transfer landfill leachate back to the plant. 

Plants that generate surface impoundment leachate will likely use a different approach 

than installing the technology basis to comply with limitations or standards based on either of the 

technology options. EPA determined that 36 percent of plants generating leachate from 

combustion residual impoundments recycle the leachate back to the ash/FGD 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 

believes that if the proposed rule included a limit on the discharge of combustion residual 

leachate, plants would comply with the limit by recycling the leachate back to the ash/FGD 

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 ash/FGD impoundment because the 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 limits prior to its discharge. Therefore, there are no compliance costs for 

combustion residual surface impoundment leachate. Where this section further addresses the 

costing methodology for combustion residual leachate, it refers to the costs associated with the 

treatment of combustion residual landfill leachate. 

9.2 POPULATION COSTED

An incremental compliance cost for leachate is assessed to any plant identified as 

collecting and discharging leachate from a landfill containing combustion residuals. EPA used 

survey 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. EPA focused on leachate collection and discharge from active, inactive, or open 

landfills. EPA identified 102 plants as discharging landfill leachate from an active, inactive, or 

open landfill containing combustion residuals.55 EPA identified plants that have announced plans 

to retire generating units prior to December 31, 2014 as described in Section 4.4.1. There are no 

conversion costs for plant that are already planned to retire prior to implementation of the ELGs. 

 

54 Since EPA has estimated costs for all plants to transport leachate from the landfill to a treatment system located at 

the main plant area, this will overestimate costs for plants choosing to install the treatment system closer to where 

the leachate is collected. 

55 When the group of plants excluding oil-fired units and units with a capacity of 50 MW or less is evaluated the 

population of plants discharging landfill leachate includes only 101 plants. 
Chapter 9 – Combustion Residual Leachate Cost Methodology 

9-3 

9.3 TREATMENT IN PLACE

For those plants discharging both combustion residual leachate and FGD wastewater, one 

wastewater treatment system is costed to handle the combined flow. EPA identified only one 

plant that operates a biological treatment system, without chemical precipitation pretreatment, to 

treat the combustion residual landfill leachate generated at the plant prior to discharge; EPA did 

not identify any plants that currently operate a chemical precipitation system to treat combustion 

residual landfill leachate. 56 However, there are plants that have treatment in place for FGD 

wastewater and discharge combustion residual landfill leachate. 

Of the plants identified as having some level of treatment in place for FGD chemical 

precipitation (Section 6.1.3), 29 plants also discharge landfill leachate. EPA conducted an 

analysis to determine if the existing FGD wastewater treatment system at these plants would be 

sufficient to treat the amount of combustion residual landfill leachate produced at the plant in 

addition to the FGD wastewater that is currently being treated. EPA compared the design flow 

rate (reported in Part D Section 5.1 of the Steam Electric Survey) for each treatment system to 

the plant-specific wastewater flow (i.e., FGD wastewater plus combustion residual landfill 

leachate). If this new flow FGD wastewater plus combustion residual landfill leachate was less 

than the specified design flow rate for the existing chemical precipitation system, EPA 

determined that the existing system could support the additional flow. EPA identified 10 plants 

that had sufficient capacity to handle the additional combustion residual landfill leachate flow; 

however, 19 plants did not have sufficient capacity. For these 19 plants, EPA estimated costs for 

an additional one-stage chemical precipitation treatment system or one-stage chemical 

precipitation followed by biological treatment system, sized to treat only the combustion residual 

landfill leachate [ERG, 2013; See Appendix 63]. 57

EPA developed an input table, the “Leachate Cost Matrix,” to hold information on which 

types of treatment system costs each plant would incur based on whether or not the plant 

discharges both FGD wastewater and leachate and whether the plant has an existing treatment 

system for FGD wastewater. 

9.4 INPUT TABLE

As discussed in Section 4.1.3, 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 leachate 

treatment. The “Landfill Leachate Input Table” contains the following fields: 

 

56 EPA identified this system after completing the compliance cost calculations; therefore, compliance cost estimates 

currently show a cost for the biological treatment system for this plant. This update will be incorporated into the 

final rule. 

57 This approach may overestimate costs for these 19 plants. It may be more cost effective for these plants to 

upgrade the existing FGD treatment system rather than install a separate treatment system for the landfill leachate. 

EPA estimated costs for a separate treatment system due to insufficient information regarding the existing FGD 

treatment system at these 19 plants and the specific upgrades required to accomocate the leachate. 
Chapter 9 – Combustion Residual Leachate Cost Methodology 

9-4 

 Plant_id: Survey Plant ID. 

 Landfill_id: Survey Landfill ID (only valid for plants completing Version 1 of the 

Steam Electric Survey). 

 Landfill_Type: Type of landfill designation (i.e. active or inactive). 

 SumofLdfl_Leach_Vol_GPD: Leachate production in 2009 in gallons per day, from 

Question F3-12 of the Steam Electric Survey (only completed for plants completing 

Version 1 of the survey). 

 Ldfl_SA: Surface area of individual landfills with leachate collection, from Question 

F3-2 of the Steam Electric Survey (only completed for plants completing Version 1 of 

the survey). 

 Landfills_Acre: Total landfill acreage from Question C1-2 of the Steam Electric 

Survey. 

 Leachate_GPD: Leachate flow in gallons per day, from Question F3-13 for all plants 

completing Version 1 of the Steam Electric Survey. Calculated 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 CBI. CBI flag 

is marked if any data used to populate the input table were marked as CBI by the 

plant. 

 Retired?: Flag indicating that the plant has identified that it will be retiring on or 

before 12/31/2014. 

Section 4.1.3 provides more detail on the methodology used to determine the landfill 

leachate flow rate and a discussion of the “Landfill Leachate Input Table.”. A copy of the 

“Landfill Leachate Input Table” is included in the appendix. 

9.5 CAPITAL COST METHODOLOGY

Capital costs associated with one-stage chemical precipitation and one-stage chemical 

precipitation with biological treatment is included in Sections 6.1.6 and 6.2.5, respectively. The 

following subsections only provide detail on capital cost components unique to costing the 

combustion residual leachate treatment systems. EPA calculated the cost to transport leachate 

from the landfill site back to the main plant for treatment. The additional pieces of equipment 

needed to transport the leachate back to the main plant area include leachate transport pumps and 

a section of stainless steel pipe.58

9.5.1 Purchased Equipment Costs: Leachate Transport Pump 

EPA costed four 100 percent capacity. skid-mounted, horizontal centrifugal pumps to 

move leachate from the landfill (or leachate collection area) to the location of the wastewater 

treatment system, assumed to be near the center of the plant. EPA designed two of these pumps 

 

58 Plants may also install fiberglass reinforced plastic (FRP) piping to transport the leachate. EPA is evaluating both 

piping costs to determine which is more cost effective and will update the cost estimate post-proposal as appropriate. 
Chapter 9 – Combustion Residual Leachate Cost Methodology 

9-5 

to function as booster pumps to the two main pumps. These pumps are modeled off the 

wastewater forwarding pumps costed for the one-stage chemical precipitation treatment system 

(see Section 6.1.6.1). EPA used Equation 9-1 to estimate the capital cost of the leachate transport 

pump: 

Leachate Transport Pump Cost (2010$) = Leachate Pump Qty × [2914 × ln(Capacity Factor × 

 Leachate GPM) – 3090.1] × Pump Freight Factor × (Cost Index 2010 / Cost Index 2011)(9-1) 

where: 

Leachate Pump Qty = Number of pumps costed, four, 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], 

Leachate GPM = Leachate flow in gallons per minute (see Section 4.1.3),

Pump Freight Factor = Factor that accounts for freight cost as a percentage of 

purchase cost, 1.04 (see Section 6.1.6.1), 

Cost Index 2010 = 183.5, and 

Cost Index 2011 = 185. 

9.5.2 Purchased Equipment Costs: Leachate Transport Piping

EPA costed a length of stainless steel pipe to span from the landfill back to the main plant 

area. As described in Section 9.1, EPA estimated that the median distance from an on-site 

landfill to the plant center is 1.3 miles. EPA developed the following equation to calculate the 

cost of the piping; note that the cost per foot of pipe changes based on the size (e.g., diameter) of 

pipe needed. 

EPA also estimated freight costs for the piping based on weight and a shipping distance 

of approximately 500 miles using quotes from FreightCenter.com. Freight costs were equal to 

approximately 0.9 percent of purchase costs (i.e., Freight Factor = 1.009). 

Leachate Transport Piping Cost (2010$) = Pipe Cost × Distance × Pipe Freight Factor ×Cost 

 Index 2010 / Cost Index 2011 (9-2) 

where: 

Pipe Cost = Cost of the stainless steel pipe in dollars per foot, (see 

below for calculated values based on flow rate), 

Distance = Estimated distance from an on-site landfill to treatment 

system at the plant center, 6,864 feet (1.3 miles), 

Pipe Freight Factor = Factor that accounts for freight cost as a percentage of 

purchase cost,1.009, 
Chapter 9 – Combustion Residual Leachate Cost Methodology 

9-6 

Cost Index 2010 = 183.5, and 

Cost Index 2011 = 185. 

 For leachate flow in gpd 0 – 158,400 gpd: 

Pipe Cost = 8.80 dollars per foot 

 For leachate flow in gpd 158,400 – 288,000 gpd:

Pipe Cost = 18.45 dollars per foot 

 For leachate flow in gpd 288,000 – 576,000 gpd:

Pipe Cost = 26.30 dollars per foot 

 For leachate flow in gpd 576,000 GPD – 1,008,000 gpd: 

Pipe Cost = 47.55 dollars per foot 

 For leachate flow in gpd 1,008,000 – 1,584,000 gpd: 

Pipe Cost = 73.92 dollars per foot 

 For leachate flow in gpd 1,584,000 – 2,880,000 gpd:

Pipe Cost = 126.10 dollars per foot

9.6 O&M COST METHODOLOGY

O&M costs associated with one-stage chemical precipitation and biological treatment can 

be found in Sections 6.1.7 and 6.2.6, respectively. EPA identified electricity used to operate the 

leachate transport pumps as the only O&M cost associated with the additional equipment needed 

to transfer leachate from the collection location to the treatment system. 

EPA modeled the electricity costs for the leachate transport pumps after the electricity 

requirements of the wastewater forwarding pump for one-stage chemical precipitation (see 

Section 6.1.7.5). Electricity requirements were calculated assuming only two of the four pumps 

are operating at any one time, using Equation 9-3. 

Leachate Transport Pump Electricity (kWh/year) = (0.0151 × Capacity Factor × Leachate GPM 

 + 2.0191) × hp KW Factor × Operating Hours × 365 dpy × Leachate Pump Qty / 2 (9-3) 

where: 

Capacity Factor = Equipment sizing factor (see Section 6.1.5), 

[Redacted], 

Leachate GPM = Leachate flow in gallons per minute (see Section 4.1.3),

hp KW factor = Factor to convert horsepower to kilowatts, 0.7456 

KW/hp, 

Operating Hours = Operating hours of the system, 24 hpd, and 
Chapter 9 – Combustion Residual Leachate Cost Methodology 

9-7 

Leachate Pump Qty = Number of pumps costed, four. 

EPA added the annual electricity requirement of the leachate transport pump to the total 

electricity requirement of the one-stage chemical precipitation system (see Section 6.1.7.5). 

9.7 MERCURY ANALYZER COST

All plants costed for either a combustion residual leachate treatment system or an FGD 

treatment system incurred costs to install and operate a mercury analyzer and treated effluent 

recycle system. Section 6.1.9 discusses costs to install and operate a mercury analyzer and 

effluent recycle system.. For those plants costed for two separate treatment systems, one for FGD 

wastewater and one for combustion residual leachate alone, EPA included mercury analyzer 

costs for each treatment system. 

9.8 SLUDGE TRANSPORTATION AND DISPOSAL COSTS

EPA determined dewatered sludge generation rates for the chemical precipitation 

treatment technology option using the methodology previously described in Section 6.1.8. EPA 

estimated the solids generated from the chemical precipitation with biological treatment 

technology option using the methodology described in Section 6.2.7.

Sections 5.3 and 5.4 discuss costs for the transportation and disposal of the sludge 

generated by each technology option. 

9.9 COMPLIANCE MONITORING COST

All plants costed for either a combustion residual leachate treatment system or an FGD 

treatment system incurred a cost for compliance monitoring. Section 5.2 discusses costs for 

compliance monitoring. 

9.10 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 

impoundment for leachate collection will continue to do so. 

9.11 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 one-stage chemical precipitation technology option and the 

chemical precipitation with biological treatment technology option. The cost output generated by 

the model includes a breakout of specific capital and O&M cost elements, including equipment 

costs, installation costs, operating labor, maintenance labor, and energy costs. The output also 
Chapter 9 – Combustion Residual Leachate Cost Methodology 

9-8 

includes costs for the common cost elements described in Chapter 5. A list of the plant-level 

costs for each technology option is included in the appendix.59 

EPA used information contained in the “Leachate Cost Matrix” to estimate compliance 

costs under Option 4. For this regulatory option plants treating FGD wastewater alone or FGD 

wastewater and leachate with the same treatment system are required to comply with effluent 

limitations associated with the biological treatment system, while treatment systems handling 

only combustion residual leachate are required to comply with the effluent limitations associated 

with chemical precipitation. EPA has included separate tables in the appendix to represent the 

estimated costs associated with Option 4. 

9.12 REFERENCES

1. Eastern Research Group, Inc (ERG). 2013. Supplemental Costs and Loadings 

Documentation. (19 April). DCN SE01825. 

2. RSMeans. 2011. Building Construction Cost Data, 69th Edition. (January). DCN 

SE02952.

 

59 Because EPA evaluated costs for the treatment of combustion residual leachate with FGD wastewater, where both 

are discharged and could be combined in the same system, EPA did not calculate costs to treat the combustion 

residual leachate separately for each plant. For those plants where the combustion residual leachate and FGD 

wastewater are expected to be combined, EPA only calculated costs for the combined treatment system. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-1 

CHAPTER 10 

POLLUTANT LOADINGS AND REMOVALS METHODOLOGY 

This chapter discusses annual pollutant loadings and removal estimates for the steam 

electric industry for each proposed regulatory option. EPA estimated the pollutant loadings and 

removals from existing steam electric power plants to evaluate the effectiveness of the treatment 

technologies, estimate benefits gained from removing pollutants discharged from plants, and 

evaluate the cost-effectiveness of the regulatory options in reducing the pollutant loadings. EPA 

defined baseline and post-compliance pollutant loadings as follows: 

 Baseline Loadings. Pollutant loadings, in pounds per year, in steam electric 

wastewater being discharged to surface water or through publicly owned treatment 

works (POTWs) to surface water prior to implementing controls to comply with the 

proposed rule. 

 Post-Compliance Loadings. Estimated pollutant loadings, in pounds per year, in 

steam electric wastewater after implementation of the proposed rule; these are also 

referred to as treated loadings. EPA calculated these loadings assuming that all steam 

electric power plants would operate wastewater treatment and pollution prevention 

technologies equivalent to the technology bases for the regulatory option. 

 Pollutant Removals. The difference between the baseline loadings and postcompliance loadings for each regulatory option. 

Some aspects of the proposed effluent limitations guidelines and standards (ELGs) (e.g., 

applicability changes) would likely not lead to a change in pollutant loadings. Other aspects of 

the proposed ELGs would likely lead to a change in pollutant loadings for a subset of plants. 

These plants typically are the plants that generate one or more of the wastestreams for which 

EPA is proposing new limitations or standards. This section describes the detailed pollutant 

loadings evaluation EPA performed to quantify the removal in pollutant loadings associated with 

the regulatory options for the proposed ELGs. Specifically, EPA determined baseline and postcompliance pollutant loadings for the following wastestreams: flue gas desulfurization (FGD) 

wastewater, fly ash transport water, bottom ash transport water, combustion residual leachate, 

gasification wastewater, and flue gas mercury control wastewater. 60 The currently operating 

gasification generating units operate vapor-compression evaporation systems (i.e., the 

technology basis for the preferred option); therefore, EPA determined that the baseline loadings 

are equal to the post-compliance loadings. Similarly, plants currently manage their flue gas 

mercury control wastes in a way that avoids pollutant discharge to surface waters, so the baseline 

loadings for these wastewaters are also equal to the post-compliance loadings. Additionally, 

because nonchemical metal cleaning wastes are already subject to the proposed best available 

control technology (BAT) limitations, based on the current best practicable control technology 

(BPT) standard, the plants generating and discharging nonchemical metal cleaning wastes are 

 

60 As described in Section 9.1, EPA expects that plants generating surface impoundment leachate will comply with 

the regulation by returning the leachate back to the impoundment from which it was generated, which will result in 

no net increase/decrease in the pollutant loadings from the plant. Therefore, EPA did not assess compliance costs or 

pollutant loadings associated with surface impoundment leachate. EPA did, however, calculate pollutant loadings 

associated with landfill leachate. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-2 

already meeting these standards. In addition, EPA is proposing to exempt from new limitations 

and standards any nonchemical metal cleaning wastes generated and authorized for discharge 

without copper and iron limits. As a result, all facilities are either already in compliance or will 

be exempt from the requirements and , therefore, EPA finds that the baseline loadings are equal 

to the post-compliance loadings. The remainder of this chapter applies to FGD wastewater, fly 

ash transport water, bottom ash transport water, and combustion residual leachate. All tables and 

figures referenced in this chapter are presented at the end of the chapter. 

10.1 GENERAL METHODOLOGY FOR ESTIMATING POLLUTANT REMOVALS

For each plant discharging an evaluated wastestream (i.e., FGD wastewater, ash transport 

water, and combustion residual leachate), EPA calculated plant-level pollutant removals for each 

of the technology options evaluated for that wastestream. For example, for any plant discharging 

FGD wastewater, EPA calculated a baseline loading and loadings associated with each treatment 

option (i.e., one-stage chemical precipitation, one-stage chemical precipitation with biological 

treatment, and one-stage chemical precipitation with vapor-compression evaporation). On a 

plant-level basis, EPA calculates baseline loadings by multiplying the average pollutant 

concentration in the discharge by the plant-specific wastewater discharge flow rate to generate 

the mass of specific pollutant discharged per year, in pounds/year. 

EPA used sampling data, gathered through the EPA sampling program described in 

Section 3.3, as well as publicly available sources, to characterize the baseline loading and postcompliance loading concentrations for each evaluated wastestream. Section 10.2 presents the 

data sources and average discharge pollutant concentrations for the baseline and each of the 

technology options associated with the evaluated wastestreams. 

Next, for each evaluated wastestream discharged by a specific plant, EPA used data from 

the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric 

Survey) to determine the plant’s discharge flow rate. In cases where survey data were 

insufficient, EPA developed a methodology for estimating flow rates. Section 10.3 provides 

details on these wastewater flow rates. 

EPA calculated baseline pollutant loadings and post compliance treatment loadings for 

each plant discharging an evaluated wastestream using the plant-specific wastewater flow for the 

wastestream and the average pollutant concentration of the specific wastestream according to 

Equation 10-1. 

Pollutant Loading (lbs/yr) = Flow Rate × Pollutant Concentration × 2.20462 lb/10,000,000 mg × 

 1,000 L / 264.17 gal (10-1) 

where: 

Flow Rate = The flow rate of the wastestream being discharged, in 

gallons per year (gpy), and 

Pollutant Concentration = The average concentration of a specific pollutant 

present in the wastestream, in milligrams per liter. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-3 

EPA identified several plants that report transferring wastewater to a POTW rather than 

discharging directly to surface water. For these plants, EPA adjusted the baseline loadings to 

account for pollutant removals expected from POTWs for each analyte. For each pollutant of 

concern (POC), Table 10-1 provides the percent removal expected from well-operated POTWs, 

as reported in the Memo to the 2006 Effluent Guidelines Program Plan Docket [ERG, 2006]. For 

any plant identified as discharging a wastestream to a POTW, EPA used the calculated baseline 

loadings and the values shown in Table 10-1 to calculate the amount of pollutant discharged 

from the POTW to surface water according to Equation 10-2. 

 Indirect Pollutant Loading (lb/yr) = Pollutant Loading × (1- POTW Removal) (10-2) 

where: 

Pollutant Loading = The loadings from a specific pollutant if it were 

discharged directly, in pounds/year, and 

POTW Removal = The estimated percentage of the pollutant loading that 

will be removed by a POTW. 

In addition to expressing pollutant loadings in pounds of pollutant discharged per year, 

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

61 EPA calculated a toxic-weighted pound equivalent (TWPE) value for each pollutant 

discharged to compare mass loadings of different pollutants based on their toxicity. To perform 

this comparison, EPA multiplied the mass loadings of pollutant in pounds/year by the pollutantspecific TWF to derive a “toxic-equivalent” loading (lb-equivalent/yr), or TWPE. Section 10.4 

discusses the wastestream mass loading (i.e., unweighted loadings) and TWPE loadings in more 

detail. 

10.2 WASTESTREAM CHARACTERIZATION AND DATA SOURCES

As discussed earlier, loadings calculations require a pollutant-specific concentration to 

determine the mass loadings. EPA used a variety of data sources to generate characterization 

data for each evaluated wastestream. For each wastestream, EPA excluded all pollutants that 

were not measured above the quantitation limit in all of the samples representing the baseline 

effluent discharges for that specific wastestream. Therefore, if a pollutant was measured above 

the quantitation limit at least once in the baseline effluent concentration dataset, that pollutant 

was included in the loadings analysis. EPA generated a separate set of characterization data for 

baseline and each post-compliance technology basis. Section 10.2.1 presents the data sources and 

characterization for FGD wastewater, Section 10.2.2 presents ash transport water, and Section 

10.2.3 presents combustion residual landfill leachate. 

 

61 A listing of pollutant-specific TWF values can be found in the Toxic Weighting Factor Development in Support of 

CWA 304(m) Planning Process [ERG, 2006]. 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. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-4 

10.2.1 FGD Wastewater Characterization

EPA is considering three technology options as the basis of proposed discharge 

requirements for FGD wastewater: one-stage chemical precipitation, one-stage chemical 

precipitation with biological treatment, and one-stage chemical precipitation with vaporcompression evaporation. Table 10-2 summarizes the concentration data sets that were included 

in the baseline and post-compliance FGD loadings analysis and their sources. EPA performed the 

following review, made substitutions, as appropriate, and performed the following analyses with 

the sampling data results, where appropriate, prior to using them in the technology option 

loadings calculations: 62

 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., 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 for all analytes. 

 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 

sample collection. For the purpose of the loadings calculations, EPA made the 

following assumptions based on the results of this field blank analysis: 

 If the sample result was less than five times the field blank result, then the sample 

result was treated as a non-detect; 

 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; and 

 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. EPA made the following assumptions when 

averaging the duplicate results: 

 If one value was quantified and the other value was not quantified above the 

quantitation limit, then EPA used one-half the sample-specific quantitation limit for 

the non-quantified result in calculating the average; 

 If both values were not quantified above the sample-specific quantitation limit, then 

EPA used one-half the quantitation limit for both non-quantified results in calculating 

the average; and 

 Both qualified and unqualified data were used in the calculation. 

 

62 Only EPA sampling activities collected and analyzed field blank and duplicate samples. EPA CWA 308 sampling 

program did not include duplicate sample analysis therefore, only the field blank analysis was conducted on this data 

set. The plant-provided self-monitoring data included no field blank or duplicate samples. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-5 

The following subsections discuss the specific data used to calculate the mass and TWPE 

loadings for each option, starting with the baseline characterization. 

10.2.1.1 Baseline FGD Wastewater Characterization 

As discussed in Section 4.1.1, EPA identified 117 plants that operate wet FGD systems 

and discharge FGD wastewater. For the FGD dischargers, EPA calculated baseline loadings by 

assigning pollutant concentrations based on the type of treatment system currently in place at the 

plant. EPA assigned treatment in place for this wastewater for one of four classes of treatment: 

surface impoundment, chemical precipitation, biological treatment, and vapor-compression 

evaporation. As discussed in Section 4.1.1, EPA used survey data to determine the baseline FGD 

wastewater treatment in place. Based on survey responses, EPA categorized 47 plants as 

operating a treatment system more advanced than a surface impoundment: 

 Forty plants operate a one-stage chemical precipitation system; 

 Five plants operate a biological treatment system;63 and 

 One plant operates a vapor-compression evaporation system.64

EPA categorized all plants not operating one of these three types of treatment systems as 

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. 

Surface impoundments use gravity to remove particulates from wastewater, reducing the 

amount of TSS and particulate forms of other specific pollutants in the wastewater. EPA’s 

sampling program collected and analyzed the untreated FGD wastewater from seven steam 

electric power plants operating wet FGD systems that use either chemical precipitation or 

chemical precipitation followed by biological treatment to treat the FGD wastewater (see Section 

3.3 for a description of these sampling activities and plants). Based on analytical data for the 

untreated FGD wastewater at these sampled plants, EPA estimated the effluent concentration 

from a surface impoundment by assuming the surface impoundment will remove most of the 

particulate phase metals from the wastewater but not dissolved. EPA calculated proxy values 

representing impoundment effluent concentrations for each analyte using the data for each of 

these seven EPA sampled plants. The methodology for calculating these proxy values is 

described below. EPA also obtained surface impoundment effluent data from a steam electric 

power plant that treats only FGD wastewater in an impoundment. EPA averaged the surface 

 

63 Six plants currently operate biological treatment systems, but at the time the costs and loadings were developed, 

EPA had only identified five plants with biological treatment systems. Therefore, only five of the six plants were 

identified as having biological treatment in place for these analyses. 

64 Through additional information collected during the rulemaking, EPA identified two additional plants that plan to 

install a vapor-compression evaporation system to treat FGD wastewater by 2014 when the rule is promulgated. 

EPA identified these systems after completing the pollutant removals; therefore, pollutant removal estimates 

currently show removals under the vapor-compression evaporation technology option. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-6 

impoundment data along with the estimated impoundment effluent concentrations from the seven 

sampled plants for each analyte to generate an average effluent concentration data set for FGD 

surface impoundments based on the eight plants. Table 10-3 presents the average 

characterization data used to calculate baseline loadings for plants currently treating FGD 

wastewater in a surface impoundment prior to discharge. 

Approximately 40 percent of plants discharging FGD wastewater use a more advanced 

treatment system. For those plants currently operating a one-stage chemical precipitation system, 

biological treatment system, or vapor-compression evaporation system, EPA used the 

concentration data sets associated with the post-compliance technology options to calculate 

baseline loadings. Section 10.2.1.2 discusses the characterization of one-stage chemical 

precipitation systems. Sections 10.2.1.3 and 10.2.1.4 discuss the characterization of one-stage 

chemical precipitation systems with biological treatment or with vapor-compression evaporation 

systems, respectively. 

Calculating FGD Settling Pond Effluent Concentrations

As described earlier, EPA used the FGD wastewater data collected during the sampling 

program and monitoring data provided by Progress Energy Carolinas’ Roxboro Steam Electric 

Plant (Roxboro) to estimate the effluent concentrations from a surface impoundment used to treat 

FGD wastewater. EPA made the following assumptions and performed the following analyses to 

calculate the loadings associated with the effluent from a FGD surface impoundment: 

 Metal Concentrations in the Solid Phase: As part of EPA’s sampling program, the 

laboratories analyzing the scrubber purge wastestreams were required to perform a 

biphasic separation of the scrubber purge sample and analyze both the solid and 

aqueous phase for each analyte. EPA only required the laboratory to perform the 

analysis if the wastewater sample contained greater than one percent solids. Both 

laboratories performed the biphasic separation for the FGD wastewater samples from 

Hatfield’s Ferry, Keystone, and Miami Fort; however, 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 converted the 

wet weight solid concentrations to dry weight solid concentrations using Equation 

10-3. 

%Solids(of solid phase)

L

C mg

1kg

1L - [1- %Solids(of solid phase)] kg

C mg

kg

C mg

wet sample

Dry 































  















 (10-3) 

where: 

CDry = Dry weight concentration of the analyte in the solid 

phase of the sample, 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-7 

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, and 

%Solids (of solid 

phase) 

= Percent solids present in the solid phase of the sample. 

Additionally, EPA calculated solid phase concentrations for the plants where the FGD 

wastewater sample contained less than one percent solids. EPA performed this 

calculation for the Allen, Belews Creek, Dickerson, and Pleasant Prairie FGD 

wastewater data. EPA used Equation 10-4 to calculate dry weight solid concentrations 

for each analyte from these plants. 

1000 ug

1mg

kg

1 10 mg

C (mg/L)

C (ug/L)-C (ug/L) C (mg/kg)

6

TSS

Total Dissolved

Dry 

  

(10-4) 

where: 

CDissolved = Dissolved concentration of the analyte in the sample, 

CDry = Dry weight concentration of the analyte in the solid 

phase of the sample, 

CTotal = Total concentration of the analyte in the sample, and 

CTSS = Total suspended solids concentration in the sample. 

 Calculating Settling Pond Effluent Concentrations for Metals from FGD Wastewater 

Data: To estimate the effluent concentrations of metals from a surface impoundment 

used to treat FGD wastewaters based on scrubber purge concentration data, EPA 

assumed that the surface impoundment would only achieve removals of metals 

present in the particulate phase of the sample and, therefore, would not remove metals 

present in the dissolved phase. EPA also assumed that the surface impoundment 

would achieve an effluent TSS concentration of 30 mg/L, which is the current 30-day 

average effluent limit for low-volume wastewaters set in 40 CFR 423 for the best 

practicable control technology currently available. EPA used this methodology to 

estimate the surface impoundment effluent concentration for all data collected from 

the sampled plants. 

EPA derived the basis for the assumption that the metals in the dissolved phase of the 

FGD wastewater 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 coalfired power plants. For six of the plants, data are presented for a filtered sample, a 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-8 

“settled” sample, and a total sample. In the report, EPRI indicates that the “settled” 

sample was collected by allowing the sample to settle for one hour, and then an 

aliquot was collected from five 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 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 

10-4 and Table 10-5. Table 10-4 presents the data for three of the six plants, and 

Table 10-5 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 metals 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 assumed that the concentration of the metal present in 

the solid phase of the sample at the effluent is equal to the concentration of the metal 

present in the solid phase of the sample in the FGD wastewater. Additionally, EPA 

assumed a TSS concentration of 30 mg/L at the effluent. These two assumptions 

allowed EPA to calculate the solid phase contribution to the total concentration in the 

surface impoundment effluent. Additionally, EPA assumed that the dissolved 

concentration in the effluent was equal to the dissolved concentration in the FGD 

wastewater. Finally, EPA assumed that the total concentration in the surface 

impoundment effluent is equal to the solid phase contribution plus the dissolved 

phase contribution. Equation 10-5 was used to perform this calculation. 

C (ug/L) 1mg

1000 ug

1 10 mg

1kg

L

30 mg

kg

C mg C (ug/L) 6 Dissolved

Dry

Settling  

   

(10-5) 

where: 

CDissolved = Dissolved concentration of the analyte in the 

wastewater sample, 

CDry = Dry weight concentration of the analyte in the solid 

phase of the wastewater sample, and 

CSettling = Calculated concentration of the analyte in the effluent 

from a surface impoundment. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-9 

 Estimating Settling Pond Effluent Concentrations for Classicals: To estimate the 

effluent concentrations of classicals 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 

the effluent from a surface impoundment used to treat FGD wastewater and the data 

EPA collected from Cardinal represented the 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). 65 Based on the results of the comparison, EPA made the 

following assumptions to estimate the settling pond effluent concentrations for the 

classical analytes: 

- TSS: EPA assumed a concentration of 30 mg/L, based on the assumption for the 

metals calculation methodology; 

- TDS: EPA assumed the concentration at the effluent is equal to the influent 

concentration (i.e., no removal); 

- Chloride: EPA assumed the concentration at the effluent is equal to the influent 

concentration (i.e., no removal); and 

- Ammonia, biological oxygen demand (BOD), chemical oxygen demand (COD), 

cyanide, nitrate/nitrite, sulfate, total Kjeldahl nitrogen (TKN), and total 

phosphorus: EPA did not estimate a concentration for these pollutants in the 

effluent from a surface impoundments for the plants with sampling data.66

EPA then took the Roxboro monitoring data and calculated an average concentration for 

each analyte for which data were available. Using the average Roxboro surface impoundment 

effluent concentrations and the calculated effluent surface impoundment concentrations for each 

of the sampled plants, EPA calculated an average concentration for each analyte. This 

calculation resulted in an overall average concentration for each analyte, which EPA then used to 

calculate the loadings. 

Finally, although EPA did not develop a methodology to estimate the effluent 

concentrations for COD, cyanide, nitrate/nitrite, and total phosphorus from a surface 

impoundment based on the FGD wastewater concentrations, EPA believes that these analytes are 

present in the effluent from the surface impoundment. Therefore, to account for these pollutants 

in the loadings analysis, EPA assumed that the concentrations of these pollutants were equal the 

concentrations calculated for the one-stage chemical precipitation system effluent. Table 10-3 

presents the average concentration data used to calculate baseline loadings for plants currently 

treating FGD wastewater with a surface impoundment prior to discharge. 

 

65 The influent and effluent samples collected from the surface impoundment do not represent paired samples. 

66 BOD, COD, TKN, and total phosphorus do not have TWFs and therefore, do not contribute to the calculated 

TWPE for the FGD loadings. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-10 

10.2.1.2 Baseline and Post-Compliance One-Stage Chemical Precipitation 

Characterization 

As part of the sampling activities described in Section 3.3, EPA identified and collected 

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 three systems operating consistently with the one-stage chemical precipitation 

technology basis. These three plants operate one-stage chemical precipitation systems that 

include the addition of organosulfide. 

The treatment systems at these plants have similar operations; however, the plants do 

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 limits. 

To calculate the pollutant concentrations for the one-stage chemical precipitation 

technology option, EPA first calculated an average concentration for each analyte using only the 

four-day EPA sampling data for each plant for which data were available. EPA included only 

total concentrations except for hexavalent chromium, which is analyzed only as a dissolved 

constituent. EPA then calculated an average concentration for each analyte at each plant by using 

the four CWA 308 monitoring data results along with the average of the four-day EPA sampling 

data (i.e., treating these as five results and calculating the average). 

Using the average concentrations from the three plants, as calculated above, EPA then 

calculated an overall average concentration for each of the analytes shown in Table 10-6. EPA 

used this average concentration to calculate the post-compliance loadings that would be 

discharged by plants that currently operate surface impoundments if they were to install the 

chemical precipitation technology. EPA also used the average concentrations presented in Table 

10-6 to calculate the baseline loadings for any plant currently operating a chemical precipitation 

treatment system as FGD wastewater treatment. 

As explained above, the values presented in Table 10-6 reflect three plants identified as 

operating consistently with the technology basis, and EPA has applied these values to all plants 

that operate chemical precipitation systems as their baseline concentrations. As discussed in 

Section 10.2.1.1, EPA classified 38 other plants as operating chemical precipitations systems. 

However, these 38 plants do not operate their chemical precipitation system in the same manner 

as the technology basis (or have all the components included in the technology basis) and would 

likely discharge greater pollutant concentrations than the systems reflecting the technology basis. 

Further, for these 38 plants that operate chemical precipitation systems that are not equivalent to 

the technology basis, the baseline and post-compliance loadings are identical, and EPA 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-11 

calculates no removals for these plants, even though these plants are being assessed compliance 

costs to upgrade the system to operate similarly to the technology basis. 67

10.2.1.3 Baseline and Post-Compliance One-Stage Chemical Precipitation and Biological 

Treatment Characterization 

EPA identified and collected data from two plants operating chemical precipitation 

systems in conjunction with biological treatment systems that represent the biological treatment 

technology option for the proposed rule. After conducting an engineering review of the data, 

EPA determined that both plants operate systems consistent with the one-stage chemical 

precipitation with biological treatment technology option. Both of the sampled plants operate 

chemical precipitation systems followed by anoxic/anaerobic biological treatment systems 

specifically designed for selenium removal. EPA used the data from both plants to represent 

treatment performance of a one-stage 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 the one-stage chemical precipitation (with sulfide precipitation) followed 

by a biological treatment system that forms the basis of the option (see Section 6.2 for complete 

description). 

EPA has multiple sets of data for these two plants, including EPA sampling data, Clean 

Water Act (CWA) 308 sampling data, and self-monitoring data, to calculate pollutant loadings 

associated with this technology option. To calculate the average pollutant concentrations for the 

biological treatment system technology option, EPA first compared long-term self-monitoring 

data provided by the plants to EPA sampling data and CWA 308 monitoring data to determine 

which analytes were represented in different sets of data. In cases where an analyte was not 

represented in the long-term self-monitoring data, but was represented in the EPA sampling and 

CWA 308 monitoring data, EPA averaged the four-day EPA sampling results and then combined 

that average with the four CWA 308 monitoring data results (i.e., EPA treated them as five 

results) for each plant. EPA then averaged these five results to calculate an overall plant-level 

average concentration for each of those analytes. In cases where an analyte was represented in 

the long-term self-monitoring data provided by the plant, the EPA sampling data, and the CWA 

308 monitoring data, EPA averaged all sample results to calculate a plant-level average 

concentration for each analyte. When combining the industry self-monitoring data with EPA’s 

sampling results (both four-day EPA sampling and CWA 308 monitoring), there were some 

instances of overlap with two sample results occurring on the same day. In these cases, the two 

results were averaged together to calculate one average concentration for each day of sampling 

before calculating an average concentration for each analyte. 

Using the average concentrations from the two BAT plants, EPA calculated an overall 

average concentration for each analyte. These are presented in Table 10-7. EPA used the average 

concentrations to calculate the post-compliance loadings that would be discharged by plants 

currently operating surface impoundments or chemical precipitation systems if they were to 

install all components of the biological technology option. EPA also used the average 

 

67 This approach results in an underestimate of the pollutant removals achieved by these 38 plants. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-12 

concentrations presented in Table 10-7 to calculate the baseline loadings for any plant currently 

operating chemical precipitation and a biological treatment system as FGD wastewater treatment. 

The average concentration used to calculate baseline and post-compliance loadings for 

the chemical precipitation and biological treatment system technology basis, presented in Table 

10-7, is based on two plants identified as operating consistently with the technology basis. As 

discussed in Section 10.2.1.1, EPA classified five plants as operating biological treatment 

systems.68 For each plant classified as a baseline biological treatment system, EPA calculated the 

baseline loadings using the average concentration presented in Table 10-7. Two of these plantsdo 

not operate consistently with the technology basis and likely discharge greater pollutant 

concentrations than the system reflecting the technology basis.69 Further, for these two plants, 

the baseline and post-compliance loadings are identical and show no additional removals even 

though these plants are being assessed compliance costs to upgrade the system to achieve the 

technology basis.70

10.2.1.4 Baseline and Post-Compliance One-Stage Chemical Precipitation and VaporCompression Evaporation Characterization 

EPA conducted an engineering review of the data for the two plants operating vaporcompression evaporation system. Because only one plant matches the technology basis and 

operates a hydroxide-sulfide chemical precipitation system followed by softening, a brine 

concentrator, and crystallization system, EPA used data from this plant to represent the 

technology option. 

To calculate the average pollutant concentrations for the vapor-compression evaporation 

treatment system technology option, EPA first calculated an average concentration by analyte for 

each of the two wastestreams at the plant (i.e., brine concentrator distillate and crystallizer 

condensate) using available sampling data (i.e., three-day EPA sampling data). For this plant, 

EPA collected and analyzed only total concentrations; therefore, the Agency did not have 

dissolved concentrations or hexavalent chromium data to use in the analysis. 

Using the average concentrations from the two streams (i.e., brine concentrator distillate 

and crystallizer condensate), EPA calculated an overall average concentration for each analyte, 

shown in Table 10-8.71 EPA used this average concentration to calculate the post-compliance 

loadings that would be discharged by plants currently operating surface impoundments, chemical 

precipitation systems, or biological treatment systems if they were to install all components of 

the vapor-compression evaporation technology option. EPA also used the average concentrations 

 

68 Six plants currently operate biological treatment systems, but at the time the costs and loadings were developed, 

EPA had only identified five plants with biological treatment systems. Therefore, only five of the six plants were 

identified as having biological treatment in place for these analyses. 

69 Of the total five baseline biological treatment plants, only three are classified as operating consistently with the 

technology basis. 

70 This approach results in an underestimate of the pollutant removals achieved by these two plants. 

71 EPA used both the brine concentrator distillate and crystallizer condensate streams to calculate the loadings 

because both wastestreams could be discharged. The vapor-compression system at Brindisi is operated as a zerodischarge 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. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-13 

presented in Table 10-8 to calculate the baseline loadings for any plant currently operating 

chemical precipitation and a vapor-compression evaporation treatment system as FGD 

wastewater treatment. 

10.2.2 Ash Impoundment Wastewater Characterization

During this rulemaking effort, EPA relied on publicly available data sources to 

characterize the effluent stream from ash impoundments at steam electric power plants; these 

sources are listed below: 

 EPA ash impoundment sampling data from the detailed study [U.S. EPA, 2009], 

 Electric Power Research Institute (EPRI) Power Plant Integrated Systems-Chemical 

Emissions Study (PISCES) Reports [EPRI, 1997-2001], 

 Permit application data, 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], and 

 The Steam Electric Technical Questionnaire Database [ERG, 2012a]. 

Each of the five data sources was discussed in Chapter 3. EPA used information available 

from each data source to characterize the impoundment/outfall as either a fly ash impoundment, 

bottom ash impoundment, or combined ash impoundment. For the purposes of this analysis, EPA 

used the following criteria to make those determinations: 

 Fly ash impoundment: An impoundment/outfall that receives fly ash transport water 

and does not receive bottom ash transport water or any other combustion residual 

wastes. The impoundment may also receive other types of wastewater (e.g., low 

volume wastewaters, cooling water). 

 Bottom ash impoundment: An impoundment/outfall that receives bottom ash 

transport water and does not receive fly ash transport water or any other combustion 

residual wastes. The impoundment may also receive other types of wastewater (e.g., 

low volume wastewaters, cooling water). 

 Combined ash impoundment: An impoundment/outfall that receives both fly ash 

transport and bottom ash transport water. The impoundment may also receive other 

types of wastewater (e.g., low volume wastewaters, cooling water). 

EPA used the concentration data obtained from the data sources described in Chapter 3 to 

calculate the average pollutant concentration in fly ash transport water, bottom ash transport 

water, and combined ash transport water. EPA notes that, because the data associated with these 

impoundments may include other wastestreams (e.g., cooling water), the concentrations may be 
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10-14 

diluted and therefore, may underestimate the pollutant loadings.72 For each data point, EPA first 

identified the type of impoundment system the data represents (i.e., fly ash impoundment, 

bottom ash impoundment, combined ash impoundment). EPA then calculated an average 

pollutant concentration for each impoundment for which EPA had data. For example, if a plant 

had pollutant concentration data for their fly ash impoundment for more than one day, EPA 

averaged all the fly ash impoundment concentration data for that specific pollutant to get a single 

value to represent the average concentration of that pollutant in the effluent from the fly ash 

impoundment. Equation 10-6 was used to calculate the average concentration of a pollutant in 

the effluent from a fly ash impoundment. 

Fly Ash Impoundment Concentration = the average across all concentration results for each 

 pollutant = Σ Fly Ash Impoundment Concentration / Number of data points (10-6) 

EPA used the same equation to calculate the average concentration of a pollutant in the 

effluents from bottom ash impoundments and combined ash impoundments. For some data 

sources, there may only be one data point, and therefore, the average is the same as the single 

data point. When performing this calculation, EPA reviewed the data and, as appropriate, made 

some substitutions to the data sets. EPA set nondetects equal to one-half the quantitation limit for 

the detailed study sampling data because EPA knew the quantitation limit. 73 For the other data 

sets (i.e., EPRI, 1982 TDD, and Form 2C), EPA could not confirm whether the non-detect results 

were presented as less than the quantitation limit or less than the MDL (or some other value); 

therefore, EPA set the non-detects equal to the value provided. 

After calculating an average concentration for each type of impoundment at the plantspecific level, EPA calculated an industry-level average pollutant concentration for each type of 

impoundment for which EPA had data by averaging the plant-level average concentrations for 

each type of impoundment. For example, EPA calculated an industry average pollutant 

concentration for a fly ash impoundment by calculating the average concentration across all fly 

ash impoundments for which EPA had data, using the average plant-specific fly ash 

impoundment pollutant concentrations from Equation 10-6. 

Industry Fly Ash Impoundment Concentration = average across all concentration results for each 

pollutant = Σ Fly Ash Impoundment Concentration / Number of Fly Ash Impoundments (10-7) 

EPA used the same equation to calculate the industry average concentration of pollutants 

in the effluent from bottom ash impoundments and combined ash impoundments. Table 10-9 

presents the average pollutant concentration for all three types of ash impoundments (i.e., fly ash 

impoundment, bottom ash impoundment, and combined ash impoundment). EPA used these 

average concentration data sets to calculate the baseline loadings for discharges from ash 

impoundments. 

 

72 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 proposed rule. 

73 To simplify the discussion, for the purpose of Section 10.2.2 the term “non-detect” is used to refer to both values 

measured below the quantitation limit and those values measured below the detection limit. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-15 

The technology option under consideration for both fly ash and bottom ash is dry ash 

handling or closed-loop recycle system. These systems do not discharge ash transport water; 

therefore, the average effluent concentration associated with the proposed technology option is 

zero. Because no ash transport water is discharged, the post-compliance discharge loading is 

zero. 

10.2.3 Combustion Residual Leachate Wastewater Characterization

As described in Section 9.1, EPA determined that combustion residual impoundments 

will recycle the leachate back to the impoundment from which it was collected rather than install 

the technology basis for the discharge requirements. EPA does not expect this recycled 

impoundment leachate to alter the discharge loadings of the impoundment in any way. By 

recycling leachate generated by the impoundment back into the same impoundment no additional 

pollutants are added to the system (i.e., the surface impoundment). The pollutants contained in 

the impoundment leachate were previously in the system; adding these pollutants back to the 

system at the concentrations found in the leachate will not alter the system as a whole. Therefore, 

EPA finds that baseline and post-compliance pollutant loadings will be the for combustion 

residual impoundment leachate. Therefore, the remainder of this section only discusses the 

pollutant concentrations associated with combustion residual landfill leachate. 

As described in Chapter 9, EPA evaluated two technology options for treating 

combustion residual landfill leachate: one-stage chemical precipitation and one-stage chemical 

precipitation with biological treatment. EPA used data collected though the Steam Electric 

Survey to calculate average effluent concentrations for untreated combustion residual landfill 

leachate. 

EPA’s Steam Electric Survey required certain plants to collect and analyze samples of 

landfill leachate and report the results of these analyses in Part G (Leachate Sampling Data for 

Ponds/Impoundments and Landfills) of the survey. EPA requested these plants to sample any 

untreated landfill leachate collected from an on-site landfill containing combustion residuals. 

EPA used these data to calculate an active and inactive pollutant concentration data set for use in 

loadings calculations. EPA used all data as provided by the plants in the survey, except for the 

following: 

 For values reported as less than the reporting limit, EPA assumed the concentration 

was equal to one-half the reporting limit provided. 

 If the plant did not provide a reporting limit, ERG assumed the concentration was 

equal to the MDL. 

EPA compiled all untreated landfill leachate sampling data reported in the Steam Electric 

Survey from 26 landfills and split them into groups based on the landfill type (i.e., active or 

inactive). The responses to the survey included data from 22 active combustion residual landfills 

and four inactive combustion residual landfills. To determine the industry average concentrations 

for a pollutant, EPA first averaged all concentration data provided for each individual landfill 

providing sampling data to calculate a landfill-specific average concentration. EPA then 

averaged the landfill-specific average concentrations at each plant based on the landfill type (i.e., 

active or inactive) to get a plant-level average pollutant leachate concentration for each landfill 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-16 

type. EPA then used the average plant-level combustion residual landfill concentration to 

calculate the average concentrations across all plants. Table 10-10 presents the average 

concentration for leachate from active and inactive landfills. EPA used these average 

concentrations to calculate baseline loadings for all plants discharging combustion residual 

landfill 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 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 10.2.1.2, to the landfill leachate for the purposes of 

calculating post-compliance loadings. In cases where the average concentration of the untreated 

active or inactive 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 

(untreated leachate) average concentration. In this case, EPA did not calculate additional 

removals of these particular pollutants by the wastewater treatment system. 

10.3 WASTEWATER FLOW RATES FOR POLLUTANT LOADINGS

As discussed earlier, EPA used plant-specific wastewater flow rates in the loadings 

calculations. EPA used information from the Steam Electric Survey to determine which plants 

discharge each specific wastestream of concern and the amount of wastewater each plant 

reported discharging. Each of the following sections provides more detail on EPA’s 

methodology for calculating the specific wastewater flow rates used in the loadings calculations. 

10.3.1 FGD Wastewater Flow Rates for Pollutant Loadings

As described in Section 6.1.4, EPA used plant-level FGD wastewater flow rates from the 

“FGD Input Table” to calculate compliance costs. FGD loadings estimates use the same plantlevel FGD wastewater flow rates. Section 4.1.1 describes the methodology used to populate the 

“FGD Input Table.” EPA used the same FGD wastewater flow rates in both the FGD wastewater 

technology cost modules as well as the FGD wastewater loadings to ensure consistency between 

the two estimates. A copy of the input table is included in the appendix. 

10.3.2 Ash Transport Water Flow Rates for Pollutant Loadings

As discussed in Section 4.1.2, EPA used Steam Electric Survey data to identify which 

plants discharge or have the potential to discharge fly ash or bottom ash transport water. Ash 

surface impoundment loadings are calculated for each of these plants based on the amount of ash 

transport water discharged. The “Ash Transport Water Input Table” holds all the input data 

needed to calculate the baseline loadings for ash surface impoundments. The “Ash Transport 

Water Input Table” contains the following fields: 

 Plant_id: Survey Plant ID. 

 EIA ID: EIA Plant ID. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-17 

 System_ID: Survey Pond System ID. 

 Influent: Flag to identify the influent to the surface impoundment system (e.g. fly ash 

transport water, bottom ash transport water, fly and bottom ash transport water, or 

combined ash transport water). 

 Surface Impoundment Type: Flag to identify the type of surface impoundment. This 

identifier is based on the type of transport water held by the surface impoundment. 

The flag can be fly ash, bottom ash, or combined ash for surface impoundments 

containing both fly and bottom ash transport water. 

 Ash Flow (GPD) over 365 days: The flow of ash transport water into the surface 

impoundment in gallons per day. This flow rate has been normalized for continuous 

flow over 365 days per year. 

 Ash Flow CBI: Flag indicating that the ash transport water flow should be considered 

CBI. CBI flag is marked if any data used to populate the input table was marked as 

CBI by the plant. 

 Calculated Ash Flow: Flag to identify which ash flow values were estimated. 

 Retired?: Flag indicating that the plant has identified that it will be retiring on or 

before 12/31/2014. 

Section 4.1.2 provides more detail on the methodology used to determine the ash flow 

rate and a discussion of the “Ash Transport Water Input Table” in. A copy of the “Ash Transport 

Water Input Table” is included in the appendix. 

10.3.3 Combustion Residual Landfill Leachate Flow Rates for Pollutant Loadings

As described in Section 9.4, EPA used plant-level leachate flow rates from the “Landfill 

Leachate Input Table” to calculate compliance costs. Leachate loadings estimates use the same 

plant-level flow rates. Section 4.1.3 describes the methodology used to populate the “Landfill 

Leachate Input Table.” EPA used the same landfill leachate flow rates in both the leachate 

technology cost modules as well as the leachate loadings to ensure consistency between the two 

estimates. A copy of the input table is included in the appendix. 

10.4 BASELINE AND POST-COMPLIANCE POLLUTANT LOADINGS AND TWPE RESULTS

As discussed in Section 10.1, EPA multiplied the average pollutant concentrations for each 

wastestream presented in Section 10.2 with the plant-specific wastewater flow rates presented in 

Section 10.3 to calculate the amount of pollutant discharged to surface waters for each plant and 

wastestream, as applicable. For those plants transferring the wastewater to a POTW, EPA 

adjusted the loadings to account for additional removals that would take place at the 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 associated with each technology option. Using 

the plant-level loadings by wastestream, EPA was then able to calculate the baseline and postcompliance loading at the industry level for each wastestream and regulatory option. The 

following section discusses the specific loadings and TWPE calculations for each wastestream 

and each technology option being considered. The section also presents the industry-level 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-18 

loadings for each wastestream. 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 SE03970). 

EPA is proposing to apply different effluent limits to oil-fired units and units with a 

capacity of 50 MW or less. For discharges from these generating units, BAT would be set equal 

to the current BPT standard for each of the wastestreams for which EPA is proposing revisions to 

the 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 units and 

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 Proposed Effluent Limitations 

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

(TDD) provides more details regarding the analyses of these factors. Section 8.1.3 of the TDD 

discusses the rationale regarding the decision. 

10.4.1 FGD Wastewater Loadings and TWPE

EPA calculated plant-specific loadings for each of the technology options considered for 

FGD wastewater. For baseline loadings, EPA multiplied the plant-specific FGD wastewater 

discharge flow rate with the average pollutant concentrations that represent the current level of 

treatment at the plant (i.e., surface impoundment, chemical precipitation, biological treatment, or 

vapor-compression evaporation). EPA identified three plants transferring FGD wastewater to a 

POTW. For these three plants, EPA adjusted the baseline loadings to account for pollutant 

removals associated with POTW treatment, as described in Section 10.1. 

For the post-compliance loadings associated with the one-stage chemical precipitation 

technology option, EPA assumed that the discharge loadings calculated for plants currently 

treating their FGD wastewater with one-stage chemical precipitation systems, biological 

treatment systems, or vapor-compression evaporation systems remain unchanged from baseline. 

EPA assumed that plants with baseline surface impoundments would install one-stage chemical 

precipitation treatment systems to meet the effluent requirements associated with this option. 

EPA calculated post-compliance loadings for these plants using the average concentration data 

set associated with one-stage chemical precipitation systems, presented in Table 10-6, and plantspecific FGD wastewater flow rates. As described in Section 10.2.1.2, for each plant classified as 

a baseline chemical precipitation system, EPA used the same chemical precipitation effluent 

concentrations to calculate the baseline and post-compliance loadings, even if the system was not 

equivalent to the technology basis. This underestimates the pollutant removals being achieved by 

the treatment system because EPA does not calculate any removals for these plants, even though 

some of these plants are being assessed compliance costs to upgrade the system to operate 

similarly to the technology basis. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-19 

For the post-compliance pollutant loadings associated with the one-stage 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 vapor-compression evaporation systems remain 

unchanged from baseline. EPA assumed that plants with surface impoundments would install 

one-stage chemical precipitation systems with biological treatment, and plants with one-stage 

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 calculated the post-compliance loadings for these plants using the average 

concentration data set associated with one-stage chemical precipitation systems followed by 

biological treatment, presented in Table 10-7, and plant-specific FGD wastewater flow rates. 

For the post-compliance pollutant loadings associated with the one-stage chemical 

precipitation treatment system followed by vapor-compression evaporation option, EPA assumed 

that the post-compliance loadings calculated for plants currently treating their FGD wastewater 

with this type of system remain unchanged from baseline. EPA assumed that plants with any 

other current treatment method (i.e., surface impoundment, chemical precipitation, or biological 

treatment) would install one-stage chemical precipitation treatment systems with vaporcompression evaporation to meet the effluent requirements associated with this technology 

option. EPA calculated the post-compliance loadings for these plants using the average 

concentration data set associated with one-stage chemical precipitation systems with vaporcompression evaporation, presented in Table 10-8, and plant-specific FGD wastewater flow 

rates. 

The raw data output of the FGD wastewater loadings database is included in the 

appendix, along with a table of plant-level loadings in pounds/year and TWPE/year. Table 10-11 

and Table 10-12 present the FGD wastewater loadings on an industry-level for baseline and each 

post-compliance technology basis. Table 10-11 presents the loadings based on all units 

discharging FGD wastewater needing to install the appropriate technology basis, and Table 

10-12 presents the loadings based on the oil-fired units and units with a capacity of 50 MW or 

less not needing to install the technology basis. The loadings exclude the pollutant parameters 

BOD, 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 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 10-13 and Table 10-14 present the pollutant removals, in both pounds per year and TWPE 

per year, for the various technology options. Table 10-13 presents the pollutant removals based 

on all units discharging FGD wastewater needing to install the appropriate technology basis and 

Table 10-14 presents the pollutant removals based on the oil-fired units and units with a capacity 

of 50 MW or less not needing to install the technology basis. EPA calculated the pollutant 

removals by subtracting the technology option loadings from the baseline loadings (or a less 

stringent technology option). 

10.4.2 Ash Transport Water Loadings and TWPE

EPA calculated plant-specific loadings for the baseline discharges and the technology 

option considered for ash transport water. For baseline loadings, EPA multiplied the plant-
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-20 

specific ash transport water discharge flow rate for each type of ash transport water (i.e., fly ash, 

bottom ash, or combined ash transport water) by the appropriate average concentration data set 

for the type of discharge. For example, for each fly ash impoundment, EPA multiplied the 

normalized discharge flow rate described in Section 10.3.2 for the plant’s fly ash impoundment 

by the average concentration data set associated with fly ash impoundments presented in Section 

10.2.2. EPA identified four plants transferring bottom ash transport water to a POTW and no 

plants transferring fly ash transport water to a POTW. For these four plants, EPA adjusted the 

baseline loadings to account for pollutant removals associated with POTW treatment, as 

described in Section 10.1. 

As described in Section 10.2.2, EPA collected ash transport water characterization data 

for fly ash impoundments, bottom ash impoundments, and combined ash impoundments. As 

such, EPA calculated loadings for each of these different types of impoundments at a plant-level. 

Because EPA considered regulatory options that would establish different effluent requirements 

for fly ash and bottom ash, EPA analyzed the pollutant loadings and removals for these two 

wastestreams separately; therefore, EPA separated the loadings for combined ash impoundments 

into fly ash loadings and bottom ash loadings. EPA used data from the EPRI PISCES reports to 

estimate the breakout of the loadings among fly ash and bottom ash contributions. As discussed 

in Section 3.6, the PISCES reports include information from several sites operating 

impoundments receiving either fly ash transport water or bottom ash transport water. The Site A, 

B, C, and D EPRI PISCES reports include tables that present the loadings to the ash 

impoundments in 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 streams in the EPRI PISCES reports to breakout 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 the analysis because the fly ash transport water is only 

transferred to the ash impoundment during occasional operation; therefore, compared 

to bottom ash transport water loadings, the fly ash transport water loadings were not 

representative of the operations at a typical plant with both wet fly and bottom ash 

sluicing operations. 

 Site B was considered to be a representative plant and therefore was included in the 

analysis. 

 Site C was considered to be a representative plant and therefore was included in the 

analysis. 

 Site D has two separate plants at the site (i.e., Plants A and B). Plant A has wet fly 

ash and bottom ash for all six units, and Plant B has wet bottom ash for two units, but 

wet fly ash for only one of the two units; therefore, only Plant A fly ash and bottom 

ash loadings were included in the analysis. Plant B loadings were excluded. 

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 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-21 

loading for fly ash and bottom ash for each pollutant. For example, for Site C, the aluminum fly 

ash loading is 190 kg/day and the bottom ash loading is 7.8 kg/day; therefore, EPA calculated a 

total ash loading of 197.8 kg/day, and the percent loading of aluminum for fly ash is 96.1 percent 

and the percent loading of aluminum for bottom ash is 3.9 percent. For this calculation, EPA 

only included the fly ash and bottom ash loadings, even though EPRI included all wastewater 

sources entering the impoundment, because EPA is only evaluating the combined ash sluice 

water and is not considering other wastewater sources. EPA performed this calculation for each 

pollutant available for each of the three sites. EPA then calculated an average percent loading for 

fly ash and bottom ash for each pollutant using the percentage calculated for each plant. These 

average percent loadings for fly ash and bottom ash are presented in Table 10-15 for each 

pollutant available. 

Because the percent loading for fly ash is consistently higher than the bottom ash percent 

loading for all of the pollutants available, EPA assumed that the fly ash loading would be higher 

for the pollutants for which data were not available. Therefore, EPA calculated the average 

percent loading for fly ash and bottom ash based on the pollutants available, 86 and 14 percent, 

respectively, and assumed this value for the percent breakout for all the other pollutants for 

which loadings were calculated for combined ash impoundments. 

For both fly ash and bottom ash transport water, EPA is considering only one technology 

option: eliminating ash transport water discharge, either by conversion to dry ash handling (fly 

ash and bottom ash MDS) or conversion to a closed-loop recycle system (bottom ash remote 

MDS). EPA assumes that all plants currently discharging ash transport water will install dry 

handling systems for fly ash and will operate wet-sluicing bottom ash handling systems as a 

closed-loop recycle system (i.e., zero discharge) or will convert to dry bottom ash handling, 

resulting in post-compliance loadings of zero for fly and bottom ash transport water pollutants 

for those plants subject to the proposed requirements. 

The raw data output of the ash impoundment loadings database can be found in the 

appendix, along with a table of plant-level loadings in pounds/year and the plant-level loadings 

in TWPE/year. Table 10-16 presents the results of the baseline ash impoundment loadings on an 

industry level. The table includes the number of impoundments discharging each type of ash 

transport water, the total industry discharge flow rate, and the total industry loadings in pounds 

per year and TWPE per year associated with each type of impoundment. The industry loadings 

presented in Table 10-16 exclude the pollutant parameters BOD, COD, TDS, and TSS because 

they double count the loadings for specific pollutants already included. Table 10-17 and 

Table 10-18 present the pollutant removals, in both pounds per year and TWPE per year, 

between the baseline and the dry handling technology option. Table 10-17 presents the pollutant 

removals based on all units discharging ash transport water needing to install the dry handling 

systems and 

Table 10-18 presents the pollutant removals based on the oil-fired and units with a 

capacity of 50 MW or less not needing to install the dry handling/closed-loop recycle systems. 

EPA calculates the pollutant removals by subtracting the technology option loadings from the 

baseline loadings. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-22 

10.4.3 Combustion Residual Landfill Leachate Loadings and TWPE

EPA calculated plant-specific loadings for each of the technology options considered for 

combustion residual landfill leachate. For baseline loadings, EPA multiplied the plant-specific 

leachate discharge flow rate with the average pollutant concentrations that represent untreated 

combustion residual landfill leachate. EPA identified seven plants transferring landfill leachate to 

a POTW. For these seven plants, EPA adjusted the baseline loadings to account for pollutant 

removals associated with POTW treatment. 

For the one-stage chemical precipitation technology option, EPA assumed that all plants 

would install this type of treatment system. No plants currently treat leachate with a one-stage 

chemical precipitation system, so all plants would need to install treatment to meet the effluent 

requirements associated with this option. Some plants can use existing FGD treatment systems, 

but these systems would also need to be modified to achieve BAT limits. EPA calculated 

discharge loadings for these plants using the average concentration data set associated with onestage chemical precipitation systems, discussed in Section 10.2.3, and plant-specific leachate 

flow rates, discussed in Section 4.1.3. 

For the one-stage chemical precipitation treatment system with biological treatment 

technology option, EPA assumed that all plants would install this type of treatment to meet the 

effluent requirements associated with this technology option. EPA calculated the discharge 

loadings for these plants using the average concentration data set associated with one-stage 

chemical precipitation systems followed by biological treatment, presented in Section 10.2.3, and 

plant-specific leachate flow rates, discussed in Section 4.1.3. 

The raw data output of the leachate loadings can be found in the appendix, along with a 

table of plant-level loadings in pounds/year and the TWPE/year. Table 10-19 and Table 10-20 

present the combustion residual landfill leachate loadings on an industry-level for baseline and 

each technology option. Table 10-19 presents loadings based on all units discharging landfill 

leachate needing to install the appropriate technology basis and Table 10-20 presents loadings 

based on the oil-fired units and units with a capacity of 50 MW or less not needing to install the 

technology basis. The loadings exclude the pollutant parameters BOD, COD, TDS, and TSS 

because they double count the loadings for specific pollutants already included. The table 

includes the number of plants identified as discharging landfill leachate, the total industry flow 

rate associated with each technology option, and the total industry loadings in pounds per year 

and TWPE per year. Table 10-21 and Table 10-22 present the pollutant removals, in both pounds 

per year and TWPE per year, for the various technology options. Table 10-21 presents the 

pollutant removals based on all units discharging landfill leachate needing to install the 

appropriate technology basis. Table 10-22 presents the pollutant removals based on the oil-fired 

units and units with a capacity of 50 MW or less not needing to install the technology basis. EPA 

calculated the pollutant removals by subtracting the technology option loadings from the baseline 

loadings (or a less stringent technology option). 

10.5 REFERENCES

1. Duke Energy. 2011a. Industry Provided Sampling Data from Duke Energy’s Belews 

Creek Steam Station. (17 August). DCN SE01808. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-23 

2. Duke Energy. 2011b. Industry Provided Sampling Data from Duke Energy’s Allen Steam 

Station. (17 August). DCN SE01809. 

3. Eastern Research Group (ERG). 2005. Memorandum to 2006 Effluent Guidelines 

Program Plan Docket, From Ellie Codding and Deb Bartram, ERG, re: Publicly Owned 

Treatment Works (POTW) Percent Removals Used for the TRI Releases2002 Database. 

(12 August). DCN SE02932. 

4. Eastern Research Group (ERG). 2006. Toxic Weighting Factor Development in Support 

of CWA 304(m) Planning Process. (June). DCN SE01952. 

5. Eastern Research Group (ERG). 2012a. Steam Electric Technical Questionnaire Database 

(“Steam Electric Survey”). (19 April). DCN SE01958. 

6. Eastern Research Group (ERG). 2012b. Final Sampling Episode Report, Duke Energy 

Carolinas’ Belews Creek Steam Station. (13 March). DCN SE01379. 

7. Eastern Research Group (ERG). 2012c. Final Sampling Episode Report, We Energies’ 

Pleasant Prairie Power Plant. (13 March). DCN SE01414. 

8. Eastern Research Group (ERG). 2012d. Non-CBI_Final Sampling Episode Report, Duke 

Energy Miami Fort Station. (13 March). DCN SE01304. 

9. Eastern Research Group (ERG). 2012e. Final Sampling Episode Report, Duke Energy 

Carolinas’ Allen Steam Station. (13 March). DCN SE01372. 

10. Eastern Research Group (ERG). 2012f. Final Sampling Episode Report, Mirant MidAtlantic, LLC’s Dickerson Generating Station. (13 March). DCN SE01385. 

11. Eastern Research Group (ERG). 2012g. Final Sampling Episode Report, Allegheny 

Energy’s Hatfield’s Ferry Power Station. (13 March). DCN SE01391. 

12. Eastern Research Group (ERG). 2012h. Final Sampling Episode Report, RRI Energy’s 

Keystone Generating Station. (13 March). DCN SE01406. 

13. Eastern Research Group (ERG). 2012i. Final Sampling Episode Report and Site Visit 

Notes, Enel’s Federico II Power Plant (Brindisi). (8 August). DCN SE02013. 

14. Eastern Research Group (ERG). 2012j. Final Power Plant Monitoring Data Collected 

Under Clean Water Act Section 308 Authority (“CWA 308 Monitoring Data”). (30 May). 

DCN SE01326. 

15. Electric Power Research Institute (EPRI). 1997 - 2001. PISCES Water Characterization 

Field Study, Sites A-G. Palo Alto, CA. DCNs 01818-01823. 

16. Electric Power Research Institute (EPRI). 2006a. Flue Gas Desulfurization (FGD) 

Wastewater Characterization: Screening Study. 1010162. Palo Alto, CA. (March). 

Available online at: http://mydocs.epri.com/docs/public/000000000001010162.pdf. Date 

accessed: 16 May 2008. DCN 01816. 

17. Electric Power Research Institute (EPRI). 2006b. EPRI Technical Manual: Guidance for 

Assessing Wastewater Impacts of FGD Scrubbers. 1013313. Palo Alto, CA. (December). 

Available online at: http://www.epriweb.com/public/000000000001013313.pdf. Date 

accessed: 16 May 2008. DCN 01817. 

18. Progress Energy. 2011. Industry Provided Sampling Data from Progress Energy’s 

Roxboro Plant. (26 June). DCN SE01812. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-24 

19. Utility Water Act Group (UWAG). 2008. Form 2C Effluent Guidelines Database. (30 

June). DCNs 02918 and 02918A. 

20. U.S. EPA. 1982. 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). DCN 02933. 

21. U.S. EPA. 2009. 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 00003. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-25 

Table 10-1. POTW Removals 

Analyte POTW Removal Percentage 

Aluminum 91.0% 

Ammonia 39.0% 

Antimony 66.8% 

Arsenic 65.8% 

Barium 55.2% 

Beryllium 61.2% 

Biochemical Oxygen Demand NA 

Boron NA 

Cadmium 90.1% 

Calcium NA 

Chemical Oxygen Demand NA 

Chloride NA 

Chromium 80.3% 

Chromium (VI) NA 

Cobalt 10.2% 

Copper 84.2% 

Cyanide, Total NA 

Iron NA 

Lead 77.5% 

Magnesium NA 

Manganese 40.6% 

Mercury 90.2% 

Molybdenum NA 

Nickel 51.4% 

Nitrate Nitrite as N 90.0%

Nitrogen, Kjeldahl NA

Phosphorus, Total NA

Selenium 34.3%

Silver 88.3%

Sodium NA

Sulfate NA

Thallium 53.8%

Tin NA

Titanium NA

Total Dissolved Solids NA

Total Suspended Solids NA

Vanadium 8.3%

Zinc 79.1%

Source: ERG, 2006. 

NA – Not applicable. 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-26 

Table 10-2. Data Sets Used in the Loadings Calculations

Plant Name Source of Data Set 

Wastestreams Represented in 

Data Seta

Progress Energy Carolinas’ Roxboro 

Steam Electric Plant (Roxboro) 

Monitoring data provided by plant Surface impoundment effluent 

Duke Energy’s Miami Fort Station 

(Miami Fort) 

EPA sampling Chemical precipitation effluent 

EPA CWA 308 monitoring 

sampling 

Chemical precipitation effluent 

RRI Energy’s Keystone Generating 

Station (Keystone) 

EPA sampling Chemical precipitation effluent 

EPA CWA 308 monitoring 

sampling 

Chemical precipitation effluent 

Allegheny Energy’s Hatfield’s Ferry 

Electric Plant (Hatfield’s Ferry) 

EPA sampling Chemical precipitation effluent 

EPA CWA 308 monitoring 

sampling 

Chemical precipitation effluent 

Duke Energy Carolinas’ Belews Creek 

Steam Station (Belews Creek) 

EPA sampling Biological treatment effluent 

EPA CWA 308 monitoring 

sampling 

Biological treatment effluent

Monitoring data provided by plant Biological treatment effluent

Duke Energy Carolinas’ Allen Steam 

Station (Allen) 

EPA sampling Biological treatment effluent 

EPA CWA 308 monitoring 

sampling 

Biological treatment effluent

Monitoring data provided by plant Biological treatment effluent

Enel Brindisi EPA sampling Vapor-compression evaporation 

effluent 

Note: EPA excluded data from the We Energies’ Pleasant Prairie Power Plant (Pleasant Prairie) in the loadings 

calculation because the Pleasant Prairie FGD wastewater treatment system consists of a two-stage chemical 

precipitation system, which is more advanced than the one-stage chemical precipitation system used as the bases for 

the chemical precipitation technology option. In addition, EPA excluded data from the Mirant Mid-Atlantic, LLC’s 

Dickerson Generating Station (Dickerson) in the loadings calculation because the Dickerson plant was not adding 

organosulfide chemicals 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. 

a The three plants with data used for chemical precipitation effluent characterization operate one-stage chemical 

precipitation systems. 

 
 Chapter 10 –Pollutant Loadings and Removals Methodology 

10-27 

Table 10-3. Average Effluent Concentration of FGD Surface Impoundments 

Analyte Unit Average Concentration 

Classicals 

Ammonia ug/L NA 

Nitrate Nitrite as N ug/L 67,300 

Nitrogen, Kjeldahl ug/L NA 

Biochemical Oxygen Demand ug/L NA 

Chemical Oxygen Demand ug/L 418,000 

Chloride ug/L 7,320,000 

Sulfate ug/L 1,240,000 

Cyanide, Total ug/L 1,190 

Total Dissolved Solids ug/L 28,600,000 

Total Suspended Solids ug/L 27,900 

Phosphorus, Total ug/L 404 

Total Metals 

Aluminum ug/L 2,080 

Antimony ug/L 13 

Arsenic ug/L 6.8 

Barium ug/L 303 

Beryllium ug/L 1.9 

Boron ug/L 243,000 

Cadmium ug/L 112 

Calcium ug/L 2,050,000 

Chromium ug/L 18 

Chromium (VI) ug/L NA 

Cobalt ug/L 183 

Copper ug/L 21 

Iron ug/L 1,510 

Lead ug/L 4.7 

Magnesium ug/L 3,370,000 

Manganese ug/L 93,100 

Mercury ug/L 5.6 

Molybdenum ug/L 125 

Nickel ug/L 878 

Selenium ug/L 1,110 

Silver ug/L 0.93 

Sodium ug/L 276,000 

Thallium ug/L 13 

Tin ug/L 100 

Titanium ug/L 27 

Vanadium ug/L 16 

Zinc ug/L 1,390 

Sources: ERG, 2012b-2012h; Progress Energy, 2011. 

Note: Concentrations are rounded to three significant figures. 

NA – Not applicable. 
 Chapter 10 –Pollutant Loadings a

10-28 

Table 10-4. Characteristics of FGD Blowdown at EPRI Sites P, R, and S 

Parameter Units 

Site P Site R 

Filtered Settled Total Filtered Settled Total Filter

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 
 Chapter 10 –Pollutant Loadings a

10-29 

Table 10-4. Characteristics of FGD Blowdown at EPRI Sites P, R, and S 

Parameter Units 

Site P Site R 

Filtered Settled Total Filtered Settled Total Filter

Chloridea 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 Fluoridea 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 Sulfatea 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. *Results from sites S and T for selenium speciation were from different samples (collected August 2005) than the other parameters (collected Oa – Chloride, fluoride, and sulfate were analyzed by ICP-MS so filtered in analysis. Therefore, “Total”, “Settled”, and “filtered” are all actually tonly one was reported. 
Chapter 10 –Pollutant Loadings a

10-30 

Table 10-5. Characteristics of FGD Blowdown at EPRI Sites T, U, and Y 

Parameter Units 

Site T Site U 

Filtered Settled Total Filtered Settled Total Filter

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 
Chapter 10 –Pollutant Loadings a

10-31 

Table 10-5. Characteristics of FGD Blowdown at EPRI Sites T, U, and Y 

Parameter Units 

Site T Site U 

Filtered Settled Total Filtered Settled Total Filter

Chloridea 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 Fluoridea 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 Sulfatea 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. *Results from sites S and T for selenium speciation were from different samples (collected August 2005) than the other parameters (collected Oa – Chloride, fluoride, and sulfate were analyzed by ICP-MS so filtered in analysis. Therefore, “Total”, “Settled”, and “filtered” are all actually tonly one was reported. U = Non-detect. . 
Chapter 10 –Pollutant Loadings and Removals Methodology 

10-32 

Table 10-6. Average Effluent Concentration of One-Stage Chemical Precipitation System 

Analyte Unit Average Concentration 

Classicals 

Ammonia ug/L 8,120 

Nitrate Nitrite as N ug/L 67,300 

Nitrogen, Kjeldahl ug/L 27,000 

Biochemical Oxygen Demand ug/L 3,130 

Chemical Oxygen Demand ug/L 418,000 

Chloride ug/L 8,940,000 

Sulfate ug/L 5,980,000 

Cyanide, Total ug/L 1,190 

Total Dissolved Solids ug/L 23,100,000 

Total Suspended Solids ug/L 6,560 

Phosphorus, Total ug/L 404 

Total Metals 

Aluminum ug/L 155 

Antimony ug/L 5.0 

Arsenic ug/L 4.5 

Barium ug/L 163 

Beryllium ug/L 1.00 

Boron ug/L 279,000 

Cadmium ug/L 3.8 

Calcium ug/L 2,330,000 

Chromium ug/L 9.1 

Chromium (VI) ug/L 5.3 

Cobalt ug/L 10 

Copper ug/L 2.0 

Iron ug/L 127 

Lead ug/L 1.00 

Magnesium ug/L 3,340,000 

Manganese ug/L 13,600 

Mercury ug/L 0.17 

Molybdenum ug/L 215 

Nickel ug/L 5.6 

Selenium ug/L 455 

Silver ug/L 1.00 

Sodium ug/L 420,000 

Thallium ug/L 8.6 

Tin ug/L 100 

Titanium ug/L 10 

Vanadium ug/L 15 

Zinc ug/L 18 

Sources: ERG, 2012d; ERG, 2012g; ERG, 2012h; ERG, 2012j. 

Note: Concentrations are rounded to three significant figures. 
Chapter 10 –Pollutant Loadings and Removals Methodology 

10-33 

Table 10-7. Average Effluent Concentration of One-Stage Chemical Precipitation 

System With Biological Treatment 

Analyte Unit Average Concentration 

Classicals 

Ammonia ug/L 8,750 

Nitrate Nitrite as N ug/L 79 

Nitrogen, Kjeldahl ug/L 12,100 

Biochemical Oxygen Demand ug/L 1,740 

Chemical Oxygen Demand ug/L 156,000 

Chloride ug/L 6,720,000 

Sulfate ug/L 1,380,000 

Cyanide, Total ug/L 74 

Total Dissolved Solids ug/L 14,100,000 

Total Suspended Solids ug/L 8,210 

Phosphorus, Total ug/L 115 

Total Metals 

Aluminum ug/L 155 

Antimony ug/L 2.0 

Arsenic ug/L 4.6 

Barium ug/L 323 

Beryllium ug/L 0.97 

Boron ug/L 125,000 

Cadmium ug/L 2.5 

Calcium ug/L 2,970,000 

Chromium ug/L 2.2 

Chromium (VI) ug/L 3.0 

Cobalt ug/L 10 

Copper ug/L 2.7 

Iron ug/L 302 

Lead ug/L 1.00 

Magnesium ug/L 741,000 

Manganese ug/L 1,960 

Mercury ug/L 0.067 

Molybdenum ug/L 20 

Nickel ug/L 2.6 

Selenium ug/L 5.0 

Silver ug/L 2.3 

Sodium ug/L 46,100 

Thallium ug/L 1.9 

Tin ug/L 100 

Titanium ug/L 10 

Vanadium ug/L 5.0 

Zinc ug/L 4.8 

Sources: ERG, 2012b; ERG, 2012e; ERG, 2012j, Duke Energy, 2011a – 2011b. 

Note: Concentrations are rounded to three significant figures. 
Chapter 10 –Pollutant Loadings and Removals Methodology 

10-34 

Table 10-8. Average Effluent Concentration of One-Stage Chemical Precipitation 

System With Vapor-Compression Evaporation 

Analyte Unit Average Concentration 

Classicals 

Ammonia ug/L 24,300 

Nitrate Nitrite as N ug/L 100 

Nitrogen, Kjeldahl ug/L 23,500 

Chemical Oxygen Demand ug/L 10,000 

Chloride ug/L 1,500 

Sulfate ug/L 2,500 

Total Dissolved Solids ug/L 10,800 

Total Suspended Solids ug/L 2,000 

Phosphorus, Total ug/L 25 

Total Metals 

Aluminum ug/L 100 

Antimony ug/L 1.00 

Arsenic ug/L 2.0 

Barium ug/L 10 

Beryllium ug/L 1.00 

Boron ug/L 3,750 

Cadmium ug/L 2.0 

Calcium ug/L 200 

Chromium ug/L 4.0 

Cobalt ug/L 10 

Copper ug/L 2.0 

Iron ug/L 100 

Lead ug/L 1.00 

Magnesium ug/L 200 

Manganese ug/L 10 

Mercury ug/L 0.0103 

Molybdenum ug/L 20 

Nickel ug/L 2.0 

Selenium ug/L 2.0 

Silver ug/L 1.0 

Sodium ug/L 5,000 

Thallium ug/L 1.0 

Tin ug/L 100 

Titanium ug/L 10 

Vanadium ug/L 5.0 

Zinc ug/L 28.5 

Source: ERG, 2012i. 

Note: Concentrations are rounded to three significant figures. 

NA – Not applicable. 
Chapter 10 –Pollutant Loadings and Removals Methodology 

10-35 

Table 10-9. Average Effluent Concentration of Ash Surface Impoundment 

Systems 

Analyte Unit 

Average Fly 

Ash 

Concentration 

Average 

Bottom Ash 

Concentration 

Average 

Combined Ash 

Concentration 

Classicals 

Ammonia (as N) mg/L 0.62 0.24 0.27 

Nitrate-Nitrite as N mg/L 2.51 9.65 2.53 

Total Kjeldahl Nitrogen mg/L 0.41 1.36 3.39 

Biochemical Oxygen Demand mg/L 1.5 1 4 

Chloride mg/L 107 53.5 16.4 

Sulfate mg/L 709 1,170 203 

Sulfide (as S) mg/L 1.01 0.51 0.52 

Sulfite (as SO3) mg/L 2 26.7 1.63 

Cyanide mg/L NA NA 0.01 

Total Dissolved Solids mg/L 1,362 1,260 262.4 

Total Suspended Solids mg/L 8.06 8.36 13.8 

Fluoride mg/L NA NA 0.15 

Hexane Extractable Material mg/L 6.25 2.5 6 

Nitrogen, Total Organic (as N) mg/L 0.65 3.28 0.51 

Oil and Grease mg/L 2.13 3.67 2.83 

Silicon-Gel Treated Hexane 

Extractable Material 

mg/L

2 NA 2.5 

Phosphorus (as P) mg/L 0.12 0.36 0.28 

Total Metals 

Aluminum mg/L 0.46 0.59 1.11 

Antimony mg/L 0.028 0.093 0.024 

Arsenic mg/L 0.042 0.018 0.064 

Barium mg/L 0.13 0.078 0.2 

Beryllium mg/L 0.003 0.004 0.005 

Boron mg/L 4.67 2.24 1.97 

Cadmium mg/L 0.006 0.008 0.008 

Calcium mg/L 102 186 70.7 

Chromium mg/L 0.017 0.014 0.02 

Hexavalent Chromium mg/L 0.005 0.001 0.012 

Cobalt mg/L 0.014 0.048 0.012 

Copper mg/L 0.042 0.027 0.04 

Iron mg/L 1.81 2.44 0.58 

Lead mg/L 0.03 0.037 0.027 

Magnesium mg/L 18.8 97.3 15.3 

Manganese mg/L 0.041 0.13 0.62 

Mercury mg/L 0.001 0.001 0.002 

Molybdenum mg/L 0.43 0.065 0.14 

Nickel mg/L 0.035 0.13 0.035 

Selenium mg/L 0.035 0.013 0.03 

Silica mg/L NA NA 5.93 

Silver mg/L 0.003 0.004 0.008 
Chapter 10 –Pollutant Loadings and Removals Methodology 

10-36 

Table 10-9. Average Effluent Concentration of Ash Surface Impoundment 

Systems 

Analyte Unit 

Average Fly 

Ash 

Concentration 

Average 

Bottom Ash 

Concentration 

Average 

Combined Ash 

Concentration 

Sodium mg/L 298 106 21.3 

Thallium mg/L 0.011 0.12 0.049 

Tin mg/L 0.025 0.34 0.15 

Titanium mg/L 0.008 0.11 0.029 

Vanadium mg/L 0.11 0.01 0.044 

Yttrium mg/L 0.003 0.003 0.003 

Zinc mg/L 0.17 0.094 0.085 

Sources: U.S. EPA, 2009; U.S. EPA, 1982; EPRI, 1997 – 2001; UWAG, 2008. 

Note: Concentrations are rounded to three significant figures. 

NA – Not applicable. 

Table 10-10. Average Untreated Landfill Leachate Concentrations 

Analyte Unit 

Untreated Active 

Landfill 

Concentration 

Untreated Inactive 

Landfill 

Concentration 

Classicals 

Chloride ug/L 542,000 11,100 

Sulfate ug/L 1,910,000 1,070,000 

Total Dissolved Solids ug/L 3,860,000 1,670,000 

Total Suspended Solids ug/L 41,400 4,210 

Total Metals 

Aluminum ug/L 5,030 100 

Antimony ug/L 4.6 4.9 

Arsenic ug/L 46 10 

Barium ug/L 57 50 

Beryllium ug/L 1.9 0.47 

Boron ug/L 20,500 3,640 

Cadmium ug/L 2.7 1.9 

Calcium ug/L 481,000 386,000 

Chromium ug/L 4.9 1.6 

Cobalt ug/L 84 3.8 

Copper ug/L 10 1.7 

Iron ug/L 59,000 95 

Lead ug/L 1.4 0.47 

Magnesium ug/L 115,000 33,700 

Manganese ug/L 4,360 355 

Mercury ug/L 1.4 0.01 

Molybdenum ug/L 1,880 995 

Nickel ug/L 69 43 

Selenium ug/L 74 84 

Silver ug/L 0.68 0.42 

Sodium ug/L 327,000 16,700 

Thallium ug/L 1.3 0.96 

Tin ug/L 11 13 
Chapter 10 –Pollutant Loadings and Removals Methodology 

10-37 

Table 10-10. Average Untreated Landfill Leachate Concentrations 

Analyte Unit 

Untreated Active 

Landfill 

Concentration 

Untreated Inactive 

Landfill 

Concentration 

Titanium ug/L 17 15 

Vanadium ug/L 3,240 6.2 

Zinc ug/L 154 58 

Source: Steam Electric Survey ERG, 2012a. 

Note: Concentrations are rounded to three significant figures. 

Table 10-11. Industry-Level FGD Wastewater Loadings for All Units 

Treatment Option 

Number of 

Plants 

Total Industry 

Discharge Flow 

(MGD)a 

Total Industry Loadings 

Pounds/Year TWPE/Year 

Baseline 117 65.4 3,240,000,000 3,030,000 

One-Stage Chemical Precipitation 117 56.8 3,650,000,000 1,490,000 

One-Stage Chemical Precipitation With 

Biological Treatment 

117 56.8 2,080,000,000 408,000 

One-Stage Chemical Precipitation With 

Evaporation/Crystallization 

117 56.8 10,600,000 33,000 

Note: Excludes loadings for BOD, COD, TSS and TDS. 

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 4.4.3. 

Table 10-12. Industry-Level FGD Wastewater Loadings 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) 

Total Industry Loadings 

Pounds/Year TWPE/Year 

Baseline 117 65.4 3,240,000,000 3,030,000 

One-Stage Chemical Precipitation 117 56.8 3,650,000,000 1,490,000 

One-Stage Chemical Precipitation With 

Biological Treatment 

117 56.8 2,080,00,000 411,000 

One-Stage Chemical Precipitation With 

Evaporation/Crystallization 

117 56.8 13,500,000 36,400 

Note: Excludes loadings for BOD, COD, TSS and TDS. 

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 4.4.3. 

 
Chapter 10 –Pollutant Loadings and Removals Methodology 

10-38 

Table 10-13. FGD Wastewater Pollutant Removals for All Units 

Treatment Option 

Total Industry Removals 

Pounds/Year TWPE/Year 

Removal (Baseline –> One-Stage Chemical Precipitation) -419,000,000a 1,540,000 

Removal (Baseline –> One-Stage Chemical Precipitation With 

Biological Treatment) 

1,160,000,000 2,620,000 

Removal (Baseline –> One-Stage Chemical Precipitation With 

Evaporation/Crystallization) 

3,220,000,000 2,990,000 

Note: Excludes loadings 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 10-11 due to rounding.

a – Characterization data used to estimate pollutant concentrations for baseline FGD surface impoundments does not 

include concentration data for ammonia, hexavalent chromium, and TKN. These pollutants are included in the postcompliance loadings and as a result appear to increase in concentration from baseline to technology option. 

Table 10-14. FGD Wastewater Pollutant Removals 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 –> One-Stage Chemical Precipitation) -417,000,000a 1,530,000 

Removal (Baseline –> One-Stage Chemical Precipitation With 

Biological Treatment) 

1,160,000,000 2,620,000 

Removal (Baseline –> One-Stage Chemical Precipitation With 

Evaporation/Crystallization) 

3,220,000,000 2,990,000 

Note: Excludes loadings 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 10-12 due to rounding.

a – Characterization data used to estimate pollutant concentrations for baseline FGD surface impoundments does not 

include concentration data for ammonia, hexavalent chromium, and TKN. These pollutants are included in the postcompliance loadings and as a result appear to increase in concentration from baseline to technology option. 
Chapter 10 –Pollutant Loadings and Removals Methodology 

10-39 

Table 10-15. 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: EPRI, 1997 – 2001 

Table 10-16. Industry-Level Baseline Ash Impoundment Loadings by Type of 

Impoundment 

Type of Ash 

Impoundment 

Number of 

Impoundments 

Total Baseline 

Industry 

Discharge Flow

(MGD) 

Total Industry Baseline 

Loadings 

Total Industry PostCompliance Loadingsa 

Pounds/Year TWPE/Year Pounds/Year TWPE/Year

Fly Ash 

Fly Ash 

Impoundment 

16 61.7 237,000,000 688,000 3,800,000 11,000 

Combined Ash 

Impoundmentb

80 262c 241,000,000 1,830,000 2,950,000 22,500 

Bottom Ash 

Bottom Ash 

Impoundment 

174 327 1,660,000,000 2,420,000 5,100,000 7,290 

Combined Ash 

Impoundmentb

80 262c 44,900,000 295,000 550,000 3,610 

TOTAL 272 651 2,180,000,000 5,240,000 12,400,000 44,400 

Note: Excludes loadings for BOD, COD, TSS, and TDS. 

Note: Loadings are rounded to three significant figures. 

a

 The post-compliance loadings present represent the loadings based on oil-fired units and units 50 MW or less not 

installing the technology basis. The post-compliance loadings for all units is zero. 

b

 The combined impoundment loadings were calculated based on the data used in the loadings calculations but then 

the total combined ash impoundment loadings were split between fly ash and bottom ash based on EPRI data, 

described in this section. 

c

 The total discharge flow from all combined impoundments is 262 MGD. The fly ash contribution and bottom ash 

contribution cannot be determined with the data provided in the Steam Electric Survey. 
Chapter 10 –Pollutant Loadings and Removals Methodology 

10-40 

Table 10-17. Fly Ash and Bottom Ash Pollutant Removals for All Units 

Type of Ash 

Surface 

Impoundment Treatment Option 

Total Industry Removals 

Pounds/Year TWPE/Year 

Fly Ash Removal (Baseline –> Technology Option) 478,000,000 2,520,000 

Bottom Ash Removal (Baseline –> Technology Option) 1,700,000,000 2,720,000 

Note: Excludes loadings 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 10-16 due to rounding. 

Table 10-18. Fly Ash and Bottom Ash Pollutant Removals Based on Oil-Fired Units and 

Units 50 MW or Less Not Installing Technology Basis 

Type of Ash 

Surface 

Impoundment Treatment Option 

Total Industry Removals 

Pounds/Year TWPE/Year 

Fly Ash Removal (Baseline –> Technology Option) 471,000,000 2,490,000

Bottom Ash Removal (Baseline –> Technology Option) 1,700,000,000 2,710,000 

Note: Excludes loadings 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 10-16 due to rounding. 

Table 10-19. Industry-Level Combustion Residual Landfill Leachate Loadings for All Units 

Treatment Option 

Number of 

Plants 

Total Industry 

Flow 

(MGD) 

Total Industry Loadings 

Pounds/Year TWPE/Year 

Baseline 102 7.90 89,800,000 56,500 

One-Stage Chemical Precipitation 102 7.90 80,900,000 20,900 

One-Stage Chemical Precipitation With 

Biological Treatment 

102 7.90 61,800,000 13,600 

Note: Excludes loadings for BOD, COD, TSS and TDS. 

Note: Loadings are rounded to three significant figures. 

Table 10-20. Industry-Level Combustion Residual Landfill Leachate Loadings 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 102 7.90 89,800,000 56,500 

One-Stage Chemical Precipitation 102 7.90 80,900,000 20,900 

One-Stage Chemical Precipitation With 

Biological Treatment 

102 7.90 61,800,000 13,600 

Note: Excludes loadings for BOD, COD, TSS and TDS. 

Note: Loadings are rounded to three significant figures. 
Chapter 10 –Pollutant Loadings and Removals Methodology 

10-41 

Table 10-21. Combustion Residual Leachate Loadings Removals for All Units 

Technology Option 

Total Industry Pollutant Removals 

Pounds/Year TWPE/Year 

Removal (Baseline –> One-Stage Chemical Precipitation) 8,900,000 35,600 

Removal (Baseline –> One-Stage Chemical Precipitation With 

Biological Treatment) 

28,000,000 42,900 

Note: Excludes loadings 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 10-19 due to rounding. 

Table 10-22. Combustion Residual Leachate Loadings Removals 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 –> One-Stage Chemical Precipitation) 8,900,000 35,600 

Removal (Baseline –> One-Stage Chemical Precipitation With 

Biological Treatment) 

28,000,000 42,900 

Note: Excludes loadings 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 10-20 due to rounding.
Chapter 11 – Summary of Costs and Pollutant Removals by Regulatory Option

11-1 

CHAPTER 11 

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 11-1 lists each regulatory option that 

EPA evaluated along with the associated treatment technology for all of the affected 

wastestreams. The Agency 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. All tables and figures referenced in 

this chapter are presented at the end of the chapter. 

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 11-1, to generate an industry-level estimated compliance cost for each 

regulatory option. Table 11-2 presents the estimated compliance cost for each of the five 

regulatory options based on all units discharging the various wastestreams installing the 

appropriate technology basis. Table 11-3 presents the estimated compliance cost for each of the 

five regulatory options based on the oil-fired units and units 50 MW or less not needing to install 

the appropriate technology basis. For each regulatory option, the capital costs, annual operating 

and maintenance costs, 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 Chapter 10, EPA combined the plant-level pollutant loadings for the 

appropriate technology options, based on the information specified in Table 11-1, to calculate 

industry-level estimated pollutant loadings and pollutant removals for each regulatory option. 

Table 11-4 presents the total industry loadings and pollutant removals at baseline and for each of 

the five regulatory options based on all units discharging the various wastestreams installing the 

appropriate technology basis. Table 11-5 presents the total industry loadings and pollutant 

removals at baseline and for each of the five regulatory options based on the oil-fired units and 

units 50 MW or less not needing to install the appropriate technology basis. EPA excluded the 

pollutant parameters biochemical oxygen demand (BOD), chemical oxygen demand (COD), 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. 
Chapter 11 – Summary of Costs and Pollutant Remo

11-2 

Table 11-1. Treatment Technologies Basis by Regulatory Option 

Regulatory 

Option 

Treatment Technologya 

FGD Wastewater 

Fly Ash 

Transport 

Water 

Bottom 

Ash 

Transport 

Water 

Combustion Residual 

Leachate 

Gasification 

Wastewater 

Chemical 

Precipitation 

Chemical 

Precipitation 

With 

Biological 

Treatment 

Chemical 

Precipitation 

With VaporCompression 

Evaporation 

Dry 

Vacuum 

System 

MDS/ 

Remote 

MDS 

Chemical 

Precipitation 

Chemical 

Precipitation 

With 

Biological 

Treatment 

VaporCompression 

Evaporation 

1 X X 2 X X 3 X X X 4 X X X Xb X 5 X X X X X 

a Table only presents the technology option evaluated for the costs and pollutant removals. All other appropriate technology cost modul

the compliance costs (e.g., compliance monitoring, transportation, disposal). 

b Any plant discharging both FGD wastewater and combustion residual leachate was assumed to combine the two wastestreams and tre

system, except at certain plants where the plant already had FGD wastewater treatment in place, as described in Section 9.3. Therefore, wastestreams were assumed to be combined, the combustion residual leachate costs and pollutant loadings were evaluated based on chebiological treatment. 
Chapter 11 – Summary of Costs and Pollutant Removals by Regulatory Option 

11-3 

Table 11-2. Cost of Implementation by Regulatory Option for All Units 

[In millions of pre-tax 2010 dollars] 

Regulatory 

Option 

Number 

of Plants 

Capital 

Costs 

Annual 

O&M 

Costs 

One Time 

Costs 

Recurring Costs 

3-year 5-year 6-year 10-year 

1 117 $1,460 $194 $0 $0 $0 $10 ($33) 

2 117 $2,510 $257 $0 $0 $0 $10 ($33) 

3 167 $2.927 $437 $0 $0 $0 $10 ($57) 

4 294 $8,206 $1,016 $0.6 $33 $69 $16 ($146) 

5 294 $11,970 $1,782 $0.6 $33 $69 $19 ($146) 

Table 11-3. Cost of Implementation by Regulatory Option Based on Oil-Fired Units and 

Units 50MW or Less Not Installing Technology Basis 

[In millions of pre-tax 2010 dollars] 

Regulatory 

Option 

Number 

of Plants 

Capital 

Costs 

Annual 

O&M 

Costs 

One Time 

Costs 

Recurring Costs 

3-year 5-year 6-year 10-year 

1 116 $1,450 $194 $0 $0 $0 $10 ($33) 

2 116 $2,499 $257 $0 $0 $0 $10 ($33) 

3 155 $2,897 $434 $0 $0 $0 $10 ($54) 

4 277 $8,011 $988 $0.6 $28 $65 $16 ($137) 

5 277 $11,755 $1,753 $0.6 $28 $65 $19 ($137) 

Table 11-4. Estimated Pollutant Removals by Regulatory Option for All Units

Regulatory Option 

Total Industry Loadings Total Industry Removal a

Pounds/Year TWPE/Year Pounds/Year TWPE/Year 

Baseline 5,500,000,000 8,320,000 0 0 

1 5,920,000,000 6,780,000 -419,000,000 1,540,000 

2 4,350,000,000 5,700,000 1,160,000,000 2,620,000 

3 3,870,000,000 3,180,000 1,630,000,000 5,140,000 

4 2,150,000,000 426,000 3,350,000,000 7,890,000 

5 91,500,000 53,800 5,410,000,000 8,270,000 

Note: Excludes 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. 

a

 Compared to baseline. 

b

 Characterization data used to estimate pollutant concentrations for baseline FGD surface impoundments does not 

include concentration data for ammonia, hexavalent chromium, and TKN. These pollutants are included in the postcompliance loadings and as a result appear to increase in concentration from baseline to technology option. 
Chapter 11 – Summary of Costs and Pollutant Removals by Regulatory Option 

11-4 

Table 11-5. Estimated Pollutant Removals by Regulatory Option Based on Oil-Fired Units 

and Units 50 MW or Less Not Installing Technology Basis 

Regulatory Option 

Total Industry Loadings Total Industry Removal a

Pounds/Year TWPE/Year Pounds/Year TWPE/Year 

Baseline 5,500,000,000 8,320,000 0 0 

1 5,920,000,000 6,790,000 -417,000,000b

 1,530,000 

2 4,350,000,000 5,710,000 1,160,000,000 2,620,000 

3 3,880,000,000 3,220,000 1,630,000,000 5,100,000 

4 2,170,000,000 474,000 3,340,000,000 7,850,000 

5 107,000,000 102,000 5,400,000,000 8,220,000 

Note: Excludes 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. 

a

 Compared to baseline. 

b

 Characterization data used to estimate pollutant concentrations for baseline FGD surface impoundments does not 

include concentration data for ammonia, hexavalent chromium, and TKN. These pollutants are included in the postcompliance loadings and as a result appear to increase in concentration from baseline to technology option. 
Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates 

12-1 

CHAPTER 12 

EVALUATION OF COST AND POLLUTANT REMOVAL 

ESTIMATES 

This chapter 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, the 

QAPP). The activities included: 

 Verifying that the collected cost data met the data acceptance specifications presented 

in QAPP Table 2-3; 

 Checking database code, spreadsheet data entry, and calculations and documenting 

these checks for databases and spreadsheets developed to estimate costs and pollutant 

loadings; and 

 Verifying that the estimated costs met the quality specifications presented in QAPP 

Table 2-4. 

All tables referenced in this chapter are presented at the end of the chapter. 

12.1 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 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 12-1, 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 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 (1981) and U.S. 

EPA Full-Scaled Field Evaluation of Waste Disposal from Coal-fired Electric Generating Plants

(1985). These estimates predate the time period specified for the currency criterion; however, 

these estimates are the “best available” and suitable for the estimate of costs associated with 

baseline operations. 
Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates 

12-2 

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 vapor-compression evaporation of FGD wastewater and/or 

combustion residual landfill 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 12-1, 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 vapor-compression evaporation of FGD wastewater and/or combustion residual 

landfill leachate; dry vacuum fly ash handling; and MDS or remote MDS for bottom ash 

handling were obtained from vendors that do business with power plants and thus met this 

specification. 

Although quotes for other equipment were from vendors that may or may not directly 

serve 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, disposal). For this reason, although the quotes in some cases are not from 

vendors that directly serve 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 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 survey responses. In this way, EPA met the 

specification for accuracy and reliability by using industry-specific data. 

Comparability. EPA requested 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 only provided 

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 survey costs to directly develop industry-specific labor rates and 

indirect cost factors. 

12.2 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. Chapter 3 of this report 

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 
Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates 

12-3 

remainder of the data came from secondary data (e.g., industry-provided monitoring data, Steam 

Electric Survey data, EPRI reports, 1974 and 1982 TDDs). 

EPA reviewed the data collected as part of the EPA sampling program to evaluate 

whether it was 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 – 2012i, 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. Table 12-2 presents the acceptance criteria EPA used to evaluate whether these data 

were sufficient for use in the loadings analysis. Table 12-3 presents the evaluation of each of 

these secondary data sources to the monitoring data acceptance criteria. 

12.3 DEVELOPING AND CHECKING THE COST AND LOADINGS MODELS

EPA developed a detailed cost model for estimating total installed capital costs and 

operating and maintenance costs for each individual power plant, as described earlier in this 

report. EPA also developed a detailed loadings model to estimate the baseline and postcompliance loadings for each individual power plant, as described in Chapter 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 models 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 re-checked 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 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: 
Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates 

12-4 

 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;74 and 

 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 re-checked 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. 

12.4 EVALUATING COST ESTIMATE QUALITY

Verification of the completed cost estimates means determining if estimated costs meet 

the data acceptance criteria specified in Table 12-4 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 on-going operating and 

maintenance costs. The cost estimates fully met these specifications. Table 12-4 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 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 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 (<20 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 power plants did not match the 

BAT design used by EPA for the technology options (or there wasn’t enough documentation to 

 

74 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 

Section 8.5) but did not calculate a pollutant loading. 
Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates 

12-5 

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 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 survey 

compared to model estimates. 

In certain cases, such as for vapor-compression 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 vapor-compression 

evaporation system costs. 

12.5 REFERENCES

1. Eastern Research Group (ERG). 2012a. Final Sampling Episode Report, Duke Energy 

Carolinas’ Belews Creek Steam Station. (13 March). DCN SE01379. 

2. Eastern Research Group (ERG). 2012b. Final Sampling Episode Report, We Energies’ 

Pleasant Prairie Power Plant. (13 March). DCN SE01414. 

3. Eastern Research Group (ERG). 2012c. Non-CBI_Final Sampling Episode Report, Duke 

Energy Miami Fort Station. (13 March). DCN SE01304. 

4. Eastern Research Group (ERG). 2012d. Final Sampling Episode Report, Duke Energy 

Carolinas’ Allen Steam Station. (13 March). DCN SE01372. 

5. Eastern Research Group (ERG). 2012e. Final Sampling Episode Report, Mirant MidAtlantic, LLC’s Dickerson Generating Station. (13 March). DCN SE01385. 

6. Eastern Research Group (ERG). 2012f. Final Sampling Episode Report, Allegheny 

Energy’s Hatfield’s Ferry Power Station. (13 March). DCN SE01391. 

7. Eastern Research Group (ERG). 2012g. Final Sampling Episode Report, RRI Energy’s 

Keystone Generating Station. (13 March). DCN SE01406. 

8. Eastern Research Group (ERG). 2012h. Final Sampling Episode Report and Site Visit 

Notes, Enel’s Federico II Power Plant (Brindisi). (8 August). DCN SE02013. 
Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates 

12-6 

9. Eastern Research Group (ERG). 2012i. Final Power Plant Monitoring Data Collected 

Under Clean Water Act Section 308 Authority (“CWA 308 Monitoring Data”). (30 May). 

DCN SE01326. 

10. U.S. EPA. 2009. 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 00003. 
Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates 

12-7 

Table 12-1. 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 12-2. Monitoring Data Acceptance Criteria 

Type of Data 

Data Usable to Demonstrate System Performance/

Efficiency 

Data Usable to Estimate 

Baseline Discharges 

Monitoring Data (e.g., 

NPDES permit, 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. 
Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates 

12-8 

Table 12-3. Evaluation of Monitoring Data for Use in Loadings Analysis 

Source Type of Data Evaluation of Data 

Duke Energy Submitted 

Monitoring Data for 

Belews Creek and Allen 

Data representing the influent and 

effluent from the full-scale FGD 

wastewater treatment system. 

These data meet all acceptance criteria for use in 

treatment performance and baseline estimates 

State Submitted 

Monitoring Data for 

Roxboro 

Data representing the influent and 

effluent from the full-scale FGD 

wastewater treatment system. 

EPA used the effluent from the settling pond, 

which is the influent to the biological treatment 

system for use in the baseline estimates. Although 

these data do not represent effluent discharges, 

EPA considers the data to be representative of 

FGD pond effluent data because the total 

suspended solids (TSS) concentrations were less 

than 30 mg/La

. These data meet all other 

acceptance criteria. 

Steam Electric Survey 

Part G Sampling Data 

Data representing the untreated 

leachate collected from landfills 

containing combustion residuals. 

EPA used the untreated leachate data for use in 

baseline estimates. Although these data do not 

represent effluent discharges, EPA considers the 

data to be representative of leachate discharges 

because the TSS concentrations were less than 30 

mg/Lb

. These data meet all other acceptance 

criteria. 

EPRI PISCES Reports Data representing the effluent 

discharges from ash impoundments. 

Also contains loading breakouts for 

all components entering the 

impoundment. 

EPA used the ash impoundment effluent data for 

use in baseline estimates. Although these data 

represent operations from the late 1990s, EPA 

notes that the constituents of coal and the ash 

impoundment operations have not changed since 

that time and are still representative of discharges 

today. These data meet all other acceptance 

criteria. 

UWAG Provided Form 

2C Data 

Data representing the effluent 

discharges from outfalls containing 

FGD and/or ash wastestreams. 

EPA used the outfall data for use in baseline 

estimates. Although the analytical methods used 

were not identified in the data set, the data were 

collected as part of the Form 2C process; 

therefore, EPA assumed that the plants used 

approved methods specified by the permitting 

authority. These data meet all other acceptance 

criteria. 

1982 TDD Data representing the ash 

impoundment overflows. 

EPA used the ash impoundment effluent data 

from the TDD for use in baseline estimates. 

Although the analytical methods used were not 

identified in the data set, the data were obtained 

from EPA regional offices and the Tennessee 

Valley Authority; therefore, EPA assumed that 

these entities used approved methods. 

Additionally, although these data represent 

operations from the late 1970’s, EPA notes that 

the constituents of coal and the ash impoundment 

operations have not changed since that time and 

are still representative of discharges today. These 

data meet all other acceptance criteria. 

a

 There are 53 results for TSS in the dataset. Of these 53 results, only 6 have TSS values greater than 30 mg/L. 

b There are 232 results for TSS in the dataset. Of these 232 results, only 35 have TSS values greater than 30 mg/L. 
Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates 

12-9 

Table 12-4. 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 on-going operating and maintenance costs (annual 

costs). 

Include periodic operating and maintenance 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 
Appendix 

Appendix
Appendix

A1-1 

All Appendix Tables have been Redacted to protect information claimed as Confidential 

Business Information (CBI).