United States Office of Water EPA-821-R-13-002

Environmental Protection Washington, DC 20460 April 2013 

Agency

Technical Development 

Document for the Proposed 

Effluent Limitations 

Guidelines and Standards 

for the Steam Electric Power 

Generating Point Source 

Category
Technical Development Document for the 

Proposed Effluent Limitations Guidelines 

and Standards for the Steam Electric 

Power Generating Point Source Category

EPA-821-R-13-002

April 2013

U.S. Environmental Protection Agency

Office of Water (4303T)

Washington, DC 20460
Acknowledgements and Disclaimer

This document was prepared by the Environmental Protection Agency. Neither the United States 

Government nor any of its employees, contractors, subcontractors, or their employees make any 

warrant, expressed or implied, or assume any legal liability or responsibility for any third party’s 

use of or the results of such use of any information, apparatus, product, or process discussed in 

this report, or represents that its use by such party would not infringe on privately owned rights. 

Questions regarding this document should be directed to: 

U.S. EPA Engineering and Analysis Division (4303T) 

1200 Pennsylvania Avenue NW 

Washington, DC 20460 

(202) 566-1000 
Table of Contents

TABLE OF CONTENTS

Page 

SECTION 1 BACKGROUND ........................................................................................................... 1-1

1.1 Legal Authority ......................................................................................................... 1-1

1.2 Clean Water Act ....................................................................................................... 1-1

1.2.1 Best Practicable Control Technology Currently Available (BPT) .............. 1-3

1.2.2 Best Conventional Pollutant Control Technology (BCT) ........................... 1-3

1.2.3 Best Available Technology Economically Achievable (BAT) ................... 1-3

1.2.4 New Source Performance Standards (NSPS) .............................................. 1-4

1.2.5 Pretreatment Standards for Existing Sources (PSES) ................................. 1-4

1.2.6 Pretreatment Standards for New Sources (PSNS) ....................................... 1-4

1.3 Regulatory History of the Steam Electric Power Generating Point Source 

Category .................................................................................................................... 1-5

1.3.1 Summary of Current ELGs Discharge Requirements and 

Applicability ................................................................................................ 1-5

1.3.2 Detailed Study of the Steam Electric Power Generating Point Source 

Category ...................................................................................................... 1-8

1.3.3 Other Statutes and Regulatory Requirements Affecting Management 

of Steam Electric Power Generating Wastewaters ...................................... 1-9

SECTION 2 SUMMARY OF PROPOSED REGULATION ................................................................... 2-1

2.1 Summary of Proposed Revisions to Discharge Requirements ................................. 2-1

2.2 Revisions to Applicability Provision and Specialized Definitions ........................... 2-4

SECTION 3 DATA COLLECTION ACTIVITIES ............................................................................... 3-1

3.1 Steam Electric Power Generating Detailed Study .................................................... 3-1

3.2 Engineering Site Visits ............................................................................................. 3-2

3.3 Questionnaire for the Steam Electric Power Generating Effluent Guidelines ......... 3-4

3.4 Field Sampling Program ........................................................................................... 3-7

3.4.1 On-Site Sampling Activities ........................................................................ 3-8

3.4.2 CWA 308 Monitoring Program ................................................................. 3-14

3.5 EPA and State Sources ........................................................................................... 3-15

3.5.1 NPDES Permits and Fact Sheets ............................................................... 3-16

3.5.2 State Groups and Permitting Authorities ................................................... 3-16

3.5.3 1974 and 1982 Technical Development Documents for the Steam 

Electric Power Generating Point Source Category ................................... 3-16

3.5.4 CWA Section 316(b) - Cooling Water Intake Structures Supporting 

Documentation and Data ........................................................................... 3-17

3.5.5 Office of Air and Radiation ....................................................................... 3-18

3.5.6 Office of Research and Development ........................................................ 3-18

3.5.7 Office of Solid Waste and Emergency Response ...................................... 3-19

3.6 Industry-Submitted Data ......................................................................................... 3-19

3.6.1 Self-Monitoring Data ................................................................................. 3-19

3.6.2 NPDES Form 2C ....................................................................................... 3-20

3.7 Technology Vendor Data ........................................................................................ 3-20

3.8 Other Sources .......................................................................................................... 3-21

i 
Table of Contents

TABLE OF CONTENTS (Continued)

Page 

3.8.1 Utility Water Act Group ............................................................................ 3-21

3.8.2 Electric Power Research Institute .............................................................. 3-21

3.8.3 Department of Energy (DOE) ................................................................... 3-22

3.8.4 Literature and Internet Searches ................................................................ 3-23

3.8.5 Environmental Groups and Other Stakeholders ........................................ 3-23

3.9 Protection of Confidential Business Information ................................................... 3-23

3.10 References ............................................................................................................... 3-23

SECTION 4 STEAM ELECTRIC INDUSTRY DESCRIPTION ............................................................. 4-1

4.1 Overview of Electric Generating Industry ................................................................ 4-1

4.1.1 Electric Generating Industry Population ..................................................... 4-2

4.1.2 Applicability of Steam Electric Power Generating Effluent 

Guidelines .................................................................................................... 4-3

4.2 Steam Electric Generating Industry .......................................................................... 4-4

4.2.1 Steam Electric Generating Process .............................................................. 4-6

4.2.2 Combined Cycle Systems ............................................................................ 4-7

4.2.3 Integrated Gasification Combined Cycle Systems .................................... 4-10

4.2.4 Demographics of the Steam Electric Power Generating Industry ............. 4-12

4.3 Steam Electric Wastestreams Evaluated for New or Additional Controls in 

the Proposed ELGs ................................................................................................. 4-19

4.3.1 Fly Ash Transport Water ........................................................................... 4-19

4.3.2 Bottom Ash Transport Water .................................................................... 4-23

4.3.3 Flue Gas Desulfurization Wastewater ....................................................... 4-27

4.3.4 Flue Gas Mercury Control Wastewater ..................................................... 4-33

4.3.5 Landfill and Impoundment Leachate and Runoff ..................................... 4-34

4.3.6 Gasification Wastewater ............................................................................ 4-37

4.3.7 Metal Cleaning Waste ............................................................................... 4-38

4.4 Steam Electric Wastestreams Not Evaluated for New or Additional Controls 

in the Proposed ELGs ............................................................................................. 4-39

4.4.1 Condenser Cooling Water ......................................................................... 4-40

4.4.2 Coal Pile Runoff ........................................................................................ 4-41

4.4.3 Selected Low Volume Waste Sources ....................................................... 4-42

4.4.4 Selective Catalytic Reduction and Selective Non-Catalytic Reduction 

Wastewater ................................................................................................ 4-43

4.4.5 Carbon Capture Wastewater ...................................................................... 4-44

4.5 References ............................................................................................................... 4-46

SECTION 5 INDUSTRY SUBCATEGORIZATION ............................................................................. 5-1

5.1 Subcategorization Factors ......................................................................................... 5-1

5.2 Analysis of Subcategorization Factors ..................................................................... 5-1

5.2.1 Age of Plant or Generating Unit .................................................................. 5-2

5.2.2 Geographic Location ................................................................................... 5-2

5.2.3 Size .............................................................................................................. 5-2

5.2.4 Fuel Type ..................................................................................................... 5-3

5.3 References ................................................................................................................. 5-3

ii
Table of Contents

TABLE OF CONTENTS (Continued)

Page 

SECTION 6 WASTEWATER CHARACTERIZATION AND POLLUTANTS OF CONCERN .................. 6-1

6.1 FGD Wastewater ...................................................................................................... 6-1

6.2 Ash Transport Water ................................................................................................. 6-8

6.2.1 Fly Ash Transport Water ............................................................................. 6-8

6.2.2 Bottom Ash Transport Water ...................................................................... 6-8

6.2.3 Ash Transport Water Characteristics ........................................................... 6-9

6.3 Combustion Residual Landfill and Impoundment Leachate .................................. 6-12

6.4 Flue Gas Mercury Control Wastewater .................................................................. 6-17

6.5 Gasification Wastewater ......................................................................................... 6-18

6.6 Metal Cleaning Waste ............................................................................................. 6-20

6.7 Identification of Pollutants of Concern ................................................................... 6-24

6.7.1 FGD Wastewater Pollutants of Concern ................................................... 6-27

6.7.2 Ash Transport Water Pollutants of Concern ............................................. 6-28

6.7.3 Combustion Residual Leachate Pollutants of Concern ............................. 6-29

6.7.4 Gasification Wastewater Pollutants of Concern ........................................ 6-31

6.7.5 Flue Gas Mercury Control Wastewater Pollutants of Concern ................. 6-32

6.7.6 Nonchemical Metal Cleaning Wastes Pollutants of Concern .................... 6-33

6.8 References ............................................................................................................... 6-34

SECTION 7 TREATMENT TECHNOLOGIES AND WASTEWATER MANAGEMENT 

PRACTICES ....................................................................................................................... 7-1

7.1 FGD Wastewater Treatment Technologies and Management Practices .................. 7-1

7.1.1 Surface Impoundments ................................................................................ 7-3

7.1.2 Chemical Precipitation ................................................................................ 7-4

7.1.3 Biological Treatment ................................................................................... 7-9

7.1.4 Vapor-Compression Evaporation System ................................................. 7-13

7.1.5 Constructed Wetlands ................................................................................ 7-16

7.1.6 Design/Operating Practices Achieving Zero Discharge ............................ 7-17

7.1.7 Other Technologies Under Investigation ................................................... 7-19

7.2 Fly Ash Handling, Management, and Treatment Technologies ............................. 7-22

7.2.1 Wet Sluicing System ................................................................................. 7-24

7.2.2 Wet Vacuum Pneumatic System ............................................................... 7-25

7.2.3 Dry Vacuum System .................................................................................. 7-26

7.2.4 Pressure System ......................................................................................... 7-27

7.2.5 Combined Vacuum/Pressure System ........................................................ 7-28

7.2.6 Mechanical System .................................................................................... 7-29

7.3 Bottom Ash Handling, Management, and Treatment Technologies ...................... 7-29

7.3.1 Wet Sluicing System ................................................................................. 7-32

7.3.2 Mechanical Drag System ........................................................................... 7-33

7.3.3 Remote Mechanical Drag System ............................................................. 7-34

7.3.4 Dry Vacuum or Pressure System ............................................................... 7-36

7.3.5 Vibratory Belt System ............................................................................... 7-37

7.3.6 Mechanical System .................................................................................... 7-38

7.3.7 Complete Recycle System ......................................................................... 7-38

7.4 Combustion Residual Leachate .............................................................................. 7-39

7.5 Flue Gas Mercury Control Wastewater Treatment Technologies .......................... 7-41

iii
Table of Contents

TABLE OF CONTENTS (Continued)

Page 

7.6 Gasification Wastewater Treatment Technologies ................................................. 7-42

7.6.1 Vapor-Compression Evaporation System ................................................. 7-43

7.6.2 Cyanide Destruction .................................................................................. 7-43

7.7 Metal Cleaning Waste Treatment Technologies and Management Practices ........ 7-43

7.8 References ............................................................................................................... 7-48

SECTION 8 TECHNOLOGY OPTIONS CONSIDERED AS BASIS FOR REGULATION ........................ 8-1

8.1 Proposed Regulatory Options ................................................................................... 8-1

8.1.1 BPT/BCT ..................................................................................................... 8-1

8.1.2 Description of the Proposed BAT/NSPS/PSES/PSNS Options .................. 8-2

8.1.3 Rationale for the Proposed BAT Technology ........................................... 8-23

8.1.4 Rationale for the Proposed Best Available Demonstrated 

Control/NSPS Technology ........................................................................ 8-37

8.1.5 Rationale for the Proposed PSES Technology .......................................... 8-40

8.1.6 Rationale for the Proposed PSNS Technology .......................................... 8-43

8.1.7 Consideration of Future FGD Installations on the Analyses for the 

ELG Rulemaking ....................................................................................... 8-44

8.2 Timing of New Requirements ................................................................................ 8-46

8.3 References ............................................................................................................... 8-47

SECTION 9 ENGINEERING COSTS ................................................................................................ 9-1

9.1 Introduction ............................................................................................................... 9-1

9.2 Steam Electric Technology Option Cost Bases ........................................................ 9-3

9.2.1 FGD Wastewater ......................................................................................... 9-3

9.2.2 Fly Ash Transport Water ............................................................................. 9-4

9.2.3 Bottom Ash Transport Water ...................................................................... 9-4

9.2.4 Combustion Residual Leachate ................................................................... 9-5

9.2.5 Gasification Wastewater .............................................................................. 9-6

9.2.6 Flue Gas Mercury Control Wastewater ....................................................... 9-6

9.2.7 Nonchemical Metal Cleaning Wastes ......................................................... 9-6

9.3 Steam Electric Compliance Cost Methodology ........................................................ 9-6

9.4 Steam Electric Cost Model ....................................................................................... 9-8

9.4.1 Input Data to Technology Cost Modules ................................................... 9-10

9.4.2 Industry Assumptions/Factors ................................................................... 9-12

9.4.3 Technology Cost Modules ......................................................................... 9-13

9.4.4 Model Outputs ........................................................................................... 9-14

9.5 Costs Applicable to All Wastestreams ................................................................... 9-14

9.5.1 Compliance Monitoring Costs ................................................................... 9-15

9.5.2 Transportation Costs .................................................................................. 9-16

9.5.3 Disposal Costs ........................................................................................... 9-17

9.5.4 Impoundment Operation Costs .................................................................. 9-17

9.5.5 Impoundment BMP Costs ......................................................................... 9-18

9.6 FGD Wastewater .................................................................................................... 9-19

9.6.1 Chemical Precipitation .............................................................................. 9-19

9.6.2 Biological Treatment ................................................................................. 9-22

9.6.3 Vapor-Compression Evaporation .............................................................. 9-26

iv
Table of Contents

TABLE OF CONTENTS (Continued)

Page 

9.6.4 Estimated Industry-Level Costs for FGD Wastewater by Treatment 

Option ........................................................................................................ 9-27

9.6.5 Compliance Costs Associated with Planned FGD Systems ...................... 9-29

9.7 Ash Transport Water ............................................................................................... 9-29

9.7.1 Fly Ash Transport Water ........................................................................... 9-30

9.7.2 Bottom Ash Transport Water .................................................................... 9-34

9.7.3 Estimated Industry-Level Costs for Ash Handling Conversions .............. 9-39

9.8 Combustion Residual Landfill Leachate ................................................................ 9-41

9.9 Summary of National Engineering Costs ............................................................... 9-42

9.10 Compliance Costs for New Sources ....................................................................... 9-44

9.11 References ............................................................................................................... 9-47

SECTION 10 POLLUTANT LOADINGS AND REMOVALS ............................................................. 10-1

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

10.2 Wastestream Pollutant Characterization and Data Sources .................................... 10-4

10.2.1 FGD Wastewater Characterization ............................................................ 10-5

10.2.2 Ash Transport Water Characterization .................................................... 10-16

10.2.3 Baseline and Post-Compliance Combustion Residual Leachate 

Characterization ....................................................................................... 10-19

10.3 Wastewater Flow Rates for Baseline and Post-Compliance Pollutant 

Loadings ............................................................................................................... 10-21

10.3.1 FGD Wastewater Flow Rates for Pollutant Loadings ............................. 10-22

10.3.2 Ash Transport Water Flow Rates for Pollutant Loadings ....................... 10-22

10.3.3 Combustion Residual Landfill Leachate Flow Rates for Pollutant 

Loadings .................................................................................................. 10-23

10.4 Baseline and Post-Compliance Pollutant Loadings and TWPE Results .............. 10-23

10.4.1 FGD Wastewater Loadings and TWPE ................................................... 10-23

10.4.2 Ash Transport Water Loadings and TWPE ............................................. 10-26

10.4.3 Combustion Residual Landfill Leachate Loadings and TWPE ............... 10-29

10.4.4 Pollutant Loadings and Removals for Regulatory Options ..................... 10-31

10.5 References ............................................................................................................. 10-32

SECTION 11 POLLUTANTS SELECTED FOR REGULATION ......................................................... 11-1

11.1 Selection of Regulated Pollutant for Direct Dischargers ........................................ 11-1

11.1.1 FGD Wastewater ....................................................................................... 11-1

11.1.2 Fly Ash Transport Water ........................................................................... 11-5

11.1.3 Bottom Ash Transport Water .................................................................... 11-5

11.1.4 Combustion Residual Leachate ................................................................. 11-5

11.1.5 Gasification Wastewater ............................................................................ 11-6

11.1.6 Flue Gas Mercury Control Wastewater ..................................................... 11-6

11.1.7 Nonchemical Metal Cleaning Wastes ....................................................... 11-6

11.2 Regulated Pollutant Selection Methodology for Indirect Dischargers ................. 11-10

11.2.1 Methodology for Determining BAT Percent Removals .......................... 11-12

11.2.2 Methodology for Determining POTW Percent Removals ...................... 11-12

11.2.3 Results of POTW Pass-Through Analysis .............................................. 11-13

11.3 References ............................................................................................................. 11-15

v 
Table of Contents

TABLE OF CONTENTS (Continued)

Page 

SECTION 12 NON-WATER QUALITY ENVIRONMENTAL IMPACTS ........................................... 12-1

12.1 Energy Requirements .............................................................................................. 12-1

12.2 Air Emissions Pollution .......................................................................................... 12-4

12.3 Solid Waste Generation ........................................................................................ 12-11

12.4 Reductions in Water Use ...................................................................................... 12-13

12.5 References ............................................................................................................. 12-14

SECTION 13 LIMITATIONS AND STANDARDS: DATA SELECTION AND CALCULATION ............ 13-1

13.1 Data Selection ......................................................................................................... 13-1

13.1.1 Data Selection Criteria .............................................................................. 13-1

13.1.2 Data Selection for Each Technology Option ............................................. 13-3

13.1.3 Combining Data from Multiple Sources within a Plant ............................ 13-6

13.2 Data Exclusions and Substitutions .......................................................................... 13-6

13.2.1 Data Exclusions ......................................................................................... 13-6

13.2.2 Data Substitutions ...................................................................................... 13-7

13.3 Data Aggregation .................................................................................................... 13-8

13.3.1 Aggregation of Field Duplicates ............................................................... 13-8

13.3.2 Aggregation of Overlapping Samples ....................................................... 13-9

13.4 Data Editing Criteria ............................................................................................... 13-9

13.5 Overview of Limitations ....................................................................................... 13-10

13.5.1 Objectives ................................................................................................ 13-10

13.5.2 Selection of Percentiles ........................................................................... 13-11

13.5.3 Compliance with Limitations .................................................................. 13-11

13.6 Calculation of the Limitations .............................................................................. 13-13

13.6.1 Calculation of Option Long-Term Average ............................................ 13-13

13.6.2 Calculation of Option Variability Factors and Limitations ..................... 13-14

13.6.3 Adjustment for Autocorrelation Factors .................................................. 13-14

13.7 Transfers of the Limitations .................................................................................. 13-15

13.7.1 Transfer of Arsenic and Mercury Limitations from Chemical 

Precipitation to Leachate ......................................................................... 13-16

13.7.2 Transfer of Arsenic and Mercury Limitations from Chemical 

Precipitation to Biological Treatment for FGD Wastewater ................... 13-16

13.8 Summary of the Limitations ................................................................................. 13-17

13.8.1 Summary of the Plant-Specific Long-Term Average and Variability 

Factors for Each Treatment Technology Option for FGD and 

Gasification Wastewaters ........................................................................ 13-18

13.8.2 Summary of the Option Long-Term Averages, Option Variability 

Factors, and Limitations for Each Treatment Technology Option for 

FGD, Gasification, and Leachate Wastewaters ....................................... 13-21

13.9 Engineering Review of the Limitations ................................................................ 13-23

13.9.1 Comparison of Limitations to Effluent Data Used As Basis for the 

Limitations ............................................................................................... 13-23

13.9.2 Comparison of Proposed Limitations to Influent Data ............................ 13-28

13.10 References ............................................................................................................. 13-28

SECTION 14 REGULATORY IMPLEMENTATION ......................................................................... 14-1

vi 
Table of Contents

TABLE OF CONTENTS (Continued)

Page 

14.1 Implementation of the Limitations and Standards .................................................. 14-1

14.1.1 Timing ....................................................................................................... 14-1

14.1.2 Applicability of NSPS/PSNS .................................................................... 14-1

14.1.3 Legacy Wastes ........................................................................................... 14-2

14.1.4 Monitoring Requirements ........................................................................ 14-13

14.2 Analytical Methods ............................................................................................... 14-18

14.3 Upset and Bypass Provisions ................................................................................ 14-18

14.4 Variances and Modifications ................................................................................ 14-19

14.4.1 Fundamentally Different Factors Variances ............................................ 14-20

14.4.2 Economic Variances ................................................................................ 14-21

14.4.3 Water Quality Variances ......................................................................... 14-21

14.4.4 Thermal Discharge Variances ................................................................. 14-22

14.4.5 Net Credits ............................................................................................... 14-22

14.4.6 Removal Credits ...................................................................................... 14-22

14.5 References ............................................................................................................. 14-24

APPENDIX A – SURVEY DESIGN AND CALCULATION OF NATIONAL ESTIMATES

APPENDIX B – MODIFIED DELTA-LOG NORMAL DISTRIBUTION

vii 
List of Tables

List of Tables

Page 

1-1 Current Effluent Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category ................................................................................... 1-6

3-1 List of Site Visits Conducted During the Detailed Study and Rulemaking ..................... 3-3

3-2 Number of Plants in Each Fuel Classification in the Survey Sample Frame Used 

to Identify Survey Recipients........................................................................................... 3-6

3-3 Selection Criteria for Plants Included in EPA’s Sampling Program in the United 

States .............................................................................................................................. 3-11

3-4 Analytical Methods Used for EPA’s Sampling Program .............................................. 3-12

4-1 Distribution of U.S. Electric Generating Plants by NAICS Code in 2007 ...................... 4-3

4-2 Distribution of Prime Mover Types for Plants Regulated by the Steam Electric 

Power Generating Effluent Guidelines .......................................................................... 4-14

4-3 Distribution of Fuel Types Used by Steam Electric Generating Units .......................... 4-16

4-4 Distribution by Size of Steam Electric Capacity and Plants Regulated by 

the Steam Electric Power Generating Effluent Guidelines ............................................ 4-18

4-5 Distribution by Size of Steam Electric Generating Units Regulated by 

the Steam Electric Power Generating Effluent Guidelines ............................................ 4-18

4-6 Fly Ash Collection Practices in the Steam Electric Industry ......................................... 4-19

4-7 Fly Ash Handling Practices in the Steam Electric Industry ........................................... 4-21

4-8 Conversions of Wet Fly Ash Sluicing Systems Since 2000 .......................................... 4-23

4-9 Bottom Ash Handling Practices in the Steam Electric Industry .................................... 4-25

4-10 Conversions of Bottom Ash Sluicing Systems Since 2000 ........................................... 4-27

4-11 Types of FGD Scrubbers in the Steam Electric Industry ............................................... 4-30

4-12 Characteristics of Coal- and Petroleum Coke-Fired Generating 

Units with FGD Systems ............................................................................................... 4-30

4-13 Leachate Collection at Coal and Petroleum Coke Plants ............................................... 4-36

4-14 Age of Impoundment or Landfill Collecting Leachate .................................................. 4-36

4-15 Destination of Leachate in Steam Electric Industry ...................................................... 4-37

4-16 Cooling Water Discharge Average Flow Rates Reported in the 

Steam Electric Industry .................................................................................................. 4-41

4-17 Selected Low Volume Waste Sources in the Steam Electric Industry .......................... 4-42

4-18 Carbon Capture Wastewater 4-Day Average Concentration Data ................................ 4-45

6-1 FGD Slurry Blowdown Flow Rates ................................................................................. 6-2

6-2 FGD Wastewater Discharge at Steam Electric Power Plants by January 1, 2014 ........... 6-5

6-3 Average Pollutant Concentrations in Untreated FGD Wastewater .................................. 6-5

viii
List of Tables

List of Tables (Continued) 

Page 

6-4 Fly Ash Transport Water Flow Rates .............................................................................. 6-8

6-5 Bottom Ash Transport Water Flow Rates ........................................................................ 6-9

6-6 Ash Wastewater Discharge at Steam Electric Power Plants .......................................... 6-10

6-7 Fly Ash Transport Water Characteristics ....................................................................... 6-11

6-8 Leachate Generation in the Steam Electric Industry ...................................................... 6-13

6-9 Landfill Leachate Discharged by Coal- and Petroleum Coke-Fired Power Plants in 

2009................................................................................................................................ 6-14

6-10 Untreated Landfill Leachate Concentrations ................................................................. 6-15

6-11 Untreated Impoundment Leachate Concentrations ........................................................ 6-16

6-12 Mercury Concentrations in Fly Ash with and without ACI Systems ............................ 6-18

6-13 Untreated Gasification Wastewater Concentrations ...................................................... 6-19

6-14 Metal Cleaning Waste Generation Frequency Reported in the Steam Electric 

Survey ............................................................................................................................ 6-21

6-15 Metal Cleaning Wastewater Flow Rates Reported in the Steam Electric Survey ......... 6-23

6-16 Baseline Values for Steam Electric Industry POCs ....................................................... 6-26

6-17 Pollutants of Concern – FGD Wastewater ..................................................................... 6-27

6-18 Pollutants of Concern – Ash Transport Water ............................................................... 6-29

6-19 Pollutants of Concern – Landfill Leachate .................................................................... 6-30

6-20 Pollutants of Concern – Impoundment Leachate ........................................................... 6-31

6-21 Pollutants of Concern – Gasification Wastewater ......................................................... 6-31

6-22 Pollutants of Concern – Flue Gas Mercury Control Wastewater .................................. 6-33

6-23 Pollutants of Concern – Nonchemical Metal Cleaning Wastes ..................................... 6-34

7-1 Destination of Metal Cleaning Wastewaters .................................................................. 7-46

8-1 Steam Electric Regulatory Options .................................................................................. 8-4

8-2 Summary of Pass Through Analysis .............................................................................. 8-41

9-1 Technology Costs Modules Used to Estimate Compliance Costs ................................... 9-9

9-2 Number of Plants Expected to Incur Compliance Costs by Wastestream and 

Regulatory Option .......................................................................................................... 9-10

9-3 Estimated Industry-Level Costs for FGD Wastewater Based on Oil-Fired Units 

and Units 50 MW or Less Not Installing Technology Basis ......................................... 9-28

9-4 Estimated Industry-Level Costs for FGD Wastewater Based on Oil-Fired Units 

and Units at Plants with a Total Plant-Level Wet Scrubbed Capacity of Less Than 

2,000 MW Not Installing Technology Basis ................................................................. 9-29

ix
List of Tables

List of Tables (Continued) 

Page 

9-5 Estimated Industry-Level Costs for Fly Ash Handling Conversions Based on OilFired Units and Units 50 MW or Less Not Installing Technology Basis ...................... 9-40

9-6 Estimated Industry-Level Costs for Bottom Ash Handling Conversions Based on 

Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis ................ 9-40

9-7 Estimated Industry-Level Costs for Bottom Ash Handling Conversions Based on 

Oil-Fired Units and Units 400 MW or Less Not Installing Technology Basis .............. 9-41

9-8 Estimated Industry-Level Costs for Combustion Residual Leachate Based on OilFired Units and Units 50 MW or Less Not Installing Technology Basis ...................... 9-42

9-9 Technology Options and Other Costs Included in the Estimated Compliance Costs 

for Each Regulatory Option ........................................................................................... 9-43

9-10 Cost of Implementation by Regulatory Option [In millions of pre-tax 

2010 dollars] .................................................................................................................. 9-43

9-11 NSPS Compliance Cost Scenarios Evaluated for the Proposed Rule ............................ 9-45

9-12 Estimated Industry-Level NSPS Costs .......................................................................... 9-46

10-1 POTW Removals ........................................................................................................... 10-3

10-2 Data Sets Used in the FGD Loadings Calculation ......................................................... 10-6

10-3 Average Effluent Pollutant Concentrations for FGD Surface Impoundments .............. 10-8

10-4 Average Effluent Pollutant Concentrations for One-Stage Chemical Precipitation 

System .......................................................................................................................... 10-10

10-5 Average Effluent Pollutant Concentrations for One-Stage Chemical Precipitation 

System with Biological Treatment ............................................................................... 10-13

10-6 Average Effluent Pollutant Concentrations for One-Stage Chemical Precipitation 

System with Vapor-Compression Evaporation ............................................................ 10-15

10-7 Average Effluent Pollutant Concentration for Ash Impoundment Systems ................ 10-18

10-8 Average Pollutant Concentrations Untreated Landfill Leachate ................................. 10-20

10-9 Industry-Level FGD Wastewater Loadings Excluding BOD, COD, TDS, and TSS 

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

Technology Basis ......................................................................................................... 10-25

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

or Less Not Installing Technology Basis ..................................................................... 10-25

10-11 Industry-Level FGD Wastewater Loadings Excluding BOD, COD, TDS, and TSS 

and Based on Oil-Fired Units and Plants with a Total Wet Scrubbed Capacity of 

Less Than 2,000 MW Not Installing Technology Basis .............................................. 10-26

10-12 FGD Wastewater Pollutant Removals Based on Oil-Fired Units and Plants with a 

Total Wet Scrubbed Capacity of Less Than 2,000 MW Not Installing Technology 

Basis ............................................................................................................................. 10-26

x 
List of Tables

List of Tables (Continued) 

Page 

10-13 Industry-Level Ash Impoundment Loadings by Type of Impoundment Excluding 

BOD, COD, TDS, and TSS ......................................................................................... 10-28

10-14 Fly Ash and Bottom Ash Pollutant Removals Based on Oil-Fired Units and Units 

50 MW or Less Not Installing Technology Basis ........................................................ 10-28

10-15 Bottom Ash Pollutant Removals Based on Oil-Fired Units and Units 400 MW or 

Less Not Installing Technology Basis ......................................................................... 10-29

10-16 Industry-Level Combustion Residual Landfill Leachate Loadings Excluding 

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

Less Not Installing Technology Basis ......................................................................... 10-30

10-17 Combustion Residual Landfill Leachate Pollutant Removals Based on Oil-Fired 

Units and Units 50 MW or Less Not Installing Technology Basis .............................. 10-31

10-18 Estimated Pollutant Removals by Regulatory Option Based on Oil-Fired Units 

and Units 50 MW or Less Not Installing Technology Basis ....................................... 10-31

11-1 Pollutants Considered for Regulation for Direct Dischargers (BAT/NSPS): FGD 

Wastewater ..................................................................................................................... 11-3

11-2 Pollutants Considered for Regulation for Direct Dischargers (BAT/NSPS): 

Combustion Residual Leachate...................................................................................... 11-8

11-3 Pollutants Considered for Regulation for Direct Dischargers (BAT/NSPS): 

Gasification Wastewater ................................................................................................ 11-9

11-4 POTW Pass-Through Analysis (FGD Wastewater) – PSES/PSNS ............................. 11-14

11-5 POTW Pass-Through Analysis (Combustion Residual Leachate) – PSES/PSNS....... 11-14

11-6 POTW Pass-Through Analysis (Gasification Wastewater) – PSES/PSNS ................. 11-15

12-1 Industry-Level Energy Requirements by Regulatory Option ........................................ 12-2

12-2 Summary of IPM Emissions Factors by NERC Region and Across Steam Electric 

Plants .............................................................................................................................. 12-6

12-3 MOBILE6.2 and California Climate Action Registry 

Transportation Emission Rates ...................................................................................... 12-8

12-4 Industry-Level Air Emissions Associated with Auxiliary Electricity and 

Transportation by Regulatory Option ............................................................................ 12-9

12-5 Industry-Level Net Air Emissions For the Preferred Regulatory Options .................. 12-10

12-6 Electric Power Industry Air Emissions ........................................................................ 12-11

12-7 Industry-Level Solid Waste Increases by Regulatory Option ...................................... 12-13

12-8 Industry-Level Process Water Reduction by Regulatory Option ................................ 12-14

12-9 Wastewater Discharge at Steam Electric Power Plants ............................................... 12-14

13-1 Aggregation of Field Duplicates .................................................................................... 13-9

xi 
List of Tables

List of Tables (Continued) 

Page 

13-2 Summary of Autocorrelation Values Used in Calculating the 

Limitations for Biological Treatment Technology Option for FGD Wastewater ........ 13-15

13-3 Plant-Specific Results for Chemical Precipitation as the 

Technology Basis for FGD Wastewater ...................................................................... 13-18

13-4 Plant-Specific Results for Biological Treatment as the Technology Basis for FGD 

Wastewater ................................................................................................................... 13-19

13-5 Plant-Specific Results for Vapor-Compression Evaporation 

(Crystallizer Condensate) as the Technology Basis for FGD Wastewater .................. 13-20

13-6 Plant-Specific Results for Vapor-Compression Evaporation (Vapor-Compression 

Evaporator Condensate) as the Technology Basis for Gasification Wastewater ......... 13-21

13-7 Proposed Option Long-Term Averages, Option Variability Factors, 

and Limitations for Each of the FGD, Gasification, and Leachate Technology 

Options ......................................................................................................................... 13-22

xii 
List of Figures

List of Figures

Page 

4-1 Types of U.S. Electric Generating Plants ........................................................................ 4-1

4-2 Steam Electric Process Flow Diagram ............................................................................. 4-8

4-3 Combined Cycle Process Flow Diagram ......................................................................... 4-9

4-4 IGCC Process Flow Diagram......................................................................................... 4-11

4-5 Plant-Level Fly Ash Handling Systems ......................................................................... 4-22

4-6 Plant-Level Bottom Ash Handling Systems .................................................................. 4-26

4-7 Typical FGD Systems .................................................................................................... 4-28

4-8 Plants Operating Wet FGD Scrubber Systems .............................................................. 4-32

4-9 Capacity of Wet Scrubbed Units by Decade .................................................................. 4-33

4-10 Diagram of Landfill Leachate Generation and Collection ............................................. 4-35

6-1 Distribution of FGD Wastewater Treatment Systems among the 117 

Plants Discharging FGD Wastewater by January 1, 2014 ............................................... 6-7

7-1 Distribution of FGD Wastewater Treatment/Management Systems 

Among 145 Plants Currently Operating Wet FGD Systems orPlanned Wet 

FGD Systems Operating by 2014 .................................................................................... 7-3

7-2 Process Flow Diagram for a Hydroxide and Sulfide Chemical Precipitation 

System .............................................................................................................................. 7-8

7-3 Process Flow Diagram for an Anoxic/Anaerobic Biological Treatment System .......... 7-11

7-4 Chemical Precipitation and Softening Pretreatment for FGD Wastewater Prior to 

Vapor-Compression Evaporation ................................................................................... 7-14 

7-5 Process Flow Diagram for a Vapor-Compression Evaporation System ........................ 7-15

7-6 Distribution of Fly Ash Handling Systems for Coal-, Petroleum Cokeand Oil-Fired Units in the Steam Electric Industry ....................................................... 7-23

7-7 Distribution of Fly Ash Handling System Types Other Than Wet 

Sluicing for Coal-, Petroleum Coke-, and Oil-fired Units Reported in the 

Steam Electric Survey .................................................................................................... 7-24

7-8 Schematic of Dry Vacuum, Pressure, and Combined Vacuum/Pressure System .......... 7-27

7-9 Pressure System Airlock Valve ..................................................................................... 7-28

7-10 Distribution of Bottom Ash Handling Systems for Coal-, Petroleum 

Coke-, and Oil-Fired Units Reported in the Steam Electric Survey .............................. 7-31

7-11 Distribution of Bottom Ash Handling System Types Other Than Wet Sluicing for 

Coal-, Petroleum Coke-, and Oil-Fired Units Reported in the Steam Electric 

Survey ............................................................................................................................ 7-31

7-12 Bottom Ash Dewatering Bin System ............................................................................. 7-33

7-13 Mechanical Drag System ............................................................................................... 7-34

xiii
List of Figures

List of Figures (Continued) 

Page

7-14 Remote Mechanical Drag System .................................................................................. 7-35

7-15 Water Flow Inside the Remote Mechanical Drag System Trough ................................ 7-36

7-16 Dry Vacuum or Pressure Bottom Ash Handling System ............................................... 7-37

7-17 Vibratory Bottom Ash Handling System ....................................................................... 7-38

7-18 Distribution of Treatment Systems for Leachate from Landfills 

and Impoundments Containing Combustion Residual Wastes ...................................... 7-40

14-1 Legacy FGD Wastewater Treatment Scenario (Regulatory Options 3 and 4a) ............ 14-4

14-2 Legacy Fly Ash Transport Water Treatment Scenario (Regulatory Options 3a, 3b, 

3, and 4a) ........................................................................................................................ 14-5

14-3 Complete Recycle Fly Ash Transport Water Treatment Scenario (Regulatory 

Options 3a, 3b, 3, and 4a) .............................................................................................. 14-6

14-4 Partial Recycle Bottom Ash Transport Water Treatment Scenario (Regulatory 

Option 4) ........................................................................................................................ 14-7

14-5 Legacy Fly Ash Transport Water Combined with Bottom Ash Transport Water 

Treatment Scenario (Regulatory Options 3a, 3b, and 3) ............................................... 14-9

14-6 Legacy Fly Ash Transport Water Combined with Bottom Ash Transport Water 

Treatment Scenario (Regulatory Option 4) .................................................................. 14-10

14-7 Legacy FGD Wastewater and Fly Ash Transport Water Combined with Bottom 

Ash Transport Water Treatment Scenario (Regulatory Option 3) ............................... 14-12

14-8 Legacy FGD Wastewater and Fly Ash Transport Water Combined with Bottom 

Ash Transport Water Treatment Scenario (Regulatory Option 4) ............................... 14-13

xiv 
Section 1 - Background

1-1 

SECTION 1

BACKGROUND 

This section provides background information on the development of revised effluent 

limitations guidelines and standards (ELGs) proposed for the Steam Electric Power Generating 

Point Source Category (Steam Electric Category). Sections 1.1 and 1.2 discuss the legal authority 

and regulatory background for the proposed rule. Section 1.3 presents a history of Steam Electric 

Category rulemaking activities.

In addition to this report, the proposed Steam Electric ELGs are supported by a number 

of reports including: 

• Environmental Assessment for the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category, Document 

No. 821-R-13-003. This report summarizes the environmental and human health 

improvements that result from implementation of the proposed ELGs. 

• Benefits and Cost Analysis for the Proposed Steam Electric Effluent Limitations 

Guidelines and Standards for the Steam Electric Power Generating Point Source 

Category, Document No. EPA-821-R-13-004. This report summarizes the monetary 

benefits and societal costs that result from implementation of the proposed ELGs. 

• Regulatory Impact Analysis for Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category (RIA), 

Document No. EPA-821-R-13-005. This report presents a profile of the steam electric 

industry, a summary of the costs and impacts associated with the regulatory options, 

and an assessment of the proposed ELGs impact on employment and small 

businesses.

The proposed effluent limitation guidelines and standards for the Steam Electric Power 

Generating Point Source Category are based on data generated or obtained in accordance with 

EPA’s Quality Policy and Information Quality Guidelines. EPA’s quality assurance (QA) and 

quality control (QC) activities for this rulemaking include the development, approval and 

implementation of Quality Assurance Project Plans for the use of environmental data generated 

or collected from sampling and analyses, existing databases and literature searches, and for the 

development of any models, which used environmental data. 

1.1 LEGAL AUTHORITY

EPA is proposing revisions of the ELGs for the Steam Electric Category (40 Code of 

Federal Regulations (CFR) 423) under the authority of Sections 301, 304, 306, 307, 308, 402, 

and 501 of the Clean Water Act, 33 U.S.C. 1311, 1314, 1316, 1317, 1318, 1342, and 1361. 

1.2 CLEAN WATER ACT

Congress passed the Federal Water Pollution Control Act Amendments of 1972, also 

known as the Clean Water Act (CWA), to “restore and maintain the chemical, physical, and 

biological integrity of the Nation’s waters.” 33 U.S.C. 1251(a). The CWA establishes a 
Section 1 - Background

1-2 

comprehensive program for protecting our nation’s waters. Among its core provisions, the CWA 

prohibits the discharge of pollutants from a point source to waters of the U.S. except as 

authorized under the CWA. Under section 402 of the CWA, discharges may be authorized 

through a National Pollutant Discharge Elimination System (NPDES) permit. The CWA also 

authorizes EPA to establish national technology-based effluent limitations guidelines and 

standards (ELGs) for discharges from categories of point sources. 

The CWA authorizes EPA to promulgate nationally applicable pretreatment standards 

that restrict pollutant discharges from facilities that discharge wastewater indirectly through 

sewers flowing to publicly owned treatment works (POTWs), as outlined in section 307(b) and 

(c), 33 U.S.C. 1317(b) and (c). EPA establishes national pretreatment standards for those 

pollutants in wastewater from indirect dischargers that may pass through, interfere with, or are 

otherwise incompatible with POTW operations. Generally, pretreatment standards are designed 

to ensure that wastewaters from direct and indirect industrial dischargers are subject to similar 

levels of treatment. See CWA section 301(b), 33 U.S.C. 1311(b). In addition, POTWs are 

required to implement local treatment limits applicable to their industrial indirect dischargers to 

satisfy any local requirements. See 40 CFR 403.5. 

Direct dischargers (i.e., those discharging directly to surface waters) must comply with 

effluent limitations in NPDES permits. Indirect dischargers, who discharge through POTWs, 

must comply with pretreatment standards. Technology-based effluent limitations in NPDES 

permits are derived from effluent limitations guidelines (CWA sections 301 and 304, 33 U.S.C. 

1311 and 1314) and new source performance standards (CWA section 306, 33 U.S.C. 1316) 

promulgated by EPA, or based on best professional judgment (BPJ) where EPA has not 

promulgated an applicable effluent guideline or new source performance standard (CWA section 

402(a)(1)(B), 33 U.S.C. 1342(a)(1)(B)). Additional limitations based on water quality standards 

are also required to be included in the permit in certain circumstances. CWA section 

301(b)(1)(C), 33 U.S.C. 1311(b)(1)(C). The ELGs are established by regulation for categories of 

industrial dischargers and are based on the degree of control that can be achieved using various 

levels of pollution control technology. 

EPA promulgates national ELGs for major industrial categories for three classes of 

pollutants: (1) conventional pollutants (i.e., total suspended solids (TSS), oil and grease (O&G), 

biochemical oxygen demand (BOD5), fecal coliform, and pH), as outlined in CWA section 

304(a)(4) and 40 CFR 401.16; (2) toxic pollutants (e.g., toxic metals such as arsenic, mercury, 

selenium, and chromium; toxic organic pollutants such as benzene, benzo-a-pyrene, phenol, and 

naphthalene), as outlined in section 307(a) of the Act, 40 CFR 401.15 and 40 CFR part 423 

appendix A; and (3) non-conventional pollutants, which are those pollutants that are not 

categorized as conventional or toxic (e.g., ammonia-N, phosphorus, and total dissolved solids).

EPA bases ELGs on the performance of control and treatment technologies. The 

legislative history of CWA section 304(b), which is the heart of the effluent guidelines program, 

describes the need to press toward higher levels of control through research and development of 

new processes, modifications, replacement of obsolete plans and processes, and other 

improvements in technology, taking into account the cost of controls. Congress has also stated 

that EPA need not consider water quality impacts on individual water bodies as the guidelines 

are developed; see Statement of Senator Muskie (October 4, 1972), reprinted in Legislative 
Section 1 - Background

1-3 

History of the Water Pollution Control Act Amendments of 1972, at 170. (U.S. Senate, 

Committee on Public Works, Serial No. 93–1, January 1973.) 

There are four types of standards applicable to direct dischargers (plants that discharge to 

surface waters), and two standards applicable to indirect dischargers (plants that discharge to 

POTWs). The following sections summarize these guidelines and standards. 

1.2.1 Best Practicable Control Technology Currently Available (BPT)

Traditionally, EPA defines BPT effluent limitations based on the average of the best 

performances of facilities within the industry, grouped to reflect various ages, sizes, processes, or 

other common characteristics. EPA may promulgate BPT effluent limits for conventional, toxic, 

and non-conventional pollutants. In specifying BPT, EPA looks at a number of factors. EPA first 

considers the cost of achieving effluent reductions in relation to the effluent reduction benefits. 

The Agency also considers the age of equipment and facilities, the processes employed, 

engineering aspects of the control technologies, any required process changes, non-water quality 

environmental impacts (including energy requirements), and such other factors as the 

Administrator deems appropriate. See CWA section 304(b)(1)(B). If, however, existing 

performance is uniformly inadequate, EPA may establish limitations based on higher levels of 

control than what is currently in place in an industrial category, when based on an Agency 

determination that the technology is available in another category or subcategory, and can be 

practically applied.

1.2.2 Best Conventional Pollutant Control Technology (BCT)

The 1977 amendments to the CWA required EPA to identify additional levels of effluent 

reduction for conventional pollutants associated with BCT technology for discharges from 

existing industrial point sources. In addition to other factors specified in section 304(b)(4)(B), 

the CWA requires that EPA establish BCT limitations after consideration of a two-part “cost 

reasonableness” test. EPA explained its methodology for the development of BCT limitations in 

July 9, 1986 (51 FR 24974). Section 304(a)(4) designates the following as conventional 

pollutants: BOD5, TSS, fecal coliform, pH, and any additional pollutants defined by the 

Administrator as conventional. The Administrator designated O&G as an additional conventional 

pollutant on July 30, 1979 (44 FR 44501; 40 CFR 401.16). 

1.2.3 Best Available Technology Economically Achievable (BAT)

BAT represents the second level of stringency for controlling direct discharge of toxic 

and nonconventional pollutants. In general, BAT ELGs represent the best available economically 

achievable performance of facilities in the industrial subcategory or category. As the statutory 

phrase intends, EPA considers the technological availability and the economic achievability in 

determining what level of control represents BAT. CWA section 301(b)(2)(A), 33 U.S.C. 

1311(b)(2)(A). Other statutory factors that EPA considers in assessing BAT are the cost of 

achieving BAT effluent reductions, the age of equipment and facilities involved, the process 

employed, potential process changes, and non-water quality environmental impacts, including 

energy requirements and such other factors as the Administrator deems appropriate. CWA 

section 304(b)(2)(B), 33 U.S.C. 1314(b)(2)(B). The Agency retains considerable discretion in 
Section 1 - Background

1-4 

assigning the weight to be accorded these factors. Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 

1045 (D.C. Cir. 1978). Generally, EPA determines economic achievability based on the effect of 

the cost of compliance with BAT limitations on overall industry and subcategory financial 

conditions. BAT may reflect the highest performance in the industry and may reflect a higher 

level of performance than is currently being achieved based on technology transferred from a 

different subcategory or category, bench scale or pilot plant studies, or foreign plants. American 

Paper Inst. v. Train, 543 F.2d 328, 353 (D.C. Cir. 1976); American Frozen Food Inst. v Train, 

539 F.2d 107, 132 (D.C. Cir. 1976). BAT may be based upon process changes or internal 

controls, even when these technologies are not common industry practice. See American Frozen 

Foods, 539 F.2d at 132, 140; Reynolds Metals Co. v. EPA, 760 F.2d 549, 562 (4th Cir. 1985); 

California & Hawaiian Sugar Co. v. EPA, 553 F.2d 280, 285-88 (2nd Cir. 1977). 

1.2.4 New Source Performance Standards (NSPS) 

NSPS reflect effluent reductions that are achievable based on the best available 

demonstrated control technology (BADCT). Owners of new facilities have the opportunity to 

install the best and most efficient production processes and wastewater treatment technologies. 

As a result, NSPS should represent the most stringent controls attainable through the application 

of the BADCT for all pollutants (that is, conventional, non-conventional, and toxic pollutants). 

In establishing NSPS, EPA is directed to take into consideration the cost of achieving the 

effluent reduction and any non-water quality environmental impacts and energy requirements. 

CWA section 306(b)(1)(B), 33 U.S.C. 1316(b)(1)(B). 

1.2.5 Pretreatment Standards for Existing Sources (PSES) 

Section 307(b), 33 U.S.C. 1317(b), of the Act calls for EPA to issue pretreatment 

standards for discharges of pollutants to POTWs. PSES are designed to prevent the discharge of 

pollutants that pass through, interfere with, or are otherwise incompatible with the operation of 

POTWs. Categorical pretreatment standards are technology-based and are analogous to BPT and 

BAT effluent limitations guidelines, and thus the Agency typically considers the same factors in 

promulgating PSES as it considers in promulgating BAT. The General Pretreatment Regulations, 

which set forth the framework for the implementation of categorical pretreatment standards, are 

found at 40 CFR part 403. These regulations establish pretreatment standards that apply to all 

non-domestic dischargers. See 52 FR 1586 (January 14, 1987). 

1.2.6 Pretreatment Standards for New Sources (PSNS) 

Section 307(c), 33 U.S.C. 1317(c) of the Act calls for EPA to promulgate PSNS. Such 

pretreatment standards must prevent the discharge of any pollutant into a POTW that may 

interfere with, pass through, or may otherwise be incompatible with the POTW. EPA 

promulgates PSNS based on best available demonstrated control technology (BADCT) for new 

sources. New indirect dischargers have the opportunity to incorporate into their facilities the best 

available demonstrated technologies. The Agency typically considers the same factors in 

promulgating PSNS as it considers in promulgating NSPS. 
Section 1 - Background

1-5 

1.3 REGULATORY HISTORY OF THE STEAM ELECTRIC POWER GENERATING POINT 

SOURCE CATEGORY

This section presents a brief history of Steam Electric Category rulemaking activities. 

Section 1.3.1 discusses the existing steam electric industry wastewater discharge regulations. 

Section 1.3.2 discusses the Detailed Study of the Steam Electric Category. Section 1.3.3

discusses other statutes and regulatory requirements affecting this industry.

1.3.1 Summary of Current ELGs Discharge Requirements and Applicability

The 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 ELGs for industrial 

dischargers. EPA first issued ELGs for the Steam Electric Category in 1974 with subsequent 

revisions in 1977 and 1982. The Steam Electric ELGs are codified at 40 CFR 423 and include 

limitations for the following wastestreams:

• Once-through cooling water;

• Cooling tower blowdown; 

• Fly ash transport water;

• Bottom ash transport water; 

• Metal cleaning wastes;

• Coal pile runoff; and 

• Low-volume waste sources, including but not limited to, wastewaters from wet 

scrubber air pollution control systems, ion exchange water treatment systems, water 

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

floor drains, cooling tower basin cleaning wastes, and recirculating house service 

water systems (sanitary and air conditioning wastes are not included) [40 CFR 

423.11(b)]. 

Table 1-1 summarizes the current ELGs, which are applicable to:

“...discharges resulting from the operation of a generating unit by an establishment 

primarily engaged in the generation of electricity for distribution and sale which 

results primarily from a process utilizing fossil-type fuel (coal, oil, or gas) or nuclear 

fuel in conjunction with a thermal cycle employing the steam water system as the 

thermodynamic medium.” [40 CFR 423.10] 

The ELGs do not apply to discharges from generating units that primarily use a nonfossil 

or nonnuclear fuel source (e.g., wood waste, municipal solid waste) to power the steam electric 

generators, nor do they apply to generating units operated by establishments that are not 

primarily engaged in generating electricity for distribution and sale.
1-6

Section 1 - Background

Table 1-1. Current Effluent Guidelines and Standards for the Steam Electric Power Generating Point Source Category

Wastestream BPTa BATa NSPSa PSES and PSNSa

All Wastestreams pH: 6-9 S.U. b

PCBs: Zero discharge

PCBs: Zero discharge pH: 6-9 S.U. b

PCBs: Zero discharge

PCBs: Zero discharge

Fly Ash

Transport

TSS: 100 mg/L; 30 mg/L 

Oil & Grease: 20 mg/L; 15 

mg/L 

Zero discharge Zero discharge

(PSNS only) 

No limitation for PSES

Bottom Ash 

Transport

TSS: 100 mg/L; 30 mg/L 

Oil & Grease: 20 mg/L; 15 

mg/L 

TSS: 100 mg/L; 30 mg/L

Oil & Grease: 20 mg/L; 15 

mg/L 

Low Volume 

Wastes

TSS: 100 mg/L; 30 mg/L 

Oil & Grease: 20 mg/L; 15 

mg/L

TSS: 100 mg/L; 30 mg/L 

Oil & Grease: 20 mg/L; 15 

mg/L 

Once-Through 

Cooling

Free Available Chlorine: 0.5 

mg/L; 0.2 mg/L 

Total Residual Chlorine:

For any plant with rated 

electric generating capacity > 

25 MW: 0.20 mg/L 

instantaneous maximum;

For any plant with rated 

electric generating capacity < 

25 MW, equal to BPT

Total Residual Chlorine:

For any plant with rated 

electric generating capacity > 

25 MW: 0.20 mg/L 

instantaneous maximum;

For any plant with rated 

electric generating capacity < 

25 MW, equal to BPT

Cooling Tower 

Blowdown

Free Available Chlorine: 0.5 

mg/L; 0.2 mg/L 

Free Available Chlorine: 0.5 

mg/L; 0.2 mg/L 

126 Priority Pollutants: No 

detectable amount, except:

Chromium, total: 0.2 mg/L; 0.2 

mg/L

Zinc, total: 1.0 mg/L; 1.0 mg/L 

Free Available Chlorine: 0.5 

mg/L; /0.2 mg/L

126 Priority Pollutants: No 

detectable amount, except:

Chromium, total: 0.2 mg/L; 0.2 

mg/L

Zinc, total: 1.0 mg/L; 1.0 mg/L

126 Priority Pollutants: Zero 

discharge, except:

Chromium: 0.2 mg/L; 0.2 mg/L

Zinc: 1.0 mg/L; 1.0 mg/L

Coal Pile Runoff TSS*: 50 mg/L instantaneous 

maximum

TSS*: 50 mg/L instantaneous 

maximum
1-7

Section 1 - Background

Table 1-1. Current Effluent Guidelines and Standards for the Steam Electric Power Generating Point Source Category

Wastestream BPTa BATa NSPSa PSES and PSNSa

Chemical Metal 

Cleaning Wastes

TSS: 100 mg/L; 30 mg/L

Oil & Grease: 20 mg/L; 15 

mg/L

Copper: 1.0 mg/L; 1.0 mg/L

Iron: 1.0 mg/L; 1.0 mg/L 

Copper: 1.0 mg/L; 1.0 mg/L

Iron: 1.0 mg/L; 1.0 mg/L

TSS: 100 mg/L; 30 mg/L

Oil & Grease: 20 mg/L; 15 

mg/L

Copper: 1.0 mg/L; 1.0 mg/L

Iron: 1.0 mg/L; 1.0 mg/L

Copper: 1.0 mg/L (daily 

maximum)

Non-chemical 

Metal Cleaning 

Wastes

Reserved Reserved Reserved

Source: [40 CFR Part 423].

a -The limitations for TSS, oil & grease, copper, iron, chromium, and zinc are presented in the table as daily maximum (mg/L); 30-day average (mg/L). For all 

effluent guidelines, where two or more wastestreams are combined, the total pollutant discharge quantity may not exceed the sum of allowable pollutant quantities for 

each individual wastestream. BPT, BAT, and NSPS allow either mass- or concentration-based limitations.

b -The pH limitation is not applicable to once-through cooling water.

Free Available Chlorine: 0.5 mg/L; 0.2 mg/L - 0.5 mg/L instantaneous maximum, 0.2 mg/L average during chlorine release period. Discharge is limited to 2 

hrs/day/unit. Simultaneous discharge of chlorine from multiple units is prohibited. Limitations are applicable at the discharge from an individual unit prior to 

combination with the discharge from another unit.

Total Residual Chlorine: 0.20 mg/L instantaneous maximum. Total residual chlorine (TRC) = free available chlorine (FAC) + combined residual chlorine (CRC). 

TRC discharge is limited to 2 hrs/day/unit. TRC is applicable to plants ≥25 MW, and FAC is applicable to plants <25 MW. The TRC limitation is applicable at the 

discharge point to surface waters of the United States and may be subsequent to combination with the discharge from another unit. 

126 Priority Pollutants: zero discharge - 126 priority pollutants from added maintenance chemicals (refer to App. A to 40 CFR 423). At the permitting authority's 

discretion, compliance with the zero-discharge limitations for the 126 priority pollutants may be determined by engineering calculations, which demonstrate that the 

regulated pollutants are not detectable in the final discharge by the analytical methods in 40 CFR part 136.

TSS*: 50 mg/L instantaneous maximum on coal pile runoff streams. No limitation on TSS for coal pile runoff flows ≥10-year, 24-hour rainfall event.
Section 1 – Background

1-8 

1.3.2 Detailed Study of the Steam Electric Power Generating Point Source Category

Section 304 of the CWA requires EPA to periodically review all effluent limitations 

guidelines and standards to determine whether revisions are warranted. In addition, Section 

304(m) of the CWA requires EPA to develop and publish, biennially, a plan that establishes a 

schedule for the review and revision of promulgated national effluent guidelines required by 

Section 304(b) of the CWA. During the 2005 annual review of the existing effluent guidelines

for all categories, EPA identified the regulations governing the steam electric power generating 

point source category for possible revision. At that time, publicly available data reported through 

the NPDES permit program and the Toxics Release Inventory (TRI) indicated that the industry 

ranked high in discharges of toxic and nonconventional pollutants. Because of these findings, 

EPA initiated a more detailed study of the category to determine if the effluent guidelines should 

be revised.

During the detailed study, EPA collected information on wastewater characteristics and 

treatment technologies through site visits, wastewater sampling, a data request that was sent to a 

limited number of companies, and various secondary data sources (Section 3 summarizes these 

data collection activities). EPA focused these data collection activities on certain discharges from 

coal-fired steam electric power plants (referred to in this report as “coal-fired power plants"). 

Based on the data collected, EPA determined that most of the toxic loadings for this category are 

associated with metals and certain other constituents, such as selenium, present in wastewater 

discharges, and that the wastestreams contributing the majority of these pollutants are associated 

with ash handling and wet flue gas desulfurization (FGD) systems. EPA also identified several 

wastestreams that are relatively new to the industry (e.g., carbon capture wastewater), and 

wastestreams for which there is little characterization data (e.g., gasification wastewater). See 

Section 4 and Section 7 for more information on these practices. 

During the study, EPA found that the use of wet FGD systems to control sulfur dioxide 

(SO2) emissions has increased significantly since the last revision of the effluent guidelines in 

1982 and it is projected to continue increasing in the next decade as power plants take steps to 

address federal and state air pollution control requirements. EPA also found that FGD 

wastewaters generally contain significant levels of metals and other pollutants and that advanced 

treatment technologies are available to treat the FGD wastewater; however, most plants were 

employing surface impoundments designed primarily to remove suspended solids from FGD 

wastewater. 

EPA also determined that technologies are available for handling the fly ash and bottom 

ash generated at a plant without using any water or at least eliminating the discharge of any 

transport water. EPA found that the fly ash and bottom ash transport waters generated from wet 

systems at coal-fired power plants are created in large quantities and contain significant 

concentrations of metals, including arsenic and mercury. Additionally, EPA determined that 

some of the metals are present primarily in the dissolved phase, and generally are not removed in 

the surface impoundments that are used to treat these wastestreams. Based on these findings, 

EPA determined that there are technologies readily available to reduce or eliminate the discharge 

of pollutants contained in fly ash and bottom ash transport water. 
Section 1 – Background

1-9 

Finally, EPA determined that FGD and ash transport wastewaters contain pollutants that 

can have detrimental impacts to the environment. EPA reviewed publicly available data and 

found documented environmental impacts that were attributable to discharges from surface 

impoundments or discharges from leachate generated from landfills containing coal combustion 

residues. EPA determined that there are a number of pollutants present in wastewaters generated 

at coal-fired power plants that can impact the environment, including metals (e.g., arsenic, 

selenium, mercury), total dissolved solids (TDS), and nutrients. EPA found the interaction of 

coal combustion wastewaters with the environment has caused a wide range of harm to aquatic 

life.

Overall from the detailed study, EPA found that the industry is generating new 

wastestreams that during the previous rulemakings either were not evaluated or were evaluated 

to only a limited extent due to insufficient characterization data. Such wastestreams include FGD 

wastewater, flue gas mercury control (FGMC) wastewater, carbon capture wastewater, and 

gasification wastewaters. EPA also found that these wastestreams, as well as other combustionrelated wastestreams at power plants (e.g., fly ash and bottom ash transport water, leachate) 

contain pollutants in concentrations and mass loadings that are causing documented 

environmental impacts and that treatment technologies are available to reduce or eliminate the 

pollutant discharges. 

Upon completing the detailed study in 2009, EPA determined that the current regulations 

have not kept pace with the significant changes that have occurred in this industry over the last 

three decades. EPA’s analysis of the wastewater discharges associated with steam electric power 

generation led the Agency to announce, in September 2009, plans to revise the effluent 

guidelines. 

1.3.3 Other Statutes and Regulatory Requirements Affecting Management of Steam 

Electric Power Generating Wastewaters

EPA is taking action to reduce emissions, discharges, and other environmental impacts 

associated with steam electric power plants. These actions, which are being implemented by 

several different EPA offices (i.e., Office of Air and Radiation (OAR), Office of Solid Waste and 

Emergency Response (OSWER), Office of Water (OW)), include establishing new regulatory 

requirements which may affect the generation and composition of wastewater discharged from 

steam electric power plants. This section provides a brief overview of these statutes and

regulatory requirements. 

1. Mercury and Air Toxics Standards (MATS) 

When the CAA was amended in 1990, EPA was directed to control mercury and 

other hazardous air pollutants from major sources of emissions to the air. For power 

plants using fossil fuels, the amendments required EPA to conduct a study of 

hazardous air pollutant emissions. CAA Section 112(n)(1)(A). The CAA amendments 

also required EPA to consider the study and other information and to make a finding 

as to whether regulation was appropriate and necessary. In 2000, the Administrator 

found that regulation of hazardous air pollutants, including mercury, from coal- and 

oil-fired power plants was appropriate and necessary. 65 FR 79825 (Dec. 20, 2000). 
Section 1 – Background

1-10 

EPA published the final MATS rule on February 16, 2012. 77 FR 9304. The rule 

established standards that will reduce emissions of hazardous air pollutants including 

metals (e.g., mercury, arsenic, chromium, nickel) and acid gases (e.g., hydrochloric 

acid, hydrofluoric acid). Steam electric power plants may use any number of 

practices, technologies, and strategies to meet the new emission limits, including 

using wet and dry scrubbers, dry sorbent injection systems, activated carbon injection 

systems, and fabric filters.

2. Cross-State Air Pollution Rule (CSAPR)

EPA promulgated the CSAPR in 2011 to require 28 states in the eastern half of the 

United States to significantly improve air quality by reducing power plant emissions 

of SO2, nitrogen oxides (NOx) and/or ozone-season NOx that cross state lines and 

significantly contribute to ground-level ozone and/or fine particle pollution problems 

in other states. The emissions of SO2, NOx and ozone-season NOx addressed by the 

CSAPR react in the atmosphere to form PM2.5 and ground-level ozone and are 

transported long distances, making it difficult for a number of states to meet the 

national clean air standards that Congress directed EPA to establish to protect public 

health. The U.S. Court of Appeals for the D.C. Circuit stayed the CSAPR on 

December 30, 2011, and on August 21, 2012, issued an opinion vacating the rule and 

ordering EPA to continue administering the Clean Air Interstate Rule. EME Homer 

City Generation, L.P. v. EPA, 696 F.3d 7 (D.C.Cir. 2012). On March 29, 2013, the 

United States filed a petition asking the Supreme Court to review the D.C. Circuit 

decision. 

3. Greenhouse Gas Emissions for New Electric Utility Generating Units

On April 13, 2012, the EPA proposed new source standards of performance under 

CAA section 111 for emissions of carbon dioxide (CO2) for fossil-fuel-fired 

electricity generating units. 77 FR 22392. The proposed requirements, which apply 

only to new sources, would require new plants greater than 25 megawatts (MW) to 

meet an output-based standard of 1,000 pounds of CO2 per MW-hour of electricity 

generated. EPA based this proposed standard on the performance of natural gas 

combined cycle technology because EPA and others project that even without this 

rule, for the foreseeable future, new fossil-fuel-fired power plants will be built with 

that technology. New coal- or petroleum coke-fired generating units could meet the 

standard by using carbon capture and storage of approximately 50 percent of the CO2

in the exhaust gas when the unit begins operating or by later installing more effective 

carbon capture and storage to meet the standard on average over a 30-year period. 

EPA is evaluating the public comments received on the proposal and has not 

determined a schedule at this time for taking final action on the proposed rule.

4. Cooling Water Intake Structures (CWA Section 316(b)) 

Section 316(b) of the CWA, 33 U.S.C. 1326(b), requires that standards applicable to 

point sources under section 301 and 306 of the Act require that the location, design, 

construction, and capacity of cooling water intake structures reflect the best 

technology available to minimize adverse environmental impacts. Each year, these 
Section 1 – Background

1-11 

facilities withdraw large volumes of water from lakes, rivers, estuaries or oceans for 

use in their facilities. In the process, these facilities remove billions of aquatic 

organisms from waters of the United States each year, including fish, fish larvae and 

eggs, crustaceans, shellfish, sea turtles, marine mammals, and other aquatic life. The 

most significant effects of these withdrawals are on early life stages of fish and 

shellfish through impingement (being pinned against intake screens or other parts at 

the facility) and entrainment (being drawn into cooling water systems).

In November 2001, EPA took final action on regulations for cooling water intake 

structures at new facilities that have a design intake flow greater than 2 million 

gallons per day (MGD) and that have at least one cooling water structure that uses at 

least 25 percent of the water it withdraws for cooling purposes. See 40 CFR 125.81. 

EPA’s requirements provide a two-track approach. Under Track 1, the intake flow at 

facilities that withdraw greater than 10 MGD is restricted to a level commensurate 

with the level that may be achieved by use of a closed-cycle recirculating cooling 

system. Facilities withdrawing greater than 10 MGD located in areas where fisheries 

need additional protection must also use technology or operational measures to 

further minimize impingement mortality and entrainment. For facilities with intakes 

of less than 10 MGD, the cooling water intake structures may not exceed a fixed 

intake screen velocity and the quantity of intake is restricted. Under Track 2, a facility 

may choose to demonstrate to the permitting authority that other technologies will 

reduce the level of adverse environmental impacts to a level that would be achieved 

under Track 1. 

In March 2011, EPA proposed standards to reduce injury and death of fish and other 

aquatic life caused by cooling water intake structures at existing power plants and 

manufacturing facilities. The proposed rule would subject existing power plants and 

manufacturing facilities withdrawing in excess of 2 MGD of cooling water to an 

upper limit on the number of fish destroyed through impingement, as well as sitespecific entrainment mortality standards. Certain plants that withdraw very large 

volumes of water would also be required to conduct studies for use by the permit 

writer in determining site-specific entrainment controls for such facilities. Finally, 

under the proposed rule, new generating units at existing power plants would be 

required to reduce the intake of cooling water associated with the new unit, to a level 

which could be attained by using a closed-cycle cooling system. EPA is continuing 

analysis and is in the process of addressing comments and finalizing the rule. 

5. Coal Combustion Residuals (CCR) Proposed Rule 

CCRs are residues from the combustion of coal in steam electric power plants and 

include materials such as coal ash (fly ash and bottom ash) and FGD wastes. CCRs 

are currently exempt from the requirements of subtitle C of the Resource 

Conservation and Recovery Act (RCRA), which governs the disposition and 

management of hazardous wastes. Potential environmental concerns regarding the 

management and disposal of CCR include pollution leaching from surface 

impoundments and landfills contaminating ground water and natural resource 

damages and risks to human health caused by structural failures of surface 
Section 1 – Background

1-12 

impoundments, like that which occurred at the Tennessee Valley Authority’s plant in 

Kingston, Tennessee, in December 2008. The spill, which flooded more than 300 

acres of land with CCR and contaminated the Emory and Clinch rivers, emphasized 

the need for national standards to address risks associated with the disposal of CCR. 

On June 21, 2010, EPA co-proposed regulations that included two approaches to 

regulating the disposal of CCRs generated by electric utilities and independent power 

producers. Under one proposed approach, EPA would list these residuals as “special 

wastes,” when destined for disposal in landfills or surface impoundments, and would 

apply the existing regulatory requirements established under subtitle C of RCRA to 

such wastes. Under the second proposed approach, EPA would establish new 

regulations applicable specifically to CCRs under subtitle D of RCRA, the section of 

the statute applicable to solid (i.e., non-hazardous) wastes. Under both approaches, 

CCR that are beneficially used would remain exempt under the Bevill exclusion. EPA 

has not yet taken final action on the proposed CCR regulations. 
Section 2– Summary of Proposed Regulation

2-1 

SECTION 2

SUMMARY OF PROPOSED REGULATION

This section presents a brief summary of the proposed revisions to the ELGs. Section 2.1

summarizes the proposed revisions to discharge requirements and Section 2.2 describes the 

proposed revisions to the applicability provision and specialized definitions. 

2.1 SUMMARY OF PROPOSED REVISIONS TO DISCHARGE REQUIREMENTS

The proposed Steam Electric rule would revise the technology-based ELGs at 40 CFR 

423 for certain wastewater discharges associated with the operation of new and existing 

generating units within the Steam Electric Category. The current regulations, which were last 

updated in 1982, do not adequately address the toxic pollutants being discharged and have not 

kept pace with changes that have occurred in the electric power industry over the last three

decades. The development of new technologies for generating electric power (e.g., coal 

gasification) and the widespread implementation of air pollution controls (e.g., flue gas 

desulfurization (FGD), selective catalytic reduction (SCR)) have altered existing or created new 

wastewater streams at many power plants. Therefore, EPA is proposing to establish new or 

additional requirements for wastewaters associated with these new or altered wastestreams.

EPA is proposing to establish new requirements for BAT, NSPS, PSES, and PSNS for 

certain wastestreams, described below, for the Steam Electric ELGs. EPA is not proposing new 

BCT nor new BPT requirements as part of this proposed rulemaking. Section 8 describes the 

technology options considered for each wastestream as the basis for the regulations, as well as 

the combination of technology options/wastestreams that comprise the regulatory options 

considered for the rulemaking. As described in Section 8, EPA is considering several options in 

this rulemaking and has identified four preferred alternatives (i.e., Regulatory Options 3a, 3b, 3, 

and 4a) for regulation of existing discharges (i.e., BAT and PSES requirements) for the proposed 

revisions to the ELGs. EPA is also proposing Regulatory Option 4 for the new NSPS and PSNS 

requirements. The preferred alternatives for the proposed ELGs are summarized below. 

Discharges Directly to Surface Water from Existing Facilities

For existing sources that discharge directly to surface water, with the exception of oilfired generating units and small generating units (i.e., 50 MW or smaller), under one preferred 

alternative for BAT (referred to as Option 3a) the proposed rule would establish BAT for 

wastestreams from these sources that include: 

• “Zero discharge” effluent limit for all pollutants in fly ash transport water and 

wastewater from flue gas mercury control systems; 

• Numeric effluent limits for mercury, arsenic, selenium and TDS in discharges of 

wastewater from gasification processes; 
Section 2– Summary of Proposed Regulation

2-2 

• Numeric effluent limits for copper and iron in discharges of nonchemical metal 

cleaning wastes;1 and

• Effluent limits for bottom ash transport water and combustion residual leachate from 

landfills and surface impoundments that are equal to the current Best Practicable 

Control Technology Currently Available (BPT) effluent limits for these discharges 

(i.e., numeric effluent limits for TSS and oil and grease. 

Under a second preferred alternative for BAT (referred to as Option 3b), the proposed 

rule would establish numeric effluent limits for mercury, arsenic, selenium, and nitrate-nitrite in 

discharges of FGD wastewater from certain steam electric facilities (those with a total plant-level 

wet scrubbed capacity of 2,000 MW or greater).2 All other proposed Option 3b requirements are 

identical to the proposed Option 3a requirements described above. 

Under a third preferred alternative for BAT (referred to as Option 3), the proposed rule 

would establish numeric effluent limits for mercury, arsenic, selenium, and nitrate-nitrite in 

discharges of FGD wastewater, with the exception of small generating units (i.e., 50 MW or 

smaller). All other proposed Option 3 requirements are identical to the proposed Option 3a 

requirements described above. 

Under a fourth preferred alternative for BAT (referred to as Option 4a), the proposed rule 

would establish “zero discharge” effluent limits for all pollutants in bottom ash transport water, 

with the exception of all generating units with a nameplate capacity of 400 MW or less (for those 

generating units that are less than or equal to 400 MW, the proposed rule would set BAT equal to 

BPT for discharges of pollutants found in the bottom ash transport water). All other proposed 

Option 4a requirements are identical to the proposed Option 3 requirements described above. 

In addition, for oil-fired generating units and small generating units (i.e., 50 MW or 

smaller) that are existing sources and discharge directly to surface waters, under the four 

preferred alternatives for regulation of existing sources, the proposed rule would establish 

effluent limits (BAT) equal to the current BPT effluent limits for the wastestreams listed above. 3

Discharges to POTWs from Existing Facilities

For discharges from existing sources to POTWs, EPA is proposing to establish PSES that 

are equal to the proposed BAT, with the following exceptions: 

 

1 As described in Section VIII, EPA is proposing to exempt from new copper and iron BAT limitations any existing 

discharges of nonchemical metal cleaning wastes that are currently authorized without iron and copper limits. For 

these discharges, BAT limits would be set equal to BPT limits applicable to low volume wastes. 

2 Total plant-level wet scrubbed capacity is calculated by summing the nameplate capacity for all of the units that 

are serviced by wet FGD systems.

3 As described in Section VIII, one of the preferred options would increase this threshold for purposes of discharges 

of pollutants in bottom ash transport water only, to 400 MW or less.
Section 2– Summary of Proposed Regulation

2-3 

• Numeric standards for discharges of nonchemical metal cleaning wastes would be 

established only for copper;4

• Under Options 3a, 3b, and 3 for PSES, EPA is not proposing to establish pretreatment 

standards for discharges of bottom ash transport water. Under Option 4a, EPA is not 

proposing to establish pretreatment standards for discharges of bottom ash transport 

water for generating units with a nameplate capacity of 400 MW or less;5 and

• Other than the pretreatment standards for nonchemical metal cleaning wastes, EPA is 

not proposing to establish pretreatment standards for existing sources for discharges 

from existing oil-fired units and small generating units (i.e., 50 MW or smaller). 

Discharges Directly to Surface Water from New Sources

For all generating units that are new sources and discharge directly to surface waters, 

including oil-fired generating and small generating units, the proposed rule would establish 

NSPS that include: 

• Numeric standards for mercury, arsenic, selenium, and nitrate-nitrite in discharges of 

FGD wastewater; 

• Maintaining the current “zero discharge” standard for all pollutants in fly ash 

transport water for direct dischargers;

• Establishing “zero discharge” standards for all pollutants in bottom ash transport 

water and wastewater from flue gas mercury control systems;

• Numeric standards for mercury, arsenic, selenium, and TDS in discharges of 

wastewater from gasification processes;

• Numeric standards for mercury and arsenic in discharges of combustion residual 

leachate; and

• Numeric standards for TSS, oil and grease, copper, and iron in discharges of 

nonchemical metal cleaning wastes.

Discharges to POTWs from New Sources 

For generating units that are new sources and discharge to POTWs, including oil-fired 

generating units and small generating units, EPA is proposing to establish PSNS that are equal to 

the proposed NSPS, except that the PSNS would also establish a “zero discharge” standard for 

all pollutants in fly ash transport water (the current NSPS already includes a zero discharge 

standard for pollutants in fly ash transport water), and the PSNS would not include numeric 

standards for TSS, oil and grease, or iron in discharges of nonchemical metal cleaning wastes.

 

4 As described in Section VIII, EPA is proposing to exempt from new copper PSES standards any existing 

discharges of nonchemical metal cleaning wastes that are currently authorized without copper limits. For these 

discharges, the regulations would not specify PSES. 

5

This is because, as explained in Section VII, EPA generally does not establish pretreatment standards for 

conventional pollutants (e.g., TSS and oil and grease) because POTWs are designed to treat these conventional 

pollutants.
Section 2– Summary of Proposed Regulation

2-4 

EPA is also proposing to add provisions to the ELGs that would prevent facilities from 

circumventing the new effluent limitations guidelines and standards. The proposed provision 

would do the following: 

• Generally require that compliance with the effluent limits applicable to a particular 

wastestream be demonstrated prior to mixing the treated wastestream with other 

wastestreams; and

• Establish requirements that prevent moving effluent produced by a process operation 

for which there is a zero discharge effluent limit/standard, to another process 

operation for discharge under less stringent requirements. 

In addition to the proposed requirements, EPA is also considering establishing the 

following provisions to the ELGs: 

• Establish best management practices (BMP) requirements that would apply to surface 

impoundments containing coal combustion residuals (e.g., ash ponds, FGD ponds); 

and

• Establish a voluntary program that would provide incentives for existing power plants 

that dewater and close their surface impoundments containing combustion residuals 

and for power plants that eliminate the discharge of all process wastewater (excluding 

cooling water discharges).

2.2 REVISIONS TO APPLICABILITY PROVISION AND SPECIALIZED DEFINITIONS

In addition to the proposed revisions to the discharge requirements, EPA is proposing 

certain modifications to the applicability provision for the ELGs. These are not substantive 

modifications that would alter which generating units are regulated by the ELGs. These units 

have been traditionally regulated by the exiting ELGs. Instead, the proposed modifications would 

remove potential ambiguity present in the current regulatory text. The changes include:

• Clarification that certain facilities, such as certain municipal-owned facilities, which

generate and distribute electricity within a service area (such as distributing electric 

power to municipal-owned buildings), but which use accounting practices which are 

not commonly thought of as a “sale” are nevertheless subject to the ELGs; 

• Clarification that “primarily,” as used in 423.10, refers to those operations where the 

generation of electricity is the predominant source of revenue and/or principal reason 

for operation; 

• Clarification that fuels derived from fossil fuel are within the scope of the current 

ELGs; and

• Clarification that combined cycle systems, which are generating units composed of 

one or more combustion turbines operating in conjunction with one or more steam 

turbines, are subject to the ELGs. 

In addition to the proposed revisions discussed above, EPA is proposing revisions to 

certain existing specialized definitions, as well as inclusion of new specialized definitions. The 

proposed revisions to existing specialized definitions (with revisions underlined) are: 
Section 2– Summary of Proposed Regulation

2-5 

(b) The term low volume waste sources means, taken collectively as if from one 

source, wastewater from all sources except those for which specific limitations are 

otherwise established in this part. Low volume waste sources include, but are not 

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

water treatment evaporator blowdown, laboratory and sampling streams, boiler 

blowdown, floor drains, cooling tower basin cleaning wastes, recirculating house 

service water systems, and scrubber air pollution control systems whose primary 

purpose is particulate removal. Sanitary wastes, air conditioning wastes, and 

wastewater from carbon capture or sequestration systems are not included in this 

definition. 

(e) The term fly ash means the ash that is carried out of the furnace by the gas stream 

and collected by a capture device such as a mechanical precipitator, electrostatic 

precipitator, and/or fabric filter. Economizer ash is included in this definition when it 

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

wet scrubber air pollution control systems whose primary purpose is particulate 

removal. 

The proposed new specialized definitions are: 

(n) The term flue gas desulfurization (FGD) wastewater means any process 

wastewater generated specifically from the wet FGD scrubber system, including any 

solids separation or solids dewatering processes.

(o) The term flue gas mercury control (FGMC) wastewater means any process 

wastewater generated from an air pollution control system installed or operated for 

the purpose of removing mercury from flue gas. This includes fly ash collection 

systems when the particulate control system follows the injection of sorbents or 

implementation of other controls to remove mercury from flue gas. Flue gas 

desulfurization systems are not included in this definition. 

(p) The term transport water means any process wastewater that is used to convey fly 

ash, bottom ash, or economizer ash from the ash collection equipment, or boiler, and 

has direct contact with the ash.

(q) The term gasification wastewater means, taken collectively as if from one source, 

wastewater from all sources associated with the gasification process or related 

chemical recovery processes at an integrated gasification combined cycle operation. 

Gasification wastewater includes, but is not limited to, slag handling wastewater, fly 

ash stream, sour/grey water (which consists of condensate from gas cooling, as well 

as other wastestreams), CO2/steam stripper wastewater, air separation unit blowdown, 

and sulfur recovery unit blowdown. 

(r) The term combustion residual leachate means leachate from onsite landfills or 

surface impoundments (e.g., ponds) containing combustion residuals. Leachate 

includes liquid, including any suspended or dissolved constituents in the liquid that 

has percolated through or drained from waste or other materials emplaced in a 
Section 2– Summary of Proposed Regulation

2-6 

landfill, or that pass through the containment structure (e.g., bottom, dikes, berms) of 

a surface impoundment. Leachate also includes the terms seepage, drains, leak, and 

leakage, which are generally used in reference to leachate from an impoundment. 

(s) The term oil-fired unit means a generating unit that uses oil as the primary or 

secondary fuel source and does not use a gasification process or any coal or 

petroleum coke as a fuel source. This definition does not include units that use oil 

only for start up or flame-stabilization purposes. 

(t) The term sufficiently sensitive analytical method means a method that ensures the 

sample-specific quantitation level for the wastewater being analyzed is at or below 

the level of the effluent limitation.

(u) The term nonchemical metal cleaning waste means any wastewater resulting from 

the cleaning of any metal process equipment without chemical cleaning compounds, 

including, but not limited to, boiler tube cleaning, boiler fireside cleaning, and air 

preheater cleaning. 
Section 3– Data Collection Activities

3-1 

SECTION 3

DATA COLLECTION ACTIVITIES

EPA collected and evaluated information and data from various sources in the course of 

developing the proposed effluent limitations guidelines and standards (ELGs) for the Steam 

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

data to develop the industry profile, determine the applicability of the rule, evaluate industry 

subcategorization, and determine wastewater characteristics, technology options, compliance 

costs, pollutant loading reductions, and non-water quality environmental impacts. This section 

discusses the following data collection activities as they relate to technical aspects of this 

proposed rulemaking: 

• Steam Electric Power Generating Detailed Study (Section 3.1);

• Engineering site visits (Section 3.2);

• Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Section 

3.3);

• Field sampling program (Section 3.4);

• EPA and state sources (Section 3.5);

• Industry-submitted data (Section 3.6);

• Technology vendor data (Section 3.7);

• Other data sources (Section 3.8); and

• Protection of confidential business information (Section 3.9).

3.1 STEAM ELECTRIC POWER GENERATING DETAILED STUDY

EPA conducted a detailed study of the steam electric power generating industry between 

2005 and 2009. During the study, EPA collected data about the industry by performing the 

following activities:

• Conducted 34 site visits and six wastewater sampling episodes at steam electric 

power plants; 

• Distributed a questionnaire to collect data from nine companies (operating 30 coalfired power plants); 

• Reviewed publicly available sources of data; and

• Coordinated with EPA program offices, other government organizations (e.g., state 

groups and permitting authorities), and industry and other stakeholders.

EPA’s Steam Electric Power Generating Point Source Category: Detailed Study Report

provides an overview of the steam electric power generating industry and its wastewater 

discharges, and the data collection activities and analyses conducted during EPA’s detailed study

[U.S. EPA, 2009b]. The study focused largely on discharges associated with coal ash handling 

operations and wastewater from flue gas desulfurization (FGD) air pollution control systems 
Section 3– Data Collection Activities

3-2 

because these sources are responsible for the majority of the toxic pollutants currently discharged 

by steam electric power plants.

EPA also evaluated wastewater from coal pile runoff, condenser cooling, equipment 

cleaning, and leachate from landfills and surface impoundments. Additionally, EPA reviewed 

information on integrated gasification combined cycle (IGCC) operations and carbon capture 

technologies. EPA also identified wastewaters from flue gas mercury control systems and 

regeneration of the catalysts used for Selective Catalytic Reduction (SCR) NOx controls as 

potential new wastestreams that warrant attention.

EPA used the information collected during the detailed study to select plants with 

different technology bases for site visits, support the development of the Questionnaire for the 

Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey), select plants to 

receive the questionnaire, and select plants for EPA’s sampling program during the rulemaking. 

Additionally, EPA used the data collected during the detailed study to develop an industry 

profile and supplement the findings from the survey and sampling program (i.e., Form 2C data 

provided by the industry trade association). The remainder of Section 3 provides additional 

details regarding the data used from the study.

3.2 ENGINEERING SITE VISITS

EPA conducted a site visit program to gather information on the types of wastewaters 

generated by steam electric power plants, and the methods of managing these wastewaters to 

allow for recycle, reuse, or discharge. EPA focused data gathering activities primarily on FGD 

wastewater treatment and management of ash transport water at coal- and petroleum coke-fired 

power plants because the FGD and ash transport water streams are the primary sources of 

pollutant discharges from the industry. EPA also conducted site visits at oil-, gas-, and nuclearfueled power plants to better understand the plant operations, the wastewaters generated, and the 

types of treatment systems used. EPA conducted 65 site visits at steam electric power plants in 

22 states between December 2006 and February 2013. The Agency conducted three additional 

site visits in Italy in April 2011 to obtain information on their FGD wastewater treatment 

systems. Table 3-1 summarizes the site visits conducted. The list of site visits excludes EPA 

sampling episodes and EPA audits of CWA 308 sampling described in Section 3.4. 

The purpose of the site visits was to collect information about each site’s electric 

generating processes, wastewater management practices, and treatment technologies, and to 

evaluate each plant for potential inclusion in EPA’s sampling program. To identify potential 

candidate plants for site visits, EPA used information from EPA’s Office of Air and Radiation 

(OAR) and data provided by the Utility Water Act Group (UWAG), and other sources to 

determine the types of operations at power plants. During the detailed study, EPA used the 

UWAG data in conjunction with information from other sources, including publicly available 

plant-specific information, state and regional permitting authorities, and the Study data request, 

to identify plants to contact and obtain additional details regarding the plants’ operations. During 

the rulemaking effort, EPA identified potential site visit candidates based on information 

provided in the survey (i.e., plant operating characteristics). From the information obtained 

during these contacts, EPA selected plants for site visits.
Section 3– Data Collection Activities

3-3 

The specific objectives of these site visits were to:

• Gather general information about each plant’s operations; 

• Gather information on pollution prevention and wastewater treatment/operations; 

• Evaluate whether the plant was appropriate to include in the sampling program; 

• Gather plant-specific information to develop sampling plans; and 

• Select and evaluate potential sampling points.

Table 3-1. List of Site Visits Conducted During the Detailed Study and Rulemaking

Plant Name, Location Month/Year of Site Visit

Yates, Georgia Dec 2006

Wansley, Georgia Dec 2006

Widows Creek, Alabama Dec 2006; Sept 2007

Conemaugh, Pennsylvania Feb 2007; Aug 2012

Homer City, Pennsylvania Feb 2007; Aug 2007; Aug 2012

Pleasant Prairie, Wisconsin Apr 2007; Mar 2010

Bailly, Indiana Apr 2007

Seminole, Florida Apr 2007; Jan 2013

Big Bend, Florida Apr 2007; Jul 2007

Cayuga, New York May 2007

Mitchell, West Virginia May 2007; Oct 2007

Cardinal, Ohio May 2007; Oct 2007; Feb 2010

Bruce Mansfield, Pennsylvania Oct 2007

Roxboro, North Carolina Mar 2008

Belews Creek, North Carolina Mar 2008; Oct 2008

Marshall, North Carolina Mar 2008

Mount Storm, West Virginia Sept 2008

Harrison, West Virginia Sept 2008

Mountaineer, West Virginia Sept 2008; Jan 2009

Gavin, Ohio Sept 2008

Deely, Texas Oct 2008

Clover, Virginia Oct 2008

JK Spruce, Texas Oct 2008

Fayette Power Project/Sam Seymour, Texas Oct 2008

Ghent, Kentucky Dec 2008

Trimble County, Kentucky Dec 2008

Cane Run, Kentucky Dec 2008

Mill Creek, Kentucky Dec 2008

Brandon Shores, Maryland Jan 2009; Mar 2010

Kenneth C Coleman, Kentucky Feb 2009

Gibson, Indiana Feb 2009
Section 3– Data Collection Activities

3-4 

Table 3-1. List of Site Visits Conducted During the Detailed Study and Rulemaking

Plant Name, Location Month/Year of Site Visit

Paradise, Kentucky Feb 2009

Wabash River, Indiana Feb 2009; Aug 2010

Miami Fort, Ohio Apr 2009; Mar 2010

Covanta, Virginia Jul 2009

Chesterfield, Virginia Sept 2009

Karn-Weadock, Michigan Sept 2009

Kinder Morgan Power, Michigan Sept 2009

Monroe, Michigan Sept 2009

Allen, North Carolina Oct 2009

Cape Fear, North Carolina Oct 2009

Catawba, South Carolina Oct 2009

HB Robinson, South Carolina Oct 2009

FP&L Sanford, Florida Oct 2009

Polk, Florida Oct 2009

Fort Martin, West Virginia Feb 2010

Hatfield's Ferry, Pennsylvania Feb 2010

Keystone, Pennsylvania Feb 2010

Dickerson, Maryland Mar 2010

Dallman, Illinois Apr 2010

Duck Creek, Illinois Apr 2010

Iatan, Missouri Apr 2010

Edwardsport, Indiana Mar 2011

Torrevaldaliga Nord, Italy Apr 2011

Monfalcone, Italy Apr 2011

Frederico II (Brindisi), Italy Apr 2011

FP&L Manatee, Florida Nov 2011

Wateree, South Carolina Jan 2013

McMeekin, South Carolina Jan 2013

3.3 QUESTIONNAIRE FOR THE STEAM ELECTRIC POWER GENERATING EFFLUENT 

GUIDELINES

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), 33 U.S.C. 1318. EPA designed the industry survey to obtain technical information 

related to wastewater generation and treatment, and economic information such as costs of 

wastewater treatment technologies and financial characteristics of potentially affected 

companies. The responses were used to evaluate pollution control options for establishing 

revisions to the ELGs for the Steam Electric Category. 
Section 3– Data Collection Activities

3-5 

EPA developed an Information Collection Request (ICR) entitled Questionnaire for the 

Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey). The survey was 

approved by the Office of Management and Budget (OMB) in May 2010 (OMB Control No. 

2040-0281). 

The survey comprised the following nine parts: 

• Part A: Steam Electric Power Plant Operations

• Part B: FGD Systems

• Part C: Ash Handling 

• Part D: Pond/Impoundment Systems and Other Wastewater Treatment Operations 

• Part E: Wastes from Cleaning Metal Process Equipment 

• Part F: Management Practices for Ponds/Impoundments and Landfills

• Part G: Leachate Sampling Data for Ponds/Impoundments and Landfills

• Part H: Nuclear Power Generation

• Part I: Economic and Financial Data

Part A gathered information on all steam electric generating units at the surveyed plant, 

the fuels used to generate electricity, air pollution controls, cooling water, ponds/impoundments 

and landfills used for coal combustion residues (CCR), coal storage and processing, and outfalls. 

Parts B through I collected economic data and detailed technical information on certain aspects 

of power plant operations, including requiring some plants to collect and analyze wastewater 

samples.

In order to identify the population of plants that would be candidates to receive the 

survey, EPA first created a sample frame consisting of all fossil- and nuclear-fueled steam 

electric power plants in the United States that reported operating under NAICS code 22, and their 

corresponding generating units. NAICS code 22 (Utilities) comprises establishments engaged in 

providing the following utility services: electric power, natural gas, steam supply, water supply, 

and sewage removal. Because power generation was not the primary purpose of some of the 

plants in this NAICS code (i.e., sewage removal plants), EPA removed them from the sample 

frame.

The resulting sample frame consisted of information obtained from databases that are 

maintained by the Energy Information Administration (EIA), a statistical agency of the U.S. 

Department of Energy (DOE) that collects information on existing electric generating plants and 

associated equipment to evaluate the current status and potential trends in the industry. The 

source of the information came primarily from the 2007 Electric Generator Report (Form EIA860) and was supplemented by information collected by Form EIA-923 and a survey conducted 

by EPA’s Office of Solid Waste and Emergency Response (OSWER) [U.S. EPA, 2009a]. In

addition, EPA identified two plants that started operations after 2007 and obtained information 

about them from Internet searches.
Section 3– Data Collection Activities

3-6 

Collectively, the data sources provided key frame information for each steam electric 

power plant with a NAICS code of 22, such as county, state, North American Electric Reliability 

Council (NERC) region, business size (small or non-small), and regulatory status (e.g., regulated 

by public service commission). Also included in the data sources were the number of each type 

of generating unit operated at the plant, an identifier that specified the fuel classification of each 

generating unit for the plant, and an identifier based on the fuel classifications of the generating 

units (e.g., coal, gas-combined cycle, nuclear). In addition, the OSWER survey results and the 

EIA-923 data set provided information on the presence of surface impoundments and landfills at 

the plant along with the materials that were stored or disposed of in the impoundment/landfill. 

EPA also used data for each generating unit reported in the EIA-860 data set classified as a 

steam electric generating unit, such as prime mover and fuel (fossil or nuclear), nameplate 

capacity (in megawatts (MW)), unit fuel classification, and the plant where the generating unit is 

housed. The sample frame contained information on 1,197 plants containing 2,571 generating 

units that were potentially within the scope of the Steam Electric ELGs.

To minimize the burden on the respondents, EPA grouped plants into strata based on fuel 

classification so that an efficient stratified sampling scheme could be used.6 This sampling 

strategy allowed for different sampling rates across the strata. Depending on the amount or type 

of information it required for the rulemaking, EPA solicited information either from all plants 

within a stratum (i.e., a census or “certainty” stratum) or from a random sample of plants within 

a stratum (i.e., probability sampled stratum). As a result, the survey was distributed to all coaland petroleum coke-fired power plants and a sample of the rest of the steam electric industry, 

including oil-fired, gas-fired, gas-combined cycle, and nuclear power plants. Table 3-2 presents 

the number of plants in each fuel classification (i.e. strata) included in the sample frame used to 

identify survey recipients. 

Table 3-2. Number of Plants in Each Fuel Classification in the Survey Sample Frame Used 

to Identify Survey Recipients

Fuel Classification Number of Facilities

Coal 495

Petroleum coke 9

Oil 43

Gas 555

Nuclear 63

Combinationa 32

a - EPA used the “combination” designation for plants that have at least two generating units that have different 

unit-level designations (e.g., oil, gas, nuclear), but do not have any coal or petroleum coke units. 

The survey comprised several sections that were tailored to address specific processes, 

data needs, or types of power plants. Parts A and I of the survey were sent to all sampled plants; 

 

6 EPA classified plants into the fuel categories to develop the sample frame of all fossil- and nuclear-fueled steam 

electric power plants in the United States. EPA further developed plant-level fuel classifications based on a 

hierarchy of the type of units operating at the plant; therefore, some plants may operate units that burn other types of 

fuel in addition to the fuel under which they are classified. Plants that operated coal- or petroleum coke-fired units 

were classified as coal or petroleum coke regardless of other fuels at the plant. For example, a plant classified as 

coal will have coal-fired unit(s) at the plant, but may also have oil- fired, gas-fired, or nuclear unit(s).
Section 3– Data Collection Activities

3-7 

the remaining sections were sent to sampled plants according to their fuel classification. 

Specifically, in addition to Parts A and I, all coal- and petroleum coke-fired power plants 

received Parts B, C, D, and H. A subsample of coal- and petroleum coke-fired power plants also 

received Parts E, F, and G. The sampled plants in the oil-fired and combination strata received 

Parts A, B, C, D, E, H, and I.7 The sampled plants in the gas-fired, gas-combined cycle, and 

nuclear power strata received Parts A, E, H, and I. 

Most parts of the survey focused on gathering information from all coal- and petroleum 

coke-fired power plants. Therefore, all plants with a fuel classification of coal or petroleum coke 

were selected with certainty (i.e., probability of selection equal to one), except for Parts E, F, and 

G. In addition, for strata with 10 or fewer plants, EPA included all plants in the sample, and at 

least 10 plants were sampled within strata containing more than 10 plants. As such, all regulated 

and nonregulated combination plants (except gas-fired and gas-combined cycle) were selected 

with certainty. For the remaining no regulated and regulated plants with plant fuel classifications 

of gas, gas-combined cycle, oil, nuclear, and combination (gas and gas-combined cycle), EPA 

randomly selected 30 percent of the plants to receive the survey while adhering to the 10 plant 

minimum per stratum. Based on this sampling design, 733 plants were selected to receive the 

survey. This total includes 495 coal-fired, 9 petroleum coke-fired, 20 oil-fired, 167 gas-fired, 20 

nuclear power plants, and 22 combination power plants. 

EPA received 733 completed surveys, including those from 53 plants that certified that 

they were not and did not have the capability to be engaged in steam electric power production, 

would be retired by December 31, 2011, or did not generate electricity in 2009 by burning any 

fossil or nuclear fuels.8

 Because responses were received for all 733 sampled plants (including 

those 53 plants that were not required to complete the remainder of the survey), there were no 

plants that were considered non-respondents, thus the response rate is 100 percent. 

EPA then developed weighting factors to represent the entire industry on a national level 

from the data provided by the 733 plants that received the survey. Because coal- and petroleum 

coke-fired plants were selected with certainty, EPA did not weight the responses for the majority 

of data because all plants were represented. However, because EPA sent only Parts E, F, and G 

of the survey to a probability sample of coal- and petroleum coke-fired plants, the Parts E, F, and 

G data were weighted to represent the entire industry. In addition, data collected from the 

probability-sampled strata for other fuel types were weighted to represent the entire industry. All 

survey data presented in this document have been weighted to represent the entire industry, 

unless otherwise noted.

3.4 FIELD SAMPLING PROGRAM

Between July 2007 and April 2011, EPA conducted a sampling program at 17 different 

steam electric power plants in the United States and Italy to collect wastewater characterization 

 

7 For the purpose of the survey, combination power plants mean plants that do not operate generating units fueled by 

coal or petroleum coke and have at least two generating units that have different unit-level fuel classifications (e.g., 

gas and oil, gas and gas-combined cycle).

8 At the time EPA developed the survey, EPA used 2011 as the cutoff year for retirements because the plants would 

be retired before the proposed rule was published.
Section 3– Data Collection Activities

3-8 

data and/or treatment performance data associated with FGD wastewater, fly ash and bottom ash 

wastewater, and wastewater from gasification and carbon capture processes. EPA also obtained 

sampling data for surface impoundment and landfill leachate collection and treatment systems at 

39 plants, as required by Part G of the Steam Electric Survey (described in Section 3.3). This 

leachate sampling is not included in the following description of the field sampling program. 

EPA’s field sampling program began during its detailed study and continued throughout 

this rulemaking effort. During the study, EPA conducted one- or two-day sampling episodes at 

six plants to characterize untreated wastewaters generated by coal-fired power plants, as well as 

to obtain a preliminary assessment of treatment technologies and best management practices for 

reducing pollutant discharges. The types of wastewaters sampled during the detailed study were 

untreated and treated FGD wastewater, fly ash wastewater, and bottom ash wastewater. See the 

Steam Electric Power Generating Point Source Category: Final Detailed Study Report for 

additional information on the sampling program completed during the detailed study [U.S. EPA, 

2009b]. 

Following completion of the detailed study, EPA conducted a sampling program at steam 

electric power plants to collect wastewater characterization data and treatment performance data 

associated with FGD wastewater and to collect data for other emerging wastestreams for which 

characterization data were not available (i.e., carbon capture and gasification wastewaters). As 

part of this sampling program, EPA conducted on-site sampling activities (i.e., samples were 

collected directly by EPA), as well as requiring some plants to collect samples for EPA (i.e., 

CWA 308 monitoring program). The following sections present information on the selection of 

plants sampled, the wastewater treatment systems sampled, and the sampling process for field 

sampling conducted following the completion of the detailed study. 

3.4.1 On-Site Sampling Activities

3.4.1.1 United States

EPA conducted four-day sampling episodes at seven U.S. plants to obtain the following: 

1) wastewater characterization data and 2) wastewater treatment technology performance data. 

EPA used these data in combination with other industry-supplied data to evaluate wastewater 

discharges resulting from steam electric power plants and to evaluate technology options for 

handling and treating these wastewaters. The sampling program primarily focused on the 

wastewaters associated with the operation of wet FGD systems. EPA collected information to 

characterize the untreated FGD scrubber purge wastewater, as well as treated FGD wastewater 

from chemical precipitation and biological treatment systems.

The sampling characterized the wastewaters generated by wet FGD scrubbers and the 

treatment performance of the systems used to treat the FGD scrubber purge wastewaters. EPA 

also collected field quality control (QC) samples consisting of bottle blanks, field blanks, 

equipment blanks, and duplicate samples, and laboratory QC samples used for matrix 

spike/matrix spike duplicate analyses.

EPA’s sampling program also collected data in order to perform an engineering 

assessment of the design, operation, and performance of treatment systems at steam electric 
Section 3– Data Collection Activities

3-9 

power plants. Specifically, EPA collected information regarding system design and day-to-day 

operation. 

EPA considered the following characteristics to select plants for sampling:

• Coal-Fired Boilers: All of the plants selected for the sampling program were coalfired plants because the wastestreams of interest for the sampling program data 

objectives are associated with coal-fired power plants. 

• Wet FGD System: EPA evaluated wastewaters generated from wet FGD systems and 

the treatment of these wastewaters. EPA considered the following selection criteria 

regarding FGD systems:

- Type of FGD Wastewater Treatment System: The primary factor for selection was 

the type of wastewater treatment system being operated to treat FGD wastewater.

EPA selected plants operating the following types of wastewater treatment 

systems, which are the basis for the technology options: 

 Chemical precipitation;

 Biological treatment; and

 Vapor-compression evaporation. 

- Age of FGD Wastewater Treatment System: EPA collected samples from 

wastewater treatment systems that reached steady-state operation. EPA sampled 

FGD wastewater treatment systems that had been operating for at least six months 

and that plant staff considered the system to have reached a pseudo-steady state 

condition past the initial commissioning period.

- Type of FGD System: EPA considered the type of FGD system operated by the 

plant (e.g., limestone forced oxidation, lime inhibited oxidation) when selecting 

plants for sampling. Plants generating FGD scrubber wastewater typically operate 

limestone forced oxidation (LSFO) FGD systems. The LSFO system has the 

capability of producing wallboard-grade gypsum, but it typically requires a purge 

stream that needs to be treated prior to discharge.9

• NOx Controls: EPA considered whether the plants operate a selective catalytic 

reduction (SCR) system or a selective noncatalytic reduction (SNCR) system. 

Although these NOx control systems do not generate a specific wastewater stream, 

their operation may affect the FGD wastewater characteristics as well as the fly ash 

and associated fly ash sluice water characteristics. 

• Power Load Cycling: EPA considered a plant’s load cycling (i.e., baseload, cycling, 

peaking) because the production load could potentially affect the FGD wastewater 

 

9 EPA did not select any plants operating inhibited oxidation FGD systems or once-through FGD systems for 

sampling after completion of the detailed study because EPA did not identify any plants that operate these systems 

and also operate a chemical precipitation or biological treatment system. The wastewater pollutants present in these 

systems are similar to those generated by LSFO systems because the scrubbing process will capture the same types 

of pollutants from the flue gas. The technologies used to treat wastewater from a recirculating LSFO FGD system 

would also be effective at treating the wastewater from inhibited oxidation or once-through LSFO FGD systems. 
Section 3– Data Collection Activities

3-10 

characteristics Most of the plants selected for sampling were baseload plants; 

however, plants with cycling units were also selected. 

• Type of Coal: EPA considered the type of coal that the plant burns and selected 

plants burning different types of coal because the types and concentration of metals 

present in the FGD wastewater could differ based on the fuel source. Most of the 

plants sampled burn bituminous coal because the majority of plants with wet FGD 

systems burn bituminous coal; however, EPA also sampled wastewater at plants that 

burn subbituminous coal. 

EPA selected and conducted sampling activities at the following plants in the U.S.: 

• 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. The treatment systems at Belews Creek, Allen, and Dickerson also 

include a biological treatment stage following the chemical precipitation. Table 3-3 presents the 

selection details for each sampled plant.

The pollutants selected for analysis reflected the current understanding of FGD 

wastewaters, including contributions from the fuel, scrubber sorbents, treatment chemicals, and 

other sources. Table 3-4 lists the analytical methods that EPA used for each analyte. In addition 

to these analytes, EPA collected field measurements at all sampling points including temperature 

and pH. 
3-11

Section 3– Data Collection Activities

Table 3-3. Selection Criteria for Plants Included in EPA’s Sampling Program in the United States

Plant Name

Selection Criteria

Coal-Fired 

Boilers

FGD Treatment System

Type of FGD 

System

NOx 

Controls

Power Load 

Cycling Type of Coal

CommercialGrade Gypsum 

By-product

Chemical 

Precipitation Biological

Belews Creek Yes Yes1,3 Yes5 LSFO SCR Baseload Eastern Bituminous Yes

Pleasant Prairie Yes Yes2,4 No LSFO SCR Baseload Subbituminous 

(Powder River Basin) Yes

Miami Fort Yes Yes2 No LSFO SCR Baseload Eastern Bituminous Yes

Allen Yes Yes1,3 Yes5 LSFO SNCR Cycling Bituminous Yes

Dickerson Yes Yes1,3 Yes6 LSFO SNCR Cycling Eastern Bituminous Yes

Keystone Yes Yes2 No LSFO SCR Baseload Eastern Bituminous No

Hatfield's Ferry Yes Yes2 No LSFO SNCR Baseload

Bituminous, 

Subbituminous 

(Powder River Basin)

No

1 - The chemical precipitation system at these plants include hydroxide precipitation and iron coprecipitation, but do not include sulfide precipitation as part of 

the process.

2 - The chemical precipitation system at these plants include hydroxide precipitation, sulfide precipitation, and iron coprecipitation.

3 - The chemical precipitation system at these plants precede a biological treatment stage.

4 - Two-stage chemical precipitation treatment. All other sampled plants use one-stage chemical precipitation.

5 - Anoxic/anaerobic biological system primarily designed to remove selenium.

6 - Sequencing batch reactor (SBR) primarily designed for nutrient removal (nitrification/denitrification).
Section 3 – Data Collection Activities

3-12 

Table 3-4. Analytical Methods Used for EPA’s Sampling Program 

Parameter Method Number

Classicals

Biochemical oxygen demand (BOD5) SM 5210 B

Chemical oxygen demand (COD) EPA 410.4

Total suspended solids (TSS) SM 2540 D

Total dissolved solids (TDS) SM 2540 C

Sulfate EPA 300.0

Chloride EPA 300.0

Ammonia as nitrogen EPA 350.1

Nitrate/nitrate as nitrogen EPA 353.2

Total Kjeldahl nitrogen (TKN) EPA 351.2

Total phosphorus EPA 365.1

Total cyanide SM 4500 CN E

Total and Dissolved Metals

Mercury EPA 1631E

Hexavalent chromium (dissolved only) EPA 218.6

Antimony, arsenic, cadmium, chromium, copper, lead, manganese, nickel, 

selenium, silver, thallium, and vanadium

EPA 200.8 with collision cell

Aluminum, barium, beryllium, boron, calcium, cobalt, iron, magnesium, 

molybdenum, sodium, tin, titanium, and zinc1

EPA 200.7

a - Zinc was analyzed using EPA Method 200.8 with collision cell for the Belews Creek, Pleasant Prairie, Miami 

Fort, and Allen sampling episodes, but was analyzed by EPA Method 200.7 for the Dickerson, Keystone, and 

Hatfield’s Ferry sampling episodes. EPA changed methods because it was observing high concentrations of zinc in 

the influent and effluent samples that were more suited for analysis by EPA Method 200.7.

EPA collected representative samples at the influent and effluent of the FGD wastewater 

treatment systems and, where applicable, the mid-point of the FGD treatment system (i.e., 

effluent from chemical precipitation system prior to biological treatment). EPA collected 24-hour 

composite samples at the mid-point and effluent sampling points for all analytes except mercury 

and cyanide. At the mid-point and effluent sampling points, EPA collected cyanide as a single 

grab sample and mercury as four individual grab samples over the 24-hour period (i.e., a grab 

sample collected every six hours). All influent samples were collected as grab samples.

Sampling episode reports describing the sample collection activities and the analytical 

results from the seven on-site sampling episodes are included in the rulemaking record. [ERG, 

2012a – 2012g] 

3.4.1.2 Italy

In April 2011, EPA conducted a three-day sampling episode at Enel’s Federico II Power 

Plant (Brindisi), located in Brindisi, Italy. The purpose was to characterize untreated FGD 

scrubber purge and treated FGD wastewater from an FGD wastewater treatment system 

consisting of chemical precipitation followed by mechanical vapor-compression evaporation. 
Section 3 – Data Collection Activities

3-13 

The mechanical vapor-compression evaporation system used a falling-film brine concentrator to 

produce a concentrated wastewater stream and a reusable distillate stream. The concentrated 

wastewater stream was further processed in a forced-circulation crystallizer, in which a solid 

product was generated along with a reusable condensate stream.

In addition to collecting the samples of untreated FGD scrubber purge and treated FGD 

wastewater, EPA also collected field QC samples consisting of bottle blanks, field blanks, 

equipment blanks, field duplicate samples, and laboratory QC aliquots used for matrix 

spike/matrix spike duplicate analyses.

Brindisi was selected by EPA for sampling because it operates a one-stage chemical 

precipitation system followed by softening and a two-stage vapor-compression evaporation 

system for the treatment of FGD wastewater. The following are the characteristics of the Brindisi 

plant: 

• The plant is a coal-fired power plant; 

• The plant operates limestone forced oxidation wet FGD systems on all four units; 

• The plant operates a segregated FGD wastewater treatment system, which includes 

the following steps: 

- Settling, 

- Equalization, 

- Lime, sodium sulfide, and caustic soda addition (pH adjustment/metal hydroxide 

precipitation),

- Ferric chloride addition, 

- Polyelectrolyte addition,

- Clarification,

- Ferrous chloride and soda ash addition (softening), 

- Clarification,

- Evaporation (brine concentrator), 

- Crystallization; and

• The plant operates selective catalytic reduction (SCR) systems on all four units.

EPA collected samples for the same list of analytes listed in Table 3-4, except for 

excluding the following analytes either because of holding time considerations or time 

constraints for the sampling event: 

• BOD5;

• Total cyanide; and

• Dissolved metals (all analytes).

EPA also collected field measurements at all sampling points including temperature and 

pH.
Section 3 – Data Collection Activities

3-14 

EPA collected representative samples of the influent to the FGD wastewater treatment 

system, the distillate from the brine concentrator, and the condensate from the crystallizer. EPA 

collected six-hour composite samples at the brine concentrator and crystallizer sampling points 

for all analytes except mercury. At the brine concentrator and crystallizer sampling points, EPA

collected mercury as three individual grab samples over the six-hour period (i.e., a grab sample 

collected every two hours). EPA collected all analytes at the influent to the FGD wastewater 

treatment system as one-day grab samples. 

A sampling episode report describing the sample collection activities and the analytical 

results from this sampling episode are included in the rulemaking record. [ERG, 2012h] 

EPA also requested that a second plant in Italy, A2A’s Centrale di Monfalcone 

(Monfalcone), collect one-day grab samples. Monfalcone operates a chemical precipitation 

followed by vapor-compression evaporation system to treat FGD wastewater. Monfalcone 

personnel collected samples of the FGD influent to wastewater treatment, the distillate from the 

brine concentrator, and the condensate from the crystallizer. Site visit notes and the 

corresponding analytical results are included in the rulemaking record. [ERG, 2013] 

3.4.2 CWA 308 Monitoring Program 

EPA required a subset of steam electric power plants to collect samples that were used to 

supplement the EPA on-site sampling program. Each of the seven plants selected for the on-site 

sampling program (except for the Italian plant) were required to participate in the CWA 308 

monitoring program so EPA could evaluate the variability associated with the FGD wastewaters

treatment systems performance. 

For those seven plants, in addition to the samples collected by EPA during the four-day 

on-site sampling event, EPA required the plants to collect four sets of samples over a four- or 

five-month period. The samples were collected directly by the plants and shipped to EPAcontracted laboratories for analysis.

EPA required four additional plants (not sampled by EPA) to participate in its CWA 308 

monitoring program. These plants were selected to obtain data about operations or treatment 

systems because EPA did not have existing data for these processes or treatment technologies. 

EPA obtained data from the following four plants: 

• Tampa Electric Company’s Polk Station (first of only two currently operating 

integrated gasification combined cycle (IGCC) plants);

• Wabash Valley Power Association’s Wabash River Station (second of only two 

currently operating IGCC plants); 

• Appalachian Power Company’s Mountaineer Plant (only plant operating a carbon 

capture system that is of interest to EPA); and

• Kansas City Power & Light’s Iatan Station (only plant in United States operating a 

one-stage vapor-compression evaporation system for treatment of FGD wastewater).
Section 3 – Data Collection Activities

3-15 

For these four plants, EPA required the plants to collect four consecutive days of samples 

at two to four locations specifically identified for each plant. The sample locations were 

identified to characterize gasification wastewaters, carbon capture wastewaters, and the treatment 

of FGD wastewater and gasification wastewater by vapor-compression evaporation systems. 

EPA used the same four-consecutive-day sampling approach that was used for EPA’s on-site 

sampling program (as described in Section 3.4.1). These samples were collected directly by the 

plants and shipped to EPA-contracted laboratories for analysis.

A report describing the results from the CWA 308 monitoring program is included in the 

rulemaking record. [ERG, 2012i] 

3.5 EPA AND STATE SOURCES

EPA collected information from databases, publications, and state groups and permitting 

authorities, including the following sources discussed below: 

• Information on current and proposed permitting practices for the steam electric 

industry from a review of selected National Pollutant Discharge Elimination System 

(NPDES) permits and accompanying fact sheets;

• Input from EPA and state permitting authorities regarding implementation of the

existing Steam Electric Power Generating ELGs;

• Background information on the steam electric industry from documents prepared 

during the development of the existing Steam Electric Power Generating ELGs (i.e., 

the 1974 and 1982 rulemakings); 

• Information from a survey of the industry conducted in support of the CWA section 

316(b) Cooling Water Intake Structures rulemaking;

• Information from EPA’s OAR, including Integrated Planning Model (IPM) 

projections based on recent air rules (i.e., Cross-State Air Pollution Rule (CSAPR) 

and Mercury and Air Toxics Standards (MATS));

• Information from EPA’s Office of Research and Development (ORD) characterizing 

CCRs and the potential leaching of pollutants from CCRs stored or disposed of in 

landfills and surface impoundments; 

• Information from EPA’s Office of Research and Development (ORD) characterizing 

CCRs and the potential leaching of pollutants from CCRs stored or disposed of in

landfills and surface impoundments 

• Data provided by the North Carolina Department of Environment and Natural 

Resources for one plant that operates an anoxic/anaerobic biological treatment system 

for FGD wastewater; and

• Information collected by EPA’s OSWER, regarding surface impoundments or other 

similar management units that contain CCRs at power plants and other information 

gathered in support of the proposed rule for regulating CCRs under the Resource 

Conservation and Recovery Act (RCRA). 
Section 3 – Data Collection Activities

3-16 

EPA’s Office of Water (OW) has coordinated its efforts with ongoing research and 

activities being undertaken by the EPA offices listed above. In addition, EPA’s OW has also 

coordinated with the Office of Enforcement and Compliance Assurance (OECA) and EPA 

regional offices to gather further information on the industry. 

3.5.1 NPDES Permits and Fact Sheets

The CWA requires direct dischargers (i.e., industrial facilities that discharge process 

wastewaters from any point source into receiving waters) to control their discharges according to 

ELGs and water-quality-based effluent limitations included in NPDES permits. EPA collected 

and reviewed selected NPDES permits and, where available, accompanying fact sheets to 

confirm or help clarify information reported in the survey responses.

3.5.2 State Groups and Permitting Authorities

Throughout the detailed study and rulemaking, EPA interacted with states and EPA 

regional permitting authorities, such as when contacting and visiting steam electric power plants. 

EPA also solicited input and suggestions from states and permitting authorities on specific steam 

electric power plant characteristics, ICR development, and implementation of the Steam Electric 

Power Generating ELGs. EPA hosted a webcast seminar in December 2008 to review 

information on wastewater discharges from power plants for NPDES permitting and 

pretreatment authorities. The webcast provided an update on EPA's review of the current ELGs

(40 CFR 423) and presented information on pollutant characteristics and treatment technologies 

for wastewater from FGD scrubbers. During the webcast, state and interstate approaches for 

managing steam electric power plant wastewaters were shared by representatives from 

Wisconsin, North Carolina, and the Ohio River Valley Water Sanitation Commission 

(ORSANCO).

In November 2009, EPA held conference calls with states and EPA permitting authorities 

to discuss development and input for the ICR [ERG, 2009]. Additionally, EPA held a joint 

Federalism/Unfunded Mandates Reform Act (UMRA) consultation meeting in October 2011 to 

request input regarding the Steam Electric Power Generating ELGs [U.S. EPA, 2011b]. 

EPA participated in periodic conference calls with ORSANCO during the rulemaking to 

discuss treatment technologies for managing wastewaters from steam electric power plants. 

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 [NCDENR, 2011]. 

3.5.3 1974 and 1982 Technical Development Documents for the Steam Electric Power 

Generating Point Source Category

Two documents prepared by EPA during previous rulemakings for the Steam Electric 

Category have provided useful information for the current rulemaking. These documents are the 

1974 Development Document for Effluent Limitations Guidelines and New Source Performance 

Standards for the Steam Electric Power Generating Point Source Category (referred to in this 
Section 3 – Data Collection Activities

3-17 

report as “the 1974 Development Document”) (U.S. EPA, 1974) and the 1982 Development 

Document for Effluent Limitations Guidelines and Standards and Pretreatment Standards for the 

Steam Electric Point Source Category (referred to in this report as “the 1982 Development 

Document”) (U.S. EPA, 1982). These development documents contain findings, conclusions, 

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

electric power plants. During this rulemaking, EPA used the information presented in the 1974 

and 1982 Development Documents for historical background on the Steam Electric Power 

Generating ELGs and for information on sources of pollutants and wastewater characteristics.

3.5.4 CWA Section 316(b) - Cooling Water Intake Structures Supporting Documentation 

and Data 

For the CWA section 316(b) Cooling Water Intake Structures rulemaking, EPA 

conducted a survey of steam electric utilities and steam electric non-utilities that use cooling 

water, as well as facilities in four other manufacturing sectors: Paper and Allied Products 

(Standard Industrial Classification (SIC) code 26), Chemical and Allied Products (SIC code 28), 

Petroleum and Coal Products (SIC code 29), and Primary Metals (SIC code 33). The survey 

requested the following types of information: 

• General plant information, such as plant name, location, and SIC codes; 

• Cooling water source and use;

• Design and operational data on cooling water intake structures and cooling water 

systems;

• Studies of the potential impacts from cooling water intake structures conducted by the 

facility; and

• Financial and economic information about the facility.

Although the Section 316(b) survey was used to create guidelines for cooling water 

intake structures, the cooling water system information collected in the survey was also useful 

for this rulemaking effort. EPA used the information provided by the Section 316(b) survey in 

the following analyses:

• Identifying plant-specific cooling water sources (e.g., specific rivers, streams); 

• Identifying industrial non-utilities;

• Identifying the type of cooling systems used by plants; 

• Linking EIA plant information to the Toxic Release Inventory (TRI) and Permit 

Compliance System (PCS) discharges; and

• Determining plant-specific wastewater dilutions associated with cooling water prior 

to discharge for the Environmental Assessment (EA) analyses associated with the 

rulemaking effort.
Section 3 – Data Collection Activities

3-18 

3.5.5 Office of Air and Radiation

EPA’s OAR works to control air pollution and radiation exposure and takes action on 

climate change by developing regulations under the Clean Air Act (CAA), and developing 

national programs and technical policies. OAR relies on the Integrated Planning Model (IPM) for 

some of its analyses of the effects of policies on the electric power sector. IPM is an engineeringeconomic optimization model of the electric power industry, which generates least-cost resource 

dispatch decisions based on user-specified constraints such as environmental, demand, and other 

operational constraints. The model uses a long-term dynamic linear programming framework 

that simulates the dispatch of generating capacity to achieve a demand-supply equilibrium on a 

seasonal basis and by region. In addition to existing capacity, the model also considers new 

resource investment options, including capacity expansion at existing plants, as well as 

investment in new plants. The model is dynamic in that it is capable of using forecasts of future 

conditions to make decisions for the present. IPM Version 4.10 MATS (IPM V4.10) incorporates 

in its analytic baseline the expected compliance response for the following air regulations 

affecting the power sector: the final Mercury and Air Toxics Standards (MATS) rule; the final 

Cross-State Air Pollution Rule (CSAPR); regulatory SO2 emission rates arising from State 

Implementation Plans; Title IV of the Clean Air Act Amendments; NOx SIP Call trading 

program; Clean Air Act Reasonable Available Control Technology requirements and Title IV 

unit specific rate limits for NOx; the Regional Greenhouse Gas Initiative; Renewable Portfolio 

Standards; New Source Review Settlements; and several state-level regulations affecting 

emissions of SO2, NOx, and Hg that were either in effect or expected to come into force by 2017. 

Thus, IPM V4.10 projects the characteristics of electricity generation for various “plant 

types” in the future, considering the expected impacts of regulations [U.S. EPA, 2011a]. EPA 

used the output from the MATS policy case for run year 2015 to identify potential future wet 

FGD scrubber installation that may not be accounted for in the survey responses. EPA used these 

data to inform a “future” profile of the industry, which is discussed in Section 8.1.7. 

3.5.6 Office of Research and Development

EPA’s ORD is evaluating the impact of air pollution controls on the characteristics of 

CCRs. Specifically, ORD is studying the potential cross-media transfer of mercury and other 

metals from flue gas, fly ash, and other residuals collected from coal-fired boiler air pollution 

controls and disposed of in landfills or impoundments. The key routes of release being studied 

are leaching into ground water or subsequent release into surface waters, re-emission of mercury, 

and bioaccumulation. ORD is also examining the use of CCRs in asphalt, cement, and wallboard 

production. 

The goal of the research is to better understand potential impacts from disposal practices 

and beneficial use of CCRs. The research evaluates life-cycle environmental tradeoffs that 

compare beneficial use applications with and without using CCRs. The outcome of this research 

will help to identify potential management practices of concern where environmental releases 

may occur, such as developing and applying a leach testing framework that evaluates a range of 

materials and the different factors affecting leaching for the varying field conditions in the 

environment. 
Section 3 – Data Collection Activities

3-19 

EPA’s OW consulted with the ORD on the status and findings of current research 

assessing the potential for CCRs to impact water quality. Additionally, during EPA’s sampling 

program, OW collected samples of CCR landfill leachate from several of the plants for 

characterization analysis by ORD.

3.5.7 Office of Solid Waste and Emergency Response

On June 21, 2010, EPA proposed the Hazardous and Solid Waste Management System: 

Identification and Listing of Special Wastes; Disposal of Coal Combustion Residuals from 

Electric Utilities (i.e., the CCR rule) (75 FR 35128; June 21, 2010). The proposed rule would 

regulate coal ash to address the risks from the disposal of the wastes generated by electric 

utilities and independent power producers. EPA used data collected by EPA’s OSWER to 

supplement the data collected for the ELGs. EPA also used costing methodologies developed by 

EPA’s OSWER in some of the costing approaches for the proposed ELGs, if appropriate. 

As part of the proposed CCR rule development, EPA’s OSWER issued Information 

Request Letters to electric utilities that have surface impoundments or similar management units 

that contain CCRs. EPA’s OSWER identified the recipients of the request letters based on plants 

that potentially operate CCR surface impoundments identified from data compiled in DOE’s EIA 

databases. However, the EIA data do not include information about waste disposal practices for 

those plants with a nameplate electric generating capacity of less than 100 MW. Additionally, the 

EIA data excludes information about impoundments at plants that use the impoundment as an 

interim step (e.g., to dewater ash or other CCR solids), but ultimately dispose of the CCRs in an 

on-site landfill or off site. Therefore, OSWER may not have identified the plants operating these 

types of impoundments as potential recipients. As such, data collected by the OSWER survey 

underestimates the total number of CCR impoundments nationwide. 

As explained in Section 1.3.3, because the CCR rule has not been finalized, EPA cannot 

factor in with certainty how any operational changes associated with any final CCR rule may 

impact the analyses for the proposed ELGs. Therefore, the analyses presented for the proposed 

ELGs represent current industry operations, without implementation of new requirements 

contemplated by the CCR rule. Rather, EPA conducted a sensitivity analyses to see how any 

final CCR rule might impact the analyses for the proposed ELGs. See DCN SE02123. 

3.6 INDUSTRY-SUBMITTED DATA

EPA obtained information on steam electric processes, technologies, wastewaters, and 

pollutants directly from the industry through self-monitoring data, as well as NPDES Form 2C

data. 

3.6.1 Self-Monitoring Data 

EPA requested self-monitoring data from Duke Energy’s Belews Creek Steam Station 

and Allen Steam Station to evaluate the treatment efficiency and pollutant characteristics of 

wastewater discharged from FGD wastewater treatment systems that incorporate both chemical 

precipitation and biological treatment (Duke Energy, 2011a and 2011b). EPA also used these 

data to supplement the data from the EPA sampling program. 
Section 3 – Data Collection Activities

3-20 

3.6.2 NPDES Form 2C

UWAG and EPA coordinated efforts to create a database of selected NPDES Form 2C 

data from UWAG’s member companies. 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 industrial facilities (including manufacturing, commercial, mining, and 

silvicultural operations). This form includes facility information, data on facility outfalls, process 

flow diagrams, treatment information, and intake and effluent characteristics.

The Form 2C database contains information about the outfalls of coal-fired power plants 

that receive FGD, ash handling, or coal pile runoff wastestreams. EPA received Form 2C data 

from UWAG for 86 plants in late June 2008 [UWAG, 2008]. UWAG did not include data on 

other outfalls, such as separate outfalls for sanitary wastes, cooling water, landfill runoff, and 

other wastestreams, in the database. 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 transport, UWAG 

did not include its information in the database. EPA used the Form 2C data for developing a 

preliminary industry profile and the survey, but these outfall data were eventually superseded by 

the data received in response to the survey. 

3.7 TECHNOLOGY VENDOR DATA

EPA gathered data from technology vendors through presentations, conferences, 

meetings, and email and phone contacts regarding the technologies used in the industry. The data 

collected informed the development of the detailed study, the industry survey, and technology 

costs and loadings estimates. Between 2007 and 2012, EPA participated in multiple technical 

conferences and reviewed the papers presented.

To gather FGD wastewater treatment information for the cost analyses, EPA contacted 

companies that manufacture, distribute, or install various components of chemical precipitation 

and biological wastewater treatment systems and vapor-compression evaporation. 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;

• Operating and maintenance costs; and

• Equipment and system energy requirements.

To gather information on handling of fly ash and bottom ash, 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 handling ash dry or 

in closed-loop recycle; 
Section 3 – Data Collection Activities

3-21 

• Equipment and modifications required to convert wet fly ash and bottom ash handling 

systems to dry handling or closed-loop recycle systems;

• Equipment that can be reused as part of the conversion from wet to dry handling or in 

a closed-loop recycle system; 

• Outage time required for the different types of ash handling systems; 

• Maintenance required for each type of system;

• Operating data for each type of system;

• Equipment and installation capital costs for fly ash and bottom ash conversion; 

• The specifications for the types of ash storage available for the different types of 

handling systems; 

• The equipment and installation capital costs associated with the storage of fly ash and 

bottom ash; and 

• Operating and maintenance costs for fly ash and bottom ash handling systems. 

To obtain additional information on FGD treatment systems and fly ash and bottom ash 

conversions, EPA held meetings, conference calls, and site visits with treatment and ash vendors. 

3.8 OTHER SOURCES

EPA obtained additional information on steam electric processes, technologies, 

wastewaters, pollutants, and regulations from sources including trade associations, the Electric 

Power Research Institute (EPRI), DOE, the U.S. Geological Survey (USGS), UWAG, and 

literature and Internet searches. 

3.8.1 Utility Water Act Group

UWAG is an association of over 200 individual electric utilities and four national trade 

associations of electric utilities: the Edison Electric Institute, the National Rural Electric 

Cooperative Association, the American Public Power Association, and the Nuclear Energy 

Institute. UWAG’s purpose is to participate on behalf of its members in EPA’s rulemakings 

under the CWA. Specifically, EPA coordinated with UWAG on collecting information on power 

plant characteristics to support site visit selection, discussing wastewater sampling approaches 

and recommendations, laboratory analytical methods, reviewing the questionnaire for clarity, 

reviewing the questionnaire mailing list to confirm plants and mailing addresses, and collecting 

existing permit data. At the invitation of individual plants, UWAG representatives also collected 

split samples during EPA’s on-site sampling and CWA 308 monitoring programs and 

participated in most site visits.

3.8.2 Electric Power Research Institute

EPRI is a research-oriented trade association for the steam electric industry. EPRI 

conducts research funded by the steam electric industry and has extensively studied wastewater 

discharges from FGD systems. The trade association provided EPA with the following reports 

that summarize the data collected during several EPRI studies: 
Section 3 – Data Collection Activities

3-22 

• Flue Gas Desulfurization (FGD) Wastewater Characterization: Screening Study 

(EPRI, 2006a); 

• EPRI Technical Manual: Guidance for Assessing Wastewater Impacts of FGD 

Scrubbers (EPRI, 2006b); 

• The Fate of Mercury Absorbed in Flue Gas Desulfurization (FGD) Systems (EPRI, 

2005); 

• Update on Enhanced Mercury Capture by Wet FGD: Technical Update (EPRI, 2007); 

• PISCES Water Characterization Field Study, Sites A-G (EPRI, 1997b-2001); 

• Selenium Removal by Iron Cementation from a Coal-Fired Power Plant Flue Gas 

Desulfurization Wastewater in a Continuous Flow System – A Pilot Study (EPRI, 

2009a); and

• Laboratory and Pilot Evaluation of Iron and Sulfide Additives with Microfiltration for 

Mercury Water Treatment (EPRI, 2009b). 

The EPRI reports provided EPA with background information regarding the 

characteristics of FGD wastewaters and the sampling techniques used during the program. These 

reports also provided EPA with information regarding the characteristics of discharges from fly 

ash and bottom ash impoundments and the respective percentage of loadings from ash 

impoundments containing both fly ash and bottom ash. Additionally, the EPRI reports provided 

information on the treatment technologies available to treat FGD and ash wastewaters, including 

findings from pilot-study evaluations. 

EPRI also participated in meetings with EPA and provided comments on EPA’s planned 

data collection activities, including the survey and the sampling program. 

3.8.3 Department of Energy (DOE)

DOE is the department of the United States government responsible for energy policy. 

EPA used information on electric generating plants from DOE’s EIA data collection forms.

The Agency used information from two of EIA’s data collection forms: Form EIA-860, 

Annual Electric Generator Report, and Form EIA-923, Power Plant Operations Report. Form 

EIA-860 collects information annually from all electric generating facilities that have or will 

have a nameplate capacity of 1 MW or more and are operating or plan to be operating within five 

years of filing this form.

10 The data collected in Form EIA-860 are associated only with the 

design and operation of generators at facilities [U.S. DOE, 2007a and 2009a]. Form EIA-923 

collects information from electric power plants and combined heat and power plants in the 

United States that have a total generator nameplate capacity greater than 1 MW. The form asks 

where the generator(s), or the facility in which the generator(s) resides, and if it is connected to 

 

10 DOE defines the generator nameplate capacity as the maximum rated output of a generator under specific 

conditions designated by the manufacturer. Generator nameplate capacity is usually indicated in units of kilovoltamperes (kVA) and in kilowatts (kW) on a nameplate physically attached to the generator. More generally, 

generator capacity is the maximum output, commonly expressed in MW, that generating equipment can supply to 

system load, adjusted for ambient conditions.
Section 3 – Data Collection Activities

3-23 

the local or regional electric power grid and has the ability to draw power from the grid or 

deliver power to the grid. The data collected in Form EIA-923 are associated with the operation 

and design of the entire facility [U.S. DOE, 2007b and 2009b]. EPA used these data to help 

identify the industry the sample frame for the Steam Electric Survey. Additionally, EPA used 

these data to supplement Steam Electric Survey data, such as age of the generating units, which 

was not included in the survey. 

3.8.4 Literature and Internet Searches

EPA conducted literature and Internet searches to obtain information on various aspects 

of the steam electric process, both for plants regulated by the ELGs and certain operations 

outside the scope of the regulations for which EPA evaluated whether they could/should be 

covered by the ELGs. The objectives of these searches included characterizing wastewaters and 

pollutants originating from these steam electric processes, the environmental impacts of these 

wastewaters, and applicable regulations. EPA also used the Internet searches to identify or 

confirm reports of planned plant/unit retirements or reports of planned unit conversions to dry or 

closed-loop recycle ash handling systems. EPA used industry journals, reference texts about the 

industry, and company press releases obtained from Internet searches to inform the industry 

profile and process modifications occurring in the industry. 

3.8.5 Environmental Groups and Other Stakeholders

EPA received information from several environmental groups and other stakeholders as 

part of public comments submitted for the 2006 and 2008 Effluent Guidelines Plans, the survey, 

and in other discussions during the detailed study and rulemaking. In general, the information 

highlighted environmental concerns associated with the pollutants present in steam electric 

power plant wastewaters, and technological controls for reducing or eliminating pollutant 

discharges from FGD and ash handling systems. 

3.9 PROTECTION OF CONFIDENTIAL BUSINESS INFORMATION

Certain data in the rulemaking record have been claimed as confidential business 

information (CBI). The Agency has withheld CBI from the public docket in the Federal Docket 

Management System. In addition, the Agency has withheld from disclosure some data not 

claimed as CBI because the release of these data could indirectly reveal CBI. 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. 

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 
Section 3 – Data Collection Activities

3-24 

3. Eastern Research Group (ERG). 2009. Memorandum to Ron Jordan, US EPA. “Outreach 

Calls for the Proposed Steam Electric ICR.” (25 February). DCN SE00203. 

4. Eastern Research Group (ERG). 2012a. Final Sampling Episode Report, Duke Energy 

Carolinas’ Belews Creek Steam Station. (13 April). DCN SE01305. 

5. Eastern Research Group (ERG). 2012b. Final Sampling Episode Report, We Energies’ 

Pleasant Prairie Power Plant. (13 April). DCN SE01306. 

6. Eastern Research Group (ERG). 2012c. Final Sampling Episode Report, Duke Energy 

Miami Fort Station. (13 April). DCN SE01304. 

7. Eastern Research Group (ERG). 2012d. Final Sampling Episode Report, Duke Energy 

Carolinas’ Allen Steam Station. (13 April). DCN SE01307. 

8. Eastern Research Group (ERG). 2012e. Final Sampling Episode Report, Mirant MidAtlantic, LLC’s Dickerson Generating Station. (13 April). DCN SE01308. 

9. Eastern Research Group (ERG). 2012f. Final Sampling Episode Report, Allegheny 

Energy’s Hatfield’s Ferry Power Station. (13 April). DCN SE01310. 

10. Eastern Research Group (ERG). 2012g. Final Sampling Episode Report, RRI Energy’s 

Keystone Generating Station. (13 April). DCN SE01309. 

11. Eastern Research Group, Inc. (ERG). 2012h. Final Site Visit Notes and Sampling 

Episode Report for Enel’s Power Plants. (8 August). DCN SE02013. 

12. 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. 

13. Eastern Research Group (ERG). 2013. Final Monfalcone Site Visit Notes. (11 March). 

DCN SE03795 and SE03796. 

14. Electric Power Research Institute (EPRI). 1997b - 2001. PISCES Water Characterization 

Field Study, Sites A-G. Palo Alto, CA. DCN SE01818 through SE01823. 

15. Electric Power Research Institute (EPRI). 2005. The Fate of Mercury Absorbed in Flue 

Gas Desulfurization (FGD) Systems. 1009955. Palo Alto, CA. (March). DCN SE01814. 

16. Electric Power Research Institute (EPRI). 2006a. Flue Gas Desulfurization (FGD) 

Wastewater Characterization: Screening Study. 1010162. Palo Alto, CA. (March). DCN 

SE01816. 

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 SE01817. 

18. Electric Power Research Institute (EPRI). 2007. Update on Enhanced Mercury Capture 

by Wet FGD: Technical Update. 1012673. Palo Alto, CA. (March). DCN SE01815. 

19. Electric Power Research Institute (EPRI). 2009a. Laboratory and Pilot Evaluation of Iron 

and Sulfide Additives with Microfiltration for Mercury Water Treatment. 1016813. Palo 

Alto, CA. (March). DCN SE00409A3. 
Section 3 – Data Collection Activities

3-25 

20. Electric Power Research Institute (EPRI). 2009b. Selenium Removal by Iron 

Cementation from a Coal-Fired Power Plant Flue Gas Desulfurization Wastewater in a 

Continuous Flow System – Pilot Study. 1017956. Palo Alto, CA. (July). DCN 

SE00409A2. 

21. NCDENR. 2011. North Carolina Department of Environment and Natural Resources 

(NCDENR) State Provided Sampling Data From North Carolina's Progress Energy 

Roxboro Plant. (26 June). DCN SE01812. 

22. U.S. DOE. 2007a. U.S. Department of Energy. Annual Electric Generator Report 

(collected via Form EIA-860). Energy Information Administration (EIA). The data files 

are available online at: http://www.eia.gov/electricity/data/eia860/index.html. DCN 

SE02014. 

23. U.S. DOE. 2007b. U.S. Department of Energy. Power Plant Operations Support 

(collected via Forms EIA-906/920/923). Energy Information Administration (EIA). The 

data files are available online at: http://www.eia.gov/electricity/data/eia923/. DCN 

SE02015. 

24. U.S. DOE. 2009a. U.S. Department of Energy. Annual Electric Generator Report 

(collected via Form EIA-860). Energy Information Administration (EIA). The data files 

are available online at: http://www.eia.gov/electricity/data/eia860/index.html. DCN 

SE01805. 

25. U.S. DOE. 2009b. U.S. Department of Energy. Power Plant Operations Support 

(collected via Form EIA-923). Energy Information Administration (EIA). The data files 

are available online at: http://www.eia.gov/electricity/data/eia923/. DCN SE02030. 

26. U.S. EPA. 1974. Development Document for Effluent Limitations Guidelines and New 

Source Performance Standards for the Steam Electric Power Generating Point Source 

Category. Washington, D.C. (October). DCN SE02917. 

27. 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 SE02931. 

28. U.S. EPA. 2009a. Office of Solid Waste and Emergency Response (OWSER), Summary 

Results from the 2009 OSWER Information Request. DCN SE02032. 

29. U.S. EPA. 2009b. Steam Electric Power Generating Point Source Category: Final 

Detailed Study. EPA 821-R-09-008. Washington, D.C., (October). DCN SE00003. 

30. U.S. EPA. 2011a. Office of Air and Radiation (OAR). Integrated Planning Model (IPM) 

2015 MATS Policy Case Output. (December). DCN SE02047. 

31. U.S. EPA. 2011b. Steam Electric ELG Rulemaking – UMRA and Federalism 

Implications: Consultation Meeting. (11 October). DCN SE03286 and SE03287. 

32. Utility Water Act Group (UWAG). 2008. UWAG Form 2C Effluent Guidelines 

Database. (30 June). DCNs SE02918 and SE02918A1. 
Section 4 – Steam Electric Industry Description

4-1 

SECTION 4

STEAM ELECTRIC INDUSTRY DESCRIPTION

Electricity is produced by converting mechanical, chemical, and/or fission energy into 

electrical energy, and may or may not involve the use of steam. This section provides an 

overview of the various types of electric generating processes operating in the United States and 

describes more fully the categories of processes regulated by the Steam Electric Power 

Generating effluent limitations guidelines and standards (ELGs). Section 4.1 generally describes 

the electric generating industry, including demographics of the steam electric industry; Section 

4.2 describes the steam electric power generating process; Section 4.3 describes the wastestreams 

generated by the steam electric industry that were evaluated for new or additional controls in the 

proposed ELGs; and Section 4.4 describes the wastestreams generated by the steam electric 

industry that were not evaluated for new or additional controls in the proposed ELGs. 

4.1 OVERVIEW OF ELECTRIC GENERATING INDUSTRY

This section describes the types of plants that compose the overall electric generating 

industry as well as the definition of the Steam Electric Power Generating Point Source Category 

(Steam Electric Category). As shown in Figure 4-1, the plants regulated by the Steam Electric 

Power Generating ELGs are only a portion of the electric generating industry. 

Figure 4-1. Types of U.S. Electric Generating Plants

Electric Generating Plants

Industrial Non-Utilities Electric Generating Industry

(Utilities and Non-Utilities)

Steam Electric 

Power Generation

Non-Steam Electric 

Power Generation

Fossil or Nuclear Steam Electric 

Generating Plants

(Steam Electric Power Generating 

Point Source Category)

Non-Fossil and Non-Nuclear 

Steam Electric Generating Plants
Section 4 – Steam Electric Industry Description

4-2 

4.1.1 Electric Generating Industry Population

In general, the companies generating electrical power are categorized as one of the 

following types: 

• Utility: Any entity that generates, transmits, and/or distributes electricity and recovers 

the cost of its generation, transmission and/or distribution assets and operations, 

either directly or indirectly, through cost-based rates set by a separate regulatory 

authority (e.g., state Public Service Commission), or is owned by a governmental unit 

or the consumers that the entity serves. According to the Department of Energy 

(DOE)’s Energy Information Administration (EIA), plants that qualify as 

cogenerators or small power producers under the Public Utility Regulatory Policies 

Act are not considered electric utilities [U.S. DOE, 2012b]. 

• Non-Industrial Non-Utility: Any entity that generates, transmits, and/or sells 

electricity, or sells or trades electricity services and products, where costs are not 

established and recovered by a regulatory authority. Non-utility power producers 

include, but are not limited to, independent power producers, power marketers and 

aggregators, merchant transmission service providers, self-generation entities, and 

cogeneration firms with Qualifying Facility Status [U.S. DOE, 2012b]. Like utilities, 

the primary purpose of non-industrial non-utilities is producing electric power for 

distribution and/or sale. 

• Industrial Non-Utility: Industrial non-utilities are similar to non-industrial nonutilities except their primary purpose is not distributing and/or selling electricity. This 

category includes electric generators that are located at industrial plants such as 

chemical manufacturing plants or paper mills. Industrial non-utilities typically 

provide most of the electrical power they generate to the industrial operation with 

which they are located, although they may also provide some electric power to the 

grid for distribution and/or sale. 

This section presents available demographic data and other information for the electric 

generating industry, excluding industrial non-utilities. EPA analyzed the available demographic 

information using EIA data for the year 2009 (Form EIA-860) [U.S. DOE, 2009] and U.S. 

Census Bureau data collected in the 2007 Economic Census [USCB, 2007]. EPA used the 2009 

EIA data because data collected from the steam electric industry via EPA’s Questionnaire for the 

Steam Electric Power Generating Effluent Guidelines (survey) represents plant-level operations 

in 2009 and the 2007 Census data because, as a 5-year census, it is the most recent year for 

which data are available. Together, these sources provide the most recent and comprehensive set 

of power plant data available. EPA identified electric generating plants in the EIA database as 

those reporting North American Industrial Classification System (NAICS) code 22 – Utilities.

11

The 2007 Economic Census data include more specific industry sector information at the sixdigit NAICS code level.

 

11 NAICS code 22 – Utilities is defined as establishments providing the following utility services: electric power, 

natural gas, steam supply, water supply, and sewage removal. Excluded from this sector are establishments primarily 

engaged in waste management services [USCB, 2007].
Section 4 – Steam Electric Industry Description

4-3 

EPA also examined the data on operations that electric generating plants reported to the 

EIA in 2009. Form EIA-860 contains records for 15,169 steam and nonsteam electric generating 

units having at least one megawatt (MW) of capacity operated at 5,300 facilities for calendar 

year 2009 [U.S. DOE, 2009]. Because the EIA data also include units at industrial non-utilities, 

they overestimate the number of units and plants that may be considered part of the electric 

generating industry. 

According to the Economic Census, there were 1,934 electric generating plants in the 

United States in 2007, 69 percent (1,327 plants) of which were characterized primarily as using 

fossil or nuclear fuel [USCB, 2007]. These data include both steam and non-steam-electric 

generating processes. Table 4-1 presents the distribution of plants among each of the electric 

generating NAICS codes. The Economic Census includes all facilities reporting under NAICS 

code 22. As a result, it includes entities categorized by DOE as utilities and non-industrial nonutilities, but does not include industrial non-utilities.

Table 4-1. Distribution of U.S. Electric Generating Plants by NAICS Code in 2007 

NAICS Code – Description Plants

221111 – Hydroelectric Power Generation 295

221112 – Fossil Fuel Electric Power Generation 1,248

221113 – Nuclear Electric Power Generation 79

221119 – Other Electric Power Generation (includes conversion of other forms of energy, 

such as solar, wind, or tidal power, into electrical energy)

312

22111 – Electric Power Generation (Total) 1,934

Source: U.S. Census, [USCB, 2007]. 

4.1.2 Applicability of Steam Electric Power Generating Effluent Guidelines

Industrial non-utilities are not included within the scope of the existing Steam Electric 

Power Generating ELGs because they are not primarily engaged in producing electricity for 

distribution and/or sale.12 As described above, these industrial non-utilities typically are 

industrial plants that produce, process, or assemble goods, and the electricity generated at these 

plants is an ancillary operation used to dispose of a by-product or for cost savings. 

Because industrial non-utilities are not included in the applicability of the Steam Electric 

Power Generating ELGs, EPA has excluded them from the discussion of the U.S. electric 

generating industry for the purposes of this document. Therefore, information presented on 

plants composing the electric generating industry includes only the utilities and the nonindustrial non-utilities. Although the transmission and distribution entities are included in the 

definition of utilities and non-industrial non-utilities, they are not included in the Steam Electric 

 

12 The applicability of the Steam Electric Power Generating Point Source Category (40 CFR 423.10) states the 

following: “The provisions of this part are applicable to discharges resulting from the operation of a generating unit 

by an establishment primarily engaged in the generation of electricity for distribution and sale which results 

primarily from a process utilizing fossil-type fuel (coal, oil, or gas) or nuclear fuel in conjunction with a thermal 

cycle employing the steam water system as the thermodynamic medium.”
Section 4 – Steam Electric Industry Description

4-4 

Category; therefore, this document presents information only on the plants and NAICS codes 

associated with the generation of electricity.

As shown in Figure 4-1, the electric generating industry can be further broken down 

based on the type of prime mover used to generate electricity. EIA defines a prime mover as the 

engine, turbine, water wheel, or similar machine that drives an electric generator or a device that 

converts energy to electricity directly (e.g., photovoltaic solar and fuel cell(s)) [U.S. DOE, 

2012a]. Because the Steam Electric Power Generating ELGs are applicable only to plants 

generating electricity using a “thermal cycle employing the steam water system as a 

thermodynamic medium,” EPA categorized the prime movers into “steam electric” and “nonsteam-electric” categories. The steam electric generating units include steam turbines and 

combined cycle systems (see Sections 4.2.1 and 4.2.2 for more details on these types of units). 

The non-steam-electric generating units include, but are not limited to, stand-alone combustion 

turbines, internal combustion engines, fuel cells, and wind turbines. 

The final criterion for a plant to meet the applicability of the Steam Electric Power 

Generating ELGs is that it must primarily utilize a fossil or nuclear fuel to generate the steam 

used in the turbine. Fossil fuels include coal, oil, or gas, and fuels derived from coal, oil, or gas 

such as petroleum coke, residual fuel oil, and distillate fuel oil. Fossil fuels also include blast 

furnace gas and the product of gasification processes using fossil-based feedstocks such as coal, 

petroleum coke, and oil. Examples of nonfossil/nonnuclear fuels used by some steam electric 

power plants include pulp mill black liquor, municipal solid waste, and wood solid waste. 

4.2 STEAM ELECTRIC GENERATING INDUSTRY

EPA identified the subset of electric generating plants in the EIA database that use steam 

electric processes as those operating at least one prime mover that utilizes steam. The following 

electric generating unit or prime mover types specified in the EIA database are included in the 

steam electric industry:

• Steam turbine;

• Combined cycle system – steam turbine portion; and

• Combined cycle system – combustion turbine portion.13

Within each prime mover category, electric generating units are also classified by type of 

unit based on how often the units are in operation. Units can be classified as baseload, peaking, 

cycling, or intermediate. Baseload units produce electricity at an essentially constant rate and 

typically run for extended periods, peaking units operate during peak-load periods, cycling units 

generally operate in a routine cycle (i.e., only operating during the day), and intermediate units 

produce electricity on an as needed basis operating more frequently than peaking units but less 

frequently than baseload units. 

 

13 Although the combustion turbine portion of the combined cycle system does not use steam to turn the turbine, the 

combined cycle system does use steam associated with the steam turbine portion; therefore, both portions are 

included in the analysis because the entire combined cycle system is covered under the Steam Electric Power 

Generating ELGs.
Section 4 – Steam Electric Industry Description

4-5 

The subset of steam electric power plants that are regulated by the Steam Electric Power 

Generating ELGs use a fossil or nuclear fuel as the primary energy source for the steam electric 

generating unit. In analyzing the EIA data, EPA included plants using the following EIA-defined 

nuclear and fossil (or fossil-derived) fuel types:

• Anthracite coal;

• Bituminous coal; 

• Lignite coal;

• Subbituminous coal; 

• Coal synfuel;

• Waste/other coal;

• Petroleum coke;

• No. 1 Fuel Oil; 

• No. 2 Fuel Oil; 

• No. 4 Fuel Oil; 

• No. 5 Fuel Oil; 

• No. 6 Fuel Oil; 

• Diesel Fuel;

• Jet fuel;

• Kerosene;

• Oil-other and waste oil (e.g., crude oil, liquid by-products, oil waste, propane (liquid), 

rerefined motor oil, sludge oil, tar oil); 

• Natural gas;

• Blast furnace gas;

• Gaseous propane; 

• Other gas; and

• Nuclear (e.g., uranium, plutonium, thorium). 

Using the criteria for the prime mover type and energy source described above for all 

plants (utilities and non-industrial non-utilities) reporting a NAICS code of 22 to EIA in 2009, 

EPA identified 1,179 steam electric power plants potentially subject to the Steam Electric Power 

Generating ELGs. In analyzing the EIA energy source data for the purpose of this report, EPA 

limited the analysis to identify only plants/units that reported one of the above energy sources as 

a “primary” or “secondary” energy source in the 2009 EIA data.

14 The 1,179 plants operate an 

 

14 For the purposes of this analysis, EPA included only plants/units based on the “secondary” energy source when it 

was reported as a type of coal or petroleum coke. For example, if a generating unit reported the “primary” energy 

source as municipal solid waste and the “secondary” energy source as coal, the plant was included in the analysis; 

however, if the generating unit reported the “secondary” energy source as natural gas, then the plant would not have 

been included in the analysis.
Section 4 – Steam Electric Industry Description

4-6 

estimated 3,341 stand-alone steam electric generating units or combined cycle systems, which 

have a total generating capacity of 778,000 MW [U.S. DOE, 2009].

4.2.1 Steam Electric Generating Process

Steam electric power plants generate electricity using a process that includes a steam 

generator (i.e., boiler), a steam turbine/electrical generator, and a condenser. Figure 4-2 

illustrates the stand-alone steam electric process, in which a combustible fuel is used as the 

energy source to generate steam. The Steam Electric Power Generating ELGs regulate 

wastewater discharged by those steam electric power plants that use fossil-type fuel (e.g., coal, 

oil, or gas) or nuclear fuel to generate the steam. As shown in Figure 4-2, fuels are fed to a boiler 

where they are combusted to generate steam. Boilers and their associated subsystems often 

include components to improve thermodynamic efficiency by boosting steam temperature and 

preheating intake air using superheaters, reheaters, economizers, and air heaters. The hot gases 

from combustion (i.e., the flue gas) leave the steam generator subsystem and pass through 

particulate collection and the sulfur dioxide (SO2) scrubbing system (if present), and then are

emitted through the stack. Natural gas-fired units typically do not operate these types of air 

pollution controls. The high-temperature, high-pressure steam leaves the boiler and enters the 

turbine generator where it drives the turbine blades as it moves from the high-pressure to the 

low-pressure stages of the turbine. The spinning of the turbine blades drives the linked generator, 

producing electricity. The lower-pressure steam leaving the turbine enters the condenser, where 

it is cooled and condensed by the cooling water flowing through heat exchanger (condenser) 

tubes. The water collected in the condenser (condensate) is returned to the boiler where it is 

again converted to steam [Babcock & Wilcox, 2005]. 

Combusting coal, petroleum coke, and oil in steam electric boilers produces a residue of 

noncombustible fuel constituents, referred to as ash. Some of the ash consists of very fine 

particles that are light enough to be entrained in the flue gas and carried out of the furnace and is 

commonly known as fly ash. The heavier ash that settles in the furnace or is dislodged from 

furnace walls is collected at the bottom of the boiler and is referred to as bottom ash. 

Combusting fossil fuels also generates pollutants in the flue gas (e.g., nitrogen oxides, 

SO2, carbon dioxide (CO2)) that, if not removed, would be emitted to the atmosphere. Therefore, 

many plants operate air pollution control technologies that remove these pollutants from the flue 

gas. The following are some of the common air pollution control technologies used in the 

industry and the pollutant they are primarily used to control: 

• Electrostatic precipitator (ESP): fly ash/particulate matter;

• Flue gas desulfurization (FGD): SO2; 

• Selective catalytic reduction (SCR): nitrogen oxides;

• Selective non-catalytic reduction (SNCR): nitrogen oxides; and 

• Flue gas mercury controls (FGMC): mercury.

The nuclear-fueled steam electric process is similar to the steam/water system described 

above. The nuclear system differs from the non-nuclear system in three key ways: fuel handling, 

nuclear fission within the reactor core instead of the boiler as the heat source for producing 
Section 4 – Steam Electric Industry Description

4-7 

steam, and no air pollution control equipment. No fuel is combusted and no ash is generated in a 

nuclear-fueled steam electric process. Instead, heat transferred from the reactor core creates

steam in boiling water reactors or creates superheated water in pressurized-water reactors. The 

steam turbine/electric generator and condenser portions of the nuclear-fueled steam electric 

process are the same as those described for the stand-alone steam electric process [U.S. DOE, 

2012c].

4.2.2 Combined Cycle Systems

Some steam electric power plants operate one or more combined cycle systems fueled by 

fossil or fossil-type fuels to produce electricity. A combined cycle system comprises one or more 

combustion turbine electric generating units operating in conjunction with one or more steam 

turbine electric generating units. Combustion turbines, which typically are similar to jet engines, 

commonly use natural gas as the fuel, but may also use oil. Exhaust gases from combustion are 

sent directly through the combustion turbine, which is connected to a generator to produce 

electricity. The exhaust gases exiting the combustion turbine still contain useful waste heat, so 

they are directed to heat recovery steam generators (HRSGs) to generate steam to drive an 

additional turbine. The steam turbine is also connected to a generator (which may be a different 

generator or the same generator that is connected to a combustion turbine) that produces 

additional electricity. Thus, combined cycle systems use steam turbine technology to increase the 

efficiency of the combustion turbines. Figure 4-3 illustrates the combined cycle system process.

Steam electric units within combined cycle systems operate almost identically to standalone steam electric units, except without the boiler. In a combined cycle system, the combustion 

turbines and HRSGs functionally take the place of the boiler of a stand-alone steam electric unit. 

The other two major components of steam electric generating units within combined cycle 

systems, the steam turbine/electric generator and steam condenser, are virtually identical to those 

of stand-alone steam electric units. Thus, the wastewaters and pollutants generated from both 

types of systems are the same. However, the wastewaters of the combined cycle units are more 

closely associated with gas-fired steam electric units, and therefore do not typically generate ash 

or FGD wastewaters. The wastewaters generated from combined cycle units typically include 

cooling water, boiler blowdown, metal cleaning wastes, and steam condensate water treatment 

wastes.
4-8

Section 4 – Steam Electric Industry Description

Fly Ash 

Collection 

System

Coal 

Storage

Bottom Ash 

Handling System

Boiler Feedwater 

Treatment

Equipment 

Cleaning

Gas to 

Atmosphere

Flue Gas 

Desulfurization Wastes

Fly Ash Sluice 

(if wet handling system)

Condensate

Boiler 

Blowdown

Flue Gas

Steam 

Turbine

High Pressure Steam

Electric 

Generator

Condenser

Blowdown

Cooling Water

Once-through Discharge

-ORRecirculating System

Once-through Cooling Water

Make-up 

Water

Chemical 

Addition

Chemical 

Addition

Cooling 

Tower

Metal 

Cleaning 

Wastes

FGD Wet 

Scrubber

Fuel Boiler

(e.g., coal, oil, or gas)

Air

Coal Pile 

Runoff

Bottom Ash Sluice

(if wet handling system)

Waste

(Treatment Residuals)

Figure 4-2. Steam Electric Process Flow Diagram
4-9

Section 4 - Steam Electric Industry Description

Air Combustion 

Chamber

Electric 

Generator

Fuel (e.g., gas, oil, or 

gasified coal)

Electric 

Generator

Condenser

Heat Recovery 

Steam Generator 

(HRSG)

Gas 

Turbine Compressor

Steam 

Turbine

Gas 

Turbine 

Cycle

Steam 

Turbine 

Cycle

Boiler 

Blowdown

Boiler Feedwater 

Treatment

Waste

(Treatment Residuals)

Condensate

Steam

Hot Exhaust 

Gases

Exhaust Gases

Equipment 

Cleaning

Metal 

Cleaning 

Wastes

Blowdown

Cooling Water

Once-through Discharge

-OR-

 Recirculating System

Make-up 

Water Chemical 

Addition

Chemical 

Addition

Cooling 

Tower

Once-through Cooling Water

Figure 4-3. Combined Cycle Process Flow Diagram
Section 4 - Steam Electric Industry Description

4-10 

4.2.3 Integrated Gasification Combined Cycle Systems

Integrated gasification combined cycle (IGCC) systems combine gasification technology 

with both gas turbine and steam turbine power generation (i.e., combined cycle power 

generation). In an IGCC system, a gasifier converts carbon-based feedstock (e.g., coal or 

petroleum coke) into a synthetic gas (“syngas”). The syngas is cleaned of particulates, sulfur, and 

other contaminants and is then combusted in a high-efficiency combustion gas turbine/generator. 

An HRSG then extracts heat from the combustion turbine exhaust to produce steam and drive a 

steam turbine/generator. IGCC plants can achieve higher thermodynamic efficiencies, emit lower 

levels of criteria air pollutants, and consume less water per MW than traditional coal combustion 

power plants. Like typical combustion power plants, solid wastes and wastewater are generated 

from the gasification process. 

DOE’s National Energy Technology Laboratory (NETL) Gasification World Database

reports two commercial-scale IGCC systems located in the United States -- the 262-MW Wabash 

River IGCC Repowering Project (Wabash River) in Indiana and the 250-MW Tampa Electric 

Polk Power Station IGCC Project (Polk) in Florida. Other U.S. power companies are 

investigating or planning IGCC systems at new or existing plants, such as Duke Energy’s

Edwardsport Station in Knox County, Indiana, which has an IGCC unit under construction that 

was expected to begin commercial operation sometime in 2012 [Duke Energy, 2012].

EPA has conducted site visits at each of the three plants identified above. Figure 4-4

presents a general process flow diagram for an IGCC system. The specific gas preparation and 

by-product recovery operations at the plants may vary, but each uses the same general electric 

generating process. For example, Polk operates a sulfuric acid plant to recover sulfur, while 

Wabash River uses the Claus process to generate an elemental sulfur product [ERG, 2009c; 

ERG, 2011]. 
4-11

Section 4 - Steam Electric Industry Description

Slurry 

Preparation

Air Separation 

Unit

Slag Handling

Gasification Particulate 

Removal Gas Cleaning

Sulfur 

Recovery 

Process

Acid Gas 

Removal

Sour 

Water Product Syngas

Sweet 

Syngas

Cool 

Sour 

Syngas

Acid Gas

Coal/ 

Petroleum Coke

Air

Slurry

Slag Product

Oxygen

Nitrogen Slag 

Slurry

Quench 

Water

Sulfur 

Product

Steam

Fly Ash 

and 

Water

Air Combustion 

Chamber

Electric 

Generator

Heat Recovery Steam 

Generator (HRSG)

Compressor Turbine

Boiler

Exhaust Gases

Steam 

Turbine

Electric 

Generator

Condenser

Cooling

Coal/ Water

Petroleum 

Coke Storage

Equipment 

Cleaning

Metal 

Cleaning 

Waste

Coal/ 

Petroleum 

Coke Pile 

Runoff

Figure 4-4. IGCC Process Flow Diagram 
Section 4 - Steam Electric Industry Description

4-12 

4.2.4 Demographics of the Steam Electric Power Generating Industry

In 2010, EPA’s Office of Water administered the Steam Electric Information Collection 

Request (ICR) (Steam Electric Survey) to power plants believed to be subject to the Steam 

Electric Power Generating ELGs. As described in Section 3.3, EPA distributed the survey to all 

coal- and petroleum-coke fired plants identified in the 2007 EIA and a statistically sampled 

subset of steam electric power plants burning other types of fuel, including oil-fired, gas-fired, 

and nuclear power plants. EPA obtained information on specific aspects of power plant operation 

for the 2009 calendar year.15 The survey also requested information about planned steam electric 

generating units, treatment systems, and other improvements or modifications through the year 

2020. EPA uses data from the Steam Electric Survey throughout this report to describe the 

current state of the steam electric industry and to make predictions on the general direction of the 

industry in the near future. This section presents demographic data and other information to 

characterize the steam electric industry based on data obtained through the 2009 EIA and EPA’s 

Steam Electric Survey. 

Table 4-2 presents the distribution of the types of steam electric prime movers used by 

plants subject to the Steam Electric Power Generating ELGs using both the 2009 EIA data and 

EPA’s Steam Electric Survey. The table includes the numbers of plants, electric generating units, 

and capacity for each type of steam electric prime mover. The number of electric generating 

units represents the number of generators/turbines used to generate electricity and does not 

necessarily relate to the number of boilers. The number of plants, units, and capacity in the steam 

electric industry generated from the Steam Electric Survey are based on values reported in the 

survey, which were scaled up to represent the industry as a whole using the industry-weighting 

factors discussed in Section 3.3. 

As shown in Table 4-2, the Steam Electric Survey estimates are lower than the 2009 EIA 

data estimates. Based on EIA data, the industry had 1,179 plants operating at least one steam 

electric generating unit powered by a fossil or nuclear fuel in 2009. The weighted survey data 

indicate that the industry had 1,079 plants operating at least one steam electric generating unit in 

2009.16 As described in Section 3.3, the survey captured data from plants identified using 2007 

EIA data but responses reflect data for the 2009 production year. The steam electric industry is 

dynamic; the discrepancies between survey data and the 2009 EIA could be due to new 

installations, unit fuel conversions, plant/unit retirements. In addition, the Steam Electric Power 

Generating ELGs are not applicable to all units generating electricity. Units that do not burn 

fossil fuels or plants with a primary purpose other than generating electricity do not fall under the 

applicability of the Steam Electric ELGs. Therefore, EPA used the weighted survey results for 

the remainder of the analyses in this document to represent the steam electric industry in 2009. 

 

15 EPA is using January 1, 2014 as the baseline for the proposed ELG because 2014 is the year that EPA expects to 

promulgate the final rule. The data presented in this section represent 2009 conditions, unless otherwise noted, 

because the data are based on responses collected from the Steam Electric Survey.

16 The weighted survey initially indicated that there were 1,088 power plants operating at least one steam electric 

generating unit powered by a fossil or nuclear fuel. However, upon further inspection, the data indicated that only 

1,079 of these plants operated at least one steam electric generating unit in 2009. 
Section 4 - Steam Electric Industry Description

4-13 

Based on the Steam Electric Survey data, the majority (66 percent) of the steam electric 

power produced by the plants subject to the ELGs is generated using stand-alone steam turbines, 

which are also the most prevalent type of steam electric prime mover used. Table 4-3 presents 

the distribution of fossil and nuclear fuels used to power each type of steam electric prime 

mover. The number of electric generating units represents the number of generators/turbines 

used to generate electricity and is not equal to the number of boilers. The vast majority (93 

percent) of these generating units burn at least some amount of either coal or gas. Coal is the 

most common primary fuel type for stand-alone steam turbines, while gas is the primary fuel for 

nearly all combined cycle systems. Oil-fired units are not very prevalent in the industry, 

accounting for roughly only 3 to 4 percent of the total number of generating units and capacity. 

Table 4-4 presents the steam electric capacity, as well as the number of steam electric 

power plants distributed by overall plant capacity.17 Table 4-4 includes the stand-alone steam 

turbines and all the combined cycle system turbines (i.e., combined cycle steam turbine, 

combined cycle single shaft, and combined cycle combustion turbine) in the number of steam 

electric power plants and steam electric capacity. According to the weighted Steam Electric 

Survey data, the largest capacity plants (>500 MW) comprise over 60 percent of all steam 

electric power plants and 90 percent of the steam electric generating capacity for all plants 

regulated by the ELGs. Based on the weighted Steam Electric Survey data, most steam electric 

power plants are either gas- or coal-fired and have a generating capacity greater than 500 MW.

Table 4-5 presents the steam electric industry broken out by size of the generating units. 

Table 4-5 includes the stand-alone steam turbines and the all the combined cycle steam turbines. 

To determine the size of the combined cycle generating units, EPA added the capacity for all 

combined cycle turbines (i.e., combined cycle steam turbine, combined cycle single shaft, and 

combined cycle combustion turbine) for each turbine identified for the specific generating unit. 

There are 281 generating units with a capacity of 50 MW or less (13 percent of all steam electric 

generating units); however, only 71 coal- or petroleum coke-fired generating units have a 

capacity of 50 MW or less (3.2 percent of all coal- or petroleum coke-fired generating units). The 

281 generating units account for only 1.1 percent of the total capacity associated with the steam 

electric industry.

Stand-alone steam turbines are more prevalent than combined cycle units within the 

steam electric industry. These stand-alone steam turbines are generally larger units, with 70 

percent having a capacity of 500 MW or greater. In most cases, stand-alone steam turbines will 

burn coal- or petroleum-coke as either a primary or a secondary fuel. Of the total steam electric 

capacity, stand-alone steam turbines burning coal or petroleum coke account for 70 percent. 

 

17 The overall plant capacity includes all electric power generated by the plant, including electricity produced using 

non-steam generators and through the use of non-fossil/non-nuclear energy sources.
4-14

Section 4 - Steam Electric Industry Description

Table 4-2. Distribution of Prime Mover Types for Plants Regulated by the Steam Electric Power Generating Effluent 

Guidelines

Steam Electric Prime Movers

2009 EIA Steam Electric Survey

Number of 

Plants a

Number of 

Electric 

Generating Units

Total Steam or 

Combined Cycle 

Turbine Capacity

(MW)

Number of 

Plants a

Number of 

Electric 

Generating Units

Total Steam or 

Combined Cycle 

Turbine Capacity

(MW)

Stand-Alone Steam Turbine 787

(67%)

1,868

(76%)

555,000

(71%)

716

(66%)

1,640b

(74%)

528,000

(71%)

Combined Cycle Systems c 438

(37%)

599

(24%)

224,000

(29%)

408

(38%)

573

(26%)

213,000

(29%)

Combined Cycle Steam Turbine d 416 550 81,100 408 573 87,700g

Combined Cycle Single Shaft (steam 

and combustion turbines shaft as single 

shaft) e

22 49 9,570 - - -

Combined Cycle Combustion Turbine 411 1,013 134,000 404 570 125,000g

Total 1,179

(100%)

2,467f

(100%)

780,000

(100%)

1,079

(100%)

2,214f

(100%)

741,000

(100%)

Source: Steam Electric Survey, [ERG, 2013]; 2009 EIA, [U.S. DOE, 2009]. 

Note: Capacity values are rounded to three significant figures.

Note: The number of plants, units, and capacity in the steam electric industry generated from the Steam Electric Survey are based on values reported in the 

survey, which were scaled up to represent the industry as a whole using the industry-weighting factors discussed in Section 3.3.

a – Because a single plant may operate multiple electric generating units of various prime mover types, the number of plants by prime mover type is not additive.

There are 1,179 plants (according to the 2009 EIA) or 1,079 plants (according to the steam electric survey) in the industry that operate at least one steam electric 

generating unit powered by either fossil or nuclear fuel.

b - One generating unit operating a stand-alone steam turbine was reported as burning only wood. This unit is not included in the count of generating units 

because it does not meet the applicability of the steam electric ELGs. 

c – Due to the nature of the EIA data, EPA was able to identify the number of combined cycle turbines (i.e., prime movers), but could not discern the number of 

actual combined cycle systems. EPA estimated the number of combined cycle systems reported in EIA by adding the number of combined cycle steam turbines 

and the number of single shaft turbines. Typically, there are multiple combustion turbines to a single steam turbine in a combined cycle system; therefore, EPA 

believes this methodology better represents the number of combined cycle systems than simply adding the number of combined cycle combustion and steam 

turbines. For the Steam Electric Survey data, the plants reported the combined-cycle-system-level information directly. 
4-15

Section 4 - Steam Electric Industry Description

d – One plant in the 2009 EIA database reported using a fossil fuel for its combined cycle steam turbine and a non-fossil/non-nuclear fuel for its three combined 

cycle combustion turbines. EPA included the combined cycle steam turbine from this plant in the table, but did not include the combined cycle combustion 

turbines using fuels not covered by the ELGs. 

e – EIA data differentiate among types of combined cycle turbines, with a separate designation for single shaft turbines (steam and combustion turbines sharing a 

single shaft). EPA's Steam Electric Survey does not differentiate between types of combined cycle systems; single shaft turbines are included as combined cycle 

systems in the survey. 

f – EPA estimated the total number of electric generating units as the sum of the stand-alone steam turbines and the estimated number of combined cycle 

systems. EPA did not sum the total number of turbines.

g – From the survey data, EPA was not able to categorize the combined cycle systems as a combined cycle steam turbine, a combined cycle single shaft, or a 

combined cycle combustion turbine. Seven plants (17 units) identified operating a combined cycle system but provided only the steam turbine capacity. The 2009 

EIA data identifies these units as single-shaft turbines. The total capacity of these units, steam turbine and combustion turbine capacity, is accounted for under 

combined cycle steam turbines.
4-16

Section 4 - Steam Electric Industry Description

Table 4-3. Distribution of Fuel Types Used by Steam Electric Generating Units 

Fossil or Nuclear Fuel a 

Stand-Alone Steam Turbines Combined Cycle Steam Turbines b

Number of 

Plants

Number of Electric 

Generating Units

Total Turbine 

Capacity (MW)

Number of 

Plants

Number of Electric 

Generating Units

Total Turbine 

Capacity (MW)

Coal: 455-465 1,080-1,090 328,000-330,000 2 2 427

Anthracite Coal 1 1 128 0 0 0

Bituminous Coal 209 497 144,000 1 1 101

Subbituminous Coal 145 310 109,000 0 0 0

Lignite Coal 10-15 10-20 7,000-8,000 0 0 0

Coal Synfuel 0 0 0 0 0 0

Waste/Other Coal 17 18 1,660 0 0 0

Blend c 106 240 66,700 1 1 326

Petroleum Coke 8 11 751 1 1 334

Oil: 55-65 70-85 22,500-23,500 5-10 5-15 1,400-1,900

No. 1 Fuel Oil 0 0 0 0 0 0

No. 2 Fuel Oil 1-5 1-5 200-300 0 0 0

No. 4 Fuel Oil 1 1 210 0 0 0

No. 5 Fuel Oil 0 0 0 0 0 0

No. 6 Fuel Oil 15-20 20-30 12,500-13,500 0 0 0

Diesel Fuel 3 3 1,480 4 7 438

Jet Fuel 0 0 0 0 0 0

Kerosene 0 0 0 1-5 1-5 1,000-1,500

Waste Oil/Other Oil 0 0 0 0 0 0

Blend c 32 46 8,430 0 0 0

Gas: 171 367 71,500 400 562 210,000

Natural Gas 171 367 71,500 395 556 210,000

Blast Furnace Gas 0 0 0 0 0 0

Gaseous Propane 0 0 0 0 0 0

Other Gases 0 0 0 0 0 0

Blend c 0 0 0 5 5 537
4-17

Section 4 - Steam Electric Industry Description

Table 4-3. Distribution of Fuel Types Used by Steam Electric Generating Units 

Fossil or Nuclear Fuel a 

Stand-Alone Steam Turbines Combined Cycle Steam Turbines b

Number of 

Plants

Number of Electric 

Generating Units

Total Turbine 

Capacity (MW)

Number of 

Plants

Number of Electric 

Generating Units

Total Turbine 

Capacity (MW)

Nuclear 66 99 104,000 0 0 0

Total 716 d 1,640 528,000 408 d 573 213,000

Source: Steam Electric Survey [ERG, 2013]. 

Note: Certain cells contain ranges of values to protect the release of information claimed confidential business information (CBI).

Note: Capacity values are rounded to three significant figures.

Note: The number of plants, units, and capacity in the steam electric industry generated from the Steam Electric Survey are based on values reported in the 

survey, which were scaled up to represent the industry as a whole using the industry-weighting factors discussed in Section 3.3.

a – Units were first classified by fuel group based on the following hierarchy: coal, oil, gas, and nuclear. For example, if a unit burns both coal and gas then it was

categorized as coal, even if coal was reported as generating less electricity compared to other fuel groups. Units were then categorized by the type of fuel burned. 

b – The Steam Electric Survey identifies combined cycle systems, which include at least one steam turbine and one combustion turbine.

c – The 'blend' category identifies units that burn more than one type of fuel within the fuel group. For example, for a generating unit that burns coal, a blend coal 

unit burns at least two different types of coal.

d – Because a single plant may operate multiple electric generating units burning various types of fuel, the number of plants by fuel type is not additive. There 

are 716 plants responding to the survey that operate at least one stand-alone steam turbine powered by either fossil or nuclear fuel. There are 408 plants 

responding to the survey that operate at least one combined-cycle system powered by either fossil or nuclear fuel.
Section 4 - Steam Electric Industry Description

4-18 

Table 4-4. Distribution by Size of Steam Electric Capacity and Plants Regulated by 

the Steam Electric Power Generating Effluent Guidelines

Overall Plant Capacity Rangea

Total

0-100

MW

100-200 

MW

200-300 

MW

300-400 

MW

400-500 

MW >500 MW

Total Steam Electric Capacity 

(MW) b 5,040 9,410 11,300 17,600 17,100 680,000 741,000

Percentage of Capacity 0.7% 1.3% 1.5% 2.4% 2.3% 91.8% 100%

Number of Plants 103 88 72 79 61 676 1,079

Percentage of Plants 9.6% 8.2% 6.6% 7.3% 5.7% 62.7% 100%

Source: Steam Electric Survey, [ERG, 2013]. 

Note: Capacity values are rounded to three significant figures.

Note: The number of plants and total steam electric capacity includes the stand-alone turbines and the combined 

cycle systems.

Note: The number of plants and capacity in the steam electric industry are based on values reported in the survey, 

which were scaled to represent the industry as a whole using the industry-weighting factors discussed in Section 3.3.

a – Overall plant steam electric capacity includes electricity produced by only steam electric generating units.

Electricity generated by non-steam-electric electric units and those using non-fossil/non-nuclear energy sources is 

not included.

b – The capacity presented within each size distribution is based on the overall plant steam electric capacity.

Table 4-5. Distribution by Size of Steam Electric Generating Units Regulated by 

the Steam Electric Power Generating Effluent Guidelines

Unit Capacity Range

Total

0-50

MW

50-100 

MW

100-200 

MW

200-300 

MW

300-400 

MW

400-500 

MW

>500 

MW

Total Steam Electric 

Capacity (MW) a 8,010 23,200 65,700 62,200 72,200 55,700 454,000 741,000

Percentage of Capacity 1.1% 3.1% 8.9% 8.4% 9.7% 7.5% 61.3% 100%

Number of Steam Electric 

Generating Units 281 305 445 247 207 124 605 2,214

Percentage of Steam 

Electric Generating Units 12.7% 13.8% 20.1% 11.2% 9.3% 5.6% 27.3% 100%

Source: Steam Electric Survey, [ERG, 2013]. 

Note: Capacity values are rounded to three significant figures.

Note: The number of plants, number of steam electric generating units, and total steam electric capacity include the 

stand-alone turbines and the combined cycle systems.

Note: The number of units and capacity in the steam electric industry are based on values reported in the survey, 

which were scaled to represent the industry as a whole using the industry-weighting factors discussed in Section 3.3. 

a – The capacity presented within each size distribution is based on the capacity at the unit level.
 

 

 

 

 

 

 

 

 

 

 

 

 

Section 4 - Steam Electric Industry Description 

4.3	 STEAM ELECTRIC WASTESTREAMS EVALUATED FOR NEW OR ADDITIONAL CONTROLS 

IN THE PROPOSED ELGS 

This section describes the wastestreams generated by steam electric power plants for 

which EPA evaluated new or revised discharge requirements for the proposed ELGs. Section 4.4 

discusses other wastestreams generated by the steam electric industry that EPA did not evaluate 

for new or revised discharge requirements in the proposed ELGs. 

4.3.1 Fly Ash Transport Water 

Depending on the boiler design, as much as 70 to 80 percent of the ash from a pulverized 

coal furnace consists of fly ash. Certain boiler designs, such as cyclone boilers, produce 

relatively small amounts of fly ash, approximately 20 to 30 percent. Many plants transport fly 

ash from the boiler using water as the motive force, known as sluicing. This section presents an 

overview of fly ash transport water generated by the steam electric industry. 

As discussed in Section 4.2.1, flue gas contains entrained fly ash as it leaves the boiler. 

Steam electric units employ three main particulate collection methods to remove fly ash from the 

flue gas: electrostatic precipitators (ESPs), baghouses, and venturi-type wet scrubbers. Of the 

approximately 1,100 coal-, petroleum coke-, and oil-fired units collecting fly ash, 97 percent 

utilize one of these three collection methods. The remaining 3 percent identified some other type 

of particulate collection system. Table 4-6 presents the number of coal- , petroleum coke-, and 

oil-fired units utilizing each of these collection methods and each is described below. 

Table 4-6. Fly Ash Collection Practices in the Steam Electric Industry 

Fly Ash Collection Method 

Number of 

Plants 

Number of Coal- and Petroleum 

Coke-Fired Steam Electric Units 

Number of Oil-Fired 

Steam Electric Units 

ESP 335 816 5-10 

Baghouse 143 220 0 

Baghouse and ESP 5-15 10-15 2 

Wet Scrubber 5-15 15-25 0 

Other 20 12 9 

Total 508-528a 1,080-1,100a 26-31 

Source: Steam Electric Survey, [ERG, 2013]. 

Note: Certain fields contain ranges of values to protect the release of information claimed CBI. 

Note: The number of plants, units, and capacity in the steam electric industry are based on values reported in the 

survey, which were scaled to represent the industry as a whole using the industry-weighting factors discussed in 

Section 3.3. 

a – 15 coal-fired generating units at 9 plants identified no fly ash collection method. These plant and unit values are 

included in the count of total plants and units collecting fly ash. 

To remove the fly ash particles from the flue gas, many plants operate electrostatic 

precipitators (ESPs). ESPs use high voltage to generate an electrical charge on the particles 

contained in the flue gas. The charged particles then collect on a metal plate with an opposite 

electric charge. Additionally, some plants may use agglomerating agents, such as ammonia, 

4-19
 
Section 4 - Steam Electric Industry Description

which help small charged ash particles form larger agglomerates that are more readily attracted 

to the charged plates, improving the removal efficiency of the ESPs. As the particles begin to 

layer on the metal plates, the plates are tapped/rapped to loosen the particles, which fall into 

collection hoppers. ESPs can remove 99.9 percent of fly ash from the flue gas [Babcock & 

Wilcox, 2005]. These types of systems are the most common type of fly ash collection system 

used in the steam electric industry. Of the approximately 1,100 coal-, petroleum coke-, and oilfired units in the industry collecting fly ash in the steam electric survey, about 830 units (75 

percent) utilize an ESP system [ERG, 2013].18

Plants may also use other particulate control technologies, such as baghouse filters. A 

baghouse system contains several compartments, each containing fabric filter bags that are 

suspended vertically in the compartment. The bags can be quite long (e.g., 40 feet) and small in 

diameter [Babcock & Wilcox, 2005]. The reverse air system is the baghouse configuration most 

commonly used by steam electric power plants. In this system, the flue gas enters into the 

various compartments and is forced to flow into the bottom of the fabric filter bags. The flue gas 

passes through the fabric filter, but the fly ash particulates cannot pass and are captured on the 

inside walls of the baghouse. As the baghouses collect more particulates, the layer of particulates 

becomes thicker and help to remove more particulates from the flue gas. After a specified period 

of time or once the pressure drop in the baghouse reaches a high set point, the plants reverse the 

flow in the compartments and send clean flue gas from the outside of the fabric filter bags to the 

inside, which dislodges the particulates. The particulates are captured in hoppers at the bottom of 

the compartment [Babcock & Wilcox, 2005]. Of the approximately 1,100 coal-, petroleum coke-, 

and oil-fired generating units that reported collecting fly ash from flue gas, about 235 units use 

baghouse filters (22 percent) [ERG, 2013].19

After the ESP or baghouse deposits the fly ash into the hoppers, the plant can either 

handle the fly ash in a dry or wet fashion. In either system, dry fly ash is initially drawn away 

from the hoppers using a vacuum to pneumatically transport the ash. Plants operating a dry fly 

ash handling system pneumatically transfer the fly ash from the hopper to a fly ash storage silo 

and then dispose of the ash. Plants operating a wet fly ash handling system use water as the 

motive force to transport the fly ash from the hopper to a surface impoundment. Section 7.2 

discusses the different ash handling methods used in the steam electric industry in more detail.

Additionally, between fifteen and twenty-five generating units use venturi-type wet 

scrubbers to remove fly ash from the flue gas [ERG, 2013]. Venturi scrubbers contain a tube 

with flared ends and a constricted middle section. The flue gas enters from one of the flared ends 

and approaches the constricted section. A liquid slurry stream is added to the scrubber just prior 

to or at the constricted section. As the flue gas enters the constricted section, its pressure and 

velocity increases, which causes the gas and liquid slurry to mix. The greater the pressure drop in 

the scrubber, the better the mixing, and the better the reaction rate, which increases the 

particulate removal efficiency. However, venturi scrubbers must be operated at high pressure 

drops to remove the same level of particulates as ESPs, making their operation costs higher than 

 

18 This includes 10 to 15 generating units that use a combination system that incorporates an ESP and baghouse 

filters to remove particulates from the flue gas.

19 This includes 10 to 15 generating units that use a combination system that incorporates an ESP and baghouse 

filters to remove particulates from the flue gas.

4-20 
Section 4 - Steam Electric Industry Description

ESPs [Babcock & Wilcox, 2005; U.S. EPA, 2010]. Based on the proposed revisions to the 

specialized definitions, described in Section 2.2, EPA does not consider the ash collected by 

venture scrubbers as fly ash, and therefore, the water generated by these systems is not 

considered fly ash transport water. 

Table 4-7 presents the fly ash handling practices used by plants operating coal-, 

petroleum coke-, and oil-fired generating units. Approximately one-fourth of the plants operating 

coal-fired generating units handle at least a portion of their fly ash with a wet sluicing system. A 

small percentage of oil-fired units, approximately 20 percent, also wet sluice fly ash. In most 

cases, plants manually remove the fly ash from these oil-fired units by methods such as scraping 

the ash out of the boiler. In general, oil-fired units produce much less fly ash than coal-fired 

units. For example, oil-fired units responding to the survey produced an average of just over 60 

tons of fly ash per year per unit, compared to over 60,000 tons per year for an average coal-fired 

unit. 

Table 4-7. Fly Ash Handling Practices in the Steam Electric Industry

Fly Ash Handling

Number of

Plants

Coal- and Petroleum CokeFired Steam Electric UnitsOil-Fired Steam 

Electric Units

Number of

Units

Capacity

(MW)

Number of

Units

Capacity

(MW)

Wet-Sluiced 57

(11%) 205 47,000(14%) 10-15 7,500-10,000(33%)

Handled Dry or Removed in 

Scrubber a

344

(67%) 713 222,000(67%) 10-15 2,500-5,000(17%)

Handled Either Wet or Dry b 81

(16%) 168 59,000(18%) 1-5 500-1,500(3%)

No Handling System Reported 31

(6%) 10 2,370(1%) 61 11,400(44%)

Total 514 1,096 330,000 80-95 21,900-27,900

Source: Steam Electric Survey, [ERG, 2013]. 

Note: Certain fields contain ranges of values to protect the release of information claimed CBI.

Note: Capacity values are rounded to three significant figures.

Note: The number of plants, units, and capacity in the steam electric industry are based on values reported in the 

survey, which were scaled to represent the industry as a whole using the industry-weighting factors discussed in 

Section 3.3. 

a – EPA considered all transport methods other than wet sluicing as dry fly ash transport.

b –These units have both wet and dry handling systems for removing fly ash from the boiler and can operate either 

system as needed.

Most plants operating wet fly ash handling systems are located east of the Mississippi 

River. Figure 4-5 provides a distribution of the three categories of fly ash handling practices 

presented in Table 4-7. Each symbol represents the plant-level fly ash handling system. The 

figure only includes the plants for which responses were provided in the Steam Electric Survey 

(i.e., the figure does not represent the weighted numbers). Plants categorized as ‘wet and dry 

handling’ operate some units at the plant with wet fly ash handling systems and other units at the 

4-21 
Section 4 - Steam Electric Industry Description

4-22 

plant with dry fly ash handling systems, or in some instances operate both a wet and a dry fly ash 

handling system for an individual generating unit. 

Source: Steam Electric Survey, [ERG, 2013].

Figure 4-5. Plant-Level Fly Ash Handling Systems 

In 1982, EPA promulgated new source performance standards (NSPS) that prohibited

new sources from discharging wastewater pollutants in fly ash transport water. Not surprisingly, 

EPA has found that the steam electric units generating wet fly ash transport water tend to be 

older units (e.g., more than 30 years old), while most units built since the NSPS were 

promulgated are outfitted with dry fly ash handling systems. 

EPA identified several plants that have installed dry fly ash handling systems, either to 

replace the preexisting wet handling system or to operate as a parallel system. Table 4-8 presents 

the number of units converted from wet fly ash handling to dry fly ash handling since 2000. Each 

plant and unit is classified by the type of dry system installed, which include wet vacuum 

pneumatic systems, dry vacuum systems, pressure systems, and combined vacuum and pressure 

systems. Each of these dry fly ash handling systems is described in Section 7. Data from the 

Steam Electric Survey show that power companies converted at least 115 units at over 45 plants 

to dry fly ash handling systems since 2000. Power companies also reported that they are planning 
Section 4 - Steam Electric Industry Description

4-23 

to convert an additional 61 units to dry handling systems by the year 2020. The reasons cited for 

installing the dry handling systems include environmental remediation (i.e., discharges from the 

fly ash impoundments caused environmental impacts), economic opportunity (e.g., revenues 

from sale of fly ash), and the need to replace ash impoundments approaching full storage 

capacity. Because dry fly ash handling practices do not generate fly ash transport water, 

converting to a dry system eliminates the discharge of fly ash transport water and the pollutants 

contained therein. In addition, it reduces the amount of intake water the plant uses and eliminates 

the need for an impoundment to store the fly ash transport water. Section 6.2 presents additional 

information on the amount of fly ash transport water generated and discharged by the steam 

electric industry and the pollutant characteristics of the transport water.

Table 4-8. Conversions of Wet Fly Ash Sluicing Systems Since 2000

Type of Dry Fly Ash Handling

System Installed Number of Plants Number of Units

Capacity

(MW)

Wet Vacuum System (pneumatic) a 1-5 1-5 2,000-3,000

Dry Vacuum System b 24 50 9,400

Pressure System c 5-10 15-25 7,500-10,000

Combined Vacuum/Pressure System d 18 36 15,800

Total e 45 – 55 (35 – 42%) 85 – 115 (26 – 35%) 34,700 – 38,200 (38-42%)

Source: Steam Electric Survey, [ERG, 2013]. 

Note: Certain fields contain ranges of values to protect the release of information claimed CBI.

Note: Capacity values are rounded to three significant figures.

Note: The number of plants, units, and capacity in the steam electric industry are based on values reported in the 

survey, which were scaled to represent the industry as a whole using the industry-weighting factors discussed in 

Section 3.3.

Note: Approximately 33 of these units also wet sluiced a portion of the fly ash in 2009.

a – One of these units also wet sluiced a portion of the fly ash in 2009.

b – Twelve of these units also wet sluiced a portion of the fly ash in 2009.

c – Four of these units also wet sluiced a portion of the fly ash in 2009.

d – Sixteen of these units also wet sluiced a portion of the fly ash in 2009. 

e – The percentages are based on the number of systems conducting any wet sluicing operations (wet sluicing 

systems and wet and dry systems) in 2000 prior to any conversions (excluding units that have retired since that 

time).

4.3.2 Bottom Ash Transport Water 

As much as 70 to 80 percent of the ash from a pulverized coal furnace consists of fly ash. 

The remaining 20 to 30 percent is bottom ash. Cyclone boilers, and other boiler designs, can 

produce a larger percentage of bottom ash, upwards of 70 to 80 percent. Like fly ash, bottom ash 

can be transported from the boiler using water. This section presents an overview of bottom ash 

transport water generated by the steam electric industry.

Heavy bottom ash particles collect in the bottom of the boiler. The sloped walls and 

opening at the bottom of the boiler allow the bottom ash to feed by gravity to the bottom ash 
Section 4 - Steam Electric Industry Description

4-24 

hoppers positioned below the boiler. The bottom ash hoppers are connected directly to the boiler 

bottom to prevent any boiler gases from leaving the boiler. Depending on the size of the boiler, 

there may be more than one bottom ash hopper running along the opening of the bottom of the 

boiler. Most bottom ash hoppers are filled with water to quench the hot bottom ash as it enters 

the hopper. Once the bottom ash hoppers have filled with bottom ash, a gate at the bottom of the 

hopper opens and the ash is directed to grinders to grind the bottom ash into smaller pieces. From 

the hopper, bottom ash can be handled in a wet or dry fashion. 

Plants operating a wet bottom ash handling system sluice the ground ash with water to an 

impoundment or a dewatering bin. Because bottom ash particles are heavier than fly ash 

particles, they more easily separate from the sluice water. Some plants operate large surface

impoundments for bottom ash, while others use a system of relatively small impoundments 

operating in series and/or parallel. Other plants operate dewatering bin systems, in which they 

use a tank-based settling operation to separate the bottom ash solids from the transport water. A 

dewatering bin system generally consists of at least two bins; while one bin is receiving bottom 

ash, the other bin is decanting the water from the collected bottom ash material. Excess water in 

the bin flows over a weir, leaving the dewatering bin. Plants can reuse this overflow water 

directly as bottom ash transport water, send it to an ash impoundment for additional settling, or 

discharge it directly to surface water.

Most coal and petroleum coke plants operate wet bottom ash handling systems, as 

described above; however, a substantial number of plants operate a completely dry bottom ash 

handling system or a system that does not generate ash transport water (e.g., mechanical drag 

system). As seen in Table 4-9, 112 plants handle at least a portion of their bottom ash dry.20

These 112 plants represent 22 percent of plants operating a coal-, petroleum coke-, or oil-fired 

generating unit. Approximately 20 percent of all coal- and petroleum coke-fired generating units 

use dry bottom ash handling systems. The most common type of dry ash handling system used in 

the steam electric industry is the mechanical drag chain system. The plant uses a drag chain to

remove the bottom ash out of the boiler. The bottom ash is dewatered as the drag chain pulls the 

bottom ash up an incline, draining the water back to the boiler. The plant then conveys the 

bottom ash to a nearby collection area from which it is loaded onto trucks and either sold for 

beneficial use or stored on site in a landfill. Section 7.3 provides more detail on dry and closedloop recycle bottom ash handling systems.

 

20For the purpose of this report, dry bottom ash handling systems includes all systems that do not generate bottom 

ash transport water, which includes completely dry bottom ash handling systems, mechanical drag systems, and 

other mechanical removal systems (e.g., scraping of bottom ash from boiler). Complete recycle and remote 

mechanical drag systems are considered wet sluicing systems. 
Section 4 - Steam Electric Industry Description

4-25 

Table 4-9. Bottom Ash Handling Practices in the Steam Electric Industry

Bottom Ash Handling

Number of 

Plants

Coal- and Petroleum Coke-Fired 

Steam Electric Units

Oil-Fired Steam Electric Units

Number of 

Units

Capacity

(MW)

Number of 

Units

Capacity

(MW)

Wet-Sluiced 335 (65%) 863 286,000 (87%) 0-5 0-250 (1%)

Handled Dry a 

101 (20%) 214 39,900 (12%) 30-35 10,000-15,000 (51%) 

Handled Either Wet or Dry 11 (2%) 6 2,610 (1%) 0 0

No Handling System 

Reported 69 (13%) 12 1,400 (<1%) 57 11, 500 (48%)

Total 516 1,096 330,000 80 – 95 21,900 – 27,900b

Source: Steam Electric Survey, [ERG, 2013].

Note: Certain fields contain ranges of values to protect the release of information claimed CBI.

Note: Capacity values are rounded to three significant figures.

Note: The number of plants, units, and capacity in the steam electric industry are based on values reported in the 

survey, which were scaled to represent the industry as a whole using the industry-weighting factors discussed in 

Section 3.3.

a – Dry bottom ash handling systems include all systems that do not generate bottom ash transport water, which 

includes completely dry bottom ash handling systems, mechanical drag systems, and other mechanical removal 

systems (e.g., scraping of bottom of boiler). 

b – Total capacity does not include the capacity of three oil units that did not report generating bottom ash.

Table 4-9 shows that 67 percent of plants (79 percent of coal- and petroleum coke-fired 

generating units) wet sluice all or part of the bottom ash produced. Figure 4-6 shows all plants 

producing bottom ash in 2009 in the United States with the type of bottom ash handling system 

identified by different colored symbols. The figure only includes the plants for which responses 

were provided in the Steam Electric Survey (i.e., the figure does not represent the weighted 

numbers) 
Section 4 - Steam Electric Industry Description

4-26 

Source: Steam Electric Survey,[ERG, 2013].

Figure 4-6. Plant-Level Bottom Ash Handling Systems

Table 4-10 presents the number of plants within the industry that converted wet sluicing 

bottom ash operations since 2000. The units and plants are classified by type of dry system 

installed. Steam electric plants use mechanical drag systems, dry vacuum systems, dry pressure 

systems, or a handful of other dry handling methods. Each of these handling technologies is 

discussed further in Section 7. These units represent approximately three percent of the total 

number of steam electric units that were wet sluicing bottom ash in 2000. Power companies 

reported plans to convert an additional 67 units to dry or closed-loop recycle bottom ash 

handling systems by the year 2020. 

Bottom ash transport water is typically directed to an on-site ash impoundment for 

treatment, as described earlier in this section. Steam electric units generate this water 

intermittently; the frequency depends upon hopper size and the operation of the boiler. Section 

6.2 discusses in more detail the amount of bottom ash transport water generated and discharged 

by the steam electric industry and the pollutant characteristics of the transport water.
Section 4 - Steam Electric Industry Description

4-27 

Table 4-10. Conversions of Bottom Ash Sluicing Systems Since 2000 

Type of Dry Bottom Ash 

Handling System Installed Number of Plants Number of Units

Capacity

(MW)

Mechanical Drag System 10-15 15-20 6,500-7,500

Dry Vacuum System 1-5 5-10 250-500

Dry Pressure System 0 0 0

Other 1-5 1-5 100-300

Total a 12 – 25 (3 – 7%) 21 – 35 (2 – 4%) 6,850 – 8,300 (3%)

Source: Steam Electric Survey, [ERG, 2013]. 

Note: Certain fields contain ranges of values to protect the release of information claimed CBI.

Note: Capacity values are rounded to three significant figures.

Note: The number of plants, units, and capacity in the steam electric industry generated from the Steam Electric 

Survey are based on values reported in the survey, which were scaled to represent the industry as a whole using the 

industry-weighting factors discussed in Section 3.3

a – The percentages are based on the number of systems conducting any wet sluicing operations (wet sluicing 

systems and wet and dry systems) in 2000 (excluding units that have retired since that time).

4.3.3 Flue Gas Desulfurization Wastewater

To meet air quality requirements, many power plants that burn coal use a variety of FGD 

scrubber systems to control SO2 emissions from flue gas generated in the plant’s boiler. These 

systems are classified as “wet” or “dry.” For the purposes of this rulemaking, “wet” FGD 

systems are those that use a sorbent slurry and that generate a water stream that exits the FGD 

scrubber absorber. Figure 4-7 presents a simplified diagram of typical wet and dry FGD systems.
Section 4 - Steam Electric Industry Description

4-28 

Dry FGD 

Scrubber

Reagent Slurry

Flue Gas

Gas to Particulate 

Collector and Stack

Wet FGD 

Scrubber

Sorbent Slurry Makeup

Flue Gas

Gas to Stack

FGD Slurry 

Blowdown

FGD Solids 

Separation

Recycle

FGD Scrubber 

Purge to 

Wastewater 

Treatment

FGD Reagent Slurry

Dry FGD System Recirculating Wet FGD System

Wet FGD 

Scrubber

Flue Gas

Gas to Stack

FGD Slurry 

Discharge to 

Wastewater 

Treatment

Sorbent Slurry Makeup

FGD Reagent Slurry

Single Pass Wet FGD System 

Figure 4-7. Typical FGD Systems 

In dry FGD scrubbers, alkaline reagent slurry is introduced into the hot flue gas stream. 

The slurry passes through an atomizer and enters the scrubber as a fine mist of droplets. In the 

scrubber, SO2 is absorbed as the slurry is evaporated and the flue gas is cooled. Dry FGD 

scrubbers typically remove between 80 and 90 percent of the SO2 which is less than a wet FGD 

system. The amount of water in the reagent slurry is controlled such that it evaporates almost 

completely in suspension [Babcock & Wilcox, 2005]. Although dry FGD scrubbers use water in 

their operation, the water in most systems evaporates and they generally do not discharge 

wastewater. Of the 72 dry FGD plants, 23 generate wastewater during operation and only 2 

discharge to a surface water. Wastewater may also be generated during cleaning operations. Of 

the 72 dry FGD plants, 31 generate wastewater from cleaning operations and only 4 discharge 

any cleaning wastewater [ERG, 2013]. Dry FGD systems generate smaller, less frequent 

quantities of wastewater from their operation/cleaning compared to the FGD wastewater from 

wet systems. EPA did not evaluate the wastewater generated from these dry FGD systems as part 

of the rulemaking and they would not be subject to the FGD wastewater requirements in the 

proposed ELGs. 

Wet FGD scrubber systems can remove over 90 percent of the SO2 in the flue gas, and in 

some cases can remove up to 99 percent. In wet FGD scrubbers, the flue gas stream contacts a 
Section 4 - Steam Electric Industry Description

4-29 

liquid stream containing a sorbent, which causes the mass transfer of pollutants from the flue gas 

to the liquid stream. The sorbents typically used for SO2 absorption are lime (Ca(OH)2) or 

limestone (CaCO3), which react with the sulfur in the flue gas to form calcium sulfite (CaSO3). 

Scrubbers can be operated with forced, inhibited, or natural oxidation systems. In forced 

oxidation systems, the CaSO3 is fully oxidized to produce gypsum (CaSO4 • 2H2O). During the 

scrubbing process, metals and other constituents that were not removed from the flue gas stream 

by the ESPs may transfer to the scrubber slurry and leave the FGD system via the scrubber 

blowdown (i.e., the slurry stream exiting the FGD scrubber that is not immediately recycled back 

to the spray/tray levels). The scrubber blowdown is typically intermittently transferred from the 

FGD scrubber to the solids separation process. As a result, FGD scrubber purge (i.e., the 

wastestream from the FGD scrubber system that is transferred to a wastewater treatment system 

or discharged) is also usually intermittent [ERG, 2013]. 

Table 4-11 presents the distribution of wet and dry FGD systems reported in the Steam 

Electric Survey operating in 2009 or planned to be operating by January 1, 2014. Table 4-12

shows the total scrubbed capacity of the steam electric units serviced in those systems.21 There 

are 401 FGD systems, servicing 458 coal-fired steam electric generating units, reported to be 

online by January 1, 2014.22 Of these 401 systems, 311 generate a slurry stream and are 

considered “wet” FGD systems for the purposes of this rulemaking. Wet FGD systems service 

78 percent of scrubbed generating units, representing 84 percent of the total industry scrubbed 

capacity. These wet systems typically use a limestone slurry with forced oxidation and service 

generating units burning bituminous coal. Often, plants also operate SCR systems on these 

generating units to control NOx emissions (see Section 4.4.4). 

Steam electric power plants operating wet FGD systems are located throughout the 

United States; the largest number is on the eastern United States where more bituminous coalfired steam electric power plants are located. Figure 4-8 shows the location of all wet scrubbed 

FGD systems located at the plants noted in Table 4-12. The figure only includes the plants for 

which responses were provided in the Steam Electric Survey (i.e., the figure does not represent 

the weighted numbers). 

 

21 The total scrubbed capacity includes electric power generated by only those steam electric units serviced by an 

FGD system.

22 Recent air regulations and new state requirements have resulted in the installation of new wet FGD scrubbers. 

EPA tried to look ahead to account for these additional wet FGD scrubbers and therefore, because the EPA expects 

to promulgate the final ELG in 2014, EPA used January 1, 2014 as the baseline for this ELG.
Section 4 – Steam Electric Industry Description

4-30 

Table 4-11. Types of FGD Scrubbers in the Steam Electric Industry

Type of Scrubber

“Wet” FGD Systems “Dry” FGD Systems

Number of Plants 

Number Electric 

Generating Units

Number of 

Plants

Number of Electric 

Generating Units

Circulating Dry 0 0 11 11

Jet Bubbling Reactor 10 - 15 30 - 40 0 0

Mechanically Aided 0 0 1 1

Packed 2 4 1 2

Spray 77 159 1 - 5 1 - 5

Spray/Tray 58 118 0 0

Spray Dryer 1 1 50 69

Tray 1 1 0 0

Venturi 10 23 1 - 5 1 - 5

Other a 7 15 5 - 10 7 - 12

No Information b 2 2 0 0

Source: Steam Electric Survey, [ERG, 2013]. 

Note: Certain fields contain ranges of values to protect the release of information claimed CBI.

Note: A plant may operate multiple electric generating units that may use different types of FGD systems; therefore, 

the sum of plants may be greater than the total number of plants with FGD systems.

a – The types of scrubber systems classified as ‘other’ include Advatech Double contact flow scrubbers and dry 

sodium injection. 

b – Insufficient information is available to classify these units/plants in a specific category.

Table 4-12. Characteristics of Coal- and Petroleum Coke-Fired Generating 

Units with FGD Systems

Wet FGD Systems Dry FGD Systems

Number of 

Plants 

Number 

Electric 

Generating 

Units

Scrubbed 

Capacity a 

(MW)

Number of 

Plants

Number of 

Electric 

Generating 

Units

Scrubbed 

Capacity a

(MW)

Total 145 352 175,000 72 97 31,800

Coal Type

Bituminous 83 196 101,000 28 40 8,730

Subbituminous 27 65 34,900 28 38 16,300

Lignite 5-10 10-15 5,000-6,000 2 3 1,320

Petroleum Coke 1-5 1-5 100-200 0-5 0-5 0-150

Other/Waste Coal 0-5 0-5 0-250 1-5 1-5 500-1,000

Blend b 33 81 33,300 8 10 1,880

No Information c 4 4 2,420 1-5 5-10 2,600-3,000

Type of Oxidation System

Forced Oxidation 112 272 138,000 1-5 5-10 800-1,200

Inhibited Oxidation 17 34 19,600 2 3 1,480
Section 4 – Steam Electric Industry Description

4-31 

Table 4-12. Characteristics of Coal- and Petroleum Coke-Fired Generating 

Units with FGD Systems

Wet FGD Systems Dry FGD Systems

Number of 

Plants 

Number 

Electric 

Generating 

Units

Scrubbed 

Capacity a 

(MW)

Number of 

Plants

Number of 

Electric 

Generating 

Units

Scrubbed 

Capacity a

(MW)

Natural Oxidation 23 47 19,000 5-10 5-15 2,200-2,600

No Information or NA d 2 3 860 61 80 27,100

Sorbent

Lime 10-15 30-40 9,500-10,500 56 74 24,800

Limestone 121 288 146,000 13 18 6,070

Magnesium-Enhanced Lime 10-15 25-35 15,500-16,500 0-5 0-5 0-250

Magnesium Oxide 0 0 0 0 0 0

Soda Ash 3 9 1,880 0 0 0

Sodium Hydroxide 0 0 0 0 0 0

Other 5 14 6,940 14 23 6,340

No Information d 1-5 5-10 3,000-4,000 1 1 46

NOx Controls e

SCR 99 203 117,000 27 32 13,200

SNCR 13-23 35-40 11,500-12,500 12 14 4,070

None/Other (no 

SCR/SNCR) 56 110 45,700 30-40 45-50 13,500-14,000

No Information d 2 2 900 5 5 1,250

Source: Steam Electric Survey, [ERG, 2013]. 

Note: Certain fields contain ranges of values to protect the release of information claimed CBI.

Note: Capacity values are rounded to three significant figures.

Note: All 145 wet scrubbed plants and 72 dry scrubbed plants are included in each of the categories presented in this 

table. Because a plant may operate multiple electric generating units that may represent more than one type of 

operation in each specific category, the sum of the plants, units, and capacity for each category may be greater than 

the total.

Note: This table does not account for any plants or units that have identified a retirement between 2009 and January 

1, 2014.

a – The scrubbed capacities represent the reported nameplate capacity for only those units serviced by a scrubber.

b – A coal blend is any combination of two or more different types of coal.

c – The current profile includes planned units whose coal type is not yet available.

d – Insufficient information is available to classify these units/plants in a specific category.

e – Some of the NOx information included in this category is associated with NOx systems that are planned or under 

construction. 
 

 

 

 

 

Section 4 – Steam Electric Industry Description 

Source: Steam Electric Survey, [ERG, 2013]. 

Figure 4-8. Plants Operating Wet FGD Scrubber Systems 

As shown in Table 4-12, limestone forced oxidation systems are the most common 

scrubbers reported in the survey. Plants that generate gypsum using limestone forced oxidation 

systems can market the gypsum for use in building materials (e.g., wallboard), while plants that 

do not generate gypsum or only partially oxidize the CaSO3 must dispose of their scrubber 

solids, typically in landfills or impoundments [U.S. EPA, 2006]. Plants that produce a saleable 

product, such as gypsum, may rinse the product cake to reduce the level of chlorides in the final 

product and reuse or potentially treat and discharge the wash water along with the FGD scrubber 

purge. Both sludge by-products (gypsum and CaSO3) typically require dewatering prior to sale, 

disposal, or processing for reuse. The dewatering process used by plants that generate CaSO3 

typically consists thickeners used in conjunction with centrifuges. The dewatering process used 

by plants that generate gypsum typically consists of hydrocyclones used in conjunction with 

vacuum filters (either drum or belt). Additionally, some plants may send the FGD blowdown 

directly to a pond where the FGD solids are scooped out of the pond with a backhoe and stacked 

on the side of the pond (referred to as “stacking”). The stacking operation is more commonly 

used by plants generating gypsum, whereas most plants sending FGD wastewater with CaSO3 

just let the solids accumulate in the pond. These dewatering processes generate a wastewater 

4-32 
Section 4 – Steam Electric Industry Description

4-33 

stream that the plant likely needs to treat before it is discharged or reused. In the case of the 

plants sending the FGD blowdown directly to a pond, the pond system is typically the only 

treatment employed prior to discharge. Section 6.1 provides more detail on the amount of FGD 

wastewater generated by wet FGD systems.

The installation of wet FGD systems reported in Table 4-12 dates back to 1972. Figure 

4-9 shows the total scrubbed capacity of wet FGD systems by decade starting with the 1970s. 

The figure includes all 311 wet FGD systems identified as operating by January 1, 2014, but it 

does not include retired units that may have operated with wet FGD systems. Therefore, while 

the Steam Electric Survey shows an increase in the total wet scrubbed capacity from 1970 to 

2010 of 123,000 MW, the actual increase may not be as large because by not including retired 

units that may have been scrubbed, the scrubbed capacity for earlier years may not be fully 

represented in the data set. However, based on previous discussions with industry 

representatives, EPA found that most power companies installed the FGD systems on the largest 

and newest generating units in their fleets, which are the generating units that are least likely to 

retire. Therefore, EPA believes that the amount of scrubbed capacity that has been retired over 

this 45-year period is likely minimal. If that is the case, then the data reasonably reflect the 

increased use of wet scrubbed FGD systems over the last 45 years.

Source: Steam Electric Survey, [ERG, 2013].

Figure 4-9. Capacity of Wet Scrubbed Units by Decade

Section 6.1 contains information on FGD wastewater characteristics and treatment.

4.3.4 Flue Gas Mercury Control Wastewater

In response to recent Clean Air Act (CAA) rules and other state regulations requiring 

limits on air emissions of mercury and other air toxics, plants are beginning to install new 

systems to improve removals of mercury from flue gas emissions, beyond those previously 

achieved by particulate control systems to remove fly ash. These systems are relatively new to 

0

20000

40000

60000

80000

100000

120000

140000

160000

180000

200000

1970 - 1980 1980 - 1990 1990 - 2000 2000 - 2010 2010 - 2014

Wet Scrubbed Capacity (MW)

Year of FGD System Installation
Section 4 – Steam Electric Industry Description

4-34 

the steam electric industry. According to responses to the Steam Electric Survey, there are 

generally two types of systems being used to control flue gas mercury emissions:

• Adding oxidizers to the coal prior to combustion, so that the wet FGD system 

removes the oxidized mercury; and 

• Injecting activated carbon into the flue gas, which adsorbs the mercury and is 

captured in a downstream particulate removal system.

Using the oxidizers does not generate a new wastewater stream, but it may increase the 

mercury concentration in FGD wastewater because oxidized mercury is more easily removed by 

the FGD system. However, the activated carbon injection system can generate a new 

wastestream at a plant, depending on the location of the injection. If the injection occurs 

upstream of the primary particulate removal system, then the mercury-containing carbon (i.e., 

FGMC waste) will be collected and handled the same way as the fly ash; therefore, if the fly ash 

is wet sluiced, then the FGMC wastes are also wet sluiced. In this case, adding the FGMC wastes 

to the fly ash can increase the pollutant concentration in the fly ash transport water. Section 6.4

provides more detail on how adding FGMC waste affects the characteristics of fly ash. If the 

injection occurs downstream of the primary particulate removal system, then the plant will need 

a secondary particulate removal system, typically a fabric filter, to capture the FGMC wastes. 

Plants typically inject the carbon downstream of the primary particulate collection system if they 

plan to market the fly ash because adding the FGMC wastes makes the fly ash unmarketable. In 

this situation, the FGMC wastes, which would be collected with some carry-over fly ash, could 

be handled either wet or dry. 

Based on the responses to the survey, there are approximately 120 currently installed 

FGMC systems, with an additional 40 new installations planned. Approximately 90 percent of 

the currently operating FGMC systems are dry systems that do not generate or affect any 

wastewater streams. Approximately six percent of the currently operating systems are wet 

systems. The type of handling system (e.g., wet or dry handling) is unknown for the remaining 

four percent of the systems. 

4.3.5 Landfill and Impoundment Leachate and Runoff

Combustion residuals comprise a variety of wastes from the combustion process, 

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

solids (e.g., gypsum and calcium sulfite); FGMC wastes; and other wastewater treatment solids 

associated with fuel combustion wastewater. Combustion residuals may be stored at the plant in 

on-site landfills or impoundments. When a landfill or impoundment has reached its capacity, it 

will typically be closed (i.e., covered) to protect against environmental release of the pollutants 

contained in the waste. However, these landfills or impoundments may continue to generate 

leachate. 

Leachate is the liquid that drains or leaches from a landfill or an impoundment. Figure 

4-10 presents a diagram depicting the generation and collection systems for landfill leachate and 

stormwater. The two sources of landfill leachate are precipitation that percolates through the 

waste deposited in the landfill and the liquids produced from the combustion residual placed in 

the landfill. In addition to leachate, stormwater that contacts the landfill wastes and flows over 
Section 4 – Steam Electric Industry Description

4-35 

the landfill may be contaminated. Leachate and contaminated stormwater contain heavy metals 

and other contaminants through the contact with the combustion residuals. Section 6.3 further 

discusses the characteristics of leachate.

Figure 4-10. Diagram of Landfill Leachate Generation and Collection 

In a lined landfill, the leachate collected from the landfill typically flows through a 

collection system consisting of ditches and/or underground pipes. From the collection system, 

the plant transports the leachate to a collection impoundment. The stormwater collection systems 

typically consist of one or more small collection impoundments surrounding the landfill area. 

Plants may collect the leachate and stormwater in separate impoundments or combine them 

together in the same impoundment(s). Some plants discharge the effluent from these collection 

impoundments, while other plants send the collection impoundment effluent to the ash 

impoundment. Sixty-three percent of the combustion residual landfills reported in the Steam 

Electric Survey are lined. Impoundments may also have liners and collection systems similar to 

the landfills; 51 percent of the combustion residual impoundments reported in the Steam Electric 

Survey are lined. Unlined impoundments and landfills do not collect leachate migrating away 

from the impoundment/landfill, which can potentially cause ground water and/or drinking water 

contamination. 

Table 4-13 presents the number of plants burning coal or petroleum coke that reported 

collecting leachate from an impoundment or landfill containing combustion residuals in the 

Steam Electric Survey. Approximately 100 plants reported collecting landfill leachate from 

approximately 110 existing (i.e., active or inactive) landfills containing combustion residuals, 

Coal Combustion 

Residue

Runoff

Runoff

Runoff Drainage 

Ditch

Leachate Leachate

Bottom Liner

Runoff Drainage 

Ditch

Clay Liner/Vegitation 

(if necessary)

Leachate Collection Leachate to System Collection Pond
Section 4 – Steam Electric Industry Description

4-36 

while approximately 50 plants reported collecting leachate from existing combustion residual 

impoundments. Another 40 plants reported collecting leachate from both combustion residual 

landfills and impoundments. 

Table 4-13. Leachate Collection at Coal and Petroleum Coke Plants

Type of Leachate Collection

Number of Coal 

and Petroleum 

Coke Plants

Number of 

Combustion 

Residual 

Landfills

Number of 

Combustion 

Residual

Impoundments

Leachate Collection from Landfills Only 90-100 100-110 NA

Leachate Collection from Impoundments Only 40-50 NA 80-90

Leachate Collection from both Landfills and 

Impoundments 30-40 30-40 60-70

Source: Steam Electric Survey, [ERG, 2013].

Note: Certain fields contain ranges of values to protect the release of information claimed CBI.

Note: Only active and inactive landfills and impoundments are shown in the table.

The majority of landfills installed since 2000 collect leachate. Table 4-14 presents a 

distribution of each management unit (impoundment or landfill) collecting leachate and the year 

of installation. Table 4-14 includes data from 283 landfills and 1,100 impoundments. A small 

percentage of lined landfills do not collect leachate; however, a large percentage of lined 

impoundments do not collect leachate. Table 4-14 shows that 18 percent of all lined landfills and 

74 percent of all lined impoundments do not collect leachate.

Table 4-14. Age of Impoundment or Landfill Collecting Leachate 

Management 

Unit Installation 

Year

Landfills a Impoundments b

Total

Number 

Lined

Number Collecting 

Leachate Total

Number 

Lined

Number Collecting 

Leachate

2000 to Present 66 55 51 88 77 30

1990 to 2000 53 33 24 96 74 18

1980 to 1990 102 60 49 308 231 34

Before 1980 59 31 22 593 180 66

Source: Steam Electric Survey, [ERG, 2013]. 

Note: The number of impoundments and landfills in the steam electric industry are based on values reported in the 

survey, which were scaled to represent the industry as a whole using the industry-weighting factors discussed in 

Section 3.3. 

a – Three landfills did not provide sufficient date or liner/leachate collection information to be included in this 

analysis.

b – Fifteen impoundments did not provide sufficient date or liner/leachate collection information to be included in 

this analysis.

Once collected, the landfill or impoundment leachate can be recycled back into the 

management unit, recycled elsewhere within the plant, or discharged. Table 4-15 presents the 

destination of leachate generated from impoundments and landfills. This table includes only 
Section 4 – Steam Electric Industry Description

4-37 

those impoundments and landfills reported as producing leachate in Part F of the Steam Electric 

Survey. The survey data show that at least 28 percent of the impoundment and landfill leachate is 

returned to the management unit.23 Most of the returned leachate originates from impoundments. 

Nearly half of the impoundment leachate systems return the leachate back to the impoundment 

from which it leached. Plants generally discharge landfill leachate directly after collection, or 

treat the leachate on site and then discharge after treatment.

Table 4-15. Destination of Leachate in Steam Electric Industry

Destination Number of Impoundments a Number of Landfills

Returned to Management Unit (impoundment or 

landfill) or Recycled Within the Plant 48 (47%) 35 (28%)

On-Site Treatment System 6 (6%) 23 (18%)

Discharged 35 (34%) 86 (68%)

Other b 21 (20%) 23 (18%)

Total c 103 126

Source: Steam Electric Survey, [ERG, 2013].

Note: The number of impoundments and landfills in the steam electric industry are based on values reported in the 

survey, which were scaled to represent the industry as a whole using the industry-weighting factors discussed in 

Section 3.3. 

a – Respondents did not provide a leachate destination of any kind for seven impoundments. These impoundments 

are not represented in the table.

b – "Other” includes perimeter drain with no flow, underground mine pool, and underground injection.

c – Total number of impoundments and landfills is not additive because leachate may have more than one 

destination. For example, it is possible for leachate from one impoundment to be both treated and discharged.

4.3.6 Gasification Wastewater 

IGCC plants generate wastewater from the gasification process, in which a fuel source 

(e.g., coal or petroleum coke) is subjected to high temperature and pressure to produce a 

synthetic gas that is used as the fuel for a combined cycle generating unit. As described in 

Section 4.2.3, the specific processes used to generate the synthetic gas and clean that gas prior to 

combustion vary to some degree at the currently operating IGCC plants; however, each of these 

processes require purging wastewater from the process to remove chlorides and other 

contaminants from the system. Pollutants that may be present in the gasification wastewater 

include selenium, chromium, arsenic, and cyanide. 

As shown in Figure 4-4, there are several wastewater streams generated as part of the 

IGCC process. Additionally, there may be other wastewaters generated at IGCC plants that are 

not included in Figure 4-4. The following is a list of the key wastewaters that may be generated 

at IGCC plants:

 

23 Part F of EPA’s Steam Electric Survey requested information on the management practices of both impoundments 

and landfills containing fuel combustion residuals. This section included questions related to the collection and 

treatment of leachate from both types of management units. As described in Section 3.3, Part F of the questionnaire 

was sent only to a probability sampled stratum of coal- and petroleum coke-fired plants.
Section 4 – Steam Electric Industry Description

4-38 

• IGCC-specific wastewaters: 

- Slag handling wastewater;

- Fly ash and water stream;

- Sour/grey water (which consists of condensate generated for gas cooling, as well 

as other wastestreams);

- CO2/steam stripper wastewater; 

- Air separation unit blowdown; and 

- Sulfur recovery unit blowdown. 

• General power plant wastewaters: 

- Blowdown from the heat recovery steam generator blowdown; 

- Coal/petroleum coke pile runoff; 

- Metal cleaning wastes;

- Raw water filtration backwash;

- Demineralizer system reject; and

- Cooling water. 

Depending on the set-up at the plant, most of the general power plant wastewaters would 

be handled similarly to how they are treated at conventional pulverized coal-fired power plants. 

Additionally, the slag handling wastewater and the fly ash and water stream may be handled 

similarly to the fly and bottom ash transport water streams at conventional pulverized coal-fired 

power plants (i.e., transferred to a surface impoundment prior to discharge). Otherwise, these 

streams may be recycled back to the slurry preparation system and sent back to the gasifier. The 

other IGCC-specific wastewaters are treated in a vapor-compression brine concentrator at both of 

the currently operating IGCC plants. See Section 6.5 for more information on the characteristics 

of IGCC wastewater.

4.3.7 Metal Cleaning Waste 

The Steam Electric Power Generating ELGs define metal cleaning waste as “any 

wastewater resulting from cleaning [with or without chemical cleaning compounds] any metal 

process equipment, including, but not limited to, boiler tube cleaning, boiler fireside cleaning, 

and air preheater cleaning.” [See 40 CFR 423.11]. Plants use chemicals to remove scale and 

corrosion products that accumulate on the boiler tubes and retard heat transfer. The major 

constituents of boiler cleaning wastes are the metals of which the boiler is constructed, typically 

iron, copper, nickel, and zinc. Boiler firesides are commonly washed with a high-pressure water 

spray against the boiler tubes while they are still hot. Fossil fuels with significant sulfur content 

will produce sulfur oxides that adsorb on air preheaters. Water with alkaline reagents is often 

used in air preheater cleaning to neutralize the acidity due to the sulfur oxides, maintain an 

alkaline pH, and prevent corrosion. The types of alkaline reagents used include soda ash, caustic 

soda, phosphates, and detergent. 

The frequency of metal cleaning activities can vary depending on the type of cleaning 

operation and individual plant practices. Some operations occur as often as several times a day, 
Section 4 – Steam Electric Industry Description

4-39 

while others occur once every several years. Soot blowing, the process of blowing away the soot 

deposits on furnace tubes, generally occurs once a day, but some units do this as often as several 

hundred times a day. While 83 percent of units responding to the survey use steam or service air 

to blow soot, some plants may generate wastewater streams. Air heater cleaning is another 

frequent cleaning activity. Sixty-six percent of the units perform this operation at least once 

every two years, while other units perform this cleaning task very infrequently, only once every 

40 years. Generally, plants use intake or potable water to clean the air heater [ERG, 2013]. 

The following is a list of all the metal cleaning wastes that were reported in response to 

the Steam Electric Survey: 

• Air compressor cleaning;

• Air-cooled condenser cleaning; 

• Air heater cleaning;

• Boiler fireside cleaning;

• Boiler tube cleaning;

• Combustion turbine cleaning (combustion portion and/or compressor portion); 

• Condenser cleaning; 

• Draft fan cleaning;

• Economizer wash; 

• FGD equipment cleaning; 

• Heat recovery steam generator cleaning;

• Mechanical dust collector cleaning;

• Nuclear steam generator cleaning;

• Precipitator wash;

• SCR catalyst soot blowing; 

• Sludge lancing;

• Soot blowing; 

• Steam turbine cleaning; and

• Superheater cleaning.

4.4 STEAM ELECTRIC WASTESTREAMS NOT EVALUATED FOR NEW OR ADDITIONAL 

CONTROLS IN THE PROPOSED ELGS

This section describes the wastestreams generated by steam electric power plants for 

which EPA did not evaluate new or revised discharge requirements for the proposed ELGs. 

Section 4.3 discusses other wastestreams generated by the steam electric industry the EPA did 

evaluate for new or revised discharge requirements in the proposed ELGs. 
Section 4 – Steam Electric Industry Description

4-40 

4.4.1 Condenser Cooling Water 

As discussed in Section 4.2.1, the steam electric process uses cooling water to condense 

the steam generated in the boiler; this steam turns the turbines and generates electricity. Because 

plants are generally generating electricity continuously, plants must provide a constant flow of 

cooling water to maintain steam condensation and a low pressure in the condenser. Steam 

electric power plants typically use either once-through or recirculating cooling water systems to 

condense the steam from the process. Approximately 96 percent of the electric generating units 

serviced by a cooling system use one of these two types of systems: once-through systems 

service approximately 52 percent of generating units and recirculating systems service roughly 

44 percent. The remaining 4 percent use other methods, most commonly dry cooling systems. 

Recirculating systems service roughly 500 coal- or petroleum coke-fired steam electric 

generating units [Steam Electric Survey]. In a recirculating cooling system, the heated water is 

sent to a cooling tower to lower its temperature. Plants periodically add fresh water to the 

cooling water system to make up for evaporative losses. As cooling water evaporates in the 

cooling tower, dissolved minerals in the water remain behind in the system and increase in 

concentration over time. To prevent the concentrations of these minerals from building up to 

unacceptable levels, plants must discharge some of the water, referred to as “cooling tower 

blowdown,” periodically to purge the minerals from the system.

As the cooling water passes through the condenser, microbiological species (e.g., 

bacterial slimes and algae) stick to and begin growing on the condenser tubes. Steam electric 

power plants use biocides, such as sodium hypochlorite, sodium bromide, or chlorine gas, to 

control biofouling on the condenser tubes and cooling tower packing material. Plants may also 

use chlorine or other antimicrobials, or other methods (e.g., mechanical, thermal) to control 

macroorganisms. 

Once-through cooling systems service roughly 740 coal- or petroleum coke-fired steam 

electric generating units [ERG, 2013]. In these systems, the cooling water is withdrawn from a 

body of water, flows through the condenser, and is discharged back to the body of water. 

Once-through cooling systems discharge at a significantly higher flow rate than 

recirculating systems. Table 4-16 provides the average cooling water blowdown rates for each 

type of cooling system reported in the Steam Electric Survey. Recirculating systems generate 

blowdown at a rate of approximately 113 MGD, roughly 30 percent of the flow rate generated by 

once-through systems. Cooling water blowdown is generally a continuous flow, occurring 

24 hours per day and 365 days per year. 
Section 4 – Steam Electric Industry Description

4-41 

Table 4-16. Cooling Water Discharge Average Flow Rates Reported in the 

Steam Electric Industry

Type of Cooling 

Water System

Number of Cooling 

Systems

Number of 

Generating Units 

Serviced

Capacity of 

Generating Units 

(MW)

Average Wastewater 

Discharge or Blowdown 

per System

(MGD) a 

Recirculating b 950 1,192 321,000 113

Once-Through 666 1,108 298,000 3,730

Other c 128 120 26,700 194

Total 1,744 2,420 645,700 1,570

Source: Steam Electric Survey, [ERG, 2013]. 

Note: Capacity values and wastewater generation rate are rounded to three significant figures.

Note: The number of plants, units, and capacity in the steam electric industry generated from the Steam Electric 

Survey are based on values reported in the survey, which were scaled to represent the industry as a whole using the 

industry-weighting factors discussed in Section 3.3. 

a – The average wastewater flow rate per system is calculated from data provided in the Steam Electric Survey. EPA 

did not include any cooling system with incomplete cooling water flow data. 

b – Fifteen generating units (twelve plants) selected ‘other’ for the type of cooling system servicing the units. Two 

units (one plant) operate a natural draft cooling system and the remaining thirteen units (eleven plants) operate a 

closed loop cooling system. All eight of these units are classified as recirculating systems.

c – Systems classified as ‘Other’ include dry cooling systems, cooling impoundments, noncontact systems, two-pass 

systems, and those systems that did not specify a type of cooling system.

Once-through cooling water and cooling tower blowdown may contain the following 

pollutants, often in low concentrations, as a result of chlorination and corrosion/erosion of the 

piping, condenser, and cooling tower materials: chlorine, iron, copper, nickel, aluminum, boron, 

chlorinated organic compounds, suspended solids, brominated compounds, and nonoxidizing 

biocides. 

4.4.2 Coal Pile Runoff

According to the Steam Electric Survey, 99 percent of coal-fired plants store or process 

coal on site. Coal-fired power plants receive coal via train, barge, or truck. The coal is unloaded 

in a designated area and conveyed to an outdoor storage area, referred to as the coal pile. Power 

plants generally store between 25 and 40 days’ worth of coal in the coal pile, but this varies by 

plant. Some coal-fired plants may have more than one coal pile, depending where the boilers are 

located and whether the plants use or blend different types of coal. Rainwater and melting snow 

contacting the coal pile generates a wastestream that contains pollutants from the coal, referred 

to as coal pile runoff. 

Coal pile runoff from the coal-fired power industry generates approximately 3.5 million 

gallons of wastewater per year [ERG, 2013]. The quantity of runoff at each plant depends upon 

the amount of precipitation, the physical location and layout of the pile, and the extent to which 

water infiltrates the ground underneath the pile. As a result, individual flows are often infrequent, 

with the average plant generating coal pile runoff a total of 131 days per year [ERG, 2013]. Coal 
Section 4 – Steam Electric Industry Description

4-42 

pile runoff is usually collected in a runoff impoundment during or immediately after times of 

rainfall.

EPA collected data on the pH of coal pile runoff impoundments during several site visits 

to coal-fired steam electric power plants. The pH of coal pile runoff holding impoundments 

ranges from 2.8 to 8.5 S.U. In general, coal pile runoff impoundments containing other 

wastewaters, specifically limestone pile runoff, have a higher pH because the limestone pile 

runoff neutralizes the acidity of the coal pile runoff [ERG, 2008a – 2008e, 2008g; ERG, 2009a, 

2009b, 2009d – 2009f]. 

4.4.3 Selected Low Volume Waste Sources

Low volume waste sources, as currently defined by the existing Steam Electric Power 

Generating ELGs, include a variety of wastestreams, such as wastewater associated with wet 

scrubber air pollution control systems, ion exchange water treatment systems, water treatment 

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

tower basin cleaning wastes, and recirculating house service water systems. See 40 CFR 423.11. 

The proposed ELGs would remove specific wastewaters from this collective group of low 

volume waste sources. As discussed in Section 8.1.1, EPA is proposing to exclude FGD 

wastewater, combustion residual leachate, and carbon capture wastewater from the low volume 

waste source category. Plants typically combine low volume wastes with other plant wastewaters 

for treatment, often in surface impoundments. In some cases, low volume wastewaters can be 

recycled within the plant. Table 4-17 shows the distribution of some of the low volume 

wastestreams. This table includes the number of plants generating each waste and the minimum 

and maximum flows as reported in the Steam Electric Survey.

Table 4-17. Selected Low Volume Waste Sources in the Steam Electric Industry

Type of Wastestream Number of Plants a Minimum Flow b (GPY) Maximum Flow b (GPY)

Ion Exchange Wastewater 134 2,590 60,400,0000

Boiler Blowdown 164 3,790 616,000,000

Evaporator Blowdown 1 1,830,000 1,830,000

Floor Drains 220 12,000 10,500,000,000

Source: Steam Electric Survey, [ERG, 2013].

Note: Wastewater flow rates are rounded to three significant figures.

Note: The table presents a subset of wastestreams that survey responses clearly identified and for which flows were 

reported.

Note: The number of plants in the steam electric industry generated from the Steam Electric Survey are based on 

values reported in the survey, which were scaled to represent the industry as a whole using the industry-weighting 

factors discussed in Section 3.3.

a – The number of plants reported as generating each wastestream is based on the total number of plants listing the 

specific wastestream as an influent to an impoundment or wastewater treatment system in the Steam Electric Survey 

and then weighted to represent all plants within the Steam Electric Industry. This includes commingled streams or 

streams for which a flow rate was not provided. 

b – Minimum and maximum flows do not include flow rates for commingled streams. This data only represents the 

flow rates that were reported in the Steam Electric Survey. 
Section 4 – Steam Electric Industry Description

4-43 

4.4.4 Selective Catalytic Reduction and Selective Non-Catalytic Reduction Wastewater 

SCR and selective noncatalytic reduction (SNCR) are technologies used to control 

nitrogen oxide (NOx) emissions in the flue gas from the boiler. Based on survey responses, EPA 

identified 426 plants operating at least one SCR system and an additional 97 plants operating at 

least one SNCR system. In SCR, ammonia (NH3) is injected into the flue gas upstream of a 

catalyst, such as vanadium or titanium. The NOx in the flue gas (comprising mainly nitrogen 

monoxide (NO) with lesser amounts of nitrogen dioxide (NO2)) reacts with the NH3 in the 

presence of oxygen and the catalyst to form nitrogen and water. SNCR utilizes either ammonia 

or urea injected into the flue gas within a specific temperature zone. As with SCR technologies, 

the NOx in the flue gas reacts with the reducing agent, either ammonia or urea, in the presence of 

oxygen to form nitrogen and water. 

In addition to forming nitrogen and water, a fraction of the SO2 in the flue gas may be 

oxidized to sulfur trioxide (SO3), and other side reactions may produce ammonium sulfate 

((NH4)2SO4) and ammonium bisulfate (NH4HSO4) as by-products. These by-products can foul 

and corrode downstream equipment. The extent to which they form depends upon various factors 

within the process, including the sulfur content of the coal used in the boiler and the amount of 

excess NH3 in the system. Unreacted NH3 in the flue gas from the SCR/SNCR is commonly 

termed ammonia slip [Babcock & Wilcox, 2005].

Plants may use different SCR/SNCR configurations based on the particular operations of 

the system, including placing the SCR/SNCR upstream of the air heater and other emission 

control devices such as a FGD scrubber and/or particulate removal device (e.g., ESP).24

Although the SCR/SNCR does not produce a wastestream during operation, it can affect the 

characteristics of fly ash transport water, air heater wash water, and FGD wastewater. As 

previously explained, unreacted NH3 and SO3 by-product can create (NH4)2SO4 and NH4HSO4, 

which can deposit in the air heater and must be removed through periodic washes. The collection 

of the (NH4)2SO4 and NH4HSO4 affect the characteristics of the air heater wash water and also 

lead to more frequent washing. The fly ash transport water characteristics can be affected by the 

SCR operation because ammonia that passes unreacted through the SCR/SNCR may attach to the 

particulates in the flue gas and be removed from the flue gas in the air pollution control 

equipment (e.g., ESP, baghouse, FGD scrubber). Because ammonia is soluble, if the ash 

collected from the particulate removal device is handled with a wet system (e.g., wet sluicing), 

then the ammonia will likely partition into the wastewater and be discharged from the plant 

[Wright, 2003].

In addition to affecting fly ash transport water and FGD wastewater characteristics, SCR 

systems could potentially need associated other cleaning operations that generate a wastestream, 

including catalyst regeneration wastewater and wastewater from washing the catalyst bed. 

According to survey responses, no plants reported generating SCR catalyst regeneration 

wastewater in 2009. Three plants reported generating wastewater from washing the SCR catalyst 

bed. Catalyst bed washing occurs infrequently, from twice per year to once every six years, and 

generates up to 1,080,000 gallons of wastewater per event. The plants reported commingling the 

 

24 The air heater utilizes the heat contained in the flue gas to increase the temperature (via heat exchange) of the air 

injected into the boiler for combustion.
Section 4 – Steam Electric Industry Description

4-44 

catalyst bed wash water with other wastestreams and treating them on site prior to discharge 

[ERG, 2013]. 

4.4.5 Carbon Capture Wastewater 

Due to potential future regulations on carbon dioxide (CO2) emissions, many steam 

electric power plants are considering alternatives available for reducing carbon emissions.

There are three main approaches for capturing the CO2 associated with generating 

electricity: postcombustion, precombustion, and oxyfuel combustion. 

• In post-combustion capture, the CO2 is removed after the fossil fuel is combusted.

• In precombustion capture, the fossil fuel is partially oxidized, such as in a gasifier. 

The resulting syngas (CO and H2) is shifted into CO2 and more H2 and the resulting 

CO2 can be captured from a relatively pure exhaust stream before combustion takes 

place.

• In oxyfuel combustion, also known as oxycombustion, the fuel is burned in oxygen 

instead of air. The flue gas consists of mainly CO2 and water vapor; the latter is

condensed through cooling. The result is an almost pure CO2 stream that can be 

transported to the storage, or sequestration, site and stored. 

After capture, the plant would transport CO2 to a suitable sequestration site. Approaches 

under consideration include the following: 

• Geologic sequestration (injection of the CO2 into an underground geologic 

formation); 

• Ocean sequestration (typically injecting the CO2 into the water column at depths to 

allow dissolution or at deeper depths where the CO2 is denser than water and would 

form CO2 “lakes”); and

• Mineral storage (where CO2 is exothermically reacted with metal oxides to produce 

stable carbonates).

Based on preliminary information regarding these technologies, EPA believes these 

systems may result in new wastestreams at steam electric power plants that will need to be 

addressed. However, as these technologies are currently in the early stages of research and 

development and/or pilot testing, the industry has little information on the potential wastewaters 

generated from carbon capture processes.

As part of EPA’s sampling program, EPA obtained analytical data from two 

wastestreams generated from a post-combustion carbon capture pilot-scale system. The pilotscale system was based on Alstom’s chilled ammonia process. This carbon capture process 

generated a few wastewater bleed streams, two of which were analyzed as part of EPA’s 

sampling program. The first stream, a pilot validation facility (PVF) bleed stream, is a purge 

stream that removes ammonium sulfate from the process. During sampling activities, the PVF 

bleed stream flow rate ranged from 800 to 5,100 gallons per day (gpd). The second stream, flue 

gas condensate, is a condensate stream generated from cooling the flue gas, which condenses the 
Section 4 – Steam Electric Industry Description

4-45 

water vapor present. The flow rate of the flue gas condensate stream ranged from 2,600 to 9,900 

gpd during sampling. Table 4-18 presents the concentrations of the pollutants measured during 

the EPA sampling program. The concentrations presented are the 4-day average concentrations.

According to plant personnel, for a full-scale system, a plant would transfer the PVF 

bleed stream to a crystallizer, producing a solid particulate product which could be used as a 

fertilizer [Lohner, 2010]. The condensate from the evaporation process could be reused in other 

plant processes or discharged. 

Table 4-18. Carbon Capture Wastewater 4-Day Average Concentration Data 

Analyte Unit

4-Day Average Concentration

PVF Bleed Stream Flue Gas Condensate

Classicals

Ammonia mg/L 26,800 < 383

Nitrate Nitrite as N mg/L 8.98 1.80

Nitrogen, Total Kjeldahl mg/L 42,800 740

Biochemical Oxygen Demand mg/L ND (14.7) < 3.65

Chemical Oxygen Demand mg/L 88.8 NQ (20.0)

Chloride mg/L NQ (300) NQ (6.75)

Sulfate mg/L 163,000 1,050

Cyanide, Total mg/L 1.20 ND (0.100)

Total Dissolved Solids mg/L 163,000 1,050

Total Suspended Solids mg/L 27.3 < 6.75

Phosphorus, Total mg/L 0.155 NQ (0.0500)

Total Metals

Aluminum ug/L 450 NQ (200)

Antimony ug/L 2.65 ND (2.00)

Arsenic ug/L 40.0 NQ (4.00)

Barium ug/L 57.5 NQ (20.0)

Beryllium ug/L ND (2.00) ND (2.00)

Boron ug/L 13,000 1,540

Cadmium ug/L NQ (4.00) ND (4.00)

Calcium ug/L 24,000 < 2,390

Chromium ug/L 1,540 < 17.5

Cobalt ug/L 73.3 NQ (20.0)

Copper ug/L 400 14.9

Iron ug/L 4,380 2,020

Lead ug/L 7.78 NQ (2.00)

Magnesium ug/L 15,800 1,990

Manganese ug/L 965 101

Mercury ng/L 3,530 1,060

Molybdenum ug/L 2,630 NQ (40.0)
Section 4 – Steam Electric Industry Description

4-46 

Table 4-18. Carbon Capture Wastewater 4-Day Average Concentration Data 

Analyte Unit

4-Day Average Concentration

PVF Bleed Stream Flue Gas Condensate

Nickel ug/L 4,530 27.5

Selenium ug/L 4,900 128

Silver ug/L ND (2.00) ND (2.00)

Sodium ug/L 16,000 NQ (10,000)

Thallium ug/L 2.30 ND (2.00)

Tin ug/L ND (200) ND (200)

Titanium ug/L NQ (20.0) NQ (20.0)

Vanadium ug/L 19.0 NQ (10.0)

Zinc ug/L 293 NQ (40.0)

Source: CWA 308 Monitoring, [ERG, 2012].

< – Average result includes at least one value measured below the quantitation limit. (Calculation uses 1⁄2 the 

sample-specific quantitation limit for values below the quantitation limit).

ND – Not detected (number in parenthesis is the quantitation limit).

NQ – Analyte was measured below the quantitation limit for all four results (number shown in parenthesis is the 

average quantitation limit), but at least one result was measured above the method detection limit.

Note: Concentrations are rounded to three significant figures.

According to the survey responses, there are no full-scale carbon capture systems 

operating in the industry. There are, however, two pilot-scale systems that have been in 

operation, the one for which EPA collected the analytical data presented in Table 4-18 (currently 

shut down and inactive) and another one that has been decommissioned. Additionally, several 

plants reported in their survey responses that they are planning to install a pilot-scale carbon 

capture system and some plants even reported plans to install full-scale systems.

In March 2012, EPA proposed a Carbon Pollution Standard for New Power Plants (FR 

Doc No: 2012-7820), which would set national limits on the amount of carbon pollution future 

power plants can emit. The proposed carbon pollution standard does not apply to existing plants 

or those permitted to begin construction by 2013. The proposed rule will allow future plants to 

choose to burn any fossil fuel to generate electricity, but would require these plants to 

incorporate technologies to reduce the carbon dioxide emissions to meet a standard of 1,000 

pounds of CO2 per megawatt-hour. This rule will likely have the greatest impact on coal-, 

petroleum coke-, and oil-fired plants because new natural gas combined cycle units should be 

able to meet the proposed standard without additional CO2 controls [U.S. EPA, 2012]. 

4.5 REFERENCES

1. Babcock & Wilcox Company. 2005. Steam: Its Generation and Use. 41st edition. Edited 

by J.B. Kitto and S.C. Stultz. Barberton, Ohio. DCN SE02919. 

2. Eastern Research Group (ERG). 2008a. Final Site Visit Notes: Appalachian Power 

Company’s Mountaineer Plant. (11 September). DCN SE02070. 
Section 4 – Steam Electric Industry Description

4-47 

3. Eastern Research Group (ERG). 2008b. Final Site Visit Notes: Kentucky Utilities 

Company’s Ghent Generating Station. (19 December). DCN SE02079. 

4. Eastern Research Group (ERG). 2008c. Final Site Visit Notes: Louisville Gas and 

Electric Company’s Cane Run Station. (11 December). DCN SE02082. 

5. Eastern Research Group (ERG). 2008d. Final Site Visit Notes: Louisville Gas and 

Electric Company’s Mill Creek Station. (December 12). DCN SE02083. 

6. Eastern Research Group (ERG). 2008e. Final Site Visit Notes: Louisville Gas and 

Electric Company’s Trimble County Station. (10 December). DCN SE02080. 

7. Eastern Research Group (ERG). 2009a. Final Site Visit Notes: Alleghany Energy’s 

Harrison Power Station. (20 January). DCN SE02069. 

8. Eastern Research Group (ERG). 2009b. Final Site Visit Notes: CPS Energy’s Calaveras 

Power Station. (29 October). DCN SE02076. 

9. Eastern Research Group (ERG). 2009c. Final Site Visit Notes: Duke Energy’s Wabash 

River Generating Station. (12 October). DCN SE02095. 

10. Eastern Research Group (ERG). 2009d. Final Site Visit Notes: Fayette Power 

Project/Sam Seymour Power Station. (30 October). DCN SE02077. 

11. Eastern Research Group (ERG). 2009e. Final Site Visit Notes: Ohio Power Company’s 

Gavin Plant. (19 January). DCN SE02072. 

12. Eastern Research Group (ERG). 2009f. Final Site Visit Notes: Tennessee Valley 

Authority’s Paradise Fossil Plant. (20 September). DCN SE02101. 

13. Eastern Research Group (ERG). 2009g. Final Site Visit Notes: Western Kentucky 

Energy’s Kenneth C. Coleman Station. (23 February). DCN SE02094. 

14. Eastern Research Group (ERG). 2011. Final Site Visit Notes: TECO Energy’s Polk 

Power Station. (2 March). DCN SE00071. 

15. Eastern Research Group (ERG). 2012. Final Power Plant Monitoring Data Collected 

Under Clean Water Act Section 308 Authority (“CWA 308 Monitoring Data”). (30 May). 

DCN SE01326. 

16. Eastern Research Group (ERG). 2013. Steam Electric Technical Questionnaire Database 

(“Steam Electric Survey”). (19 April). DCN SE01958. 

17. Lohner, Tim. 2010. Email to Ron Jordan of U.S. EPA from Tim Lohner of AEP. (6 

December). DCN SE01335. 

18. USCB. 2007. U.S. Census Bureau. Electric Power Generation, Transmission, and 

Distribution: 2007 Economic Census Utilities Industry Series. Document and data are 

available online at: http://www.census.gov/econ/census07/. DCN SE01802. 

19. 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 SE02933. 

20. U.S. DOE. 2006. U.S. Department of Energy. Introduction to Nuclear Power. Energy 

Information Administration (EIA). Available online at: 
Section 4 – Steam Electric Industry Description

4-48 

http://www.eia.doe.gov/cneaf//page/intro.html. Date accessed: August 2006. DCN 

SE01803. 

21. U.S. DOE. 2009. U.S. Department of Energy. Annual Electric Generator Report 

(collected via Form EIA-860). Energy Information Administration (EIA). The data files 

are available online at: http://www.eia.doe.gov/cneaf//page/eia860.html. DCN SE01805. 

22. Wright, Thomas. 2003. “SCR Operation Optimization: SO3 Removal to Optimize 

Catalyst Life & NH3 Distribution in Wastewater.” In: Proceedings from the Selective 

Catalytic/Non-Catalytic Reduction Conference. Chattanooga, TN. (October 30). DCN 

SE02934. 

23. U.S. DOE. U.S. Department of Energy. Energy Efficiency and Renewable Energy - 

Geothermal Technologies Program. Available online at: 

http://www1.eere.energy.gov/al/faqs.html and 

http://www1.eere.energy.gov//powerplants.html. DCN SE01804.
Section 5 – Industry Subcategorization

5-1 

SECTION 5

INDUSTRY SUBCATEGORIZATION

This section presents information about factors EPA considered in evaluating whether 

different limitations or standards are warranted for certain facilities in the steam electric power 

generating point source category. Section 5.1 describes why EPA considers factors that could 

lead to establishing different requirements for certain facilities in the point source category and 

presents background on the industry categorization established in the 1974 and 1982 ELG 

rulemakings. Section 5.2 presents the factors considered in detail and reviews the analyses EPA 

performed to review whether subcategorization was necessary to the revisions proposed. 

5.1 SUBCATEGORIZATION FACTORS

The CWA requires EPA to consider a number of different factors when developing ELGs 

for a particular industry category (Section 304(b)(2)(B), 33 U.S.C. § 1314(b)(2)(B)). For BAT, 

in addition to the technological availability and economic achievability, these factors are the age 

of the equipment and plants, the process employed, the engineering aspects of the application of 

various types of control techniques, process changes, the cost of achieving such effluent 

reduction, non-water quality environmental impacts (including energy requirements), and such 

other factors the Administrator deems appropriate. One way EPA may take these factors into 

account, where appropriate, is by dividing a point source category into groupings called 

“subcategories.” Regulating a category by subcategory, where determined to be warranted,

ensures that each subcategory has a uniform set of ELGs that take into account technology 

availability and economic achievability and other relevant factors unique to that subcategory. 

The current Steam Electric ELGs do not divide plants or process operations into 

subcategories, although they do include different effluent requirements for cooling water 

discharges from generating units smaller than 25 MW generating capacity [U.S. EPA, 1974; U.S. 

EPA, 1982]. For this proposed rule, EPA evaluated whether different effluent requirements 

should be established for certain facilities within the steam electric power generating point 

source category using information from responses to the industry surveys, site visits, sampling, 

and other data collection activities (see Section 3 for more details). EPA performed analyses to 

assess the influence of age, size, fuel type, and geographic location on the wastewaters 

generated, discharge flow rates, pollutant concentrations, and treatment technology availability at 

steam electric power plants to determine whether subcategorization was appropriate.

5.2 ANALYSIS OF SUBCATEGORIZATION FACTORS

EPA performed analyses to assess the influence of age, size, fuel type, and geographic 

location on the wastewaters generated at steam electric power plants and the availability of 

technologies to manage those wastewaters. The following sections summarize the analyses 

performed as part of the subcategorization reevaluation. For additional information on the 

specific analyses performed as part of the reevaluation, see the memorandum entitled 

“Subcategorization Memorandum” [ERG, 2013a]. 
Section 5 – Industry Subcategorization

5-2 

5.2.1 Age of Plant or Generating Unit 

EPA analyzed the age of the power plants and the generating units included in the scope 

of the rule. EPA determined that the age of the plant by itself does not in general impact the 

wastewater characteristics, the processes in place, or the ability to install the treatment 

technologies evaluated as part of this rulemaking [ERG, 2013a]. Therefore, EPA did not 

establish subcategories based solely on the age of the plant or generating unit for this proposed 

rule. 

5.2.2 Geographic Location 

EPA analyzed the geographic location of power plants included in the scope of the rule. 

EPA determined that the geographic location of the plant by itself does not affect the wastewater 

characteristics, the processes in place, or the ability to install the treatment technologies 

evaluated as part of this rulemaking. During its evaluation, EPA did find that wet FGD systems, 

both wet and dry fly ash handling systems, and both wet and dry bottom ash handling systems 

are located throughout the United States, as illustrated in Section 4. Additionally, the location of 

the plant does not affect the plant’s ability to install the treatment technologies evaluated as part 

of this rulemaking. For example, a plant in the southern United States will be able to install and 

operate the chemical precipitation and biological treatment system proposed as the BAT 

technology basis for FGD wastewater. Because of the warm climate, plants in locations such as 

this may find it necessary to install heat exchangers to keep the FGD wastewater temperature at 

ideal operating conditions during the summer months. EPA’s approach for estimating 

compliance costs takes such factors into account. Based on the information in the record 

regarding the current geographic location of the various types of systems generating the 

wastewaters addressed by this rulemaking and engineering knowledge of the operational 

processes and candidate BAT/NSPS treatment technologies, EPA determined that subcategories 

based on plant location are not warranted. 

5.2.3 Size

EPA analyzed the size (i.e., nameplate generating capacity in MW) of the steam electric 

generating unit and determined that it is an important factor influencing the volume of the 

discharge flow from the plant. Typically, as the size of the generating unit increases, the 

discharge flows of ash transport water generally increase. In general, this is to be expected 

because the larger the generating unit, the more fuel it consumes, which generates more ash, and 

uses more water in the water/steam thermodynamic cycle [ERG, 2013b]. Although the volume of 

the wastewater increases with the size of the generating unit, the pollutant characteristics of the 

wastewater generally are unaffected by the size of the generating unit and any variability 

observed in wastewater pollutant characteristics does not appear to be correlated to generating 

capacity.

As a result of its evaluation, EPA believes that, in certain circumstances, it would be 

appropriate to apply different limits for a class of existing generating units or plants based on 

size. Section 8 discusses in greater detail EPA’s proposal for applying different standards to 

certain existing units and plants.
Section 5 – Industry Subcategorization

5-3 

5.2.4 Fuel Type 

The type of fuel (e.g., coal, petroleum coke, oil, gas, nuclear) used to create steam most 

directly influences the type and number of wastestreams generated. For example, gas and nuclear 

power plants typically generate cooling water, metal cleaning wastes (both chemical and 

nonchemical), and other low volume wastestreams, but do not generate wastewaters associated 

with air pollution control devices (e.g., fly ash and bottom ash transport water, FGD wastewater). 

Coal, oil, and petroleum-coke power plants may generate all of those wastewaters. The 

wastestream that is most influenced by fuel selection is the ash transport water because the 

quantity and quality of ash generated from oil-fired units is different from that generated from 

coal- and petroleum coke-fired units. Additionally, the quantity and quality of ash differs based 

on the type of oil used in the boiler. For example, heavy or residual oils such as No. 6 fuel oil 

generate fly ash and may generate bottom ash, but lighter oils such as No. 2 fuel oil may not 

generate any ash.

From an analysis of responses to the Steam Electric Survey, EPA determined that 74 

percent of the steam electric units in the industry burn more than one type of fuel (e.g., coal and 

oil, coal and gas). Some of these plants may burn only one fuel at a specific time, but burn both 

types of fuels during the year. Other plants may burn multiple fuels at the same time. In cases 

where facilities burn multiple fuels at the same time, it would be impossible to separate the 

wastestreams by fuel type [ERG, 2013b]. 

EPA did not identify any basis for subcategorizing gas-fired and nuclear generating units. 

These generating units generally manage nonchemical metal cleaning wastes in the same manner 

as other steam electric generating units, and the proposed requirements for this wastestream 

would establish limitations and standards that are equal to current BPT limitations for existing 

direct dischargers.25 Furthermore, the gas-fired and nuclear generating units do not generate the 

other six wastestreams addressed by this rulemaking. However, based on responses to the Steam 

Electric Survey, there are some oil-fired units that generate and discharge fly ash and/or bottom 

ash transport water. For these reasons, EPA looked carefully at oil-fired units. As a result, EPA 

believes that, in certain circumstances, it is appropriate to apply different limits to existing oilfired generating units. Section 8 discusses in greater detail EPA’s proposal for applying different 

standards to certain existing oil-fired units. 

5.3 REFERENCES

1. Eastern Research Group (ERG). 2013a. Steam Electric Technical Questionnaire Database 

(“Steam Electric Survey”). (19 April). DCN SE01958 

2. Eastern Research Group (ERG). 2013b. Memorandum to the Steam Electric Rulemaking 

Record. Subcategorization Memorandum.” (19 April). DCN SE02127. 

3. U.S. EPA. 1974. Development Document for Effluent Limitations Guidelines and New 

Source Performance Standards for the Steam Electric Power Generating Point Source 

Category. Washington, D.C. (October). DCN SE02917. 

 

25 As described in Section 8, EPA is proposing to exempt from new copper and iron BAT limitations any existing 

discharges of nonchemical metal cleaning wastes that are currently authorized without iron and copper limits. For 

these discharges, BAT limits would be set equal to BPT limits applicable to low volume wastes.
Section 5 – Industry Subcategorization

5-4 

4. 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 SE02933. 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-1 

SECTION 6

WASTEWATER CHARACTERIZATION AND POLLUTANTS OF 

CONCERN 

This section summarizes information gathered from survey data, EPA sampling data, 

Clean Water Act (CWA) 308 sampling data, and industry-submitted sampling data on 

wastewater generation practices associated with the steam electric industry. Sections 6.1 through 

6.6 provide details on only those wastestreams for which EPA evaluated new or revised 

discharge requirements for the proposed ELGs, those discussed in Section 4.3, including flue gas 

desulfurization (FGD) wastewater, ash transport water, combustion residual landfill leachate, 

flue gas mercury control (FGMC) wastewater, gasification wastewater, and metal cleaning 

waste. Each section provides detail on wastewater generation rates and provides characterization 

data for the untreated process wastewater, where available. Section 6.7 identifies the pollutants 

of concern (POCs) related to this rulemaking. 

6.1 FGD WASTEWATER

Wet FGD scrubber systems are classified into two categories, recirculating wet FGD 

systems and single pass wet FGD systems, as shown in Figure 4-7. In a recirculating system, 

most of the FGD slurry at the bottom of the scrubber is recirculated back within the scrubber and 

occasionally a blowdown stream is transferred away from the scrubber, called FGD slurry 

blowdown. The slurry blowdown stream undergoes solid separation and the wastewater is either 

recycled back to the scrubber or transferred to a wastewater treatment system as FGD scrubber 

purge. In a single pass system, all of the FGD slurry at the bottom of the scrubber is leaves the 

scrubber without recirculating the slurry within the system. FGD wastewater can include the 

FGD scrubber purge from a recirculating systems, the FGD slurry from single pass systems, any 

gypsum wash water, and water generated from the solids dewatering process. This section

describes the amount of FGD wastewater generated by FGD systems at coal-fired power plants 

within the steam electric industry and discusses the characteristics of FGD wastewater.

As described in Section 4.3.3, the FGD wastewater generated by wet FGD systems needs 

to be removed to purge chlorides from the system. This FGD wastewater is typically generated 

intermittently. The factors that can affect the characteristics and flow rate of the FGD wastewater 

include the type of coal, scrubber design and operating practices, solids separation process, and 

solids dewatering process used at the plant, which are discussed below.

The type of coal burned at the plant can affect the FGD wastewater flow rate. Generally, 

burning a higher sulfur coal will require a higher FGD wastewater flow from the system. Higher 

sulfur coals produce more sulfur dioxide in the combustion process, which in turn increases the 

amount of sulfur dioxide removed in the FGD scrubber. As a result, more solids are generated in 

the reaction in the scrubber, which increases frequency at which FGD wastewater is removed 

from the system and transferred to treatment.

Likewise, the use of a high chlorine coal can increase the volume and frequency of the 

FGD wastewater generated by the system. Many FGD systems are designed with materials 

resistant to corrosion for specific chloride concentrations. The chlorine present in the coal leads 

to chlorides present in the FGD systems. As the FGD system recirculates the water in the system, 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-2 

the chlorides build up within the scrubber. The plant will have to purge some of the wastewater 

to remove the chlorides from the system as the chloride concentration in the scrubber begins 

approaching the maximum allowable limit for the specific material of construction of the FGD 

system. In the United States, FGD scrubbers are generally constructed of alloys that are designed 

to withstand a chloride concentration of 20,000 parts per million (ppm) or more. The larger the 

maximum allowable chloride concentration in the scrubber, the lower the FGD wastewater flow 

rate; however, this lower purge rate leads to additional cycling in the scrubber, which increases 

the pollutant concentrations in the FGD wastewater [Babcock and Wilcox, 2005].

Table 6-1 summarizes the FGD slurry blowdown generated by the steam electric industry 

in 2009 as reported in the Questionnaire for the Steam Electric Power Generating Effluent 

Guidelines (Steam Electric Survey). On average, a steam electric power plant generates 1.2 

million gallons per day (MGD) of FGD slurry blowdown. As described above, the FGD slurry 

blowdown undergoes dewatering before being transferred to treatment or recycled back to the 

scrubber. 

Table 6-1. FGD Slurry Blowdown Flow Rates 

Number of 

Plants

Average Flow 

Rate

Median Flow 

Rate

Range 

of Flow Rate

Flow Rate per Plant

Gallons per day (gpd)/plant 137 1,220,000 598,000 3,300 – 22,000,000

Source: Steam Electric Survey, [ERG, 2013b].

Note: Flows are rounded to three significant figures.

Note: Two plants are missing data and are therefore not included in the count of plants presented in this table. An 

additional six (6) plants identified plans for a future FGD system that will generate FGD blowdown. These future 

FGD systems are also not included in the count of plants represented in this table.

The pollutant concentrations in FGD wastewater vary from plant to plant depending on 

the coal type, the sorbent used, the materials of construction in the FGD system, the FGD system 

operation, the level of recycle within the absorber, and the air pollution control systems operated 

upstream of the FGD system. The fuel (coal or petroleum coke) is the source of most of the 

pollutants that are present in the FGD wastewater (i.e., the pollutants in the coal are likely to be 

in the FGD wastewater). The sorbent used in the FGD system also introduces pollutants into the 

FGD wastewater and, therefore, the type and source of the sorbent used affects the pollutant 

concentrations in the FGD wastewater.

The materials of construction in the FGD system and the FGD system operation affect the 

types of pollutants in the wastewater, as well as their concentrations. Using organic acid 

additives contributes to higher concentrations of biochemical oxygen demand (BOD5) in the 

FGD wastewater. Additionally, the type of oxidation the FGD system uses (i.e., forced oxidation, 

inhibited oxidation, natural oxidation) can affect the form of the pollutants present in the FGD 

wastewater. According to the Electric Power Research Institute (EPRI), forced oxidation systems 

produce most of the selenium present as selenate (Se+6) whereas natural and inhibited oxidation 

systems produce most of the selenium present as selenite (Se+4) [EPRI, 2006]. The FGD 

wastewater characteristics presented later in this section represent data from plants operating 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-3 

forced oxidation systems. EPA focused the sampling program on plants operating forced 

oxidation systems for the following reasons: 

Most plants operating natural or inhibited oxidations systems do not discharge FGD 

wastewater because they either operate complete recycle systems or because the water is 

evaporated in evaporation ponds or during a pozzolonic reaction. 

Selenate is the form of selenium that is more difficult to treat; therefore, if the technology 

option selected as the basis for the ELGs can remove the selenate, it will also be able to remove 

the selenite. Additionally, the biological treatment process used as the basis for Regulatory 

Options 3 and 4 reduces both selenate and selenite to its elemental form; therefore, the form of 

selenium present in the wastewater does not impact the removals achieved by the preferred 

options. 

The materials of construction and the other FGD system operations can also affect the 

concentration of pollutants in the FGD wastewater because they affect the amount of recycle 

within the system, which in turn, affects the rate at which the FGD wastewater is generated. For 

example, during the detailed study, EPA collected samples from the Tennessee Valley 

Authority’s Widows Creek Fossil Plant (Widows Creek), which operates once-through FGD 

systems. These FGD systems do not cycle the wastewater within the system, thereby generating 

FGD scrubber purge continuously and at a much larger flow rate compared to plants that do 

recirculate the FGD water. However, based on the data collected from the Widows Creek 

sampling episode and the data collected during EPA’s sampling program, the FGD scrubber 

purge that is generated in the once-through systems is at lower concentrations compared to plants 

that recirculate the water. While the concentrations are lower, the concentrations of the pollutants 

of concern are still at treatable levels for the FGD wastewater treatment system. Because of the 

larger flow rate associated with these systems, EPA evaluated costs for these plants to recirculate 

some of the FGD water back to the FGD system, as long as the materials of construction in the 

FGD system would be able to handle the buildup of additional chlorides. For more information 

on this analysis, see Section 4.4.3 of EPA’s Incremental Costs and Pollutant Removals for 

Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category Report. 

The air pollution controls operated upstream of the FGD system can also affect the 

pollutant concentrations in the FGD wastewater. For example, if a plant does not operate a 

particulate collection system (e.g., electrostatic precipitator, or ESP) upstream of the FGD 

system, the FGD system will act as the particulate control system and the FGD blowdown 

exiting the scrubber will contain fly ash and other particulates. As a result, the FGD wastewater

will likely contain increased concentration of pollutants associated with the fly ash, such as 

arsenic and mercury. Based on responses to the Steam Electric Survey, EPA determined that 

there are approximately 15 to 25 coal- and petroleum coke-fired generating units that operate 

without a particulate collection system prior to the FGD system. EPRI collected data from a plant 

that has a generating unit with this configuration as well as a generating unit that operates an 

ESP prior to its FGD system. Using the data from the EPRI report representing the FGD influent 

from these two different units, EPA determined that the concentrations of mercury, nitrate/nitrite, 

and total suspended solids (TSS) are higher in FGD influent for the generating unit that operates 

the ESP; however the concentration of arsenic is higher for the unit without the ESP [EPRI, 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-4 

1998a; EPRI, 1998b].26 However, based on the information from the EPA sampling program, 

EPA determined that arsenic is treated to low levels in the technology selected as the proposed 

FGD wastewater treatment system, regardless of the influent concentrations entering the system.

Research conducted by EPA’s Office of Research and Development (ORD) has observed 

that using postcombustion nitrogen oxide (NOx) controls (e.g., selective catalytic reduction 

(SCR) and selective noncatalytic reduction (SNCR)) is correlated to an increased fraction of 

chromium in coal combustion residues (CCR) (including FGD wastes) being oxidized to 

hexavalent chromium (Cr+6). Hexavalent chromium is a more soluble and more toxic form of 

chromium than the trivalent chromium (Cr+3) usually measured in CCRs. This could explain why 

ORD has observed increased leachability of chromium when postcombustion NOx controls are 

operating [U.S. EPA, 2008]. As part of EPA’s sampling program, it collected samples from four 

plants operating SCRs at the time of the sampling episodes, one plant operating SNCRs at the 

time of the sampling episodes, and two plants that were not operating the SCR/SNCR at the time 

of the sampling episode. EPA compared the influent FGD wastewater characteristics from these 

plants to evaluate whether the operation of the NOx control systems lead to higher concentrations 

of certain pollutants. EPA found that none of the plants had detectable concentrations of 

hexavalent chromium in the influent FGD wastewater samples, except for one of the plants that 

was not operating its SCR/SNCR. Additionally, EPA found that the concentrations of ammonia 

and nitrate/nitrite are not significantly different for the plants operating NOx controls compared 

to the plants not operating NOx controls.27 While the ammonia and nitrate/nitrite concentrations 

were higher for some of the plants operating NOx controls compared to the plants not operating 

NOx controls, there were also plants operating NOx controls that had lower concentrations of 

ammonia and nitrate/nitrite compared to plants not operating NOx controls. 

Table 6-2 summarizes the FGD wastewater discharged by the steam electric industry in 

2009 as reported in the Steam Electric Survey. By January 1, 2014, 117 coal- and petroleum 

coke-fired plants will discharge FGD wastewater.28 Collectively, these plants are expected to 

discharge 23.7 billion gallons of FGD wastewater per year, with an average total industry daily 

discharge of 65 MGD (0.6 MGD per plant). The amount of FGD wastewater discharged by the 

steam electric industry is less than the amount of blowdown generated by the industry, presented 

in Table 6-1, due to plants recycling the blowdown within the FGD scrubber as FGD preparation 

water and in other non-FGD plant processes. Table 6-2 also presents the distribution of FGD 

wastewater discharged based on type of coal used. Based on data from the Steam Electric 

Survey, the highest average discharge of FGD wastewater occurs from plants with FGD systems 

servicing units burning lignite coal.

 

26 The EPRI report does not include data for selenium; therefore, EPA could not evaluate if the selenium 

concentrations are higher with or without an ESP. Regardless, the biological treatment system selected as the 

proposed FGD wastewater treatment technology is capable of removing selenium, even at high concentrations.

27 EPA evaluated the ammonia and nitrate/nitrite concentrations because ammonia is injected into the flue gas as 

part of the operation of the SCR/SNCR operation; therefore, EPA had hypothesized that there might be higher 

concentrations of these pollutants in the FGD wastewater for plants operating these systems.

28 By January 1, 2014, EPA estimates that there will be approximately 145 plants generating FGD wastewater from 

wet FGD systems; however, only 117 of these plants will discharge to a surface water or POTW.
Section 6 – Wastewater Characterization and Pollutants of Concern

6-5 

Table 6-2. FGD Wastewater Discharge at Steam Electric Power Plants by January 1, 2014 

Number of Plants

Discharging

Total Discharged FGD 

Wastewater Flow

(gpd)

Average Discharged FGD 

Wastewater Flow

(gpd/plant)

Total 117 65,000,000 559,000

Coal Type a

Bituminous 68 41,000,000 600,000

Subbituminous 15-20 5,000,000 275,000

Lignite 1-5 4,000,000 800,000

Petroleum Coke 1-5 15,000 3,000

Blend b 23-28 15,400,000 620,000

Source: Steam Electric Survey, [ERG, 2013b].

Note: Wastewater flow rates are rounded to three significant figures.

Note: The FGD wastewater flow was estimated for 27 plants. Details on the methodology for estimating FGD 

wastewater flow rates are provided in EPA’s Incremental Costs and Pollutant Removals for Proposed Effluent 

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

SE01957).

a – Coal type classification is based on the types of coal burned in the units serviced by the wet FGD systems at each 

plant.

b – Plants operating wet FGD systems servicing units that burn two or more different coal types are classified as 

'blend'.

EPA collected data as part of its sampling program, described in Section 3.4, to 

characterize the FGD wastewater from steam electric power plants. EPA’s Office of Water (OW) 

also collected additional self-monitoring data from Duke Energy Carolinas’ Belews Creek and 

Allen Steam Stations and Progress Energy Carolinas’ Roxboro Steam Electric Plant. EPA used 

its sampling data and plant self-monitoring data to characterize the untreated FGD wastewater 

generated by the steam electric industry. Table 6-3 presents the average pollutant concentrations 

of the influent to the FGD wastewater treatment systems (i.e., downstream of the solids 

separation/solids dewatering processes). As shown in the table, FGD wastewater contains 

significant concentrations of chloride, total dissolved solids (TDS), nutrients, and metals, 

including bioaccumulative pollutants such as arsenic, mercury, and selenium. Some metals, such 

as boron, magnesium, manganese, and sodium, are largely present in the dissolved phase. 

Table 6-3. Average Pollutant Concentrations in Untreated FGD Wastewater

Analyte Unit Average Total Concentration

Classicals

Ammonia mg/L 6.35

Nitrate Nitrite as N mg/L 74.9

Nitrogen, Total Kjeldahl mg/L 39.6

Biochemical Oxygen Demand mg/L 9.38

Chemical Oxygen Demand mg/L 367

Chloride mg/L 7,740
Section 6 – Wastewater Characterization and Pollutants of Concern

6-6 

Table 6-3. Average Pollutant Concentrations in Untreated FGD Wastewater

Analyte Unit Average Total Concentration

Sulfate mg/L 8,140

Cyanide, Total mg/L 0.764

Total Dissolved Solids mg/L 28,600

Total Suspended Solids mg/L 16,800

Phosphorus, Total mg/L 3.19

Analyte Unit

Average Total 

Concentration

Average Dissolved 

Concentration

Metals

Aluminum ug/L 332,000 37,200

Antimony ug/L 22 6

Arsenic ug/L 489 10

Barium ug/L 2,850 321

Beryllium ug/L 17 3

Boron ug/L 291,000 266,000

Cadmium ug/L 159 128

Calcium ug/L 3,250,000 2,100,000

Chromium ug/L 1,300 380

Chromium (VI) ug/L NA 5

Cobalt ug/L 310 225

Copper ug/L 784 88

Iron ug/L 764 52,600

Lead ug/L 323 6

Magnesium ug/L 3,630,000 3,400,000

Manganese ug/L 107,000 106,000

Mercury ug/L 411 78

Molybdenum ug/L 313 185

Nickel ug/L 1,880 1,230

Selenium ug/L 4,490 1,980

Silver ug/L 9 1

Sodium ug/L 275,000 265,000

Thallium ug/L 27 16

Tin ug/L 184 130

Titanium ug/L 4,840 734

Vanadium ug/L 1,450 18

Zinc ug/L 5,380 2,290

Source: EPA Sampling Data, [ERG, 2012a – 2012g];Progress Energy Data, [NCDENR, 2011]; Duke Energy Data, 

[Duke Energy, 2011a-2011b].

NA – Not applicable. Samples were not analyzed for this particular analyte.

Note: Concentrations are rounded to three significant figures.
Section 6 – Wastewater Characterization and Pollutants of Concern

6-7 

As indicated in Table 6-2, 117 plants discharge FGD wastewater. More than half (54 

percent) of the 117 plants that discharge FGD wastewater use surface impoundments to treat the 

FGD wastewater prior to discharging it to a surface water or publicly owned treatment works 

(POTW). Surface impoundments are designed to remove particulates from wastewater by means 

of gravity. The use of more advanced wastewater treatment systems, such as chemical 

precipitation and biological treatment, is increasing to a limited extent due to more stringent 

effluent limit requirements some states have imposed on a site-specific basis. Figure 6-1 shows 

the distribution of FGD wastewater treatment systems currently used in the steam electric 

industry. All 117 steam electric power plants discharging FGD wastewater by January 1, 2014 

are represented in the figure. Based on information provided in the Steam Electric Survey, EPA 

classified each plant’s FGD wastewater treatment system based on the highest level of treatment 

into the following hierarchy: surface impoundment; any type of chemical precipitation system; a 

biological treatment system (either anoxic or anaerobic); or other.29 Section 7 provides more 

detail on the variety of FGD wastewater treatment technologies currently used in the steam 

electric industry.

Source: Steam Electric Survey., [ERG, 2013b]

Figure 6-1. Distribution of FGD Wastewater Treatment Systems among the 117 

Plants Discharging FGD Wastewater by January 1, 2014 

 

29 ‘Other’ refers to some level of FGD wastewater treatment beyond a surface impoundment, but not classified as 

either a chemical precipitation system or biological treatment systems. Those types of systems classified as ‘other’ 

include, but are not limited to, constructed wetlands, aerobic biological reactors, vapor-compression evaporation, ion 

exchange, and resin absorption.
Section 6 – Wastewater Characterization and Pollutants of Concern

6-8 

6.2 ASH TRANSPORT WATER

As described in Section 4.3, plants often use water to remove fly and bottom ash from the 

particulate removal systems and boiler, respectively. This ash transport water can be reused as 

ash transport water or sent to treatment, typically in an on-site impoundment, and then 

discharged. This section presents an overview of the amount of fly ash and bottom ash transport 

water generated at coal-fired power plants within the steam electric industry. This section also 

discusses the characteristics of fly ash and bottom ash transport water and the amount of ash 

transport water that is discharged to surface water.

6.2.1 Fly Ash Transport Water 

Fly ash transport water is one of the largest flows generated at coal-fired power plants. 

Many of the large baseload units generate enough fly ash that they operate fly ash transport water 

systems continuously, while some smaller units and peaking units typically generate less fly ash, 

and therefore, may operate fly ash transport water systems intermittently.30,31 Table 6-4 presents 

the fly ash transport water flow rates generated by plants. The fly ash transport water flow rate is 

the flow rate of the fly ash transport water from the sluicing system to the impoundment, and 

does not necessarily represent the fly ash discharge flow rate from the plant. The industry 

generated 128 billion gallons of fly ash transport water in 2009, with the average plant 

generating 4.2 MGD.

Table 6-4. Fly Ash Transport Water Flow Rates

Flow Rate 

per Plant Number of Plantsa Average Flow Rate Median Flow Rate Range of Flow Rate

gpm/plant 137 5,980 2,730 10 – 226,000

gpd/plant 137 4,230,000 2,140,000 4,000 – 35,700,000

gpy/plant 137 953,000,000 389,000,000 80,000 – 9,200,000,000

Source: Steam Electric Survey. [ERG, 2013b].

Note: Wastewater flow rates are rounded to three significant figures.

Note: The number of plants generating transport water are based on values reported in the Steam Electric Survey, 

which were scaled to represent the industry as a whole using the industry-weighting factors discussed in Section 3.3. 

a - A total of 141 plants wet sluiced fly ash in 2009. Four plants did not provide sufficient data to determine the 

plant-level fly ash transport water flow rate.

6.2.2 Bottom Ash Transport Water 

Bottom ash transport water is an intermittent stream from steam electric units. The 

bottom ash transport water flow rates are typically not as large as the fly ash transport water flow 

rates. However, bottom ash transport water is still one of the larger volume wastestreams for 

steam electric power plants. Table 6-5 presents the bottom ash transport water flow rates 

 

30 A baseload unit is defined as a unit normally operating to produce electricity at an essentially constant rate. The 

unit will typically run for extended periods of time.

31 A peaking unit is defined as a unit normally used only during peak-load periods of electricity demand or to 

replace the loss of another generating unit.
Section 6 – Wastewater Characterization and Pollutants of Concern

6-9 

reported by the industry. The bottom ash transport water flow rate is the flow rate of the bottom 

ash transport water from the sluicing system to the impoundment, and does not necessarily 

represent the bottom ash discharge flow rate from the plant. While there are significantly more 

plants producing bottom ash transport water than those producing fly ash transport water, the 

average daily flow rate per plant is 40 percent less than the average fly ash transport water flow 

rate presented in Table 6-4. The industry generated 255 billion gallons of bottom ash transport 

water in 2009, with the average plant generating 2.5 MGD. 

Table 6-5. Bottom Ash Transport Water Flow Rates 

Flow Rate 

per Plant Number of Plantsa Average Flow Rate Median Flow Rate Range of Flow Rate

gpm/plant 327 6,200 3,310 2 - 119,000

gpd/plant 328 2,490,000 1,020,000 3,200 – 34,600,000

gpy/plant 326 785,000,000 296,000,000 608,000 - 10,800,000,000

Source: Steam Electric Survey, [ERG, 2013b].

Note: Wastewater flow rates are rounded to three significant figures.

Note: The number of plants generating transport water are based on values reported in the Steam Electric Survey, 

which were scaled to represent the industry as a whole using the industry-weighting factors discussed in Section 3.3. 

a – The number of plants listed indicate the total number of plants providing sufficient data to determine the bottom 

ash transport water flow rate. In 2009, 346 plants wet sluiced bottom ash but not all plants provided transport water 

flow rate information.

6.2.3 Ash Transport Water Characteristics

Fly ash and bottom ash transport water are typically treated in large surface impoundment

systems. Plants operating both wet fly ash and wet bottom ash handling systems often 

commingle the two transport water streams, along with other wastestreams, within the same 

surface impoundment system. Plants operating only one wet ash handling system (e.g., fly ash or 

bottom ash, but typically bottom ash) may treat the ash transport water in surface impoundments, 

which often receive other plant wastewaters. Some plants recycle part or all of the impoundment 

effluent, but most plants discharge this impoundment overflow. Untreated ash transport waters 

contain significant concentrations of TSS and metals. The effluent from ash impoundments 

generally contains low concentrations of TSS; however, metals are still present in the 

wastewater, predominantly in dissolved form. 

Impoundments are designed to remove particulates from wastewater by gravity. The fly 

ash, bottom ash, and other solids (e.g., FGD solids) settle out of the wastewater to the bottom of 

the impoundment. To accomplish this, the wastewater must reside in the impoundment long 

enough to settle the desired particle size. Impoundments can effectively reduce TSS in ash 

transport water, particularly bottom ash transport water, which contains relatively dense ash 

particles. Because impoundments remove solid particulates, they may also effectively remove 

some metals from fly ash transport water when the metals are present in suspended particulate 

form.

Impoundment overflow or discharge flow rates are not the same as ash transport water 

flow rates. The ash transport water flow rate is the flow rate of the transport water from the 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-10 

sluicing system to the impoundment, while the impoundment overflow or discharge flow is the 

flow rate of the water that is leaving the impoundment (e.g., discharged, recycled). 

Impoundments typically receive wastestreams in addition to bottom ash and fly ash (e.g., boiler 

blowdown, cooling water, low volume wastewater). In addition, there are factors acting to reduce 

the impoundment overflow rate, including impoundment losses from infiltration through the 

bottom of the impoundment or retaining dikes, evaporation, and amount of recycle from the 

impoundment back to the plant for reuse. Table 6-6 presents the amount of fly ash and bottom 

ash wastewater discharged in 2009, whereas Table 6-4 and Table 6-5 present the fly ash and 

bottom ash transport water generation flow rates. On average, a single plant discharges 

approximately 2.4 MGD of fly ash transport water and approximately 1.8 MGD of bottom ash 

transport water. Therefore, on average, the Steam Electric Category discharges approximately 57 

percent of all fly ash transport water generated and 71 percent of all bottom ash transport water 

generated. Section 7 discusses various impoundment management practices in place in the 

industry. 

Table 6-6. Ash Wastewater Discharge at Steam Electric Power Plants

Type of Wastewater

Number of Plants 

Discharging

Total Wastewater 

Discharged 

(2009, million gallons/year)

Average Wastewater 

Discharge Flow Rate

(gpd/plant)

Fly Ash 95 81,100 2,390,000

Bottom Ash 245 157,000 1,760,000

Source: Steam Electric Survey, [ERG, 2013b]. 

Note: The number of plants and discharge flow rates in the steam electric industry are based on values reported in 

the Steam Electric Survey, which were scaled to represent the industry as a whole using the industry-weighting 

factors discussed in Section 3.3. 

Note: 76 plants combine their fly and bottom ash sluice streams into one impoundment or impoundment system, 

identified as a combined ash impoundment. All 76 plants discharging combined ash wastewater were included in the 

table and counted as both fly ash and bottom ash dischargers. For these plants, a median percentage of total sluice 

flow for both fly and bottom ash sluice was calculated and used to calculate a fly and bottom ash contribution for all 

combined ash wastewater flows. The median fly ash wastewater contribution is 61.1 percent and the median bottom 

ash contribution is 38.9 percent.

Note: Wastewater flow rates are rounded to three significant figures.

The design, operation, and maintenance of impoundments in the steam electric industry 

varies by plant/company. As described above, impoundments are designed to remove TSS; 

therefore, the size of the impoundment depends upon the combined flow rate of the influent 

wastestreams, as well as the settling properties of the solids in the wastestreams. Some plants 

may add chemicals to the impoundments effluent to control the pH of the discharge. The current 

Steam Electric Power Generating ELGs limit the pH of discharged wastestreams to a range of 

6.0 to 9.0 S.U. Common chemicals used to control the pH in impoundments are sodium 

hydroxide and hydrochloric acid. 

EPA did not collect data representing fly ash or bottom ash transport water entering an 

impoundment during the sampling program for the rulemaking. However, during EPA’s detailed 

study of the industry, EPA collected a wastewater sample representing the influent to a fly ash 

impoundment; the analytical results are presented in Table 4-18. Based on these samples, fly ash 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-11 

transport water contains significant concentration of metals, including arsenic, calcium, and 

titanium. Some metals are primarily present in the dissolved phase, such as boron, molybdenum, 

and selenium. 

Table 6-7. Fly Ash Transport Water Characteristics

Analyte Unit Average Concentration

Classicals

Ammonia As Nitrogen (NH3-N) mg/L 0.17

Nitrate/Nitrite (NO3-N + NO2-N) mg/L 2.65

Total Kjeldahl Nitrogen (TKN) mg/L 1.01

Biochemical Oxygen Demand (BOD) mg/L ND (2.00)

Chloride mg/L 56.8

Hexane Extractable Material (HEM) mg/L 7.00

Silica Gel Treated HEM (SGT-HEM) mg/L 6.00

Sulfate mg/L 1,110

Total Dissolved Solids (TDS) mg/L 662

Total Phosphorus mg/L 4.03

Total Suspended Solids (TSS) mg/L 23,400

Analyte Unit

Average Total 

Concentration

Average Dissolved 

Concentration

Metals (EPA Method 200.7)

Aluminum μg/L 320,000 283

Antimony μg/L ND (81.2) ND (20.0)

Arsenic μg/L 1,520 86.8

Barium μg/L 5,060 164

Beryllium μg/L 71.5 ND (5.00)

Boron μg/L 2,790 1,380

Cadmium μg/L 39.6 ND (5.00)

Calcium μg/L 204,000 94,800

Chromium μg/L 1,300 ND (10.0)

Chromium (VI) μg/L NA 5.00

Cobalt μg/L 381 ND (50.0)

Copper μg/L 964 ND (10.0)

Iron μg/L 298,000 ND (100)

Lead μg/L 786 ND (50.0)

Magnesium μg/L 35,100 15,200

Manganese μg/L 1,120 40.3

Mercury μg/L 2.31 ND (0.200)

Molybdenum μg/L 333 243

Nickel μg/L 739 ND (50.0)

Selenium μg/L ND (20.3) 16.6

Sodium μg/L 69,900 64,400
Section 6 – Wastewater Characterization and Pollutants of Concern

6-12 

Table 6-7. Fly Ash Transport Water Characteristics

Analyte Unit Average Concentration

Thallium μg/L ND (40.6) ND (10.0)

Titanium μg/L 24,900 ND (10.0)

Vanadium μg/L 2,340 70.7

Yttrium μg/L 521 ND (5.00)

Zinc μg/L 1,220 ND (10.0)

Metals (EPA Method 1638, 1631E)

Antimony μg/L 33.1 17.4

Arsenic μg/L 519 80.7

Cadmium μg/L 9.51 ND (1.00)

Chromium μg/L 569 ND (80.0)

Chromium (VI) μg/L NA NA

Copper μg/L 719 ND (20.0)

Lead μg/L 260 ND (0.500)

Mercury μg/L 1.16 0.00055

Nickel μg/L 291 ND (100)

Selenium μg/L ND (200) 21.2

Thallium μg/L 43.6 3.1

Zinc μg/L 720 ND (50.0)

Source: Cardinal SER, [ERG, 2008].

NA – Not applicable. No data for this analyte were available specific to the impoundment type.

ND – Not detected (number in parenthesis is the reporting limit). The sampling episode report for the plant contains 

additional sampling information, including analytical results for analytes measured above the detection limit, but 

below the reporting limit (i.e., J-values).

Note: Concentrations are rounded to three significant figures.

6.3 COMBUSTION RESIDUAL LANDFILL AND IMPOUNDMENT LEACHATE

As discussed earlier, plants generating FGD wastewater and ash transport water generally 

send the wastewater to a surface impoundment or wastewater treatment system. Solids resulting 

from FGD wastewater treatment system are typically transferred to a landfill for disposal. The 

FGD solids and ash sent to the surface impoundments may be stored permanently in the 

impoundment or dredged from the impoundment and transferred to a landfill. Additionally, 

plants may place dry ash, both fly ash and bottom ash, and FGD residuals (i.e., gypsum or 

calcium sulfite) in a landfill. These combustion residuals stored in the landfills and 

impoundments can contaminate the water that contacts the residuals in these management units. 

As discussed in Section 4.3.5, leachate is the liquid that drains or leaches from a landfill or 

impoundment. Leachate, which includes contaminated stormwater, that has come into contact 

with combustion residual solids deposited in an impoundment or a landfill, contains heavy 

metals and other contaminants. The following section describes the amount of leachate estimated 

to be generated by the steam electric industry and the characteristics of these wastestreams.
Section 6 – Wastewater Characterization and Pollutants of Concern

6-13 

EPA’s Steam Electric Survey included a section, Part F, that requested information on the 

management practices of both impoundments and landfills containing combustion residuals. Part 

F of the survey included questions related to the collection and treatment of leachate from both 

types of management units. As described in Section 3.3, EPA sent Part F only to a statistically 

sampled stratum of coal- and petroleum coke-fired plants (97 plants). EPA used the responses to 

Part F of the survey along with the appropriate survey weights for Part F to estimate the number 

of plants in the industry generating leachate from impoundments and landfills containing 

combustion residuals. Table 6-8 presents the estimated number of plants generating leachate in 

the steam electric industry from either an impoundment or a landfill. Based on the reported 

leachate generation rates and the survey weights for Part F, EPA estimates that the steam electric 

industry generates approximately 6.6 billion gpy of combined impoundment and landfill 

leachate.

Table 6-8. Leachate Generation in the Steam Electric Industry

Type of 

Wastewater

Management Unit 

Status

Number of 

Plants

Total Wastewater Generated

(2009, million gallons/year)

Average Wastewater 

Generation Rate

(gpd/plant)

Total Landfill 

Leachate a

Total 92 b 2,210 60,400

Active/Inactive 84 2,200 65,500

Planned 1 2 6,220

Retired 5-10 17 5,950

Total Impoundment

Leachate c Total 66 4,000 236,000

Source: Steam Electric Survey, [ERG, 2013b]. 

Note: Wastewater flow rates are rounded to three significant figures.

Note: Part F of the Steam Electric Survey was distributed to 97 plants. The responses from these plants were 

weighted to reflect the portion of plants generating leachate in the industry. Weighted, these 97 plants represent 384 

coal- and petroleum coke-fired stream electric plants.

Note: The number of plants generating leachate are based on values reported in the Steam Electric Survey, which 

were scaled to represent the industry as a whole using the industry-weighting factors discussed in Section 3.3.Note: 

For presentation purposes, EPA used leachate generation from the Steam Electric Survey reported in gpy to 

calculate the total wastewater generated in 2009. Leachate flow can fluctuate significantly from day to day based on 

rainfall; therefore, EPA believes it is more appropriate to use the values estimated by the plants instead of using the 

average gpd and number of days generating leachate to calculate the yearly flow. To calculate the average 

wastewater generation rate, EPA used leachate generation reported in gpd as a rough estimate of the average 

leachate generation per day.

a – Eighteen (18) plants reported operating a leachate collection system but did not provide the amount of leachate 

collected in 2009. These plants are not included in the number of plants or used when calculating the average 

wastewater generated in Table 6-8. 

b – The number of plants in each landfill status category is not additive. Some plants may operate more than one 

landfill, each with a different status (active/inactive, retired, or planned).

c – Nine plants reported operating a leachate collection system but did not provide the amount of leachate collected 

in 2009. These plants are not included in the number of plants or used when calculating the average wastewater 

generated in Table 6-8. All impoundment leachate reported in the survey is from active/inactive impoundments (i.e., 

plants did not report leachate from closed/retired impoundments).
Section 6 – Wastewater Characterization and Pollutants of Concern

6-14 

The leachate collected from impoundments/landfills is generally transferred to a 

collection impoundment. The effluent from these collection impoundments can be discharged, 

sent to a holding impoundment, or sent to further treatment such as a constructed wetland 

system. Only a small percentage of the leachate collected from combustion residual 

impoundments/landfills is treated by means other than a surface impoundment: 9 percent of 

impoundment leachate and 24 percent of landfill leachate. Section 7.4 provides more detail on 

the types of leachate treatment technologies [ERG, 2013b]. 

As discussed previously in Section 4.3.5, nearly 50 percent of impoundment leachate 

generated in the industry is returned directly to the impoundment (or recycled within the plant). 

An additional 9 percent is treated on site in some fashion prior to being discharged. Forty-one 

percent of plants discharge leachate from impoundments without any further treatment. 

The majority of landfill leachate is discharged to surface water without prior treatment 

(68 percent of landfills generating leachate). As shown in Table 4-15, the remaining 32 percent 

of landfills return the leachate back to the landfill or treat the leachate on site prior to discharge. 

Table 6-9 presents the number of coal- and petroleum coke-fired plants that discharging landfill 

leachate in 2009. The table separates the amount of leachate discharged by active or inactive 

landfills from the amount discharged by retired landfills. Data from the Steam Electric Survey 

indicate a significant difference between the amount of leachate discharged by landfills classified 

as active or inactive and the amount discharged by landfills classified as retired. The survey 

defined a retired landfill as a landfill that will never accept additional waste and an inactive 

landfill as a landfill that is currently not receiving waste, but might in the future. Retired landfills 

likely discharge less leachate compared to active and inactive landfills because many retired 

landfills are partially or completely capped/covered, thereby reducing the amount of precipitation 

entering the landfill.

Table 6-9. Landfill Leachate Discharged by Coal- and Petroleum Coke-Fired 

Power Plants in 2009 

Type of Wastewater

Number 

of 

Plants

Total Wastewater 

Discharged 

(2009, million gallons/year)

Average Wastewater 

Flow Rate

(gpd/plant)

Active/Inactive Landfill Leachate 100-105 2,200 54,000

Retired Landfill Leachate 5-10 17 6,180

Source: Steam Electric Survey, [ERG, 2013b]. 

Note: Ranges are provided to protect CBI data. Wastewater flow rates are rounded to three significant figures.

Note: The number of plants and discharge flow rates in the steam electric industry are based on values reported in 

the Steam Electric Survey, which were scaled to represent the industry as a whole using the industry-weighting 

factors discussed in Section 3.3. 

As part of the Steam Electric Survey, EPA requested that a subset of plants provide 

sampling data for leachate collected at the plant. EPA used these data to characterize the 

untreated landfill leachate discharged by the steam electric industry. In response to the survey, 

EPA obtained sampling data from 22 active fuel combustion residual landfills, four inactive fuel 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-15 

combustion residual landfills, and seven retired landfills. Table 6-10 presents the average 

pollutant concentration for each type of landfill. Combustion residual landfill leachate contains 

high concentration of metals, such as boron, calcium, chloride, and sodium, similar to FGD and 

ash wastewaters. The metals in the leachate are generally at lower concentrations than those seen 

in FGD wastewater and ash transport water, but still at treatable levels above the quantitation 

limit. As expected, the leachate from active landfills generally has larger concentrations of 

metals compared to inactive and retired landfills.

Table 6-10. Untreated Landfill Leachate Concentrations 

Analyte Units

Untreated Active 

Landfill 

Concentration

Untreated Inactive 

Landfill 

Concentration

Untreated Retired 

Landfill 

Concentration

Classicals

Chloride ug/L 542,000 11,100 149,000

Sulfate ug/L 1,910,000 1,070,000 881,000

TDS ug/L 3,860,000 1,670,000 1,660,000

TSS ug/L 41,400 4,210 13,800

Metals

Aluminum ug/L 5,030 100 87

Antimony ug/L 4.6 4.9 1.1

Arsenic ug/L 46 10 41

Barium ug/L 57 50 37

Beryllium ug/L 1.9 0.47 1.1

Boron ug/L 20,500 3,640 10,100

Cadmium ug/L 2.7 1.9 0.73

Calcium ug/L 481,000 386,000 303,000

Chromium ug/L 4.9 1.6 3.4

Cobalt ug/L 84 3.8 7.6

Copper ug/L 10 1.7 2.4

Iron ug/L 59,000 95 5,700

Lead ug/L 1.4 0.47 0.83

Magnesium ug/L 115,000 33,700 21,800

Manganese ug/L 4,360 355 1,280

Mercury ug/L 1.4 0.01 13

Molybdenum ug/L 1,880 995 702

Nickel ug/L 69 43 16

Selenium ug/L 74 84 46

Silver ug/L 0.68 0.42 1.03

Sodium ug/L 327,000 16,700 66,200

Thallium ug/L 1.3 0.96 0.92

Tin ug/L 11 13 33

Titanium ug/L 17 15 11

Vanadium ug/L 3,240 6.2 69
Section 6 – Wastewater Characterization and Pollutants of Concern

6-16 

Table 6-10. Untreated Landfill Leachate Concentrations 

Analyte Units

Untreated Active 

Landfill 

Concentration

Untreated Inactive 

Landfill 

Concentration

Untreated Retired 

Landfill 

Concentration

Zinc ug/L 154 58 38

Source: Steam Electric Survey, [ERG, 2013b].

Note: Concentrations are rounded to three significant figures.

In response to the survey, EPA obtained sampling data from 20 leachate impoundments. 

Table 6-11 presents the average pollutant concentration for the 20 impoundments. Combustion 

residual impoundment leachate contains high concentrations of metals, such as calcium, chloride, 

and sodium, similar to FGD and ash wastewaters. The metals present in the leachate are 

generally at lower concentrations than those seen in FGD wastewater and ash transport water, 

but still at treatable levels above the quantitation limit.

Table 6-11. Untreated Impoundment Leachate Concentrations

Analyte Units Average Untreated Impoundment Concentration

Classicals

Chloride ug/L 251,000

Sulfate ug/L 1,242,000

Total Dissolved Solids ug/L 2,380,000

Total Suspended Solids ug/L 9,230

METALS

Aluminum ug/L 213

Antimony ug/L 0.96

Arsenic ug/L 20

Barium ug/L 55

Beryllium ug/L 0.51

Boron ug/L 22,800

Cadmium ug/L 5.1

Calcium ug/L 291,000

Chromium ug/L 1.8

Cobalt ug/L 8.1

Copper ug/L 2.7

Iron ug/L 7,070

Lead ug/L 0.51

Magnesium ug/L 123,000

Manganese ug/L 2,170

Mercury ug/L 0.19

Molybdenum ug/L 208

Nickel ug/L 21

Selenium ug/L 152
Section 6 – Wastewater Characterization and Pollutants of Concern

6-17 

Table 6-11. Untreated Impoundment Leachate Concentrations

Analyte Units Average Untreated Impoundment Concentration

Silver ug/L 0.63

Sodium ug/L 145,000

Thallium ug/L 0.67

Tin ug/L 105

Titanium ug/L 7.1

Vanadium ug/L 3.9

Zinc ug/L 301

Source: Steam Electric Survey, [ERG, 2013b].

Note: Concentrations are rounded to three significant figures.

6.4 FLUE GAS MERCURY CONTROL WASTEWATER

As described in Section 4.3.4, there are two types of systems used for FGMC: addition of 

oxidizers to the coal prior to combustion and injection of activated carbon into the flue gas, after 

combustion. Adding the oxidizers does not generate a new wastewater stream, but it may 

increase the concentration of mercury in the FGD wastewater because the oxidized mercury is 

more easily removed by the FGD system. Activated carbon injection (ACI) systems, however, 

have the potential to generate a new wastestream, depending on the location of the injection. If 

the injection occurs upstream of the primary particulate removal system, then the mercurycontaining carbon (i.e., FGMC waste) will be collected and handled the same way as the fly ash; 

therefore, if the fly ash is wet sluiced, then the FGMC wastes are also wet sluiced. When the 

activated carbon is injected downstream of the primary particulate removal system, the FGMC 

waste must be collected in a separate particulate removal system, typically a fabric filter 

baghouse. Residual fly ash that passes through the primary particulate removal system may also 

be captured.

The FGMC waste/fly ash can either be handled using a wet sluicing system or handled in 

a dry fashion. There are 15 plants with at least one ACI system injecting carbon downstream of 

the primary particulate removal system. Six of these plants identified the FGMC system as 

planned, with an installation date after 2009. Of these fifteen plants, only one plant plans to 

handle the FGMC waste using a wet sluicing system; however, this plant will send the FGMC 

transport water to a zero discharge impoundment, where the impoundment overflow will be 

reused for fly ash, bottom ash, and FGMC transport water. EPA does not have any sampling data 

on wastewater characteristics of the FGMC transport water or the characteristics of FGMC waste 

[ERG, 2013b]. 

For ACI systems in which the carbon is injected upstream of the primary particulate 

control system, the FGMC waste is collected with fly ash. Again, this can be handled either wet 

or dry, depending on how the plant is handling the fly ash. There are 58 plants with at least one 

ACI system injecting carbon upstream of the primary particulate system. Fourteen of these plants 

identified the FGMC system as planned, with an installation date after 2009. Of these 58 plants, 

five (three with current systems and two with planned systems) reported handling the FGMC 

waste using a wet sluicing system. EPA does not have any sampling data on the wastewater 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-18 

characteristics of the FGMC transport water associated with these wet systems; however, ORD 

evaluated the effects of these ACI systems on the characteristics of fly ash and determined that 

these systems substantially increase the total mercury content of the fly ash [U.S. EPA, 2006]. 

EPA does not have any sampling data demonstrating how the added mercury in the fly ash 

affects the characteristics of the fly ash transport water.

ORD looked at six plants, four operating ACI systems and two operating brominated ACI 

systems.32 ORD collected fly ash from these plants, with and without FGMC waste, and 

analyzed the fly ash for mercury, arsenic, and selenium. ORD concluded that, of the three 

constituents analyzed, FGMC waste significantly affects only the mercury concentration of fly 

ash. Five of the six plants showed an increase in the mercury concentration of fly ash with 

FGMC waste as compared to fly ash alone [U.S. EPA, 2006]. Table 6-12 shows the distribution 

of mercury concentrations at each of the six plants.

Table 6-12. Mercury Concentrations in Fly Ash with and without ACI Systems

Plant

Mercury (EPA Method 3052) Mercury (EPA Method 7473)

Fly Ash Only 

(ng/g)

With ACI 

(ng/g)

Percent 

Increase

Fly Ash Only 

(ng/g)

With ACI 

(ng/g)

Percent 

Increase

Brayton Point 651 1,530 135% 582 1,414 143%

Pleasant Prairie 158 1,180 648% 147 1,177 701%

Salem Harbor 529 412 -22% 574 454 -21%

Facility C 16 1,151 7,094% 11 1,090 9,810%

St. Clair a 111 1,163 949% NT NT NA

Facility L (Run 1) a 13 38 190% NT NT NA

Facility L (Run 2) a 20 71 252% NT NT NA

Source: [U.S. EPA, 2006]

Note: ORD analyzed mercury using two different analytical methods, EPA Method 3052 and EPA Method 7473. 

Both results are shown in the table.

NT – Not tested.

NA – Not applicable.

a – Plant operates a brominated activated carbon injection system.

6.5 GASIFICATION WASTEWATER

As discussed in Section 4.3.6, the gasification process creates a number of different 

wastewater streams, some of which are specific to the integrated gasification combined cycle 

(IGCC) process (e.g., air separation unit blowdown) and others that are similar to general power 

plant wastewaters (e.g., cooling water). The IGCC-specific wastewaters are generally combined, 

sometimes along with other plant wastewaters, and collectively referred to as grey water or sour 

water. The sour water is sent to a steam stripper, sometimes called a sour water treatment unit, 

which essentially distills the wastewater and produces a sweet water stream and recycle slurry 

 

32 The chloride content of flue gas can affect the performance of activated carbon systems, low chloride 

concentrations can yield low mercury removal. Some plants with low chloride levels utilize brominated activated 

carbon as a sorbent to increase the amount of mercury captured [U.S. EPA, 2006]. 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-19 

stream that is reused in slurry preparation. Figure 4-4 depicts the general process flow diagram 

for the IGCC process. Although it has been treated by steam stripping, the sweet water stream is 

still contaminated with elements from the gasification process, such as selenium, chromium, and 

arsenic. The sweet water may also be contaminated with various other metals formed in the 

gasification unit, such as selenocyanate. These metals are not known to be generated in 

traditional coal-fired boilers.

EPA collected data as part of the CWA 308 monitoring program described in Section 

3.4.1 from two plants operating IGCC systems. Both plants, Tampa Electric Company’s Polk 

Station (Polk) and Wabash Valley Power Association’s Wabash River Station (Wabash River), 

treat their gasification wastewater with a vapor-compression evaporation system. Both plants 

sampled the influent streams transferred to the vapor-compression evaporation system and the 

distillate/condensate(s) from the systems. EPA used the data from both plants to characterize 

untreated gasification wastewater. Table 6-13 presents the average concentrations of the 

untreated gasification wastewater. The table provides the individual average concentrations for 

the two plants, as well as the average for both plants combined. For both plants, the gasification 

wastewater represents a combination of multiple wastestreams, but because the plants operate 

slightly different processes, they are not the same wastestreams at both plants.

Table 6-13. Untreated Gasification Wastewater Concentrations

Analyte Units

Polk 

Concentration

Wabash River 

Concentration

Average Polk and

Wabash River 

Concentration

Classicals

Ammonia mg/L 175 35 105

Nitrate Nitrite as N mg/L 0.09 0.05 0.07

Nitrogen, Kjeldahl mg/L 603 65 334

Biochemical Oxygen Demand mg/L 7.7 205 106

Chemical Oxygen Demand mg/L 101 823 462

Chloride mg/L 1,300 1,050 1,175

Sulfate mg/L 2,750 11 1,380

Total Dissolved Solids mg/L 4,575 4,225 4,400

Total Suspended Solids mg/L 16 2.0 8.9

Phosphorus, Total mg/L 0.47 0.19 0.33

Metals

Aluminum ug/L 11,475 100 5,788

Antimony ug/L 363 1.0 182

Arsenic ug/L 280 4 142

Barium ug/L 118 10 64

Beryllium ug/L 14 1.0 7.3

Boron ug/L 38,250 34,750 36,500

Cadmium ug/L 4.1 2.0 3.0

Calcium ug/L 19,450 783 10,116

Chromium ug/L 4.0 4.0 4.0
Section 6 – Wastewater Characterization and Pollutants of Concern

6-20 

Table 6-13. Untreated Gasification Wastewater Concentrations

Analyte Units

Polk 

Concentration

Wabash River 

Concentration

Average Polk and

Wabash River 

Concentration

Cobalt ug/L 10 10 10

Copper ug/L 2.0 2.0 2.0

Cyanide, Total mg/L 1.4 2.3 1.8

Iron ug/L 2,115 1,140 1,628

Lead ug/L 18 1.0 10

Magnesium ug/L 5,325 200 2,763

Manganese ug/L 238 10 124

Mercury ng/L 70 4.3 37

Molybdenum ug/L 49 20 35

Nickel ug/L 4,950 2.0 2,476

Selenium ug/L 1,278 920 1,099

Silver ug/L 1.0 1.0 1.0

Sodium ug/L 1,675,000 1,850,000 1,762,500

Thallium ug/L 254 3 129

Tin ug/L 100 100 100

Titanium ug/L 19 10 15

Vanadium ug/L 280 16 148

Zinc ug/L 77 20 49

Source: CWA 308 Monitoring Data, [ERG, 2012h].

6.6 METAL CLEANING WASTE

As discussed in Section 4.3.7, metal cleaning wastes are generated during the cleaning of 

metal process equipment and can consist of chemical and non-chemical cleaning operations. 

There are several different types of metal cleaning wastes (identified in Section 4.3.7) and the 

frequency of generation varies among the different types of metal cleaning wastes. Table 6-14

presents the minimum, median, and maximum frequency of the generation for each of the metal 

cleaning wastes, broken out between chemical and nonchemical operations. Air heater cleaning 

and soot blowing are both examples of cleaning activities that do not use chemicals; between 98 

and 100 percent of all units conducting these cleaning operations use no chemicals during the 

cleaning operations.33 Boiler tube cleaning generally involves the addition of chemicals and 

typically occurs less often than once a year. Fifty-nine percent of the units identified as 

conducting boiler tube cleaning do so once every 10 or more years. 

EPA compared the frequency information reported in the Steam Electric Survey to data 

included in the 1974 Technical Development Document (TDD) to determine if the industry has 

 

33 From the responses to the Steam Electric Survey, EPA determined that 98 percent of units conducting air heater 

cleaning operations and 100 percent of units blowing soot (that use water) do not use chemical addition in the 

cleaning process.
Section 6 – Wastewater Characterization and Pollutants of Concern

6-21 

changed the frequency with which they conduct metal cleaning operations. The 1974 TDD 

contains frequency information for three metal cleaning operations: air heater cleaning, boiler 

fireside cleaning, and boiler tube cleaning. For air heater cleaning, the 1974 TDD frequency data 

ranges from once per month to four times per year, which is generally more frequent compared 

to the data from the Steam Electric Survey. For boiler fireside cleaning, the 1974 TDD frequency 

data ranges from eight times per year to twice per year, which is comparable to the frequency 

data from the Steam Electric Survey. For boiler tube cleaning, the 1974 TDD frequency data 

ranges from twice per year to once every eight years, which is also comparable to the frequency 

data from the Steam Electric Survey. Therefore, EPA determined that the industry is still 

performing these cleaning operations at a similar frequency compared to when the Agency 

initially set the BPT standards for metal cleaning wastes.

In addition to frequency, the volume of wastewater generated also varies among the 

different types of metal cleaning wastes. Table 6-15 provides the minimum and maximum flow 

rates associated with each of these cleaning operations. The 1974 TDD contains flow rate 

information for air heater cleaning, boiler fireside cleaning, and boiler tube cleaning. For air 

heater cleaning, the 1974 TDD flow rates ranges from 43,000 to 600,000 gallons per event, 

which is within the range reported in the Steam Electric Survey. For boiler fireside cleaning, the 

1974 TDD flow rate data ranges from 24,000 to 720,000 gallons/event, which is within the range 

reported in the Steam Electric Survey. For boiler tube cleaning, the 1974 TDD flow rate data 

ranges from 13,900 to 150,000 gallons/event, which is also within the range reported in the 

Steam Electric Survey. While all of these are within the ranges reported in the Steam Electric 

Survey, EPA noted that the maximum value reported in the Steam Electric Survey was 

significantly higher (i.e., an order of magnitude) for each of these cleaning operations. However, 

based on these results, EPA found that the industry is still generating similar quantities of 

wastewater from these cleaning operations compared to when the Agency initially set the BPT 

standards for metal cleaning wastes. 

The 1974 and 1982 TDD contain characterization data for metal cleaning wastewaters. 

Tables A-V-5, A-V-6, and A-V-20 in the 1974 TDD contain characterization data associated 

with boiler tube cleaning, air preheater cleaning, and boiler fireside cleaning [U.S. EPA, 1974]. 

Tables V-68 through V-73 in the 1982 TDD contain characterization data and wastewater flow 

rate data boiler fireside and air preheater cleaning [U.S. EPA, 1982].

Table 6-14. Metal Cleaning Waste Generation Frequency Reported in the Steam Electric 

Survey

Type of Wastestream

Minimum Frequency 

(i.e., Least Frequent) Median Frequency

Maximum Frequency 

(i.e., Most Frequent)

Nonchemical Cleaning Operations

Air Compressor Cleaning NA NA NA

Air-Cooled Condenser Cleaning a a a

Air Heater Cleaning Once Every 40 Years Once Every Year 11 Times Every Day

Boiler Fireside Cleaning Once Every 30 Years Once Every Year Twice Every Day

Boiler Tube Cleaning Once Every 10 Years Once Every 1-2 Years Twice Every Year
Section 6 – Wastewater Characterization and Pollutants of Concern

6-22 

Table 6-14. Metal Cleaning Waste Generation Frequency Reported in the Steam Electric 

Survey

Type of Wastestream

Minimum Frequency 

(i.e., Least Frequent) Median Frequency

Maximum Frequency 

(i.e., Most Frequent)

Combustion Turbine Cleaning 

(Combustion) Twice Every Year Once Every Three Days Once Every Two Days

Combustion Turbine Cleaning 

(Compressor) Once Every Year Once Every Two Days 2-3 Times Every Day

Condenser Cleaning a Once Every Year Once Every Year

Draft Fan Cleaning Once Every Four Years Once Every Year Once Every Year

Economizer Cleaning Once Every 50 Years Once Every Three years Once Every Year

FGD Equipment Cleaning a a Once Every Day

Heat Recovery Steam Generator Cleaning NA NA NA

Mechanical Dust Collector Cleaning Once Every 10 Years Once Every Four Years Once Every Year

Nuclear Steam Generator Cleaning NA NA NA

Precipitator Wash Once Every 10 Years Once Every Three Years Once Every Year

SCR Catalyst Soot Blowing Three Times Every Year Three Times Every Year Three Times Every Year

Sludge Lancing Once Every 4-5 Years Once Every Three Years Once Every 1-2 Years

Soot Blowing Once Every 10 Years Once Every Day 600 Times Every Day

Steam Turbine Cleaning Once Every 10 Years Once Every 7 Years Three Times Every Year

Superheater Cleaning NA NA NA

Chemical Cleaning Operations

Air Compressor Cleaning Twice Every Year Twice Every Year Twice Every Year

Air-Cooled Condenser Cleaning NA NA NA

Air Heater Cleaning Once Every Two Years Twice Every Month Twice Every Month

Boiler Fireside Cleaning Once Every 10 Years a a

Boiler Tube Cleaning Once Every 50 Years Once Every 10 Years Once Every Two Years

Combustion Turbine Cleaning 

(Combustion) Once Every 8 Years Twice Every Year

Three Times Every 

Month

Combustion Turbine Cleaning 

(Compressor) Once Every 10 Years Twice Every Year Once Every Two Days

Condenser Cleaning Once Every 30 Years Once Every 25 Years a

Draft Fan Cleaning Once Every 3-4 Years Once Every 3-4 Years Once Every 3-4 Years

Economizer Cleaning NA NA NA

FGD Equipment Cleaning Once Every Day Once Every Day Once Every Day

Heat Recovery Steam Generator Cleaning Once Every 40 Years Once Every 40 Years Once Every 10 Years

Mechanical Dust Collector Cleaning NA NA NA

Nuclear Steam Generator Cleaning a a a

Precipitator Wash NA NA NA

SCR Catalyst Soot Blowing NA NA NA

Sludge Lancing NA NA NA
Section 6 – Wastewater Characterization and Pollutants of Concern

6-23 

Table 6-14. Metal Cleaning Waste Generation Frequency Reported in the Steam Electric 

Survey

Type of Wastestream

Minimum Frequency 

(i.e., Least Frequent) Median Frequency

Maximum Frequency 

(i.e., Most Frequent)

Soot Blowing NA NA NA

Steam Turbine Cleaning Once Every 30 Years Once Every Four Years Once Every Year

Superheater Cleaning Once Every 37 Years Once Every 37 Years Once Every 37 Years

Source: Steam Electric Survey, [ERG, 2013b].

Note: This table presents data gathered from only the subset of plants that were required to complete Part E of the 

survey.

NA – Not applicable. The cleaning operation was not reported in the Steam Electric Survey for the type of chemical 

usage (i.e., nonchemical or chemical cleaning). 

a – Data were removed from certain cells to protect the release of information claimed confidential business 

information.

Table 6-15. Metal Cleaning Wastewater Flow Rates Reported in the Steam 

Electric Survey

Type of Wastestream

Minimum Flow

(Gallons per Event)

Maximum Flow

(Gallons per Event)

Nonchemical Cleaning Operations

Air Compressor Cleaning NA NA

Air-Cooled Condenser Cleaning a a

Air Heater Cleaning 0 8,000,000

Boiler Fireside Cleaning 0 4,500,000

Boiler Tube Cleaning 0 250,000

Combustion Turbine Cleaning (Combustion) 0 1,800

Combustion Turbine Cleaning (Compressor) 0 5,000

Condenser Cleaning 4,800 a

Draft Fan Cleaning 5,000 169,000

Economizer Cleaning 5,000 2,640,000

FGD Equipment Cleaning 15 a

Heat Recovery Steam Generator Cleaning NA NA

Mechanical Dust Collector Cleaning 180,000 3,000,000

Nuclear Steam Generator Cleaning NA NA

Precipitator Wash 9,000 16,800,000

SCR Catalyst Soot Blowing 11,900 11,900

Sludge Lancing 0 800

Soot Blowing 0 200,000

Steam Turbine Cleaning 0 2,000,000

Superheater Cleaning NA NA

Chemical Cleaning Operations
Section 6 – Wastewater Characterization and Pollutants of Concern

6-24 

Table 6-15. Metal Cleaning Wastewater Flow Rates Reported in the Steam 

Electric Survey

Type of Wastestream

Minimum Flow

(Gallons per Event)

Maximum Flow

(Gallons per Event)

Air Compressor Cleaning 20 20

Air-Cooled Condenser Cleaning NA NA

Air Heater Cleaning 2,700 80,000

Boiler Fireside Cleaning 0 50,000

Boiler Tube Cleaning 0 2,000,000

Combustion Turbine Cleaning (Combustion) 0 11,000

Combustion Turbine Cleaning (Compressor) 0 10,000

Condenser Cleaning 25,000 a

Draft Fan Cleaning 100 100

Economizer Cleaning NA NA

FGD Equipment Cleaning 10 15

Heat Recovery Steam Generator Cleaning 0 231,000

Mechanical Dust Collector Cleaning NA NA

Nuclear Steam Generator Cleaning a a

Precipitator Wash NA NA

SCR Catalyst Soot Blowing NA NA

Sludge Lancing NA NA

Soot Blowing NA NA

Steam Turbine Cleaning 1,500 20,000

Superheater Cleaning 39,000 39,000

Source: Steam Electric Survey, [ERG, 2013b].

Note: This table presents data gathered from only the subset of plants that were required to complete Part E of the 

survey.

NA – Not applicable. The cleaning operation was not reported in the Steam Electric Survey for the type of chemical 

usage (i.e., nonchemical or chemical cleaning). 

a – Data were removed from certain cells to protect the release of information claimed confidential business 

information.

6.7 IDENTIFICATION OF POLLUTANTS OF CONCERN

Constituents present in combustion wastewater are primarily derived from the parent 

carbon feedstock (e.g., coal, petroleum coke). A number of these constituents have the potential 

to cause environmental harm depending on the mass pollutant loadings, wastewater 

concentration, and how organisms are exposed to them in the environment. EPA conducted a 

field sampling program as part of the detailed study and rulemaking efforts for the Steam 

Electric Power Generating ELGs to characterize the wastewater generated by the industry. The 

analytes selected for analysis reflect EPA’s current understanding of power plant wastewaters, 

including contributions from scrubber sorbents, treatment chemicals, and other sources. Section 

3.4.1 discusses the analytes evaluated in the EPA sampling program.
Section 6 – Wastewater Characterization and Pollutants of Concern

6-25 

EPA primarily used the analytical data from the sampling episodes to identify the 

pollutants of concern (POCs) considered for this rulemaking. From the list of analytes sampled, 

EPA eliminated from consideration all pollutants that were never detected in untreated 

wastewater samples. EPA then reviewed its data from untreated wastewater samples from 

individual wastestreams to identify pollutants detected at greater than or equal to 10 times the 

baseline value in at least 10 percent of all untreated process wastewater samples.34 This criterion 

ensures that the pollutant was present in sufficient concentrations at sites where EPA evaluated 

treatment performance. This is used as a screening tool to identify those pollutants that are 

quantified in a wastestream at sufficient frequency and at treatable levels. Using 10 times the 

baseline value as a screening threshold can facilitate evaluations of treatment system 

performance and efficacy, since it ensures the influent concentrations are high enough to more 

readily quantify the degree of pollutant removal resulting from treatment processes such as 

chemical or biological removal. However, the criterion is less applicable in cases where the 

technology basis results in complete removal of all pollutants present, such as would occur under 

the technology options considered for fly ash transport water, bottom ash transport water, and 

FGMC wastewater. For these “zero discharge” technologies, confirmation that a pollutant is 

present in the wastestream at quantifiable levels may be sufficient to identify a pollutant as a

pollutant of concern. Additionally, in past effluent guidelines rulemakings, EPA has determined 

that a lower threshold (e.g., 5 times the baseline value) was the appropriate criterion for 

identifying pollutants of concern. For example, see Section 7 of the Technical Development 

Document for the Final Effluent Limitations Guidelines and Standards for the Meat and Poultry 

Products Point Source Category (40 CFR 432) (EPA-821-R-04-011). 

EPA used the baseline values that were developed for the 2000 Centralized Waste 

Treatment (CWT) Industry Effluent Limitations Guidelines for this analysis. The baseline values 

are generally equal to the nominal quantitation limit identified for the analytical method for a 

pollutant. For the CWT ELGs, the Agency made several exceptions to this general rule if it 

determined that reliable measurements of a pollutant could be made at a lower level, or if the 

nominal quantitation limit could not be reasonably achieved, or if a single baseline value had to 

be selected when a pollutant had multiple nominal quantitation limits. Generally, the CWT ELGs 

used the instrument detection limit for EPA Method 1620 as the basis for the metals baseline 

values, with some exceptions. For the steam electric proposed ELGs, EPA analyzed the samples 

using EPA Methods 200.7, 200.8 with collision cell, and 1631E. Each of these methods are 

capable of achieving quantitation limits that are lower than the baseline values from CWT. 

However, EPA used the CWT baseline values, in most cases, as a more conservative value for 

the analysis. EPA did make a couple of exceptions and used the minimum level for mercury 

defined in EPA Method 1631E (i.e., 0.5 ng/L). Additionally, EPA used 2.0 μg/l for arsenic, 

which is based on a method detection limit study conducted by EPA [CSC, 2013]. Table 6-16

presents the baseline values used for the identification of POCs associated with the proposed 

Steam Electric ELGs.

 

34 This approach is consistent with the process EPA used to identify pollutants of concern for many categories. EPA 

takes this approach to ensure the pollutants are present at treatable levels.
Section 6 – Wastewater Characterization and Pollutants of Concern

6-26 

Table 6-16. Baseline Values for Steam Electric Industry POCs

Analyte Unit Baseline Value

Classicals or Conventionals

Ammonia as Nitrogen μg/l 50.0

Biochemical Oxygen Demand μg/l 2,000.0

Chemical Oxygen Demand μg/l 5,000.0

Chloride μg/l 1,000.0

Nitrate/Nitrite μg/l 50.0

Total Cyanide μg/l 20.0

Total Dissolved Solids μg/l 10,000.0

Total Phosphorus μg/l 10.0

Total Sulfide μg/l 1,000.0

Total Suspended Solids μg/l 4,000.0

Metals

Aluminum μg/l 200.0

Antimony μg/l 20.0

Arsenic μg/l 2.0

Barium μg/l 200.0

Beryllium μg/l 5.0

Boron μg/l 100.0

Cadmium μg/l 5.0

Calcium μg/l 5,000.0

Chromium μg/l 10.0

Cobalt μg/l 50.0

Copper μg/l 25.0

Iron μg/l 100.0

Lead μg/l 50.0

Magnesium μg/l 5,000.0

Manganese μg/l 15.0

Mercury ng/l 0.5

Molybdenum μg/l 10.0

Nickel μg/l 40.0

Phosphorus μg/l 1,000.0

Potassium μg/l 1,000.0

Selenium μg/l 5.0

Sodium μg/l 5,000.0

Sulfur μg/l 1,000.0

Thallium μg/l 10.0

Titanium μg/l 5.0

Vanadium μg/l 50.0

Zinc μg/l 20.0

Source: Development Document for Effluent Limitations Guidelines and Standards for the Centralized Waste 

Treatment Industry, [EPA, 2000]; EPA Method 1631E; [CSC, 2013] 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-27 

For some pollutants, EPA did not have a baseline value identified from the 2000 CWT 

ELGs. For these pollutants, EPA used the sample-specific method detection limit (MDL) for the 

analysis. For some wastestreams (e.g., ash transport water), there were pollutants that did not 

have a baseline value nor a sample-specific MDL; therefore, these pollutants were not included 

in the analysis and were not identified as a POC for the specific wastestream. Finally, for some 

wastestreams, EPA identified pollutants as POCs because they were identified as POCs for the 

wastestream during previous rulemakings. Using the criteria described above, EPA developed 

lists of POCs for each fuel combustion wastewater: FGD wastewater, fly ash transport water, 

bottom ash transport water, landfill combustion residual leachate, impoundment combustion 

residual leachate, FGMC wastewater, gasification wastewater, and nonchemical metal cleaning 

wastes. The following sections identify the POCs for each wastestream. The POCs identified for 

each wastestream are used only as the basis for the selection of regulated pollutants, described in 

Section 11. 

6.7.1 FGD Wastewater Pollutants of Concern 

EPA reviewed untreated wastewater data from seven steam electric power plants 

operating FGD wastewater treatment systems (total of seven sampling points and 28 samples) to 

identify POCs for FGD wastewater; see Table 6-17. EPA identified 35 POCs using the criteria 

presented in Section 6.7. 

Table 6-17. Pollutants of Concern – FGD Wastewater 

Pollutant Group Pollutant of Concern

Conventional Pollutants

Oil and Greasea

Total Suspended Solids

Priority Pollutants

Antimony

Arsenic

Beryllium

Cadmium

Chromium

Copper

Cyanide

Lead

Mercury

Nickel

Selenium

Thallium

Zinc

Nonconventional Pollutants

Aluminum

Ammonia

Barium

Boron

Calcium
Section 6 – Wastewater Characterization and Pollutants of Concern

6-28 

Table 6-17. Pollutants of Concern – FGD Wastewater 

Pollutant Group Pollutant of Concern

Nonconventional Pollutants

Chemical Oxygen Demand

Chloride

Cobalt

Iron

Magnesium

Manganese

Molybdenum

Nitrate/Nitrite

Nitrogen Total, Kjeldahl

Phosphorus

Sodium

Sulfate

Titanium

Total Dissolved Solids

Vanadium

Source: EPA Sampling Data, [ERG, 2012a – 2012g]; [ERG, 2013a].

a – EPA did not analyze its field sampling data for oil and grease. Rather, since the existing steam electric ELGs 

currently contain BPT limitations applicable to FGD wastewater for oil and grease, EPA already has data from the 

existing rulemaking demonstrating oil and grease is also a pollutant of concern in FGD wastewater.

6.7.2 Ash Transport Water Pollutants of Concern 

EPA sampled untreated fly ash sluice at one plant during the steam electric detailed 

study. EPA reviewed the untreated fly ash transport water data from this plant (one sampling 

point and one sample) to identify POCs for fly ash transport water. Table 6-18 lists the POCs 

identified for fly ash transport water. EPA identified 24 POCs using the criteria presented in 

Section 6.7. EPA also identified selenium as a POC for fly ash transport water based on a study 

conducted at Belews Lake that linked fish kills to selenium accumulation in the lake associated 

with discharges from a power plant, as well as other documented instances of harm caused by 

discharges of selenium in ash transport water [Lemly, 1985]. As discussed above in Section 6.7, 

the criterion EPA used as a screening tool to identify pollutants of concern is less applicable in 

cases where the technology basis results in complete removal of all pollutants present, such as 

would occur under the technology options considered for fly ash transport water, bottom ash 

transport water, and FGMC wastewater. For these “zero discharge” technologies, confirmation 

that a pollutant is present in the wastestream at quantifiable levels may be sufficient to identify a 

pollutant as a pollutant of concern. Based on the information in the record for selenium in ash 

transport water, EPA identified it as a pollutant of concern. 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-29 

Table 6-18. Pollutants of Concern – Ash Transport Water 

Pollutant Group Pollutant of Concern

Conventional Pollutants

Oil and Greasea

Total Suspended Solids

Priority Pollutants

Arsenic

Beryllium

Chromium

Copper

Lead

Mercury

Nickel

Selenium

Zinc

Nonconventional Pollutants

Aluminum

Barium

Boron

Calcium

Chloride

Iron

Manganese

Molybdenum

Nitrate/Nitrite

Sodium

Titanium

Total Dissolved Solids

Vanadium

Yttrium

Source: [ERG, 2008]; [ERG, 2013a].

a – EPA did not analyze its field sampling data for oil and grease. Rather, since the existing steam electric ELGs 

currently contain BPT limitations applicable to fly ash transport water for oil and grease, EPA already has data from 

the existing rulemaking demonstrating oil and grease is also a pollutant of concern in fly ash transport water.

Constituents present in ash, and therefore ash transport water, are primarily derived from 

the type of coal/petroleum coke burned; therefore, as discussed in Section 6.2.3, EPA expects 

that the bottom ash transport water will have the same constituents that are found in the fly ash 

transport water. For this reason, the POCs for bottom ash transport water are identical to those of 

fly ash transport water.

6.7.3 Combustion Residual Leachate Pollutants of Concern

As part of the Steam Electric Survey, EPA required a subset of plants to sample their 

leachate from impoundments and landfills containing combustion residual. EPA reviewed the 

untreated landfill and impoundment leachate data collected from the survey responses to identify 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-30 

POCs for landfill leachate and POCs for impoundment leachate. Table 6-19 lists the POCs 

identified for combustion residual landfill leachate using the criteria presented in Section 6.7. 

Table 6-19. Pollutants of Concern – Landfill Leachate

Pollutant Group Pollutant of Concern

Conventional Pollutants

Oil and Greasea

Total Suspended Solids

Priority Pollutants

Arsenic

Mercury

Selenium

Nonconventional Pollutants

Aluminum

Boron

Calcium

Chloride

Iron

Magnesium

Manganese

Molybdenum

Sodium

Sulfate

Total Dissolved Solids

Source: Steam Electric Survey , [ERG, 2013b]; [ERG, 2013a]. 

a – The landfill leachate samples were not analyzed for oil and grease (O&G). Rather, since the existing steam 

electric ELGs currently contain BPT limitations applicable to combustion residual leachate for O&G, EPA already 

has data from the existing rulemaking demonstrating O&G is also a pollutant of concern in combustion residual 

leachate.

Table 6-20 lists the POCs identified for combustion residual impoundment leachate using 

the criteria presented in Section 6.7. 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-31 

Table 6-20. Pollutants of Concern – Impoundment Leachate

Pollutant Group Pollutant of Concern

Conventional Pollutants Oil and Greasea

Priority Pollutants

Arsenic

Mercury

Nonconventional Pollutants

Boron

Calcium

Chloride

Iron

Magnesium

Manganese

Molybdenum

Sodium

Sulfate

Total Dissolved Solids

Source: Steam Electric Survey, [ERG, 2013b]; [ERG, 2013a]. 

a – The impoundment leachate samples were not analyzed for O&G. Rather, since the existing steam electric ELGs 

currently contain BPT limitations applicable to combustion residual leachate for O&G, EPA already has data from 

the existing rulemaking demonstrating O&G is also a pollutant of concern in combustion residual leachate.

6.7.4 Gasification Wastewater Pollutants of Concern 

EPA sampled wastewater streams at two plants operating IGCC generating units as part 

of the CWA 308 sampling program discussed in Section 3.4. EPA reviewed the untreated 

wastewater data from these two stream electric power plants (5 sampling points and 20 samples) 

to identify POCs for IGCC wastewater.

EPA identified 20 POCs for gasification wastewater. Table 6-21 lists the POCs EPA 

identified using the criteria discussed in Section 6.7. 

Table 6-21. Pollutants of Concern – Gasification Wastewater 

Pollutant Group Pollutant of Concern

Conventional Pollutants Biochemical Oxygen Demand

Priority Pollutants

Antimony

Arsenic

Cyanide

Mercury

Nickel

Selenium

Thallium

Nonconventional Pollutants

Aluminum

Ammonia
Section 6 – Wastewater Characterization and Pollutants of Concern

6-32 

Table 6-21. Pollutants of Concern – Gasification Wastewater 

Pollutant Group Pollutant of Concern

Nonconventional Pollutants

Boron

Chemical Oxygen Demand

Chloride

Iron

Manganese

Nitrate/Nitrite

Nitrogen Total, Kjeldahl

Sodium

Sulfate

Total Dissolved Solids

Source: CWA 308 Monitoring Data, [ERG, 2012h]; [ERG, 2013a].

6.7.5 Flue Gas Mercury Control Wastewater Pollutants of Concern

As described in Section 6.4, for ACI systems, the activated carbon can either be injected 

upstream or downstream of the primary particulate removal system. When the activated carbon is 

injected upstream of the primary particulate removal system, the FGMC waste is captured with 

the fly ash removed by the system. When the activated carbon is injected downstream of the 

primary particulate removal system, the FGMC waste must be collected in a separate particulate 

removal system, typically a fabric filter baghouse, and residual fly ash that passes through the 

primary particulate removal system may also be captured in the system. 

The FGMC waste/fly ash from either of these configurations can be handled using either 

a wet sluicing system or dry handling system. Based on responses to the Steam Electric Survey, 

EPA determined that more plants are operating ACI systems injecting the carbon upstream of the 

primary particulate removal system compared to downstream injection. Additionally, EPA 

determined that there are more plants operating wet sluicing systems for upstream carbon 

injection compared to downstream injection. Based on these data, EPA determined that the 

majority of plants generating FGMC wastewater are collecting the FGMC waste with the bulk of 

the fly ash removed from the flue gas. Therefore, because EPA does not have any sampling data 

specific to FGMC wastewater, EPA assumed that the pollutants of concern associated with 

FGMC wastewater will be the same as those for fly ash transport water. Based on this 

assumption, EPA identified 25 POCs associated with FGMC wastewater. Table 6-22 lists the 

POCs identified for FGMC wastewater, which is the same as the list for fly ash transport water, 

presented in Table 6-18. 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-33 

Table 6-22. Pollutants of Concern – Flue Gas Mercury Control Wastewater

Pollutant Group Pollutant of Concern

Conventional Pollutants

Oil and Grease

Total Suspended Solids

Priority Pollutants

Arsenic

Beryllium

Chromium

Copper

Lead

Mercury

Nickel

Selenium

Zinc

Nonconventional Pollutants

Aluminum

Boron

Barium

Calcium

Chloride

Iron

Manganese

Molybdenum

Nitrate/Nitrite

Sodium

Titanium

Total Dissolved Solids

Vanadium

Yttrium

Source: [ERG, 2008]; [ERG, 2013a].

6.7.6 Nonchemical Metal Cleaning Wastes Pollutants of Concern 

As part of the 1974 rulemaking, EPA collected characterization data associated with 

chemical and nonchemical metal cleaning wastes. Based on the data collected during that 

rulemaking, EPA determined that TSS, oil and grease (O&G), copper, and iron were pollutants 

of concern for metal cleaning waste warranting regulation. As such, EPA set BPT limitations for 

these four pollutants in discharges of metal cleaning wastes, including both nonchemical and 

chemical cleaning wastes, as shown in Table 1-1. For additional information regarding the 

pollutants that may be present in nonchemical metal cleaning wastes, see the 1974 Development 

Document for Effluent Limitations Guidelines and New Source Performance Standards for the 

Steam Electric Power Generating Point Source Category [U.S. EPA, 1974]. 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-34 

Based on this assessment, EPA determined that TSS, O&G, copper, and iron are POCs 

for nonchemical metal cleaning wastes. Table 6-23 presents the four POCs for nonchemical 

metal cleaning wastes. 

Table 6-23. Pollutants of Concern – Nonchemical Metal Cleaning Wastes 

Pollutant Group Pollutant of Concern

Conventional Pollutants

Oil & Grease

Total Suspended Solids

Priority Pollutants Copper

Nonconventional Pollutants Iron

Source: [U.S. EPA, 1974].

6.8 REFERENCES

1. Babcock & Wilcox Company. 2005. Steam: Its Generation and Use. 41st edition. Edited 

by J.B. Kitto and S.C. Stultz. Barberton, Ohio. DCN SE02919. 

2. Computer Sciences Corporation (CSC). 2013. Results of the ICP/MS Collision Cell 

Method Detection Limit Studies in the Synthetic Flue Gas Desulfurization Matrix. (16 

January). DCN SE03872. 

3. Duke Energy. 2011a Industry Provided Sampling Data from Duke Energy’s Belews 

Creek Steam Station. (17 August). DCN SE01808. 

4. Duke Energy. 2011b Industry Provided Sampling Data from Duke Energy’s Allen Steam 

Station. (17 August). DCN SE01809. 

5. Eastern Research Group (ERG). 2008. Final Sampling Episode Report, Buckeye Power 

Company’s Cardinal Power Plant. (August 26). DCN SE02107. 

6. Eastern Research Group (ERG). 2012a. Final Sampling Episode Report, Duke Energy 

Carolinas’ Belews Creek Steam Station. (13 April). DCN SE01305. 

7. Eastern Research Group (ERG). 2012b. Final Sampling Episode Report, We Energies’ 

Pleasant Prairie Power Plant. (13 April). DCN SE01306. 

8. Eastern Research Group (ERG). 2012c. Final Sampling Episode Report, Duke Energy 

Miami Fort Station. (13 April). DCN SE01304. 

9. Eastern Research Group (ERG). 2012d. Final Sampling Episode Report, Duke Energy 

Carolinas’ Allen Steam Station. (13 April). DCN SE01307. 

10. Eastern Research Group (ERG). 2012e. Final Sampling Episode Report, Mirant MidAtlantic, LLC’s Dickerson Generating Station. (13 April). DCN SE01308. 

11. Eastern Research Group (ERG). 2012f. Final Sampling Episode Report, Allegheny 

Energy’s Hatfield’s Ferry Power Station. (13 April). DCN SE01310. 

12. Eastern Research Group (ERG). 2012g. Final Sampling Episode Report, RRI Energy’s 

Keystone Generating Station. (13 April). DCN SE01309. 
Section 6 – Wastewater Characterization and Pollutants of Concern

6-35 

13. Eastern Research Group (ERG). 2012h. Final Power Plant Monitoring Data Collected 

Under Clean Water Act Section 308 Authority (“CWA 308 Monitoring Data”). (30 May). 

DCN SE01326. 

14. Eastern Research Group (ERG). 2013a. Memorandum to the Steam Electric Rulemaking 

Record: Pollutants of Concern Memorandum. (19 April). DCN SE02124. 

15. Eastern Research Group (ERG). 2013b. Steam Electric Technical Questionnaire Database 

(“Steam Electric Survey”). (19 April). DCN SE01958. 

16. Electric Power Research Institute (EPRI). 1998a. PISCES Water Characterization Field 

Study, Sites D Report. TR-108892-V1. Palo Alto, CA. (August). DCN SE01820. 

17. Electric Power Research Institute (EPRI). 1998b. PISCES Water Characterization Field 

Study, Sites D Appendix. TR-108892-V2. Palo Alto, CA. (August). DCN SE01820A1. 

18. Electric Power Research Institute (EPRI). 2006. Flue Gas Desulfurization (FGD) 

Wastewater Characterization: Screening Study. 1010162. Palo Alto, CA. (March). DCN 

SE01816. 

19. Lemly, D.A., 1985. Toxicology of Selenium in a Freshwater Reservoir: Implications for 

Environmental Hazard Evaluation and Safety. Ecotoxicology and Environmental Safety, 

10: 314-338. DCN SE01363. 

20. NCDENR. 2011. North Carolina Department of Environment and Natural Resources 

(NCDENR). State Provided Sampling Data from North Carolina’s Progress Energy 

Roxboro Plant. (26 June). DCN SE01812. 

21. U.S. EPA. 1974. Development Document for Effluent Limitations Guidelines and New 

Source Performance Standards for the Steam Electric Power Generating Point Source 

Category. Washington, D.C. (October). DCN SE02917. 

22. 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 SE02933. 

23. U.S. EPA, 2000. Development Document for Effluent Limitations Guidelines and 

Standards for the Centralized Waste Treatment Industry. (August). DCN SE02920. 

24. U.S. EPA Office of Research and Development. 2006. Characterization of MercuryEnriched Coal Combustion Residues from Electric Generating Utilities using Enhanced 

Sorbents for Mercury Control. (February). DCN SE01339. 

25. U.S. EPA. 2008. Characterization of Coal Combustion Residues from Electric Utilities 

Using Wet Scrubbers for Multi-Pollutant Control. EPA-600-R-08-077. (July). Available 

online at: http://www.epa.gov/nrmrl/pubs/600r08077/600r08077.pdf. DCN SE02921. 
Section 7– Treatment Technologies and Wastewater Management Practices

7-1 

SECTION 7

TREATMENT TECHNOLOGIES AND WASTEWATER 

MANAGEMENT PRACTICES

This chapter provides an overview of treatment technologies and wastewater 

management practices at steam electric power plants for flue gas desulfurization (FGD) 

wastewater, fly ash and bottom ash handling, combustion residual landfill leachate, gasification 

wastewater, and flue gas mercury control (FGMC) wastewater.

7.1 FGD WASTEWATER TREATMENT TECHNOLOGIES AND MANAGEMENT PRACTICES

During the Steam Electric Power Generating study and rulemaking, EPA identified 145 

steam electric power plants that generate FGD wastewater. Of these plants, 117 (81 percent) 

discharge FGD wastewater after treatment. EPA identified and investigated wastewater treatment 

systems operated by steam electric power plants discharging FGD wastewater, as well as 

operating/management practices that plants use to reduce the pollutants associated with 

discharge of FGD wastewater. A list of the treatment technologies and management practices, 

including a brief description of each, are included below. This section provides a detailed 

description of each of the treatment technologies and management practices listed below. 

• Surface Impoundments: Surface impoundments (e.g., settling ponds) remove 

particulates from wastewater by means of gravity. Impoundments are typically sized 

to reduce total suspended solids (TSS) and allow for a certain residence time within 

the impoundment. 

• Chemical Precipitation: In chemical precipitation systems, the wastewater is treated 

in tank-based systems. Chemicals are added to enhance the removal of suspended 

solids and to remove dissolved solids, particularly metals. The precipitated solids are 

then removed from solution by coagulation/flocculation followed by clarification 

and/or filtration.

• Biological Treatment: Power plants can also treat FGD wastewater using biological 

treatment systems. EPA identified three types of biological treatment systems 

currently used to treat FGD wastewater, including aerobic/anaerobic sequencing 

batch reactors (target removals of organics and nutrients), fixed-film bioreactors 

(target removals of nitrogen compounds and selenium), and suspended growth 

systems (target removals of selenium and other metals).

• Vapor-Compression Evaporation System: This type of system uses a falling-film 

evaporator (or brine concentrator) to produce a concentrated wastewater stream and a 

distillate stream to reduce wastewater by 80 to 90 percent (with a pretreatment step) 

and similarly reduce the discharge of pollutants. The concentrated wastewater may be 

further processed in a crystallizer or spray dryer.

• Constructed Wetlands: Constructed wetlands are engineered systems that use natural 

biological processes involving wetland vegetation, soils, and microbial activity to 

reduce the concentrations of metals, nutrients, and TSS in wastewater.

• Design/Operating Practices Achieving Zero Discharge: EPA identified four 

design/operating practices available enabling plants to eliminate the discharge of 
Section 7– Treatment Technologies and Wastewater Management Practices

7-2 

FGD wastewater: 1) several variations of complete recycle, 2) evaporation 

impoundments, 3) conditioning dry fly ash, and 4) underground injection. 

• Other Technologies Under Investigation: EPA identified several other technologies 

that have been evaluated for treatment of FGD wastewater, including iron 

cementation, reverse osmosis, absorption media, ion exchange, and electrocoagulation. Other technologies under laboratory-scale study include polymeric 

chelates, taconite tailings, and nano-scale iron reagents.

Most plants currently discharging FGD wastewater use surface impoundments for 

treatment; however, the use of more advanced wastewater treatment systems is increasing due to 

more stringent requirements imposed by some states and regions on a site-specific basis. Figure 

7-1 shows the distribution of FGD wastewater management/treatment technologies reported in 

the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric 

Survey) for the 145 plants that reported using a wet FGD scrubber system in 2009 or planning to 

operate one by January 1, 2014. Because the majority of the FGD wastewater management/ 

treatment technologies are surface impoundments, chemical precipitation systems, biological 

treatment, or zero discharge, EPA grouped the vapor-compression evaporation and constructed 

wetlands with the “Other” technologies for Figure 7-1. For the purpose of Figure 7-1, to identify 

the different treatment systems reported in the Steam Electric Survey, EPA grouped the systems 

into the following categories:

• Surface Impoundments: This grouping includes systems comprising of one or more 

impoundments where the impoundment is the only treatment unit. This grouping also 

includes impoundments with chemical addition to control pH levels prior to 

discharge. This grouping does not include systems containing impoundments as 

treatment units in a more advanced treatment system (i.e., chemical precipitation, 

biological treatment). This grouping does not include systems that achieve zero 

discharge of FGD wastewater.

• Chemical Precipitation: This grouping includes systems using hydroxide and/or 

sulfide precipitation as the treatment mechanism. This grouping also includes systems 

using surface impoundments in combination with chemical precipitation systems and 

systems with chemical precipitation in combination with aerobic biological treatment 

for BOD5 removal or biological treatment designed for nutrient removal (i.e., not 

designed for heavy metals removal). This grouping does not include systems with 

chemical precipitation and anoxic/anaerobic biological treatment systems. This 

grouping does not include systems that achieve zero discharge of FGD wastewater.

• Biological Treatment: This grouping includes systems using anoxic/anaerobic or 

suspended growth biological treatment systems designed for the removal of heavy 

metals. This grouping includes systems that also include surface impoundments 

and/or chemical precipitation treatment units in combination with the biological 

system. This grouping does not include systems that achieve zero discharge of FGD 

wastewater.

• Other: This grouping includes systems using constructed wetlands or vaporcompression evaporation treatment units. This grouping includes systems that also 

include surface impoundments in combination with the constructed wetland/vapor-
Section 7– Treatment Technologies and Wastewater Management Practices

7-3 

compression evaporation system. This grouping does not include systems that achieve 

zero discharge of FGD wastewater.

• Zero Discharge: This grouping includes all FGD wastewater treatment systems that 

achieve zero discharge, regardless of the treatment units (e.g., surface impoundments, 

chemical precipitation) used to treat the wastewater prior to reuse. Chemical 

precipitation systems using aerobic biological treatment to remove BOD were 

classified as chemical precipitation; and

Source: Steam Electric Survey [ERG, 2013g]

Figure 7-1. Distribution of FGD Wastewater Treatment/Management Systems 

Among 145 Plants Currently Operating Wet FGD Systems or Planned Wet 

FGD Systems Operating by 2014 

7.1.1 Surface Impoundments

Surface impoundments are designed to remove particulates from wastewater using 

gravity sedimentation. For this to occur, the wastewater must stay in the impoundment long 

enough for particles to fall out of suspension before being discharged from the impoundment. 

The size and configuration of surface impoundments varies by plant; some surface 

impoundments operate as a system of several impoundments, operated in series or in parallel, 

while others consist of one large impoundment. Plants typically size the impoundments to 

provide enough residence time to reduce the total suspended solids (TSS) levels in the 

wastewater to a target concentration and to allow for a certain lifespan of the impoundment 
Section 7– Treatment Technologies and Wastewater Management Practices

7-4 

based on the expected rate of solids buildup within the impoundment. Coal-fired power plants do 

not typically add treatment chemicals to surface impoundments, other than to adjust the pH of 

the wastewater before it exits the impoundment to bring it into compliance with National 

Pollutant Discharge Elimination System (NPDES) permit limits.

Surface impoundments can reduce the amount of TSS in the wastewater discharge 

provided sufficient residence time. In addition to TSS, surface impoundments can also reduce 

some specific pollutants in the particulate form to varying degrees in the wastewater discharge.

However, surface impoundments are not designed to reduce the amount of dissolved metals in 

the wastewater. The FGD wastewater entering a treatment system contains significant 

concentrations of several pollutants in the dissolved phase, including manganese, selenium, and 

boron. These dissolved metals are not largely removed by the FGD wastewater surface 

impoundments [ERG, 2008]. Additionally, the Electric Power Research Institute (EPRI) has 

reported that adding FGD wastewater to ash impoundments reduces the settling efficiency of the 

impoundment leading to increased TSS concentrations and therefore, increased concentrations of 

other pollutants (e.g., metals), due to gypsum particle dissolution occurring in the impoundment 

[EPRI, 2006]. EPRI has also reported that the FGD wastewater includes high loadings of volatile 

metals that can affect the solubility of metals in the ash impoundment, thereby potentially 

increasing the effluent metal concentrations [EPRI, 2006]. 

EPA compiled data for the 145 plants operating wet FGD systems, or planned wet FGD 

systems operating by 2014, and the wastewater treatment systems used to treat the FGD 

wastewaters generated. Based on these data, surface impoundments are the most commonly used 

systems for managing FGD wastewater (approximately 44 percent). Most of these plants transfer 

the FGD wastewater directly to a surface impoundment that also treats other wastestreams, 

specifically fly and/or bottom ash transport water. Approximately 23 percent of plants managing 

FGD wastewater with surface impoundments transfer the FGD wastewater to a segregated 

surface impoundment specifically designated to treat FGD wastewater [ERG, 2013g]. These 

plants either discharge the FGD wastewater effluent directly to surface waters from the 

segregated FGD surface impoundment (with or without commingling with cooling water or other 

large volume wastes streams) while others transfer the effluent to another impoundment, 

potentially containing other combustion residual wastes (i.e., ash), for further settling and 

dilution. 

EPA has also identified plants that transfer the FGD wastewater to a surface 

impoundment for initial solids removal and then pump the wastewater to a chemical precipitation 

system or a biological treatment system for further treatment. As previously mentioned, because 

these surface impoundments are treatment units in a more advanced wastewater treatment 

system, EPA classifies these plants as “chemical precipitation” or “biological” rather than 

“surface impoundments,” respectively. 

7.1.2 Chemical Precipitation

In a chemical precipitation wastewater treatment system, plants add chemicals to the 

wastewater to alter the physical state of dissolved and suspended solids to help settle and remove 

the solids. The specific chemical(s) used depends upon the type of pollutant requiring removal. 

EPA identified 40 steam electric power plants using chemical precipitation systems to treat FGD 
Section 7– Treatment Technologies and Wastewater Management Practices

7-5 

wastewater. Power plants commonly use the following three types of systems to precipitate 

metals out of FGD wastewater:

• Hydroxide precipitation (40 plants); 

• Iron coprecipitation (38 plants); and 

• Sulfide precipitation (33 plants). 

In a hydroxide precipitation system, plants add lime (calcium hydroxide) to elevate the 

pH of the wastewater to a designated set point, helping precipitate metals into insoluble metal 

hydroxides that can be removed by settling or filtration. Sodium hydroxide can also be used in 

this type of system, but it is more expensive than lime and, therefore, not as common in the 

industry. 

Thirty-eight power plants use iron coprecipitation as a way to increase the removal of 

certain metals in a hydroxide precipitation system. Plants can add ferric (or ferrous) chloride to 

the precipitation system to coprecipitate additional metals and organic matter.35 The ferric 

chloride also acts as a coagulant, forming a dense floc that enhances settling of the metals 

precipitate in downstream clarification stages.

Sulfide precipitation systems use sulfide chemicals (e.g., trimercapto-s-triazine (TMT), 

Nalmet® 1689, sodium sulfide) to precipitate and remove heavy metals, similar to the set of 

metals removed in hydroxide precipitation. Plants operating sulfide precipitation systems can use 

TMT, Nalmet® 1689, MetClearTM, sodium sulfide, or other sulfide chemicals in the system. The 

plants may test several different sulfide chemicals to determine the one most appropriate for their 

treatment system. Sulfide precipitation can also provide more optimal removal of metals with 

lower solubilities, such as mercury, than hydroxide precipitation or hydroxide precipitation with 

iron co-precipitation. The EPA sampling data suggest that adding organosulfide to the FGD 

wastewater can reduce dissolved mercury concentrations to the tens of parts per trillion [ERG, 

2012b]. Sulfide precipitation is more effective than hydroxide precipitation in removing metals 

with low solubilities because metal sulfides have lower solubilities than metal hydroxides. 

Because sulfide precipitation is more expensive than hydroxide precipitation, plants usually use 

hydroxide precipitation first to remove most of the metals, and then sulfide precipitation to 

remove the remaining low solubility metals. This configuration overall requires less sulfide, 

thereby reducing the expense for the bulk metals removal.

FGD wastewater chemical precipitation systems may include various stages of lime, 

sulfide, and ferric chloride addition, as well as clarification stages. Some plants add all three 

chemicals (i.e., lime, ferric chloride, and organosulfide) to a single reaction tank, whereas other 

plants add the chemicals to separate tanks. The plants operating separate tanks may be targeting 

different pH set points within the system for optimal precipitation of certain metals. For example, 

We Energies’ Pleasant Prairie Power Plant (Pleasant Prairie) adds hydrated lime to its FGD 

wastewater in the first reaction tank of the treatment system, raising the pH from 5.5 to 8.5 S.U. 

to precipitate soluble metals as insoluble hydroxides and oxyhydroxides. After primary 

 

35 The remainder of this section discusses the use of ferric chloride, as ferrous chloride is not commonly used in the 

steam electric industry. However, ferrous chloride could also be used in the place of ferric chloride.
Section 7– Treatment Technologies and Wastewater Management Practices

7-6 

clarification, the wastewater flows to a second reaction tank and the plant adds organosulfide and 

hydrochloric acid, which drops the pH to around 7 S.U. Pleasant Prairie determined that adding 

the organosulfide at a neutral pH removed more mercury compared to operating at a more basic 

pH level [ERG, 2013c]. 

During its site visit program, EPA determined that the majority of steam electric power 

plant permits include only TSS, pH, and oil and grease (O&G) limitations for FGD wastewater 

based on the current Steam Electric ELGs BPT limits for low volume wastewater. For this 

reason, 63 plants (44%) operate surface impoundments, as discussed previously, to remove TSS. 

However, some steam electric power plant permits include limitations for specific metals due to 

state or regional regulations or local limitations. Most effluent limits in NPDES permits for FGD 

wastewater (other than TSS and O&G) are water-quality-based effluent limitations (WQBELs) 

to meet applicable water quality standards. In these cases, a number of plants have opted to 

install chemical precipitation systems designed and operated to target the specific metal or 

metals included in the permit. For example, if the plant has a mercury effluent limitation, they 

are more likely to operate sulfide precipitation, rather than just hydroxide precipitation or a 

surface impoundment if they had only a limitation for TSS. 

One example of a treatment system operating to meet only the BPT-based limitations for 

TSS, pH, and O&G was AEP’s Mountaineer plant, which operates a chemical precipitation 

system to treat its FGD wastewater. In 2008, one year after the start-up of the FGD scrubbers and 

the FGD wastewater treatment system, the plant went through a permit renewal process and the 

state proposed to add a limit for mercury. Based on the proposed mercury limitations in the new 

permit, AEP conducted a pilot study evaluating three different technologies that could be 

installed as additional treatment downstream of the currently operating chemical precipitation 

system. Mountaineer conducted the pilot study from July through December 2008. During the 

first three months of the study, the mercury concentrations of the chemical precipitation system 

effluent feeding the pilot tests averaged 1,300 parts per trillion (ppt). None of the three 

technologies achieved the target effluent concentrations for the pilot testing. Therefore, AEP 

took steps to optimize the solids removal in the chemical precipitation system, including adding 

additional polymers and organosulfide. Using these optimization steps, AEP noted that “[t]he 

combination of supplemental coagulation and organosulfide addition consistently yielded 

approximately 80 percent of additional mercury reduction...” within the chemical precipitation 

system [AEP, 2010]. 

In some cases, plants may experience a spike in concentrations for certain metals in their 

untreated FGD wastewater, likely based on changes in fuels or operating conditions within the 

FGD scrubber. EPA’s data demonstrate that well operated systems maintain their chemical 

precipitation effluent concentrations because they actively monitor their untreated wastewater for 

target concentrations of certain metals allowing them to adjust the operation of the chemical 

precipitation system, as necessary. Plants that actively monitor their untreated FGD wastewater 

would be able to identify these excursions and adjust the chemical addition rates to treat the 

wastewater to the required permit limitation. Some plants actively monitor the influent to the 

treatment system and adjust chemical addition by including an equalization tank with a 24-hour 

holding time as the first step in the treatment system. Alternatively, plants could monitor the 

effluent prior to discharge to make sure that they are in compliance before discharge. For 

example, Pleasant Prairie monitors the effluent from the system daily by collecting and analyzing 
Section 7– Treatment Technologies and Wastewater Management Practices

7-7 

samples using an in-house Method DMA 80 mercury analyzer. The analyzer can generate results 

in approximately six minutes [Michel, 2012]. The plant uses the mercury analyzer to alert 

operators when mercury concentrations are at levels close to the plant’s mercury permit limit; 

therefore, the operators can adjust the system (e.g., chemical feed rates) to achieve additional 

mercury removal. When the concentrations are close to the permit limits, the plant begins 

discharging in the wastewater in batches. The plant transfers the wastewater to the effluent 

storage tank and when the tank is full, the plant collects a sample of the wastewater to confirm it 

is below the permit limit. Once the plant confirms the concentration is lower than the limit, the 

plant discharges the wastewater from the effluent tank [ERG, 2013c]. 

Figure 7-2 presents a process flow diagram for a chemical precipitation system using 

hydroxide precipitation, sulfide precipitation, and iron coprecipitation to treat FGD wastewater. 

This system is designed to remove heavy metals and organic matter. A chemical precipitation 

system with no sulfide precipitation stage would be similar, but without the sulfide addition 

reaction tank.

For the system illustrated by Figure 7-2, the plant transfers the FGD wastewater from the 

plant’s solid separation/dewatering process to an equalization tank. This tank equalizes the 

intermittent flows, allowing the plant to pump a constant flow of wastewater through the 

treatment system. The equalization tank also receives wastewater from a filtrate sump, which 

includes water from the gravity filter backwash and filter press filtrate.

The FGD wastewater is transferred in a continuous flow from the equalization tank to 

reaction tank 1, where the plant adds hydrated lime to raise the pH of the wastewater from 

between 5.5 – 6.0 S.U. to between 8.0 – 10.5 S.U. to precipitate the soluble metals as insoluble 

hydroxides and oxyhydroxides. The reaction tank also desaturates the remaining gypsum in the 

wastewater, which prevents gypsum scale formation in the downstream wastewater treatment 

equipment. 

From reaction tank 1, the wastewater flows to reaction tank 2, where the plant adds 

organosulfide or inorganic sulfide. Plants can also reconfigure the treatment system by adding 

the organosulfide upstream of the hydroxide precipitation step or adding a clarification step 

between the two chemical addition steps.36

From reaction tank 2, the wastewater flows to reaction tank 3, where the plant adds ferric 

chloride to the wastewater for coagulation and coprecipitation. The effluent from reaction tank 3 

flows to the flash mix tank, where the plant adds polymer to the wastewater prior to transferring 

it to the clarifier. Alternatively, the plant can add polymer directly to the wastestream as it enters 

the clarifier or reaction tank 3. The polymer acts to flocculate fine suspended particles in the 

wastewater.

 

36 Some plants may have a clarification step between reaction tank 1 and reaction tank 2 to remove the hydroxide 

precipitates from the wastewater prior to adding organosulfide. In addition, plants may adjust the pH prior to sulfide 

addition to target the removal of different metals. 
7-8

Section 7– Treatment Technologies and Wastewater Management Practices

FGD Wastewater

Lime

Organosulfide

Ferric 

Chloride

Polymer Hydrochloric 

Acid

Treated 

Effluent to 

Discharge

To Sludge Disposal

Equalization 

Tank Reaction Tank 1 Reaction 

Tank 2

Reaction 

Tank 3

Flash 

Mix Tank Clarifier

Filter Treated 

Wastewater 

Holding 

Tank

Sludge Holding 

Tank

Filter Press

Filtrate 

Sump

Filter 

Backwash

Treated 

Effluent 

Recycle

Legend

Wastewater Flow

Intermittent Wastewater Flow

Figure 7-2. Process Flow Diagram for a Hydroxide and Sulfide Chemical Precipitation System 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-9 

The clarifier settles the solids that were initially present in the FGD wastewater as well as 

the additional solids (precipitate) formed during the chemical precipitation steps. The system 

may also include a sand filter to further reduce solids, as well as metals attached to the solids. 

The system transfers the backwash from the sand filters to a filtrate sump and recycles it back to 

the equalization tank at the beginning of the treatment system.

The plant collects the treated FGD wastewater in a holding tank and either discharges it

directly to surface waters or, in most cases, commingles it with other wastestreams prior to 

discharge.

The plant transfers the solids that settle in the clarifier (clarifier sludge) to the sludge 

holding tanks, after which the sludge is dewatered using a filter press. The plant then disposes of 

the dewatered sludge, or filter cake, in an on-site landfill, and transfers the filtrate from the filter 

press to a sump and recycles it back to the equalization tank at the beginning of the treatment 

system.

7.1.3 Biological Treatment 

Biological wastewater treatment systems use microorganisms to consume biodegradable 

soluble organic contaminants and bind much of the less soluble fractions into floc. Pollutants 

may be reduced aerobically, anaerobically, and/or by using anoxic zones. Based on the 

information EPA collected during the rulemaking, steam electric power plants use two main 

types of biological treatment systems to treat FGD wastewater: aerobic systems to reduce

biochemical oxygen demand (BOD5) and anoxic/anaerobic systems to remove metals and 

nutrients. These systems may consist of fixed film or suspended growth bioreactors, and operate 

as conventional flow-through or as sequencing batch reactors (SBRs). This section describes the 

wastewater treatment processes for each of these systems. These biological treatment processes 

are typically operated downstream of a chemical precipitation system or a solids removal system 

(e.g., clarifier, surface impoundment). 

7.1.3.1 Aerobic Biological Treatment

Some plants operate aerobic biological treatment systems to reduce BOD5 in their FGD 

wastewater. In a conventional flow-through design, the system continuously feeds the 

wastewater to the aerated bioreactor. The plant may add chemicals to the wastewater before it 

enters the bioreactor to adjust the pH levels and, in certain climates, feed the wastewater through 

a heat exchanger to maintain a certain temperature to make sure the microorganisms are 

operating at optimal levels [ERG, 2007]. The microorganisms in the reactor use the dissolved 

oxygen from the aeration to digest the organic matter in the wastewater, thus reducing the BOD5. 

The digestion of the organic matter produces sludge, which the plant may dewater with a vacuum 

filter to better manage its ultimate disposal. The treated wastewater from the system overflows 

out of the reactor. 

An SBR is a type of activated sludge treatment system that can reduce BOD5 and, when 

operated to create anoxic zones under certain conditions, can also reduce nitrogen compounds 

through nitrification and denitrification. Plants often operate at least two identical reactors 

sequentially in batch mode. The treatment in each SBR consists of a four-stage process: fill, 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-10 

aeration and reaction, settling, and decant. While one of the SBRs is settling and decanting, the 

other SBR is filling, aerating, and reacting.

As an aerobic system, the SBR operates as follows. The filling stage of the SBR involves 

transferring the FGD wastewater into a reactor that contains some activated sludge from the 

previous reaction batch. During the aeration and reaction stages, the reactor is aerated and the 

microorganisms reduce the BOD5 by digesting the organic matter in the wastewater. During the 

settling phase, the plant stops aeration and the solids in the SBR settle to the bottom. The plant 

then decants the wastewater off the top of the SBR and transfers it to surface water for discharge

or to additional treatment or reuses it in plant processes without further treatment. Additionally, 

the plant removes and dewaters some of the solids from the bottom of the SBR, but retains some 

of the solids in the SBR to keep microorganisms in the system.

7.1.3.2 Anoxic/Anaerobic Biological Treatment 

Some coal-fired power plants use anoxic/anaerobic biological systems to reduce certain 

pollutants (e.g., selenium, mercury, nitrates) more effectively than has been possible with surface 

impoundments, chemical precipitation, or aerobic biological treatment processes. Figure 7-3

presents a process flow diagram for an anoxic/anaerobic biological treatment system. The 

microorganisms in this system are susceptible to high temperatures in excess of 105 oF [Pickett, 

2005]. Because of this susceptibility, some plants cool the FGD wastewater prior to entering the 

biological system using heat exchangers or cooling impoundments. Based on data from EPA 

sampling episodes, these plants generally include those in geographic locations with sustained 

periods of maximum ambient temperatures greater than 90 oF [U.S. EPA, 2013]. 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-11 

Solids Pretreatment 

Step (e.g., Settling 

Pond, Chemical 

Precipitation)

Sump

Wastewater Flow

Intermittent Wastewater Flow

Nutrient

First-Stage 

Bioreactors First-Stage 

Effluent 

Storage

Second-Stage 

Bioreactors

Effluent 

Storage

Bio Reactor Backflush

Heat 

FGD Exchanger

Wastewater

Treated FGD Wastewater 

for Discharge

Recycle to Beginning of FGD 

Wastewater Treatment

Legend

Figure 7-3. Process Flow Diagram for an Anoxic/Anaerobic Biological Treatment System 

Plants employing an anoxic/anaerobic biological treatment system operate a fixed-film 

bioreactor that consists of an activated carbon bed, such as granular activated carbon (GAC) or 

some other permanent porous substrate, that is inoculated with naturally occurring, beneficial 

microorganisms that reduce selenium and other metals [Sonstegard, 2010]. The microorganisms 

grow within the activated carbon bed, creating a fixed-film that retains the microorganisms and 

precipitated solids within the bioreactor. The system uses microorganisms chosen specifically for 

use in FGD systems because of their hardiness in the extreme water chemistry as well as 

selenium respiration and reduction [Sonstegard, 2010]. Power plants also add a molasses-based 

feed source for the microorganisms to the wastewater before it enters the bioreactor [ERG, 

2012a]. 

The bioreactor is designed for plug flow to ensure the feed water is evenly distributed and 

has maximum contact with the microorganisms in the fixed-film. The bioreactor contains 

different zones that have differing oxidation reduction potentials (ORP). Plants operate the 

bioreactors to achieve a negative ORP within the system, which provides the optimal 

environment to reduce selenium to its elemental form. The ORP is controlled by the amount of 

nutrient that is fed to the system [ERG, 2012a]. The top part of the bioreactor, where the plant 

feeds the wastewater, is aerobic with a positive ORP, which allows nitrification and organic 

carbon oxidation to occur. As the wastewater moves down through the bioreactor, it enters an 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-12 

anoxic zone (negative ORP) where denitrification as well as chemical reduction of selenium 

(both selenate and selenite) occur [Pickett, 2006; Sonstegard, 2010]. The system maintains a pH 

level in the bioreactor between 6.0 and 9.0 S.U. because extreme high or low pH levels could 

affect the performance of the microbes and potentially allow nondesirable microbes to propagate 

[ERG, 2012a].

When the microorganisms reduce the selenate and selenite to elemental selenium, it 

forms nanospheres that adhere to the cell walls of the microorganisms. Because the activated 

carbon bed retains the microorganisms within the bioreactor, the elemental selenium is 

essentially fixed to the activated carbon until it is removed from the system. The microorganisms

can also reduce other metals, including arsenic, cadmium, and mercury, by forming metal 

sulfides within the system [Pickett, 2006]. 

The bioreactor system typically contains multiple bioreactor cells. For example, the Duke 

Energy Carolinas’ Allen Steam Station and Belews Creek Steam Station have two stages of 

bioreactor cells in series, as shown in Figure 7-3, but both stages of bioreactors contain multiple 

cells in parallel. Plants usually require multiple bioreactors to provide the necessary residence 

time to achieve the specified removals.

Periodically, the bioreactor must be backflushed to remove the solids and inorganic 

materials that have accumulated within it. The flushing process involves flowing water upward 

through the system, which dislodges the particles fixed within the activated carbon. The water 

and solids overflow out of the top of the bioreactor and are removed from the system. This flush 

water contains elevated levels of solids, with selenium adhered to it [Pickett, 2006], and will 

likely need to be treated prior to discharge. Some plants send the backflush water to the 

beginning of the chemical precipitation wastewater treatment system so that the system can 

remove the solids (and adhered selenium) within the clarifier. Other plants transfer the backflush 

water to a surface impoundment where the solids (and adhered selenium) settle out [ERG, 2010; 

Jordan, 2008].

As the microorganisms denitrify the wastewater, nitrogen and carbon dioxide gases form, 

which periodically build up and form pockets within the bioreactor. As a result, water flows 

through channels, reducing microbial contact and increasing head-loss across the bioreactor, an 

overall negative effect on the system [Sonstegard, 2010]. To remove these gas pockets, plants 

occasionally perform a degassing operation by transferring water backwards through the cells, 

similar to a backflush, but the flush is only long enough for the gas to “burp” out of the system 

[Allen SER]. The system flush is long enough to lift the biomatrix and release entrained gases, 

but short enough to avoid flushing any water out of the bioreactor [Sonstegard, 2010]. 

One plant has pilot tested another type of anoxic/anaerobic biological treatment system 

that consists of suspended growth flow-through bioreactors instead of fixed-film bioreactors. 

Both designs share the fundamental processes that lead to nitrification/denitrification and 

reduction of metals in anoxic and anaerobic environments. Based on the results of the pilot test, 

in January 2012, the plant commissioned a full-scale suspended growth bioreactor system to treat 

FGD wastewater [ERG, 2013f]. 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-13 

Plants can also operate SBRs to achieve anoxic/anaerobic conditions. The SBR operation 

is similar to the aerobic biological treatment system described above; however, the aeration stage 

would be followed by periods of air on, air off, which creates aerobic zones for nitrification and 

anoxic zones for denitrification to remove the nitrogen in the wastewater. According to the 

treatment system vendor, SBR systems will denitrify the wastewaters, but the ORP in the system 

is not managed at levels conducive to reducing metals. Therefore, these SBR systems will not 

remove selenium (and other metals) as effectively as the fixed-film or suspended growth 

bioreactor systems.

7.1.4 Vapor-Compression Evaporation System 

Mechanical evaporators in combination with a final drying process can significantly 

reduce the quantity of wastewater pollutants and volume discharged from certain process 

operations at various types of industrial plants, including steam electric power plants, oil 

refineries, and chemical plants. One type of evaporation system uses a falling-film evaporator 

(also referred to as a brine concentrator) to produce a concentrated wastewater stream (i.e., brine) 

and a reusable distillate stream. The concentrated wastewater stream may be further processed in 

a crystallizer or spray dryer, in which the remaining water is evaporated. When used with a 

crystallizer or spray dryer, this process generates a distillate stream and a solid by-product that 

can then be disposed of in a landfill.

Steam electric power plants most often use vapor-compression evaporation systems to 

treat wastestreams such as cooling tower blowdown and demineralizer waste; however, in 2009, 

one plant in the United States began to operate a vapor-compression evaporation system to treat 

FGD wastewater [ERG, 2013g]. Two other plants in the United States have installed, or are in 

the process of installing, this technology [Jacobs Consultancy, 2012; Loewenberg, 2012]. 

Additionally, four coal-fired power plants in Italy are treating FGD wastewater with vaporcompression evaporation systems [Rao, 2008; Veolia Water Solution, 2007]. Two other plants in 

Italy also installed vapor-compression evaporation systems but subsequently determined that offsite disposal is more economical.

Before entering the vapor-compression evaporation system, FGD wastewater is usually 

pretreated to remove calcium and magnesium salts, as shown in Figure 7-4. Calcium and 

magnesium salts in the FGD wastewater can pose difficulties for 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]. See Section 7.1.2 for more specific information on 

chemical precipitation systems.
Section 7 – Treatment Technologies and Wastewater Management Practices

7-14 

Sodium 

Carbonate

Reaction 

Tank

Clarifier

Calcium 

Carbonate

Pretreated FGD 

Chemical Precipitation Wastewater

(See Figure 7-2)

Vapor-Compression 

Evaporation System

(See Figure 7-5)

Chemical 

Precipitation Effluent

Figure 7-4. Chemical Precipitation and Softening Pretreatment for FGD 

Wastewater Prior to Vapor-Compression Evaporation 

Figure 7-5 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, 2012d]. 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, 2012d]. 

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, 2012d]. 

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 because of 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]. However, without pretreatment, the brine 
7-15

Section 7 – Treatment Technologies and Wastewater Management Practices

Pretreated FGD 

Wastewater

Acid

Distillate for 

Reuse/Discharge

Feed/Distillate 

Heat Exchanger

Distillate 

Tank

Deaerator

Vent to 

Atmosphere

Brine Concentrator/

Vapor Separator

Multistage 

Compressor/

Blower

Vent to 

Atmosphere

FGD Waste Brine 

Solution

Brine 

Recycle

Concentrated Brine 

Slurry to:

 - Crystallizer;

 - Spray Dryer; or

 - Fly Ash Conditioning

Distillate

Liquid Stream

2-Phase Stream

Legend

Gas Stream

Figure 7-5. Process Flow Diagram for a Vapor-Compression Evaporation System 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-16 

concentrator is not as effective because of boiling point rise (the increase in energy required to 

concentrate the wastewater stream because of the additional calcium and magnesium salts or 

other solids in the wastewater). For example, one plant operates only a clarifier prior to the 

vapor-compression evaporation system. The brine concentrator reduces the inlet FGD scrubber 

purge water volume only up to 53 percent [ERG, 2012c].

Plants typically consider three options for eliminating the brine concentrate: (1) 

evaporating the brine in a brine crystallizer; (2) evaporating the brine in a spray dryer; or (3) 

using the brine to condition (add moisture to) dry fly ash or other solids and disposing of the 

mixture in a landfill.

Plants may use brine concentrators to treat a wastestream other than FGD wastewater 

(e.g., cooling tower blowdown). For these non-FGD systems, the plant typically sends the 

concentrated brine from the sump to a forced-circulation crystallizer to evaporate the remaining 

water from the concentrate and generate a solid product for disposal. 

Coal-fired power plants can avoid having to operate the chemical precipitation 

pretreatment process by using a spray dryer to evaporate the residual wastestream from the brine 

concentrator. Because the material generated from this process is hygroscopic (i.e., readily taking 

up and retaining moisture), the solid residual from the spray dryer is typically bagged 

immediately and disposed of in a landfill. Alternatively, the plant can combine the concentrated 

brine wastestream with dry fly ash or other solids for disposal in a landfill. To do this, the plant 

must generate enough dry fly ash to mix with the brine; otherwise, there will be brine remaining 

that the plant must handle. 

7.1.5 Constructed Wetlands

A constructed wetland treatment system is an engineered system that uses natural 

biological processes involving wetland vegetation, soils, and microbial activity to achieve 

reductions in the concentrations of metals, nutrients, and TSS in wastewater. A constructed 

wetland typically consists of several cells that contain bacteria and vegetation (e.g., bulrush, 

cattails, peat moss), which the steam electric plant selects based on the specific pollutants 

targeted for removal. The vegetation completely fills each cell and produces organic matter (i.e., 

carbon) used by the bacteria. The bacteria reduce metals in the aqueous phase of the wastewater, 

such as mercury and selenium, to their elemental state. The metals removed by the bacteria will 

partition into the sediment, where they either accumulate or are absorbed by the vegetation in the 

wetland cells [EPRI, 2006; Rogers, 2005]. 

High temperature, chemical oxygen demand (COD), nitrates, sulfates, boron, and 

chlorides in the wastewater can adversely affect constructed wetlands’ performance. To avoid 

this, plants typically dilute the FGD wastewater with service water before it enters the wetland to 

reduce the temperature of the wastewater and concentration of chlorides and other pollutants, 

which can harm the vegetation in the treatment cells. Plants typically maintain the chlorides in a 

constructed wetland treatment system below 4,000 mg/L. Because most plants operate their FGD 

scrubber system to maintain chloride levels within a range of 10,000 – 20,000 ppm, they would 

need to dilute the FGD wastewater prior to transferring it to a wetland system. EPA identified 

three plants operating constructed wetlands to treat FGD wastewater. EPA has observed that 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-17 

these steam electric power plants tend to operate the FGD system at lower concentrations of 

chlorides (e.g., 1,000 to 10,000 ppm). To do this, the plants purge FGD wastewater from the 

system at a higher flow rate than they otherwise would do if operating the FGD system at a 

higher chloride concentration level.

7.1.6 Design/Operating Practices Achieving Zero Discharge

During its engineering site visit program, EPA observed that some of the plants operating 

wet FGD systems designed and/or managed the FGD system to eliminate the discharge of FGD 

wastewater. EPA identified 28 plants (19%) achieving zero discharge of FGD wastewater. Based 

on information collected as part of the Steam Electric Survey, EPA identified five design/ 

operating practices available to prevent the FGD wastewater discharge:

• Variations of complete recycle; 

• Evaporation impoundments; 

• Underground injection; 

• Operation of both wet and dry FGD scrubber systems; and

• Dry fly ash conditioning. 

This section discusses each of these practices below.

Complete Recycle

Most plants do not recycle their treated FGD wastewater within the FGD system because 

of the elevated chloride levels in the treated effluent. Some plants, however, completely recycle 

the FGD wastewater within the system without using a wastewater purge stream to remove 

chlorides. Such plants generally do not produce a saleable solid product from the FGD system 

(e.g., wallboard-grade gypsum). Because the plant is not selling the FGD solid by-product, and 

therefore, is most likely disposing of it in a landfill, it has no specific chloride specifications for 

the material. Therefore, the plant can operate the FGD system and solids separation/dewatering 

process such that the moisture retained with the landfilled solids contains sufficient chlorides that 

the plant does not need a separate wastewater purge stream. Transferring the FGD solids to the 

landfill essentially serves as the chloride purge from the system.

From the information provided in the Steam Electric Survey, EPA determined that, of the 

145 plants operating wet FGD systems, approximately 16 operate complete recycle systems and 

do not discharge any FGD wastewaters to surface waters. Of these 16 plants, nine operate natural 

or inhibited oxidation system, which generate calcium sulfite instead of calcium sulfate, and are 

therefore more likely to dispose of the solids in a landfill. 

Evaporation Impoundments 

EPA identified approximately 10 plants located in the southwestern United States that use 

evaporation impoundments to avoid discharging any FGD wastewaters to surface waters. 

Because of the warm, dry climate in this region, the plants can transfer the FGD wastewater to 

one or more impoundments where the water evaporates. The evaporation rate from the 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-18 

impoundments at these plants is greater than or equal to the flow rate of the FGD wastewater and 

amount of direct precipitation entering the impoundments; therefore, there is no discharge. 

Conditioning Dry Fly Ash 

Many plants that operate dry fly ash handling systems need to add water to the fly ash to

suppress dust or improve handling and/or compaction characteristics. EPA identified six plants 

that use FGD wastewater to suppress dust around landfills or to moisture condition fly ash prior 

to landfill disposal [ERG, 2013g]. Another plant, discussed in Section 7.1.4, uses a vaporcompression evaporation system in combination with conditioning dry fly ash to prevent 

discharging FGD wastewater [ERG, 2013b]. The plant uses the vapor-compression evaporation 

system to reduce the volume of the FGD wastewater and then mixes the concentrated brine 

slurry with dry fly ash and disposes of it in a landfill. 

Combination of Wet and Dry FGD Systems 

Operating combined wet and dry FGD systems on the same unit or at the same plant can 

eliminate the scrubber purge associated with the wet FGD process. The dry FGD process 

involves atomizing and injecting wet lime slurry, which ranges from approximately 18 to 25 

percent solids, into a spray dryer. The water contained in the slurry evaporates from the heat of 

the flue gas within the system, leaving a dry residue that is removed from the flue gas by a fabric 

filter (i.e., baghouse) [Babcock and Wilcox, 2005]. By operating a combination wet and dry 

FGD system, the plant can use the FGD wastewater associated with the wet FGD system as 

make-up water for the lime slurry feed to the dry FGD process, thereby eliminating the FGD 

wastewater [McGinnis, 2009]. 

From its data collection activities, EPA identified three plants expected to operate dry and 

wet FGD systems in combination on existing or planned units, eliminating the need to discharge 

the wastewater associated with the wet FGD system [ERG, 2013g]. 

Underground Injection 

Underground injection is a technique used to dispose of wastes by injecting them into an 

underground well, an alternative to discharging wastewater to surface waters. One plant began 

using underground injection to dispose of FGD wastewater in 2007, but it has not been 

successful. Due to unexpected pressure issues and problems with building the wells due to 

geological formations encountered (unrelated to the characteristics of the FGD wastewater), the 

plant has not been able to continuously inject the wastewater. The plant operates a chemical 

precipitation system as pretreatment for the injection system.37 When it is not injecting the FGD 

wastewater, the plant transfers the effluent from the chemical precipitation system to the cooling 

lake, which does not discharge to surface water (e.g. zero discharge) [ERG, 2013A; ERG,

2013g]. Another plant also began injecting the FGD wastewater underground in 2010 [ERG, 

2013g]. Underground injection is currently managed under the Underground Injection Control 

(UIC) program. Underground disposal of FGD wastewater constitutes zero discharge to waters 

of the United States.

 

37 Plant operates an iron coprecipitation system.
Section 7 – Treatment Technologies and Wastewater Management Practices

7-19 

7.1.7 Other Technologies Under Investigation 

EPRI is conducting industry-funded studies to evaluate and demonstrate technologies that 

can potentially remove trace metals from FGD wastewater. EPRI conducted pilot- and full-scale 

optimization field studies on some technologies already used by coal-fired power plants to treat 

FGD wastewater, such as chemical precipitation (organosulfide and iron coprecipitation), 

constructed wetlands, and an anoxic/anaerobic biological treatment system. EPRI is also 

conducting laboratory- and pilot-scale studies for other technologies that can potentially remove 

metals from FGD wastewaters, which include iron cementation, reverse osmosis, absorption 

media, ion exchange, and electro-coagulation. EPA discusses each of these technologies below. 

Iron and Sulfide Additives with Microfiltration

EPRI conducted bench- and pilot-scale testing of a process to aid in removing mercury 

from FGD wastewater. This process involved iron coprecipitation (e.g., ferric chloride addition) 

and organosulfide addition, common in currently operating chemical precipitation systems, but 

added microfiltration to determine if that would improve solids removal over conventional 

clarification and media filtration. Microfiltration typically targets removing particles between 0.1 

and 2 microns. Incorporating sludge recirculation theoretically increases particle size of the 

resulting precipitates, resulting in better solids removal in conjunction with microfiltration. EPRI 

determined that adding microfiltration may help remove fine-particle mercury that passes 

through media filters [EPRI, 2009a].

Iron Cementation 

EPRI conducted bench-scale testing of the metallic iron cementation treatment 

technology as a way to remove all species of selenium from FGD wastewater. EPRI believes this 

process may also effectively remove mercury. The iron cementation process consists of 

contacting the FGD wastewater with an iron powder, which reduces selenium to its elemental 

form (i.e., cementation). The pH of the wastewater is then raised to form metal hydroxides, and 

the wastewater is filtered to remove the precipitated solids. The iron powder used in the process 

is separated from the wastewater and recycled back to the cementation step. From the initial

studies, EPRI concluded that the metallic iron cementation approach is promising for treating 

FGD wastewater for multiple species of selenium, including selenite, selenate, and other 

unknown selenium compounds [EPRI, 2008b]. 

EPRI continued its study of iron cementation by specifically designing a pilot-scale 

system to remove selenium and installing the prototype at a plant burning coal from the powder 

river basin with FGD wastewater containing high levels of total dissolved solids (TDS), sulfate, 

magnesium, nitrate/nitrite-nitrogen, and selenium. Additionally, EPRI evaluated the 

effectiveness of the pilot-scale treatment system under continuous flow conditions. The study 

showed that iron cementation does reduce selenium, specifically at a lower pH and a greater 

hydraulic retention time. EPRI stated that increasing the hydraulic retention time improves the 

dissolution of the metallic selenium ion. The study results also show that selenium removal and 

iron dissolution are directly related; however, the pilot-scale system was unable to duplicate the 

selenium removal levels observed in the previous bench-scale testing described above. Under 

ideal operating conditions, the bench-scale testing showed that iron cementation reduced 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-20 

dissolved selenium to less than 0.05 mg/L; however, the pilot-scale testing’s lowest selenium 

effluent concentration was 0.159 mg/L. Additionally, EPRI also evaluated mercury removals 

from a limited data set. EPRI found that mercury was significantly reduced (by a range of 84 to 

97 percent) in the iron reactor [EPRI, 2009b]. 

Reverse Osmosis

Reverse osmosis systems are currently in use at steam electric power plants, usually to 

treat boiler make-up water or cooling tower blowdown wastewaters. EPRI identified a highefficiency reverse osmosis (HEROTM) process that operates at a high pH, allowing the system to 

treat wastewaters with high silica concentrations without scaling or membrane fouling because 

silica is more soluble at higher pHs. The wastewater undergoes a water-softening process to raise 

its pH before entering the HEROTM system.

Although the HEROTM system is currently in use in the industry to treat steam electric 

power plant cooling tower blowdown wastewater, its use for FGD wastewater is potentially 

limited due to the osmotic pressure of the FGD wastewater resulting from the high 

concentrations of chlorides and TDS [EPRI, 2007]. Although many plants may not be able to use 

the HEROTM system to treat FGD wastewater, some plants with lower TDS and chloride 

concentrations may be able to. The HEROTM system is of particular interest for treating boron in

FGD wastewaters because boron becomes ionized at an elevated pH and, therefore, could be 

removed using a reverse osmosis system [EPRI, 2007]. 

Sorption Media 

The drinking water industry uses sorption media to remove arsenic from the drinking 

water. Because of its success at removing similar pollutants found in FGD wastewater, 

specifically arsenic, EPRI reviewed sorption media technologies to determine whether they are 

applicable for treating FGD wastewater. These sorption processes adsorb pollutants onto the 

media’s surface area using physical and chemical reactions. EPRI determined the most effective 

adsorbents are metal-based single-use products, which can be disposed of in nonhazardous 

landfills. EPRI also determined granular ferric oxide or hydroxide- and titanium-based oxides are 

the most prevalent adsorbent at the time of the study. Ferric- and titanium-based media 

effectively remove both common forms of arsenic (arsenate and arsenite) and selenium (selenite) 

over a wide pH range [EPRI, 2007]. 

EPA identified one plant that treats its FGD wastewater with a chemical precipitation 

system followed by a full-scale treatment unit that uses cartridge filters in combination with two 

sets of adsorbent media specifically designed to enhance removals of metals. After passing 

through three sets of cartridge filters (3-micron, 1-micron, and then 0.2 micron), the FGD 

wastewater passes through a carbon-based media that adsorbs mercury, and then through a ferric 

hydroxide-based media that adsorbs arsenic, chromium, and other metals. The adsorbent media 

reportedly achieves a maximum effluent concentration of 14 parts per trillion for mercury. 

[Smagula, 2010] 

According to Siemens, the vendor of the adsorption media technology used in the fullscale operation, the capital costs for a system including the two sets of adsorption media could 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-21 

range from $200,000 to $2,000,000 dollars, depending on the flow rate, influent concentrations, 

and system configurations. Siemens estimates that the O&M costs for the carbon-based media 

are approximately $2 per 1,000 gallons treated and the O&M costs for the ferric hydroxide media 

are approximately $1 per 1,000 gallons treated. [Schultz, 2013] 

Ion Exchange 

Ion exchange systems are currently in use at power plants to pretreat boiler make-up 

water. Ion exchange systems remove specific constituents from wastewater; therefore, the system 

can target specific metals to be removed. The ion exchange resin works by substituting one ion 

for another on a specific resin, which must be replaced or regenerated when full [AEP, 2010]. 

The typical metals targeted by ion exchange systems include boron, cadmium, cobalt, copper, 

lead, mercury, nickel, uranium, vanadium, and zinc. Although the ion exchange process does not 

generate any residual sludge, it does generate a regenerant stream that contains the metals 

stripped from the wastewater [AEP, 2010]. 

In 2008, a pilot test was performed that evaluated mercury removals from filtration and 

ion exchange. The system was successful in removing trace mercury from FGD wastewater; 

however, the filtration process and not the ion exchange system removed most of the colloidal 

mercury [Goltz, 2009]. Additionally, EPA identified one plant that tested two ion exchange 

resins for treating FGD wastewater, specifically mercury removal. The plant determined that 

while the resin can remove dissolved mercury, it is not effective at removing particulate or 

colloidal mercury [AEP, 2010]. 

EPA identified one plant that has installed ion exchange systems to treat FGD 

wastewater. This plant operates a full-scale ion exchange system that selectively targets the 

removal of boron, in conjunction with a chemical precipitation treatment stage to remove 

mercury and other metals, and an anaerobic biological treatment stage to remove selenium 

[ERG, 2013f]. 

Electro-Coagulation 

Electro-coagulation uses an electrode to introduce an electric charge to the wastewater, 

which neutralizes the electrically charged colloidal particles allowing them to precipitate out of 

solution. These systems typically use aluminum or iron electrodes, which dissolve into the 

wastestream during the process. The dissolved metallic ions precipitate with the other pollutants 

in the wastewater and form insoluble metal hydroxides. EPRI believes additional polymer or 

supplemental coagulants may need to be added to the wastewater depending on the specific 

characteristics. These systems are typically used to treat small wastestreams, ranging from 10 to 

25 gpm, but may also be able to treat wastestreams of up to 50 or 100 gpm [EPRI, 2007]. 

Other Technologies 

EPA obtained only limited information on other technologies under laboratory-scale 

study, including polymeric chelates, taconite tailings, and nano-scale iron reagents. In addition, 

EPRI is investigating various physical treatment technologies, primarily to remove mercury, 

including filtration [EPRI, 2008a]. 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-22 

7.2 FLY ASH HANDLING, MANAGEMENT, AND TREATMENT TECHNOLOGIES

During the Steam Electric Power Generating study and rulemaking, EPA identified and 

investigated fly ash handling systems operated by coal-, petroleum coke-, and oil-fired steam 

electric power plants to collect and convey fly ash, that are designed to minimize or eliminate the 

discharge of pollutants in fly ash handling transport water. As part of the proposed rulemaking, 

EPA considered chemical precipitation for the treatment of fly ash transport water. However, 

EPA has not identified any plants using this treatment technology to treat fly ash transport water, 

although EPA has reviewed two literature sources that describe laboratory- or pilot-scale tests

using the technology. Upon reviewing the discharge flow rate for fly ash transport water; 

however, EPA determined that the capital and operating and maintenance (O&M) costs 

associated with treatment were comparable to the costs of converting to dry handling 

technologies, despite being less effective at removing pollutants. Therefore, EPA did not select 

chemical precipitation as a treatment technology option for fly ash in this proposed rule. A list of 

the fly ash handling technologies evaluated by EPA, including a brief description of each, are 

included below. This section describes in detail the fly ash handling technologies listed below. 

• Wet Sluicing Systems: These systems convey fly ash wet using water-powered 

hydraulic vacuums that pull the fly ash from the hopper to a separator/transfer tank, 

where the fly ash combines with the transport water flowing through the sluice pipes. 

Plants usually direct the resulting sluice to a surface impoundment. 

• Wet Vacuum Pneumatic Systems: These systems convey dry fly ash to a silo using 

water-powered hydraulic pumps to withdrawal fly ash from the hopper and filterreceivers to collect the fly ash dry.

• Dry Vacuum Systems: System that uses a mechanical exhauster to move air, below 

atmospheric pressure, to pull the fly ash from the hoppers and convey it directly to a 

silo.

• Pressure Systems: These systems convey dry fly ash to a silo using air produced by a 

positive displacement blower directly to a silo.

• Combined Vacuum/Pressure Systems: These systems use a dry vacuum system to pull 

ash from the hoppers to a transfer station, where is introduced to a high pressure 

conveying line that conveys the dry ash directly to a silo. 

• Mechanical Systems: Manual or systematic systems plant’s operating units with a low 

volume of fly ash operate remove fly ash from the hopper. 

Coal-, petroleum coke-, and oil-fired power plants use particulate control technologies 

such as electrostatic precipitators (ESPs), baghouse filters, or venturi-type wet scrubbers to 

remove fly ash particles from the flue gas. Section 4 discusses the various types of fly ash 

collection methods used in the Steam Electric Industry. After collection, fly ash particles transfer 

to hoppers where plants transport fly ash via wet sluicing, dry handling, or a combination of both 

to its next destination. From information provided in the Steam Electric Survey, EPA determined 

that 481 coal-, petroleum coke-, and oil-fired power plants, corresponding to 1,074 coal- and 

petroleum coke-fired units and 30 oil-fired units, generate fly ash. Most of these plants 

(approximately 70 percent) currently transport fly ash from all of their coal-, petroleum coke-, or 

oil-fired steam electric generating units using dry handling systems or other processes that do not 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-23 

require wet sluicing. As shown in Figure 7-6, approximately 19 percent of coal- and petroleum 

coke-fired units operate wet sluicing only systems to collect fly ash, whereas half of the oil-fired 

units operate wet sluicing systems. Based on survey responses, the numbers of plants wet 

sluicing fly ash will decline by 2014. From survey data, EPA identified nine plants 

(corresponding to 18 coal-fired units) operating wet sluicing systems that will convert from wet 

to all dry handling operations by January 2014. Additionally, from publicly available data, ERG 

identified another eight plants, corresponding to 39 coal-fired units, that announced they will 

convert from wet to all dry handling operations [ERG, 2013d]. Plants operating dry handling 

systems typically sell the collected fly ash to available markets or condition it with moisture 

prior to disposal in a landfill. For Figure 7-6, EPA grouped each coal- petroleum coke-, and oilfired generating unit into one of the following three categories based on the type of fly ash 

handling system operated by the unit: 

• Units with wet sluicing systems only;

• Units with any other type(s) of handling system listed above (excluding wet sluicing); 

and

• Units that have multiple fly ash handling systems, including wet sluicing. 

Source: Steam Electric Survey [ERG, 2013g].

Figure 7-6. Distribution of Fly Ash Handling Systems for Coal-, Petroleum Cokeand Oil-Fired Units in the Steam Electric Industry

Based on information provided in the Steam Electric Survey, the number of plants 

installing fly ash handling systems other than wet sluicing systems on new units, or converting 

existing units, is increasing due to their ability to market fly ash and reduce water consumption. 

Excluding wet sluicing systems, the most common type of fly ash handling system currently in 

operation is the dry vacuum system (approximately 49 percent of non-wet-sluicing systems). 

Figure 7-7 shows the distribution of fly ash handling systems, excluding any units with wet 

sluicing systems only or units with combination wet and dry handling systems, reported in the 

Steam Electric Survey for coal-, petroleum coke-, and oil-fired units. EPA grouped other 

handling systems, mechanical systems, and a combination of multiple systems, excluding wet 

sluicing, as “Other/Mechanical” in Figure 7-7. 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-24 

Source: Steam Electric Survey [ERG, 2013g].

Figure 7-7. Distribution of Fly Ash Handling System Types Other Than Wet 

Sluicing for Coal-, Petroleum Coke-, and Oil-fired Units Reported in the

Steam Electric Survey

The following sections discuss fly ash handling systems currently operating in the 

industry, including wet sluicing systems and systems that minimize or eliminate the need for fly 

ash transport water.

7.2.1 Wet Sluicing System

In a wet sluicing system, water-powered hydraulic vacuums create the vacuum for the 

initial withdrawal of fly ash from the hoppers. The vacuum pulls the ash to a separator/transfer 

tank, where the fly ash combines with the transport water flowing through the sluice pipes. The 

sluice pipes transfer the resulting fly ash slurry to an ash impoundment. Section 6.2.3 describes 

wet sluicing operations in the steam electric industry in more detail.

Fly ash transport water is typically treated in large surface impoundments, either 

completely separate from or commingled with other combustion residual wastes. Impoundments 

vary in size, capacity, age, and most impoundments receive other plant wastewater (e.g., boiler 

blowdown, cooling water, low volume wastewater). Plants typically size the impoundments to 

provide enough residence time to reduce the TSS levels in the wastewater to meet the discharge 

requirement and to allow for a certain lifespan of the impoundment based on the expected rate of 

solids buildup within the impoundment. 

Surface impoundments can reduce the amount of TSS in the wastewater discharge 

provided sufficient residence time. In addition to TSS, surface impoundments can also reduce 

some specific pollutants in the particulate form to varying degrees in the wastewater discharge.

However, surface impoundments are not designed to reduce the amount of dissolved metals in 

the wastewater. While most plants discharge the overflow from the surface impoundment, some 

plants reuse a portion, or all, of the surface impoundment effluent as make-up for the fly ash 

transport water system. Additionally, some plants reuse the effluent for other plant operations. In 

these cases, much like discharged ash transport water, recycled transport water is often treated 

only via settling. Some plants, however, also have pH control systems to adjust the pH of the 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-25 

impoundment or the impoundment effluent stream to mitigate the potential for corrosion of the 

boiler and ash handling equipment. 

Power plants operate and maintain the impoundments in varying ways. For example, 

some plants constantly remove settled ash solids from the impoundment inlet and stack them on 

the sides of the impoundment to dewater and build up the height of the impoundment. 

Alternatively, some plants periodically dredge the impoundment to remove the ash from the 

bottom and transfer the solids off site for disposal or to an on-site landfill, or use the solids to 

build up the height of the impoundment. Finally, some plants may not dredge the impoundment, 

but leave the ash in the impoundment permanently and, when the impoundment reaches its 

capacity, build a new ash impoundment and decommission the old impoundment. 

7.2.2 Wet Vacuum Pneumatic System

Wet vacuum pneumatic systems are fly ash handling systems that use water-powered 

hydraulic vacuums to create the vacuum for the initial withdrawal of fly ash from the hoppers, 

similar to wet sluicing systems. However, the fly ash is not directed to a separator/transfer tank 

and is not combined with the water flowing through the sluice pipes. Instead, the fly ash is 

captured by a filter-receiver (i.e., bag filter with a receiving tank) placed before the junction 

where the fly ash would have been mixed with the sluice water. Wet vacuum pneumatic systems 

are able to convey dry ash up to 50 tons per hour (tph) and 500 feet [Mooney, 2010]. From the 

filter-receiver tank, the system deposits the fly ash into a silo. The silo receiving the ash is 

equipped with an exhauster that displaces the air from the vacuum created by the hydraulic pump 

and a baghouse filter that captures the fly ash in the silo. 

From the silo, the fly ash is either sold to an available market or moisture conditioned and 

sent to a landfill. For unloading the ash for sale or conditioning, silos are usually equipped with 

dry unloaders, wet unloaders, or a combination of unloading equipment for each disposal 

method. The dry unloaders are conical shaped spouts, with a vacuum system to control fugitive 

dust. The system loads the ash, with a moisture content of less than one percent, from the spout 

into vacuum-sealed trucks, which transport the ash to the market destination. Wet unloaders use 

pugmills to simultaneously unload the fly ash and increase the moisture content of the ash by 

conditioning it with water. Pugmills condition the fly ash to between 15 and 20 percent moisture 

before it is unloaded into uncovered dump trucks. Responses in the Steam Electric Survey show 

that plants use the following types of water to moisture condition fly ash at silo locations: 

• Raw intake water;

• Intake water that is treated prior to use;

• Cooling tower blowdown; 

• General runoff; 

• Floor drain wastewater;

• Leachate;

• Recycled process water;

• FGD wastewater; and
Section 7 – Treatment Technologies and Wastewater Management Practices

7-26 

• Bottom ash transport water. 

After moisture conditioning and loading, the trucks transport the ash to the landfill. Some 

silos are equipped with both wet and dry unloading capabilities for flexibility with the fly ash 

market.

The wet vacuum pneumatic system is not commonly installed on new units; however, the 

system is attractive to plants that are converting existing units from wet to dry fly ash handling 

because it allows the plants to reuse the existing vacuum source. The bag filters used to collect 

the fly ash prior to mixing with the vacuum water are unable to remove 100 percent of the fly 

ash; therefore, a small amount of fly ash contaminates the water generated from the system. 

Different from fly ash transport water associated with wet sluicing systems, whose purpose is to 

transport ash to an impoundment or other treatment, the purpose of the wet vacuum pneumatic 

vacuum water is strictly to create the vacuum to move the ash to the silo, and not to transport the 

ash to other locations outside of the system. While this stream is contaminated with a small 

amount of carryover fly ash, according to survey responses, most plants operating this type of 

system transfer the wastewater to an impoundment and reuse the overflow in the wet vacuum 

pneumatic system.

7.2.3 Dry Vacuum System 

Dry vacuum systems use a mechanical exhauster to move air, below atmospheric 

pressure, to pull the fly ash from the hoppers and convey it directly to a silo. Dry vacuum 

systems can convey dry ash up to 60 tph and typically up to 1,000 feet [Mooney, 2010]. From 

discussions with fly ash handling vendors, EPA determined that some dry vacuum systems can 

convey ash up to 1,500 feet (at 30 to 50 tph), depending on capacity requirements, line 

configuration, and plant altitude [McDonough, 2011]. The fly ash empties from the hoppers into 

the conveying system via a material handling valve. Similar to the silo configuration described in 

Section 7.2.2, the silo is equipped with an aeration system and baghouse filter to receive the fly 

ash from the hopper. From the silo, the plant either sells the fly ash or disposes of it in a landfill. 

The unloading procedures described in Section 7.2.2 also apply to the dry vacuum system. See 

Figure 7-8 for a schematic of a typical dry vacuum fly ash handling system set-up. 

Dry vacuum systems have fewer components than pressure systems, allowing for more 

flexibility for installing them under existing hoppers. Dry vacuum systems can also start and stop 

automatically during operation, due to the components and nature of the vacuum system. 

Vacuum systems maintain cleaner operations than other conveyance methods because any leaks 

simply pull ambient air into the system [Babcock and Wilcox, 2005].
Section 7 – Treatment Technologies and Wastewater Management Practices

7-27 

Graphic reprinted with permission from FLSmidth Inc. [FLSmidth, 2012].

Figure 7-8. Schematic of Dry Vacuum, Pressure, and Combined Vacuum/Pressure System

7.2.4 Pressure System

A pressurized system uses air produced by a positive displacement blower to convey ash 

directly from the hoppers to a silo. Each hopper collecting ash is equipped with airlock valves 

that transfer the fly ash from low pressure to high pressure in the conveying line, shown in 

Figure 7-9. The airlock valves are transfer points that accept ash at a low pressure, separate it 

from the air pressure in the bottom of the hoppers, and then release the ash to the high pressure 

conveying line [Babcock and Wilcox, 2005]. Once in the conveying line, the system transports 

the fly ash directly to the silo. Because of the high-pressure air, the aeration system at the silo is 

less sophisticated than those used for wet vacuum pneumatic systems (Section 7.2.2), because a 

vacuum is not involved in the operation. From the silo, the plant either sells the fly ash or 

disposes of it in a landfill. The unloading procedures described in Section 7.2.2 also apply to the 

pressure system. See Figure 7-8 for a schematic of a typical pressure fly ash handling system setup. 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-28 

Graphic reprinted with permission from Steve Stultz [Babcock and Wilcox, 2005].

Figure 7-9. Pressure System Airlock Valve

Plants use pressure systems to convey more ash longer distances compared to a dry 

vacuum systems: 100 tph of fly ash for distances up to 5,000 feet [Mooney, 2010]. Depending on 

the conveying capacity requirements, pressurized systems can convey ash up to 8,000 feet 

[McDonough, 2011]. The airlock valves (see Figure 7-9) at the bottom of the hoppers, however, 

require a significant amount of available headspace for installation; therefore, not all plants 

currently operating wet sluicing systems would be able to easily install pressure systems without 

significant capital investment to raise the bottom of the hopper. Additionally, pressure systems 

are not able to stop and start automatically because airlock valves require manual stop and 

restart. Pressure systems can also experience leaks of fine ash particulates, usually at the piping 

joints due to the high pressure in the conveying line [Babcock and Wilcox, 2005].

7.2.5 Combined Vacuum/Pressure System

Combined vacuum/pressure fly ash handling systems utilize both dry vacuum and 

pressure systems. A mechanical exhauster moves air, below atmospheric pressure, to pull the fly 

ash from the hoppers, similar to the dry vacuum system. After a short distance, approximately 

800 feet or less, the system directs the fly ash to an intermediate transfer vessel, such as a filter 

separator, where it transfers the ash from the vacuum (low pressure) to ambient pressure. From 

the filter separator, the system transfers the fly ash to airlock valves that convey the ash to the 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-29 

high pressure conveying line. This conveying line can convey ash up to 8,000 feet [McDonough, 

2011] directly to a silo. Because the second portion of the combination system is a pressure 

system, the aeration system at the silo is less sophisticated than for a dry vacuum system, as 

described above for the pressure system. From the silo, the plant either sells the fly ash or 

disposes of it in a landfill. The unloading procedures described in Section 7.2.2 also apply to the 

combined vacuum/pressure system. See Figure 7-8 for a schematic of a typical combined 

vacuum/pressure fly ash handling system set-up. 

Plants use combination systems to transport fly ash longer distances than vacuum systems 

alone can, while retaining the space advantages of the dry vacuum system (i.e., no additional 

headspace required under the hopper). Manual stop and restart is still required to transfer fly ash 

from the vacuum to the pressure system. Additionally, leaks of fine ash particles will also occur 

at the piping joints due to the high-pressure portion of the system [Babcock and Wilcox, 2005].

7.2.6 Mechanical System

Mechanical fly ash handling systems usually service units that generate a low volume of 

fly ash. These units are usually oil-fired units, which typically produce less ash than coal-fired 

units. Mechanical systems include any manual or systematic approach to removing fly ash. 

Based on responses to the Steam Electric Survey, the systems include periodic scheduled 

cleanings of the boiler or manual removal. Manual removal procedures include scraping the sides 

of the boilers with sprayers or shovels, then collecting and removing the fly ash to an 

intermediate storage destination or sending it to a landfill.

EPA is also aware of one plant that retrofitted an oil unit with a mechanical system that 

included collecting fly ash with vactor trucks. A vactor truck is a vacuum with a portable pump 

to collect the fly ash from the roll-off dumpster. The collection system includes vacuum piping 

that transports fly ash in the bottom of the hoppers to a roll-off vacuum container. For plants with 

multiple hoppers, the fly ash is conveyed to the roll-off vacuum container one hopper at a time 

by closing the valves below the other hoppers. A vactor truck connects to the roll-off container, 

vacuums the fly ash to the truck, and disposes of the fly ash off site. Steam electric power plants 

can operate this system themselves or contract the vactor truck operation and off-site disposal to 

an outside vendor [ERG, 2013g]. 

7.3 BOTTOM ASH HANDLING, MANAGEMENT, AND TREATMENT TECHNOLOGIES

During the Steam Electric Power Generating study and rulemaking, EPA identified and 

investigated bottom ash handling systems operated by coal-, petroleum coke-, and oil-fired steam

electric power plants to collect and convey bottom ash, that are designed to minimize or 

eliminate the discharge of pollutants associated with bottom ash transport water. As part of the 

proposed rulemaking, EPA considered chemical precipitation for the treatment of bottom ash 

transport water. However, upon reviewing the discharge flow rate for bottom ash transport water, 

EPA determined that the capital and O&M costs associated with treatment were comparable to 

the costs of converting to dry handling or closed-loop recycle technologies, despite being less 

effective at removing pollutants. Therefore, EPA did not select chemical precipitation as a 

treatment technology option for bottom ash in this proposed rule. A list of the bottom ash 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-30 

handling technologies evaluated by EPA, including a brief description of each, are included 

below. This section describes in detail the bottom ash handling technologies listed below. 

• Wet Sluicing Systems: These systems convey bottom ash wet from a quench bath 

underneath the boiler via slurry lines. Plants usually direct the resulting sluice to a 

surface impoundment. 

• Mechanical Drag System: These systems are located directly underneath the boiler. 

The bottom ash is collected in a water quench bath. A drag chain conveyor pulls the 

bottom ash out of the water bath on an incline to dewater the bottom ash. 

• Remote Mechanical Drag System: These systems transport bottom ash using the same 

processes as wet sluicing systems to a remote mechanical drag system. A drag chain 

conveyor pulls the bottom ash out of the water bath on an incline to dewater the 

bottom ash. 

• Dry Vacuum or Pressure System: These systems transport bottom ash from the boiler 

to a dry hopper without using any water. Air is percolated through the ash to cool it 

and combust unburned carbon. Cooled ash then drops to a crusher and is conveyed 

via vacuum or pressure to an intermediate storage destination. 

• Vibratory Belt System: Bottom ash deposits on a vibratory conveyor trough, where 

the ash is air cooled and ultimately moved through the conveyor deck to an 

intermediate storage destination.

• Mechanical Systems: Manual or systematic systems plant’s operating units with a low 

volume of bottom ash operate remove bottom ash from the hopper. 

• Complete Recycle: Manual or systematic systems plant’s operating units with a low 

volume of fly ash operate remove fly ash from the hopper. 

From information provided in the Steam Electric Survey, EPA determined that 510 coal-, 

petroleum coke-, petroleum coke-, and oil-fired power plants, corresponding to 1,083 coal- or 

petroleum coke-fired units and 33 oil-fired units, generate bottom ash. Figure 7-10 shows a 

distribution of the coal-, petroleum coke-, and oil-fired units based on their type of bottom ash 

handling system(s). For this figure, the systems are grouped into the following three categories: 

• Units with wet sluicing systems only;

• Units with systems that eliminate bottom ash transport water; and

• Units with multiple bottom ash handling systems, including wet sluicing.

Approximately 72 percent of the 510 steam electric power plants mentioned above 

currently operate wet sluicing handling systems on all steam electric generating units that 

produce bottom ash. The remaining plants currently operate systems other than wet sluicing 

systems, exclusively or in combination with wet sluicing systems. As shown in Figure 7-10, 

approximately 80 percent of coal- and petroleum coke-fired units use only wet sluicing systems 

to handle bottom ash, whereas over 95 percent of oil-fired units use systems that do not use 

bottom ash transport water. From survey data, EPA expects approximately eight plants, 

corresponding to 15 coal-fired units, that operate wet sluicing systems to convert from wet to dry 

or closed-loop recycle systems by January 2014. Additionally, from publicly available data, EPA 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-31 

expects another 11 plants, corresponding to 59 coal-fired units, to convert from wet to dry or 

closed-loop complete system systems [ERG, 2013d]. After collecting the ash, plants can sell 

dewatered or dry bottom ash or send it to a landfill. 

Source: Steam Electric Survey [ERG, 2013g].

Figure 7-10. Distribution of Bottom Ash Handling Systems for Coal-, Petroleum 

Coke-, and Oil-Fired Units Reported in the Steam Electric Survey

Information provided in the Steam Electric Survey and vendor data shows the number of 

plants installing mechanical drag systems on new units is increasing [McDonough, 2011]. From 

the Steam Electric Survey and EIA data, approximately 70 percent of steam electric generating 

units that began operating in the last ten to 25 years are installing handling systems other than 

wet sluicing. Of those systems, 55 percent are mechanical drag systems [ERG, 2013g]. Figure 

7-11 shows the distribution of bottom ash handling systems, excluding units with any wet 

sluicing systems, reported in the Steam Electric Survey for coal-, petroleum coke-, and oil-fired 

units. Steam electric generating units with more than one type of bottom ash handling system, 

excluding wet sluicing systems, or other mechanical systems were included as “Other” in Figure 

7-11. 

Source: Steam Electric Survey [ERG, 2013g].

Figure 7-11. Distribution of Bottom Ash Handling System Types Other Than Wet Sluicing 

for Coal-, Petroleum Coke-, and Oil-Fired Units Reported in the Steam Electric Survey
Section 7 – Treatment Technologies and Wastewater Management Practices

7-32 

Steam electric generating units that produce bottom ash collect the ash particles in 

hoppers, or other types of collection equipment, directly below the boilers. Generally, boilers are 

sloped inward and have an opening at the bottom to allow the bottom ash to feed by gravity into 

the ash collection system (i.e., hoppers or the trough of a mechanical drag system). The 

following sections discuss current bottom ash wet sluicing systems in the industry in addition to 

those that minimize or eliminate the discharge of bottom ash transport water.

7.3.1 Wet Sluicing System

In a wet sluicing system, bottom ash hoppers are filled with water to quench the hot 

bottom ash as it enters the hopper. Once the hoppers are full of bottom ash, a gate at the bottom 

of the hopper opens and the ash is directed to grinders to grind the bottom ash into smaller pieces

(Babcock & Wilcox, 2005). As the gates at the bottom of the hoppers open, they release the 

bottom ash and water, emptying the water quench bath in the hopper. Once the gates are closed, 

the bottom of the hopper fills with water. Because of the batch style process, bottom ash removal 

is not continuous. 

After the bottom ash passes through the grinder, the system feeds the bottom ash to the 

conveying line. The plant then dilutes the bottom ash with water to approximately 20 percent 

solids (by weight) and pumps the bottom ash slurry to an impoundment or a dewatering bin for 

solids removal. Section 6.2.3 describes wet sluicing operations in the steam electric industry in 

more detail.

Similar to fly ash transport water, bottom ash transport water is typically treated in large 

surface impoundments, either completely separate from or commingled with other combustion 

residual wastes. See Section 7.2.1 for more information on how plants typically maintain ash 

impoundments. 

As stated above, the bottom ash slurry can either be transferred to an impoundment or a 

dewatering bin. For dewatering bin systems, plants usually operate two dewatering bins so that 

while one bin fills, the other is dewatered and the ash is unloaded into trucks or rail cars. As the 

bins fill with bottom ash transport water, the particulates are contained at the bottom of the bin. 

Excess water in the bin flows over a serrated overflow weir, leaving the dewatering bin. At the 

top of the bin, an underflow baffle prevents finer particulates from floating out of the bin with 

the overflow [Babcock & Wilcox, 2005]. As the dewatering bin continues to receive bottom ash 

transport water, it eventually reaches its solids loading capacity, at which time the plant directs 

the bottom ash transport water to another dewatering bin and begins the decant process in the 

first bin. The bottom ash transport water exiting the top of the bin and the water that is decanted 

from the bin prior to removing the solids, can either overflow to additional settling tanks or be 

pumped to a surface impoundment. Figure 7-12 presents a diagram of a dewatering bin system 

with additional settling tanks after the dewatering bins.
Section 7 – Treatment Technologies and Wastewater Management Practices

7-33 

Graphic reprinted with permission from United Conveyor Corporation [UCC, 2009]. 

Figure 7-12. Bottom Ash Dewatering Bin System 

7.3.2 Mechanical Drag System

Mechanical drag systems collect bottom ash from the bottom of the boiler, similar to the 

description above for the wet sluicing system. Because of the shape of the boiler, explained 

above, the bottom ash is gravity fed through the opening at the bottom of the boiler, through a 

transition chute, and into a water-filled trough. The water bath in the trough quenches the hot 

bottom ash as it falls from the boiler and seals the boiler gases. The drag system comprises a 

drag chain with a parallel pair of chains. The chains are attached with crossbars at regular 

intervals along the bottom of the water bath and move in a continuous loop towards the far end 

of the bath. At the far end, the drag chain begins moving up an incline, which dewaters the 

bottom ash by gravity, draining the water back to the trough as the bottom ash moves upward. 

Because the bottom ash falls directly into the water bath from the bottom of the boiler and the 

drag chain moves constantly on a loop, bottom ash removal is continuous. The dewatered bottom 

ash is often conveyed to a nearby collection area, such as a small bunker outside the boiler 

building, from which it is loaded onto trucks and either sold or transported to a landfill. See 

Figure 7-13 for a diagram of a mechanical drag system.

Because the trough has a water bath, the mechanical drag system does generate some 

water (i.e., residual water that collects in the storage area as the bottom ash continues to 

dewater). This wastewater, however, is typically completely recycled back to the quench water 

bath. Additionally, EPA does not consider this wastewater to be transport water because the 

transport mechanism is the drag chain, not the water. 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-34 

Mechanical drag systems come in various standard widths and require little headspace 

under the boiler; however, the system may not be suitable for all boiler configurations. For 

example, existing boilers located below grade are usually surrounded with support columns and 

positioned close to the floor with the sluice lines 1 to 2 feet above the ground. A mechanical drag 

system would be difficult to install with such space limitations. Mechanical drag systems are not 

able to combine and collect bottom ash from multiple boilers and generally need a straight exit 

from the boiler to the outside of the building. These systems may also be susceptible to 

maintenance outages because bottom ash fragments fall directly on to the drag chain. 

Graphic reprinted with permission from United Conveyor Corporation [UCC, 2009].

Figure 7-13. Mechanical Drag System 

7.3.3 Remote Mechanical Drag System 

Remote mechanical drag systems collect bottom ash using the same operations and 

equipment as wet sluicing systems at the bottom of the boiler. However, instead of sluicing the 

bottom ash directly to an impoundment, the plant pumps the bottom ash transport water to a 

remote mechanical drag system. This type of system has the same configuration as a mechanical 

drag system; however, it has additional dewatering equipment in the trough and is not located 

under the boiler, but rather in an open space on the plant property. See Figure 7-14 for a diagram 

of a remote mechanical drag system. Plants can use this system when converting existing bottom 

ash handling systems where space or other limitations limit the changes that can be made to the 

bottom of the boiler. Currently, one U.S. plant is operating and another plant is installing a 

remote mechanical drag system. The second system is scheduled to begin operating in 2013 

[McDonough, 2012b]. 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-35 

Graphic reprinted with permission from United Conveyor Corporation [McDonough, 2012a].

Figure 7-14. Remote Mechanical Drag System 

The plant pumps the bottom ash transport water from the sluice pipes into the trough of 

the remote mechanical drag system. Similar to dewatering bins (see Section 7.3.7), an underflow 

baffle prevents the finer particles from exiting the trough with the overflow. As shown in Figure 

7-15, the excess transport water in the trough flows over a serrated overflow weir, leaving the 

remote mechanical drag system. The plants collect this overflow water in a basin/sump and reuse 

it in the bottom ash handling system. Because of the chemical properties of bottom ash sluice, 

some plants may have to install a pH adjustment system to treat the overflow prior to recycle to 

prevent scaling and fouling in the system. Similar to the mechanical drag system, the drag chain 

conveys the ash to a collection area and the plant then sells the ash or disposes of it in a landfill. 

The settled bottom ash is removed from the trough using the same drag system described 

in Section 7.3.2. The bottom ash can be loaded directly onto trucks and either sold or transported 

to a landfill. Remote mechanical drag systems are larger than mechanical drag systems located at 

the bottom of the boiler, for comparative units, because the remote systems receive excess water 

that must be separated from the bottom ash. Additionally, the remote mechanical drag systems 

can service multiple units [Fleming, 2011]. 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-36 

Graphic reprinted with permission from Clyde Bergemann 

Power Group [CBPG, 2012].

Figure 7-15. Water Flow Inside the Remote Mechanical Drag System Trough 

The remote mechanical drag system essentially combines a mechanical drag system and a 

dewatering bin. However, because the remote mechanical drag system is located away from the 

boiler and is close to the ground, unlike a traditional dewatering bin, there is little increase in the 

total dynamic head requirements on the existing pumps and no additional water requirements 

compared with a traditional wet sluicing system. Also, because the remote mechanical drag 

system is not located underneath the boiler and the bottom ash particles have already been 

through a grinder, these systems require less maintenance than mechanical drag systems 

[Fleming, 2011]. The plant then sells the ash or disposes of it in a landfill. Unlike the mechanical 

drag system, remote mechanical drag systems are not located at the bottom of the boiler and 

therefore requires water to transport ash to the system. The water associated with the remote 

mechanical drag system is ash transport water because, like a sluicing system, the water is the 

transport mechanism that moves the bottom ash away from the hoppers. 

7.3.4 Dry Vacuum or Pressure System

Dry vacuum or pressure bottom ash handling systems transport bottom ash from the 

bottom of the boiler into a dry hopper, without using any water. The system percolates air into 

the hopper to cool the ash, combust additional unburned carbon, and increase the heat recovery 

to the boiler. Periodically, the grid doors at the bottom of the hopper open to allow the ash to 

pass into a crusher that crushes the bottom ash into smaller pieces. The system then conveys the 

crushed bottom ash by vacuum or pressure to an intermediate storage facility [UCC, 2009]. 

Figure 7-16 presents a typical dry vacuum or pressure bottom ash handling system. 

Dry vacuum or pressure systems eliminate water requirements and improve heat recovery 

and boiler efficiency. These systems are also less complicated to retrofit to existing units because 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-37 

there are less structural limitation (e.g., headspace requirements below the boiler) and the 

systems can be installed to collect bottom ash from multiple boilers (e.g., one intermediate 

storage facility for multiple units). The plant then sells the ash or disposes of it in a landfill.

Graphic reprinted with permission from United Conveyor Corporation [UCC, 2009]. 

Figure 7-16. Dry Vacuum or Pressure Bottom Ash Handling System

7.3.5 Vibratory Belt System 

Vibratory belt systems feed bottom ash by gravity from the bottom of the boiler directly 

to a vibratory conveyor trough supported by coil springs, which reduce the stress of impact from 

the falling bottom ash. The vibratory conveyor produces an oscillatory toss-and-catch motion, 

transporting bottom ash in a series of successive throws. With each throw, the ash moves up and 

forward onto the conveyor deck. Controlled forced draft air enters through the vibratory 

conveyor deck to cool, suspend, and enhance oxidation of unburned carbon. The forced draft air 

surrounds the entire ash surface creating a fluidized bed of ash, which is conveyed to an 

intermediate storage destination. The plant then sells the ash or disposes of it in a landfill [UCC, 

2009]. See Figure 7-17 for the layout of a vibratory bottom ash handling system. 

The vibratory system eliminates water requirements and has the lowest power 

consumption of all other bottom ash handling systems. Additionally, unlike other bottom ash 

handling systems, the vibratory system does not have any moving or hinged joints that can 

become damaged from falling boiler slag, decreasing the chance of unscheduled outages for 

maintenance [UCC, 2009]. 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-38 

Graphic reprinted with permission from United Conveyor Corporation [UCC, 2009]. 

Figure 7-17. Vibratory Bottom Ash Handling System

7.3.6 Mechanical System

Similar to fly ash handling systems, mechanical bottom ash handling systems usually 

service units that generate low volumes of bottom ash, or handle fly and bottom ash together. 

These units are usually oil-fired units, which typically produce less ash than coal-fired units. 

Mechanical systems include any manual or systematic approach to removing bottom ash. Based 

on responses to the Steam Electric Survey, the systems can include periodic scheduled boiler 

cleanings or manual ash removal. Both procedures involve scraping the sides of the boilers with 

sprayers or shovels, then collecting and removing the bottom ash to an intermediate storage 

destination. Some plants store the manually collected ash in an ash impoundment, while others 

sell or dispose of the ash in a landfill. 

7.3.7 Complete Recycle System

Complete recycle bottom ash systems transport bottom ash via water, using the same 

process as wet sluicing systems, but all the water that leaves the system is recycled back to the 

bottom of the boiler and/or used as make-up to the bottom ash sluicing system. Because the 

bottom ash is hot and evaporates a portion of the water in the quench bath, the bottom ash 

sluicing system is a net consumer of water, which allows the system to completely reuse all the 

water along with a make-up stream. The complete recycle system can operate using several 

different configurations. The most common configuration in the industry is to operate with 

dewatering bins (described in Section 7.3.1) with the overflow pumped to an impoundment and 

the overflow from the impoundment being pumped back to the bottom ash sluice system. There 

are also several other configurations that achieve complete recycle using tank-based systems that 

do not include impoundments. These tank-based systems can either use dewatering bins or a 

remote MDS. For a dewatering bin complete recycle system, the overflow and decant are 

transferred to additional settling tanks prior to being recycled back to the bottom ash sluice 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-39 

system, as shown in Figure 7-12. In the settling tank, a large percentage of the fine ash carryover 

settles to the bottom and is pumped to the dewatering bin for removal. The plant directs the 

overflow from the settling tank to the surge tank, where recirculation pumps return the water to 

the existing bottom ash handling system or as make-up water to the quench water bath. For a 

remote MDS complete recycle system, the overflow water is collected in a sump prior to being 

recycled back to the bottom ash sluice system. Fine ash that carries over into the sump will 

collect at the bottom of the sump and the plant will need to collect this material occasionally and 

dispose of it off site or in a landfill. 

Some complete recycle systems may need to add chemical treatment, specifically pH 

control, for the overflow/decant water because of the chemical properties in the water. The 

chemical treatment may be necessary to eliminate any scaling or fouling caused by the recycled 

water.

Plants that install complete recycle systems on existing wet sluicing units can reuse all of 

the existing wet sluicing equipment. These systems also allow plants to handle bottom ash from 

multiple boilers. However, because of the amount of equipment and water these systems use, 

complete recycle systems have the highest equipment, maintenance, and power consumption 

requirements of all other bottom ash handling systems. 

Alternatively, plants can achieve complete recycle systems using impoundment systems. 

Some plants discharge the ash to an impoundment, or series of impoundments, to settle and then 

return all effluent from the impoundment, or impoundment system, to the boiler to use as 

transport water. These plants often add additional make-up water to the system to compensate for 

any water lost due to evaporation or water retained in the ash. 

7.4 COMBUSTION RESIDUAL LEACHATE

During the rulemaking, EPA identified and investigated wastewater treatment systems 

and management practices in use by steam electric power plants to treat leachate collected from 

landfills and impoundments containing combustion residual wastes. From industry profile 

information and leachate characterization data, described in Sections 4.3.5 and 6.3, EPA 

determined that combustion residual leachate from landfills and impoundments includes similar 

types of constituents as FGD wastewater. However, EPA determined that concentrations of the 

constituents in combustion residual leachate are generally lower than in FGD wastewater, 

especially for TDS. Based on this characterization of the wastewater, EPA believes that certain 

treatment technologies identified for FGD wastewater, as described in Section 7.1, could also be 

used to treat leachate from landfills and impoundments containing combustion residual wastes. 

Additionally, EPA used information from the Steam Electric Survey, site visits, and 

industry profile to identify wastewater treatment systems and management practices currently 

used, or considered, to treat and manage combustion residual landfill and impoundment leachate. 

The wastewater treatment technologies that EPA identified to treat combustion residual leachate 

include: 

• Surface impoundments; 

• Chemical precipitation;
Section 7 – Treatment Technologies and Wastewater Management Practices

7-40 

• Biological treatment (anoxic/anaerobic system with fixed film bioreactors); and

• Constructed wetlands. 

In the Steam Electric Survey, EPA requested a subset of coal-fired power plants to 

provide information on combustion residual leachate treatment systems and management 

practices used in the industry. From the treatment information received, EPA determined that 

surface impoundments are the most commonly used system to treat combustion residual leachate 

from landfills and impoundments [ERG, 2013g]. Figure 7-18 shows the distribution of 

combustion residual leachate treatment technologies reported in the Steam Electric Survey or 

determined by EPA through industry contacts, for the 29 plants that reported treatment systems 

for combustion residual landfill and impoundment leachate. 

Source: Steam Electric Survey [ERG, 2013g, WVDEP, 2010]. 

Figure 7-18. Distribution of Treatment Systems for Leachate from Landfills 

and Impoundments Containing Combustion Residual Wastes

Additionally, EPA investigated the management practices for combustion residual 

leachate from landfills and impoundments. From information in the Steam Electric Survey, EPA 

determined that 14 plants collect their combustion residual landfill leachate and use it as water 

for moisture conditioning dry fly ash prior to disposal or dust control around dry unloading areas 

and landfills.38 EPA also identified one plant that uses the collected leachate as truck wash and 

routes it back to an impoundment at the plant. 

EPA also identified different management practices for combustion residual 

impoundment leachate. From the Steam Electric Survey, EPA identified approximately 36 

percent of plants collecting combustion residual impoundment leachate recycle the leachate 

directly back to the impoundment from which it was collected. In this case, because the 

 

38 EPA also identified three additional plants that use leachate for moisture conditioning fly ash and/or dust control;

however, EPA was unable to determine if the wastewater is combustion residual landfill or impoundment leachate.
Section 7 – Treatment Technologies and Wastewater Management Practices

7-41 

wastewater originated from the impoundment, the collection system is essentially just capturing 

a portion of the impoundment wastewater and EPA does not consider the wastewater recycled 

directly back to the impoundment as a new wastestream entering the pond. Instead, EPA 

considers it to be the same as the wastewater that is already contained within the impoundment 

system. However, if any of this collected wastewater is transferred to any other process or 

operation, then EPA would consider this a new wastestream that is subject to the proposed 

effluent limitations for combustion residual leachate. EPA also determined that seven plants 

collect their combustion residual impoundment leachate and use it as water for moisture 

conditioning dry fly ash prior to disposal or dust control around dry unloading areas and 

landfills.39

7.5 FLUE GAS MERCURY CONTROL WASTEWATER TREATMENT TECHNOLOGIES

During the rulemaking, EPA identified and investigated wastewater treatment systems 

operated by steam electric power plants to treat wastewater generated from FGMC, as well as 

operating/management practices used to reduce the wastewater discharge. As described in 

Section 4.3.4, the installation of these systems is relatively new to the industry.

Generally, there are two types of FGMC systems, addition of oxidizers to the coal prior 

to combustion, and injection of activated carbon into the flue gas upstream or downstream of the 

primary particulate control system. FGMC systems that add oxidizers simply collect the oxidized 

mercury with the wet FGD system. This does not generate a new wastewater stream; however, it 

may increase the concentration of mercury in the FGD wastewater because the oxidized mercury 

is more easily removed by the FGD system.

In activated carbon injection (ACI) systems, the steam electric power plant injects 

activated carbon either before or after primary particulate control. If activated carbon is injected 

prior to the primary particulate control system, the adsorbed mercury is collected with the fly ash 

and handled according to the technologies described in Section 7.2, including wet sluicing. 

However, if the activated carbon is injected after the primary particulate control system, the plant 

must install a different handling system to handle the FGMC waste. Similar to Section 7.2, these 

systems include:

• Wet Sluicing System: These systems use water-powered hydraulic vacuums to create 

the vacuum for the initial withdrawal of fly ash from the hoppers. The FGMC waste 

is combined with the water used to create the vacuum and then pumped to an ash 

impoundment. 

• Wet Vacuum Pneumatic System: These systems use water-powered hydraulic 

vacuums to create the vacuum for the initial withdrawal of fly ash from the hoppers, 

similar to wet sluicing systems; however, the fly ash is directed to a silo and is not 

combined with the water flowing through the sluice pipes. 

 

39 EPA also identified three additional plants that use leachate for moisture conditioning fly ash and/or dust control; 

however, EPA was unable to determine if the wastewater is combustion residual landfill or impoundment leachate.
Section 7 – Treatment Technologies and Wastewater Management Practices

7-42 

• Dry Vacuum System: These systems use a mechanical exhauster to move air, below 

atmospheric pressure, to pull the fly ash from the hoppers and convey it directly to a 

silo. 

• Pressure System: These systems use air produced by a positive displacement blower 

to convey ash directly from the hopper to a silo. 

• Combined Vacuum/Pressure System: These systems first utilize a dry vacuum system 

to pull ash from the hoppers to a transfer station, and then use a positive displacement 

blower to convey the ash to a silo. 

• Mechanical System: These systems include any manual or systematic approach to 

removing fly ash, such as scraping the sides of the boilers with sprayers or shovels, 

then collecting and removing the fly ash to an intermediate storage destination or 

disposal. 

Based on responses to the Steam Electric Survey, EPA identified 73 power plants that 

operate ACI systems. As discussed in Section 6, 15 of these power plants inject the activated 

carbon downstream of the primary particulate removal system and the remaining 58 plants inject 

the activated carbon upstream of the particulate removal system [ERG, 2013g]. The following 

describes how these plants handle their FGMC wastes:

• Of the downstream ACI systems, only one plant handles the FGMC waste wet. The 

plant identified a planned FGMC system and indicated that the waste will be sluiced 

to a zero discharge impoundment from which solids are landfilled and wastewater is 

recycled within the plant; 

• The remaining 14 downstream ACI systems handle the FGMC waste dry; 

• Of the upstream ACI systems, five plants handle the FGMC waste wet. These plants 

indicated that the waste will be wet sluiced to an impoundment from which solids are 

landfilled and wastewater is potentially discharged;40

• The remaining 53 upstream ACI systems handle the FGMC waste dry.

7.6 GASIFICATION WASTEWATER TREATMENT TECHNOLOGIES

During the rulemaking, EPA identified and investigated wastewater treatment systems 

operated by steam electric power plants to treat wastewater generated at IGCC plants from the 

gasification process, as well as operating/management practices used to reduce the wastewater 

discharge. This section describes the following technologies: 

• Vapor-compression evaporation system; and 

• Cyanide destruction. 

EPA is aware of two plants that currently operate IGCC units in the United States, and 

another plant that is scheduled to begin commercial operation in 2012. All three of these plants 

 

40 Four of these plants do not discharge any flue gas mercury control wastewater; however, one plant does discharge 

the flue gas mercury control wastewater. This one plant has the capability to handle the fly ash and FGMC waste 

using a dry system, but sometimes uses the wet system instead.
Section 7 – Treatment Technologies and Wastewater Management Practices

7-43 

currently treat or plan to treat the IGCC wastewaters with vapor-compression evaporation 

systems. One of these plants plans to install a cyanide destruction system in addition to a vaporcompression evaporation system.

7.6.1 Vapor-Compression Evaporation System 

As described in Section 7.1.4, plants can use vapor-compression evaporation systems to 

treat FGD wastewater and cooling tower blowdown. Additionally, the plants currently operating 

IGCC units are using vapor-compression evaporation systems to treat the IGCC wastewaters 

generated. The treatment system set-up is the same as that described for treating FGD 

wastewater, as discussed in Section 7.1.4; however, unlike the system used to treat FGD 

wastewater, the gasification wastewater does not require the pretreatment chemical precipitation 

and softening steps. 

This vapor-compression evaporation system uses a falling-film evaporator (or brine 

concentrator) to produce a concentrated wastewater stream and a distillate stream. The 

concentrated wastewater stream may be further processed in a crystallizer, spray dryer, or rotary 

drum dryer, in which the remaining water is evaporated, generating a solid waste product and 

potentially a condensate stream. The plant can reuse the distillate and condensate streams or 

discharge them to surface waters. Figure 7-5 presents a process flow diagram for a vaporcompression evaporation system.

7.6.2 Cyanide Destruction

Because the wastewaters from the IGCC process can contain different cyanide 

contaminants (e.g., selenocyanate) formed in the gasification unit, one steam electric power 

plants plans to use cyanide destruction to treat both the distillate and condensate effluent streams 

from the vapor-compression evaporation system. Cyanide destruction treatment involves adding 

sodium hypochlorite (i.e., bleach) to the wastewater in mixing tanks and providing enough 

residence time for the bleach to completely react with the cyanide present.

7.7 METAL CLEANING WASTE TREATMENT TECHNOLOGIES AND MANAGEMENT 

PRACTICES

During the rulemaking, EPA identified the potential for revising the ELGs to include 

BAT/NSPS/PSES/PSNS limitations for nonchemical metal cleaning wastes as part of this 

rulemaking. The rationale for this potential revision is described in Section 8.1.2.7. EPA 

reviewed information reported in response to the Steam Electric Survey to evaluate the 

management practices used to manage and treat chemical and nonchemical metal cleaning 

wastes.

Table 7-1 presents a summary of the destinations reported as receiving metal cleaning 

wastes, broken out by the type of cleaning operation, based on the information reported in 

response to the Steam Electric Survey. 

The Steam Electric Survey data indicate that, to a large extent, chemical and nonchemical 

metal cleaning wastes are managed in similar fashion. For example, both types of wastes may be 

discharged by plants to surface water or POTWs, as reported for 39 percent of nonchemical 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-44 

metal cleaning wastes and 17 percent of chemical metal cleaning wastes. Both types of wastes 

are evaporated during the cleaning operation at some plants (29 percent for chemical metal 

cleaning wastes; 10 percent for nonchemical metal cleaning wastes). Other disposal methods are 

also used for both types of wastes, including offsite treatment, disposal wells, landfilling, and 

other techniques (46 percent for chemical metal cleaning wastes; 29 percent for nonchemical 

metal cleaning wastes). 

The Steam Electric Survey data also indicate that treatment practices for chemical and 

nonchemical metal cleaning wastes are similar. Chemical precipitation was reported as the type 

of onsite treatment system for both chemical and nonchemical metal cleaning wastes (8 percent 

and 11 percent, respectively). Surface impoundments were also used to treat both types of 

wastes, with impoundments being used more frequently for nonchemical metal cleaning wastes. 

This is to be expected since nonchemical cleaning (i.e., without the use of chemical compounds) 

is likely to remove fewer pollutants from metal process equipment, resulting in lower pollutant 

concentrations in the wastewater and, therefore, would more easily meet the current BPT effluent 

limits with surface impoundments (i.e., gravity settling). The data from the Steam Electric 

Survey indicate, however, that some chemical metal cleaning wastes are also sufficiently treated 

by surface impoundments. 

EPA has also conducted a review of permits to identify how discharges of nonchemical 

metal cleaning wastes are being regulated in NPDES permits. To conduct this permit review, 

EPA used responses to the Steam Electric Survey to identify plants that reported generating 

chemical and nonchemical metal cleaning wastes. EPA provided the listing of these plants to the 

EPA Regional offices and asked them to review permits for the following:

1. How is the metal cleaning waste handled at the plant? Is there any distinction 

between chemical cleaning waste and nonchemical cleaning waste? If so, what are 

the limits for each?

2. How is the nonchemical cleaning waste handled at the plant, as metal cleaning 

waste or low-volume waste? What is the limit used?

3. If the non-chemical cleaning waste is handled as low-volume waste, what is the 

basis for this assumption? Does the factsheet make any specific reference to the 

1975 EPA “Jordan Memo” or provide other justification? 

EPA’s Regional offices reviewed permits for 56 steam electric power plants, 45 of which 

are for plants believed to generate nonchemical metal cleaning wastes, based on responses to the 

Steam Electric Survey. For the 45 plants believed to generate nonchemical metal cleaning 

wastes, EPA determined the following: 

• 64 percent of the plants either do not discharge metal cleaning wastes or have to 

comply with effluent limits for copper and iron; 

• Permits for 27 percent of the plants do not include effluent limits for copper and iron; 

and
Section 7 – Treatment Technologies and Wastewater Management Practices

7-45 

• Permits for nine percent of the plants do not include enough information to determine 

whether the plant already operates in a manner that would be in compliance with the 

proposed BAT limitations. 

See the memorandum entitled “Nonchemical Metal Cleaning Waste Permit Review” for 

additional details on the permit review and a compilation of the data received from the EPA 

Regional offices [ERG, 2013e]. 
7-46

Section 7 – Treatment Technologies and Wastewater Management Practices

Table 7-1. Destination of Metal Cleaning Wastewaters 

Cleaning Operation

Immediately 

Recycled 

Back to 

Plant

Transferred to Onsite Treatment System Discharged 

to Surface 

Water or 

POTW

Evaporated 

During 

Cleaning 

Operation

Other 

Disposal 

Methodb

Surface 

Impoundment

Chemical 

Precipitation

Constructed 

Wetland Othera

Non-Chemical Cleaning Operations 4% 58% 11% <1% 2% 39% 10% 29%

Air Compressor Cleaning NA NA NA NA NA NA NA NA

Air-Cooled Condenser Cleaning c c c c c c c c

Air Heater Cleaning 6% 72% 15% <1% 3% 51% 5% 21%

Boiler Fireside Cleaning 6% 70% 10% 0% 2% 50% <1% 29%

Boiler Tube Cleaning 0% 30% 15% 0% 4% 41% 26% 19%

Combustion Turbine Cleaning (Combustion) 0% 0% 0% 0% 0% 0% 50% 50%

Combustion Turbine Cleaning (Compressor) 0% 2% 0% 0% 7% 7% 78% 9%

Condenser Cleaning c 37% 0% 0% 0% 61% 11% 21%

Draft Fan Cleaning 0% 64% 64% 36% 36% 0% 0% 36%

Economizer Cleaning 0% 69% 69% 0% 6% 69% 0% 19%

FGD Equipment Cleaning c 35% 0% 0% 0% 0% 0% 0%

Heat Recovery Steam Generator Cleaning NA NA NA NA NA NA NA NA

Mechanical Dust Collector Cleaning 0% 50% 93% 0% 7% 50% 0% 0%

Nuclear Steam Generator Cleaning NA NA NA NA NA NA NA NA

Precipitator Wash 0% 100% 11% 0% 2% 42% 0% 14%

SCR Catalyst Soot Blowing 0% 0% 0% 0% 0% 0% 100% 0%

Sludge Lancing 0% 44% 0% 0% 44% 0% 0% 14%

Soot Blowing 0% 22% 4% 0% <1% 11% 25% 45%

Steam Turbine Cleaning 0% 9% 9% 0% 0% 26% 0% 43%

Superheater Cleaning NA NA NA NA NA NA NA NA

Chemical Cleaning Operations 2% 17% 8% 0% 12% 17% 29% 46%

Air Compressor Cleaning 0% 0% 0% 0% 100% 0% 0% 0%

Air-Cooled Condenser Cleaning NA NA NA NA NA NA NA NA

Air Heater Cleaning 0% 46% 0% 0% 54% 8% 0% 92%

Boiler Fireside Cleaning 0% 0% 0% 0% 44% 0% 0% 100%

Boiler Tube Cleaning 2% 21% 12% 0% 11% 13% 41% 37%

Combustion Turbine Cleaning (Combustion) 0% 0% 0% 0% 19% 54% 0% 43%
7-47

Section 7 – Treatment Technologies and Wastewater Management Practices

Table 7-1. Destination of Metal Cleaning Wastewaters 

Cleaning Operation

Immediately 

Recycled 

Back to 

Plant

Transferred to Onsite Treatment System Discharged 

to Surface 

Water or 

POTW

Evaporated 

During 

Cleaning 

Operation

Other 

Disposal 

Methodb

Surface 

Impoundment

Chemical 

Precipitation

Constructed 

Wetland Othera

Combustion Turbine Cleaning (Compressor) 2% 1% 0% 0% 11% 30% 9% 52%

Condenser Cleaning 29% c 0% 0% 0% 0% 17% 17%

Draft Fan Cleaning 0% 100% 0% 0% 0% 100% 0% 0%

Economizer Cleaning NA NA NA NA NA NA NA NA

FGD Equipment Cleaning 0% 50% 0% 0% 50% 0% 0% 0%

Heat Recovery Steam Generator Cleaning 0% 0% 0% 0% 0% 0% 13% 100%

Mechanical Dust Collector Cleaning NA NA NA NA NA NA NA NA

Nuclear Steam Generator Cleaning 0% 0% 0% 0% 100% 100% 0% 0%

Precipitator Wash NA NA NA NA NA NA NA NA

SCR Catalyst Soot Blowing NA NA NA NA NA NA NA NA

Sludge Lancing NA NA NA NA NA NA NA NA

Soot Blowing NA NA NA NA NA NA NA NA

Steam Turbine Cleaning 0% 29% 8% 0% 18% 13% 27% 61%

Superheater Cleaning 0% 100% 0% 0% 0% 100% 0% 0%

Unknown 7% 11% 12% 0% 12% 40% 7% 42%

All Cleaning Operations 3% 41% 10% <1% 6% 30% 17% 36%

Source: Steam Electric Survey, [ERG, 2013g].

Note: The percentages reported for each cleaning operation may sum to greater than 100% in some cases because all destinations for metal cleaning wastewater 

are identified. In some cases, wastewater can be treated and then discharged.

NA – Not applicable. The cleaning operation was not reported in the Steam Electric Survey for the type of chemical usage (i.e., nonchemical or chemical 

cleaning). 

a – Other treatment systems include filtration, zero liquid discharge treatment, reverse osmosis, clarification, oil/water separation, and brine concentrator.

b – Other disposal methods include offsite treatment, evaporated in another generating unit, hazardous waste disposal, third-party disposal, mixed with fly ash 

and landfilled, and deep injection well.

c – Data were removed from certain cells to protect the release of information claimed confidential business information.
Section 7 – Treatment Technologies and Wastewater Management Practices

7-48 

7.8 REFERENCES

1. AEP. 2010. American Electric Power Mercury Removal Effectiveness Report. (29 

January). DCN SE02008. 

2. Babcock & Wilcox Company. 2005. Steam: Its Generation and Use. 41st edition. Edited 

by J.B. Kitto and S.C. Stultz. Barberton, Ohio. DCN SE02919. 

3. Clyde Bergemann Power Group (CBPG). 2010. “Bottom Ash Conversion Options and 

Economics.” Diagram: ASHCONTM RSSC Design Concept.” (December). DCN 

SE02037. 

4. Eastern Research Group, Inc. (ERG). 2007. Final Engineering Site Visit Report for EME 

Homer City Generation L.P.’s Homer City Power Plant. (9 August). DCN SE02057. 

5. Eastern Research Group, Inc. (ERG). 2008. Final Sampling Episode Report, Tennessee 

Valley Authority’s Widows Creek Fossil Plant. (26 August). DCN SE02105. 

6. Eastern Research Group, Inc. (ERG). 2010. Final Sampling Plan, Duke Energy Carolinas' 

Belews Creek Steam Station. (27 May). DCN SE00502. 

7. Eastern Research Group, Inc. (ERG). 2012a. Final Sampling Episode Report, Duke 

Energy Carolinas’ Allen Steam Station. (13 March). DCN SE01307. 

8. Eastern Research Group, Inc. (ERG). 2012b. Final Sampling Episode Report, Allegheny 

Energy’s Hatfield’s Ferry Power Station. (13 March). DCN SE01310. 

9. Eastern Research Group, Inc. (ERG). 2012c. Final Power Plant Monitoring Data 

Collected Under Clean Water Act Section 308 Authority (“CWA 308 Monitoring Data”). 

(30 May). DCN SE01326. 

10. Eastern Research Group, Inc. (ERG). 2012d. Final Site Visit Notes and Sampling 

Episode Report for Enel’s Power Plants. (8 August). DCN SE02013. 

11. Eastern Research Group, Inc. (ERG). 2013a. Final Site Visit Notes for Duke Energy’s 

Gibson Generating Station (11 March). DCN SE03622. 

12. Eastern Research Group, Inc. (ERG). 2013b. Final Site Visit Notes for Kansas City 

Power & Light’s Iatan Generating Station. (16 March). DCN SE03727. 

13. Eastern Research Group, Inc. (ERG). 2013c. Final Site Visit Notes for We Energies’ 

Pleasant Prairie Power Plant. (6 April). DCN SE00312. 

14. Eastern Research Group (ERG). 2013d. Memorandum to Steam Electric Rulemaking 

Record. “Changes to Industry Profile for Steam Electric Generating Units for Steam 

Electric Effluent Guidelines Proposed Rule.” (28 January). DCN SE02033. 

15. Eastern Research Group, Inc. (ERG). 2013e. Memorandum to the Steam Electric 

Rulemaking Record: Nonchemical Metal Cleaning Waste Permit Review. (19 April). 

DCN SE03902. 

16. Eastern Research Group, Inc. (ERG). 2013e. Site Visit Notes for GenOn Energy’s 

Conemaugh Generating Station. (16 March). DCN SE03756. 

17. Eastern Research Group, Inc. (ERG). 2013f. Steam Electric Technical Questionnaire 

Database (“Steam Electric Survey”). (19 April). DCN SE01958. 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-49 

18. Electric Power Research Institute (EPRI). 2006. 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 SE01817. 

19. Electric Power Research Institute (EPRI). 2007. Treatment Technology Summary for 

Critical Pollutants of Concern in Power Plant Wastewaters. 1012549. Palo Alto, CA. 

(January). Available online at: 

http://www.epriweb.com/public/000000000001012549.pdf. Date accessed: 26 June 2008. 

DCN SE02922. 

20. Electric Power Research Institute (EPRI). 2008a. Environment Quick News: A Monthly 

Report from EPRI’s Environment Sector. Program 56: Effluent Guidelines and Water 

Quality Management. Available online at: 

http://mydocs.epri.com/docs/CorporateDocuments/Newsletters/ENV/QN-2008-02/ENVQN-2008-02.pdf. Date accessed: 16 May 2008. DCN SE02923. 

21. Electric Power Research Institute (EPRI). 2008b. Program on Technology Innovation: 

Selenium Removal from FGD Wastewaters Using Metallic Iron Cementation. Available 

online at: http://my.epri.com/portal/server.pt?Abstract_id=000000000001016191. Date 

accessed: 16 May 2008. DCN SE02924. 

22. Electric Power Research Institute (EPRI). 2009a. Laboratory and Pilot Evaluation of Iron 

and Sulfide Additives with Microfiltration for Mercury Water Treatment. 1016813. Palo 

alto, CA. (March). DCN SE00409A3.

23. Electric Power Research Institute (EPRI). 2009b. Selenium Removal by Iron 

Cementation from a Coal-Fired Power Plant Flue Gas Desulfurization Wastewater in a 

Continuous Flow System – Pilot Study. 1017956. Palo Alto, CA. (July). DCN 

SE00409A2. 

24. Fleming, Craig, et al. 2011. Telephone conversation with Craig Fleming, Gary Mooney, 

and Ron Grabowski, Clyde Bergemann Power Group, Ron Jordan, U.S. EPA and 

Elizabeth Sabol and TJ Finseth, Eastern Research Group, Inc. “Conversion Costs for Wet 

to Dry Bottom Ash Handling Systems.”(22 June). DCN SE02020. 

25. FLSmidth, Inc. 2012. Fly Ash Handling Illustration. (October). DCN SE02038. 

26. Goltz, Robert, et al. 2009. Trace Mercury Removal from Flue Gas Desulfurization 

Wastewater. DCN SE02041. 

27. Jacobs Consultancy. 2012. New Hampshire Clean Air Project Final Report Prepared for 

New Hampshire Public Utilities Commission. (10 September). SE02011. 

28. Jordan, Ron. 2008. Site Visit Notes: Progress Energy Carolinas’ Roxboro Steam Electric 

Plant. (7 July). DCN SE02064. 

29. Loewenberg, Matthias. 2012. Zero-Liquid Discharge System at Progress Energy Mayo 

Generation Station. DCN SE02027. 

30. McDonough, Kevin. 2011. Telephone and email communication with Kevin 

McDonough, United Conveyor Corporation (UCC), and Elizabeth Sabol, Eastern 

Research Group, Inc. “Wet to Dry Ash Handling Conversions – Fly and Bottom.” 

(April). DCN SE02017. 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-50 

31. McDonough, Kevin. 2012a. Letter from Kevin McDonough, UCC, to Jezebele Alicea, 

EPA, RE: Copyright Permission Request – United Conveyor Corporation (UCC®). (27 

November). DCN SE02968. 

32. McDonough, Kevin. 2012b. Teleconference Notes between Kevin McDonough & Mike 

Kippis, United Conveyor Corporation, Ron Jordan and Jezebele Alicea-Virella, EPA, and 

TJ Finseth and Elizabeth Sabol, Eastern Research Group, Inc. “Bottom Ash Handling 

Conversions in the Industry.” (May). DCN SE02016. 

33. McGinnis, Gregory, et al. 2009. "Cliffside 6 Integrated Emissions Control System." 

Power Engineering. (28 April). Available on-line at: 

http://pepei.pennnet.com/display_article/358960/6/ARTCL/none/none/1/Cliffside-6-

Integrated-Emissions-Control-System/. DCN SE02925. 

34. Michel, Tim. 2012. Telephone conversation with Michel Tim of Milestone, Inc. and 

Kavya Kasturi, Eastern Research Group, Inc. “Milestone’s Direct Mercury Analyzers.” 

(27 March). DCN SE02031. 

35. Mooney, Gary. 2010. Telephone and email communication with Gary Mooney, Clyde 

Bergemann Power Group, Inc. and Elizabeth Sabol, Eastern Research Group, Inc. 

“Conversion from Wet to Dry Ash Handling Systems – Fly and Bottom.” (18 

November). DCN SE01825A69. 

36. Pickett, Tim, et al. 2005. ABMet® Biological Selenium Removal from FGD Wastewater. 

(March). DCN SE02039. 

37. Pickett, Tim, et al. 2006. “Using Biology to Treat Selenium.” Power Engineering. 

(November). Available online at: 

http://pepei.pennnet.com/display_article/278443/6/ARTCL/none/none/Using-Biology-toTreat-Selenium/. Date accessed: May 16, 2008. DCN SE02926. 

38. Rao, M.N. 2008. Aquatech International Corporation. ZLD Systems Installed for ENEL 

Power Plants in Italy. International Water Conference. (27 - 29 October). DCN SE02927. 

39. Rogers, John. et al. 2005. Specifically Designed Constructed Wetlands: A Novel 

Treatment Approach for Scrubber Wastewater. (September). DCN SE02928. 

40. Schultz, Shelly. 2013. Teleconference Notes between Timothy Peschman, Adam 

Szczeniak, & Jennifer Ellis, Siemens Industry Inc., and TJ Finseth and Shelly Schultz, 

Eastern Research Group, Inc. “Discussion of Merrimack Station System Operation and 

Costs.” (2 January). DCN SE03901. 

41. Smagula, William. 2010. Letter from William H. Smagula, Public Service Company of 

New Hampshire, to John King, Office of Ecosystem Protection (U.S. EPA). "Public 

Service Company of New Hampshire Merrimack Station, Bow, New Hampshire 

Response to Informal EPA Request for Supplemental Information about Planned Stateof-the-Art FGD Wastewater Treatment System." (8 October). SE02010. 

42. 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. DCN SE02929. 
Section 7 – Treatment Technologies and Wastewater Management Practices

7-51 

43. Sonstegard, Jill, et al. 2010. ABMet®: Setting the Standard for Selenium Removal. 

(October). DCN SE02040. 

44. United Conveyor Corporation (UCC). 2009. Wet-to-Dry Conversion: Bottom Ash & Fly 

Ash Systems. DCN SE02042. 

45. U.S. EPA. 2013. Incremental Costs and Pollutant Removals for Proposed Effluent 

Limitation Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category Report. (19 April). DCN SE01957 

46. Veolia Water Solution & Technologies Company. 2007. “HPD Awarded Flue Gas 

Desulfurization (FGD) Effluent Treatment for Monfalcone Coal-Fired Generating 

Station.” News Release. (16 January). DCN SE02930. 

47. WVDEP. 2010. National Pollutant Discharge Elimination System Permit for American 

Electric Power’s Mountaineer Plant (WV0048500). (6 August). DCN SE02009. 
Section 8 - Technology Options Considered as Basis for Regulation

8-1 

SECTION 8

TECHNOLOGY OPTIONS CONSIDERED AS BASIS FOR 

REGULATION

This section presents the technology options considered by EPA as the basis for the 

proposed effluent limitations guidelines and standards (ELGs) for the Steam Electric Power 

Generating Point Source Category. EPA developed technology options for the following 

limitations and standards:

• Best Practicable Control Technology Currently Available (BPT); 

• Best Available Technology Economically Achievable (BAT);

• New Source Performance Standards (NSPS);

• Pretreatment Standards for Existing Sources (PSES); and

• Pretreatment Standards for New Sources (PSNS).

EPA is not developing Best Conventional Pollutant Control Technology (BCT) 

limitations for this point source category.

EPA’s technology options incorporate pollutant control technologies that are 

demonstrated in the steam electric industry, minimize water use, and result in minimal non-water 

quality environmental impacts. While EPA establishes ELGs based on a particular set of inprocess and end-of-pipe treatment technology options, EPA does not require a discharger to use 

these technologies. Rather, the technologies that may be used to treat wastewater are left entirely 

to the discretion of the individual plant operator, as long as the plant can achieve the numerical 

discharge limitations and standards, as required by Section §301(b) of the Clean Water Act 

(CWA). Direct and indirect dischargers can use any combination of process modifications, inprocess technologies, and end-of-pipe wastewater treatment technologies to achieve the ELGs.

8.1 PROPOSED REGULATORY OPTIONS

This section discusses the regulatory options evaluated for the proposed revisions to the 

ELGs for each wastestream. EPA selected the technology bases for each wastestream for which 

it is proposing revisions to the regulation from the technologies described in Section 7. Section 

8.1.1 describes BPT/BCT. The overall technology bases for the development of BAT, NSPS, 

PSES, and PSNS are discussed in Section 8.1.2. Sections 8.1.3 through 8.1.6 discuss the 

rationale for the selected technologies for each regulation. Sections 8.1.7 discusses 

considerations made by EPA related to future FGD installations.

8.1.1 BPT/BCT

EPA is not proposing to revise the BPT effluent guidelines or establish BCT effluent 

guidelines for the proposed rulemaking because the same wastestreams would be controlled at 

the proposed BAT/BADCT (NSPS) level of control. EPA is proposing to remove FGD 

wastewater, FGMC wastewater, gasification wastewater, and leachate from the definition of lowvolume wastes. As a result, EPA is making a structural adjustment to the text of the regulation at 
Section 8 - Technology Options Considered as Basis for Regulation

8-2 

40 CFR 423 to add paragraphs that list these four wastestreams by name, along with their 

applicable effluent limitations. The reformatted regulatory text for these four wastestreams 

includes BPT effluent limits, which are the same as the current BPT effluent limits for low 

volume wastes.

8.1.2 Description of the Proposed BAT/NSPS/PSES/PSNS Options

EPA is proposing to revise or establish BAT, BADCT (NSPS), PSES, and PSNS that 

may apply to discharges of seven wastestreams: FGD wastewater, fly ash transport water, bottom 

ash transport water, combustion residual leachate, nonchemical metal cleaning wastes, and 

wastewater from FGMC systems and gasification systems. Section 7 describes the treatment 

technologies and operational practices that EPA reviewed during the development of this 

proposed rule. From these, EPA identified a subset of technologies (treatment processes and 

operational practices) that were most promising as candidate BAT/BADCT options. For the 

proposed ELGs, EPA is presenting eight main regulatory options (i.e., Option 1, Option 3a, 

Option 2, Option 3b, Option 3, Option 4a, Option 4, and Option 5) that represent different levels 

of pollutant removal associated with different wastewater streams (i.e., each succeeding option 

from Option 1 to Option 5 would achieve more reduction in discharges of pollutants to waters of 

the U.S). Table 8-1 summarizes the eight main regulatory options, which are described in the 

following paragraphs. 

EPA is also proposing to add provisions to the ELGs that would prevent facilities from 

circumventing applicable ELGs. The proposed provisions would clarify the acceptable 

conditions for discharge of reused process wastewater and establish effluent monitoring 

requirements. 

EPA is considering establishing BMPs that would apply to surface impoundments (i.e., 

ponds) that receive, store, dispose of, or are otherwise used to manage coal combustion residuals 

including FGD wastes, fly ash, bottom ash (which includes boiler slag), leachate, and other 

residuals associated with the combustion of coal to prevent uncontrolled discharges from these 

impoundments as described in Section 8.1.2.9. 

As part of its consideration of technological availability and economic achievability for 

all regulatory options, EPA considered the magnitude and complexity of process changes and 

new equipment installations that would be required at facilities to meet the requirements of the 

rule. EPA proposes that certain limitations and standards being proposed for existing sources 

would not apply until July 1, 2017 (approximately three years from the effective date of this 

rule). 

EPA is also considering establishing, as part of the BAT for existing sources, a voluntary 

incentive program that would provide more time for plants to implement the proposed BAT 

requirements if they adopt additional process changes and controls that would provide significant 

environmental protections beyond those achieved by the preferred options in the proposed rule. 

Power plants would be granted two additional years (beyond the time described above in the 

preceding paragraph) if they also dewater, close and cap all CCR surface impoundments at the 

facility (except combustion residual leachate impoundments), including those surface 

impoundments located on non-adjoining property that receive CCRs from the facility. A power 
Section 8 - Technology Options Considered as Basis for Regulation

8-3 

plant participating in the voluntary incentive program could continue to operate surface 

impoundments for which combustion residual leachate was the only type of CCR solids or 

wastewater contained in the impoundment. Power plants would be granted five additional years 

(beyond the time described above in the preceding paragraph) if they eliminate discharges of all 

process wastewater to surface waters, with the exception of cooling water discharges.
8-4

Section 8 - Technology Options Considered as Basis for Regulation

Table 8-1. Steam Electric Regulatory Options 

Wastestreams

Technology Basis for BAT/NSPS/PSES/PSNS

Regulatory Options

1 3a 2 3b 3 4a 4 5

FGD

Wastewater

Chemical 

Precipitation

BPJ 

Determination

Chemical 

Precipitation + 

Biological 

Treatment

Chemical 

Precipitation + 

Biological Treatment 

for units at a facility 

with a total wetscrubbed capacity of 

2,000 MW and more; 

BPJ determination for 

<2,000 MW

Chemical 

Precipitation 

+ Biological 

Treatment

Chemical 

Precipitation + 

Biological 

Treatment

Chemical 

Precipitation + 

Biological 

Treatment

Chemical 

Precipitation + 

Evaporation

Fly Ash Transport 

Water

Impoundment

(Equal to BPT)

Dry handling Impoundment

(Equal to BPT)

Dry handling Dry handling Dry handling Dry handling Dry handling

Bottom Ash 

Transport Water

Impoundment 

(Equal to BPT) 

Impoundment

(Equal to BPT) 

Impoundment

(Equal to BPT)

Impoundment

(Equal to BPT) 

Impoundment

(Equal to

BPT) 

Dry handling/

Closed loop (for 

units >400 MW); 

Impoundment

(Equal to BPT)(for 

units ≤400 MW)

Dry handling/

Closed loop

Dry handling/

Closed loop

Leachate Impoundment 

(Equal to BPT) 

Impoundment

(Equal to BPT) 

Impoundment

(Equal to BPT)

Impoundment

(Equal to BPT) 

Impoundment

(Equal to

BPT)

Impoundment

(Equal to BPT) 

Chemical 

Precipitation

Chemical 

Precipitation

FGMC

Wastewater

Impoundment 

(Equal to BPT)

Dry handling Impoundment

(Equal to BPT)

Dry handling Dry handling Dry handling Dry handling Dry handling

Gasification

Wastewater

Evaporation Evaporation Evaporation Evaporation Evaporation Evaporation Evaporation Evaporation

Nonchemical Metal 

Cleaning Wastes41

Chemical 

Precipitation

Chemical 

Precipitation

Chemical 

Precipitation

Chemical 

Precipitation

Chemical 

Precipitation

Chemical 

Precipitation

Chemical 

Precipitation

Chemical 

Precipitation

 

41 As described in Section 8.1.3, EPA is proposing to exempt from new copper and iron BAT limitations any existing discharges of nonchemical metal cleaning 

wastes that are currently authorized without iron and copper limits.
Section 8 - Technology Options Considered as Basis for Regulation

8-5 

8.1.2.1 FGD Wastewater 

Addressing the variety of pollutants present in FGD wastewater typically requires several 

stages of treatment to remove the suspended solids, particulate and dissolved metals, and other 

pollutants present. Historically, power plants have relied on surface impoundments to treat FGD 

wastewater because NPDES permits generally focused on controlling suspended solids for this 

wastestream. Surface impoundments are the technology basis for the current BPT effluent limits

(last revised in 1982) for steam electric power plants. In recent years, physical/chemical 

treatment systems and other more advanced systems have become more widely used as effluent 

limits for metals and other pollutants have been included in permits, in nearly all cases driven by 

the need to utilize such technologies to meet water quality-based effluent limits (WQBELs) 

established to meet applicable water quality standards in the receiving waters. At present, a 

number of steam electric plants either use chemical precipitation or chemical precipitation and 

biological treatment to control discharges of FGD wastes. However, surface impoundments 

continue to be the predominant technology used to treat FGD wastewater, with 54 percent of 

plants that discharge FGD wastewater relying on this technology alone (i.e., not including the 

plants that use surface impoundments as pretreatment for more advanced treatment). In addition, 

it is common for plants to commingle the surface impoundment FGD effluent with wastestreams 

of significantly higher flows (e.g., ash transport water and cooling water) because the higherflow wastestreams dilute the FGD wastewater so that the resulting pollutant concentrations in the 

combined wastestream do not exceed the applicable water quality-based effluent limitations. 

Surface impoundments use gravity to remove solid particles (i.e., suspended solids) from 

the wastewater. Metals in FGD wastewater are present in both soluble (i.e., dissolved) and 

particulate form. Some metals, such as arsenic, are often present mostly in particulate form; these 

usually can be removed to a substantial degree by a well-operated settling process that has a 

sufficiently long residence time. However, other pollutants, such as selenium, boron, and 

magnesium, are present mostly in soluble form and are not effectively and reliably removed by 

wastewater surface impoundments. For metals present in both soluble and particulate forms 

(such as mercury), surface impoundments will not effectively remove the dissolved fraction. 

Furthermore, the conditions present in some surface impoundments can create chemical 

conditions (e.g., low pH) that convert particulate forms of metals to soluble forms, which would 

not be removed by the gravity settling process in the surface impoundment. Additionally, EPRI 

(a technical research organization funded by the electric power industry) has reported that adding 

FGD wastewater to surface impoundments used to treat ash transport water (i.e., ash ponds) may 

reduce the settling efficiency in the impoundments due to gypsum particle dissolution, thus 

increasing the effluent TSS concentrations. EPRI has also reported that the FGD wastewater 

includes high loadings of volatile metals, which can increase the solubility of metals in surface 

impoundments, thereby leading to increased levels of dissolved metals and resulting in higher 

concentrations of metals in the discharge from surface impoundments [EPRI, 2006]. 

During the summer, some surface impoundments become thermally stratified. When this 

occurs, the top layer of the impoundment is warmer and contains higher levels of dissolved 

oxygen, whereas the bottom layer of the impoundment is colder and can have significantly lower 

levels of oxygen and may develop anoxic conditions. Typically, during fall, as the air 

temperature decreases, the upper layer of the impoundment becomes cooler and more dense, 

thereby sinking and causing the entire volume of the impoundment to circulate. Solids that have 
Section 8 - Technology Options Considered as Basis for Regulation

8-6 

collected at the bottom of the impoundment may become resuspended due to such mixing, 

increasing the concentrations of pollutants discharged during the turnover period. Seasonal 

turnover effects largely depend upon the size and configuration of the surface impoundment. 

Smaller, and especially shallow, surface impoundments likely do not experience turnover 

because they do not have physical characteristics that promote thermal stratification. However, 

some surface impoundments are large (e.g., greater than 300 acres) and deep (e.g., greater than 

10 meters deep) and likely experience some degree of turnover.

Technologies more advanced than surface impoundments exist and that are more 

effective at removing both soluble (i.e., dissolved) and particulate forms of metals, as well as

other pollutants such as nitrogen compounds and TDS. Because many of the pollutants of 

concern for FGD wastewater are present in dissolved form and would not be removed by surface 

impoundments, and because of the relatively large mass loadings of these pollutants (e.g., 

selenium, dissolved mercury) discharged by the FGD wastestream, EPA explored other 

technologies that would be more effective at removing these pollutants of concern and is coproposing three options that would include such technologies. However, for reasons discussed in 

Section 8.1.3, EPA is also co-proposing options under which some or all facilities would 

continue, for the purposes of the ELGs, to be subject to the BPT requirements based on surface 

impoundments for treatment of FGD wastewater. Under these options, BAT would be left to a 

site-specific determination. For the reasons discussed above and in Section 8.1.3, EPA does not 

believe that surface impoundments represent best available demonstrated control technology for 

controlling pollutants in FGD wastewater. Therefore, none of the regulatory options for NSPS 

presented in this proposal are based on the performance of surface impoundments for FGD 

wastewater.

The technology basis for the effluent limitations and standards for FGD wastewater in 

Option 1 is physical/chemical treatment consisting of the following: chemical 

precipitation/coprecipitation (employing the combination of hydroxide precipitation, iron 

coprecipitation, and sulfide precipitation). Option 1 also incorporates the use of flow 

minimization for plants with high FGD discharge flow rates (i.e., greater than 1,000 gpm) and 

FGD system metallurgy and operating practices that can accommodate an increase in chlorides 

(e.g., scrubber systems constructed of non-metallic materials or corrosion-resistant metal alloys, 

or systems operating with absorber chloride concentrations substantially below the design 

chloride limit). The flow minimization at these plants would be achieved by either reducing the 

FGD purge rate or recycling a portion of their FGD wastewater.

Physical/chemical treatment (i.e., chemical precipitation) is used to remove metals and

other pollutants from wastewater. Chemicals are added to the wastewater in a series of reaction 

tanks to convert soluble metals to insoluble metal hydroxide or metal sulfide compounds, which 

precipitate from solution and are removed along with other suspended solids. An alkali, such as 

hydrated lime, is typically added to adjust the pH of the wastewater to the point where metals 

precipitate out as metal hydroxides (typically referred to as hydroxide precipitation). Chemicals 

such as ferric chloride are often added to the system to increase the removal of certain metals 

through iron coprecipitation. The ferric chloride also acts as a coagulant, forming a dense floc 

that enhances settling of the metal precipitate in the downstream clarification stage. Coagulants 

and flocculants are often added to facilitate the settling and removal of the newly formed solids. 

Plants trying to increase removals of mercury and other metals will also include sulfide addition 
Section 8 - Technology Options Considered as Basis for Regulation

8-7 

(e.g., organosulfide) as part of the process. Adding sulfide chemicals in addition to hydroxide 

precipitation provides even greater reductions of heavy metals due to the very low solubility of 

metal sulfide compounds, relative to metal hydroxides. Sulfide precipitation is widely used in 

Europe and multiple locations in the United States have installed this technology. Forty U.S. 

power plants (34 percent of plants discharging FGD wastewater) include physical/chemical 

treatment as part of the FGD wastewater treatment system; more than half of these plants (28 

percent of plants discharging FGD wastewater) use both hydroxide and sulfide precipitation in 

the process. 

The technology basis for the effluent limitations and standards for FGD wastewater in 

Options 2, 3b (for units located at facilities with a total wet-scrubbed capacity of 2,000 MW or 

more), 3, 4a, and 4 is chemical precipitation/coprecipitation (the same technology basis under 

Option 1) used in combination with anoxic/anaerobic biological treatment designed to optimize 

removal of selenium.42 As is the case for Option 1, these BAT options also incorporate the use of 

flow minimization for plants with high FGD discharge flow rates (i.e., greater than 1,000 gpm) 

and FGD system metallurgy and operating practices that can accommodate an increase in 

chlorides. The flow minimization at these plants would be achieved by either reducing the FGD 

purge rate or recycling a portion of their FGD wastewater. 

Physical/chemical treatment systems are capable of achieving low effluent concentrations 

of various metals and the sulfide addition is particularly important for removing mercury; 

however, this technology is not effective at removing selenium, nitrogen compounds, and certain 

metals that contribute to high concentrations of TDS in FGD wastewater (e.g., bromides, boron). 

Six power plants in the U.S. are operating FGD treatment systems that include a biological 

treatment stage designed to substantially reduce nitrogen compounds and selenium.43 Other 

industries have also used this technology to remove selenium and other pollutants. These systems 

use anoxic/anaerobic bioreactors optimized to remove selenium from the wastewater. The 

bioreactor alters the form of selenium, reducing selenate and selenite to elemental selenium, 

which is then captured by the biomass and retained in treatment system residuals. The conditions 

in the bioreactor are also conducive to forming metal sulfide complexes to facilitate additional 

removals of mercury, arsenic, and other metals. The information in the record for this proposed 

rule demonstrates that the amount of mercury and other pollutants removed by the biological 

treatment stage of the treatment system, above and beyond the amount of pollutants removed in 

the chemical precipitation treatment stage preceding the bioreactor, can be substantial. In 

addition, the anoxic conditions in the bioreactor remove nitrates by denitrification and, if 

necessary, the biological processes can be modified to include a step to nitrify and remove 

ammonia. Four of these six plants precede the biological treatment stage with physical/chemical 

treatment; thus, the entire system is designed to remove suspended solids, particulate and 

dissolved metals, soluble and insoluble forms of selenium, and nitrate and nitrite forms of 

nitrogen. The other two plants operating anoxic/anaerobic bioreactors to remove selenium 

precede the biological treatment stage with surface impoundments instead of chemical 

 

42 This value is calculated by summing the nameplate capacity for all of the units that are serviced by wet FGD 

systems.

43 A seventh plant is scheduled to begin operating a biological treatment system for selenium removal next year. 

Another plant is installing a similar treatment system to remove selenium in discharges of combustion residual 

leachate [ERG, 2013c].
Section 8 - Technology Options Considered as Basis for Regulation

8-8 

precipitation. While the treatment systems at these two plants would be less effective at 

removing metals (including many dissolved metals) than the plants utilizing chemical 

pretreatment, they nevertheless show the efficacy of biological treatment for removing selenium 

and nitrate/nitrite from FGD wastewater. Three percent of the plants discharging FGD 

wastewater use chemical precipitation followed by anaerobic biological treatment to treat this 

wastewater, which is the technology basis for Options 2, 3b (for units located at facilities with a 

total wet-scrubbed capacity of 2,000 MW or more), 3, 4a, and 4. 

The technology basis for the effluent limitations and standards for FGD wastewater in 

Option 5 is chemical precipitation/coprecipitation used in combination with vapor-compression 

evaporation. Physical/chemical treatment systems can achieve low effluent concentrations for a 

number of pollutants, and reduce concentrations even further when combined with biological 

treatment systems. However, these technologies have not been effective at removing substantial 

amounts of boron and pollutants such as sodium and bromides that contribute to high 

concentrations of TDS. Another FGD wastewater treatment technology that can address these 

more recalcitrant pollutants, as well as removing the pollutants treated by physical/chemical and 

biological technologies, is vapor-compression evaporation. This technology uses an evaporator 

to produce a concentrated wastewater stream and a reusable distillate stream. The concentrated 

wastewater stream is either disposed of or further processed to produce a solid by-product and 

additional distillate. The plant can reuse the distillate stream as makeup water. Two U.S. plants 

and four Italian plants are operating this technology to treat FGD wastewater from their coalfired generating units.44 

For Option 3a and Option 3b (for units located at facilities with a total wet-scrubbed 

capacity of less than 2,000 MW), EPA is proposing not to characterize a technology basis for 

effluent limitations and standards applicable to discharges of pollutants in FGD wastewater at 

this time. As illustrated above, there is a wide range of technologies currently in use for reducing 

pollutant discharges associated with FGD wastewater, and research continues in the development 

of additional technologies to treat FGD wastewater (see Section 7.1.7 for more information on 

emerging technologies). The more advanced technologies (those that reduce the most pollutants) 

reflect recent innovations in the area of treatment of FGD wastewater. EPA expects this trend to 

continue and, therefore, under Option 3a and Option 3b (for units located at facilities with a total 

wet-scrubbed capacity of less than 2,000 MW), effluent limitations representing BAT for 

discharges of FGD wastewater would be determined on a site-specific best professional 

judgment (BPJ) basis. Under Options 3a and Option 3b (for units located at facilities with a total 

wet-scrubbed capacity of less than 2,000 MW), pretreatment program control authorities would 

need to develop local limits to address the introduction of pollutants in FGD wastewater by 

steam electric plants to the POTWs that cause pass through or interference, as specified in 40 

C.F.R. 403.5(c)(2). 

EPA is proposing that certain limitations and standards being proposed for existing 

sources would apply to discharges of FGD wastewater generated on or after the date established 

by the permitting authority that is as soon as possible within the next permit cycle after July 1, 

2017. FGD wastewater generated prior to that date (i.e., “legacy” wastewater) from existing 

direct dischargers would remain subject to the existing BPT effluent limits. For indirect 

 

44 A third U.S. plant is currently installing a vapor-compression evaporation system to treat the FGD wastewater.
Section 8 - Technology Options Considered as Basis for Regulation

8-9 

dischargers, EPA is proposing that PSES for FGD wastewater would apply to FGD wastewater 

generated after a date determined by the control authority that is as soon as possible beginning 

July 1, 2017. EPA considered subjecting legacy FGD wastewater to the proposed BAT and PSES 

requirements. However, as explained above, FGD wastewater and its associated pollutants are 

typically sent to surface impoundments for treatment prior to discharge. These surface 

impoundments often contain other plant wastewaters, such as fly ash or bottom ash transport 

water, coal pile runoff, and/or low volume wastes. According to data provided by the industry 

survey, 78 percent of surface impoundments that receive FGD wastewater also receive fly ash 

and/or bottom ash transport water. EPA does not have the data to demonstrate that the 

technologies identified above represent BAT for legacy FGD wastewater. As such, EPA is not 

proposing BAT requirements associated with discharges of legacy FGD wastewater generated 

prior to the date established by the permitting authority (for direct dischargers) or control 

authority (for indirect dischargers). As proposed, discharges of legacy FGD wastewater by 

existing direct dischargers would remain subject to the existing BPT effluent limits; however, 

under some of the proposed options, EPA is also considering setting the BAT effluent limitations 

for legacy FGD wastewater that has not been mixed with non-legacy wastes equal to the existing 

BPT effluent limits. See Section 14.1.3 for additional information. 

8.1.2.2 Fly Ash Transport Water 

Under Options 1 and 2, BAT effluent limitations for fly ash transport water would be set 

equal to the current BPT effluent limitations, based on the technology of gravity settling in 

surface impoundments to remove suspended solids. The current effluent guidelines for existing 

sources include BPT effluent limits for the allowable levels of TSS and oil and grease in 

discharges of fly ash transport water. The BPT effluent limits are based on the performance of 

surface impoundments, which when well-designed and well-operated can effectively remove 

suspended solids, including pollutants such as particulate forms of certain metals when 

associated with the suspended solids. 

Under Options 3a, 3b, 3, 4a, 4, and 5, EPA would establish “zero discharge” effluent 

limitations and standards for discharges of pollutants in fly ash transport water, based on the use 

of dry fly ash handling technologies. The dry handling technologies for fly ash are described in 

Section 7. Although surface impoundments can be effective at removing particulate forms of 

certain metals and other pollutants, they are not designed for, nor are they effective at, removing 

other pollutants of concern such as dissolved metals and nutrients. The concentrations of 

pollutants that remain in the ash impoundment effluent following gravity settling, in combination 

with the large volumes of fly ash transport water discharged to surface waters (2.4 MGD on 

average per discharging plant), results in a large mass loading of pollutants of concern being 

discharged from surface impoundments. Furthermore, as described in Section 8.1.2.1, surface 

impoundments can be susceptible to seasonal turnover that degrades pollutant removal efficacy, 

and co-managing FGD and ash wastes in the same impoundments can lead to increased pollutant 

discharges.

Dry handling technologies are the technology basis for the current fly ash NSPS/PSNS

requirements, which were promulgated in 1982. All generating units built since then have been 

subject to a “zero discharge” standard. Some existing units have also converted to dry handling 

technologies. Due to the NSPS discharge standard or economic or operational factors, 
Section 8 - Technology Options Considered as Basis for Regulation

8-10 

approximately 66 percent of coal- and petroleum coke-fired generating units that produce fly ash 

currently operate dry fly ash transport systems, while another 15 percent operate both wet and 

dry fly ash transport systems. The remaining 19 percent operate only wet fly ash transport 

systems. In cases where a unit has both wet and dry handling operations, the wet handling system 

is typically used as a backup to the dry system. Effluent limitations and standards based on dry 

ash handling would completely eliminate the discharge of pollutants in fly ash transport water. 

EPA considered basing one or more regulatory options for fly ash transport water on 

chemical precipitation treatment technology, with numeric effluent limits for discharges of the 

wastestream to surface waters. EPA has not identified any facilities using this treatment 

technology to treat fly ash transport water, although EPA has reviewed two literature sources that 

describe laboratory- or pilot-scale tests using the technology. Upon reviewing the discharge flow 

rates for fly ash transport water, however, EPA determined that the costs associated with 

treatment using chemical precipitation were higher than the cost of the dry handling technology 

upon which Options 3a, 3b, 3, 4a, 4, and 5 are based, despite being less effective at removing 

pollutants. Because the costs for chemical precipitation treatment are higher than the cost for 

converting to dry handling technologies, and chemical precipitation removes fewer pollutants, 

EPA did not include chemical precipitation treatment as part of the regulatory options for fly ash 

transport water in this proposed rule [ERG, 2013b]. 

EPA is proposing that the limitations for existing sources based on Options 3a, 3b, 3, 4a, 

4, or 5 would apply to discharges of fly ash transport water generated after the date established 

by the permitting authority that is as soon as possible within the next permit cycle after July 1, 

2017. For indirect dischargers, EPA is proposing that PSES for fly ash would apply to the fly ash 

transport water generated after a date determined by the control authority that is as soon as 

possible beginning July 1, 2017. Fly ash transport water generated by existing direct dischargers 

prior to that date (i.e., “legacy” wastewater) would remain subject to the existing BPT effluent 

limits. EPA considered subjecting legacy fly ash transport water (i.e., the fly ash transport water 

generated prior to the date established by the permitting authority, as described above) to the 

proposed BAT zero discharge requirement. As explained above, currently fly ash transport 

wastewater and the associated pollutants are sent to surface impoundments for treatment prior to 

discharge. The technology basis identified for the proposed zero discharge requirement 

eliminates the generation of the fly ash wastewater but does not eliminate fly ash transport 

wastewater that has already been transferred to a surface impoundment. Furthermore, the 

technologies identified as the basis for fly ash transport water discharge requirements have not 

been demonstrated for the legacy fly ash transport wastewater that has already been generated.

As such, EPA is not proposing BAT or PSES requirements for discharges of legacy fly ash 

transport water generated prior to the date established by the permitting authority or control 

authority. As proposed, discharges of legacy fly ash transport water by existing direct 

dischargers would remain subject to the existing BPT effluent limits; however, EPA is also 

considering whether to set the BAT effluent limitations for legacy fly ash transport water equal 

to the existing BPT effluent limits. See Section 14.1.3 for additional information. 

8.1.2.3 Bottom Ash Transport Water 

Under Options 1, 3a, 2, 3b, 3, and 4a (for units less than or equal to 400 MW), effluent 

limitations and standards for bottom ash transport water would be set equal to the current BPT 
Section 8 - Technology Options Considered as Basis for Regulation

8-11 

effluent limitations, based on the technology of gravity settling in surface impoundments to 

remove suspended solids. The 1982 effluent guidelines for existing sources include BPT effluent 

limits for the allowable levels of TSS and oil and grease in discharges of bottom ash transport 

water. The BPT effluent limits are based on the performance of surface impoundments, which 

when well-designed and well-operated can effectively remove suspended solids, including 

pollutants such as particulate forms of certain metals when associated with the suspended solids. 

Although surface impoundments can be effective at removing particulate forms of metals 

and other pollutants, they are not designed for nor are they effective at removing other pollutants 

of concern such as dissolved metals and nutrients. The concentrations of pollutants that remain in 

the wastestream at the ash impoundment effluent, in combination with the large volumes of 

bottom ash transport water discharged to surface waters, results in a large mass loading of 

pollutants of concern being discharged from surface impoundments. Effluent limitations and 

standards based on the technologies used as the basis for Options 4a (for units more than 400 

MW), 4, and 5 would completely eliminate the discharge of pollutants in bottom ash transport 

water. 

Under Options 4a (for units more than 400 MW), 4, and 5, EPA would establish “zero 

discharge” effluent limitations and standards for discharges of pollutants in bottom ash transport 

water, based on either using bottom ash handling technologies that do not require transport water 

or managing a wet-sluicing bottom ash handling system so that it does not discharge bottom ash 

transport water or pollutants associated with the bottom ash transport water. These technologies 

for handling bottom ash are described above in Section 7. About 80 percent of coal- and 

petroleum coke-fired units generating bottom ash operate wet bottom ash transport systems, 

while approximately 20 percent operate systems that eliminate the use of transport water. Most, 

but not all, of the wet bottom ash transport systems discharge to surface waters. In cases where a 

plant has both wet and dry handling operations, the wet handling system is typically used as a 

backup to the dry system. In the case of bottom ash handling systems, the term “dry” is typically 

used to refer to a process that does not use water as the transport medium to sluice the bottom 

ash to a CCR impoundment. In some cases, a “dry” bottom ash system may be entirely dry and 

avoid all use of water. Many dry bottom ash systems, however, include a water bath at the 

bottom of a boiler in which the bottom ash is dropped and cooled, and then the bottom ash is 

mechanically dragged out of the boiler along a conveyor belt and deposited in a pile adjacent to 

the building housing the boiler. The bottom ash conveyed out of the water bath will be damp 

because the ash particles retain some moisture from the water bath and small volumes of water 

will typically drain from the standing bottom ash pile. The water draining from the pile is usually 

collected in a sump and either returned to the water bath below the boiler or managed as low 

volume waste. Such mechanical drag systems are considered as one available technology that 

may be used to achieve proposed limitations and standards under Options 4a (for units >400 

MW), 4, and 5. Other technologies serving as the basis for limitations and standards proposed 

under Options 4a (for units >400 MW), 4, and 5 are completely dry bottom ash systems, remote 

mechanical drag systems, and impoundment-based systems that are managed to eliminate the 

discharge of all bottom ash transport water and the associated pollutants. 

In developing the technologies that serve as the basis for the regulatory options with 

respect to bottom ash transport water, EPA considered basing one or more options on chemical 

precipitation treatment technology, with numeric effluent limitations or standards for discharges 
Section 8 - Technology Options Considered as Basis for Regulation

8-12 

of the wastestream to surface waters. Upon reviewing the discharge flow rates for bottom ash 

transport water, however, EPA determined that the costs associated with treatment were 

comparable to the cost of the technologies upon which Options 4a (for units more than 400 

MW), 4, and 5 are based, despite being less effective at removing pollutants. Because the costs 

for chemical precipitation treatment were found to be higher than the cost for converting to dry 

handling or closed loop technologies, and the treatment technology removes fewer pollutants, 

EPA did not include chemical precipitation treatment as part of the regulatory options for bottom 

ash in this proposed rule [ERG, 2013b]. 

EPA is proposing that certain BAT limitations for existing sources under Options 4a (for 

units more than 400 MW), 4, or 5 would apply to discharges of bottom ash transport water 

generated after the date established by the permitting authority or control authority that is as soon 

as possible within the next permit cycle after July 1, 2017. For indirect dischargers, EPA is 

proposing that PSES for bottom ash transport water would apply to bottom ash transport water 

generated after a date determined by the control authority that is as soon as possible beginning 

July 1, 2017. Bottom ash transport water generated by existing direct dischargers prior to that 

date (i.e., “legacy” wastewater) would remain subject to the existing BPT effluent limits. EPA 

considered subjecting legacy bottom ash transport water (i.e., the bottom ash transport water 

generated prior to the date established by the permitting authority or control authority to the BAT 

and PSES zero discharge requirement considered under Options 4a (for units more than 400 

MW), 4, and 5. As explained above, currently, bottom ash transport wastewater and the 

associated pollutants are sent to surface impoundments for treatment prior to discharge. The 

technology bases identified above for Options 4a (for units more than 400 MW), 4, and 5 

eliminate the generation of the bottom ash wastewater but do not eliminate bottom ash transport 

wastewater that has already been transferred to a surface impoundment. The technologies

identified as the basis for bottom ash transport water discharge requirements under Options 4a 

(for units more than 400 MW), 4, and 5 have not been demonstrated for the legacy bottom ash 

transport wastewater that has already been generated and do not represent BAT/PSES with 

respect to legacy bottom ash wastewater. As such, under Options 4a (for units more than 400 

MW), 4, and 5 EPA would not establish BAT or PSES requirements for discharges of legacy 

bottom ash transport water generated prior to the date established by the permitting authority. As 

proposed, discharges of legacy bottom ash transport water by existing direct dischargers would 

remain subject to the existing BPT effluent limits; however, EPA is also considering whether to 

set the BAT effluent limitations for legacy bottom ash transport water equal to the existing BPT 

effluent limits. See Section 14.1.3 for additional information. 

8.1.2.4 Leachate from Surface Impoundments and Landfills Containing Combustion 

Residuals

Under Options 1, 3a, 2, 3b, 3, and 4a, effluent limitations and standards for leachate from 

surface impoundments and landfills containing combustion residuals would be set equal to the 

current BPT effluent limitations, based on the technology of gravity settling in surface 

impoundments to remove suspended solids. Leachate is currently included under the definition 

of low volume wastes, which are regulated by effluent limits for TSS and oil and grease based on 

surface impoundments designed to remove suspended solids. EPA is proposing that under 

Options 1, 3a, 2, 3b, 3, and 4a, the rule would remove leachate from the definition of low volume 
Section 8 - Technology Options Considered as Basis for Regulation

8-13 

wastes at 40 CFR 423.11(b) and would set BAT effluent limits for leachate equal to BPT limits 

for TSS and oil and grease (i.e., the current effluent limits for low volume wastes). 

The technology basis for effluent limitations and standards for leachate under Options 4 

and 5 is chemical precipitation/coprecipitation. This same technology is the basis for BAT 

Option 1 for FGD wastewater. Properly designed and operated surface impoundments can 

effectively remove suspended solids, including pollutants such as particulate forms of certain 

metals when associated with the suspended solids. However, since surface impoundments are not 

designed for, nor are they effective at, removing other pollutants of concern such as dissolved 

metals, EPA used chemical precipitation/coprecipitation as the technology basis for combustion 

residual leachate for Options 4 and 5. Physical/chemical treatment systems are capable of 

achieving low effluent concentrations of various metals and are effective at removing many of 

the pollutants of concern present in leachate discharges to surface waters. The pollutants of 

concern in leachate are the same pollutants that are present in, and in many cases are also 

pollutants of concern for, FGD wastewater, fly ash transport wastewater, bottom ash transport 

water, and other combustion residuals. This is to be expected since the leachate itself comes from 

landfills and surface impoundments containing the combustion residuals and those wastes are the 

source for the pollutants entrained in the leachate. Given the similarities present among the 

different types of wastewaters associated with combustion residuals, combustion residual 

leachate will be similarly amenable to chemical precipitation treatment. The treatability of 

pollutants such as arsenic and mercury using chemical precipitation technology is also 

demonstrated by technical information compiled for ELGs promulgated for other industry 

sectors. See, e.g., the TDDs supporting the ELGs for the Landfills Point Source Category (EPA821-R-99-019) and the ELGs for the Metal Products and Machinery Point Source Category 

(EPA-821-B-03-001). However, as is the case when treating FGD wastewater, this technology is 

not effective at removing selenium, boron and certain other parameters that contribute to total 

dissolved solids (e.g., magnesium, sodium). 

EPA also considered developing a regulatory option that, for leachate, would be based on 

the technology of chemical precipitation/coprecipitation used in conjunction with 

anoxic/anaerobic biological treatment. This is the same technology used as the basis for effluent 

limitations and standards for FGD wastewater under Options 2, 3b (for units at facilities with a 

total wet-scrubbed capacity of 2,000 MW or more), 3, 4a, and 4. EPA has reviewed this 

technology as a potential basis for effluent limitations and standards for leachate. The 

microorganisms used in the bioreactors for the biological treatment technology for FGD 

wastewater are resilient and have shown that they operate effectively under varying conditions 

that occur in FGD system and the FGD wastewater treatment system. However, leachate flows 

can be more variable than FGD wastewater and, more importantly, may be too intermittent to 

facilitate reliable and consistent biological treatment. Such variations are easily accommodated 

in a chemical precipitation treatment system, but may be difficult to manage in a biological 

treatment system reliant on healthy and sustainable populations of microorganisms. 

If EPA did finalize BAT effluent limits developed under Options 4 or 5 (although these 

options are not the preferred options included in the proposed rule), EPA’s intent is that these 

limits would apply to discharges of leachate generated after the date established by the 

permitting authority that is as soon as possible within the next permit cycle after July 1, 2017. 

For indirect dischargers, PSES for leachate would apply to leachate generated after a date 
Section 8 - Technology Options Considered as Basis for Regulation

8-14 

determined by the control authority that is as soon as possible beginning July 1, 2017. Leachate 

generated by existing direct dischargers prior to that date (i.e., “legacy” leachate wastewater) 

would remain subject to the existing BPT effluent limits. EPA considered subjecting legacy 

leachate wastewater to the proposed BAT and PSES limitations and standards. However, 

although some plants use relatively small surface impoundments to treat leachate and these 

impoundments would contain relatively small volumes of legacy leachate wastewater, other 

plants send leachate to relatively large surface impoundments that also contain other plant 

wastewaters, such as fly ash or bottom ash transport water, cooling water, and/or other low 

volume wastes. EPA does not have the data to demonstrate that the technologies identified above 

represent BAT for legacy combustion residual leachate. As such, EPA would not expect to 

finalize BAT requirements associated with discharges of legacy combustion residual leachate 

(i.e., the leachate generated prior to the date established by the permitting authority or control 

authority). As proposed, discharges of legacy combustion residual leachate by existing direct 

dischargers would remain subject to the existing BPT effluent limits; however, EPA is also 

considering whether to set the BAT effluent limitations for legacy combustion residual leachate 

that has not been mixed with non-legacy wastes equal to the existing BPT effluent limits. See 

Section 14.1.3 for additional information. 

8.1.2.5 FGMC Wastewater 

Under Options 1 and 2, effluent limitations and standards for FGMC wastewater would 

be set equal to the current BPT effluent limitations, based on the technology of gravity settling in 

surface impoundments to remove suspended solids. Like leachate, FGMC wastewater is 

currently included under the definition of low volume wastes, with effluent limits for TSS and oil 

and grease based on surface impoundments designed to remove suspended solids. EPA is 

proposing that under all options, FGMC wastewater would be removed from the definition of 

low volume wastes at 40 CFR 423.11(b). Under Options 1 and 2, BAT effluent limits for FGMC 

wastewater would be set equal to BPT limits for TSS and oil and grease (i.e., the current effluent 

limits for low volume wastes). 

As discussed in Section 4.3.4, some plants inject dry sorbents (e.g., activated carbon) into 

the flue gas stream to reduce mercury emissions from the flue gas. Mercury adsorbs to the 

sorbent particles, and these mercury-enriched sorbents are then removed from the flue gas using 

a fabric filter or ESP. The sorbent can be injected upstream of the primary particulate collector, 

in which case the mercury-enriched sorbent is collected with the majority of the fly ash. 

Alternatively, the sorbent can be injected downstream of the primary particulate collector and 

collected with a much smaller amount of fly ash (i.e., the fly ash that passed through the primary 

collector) in a smaller, dedicated secondary particulate collector such as a fabric filter. In either 

case, the plant collects the mercury-enriched sorbents along with fly ash. Because of this, the 

BAT technology basis for FGMC wastewater in this proposal is identical to the BAT technology 

basis for fly ash. 

Under Options 3a, 3b, 3, 4a, 4, and 5, EPA would establish “zero discharge” effluent 

limitations and standards for discharges of pollutants in FGMC wastewater based on using dry 

handling technologies to store and dispose of fly ash without utilizing transport water. The dry 

handling technologies that would be used for FGMC wastes are identical to the dry fly ash 

handling technologies described in Section 7.2. Although surface impoundments can effectively
Section 8 - Technology Options Considered as Basis for Regulation

8-15 

remove particulate forms of metals and other pollutants, they are not designed for nor are they 

effective at removing other pollutants of concern such as dissolved metals and nutrients. Effluent 

limits based on dry handling would completely eliminate the discharge of pollutants in FGMC 

wastewater. 

EPA is also aware of some plants that add oxidizers to the coal prior to burning the coal 

in the boiler. This chemical addition oxidizes the mercury present in the flue gas, which allows 

the plant to remove mercury more readily from the flue gas in the wet FGD system. EPA did not 

evaluate separate treatment technologies for the use of oxidizers to control flue gas mercury 

emissions because using oxidizers does not generate a separate FGMC wastewater.

To the extent that a power plant generates FGMC wastewater before any BAT zero 

discharge limitation were to apply, the proposed BAT limitations under Options 3a, 3b, 3, 4a, 4, 

and 5 would apply to discharges of FGMC wastewater generated after the date established by the 

permitting authority that is as soon as possible within the next permit cycle after July 1, 2017. 

For indirect dischargers, EPA is proposing that PSES for FGMC wastewater would apply to 

FGMC wastewater generated after a date determined by the control authority that is as soon as 

possible beginning July 1, 2017. As proposed, legacy FGMC wastewater generated by existing 

direct dischargers prior to that date would remain subject to the existing BPT effluent limits; 

however, EPA is also considering whether to set the BAT effluent limitations for legacy FGMC 

wastewater equal to the existing BPT effluent limits. EPA considered subjecting legacy FGMC 

wastewater to the proposed BAT/PSES zero discharge requirements. As described in Section 7.5, 

although most FGMC wastes are managed using dry handling systems, EPA has identified six 

plants that manage their FGMC waste with systems that use water to transport the waste to 

surface impoundments. The technology basis identified for the proposed zero discharge 

requirement eliminates the generation of the FGMC wastewater by implementing certain process 

changes that do not use water to transport the FGMC waste; however, it does not eliminate the 

already-generated FGMC wastewater that has already been transferred to and stored in a surface 

impoundment. The technologies that underlie Regulatory Options 3a, 3b, 3, 4a, 4, and 5 do not 

represent BAT or PSES for the control of pollutants from legacy FGMC wastewater and would 

not allow FGMC wastewater that has already been generated to comply with a zero discharge 

requirement. As such, EPA is not proposing BAT or PSES requirements associated with 

discharges of legacy FGMC wastewater generated prior to the date established by the permitting 

authority or control authority. However, EPA is considering whether to set the BAT effluent 

limitations for legacy FGMC wastewater equal to the existing BPT effluent limits. See Section 

14.1.3 for additional information. 

8.1.2.6 Gasification Wastewater 

The technology basis for the effluent limitations for all eight regulatory options for 

gasification wastewater is vapor-compression evaporation. Two operating IGCC plants in the 

U.S. currently use this technology, and a third IGCC plant that is scheduled to begin commercial 

operation soon will also use it to treat gasification wastewater. Like leachate and FGMC 

wastewater, gasification wastewater is currently included under the definition of low volume 

wastes, with effluent limits for TSS and oil and grease based on surface impoundments designed 

to remove suspended solids. EPA considered using surface impoundments as the technology 

basis for one or more of the regulatory options for gasification wastewater. However, surface 
Section 8 - Technology Options Considered as Basis for Regulation

8-16 

impoundments are not effective at removing the pollutants of concern present in gasification 

wastewater. In addition, one of the currently operating IGCC plants formerly used a surface 

impoundment to treat its gasification wastewater and the impoundment effluent repeatedly 

exceeded NPDES permit limits established to protect water quality. Because of the demonstrated 

inability of surface impoundments to remove the pollutants of concern and the current industry 

practice of operating vapor-compression evaporation to treat the gasification wastewater at all 

U.S. IGCC plants, EPA determined that surface impoundments do not represent BAT level of 

control. 

In addition to the vapor-compression evaporation technology that is the basis for all BAT 

and BADCT/NSPS options for gasification wastewater, EPA considered also including cyanide 

treatment as part of the technology basis for one or more options. EPA notes that the 

Edwardsport IGCC plant that is scheduled to soon begin commercial operation includes cyanide 

destruction as one step in the treatment process for gasification wastewater. However, EPA 

currently does not have sufficient gasification wastewater data with which to calculate effluent 

limits based on the performance of cyanide treatment as part of a BAT/BADCT (NSPS)

regulatory option. A possible approach to resolve this would be to transfer effluent limits for 

cyanide from an ELG for another industry sector. Alternatively, EPA may obtain effluent data 

from the gasification wastewater treatment system for the Edwardsport IGCC unit once it begins 

commercial operation and use these data to calculate effluent limitations for cyanide. 

8.1.2.7 Nonchemical Metal Cleaning Wastes 

The technology basis for the effluent limitations for all eight regulatory options for 

nonchemical metal cleaning wastes is chemical precipitation. Separation processes in the 

physical/chemical treatment, along with chemical addition when needed to facilitate coagulation 

and settling of suspended solids, would effectively remove TSS and oil and grease to effluent 

concentrations below the limitations included in the proposed rule. In addition, treatment 

chemicals added to adjust pH to precipitate dissolved metals or to facilitate 

flocculation/coagulation are effective at removing copper and iron to effluent concentrations 

below the proposed limitations, in addition to reducing the concentrations of other pollutants 

present in nonchemical metal cleaning wastes.

The current ELG relies on three key terms specific to metal cleaning waste: “metal 

cleaning waste,” “chemical metal cleaning waste,” and “nonchemical metal cleaning waste.” The 

regulation includes a definition of the broadest term, “metal cleaning waste,” as “any wastewater 

resulting from cleaning [with or without chemical cleaning compounds] any metal process 

equipment, including, but not limited to, boiler tube cleaning, boiler fireside cleaning, and air 

preheater cleaning.” 40 CFR 423.11(d). Thus, this definition includes any wastewater generated 

from either the chemical or nonchemical cleaning of metal process equipment. In addition, the 

regulation also defines “chemical metal cleaning waste” as “any wastewater resulting from 

cleaning of any metal process equipment with chemical compounds, including, but not limited 

to, boiler tube cleaning.” See 40 CFR 423.11(c). The regulation also includes, but does not 

expressly define the term “nonchemical metal cleaning waste” when it states that it has 

“reserved” the development of BAT ELGs for such wastes. See 40 CFR 423.13(f). Although the 

regulation provides no definition of “nonchemical metal cleaning waste,” it is clear from the 

definitions of metal cleaning waste and chemical metal cleaning waste that nonchemical metal 
Section 8 - Technology Options Considered as Basis for Regulation

8-17 

cleaning waste is any wastewater resulting from the cleaning of metal process equipment without 

chemical cleaning compounds. 

The current ELGs include BPT effluent limits for the allowable levels of TSS, oil and 

grease, copper and iron in discharges of metal cleaning waste, which includes both chemical and 

nonchemical metal cleaning wastes. Although the current BPT effluent limits apply to 

nonchemical metal cleaning wastes, EPA has found that some discharges of nonchemical metal 

cleaning waste are authorized pursuant to permits incorporating limitations based on BPT 

requirements for low volume wastes and, therefore, do not have iron and copper limits. The 

information EPA has collected to date indicates many facilities are not discharging nonchemical 

metal cleaning wastewater or have copper and iron limits (see Section 7.7 for more information). 

The current ELGs do not include BAT/NSPS requirements for the broadly defined 

category of metal cleaning wastes; however, they do include BAT/NSPS for chemical metal 

cleaning waste. EPA has not promulgated BAT/NSPS for nonchemical metal cleaning waste. 

Similarly, although the current ELGs do not include PSES/PSNS for metal cleaning waste, they 

do include PSES/PSNS for chemical metal cleaning waste. EPA has not promulgated 

PSES/PSNS for nonchemical metal cleaning waste. An overview of the ELGs and existing 

limitations for metal cleaning waste, including chemical and nonchemical metal cleaning waste, 

is included in Table 1-1. 

As described above, EPA found that some discharges of nonchemical metal cleaning 

waste are authorized pursuant to permits incorporating limitations based on BPT requirements 

for low volume wastes and, therefore, do not have iron and copper limits. Because the potential 

costs for dischargers to comply with iron and copper limits is not known, EPA is proposing to 

provide an exemption from new copper and iron limitations or standards for existing discharges 

of nonchemical metal cleaning wastes from generating units that are currently authorized without 

iron and copper limits. For these discharges, BAT limitations for nonchemical metal cleaning 

waste would be set equal to BPT limitations for low volume waste, and the regulations would not 

specify PSES. 

EPA is also considering setting BAT for nonchemical metal cleaning waste equal 

to the metal cleaning waste BPT for all nonchemical metal cleaning wastes (i.e., no exemption 

for discharges of nonchemical metal cleaning wastes currently authorized without iron and 

copper limits) and, for PSES, to establish copper standards for all discharges of nonchemical 

cleaning wastes. As part of this approach, EPA is evaluating whether some plants would incur 

costs to comply with the current BPT standards 

8.1.2.8 Anti-Circumvention Provision

EPA is proposing to add provisions to the regulations that would prevent facilities from 

circumventing the effluent limitations guidelines and standards. The proposed provisions would 

do three things, as described below. 

First, the anti-circumvention provision would require that compliance with the new 

effluent limits applicable to a particular wastestream (e.g., FGD, gasification wastewater, 

leachate) be demonstrated prior to use of the wastewater in another plant process that results in 
Section 8 - Technology Options Considered as Basis for Regulation

8-18 

surface water discharge or mixing the treated wastestream with other wastestreams. Under 40 

CFR 122.45(h), in situations where an NPDES permit effluent limitations or standards imposed 

at the point of discharge are impractical or infeasible, effluent limitations or standards may be 

imposed on internal wastestreams before mixing with other wastestreams or cooling water 

streams. Limitations on internal wastestreams may be necessary, such as in situations where the 

wastes at the point of discharge are so diluted as to make monitoring impracticable, or the 

interferences among pollutants would make detection or analysis impracticable. Many power 

plants combine FGD wastewater and other power plant wastewaters with ash transport water 

and/or cooling water prior to discharge, which can dilute the wastewaters by several orders of 

magnitude prior to the final outfall. In addition, surface impoundments typically contain a variety 

of wastes (e.g., ash transport water, coal pile runoff, landfill/impoundment leachate) that when 

mixed with the FGD wastewater or gasification wastewater may make the analysis to measure 

compliance with technology-based effluent limits impracticable. Because of the high degree of 

dilution and the number of wastestream sources containing similar pollutants, effluent limits and 

monitoring requirements for certain internal wastestreams (e.g., FGD wastewater, combustion 

residual leachate, gasification wastewater) are necessary to ensure appropriate control of the 

pollutants present in the wastewater. 

Second, the anti-circumvention provision would establish requirements intended to 

prevent steam electric power plants from circumventing the effluent limits and standards by 

moving effluent produced by a process operation for which there is a zero discharge effluent 

limit/standard to another process operation for discharge under less stringent requirements than 

intended by the steam electric ELGs. For example, several options (including Option 3a) 

considered in this rulemaking would establish a zero discharge requirement for pollutants in fly 

ash transport water and FGMC wastewater. If this option were selected for the final rule, the 

anti-circumvention provisions would allow power plants to recycle/reuse these wastestreams in 

ash transport processes or other plant processes, but only to the extent that the plants do not 

discharge any pollutants associated with flue gas mercury controls or transporting fly ash. The 

presence of a zero discharge wastestream in a process that ultimately discharges to surface water 

(e.g., use of fly ash transport water as FGD absorber make-up water in a scrubber that discharges 

FGD wastewater) would not be in compliance with the effluent limit. 

Last, the anti-circumvention provisions would expressly require permittees to use 

analytical EPA-approved methods that are sufficiently sensitive to provide reliable quantified 

results at levels necessary to demonstrate compliance with the effluent limits proposed by this 

rulemaking when such methods are available. EPA’s detailed study and the field sampling for 

this rulemaking demonstrate that the use of sufficiently sensitive analytical methods is critically 

important to detecting, identifying, and measuring the concentrations of pollutants present in 

power plant wastewaters. Where EPA has approved more than one analytical method for a 

pollutant, the Agency expects that permittees would select methods that are able to quantify the 

presence of pollutants in a given discharge at concentrations that are low enough to determine 

compliance with effluent limits, when such methods are available. Facilities should not use a less 

sensitive or less appropriate method, thus masking the presence of a pollutant in the discharge, 

when an EPA-approved method is available that can quantify the pollutant concentration at the 

lower levels needed for demonstrating compliance. For purposes of the proposed anticircumvention provision, a method is “sufficiently sensitive” when the sample-specific 

quantitation level for the wastewater being analyzed is at or below the level of the effluent 
Section 8 - Technology Options Considered as Basis for Regulation

8-19 

limitation.

45 Allowing plants to use insufficiently sensitive analytical methods for compliance 

monitoring purposes when EPA-approved sufficiently sensitive methods are available could 

result in an undetected exceedance of the effluent limits.

8.1.2.9 BMPs for CCR Surface Impoundments

EPA is considering establishing BMPs for plant operators to conduct periodic inspections 

of active and inactive surface impoundments and to take corrective actions where warranted. 

This requirement would apply to direct dischargers. For new sources, EPA would be relying on 

CWA section 306, which authorizes the promulgation of standards of performance for new 

sources. For existing sources, EPA would be relying on CWA section 304(e), which authorizes 

BMPs supplemental to ELGs for toxic or hazardous pollutants to control plant site runoff, 

spillage or leaks, sludge or waste disposal, and drainage from raw material storage which the 

Administrator determines are associated with or ancillary to the industrial process and may 

contribute significant amounts of pollutants to the nation’s waters. And CWA section 402(a) (2) 

authorizes the imposition of conditions, which would include BMPs and monitoring 

requirements, necessary to ensure compliance with all other applicable requirements. EPA’s 

regulation at 40 CFR 122.44(k) implements these authorities. Specifically, 40 CFR 122.44(k) 

allow for NPDES permits to require the use of BMPs to control and abate the discharge of toxic 

pollutants. Existing regulations at 40 CFR 122.41(e) further require that NPDES permittees 

properly operate and maintain all facilities and systems of treatment and control used to achieve 

compliance with their permits. Using CWA authority, EPA could establish the BMPs as part of 

the ELGs (BAT and NSPS) codified at 40 CFR part 423, and thus these BMPs would be 

implemented through NPDES permits. Structural integrity requirements that seek to reduce the 

potential for catastrophic releases from surface impoundments could, alternatively, be 

established using RCRA authority. The BMPs under consideration in this rulemaking are similar 

to the structural integrity inspection and corrective active requirements proposed in the CCR 

rulemaking, but do not include closure requirements that were proposed as part of the CCR 

rulemaking. 

The Agency believes that the BMP requirements being considered by the Agency in this 

rulemaking and in the CCR rulemaking are critical to ensure that the owners and operators of 

surface impoundments become aware of any problems that may arise with the structural stability 

of the surface impoundment before they occur and, thus, prevent catastrophic releases, such as

those that occurred at Martins Creek, Pennsylvania and TVA’s Kingston, Tennessee facility. 

The BMPs being considered by EPA in this rulemaking would require, first, that 

inspections be conducted every seven days by a person qualified to recognize specific signs of 

structural instability and other hazardous conditions by visual observation and, if applicable, to 

monitor instrumentation such as piezometers. If a potentially hazardous condition develops, the 

owner or operator shall immediately take action to eliminate the potentially hazardous condition; 

notify the Regional Administrator or the authorized State Director; and notify and prepare to 

evacuate, if necessary, all personnel from the property that may be affected by the potentially 

hazardous condition(s). Additionally, the owner or operator must notify state and local 

 

45 For the purposes of this rulemaking, EPA is considering the following terms related to analytical method 

sensitivity to be synonymous: “quantitation limit,” “reporting limit,” “level of quantitation,” and “minimum level.”
Section 8 - Technology Options Considered as Basis for Regulation

8-20 

emergency response personnel if conditions warrant so that people living in the area down 

gradient from the surface impoundment can evacuate. Reports of inspections are to be 

maintained in the facility operating record.

Second, to address the integrity of surface impoundments, EPA would establish BMPs 

for CCR surface impoundments similar to those promulgated for coal slurry impoundments 

regulated by the Mine Safety and Health Administration (MSHA) at 30 CFR 77.216. Although 

the MSHA regulations are applicable to coal slurry impoundments at coal mines and not to the 

impoundments containing CCR at power plants, there are sufficient similarities between coal 

slurry and CCR impoundments for the MSHA regulations to be used as a model for the BMP 

requirements being considered for the ELG rule. Facilities using CCR impoundments would 

need to (1) submit to EPA or the authorized state plans for the design, construction, and 

maintenance of existing impoundments, (2) submit to EPA or the authorized state plans for 

closure, (3) conduct periodic inspections by trained personnel who are knowledgeable in 

impoundment design and safety, and (4) provide an annual certification by an independent 

registered professional engineer that all construction, operation, and maintenance of 

impoundments is in accordance with the approved plan. When problematic stability and safety 

issues are identified, owners and operators would be required to address these issues in a timely 

manner.

In developing these possible structural integrity BMP requirements, EPA sought advice 

from the federal agencies charged with managing the safety of dams in the United States. Many 

agencies in the federal government are charged with dam safety, including the U.S. Department 

of Agriculture (USDA), the Department of Defense (DOD), the Department of Energy (DOE), 

the Nuclear Regulatory Commission (NRC), the Department of Interior (DOI), and the 

Department of Labor (DOL), MSHA. EPA looked particularly to MSHA, whose charge and 

jurisdiction appeared to EPA to be the most similar to the Agency’s in this context. MSHA’s 

jurisdiction extends to all dams used as part of an active mining operation and their regulations 

cover “water, sediment or slurry impoundments” so they include dams for waste disposal, 

freshwater supply, water treatment, and sediment control. In fact, MSHA’s current impoundment 

regulations were created as a result of the dam failure at Buffalo Creek, West Virginia on 

February 26, 1972. (This failure released 138 million gallons of stormwater run-off and fine coal 

refuse, and resulted in 125 persons killed, another 1,000 injured, over 500 homes completely 

destroyed, and nearly 1,000 others damaged.)

MSHA has nearly 40 years of experience writing regulations and inspecting dams 

associated with coal mining. MSHA’s regulations are comprehensive and directly applicable to 

the dams used in surface impoundments at coal-fired utilities to manage CCRs. EPA believes

that, based on the record compiled by MSHA for its rulemaking, and on MSHA’s 40 years of 

experience implementing these regulations, the requirements being considered in this rulemaking 

would substantially reduce the potential for catastrophic release of CCRs from surface 

impoundments, as occurred at TVA’s facility in Kingston, Tennessee, and would generally meet 
Section 8 - Technology Options Considered as Basis for Regulation

8-21 

RCRA’s objective to ensure the protection of humans and the environment.46 Thus, EPA is 

considering establishing BMPs that would be modeled on MSHA regulations in 30 CFR Part 77. 

MSHA’s regulations for coal slurry impoundments apply to those impoundments at coal 

mines, which impound water, sediment or slurry to an elevation of more than five feet and have a 

storage volume of 20 acre-feet or more and those coal slurry impoundments that impound water, 

sediment, or slurry to an elevation of 20 feet or more. The BMPs being considered for the ELG 

rule would apply to all CCR impoundments at steam electric power generating facilities, 

regardless of height and storage volume. EPA is also considering variations on BMPs for the 

ELGs, including, but not limited to, different inspection frequencies or limitations on the 

applicability of BMPs that more closely mirror the applicability of the MSHA regulations. 

8.1.2.10 Voluntary Incentive Program for Power Plants that Close CCR 

Impoundments or Eliminate All Process Wastewater Dischargers (Except 

Cooling Water 

EPA is considering establishing, as part of the BAT for existing sources, a voluntary 

incentive program that provides more time for plants to implement the proposed BAT 

requirements if they adopt additional process changes and controls that provide significant 

environmental protections beyond those achieved by the preferred options for this proposed rule. 

The development of advanced process changes and controls is a critical step toward the Clean 

Water Act’s ultimate goal of eliminating the discharge of pollutants into the Nation’s waters. See 

CWA Section 101(a)(1). Section 301(b)(1)(C) demands that BAT result in “reasonable further 

progress toward the national goal of eliminating the discharge of pollutants.” EPA intends that, 

for any BAT option that is ultimately selected as part of any final ELG rule, such option would 

represent “reasonable further progress,” while the voluntary incentives program is designed to 

continue progress toward achieving the national goal of the Act. In addition, Section 104(a)(1) of 

the Act gives the Administrator authority to establish national programs for the prevention, 

reduction, and elimination of pollution, and it provides that such programs shall promote the 

acceleration of research, experiments, and demonstrations relating to the prevention, reduction, 

and elimination of pollution. The voluntary incentives program being considered for the 

proposed rule would effectively accelerate the research into and use of controls and processes 

intended to prevent, reduce, and eliminate pollution because it would increase the number of 

plants choosing to close and cap CCR surface impoundments and eliminate discharges of all 

process wastewater (except cooling water) to surface waters.

This voluntary program would establish two levels, or “tiers,” of advanced technology 

performance requirements which would be incorporated into the NPDES permits for the facilities 

that participate in the program. Under Tier 1, power plants would be granted two additional years 

(beyond the time described below in Section 8.2) if they also dewater, close and cap all CCR 

surface impoundments (except for those impoundments containing only combustion residual 

 

46 On December 22, 2008, the retention wall of a coal ash impoundment at Tennessee Valley Authority’s Kingston 

Plant collapsed, which resulted in a massive release of CCRs directly into the Emory River and its tributaries. The 

Emory River joins to the Clinch River and then converges with the Tennessee River, a major drinking water source 

for populations downstream. This failure released over a billion gallons of fly ash and bottom ash, which 

impacted over 100 properties, destroyed three homes, and ruptured a gas line resulting in the evacuation of 22 

residents.
Section 8 - Technology Options Considered as Basis for Regulation

8-22 

leachate) at the facility, including those surface impoundments located on non-adjoining property 

that receive CCRs from the facility. A power plant participating in the Tier 1 program could 

continue to operate surface impoundments for which combustion residual leachate is the only 

type of CCR solids or wastewater contained in the impoundment. In general, power plants 

accepted in the Tier 1 incentives program would first convert ash handling operations to dry 

handling or closed-loop tank-based systems and FGD wastewater treatment operations to tankbased systems, as described above in Section 7. This first step would eliminate new contributions 

of CCRs (solids and wastewater) to the surface impoundments. The plants would then dewater 

the impoundments by draining or pumping the wastewater from the impoundments, in 

compliance with the ELGs and other requirements established in their NPDES permits. Upon 

completing the dewatering operations, plants would then stabilize the contents and close and cap 

the impoundments consistent with state requirements and any other additional requirements that 

may be established by EPA as part of the Tier 1 incentives program or other applicable 

requirements. 

Under Tier 2, power plants would be granted five additional years (beyond the time 

described below in Section 8.2) if they eliminate the discharge of all process wastewater to 

surface waters, with the exception of cooling water discharges. The Tier 2 incentives would not 

be available to power plants that eliminate direct discharge to surface water by sending the 

wastewater to a POTW. A plant accepted into the Tier 2 incentives program would ultimately 

need to manage its processes and wastewater in a manner that implements a coordinated 

approach toward wastewater minimization, treatment and reuse. To achieve Tier 2 status, these 

plants would eliminate all process wastewater discharges (except cooling water) by reducing the 

amount of wastewater generated and preferentially using recycled wastewater to meet water 

supply demands. To accomplish this, Tier 2 plants would conduct engineering assessments of the 

processes that generate wastewater and identify opportunities to eliminate or reduce the amount 

of wastewater they generate. These plants would also assess the processes that use water and 

determine how they could use recycled wastewater in those processes, as well as the degree of 

treatment that may be needed to enable such reuse. Based on responses to the industry survey, 

EPA has identified a number of steam electric power plants that currently discharge no process 

wastewater. In addition, two of the plants that EPA visited in Italy previously discharged process 

wastewater, but have implemented wastewater treatment and process changes, including 

wastewater recycle, that now allow them to operate without discharging any process wastewater 

except for their cooling water.

The primary objective of this program is to encourage individual power plants to install 

advanced pollution prevention technologies or make process changes that would further reduce 

releases of toxic pollutants to the environment beyond the limits that would be set by the 

proposed rule. The voluntary incentive program being considered is designed to promote 

improvements that, in concert with other environmental practices, make significant progress 

toward achieving EPA’s vision of the “power plant of the future” – one which will have a 

minimum impact on the environment. This program would give power plants a platform to 

advance the research and development of technologies and processes that promote water 

conservation and water recycling and provide greater environmental protection. EPA has 

conducted site visits at power plants that have implemented processes that eliminate the use of 

water or recycle process wastewater to a substantial degree. Furthermore, as noted above, EPA 

observed operations at power plants that implemented process modifications and treatment 
Section 8 - Technology Options Considered as Basis for Regulation

8-23 

technologies that eliminated all discharges of process wastewater with the exception of their 

cooling water. Implementing such practices at other power plants would dramatically reduce 

discharges of toxic and other pollutants. These practices would also substantially reduce the 

amount of water consumed or used by the plant, which could be an important consideration for 

addressing water availability and other concerns. In exchange for providing additional time for 

power plants to comply with the proposed BAT limitations, the program would lead to superior 

effluent quality and greater environmental protection. 

Participation in the program would be voluntary and it would be available only to 

existing power plants that discharge directly to surface waters. Power plants would have until 

July 1, 2017 (approximately 3 years after promulgation of the final ELGs) to commit to the 

program and submit a plan for achieving the Tier 1 or Tier 2 requirements. Once a power plant 

enrolls in the program, the NPDES permitting authority would develop specific discharge limits 

and key milestones consistent with that tier.

Power plants enrolled in the program would ultimately be agreeing to adopt NPDES 

permit limits that are more stringent than those that would be required by the proposed and final 

BAT in exchange for additional time to comply with their new effluent limitations. These power 

plants and their corporate owners would also receive public recognition for their commitment to 

increased environmental protection. 

EPA considered including features of the Tier 1 and Tier 2 incentives as part of the 

options for the proposed rule. However, although EPA has observed these practices in operation 

and they are available for at least a portion of the industry, the degree of complexity will vary 

from plant to plant and EPA does not have the site-specific information that could be used to 

sufficiently assess how that complexity may affect the engineering challenges and costs that 

plants would encounter. 

8.1.3 Rationale for the Proposed BAT Technology 

BAT represents the best available economically achievable performance of facilities in an

industrial subcategory or category taking into account factors specified in the CWA. The CWA 

factors considered in assessing BAT are the cost of achieving BAT effluent reductions, the age 

of equipment and facilities involved, the process employed, potential process changes, and nonwater quality environmental impacts, including energy requirements and such other factors as the 

Administrator deems appropriate. See Section 304(b)(2)(B). In addition to technological 

availability, economic achievability is also a factor considered in setting BAT. See Section 

301(b)(2)(A).

After considering all of the technologies described in Section 7, in light of the factors 

specified in Section 304(b)(2)(B) and Section 301(b)(2)(A) of the CWA, as appropriate, EPA is 

putting forth four preferred alternatives for BAT. These four preferred alternatives primarily 

differ in that some would establish more environmentally protective BAT requirements for 

discharges from two of the wastestreams from existing sources. Under the first preferred 

alternative, EPA is proposing to establish BAT effluent limits based on the technologies 

specified in Option 3a. With the exception of oil-fired generating units and small generating 

units (i.e., 50 MW or smaller), the proposed rule under Option 3a would: 
Section 8 - Technology Options Considered as Basis for Regulation

8-24 

• Establish a “zero discharge” effluent limit for all pollutants in fly ash transport water 

and FGMC wastewater;

• Establish numeric effluent limits for mercury, arsenic, selenium, and TDS in 

discharges of gasification wastewater; 

• Establish numeric effluent limits for copper and iron in discharges of nonchemical 

metal cleaning wastes;47 

• Establish BAT effluent limits for bottom ash transport water and combustion residual 

leachate that are equal to the current BPT effluent limits for these discharges (i.e., 

numeric effluent limits for TSS and oil and grease; and

• BAT for discharges of FGD wastewater would continue to be determined on a sitespecific basis.

Under the second preferred alternative for BAT, EPA is proposing to establish BAT 

effluent limits based on the technologies specified in Option 3b. With the exception of oil-fired 

generating units and small generating units (i.e., 50 MW or smaller), the proposed rule under 

Option 3b would: 

• Establish numeric effluent limits for mercury, arsenic, selenium, and nitrate-nitrite in 

discharges of FGD wastewater for units located at plants with a total wet-scrubbed 

capacity of 2,000 MW or more;48,49

• Establish a “zero discharge” effluent limit for all pollutants in fly ash transport water 

and FGMC wastewater;

• Establish numeric effluent limits for mercury, arsenic, selenium, and TDS in 

discharges of gasification wastewater; 

• Establish numeric effluent limits for copper and iron in discharges of nonchemical 

metal cleaning wastes;50 and

• Establish BAT effluent limits for bottom ash transport water and leachate that are 

equal to the current BPT effluent limits for these discharges (i.e., numeric effluent 

limits for TSS and oil and grease).

Under the third preferred alternative for BAT, EPA is proposing to establish BAT 

effluent limits based on the technologies specified in Option 3. In addition to the requirements 

 

47 As described later in this section, EPA is proposing to exempt from new BAT copper and iron limitations existing 

discharges of nonchemical metal cleaning wastes that are currently authorized under their existing NPDES permit 

without iron and copper limits. For these discharges, BAT limits would be set equal to BPT limits for low volume 

waste.

48 Total plant-level wet-scrubbed capacity is calculated by summing the nameplate capacity for all of the units that 

are serviced by wet FGD systems.

49 For units below the 2,000 MW threshold, BAT would continue to be determined on a site-specific basis.

50 As described later in this section, EPA is proposing to exempt from new BAT copper and iron limitations existing 

discharges of nonchemical metal cleaning wastes that are currently authorized under their existing NPDES permit 

without iron and copper limits. For these discharges, BAT limits would be set equal to BPT limits for low volume 

wastes.
Section 8 - Technology Options Considered as Basis for Regulation

8-25 

described for Option 3b, the proposed rule would establish the same numeric effluent limits as in 

Option 3b for mercury, arsenic, selenium, and nitrate-nitrite in discharges of FGD wastewater

from units located at all steam electric facilities, with the exception of oil-fired generating units 

and small generating units (i.e., 50 MW or less). 

Under the fourth preferred alternative for BAT (Option 4a), in addition to the 

requirements described for Option 3, the proposed rule would establish “zero discharge” effluent 

limits for all pollutants in bottom ash transport water from units greater than 400 MW. 

For oil-fired generating units and small generating units (i.e., 50 MW and smaller) that 

are existing sources, under all four preferred options, EPA is proposing to set the BAT effluent 

limits equal to the current BPT effluent limits for copper and iron for nonchemical metal 

cleaning wastes, and for TSS and oil and grease for five of the six wastestreams listed above 

(i.e., FGD wastewater, fly ash transport water, FGMC wastewater, leachate from landfills and 

surface impoundments containing combustion residuals, and gasification wastewater).51 EPA is 

proposing Options 3a, 3b, 3 and 4a as the preferred BAT regulatory options because its analysis 

to this date suggests that they are all technologically available, economically achievable, and 

have acceptable non-water quality environmental impacts. However, EPA is putting forth a range 

of options as candidates for BAT in order to enhance the Agency’s understanding of the pros 

and cons of each of these options in light of the statutory factors through the public comment 

process and intends to evaluate this information and how it relates to the factors specified in the 

CWA. As discussed above in Section 7 and 8.1.2, the data in EPA’s record and its analysis to 

date suggests that all four options are technologically available. EPA’s record indicates that the 

technologies comprising Options 3a, 3b, 3, and 4a are well-demonstrated and have been 

employed at a subset of existing power plants. 

Under all of the preferred options, the technology basis for fly ash transport water is dry 

handling. All generating units built in the 30 years since the ELGs were last revised in 1982 have 

been subject to a zero discharge standard for the pollutants in fly ash transport water, in nearly all 

cases installing dry fly ash handling technologies to comply with the standard. In addition, many 

other generating units that could discharge their fly ash transport water upon meeting a TSS 

effluent limit have instead retrofitted the dry fly ash handling technology to meet operational 

needs or for economic reasons. Approximately 40 percent of the plants that were operating wetsluicing systems in 2000 have converted generating units to dry fly ash (approximately 115 

generating units at 45 power plants). Another 61 generating units are slated to convert to dry fly 

ash handling by 2020. Based on data collected by the industry survey, approximately 66 percent 

of coal- and petroleum coke-fired generating units handle all fly ash with dry technologies. 

Another 15 percent of coal- and petroleum coke-fired generating units have both wet and dry fly 

ash handling systems (typically, the wet system is a legacy system that the plant has not 

decommissioned following retrofit with a dry system). Only 19 percent of coal- and petroleum 

coke-fired generating units exclusively use a wet fly ash handling system. Furthermore, some of 

these plants with wet fly ash handling systems manage the ash handling process so that they do 

 

51 As described later in this section, EPA is proposing to exempt from new BAT copper and iron limitations existing 

discharges of nonchemical metal cleaning wastes that are currently authorized under their existing NPDES permit 

without iron and copper limits. For these discharges, BAT limits would be set equal to BPT limits for low volume 

waste.
Section 8 - Technology Options Considered as Basis for Regulation

8-26 

not discharge fly ash transport water. As a result, EPA determined that only 13 percent of coalfired power plants would incur costs to comply with a BAT zero discharge requirement for fly 

ash transport water. 

Power plants recently began installing FGMC systems either to comply with state 

requirements or to prepare for emissions limits established by the MATS rule. Plants using 

sorbent injection systems (e.g., activated carbon injection) typically handle the spent sorbent in 

the same manner as their fly ash. Nearly all plants with FGMC systems use dry handling 

technologies. Only a few plants use wet systems to transport the spent sorbent to disposal in 

surface impoundments. Based on the industry survey, the plants using wet handling systems 

currently operate them as closed-loop systems and do not discharge FGMC wastewater to 

surface waters, or have the capability to do so. These plants could continue to operate these wet 

systems as closed-loop systems, or could convert to dry handling technologies by managing the 

fly ash and spent sorbent together in a retrofitted dry system (the wastes are currently managed 

together in the impoundments) or by installing dedicated dry handling equipment for the FGMC 

wastes similar to the equipment used for fly ash. 

The technology basis for control of discharges of FGD wastewater under Options 3b (for 

units located at plants with a total wet-scrubbed capacity of 2,000 MW or more), 3, and 4a is 

chemical precipitation followed by anaerobic biological treatment. Four power plants, or 

approximately three percent of wet-scrubbed power plants that discharge FGD wastewater 

already have the Options 3b (for units located at plants with a total wet-scrubbed capacity of 

2,000 MW or more), 3, and 4a BAT technology in place. Under Options 3b (for units located at 

plants with a total wet-scrubbed capacity of 2,000 MW or more), 3, and 4a, in addition to other 

new requirements that would be established, numeric limits would be established for toxic 

discharges including arsenic, mercury, and selenium from FGD wastewater. 

The technology used as the basis for FGD wastewater treatment under Options 3b (for 

units at plants with a total wet-scrubbed capacity of 2,000 MW or more), 3, and 4a has been 

tested at power plants for more than 10 years and full-scale systems have been operating at a 

subset of plants for 5 years. The biological treatment processes used in the bioreactor portion of 

the treatment technology have been widely used in many industrial applications for decades both 

in the U.S. and internationally. Five steam electric power plants operate fixed-film 

anoxic/anaerobic biological treatment systems to treat FGD wastewater and another operates a 

suspended growth biological treatment system that targets removal of selenium.

52 Other power 

plants are considering installing the biological treatment technology to remove selenium and at 

least one plant is moving forward with construction [ERG, 2013c]. In addition, four additional 

power plants currently operate anaerobic biological treatment systems for their FGD wastewater, 

indicative that this is available technology. EPA is aware of industry concerns with the feasibility 

of biological treatment at some power plants. Specifically, industry has asserted that the efficacy 

of these systems is unpredictable, and is subject to temperature changes, high chloride 

concentrations, and high oxidation reduction potential in the absorber (which may kill the 

treatment bacteria). EPA’s record to date does not support these assertions, but is interested in 

additional information that addresses these concerns. 

 

52 Four of the six operate the biological treatment systems in combination with chemical precipitation.
Section 8 - Technology Options Considered as Basis for Regulation

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More than one-third of plants that discharge FGD wastewater utilize chemical 

precipitation (in some cases, also using additional treatment steps). As noted above, four power 

plants currently operate chemical precipitation systems in combination with anaerobic biological 

treatment systems. The chemical precipitation treatment processes included in the FGD 

wastewater technology basis for these options are used at 24 percent of steam electric power 

plants that discharge FGD wastewater (and another 11 percent of plants also use chemical 

precipitation systems that could be upgraded to this technology basis) and also at thousands of 

industrial facilities nationwide, including Metal Products and Machinery facilities, Iron & Steel 

manufacturers, and metal finishers [U.S. EPA, 2003; U.S. EPA, 2002; U.S. EPA, 1983].53

Option 3b proposes limitations based on this technology for units at the largest plants (as 

determined by a 2,000 MW total wet-scrubbed capacity threshold), and BAT for the control of 

discharges of FGD wastewater from units at plants below this threshold would continue to be 

determined on a site-specific basis. For FGD wastewater only, EPA believes any threshold 

should be based on a plant level rather than a unit level because many plants currently use a 

single FGD treatment systems to service multiple units. Additionally, EPA determined that wetscrubbed capacity is an appropriate metric because it only reflects units that are generating FGD 

wastewater. For example, a plant could have a total plant nameplate generating capacity of 3,500 

MW, but only have a wet-scrubbed capacity of 200 MW if only one of its units is wet-scrubbed. 

EPA is putting forth this option as a preferred option based on an assumption that these facilities 

are more able to achieve these limits based on economies of scale. These largest facilities will 

likely also be able to absorb the costs of installing and operating the chemical precipitation and 

anaerobic biological treatment systems on which the FGD wastewater limitations are based. For 

these reasons, as well as those specified above related to current innovation and treatment trends, 

Option 3b proposes that BAT effluent limitations for discharges of FGD wastewater would 

continue to be determined on a site-specific basis for units at facilities below the 2,000 MW 

threshold. 

The fourth preferred alternative for this proposed rule, Option 4a, in addition to the 

requirements that would be established under Option 3, would eliminate discharges of pollutants 

in bottom ash transport water from units greater than 400 MW. The technology basis for bottom 

ash for the zero discharge requirement is dry handling or a closed-loop system. Bottom ash 

transport water is one of the three largest sources for discharges of the pollutants of concern from 

steam electric power plants and these discharges occur at many power plants across the nation. 

Based on data collected by the industry survey, approximately 30 percent of coal-fired and 

petroleum coke-fired power plants handle bottom ash using technologies that do not generate any 

transport water. In addition, another 12 percent of coal- and petroleum coke-fired power plants 

manage the wet-sluicing bottom ash handling system as a closed-loop system that recirculates all 

bottom ash transport water so that it is not discharged. In addition, 83 percent of coal-fired 

generating units built in the last 20 years installed dry bottom ash handling systems. 

EPA recognizes that the potential costs associated with compliance with a zero discharge 

standard for discharges of bottom ash transport water would be substantial if applied to all 

 

53 Physical/chemical treatment systems can be effective at removing mercury and certain other metals; however, to 

achieve effective removal of selenium this technology must be coupled with additional treatment technology such as 

anoxic/anaerobic biological treatment.
Section 8 - Technology Options Considered as Basis for Regulation

8-28 

facilities (for example, approximately half of Option 4 costs and approximately a third of Option 

5 costs), and, therefore, EPA looked carefully at this wastestream with a particular focus on 

generating unit size. EPA’s review demonstrated that, in the case of bottom ash transport water, 

units less than or equal to 400 MW are more likely to incur compliance costs that are 

disproportionately higher per MW than those incurred by larger units. For example, the average 

annualized cost of achieving zero discharge limits for bottom ash discharges (i.e. dry handling or 

closed loop) per MW for a 200 MW unit is more than three times higher than the average cost 

for a 400 MW unit. Based on the data from the industry survey, EPA estimates that 25 percent of 

coal-fired power plants would incur costs to comply with a BAT zero discharge requirement for 

bottom ash transport water from units greater than 400 MW. 

Furthermore, while all plants, regardless of size, are capable of installing and operating 

dry handling or closed-loop systems for bottom ash transport water, and the costs would be 

affordable for most plants, EPA believes that companies may choose to shut down 400 MW and 

smaller units instead of making new investments to comply with proposed zero discharge bottom 

ash requirements. EPA is basing this belief on its review of units that facilities have announced 

will be retired or converted to non-coal based fuel sources. Of those units that plants have 

announced for retirement, and that also generate bottom ash transport water, over 90 percent are 

400 MW or less [ERG, 2013d]. Therefore, for the reasons specified above, for units less than or 

equal to 400 MW, Option 4a proposes to set the BAT effluent limits equal to the current BPT 

effluent limits based on surface impoundments. 

The two IGCC plants currently operating in the United States use the technology that is 

the basis for all four preferred options for gasification wastewater. A third IGCC plant that will 

soon begin commercial operation will also use the technology and, in addition to that, will also 

operate a cyanide destruction step as part of the treatment system.

For all four preferred options, the proposed BAT limits for copper and iron in discharges 

of nonchemical metal cleaning waste are equal to the current BPT effluent limits for these 

pollutants in metal cleaning waste. These effluent limits are based on the same technology that 

was used as the basis for the current ELG BPT requirements for metal cleaning waste (i.e., 

chemical precipitation). 

Discharges of metal cleaning wastes that are generated from cleaning metal process 

equipment without chemical cleaning compounds (i.e., nonchemical metal cleaning waste) are

already subject to BPT effluent limits for copper and iron equal to the BAT effluent limits in the 

proposed rule. Based on responses to the industry survey, facilities typically treat both chemical 

and nonchemical metal cleaning waste in similar fashion.

Since, as described above, nonchemical metal cleaning waste is included within the 

definition of metal cleaning waste, and copper and iron are already regulated under metal 

cleaning wastes, EPA would be establishing BAT limits equal to the BPT limits (for copper and 

iron) that already apply to these wastes. As a result, facilities should incur no cost to comply with 

the proposed BAT for these wastes. However, EPA recognizes that previous guidance provided 

after the final 1974 regulation stated that wastes from metal cleaning with water are considered 

“low volume” wastes. The extent to which this statement was relied upon is unclear, and EPA 

rejected the guidance in the 1982 rulemaking for the steam electric ELGs (47 FR 52297). 
Section 8 - Technology Options Considered as Basis for Regulation

8-29 

However, because permitting authorities and others may have relied on this guidance and the 

potential costs to those facilities are not known, EPA is proposing to exempt from any new 

copper and iron BAT requirements those discharges of nonchemical metal cleaning waste to 

which this guidance was applied in the past. In other words, EPA is proposing to exempt from 

proposed new copper and iron BAT limitations those discharges of nonchemical metal cleaning 

wastes from generating units that are currently authorized to discharge nonchemical metal 

cleaning wastes without copper and iron limits pursuant to existing BPT requirements for metal 

cleaning waste. For such discharges, EPA is proposing to set BAT limitations equal to BPT 

limitations for low volume waste.

To get a better understanding of how discharges of nonchemical metal cleaning wastes 

are currently permitted, EPA’s regional offices recently reviewed 45 permits for plants that EPA 

had reason to believe generated nonchemical metal cleaning waste based on responses to the 

industry survey. For these permits, EPA determined the following based on the review: 

• 64 percent of the plants are either zero discharge of metal cleaning wastes or have to 

comply with copper and iron limits; 

• 27 percent of plants do not have to comply with copper and iron limits; and 

• 9 percent of plant permits do not include enough information to determine whether 

the plant would be in compliance with the proposed BAT limitations. 

While not exhaustive, this review provides some information to suggest that many, but 

not all, plants are either zero discharge or have iron and copper limits and thus are already 

meeting the proposed BAT limitations. For additional information on the permit review 

conducted, see Section 7.7. 

In order to implement the exemption proposed for certain discharges of nonchemical 

metal cleaning waste that have historically been treated as low volume wastes and not subject to 

copper and iron limits under metal cleaning waste BPT requirements, EPA’s current thinking is 

to develop a specific list of generating units eligible for the exemption. Therefore, EPA is 

seeking to identify those generating units that should be eligible for the exemption through the 

public comment process on this rulemaking. To qualify for the proposed exemption, the 

generating unit must meet all three of the following criteria:

• The generating unit must currently generate nonchemical metal cleaning wastes;

• The generating unit must discharge the nonchemical metal cleaning waste; and

• The generating unit must be located at a plant that is authorized to discharge the 

nonchemical metal cleaning waste without limitations for copper and iron. 

If the nonchemical metal cleaning wastes generated and discharged by a generating unit 

do not meet all of these three criteria, then EPA proposes that the generating unit will not be 

eligible for the exemption. For example, if the plant currently hauls the nonchemical metal 

cleaning wastes off site for disposal, the generating units associated with the nonchemical metal 

cleaning waste generation would not be exempt. Another approach EPA is considering would be 

to define the conditions of the exemption, and then make it available to any facility that 

qualified, regardless of whether the facility was identified to EPA during the comment period. 
Section 8 - Technology Options Considered as Basis for Regulation

8-30 

This would give EPA less information on the potential effects of including this exemption in the 

final rule, but would also allow qualified facilities to make use of the exemption even if they 

were unaware of the need to file comments during the comment period in order to make use of it. 

EPA is also considering setting BAT limitations equal to BPT limitations applicable to 

metal cleaning waste for all discharges of nonchemical metal cleaning wastes (i.e., not creating 

an exemption from copper and iron limits for discharges of nonchemical metal cleaning wastes 

from generating units currently authorized to discharge those wastes without copper and iron 

limits). As part of this approach, EPA is evaluating whether plants would incur costs to comply 

with the current BPT requirements applicable to discharges of metal cleaning wastes. 

EPA’s analysis to date suggests that all four preferred options, Option 3a, Option 3b, 

Option 3, and Option 4a, are economically achievable. EPA performed cost and economic 

impact assessments using the Integrated Planning Model (IPM) for Option 3 and Option 4.54

Option 4 is more costly than any of the four preferred options including Option 4a; therefore by 

performing the assessments with these two options, EPA can evaluate the potential effects of 

each of the preferred options. Because the costs and the facilities affected by Option 3a and 3b 

are a subset of Option 3, EPA can use the results of Option 3 to inform the potential impacts of 

Option 3a and Option 3b. In a similar way, because the costs and the facilities affected by Option 

4a are a subset of Option 4, EPA can use the results of Option 4 to inform the potential impacts 

of Option 4a. 

For the options analyzed overall, the model showed very small effects on the electricity 

market, on both a national and regional sub-market basis. Based on the results of these analyses, 

EPA estimates that the proposed requirements associated with Option 3a, Option 3b, and Option 

3 would not lead to the premature retirement of any steam electric generating units (i.e., no 

partial or full plant closures). 

The results for Option 4 show fourteen unit (partial) closures and zero plant (full) 

closures projected as of the model year 2030, reflecting full compliance of all facilities.55,56 The 

14 generating units are located at six plants. The IPM results also show that five steam electric 

units that are projected to close under the base case (i.e., in the absence of the proposed revisions 

to the ELG) would remain operating under proposed Option 4 (i.e., avoiding closure). As a 

result, for Option 4, the IPM analysis projects total net closure of nine generating units, with total 

combined generating capacity of 317 MW. These results support EPA’s conclusion that Option 4 

is economically achievable. As explained above, because the costs and facilities affected by 

Option 4a are only a subset of Option 4 (i.e., are less than those for Option 4), the model would 

project similar or smaller effects for Option 4a. These IPM estimates for closures and avoided 

 

54 IPM is a comprehensive electricity market optimization model that can evaluate such impacts within the context 

of regional and national electricity markets. See the Regulatory Impact Analysis for Proposed Effluent Limitations 

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

55 As used here for the purpose of this rulemaking, the term partial closure refers to a plant where the closure of a 

generating unit is projected, but one or more generating units at the plant will continue operating. A full closure 

refers to a situation where all generating units at a plant are projected to shut down. 

56 Given the design of IPM, unit-level and thereby plant-level projections are presented as an indicator of overall 

regulatory impact rather than a prediction of future unit–level or plant-specific compliance actions.
Section 8 - Technology Options Considered as Basis for Regulation

8-31 

closures also support EPA’s conclusion that Option 4a is economically achievable for the steam 

electric industry.

As part of its consideration of technological availability and economic achievability, EPA 

also considered the magnitude and complexity of process changes and new equipment 

installations that would be required at facilities to meet the requirements of the rule. As described 

in greater detail in Section 14, EPA is proposing that, where the limitations and standards being 

proposed for existing direct and indirect dischargers are more stringent than existing BPT 

requirements, those limitations and standards do not begin to apply until July 1, 2017 

(approximately three years following promulgation of the final rule). EPA is proposing this 

approach to provide the time that many facilities will need to raise capital, plan and design 

systems, procure equipment, and construct and then test systems. Moreover, this approach will 

enable facilities to take advantage of planned shutdown or maintenance periods to install new 

pollution control technologies. EPA’s proposal is designed to minimize any potential impacts on 

electricity availability caused by forced outages.

Options 3a, 3b, 3 and 4a have acceptable non-water quality environmental impacts, as 

discussed in Section 12. EPA estimates that Options 3a, 3b, 3, and 4a would increase energy 

consumption by less than 0.003 percent, less than 0.004 percent, less than 0.008 percent, and less 

than 0.012 percent, respectively, of the total electricity generated by power plants. EPA also 

estimates that Options 3a, 3b, 3, and 4a would increase the amount of fuel consumed by 

increased operation of motor vehicles (e.g., for transporting fly ash) by less than 0.009 percent, 

less than 0.009 percent, less than 0.009 percent, and less than 0.014 percent, respectively, of total 

fuel consumption by all motor vehicles. 

As discussed in Section 12.2, EPA also evaluated the effect of the proposed rule on air 

emissions generated by power plants (NOx, sulfur oxides (SOx), and CO2). For Options 3a, 3b, 

and 3, the NOx emissions are estimated to increase by no more than 0.12 percent, and for Option 

4a, by no more than 0.13 percent. EPA projects no significant increase in emissions of SOx or 

CO2 under the four preferred options. 

EPA also evaluated the effect of the proposed rule on solid waste generation and water 

usage. There would be no increase in solid waste generation under Option 3a, and EPA estimates 

that solid waste generation at power plants will increase by less than 0.001 percent under the 

other three preferred options. EPA estimates the power plants would reduce water use by 50 

billion gallons per year (136 million gallons per day) under Option 3a, 52 billion gallons per year 

(143 million gallons per day) under Option 3b, 53 billion gallons per year (144 million gallons 

per day) under Option 3, and 103 billion gallons per year (282 million gallons per day) under 

Option 4a. 

EPA also examined the effects of the preferred options on consumers as an “other factor” 

that might be appropriate when considering what level of control represents BAT. If all 

compliance costs were passed on to residential consumers of electricity instead of being borne by 

the operators and owners of power plants, the monthly increase in electricity bill would be no 

more than $0.04, $0.06, $0.13, and $0.22, respectively under Options 3a, 3b, 3, and 4a. 
Section 8 - Technology Options Considered as Basis for Regulation

8-32 

EPA is not proposing either Option 1 or Option 2 as its preferred option for BAT because 

neither option would represent the best available technology level of control for steam electric 

power plant discharges. For example, Options 1 and 2 would allow plants to continue to 

discharge fly ash transport wastewater without treating the wastes to remove dissolved metals 

and many of the other pollutants present in the wastewater. However, 66 percent of all coal- and 

petroleum coke-fired generating units that produce fly ash as a residue of the combustion process 

already use dry fly ash technologies to manage all of their fly ash without any associated creation 

or discharge of fly ash transport water. And another 15 percent of the coal- and petroleum cokefired generating units that produce fly ash also already operate dry fly ash handling systems in 

addition to a wet ash handling system (either as a completely redundant system, or to manage a 

fraction of the fly ash that is produced during combustion). Similarly, every generating unit 

operating a FGMC system does so in a manner that avoids creating any FGMC wastewater (92 

percent of units with FGMC), or manages the FGMC wastewater in a closed cycle process that 

does not result in a discharge to surface water (8 percent of units with FGMC). The technology 

serving as the basis for FGD effluent limits under Option 1 is not effective at removing many of 

the pollutants of concern in FGD wastewater, including selenium, nitrogen compounds, and 

certain metals that contribute to high concentrations of total dissolved solids in FGD wastewater 

(e.g., bromides, boron). Furthermore, the information in the record for this proposed rule 

demonstrates that the amount of mercury, selenium, and other pollutants removed by the 

biological treatment stage of the treatment system, above and beyond the amount of pollutants 

removed in the chemical precipitation treatment stage preceding the bioreactor, can be 

substantial. Options 1 and 2 would remove fewer or similar levels of pollutants to the preferred 

options, all of which EPA believes, based on its analysis to date, to be technologically available, 

economically achievable, and have acceptable non-water quality environmental impacts. Options 

1 and 2 would establish new effluent limits for three of the seven key wastestreams addressed in 

this rulemaking. For the remaining four wastestreams, BAT effluent limits would be set equal to 

the current BPT effluent limits. 

EPA did not select Option 4 as its preferred regulatory option because of concerns 

expressed above associated with the projected compliance costs associated with zero discharge 

requirements for bottom ash for units equal to or below 400 MW. The bottom ash requirements 

for Option 4 and the preferred Option 4a are the same with the exception that Option 4a proposes 

to set the BAT effluent limits for bottom ash transport water equal to the current BPT effluent 

limits for units less than or equal to 400 MW, while Option 4 would set the BAT effluent limits 

for bottom ash transport water equal to the BPT effluent limits for units less than or equal to 50 

MW. All other units would be subject to “zero discharge” effluent limits for all pollutants in 

bottom ash transport water. 

Moreover, Option 4 proposes to establish BAT discharge limitations for toxic discharges 

for leachate. The record demonstrates that the amount of pollutants collectively discharged in 

leachate by steam electric plants is a very small portion of the pollutants discharged collectively 

for all steam electric power plants (i.e., less than 1⁄2 a percent). The technology basis for 

limitations on discharges of combustion residual leachate proposed under Option 4 is chemical 

precipitation. Because of the relatively low level of pollutants in this wastestream, and because 

EPA believes this is an area ripe for innovation and improved cost effectiveness, EPA is not 

putting forward this option as a preferred option. On balance, EPA would like to collect 

additional information on costs and effectiveness of chemical precipitation and other possible 
Section 8 - Technology Options Considered as Basis for Regulation

8-33 

technologies for reducing pollutants discharged in leachate before making a finding with respect 

to what technologies represent the best available technology economically achievable for 

controlling discharges of pollutants found in combustion residual leachate. 

EPA did not select Option 5 as its preferred option for BAT because of the high total 

industry cost for the option ($2.3 billion/year annualized social cost) and because of preliminary 

indications that Option 5 may not be economically achievable. While EPA has traditionally 

looked at affordability of the rule to the regulated industry, EPA has in some limited instances 

over the past three decades rejected an option primarily on the basis of total industry costs. See 

48 FR 32462, 32468 (July 15, 1983) (Final Rule establishing ELGs for the Electroplating and 

Metal Finishing Point Source Categories); 74 FR 62996, 63026 (Dec. 1, 2009) (Final Rule 

establishing ELGs for the Construction and Development Point Source Category); BP 

Exploration & Oil, Inc. v. EPA, 66 F.3d 784, 796-97 (6th Cir. 1996) (upholding EPA’s decision 

not to require zero discharge of produced waters based on reinjection for the Offshore 

subcategory of the Oil and Gas Extraction Point Source Category based in part on total industry

cost). EPA similarly finds this appropriate here. In addition, certain screening-level economic 

impact analyses indicated that compliance costs may result in financial stress to some entities 

owning steam electric plants. Although EPA did not select Option 5 as the preferred BAT option, 

without question, Option 5 would remove the most pollutants from steam electric power plant 

discharges. Also, the technologies are all potentially available and may be appropriate 

(individually or in totality) as the basis for water quality-based effluent limits in NPDES permits, 

depending on site-specific conditions. For example, any of the requirements that would be 

established under Option 5, including at a minimum the vapor-compression evaporation 

technology serving as the Option 5 technology basis for FGD wastewater, may be appropriate for 

those power plants that discharge upstream of drinking water treatment plants and that have 

bromide releases in wastewaters that impact treatment of source waters at the drinking water 

treatment plants. See the Environmental Assessment for the Proposed Effluent Limitations 

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

additional discussion about discharges of bromides. 

For the reasons described in Section 8.2, EPA is proposing that, where the limitations and 

standards in the proposed rule are more stringent than existing BPT requirements, those 

limitations and standards do not begin to apply until July 1, 2017 (approximately three years 

from the effective date of this rule).

For all eight of the main BAT options under consideration, EPA is proposing to establish 

effluent limits for oil-fired generating units and small generating units (i.e., 50 MW or less) that 

differ from the effluent limits for all other generating units.

57 For oil-fired generating units and 

small generating units, EPA is proposing to set the BAT effluent limits equal to the current BPT 

effluent limits for all seven of the key wastestreams addressed by this proposed rule. For six of 

these wastestreams, BAT would be set equal to current BPT numeric limits for TSS and oil and 

grease, with these pollutants regulated as indicator pollutants for the control of toxic and 

nonconventional pollutants. For nonchemical metal cleaning wastes, EPA is proposing to set 

BAT equal to the current BPT effluent limits for copper and iron in metal cleaning wastes, but 

 

57 For Option 4a, for discharges of pollutants found in bottom ash transport water only, as explained previously, 

EPA is proposing to raise the value from less than or equal to 50 MW to less than or equal to 400 MW.
Section 8 - Technology Options Considered as Basis for Regulation

8-34 

would not establish BAT effluent limits for TSS and oil and grease (which are also currently 

regulated by BPT for metal cleaning wastes).58 EPA’s proposal and reasoning is detailed in 

subsections 8.1.3.1 and 8.1.3.2. 

In addition, EPA has identified some differences among the options in terms of cost 

effectiveness. The Regulatory Impact Analysis for Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category describes EPA’s 

cost-effectiveness analysis for the preferred regulatory options. EPA’s analysis to date shows 

that the average cost effectiveness ($1981/TWPE) under Option 3a, 3b, 3, and 4a for existing 

direct dischargers is $27, $31, $44, and $57, respectively. This demonstrates that Option 3a is the 

most cost effective of the preferred options, Option 4a is the least cost effective of the preferred 

options, and Option 3 and Option 3b are between the two. 

EPA also calculated the cost-effectiveness of particular controls for the wastestreams that 

would be controlled under the preferred options for existing direct dischargers.59 The costeffectiveness for zero discharge of fly ash transport and FGMC wastewater, as in Option 3a, is 

$27 per TWPE removed. The cost effectiveness of chemical precipitation alone is $70 per TWPE 

removed, while the cost effectiveness of chemical precipitation plus anaerobic biological 

treatment, which is included in all options except Option 3a, is $60 per TWPE removed. The cost 

effectiveness of zero discharge of bottom ash transport water for all units more than 50 MW is 

$107 per TWPE. In comparison, when this requirement is applied only to units more than 400 

MW, as in Option 4a, the cost effectiveness value is $99 per TWPE removed. 

Thus, the cost effectiveness for control of the various wastestreams included within the 

preferred options ranges from $27-$107 per TWPE in $1981; with zero discharge controls on fly 

ash transport wastewater being the most cost-effective, zero discharge controls on bottom ash 

transport wastewater being the least cost effective, and controls for FGD wastewater based on 

chemical precipitation in combination with anaerobic biological treatment between the two.

8.1.3.1 Effluent Limits for Oil-Fired Generating Units

EPA is proposing to establish BAT limits equal to BPT for existing oil-fired units. For 

the purpose of the proposed BAT effluent limits, oil-fired generating units would be those that 

use oil as either the primary or secondary fuel and do not burn coal or petroleum coke. Units that 

use oil only during startup or for flame stabilization would not be considered oil-fired generating 

units. EPA is proposing to set BAT limits equal to BPT for existing oil-fired units because, in 

comparison to coal- and petroleum coke-fired units, oil-fired units generate substantially fewer 

pollutants, are generally older and operate less frequently, and in many cases are more 

susceptible to early retirement when faced with compliance costs attributable to the proposed 

ELGs. 

 

58 As described earlier in this section, EPA is proposing to exempt from new BAT copper and iron limitations 

existing discharges of nonchemical metal cleaning wastes that are currently authorized under their existing NPDES 

permit without iron and copper limits. For these discharges, BAT limits would be set equal to BPT limits for low 

volume waste.

59 While it is not included in the preferred options as a wastestream with additional controls, EPA also looked at the 

cost effectiveness of controlling leachate using chemical precipitation and this value would exceed $1,000 per 

TWPE removed.
Section 8 - Technology Options Considered as Basis for Regulation

8-35 

The amount of ash generated at oil-fired units is a small fraction of the amount produced 

by coal-fired units. Coal-fired units generate hundreds or thousands of tons of ash each day, with 

some plants generating more than 1,500 tons per day of ash. In contrast, oil-fired units generate 

less than one ton of ash per day. This disparity is also apparent when comparing the ash tonnage 

to the amount of power generated, with coal-fired units producing nearly 300 times more ash 

than oil-fired units (0.04 tons per MW-hour on average for coal units; 0.000145 tons per MWhour on average for oil units). The amount of pollutants discharged to surface waters is roughly 

correlated to the amount of ash wastewater discharged, thus oil-fired units discharge 

substantially less pollutants to surface waters than a coal-fired unit even when generating the 

same amount of electricity. EPA estimates that if BAT effluent limits for oil-fired units were set 

equal to either the proposed Option 3 or Option 4a limits for coal-fired units (>50 MW), the total 

industry pollutant reductions attributable to the proposed rule would increase by less than one 

percent.

Oil-fired units are generally among the oldest steam electric units in the industry. Eightyseven percent of the units are more than 25 years old. In fact, more than a quarter of the units 

began operation more than 50 years ago. Based on responses to the industry survey, only 20 

percent of oil-fired units operate as baseload units; the rest are either cycling/intermediate units 

(45 percent) or peaking units (35 percent). These units also have notably low capacity utilization. 

While a quarter of the baseload units report capacity utilization greater than 75 percent, most 

baseload units (60 percent) report a capacity utilization of less than 25 percent. Eighty percent of 

the cycling/intermediate units and all peaking units also report capacity utilization less than 25 

percent. Thirty-five percent of oil-fired units operated for more than six months in 2009; nearly 

half of the units operated for less than 30 days. 

As shown above, oil-fired units are generally older and operate intermittently (i.e., they 

are peaking, cycling, or intermediate units). While these oil-fired units are capable of installing 

and operating the treatment technologies evaluated as part of this rulemaking, and the costs 

would be affordable for most of the plants, EPA believes that, due to the factors described here, 

companies may choose to shut down these oil-fired units instead of making new investments to 

comply with the rule. If these units shut down, it could reduce the flexibility that grid operators 

have during peak demand because there would be less reserve generating capacity to draw upon. 

But more importantly, maintaining a diverse fleet of generating units that includes a variety of 

fuel sources is vital to the nation’s energy security. Because the supply/delivery network for oil 

is different from other fuel sources, maintaining the existence of oil-fired generating units helps

ensure reliable electric power generation. Thus, the oil-fired generating units add substantially to 

electric grid reliability and the nation’s energy security. 

Based on responses to the industry survey, EPA estimates that less than 20 oil-fired units 

discharged fly ash or bottom ash transport water in 2009. At the same time, EPA notes that many 

oil-fired units operate infrequently, which could contribute to the relatively low numbers of units 

discharging ash-related wastewater. Should more widespread operation of oil units be required to 

meet demands of the electric grid, additional plants may find it necessary to discharge ash 

transport water. Because of the operating conditions unique to the existing fleet of oil-fired units 

and potential effects on the nation’s electric power grid, a non-water quality environmental 

impact that EPA considers under Section 304(b) of the CWA, EPA believes it is appropriate to 

set BAT effluent limits for oil-fired equal to the current BPT limits.
Section 8 - Technology Options Considered as Basis for Regulation

8-36 

8.1.3.2 Effluent Limits for Small Generating Units

EPA is proposing to establish BAT effluent limits equal to BPT for existing small 

generating units, which would be defined as those units with a total nameplate generating 

capacity of 50 MW or less.60 Small units are more likely to incur compliance costs that are 

disproportionately higher per amount of energy produced than those incurred by large units 

because they are not as able to take advantage of economies of scale. For example, the unit-level 

annualized cost for the proposed FGD wastewater treatment technology under Option 3 

(chemical precipitation plus biological treatment) is approximately seven times more expensive 

on a dollar-per-megawatt basis for small generating units, relative to units larger than 50 MW. 

Similarly, the unit-level annualized cost to convert the fly ash handling system to dry technology 

(conveyance equipment and intermediate storage silos) is more than four times more expensive 

on a dollar-per-megawatt basis for small generating units, relative to units larger than 50 MW. 

For Option 4, bottom ash conversions are more than six times more expensive for small units, on 

a dollar-per-megawatt basis. 

Moreover, the record demonstrates that the amount of pollutants collectively discharged 

by small generating units is a very small portion of the pollutants discharged collectively for all 

steam electric power plants (e.g., less than 1 percent under Option 3). As a result, setting BAT 

limits equal to BPT for existing steam electric generating units with a capacity of 50 MW or less 

will have little impact on the pollutant removals for the overall rule. 

EPA considered establishing the size thresholds for small generating units at 25 MW 

because that threshold is already used for this industry sector in some regulatory contexts. For 

example, the Clean Air act defines an “electric utility generating unit” as “any fossil fuel fired 

combustion unit of more than 25 megawatts that serves a generator that produces electricity for 

sale.” CAA Section 112(a)(8), 42 U.S.C. 7412(a)(8). The existing ELGs for the steam electric 

power generating point source category also include different effluent limitations for plants with 

total rated generating capacity of less than 25 MW. See 40 CFR 423.13(c)(1) and 423.15(i)(1). 

EPA currently proposes a threshold of 50 MW rather than 25 MW because the proposed 

50 MW threshold would do more to alleviate potential impacts. 61,62 EPA recognizes that any 

attempt to establish a size threshold for generating units will be imperfect due to individual 

differences across units and firms. However, EPA believes that a threshold of 50 MW or less 

reasonably and effectively targets those generating units that should receive different treatment 

based on the considerations described above. 

 

60 Preferred Option 4a would increase this threshold for purposes of discharges of pollutants in bottom ash transport 

water only, to 400 MW or less.

61 For Option 4a, for bottom ash transport water only, as explained previously, EPA is proposing to raise the value 

from less than or equal to 50 MW to less than or equal to 400 MW.

62 As discussed in Section XVII.C, the proposed 50 MW threshold also alleviates potential impacts which may be 

borne by small entities or municipalities.
Section 8 - Technology Options Considered as Basis for Regulation

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8.1.4 Rationale for the Proposed Best Available Demonstrated Control/NSPS Technology 

Section 306 of the CWA directs EPA to promulgate New Source Performance Standards, 

or NSPS, “for the control of the discharge of pollutants which reflects the greatest degree of 

effluent reduction which the Administrator determines to be achievable through application of 

the best available demonstrated control technology, processes, operating methods, or other 

alternatives, including, where practicable, a standard permitting no discharge of pollutants.” 

Congress envisioned that new sources could meet tighter controls than existing sources because 

of the opportunity to incorporate the most efficient processes and treatment systems into the 

facility design. As a result, NSPS should represent the most stringent controls attainable through 

the application of the best available demonstrated control technology, or BADCT, for all 

pollutants (that is, conventional, nonconventional, and priority pollutants). 

After considering all of the technology options described in Section 7, EPA is proposing 

to establish NSPS based on the suite of technologies identified for Option 4 in Table 8-1. Thus, 

the proposed NSPS would do the following: 

• Establish numeric effluent limits for mercury, arsenic, selenium, and nitrate-nitrite in 

discharges of FGD wastewater;

• Maintain the current “zero discharge” effluent limit for all pollutants in fly ash 

transport water, and establish new “zero discharge” effluent limits for all pollutants in

bottom ash transport water and FGMC wastewater; 

• Establish numeric effluent limits for mercury, arsenic, selenium, and TDS in 

discharges of gasification wastewater;

• Establish numeric effluent limits for TSS, oil and grease, copper, and iron in 

discharges of nonchemical metal cleaning wastes; and

• Establish numeric effluent limits for mercury and arsenic in discharges of leachate.

The record indicates that the proposed NSPS is technologically available and 

demonstrated. The technologies that serve as the basis for Option 4 are all available based on the 

performance of plants using components of the suite of technologies within the past decade. For 

example, approximately a third of plants that discharge FGD wastewater utilize chemical 

precipitation (in some cases, also using additional treatment steps). Five plants operate fixed-film 

anoxic/anaerobic biological treatment systems for the treatment of FGD wastewater and another 

operates a suspended growth biological treatment system that targets removal of selenium.63

EPA is aware of industry concerns with the feasibility of biological treatment at some power 

plants. Specifically, industry has asserted that the efficacy of these systems is unpredictable, and 

is subject to temperature changes, high chloride concentrations, and high oxidation reduction 

potential in the absorber (that may kill the treatment bacteria). EPA’s record to date does not 

support these assertions, but is interested in additional information that addresses these concerns. 

Moreover, approximately 50 coal-fired generating units were built within the last 20 years and 

most (83 percent) manage their bottom ash without using water to transport the ash and, as a 

 

63 Four of the six operate the biological treatment systems in combination with chemical precipitation. Other power 

plants are considering installing the biological treatment technology to remove selenium, and at least one plant is 

moving forward with construction.
Section 8 - Technology Options Considered as Basis for Regulation

8-38 

result, do not discharge bottom ash transport water. The Option 4 technologies in the proposed 

rule represent current industry practice for gasification wastewater. Every IGCC power plant 

currently in operation uses vapor-compression evaporation to treat the gasification wastewater, 

even when the wastewater is not discharged and is instead reused at the plant. In the case of 

FGMC wastewater, every plant currently using post-combustion sorbent injection (e.g., activated 

carbon injection) either handles the captured spent sorbent with a dry process or manages the 

FGMC wastewater so that it is not discharged to surface waters (or has the capability to do so). 

For leachate, as discussed in Section 7, chemical precipitation is a well-demonstrated technology 

for removing metals and other pollutants from a variety of industrial wastewater, including 

leachate from other landfills not located at power plants. It therefore represents the “greatest 

degree of effluent reduction...achievable” as that phrase is used in section 306 of the Clean 

Water Act.

The proposed NSPS for discharges of nonchemical metal cleaning waste are equal to the 

current BPT effluent limits that apply to discharges of these wastes from existing sources. As 

such, the proposed NSPS would be consistent with current industry practice for treating 

nonchemical metal cleaning waste and is based on the same technology that was used as the 

basis for the current NSPS for chemical metal cleaning waste. Based on responses to the industry 

survey, facilities typically treat both chemical and nonchemical metal cleaning waste in similar 

fashion. 

The NSPS being proposed also poses no barrier to entry. The cost to install technologies 

at new units are typically less than the cost to retrofit existing units. For example, the cost 

differential between BAT Options 3 and 4 for existing sources is mostly associated with 

retrofitting controls for bottom ash handling systems. For existing generating units, the effluent 

requirements considered under Option 4a for BAT would cause those plants with units greater 

than 400 MW that discharge bottom ash wastewater to either modify their processes to become a 

closed-loop wet sluicing system, or retrofit modifications such as replacing the bottom of boilers 

to accommodate mechanical drag chain systems. For new sources, however, Option 4 would not 

present plants with the same choice of retrofit versus modification of existing processes. This is 

because every new generating unit already has to install some type of bottom ash handling 

system as the unit is constructed. Establishing a zero discharge standard for pollutants in bottom 

ash transport water as part of the NSPS means that power plants will install a dry bottom ash 

handling system during construction instead of installing a wet-sluicing system. EPA estimates 

that over the past 20 years, more than 50 new coal-fired generating units were built and that most 

of these units (83 percent) installed dry bottom ash handling systems. 

Moreover, as described in the Regulatory Impact Analysis for Proposed Effluent 

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

Category, EPA assessed the possible impacts of Option 4 to new units by comparing the costs of 

the Option 4 technologies to the costs of a new generating unit as part of its Integrated Planning 

Model analyses. In both cases, the results show that the incremental costs that would be imposed 

by Option 4 do not present a barrier to entry. EPA estimated that the compliance costs for a new 

unit (capital and O&M) represent at most 1.5 percent of the annualized cost of building and 

operating a new 1,300 MW coal-fired plant, with capital costs representing less than 1 percent of 

the overnight construction costs, and annual O&M costs representing less than 5 percent of the 

cost of operating a new plant. IPM results show no barrier to new generation capacity during the 
Section 8 - Technology Options Considered as Basis for Regulation

8-39 

model years in which all existing plants must be in compliance as a result of the BAT/NSPS 

compliance scenario. 

Finally, EPA has analyzed non-water quality environmental impacts associated with 

Option 4 for existing sources, and its analysis is relevant to the consideration of non-water 

quality environmental impacts associated with Option 4 for new sources. EPA’s analysis 

demonstrates that the non-water quality environmental impacts associated with Option 4 for 

existing sources are acceptable. Given that there is nothing inherent about a new unit that would 

alter the analysis for such sources, EPA believes that the non-water quality environmental 

impacts associated with the proposed NSPS regulatory option are, likewise, acceptable. 

In contrast to the best available technology economically achievable, or BAT, that EPA is 

proposing for existing sources, the proposed NSPS would establish the same limits for oil-fired 

generating units and small generating units that are being proposed for all other new sources.64 A 

key factor that affects compliance costs for existing sources is the need to retrofit new pollution 

controls to replace existing pollution controls. New sources do not trigger retrofit costs because 

the pollution controls (process operations or treatment technology) are installed at the time the 

new source is constructed. Thus, new sources are less likely than an existing source to 

experience financial stress by the cost of installing pollution controls, even if the pollution 

controls are identical. 

EPA is not proposing regulatory Options 1 or 2, which would establish new effluent 

limits for only two of the seven key wastestreams addressed by this proposed rule, as its 

preferred option for NSPS. As explained above, neither of these two options represents the 

greatest degree of effluent reduction which the Administrator determines to be achievable 

through the best available demonstrated control technology. 

EPA also did not select any of the preferred BAT regulatory Options (i.e., Options 3a, 3b, 

3, or 4a) as its preferred option for NSPS because they would not control FGD wastewater 

(Option 3a and Option 3b for plants with a total wet-scrubbed capacity of less than 2,000 MW), 

bottom ash transport water (Option 3a, Option 3b, Option 3, and Option 4a for units less than or 

equal to 400 MW) or leachate discharges (Options 3a, 3b, 3, and 4a) and other, more effective, 

available technologies exist that do not present a barrier to entry and have acceptable non-water 

quality environmental impacts. EPA did not select preferred Option 3a for the same reasons it 

rejected Options 1 and 2. EPA did not select Options 3b, 3, or 4a because, under these regulatory 

options, NSPS effluent limits for bottom ash transport water for all or some portion of units and 

leachate would be set equal to the current BAT effluent limits on TSS and oil and grease, which 

are based on using surface impoundments.65 The record demonstrates that zero discharge 

technologies are effective and available for managing bottom ash at new sources. Since these 

zero discharge technologies have been installed at 83 percent of coal-fired units built in the last 

20 years, effluent standards based on surface impoundments do not represent Best Available 

Demonstrated Control Technology to control the discharge of pollutants in the bottom ash 

wastestream from new sources regardless of the unit size. In addition, the record demonstrates 

that chemical precipitation is a more effective technology than surface impoundments for 

 

64 As a point of clarification, this similarly holds true for bottom ash limitations. 

65 This rationale similarly applies to Option 3a.
Section 8 - Technology Options Considered as Basis for Regulation

8-40 

controlling the pollutants present in leachate. For these reasons, Options 3b, 3 and 4a do not 

represent the best available demonstrated control technology to control the discharge of 

pollutants of concern from new sources. 

EPA did not select Option 5 as its preferred option for NSPS because of its high costs, 

which are substantially higher than the costs for Option 4 and the other options evaluated for 

NSPS. See Section 9.10 for more information about the estimated compliance costs for the NSPS 

options. The cost differential between Options 4 and 5 is primarily due to the evaporation 

technology basis for controlling pollutants in FGD wastewater under Option 5. 

Finally, EPA notes that Option 5 is comparable to Option 4 with respect to much of the 

anticipated pollutant removals, particularly the expected removals of arsenic, mercury, selenium 

and nitrogen. At the same time, Option 5 would control other pollutants in FGD wastewater that 

Options 1 through 4 do not effectively control, namely boron, bromides, and TDS. EPA is aware 

that bromide in wastewater discharges from steam electric power plants located upstream from a 

drinking water intake has been associated with the formation of trihalomethanes, also known as 

THMs, when it is exposed to disinfectant processes in water treatment plants. EPA recommends

that permitting authorities consider the potential for bromide discharges to adversely impact 

drinking water intakes when determining whether additional water quality-based effluent limits 

may be warranted. Although EPA did not select Option 5 as the preferred NSPS option, the 

technologies forming the basis for Option 5 are all technologically available and may be 

appropriate (individually or in totality) as the basis for water quality-based effluent limits in 

individual or general permits depending on site-specific conditions. 

8.1.5 Rationale for the Proposed PSES Technology 

Section 307(b), 33 U.S.C. 1317(b), of the Clean Water Act requires EPA to promulgate 

pretreatment standards for pollutants that are not susceptible to treatment by POTWs or which 

would interfere with the operation of POTWs. EPA looks at a number of factors in selecting the 

technology basis for pretreatment standards. For existing sources, these factors are generally the 

same as those considered in establishing BAT. However, unlike direct dischargers whose 

wastewater will receive no further treatment once it leaves the facility, indirect dischargers send 

their wastewater to POTWs for further treatment. As such, EPA must also determine that a 

pollutant is not susceptible to treatment at a POTW or would interfere with POTW operations. 

Table 8-2 summarizes the pass through analysis results for the BAT/NSPS pollutants for 

the various wastestreams and regulatory options. As shown in the table, all of the pollutants 

proposed for regulation under BAT/NSPS pass through. 
Section 8 - Technology Options Considered as Basis for Regulation

8-41 

Table 8-2. Summary of Pass Through Analysis 

Technology Option Pollutant

Pass Through?

(Yes or No)

Chemical Precipitation for FGD Wastewater 

and/or Combustion Residual Leachate

Arsenic Yes

Mercury Yes

Biological (one-stage chemical precipitation 

followed by anoxic/anaerobic biological) for FGD 

wastewater and/or Combustion Residual Leachate

Arsenic Yes

Mercury Yes

Nitrate Nitrite as N Yes

Selenium Yes

Mechanical Vapor-Compression Evaporation for 

FGD Wastewater

Arsenic Yes

Mercury Yes

Selenium Yes

TDS Yes

Mechanical Vapor-Compression Evaporation for 

IGCC Wastewater 

Arsenic Yes

Mercury Yes

Selenium Yes

TDS Yes

Nonchemical Metal Cleaning Wastes Copper Yes

EPA evaluated the same model technologies and regulatory options for PSES that it 

evaluated for BAT (described in Section 8.1.2). These standards would apply to existing 

generating units that discharge wastewater to POTWs. 

As explained in Section 1.2.5, in selecting the PSES technology basis, the Agency 

generally considers the same factors as it considers when setting BAT, including economic 

achievability. Typically, the result is that the PSES technology basis is the same as the BAT 

technology basis. After considering all of the technology options described in Section 8.1.2, as is 

the case for BAT, EPA is proposing four preferred alternatives for PSES (i.e., Options 3a, 3b, 3, 

and 4a). 

With the exception of oil-fired generating units and small generating units (i.e., 50 MW 

or smaller), the proposed rule under Option 3a would: 

• Establish a “zero discharge” effluent limit for all pollutants in fly ash transport water 

and FGMC wastewater;

• Establish numeric effluent limits for mercury, arsenic, selenium, and TDS in 

discharges of gasification wastewater; 
Section 8 - Technology Options Considered as Basis for Regulation

8-42 

• Establish numeric effluent limits for copper in discharges of nonchemical metal 

cleaning wastes;

66 and

• Establish BAT effluent limits for bottom ash transport water and leachate that are 

equal to the current BPT effluent limits for these discharges (i.e., numeric effluent 

limits for TSS and oil and grease)

With the exception of oil-fired generating units and small generating units (i.e., 50 MW 

or smaller), the proposed PSES under Option 3b would: 

• Establish standards for mercury, arsenic, selenium, and nitrate-nitrite in discharges of 

FGD wastewater for units located at plants with a total wet-scrubbed capacity of 

2,000 MW;67

• Establish a “zero discharge” standard for all pollutants in fly ash transport water and 

FGMC wastewater; 

• Establish standards for copper in discharges of nonchemical metal cleaning wastes;68

and

• Establish standards for mercury, arsenic, selenium, and TDS in discharges of 

gasification wastewater.

Under the third preferred alternative for PSES (Option 3), in addition to the requirements 

described for Option 3b, the proposed rule would establish the same standards for mercury, 

arsenic, selenium, and nitrate-nitrite in discharges of FGD wastewater as for Option 3b from 

units at all steam electric facilities, with the exception of oil-fired generating units and small 

generating units (i.e., 50 MW or smaller). 

Under the fourth preferred alternative for PSES (Option 4a), the proposed rule would 

establish “zero discharge” effluent limits for all pollutants in bottom ash transport water for units 

greater than 400 MW. All other proposed Option 4a requirements are identical to the proposed 

Option 3 requirements. 

EPA is putting forth Options 3a, 3b, 3, and 4a as the Agency’s preferred PSES regulatory 

options in order to confirm its understanding of the pros and cons of these options through the 

 

66 As described in Section VIII.A.3, EPA is proposing to exempt from new BAT copper and iron effluent limits 

existing discharges of nonchemical metal cleaning wastes that are currently authorized by an NPDES permit without 

iron and copper limits. This exemption also applies to any indirect discharges of nonchemical metal cleaning waste 

that are authorized without copper pretreatment standards. For such indirect discharges, the regulation would not 

specify PSES.

67 Under Option 3b (for units located at plants with a total wet-scrubbed capacity of less than 2,000 MW), the 

regulations would not specify PSES for FGD wastewater, and POTWs would need to develop local limits to address 

the introduction of pollutants by steam electric power plants to the POTWs that cause pass through or interference, 

as specified in 40 C.F.R.403.5(c)(2).

68As described in Section VIII.A.3, EPA is proposing to exempt from new BAT copper and iron effluent limits 

existing discharges of nonchemical metal cleaning wastes that are currently authorized by an NPDES permit without 

iron and copper limits. This exemption also applies to any indirect discharges of nonchemical metal cleaning waste 

that are authorized without copper pretreatment standards. For such indirect discharges, the regulation would not 

specify PSES. 
Section 8 - Technology Options Considered as Basis for Regulation

8-43 

public comment process and intends to evaluate this information and how it relates to the factors 

specified in the CWA. For the same reasons identified in Section 8.1.3 for BAT, EPA’s analysis 

to date suggests that for indirect dischargers as well as direct dischargers, the Option 3a, Option 

3b, Option 3, and Option 4a technologies are available and economically achievable, and that the 

other regulatory options (Options 1, 2, 4, and 5) do not reflect the criteria for PSES. In addition, 

EPA has determined that these standards will prevent pass-through of pollutants from POTWs 

into receiving streams and also help control contamination of POTW sludge. EPA also 

considered the non-water quality environmental impacts and found them to be acceptable, as 

described in Section 12. Furthermore, for the same reasons that apply to EPA’s preferred BAT 

options and described in Section 8.1.3, with the exception of numeric standards for copper in 

discharges of nonchemical metal cleaning wastes, EPA is proposing not to subject discharges 

from oil-fired generating units and small generating units (i.e., 50 MW or smaller) to POTWs to 

requirements based on Options 3a, 3b, 3, or Option 4a.69,70 

Finally, similar to EPA’s preferred BAT options and for the reasons supporting those 

options, for certain wastestreams, EPA is proposing that any new PSES discharge standards 

would apply to discharges of the regulated wastewater generated after July 1, 2017. See 

discussion in Section 14. 

8.1.6 Rationale for the Proposed PSNS Technology 

Section 307(c) of the CWA, 33 U.S.C. 1317(c), authorizes EPA to promulgate 

pretreatment standards for new sources (PSNS) at the same time it promulgates new source 

performance standards (NSPS). As is the case for PSES, PSNS are designed to prevent the 

discharge of any pollutant into a POTW that may interfere with, pass through, or may otherwise 

be incompatible with POTWs. In selecting the PSNS technology basis, the Agency generally 

considers the same factors it considers in establishing NSPS along with the results of a pass 

through analysis. As a result, EPA typically promulgates pretreatment standards for new sources 

based on best available demonstrated technology for new sources See National Ass'n of Metal 

Finishers v. EPA, 719 F.2d 624, 634 (3rd Cir. 1983). The legislative history explains that 

Congress required simultaneous establishment of new source standards and pretreatment 

standards for new sources for two reasons. First, Congress wanted to ensure that any new source 

industrial user achieve the highest degree of internal effluent controls necessary to ensure that 

such user's contribution to the POTW would not cause a violation of the POTW's permit. 

Second, Congress wished to eliminate from the new user’s discharge any pollutant that would 

pass through, interfere, or was otherwise incompatible with POTW operations. 

For the proposed ELGs, EPA evaluated the same model technologies and regulatory 

options for PSNS that it evaluated for NSPS (described in Section 8.1.4). These standards would 

apply to new generating units or new facilities that discharge wastewater to POTWs. After 

considering all of the technology options described in Section 8.1.2, as is the case for NSPS, 

 

69 EPA is proposing to exempt from new PSES copper standards for existing discharges of nonchemical metal 

cleaning wastes that are currently authorized. For these discharges, the regulation would not specify PSES.

70 Preferred Option 4a would increase this threshold for purposes of discharges of pollutants in bottom ash transport 

water only, to 400 MW or less.
Section 8 - Technology Options Considered as Basis for Regulation

8-44 

EPA is proposing to establish PSNS based on the technologies specified in Option 4. The 

proposed PSNS would: 

• Establish standards for mercury, arsenic, selenium, and nitrate-nitrite in discharges of 

FGD wastewater;

• Maintain a “zero discharge” standard for all pollutants in fly ash transport water, and 

establish a zero discharge standard for bottom ash transport water and FGMC 

wastewater;

• Establish standards for mercury, arsenic, selenium, and TDS in discharges of 

gasification wastewater; 

• Establish standards for copper in discharges of nonchemical metal cleaning wastes; 

and

• Establish standards for mercury and arsenic in discharges of leachate. 

For the same reasons identified for NSPS in Section 8.1.4, EPA is proposing Option 4 as 

its preferred option because the technologies forming the basis for that option are available and 

demonstrated and will not pose a barrier to entry.71 In addition, EPA has determined that these 

standards will prevent pass-through of pollutants from POTWs into receiving streams and also 

help control contamination of POTW sludge. EPA also considered the non-water quality 

environmental impacts associated with the preferred option and found them to be acceptable, as 

described in Section 14. 

8.1.7 Consideration of Future FGD Installations on the Analyses for the ELG 

Rulemaking

As explained earlier, implementation of air pollution controls may create new wastewater 

streams at power plants. The analyses and the findings on economic achievability presented in 

this preamble reflect consideration of wastestreams generated by air pollution controls that will 

likely be in operation at plants at the time EPA takes final action on this rulemaking. However, 

EPA recognizes that some recently promulgated Clean Air Act requirements, along with state 

requirements or enforcement actions, may lead to additional air pollution controls (and resulting 

wastestreams) at existing plants beyond this date. In an effort to assess the economic 

achievability of the proposed rule in such cases, EPA also conducted a sensitivity analysis that 

forecasts future installations of air controls through 2020 and the associated costs of complying 

with the proposed regulatory requirements for the wastewater that may result from the forecasted 

air control installations.72 The sensitivity analysis and results are described in more detail in the 

memorandum entitled, “Flue Gas Desulfurization Future Profile Sensitivity Analysis” [ERG, 

2013a]. 

 

71 For the same reasons discussed above in Section VIII for NSPS, EPA similarly determined the other regulatory 

options do not reflect PSNS.

72 EPA considers that by forecasting future installations of controls out to the year 2020, the sensitivity analyses for 

this rulemaking reasonably reflect full implementation of air pollution controls to comply with existing federal and 

state requirements.
Section 8 - Technology Options Considered as Basis for Regulation

8-45 

EPA has two primary data sources upon which to make its projections of future air 

control installations: 1) Integrated Planning Model estimates for the final MATS rule;73 and 2) 

responses to EPA’s steam electric industry survey. At the time EPA promulgated the MATS rule 

in 2011, it projected air pollution control retrofits using IPM (which also included projected 

retrofits for CSAPR). To support this rulemaking, EPA surveyed the industry about its plans for 

installing certain new air pollution controls at facilities through 2020. EPA has no reason to 

conclude that either the IPM FGD projections or the survey projections are more accurate than 

the other. In fact, both of these sources may overstate actual installations. Prior to MATS 

becoming final, many plant owners and operators assumed that wet scrubbers would be the only 

technology available to meet emissions limits for acid gases. As EPA gathered and published 

additional data on facility emission rates (which informed how the Agency set the standards), 

and as stakeholders researched and published additional information on the performance of less 

capital-intensive control technologies such as dry sorbent injection, it has become clear that 

many facilities will find it more cost-effective to forgo wet scrubbers in favor of other emissionreduction strategies. Furthermore, major economic variables such as electricity demand and 

natural gas prices have changed substantially since the prevailing market conditions in 2010, 

when respondents were answering the survey. For example, a facility originally indicating an 

expectation in the industry survey to install a wet scrubber by 2020 may now find itself no longer 

competitive in the updated marketplace with substantially lower natural gas prices and lower 

electricity demand growth than previously expected. Consequently, the facility may elect to 

retire and thereby neutralize the previously reported intent to scrub. Nevertheless, these two 

sources remain the best available information EPA has with which to estimate future conditions. 

As a first step in conducting a sensitivity analysis, EPA compared the projections from 

the two sources described above. This comparison demonstrates that the IPM results for the 

MATS Policy Case and the ELG industry survey responses are consistent at the aggregate level. 

Furthermore, in very large part, both the survey and IPM identify the same generating units as 

being wet-scrubbed, either currently or in the future (the two sources are in agreement for 

approximately 94 percent of the wet-scrubbed units). The two sources also project similar wetscrubbed capacities. In the very few cases where there are differences between the two sources, 

the differences are primarily due to the expected variation at a unit-level (e.g., IPM projects wet 

FGD at unit A and dry FGD at unit B, but instead the survey responses report wet FGD at unit B 

and dry FGD at unit A). Another difference between the MATS IPM estimates and the industry 

survey estimates is that, in a very few cases, the IPM results estimate that certain plants would 

retire (and therefore would not install wet scrubbers). In conducting the analyses for the ELG, 

EPA made the conservative assumption (i.e., one that would tend to overestimate cost, if 

anything) that a plant would still be in operation in 2020 unless the plant has formally announced 

its closure by 2014. 

Because its goal in conducting this sensitivity analysis was to assess the economic 

achievability of the proposed ELG, even in light of possible future air controls, EPA developed a 

conservative upper bound estimate of future installations by combining the results of the two 

sources to develop its “future steam profile.” In other words, EPA combined any source that 

reported or projected a wet FGD into one “future steam profile.” This “future steam profile” is 

 

73 EPA IPM v.4.10 projections for units based on compliance with CSAPR, MATS, state rules, and enforcement 

actions including consent decrees.
Section 8 - Technology Options Considered as Basis for Regulation

8-46 

conservative because it reflects more wet FGDs than are anticipated to actually be installed; that 

is, by aggregating the survey and IPM forecast estimates it results in a total number of wet FGD 

systems and wet-scrubbed capacity that is greater than either of those individual sources. EPA 

then added costs associated with projected wastewater discharges from this future steam profile 

to comply with the proposed ELGs to the total costs it previously calculated for the existing 

universe. Based on the results of this conservative analysis, EPA finds that discharges from these 

additional air controls (which, if actually installed, would be due to various requirements 

including state rules, consent decrees, CSAPR/CAIR, and MATS) may increase the costs of the 

proposed rule by no more than 10 to 15 percent. Even if all of these additional costs were to 

come to fruition, which is unlikely since the “future steam profile” overestimates the number of 

new wet FGD systems that are anticipated, EPA finds that these additional costs are 

economically achievable. 

EPA notes that subsequent to its analysis, the D.C. Circuit Court of Appeals vacated the 

CSAPR. EPA will continue to assess the potential impacts that changes to air pollution 

regulations may have on future installations of wet FGD systems. For the purpose of FGD 

wastewater analyses for this rulemaking, EPA has made a conservative assumption that all of the 

previously projected wet scrubber additions in the CSAPR-inclusive baseline (which also 

included MATS, state rules, consent decrees, etc.) would continue to be built, and that discharges 

from those additional wet scrubbers would therefore be subject to the proposed revisions to the 

ELGs.

8.2 TIMING OF NEW REQUIREMENTS

As part of its consideration of technological availability and economic achievability, EPA 

considered the magnitude and complexity of process changes and new equipment installations 

that would be required at many existing facilities to meet the requirements of the rule. As 

discussed in Section 8.1.2, EPA proposes that certain BAT limitations for existing sources (those 

that would establish requirements more stringent than existing BPT requirements) would apply 

on a date determined by the permitting authority that is as soon as possible when the next permit 

is issued beginning July 1, 2017 (approximately three years from the effective date of this rule). 

This is true of the proposed limitations and standards based on any of the eight main regulatory 

options, including the preferred options, Option 3a, Option 3b, Option 3, or Option 4a. 

EPA is proposing this approach for several practical reasons. While some facilities 

already have the necessary equipment and processes in place, or could do so relatively quickly, 

and may need little time before they are able to comply with the revised ELG requirements, not 

all will be able to do so. Some facilities will need time to raise the capital, plan and design the 

system, procure equipment, construct and then test the system. Moreover, providing a window of 

time will better enable facilities to install the pollution control technology during an otherwise 

planned shutdown or maintenance period. In some cases, a facility must apply for permission to 

enter into such a period where they are producing no or less power. 

During site visits, EPA found that most facilities need several years to plan, design, 

contract, and install major system modifications, especially if they are to be accomplished during 

planned maintenance periods to avoid causing forced outages. EPA recognizes that the proposed 

rule would require a significant amount of system design by engineering firms, equipment 
Section 8 - Technology Options Considered as Basis for Regulation

8-47 

procurement from vendors, and installation by trained labor forces. EPA anticipates that changes 

to FGD wastewater treatment systems, fly ash systems, bottom ash systems, and/or leachate 

treatment systems would constitute major system modifications requiring several years to 

accomplish for many plants. EPA identified certain technical and logistical issues at some 

facilities that may warrant additional time, such as coordinating ash system conversions for 

multiple generating units. In order to avoid any impacts on the consistency and reliability of 

power generation, outages at multiple facilities in one geographic area would need to be 

coordinated, which could also result in the need for more time. 

EPA recognizes that permitting authorities have discretion with respect to when to reissue 

permits and can take into consideration the need to provide additional time to include BAT limits 

to prevent or minimize forced outages. Thus, in some cases, the new BAT requirements may as a 

practical matter be applied to a facility sometime after July 1, 2017. However, EPA judges that, 

under the proposed approach, all steam electric facilities will have the proposed BAT limitations 

applied to their permits no later than July 1, 2022, approximately 8 years from the date of 

promulgation of any final ELGs. For indirect discharges, except with respect to discharges of 

nonchemical metal cleaning waste, the proposed PSES requirements would apply by the date 

determined by the control authority that is as soon as possible beginning July 1, 2017, or 

approximately three years after promulgation of any final ELGs. EPA's record indicates it may 

not take that long for all facilities to meet the limitations and standards. Some plants may not 

require a major modification for one or more systems to be able to comply with new effluent 

limits and therefore would need less time. For example, some plants have installed dry fly ash 

handling systems that have capacity to handle all generated ash dry, yet they also maintain a wet 

ash handling system as a backup. The backup wet system is typically operated only a few days 

per year. According to the industry survey, plants such as these could quickly cease operation of 

the wet system, complying with a zero discharge requirement with relative ease. 

EPA envisions that each facility subject to the proposed ELGs would study available 

technologies and operational measures, and subsequently install, incorporate and optimize the 

technology most appropriate for each site. EPA believes the proposed rule affords flexibility for 

a reasonable amount of time to conduct engineering studies, assess and select appropriate 

technologies, apply for necessary permits, complete construction, and optimize the technologies’ 

performance. The permitting authority could establish any additional interim milestones, as 

appropriate, within these timelines. 

8.3 REFERENCES

1. Eastern Research Group (ERG). 2013a. Memorandum to the Record: Flue Gas 

Desulfurization Future Profile Sensitivity Analysis. (29 January). DCN SE01989. 

2. Eastern Research Group (ERG). 2013b. Memorandum to the Steam Electric Rulemaking 

Record: Evaluation of Chemical Precipitation Costs for Ash Transport Water. (19 April). 

DCN SE03869. 

3. Eastern Research Group (ERG). 2013c. Memorandum to the Steam Electric Rulemaking 

Record: Status of Biological Treatment Systems to Remove Selenium. (19 April). DCN 

SE03874. 
Section 8 - Technology Options Considered as Basis for Regulation

8-48 

4. Eastern Research Group (ERG). 2013d. Memorandum to the Rulemaking Record: 

Methodologies for Estimating Costs and Pollutant Removals for Steam Electric ELG 

Regulatory Option 4a. (19 April). DCN SE03834. 

5. Electric Power Research Institute (EPRI). 2006. 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 SE01817. 

6. U.S. EPA. 2002. Development Document for Final Effluent Limitations Guidelines and 

Standards for the Iron and Steel Manufacturing Point Source Category. EPA-821-R-02-

004. Washington, DC. (April). 

7. U.S. EPA. 2003. Development Document for the Final Effluent Limitations Guidelines 

and Standards for the Metal Products & Machinery Point Source Category. EPA-821-B03-001. Washington, DC. (February). 

8. U.S. EPA. 1983. Development Document for Effluent Limitations Guidelines and 

Standards for the Metal Finishing Point Source Category. EPA-440/1-83/091. 

Washington, DC. (June). 
Section 9 - Engineering Costs

9-1 

SECTION 9

ENGINEERING COSTS

This section presents EPA’s methodology to determine incremental capital and operating 

and maintenance (O&M) costs for the steam electric industry to comply with each regulatory 

option considered for the proposed rule. 

Section 9 describes EPA’s general approach for estimating incremental compliance costs 

for effluent limitations guidelines and standards (ELGs) for industrial categories. Section 9.2

provides a brief description of the basis for the compliance costs for each wastestream and 

technology option. Section 9.3 describes the methodology EPA used to estimate costs for the 

steam electric industry to achieve the limitations and standards based on each technology option 

considered (described in Section 8 of this report). Section 9.3 presents information on the 

specific cost elements included in EPA’s methodology and the criteria EPA used to identify 

plants that would likely incur compliance costs. Section 9.4 describes the development of the 

data inputs, outputs, and model used to estimate the compliance costs. Section 9.5 presents 

EPA’s methodologies for estimating those components of compliance costs that are applicable to 

more than one of the treatment technologies evaluated. Sections 9.6, 9.7, and 9.8 summarize the 

technology options costed and the results of the costs analyses for flue gas desulfurization (FGD) 

wastewater, fly ash and bottom ash transport water, and combustion residual landfill leachate, 

respectively.

9.1 INTRODUCTION

Effluent limitations guidelines and standards establish numerical limits on the discharge 

of pollutants to waters of the United States. These limits are based upon the performance of 

specific technologies that comprise the regulatory options. While implementation of the specific 

technologies that form the basis for the proposed regulatory options would not be required, EPA 

calculates the cost for plants to implement these technologies to estimate the compliance costs 

for the industry to meet the numerical limitations and standards, including any identified best 

management practices (BMPs). For existing sources, compliance costs are incremental, meaning 

they represent the costs expected to be incurred as a result of plants revising exiting operations to 

match those that form the bases of the regulatory options. For new sources, EPA estimates the 

costs to install such technologies compared to what a typical source would do in the absence of 

the rule.

EPA often estimates costs on a per plant basis and then sums or otherwise escalates the 

plant-specific values to represent industry-wide compliance costs. Calculating costs on a per 

plant basis allows EPA to account for differences in plant characteristics such as types of 

processes used, wastewaters generated and their flows/volumes and characteristics, and 

wastewater controls in place (e.g., best management practices and end-of-pipe treatment). EPA 

took this approach in estimating the compliance costs associated with the proposed rule. 

EPA estimated the costs to steam electric power plants – whose primary business is 

electric power generation or related electric power services – of complying with the proposed 

ELGs. EPA evaluated the costs of the proposed ELGs on all plants currently subject to the 
Section 9 - Engineering Costs

9-2 

existing ELGs.74 Some aspects of the proposed ELGs (e.g., applicability changes) would likely 

not lead to increased costs to complying plants. Other aspects of the proposed ELGs would likely 

lead to increased costs to a subset of complying plants. These plants are generally those that 

generate the wastestreams for which EPA is proposing new limitations or standards. This section 

describes the detailed costing evaluation EPA performed for these plants that may incur 

compliance costs associated with the proposed rule. 

As discussed earlier in Section 5, EPA proposes to establish a separate set of 

requirements for existing oil-fired generating units and units with a capacity of 50 MW or less. 

For these units, BAT limits would be set equal to BPT limits. As the proposed rule would not 

establish additional control on discharges associated with these operations, EPA accordingly did 

not include incremental costs for these units as a result of this proposed rule.75

EPA estimated compliance costs associated with each of the regulatory options from data 

collected through survey responses, site visits, sampling episodes, and from individual power 

plants and equipment vendors. EPA used this information to develop computerized cost models 

for each of the technologies that form the basis of the regulatory options. EPA used these models 

to calculate plant-specific compliance costs for all power plants that the information suggests 

would incur costs to comply with one or more proposed requirements associated with the 

regulatory options.76 Therefore, EPA's plant-specific cost estimates represent the incremental 

costs for a plant when its existing practices would not lead to compliance with the option being 

evaluated. While implementation of the specific technologies that form the basis for the proposed 

regulatory options would not be required, EPA calculated the cost and for the plant to implement 

these technologies to estimate of the compliance costs associated with EPA’s proposal. 

EPA’s cost estimates include the following key cost components: capital costs (one-time 

costs); annual operating and maintenance costs (which are incurred every year); and other onetime or recurring costs. Capital costs comprise the direct and indirect costs associated with the 

purchase, delivery, and installation of pollution control technologies. Capital cost elements are 

specific to the industry and commonly include purchased equipment and freight, equipment 

installation, buildings, site preparation, engineering costs, construction expenses, contractor’s 

fees, and contingency. Annual operating and maintenance costs comprise all costs related to 

operating and maintaining the pollution control technologies or performing BMPs for a period of 

one year. Operating and maintenance costs are also specific to the industry and commonly 

include costs associated with operating labor, maintenance labor, maintenance materials (routine 

replacement of equipment due to wear and tear), chemical purchase, energy requirements, 

residual disposal, and compliance monitoring. In some cases, the technology options may also 

 

74 Based on the Steam Electric Survey responses, Internet searches, articles, and data provided by the industry, EPA

removed the following types of plants, or steam electric generating units, from the analysis as they were considered 

outside the applicability of the rule or would be by the time the final rule is promulgated: plants, or steam electric 

generating units, expected to be retired by 2014; and plants, or steam electric generating units, converting to nonfossil fuel sources (e.g., natural gas, municipal solid waste) by 2014.

75 EPA did estimate costs for these operations to comply with the BAT limits applicable to the rest of the units and 

has included those estimates in the docket for the proposed rule.[U.S. EPA, 2012].

76 Because the rule is scheduled for promulgation in May 2014, EPA did not include compliance costs or pollutant 

removals for plants that are expected to retire by 2014 and plants that do not discharge any of the applicable 

wastestreams.
Section 9 - Engineering Costs

9-3 

result in recurring costs that are incurred less frequently than annually (e.g., 3-year recurring 

costs for equipment replacement) or one-time costs other than capital investment (e.g., one-time 

engineering costs).

9.2 STEAM ELECTRIC TECHNOLOGY OPTION COST BASES

The following subsections provide a brief description of the basis for the estimation of 

the compliance costs for each wastestream and technology option. The technology options 

considered as the bases of the regulatory options are identified in Section 8 and described in 

detail in Section 7. 

9.2.1 FGD Wastewater 

EPA estimated compliance costs for plants to treat FGD wastewater using one of the 

following three technology options: 

• One-stage chemical precipitation;

• One-stage chemical precipitation followed by biological treatment; and

• One-stage chemical precipitation followed by softening and vapor-compression 

evaporation. 

For the one-stage chemical precipitation system, EPA included costs for the plants to 

install and operate the following: 

• Equalization tank to hold and store the wastewater; 

• Reaction tanks for the addition of lime, organosulfide, ferric chloride, and polymers; 

• Solids-contact clarifier to remove suspended solids; 

• Gravity sand filter to reduce solids; and 

• Effluent storage tank. 

Additionally, EPA included costs for a sludge holding tank and filter presses to dewater 

the solids collected in the clarifier. EPA also included costs for the transport and disposal of the 

resulting solids in a landfill. The costs also include all ancillary equipment and the associated 

operating and maintenance costs associated with the system.

For the one-stage chemical precipitation followed by biological treatment system, EPA 

included all the costs described above for the chemical precipitation system, but it also included 

costs for the following: 

• Anoxic/anaerobic biological treatment system (two stages); and

• Heat exchanger (for plants in certain geographic locations).

EPA also included costs for the transport and disposal of additional solids collected in the 

biological system. The costs include all ancillary equipment and the associated operating and 

maintenance costs associated with the system.
Section 9 - Engineering Costs

9-4 

For the one-stage chemical precipitation followed by softening and vapor-compression 

evaporation, EPA included all the costs described above for the chemical precipitation system, 

but it also included costs for the following: 

• Softening step, including clarification and solids dewatering; 

• Reaction tank for acid addition; 

• Heat exchanger to increase the temperature of the wastewater;

• Deaerator to remove noncondensibles; 

• Mechanical vapor compression brine concentrator; 

• Distillate tank; and

• Forced-circulation crystallizer.

EPA also included costs for the transport and disposal of additional solids collected in the 

softener and the forced-circulation crystallizer. The costs include all ancillary equipment and the 

associated operating and maintenance costs associated with the system.

9.2.2 Fly Ash Transport Water 

EPA estimated compliance costs for plants operating wet sluicing systems to convert to 

dry vacuum fly ash handling systems. For each generating unit with a wet sluicing system, EPA 

determined that the plants would likely continue to use the existing valves and branch lines 

underneath the fly ash collection hoppers, but the plant would require new valves and piping to 

convey the ash to the silo(s). Additionally, EPA included costs for a mechanical exhauster to 

create the vacuum. EPA also included costs for the plant to install a new silo, including pugmills 

and wet unloading equipment. Finally, EPA included costs for the transport and disposal of all 

the additional ash that the plant is now handling with the dry vacuum system. 

9.2.3 Bottom Ash Transport Water 

EPA estimated compliance costs for plants operating wet sluicing systems to convert to 

bottom ash handling systems that eliminate the discharge of bottom ash transport water. For each 

generating unit with a wet sluicing system, EPA estimated the costs for converting to one of the 

following two systems:

• Mechanical drag system; and

• Remote mechanical drag system.

For the mechanical drag system, EPA included the costs for the demolition of the bottom 

of the boiler and installation of a mechanical drag system at the bottom of the boiler. The MDS 

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 
Section 9 - Engineering Costs

9-5 

eliminating the need for a heat exchanger.77 For the remote mechanical drag system, EPA 

included the costs for the construction of a remote mechanical drag system away from the boiler, 

as well as a sump, recycle pumps, and a chemical feed system to return the water to the boiler for 

reuse as bottom ash transport water.78 EPA also included the costs for a semi-dry silo for both 

systems. Additionally, EPA included the costs for the transport and disposal of all bottom ash to 

a landfill.

For certain plants that recycle most of the bottom ash transport water within the system 

and only discharge a small amount of wastewater, EPA estimated costs for these plants to hire a 

consultant to help them cease discharging bottom ash transport water and operate a completely 

closed-loop system. 

9.2.4 Combustion Residual Leachate

EPA estimated compliance costs for plants generating combustion residual leachate from 

landfills or surface impoundments to comply with requirements based on one of the following 

two technology options: 

• One-stage chemical precipitation; and

• One-stage chemical precipitation followed by biological treatment.

To estimate the compliance costs for plants that generate landfill leachate, EPA used the 

same general methodology described in Section 9.2.1. 

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. As described in Section 7.4, 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 when faced with the proposed effluent limitations for discharges 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 would be no (or 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, but the 

costs would be offset because the plant no longer needs to operate a separate impoundment (or 

other treatment system) that is currently used to treat the leachate to meet the existing BPT 

 

77 Because the MDS system does not use water as the transport mechanism, the water removed from the system with 

the bottom ash is not bottom ash transport water, and therefore, is not subject to the bottom ash transport water 

effluent limitations.

78 Because the remote MDS system does use water as the transport mechanism, all water removed from the system 

must be reused without discharge to meet the proposed zero discharge effluent limitations for bottom ash transport 

water.
Section 9 - Engineering Costs

9-6 

effluent limitations prior to its discharge. Therefore, there are no compliance costs for 

combustion residual leachate from surface impoundments. Therefore, where this section further 

addresses the costing methodology for combustion residual leachate, it refers to the costs 

associated with the treatment of combustion residual leachate from landfills.

9.2.5 Gasification Wastewater 

As described in Section 4.2.3, there are two currently operating and one planned 

integrated gasification combined-cycle (IGCC) units in the United States. Each of these three 

plants is operating or will operate the vapor-compression evaporation system that is the 

technology basis for the proposed ELGs for gasification wastewater. Therefore, because all the 

plants are currently operating the BAT system, there are no compliance costs for gasification 

wastewater.

9.2.6 Flue Gas Mercury Control Wastewater 

As described in Section 6.4, there are approximately 73 plants with at least one activated 

carbon injection (ACI) system. Of these, only six (three with current systems and three with 

planned systems) reported handling the flue gas mercury control (FGMC) waste using a wet 

sluicing system. However, of these six plants, only one discharges FGMC wastewater, and that 

one plant collects the FGMC waste with the fly ash in the primary particulate control system and 

already has the capability to handle both the FGMC and fly ash dry. Therefore, there are no 

compliance costs for flue gas mercury control wastewater.

9.2.7 Nonchemical Metal Cleaning Wastes 

As described in Section 8.1.3, EPA is proposing to set BAT limitations for nonchemical 

metal cleaning wastes that are equivalent to the BPT standards that are already in place for this 

wastestream. Because nonchemical metal cleaning wastes are already subject to the proposed 

BAT limitations, based on the current BPT standard, the plants generating and discharging 

nonchemical metal cleaning wastes should already be meeting these standards. Additionally, as 

described in Section 8.1.3, 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 there are no compliance costs for nonchemical metal 

cleaning wastes.

9.3 STEAM ELECTRIC COMPLIANCE COST METHODOLOGY

EPA developed a cost methodology to estimate plant-level compliance costs for existing 

and new sources using data collected from the Questionnaire for the Steam Electric Power 

Generating Effluent Guidelines (Steam Electric Survey), site visits, and sampling episodes. EPA 

also solicited data from vendors of various wastewater treatment technologies and ash handling 

operations to estimate plant-level compliance costs. The estimated costs are incremental costs to 

account for only the additional costs beyond those the plant already incurs, or would incur as a 

new source, in order to comply with the proposed regulations. 
Section 9 - Engineering Costs

9-7 

As a first step in estimating costs associated with new or additional limitations or 

standards for discharges from a particular generating unit at an existing steam electric plant (i.e., 

existing sources), EPA used the plant’s survey response to determine if the wastestreams it 

discharges may be subject to new requirements under a regulatory option. Then, for each of the 

wastestreams that may be subject to new requirements for a regulatory option, EPA reviewed the 

survey response, available sampling data, and industry long-term self-monitoring data for the 

plant to determine if its existing practices would lead to compliance with the new or revised 

limitations or standards (e.g. plant currently employs the technology option). In this case, EPA 

finds the plant will incur no compliance cost associated with the discharge of that particular 

wastestream other than compliance monitoring costs. For all other applicable wastestreams, EPA 

assessed the operations and treatment system components in place at the plant, identified 

necessary components that the plant would need to come into compliance, and estimated the cost 

to install and operate those components. As appropriate, EPA also accounted for expected 

reductions in the plant’s costs associated with their current operations or treatment systems that 

would no longer be needed as a result of installing and operating the technology bases (e.g., 

avoided costs to manage surface impoundments). For plants that may already have certain 

components installed, EPA compared certain key operating characteristics, such as chemical 

addition rates, to determine if additional costs (e.g., chemical costs) were warranted.

For example, to comply with Option 3, EPA estimated compliance costs for a plant that 

currently sluices fly ash to an ash impoundment and subsequently discharges that fly ash 

transport water. In this case, EPA estimated the cost for the plant to convert its fly ash handling 

system to a dry vacuum system and determined that certain components of its existing system 

would continue to be used following the conversion.79 EPA also included costs for additional 

equipment, such as vacuum systems and silos, to handle and store the dry fly ash. EPA also 

included additional transportation and landfill disposal costs, and cost savings for managing less 

waste through the ash impoundment(s). 

As another example, to comply with Option 3, EPA estimated compliance costs for a 

plant that currently treats its FGD wastewater through a chemical precipitation system prior to 

discharge. In this case, EPA evaluated 1) whether the chemical precipitation system design basis 

includes equalization with 24-hour residence time, 2) if the plant had an equivalent number 

and/or type of reaction tanks, and 3) if the plant already had components such as chemical feed 

systems, solids contact clarifier, sand filter, effluent and sludge holding tanks, sludge filter 

presses, and pumps in place. If the plant had any of these components in place, EPA did not 

include that cost in its compliance cost estimate. EPA also evaluated whether chemical addition 

costs would be required based on the plant’s reported chemical addition and dosages, and 

estimated the costs for installing and operating the biological treatment stage.

EPA also evaluated the additional transportation and landfill operations required to 

dispose of the additional solid waste generated (FGD sludge, fly ash, bottom ash) from the 

implementation of the technology options. EPA estimated disposal costs based on whether the 

plant reported an on-site combustion residual landfill.

 

79 The conversion from wet to dry fly ash handling for a unit requires new equipment to pneumatically convey the 

ash; however, ash handling vendors stated that for dry vacuum retrofits, the existing hopper equipment and branch 

lines can be retained and reused.
Section 9 - Engineering Costs

9-8 

For each plant, EPA calculated compliance costs for all applicable technology options 

and then calculated the total costs for the eight regulatory options, presented in Section 8.1 of 

this report. For more information on the compliance cost methodology, see EPA’s Incremental 

Costs and Pollutant Removals for Proposed Effluent Limitation Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category [U.S. EPA, 2013]. 

9.4 STEAM ELECTRIC COST MODEL

EPA calculated the industry incremental compliance cost estimates by developing a 

computer-based cost model containing the following main components: 

• Input Data

• Industry Assumptions/Factors

• Technology Cost Modules 

• Model Outputs 

Input data include relevant plant-specific information, such as identification of which 

wastewaters are discharged from each plant, together with plant characteristics such as plant 

processes, wastewater flow rates, production data, and existing pollution control technologies. 

Industry assumptions and factors are general values and factors that are not plant-specific and are 

applicable to the entire industry. These include constants and coefficients used in the cost 

calculations such as equipment design basis (used for equipment sizing, for example hydraulic 

residence time), materials of construction, equipment capacity (accounts for maximum design 

capacity as compared to typical operating conditions), equipment redundancy, transport distance 

for equipment and supplies, transport mode and capacity, and cost indices (used to adjust cost 

data from different years to a common base year). Technology cost modules use the plantspecific input data and industry assumptions/factors to calculate and output costs for a specific 

cost component (technology or technology component) for each applicable wastestream for each 

plant and each regulatory option. Finally, reporting programs combine the applicable cost 

components to calculate plant-level capital and operating and maintenance costs (and any 

necessary one-time and/or recurring costs) for each regulatory option, and to sum or otherwise 

escalate these plant-level costs to calculate total industry capital and operating costs by 

regulatory option. 

EPA used this computer-based cost model approach, including all four main components 

described above, to generate plant-specific compliance costs. The steam electric cost model 

calculates compliance costs by referencing several input tables and running the applicable 

technology cost modules specific to each plant’s input characteristics. The compliance costs for 

each technology option are calculated using a combination of the technology cost modules, some 

that calculate option costs specific to each technology option (e.g., biological treatment, dry fly 

ash handling) and some that calculate common cost elements for each technology option, 

although the inputs may differ based on specific wastestreams (e.g., transport and disposal costs). 

Table 9-1 presents the different technology cost modules that compose the technology options. 

Each technology option incorporates technology-specific and global assumptions and factors to 

calculate the compliance costs (e.g., the model outputs). 
9-9

Section 9 - Engineering Costs

Table 9-1. Technology Costs 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 

Handlinga 

Transportation

Disposal

Impoundment 

Operation Costs

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: As described in Sections 9.2.5 and 9.2.6, EPA did not estimate costs for gasification wastewater, flue gas mercury control wastewater, or nonchemical 

metal cleaning wastes.

a – The technology cost module is called the “Dry Bottom Ash Handling” module, but it includes a technology option that is a closed-loop recycle system.
Section 9 - Engineering Costs

9-10 

9.4.1 Input Data to Technology Cost Modules 

EPA developed a set of input tables based on information from the Steam Electric 

Survey, site visits, and sampling episodes. The cost model references the input tables to estimate 

the appropriate compliance cost for each plant for each technology option. The cost model 

estimates compliance costs at a plant basis for each technology option and then sums the various 

technology option to estimate the plant-level compliance costs for each regulatory option. The 

cost model first references a plant-level input table, which indicates the technology options 

specific to each plant. The plant-level cost input table was developed using data from the Steam 

Electric Technical Questionnaire Database (survey technical database), which was developed 

using the plant responses to the Steam Electric Survey to identify the population of plants that 

discharge wastestreams that may be subject to new or additional limitations or standards [ERG, 

2013d]. For all plants that generate at least one of these wastestreams, EPA determined if the 

plant discharges (or may discharge by 2014) one or more of the applicable wastestreams (e.g., 

FGD wastewater, fly ash transport water) controlled by a regulatory option. If the plant does not 

discharge an applicable wastestream, then EPA set the compliance costs for that wastestream to 

be zero. If the plant does discharge an applicable wastestream, then EPA gathered the plantspecific data appropriate for the applicable technology cost modules. Table 9-2 identifies the 

number of plants that EPA finds will likely incur costs to comply with new or additional 

limitations or standards for a wastestream under at least one of the evaluated regulatory options. 

Table 9-2. Number of Plants Expected to Incur Compliance Costs by Wastestream and 

Regulatory Option 

Regulatory 

Option

FGD 

Wastewater

Fly Ash 

Transport 

Water

Bottom Ash 

Transport 

Water

Combustion 

Residual 

Leachate

Gasification 

Wastewater

Flue Gas 

Mercury 

Control 

Wastewater

Nonchemical 

Metal 

Cleaning 

Wastes Totala 

1 116 0 0 0 0 0 0 116

3a 0 66 0 0 0 0 0 66

2 116 0 0 0 0 0 0 116

3b 17 66 0 0 0 0 0 80

3 116 66 0 0 0 0 0 155

4a 116 66 115 0 0 0 0 200

4 116 66 240 101 0 0 0 277

5 116 66 240 101 0 0 0 277

a – The number of plants incurring costs is not additive for each regulatory option because some plants may incur 

costs for multiple wastestreams. 

Each technology cost module includes a set of input tables. These input tables include 

indicators specifying the level of costs required for each technology option and the plant-specific 

data used in the cost equations. The following subsections describe each of the input tables used 

in the technology cost modules. See the appendix of EPA’s Incremental Costs and Pollutant 

Removals for Proposed Effluent Limitation Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category report for the specific input tables described below 

[U.S. EPA, 2013]. 
Section 9 - Engineering Costs

9-11 

FGD Wastewater Flow 

For each applicable plant, EPA identified a plant-level FGD wastewater flow rate in 

gallons per day. EPA used the purge rate reported in the Steam Electric Survey as the input value 

for the FGD technology cost modules. For plants operating more than one FGD system, the input 

value was the sum of the purge rates for the individual systems. For current FGD systems that 

did not provide an FGD purge flow value, EPA estimated the purge rate based on the amount of 

coal burned and the median FGD purge rate per ton of coal burned based on coal type. See 

Section 4.1.1 of EPA’s Incremental Costs and Pollutant Removals for Proposed Effluent 

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

Category report for more details on the FGD wastewater flow rate estimation methodology [U.S. 

EPA, 2013].

FGD Treatment-In-Place Data 

This 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 systems, 

EPA did not estimate compliance costs for the specific pieces of equipment that are already 

operating at the plant. For example, under Option 1, if a plant operates a one-stage chemical 

precipitation system for the treatment of FGD wastewater that includes all the steps included as 

the basis for the technology option other than sulfide precipitation, then EPA would include 

capital costs for the plant to install a reaction tank and sulfide chemical feed system and 

operating and maintenance costs for the amount of sulfide added to the system on a yearly basis. 

The compliance costs for all other pieces of equipment for the system would be set to zero. 

Fly Ash Production Data

For each applicable generating unit, EPA identified generating unit-level wet fly ash 

production in tons per day and operating days per year. EPA used these values reported in the 

Steam Electric Survey as input values for the fly ash technology cost module. Because the cost 

model estimates fly ash compliance cost at the generating unit level, EPA used unit-level input 

values.

EPA also identified generating units with existing dry fly ash handling equipment. Steam 

electric generating units equipped with only wet fly ash handling systems would incur the costs 

for complete conversion of the ash handling system. Those generating units equipped with both 

wet and dry fly ash handling capabilities may need only certain additional equipment in order for 

them to handle all fly ash dry (i.e., additional vacuum capacity, additional silo capacity, 

additional unloading equipment). EPA evaluated each plant and unit to identify the additional 

equipment that would be needed and included costs for only those pieces of equipment. 

Bottom Ash Production Data 

For each applicable generating unit, EPA identified generating unit-level wet bottom ash 

production in tons per day, operating days per year, and capacity in megawatt (MW). EPA used 

these values reported in the Steam Electric Survey as input values for the bottom ash technology 
Section 9 - Engineering Costs

9-12 

cost module. Because the cost model estimates bottom ash compliance cost at the generating unit 

level, EPA used unit-level input values. 

Impoundment Data

EPA used data from the Steam Electric Survey and plant contacts to identify which plants 

operate one or more impoundments containing combustion residuals including FGD solids, fly 

ash, and/or bottom ash. 

On-Site Landfill Data

EPA used data from the Steam Electric Survey to identify which plants operate on-site 

active/inactive landfills containing combustion residuals including FGD solids, fly ash, and/or 

bottom ash. 

Landfill and Leachate Data 

For each landfill identified as generating landfill leachate, EPA identified the landfill 

leachate volume discharged each year in gallons per day. For those plants that did not report a 

leachate volume in the Steam Electric Survey, EPA estimated a flow using data from other plants 

that reported a leachate volume in the survey. EPA first determined a median leachate discharge 

rate per acre of landfill containing combustion residuals, based on the plant responses to the 

Steam Electric Survey, and multiplied this value by a plant’s reported combustion residual 

landfill acreage collecting leachate to estimate a flow. For those plants that didn’t report a 

leachate volume or a landfill acreage collecting leachate, EPA estimated the landfill acreage 

collecting leachate based on the plant’s reported total active/inactive landfill acreage and the 

median ratio of landfill acreage collecting leachate to total active/inactive landfill acreage for 

those plants that provided both values. Finally, for those plants EPA could not estimate a value 

using the other two approaches, EPA estimated the leachate volume using the median leachate 

volume for all plants reporting a volume. 

See Section 4.1.3 of EPA’s Incremental Costs and Pollutant Removals for Proposed 

Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category report for more details on the landfill leachate flow rate estimation 

methodology [U.S. EPA, 2013].

9.4.2 Industry Assumptions/Factors

The steam electric cost model includes several data tables containing values for industry 

assumptions and factors. These assumptions and factors are used in the cost equations for the 

specific technology options for all plants incurring costs for the specific technology option. 

Each technology cost module contains a set of tables including the specific factors for 

that technology option. These factors include the coefficients for the technology option equations 

and other input constants applicable to all plants incurring the specific technology option costs. 

For example, for the fly ash cost methodology, EPA used a dry fly ash density of 45 lbs./ft3, 

which is used to estimate the size of the silo(s) required to store the ash. EPA used this density 

for all generating units for which the fly ash compliance costs are applicable. For more 
Section 9 - Engineering Costs

9-13 

information on the specific technology cost module factors, see EPA’s Incremental Costs and 

Pollutant Removals for Proposed Effluent Limitation Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category report. [U.S. EPA, 2013] 

Although each technology cost module contains its own set of factor tables, there are two 

sets of industry factors referenced by all technology option modules. These coefficients and 

constants do not change based on the different elements of the technology cost modules. These 

industry factors include: 

• Cost Indices. Because EPA presents all compliance costs in 2010 dollars, EPA had to 

index several cost components. EPA adjusted all costs to 2010 dollars using the RS 

Means Historical Cost Index values for all technology cost modules [RSMeans, 2011] 

• Freight Cost Factors. For all technology options, EPA estimates several freight costs 

for shipping equipment or materials to the plant. The factors used to estimate these 

shipping costs are universal for all technology options. These values were estimated 

using data from FreightCenter.com and vendor contacts. [U.S. EPA, 2013]. 

9.4.3 Technology Cost Modules 

To estimate the plant-level technology option compliance costs, EPA developed nine 

different technology cost modules that use the various input data, industry assumptions and 

factors, and costing methodologies to generate plant-specific compliance cost outputs. Each 

technology cost module calculates specific cost components for each plant incurring compliance 

costs. The technology cost modules and a brief description of the cost components calculated are 

included in the following listing. See Sections 9.4 and 9.5 for more specific information on the 

technology cost modules. 

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

anoxic/anaerobic biological treatment system;

• 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;
Section 9 - Engineering Costs

9-14 

• 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. 

EPA calculates each technology option cost by summing the costs estimated by the 

applicable individual technology cost module (e.g., biological treatment or bottom ash handling) 

and the technology cost modules that calculate transportation, disposal, and impoundment costs. 

For each technology option, the cost model sums the costs associated with the technology cost 

modules that compose each option, as shown in Table 9-1. The cost model combines the cost 

components and calculates total capital, total O&M, one-time and recurring costs for each 

technology option. 

As explained in Section 8.1.2, EPA is also considering BMPs as part of all of the 

regulatory options evaluated for the proposed ELGs. In order to better inform this consideration, 

EPA also calculated costs associated with BMPs. EPA only calculated BMP costs for 

impoundments that are expected to continue receiving combustion residual wastewater after the 

implementation of the ELGs. Therefore, the determination of which impoundments will incur 

BMP costs must be based on the entire regulatory option (e.g., Option 3), and not just at the 

technology option (e.g., fly ash transport water) because EPA can only determine if an 

impoundment will stay open or stop receiving combustion residual waste when assessing all the 

wastes. For example, if an impoundment receives FGD wastewater and fly ash transport water, 

the impoundment would stay open (i.e., continue to operate) under Option 1 because fly ash 

transport water would still be sent to the impoundment, but the impoundment would stop 

receiving combustion residual wastewater under Option 3. As shown in this example, the 

impoundment BMP costs cannot be determined only based on the technology options, but must 

be determined based on the regulatory option. Therefore, EPA did not include the impoundment 

BMP cost module in Table 9-1. See Section 9.5.5 for additional information on EPA’s approach 

for estimating costs associated with BMPs.

9.4.4 Model Outputs

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

costs. The output reflects each plant incurring a cost for an evaluated wastestream. EPA presents 

the incremental costs on two levels: at the cost-component level and at the total plant level. The 

total plant costs include total capital, total O&M, total three-year recurring costs, total five-year 

recurring costs, total 6-year recurring costs, total 10-year recurring costs, and total one-time costs 

incurred by the plant. The cost-component level shows a breakdown of the individual cost 

components for each of the technology costs. The cost-component level includes individual 

capital costs (e.g. equipment, installation, land, and engineering) and individual O&M costs (e.g. 

labor, materials, energy, effluent monitoring, and chemicals). See Sections 9.6.4, 9.7.3, and 9.8

for the cost model outputs for each technology. 

9.5 COSTS APPLICABLE TO ALL WASTESTREAMS

EPA developed several methodologies to calculate compliance costs applicable to more 

than one technology option. Using this approach, EPA could use the same methodology for each 
Section 9 - Engineering Costs

9-15 

Compliance Monitoring Costs = Sampling Labor Costs + Sampling Materials Costs 

+ Sample Shipping Costs + Sample Analysis Costs 

technology option without duplicating the calculations in the cost model. For example, the cost 

methodology for disposing combustion residual solid waste to a landfill is the same for each type 

of waste; however, the input values and factors (i.e., type, amount, and density of waste) vary 

depending on the technology option (FGD, fly ash, or bottom ash). The following subsections 

present the methodology used to estimate costs for compliance monitoring, transportation, 

disposal, impoundment operations, and impoundment BMPs. 

9.5.1 Compliance Monitoring Costs 

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 the proposed 

effluent limitations. Compliance monitoring costs are annual O&M costs calculated by summing 

the components shown in the equation below. 

Sampling labor costs are the costs associated with plant personnel collecting and 

analyzing wastewater samples. EPA calculated sample labor costs using a labor rate and the total 

number of labor hours required per year. EPA assumed samples would be collected and analyzed 

weekly for NPDES compliance monitoring. EPA used data from the Steam Electric Survey and 

the U.S. Bureau of Labor Statistics to estimate the labor rate for the sampling team and 

environmental engineer required to collect and analyze the samples.

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 to collect and analyze samples. EPA calculated material and supply costs using the cost 

of the materials and supplies per sampling events and the number of sampling events per year. 

EPA based the sampling material costs on the costs the Agency incurred for individual items 

during its field sampling program. EPA multiplied the item costs by the number of items that 

would be required over the course of a year and then summed the costs for all the individual 

items.

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. EPA assumed 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 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. See 

Section 5.2 of EPA’s Incremental Costs and Pollutant Removals for Proposed Effluent 

Limitation Guidelines and Standards for the Steam Electric Power Generating Point Source 
Section 9 - Engineering Costs

9-16 

Category report for more details on the compliance monitoring cost methodology [U.S. EPA, 

2013]. 

9.5.2 Transportation Costs 

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.

All combustion residuals 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 for these plants 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 have only on-site landfills that do not contain combustion residuals), EPA 

included costs for these plants to dispose of the additional combustion residuals in an off-site 

non-hazardous landfill. 

As described in Section 9.4.1, EPA used data from the Steam Electric Survey to identify 

which plants have existing landfills containing combustion residuals. EPA estimated costs for 

on-site transportation of ash and FGD solids for all plants with at least one open landfill 

containing combustion residuals. EPA estimated off-site trasnportation costs for ash and FGD 

solids for all other plants (i.e., those without an open landfill containing fuel combustion 

residuals).

EPA based plant-level costs for transportation of combustion residuals on the total 

amount of waste generated at each plant. For each wastestream, EPA calculated the amount of 

solid waste generated using methodologies presented, by technology option, in Sections 9.6, 9.7, 

and 9.8. 

EPA estimated transportation costs for plants with an on-site landfill using the estimated 

amount of solid waste and an on-site specific unitized cost value, in dollar per ton, based on 

information provided by ORCR for the coal combustion residuals (CCR) rule, developed using 

the Remedial Action Cost Engineering Requirements (RACER 2010) software version 10.4. 

EPA estimated transportation costs for plants with an off-site landfill using the estimated amount 

of solid waste and an off-site specific unitized cost value, in dollar per ton, provided by ORCR 

based on the RACER 2010 model. For each plant and wastestream, EPA summed the total 

tonnage of combustion residuals and multiplied it by the appropriate transportation cost to 

estimate a plant-specific transportation cost. See Section 5.3 of EPA’s Incremental Costs and 

Pollutant Removals for Proposed Effluent Limitation Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category report for more details on the on- and off-site 

transportation cost methodologies [U.S. EPA, 2013]. 
Section 9 - Engineering Costs

9-17 

9.5.3 Disposal Costs 

EPA conservatively determined costs for plants to dispose of all combustion residual 

landfills to on-site or off-site landfills. To the extent plants are able to market/sell these residuals, 

EPA has over costed disposal and has not accounted for revenue associated with other options. 

As previously discussed in Section 9.5.2, EPA used data from the Steam Electric Survey to 

identify which plants have existing landfills containing combustion residuals. EPA estimated 

costs for on-site disposal of ash and FGD solids for all plants with at least one open landfill 

containing combustion residuals. EPA compliance costs estimate the costs for the plant to 

expand the landfill to handle the additional combustion residuals that will need to be stored in the 

landfill to comply with the ELGs. EPA estimated off-site diposal costs for ash and FGD solids 

for all other plants (i.e., those without an open landfill containing combustion residuals). 

EPA based plant-level costs for disposal of combustion residuals on the total amount of 

waste generated at each plant. For each wastestream, EPA calculated the amount of solid waste 

generated using methodologies presented, by technology option, in Sections 9.6, 9.7, and 9.8. 

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 that 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. 

EPA estimated off-site disposal costs using a unitized cost (in dollar per ton) and the 

estimated amount of additional solid waste transported off-site. The unitized cost value 

represents the fee off-site landfills generally charge prior to accepting waste, known as the 

tipping fee. EPA estimated the tipping fees using state-level tipping fees and data provided in the 

Steam Electric Survey. See Section 5.4 of EPA’s Incremental Costs and Pollutant Removals for 

Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category report for more details on the on- and off-site disposal cost 

methodologies [U.S. EPA, 2013]. 

9.5.4 Impoundment Operation Costs

Implementation of the technology options will reduce, and in some cases eliminate, FGD 

wastewater, ash transport water, and combustion residuals managed in on-site impoundments. 

EPA therefore expects plants will experience cost savings in operating these impoundments. To 

calculate the incremental compliance cost of the technology option, EPA estimated the annual 

O&M and recurring costs associated with managing these wastewaters and combustion residuals 

in on-site impoundments. For each technology option evaluated, EPA estimated the amount of 

wastewater or combustion residual no longer expected to be managed in on-site impoundments 

and the associated cost savings. EPA estimated O&M and 10-year recurring costs associated 

with impoundment operations using the equations provided below. See Section 5.5 of EPA’s 

Incremental Costs and Pollutant Removals for Proposed Effluent Limitation Guidelines and 
Section 9 - Engineering Costs

9-18 

Total O&M Costs = (-1) × (Impoundment O&M Costs + Earthmoving O&M Costs) 

× (Capacity Factor)

Total 10-Year Recurring Costs = (-1) × (Cost of Earth Moving Vehicle) 

Standards for the Steam Electric Power Generating Point Source Category report for more 

details on the impoundment operation cost methodology [U.S. EPA, 2013]. 

Impoundment O&M costs are the costs associated with the operation of the transportation 

system (i.e., pipelines, vacuum source), impoundment site, wastewater treatment system, and 

water recycle system at the impoundment. EPA calculated impoundment O&M costs using a 

unitized cost value ($7.35/ton), representing the impoundment O&M costs only, and the 

estimated amount of wet combustion residual waste generated (FGD solids, fly ash, and bottom 

ash).

Earthmoving O&M costs are the costs associated with the operation of earthmoving 

equipment (i.e., backhoe) required for sorting/stacking fuel combustion residual materials at the 

impoundment site. EPA calculated the impoundment O&M costs using a unitized cost value 

($2.49/ton), representing the O&M only associated with the operation of the earthmoving 

equipment, and the estimated amount of wet combustion residual waste generated. 

Additionally, EPA applied a capacity factor to adjust both unitized cost values for 

impoundment and earthmoving O&M costs based on the size of plant (in MW). EPA applied this 

factor to account for the economics of scale, the concept that larger plants, which will generally 

operate larger impoundments, incur smaller costs per ton of wet combustion residual [U.S. EPA, 

1985]. 

EPA calculated 10-year recurring costs associated with operating the earthmoving 

equipment (i.e., backhoe). EPA calculated the total 10-year recurring costs by determining the 

cost and average expected life of a backhoe. EPA determined that the expected life of a backhoe 

is 10 years and that each plant will operate one backhoe. 

9.5.5 Impoundment BMP Costs

Although implementation of the technology options will reduce, and in some cases 

eliminate, FGD wastewater, ash transport water, and combustion residuals managed in on-site 

impoundments, some impoundments may remain open. As explained in Section 8.1.2, EPA is 

considering BMPs as part of all of the regulatory options evaluated for the proposed ELGs. In 

order to better inform this consideration, EPA calculated costs associated with BMPs. EPA 

estimated BMP costs for the impoundments that are expected to continue operating after 

complying with the ELGs. See Section 5.6 of EPA’s Incremental Costs and Pollutant Removals 

for Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category report for more details on the impoundment BMP cost 

methodology [U.S. EPA, 2013]. The BMPs include remedial actions (e.g., slope repairs, drawing 

down water levels, controlling vegetation) and increases in inspection frequency from 17 times 
Section 9 - Engineering Costs

9-19 

annually to 52 times annually. These management practices will help prevent future 

impoundment failures that have the potential to devastate the surrounding communities. 

In order to estimate costs associated with these BMPs, which may be beyond the current 

state requirements, EPA reviewed the combustion residual impoundments at plants incurring 

compliance costs for FGD wastewater, fly ash transport wastewater, and/or bottom ash transport 

wastewater. For purposes of estimating BMP costs, EPA made some assumptions regarding the 

continued use of existing impoundments. Because these impoundments can contain multiple 

combustion residual waste, the probability that the impoundment will remain open depends on 

the regulatory option. For example, if an impoundment contains FGD waste and bottom ash, the 

impoundment would remain open based on the proposed Regulatory Option 3, which only 

affects FGD and fly ash transport wastewaters. EPA would expect 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 based on Regulatory Option 3; however, EPA estimated zero costs based 

on Regulatory Option 4. 

EPA estimated an annualized cost for each impoundment determined to remain open, 

based on 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. 

9.6 FGD WASTEWATER

EPA estimated capital, 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. 

9.6.1 Chemical Precipitation

Section 7.1.2 describes the one-stage chemical precipitation system that forms the basis 

for this technology option. Additionally, Section 9.2.1 provides a brief summary of the 
Section 9 - Engineering Costs

9-20 

Total Capital Costs = Purchased Equipment Costs + Purchased Equipment 

Installation Costs + Building Costs + Land Costs + Site Preparation Costs + 

Engineering Costs + Construction Expenses + Other Contractor Fees + Contingency 

Fees + Sludge Disposal Costs 

technology basis for the chemical precipitation system. EPA estimated the costs to install and 

operate a one-stage chemical precipitation technology to treat FGD wastewater, specifically 

developed to remove mercury and arsenic (and other heavy metals). See Section 6.1 of the 

Incremental Costs and Pollutant Removals for Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category for more details on 

the FGD chemical precipitation cost methodology [U.S. EPA, 2013].Based on site visits,

untreated FGD wastewater can contain elevated mercury concentrations based on a variety of 

different plant operating characteristics. To ensure that the mercury concentrations in the effluent 

discharged from the chemical precipitation system meet the proposed ELGs, EPA included costs 

for a mercury analyzer and extra equipment to analyze mercury in the discharge and recycle the 

chemical precipitation discharge for further treatment if necessary. The use of this equipment 

will allow plants to test the mercury in the effluent daily to ensure compliance with the ELGs. If 

the 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. See Section 7 of this document for additional details. 

As noted in Section 9.4.1, EPA evaluated plant responses to the Steam Electric Survey to 

determine whether chemical precipitation technologies are currently in place to treat FGD 

wastewater. As appropriate, plants operating these technologies were given credit for having 

treatment in place. EPA gave plants credit only for the associated cost components that are 

already in place at the plant. For example, for Regulatory Option 1, if a plant operates a onestage chemical precipitation system for the treatment of FGD wastewater that includes all the 

steps included as the basis for the technology option other than sulfide precipitation, then EPA 

would include capital costs for the plant to install a reaction tank and sulfide chemical feed 

system and operating and maintenance costs for the amount of sulfide added to the system on a 

yearly basis. The compliance costs for all other pieces of equipment for the system would be set 

to zero. 

EPA estimated capital, O&M, and 6-year recurring costs for a chemical precipitation 

system using the equations provided below. 

Purchased equipment costs are the costs associated with purchasing the pieces of 

equipment required to construct a chemical precipitation system, in addition to ancillary 

equipment and freight costs. EPA included the following pieces of equipment in the calculation 

of the chemical precipitation system purchased equipment costs:

• Pumps; 

• Tanks (e.g., equalization tanks, reaction tanks, holding tanks); 

• Chemical feed systems;

• Mixers;
Section 9 - Engineering Costs

9-21 

Total O&M Costs = Operating Labor Costs + Maintenance Labor Costs + 

Maintenance Materials Costs + Chemical Purchase Costs + Energy Costs + Sludge 

Transportation Costs + Sludge Disposal Costs + Compliance Monitoring Costs + 

Impoundment Operation Costs 

• Clarifiers;

• Filter presses; and

• Sand filters.

For each piece of equipment, EPA obtained cost information from vendors for various 

sizes of the equipment (e.g., flow, volume). EPA then related all of these to an associated flow 

rate using information based on the technology design basis (e.g., tank volume related to flow by 

design residence time). EPA then used the cost and flow information to generate an equation that 

could estimate the costs for any FGD wastewater flow rate.

Purchased equipment installation costs are the cost associated with installing those pieces 

of purchased equipment, including piping, instrumentation, calibration, and structural supports. 

Building, land, site preparation, engineering, construction, other contractor fee costs are the costs 

associated with preparing a specific site for the installation of the chemical precipitation 

equipment and the costs required for supervision and inspection of the installation. For each of 

these costs components, EPA estimated the capital costs by developing cost factors from data in 

the Steam Electric Survey. To develop these cost factors, EPA created ratios of the specific cost 

component to the total reported purchased equipment cost for each plant that reported cost data 

for an FGD chemical precipitation system. EPA then used the median or average ratio based on 

the plants in the analysis as the cost factor for calculating the costs. Therefore, once EPA 

calculated the total purchased equipment costs, EPA then multiplied the costs by each of the cost 

factors to estimate the costs for each of these components.

To calculate the sludge disposal costs, associated with on-site landfill disposal described 

in Section 9.5.3, EPA needed to estimate the quantity of sludge that would be generated 

annually. EPA used data from the Steam Electric Survey to compare the quantity of FGD 

wastewater treatment sludge generated to the FGD wastewater treatment system flow rate. EPA 

calculated a ratio of these values for each plant and used the median as a flow-normalized 

dewatered sludge generation rate in tons per gallon. Then based on the plant-specific FGD 

wastewater flow rate, EPA estimated the quantity of sludge generated by the system. 

Operating labor, maintenance labor, and maintenance material costs are the costs 

associated with the manual labor and materials required to operate and maintain the chemical 

precipitation system 24 hours per day, 365 days per year. To estimate these labor costs, EPA 

used data from the Steam Electric Survey to compare the labor costs to the flow rate of the 

system. From the costs reported in response to the survey and the associated FGD wastewater 

treatment flow rate, EPA developed equations to estimate the cost based on the flow rate. EPA 

then used these equations and each plant’s FGD wastewater flow rate to determine the operating 

labor and maintenance labor costs. EPA performed a similar analysis to estimate the maintenance 
Section 9 - Engineering Costs

9-22 

Total Recurring 6-Year Costs = Cost of Mercury Analyzer

material costs by using data from the Steam Electric Survey to develop an equation relating FGD 

wastewater treatment flow to the total yearly maintenance material costs.

Chemical purchase costs are the costs associated with purchasing the chemicals required 

to operate the chemical precipitation system. EPA estimated chemical purchase costs using a 

chemical dosage rate (expressed in grams of chemical per liter of wastewater flow), the plant 

FGD wastewater flow rate, and chemical costs (expressed in dollars per ton). EPA determined 

the appropriate dosage rates based on the average chemical dosage rates used by the best 

available technology economically achievable (BAT) plants included in EPA’s sampling 

program. EPA obtained chemical costs directly from chemical suppliers in dollars per ton. 

Energy costs are the costs associated with the power requirement to run the chemical 

precipitation system. EPA obtained the power requirements for each piece of equipment used in 

the system from equipment vendors and used these power requirements to develop energy cost 

equations and estimate total energy consumption (in kWh/yr). EPA used the national 2010 

energy cost of 4.05 cents per kilowatt hour to calculate the energy cost [U.S. DOE, 2011]. 

EPA estimated the O&M costs associated with compliance monitoring, transportation, 

disposal, and impoundment operations according to the methodologies described in Section 9.5. 

EPA used the same estimated tonnage described for the capital cost equation above to estimate 

sludge transportation, disposal, and impoundment operation costs. 

EPA calculated 6-year recurring costs associated with operating a mercury analyzer, 

which is included in the system to allow plants to monitor the effluent quality on a daily basis to 

ensure the treatment system is effectively treating mercury to the proposed limitations. EPA 

estimated the total 6-year recurring costs by determining the cost and average expected life of a 

mercury analyzer, based on vendor information. EPA assumed that the expected life of a 

mercury analyzer is six years and that each plant will operate one analyzer for FGD wastewater.

9.6.2 Biological Treatment 

Section 7.1.3 describes the anoxic/anaerobic biological treatment system that forms the 

basis for this technology option. For Regulatory Options 3 and 4, EPA estimated compliance 

costs to install and operate the anoxic/anaerobic system to treat FGD wastewater following the 

BAT chemical precipitation system. The anoxic/anaerobic system is specifically designed and 

operated to target removals of selenium (and other heavy metals). See Section 6.2 of the 

Incremental Costs and Pollutant Removals for Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category for more details on 

the FGD biological treatment cost methodology [U.S. EPA, 2013]. 

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.
Section 9 - Engineering Costs

9-23 

Total Capital Costs = Purchased Equipment Costs + Purchased Equipment Installation 

Costs + Plant Overhead Engineering Costs + Sludge Disposal Costs 

EPA developed untreated FGD wastewater characteristics to use as the basis for cost 

development for the biological treatment system.80 EPA developed these FGD wastewater 

characteristics from industry site visits, its sampling program, and the Clean Water Act (CWA) 

308 monitoring program. A treatment vendor developed the specific anoxic/anaerobic biological 

treatment system design and system-level costs based on its evaluation of these untreated FGD 

wastewater characteristics. The anoxic/anaerobic biological system design consists of a series of 

two bioreactors operating in parallel trains. The number of trains and the size of the bioreactors 

are dependent on a plant’s FGD wastewater flow rate. For flow rates greater than 40 gallons per 

minute (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, prefabricated 

modular reactor, which is more cost-effective for this flow range.

Based on site visits, EPA’s sampling program, and the CWA 308 monitoring program, 

FGD wastewater temperatures can exceed the maximum operating temperature for the biological

system, especially during the warmer seasons, and may require cooling prior to entering 

biological treatment. Therefore, the design basis includes a heat exchanger for certain southern 

plants determined to require cooling of FGD wastewater for biological treatment, based on set 

latitudinal and longitudinal coordinates where the average July temperature is 90°F or greater. 

As noted in Section 9.4.1, EPA evaluated plant responses to the Steam Electric Survey to 

determine whether a biological treatment system for selenium removal is currently in place to 

treat FGD wastewater. As appropriate, plants operating this technology were given credit for 

having treatment in place, to ensure that incremental costs associated with compliance with the 

technology options are accurately assessed. EPA gave plants credit only for the associated cost 

components that are already in place at the plant.

EPA estimated capital and O&M costs for the anoxic/anaerobic system using the 

equations provided below. 

Purchased equipment costs are the costs associated with purchasing the pieces of 

equipment required to construct the anoxic/anaerobic biological system. EPA calculated 

purchased equipment costs by summing the costs of the anoxic/anaerobic biological system, the 

heat exchanger (for applicable plants), and a backwash recycle pump. The vendor provided EPA 

with cost equations based on FGD wastewater flow rate and backwash flow rate for the 

anoxic/anaerobic system and backwash recycle pump, respectively. The costs provided by the 

vendor include the following cost components: 

 

80 The untreated FGD wastewater characteristics developed for this analysis are similar to the characteristics 

identified in Section 6.1; however, they are slightly different because EPA had less data at the time this analysis was 

completed. The wastewater characteristics are included in Incremental Costs and Pollutant Removals for Proposed

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

[U.S. EPA, 2012].
Section 9 - Engineering Costs

9-24 

• Two-stage bioreactor system (i.e., 2 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. 

EPA used information obtained from vendors to develop cost equations for the heat 

exchanger, as well as the cooling water pumped needed for the system. Based on the chlorides 

level in the FGD wastewater and vendor recommendations, EPA developed heat exchanger costs 

for a carbon steel frame heat exchanger consisting of titanium plates. EPA estimated the size, 

and cost, of the cooling water pumps based on the flow for the FGD wastewater treatment 

system, accounting for the estimated heat transfer required to reduce the temperature of the 

wastewater to 95°F prior to entering the bioreactors.

Installation equipment costs are the costs associated with installing the purchased 

equipment, including any additional piping or instrumentation for the system. EPA estimated 

installation capital costs for the biological treatment system for each plant using two different 

installation cost factors. The first factor was provided by the vendor and is specific to installation 

of the anoxic/anaerobic biological system. The second factor was determined based on responses 

to the Steam Electric Survey and applies to installation of the heat exchanger and system pumps. 

This second factor is the same installation equipment cost factor used for the FGD chemical 

precipitation system.

Overhead engineering costs are costs associated with general process design and general 

engineering fees for the plant. EPA calculated the ratio of the overhead engineering costs to the 

total reported purchased equipment cost for each plant that reported cost data for an FGD 

chemical precipitation and/or biological treatment system. EPA then used the median ratio based 

on the plants in the analysis as the cost factor for calculating the costs. 
Section 9 - Engineering Costs

9-25 

Total O&M Costs = Operating Labor Costs + Maintenance Labor Costs + 

Maintenance Materials Costs + Chemical Purchase Costs + Energy Costs + Compliance 

Monitoring Costs + Sludge Transportation Costs + Sludge Disposal Costs + 

Impoundment Operation Costs

The sludge generated by the biological treatment system is associated with the backwash 

from the system. The backwash water is recycled to the equalization tank prior to the FGD 

wastewater chemical precipitation system and is ultimately removed with the chemical 

precipitation sludge. The vendor provided an equation to calculate the estimated annual amount 

of dry solids generated during the backwash based on plant-specific FGD wastewater flow. EPA 

used the sludge generation rate to estimate the disposal costs, described in Section 9.5.3. 

Operating labor, maintenance labor, and maintenance material costs are the costs 

associated with the manual labor and materials required to operate and maintain the 

anoxic/anaerobic system 24 hours per day, 365 days per year. EPA estimated these labor costs 

using vendor data and industry responses to the Steam Electric Survey to estimate the number of 

full time equivalent (FTE) workers required to operate the system. EPA used this estimation and 

the median operating and maintenance labor rates from the Steam Electric Survey to calculate 

the labor costs. To calculate the maintenance material costs, EPA used Steam Electric Survey to 

compare the reported maintenance material costs to the sum of the energy, chemical, and 

operating and maintenance labor O&M costs plants operate FGD chemical precipitation and/or 

biological treatment systems. EPA used then used the calculated value and multiplied it by the 

sum of the energy, chemical, and operating and maintenance labor O&M costs to estimate the 

maintenance material costs for each plant. 

Chemical purchase costs are the costs associated with purchasing the chemicals required 

to operate the anoxic/anaerobic biological system. EPA estimated the chemical purchase costs 

using nutrient dosages provided by the vendor, based on an assumed nitrate/nitrite (as nitrogen) 

concentration in the FGD wastewater, a nutrient cost provided by the vendor, and the plantspecific FGD wastewater flow rate.

Energy costs are the costs associated with the power requirement to run the 

anoxic/anaerobic biological system. The vendor provided an equation to calculate power 

requirements per gallon of FGD wastewater. EPA calculated the annual anoxic/anaerobic 

biological system energy consumption (in kWh/yr) by multiplying the anoxic/anaerobic 

biological system energy requirement by the plant-specific FGD wastewater flow and backwash 

flow. For the pumps, EPA developed energy cost equations based on the power requirements 

provided by equipment vendors (in kWh/yr). EPA used the national 2010 energy cost of 4.05 

cents per kilowatt hour to calculate the energy cost [U.S. DOE, 2011]. 

EPA estimated the O&M costs associated with compliance monitoring, transportation, 

disposal, and impoundment operations according to the methodologies described in Section 9.5. 

EPA used the same estimated tonnage described for the capital cost equation above to estimate 

sludge transportation, disposal, and impoundment operation costs. 
Section 9 - Engineering Costs

9-26 

Total Capital Costs = Purchased Equipment Costs + Purchased Equipment 

Installation Costs + Sludge Disposal Costs

9.6.3 Vapor-Compression Evaporation 

Section 7.1.3 describes the vapor-compression evaporation system that forms the basis 

for this technology option. The purpose of the vapor-compression evaporation system is to 

evaporate and condense the water from the FGD wastewater to produce a clean distillate stream 

and a concentrated brine solution. The concentrated brine solution is then further treated to 

generate a solid by-product. See Section 6.3 of the Incremental Costs and Pollutant Removals for 

Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category for more details on the FGD vapor-compression evaporation 

cost methodology [U.S. EPA, 2013]. 

As noted in Section 9.4.1, EPA evaluated plant responses to the Steam Electric Survey to 

determine whether a vapor-compression evaporation system is currently in place to treat FGD 

wastewater. As appropriate, plants operating this technology were given credit for having 

“treatment in place” to ensure that incremental costs associated with compliance with the 

technology options are accurately assessed. EPA gave plants credit only for the associated cost 

components that are already in place at the plant.

EPA estimated capital and O&M for a vapor-compression evaporation system using the 

equations provided below. 

Purchased and installation equipment costs are the costs associated with purchasing and 

installing the pieces of equipment, including extra piping, instrumentation, and support 

structures, required to construct a vapor-compression evaporation system. EPA estimated 

purchased and installation costs using data from vendors. The vendors provided total system 

costs for two different FGD wastewater treatment system flow rates. The system costs include 

the following pieces of equipment: 

• Water softener;

• Mechanical vapor compression brine concentrator; and 

• Forced-circulation crystallizer.

Using the information provided by the vendors, EPA developed costs equations to 

estimate the plant-specific compliance costs to install the system. For the brine concentrator and 

crystallizer, EPA developed the equation to relate the costs to the FGD wastewater treatment 

system flow rate. The cost for the softener is based on a percentage of the brine concentrator and 

the crystallizer costs. EPA estimated installation costs using a factor provided by the vendors and 

the calculated total purchased equipment costs.

Sludges generated by the vapor-compression evaporation system include softening sludge 

and crystallizer sludge. Vendors provided an equation to calculate the estimated sludge based on 

the plant-specific FGD wastewater flow. EPA used the sludge generation rate to estimate the 

disposal costs, described in Section 9.5.3. 
Section 9 - Engineering Costs

9-27 

Total O&M Costs = Operating Labor Costs + Maintenance Labor Costs + 

Maintenance Materials Costs + Chemical Purchase Costs + Energy Costs + 

Compliance Monitoring Costs + Sludge Transportation Costs + Sludge Disposal Costs 

+ Impoundment Operation Costs 

Operating labor, maintenance labor, and maintenance material costs are the costs 

associated with the manual labor and materials required to operate and maintain a vaporcompression evaporation system 24 hours per day, 365 days per year. To calculate labor rates, 

EPA used industry responses to Steam Electric Survey for chemical precipitation systems with 

and without subsequent vapor-compression evaporation treatment. EPA determined one 

operator, 24 hours per day, is required to operate the system based on observations during a site 

visit to a plant operating a vapor-compression evaporation system to treat FGD wastewater. The 

median operating labor rate was multiplied by the expected labor hours to determine the 

operating labor costs. 

Vapor-compression evaporation system vendor information was insufficient for use in 

estimating maintenance labor and maintenance material costs; therefore, EPA used the chemical 

precipitation factors, described in Section 9.6.1, to calculate these cost elements.

Chemical purchase costs are the costs associated with purchasing the chemicals required 

to operate the vapor-compression evaporation system. The softening portion of the system 

requires soda ash to soften the wastewater. The vendor provided the cost to purchase soda ash for 

one flow rate [HPD, 2009]. EPA used this cost and associated flow rate to generate a dollar per 

gallon per minute value to estimate costs based on the plant-specific FGD wastewater flow rate.

Energy costs are the costs associated with the power requirement to run the vaporcompression evaporation system. EPA obtained the power requirements for each piece of 

equipment used in the system from equipment vendors and used these power requirements to 

develop energy cost equations and estimate total energy consumption (in kWh/yr). EPA used the 

national 2010 energy cost of 4.05 cents per kilowatt hour to calculate the energy cost [U.S. DOE, 

2011]. 

EPA estimated the O&M costs associated with compliance monitoring, transportation, 

disposal, and impoundment operations according to the methodologies described in Section 9.5. 

EPA used the same estimated tonnage described for the capital cost equation above to estimate 

sludge transportation, disposal, and impoundment operation costs. 

9.6.4 Estimated Industry-Level Costs for FGD Wastewater by Treatment Option

Table 9-3 presents the estimated capital and O&M costs on an industry level for each 

FGD wastewater treatment technology discussed in the sections above, including transport, 

disposal, and impoundment costs. The table also includes the number of plants incurring costs 

for each treatment technology. The costs presented in the table represent the compliance costs for 

those generating units expected to be subject to the proposed ELGs; therefore, oil-fired units and 

units with a capacity of 50 MW or less are not included because they do not need to install the 

technology basis to meet the new BAT limitations (which are based on the current BPT 
Section 9 - Engineering Costs

9-28 

requirements for these units). See EPA’s Incremental Costs and Pollutant Removals for 

Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category report for the costs for all generating units [U.S. EPA, 2013]. 

Table 9-3. Estimated Industry-Level Costs for FGD Wastewater Based on Oil-Fired Units 

and Units 50 MW or Less Not Installing Technology Basis 

Technology Option

Number 

of Plants

Total Capital 

Cost 

($)

Total O&M 

Cost 

($/year)

6-Year 

Recurring 

Cost

($/6-year)

10-Year 

Recurring Cost 

($/10-year)a 

Chemical Precipitation 116 $1,450,000,000 $194,000,000 $9,900,000 ($33,000,000)

Chemical Precipitation 

followed by Biological 

Treatment

116 $2,500,000,000 $257,000,000 $9,900,000 ($33,000,000)

Chemical Precipitation 

followed by VaporCompression Evaporation116 $6,240,000,000 $1,030,000,000 $9,900,000 ($33,000,000)

a – The values in this column are negative because they represent cost savings.

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2011]. 

EPA also estimated the industry-level costs for only those plants with a total plant-level 

wet scrubbed capacity of 2,000 MW or greater to install the chemical precipitation followed by 

biological treatment technology. To estimate these industry-level costs, EPA zeroed the costs 

from its FGD biological treatment cost outputs and for those plants with a total plant-level wet 

scrubbed capacity of less than 2,000 MW. For all plants with a total plant-level wet scrubbed 

capacity of 2,000 MW or greater, EPA used the costs from its FGD biological treatment cost 

outputs. For more details on how EPA estimated these plant-level FGD biological treatment 

costs, see the memorandum entitled “Memorandum to the Rulemaking Record: Methodologies 

for Estimating Costs and Pollutant Removals for Steam Electric ELG Regulatory Options 3a and 

3b” [ERG, 2013c]. 

Table 9-4 presents the estimated capital, O&M, and recurring costs on an industry-level 

associated with dry or closed-loop recycle bottom ash handling conversions for this analysis. The 

table also includes the number of plants incurring compliance costs. The costs presented in the 

table represent the compliance costs for those generating units expected to be subject to the 

proposed ELGs for Regulatory Option 4a; therefore, oil-fired units and units with a capacity of 

400 MW or less are not included because they do not need to install the technology basis to meet 

the new BAT limitations (which are based on the current BPT requirements for these units). 

Table 9-4 presents the estimated capital and O&M costs on an industry level for the FGD 

chemical precipitation followed by biological treatment wastewater treatment technology 

discussed in the sections above, including transport, disposal, and impoundment costs. The table 

also includes the number of plants incurring costs for each treatment technology. The costs 

presented in the table represent the compliance costs for those generating units expected to be 

subject to the proposed ELGs; therefore, oil-fired units and units at plants with a total plant-level 
Section 9 - Engineering Costs

9-29 

wet scrubbed capacity of less than 2,000 MW are not included because they do not need to install 

the technology basis to meet the new BAT limitations (which are based on the current BPT 

requirements for these units). 

Table 9-4. Estimated Industry-Level Costs for FGD Wastewater Based on Oil-Fired Units 

and Units at Plants with a Total Plant-Level Wet Scrubbed Capacity of Less Than 2,000 

MW Not Installing Technology Basis 

Technology Option

Number 

of Plants

Total Capital 

Cost 

($)

Total O&M 

Cost 

($/year)

6-Year

Recurring 

Cost

($/6-year)

10-Year 

Recurring Cost 

($/10-year)a 

Chemical Precipitation 

followed by Biological 

Treatment

17 $600,000,000 $67,600,000 $1,450,000 ($5,640,000)

a – The values in this column are negative because they represent cost savings.

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2011]. 

9.6.5 Compliance Costs Associated with Planned FGD Systems

In addition to existing sources, EPA also evaluated costs of compliance associated with 

planned installations of FGD systems. Implementation of air pollution controls may create new 

wastewater streams at power plants. The compliance costs and pollutant removal estimates 

included in this document reflect consideration of wastestreams generated by air pollution 

controls that will likely be in operation at plants at the time of ELG promulgation. However, 

EPA recognizes that some recently promulgated Clean Air Act requirements may lead to 

additional air pollution controls (and resulting wastestreams) at existing plants beyond the date 

of ELG promulgation. In an effort to confirm that the proposed ELGs would be economically 

achievable in such cases, EPA also conducted a sensitivity analysis that forecasts future 

installations of air controls through 2020 and the associated costs of complying with the 

proposed ELGs for the wastewater that may result from the forecasted air control installations.81

These sensitivity analyses are described in more detail in the memorandum entitled “Flue Gas 

Desulfurization Future Profile Sensitivity Analysis” [ERG, 2013a].

9.7 ASH TRANSPORT WATER

As discussed in Section 4.2.1, combusting coal and oil in steam electric boilers produces 

a residue of noncombustible fuel constituents, referred to as ash. The ash that is light enough to 

be carried out of the boiler is referred to as fly ash and the heavier ash that falls to the bottom of 

the boiler is referred to as bottom ash. 

Based on survey responses, plants usually collect and handle fly ash and bottom ash 

separately. Fly ash is either handled dry and pneumatically transferred dry to silos for temporary 

 

81 EPA expects that plants will be in compliance with new federal and state air pollution control requirements by 

2020.
Section 9 - Engineering Costs

9-30 

storage or sluiced with water to an impoundment. Bottom ash is either collected in a water-filled 

hopper positioned below the hopper and sluiced with water to an impoundment, collected under 

the boiler using a mechanical drag system and stored in an outdoor pile for temporary storage, or 

pneumatically transferred to silos for temporary storage. 

Because of the development of ash handling systems that require little to no water and the 

ability to market dry fly and/or bottom 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. The following sections describe the technology bases used to 

estimate the compliance costs associated with converting from wet to dry fly ash handling and 

wet to dry or closed-loop recycle bottom ash handling. 

9.7.1 Fly Ash Transport Water 

EPA estimated capital, O&M, and 10-year recurring costs associated with converting wet 

fly ash handling systems (specifically wet fly ash sluicing systems) to dry vacuum fly ash 

handling systems for steam electric generating units generating fly ash. Section 7.2.3 provides 

more details on the dry vacuum fly ash handling system. 

In addition to the dry vacuum system, EPA evaluated a different technology for 

generating units with significantly less fly ash production. These generating units are usually oilfired. Based on Steam Electric Survey data, EPA evaluated costs for oil-fired units operating less 

than 100 days per year to use a vactor truck to collect and handle the fly ash to comply with a 

zero discharge requirement. See Chapter 7 of the Incremental Costs and Pollutant Removals for 

Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category for more details on the fly ash cost methodology [U.S. EPA, 

2013].

EPA’s approach for estimating costs associated with converting to dry vacuum systems 

and for using vactor trucks is described in more detail below. 

Dry Vacuum Conversion 

Based on data from the Steam Electric Survey and site visits, EPA determined that a 

single steam electric generating unit can be equipped with both wet and dry handling 

capabilities. Therefore, not all steam electric generating units require complete conversion costs 

depending on the equipment, and the capacity of that equipment, already operating at the plant. 

As appropriate, plants with wet and dry handling systems were given credit for having this 

equipment at the plant. Therefore, to estimate compliance costs for a fly ash handling conversion 

to a dry vacuum 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 that 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.
Section 9 - Engineering Costs

9-31 

Total Capital Costs = Purchased Equipment Costs + Purchased Equipment Installation 

Costs + Plant Overhead Engineering Costs + Fly Ash Disposal Costs 

• Intermediate Storage. The destination to which the dry fly ash is conveyed from the 

bottom of the hopper. The intermediate storage includes 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 

prior to transportation and disposal.82 EPA calculated intermediate storage costs at the 

plant level.

• Transportation/Disposal. The trucking equipment and operation to move the dry fly 

ash to its final destination (e.g., on-site or off-site landfill). EPA calculated 

transport/disposal costs at the plant level.

For example, the vacuum lines for a generating unit may have the capacity to handle all 

of the dry fly ash generated, but the silo may not be large enough to store all of the dry fly ash. 

There EPA would only estimate compliance costs associated with the additional intermediate 

storage (silo capacity) required.

EPA estimated capital, O&M, and 10-year recurring costs for the conversion to dry fly 

ash handling using a dry vacuum system using the equations provided below. EPA calculated the 

capital, O&M, and 10-year recurring costs by summing the estimated costs for the conveyance, 

intermediate storage, and transport/disposal portions of the system. 

Purchased equipment costs are the costs associated with purchasing all equipment to 

retrofit all generating units, 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 

calculated 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, including all 

system elements, for each plant 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 by 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 

 

82 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 of the silo and one for the 

pugmill.
Section 9 - Engineering Costs

9-32 

Total O&M Costs = Operating Labor Costs + Maintenance Labor Costs + Maintenance 

Materials Costs + Energy Costs + Fly Ash Transport Costs + Fly Ash Disposal Costs + 

Impoundment Operation Costs 

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 handling 

conversion using wet fly ash generation rate at the plant-level and an average moisture content of 

fly ash from the Steam Electric Survey, supplemented with vendor data. EPA used the moistureconditioned fly ash tonnage to estimate the disposal costs, described in Section 9.5. 

Operating and maintenance labor costs are the costs associated with operating and 

maintaining the conveyance, intermediate storage, and transport/disposal portions of the dry 

vacuum system. EPA calculated operating labor costs using the labor rate, the estimated number 

of required operator hours per day, and the total number of days the generating units operated. 

EPA calculated the maintenance labor costs using the labor rate and the estimated maintenance 

hours per year. EPA used the Steam Electric Survey data, supplemented with U.S. Bureau of 

Labor Statistics data, to calculate the labor rate for fly ash conversion costs [U.S. Bureau of 

Labor Statistics, 2010]. EPA estimated the number of required operator hours per day and 

maintenance hours per year using data provided in the Steam Electric Survey. Additionally, EPA 

used the number of unit operating days in 2009 reported the Steam Electric Survey. 

In addition to the intermediate storage system operating labor costs, EPA also estimated 

O&M costs for operating dust suppression water trucks around the fly ash unloading area, 

including operating labor and fuel costs, if appropriate.83 EPA estimated the water truck 

operating labor cost using a water truck labor rate, number of required operator hours per day, 

the number of operating days per year, and the number of silos. To determine the water truck 

labor rate, EPA selected the national average loaded labor rate for industrial truck/tractor 

operators as reported by the U.S. Bureau of Labor Statistics [U.S. Bureau of Labor Statistics, 

2010]. EPA estimated the number of required operator hours per day and the number of 

operating days using data from the Steam Electric Survey. EPA calculated the number of silos as 

part of the compliance cost methodology. EPA estimated the fuel costs associated with the water 

trucks by multiplying the number of hours each water truck operates by the number of water 

trucks, the distance the water truck travels every hour, and the gas mileage and fuel cost. The 

number of water trucks required at a plant was determined using data from the Regulatory 

Impact Analysis For EPA’s Proposed RCRA Regulation Of Coal Combustion Residues (CCR) 

Generated by the Electric Utility Industry [ORCR, 2010], based on the dry fly ash tonnage 

produced at the plant after the handling conversion. The fuel consumption of the water truck was 

 

83 For plants that already have some portion of dry fly ash handling, EPA only included additional costs for water 

trucks if the additional tonnage that would now be handled dry would require the plant to purchase and operate 

additional water trucks. See Section 7.1.9 of the Incremental Costs and Pollutant Removals for Proposed Effluent 

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

details on the water truck methodology [U.S. EPA, 2012].
Section 9 - Engineering Costs

9-33 

Total 10-Year Recurring Costs = Cost of Water Truck

determined from vendor contacts. EPA assumed the same trip distance and fuel cost from the 

disposal technology cost methodology. 

Similarly, EPA used data from the Steam Electric Survey to determine a maintenance 

materials factor with respect to the total O&M costs for conveyance and intermediate storage 

system elements, respectively. EPA calculated a median maintenance material factor for each 

system element (e.g., conveyance, intermediate storage) and applied it to the calculated O&M.

Energy costs are the costs associated with the power requirement to run the dry vacuum 

system. EPA obtained the power requirements for each piece of equipment (pumps and pugmills) 

used in the system from the vendors and used these power requirements to develop energy cost 

equations for the system pumps and pugmill(s) and estimate total energy consumption (in 

kWh/yr). EPA used the national 2010 energy cost of 4.05 cents per kilowatt hour to calculate the 

energy cost [U.S. DOE, 2011]. 

EPA estimated the O&M costs associated with compliance monitoring, transportation, 

disposal, and impoundment operations according to the methodologies described in Section 9.5. 

EPA used the same estimated tonnage described for the capital cost equation above to estimate 

fly ash transportation, disposal, and impoundment operation costs. 

EPA calculated 10-year recurring costs associated with intermediate storage water trucks 

by determining the cost, expected life, and number of water trucks required (from ORCR 

regulatory impact analysis information). EPA determined that the expected life of a water truck 

is ten years.

Vactor Truck Conversion 

For oil-fired units that operate less than 100 days, 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 includes piping the fly ash away from the primary particulate collection 

system using a vactor truck operated by a third-party contractor. The fly ash is drawn to a 10-

yard roll-off vacuum container stored at the end of the fly ash lines. To remove the fly ash from 

the vacuum container, the plant would contract a vendor, on a yearly basis, to vacuum fly ash 

from the vacuum container using a vactor truck. 

The capital costs associated with this system include installing the piping from the 

primary particulate collection system to the location were the roll-off vacuum container will be 

stored. Capital costs for the vactor truck system were determined using a direct relationship 

between capital cost and the fly ash generation rate, similar to the dry vacuum system. EPA used 

Steam Electric Survey data to determine the capital cost estimates. Similarly, EPA used Steam 

Electric Survey data and plant contact information to develop a relationship between the O&M 

costs for conveyance and storage and the fly ash generation rate.
Section 9 - Engineering Costs

9-34 

Total MDS Capital Costs = Conveyance & Intermediate Storage Equipment Costs + 

Plant Overhead Engineering Costs + Bottom Ash Disposal Costs 

9.7.2 Bottom Ash Transport Water 

EPA estimated capital, O&M, three-year recurring, five-year recurring, and 10-year 

recurring costs associated with converting bottom ash handling systems from wet sluicing to 

mechanical drag or remote mechanical drag systems for generating units generating bottom ash. 

EPA selected two systems, the mechanical drag system (MDS) and the remote MDS, as the basis 

for the dry and closed-loop recycle systems, respectively, based on system operation data from 

vendors and operation data from the 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 costs associated with the change in 

bottom ash handling. See Chapter 8 of the Incremental Costs and Pollutant Removals for 

Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category for more details on the bottom ash cost methodology [U.S. 

EPA, 2013]. 

EPA estimated costs for both MDS and remote MDS systems. The cost estimates reflect 

fully erected and commissioned systems, including equipment, controls, foundations, and field 

labor. For more detail on the MDS and remote MDS equipment, see Sections 7.3.2 and 7.3.3 of 

this report. 

Because EPA evaluated two technologies for bottom ash handling conversions, EPA 

estimated compliance costs for both technologies for each plant. EPA selected the technology 

associated with the lowest estimated annualized cost for the combined system conversion, 

transport and disposal, and impoundment costs, at a plant level, as the cost basis for the plant. 

EPA estimated capital, O&M, three-, five-, and 10-year recurring costs for MDS and 

remote MDS conversions using the equations provided below. Because the MDS and remote 

MDS share similar system elements, EPA calculated the O&M in four components. The 

components include the following: 

• Shared O&M Costs – Conveyance, transport, disposal, and impoundment O&M costs 

applicable to both MDS and remote MDS;

• Additional Remote MDS O&M Costs – Additional O&M costs, primarily chemical 

costs associated with the remote MDS;

• Intermediate Storage O&M Costs – Storage O&M costs applicable to both MDS and 

remote MDS; and

Wet Sluicing O&M Costs – Costs associated with the currently operating wet sluicing 

system.

Conveyance and intermediate storage equipment costs are the costs associated with the 

purchase and installation for a fully erected and commissioned MDS, including equipment, 

controls, foundations, and field labor. EPA estimated equipment costs on a generating unit basis 
Section 9 - Engineering Costs

9-35 

using a relationship between capital cost and unit capacity (in MW). EPA obtained unit capacity 

information from the Steam Electric Survey. Vendors provided the relationship between the cost 

and the generating capacity. The conveyance and intermediate storage costs provided for the 

MDS system include the costs for a semi-dry silo. After calculating the capital costs at the unit 

level, EPA summed the capital costs to a plant level.

Plant overhead engineering costs were determined from Steam Electric Survey. 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 conveyance and intermediate storage equipment costs.

EPA calculated the amount of moisture-conditioned bottom ash generated from the 

handling conversion using the wet bottom ash generation rate at the plant-level and an average 

moisture content of bottom ash from the Steam Electric Survey, supplemented with vendor data. 

EPA used the moisture-conditioned bottom ash tonnage to estimate the disposal costs, described

in Section 9.5. 

Conveyance and intermediate storage equipment costs are the costs associated with the 

purchase and installation for a fully erected and commissioned remote MDS, including 

equipment, controls, foundations, and field labor. EPA estimated equipment costs on a 

generating unit basis using a relationship between capital cost and unit capacity (in MW). EPA 

obtained unit capacity from the Steam Electric Survey. Vendors provided the relationship 

between the cost and the capacity. The conveyance and intermediate storage costs provided for 

the remote MDS system include the costs for a semi-dry silo. After calculating the capital costs 

at the unit level, EPA summed the capital costs to a plant level.

Recycle pump costs are the costs associated with the purchase of a pump used to recycle 

the sluice water from the remote MDS back to the steam electric generating unit. The chemical 

feed system costs are the costs associated with the purchase of a chemical feed system to adjust 

the pH of the sluice water as required to completely recycle the bottom ash sluice. To estimate 

the costs of the recycle pump and the chemical feed system for the remote MDS, EPA used the 

same type of recycle pump type and chemical feed system used in the FGD chemical 

precipitation cost methodology. See Section 6.1.6.1 of EPA’s Incremental Costs and Pollutant 

Removals for Proposed Effluent Limitation Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category report [U.S. EPA, 2013]. The recycle pump and 

chemical feed system costs include the freight costs associated with each piece of equipment. To 

estimate these costs, EPA used the bottom ash sluice rate, in gallons per day, from the Steam 

Electric Survey at a generating unit level and summed them to the plant level. EPA obtained 

recycle pump and chemical feed system cost relationships and estimated freight costs from 

vendors. 

Installation equipment costs are the costs associated with the installation of the recycle 

pump and chemical feed system. EPA estimated capital installation costs associated with the 

recycle pump and chemical feed system using an installation factor calculated based on Steam 

Electric Survey data and vendor data used in the fly ash conveyance and intermediate storage 

cost methodology. 
Section 9 - Engineering Costs

9-36 

Plant overhead engineering costs and disposal costs are calculated using the same 

methodology described for the total MDS capital costs. 

Conveyance operating and maintenance labor costs are the costs associated with 

operating and maintaining the conveyance portion of the bottom ash handling system. EPA 

calculated the conveyance O&M labor costs using the labor rate and the number of required 

operator or maintenance hours per year for operating or maintenance labor, respectively. EPA 

used the Steam Electric Survey data supplemented with U.S. Bureau of Labor Statistics data to 

calculate the labor rate for all system elements for the bottom ash conversion costs. Operating 

and maintenance hours per year were calculated using data in the Steam Electric Survey.

Similarly, EPA used data from the Steam Electric Survey to determine a maintenance 

materials factor with respect to the total O&M costs for the conveyance portion of the bottom ash 

handling system. EPA applied the median maintenance material factor to the total conveyance 

O&M costs to estimate the maintenance material costs.

Energy costs are the costs associated with the costs required to power the conveyance 

portion of the bottom ash handling system. Vendors supplied the size and horsepower 

specifications for pumps for the MDS and remote MDS systems based on generating unit 

capacity (in MW). EPA used the vendor data to create equations for estimating the energy 

consumption at the plant (in kWh/yr). EPA used the national 2010 energy cost of 4.05 cents per 

kilowatt hour to calculate the energy cost [U.S. DOE, 2011]. 

EPA estimated the O&M costs associated with transportation, disposal, and 

impoundment operations according to the methodologies described in Section 9.5. EPA used the 

same estimated tonnage described for the capital cost equation above to estimate bottom ash 

transportation, disposal, and impoundment operation costs. 

Chemical purchase costs are the costs associated with purchasing chemicals to control pH 

levels for bottom ash sluice recirculation. To calculate chemical purchase costs, EPA estimated 

the hydrogen chloride (HCl) consumption, chemical purchase, and freight costs. EPA calculated 

the HCl consumption using wet sluicing data and operating days in the Steam Electric Survey. 

For more explanation regarding estimating chemical consumption, see Section 6.1.7.4 in EPA’s 

Incremental Costs and Pollutant Removals for Proposed Effluent Limitation Guidelines and 

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

2013].

Total Shared O&M Costs = Conveyance Operating Labor Costs + Conveyance 

Maintenance Labor Costs + Conveyance Maintenance Materials Costs + Conveyance 

Energy Costs + Bottom Ash Transportation Costs + Bottom Ash Disposal Costs + 

Impoundment Operation Costs 

Total Additional Remote O&M Costs = Chemical Purchase Costs + Chemical Pump 

Energy Costs 
Section 9 - Engineering Costs

9-37 

Total Wet Sluicing O&M Costs = Sluicing Operating Labor Costs + Sluicing 

Maintenance Labor Costs + Sluicing Maintenance Materials Costs+ Sluicing Energy 

Costs 

Total Intermediate Storage O&M Costs = Storage Operating Labor Costs + Storage 

Maintenance Labor Costs + Storage Maintenance Materials Costs + Storage Energy 

Costs 

Energy requirements unique to the remote MDS consist of the energy required to operate 

the pump that returns sluice water from the sump pit back to the boiler area and 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. Pump energy 

consumption (in kWh/yr) is a function of pump horsepower. EPA used the national 2010 energy 

cost of 4.05 cents per kilowatt hour to calculate the energy cost [U.S. EPA, 2013]. 

Intermediate storage labor costs are the costs associated with operating and maintaining 

the intermediate storage area where bottom ash is conveyed prior to disposal. EPA calculated 

intermediate storage O&M labor costs using an estimated labor rate and the number of required 

operator or maintenance hours per year for operating or maintenance labor, respectively. EPA 

used the Steam Electric Survey data supplemented with U.S. Bureau of Labor Statistics data to 

calculate the labor rate for all system elements for the intermediate storage costs. EPA calculated 

O&M hours per year using data in the Steam Electric Survey.

Similarly, EPA used data from the Steam Electric Survey to determine a maintenance 

materials cost factor with respect to the total O&M costs for the intermediate storage of the 

bottom ash. EPA applied the median maintenance material cost factor to the total intermediate 

storage O&M costs to estimate the maintenance material costs.

Intermediate storage energy costs are the costs associated with power requirements for 

the pugmill unloader at the silo. EPA used vendor supplied size and horsepower specifications 

for pugmill unloaders to calculate the intermediate storage energy consumption (in kWh/yr). 

EPA used the national 2010 energy cost of 4.05 cents per kilowatt hour to calculate the energy 

cost [U.S. EPA, 2013]. 

The sluicing operating and maintenance labor costs are the costs associated with 

operating and maintaining the sluicing portion of the bottom ash handling system. EPA 

calculated wet sluicing O&M labor costs using an estimated labor rate and the number of 

required operator or maintenance hours per year for operating or maintenance labor, respectively. 

EPA used the Steam Electric Survey data supplemented with U.S. Bureau of Labor Statistics 

data to calculate the labor rate for all system elements for the wet sluicing costs. EPA estimated 

operating hours using median worker hours per day and the total number of days the unit 

operated in 2009, obtained from the Steam Electric Survey. EPA used industry responses from 

the Steam Electric Survey for wet sluicing systems to calculate median operating worker hours 
Section 9 - Engineering Costs

9-38 

Total MDS O&M Costs = Shared O&M Costs + Intermediate Storage O&M Costs – 

Wet Sluicing O&M Costs

Total 3-Year Recurring Costs = Cost of Mechanical Drag Chain for MDS

per day for the conveyance portion of the system. EPA used the number of unit operating days in 

2009, reported in the Steam Electric Survey, to calculate the total O&M days per year. EPA 

estimated maintenance hours per year using the maintenance labor median worker hours per year 

obtained from industry responses to the Steam Electric Survey.

EPA estimated maintenance material costs based on an evaluation of O&M costs reported 

in the Steam Electric Survey for generating units with wet sluicing bottom ash handling systems. 

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 applied the median maintenance 

material cost factor to the total conveyance O&M costs to estimate the maintenance material 

costs.

Wet bottom ash conveyance 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 the FGD wastewater chemical precipitation costing methodology; 

see Section 6.1.6.1 of EPA’s Incremental Costs and Pollutant Removals for Proposed Effluent 

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

Category report [U.S. EPA, 2013]. The pump horsepower was estimated as a function of sluice 

flow rate, obtained from the Steam Electric Survey. EPA estimated the hours of operation for the 

system using the operating days of the generating unit and an estimated value for the number of 

hours the system conveys bottom ash supplied by vendors. EPA used the national 2010 energy 

cost of 4.05 cents per kilowatt hour to calculate the energy cost [U.S. DOE, 2011]. 

As previously described, EPA estimated four different cost components to calculate total 

O&M costs for each system because different components apply to the two different systems. 

EPA estimated MDS costs using the shared, intermediate storage, and wet sluicing costs. EPA 

subtracted wet sluicing cost components from the calculated costs to represent the incremental 

cost achieved by the MDS system.

Total O&M costs for the remote MDS system include the shared and intermediate storage 

costs; however, EPA also included additional costs for operating the recycle pump and chemical 

feed system to allow for complete recycle. EPA did not subtract wet sluicing O&M costs from 

the remote MDS costs because the system still includes the operation of the existing sluicing 

operations. 

Total Remote MDS O&M Costs = Shared O&M Costs + Additional Remote MDS 

O&M Costs + Intermediate Storage O&M Costs
Section 9 - Engineering Costs

9-39 

Total 5-Year Recurring Costs = Cost of Mechanical Drag Chain for Remote MDS

One Time Costs = Engineering Consulting Cost 

EPA calculated three-year recurring costs associated with the drag chain for the MDS. 

The drag chain is the component of the system that drags the bottom ash from the water bath, up 

the incline to intermediate storage. EPA calculated the three-year recurring cost by determining 

the cost and expected life of a drag chain for the MDS. Because the drag chain of the MDS 

system is located underneath the boiler, and more susceptible to large chunks of falling bottom 

ash, EPA determined that the expected life of a MDS drag chain is three years.

EPA calculated five-year recurring costs associated with the drag chain for the remote 

MDS. The drag chain is the component for the remote MDS is the same described for the MDS. 

EPA calculated the five-year recurring cost by determining the cost and expected life of a drag 

chain for the remote MDS. Because the drag chain of the remote MDS system is not located 

directly underneath boiler, and less likely to be damaged by falling bottom ash, EPA determined 

that the expected life of a remote MDS drag chain is five years.

EPA reviewed plants operating bottom ash handling systems that recycled the majority of 

their bottom ash sluice from wet handling operations. Instead of estimating compliance costs for 

a full conversion to a MDS or remote MDS system, EPA estimated a one-time cost associated 

with consulting an engineer to completely close the bottom ash recycle system, eliminating all 

discharges of bottom ash transport water. See Section 8.5 of EPA’s Incremental Costs and 

Pollutant Removals for Proposed Effluent Limitation Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category report [U.S. EPA, 2013]. 

9.7.3 Estimated Industry-Level Costs for Ash Handling Conversions 

Table 9-5 presents the estimated capital, O&M, and recurring costs on an industry level 

associated with dry fly ash handling conversions, while Table 9-6 presents the estimated capital, 

O&M, and recurring costs on an industry-level associated with dry or closed-loop recycle bottom 

ash handling conversions. Both tables also include the number of plants incurring compliance 

costs. The costs presented in the table represent the compliance costs for those generating units 

expected to be subject to the proposed ELGs; therefore, oil-fired units and units with a capacity 

of 50 MW or less are not included because they do not need to install the technology basis to 

meet the new BAT limitations (which are based on the current BPT requirements for these units). 

See EPA’s Incremental Costs and Pollutant Removals for Proposed Effluent Limitation 

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

report for the costs for all generating units [U.S. EPA, 2013]. 
Section 9 - Engineering Costs

9-40 

Table 9-5. Estimated Industry-Level Costs for Fly Ash Handling Conversions Based on 

Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis 

Number of Plants

Total Capital Cost

($)

Total O&M Cost

($/year)

10-Year Recurring Cost

($/10-year)a 

66 $398,000,000 $177,000,000 ($20,700,000)

a – The values in this column are negative because they represent cost savings.

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2011]. 

Table 9-6. Estimated Industry-Level Costs for Bottom Ash Handling Conversions Based on 

Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis 

Number of 

Plants

Total Capital 

Cost

($)

Total O&M 

Cost

($/year)

One Time 

Cost

($)

3-Year 

Recurring 

Cost

($/3-year)

5-Year 

Recurring 

Cost

($/5-year)

10-Year 

Recurring 

Cost

($/10-year)a 

240 $4,470,000,000 $494,000,000 $583,000 $28,200,000 $64,800,000 ($83,800,000)

a – The values in this column are negative because they represent cost savings.

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2011]. 

EPA also estimated the industry-level costs for plants to convert only the generating units 

that are greater than 400 MW to dry or closed-loop recycle bottom ash handling systems. 

However, EPA used a different approach to estimate the plant-level costs for this analysis. For 

those plants with all generating units with a nameplate capacity of 400 MW or less, EPA zeroed 

the costs from its bottom ash cost outputs and for those plants with all generating units with a 

nameplate capacity greater than 400 MW, EPA used the costs from its bottom ash cost outputs. 

For those plants that have at least one generating unit with a nameplate capacity of 400 MW or 

less and at least one other generating unit with a nameplate capacity of greater than 400 MW, 

EPA approximated the plant-level bottom ash costs. To perform this approximation, EPA 

calculated a plant-level bottom ash adjustment factor based on the amount of bottom ash 

generated by the generating units expected to incur compliance costs with a nameplate capacity 

greater than 400 MW compared to the total amount of bottom ash generated at the plant for those 

generating units expected to incur compliance costs (excluding the generating units with a 

nameplate capacity of 50 MW or less). EPA then multiplied the bottom ash adjustment factors by 

the plant-level bottom ash compliance costs to estimate the bottom ash compliance costs for this 

analysis. For more details on how EPA estimated these plant-level bottom ash costs, see the 

memorandum entitled “Memorandum to the Rulemaking Record: Methodologies for Estimating 

Costs and Pollutant Removals for Steam Electric ELG Regulatory Option 4a” (DCN SE03834). 

Table 9-7 presents the estimated capital, O&M, and recurring costs on an industry-level 

associated with dry or closed-loop recycle bottom ash handling conversions for this analysis. The 

table also includes the number of plants incurring compliance costs. The costs presented in the 

table represent the compliance costs for those generating units expected to be subject to the 

proposed ELGs for Regulatory Option 4a; therefore, oil-fired units and units with a capacity of 
Section 9 - Engineering Costs

9-41 

400 MW or less are not included because they do not need to install the technology basis to meet 

the new BAT limitations (which are based on the current BPT requirements for these units). 

Table 9-7. Estimated Industry-Level Costs for Bottom Ash Handling Conversions Based on 

Oil-Fired Units and Units 400 MW or Less Not Installing Technology Basis 

Number of 

Plants

Total Capital 

Cost

($)

Total O&M 

Cost

($/year)

One Time 

Cost

($)

3-Year 

Recurring 

Cost

($/3-year)

5-Year 

Recurring 

Cost

($/5-year)

10-Year 

Recurring 

Cost

($/10-year)a 

115 $2,580,000,000 $255,000,000 $314,000 $1,120,000 $37,800,000 ($35,600,000)

a – The values in this column are negative because they represent cost savings.

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2011]. 

9.8 COMBUSTION RESIDUAL LANDFILL LEACHATE

EPA estimated capital and O&M costs associated with installing and operating a onestage chemical precipitation wastewater treatment system to treat combustion residual landfill 

leachate. Note that as described in Section 9.2.4, EPA finds that plants with combustion residual 

surface impoundment leachate will not incur costs associated with any proposed leachate 

requirements. 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.84 However, for plants that do 

not have FGD wastewater, EPA calculated the cost for a chemical precipitation to handle just the 

landfill leachate using the equations in Sections 9.6.1 associated with one-stage chemical 

precipitation. [ERG, 2013d] 

Of the plants identified as having some level of treatment in place for FGD chemical 

precipitation, 29 plants also discharge landfill leachate. EPA conducted an analysis to determine 

if the existing FGD wastewater treatment systems at these plants would be sufficient to treat the 

amount of combustion residual landfill leachate produced at the plants 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 of these plants had sufficient 

capacity to handle the additional combustion residual landfill leachate flow; however, 19 of the 

plants did not have the capacity to treat the additional combustion residual landfill leachate flow. 

 

84 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 which subjects leachate to both chemical precipitation and biological treatment.
Section 9 - Engineering Costs

9-42 

For these 19 plants, EPA estimated costs for an additional one-stage chemical precipitation 

wastewater treatment system sized to treat only the combustion residual landfill leachate.

Additionally, for leachate treatment, EPA developed cost equations and calculated costs, 

including equipment and energy, 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 stainless steel piping.

Table 9-8 presents the estimated capital and O&M costs on an industry level associated 

with the treatment of combustion residual landfill leachate. The table also includes the number of 

plants incurring compliance costs. For plants where EPA calculated costs for the treatment of 

FGD wastewater and combustion residual landfill leachate in the same system, EPA is presenting 

the incremental increase in the cost of the treatment system compared to the treatment of only 

FGD wastewater (i.e., the cost of treating FGD wastewater alone was subtracted from the cost of 

treating the combined wastestreams). EPA estimated industry-level costs excluding units that are 

50 MW or less and oil-fired units. The costs presented in the table represent the compliance costs 

for those plants expected to be subject to the proposed ELGs; therefore, oil-fired units and units 

with a capacity of 50 MW or less are not included because they do not need to install the 

technology basis to meet the new BAT limitations (which are based on the current BPT 

requirements for these units). See EPA’s Incremental Costs and Pollutant Removals for 

Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category report for the costs for all generating units. [U.S. EPA, 2013] 

Table 9-8. Estimated Industry-Level Costs for Combustion Residual Leachate Based on 

Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis 

Technology Option

Number of 

Plants

Total Capital 

Cost

($)

Total O&M 

Cost

($/year)

6-Year 

Recurring Cost

($/6-year)

10-Year 

Recurring Cost

($/10-year)

Chemical Precipitation 101 $615,000,000 $58,600,000 $5,630,000 $0

Chemical Precipitation 

followed by Biological 

Treatment 101 $931,000,000 $79,100,000 $5,630,000 $0

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2011]. 

Note: For plants where EPA calculated costs for the treatment of FGD wastewater and combustion residual landfill 

leachate in the same system, EPA is presenting the incremental increase in the cost of the treatment system 

compared to the treatment of only FGD wastewater (i.e., the cost of treating FGD wastewater alone was subtracted 

from the cost of treating the combined wastestreams).

9.9 SUMMARY OF NATIONAL ENGINEERING COSTS

As described in Section 8, EPA evaluated eight regulatory options comprised of various 

combinations of the technology options considered for each wastestream, as shown in Table 9-9. 

The Agency estimated the costs associated with steam electric power plants to achieve 

compliance for each regulatory option under consideration. This section summarizes the total 

estimated compliance costs associated with each option (see Table 9-10). For each regulatory 
Section 9 - Engineering Costs

9-43 

option, the capital cost, annual operating and maintenance costs, one-time costs, and recurring 

costs are presented. See the Regulatory Impact Analysis for Proposed Effluent Limitations 

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

listing of total annualized costs by regulatory option. All cost estimates in this section are 

expressed in terms of pre-tax 2010 dollars. The costs presented in the table represent the 

compliance costs for those plants expected to be subject to the proposed ELGs; therefore, oilfired units and units with a capacity of 50 MW or less are not included because they do not need 

to install the technology bases to meet the new BAT limitations (which are based on the current 

BPT requirements for these units). See EPA’s Incremental Costs and Pollutant Removals for 

Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category report for the costs for all generating units. [U.S. EPA, 2013] 

Table 9-9. Technology Options and Other Costs Included in the Estimated Compliance 

Costs for Each Regulatory Option 

Wastestream Technology Option

Regulatory Option

1 2 3a 3b 3 4a 4 5

FGD Wastewater

Chemical Precipitation X X X X X X X

Biological Treatment X X X X X

Vapor-Compression Evaporation X

Fly Ash Transport Water Dry Fly Ash Handling X X X X X X

Bottom Ash Transport Water Dry or Closed-loop recycle Bottom

Ash Handling X X X 

Leachate Chemical Precipitation X X

Gasification Wastewater Vapor-Compression Evaporation X X X X X X X X

Flue Gas Mercury Control 

Wastes Dry Handling X X X X X X 

Nonchemical Metal 

Cleaning Wastes Chemical Precipitation X X X X X X X X 

Other Costs Not Specific to Wastestream

Solids Transportation X X X X X X X X

Solids Disposal X X X X X X X X

Impoundment Operation X X X X X X X X

Compliance Monitoring X X X X X X X

Table 9-10. Cost of Implementation by Regulatory Option [In millions of pre-tax 

2010 dollars] 

Regulatory 

Option

Number of 

Plants Capital Cost

Annual 

O&M Cost

One Time 

Costs

Recurring Costs

3-year 5-year 6-year 10-year

1 116 $1,450 $194 $0 $0 $0 $10 ($33)

3a 66 $398 $177 $0 $0 $0 $0 ($21)

2 116 $2,499 $257 $0 $0 $0 $10 ($33)
Section 9 - Engineering Costs

9-44 

Table 9-10. Cost of Implementation by Regulatory Option [In millions of pre-tax 

2010 dollars] 

Regulatory 

Option

Number of 

Plants Capital Cost

Annual 

O&M Cost

One Time 

Costs

Recurring Costs

3-year 5-year 6-year 10-year

3b 80 $998 $244 $0 $0 $0 $1 ($26)

3 155 $2,897 $434 $0 $0 $0 $10 ($54)

4a 200 $5,478 $689 $0.3 $1 $38 $10 ($90)

4 277 $8,011 $988 $0.6 $28 $65 $16 ($137)

5 277 $11,755 $1,753 $0.6 $28 $65 $19 ($137)

The compliance costs above account for unit retirements, repowerings and conversions 

that have been announced by companies and are scheduled to occur by 2014, based on 

information obtained by EPA as of August 2012. But they do not reflect additional planned unit 

retirements, repowerings, and conversions that have been announced since August 2012, nor do 

they reflect announced retirements, repowerings, and conversions that are scheduled to occur by 

2022. (See DCN SE02033, “Changes to Industry Profile for Steam Electric Generating Units 

Updates”). EPA estimates that accounting for these additional changes would reduce the total 

annualized compliance costs for the rule, which are presented in the Regulatory Impact Analysis 

for Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category. For example, EPA estimated that total pre-tax annualized 

compliance costs for Option 3 would go from $561.3 million to $532.8 million (5 percent 

reduction), whereas costs for Option 4 would go from $1,373.2 million to $1,252.9 million (9 

percent reduction). EPA expects that similar levels of reductions would be seen in the capital and 

O&M engineering compliance costs based on these changes.

9.10 COMPLIANCE COSTS FOR NEW SOURCES

EPA evaluated the expected costs of compliance for new sources. The construction of 

new generating units may occur at an existing power plant or at a new plant construction site. 

The incremental cost associated with complying with the proposed NSPS and PSNS 

options will vary depending on the types of processes, wastestreams, and waste management 

systems that would have been installed in the absence of the proposed new source requirements. 

EPA estimated capital and O&M costs for eight different scenarios that represent the different 

types of operations that are present at existing power plants or are typically included at new 

power plants. These scenarios captured differences in the following characteristics:

• Plant status (i.e., Greenfield versus existing plant);

• Presence/capacity of on-site impoundments; 

• Presence/capacity of on-site landfills;

• Type of FGD system in service;

• Bottom ash handling; and 

• Combustion residual leachate collection and handling. 
Section 9 - Engineering Costs

9-45 

While EPA evaluated eight different scenarios, EPA determined that two of the scenarios 

best represent the conditions that will be present at new sources. One scenario reflects conditions 

for a Greenfield plant and the other scenario reflects conditions for a new source constructed at 

an existing plant. EPA selected the scenarios that most resembled current industry practices, 

based on an evaluation of the industry profile, for use in the NSPS analysis. Table 9-11 identifies 

the characteristics that were used for these two scenarios.

Table 9-11. NSPS Compliance Cost Scenarios Evaluated for the Proposed Rule 

Plant Characteristics Existing Plant Scenario Greenfield Plant Scenario

Plant Status Existing Greenfield

Presence of On-Site Impoundments On-site impoundment with no 

additional capacity.

No on-site impoundment.

Presence of On-Site Landfill On-site landfill with available 

capacity.

On-site landfill to be installed.

Type of FGD System Wet FGD system. Wet FGD system.

Bottom Ash Handling Mechanical drag system already 

planned.

Mechanical drag system already 

planned.

Combustion Residual Leachate1 No leachate collection in the landfill. Landfill leachate collected and treated 

with FGD wastewater.

a – Because the Greenfield plant includes leachate collection while the existing plant does not (because leachate at 

the existing plant would likely be subject to BAT), the costs presented in Table 9-12 are more expensive for the 

Greenfield plant than for the existing plant.

EPA evaluated new source costs for FGD wastewater, bottom ash transport wastewater, 

and combustion residual leachate. Because the current Steam Electric NSPS ELGs already 

require zero discharge for fly ash transport wastewater, EPA did not calculate new source costs 

for fly ash. Additionally, because the technology bases for gasification wastewater, flue gas 

mercury control wastewater, and nonchemical metal cleaning wastes are already standard 

industry practices, EPA did not calculate new source costs for these wastestreams.

Additionally, EPA determined that the majority of plants installing bottom ash handling 

systems in the last 10-25 years are installing dry handling systems (approximately 80 percent). 

Therefore, EPA determined new source incremental compliance costs for dry bottom ash 

handling would be zero. 

In addition to calculating the compliance costs for these two different scenarios, EPA also 

evaluated the costs for three different model-sized generating units (i.e., small, medium, and 

large generating units). Table 9-12 presents the estimated capital and O&M costs for each 

scenario and each model plant size. The estimated incremental compliance costs for each of 

scenarios evaluated by EPA is included in the memorandum entitled “New Source Performance 

Standards (NSPS) Costing Methodology.” 
9-46

Section 9 - Engineering Costs

Table 9-12. Estimated Industry-Level NSPS Costs

Regulatory 

Optiona 

Small Unit (350 MW) Medium Unit (600 MW) Large Unit (1,300 MW)

Total Capital Cost 

($)

Total O&M Cost 

($/year)

Total Capital Cost 

($)

Total O&M Cost 

($/year)

Total Capital Cost 

($)

Total O&M Cost 

($/year)

Greenfield Plant

1 b b b b b b

2 12,900,000 1,110,000 15,400,000 1,550,000 24,600,000 2,860,000

3 12,900,000 1,110,000 15,400,000 1,550,000 24,600,000 2,860,000

4 13,500,000 1,379,281 19,400,000 2,010,000 26,900,000 3,820,000

5 38,200,000 3,850,000 43,500,000 5,840,000 61,500,000 11,700,000

Existing Plant

1 b b b b b b

2 12,900,000 1,110,000 15,400,000 1,550,000 24,600,000 2,860,000

3 12,900,000 1,110,000 15,400,000 1,550,000 24,600,000 2,860,000

4 12,900,000 1,110,000 15,400,000 1,550,000 24,600,000 2,860,000

5 33,800,000 2,850,000 39,000,000 4,280,000 56,300,000 8,530,000

Source: [ERG, 2013b]

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2011]. 

a – EPA did not evaluate Regulatory Option 3a for NSPS because the current ELGs already have a zero discharge standard for NSPS. EPA did not evaluate 

Regulatory Option 3b for NSPS because EPA does not have data regarding future new source plant-level wet scrubbed capacity at existing plants. EPA also did 

not evaluate Regulatory Option 4a for NSPS because, as is the case for Options 4 and 5, there are no incremental NSPS costs for bottom ash. Therefore, the costs 

associated with Option 4a would be equal to Option 3.

b – The NSPS costs for Regulatory Option 1 have been withheld to protect confidential business information.
Section 9 - Engineering Costs

9-47 

9.11 REFERENCES

1. HPD. 2009. Communications between Name, HPD and Sarah Holman, Eastern Research 

Group, Inc. RE: MVC Costs.” (17 February). DCN SE01025. 

2. Eastern Research Group (ERG). 2013a. Memorandum to the Record. “Flue Gas 

Desulfurization Future Profile Sensitivity Analysis.” (29 January). DCN SE01989. 

3. Eastern Research Group (ERG). 2013b. Memorandum to the Steam Electric Rulemaking 

Record: New Source Performance Standards (NSPS) Costing Memorandum. (19 April). 

DCN SE02130. 

4. Eastern Research Group (ERG). 2013c. Memorandum to the Rulemaking Record: 

Methodologies for Estimating Costs and Pollutant Removals for Steam Electric ELG 

Regulatory Options 3a and 3b. (19 April). DCN SE03881. 

5. Eastern Research Group (ERG). 2013d. Steam Electric Technical Questionnaire Database 

(“Steam Electric Survey”). (19 April). DCN SE01958. 

6. RSMeans. 2011. Building Construction Cost Data, 69th Edition. 

7. U.S. DOE. 2011. U.S. Department of Energy, Energy Information Administration (EIA). 

Electric Power Annual 2009. Washington, D.C. (January). DCN SE02023. 

8. U.S. Department of Labor, Bureau of Labor Statistics. 2010. Occupational Employment 

Statistics: May 2009 National Occupational Employment and Waste Estimates, United 

States. Washington, D.C. (May). DCN SE02024. 

9. 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. (April). DCN 

SE03168. 

10. U.S. EPA. 2013. Incremental Costs and Pollutant Removals for Proposed Effluent 

Limitation Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category Report. (19 April). DCN SE01957. 
Section 10 - Pollutant Loadings and Removals

10-1 

SECTION 10

POLLUTANT LOADINGS AND REMOVALS

This section 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.

• 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 ELGs (e.g., applicability changes) would likely not lead to 

a change in pollutant loadings to complying plants. Other aspects of the proposed ELGs would 

likely lead to a change in pollutant loadings for a subset of complying plants. These plants 

generally generate the wastestreams for which EPA is proposing new limitations or standards. 

This section describes the detailed pollutant loadings evaluation EPA performed for these plants 

that are likely to achieve a reduction in pollutant loadings associated with the regulatory options 

evaluated for the proposed ELGs. Specifically, EPA determined baseline and post-compliance 

pollutant loadings for the following wastestreams: FGD wastewater, fly ash transport water, 

bottom ash transport water, combustion residual landfill leachate, gasification wastewater, and 

flue gas mercury control wastewater.

The currently operating gasification generating units operate vapor-compression 

evaporation systems (i.e., the technology basis for the preferred options); therefore, EPA 

determined that the baseline loadings are equal to the post-compliance loadings. Similarly, plants 

currently manage their flue gas mercury control wastes so there is no pollutant discharge to 

surface waters; therefore, the baseline loadings for these wastewaters are also equal to the postcompliance loadings. Additionally, because nonchemical metal cleaning wastes are already 

subject to the proposed BAT limitations, based on the current BPT standard (as described in 

Section 8.1.3, and because EPA is proposing to exempt from limitations and standards any 

nonchemical metal cleaning wastes currently generated and authorized for discharge without 

copper and iron limits, EPA finds that the baseline loadings are equal to the post-compliance 

loadings. Therefore, the remainder of this section applies to FGD wastewater, fly ash transport 

water, bottom ash transport water, and combustion residual landfill leachate. 
Section 10 - Pollutant Loadings and Removals

10-2 

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 presented in Section 8. For example, for any plant discharging FGD 

wastewater, EPA calculated both a baseline loading and post-compliance loadings associated 

with each technology basis (i.e., one-stage chemical precipitation, one-stage chemical

precipitation with biological treatment, and one-stage chemical precipitation with vaporcompression 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 pollutant discharged per year, in pounds/year. 

EPA used sampling data gathered through its sampling program described in Section 3, 

as well as publicly available sources, to characterize the baseline loading and post-compliance 

loading concentrations for each evaluated wastestream. Section 10.2 presents the data sources 

and average discharge pollutant concentrations for 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 average pollutant concentration of the specific wastestream in the following 

equation: 

Loadingpollutant �

lbs

yr � = FlowRate �

gallons

yr � × Concpollutant �

mg

L � × �

2.20462 lb

106 mg � × � 1000 L

264.17 gallons�

Where:

Loadingpollutant = The loadings from a specific pollutant discharged directly to surface 

water, in pounds per year. 

FlowRate = The flow rate of the wastestream being discharged, in gallons per 

year.

Concpollutant = The average concentration of a specific pollutant present in the 

wastestream, in milligrams per liter.

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 POC, Table 

10-1 provides the percent removals expected from well-operated POTWs as reported in the 

Memo to the 2006 Effluent Guidelines Program Plan Docket [ERG, 2005]. For any plant 
Section 10 - Pollutant Loadings and Removals

10-3 

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 the following equation: 

Loadingpollutant_indirect �

lbs

yr � =Loadingpollutant �

lbs

yr � ×(1-POTWRemoval)

Where:

Loadingpollutant_indirect = The loadings from a specific pollutant that is transferred to a POTW 

prior to discharge, in pounds/year. 

Loadingpollutant = The loadings from a specific pollutant if it were discharged directly, 

in pounds/year. 

POTWRemoval = 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.85 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.86 Section 10.4

discusses the wastestream mass loading (i.e., unweighted loadings) and TWPE loadings in more 

detail.

Table 10-1. POTW Removals 

Analyte Median 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

 

85 A list of pollutant-specific TWF values is located in the Toxic Weighting Factor Development in Support of CWA 

304(m) Planning Process [U.S. EPA, 2004]. 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.

86 If discharged to a POTW, EPA adjusted the TWPE to account for POTW removals, as described above.
Section 10 - Pollutant Loadings and Removals

10-4 

Table 10-1. POTW Removals 

Analyte Median POTW Removal Percentage

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: Memo to 2006 Effluent Guidelines Program Plan Docket [ERG, 2005].

NA – Not applicable.

10.2 WASTESTREAM POLLUTANT CHARACTERIZATION AND DATA SOURCES

As discussed earlier, loadings calculations require pollutant concentrations to determine 

the mass pollutant 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 
Section 10 - Pollutant Loadings and Removals

10-5 

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, Section 10.2.2, and Section 

10.2.3 present the data sources and characterization for FGD wastewater, ash transport water, 

and combustion residual leachate, respectively.

10.2.1 FGD Wastewater Characterization

As described in Section 8, EPA is considering three technologies 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 

vapor-compression 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:87

• J-Values and Nondetects: 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 method detection limit, 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 

nondetects below the method detection limit) 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 nondetect;

- 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:

 

87 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.
Section 10 - Pollutant Loadings and Removals

10-6 

- 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. 

Table 10-2. Data Sets Used in the FGD Loadings Calculation 

Plant Name Source of Data Set

Wastestreams Represented 

in Data Set a 

Progress Energy Carolinas’ Roxboro

Steam Electric Plant (Roxboro)

Monitoring data provided by plant Settling impoundment effluent

Duke Energy’s Miami Fort Station 

(Miami Fort)

EPA Sampling Chemical precipitation effluent

EPA CWA 308 Sampling Chemical precipitation effluent

RRI Energy’s Keystone Generating 

Station (Keystone)

EPA Sampling Chemical precipitation effluent

EPA CWA 308 Sampling Chemical precipitation effluent

Allegheny Energy’s Hatfield’s Ferry 

Electric Plant (Hatfield’s Ferry)

EPA Sampling Chemical precipitation effluent

EPA CWA 308 Sampling Chemical precipitation effluent

Duke Energy Carolinas’ Belews Creek

Steam Station (Belews Creek)

EPA Sampling Biological treatment effluent

EPA CWA 308 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 Sampling Biological treatment effluent

Monitoring data provided by plant Biological treatment effluent

Enel Brindisi EPA Sampling Vapor-Compression Evaporation 

Effluent

a -The three plants with data used for chemical precipitation effluent characterization operate one-stage chemical 

precipitation systems.

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, wastewater treatment upsets, and the treatment system is not designed to remove selenium.

Each of the following sections presents the characterization data set used to calculate 

mass and TWPE loadings for each option, starting with the baseline characterization. 

10.2.1.1 Baseline FGD Wastewater Loading Characterization 

As discussed in Section 9, EPA identified 117 plants that operate wet FGD systems and 

discharge FGD wastewater. For the FGD dischargers, EPA calculated baseline loadings by 
Section 10 - Pollutant Loadings and Removals

10-7 

assigning pollutant concentrations based on the type of treatment system currently in place at the 

plant. EPA assigned treatment in place for this wastewater to one of four classes of treatment: 

surface impoundment, chemical precipitation, biological treatment, and vapor-compression 

evaporation. As discussed in Section 9, EPA used survey data to determine the baseline FGD 

wastewater treatment in place. Based on survey responses, EPA categorized 46 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;88 and

• One plant operates a vapor-compression evaporation system.89

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 operation of these types of system 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. 

As discussed in Section 7.1.1, surface impoundments use gravity to remove particulates 

from wastewater, reducing the amount of total suspended solids (TSS) and particulate forms of 

other specific pollutants in the wastewater. EPA’s sampling program collected and analyzed the 

untreated FGD wastewater of 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 3.4 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 that a surface 

impoundment will remove most of the particulate phase metals, but will not remove dissolved 

metals from the wastewater.90 EPA calculated proxy values representing impoundment effluent 

concentrations for each analyte using the data for each of these seven EPA sampled plants. EPA 

also obtained surface impoundment effluent data from a steam electric power plant that treats 

only FGD wastewater in the impoundment. EPA averaged the surface 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 

 

88 There are six plants currently operating biological treatment system, 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.

89 There are two plants currently operating vapor-compression evaporation systems, but at the time the costs and 

loadings were developed, EPA had only identified one plant with a vapor-compression evaporation system. 

Therefore, only one of the two plants were identified as having vapor-compression treatment in place for these 

analyses. 

90 The methodology used to estimate settling impoundment effluent concentrations is presented in detail in the 

Incremental Costs and Pollutant Removals for Proposed Effluent Limitation Guidelines and Standards for the Steam 

Electric Generating Point Source Category Report [U.S. EPA, 2013].
Section 10 - Pollutant Loadings and Removals

10-8 

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.

Table 10-3. Average Effluent Pollutant Concentrations for 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
Section 10 - Pollutant Loadings and Removals

10-9 

Table 10-3. Average Effluent Pollutant Concentrations for FGD 

Surface Impoundments

Analyte Unit Average Concentration

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

Source: [ERG, 2012a – 2012i]; [NCDENR, 2011].

Note: Concentrations are rounded to three significant figures.

NA – Not applicable. 

10.2.1.2 Baseline and Post Compliance One-Stage Chemical Precipitation Pollutant 

Characterization

As part of the sampling activities described in Section 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 were designed and are 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 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 
Section 10 - Pollutant Loadings and Removals

10-10 

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 10-4. 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 

10-4 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 10-4 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 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.

Table 10-4. Average Effluent Pollutant Concentrations for 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
Section 10 - Pollutant Loadings and Removals

10-11 

Table 10-4. Average Effluent Pollutant Concentrations for One-Stage 

Chemical Precipitation System

Analyte Unit Average Concentration

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

Source: [ERG, 2012c]; [ERG, 2012f]; [ERG, 2012g]; [ERG, 2012i].

Note: Concentrations are rounded to three significant figures.

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

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 plants sampled operate 
Section 10 - Pollutant Loadings and Removals

10-12 

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, these 

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 7 for 

complete description). 

EPA has multiple sets of data for these two plants including EPA sampling data, 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 longterm 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., 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, 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, which is presented in Table 10-5. EPA used this average 

concentration 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 

concentrations presented in Table 10-5 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 a biological treatment system technology basis, presented in Table 

10-5, 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.91 For each plant classified as a baseline biological treatment system EPA calculated the 

baseline loadings using the average concentration presented in Table 10-5. Two of these plants 

 

91 There are six plants currently operating biological treatment system, 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.
Section 10 - Pollutant Loadings and Removals

10-13 

do not operate consistently with the technology basis and likely discharge greater pollutant 

concentrations than the system reflecting the technology basis.92 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. 

Table 10-5. Average Effluent Pollutant Concentrations for 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

 

92 Of the total five baseline biological treatment plants, only three are classified as operating consistently with the 

technology basis.
Section 10 - Pollutant Loadings and Removals

10-14 

Table 10-5. Average Effluent Pollutant Concentrations for One-Stage Chemical 

Precipitation System with Biological Treatment 

Analyte Unit Average Concentration

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

Source: [ERG, 2012a]; [ERG, 2012d]; [ERG, 2012i]; [Duke Energy, 2011a – 2011b].

Note: Concentrations are rounded to three significant figures.

10.2.1.4 Baseline and Post-Compliance One-Stage Chemical Precipitation with 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, EPA 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 10-6.

93 EPA used this average concentration to calculate the post-compliance 

loadings that would be discharged by plants currently operating surface impoundments, chemical 

 

93 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 discharge to surface water or POTW. The plant could choose to 

discharge both the brine concentrator and the crystallizer condensate streams, together or separately.
Section 10 - Pollutant Loadings and Removals

10-15 

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 

presented in Table 10-6 to calculate the baseline loadings for any plant currently operating 

chemical precipitation and a vapor-compression evaporation treatment system as FGD 

wastewater treatment.

Table 10-6. Average Effluent Pollutant Concentrations for 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
Section 10 - Pollutant Loadings and Removals

10-16 

Table 10-6. Average Effluent Pollutant Concentrations for One-Stage Chemical 

Precipitation System with Vapor-Compression Evaporation

Analyte Unit Average Concentration

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, 2012h].

Note: Concentrations are rounded to three significant figures.

NA – Not applicable. 

10.2.2 Ash Transport Water 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]; and

• 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]. 

Section 3 provides details regarding each of the four data sources used in the ash 

impoundment loadings. 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).
Section 10 - Pollutant Loadings and Removals

10-17 

• 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 these data sources 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 wastestream (e.g., cooling water), the concentrations may be 

diluted and therefore, may underestimate the pollutant loadings. First, EPA reviewed the data 

and, as appropriate, made some substitutions to the data sets. EPA set nondetects equal to onehalf the quantitation limit for the detailed study sampling data because EPA knew the 

quantitation limit.94 For the other (i.e., EPRI, 1982 TDD, and Form 2C) data sets, EPA could not 

confirm whether the nondetect results were presented as less than the quantitation limit or the 

method detection limit (or some other value); therefore, EPA set the nondetects equal to the 

value provided. 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 it had data. For example, if a plant had pollutant concentration data for its fly ash 

impoundment for more than one day, EPA averaged all these data for that specific pollutant to 

get a single representative value of average concentration of that pollutant in the effluent from 

the fly ash impoundment. EPA used the same methodology to calculate the average 

concentration of a pollutant in the effluents from bottom ash impoundments and combined ash 

impoundments. Some data sources provided only one data point, and therefore, the average is the 

same as that data point.

After calculating an average concentration for each type of impoundment at the plantspecific level, EPA then 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.95 Table 10-7 presents the average pollutant 

concentration for all three types of ash impoundment. EPA used these average concentration data 

sets to calculate the baseline loadings for discharges from ash impoundments. 

The technology option under consideration for both fly ash and bottom ash is dry or 

closed-loop recycle ash handling. As discussed in Section 7, these systems do not discharge ash 

transport water; therefore, the average effluent concentration associated with dry or closed-loop 

recycle ash handling is zero. Because no ash transport water is discharged, the post-compliance 

discharge loading is zero.

 

94 To simplify the discussion, for the purpose of Section 10.2.2 the term “nondetect” is used to refer to both values 

measured below the quantitation limit and those values measured below the detection limit.

95 The methodology used to calculate the average concentrations for ash impoundment effluent is presented in the 

Incremental Costs and Pollutant Removals for Proposed Effluent Limitation Guidelines and Standards for the Steam 

Electric Generating Point Source Category Report [U.S. EPA, 2013].
Section 10 - Pollutant Loadings and Removals

10-18 

Table 10-7. Average Effluent Pollutant Concentration for Ash 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

Silica-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
Section 10 - Pollutant Loadings and Removals

10-19 

Table 10-7. Average Effluent Pollutant Concentration for Ash Impoundment Systems

Analyte Unit

Average 

Fly Ash 

Concentration

Average 

Bottom Ash 

Concentration 

Average Combined 

Ash Concentration 

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

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

Source: [U.S. EPA, 2009]; [U.S. EPA, 1982]; [EPRI, 1997 – 2001]; [UWAG, 2008].

Note: Concentrations are rounded to three significant figures.

NA – Not applicable. 

10.2.3 Baseline and Post-Compliance Combustion Residual Leachate Characterization 

As described in Section 6, 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 anyway. 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. The 

concentrations of pollutants in the discharge stream will remain at equilibrium. Therefore, EPA 

finds that baseline and post-compliance pollutant loadings will be the same at baseline and at 

post-compliance 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 Section 8, 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 through the Steam Electric Survey to 

calculate average effluent concentrations for untreated combustion residual landfill leachate.
Section 10 - Pollutant Loadings and Removals

10-20 

EPA’s Steam Electric Survey required certain plants to collect and analyze samples of 

landfill leachate and report the results of these analyses. EPA requested these plants to sample 

any untreated landfill leachate collected from an on-site landfill containing combustion residuals. 

EPA used all data as provided by the plants in the survey, except for the following:

• For values reported as less than the quantitation limit, EPA assumed the concentration 

was equal to one-half the quantitation limit provided; and

• If the plant did not provide a quantitation limit, EPA assumed the concentration was 

equal to the method detection limit.

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 

type. EPA then used the average plant-level combustion residual landfill to calculate the average 

concentrations across all plants. Table 6-10 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 7.4, 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, 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.

Table 10-8. Average Pollutant Concentrations Untreated Landfill Leachate

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
Section 10 - Pollutant Loadings and Removals

10-21 

Table 10-8. Average Pollutant Concentrations Untreated Landfill Leachate

Analyte Unit

Untreated Active Landfill 

Concentration

Untreated Inactive 

Landfill Concentration

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

Titanium ug/L 17 15

Vanadium ug/L 3,240 6.2

Zinc ug/L 154 58

Source: Steam Electric Survey [ERG, 2013].

Note: Concentrations are rounded to three significant figures.

10.3 WASTEWATER FLOW RATES FOR BASELINE AND POST-COMPLIANCE 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. This section provides more detail on EPA’s methodology for calculating 

the specific wastewater flow rates used in the loadings calculations.
Section 10 - Pollutant Loadings and Removals

10-22 

10.3.1 FGD Wastewater Flow Rates for Pollutant Loadings 

As described in Section 9, EPA used plant-level FGD wastewater flow rates to calculate 

compliance costs. EPA used the same FGD wastewater flow rates in both the FGD wastewater 

technology cost modules and the FGD wastewater loadings to ensure consistency between the 

two estimates.

10.3.2 Ash Transport Water Flow Rates for Pollutant Loadings 

EPA used data from the Steam Electric Survey to identify those plants that discharge or 

have the potential to discharge fly ash or bottom ash transport water. Based on the amount of ash 

transport water discharged, EPA calculated ash impoundment discharge loadings for each of 

these plants. EPA first identified all impoundments with ash transport water as an influent stream

and an effluent stream that discharges to a surface water or POTW.96 For each impoundment 

included in its analysis, EPA identified the flow rate associated with the fly ash transport water, 

bottom ash transport water, or combined ash transport water. EPA used the following hierarchy 

to determine the ash transport water flow rates:97

• Influent flow rates to the impoundments reported in the pond/impoundment systems 

section of the Steam Electric Survey;

• Ash transport water flow rates reported in the ash handling section of the survey; or 

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

outfall flow rate reported in the general power plant operations section of the survey. 

Because most generating units/ash handling systems do not operate 365 days per year, 

EPA normalized the ash impoundment discharge flow rates. To do this, EPA calculated the 

amount of ash transport water transferred to each ash impoundment per year by multiplying the 

flow rate by the number of days the ash transport water is generated or transferred to the 

impoundment, depending on which source is being used. EPA divided this yearly ash transport 

water flow by 365 days per year to calculate a flow rate in gallons per day (gpd) for use in 

loadings calculations. Using these normalized ash impoundment discharge flow rates, EPA 

calculated plant-level ash impoundment discharge flow rates for each of the three possible types 

(fly, bottom, and combined) of ash transport waters. 

The ash transport water flow rates used for the loadings analysis is not the same data used 

to estimate compliance costs for plants to eliminate fly ash or bottom ash transport water. 

Compliance costs are based on the amount of fly ash or bottom ash generated by specific 

generating units while baseline and post-compliance loadings are based on the flow rate of ash 

transport water.

 

96 As defined in the Steam Electric Survey, impoundments refer to a system of one or more surface impoundments.

97 The Incremental Costs and Pollutant Removals for Proposed Effluent Limitation Guidelines and Standards for the 

Steam Electric Generating Point Source Category Report provides more specific detail on the specifics of this 

hierarchy and EPA’s methodology for generating impoundment-specific ash impoundment discharge flow rates 

[U.S. EPA, 2013].
Section 10 - Pollutant Loadings and Removals

10-23 

10.3.3 Combustion Residual Landfill Leachate Flow Rates for Pollutant Loadings 

As described in Section 9, EPA used plant-level landfill leachate flow rates to calculate 

compliance costs. EPA used the same landfill leachate flow rates in both the leachate technology 

cost modules and the leachate loadings to ensure consistency between the two estimates. 

10.4 BASELINE AND POST-COMPLIANCE POLLUTANT LOADINGS AND TWPE RESULTS

As discussed in Section 10.1, as applicable, 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. 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 post-compliance loading at the industry level for each wastestream and regulatory 

option. The following section discusses the specific loadings and TWPE calculations for each 

wastestream, each of the technology options being considered, and each of the regulatory options 

evaluated by EPA. The section also presents the industry-level loadings for each wastestream 

and regulatory option. 

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 two plants transferring FGD wastewater to a 

POTW. For these two plants, EPA adjusted the baseline loadings to account for pollutant 

removals associated with POTW treatment.

For the post-compliance loadings associated with the one-stage chemical precipitation 

technology option, EPA assumed the discharge loadings calculated for plants currently treating 

their FGD wastewater with a one-stage chemical precipitation system, a biological treatment 

system, or a vapor-compression evaporation system remain unchanged from baseline. EPA 

assumed plants with a baseline surface impoundment would install a one-stage chemical 

precipitation treatment system 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 10-4, 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 is not 

equivalent to the technology basis. This underestimates the pollutant removals being achieved by 

the treatment system because EPA calculates no removals for these plants, even though some of 
Section 10 - Pollutant Loadings and Removals

10-24 

these plants are being assessed compliance costs to upgrade the system to operate similarly to the 

technology basis. 

For the post-compliance pollutant loadings associated with the one-stage chemical 

precipitation treatment system followed by biological treatment technology option, EPA 

assumed the post-compliance loadings calculated for plants currently treating their FGD 

wastewater with a biological treatment system or a vapor-compression evaporation system 

remain unchanged from baseline. EPA assumed plants with a surface impoundment would install 

a one-stage chemical precipitation system with biological treatment and plants with a one-stage 

chemical precipitation system (but no biological treatment for selenium removal) would install a 

biological treatment system 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 10-5, 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 

the post-compliance loadings calculated for plants currently treating their FGD wastewater with 

this type of system remain unchanged from baseline. EPA assumed plants with any other current 

treatment method (i.e., surface impoundment, chemical precipitation, or biological treatment) 

would install a one-stage chemical precipitation treatment system with vapor-compression 

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 vapor-compression evaporation, 

presented in Table 10-6, and plant-specific FGD wastewater flow rates.

Table 10-9 presents the FGD wastewater loadings at an industry level for baseline and 

each post-compliance technology basis. The loadings presented in Table 10-9 are based on the 

oil-fired units and those units with a generating capacity of 50 MW or less not needing to install 

the technology basis because they already meet the new BAT limitations (which are based on the 

current BPT requirements for these units). The loadings also exclude the pollutant parameters 

biochemical oxygen demand (BOD), chemical oxygen demand (COD), total dissolved solids 

(TDS), and TSS to avoid double counting the loadings for other specific pollutants. The table 

includes the number of plants identified as discharging FGD wastewater, the total industry 

discharge flow rate associated with each technology option, and the total industry loading in 

pounds per year and TWPE per year. Table 10-10 presents the pollutant removals, in both 

pounds per year and TWPE per year, for the various technology options. EPA calculates the 

pollutant removals by subtracting the post-compliance loadings from the baseline loadings. The 

loadings for all units installing the technology basis, including the oil-fired units and small units 

(i.e., 50 MW or less generating capacity), are presented in EPA’s Incremental Costs and 

Pollutant Removals for Proposed Effluent Limitation Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category Report [U.S. EPA, 2013]. 
Section 10 - Pollutant Loadings and Removals

10-25 

Table 10-9. Industry-Level FGD Wastewater Loadings Excluding BOD, COD, TDS, and 

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

Basis

Technology Option

Number of 

Plants

Total Industry

Discharge Flow

(MGD)

Total Industry Loading

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 2,080,000,000 411,000

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.

Table 10-10. FGD Wastewater Pollutant 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

Reduction (Baseline –> One-Stage Chemical Precipitation) -417,000,000a 1,530,000

Reduction (Baseline –> One-Stage Chemical Precipitation with 

Biological Treatment)

1,160,000,000 2,620,000

Reduction (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 10-9 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.

EPA also estimated the industry-level post-compliance loadings for the one-stage 

chemical precipitation with biological treatment option for the scenario based on oil-fired units 

and plants with a total plant-level wet scrubbed capacity of less than 2,000 MW not installing the 

technology basis, which is associated with Regulatory Option 3b. Based on this scenario, there 

are only 17 plants would be expected to install the technology basis; therefore, EPA calculated 

the post-compliance loadings for each plant by applying the FGD biological treatment effluent 

concentrations to those 17 plants and the FGD baseline concentrations to the remaining 100 

plants. Table 10-11 presents the FGD wastewater loadings at an industry level for this postcompliance scenario. The loadings presented in Table 10-11 exclude the pollutant parameters 

BOD, COD, TDS, and TSS to avoid double counting the loadings for other specific pollutants. 

The table includes the number of plants identified as discharging FGD wastewater, the total 

industry discharge flow rate associated with the scenario, and the total industry loading in 

pounds per year and TWPE per year. Table 10-12 presents the pollutant removals, in both 
Section 10 - Pollutant Loadings and Removals

10-26 

pounds per year and TWPE per year, for the scenario. EPA calculates the pollutant removals by 

subtracting the post-compliance loadings from the baseline loadings. 

Table 10-11. Industry-Level FGD Wastewater Loadings Excluding BOD, COD, TDS, and 

TSS and Based on Oil-Fired Units and Plants with a Total Wet Scrubbed Capacity of Less 

Than 2,000 MW Not Installing Technology Basis

Technology Option

Number of 

Plants

Total Industry

Discharge Flow

(MGD)

Total Industry Loading

Pounds/Year TWPE/Year

One-Stage Chemical Precipitation 

with Biological Treatment

117 59.1 2,790,000,000 2,120,000

Note: Excludes loadings for BOD, COD, TSS and TDS.

Note: Loadings are rounded to three significant figures.

Table 10-12. FGD Wastewater Pollutant Removals Based on Oil-Fired Units and Plants 

with a Total Wet Scrubbed Capacity of Less Than 2,000 MW Not Installing Technology 

Basis

Technology Option

Total Industry Pollutant Removals

Pounds/Year TWPE/Year

Reduction (Baseline –> One-Stage Chemical Precipitation with 

Biological Treatment)

446,000,000 908,000

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 10-9 and Table 10-11 due to rounding.

10.4.2 Ash Transport Water Loadings and TWPE 

EPA calculated plant-specific loadings for the baseline discharges and technology option 

considered for ash transport water. For baseline loadings, EPA multiplied the plant-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 two plants transferring bottom ash transport water to a POTW. For these two 

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 ponds 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 
Section 10 - Pollutant Loadings and Removals

10-27 

into fly ash loadings and bottom ash loadings. To do this, EPA used data from the EPRI PISCES 

reports to estimate the breakout of the loadings among fly ash and bottom ash contributions. The 

PISCES reports include information from several plants operating impoundments receiving 

either fly ash or bottom ash transport water. The reports include a table presenting loadings 

associated with each stream entering the impoundment for several metal pollutants. EPA used 

the fly ash and bottom ash loadings presented in the reports to calculate a site-specific percent 

loading for fly ash and bottom ash for each pollutant. EPA then calculated an average percent 

loading for fly ash and bottom ash using data from all available pollutants. EPA determined that, 

on average, pollutant contributions from fly ash account for 86 percent of combined ash 

loadings, with bottom ash contributing only 14 percent. Therefore, EPA assumed fly ash and 

bottom ash account for 86 and 14 percent, respectively, of all combined ash loadings for those 

pollutants for which a specific value could not be calculated using the EPRI data, EPA then used 

these percentages to break out the combined ash loadings into associated fly ash and bottom ash 

loadings. After separating the loadings into fly ash and bottom ash components, EPA calculated 

total fly ash and bottom ash transport water baseline loadings for each plant. 

For both fly ash and bottom ash transport water, EPA is considering only one technology 

option: conversion to dry or closed-loop recycle ash handling. 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 system (i.e., zero discharge) 

or will convert to dry bottom ash handling, resulting in post-compliance loadings of zero for fly 

ash and bottom ash transport water pollutants for those plants subject to the proposed 

requirements.

Table 10-13 presents the results of the baseline and post-compliance 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 10-13 exclude the pollutant parameters BOD, COD, TDS, and TSS 

to avoid double counting the loadings for other specific pollutants. Table 10-14 presents the 

pollutant removals, in both pounds per year and TWPE per year, between the baseline and the 

dry or closed-loop recycle handling technology option. The pollutant removals are based on the 

oil-fired units and those units with a generating capacity of 50 MW or less not needing to install 

the technology basis because they already meet the new BAT limitations (which are based on the 

current BPT requirements for these units). EPA calculates the pollutant removals by subtracting 

the post-compliance loadings from the baseline loadings. The pollutant removals for all units 

installing the technology basis, including the oil-fired units and small units (i.e., 50 MW or less 

generating capacity), are presented in EPA’s Incremental Costs and Pollutant Removals for 

Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category Report [U.S. EPA, 2013]. 
Section 10 - Pollutant Loadings and Removals

10-28 

Table 10-13. Industry-Level Ash Impoundment Loadings by Type of Impoundment 

Excluding BOD, COD, TDS, and TSS

Type of Ash 

Impoundment

Number of 

Impoundments

Total Baseline 

Industry

Discharge Flow

(MGD)

Total Industry Baseline 

Loading

Total Industry PostCompliance Loading

Pounds/Year TWPE/Year Pounds/Year TWPE/Year

Fly Ash

Fly Ash Pond 16 61.7 237,000,000 688,000 3,800,000 11,000

Combined Ash 

Pondb 

80 262a 241,000,000 1,830,000 2,950,000 22,500

Bottom Ash

Bottom Ash 

Pond

174 327 1,660,000,000 2,420,000 5,100,000 7,290

Combined Ash 

Pondb 

80 262a 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 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.

b – The combined ash pond loadings were calculated based on the data used in the loadings calculation, but then the 

total combined ash pond loadings were split between fly ash and bottom ash based the EPRI data, described in this 

section.

Table 10-14. 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 

Impoundment Technology Option

Total Industry Pollutant Removals

Pounds/Year TWPE/Year

Fly Ash Reduction (Baseline –> Technology Option) 471,000,000 2,490,000

Bottom Ash Reduction (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 10-13 due to rounding.

EPA also estimated the industry-level pollutant loadings for plants to convert only the 

generating units that are greater than 400 MW to dry or closed-loop recycle bottom ash handling 

systems. However, EPA used a different approach to estimate the plant-level loadings for this 

analysis. For those plants with all generating units with a nameplate capacity of 400 MW or less, 

EPA assumed that the post-compliance loadings would be equal to the baseline loadings and for 

those plants with all generating units with a nameplate capacity greater than 400 MW, EPA 

assumed that the post-compliance loadings would be zero (as was done for Options 4 and 5). For 

those plants that have at least one generating unit with a nameplate capacity of 400 MW or less 

and at least one other generating unit with a nameplate capacity of greater than 400 MW, EPA 

approximated the plant-level bottom ash pollutant removals. To perform this approximation, 
Section 10 - Pollutant Loadings and Removals

10-29 

EPA calculated a plant-level bottom ash adjustment factor based on the amount of bottom ash 

generated by the generating units expected to incur compliance costs with a nameplate capacity 

greater than 400 MW compared to the total amount of bottom ash generated at the plant for those 

generating units expected to incur compliance costs (excluding the generating units with a 

nameplate capacity of 50 MW or less). This is the same adjustment factor that was calculated for 

the bottom ash compliance costs for Option 4a, described in Section 9.7.3. EPA then multiplied 

the bottom ash adjustment factors by the plant-level bottom ash pollutant removals calculated 

based on all generating units (other than oil-fired units) with a nameplate capacity greater than 

50 MW to estimate the bottom ash pollutant removals for this analysis. For more details on how 

EPA estimated these plant-level bottom ash pollutant removals, see the memorandum entitled 

“Memorandum to the Rulemaking Record: Methodologies for Estimating Costs and Pollutant 

Removals for Steam Electric ELG Regulatory Option 4a” (DCN SE03834). 

Table 10-15 presents the pollutant removals, in both pounds per year and TWPE per year, 

between the baseline and the dry or closed-loop recycle handling technology option associated 

with Regulatory Option 4a. The pollutant removals are based on the oil-fired units and those 

units with a generating capacity of 400 MW or less not needing to install the technology basis 

because they already meet the new BAT limitations (which are based on the current BPT 

requirements for these units). EPA calculates the pollutant removals by subtracting the postcompliance loadings from the baseline loadings.

Table 10-15. Bottom Ash Pollutant Removals Based on Oil-Fired Units and Units 400 

MW or Less Not Installing Technology Basis

Type of Ash 

Impoundment Technology Option

Total Industry Pollutant Removals

Pounds/Year TWPE/Year

Bottom Ash Reduction (Baseline –> Technology Option) 991,000,000 1,570,000

Note: Excludes loadings for BOD, COD, TSS, and TDS.

Note: Removals are rounded to three significant figures. 

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 that 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. EPA calculated discharge loadings for these plants 

using the average concentration data set associated with one-stage chemical precipitation 

systems, presented in Section 10.2.3, and plant-specific leachate flow rates.
Section 10 - Pollutant Loadings and Removals

For the one-stage chemical precipitation treatment system with biological treatment 

technology option, EPA assumed that all plants would install that 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.

Table 10-16 presents the combustion residual landfill leachate loadings at an industry 

level for baseline and each post-compliance technology basis. The loadings presented in Table 

10-16 are based on the oil-fired units and those units with a generating capacity of 50 MW or 

less not needing to install the technology basis because they already meet the new BAT 

limitations (which are based on the current BPT requirements for these units). The loadings also 

exclude the pollutant parameters BOD, COD, TDS, and TSS to avoid double counting the 

loadings for other specific pollutants. Included in the table is the number of plants discharging 

combustion residual landfill leachate, the total industry flow rate associated with each 

technology option, and the total industry loading in pounds per year and TWPE per year. Table 

10-17 presents the pollutant removals, in both pounds per year and TWPE per year, for the 

various technology options. EPA calculated the pollutant removals by subtracting the postcompliance loadings from the baseline loadings. The loadings for all units installing the 

technology basis, including the oil-fired units and small units (i.e., 50 MW or less generating 

capacity), are presented in EPA’s Incremental Costs and Pollutant Removals for Proposed 

Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category Report [U.S. EPA, 2013].

10-30 

Table 10-16. Industry-Level Combustion Residual Landfill Leachate Loadings Excluding 

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

Installing Technology Basis

Technology Option

Number of 

Plants

Total Industry

Discharge Flow

(MGD) 

Total Industry Loading

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.
 

 

 

 

 

 

 

 

 

 

 

 

 

Section 10 - Pollutant Loadings and Removals 

Table 10-17. Combustion Residual Landfill Leachate Pollutant 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 

Reduction (Baseline –> One-Stage Chemical Precipitation) 8,900,000 35,600 

Reduction (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 10-16 due to rounding. 

10.4.4 Pollutant Loadings and Removals for Regulatory Options 

As described in Section 8, EPA evaluated eight regulatory options comprised of various 

combinations of the technology options considered for each wastestream. EPA estimated the 

pollutant removals associated with steam electric power plants to achieve compliance for each 

regulatory option under consideration. Table 10-18 presents the total industry loadings and 

pollutant removals at baseline and for each of the eight regulatory options. The loadings and 

TWPE values presented in these tables exclude pollutant parameters BOD, COD, TDS, and TSS. 

The table presents the estimated loadings and pollutant removals based on the oil-fired units and 

units with a capacity of 50 MW or less not needing to install the appropriate technology bases.98 

The loadings and pollutant removals for all units installing the technology basis, including the 

oil-fired units and small units (i.e., 50 MW or less generating capacity), are presented in EPA’s 

Incremental Costs and Pollutant Removals for Proposed Effluent Limitation Guidelines and 

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

2013]. The pollutant-level baseline loadings and pollutant-level removals for each regulatory 

option by wastestream are presented in the memorandum entitled, “Steam Electric PollutantLevel Loadings and Removals for Each Wastestream and Regulatory Option” (DCN SE03970). 

Table 10-18. 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 Loading Total Industry Pollutant Removals 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 

3a 5,030,000,000 5,830,000 471,000,000 2,490,000 

2 4,350,000,000 5,710,000 1,160,000,000 2,620,000 

3b 4,590,000,000 4,920,000 916,000,000 3,400,000 

98 Except for Regulatory Options 4a and 3b. For Regulatory Option 4a, the bottom ash estimated loadings and 

pollutant removals are based on the oil-fired units and units with a capacity of 400 MW or less not needing to install 

the appropriate technology bases. For Regulatory Option 3b, the FGD wastewater estimated loadings and pollutant 

removals are based on the oil-fired units and plants with a total wet scrubbed capacity of less than 2,000 MW not 

needing to install the appropriate technology bases. 

10-31
 
 

 

 

 

 

 

 

Section 10 - Pollutant Loadings and Removals 

Table 10-18. 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 Loading Total Industry Pollutant Removals a 

Pounds/Year TWPE/Year Pounds/Year TWPE/Year 

3 3,880,000,000 3,220,000 1,630,000,000 5,100,000 

4a 2,870,000,000 1,640,000 2,620,000,000 6,680,000 

4 2,160,000,000 474,000 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: Removals are rounded to three significant figures. The removals may not equal the sum of the removals 

presented in the tables in this section from the various wastestreams 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. 

10.5 REFERENCES 

1.	 Duke Energy. 2011a. Industry Provided Sampling Data from Duke Energy’s Belews 

Creek Steam Station. (17 August). DCN SE01808. 

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 SE02931. 

5.	 Eastern Research Group, Inc. (ERG). 2008. Final Sampling Episode Report, Buckeye 

Power Company’s Cardinal Power Plant. (26 August). DCN SE02107. 

6.	 Eastern Research Group (ERG). 2012a. Final Sampling Episode Report, Duke Energy 

Carolinas’ Belews Creek Steam Station. (13 March). DCN SE01305. 

7.	 Eastern Research Group (ERG). 2012b. Final Sampling Episode Report, We Energies’ 

Pleasant Prairie Power Plant. (13 March). DCN SE01306. 

8.	 Eastern Research Group (ERG). 2012c. Final Sampling Episode Report, Duke Energy 

Miami Fort Station. (13 March). DCN SE01304. 

9.	 Eastern Research Group (ERG). 2012d. Final Sampling Episode Report, Duke Energy 

Carolinas’ Allen Steam Station. (13 March). DCN SE01307. 

10. Eastern Research Group (ERG). 2012e. Final Sampling Episode Report, Mirant MidAtlantic, LLC’s Dickerson Generating Station. (13 March). DCN SE01308. 

10-32
 
Section 10 - Pollutant Loadings and Removals

11. Eastern Research Group (ERG). 2012f. Final Sampling Episode Report, Allegheny 

Energy’s Hatfield’s Ferry Power Station. (13 March). DCN SE01310. 

12. Eastern Research Group (ERG). 2012g. Final Sampling Episode Report, RRI Energy’s 

Keystone Generating Station. (13 March). DCN SE01309. 

13. Eastern Research Group (ERG). 2012h. Final Sampling Episode Report and Site Visit 

Notes, Enel’s Federico II Power Plant (Brindisi). (8 August). DCN SE02013. 

14. 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. 

15. Eastern Research Group (ERG). 2013. Steam Electric Technical Questionnaire Database 

(“Steam Electric Survey”). (19 April). DCN SE01958. 

16. Electric Power Research Institute (EPRI). 1997 - 2001. PISCES Water Characterization 

Field Study, Sites A-G. Palo Alto, CA. DCN SE01818 through SE01823. 

17. NCDENR. 2011. North Carolina Department of Environment and Natural Resources 

(NCDENR). State Provided Sampling Data from North Carolina’s Progress Energy 

Roxboro Plant. (26 June). DCN SE01812. 

18. Utility Water Act Group (UWAG). 2008. Form 2C Effluent Guidelines Database. (30 

June). DCNs SE02918 and SE02918A1. 

19. 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 SE02933. 

20. U.S. EPA. 2013. Incremental Costs and Pollutant Removals for Proposed Effluent 

Limitation Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category Report. (19 April). DCN SE01957. 

10-33 
Section 11 - Pollutants Selected for Regulation

11-1 

SECTION 11

POLLUTANTS SELECTED FOR REGULATION

This section describes the selection of regulated pollutants for each wastestream for 

which EPA evaluated new or revised discharge requirements in the Steam Electric ELGs. 

Regulated pollutants are pollutants for which EPA proposes to establish numerical effluent 

limitations and standards. This section describes the methodology and rationale EPA used to 

select the subset of regulated pollutant parameters from the list of pollutants of concern (POC) 

for each wastestream.

11.1 SELECTION OF REGULATED POLLUTANT FOR DIRECT DISCHARGERS

The list of POCs for each wastestream represents those pollutants that are present at 

treatable concentrations in a significant percentage of untreated wastewater samples from that 

wastestream; the selection of POCs for each wastestream is presented in Section 6.7 of this 

document. Effluent monitoring for all POCs is not necessary to ensure that steam electric 

wastewater pollution is adequately controlled because many of the pollutants originate from 

similar sources, have similar treatabilities, are removed by similar mechanisms, and are treated to 

similar concentrations. Therefore, it may be sufficient to monitor for one pollutant as a surrogate 

or indicator of several others. 

From the POC list for each wastestream, EPA selected a subset of pollutants for 

establishing numerical effluent limitations. EPA considered the following factors in selecting 

regulated pollutants from the list of POCs for each subcategory: 

• The pollutant was detected in the untreated wastewater at the BAT plant(s) at 

treatable levels in a significant number of samples. This was the same methodology 

used to identify the POCs, as described in Section 6.7. 

• The pollutant is not used as a treatment chemical in the treatment technology that 

serves as a basis for the proposed regulatory option. EPA excluded pollutants that 

may serve as treatment system additives: aluminum, calcium, iron, sodium, and 

phosphorus. EPA eliminated these pollutants because regulating these pollutants 

could interfere with efforts to optimize treatment system operation.

• The pollutant is effectively treated by the treatment technology that serves as the 

basis for the proposed regulatory option. EPA excluded pollutants for which the 

treatment technology was ineffective (i.e., pollutant concentrations remained 

approximately unchanged or increased across the treatment system).

• The pollutant is not adequately controlled through the regulation of another pollutant. 

• The following subsections describe EPA’s pollutant selection analysis for each 

wastestream.

11.1.1 FGD Wastewater 

EPA proposes establishing BAT and NSPS limitations and standards for FGD wastewater 

for four pollutants: arsenic, mercury, nitrate/nitrite, and selenium. These limitations and 
Section 11 - Pollutants Selected for Regulation

11-2 

standards are based on a one-stage chemical precipitation system followed by anoxic/anaerobic 

biological treatment, as described in Section 13.8. The regulated pollutant selection criteria 

matrix for the 35 POCs considered for regulation for FGD wastewater is illustrated in Table 

11-1. The following discussion explains the rationale used to select which of the 35 POCs to 

regulate at BAT/NSPS for the preferred options. 

• Conventional Pollutants: EPA identified oil and grease (O&G) and total suspended 

solids (TSS) as POCs. TSS and O&G are adequately controlled by existing BPT 

limitations.

• Treatment Chemicals: EPA identified and eliminated five POCs that are also used as 

treatment chemicals: aluminum, calcium, iron, sodium, and phosphorus. 

• Pollutants Not Effectively Treated by the Proposed BAT/NSPS Technology: EPA 

eliminated eight pollutants, ammonia, boron, chloride, COD, cyanide, sulfate, TDS, 

and TKN, because the technology option associated with the preferred options is not 

designed to achieve consistent effluent concentrations of these pollutants. 

• Pollutants Directly Regulated or Controlled by Regulation of Other Pollutants: The 

remaining pollutants are metals and nitrate/nitrite. As described in Section 7, 

chemical precipitation systems use chemicals to alter the physical state of dissolved 

and suspended solids to help settle and remove solids from the wastewater. The 

metals present in the wastewater form insoluble hydroxides and/or sulfide complexes. 

The solubilities of these complexes vary by pH, therefore, specific pHs can be 

targeted to remove specific metals. But in this process, most metals are precipitated to 

at least some degree, thereby resulting in the removal of a wide range of metals. 

EPA’s design basis for the BAT system uses both hydroxide and sulfide precipitation, 

as well as iron coprecipitation. EPA selected arsenic and mercury as regulated 

pollutants and as indicators of effective removals of many other metal pollutants of 

concern present in FGD wastewater, such as cadmium and chromium. While most 

metals can be removed to low levels using chemical precipitation alone, selenium 

requires additional treatment to achieve consistent removals. Therefore, EPA also 

selected selenium and nitrate/nitrite for regulation.
11-3

Section 11 - Pollutants Selected for Regulation

Table 11-1. Pollutants Considered for Regulation for Direct Dischargers (BAT/NSPS): FGD Wastewater

Pollutant Group Pollutant of Concern Treatment Chemical

Not Effectively Treated by 

the Proposed BAT/NSPS 

Technology

Directly Regulated or 

Controlled by Regulation of 

Another Parameter

Conventional

Oil and Grease 

Total Suspended Solids 

Priority Pollutants

Antimony 

Arsenic 

Beryllium 

Cadmium 

Chromium 

Copper 

Cyanide 

Lead 

Mercury 

Nickel 

Selenium 

Thallium 

Zinc 

Nonconventional

Aluminum 

Ammonia 

Barium 

Boron 

Calcium 

Chemical Oxygen Demand 

Chloride 

Cobalt 

Iron 

Magnesium 
11-4

Section 11 - Pollutants Selected for Regulation

Table 11-1. Pollutants Considered for Regulation for Direct Dischargers (BAT/NSPS): FGD Wastewater

Pollutant Group Pollutant of Concern Treatment Chemical

Not Effectively Treated by 

the Proposed BAT/NSPS 

Technology

Directly Regulated or 

Controlled by Regulation of 

Another Parameter

Nonconventional

Manganese 

Molybdenum 

Nitrate/Nitrite 

Nitrogen, Kjeldahl 

Phosphorus 

Sodium 

Sulfate 

Titanium 

Total Dissolved Solids 

Vanadium 
Section 11 - Pollutants Selected for Regulation

11-5 

11.1.2 Fly Ash Transport Water 

EPA proposes establishing BAT limitations requiring no discharge of wastewater 

pollutants from fly ash transport water for each of the preferred regulatory options (i.e., Option 

3a, 3b, 3, and 4a). Additionally, the same standard was already set for NSPS as part of the 1982 

revisions to the ELGs. Therefore, the Agency did not apply its pollutant selection methodology 

to this wastestream. All pollutants of concern would be regulated and removed by the preferred 

options. 

11.1.3 Bottom Ash Transport Water

EPA proposes establishing BAT limitations equal to the current BPT limitations for 

bottom ash transport water under Regulatory Options 3a, 3b, and 3. Under Regulatory Option 4a, 

EPA proposes establishing BAT limitations requiring no discharge of wastewater pollutants from 

bottom ash transport water for generating units with a nameplate capacity greater than 400 MW, 

while EPA is proposing to establish BAT limitations equal to the current BPT limitations for 

bottom ash transport water for all generating units with a nameplate capacity of 400 MW or less. 

EPA also proposes establishing NSPS standards requiring no discharge of wastewater pollutants 

from bottom ash transport water. Therefore, because either all pollutants are regulated 

(Regulatory Option 4a for generating units with a nameplate capacity of greater than 400 MW) 

or the pollutants selected are the same as those regulated under BPT (Regulatory Options 3a, 3b, 

3, and 4a for generating units with a nameplate capacity of 400 MW or less), the Agency did not 

apply its pollutant selection methodology to this wastestream.

11.1.4 Combustion Residual Leachate

EPA proposes establishing BAT limitations for combustion residual leachate equal to the 

current BPT limitations for low volume waste sources under a preferred regulatory options. EPA 

is proposing to establish NSPS limitations for arsenic and mercury. These NSPS limitations are 

based on a one-stage chemical precipitation system. The regulated pollutant selection criteria 

matrix for the 16 POCs considered for regulation for combustion residual leachate is illustrated 

in Table 11-2. The following discussion explains the rationale used to select which of the 16 

POCs to regulate at NSPS (based on Regulatory Option 4).99

• Conventional Pollutants: EPA identified O&G and TSS as POCs. TSS and O&G are 

adequately controlled by existing BPT limitations.

• Treatment Chemicals: EPA identified and eliminated four POCs that are also used as 

treatment chemicals: aluminum, calcium, iron, and sodium.

• Pollutants Not Effectively Treated by the Proposed NSPS Technology: EPA 

eliminated five pollutants, boron, chloride, selenium, sulfate, and total dissolved 

solids, because the technology option associated with Regulatory Option 4 is not 

designed to achieve consistent effluent concentrations of these pollutants. 

• Pollutants Directly Regulated or Controlled by Regulation of Other Pollutants: The 

remaining pollutants of concern are all metals. As explained above for FGD 

 

99 These are also the 16 POCs that would be considered for regulation under BAT Options 4 and 5.
Section 11 - Pollutants Selected for Regulation

11-6 

wastewater, chemical precipitation is effective at removing metals present in 

wastewater, especially when both hydroxide and sulfide precipitation mechanisms are 

employed, which is part of the basis for the technology option. EPA selected arsenic 

and mercury as regulated pollutants and as indicators of effective removals of many 

other metal pollutants of concern present in combustion residual leachate, such as 

magnesium and manganese.

11.1.5 Gasification Wastewater 

For gasification wastewater, EPA is proposing to establish BAT and NSPS limitations 

and standards for four pollutants: arsenic, mercury, selenium, and TDS. These limitations and 

standards are based on a vapor-compression evaporation system for direct dischargers. The 

regulated pollutant selection criteria matrix for the 20 POCs considered for regulation for 

gasification wastewater is illustrated in Table 11-3. The following discussion explains the 

rationale used to select which of the 20 POCs to regulate at BAT/NSPS. 

• Conventional Pollutants: EPA identified BOD5 as a POC. BOD is not subject to BAT 

limitations.

• Pollutants Not Effectively Treated by the Proposed BAT/NSPS Technology: EPA 

eliminated five pollutants, ammonia, COD, cyanide, nitrate/nitrite, and TKN, because 

the technology option associated with the preferred options is not designed to achieve 

consistent effluent concentrations of these pollutants. 

• Pollutants Directly Regulated or Controlled by Regulation of Other Pollutants: The 

remaining pollutants are metals and salt ions (i.e., chloride and sulfate). As described 

in Section 7, the vapor-compression evaporation system uses steam to evaporate the 

water from the wastewater, producing a distillate stream and a solid residual 

byproduct (i.e., crystallized salts). The removal of metals from this system will 

depend on the volatility of the metals because the more volatile the metal, the greater 

amount that will be carried over into the distillate stream. Therefore, EPA selected 

three metals, arsenic, mercury, and selenium to represent different volatilities of 

metals and act as indicator pollutants for other metals. EPA also selected TDS for 

regulation as an indicator of pollutants (e.g., sodium, chloride) present in the 

wastewater.

11.1.6 Flue Gas Mercury Control Wastewater

EPA proposes establishing BAT limitations requiring no discharge of wastewater 

pollutants from FGMC wastewater. EPA also proposes establishing NSPS standards requiring no 

discharge of wastewater pollutants from FGMC wastewater for NSPS. Therefore, the Agency did 

not apply its pollutant selection methodology to this wastestream. All pollutants of concern 

would be regulated and removed by the preferred options. 

11.1.7 Nonchemical Metal Cleaning Wastes 

EPA proposes establishing BAT limitations for nonchemical metal cleaning wastes for 

two pollutants, copper and iron. EPA is also proposing to establish NSPS limitations for 

nonchemical metal cleaning wastes for TSS, O&G, copper, and iron. These limitations and 
Section 11 - Pollutants Selected for Regulation

11-7 

standards are based on the current BPT limitations for metal cleaning wastes. Because the 

limitations and standards are based on the existing BPT limitations, the pollutants for regulation 

are already identified, and therefore, EPA did not apply its pollutant selection methodology to 

this wastestream.
11-8

Section 11 - Pollutants Selected for Regulation

Table 11-2. Pollutants Considered for Regulation for Direct Dischargers (BAT/NSPS): Combustion Residual Leachate

Pollutant Group Pollutant of Concern Treatment Chemical

Not Effectively Treated by 

the Proposed BAT/NSPS 

Technology

Directly Regulated or 

Controlled by Regulation of 

Another Parameter

Conventional Pollutants

Oil and Grease 

Total Suspended Solids 

Priority Pollutants

Arsenic 

Mercury 

Selenium 

Nonconventional Pollutants

Aluminum 

Boron 

Calcium 

Chloride 

Iron 

Magnesium 

Manganese 

Molybdenum 

Sodium 

Sulfate 

Total Dissolved Solids 
11-9

Section 11 - Pollutants Selected for Regulation

Table 11-3. Pollutants Considered for Regulation for Direct Dischargers (BAT/NSPS): Gasification Wastewater

Pollutant Group Pollutant of Concern Treatment Chemical

Not Effectively Treated

by the Proposed 

BAT/NSPS Technology

Directly Regulated or 

Controlled by Regulation 

of Another Parameter

Priority Pollutants

Antimony 

Arsenic 

Cyanide 

Mercury 

Nickel 

Selenium 

Thallium 

Conventional Pollutants Biochemical Oxygen Demand 

Nonconventional Pollutants

Aluminum 

Ammonia 

Boron 

Chemical Oxygen Demand 

Chloride 

Iron 

Manganese 

Nitrate/Nitrite 

Nitrogen, Kjeldahl 

Sodium 

Sulfate 

Total Dissolved Solids 
Section 11 - Pollutants Selected for Regulation

11-10 

11.2 REGULATED POLLUTANT SELECTION METHODOLOGY FOR INDIRECT DISCHARGERS

Unlike direct dischargers whose wastewater will receive no further treatment once it 

leaves the plant, indirect dischargers send their wastewater to publicly-owned treatment works 

(POTWs) for further treatment. However, POTWs typically install secondary biological 

treatment systems that are designed to control conventional pollutants (i.e., BOD, TSS, oil & 

grease (O&G), pH, and fecal coliform), the principal parameters in domestic sewage. Except for 

nutrient control for nitrogen compounds and phosphorus, POTWs usually do not install advanced 

or tertiary treatment technology to control priority and nonconventional pollutants, although 

secondary biological treatment systems may achieve significant removals for some priority 

pollutants. Instead, the Clean Water Act envisions that implementation of pretreatment programs 

and industrial compliance with categorical pretreatment standards will adequately control toxic 

and nonconventional pollutants in municipal effluents. 

Section 307(b) and (c) of the CWA requires EPA to promulgate pretreatment standards 

for pollutants that are not susceptible to treatment by POTWs or which would interfere with the 

operation of POTWs. EPA looks at a number of factors in selecting the technology basis for 

pretreatment standards for existing and new sources. These factors are generally the same as 

those considered in establishing BAT and NSPS, respectively. However, unlike direct 

dischargers whose wastewater will receive no further treatment once it leaves the plant, indirect 

dischargers send their wastewater to POTWs for further treatment. As such, EPA must also 

determine that a pollutant is not susceptible to treatment at a POTW or would interfere with 

POTW operations. 

Therefore, for indirect dischargers, before establishing PSES/PSNS for a pollutant, EPA 

examines whether the pollutant “passes through” a POTW to waters of the U.S. or interferes with 

the POTW operation or sludge disposal practices. In determining whether a pollutant would pass 

though POTWs for PSES/PSNS, EPA generally compares the percentage of a pollutant removed 

by well-operated POTWs performing secondary treatment to the percentage removed by 

BAT/NSPS treatment systems. A pollutant is determined to pass through POTWs when the 

median percentage removed nationwide by well-operated POTWs is less than the median 

percentage removed by direct dischargers complying with BAT/NSPS effluent limitations and 

standards. Pretreatment standards are established for those pollutants regulated under BAT/NSPS 

that pass through POTWs to waters of the U.S. or interfere with POTW operations or sludge 

disposal practices. This approach to the definition of pass-through satisfies two competing 

objectives set by Congress: (1) that standards for indirect dischargers be equivalent to standards 

for direct dischargers, and (2) that the treatment capability and performance of POTWs be 

recognized and taken into account in regulating the discharge of pollutants from indirect 

dischargers.

The POTW pass-through analysis was performed for pollutants selected for regulation for 

direct dischargers for each wastestream of concern. Those pollutants that EPA determines pass 

through POTWs are the pollutants EPA proposes to regulate. The following pollutants were not 

analyzed for pass through even if selected for regulation under BAT/NSPS: biochemical oxygen 

demand (BOD5), TSS, and O&G. POTWs are designed to treat these pollutants; therefore, they 

were not considered to pass through. 
Section 11 - Pollutants Selected for Regulation

11-11 

For the proposed Steam Electric ELGs, EPA is setting limitations for the following 

wastestreams:

• FGD wastewater;

• Fly ash transport water;

• Bottom ash transport water; 

• Combustion residual leachate; 

• Gasification wastewater; 

• Flue gas mercury control wastewater; and

• Nonchemical metal cleaning wastes.

EPA conducted the pass-through analysis for all regulated pollutants for FGD 

wastewater, combustion residual leachate, and gasification wastewater. EPA did not conduct its 

traditional POTW pass-through analysis for fly ash transport water, bottom ash transport water, 

and flue gas mercury control wastewater because limitations for these wastestreams for direct 

dischargers consist of no discharge of process wastewater pollutants to waters of the U.S.100

Because the BAT/NSPS technology options for fly ash transport water, bottom ash transport 

water, and flue gas mercury control wastewater achieve 100 percent removal of all pollutants, 

which is greater than the percent removals by POTWs, EPA determined the pollutants would 

pass through the POTW for these wastestreams.

During the 1976 development of pretreatment standards for chemical metal cleaning 

wastes, EPA selected pollutants for regulation based on two criteria: 

• The pollutant has the potential to harm the POTW (e.g., impair the activity of the 

biological treatment system); or

• The pollutant has the potential to harm the receiving water (i.e., if the pollutant is not 

removed or is removed inadequately by the POTW). 

Using these criteria, the Agency determined it was appropriate to establish pretreatment 

standards for the discharge of copper in chemical metal cleaning wastes. EPA believes that, as is 

the case for copper in chemical metal cleaning wastes, the copper present in nonchemical metal 

cleaning wastes would pass through the POTW. 

The following subsections present the POTW pass-through analysis:

• Methodology for determining BAT percent removals; 

• Methodology for determining POTW percent removals; and 

• Results of the POTW pass-through analysis.

 

100 To ensure standards for indirect dischargers be equivalent to limitations for direct dischargers, EPA similarly 

designates standards for these wastestreams as zero discharge.
Section 11 - Pollutants Selected for Regulation

11-12 

11.2.1 Methodology for Determining BAT Percent Removals 

EPA calculated percent removals for each selected technology option using the data used 

to determine the long-term averages (LTAs) and limitations/standards for the selected BAT or 

NSPS technology option. Therefore, the data used to calculate the treatment option percent 

removals was subjected to the same date editing criteria as the data used to establish the 

limitations/standards. See Section 13. 

1. For each pollutant and each model plant for which EPA had influent and effluent 

data, EPA averaged the influent data and effluent data to obtain a plant-specific 

average influent and effluent concentration, respectively. 

2. EPA calculated percent removals for each pollutant for each model plant from the 

site-specific average influent and effluent concentrations using the following 

equation: 

PercentRemoval = 

AverageInfluentConcentration - AverageEffluentConcentration

AverageInfluentConcentration x 100 

3. If EPA calculated percent removals for multiple model plants for a pollutant, EPA 

used the median percent removal for that pollutant from the plant-specific percent 

removals as the BAT option percent removal.

11.2.2 Methodology for Determining POTW Percent Removals

EPA generally calculated pollutant percent removals at POTWs nationwide from two 

available data sources:

• Fate of Priority Pollutants in Publicly Owned Treatment Works, September 1982, 

EPA 440/1-82/303 (50 POTW Study); and 

• National Risk Management Research Laboratory (NRMRL) Treatability Database, 

Version 5.0, February 2004 (formerly called the Risk Reduction Engineering 

Laboratory (RREL) database).

When available for a pollutant, EPA used data from the 50-POTW Study. For those 

pollutants not covered in the 50 POTW Study, EPA used NRMRL data. The 50 POTW Study 

presents data on the performance of 50 well-operated POTWs that employ secondary treatment 

to remove toxic pollutants. EPA edited the data to minimize the possibility that low POTW 

removals might simply reflect low influent concentrations instead of treatment effectiveness. The 

criteria used in editing the 50-POTW study data for this rule are listed below:

1. Substitute the standardized pollutant-specific analytical ML for values reported as 

“not detected,” “trace,” “less than (followed by a number),” or a number less than the 

standardized minimum analytical detection limit (ML); and
Section 11 - Pollutants Selected for Regulation

11-13 

2. Retain pollutant influent and corresponding effluent values if the average pollutant 

influent level is greater than or equal to 10 times the pollutant ML. 

For each POTW that had data pairs that passed the editing criteria, EPA calculated its 

percent removal for each pollutant using the equation provided above. EPA then used the median 

value of all the POTW pollutant-specific percent removals as the nationwide percent removal in 

its pass-through analysis. For this pass-through analysis, EPA used the 50-POTW study data for 

arsenic and mercury.

The NRMRL database, used to augment the POTW database for the pollutants that the 50 

POTW Study did not cover, is a computerized database that provides information, by pollutant, 

on removals obtained by various treatment technologies. The database provides the user with the 

specific data source and the industry from which the wastewater was generated. For each of the 

pollutants regulated at BAT that were not found in the 50-POTW database (e.g., selenium), EPA 

used data from portions of the NRMRL database. EPA applied the following editing criteria:

1. Only treatment technologies representative of typical POTW secondary treatment 

operations (activated sludge, activated sludge with filtration, aerated lagoons) were 

used; 

2. Only information pertaining to domestic or industrial wastewater were used;

3. Pilot-scale and full-scale data were used, while bench-scale data were eliminated; and

4. Only data from peer-reviewed journals or government reports were used. 

Using the NRMRL pollutant removal data that passed the above criteria, EPA calculated 

the average percent removal for each pollutant. For this pass-through analysis, EPA used the 

NRMRL database for selenium.

Neither source includes pollutant removal data for TDS. Secondary treatment 

technologies are generally understood to be ineffective at removing TDS and as such TDS 

removals at POTWs are likely to be close to zero. For purposes of this pass through analysis, 

EPA assumes the percent removal to be zero [Metcalf & Eddy, 2003].

11.2.3 Results of POTW Pass-Through Analysis 

The following subsections provide the results of EPA’s pass through analyses for FGD 

wastewater, combustion residual leachate, and gasification wastewater using the methodology 

described above. EPA did not conduct its traditional pass-through analysis for fly ash transport 

water, bottom ash transport water, and flue gas mercury control wastewater because limitations 

for these wastestreams for direct dischargers consist of no discharge of process wastewater 

pollutants to waters of the U.S., and therefore, all pollutants “pass through” the POTW for these 

wastestreams.
Section 11 - Pollutants Selected for Regulation

11-14 

FGD Wastewater

The technology basis for PSES and PSNS for FGD discharges is one-stage chemical 

precipitation followed by biological treatment. Table 11-4 presents the treatment technology 

percent removals and POTW removals for FGD wastewater. Because the proposed FGD 

wastewater BAT and NSPS limitations/standards for arsenic and mercury were transferred from 

the one-stage chemical precipitation system, EPA performed the pass-through analysis for 

arsenic and mercury based on the pollutant removals achieved by the one-stage chemical 

precipitation system. All five regulated pollutants were determined to pass through POTW 

secondary treatment and EPA selected them as regulated pollutants for PSES/PSNS. 

Table 11-4. POTW Pass-Through Analysis (FGD Wastewater) – PSES/PSNS

Pollutant

Median BAT % 

Removal POTW % Removal

BAT % Removal > 

POTW % Removal?

Does Pollutant Pass 

Through?

Arsenic 99.5%a 65.8% Yes Yes

Mercury 99.9%a 90.2% Yes Yes

Nitrate, Nitrite as N 99.6% 90.0% Yes Yes

Selenium 99.9% 34.3% Yes Yes

a – The arsenic and mercury BAT percent removals are based on the one-stage chemical precipitation treatment, 

because the proposed BAT effluent limitations were transferred from the one-stage chemical precipitation system.

Combustion Residual Leachate 

The technology basis for PSES and PSNS for combustion residual leachate, under 

Regulatory Options 4 and 5, is chemical precipitation. As explained further in Section 13, EPA is 

transferring the limitations/standards for leachate from the one-stage chemical precipitation 

technology option for FGD wastewater. Therefore, for arsenic and mercury, the technology basis 

percent removals for leachate are based on the removals achieved by the one-stage chemical 

precipitation system for FGD wastewater. Table 11-5 presents the treatment option percent 

removals and POTW removals for combustion residual leachate using the methodology 

described above. Both mercury and arsenic pass through and EPA is proposing them for 

regulation under PSES and PSNS. 

Table 11-5. POTW Pass-Through Analysis (Combustion Residual Leachate) – PSES/PSNS

Pollutant

Median BAT % 

Removal POTW % Removal

BAT % Removal > 

POTW % Removal?

Does Pollutant Pass 

Through?

Arsenic 99.5 %a 65.8% Yes Yes

Mercury 99.9% a 90.2% Yes Yes

a – The arsenic and mercury BAT percent removals are based on FGD wastewater one-stage chemical precipitation 

treatment, because the proposed BAT effluent limitations were transferred from the FGD wastewater one-stage 

chemical precipitation system.
Section 11 - Pollutants Selected for Regulation

11-15 

Gasification Wastewater

The technology option for gasification is vapor-compression evaporation. Table 11-6

presents the technology option percent removals and POTW removals for gasification 

wastewater. All four regulated pollutants were determined to pass through POTW secondary 

treatment and EPA is proposing them for PSES and PSNS. 

Table 11-6. POTW Pass-Through Analysis (Gasification Wastewater) – PSES/PSNS

Pollutant

Median BAT % 

Removal POTW % Removal

BAT % Removal > 

POTW % Removal?

Does Pollutant Pass 

Through?

Arsenic 99.4% 65.8% Yes Yes

Mercury 98.5% 90.2% Yes Yes

Selenium 88.9% 34.3% Yes Yes

TDS 99.7% 0% Yes Yes

11.3 REFERENCES

1. Metcalf & Eddy, Inc. 2003. Wastewater Engineering, Treatment and Reuse, Fourth 

Edition. McGraw-Hill. New York. DCN SE02936. 

2. U.S. EPA. 1976. Supplement for Pretreatment to the Development Document for the 

Steam Electric Power Generating Point Source Category. EPA 440/1-76/084. 

Washington, D.C. (November). DCN SE02935. 
Section 12 - Non-Water Quality Environmental Impacts

12-1 

SECTION 12

NON-WATER QUALITY ENVIRONMENTAL IMPACTS

The elimination or reduction of one form of pollution has the potential to aggravate other 

environmental problems, an effect frequently referred to as cross-media impacts. Sections 304(b) 

and 306 of the Clean Water Act require EPA to consider non-water quality environmental 

impacts (NWQIs), including energy requirements, associated with effluent limitations guidelines 

and standards (ELGs). Accordingly, EPA has considered the potential impacts of the proposed 

regulation on energy consumption, air emissions, and solid waste generation and management.

101

EPA determined that the proposed ELGs have non-water quality environmental impacts 

associated with operations for treating and managing FGD wastewater, combustion residual 

landfill leachate, and ash transport water. However, because all plants generating flue gas 

mercury control wastewater and gasification wastewater currently operate the technologies 

identified as the basis for BAT, EPA does not predict any net increase of energy or fuel usage, 

sludge generation, or air emissions for these wastestreams for the proposed ELGs. Additionally, 

because all plants generating and discharging nonchemical metal cleaning wastes are either 

already meeting the proposed BAT limitations (based on the current BPT standard) or will be 

exempt from the proposed BAT limitations, EPA does not predict any net increase of energy or 

fuel usage, sludge generation, or air emissions for nonchemical metal cleaning wastes for the 

proposed ELGs. As described throughout this section, although the regulatory options will result 

in increases of energy and fuel usage, sludge generation, and air emissions, the increases are 

small compared to national levels of energy/fuel usage, current air emissions from power plants, 

and sludge production from municipal wastewater treatment plants.102

12.1 ENERGY REQUIREMENTS

Steam electric power plants use energy when transporting ash and other solids on or off 

site, operating wastewater treatment systems (e.g., chemical precipitation, biological treatment), 

operating ash handling systems, or operating water trucks for dust suppression. For those plants 

that EPA projected would incur costs to comply with the regulatory options, EPA considered 

whether or not there would be an associated incremental energy need. That need varies 

depending on the regulatory option evaluated and the current operations of the plant. Therefore, 

as applicable, EPA estimated the additional energy usage in megawatt hours (MWh) for 

equipment added to the plant systems or in consumed fuel (gallons) for transportation/operating 

equipment. Similarly, as applicable, EPA also estimated the decrease in energy requirements 

resulting from the reduction in wet sluicing operations and use of earth-moving equipment. EPA 

scaled the plant-specific estimate to calculate the net change in energy requirements for the 

regulatory options for this proposed rulemaking. 

To determine potential increases in electrical energy use, EPA estimated the amount of 

energy needed to operate wastewater treatment systems and ash handling systems. To determine 

 

101 EPA also evaluated the increases of energy and fuel usage, sludge generation, and air emissions for the future 

profile population and new sources. For more information on the NWQI EPA evaluated for future profile and new 

sources, see EPA’s memorandum “Evaluation of NWQI for the Future Profile Population and New Sources” [U.S. 

EPA, 2012b].

102 The proposed regulatory options will also result in decreases of air emissions for certain pollutants.
Section 12 - Non-Water Quality Environmental Impacts

12-2 

potential decreases in electrical energy use, EPA estimated the amount of energy saved from 

reducing wet sluice pumping operations based on the horsepower rating of the pumps. Similarly, 

EPA estimated the amount of energy saved by reducing the number of backhoes needed to 

dredge solids from ash impoundments, resulting from the reduction of wet sluice operations. 

EPA estimated these energy savings using the horsepower rating of the backhoe engine. EPA 

only estimated energy savings associated with earthmoving equipment for plants operating 

surface impoundments. See EPA’s Incremental Costs and Pollutant Removals for Proposed 

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

Source Category for more information on the specific calculations used to estimate energy. [U.S. 

EPA, 2013] Table 12-1 presents the net change in annual electrical energy usage associated with 

the proposed regulation. 

Table 12-1. Industry-Level Energy Requirements by Regulatory Option 

Regulatory Option

Electrical Energy Usage

(MWh/year)

Fuel

(GPY)

1 84,333 172,205

3a 112,004 2,867,770

2 191,327 173,421

3b 160,753 2,903,656

3 303,332 3,041,191

4a 472,369 4,617,848

4 673,780 6,027,266

5 2,835,389 7,548,543

Energy usage also includes the fuel consumption associated with transportation. EPA 

estimated the need for increased transportation of ash and other solid waste, including wastes 

from the treatment of FGD wastewater and landfill leachate, at steam electric power plants to onsite or off-site landfills, based on plant-specific data, using open dump trucks. In general, the fuel 

usage was calculated as shown:

Fuel (gallons) plant = [((Loading Time (hr/trip) idling + Unloading Time (hr/trip) idling) x 

(Fuel Consumption (gal/hr) idling)) + (Transport Distance (mile/round trip) x 

Fuel consumption (gal/mile))] x (Number of Trips (trips/yr)) 

Where:

Loading Time (hr/trip) = The estimated time to load an open dump truck 

with sludge and/or ash per trip, estimated to be 

0.1667 hours (10 minutes) per trip. 

Unloading Time (hr/trip) = The estimated time to unload an open dump truck 

with sludge and/or ash per trip, estimated to be 

0.1667 hours (10 minutes) per trip. 

Fuel Consumption (gal/hr) 

idling

= The estimated fuel consumption while the truck is 

idling. The MOBILE6.2 vehicle emission 
Section 12 - Non-Water Quality Environmental Impacts

12-3 

modeling software assumes that dump trucks 

average 2.5 miles per hour and 6.6 miles per gallon 

at idle. Therefore, EPA estimated the idle fuel 

consumption to be 0.38 gal/hr. 

Transport Distance 

(mile/round trip)

= The estimated round trip distance to/from the 

landfill. Distance varies based on plants with 

onsite versus offsite landfills. For onsite landfills, 

EPA estimated a round trip to be 2.6 miles. For 

offsite landfills, EPA estimated a round trip to be 

40 miles.

Fuel consumption (gal/mile) = The estimated fuel consumption while the truck is 

in drive, estimated to be 20.24 gal/100 miles. 

Number of Trips (trips/yr) = The calculated number of trips for one year in the 

transportation methodology to truck all ash to the 

onsite or offsite landfill.

The frequency and distance of transport depends on a plant’s operation and configuration. 

For example, the volume of waste generated per day determines the frequency with which trucks 

will be travelling to and from the storage sites. The availability of either an on-site or off-site 

non-hazardous landfill and its distance from the plant determines the length of travel time.

EPA also estimated fuel consumption associated with the dust suppression water trucks 

based on the total distance (in miles) traveled and the total number of hours estimated for water 

truck operations. See EPA’s Incremental Costs and Pollutant Removals for Proposed Effluent 

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

Category for more information on the specific calculations used to estimate transportation fuel

usage. [U.S. EPA, 2012c] Table 12-1 shows the net change in national annual fuel consumption 

associated with the proposed regulation. 

To provide some perspective on the potential net increase in annual electric energy 

consumption associated with the preferred options, EPA compared the estimated increase in 

energy usage (MWh), as shown in Table 12-1, to the net amount of electricity generated in a year 

by all electric power plants throughout the United States. According to EPA’s Emissions & 

Generation Resource Integrated Database (eGRID), the electric power industry generated 

approximately 3,951 million MWh of electricity in 2009. EPA estimates that energy increases 

associated with the preferred BAT and PSES regulatory options range from less than 0.003 

percent (Option 3a) to 0.012 percent (Option 4a) of the total electricity generated by all electric 

power plants. 

Similarly, EPA compared the additional net fuel consumption (gallons) estimated for the 

preferred options, as shown in Table 12-1, to national fuel consumption estimates for motor 

vehicles. According to the U.S. Energy Information Administration (EIA), on-highway vehicles, 

which include automobiles, trucks, and buses, consumed approximately 34 billion gallons of 

distillate fuel oil in 2009. EPA estimates that the fuel consumption increase associated with the 

proposed Option 3a for BAT and PSES will be 0.008 percent of total fuel consumption by all 
Section 12 - Non-Water Quality Environmental Impacts

12-4 

motor vehicles. Fuel consumption is estimated to increase by less than 0.009 percent under 

Options 3b and Option 3, and less than 0.014 percent under Option 4a. 

12.2 AIR EMISSIONS POLLUTION

The proposed ELGs are expected to affect air pollution through three main mechanisms: 

Additional auxiliary electricity use by steam electric plants to operate wastewater 

treatment, ash handling, and other systems needed to comply with the new effluent limitations 

and standards; 

Additional transportation-related emissions due to the increased trucking of combustion 

residual waste to landfills; and

The change in the profile of electricity generation due to relatively higher costs to 

generate electricity at plants incurring compliance costs for the proposed rule.

This section provides greater detail on air emission changes associated with the first two 

mechanisms and presents the estimated net change in air emissions that take all three 

mechanisms into account. See EPA’s Benefit and Cost Analysis for the Proposed Effluent 

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

Category report for additional discussion of the third mechanism. 

Air pollution is generated when fossil fuels are combusted. In addition, steam electric 

power plants generate air emissions from the operating transport vehicles, such as dump trucks 

and vacuum trucks, dust suppression water trucks, and earth-moving equipment, which release 

criteria air pollutants and greenhouse gases when operated. Criteria air pollutants are those 

pollutants for which a national ambient air quality standard (NAAQS) has been set and include 

sulfur dioxide (SO2) and nitrogen oxides (NOx). Greenhouse gases are gases such as carbon 

dioxide (CO2), methane (CH4), and nitrous oxide (N2O) that absorb radiation, thereby trapping 

heat in the atmosphere, and contributing to global warming.103 Similarly, a decrease in energy 

use or vehicle operation will result in decreased air pollution. 

EPA estimated the energy usage associated with the operation of wastewater treatment 

systems and ash handling systems in megawatt hours (MWh). Additionally, EPA also estimated 

the decrease in energy requirements associated with terminating wet sluicing operations and 

reduced use of earth-moving equipment associated with the new technology options. EPA used 

these estimates to calculate the net change in energy requirements for all regulatory options 

considered for this proposed rulemaking. 

EPA calculated air emissions resulting from increased auxiliary electricity using yearexplicit emission factors projected in IPM for CO2, NOx, and SO2. EPA obtained emission 

factors for years 2017 through 2024 based on IPM outputs for Run Year 2020 and emission 

 

103 EPA did not specifically evaluate nitrous oxide emissions as part of the NWQI analysis. To avoid double 

counting air emission estimates, EPA only calculated nitrogen oxide emissions, which would include nitrous oxide 

emissions. 
Section 12 - Non-Water Quality Environmental Impacts

12-5 

factors for years 2025 through 2040 based on IPM output for Run Year 2030. EPA used the 

values associated with Run Year 2030 because these values represent full implementation of the 

proposed rule. Table 12-2 presents the IPM emission factors for Regulatory Options 3 and 4 for 

CO2, NOx, and SO2 by NERC region, as well as the average for the United States.
12-6

Section 12 - Non-Water Quality Environmental Impacts

Table 12-2. Summary of IPM Emissions Factors by NERC Region and Across Steam Electric Plants

Run 

Year NERC Region / Plants

Option 3 Option 4

CO2 NOx SO2 CO2 NOx SO2

Metric Tonnes / 

MWh Tons / MWh Tons / MWh

Metric Tonnes / 

MWh Tons / MWh Tons / MWh

2020

US 0.5324 0.0004 0.0005 0.5322 0.0004 0.0005

ERCOT 0.5599 0.0003 0.0003 0.5610 0.0003 0.0003

FRCC 0.5031 0.0003 0.0003 0.5051 0.0003 0.0003

MRO 0.6892 0.0008 0.0008 0.6902 0.0008 0.0008

NPCC 0.2694 0.0002 0.0002 0.2694 0.0002 0.0002

RFC 0.5904 0.0005 0.0007 0.5904 0.0005 0.0007

SERC 0.5674 0.0004 0.0006 0.5674 0.0004 0.0006

SPP 0.7290 0.0006 0.0007 0.7290 0.0006 0.0007

WECC 0.3772 0.0005 0.0002 0.3772 0.0005 0.0002

2030

US 0.5210 0.0004 0.0005 0.5204 0.0004 0.0005

ERCOT 0.5411 0.0003 0.0002 0.5408 0.0003 0.0002

FRCC 0.4782 0.0003 0.0002 0.4781 0.0003 0.0002

MRO 0.6555 0.0007 0.0008 0.6555 0.0007 0.0008

NPCC 0.2980 0.0002 0.0002 0.2979 0.0002 0.0002

RFC 0.5764 0.0005 0.0006 0.5764 0.0005 0.0006

SERC 0.5604 0.0004 0.0006 0.5604 0.0004 0.0006

SPP 0.7130 0.0006 0.0007 0.7130 0.0006 0.0007

WECC 0.3645 0.0004 0.0001 0.3645 0.0004 0.0001
Section 12 - Non-Water Quality Environmental Impacts

12-7 

For plants with capacity utilization rates (CUR) of 90.4 percent or less, EPA estimated 

emissions using plant-specific and year-explicit emission factors obtained from IPM outputs.104

These plants are assumed to be able to generate the additional auxiliary electricity on site.

For plants with CUR greater than 90.4 percent, EPA used NERC-average emission 

factors for each year instead of plant-specific emissions factors. EPA used these NERC-average 

factors based on the assumption that additional electricity consumption for auxiliary power will 

displace grid power within the region instead of coming from additional generation at the plant 

(i.e., the plant will be using part of its existing generation to power equipment, requiring other 

plants within the same NERC region to generate additional electricity to meet demand).

EPA calculated NOX emissions as follows:

NOXt p = � E × EF_NOXp,t p × T ,t p × W

733

p=1

Where: 

NOXt = Total NOx emissions in year t.

Ep = Incremental auxiliary power electricity consumption at plant p, 

in MWh per year.

EF_NOXp,t = NOx emission factor at plant p in year t, in tons NOx per MWh. 

If CURp > 90.4 percent, EF_NOXp,t is based on average 

EF_NOXt for the NERC region where plant p is located. For t = 

2017 to 2024, the calculations use IPM EF_NOXp,2020. For t = 

2025 to 2040, the calculations use IPM EF_NOXp,2030.

Tp,t = Timing adjustment to reflect year when plants are assumed to 

install the compliance technology between 2017 and 2021 and 

start incurring additional electricity consumption (Tp,t =0 if t < 

Year when plant p installs technology; Tp,t =1 if t ≥ Year when 

plant p installs technology).

Wi = Sample weight for plant p.

Emissions of CO2 and SO2 are calculated similarly but using the CO2 and SO2 emission 

factors, respectively.

Since IPM was run for Regulatory Options 3 and 4 only, EPA used IPM emission factors 

for Option 3 to estimate changes in auxiliary power air emissions for Options 1 and 2, and IPM 

emissions factors for Option 4 to estimate changes in auxiliary power air emissions for Option 5. 

EPA used the auxiliary power air emissions calculated for Option 1 through 5 to estimate the 

auxiliary power air emissions for Options 3a, 3b, and 4a. For additional details on these 

estimation methodologies, see the memoranda entitled “Memorandum to the Rulemaking 

 

104 Emission factors are calculated as plant-level emissions divided by plant-level generation.
Section 12 - Non-Water Quality Environmental Impacts

12-8 

Record: Methodologies for Estimating Costs and Pollutant Removals for Steam Electric ELG 

Regulatory Options 3a and 3b” and “Memorandum to the Rulemaking Record: Methodologies 

for Estimating Costs and Pollutant Removals for Steam Electric ELG Regulatory Option 4a”

[ERG, 2013a; ERG, 2013b]. 

To estimate air emissions associated with increased operation of transport vehicles, EPA 

used the MOBILE6.2 model to generate air emission factors (grams per mile) for hydrocarbons 

(HC), carbon monoxide (CO), NOx, CO2, and particulate matter (PM). EPA assumed the general 

input parameters such as the year of the vehicle and the annual mileage accumulation by vehicle 

class to develop these factors. See EPA’s report entitled Incremental Costs and Pollutant 

Removals for Proposed Effluent Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category for more specific information on the assumptions 

made by EPA for year of the vehicle and annual mileage accumulation. [U.S. EPA, 2012c] 

Because MOBILE6.2 does not estimate emission factors for CH4, EPA used the emission factors 

from the California Climate Action Registry, General Reporting Protocol, Version 2.2. Table 

12-3 provides a table of the transportation emission factors for each air pollutant considered in 

the NWQI analysis.

Table 12-3. MOBILE6.2 and California Climate Action Registry 

Transportation Emission Rates

Nitrogen Oxides

Highway (ton/mi) 

Nitrogen Oxides

Local (ton/mi)

Sulfur Oxides 

(ton/mi)

Carbon Dioxide

(ton/mi)

Methane 

(ton/mi)

6.76 x 10-7 6.52 x 10-7 1.58 x 10-8 0.0017 6.61 x 10-8

Source: MOBILE6.2 [U.S. EPA, 2004] and California Climate Action Registry, General Reporting Protocol, V2.2 

[California Climate Action Registry, 2007]

Note: The MOBILE6.2 highway and local emission rates are the same for all pollutant except nitrogen oxides.

Using the transportation emission rates per mile, EPA calculated the air emissions 

associated with the additional energy estimated for the regulatory options, as shown: 

Emission (tons) pollutant x, plant = (Air Emission Factor (ton/mile) pollutant x, vehicle) x 

(Transport Distance (mile/round trip)) x (Number of Trips (trips/yr)).

Where: 

Air Emission Factor 

(ton/mile) pollutant x, vehicle

= The transportation emission factor for each pollutant 

presented in Table 12-3. 

Transport Distance 

(mile/round trip)

= The estimated round trip distance to/from the landfill. 

Distance varies based on plants with on-site versus 

off-site landfills. For on-site landfills, EPA estimated a 

round trip to be 2.6 miles. For off-site landfills, EPA 

estimated a round trip to be 40 miles. 
Section 12 - Non-Water Quality Environmental Impacts

12-9 

Number of Trips (trips/yr) = The calculated number of trips for one year in the 

transportation methodology to truck all ash to the onsite or off-site landfill.

EPA estimated the annual number of miles that would be traveled by dump trucks or 

vacuum trucks moving ash or wastewater treatment solids to on- or off-site landfills related to 

the regulatory options. In addition to the trucks associated with transporting the additional solid 

waste, EPA also estimated the annual number of miles that would be traveled by water trucks 

spraying water around landfills and ash unloading areas to control dust. EPA used these 

estimates to calculate the net increase in air emissions for this rulemaking. See EPA’s report 

entitled Incremental Costs and Pollutant Removals for Proposed Effluent Limitations Guidelines 

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

information. [U.S. EPA, 2012c] The increases in national annual air emissions associated with

auxiliary electricity and transportation for each of the regulatory options are shown in Table 12-4

[ERG, 2013c]. 

Table 12-4. Industry-Level Air Emissions Associated with Auxiliary Electricity and 

Transportation by Regulatory Option 

Regulatory Option

Air Emissions

NOX 

(tons/year)

SOX 

(tons/year)

CO2 

(metric tons/year)

CH4 

(tons/year)

1 54 90 79,753 1.2

3a 88 84 117,863 2.4

2 119 190 181,366 2.7

3b 113 126 164,318 3.1

3 207 274 299,229 5.1

4a 321 418 459,074 7.9

4 547 709 663,957 11

5 1,772 2,708 2,674,207 41

EPA estimated the change in the profile of electricity generation due to relatively higher 

costs to generate electricity at plants incurring compliance costs for the proposed rule using data 

from IPM. IPM predicts changes in electricity generation due to compliance costs attributable to 

the proposed ELG options. Therefore, EPA predicts that these changes, either increases or 

decreases, in electricity generation affect the air emissions from steam electric power plants. 

EPA only estimated the changes associated with the IPM predications, one of the three air 

emission mechanisms, for Option 3 and 4. The net changes in national annual air emissions 

associated with the preferred options are shown in Table 12-5. 
Section 12 - Non-Water Quality Environmental Impacts

12-10 

Table 12-5. Industry-Level Net Air Emissions For the Preferred Regulatory Options

Regulatory 

Option

Air Emissions

NOx 

(tons/year)

SOx 

(tons/year)

CO2 

(metric tons/year)

CH4 

(tons/year)

3a 88-1,090a <84b <117,863b 2.4

3b 110-1,110a <130b <164,318b 3.1

3 1,207 -2,726 -1,162,771 5.1

4a 1,320c <-2,580c <-1,002,926c 7.9

4 1,547 -3,291 -3,749,043 11

a - EPA quantified the air emissions associated with additional electricity and additional transportation for Options 

3a and 3b. Based on the values quantified for Option 3 for the changes to air emissions projected by IPM, EPA 

calculated the range of emissions for NOx. The lower end of the range represents the emissions only associated with 

additional electricity and transportation. The upper end of the range also includes the changes to air emissions 

projected by IPM (based on Option 3), which are large than would be expected for Option 3a and 3b. 

b - EPA quantified the air emissions associated with additional electricity and additional transportation for Options 

3a and 3b. Based on the values quantified for Option 3 for the changes to air emissions projected by IPM, which 

were negative, EPA decided not to include these IPM air emission changes in the calculated SOx and CO2 emissions 

for Options 3a and 3b. These SOx and CO2 emissions are considered maximum values because EPA expects that the 

air emission changes projected by IPM for Options 3a and 3b will also be negative (as they are for Options 3 and 4).

c - EPA quantified the air emissions associated with additional electricity and additional transportation for Option 

4a. To estimate the total emissions for Option 4a, EPA added the changes to air emissions projected by IPM for 

Option 3 because they are more conservative (i.e., they overestimate the emissions). The contribution of NOx is 

unchanged compared to Option 3 and 4; therefore, EPA assumed this would also be the contribution for Option 4a. 

For SOx and CO2, the contribution associated with Option 4 are lower (i.e., more negative); therefore, because EPA 

used the Option 3 values, the values presented in the table are maximum values.

To provide some perspective on the potential increase in annual air emissions associated 

with the preferred options, EPA compared the estimated increase in air emissions associated with 

Regulatory Options 3a, 3b, 3, 4a, and 4 to the net amount of air emissions generated in a year by 

all electric power plants throughout the United States. Table 12-6 presents the 2009 emissions 

generated by the electric power industry, based on eGRID, and the percent of increased 

emissions associated with the proposed rule. [U.S. EPA, 2012a] 
Section 12 - Non-Water Quality Environmental Impacts

12-11 

Table 12-6. Electric Power Industry Air Emissions

Non-Water 

Quality Impact

Value Associated with 

Preferred Regulatory Option

(Million Tons)

2009 Emissions by Electric 

Power Industry

(Million Tons)

Increase In Emissions

(%)

Regulatory Option 3a

NOx 0.000088-0.00109 1 0.008-0.109

SOx <0.000084 6 <0.0014

CO2 <0.130 2,403 <0.0054

CH4 0.0000024 95 0.0000025

Regulatory Option 3b

NOx 0.00011-0.00111 1 0.011-0.111

SOx <0.00013 6 <0.0021

CO2 <0.181 2,403 <0.0075

CH4 0.0000031 95 0.0000033

Regulatory Option 3

NOx 0.00121 1 0.121

SOx -0.00273 6 -0.045

CO2 -1.282 2,403 -0.053

CH4 0.000001 95 0.000001

Regulatory Option 4a

NOx 0.00132 1 0.132

SOx <-0.00258 6 <-0.043

CO2 <-1.106 2,403 <-0.046

CH4 0.0000079 95 0.0000083

Regulatory Option 4

NOx 0.00154 1 0.154

SOx -0.00329 6 -0.055

CO2 -4.133 2,403 -0.172

CH4 0.000001 95 0.000001

12.3 SOLID WASTE GENERATION

Steam electric power plants generate solid waste associated with sludge from wastewater 

treatment systems (e.g., chemical precipitation, biological treatment). The regulatory options 

evaluated would increase the amount of solid waste generated from FGD wastewater treatment, 

including sludge from chemical precipitation, biological treatment, and vapor-compression 

evaporation technologies. EPA estimated the amount of solid waste generated from each 

technology for each plant and estimates that the preferred BAT/PSES regulatory options 

(Options 3a, 3b, 3, and 4a) would increase solids generated annually from treatment. Fly ash and 

bottom ash are also solid wastes generated at steam electric power plants. The preferred 

regulatory options for BAT and PSES are, however, not expected to alter the amount of fly ash, 

bottom ash, or other combustion residuals generated.
Section 12 - Non-Water Quality Environmental Impacts

12-12 

EPA determined dewatered sludge generation rates for chemical precipitation treatment 

by multiplying a flow-normalized dewatered sludge generation rate (expressed in tons per day of 

sludge per gallon per minute FGD flow) by the plant flow rate. The flow-normalized dewatered 

sludge generation rate was determined based on responses in the questionnaire for FGD 

wastewater chemical precipitation treatment. EPA selected the median flow-normalized 

dewatered sludge generation rate based on an assessment of the characteristics of the dataset. 

EPA then calculated the annual sludge generation as follows: 

Annual Sludge Generation, tons/yr = Sludge Generation Rate × FGD Wastewater Flow, 

gpm ×60 min/hr × 24 hr/day × 365 day/year 

Where:

Sludge 

Generation Rate

= The median flow normalized rate of sludge generation based on 

the questionnaire. EPA estimated this rate to be 0.24 tons per 

day per gallon per minute of FGD wastewater flow.

FGD Wastewater 

Flow

= The FGD wastewater for the plant in units of gallons per 

minute. This value was calculated from the gallons per day 

value reported in the survey and divided by 24 x 60 to convert 

to gallons per minute. 

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. Sludge generated by the vaporcompression evaporation system includes softening sludge and crystallizer sludge. EPA obtained 

sludge generation rates for the softening sludge and crystallizer sludge based on FGD wastewater 

flow rates from equipment vendors. [HPD, 2009] Based on this information, EPA calculated 

sludge generation rates using the equations provided below. 

Softening Sludge, tons/yr = Softening Sludge Factor, lb/hr-gpm × FGD Wastewater Flow,

gpm × (1 ton/2,000 lb) × 24 hpd × 365 dpy 

Crystallizer Sludge, tons/yr = Crystallizer Sludge Factor, lb/hr-gpm × FGD Wastewater Flow, 

gpm × (1 ton/2,000 lb) × 24 hpd × 365 dpy 

Where:

Softening Sludge Factor = 

A factor that relates the amount of sludge generated in the 

softening process to the scrubber purge flow based on data 

provided by HPD, 51.43 lb/hr-gpm.

Crystallizer Sludge Factor = 

A factor that relates the amount of sludge generated in the 

crystallizer process to the scrubber purge flow based on data 

provided by HPD, 17.14 lb/hr-gpm.
Section 12 - Non-Water Quality Environmental Impacts

12-13 

See EPA’s report entitled Incremental Costs and Pollutant Removals for Proposed 

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

Source Category for more information [U.S. EPA, 2012c]. The net change in national annual 

sludge production associated with the regulatory options is shown in Table 12-7. 

To provide some perspective on the potential increase in annual solid waste generation 

associated with Regulatory Options 3a, 3, and 4a, EPA compared the estimated increase in solid 

waste generation to the amount of solids generated in a year by electric power plants throughout 

the United States. According to the EIA, power plants generated approximately 134 billion tons 

of solids in 2009. EPA estimates that solid waste generation increases associated with the 

preferred regulatory options will be less than 0.001 percent of the total solid waste generated by 

all electric power plants.

Table 12-7. Industry-Level Solid Waste Increases by Regulatory Option 

Regulatory Option Sludge (Tons/Year)

1 1,209,859

3a 0

2 1,218,691

3b 365,960

3 1,218,691

4a 1,218,691

4 1,459,011

5 13,281,443

12.4 REDUCTIONS IN WATER USE

Steam electric power plants generally use water for handling solid waste, including ash, 

and for operating wet FGD scrubbers. The technology options for fly ash and bottom ash will 

eliminate or reduce water use associated with current wet sluicing operating systems. EPA 

estimated the reductions in water use by calculating the amount of ash sluice water, specifically 

that amount of water identified as intake process water, that will no longer be discharged as part 

of the proposed rulemaking. In order to calculate this reduction, EPA used data from Part C of 

the Steam Electric Survey to calculate an average percentage of ash sluice water identified as 

intake water. EPA multiplied this percentage by the amount of sluice water discharged by each 

plant to calculate the estimated process water reduction. See the memorandum entitled “Steam 

Electric Effluent Guidelines Non-Water Quality Impacts” for more information [ERG, 2013c]. 

The technology basis for the preferred regulatory option with respect to FGD wastewater 

discharges (e.g., chemical precipitation, biological treatment) would not be expected to reduce 

the amount of water used unless plants recycle FGD wastewater as part of their treatment system. 

EPA estimated that five plants would be able to incorporate recycle within their FGD systems 

based on the maximum operating chlorides concentration compared to the design maximum 

chlorides concentration (other plants may also be able to do so). In order to estimate the water 

reductions associated with the recycled FGD wastewater, EPA used data from Part B of the 

Steam Electric Survey to calculate an average percentage of FGD wastewater identified as intake 
Section 12 - Non-Water Quality Environmental Impacts

12-14 

water. EPA multiplied this percentage by the amount of water that could be recycled by the FGD 

system to calculate the estimated water reduction. EPA also used the adjusted FGD scrubber 

purge flows to estimate compliance cost and pollutant loadings associated with these plants. See 

EPA’s report entitled Incremental Costs and Pollutant Removals for Proposed Effluent 

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

Category for more information [U.S. EPA, 2012c]. 

EPA estimates that power plants would reduce the use of water associated with the 

regulatory options. Table 12-8 presents the expected reduction in process water use for each 

regulatory option evaluated for the proposed rule. For comparison, EPA compared the expected 

levels of process water reductions to the current amount of wastewater discharged from the 

wastestreams expected to have associated non-water quality environmental impacts for this 

proposed rulemaking, presented in Table 12-9. 

Table 12-8. Industry-Level Process Water Reduction by Regulatory Option 

Regulatory Option

Water Reduction

(Million Gallons/Year)

1 2,820

3a 49,900

2 2,820

3b 52,100

3 52,700

4a 103,000

4 153,000

5 153,000

Table 12-9. Wastewater Discharge at Steam Electric Power Plants

Type of Wastewater

Number of Plants 

Discharging Wastewater

Total Wastewater Discharged

(2009, Million Gallons/Year)

FGD Wastewater 117 23,700

Fly Ash Transport Water 95 81,100

Bottom Ash Transport Water 245 157,000

Landfill Leachate 100-115 2,200

12.5 REFERENCES

1. California Climate Action Registry. 2007. General Reporting Protocol: Reporting EntityWide Greenhouse Gas Emission, Version 2.2. (March). DCN SE02035. 

2. Eastern Research Group (ERG). 2013a. Memorandum to the Rulemaking Record: 

Methodologies for Estimating Costs and Pollutant Removals for Steam Electric ELG 

Regulatory Options 3a and 3b. (19 April). DCN SE03881. 
Section 12 - Non-Water Quality Environmental Impacts

12-15 

3. Eastern Research Group (ERG). 2013b. Memorandum to the Rulemaking Record: 

Methodologies for Estimating Costs and Pollutant Removals for Steam Electric ELG 

Regulatory Option 4a. (19 April). DCN SE03834. 

4. Eastern Research Group (ERG). 2013c. Memorandum to the Steam Electric Rulemaking 

Record. “Steam Electric Effluent Guidelines Non-Water Quality Impacts.” (19 April). 

DCN SE02025. 

5. U.S. EPA. 2004. MOBILE6.2 Vehicle Emission Modeling Software, available online at: 

http://www.epa.gov/oms/m6.htm. 

6. U.S. EPA. 2012a. The Emissions & Generation Resource Integrated Database for 2012 

(eGRID 2012) Technical Support Document. Available online at: 

http://www.epa.gov/cleanenergy/documents/egridzips/eGRID2012_year09_TechnicalSup

portDocument.pdf. DCN SE02112. 

7. U.S. EPA. 2012b. eGRID2012 Version 1.0 2009 Data. Available online at: 

http://www.epa.gov/cleanenergy/energy-resources/egrid/index.html. DCN SE02111. 

8. U.S. EPA. 2013. Incremental Costs and Pollutant Removals for Proposed Effluent 

Limitation Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category Report. (19 April). DCN SE01957. 
Section 13- Limitations and Standards: Data Selection and Calculation

13-1 

SECTION 13

LIMITATIONS AND STANDARDS: DATA SELECTION AND 

CALCULATION 

This section describes the data sources, data selection, and statistical methodology EPA 

used to calculate the long-term average, variability factors, and limitations and standards for 

existing and new sources. The effluent limitations guidelines and standards are based on longterm average effluent values and variability factors that account for variation in treatment 

performance within a particular treatment technology over time. For simplicity, in the remainder 

of this section, the proposed effluent limitations and/or standards are referred to as “limitations.”

Also, the term “option long-term average” and “option variability factor” are used to refer to the 

long-term averages and variability factors for the treatment technology options for an individual 

wastestream rather than the regulatory options described in Section 8.1. 

Section 13.1 provides a brief overview of the criteria EPA used to evaluate and select 

model plants (and the associated datasets) that are the basis of the proposed limitations. Section 

13.2 describes the data exclusions and substitutions. Section 13.3 presents the procedures for 

data aggregation. Section 13.4 describes data editing criteria used to select plant datasets in 

developing the limitations. Sections 13.5 and 13.6 provide an overview and the procedure for 

estimation of the long-term averages, variability factors, and limitations. Section 13.7 describes 

the rationale for the transfer of limitations. Sections 13.8 and 13.9 provide the summary of the 

limitations and engineering review of the limitations.

13.1 DATA SELECTION

In developing the long-term averages, variability factors, and limitations for a particular 

wastestream and a particular technology option, EPA used wastewater data from plants operating

the model technology as the basis for the technology option. The data sources evaluated 

include: (i) Sampling performed by EPA (hereafter referred to as “EPA sampling”) during which 

EPA collected samples; (ii) Sampling directed by EPA (hereafter referred to as “CWA 308 

sampling”) during which EPA directed plants to collect samples; and (iii) Plants self-monitoring 

data (hereafter referred to as “plant self-monitoring”) collected by Duke Energy for two plants 

over a period of several years.

13.1.1 Data Selection Criteria

This section describes the criteria that EPA applied in selecting plants and data to use as 

the basis for the limitations for FGD, leachate, and gasification wastestreams. EPA has used 

these, or similar criteria, in developing limitations and standards for other industries. EPA uses 

these criteria to select data that reflect consistently good performance of the model technology in 

treating the industrial wastes under normal operating conditions. Generally, for each technology 

option, EPA has defined a treatment system (or management practices) comprised of specific 

components (e.g., equipment, chemical additives, etc.) that is carefully designed to operate under 

the expected wastestream characteristics (e.g., pollutant concentrations, flow rates, etc.) and that 

is diligently operated to achieve stable, optimized pollutant removal performance. Indicators of 

diligent operation include adequate staffing by trained personnel, frequent monitoring of 

treatment system operating conditions, and practice response to changes in operating conditions 
Section 13- Limitations and Standards: Data Selection and Calculation

13-2 

or indicators of system performance. The following paragraphs describe the criteria specific to 

the steam electric category.

The first criterion requires that the plant must have the model technology and 

demonstrate consistently diligent and optimal operation. Application of this criterion typically 

eliminates any plant with treatment other than the model technology. EPA generally determines 

whether a plant meets this criterion based upon site visits, discussions with plant management, 

and/or comparison to the characteristics, operation, and performance of treatment systems at 

other plants. EPA often contacts plants to determine whether data submitted were representative 

of normal operating conditions for the plant and equipment. EPA typically excludes the data in 

developing the limitations when the plant has not optimized the performance of its treatment 

system to the degree that represents the appropriate level of control (BAT or BADCT).

The second criterion generally requires that the influents and effluents from the treatment 

components represent typical wastewater from the industry, without incompatible wastewater 

from other sources. Application of this criterion results in EPA selecting only those plants where 

the commingled wastewaters were not characterized by substantial dilution, unequalized slug 

loads that resulted in frequent upsets and/or overloads, more concentrated wastewaters, or 

wastewaters with different types of pollutants than those generated by the wastestream for which 

EPA is establishing effluent limitations.

The third criterion typically ensures that the pollutants were present in the influent at 

sufficient concentrations to evaluate treatment effectiveness. To evaluate whether the data meet 

this criterion for the proposed rule, EPA often uses a long-term average test (or LTA test) for 

plants where EPA possesses paired influent and effluent data. EPA has used this test in 

developing regulations for other industries, e.g., the Iron and Steel Category (EPA 2002). The 

test measures the influent concentrations to ensure a pollutant is present at sufficient 

concentration to evaluate treatment effectiveness. If a dataset for a pollutant fails the test (i.e., 

not present at a treatable concentration), EPA excludes the data for that pollutant at that plant 

when calculating the limitations. See Section 13.4 for a detailed discussion of the LTA test. 

The fourth criterion typically requires that the data are valid and appropriate for their 

intended use (e.g., the data must be analyzed with a sufficiently-sensitive method). Also, EPA 

does not use data associated with periods of treatment upsets because these data would not 

reflect the performance from well-designed and well-operated treatment systems. In applying the 

fourth criterion, EPA may evaluate the pollutant concentrations, analytical methods and the 

associated quality control/quality assurance data, flow values, mass loadings, plant logs, and 

other available information. As part of this evaluation, EPA reviews the process or treatment 

conditions that may have resulted in extreme values (high and low). As a consequence of this 

review, EPA may exclude data associated with certain time periods or other data outliers that 

reflect poor performance or analytical anomalies by an otherwise well-operated site. 

The fourth criterion also is applied in EPA’s review of data corresponding to the start-up 

or initial commissioning period for treatment systems. Most industries incur commissioning 

periods associated with installing new treatment systems to acclimate and optimize the system. 

During this acclimation and optimization process, the effluent concentration values tend to be 

highly variable with occasional extreme values (high and low). This occurs because the treatment 
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system typically requires some “tuning” as the plant staff and equipment and chemical vendors 

work to determine the optimum chemical addition locations and dosages, vessel hydraulic 

residence times, internal treatment system recycle flows (e.g., filter backwash frequency, 

duration and flow rate; return flows between treatment system components), and other 

operational conditions including clarifier sludge wasting protocols. It may also take several 

weeks or months for treatment system operators to gain expertise on operating the new treatment 

system, which also contributes to treatment system variability during the commissioning period. 

After this initial adjustment period, the systems should operate at steady state with relatively low 

variability around a long-term average over many years. Because commissioning periods 

typically reflect one-time operating conditions unique to the first time the treatment system 

begins operation, EPA generally excludes such data in developing the limitations.105

13.1.2 Data Selection for Each Technology Option 

This section discusses the data selected for use in developing the limitations for each 

pollutant for each technology option. This section includes an abbreviated description of the 

technology options. See Section 8.1.2 for a more complete discussion of the technology basis of 

the options considered. 

For fly ash transport water and flue gas mercury control (FGMC) wastewater, all of the 

preferred regulatory options propose zero discharge of pollutants based on dry handling 

technologies; therefore, no effluent concentration data were used to set the limitations for these 

wastestreams.106 This is also true for the regulatory options that include zero discharge of 

pollutants for any set of dischargers for bottom ash. For nonchemical metal cleaning wastes, 

EPA is proposing to establish limitations that are equal to the current BPT limitations that apply 

to discharges of nonchemical metal cleaning wastes from existing sources that are direct 

dischargers. No new effluent concentration data were used to set the effluent limitations for 

nonchemical metal cleaning wastes in this rulemaking, therefore, the limitations for this 

wastestream are not discussed in this section. For combustion residual leachate (hereafter 

referred to in this section as leachate) limitations based on the chemical precipitation technology 

option, EPA is proposing to transfer the limitations calculated based on the chemical 

precipitation technology option for FGD wastewater because EPA does not have available 

effluent data for leachate from plants employing the chemical precipitation technology. For the 

limitations based on the biological treatment technology option for FGD wastewater, EPA is 

 

105 Examples of conditions that are typically unique to the initial commissioning period include operator 

unfamiliarity or inexperience with the system and how to optimize its performance; wastewater flow rates that differ 

significantly from engineering design, altering hydraulic residence times, chemical contact times, and/or clarifier 

overflow rates, and potentially causing large changes in planned chemical dosage rates or the need to substitute 

alternative chemical additives; equipment malfunctions; fluctuating wastewater flow rates or other dynamic 

conditions (i.e., not steady state operation); and initial purging of contaminants associated with installation of the 

treatment system, such as initial leaching from coatings, adhesives, and susceptible metal components. These 

conditions differ from those associated with the restart of an already-commissioned treatment system, such as may 

occur from a treatment system that has undergone either short or extended duration shutdown.

106 EPA also considered a technology option that would require zero discharge of pollutants in bottom ash transport 

water. This technology option would be based on bottom ash handling practices that do not use water to carry the 

ash away from the boiler or that operate wet sluicing systems as closed-loop systems that do not discharge 

wastewater; therefore, no effluent concentration data would be used to set a zero discharge limitation for bottom ash 

transport water.
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proposing to transfer the limitations for two pollutants (arsenic and mercury) calculated based on 

the chemical precipitation technology option for the FGD wastewater for the reasons described 

in Section 13.7.2. See Section 13.7 for a detailed discussion of the transfer of limitations. 

Under some regulatory options being proposed, EPA would establish limitations for 

certain wastewater discharges that are equal to current BPT limitations for those dischargers. No 

new effluent concentration data would be used to establish BAT/NSPS limitations that are set 

equal to BPT, therefore, such limitations are not discussed in this section. See Section 8 for a 

more complete discussion of the basis for the proposed regulatory options.EPA used specific 

data sources to set the limitations for the different FGD wastewater treatment technologies and 

for gasification wastewater treatment. The data sources used to calculate effluent limitations for 

each technology option are described below. 

FGD Wastewater

As part of the EPA sampling program and additional plant self-monitoring data EPA 

obtained during the rulemaking, EPA evaluated the performance of 10 FGD wastewater 

treatment systems. For seven of the 10 systems, EPA collected data representing the influent and 

effluent for chemical precipitation treatment system. EPA evaluated these seven systems and 

determined that the systems operating the chemical precipitation system with both hydroxide and 

sulfide precipitation achieved better removals of mercury compared to the plants that used only 

hydroxide precipitation. Therefore, EPA did not use data from the three plants that use only 

hydroxide precipitation. Four of the seven plants use hydroxide and sulfide precipitation; 

however, one of the plants operates a two-stage chemical precipitation system. Because EPA’s 

basis for the technology option is a one-stage system, EPA did not use the data from the twostage system in developing the limitations.107 Therefore, EPA used data from the following three 

plants to develop the limitations based on treatment of FGD wastewater using the chemical 

precipitation technology option (i.e., one-stage chemical precipitation system employing both 

hydroxide and sulfide precipitation and iron coprecipitation, as well as flow reduction at plants 

with large FGD wastewater flow rates, hereafter referred to in this section as “chemical 

precipitation”– see Section 8.1.2.1 above for a more detailed description): 

• Duke Energy’s Miami Fort Station (hereafter referred to as Miami Fort);

• RRI Energy’s Keystone Generating Station (hereafter referred to as Keystone); and

• Allegheny Energy’s Hatfield’s Ferry Power Station (hereafter referred to as Hatfield’s 

Ferry).

For the treatment of FGD wastewater using a system that also includes a biological 

treatment system (chemical precipitation system followed by anoxic/anaerobic biological 

treatment to remove selenium, hereafter referred to as “biological treatment”), EPA evaluated the 

 

107 Based on data EPA has evaluated for the steam electric industry and other industry sectors, two-stage chemical 

precipitation systems generally achieve better pollutant removals than one-stage systems. Since the technology basis 

for chemical precipitation treatment of FGD wastewater in the proposed rule is a one-stage system and that is the 

configuration used to estimate compliance costs, EPA concluded that effluent data for the two-stage system 

(Pleasant Prairie) should not be used when calculating effluent limits for the technology option.
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13-5 

treatment systems that include biological treatment at three power plants as part of the EPA 

sampling program.108 EPA determined that one of the biological treatment systems was not 

designed for effective removal of selenium and does not represent the model technology. 

Because EPA’s basis for the technology option includes anoxic/ anaerobic biological treatment 

to remove selenium, EPA did not use data from this system in developing the limitations.

Therefore, EPA used data from the following two plants to develop the limitations and 

standards for the treatment of FGD wastewater using a one-stage chemical precipitation system 

followed by biological treatment:

109

• Duke Energy Carolina’s Belews Creek Steam Station (hereafter referred to as Belews 

Creek); and

• Duke Energy Carolina’s Allen Steam Station (hereafter referred to as Allen).

For the treatment of FGD wastewater using chemical precipitation followed by a vaporcompression evaporation system, hereafter referred to as a “vapor-compression evaporation” 

system (which is the technology serving as the basis for Regulatory Option 5), EPA evaluated 

three systems as part of the EPA sampling program. One plant operates a system that is similar to 

the technology basis for the FGD wastewater limitations in the proposed rule: a one-stage 

chemical precipitation system followed by softening and a vapor-compression evaporation 

system. EPA used the data from this plant to develop the limitations based on the vaporcompression evaporation technology for the treatment of the FGD wastewater. That plant is 

Enel’s Federico II Power Plant, located in Brindisi, Italy (hereafter referred to as Brindisi). EPA 

used data from a second plant for characterization purposes and not for limitations development 

because it only collected effluent data for one day from the plant. The third system does not 

represent the technology serving as the basis for the vapor-compression evaporation option, and 

was not used for the limitations development. This plant operates a solids removal process prior 

to the vapor-compression evaporation system but includes neither a full chemical precipitation 

system nor a softening step. Furthermore, this plant also operates a one-stage evaporation system 

and instead of employing a second stage of evaporation to crystallize and remove salts and other 

pollutants from the concentration brine, mixes the brine with fly ash and sends it to the landfill 

for disposal. 

Gasification Wastewater

For the treatment of gasification wastewater using a vapor-compression evaporation 

system EPA evaluated systems from the following two plants as part of the EPA sampling 

program: 

• Tampa Electric Company’s Polk Station (hereafter referred to as Polk); and

 

108 In the remainder of this section, the term “biological treatment” refers to chemical precipitation/iron 

coprecipitation (with both hydroxide and sulfide precipitation) followed by anoxic/anaerobic biological treatment. 

109 The limitations for arsenic and mercury for the biological (chemical precipitation followed by anoxic/anaerobic 

biological treatment) technology option were transferred from chemical precipitation technology option. See Section 

13.7.2 for a detailed discussion of the transfer of the limitations. 
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13-6 

• Wabash Valley Power Association’s Wabash River Station (hereafter referred to as 

Wabash River).

Both systems are representative of the system used as the basis for the technology option 

and were used in calculating the limitations.

13.1.3 Combining Data from Multiple Sources within a Plant

Typically, if sampling data from a plant were collected over two or more distinct time 

periods, EPA analyzes the data from each time period separately. In past ELG rulemakings, 

where appropriate, EPA has analyzed the data as if each time period represents a different plant 

since these data can represent different operating conditions due to changes in management, 

personnel, and procedures. On the other hand, when EPA obtains the data (such as EPA 

sampling and plant self-monitoring data) from a plant during the same time period, EPA 

typically combines the data from these sources into a single dataset for the plant for the statistical 

analyses.

For this rulemaking, data for most of the plants came from multiple sources such as EPA 

sampling, CWA 308, or plant self-monitoring. For three plants (Allen, Belews Creek, and 

Hatfield’s Ferry), the multiple sources of the data were collected during overlapping time 

periods, thus, EPA combined these data into a single dataset for the plant. For two plants 

(Keystone and Miami Fort), the multiple sources of the data were collected during nonoverlapping time periods. However, in these instances the time period between the nonoverlapping data collection periods was relatively small (two months). Furthermore, EPA has no 

information to indicate that the data represent different operating conditions. Thus, EPA also 

combined the multiple sources of data for each of these plants into a single dataset for the plant. 

This approach is consistent with EPA’s traditional approach for other effluent guidelines 

rulemakings. Three plants (Brindisi, Polk, and Wabash River) had data from a single source, and 

for these plants it was not necessary to combine data. For a listing of all the data and their 

sampling sources for each of the plants, see the document entitled, “Sampling Data Used as the 

Basis for Effluent Limitations for the Steam Electric Rulemaking.” [U.S. EPA, 2012c]. 

13.2 DATA EXCLUSIONS AND SUBSTITUTIONS

The sections below describe the data exclusions and substitutions. Other than the data 

exclusions described in this section and the data excluded due to failing the data editing criteria 

(described in Section 13.4), EPA used all the data from the plants presented in Section 13.1.2. 

13.2.1 Data Exclusions 

Following EPA’s selection of the model plant(s), EPA applied the criteria described 

above in Section 13.1.1 by thoroughly evaluating all available data for each model plant. EPA 

identified certain data that warranted exclusion from calculating the limitations because: (i) 

samples were analyzed using an insufficiently-sensitive analytical method (i.e., use of EPA 

Method 245.1 instead of Method 1631E for mercury); (ii) the samples were collected during 

initial commissioning period for the treatment system; or (iii) the analytical results were 

identified as questionable due to quality control issues, abnormal conditions or treatment upsets, 

or were analytical anomalies. See the memorandum entitled “Effluent Limitations for FGD 
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13-7 

Wastewater, Gasification Wastewater, and Combustion Residual Leachate for the Proposed 

Effluent Limitations Guidelines and Standards for the Steam Electric Rulemaking” for a detailed 

discussion of the data that were excluded and a listing of the data excluded [U.S. EPA, 2012a]. 

13.2.2 Data Substitutions

In general, EPA used detected values or sample-specific detection limits (for nondetected values) in calculating the limitations.

110 However, there were some instances where 

EPA substituted a baseline value for a detected value or a sample-specific detection limit. The 

baseline value was used in the calculations to account for the possibility that certain a detected 

result may be at a lower concentration than can be reliably achieved by well-operated 

laboratories. This approach is consistent with the way EPA has calculated limitations in previous 

effluent guidelines rulemakings. After excluding all the necessary data as described in Section 

13.2.1, EPA compared each reported result to a baseline value. When a detected value or samplespecific detection limit (i.e., sample specific quantitation limit) was lower than the baseline 

value, EPA used the baseline value instead and classified the value as non-detected (even if the 

actual reported result was a detected value). For example, if the baseline value was 10 ug/L and 

the laboratory reported a detected value of 5 ug/L, EPA’s calculations would treat the sample 

result as being non-detected with a sample-specific detection limit of 10 ug/L. 

EPA used the following baseline values for each pollutant in the development of the 

effluent limitations for the steam electric rulemaking:

• Arsenic: 2 ug/L; 

• Mercury: 0.5 ng/L; 

• Nitrate-nitrite as N: 0.05 mg/L; 

• Selenium: 5 ug/L; and

• TDS: 10 mg/L. 

EPA determined the baseline values for mercury, nitrate-nitrite as N, and TDS using the 

minimum levels (MLs) established by the analytical methods used to obtain the reported values 

or a comparable analytical method where an ML was not specified by the method.

111 The 

baseline values for arsenic and selenium are based on the results of method detection limit 

(MDL) studies conducted by well-operated commercial laboratories using EPA Method 200.8 to 

analyze samples of synthetic FGD wastewater. [CSC, 2013] 

 

110 For the purpose of the discussion of the calculation of the long-term averages, variability factors, and effluent 

limitations, the term “detected” refers to analytical results measured and reported above the sample-specific 

quantitation limit (QL). The term “non-detected” refers to values that are below the method detection limit (MDL) 

and also those measured by the laboratory as being between the MDL and the quantitation limit in the original data 

(before adjusting for baseline).

111 The baseline values for mercury and nitrate-nitrite as N are equal to the MLs specified in EPA Methods 1631E 

and 353.2, respectively. The method EPA used to analyze for TDS (Standard Method 2540C) does not explicitly 

state a MDL or ML. However, EPA Method 160.1 is similar to Standard Method 2540C and the lower limit of its 

measurement range is 10 mg/L (i.e., the nominal quantitation limit). Thus, EPA used 10 mg/L as the baseline value 

for TDS.
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In addition to calculating the limitations for each pollutant for each technology option 

adjusting for the baseline values, as described above, EPA also performed additional calculations 

to determine what the limitations would be using all valid reported results (i.e., without 

substituting baseline values and/or changing the classification of the result). The purpose of 

calculating the limitations using the data as reported is to allow a comparison between the 

limitations using baseline substitution and the limitations that would be obtained without the use 

of baseline substitution. For a detailed discussion of these calculations and the results, see the 

memorandum entitled, “Assessment of Effluent Limitations and Standards with No Baseline 

Substitution for the Steam Electric Rulemaking” [U.S. EPA, 2012b]. 

13.3 DATA AGGREGATION

EPA used daily values in developing the limitations. In cases with at least two samples 

per day, EPA mathematically aggregated these samples to obtain a single value for that day (the 

procedure to aggregate the samples is described in subsections below). For the sampling data 

used in this rulemaking, there are instances when there are multiple sample results available for a 

given day. This occurred with field duplicates, overlaps between plant self-monitoring and EPA 

sampling, or overlaps between plant self-monitoring and CWA 308 sampling. 

When aggregating the data, EPA took into account whether each value was detected (D) 

or non-detected (ND). Measurements reported as being less than the sample-specific detection 

limit (or baseline values, as appropriate) are designated as non-detected (ND) for the purpose of 

statistical analyses to calculate the limitations. In the tables and data listings in this document and 

in the rulemaking record, EPA uses the indicators D and ND denote the censoring type for 

detected and non-detected values, respectively.

The subsections below describe each of the different aggregation procedures. They are 

presented in the order that the aggregation was performed; i.e., field duplicates were aggregated 

first and then any overlaps between plant self-monitoring and EPA sampling data or CWA 308 

sampling were aggregated.

13.3.1 Aggregation of Field Duplicates 

During the EPA sampling episodes, EPA collected field duplicate samples as part of the 

quality assurance/quality control activities undertaken to ensure that the quality of the data 

collected is appropriate for their intended use. Field duplicates are two samples collected for the 

same sampling point at approximately the same time. The duplicates are assigned different 

sample numbers, and they are flagged as duplicates for a single sampling point at a plant. 

Because the analytical data from a duplicate pair are intended to characterize the same conditions 

at a given time at a single sampling point, EPA averaged the data to obtain one value for each 

duplicate pair.

In most cases, both duplicates in a pair had the same censoring type, so the censoring 

type of the aggregated value was the same as that of the duplicates. In some instances, one 

duplicate was a detected (D) value and the other duplicate was a non-detected (ND) value. When 

this occurred, EPA determined that the aggregated value should be treated as detected (D) 

because the pollutant is confirmed to be present at a level above the sample-specified detection 
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limit in one of the duplicates. The document entitled “Sampling Data Used as the Basis for 

Effluent Limitations for the Steam Electric Rulemaking” lists the data before the aggregation as 

well as after the aggregation [U.S. EPA, 2012c]. 

Table 13-1 below summarizes the procedure for aggregating the sample measurements

from the field duplicates. The aggregation of the duplicate pairs was the first step in the 

aggregation procedures for both influent and effluent measurements. 

Table 13-1. Aggregation of Field Duplicates

If the Field 

Duplicates Are:

Censoring Type 

of Average Is: Value of the Aggregate Is:

Formulas for Aggregate 

Values of Duplicates

Both Detected D Arithmetic average of measured values. (D1 + D2)/2

Both Non-Detected ND Arithmetic average of sample-specific 

detected limits (or baseline). (DL1 + DL2)/2

One Detected and 

One Non-Detected D Arithmetic average of measured value and sample-specific detection limit (or baseline). (D + DL)/2

D - detected. 

ND - non-detected. 

DL - sample-specific detection limit.

13.3.2 Aggregation of Overlapping Samples 

At the Allen and Belews Creek plants, sampling data were available from EPA sampling, 

CWA 308 sampling, and plant self-monitoring. As explained in Section 13.1.3 above, there was 

some overlap between the data from these sources. On some days at a given plant, samples were 

available from two sources, specifically, plant self-monitoring and either EPA sampling or CWA 

308 sampling. When these overlaps occurred, EPA aggregated the measurements from the 

available samples to obtain one value for that day. The document entitled “Sampling Data Used 

as the Basis for Effluent Limitations for the Steam Electric Rulemaking” lists the data before the 

aggregation as well as after the aggregations [U.S. EPA, 2012c]. 

The procedure averaged the measurements to obtain a single value for that day. When 

both measurements had the same censoring type, then the censoring type of the aggregate was 

the same as that of the overlapping values. When one or more measurements were detected (D), 

EPA determined that the appropriate censoring type of the aggregate was detected because the 

pollutant is confirmed to be present at a level above the sample-specific detection limit in one of 

the samples. The procedure for obtaining the aggregated value and censoring type is similar to 

the procedure shown in Table 13-1. 

13.4 DATA EDITING CRITERIA

After excluding and aggregating the data, EPA applied data editing criteria on a 

pollutant-by-pollutant basis to select the datasets to be used for developing the limitations for 

each technology option. These criteria are referred to as the long-term average test (or LTA test). 

EPA established the LTA test to ensure that the pollutants were present in the influent at

sufficient concentrations to evaluate treatment effectiveness at the plant. The influent first had to 
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13-10 

pass a basic requirement that 50% of the influent measurements for the pollutants had to be 

detected at any concentration. If the dataset at a plant passed the basic requirement, then the data 

had to pass one of the following two criteria to pass the LTA test: 

• Criterion 1. At least 50% of the influent measurements in a dataset at a plant were 

detected at levels equal to or greater than 10 times the baseline value (described in 

Section 13.2.2).

• Criterion 2. At least 50% of the influent measurements in a dataset at a plant were 

detected at any concentration and the influent arithmetic average was equal to or 

greater than 10 times the baseline value (described in Section 13.2.2).

If the dataset at a plant failed the basic requirement, then EPA automatically set both 

Criteria 1 and 2 to “fail”. If the dataset for a plant failed the basic requirement, or passed the 

basic requirement but failed both criteria, EPA would exclude the plant’s effluent data for that 

pollutant when calculating limitations. Through the application of the LTA test, EPA ensures 

that the limitations result from treatment of the wastewater and not simply the absence or 

substantial dilution of that pollutant in the wastestream.

After performing the LTA test for all the pollutants at each plant that was selected as the 

basis for the limitations for this rulemaking, it was found that all the datasets passed the LTA test 

except for arsenic and mercury data at Wabash River. Thus, data for arsenic and mercury at 

Wabash River were excluded from the calculation of the long-term average, variability factors, 

and limitations. See the memorandum entitled, “Effluent Limitations for FGD Wastewater, 

Gasification Wastewater, and Combustion Residual Leachate for the Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric Rulemaking” for the results of the 

LTA test for each pollutant at each plant [U.S. EPA, 2012a]. 

13.5 OVERVIEW OF LIMITATIONS

The preceding sections discussed the data selection, data exclusions and substitutions, 

data aggregation as well as the data editing procedures that EPA used to obtain the daily values 

for its calculations. This section describes EPA’s objectives for the daily maximum and monthly 

average effluent limitations, the selection of percentiles for those limitations, and compliance 

with the limitations.

13.5.1 Objectives

EPA’s objective in establishing daily maximum limitations is to restrict the discharges on 

a daily basis at a level that is achievable for a plant that targets its treatment at the long-term 

average. EPA acknowledges that variability around the long-term average occurs during normal 

operations. This variability means that plants may discharge at a level that is higher (or lower) 

than the long-term average. To allow for these possibly higher daily discharges, EPA has 

established the daily maximum limitation. A plant that consistently discharges at a level near the 

daily maximum limitation would not be operating its treatment to achieve the long-term average. 

Targeting treatment to achieve the daily maximum limitations, rather than the long-term average, 

may result in values that frequently exceed the limitations due to routine variability in treated 

effluent.
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EPA’s objective in establishing monthly average limitations is to provide an additional 

restriction to help ensure that plants target their average discharges to achieve the long-term 

average. The monthly average limitation requires dischargers to provide on-going control, on a 

monthly basis, that supplements controls imposed by the daily maximum limitation. In order to 

meet the monthly average limitation, a plant must counterbalance a value near the daily 

maximum limitation with one or more values well below the daily maximum limitation. To 

achieve compliance, these values must result in a monthly average value at or below the monthly 

average limitation.

13.5.2 Selection of Percentiles

EPA calculates effluent limitations based upon percentiles that should be both high 

enough to accommodate reasonably anticipated variability within control of the plant, and low 

enough to reflect a level of performance consistent with the Clean Water Act requirement that 

these effluent limitations be based on the “best” available technologies. The daily maximum 

limitation is an estimate of the 99th percentile of the distribution of the daily measurements. The 

monthly average limitation is an estimate of the 95th percentile of the distribution of the monthly 

averages of the daily measurements. The percentiles for both types of effluent limitations are 

estimated using the products of long-term averages and variability factors.

EPA uses the 99th and 95th percentiles to draw a line at a definite point in the statistical 

distributions that would ensure that operators work to establish and maintain the appropriate 

level of control. These percentiles reflect a longstanding Agency policy judgment about where to 

draw the line. The development of the limitations takes into account the reasonable anticipated 

variability in discharges that may occur at a well-operated plant. By targeting its treatment at the 

long-term average, a well-operated plant should be capable of complying with the effluent

limitations at all times because EPA has incorporated an appropriate allowance for variability in 

the limitations.

In conjunction with setting the limitations as described above, EPA performs an

engineering review to verify that the limitations are reasonable based upon the design and 

expected operation of the control technologies and the plant process conditions. As part of the 

review, for each plant EPA compared the influent and effluent measurements with the 

limitations. See Section 13.8 below for details of these comparisons for each pollutant at each 

plant, as well as a discussion of the findings of the engineering review.

13.5.3 Compliance with Limitations

EPA promulgates limitations with which plants are capable of complying at all times by 

properly operating and maintaining their processes and treatment technologies. Commenters 

often raise the issue of exceedances or excursions (i.e., values that exceed the limitations) on 

limitations.

This issue was, in fact, raised in other rulemakings, including EPA’s Organic Chemicals, 

Plastics, and Synthetic Fibers (OCPSF) rulemaking. EPA’s general approach there for 

developing limitations based on percentiles is the same in this rule, and was upheld in the court 
Section 13- Limitations and Standards: Data Selection and Calculation

13-12 

ruling of Chemical Manufacturers Association v. U.S. Environmental Protection Agency, 870 

F.2d 177, 230 (5th Cir. 1989). The Court determined that: 

EPA reasonably concluded that the data points exceeding the 99th and 95th percentiles 

represent either quality-control problems or upsets because there can be no other 

explanation for these isolated and extremely high discharges. If these data points 

result from quality-control problems, the exceedances they represent are within the 

control of the plant. If, however, the data points represent exceedances beyond the 

control of the industry, the upset defense is available.

Id. at 230. 

This issue was raised also in EPA’s Phase I rule for the pulp and paper industry. In that 

rulemaking, EPA used the same general approach for developing limitations based on percentiles 

that it had used for the OCPSF rulemaking and for this proposed rule. This approach for the 

monthly average limitation was upheld in National Wildlife Federation, et al v. Environmental 

Protection Agency, No. 99-1452, Slip Op. at Section III.D (D.C. Cir.) (April 19, 2002). The 

Court determined that: 

EPA's approach to developing monthly limitations was reasonable. It established 

limitations based on percentiles achieved by plants using well-operated and controlled 

processes and treatment systems. It is therefore reasonable for EPA to conclude that 

measurements above the limitations are due to either upset conditions or deficiencies 

in process and treatment system maintenance and operation. EPA has included an 

affirmative defense that is available to mills that exceed limitations due to an 

unforeseen event. EPA reasonably concluded that other exceedances would be the 

result of design or operational deficiencies. EPA rejected Industry Petitioners' claim 

that facilities are expected to operate processes and treatment systems so as to violate 

the limitations at some pre-set rate. EPA explained that the statistical methodology 

was used as a framework to establish the limitations based on percentiles. These 

limitations were never intended to have the rigid probabilistic interpretation that 

Industry Petitioners have adopted. Therefore, we reject Industry Petitioners' challenge 

to the effluent limitations.

As the Court recognized, EPA’s allowance for reasonably anticipated variability in its 

effluent limitations, coupled with the availability of the upset defense, reasonably accommodates 

acceptable excursions. Any further excursion allowances would go beyond the reasonable 

accommodation of variability and would jeopardize the effective control of pollutant discharges 

on a consistent basis. Further excursion allowances also could bog down administrative and 

enforcement proceedings in detailed fact finding exercises, contrary to Congressional intent. See, 

e.g., Rep. No. 92-414, 92d Congress, 2d Sess. 64, reprinted in A Legislative History of the Water 

Pollution Control Act Amendments of 1972 at 1482; Legislative History of the Clean Water Act 

of 1977 at 464-65. 

More recently, for EPA’s rule for the iron and steel industry, EPA’s selection of 

percentiles was upheld in American Coke and Coal Chemicals Institute v. Environmental 

Protection Agency, 452 F.3d 930, 945 (D.C. Cir. 2006). 
Section 13- Limitations and Standards: Data Selection and Calculation

13-13 

EPA expects that plants will comply with promulgated limitations at all times. If an 

exceedance is caused by an upset condition, the plant would have an affirmative defense to an 

enforcement action if the requirements of 40 CFR 122.41(n) are met. If the exceedance is caused 

by a design or operational deficiency, then EPA has determined that the plant’s performance 

does not represent the appropriate level of control. For promulgated limitations and standards, 

EPA has determined that such exceedances can be controlled by diligent process and wastewater 

treatment system operational practices such as frequent inspection and repair of equipment, use 

of back-up systems, and operator training and performance evaluations. 

13.6 CALCULATION OF THE LIMITATIONS

EPA calculated the limitations by multiplying the long-term average by the appropriate 

variability factors. In estimating the limitations for a pollutant, EPA first calculates an average 

performance level (the option long-term average discussed below) that a plant with welldesigned and well-operated model technologies is capable of achieving. This long-term average 

is calculated using data from the plant or plants with the model technologies for the option. 

In the second step of developing a limitation for a pollutant, EPA determines an 

allowance for the variation (the option variability factor discussed below) in pollutant 

concentrations for wastewater that has been processed through well-designed and well-operated

treatment systems. This allowance for variation incorporates all components of variability 

including shipping, sampling, storage, and analytical variability. This allowance is incorporated 

into the limitations through the use of the variability factors which are calculated from the data 

from the plants using the model technologies. If a plant operates its treatment system to meet the 

relevant long-term average, EPA expects the plant will be able to meet the limitations.

Variability factors ensure that normal fluctuations in a plant’s treatment are accounted for in the 

limitations. By accounting for these reasonable excursions above the long-term average, EPA’s 

use of variability factors results in effluent limitations that are generally well above the long-term 

averages.

The following sections describe the calculation of the option long-term averages, option 

variability factors and limitations, and the adjustment made for autocorrelation in the calculation 

of the limitations for each pollutant proposed for regulation. 

13.6.1 Calculation of Option Long-Term Average 

EPA calculated the option long-term average for a pollutant using two steps. First, EPA 

calculated the plant-specific long-term average for each pollutant that had enough distinct 

detected values by fitting a statistical model to the daily concentration values. In cases when a 

dataset for a specific pollutant did not have enough distinct detected values, then the statistical 

model was not used to obtain the long-term average. In these cases, the plant-specific long-term 

average for each pollutant was the arithmetic mean of the available daily concentration values. 

Appendix B contains the required minimum number of distinct detected observations and an 

overview of the statistical model and a description of the procedures EPA used to estimate the 

plant-specific long-term average. 
Section 13- Limitations and Standards: Data Selection and Calculation

13-14 

Second, EPA calculated the option long-term average for a pollutant as the median of the 

plant-specific long-term averages for that pollutant. The median is the midpoint of the values 

when ordered (i.e., ranked) from smallest to largest. If there is an odd number of values, then the 

value of the mth ordered observation is the median (where m=(n+1)/2 and n=number of values). 

If there are an even number of values, then the median is the average of the two values in the 

n/2th and [(n/2)+1]th positions among the ordered observations. 

13.6.2 Calculation of Option Variability Factors and Limitations 

The following describes the calculations performed to obtain the option variability factors 

and limitations. First, EPA calculated the plant-specific variability factors for each pollutant that 

had enough distinct detected values by fitting a statistical model to the daily concentration 

values. Each plant-specific daily variability factor for each pollutant is the estimated 99th

percentile of the distribution of the daily concentration values divided by the plant-specific longterm average. Each plant-specific monthly variability factor for each pollutant is the estimated 

95th percentile of the distribution of the 4-day average concentration values divided by the plantspecific long-term average. The calculation of the plant-specific monthly variability factor 

assumes that the monthly averages are based on the pollutant being monitored weekly 

(approximately four times each month). In cases when there were not enough distinct detected

values for a specific pollutant, then the statistical model was not used to obtain the variability 

factors. In these cases, the data for the pollutant at the plant was excluded from the calculation of 

the option variability factors. Appendix B contains the required minimum number of distinct 

detected observations and a description of the procedures used to estimate the plant-specific 

daily and monthly variability factors. 

Second, EPA calculated the option daily variability factor for a pollutant as the mean of 

the plant-specific daily variability factors for that pollutant. Similarly, the option monthly 

variability factor was the mean of the plant-specific monthly variability factors for that pollutant. 

Finally, the daily maximum limitations for each pollutant for each technology option are 

the product of the option long-term average and option daily variability factors. The monthly 

average limitations for each pollutant for each technology option are the product of the option 

long-term average and option monthly variability factors. 

13.6.3 Adjustment for Autocorrelation Factors

Effluent concentrations that are collected over time may be autocorrelated. The data are 

positively autocorrelated when measurements taken at specific time intervals, such as one or two 

days apart, are similar. For example, positive autocorrelation would occur if the effluent 

concentration were relatively high one day and were likely to remain high on the next and 

possibly succeeding days. Because the autocorrelated data affect the true variability of treatment 

performance, EPA typically adjusts the variance estimates for the autocorrelated data, when 

appropriate. 

For this rulemaking, whenever there was sufficient data for a pollutant at a plant to 

evaluate the autocorrelation reliably, EPA estimated the autocorrelation and incorporated it into 

the calculation of the limitations. For a plant without enough data to reliably evaluate and obtain 
Section 13- Limitations and Standards: Data Selection and Calculation

13-15 

an estimate of the autocorrelation, EPA set the autocorrelation to zero in calculation of the 

limitations. EPA did so because there were not sufficient data to reliably evaluate the 

autocorrelation, nor did EPA have a valid correlation estimate available that could be transferred 

from a similar technology and wastestream. See the memorandum entitled, “Serial Correlations 

for Steam Electric With and Without Adjustment for Baseline Values” for details of the 

statistical methods and procedures EPA used to determine the autocorrelation values, as well as a 

detailed discussion of the minimum number of observations needed to obtain a reliable estimate 

of the autocorrelation [Westat, 2013]. The following paragraphs describe the instances where 

EPA was able to obtain an estimated autocorrelation and the assumptions made about the 

autocorrelation when there were too few observations to estimate the autocorrelation. 

For the biological treatment technology for FGD wastewater (represented by Allen and 

Belews Creek plants), EPA was able to perform a statistical evaluation of the autocorrelation and 

obtain a reliable estimate of the autocorrelation because several years of data were available for 

these plants. As a result of the evaluation, EPA determined that adjustments for autocorrelation 

should be incorporated into the limitations for the biological treatment technology option. Table 

13-2 below lists the autocorrelation values EPA used in the calculation of the limitations for 

nitrate-nitrite as N and selenium. No autocorrelation values are presented here for arsenic and

mercury since EPA transferred the limitations from chemical precipitation technology option for 

FGD for these pollutants (see Section 13.7.2 for a detailed discussion of the transfer of these

limitations).

Table 13-2. Summary of Autocorrelation Values Used in Calculating the 

Limitations for Biological Treatment Technology Option for FGD Wastewater

Pollutant Correlation Value Used for Limit Calculations

Selenium

0.291

Nitrate-nitrite as N a

a - There were only eight observations available for nitrate-nitrite as N (only EPA sampling and CWA 308 sampling 

data available) at Allen and Belews Creek, so EPA was not able to evaluate the autocorrelation. EPA transferred the 

autocorrelation from selenium since these two chemicals behave similarly in the biological treatment system.

For the chemical precipitation treatment option for FGD wastewater (represented by 

Hatfield’s Ferry, Keystone, and Miami Fort plants), for the vapor-compression evaporation 

treatment technology option for FGD wastewater (represented by Brindisi), and for the vaporcompression evaporation treatment technology option for gasification wastewater (represented 

by Polk and Wabash River), EPA was unable to perform an evaluation and obtain a reliable 

estimate of the autocorrelation because there were too few observations available at the plants. 

Thus, for these plants, EPA set the autocorrelation to zero in the calculation of the limits. EPA 

did so because there were not sufficient data to reliably evaluate the autocorrelation, nor did EPA 

have a valid correlation estimate available that could be transferred from a similar technology

and wastestream. 

13.7 TRANSFERS OF THE LIMITATIONS

In some cases, EPA was either unable to calculate the limitations since there was no data 

available for the treatment technology option or determined that the treatment provided by plants 
Section 13- Limitations and Standards: Data Selection and Calculation

13-16 

employing the technology option did not fully represent the performance achievable by proper 

operation of all components of the model technologies. In these cases, EPA transferred 

limitations from another technology option. The following sections describe each case in which

the limitations were transferred.

13.7.1 Transfer of Arsenic and Mercury Limitations from Chemical Precipitation to 

Leachate

The effluent limitations for leachate based on the chemical precipitation technology 

option are transferred from the chemical precipitation technology option for FGD wastewater 

because EPA does not have the available effluent data for leachate from the plants that employ 

the chemical precipitation technology. This transfer of limitations for arsenic and mercury is 

appropriate because the pollutants in leachate are similar to those in FGD wastewater except at 

lower concentrations. The use of chemical precipitation technology to remove arsenic and 

mercury has been extensively demonstrated for a wide variety of industrial wastewaters 

including leachate from other industrial landfills. Because of the similarities between leachate 

and FGD wastewater, plants employing chemical precipitation treatment technology for leachate 

wastewater should be able to comply with the proposed limitations. 

13.7.2 Transfer of Arsenic and Mercury Limitations from Chemical Precipitation to 

Biological Treatment for FGD Wastewater 

EPA is transferring the FGD wastewater effluent limitations for arsenic and mercury 

calculated for the chemical precipitation technology option to the biological treatment 

technology option. This transfer of limitations for arsenic and mercury is appropriate because the 

plants represented by the chemical precipitation technology option better reflect the effluent 

concentrations that would be attained by the biological technology when it employs all features

in the technology option that work to remove arsenic, mercury and many other metals from the 

wastewater. The technology upon which biological treatment is based includes the following: 

equalization of the influent wastewater; chemical precipitation/coprecipitation to precipitate and 

remove both dissolved and particulate forms of the targeted pollutants (including pH adjustment, 

hydroxide precipitation, iron coprecipitation, sulfide precipitation, and clarification/filtration); 

and anoxic/anaerobic biological treatment to remove nitrogen (i.e., nitrate-nitrite as N) and both 

soluble and insoluble forms of selenium. All of these treatment steps contribute to the mercury 

removals achieved by the biological treatment technology although in different ways. 

Equalization of the treatment system influent stream acts to reduce the variability of the 

untreated wastewater, reducing extreme variations in flow rates and pollutant concentrations. In 

doing so, chemical dosage rates in chemical reaction tanks and clarifiers are more closely tuned 

to the characteristics of the untreated wastewater and provide the necessary chemistry 

adjustments. In addition, physical mixing or settling conditions are not subjected to sudden 

extreme fluctuations. The data for the biological treatment technology demonstrates that it is also 

effective at removing mercury from FGD wastewater, on the order of as much as 90 percent of 

the mercury entering the bioreactor.

EPA evaluated what the limitations for arsenic and mercury would be based on data from 

the two plants employing biological treatment: Allen and Belews Creek. Both of these plants 

have installed all equipment associated with the model technology; however, while both plants 
Section 13- Limitations and Standards: Data Selection and Calculation

13-17 

have installed the capability to add organosulfide chemicals to achieve sulfide precipitation of 

dissolved mercury in the chemical precipitation stage preceding the bioreactors, neither plant 

was dosing the organosulfide chemical during the periods covered by the effluent performance 

data. Although hydroxide precipitation may be sufficient for meeting NPDES permit limits for 

some plants, plants striving to maximize removals of mercury and other metals will also include 

sulfide addition (e.g., organosulfide) as part of the process. Adding sulfide chemicals in addition 

to the alkali provides even greater removals of heavy metals due to the very low solubility of 

metal sulfide compounds, relative to metal hydroxides. It is for this reason that the technology 

basis, for both the chemical precipitation technology option and the biological treatment 

technology option, includes the use of hydroxide precipitation, sulfide precipitation, and iron 

coprecipitation. Thus, although both Allen and Belews Creek have the technology in place, since 

neither was actually adding organosulfide they were not optimizing the pollutant removal 

efficacy of the treatment systems. Because of this, the treatment systems are susceptible to 

fluctuations in concentrations of dissolved metals, especially mercury, in the FGD wastewater. 

When the technology is operated without adding the chemicals for sulfide precipitation, it can be 

overwhelmed by high concentrations of dissolved mercury. To the extent these high 

concentrations of dissolved mercury pass though the chemical precipitation treatment stage 

(which is only partially effective at removing dissolved mercury when sulfide precipitation is not 

employed), they can also pass through the biological treatment stage at higher than normal 

concentrations even if approximately 90 percent of the mercury entering the bioreactors is 

removed. EPA’s analysis of the performance data for Allen and Belews Creek shows that 

dissolved mercury is not being adequately treated at these plants, which is attributable to the 

plants not adding organosulfide. In contrast, the plants used as the basis for the chemical 

precipitation technology are all adding organosulfide chemicals and operating the other key 

components for the chemical treatment stage for the biological treatment technology. EPA 

determined that the data used for chemical precipitation limitations better reflect the treatment 

efficacy for mercury and arsenic (and many other metals for which limitations are not being 

established) for treatment systems employing chemical precipitation/coprecipitation with both 

hydroxide and sulfide precipitation. 

As a result, EPA is proposing to establish the biological treatment technology limitations 

for arsenic and mercury based on transferring the limitations calculated for chemical 

precipitation treatment technology. EPA notes that it is reasonable to expect plants employing 

the biological treatment technology to actually achieve even better effluent performance, since 

the biological treatment stage will remove additional mercury following the chemical 

precipitation upon which the mercury and arsenic limits are now based. 

13.8 SUMMARY OF THE LIMITATIONS

Section 13.8.1 provides a summary of the plant-specific long-term averages, plantspecific daily variability factors, and plant-specific monthly variability factors for each pollutant 

in each treatment technology option. Section 13.8.2 provides a summary of the proposed 

limitations together with the option long-term average and variability factors for each pollutant 

in each treatment technology option. 
Section 13- Limitations and Standards: Data Selection and Calculation

13-18 

13.8.1 Summary of the Plant-Specific Long-Term Average and Variability Factors 

for Each Treatment Technology Option for FGD and Gasification Wastewaters 

The plant-specific long-term average and variability factors for each pollutant for each 

treatment technology option for FGD and gasification wastewaters are presented below. The 

document entitled, “Sampling Data Used as the Basis for Effluent Limitations for the Steam 

Electric Rulemaking” contains a listing of the data that were used to calculate the plant-specific 

results for each of the technology options [U.S. EPA, 2012c]. 

Chemical Precipitation Treatment Technology Option for FGD

Table 13-3 presents the plant-specific results (i.e., long-term averages and variability 

factors) for chemical precipitation as the technology basis for FGD wastewater. The pollutants 

proposed to be regulated under this technology option are arsenic and mercury.

Table 13-3. Plant-Specific Results for Chemical Precipitation as the 

Technology Basis for FGD Wastewater

Pollutant Plant Name

Autocorrelation 

Value

Plant-Specific

Long-Term 

Average

Plant-Specific 

Daily Variability 

Factor

Plant-Specific 

Monthly Variability 

Factor

Arsenic (ug/L)

Hatfield’s Ferry 0 6.682 2.285 1.373

Keystone 0 4.006 a --b --b

Miami Fort 0 4.483 1.197 1.072

Mercury (ng/L)

Hatfield’s Ferry 0 75.404 4.083 1.766

Keystone 0 64.260 3.257 1.584

Miami Fort 0 168.569 2.286 1.361

a - Long-term average is the arithmetic mean since there were too few detected observations.

b - Nearly all observations were non-detected, so variability factors could not be calculated.

Biological Treatment Technology Option for FGD 

Table 13-4 presents the plant-specific results (i.e., long-term averages and variability 

factors) for biological treatment for nitrate-nitrite as N and selenium as the technology basis for 

FGD wastewater. The pollutants proposed to be regulated under this technology option are 

arsenic, mercury, nitrate-nitrite as N, and selenium. As explained in detailed in Section 13.7.2

above, EPA is transferring the limitations for arsenic and mercury from the chemical 

precipitation treatment technology for FGD wastewater, thus, the table does not present the 

results for arsenic and mercury.
Section 13- Limitations and Standards: Data Selection and Calculation

13-19 

Table 13-4. Plant-Specific Results for Biological Treatment as the Technology 

Basis for FGD Wastewater

Pollutant Plant Name

Autocorrelation

Factor

Plant-Specific

Long-Term 

Average

Plant-Specific 

Daily Variability 

Factor

Plant-Specific 

Monthly 

Variability 

Factor

Arsenic (ug/L) a -- -- -- -- --

Mercury (ng/L) a -- -- -- -- --

Nitrate-nitrite as N (mg/L)

Allen 0.291 0.104 b --c --c

Belews Creek 0.291 0.115 1.499 1.157

Selenium (ug/L)

Allen 0.291 5.551 1.627 1.192

Belews Creek 0.291 9.359 2.663 1.450

a - Option LTA, option variability factors, and effluent limitations were transferred from chemical precipitation 

technology option for FGD wastewater.

b - Long-term average is the arithmetic mean since there were too few detected observations.

c - Nearly all observations were non-detected, so variability factors could not be calculated.

Vapor-Compression Evaporation Treatment Technology Option for FGD 

EPA based the limitations for the vapor-compression evaporation technology option on 

the effluent data at Brindisi. The treatment system for the Brindisi power plant actually produces 

two effluent streams: (1) brine concentrator distillate; and (2) crystallizer condensate. Both of 

these streams are essentially the condensed steam from different stages of the evaporation 

process. At Brindisi, these streams are ultimately recombined in a distillate tank and then reused 

at the plant. However, it is possible that a plant may choose to reuse both streams, discharge both 

streams, or reuse one stream while discharging the other to surface water. The effluent quality 

for the brine concentrator distillate and the crystallizer condensate are not identical. EPA 

anticipates that plants employing this treatment technology will often combine the two effluent 

streams from the evaporator. EPA considered establishing a single set of effluent limitations 

based on the two effluent streams being combined prior to discharge or reuse; however, there is 

sufficient uncertainty about the flow rates for each of the streams that preclude establishing a 

combined limitation. EPA also considered establishing two sets of effluent limitations, with a 

separate set of limitations for each effluent stream. Although this approach is technically 

feasible, it would require plants to collect and analyze separate samples for each effluent stream. 

EPA does not believe that establishing limitations for both effluent streams is necessary to ensure 

the FGD wastewater is being treated to the effluent quality achievable by operation of the 

evaporation technology, and that establishing separate limitations for each wastestream is 

unnecessarily burdensome. EPA believes a single set of effluent limitations will be sufficient to 

ensure the level of control would be achieved, should vapor-compression evaporation be selected 

as the technology basis for FGD wastewater. Because the effluent quality of the two effluent 

streams is not identical, EPA would establish the limitations based on the stream with the higher 

pollutant concentrations: crystallizer condensate. Setting the limitations on the higher 

concentration stream is necessary to ensure plants operating a well-designed and well-operated 

evaporation system can meet the limitations, regardless of whether they sample the effluent 

streams separately or as a combined stream. See the memorandum entitled, “Effluent Limitations 
Section 13- Limitations and Standards: Data Selection and Calculation

13-20 

for FGD Wastewater, Gasification Wastewater, and Combustion Residual Leachate for the 

Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Rulemaking for 

the limitations that were calculated for each of the effluent streams discussed above [U.S. EPA, 

2012a]. 

Table 13-5 presents the plant-specific results (i.e., long-term averages and variability 

factors) for vapor-compression evaporation treatment as the technology basis for FGD 

wastewater. The pollutants proposed to be regulated under this technology option are arsenic, 

mercury, selenium, and total dissolved solids (TDS). 

Table 13-5. Plant-Specific Results for Vapor-Compression Evaporation 

(Crystallizer Condensate) as the Technology Basis for FGD Wastewater

Pollutant Plant Name

Autocorrelation 

Value

Plant -Specific

Long-Term 

Average

Plant -Specific 

Daily Variability 

Factor

Plant - Specific 

Monthly Variability 

Factor

Arsenic (ug/L) Brindisi 0 4.0 a --b --b

Mercury (ng/L) Brindisi 0 17.788 2.192 1.338

Selenium (ug/L) Brindisi 0 5.0 a --b --b

TDS (mg/L) Brindisi 0 14.884 3.341 1.572

a - Long-term average is the arithmetic mean since all observations were detected observations.

b - All observations were non-detected, so variability factors could not be calculated.

Vapor-Compression Evaporation Treatment Technology Option for Gasification 

Wastewater

In developing the limitations for this technology option, EPA calculated the limitations 

using the data from Wabash River and Polk. The treatment system at Wabash River produces 

one effluent stream: condensate from vapor compression evaporator. The treatment system for 

Polk Power Station actually produces two effluent streams: (1) condensate from the vapor 

compression evaporator; and (2) condensate from the forced circulation evaporator. Both of 

these streams at Polk are essentially the condensed steam from different stages of the evaporation 

process. Because it is possible that a plant may choose to reuse both streams, discharge both 

streams, or reuse one stream while discharging the other to surface water. EPA considered data 

from the following effluent streams when developing the limitations for this technology option: 

(i) forced circulation evaporator condensate effluent (based only on Polk); and (ii) vapor 

compression evaporator effluent (based on Polk and Wabash River). EPA is proposing the 

limitations for this technology option based on vapor compression evaporator effluent data. EPA 

decided to propose the limitations based on vapor compression evaporator effluent data since 

EPA determined that the data collected at forced circulation evaporator condensate did not 

demonstrate typical removal rates for pollutants generally well treated by evaporation and 

therefore were not adequate to form the basis of the limitations. Based on its review of the 

treatment system, EPA believes that the evaporator (or at a minimum the forced circulation 

evaporation stage) was operating abnormally and allowing carryover of pollutant to the 

condensate effluent stream. For this reason, EPA based the limitations for this technology option 

on the limitations calculated from the vapor compression evaporator effluent data. Table 13-6

presents the plant-specific results (i.e., long-term averages and variability factors) for vapor-
Section 13- Limitations and Standards: Data Selection and Calculation

13-21 

compression evaporation treatment as the technology basis for gasification wastewater. The 

pollutants proposed to be regulated under this technology option are arsenic, mercury, selenium, 

and total dissolved solids (TDS). As explained in Section 13.4, the data for arsenic and mercury 

at Wabash River failed the data editing criteria, thus, EPA excluded the arsenic and mercury 

datasets from Wabash River when calculating the limitations for this technology option. 

Table 13-6. Plant-Specific Results for Vapor-Compression Evaporation 

(Vapor-Compression Evaporator Condensate) as the Technology Basis 

for Gasification Wastewater

Pollutant Plant Name

Autocorrelation 

Factor

Plant -Specific

Long-Term 

Average

Plant -Specific Daily

Variability Factor

Plant - Specific 

Monthly Variability 

Factor

Arsenic (ug/L) Polk 0 4.00 a --b --b

Mercury (ng/L) Polk 0 1.075 1.632 1.194

Selenium (ug/L)

Polk 0 288.430 3.083 1.545

Wabash River 0 5.130 --b --b

TDS (mg/L)

Polk 0 16.512 2.149 1.327

Wabash River 0 13.906 2.818 1.450

a - Long-term average is the arithmetic mean since there are too few detected observations.

b - Nearly all observations were non-detected, so variability factors could not be calculated.

13.8.2 Summary of the Option Long-Term Averages, Option Variability Factors, 

and Limitations for Each Treatment Technology Option for FGD, Gasification, 

and Leachate Wastewaters

This section presents the proposed daily maximum and monthly average limitations, as 

well as the option long-term average and variability factors for each pollutant in each of the 

treatment technology options for FGD, gasification, and leachate wastewaters. These results 

were obtained by combining the plant-specific results in each technology option presented in 

Section 13.8.1 (except for leachate wastewater because the limitations for leachate were 

transferred). As mentioned above, the option long-term average for each pollutant is the median 

of the plant-specific long-term averages. The option variability factor for each pollutant is the 

mean of the plant-specific variability factors. The daily limitation for each pollutant is the 

product of the option long-term average and option daily variability factor. The monthly average 

limitation for each pollutant is the product of the option long-term average and option monthly 

variability factor.

The limitations for FGD wastewater based on chemical precipitation followed by vaporcompression evaporation and the limitations for gasification wastewater based on vaporcompression are each based on data from one plant. As such, the option long-term averages and 

variability factors for these options are the same as the plant-specific long-term averages and 

variability factors. Also, in special cases where there are too few detected results, the statistical 

models are not appropriate for calculating limitations since reliable estimates could not be 

obtained from the models. In such instances, EPA has established the daily maximum limitations
Section 13- Limitations and Standards: Data Selection and Calculation

13-22 

based on the detection limit (i.e., “minimum level”).

112 Also, monthly average limitations are not 

established when the daily maximum limitation is based on the detection limit.

In developing the long-term average and variability factors, EPA used five digit decimal 

points for accuracy (but only three digit decimal points are presented in for simplification of the 

presentation); however, EPA rounded the limitations upward to allow for more variability during 

actual monitoring. In most instances, limitations greater than 1.0 were rounded upward to the 

next highest integer, while limitations less than 1.0 were rounded up to the next highest 

hundredths decimal place. For gasification wastewater, however, if EPA were to round both 

limitations up to the next highest integer, the daily and monthly average limitations for mercury 

for gasification wastewater would be the same (i.e., both limits would be 2 ng/L since the prerounded daily and monthly average limitations were calculated to be 1.754 and 1.284, 

respectively). Thus, in order to avoid having the same value for the daily and monthly average 

limitation, the proposed daily and monthly average limitations for mercury for gasification 

wastewater were rounded to next highest hundredths decimal place. 

Table 13-7 provides the preferred option long-term average, option variability factors, 

and limitations for each of the FGD, gasification, and leachate technology options. 

Table 13-7. Proposed Option Long-Term Averages, Option Variability Factors, 

and Limitations for Each of the FGD, Gasification, and Leachate Technology Options

Treatment 

Technology Option Pollutant

Option 

LongTerm 

Average

Option Daily 

Variability 

Factor

Option 

Monthly 

Variability 

Factor

Daily 

Maximum 

Limitationd

Monthly 

Average 

Limitationd

Chemical Precipitation 

for FGD Wastewater

Arsenic (ug/L) 4.483 1.741 1.223 8 6

Mercury (ng/L) 75.404 3.209 1.570 242 119

Chemical Precipitation 

and Biological

Treatment

for FGD Wastewater

Arsenic (ug/L) a 4.483 1.741 1.223 8 6

Mercury (ng/L) a 75.404 3.209 1.570 242 119

Nitrate-nitrite as N 

(mg/L) 0.110 1.499 1.157 0.17 0.13

Selenium (ug/L) 7.455 2.145 1.321 16 10

Chemical Precipitation 

and Evaporation for 

FGD Wastewater 

Arsenic (ug/L) 4.0 b --c --c 4 e --f

Mercury (ng/L) 17.788 2.192 1.338 39 24

Selenium (ug/L) 5.0 b --c --c 5 e --f

TDS (mg/L) 14.884 3.341 1.572 50 24

 

112 As used in this chapter of this document, “detection limit” refers to the quantitation limit (QL) and not the 

method detection limit (MDL). Thus, effluent limitations in those instances would be established as a daily 

maximum limit at the quantitation limit.
Section 13- Limitations and Standards: Data Selection and Calculation

13-23 

Table 13-7. Proposed Option Long-Term Averages, Option Variability Factors, 

and Limitations for Each of the FGD, Gasification, and Leachate Technology Options

Treatment 

Technology Option Pollutant

Option 

LongTerm 

Average

Option Daily 

Variability 

Factor

Option 

Monthly 

Variability 

Factor

Daily 

Maximum 

Limitationd

Monthly 

Average 

Limitationd

Vapor-Compression 

Evaporation for 

Gasification 

Wastewater 

Arsenic (ug/L) 4.0 b -- c -- c -- 4e --f

Mercury (ng/L) 1.075 1.632 1.194 1.76 1.29

Selenium (ug/L) 146.780 3.083 1.545 453 227

TDS (mg/L) 15.209 2.483 1.389 38 22

Chemical Precipitation 

for Leachate 

Wastewater

Arsenic (ug/L)a 4.483 1.741 1.223 8 6

Mercury (ng/L)a 75.404 3.209 1.570 242 119

a - Option LTA, option variability factors, and limitations were transferred from chemical precipitation technology 

option for FGD wastewater.

b - Long-term average is the arithmetic mean since all observations were non-detected.

c - All observations were non-detected, so variability factors could not be calculated.

d - Limitations less than 1.0 are rounded up to the next highest hundredths decimal place. Limitations greater than 

1.0 have been rounded upward to the next highest integer, except for limitations for mercury based on the vaporcompression evaporation treatment technology option for gasification wastewater which have been rounded up to 

the next highest hundredths decimal place.

e - Limitation is set equal to the detection limit.

f - Monthly average limitations are not proposed when the daily maximum limitation is based on the detection limit.

13.9 ENGINEERING REVIEW OF THE LIMITATIONS

In conjunction with the statistical methods, EPA performed an engineering review to 

verify that the proposed limitations are reasonable based upon the design and expected operation 

of the control technologies. The following sections describe two types of comparisons that EPA 

performed. First, EPA compared the limitations to the effluent data used to develop the 

limitations. Second, EPA compared the limitations to the influent data. For the detailed results of 

these comparisons, see the memorandum entitled, “Effluent Limitations for FGD Wastewater, 

Gasification Wastewater, and Combustion Residual Leachate for the Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric Rulemaking” [U.S. EPA, 2012a]. 

13.9.1 Comparison of Limitations to Effluent Data Used As Basis for the Limitations

As part of its data evaluations, EPA compared the value of the limitations to the effluent 

values used to calculate the limitations. This type of comparison helps to evaluate how 

reasonable the proposed limitations may be from an engineering perspective. Since EPA is 

proposing both daily and monthly average limitations, EPA has performed two comparisons for 

each pollutant in each technology option. EPA first compared the daily limitations to the daily 

effluent values. Second, EPA compared the monthly average limitations to all the effluent daily 

values, and identified those months where at least one value within a month exceeded the 

monthly average limitations.
Section 13- Limitations and Standards: Data Selection and Calculation

13-24 

After thoroughly evaluating the results of the comparison between the limitations and the 

effluent values used to calculate the limitations for each treatment technology option for FGD 

and gasification wastewaters, EPA determined that the statistical distributional assumptions used 

to develop the limitations are appropriate for the data, and thus the limitations for each 

technology option are reasonable. (This conclusion is also true for the leachate limitations based 

on the chemical precipitation technology since the leachate limitations were transferred from the 

FGD wastewater technology option.) If a plant properly designs and operates its wastewater 

treatment system to achieve the option long-term average for the model technology (rather than 

targeting performance at the effluent limitations themselves), it will be able to comply with the 

limitations. The sections below discuss the results of the comparisons for each of the technology 

options. See the memorandum entitled, “Effluent Limitations for FGD Wastewater, Gasification 

Wastewater, and Combustion Residual Leachate for the Proposed Effluent Limitations 

Guidelines and Standards for the Steam Electric Rulemaking” for a listing of all daily effluent 

values that exceeded the daily and monthly average limitations for each pollutant in each 

treatment technology option [U.S. EPA, 2012a]. 

Chemical Precipitation Treatment Technology Option for FGD Wastewater 

For the chemical precipitation treatment technology option for FGD wastewater, EPA is 

proposing limitations for arsenic and mercury. The limitations were calculated using data from 

three plants: Hatfield’s Ferry, Keystone, and Miami Fort. 

For both arsenic and mercury, there are some daily effluent concentration values that are 

above both the daily and monthly average limitations. After thoroughly examining the data, EPA 

determined that the concentration values that are above both the daily and monthly limitations 

for arsenic came from the plant with relatively higher effluent concentration values (i.e., with a 

higher long-term average than the other two plants). EPA observed that the same was true for the 

mercury concentration values that are above both the daily and monthly limitations calculated for 

the chemical precipitation technology option. Since the limitations are developed using the data 

from all three plants, it is reasonable to expect that the plant with relatively higher concentrations 

is more likely to have values above the daily and monthly limitations. As EPA explains below in 

this section, it is reasonable for this situation to arise in the datasets used to calculate the

limitations and there are specific steps plants can take that enable them to improve treatment 

system performance so that effluent concentrations would be in compliance with the proposed 

limitations at all times.

EPA also identified an instance where two (of four) daily concentration values in a month 

are higher than the monthly limitation, and the resulting monthly average is equal to the monthly 

average limitation. Instances such as this (i.e., where one or more individual results are higher 

than the monthly limitation, but the average of all results in a month are equal to or below the 

monthly limitation) are normal and consistent with the way effluent limitations are calculated 

and implemented in NPDES permits. This is illustrated, in fact, by the selenium data for the 

biological treatment technology option, as described in the next section. EPA also identified 

some cases where only one sample was taken during a month and the resulting concentration 

value for that lone sample is above the average monthly limitation. In such cases, additional 

monitoring of the effluent (e.g., at weekly intervals) would likely result in a monthly average that 

would fall below the monthly limitation.
Section 13- Limitations and Standards: Data Selection and Calculation

13-25 

In addition, EPA identified one month where two (out of four) daily concentration values 

from the month are above the monthly average limitation, and the resulting monthly average for 

all four values is above the monthly limitation. Based on its engineering judgment developed 

over years of evaluating wastewater treatment processes for power plants and other industrial 

sectors, EPA determined that the combination of additional monitoring, closer operator attention, 

and optimizing treatment system performance to target the effluent concentrations at the 

technology option long-term average will result in lower effluent concentrations that would be in 

compliance with the proposed effluent limitations.

EPA noted that while these plants were selected as representing the “best available” 

technology, it does not mean that the plants have the systems fully optimized, especially since 

most of the plants do not have specific limits on the FGD wastewater for the pollutants of 

concern or because their existing limits are well above what the system is achieving. 

Specifically, none of these three plants have specific limits for arsenic. Also, only Keystone and 

Hatfield’s Ferry have NPDES permit limits on mercury; however, their current permit limits are 

more than 30 times higher than the proposed BAT effluent limitations. For this reason, these 

plants currently do not need to closely monitor the treatment system to confirm performance 

below their permit limitation. If these plants were required to meet the proposed limitations, EPA 

believes that these plants would be capable of meeting the limitations without significant 

expense. For example, EPA’s review of chemical precipitation systems for this industry noted 

that plants could benefit from using an in-house mercury analyzer to monitor the performance of 

the system on a daily basis. Mercury analyzers have been effectively used at a power plant to 

alert operators when mercury concentrations begin trending upward so that they may take steps 

to adjust treatment system performance and remain in compliance with their NPDES permit 

limits. Furthermore, some plants that rely solely on hydroxide precipitation could add sulfide 

precipitation to improve removals of arsenic and mercury. Organosulfide addition, particularly 

using long-chain organosulfide polymers, has been demonstrated to be particularly effective at 

improving mercury removals in chemical precipitation treatment systems. Finally, EPA has also 

evaluated the results of testing at a power plant that, although its FGD wastewater treatment 

system had been in operation for more than a year and was operating at a steady state condition, 

the plant significantly improved the pollutant removal performance merely by altering the dosage 

rates for the wastewater treatment chemical additives. As a result, EPA identified various 

approaches plants can use to improve their performance and achieve the limitations. EPA notes 

that its compliance cost estimates for the proposed rule includes costs for mercury analyzers, 

sulfide precipitation, and proper dosing of treatment system chemical additives.

Based on the results of the comparisons described above, EPA determined that the 

statistical distributional assumptions are appropriate for the effluent data and that the proposed 

limitations are reasonable.

Biological Treatment Technology Option for FGD Wastewater 

For the biological treatment technology option for FGD wastewater, EPA is proposing 

limitations for arsenic, mercury, nitrate-nitrite as N, and selenium. For arsenic and mercury, EPA 

transferred the limitations from the chemical precipitation treatment system for FGD wastewater 

(as explained in Section 13.7.2 above). Because the limitations for arsenic and mercury were 

transferred and since this technology option includes chemical precipitation as a first step, the 
Section 13- Limitations and Standards: Data Selection and Calculation

13-26 

comparison described above for the chemical precipitation technology option is relevant for 

arsenic and mercury. Because of this, EPA expects that the plants employing this technology 

option would be able to comply with the proposed arsenic and mercury limitations. Furthermore, 

EPA’s data demonstrate that the biological treatment stage provides pollutant removals for 

arsenic and mercury (and other pollutants of concern with similar removal mechanisms) in 

addition to the pollutant removals that occur in the chemical precipitation stage of the biological 

treatment technology option (see, for example, Section 10.4.1). Thus, plants employing and 

optimally operating all components of the biological treatment technology option (including 

adding organosulfide to achieve sulfide precipitation) should achieve pollutant removals for 

arsenic and mercury (and other pollutants with similar removal mechanisms) that are equal to or 

even greater than the removals based on chemical precipitation technology.

For nitrate-nitrite as N at Allen, all daily effluent concentration values are below both the 

daily and monthly limitations. For nitrate-nitrite as N at Belews Creek, all daily effluent values 

are below the daily limitation. However, there are two nitrate-nitrite as N daily effluent values in 

different months that are above the monthly limitation. In each case only one sample was 

collected during the month. As explained above for the chemical precipitation technology option 

and demonstrated in the following paragraph, additional effluent monitoring (e.g., at weekly 

intervals) would likely result in a monthly average that would fall below the monthly limitation. 

For selenium at Allen, all daily effluent concentration values are below the daily 

limitation. Only one daily effluent value (out of two collected in the same month) for Allen is 

above the monthly limitation. However, after averaging these two observations, the average for 

the month is below the monthly limitation. All other daily concentration values for Allen, 

spanning the period from September 2009 through May 2011, are below the average monthly 

limitation.

For selenium at Belews Creek, there are some daily effluent observations that are above 

both the daily and monthly limitations. After thoroughly examining the data, EPA determined 

that the effluent concentration values at Belews Creek are relatively higher (i.e., with a higher 

long-term average) than the effluent concentration values at Allen. As discussed above, since the 

limitations are developed using the data from both plants, it is reasonable to expect that the plant 

with relatively higher concentrations is more likely to have values above the daily and monthly 

limitations. Furthermore, as EPA explained above there are steps plants can take to achieve 

better treatment system performance to ensure compliance with the effluent limitations. EPA 

identified instances in which some daily effluent values at Belews Creek are above the average 

monthly limitations. However, these are the only concentration values that were collected within 

each of those months. As described above, additional effluent monitoring (e.g., at weekly 

intervals) would likely result in a monthly average that would fall below the monthly limitation. 

EPA also identified four instances where some (or all) daily concentration values from a month 

are above the monthly limitation, but the daily values for other samples collected within the 

month are below the monthly limitation. In these instances, the average for all samples collected 

within the month is above the monthly limitation. Three of these four instances occur in the first 

three months of operation (August–October 2008) following the end of the initial commissioning 

period for the treatment system. The Belews Creek FGD wastewater treatment system was the 

first FGD bioreactor system operated by Duke Energy, and one of the first two systems to begin 

operating in the U.S. After evaluating all selenium data for the biological treatment technology 
Section 13- Limitations and Standards: Data Selection and Calculation

13-27 

option (nearly three years of data for Belews Creek and nearly two years for Allen, excluding the 

initial commissioning periods), EPA concluded that the selenium results for August-October 

2008 reflect less than optimum performance of the treatment system due either to the 

inexperience of operators with this type of treatment system, or to continued variability 

associated with the initial commissioning of the treatment system, or a combination thereof.

113

Based on the results of this comparison for the biological treatment technology option based on 

Allen and Belews Creek, EPA determined that the statistical distributional assumptions are

appropriate for the effluent data and that the proposed limits are reasonable. 

Vapor-Compression Evaporator Treatment Technology Option for FGD Wastewater 

For the chemical precipitation followed by vapor-compression evaporation treatment 

technology option for FGD wastewater, EPA developed limitations for arsenic, mercury, 

selenium, and TDS. The limitations were calculated using data from Brindisi plant. All daily 

effluent concentration values are below the daily and monthly limitations. After thoroughly 

reviewing the data, EPA determined that the statistical distributional assumptions are appropriate 

for the effluent data and that the proposed limitations are reasonable. 

Vapor-Compression Evaporator Treatment Technology Option for Gasification 

Wastewater

For the vapor-compression evaporation treatment technology option for gasification 

wastewater, EPA is proposing limitations for arsenic, mercury, selenium, and TDS. The 

limitations were calculated using data from both the Polk and Wabash River plants, except for 

the arsenic and mercury limitations, which were based only on data from Polk (since data from 

Wabash River failed the LTA test).

For arsenic and mercury, daily concentration values are below both the daily and monthly 

limitations. For total dissolved solids, there is one (out of four collected in the same month) daily 

effluent concentration value at Polk above the monthly limitation. However, after averaging 

these four observations, the average for the month is below the monthly limitation.

For selenium at Polk, there is one daily effluent concentration value above the daily 

limitation. Also, there are two (out of four collected in the same month) daily effluent values 

above the monthly average limitation. After averaging these four observations, the average for 

the month is above the monthly limitation. After thoroughly examining the data, EPA 

determined that the effluent concentration values for selenium at Polk are relatively higher (i.e., 

with a higher long-term average) than the effluent concentration values at Wabash River. As 

discussed above, since the limitations are developed using the data from both plants, it is 

 

113 Note that although the Belews Creek selenium data (and other pollutants as well) from August-October 2008 may 

be influenced by the initial commissioning period for the treatment system, EPA used these data when calculating 

the proposed effluent limitations for the biological treatment technology option for FGD wastewater. EPA has used 

the August-October 2008 data because although EPA believes that, as a general rule, the initial commissioning 

period duration will be on the order of 3-4 months, and certainly no more than 6 months except in unique 

circumstances, EPA has not confirmed that the initial commissioning for Belews Creek was of such exceptional 

duration. Without the information to confirm the commissioning period was still in progress, EPA concluded that 

the sampling data should be used when calculating effluent limitations.
Section 13- Limitations and Standards: Data Selection and Calculation

13-28 

reasonable to expect that the plant with relatively higher concentrations is more likely to have 

values above the daily and monthly limitations. Additionally, as discussed above in Section 

13.8.1, the data for the Polk treatment system indicates that the evaporator (or at a minimum the 

forced circulation evaporation stage) was operating abnormally and allowing carryover of 

pollutants to the condensate effluent stream. Based upon its review of the data, EPA concluded if 

the plant designed and operated its treatment system to achieve the option long-term average for 

the model technology, then the plant will be able to comply with the proposed limitation. 

Further, EPA notes that the Polk reuses all treatment gasification wastewater (i.e., condensate) in 

the gasification process and does not discharge any gasification wastewater. As such, the plant’s 

treatment objective is to ensure the wastewater is of sufficient quality for reuse in the process 

rather than to comply with a NPDES permit limit. Thus, EPA concluded that the statistical 

distributional assumptions are appropriate for the effluent data and that the proposed limitations 

are reasonable.

13.9.2 Comparison of Proposed Limitations to Influent Data 

In addition to comparing the proposed limitations to the data used to develop the 

limitations, EPA also compared the proposed limitations to the influent concentration values. 

This comparison helps evaluate whether the proposed limitations are set at a level that ensures 

that treatment of the wastewater would be necessary to meet the limitations and that the influent 

concentrations were generally well-controlled by the treatment system. In doing so, EPA 

confirms that treatment to remove the regulated pollutants will take place. See the memorandum 

entitled, “Effluent Limitations for FGD Wastewater, Gasification Wastewater, and Combustion 

Residual Leachate for the Proposed Effluent Limitations Guidelines and Standards for the Steam 

Electric Rulemaking” for a detailed listing of the summary statistics for the influent data for each 

pollutant in each treatment technology option [U.S. EPA, 2012a].

For all treatment technology options for both FGD and gasification wastewater, the 

minimum, average, and maximum influent concentration values were much higher than the longterm average and proposed limitations. Thus, EPA determined that plants would need to treat the 

wastewater to ensure compliance with the proposed limitations and that the proposed rule would 

result in removing the regulated pollutants and other pollutants of concern. Furthermore, in 

evaluating influent concentrations, EPA found that influent concentrations were generally wellcontrolled by the treatment plant for all plants with model technology. In general, the treatment 

systems adequately treated even the extreme influent values, and the high effluent values did not 

appear to be the result of high influent discharges. 

13.10 REFERENCES

1. Computer Sciences Corporation (CSC). 2013. Results of the ICP/MS Collision Cell 

Method Detection Limit Studies in the Synthetic Flue Gas Desulfurization Matrix. (16 

January). DCN SE03872. 

2. U.S. EPA. 2012a. Memorandum to Ronald Jordan: Effluent Limitations for FGD 

Wastewater, Gasification Wastewater, and Combustion Residual Leachate for the 

Proposed Effluent Limitations Guidelines and Standards for the Steam Electric 

Rulemaking. (20 October). DCN SE01999. 
Section 13- Limitations and Standards: Data Selection and Calculation

13-29 

3. U.S. EPA. 2012b. Memorandum to Steam Electric Rulemaking Record: Assessment of 

Effluent Limitations and Standards with No Baseline Substitution for the Steam Electric 

Rulemaking. (18 November). DCN SE02000. 

4. U.S. EPA. 2012c. Sampling Data Used as the Basis for Effluent Limitations for the 

Steam Electric Rulemaking. (31 October). DCN SE02002. 

5. Westat. 2013. Memorandum to Cuc Schroeder: Serial Correlations for Steam Electric 

With and Without Adjustment for Baseline Values. (15 April). DCN SE02001. 

6. Results of the ICP/MS Collision Cell Method Detection Limit Studies in the Synthetic 

Flue Gas Desulfurization Matrix - DCN SE03872
Section 14 – Regulatory Implementation

14-1 

SECTION 14

REGULATORY IMPLEMENTATION

This section provides guidance to permit writers and control authorities (e.g., publicly 

owned treatment works (POTWs)) in implementing the revisions to the steam electric effluent 

limitations guidelines and standards (ELGs). 

14.1 IMPLEMENTATION OF THE LIMITATIONS AND STANDARDS

Effluent guidelines limitations and standards act as a primary mechanism to control the 

discharge of pollutants to waters of the United States. The BAT and NSPS limitations and 

standards in the proposed rule would be applied to steam electric wastewater discharges through 

incorporation into NPDES permits issued by the EPA or states under Section 402 of the Act. The 

PSES and PSNS standards are implemented through pretreatment programs under Section 307 of 

the Act.

The Agency has developed the limitations and standards for this proposed rule to control 

the discharge of pollutants from the steam electric power generating point source category. Once 

promulgated, those permits or control mechanisms issued after this rule’s effective date would be 

required to incorporate the effluent limitations guidelines and standards, as applicable. Also, 

under section 510 of the CWA, states may require effluent limitations under state law as long as 

they are no less stringent than the requirements of this rule. Finally, in addition to requiring 

application of the technology-based effluent limitations guidelines and standards in this rule, 

section 301(b)(1)(C) of CWA requires the permitting authority to impose more stringent effluent 

limitations on discharges as necessary to meet applicable water quality standards.

14.1.1 Timing

For the reasons explained in Section 8.2, EPA proposes that certain limitations and 

standards based on any of the eight main regulatory options being proposed for existing direct 

and indirect dischargers do not apply until July 1, 2017 (approximately three years from the 

effective date of this rule). EPA finds this is appropriate for any proposed BAT and PSES for 

FGD wastewater, gasification wastewater, fly ash transport water, flue gas mercury control 

wastewater, bottom ash transport water, or combustion residual leachate where EPA is not 

proposing to establish BAT limitations that are equal to BPT limitations. For those plants and 

wastestreams where EPA is proposing to establish BAT equal to the current BPT effluent 

limitations, the revised BAT requirements would be applicable on the effective date of the final 

rule.

The proposed requirements for new direct and indirect dischargers (NSPS and PSNS) and 

the proposed requirements for existing sources where BAT is set equal to BPT would be 

applicable as of the effective date of the final rule.

14.1.2 Applicability of NSPS/PSNS

In 1982, EPA promulgated NSPS/PSNS for certain discharges from new units. 

Regardless of the outcome of the current rulemaking, those units that are currently subject to the 
Section 14 – Regulatory Implementation

14-2 

1982 NSPS/PSNS will continue to be subject to such standards. In addition, EPA is proposing to 

clarify in the text of the regulation that, assuming the Agency promulgates BAT/PSES 

requirements as part of the current rulemaking, units to which the 1982 NSPS/PSNS apply will 

also be subject to any newly promulgated BAT/PSES requirements because they will be existing 

sources with respect to such new requirements.

14.1.3 Legacy Wastes 

For the reasons explained in Section 8.1.2, EPA is proposing that BAT and PSES

requirements for existing sources based on any of the eight main regulatory options would apply 

to discharges of FGD wastewater, fly ash transport water, bottom ash transport water, FGMC 

wastewater, combustion residual leachate, and gasification wastewater generated on or after the 

date established by the permitting authority that is as soon as possible after July 1, 2017.114 Such 

wastewater generated prior to that date (i.e., “legacy” wastewater), in the case of direct 

dischargers, would remain subject to the existing BPT effluent limits. EPA is also considering 

establishing BAT effluent limitations for legacy wastewater (except gasification wastewater) that 

would be equal to the existing BPT effluent limits.

EPA also considered subjecting the legacy wastewater (except gasification wastewater) to 

the proposed BAT and PSES requirements. However, EPA found that these legacy wastewaters 

are typically transferred to surface impoundments that often commingle these legacy 

wastewaters and also contain other plant wastewaters, such as cooling water, coal pile runoff, 

and/or other low volume wastes. For each of the wastestreams for which EPA is proposing new 

BAT/PSES requirements, EPA does not have data to demonstrate that the technologies identified 

as representing BAT for newly generated wastewater from the various sources considered (e.g., 

FGD wastewater, fly ash transport wastewater) would also represent BAT for the legacy 

wastewaters. For example, for fly ash transport water, the technology basis identified for the 

proposed zero discharge requirement (i.e., conversion to dry ash handling) would eliminate 

generating new volumes of fly ash transport water but does not eliminate fly ash transport water 

that has already been generated and transferred to an impoundment prior to the conversion. EPA 

also evaluated whether other technologies would be available that might represent BAT for these 

legacy wastewaters. However, EPA determined these alternatives are either impracticable or 

insufficient data are available for establishing effluent limitations. For example, for a surface 

impoundment that receives both fly ash transport water and cooling tower blowdown, if the plant 

converts to a dry ash handling system, the surface impoundment would cease to receive 

additional fly ash transport water, but it would continue to receive the cooling tower blowdown. 

In this example, the surface impoundment would now contain a mixture of cooling tower 

blowdown and legacy fly ash transport water. As the plant continues to discharge from the 

impoundment, the concentration of pollutants in the impoundment that are associated with the 

legacy fly ash transport water would decrease over time but theoretically would never become 

zero (i.e., “zero discharge”) because the remaining legacy wastewater is diluted over time but is 

never completely flushed from the impoundment. As pollutant concentrations associated with the 

legacy wastewater decrease over time, the treatability of the legacy wastewater remaining in the 

impoundment may be affected and, similarly, the resulting concentrations in the treated effluent 

may be affected. For this reason, EPA has found that the technologies considered for legacy 

 

114 Except where BAT is equivalent to BPT.
Section 14 – Regulatory Implementation

14-3 

wastewater in surface impoundments are either impracticable or insufficient data are available 

for establishing effluent limitations.

The remainder of this subsection presents examples of how the proposed BAT effluent 

limitations and the existing BPT limitations should be applied to these wastewaters after the date 

established by the permitting authority that is as soon as possible after July 1 2017. Wastewater 

generated prior to the date established by the permitting authority is referred to as “legacy” 

wastewater and wastewater generated after the date established by the permitting authority is 

referred to as “newly generated” wastewater. 

Figure 14-1 presents an example treatment scenario for a plant operating an 

impoundment receiving only FGD wastewater prior to the implementation of the ELGs. Under 

Regulatory Options 3 and 4a, the plant will need to meet the new BAT effluent limitations for 

the FGD wastewater, in which case, EPA envisions that the plant will have installed a tank-based 

treatment system to meet the limits. However, the plant has several options for the configuration 

of the treatment system in association with the existing impoundment, which are included in the 

post rule scenarios in Figure 14-1. Under post rule scenario A, the plant transfers the newly 

generated FGD wastewater to the tank-based system and discharges directly from the tank-based 

system to the receiving water. In this case, the plant would be required to demonstrate 

compliance with the new BAT and the existing BPT effluent limitations for the newly generated 

FGD wastewater at the effluent from the tank-based treatment system. Additionally, any legacy 

FGD wastewater that remains in the existing impoundment could still be discharged (e.g., after a 

rainfall event, when dewatering the impoundment for closure) and would only be subject to the 

existing BPT effluent limitations.115

Under post rule scenario B, the plant transfers the newly generated FGD wastewater to 

the tank-based system and then transfers the effluent from the system to the existing 

impoundment, containing legacy FGD wastewater, for additional polishing prior to discharge. As 

stated in the proposed rule, and described further in Section 14.1.4.3, EPA is proposing to require 

monitoring for compliance with the proposed BAT effluent limitations for newly generated FGD 

wastewater prior to use of the FGD wastewater in any other non-FGD plant process or 

commingling of the FGD wastewater with any water or other process wastewater, except for 

combustion residual leachate (including legacy leachate) or legacy FGD wastewater that is 

treated to achieve pollutant removals equivalent to or greater than achieved by the BAT 

technology that serves as the basis for the proposed effluent limitations. In this case, because the 

existing FGD wastewater impoundment does not achieve equivalent removals compared to the 

tank-based system, the plant would be required to demonstrate compliance with the new BAT 

limitations for the newly generated FGD wastewater at the effluent from the tank-based FGD 

wastewater treatment system, and compliance with the BPT requirements for the commingled 

new/legacy FGD wastewater at the point of discharge from the existing FGD wastewater 

impoundment. 

Under post rule scenario C, the plant transfers the newly generated FGD wastewater to 

the existing FGD wastewater impoundment, containing legacy FGD wastewater. The 

 

115 All examples presented in this section focus on the implementation of the ELGs. All NPDES discharge outfalls 

may also be required to comply with additional water quality-based effluent limitations.
Section 14 – Regulatory Implementation

14-4 

impoundment effluent is then transferred to the tank-based treatment system. In this case, both 

the newly generated FGD wastewater and the legacy FGD wastewater would be treated by the 

tank-based FGD wastewater treatment system . In this case, the plant would be required to 

demonstrate compliance with the new BAT and existing BPT effluent limitations for FGD 

wastewater at the effluent from the tank-based treatment system (i.e., prior to discharge or 

commingling with other wastestreams).

Figure 14-1. Legacy FGD Wastewater Treatment Scenario 

(Regulatory Options 3 and 4a) 

Figure 14-2 presents an example treatment scenario for an impoundment receiving only 

fly ash transport water prior to the implementation of the ELGs. Under Regulatory Options 3a, 

3b, 3, and 4a, the plant will need to meet the zero discharge BAT standard for fly ash transport 

FGD Treatment Scenarios

FGD

Wastewater

FGD Wastewater 

Impoundment Pre Rule

Receiving Water

Legacy

FGD Wastewater

Impoundment BPT

A

Newly Generated 

FGD Wastewater

BAT

BPT

Tank Based 

Treatment

System

Post Rule

Receiving Water

Tank Based 

Treatment

System

Legacy and 

Newly Generated 

FGD Wastewater 

Impoundment BAT B

BPT

Tank Based 

Treatment

System

Legacy and 

Newly Generated 

FGD Wastewater 

Impoundment BAT 

BPT

C Newly Generated 

FGD Wastewater

BPT

Newly Generated 

FGD Wastewater

Receiving Water

Receiving Water
Section 14 – Regulatory Implementation

14-5 

water, in which case, EPA envisions that the plant will have installed a dry fly ash handling 

system to meet the new BAT limitation. In this case, the plant will no longer be transferring fly 

ash transport water to the impoundment. However, legacy fly ash transport water could still be 

discharged from the impoundment (e.g., after a rainfall event, when dewatering the 

impoundment for closure) and would only be subject to the existing BPT effluent limitations. 

Figure 14-2. Legacy Fly Ash Transport Water Treatment Scenario 

(Regulatory Options 3a, 3b, 3, and 4a) 

Figure 14-3 presents an example of the treatment scenario for a plant that operates a 

complete recycle fly ash sluicing system in which the plant does not discharge any fly ash 

transport water to a receiving water. Because the plant does not discharge fly ash transport water 

prior to the implementation of the rule, the plant can continue to operate using the same system 

(i.e., no system modifications required) and still be in compliance with the new zero discharge 

BAT limitation.

Fly Ash Only Scenarios

Fly Ash

Transport Water

Fly Ash 

Transport Water 

Impoundment

Pre Rule

Receiving Water

Legacy Fly Ash

Transport Water

Impoundment

Receiving Water

Post Rule

BPT

BPT

Note: Fly ash converted to dry handling system.

No newly generated fly ash transport water.
Section 14 – Regulatory Implementation

14-6 

Figure 14-3. Complete Recycle Fly Ash Transport Water Treatment Scenario 

(Regulatory Options 3a, 3b, 3, and 4a) 

Figure 14-4 presents an example treatment scenario for a plant that operates a partial 

recycle bottom ash sluicing system in which the plant recycles a majority of the bottom ash 

transport water for reuse in the system, but some of the bottom ash transport water is discharged 

to a receiving water. Under Regulatory Options 3a, 3b, and 3, the plant could continue to operate 

the system without any changes/modifications because Options 3a, 3b, and 3 would establish 

BAT limitations for bottom ash transport water equal to the current BPT limitations. However, 

under Regulatory Option 4, the plant will need to meet the new zero discharge BAT limitation, in 

which case, EPA envisions that the plant has two options for complying with the new limitation, 

which are included in the post rule scenarios in Figure 14-4. Under post rule scenario A, the 

plant would convert to a dry bottom ash handling system, and would not transfer any newly 

generated bottom ash transport water to the existing impoundment. However, legacy bottom ash 

transport water could still be discharged from the impoundment (e.g., after a rainfall event, when 

dewatering the impoundment for closure) and would only be subject to the existing BPT effluent 

limitations.

Under post rule scenario B, the plant would evaluate the water balance for the bottom ash 

system and determine whether the system could operate without discharging to a receiving 

Fly Ash 

Transport Water 

Impoundment

No

Discharge

Pre Rule

Fly Ash

Transport Water Generating 

Unit

Sluicing 

System

Legacy and Newly 

Generated Fly 

Ash Transport 

Water 

Impoundment No

Discharge

Post Rule

Fly Ash

Transport Water* Generating 

Unit

Sluicing 

System

y s O y Sce a os

Note: No changes/modifications are necessary for the system because the 

configuration already meets the proposed zero discharge BAT limitation.

*Consists of both newly generated fly ash transport 

water and legacy fly ash transport water because 

recycled impoundment wastewater is used as the 

source of the transport water.
Section 14 – Regulatory Implementation

14-7 

stream. If the plant determines that the system can achieve complete recycle, then the plant can 

continue to operate the existing bottom ash handling system, but can no longer discharge the 

wastewater from the impoundment to the receiving water in order to meet the new zero discharge 

BAT limitation. 

Figure 14-4. Partial Recycle Bottom Ash Transport Water Treatment Scenario 

(Regulatory Option 4) 

Figure 14-5 and Figure 14-6 present example treatment scenarios for an impoundment 

receiving both fly ash and bottom ash transport water prior to the implementation of the ELGs. 

Figure 14-5 presents the treatment scenario under Regulatory Options 3a, 3b, and 3 and Figure 

Bottom Ash 

Transport Water 

Impoundment BPT

Pre Rule

Bottom Ash

Transport Water Generating 

Unit

Sluicing 

System

Legacy and Newly 

Generated Bottom 

Ash Transport Water 

Impoundment No

Discharge

Post Rule

Bottom Ash

Transport Water* Generating 

Unit

Sluicing 

System

a t a ecyc e Sce a os

*Consists of both newly generated bottom ash 

transport water and legacy bottom ash transport 

water because recycled impoundment wastewater is 

used as the source of the transport water.

A

B

Legacy Bottom Ash 

Transport Water 

Impoundment

BPT

Note for Scenario A: Bottom ash converted to dry handling system. 

No newly generated bottom ash transport water.

Receiving Water

Receiving Water
Section 14 – Regulatory Implementation

14-8 

14-6 presents the treatment scenario under Regulatory Option 4. Under Regulatory Options 3a, 

3b, and 3, the plant will need to meet the zero discharge BAT limitation for fly ash transport 

water, in which case, EPA envisions that the plant will have installed a dry fly ash handling 

system to meet the limitation. In this case, the plant will no longer be transferring fly ash 

transport water to the impoundment. However, the impoundment still contains legacy fly ash 

transport water and legacy bottom ash transport water and the impoundment will continue to 

discharge because of the newly generated bottom ash transport water that will continue to be 

transferred to the impoundment. In this case, the plant would be required to demonstrate 

compliance with the existing BPT effluent limitations for the legacy fly ash transport water and 

legacy bottom ash transport water and the new BAT effluent limitations for the newly generated 

bottom ash transport water. 

Under Regulatory Option 4, the plant will need to meet the zero discharge BAT 

limitation for both fly ash transport water and bottom ash transport water, in which case, EPA 

envisions that the plant has two options for complying with the BAT limitations, which are 

included in the post rule scenarios in Figure 14-6. Under post rule scenario A, the plant would 

convert to a dry fly ash handling system and a dry bottom ash handling system, and would not 

transfer any newly generated fly ash transport water or newly generated bottom ash transport 

water to the existing impoundment. However, legacy fly ash transport water and legacy bottom 

ash transport water could still be discharged from the impoundment (e.g., after a rainfall event, 

when dewatering the impoundment for closure) and would only be subject to the existing BPT 

effluent limitations.

Under post rule scenario B, the plant would evaluate the water balance for the fly ash and 

bottom ash systems and determine whether the systems could operate without discharging to a 

receiving stream. If the plant determines that the systems can achieve complete recycle, then the 

plant can continue to operate the existing wet fly ash and bottom ash handling systems, but can 

no longer discharge the wastewater from the impoundment to the receiving water in order to 

meet the new zero discharge BAT limitations. 
Section 14 – Regulatory Implementation

14-9 

Figure 14-5. Legacy Fly Ash Transport Water Combined with Bottom Ash 

Transport Water Treatment Scenario (Regulatory Options 3a, 3b, and 3) 

 

 

Opt o 3

Fly Ash and Bottom Ash 

Transport Water 

Impoundment

Pre Rule

Receiving Water

Legacy Fly Ash and 

Bottom Ash and Newly 

Generated Bottom Ash 

Transport Water 

Impoundment

 Post Rule

Receiving Water

Fly Ash 

Transport Water

Bottom Ash

Transport Water

BPT

BAT (for bottom 

ash only)

Newly Generated 

Bottom Ash

Transport Water

Note: Fly ash converted to dry handling system. 

No newly generated fly ash transport water. 

Or, if fly ash transport water continues to be 

handled wet, cannot discharge from impoundment.

BPT
Section 14 – Regulatory Implementation

14-10 

Figure 14-6. Legacy Fly Ash Transport Water Combined with Bottom Ash 

Transport Water Treatment Scenario (Regulatory Option 4) 

Figure 14-7 and Figure 14-8 present example treatment scenarios for a system where 

FGD wastewater is treated in an impoundment receiving only FGD wastewater with the effluent 

from the impoundment being transferred to an impoundment that receives both fly ash and 

bottom ash transport water prior to the implementation of the ELGs. Figure 14-7 presents the 

treatment scenario under Regulatory Option 3 and Figure 14-8 presents the treatment scenario 

under Regulatory Option 4. Under Regulatory Option 3, the plant will need to meet the new BAT 

effluent limitations for FGD wastewater, in which case, EPA envisions that the plant will have 

 

( y a d otto ) Sce a os

Opt o 

Fly Ash and Bottom Ash 

Transport Water 

Impoundment

Pre Rule

Receiving Water

Legacy 

Fly Ash and Bottom Ash 

Transport Water 

Impoundment

 Post Rule

Receiving Water

Fly Ash 

Transport Water

Bottom Ash

Transport Water

BPT

Note: Fly ash and bottom ash converted to dry handling systems. 

No newly generated fly ash or bottom ash transport water. 

BPT

 A

Legacy and Newly 

Generated Fly Ash and 

Bottom Ash Transport 

Water Impoundment No

Discharge

Fly Ash and Bottom Ash

Transport Water* Generating 

Unit

Sluicing 

System

*Consists of both legacy fly ash transport water and 

legacy bottom ash transport water because recycled 

impoundment water is used as the source of the 

transport water. Also includes newly generated fly 

ash transport water and/or newly generated bottom 

ash transport water based on which ash handling 

system(s) continues wet sluicing operations (i.e., not 

converted to dry handling.)

B
Section 14 – Regulatory Implementation

14-11 

installed a tank-based treatment system to meet the limitations. Additionally, the plant will need 

to meet the zero discharge BAT limitation for fly ash transport water, in which case, EPA 

envisions that the plant will have installed a dry fly ash handling system to meet the limitations.

The plant has a couple options for the handling of the FGD wastewater in association with the 

existing impoundments, which are included in the post rule scenarios in Figure 14-7. Under the 

post rule scenario, the plant can either transfer the FGD wastewater from the tank-based system 

to the existing FGD impoundment, or the plant can bypass the FGD impoundment and transfer 

the effluent from the tank-based FGD wastewater treatment system directly to the existing ash 

impoundment. In either case, the plant would be required to demonstrate compliance with the 

new FGD wastewater BAT limitations at the effluent from the tank-based system, prior to 

entering either of the impoundments. The plant would also be required to demonstrate 

compliance with the existing BPT limitations for legacy and newly generated FGD wastewater, 

legacy fly ash transport water, and legacy bottom ash transport water, as well as the BAT 

limitation for newly generated bottom ash transport water, at the effluent from the ash 

impoundment. 

Under Regulatory Option 4, the plant will need to meet the new BAT effluent limitations 

for FGD wastewater and the zero discharge BAT limitations for fly ash transport water and 

bottom ash transport water. In this case, EPA envisions that the plant will have installed a tankbased treatment system to treat the FGD wastewater and dry fly ash and dry bottom ash handling 

systems. As described for Regulatory Option 3, the plant has a couple options for the handling of 

the FGD wastewater, which are included in the post rule scenarios in Figure 14-8. Under the post 

rule scenario, the plant can either transfer the FGD wastewater from the tank-based system to the 

existing FGD impoundment, or the plant can bypass the FGD impoundment and transfer the 

effluent from the tank-based FGD wastewater treatment system directly to the existing ash 

impoundment. In either case, the plant would be required to demonstrate compliance with the 

new FGD wastewater BAT limitations at the effluent from the tank-based system, prior to 

entering either of the impoundment. The plant would also be required to demonstrate compliance 

with the existing BPT limitations for legacy and newly generated FGD wastewater, legacy fly 

ash transport water, and legacy bottom ash transport water at the effluent from the ash 

impoundment. The plant would not be able to discharge wastewater from the impoundments if 

newly generated fly ash transport water or bottom ash transport water was sent to the 

impoundment. 
Section 14 – Regulatory Implementation

14-12 

Figure 14-7. Legacy FGD Wastewater and Fly Ash Transport Water Combined with 

Bottom Ash Transport Water Treatment Scenario (Regulatory Option 3) 

FGD Wastewater, Fly Ash 

and Bottom Ash Transport 

Water Impoundment

Pre Rule

Receiving Water

G / / Co ected 

o d et o Opt o 3

FGD Wastewater 

Impoundment

FGD

Wastewater

Fly Ash

Transport Water

Bottom Ash 

Transport Water

Legacy and Newly 

Generated FGD Wastewater, 

Legacy Fly Ash Transport 

Water, and Legacy and 

Newly Generated Bottom 

Ash Transport Water 

Impoundment

 Post Rule

Receiving 

Water

Legacy (and Newly 

Generated) 

FGD Wastewater 

Impoundment

Newly Generated 

FGD Wastewater

BAT

BAT

Newly Generated Bottom 

Ash Transport Water

Tank Based

Treatment

System

BPT

Note: Fly ash converted to dry handling system. 

No newly generated fly ash transport water. 

Or, if fly ash transport water continues to be 

handled wet, cannot discharge from impoundment.

BPT

BAT (for bottom 

ash only)
Section 14 – Regulatory Implementation

14-13 

Figure 14-8. Legacy FGD Wastewater and Fly Ash Transport Water Combined with 

Bottom Ash Transport Water Treatment Scenario (Regulatory Option 4) 

14.1.4 Monitoring Requirements

The NPDES permit regulations at §122.41(j)(4) and the pretreatment regulations at 

§403.12(b)(5)(vi) require that facilities conduct sampling and analyses to monitor compliance 

according to the techniques set out at 40 CFR 136, as amended. The Agency is proposing several 

specific monitoring requirements in the steam electric proposed rule. Sections 14.1.4.1 through 

14.1.4.4 provide guidance on establishing these requirements. 

FGD Wastewater, Fly Ash 

and Bottom Ash Transport 

Water Impoundment

Pre Rule

Receiving Water

G / / Co ected 

o d et o Opt o 

FGD Wastewater 

Impoundment

FGD

Wastewater

Fly Ash

Transport Water

Bottom Ash 

Transport Water

Legacy and Newly 

Generated FGD Wastewater, 

Legacy Fly Ash and Legacy 

Bottom Ash Transport Water 

Impoundment

 Post Rule

Receiving Water

Legacy (and Newly 

Generated) 

FGD Wastewater 

Impoundment

Newly Generated 

FGD Wastewater

BAT

BAT

BPT

Tank Based

Treatment

System

BPT

Note: Fly ash and bottom ash converted to dry handling systems. 

No newly generated fly ash transport water or bottom ash transport water.
Section 14 – Regulatory Implementation

14-14 

14.1.4.1 Sample Types

EPA recommends flow-proportioned, 24-hour composite samples for the following 

regulated pollutants: 

• Total dissolved solids; 

• Total arsenic;

• Total selenium; and

• Nitrate/nitrite as N. 

Part 136 recommends that plants use the clean sampling techniques described in EPA’s 

draft method 1669: Sampling Ambient Water for Trace Metals at EPA Water Quality Criteria 

Levels (EPA-821-R-96-011) for mercury collection for EPA Methods 245.7 and 1631E to 

prevent contamination at low-level, trace metal determinations.116 EPA Methods 245.7 and 

1631E are the only Part 136-approved methods that have a detection limit low enough to be used 

for the mercury analysis for the FGD wastewater limit in the proposed rule. While EPA Methods 

245.7, 1631E, and 1669 do not specifically require plants to collect mercury samples as grab 

samples, EPA recommends that mercury be collected as grab samples because there is less 

potential for contamination compared to composite sampling. EPA also recommends that 

mercury samples be collected as four grab samples in a 24-hour monitoring day, and that the 

results should be averaged to represent a daily sample.

14.1.4.2 Monitoring Frequency

The monitoring frequencies specified in steam electric NPDES permits vary depending 

upon the size of the plant, potential impacts on receiving waters, compliance history, and other 

factors, including monitoring policies or regulations required by permit authorities. The Agency 

is not proposing any specific monitoring frequencies; therefore, permit authorities may establish 

monitoring frequencies at their discretion, consistent with the requirements in 40 CFR 122. 

When developing the proposed rule, EPA assumed a monitoring frequency of once per 

week for regulated pollutants. Facilities may monitor effluent more frequently than specified in 

their permits. During site visits, EPA observed that many plants often collect samples for key 

pollutants on a more frequent basis than required in their permits to help them stay attuned to 

treatment system performance and facilitate improved performance.

14.1.4.3 Compliance Monitoring Locations 

Working in conjunction with the effluent limitations guidelines and standards are the 

monitoring conditions set out in a NPDES discharge permit or POTW control mechanism. An 

integral part of the monitoring conditions is the monitoring point. The point at which a sample is 

collected can have a dramatic effect on the monitoring results for that plant. Therefore, it may be 

 

116 EPA also recommends that plants use the clean sampling techniques for the collection of arsenic and selenium. If 

clean sampling techniques are not used, EPA recommends that field blanks be collected to evaluate whether 

contamination may be affecting the sampling results.
Section 14 – Regulatory Implementation

14-15 

necessary to require internal monitoring points in order to assure compliance. Authority to 

address internal wastestreams is provided in 40 CFR 122.44(i)(1)(iii) and 122.45(h). 

EPA is proposing that dischargers demonstrate compliance with the new effluent 

limitations and standards applicable to a particular wastestream prior to mixing the treated 

wastestream with other wastestreams, as described below. Therefore, with the exception of the 

cases where BAT limitations are equivalent to BPT limitations, any final limitations or standards 

(except pH) based on any of the eight main regulatory options in the proposed rule could require 

internal monitoring points. The following provides more detailed information for each 

wastestream:

• FGD Wastewater: Where an option proposes BAT/NSPS limitations for FGD 

wastewater that are not equal to existing BPT limitations, EPA is also proposing to 

require monitoring for compliance with the proposed effluent limitations and 

standards prior to use of the FGD wastewater in any other non-FGD plant process or 

commingling of the FGD wastewater with any water or other process wastewater.

117

This monitoring requirement would not, however, apply prior to commingling of 

FGD wastewater with combustion residual leachate (including legacy leachate) or 

legacy FGD wastewater that is treated to achieve pollutant removals equivalent to or 

greater than achieved by the BAT/NSPS technology that serves as the basis for the 

effluent limitations and standards in the proposed rule. 

For example, many plants currently treat their FGD wastewater and leachate in onsite 

surface impoundments. EPA envisions that, under the Option 3 requirements, some of 

these plants may choose to install tank-based FGD wastewater treatment systems for 

their newly generated FGD wastewater. Such a plant may choose to discharge the 

effluent from its new treatment system directly or may wish to discharge it to the 

existing surface impoundment containing legacy wastewaters. In this case, the plant 

would be required to demonstrate compliance with the proposed effluent limitations 

and standards for the newly generated FGD wastewater at the effluent from the tankbased FGD wastewater treatment system, and compliance with the BPT requirements 

for the commingled new/legacy FGD wastewater at the point of discharge from the 

FGD wastewater impoundment. The same plant may also configure its system so that 

the impoundment (which also contains legacy FGD wastewater) is used for 

equalization, with the impoundment effluent sent to the tank-based treatment system. 

In this case, both the newly generated FGD wastewater and the legacy FGD 

wastewater would be treated by the tank-based treatment system and an appropriate 

compliance monitoring point would be the treatment system effluent. Under such a 

scenario, commingling of FGD wastewater generated at any date may occur as long 

as such combined wastewater meets the effluent limitations or standards prior to use 

of the treated commingled new/legacy FGD wastewater in any other plant process, or 

combining the FGD wastewater with any water or other process wastewater. See 

Figure 14-1 for illustrations of these examples of the compliance monitoring points. 

 

117 Similarly applies to PSES and PSNS.
Section 14 – Regulatory Implementation

14-16 

• Ash Transport Water and FGMC Wastewater: EPA is proposing to specify that 

whenever ash transport water or flue gas mercury control wastewater generated from 

a generating unit that must comply with the “zero discharge” standard is used in any 

other plant process or is sent to a treatment system at the plant, the resulting effluent 

must comply with the proposed discharge prohibition for the pollutants in such 

wastewater. 

For example, many plants currently treat their fly ash transport water in an onsite fly 

ash impoundment. In this case, under any proposed “no discharge” requirements, 

EPA envisions that such plants may convert their fly ash handling to a dry system, 

and no longer generate fly ash transport water. In such cases, the plant could 

demonstrate compliance with the proposed zero discharge requirement by showing 

that no fly ash transport water is generated after the date on which the new, proposed 

standards apply and by monitoring for compliance with the BPT requirements at the 

discharge from the legacy fly ash impoundment. See Figure 14-2 for an illustration of 

the example compliance monitoring points. Under EPA’s proposal, the plant could 

not demonstrate compliance with the applicable discharge prohibition by simply 

using the fly ash transport water or FGMC wastewater in another plant process that 

ultimately discharges because the prohibition on the discharge of pollutants in ash 

transport water and FGMC wastewater is also applicable to the discharge of 

wastewater from plant processes that use these wastewaters.

• Gasification Wastewater: EPA is proposing to require monitoring for compliance 

prior to use of the gasification wastewater in any other plant process or commingling 

of the gasification wastewater with water or any other process wastewater. For 

example, EPA envisions gasification plants would show compliance with the 

proposed BAT or PSES requirements directly following gasification wastewater 

treatment (however, there would be no need to demonstrate compliance if the 

gasification wastewater is completely reused within the gasification process).

• Combustion Residual Leachate: Under Options 4 and 5, EPA is proposing to require 

monitoring for compliance prior to use of leachate in any other plant process or 

commingling of the leachate with water or any other process wastewater. This 

monitoring requirement would not, however, apply prior to commingling of 

combustion residual leachate with FGD wastewater (including legacy FGD 

wastewater) or legacy combustion residual leachate that is treated to achieve pollutant 

removals equivalent to or greater than that achieved by the BAT/NSPS technology 

that serves as the basis for the effluent limitations and standards in the proposed rule. 

For example, many plants currently treat their leachate in onsite surface 

impoundments. EPA envisions that some plants may choose to install a tank-based 

leachate treatment system so that the impoundment (which also contains legacy 

combustion residual leachate) is used for equalization, with the impoundment effluent 

ultimately sent to the tank-based treatment system. In this case, both the newly 

generated leachate and the legacy leachate would be treated by the tank-based 

treatment system and an appropriate compliance monitoring point would be the 

treatment system effluent. Under such a scenario, commingling of combustion 

residual leachate generated at any date may occur as long as such combined 

wastewater meets the effluent limitations or standards prior to use of the treated 
Section 14 – Regulatory Implementation

14-17 

commingled new/legacy leachate in any other plant process, or combining the 

leachate with any water or other process wastewater. (If the combustion residual 

leachate is commingled with FGD wastewater, the plant will also have to demonstrate 

compliance with the applicable FGD wastewater effluent limitations and standards.) 

14.1.4.4 Size Threshold Implementation

Under the BAT/PSES regulatory options, EPA is proposing to set size thresholds which 

would subject discharges from certain generating units to a different set of controls. The 

following provides examples of how these size thresholds should be evaluated for the purposes 

of setting permit requirements.

Fly Ash 50 MW Threshold (Options 3a, 3b, 3, 4a, 4, 5) 

Under the proposed regulatory options, there is the potential that some generating units at 

a plant would need to comply with the proposed “zero discharge” requirement, while other units 

at the plant would only need to comply with the current BPT standards. For example, consider a 

plant that has a generating unit with a nameplate capacity of 50 MW or less and another 

generating unit with a nameplate capacity of greater than 50 MW that both discharge fly ash 

transport water. In this case, if the plant continues to wet sluice the fly ash from the unit with a 

nameplate capacity greater than 50 MW, the fly ash transport water for that unit must be 

completely reused in a process that does not ultimately discharge to surface waters, including 

indirect discharges to POTWs, (or the unit converted to dry handling) to be in compliance with 

the proposed “zero discharge” requirement. The fly ash transport water from the unit with a 

nameplate capacity greater than 50 MW cannot be reused to wet sluice the fly ash for the 

generating unit with a nameplate capacity of 50 MW or less if it is ultimately discharged. 

Therefore, the plant has three potential options to comply with the proposed “zero discharge” 

requirement for the generating unit with a nameplate capacity of greater than 50 MW:

• Convert the generating unit to dry fly ash handling; 

• Commingle the fly ash transport water for all generating units and completely recycle 

the fly ash transport water with no discharge from any of the generating units; or

• Segregate the fly ash transport water for the generating unit with a nameplate capacity 

greater than 50 MW and completely recycle that within that specific unit, but still 

discharge the fly ash transport water from the generating unit with a nameplate 

capacity of 50 MW or less. 

This example would also apply to the 400 MW threshold for bottom ash transport water 

under Option 4a. 

FGD Wastewater 2,000 MW Plant-Level Wet-Scrubbed Capacity Threshold (Option 3b) 

EPA is not proposing to establish BAT/PSES for discharges of FGD wastewater under 

Option 3b, for those plants that have a total plant-level wet scrubbed capacity of less than 2,000 

MW. Therefore, if a plant has a total wet scrubbed capacity of 1,800 MW, no new effluent limits 

would be established under BAT or PSES for discharges of FGD wastewater. However, if the 

plant were to install a new wet FGD system with a nameplate capacity of 200 MW or greater at a 
Section 14 – Regulatory Implementation

14-18 

later time, which would put the plant at or above the 2,000 MW threshold, the plant would then 

be required to comply with the proposed effluent limits for all FGD wastewater generated at the 

plant, not just the wastewater associated with the new FGD system. Therefore, at the time the 

plant begins operation of the new FGD system, the plant would be required to meet the proposed 

arsenic, mercury, selenium, and nitrate-nitrite limitations for all FGD wastewater discharges at 

the plant. 

14.2 ANALYTICAL METHODS

Section 304(h) of the CWA directs the EPA to promulgate guidelines establishing test 

procedures (methods) for the analysis of pollutants. These methods are used to determine the 

presence and concentration of pollutants in wastewater and for compliance monitoring. They are 

also used for filing applications for the National Pollutant Discharge Elimination System 

(NPDES) permit program under 40 CFR 122.41(j)(4) and 122.21(g)(7), and under 40 CFR 

403.7(d) for the pretreatment program. The EPA has promulgated analytical methods for 

monitoring discharges to surface water at 40 CFR part 136 for the pollutants proposed for 

regulation in the proposed rule. As part of this proposed rule, EPA is providing notice of 

standard operating procedures (SOPs) for the analysis of FGD wastewater using collision cell 

technology in conjunction with EPA Method 200.8. EPA Method 200.8 has been promulgated 

under 40 CFR part 136 and is an approved method for use in NPDES compliance monitoring. 

Also, the use of collision cell technology is an approved modification allowed under 40 CFR part 

136.6. The SOPs developed by EPA are titled, “Draft Procedure for Trace Element Analysis of 

Flue Gas Desulfurization Wastewaters Using Perkin Elmer NexION 300D ICP-MS 

Collision/Reaction Cell Procedure” and “Draft FGD ICP/MS Collision Cell Procedure for Trace 

Element Analysis in Flue Gas Desulfurization Wastewaters” [U.S. EPA, 2012a; U.S. EPA, 

2012b]. 

In addition, as explained in Section 8.1.2.8, with the exception of the cases where BAT 

limitations are equivalent to BPT limitations, EPA is proposing that compliance with any final 

limitations or standards (except pH) based on any of the eight main regulatory options in the 

proposed rule reflects results obtained from sufficiently sensitive analytical methods. Where 

EPA has approved more than one analytical method for a pollutant, the Agency expects that 

permittees would select methods that are able to quantify the presence of pollutants in a given 

discharge at concentrations that are low enough to determine compliance with effluent limits. For 

purposes of the proposed anti-circumvention provisions, a method is “sufficiently sensitive” 

when the sample-specific quantitation level for the wastewater matrix being analyzed is at or 

below the level of the effluent limit.118

14.3 UPSET AND BYPASS PROVISIONS

The CWA, the NPDES permit regulations at §122.41(m) and (n), and the pretreatment 

regulations at §403.16 and §403.17 allow effluent discharges above permit limits under certain 

exceptional and limited circumstances. A bypass is an intentional diversion of a wastestream

from any portion of a treatment facility to prevent unavoidable loss of life, personal injury, or 

 

118 For the purposes of the discussion in this rulemaking, the following terms related to analytical method sensitivity 

are synonymous: “quantitation limit,” “reporting limit,” “level of quantitation,” and “minimum level.”
Section 14 – Regulatory Implementation

14-19 

severe property damage. Economic loss caused by delays in production does not constitute 

severe property damage for the purposes of this regulation. The key requirements for the bypass 

provisions of a permit are: (1) the bypass must be intentional; (2) prior notice (10 days, if 

possible) must be provided; and (3) there must be no feasible alternatives to the bypass. A plant 

does not meet these requirements if it lacks adequate back-up equipment that it should have 

installed to prevent a bypass during periods of normal operation or maintenance using reasonable 

engineering judgment. In other cases, intentional bypasses are allowed if required for essential 

maintenance to ensure efficient operation, as long as these bypasses do not cause the plant to 

exceed its effluent limitations.

An upset is an exceptional incident in which a facility unintentionally and temporarily 

cannot comply with its technology-based permit effluent limitations due to factors beyond its 

reasonable control. An upset does not include noncompliance due to operational error, 

improperly designed treatment facilities, inadequate treatment facilities, lack of preventative 

maintenance, or careless or improper operation. A plant can defend a case in which it exceeds its 

effluent limitations if the permit holder can demonstrate the following: the cause of the upset can 

be identified, the permitted facility was being properly operated at the time of the upset, and the 

permit holder made the required 24-hour notification. In any enforcement proceeding, the burden 

of proof is on the permit holder, through properly signed operating logs or other relevant 

evidence, to demonstrate an upset has occurred.

Because Section 510 of the CWA authorizes permit authorities to include more stringent 

controls than those contained in the federal regulations, any bypass and upset provisions must be 

included in permits issued by permit authorities to become available to permit holders. Permit 

authorities should anticipate that permit holders with properly designed and operated wastewater 

treatment systems would have very few, if any, bypasses or upsets in the course of a five-year 

NPDES permit that meet the above criteria.

14.4 VARIANCES AND MODIFICATIONS

The CWA requires application of effluent limitations established pursuant to Section 301 

or the pretreatment standards of Section 307 to all direct and indirect dischargers. However, the 

statute provides for the modification of these national requirements in a limited number of 

circumstances. The Agency has established administrative mechanisms to provide an opportunity 

for relief from the application of the national effluent limitations guidelines for categories of 

existing sources for toxic, conventional, and nonconventional pollutants. 

As opposed to the bypass and upset provisions that are applicable within the term of a 

permit, the permit writer develops the variance and alternative limitations at the time of draft 

permit renewal so that the variance and alternative limitations are subject to public review and 

comment at the same time the entire permit is put on public notice. The variance and alternative 

limitations remain in effect for the term of a permit, unless the permit writer modifies it prior to 

expiration. 

A permit applicant must meet specific data requirements before a variance is granted. As 

the term implies, a variance is an unusual situation, and the permit writer should not expect to 
Section 14 – Regulatory Implementation

14-20 

routinely receive variance requests. The permit writer should consult 40 CFR §124.62 for 

procedures on making decisions on the different types of variances, which are discussed below. 

14.4.1 Fundamentally Different Factors Variances

As explained above, the CWA requires application of the effluent limitations established 

pursuant to Section 301 or the pretreatment standards of Section 307 to all direct and indirect 

dischargers. However, the statute provides for the modification of these national requirements in 

a limited number of circumstances. Moreover, the Agency has established administrative 

mechanisms to provide an opportunity for relief from the application of national effluent 

limitations guidelines and pretreatment standards for categories of existing sources for priority, 

conventional, and nonconventional pollutants. 

EPA may develop, with the concurrence of the state, effluent limitations or standards 

different from the otherwise applicable requirements for an individual existing discharger if it is 

fundamentally different with respect to factors considered in establishing the effluent limitations 

or standards applicable to the individual discharger. Such a modification is known as an FDF 

variance.

EPA, in its initial implementation of the effluent guidelines program, provided for the 

FDF modifications in regulations, which were variances from the BPT effluent limitations, BAT 

limitations for toxic and nonconventional pollutants, and BCT limitations for conventional 

pollutants for direct dischargers. FDF variances for toxic pollutants were challenged judicially 

and ultimately sustained by the Supreme Court Chemical Manufacturers Association v. Natural 

Resources Defense Council, 470 U.S. 116, 124 (1985). 

Subsequently, in the Water Quality Act of 1987, Congress added new CWA Section 

301(n). This provision explicitly authorizes modifications of the otherwise applicable BAT 

effluent limitations, if a discharger is fundamentally different with respect to the factors specified 

in CWA Section 304 (other than costs) from those considered by EPA in establishing the effluent 

limitations. CWA Section 301(n) also defined the conditions under which EPA may establish 

alternative requirements. Under Section 301(n), an application for approval of a FDF variance 

must be based solely on (1) information submitted during rulemaking raising the factors that are 

fundamentally different or (2) information the applicant did not have an opportunity to submit. 

The alternate limitation must be no less stringent than justified by the difference and must not 

result in markedly more adverse non-water quality environmental impacts than the national 

limitation.

EPA regulations at 40 CFR Part 125, subpart D, authorizing the regional administrators 

to establish alternative limitations, further detail the substantive criteria used to evaluate FDF 

variance requests for direct dischargers. Thus, 40 CFR 125.31(d) identifies six factors (e.g., 

volume of process wastewater, age and size of a discharger's facility) that may be considered in 

determining if a discharger is fundamentally different. The Agency must determine whether, 

based on one or more of these factors, the discharger in question is fundamentally different from 

the dischargers and factors considered by EPA in developing the nationally applicable effluent 

guidelines. The regulation also lists four other factors (e.g., inability to install equipment within 

the time allowed or a discharger's ability to pay) that may not provide a basis for an FDF 
Section 14 – Regulatory Implementation

14-21 

variance. In addition, under 40 CFR 125.31(b) (3), a request for limitations less stringent than the 

national limitation may be approved only if compliance with the national limitations would result 

in either (a) a removal cost wholly out of proportion to the removal cost considered during 

development of the national limitations, or (b) a non-water quality environmental impact 

(including energy requirements) fundamentally more adverse than the impact considered during 

development of the national limits. The legislative history of Section 301(n) underscores the 

necessity for the FDF variance applicant to establish eligibility for the variance. EPA's 

regulations at 40 CFR 125.32(b)(1) impose this burden upon the applicant. The applicant must 

show that the factors relating to the discharge controlled by the applicant's permit that are 

claimed to be fundamentally different are, in fact, fundamentally different from those factors 

considered by EPA in establishing the applicable guidelines. In practice, very few FDF variances 

have been granted for past ELGs. An FDF variance is not available to a new source subject to 

NSPS. DuPont v. Train, 430 U.S. 112 (1977). 

14.4.2 Economic Variances

Section 301(c) of the CWA allows a plant to request a variance for nonconventional 

pollutants from technology-based BAT effluent limitations due to economic factors, at the 

request of the plant and on a case-by-case basis. There are no implementing regulations for 

§301(c); rather, variance requests must be made and reviewed based on the statutory language in 

CWA §301(c). The economic variance may also apply to nonguideline limits in accordance with 

40 CFR §122.21(m)(2)(ii). The applicant normally files the request for a variance during the 

public notice period for the draft permit. Other filing time periods may apply, as specified in 40 

CFR §122.21(m)(2). Specific guidance for this type of variance is provided in Draft Guidance 

for Application and Review of Section 301(c) Variance Requests, dated August 21, 1984, 

available on EPA's Web site at http://www.epa.gov/npdes/pubs/OWM0469.pdf. 

The variance application must show that the modified requirements: 

• Represent the maximum use of technology within the economic capability of the 

owner or operator; and 

• Result in further progress toward the goal of discharging no process wastewater. 

Facilities in industrial categories other than utilities must conduct three financial tests to 

determine if they are eligible for a 301(c) variance. Generally, EPA will grant a variance only if 

all three tests indicate that the required pollution control is not economically achievable and the 

applicant makes the requisite demonstration regarding “reasonable further progress.” 

To meet the second requirement for a 301(c) modification, the applicant must at a 

minimum demonstrate compliance with all applicable BPT limitations and pertinent water

quality standards. In addition, the proposed alternative requirements must reasonably improve 

the applicant’s discharge.

14.4.3 Water Quality Variances

Section 301(g) of the CWA authorizes a variance from BAT effluent guidelines for 

certain nonconventional pollutants due to localized environmental factors. These pollutants 
Section 14 – Regulatory Implementation

14-22 

include ammonia, chlorine, color, iron, and total phenols. As this proposed rule would not 

establish limitations or standards for any of these pollutants, this variance would not be 

applicable to this particular rule.

14.4.4 Thermal Discharge Variances

Section 316(a) of the CWA allows variances from effluent limitations for the thermal 

component of a discharge. See 40 CFR 125, Subpart H for regulations for submitting and 

reviewing thermal discharge variance requests. Permits may include less stringent alternative 

thermal effluent limits if the discharger demonstrates that the promulgated limits are more 

stringent than necessary to ensure the protection and propagation of a balanced, indigenous 

community of shellfish, fish, and wildlife in and on the water body into which the discharge is 

made. The applicant must take into account the cumulative impact of its thermal discharge 

together with all other significant impacts on the species affected.

14.4.5 Net Credits

In some cases, solely because of the level of pollutants in the intake water, plants find it 

difficult or impossible to meet technology-based limits with BAT/BCT technology. Under 

certain circumstances, the NPDES regulations allow credit for pollutants in intake water. 40 CFR 

§122.45(g) establishes the following requirements for net limitations:

• Credit for generic pollutants, such as BOD or TSS, are authorized only where the 

constituents resulting in the effluent BOD and TSS are similar between the intake 

water and the discharge;

• Credit is authorized only up to the extent necessary to meet the applicable limitation 

or standard, with a maximum value equal to the influent concentration; 

• Intake water must be taken from the same body of water into which the discharge is 

made; and

• Net credits do not apply to the discharge of raw water clarifier sludge generated 

during intake water treatment. 

Permit writers are authorized to grant net credits for the quantity of pollutants in the 

intake water where the applicable ELGs specify that the guidelines are to be applied on a net 

basis or where the pollution control technology would, if properly installed and operated, meet 

applicable ELGs in the absence of the pollutants in the intake waters. The proposed ELGs are to 

be applied on a gross basis. 

14.4.6 Removal Credits 

Section 307(b)(1) of the CWA establishes a discretionary program for POTWs to grant 

“removal credits” to their indirect dischargers. Removal credits are a regulatory mechanism by 

which industrial users may discharge a pollutant in quantities that exceed what would otherwise 

be allowed under an applicable categorical pretreatment standard because it has been determined 

that the POTW to which the industrial user discharges consistently treats the pollutant. EPA has 

promulgated removal credit regulations as part of its pretreatment regulations. See 40 CFR 
Section 14 – Regulatory Implementation

14-23 

403.7. These regulations provide that a POTW may give removal credits if prescribed 

requirements are met. The POTW must apply to and receive authorization from the Approval 

Authority. To obtain authorization, the POTW must demonstrate consistent removal of the 

pollutant for which approval authority is sought. Further, the POTW must have an approved 

pretreatment program. Finally, the POTW must demonstrate that granting removal credits will 

not cause the POTW to violate applicable Federal, State and local sewage sludge requirements. 

40 CFR 403.7(a)(3). 

The United States Court of Appeals for the Third Circuit interpreted the Clean Water Act 

as requiring EPA to promulgate the comprehensive sewage sludge regulations required by CWA 

§405(d)(2)(A)(ii) before any removal credits could be authorized. See NRDC v. EPA, 790 F.2d 

289, 292 (3d Cir., 1986); cert. denied., 479 U.S. 1084 (1987). Congress made this explicit in the 

Water Quality Act of 1987, which provided that EPA could not authorize any removal credits 

until it issued the sewage sludge use and disposal regulations. On February 19, 1993, EPA 

promulgated Standards for the Use or Disposal of Sewage Sludge, which are codified at 40 CFR 

Part 503 (58 FR 9248). EPA interprets the Court’s decision in NRDC v. EPA as only allowing 

removal credits for a pollutant if EPA has either regulated the pollutant in part 503 or established 

a concentration of the pollutant in sewage sludge below which public health and the environment 

are protected when sewage sludge is used or disposed. 

The Part 503 sewage sludge regulations allow four options for sewage sludge disposal: 

(1) land application for beneficial use, (2) placement on a surface disposal unit, (3) firing in a 

sewage sludge incinerator, and (4) disposal in a landfill which complies with the municipal solid 

waste landfill criteria in 40 CFR Part 258. Because pollutants in sewage sludge are regulated 

differently depending upon the use or disposal method selected, under EPA’s pretreatment 

regulations the availability of a removal credit for a particular pollutant is linked to the POTW’s 

method of using or disposing of its sewage sludge. The regulations provide that removal credits 

may be potentially available for the following pollutants:

1. If POTW applies its sewage sludge to the land for beneficial uses, disposes of it in a 

surface disposal unit, or incinerates it in a sewage sludge incinerator, removal credits 

may be available for the pollutants for which EPA has established limits in 40 CFR 

Part 503. EPA has set ceiling limitations for nine metals in sludge that is land applied, 

three metals in sludge that is placed on a surface disposal unit, and seven metals and 

57 organic pollutants in sludge that is incinerated in a sewage sludge incinerator. 40 

CFR 403.7(a)(3)(iv)(A).

2. Additional removal credits may be available for sewage sludge that is land applied, 

placed in a surface disposal unit, or incinerated in a sewage sludge incinerator, so 

long as the concentration of these pollutants in sludge do not exceed concentration 

levels established in Part 403, Appendix G, Table II. sewage sludge that is land 

applied, removal credits may be available for an additional two metals and 14 organic 

pollutants. sewage sludge that is placed on a surface disposal unit, removal credits 

may be available for an additional seven metals and 13 organic pollutants. sewage 

sludge that is incinerated in a sewage sludge incinerator, removal credits may be 

available for three other metals 40 CFR 403.7(a)(3)(iv)(B). 
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14-24 

3. When a POTW disposes of its sewage sludge in a municipal solid waste landfill that 

meets the criteria of 40 CFR Part 258, removal credits may be available for any 

pollutant in the POTW’s sewage sludge. 40 CFR 403.7(a)(3)(iv)(C).

14.5 REFERENCES

1. U.S. EPA. 2010. NPDES Permit Writer’s Manual. EPA-833-K-10-001. Washington, DC. 

(September). 

2. U.S. EPA. 1989. Industrial User Permitting Guidance Manual. EPA 833/R-89-001. 

Washington, DC. (29 September). 

3. U.S. EPA. 2005. Method 245.7, Mercury in Water by Cold Vapor Atomic Fluorescence 

Spectrometry, Revision 2.0. EPA-821-R-05-001. Washington, DC. (February). 

4. U.S. EPA. 2002. Method 1631E, Revision E: Mercury in Water by Oxidation, Purge and 

Trap, and Cold Vapor Atomic Fluorescence Spectrometry. EPA-821-R-02-019. 

Washington, DC. (August). 

5. U.S. EPA. 2009. Steam Electric Power Generating Point Source Category: Final Detailed 

Study. EPA 821-R-09-008. Washington, DC. (October). DCN SE00003. 

6. U.S. EPA. 2012a. Draft Procedure for Trace Element Analysis of Flue Gas 

Desulfurization Wastewaters Using Perkin Elmer NexION 300D ICP-MS 

Collision/Reaction Cell Procedure. (1 December). DCN SE03868. 

7. U.S. EPA. 2012b. Draft FGD ICP/MS Collision Cell Procedure for Trace Element 

Analysis in Flue Gas Desulfurization Wastewaters. (June). DCN SE03835. 

8. U.S. EPA. 1984. Technical Guidance Manual for the Regulations Promulgated Pursuant 

to Section 301(g) of the Clean Water Act of 1977, 40 CFR Part 125 (Subpart F). 

Washington, D.C. 
Appendix A – Survey Design and Calculation of National Estimates

APPENDIX A

SURVEY DESIGN AND CALCULATION OF NATIONAL ESTIMATES
Appendix A – Survey Design and Calculation of National Estimates

A-1 

Survey Design and Calculation of National Estimates

In June 2010, EPA distributed a survey, entitled The Questionnaire for the Steam Electric 

Power Generating Effluent Guidelines, to 733 steam electric power plants. The survey was 

designed to collect technical information related to wastewater generation and treatment, and 

economic information such as costs of wastewater treatment technologies and financial 

characteristics of affected companies.

Section 1 of this appendix describes the survey design, and Section 2 provides a summary 

of the survey responses. Section 3 discusses the weighting procedures, while Section 4 discusses 

the calculation of national estimates and variance estimation. 

A.1 SURVEY DESIGN

This section describes the development of the sample frame, stratification factors, sample 

design and selection, and the targeted level of precision.

A.1.1 Sample Frame

The sample frame for the Steam Electric Survey is a list of steam electric power 

generating plants subject to the steam electric power generating effluent guidelines. In addition 

to listing population elements in terms of contact information (address, phone number, etc.), 

other information in a sample frame was also used to design the survey. 

For this survey, EPA considered the target population to be all fossil- and nuclear-fueled 

steam electric power plants in the U.S. that report as operating under North American Industry 

Classification System (NAICS) code 22. EPA constructed the sampling frame using databases 

that are maintained by the Energy Information Administration (EIA), a statistical agency of the 

U.S. Department of Energy (DOE), and supplemented it with additional information compiled by 

EPA. The primary source of information was the 2007 Electric Generator Report (Form EIA860). Supplemental information was found in Form EIA-923 and in a survey conducted by 

EPA’s Office of Resource Conservation and Recovery. In addition, EPA identified several 

facilities that started operations after 2007 and obtained necessary information for them.

Using these sources of information, EPA compiled a sample frame containing 

information on 1,197 steam electric power plants with a total of 2,571 generating units that were 

within the scope of the survey. 

A.1.2 Plant Fuel Classification: the Main Stratification Variable

For this survey, the plant is the sampling unit. EPA stratified the sample frame based on 

the plant fuel classification, which was determined by the type of fuel used by each of the 

generating units in operation at the plant. EPA classified each plant’s fuel type in the sample 

frame using the following hierarchical structure:

First, plants were identified as coal plants if the plant had one or more generating units 

that used coal as its primary or secondary fuel. Since the integrated gasification combined cycle 

(IGCC) units used coal as the fuel source, they were classified as coal plants.
Appendix A – Survey Design and Calculation of National Estimates

A-2 

Second, plants were identified as petroleum coke plants if the plant had one or more 

generating units that used petroleum coke as its primary or secondary fuel (and the plant was not 

already classified as a coal plant);

Third, among the remaining plants, those plants for which all units used the same primary 

fuel type were classified as follows:

• Gas: all units used gas as the primary fuel type, but did not use combined cycle steam 

turbines; 

• Gas-Combined Cycle (CC): all units used gas as the primary fuel type and each used 

combined cycle steam turbines; 

• Oil: all units used oil as the primary fuel type;

• Nuclear: all units were nuclear-fueled; 

Finally, all remaining plants with generating units having different fuel types were 

classified as combination plants as follows:

• Combination - Gas and Gas-CC; 

• Combination - Gas and Oil; 

• Combination - Gas-CC and Oil; 

• Combination - Gas, Gas-CC, and Oil; 

• Combination - Gas-CC, Nuclear, and Oil. 

A.1.3 Sample Design

The basic sample design of the survey was a stratified design of the plants. The first 

stratification variable was the plant fuel classification as defined in subsection A.1.2. The second 

stratification variable was regulatory status, by which each plant was classified as regulated or 

unregulated. The questionnaire included questions about generating units, and each selected 

plant was required to complete the questionnaire for every generating unit at the plant.

Another candidate variable for stratification was North American Electric Reliability 

Corporation (NERC) region but it was not used as a stratification variable. Instead it was used as 

a sorting variable in systematic sampling to ensure the sample be spread evenly by NERC 

region; stratum members were sorted by NERC region and every k

th member was selected 

(where k is the ratio of the stratum population size to the stratum sample size). As a result of this 

systematic sampling, the percentage representation of each NERC region in the sample was 

expected to be proportional to the size of the region in the population.

All coal and petroleum coke plants were taken with certainty (i.e., all plants in the 

stratum were selected), whereas for other strata, the sampling rate was 30 percent with a 

minimum sample size constraint of 10. Therefore, if a stratum population size was less than 34, 

10 plants were selected systematically or all plants if there were not more than 10 plants. Due to 

this constraint, most combination strata were taken with certainty. Table A-1 presents the 
Appendix A – Survey Design and Calculation of National Estimates

A-3 

distribution of the sample frame (plants and generating units) and sample allocation of the plants 

by design stratum. 

Table A-1. Population Distribution of Plants and Generating Units, and Plant 

Sample Size by Design Stratum

Plant Fuel Classification Regulatory Status

Sample Frame Sample

Plant Generating Unit Plant

Coal Regulated 344 963 344

Unregulated 151 340 151

Gas Regulated 129 310 39

Unregulated 54 137 16

Gas-Combined Cycle (CC) Regulated 96 129 29

Unregulated 276 375 83

Nuclear Regulated 31 52 10

Unregulated 32 48 10

Oil Regulated 23 55 10

Unregulated 20 38 10

Petroleum Coke Regulated 0 0 0

Unregulated 9 9 9

Combination: Gas-CC and Nuclear 

and Oil

Regulated 1 5 1

Unregulated 0 0 0

Combination: Gas-CC and Oil Regulated 2 6 2

Unregulated 0 0 0

Combination: Gas and Gas-CC Regulated 20 69 10

Unregulated 6 23 6

Combination: Gas and Gas-CC and 

Oil

Regulated 1 4 1

Unregulated 0 0 0

Combination: Gas and Oil Regulated 1 4 1

Unregulated 1 4 1

Total 1,197 2,571 733

The exact number of generating units from these 733 plants to be selected was not known 

prior to the sample draw because the number of generating units varies by plant and thus would 

depend on the specific set of plants selected. EPA estimated that about 1,722 generating units 

would be included in the survey from these 733 plants. This estimated number of generating 

units was arrived at in the following manner. Generating units within plants that are selected with 

certainty will automatically be included in the sample. For each non-certainty stratum, EPA 

estimated the corresponding number of generating units by assuming that the rate of generating 

units per plant in the sample will be the same as the rate among plants in the sampling frame.

A.1.4 Subsample of Coal and Petroleum Coke Plants for Questionnaire Parts E, F, and G 

A subsample of coal and petroleum coke plants was selected to receive additional 

questions in Parts E, F, and G of the questionnaire. To minimize the burden on small entities, 
Appendix A – Survey Design and Calculation of National Estimates

A-4 

EPA did not collect this additional information from plants that were operated by small entities. 

Of the 495 coal plants, 55 of these were identified as small entities. The remaining 440 non-small

(i.e., not owned by small entities) coal plants were further stratified by whether the plant had a 

pond or a landfill for waste management as EPA intended to collect information from plants that 

had ponds and/or landfills containing coal combustion residues (i.e., coal ash or flue gas 

desulfurization (FGD) wastes). Thus, plants that were classified as “No ponds or landfills” were 

excluded from subsampling for Parts E, F, and G. 

Strata defined by pond-landfill status are as follows:

• Pond Only – FGD: Contained all coal plants identified in the sample frame as having 

a pond with FGD waste as one of its contents, but not a landfill; 

• Pond Only – No FGD: Contained all coal plants with an ash pond that does not 

receive FGD waste, but without landfill;

• Landfill Only – FGD: Contained all coal plants that had a landfill with FGD waste as 

one of its contents, but no pond containing coal combustion residues (CCR); 

• Landfill Only – No FGD: Contained all coal plants that had a landfill containing ash 

but without FGD wastes, and did not operate a CCR pond; 

• Ponds and Landfills: Contained all coal plants that had both ponds and landfills 

containing CCR (either ash or FGD wastes). To minimize the number of strata, no 

distinction in plants was made by FGD status; and

• No Ponds or Landfills: Contained all coal plants that did not store or dispose ash or 

FGD wastes in a pond or landfill. 

Seven plants known to operate leachate collection systems were selected with certainty 

because EPA wanted to capture this information fully. EPA excluded two coal plants (containing 

a total of six generating units) from subsampling to avoid the potential burden imposed on these 

plants. Other plants were subsampled with a sampling rate of 30 percent or 10 plants, whichever 

was larger for each stratum listed above.

Table A-2 displays the population counts of coal and petroleum coke plants and the 

corresponding number of generating units, and the sample size for each stratum defined by 

business size and pond-landfill status. The total sample size for Parts E, F, and G for the coal 

plants is 94, of which seven were plants with leachate system selected with certainty (shown in 

parentheses in table A-2). All three non-small petroleum coke plants were included in the 

subsample that received Parts E, F, and G. These plants were not classified by pond-landfill 

status. Therefore, the total sample size for Parts E, F, and G was 97, which consisted of 94 coal 

plants and 3 petroleum coke plants. 
Appendix A – Survey Design and Calculation of National Estimates

A-5 

Table A-2. Population Counts of Coal/Pet Coke Plants and Generating Units, 

and Parts EFG Subsample Size by Substratum

Plant Fuel 

Classification

Business 

Size Pond/Landfill Population Count of Plants

Population 

Count of 

Generating 

Units

Sample Size 

(Certainty 

Selection)b 

Coal

Small All 55 121 0

Non-Small

Pond Only – FGD 39 122 12 (1)

Pond Only – No FGD 99 315 30 (0)

Landfill Only – FGD 18 34 10 (1)

Landfill Only – No FGD 55 142 17 (3)

Both Pond and Landfill 84 256 25 (2)

No Pond or Landfill 143 307 0

Avoid Burdena 2 6 0

Pet Coke

Small -- 6 6 0

Non-Small -- 3 3 3

Total 504 1,312 97 (7)

a - EPA excluded two coal plants from receiving parts E, F, and G to avoid overburdening these plants.

b - In parentheses, the number of plants with the leachate system selected with certainty is shown. The sample size 

includes this number.

The exact number of generating units at the 94 coal plants to be selected was not known 

prior to the sample draw because the number of generating units varies by plant and thus would 

depend on the specific set of coal plants selected. Prior to selecting the sample of coal plants, 

EPA estimated that about 272 generating units at these 94 coal plants would be included in the 

survey. In addition, there were three petroleum coke generating units (from three plants) 

that were selected with certainty. Thus, it was expected that there would be about 275 generating 

units from these 97 plants that would be included in the subsample. 

A.1.5 Sample Selection

The regular sample that received the questionnaire without Parts E, F, and G was selected 

according to the sample design described in subsection A.1.3, resulting in 733 sample plants. The 

majority of the strata were sampled with certainty by design or the constraint of minimum 

sample size of 10 if possible. Because of this minimum sample size constraint, almost all 

combination fuel type strata were certainty strata.

The coal and petroleum coke plants were selected with certainty in the regular sample by 

design but only a subsample of 97 was selected by a stratified design to receive Parts E, F, and G 

of the questionnaire. This subsample is called the Parts EFG subsample. The sample results are 

summarized in Table A-3. The table also presents the base weights, which are the inverse of the 

sampling probability. 
Appendix A – Survey Design and Calculation of National Estimates

A-6 

Table A-3. Summary of Sample Selection of Plants

Stratum/Coal Substratum Population 

Size

Regular Sample Subsample

Size Base Weight Size Base Weighta

Coal – Small Entity 55 55 1 -

Coal – Pond Only –FGD 39 39 1 12 3.45

Coal – Pond Only –no FGD 101b 101 1 30 3.37

Coal – Landfill Only – FGD 18 18 1 10 1.89

Coal – Landfill Only – No FGD 55 55 1 17 3.71

Coal – Both Pond and Landfill 84 84 1 25 3.57

Coal – No Pond and Landfill 143 143 1 - -

Coal Subtotal 495 495 - 94

Gas-Regulated 129 39 3.31 - -

Gas-Unregulated 54 16 3.38 - -

Gas-CC-Regulated 96 29 3.31 - -

Gas-CC-Unregulated 276 83 3.33 - -

Nuclear-Regulated 31 10 3.1 - -

Nuclear-Unregulated 32 10 3.2 - -

Oil-Regulated 23 10 2.3 - -

Oil-Unregulated 20 10 2 - -

Petroleum Coke-Unregulated/Small Entity 6 6 1 - -

Petroleum Coke-Unregulated/Non-small 3 3 1 3 1

Combination: Gas-CC, Nuclear, and OilRegulated 1 1 1 - -

Combination: Gas-CC and Oil-Regulated 2 2 1 - -

Combination: Gas and Gas-CC-Regulated 20 10 2 - -

Combination: Gas and Gas-CC-Unregulated 6 6 1 - -

Combination: Gas, Gas-CC and OilRegulated 1 1 1 - -

Combination: Gas and Oil-Regulated 1 1 1 - -

Combination: Gas and Oil-Unregulated 1 1 1 - -

Non-Coal Subtotal 702 238 - 3 -

Grand Total 1,197 733 - 97 -

a - The subsample base weights are for non-certainty coal plants or for certainty petroleum coke plants.

b - This count includes two plants that were not subsampled due to burden consideration.

A.1.6 Expected Precision

An expected precision is usually calculated for a population proportion of 50 percent. 

Assuming a response rate of 90 percent, the final sample size for the regular sample was 

expected to be 660 (i.e., 90 percent of the 733 sampled plants). To calculate an expected 

precision, a design effect of one was assumed, and the finite population correction was ignored 

to be conservative. The stratification would decrease the design effect but weighting adjustment 

for nonresponse would increase the design effect. So we assumed that these two effects would 
Appendix A – Survey Design and Calculation of National Estimates

A-7 

cancel each other to make the design effect close to one. Under this scenario, the 95 percent 

confidence interval for a point estimate of a population proportion of 50 percent was expected to 

be within ± 3.8 percentage points of the point estimate. If we project the precision for a 

population proportion of 30 percent, the 95 percent confidence interval would be within ± 3.5 

percentage points. 

For the subsample of the coal plants for the Parts E, F, and G questionnaire, under the 

same assumption, it was estimated to have an expected sample size of 85 from the subsample of 

94 coal plants. The 95 percent confidence interval for a point estimate of a population proportion 

of 30 percent was expected to be within +/- 9.2 percentage points of the point estimate. 

For generating unit level estimates, under the same assumption made above and further 

ignoring the clustering effect, the final sample size was expected to be 1,550 (i.e., 90 percent of 

the expected number of generating units of 1,722 in the sample), and the 95 percent confidence 

interval for a point estimate of a population proportion of 50 percent was expected to be within 

+/- 2.5 percentage points of the point estimate. 

EPA determined that these precisions were sufficient to meet the objectives of the survey, 

both for overall plant-level and generating unit level estimates. Moreover, the actual precision is 

expected to be better than the projected precision when the finite population correlation is 

incorporation. Furthermore, the plant level response rate was 100 percent, which further adds 

more precision than projected. 

A.2 SURVEY RESPONSES

Of the 733 survey questionnaires sent out, all were returned, so the plant level response 

rate was 100 percent. However, the survey responses indicate that the frame information on plant 

eligibility, plant fuel classification, and pond-landfill status for coal and petroleum coke plants 

was imperfect. The following subsections provide updated information on the eligibility 

assessment, plant classifications, and pond-landfill classification.

A.2.1 Survey Result of the Eligibility Assessment

Out of 733 respondent plants, a total of 53 plants were found to be ineligible (i.e., out of 

scope). The reasons for the ineligibility include the following: plant did not have the capability to 

engage in steam electric power production; plant would be retired by December 31, 2011; or 

plant did not generate electricity in 2009 using any fossil or nuclear fuels. Of these 53 plants that 

were deemed ineligible, the distribution over the plants fuel types is as follows: 26 coal plants, 

17 gas plants, 6 gas-combined cycle plants, 2 oil plants, 1 petroleum coke plant, and 1 

combination plant. To see the distribution of these ineligible plants further classified by 

regulatory status, see Table A-6 in Section A.3.1, where the number of eligible plants is shown 

and the number of ineligible plants can be obtained by the balance between the original sample 

size and the number of eligible plants. 
Appendix A – Survey Design and Calculation of National Estimates

A-8 

A.2.2 Update of Plant Fuel Type Classification 

At the survey design stage, plant fuel type was classified based on the EIA data and other 

information available to the EPA. After receiving the survey responses, EPA reclassified the 

sampled plant fuel types using the information from the questionnaire. EPA found that 17 of 680 

eligible plants had a fuel type that was different from the original plant fuel type determined at 

the design stage. The table below provides the final plant fuel classification for all 680 eligible 

sampled plants based on the survey data. 

Table A-4. Final Eligible Sampled Plant Fuel Types

Final Plant Fuel Type

(Classified Based on the Survey Data) Number of Plants

Coal 463

Gas 44

Gas - Combined Cycle 109

Nuclear 20

Oil 13

Petroleum Coke 9

Combination: Gas-CC and Nuclear and Oil 1

Combination: Gas-CC and Oil 3

Combination: Gas and Gas-CC 14

Combination: Gas and Gas-CC and Oil 1

Combination: Gas and Oil 3

Total 680

A.2.3 Survey Results for the Coal and Petroleum Coke Plants and the Subsample for 

Parts E, F, and G 

The 504 coal and petroleum coke plants identified at the survey design stage were 

selected with certainty, but only a subsample of 97 of these plants was selected to receive Parts 

E, F, and G of the questionnaire using the sample design described in Section A.1.4. 

Of the 94 coal plants that were selected to receive Parts E, F, and G, 92 plants remained 

eligible after receiving the survey responses. Of the 3 petroleum coke plants selected to receive

Parts E, F, and G, two plants remained eligible after receiving the survey responses. 

Further, the updated pond-landfill status for each plant was obtained from Part A, which 

was completed by every regular sample plant, including those that were not subject to 

subsampling. Based on the survey information, EPA found that some of the pond-landfill for 

coal and petroleum coke plants were incorrectly classified in the frame. The table below provides 

the final summary of how these coal and petroleum coke plants were classified based on the 

updated survey data. 
Appendix A – Survey Design and Calculation of National Estimates

A-9 

Table A-5. Frequency Summary by the Updated Pond-Landfill Status for 

Eligible Coal Plants and by Petroleum Coke Status in the Population and in 

the Parts EFG Subsample

Updated Pond/Landfill Stratum

(Based on the Survey Data)

Eligible Plants in the 

Population

Eligible Plants in 

Subsample

Coal - Both Pond and Landfill 192a 56

Coal - Landfill Only – FGD 12 1

Coal - Landfill Only – No FGD 22 1

Coal - Pond Only – FGD 37 7

Coal - Pond Only – No FGD 112a 27

Coal - No Pond or Landfill 88 0

Petroleum Coke 9 2

Total 472 94

a - The count includes coal plants, which were excluded from subsampling due to concerns of burden.

A.3 WEIGHTING OF THE SURVEY DATA

This section describes the weighting procedure for the regular sample and the subsample 

at the plant level.

A.3.1 Plant-Level Weighting

Weighting the survey data starts with calculating the base weight, which is the inverse of 

the sampling probability, and then nonresponse adjustment is usually applied. Nonresponse 

adjustment entails adjusting the base weight for both non-response and unknown eligibility. 

However for the Steam Electric Survey, there was neither non-response nor sample plants with 

unknown eligibility. Thus, there was no need for EPA to apply this type of weighting adjustment. 

Consequently, the final weight for this survey is defined as the base weight for all sample plants

in the regular sample (note that the Parts EFG subsample is also included in the regular sample). 

The ineligible plants in the sample represent the ineligible population and are given the same 

base weights as well. 

Reclassification of stratification variables does not affect the weighting because the 

weight is the inverse of the selection probability, which is determined at the time of sample 

selection. However, a reclassified stratum now consists of plants from other design strata that 

may have different weights, and this would affect analyses that would be done using the updated 

classification. Table A-6 shows the original population and sample sizes, the number of sample 

plants that were eligible among the original regular sample, the final weight, the reclassified 

number of eligible plants that includes plants from other strata due to reclassification, and the 

estimated population size based on updated classification, which was calculated as the sum of 

final weights of the reclassified plants.
Appendix A – Survey Design and Calculation of National Estimates

A-10 

Table A-6. Estimated Eligible Population Size for Survey-Based Fuel Type Classification

Fuel 

Classification

Regulatory 

Status

Population 

Size in 

Frame

Original 

Sample 

Size

Number 

of 

Eligible 

Plants

Final 

Weight

Reclassified 

No. of 

Eligible 

Plantsa 

Estimated 

Population 

Sizeb 

Coal Regulated 344 344 328 1.0 323 323

Unregulated 151 151 141 1.0 140 140

Gas Regulated 129 39 29 3.308 31 98

Unregulated 54 16 9 3.375 13 39

Gas-CC Regulated 96 29 28 3.310 30 92

Unregulated 276 83 78 3.325 79 258

Nuclear Regulated 31 10 10 3.1 10 31

Unregulated 32 10 10 3.2 10 32

Oil Regulated 23 10 9 2.3 8 18

Unregulated 20 10 9 2.0 5 10

Petroleum Coke a Regulated 0 0 0 - 1 1

Unregulated 9 9 8 1.0 8 8

Comb: Gas-CC, 

Nuclear & Oil

Regulated 1 1 1 1.0 1 1

Unregulated 0 0 0 - - -

Comb: Gas-CC 

and Oil

Regulated 2 2 2 1.0 2 2

Unregulated 0 0 0 - 1 1

Comb: Gas and 

Gas-CC

Regulated 20 10 10 2.0 12 26

Unregulated 6 6 5 1.0 2 2

Comb: Gas and 

Gas-CC and Oil

Regulated 1 1 1 1.0 1 1

Unregulated 0 0 0 - 0 -

Comb: Gas and 

Oil

Regulated 1 1 1 1.0 0 -

Unregulated 1 1 1 1.0 3 5

Total 1,197 733 680 - 680 1,088

a - The count includes reclassified plants initially belonging to a different design stratum.

b - This column shows the sum of the final weights of reclassified plants that was rounded to the nearest integer.

While the column “Number of Eligible Plants” provides the number of eligible plants 

based on the original fuel type classification (regardless of their reclassified fuel type), the 

column named “Reclassified Number of Eligible Plants” gives the number of eligible plants 

based on the reclassification of their fuel type. For example, there were 29 eligible plants among 

those plants originally classified as gas – regulated but 31 plants fell in the class after 

reclassification based on the survey response. Therefore, it should be noted that the estimated 

population size in the last column is the (rounded) sum of the final weights of the reclassified 

eligible plants as each plant carries its own final weight wherever it is reclassified. It is not the 
Appendix A – Survey Design and Calculation of National Estimates

A-11 

same in general as the product of the reclassified number of eligible plants (which may have 

different final weights due to reclassification) and the final weight for the original stratum.119

In general, the estimated population size is smaller than the frame population size for due 

to reclassification and loss of ineligible plants. However, it could be larger if more plants were 

reclassified into that stratum. The overall estimated population size for this survey is 9.9 percent 

less than the frame population size due to loss of ineligible plants. 

The same weighting principle applies to the subsample of 97 coal or petroleum coke 

plants that received Parts E, F, and G because this subsample was selected from the census of the 

coal/petroleum coke population. However, there is an important departure from the weighting 

method used for the full (regular) sample because the subsample was made also to cover plants, 

which were not subject to subsampling. Moreover, it was necessary to do more because almost 

half of the plants in the subsample changed their stratification. So, post-stratification weight 

adjustment was used to address these issues, which is further explained in Section A.3.2 below. 

A.3.2 Plant-Level Weighting for the Parts EFG Subsample 

The subsample of 97 plants was selected from the 504 coal or petroleum coke plants 

identified in the sample frame to receive Parts E, F, and G of the questionnaire. However, 206 

plants were not subject to subsampling (including plants operated by small entities (61), plants 

with no CCR pond or landfill (143), and plants excluded to avoid overburdening (2)). 

Nevertheless, EPA wanted to use the subsample to represent the whole population. Therefore, 

non-coverage weighting adjustment was performed for the subsample.

One subsample was selected for Parts E, F, and G but Part E items do not have as much 

bearing with the Pond-Landfill status as do Parts F and G items. Part E of the questionnaire 

collected information about metal cleaning wastes, which is relevant to all plants, including 

plants with or without CCR ponds or landfills. On the other hand, since Parts F and G are 

applicable only to coal or petroleum coke plants with CCR ponds or landfills, the weighting had 

to account for the Pond-Landfill status. To address the difference in the characteristics of Part E 

items and Parts F and G items, two different sets of weights were developed as explained below: 

one set for Part E and another set for Parts F and G. 

A.3.2.1 Development of the Final Weight for Part E 

As explained in the previous section, the relevant Part E items do not have much bearing 

with the stratification by the Pond-Landfill status. Therefore, non-coverage weight adjustment 

was done so that the sum of the adjusted weights of the subsample of 94 eligible plants is equal

to the eligible population size of 472 (504 frame size minus 32 plants that were ineligible or were 

reclassified as non-coal or non-petroleum coke plants) regardless of their Pond-Landfill status. 

This amounts to using a single weighting adjustment factor that is given by 472 divided by the 

total sum of the base weights of 94 eligible subsample plants, which is 290.4, so the factor is 

 

119 In the Gas – Regulated stratum, there are 31 reclassified eligible plants, which consist of 29 original plants and 2 

reclassified from the Coal stratum (see Table A-6). Therefore, the estimated eligible population size for the Gas – 

Regulated stratum is obtained by 29*3.308+2*1 = 97.932, which is rounded to 98.
Appendix A – Survey Design and Calculation of National Estimates

A-12 

472/290.4 = 1.6253. This factor is multiplied by the subsampling base weights to obtain the Part 

E final weights.

A.3.2.2 Development of the Final Weight for Parts F and G 

Since Parts F and G are only applicable to coal or petroleum coke plants with a CCR 

pond or landfill, the relevant population for Parts F and G consists of all eligible coal plants with 

either a CCR pond or a CCR landfill or petroleum coke plants. Therefore, the subsample of 94 

coal or petroleum coke plants was weighted so that the final weights sum to the eligible 

population size of 384 coal plants with a pond or landfill and petroleum coke plants (i.e., 384 = 

472 eligible coal and petroleum coke plants – 88 plants without pond/landfill).

As shown in Table A-5 above, after the reclassification process, it was found that the 

numbers of sampled plants in some updated substrata are very small (i.e., in the updated “Coal – 

Landfill Only – FGD” and “Coal – Landfill Only – No FGD” strata, there was only 1 plant in 

each received Parts E, F, and G of the questionnaire). Moreover, the ratios between the 

population sizes and sample sizes vary widely. This indicates that if updated substrata are used as 

post-strata for weight adjustment, the resulting weights will be very unstable, and it will cause 

instability of the variance estimate. Therefore, small substrata were collapsed to form the poststrata. With this goal in mind, the updated substrata “Coal – Landfill Only – FGD” and “Coal – 

Landfill Only – No FGD” were collapsed into the updated substratum “Coal – Both Pond and 

Landfill” resulting in four post-strata as follows:

• Post-stratum 1: Coal – Both Pond and Landfill, Coal – Landfill Only – FGD, and 

Coal – Landfill Only – No FGD;

• Post-stratum 2: Coal - Pond Only – FGD;

• Post-stratum 3: Coal - Pond Only – No FGD;

• Post-stratum 4: Petroleum Coke.

Note that all post-strata above were defined using the updated strata.

The weight adjustment factors presented below were used to obtain the final survey 

weights, which are the product of the adjustment factor and the initial base weight in each poststratum. The weight adjustment factor is defined as the ratio of the population size to the sum of 

base weights of eligible subsample plants in the post-stratum.
Appendix A – Survey Design and Calculation of National Estimates

A-13 

Table A-7. Weight Adjustment Factors for the Four Post-Strata

Post Stratum 

Number Updated Substratum

Population

Size

Eligible 

Sample Size

Weight 

Adjustment 

Factor

1 

Coal - Both Pond and Landfill

Coal - Landfill Only – FGD 226 58 1.27

Coal - Landfill Only - No FGD

2 Coal - Pond Only – FGD 37 7 1.86

3 Coal - Pond Only - No FGD 112 27 1.24

4 Pet-Coke - Selected for EFG 9 2 4.5

Total 384 94

A.4 ESTIMATION METHOD

This section presents the general methodology and equations for calculating estimates 

from the survey. 

A.4.1 National Estimates 

The survey collected many sub-items below the plant level. For example, some 

characteristics of generating units were collected. However, sub-units (e.g., generating unit) 

below the plant were all selected, therefore the weight appropriate for weighted analysis is the 

same as the plant level weight. Some of the missing data were filled in using data from the 2009 

EIA database, which is the same year basis as the data provided in response to the questionnaire. 

A small amount of missing data remains, primarily among the sub-plant level variables. 

Nevertheless, in the discussion below, no adjustments are made for missing data. For most 

variables, the consequence of this is negligible due to the small amount of missing data. 

There are three levels of analytical unit (plant, generating unit, sub-generating-unit 

element) with item characteristics at each of these levels. Let whi be the sampling weight for 

plant i within variance stratum h.

120 The variance stratum is defined in the following section, 

where variance estimation is explained.

Different formulas are used for point estimation depending on the type of estimate. Since

estimation of the population total is the most basic, and many estimates can be defined using the 

total estimates, we first discuss estimation of the population total.

Suppose that the parameter of interest is the population total (Y) of a variable denoted by 

y. Then the plant-level weighted total of the y-values for plant i in variance stratum h, ˆhi y , is 

defined as:

 

120 We could use the design stratum to give the estimation formula but to tie point estimation with variance 

estimation, it is more convenient to use the variance stratum.
Appendix A – Survey Design and Calculation of National Estimates

A-14 

 if the -variable is at the plant level 

ˆ if the -variable is at the generating-unit level 

hi hi

hi hi hij j

w y y

ywy y = ∑ 

 if the -variable is at the sub-generating-unit level hi hijk j k wy y











 ∑ ∑

(1)

Using this, the total Y is estimated by:

1 1

ˆ ˆ H nh

hi h i Y y = = = ∑ ∑ (2)

where H is the total number of variance strata, and h n is the number of sample plants in variance 

stratum h for the analysis. Note that the strata involved in analysis depend on the analysis 

variables (items). If the variable is one of the Part E, F, or G items, then the strata are those for 

the Parts EFG subsample. The “hat” over the population parameter indicates an estimate of the 

parameter. When a weighted frequency (e.g., the total number of generating units with a fly wet 

handling system) is calculated, the same formula is used, but the analysis variable y has a value 

of one if the case has the attribute (e.g., having a fly wet handling system), and a value of zero 

otherwise.

To estimate the population mean, we need an estimate of the eligible population size (N), 

and it is estimated by the sum of the weights as follows: 

11 11

ˆ ˆ Hn Hn h h

hi hi hi hi hi

N N w c = = = = = ∑∑ ∑∑ = . (3)

where hi c is the count of the analysis units for plant i in variance stratum h – it is one if the 

analysis unit is the plant, otherwise the count of sub-plant level units.

An estimate of the population mean (Y ) for y-variable is given by: 

ˆ ˆ

ˆ

Y Y

N = . (4)

Population proportions are estimated by (4) if the y-variable is dichotomous. The estimate 

given by (4) is defined as the ratio of two total estimates, so it is called the ratio estimate. When

the population parameter of interest is a ratio (R) of two analysis variables y and x, then it is 

defined as the ratio of two estimated totals:

ˆ ˆ ˆ

Y R

X = (5)
Appendix A – Survey Design and Calculation of National Estimates

A-15 

A.4.2 Variance Estimation 

The original regular sample was selected by a stratified equal probability sample of 

plants, and some strata are very small in size. For variance estimation, small design strata with 

one or two plants selected in Combination strata were collapsed into one stratum. This redefined 

stratum and other original design strata were used as strata for variance estimation, and for this 

reason, they are called variance strata. 

For the Parts EFG subsample, a stratified equal probability sampling method was also 

used except for those coal plants with a leachate collection system, which were selected with 

certainty. These original substrata were also the variance strata for variance estimation for the 

variables from Parts E, F, and G.

Any elements below the plant level such as the generating unit were selected with 

certainty. Therefore, the sample design can be regarded as a single stage cluster sample for items 

at the sub-plant level, where the plants are the primary sampling unit (PSU) and sub-plant level 

elements are the secondary sample unit (SSU). Furthermore, the sub-generating-unit element 

under the generating unit can be considered as the tertiary sampling unit (TSU). The PSUs are 

usually used as variance units for variance estimation, where the variance of an estimate (e.g., 

total) is calculated as the variability of PSU estimates, as is the case for the Steam Electric 

Survey. The variance estimate for the total estimate given in (2) is given by:

( ) ( ) ( ) 2

1 1

ˆ ˆ () 1 ˆ ˆ 1 H nh

h hi h h h i VY f y y n = = =− − − ∑ ∑ (6)

where h hh f nN = , which is the variance stratum sampling fraction, h n is the plant sample size of 

the variance stratum for the analysis, Nh is the variance stratum population size, and 

1 ˆ ˆ h n

h hi h i y yn = = ∑ . The factor 1 h − f in (6) is called the finite population correction (FPC). The 

variance estimate for a non-linear statistic such as the ratio estimate given by equation (4) or (5) 

needs a different formula or technique. 

There are two main approaches for estimating the variance of a non-linear point estimate: 

the Taylor linearization method and resampling methods. For the analyses in all parts (except for 

Parts F and G), the Taylor method was used. Since complex post-stratification weighting was 

used for Parts F and G items, a resampling method known as the jackknife was chosen for the 

analysis, for which the jackknife replicate weights were developed for the Parts F and G. For 

analysis of Parts F and G variables the Taylor method could have been used as well, but the 

jackknife variance estimates were used since they are less biased. The jackknife and FPC factors 

for analysis of variables from Parts F and G are provided in the following table. 
Appendix A – Survey Design and Calculation of National Estimates

A-16 

Table A-8. The Jackknife and Finite Population Correction (FPC) Factors 

for Parts F and G 

Variance 

Stratum Description of Variance Stratum

Number of 

Replicates

Jackknife 

Factor FPC Factor

1 Coal – Both Pond and Landfill 23 0.95652 0.77841

2 Coal – Landfill Only – FGD 9 0.88889 0.59805

3 Coal – Landfill Only – No FGD 14 0.92857 0.78810

4 Coal – Pond Only - FGD 11 0.90909 0.78898

5 Coal – Pond Only – No FGD 28 0.96429 0.76230

6 Coal – All other types 7 0.85714 0.24871

7 Petroleum coke – Selected for EFG 2 0.5 0.77778
Appendix B –Modified Delta-Log Normal Distribution

APPENDIX B

MODIFIED DELTA-LOGNORMAL DISTRIBUTION
Appendix B –Modified Delta-Log Normal Distribution

B-1 

APPENDIX B

Contents

B.1 Basic Overview of the Modified Delta-Lognormal Distribution 

B.2 Continuous and Discrete Portion of the Modified Delta-Lognormal Distribution

B.3 Combining the Continuous and Discrete Portion

B.4 Autocorrelation 

B.5 Plant-Specific Estimates Under the Modified Delta-Lognormal Distribution

B.5.1 Dataset Requirement

B.5.2 Estimation of Plant-Specific Long-Term Averages and Variability Factors

B.5.2.1 Estimation of Plant-Specific Long-Term Averages (LTA)

B.5.2.2 Estimation of Plant-Specific Daily Variability Factors (VF1)

B.5.2.3 Estimation of Plant-Specific Monthly Variability Factors (VF4)

B.6 Estimation of Plant-Specific Long-Term Averages and Variability Factors

Assuming Autocorrelation 

B.6.1 Estimation of Plant-Specific Long-Term Averages (LTA)

B.6.2 Estimation of Plant-Specific Daily Variability Factors (VF1)

B.6.3 Estimation of Plant-Specific Monthly Variability Factors (VF4)

B.7 Evaluation of Plant-Specific Variability Factors

B.8 References
Appendix B –Modified Delta-Log Normal Distribution

B-2 

This appendix describes the modified delta-lognormal distribution and the estimation of 

the plant-specific long-term averages and plant-specific variability factors used to calculate the 

limitations and standards. This appendix provides the statistical methodology that was used to 

obtain the results presented in Section 13 of the Technical Development Document. For 

simplicity, in the remainder of this appendix, references to “limitations” include “standards”.

The term “detected” in this document refers to analytical results measured and reported 

above the sample-specific quantitation limit. Thus, the term “non-detected” refers to values that 

are below the method detection limit (MDL) and those measured by the laboratory as being 

between the MDL and the quantitation limit (QL) in the original data (before adjusting for 

baseline). 

B.1 Basic Overview of the Modified Delta-Lognormal Distribution 

EPA selected the modified delta-lognormal distribution to model pollutant effluent 

concentrations from the steam electric industry in developing the long-term averages and 

variability factors. A typical effluent dataset from EPA sampling, CWA 308 sampling, or from a 

plant’s self-monitoring consists of a mixture of measured (detected) and non-detected values. 

The modified delta-lognormal distribution is appropriate for such datasets because it models the 

data as a mixture of detected measurements that follow a lognormal distribution and non-detect 

measurements that occur with a certain probability. The model also allows for the possibility that 

non-detected measurements occur at multiple sample-specific detection limits. Because the data 

appeared to fit the modified delta-lognormal model reasonably well, EPA has determined that 

this model is appropriate for these data.

The modified delta-lognormal distribution is a modification of the ‘delta distribution' 

originally developed by Aitchison and Brown.121 While this distribution was originally 

developed to model economic data, other researchers have shown the application to 

environmental data.122 The resulting mixed distributional model, that combines a continuous 

density portion with a discrete-valued spike at zero, is also known as the delta-lognormal 

distribution. The delta in the name refers to the proportion of the overall distribution contained in 

the discrete distributional spike at zero, that is, the proportion of zero amounts. The remaining 

non-zero amounts are grouped together and fit to a lognormal distribution.

EPA modified this delta-lognormal distribution to incorporate multiple detection limits. 

In the modification of the delta portion, the single spike located at zero is replaced by a discrete 

distribution made up of multiple spikes. Each spike in this modification is associated with a 

distinct sample-specific detection limit associated with non-detected (ND) measurements in the 

database. A lognormal density is used to represent the set of detected values. This modification 

of the delta-lognormal distribution is illustrated in the figure below. 

 

121 Aitchison, J. and J.A.C. Brown. 1963. The Lognormal Distribution. Cambridge University Press, pages 87-99.

122 Owen, W.J. and T.A. DeRouen. 1980. “Estimation of the Mean for Lognormal Data Containing Zeroes and LeftCensored Values, with Applications to the Measurement of Worker Exposure to Air Contaminants.” Biometrics, 

36:707-719. 
Appendix B –Modified Delta-Log Normal Distribution

B-3 

Figure B-1. Modification of the Delta-Lognormal Distribution 

The following two sections describe the delta and lognormal portions of the modified 

delta-lognormal distribution in further detail.

B.2 Continuous and Discrete Portions of the Modified Delta-Lognormal Distribution 

In the discrete portion of the modified delta-lognormal distribution, the non-detected 

values correspond to the k reported sample-specific detection limits. In the model, δ represents 

the proportion of non-detected values and is the sum of δi, i=1,...,k, which represents the 

proportion of non-detected values associated with the i

th distinct detection limit. By letting Di

equal the value of the i

th smallest distinct detection limit in the dataset and letting the random 

variable XD represent a randomly chosen non-detected measurement, the cumulative distribution 

function of the discrete portion of the modified delta-lognormal model can be mathematically 

expressed as:

Pr(XD ≤ c) = 1

δ � δi

i:Di≤c

, c > 0 (1)

0

Modified Delta-Lognormal Distribution

Censoring Type D ND
Appendix B –Modified Delta-Log Normal Distribution

B-4 

The mean and variance of this discrete distribution can be calculated using the following 

formulas:

E(XD) = 1

δ�δi

k

i=1

Di (2)

Var(XD) = 1

δ�δi(Di − E(XD))2

k

i=1

(3)

The continuous, lognormal portion of the modified delta-lognormal distribution was used 

to model the detected measurements. The cumulative probability distribution of the continuous 

portion of the modified delta-lognormal distribution can be mathematically expressed as:

Pr(XC ≤ c) = Φ �

ln(c) − μ

σ � (4)

where the random variable X C represents a randomly chosen detected measurement, Φ(·) is the 

cumulative distribution function of the standard normal distribution, and μ and σ are parameters 

of the distribution. 

The expected value, E(XC), and the variance, Var(XC), of the lognormal distribution can 

be calculated as:

E(Xc) = exp �μ +

σ2

2 � (5)

Var(XC) = �E(XC)�

2

(exp(σ2) − 1) (6)

B.3 Combining the Continuous and Discrete Portions

The continuous portion of the modified delta-lognormal distribution is combined with the 

discrete portion to model data that contain a mixture of non-detected and detected measurements. 

It is possible to fit a wide variety of observed effluent data to the modified delta-lognormal 

distribution. Multiple detection limits for non-detect measurements are incorporated, as are 

measured ("detected") values. The same basic framework can be used even if there are no nondetected values in the dataset (in this case, it is the same as the lognormal distribution). Thus, the 

modified delta-lognormal distribution offers a large degree of flexibility in modeling effluent 

data.

The modified delta-lognormal random variable U can be expressed as a combination of 

three other independent variables as follows: 
Appendix B –Modified Delta-Log Normal Distribution

B-5 

U = IUXD + (1 − IU)Xc (7)

where XD represents a random non-detect from the discrete portion of the distribution, XC

represents a random detected measurement from the continuous lognormal portion, and UI is a 

variable indicating whether any particular random measurement, U, is non-detected or detected 

(that is, IU=1 if u is non-detected, and IU=0 if u is detected). Using a weighted sum, the 

cumulative distribution function from the discrete portion of the distribution (equation 1) can be 

combined with the function from the continuous portion (equation 4) to obtain the overall 

cumulative probability distribution of the modified delta-lognormal distribution:

Pr(U ≤ c) = � δi

i:Di≤c

+ (1 − δ)Φ �

ln(c) − μ

σ � (8)

The expected value of the random variable U can be derived as a weighted sum of the 

expected values of the discrete and continuous portions of the distribution (equations 2 and 5, 

respectively) as follows:

E(U) = δE(XD) + (1 − δ)E(XC) (9)

In a similar manner, the expected value of 2 U can be written as a weighted sum of the 

expected values of the squares of the discrete and continuous portions of the distribution: 

E(U2) = δE(XD

2) + (1 − δ)E(XC

2) (10) 

Although written in terms of U, the following relationship holds for all random variables: 

E(U2) = Var(U) + �E(U)�

2 (11) 

Now using equation 11 to solve for Var(U), and applying the relationships in equations 9 and 10, 

the variance of U is given by 

Var(U) = δ �Var(XD) + �E(XD)�

2

� + (1 − δ) �Var(XC) + �E(XC)�

2

� − �E(U)�

2 (12) 

Thus the modified delta-lognormal distribution can be described by the following parameters: the 

k distinct detection limits, Di, and their corresponding probabilities, , 1,..., , i δ i k = and the 

parameters μ and σ of the lognormal distribution for detected values. 

B.4 Autocorrelation 

Effluent data from wastewater treatment technologies may be autocorrelated. For 

example, positive autocorrelation is present in the data if the effluent concentration was 

relatively high one day and was likely to remain high on the next and possibly succeeding days. 
Appendix B –Modified Delta-Log Normal Distribution

B-6 

For data with autocorrelation, statistical time series are appropriate for modeling the data. There 

are many time series models that might be considered for modeling wastewater measurements. 

One method of modeling autocorrelation is by using an autoregressive lag-1 model, designated 

as an AR(1) model. The AR(1) model is a reasonable model for many series of wastewater 

measurements. The AR(1) model has one parameter, ρ1, the correlation between log-transformed 

measurements from successive sampling events equally spaced over time, otherwise referred to 

as the lag-1 correlation. Unless specified otherwise, ρ1 is assumed to be zero, i.e., no 

autocorrelation.

The autocorrelation affects the mean and variance estimates. Specifically, when the data 

are deemed to be positively autocorrelated, the variance estimate from samples collected on 

successive days will be less than the variance of the long-term concentration series, and thus the 

variance estimates from the sampled days should be adjusted for the correlation in order to 

obtain an accurate estimate of the variance for the long-term series. Adjustments for 

autocorrelation have been made whenever appropriate. See Section 13 of the Technical 

Development Document for a discussion of the use of autocorrelation in calculating the limits.

The equations in Section B.5 were used when the autocorrelation was assumed to be 

zero; otherwise the equations in Section B.6 were used. 

B.5 Plant-Specific Estimates Under the Modified Delta-Lognormal Distribution 

In order to use the modified delta-lognormal model, the parameters of the distribution 

must be estimated from the data. These estimates are then used to calculate the limitations. The 

following assumes that the parameter estimates are calculated from n observed daily values. 

The parameters δi and δ are estimated from the data using the following formulas:

δ̂

i = 1

n�I

nd

j=1

�dj = Di�

δ̂ = nd

n

(13)

where n is the number of measurements (both detected and non-detected), I(

.

) is an indicator 

function equal to one if the argument is true (and zero otherwise), dj, j = 1,..., nd, is the detection 

limit for the j

th non-detected measurement, and nd is the total number of non-detected 

measurements. The "hat" over the parameters indicates that these values are estimated from the 

data.

The expected value and the variance of the discrete portion of the modified deltalognormal distribution can be estimated from the data as:

E�(XD) = 1

δ̂

�δ̂

i

k

i=1

Di (14) 
Appendix B –Modified Delta-Log Normal Distribution

B-7 

V�ar(XD) = 1

δ̂

�δ̂

i

k

i=1

�Di − E�(XD)�

2

(15) 

The parameters μ and σ of the continuous portion of the modified delta-lognormal 

distribution are estimated from

μ̂= �ln(xi)

nc

nc

i=1

(16) 

σ�2 = �(ln(xi) − μ̂)2

nc − 1

nc

i=1

(17) 

where xi is the i

th detected measurement and nc is the number of detected measurements (note 

that n = nd + nc). 

The expected value and the variance of the lognormal portion of the modified deltalognormal distribution can be calculated from the data as:

E�(XC) = exp �μ̂+

σ�2

2 � (18) 

V�ar(XC) = �E�(XC)�

2

(exp(σ�2) − 1) (19) 

Finally, the expected value and variance of the modified delta-lognormal distribution can 

be estimated using the following formulas:

E�(U) = δ̂E�(XD) + �1 − δ̂�E�(XC) (20)

V�ar(U) = δ̂ �V�ar(XD) + �E�(XD)�

2

� + �1 − δ̂� �V�ar(XC) + �E�(XC)�

2

� − �E�(U)�

2

(21) 

Equations 18 through 21 are particularly important in the estimation of the plant longterm averages and variability factors as described in the following sections.

B.5.1 Dataset Requirements

The parameter estimates for the lognormal portion of the modified delta-lognormal 

distribution can be calculated with as few as two distinct detected values in a dataset. (In order to 

estimate the variance of the modified delta-lognormal distribution, at least two distinct detected 

values are required.)

For this rulemaking, EPA used a plant dataset for a pollutant to calculate the plantspecific long-term average and variability factor if the dataset contained three or more 
Appendix B –Modified Delta-Log Normal Distribution

B-8 

observations with at least two distinct detected concentration values. If the plant dataset for a 

pollutant did not meet these requirements, EPA used an arithmetic average to calculate the plantspecific long-term average and excluded the dataset from the variability factor calculations (since 

the variability could not be calculated in this situation). 

B.5.2 Estimation of Plant-Specific Long-Term Averages and Variability Factors 

If a dataset for a pollutant at a plant meets the requirement described in Section B.5.1 

above, then the plant-specific long-term averages and variability factors are estimated as 

described in the subsections below. Furthermore, another assumption made in the estimating 

procedures described below is that no autocorrelation exists in the data (i.e., daily measurements 

are independent).

B.5.2.1 Estimation of Plant-Specific Long-Term Averages (LTA)

The plant specific long-term average (LTA) is calculated as follows:

LTA = E�(U) = δ̂E�(XD) + �1 − δ̂�E�(XC) = �δ̂

iDi + �1 − δ̂�exp(μ̂+ 0.5σ�2)

k

i=1

(22) 

Section B.5 contains all the formulas used for each of the expressions above. In the case 

where there are less than two distinct detected values, the variance in the above formula cannot 

be calculated. In this case, the long-term average is calculated as the arithmetic mean of the 

available data (consisting of detected values and detection limits).

B.5.2.2 Estimation of Plant-Specific Daily Variability Factors (VF1) 

The plant-specific daily variability factor is the ratio of the 99th percentile to the longterm average and is calculated as follows:

VF1 = P�

99

E�(U)

= P�

99

LTA (23) 

Below a description is given of how the 99th percentile of the modified delta-lognormal 

distribution is estimated, including how multiple detection limits are accounted for when 

estimating the 99th percentile.

Under the modified delta-lognormal distribution, if D1 < D2 < ... < Dk are the k observed 

detection limits expressed in increasing order, then let

q�m = � δ̂

i + �1 − δ̂�Φ �ln(Dm) − μ

σ� � , m = 1, ... , k

m

i=1

(24) ̂

where Φ(·) is the cumulative distribution function of the standard normal distribution. If all k of 

the ˆmq values are below 0.99, then 
Appendix B –Modified Delta-Log Normal Distribution

B-9 

P�

99 = exp �μ̂+ σ� ∙ Φ−1 �

0.99 − δ̂

1 − δ̂ �� (25) 

where Φ-1(p) is the p

th percentile of the standard normal distribution. Otherwise, find j such that 

Dj is the smallest detection limit for which ˆj q ≥ 0.99, and let ˆ ˆ ˆ *

j j q q = −δ . Then the 99th percentile 

is found by the following: 

P�

99 =

⎩

⎪

⎨

⎪

⎧ Dj if q�∗ < 0.99

exp �μ̂+ σ� ∙ Φ−1 �

0.99 − ∑ δ̂

i

j−1

i=1

1 − δ̂ �� if q�∗ ≥ 0.99 (26) 

B.5.2.3 Estimation of Plant-Specific Monthly Variability Factors (VF4) 

Plant-specific monthly variability factors were based on 4-day monthly averages because 

EPA assumed the monitoring frequency to be weekly (approximately four times a month). The 

plant-specific monthly variability factor for each plant is the ratio of a 95th percentile to the long 

term average. In this case, the percentile we seek is the 95th percentile of the distribution ofU4 , 

which represents the average of four samples for a given plant. The monthly variability factor is 

calculated as follows:

VF4 = P�

95

E�(U)

= P�

95

LTA (27) 

Below a description is given of how the 95th percentile is estimated under the assumption 

that U4 has a modified delta-lognormal distribution. The following steps also show how multiple 

detection limits (for non-detected values) were accounted for when estimating the 95th percentile

of the monthly average. 

In order to calculate the 4-day variability factor (VF4), the assumption was made that the 

approximating distribution of U4 , the sample mean for a random sample of four independent 

concentrations, was also derived from the modified delta-lognormal distribution. To obtain the 

expected value of the mean of the four daily values, equation 20 is modified to indicate that it 

applies to the average:

E�(U�4) = δ̂

4�E�(X�4)D� + �1 − δ̂4�E�(X�4)C (28)

where ( ) 4 D X denotes the mean of the discrete portion of the distribution of the average of four 

independent concentrations, (i.e., when all observations are non-detected) and ( ) 4 C

X denotes the 

mean of the continuous lognormal portion (i.e., for averages involving detected observations). 
Appendix B –Modified Delta-Log Normal Distribution

B-10 

First, it was assumed that the detection of each measurement is independent (the 

measurements were also assumed to be independent). Therefore, the probability of the detection 

of the measurements can be written as δ4 = δ4. Because the measurements are assumed to be 

independent, the following relationships hold: 

E�(U�4) = E�(U)

V�ar(U�4) = V�ar(U)

4

E�((X�4)D) = E�(XD) (29)

V�ar((X�4)D) = V�ar(XD)

4

Substituting into equation 28 and solving for the expected value of the continuous portion 

of the distribution gives: 

E�(X�4)C = E�(U) − δ̂4E�(XD)

1 − δ̂4 (30) 

Using the relationship in equation 21 for the averages of 4 daily values, substituting terms 

from equation 29, and solving for the variance of the continuous portion of U4 gives:

V�ar(X�4)C =

V�ar(U)

4 + �E�(U)�

2

− δ̂4 �

V�ar(XD)

4 + �E�(XD)�

2

�

1 − δ̂4 − �E�(X�4)C�

2 (31) 

Using equations 18 and 19 and solving for the parameters of the lognormal distribution 

describing the distribution of ( ) X4 C gives:

σ�4

2 = ln �V�ar(X�4)C

�E�(X�4)C�

2 + 1�

μ̂

4 = ln�E�(X�4)C� − σ�4

2

2 (32) 

The non-detects can generate an average that is not necessarily equal to any of the D1, 

D2,...,Dk. Consequently, more than k discrete points exist in the distribution of the 4-day 

averages. For example, the average of four non-detects when there are k=2 distinct detection 

limits are at the following discrete k* points with the associated probabilities denoted by *

, δ i

i=1,..., k*: 
Appendix B –Modified Delta-Log Normal Distribution

B-11 

i Value of U4 ( * Di ) Probability of Occurrence ( * δ i )

1 D1 

4

1 δ

2 (3D1 + D2)/4 2

3

1 4 δδ

3 (2D1 + 2D2)/4 2

2

2 6 1 δδ

4 (D1 + 3D2)/4 3

21 4 δδ

5 (=k*) D2

4

2 δ

When all four observations are non-detected values, and when k distinct non-detected 

values exist, the multinomial distribution can be used to determine associated probabilities. That 

is,

Pr �U�4 = ∑ uiDi

k

i=1

4 � = 4!u1! u2! ⋯ uk!

�δi

ui

k

i=1

(33) 

where ui is the number of non-detected measurements at the detection limit Di. The number k* of 

possible discrete averages for k=1,...,5, are as follows:

K k*

1 1

2 5

3 15

4 35

5 70

The remaining approach to estimating P95 is similar to the approach used to estimate P99

in the calculation of one-day variability factors, as described above. For m = 1, ..., k*, let

q�m = �δ̂

i

∗ + �1 − δ̂4�

m

i=1

Φ �

ln(Dm

∗ ) − μ̂

4

σ�4

� (34) 

where Φ(·) is the cumulative distribution function of the standard normal distribution. 

Now, if all k values of ˆmq defined above are less than 0.95, then the 95th percentile is 

defined as: 
Appendix B –Modified Delta-Log Normal Distribution

B-12 

P�

95 = exp �μ̂4 + σ�4 ∙ Φ−1 �

0.95 − δ̂4

1 − δ̂4 �� (35) 

where Φ-1(p) is the p

th percentile of the standard normal distribution. Otherwise, let * Dj denote 

the smallest of the k* values of * Di for which ˆj q ≥ 0.95, and let qˆ *= ˆj q - ˆ*

j δ . Then, the 95th

percentile is defined by the following: 

P�

95 =

⎩

⎪

⎨

⎪

⎧ Dj

∗ if q�∗ < 0.95

exp �μ̂

4 + σ�4 ∙ Φ−1 �

0.95 − ∑ δ̂

i

j−1 ∗

i=1

1 − δ̂4 �� if q�∗ ≥ 0.95 (36) 

B.6 Estimation of Plant-Specific Long-Term Averages and Variability Factors 

Assuming Autocorrelation 

Section B.5 above described the procedure used to estimate the long-term averages and 

variability factors assuming no autocorrelation existed in the data. The subsections below 

describe how the plant specific long-term averages and variability factors are estimated assuming 

the autocorrelation exists in the data. Autocorrelation in the successive measurements affects the 

variance of the observed data. Therefore, if autocorrelation is deemed present in the data, then it 

should be accounted for when calculating the long term average and variability factors.

When the concentrations have autocorrelation, EPA substitutes the detection limit for the 

non-detects and assumes that all resulting values are detected and have a lognormal distribution. 

Since all measurements are treated as detects, δ=0 and the equations for the continuous portion 

of the delta-lognormal distribution can be adapted to describe all the data. 

B.6.1 Estimation of Plant-Specific Long-Term Averages (LTA)

If a dataset for a pollutant at a plant meets the requirements described in Section B.5.1, 

then the plant specific long-term average (LTA) is calculated as follows:

LTA = exp(μ̂

all + 0.5σ�A

2) (37) 

The parameter estimates μall ˆ and 2 ˆσ A are obtained using all n measurements as follows:

μ̂

all = �ln(xi)

n

n

i=1

(38) 
Appendix B –Modified Delta-Log Normal Distribution

B-13 

σ�A

2 = 1

g(R)

�(ln(xi) − μ̂

all)2

n − 1

n

i=1

(39) 

where xi is the i

th measurement value, n is the total number of measurements (including both 

detected and non-detected values), and g(R) is the adjustment for autocorrelation. For an AR(1) 

model with a 1-day lag correlation of ρ1

 and n daily values, the correlation (in the log scale) 

between xi and xj (i ≠ j) is Corr(ln(xi), ln(xj)) = 1

i j ρ − . Then the adjustment for the autocorrelation 

is

g(R) = 1 − ∑ ∑ ρ1

|i−j|

i∈T j∈T,j≠i

n(n − 1) (40) 

where T = {1,...,n} is the set of days with observed daily values. For an AR(1) model with n

sequential daily values, this reduces to

g(R) = 1 − � 2

n(n − 1)

� � ρ1

1 − ρ1

� �(n − 1) − ρ1(1 − ρ1

n−1)

1 − ρ1

� (41) 

since

� � ρ1

|i−j|

j ∈T,

j≠i

i∈T

= 2 � ρ1

1 − ρ1

� �(n − 1) − ρ1(1 − ρ1

n−1)

1 − ρ1

�

where ρ1 is the correlation of the log-transformed measurements from successive sampling events. 

Note that if the daily values are independent (i.e., autocorrelation is not present in the data), then 

g(R) = 1. 

B.6.2 Estimation of Plant-Specific Daily Variability Factors (VF1) 

The plant-specific daily variability factor is the ratio of the 99th percentile to the longterm average and is calculated by

VF1 = P�

99

E�(U)

= P�

99

LTA (42) 

The 99th percentile 99 Pˆ in equation 42 is calculated as 

P�

99 = exp�μ�all + 2.326 σ�A� (43)
Appendix B –Modified Delta-Log Normal Distribution

B-14 

where 2.326 is the 99th percentile of the standard normal distribution. 

B.6.3 Estimation of Plant-Specific Monthly Variability Factors (VF4) 

Plant-specific monthly variability factors were based on 4-day monthly averages because 

EPA assumed the monitoring frequency to be weekly (approximately four times a month). The 

plant-specific monthly variability factor for each plant is the ratio of a 95th percentile to the longterm average. In this case, the percentile we seek is the 95th percentile of the distribution ofU4 , 

which represents the average of four samples for a given plant. 

Assuming the data follow a lognormal distribution, the monthly variability factor is 

calculated as:

VF4 = P�95

E�(U) = exp�μ̂

4 + σ�4Φ−1(0.95)�

LTA

(44)

where

σ�4

2 = ln �

V�ar(U�4)C

�E�(U�4)C�

2 + 1�

μ̂

4 = ln�E�(U�4)C� − σ�4

2

2

(45) 

The variance of the average represented by ( ) 4 Var U ˆ is 

V�ar(U�4) = V�ar(U)

4 �1 + f4(R)� (46) 

where the factor 4f R( ) is used to adjust for the autocorrelation among the four values in the 

average. This adjustment factor is found by 

f4(R) = 2

4�(4 − k)

3

k=1

�

exp�ρ1

7kσ�A2� − 1

exp(σ�A

2) − 1 � (47) 

B.7 Evaluation of Plant-Specific Variability Factors

The parameter estimates for the lognormal portion of the distribution can be calculated 

with as few as two distinct measured values in a dataset (in order to calculate the variance); 

however, these estimates can be imprecise (as can estimates from larger datasets). As stated in 

Section B.5.1 above, EPA developed plant-specific variability factors for datasets that had three 

or more observations with two or more distinct measured concentration values. 
Appendix B –Modified Delta-Log Normal Distribution

B-15 

To identify situations producing unexpected results, EPA reviewed all of the variability 

factors and compared daily to monthly variability factors. EPA used several criteria to determine 

if the plant-specific daily and monthly variability factors should be included in calculating the 

option variability factors (the option variability factors refer to the technology option variability 

factor for a pollutant rather than regulatory option). One criterion that EPA used was that the 

daily and monthly variability factors should be greater than 1.0. A variability factor less than 1.0 

would result in an unexpected result where the estimated 99th percentile would be less than the 

long-term average. This would be an indication that the estimate of σ (the standard deviation in 

log scale) was particularly large and most likely imprecise. A second criterion was that not all of 

the sample-specific detection limits could exceed the detected values. All plant-specific 

variability factors used for the limitations and standards met both the first and second criteria. A 

third criterion was that the daily variability factor had to be greater than the monthly variability 

factor. When this criterion was not met, the daily and monthly variability factors were excluded. 

B.8 References

1. Aitchison, J. and J.A.C. Brown. 1963. The Lognormal Distribution. Cambridge 

University Press, New York. 

2. Barakat, R. 1976. “Sums of Independent Lognormally Distributed Random Variables.” 

Journal Optical Society of America, 66: 211-216. 

3. Cohen, A. C. 1976. “Progressively Censored Sampling in the Three Parameter LogNormal Distribution.” Technometrics, 18:99-103. 

4. Crow, E.L. and K. Shimizu. 1988. Lognormal Distributions: Theory and Applications. 

Marcel Dekker, Inc., New York. 

5. Kahn, H.D., and M.B. Rubin. 1989. "Use of Statistical Methods in Industrial Water 

Pollution Control Regulations in the United States." Environmental Monitoring and 

Assessment. Vol. 12:129-148. 

6. Owen, W.J. and T.A. DeRouen. 1980. “Estimation of the Mean for Lognormal Data 

Containing Zeroes and Left-Censored Values, with Applications to the Measurement of 

Worker Exposure to Air Contaminants.” Biometrics, 36:707-719.