United States Office of Water EPA-821-R-15-007

Environmental Protection Washington, DC 20460 September 2015

Agency

Technical Development 

Document for the Effluent 

Limitations Guidelines and 

Standards for the Steam 

Electric Power Generating 

Point Source Category
Technical Development Document for the 

Effluent Limitations Guidelines and 

Standards for the Steam Electric Power 

Generating Point Source Category

EPA-821-R-15-007

September 2015

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

i

TABLE OF CONTENTS

Page

GLOSSARY ................................................................................................................................ XVIII

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 Best Available Demonstrated Control Technology (BADCT)/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).......................................1-5

1.3 Regulatory History of the Steam Electric Power Generating Point Source 

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

1.3.1 Discharge Requirements Established in Prior Rulemakings.......................1-5

1.3.2 Detailed Study of the Steam Electric Power Generating Point Source 

Category ......................................................................................................1-6

1.3.3 Other Statutes and Regulatory Requirements Affecting Management 

of Steam Electric Power Generating Wastewaters......................................1-7

SECTION 2 SUMMARY OF THE FINAL RULE................................................................................2-1

2.1 Summary of Discharge Requirements......................................................................2-1

2.1.1 Discharges Directly to Surface Water from Existing Sources ....................2-2

2.1.2 Discharges Directly to Surface Water from New Sources..........................2-3

2.1.3 Discharges to POTWs from Existing Sources.............................................2-4

2.1.4 Discharges to POTWs from New Sources ..................................................2-4

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 Questionnaire for the Steam Electric Power Generating Effluent Guidelines .........3-2

3.3 Site Visits..................................................................................................................3-5

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 National Pollutant Discharge Elimination System (NPDES) Permits, 

Permit Applications, and Fact Sheets........................................................3-15

3.5.2 State Groups and Permitting Authorities...................................................3-15

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 ...........................................................................3-16

3.5.5 Office of Air and Radiation.......................................................................3-17
Table of Contents

TABLE OF CONTENTS (Continued)

Page

ii

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

3.5.7 Office of Solid Waste and Emergency Response......................................3-18

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

3.6.1 Self-Monitoring Data for Proposed Rule ..................................................3-19

3.6.2 Post-Proposal Industry-Submitted Data ....................................................3-19

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

3.7 Technology Vendor Data........................................................................................3-21

3.8 Other Data Sources.................................................................................................3-22

3.8.1 Utility Water Act Group............................................................................3-22

3.8.2 Electric Power Research Institute..............................................................3-22

3.8.3 Department of Energy ...............................................................................3-24

3.8.4 Literature and Internet Searches................................................................3-25

3.8.5 Environmental Groups and Other Stakeholders........................................3-25

3.8.6 EPA Public Meetings ................................................................................3-25

3.9 Protection of Confidential Business Information ...................................................3-25

3.10 References...............................................................................................................3-26

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

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

4.3 Steam Electric Wastestreams with New Controls in the Final 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 Combustion Residual Leachate .....................4-34

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

4.4 Steam Electric Wastestreams Selected for New Controls in the Final ELGs.........4-38

4.4.1 Metal Cleaning Waste ...............................................................................4-38

4.4.2 Carbon Capture Wastewater......................................................................4-40

4.5 Changes in Steam Electric Industry Population .....................................................4-42

4.5.1 Updated Industry Profile Population.........................................................4-43

4.5.2 CCR Population.........................................................................................4-44

4.5.3 CPP Population..........................................................................................4-45

4.6 References...............................................................................................................4-46

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

5.1 Subcategorization Factors.........................................................................................5-1
Table of Contents

TABLE OF CONTENTS (Continued)

Page

iii

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

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

5.2.2 Geographic Location ...................................................................................5-3

5.2.3 Size ..............................................................................................................5-3

5.2.4 Fuel Type.....................................................................................................5-4

5.2.5 Processes Employed ....................................................................................5-4

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

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

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

6.2 Ash Transport Water.................................................................................................6-7

6.2.1 Fly Ash Transport Water.............................................................................6-7

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

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

6.3 Combustion Residual Leachate from Landfills and Surface Impoundments.........6-11

6.4 Flue Gas Mercury Control Wastewater..................................................................6-14

6.5 Gasification Wastewater.........................................................................................6-15

6.6 Pollutants of Concern .............................................................................................6-17

6.6.1 FGD Wastewater POCs.............................................................................6-18

6.6.2 Combustion Residual Leachate POCs.......................................................6-20

6.6.3 Gasification Wastewater POCs .................................................................6-21

6.6.4 Ash Transport Water POCs.......................................................................6-23

6.6.5 Flue Gas Mercury Control Wastewater POCs...........................................6-27

6.7 References...............................................................................................................6-28

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 ................................................................................7-5

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

7.1.4 Evaporation System...................................................................................7-14

7.1.5 Constructed Wetlands................................................................................7-18

7.1.6 Design/Operating Practices Achieving Zero Discharge............................7-18

7.1.7 Other Technologies under Investigation ...................................................7-20

7.2 Fly Ash Handling, Management, and Treatment Technologies.............................7-25

7.2.1 Wet Sluicing System .................................................................................7-28

7.2.2 Fly Ash Dense Slurry System....................................................................7-29

7.2.3 Wet Vacuum Pneumatic System ...............................................................7-31

7.2.4 Dry Vacuum System..................................................................................7-32

7.2.5 Pressure System.........................................................................................7-33

7.2.6 Combined Vacuum/Pressure System ........................................................7-35

7.2.7 Mechanical System....................................................................................7-35

7.3 Bottom Ash Handling, Management, and Treatment Technologies ......................7-36

7.3.1 Wet-Sluicing System.................................................................................7-39
Table of Contents

TABLE OF CONTENTS (Continued)

Page

iv

7.3.2 Bottom Ash Dense Slurry System.............................................................7-40

7.3.3 Mechanical Drag System...........................................................................7-41

7.3.4 Remote Mechanical Drag System .............................................................7-42

7.3.5 Dry Mechanical Conveyor ........................................................................7-44

7.3.6 Dry Vacuum or Pressure System...............................................................7-45

7.3.7 Vibratory Belt System ...............................................................................7-46

7.3.8 Mechanical System....................................................................................7-47

7.3.9 Complete Recycle System.........................................................................7-47

7.4 Combustion Residual Leachate ..............................................................................7-48

7.5 Flue Gas Mercury Control Wastewater Treatment Technologies..........................7-50

7.6 Gasification Wastewater Treatment Technologies.................................................7-51

7.6.1 Evaporation System...................................................................................7-52

7.6.2 Cyanide Destruction ..................................................................................7-52

7.7 References...............................................................................................................7-52

SECTION 8 THE FINAL RULE.......................................................................................................8-1

8.1 BPT...........................................................................................................................8-1

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

8.2.1 FGD Wastewater .........................................................................................8-4

8.2.2 Fly Ash Transport Water.............................................................................8-4

8.2.3 Bottom Ash Transport Water ......................................................................8-4

8.2.4 FGMC Wastewater......................................................................................8-5

8.2.5 Gasification Wastewater..............................................................................8-5

8.2.6 Combustion Residual Leachate from Surface Impoundments and 

Landfills Containing Combustion Residuals...............................................8-5

8.2.7 Non-Chemical Metal Cleaning Wastes.......................................................8-6

8.3 Best Available Technology Economically Achievable ............................................8-6

8.3.1 FGD Wastewater .........................................................................................8-7

8.3.2 Fly Ash Transport Water...........................................................................8-13

8.3.3 Bottom Ash Transport Water ....................................................................8-14

8.3.4 FGMC Wastewater....................................................................................8-16

8.3.5 Gasification Wastewater............................................................................8-16

8.3.6 Combustion Residual Leachate .................................................................8-17

8.3.7 Timing .......................................................................................................8-18

8.3.8 Legacy Wastewater ...................................................................................8-19

8.3.9 Economic Achievability ............................................................................8-20

8.3.10 Non-Water Quality Environmental Impacts, Including Energy 

Requirements.............................................................................................8-21

8.3.11 Impacts on Residential Electricity Prices and Low-Income and 

Minority Populations.................................................................................8-22

8.3.12 Existing Oil-Fired Generating Units and Small Generating Units............8-22

8.3.13 Voluntary Incentives Program...................................................................8-25

8.4 Best Available Demonstrated Control Technology/NSPS .....................................8-28

8.5 PSES .......................................................................................................................8-30
Table of Contents

TABLE OF CONTENTS (Continued)

Page

v

8.6 PSNS.......................................................................................................................8-33

8.7 Anticircumvention Provision..................................................................................8-33

8.8 Other Revisions ......................................................................................................8-35

8.8.1 Correction of Typographical Error for PSNS............................................8-36

8.8.2 Clarification of Applicability ....................................................................8-36

8.9 Non-Chemical Metal Cleaning Waste ....................................................................8-37

8.10 Best Management Practices....................................................................................8-38

8.11 References...............................................................................................................8-38

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 ......................................................................9-5

9.2.4 Combustion Residual Leachate ...................................................................9-6

9.2.5 Gasification Wastewater..............................................................................9-7

9.2.6 Flue Gas Mercury Control Wastewater.......................................................9-7

9.3 Steam Electric Compliance Cost Methodology........................................................9-7

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

9.4.1 Input Data to Technology Cost Modules...................................................9-11

9.4.2 Industry Assumptions/Factors...................................................................9-17

9.4.3 Technology Cost Modules.........................................................................9-18

9.4.4 Model Outputs...........................................................................................9-18

9.5 Costs Applicable to All Wastestreams ...................................................................9-19

9.5.1 Compliance Monitoring Costs...................................................................9-19

9.5.2 Transportation Costs..................................................................................9-20

9.5.3 Disposal Costs...........................................................................................9-21

9.5.4 Impoundment Operation Costs..................................................................9-22

9.6 FGD Wastewater ....................................................................................................9-23

9.6.1 Chemical Precipitation ..............................................................................9-23

9.6.2 Biological Treatment.................................................................................9-26

9.6.3 Evaporation................................................................................................9-31

9.6.4 Estimated Industry-Level Costs for FGD Wastewater by Treatment 

Option........................................................................................................9-32

9.7 Ash Transport Water...............................................................................................9-33

9.7.1 Fly Ash Transport Water...........................................................................9-33

9.7.2 Bottom Ash Transport Water ....................................................................9-37

9.7.3 Estimated Industry-Level Costs for Ash Handling Conversions ..............9-44

9.8 Combustion Residual Landfill Leachate ................................................................9-46

9.9 Gasification Wastewater.........................................................................................9-47

9.10 Summary of National Engineering Costs...............................................................9-48

9.11 Compliance Costs for New Sources.......................................................................9-50

9.12 References...............................................................................................................9-53
Table of Contents

TABLE OF CONTENTS (Continued)

Page

vi

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

10.1 General Methodology for Estimating Pollutant Removals.....................................10-1

10.2 Wastestream Pollutant Characterization and Data Sources....................................10-5

10.2.1 FGD Wastewater Characterization............................................................10-6

10.2.2 Ash Transport Water Characterization....................................................10-19

10.2.3 Baseline and Post-Compliance Combustion Residual Leachate 

Characterization.......................................................................................10-23

10.3 Wastewater Flow Rates for Baseline and Post-Compliance Pollutant 

Loadings ...............................................................................................................10-27

10.3.1 FGD Wastewater Flow Rates for Pollutant Loadings.............................10-27

10.3.2 Ash Transport Water Flow Rates for Pollutant Loadings.......................10-27

10.3.3 Combustion Residual Leachate Flow Rates for Pollutant Loadings.......10-29

10.4 Baseline and Post-Compliance Pollutant Loadings and TWPE Results ..............10-30

10.4.1 FGD Wastewater Loadings and TWPE...................................................10-30

10.4.2 Ash Transport Water Loadings and TWPE.............................................10-33

10.4.3 Combustion Residual Leachate Loadings and TWPE.............................10-38

10.4.4 Pollutant Loadings and Removals for Regulatory Options.....................10-40

10.4.5 Evaluation of Non-Detected Values on Pollutant Loadings....................10-42

10.5 References.............................................................................................................10-43

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

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

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

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

11.1.3 Gasification Wastewater..........................................................................11-11

11.2 Regulated Pollutant Selection Methodology for Indirect Dischargers.................11-14

11.2.1 Methodology for Determining BAT Percent Removals..........................11-14

11.2.2 Methodology for Determining POTW Percent Removals ......................11-15

11.2.3 Results of POTW Pass-Through Analysis ..............................................11-16

11.3 References.............................................................................................................11-18

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

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

12.2 Air Emissions Pollution..........................................................................................12-3

12.3 Solid Waste Generation ..........................................................................................12-8

12.4 Reductions in Water Use ........................................................................................12-9

12.5 References.............................................................................................................12-11

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 ............................13-7

13.2 Data Exclusions And Substitutions ........................................................................13-8

13.2.1 Data Exclusions.........................................................................................13-8
Table of Contents

TABLE OF CONTENTS (Continued)

Page

vii

13.2.2 Data Substitutions......................................................................................13-8

13.3 Data Aggregation..................................................................................................13-10

13.3.1 Aggregation of Field Duplicates .............................................................13-11

13.3.2 Aggregation of Overlapping Samples.....................................................13-12

13.4 Data Editing Criteria.............................................................................................13-12

13.5 Overview Of Limitations......................................................................................13-13

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

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

13.5.3 Compliance with Limitations..................................................................13-15

13.6 Calculation Of The Limitations............................................................................13-17

13.6.1 Calculation of Option Long-Term Average ............................................13-17

13.6.2 Calculation of Option Variability Factors and Limitations.....................13-18

13.6.3 Adjustment for Autocorrelation ..............................................................13-18

13.7 Transfers of the Limitations..................................................................................13-20

13.7.1 Transfer of Arsenic and Mercury Limitations for Chemical 

Precipitation to Combustion Residual Leachate......................................13-20

13.7.2 Transfer of Arsenic and Mercury Limitations for Chemical 

Precipitation to Biological Treatment for FGD Wastewater...................13-21

13.8 Summary of the Limitations.................................................................................13-23

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

Factors for Each Treatment Technology Option for FGD and 

Gasification Wastewaters........................................................................13-23

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

Factors, and Limitations for Each Treatment Technology Option for 

FGD, Gasification, and Combustion Residual Leachate Wastewaters ...13-27

13.8.3 Long-Term Averages and Effluent Limitations for FGD Wastewater, 

Gasification Wastewater, and Combustion Residual Leachate...............13-30

13.9 Engineering Review Of The Limitations..............................................................13-31

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

Limitations...............................................................................................13-33

13.9.2 Comparison of Final Limitations to Influent Data ..................................13-43

13.10 References.............................................................................................................13-44

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

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

14.1.1 Requirements.............................................................................................14-1

14.1.2 Timing .......................................................................................................14-9

14.1.3 Applicability of 1982 NSPS/PSNS .........................................................14-12

14.1.4 Legacy Wastewater .................................................................................14-12

14.1.5 Combined Wastestreams.........................................................................14-12

14.1.6 Implementation Examples.......................................................................14-14

14.1.7 Monitoring Requirements........................................................................14-29

14.1.8 Analytical Methods .................................................................................14-29

14.1.9 Non-Chemical Metal Cleaning Wastes...................................................14-30
Table of Contents

TABLE OF CONTENTS (Continued)

Page

viii

14.2 Upset and Bypass Provisions................................................................................14-30

14.3 Variances and Modifications................................................................................14-31

14.3.1 Fundamentally Different Factors Variances............................................14-31

14.3.2 Economic Variances................................................................................14-33

14.3.3 Water Quality Variances .........................................................................14-33

14.3.4 Net Credits...............................................................................................14-33

14.3.5 Removal Credits......................................................................................14-34

14.4 Site-Specific Water Quality-Based Effluent Limitations.....................................14-35

14.5 References.............................................................................................................14-38

APPENDIX A – SURVEY DESIGN AND CALCULATION OF NATIONAL ESTIMATES

APPENDIX B – MODIFIED DELTA-LOG NORMAL DISTRIBUTION
List of Tables

ix

List of Tables

Page

Table 3-1. Number of Plants in Each Fuel Classification in the Survey Sample Frame 

Used to Identify Survey Recipients ................................................................................. 3-4

Table 3-2. List of Site Visits Conducted During the Detailed Study and Rulemaking ............... 3-6

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

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

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

Table 3-5. Reports and Studies Submitted to EPA from EPRI.................................................. 3-23

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

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

Power Generating ELGs................................................................................................ 4-14

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

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

the Steam Electric Power Generating ELGs.................................................................. 4-18

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

the Steam Electric Power Generating ELGs.................................................................. 4-18

Table 4-6. Fly Ash Collection Practices in the Steam Electric Power Generating Industry 

in 2009 ........................................................................................................................... 4-19

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

Table 4-8. Conversions of Wet Fly Ash Sluicing Systems Between 2000 and 2009................ 4-23

Table 4-9. Bottom Ash Handling Practices in the Steam Electric Power Generating 

Industry .......................................................................................................................... 4-25

Table 4-10. Conversions of Bottom Ash Sluicing Systems Between 2000 and 2009............... 4-27

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

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

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

Table 4-13. Age of Impoundment or Landfill Collecting Combustion Residual Leachate....... 4-36

Table 4-14. Destination of Combustion Residual Leachate in Steam Electric Power 

Generating Industry ....................................................................................................... 4-37

Table 4-15. Carbon Capture Wastewater 4-Day Average Concentration Data ......................... 4-41

Table 4-16. Number of Plants Removed from ELG Compliance Costs and Pollutant 

Loadings Estimates Due to Updates to the Industry Profile .......................................... 4-44

Table 4-17. Number of Plants Removed from ELG Compliance Costs and Pollutant 

Loadings Estimates Due to Implementation of the CCR Rule ..................................... 4-45
List of Tables

List of Tables (Continued)

Page

x

Table 4-18. Number of Plants Removed from ELG Compliance Costs Due to 

Implementation of the CPP............................................................................................ 4-45

Table 6-1. FGD Slurry Blowdown Flow Rates for the Steam Electric Power Generating 

Industry in 2009 ............................................................................................................... 6-2

Table 6-2. FGD Wastewater Discharges for the Steam Electric Power Generating 

Industry in 2009 ............................................................................................................... 6-5

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

Table 6-4. Fly Ash Transport Water Flow Rates for the Steam Electric Power Generating 

Industry in 2009 ............................................................................................................... 6-8

Table 6-5. Bottom Ash Transport Water Flow Rates for the Steam Electric Power 

Generating Industry in 2009 ............................................................................................ 6-9

Table 6-6. Ash Wastewater Discharge for the Steam Electric Power Generating Industry 

in 2009 ........................................................................................................................... 6-10

Table 6-7. Combustion Residual Leachate Flow Rates for the Steam Electric Power 

Generating Industry in 2009 .......................................................................................... 6-12

Table 6-8. Combustion Residual Leachate Discharged for the Steam Electric Power 

Generating Industry in 2009 .......................................................................................... 6-12

Table 6-9. Average Pollutant Concentrations of Combustion Residual Leachate..................... 6-13

Table 6-10. Mercury Concentrations in Fly Ash With and Without ACI Systems................... 6-15

Table 6-11. Untreated Gasification Wastewater Concentrations............................................... 6-16

Table 6-12. Pollutants of Concern – FGD Wastewater ............................................................. 6-19

Table 6-13. Pollutants of Concern – Combustion Residual Leachate ....................................... 6-21

Table 6-14. Pollutants of Concern – Gasification Wastewater.................................................. 6-22

Table 6-15. Pollutants of Concern – Fly Ash Transport Water................................................. 6-24

Table 6-16. Pollutants of Concern – Bottom Ash Transport Water .......................................... 6-25

Table 6-17. Pollutants of Concern – FGMC Wastewater.......................................................... 6-27

Table 8-1. Steam Electric Power Generating Point Source Category Regulatory Options......... 8-3

Table 8-2. Summary of Pass-Through Analysis........................................................................ 8-31

Table 9-1. Technology Costs Modules Used to Estimate Compliance Costs............................ 9-10

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

Regulatory Option.......................................................................................................... 9-12

Table 9-3. Number of Plants Expected to Incur Compliance Costs by Wastestream and 

Regulatory Option, Accounting for CPP ....................................................................... 9-12

Table 9-4. ELG Baseline Changes Accounting for CCR Rule.................................................. 9-16
List of Tables

List of Tables (Continued)

Page

xi

Table 9-5. Estimated Industry-Level Costs for FGD Wastewater Based on Oil-Fired Units 

and Units 50 MW or Less Not Installing Technology Basis......................................... 9-32

Table 9-6. Estimated Industry-Level Costs for FGD Wastewater Based on Oil-Fired Units 

and Units 50 MW or Less Not Installing Technology Basis, Accounting for CPP....... 9-33

Table 9-7. Estimated Industry-Level Costs for Fly Ash Handling Conversions Based on 

Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis................ 9-44

Table 9-8. Estimated Industry-Level Costs for Fly Ash Handling Conversions Based on 

Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis, 

Accounting for CPP ....................................................................................................... 9-44

Table 9-9. Estimated Industry-Level Costs for Bottom Ash Handling Conversions Based 

on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis........... 9-45

Table 9-10. Estimated Industry-Level Costs for Bottom Ash Handling Conversions Based 

on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis, 

Accounting for CPP ....................................................................................................... 9-45

Table 9-11. Estimated Industry-Level Costs for Bottom Ash Handling Conversions Based 

on Oil-Fired Units and Units Less than 400 MW Not Installing Technology Basis..... 9-45

Table 9-12. Estimated Industry-Level Costs for Bottom Ash Handling Conversions Based 

on Oil-Fired Units and Units Less than 400 MW Not Installing Technology Basis, 

Accounting for CPP ....................................................................................................... 9-46

Table 9-13. Estimated Industry-Level Costs for the Chemical Precipitation Technology 

Option for Combustion Residual Leachate Based on Oil-Fired Units and Units 50 

MW or Less Not Installing Technology Basis............................................................... 9-46

Table 9-14. Estimated Industry-Level Costs for the Chemical Precipitation Technology 

Option for Combustion Residual Leachate Based on Oil-Fired Units and Units 50 

MW or Less Not Installing Technology Basis, Accounting for CPP ............................ 9-47

Table 9-15. Estimated Industry-Level Costs for Gasification Wastewater ............................... 9-47

Table 9-16. Estimated Industry-Level Costs for Gasification Wastewater, Accounting for

CPP ................................................................................................................................ 9-47

Table 9-17. Technology Options and Other Costs Included in the Estimated Compliance 

Costs for Each Regulatory Option ................................................................................. 9-48

Table 9-18. Cost of Implementation by Regulatory Option [In millions of pre-tax 

2010 dollars] .................................................................................................................. 9-49

Table 9-19. Cost of Implementation by Regulatory Option [In millions of pre-tax 

2010 dollars] Accounting for CPP................................................................................. 9-49

Table 9-20. NSPS Compliance Cost Scenarios Evaluated for the Rule .................................... 9-51

Table 9-21. Estimated Industry-Level NSPS Costs................................................................... 9-52

Table 10-1. POTW Removals.................................................................................................... 10-4
List of Tables

List of Tables (Continued)

Page

xii

Table 10-2. Data Sets Used in the FGD Loadings Calculation ................................................. 10-7

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

Table 10-4. Average Effluent Pollutant Concentrations for Chemical Precipitation System.. 10-13

Table 10-5. Average Effluent Pollutant Concentrations for Chemical Precipitation System 

with Biological Treatment ........................................................................................... 10-16

Table 10-6. Average Effluent Pollutant Concentrations for Chemical Precipitation System 

with Evaporation.......................................................................................................... 10-18

Table 10-7. Average Effluent Pollutant Concentration for Ash Impoundment Systems ........ 10-22

Table 10-8. Average Effluent Pollutant Concentrations for Chemical Precipitation System 

for the Treatment of Combustion Residual Leachate .................................................. 10-24

Table 10-9. Average Effluent Pollutant Concentrations for Biological Treatment of 

Combustion Residual Leachate.................................................................................... 10-26

Table 10-10. 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......................................................................................................... 10-32

Table 10-11. 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, Accounting for CPP ...................................................................... 10-32

Table 10-12. FGD Wastewater Pollutant Removals Excluding BOD, COD, TDS, and 

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

Technology Basis......................................................................................................... 10-32

Table 10-13. FGD Wastewater Pollutant Removals Excluding BOD, COD, TDS, and 

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

Technology Basis, Accounting for CPP ...................................................................... 10-33

Table 10-14. Industry-Level Baseline Ash Impoundment Loadings by Type of 

Impoundment Excluding BOD, COD, TDS, and TSS................................................. 10-34

Table 10-15. Industry-Level Baseline Ash Impoundment Loadings by Type of 

Impoundment Excluding BOD, COD, TDS, and TSS, Accounting for CPP .............. 10-35

Table 10-16. Estimated Ash Impoundment Pollutant Removals by Regulatory Option 

Excluding BOD, COD, TDS, and TSS........................................................................ 10-37

Table 10-17. Estimated Ash Impoundment Pollutant Removals by Regulatory Option 

Excluding BOD, COD, TDS, and TSS, Accounting for CPP...................................... 10-37

Table 10-18. Industry-Level Combustion Residual Leachate Loadings Excluding BOD, 

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

Installing Technology Basis......................................................................................... 10-39
List of Tables

List of Tables (Continued)

Page

xiii

Table 10-19. Industry-Level Combustion Residual Leachate Loadings Excluding BOD, 

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

Installing Technology Basis, Accounting for CPP ...................................................... 10-39

Table 10-20. Combustion Residual Leachate Pollutant Removals Excluding BOD, COD, 

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

Installing Technology Basis......................................................................................... 10-39

Table 10-21. Combustion Residual Leachate Pollutant Removals Excluding BOD, COD, 

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

Installing Technology Basis, Accounting for CPP ...................................................... 10-40

Table 10-22. Estimated Pollutant Loadings and Removals by Regulatory Option ................. 10-41

Table 10-23. Estimated Pollutant Loadings and Removals by Regulatory Option, 

Accounting for CPP ..................................................................................................... 10-41

Table 10-24. Pollutant Removals – Method 1 Not Excluding High ND................................. 10-43

Table 10-25. Pollutant Removals – Method 2 Excluding High ND........................................ 10-43

Table 11-1. POCs Considered for Regulation for Direct Dischargers (BAT): FGD 

Wastewater..................................................................................................................... 11-4

Table 11-2. POCs Considered for Regulation for Direct Dischargers (NSPS): FGD 

Wastewater..................................................................................................................... 11-6

Table 11-3. Pollutants Considered for Regulation for Direct Dischargers (NSPS): 

Combustion Residual Leachate...................................................................................... 11-9

Table 11-4. Pollutants Considered for Regulation for Direct Dischargers (BAT/NSPS): 

Gasification Wastewater.............................................................................................. 11-12

Table 11-5. POTW Pass-Through Analysis (FGD Wastewater) – PSES................................ 11-17

Table 11-6. POTW Pass-Through Analysis (FGD Wastewater) – PSNS ............................... 11-17

Table 11-7. POTW Pass-Through Analysis (Combustion Residual Leachate) – PSNS ......... 11-18

Table 11-8. POTW Pass-Through Analysis (Gasification Wastewater) – PSES/PSNS.......... 11-18

Table 12-1. Industry-Level Energy Requirements by Regulatory Option................................. 12-3

Table 12-2. Industry-Level Energy Requirements by Regulatory Option, Accounting for 

CPP ................................................................................................................................ 12-3

Table 12-3. MOBILE6.2 and California Climate Action Registry 

Transportation Emission Rates...................................................................................... 12-5

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

Transportation by Regulatory Option ............................................................................ 12-6

Table 12-5. Industry-Level Air Emissions Associated with Auxiliary Electricity and 

Transportation by Regulatory Option, Accounting for CPP.......................................... 12-6

Table 12-6. Industry-Level Net Air Emissions for Regulatory Options B and D ..................... 12-7
List of Tables

List of Tables (Continued)

Page

xiv

Table 12-7. Industry-Level Net Air Emissions for Regulatory Options B and D, 

Accounting for CPP ....................................................................................................... 12-7

Table 12-8. Electric Power Industry Air Emissions.................................................................. 12-8

Table 12-9. Electric Power Industry Air Emissions, Accounting for CPP................................ 12-8

Table 12-10. Industry-Level Solid Waste Increases by Regulatory Option .............................. 12-9

Table 12-11. Industry-Level Solid Waste Increases by Regulatory Option, Accounting for 

CPP ................................................................................................................................ 12-9

Table 12-12. Industry-Level Process Water Reduction by Regulatory Option....................... 12-10

Table 12-13. Industry-Level Process Water Reduction by Regulatory Option, Accounting 

for CPP......................................................................................................................... 12-10

Table 12-14. Estimated Wastewater Discharges at Steam Electric Power Plants................... 12-10

Table 13-1. Aggregation of Field Duplicates .......................................................................... 13-11

Table 13-2. Summary of Autocorrelation Values Used in Calculating the Limitations for 

Biological Treatment Technology Option for FGD Wastewater................................. 13-19

Table 13-3. Plant-Specific Results for the Chemical Precipitation Technology Option for 

FGD Wastewater.......................................................................................................... 13-24

Table 13-4. Plant-Specific Results for the Biological Treatment Technology Option for 

FGD Wastewater.......................................................................................................... 13-25

Table 13-5. Plant-Specific Results for the Vapor-Compression Evaporation Technology 

Option (Crystallizer Condensate) for FGD Wastewater.............................................. 13-26

Table 13-6. Plant-Specific Results for the Vapor-Compression Evaporation Technology 

Option (Vapor-Compression Evaporator Condensate) for Gasification Wastewater.. 13-27

Table 13-7. Option-Level Long-Term Averages, Variability Factors, and Limitations for 

Each of the FGD, Gasification, and Combustion Residual Leachate Technology 

Options with or without baseline Adjustment ............................................................. 13-28

Table 13-8. Long-Term Averages and Effluent Limitations and Standards for FGD 

Wastewater and Gasification Wastewater for Existing Sources.................................. 13-30

Table 13-9. Long-Term Averages and Standards for FGD Wastewater, Gasification 

Wastewater, and Combustion Residual Leachate for New Sources............................ 13-30

Table 14-1. BPT/BAT Limitations for Existing Units > 50 MW and Not Oil-Fired Units; 

Not Also Subject to 1982 NSPS .................................................................................... 14-2

Table 14-2. BAT/NSPS Limitations for Existing Units > 50 MW and Not Oil-Fired 

Units; Also Subject to 1982 NSPSa ............................................................................... 14-3

Table 14-3. BPT/BAT Limitations for Existing Units (< or Equal To 50 MW or Oil-Fired 

Units); Not Also Subject to 1982 NSPS ........................................................................ 14-5
List of Tables

List of Tables (Continued)

Page

xv

Table 14-4. BAT/NSPS Limitations for Existing Units (< or Equal To 50 MW or OilFired Units); Also Subject to 1982 NSPSa

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

Table 14-5. 2015 NSPS Limitations for New Sources.............................................................. 14-7

Table 14-6. PSES for Existing Units > 50 MW and Not Oil-Fired Units; Not Also Subject 

to 1982 PSNS................................................................................................................. 14-8

Table 14-7. PSES for Existing Units >50 MW and Not Oil-Fired Units; Also Subject to 

1982 PSNS..................................................................................................................... 14-8

Table 14-8. 2015 PSNS for New Sources.................................................................................. 14-9

Table 14-9. Combined Monthly BAT Limitations Using Building Block Approach ............. 14-26

Table 14-10. Combined Monthly BAT Limitations Using Building Block Approach ........... 14-28
List of Figures

xvi

List of Figures

Page

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

Figure 4-2. Steam Electric Power Generating Process Flow Diagram........................................ 4-9

Figure 4-3. Combined Cycle Process Flow Diagram ................................................................ 4-10

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

Figure 4-5. Plant-Level Fly Ash Handling Systemsin the Steam Electric Power 

Generating Industry in 2009 .......................................................................................... 4-22

Figure 4-6. Plant-Level Bottom Ash Handling Systems in the Steam Electric Industry........... 4-26

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

Figure 4-8. Plants Operating Wet FGD Scrubber SystemsPower Generating in 2009 ............ 4-32

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

Figure 4-10. Diagram of Landfill Combustion Residual Leachate Generation and 

Collection....................................................................................................................... 4-35

Figure 7-1. Distribution of FGD Wastewater Treatment/Management Systems 

Among 139 Plants Generating FGD Wastewater in the EPA Population ....................... 7-3

Figure 7-2. Process Flow Diagram for a Hydroxide and Organosulfide Chemical 

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

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

System............................................................................................................................ 7-11

Figure 7-4. Chemical Precipitation and Softening Pretreatment for FGD 

Wastewater Prior to Evaporation................................................................................... 7-14

Figure 7-5. Process Flow Diagram for an Evaporation System................................................. 7-16

Figure 7-6. Distribution of Fly Ash Handling Systems for Coal-, Petroleum Cokeand Oil-Fired Generating Units Reported in the Steam Electric Power Generating

Industry .......................................................................................................................... 7-27

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

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

the Steam Electric Survey.............................................................................................. 7-28

Figure 7-8. JEA Northside Dense Slurry System Material Flow Diagram................................ 7-30

Figure 7-9. Schematic of Dry Vacuum, Pressure, and Combined Vacuum/Pressure 

System............................................................................................................................ 7-33

Figure 7-10. Pressure System Airlock Valve............................................................................. 7-34

Figure 7-11. Distribution of Bottom Ash Handling Systems for Coal-, Petroleum 

Coke-, and Oil-Fired Units Reported in the Steam Electric Survey.............................. 7-38
List of Figures

List of Figures (Continued)

Page

xvii

Figure 7-12. Distribution of Bottom Ash Handling System Types Other Than Wet 

Sluicing for Coal-, Petroleum Coke-, and Oil-Fired Generating Units Reported in 

the Steam Electric Survey.............................................................................................. 7-39

Figure 7-13. Bottom Ash Dewatering Bin System.................................................................... 7-40

Figure 7-14. Mechanical Drag System ...................................................................................... 7-42

Figure 7-15. Remote Mechanical Drag System......................................................................... 7-43

Figure 7-16. Water Flow Inside the Remote Mechanical Drag System Trough ....................... 7-44

Figure 7-17. Dry Vacuum or Pressure Bottom Ash Handling System...................................... 7-46

Figure 7-18. Vibratory Bottom Ash Handling System.............................................................. 7-47

Figure 7-19. Distribution of Treatment Systems for Leachate from Landfills 

and Impoundments Containing Combustion Residual Wastes...................................... 7-49

Figure 8-1. Regulatory Option D Annualized Cost Per MW Compared to Unit Capacity 

(MW).............................................................................................................................. 8-25

Figure 14-1. Legacy FGD Wastewater Treatment Scenario.................................................... 14-16

Figure 14-2. Legacy Fly Ash Transport Water and FGMC Wastewater Treatment 

Scenario........................................................................................................................ 14-17

Figure 14-3. Complete Recycle Fly Ash Transport Water Treatment Scenario...................... 14-18

Figure 14-4. Partial Recycle Bottom Ash Transport Water Treatment Scenario .................... 14-19

Figure 14-5. Gasification Wastewater Treatment Scenario..................................................... 14-21

Figure 14-6. Legacy Combustion Residual Leachate Scenario............................................... 14-23

Figure 14-7. Implementation of Size Threshold...................................................................... 14-25

Figure 14-8. Building Block Approach; FGD Wastewater with Cooling Water..................... 14-27

Figure 14-9. Building Block Approach; FGD Wastewater with Combustion Residual 

Leachate ....................................................................................................................... 14-28
Glossary

xviii

GLOSSARY

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

Agency – U.S. Environmental Protection Agency.

BAT – Best available technology economically achievable, as defined by CWA Sections 

301(b)(2)(A) and 304(b)(2)(B).

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

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

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

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

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

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

uptake from all routes of exposure.

BMP – Best management practice.

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

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

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

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

CBI – Confidential Business Information.

CCR – Coal Combustion Residuals.

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

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

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

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

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

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

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

associated with the combustion of other fossil fuels.

Combustion residual leachate – Leachate from landfills or surface impoundments containing 

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

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

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

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

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

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

operational control of the permitted facility.
Glossary

xix

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

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

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

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

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

collected or channeled by man; discharges though pipes, sewers, or other conveyances owned by 

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

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

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

A facility that discharges treated or untreated wastewaters into waters of the U.S.

DOE – Department of Energy.

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

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

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

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

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

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

convey fly ash away from particulate collection equipment. 

Effluent limitation – Under CWA section 502(11), any restriction, including schedules of 

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

chemical, physical, biological, and other constituents which are discharged from point sources 

into navigable waters, the waters of the contiguous zone, or the ocean, including schedules of 

compliance.

EIA – Energy Information Administration.

ELGs – Effluent limitations guidelines and standards.

EO – Executive Order.

EPA – U.S. Environmental Protection Agency.

ESP – Electrostatic precipitator.

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

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

FGD – Flue gas desulfurization.

FGD wastewater – Wastewater generated specifically from the wet flue gas desulfurization 

scrubber system that comes into contact with the flue gas or the FGD solids, including but not 

limited to, the blowdown or purge from the FGD scrubber system, overflow or underflow from 

the solids separation process, FGD solids wash water, and the filtrate from the solids dewatering 

process. Wastewater generated from cleaning the FGD scrubber, cleaning FGD solids separation 
Glossary

xx

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

FGD process area is not considered FGD wastewater.

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

any solids separation or solids dewatering processes.

FGMC – Flue gas mercury control.

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

removing mercury from flue gas. 

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

operated for the purpose of removing mercury from flue gas. This includes fly ash collection 

systems when the particulate control system follows sorbent injection or other controls to remove 

mercury from flue gas. FGD wastewater generated at plants using oxidizing agents to remove 

mercury in the FGD system and not in a separate FGMC system is not included in this definition.

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

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

Gasification wastewater – Any wastewater generated at an integrated gasification combined 

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

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

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

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

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

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

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

operation of the gasification operation is not considered gasification wastewater. 

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

surface.

IGCC – Integrated gasification combined cycle.

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

IPM – Integrated Planning Model.

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

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

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

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

action management unit.
Glossary

xxi

Low volume waste sources – 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 wet scrubber air pollution control systems whose 

primary purpose is particulate removal. Sanitary wastes, air conditioning wastes, and wastewater

from carbon capture or sequestration systems are not included in this definition.

MDS – Mechanical drag system.

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

of the boiler in a water-filled trough. The water bath in the trough quenches the hot bottom ash as 

it falls from the boiler and seals the boiler gases. A drag chain operates in a continuous loop to 

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

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

ash is often conveyed to a nearby collection area, such as a small bunker outside the boiler 

building, from which it is loaded onto trucks and either sold or transported to a landfill. The 

MDS is considered a dry bottom ash handling system because the ash transport mechanism is 

mechanical removal by the drag chain, not the water.

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

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

cleaning, boiler fireside cleaning, and air preheater cleaning.

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

NAICS – North American Industry Classification System. 

NPDES – National Pollutant Discharge Elimination System.

NSPS – New Source Performance Standards.

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

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

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

ORCR – Office of Resource Conservation and Recovery.

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

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

concentrated animal feeding operation, or vessel or other floating craft from which pollutants are 

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

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

122.2.

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

122.2, 403.3
Glossary

xxii

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

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

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

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

collection system.

PSES – Pretreatment Standards for Existing Sources.

PSNS – Pretreatment Standards for New Sources.

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

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

wastes of a liquid nature that is owned by a state or municipality. This includes sewers, pipes, or 

other conveyances only if they convey wastewater to a POTW providing treatment. See CWA 

section 212, 33 U.S.C. 1292; 40 CFR §§ 122.2, 403.3.

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

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

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

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

system because the ash transport mechanism is water.

RFA – Regulatory Flexibility Act.

SBA – Small Business Administration.

Sediment – Particulate matter lying below water.

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

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

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

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

residuals.

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

seas.

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

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

CFR 423.

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

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

ash. Transport water does not include low volume, short duration discharges of wastewater from 

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

(e.g., replacement of valves or pipe sections).UMRA – Unfunded Mandates Reform Act.
Glossary

xxiii

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

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

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

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

transport water (remote MDS or complete recycle system).

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

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

FGD scrubber absorber.

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

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

slurry in a surface impoundment.
Section 1—Background

1-1

SECTION 1

BACKGROUND

This section provides background information on the development of revised effluent 

limitations guidelines and standards (ELGs) 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 final rule. Section 1.3 presents a history of Steam Electric 

Category rulemaking activities.

In addition to this report, there are other reports that support the development of the 

Steam Electric ELGs:

• Environmental Assessment for the Effluent Limitations Guidelines and Standards for 

the Steam Electric Power Generating Point Source Category (EA Report), Document 

No. EPA-821-R-15-006. This report summarizes the environmental and human health 

improvements that result from implementation of the revised ELGs.

• Benefits and Cost Analysis for the Effluent Limitations Guidelines and Standards for 

the Steam Electric Power Generating Point Source Category (BCA), Document No. 

EPA-821-R-15-005. This report summarizes the societal benefits and costs expected 

to result from implementation of the ELGs.

• Regulatory Impact Analysis for the Effluent Limitations Guidelines and Standards for 

the Steam Electric Power Generating Point Source Category (RIA), Document No. 

EPA-821-R-15-004. 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 ELGs’ impact on employment and small businesses.

The ELGs for the Steam Electric 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 developing, 

approving, and implementing Quality Assurance Project Plans for the use of environmental data 

generated or collected from sampling and analyses, existing databases, and literature searches, 

and for developing any models that used environmental data.

1.1 LEGAL AUTHORITY

EPA is finalizing revisions of the ELGs for the Steam Electric Power Generating Point 

Source 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 CWA to "restore and maintain the chemical, physical, and biological 

integrity of the Nation's waters." 33 U.S.C. 1251(a). In order to achieve this objective, the Act 

has, as a national goal, the elimination of the discharge of all pollutants into the nation’s waters. 

33 U.S.C. 1251(a)(1). The CWA establishes a comprehensive program for protecting our 
Section 1—Background

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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, 33 U.S.C. 1342, discharges may be authorized through a National Pollutant Discharge 

Elimination System (NPDES) permit. The CWA establishes a dual approach for these permits, 

technology-based controls that establish a floor of performance for all dischargers, and water 

quality-based effluent limitations, where the technology-based effluent limitations are 

insufficient to meet applicable water quality standards (WQS). To serve as the basis for the 

technology-based controls, the CWA authorizes EPA to establish national technology-based 

effluent limitations guidelines and new source performance standards for discharges from 

categories of point sources (such as industrial, commercial, and public sources) that occur 

directly into waters of the U.S.

The CWA also authorizes EPA to promulgate nationally applicable pretreatment 

standards that control pollutant discharges from sources that discharge wastewater indirectly to 

waters of the U.S., through sewers flowing to POTWs, as outlined in sections 307(b) and (c) of 

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

pollutants in wastewater from indirect dischargers that 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 (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 and standards 

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 limitation guideline or new source performance standard 

(CWA section 402(a)(1)(B), 33 U.S.C. 1342(a)(1)(B)). Additional limitations are also required in 

the permit where necessary to meet WQS. CWA section 301(b)(1)(C), 33 U.S.C. 1311(b)(1)(C). 

The ELGs are established by EPA 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, as specified in the Act (e.g., BPT, BCT, BAT; see below).

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

pollutants: (1) conventional pollutants (TSS, oil and grease, 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 

CWA section 307(a), 33 U.S.C. 1317(a); 40 CFR § 401.15 and 40 CFR part 423 appendix A; and 

(3) nonconventional pollutants, which are those pollutants that are not categorized as 

conventional or toxic (e.g., ammonia-N, phosphorus, and TDS).

EPA establishes ELGs based on the performance of well-designed and well-operated 

control and treatment technologies. The legislative history of CWA section 304(b), which is the 
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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 plants 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 

(principal author) (October 4, 1972), reprinted in Legislative 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, and two types of 

standards applicable to indirect dischargers, described in detail below.

1.2.1 Best Practicable Control Technology Currently Available (BPT)

Traditionally, EPA establishes effluent limitations based on BPT by reference to the 

average of the best performances of facilities within the industry, grouped to reflect various ages, 

sizes, processes, or other common characteristics. EPA can promulgate BPT effluent limitations 

for conventional, toxic, and nonconventional 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), 33 U.S.C. 

1314(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 require EPA to identify additional levels of effluent 

reduction for conventional pollutants associated with BCT for discharges from existing industrial 

point sources. In addition to other factors specified in section 304(b)(4)(B), 33 U.S.C. 

1314(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 on 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 oil and grease as a 

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 discharges of toxic 

and nonconventional pollutants. 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 
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facilities involved, the process employed, potential process changes, non-water quality 

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

Administrator deems appropriate. The Agency retains considerable discretion in 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 (if applicable) financial 

conditions. BAT is intended to reflect the highest performance in the industry, and it 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 studies, or foreign plants. Am. 

Paper Inst. v. Train, 543 F.2d 328, 353 (D.C. Cir. 1976); Am. 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 Am. Frozen Food Inst., 539 

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

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

1.2.4 Best Available Demonstrated Control Technology (BADCT)/New Source 

Performance Standards (NSPS)

NSPS reflect “the greatest degree of effluent reduction” that is achievable based on the 

“best available demonstrated control technology” (BADCT), “including, where practicable, a 

standard permitting no discharge of pollutants.” CWA section 306(a)(1), 33 U.S.C. 1316(a)(1). 

Owners of new facilities have the opportunity to install the best and most efficient production 

processes and wastewater treatment technologies. As a result, NSPS generally represent the most 

stringent controls attainable through the application of BADCT for all pollutants (that is, 

conventional, nonconventional, 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) of the CWA, 33 U.S.C. 1317(b), authorizes EPA to promulgate 

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. Congress 

intended for the combination of pretreatment and treatment by the POTW to achieve the level of

treatment that would be required if the industrial source were making a direct discharge. Conf. 

Rep. No. 95-830, at 87 (1977), reprinted in U.S. Congress. Senate Committee on Public Works 

(1978), A Legislative History of the CWA of 1977, Serial No. 95-14 at 271 (1978). 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).
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1.2.6 Pretreatment Standards for New Sources (PSNS)

Section 307(c) of the CWA, 33 U.S.C. 1317(c), authorizes EPA to promulgate PSNS at 

the same time it promulgates NSPS. As is the case for PSES, PSNS are designed to prevent the 

discharge of any pollutant into a POTW that interferes with, passes through, or is otherwise 

incompatible with the POTW. In selecting the PSNS technology basis, the Agency generally 

considers the same factors it considers in establishing NSPS, along with the results of a passthrough analysis. Like new sources of direct discharges, new sources of indirect discharges have 

the opportunity to incorporate into their operations the best available demonstrated technologies.

As a result, EPA typically promulgates pretreatment standards for new sources based on best 

available demonstrated control technology for new sources. See Nat’l Ass’n of Metal Finishers 

v. EPA, 719 F.2d 624, 634 (3rd Cir. 1983).

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 Discharge Requirements Established in Prior Rulemakings

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

in 1977 and 1982. These previously established ELGs applied to a subset of the electric power 

industry, namely those plants “primarily engaged in the generation of electricity...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.” The 

previously established ELGs did not apply to discharges from generating units that primarily use 

a non-fossil or non-nuclear fuel source (e.g., wood waste, municipal solid waste) to power the 

steam electric generators, nor did they apply to generating units operated by establishments that 

are not primarily engaged in generating electricity for distribution and sale.

The Steam Electric ELGs are codified at 40 CFR 423 and these prior rulemakings 

established requirements for the following wastestreams:

• Once-through cooling water.

• Cooling tower blowdown.

• Fly ash transport water.

• Bottom ash transport water.

• Metal cleaning wastes, including chemical metal cleaning wastes.

• Coal pile runoff.

• Low-volume waste sources [40 CFR 423.11(b)].

As described in Section 1.3.2, the previously established ELGs for the steam electric 

power generating industry, which EPA last updated in 1982, do not adequately address the toxic 
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1-6

pollutants discharged from this industry sector, nor have they kept pace with process changes 

that have occurred 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), and 

flue gas mercury controls (FGMC)) have altered existing wastestreams and/or created new 

sources of wastewater at many power plants, particularly coal-fired plants. 

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 ELGs 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 reviewing and revising

promulgated national effluent guidelines required by CWA section 304(b). 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 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 nonmetallic elements, such as selenium, present in wastewater 

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

with ash transport and wet FGD systems. EPA also identified several wastestreams that are 

relatively new to the industry (e.g., carbon capture wastewater) and wastestreams for which there 

are 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 increased significantly since the last revision of the effluent guidelines in 1982 

and its use was projected to continue increasing as steam electric power plants took 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 

using 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 ash 

transport water. EPA found that fly ash and bottom ash transport waters are generated in large 

quantities from wet systems at coal-fired power plants and contain significant concentrations of 

metals, including arsenic and mercury. Additionally, EPA determined that some of the metals are 
Section 1—Background

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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.

Finally, EPA determined that FGD wastewater and ash transport waters 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 and 

impoundments containing coal combustion residuals (CCR). EPA determined that there are a 

number of pollutants present in wastewaters generated at coal-fired power plants that can affect 

the environment, including metals and nonmetallic elements (e.g., arsenic, selenium, mercury), 

TDS, and nutrients. EPA found that wastewaters generated at coal-fired power plants have 

caused a wide range of harm to aquatic life.

Overall, EPA found from the detailed study 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, FGMC wastewater, carbon capture wastewater, and gasification wastewater. EPA 

also found that these wastestreams, as well as other wastewaters generated at coal-fired power 

plants (e.g., fly ash and bottom ash transport water, combustion residual 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 from these wastewaters.

After 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, in September 2009, to announce plans to revise the effluent 

guidelines.

1.3.3 Other Statutes and Regulatory Requirements Affecting Management of Steam 

Electric Power Generating Wastewaters

EPA recognizes that this rule does not exist in isolation. 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 that may affect the generation 

and composition of wastewater discharged from steam electric power plants. For example, since 

proposal, EPA has promulgated the Cooling Water Intake Structures rule (79 FR 48300) for 

existing facilities, the Coal Combustion Residuals rule (80 FR 21302), the Clean Power Plan 

(signed on August 3, 2015), and the Carbon Pollution Standard for New Power Plants (signed on 

August 3, 2015). EPA made every effort to appropriately account for these other rules in its 

many analyses for this rule. In some cases, EPA performed two sets of parallel analyses to 

demonstrate how the other rules affect this final rule. This section provides a brief overview of 

these statutes and the regulatory requirements associated with steam electric power plants.
Section 1—Background

1-8

1. Mercury and Air Toxics Standards (MATS)

When the Clean Air Act (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 hazards to public health reasonably anticipated to occur as a result of the emissions 

of hazardous air pollutants from electric steam generating units (CAA Section 

112(n)(1)(A)). The CAA amendments also required and the Administrator to make a 

finding as to whether regulation was appropriate and necessary after considering the 

results of the study. In 2000, the Administrator found and reaffirmed in December of 

2011 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)).

EPA published the reaffirmation and 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 wet and dry scrubbers, dry sorbent injection systems, activated carbon 

injection systems, and fabric filters. Sources have up to three years to come into 

compliance and permitting agencies – usually the state agency – can give a source an 

additional year if it is needed. Many sources, therefore are already in compliance 

with MATS and all must be in compliance by April 15, 2016. In Michigan v. EPA, 

the Supreme Court reversed on narrow grounds a portion of the D.C. Circuit decision 

upholding the MATS rule, finding that EPA erred by not considering cost when 

determining that regulation of EGUs was "appropriate" pursuant to CAA section 

112(n)(1). 135 S.Ct. 192 (2015). The case was remanded to the D.C. Circuit for 

further proceedings, and the MATS rule currently remains in place. EPA has 

requested that the D.C. Circuit remand MATS without vacatur. Given the existing 

record demonstrating that EPA considered cost throughout the MATS rulemaking, 

the Agency believes it can meet an ambitious schedule on remand and intends to 

finalize our analysis of cost for the appropriate and necessary finding as close to April 

15, 2016 as possible. If EPA reaffirms that finding on remand, there is no reason for 

EPA to revisit any other portions of the Rule. In the meantime, consistent with the 

Rule’s April 16, 2015 compliance date, the many units already in compliance 

represent half of the domestic coal capacity, and many of those that received a oneyear extension will have already made significant investments or entered into 

contractual commitments in order to meet the extended deadline. Since the final 

MATS rule remains in effect and many sources are already in compliance, MATS is 

included in the analytical baseline for this final rule.

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 react in the 
Section 1—Background

1-9

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. 

On April 29, 2014, the U.S. Supreme Court issued an opinion reversing the August 

21, 2012, D.C. Circuit decision that had vacated CSAPR. Following the remand of 

the case to the D.C. Circuit, EPA requested that the court lift the CSAPR stay and 

extend the CSAPR compliance deadlines by 3 years. On October 23, 2014, the D.C. 

Circuit granted EPA's request. Accordingly, CSAPR Phase 1 implementation is now 

scheduled for 2015, with Phase 2 beginning in 2017.

3. Clean Power Plan (CPP)

On August 3, 2015, EPA issued the Clean Power Plan (CPP), which establishes CO2

emission guidelines for existing fossil fuel-fired electric utility generating units

(EGUs). The CPP will achieve significant reductions in CO2 emissions by 2030. The 

final CPP establishes a CO2 emission performance rate for each of two subcategories 

of fossil fuel-fired EGUs – fossil fuel-fired electric steam generating units and natural 

gas combined cycle generating units. The emission performance rates reflect the “best 

system of emission reductions ... adequately demonstrated” for CO2 emissions from 

each EGU subcategory. The rule establishes guidelines for the development, 

submittal and implementation of state plans to implement the CO2 emission 

performance rates. State plans will ensure that the power plants in their state either 

individually, together, or in combination with other measures achieve an interim CO2 

emission performance rate, a rate based goal, or a mass-based goal over the period of 

2022 to 2029, and final CO2 emission performance rate or goal in 2030. Each state 

will have the flexibility to select the measures it prefers in order to achieve the CO2

performance rates for its affected plants or meet the equivalent statewide rate- or 

mass-based goal. States instead may adopt a model rule that EPA proposed on August 

3, 2015. It provides a cost effective pathway for states to adopt a trading system 

supported by EPA. 

States can tailor their plans to meet their respective energy, environmental and 

economic needs and goals, and those of their local communities by relying on a 

diverse set of energy resources. This flexibility helps to protect electric reliability, 

provides affordable electricity, and recognizes the investments that states and power 

companies are already making. States, cities, and businesses across the country are 

already taking action to address the risks of climate change. EPA's final rule builds on 

those actions and is flexible, taking into consideration that different states have a 

different mix of sources and opportunities and reflecting the important role of states 

as full partners with the federal government in cutting pollution. This final rule will 

maintain an affordable, reliable energy system, while cutting pollution and protecting 

our health and environment now and for future generation.
Section 1—Background

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Also on August 3, 2015, EPA proposed a Federal Plan, which EPA would implement 

in any state that does not submit an approvable state plan. The proposal includes two 

different plan types for a federal plan – a rate-based trading plan and a mass-based 

trading plan. Both plan types would require affected EGUs to meet emissions 

standards using the CO2 performance rates in the CPP and would achieve the same 

levels of emissions performance as required of state plans under the CPP.

4. Carbon Pollution Standard for New Power Plants

On August 3, 2015, EPA issued the Carbon Pollution Standards for New, Modified 

and Reconstructed fossil fuel-fired power plants. The final standards apply to newly 

constructed sources built, and to those that may be built in the future and to existing 

units that meets certain specific conditions described in the Clean Air Act and 

implementing regulations, for being “modified” or “reconstructed.” In this final 

action, EPA established separate standards for two types of fossil-fuel fired sources:

stationary combustion turbines and electric utility steam generating units.

These final performance standards reflect the degree of emission limitation 

achievable through the application of the best system of emission reduction that EPA 

has determined has been adequately demonstrated for each type of unit. Because 

these standards are consistent with current industry investment patterns, these

standards are not expected to have notable costs and are not projected to affect 

electricity prices or reliability.

5. 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 CWA sections 301 and 306 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 

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

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

organisms from waters of the United States, 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).

On August 17, 2014 (79 FR 48300), EPA published final standards under the CWA

for all existing power generating facilities and existing manufacturing and industrial 

facilities that withdraw more than 2 million gallons of water per day from waters of 

the United States and use at least 25 percent of that water exclusively for cooling 

purposes. This rule covers roughly 544 power plants. The national requirements, 

which will be implemented through NPDES permits, are applicable to the location, 

design, construction, and capacity of cooling water intake structures at these facilities 

and are based on the best technology available for minimizing environmental impact. 

The rule establishes a baseline level of protection and then allows additional 

safeguards for aquatic life to be developed through site-specific analysis.
Section 1—Background

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6. CCR Final Rule

CCRs are residuals 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. 

On April 17, 2015, EPA finalized national regulations to require the safe disposal of 

CCRs from coal-fired power plants. The final rule is the culmination of extensive 

study on the effects of coal ash on the environment and public health. The rule 

establishes technical requirements for CCR landfills and surface impoundments under 

Subtitle D of the Resource Conservation and Recovery Act (RCRA), the nation's 

primary law for regulating solid waste. 

These regulations address the risks from coal ash disposal – contaminants leaking into 

ground water or blowing into the air as dust, and the catastrophic failure of coal ash 

surface impoundments. Additionally, the rule establishes recordkeeping and reporting 

requirements as well as the requirement for each facility to post specific information 

to a publicly accessible website. This final rule also supports the responsible 

recycling of CCRs by distinguishing safe, beneficial use from disposal.

More specifically, the CCR rule includes groundwater protection requiring the 

owners or operators of a CCR management unit (i.e., landfill or surface 

impoundment) to install monitoring wells and procedures for sampling those wells to 

detect the presence of hazardous constitutes. If contamination is found, the rule 

includes requirements related to corrective action and/or closure. The final rule also 

establishes location restrictions to help ensure that CCR landfills and surface 

impoundments are appropriately sited and liner design criteria for all new landfills, 

new surface impoundments, and lateral expansions. 

The CCR rule also addresses the day-to-day operations of CCR management units 

and includes requirements to prevent public health and environmental impacts from 

these management units. These include air criteria to address pollution caused by 

windblown dust from CCR management units, run-on and run-off controls for 

landfills, controls related to water discharges and the creation of landfill leachate, and 

run-off controls to help protect against releases to surface waters. 

To reduce the risk of catastrophic failure from coal ash surface impoundments, the 

CCR rule includes structural integrity design criteria and requires that owners and 

operators periodically conduct structural integrity-related assessments. Certain 

surface impoundments must develop an emergency action plan that details actions to 

take to protect communities if there is an issue with the structural safety of the 

management unit.
Section 2—Summary of the Final Rule

2-1

SECTION 2

SUMMARY OF THE FINAL RULE

This section presents a brief summary of the final rule. Section 2.1 summarizes the 

discharge requirements and Section 2.2 describes the applicability provision and specialized 

definitions.

2.1 SUMMARY OF DISCHARGE REQUIREMENTS

Steam electric power plants1 discharge large wastewater volumes, containing vast 

quantities of pollutants, into waters of the United States. The pollutants include both toxic and 

bioaccumulative pollutants such as arsenic, mercury, selenium, chromium, and cadmium. Today, 

these discharges account for about 30 percent of all toxic pollutants discharged into surface 

waters by all industrial categories regulated under the CWA.2 The electric power industry has 

made great strides to reduce air pollutant emissions under Clean Air Act programs. Yet many of 

these pollutants are transferred to the wastewater as plants employ technologies to reduce air 

pollution. The pollutants in steam electric power plant wastewater discharges present a serious 

public health concern and cause severe ecological damage, as demonstrated by numerous 

documented impacts, scientific modeling, and other studies. When toxic metals such as mercury, 

arsenic, lead, and selenium accumulate in fish or contaminate drinking water, they can cause

adverse effects in people who consume the fish or water. These effects can include cancer, 

cardiovascular disease, neurological disorders, kidney and liver damage, and lowered IQs in 

children.

There are, however, affordable technologies that are widely available, and already in 

place at some plants, which are capable of reducing or eliminating steam electric power plant 

discharges. In the several decades since the steam electric ELGs were last revised, these 

technologies have increasingly been used at plants. This final rule is the first to ensure that plants 

in the steam electric industry employ technologies designed to reduce discharges of toxic metals 

and other harmful pollutants discharged in the plants’ largest sources of wastewater.

The steam electric ELGs that EPA promulgated and revised in 1974, 1977, and 1982 are 

out of date. They do not adequately control pollutants (toxic metals and other) discharged by this 

industry, nor do they reflect relevant process and technology advances that have occurred in the 

last 30-plus years. The rise of new processes for generating electric power (e.g. coal gasification) 

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

and flue gas mercury controls (FGMC)) have altered existing wastestreams and created new 

types of wastewater at many steam electric power plants, particularly coal-fired plants. The 

 1 Steam electric power plants covered by the ELGs use nuclear or fossil fuels such as coal, oil, and natural gas to 

heat water in boilers, which generate steam. This rule does not apply to plants that use non-fossil fuel or non-nuclear 

fuel or other energy sources, such as biomass or solar thermal energy. The steam is used to drive turbines connected 

to electric generators. The plants generate wastewater composed of chemical pollutants and thermal pollution 

(heated water) from their wastewater treatment, power cycle, ash handling, and air pollution control systems, as well 

as from coal piles, yard and floor drainage, and other plant processes.

2 Although the way electricity is generated in this country is changing, EPA projects that, without this final rule, 

steam electric power plant discharges would likely continue to account, over the foreseeable future, for about thirty 

percent of all toxic pollutants discharged into surface waters by all industrial categories regulated under the CWA.
Section 2—Summary of the Final Rule

2-2

processes employed and pollutants discharged by the industry look very different today than they 

did in 1982. Many plants, nonetheless, still treat their wastewater using only surface 

impoundments, which are largely ineffective at controlling discharges of toxic pollutants and 

nutrients.

To further its ultimate objective to "restore and maintain the chemical, physical, and 

biological integrity of the Nation's waters," the CWA authorizes EPA to establish national 

technology-based effluent limitations guidelines and new source performance standards for 

discharges from categories of point sources that occur directly into waters of the U.S. The CWA 

also authorizes EPA to promulgate nationally applicable pretreatment standards that control 

pollutant discharges from existing and new sources that discharge wastewater indirectly to 

waters of the U.S. through sewers flowing to publicly owned treatment works (POTWs). EPA 

establishes ELGs based on the performance of well-designed and well-operated control and 

treatment technologies. 

EPA completed a study of the steam electric category in 2009 and proposed the ELG rule 

in June 2013. The public comment period extended for more than three months. This final rule 

reflects the statutory factors outlined in the CWA, as well as EPA’s full consideration of the 

comments received and updated analytical results. 

EPA’s final rule revises the steam electric ELGs, as they apply to a subset of power 

plants that discharge wastestreams containing harmful pollutants. EPA is establishing new 

requirements for best available technology economically achievable (BAT), new source 

performance standards (NSPS), pretreatment standards for existing sources (PSES), and 

pretreatment standards for new sources (PSNS) for certain wastestreams, described below, for 

the Steam Electric ELGs. EPA is not proposing new best conventional pollutant control 

technology (BCT) nor new best practicable control technology (BPT) requirements as part of the 

final rule. 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 

included in the regulatory options considered for the rulemaking. As described in Section 8, EPA 

identified six options for regulating existing discharges (i.e., BAT and PSES requirements) for 

the revisions to the ELGs. EPA identified one option for regulating discharges from new sources 

(i.e., NSPS and PSNS requirements). The final rule requirements are summarized below.

2.1.1 Discharges Directly to Surface Water from Existing Sources

For existing sources that discharge directly to surface water, with the exception of oilfired generating units and small generating units (those with a nameplate capacity of 50 

megawatts (MW) or less), the final rule establishes effluent limitations based on BAT. BAT is 

based on technological availability, economic achievability, and other statutory factors and is 

intended to reflect the highest performance in the industry (see Section 8.3). The final rule 

establishes BAT limitations as follows: 3

• For fly ash transport water, bottom ash transport water, and FGMC wastewater, there 

are two sets of BAT limitations. The first set of BAT limitations is a numeric effluent 

 3 For details on when the following BAT limitations apply, see Section 8.3.
Section 2—Summary of the Final Rule

2-3

limitation on Total Suspended Solids (TSS) in the discharge of these wastewaters 

(these limitations are equal to the TSS limitations in the previously established BPT

regulations). The second set of BAT limitations is a zero discharge limitation for all 

pollutants in these wastewaters.4

• For FGD wastewater, there are two sets of BAT limitations. The first set of 

limitations is a numeric effluent limitation on TSS in the discharge of FGD 

wastewater (these limitations are equal to the TSS limitations in the previously 

established BPT regulations). The second set of BAT limitations is numeric effluent 

limitations on mercury, arsenic, selenium, and nitrate/nitrite as N in the discharge of 

FGD wastewater.5

• For gasification wastewater, there are two sets of BAT limitations. The first set of 

limitations is a numeric effluent limitation on TSS in the discharge of gasification 

wastewater (this limitation is equal to the TSS limitation in the previously established 

BPT regulations). The second set of BAT limitations is numeric effluent limitations 

on mercury, arsenic, selenium, and total dissolved solids (TDS) in the discharge of 

gasification wastewater. 

• A numeric effluent limitation on TSS in the discharge of combustion residual leachate 

from landfills and surface impoundments. This limitation is equal to the TSS 

limitation in the previously established BPT regulations.

For oil-fired generating units and small generating units (50 MW or smaller), the final 

rule establishes BAT limitations on TSS in the discharge of fly ash transport water, bottom ash 

transport water, FGMC wastewater, FGD wastewater, and gasification wastewater. These 

limitations are equal to the TSS limitations in the existing BPT regulations.

2.1.2 Discharges Directly to Surface Water from New Sources

The CWA mandates that NSPS reflect the greatest degree of effluent reduction that is 

achievable, including, where practicable, a standard permitting no discharge of pollutants (see 

Section 8.4). NSPS represent the most stringent controls attainable, taking into consideration the 

cost of achieving the effluent reduction and any non-water quality environmental impacts and 

energy requirements. For direct discharges to surface waters from new sources, including 

discharges from oil-fired generating units and small generating units, the final rule establishes 

NSPS as follows:

• A zero discharge standard for all pollutants in fly ash transport water, bottom ash 

transport water, and FGMC wastewater.

• Numeric standards on mercury, arsenic, selenium, and TDS in the discharge of FGD 

wastewater.

 4 When fly ash transport water or bottom ash transport water is used in the FGD scrubber, the applicable limitations 

are those established for FGD wastewater on mercury, arsenic, selenium and nitrate/nitrite as N.

5 For plants that opt into the voluntary incentives program, the second set of BAT limitations is numeric effluent 

limitations on mercury, arsenic, selenium, and TDS in the discharge of FGD wastewater.
Section 2—Summary of the Final Rule

2-4

• Numeric standards on mercury and arsenic in the discharge of combustion residual 

leachate.

2.1.3 Discharges to POTWs from Existing Sources

PSES are designed to prevent the discharge of pollutants that pass through, interfere with, 

or are otherwise incompatible with the operation of POTWs. PSES are analogous BAT effluent 

limitations for direct dischargers and are generally based on the same factors (see Section 8.5). 

The final rule establishes PSES as follows:6

• A zero discharge standard for all pollutants in fly ash transport water, bottom ash 

transport water, and FGMC wastewater.7

• Numeric standards on mercury, arsenic, selenium, and nitrate/nitrite as N in the 

discharge of FGD wastewater. 

• Numeric standards on mercury, arsenic, selenium and TDS in the discharge of 

gasification wastewater. 

2.1.4 Discharges to POTWs from New Sources

PSNS are also designed to prevent the discharge of any pollutant into a POTW that 

interferes with, passes through, or is otherwise incompatible with the POTW. PSNS are 

analogous to NSPS for direct dischargers, and EPA generally considers the same factors for both 

sets of standards (see Section 8.6). The final rule establishes PSNS that are the same as the rule’s 

NSPS.

2.2 REVISIONS TO APPLICABILITY PROVISION AND SPECIALIZED DEFINITIONS

In addition to the discharge requirements described in Section 2.1, the final rule modifies 

the applicability provision for the ELGs. These modifications would not alter which generating 

units are regulated by the ELGs. These units have been traditionally regulated by the existing 

ELGs. Instead, the modifications would remove potential ambiguity present in the preexisting 

regulatory text. The changes include:

• Clarification that certain plants, such as certain municipally-owned plants, which

generate and distribute electricity within a service area (such as distributing electric 

power to municipally-owned buildings), but which use accounting practices that are 

not commonly thought of as a “sale,” are nevertheless subject to the ELGs.

• Clarification that “primarily,” as used in 40 CFR Part 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.

 6 For details on when PSES apply, see Section 8.5.

7 When fly ash transport water or bottom ash transport water is used in the FGD scrubber, the applicable standards 

are those established for FGD wastewater on mercury, arsenic, selenium and nitrate/nitrite as N.
Section 2—Summary of the Final Rule

2-5

• Clarification that combined cycle systems, which are generating units comprising one 

or more combustion turbines operating in conjunction with one or more steam 

turbines, are subject to the ELGs.

In addition to the revisions discussed above, the final rule revises certain existing 

specialized definitions, as well as includes new specialized definitions. The revisions to existing 

specialized definitions (with revisions underlined) are:

(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 or 

standards are otherwise established in this part. Low volume wastes sources include, 

but are not limited to, the following: wastewaters from wet scrubber air pollution 

control systems, wastewaters from 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, and wet scrubber air pollution control systems whose primary purpose 

is particulate removal. Sanitary and 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 precipitators, electrostatic 

precipitators, and/or fabric filters. Economizer ash is included in this definition when 

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

wet scrubber air pollution control systems whose primary purpose is particulate 

removal.

(f)The term bottom ash means the ash, including boiler slag, which settles in the 

furnace or is dislodged from furnace walls that drops out of the furnace gas stream in 

the furnace and in the economizer sections. Economizer ash is included when it is 

collected with bottom ash.

New specialized definitions are:

(n) The term flue gas desulfurization (FGD) wastewater means wastewater generated 

specifically from the wet flue gas desulfurization scrubber system that comes into 

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

blowdown or purge from the FGD scrubber system, overflow or underflow from the 

solids separation process, FGD solids wash water, and the filtrate from the solids 

dewatering process. Wastewater generated from cleaning the FGD scrubber, cleaning 

FGD solids separation equipment, cleaning FGD solids dewatering equipment, or that 

is collected in floor drains in the FGD process area is not considered FGD 

wastewater.

(o) The term flue gas mercury control (FGMC) wastewater means 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 sorbent injection or other controls to remove 
Section 2—Summary of the Final Rule

2-6

mercury from flue gas. FGD wastewater generated at plants using oxidizing agents to 

remove mercury in the FGD system and not in a separate FGMC system is not 

included in this definition.

(p) The term transport water means wastewater that is used to convey fly ash, bottom 

ash, or economizer ash from the ash collection or storage equipment, or boiler, and 

has direct contact with the ash. Transport water does not include low volume, short 

duration discharges of wastewater from minor leaks (e.g., leaks from valve packing, 

pipe flanges, or piping) or minor maintenance events (e.g., replacement of valves or 

pipe sections).

(q) The term gasification wastewater means any wastewater generated at an 

integrated gasification combined cycle operation from the gasifier or the syngas 

cleaning, combustion, and cooling processes. Gasification wastewater includes, but is 

not limited to the following: sour/grey water; CO2/steam stripper wastewater; sulfur 

recovery unit blowdown, and wastewater resulting from slag handling or fly ash 

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

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

byproduct piles are not considered gasification wastewater. Wastewater that is 

collected intermittently in floor drains in the gasification process area from leaks, 

spills and cleaning occurring during normal operation of the gasification operation is 

not considered gasification wastewater.

(r) The term combustion residual leachate means leachate from landfills or surface 

impoundments containing combustion residuals. Leachate is composed of liquid, 

including any suspended or dissolved constituents in the liquid, that has percolated 

through waste or other materials emplaced in a landfill, or that passes through the 

surface impoundment’s containment structure (e.g., bottom, dikes, berms). 

Combustion residual leachate includes seepage and/or leakage from a combustion 

residual landfill or impoundment unit. Combustion residual leachate includes 

wastewater from landfills and surface impoundments located on non-adjoining 

property when under the operational control of the permitted facility.

(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 phrase “as soon as possible” means November 1, 2018, unless the permitting 

authority establishes a later date, after receiving information from the discharger, 

which reflects a consideration of the following factors:

(1) Time to expeditiously plan (including to raise capital), design, procure, and 

install equipment to comply with the requirements of this part.

(2) Changes being made or planned at the plant in response to (i) new source 

performance standards for greenhouse gases from new fossil fuel-fired electric 
Section 2—Summary of the Final Rule

2-7

generating units, under sections 111, 301, 302, and 307(d)(1)(C) of the Clean Air 

Act, as amended, 42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C); (ii) emission 

guidelines for greenhouse gases from existing fossil fuel-fired electric generating 

units, under sections 111, 301, 302, and 307(d) of the Clean Air Act, as amended, 

42 U.S.C. 7411, 7601, 7602, 7607(d); or (iii) regulations that address the disposal 

of coal combustion residuals as solid waste, under sections 1006(b), 1008(a), 

2002(a), 3001, 4004, and 4005(a) of the Solid Waste Disposal Act of 1970, as 

amended by the Resource Conservation and Recovery Act of 1976, as amended 

by the Hazardous and Solid Waste Amendments of 1984, 42 U.S.C. 6906(b), 

6907(a), 6912(a), 6944, and 6945(a).

(3) For FGD wastewater requirements only, an initial commissioning period for 

the treatment system to optimize the installed equipment.

(4) Other factors as appropriate.

As stated in the new specialized definition for ash transport water, transport water does 

not include low volume, short duration discharges of wastewater from minor maintenance 

events. Examples of minor maintenance events include, but are not limited to, the following:

• Sluice line isolation/crossover valve packing failure or other mechanical valve failure.

• Minor leaks due to corrosion/erosion in the closed-loop system pumps, piping, valves, 

connections, and tanks.

• Minor leaks due to packing or seal failures in pumps, ash crushers, and bottom ash 

hopper isolation gates.

EPA does not consider any activity that requires draining the majority of the water 

volume from a wet sluicing, closed-loop system containment vessel (e.g., bottom ash hopper, 

remote MDS, dewatering bin, settling tank, surge tank) a minor maintenance event. Examples of 

maintenance events that are not included in EPA’s definition of “minor maintenance” include, 

but are not limited to, the following: 

• Bottom ash hopper refractory or steel hopper plate replacement.

• Bottom ash hopper enclosure replacement or sluice door maintenance.

• Remote mechanical drag system (MDS) wear plate or steel hopper plate replacement.

• Closed-loop system surge tank plate steel replacement or maintenance.

• MDS mechanical failure (e.g., chain derailment), wear plate replacement, or steel 

hopper plate replacement or maintenance.
Section 3—Data Collection Activities

3-1

SECTION 3

DATA COLLECTION ACTIVITIES

EPA collected and evaluated information from various sources in the course of 

developing the effluent limitations guidelines and standards (ELGs) for the Steam Electric Power 

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

the industry profile, determine the plant population affected by the rule, evaluate industry 

subcategorization, identify plant-specific operations, and determine wastewater characteristics, 

technology options, compliance costs, baseline pollutant loadings, post-compliance pollutant

reductions, and non-water quality environmental impacts. This section discusses the following 

data collection activities as they relate to technical aspects of this rulemaking:

• Steam Electric Power Generating Detailed Study (Section 3.1).

• Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Section 

3.2).

• Site visits (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).

• 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.

• 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

describes 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, 2009a]. The 

study focused largely on discharges associated with coal ash handling operations and wastewater 

from flue gas desulfurization (FGD) air pollution control systems because these sources are 

responsible for the majority of the toxic pollutants discharged by steam electric power plants.
Section 3—Data Collection Activities

3-2

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 (FGMC) 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, select plants to receive the survey, 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 permit application data provided 

by an industry trade association). The remainder of Section 3 provides additional details 

regarding the data used from the study.

3.2 QUESTIONNAIRE FOR THE STEAM ELECTRIC POWER GENERATING EFFLUENT 

GUIDELINES

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

responses provided by industry to the survey distributed by EPA under the authority of section 

308 of the Clean Water Act (CWA), 33 U.S.C. 1318. EPA designed the industry survey to obtain 

technical information related to wastewater generation and treatment, and economic information 

such as costs of wastewater treatment technologies and financial characteristics of potentially 

affected companies. The Agency used the responses to evaluate pollution control options for 

establishing revisions to the ELGs for the Steam Electric Category.

EPA developed an Information Collection Request (ICR) entitled Questionnaire for the 

Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey) [U.S. EPA, 2010]. 

The survey, approved by the Office of Management and Budget (OMB) in May 2010 (OMB 

Control No. 2040-0281), comprises 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 residuals (CCR), coal storage and processing, and outfalls. 

Parts B through H collected detailed technical information on certain aspects of power plant 
Section 3—Data Collection Activities

3-3

operations, including requiring some plants to collect and analyze wastewater samples, while 

Part I collected economic data.

To identify the population of steam electric power 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 North American 

Industry Classification System (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 gathered was primarily the 2007 Electric Generator Report (Form EIA860) and it was supplemented by information collected by the 2007 Power Plant Operations 

Report (Form EIA-923) and a survey conducted by EPA’s Office of Solid Waste and Emergency 

Response (OSWER) [U.S. EPA, 2009b]. In addition, EPA identified two plants that started 

operations after 2007 and obtained information about them from Internet searches.

Collectively, the data sources provided key 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 and the type of fuel used by each generating unit. 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 the plant 

stored or disposed of in the impoundment/landfill. EPA also used data for steam electric

generating units reported in the EIA-860 data set, 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 based on the type(s) of 

fuel they use so that an efficient stratified sampling scheme could be applied.

8 This sampling 

strategy allowed for different sampling rates across the strata. Depending on the amount or type 

of information it needed 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 

 8 EPA classified plants into 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 an oil- fired, gas-fired, or nuclear unit(s).
Section 3—Data Collection Activities

3-4

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 power 

generating industry, including oil-fired, gas-fired, gas-combined cycle, and nuclear power plants. 

Table 3-1 presents the number of plants in each fuel classification (i.e., stratum) for the sample 

frame used to identify survey recipients. 

Table 3-1. 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

Combination a 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. EPA sent Parts A and I of the survey to all sampled plants

and the remaining sections 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.9 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) to receive Parts A, B, C, 

D, E, H, and I. 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 nonregulated and regulated plants with 

plant fuel classifications of gas, gas-combined cycle, oil, nuclear, and combination (gas and gascombined 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 from 

the survey sample frame presented on Table 3-1 were selected to receive the survey. This total 

includes 495 coal-fired, nine petroleum coke-fired, 20 oil-fired, 167 gas-fired, 20 nuclear power 

plants, and 22 combination power plants.

 9 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).
Section 3—Data Collection Activities

3-5

EPA distributed and 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 

generation, would be retired by December 31, 2011, or did not generate electricity in 2009 by 

burning any fossil or nuclear fuels.10 Because responses were received for all 733 sampled plants 

(including those 53 plants that were not required to complete the remainder of the survey), no 

plants were considered non-respondents and the response rate was 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 it selected coal- and 

petroleum coke-fired plants 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 Agency weighted 

the data from these parts to represent the entire industry. In addition, EPA weighted data 

collected from the probability-sampled strata for other fuel types to represent the entire industry. 

All survey data presented in this document have been weighted to represent the entire industry, 

unless otherwise noted.

3.3 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. For most site visits, 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 nuclear-fueled power plants to better understand the plant operations, the wastewaters 

generated, and the types of treatment systems used. EPA conducted 73 site visits at steam 

electric power plants in 18 states between December 2006 and November 2014. The Agency 

conducted three additional site visits in Italy in April 2011 to obtain information on their FGD 

wastewater treatment systems. Table 3-2 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. EPA used information 

gathered from EPA’s Office of Air and Radiation (OAR), EIA, the Utility Water Act Group 

(UWAG), and other sources, including publicly available plant-specific information, state and 

regional permitting authorities, the Study data request, and the Steam Electric Survey, to identify 

plant operations of interest. EPA made pre-site visit phone calls to confirm plant characteristics 

and to select plants for site visits. 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.

 10 At the time EPA developed the survey, it 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

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• Evaluate whether the plant was appropriate to include in the sampling program.

• Gather plant-specific information to develop sampling plans.

• Select and evaluate potential sampling points.

Table 3-2. 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

Paradise, Kentucky Feb 2009

Wabash River, Indiana Feb 2009; Aug 2010

Miami Fort, Ohio Apr 2009; Mar 2010

Covanta, Virginia Jul 2009
Section 3—Data Collection Activities

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Table 3-2. List of Site Visits Conducted During the Detailed Study and Rulemaking

Plant Name, Location Month/Year of Site Visit

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

JEA Northside, Florida Apr 2014

John E. Amos, West Virginia Nov 2014

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 

data and treatment performance data associated with FGD wastewater, fly ash and bottom ash 

transport water, 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. 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 1- or 2-day sampling episodes at six

plants to characterize untreated wastewaters generated by coal-fired power plants, as well as 

assess treatment technologies and best management practices for reducing pollutant discharges. 
Section 3—Data Collection Activities

3-8

The types of wastewaters sampled during the detailed study were untreated and treated FGD 

wastewater, fly ash transport water, and bottom ash transport water. 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, 2009a].

After completing 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) and also required 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 process for field sampling 

conducted following the completion of the detailed study.

3.4.1 On-Site Sampling Activities

As part of EPA’s field sampling program, EPA conducted sampling episodes at steam 

electric power plants in the United States and Italy to collect wastewater characterization and 

wastewater treatment technology performance data.

3.4.1.1 United States

EPA conducted 4-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 operating 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 also collected data regarding system design and day-to-day operation to perform an 

engineering assessment of the design, operation, and performance of treatment systems at steam 

electric power plants. 

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.
Section 3—Data Collection Activities

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• 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.

• 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 6 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.11

• NOx Controls: EPA considered whether the plants operate a SCR system or a 

selective noncatalytic reduction (SNCR) system. Although these NOx control systems 

do not generate a specific wastewater stream, EPA considered whether 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 typical load cycling (i.e., baseload, 

cycling, peaking). Most of the plants sampled were baseload plants; however, EPA 

also selected plants with cycling units.

• Type of Coal: EPA selected plants burning different types of coal to help assess 

whether the types and concentration of metals present in the FGD wastewater could 

differ based on the fuel source. Most of the sampled plants 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 conducted sampling activities at the following U.S. plants:

 11 EPA did not select any plants operating inhibited oxidation FGD systems or once-through FGD systems for 

sampling after completing 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 captures 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

• Duke Energy Carolina’s Belews Creek Steam Station, North Carolina [ERG, 2012a].

• We Energies’ Pleasant Prairie Power Plant, Wisconsin [ERG, 2012b].

• Duke Energy’s Miami Fort Station, Ohio [ERG, 2012c].

• Duke Energy Carolina’s Allen Steam Station, North Carolina [ERG, 2012d].

• Mirant Mid-Atlantic, LLC’s Dickerson Generating Station, Maryland [ERG, 2012e].

• RRI Energy’s Keystone Generating Station, Pennsylvania [ERG, 2012f].

• Allegheny Energy’s Hatfield’s Ferry Power Station, Pennsylvania [ERG, 2012g].

All of the plants selected for sampling operated chemical precipitation wastewater 

treatment systems to treat their FGD wastewater. The treatment systems at Belews Creek Steam 

Station, Allen Steam Station, and Dickerson Generating Station also included a biological 

treatment stage following the chemical precipitation. Table 3-3 presents the 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, including temperature and pH, at all 

sampling points.
Section 3 – Data Collection Activities

3-11

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 Yesa,c Yesd LSFO SCR Baseload Eastern Bituminous Yes

Pleasant Prairie Yes Yesb No LSFO SCR Baseload Subbituminous Yes

Miami Fort Yes Yesb No LSFO SCR Baseload Eastern Bituminous Yes

Allen Yes Yesa,c Yesd LSFO SNCR Cycling Bituminous Yes

Dickerson Yes Yesa,c Yese LSFO SNCR Cycling Eastern Bituminous Yes

Keystone Yes Yesb No LSFO SCR Baseload Eastern Bituminous No

Hatfield's Ferry Yes Yesb No LSFO SNCR Baseload Bituminous, 

Subbituminous No

a – The chemical precipitation systems at these plants include hydroxide precipitation and iron co-precipitation, but do not include sulfide precipitation as part of 

the process.

b – The chemical precipitation systems at these plants include hydroxide precipitation, sulfide precipitation, and iron co-precipitation.

c – The chemical precipitation systems at these plants precede a biological treatment stage.

d – The biological treatment systems at these plants include an anoxic/anaerobic biological system primarily designed to remove selenium.

e – The biological treatment system at this plant includes a 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-nitrite 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, nickel, selenium, 

silver, thallium, and vanadium

EPA 200.8 with collision cell

Aluminum, barium, beryllium, boron, calcium, cobalt, iron, magnesium, 

manganese, molybdenum, sodium, tin, titanium, and zinc a

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 the Agency observed 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 3-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. 

The mechanical vapor-compression evaporation system used a falling-film brine concentrator to 
Section 3—Data Collection Activities

3-13

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 quality control (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.

EPA selected Brindisi for sampling because it operates a one-stage chemical precipitation 

system followed by softening and a two-stage vapor-compression evaporation system to treat

FGD wastewater. The following are the characteristics of the Brindisi plant:

• The plant is a coal-fired power plant.

• The plant operates LSFO 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.

• The plant operates SCR systems on all four units.

EPA collected samples for the same list of analytes listed in Table 3-4, except for BOD5, 

total cyanide, and dissolved metals (all analytes) because of either holding time considerations or 

time constraints for the sampling event. EPA also collected field measurements, including 

temperature and pH, at all sampling points.

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. At the 

brine concentrator and crystallizer sampling points, EPA collected six-hour composite samples 

for all analytes except mercury, which was collected 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 1-day grab samples.

A sampling episode report describing the sample collection activities and the analytical 

results from this sampling episode is included in the rulemaking record [ERG, 2012h].
Section 3—Data Collection Activities

3-14

EPA also requested the collection of 1-day grab samples from a second plant in Italy, 

A2A’s Centrale di Monfalcone (Monfalcone). This plant treats FGD wastewater using a system 

comprising chemical precipitation followed by vapor-compression evaporation. 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) was required to participate in the CWA 308 

monitoring program so EPA could evaluate the variability associated with the FGD wastewater 

treatment systems’ performance.

In addition to collecting the samples during the 4-day on-site sampling event, EPA 

required these seven plants to each collect four sets of samples over a 4- or 5-month period. The 

samples were collected directly by the plants and shipped to EPA-contracted laboratories for 

analysis.

EPA required four additional plants (not sampled by EPA) to participate in its CWA 308 

monitoring program. These plants were selected to collect samples from their 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 commercially operating IGCC plant at 

the time of EPA’s sampling program). 12

• Wabash Valley Power Association’s Wabash River Station (second commercially 

operating IGCC plant at the time of EPA’s sampling program).

• Appalachian Power Company’s Mountaineer Plant (only plant operating a carbon 

capture system at the time of EPA’s sampling program).

• Kansas City Power & Light’s Iatan Station (only plant in the United States operating 

an evaporation system to treat FGD wastewater at the time of EPA’s sampling 

program).

EPA required each of these four plants to collect four consecutive days of samples at two 

to four locations specifically identified for each plant. The sample locations were identified to 

characterize gasification wastewaters, carbon capture wastewaters, and the treatment of FGD 

wastewater and gasification wastewater by vapor-compression evaporation systems. EPA used 

the same 4-consecutive-day sampling approach that it used for its 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.

 12 EPA identified that Duke Energy’s Edwardsport Power Station also operates an IGCC system; however, it was 

not yet in commercial operation at the time of EPA’s sampling program.
Section 3—Data Collection Activities

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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 about the steam electric power generating industry, treatment 

technologies, and the evaluated wastestreams from databases, publications, state groups, and 

permitting authorities. Sections 3.5.1 through 3.5.7 summarize the state and EPA data collected 

during the development of the Steam Electric ELG.

EPA’s Office of Water (OW) coordinated its efforts with ongoing research and activities 

being undertaken by the EPA offices discussed below. In addition, EPA’s OW 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 National Pollutant Discharge Elimination System (NPDES) Permits, Permit 

Applications, 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 permit applications 

and 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, 2011a]. EPA also 

participated in periodic conference calls with ORSANCO during the rulemaking to discuss 

treatment technologies for managing wastewaters from steam electric power plants. Moreover, 

EPA coordinated with the North Carolina Department of Environmental and Natural Resources

to obtain long-term characterization data from Progress Energy Carolinas’ Roxboro Steam Plant
Section 3—Data Collection Activities

3-16

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 

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 the current 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.

EPA found that many steam electric power plants still use the same handling practices 

and treatment technologies for fly ash and bottom ash that were evaluated in the 1982 

rulemaking. EPA reviewed wastewater characterization data presented in the 1982 Development 

Document to characterize ash impoundment effluent for the ELG. EPA determined that the 

method in which fly and/or bottom ash is wet sluiced to surface impoundments and management 

practices of those surface impoundments are relatively unchanged since promulgation of the

1982 Steam Electric ELG; therefore, the ash transport water characterization data are still valid 

to characterize current ash impoundment discharges.

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 plants 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 

plant.

• Financial and economic information about the plant.
Section 3—Data Collection Activities

3-17

Although EPA used the Section 316(b) survey to create regulations 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.

• Determining plant-specific wastewater dilutions associated with cooling water prior 

to discharge for the Environmental Assessment (EA) analyses associated with the 

rulemaking effort.

3.5.5 Office of Air and Radiation

EPA’s OAR works to control air pollution and radiation exposure through 

implementation of the Clean Air Act. EPA is taking action on climate change by developing 

regulations under the Clean Air Act (CAA) to reduce emissions of greenhouse gases (GHGs). 

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 engineering-economic optimization model of the 

electric power industry, which generates least-cost resource dispatch decisions based on userspecified 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 and 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 [U.S. EPA, 2011b]. Thus, IPM incorporates electricity demand growth assumptions from 

the Department of Energy’s Annual Energy Outlook 2013 (AEO 2013). IPM Version 5.13 (IPM 

V5.13) incorporates in its analytic baseline the expected compliance response for federal and 

state air emission laws and regulations whose provisions were either in effect or enacted and 

clearly delineated at the time the base case was finalized in August 2013, including: the final 

Mercury and Air Toxics Standards (MATS) rule; the Clean Air Interstate Rule (CAIR); 

regulatory sulfur dioxide (SO2) emission rates arising from State Implementation Plans; Title IV 

of the Clean Air Act Amendments; NOx State Implementation Plan (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 mercury that were either in effect or expected to come into force by 2017. In addition, 

the modeling includes the proposed CAA section 111(d) Clean Power Plan and the proposed 

CAA section 111(b) Carbon Pollution Standards, due to time limitations for modeling (the final 

CAA section 111 rules were issued on August 3, 2015). This does not materially impact the 

analysis of the effluent guidelines since the impacts of the CAA section 111(d) rule for existing 

sources was similar from proposal to final rule. In addition to these air regulations, the IPM 
Section 3—Data Collection Activities

3-18

V5.13 base case used for the analysis of the Steam Electric ELGs also takes into account the 

industry’s expected compliance response to the CWA Section 316(b) regulations EPA 

promulgated in August 2014 and the Disposal of Coal Combustion Residuals from Electric 

Utilities (CCR) regulation EPA promulgated in December 2014. The CWA section 316(b) and 

CCR rule are discussed further in Sections 3.5.4 and 3.5.7, respectively.

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.

EPA’s OW consulted with 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 December 19, 2014, EPA finalized the Disposal of Coal Combustion Residuals from 

Electric Utilities (CCR rule) (80 FR 21302; April 17, 2015). The rule provides requirements for 

the safe disposal of CCRs generated by electric utilities and independent power producers. The 

CCR rule is the culmination of extensive study on the effects of coal ash on the environment and 

public health. The rule establishes technical requirements for CCR landfills and surface 

impoundments under Subtitle D of the Resource Conservation and Recovery Act (RCRA), the 

nation's primary law for regulating solid waste. EPA used data collected by EPA’s OSWER to 

supplement the data collected for the Steam Electric ELGs. EPA also used costing 

methodologies developed by EPA’s OSWER to estimate certain costs associated with plants 

implementing the requirements of the Steam Electric ELGs, where appropriate. 

As part of the CCR rule development, OSWER issued Information Request Letters to 

electric utilities that have surface impoundments or similar management units that contain CCRs. 

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 
Section 3—Data Collection Activities

3-19

nameplate electric generating capacity of less than 100 megawatts (MW). Additionally, the EIA 

data exclude 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.

EPA developed a methodology to account for how operational changes associated with 

the CCR rule may impact the analyses for the ELGs. The analyses presented for the Steam 

Electric ELGs represent the current industry operations, while also taking into account the 

actions plants may take to implement the new requirements from the CCR rule. EPA’s 

methodologies for incorporating the CCR rule impacts into the engineering costs and pollutant 

loadings and removals are described in Section 9 and Section 10.

3.6 INDUSTRY-SUBMITTED DATA

EPA obtained information on steam electric processes, technologies, wastewaters, and 

pollutants directly from the industry through self-monitoring data, NPDES Form 2C data, and 

data provided during public comment.

3.6.1 Self-Monitoring Data for Proposed Rule

Prior to the proposed rule, EPA requested self-monitoring data from Duke Energy’s 

Belews Creek Steam Station and Allen Steam Station to evaluate the treatment efficacy and 

pollutant characteristics of wastewater discharged from FGD wastewater treatment systems that 

incorporate both chemical precipitation and biological treatment [Duke Energy, 2011a; Duke 

Energy, 2011b]. EPA also used these data to supplement the data from EPA’s sampling program.

3.6.2 Post-Proposal Industry-Submitted Data

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

data collected during EPA’s sampling program, EPA relied on industry-supplied data and 

publicly available data sources, including data received during public comment, to characterize 

pollutant discharge concentrations and evaluate treatment technologies. In some cases, EPA 

requested additional information from industry to fully evaluate the data provided or to support 

additional analyses, including evaluating FGD wastewater treatment system performance and 

characterizing ash impoundment effluent. EPA collected the following types of information from 

industry to characterize the evaluated wastestreams and treatment system performance:

• FGD system information (e.g., identity of the organosulfide additives used in each 

chemical precipitation treatment system, conditions within each FGD scrubber system 

during sampling period). 

• Pollutant concentrations in FGD purge, FGD chemical precipitation effluent, and 

FGD biological treatment influent and effluent. 

• Ash system information.

• Pollutant concentrations in ash impoundment influent and effluent.
Section 3—Data Collection Activities

3-20

• Pollutant concentrations in source water.

• Amount, source, sulfur content, chlorine content, and type of coal burned.

Following receipt of public comments, EPA also received additional bottom ash transport 

water characterization data from UWAG for consideration in the final rule. 

EPA reviewed public comments received on the proposed rule related to plant-specific 

operations and the cost for installing or upgrading FGD wastewater treatment and ash handling 

technologies. EPA evaluated public comments to identify plant-specific operation and flow data 

and, where appropriate, used this information to revise estimates of compliance costs and 

pollutant removals for those facilities. One example of plant-specific revision is where a facility 

asserted that space constraints below the boiler made retrofitting a mechanical drag system 

infeasible, EPA based cost estimates for zero pollutant discharge of bottom ash transport water 

on the remote mechanical drag system technology.

EPA received data for plants operating FGD wastewater treatment systems through 

industry-submitted public comments on the proposed rule for the Steam Electric ELGs; however, 

EPA identified supplemental information required to evaluate FGD operations during the range 

of dates provided for the monitoring data. For this reason, EPA contacted the plants operating 

chemical precipitation or biological treatment system components that make up the BAT 

technology basis to request FGD wastewater characterization data (if not yet provided) and 

supplemental information on FGD operations over a 2-year period (i.e., January 2012 –

December 2013). FGD wastewater characterization data requested by EPA included chemical 

precipitation and biological treatment system effluent concentrations for arsenic, mercury, 

selenium, and several other metals. Supplemental information requested by EPA included type 

and source of coal, the sulfur and chlorine content of the coal used at the plant, and FGD system 

operational information for the range of dates for which characterization data were collected and 

analyzed. EPA also contacted individual plants to verify the quality of the samples and ensure 

that the data were appropriate for use in EPA’s wastestream characterization and treatment 

performance evaluations. 

3.6.3 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. Information collected by this form includes facility 

information, data on facility outfalls, process flow diagrams, treatment information, and intake 

and effluent characteristics.

The Form 2C database, compiled by UWAG and provided to EPA, contains information 

about the outfalls of coal-fired power plants that receive FGD wastewater, ash transport water, or 

coal pile runoff. EPA received Form 2C data from UWAG for 86 plants in 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 
Section 3—Data Collection Activities

3-21

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 Steam Electric Survey, and to 

evaluate and characterize ash impoundment effluent.

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 2015, EPA participated in multiple technical 

conferences and reviewed the papers presented for relevant information to the rulemaking.

To gather FGD wastewater and combustion residual leachate 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 

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.

• Operation and maintenance (O&M) costs.

• Equipment and system energy requirements.

To gather information on handling 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:

• Type of fly ash and bottom ash handling systems available for reducing or 

eliminating ash transport water.

• Equipment, modifications, and demolition required to convert wet-sluicing fly ash 

and bottom ash handling systems to dry ash handling or closed-loop recycle 

systems.13

• 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.

• Purchased equipment, other direct, and indirect capital costs for fly ash and bottom 

ash conversions.

 13 Throughout this report, EPA refers to bottom ash systems that eliminate the use of ash transport water as dry ash 

handling systems; however, some of these systems (e.g., mechanical drag system) still use water in a quench bath 

and, therefore, are not completely dry systems.
Section 3—Data Collection Activities

3-22

• Specifications for the types of ash storage available (e.g., steel silos or concrete silos) 

for the different types of handling systems.

• Equipment and installation capital costs associated with the storage of fly ash and 

bottom ash.

• Operation 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 conducted meetings, conference calls, and site visits with treatment and ash 

vendors. The information collected from technology vendors is detailed further in the 

Incremental Costs and Pollutant Removals for the Final Limitations Guidelines and Standards 

for the Steam Electric Power Generating Point Source Category [ERG, 2015].

3.8 OTHER DATA SOURCES

EPA obtained additional information on steam electric processes, technologies, 

wastewaters, pollutants, and regulations from sources including UWAG, the Electric Power 

Research Institute (EPRI), DOE, literature and Internet searches, and environmental groups and 

other stakeholders. 

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, discussing 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. Additionally, UWAG coordinated with individual plants to 

submit public comments, including the plant-specific wastewater characterization data discussed 

in Section 3.6.2.

3.8.2 Electric Power Research Institute

EPRI is a research-oriented trade association for the steam electric power generating 

industry. EPRI conducts research funded by the steam electric power generating industry and has 

extensively studied wastewater discharges from FGD systems. Table 3-5 presents the reports 

provided to EPA by the trade association that summarize the data collected during several EPRI 

studies.

In addition, as part of their response to the Steam Electric Survey, several steam electric 

power plants submitted EPRI studies on wastewater discharges from FGD systems and ash 

impoundments at their plants.
Section 3—Data Collection Activities

3-23

The EPRI reports provided EPA with the following: background information regarding 

the characteristics of FGD wastewaters and the sampling techniques used during the program;

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; and information on the treatment technologies available to treat 

FGD and ash wastewaters, including findings from pilot-study evaluations.

EPA reviewed all EPRI reports to determine if they contained FGD wastewater or ash 

impoundment characterization data that met all acceptance criteria. As described in Sections 11 

and 12 of the Incremental Costs and Pollutant Removals for the Final Limitations Guidelines 

and Standards for the Steam Electric Power Generating Point Source Category report [ERG, 

2015] for this rulemaking, EPA used data from EPRI reports to characterize FGD wastewater or 

ash transport water. 

EPRI conducts 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, constructed wetlands, and anoxic/anaerobic 

biological treatment systems. In addition, EPRI has conducted studies for other technologies that 

can potentially remove metals from FGD wastewaters. EPA analyzed EPRI reports describing 

alternative FGD wastewater treatment technologies as bench-, pilot-, and full-scale. EPA’s 

evaluation of alternative treatment technologies is further discussed in Section 7.1.7.

EPRI also participated in meetings with EPA and provided comments on EPA’s planned 

data collection activities, including the Steam Electric Survey and the sampling program.

Table 3-5. Reports and Studies Submitted to EPA from EPRI

Title of Report/Study Document Control 

Number

PISCES Wastewater Characterization Field Study, Sites A-G DCNs SE01818-SE01823

The Fate of Mercury Absorbed in Flue Gas Desulfurization (FGD) Systems DCN SE01814

Flue Gas Desulfurization (FGD) Wastewater Characterization: Screening Study DCN SE01816

EPRI Technical Manual: Guidance for Assessing Wastewater Impacts of FGD 

Scrubbers

DCN SE01817

Update on Enhanced Mercury Capture by Wet FGD: Technical Update DCN SE01815

Selenium Removal by Iron Cementation from a Coal-Fired Power Plant Flue Gas 

Desulfurization Wastewater in Continuous Flow System – A Pilot Study

DCN SE0409A2

Laboratory and Pilot Evaluation of Iron and Sulfide Additives with 

Microfiltration for Mercury Water Treatment

DCN SE0409A3

Impact of Wet Flue Gas Desulfurization (FGD) Design and Operating Conditions 

on Selenium Speciation: 2009 Update

DCN SE04369

Integrated Fly Ash Pond Management: A Field Study of Five Central United 

States Pond Systems.

DCN SE04361

Current Practices for Flue Gas Desulfurization (FGD) Water Management and 

Treatment in Ponds

DCN SE04367
Section 3—Data Collection Activities

3-24

Table 3-5. Reports and Studies Submitted to EPA from EPRI

Title of Report/Study Document Control 

Number

Pilot-Scale and Full-Scale Evaluation of Treatment Technologies for the Removal 

of Mercury and Selenium in Flue Gas Desulphurization Water

DCN SE04362

Impact of Wet Flue Gas Desulfurization (FGD) Design and Operating Conditions 

on Selenium Speciation: 2010 Update

DCN SE04370

Review of Water Treatment Technologies for Selenium Removal Implemented at 

Power Plants

DCN SE04363

Evaluation of Mercury Speciation and Its Treatment Implication in Flue Gas 

Desulfurization Waters

DCN SE04368

Thermal Flue Gas Desulfurization Wastewater Treatment Processes for Zero 

Liquid Discharge Operations

DCN SE04365

Selenium Speciation and Management in Wet FGD Systems DCN SE04364

Corrosion in Wet Flue Gas Desulfurization (FGD) Systems: Technical Root 

Cause Analysis of Internal Corrosion on Wet FGD Alloy Absorbers

DCN SE04366

Pilot Evaluation of the Anaerobic Membrane Bioreactor Technology for Flue Gas 

Desulfurization Wastewater Treatment

DCN SE05615

Pilot Evaluation of the PironoxTM System for Flue Gas Desulphurization 

Wastewater Treatment

DCN SE05616

Pilot Evaluation of a Fluidized Bed Reactor/Membrane Bioreactor Technology 

for Flue Gas Desulfurization Wastewater Treatment

DCN SE05617

Pilot Evaluation of the ABMet Technology for Flue Gas Desulphurization 

Wastewater Treatment

DCN SE05618

Pilot Evaluation of the ZVI BlueTM Technology for Flue Gas Desulphurization 

Wastewater Treatment

DCN SE05619

3.8.3 Department of Energy 

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 5

years of filing this form.14 The data collected in Form EIA-860 are associated only with the 

design and operation of generators at facilities [U.S. DOE, 2007a; U.S. DOE, 2009a]. Form EIA923 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) resides, and if it is connected to the local or regional electric power grid 

 14 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

3-25

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 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 requested 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 power generating process. The objectives of these searches included 

characterizing wastewaters and pollutants originating from these steam electric power generating 

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, standard engineering design and cost references, 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.

In addition to chemical precipitation, biological treatment, vapor-compression 

evaporation, constructed wetlands, and zero discharge systems for FGD wastewater treatment, 

EPA also identified several emerging treatment technologies that are being developed to treat 

FGD wastewater. EPA analyzed industry sources and published research articles describing 

alternative FGD wastewater treatment technologies at bench-, pilot-, and full-scale levels. EPA’s 

evaluation of alternative treatment technologies is further discussed in Section 7.1.7.

3.8.5 Environmental Groups and Other Stakeholders

EPA received information from several environmental groups and other stakeholders as 

part of public comments received on the 2006 and 2008 Effluent Guidelines Plans and the 

proposed ELGs, during development of the survey, and in other discussions during the detailed 

study and rulemaking. In general, the information highlights the 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.

3.8.6 EPA Public Meetings

On July 9, 2013, EPA held a pretreatment public hearing about the pretreatment 

standards contained in the proposed Steam Electric ELGs. This hearing collected oral public 

comments from 55 commenters and written comments from 38 commenters [U.S. EPA, 2013a]. 

In addition, on August 20, 2013, EPA held a webinar where EPA presented a summary of the

proposed rule and answered questions raised by participants. The presentation given by EPA and 

the transcript from the webinar are included in the record [U.S. EPA, 2013b]. 

3.9 PROTECTION OF CONFIDENTIAL BUSINESS INFORMATION

Certain data in the rulemaking record have been claimed as confidential business 

information (CBI). As required by federal regulations at 40 CFR 2, EPA has taken precaution to 
Section 3—Data Collection Activities

3-26

prevent the inadvertent disclosure of this CBI. The Agency has withheld CBI from the public 

docket in the Federal Docket Management System. In addition, EPA 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 protecting

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

opportunity for public comment, without compromising data confidentiality.

3.10 REFERENCES

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

Allen Steam Station. (17 August). DCN SE01809.

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

Belews Creek Steam Station. (17 August). DCN SE01808.

3. Duke Energy. 2013. Comments of Duke Energy on Effluent Limitations Guidelines 

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

EPA-HQ-OW-2009-0819-4305. (7 June).

4. Duke Energy. 2014. Duke Response to Post Proposal Data Request. (28 March and 

13 August). DCN SE04360 and SE04331.

5. ERG. 2009. Eastern Research Group, Inc. Memorandum to Ron Jordan, U.S. EPA. 

“Outreach Calls for the Proposed Steam Electric ICR.” (25 February). DCN 

SE00203.

6. ERG. 2012a. Eastern Research Group, Inc. Final Sampling Episode Report, Duke 

Energy Carolinas’ Belews Creek Steam Station. (13 April). DCN SE01305.

7. ERG. 2012b. Eastern Research Group, Inc. Final Sampling Episode Report, We 

Energies’ Pleasant Prairie Power Plant. (13 April). DCN SE01306.

8. ERG. 2012c. Eastern Research Group, Inc. Final Sampling Episode Report, Duke 

Energy Miami Fort Station. (13 April). DCN SE01304.

9. ERG. 2012d. Eastern Research Group, Inc. Final Sampling Episode Report, Duke 

Energy Carolinas’ Allen Steam Station. (13 April). DCN SE01307.

10. ERG. 2012e. Eastern Research Group, Inc. Final Sampling Episode Report, Mirant 

Mid-Atlantic, LLC’s Dickerson Generating Station. (13 April). DCN SE01308.

11. ERG. 2012f. Eastern Research Group, Inc. Final Sampling Episode Report, RRI 

Energy’s Keystone Generating Station. (13 April). DCN SE01309.

12. ERG. 2012g. Eastern Research Group, Inc. Final Sampling Episode Report, 

Allegheny Energy’s Hatfield’s Ferry Power Station. (13 April). DCN SE01310.

13. ERG. 2012h. Eastern Research Group, Inc. Final Site Visit Notes and Sampling 

Episode Report for Enel’s Power Plants. (8 August). DCN SE02013.

14. ERG. 2012i. Eastern Research Group, Inc. Final Power Plant Monitoring Data 

Collected Under Clean Water Act Section 308 Authority (“CWA 308 Monitoring 

Data”). (30 May). DCN SE01326.
Section 3—Data Collection Activities

3-27

15. ERG. 2013. Eastern Research Group, Inc. Final Monfalcone Site Visit Notes. (11 

March). DCN SE03795 and SE03796.

16. ERG. 2015. Eastern Research Group, Inc. Incremental Costs and Pollutant 

Removals for the Final Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category (30 September). DCN SE05831.

17. Hoosier Energy Rural Electric Cooperative (Hoosier). 2013. Comments of Hoosier 

Energy on Effluent Limitations Guidelines and Standards for the Steam Electric

Power Generating Point Source Category. EPA-HQ-OW-2009-0819-4471. (20 

September).

18. Hoosier Energy Rural Electric Cooperative (Hoosier). 2014. Hoosier Response to 

Post Proposal Information Request. (11 and 14 April). DCNs SE04701 and 

SE04702.

19. NCDENR. 2011. North Carolina Department of Environment and Natural 

Resources. North Carolina Department of Environment and Natural Resources State 

Provided Sampling Data From North Carolina's Progress Energy Roxboro Plant. (26 

June). DCN SE01812.

20. 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. 

21. 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. 

22. 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. 

23. 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. 

24. U.S. EPA. 1974. U.S. Environmental Protection Agency. Development Document 

for Effluent Limitations Guidelines and New Source Performance Standards for the 

Steam Electric Power Generating Point Source Category. EPA-440-1-74-029a.

Washington, DC (October). DCN SE02917.

25. U.S. EPA. 1982. U.S. Environmental Protection Agency. Development Document 

for Effluent Limitations Guidelines and Standards and Pretreatment Standards for 

the Steam Electric Point Source Category. EPA-440-1-82-029. Washington, DC. 

(November). DCN SE02931.
Section 3—Data Collection Activities

3-28

26. U.S. EPA. 2009a. U.S. Environmental Protection Agency. Steam Electric Power 

Generating Point Source Category: Final Detailed Study Report. EPA 821-R-09-

008. Washington, DC (October). DCN SE00003. 

27. U.S. EPA. 2009b. U.S. Environmental Protection Agency. Office of Solid Waste 

and Emergency Response (OWSER). Summary Results from the 2009 OSWER 

Information Request. DCN SE02032.

28. U.S. EPA. 2010. U.S. Environmental Protection Agency. Questionnaire for the 

Steam Electric Power Generating Effluent Guidelines. OMB Approval Number: 

2040-0281. Washington, DC. (2 June). DCN SE00402-SE 00402A09.

29. U.S. EPA. 2011a. U.S. Environmental Protection Agency. Steam Electric ELG 

Rulemaking – UMRA and Federalism Implications: Consultation Meeting. (11 

October). DCN SE03286 and SE03287.

30. U.S. EPA. 2011b. U.S. Environmental Protection Agency. Office of Air and 

Radiation (OAR). Integrated Planning Model (IPM) 2015 MATS Policy Case 

Output. (December). DCN SE02047.

31. U.S. EPA. 2013a. U.S. Environmental Protection Agency. Public Hearing on the 

Proposed Effluent Guidelines for the Steam Electric Power Generating Industry –

Transcript and Comments Received. (July). DCNs SE04082-SE04082A39.

32. U.S. EPA. 2013b. U.S. Environmental Protection Agency. EPA Webcast, Reducing 

Toxic Water Pollutions from Power Plants. (20 August). DCNs SE05614 and 

SE05614A1.

33. UWAG. 2008. Utility Water Act Group. UWAG Form 2C Effluent Guidelines 

Database. (30 June). DCNs SE02918 and SE02918A1.

34. UWAG. 2013a. Comments on EPA’s Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category. EPAHQ-OW-2009-0819-4655. (7 June 2013).

35. UWAG. 2014. UWAG Response to Post Proposal Information Request. (1 August). 

DCN SE04717.
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 describes the 

electric power generating industry, including demographics of the steam electric power 

generating industry; Section 4.2 describes the steam electric power generating process; Section 

4.3 describes the wastestreams generated by the steam electric power generating industry that 

were evaluated for new controls in the ELGs; and Section 4.4 describes the wastestreams 

generated by the steam electric power generating industry that were not evaluated for new 

controls in the ELGs.

4.1 OVERVIEW OF ELECTRIC GENERATING INDUSTRY

This section describes the 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, 2012a; 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, 2012a; 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 power generating industry via EPA’s 

Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric 

Survey) represent plant-level operations in 2009, and used the 2007 Census data because, as a 5-

year census, it is the closest year to the Steam Electric Survey for which data are available. 

Together, these sources provide the most 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.

15 The 2007 Economic Census data 

 15 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

include more specific industry sector information at the six-digit North American Industry 

Classification System (NAICS) code level.

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 non-steam-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.

16 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 

 16 The applicability of the Steam Electric Power Generating Point Source Category (40 CFR 423.10) states that “the 

provisions of this part apply to discharges resulting from the operation of a generating unit by an establishment 

whose generation of electricity is the predominant source of revenue or principal reason for operation, and which 

results primarily from a process utilizing fossil-type fuel (coal, oil, or gas), fuel derived from fossil fuel (e.g., 

petroleum coke, synthesis 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

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 

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, 

2012c]. 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.

• Combined cycle system – combustion turbine portion.17

• Combined cycle single shaft – steam and combustion turbines sharing a single shaft.

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 

 17 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 (See 40 CFR 423.10).
Section 4—Steam Electric Industry Description

4-5

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.

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.

• 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 those plants/units that reported one of the above energy 

sources as a “primary” energy source or that reported coal or petroleum coke as either the 

“primary” or “secondary” energy source in the 2009 EIA data.

18 The 1,179 plants operate an 

 18 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; 
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 power generation process, which uses a combustible 

fuel 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. This 

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) 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 pollutants

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.

• Flue gas mercury controls (FGMC): mercury.

 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

4-7

The nuclear-fueled steam electric process is similar to the steam/water system described 

above. The nuclear system differs from the nonnuclear system in three key ways: fuel handling, 

nuclear fission within the reactor core instead of the boiler as the heat source for producing 

steam, and no air pollution control equipment. No fuel is combusted and no ash is generated in a 

nuclear-fueled steam electric power generating 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 power generating process are the same as those described for the stand-alone steam 

electric process [U.S. DOE, 2006].

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. Figure 4-3 illustrates the combined cycle system 

process. 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 other fuels, such as oil or synthetic gas. 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. 

Steam electric generating units within combined cycle systems operate almost identically

to stand-alone steam electric generating units, except without the boiler. In a combined cycle 

system, the combustion turbines and HRSGs functionally take the place of the boiler of a standalone steam electric generating 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 generating 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 generating 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.

4.2.3 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). Figure 4-4 presents a general process flow diagram for an IGCC system. 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. 
Section 4—Steam Electric Industry Description

4-8

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 three commercial-scale IGCC systems located in the United States; the 262-MW Wabash 

River IGCC Repowering Project (Wabash River) in Indiana, the 250-MW Tampa Electric Polk 

Power Station IGCC Project (Polk) in Florida, and the 618-MW Edwardsport IGCC Project in 

Indiana [U.S. DOE, 2014]. Other U.S. power companies are investigating or planning IGCC 

systems at new or existing plants, such as the 582-MW Kemper County IGCC Project in 

Mississippi, which is under construction and is expected to begin commercial operation in early 

to mid-2016. The system at Kemper County will achieve zero discharge of its gasification 

wastewater and will include a carbon capture system [Southern Company, 2015]. EPA has 

conducted site visits at the Wabash River, Polk, and Edwardsport plants. The specific gas 

preparation and by-product recovery operations at the plants may vary, but each uses the same 

general electric power generating process as shown in Figure 4-4. 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, 2009; ERG, 2011].
Section 4—Steam Electric Industry Description

4-9

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 Power Generating Process Flow Diagram
Section 4—Steam Electric Industry Description

4-10

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

4-11

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 Questionnaire for the Steam Electric 

Power Generating Effluent Guidelines (Steam Electric Survey) to power plants believed to be 

subject to the Steam Electric Power Generating ELGs. As described in Section 3.2, EPA 

distributed the Steam Electric 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-fueled fire. EPA obtained information on 

specific aspects of power plant operation for the 2009 calendar year. The Steam Electric Survey 

also requested information about planned steam electric generating units, wastewater treatment 

systems, and other improvements or modifications through the year 2020. EPA uses data from 

the Steam Electric Survey throughout this document to describe the state of the steam electric 

power generating industry and to make projections on the general direction of the industry in the 

near future. As described in Section 4.5 and later sections, EPA considered plant and generating 

unit retirements, fuel conversions (repowering), ash handling conversions, wastewater treatment 

upgrades, and other industry profile changes in the development of the regulatory options and 

supporting technical analyses; however, the data presented in this section represent 2009 

conditions, unless otherwise noted. Although there have been some changes in the industry since 

EPA conducted the survey (and these are reflected to the extent practicable in the ELG analyses), 

the survey remains the best available source of information for characterizing operations across 

the industry. The Steam Electric Survey data presented in this document are based on reported 

values, which were scaled up to represent the steam electric power generating industry in 2009 as 

a whole using the industry-weighting factors discussed in Section 3.2.

Table 4-2 presents the distribution of the types of steam electric prime movers used by 

plants to which the Steam Electric Power Generating ELGs apply using both 2009 EIA data and 

EPA’s Steam Electric Survey data. 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. As shown in Table 4-2, the Steam Electric 

Survey estimates are lower than the 2009 EIA data estimates. The EIA data indicate that there 

were 1,179 plants operating at least one steam electric generating unit powered by a fossil or 

nuclear fuel in 2009. Based on the weighted Steam Electric Survey data, however, the industry 

had 1,079 plants operating at least one steam electric generating unit in 2009.19 As described in 

Section 3.2, the Steam Electric Survey captured data from plants identified using 2007 EIA data 

but responses reflect data for the 2009 production year. The steam electric power generating 

industry is dynamic; the discrepancies between Steam Electric Survey data and the 2009 EIA

data could be due to new installations, unit fuel conversions, and 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. Since the 

survey provides more complete information about power plant operations and is a better source 

for identifying plants that are covered by the ELGs, EPA used the weighted Steam Electric 

 19 EPA identified another plant that began operation after the time period for the Steam Electric Survey, resulting in 

a total baseline population of 1,080 plants for the ELG analyses.
Section 4—Steam Electric Industry Description

4-13

Survey results for the remainder of the analyses in this document to represent the steam electric 

power generating industry in 2009.

Based on the Steam Electric Survey data, the majority (71 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.

20 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) make up 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 power generating 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.

Stand-alone steam turbines are more prevalent than combined cycle units within the 

steam electric power generating 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. 

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 power generating industry.

 20 The overall plant capacity includes all electric power generated by the plant, including electricity produced using 

non-steam generators and non-fossil/non-nuclear energy sources.
Section 4—Steam Electric Industry Description

4-14

Table 4-2. Distribution of Prime Mover Types for Plants Regulated by the Steam Electric Power Generating ELGs

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%)

1,640 b

(74%)

528,000

(71%)

Combined Cycle System 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 87,700 e

Combined Cycle Single Shaft (steam 

and combustion turbines sharing a 

single shaft) f

22 49 9,570 - - -

Combined Cycle Combustion Turbine 411 1,013 134,000 404 570 125,000 g

Total 1,179

(100%)

2,467 g

(100%)

780,000

(100%)

1,079 h

(100%)

2,214 g

(100%)

741,000

(100%)

Source: Steam Electric Survey [ERG, 2015a]; 2009 EIA [U.S. DOE, 2009].

Note: Capacity values are rounded to three significant figures.

Note: The number of plants, generating units, and capacity in the steam electric power generating industry generated from the Steam Electric Survey are based on 

reported values, which were scaled up to represent the industry as a whole using the industry-weighting factors discussed in Section 3.2.

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 reported 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 Power Generating 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. 

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.
Section 4—Steam Electric Industry Description

4-15

e – From the Steam Electric 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.

f – 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.

g – 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.

h – EPA identified another plant that began operation after the time period for the Steam Electric Survey, resulting in a total baseline population of 1,080 plants

for the ELG analyses.
Section 4—Steam Electric Industry Description

4-16

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
Section 4—Steam Electric Industry Description

4-17

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, 2015a].

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 power generating industry generated from the Steam Electric Survey are based on reported 

values, which were scaled up to represent the industry as a whole using the industry-weighting factors discussed in Section 3.2.

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. Of the 

plants that responded to the Steam Electric Survey, 716 plants reported operating at least one stand-alone steam turbine powered by either fossil or nuclear fuel

and 408 plants reported operating 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 ELGs

Overall Plant Capacity Range a

Total

0-100

MW

100-200 

MW

200-300 

MW

300-400 

MW

400-500 

MW >500 MW

Total Steam Electric Capacity 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 c

Percentage of Plants 9.6% 8.2% 6.6% 7.3% 5.7% 62.7% 100%

Source: Steam Electric Survey [ERG, 2015a].

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 power generating industry are based on values 

reported in the Steam Electric Survey, which were scaled to represent the industry as a whole using the industryweighting factors discussed in Section 3.2.

a – Overall plant steam electric capacity includes electricity produced by only steam electric generating units.

Electricity generated by non-steam-electric generating 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 generating 

capacity.

c – EPA identified another plant that began operation after the time period for the Steam Electric Survey, resulting 

in a total baseline population of 1,080 plants for the ELG analyses.

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

the Steam Electric Power Generating ELGs

Unit Capacity Range a

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 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, 2015a].

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 power generating 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 3.2.

a – The capacity presented within each size distribution is based on the capacity at the unit level.
Section 4—Steam Electric Industry Description

4-19

4.3 STEAM ELECTRIC WASTESTREAMS WITH NEW CONTROLS IN THE FINAL ELGS

This section describes the wastestreams generated by steam electric power plants for 

which EPA established new or revised discharge requirements for the ELGs. Section 4.4

discusses other wastestreams generated by the steam electric power generating industry for 

which EPA is not establishing new discharge requirements in the 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 lesser 

amounts of fly ash, approximately 20 to 30 percent of the ash generated. Many plants transport 

fly ash from the particulate collection system (i.e., collection hoppers) using water as the motive 

force, known as sluicing. This section presents an overview of fly ash transport water generated 

by the steam electric power generating industry.

As discussed in Section 4.2.1, flue gas contains entrained fly ash as it leaves the boiler. 

Steam electric generating units use three main particulate collection methods to remove fly ash 

from the flue gas: 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. These three collection methods are described below and Table 4-6 presents 

the number of coal- , petroleum coke-, and oil-fired units utilizing each of these collection 

methods.

Table 4-6. Fly Ash Collection Practices in the Steam Electric Power Generating Industry

in 2009

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 508-528 a 1,080-1,100 a 26-31

Source: Steam Electric Survey [ERG, 2015a]. 

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 power generating industry are based on values 

reported in the Steam Electric Survey, which were scaled to represent the industry as a whole using the industryweighting factors discussed in Section 3.2.

a – Fifteen coal-fired generating units at nine 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 only.

To remove the fly ash particles from the flue gas, many plants operate ESPs, which 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, 
Section 4—Steam Electric Industry Description

4-20

some plants may use agglomerating agents, such as ammonia, 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 power 

generating industry. Of the approximately 1,100 coal-, petroleum coke-, and oil-fired units in the 

industry that reported collecting fly ash in the Steam Electric Survey, about 830 units (75 

percent) utilize an ESP system [ERG, 2015a].21

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 are captured on the inside walls of the

baghouse. As the baghouses collect more particulates, the layer of particulates becomes thicker 

and helps 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 (22 

percent) use baghouse filters [ERG, 2015a].22

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 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 power generating industry in more detail.

Additionally, between 15 and 25 generating units use venturi-type wet scrubbers to 

remove fly ash from the flue gas [ERG, 2015a]. 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 

 21 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.

22 This includes 10 to 15 generating units that use a combination system comprising an ESP and baghouse filters to 

remove particulates from the flue gas.
Section 4—Steam Electric Industry Description

4-21

remove the same level of particulates as ESPs, making their operation costs higher than ESPs 

[Babcock & Wilcox, 2005]. EPA does not consider the ash collected by venturi-type wet

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. In 2009, approximately one-third of the coal- and 

petroleum-fired generating units handled at least a portion of their fly ash with a wet-sluicing 

system. A small percentage (about 20 percent) of oil-fired units also handled at least a portion of 

their fly ash with a wet-sluicing system. 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 Steam Electric 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 Power Generating 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 32

(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, 2015a]. 

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 power generating industry are based on values 

reported in the Steam Electric Survey, which were scaled to represent the industry as a whole using the industryweighting factors discussed in Section 3.2.

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 includes only the plants that provided responses to 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 with dry fly ash 
Section 4—Steam Electric Industry Description

4-22

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, 2015a].

Figure 4-5. Plant-Level Fly Ash Handling Systemsin the Steam Electric Power Generating

Industry in 2009

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 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.

From the Steam Electric Survey data, EPA identified 45 to 55 plants that have installed 

dry fly ash handling systems, either to replace the current wet handling system or to operate as a 

parallel system, between 2000 and 2009. Table 4-8 presents the number of generating units that

converted from wet fly ash handling to dry fly ash handling between 2000 and 2009 identified in 

the Steam Electric Survey. Each plant and generating 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 
Section 4—Steam Electric Industry Description

4-23

described in Section 7. Data from the Steam Electric Survey show that, as of 2009, power 

companies converted at least 85 generating units at over 45 plants to dry fly ash handling 

systems since 2000. Power companies also reported in the Steam Electric Survey that they are 

planning to convert an additional 61 generating 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 power generating industry and the pollutant characteristics of 

the transport water.

Table 4-8. Conversions of Wet Fly Ash Sluicing Systems Between 2000 and 2009

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, 2015a].

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 power generating industry are based on values 

reported in the Steam Electric Survey, which were scaled to represent the industry as a whole using the industryweighting factors discussed in Section 3.2.

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 power generating industry.
Section 4—Steam Electric Industry Description

4-24

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 

hoppers positioned below the boiler. The bottom ash hoppers are connected directly to the boiler 

bottom to prevent any gases from leaving the boiler. Depending on the size of the boiler, there 

may be more than one 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 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 bottom 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 transport 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. Some plants operating wet bottom ash handling systems

can operate as closed-loop systems. These plants completely recycle the bottom ash transport 

water from impoundments, dewatering bins, or other handling systems back to the wet-sluicing 

system.

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 handled at least a portion of their bottom ash dry in 

2009.

23 These 112 plants represented 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 power generating 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 closed-loop recycle bottom ash handling systems.

 23 For the purpose of this discussion, dry bottom ash handling systems includes all systems that do not generate 

bottom ash transport water; these include completely dry bottom ash handling systems, mechanical drag systems, 

and other mechanical removal systems (e.g., scraping of bottom ash from boiler). Although a mechanical drag 

system may be used at a boiler that uses water in a quench bath to cool bottom ash, water is not used to transport the 

ash and thus it is considered, for the purpose of this report and the ELGs, to be a “dry” bottom ash system. Complete 

recycle and remote mechanical drag systems that use water to transport ash as part of the process are considered 

wet-sluicing systems. 
Section 4—Steam Electric Industry Description

4-25

Table 4-9. Bottom Ash Handling Practices in the Steam Electric Power Generating 

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 319 (62%) 863 286,000 (87%) 0-5 0-250 (1%)

Handled Dry a 

142 (28%) 214 39,900 (12%) 30-35

10,000-15,000 

(51%)

Handled Either Wet or Dry 26 (5%) 6 2,610 (1%) 0 0

No Handling System 

Reported 29 (5%) 12 1,400 (<1%) 57 11, 500 (48%)

Total 516 1,096 330,000 80-95 21,900-27,900 b

Source: Steam Electric Survey [ERG, 2015a].

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 power generating industry are based on values 

reported in the Steam Electric Survey, which were scaled to represent the industry as a whole using the industryweighting factors discussed in Section 3.2.

a – Dry bottom ash handling systems include all systems that do not generate bottom ash transport water; these

include 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 includes only the plants that responded to 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, 2015a].

Figure 4-6. Plant-Level Bottom Ash Handling Systems in the Steam Electric Industry

Table 4-10 presents the 12 to 25 plants within the industry that converted wet-sluicing 

bottom ash operations between 2000 and 2009, from Steam Electric Survey data. The generating 

units and plants are classified by type of dry system installed. Steam electric power 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 

generating units represent approximately 3 percent of the total number of steam electric 

generating units that were wet-sluicing bottom ash in 2000. In Steam Electric Survey data, power 

companies reported plans to convert an additional 67 generating 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 generating 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 power generating 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 Between 2000 and 2009

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, 2015a].

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 power generating industry generated from the 

Steam Electric Survey are based on reported values, which were scaled to represent the industry as a whole using the 

industry-weighting factors discussed in Section 3.2

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 coal- and petroleum coke-fired steam electric

power plants 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

Once-Through 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 two

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 four discharge 

any cleaning wastewater [ERG, 2015a]. 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 

ELGs.
Section 4—Steam Electric Industry Description

4-29

Wet FGD scrubber systems can remove over 90 percent, and in some cases up to 99 

percent, of the SO2 in the flue gas. In wet FGD scrubbers, the flue gas stream contacts a 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, 2015a].

Table 4-11 presents the distribution of wet and dry current and planned FGD systems 

based on plant reported data in the Steam Electric Survey. Table 4-12 shows the total scrubbed 

capacity of the steam electric generating units serviced in those systems.24 There are 401 current 

and planned FGD systems, servicing 458 coal-fired steam electric generating units.

25 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.

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 includes only the plants that 

provided responses to the Steam Electric Survey (i.e., the figure does not represent the weighted 

numbers).

 24 The total scrubbed capacity includes electric power generated by only those steam electric generating units 

serviced by an FGD system.

25 EPA incorporated company-verified steam electric generating unit retirements, fuel conversions, and wastewater 

treatment upgrades prior to implementation of final rule in EPA’s analyses, compliance cost estimates, and pollutant 

loadings for the ELGs (see Section 4.5).
Section 4—Steam Electric Industry Description

4-30

Table 4-11. Types of FGD Scrubbers in the Steam Electric Power Generating Industry

Type of Scrubber

“Wet” FGD Systems “Dry” FGD Systems

Number of Plants 

Number of 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, 2015a].

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 scrubbers.

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 of

Electric 

Generating 

Units

Scrubbed 

Capacity a

(MW)

Number of 

Plants

Number of 

Electric 

Generating 

Units

Scrubbed 

Capacity a

(MW)

Total 150 357 176,000 72 99 32,200

Coal Type

Bituminous 86 200 102,000 28 40 8,610

Subbituminous 28 63 33,400 29 40 16,900

Lignite 7 9 5,330 2 3 1,320

Petroleum Coke 1 1 184 0 0 0

Other/Waste Coal 0 0 0 1 1 585

Blend b 32 80 32,800 8 10 1,870

No Information c 4 4 2,420 5 5 2,850

Type of Oxidation System

Forced Oxidation 113 272 136,000 3 4 851
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 of

Electric 

Generating 

Units

Scrubbed 

Capacity a

(MW)

Number of 

Plants

Number of 

Electric 

Generating 

Units

Scrubbed 

Capacity a

(MW)

Inhibited Oxidation 17 34 19,600 2 3 1,480

Natural Oxidation 25 51 19,900 5 10 2,310

No Information or NA d 3 4 1,220 62 82 27,500

Sorbent

Lime 12 29 9,340 56 73 24,500

Limestone 122 286 144,000 14 20 6,660

Magnesium-Enhanced 

Lime 13 29 15,900 0 0 0

Magnesium Oxide 1 2 740 0 0 0

Soda Ash 3 9 1,870 0 0 0

Sodium Hydroxide 1 2 277 0 0 0

Other 5 12 6,030 14 24 6,380

No Information d 4 6 3,670 0 0 0

NOx Controls e

SCR 97 201 116,000 27 32 13,200

SNCR 13-23 35-40 11,500-12,500 12 14 4,070

None/Other (no 

SCR/SNCR) 58 113 46,300 30-40 45-50 13,500-14,000

No Information d 2 2 900 5 5 1,250

Source: Steam Electric Survey [ERG, 2015a]. 

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 150 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.

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

4-32

Source: Steam Electric Survey [ERG, 2015a].

Figure 4-8. Plants Operating Wet FGD Scrubber Systems in the Steam Electric Power 

Generating Industry in 2009

As shown in Table 4-12, limestone forced oxidation systems are the most common 

scrubbers reported in the Steam Electric 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 of 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 
Section 4—Steam Electric Industry Description

4-33

wastewater with CaSO3 just let the solids accumulate in the pond. These dewatering processes

generate a wastewater stream that the plant likely needs to treat before it is discharged or reused.

Plants that send the FGD blowdown directly to a pond typically do not use any other treatment 

prior to discharging the blowdown. 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 4-13 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 current and planned FGD systems, 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 the wet scrubbing capacity for earlier years for 

retired units may not be fully represented in the data set. However, based on 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, 2015a].

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 

the steam electric power generating industry. According to responses to the Steam Electric 

Survey, there are generally two types of systems being used to control flue gas mercury 

emissions:
Section 4—Steam Electric Industry Description

4-34

• Adding oxidizing agents to the coal prior to combustion, so that the wet FGD system 

removes the oxidized mercury.

• Injecting activated carbon into the flue gas, which adsorbs the mercury so that it is 

captured in a downstream particulate removal system.

Using the oxidizing agents does not generate a new wastewater stream. 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. See Section 6.4 for 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 use 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 Steam Electric Survey, there were approximately 120 

installed FGMC systems as of 2009, with an additional 40 new installations planned. 

Approximately 90 percent of those installed FGMC systems are dry systems that do not generate 

or affect any wastewater streams. Approximately 6 percent of the current operating systems are 

wet systems. The type of handling system (e.g., wet or dry handling) is unknown for the 

remaining 4 percent of the systems because they were planned FGMC systems at the time of the 

Steam Electric Survey.

26

4.3.5 Landfill and Impoundment Combustion Residual Leachate

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; FGD solids (e.g., 

gypsum and calcium sulfite); FGMC wastes; and 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 may 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 combustion residual 

leachate.

Combustion residual leachate is leachate from landfills or surface impoundments 

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

dissolved constituents in the liquid, that has percolated through or drained from waste or other 

materials emplaced in a landfill, or that passes through the surface impoundment’s containment 

structure (e.g., bottom, dikes, berms). Combustion residual leachate includes seepage and/or 

 26 EPA did not estimate incremental compliance costs for FGMC wastewater because, as described in Section 9.2.6, 

EPA determined that all plants operating sorbent injection systems to remove mercury from the flue gas already 

operate dry handling systems, operate wet systems that do not discharge, or have the capability to operate dry 

handling systems.
Section 4—Steam Electric Industry Description

4-35

leakage from a combustion residual landfill or impoundment unit. Combustion residual leachate 

includes wastewater from landfills and surface impoundments located on non-adjoining property 

when under the operational control of the permitted facility. Figure 4-10 presents a diagram 

depicting the generation and collection systems for landfill combustion residual leachate and 

stormwater. The two sources of landfill combustion residual leachate are precipitation that 

percolates through the waste deposited in the landfill and the liquids produced from the 

combustion residual placed in the landfill. Section 6.3 further discusses the characteristics of 

leachate.

Figure 4-10. Diagram of Landfill Combustion Residual Leachate Generation and 

Collection

In a lined landfill, the combustion residual 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 combustion residual 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 combustion 

residual 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 combustion residual leachate migrating away from the 

impoundment/landfill, which can potentially contaminate ground water and/or drinking water.
Section 4—Steam Electric Industry Description

4-36

Approximately 160 to 190 coal- and petroleum-fired steam electric power plants reported 

collecting combustion residual leachate from either an existing (i.e., active or inactive) 

impoundment and/or landfill. Table 4-14 presents a distribution of each management unit

(impoundment or landfill) collecting leachate and the year of installation based on information 

from Part A from the Steam Electric Survey. As shown in Table 4-13, the majority (52 percent) 

of landfills collect leachate, while only 13 percent of impoundments collect leachate. However, 

the table also demonstrates that recently installed landfills and impoundments are more likely to 

be lined and to collect leachate.

Table 4-13. Age of Impoundment or Landfill Collecting Combustion Residual Leachate

Management

Unit Installation 

Year

Landfills Impoundments

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

Insufficient Data 3 -- -- 15 -- --

Total 283 179 146 1,100 562 148

Source: Steam Electric Survey [ERG, 2015a]. 

Note: The number of impoundments and landfills in the steam electric power generating 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 3.2.

Once collected, the landfill or impoundment leachate can be recycled back into the 

management unit, recycled elsewhere within the plant, or discharged. Table 4-14 presents the 

destination of leachate collected from combustion residual impoundments and landfills. This 

table includes impoundments and landfills reported as producing leachate in Part F of the Steam 

Electric Survey, scaled to represent all industry operations. Therefore, the total number of 

impoundments and landfills with collected leachate differs from that presented in Table 4-13,

collected from Part A of the Steam Electric Survey. The Steam Electric Survey data from Part F 

indicates that 47 percent of combustion residual impoundment leachate and 28 percent of 

combustion residual landfill leachate is returned to the management unit.27 Plants generally 

discharge landfill leachate directly after collection, or treat the leachate on site and then 

discharge it after treatment.

 27 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 3.2, 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

4-37

Table 4-14. Destination of Combustion Residual Leachate in Steam Electric Power 

Generating Industry

Destination Number of Impoundments 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 a 21 (20%) 23 (18%)

Insufficient Data 7 --

Total b 110 126

Source: Steam Electric Survey [ERG, 2015a].

Note: The number of impoundments and landfills in this table are based on values reported in Part F of the Steam 

Electric Survey, which were scaled to represent the industry as a whole using the industry-weighting factors 

discussed in Section 3.2. The number of impoundments and landfills will not equal the numbers provided in Table 

4-13 because not all plants were provided Part F of the Steam Electric Survey.

a – "Other” includes perimeter drain with no flow, underground mine pool, and underground injection.

b – 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 and then clean the synthetic gas prior to 

combustion vary to some degree at the currently operating IGCC plants; however, each of these 

processes requires purging wastewater from the process to remove chlorides and other 

contaminants from the system.

As shown in Figure 4-4, there are several wastestreams generated as part of the 

gasification process. Additionally, there may be other wastewaters generated at IGCC plants that 

are not included in Figure 4-4 because they are not generated from the gasification process or

other processes directly linked to the gasification process (e.g., wastewater associated with sulfur 

recovery processes). The following is a list of the key wastewaters that are generally considered 

associated with the gasification process:

• 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.

• Sulfur recovery unit blowdown.

Other types of wastewater that may be present at an IGCC plant, but which are not 

considered gasification wastewater include:
Section 4—Steam Electric Industry Description

4-38

• Blowdown from the heat recovery steam generator blowdown.

• Coal/petroleum coke pile runoff.

• Metal cleaning wastes.

• Air separation unit blowdown.

• Service water filtration backwash.

• Demineralizer system reject.

• Cooling water.

Depending on the design of the plant, wastewaters not associated with the gasification 

process are typically handled similarly to how they are managed at conventional pulverized coalfired power plants. For example, coal/petroleum coke pile runoff is typically transferred to a 

surface impoundment and then discharged. However, these streams may also be recycled back to 

the slurry preparation system and sent back to the gasifier. Both IGCC plants identified as 

operating in 2009 treat gasification wastewaters in a vapor-compression brine concentrator. . See 

Section 6.5 for more information on the characteristics of gasification wastewater.

4.4 STEAM ELECTRIC WASTESTREAMS SELECTED FOR NEW CONTROLS IN THE FINAL 

ELGS

This section describes the wastestreams generated by steam electric power plants for 

which EPA did not establish new discharge requirements for the ELGs.

4.4.1 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 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, 

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 Steam Electric Survey use 

steam or service air to blow soot, some plants may generate wastewater streams. Air heater

cleaning is another frequent cleaning activity. About 66 percent of the units perform this 

operation at least once every 2 years, while other units perform this cleaning task very 
Section 4—Steam Electric Industry Description

4-39

infrequently, only once every 40 years. Generally, plants use intake or potable water to clean the 

air heater [ERG, 2015a]. 

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.

• Superheater cleaning.

EPA proposed to establish new requirements for non-chemical metal cleaning waste

equal to previously established BPT limitations for metal cleaning waste. The proposal was 

based on EPA’s understanding, from industry survey responses, that most steam electric power 

plants manage their chemical and non-chemical metal cleaning waste in the same manner. Since 

then, the Agency has learned that plants refer to the same operation using different terminology; 

some classify non-chemical metal cleaning wastes as such while others classify it as low volume 

wastes. Because the survey responses reflect each plant’s individual nomenclature (i.e., nonchemical metal cleaning wastes versus low volume wastes), the survey results for non-chemical 

metal cleaning wastes are skewed. 

Therefore, the final rule continues to “reserve” new requirements for non-chemical metal 

cleaning wastes, as the previously promulgated regulations did. By reserving limitations and 

standards for non-chemical metal cleaning waste in the final rule, the permitting authority must 

establish such requirements based on best professional judgment for any steam electric power 

plant discharging non-chemical metal cleaning wastes. As part of this determination, EPA 

expects that the permitting authority would examine the historical permitting record for the 

particular plant to determine how discharges of non-chemical metal cleaning wastes had been 

permitted in the past, including whether such discharges had been treated as low volume waste 

sources or metal cleaning wastes. 
Section 4—Steam Electric Industry Description

4-40

4.4.2 Carbon Capture Wastewater

Steam electric power plants have considered alternatives available for reducing carbon 

emissions. There are three main approaches for capturing the carbon dioxide (CO2) associated 

with generating electricity: post-combustion, 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 

wouldform CO2 “lakes”).

• 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 its sampling program, EPA obtained analytical data from two wastestreams 

generated from a post-combustion carbon capture pilot-scale system. The pilot-scale 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 water vapor present. 

The flow rate of the flue gas condensate stream ranged from 2,600 to 9,900 gpd during sampling. 

Table 4-15 presents the concentrations of the pollutants measured during the EPA sampling 

program. The concentrations presented are the 4-day average concentrations.
Section 4—Steam Electric Industry Description

4-41

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 that could be used as a 

fertilizer [Lohner, 2010]. The condensate from the evaporation process could be reused in other 

plant processes or discharged to surface water.

Table 4-15. 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)

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)
Section 4—Steam Electric Industry Description

4-42

Table 4-15. Carbon Capture Wastewater 4-Day Average Concentration Data

Analyte Unit

4-Day Average Concentration

PVF Bleed Stream Flue Gas Condensate

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 samplespecific 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 Steam Electric Survey responses, there are no full-scale carbon capture 

systems operating in the industry. There are, however, two pilot-scale systems that have been 

tested, the one for which EPA collected the analytical data presented in Table 4-15 (currently 

shut down and inactive) and another one that has been decommissioned.

4.5 CHANGES IN STEAM ELECTRIC INDUSTRY POPULATION

Although EPA used Steam Electric Survey data to generate the demographics of the 

steam electric power generating industry presented in this section, the Agency recognizes that 

plant operations may have changed since plants submitted responses in 2009. These changes 

might be due to updated or new wastewater treatment practices, ash handling practices, changes 

in the type of fuel used, or plant or generating unit retirements. EPA also identified changes in 

plant operations from other rulemakings affecting the steam electric power generating industry. 

In order to explain how these changes have an impact on the numbers presented in the remaining 

sections of this document, such as the compliance costs and pollutant loading estimates presented 

in Section 9 and Section 10, EPA grouped them into the following categories:

• Plants or generating units expected to upgrade wastewater treatment technologies, 

convert to dry or closed-loop fly and/or bottom ash handling, convert to different fuel 

sources, or retire, verified by EPA from company sources (Updated Industry Profile 

Population).

• Plants expected to convert to dry handling or upgrade wastewater treatment 

technologies as a result of the coal combustion residual (CCR) rule (CCR 

Population).

• Plants or generating units expected to retire as a result of the Clean Power Plan (CPP)

(CPP Population).

EPA incorporated the updates to the industry profile into the data presented in the 

remainder of this document. EPA also incorporated the updates to the industry profile into the 
Section 4—Steam Electric Industry Description

4-43

estimates of compliance costs, pollutant loadings, and other analyses as appropriate. 28 Further, 

EPA also incorporated impacts from the CCR and CPP rulemakings into the estimates of

compliance costs, pollutant loadings, and other analyses as appropriate. 

4.5.1 Updated Industry Profile Population

The BAT limitations for the ELGs do not begin to apply until a date determined by the 

permitting authority that is as soon as possible beginning November 1, 2018 (approximately 3

years following promulgation of the final rule), and they must be achieved by December 31, 

2023 (approximately 8 years from the promulgation of this rule). Therefore, EPA’s analysis of 

the regulatory options considered for the ELGs included all plants subject to the previously 

established ELGs, accounting for plant/unit retirements and fuel conversions expected to occur 

prior to implementation of the final rule. EPA’s analyses reflect that all generating units with 

company-announced retirements or fuel conversions prior to implementation of the final rule 

would not incur compliance costs, nor would they discharge FGD wastewater or ash transport 

water.29 EPA has a high degree of confidence that the identified retirements and fuel conversions 

will occur because were factored into the analyses only if they could be verified by information 

directly from the plant operating company or a government entity. Because these retirements and 

fuel conversions are scheduled to occur prior to implementation of the ELGs, EPA determined 

there are no incremental costs or pollutant removals associated with these generating units. 

In addition, EPA incorporated changes into its analyses for plants that announced they 

were planning to convert to a dry or closed-loop ash handling system (ash handling conversion).

EPA determined that for such ash handling conversions scheduled to occur prior to 

implementation of the final rule, the plant would not incur compliance costs for ash transport 

water from the respective generating unit nor would it discharge ash transport water from the 

converted ash handling system.30 The specifics of how EPA incorporated these plant operation 

changes into the analyses are explained in the “Changes to Industry Profile for Steam Electric 

Generating Units for the Steam Electric Effluent Guidelines Final Rule” (Industry Profile 

Changes Memo) [ERG, 2015b]. In August 2015, EPA conducted a review of all plants in the 

Updated Industry Profile Population to confirm that all announced retirements and fuel 

conversions have occurred or are still planned to occur. EPA confirmed more than 95 percent of 

 28 EPA determined that steam electric generating units would incur zero or reduced compliance costs or pollutant 

removals associated with the ELGs if the steam electric generating unit retired, converted fuels, updated ash 

handling practices, or updated wastewater treatment practices prior to the implementation of the ELGs. However, 

EPA only included industry profile changes that were substantiated by information directly from the operating 

company or government entity, either through an article, report, or press release. While EPA considered industry 

profile changes provided in public comments, only those industry profile changes that could be verified were 

included in EPA’s analyses.

29 EPA accounted for all retirements and fuel conversions announced and verified as of August 2014 in the analyses. 

Any retirements or fuel conversions identified after that date were too late to be fully factored into all analyses; 

however, EPA did consider any retirements or fuel conversions identified between August 2014 and June 2015 in a 

sensitivity analysis. See EPA’s “Changes to Industry Profile for Steam Electric Generating Units for the Steam 

Electric Effluent Guidelines Final Rule” (“Industry Profile Changes Memo”) for more information [ERG, 2015b]. 30 EPA accounted for all ash handling conversions announced and verified as of August 2014 in the analyses. Any 

ash handling conversions identified after that date were too late to be fully factored into all analyses; however, EPA 

did consider ash handling conversions identified between August 2014 and June 2015 in a sensitivity analysis. See 

EPA’s Industry Profile Changes Memo for more information [ERG, 2015b].
Section 4—Steam Electric Industry Description

4-44

the retirements/fuel conversions and identified additional industry profile changes. The details of 

this analysis are provided in the “Evaluation of Verified Retirements in the Updated Industry 

Profile Population for the Steam Electric Effluent Guidelines Final Rule” [ERG, 2015c].

Generally, these updates to the industry profile result in a full or partial removal of the 

plant from the estimated compliance costs and/or pollutant loadings. For example, if the coalfired steam electric generating units retiring, converting fuel, and/or converting ash handling 

practices at Plant A affected all units at Plant A that would otherwise be included in the 

compliance costs and/or pollutant loadings analyses, Plant A was completely removed from the 

analyses (i.e., full removal). Conversely, a partial removal indicates that Plant B maintains at 

least one coal-fired steam electric generating unit expected to incur compliance costs and/or 

affect pollutant loadings under the ELGs. Table 4-16 displays the number of plants EPA 

identified as full or partial removals due to retirements/fuel conversions, bottom ash handling 

conversions, and/or fly ash handling conversions scheduled to occur no later than December 31, 

2023.

Table 4-16. Number of Plants Removed from ELG Compliance Costs and Pollutant 

Loadings Estimates Due to Updates to the Industry Profile

Type of Removal from 

Costs and/or Loadings

Retirement or Fuel 

Conversion Bottom Ash Conversion Fly Ash Conversion

Full 145 17 18

Partial 25 0 0

Total 170 17 18

Source: Industry Profile Changes Memo [ERG, 2015b].

Note: The numbers in this table reflect retirements and conversions identified prior to August 2014.

Note: Plants can be considered both a retirement and an ash conversion if some units are retiring and other units are 

converting. However, if EPA identified a plant with the same units retiring and converting, the plant is considered 

only a retirement. 

EPA incorporated changes into its compliance costs, pollutant loadings, and other 

analyses for plants that announced wastewater treatment upgrades. Specifically, three plants that 

upgraded their FGD wastewater treatment system since 2009 were given credit for FGD 

wastewater “treatment in place” when calculating plant compliance cost estimates, see Section 

9.4.1. Similarly, two plants that upgraded or are planning to update their coal combustion 

residual leachate treatment system after 2009 were given credit for “treatment in place,” see

Section 9.8.

31

4.5.2 CCR Population

EPA coordinated the requirements of the CCR rule and the ELGs to avoid establishing 

overlapping regulatory requirements and to facilitate the implementation of engineering, 

financial, and permitting activities. For the ELGs, EPA calculated compliance costs, pollutant 

 31 EPA accounted for all wastewater treatment upgrades announced and verified as of August 2014 in the analyses. 

Any wastewater treatment upgrades identified after that date were too late to be fully factored into all analyses; 

however, EPA did consider any wastewater treatment upgrades identified between August 2014 and June 2015 in a 

sensitivity analysis. See EPA’s Industry Profile Changes Memo for more information [ERG, 2015b].
Section 4—Steam Electric Industry Description

4-45

loadings/removals, and other analyses taking the effect of the CCR rule into account.32 For more 

information about how EPA incorporated the CCR rule into the ELG analyses, see Section 9. 

Table 4-17 presents the number of plants that are removed from compliance cost estimates and 

pollutant loadings for bottom ash transport water and/or fly ash transport water because they are 

determined to be converting to dry handling as a result of the CCR rule. Additionally, EPA 

identified adjustments to FGD compliance cost estimates and pollutant loadings due to 

wastewater treatment upgrades projected to result from plants implementing the CCR rule, as 

well as adjustments to ash compliance cost estimates and pollutant loadings to reflect changes in 

CCR storage handling practices that would result from implementing the CCR rule; however, 

these adjustments do not change the number of plants incurring costs for the ELGs. 

Note: Only includes plants that are removed from compliance costs or pollutant loadings to reflect changes resulting 

from the CCR rule prior to implementing the ELGs. Therefore, if a plant was already removed to reflect the Updated 

Industry Profile Population, the plant is not included in this table.

4.5.3 CPP Population

The CPP establishes limits on emissions to reduce carbon pollution from steam electric 

power plants. EPA projects that as plants take steps to implement the CPP, some plants may 

retire one or more generating units prior to the unit(s) having to implement the ELGs. To account 

for this, EPA incorporated projected CPP retirements into EPA’s compliance cost estimates, 

pollutant loadings, and other analyses for the ELGs. For more information about how EPA 

incorporated the CPP into the ELG analyses, see Section 9. Similar to the Updated Industry 

Profile Population described in Section 4.5.1, EPA classified CPP retirements as partial or full

removals. Table 4-18 presents the number of plants that are either partially or fully removed 

from the cost and pollutant removal estimates due to retirements projected to result from 

implementing the CPP.

Note: Only includes plants that are removed from compliance costs to reflect implementation of the CPP. Therefore, 

if a plant was already removed to reflect the Updated Industry Profile Population or implementation of the CCR rule 

(i.e., CCR Population), the plant is not included in this table.

 32 EPA also conducted additional analyses to estimate what the costs and pollutant removals for the ELGs would be 

in the absence of the CCR rule.

Table 4-17. Number of Plants Removed from ELG Compliance Costs and Pollutant 

Loadings Estimates Due to Implementation of the CCR Rule

Total for Regulatory Option D Bottom Ash Fly Ash

27 23 12

Table 4-18. Number of Plants Removed from ELG Compliance Costs Due to 

Implementation of the CPP

Type of Removal

Total for

Regulatory 

Option D

Bottom Ash Fly Ash FGD IGCC 

Full 47 38 3 18 1

Partial 19 15 5 9 0

Total 66 53 8 27 1
Section 4—Steam Electric Industry Description

4-46

4.6 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. ERG. 2009. Final Site Visit Notes: Duke Energy’s Wabash River Generating 

Station. (October 20). DCN SE02095.

3. ERG. 2011. Final Site Visit Notes: TECO Energy’s Polk Power Station. (March 2). 

DCN SE00071.

4. ERG. 2012. Final Power Plant Monitoring Data Collected Under Clean Water Act 

Section 308 Authority (“CWA 308 Monitoring Data”). (May 30). DCN SE01326.

5. ERG. 2015a. Steam Electric Technical Questionnaire Database (“Steam Electric 

Survey”). (30 September). DCN SE05903.

6. ERG. 2015b. “Changes to Industry Profile for Steam Electric Generating Units for 

the Steam Electric Effluent Guidelines Final Rule” (“Industry Profile Changes 

Memo”). (30 September). DCN SE05069.

7. ERG. 2015c. “Evaluation of Verified Retirements in the Updated Industry Profile 

Population for the Steam Electric Effluent Guidelines Final Rule”. (30 September).

DCN SE05702.

8. Lohner, Tim. 2010. Email to Ron Jordan of U.S. EPA from Tim Lohner of AEP. 

(December 6). DCN SE01335.

9. Southern Company. 2015. Kemper County Energy Facility. Available online at: 

http://www.southerncompany.com/what-doing/energy-innovation/smartenergy/smart-power/kemper.cshtml. DCN SE05086.

10. USCB. 2007. U.S. Census Bureau. Electric Power Generation, Transmission, and 

Distribution: 2007 Economic Census Utilities Industry Series. A vailable online at:

http://www.census.gov/econ/census07/. DCN SE01802.

11. U.S. DOE. 2006. U.S. Department of Energy. Introduction to Nuclear Power. 

Energy Information Administration (EIA). Available online at: 

http://www.eia.doe.gov/cneaf//page/intro.html. Date accessed: August 2006. DCN 

SE01803.

12. U.S. DOE. 2009. Annual Electric Generator Report (collected via Form EIA-860). 

EIA. Available online at: http://www.eia.doe.gov/cneaf//page/eia860.html. DCN 

SE01805.

13. U.S. DOE. 2012a. Energy Information Administration (EIA). Electric Power 

Industry Overview. Available at: 

http://www.eia.gov/cneaf/electricity/page/prim2/chapter1.html. Accessed on April 

23, 2012. DCN SE03252.

14. U.S. DOE. 2012b. U.S. Department of Energy. Energy Information Administration. 

Glossary. Available at http:// www.eia.gov/tools/glossary/. Accessed on April 23, 

2012. DCN SE01806.

15. U.S. DOE. 2012c. U.S. Department of Energy. Energy Efficiency and Renewable 

Energy - Geothermal Technologies Program. Available online at: 
Section 4—Steam Electric Industry Description

4-47

http://www1.eere.energy.gov/al/faqs.html and 

http://www1.eere.energy.gov//powerplants.html. DCN SE01804.

16. U.S. DOE. 2014. National Energy Technology Laboratory. Proposed Gasification 

Plant Database. Web. Mar. 2015. Available online at: 

http://www.netl.doe.gov/research/coal/energy-systems/gasification/gasificationplant-databases. DCN SE05642.

17. U.S. EPA. 2006. U.S. Environmental Protection Agency. Characterization of 

Mercury-Enriched Coal Combustion Residues from Electric Generating Utilities 

using Enhanced Sorbents for Mercury Control. (February). DCN SE01339.
Section 5—Industry Subcategorization

5-1

SECTION 5

INDUSTRY SUBCATEGORIZATION

This section presents information about factors EPA considered in evaluating whether 

different effluent limitations or standards are warranted for certain facilities in the Steam Electric 

Power Generating Point Source Category (Steam Electric Category). Section 5.1 describes why 

EPA considers factors that could lead to establishing different requirements for certain facilities 

in the category and presents background on the industry categorization established in the 1974 

and 1982 effluent limitations guidelines and standards (ELGs) rulemakings. Section 5.2 presents 

the factors considered in detail and the analyses EPA performed to review whether 

subcategorization was appropriate for establishing the ELGs for this category.

5.1 SUBCATEGORIZATION FACTORS

The Clean Water Act (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 best available control technology economically available (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 Power Generating ELGs do not divide plants or process 

operations into subcategories, although they do include different requirements for cooling water 

discharges from plants smaller than 25 MW generating capacity [U.S. EPA, 1974; U.S. EPA, 

1982]. For this final rule, EPA evaluated whether different effluent requirements should be 

established for certain plants within the Steam Electric 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, geographic 

location, size, fuel type, and processes employed 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 assessed the influence of age, geographic location, size, fuel type, and processes 

employed (e.g., scrubber and boiler type) 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 evaluation. For additional 

information on the specific analyses performed as part of the evaluation, see the memorandum 

entitled “Steam Electric Effluent Guidelines – Evaluation of Potential Subcategorization 

Approaches” [ERG, 2015a].
Section 5—Industry Subcategorization

5-2

5.2.1 Age of Plant or Generating Unit

EPA analyzed the age of the plants and the generating units included in the scope of the 

rule and determined that the age 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 the final rule. For example, although the “zero discharge” NSPS for fly ash 

transport water was not promulgated until 1982 and prior to that date most generating units were 

built with wet fly ash handling systems, EPA determined that many generating units have since 

converted their wet handling systems to dry fly ash handling. As a result, most generating units 

now use dry handling or are in the process of converting to dry fly ash handling. The age of the 

generating unit does not hinder the ability to retrofit dry fly ash systems, and the data in the 

record show that the majority of the steam electric generating units that retrofitted to dry fly ash 

handling are at least 30 years old [ERG, 2015a]. 

Based on data presented in the Steam Electric Survey, more than 80 percent of generating 

units built in the last 20 years installed dry bottom ash handling at the time of construction. In 

addition, many generating units originally built with wet-sluicing systems have converted or are 

in the process of converting to dry or closed-loop bottom ash handling. The age of the generating 

unit does not hinder the ability to retrofit to a dry or closed-loop system, and the data in the 

record show that the majority of the steam electric generating units that retrofitted to dry bottom 

ash handling are at least 30 years old [ERG, 2015a]. 

EPA determined that the age of plants and steam electric generating units also does not 

impact the plants’ ability to install the FGD wastewater treatment technologies that are the basis 

for the BAT/PSES effluent limits because the treatment system for the FGD wastewater is 

distinctly separate from the generating unit. EPA reviewed the age of plants, with available age 

data, that operate chemical precipitation followed by biological treatment to treat FGD 

wastewater and determined that each of the plants are at least 20 years old, and one of the plants 

is more than 50 years old. Additionally, based on available age data, EPA determined that plants 

operating evaporation systems are at least 25 years old, and one of the plants is at least 45 years 

old [ERG, 2015a]. 

EPA also evaluated whether plants might choose to retire older generating units rather 

than install retrofits to comply with the revised ELGs, but did not find that to be the likely 

outcome. EPA analyzed the impacts that the ELGs may have on the steam electric industry using 

the Integrated Planning Model (IPM) and estimated that the requirements associated with the 

ELG would have the net effect of two generating unit (partial) closures and one steam electric 

generating plant (full) closure, for a net change of 843 MW. EPA determined that the majority 

(over 80 percent) of coal- and oil-fired steam electric generating units are over 30 years old. EPA 

determined that the generating units predicted to retire are also over 30 years old. These 

generating units represent a small percentage of the operating generating units that are over 30 

years old and, given that many other generating units more than 30 years old are projected to 

continue operating, the age of the plant or generating unit is not a significant factor. Therefore, 

EPA did not establish subcategories based solely on the age of the plant or generating unit for 

this final rule.
Section 5—Industry Subcategorization

5-3

5.2.2 Geographic Location

EPA analyzed the geographic location of steam electric 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 the final rule. Wet flue gas desulfurization (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 

the final rule. 

For example, a plant in the southern United States would be able to install and operate the 

chemical precipitation and biological treatment system that is the BAT technology basis for 

controlling discharges of FGD wastewater. Because of the warm climate, plants in southern 

states may find it appropriate 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. Additionally, a plant in the northern United 

States will be able to install and operate the chemical precipitation and biological treatment 

system, the BAT technology basis for controlling discharges of FGD wastewater, and the remote 

mechanical drag system (MDS) closed-loop bottom ash handling system, the BAT technology 

basis for controlling discharges of bottom ash transport water. EPA’s compliance cost estimates 

account for costs to address climate concerns in the northern United States (e.g., costs to keep the 

FGD wastewater temperature at ideal operating conditions and costs to protect the remote MDS 

from adverse weather conditions). 

Based on the information in the public 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 (new source 

performance standards) treatment technologies, EPA determined that subcategories based on 

plant geographic location are not warranted.

5.2.3 Size

EPA analyzed the size (i.e., nameplate generating capacity in megawatts (MW)) of the 

steam electric generating units 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, so do the discharge flows of ash transport water. In general, this is to be expected 

because the larger the generating unit, the more fuel it consumes, which generates more ash, and 

the more water it uses in the water/steam thermodynamic cycle [ERG, 2015b]. 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 limitations for a class of existing generating units based on size. 
Section 5—Industry Subcategorization

5-4

Section 8 discusses in detail EPA’s establishment of different limitations and standards for 

certain existing generating units based on their size.

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 Questionnaire for the Steam Electric Power 

Generating Effluent Guidelines (Steam Electric Survey), EPA determined that 74 percent of the 

steam electric generating units in the industry burn more than one type of fuel (e.g., coal and oil, 

coal and gas). Some of these generating units may burn only one fuel at a time, but burn both 

types of fuels during the year. Other generating units may burn multiple fuels at the same time. 

In cases where a generating unit burns multiple fuels at the same time, it would be impossible to 

separate the wastestreams by fuel type [ERG, 2015b].

EPA did not identify any basis for subcategorizing gas-fired and nuclear generating units. 

These generating units generally manage their process wastestreams in the same manner as other 

steam electric generating units. However, based on responses to the Steam Electric Survey, there 

are some oil-fired generating units that generate and discharge fly ash and/or bottom ash 

transport water. For these reasons, EPA looked carefully at oil-fired generating units. As a result, 

EPA determined that, in certain circumstances, it is appropriate to apply different limits to

existing oil-fired generating units. Section 8 discusses in detail EPA’s establishment of different 

limitations and standards for existing oil-fired generating units.

5.2.5 Processes Employed

EPA analyzed different processes employed at plants, including the FGD scrubber and 

boiler type, included in the scope of this rule. Specifically, EPA used data from the Steam 

Electric Survey and the detailed study to compare characteristics of once-through FGD systems 

to recirculating systems and to determine if the type of system affects the plant’s ability to install 

and operate the FGD treatment technologies evaluated as part of the final rule. Based on the 

comparison, EPA found that there is no distinguishable difference between the two types of 

systems related to materials of construction, operating chloride levels, and flow rates (i.e., slurry 

blowdown flow rates for the once-through FGD systems are within the range of the FGD purge 

flow rates for recirculating systems). Additionally, EPA compared analytical data for untreated 

FGD wastewater from once-through and recirculating systems. Based on the comparison of total 
Section 5—Industry Subcategorization

5-5

metals concentrations, EPA found that all pollutants in untreated FGD wastewater from oncethrough FGD systems were within the range of pollutant concentrations for FGD wastewater 

from recirculating systems. Therefore, EPA determined that subcategories based on scrubber 

type are not warranted [ERG, 2015a].

EPA also analyzed data in the Steam Electric Survey to determine if the steam electric 

generating unit boiler type, specifically cyclone and circulating fluidized bed (CFB) boilers, 

affects plants’ ability to install and operate the bottom ash handling treatment technologies 

evaluated as part of the final rule. Based on Steam Electric Survey data, EPA determined that 

there are plants with cyclone and CFB boilers that collect and manage bottom ash with an MDS. 

Additionally, based on vendor contacts, EPA determined that remote MDS conversions are 

suitable for these boiler types because the traditional wet-sluicing system is still operated to 

collect and transport bottom ash to the remote MDS. Therefore, EPA determined that 

subcategories based on boiler type are not warranted.

5.3 REFERENCES

1. ERG. 2015a. Memorandum to the Steam Electric Rulemaking Record. Steam 

Electric Effluent Guidelines – Evaluation of Potential Subcategorization 

Approaches.” (September 30). DCN SE05813.

2. ERG. 2015b. Steam Electric Technical Questionnaire Database (“Steam Electric 

Survey”). (September 30). DCN SE05903.

3. U.S. EPA. 1974. U.S. Environmental Protection Agency. Development Document 

for Effluent Limitations Guidelines and New Source Performance Standards for the 

Steam Electric Power Generating Point Source Category. Washington, DC. 

(October). DCN SE02917.

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) Section 308 sampling data, and industry- and state-submitted plant 

monitoring data on wastewater generation practices associated with the steam electric power 

generating industry. EPA used plant responses from the Questionnaire for the Steam Electric 

Power Generating Effluent Guidelines (Steam Electric Survey) to identify the population of 

plants that generate and discharge in 2009 the wastestreams for which EPA is finalizing new or 

revised effluent limitations and standards. These wastestreams include flue gas desulfurization 

(FGD) wastewater, fly and bottom ash transport water, combustion residual leachate, flue gas 

mercury control (FGMC) wastewater, and gasification wastewater. Similar to Section 4, EPA 

used the weighted Steam Electric Survey results to represent the steam electric power generating 

industry in 2009 because they provide more complete information about power plant operations. 

Additionally, EPA characterized these wastestreams based on sampling, plant-monitoring, and 

other industry data. Sections 6.1 through 6.6 provide details on wastewater generation rates and 

provide characterization data for the untreated process wastewater, where available. Section 6.6

identifies the pollutants of concern (POCs) related to this rulemaking.

6.1 FGD WASTEWATER

EPA used the responses from Part B of the Steam Electric Survey to develop the list of 

plants operating FGD systems. Plants reported information on FGD systems in operation as of 

2009 and planned FGD systems through 2020. EPA included plants with FGD systems in 

operation as of 2009 and planned systems reported in the Steam Electric Survey33 to accurately 

reflect the potential compliance costs and pollutant removals associated with the final rule. This 

section describes the amount of FGD wastewater generated by these FGD systems and discusses 

the characteristics of FGD wastewater.

Wet FGD scrubber systems are classified into two categories, recirculating wet FGD 

systems and once-through 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, called FGD slurry blowdown, is transferred away from the 

scrubber. The slurry blowdown stream undergoes solids separation, and the wastewater is either 

recycled back to the scrubber or transferred to a wastewater treatment system as FGD scrubber 

purge. In a once-through system, all of the FGD slurry at the bottom of the scrubber 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 once-through systems, 

any gypsum wash water, and water generated from the solids separation/dewatering process. 

Table 6-1 summarizes FGD slurry blowdown flow rates for plants with FGD systems that 

generate slurry blowdown. In 2009, a typical steam electric power plant generated on average 2.1 

million gallons per day (MGD) of FGD slurry blowdown. As described previously, the FGD 

 33 EPA included FGD systems reported in the Steam Electric Survey to be in operation as of January 1, 2014 (i.e., 

those expected to be built between 2010 and 2013).
Section 6—

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6-2

slurry blowdown undergoes solids separation/dewatering before being transferred to treatment or 

is recycled back to the scrubber.

Table 6-1. FGD Slurry Blowdown Flow Rates for the Steam Electric Power Generating 

Industry in 2009

Number of 

Plants

Average Flow 

Rate

Median Flow 

Rate

Range 

of Flow Rate

Flow Rate per Plant

Gallons per day (gpd)/plant 150 2,100,000 1,110,000 3,300 – 24,200,000

Source: Steam Electric Survey [ERG, 2015a].

Note: Wastewater flow rates are rounded to three significant figures.

Note: The number of plants generating FGD slurry blowdown is based on values reported in the Steam Electric 

Survey for operations in 2009, which were scaled to represent the industry as a whole using the industry-weighting 

factors discussed in Section 3.2. The reported values do not account for changes in the industry since 2009.

Note: EPA did not have sufficient information in the Steam Electric Survey to determine the generation flow rates 

for 13 plants. Although EPA included these plants in the count of plants generating FGD wastewater, EPA did not 

include them in the determination of the average, median, or range of generation flow rates in the table.

As described in Section 4.3.3, the FGD wastewater generated by wet FGD systems is 

removed as slurry blowdown to purge chlorides from the system. The FGD slurry blowdown is 

typically generated intermittently. The factors that can affect the flow rate of the FGD 

wastewater generated at the plant include the type of coal used, scrubber design and operating 

practices, solids separation process, and solids dewatering process. 

The type of coal burned at the plant can affect the FGD wastewater flow rate. Generally, 

a plant burning a higher sulfur coal generates higher FGD wastewater flow rates. Higher sulfur 

coals produce more sulfur dioxide (SO2) in the combustion process, which in turn increases the 

amount of SO2 removed in the FGD scrubber. As a result, more solids are generated in the 

reaction in the scrubber, which increases the frequency at which FGD wastewater is removed 

from the system.

Likewise, using 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 system. As the FGD system recirculates the water in the system, the chlorides 

build up within the scrubber. As the chloride concentration begins approaching the maximum 

allowable limit for the specific material of construction of the FGD system, the plant purges 

some of the wastewater to remove the chlorides from the 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 affects the pollutant 

concentrations in the FGD wastewater [Babcock & Wilcox, 2005]. Based on information 

collected from the EPA sampling program, these chloride concentrations do not impact the 

treatability of FGD wastewater.
Section 6—

Wastewater Characterization and Pollutants of Concern

6-3

Pollutant concentrations in FGD wastewater can also vary to some degree 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 recirculation in the scrubber, 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 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 sorbent and type of oxidation the FGD system used (i.e., forced oxidation, inhibited 

oxidation, natural oxidation) affects the species of pollutants present in the FGD wastewater. 

According to the Electric Power Research Institute (EPRI), forced oxidation systems generate 

selenium species that are mostly present as selenate whereas natural and inhibited oxidation 

systems generate selenium species that are mostly present as selenite [EPRI, 2006]. The FGD 

wastewater characteristics presented later in this section represent data from plants operating 

limestone forced oxidation systems. EPA focused the sampling program on plants operating 

limestone forced oxidation systems because most plants operate these systems (as shown in 

Table 4-12. Natural or inhibited oxidations systems use other types of sorbents (e.g., lime, maglime) and generally do not discharge FGD wastewater. They either operate complete-recycle 

systems or the water is evaporated in evaporation ponds or consumed during a pozzolanic 

reaction.

The FGD system operation and materials of construction in the FGD system affect the 

types of pollutants in the wastewater. Using organic acid additives contributes to biochemical 

oxygen demand (BOD5) in the FGD wastewater. Additionally, the oxidation-reduction potential 

(ORP) of the FGD scrubber affects the overall wastewater characteristics. EPA evaluated the 

effects of ORP on the treatability of FGD wastewater, and concluded that these effects can be 

controlled, as described in Section 7.1.3. 

The materials of construction and the other FGD system operations could 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 of the steam electric power generating industry, 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 slurry blowdown continuously and 

potentially at a larger flow rate compared to plants that do recirculate the FGD water. EPA 

compared wastewater characteristics from FGD slurry blowdown at once-through FGD systems 

to FGD scrubber purge wastewater characteristics at recirculating FGD systems to determine 

whether the operations generate different wastewater characteristics. EPA compared data from 

Widow’s Creek (representing once-through FGD systems) to the monitoring data submitted in 

Part B Section 6 of the Steam Electric Survey for FGD slurry blowdown and to data EPA 

collected during the EPA sampling program and CWA 308 monitoring program for FGD 

scrubber purge wastewater from recirculating systems. Although once-through systems operate 

differently from recirculating systems, EPA determined that wastewater characteristics for oncethrough FGD systems fall within the concentration range observed for recirculating FGD 

systems and pollutants are present at treatable levels [ERG, 2015b]. Because of the larger flow 
Section 6—

Wastewater Characterization and Pollutants of Concern

6-4

rate associated with the once-through systems, EPA also evaluated all plants with larger FGD 

wastewater flow rates (i.e., greater than or equal to 1,000 gpm) to determine if the FGD system 

could accommodate the buildup of additional chlorides associated with recirculating the FGD 

wastewater back to the FGD system. For more information on this analysis, see Section 4.5.2 of 

EPA’s Incremental Costs and Pollutant Removals for Final Effluent Limitation Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category Report [ERG, 

2015c].

The air pollution controls operated upstream of the FGD system can also affect the FGD 

wastewater characteristics. For example, if a plant does not operate a particulate collection 

system (e.g., electrostatic precipitator, or ESP) upstream of the FGD system, the 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 may 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. 

Comparing the data from the EPRI report for the untreated FGD wastewater from these two 

different units, EPA determined that the concentrations of mercury and selenium did not differ. 

Nitrate-nitrite as N and total suspended solids (TSS) concentrations are higher in FGD 

wastewater for the generating unit that operates the ESP; however, the concentration of arsenic is 

higher for the unit that does not operate the ESP [EPRI, 1998a; EPRI, 1998b]. Therefore, those

plants operating FGD systems without an ESP may have higher arsenic concentrations present in 

their FGD wastewater. Nonetheless, based on the information from its sampling program, EPA 

determined that arsenic is treated to low levels in the chemical precipitation technology selected 

as part of the BAT technology basis for control of FGD wastewater, regardless of the influent 

concentrations entering the system.

Research conducted by EPA’s Office of Research and Development (ORD) has shown 

that using post-combustion 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 residuals (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 post-combustion NOx controls are 

operating [U.S. EPA, 2008]. As part of its sampling program, EPA collected samples from four 

plants operating SCRs during the sampling, one plant operating SNCRs during the sampling, and 

two plants that were not operating the SCR/SNCR during the sampling. EPA compared the 

influent FGD wastewater characteristics from these plants to evaluate whether operating the NOx

control systems led 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 at the time. 

Additionally, EPA found that the concentrations of ammonia and nitrate-nitrite as N are not 

significantly different for the plants operating NOx controls compared to the plants not operating 
Section 6—

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6-5

NOx controls.34 While the ammonia and nitrate-nitrite as N concentrations were higher for some 

of the plants operating NOx controls compared to the plants not operating NOx controls, some 

plants operating NOx controls had lower concentrations of ammonia and nitrate-nitrite as N 

compared to plants not operating NOx controls.

Table 6-2 summarizes the FGD wastewater discharged by the steam electric power 

generating industry. EPA estimates 100 coal- and petroleum coke-fired plants discharge FGD 

wastewater out of the 150 plants operating wet FGD systems. Collectively, these plants are 

expected to discharge 16.1 billion gallons of FGD wastewater per year, with an average total 

industry daily discharge of 0.45 MGD per plant. The amount of FGD wastewater discharged by 

the steam electric power generating industry is less than the amount of blowdown it generates by 

the industry, as shown in Table 6-1, because some plants recycle FGD blowdown from the 

scrubber to use as FGD preparation water and in other non-FGD plant processes (e.g., ash 

transport water). Table 6-2 also presents the distribution of FGD wastewater discharged based on 

type of coal used. 

Table 6-2. FGD Wastewater Discharges for the Steam Electric Power Generating 

Industry in 2009

Number of Plants Discharging 

Average Discharged 

Wastewater Flow

(gpd/plant)

Total 100 451,000

Coal Type a

Bituminous 64 488,000

Subbituminous 15-20 157,000

Lignite 1-5 525,000

Blend b 10-15 555,000

Source: Steam Electric Survey [ERG, 2015a].

Note: Wastewater flow rates are rounded to three significant figures.

Note: Certain fields contain ranges of values to protect the release of information claimed confidential business 

information (CBI).

Note: The number of plants discharging FGD wastewater is based on values reported in the Steam Electric Survey

for operations in 2009, which were scaled to represent the industry as a whole using the industry-weighting factors 

discussed in Section 3.2. The reported values do not account for changes in the industry since 2009.

Note: EPA did not have sufficient information in the Steam Electric Survey to determine discharge flow rates for 

two plants. Although EPA included these plants in the count of plants discharging FGD wastewater, EPA did not 

include them in the determination of the average discharge flow rate.

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'.

 34 EPA evaluated the ammonia and nitrate-nitrite as N concentrations because ammonia is injected into the flue gas 

as part of the operation of the SCR/SNCR; therefore, EPA had hypothesized that there might be higher 

concentrations of these pollutants in the FGD wastewater for plants operating these systems.
Section 6—

Wastewater Characterization and Pollutants of Concern

6-6

As discussed in Section 3.4, EPA conducted on-site sampling activities as part of its 

sampling program and required a subset of plants to collect additional data under the CWA 

Section 308 monitoring program to characterize the FGD wastewater from steam electric power 

plants. To supplement its data collection activities, EPA also received plant monitoring data 

through public comments, plant-specific data requests, and requests to state authorities, which 

are described in Sections 3.5 and 3.6. EPA used sampling data and plant monitoring data to 

characterize the untreated FGD wastewater generated by the steam electric power generating 

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 chloride, sulfate, total dissolved 

solids (TDS), TSS, and bioaccumulative pollutants such as arsenic, mercury, and selenium. 

Additionally, pollutants such as boron, calcium, 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

Average Dissolved 

Concentration a

Classicals

Ammonia as Nitrogen mg/L 13.1 NA

Nitrate-Nitrite as N mg/L 91.4 NA

Nitrogen, Kjeldahl mg/L 34.9 NA

Biochemical Oxygen Demand mg/L 8.18 NA

Chemical Oxygen Demand mg/L 345 NA

Chloride mg/L 7,180 NA

Sulfate mg/L 13,300 NA

Cyanide, Total mg/L 0.733 NA

Total Dissolved Solids mg/L 33,300 NA

Total Suspended Solids mg/L 14,500 NA

Phosphorus, Total mg/L 4.02 NA

Metals, Metalloids, and other Nonmetals

Aluminum ug/L 331,000 1,470 

Antimony ug/L 28.9 3.87 

Arsenic ug/L 507 7.07 

Barium ug/L 2,750 284 

Beryllium ug/L 17.5 2 

Boron ug/L 242,000 266,000 

Cadmium ug/L 127 128 

Calcium ug/L 3,290,000 2,050,000 

Chromium ug/L 1,270 4.17 

Hexavalent Chromium ug/L NA 4.76 

Cobalt ug/L 245 206 

Copper ug/L 673 20.1 

Iron ug/L 566,000 100 
Section 6—

Wastewater Characterization and Pollutants of Concern

6-7

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

Analyte Unit

Average Total 

Concentration

Average Dissolved 

Concentration a

Lead ug/L 315 1.00

Magnesium ug/L 3,250,000 3,370,000 

Manganese ug/L 85,700 106,000 

Mercury ug/L 289 7.19 

Molybdenum ug/L 273 136 

Nickel ug/L 1,490 973 

Selenium ug/L 3,130 1,130 

Silver ug/L 8.18 1.00

Sodium ug/L 2,520,000 276,000 

Thallium ug/L 22.1 15.1 

Tin ug/L 164 100 

Titanium ug/L 4,300 10 

Vanadium ug/L 1,300 13.4 

Zinc ug/L 4,110 1,580 

Source: Steam Electric Analytical Database for the Final Rule [ERG, 2015d].

NA - Not applicable. Samples were not analyzed for this particular analyte.

Note: Concentrations are rounded to three significant figures.

a – EPA calculated the average concentrations based on various data sets available for untreated FGD wastewater 

(as described in Section 3). As a result of using various data sets, the average dissolved concentrations presented in 

the table may be higher than the total concentrations; however, the pollutant concentrations for untreated FGD 

wastewater are not used in EPA’s loadings calculations.

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 power generating industry.

This section also discusses the characteristics of fly ash and bottom ash transport water and the 

amount of ash transport water discharged to surface water.

6.2.1 Fly Ash Transport Water

Fly ash transport water is one of the largest wastewater sources 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 
Section 6—

Wastewater Characterization and Pollutants of Concern

6-8

generate less fly ash, and therefore, may generate fly ash transport water intermittently.35,36

Table 6-4 presents the fly ash transport water flow rates generated by steam electric power 

plants. The fly ash transport water flow rate is the amount of the fly ash transport water that is 

pumped with the fly ash to the impoundment over time; however, it is not necessarily the same 

as the amount of fly ash transport water discharged to surface water due to evaporation, 

infiltration, recycle, or other processes (see Section 6.2.3). The steam electric power generating 

industry generated 209 billion gallons of fly ash transport water in 2009, with the average plant 

generating 4.27 MGD.

Table 6-4. Fly Ash Transport Water Flow Rates for the Steam Electric Power Generating 

Industry in 2009

Number of 

Plants

Average Flow 

Rate

Median Flow 

Rate

Range 

of Flow Rate

Flow Rate per Plant

gpd/plant 145-150 4,270,000 2,140,000 4,000-35,700,000

Source: Steam Electric Survey [ERG, 2015a].

Note: Wastewater flow rates are rounded to three significant figures.

Note: Certain fields contain ranges of values to protect the release of information claimed confidential business 

information (CBI).

Note: The number of plants generating transport water is based on values reported in the Steam Electric Survey for 

operations in 2009, which were scaled to represent the industry as a whole using the industry-weighting factors 

discussed in Section 3.2. The reported values do not account for changes in the industry since 2009.

Note: EPA did not have sufficient information in the Steam Electric Survey to determine generation flow rates for 

nine plants. Although EPA included these plants in the count of plants generating fly ash transport water, EPA did 

not include them in the determination of the average, median, or range of generation flow rates in the table.

Additionally, some plants reported that they generated fly ash transport water but may not have specified a wet ash 

handling system in another part of the Steam Electric Survey (see Table 4-7). EPA included these plants in its 

determination of the generation rates presented in this table.

6.2.2 Bottom Ash Transport Water

Bottom ash transport water is an intermittent stream from steam electric generating 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 

reported by the industry. The bottom ash transport water flow rate is the amount of the bottom 

ash transport water that is pumped with the bottom ash to the impoundment over time; however, 

it is not necessarily the same as the amount of bottom ash transport water discharged to surface 

water due to evaporation, infiltration, recycle, or other processes (see Section 6.2.3). Although 

the average daily flow rate per plant is approximately 40 percent less than the average fly ash 

transport water flow rate presented in Table 6-4, there are significantly more plants generating 

bottom ash transport water than those generating fly ash transport water. The industry generated 

 35 A baseload unit is a generating unit normally operating to produce electricity at an essentially constant rate. The 

unit will typically run for extended periods of time.

36 A peaking unit is a generating 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

297 billion gallons of bottom ash transport water in 2009, with the average plant generating 2.49 

MGD.

Table 6-5. Bottom Ash Transport Water Flow Rates for the Steam Electric Power 

Generating Industry in 2009

Number of 

Plants

Average Flow 

Rate

Median Flow 

Rate Range of Flow Rate

Flow Rate per Plant

gpd/plant 348 2,490,000 1,030,000 3,150-34,600,000

Source: Steam Electric Survey [ERG, 2015a].

Note: Wastewater flow rates are rounded to three significant figures.

Note: The number of plants generating transport water is based on values reported in the Steam Electric Survey for 

operations in 2009, which were scaled to represent the industry as a whole using the industry-weighting factors 

discussed in Section 3.2. The reported values do not account for changes in the industry since 2009.

Note: EPA did not have sufficient information in the Steam Electric Survey to determine generation flow rates for 

22 plants. Although EPA included these plants in the count of plants generating bottom ash transport water, EPA did 

not include them in the determination of the average, median, or range of generation flow rates in the table.

Additionally, some plants reported that they generated bottom ash transport water but may not have specifed a wet 

ash handling system in another part of the Steam Electric Survey (see Table 4-9). EPA included these plants in its 

determination of the generation rates presented in this table.

6.2.3 Ash Transport Water Characteristics

Fly ash and bottom ash transport waters are typically treated in large surface 

impoundment systems that sometimes comprise multiple impoundments. These impoundments 

often receive other plant wastewaters along with fly and/or bottom ash transport water. 

Additionally, plants operating both wet fly ash and wet bottom ash handling systems will often 

send both fly ash and bottom ash transport waters to the same surface impoundment system. 

Some plants recycle part or all of the surface impoundment effluent, but most plants discharge 

the overflow. Untreated ash transport waters contain significant concentrations of TSS and 

metals. The effluent from ash surface impoundments generally contains low concentrations of 

TSS; however, metals are still present in the effluent, predominantly in dissolved form.

Surface 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. The wastewater must reside in the impoundment long enough to 

settle the desired particle size. Surface impoundments can effectively reduce TSS in ash transport 

water, particularly bottom ash transport water, which contains relatively dense ash particles. 

They also effectively remove some metals from ash transport water when the metals are present 

in suspended particulate form.

The discharge flow rates from the impoundments are not the same as ash transport water 

flow rates. The ash transport water flow rate is the amount of the fly and bottom ash transport 

water that is pumped with the ash to the impoundment over time, while the discharge flow is the 

amount of the overflow water that is discharged from the impoundment or recycled. 

Impoundments typically receive wastestreams in addition to bottom ash and fly ash transport 

waters (e.g., boiler blowdown, cooling water, low volume wastewater). In addition, the 
Section 6—

Wastewater Characterization and Pollutants of Concern

6-10

impoundment overflow rate is reduced by 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, respectively. On average, a single plant 

discharges approximately 3.5 MGD of fly ash transport water and approximately 2.1 MGD of

bottom ash transport water. Therefore, on average, the steam electric power generating industry 

discharges approximately 81 percent of all fly ash transport water generated and 82 percent of all 

bottom ash transport water generated. Section 7 discusses surface impoundment management 

practices in place in the steam electric power generating industry.

Table 6-6. Ash Wastewater Discharge for the Steam Electric Power Generating Industry 

in 2009

Type of Wastewater Number of Plants Discharging

Average Discharged Wastewater Flow

(gpd/plant)

Fly Ash 113 3,480,000

Bottom Ash 283 2,050,000

Source: Steam Electric Survey [ERG, 2015a].

Note: Wastewater flow rates are rounded to three significant figures.

Note: The number of plants and discharge flow rates in the steam electric power generating industry are based on 

values reported in the Steam Electric Survey for operations in 2009, which were scaled to represent the industry as a 

whole using the industry-weighting factors discussed in Section 3.2. The reported values do not account for changes 

in the industry since 2009.

Note: In 2009, 76 plants combined 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, EPA calculated a 

median percentage of total flow for both fly and bottom ash sluice and used the percentages to calculate a fly and 

bottom ash contribution for all combined ash wastewater flows. The median fly ash wastewater contribution is 60.3 

percent and the median bottom ash contribution is 39.7 percent.

The design, operation, and maintenance of impoundments in the steam electric power 

generating industry vary 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 impoundment effluent to control the pH of the discharge. The 

Steam Electric Power Generating Effluent Limitations Guidelines and Standards (ELGs) limit 

the pH of all 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 collected a wastewater sample representing the influent to a fly ash impoundment at 

the Cardinal plant during EPA’s detailed study of the industry. EPA also used industry-supplied 

data and publicly available data sources, including data received during public comments, to 

characterize fly ash and bottom ash transport water, including samples representative of 

untreated/raw ash transport water, partially treated ash transport water, and ash impoundment 

effluent. The data set of untreated ash transport samples is very small and typically represents 
Section 6—

Wastewater Characterization and Pollutants of Concern

6-11

some amount of settling37. Based on the information EPA collected, fly ash transport water 

generally contains TSS, TDS, sulfate, chloride, sodium, calcium, copper, and selenium. Bottom 

ash transport generally contains TSS, TDS, sulfate, sulfite, chloride, and metals, including 

sodium, calcium, and magnesium.

6.3 COMBUSTION RESIDUAL LEACHATE FROM LANDFILLS AND SURFACE IMPOUNDMENTS

Plants generating FGD wastewater and ash transport water generally send the wastewater 

to a surface impoundment or wastewater treatment system. The FGD solids and ash sent to a 

surface impoundment may be stored permanently in the impoundment or dredged from the 

impoundment and transferred to a landfill. Solids collected in FGD wastewater treatment 

systems are typically disposed of in a landfill. Additionally, plants may send the fly ash, bottom 

ash, and FGD residuals (i.e., gypsum or calcium sulfite) directly to a landfill without first 

sending them to a surface impoundment. Water that comes in contact with the combustion 

residuals that are stored in these management units will be contaminated by metals and other 

contaminants present in the combustion residuals. As discussed in Section 4.3.5, combustion 

residual leachate includes the liquid and any suspended or dissolved constituents in the liquid 

that has percolated through or drained from waste or other materials placed in a landfill, or that 

passes through the containment structure (e.g., bottom, dikes, berms) of a surface impoundment. 

Combustion residual leachate includes seepage and/or leakage from a combustion residual 

landfill or impoundment unit and also includes wastewater from landfills and surface 

impoundments located on non-adjoining property when under the operational control of the 

permitted facility. The following section describes the estimated amount of combustion residual 

leachate generated by the steam electric power generating industry and the characteristics of this 

wastestream.

Part F of EPA’s Steam Electric Survey requested information on the management

practices of both impoundments and landfills containing combustion residuals, including 

information about how the combustion residual leachate is collected and treated. As described in 

Section 3.2, EPA sent Part F to a subset of coal- and petroleum coke-fired power plants, and used 

information from this subset to estimate the total number of plants in the steam electric power 

generating industry generating combustion residual leachate. Table 6-7 presents the total 

estimated number of plants generating leachate in the steam electric power generating industry 

from either an active or inactive impoundment or landfill. As defined in the survey, an inactive 

landfill or impoundment is a management unit that is currently not r;eceiving waste but is still 

capable of receiving waste in the future and therefore, subject to the final rule. EPA estimates 

that, in 2009, 150 to 200 coal-fired and petroleum coke-fired steam electric plants generated on 

average 0.57 MGD per plant of combustion residual leachate.

 37 Due to the limited amount of untreated ash transport water data available, EPA also used partially treated and 

treated ash transport water samples for the identification of pollutants of concern, as described later in Section 6.6.4. 
Section 6—

Wastewater Characterization and Pollutants of Concern

6-12

Table 6-7. Combustion Residual Leachate Flow Rates for the Steam Electric Power 

Generating Industry in 2009

Combustion 

Residual 

Management 

Unit 

Unit 

Operating 

Status

Number of 

Plants a

Average Flow 

Rate

Median Flow 

Rate Range of Flow Rate

Flow Rate per Plant (gpd/plant)

Landfill Active/Inactive 110-120 239,000 202,000 11,700-1,480,000

Impoundment Active/Inactive 100-110 826,000 176,000 170-7,880,000

Total 150-200 574,000 157,000 693-7,880,000

Source: Steam Electric Survey [ERG, 2015a].

Note: Wastewater flow rates are rounded to three significant figures.

Note: Certain fields contain ranges of values to protect the release of information claimed confidential business 

information (CBI).

Note: Part F of the Steam Electric Survey was distributed to 97 plants. The responses from these plants were 

weighted to reflect the number of plants and the volume of leachate generated in the industry. The number of plants 

generating leachate is based on values reported in the Steam Electric Survey for operations in 2009, which were 

scaled to represent the industry as a whole using the industry-weighting factors discussed in Section 3.2. The 

reported values do not account for changes in the industry since 2009.

Note: EPA did not have sufficient information in the Steam Electric Survey to determine the generation flow rates 

for 31 plants collecting combustion residual leachate from landfills and 32 plants collecting combustion residual 

leachate from impoundments. Although EPA included these plants in the count of plants generating combustion 

residual leachate, EPA did not include them in the determination of the average, median, or range of generation flow 

rates in the table.

a – Some plants may have more than one landfill or impoundment management unit.

Table 6-8 presents the number of coal-fired and petroleum coke-fired plants that discharged 

combustion residual leachate in 2009. The amount of combustion residual leachate discharged by 

the steam electric power generating industry is less than the amount of combustion residual 

leachate generated, as shown in Table 6-1 through Table 6-7. The combustion residual leachate 

collected is generally transferred to a collection impoundment. Once collected, the combustion 

residual leachate can be recycled back into the management unit or recycled elsewhere within the 

plant, sent to an on-site treatment system, or discharged. More than half of the plants generating 

combustion residual leachate from surface impoundments recycle the wastestream [ERG, 

2015a]. Section 7.4 provides more detail on the types of leachate treatment technologies.

Table 6-8. Combustion Residual Leachate Discharged for the Steam Electric Power 

Generating Industry in 2009

Combustion Residual 

Management Unit

Unit Operating 

Status

Number of 

Plants

Average Discharged Wastewater Flow

(gpd/plant)

Landfill Active/Inactive 90-100 70,000-80,000

Impoundment Active/Inactive 30-40 70,000-80,000

Total 100-110 80,000-90,000

Source: Steam Electric Survey [ERG, 2015a].

Note: Wastewater flow rates are rounded to three significant figures.
Section 6—

Wastewater Characterization and Pollutants of Concern

6-13

Note: Certain fields contain ranges of values to protect the release of information claimed confidential business 

information (CBI).

Note: The number of plants and discharge flow rates in the steam electric power generating industry are based on 

values reported in the Steam Electric Survey for operations in 2009, which were scaled to represent the industry as a 

whole using the industry-weighting factors discussed in Section 3.2. The reported values do not account for changes 

in the industry since 2009.

Note: EPA did not have sufficient information in the Steam Electric Survey to determine the discharge flow rates for 

one plant collecting combustion residual leachate from landfills and two plants collecting combustion residual 

leachate from impoundments. Although EPA included these plants in the count of plants discharging combustion 

residual leachate, EPA did not include them in the determination of the average discharge flow rate.

As part of the Steam Electric Survey, EPA requested that a subset of plants provide 

sampling data for untreated landfill and/or impoundment leachate collected at the plant. EPA 

received data from active and inactive landfills and impoundments, which were used to 

characterize the combustion residual leachate generated by the steam electric power generating 

industry. Table 6-9 presents the average pollutant concentrations for combustion residual 

leachate, which represents both landfills and impoundments. Combustion residual leachate 

contains concentrations of chloride, sulfate, TDS, TSS, calcium, sodium, and magnesium that are 

at least one magnitude higher than other pollutants in the wastestream. The pollutants in the 

leachate are generally at lower concentrations than those seen in FGD wastewater and ash 

transport water. 

Table 6-9. Average Pollutant Concentrations of Combustion Residual Leachate 

Analyte Units Average Total Concentration 

Classicals

Chloride ug/L 413,000 

Sulfate ug/L 1,790,000 

TDS ug/L 3,500,000 

TSS ug/L 35,800 

Metals, Metalloids, and other Nonmetals

Aluminum ug/L 2,990 

Antimony ug/L 3.75 

Arsenic ug/L 38.4 

Barium ug/L 53.2 

Beryllium ug/L 1.33 

Boron ug/L 22,400 

Cadmium ug/L 10.1 

Calcium ug/L 408,000 

Chromium ug/L 2,120 

Cobalt ug/L 38.6 

Copper ug/L 7.58 

Iron ug/L 37,100 

Lead ug/L 2.37 

Magnesium ug/L 118,000 

Manganese ug/L 2,720 
Section 6—

Wastewater Characterization and Pollutants of Concern

6-14

Table 6-9. Average Pollutant Concentrations of Combustion Residual Leachate 

Analyte Units Average Total Concentration 

Mercury ug/L 1.06 

Molybdenum ug/L 1,380 

Nickel ug/L 46.5 

Selenium ug/L 111 

Silver ug/L 1.63 

Sodium ug/L 308,000 

Thallium ug/L 1.16 

Tin ug/L 49.3 

Titanium ug/L 13.6 

Vanadium ug/L 1,910 

Zinc ug/L 211 

Source: Steam Electric Survey [ERG, 2015a].

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 to control flue gas 

mercury emissions: adding oxidizing agents to the coal prior to combustion and injecting 

activated carbon into the flue gas after combustion. Adding oxidizing agents prior to combustion 

does not generate a new wastewater stream; however, activated carbon injection (ACI) systems 

have the potential to generate a FGMC wastestream, depending on the location of the sorbent 

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.

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 and fly ash can either be handled using a wet-sluicing system or a dry 

handling system. 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 and installed after 2009. Of these 15 plants, only one planned to handle the FGMC waste 

using a wet-sluicing system; however, this plant planned to send the FGMC waste to a zero 

discharge impoundment, where the impoundment overflow will be reused for fly ash, bottom 

ash, and FGMC transport water [ERG, 2015a].

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 and installed after 2009. Of these 58 plants, five (three 
Section 6—

Wastewater Characterization and Pollutants of Concern

6-15

with current systems and two with planned systems) reported handling the FGMC waste using a 

wet-sluicing system. 

EPA’s 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]. ORD looked at six plants, four operating ACI systems and two operating 

brominated ACI systems.38 ORD collected fly ash from these plants, with and without FGMC 

waste, and analyzed it 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 6-10 shows the distribution 

of mercury concentrations at each of the six plants. 

Table 6-10. 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, there are several wastestreams generated at integrated 

gasification combined cycle (IGCC) plants that comprise gasification wastewater. Figure 4-4

depicts the general process flow diagram for the IGCC process. Gasification wastewater includes 

wastewater from all sources of an IGCC process (except those for which specific limitations or 

standards are otherwise established). Gasification wastewater includes, but is not limited to 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; and 

 38 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

6-16

sulfur recovery unit blowdown. Air separation unit blowdown and runoff from fuel and/or 

byproduct piles are not considered gasification wastewater.

As part of the CWA 308 monitoring program described in Section 3.4.1, EPA collected 

data 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 an evaporation system. Both plants sampled the influent 

streams transferred to the evaporation system and the distillate/condensate(s) from the systems. 

EPA used the influent data from both plants to characterize untreated gasification wastewater. 

Table 6-11 provides the individual average concentrations of the untreated gasification 

wastewater for the two plants, as well as the combined average for both plants. 

Table 6-11. Untreated Gasification Wastewater Concentrations

Analyte Units

Polk 

Concentration

Wabash River 

Concentration

Average Polk and

Wabash River 

Concentration

Classicals

Ammonia as Nitrogen 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, Metalloids, and Other Nonmetals

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

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
Section 6—

Wastewater Characterization and Pollutants of Concern

6-17

Table 6-11. Untreated Gasification Wastewater Concentrations

Analyte Units

Polk 

Concentration

Wabash River 

Concentration

Average Polk and

Wabash River 

Concentration

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: Steam Electric Analytical Database for the Final Rule [U.S. EPA, 2015d].

6.6 POLLUTANTS OF CONCERN

Constituents present in combustion wastewater are primarily derived from the parent 

carbon feedstock (e.g., coal, petroleum coke). EPA evaluated the combustion wastewater 

characteristics generated by the industry and identified POCs for each of the regulated 

wastestreams. The POC analysis preferentially uses samples of untreated wastewater; however, 

where EPA lacked data on specific pollutants, it supplemented the dataset with partially treated 

or treated samples as appropriate for the wastestream. 

The extent of data available to characterize each of the regulated wastestreams varies.

EPA conducted a field sampling program and Steam Electric Survey as part of the rulemaking 

efforts for the Steam Electric Power Generating ELGs and in part, from the detailed study 

preceding these efforts. EPA also collected data from industry and from publicly available 

sources. Combined, EPA used these data sources to characterize the wastestreams generated by 

the industry. EPA subjected all data to the data quality review criteria for sampling data, 

questionnaire data, and secondary data, as described in the “Development Memorandum for 

Steam Electric Analytical Database for the Final Rule” [ERG, 2015e]. EPA reviewed each data 

source to determine if the data met EPA’s criteria for use in characterizing in-process 

wastestreams for the purpose of identifying POCs. The following general criteria applied across 

all wastestreams: 

• Sample must be representative of typical full-scale plant operations (e.g., not samples 

of wastewater evaluated on a pilot or bench scale).

• Sample descriptions and locations must be unambiguous and clearly described such 

that it can be categorized by wastestream type (e.g., FGD purge, bottom ash 

impoundment influent) and by level of treatment (e.g., untreated, partially treated). 

For fly ash and bottom ash transport water wastestreams, the sample location must 

comprise at least 75 percent by volume fly ash or bottom ash transport water.
Section 6—

Wastewater Characterization and Pollutants of Concern

6-18

• Sample analysis must be completed using accepted analytical methods for 

wastewater.

• Sample results must contain sufficient information (e.g., non-detects must contain 

method detection limits or quantitation limits, data qualifiers where needed, 

information to identify units). 

• Source water sample data that are paired with wastewater sample data must be taken 

within a day the wastewater sample collection date. 

• Data must not be duplicative of other accepted data. Where duplicate data exists (e.g., 

submitted by a trade association representing individual plants and also submitted by 

the individual plant), EPA used only accepted data collected from the individual 

plant. 

The following sections discuss the POCs identified for each of the regulated 

wastestreams, and where relevant, any additional data editing criteria EPA applied to develop the 

data set used for the analysis. The POCs identified for each wastestream are used as the basis for 

calculating pollutant loadings, described in Section 10, and the selection of regulated pollutants, 

described in Section 11.

6.6.1 FGD Wastewater POCs

As described in ERG’s memorandum FGD Wastewater, Combustion Residual Leachate, 

and Gasification Wastewater Pollutants of Concern (POC) Analysis Methodology [ERG, 2015f],

EPA reviewed data sources containing information on untreated FGD wastewater using the 

general data quality review criteria described earlier in this section. EPA used the following data 

sources that met the criteria to identify POCs in untreated FGD wastewater [U.S. EPA, 2015f]:

• EPA Field Sampling Program. As part of the sampling program, EPA collected four 

samples of untreated FGD wastewater from seven steam electric power plants 

operating FGD wastewater treatment systems. EPA analyzed a total of 28 samples for 

38 analytes. Section 3.4.1 discusses the analytes evaluated in the EPA sampling 

program. 

• EPA CWA 308 Monitoring Program. EPA required eight plants to participate in the 

CWA 308 monitoring program and required each plant to collect three to four

samples of untreated FGD wastewater. EPA analyzed a total of 31 samples for 37 

analytes (not including hexavalent chromium). 

• Steam Electric Public Comments on the Proposed Rulemaking. EPA received 

analytical data on untreated FGD wastewater from one plant as part of their public 

comment submission. The plant submitted analytical results representing a total of 

159 samples for arsenic, mercury, and selenium. 

• EPA Data Requests. In EPA’s data requests to specific plants for information on FGD 

wastewater treatment, three plants submitted analytical data on untreated FGD 

wastewater. The plants submitted analytical results representing a total of 189

samples for ammonia, arsenic, mercury, nitrate-nitrite as N, and selenium. 
Section 6—

Wastewater Characterization and Pollutants of Concern

6-19

For wastestreams where the final rule establishes numeric effluent limits, the POCs are 

those pollutants that have been quantified in a wastestream at sufficient frequency at treatable 

levels (concentrations). EPA reviewed data for the untreated FGD wastewater to identify 

pollutants detected at greater than or equal to 10 times the quantitation limit in at least 10 percent 

of all samples. 

EPA used the sample-specific quantitation limit as an indicator of the pollutants present 

in FGD wastewater because it provides a direct comparison to the sample result. The quantitation 

limit is sample-specific and accounts for analytical adjustments made in the determination of the 

sample result. Additionally, using 10 times the quantitation limit as a screening threshold ensures 

the influent concentrations are high enough to quantify the degree of pollutant removal following 

treatment processes. EPA used all available untreated FGD wastewater data that met the data 

acceptance criteria in the POC analysis except seven samples, which did not contain quantitation 

limits. Table 6-12 lists the 31 POCs identified for FGD wastewater. 

Table 6-12. Pollutants of Concern – FGD Wastewater

Pollutant Group Pollutant of Concern

Conventional Pollutants Total Suspended Solids

Priority Pollutants

Antimony

Arsenic

Beryllium

Cadmium

Chromium

Copper

Cyanide, Total

Lead

Mercury

Nickel

Selenium

Thallium

Zinc

Nonconventional Pollutants

Aluminum

Ammonia as Nitrogen

Barium

Boron

Calcium

Chloride

Cobalt

Iron

Magnesium

Manganese

Molybdenum

Nitrate Nitrite as N
Section 6—

Wastewater Characterization and Pollutants of Concern

6-20

Table 6-12. Pollutants of Concern – FGD Wastewater

Pollutant Group Pollutant of Concern

Phosphorus

Sodium

Titanium

Total Dissolved Solids

Vanadium

Source: FGD Wastewater, Combustion Residual Leachate, and Gasification Wastewater Pollutants of Concern 

(POC) Analysis Methodology [ERG, 2015f].

Note: Oil and grease is regulated under the previously promulgated best practicable control technology currently 

available (BPT) for low volume waste sources, which covered FGD wastewater. EPA did not collect data for oil and 

grease and does not have data available to identify it as a POC for FGD wastewater.

6.6.2 Combustion Residual Leachate POCs

As part of the Steam Electric Survey, EPA required a subset of plants to sample their 

leachate from impoundments and landfills containing combustion residuals. EPA used the 

combustion residual leachate data collected from the survey responses to identify POCs for the 

wastestream. The data EPA used in the analysis included 246 samples for 30 analytes. EPA 

excluded data from retired or closed units for use in this analysis because combustion residual 

leachate from retired units is not regulated in the final rule. Similar to the POC analysis for FGD 

wastewater described in Section 6.6.1, EPA reviewed the data for untreated combustion residual 

leachate to identify pollutants detected at greater than or equal to 10 times the quantitation limit 

in at least 10 percent of all samples [ERG, 2015f]. Table 6-13 lists the 25 POCs identified for 

combustion residual leachate.
Section 6—

Wastewater Characterization and Pollutants of Concern

6-21

Table 6-13. Pollutants of Concern – Combustion Residual Leachate

Pollutant Group Pollutant of Concern

Conventional Pollutants Total Suspended Solids

Priority Pollutants

Antimony

Arsenic

Cadmium

Chromium

Copper

Mercury

Nickel

Selenium

Thallium

Zinc

Nonconventional Pollutants

Aluminum

Barium

Boron

Calcium

Chloride

Cobalt

Iron

Magnesium

Manganese

Molybdenum

Sodium

Sulfate

Total Dissolved Solids

Vanadium

Source: FGD Wastewater, Combustion Residual Leachate, and Gasification Wastewater Pollutants of Concern 

(POC) Analysis Methodology [ERG, 2015f].

Note: Oil and grease is regulated under the previously promulgated BPT for low volume waste sources, which 

covered combustion residual leachate wastewater. EPA did not collect data for oil and grease and does not have data 

available to identify it as a POC for combustion residual leachate.

6.6.3 Gasification Wastewater POCs

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 data for 

untreated gasification wastewater from these two steam electric power plants and all data, 20 

samples for 37 analytes, met the data acceptance criteria and were used to evaluate POCs. 

Similar to the POC analysis for FGD wastewater described in Section 6.6.1, EPA identified 

pollutants detected at greater than or equal to 10 times the quantitation limit in at least 10 percent 

of all samples [ERG, 2015f]. Table 6-14 lists the 34 POCs identified for gasification wastewater. 
Section 6—

Wastewater Characterization and Pollutants of Concern

6-22

Table 6-14. Pollutants of Concern – Gasification Wastewater

Pollutant Group Pollutant of Concern

Conventional Pollutants Biochemical Oxygen Demand

Total Suspended Solids

Priority Pollutants

Antimony

Arsenic

Beryllium

Cadmium

Copper

Lead

Mercury

Nickel

Selenium

Thallium

Cyanide, Total

Zinc

Nonconventional Pollutants

Aluminum

Ammonia as Nitrogen

Barium

Boron

Calcium

Chemical Oxygen Demand

Chloride

Cobalt

Iron

Magnesium

Manganese

Molybdenum

Nitrate Nitrite as N

Nitrogen, Kjeldahl

Sodium

Sulfate

Titanium

Total Dissolved Solids

Phosphorus, Total

Vanadium

Source: FGD Wastewater, Combustion Residual Leachate, and Gasification Wastewater Pollutants of Concern 

(POC) Analysis Methodology [ERG, 2015f].
Section 6—

Wastewater Characterization and Pollutants of Concern

6-23

6.6.4 Ash Transport Water POCs

As described in the memorandum, “Bottom Ash and Fly Ash Transport Water Pollutants 

of Concern (POC) Analysis Methodology” [ERG, 2015h], EPA reviewed data sources 

containing information on bottom ash transport water and fly ash transport water using the 

general data quality review criteria described earlier in this section, as well as more specific 

criteria listed in the memorandum. Bottom ash and fly ash transport water data primarily consist 

of secondary data sources. EPA did not collect data through the EPA field sampling program or 

the Steam Electric Survey. EPA’s review of the ash data sources is detailed in “Ash Analytical 

Data Review Memorandum” [ERG, 2015g].

EPA used the following data sources that met the criteria to identify POCs for bottom ash 

and fly ash transport water [ERG, 2015h]:

• Data Collected from Utilities. EPA received various forms of analytical data 

submitted from plants or electric power companies as part of the public comments on 

the proposed rulemaking and in responses to the Steam Electric Survey. Data 

submitted in public comment by Hoosier Energy and Duke Energy and survey data

submitted by Interstate Power and Light Company met EPA’s data acceptance criteria

and were used in the analysis. These data are: 

- 147 paired source water and fly ash pond samples from two plants. 

- 195 paired source water and bottom ash transport water samples from 7 plants.

- 5 non-paired bottom ash samples from one plant. 

• Industry Trade Association Data. EPA coordinated with UWAG to collect ash 

transport water data from its member companies that was submitted to EPA during 

the detailed study and in public comments on the proposed rulemaking. EPA also 

obtained reports containing ash transport water data from EPRI, including the Plant 

Integrated Systems: Chemical Emissions Studies (PISCES) Reports and other EPRIpublished reports provided by plants in responses to the Steam Electric Survey. Data 

accepted for the ash transport water POC analysis are: 

- 153 paired fly ash and source water samples from four plants. 

- 189 paired bottom ash and source water samples from eleven plants. 

- 260 non-paired fly ash samples from three plants.

- 16 non-paired bottom ash samples from eight plants.

• Previously Collected EPA Data. EPA collected data on ash transport water data

during the 1982 Steam Electric Rulemaking and during the 2009 Steam Electric 

Detailed Study. Data accepted for the ash transport water POC analysis are: 

- 28 paired fly ash and source water samples from three plants.

- 27 paired bottom ash and source water samples from three plants. 

- 1 non-paired fly ash sample from one plant.

- 1 non-paired bottom ash sample from one plant.
Section 6—

Wastewater Characterization and Pollutants of Concern

6-24

EPA included data for fly ash and bottom ash transport water samples but did not include 

combined ash transport water samples in the POC analysis.

39 Due to the limited data set for 

untreated fly and bottom ash transport water, EPA also included samples representing partially 

treated ash transport water and ash impoundment effluent to identify POCs for this wastestream. 

For wastestreams where EPA is establishing zero discharge (i.e., fly ash transport water, 

bottom ash transport water, and FGMC wastewater), the POCs identified for each wastestream

are those pollutants that are confirmed to be present at sufficient frequency in untreated 

wastewater samples of that wastestream. Because EPA did not need to identify pollutants at a 

treatable level, EPA determined partially treated and ash impoundment effluent data were 

acceptable for use in the POC analysis. 

As shown above, for some of the data, industry also supplied paired source water data to 

demonstrate that the source water used for ash sluicing may contribute to the pollutants present 

in untreated ash transport water. Where paired source water and ash transport water samples 

were available, EPA reviewed data for the paired source water and ash transport water to identify 

pollutants detected at greater than or equal to two times the concentration of the source water at 

10 percent or more of all plants with paired samples. EPA used two times the source water 

concentration for the analysis because it sufficiently indicates the pollutant is present in 

concentrations above the source water concentrations. Where paired source water and ash 

transport water data were not available or did not sufficiently indicate the presence of the 

pollutant in ash transport water, EPA reviewed data for ash transport water without paired source 

water data and identified pollutants detected at greater than or equal to two times the pollutant’s

baseline values at 10 percent or more of all plants with unpaired samples. EPA used baseline 

values from the Development Document for Effluent Limitations Guidelines and Standards for 

the Centralized Waste Treatment Industry [U.S. EPA, 2000]. Table 6-15 and Table 6-16 present 

the final list of POCs for fly ash transport water and bottom ash transport water, respectively. 

EPA identified 38 POCs for fly ash transport water and 37 POCs for bottom ash transport water.

Table 6-15. Pollutants of Concern – Fly Ash Transport Water

Pollutant Group Pollutant of Concern

Conventional Pollutants a Total Suspended Solids

Chemical Oxygen Demand

Priority Pollutants

Arsenic

Beryllium

Cadmium

Chromium

Copper

Lead

Mercury

Nickel

 39 As described in Section 10.2.2, EPA evaluated the pollutants present in combined ash impoundments, calculated 

average pollutant concentrations in combined ash impoundment effluent, and included combined ash ponds in the 

pollutant loadings calculation.
Section 6—

Wastewater Characterization and Pollutants of Concern

6-25

Table 6-15. Pollutants of Concern – Fly Ash Transport Water

Pollutant Group Pollutant of Concern

Selenium

Thallium

Zinc

Nonconventional Pollutants

Aluminum

Ammonia (as N) b

Barium

Boron

Calcium

Chloride

Cobalt

Fluoride

Iron

Magnesium

Manganese

Molybdenum

Nitrate Nitrite (as N)

Nitrogen, Total Kjeldahl (TKN)

Phosphorus

Potassium

Silica

Sodium

Strontium

Sulfate

Titanium

Total Dissolved Solids

Vanadium

Yttrium

Source: Bottom Ash and Fly Ash Transport Water Pollutants of Concern (POC) Analysis Methodology [ERG, 

2015h].

a – EPA did not evaluate data on oil and grease because it is already adequately controlled by BPT regulations.

b – EPA identified ammonia (as N) as a POC; however, EPA excluded this POC from the calculation of pollutant 

loads to avoid double counting of nitrogen compounds.

Table 6-16. Pollutants of Concern – Bottom Ash Transport Water

Pollutant Group Pollutant of Concern

Conventional Pollutants a Total Suspended Solids

Chemical Oxygen Demand

Priority Pollutants Antimony

Arsenic
Section 6—

Wastewater Characterization and Pollutants of Concern

6-26

Table 6-16. Pollutants of Concern – Bottom Ash Transport Water

Pollutant Group Pollutant of Concern

Bromide

Cadmium

Chromium

Copper

Lead

Mercury

Nickel

Selenium

Thallium

Zinc

Nonconventional Pollutants

Aluminum

Ammonia (as N) b

Barium

Boron

Calcium

Chloride

Cobalt

Iron

Magnesium

Manganese

Molybdenum

Nitrate Nitrite (as N)

Nitrogen, Total Kjeldahl (TKN)

Phosphorus

Potassium

Silica

Sodium

Strontium

Sulfate

Sulfite

Titanium

Total Dissolved Solids

Vanadium

Source: Bottom Ash and Fly Ash Transport Water Pollutants of Concern (POC) Analysis Methodology [ERG, 

2015h].

a – EPA did not evaluate data on oil and grease because it is already adequately controlled by BPT regulations.

b – EPA identified ammonia (as N) as a POC; however, EPA excluded this POC from the calculation of pollutant 

loads to avoid double counting of nitrogen compounds.
Section 6—

Wastewater Characterization and Pollutants of Concern

6-27

6.6.5 Flue Gas Mercury Control Wastewater POCs

The FGMC waste (fly ash) 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. 

EPA was unable to obtain readily available data for identifying the POCs in FGMC 

wastewater. Nevertheless, based on process knowledge and engineering judgment, EPA 

concluded that the POCs for FGMC wastewater are likely to be identical to the POCs identified 

for fly ash transport water. As described in Section 6.4, EPA’s review of fly ash with and without 

FGMC waste showed that FGMC waste did not alter the characteristics of the fly ash 

characteristics in two of the three analytes, with arsenic and selenium remaining similar and an 

increase in mercury concentrations with FGMC waste. Thus, EPA concluded that FGMC waste 

would exhibit similar characteristics as fly ash. Based on this conclusion, EPA identified 38 

POCs associated with FGMC wastewater. Table 6-17 lists the POCs identified for FGMC 

wastewater, which is the same as the list for fly ash transport water (see Table 6-15).

Table 6-17. Pollutants of Concern – FGMC Wastewater

Pollutant Group Pollutant of Concern

Conventional Pollutants a Total Suspended Solids

Priority Pollutants

Antimony

Arsenic

Beryllium

Cadmium

Chromium

Copper

Lead

Mercury

Nickel

Selenium

Thallium

Zinc

Nonconventional Pollutants

Aluminum

Ammonia as Nitrogen

Barium

Boron

Calcium

Chloride

Cobalt
Section 6—

Wastewater Characterization and Pollutants of Concern

6-28

Table 6-17. Pollutants of Concern – FGMC Wastewater

Pollutant Group Pollutant of Concern

Fluoride

Hexavalent Chromium

Iron

Magnesium

Manganese

Molybdenum

Nitrate Nitrite as N

Nitrogen, Kjeldahl

Nitrogen, Total Organic (as N)

Silica

Sodium

Sulfate

Titanium

Total Dissolved Solids

Phosphorus, Total

Vanadium

Yttrium

Source: Bottom Ash and Fly Ash Transport Water Pollutants of Concern (POC) Analysis Methodology [ERG, 

2015g].

a – EPA did not evaluate data on oil and grease because it is already adequately controlled by BPT regulations.

6.7 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. ERG. 2015a. Eastern Research Group, Inc. Steam Electric Technical Questionnaire 

Database (“Steam Electric Survey”). (30 September). DCN SE05903. 

3. ERG. 2015b. Eastern Research Group, Inc. “Memorandum to the Steam Electric 

Rulemaking Record: Comparison of Once-Through and Recirculating FGD 

systems.” (30 September). DCN SE04340.

4. ERG. 2015c. Eastern Research Group, Inc. Incremental Costs and Pollutant 

Removals for Final Effluent Limitation Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category. (30 September). DCN SE05831. 

5. ERG. 2015d. Eastern Research Group, Inc. Steam Electric Analytical Database for 

the Final Rule. (30 September). DCN SE05359.

6. ERG. 2015e. Eastern Research Group, Inc. “Development Memorandum for Steam 

Electric Analytical Database for the Final Rule.” (30 September). DCN SE05876. 

7. ERG. 2015f. Eastern Research Group, Inc. “Memorandum to the Steam Electric 

Rulemaking Record: FGD, Combustion Residual Leachate and Gasification 
Section 6—

Wastewater Characterization and Pollutants of Concern

6-29

Wastewater Pollutants of Concern (POC) Analysis Methodology.” (30 September). 

DCN SE05342.

8. ERG. 2015g. Eastern Research Group, Inc. “Ash Analytical Data Review 

Memorandum.” (30 September). DCN SE05567.

9. ERG. 2015h. Eastern Research Group, Inc. “Bottom Ash and Fly Ash Transport 

Water Pollutants of Concern (POC) Analysis Methodology” (30 September). DCN 

SE04745.

10. EPRI. 1998a. Electric Power Research Institute. PISCES Water Characterization 

Field Study, Sites D Report. TR-108892-V1. Palo Alto, CA. (August). DCN 

SE01820.

11. EPRI. 1998b. Electric Power Research Institute. PISCES Water Characterization 

Field Study, Sites D Appendix. TR-108892-V2. Palo Alto, CA. (August). DCN 

SE01820A1.

12. EPRI. 2006. Electric Power Research Institute. Flue Gas Desulfurization (FGD) 

Wastewater Characterization: Screening Study. 1010162. Palo Alto, CA. (March). 

DCN SE01816.

13. U.S. EPA 2000. U.S. Environmental Protection Agency. Development Document 

for Effluent Limitations Guidelines and Standards for the Centralized Waste 

Treatment Industry. EPA-821-R-00-020. Washington, DC (August). Available 

online at 

http://water.epa.gov/scitech/wastetech/guide/cwt/upload/CWT_DD_2000.pdf

14. U.S. EPA. 2006. U.S. Environmental Protection Agency. Characterization of 

Mercury-Enriched Coal Combustion Residues from Electric Generating Utilities 

using Enhanced Sorbents for Mercury Control. (February). DCN SE01339.

15. U.S. EPA. 2008. U.S. Environmental Protection Agency. Characterization of Coal 

Combustion Residues from Electric Utilities Using Wet Scrubbers for MultiPollutant 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 section 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 wastewater, combustion residual landfill leachate, gasification

wastewater, and flue gas mercury control (FGMC) wastewater. This section presents information 

based on the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam 

Electric Survey), industry profile changes (see Section 4.5), and additional industry-provided 

information; therefore, all figures, tables, and values provided represent the steam electric power 

plant population EPA evaluated for the ELGs.

7.1 FGD WASTEWATER TREATMENT TECHNOLOGIES AND MANAGEMENT PRACTICES

During the Steam Electric Power Generating detailed study and rulemaking, EPA 

identified 139 steam electric power plants that generate FGD wastewater; 88 (63 percent) of 

these plants 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 FGD wastewater discharges. 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 allow for a certain residence time within the impoundment to facilitate removing 

total suspended solids (TSS).

• Chemical Precipitation: In chemical precipitation systems, the wastewater is treated 

in tanks. Chemicals are added to help remove suspended solids and dissolved solids, 

particularly metals. The precipitated solids are then removed from solution by 

coagulation/flocculation followed by clarification and/or filtration.

• Biological Treatment: EPA identified three types of biological treatment systems 

currently used to treat FGD wastewater, including anoxic/anaerobic fixed-film 

bioreactors (that target removals of nitrogen compounds and selenium), 

anoxic/anaerobic suspended growth systems (that target removals of selenium and 

other metals), and aerobic/anaerobic sequencing batch reactors (that target removals 

of organics and nutrients).

• Vapor-Compression Evaporation System (Evaporation): This type of system uses a 

falling-film evaporator (or brine concentrator), following a pretreatment step, to 

produce a concentrated wastewater stream and a distillate stream to reduce 

wastewater by 80 to 90 percent and reduce the discharge of pollutants. The 

concentrated wastewater is usually further processed in a crystallizer. This treatment 

system is referred to throughout the TDD as evaporation.
Section 7—Treatment Technologies and

Wastewater Management Practices

7-2

• 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 several

design/operating practices that have been used at some plants to eliminate the 

discharge of FGD wastewater: 1) 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 to treat FGD wastewater but for which full-scale operation 

has not been demonstrated, including zero-valent iron cementation, reverse osmosis, 

absorption media, ion exchange, and electrocoagulation. Other technologies under 

bench-scale study include polymeric chelates, taconite tailings, and nano-scale iron 

reagents.

Most plants that discharge 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 based on the 

Steam Electric Survey and other industry-provided data for the 139 plants that reported using a 

wet FGD scrubber system in 2009 or planning to operate one by January 1, 2014.

40 Because the 

majority of the FGD wastewater management/treatment technologies are surface impoundments, 

chemical precipitation systems, biological treatment, or zero discharge, EPA grouped 

evaporation and constructed wetlands with the “Other” technologies for Figure 7-1. To identify 

the different treatment systems reported in the Steam Electric Survey, EPA grouped the systems 

into the following categories (shown in Figure 7-1):

• Surface Impoundments: Includes systems comprising one or more impoundments 

where the impoundment is the only treatment unit. This group also includes 

impoundments with chemical addition to control pH levels prior to discharge. It does 

not include systems containing impoundments as treatment units in a more advanced 

treatment system (e.g., chemical precipitation, biological treatment), nor does it 

include systems that achieve zero discharge of FGD wastewater.

• Chemical Precipitation: Includes systems using hydroxide and/or organosulfide 

precipitation as the treatment mechanism. This group 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). It does not include systems with chemical 

precipitation and anoxic/anaerobic biological treatment systems, nor does it include 

systems that achieve zero discharge of FGD wastewater.

 40 EPA incorporated Steam Electric Survey reported planned systems operating prior to January 1, 2014, and 

company-verified steam electric generating unit retirements, fuel conversions, and wastewater treatment upgrades 

occurring no later than December 31, 2013 in EPA’s analyses, compliance cost estimates, and pollutant loadings for 

the final Steam Electric Power Generating effluent limitations guidelines and standards (ELGs) (see Section 4.5).
Section 7—Treatment Technologies and

Wastewater Management Practices

7-3

• Biological Treatment: Includes systems using anoxic/anaerobic fixed-film or 

suspended growth biological treatment systems designed to remove selenium and 

other pollutants. This group includes systems that also include surface impoundments 

and/or chemical precipitation treatment units in combination with the biological 

system. It does not include systems that achieve zero discharge of FGD wastewater.

• Other: Includes systems using constructed wetlands or evaporation treatment units. 

This group includes systems that also include surface impoundments in combination 

with the constructed wetland/evaporation system and plants that operate tank-based

settling systems that are not considered chemical precipitation (e.g., clarifier 

systems). It does not include systems that achieve zero discharge of FGD wastewater.

• Zero Discharge: Includes all FGD wastewater treatment systems that achieve zero 

discharge, regardless of the type of unit (e.g., surface impoundments, chemical 

precipitation) used to treat the wastewater prior to reuse.

Source: Steam Electric Survey [ERG, 2015a].

Note: This figure represents the EPA population used in analyses for the ELGs, which was developed using the 

Steam Electric Survey, industry profile changes (see Section 4.5), and additional industry-provided information.

Note: This figure represents the highest level of treatment; for instance, some plants categorized as “Other” or 

“Biological (Anoxic/Anaerobic)” may also operate a chemical precipitation system as part of a more advanced 

treatment system.

Figure 7-1. Distribution of FGD Wastewater Treatment/Management Systems 

Among 139 Plants Generating FGD Wastewater in the EPA Population

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 
Section 7—Treatment Technologies and

Wastewater Management Practices

7-4

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 TSS levels in the wastewater to a target concentration 

and to allow for a certain lifespan of the impoundment based on the expected rate of solids 

buildup within the impoundment. Coal-fired steam electric 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 limitations.

Surface impoundments can reduce the amount of TSS in the wastewater discharge 

provided there is sufficient residence time. In addition to TSS, surface impoundments can also 

reduce 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 metals in the dissolved phase, including manganese, selenium, and 

boron, and these are mostly not 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 concentrations of TSS and 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 139 plants operating wet FGD systems, or planned wet FGD 

systems, and the wastewater treatment systems used to treat the FGD wastewaters generated. 

Based on these data, presented in Figure 7-1 surface impoundments are the most commonly used 

systems for managing FGD wastewater (approximately 28 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. According to the Steam Electric Survey, less 

than 16 percent of the 39 plants generating FGD wastewater managing it with surface 

impoundments transfer the FGD wastewater to a segregated surface impoundment specifically 

designated to treat FGD wastewater [ERG, 2015a]. Some of these plants discharge the FGD 

effluent from the segregated FGD surface impoundments directly to surface waters (with or 

without commingling with cooling water or other large volume wastestreams) while others 

transfer the effluent to another impoundment, potentially containing other combustion residuals 

(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.”
Section 7—Treatment Technologies and

Wastewater Management Practices

7-5

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

them. The specific chemical(s) used depends upon the type of pollutant requiring removal. EPA 

identified 39 steam electric power plants using some form of chemical precipitation as part of 

their FGD wastewater treatment system.41 Power plants commonly use the following three types 

of systems to precipitate metals out of FGD wastewater:

• Hydroxide precipitation (37 plants).

• Iron coprecipitation (35 plants).

• Organoulfide precipitation (27 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-five power plants use iron coprecipitation 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.42 The ferric chloride also acts as a 

coagulant, forming a dense floc that enhances settling of the metals precipitate in downstream 

clarification stages.

Organosulfide precipitation systems use organosulfide chemicals (e.g., trimercapto-striazine (TMT), Nalmet® 1689, sodium sulfide) to precipitate and remove heavy metals, similar 

to the set of metals removed in hydroxide precipitation. Plants operating organosulfide 

precipitation systems typically use TMT-15®, Nalmet® 1689, MetClearTM, sodium sulfide, or 

other organosulfide chemicals in the system. The plants may test several different organosulfide 

chemicals to determine the one most appropriate for their treatment system. Based on discussions 

with system operators, EPA has determined that several plants switched from using TMT-15® 

when the treatment system started operation to using either Nalmet® 1689 or MetClearTM

products. Plants made this switch from TMT-15® products because when they started working 

on optimizing the operation of the system, they performed studies with several different 

organosulfide chemicals, and the results exhibited significantly lower effluent mercury 

concentrations with Nalmet® 1689 or MetClearTM products [ERG, 2014a; ERG, 2015b]. 

Organosulfide precipitation can also provide more optimal removal of metals with lower 

solubilities, such as mercury, than hydroxide precipitation or hydroxide precipitation with iron 

 41 The count of plant operating a chemical precipitation system does not equal the count in Figure 7-1 because this 

figure represents the highest level of treatment. There are plants categorized as “Other” or “Biological 

(Anoxic/Anaerobic)” that operate a chemical precipitation system in conjunction with a more advanced treatment 

system.

42 The remainder of this section discusses the use of ferric chloride, as ferrous chloride is not commonly used in the 

steam electric power generating industry. However, ferrous chloride could also be used instead of ferric chloride and 

can also act as a reducing agent for wastewater with high ORP.
Section 7—Treatment Technologies and

Wastewater Management Practices

7-6

coprecipitation. The EPA sampling data suggest that adding organosulfide to the FGD 

wastewater can reduce dissolved mercury concentrations to less than 10 parts per trillion [ERG, 

2012a]. Organosulfide precipitation is more effective than hydroxide precipitation in removing 

metals with low solubilities because metal sulfides have lower solubilities than metal hydroxides. 

Because organosulfide precipitation is more expensive than hydroxide precipitation, plants 

usually use hydroxide precipitation first to remove most of the metals, and then organosulfide 

precipitation to remove the remaining low solubility metals. This configuration overall requires 

less organosulfide, therefore reducing the expense for the bulk metals removal.

FGD wastewater chemical precipitation systems may include various stages of lime, 

organosulfide, and ferric chloride addition, as well as clarification stages. EPA identified that 24

plants add all three chemicals (i.e., lime, ferric chloride, and organosulfide) within the chemical 

precipitation system. Some add all three chemicals 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 

standard unit (S.U.) to precipitate soluble metals as insoluble hydroxides and oxyhydroxides. 

After primary clarification, the wastewater flows to a second reaction tank where organosulfide 

and hydrochloric acid is added, 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, 2013a].

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 previously established best practicable control technology currently available (BPT) 

limitations for low volume wastewater. For this reason, 39 plants (28 percent) 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.43 Most effluent limitations in NPDES permits for FGD wastewater (other than TSS 

and O&G) are water quality-based effluent limitations (WQBELs) designed 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 rather than only a TSS 

limitation, it is more likely to operate organosulfide precipitation, rather than just hydroxide 

precipitation or a surface impoundment.

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 initially operated a chemical 

precipitation system to treat its FGD wastewater. In 2008, 1 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 WQBEL for mercury. Based on the proposed mercury 

limitations in the new permit, AEP conducted a pilot study evaluating three different 

 43 In some cases, the steam electric power plant permit requires the plant to monitor and report the concentration of 

specific pollutants; however, the permit does not contain numerical effluent limitations that must be met prior to 

discharge.
Section 7—Treatment Technologies and

Wastewater Management Practices

7-7

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 3 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 wastewater for target 

concentrations of certain metals, allowing them to adjust the operation of the chemical 

precipitation system as necessary. Some plants actively monitor the influent to the treatment 

system and adjust chemical addition in an equalization tank with a 24-hour holding time as the 

first step in the treatment system. Plants can also 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 samples using an in-house Method 

DMA 80 mercury analyzer, which can generate results in approximately 6 minutes [Michel, 

2012]. The plant uses the mercury analyzer to alert operators when mercury concentrations are 

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 transferring the wastewater in batches to the effluent storage 

tank. When the tank is full, the plant collects a sample of the wastewater to confirm it is below 

the permit limit. Once it confirms the concentration is lower than the limit, the plant discharges 

the wastewater from the effluent tank [ERG, 2013a].

Figure 7-2 presents a process flow diagram for a chemical precipitation system using 

hydroxide precipitation, organosulfide precipitation, and iron coprecipitation to treat FGD 

wastewater. A chemical precipitation system with no organosulfide precipitation stage would be 

similar, but without the organosulfide addition reaction tank.

For the system illustrated by Figure 7-2, the plant transfers the FGD wastewater from the 

plant’s solids 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 wastewater pH 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 
Section 7—Treatment Technologies and

Wastewater Management Practices

7-8

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 Organosulfide Chemical Precipitation System
Section 7—Treatment Technologies and

Wastewater Management Practices

7-9

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. 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.44

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.

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). These pretreatment steps, specifically chemical 

 44 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 optimize the removal of different metals. 
Section 7—Treatment Technologies and

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7-10

precipitation systems, have been demonstrated to handle the FGD wastewater variability over 

long periods of time.

7.1.3.1 Aerobic Biological Treatment

Some steam electric power 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 ensure 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 an 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: filling, 

aeration and reaction, settling, and decanting. 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. In the filling stage, the FGD 

wastewater is transferred 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 the 

concentrations of 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 temperatures in excess of 

105oF [Pickett, 2005]. Because of this susceptibility, some plants cool the FGD wastewater 

before it enters the biological system using heat exchangers or cooling impoundments. Based on 

data from EPA sampling episodes, these plants generally are located in geographic regions with 

sustained periods of maximum ambient temperatures greater than 90oF [U.S. EPA, 2015].

Four plants use an anoxic/anaerobic fixed-film bioreactor that consists of an activated 

carbon bed, such as granular activated carbon (GAC) or some other permanent porous substrate,
Section 7—Treatment Technologies and

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7-11

that is inoculated with naturally occurring, beneficial microorganisms that reduce selenium and 

other metals [Sonstegard, 2010].

45 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]. Steam electric power plants also add a molasses-based feed source for the 

microorganisms to the wastewater before it enters the bioreactor [ERG, 2012b].

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

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 in the reactor effluent, 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, 2012b]. The top part of the bioreactor, where the plant 

feeds the wastewater, is aerobic with a positive ORP, which allows nitrification and organic 

 45 One additional plant currently operates an anoxic/anaerobic fixed-film bioreactor and is planned to install an 

evaporation system; therefore, it is considered “Other” in Figure 7-1 and are not included in this count of four plants.
Section 7—Treatment Technologies and

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7-12

carbon oxidation to occur. As the wastewater moves down through the bioreactor, it enters an 

anoxic zone (negative ORP) where denitrification and 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 undesirable microbes to propagate [ERG, 

2012b].

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, nickel, 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 employ multiple bioreactors to provide the necessary residence 

time to achieve the specified removals.

Periodically, the bioreactor is 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 the solids [Pickett, 2006] and would 

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 

[ERG, 2012b]. 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 operates 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. The plant began operating the anoxic/anaerobic 

suspended growth biological treatment system in January 2012 [ERG, 2013b].
Section 7—Treatment Technologies and

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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 

is 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 systems currently in 

operation at steam electric power plants is not managed at levels conducive to reducing metals. 

Therefore, these SBR systems, as currently designed and operated, do not remove selenium (and 

other metals) as effectively as the fixed-film or suspended growth bioreactor systems.

Management of the ORP in the bioreactor is important for optimizing removal of nitratenitrite and selenium, regardless of whether the system uses a fixed-film, suspended growth, or 

other design. Nitrate-nitrite and selenium removals are optimized when ORP in the reactor is in 

range of -300 to -150 mV [Teng et. al., 2012; Lau et. al., 2012]. Additionally, conditions of very 

high, positive ORP (on the order of 500 mV) have been associated with the presence of high 

concentrations of oxidants in the FGD wastewater [Brown et. al., 2013]. High concentrations of 

oxidants have the potential to inhibit the growth and activity of the anaerobic microorganisms 

that reduce the nitrate-nitrite and selenium However, testing of the biological treatment systems 

at the pilot-scale and at full-scale systems operating at steam electric power plants has 

demonstrated that the presence of oxidants can be overcome with an applied understanding of 

oxidant/FGD chemistry, awareness that adjustments to certain upstream processes can affect 

ORP, and implementation of an oxidant monitoring and mitigation strategy. In doing so, plant 

operators can (1) take steps to prevent or mitigate the formation of oxidants in the FGD absorber; 

(2) monitor ORP and total oxidants in the absorber and in the purge directed to the wastewater 

treatment system; (3) employ oxidant removal and control, as needed, by adding reducing agents 

within the chemical precipitation stage of the treatment system or a separate unit process 

upstream of the bioreactor; and (4) monitor and maintain the ORP within the bioreactor at the 

appropriate level. 

A pilot test conducted at a plant in the southeast U.S. highlights the importance of 

controlling ORP. At this site, FGD wastewater from a surface impoundment was sent to a pilotscale fixed-film anoxic/anaerobic bioreactor, as well as several other pilot-scale treatment 

technologies. Pollutant removal performance for this pilot test was degraded due to the very low 

pH and high ORP of the wastewater. The test also suffered from the small-scale pilot equipment 

being not sufficiently protected against exposure to cold weather, which resulted in freezing 

causing issues with chemical dosing equipment. During the test period, plant operators 

determined that the pH control loop for the FGD absorber was not operating properly; this, in 

turn, ultimately affected the wastewater pH and FGD purge rate and led to elevated levels of 

oxidants in the wastewater. Subsequent laboratory testing of the FGD wastewater from the 

surface impoundment showed that by adding reducing agents, the oxidants could be removed and 

the wastewater was able to support microbial growth and activity. Since that time, the vendor has 

continued to perform pilot testing at other plants and found that by monitoring the ORP in the 

wastewater, optimizing pretreatment with chemical precipitation including the addition of 

reducing agents to pretreat the wastewater, the issues related to the increased ORP levels can be 

controlled and the biological treatment system is able to function as expected [ERG, 2015c]. A 

plant operating a full-scale biological treatment system similarly found that adding reducing 

agents to the wastewater prior to sending it to the bioreactor, in this case using ferrous chloride 

instead of ferric chloride in the chemical precipitation stage, effectively controlled the oxidants.
Section 7—Treatment Technologies and

Wastewater Management Practices

7-14

7.1.4 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 is then processed in a 

forced-circulation crystallizer, in which the remaining water is evaporated. In this configuration, 

the evaporation system 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 evaporation systems to treat wastestreams 

such as cooling tower blowdown and demineralizer waste. In 2009, however, one plant in the 

United States began to operate an evaporation system to treat FGD wastewater [ERG, 2015a] 

and two other U.S. plants 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 evaporation systems [Rao, 2008; Veolia Water Solution, 

2007]. Two other plants in Italy also installed evaporation systems but subsequently determined 

that off-site disposal was more economical.

Before entering the 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.

Figure 7-4. Chemical Precipitation and Softening Pretreatment for FGD 

Wastewater Prior to Evaporation

Figure 7-5 presents a process flow diagram for an evaporation system. When an

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. Some plants also add an antiscalant to the wastewater prior 
Section 7—Treatment Technologies and

Wastewater Management Practices

7-15

to the evaporation system [ERG, 2012c]. Following pH adjustment, the FGD wastewater goes 

through a heat exchanger to bring the wastestream to its boiling point. From the heat exchanger, 

the wastestream is sent to the deaerator, where the noncondensable materials such as carbon 

dioxide and oxygen are vented to the atmosphere [ERG, 2012c].

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, 2012c].

The condensed vapor (i.e., distillate water) can be recycled back to the FGD process, 

used in other plant operations (e.g., boiler makeup 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 an 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 

concentrator is not as effective because of boiling point rise (the increase in energy required to 
Section 7—Treatment Technologies and

Wastewater Management Practices

7-16

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 an Evaporation System
Section 7—Treatment Technologies and

Wastewater Management Practices

7-17

concentrate the wastewater stream due to the additional calcium and magnesium salts or other 

solids in the wastewater). For example, one plant operates only a clarifier prior to the 

evaporation system. The brine concentrator reduces the inlet FGD scrubber purge water volume 

only up to 53 percent [ERG, 2012d].

As described previously, the configuration of the evaporation system that EPA evaluated 

as the basis for the technology option consisted of a pretreatment system including hydroxide 

and organosulfide chemical precipitation, softening, the evaporation system (brine concentrator), 

and a forced-circulation crystallizer. However, there are other options that plants can consider for 

processing the concentrated brine stream from the evaporation system. Plants typically consider

hree other options for eliminating the brine concentrate: (1) using the brine to condition (add 

moisture to) dry fly ash or other solids and disposing of the mixture in a landfill (approach used 

at Kansas City Power & Light’s Iatan Generating Station); (2) adding reagents to fixate the 

material in a pozzolanic reaction and disposing of the mixture in a landfill; or (3) evaporating the 

brine in a spray dryer.

Plants can 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 steam electric 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.

At least one vendor of the evaporation system for treating FGD wastewater has been 

pilot-testing a process to solidify the concentrated brine from the evaporation system. The 

solidification process consists of mixing the concentrated brine with fly ash and other reagents to 

form a solidified material via a pozzolanic reaction. The vendor’s pilot testing has shown that the 

solidified material passes all the toxicity characteristic leachating procedure criteria. According 

to the vendor, by solidifying the material, it is not necessary to soften the wastewater prior to the 

evaporation system, which significantly reduces the operation and maintenance (O&M) costs and 

the amount of solids generated by the system. It also reduces the capital costs because the 

solidification process equipment is significantly less expensive than a forced-circulation 

crystallizer [ERG, 2015d].

Similarly, another vendor of the evaporation system for treating FGD wastewater has 

developed a system that does not require a chemical precipitation or lime-softening step. 

Therefore, the FGD wastewater can be sent directly into the evaporation and crystallization 

process that is operated at a low temperature for optimizing the FGD wastewater chemistry. At a 

lower temperature, dissolved solids will crystallize (e.g., hydrates and double salts) at lower 

concentrations. Therefore, this system does not produce any additional sludge from chemical 
Section 7—Treatment Technologies and

Wastewater Management Practices

7-18

additions, allows the evaporated water to be reused, and produces stable solids for disposal 

[Veolia Water Solution, 2013; ERG, 2015d]. 

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 reduce 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 power 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. In the aqueous phase of the wastewater, the bacteria reduce metals, 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 

such as boron, which can harm the vegetation in the treatment cells. For example, most plants 

typically maintain the chlorides in a constructed wetland treatment system below 4,000 

milligrams per liter (mg/L) but operate their FGD scrubber systems to maintain chloride levels 

within a range of 10,000-20,000 parts per million (ppm); therefore, 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 these steam 

electric power plants tend to operate their FGD systems 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 if operating the FGD system at a higher chloride 

concentration level.

7.1.6 Design/Operating Practices Achieving Zero Discharge

During the site visit program, EPA observed that some of the plants operating wet FGD 

systems managed the system to eliminate the discharge of FGD wastewater. EPA identified 51 

plants (37 percent) achieving zero discharge of FGD wastewater. Based on information collected 

as part of the Steam Electric Survey, EPA identified five operating practices available to prevent 

the FGD wastewater discharge:

• Complete recycle.

• Evaporation impoundments.

• Underground injection.

• Operation of both wet and dry FGD scrubber systems.

• Dry fly ash conditioning.

This section discusses each of these practices.
Section 7—Treatment Technologies and

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7-19

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 is

most likely disposing of it in a landfill, it has no specific chloride specifications for the FGD 

solids material and 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 

139 plants operating wet FGD systems, 18 operate complete-recycle systems and do not 

discharge any FGD wastewaters to surface waters. Of these 18 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 nine plants located in the southwestern United States that use evaporation 

impoundments to avoid discharging any FGD wastewater 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 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 to surface water.

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 in an on-site landfill. 

Although conditioning fly ash involves water in direct contact with dry fly ash, this is not 

considered fly ash transport water because the purpose is not to convey fly ash from the 

collection/storage equipment or boiler. EPA identified five plants that use FGD wastewater to 

suppress dust around landfills or to moisture condition fly ash prior to landfill disposal [ERG, 

2015a]. Another plant, discussed in Section 7.1.4, uses an evaporation system to reduce the 

volume of FGD wastewater and then mixes the concentrated brine slurry with dry fly ash and 

disposes of it in a landfill to prevent discharging FGD wastewater [ERG, 2013c]. 

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 system, the plant 

can use the FGD wastewater associated with the wet FGD system as makeup water for the lime 

slurry feed to the dry FGD process, thereby eliminating the FGD wastewater [McGinnis, 2009].
Section 7—Treatment Technologies and

Wastewater Management Practices

7-20

From its data collection activities, EPA identified three plants that planned 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, 2015a].

Underground Injection

Underground injection is used to dispose of wastes by injecting them into an underground 

well as an alternative to discharging wastewater to surface waters. Based on EPA’s information, 

one plant began using underground injection to dispose of FGD wastewater in 2007, but it has 

not been successful. Because of 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.46 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, 2013d; ERG, 2015a]. Another plant began injecting the FGD wastewater underground in 

2010 [ERG, 2015a]. 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.

7.1.7 Other Technologies under Investigation

In addition to chemical precipitation, biological treatment, evaporation, constructed 

wetlands, and zero discharge systems for FGD wastewater treatment, EPA also identified several 

emerging treatment technologies that have been proven to treat FGD wastewater. EPA reviewed 

EPRI reports, industry sources, and published research articles describing alternative FGD 

wastewater treatment technologies being evaluated at the bench-, pilot-, and full-scale levels. For 

additional information on these and other technologies under investigation for FGD wastewater 

treatment, see “Evaluation of Emerging Technologies for the Treatment of Flue Gas 

Desulfurization Wastewater” [ERG, 2015d].

Iron and Sulfide Additives with Microfiltration

EPRI conducted bench- and pilot-scale testing of a process to help remove 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 in size. 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]. 

 46 Plant operates an iron coprecipitation system.
Section 7—Treatment Technologies and

Wastewater Management Practices

7-21

Zero-Valent Iron Cementation

In general, zero-valent iron (ZVI) cementation removes pollutants by contacting 

wastewater with an iron powder, reducing the pollutant to its elemental form (i.e., cementation). 

The pH of the wastewater is increased to form metal hydroxides, and the wastewater is filtered to 

remove the precipitated solids. Next, the iron powder is separated from the wastewater and 

recycled back to the cementation step. ZVI cementation has been proven to remove several 

heavy metals from FGD wastewater (e.g., arsenic, mercury, copper, chromium); however, 

EPRI’s research was focused on removing selenium in the selenate, selenite, and other forms. 

EPRI conducted bench-scale testing of the ZVI cementation treatment technology as a 

way to remove all species of selenium from FGD wastewater. EPRI believes this process may 

also effectively remove mercury. From the initial studies, EPRI concluded that the ZVI iron 

cementation approach is promising for treating FGD wastewater for multiple species of 

selenium, including selenite, selenate, and other unknown selenium compounds [EPRI, 2008a].

EPRI continued its study of ZVI 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 ZVI 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 bench-scale testing described above. Under ideal 

operating conditions, the bench-scale testing showed that iron cementation reduced dissolved 

selenium to less than 0.05 mg/L; however, the pilot-scale testing’s lowest selenium effluent 

concentration was 0.159 mg/L. 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].

EPA obtained information from two pilot studies conducted as a partnership between 

EPRI and SCANA at a coal-fired power plant that evaluated a ZVI technology for treating FGD 

wastewater. The pilot studies were performed from November 2013 to March 2014 and tested 

two different system configurations using the same ZVI technology. The pilot test used FGD 

surface impoundment effluent as the initial influent stream to the system; however, on February 

28, 2014, a pilot-scale chemical precipitation system was added upstream of the pilot 

technologies to pretreat the FGD wastewater. The first ZVI system configuration (System 1) 

utilized a 1.0 gallon per minute (gpm) FGD wastewater influent flow rate and treated the 

wastewater using the following design elements:

• One sand filter.

• Three bag filters (25 micrometers (μm), 10μm, and 1μm).

• Eight vessels (125 gallons) containing stacks of porous media loaded with fine ZVI 

shavings.
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This pilot test was not able to achieve effluent pollutant that met ELG limitations for 

selenium, mercury, arsenic, and nitrate/nitrite as N. However, after chemical precipitation was 

installed upstream of the pilot test, this system configuration consistently maintained selenium 

concentrations less than 100 ppb in the effluent, compared to an effluent selenium concentration 

of 1,200 to 1,400 ppb when the FGD surface impoundment effluent was used as the influent. The 

second ZVI system configuration (System 2) maintained an influent flow rate of 0.00132 gpm 

and treated the FGD wastewater using the following design elements:

• One anaerobic membrane bioreactor (continuous stirred tank reactor, followed by an 

ultrafilter membrane).

• An ultraviolet (UV) disinfection step. 

• Four columns (2.5” diameter; 12.5” media) containing porous media loading with 

fine ZVI shavings.

The bioreactor was added before the ZVI columns to remove the nitrates because the 

positive charge on the nitrogen causes these species to compete with the selenium species and 

significantly inhibit selenium removal from the FGD wastewater. Therefore, the second ZVI 

system configuration, containing the pretreatment bioreactor, was able to meet the ELG 

limitations for selenium, mercury, nitrate/nitrite as N, and arsenic. In addition, the ZVI media 

chemically reduced and removed other selenium compounds, such as selenocyanate and methyl 

seleninic acid [EPRI, 2014; ERG, 2015e].

EPA also obtained information from a ZVI pilot study conducted at another coal-fired 

power plant. The plant conducted this pilot study from March 2014 to July 2014 using the 

effluent from its chemical precipitation system. This ZVI system (System 3) contained a sand 

filter, bag filters, and eight vessels containing porous ZVI-loaded media (similar to System 1 

described above). However, the chemical precipitation effluent from this plant contained lower 

levels of nitrates than the other coal-fired power plant (where System 1 and 2 were studied). The 

pilot study demonstrated that this ZVI system met the ELG limitations for selenium, arsenic, and 

mercury [ERG, 2015e; ERG, 2015f].

Reverse Osmosis

Reverse osmosis systems are currently in use at steam electric power plants, usually to 

treat boiler makeup 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 a higher pH. 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 steam electric power generating 

industry to treat cooling tower blowdown wastewater, its use for FGD wastewater is potentially 

limited due to the osmotic pressure of the FGD wastewater due to 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 
Section 7—Treatment Technologies and

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7-23

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 the sorption media’s 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 titaniumbased oxides were the most prevalent adsorbent at the time of the study. Ferric- and titaniumbased media effectively remove both common forms of arsenic (arsenate and arsenite) and 

selenium (selenite) over a wide pH range [EPRI, 2007].

A University of Granada study analyzed the absorption of bromide and iodide using a 

type of sorption media, metal-doped aerogels, which attaches the halide on the aerogel surface 

through a chemisorption process. This technique used Ag-doped aerogels in 25 cubic centimeters 

(cm3

) columns to remove bromide from Lake Zurich and mineral water. The columns were 

saturated with bromide and iodide and regenerated with NH4OH. The study exhibited a high 

efficiency of removing the bromide from the water before and after regeneration; however, 

additional studies need to be performed to analyze whether this sorption media would be 

effective for bromide removal in FGD wastewater [Sanchez-Polo, 2007].

EPA identified one plant that installed an FGD wastewater treatment system that includes 

chemical precipitation followed by another treatment stage that uses cartridge filters in 

combination with two sets of adsorbent media specifically designed to help remove 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 ppt for mercury [Smagula, 

2010]. According to Siemens, the adsorption media technology vendor, the capital costs for a 

system including the two sets of adsorption media could range from $200,000 to $2,000,000, 

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 makeup 

water. These systems remove specific constituents from wastewater and therefore 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 
Section 7—Treatment Technologies and

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7-24

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. Although the system was successful in removing trace mercury from FGD 

wastewater, 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 a model study performed at the University of North Carolina at Chapel 

Hill using ion exchange to remove bromides. Bromide removal was evaluated with a 

polyacrylate-based magnetic ion exchange (MIEX) resin and two polystyrene resins, Iona A-641 

and Amberlite IRA910, using simulated natural waters containing natural organic matter, 

bicarbonate, chloride, and bromide. This study removed bromide and demonstrated that the 

polystyrene resins were the most effective. The study did not analyze the use of ion exchange 

resins on FGD wastewater; therefore, additional studies are needed to determine if this 

technology can remove bromide in FGD wastewater [Hsu, 2010].

EPA identified one plant that has installed an ion exchange system 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, 

2015a].

Electrocoagulation

Electrocoagulation 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].

A bench- and pilot-scale study performed by the University of California, Los Angeles, 

examined the removal of bromine from raw lake water (i.e., Castaic Lake) using the Wunsche 

and Kossuth processes. The Wunsche process uses monopolar carbon electrodes with a 

diaphragm to separate the anode and the cathode, while the Kossuth process uses dipolar carbon 

electrodes without a diaphragm. Both processes remove bromide by oxidizing the halogen to 

bromine, then applying heating and air stripping to volatize the bromine [Kimbrough, 2002]. The 

pilot-scale study of the electrolytic volatization method was recently published on naturally 

occurring bromine in Castaic Lake. This study determined that up to 35 percent bromide and 60

percent disinfection by-products could be removed through electrolysis [Kimbrough, 2006]. The 

bromide was volatized when passed between electrodes, clarified in an upflow sand clarifier, and 
Section 7—Treatment Technologies and

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7-25

filtered through a monomedium deep-bed anthracite coal filter. This study estimated that the 

costs for a demonstration-scale electrolytic reactor would be $1,549-2,099 per million gallons of 

water treated [Kimbrough, 2013].

Other Technologies

EPA obtained only limited information on other technologies including polymeric 

chelates, taconite tailings, nano-scale iron reagents, modular biological treatment systems, 

modular zero liquid discharge systems, and aluminum coagulation. In addition, EPRI is 

investigating various physical treatment technologies, primarily to remove mercury, including 

filtration [EPRI, 2008b].

7.2 FLY ASH HANDLING, MANAGEMENT, AND TREATMENT TECHNOLOGIES

The information presented in this section is based on the Steam Electric Survey (2009 

data), industry profile changes (see Section 4.5), and industry-provided information. During the 

Steam Electric Power Generating detailed 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 final rulemaking, EPA considered 

chemical precipitation for treating 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 associated with chemical precipitation treatment were comparable to the costs of 

converting to dry handling technologies, despite being less effective at removing pollutants 

[ERG, 2015g]. Therefore, EPA did not select chemical precipitation as a treatment technology 

basis for control of fly ash in the final ELGs. Fly ash handling technologies evaluated by EPA 

are listed below and described in detail in this section.

Fly Ash Handling Systems that Generate Fly Ash Transport Water

• 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. Some plants may 

wet sluice fly ash transport water in combination with a surface impoundment and 

recycle a portion or all water within the fly ash handling system.

• Dense Slurry Systems: These systems use a dry vacuum or pressure system to convey 

the dry fly ash to a silo (as described below for the “Dry Vacuum Systems” and 

“Pressure Systems”), but instead of using trucks to transport the fly ash to a landfill, 

the plant mixes the fly ash with a lower percentage of water compared to a wetsluicing system and pumps the mixture to the landfill.47

 47 Because of the much smaller volume of water used for the DSS, relative to a traditional wet sluicing system, 

plants should be better able to engineer and operate the process so that there will be no discharge. To accomplish 

this, plants should divert stormwater away from the dense slurry to the extent practicable. If stormwater or other 
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7-26

Fly Ash Handling Systems that Do Not Generate Fly Ash Transport Water

• Wet Vacuum Pneumatic Systems: These systems convey dry fly ash to a silo using 

water-powered hydraulic pumps to withdraw fly ash from the hopper and filterreceivers to collect the fly ash dry.

• Dry Vacuum Systems: 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 Systems: These systems convey dry fly ash to a silo using air produced by a 

positive displacement blower directly.

• Combined Vacuum/Pressure Systems: These systems use a dry vacuum system to pull 

dry ash from the hoppers to a transfer station, where it is conveyed via a highpressure conveying line directly to a silo.

EPA also identified mechanical systems as fly ash handling systems. The mechanical 

systems include manual or systematic approaches to remove fly ash (e.g., scraping the sides of 

the boilers with sprayers or shovels, then collecting and removing the fly ash to an intermediate 

storage destination or disposal). Depending on the type of system used, it may or may not 

generate fly ash transport water.

Coal-, petroleum coke-, and oil-fired steam electric power plants use particulate control 

technologies such as electrostatic precipitators (ESPs) or baghouse filters 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 power generating industry. After the fly ash particles are captured by 

the ESP or baghouse filters, they are dropped into the collection hoppers. From the hoppers, the 

plants transport the 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 348

coal-, petroleum coke-, and oil-fired power plants, corresponding to 708 coal- and petroleum 

coke-fired generating units and 18 oil-fired generating units, generate fly ash. Most of these 

plants (approximately 76 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 require wet-sluicing. As shown in Figure 7-6, approximately 7 percent of coal- and 

petroleum coke-fired generating units operate wet-sluicing-only systems to collect fly ash, 

whereas 44 percent of the oil-fired generating units operate wet-sluicing systems. Based on 

Steam Electric Survey responses and publicly available data, EPA identified 18 plants 

(corresponding to 46 steam electric generating units) operating wet-sluicing systems that 

announced they will convert from wet to all dry handling operations no later than December 31, 

2023 [ERG, 2015h]. 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 oil-fired generating unit into one of the following 

three categories based on the type of fly ash handling system operated by the unit: 

 

wastestreams come into contact with the dense slurry prior to completing the solidification and evaporation or 

encapsulation of the transport water, the commingled wastestream would need to comply with the zero discharge 

standard for fly ash and bottom ash transport water.
Section 7—Treatment Technologies and

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• Units with wet-sluicing systems only.

• Units with any other type(s) of handling system listed above (excluding wet-sluicing).

• Units that have multiple fly ash handling systems, including wet-sluicing.

Source: Steam Electric Survey [ERG, 2015a].

Note: This figure represents the EPA population used in analyses for the ELGs which was developed using the 

Steam Electric Survey, industry profile changes (see Section 4.5), and additional industry-provided information.

Figure 7-6. Distribution of Fly Ash Handling Systems for Coal-, Petroleum Cokeand Oil-Fired Generating Units Reported in the Steam Electric Power Generating 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 generating units, or 

converting existing generating 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 43 percent of 

non-wet-sluicing systems). Figure 7-7 shows the distribution of fly ash handling systems, 

excluding any generating units with wet-sluicing systems only or generating units with 

combination wet and dry handling systems, reported in the Steam Electric Survey for coal-, 

petroleum coke-, and oil-fired generating units. EPA grouped other handling systems, 

mechanical systems, and a combination of multiple systems, excluding wet sluicing, as 

“Other/Mechanical” in Figure 7-7.
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Source: Steam Electric Survey [ERG, 2015a].

Note: This figure represents the EPA population used in analyses for the ELGs which was developed using the 

Steam Electric Survey, industry profile changes (see Section 4.5), and additional industry-provided information.

Note: The coal- and petroleum coke-fire units categorized as “Unknown Dry Ash Conversion” are fly ash handling 

conversions identified in the Updated Industry Profile Population described in Section 4.5.1. Therefore, EPA has 

verified that the steam electric generating unit is converting to dry fly ash handling prior to implementation of the 

final rule, but the type of system is unknown. For more information about EPA’s incorporation of changes in the 

steam electric power generating industry, see Section 4.5.

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

Sluicing for Coal-, Petroleum Coke-, and Oil-fired Generating 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 power generating industry in more detail.

Fly ash transport water is typically treated in large surface impoundments, either 

completely separate from or commingled with other wastewaters. Impoundments vary in size, 

capacity, and 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.
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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 impoundment overflow, 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 via only 

settling. Some plants, however, also have pH control systems to adjust the pH of the 

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 inlet and stack them on the sides of the 

impoundment to dewater and build up its height. 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 it permanently and, when it

reaches its capacity, build a new ash impoundment and decommission the old one.

7.2.2 Fly Ash Dense Slurry System

The term “dense slurry” refers to a mixture of combustion residuals (e.g., fly ash) with 

water, where the solid-to-water ratio is approximately 1:1. This ratio for the dense slurry system 

is much higher than the ratio used in the wet-sluicing system, which is typically in the range of 

1:10 to 1:15 solid-to-water ratio. While bottom ash and FGD waste can be incorporated in a 

smaller fraction for some dense slurries, this handling system is predominately used in 

commercial applications to transport fly ash. A dense slurry system (DSS) is designed to pump 

the slurry to a disposal location (i.e., landfill) where pozzolanic reactions occur to form a low 

hydraulic conductivity, high-compressible-strength solid product within 24 to 72 hours. As of 

spring 2012, there were 12 commercially applied DSSs in the world: four in Hungary, six in 

Romania, one in India, and one in the United States [GEA, 2014; GEA, 2013]. Because the DSS 

uses water to transport the fly ash to the disposal area, this system is considered to generate fly 

ash transport water and, therefore, the zero discharge requirements would apply to this system. 

EPA investigated the only DSS operating in the United States, the Jacksonville Electric 

Authority Northside Generating Station (JEA Northside), during a site visit on April 8, 2014. 

JEA Northside has coal-, petroleum coke-, natural gas-, and landfill gas-fired generating units 

that have a circulating fluidized-bed boiler, where the plant injects limestone directly into the 

boiler for sulfur dioxide control. In 2002, JEA Northside installed the DSS to transport fly ash 

and bottom ash to a by-product storage area, due to traffic and scaling concerns.48 The solid byproduct is either marketed (e.g., binder for landfills, binder for remediation sites, binder for pond 

closures, interim road cover, or secondary road cover) or landfilled. The DSS was designed to 

 48 JEA Northside decided installing a traditional dry ash handling system was not feasible because of the volume of 

trucks needed and concern for increased limestone in the ash-causing scaling issues in the surface impoundment 

used to store fly ash.
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handle all the fly ash and bottom ash produced by JEA Northside’s two generating units and 

designed by the United Conveyor Corporation.49 The fly ash falls out of the flue gas stream in 

the economizer or is collected after the spray dryer absorber in fabric filter baghouses and 

pneumatically conveyed to fly ash silos. In addition, the bottom ash flows out the bottom of the 

boiler into a stripper/cooler and is carried by a series of mechanical drag chains to a clinker 

grinder. The ground bottom ash drops into a surge hopper and is pneumatically conveyed to 

bottom ash silos (bed ash silos in Figure 7-8). Next the fly ash is mixed with makeup water and 

pumped to the dense ash slurry mixing tank for blending with bottom ash and additional makeup 

water. Then the dense slurry mixture is pumped to the by-product storage area [ERG, 2014b]. 

See Figure 7-8 for a schematic of the JEA Northside DSS for fly ash and bottom ash.

Source: JEA Northside Site Visit Notes [ERG, 2014b].

Figure 7-8. JEA Northside Dense Slurry System Material Flow Diagram

The JEA Northside DSS conveys ash from only one fly and bottom ash silo at a time and 

is able to mix 220-250 tons of ash per minute. The dense slurry is approximately 60 percent 

solids by weight but the ratio of fly ash, bottom ash, and makeup water depends on the type of 

 49 Unit 1 and Unit 2 each generate approximately 500 tons of fly ash and 700 tons of bottom ash per day and 

500,000 tons of DSS by-product per year. The diaphragm pumps (GEHO pumps in Figure 7-8) were obtained from 

a European-based company.
Section 7—Treatment Technologies and

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coal burned and desired market product. The DSS by-product is dried, milled, and tested for 

strength and waste stabilization benchmarks to ensure it complies with market specifications. 

Because JEA Northside injects limestone into the boiler for sulfur dioxide control, the fly 

ash contains excess calcium compared to fly ash generated for a typical coal-fired generating 

unit. The excess calcium aids in the pozzolanic reactions that occur at the landfill to make the 

cementitious material. Therefore, for most coal-fired generating units to effectively operate a fly 

ash dense slurry system, the plant would need to mix the fly ash with lime or limestone and 

water prior to transferring the dense slurry to the landfill for disposal.

7.2.3 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 1 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.

• Bottom ash transport water.
Section 7—Treatment Technologies and

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After moisture conditioning and loading, the ash is transported by truck 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 generating units; 

however, the system is attractive to plants that are converting existing generating 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. In addition, the outage required for installing or 

converting to vacuum systems is about 6 to 8 weeks if the plant is not retaining the ash collection 

hoppers. However, if the plant retains the fly ash hopper and branch lines, the silo and wet 

vacuum pneumatic system can be installed nearby while the steam electric generating unit is on 

line and will only take a few days to tie in to existing pipe headers and diverter valves. 

Therefore, this installation or conversion can occur during normal scheduled maintenance 

outages [CBPG, 2010].

7.2.4 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 7.2.3, 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 7.2.3 also apply to the dry vacuum system. See 

Figure 7-9 for a schematic of a typical dry vacuum fly ash handling system set-up. As shown in 

Figure 7-7, the dry vacuum system is the most commonly used dry fly ash handling system for 

coal- and petroleum coke-fired generating units, accounting for 43 percent of all installations.

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 & Wilcox, 2005]. In addition, the outage required to 

install or convert to vacuum systems is about 6 to 8 weeks if the plant is not retaining the ash 

collection hoppers. However, if the plant retains the fly ash hopper and branch lines, the silo and 

the dry vacuum system can be installed nearby while the steam electric generating unit is on line 
Section 7—Treatment Technologies and

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and will only take a few days to tie in to existing pipe headers and diverter valves. Therefore, this 

installation or conversion can occur during normal scheduled maintenance outages [CBPG, 

2010].

Graphic reprinted with permission from FLSmidth Inc. [FLSmidth, 2012].

Figure 7-9. Schematic of Dry Vacuum, Pressure, and Combined Vacuum/Pressure System

7.2.5 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 7-10. 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 & 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 7.2.3), 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 7.2.3 also apply to the 

pressure system. See Figure 7-9 for a schematic of a typical pressure fly ash handling system setup.
Section 7—Treatment Technologies and

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Graphic reprinted with permission from Steve Stultz [Babcock & Wilcox, 2005].

Figure 7-10. 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 7-10) 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 & Wilcox, 2005]. In addition, the 

outage required to install or convert to pressure systems is about 8 to 12 weeks if the plant is not 

retaining the ash collection hoppers. However, if the plant retains the fly ash hopper and branch 

lines, the silo and the pressure system can be installed nearby while the steam electric generating 

unit is on line and will only take a few days to tie in to existing pipe headers and diverter valves. 

Therefore, this installation or conversion can occur during normal scheduled maintenance 

outages [CBPG, 2010].
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7.2.6 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 

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 7.2.3 also apply to the 

combined vacuum/pressure system. See Figure 7-9 for a schematic of a typical combined 

vacuum/pressure fly ash handling system.

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, fine ash particles will also leak at the 

piping joints due to the high-pressure portion of the system [Babcock & Wilcox, 2005]. In 

addition, the outage required to install or convert to a combined vacuum pressure systems is 

about 8 to 12 weeks if the plant is not retaining the ash collection hoppers. However, if the plant 

retains the fly ash hopper and branch lines, the silo and the combination vacuum pressure system 

can be installed nearby while the steam electric generating unit is on line and will only take a few 

days to tie in to existing pipe headers and diverter valves. Therefore, this installation or 

conversion can occur during normal scheduled maintenance outages [CBPG, 2010].

7.2.7 Mechanical System

Mechanical fly ash handling systems usually service generating units that generate a low 

volume of fly ash. These generating units are usually oil-fired and typically produce less ash than 

coal-fired generating 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 includes 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-fired generating 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 into 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, 2015a].
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7.3 BOTTOM ASH HANDLING, MANAGEMENT, AND TREATMENT TECHNOLOGIES

The information presented in this section is based on the Steam Electric Survey (2009 

data), industry profile changes (see Section 4.5), and industry-provided information. During the 

Steam Electric Power Generating detailed 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 final ELGs, 

EPA considered chemical precipitation for treating bottom ash transport water. However, upon 

reviewing the discharge flow rate for bottom ash transport water, EPA determined that the 

capital associated with chemical precipitation treatment were comparable to the costs of 

converting to dry handling or closed-loop recycle technologies, despite being less effective at 

removing pollutants [ERG, 2015g]. Therefore, EPA did not select chemical precipitation as a 

treatment technology basis for controlling bottom ash for the final ELGs. Bottom ash handling 

technologies evaluated by EPA, including a brief description of each, are listed below and 

described in detail in this section.

Bottom Ash Handling Systems that Generate Bottom Ash Transport Water

• Wet-Sluicing Systems: These systems convey bottom ash wet from a quench bath 

underneath the boiler via slurry lines usually to a surface impoundment. Some plants 

may wet sluice bottom ash transport water in combination with a surface 

impoundment, dewatering bin, and/or settling tank to recycle a portion or all water 

within the bottom ash handling system.

• 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.

• Dense Slurry Systems: These systems use a dry vacuum or pressure system to convey 

the bottom ash to a silo (as described below for the “Dry Vacuum or Pressure 

System”), but instead of using trucks to transport the bottom ash to a landfill, the 

plant mixes the bottom ash with a lower percentage of water compared to a wetsluicing system and pumps the mixture to the landfill.50

Bottom Ash Handling Systems that Do Not Generate Bottom Ash Transport Water

• 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. 

 50 Because of the much smaller volume of water used for the DSS, relative to a traditional wet sluicing system, 

plants should be better able to engineer and operate the process so that there will be no discharge. To accomplish 

this, plants should divert stormwater away from the dense slurry to the extent practicable. If stormwater or other 

wastestreams come into contact with the dense slurry prior to completing the solidification and evaporation or 

encapsulation of the transport water, the commingled wastestream would need to comply with the zero discharge 

standard for fly ash and bottom ash transport water.
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• Dry Mechanical Conveyor: These systems are located directly underneath the boiler. 

The system uses ambient air to cool the bottom ash in the boiler and then transports 

the ash out of the boiler using a conveyor. There is no water used in this process.

• 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: These systems deposit bottom ash on a vibratory conveyor 

trough, where the ash is air-cooled and ultimately moved through the conveyor deck 

to an intermediate storage destination.

EPA also identified mechanical systems as bottom ash handling systems. The mechanical 

systems include manual or systematic approaches to remove bottom ash (e.g., scraping the sides 

of the boilers with sprayers or shovels, then collecting and removing the bottom ash to an 

intermediate storage destination or disposal). Depending on the type of system used, it may or 

may not generate bottom ash transport water.

From information provided in the Steam Electric Survey, EPA determined that 350 coal-, 

petroleum coke-, and oil-fired power plants, corresponding to 717 coal- or petroleum coke-fired 

generating units and 23 oil-fired generating units, generate bottom ash. Figure 7-11 shows a 

distribution of the coal-, petroleum coke-, and oil-fired generating units based on their type of 

bottom ash handling system(s). For this figure, the systems are grouped into the following three 

categories:

• Generating units with wet-sluicing systems only.

• Generating units with systems that eliminate bottom ash transport water.

• Generating units with multiple bottom ash handling systems, including wet sluicing.

Approximately 58 percent of the 350 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 7-11, 

approximately 68 percent of coal- and petroleum coke-fired generating units use only wetsluicing systems to handle bottom ash, whereas over 95 percent of oil-fired units use systems that 

do not use bottom ash transport water. Based on survey data and publicly available data, EPA 

identified 17 plants (corresponding to 53 steam electric generating units) operating wet-sluicing 

systems that will convert from wet to all dry handling operations no later than December 31, 

2023 [ERG, 2015h]. After collecting the ash, plants can sell dewatered or dry bottom ash or send 

it to a landfill.
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Source: Steam Electric Survey [ERG, 2015a].

Note: This figure represents the EPA population used in analyses for the ELGs, which was developed using the 

Steam Electric Survey, industry profile changes (see Section 4.5), and additional industry-provided information.

Figure 7-11. 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 generating units is increasing [McDonough, 

2011]. From the Steam Electric Survey and Energy Information Administration (EIA) data, 

approximately 65 percent of steam electric generating units that began operating in the last 10 to 

25 years are installing handling systems other than wet sluicing. Of those systems, 67 percent are 

mechanical drag systems [ERG, 2015a]. Figure 7-12 shows the distribution of bottom ash 

handling systems, excluding generating units with any wet-sluicing systems, reported in the 

Steam Electric Survey for coal-, petroleum coke-, and oil-fired generating 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 7-12.
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Source: Steam Electric Survey [ERG, 2015a].

Note: This figure represents the EPA population used in analyses for the ELGs, which was developed using the 

Steam Electric Survey, industry profile changes (see Section 4.5), and additional industry-provided information.

Note: The coal- and petroleum coke-fire units categorized as “Unknown Dry Ash Conversion” are bottom ash 

handling conversions identified in the Updated Industry Profile Population described in Section 4.5.1. Therefore, 

EPA has verified that the steam electric generating unit is converting to dry or closed-loop bottom ash handling prior 

to implementation of the final rule, but the type of system is unknown. For more information about EPA’s 

incorporation of changes in the steam electric power generating industry, see Section 4.5.

Figure 7-12. Distribution of Bottom Ash Handling System Types Other Than Wet Sluicing 

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

Survey

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 (e.g., 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 it 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 power generating industry in 

more detail.
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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 wastewaters. 

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. Plants with dewatering bin systems 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 7-13 presents a diagram of a dewatering bin system 

with additional settling tanks after the dewatering bins.

Graphic reprinted with permission from United Conveyor Corporation [UCC, 2009].

Figure 7-13. Bottom Ash Dewatering Bin System

7.3.2 Bottom Ash Dense Slurry System

The DSS for handling bottom ash is similar to the DSS for handling fly ash. As described 

in Section 7.2.2, the DSS is a system that pumps a mixture of combustion residuals with water, 

where the solid-to-water ratio is approximately 1:1. This ratio for the dense slurry system is 

much higher than the solid-to-water ratio used in the wet-sluicing system, which is typically in 
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the range of 1:10 to 1:15. A DSS is designed to pump the slurry to a disposal location (i.e., 

landfill) where pozzolanic reactions occur to form a low hydraulic conductivity, highcompressible-strength solid product within 24 to 72 hours. See Section 7.2.2 for additional 

information regarding the operation of the DSS at JEA Northside [ERG, 2014b; GEA, 2013].

Because the DSS uses water to transport the bottom ash to the disposal area, this system is 

considered to generate bottom ash transport water and, therefore, the zero discharge requirements 

would apply to this system.

7.3.3 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. As shown in Figure 7-12, there are 84 units that 

operate a mechanical drag system, which represent 34 percent of all coal-, petroleum coke-, and 

oil-fired steam electric generating units which operate systems other than wet sluicing. 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 7-14 for a diagram of a mechanical drag system.

Because the trough has a water bath, the mechanical drag system does generate some 

wastewater (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 bottom ash transport water 

because the transport mechanism is the drag chain, not the water. Therefore, the MDS design 

does not include operation as a closed-loop system, eliminating the need for a heat exchanger. 51

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. These 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. In addition, these systems may be susceptible to 

maintenance outages because bottom ash fragments fall directly onto the drag chain. The outage 

 51 The MDS does not need to operate as a closed-loop system because it does not use water as the transport 

mechanism to remove the bottom ash from the boiler; the conveyor is the transport mechanism. Therefore, any water 

leaving with the bottom ash does not fall under the definition of “bottom ash transport water,” but rather, is a low

volume waste.
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required to install or convert to mechanical drag systems is about 6 to 8 weeks to demolish 

existing equipment and install new equipment. Therefore, this installation or conversion can 

occur during normal scheduled maintenance outages [CBPG, 2010].

Graphic reprinted with permission from United Conveyor Corporation [UCC, 2009].

Figure 7-14. Mechanical Drag System

7.3.4 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 except that 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 7-15 for a diagram 

of a remote mechanical drag system. Plants converting existing bottom ash handling systems can 

use this system where space or other restrictions 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 [ERG, 2015i, McDonough, 2012b].
Section 7—Treatment Technologies and

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Graphic reprinted with permission from United Conveyor Corporation [McDonough, 2012a].

Figure 7-15. 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 7.3.9), an underflow 

baffle prevents the finer particles from exiting the trough with the overflow. As shown in Figure 

7-16, the excess transport water in the trough flows over a serrated overflow weir. 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 or disposes of it in a landfill.

The settled bottom ash is removed from the trough using the same drag system described 

in Section 7.3.3. 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

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Graphic reprinted with permission from Clyde Bergemann Power Group [CBPG, 2012].

Figure 7-16. 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]. Unlike the mechanical drag system, remote mechanical drag systems are not 

located at the bottom of the boiler and, therefore, require 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. As such, any excess water that drains off the bottom ash as it is dewatered in an 

intermediate storage area is considered bottom ash transport water and must meet the zero

discharge requirements of the ELGs. In addition, the remote mechanical drag system can be 

installed nearby while the steam electric generating unit is on line and only takes a few days to 

tie into the piping to the settling basin/tank. Therefore, this installation or conversion can occur 

during normal scheduled maintenance outages [CBPG, 2010].

7.3.5 Dry Mechanical Conveyor

Dry mechanical conveyor systems operate similarly to a mechanical drag system, but 

instead of collecting the bottom ash in a water bath, it is collected directly onto the dry conveyor. 

The system introduces ambient air countercurrent to the direction of the bottom ash using the 

negative pressure in the furnace. Introducing additional air activates a reburning process and 

results in less unburned carbon and additional thermal energy to the steam electric generating 

process in the boiler, which increases the boiler efficiency. The dry conveyor then conveys the 
Section 7—Treatment Technologies and

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bottom ash to an intermediate storage destination. The plant then sells the ash or disposes of it in 

a landfill. The modular design of the system allows it to be retrofitted into plants with space or 

headroom limitations and a wide range of steam electric generating unit capacities (i.e., 5-1000 

megawatts (MW)). In addition, the outage required install or convert to a dry mechanical 

conveyer is about 6 to 8 weeks to demolish existing equipment and install new equipment. 

Therefore, this installation or conversion can occur during normal scheduled maintenance 

outages [CBPG, 2010]. Recent advancements related to bottom ash handling technologies, such 

as the dry mechanical conveyer, have focused on providing more flexible retrofit solutions and 

improving the thermal efficiency of the boiler operation, which result in additional savings 

related to electricity use, operation and maintenance, water costs, and thermal energy recovery.

A coal-fired steam electric power plant in Florida retrofitted its existing wet-sluicing 

systems on its two generating units (greater than 650 MW) with dry mechanical conveyers. The 

generating units experienced less than 22 days of outages before coming back online in April 

2012 and November 2012. After installing the dry mechanical conveyors, the plant has 

experienced a decrease in power consumption and O&M costs and a reduction in loss-onignition in the bottom ash [CBPG, 2013].

7.3.6 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 7-17 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 generating 

units because there are less structural limitations (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 generating units). The plant then sells the ash or 

disposes of it in a landfill. In addition, the outage required install or convert to dry vacuum or 

pressure systems is about 6 to 8 weeks. Therefore, this installation or conversion can occur 

during normal scheduled maintenance outages [UCC, 2011].
Section 7—Treatment Technologies and

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Graphic reprinted with permission from United Conveyor Corporation [UCC, 2009].

Figure 7-17. Dry Vacuum or Pressure Bottom Ash Handling System

7.3.7 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 7-18 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]. However, there are no vibratory belt systems operating in the United 

States. The outage required to install or convert to dry vacuum or pressure systems is about 6 to 

8 weeks. Therefore, this installation or conversion can occur during normal scheduled 

maintenance outages [UCC, 2011].
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Graphic reprinted with permission from United Conveyor Corporation [UCC, 2009].

Figure 7-18. Vibratory Bottom Ash Handling System

7.3.8 Mechanical System

Similar to fly ash handling systems, mechanical bottom ash handling systems usually 

service generating units that generate low volumes of bottom ash, or handle fly and bottom ash 

together. These units are usually oil-fired generating units, which typically produce less ash than 

coal-fired generating 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 collected ash in an ash impoundment, 

while others sell or dispose of the ash in a landfill.

7.3.9 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 mechanical drag system. 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 
Section 7—Treatment Technologies and

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7-48

sluice system, as shown in Figure 7-13. 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 makeup water to the quench water bath. 

For a remote mechanical drag system 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 treatment chemicals, specifically for pH 

control, to the overflow/decant water to eliminate any scaling or fouling caused by the recycled 

water.

Plants that install complete-recycle systems on existing wet-sluicing generating 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 use impoundment systems to achieve complete recycle. Some plants 

discharge the ash to an impoundment, or series of impoundments, to settle and then return all 

impoundment, or impoundment system, effluent to the boiler to use as transport water. These 

plants often add additional makeup water to the system to compensate for any water lost due to 

evaporation or water retained in the ash. In addition, closed recirculation systems can be built 

while the steam electric generating unit is on line and would not take more than a few days to tie 

into the system. Therefore, this installation or conversion can occur during normal scheduled 

maintenance outages [UCC, 2011].

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 residuals. 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, although the concentrations of the constituents in combustion 

residual leachate are generally lower than in FGD wastewater. Based on this characterization of 

the wastewater and knowledge of treatment technologies, EPA determined that certain treatment 

technologies identified for FGD wastewater could also be used to treat leachate from landfills 

and impoundments containing combustion residuals. 

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:
Section 7—Treatment Technologies and

Wastewater Management Practices

7-49

• Surface impoundments.

• Chemical precipitation.

• Biological treatment (anoxic/anaerobic system with fixed-film bioreactors).

• 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 system information received, EPA determined 

that surface impoundments are the most commonly used system to treat combustion residual 

leachate from landfills and impoundments [ERG, 2015a]. Figure 7-19 shows the distribution of 

combustion residual leachate treatment technologies reported in the Steam Electric Survey or 

determined by EPA through industry contacts for the 17 plants that reported treatment systems 

for combustion residual landfill and impoundment leachate.

Source: Steam Electric Survey [ERG, 2015a; WVDEP, 2010].

Note: This figure represents the EPA population used in analyses for the ELGs, which was developed using the 

weighted Steam Electric Survey data (see Section 4.2.4), industry profile changes (see Section 4.5), and additional 

industry-provided information.

Figure 7-19. 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 
Section 7—Treatment Technologies and

Wastewater Management Practices

7-50

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. EPA also identified five plants that use the collected leachate as truck wash and 

route it back to an impoundment.

EPA also identified from the Steam Electric Survey approximately 40 percent of plants 

that collect combustion residual impoundment leachate and recycle it directly back to the 

impoundment from which it was collected. In this case, because the wastewater originated from 

the impoundment, and the collection system is essentially just capturing and returning a portion 

of the impoundment wastewater, EPA does not consider the wastewater recycled directly back to 

the impoundment as a new wastestream entering the impoundment. 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 and 

discharged, then it would be considered combustion residual leachate and must comply with the 

applicable limitations established by the ELGs. EPA determined that six plants collect 

combustion residual leachate from the impoundment and use it as water for moisture 

conditioning dry fly ash prior to disposal or dust control around dry unloading areas and 

landfills. EPA also identified four additional plants that use combustion residual leachate for 

moisture conditioning fly ash and/or dust control; however, EPA was unable to determine if the 

wastewater originated from a landfill or impoundment.

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, these systems are relatively new to the industry.

Generally, there are two types of FGMC systems: addition of oxidizing agents to the coal 

prior to combustion and injection of activated carbon (or other sorption material) 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:

FGMC Systems that Generate FGMC Wastewater

• Wet-Sluicing System: These systems use water-powered hydraulic vacuums to create 

the vacuum for the initial withdrawal of FGMC waste from the hoppers. The FGMC 
Section 7—Treatment Technologies and

Wastewater Management Practices

7-51

waste is combined with the water used to create the vacuum and then pumped to an 

ash impoundment.

FGMC Systems that Do Not Generate FGMC Wastewater

• Wet Vacuum Pneumatic System: These systems use water-powered hydraulic 

vacuums to create the vacuum for the initial withdrawal of FGMC waste from the 

hoppers, similar to wet-sluicing systems; however, the FGMC waste is directed to a 

silo and is not combined with the water flowing through the sluice pipes.

• Dry Vacuum System: These systems use a mechanical exhauster to move air, below 

atmospheric pressure, to pull the FGMC waste from the hoppers and convey it 

directly to a silo.

• Pressure System: These systems use air produced by a positive displacement blower 

to convey the FGMC waste directly from the hopper to a silo.

• Combined Vacuum/Pressure System: These systems first utilize a dry vacuum system 

to pull FGMC waste from the hoppers to a transfer station and then use a positive 

displacement blower to convey the FGMC waste to a silo.

Based on responses to the Steam Electric Survey, EPA identified 62 power plants that 

operate ACI systems. Twelve of these plants inject the activated carbon downstream of the 

primary particulate removal system and the remaining 50 plants inject the activated carbon 

upstream of the particulate removal system [ERG, 2015a]. 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 11 downstream ACI systems handle the FGMC waste dry.

• Of the upstream ACI systems, three 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 discharged52

• The remaining 47 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 integrated gasification

combined cycle (IGCC) plants from the gasification process, as well as operating/management 

practices used to reduce the wastewater discharge. This section describes the following 

technologies:

 52 Two of these plants do not discharge any FGMC wastewater. The one plant that does discharge the FGMC

wastewater also has the capability to handle its fly ash and FGMC waste using a dry system.
Section 7—Treatment Technologies and

Wastewater Management Practices

7-52

• Evaporation system.

• Cyanide destruction.

EPA is aware of three plants that currently operate IGCC units in the United States.53 All 

three of these plants currently treat the gasification wastewaters with evaporation systems. One

of these plants installed a cyanide destruction system in addition to an evaporation system.

7.6.1 Evaporation System

As described in Section 7.1.4, plants can use evaporation systems to treat FGD 

wastewater and cooling tower blowdown. Additionally, the plants currently operating IGCC 

units are using evaporation systems to treat the gasification wastewaters generated. The 

treatment system design 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 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 an 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 plant 

installed a cyanide destruction system to treat both the distillate and condensate effluent streams 

from the 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.

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Section 7—Treatment Technologies and

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Section 7—Treatment Technologies and

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34. EPRI. 2009b. Selenium Removal by Iron Cementation from a Coal-Fired Power 

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35. EPRI. 2014. Pilot Evaluation of the ZVI BlueTM Technology for Flue Gas 

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37. FLSmith, Inc. 2012. Fly Ash Handling Illustration. (October). DCN SE02038.

38. GEA EGI Contracting/Engineering Co. Ltd. 2013. Comments of GEA on Effluent 

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39. GEA EGI Contracting/Engineering Co. Ltd. 2014. Notes from Call with GEA EGI 

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40. Goltz, Robert et al. 2009. Trace Mercury Removal from Flue Gas Desulfurization 

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41. Hsu, S. and P. C. Singer. 2010. "Removal of bromide and natural organic matter by 

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43. Jordan, Ron. 2008. Site Visit Notes: Progress Energy Carolinas’ Roxboro Steam 

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48. Loewenberg, Matthias. 2012. Zero-Liquid Discharge System at Progress Energy 

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(April). DCN SE02017.

50. McDonough, Kevin. 2012a. Letter from Kevin McDonough, UCC, to Jezebele 

Alicea, EPA, Re: Copyright Permission Request – United Conveyor Corporation 

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51. McDonough, Kevin. 2012b. Teleconference Notes between Kevin McDonough & 

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53. Michel, Tim. 2012. Telephone conversation with Michel Tim of Milestone, Inc. and 

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54. Mooney, Gary. 2010. Telephone and email communication with Gary Mooney, 

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55. Pickett, Tim et al. 2005. ABMet® Biological Selenium Removal from FGD 

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58. Rogers, John et al. 2005. Specifically Designed Constructed Wetlands: A Novel 

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59. Sanchez-Polo, M. et al. 2007. "Bromide and iodide removal from waters under 

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60. Schultz, Shelly. 2013. Teleconference Notes between Timothy Peschman, Adam 

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61. Smagula, William. 2010. Letter from William H. Smagula, Public Service Company 

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Section 8—The Final Rule

8-1

SECTION 8

THE FINAL RULE

This section describes the final rule, including the technology bases and rationale for the 

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

Point Source Category. This section describes the revisions to 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).

• Pretreatment Standards for New Sources (PSNS).

The technology options selected as the basis for the final rule incorporate pollutant 

control technologies that are demonstrated in the steam electric power generating industry, 

minimize water use, and result in minimal non-water quality environmental impacts. While EPA 

establishes limitations and standards based on a particular set of in-process 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, in-process technologies, 

and end-of-pipe wastewater treatment technologies to achieve the ELGs.

EPA selected the technology bases for the final rule for each wastestream from the 

technologies described in Section 7. Section 8.1 describes the existing BPT/BCT requirements. 

Section 8.2 describes the regulatory options and underlying technology bases evaluated for BAT, 

NSPS, PSES, and PSNS. Sections 8.3 through 8.6 discuss the rationale for the selected 

technology bases for BAT, NSPS, PSES, and PSNS, respectively. Sections 8.7 through 8.10

discuss other elements of the final rule, including anticircumvention provisions, applicability 

clarification, non-chemical metal cleaning waste, and best management practices (BMPs).

8.1 BPT

The final rule does not revise the previously established best practicable control 

technology currently available (BPT) effluent limitations because the rule regulates the same 

wastestreams at the more stringent BAT/NSPS level of control. The rule does, however, make

certain structural modifications to the BPT regulations in light of new and revised definitions. In 

particular, the final rule establishes separate definitions for FGD wastewater, FGMC wastewater, 

gasification wastewater, and combustion residual leachate, making clear that these four 

wastestreams are no longer considered low volume waste sources. Given these new and revised 

definitions, the final rule modifies the structure of the previously established BPT regulations so 

that they specifically identify these four wastestreams, but without changing their applicable 

BPT limitations, which are equal to those for low volume waste sources.
Section 8—The Final Rule

8-2

8.2 DESCRIPTION OF THE BAT/NSPS/PSES/PSNS OPTIONS

EPA analyzed many regulatory options at proposal, the details of which were discussed 

fully in the document published on June 7, 2013 (78 FR 34432). EPA proposed to regulate 

pollutants found in seven wastestreams found at steam electric power plants, each based on 

particular control technologies. Depending on the interests represented, public commenters 

supported virtually all of the regulatory options that EPA proposed – from the least stringent to 

the most stringent, and many options in between. For this final rule, based on public comments, 

EPA also considered a few additional regulatory options. None of these additional regulatory 

options involve regulation of different control technologies than those explicitly considered and 

presented at proposal. Rather, they involve slight variations on the overall packaging of the key 

options presented at proposal. Thus, in developing this final rule, EPA named six main 

regulatory options, Options A, B, C, D, E, and F.54 Table 8-1 summarizes these six regulatory 

options. In general, as one moves from Option A to Option F, there is a greater estimated 

reduction in pollutant discharges from steam electric power plants and a higher associated cost.

Consistent with the proposed rule, under all Options A through F, for oil-fired generating 

units and small generating units (50 megawatts (MW) or smaller) that are existing sources, the 

rule would establish BAT/PSES effluent limitations and standards on TSS in fly ash transport 

water, bottom ash transport water, FGD wastewater, FGMC wastewater, combustion residual 

leachate, and gasification wastewater equal to the previously promulgated BPT effluent 

limitations on TSS55 in fly ash transport water, bottom ash transport water, and low volume 

waste sources, where applicable. Under Options A through E, EPA would establish a voluntary 

incentives program for plants that choose to meet BAT limitations for FGD wastewater based on 

evaporation technology. Moreover, as EPA proposed, under Options A through F, the ELG 

would establish an anti-circumvention provision designed to ensure that the purpose of the rule is 

achieved, as further described in Section 8.7. Finally, as EPA proposed, under all Options A 

through F, the ELG would correct a typographical error in the previously promulgated 

regulations, as well as make certain clarifying revisions to the applicability provision of the 

regulations, as further described in Section 8.8.

Sections 8.2.1 through 8.2.7 describe Options A through F, by wastestream, including the 

technology bases for the requirements associated with each.

 54 Option B is equivalent to Proposed Option 3, Option C is equivalent to Proposed Option 4a, and Option E is 

equivalent to Proposed Option 4 and Option F is equivalent to Proposed Option 5. Option A is a slight variant of 

Proposed Options 1 and 3 and Option D is a slight variant of Proposed Option 4. 

55 Although TSS is a conventional pollutant, whenever EPA would be regulating TSS in this final rule, it would be 

regulating it as an indicator pollutant for the particulate form of toxic metals.
Section 8—The Final Rule

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Table 8-1. Steam Electric Power Generating Point Source Category Regulatory Options

Wastestreams

Technology Basis for BAT/NSPS/PSES/PSNS

Regulatory Options

A B C D E F

FGD

Wastewater

Chemical 

Precipitation

Chemical Precipitation 

+ Biological Treatment

Chemical Precipitation + 

Biological Treatment

Chemical Precipitation + 

Biological Treatment

Chemical Precipitation 

+ Biological 

Treatment

Evaporation

Fly Ash Transport 

Water

Dry Handling Dry Handling Dry handling Dry handling Dry handling Dry handling

Bottom Ash 

Transport Water

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

Dry handling/

Closed loop

FGMC

Wastewater

Dry handling Dry handling Dry handling Dry handling Dry handling Dry handling

Gasification

Wastewater

Evaporation Evaporation Evaporation Evaporation Evaporation Evaporation

Combustion 

Residual Leachate

Impoundment (Equal

to BPT)

Impoundment (Equal to

BPT)

Impoundment

(Equal to BPT)

Impoundment

(Equal to BPT)

Chemical 

Precipitation

Chemical 

Precipitation

Non-Chemical 

Metal Cleaning 

Wastes

[Reserved] [Reserved] [Reserved] [Reserved] [Reserved] [Reserved]
Section 8—The Final Rule

8-4

8.2.1 FGD Wastewater

Under Option A, EPA would establish effluent limitations and standards for mercury and 

arsenic in FGD wastewater based on treatment using chemical precipitation. As used in the 

regulatory options for this rulemaking, this technology is a combination of hydroxide 

precipitation, iron coprecipitation, and sulfide precipitation to remove heavy metals. Under 

Options B through E, EPA would establish effluent limitations and standards for mercury, 

arsenic, selenium, and nitrate-nitrite as N in FGD wastewater based on treatment using chemical 

precipitation followed by biological treatment. For the regulatory options, biological treatment 

refers to an anoxic/anaerobic fixed-film biological system optimized to remove selenium from 

the wastewater. Part of the technology basis under Options A through E would also include the 

use of flow minimization for plants with high FGD discharge flow rates (greater than 1,000 

gpm).56 Under Option F, EPA would establish effluent limitations and standards for mercury, 

arsenic, selenium, and TDS in FGD wastewater based on treatment using an evaporation system. 

Under all options, to facilitate implementation of the new BAT/NSPS/PSES/PSNS requirements, 

EPA would also promulgate a definition for FGD wastewater, making clear it would no longer 

be considered a low volume waste source.

8.2.2 Fly Ash Transport Water

Under all Options A through F, EPA would establish (or in the case of NSPS/PSNS, 

maintain) zero discharge effluent limitations and standards for pollutants in fly ash transport 

water based on use of a dry handling system. For the regulatory options, a dry handling system 

refers to a dry vacuum 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. Fly ash dry 

handling technologies are described in more detail in Section 7.

8.2.3 Bottom Ash Transport Water

Under Options A and B, EPA would establish effluent limitations and standards for 

bottom ash transport water equal to the previously promulgated BPT limitation on TSS,57 which 

is based on the use of a surface impoundment. Under Options D, E, and F, EPA would establish 

zero discharge effluent limitations and standards for pollutants in bottom ash transport water 

based on one of two technologies: a dry handling system or a closed-loop system. EPA evaluated 

two different technology bases for bottom ash because not all plants will be able to install a dry 

handling system due to space constraints at the boiler. For the dry handling system, EPA 

evaluated a mechanical drag system, where the bottom ash collects in a water quench bath and a 

drag chain conveyor pulls the bottom ash out of the water bath on an incline to dewater the 

bottom ash. For the closed-loop system, EPA evaluated a remote mechanical drag system, where 

the bottom ash is transported using the same processes as a wet-sluicing system. However, 

instead of transporting the bottom ash to an impoundment, the ash is sluiced to a remote 

mechanical drag system, where a drag chain conveyor pulls the bottom ash out of the water on an 

 56 Only for those high-flow plants where the metallurgy of the FGD system can accommodate higher chloride 

concentrations that would result from flow minimization.

57 Although TSS is a conventional pollutant, whenever EPA would be regulating TSS in this final rule using BAT, it 

would be regulating it as an indicator pollutant for the particulate form of metals.
Section 8—The Final Rule

8-5

incline to dewater it. The transport (sluice) water is treated to remove solids in a settling tank and 

is recycled to the bottom ash collection system. Both mechanical drag and remote mechanical 

drag systems are described in more detail in Section 7. Under Option C, EPA would establish, 

for bottom ash transport water, zero discharge limitations and standards based on dry handling or 

closed-loop systems only for generating units with a nameplate capacity of more than 400 MW. 

Units with a nameplate capacity equal to or less than 400 MW would have to meet new effluent 

limitations and standards equal to the previously established BPT limitation on TSS, based on 

surface impoundments.

8.2.4 FGMC Wastewater

Under all Options A through F, EPA would establish zero discharge effluent limitations 

and standards for FGMC wastewater based use of a dry handling system. For the regulatory 

options, dry handling system refers to a dry vacuum system that uses a mechanical exhauster to 

move air, below atmospheric pressure, to pull the FGMC waste from the hoppers and convey it 

directly to a silo. Dry handling systems are described in more detail in Section 7. The previously 

established regulations included FGMC wastewater within the definition of low volume waste 

sources, which is subject to BPT limitations for TSS and oil and grease (based on surface 

impoundments). Under all Options A through F, EPA would establish a separate definition for 

FGMC wastewater, making clear it would no longer be considered a low volume waste source.

8.2.5 Gasification Wastewater

The technology basis for control of gasification wastewater under all Options A through 

F is an evaporation system. Under these options, EPA would establish limitations and standards 

on arsenic, mercury, selenium, and total dissolved solids (TDS) in gasification wastewater. For 

the regulatory options, evaporation refers to a system using 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. Evaporation systems are described in more detail in Section 7. As 

with FGMC wastewater, the previously established regulations included gasification wastewater 

within the definition of low volume waste sources, which is subject to BPT limitations on TSS 

and oil and grease, based on surface impoundments. Under all Options A through F, EPA would 

establish a separate definition for gasification wastewater, making clear it would no longer be 

considered a low volume waste source.

8.2.6 Combustion Residual Leachate from Surface Impoundments and Landfills 

Containing Combustion Residuals

Under Options A through D, EPA would establish effluent limitations and standards for 

combustion residual leachate from surface impoundments and landfills containing combustion 

residuals equal to the previously promulgated BPT effluent limitation on TSS58 for low volume 

waste sources. Under Options E and F, EPA would establish limitations and standards on arsenic 

and mercury in combustion residual leachate based on treatment using a chemical precipitation

system (the same technology basis described for control of FGD wastewater under Option A).

 58 Although TSS is a conventional pollutant, whenever EPA would be regulating TSS in this final rule, it would be 

regulating it as an indicator pollutant for the particulate form of toxic metals.
Section 8—The Final Rule

8-6

See Section 7 for a discussion of these technologies. As with FGMC and gasification wastewater, 

the previously established regulations included combustion residual leachate within the 

definition of low volume waste sources, which is subject to BPT limitations on TSS and oil and 

grease. Under all Options A through F, EPA would establish a separate definition for combustion 

residual leachate, making clear it would no longer be considered a low volume waste source.

8.2.7 Non-Chemical Metal Cleaning Wastes

Under all Options A through F, EPA would continue to reserve BAT/NSPS/PSES/PSNS 

for non-chemical metal cleaning wastes, as the previously established regulations do.

8.3 BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE

After considering the technologies described in Section 7, as well as public comments,

and in light of the factors specified in CWA sections 304(b)(2)(B) and 301(b)(2)(A), EPA

decided to establish BAT effluent limitations based on the technologies described in Option D. 

Thus, for BAT, the final rule establishes: 

• Limitations on arsenic, mercury, selenium, and nitrate-nitrite as N in FGD 

wastewater, based on chemical precipitation plus biological treatment.59

• A zero discharge limitation for pollutants in fly ash transport water, based on dry 

handling. 

• A zero discharge limitation for pollutants in bottom ash transport water, based on dry 

handling/closed-loop systems. 

• A zero discharge standard for FGMC wastewater, based on dry handling. 

• Limitations on mercury, arsenic, selenium, and TDS in gasification wastewater, based 

on evaporation. 60

• A limitation on TSS in combustion residual leachate based on surface 

impoundments.61

The final rule also establishes new definitions for FGD wastewater, FGMC wastewater, 

gasification wastewater, and combustion residual leachate.

Sections 8.3.1 through 8.3.6 provide more detail on the Option D technologies for each 

wastestream.

 59 For those plants that choose to participate in the voluntary incentives program, the applicable limitations are for 

arsenic, mercury, selenium, and TDS in FGD wastewater, based on the use of an evaporation system (see Section 

8.3.13).

60 For small (50 MW or less) generating units and oil-fired generating units, the final rule establishes different BAT 

limitations for FGD wastewater, fly ash transport water, bottom ash transport water, FGMC wastewater, and 

gasification wastewater (see Section 8.3.12).

61 The final rule also establishes BAT limitations on TSS in discharges of “legacy wastewater,” which are equal to 

previously established TSS limitations (see Section 8.3.8).
Section 8—The Final Rule

8-7

8.3.1 FGD Wastewater

This rule identifies treatment using chemical precipitation followed by biological 

treatment as the BAT technology basis for control of pollutants discharged in FGD wastewater. 

More specifically, the technology basis for BAT is a chemical precipitation system that employs 

hydroxide precipitation, sulfide precipitation (organosulfide), and iron coprecipitation, followed 

by an anoxic/anaerobic fixed-film biological treatment system designed to remove heavy metals, 

selenium, and nitrates.62 After accounting for industry changes described in Section 4.5, fortyfive percent of all steam electric power plants with wet scrubbers have equipment or processes in 

place able to meet the final BAT/PSES effluent limitations and standards.63 Many of these plants 

use FGD wastewater management approaches that eliminate the discharge of FGD wastewater.64

Other plants employ wastewater treatment technologies that reduce the amount of pollutants in 

the FGD wastestream.

Both chemical precipitation and biological treatment are well-demonstrated technologies 

that are available to steam electric power plants for use in treating FGD wastewater. Based on 

responses to the Questionnaire for the Steam Electric Power Generating Effluent Guidelines 

(Steam Electric Survey), 39 U.S. steam electric power plants (44 percent of plants discharging 

FGD wastewater) use some form of chemical precipitation as part of their FGD wastewater 

treatment system. More than half of these plants (30 percent of plants discharging FGD 

wastewater) use both hydroxide and sulfide precipitation in the process to further reduce metals 

concentrations. In addition, for the last several decades, thousands of industrial facilities 

nationwide such as Metal Products and Machinery facilities, Iron & Steel manufacturers, metal 

finishers, and mining operations (including coal mines) have used chemical precipitation (see

Section 7) [U.S. EPA, 2003; U.S. EPA, 2002; U.S. EPA, 1983].65

The biological treatment system that forms part of the basis for BAT in the ELG is 

optimized to remove selenium from the wastewater. The information in the record 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 

 62 In estimating costs associated with this technology basis, EPA assumed that in order to meet the limitations and 

standards, certain plants with high FGD discharge flow rates (greater than or equal to 1,000 gpm) would elect to 

incorporate flow minimization into their operating practices (by reducing the FGD purge rate or recycling a portion 

of their FGD wastewater back to the FGD system), where the FGD system metallurgy can accommodate an increase 

in chlorides. See Section 4.5.4 of EPA’s Incremental Costs and Pollutant Removals for the Final Effluent 

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

2015a].

63 This value accounts for announced retirements, conversions, and changes plants are projected to make to comply 

with the CPP and CCR rules.

64 A variety of approaches that depend on plant specific conditions are used to achieve zero pollutant discharge at 

these plants, including evaporation ponds, complete recycle, and processes that combine the FGD wastewater with

other materials for landfill disposal. Although these technologies, as well as others currently used for achieve zero 

pollutant discharge, may be available for some plants with FGD wastewater, EPA determined they are not available 

nationally. For example, evaporation ponds are only available in certain climates. Similarly, complete recycle is only 

available at plants with appropriate FGD metallurgy. 

65 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—The Final Rule

8-8

precipitation treatment stage preceding the bioreactor, can be substantial. In addition, the anoxic 

conditions in the bioreactor can remove substantial concentrations of nitrates by denitrification. 

FGD wastewater containing exceptionally high levels of nitrates (e.g., greater than 100 parts per 

million (ppm) nitrate/nitrite (as N)) can be pretreated using standard denitrification technologies 

such as membrane bioreactors or stirred-tank bioreactors. If necessary, the biological processes 

can also be modified to include a step to nitrify and remove ammonia. 

Biological treatment has been tested at steam electric power plants for more than ten

years and full-scale systems have been operating at a subset of plants for seven years. It has been 

widely used in many industrial applications for decades in both the U.S. and abroad and it has 

been employed at coal mines. Currently, six U.S. steam electric power plants (approximately ten 

percent of those discharging FGD wastewater) use biological treatment designed to substantially 

reduce nitrogen compounds and selenium in their FGD wastewater. Other power plants are 

considering installing biological treatment to remove selenium, and at least one plant is 

scheduled to begin operating a biological treatment system for selenium removal next year [GE, 

2015]. An additional two plants are installing a similar treatment system to remove selenium in 

discharges of combustion residual leachate [ERG, 2015a]. Four of the six plants using biological 

systems to treat FGD wastewater precede the biological treatment stage with chemical 

precipitation; thus, the entire system is designed to remove suspended solids, particulate and 

dissolved metals (such as mercury and arsenic), soluble and insoluble forms of selenium, and 

nitrate and nitrite forms of nitrogen. These plants show that chemical precipitation followed by 

biological treatment is technologically available and demonstrated. The other two plants 

operating anoxic/anaerobic bioreactors to remove selenium precede the biological treatment 

stage with surface impoundments instead of chemical precipitation. The treatment systems at 

these two plants are likely to be less effective at removing metals (including many dissolved 

metals) and would likely face more operational problems than the plants employing chemical 

pretreatment, but they nevertheless show the efficacy and availability of biological treatment for 

removing selenium and nitrate/nitrite in FGD wastewater. Finally, vendors continue to make 

improvements to these systems and to develop non-biological systems for selenium removal.

BAT for FGD wastewater also incorporates flow minimization for certain plants with 

high FGD discharge flow rates (greater than 1,000 gpm). Plants may choose to minimize their 

flows by either reducing the FGD purge rate or recycling a portion of their FGD wastewater back 

to the FGD system. 

A few commenters questioned the feasibility of biological treatment at some power 

plants. Specifically, they claimed, in part, that the efficacy of biological systems is unpredictable 

and is subject to temperature changes, high chloride concentrations, scaling, and high oxidationreduction potential (ORP) in the absorber, which could kill the microorganisms in the bioreactor. 

EPA’s record does not support these assertions for a well-designed and well-operated chemical 

precipitation and biological treatment system.

EPA’s record demonstrates that proper pretreatment prior to biological treatment and 

proper monitoring with adjustments to the treatment system as necessary are key to reducing 

operational concerns raised by commenters. Proper pretreatment includes chemical precipitation, 

which can address wastewater containing high oxidant loadings through addition of a reducing 
Section 8—The Final Rule

8-9

agent in one of the treatment system’s reaction tanks.

66 EPA included capital costs for a chemical 

addition system and hopper for a reducing agent in its cost estimates for the BAT limitations 

based on chemical precipitation plus biological treatment. The dose of reducing agent can be 

determined in real time based on a combination of pH and ORP measurements of the feed to the 

chemical precipitation system. System operators may wish to conduct testing to correlate pH and 

ORP with the necessary dosage of reducing agent. Alternatively, operators could use a simple 

titration to determine Total Oxidant Load (e.g., iodometric titration) to determine the amount of 

reducing agent that must be added to remove any oxidant load. The reaction between any oxidant 

in the wastewater and the reducing agent is very fast and would not require a separate mixing 

tank. Additionally, EPA recommends that plants evaluate the operation of their FGD scrubbers 

to understand what conditions lead to high oxidant excursions and optimize the operation of the 

scrubber with respect to wastewater treatment. Recent pilot studies of biological treatment 

systems for FGD wastewater treatment demonstrate that monitoring ORP, pH, and total oxidant 

loading is essential for proper operation of these systems and have shown that these strategies 

can be used to address the issue of high oxidant load in FGD wastewater [ERG, 2015b].

Monitoring these parameters enables the plant to adjust the system as necessary. For example, 

plants that monitor ORP in the absorber or in the FGD purge will have sufficient advanced 

warning to respond to elevated ORP levels by adding a chemical reductant to the chemical 

precipitation system and/or increasing the feed rate of the nutrient mix in the biological reactor.

EPA’s cost estimates account for all of these monitoring steps. 

Plants can also use the chemical precipitation system to minimize scaling on downstream 

equipment. FGD wastewater leaving the hydroclones may be saturated or potentially 

supersaturated with calcium sulfate, which could cause significant scaling if calcium sulfate 

deposits form in piping or other surfaces of the FGD wastewater treatment system. A welldesigned and well-operated chemical/physical precipitation system has enough residence time 

and optimized chemical conditions to precipitate much of the calcium sulfate as solid particles 

and then remove them in the clarifier.

Although chemical precipitation systems are typically not able to remove chlorides from 

FGD wastewater, EPA’s record demonstrates that the anaerobic bioreactor systems can handle

chloride levels of up to 30,000 ppm [GE, 2014a]. Careful system design can account for this 

constraint by adjusting the amount of flow minimization used in the FGD scrubber and the size 

of the treatment system itself.

FGD wastewater containing exceptionally high levels of nitrates (e.g., greater than 100 

ppm nitrate/nitrite as N) can be pretreated using standard denitrification technologies such as 

membrane bioreactors or stirred-tank bioreactors. If necessary, the biological processes can also 

be modified to include a step to nitrify and remove ammonia. EPA’s cost estimates account for 

this pretreatment step. EPA’s record, moreover, shows that the treatment systems that form the 

bases for the BAT limitations for FGD wastewater are able to effectively remove the regulated 

pollutants at varying influent concentrations [U.S. EPA, 2015b]. Finally, vendors continue to 

make improvements to these systems and to develop non-biological systems for selenium 

 66 EPA included the equipment for chemical addition of a reducing agent in its cost estimates for Options B through 

E.
Section 8—The Final Rule

8-10

removal. Additional information on strategies to address potential operational concerns are 

included in EPA’s communications with the vendor [GE, 2014a; GE, 2014b].

Some commenters also claimed that the efficacy of biological systems in removing 

selenium is subject to changes in switching from one coal type to another (also referred to as fuel 

flexing). Where EPA had biological treatment performance data paired with fuel type, EPA 

reviewed it and found that existing biological treatment systems continue to perform well during 

periods of fuel switching [ERG, 2015c]. The data show that, in all cases except one, the plants 

met the selenium limitations following fuel switches. In one instance when a plant switched to a 

certain coal type, the plant exceeded the final daily maximum selenium limitation for one out of 

thirteen observations for the month while the average of all values for that month were below the 

final monthly selenium limitation. While the data demonstrate that one plant did, at times, 

experience elevated selenium effluent concentrations when it switched to a certain coal type, it 

also showed that there were no changes in selenium effluent concentrations at several other times 

when the plant switched coals. This plant was not subject to a selenium limit at the time data was 

collected. Moreover, EPA’s record demonstrates that effective communication between the 

operator(s) of the generating unit and the boiler, as well as bench testing and monitoring the 

ORP, and making proper adjustments to the operation of the treatment system, would make it 

possible to prevent potential selenium exceedances at this plant. Data for two other plants 

operating full-scale biological treatment systems shows that fuel switches should not result in 

exceeding the effluent limitations. EPA also has data from a pilot project at another plant 

employing the same type of coal used by the one plant that experienced elevated selenium 

effluent concentrations following a coal switch. The data for this pilot project demonstrate 

effective selenium removal by the BAT technology basis, with all effluent values at 

concentrations below the BAT limitations established in this rule. 

EPA also reviewed effluent data in the record for plants operating combined chemical 

precipitation and biological treatment for FGD wastewater to evaluate how cycling operation 

(i.e., changes in electricity generation rate) and short or extended shutdown periods may affect 

the ability of plants to meet the BAT effluent limitations. These data demonstrate that cycling 

operations and shutdown periods, whether short or long in duration, are manageable and do not 

result in plants being unable to meet the ELG effluent limitations [ERG, 2015c]. 

EPA did not select surface impoundments as the technology basis for BAT for FGD 

wastewater because it would not result in reasonable further progress toward eliminating the 

discharge of all pollutants, particularly toxic pollutants (see CWA section 301(b)(2)(A)). Surface 

impoundments, which rely on gravity to remove particulates from wastewater, are the technology 

basis for the previously promulgated BPT effluent limitations for low volume waste sources.

Pollutants that are present mostly in soluble (dissolved) form, such as selenium, boron, and 

magnesium, are not effectively and reliably removed by gravity in surface impoundments. For 

metals present in both soluble and particulate forms, such as mercury, gravity settling in surface 

impoundments does not effectively remove the dissolved fraction. Furthermore, the environment 

in some surface impoundments can create chemical conditions (e.g., low pH) that convert 

particulate forms of metals to soluble forms, which are not removed by the gravity settling

process. Additionally, EPRI has reported that adding FGD wastewater to surface impoundments 

used to treat ash transport water can reduce the settling efficiency in the impoundments due to 

gypsum particle dissolution, thus increasing the effluent TSS concentrations. Discharging 
Section 8—The Final Rule

8-11

wastewater containing elevated levels of TSS would likely result in also discharging other 

pollutants (e.g., metals) in higher concentrations.67 EPRI has also reported that 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 higher concentrations 

of metals in discharges from surface impoundments [EPRI, 2006].

Surface impoundments are also subject to seasonal turnover, which adversely affects their 

efficacy. 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.68 Typically, during fall, as the air 

temperature decreases, the upper layer of the impoundment becomes cooler and denser, thereby 

sinking and causing the entire volume of the impoundment to circulate. Solids that have 

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.

Chemical precipitation and biological treatment are more effective than surface 

impoundments at removing both soluble and particulate forms of metals, as well as other 

pollutants such as nitrogen compounds and TDS. Because many of the pollutants of concern in

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 in the FGD wastestream, EPA decided not to finalize

BAT effluent limitations for FGD wastewater based on surface impoundments.

EPA also rejected identifying chemical precipitation, alone, (Option A) as BAT for FGD 

wastewater because, while chemical treatment systems are capable of achieving removals of 

various metals, the technology is not effective at removing selenium, nitrogen compounds, and 

certain metals that contribute to high concentrations of TDS in FGD wastewater. These 

pollutants of concern are discharged by steam electric power plants throughout the nation, 

causing adverse human health impacts and some of the most egregious environmental impacts 

(see the Environmental Assessment for the Final Effluent Limitations Guidelines and Standards 

for the Steam Electric Power Generating Point Source Category). In light of this, and the fact 

that economically achievable technologies are available to reduce these pollutants of concern, 

EPA determined that, by itself, chemical precipitation would not result in reasonable further 

progress toward the national goal of eliminating the discharge of all pollutants (see CWA section 

 67 Although TSS is a conventional pollutant, whenever EPA would be regulating TSS in this final rule, it would be 

regulating it as an indicator pollutant for the particulate form of toxic metals.

68 The anoxic, or low oxygen, conditions that are created at the bottom of surface impoundments do not achieve the 

same type of pollutant removals as a designed anoxic/anaerobic biological treatment system.
Section 8—The Final Rule

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301(b)(2)(A)), and rejected that technology basis as BAT in favor of chemical precipitation 

followed by anaerobic/anoxic biological treatment.

EPA also decided not to establish, for all steam electric power plants, BAT limitations for 

FGD wastewater based on treatment using an evaporation system. In particular, this technology 

basis would employ a falling-film evaporator (also known as a brine concentrator) to produce a 

concentrated wastewater stream (brine) and a distillate stream.

69 While evaporation systems are 

effective at removing boron and pollutants that contribute to high concentrations of TDS, EPA 

decided it would not be appropriate to identify evaporation as the basis for BAT limitations for 

FGD wastewater at all steam electric power plants because of the high cost of possible regulatory 

requirements based on evaporation for discharges of FGD wastewater at existing facilities. The 

annual cost to the industry of limitations based on evaporation would be more than 2 and 1⁄2 times 

the cost to industry estimated for the final rule (after tax) (approximately $570 million more 

expensive than the final rule, on an annual basis, after tax). Given the high costs associated with 

the technology, and the fact that the steam electric industry is facing costs associated with several 

other rules in addition to this rule, EPA decided not to establish BAT limitations for FGD 

wastewater based on evaporation for all steam electric power plants. Nevertheless, the final rule

does establish a voluntary incentives program under which steam electric power plants can 

choose to be subject to more stringent BAT limitations for FGD wastewater based on 

evaporation. See Section 8.3.13 for more discussion of the voluntary incentives program.

Although EPA has decided not to finalize BAT requirements based on evaporation for 

treating FGD wastewater at all steam electric power plants in the ELG, evaporation technology is

potentially available and may be appropriate to achieve water quality-based effluent limitations, 

depending on site-specific conditions. For example, evaporation may be appropriate for those 

steam electric power plants that discharge upstream of drinking water treatment plants and 

whose discharge of bromide negatively impacts treatment of source waters at these treatment 

plants.

Finally, EPA decided not to establish a requirement that would direct permitting 

authorities to establish limitations for FGD wastewater using site-specific Best Professional 

Judgment (BPJ). Public commenters representing industry, state, and environmental group 

interests urged EPA not to establish any requirement that would leave BAT effluent limitations 

for FGD wastewater to be determined on a BPJ basis. Sections 301 and 304 of the CWA require 

EPA to develop nationally applicable ELGs based on the BAT, taking certain factors into 

account. EPA decided that it would not be appropriate to leave FGD wastewater requirements in 

the final rule to be determined on a BPJ basis because there are sufficient data to set uniform, 

nationally applicable limitations on FGD wastewater at plants across the nation. Given this, BPJ 

permitting of FGD wastewater would place an unnecessary burden on permitting authorities, 

including state and local agencies, to conduct a complex technical analysis that they may not 

have the resources or expertise to complete. BPJ permitting of FGD wastewater would also 

unnecessarily burden the regulated industry because of associated delays and uncertainty with 

respect to permits.

 69 This evaporation step would have been preceded by a chemical precipitation step using hydroxide precipitation,

sulfide precipitation, and iron co-precipitation, as well as a softening step.
Section 8—The Final Rule

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8.3.2 Fly Ash Transport Water

This rule identifies dry handling as the BAT technology basis for control of pollutants in 

fly ash transport water. Specifically, the technology basis for BAT is a dry vacuum system that 

employs a mechanical exhauster to pneumatically convey the fly ash (via a change in air 

pressure) from hoppers directly to a silo. Dry handling is clearly available to control the 

pollutants present in fly ash transport water. Today, the vast majority of steam electric power 

plants use dry handling techniques to manage fly ash, and by doing so avoid generating fly ash 

transport water. Based on data collected in the Steam Electric Survey, EPA estimates that 

approximately 80 percent of coal- and petroleum coke-fired generating units handle all fly ash 

with dry technologies. Another 13 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 after retrofitting with a dry system). Only 7 percent of coaland petroleum coke-fired generating units exclusively use a wet fly ash handling system and 

some of these plants manage the ash handling process so that they do not discharge fly ash 

transport water. As a result, EPA estimated that only 16 coal-fired steam electric power plants 

would incur costs to comply with a zero discharge BAT limitation for pollutants in fly ash 

transport water. See Section 7 for more information on the population of plants discharging fly 

ash transport water.

All new generating units built since the ELGs were last revised in 1982 have been subject 

to a zero discharge standard for pollutants in fly ash transport water. In nearly all cases, plants 

have installed dry fly ash handling technologies to comply with the standard. In addition, many 

owners and operators with generating units that are not subject to the previously established zero 

discharge NSPS for fly ash transport water have chosen to retrofit their units with dry fly ash 

handling technology to meet operational needs or for economic reasons. The trend in the industry 

is, moreover, toward the conversion and use of dry fly ash handling systems (see Section 4.5). 

Based on data collected in the Steam Electric Survey, EPA estimates that approximately 80 

percent of coal- and petroleum coke-fired generating units operate dry fly ash handling systems 

(see Section 4.3.1). Since the survey, companies have continued to upgrade, or announce plans to 

upgrade, their ash handling systems at generating units (see Section 4.5).

EPA considered establishing BAT limitations for fly ash transport water based on 

chemical precipitation. Upon reviewing the discharge flow rates for fly ash transport water, 

however, EPA determined that the costs associated with chemical precipitation treatment were 

higher than the cost of the dry handling technology and chemical precipitation is less effective at 

removing pollutants. For these reasons, EPA did not select chemical precipitation as BAT for 

control of fly ash transport water [ERG, 2015d].

Dry ash handling does not adversely affect plant operation or reliability and it promotes 

the beneficial reuse of coal combustion residuals (CCRs). In addition, converting to dry fly ash 

handling eliminates the need to treat fly ash transport water in a surface impoundment, and it 

reduces the amount of wastes entering surface impoundments and the risk and severity of 

structural failures and spills.

EPA decided not to finalize a BAT limitation on fly ash transport water equal to the 

previously promulgated BPT limit on TSS, based on the technology of surface impoundments. 
Section 8—The Final Rule

8-14

EPA concluded that it would not be appropriate to establish new BAT requirements equal to 

previously established BPT requirements for fly ash transport water because surface 

impoundments are not designed for or effective at removing dissolved metals and nutrients, 

which are pollutants of concern in fly ash transport water. Furthermore, they can be susceptible 

to seasonal turnover that degrades pollutant removal efficacy (see discussion in Section 8.3.1). 

Surface impoundments, therefore, would not result in reasonable further progress toward the 

national goal of eliminating the discharge of all pollutants. 

8.3.3 Bottom Ash Transport Water

This rule identifies dry handling or closed-loop systems as the BAT technology basis for 

control of pollutants in bottom ash transport water.70 More specifically, the first technology basis 

for BAT is a system in which bottom ash is collected in a water quench bath and a drag chain 

conveyor (mechanical drag system) then pulls the bottom ash out of the water bath on an incline 

to dewater the bottom ash. The second technology basis for BAT is a system in which the bottom 

ash is transported using the same processes as a wet-sluicing system, but instead of going to an 

impoundment, the bottom ash is sluiced to a remote mechanical drag system. Once there, a drag 

chain conveyor pulls the bottom ash out of the water on an incline to dewater the bottom ash, and 

the transport (sluice) water is then recycled back to the bottom ash collection system.

These technologies for control of bottom ash transport water are demonstrably available. 

Based on data collected in the Steam Electric Survey, approximately 20 percent of coal-fired and 

petroleum coke-fired steam electric power plants handle bottom ash using technologies that do 

not generate any bottom ash transport water and more than 80 percent of coal-fired generating 

units built in the last 20 years have installed dry bottom ash handling systems. In addition, EPA 

found that more than half of the entities that would be subject to BAT requirements for bottom 

ash transport water are already employing zero discharge technologies (dry handling or closedloop wet ash handling) or planning to do so in the near future.

EPA considered establishing BAT limitations for bottom ash transport water based on 

chemical precipitation. Upon reviewing the discharge flow rates for bottom ash transport water, 

however, EPA determined that the costs associated with chemical precipitation treatment were 

comparable to the cost of control using dry handling/closed-loop systems and chemical 

precipitation is less effective at removing pollutants. For these reasons, EPA did not select

chemical precipitation as BAT for control of bottom ash transport water [ERG, 2015d].

Dry bottom ash handling does not adversely affect plant operations or reliability and 

shifting to dry bottom ash systems offers certain benefits. As is the case for dry fly ash systems, 

shifting to dry bottom ash handling eliminates the need to send bottom ash transport water to a 

surface impoundment and it reduces the amount of waste entering surface impoundments and the 

risk and severity of structural failures and spills. Furthermore, one way companies can choose to 

comply with the final rule’s requirement is to install a completely dry bottom ash system, which 

increases the energy efficiency of the boiler, thus reducing the amount of coal burned and 

associated emissions of carbon dioxide (CO2) and other pollutants per MW of electricity 

 70 EPA identified two technologies, a mechanical drag system or a remote mechanical drag system, as the BAT 

technology basis for bottom ash transport water because of potential space constraints at some plants’ boilers.
Section 8—The Final Rule

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generation [CBPG, 2013]. On an annual basis, EPA calculated significant fuel savings and 

reduced air emissions from such systems, the value of which EPA estimates to be $41 million to 

$117 million per year [Abt, 2015].

71

EPA did not identify surface impoundments as BAT for bottom ash transport water 

because surface impoundments are not designed for or effective at removing dissolved metals 

and nutrients, which are pollutants of concern in bottom ash transport water. They are also 

susceptible to seasonal turnover that degrades pollutant removal efficacy (see discussion in 

Section 8.3.1). Moreover, in the steam electric power generating industry, bottom ash transport 

water is one of the three largest sources of discharges of pollutants of concern, and these 

discharges occur at many steam electric power plants across the nation. Thus, limitations based 

on surface impoundments would not result in reasonable further progress toward the national 

goal of eliminating the discharge of all pollutants (CWA section 301(b)(2)(A)). 

Moreover, because the estimated overall cost of the ELG has decreased since proposal

(see Section 9), EPA also decided that establishing different bottom ash transport water 

limitations for generating units of and below a certain size (other than 50 MW, as described in 

Section 8.3.12), as in Option C, was not warranted. At proposal and for the final rule, EPA 

considered an option that would have established differentiated bottom ash transport water 

requirements for units below 400 MW (Option C). Some public commenters stated that EPA’s 

record does not support differentiated requirements for bottom ash transport water. They stated 

that BAT should be established at a level at which the costs are affordable to the industry as a 

whole, and that the cost to a unit in terms of dollars per amount of energy produced (in MW) is 

not a relevant factor. They cited EPA’s record, which demonstrates that units of all sizes have 

installed dry handling and closed-loop systems, as well as EPA’s economic achievability 

analysis, which does not show that units of 400 MW or less are especially likely to shut down if 

faced with a zero discharge requirement. Other commenters supported EPA’s consideration of 

the relative magnitude of costs per amount of energy produced for units below or equal to 400 

MW, as compared to larger units, as well as differentiated bottom ash transport water 

requirements for these units.

EPA reviewed its record and re-evaluated whether it would be appropriate to establish 

differentiated requirements for discharges of bottom ash transport water from existing sources 

based on unit size, in light of comments and the key changes since proposal. Annualized cost per 

amount of energy produced increases along a smooth curve moving from the very largest units to 

the smallest units [ERG, 2015f]. That, however, is expected due to economies of scale. Thus, 

there is no clear breaking point at which to establish a size threshold for purposes of 

differentiated requirements for bottom ash transport water.72 Furthermore, EPA collected 

information in the industry survey that found that units of all sizes, including those less than 400 

MW, have installed dry handling and closed-loop systems. And, as further described below, EPA 

projects a net retirement of only 843 MW under the final rule. This suggests that, as a group, 

 71 Neither these savings nor the fuel and emissions reductions have been incorporated into EPA’s analyses for this 

final rule. 

72 At the same time, costs per amount of energy produced do begin to increase very dramatically as one moves from 

units above 50 MW to units that are equal to 50 MW and smaller, and thus for reasons discussed in Section 8.3.12, 

the final rule establishes different requirements for units of 50 MW or less for several wastestreams, including 

bottom ash transport water.
Section 8—The Final Rule

8-16

units of 400 MW or less do not face particularly unique hardships under the final rule with 

respect to the industry as a whole. For these reasons, the final rule does not establish 

differentiated bottom ash transport water requirements for units equal to or below 400 MW (or 

for units equal to or below any other size threshold, other than 50 MW).

8.3.4 FGMC Wastewater

This rule identifies dry handling as the BAT technology basis for the control of pollutants 

in FGMC wastewater. More specifically, the technology basis for BAT is a dry vacuum system 

that employs a mechanical exhauster to convey the FGMC waste (via a change in air pressure) 

from hoppers directly to a silo. Dry handling of FGMC wastes is available and welldemonstrated in the industry; indeed, nearly all plants with FGMC systems use dry handling 

systems. Plants using sorbent injection systems (e.g., activated carbon injection) to reduce 

mercury emissions from the flue gas typically handle the spent sorbent in the same manner as 

their fly ash (see Section 7). As of 2009, 92 percent of the industry generating FGMC waste uses

dry handling to manage it. Only a few plants use wet systems to transport the spent sorbent to 

disposal in surface impoundments. Based on the Steam Electric Survey, the plants using wet 

handling systems operate them as closed-loop systems and do not discharge FGMC wastewater, 

or they already have a dry handling system that is capable of achieving zero discharge. Under the 

zero discharge limitation, these plants could choose to continue to operate their wet systems as 

closed-loop systems, or they could convert to dry handling technologies by managing the fly ash 

and spent sorbent together in a retrofitted dry system (rather than an impoundment) or by 

installing dedicated dry handling equipment for the FGMC waste similar to the equipment used 

for fly ash. 

EPA is also aware of some plants that add oxidizing agents to the coal prior to burning it

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 using oxidizing agents to control flue gas mercury 

emissions because using oxidizing agents does not generate a separate FGMC wastestream.

EPA decided that it would not be appropriate to set BAT limitations for FGMC 

wastewater based on surface impoundments. While impoundments can effectively remove some 

particulate forms of metals and other pollutants, they are not designed for or effective at 

removing other pollutants of concern, such as dissolved metals and nutrients. They are also 

susceptible to seasonal turnover that degrades pollutant removal efficacy (see discussion in 

Section 8.3.1). Thus, they would not result in reasonable further progress toward the national 

goal of eliminating discharges of all pollutants (see CWA sections 101(a) and 301(b)(2)(A)). 

8.3.5 Gasification Wastewater

This rule identifies evaporation as the BAT technology basis for the control of pollutants 

in gasification wastewater. More specifically, the technology basis for BAT is an evaporation 

system using a falling-film evaporator (or brine concentrator) to produce a concentrated 

wastewater stream (brine) and a reusable distillate stream. Evaporation, described in Section 7, is 

available and well-demonstrated in the industry for treatment of gasification wastewater. All 

three integrated gasification combined cycle (IGCC) plants now operating in the United States 
Section 8—The Final Rule

8-17

(the only existing sources of gasification wastewater) use evaporation technology to treat their 

gasification wastewater. 

EPA did not identify surface impoundments as BAT for gasification wastewater because 

surface impoundments are not effective at removing the pollutants of concern present in 

gasification wastewater. They are also susceptible to seasonal turnover that degrades pollutant 

removal efficacy (see discussion in Section 8.3.1). In addition, one existing IGCC plant

previously used a surface impoundment to treat its gasification wastewater, and the 

impoundment effluent repeatedly exceeded its National Pollutant Discharge Elimination System 

(NPDES) permit effluent limitations necessary to meet applicable water quality standards. 

Because of the demonstrated inability of surface impoundments to remove the pollutants of 

concern, particularly dissolved solids, and given that current industry practice is treatment of 

gasification wastewater using evaporation, EPA concluded that surface impoundments do not 

represent BAT for gasification wastewater.

EPA also considered including cyanide treatment as part of the technology basis for BAT 

(as well as NSPS, PSES, and PSNS) for gasification wastewater. EPA is aware that the

Edwardsport IGCC plant, which began commercial operation in June 2013, includes cyanide 

destruction as one step in the treatment process for gasification wastewater. EPA, however, does 

not currently have sufficient data with which to calculate possible effluent limitations for 

cyanide. Thus EPA decided not to establish cyanide limitations or standards for gasification 

wastewater in this rule. This decision does not preclude permitting authorities from setting more 

stringent effluent limitations where necessary to meet water quality standards. In those cases, 

plants may elect to install additional treatment, like cyanide destruction, to meet water qualitybased effluent limitations (WQBELs).

8.3.6 Combustion Residual Leachate

EPA received public comments expressing concern that the proposed definition of 

combustion residual leachate would apply to contaminated stormwater. Although this was not 

the Agency’s intention, for the final rule, EPA revised the definition to make it clear that 

contaminated stormwater does not fall within the final definition of combustion residual 

leachate. This rule identifies surface impoundments as the BAT technology basis for control of 

pollutants in combustion residual leachate. Based on surface impoundments, which rely on 

gravity to remove particulates, this rule establishes a BAT limitation on TSS in combustion 

residual leachate equal to the previously promulgated BPT limitation on TSS in low volume 

waste sources. Few steam electric power plants currently employ technologies other than surface 

impoundments for treatment of combustion residual leachate. Throughout the development of 

this rule, EPA considered whether technologies in place for treatment of other wastestreams at 

steam electric power plants and wastestreams generated by other industries, including chemical 

precipitation, could be used for combustion residual leachate. At proposal, noting the small 

amount of pollutants in combustion residual leachate relative to other significant wastestreams at 

steam electric power plants, and that this was an area ripe for innovation, EPA requested 

additional information related to cost, pollutant reduction, and effectiveness of chemical 

precipitation and alternative approaches to treat combustion residual leachate. Commenters did 

not provide information that EPA could use to establish BAT limitations. Thus, EPA decided not 

to finalize BAT limitations for combustion residual leachate based on chemical precipitation 
Section 8—The Final Rule

8-18

(Option E). The record demonstrates that the amount of pollutants collectively discharged in 

combustion residual leachate by steam electric power plants is a very small portion of the 

pollutants discharged collectively by all steam electric power plants (approximately 3 percent of 

baseline loadings, on a toxic-weighted basis). Given this, and the fact that this rule regulates the

wastestreams representing the three largest sources of pollutants from steam electric power 

plants (including by setting a zero discharge standard for two out of the three wastestreams), 

EPA decided that this rule already represents reasonable further progress toward the CWA’s 

goals. The final rule, therefore, establishes BAT limitations for combustion residual leachate 

equal to the BPT limitation on TSS for low volume waste sources.

8.3.7 Timing

As part of its consideration of the technological availability and economic achievability

of the BAT limitations in the rule, EPA considered the magnitude and complexity of process 

changes and new equipment installations that would be required at facilities to meet the rule’s 

requirements. As described in greater detail in Section 14, where BAT limitations in the ELG are 

more stringent than previously established BPT limitations, those limitations do not apply until a 

date determined by the permitting authority that is as soon as possible beginning November 1, 

2018 (approximately three years following promulgation of the ELG), but that is also no later 

than December 31, 2023 (approximately eight years following promulgation). 

Consistent with the proposed rule and supported by many commenters, EPA takes this 

approach in the ELG to provide the time that many plants need to raise capital, plan and design 

systems, procure equipment, and construct and then test systems. It also allows for consideration 

of plant changes being made in response to other Agency rules affecting the steam electric 

industry. Moreover, it enables facilities to take advantage of planned shutdown or maintenance 

periods to install new pollution control technologies.73 EPA’s decision is also designed to allow, 

more broadly, for the coordination of generating unit outages in order to maintain grid reliability 

and prevent any potential impacts on electricity availability, something that public commenters 

urged EPA to consider.

In addition, as requested by industry and states, the final rule and preamble clarify how 

the “as soon as possible date” is determined and implemented for steam electric power plants. 

The final rule specifies the factors that the permitting authority must consider in determining the 

“as soon as possible” date, and provides guidance on implementation with respect to timing in 

Section 14. In addition, the rule includes a “no later than” date of December 31, 2023, for 

implementation because, as public commenters pointed out, without such a date, implementation 

could be substantially delayed, and a firm “no later than” date creates a more level playing field 

across the industry. EPA’s economic analysis assumes prompt renewal of permits and, thus, that 

the requirements of the rule will be fully implemented by 2023. While some commenters 

requested that EPA give permitting authorities the ability to extend the implementation period 

beyond December 31, 2023, in light of public comments received on the proposal, and the fact 

that plants can reasonably be expected to meet the new ELGs by December 31, 2023, this 

 73 EPA’s record demonstrates that plants typically have one or two planned shut-downs annually and that the length 

of these shutdowns is more than adequate to complete installation of relevant treatment and control technologies.
Section 8—The Final Rule

8-19

timeframe is appropriate given the CWA’s pollutant discharge elimination goals (see CWA 

section 101(a)). 

8.3.8 Legacy Wastewater

For purposes of the BAT limitations in this rule, EPA uses the term “legacy wastewater” 

to refer to FGD wastewater, fly ash transport water, bottom ash transport water, FGMC 

wastewater, or gasification wastewater generated prior to the date determined by the permitting 

authority that is as soon as possible beginning November 1, 2018, but no later than December 31, 

2023 (see Section 8.3.7). Under this rule, legacy wastewater must comply with specific BAT 

limitations, which EPA is setting equal to the previously promulgated BPT limitations on TSS in 

the discharge of fly ash transport water, bottom ash transport water, and low volume waste 

sources. 

EPA did not establish zero discharge BAT limitations for legacy wastewater because 

technologies that can achieve zero discharge (such as the ones on which the final BAT 

requirements discussed in Sections 8.3.2 through 8.3.4 are based) are not shown to be available 

for legacy wastewater. Legacy wastewater already exists in wet form, and thus dry handling 

could not be used eliminate its discharge. Furthermore, EPA lacks data to show that legacy 

wastewater could be reliably incorporated into a closed-loop process that eliminates discharges, 

given the variation in operating practices among surface impoundments containing legacy 

wastewater. 

EPA also decided not to establish BAT limitations for legacy wastewater based on a 

technology other than surface impoundments (chemical precipitation, chemical precipitation plus 

biological treatment, evaporation) because it does not have the data to do so. Data are not 

available because of the way that legacy wastewater is currently handled at plants. 

The vast majority of plants combine some of their legacy wastewater with each other and 

with other wastestreams, including cooling water, coal pile runoff, metal cleaning wastes, and 

low volume waste sources in surface impoundments. 74 Once combined in surface 

impoundments, the legacy wastewater no longer has the same characteristics that it did when it 

was first generated. For example, the addition of cooling water can dilute legacy wastewater to a 

point where the pollutants are no longer present at treatable levels. Additionally, some 

wastestreams have significant variations in flow, such as metal cleaning wastes, which are 

generally infrequently generated, or coal pile runoff, which is generated during precipitation 

events. Because surface impoundments are typically open, with no cover, they also receive direct 

precipitation. As a result of all of this, the characteristics of legacy wastewater contained in 

surface impoundments (flow rate and pollutant concentrations) vary at both any given plant, as 

well as across plants nationwide. Furthermore, EPA generally would like to have enough 

performance data at a well-designed, well-operated plant or plants to derive limitations and 

standards using its well-established and judicially upheld statistical methodology. In this case, 

 74 For example, there are 65 plants for which EPA estimated FGD wastewater compliance costs and that use an 

impoundment as part of their treatment system. For 54 of the 65 plants (83 percent), the FGD wastewater is 

commingled with, at least, fly and/or bottom ash transport water, and for another eight of the 65 plants (12 percent), 

the FGD wastewater is commingled with non-ash wastewater, such as cooling tower blowdown or low volume 

waste sources [ERG, 2015g].
Section 8—The Final Rule

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except in limited circumstances, plants do not treat the legacy wastewater that they send to an 

impoundment using anything beyond the surface impoundment itself.75 Thus, the final rule 

establishes BAT limitations for legacy wastewater equal to the previously promulgated BPT 

limitations on TSS in discharges of fly ash transport water, bottom ash transport water, and low 

volume waste sources. 

Finally, while there are a few plants that discharge from an impoundment containing only 

legacy FGD wastewater, 76 EPA rejected establishing requirements for such legacy FGD 

wastewater based on a technology other than surface impoundments. EPA determined that, while 

it could be possible for plants to treat the legacy FGD wastewater with the same technology used 

to treat FGD wastewater subject to the BAT limitations described in Section 8.3.1 (because their 

characteristics could be similar), establishing requirements based on any technology more 

advanced than surface impoundments for these legacy “FGD-only” wastewater impoundments 

could encourage plants to alter their operations prior to the date that the final limitations apply in 

order to avoid the new requirements. Likely, a plant would begin commingling other process 

wastewater with their legacy FGD wastewater in the impoundment so that any legacy “FGDonly” wastewater requirements would no longer apply. Alternatively, plants might choose to 

pump the legacy FGD wastewater out of the impoundment on an accelerated schedule and prior 

to the date that the final limitations apply. In this case, the more rapid discharge of the 

wastewater could result in temporary increases in environmental impacts (e.g., exceedances of 

water quality criteria for acute impacts to aquatic life). EPA wanted to avoid creating such a 

perverse incentive in this rule, and it therefore decided to establish BAT limitations for 

discharges of legacy FGD wastewater based on the previously promulgated BPT limitations on 

TSS for low volume waste sources. Finally, EPA notes that, as a result of the zero discharge 

requirements for discharges of all pollutants in three wastestreams (fly ash transport water, 

bottom ash transport water, and flue gas mercury control wastewater, this rule provides strong 

incentives for steam electric power plants to greatly reduce, if not completely eliminate, the 

disposal and treatment of their major sources of ash-containing wastewater in surface 

impoundments. As a result, EPA anticipates that overall volumes of legacy wastewater will 

continue to decrease dramatically over time, as this rule becomes fully implemented.

8.3.9 Economic Achievability

EPA’s analysis for the final BAT limitations demonstrates that they are economically 

achievable for the steam electric industry as a whole, as required by CWA section 301(b)(2)(A). 

EPA performed cost and economic impact assessments on existing plants using the Integrated 

 75 For example, no plant uses chemical precipitation, biological treatment, or evaporation to treat its legacy fly ash 

transport water or legacy bottom ash transport water contained in an impoundment, including any impoundment that 

may contain only legacy fly ash transport water or only legacy bottom ash transport water. Thus, no steam electric 

industry data exist to establish BAT limitations for possible “fly ash-only” impoundments or “bottom ash-only” 

impoundments based on these technologies.

76 EPA determined that there are three plants that are estimated to incur FGD wastewater compliance costs and that 

use an impoundment as part of the treatment system, but where the FGD wastewater is not commingled with other 

process wastewaters in the impoundment. There are no plants that discharge from an impoundment containing only 

gasification wastewater.
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Planning Model (IPM)77 using a baseline that reflects impacts from other relevant environmental 

regulations (see the Regulatory Impact Analysis for Proposed Effluent Limitations Guidelines 

and Standards for the Steam Electric Power Generating Point Source Category). For the ELG, 

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 estimated that the requirements 

associated with the ELG would result in a net reduction of 843 MW in steam electric generating 

capacity as of the model year 2030, reflecting full compliance by all plants. This capacity 

reduction corresponds to a net effect of two unit closures or, when aggregating to the level of 

steam electric generating plants, and net plant closure.78 These results support EPA’s conclusion 

that the ELG is economically achievable.

8.3.10 Non-Water Quality Environmental Impacts, Including Energy Requirements79

The final BAT effluent limitations have acceptable non-water quality environmental 

impacts, including energy requirements (see Section 12 for more detail EPA’s analysis of these 

impacts). EPA estimates that by the year 2023, under the final rule and reflecting full 

compliance, energy consumption increases by less than 0.01 percent of the total electricity 

generated by power plants. EPA also estimates that the amount of fuel consumed by increased 

operation of motor vehicles (e.g., for transporting fly ash) increases by approximately 0.002 

percent of total fuel consumption by all motor vehicles. 

As discussed in Section 12, EPA also evaluated the effect of the BAT effluent limitations

on air emissions generated by all electric power plants (NOX, sulfur oxides (SOX), and CO2), 

solid waste generation, and water usage. Under the final rule, NOX emissions are projected to 

decrease by 1.16 percent, SOX emissions are projected to increase by 0.04 percent, and CO2

emissions are projected to decrease by 0.106 percent due to changes in the mix of electricity 

generation (e.g., less electricity from coal-fired steam electric generating units and more 

electricity from natural gas-fired steam electric generating units). Moreover, solid waste 

generation is projected to increase by less than 0.001 percent of total solid waste generated by all 

electric power plants. Finally, EPA estimates that the final rule has a positive impact on water 

use, with steam electric power plants reducing the amount of water they withdraw by 57 billion

gallons per year (155 million gallons per day).

 77 IPM is a comprehensive electricity market optimization model that can evaluate such impacts within the context 

of regional and national electricity markets.

78 Given the design of IPM, unit-level and thereby plant-level projections are presented as an indicator of overall 

regulatory impact rather than a precise prediction of future unit–level or plant-specific compliance actions.

79 As described in Section 8.3.13, this rule includes a voluntary incentives program that provides the certainty of 

more time for plants to implement new BAT requirements, if they adopt additional process changes and controls that 

achieve limitations on mercury, arsenic, selenium, and TDS in FGD wastewater, based on evaporation technology. 

The information presented in this section assumes plants will choose to comply with BAT limitations for FGD 

wastewater based on chemical precipitation and biological treatment. EPA does not know how many plants will opt 

into the voluntary incentives program. Therefore, EPA also calculated non-water quality environmental impacts 

assuming all plants will elect to comply with the voluntary incentives program and similarly found these impacts to 

be acceptable [ERG, 2015h]. 
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8.3.11 Impacts on Residential Electricity Prices and Low-Income and Minority 

Populations

EPA examined the effects of the ELG on consumers as an additional 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 (a very conservative assumption), the average monthly increase in 

electricity bill for a typical household would be no more than $0.12 under the final rule.

EPA also considered the effect of the rule on minority and low-income populations. As 

explained in Section XVII.J of the preamble, using demographic data regarding who resides 

closest to steam electric power plant discharges and who consumes the most fish from waters

receiving power plant discharges, EPA concluded that low-income and minority populations 

benefit to an even greater degree than the general population from the reductions in discharges 

associated with the final rule.

8.3.12 Existing Oil-Fired Generating Units and Small Generating Units

EPA considered whether subcategorization of the ELGs was warranted based on the 

factors specified in CWA section 304(b)(2)(B) and other factors identified in public comments. 

Ultimately, EPA concluded it would be appropriate to set different limitations for existing small 

generating units (units with a nameplate capacity of 50 MW or less) and existing oil-fired 

generating units. No other, different requirements were warranted for this ELG under the factors 

considered (see Section 5 for more detail). 

Oil-fired Generating Units. For oil-fired generating units, the final rule establishes BAT 

limitations for FGD wastewater, fly ash transport water, bottom ash transport water, FGMC 

wastewater, and gasification wastewater equal to previously established BPT limitations on TSS 

in fly ash transport water, bottom ash transport water, and low volume waste sources. As defined 

in the rule, oil-fired generating units refer to those that use oil as either the primary or secondary 

fuel and do not burn coal or petroleum coke. Units that use only oil during startup or for flame 

stabilization are not considered oil-fired generating units. EPA decided to finalize these 

limitations for oil-fired generating units because EPA’s record demonstrates that, in comparison 

to coal- and petroleum coke-fired generating units, oil-fired generating 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 

ELG. 

The amount of ash generated by oil-fired generating units is a small fraction of the 

amount produced by coal-fired units. Coal-fired units generate hundreds to thousands of tons of 

ash each day, with some plants generating more than 2,000 tons per day. In contrast, oil-fired 

units generate less than ten tons of ash per day. This disparity is also apparent when comparing 

the ash tonnage to the amount of power generated, with coal-fired generating units producing 

nearly 1,800 times more ash than oil-fired generating units (0.6 tons per MW-hour on average 

for coal units; 0.000319 tons per MW-hour 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 generating units discharge substantially fewer pollutants to surface waters than 
Section 8—The Final Rule

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coal-fired units, even when generating the same amount of electricity. EPA estimates that the 

amount of pollutants discharged collectively by all oil-fired generating units is a very small 

portion of the pollutants discharged collectively by all steam electric power plants (less than one 

percent, on a toxic-weighted basis).

Oil-fired generating units are generally among the oldest steam electric generating units 

in the industry. Eighty-seven percent of the generating units are more than 25 years old and more 

than a quarter of the generating units began operation more than 50 years ago. Based on 

responses to the Steam Electric Survey, fewer than 20 oil-fired generating units discharged fly 

ash or bottom ash transport water in 2009. This is likely because only about 20 percent of oilfired generating units operate as baseload units; the rest are either cycling/intermediate units 

(about 45 percent) or peaking units (about 35 percent). These units also have notably low 

capacity utilization. While about 30 percent of the baseload units report capacity utilization 

greater than 75 percent, almost half 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 generating units operated for more than 6 months 

in 2009; nearly half of the units operated for less than 30 days.

While these older and generally intermittently operated oil-fired generating units are 

capable of installing and operating the treatment technologies that form the bases for this rule, 

and the costs would be affordable for most plants, EPA concludes 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 ELG. If these units shut down, EPA is concerned about resulting 

reductions in the flexibility that grid operators have during peak demand due to 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 as 

commenters confirmed. 

Based on responses to the Steam Electric Survey, EPA estimates that less than 20 oilfired generating units discharged fly ash or bottom ash transport water in 2009. At the same time, 

EPA notes that many oil-fired generating units operate infrequently, which could contribute to 

the relatively low numbers of units discharging ash-related wastewater. Should more widespread 

operation of oil-fired generating units be required to meet demands of the electric grid, additional 

plants may find it necessary to discharge ash transport water. 

EPA considered these potential impacts on electric grid reliability and the nation’s energy 

security, under CWA section 304(b)(2)(B), in its decision to establish different BAT limitations 

for oil-fired generating units.

Small Generating Units. The final rule also establishes BAT limitations for FGD 

wastewater, fly ash transport water, bottom ash transport water, FGMC wastewater, and 

gasification water at small generating units equal to previously established BPT limitations on 

TSS for fly ash transport water, bottom ash transport water, and low volume waste sources. For 

purposes of this rule, small generating units refer to those units with a total nameplate generating 

capacity of 50 MW or less. EPA decided to establish these different BAT limitations for small
Section 8—The Final Rule

8-24

generating units because they are more likely to incur compliance costs that are significantly and 

disproportionately higher per amount of energy produced (dollars per MW) than those incurred 

by large generating units. 

Some commenters stated that the cost to a unit in terms of dollars per MW is not relevant 

because BAT should be established at a level at which the costs are affordable to the industry as 

a whole. They noted that EPA’s IPM analysis demonstrates that the most stringent proposed 

regulatory option is economically achievable for all units above 50 MW [ERG, 2015f]. Other 

commenters supported EPA’s consideration of the relative magnitude of costs for smaller units 

compared to larger units, and some suggested EPA should increase the size threshold to 100 MW 

because those units also have disproportionate costs per amount of energy produced, and they 

collectively discharge a small fraction of the total pollutants discharged by all steam electric 

power plants.

EPA reviewed the record and re-evaluated the threshold for small units in light of 

comments and the key changes since proposal. EPA considered establishing no threshold, as well 

as several different size thresholds, for small units. The Agency looked closely at establishing a 

threshold at 50 MW or 100 MW. While the total amount of pollutants discharged by units at 

these thresholds is relatively small in comparison to those discharged by all steam electric power 

plants, the amount of pollutants discharged by units smaller than or equal to 100 MW is almost 

double the amount of pollutants discharged by units smaller than or equal to 50 MW [ERG, 

2015f]. The record indicates that the cost per unit of energy produced increases as the size of the 

generating unit decreases, and while there is no clear “knee of the curve” at which to establish a 

size threshold, there is a difference between units at 50 MW and below compared to those above 

50 MW. Figure 8-1, below, shows the annualized cost per amount of energy produced for 

existing units under Regulatory Option D. Figure 8-1 shows that the cost per amount of energy 

produced increases as the size of the generating unit decreases. Annualized cost per amount of 

energy produced increases gradually as one moves from the very largest units down to 100 MW, 

and then the cost per amount of energy produced begins to increase more rapidly as one moves 

from 100 MW down to 50 MW, until it increases very rapidly for units at 50MW and below. 

Additionally, Figure 8-1 shows that nearly all of the ratios of cost to amount of energy produced 

for units smaller than or equal to 50 MW are above those for the entire population of remaining 

units. The same cannot be said of the ratio for units smaller than or equal to 100 MW. 
Section 8—The Final Rule

8-25

Figure 8-1. Regulatory Option D Annualized Cost Per MW Compared to Unit Capacity 

(MW)

In light of the fact that the costs per amount of energy produced are significantly and 

disproportionately higher for units smaller than or equal to 50 MW compared to larger units, and 

in light of the very small fraction of pollutants discharged by units smaller than or equal to 

50MW, EPA ultimately decided to establish different requirements for units at this threshold.

Keeping in mind the statutory directive to set effluent limitations that result in reasonable further 

progress toward the national goal of eliminating the discharge of all pollutants (CWA section 

301(b)(2)(A)), EPA used its best judgment to balance the competing interests. EPA recognizes 

that any attempt to establish a size threshold for generating units will be imperfect due to 

individual differences across units and firms. EPA concludes, however, 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, while advancing the CWA’s goals. 

Furthermore, EPA’s analysis demonstrates that the final rule, with a threshold established at 50 

MW, is economically achievable. 

8.3.13 Voluntary Incentives Program

As part of BAT for existing sources, the final rule establishes a voluntary incentives 

program that provides the certainty of more time (until December 31, 2023) for plants to 

implement the BAT requirements, if they adopt additional process changes and controls that 

achieve limitations on mercury, arsenic, selenium, and TDS in FGD wastewater, based on 

evaporation technology (see Section 8.3.1 for a more complete description of the evaporation 
Section 8—The Final Rule

8-26

technology basis). This optional program provides significant environmental protections beyond 

those achieved by the final BAT limitations for FGD wastewater based on chemical precipitation 

plus biological treatment because evaporation technology is capable of achieving significant 

removals of toxic metals, as well as TDS.80 EPA’s proposal included a voluntary incentives 

program that contained, as one element, incentives in the form of additional implementation time 

for plants that eliminate the discharge of all process wastewater (except cooling water). Public 

commenters urged EPA to consider establishing, instead, a program that provided incentives for 

plants that go further than the rule’s requirements to reduce discharges from individual 

wastestreams. Because the final rule already contains zero discharge limitations for several key 

wastestreams, EPA decided that the voluntary incentives program should focus on FGD 

wastewater.

EPA concluded that additional pollutant reductions could be achieved under a voluntary 

incentives program because there are certain reasons a plant might opt to treat its FGD 

wastewater using evaporation rather than chemical precipitation plus biological treatment. One 

such reason is the possibility that a plant’s NPDES permit may need more stringent limitations 

necessary to meet applicable water quality standards. For example, some power plant discharges 

containing TDS (including bromide) that occur upstream of drinking water treatment plants can 

negatively impact treatment of source waters at the drinking water treatment plants. A recent 

study identified four drinking water treatment plants that experienced increased levels of 

bromide in their source water, and corresponding increases in the formation of carcinogenic 

disinfection by-products (brominated DPBs) in the finished drinking water, after the installation 

of wet FGD scrubbers at upstream steam electric power plants [McTigue et al., 2014]. 

Furthermore, based on trends in the industry and experience with this and other 

industries, EPA expects that, over time, the costs of evaporation (and other technologies that 

could achieve the limitations in the voluntary incentives program, including zero discharge 

practices) will decrease so as to make it an even more attractive option for plants. EPA 

understands that vendors are already working on changes to this technology to reduce the costs, 

reduce the amount of solids generated, and improve the solids handling. See Section 7.1.4. 

The technology on which the BAT limitations in the voluntary incentives program are 

based, evaporation, is available to steam electric power plants. EPA identified three plants in the 

U.S. that have installed, and one plant that is in the process of installing, evaporation systems to 

treat their FGD wastewater. Four coal-fired power plants in Italy treat FGD wastewater using 

evaporation. See Section 7. Furthermore, the voluntary program is economically achievable 

because only those plants that opt to be subject to the BAT limitations based on evaporation, 

rather than the BAT limitations based on chemical precipitation plus biological treatment, must 

achieve them. Therefore, any plant that chooses to be subject to the more stringent limitations 

has determined for itself, in light of its own financial information and economic outlook, that 

such limitations are economically achievable. Finally, EPA analyzed the non-water quality 

environmental impacts and energy requirements associated with the voluntary incentives 

program, and it found them acceptable [ERG, 2015h].

 80 Properly operated evaporated systems are also capable of achieving the BAT limitations based on chemical 

precipitation plus biological treatment.
Section 8—The Final Rule

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The development of this voluntary incentives program furthers the CWA’s ultimate goal 

of eliminating the discharge of pollutants into the Nation’s waters. See CWA section 101(a)(1) 

and section 301(b)(2)(A) (specifying that BAT will result in “reasonable further progress toward 

the national goal of eliminating the discharge of pollutants”). While the final rule’s BAT 

limitations based on chemical precipitation plus biological treatment represent “reasonable 

further progress,” the voluntary incentives program is designed to press further toward achieving 

the national goal of the Act, as wastewater that has been treated properly using evaporation has 

very low pollutant concentrations (also making it possible to reuse the wastewater and 

completely eliminate the discharge of any pollutants). In addition, CWA section 104(a)(1) 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. EPA anticipates that this voluntary incentives program will effectively accelerate 

the research into, and demonstration of controls and processes intended to prevent, reduce, and 

eliminate pollution because, under it, plants will opt to employ control and treatment strategies to 

significantly reduce discharges of pollutants found in FGD wastewater.

Steam electric power plants agreeing to meet BAT limitations for FGD wastewater based 

on evaporation must comply with those limitations on arsenic, mercury, selenium, and TDS in 

FGD wastewater.81 For such plants, the BAT limitations based on evaporation apply as of 

December 31, 2023, to FGD wastewater generated on and after December 31, 2023. Plants 

opting to participate in the voluntary program can use the period in advance of this date to 

research, engineer, design, procure, construct, and optimize systems capable of meeting the 

limitations based on evaporation. 

For purposes of the voluntary incentives program BAT limitations, legacy FGD 

wastewater is FGD wastewater generated prior to December 31, 2023. For such legacy FGD 

wastewater, the final rule establishes BAT limitations on TSS in discharges of FGD wastewater 

that are equal to BPT limitations for low volume waste sources. 

EPA decided not to make the voluntary incentives program available to plants that send 

their FGD wastewater to POTWs. Under CWA section 307(b)(1), PSES must specify a time for 

compliance that does not exceed three years from the date of promulgation, and thus the 

additional time of up to 2023 cannot be given to indirect dischargers. Of course, nothing 

prohibits an indirect discharger from using any technology, including evaporation, to comply 

with the final PSES and PSNS. 

EPA expects that any plant interested in the voluntary incentives program would indicate 

their intent to opt into the program prior to issuance of its next NPDES permit, following the 

effective date of this rule. A plant can indicate its intent to opt into the voluntary program on its 

permit application or through separate correspondence to the NPDES Director, as long as the 

signatory requirements of 40 CFR § 122.22 are met.

 81 For some plants, proper pretreatment such as softening or chemical precipitation is likely appropriate to ensure 

effective and efficient operation of evaporation systems.
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8-28

8.4 BEST AVAILABLE DEMONSTRATED CONTROL TECHNOLOGY/NSPS

After considering all of the technologies described in Section 7, as well as public 

comments, and in light of the factors specified in section 306 of the CWA, EPA concluded that 

the technologies described in Option F represent the best available demonstrated control 

technology (BADCT) for steam electric power plants, and the final rule promulgates NSPS based 

on that option. Thus, the final NSPS establish: 

• Standards on arsenic, mercury, selenium, and TDS in FGD wastewater, based on

evaporation (same basis as for BAT limitations in the voluntary incentives program). 

• A zero discharge standard on all pollutants in bottom ash transport water, based on 

dry handling or closed-loop systems (same bases as for BAT limitations). 

• A zero discharge standard on all pollutants in FGMC wastewater, based on dry 

handling (same bases as for BAT limitations). 

• Standards on mercury, arsenic, selenium, and TDS in gasification wastewater, based 

on evaporation technology (same bases as for BAT limitations). 

• Standards on mercury and arsenic in discharges of combustion residual leachate, 

based on chemical precipitation (more specifically, the technology basis is a chemical 

precipitation system that employs hydroxide precipitation, sulfide precipitation, and 

iron coprecipitation to remove heavy metals). 

The ELG also maintains the previously established zero discharge NSPS on discharges of 

fly ash transport water, based on dry handling. 

The record indicates that the technologies that serve as the bases for NSPS in the ELG are

well-demonstrated, based on the performance of plants using the technologies. For example:

• New steam electric power generating sources have been meeting the previously 

established zero discharge standard for fly ash transport water since 1982, 

predominantly by using dry handling technologies. 

• Three plants in the U.S. and four plants in Italy use evaporation technology to treat 

their FGD wastewater, and another U.S. plant is in the process of installing such 

technology for that purpose.

• Of the approximately 50 coal-fired generating units built within the last 20 years, 

most (83 percent) manage their bottom ash without using water to transport the ash 

and, as a result, do not discharge bottom ash transport water. 

• The technology identified as BAT for gasification wastewater represents current 

industry practice. Every IGCC power plant currently in operation uses evaporation to 

treat their 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). 
Section 8—The Final Rule

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• For combustion residual leachate, chemical precipitation is a well-demonstrated 

technology for removing metals and other pollutants from a variety of industrial 

wastewaters, including combustion residual leachate from landfills not located at 

power plants. Chemical precipitation is also well-demonstrated at steam electric 

power plants for treatment of FGD wastewater that contains the pollutants in 

combustion residual leachate. 

The NSPS in the ELG also pose no barrier to entry. The cost to install technologies at 

new units is typically less than the cost to retrofit existing units. For example, the cost 

differential between Options B, C, and D for existing sources is mostly associated with 

retrofitting controls for bottom ash handling systems. For new sources, however, NSPS based on 

Option F do not present plants with the same choice of retrofit versus modification of existing 

processes because every new generating unit must 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 NSPS means that new steam electric power plants will install a dry 

bottom ash handling system instead of a wet-sluicing system. 

Moreover, EPA assessed the possible impacts of the final NSPS on new sources by 

comparing the incremental costs of the Option F technologies to the costs of hypothetical new 

generating units. EPA is not able to predict which plants might construct new units or the exact 

characteristics of such units. Instead, EPA calculated and analyzed compliance costs for a variety 

of plant and unit configurations. EPA developed NSPS compliance costs for new sources using a 

methodology similar to the one used to develop compliance costs for existing sources. EPA’s 

estimates for compliance costs for new sources are based on the net difference in costs between 

wastewater treatment system technologies that would likely have been implemented at new 

sources under the previously established regulatory requirements, and those that would likely be 

implemented under the final rule. EPA estimated that the incremental compliance costs for a new 

generating unit (capital and O&M) represent approximately 3.3 percent of the annualized cost of 

building and operating a new 1,300 MW coal-fired plant, with capital costs representing 0.3 to 

2.8 percent of the overnight construction costs, and annual O&M costs representing 0.3 to 3.9 

percent of the fuel and other O&M cost of operating a new plant.

Finally, EPA analyzed the non-water quality environmental impacts associated with 

Option F for existing sources, and its analysis is relevant to the consideration of non-water 

quality environmental impacts associated with Option F for new sources. Since there is nothing 

inherently different between an existing and new source, EPA’s analysis with respect to existing 

sources is instructive. Using this analysis, EPA determined that NSPS based on the Option F 

technologies have acceptable non-water quality environmental impacts and energy requirements

[ERG, 2015h; ERG, 2015e].

In contrast to the BAT effluent limitations, EPA establishes the same NSPS for oil-fired

generating units and small generating units as for all other new sources. 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 incur retrofit costs because the pollution controls 

(process operations or treatment technology) are installed at the time of construction. Thus, the 

costs for new sources are lower, even if the pollution controls are identical.
Section 8—The Final Rule

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For each of the wastestreams except combustion residual leachate, EPA rejected 

establishing NSPS based on surface impoundments for the same reasons it rejected establishing 

BAT based on surface impoundments. For FGD wastewater, EPA also did not establish NSPS 

based on chemical precipitation for the same reasons it rejected establishing BAT based on that 

technology. In particular, these other technologies would not achieve as much pollutant reduction 

as the technology bases in Option F – which is technologically available and economically 

achievable with acceptable non-water quality environmental impacts and energy requirements –

and thus do not represent best available demonstrated control technology.

EPA did not select surface impoundments as the basis for NSPS for combustion residual 

leachate because, unlike BAT, NSPS represent the “greatest degree of effluent reduction . . . 

achievable” (CWA section 306), and (besides “cost” and “any non-water quality environmental 

impact and energy requirements”) EPA does not consider “other factors” in establishing NSPS. 

When used to treat combustion residual leachate, chemical precipitation can achieve substantial 

pollutant reductions as compared to surface impoundments. Thus, EPA has determined that 

NSPS for leachate based on chemical precipitation achieve the “greatest degree of effluent 

reduction” as that term is used in CWA section 306.

Similarly, EPA did not select chemical precipitation plus biological treatment as the basis 

for NSPS for FGD wastewater because, under CWA section 306, NSPS reflect “the greatest 

degree of effluent reduction . . . achievable.” Evaporation systems are capable of achieving 

extremely low pollutant discharge levels, and in fact can be the basis for a plant completely 

eliminating all discharges associated with FGD wastewater. Moreover, unlike EPA’s decision 

not to identify evaporation as the technology basis for FGD wastewater discharges from all 

existing sources due to the large associated cost, establishing NSPS for FGD wastewater based 

on evaporation does not add to the overall estimated cost of the rule because EPA does not 

predict any new coal-fired generating units will be installed in the foreseeable future. As 

explained above, however, in the event that a new unit is installed, EPA determined that the 

NSPS compliance costs would not present a barrier to entry. 

8.5 PSES

The CWA requires EPA to promulgate pretreatment standards for pollutants that are not 

susceptible to treatment by POTWs or that would interfere with the operation of POTWs. 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. Therefore, in setting 

PSES, in addition to considering the factors assessed for BAT, EPA must also determine whether

a pollutant “passes through” secondary treatment at a POTW.

Table 8-2 summarizes the results of EPA’s pass-through analysis for the regulated 

pollutants (with numeric limitations) in each wastestream, as controlled by the relevant BAT and 

NSPS technology basis.82 As explained in Section 11, EPA did not conduct its traditional passthrough analysis for wastestreams with zero discharge limitations or standards. Zero discharge 

 82 The regulation of TSS in combustion residual leachate (based on surface impoundments) under the final BAT 

limitations is not represented here because TSS is a conventional pollutant that is effectively treated by POTWs (it 

does not pass through).
Section 8—The Final Rule

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limitations and standards achieve 100 percent removal of pollutants; therefore, all pollutants in 

those wastestreams pass through the POTW. As shown in the table, all of the pollutants regulated 

under BAT/NSPS pass through secondary treatment by a POTW.

Table 8-2. Summary of Pass-Through Analysis

Technology Option Pollutant

Pass Through?

(Yes or No)

Chemical Precipitation for Combustion Residual 

Leachate (only for NSPS)

Arsenic Yes

Mercury Yes

Chemical Precipitation Plus Biological Treatment 

for FGD wastewater

Arsenic Yes

Mercury Yes

Nitrate Nitrite as N Yes

Selenium Yes

Evaporation for FGD Wastewater (only for NSPS) Arsenic Yes

Mercury Yes

Selenium Yes

TDS Yes

Evaporation for Gasification Wastewater Arsenic Yes

Mercury Yes

Selenium Yes

TDS Yes

After considering all of the relevant factors and technology options described in Section 

7, as well as public comments, as is the case with BAT, EPA decided to establish PSES based on 

the technologies described in Option D. For PSES, the final rule establishes: 

• Standards on arsenic, mercury, selenium, and nitrate-nitrite as N in FGD wastewater, 

based on chemical precipitation plus biological treatment. 

• A zero discharge standard on all pollutants in fly ash transport water, based on dry 

handling. 

• A zero discharge standard on all pollutants in bottom ash transport water, based on 

dry handling or closed-loop systems. 

• A zero discharge standard on all pollutants in FGMC wastewater, based on dry 

handling. 

• Standards on mercury, arsenic, selenium, and TDS in gasification wastewater, based 

on evaporation technology.83

 83 For small (50 MW or smaller) and oil-fired generating units, EPA is not finalizing PSES for fly ash transport 

water, bottom ash transport water, FGMC wastewater, and gasification wastewater. 
Section 8—The Final Rule

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All of the technology bases for the final PSES are the same as those described for the 

final BAT limitations. The final rule does not establish PSES for combustion residual leachate 

because TSS and the pollutants that it represents do not pass through POTWs. 

EPA selected the Option D technologies as the basis for PSES for the same reasons that 

EPA selected the Option D technologies as the bases for BAT. EPA’s analysis shows that, for 

both direct and indirect dischargers, the Option D technologies are available and economically 

achievable, and Option D has acceptable non-water quality environmental impacts, including 

energy requirements (see Section 12). EPA rejected other options for PSES for the same reasons 

that it rejected other options for BAT. Furthermore, for the same reasons that apply to EPA’s 

final BAT limitations for oil-fired generating units and small generating units, and described in 

Section 8.3.12, EPA does not establish PSES that would apply to oil-fired generating units and 

small generating units (50 MW or smaller). 84 Finally, EPA determined that the final PSES 

prevent pass-through of pollutants from POTWs into receiving streams and also help control 

contamination of POTW sludge.

As with the final BAT limitations, in considering the availability and achievability of the 

final PSES, EPA concluded that existing indirect dischargers need some time to achieve the new 

standards, in part to avoid forced outages (see Section 8.3.7). However, in contrast to the BAT

limitations (which apply on a date determined by the permitting authority that is as soon as 

possible beginning November 1, 2018, but no later than December 31, 2023), the new PSES 

apply as of November 1, 2018. Under CWA section 307(b)(1), pretreatment standards shall 

specify a time for compliance not to exceed 3 years from the date of promulgation, so EPA 

cannot establish a longer implementation period. Moreover, unlike requirements on direct 

discharges, requirements on indirect discharges are not implemented through an NPDES permit

and thus are not subject to awaiting the next permit issuance before the limitations are specified 

clearly for the discharger. EPA has determined that all of the existing indirect dischargers can 

meet the standards by November 1, 2018, and because there are relatively few indirect 

dischargers (who would have approximately 3 years from the date of promulgation to achieve the 

standards), implementing the standards by that date would not lead to electricity availability 

concerns (see the RIA).

For purposes of the PSES in this rule, the term “legacy wastewater” refers to FGD 

wastewater, fly ash transport water, bottom ash transport water, FGMC wastewater, or 

gasification wastewater generated prior to November 1, 2018. For the same reasons that EPA 

decided to establish BAT limitations on TSS in discharges of legacy wastewater equal to BPT 

limitations for fly ash transport water, bottom ash transport water, and low volume waste 

sources, the final rule does not establish PSES for legacy wastewater (see Section 8.3.8). TSS 

and the pollutants it represents are effectively treated by, and thus do not pass through, POTWs.

 84 Whereas the final rule establishes BAT limitations on TSS in fly ash and bottom ash transport water, FGMC 

wastewater, FGD wastewater, and gasification wastewater for small generating units and oil-fired generating units, 

TSS and the pollutants that they represent do not pass through POTWs.
Section 8—The Final Rule

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8.6 PSNS

After considering all of the relevant factors and technology options described in Section 

7, as well as public comments, as was the case for NSPS, EPA selected the Option F

technologies as the basis for PSNS in the ELG. As a result, the final PSNS establish:

• Standards on arsenic, mercury, selenium, and TDS in FGD wastewater, based on 

evaporation. 

• A zero discharge standard on all pollutants in bottom ash transport water, based on 

dry handling or closed-loop systems. 

• A zero discharge standard on all pollutants in FGMC wastewater, based on dry 

handling. 

• Standards on mercury, arsenic, selenium, and TDS in gasification wastewater, based 

on evaporation technology. 

• Standards on mercury and arsenic in combustion residual leachate, based on chemical 

precipitation. 

All the technology bases for the final PSNS are the same as those described for the final 

NSPS. The final rule also maintains the previously established zero discharge PSNS on 

discharges of fly ash transport water, based on dry handling. As with the final NSPS, this rule 

establishes the same PSNS for oil-fired generating units and small generating units as for all 

other new sources.

EPA selected the Option F technologies as the basis for PSNS for the same reasons that 

EPA selected the Option F technologies as the basis for NSPS (see Section 8.4). EPA’s record 

demonstrates that the technologies described in Option F are available and demonstrated, and 

Option F does not pose a barrier to entry and has acceptable non-water quality environmental 

impacts, including energy requirements (see Section 12). EPA rejected other options for PSNS 

for the same reasons that the Agency rejected other options for NSPS. And, as with the final 

PSES, EPA determined that the final PSNS prevent pass-through of pollutants from POTWs into 

receiving streams and also help control contamination of POTW sludge.

8.7 ANTICIRCUMVENTION PROVISION

The final rule establishes one of the three anti-circumvention provisions that EPA 

proposed. The one anti-circumvention provision that EPA decided to establish applies only for 

existing sources to those wastestreams for which this rule established zero discharge limitations 

or standards. In general, this provision prevents steam electric power plants from circumventing 

the final rule by moving effluent produced by a process operation for which there is an 

applicable zero discharge effluent limitation or standard to another plant process operation for 

discharge.85 EPA determined it was appropriate to include this provision in the final rule to make 

clear that, just because a wastestream that is subject to a zero discharge limitation or standard is 

moved to another plant process, it does not mean that the wastestream ceases being subject to the 

 85 The anti-circumvention provision applies only to limitations and standards established in this final rule. It does not 

apply to limitations and standards promulgated previously.
Section 8—The Final Rule

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applicable zero discharge limitation or standard. For example, using fly ash or bottom ash 

transport water as makeup water for a cooling tower does not relieve a plant of having to meet 

the zero discharge limitations and standards for fly ash and bottom ash transport water. EPA 

encourages the reuse of wastewater where appropriate, but not to the extent that it undermines 

the zero discharge effluent limitations and standards in this rule. Plants are free to reuse their 

wastewater, so long as the wastewater ultimately complies with the final limitations and 

standards. 

Some public commenters stated that zero discharge effluent limitations and standards for 

fly ash and bottom ash transport water, together with this anti-circumvention provision, would 

prohibit water reuse and prevent water use reduction at steam electric power plants. In general, 

EPA disagrees with these commenters. Most plants will choose to comply with the requirements 

for ash transport water by operating either a dry or closed-loop wet-sluicing system to handle 

their fly and bottom ash, which will eliminate or substantially reduce the amount of water they 

currently use in the traditional wet-sluicing system. To the extent that a plant currently uses (or 

was considering using) ash transport water, such as the effluent from an impoundment, as 

makeup water for processes such make-up cooling water and would be precluded from doing so 

because of the anti-circumvention provision in this rule, the plant could merely switch to an 

alternate source for the makeup water, such as the water that was (prior to implementing the zero 

discharge requirement for ash transport water) used to sluice fly ash or bottom ash to the 

impoundment. In other words, the volume of water that is currently used to sluice ash to an 

impoundment and subsequently reused as makeup water would no longer be needed to sluice the 

ash and could instead be directly used as makeup water for the cooling water system or other 

processes. Because of this, the zero discharge limitations in this rule will not lead to a net 

increase at the plant and in fact could result in a decrease in water use. Lastly, a plant is free to 

reuse ash transport water, and would be in compliance with the anti-circumvention provision, so 

long as it is used in a process that does not ultimately result in a discharge.

There is one particular type of plant practice that the final rule’s anti-circumvention 

provision does not apply to. Many industry commenters noted that they use ash transport water 

in their FGD scrubber. They stated that this practice is preferable to using a fresh water source 

and allows for an overall reduction in source water withdrawals. They further stated that, under 

the final rule, any wastewater that passes through the scrubber would undergo significant 

treatment in order to meet the final FGD wastewater limitations and standards. EPA agrees, in 

part, with these comments. As explained above, EPA does not agree that using wastewater from 

one industrial process as makeup water in another industrial process necessarily results in a net 

reduction in water withdrawals. EPA does agree, however, that using wastewater from an 

industrial process as makeup water in another industrial process may be preferable to using a 

fresh water source. EPA is mindful of the CWA’s pollutant discharge elimination goal, but also 

wants to promote opportunities for water reuse. Furthermore, as explained in Section 4.5, EPA 

recognizes the extensive changes in this industry, and it wants to provide flexibility to plants in 

managing their wastewater and operations, as well as preserve the ability of plants to retain 

existing approaches where it is consistent with the CWA’s goals. While EPA would not choose 

to promote these considerations where it resulted in no further progress toward the pollutant 

discharge elimination goal of the Act, in the case of using ash transport water in an FGD 

scrubber, since any resulting wastewater discharges would still be required to meet BAT or 

PSES requirements based on either chemical precipitation plus biological treatment or chemical 
Section 8—The Final Rule

8-35

precipitation plus evaporation under this final rule, EPA decided not to apply the anticircumvention provision to this particular practice.

This rule does not establish an anti-circumvention provision that would have required 

internal monitoring to demonstrate compliance with certain numeric limitations and standards. 

Some public commenters argued that the proposed provision was unduly restrictive, and they 

stated that EPA already has authority to accomplish the goal of this particular provision, which is 

to ensure that wastestreams are being treated rather than simply diluted. EPA agrees with these 

commenters and thus decided that existing rules, along with the guidance in TDD Section 14, 

provide appropriate flexibility to steam electric power plants to combine wastestreams with 

similar pollutants and treatability, while adequately addressing EPA’s concern that plants meet 

the effluent limitations and standards in this rule through treatment and control strategies, rather 

than through dilution. Furthermore, some commenters raised concerns that the proposed 

provision would be a disincentive for plants to internally reuse the treated wastewater within the 

plant, particularly when the reuse eliminates the discharge of the wastewater. For example, they 

stated that some steam electric power plants might opt to use a wet scrubber’s FGD wastewater 

as reagent make-up for a new dry scrubber in an integrated design which would essentially 

evaporate the wet FGD wastewater. EPA notes that plants that internally reuse wastestreams for 

which EPA is establishing numeric limitations and standards (e.g., FGD wastewater) in a way 

that completely prevents discharge of that wastestream would not be subject to the numeric 

limitations and standards because they do not discharge the wastewater. EPA is aware of at least 

one plant that elected to take such an approach as an alternative to meeting NPDES permit 

limitations by installing wastewater treatment technology [ERG, 2015i]. In general, EPA 

supports such approaches because they result in further progress towards achieving the pollutant 

discharge elimination goal of the CWA. Moreover, such approaches are favored because they 

reduce overall water intake needs.

This rule also does not establish an anti-circumvention provision that would have 

required permittees to use EPA-approved analytical methods that are sufficiently sensitive to 

provide reliable, quantified results at levels necessary to demonstrate compliance with the final 

effluent limitations and standards because another recently promulgated rule already 

accomplishes this. As public commenters pointed out, EPA was conducting a rulemaking on that 

topic; and, in August 2014, EPA published a rule requiring the use of sufficiently sensitive 

analytical test methods when completing any NPDES permit application. Moreover, the NPDES 

permit authority must prescribe that only sufficiently sensitive methods be used for analyses of 

pollutants or pollutant parameters under an NPDES permit where EPA has promulgated a CWA 

method for analysis of that pollutant. That rule clarifies that NPDES applicants and permittees 

must use EPA-approved analytical methods that are capable of detecting and measuring the 

pollutants at, or below, the applicable water quality criteria or permit limits. 

8.8 OTHER REVISIONS

This section describes other revisions to the steam electric power generating ELGs

related to corrections of typographical errors and further clarifications on the applicability.
Section 8—The Final Rule

8-36

8.8.1 Correction of Typographical Error for PSNS

As EPA proposed to do, EPA corrects a typographical error in the previously established 

PSNS for cooling tower blowdown. As is clear from the development document for the 1982 

rulemaking, as well as the previously promulgated NSPS for cooling tower blowdown, EPA 

inadvertently omitted a footnote in the table that appears in 40 CFR 423.17(d)(1). The footnote 

reads “No detectable amount,” and it applies to the effluent standard for 124 of the 126 priority 

pollutants contained in chemicals added for cooling tower maintenance. (See Development 

Document for Final Effluent Guidelines, New Source Performance Standards and Pretreatment 

Standards for the Steam Electric Power Generating Point Source Category, Document No. EPA 

440/1-82/029. November 1982.)

8.8.2 Clarification of Applicability

The final rule contains three minor modifications to the wording of the applicability 

provision in the steam electric power generating ELGs to reflect EPA’s longstanding

interpretation and implementation of the rule. These revisions do not alter the universe of 

generating units regulated by the ELGs, nor do they impose compliance costs on the industry. 

Instead, they remove potential ambiguity in the regulations by revising the text to more clearly 

reflect EPA’s long-standing interpretation. 

First, the applicability provision in the previous ELGs stated, in part, that the ELGs apply 

to “an establishment primarily engaged in the generation of electricity for distribution and sale . . 

. .” (40 CFR 423.10). The final rule revises that phrase to read “an establishment whose

generation of electricity is the predominant source of revenue or principal reason for operation . . 

. .” The final rule thus clarifies that certain plants, such as generating units owned and operated 

by industrial facilities in other sectors (e.g., petroleum refineries, pulp and paper mills) that have 

not traditionally been regulated by the steam electric ELGs, are not within the scope of the 

ELGs. In addition, the final rule clarifies that certain municipally-owned plants that generate and 

distribute electricity within a service area (such as distributing electric power to municipallyowned buildings), but which use accounting practices that are not commonly thought of as a 

“sale,” are subject to the ELGs. Such plants have traditionally been regulated by the steam 

electric power generating ELGs.

Second, the final rule clarifies that fuels derived from fossil fuel are within the scope of 

the ELGs. The previous ELGs stated, in part, that they apply to discharges related to the 

generation of electricity “which results primarily from a process utilizing fossil-type fuels (coal,

oil, or gas) or nuclear fuel . . . .” (40 CFR 423.10). Because a number of fuel types are derived 

from fossil fuels themselves, the final rule explicitly mentions and gives examples of such fuels. 

Thus, the final rule reads that the ELGs apply to discharges resulting from the operation of a 

generating unit “whose generation results primarily from a process utilizing fossil-type fuel 

(coal, oil, or gas), fuel derived from fossil fuel (e.g., petroleum coke, synthesis gas), or nuclear 

fuel . . . .”

Third, the final rule clarifies the applicability provision to reflect the current 

interpretation that combined cycle systems are subject to the ELGs. The ELGs apply to electric 

generation processes that utilize “a thermal cycle employing the steam water system as the 
Section 8—The Final Rule

8-37

thermodynamic medium.” (40 CFR 423.10). EPA’s longstanding interpretation is that the ELGs 

apply to discharges from all electric generating processes with at least one prime mover that 

utilizes steam (and that meet the other applicability factors in 40 CFR 423.10). 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. The combustion turbines 

for a combined cycle system operate in tandem with the steam turbines; therefore, the ELGs 

apply to wastewater discharges associated with both the combustion turbine and steam turbine 

portions of the combined cycle system. The final rule, therefore, clarifies that “[t]his part applies 

to discharges associated with both the combustion turbine and steam turbine portions of a 

combined cycle generating unit.”

8.9 NON-CHEMICAL METAL CLEANING WASTE

EPA proposed to establish BAT/NSPS/PSES/PSNS requirements for non-chemical metal 

cleaning wastes equal to previously established BPT limitations for metal cleaning wastes.86

EPA based the proposal on EPA’s understanding, from industry survey responses, that most 

steam electric power plants manage their chemical and non-chemical metal cleaning wastes in 

the same manner. Since then, based in part on public comments submitted by industry groups, 

the Agency has learned that plants refer to the same operation using different terminology; some 

classify non-chemical metal cleaning waste as such, while others classify it as low volume waste 

sources. Because the survey responses reflect each plant’s individual nomenclature, the survey 

results for non-chemical metal cleaning wastes are skewed. Furthermore, EPA does not know the 

nomenclature each plant used in responding to the survey, so it has no way to adjust the results to 

account for this. Consequently, EPA does not have sufficient information on the extent to which 

discharges of non-chemical metal cleaning wastes occur, or on the ways that industry manages 

their non-chemical metal cleaning wastes. Moreover, EPA also does not have information on 

potential best available technologies or best available demonstrated control technologies, or the 

potential costs to industry to comply with any new requirements. Due to incomplete data, some 

public commenters urged EPA not to establish BAT limitations for non-chemical metal cleaning 

wastes in this final rule. Ultimately, EPA decided that it does not have enough information on a 

national basis to establish BAT/NSPS/PSES/PSNS requirements for non-chemical metal 

cleaning wastes. The final rule, therefore, continues to “reserve” BAT/NSPS/PSES/PSNS for 

non-chemical metal cleaning wastes, as the previously promulgated regulations did.87

By reserving limitations and standards for non-chemical metal cleaning waste in the final 

rule, the permitting authority must establish such requirements based on BPJ for any steam 

electric power plant discharging non-chemical metal cleaning wastes. As part of this 

determination, EPA expects that the permitting authority would examine the historical permitting 

record for the particular plant to determine how discharges of non-chemical metal cleaning waste 

 86 Under the structure of the previously promulgated regulations, non-chemical metal cleaning wastes are a subset of 

metal cleaning wastes. 

87 As part of its proposal to establish new BAT/PSES/NSPS/PSNS requirements for non-chemical metal cleaning 

waste equal to BPT limitations for metal cleaning waste, EPA also proposed an exemption for certain discharges of 

non-chemical metal cleaning waste, which would be treated as low volume waste sources. Because the final rule 

does not establish these new requirements, EPA also did not finalize the proposed exemption.
Section 8—The Final Rule

8-38

had been permitted in the past, including whether such discharges had been treated as low 

volume waste sources or metal cleaning waste.

8.10 BEST MANAGEMENT PRACTICES

EPA proposed to include BMPs in the ELGs that would require plant operators to 

conduct periodic inspections of active and inactive surface impoundments to ensure their 

structural integrity and to take corrective actions where warranted. The proposed BMPs were 

largely similar to those proposed for the CCR rule, except for the closure requirements. EPA 

took comments on whether establishment of BMPs was more appropriate under the authority of 

the Resource Conservation and Recovery Act (RCRA) or the CWA. While some commenters 

asked EPA to establish BMPs in the final rule, many others urged EPA not to do so, arguing that 

BMPs are better suited for the CCR rule. Because EPA promulgated BMPs in the CCR rule, to 

avoid unnecessary duplication, the final rule does not establish BMPs.

8.11 REFERENCES

1. Abt. 2015. Abt Associates, Inc. Estimated Benefits of Alternative Bottom Ash 

Technology (Dry Handling); Option D. Summary of Analysis Results. (29 June). 

DCN SE05980.

2. CBPG. 2013. Comments of CBPG on Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category. EPAHQ-OW-2009-0819-2927-A2. (June 26).

3. ERG. 2015a. Eastern Research Group, Inc. “Changes to Industry Profile for 

Steam Electric Generating Units for the Steam Electric Effluent Guidelines Final 

Rule” (“Industry Profile Changes Memo”). (30 September). DCN SE05069.

4. ERG. 2015b. Eastern Research Group, Inc. Notes from Call with GE Water on

March 4, 2015. (28 September). DCN SE06336.

5. ERG. 2015c. Eastern Research Group, Inc. “Memorandum to the Steam Electric 

Rulemaking Record: Variability in FGD Wastewater: Monitoring and Response.” 

(September 30). DCN SE05846.

6. ERG. 2015d. Eastern Research Group, Inc. “Memorandum to the Steam Electric 

Rulemaking Record: Evaluation of Chemical Precipitation Costs for Ash 

Transport Water.” (19 April). DCN SE05654.

7. ERG. 2015e. Eastern Research Group, Inc. “Memorandum to the Steam Electric 

Rulemaking Record: Steam Electric Effluent Guidelines Nonwater Quality 

Environmental Impacts for NSPS/PSNS” (30 September). DCN SE05905.

8. ERG. 2015f. Eastern Research Group, Inc. “Memorandum to the Steam Electric 

Rulemaking Record. Steam Electric Effluent Guidelines – Evaluation of Potential 

Subcategorization Approaches.” (30 September). DCN SE05813.

9. ERG, 2015g. Eastern Research Group, Inc. Final Pond Mapping Database. (30 

September). DCN SE05875.
Section 8—The Final Rule

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10. ERG. 2015h. Eastern Research Group, Inc. “Memorandum to the Steam Electric 

Rulemaking Record. Steam Electric Effluent Guidelines Non-Water Quality 

Impacts.” (30 September). DCN SE05574.

11. ERG. 2015i. Eastern Research Group, Inc. Notes on Wet FGD System Operation, 

(29 September). DCN SE06338.

12. EPRI. 2006. Electric Power Research Institute. EPRI Technical Manual: 

Guidance for Assessing Wastewater Impacts of FGD Scrubbers. 1013313. Palo 

Alto, CA. (December). DCN SE01817. Available online at: 

http://www.epriweb.com/public/000000000001013313.pdf. 

13. GE. 2014a. General Electric. GE Responses to Post Proposal Questions. (3 April). 

DCN SE04208.

14. GE. 2014b. General Electric. CBI GE Written Response to Additional Follow-up 

Questions. (2 May). DCN SE04222.

15. GE. 2015. General Electric. “ABMet Experience List”. (July). DCN SE05646.

16. McTigue, et. al. 2014. Occurrence and Consequences of Increased Bromide in 

Drinking Water Sources. (November). DCN SE04503. 

17. U.S. EPA. 1983. U.S. Environmental Protection Agency. Development Document 

for Effluent Limitations Guidelines and Standards for the Metal Finishing Point 

Source Category. Washington, DC. (June). EPA-440/1-83/091.

18. U.S. EPA. 2002. U.S. Environmental Protection Agency. Development Document 

for Final Effluent Limitations Guidelines and Standards for the Iron and Steel 

Manufacturing Point Source Category. Washington, DC. (April). EPA-821-R-02-

004.

19. U.S. EPA. 2003. U.S. Environmental Protection Agency. Development Document 

for the Final Effluent Limitations Guidelines and Standards for the Metal 

Products & Machinery Point Source Category. Washington, DC. (February).

EPA-821-B-03-001.

20. U.S. EPA. 2015a. U.S. Environmental Protection Agency. Incremental Costs and 

Pollutant Removals for Final Effluent Limitation Guidelines and Standards for 

the Steam Electric Power Generating Point Source Category. (30 September).

DCN SE05831.

21. U.S. EPA. 2015b. U.S. Environmental Protection Agency. Statistical Support 

Document: Effluent Limitations for FGD Wastewater, Gasification Wastewater, 

and Combustion Residual Leachate for the Final Steam Electric Power 

Generating Effluent Limitations Guidelines and Standards. (30 September). DCN 

SE05733.
Section 9—Engineering Costs

9-1

SECTION 9

ENGINEERING COSTS

This section presents EPA’s methodology to determine incremental capital and operation 

and maintenance (O&M) costs for the steam electric power generating industry to comply with 

the final rule. For more specific information on EPA’s cost methodology, see EPA’s Incremental 

Costs and Pollutant Removals for Final Effluent Limitation Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category [U.S. EPA, 2015a].

Section 9.1 describes EPA’s general approach for estimating incremental compliance 

costs for the steam electric effluent limitations guidelines and standards (ELGs). Section 9.2

describes 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 power 

generating industry to achieve the limitations and standards based on the technology options 

(described in Section 8 of this report). Section 9.3 also 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, 9.8, and 9.9 summarize the technology 

options assessed in the cost analysis and the results for flue gas desulfurization (FGD) 

wastewater, fly ash and bottom ash transport water, combustion residual leachate, and 

gasification wastewater, respectively.88

9.1 INTRODUCTION

EPA estimated plant-specific costs to control discharges at existing steam electric power 

plants to which the ELGs apply (existing sources). For all applicable wastestreams, EPA 

assessed the operations and treatment system components in place at a given plant in the 

baseline, identified equipment and process changes that the plant would likely make to meet 

ELGs, and estimated the incremental cost to implement those changes.89 While plants are not 

required to implement the specific technologies that form the basis for the options considered for 

the final rule EPA often calculates the cost for plants to implement these technologies to estimate 

incremental compliance costs to industry associated with the ELGs. As appropriate, EPA also 

accounted for cost savings associated with these equipment and process changes (e.g., avoided 

costs to manage surface impoundments). EPA thus derived incremental capital and O&M costs 

at the plant level for control of each wastestream using the technology that forms the basis for 

 88 EPA did not estimate incremental compliance costs for flue gas mercury control (FGMC) wastewater because, as 

described in Section 9.2.6, EPA determined that all plants operating sorbent injection systems to remove mercury 

from the flue gas already operate dry handling systems, operate wet systems that do not discharge, or have the 

capability to operate dry handling systems. 

89 Baseline operations and treatment system components characterize current plant operations as determined based 

on responses to the Questionnaire for the Steam Electric Power Generating Effluent Guidelines and other publicly 

available information including comments to the proposed rulemaking, vendor information, and data from operating 

companies.
Section 9—Engineering Costs

9-2

the final rule. All cost components described and presented in the section for existing sources 

represent EPA’s estimated incremental capital and O&M costs. 

EPA estimated the costs on a per plant basis and then summed or otherwise escalated the 

plant-specific values to represent industry-wide compliance costs (see Regulatory Impact 

Analysis for Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category (EPA-821-R-15-004)). Calculating costs on a per plant basis 

allowed 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 (BMPs) and end-of-pipe treatment).

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 ELGs (EPA 

also estimated the costs for complying with several other regulatory options considered, but not 

selected, for the final rule.) EPA evaluated the costs of the ELGs on all plants currently subject 

to the existing ELGs.90 Some aspects of the ELGs (e.g., applicability changes) would likely not 

lead to increased costs to complying plants. Other aspects of the ELGs would likely increase 

costs for a subset of complying plants. These are plants that generally generate the wastestreams 

for which EPA is promulgating new effluent limitations or standards. This section describes the 

detailed costing evaluation EPA performed for these plants that may incur compliance costs 

associated with the rulemaking.

Where the final rule does not establish new requirements for existing facilities or 

establishes the best available technology economically achievable (BAT) based on previously 

established best practicable control technology current available (BPT) limitations, there are no

incremental costs to comply with the final rule. For example, EPA did not estimate incremental 

compliance costs for existing facilities to comply with the final BAT limitations and standards 

for combustion residual leachate or for oil-fired generating units and small generating units with 

a capacity of 50 megawatts (MW) or less.

EPA estimated compliance costs associated with each of the regulatory options from data 

collected through the Questionnaire for the Steam Electric Power Generating Effluent 

Guidelines (Steam Electric 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 requirements associated with the 

regulatory options. Additionally, EPA calculated plant-specific costs for other scenarios as well.

Specifically, EPA calculated plant-specific costs that take into account expected plant operation 

changes resulting from the Resource Conservation and Recovery Act (RCRA) requirements (i.e., 

 90 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 December 31, 2023; and plants, or steam electric generating units, 

converting to non-fossil fuel sources (e.g., natural gas, municipal solid waste) by December 31, 2023. This approach 

is reasonable given that EPA identified only one plant closing before 2023 for which the assumed technology 

implementation year would precede the announced retirement or conversion year (by one year).
Section 9—Engineering Costs

9-3

coal combustion residual (CCR) rule) and plant-specific retirements resulting from the Clean 

Power Plan (CPP). EPA’s cost estimates include the following key cost components: 

• Capital costs (one-time costs).

• Annual O&M costs (which are incurred every year).

• Other one-time or recurring costs. 

Capital costs comprise the direct and indirect costs associated with purchasing, 

delivering, and installing 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 O&M costs comprise all costs related to operating and maintaining the 

pollution control technologies for a period of 1 year. O&M 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 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 sections describe the technologies used as the basis for estimating 

compliance costs for each wastestream and technology option. Section 8 identifies the 

technology options considered for this rulemaking, while Section 7 describes them in detail.

9.2.1 FGD Wastewater

EPA estimated compliance costs for plants to treat FGD wastewater using one of the 

following two technology options: chemical precipitation or chemical precipitation followed by 

biological treatment.

EPA also estimated compliance costs for plants to treat FGD wastewater using chemical 

precipitation followed by evaporation. As described in “Plant-Specific Compliance Cost 

Estimates for the Treatment of FGD Wastewater with Chemical Precipitation Followed by 

Evaporation”, EPA determined that the total industry costs for existing sources would be too 

high, nearly $1 billion more expensive on an annual basis than the cost of limitations based on 

chemical precipitation followed by biological treatment [ERG, 2015f]. EPA did not evaluate 

chemical precipitation followed by evaporation further as a treatment technology for existing 

sources and therefore, this treatment technology for FGD wastewater is not discussed further in 

this section.

For the 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.
Section 9—Engineering Costs

9-4

• Solids-contact clarifier to remove suspended solids.

• Gravity sand filter to reduce solids.

• Effluent storage tank.

• Mercury analyzer.

Additionally, EPA included costs for a sludge holding tank, filter presses to dewater the 

solids collected in the clarifier, and costs to transport and dispose of the resulting solids in a 

landfill. The costs also include all ancillary equipment and the associated O&M costs for the 

system.

For the 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).

• Heat exchanger (for plants in certain geographic locations).

• Oxidation-reduction potential (ORP) monitor.

• Chemical addition system for ORP control.

• Denitrification treatment system (for plants with nitrate/nitrite concentrations greater 

than 100 parts per million (ppm)).

EPA also included costs to transport and dispose of additional solids collected in the 

biological system. The costs include all ancillary equipment and the associated O&M costs for 

the system.

9.2.2 Fly Ash Transport Water

EPA estimated compliance costs for plants discharging fly ash transport water to convert 

from a wet ash handling system to a dry vacuum fly ash handling system. For the conversion to 

the dry vacuum fly ash handling system, EPA included costs for the plants to install and operate 

the following91:

• Mechanical exhausters.

• Piping and valves.

• Filter-receivers.

• Silo(s) (steel or concrete).

• Pugmills.

For generating units determined to require only redundant conveyance or backup storage 

equipment to handle all fly ash dry, EPA estimated capital costs to install the following (based 

on the type of existing dry fly ash handling system for the generating unit): 

 91 For each generating unit discharging fly ash transport water, EPA determined that the plants would likely continue 

to use the existing valves and branch lines underneath the fly ash collection hoppers, associated with the existing 

wet-sluicing system, but the plant would require new valves and piping to convey the dry fly ash to the silo(s). 
Section 9—Engineering Costs

9-5

• Mechanical exhausters.

• Filter-receivers.

• Silo(s) (steel or concrete).

• Pugmills.

Additionally, EPA included capital and O&M costs to transport and dispose of the 

moisture conditioned fly ash in a landfill, and costs associated with water trucks around the 

landfill for dust suppression.

9.2.3 Bottom Ash Transport Water

EPA estimated compliance costs for plants discharging bottom ash transport water to 

convert from a wet ash handling system to a dry or closed-loop bottom ash handling system (i.e., 

a system that eliminates the discharge of bottom ash transport water). For each generating unit 

discharging bottom ash transport water, EPA estimated costs associated with converting to a dry 

bottom ash handling system in the form of a mechanical drag system (MDS) and costs associated 

with converting to a closed-loop bottom ash handling system in the form of a remote MDS. 

For the MDS, EPA included the costs to demolish the bottom of the boiler and install and 

operate an MDS (at the bottom of the boiler) and a semi-dry silo.

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), therefore eliminating the need for a heat exchanger.92

For the remote MDS, EPA included the costs to install and operate the following:

• Remote MDS (away from the boiler). 

• Sump.

• Recycle pumps.

• Chemical feed system.93

• Semi-dry silo.

 92 The MDS does not need to operate as a closed-loop system because it does not use water as the transport 

mechanism to remove the bottom ash from the boiler; the conveyor is the transport mechanism. Therefore, any water 

leaving with the bottom ash does not fall under the definition of “bottom ash transport water,” but rather, is a low

volume waste.

93 Because the remote MDS uses water as the transport mechanism, all water removed from the system must be 

reused without discharge to meet the zero discharge effluent limitations for bottom ash transport water. EPA 

included costs for a chemical feed system to control pH, should that become necessary to prevent scaling within the 

system. Information in the record indicates that few, if any, plants are likely to need to use such systems. However, 

because EPA could not conclusively determine that none of the plants would need the chemical feed system to 

control pH of the recirculating system, nor which of the plants would be likely to need the system; costs were 

included for all plants. This likely overestimates the compliance costs for most plants; however, the cost for 

chemical addition is relatively small in relation to other costs for the remote MDS.
Section 9—Engineering Costs

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EPA also included capital and O&M costs for transporting and disposing of all bottom 

ash to a landfill for both the MDS and remote MDS.

For all generating units discharging bottom ash transport water, EPA estimated costs for 

the generating unit to convert to either an MDS or a remote MDS. EPA evaluated both of these 

technologies because the MDS is the most commonly used dry handling/closed-loop system 

operating in the industry, but EPA is aware that not all generating units have enough space 

underneath the boiler to accommodate an MDS conversion. While the remote MDS is not as 

common as the MDS, EPA has determined that it can be installed at all power plants. Therefore, 

EPA determined that plants will be able to install one of the two technologies to meet the zero 

discharge requirements. Where plants/companies provided data identifying space constraints 

associated with an MDS conversion, EPA used the cost estimates for the remote MDS 

conversion only for those specific plants. For the remainder, EPA used the lower of the two 

costs.

EPA also identified several plants that operate bottom ash wet handling systems 

predominantly as closed-loop systems. These plants did not discharge bottom ash transport water 

in 2009. However, based on data in responses to the Steam Electric Survey, EPA determined that 

these plants have the ability to discharge bottom ash transport water from emergency outfalls.

Because of the potential to discharge bottom ash transport water, EPA estimated costs for these 

plants to hire a consultant to eliminate the bottom ash transport water emergency outfall and 

install and operate a chemical feed system.

9.2.4 Combustion Residual Leachate

For Regulatory Option E, EPA estimated compliance costs for plants to treat combustion 

residual leachate with a chemical precipitation system. For the remaining regulatory options (A 

through D) requirements for combustion residual leachate based on previously established BPT 

limitations. Therefore, EPA estimated there will be no compliance costs in the final rule 

associated with control of discharges of combustion residual leachate for Regulatory Options A, 

B, C, and D.To estimate the compliance costs for plants that generate landfill leachate, EPA 

included the same cost components as described in Section 9.2.1 for chemical precipitation 

treatment of FGD wastewater.

Plants that generate leachate from surface impoundments containing combustion 

residuals will likely use a different approach than installing the technology basis to comply with 

requirements based on the chemical precipitation technology option. As described in Section 7.4, 

40 percent of plants generating leachate from impoundments containing combustion residuals 

recycle the leachate back to the impoundment from which it was collected. Additionally, some 

plants use the combustion residual impoundment leachate for dust control at a landfill or to 

moisture condition ash transported to a landfill. Based on these data, EPA determined that plants 

would likely comply with the effluent limitations and standards for discharges of combustion 

residual leachate discharges by recycling the leachate back to the impoundment where it was 

generated or use the leachate in a process that does not result in discharge to surface water (e.g., 

moisture conditioning) instead of installing the technology option to treat and discharge the 

wastewater because it is a less expensive alternative. EPA does not consider impoundment 

leachate that is returned back to the impoundment where it was generated as leachate because the 
Section 9—Engineering Costs

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wastewater never leaves the impoundment system. In this case, EPA still considers the 

wastewater to be the wastewater that enters the impoundment (e.g., fly ash transport water, low 

volume wastewater sources). There would be no (or negligible) costs associated with recycling 

the combustion residual impoundment leachate back to the impoundment because the plant will 

either: 1) use the existing pump that transfers the leachate to a separate location to pump it back 

to the impoundment; or 2) install a pump to transfer the leachate to the impoundment. In the 

second case, the costs would likely be offset because the plant would no longer need to operate a 

separate impoundment (or other treatment system) to treat the leachate to meet the previously 

established BPT effluent limitations prior to its discharge. Therefore, EPA determined that there 

are no compliance costs associated with control of discharges of combustion residual leachate 

from surface impoundments under any of the regulatory options considered. Therefore, where 

this section further addresses the costing methodology for combustion residual leachate 

associated with the chemical precipitation technology option, it refers to the costs associated with 

treating combustion residual leachate from landfills.

9.2.5 Gasification Wastewater

EPA identified three currently operating integrated gasification combined-cycle (IGCC) 

units in the United States discharging gasification wastewater.94 Each of these plants operates the 

evaporation system that is the technology basis for the ELGs for gasification wastewater.

95

Therefore, because all the plants are currently operating the BAT system, EPA determined that 

there will be no capital compliance costs associated with the control of discharges of gasification 

wastewater. EPA estimated the O&M costs for these three plants related to compliance 

monitoring.

9.2.6 Flue Gas Mercury Control Wastewater

As described in Section 7.5, there are approximately 62 plants with at least one activated 

carbon injection (ACI) system. Of these, only four (two with current systems and two with 

planned systems) report handling the FGMC waste using a wet-sluicing system. However, only 

one of these four plants 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 

dry handle both the FGMC waste and fly ash. Therefore, EPA estimated there will be no 

compliance costs in the final rule associated with control of discharges of FGMC wastewater.

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 Steam Electric Survey, site visits, and sampling 

episodes. EPA also solicited data from vendors of various wastewater treatment technologies and 

 94 EPA is aware of the Mississippi Power Company’s Kemper County Energy Facility, which is a new IGCC plant 

that is currently under construction. According the operating companies website, the plant will not discharge any 

gasification wastewater and, therefore, the plant will not incur any costs to comply with the ELGs.

95 EPA evaluated all plants operating the evaporation system to determine if any of these plants would require 

additional treatment in order to comply with the ELGs. See “Effluent Limitations for FGD Wastewater, Gasification 

Wastewater, and Combustion Residual Leachate for the Final Effluent Limitations Guidelines and Standards for the 

Steam Electric Rulemaking" for further details on this evaluation [U.S. EPA, 2015b].
Section 9—Engineering Costs

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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, to comply with the final regulations.

As a first step in estimating costs associated with new 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 Steam Electric Survey response and other industry-submitted data

to determine if the wastestreams it discharges may be subject to new requirements under a 

regulatory option considered for the ELGs. Then, for each wastestream that may be subject to 

new requirements for a regulatory option, EPA reviewed the Steam Electric 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., the plant currently uses the technology option for a given wastestream). In some cases, 

EPA determined that a particular plant will incur only minimal compliance costs (e.g., 

compliance monitoring, ORP monitors) for a particular wastestream. For all other applicable 

wastestreams, EPA assessed the operations and treatment system components in place at the 

plant, identified components that the plant would likely install to comply with the final rule, 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 its 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, for an existing source to comply with Option D, 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.

96 EPA 

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, for an existing source to comply with Option D, EPA estimated 

compliance costs for a plant that currently treats its FGD wastewater in a chemical precipitation 

system prior to discharge. In this case, EPA evaluated the following: 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 in 

place components such as chemical feed systems, solids contact clarifier, sand filter, effluent and 

sludge holding tanks, sludge filter presses, and pumps. 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 should be factored in based on the plant’s reported chemical 

 96 Converting a steam electric generating unit from wet to dry fly ash handling 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

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addition and dosages, and estimated the costs for installing and operating the biological treatment 

stage.

EPA also evaluated the additional transportation and landfill operations that might be 

appropriate to dispose of the additional solid waste generated (FGD sludge, fly ash, bottom ash) 

from implementing the technology options. EPA estimated disposal costs based on whether or 

not the plant reported an on-site combustion residual landfill.

For each plant, EPA calculated compliance costs for all applicable technology options 

and then calculated the total capital, O&M, and other one-time or recurring costs for the six main 

regulatory options, presented in Table 8-1. For more information on the compliance cost 

methodology, see EPA’s Incremental Costs and Pollutant Removals for Final Effluent Limitation 

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

EPA, 2015a].

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 identifying which 

wastewaters are discharged from each plant, 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 plant-specific input data and industry 

assumptions/factors to calculate costs for a specific cost component (technology or technology 

component) for each applicable wastestream for each plant and each regulatory option. Finally, 

reporting programs generate the model outputs. These reporting programs combine the 

applicable cost components to calculate plant-level capital and O&M 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 O&M costs by regulatory option.

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).
Section 9—Engineering Costs

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

Technology Option

Technology Cost Module

Chemical 

Precipitation

Biological 

Treatment

Evaporation

Dry Fly Ash 

Handling

Dry Bottom Ash 

Handling a

Compliance 

Monitoring

Transportation

Disposal

Surface 

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    

Gasification Wastewater: Evaporation b 

Note: As described in Section 9.2.6, EPA did not estimate costs for FGMC wastewater.

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.

b – The Agency calculated the plant-level gasification wastewater costs separate from the cost model. See Section 9.9. 
Section 9—Engineering Costs

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9.4.1 Input Data to Technology Cost Modules

EPA developed a set of input tables based on information from the Steam Electric Survey 

responses, site visits, sampling episodes, and other industry provided data. The cost model 

references the input tables to estimate the appropriate compliance cost for each plant for each 

technology option. To estimate the plant-level compliance costs for each regulatory option, the 

cost model estimates compliance costs on a plant basis for each technology option and then sums 

the various technologies. EPA used plant responses to the Steam Electric Survey, public 

comments, and other data gathered from vendors and discussions with specific plants to identify 

the population of plants that discharge wastestreams that may be subject to new or additional 

limitations or standards [ERG, 2015a]. If the plant does not discharge an applicable wastestream, 

or if the plant announced plans to retire or alter operations that would eliminate the discharge of 

an applicable wastestream then EPA set the compliance costs for that wastestream at zero.

97

EPA’s estimate of the number of plants and corresponding compliance costs presented in this 

section reflect these planned retirements and changes in operations that would eliminate the 

discharge of an applicable wastestream.

EPA coordinated the requirements of the CCR rule and the ELG to avoid establishing 

overlapping regulatory requirements and to facilitate the implementation of engineering, 

financial, and permitting activities. For the ELGs, EPA calculated costs, pollutant 

loadings/removals, non-water quality environmental impacts, environmental assessment, and 

benefits analyses under two scenarios: one that incorporates changes EPA expects as a result of 

plants complying with the CCR rule and one that also incorporates changes EPA expects as a 

result of plants complying with the CPP.

98 To account for the implementation of the CCR rule, 

EPA updated its population and associated treatment in place to account for the changes in plant 

operations that EPA projected under the CCR rule (see the description of the CCR Input Table 

later in this section). All numbers presented in this report reflect the analyses EPA prepared 

based on the population that accounts for the implementation of the CCR rule. Table 9-2

identifies the number of plants that EPA estimates would incur costs to comply with new or 

additional effluent limitations or standards for a wastestream under at least one of the evaluated 

ELG regulatory options. See the appendix of EPA’s Incremental Costs and Pollutant Removals 

for Final Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category report for the estimate of what the cost and loadings for the ELG would 

be in absence of the CCR rule and CPP [U.S. EPA, 2015a].

Similar to the CCR rule, EPA accounted for operational changes expected as part of the 

CPP. Because only the proposed version of the CPP was available at the time EPA evaluated 

compliance costs, the Agency estimated compliance costs that account for expected changes 

 97 EPA assumed that there would be no incremental compliance costs attributable to the ELGs for generating units 

that have announced plans to retire, convert to a non-coal fuel source, or change/upgrade ash handling practices 

prior to implementation of the final rule. See the Changes to Industry Profile for Steam Electric Generating Units 

for the Steam Electric Effluent Guidelines Final Rule [ERG, 2015d] for a detailed list of these plants and generating 

units.

98 EPA also conducted additional analyses to estimate what the costs and pollutant removals for the ELGs would be 

in the absence of both the CCR rule and CPP. For more details on this sensitivity analysis see the Incremental Costs 

and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category [U.S. EPA, 2015a].
Section 9—Engineering Costs

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from the proposed CPP rather than the final CPP. As discussed in Section 1.3.3, the CPP 

rulemaking is focused on cutting carbon pollution from power plants and EPA estimates that 

some generating units may retire due to the CPP.99 To account for these closures/retirements, 

EPA generated a second set of compliance cost estimates where all generating units that are 

projected by the Integrated Planning Model (IPM) to close/retire due to the CPP were assumed to 

be retired prior to implementation of the ELGs; therefore, these generating units would not incur 

any ELG compliance costs. Throughout the remainder of this section, EPA presents compliance 

cost estimates that do not account for the CPP, followed by estimates that account for the CPP 

(referred to hereafter as “accounting for CPP”). Table 9-3 adjusts the results shown in Table 9-2, 

accounting for the projected closures related to the implementation of the CPP.

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

FGMC

Wastewater Total a

A 87 19 0 0 3 0 100

B 87 19 0 0 3 0 100

C 87 19 78 0 3 0 139

D 87 19 141 0 3 0 181

E 87 19 141 82 3 0 196

a – The number of plants incurring costs is not additive for each regulatory option because some plants may incur 

costs for multiple wastestreams. 

Table 9-3. Number of Plants Expected to Incur Compliance Costs by Wastestream and 

Regulatory Option, Accounting for CPP

Regulatory 

Option

FGD 

Wastewater

Fly Ash 

Transport 

Water

Bottom Ash 

Transport 

Water

Combustion 

Residual 

Leachate

Gasification 

Wastewater

FGMC

Wastewater Total a

A 69 16 0 0 2 0 79

B 69 16 0 0 2 0 79

C 69 16 61 0 2 0 108

D 69 16 103 0 2 0 134

E 69 16 103 60 2 0 145

a – The number of plants incurring costs is not additive for each regulatory option because some plants may incur 

costs for multiple wastestreams. 

 99 The IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. electric power sector. 

It provides forecasts of least-cost capacity expansion, electricity dispatch, and emission control strategies for 

meeting energy demand and environmental, transmission, dispatch, and reliability constraints. IPM can be used to 

evaluate the cost and emissions impacts of proposed policies to limit emissions of sulfur dioxide (SO2), nitrogen 

oxides (NOx), carbon dioxide (CO2), hydrogen chloride (HCl), and mercury (Hg) from the electric power sector. The 

Agency used IPM to predict the industry response to the CPP, which EPA used to identify projected generating unit 

retirements. The CPP IPM policy run projected 323 generating units to close or retire by 2020.
Section 9—Engineering Costs

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Each technology cost module includes a set of input tables. These input tables include 

indicators specifying the type of costs required for each technology option and the plant-specific 

data used in the cost equations. The following sections describe each of the input tables used in 

the technology cost modules. See the FGD and Ash Steam Electric Cost Model and the Leachate 

Steam Electric Cost Model for the specific input tables described below [ERG, 2015b; ERG, 

2015c].

FGD Wastewater Flow

For each applicable plant, EPA identified a system-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. The cost model calculated a plant-level FGD wastewater 

flow rate by summing the system-level purge rates for each FGD system at each plant. 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 

Final 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, 2015a].100

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 chemical precipitation, 

anoxic/anaerobic biological treatment, or evaporation systems, EPA did not estimate compliance 

costs for the specific pieces of equipment that are already operating at the plant. For example, 

under Regulatory Option D, if a plant operates a chemical precipitation system to treat FGD 

wastewater that includes all the steps included as the basis for the technology option other than 

sulfide precipitation, then EPA included capital costs for the plant to install a reaction tank and 

sulfide chemical feed system and O&M costs for the amount of sulfide added to the system on a 

yearly basis, plus the full capital and O&M costs for the biological treatment system. A plant 

would not incur compliance costs for pieces of equipment that are part of the technology basis 

and already installed and operating at the plant. 

Fly Ash Production Data

For each applicable generating unit, EPA identified generating unit-level wet fly ash 

production and dry fly ash production in tons per day and days per year, generating unit type, 

capacity in MW, fly ash transport water flow rate in gallons per day (gpd), and operating days 

per year. EPA used these values reported in the Steam Electric Survey as input values for the fly 

 100 EPA assumed that to achieve the limitations and standards, certain plants with high FGD discharge flow rates 

(greater than or equal to 1,000 gallons per minute (gpm)) would elect to incorporate flow minimization into their 

operating practices (by recycling a portion of their FGD wastewater back to the FGD system), where the FGD 

system metallurgy can accommodate an increase in chlorides. See Section 4.5.4 of EPA’s Incremental Costs and 

Pollutant Removals for Final Effluent Limitation Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category report for more details on the methodology specific to plants with high FGD 

discharge flow rates [U.S. EPA, 2015a].
Section 9—Engineering Costs

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ash technology cost module. Because the cost model estimates fly ash compliance cost at the 

generating unit level, EPA used generating 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 were estimated to incur 

the costs for complete conversion of the dry fly ash handling system. Those generating units 

equipped with both wet and dry fly ash handling capabilities may need only certain additional 

equipment for them to handle all fly ash dry (i.e., additional vacuum capacity, redundant system 

conveyance equipment, additional silo capacity, additional unloading equipment, back up silos 

and/or unloading equipment). EPA evaluated each plant and generating unit to identify the 

additional equipment that is likely to be needed and included costs for only those pieces of 

equipment. EPA determined that those generating units that currently use only a dry fly ash 

handling system do not incur any costs to comply with the ELGs.

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, capacity in MW, generating unit type, 

bottom ash transport flow rate in gpd, and pond distance. EPA used these values reported in the 

Steam Electric Survey as input values for the bottom ash technology cost module. Because the 

cost model estimates bottom ash compliance cost at the generating unit level, EPA used 

generating-unit-level input values to estimate conversion costs. EPA also identified generating 

units that recycle the majority of their bottom ash sluice and have emergency outfalls only to 

estimate bottom ash management costs.

EPA also identified generating units with existing dry or closed-loop bottom ash handling 

equipment. Steam electric generating units equipped with only wet bottom ash handling systems 

that discharge bottom ash transport water were estimated to incur the costs for complete 

conversion to the dry or closed-loop dry bottom ash handling system. EPA determined that those 

generating units that currently use only a dry or closed-loop bottom ash handling system do not 

incur any costs to comply with the ELGs. EPA did not identify any generating units equipped 

with both wet and dry bottom ash handling capabilities.

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.

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 as defined by the plant in response to the Steam Electric Survey. Plants without an 

on-site active/inactive landfill with combustion residuals were identified as off-site landfills.
Section 9—Engineering Costs

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Combustion Residual Leachate Data

For each landfill identified as collecting and discharging combustion residual landfill 

leachate, EPA determined the combustion residual landfill leachate volume discharged each year 

in gallons per day. For those plants that did not report a combustion residual landfill leachate 

volume in the Steam Electric Survey, EPA estimated a flow rate using data from other plants that 

did report a combustion residual landfill leachate volume. EPA first determined a median 

combustion residual landfill leachate discharge rate per acre of landfill containing combustion 

residuals, based on the responses to the Steam Electric Survey. EPA then multiplied the median 

value by a plant’s reported combustion residual landfill acreage collecting leachate to estimate a 

flow rate. For those plants that did not report a combustion residual landfill 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 for which it could not estimate a value using the other two 

approaches, EPA estimated the combustion residual landfill leachate volume using the median 

combustion residual landfill leachate volume for all plants reporting a volume.

See Section 4.1.3.1 of EPA’s Incremental Costs and Pollutant Removals for Final

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, 2015a].

Final CCR Rule Decisions Input Table

The CCR rule sets requirements for managing impoundments and landfills containing 

CCRs. Based on the CCR requirements, EPA expects that some plants will alter how they 

operate their current CCR impoundments, including by undertaking the following potential 

changes:

• Close the disposal surface impoundment101 and open a new disposal surface 

impoundment in its place.

• Convert the disposal surface impoundment to a new storage impoundment.

102

• Close the disposal surface impoundment and convert to dry handling operations.

• Make no changes to the operation of the disposal surface impoundment.

The CCR rule evaluated these potential operational changes for plants that were 

identified as operating disposal impoundments based on Energy Information Administration 

(EIA) data.103 To be consistent with the methodology used by RCRA, EPA did not evaluate 

these options for storage impoundments because EPA assumed that storage impoundments will 

 101 For the CCR rule, a disposal surface impoundment is generally defined as an impoundment that is not dredged 

and all CCRs are left in place in perpetuity. 102 For the CCR rule, a storage impoundment is generally defined as an impoundment that is periodically dredged 

and has its CCR disposed elsewhere such that it can continue operating indefinitely.

103 For the CCR rule, if a plant reported active wet CCR disposal in one or more impoundments in its EIA data, EPA 

considered the largest impoundment (in terms of capacity) at the plant as a CCR disposal impoundment.
Section 9—Engineering Costs

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operate indefinitely and if a groundwater contamination event occurs, the plant will build a new 

storage impoundment (but will not convert to dry handling operations).104

For this rulemaking, EPA developed a methodology to use the output analysis of the 

CCR rule to predict which of the four potential operational changes would likely occur at each 

coal-fired power plant that operates disposal impoundments under the CCR rule. See EPA’s 

Incremental Costs and Pollutant Removals for Final Effluent Limitation Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category report for more 

details on the methodology EPA used to predict operational changes expected as a result of the 

CCR rule [U.S. EPA, 2015a]. Using the plant-level decision for operational changes the plant 

will likely make based on the CCR rule, EPA then applied that decision to each of the evaluated 

discharged wastestreams for this rule. Finally, EPA evaluated the EIA data to identify which 

plants were identified under the CCR rule as operating only storage impoundments. While these 

plants, and wastestreams, are not converting to a storage impoundment as a result of CCR, they 

already operate a storage impoundment and, therefore, it allowed EPA to classify them in the 

population as operating storage impoundment for the appropriate wastestreams.

Based on those analyses, EPA generated the CCR Input Table that it used in the costs 

model and loadings databases to adjust the ELG baseline to account for the CCR rule. Table 9-4

describes how EPA used the classifications in the CCR Input Table to adjust the ELG baseline. 

After adjusting the ELG baseline to account for the implementation of the CCR rule, 

EPA generated the costs, pollutant loadings, non-water quality impacts, environmental 

assessment, and benefits of the rule. As such, EPA has minimized the degree to which its 

analyses have potentially “double counted” impacts associated with the ELG and the CCR rule. 

All numbers presented in this report reflect the updated ELG baseline population accounting for 

the CCR rule.

Table 9-4. ELG Baseline Changes Accounting for CCR Rule

ELG 

Wastestream

CCR Rule 

Decision

Adjustment to 

ELG Baseline Effect on ELG Costs a

Effect on ELG 

Loadings a

FGD 

wastewater

New disposal 

impoundment

No changes No changes No changes

New storage 

impoundment

No changes No changes No changes

Convert to dry 

handling

Plant has a BAT 

chemical 

precipitation system 

in place

Plant incurs the following costs:

- Mercury analyzer

- Compliance monitoring

- All biological treatment 

system costs (including 

transportation/disposal)

Baseline loadings 

are based on 

chemical 

precipitation 

treatment in place

No decision No changes No changes No changes

New disposal 

impoundment

No changes No changes No changes

 104 For the CCR rule, if a plant did not report active wet CCR disposal in any impoundments in its EIA data, EPA 

considered all impoundments at the plant to be CCR storage impoundments.
Section 9—Engineering Costs

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Table 9-4. ELG Baseline Changes Accounting for CCR Rule

ELG 

Wastestream

CCR Rule 

Decision

Adjustment to 

ELG Baseline Effect on ELG Costs a

Effect on ELG 

Loadings a

Fly ash 

transport 

water

New storage 

impoundment

Plant dredges fly 

ash from 

impoundment and 

disposes of it

Plant incurs full conveyance and 

intermediate storage capital and 

O&M costs, but does not incur

transport/disposal costs

No changes

Convert to dry 

handling

Plant operates a dry 

fly ash handling 

system for all 

generating units

Plant incurs no fly ash 

compliance costs.

Plant has a 

baseline fly ash 

loading of zero.

No decision No changes No changes No changes

Bottom ash 

transport 

water

New disposal 

impoundment

No changes No changes No changes

New storage 

impoundment

Plant dredges 

bottom ash from 

impoundment and 

disposes of it

Plant incurs full conveyance and 

intermediate storage capital and 

O&M costs, but does not incur 

transport/disposal costs

No changes

Convert to dry 

handling

Plant operates a dry 

bottom ash 

handling or closedloop recycle system 

for all generating 

units

Plant incurs no fly ash 

compliance costs.

Plant has a 

baseline bottom 

ash loading of 

zero.

No decision No changes No changes No changes

a – Changes described are compared to the costs and loads that would have been calculated if EPA was not 

accounting for the CCR rule.

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 all 

plants incurring costs for a specific 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 pounds/cubic foot (lbs/ft3), 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 information on the specific technology cost module factors, see 

EPA’s Incremental Costs and Pollutant Removals for Final Effluent Limitation Guidelines and 

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

2015a].

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. EPA adjusted all costs to 2010 dollars using the RS Means Historical 

Cost Index values for all technology cost modules [RSMeans, 2015].
Section 9—Engineering Costs

9-18

• Freight Cost Factors. The factors used to estimate shipping costs are universal for 

all technology options. EPA estimated these values using data from 

FreightCenter.com and vendor contacts. [U.S. EPA, 2015a].

9.4.3 Technology Cost Modules

To estimate the plant-level technology option compliance costs, EPA developed eight 

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 list. 

• Biological Treatment – calculates capital and O&M costs for an anoxic/anaerobic 

biological treatment system.

• Chemical Precipitation – calculates capital and O&M costs for the chemical 

precipitation system.

• Evaporation – calculates capital and O&M costs for the evaporation system,

• Dry Fly Ash Handling – calculates capital, O&M, and recurring costs for the dry fly 

ash handling system.

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

for the dry or closed-loop recycle bottom ash handling systems.

• Transportation – calculates O&M costs for 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 for disposing of FGD, ash, and/or 

landfill leachate solid waste in an on- or off-site landfill.

• Impoundment Operation – calculates O&M and recurring costs for operating and 

maintaining an on-site impoundment.

For each technology option shown in Table 9-1, the cost model sums the costs calculated 

from the technology cost modules that compose each option to calculate total capital, total O&M, 

and one-time and recurring costs.

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 costs, total O&M costs, total 3-year recurring costs, total 5-

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 

components for each of the technology costs. The cost-component level includes equipment 

costs, direct capital costs, indirect capital costs, and individual O&M costs (e.g. labor, materials, 

energy, effluent monitoring, and chemicals). See Sections 9.6.4, 9.7.3, 9.8, and 9.9 for the cost 

model outputs for each technology.
Section 9—Engineering Costs

9-19

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 

technology option without duplicating the calculations in the cost model. For example, the cost 

methodology for disposing of combustion residual solid waste in 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 wastestream (e.g., FGD, fly ash, or bottom ash). The following sections 

describe the methodology used to estimate costs for compliance monitoring, transportation,

disposal, and impoundment operations.

9.5.1 Compliance Monitoring Costs

Where a regulatory option would establish requirements for pollutants not regulated in 

the previously established ELGs, EPA calculated plant-level compliance monitoring costs for 

plants to sample and analyze their discharges to assess their compliance with the associated 

effluent limitations and standards. 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 National Pollutant Discharge Elimination System (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. EPA based the number of labor hours on the labor required during its field 

sampling program.

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 event and the number of sampling events per year. 

EPA based the sampling material costs on the costs it 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 sample preservation costs for nitrate/nitrite samples. These samples 

require chemical preservation to ensure that pollutants present in the wastewater do not degrade 

prior to laboratory analysis. EPA based the sample preservation costs on the costs it incurred 

during its field sampling program. Sample preservation is not required for arsenic, selenium, or 

mercury.

Compliance Monitoring Costs = Sampling Labor Costs + Sampling Materials Costs 

+ Sample Preservation Costs + Sample Shipping Costs + Sample Analysis Costs
Section 9—Engineering Costs

9-20

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 these laboratories would be able to analyze 

the samples for total dissolved solids and nitrate-nitrite as N. This methodology would 

overestimate costs for those plants that are already monitoring for these pollutants.

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 it incurred during its field sampling program. See Section 5.2 

of EPA’s Incremental Costs and Pollutant Removals for Final Effluent Limitation Guidelines

and Standards for the Steam Electric Power Generating Point Source Category report for more 

details on the compliance monitoring cost methodology [U.S. EPA, 2015a].

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 

ELGs, EPA conservatively included costs for plants to transport all solid waste generated as a 

result of complying with the ELGs 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. EPA included costs for plants with existing on-site landfills containing combustion 

residuals to dispose of any combustion residuals resulting from compliance with the ELGs in an 

on-site landfill (e.g., wet ash handling system converted to dry ash handling system), 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 nonhazardous landfill. Costs for disposing of combustion 

residuals are described in Section 9.5.3.

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 transportation 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 transporting combustion residuals on the total amount of 

waste generated at each plant as a result of compliance with the ELGs. 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. The dollar per 

ton of solid waste value for on-site landfills is based on information provided by ORCR for the 

CCR rule, developed using the Remedial Action Cost Engineering Requirements (RACER 2010) 
Section 9—Engineering Costs

9-21

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. The dollar per ton of solid waste value for off-site landfills was provided by ORCR 

based on the RACER 2010 model. For each plant and wastestream, EPA summed the total 

tonnage of combustion residuals generated as a result compliance with the ELG and multiplied it 

by the appropriate transportation cost to estimate a plant-specific transportation cost for each 

wastestream. See Section 5.3 of EPA’s Incremental Costs and Pollutant Removals for Final 

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, 2015a].

9.5.3 Disposal Costs

EPA conservatively determined costs for plants to dispose of all combustion residuals 

generated as a result of compliance with the ELGs in on-site or off-site landfills. For plants able 

to market/sell these residuals, EPA overestimated the disposal costs and has not accounted for 

any revenue associated with other marketing options. As , EPA used data from the Steam 

Electric Survey to identify which plants have existing on-site 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. The costs include those 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 disposal costs (e.g., tipping fees) 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 as a result of complying with the ELGs. 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.

For disposal in an on-site landfill, capital costs include the construction of the landfill, 

liner, additional groundwater monitoring, leachate collection system, and closures associated 

with expanding an existing landfill. EPA used a unitized cost value (in dollars per ton), that 

represents the capital cost components for an on-site landfill, and the estimated amount of solid 

waste produced from implementing the 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 

Final 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, 2015a].
Section 9—Engineering Costs

9-22

9.5.4 Impoundment Operation Costs

Implementing 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 associated with not 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 Final Effluent Limitation 

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

report for more details on the impoundment operation cost methodology [U.S. EPA, 2015a].

Impoundment O&M costs are the costs associated with operating the impoundment, 

including the transportation system (i.e., pipelines, vacuum source), the impoundment site, the 

treatment operations (e.g., pH adjustment), and the water recycle system at the impoundment.

105

EPA calculated impoundment O&M costs using a unitized cost value ($7.35/ton), representing 

the impoundment O&M costs only, and the estimated difference in the amount of wet FGD 

solids, fly ash, and bottom ash entering an impoundment at baseline and after compliance.

Earthmoving O&M costs are the costs associated with operating earthmoving equipment 

(e.g., front-end loader) required for sorting/stacking fuel combustion residual materials at the 

impoundment site. EPA calculated the earthmoving O&M costs using a unitized cost value 

($2.49/ton), representing the O&M costs associated only with operating the earthmoving 

equipment, and the estimated difference in the amount of wet FGD solids, fly ash, and bottom 

ash entering an impoundment at baseline and after compliance.

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 economies 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].

 105 EPA estimated costs associated with operating the transportation system (i.e., pipelines, vacuum source) for the 

fly ash portion of the estimate. These costs were excluded from the bottom ash portion of the estimate due to the two 

technology options selected by EPA for bottom ash (MDS and remote MDS). The compliance costs associated with 

the MDS already accounts for these savings. Alternatively, the remote MDS still requires using the existing wetsluicing system to transport the bottom ash to the remote MDS destination. 

Total O&M Costs = (-1) × (Impoundment O&M Costs + Earthmoving O&M Costs) 

× (Capacity Factor)
Section 9—Engineering Costs

9-23

EPA calculated 10-year recurring costs associated with operating the earthmoving 

equipment (i.e., front-end loader). EPA calculated the total 10-year recurring costs by 

determining the cost and average expected life of a front-end loader. EPA determined that the 

expected life of a front-end loader is 10 years and that each plant will operate one front-end 

loader per each type of combustion residual waste (e.g., FGD solids, fly ash, or bottom ash) 

identified as entering an impoundment at baseline. 

9.6 FGD WASTEWATER

EPA estimated capital, O&M, 6-, and 10-year recurring costs associated with installing 

three technology options for FGD wastewater:

• Chemical Precipitation.

• Chemical Precipitation followed by Biological Treatment.

• Chemical Precipitation followed by Evaporation.

EPA estimated the chemical precipitation, biological treatment, and 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 evaporation costs to calculate the total costs for the 

technology option).

9.6.1 Chemical Precipitation

Section 7.1.2 describes the chemical precipitation system that forms the basis for this 

technology option. Additionally, Section 9.2.1 summarizes the technology basis for the chemical 

precipitation system. EPA estimated the costs to install and operate a 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 Final

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, 2015a]. 

Based on site visits, EPA determined that 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 ELGs, EPA included costs for a mercury analyzer and extra equipment to analyze 

mercury in the FGD wastewater discharge and, if necessary (i.e., when effluent concentrations 

do not meet the ELGs), recycle the chemical precipitation discharge for further treatment. Using 

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 ELGs. See Section 7 for additional details.

Total 10-Year Recurring Costs = (-1) × (Cost of Earthmoving Vehicle)
Section 9—Engineering Costs

9-24

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 D, if a plant operates a 

chemical precipitation system to treat FGD wastewater that includes all the steps included as the 

basis for the technology option other than sulfide precipitation, then EPA included capital costs 

for the plant to install a reaction tank and sulfide chemical feed system and O&M costs for the 

amount of sulfide added to the system on a yearly basis, plus the full capital and O&M costs for 

the biological treatment system. A plant would not incur compliance costs for pieces of 

equipment that are part of the technology basis and already installed and operating at the plant.

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 to purchase 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.

• Clarifiers.

• Filter presses.

• Sand filters.

• Mercury analyzer.

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.

Direct capital costs account for all costs incurred as a direct result of installing the 

chemical precipitation system. The direct capital costs include purchased equipment 

installation,106 building, land, and site preparation. Indirect capital costs account for all nondirect costs incurred as a result of installing the treatment system. The indirect capital costs (e.g., 

 106 Purchased equipment installation costs are the costs associated with installing those pieces of purchased 

equipment, including piping, instrumentation, calibration, and structural supports.

Total Capital Costs = Purchased Equipment Costs + Direct Capital Costs + Indirect 

Capital Costs + Sludge Disposal Costs
Section 9—Engineering Costs

9-25

engineering, construction, and other contractor fee costs) are those associated with preparing a 

specific site for installing the chemical precipitation equipment and the costs required for 

supervising and inspecting the installation. EPA estimated the direct capital costs by developing 

a cost factor from data provided in response to the Steam Electric Survey. EPA used the median 

ratio of total direct capital costs to total reported purchased equipment costs based on the plants 

in the analysis. Therefore, once EPA calculated the total purchased equipment costs for chemical 

precipitation, EPA then multiplied the cost by median ratio to estimate the direct capital cost. 

EPA estimated indirect capital costs as a percentage of the total direct capital costs (purchased 

equipment costs plus direct capital costs) based on information obtained from a publically 

available costing manual, Plant Design and Economics for Chemical Engineers (Peters and 

Timmerhaus, 1991). See Section 6.2.6.10 of the Incremental Costs and Pollutant Removals for 

Final Effluent Limitations Guidelines and Standards for the Steam Electric Generating Point 

Source Category report for more details on the methodology for estimating the indirect capital 

costs [U.S. EPA, 2015a].

To calculate the sludge disposal costs, associated with on-site landfill disposal described 

in Section 9.5.3, EPA needed to estimate the annual generation of sludge associated with the 

chemical precipitation treatment system. 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 materials 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 Steam Electric 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 materials costs by using data from the Steam Electric Survey to develop an equation 

relating FGD wastewater treatment flow rate to the total yearly maintenance material costs.

Chemical purchase costs are the costs to purchase 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 BAT plants included in 

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
Section 9—Engineering Costs

9-26

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 kilowatt hour per year (kWh/yr). EPA used 

the national 2010 energy cost of 4.05 cents per kWh to calculate the energy cost [U.S. DOE, 

2011].

EPA estimated the O&M costs associated with compliance monitoring, transportation, 

disposal, and impoundment operations savings 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 daily to ensure the 

treatment system is effectively treating mercury to meet the final effluent 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 6 years and that each plant will operate one analyzer for FGD wastewater.

9.6.2 Biological Treatment

Section 7.1.3.2 describes the anoxic/anaerobic biological treatment system that forms the 

basis for this technology option. For Regulatory Options B, C, D, and E, EPA estimated 

compliance costs to install and operate the anoxic/anaerobic system to treat FGD wastewater in 

addition to the BAT chemical precipitation system. The anoxic/anaerobic system is specifically 

designed and operated to target removals of selenium and nitrate. See Section 6.2 of the 

Incremental Costs and Pollutant Removals for Final 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, 2015a].

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.

EPA developed pretreated FGD wastewater characteristics to use as the basis for cost 

development for the biological treatment system.107 EPA developed these FGD wastewater 

 107 The pretreated FGD wastewater characteristics developed for this analysis are similar to the chemical 

precipitation effluent characteristics identified in Section 10; 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 Final Effluent Limitations Guidelines and Standards for the Steam Electric Generating 

Point Source Category report [U.S. EPA, 2015a].

Total Recurring 6-Year Costs = Cost of Mercury Analyzer
Section 9—Engineering Costs

9-27

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 pretreated 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 

depend on a plant’s FGD wastewater flow rate. For flow rates greater than 25 gpm, the vendor 

provided costs for customized field-erected biological treatment systems. For flow rates less than 

25 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 

treatment system, especially during the warmer seasons, and the wastewater may require cooling 

prior to entering biological treatment. Therefore, the design basis includes a heat exchanger for 

certain southern plants that EPA determined required cooling of FGD wastewater for biological 

treatment, based on set latitudinal and longitudinal coordinates where the average July 

temperature is 90°F or greater. The design basis also includes a building for northern plants, 

located in areas where the mean daily minimum temperature is below 32°F, to house biological 

treatment equipment to prevent freezing.

As described in Section 7.1.3, EPA included an ORP monitor as part its design basis of 

the biological treatment system. This monitor is installed in the FGD purge line (or at the 

chemical precipitation equalization tank) to monitor ORP, which may affect biological treatment 

performance, in the biological treatment influent. The monitor serves to notify operators to alter 

FGD operations to control the ORP, which is necessary to prevent corrosion of the FGD 

equipment and prevent mercury re-emission in stack emissions. Through contact with vendors 

and other industry representatives, EPA has learned that sodium bisulfite, a reducing agent, has 

been used in current FGD treatment systems to help control free oxidants that may be present 

during periods of elevated ORP.108 The design basis in EPA’s cost estimate includes a sodium 

bisulfite chemical feed system to counteract elevated ORP. See Section 7 for more details 

regarding elevated ORP levels in FGD scrubbers/wastewater and its effect on biological 

treatment systems.

Based on feedback from the biological treatment system vendor, FGD wastewater with 

nitrate-nitrite as N concentrations exceeding 100 milligrams per liter (mg/L) should be pretreated 

to reduce concentrations prior to the biological treatment stage. EPA used sampling data and 

responses to the Steam Electric Survey to identify plants with nitrate-nitrite as N concentrations 

at or above 100 ppm. For these plants, EPA included an additional denitrification system in its 

cost estimate to target removal of nitrate-nitrite in the FGD wastewater. EPA’s design basis 

includes a tank and biofilm reactor installed downstream of the chemical precipitation system, 

but upstream of the biological treatment system for only those plants demonstrating elevated 

nitrate/nitrite concentrations.

 108 Using ferrous chloride (in place of ferric chloride) within the chemical precipitation treatment system can also 

control free oxidants.
Section 9—Engineering Costs

9-28

As noted in Section 9.4.1, EPA evaluated 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 to purchase the pieces of equipment required to 

construct the anoxic/anaerobic biological system. EPA calculated purchased equipment costs by 

summing the following costs:

• Anoxic/anaerobic biological system.

• Heat exchanger (for applicable plants).

• Backwash recycle pump.

• ORP monitor. 

• Sodium bisulfite chemical addition system.

• Denitrification system (for applicable plants). 

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 vendor provided costs for the following cost components:

• Two-stage bioreactor system (i.e., two reactors in series per train) with a 10-hour 

residence time for the system, operating 24 hours per day and 365 days per year. 

System-level costs include the following purchased equipment and associated 

ancillary equipment:

- All process pumps, valves, and instruments.

- Process and instrument compressed air system, valves, and lines.

- Nutrient system, storage tank, and pumping.

- Process piping and supports.

- Concrete bioreactor tank walls and floor with epoxy-coated rebar and epoxy 

flake-glass coating.

- Concrete backwash supply and backwash wastewater tank walls and floor with 

epoxy-coated rebar and epoxy flake-glass coating.

- Concrete process and utility sump with pumps.

- Support steel, access stairs, walkways, grating, and handrails.

Total Capital Costs = Purchased Equipment Costs + Direct Capital Cost + Indirect 

Capital Cost + Sludge Disposal Costs
Section 9—Engineering Costs

9-29

• Process equipment building with heating, ventilating, and air conditioning (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).

• 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 pump needed for some systems. 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 wastewater temperature 

to 95°F prior to entering the bioreactors.

EPA also used information from vendors to develop cost equations for the ORP monitor 

and sodium bisulfite chemical addition system. EPA used pilot test data provided by the industry 

to estimate the concentration and dosage of sodium bisulfite needed to treat the FGD wastewater 

based on plant-specific FGD wastewater flow rates. 

EPA used cost information from a vendor to develop cost equations for the denitrification 

system. The vendor provided EPA with cost estimates for three different FGD wastewater flow 

rates for the following cost components:

• One moving bed biofilm reactor (MBBR) (One reactor at100%).

• AnoxKaldnesTM media (specialized plastic biocarriers).

• Reactor mixer.

• Sieves.

• Two micro C feed pumps (Two pumps at 100%).

• One drumfilter (for 100 gpm) or discfilter (for 500 and 1,000 gpm) (One filter at 

100%).

• All necessary probes and sensors.

• One phosphoric acid metering skid pump.

• One polymer feed pump.

• Start-up and training.

• Detailed engineering.

• Equipment shipping, unloading, and installation.

• Civil, mechanical, electrical, and instrumentation and controls.

• Access structure (e.g., ladders, platforms).

• Performance testing.

EPA used the cost information to create cost curves used to estimate plant-level costs for specific 

flow rates.
Section 9—Engineering Costs

9-30

Direct capital costs account for all costs incurred installing and erecting the biological 

treatment system. The direct capital costs include purchased equipment installation, building, 

land, and site preparation. 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 anoxic/anaerobic biological system for each plant 

using two different installation cost factors. The first factor was provided by the vendor and is 

specific to installing the anoxic/anaerobic biological system. The second factor was determined 

based on responses to the Steam Electric Survey and applies to installing the heat exchanger, 

system pumps, ORP monitor, and sodium bisulfite chemical feed system. This second factor is 

the same installation equipment cost factor used for the FGD chemical precipitation system. EPA 

did not estimate additional direct capital costs for the denitrification system because vendor 

estimates already include costs for installation, instrumentation and controls, and other 

installation activities.

EPA estimated costs for plants located in cold climates to erect a building to house the 

biological treatment system equipment to prevent freezing. EPA calculated a ratio of the building 

cost to the FGD wastewater treatment flow rate for each plant that reported cost and flow rate 

data in the Steam Electric Survey. EPA used the average ratio to estimate building costs for only 

those plants located in regions with below freezing mean daily minimum temperatures, based on 

data from the National Climate Data Center.

Indirect capital costs account for all non-direct costs incurred as a result of installing and 

erecting the treatment system. The indirect capital costs (e.g., engineering, construction, other 

contractor fee costs) are those associated with preparing a specific site for installing the 

biological treatment system and the costs required for supervising and inspecting the installation.

EPA estimated indirect capital costs as a percentage of the total direct costs (purchased 

equipment costs plus direct capital costs) based on information obtained from a publically 

available costing manual, Plant Design and Economics for Chemical Engineers (Peters and 

Timmerhaus, 1991). See Section 6.2.5.7 of the Incremental Costs and Pollutant Removals for 

Final Effluent Limitations Guidelines and Standards for the Steam Electric Generating Point 

Source Category report for more details on methodology for estimating the indirect capital costs

[U.S. EPA, 2015a].

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.

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
Section 9—Engineering Costs

9-31

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 workers required to operate the system. EPA used number of workers and 

the median operation and maintenance labor rates from responses to the Steam Electric Survey to 

calculate the labor costs. To calculate the maintenance materials costs, EPA used Steam Electric 

Survey data to calculate a ratio of the reported maintenance materials costs to the sum of the 

energy, chemical, and O&M labor costs for plants that operate FGD chemical precipitation 

and/or biological treatment systems. EPA then used the calculated value and multiplied it by the 

sum of the energy, chemical, and O&M labor costs to estimate the maintenance material costs 

for each plant.

Chemical purchase costs are the costs to purchase the chemicals required to operate the 

anoxic/anaerobic biological system and denitrification system (if applicable). EPA estimated the 

chemical purchase costs for the anoxic/anaerobic biological system 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 plant-specific FGD wastewater 

flow rate. EPA estimated chemical purchase costs for the denitrification system using unit cost 

and dosage information provided by the vendor, based on FGD wastewater flow rate.

Energy costs are the costs associated with the power requirement to run the 

anoxic/anaerobic biological system. Vendors provided equations to calculate power requirements 

per gallon of FGD wastewater for the anoxic/anaerobic biological system and the denitrification 

system. EPA calculated the annual anoxic/anaerobic biological system energy consumption

(kWh/yr) by multiplying the anoxic/anaerobic biological system energy requirement by the 

plant-specific FGD wastewater flow and backwash flow. EPA used a similar process to calculate 

the denitrification system energy requirement using the denitrification system energy 

consumption (kWh/yr) multiplied 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 (kWh/yr). EPA used the national 2010 energy cost of 4.05 cents 

per kWh to calculate the energy cost [U.S. DOE, 2011].

EPA estimated the O&M costs associated with compliance monitoring, transportation, 

disposal, and impoundment operations savings 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.

9.6.3 Evaporation

Section 7.1.4 describes the evaporation system that forms the basis for this technology 

option. The purpose of the 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. As described in 

Section 9.2.1, EPA estimated compliance costs for plants to treat FGD wastewater using 

chemical precipitation followed by evaporation but determined that the total industry cost would 

be too high to warrant further evaluation of this technology as a BAT option for existing sources 
Section 9—Engineering Costs

9-32

[ERG, 2015f]. The methodology used to estimate compliance costs associated with chemical 

precipitation followed by evaporation is described in detail in Section 6.3 of the Incremental 

Costs and Pollutant Removals for Final Effluent Limitations Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category [U.S. EPA, 2015a].

9.6.4 Estimated Industry-Level Costs for FGD Wastewater by Treatment Option

Table 9-5 presents the estimated capital and O&M costs on an industry level for each 

FGD wastewater treatment technology discussed in the sections above, including compliance 

monitoring, transport, disposal, and impoundment costs. The table also includes the number of 

plants incurring costs for each technology option. The costs presented in the table represent the 

compliance costs for those generating units facing more stringent requirements under the final 

rule than exist under the previously established regulations; therefore, oil-fired generating units 

and generating units with a capacity of 50 MW or less are not included because they do not need 

to meet any more stringent requirements than already existed under BPT regulations. See EPA’s 

Incremental Costs and Pollutant Removals for Final 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, 2015a]. Table 9-6 adjusts the results shown in Table 9-5, 

accounting for the expected closures related to the implementation of the CPP.

Table 9-5. 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 87 $888,000,000 $78,100,000 $7,420,000 ($20,500,000)

Chemical Precipitation 

followed by Biological 

Treatment

87 $1,790,000,000 $123,000,000 $7,420,000 ($20,500,000)

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].

a – The values in this column are negative, and presented in parenthesis, because they represent cost savings.
Section 9—Engineering Costs

9-33

Table 9-6. Estimated Industry-Level Costs for FGD Wastewater Based on Oil-Fired Units 

and Units 50 MW or Less Not Installing Technology Basis, Accounting for CPP

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 69 $775,000,000 $67,500,000 $5,890,000 ($16,100,000)

Chemical Precipitation 

followed by Biological 

Treatment

69 $1,510,000,000 $103,000,000 $5,890,000 ($16,100,000)

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].

a – The values in this column are negative, and presented in parenthesis, because they represent cost savings.

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 Steam Electric Survey responses, plants usually collect and handle fly ash and 

bottom ash separately. Fly ash is either handled dry and pneumatically transferred to silos for 

temporary 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. Based on 

information from vendors and industry site visits, bottom ash can also be collected under the 

boiler using a completely dry mechanical conveyor and conveyed 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 to convert 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 to dry vacuum fly ash handling systems for steam electric generating 

units producing and discharging fly ash transport water. Section 7.2.4 provides more details on 

the dry vacuum fly ash handling system.

EPA’s approach for estimating costs associated with converting to dry vacuum systems is 

described in more detail below. See Section 7 of the Incremental Costs and Pollutant Removals 
Section 9—Engineering Costs

9-34

for Final 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, 

2015a].

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 fly ash handling 

capabilities. Therefore, not all steam electric generating units are expected to incur complete 

conversion costs depending on the equipment and its capacity already operating at the plant. 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. In such cases, 

EPA estimated compliance costs associated with the additional intermediate storage (silo 

capacity) required. As appropriate, plants with wet and dry fly ash handling systems were given 

credit for having this equipment at the plant. 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.

• 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 fly ash from the 

conveyance lines and the unloading equipment necessary for moisture conditioning 

prior to transportation and disposal.109 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.

EPA also identified a specific subset of plants operating both dry and wet fly ash 

handling systems in the Steam Electric Survey; these plants indicated that redundant equipment 

would be required to discontinue the use of the wet fly ash handling system. EPA estimated the 

capital costs associated with the redundant equipment based on the type of dry fly ash handling 

system already installed at the plant (e.g., vacuum, pressure, or combined vacuum/pressure). 

EPA estimated capital, O&M, and 10-year recurring costs for converting to dry fly ash 

handling with a dry vacuum system using the equations provided below.110 EPA calculated the 

 109 Plants may have a silo but, they may need to install the equipment for moisture-conditioning fly ash prior to 

unloading. Therefore, the intermediate storage costs are based on two cost indicators, one of the silo and one for the 

pugmill.

110 For plants requiring redundant or back-up equipment, EPA estimated only capital compliance costs; EPA did not 

estimate O&M and recurring costs for these plants because the equipment installed is for back-up and is only
Section 9—Engineering Costs

9-35

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 to purchase all equipment to retrofit all 

generating units that collected 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 the conveyance system 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.

Direct capital costs incurred to install the dry vacuum fly ash handling system include 

purchased equipment installation and site preparation. Indirect capital costs (e.g., engineering, 

construction, and other contractor fee costs) incurred to install the dry vacuum fly ash handling 

system are the costs associated with preparing a specific site for the installation of the dry 

vacuum equipment and the costs required for supervising and inspecting the installation. EPA 

estimated direct capital costs associated with conveyance and intermediate storage for each plant 

using a direct capital cost factor determined from Steam Electric Survey, vendor, and other 

industry-submitted data. To estimate these costs, EPA applied the calculated factor to the 

purchased equipment cost. EPA estimated indirect capital costs as a percentage of the total direct 

capital costs (purchased equipment costs plus direct capital costs) based on information obtained 

from a publically available costing manual, Plant Design and Economics for Chemical 

Engineers [Peters and Timmerhaus, 1991]. See Section 7.1.5 of the Incremental Costs and 

Pollutant Removals for Final Effluent Limitations Guidelines and Standards for the Steam 

Electric Generating Point Source Category report for more details on methodology for 

estimating the indirect capital costs [U.S. EPA, 2015a].

EPA calculated the amount of moisture-conditioned fly ash generated from the handling 

conversion using the wet fly ash generation rate at the plant-level and an average moisture 

content of fly ash from the Steam Electric Survey data, supplemented with vendor data. EPA 

used the moisture-conditioned fly ash tonnage to estimate the disposal capital costs, described in 

Section 9.5.3.

 operated when the back-up wet-sluicing system would have operated. EPA determined that the O&M and recurring 

costs associated with the wet-sluicing system are comparable to the dry system. Therefore, the operation of the 

redundant or back-up equipment results in no incremental O&M costs [U.S. EPA, 2015a].

Total Capital Costs = Purchased Equipment Costs + Direct Capital Costs + Indirect 

Capital Costs + Fly Ash Disposal Costs
Section 9—Engineering Costs

9-36

O&M labor costs are the costs associated with operating and maintaining the conveyance, 

intermediate storage, and transport/disposal portions of the dry vacuum system. To calculate the 

labor rate for fly ash conversion costs, EPA used the Steam Electric Survey data, supplemented 

with U.S. Bureau of Labor Statistics data [U.S. Bureau of Labor Statistics, 2010]. EPA 

calculated conveyance 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 intermediate storage operating labor costs using the labor rate and the estimated 

number of operator hours per year. EPA calculated the maintenance labor costs using the labor 

rate and the estimated maintenance hours per year. Using data provided in the Steam Electric 

Survey, EPA estimated the number of required operator hours per day and maintenance hours 

per year. Additionally, EPA used the number of generating unit operating days in 2009 reported 

in 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.111 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 fly ash capital cost methodology based on fly ash tonnage. To estimate the fuel costs 

associated with the water trucks, EPA multiplied 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 (RIA) For EPA’s 2015 Coal Combustion Residuals (CCR) 

Final Rule [ORCR, 2014], based on the dry fly ash tonnage produced at the plant after the ash 

handling conversion. Vendor contacts provided the water truck’s fuel consumption. EPA 

assumed the same trip distance and fuel cost from the disposal technology cost methodology.

Maintenance materials costs are the costs associated with replacing equipment due to 

routine wear and tear. EPA used data from the Steam Electric Survey to determine conveyance 

and intermediate storage maintenance materials factors based on a comparison of maintenance 

material costs to the total O&M costs for conveyance and intermediate storage system elements, 

 111 For plants that already have some portion of dry fly ash handling, EPA included only additional costs for water 

trucks if the additional tonnage that would now be handled dry would likely lead the plant to purchase and operate 

additional water trucks. See Section 7.1.9 of the Incremental Costs and Pollutant Removals for Final Effluent 

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

details on the water truck methodology [U.S. EPA, 2015a].

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
Section 9—Engineering Costs

9-37

respectively. EPA calculated a median maintenance materials factor for each system element 

(i.e., conveyance, intermediate storage) and applied it to the calculated O&M costs.

Energy costs are the costs associated with the power requirement to run the dry vacuum 

system and intermediate storage. 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 (kWh/yr). EPA used the national 2010 energy cost of 4.05 cents per 

kWh to calculate the energy cost [U.S. DOE, 2011].

EPA estimated the O&M costs associated with transportation, disposal, and 

impoundment operations savings according to the methodologies described in Section 9.5. EPA 

used the same estimated tonnage described for the capital cost equation 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 10 years.

9.7.2 Bottom Ash Transport Water

EPA estimated capital, O&M, 3-year recurring, 5-year recurring, and 10-year recurring 

costs associated with converting bottom ash handling systems from wet sluicing to an MDS or 

remote MDS for generating units producing and discharging bottom ash transport water. EPA 

selected two systems, the 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 data. 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 Section 8 of the Incremental Costs and Pollutant Removals for Final 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, 2015a].

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 7.3.3 and 7.3.4.

Because EPA evaluated two technologies for bottom ash handling conversions, EPA 

estimated compliance costs for both technologies for each plant except where plant-specific data 

were available(e.g., public comments provided by plants show that an MDS could not be 

installed underneath the boiler due to space constraints). For these plants, EPA estimated only 

compliance costs associated with a remote MDS conversion. For all other plants, EPA selected 

Total 10-Year Recurring Costs = Cost of Water Truck
Section 9—Engineering Costs

9-38

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, 3-, 5-, and 10-year recurring costs for MDS and remote 

MDS conversions using the equations described later in this section. Because the MDS and 

remote MDS share similar system elements, EPA calculated the O&M costs for four 

components. 

• 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.

• Wet-Sluicing O&M Costs – Cost savings associated with the currently operating wetsluicing system.

Conveyance and intermediate storage equipment and direct capital costs are the costs 

associated with purchasing and installing a fully erected and commissioned MDS, including 

equipment, controls, foundations, and field labor. EPA estimated equipment and direct capital 

costs on a generating unit basis using a relationship between capital costs and generating unit 

capacity (MW). EPA obtained generating unit capacity information from the Steam Electric 

Survey data. Vendors provided the relationship between the equipment and direct capital costs 

and the generating unit 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 

generating unit level, EPA summed the capital costs to a plant level.

Indirect capital costs (e.g., engineering, construction, and other contractor fee costs) are 

the costs associated with preparing a specific site for the installation of the MDS equipment and 

the costs required for supervising and inspecting the installation. EPA estimated indirect capital 

costs as a percentage of the total direct capital costs (purchased equipment costs plus direct 

capital costs) based on information obtained from a publicly available costing manual, Plant 

Design and Economics for Chemical Engineers (Peters and Timmerhaus, 1991). See Section 

8.1.4 of the Incremental Costs and Pollutant Removals for Final Effluent Limitations Guidelines 

and Standards for the Steam Electric Generating Point Source Category report for more details 

on methodology for estimating the indirect capital costs [U.S. EPA, 2015a].

EPA calculated the amount of moisture-conditioned bottom ash generated from the 

moisture-conditioned bottom ash 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 

Total MDS Capital Costs = Conveyance and Intermediate Storage Equipment Costs + 

Direct Capital Costs + Indirect Capital Costs + Bottom Ash Disposal Costs
Section 9—Engineering Costs

9-39

data, supplemented with vendor data. EPA used the moisture-conditioned bottom ash tonnage to 

estimate the disposal costs, described in Section 9.5.3.

Conveyance and intermediate storage equipment and direct capital costs are the costs 

associated with purchasing and installing a fully erected and commissioned remote MDS, 

including equipment, controls, foundations, and field labor. EPA estimated equipment and direct 

costs on a generating-unit basis using a relationship between capital costs and generating unit 

capacity (MW). EPA obtained generating unit capacity from the Steam Electric Survey data. 

Vendors provided the relationship between the equipment and direct capital costs and the 

generating-unit capacity. The conveyance and intermediate storage costs provided for the remote 

MDS system include the costs for a semidry silo. After calculating the capital costs at the 

generating-unit level, EPA summed the capital costs to a plant level.

EPA also estimated equipment costs associated with a recycle pump and chemical feed 

system. Recycle pump costs are the costs associated with purchasing 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 purchasing a chemical feed system to adjust the pH of 

the bottom ash transport 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 and chemical feed system used in the FGD chemical 

precipitation cost methodology. See Section 6.1.6.2 of EPA’s Incremental Costs and Pollutant 

Removals for Final Effluent Limitation Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category report [U.S. EPA, 2015a]. 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 gpd, from the Steam Electric Survey data 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.

EPA estimated additional direct capital costs, including installation and site preparation, 

for the recycle pump and chemical feed system for the remote MDS. EPA estimated direct 

capital costs associated with this equipment for each plant using a direct capital cost factor 

determined from Steam Electric Survey, vendor, and other industry-submitted data. EPA 

estimated the other direct capital costs by applying the calculated factor to the recycle pump and 

chemical feed system purchased equipment cost.

Indirect and disposal capital costs are calculated using the same methodology described 

for the total MDS capital costs.

Total Remote MDS Capital Costs = Conveyance and Intermediate Storage Equipment 

Costs + Direct Capital Costs + Indirect Capital Costs + Bottom Ash Disposal Costs
Section 9—Engineering Costs

9-40

Conveyance O&M labor costs are the costs associated with operating and maintaining the 

conveyance portion of the bottom ash handling system. To calculate the labor rate for all system 

elements for the bottom ash conversion costs, EPA used the Steam Electric Survey data 

supplemented with U.S. Bureau of Labor Statistics data. The Agency 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. Operating and maintenance hours per 

year were calculated using data in the Steam Electric Survey.

Maintenance materials costs are the costs associated with replacing equipment due to 

routine wear and tear. EPA used data from the Steam Electric Survey to determine a maintenance 

materials factor based on a comparison of maintenance material costs 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 materials costs.

Energy costs are the costs associated with the power requirements for 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 (kWh/yr). EPA used the national 2010 energy cost of 4.05 cents per 

kWh 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 to estimate bottom ash 

transportation, disposal, and impoundment operation costs.

Chemical purchase costs are the costs to purchase chemicals to control pH levels for 

bottom ash sluice recirculation. To calculate chemical purchase costs, EPA estimated the 

hydrochloric acid (HCl) consumption, chemical purchase, and freight costs. EPA calculated the 

HCl consumption using wet-sluicing data and operating days in the Steam Electric Survey data. 

For more explanation regarding estimating chemical consumption, see Section 6.1.7.4 in EPA’s

Incremental Costs and Pollutant Removals for Final Effluent Limitation Guidelines and 

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

2015a].

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 

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

9-41

pump. EPA determined this additional energy consumption (kWh/yr) by calculating and 

summing the annual power consumption for these two pumps for each generating unit, and then 

summing these generating unit-level consumptions to calculate plant-level energy consumption. 

Pump energy consumption (kWh/yr) is a function of pump horsepower. EPA used the national 

2010 energy cost of 4.05 cents per kWh to calculate the energy cost [U.S. EPA, 2015a].

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.

Maintenance materials costs are the costs associated with replacing equipment due to 

routine wear and tear. EPA used data from the Steam Electric Survey to determine a maintenance 

materials factor based on a comparison of maintenance material costs to the total O&M costs for 

the intermediate storage portion of the bottom ash handling system. EPA applied the median 

maintenance materials cost factor to the total intermediate storage O&M costs to estimate the 

maintenance materials 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 (kWh/yr). EPA 

used the national 2010 energy cost of 4.05 cents per kWh to calculate the energy cost [U.S. EPA, 

2015a].

EPA estimated wet-sluicing O&M cost components to subtract them from the calculated 

costs to represent the incremental cost achieved by the MDS system. EPA is subtracting these 

O&M costs because the MDS system will no longer require the use of the wet-sluicing system 

after the system is installed. 

The sluicing O&M 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 

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
Section 9—Engineering Costs

9-42

elements for the wet-sluicing costs. EPA used industry responses from the Steam Electric Survey 

for wet-sluicing systems to calculate median operating worker hours per day for the conveyance 

portion of the system. To calculate the total O&M days per year, EPA used the number of 

generating unit operating days in 2009, reported in the Steam Electric Survey. 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 materials 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 materials costs to the total sum of 

operating labor, maintenance labor, energy, and other O&M costs. EPA applied the median 

maintenance materials cost factor to the total conveyance O&M costs to estimate the 

maintenance materials costs.

Wet-sluicing energy costs are the costs associated with power requirements for the wet 

bottom ash handling system. EPA used vendor supplied size and horsepower specifications 

pumps to calculate energy consumption (kWh/yr). EPA used the national 2010 energy cost of 

4.05 cents per kilowatt hour to calculate the energy cost [U.S. EPA, 2015a].

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 O&M 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 existing sluicing operations.

EPA calculated 3-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 3-year recurring cost by determining the cost 

and expected life of a drag chain for the MDS. Because the drag chain is located underneath the 

boiler, and more susceptible to large chunks of falling bottom ash, EPA determined that the 

Total MDS O&M Costs = Shared O&M Costs + Intermediate Storage O&M Costs –

Wet-Sluicing O&M Costs

Total Remote MDS O&M Costs = Shared O&M Costs + Additional Remote MDS 

O&M Costs + Intermediate Storage O&M Costs

Total 3-Year Recurring Costs = Cost of Mechanical Drag Chain for MDS
Section 9—Engineering Costs

9-43

expected life of a MDS drag chain is 3 years. The generating unit can continue to operate during 

the replacement of the drag chain components.

EPA calculated 5-year recurring costs associated with the drag chain for the remote MDS 

and rental tanks associated with remote MDS maintenance. The drag chain component for the 

remote MDS is the same as that described for the MDS. EPA calculated the 5-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 the boiler, and is less likely to 

be damaged by falling bottom ash, EPA determined that the expected life of a remote MDS drag 

chain is 5 years. The generating unit can continue to operate during the replacement of the drag 

chain components.

Based on vendor data, EPA determined that wear plates at the bottom ash remote MDS 

conveyance systems may need to be replaced every 5 years. EPA estimated 5-year costs 

associated with renting additional surge tank capacity so that the water in the remote MDS can 

be drained and stored during this maintenance, if necessary. These rental tank costs were 

estimated based on the bottom ash transport water volume estimated to be in the remote MDS 

and sluice pipeline. EPA estimated remote MDS volume based on a relationship, from vendor 

data, between design bottom ash tonnage and volume (in gallons). EPA estimated pipe volume 

based on a relationship, from vendor data, between generating unit capacity (in MW) and pipe 

diameter. EPA used bottom ash design tonnage and generating unit capacity from the Steam 

Electric Survey data. EPA used the distance to ponds reported in the Steam Electric Survey to 

estimate the length of sluice piping at the plant. The rental tank costs include the tanks, delivery 

costs, and hose, pump, and fitting rentals.

EPA also identified several plants that operate bottom ash wet-sluicing systems 

predominantly as closed-loop systems. These plants did not discharge bottom ash transport water 

in 2009. However, based on data in the Steam Electric Survey, EPA determined that these plants 

have the ability to discharge bottom ash transport water from emergency outfalls. Although these 

plants did not discharge bottom ash transport water in 2009, EPA still determined it may be 

appropriate to estimate a one-time cost associated with consulting an engineer to completely 

close the bottom ash recycle system, eliminating the potential for future discharges of bottom ash 

transport water. In addition, EPA estimated capital and O&M costs associated with a chemical 

feed system for all generating units at a plant currently operating wet-sluicing systems. EPA used 

the same equations as the remote MDS methodology to estimate capital and O&M costs 

associated with a chemical feed system for the plant. See Section 8.5 of EPA’s Incremental 

Costs and Pollutant Removals for Final Effluent Limitation Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category report [U.S. EPA, 2015a].

Total 5-Year Recurring Costs = Cost of Mechanical Drag Chain for Remote MDS + 

Cost of Rental Tank for Remote MDS Maintenance

Bottom Ash Management Costs = Engineering Consulting Cost + Total Capital 

Chemical Feed System Cost + Total O&M Chemical Feed System Cost
Section 9—Engineering Costs

9-44

9.7.3 Estimated Industry-Level Costs for Ash Handling Conversions

Table 9-7 presents the estimated capital, O&M, and recurring costs on an industry level 

associated with dry fly ash handling conversions. 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 facing more stringent requirements under the final rule than exist under 

the previously established regulations; therefore, oil-fired generating units and generating units 

with a capacity of 50 MW or less are not included because they do not to need meet any more 

stringent requirements than already exist under BPT regulations. See EPA’s Incremental Costs 

and Pollutant Removals for Final 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, 2015a]. Table 9-8 adjusts the results shown in Table 9-7, accounting for the expected 

closures related to the implementation of the CPP.

Table 9-7. 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) a

10-Year Recurring Cost

($/10-year) a

19 $180,000,000 ($720,000) ($4,300,000)

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].

a – The values in this column are negative, and presented in parenthesis, because they represent cost savings.

Table 9-8. Estimated Industry-Level Costs for Fly Ash Handling Conversions Based on 

Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis, Accounting for 

CPP

Number of Plants

Total Capital Cost

($)

Total O&M Cost

($/year) a

10-Year Recurring Cost

($/10-year) a

16 $135,000,000 ($573,000) ($3,300,000)

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].

a – The values in this column are negative, and presented in parenthesis, because they represent cost savings.

Table 9-9 presents the estimated capital, O&M, and recurring costs at an industry level 

associated with dry or closed-loop recycle bottom ash handling conversions. 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 facing more stringent requirements 

under the final rule than exist under the previously established regulations; therefore, oil-fired 

generating units and generating units with a capacity of 50 MW or less are not included because 

they do not need to meet any more stringent requirements than already exist under BPT 

regulations. See EPA’s Incremental Costs and Pollutant Removals for Final 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, 2015a]. Table 9-10 adjusts the results 

shown in Table 9-9, accounting for the expected closures related to the implementation of the 

CPP.
Section 9—Engineering Costs

9-45

Table 9-9. 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

141 $3,460,000,000 $203,000,000 $202,000 $3,680,000 $48,800,000 ($51,500,000)

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].

a – The values in this column are negative, and presented in parenthesis, because they represent cost savings.

Table 9-10. Estimated Industry-Level Costs for Bottom Ash Handling Conversions Based 

on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis, Accounting 

for CPP 

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

103 $2,520,000,000 $133,000,000 $179,000 $2,450,000 $32,000,000 ($38,300,000)

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].

a – The values in this column are negative, and presented in parenthesis, because they represent cost savings.

Under Regulatory Option C, EPA would have established zero discharge requirements 

for bottom ash transport water only for units greater than 400 MW. Therefore, EPA also 

estimated the industry-level costs for plants to convert only the generating units that are 400 MW 

or greater to dry or closed-loop recycle bottom ash handling. Table 9-11 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. Table 9-11 does not include costs for oil-fired 

generating units and generating units with a capacity of less than or equal to 400 MW because 

they would not need to meet any more stringent requirements than already existed under BPT 

regulations. Table 9-12 adjusts the results shown in Table 9-11, accounting for the expected 

closures related to the implementation of the CPP. 

Table 9-11. Estimated Industry-Level Costs for Bottom Ash Handling Conversions Based 

on Oil-Fired Units and Units Less than 400 MW 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

78 $2,290,000,000 $97,100,000 $112,000 $0 $24,300,000 ($29,400,000)

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].

a – The values in this column are negative, and presented in parenthesis, because they represent cost savings.
Section 9—Engineering Costs

9-46

Table 9-12. Estimated Industry-Level Costs for Bottom Ash Handling Conversions Based 

on Oil-Fired Units and Units Less than 400 MW Not Installing Technology Basis, 

Accounting for CPP 

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

61 $1,820,000,000 $77,600,000 $89,700 $0 $18,800,000 ($23,000,000)

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].

a – The values in this column are negative, and presented in parenthesis, because they represent cost savings.

9.8 COMBUSTION RESIDUAL LANDFILL LEACHATE

EPA estimated capital and O&M costs associated with installing and operating a 

chemical precipitation wastewater treatment system to treat combustion residual landfill 

leachate. Note that as described in Section 9.2.4, EPA determined that plants with combustion 

residual surface impoundment leachate will not incur costs associated with any final leachate 

requirements because plants will likely use a different approach than installing the technology 

basis to comply with requirements based on the chemical precipitation technology option. EPA 

calculated the cost for a stand-alone chemical precipitation system to treat the landfill leachate 

using the equations in Sections 9.6.1 associated with chemical precipitation treatment of FGD 

wastewater [ERG, 2015a].

Table 9-13 presents the estimated capital and O&M costs on an industry level associated 

with treating combustion residual landfill leachate. The table also includes the number of plants 

incurring compliance costs. The costs presented in the table represent the compliance costs for 

those plants facing more stringent requirements under the technology option e than exist under 

the previously established regulations; therefore, plants operating only oil-fired generating units 

and/or generating units with a capacity of 50 MW or less are not included because they do not 

need to meet any more stringent requirements than already existed under BPT regulations. See 

EPA’s Incremental Costs and Pollutant Removals for Final 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, 2015a]. Table 9-14 adjusts the results shown in Table 9-13, 

accounting for the expected closures related to the implementation of the CPP.

Table 9-13. Estimated Industry-Level Costs for the Chemical Precipitation Technology 

Option 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 82 $605,000,000 $34,300,000 $7,000,000 $0

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].
Section 9—Engineering Costs

9-47

Table 9-14. Estimated Industry-Level Costs for the Chemical Precipitation Technology 

Option for Combustion Residual Leachate Based on Oil-Fired Units and Units 50 MW or 

Less Not Installing Technology Basis, Accounting for CPP

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 60 $478,000,000 $28,600,000 $5,120,000 $0

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].

9.9 GASIFICATION WASTEWATER

EPA estimated capital and O&M costs associated with installing and operating an 

evaporation treatment system for gasification wastewater. As described in Section 7.6, EPA 

identified three plants currently operating IGCC generating units by 2014. All three of these 

plants operate the technology option selected as BAT, evaporation. Because these three plants 

already operate the BAT technology basis, EPA estimated a capital cost of zero. EPA estimated 

only costs associated with compliance monitoring described in Section 9.5

Table 9-15 presents the estimated capital and O&M costs on an industry level associated 

with treating gasification wastewater. The table also includes the number of plants incurring 

compliance costs. See EPA’s Incremental Costs and Pollutant Removals for Final 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, 2015a] Table 9-16 adjusts the 

results shown in Table 9-15, accounting for the expected closures related to the implementation 

of the CPP.

Table 9-15. Estimated Industry-Level Costs for Gasification Wastewater 

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)

Evaporation 3 $0 $192,000 $0 $0

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].

Table 9-16. Estimated Industry-Level Costs for Gasification Wastewater, Accounting for 

CPP

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)

Evaporation 2 $0 $128,000 $0 $0

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].
Section 9—Engineering Costs

9-48

9.10 SUMMARY OF NATIONAL ENGINEERING COSTS

As described in Section 8, EPA evaluated six main regulatory options comprised of 

various combinations of the technology options considered for control of each wastestream, as 

shown in Table 9-17. The Agency estimated the costs associated with steam electric power 

plants to achieve compliance with each of the main regulatory options. Table 9-18 summarizes 

the total estimated compliance costs (including capital costs, annual O&M costs, one-time costs, 

and recurring costs) associated with each regulatory option. See the Regulatory Impact Analysis 

for Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category (EPA-821-R-15-004) for a list 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 facing more stringent 

requirements under the final rule than exist under the previously established regulations; 

therefore, oil-fired generating units and generating units with a capacity of 50 MW or less are not 

included because they do not need to meet any more stringent requirements than already existed 

under BPT regulations. Under Regulatory Option C, generating units that discharge bottom ash 

transport water with a capacity of less than or equal to 400 MW are not included because they 

would not need to meet any more stringent requirements than already existed under BPT 

regulations. See EPA’s Incremental Costs and Pollutant Removals for Final 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, 2015a]. Table 9-19 adjusts the results 

shown in Table 9-18, accounting for the expected closures related to the implementation of the 

CPP.

Table 9-17. Technology Options and Other Costs Included in the Estimated Compliance 

Costs for Each Regulatory Option

Wastestream Technology Option

Regulatory Option

A B C D E F a

FGD Wastewater

Chemical Precipitation      

Biological Treatment    

Evaporation 

Fly Ash Transport Water Dry Fly Ash Handling      

Bottom Ash Transport Water Dry or Closed-loop Recycle Bottom

Ash Handling

 b   

Leachate Chemical Precipitation  

Gasification Wastewater Evaporation      

Flue Gas Mercury Control Wastes Dry Handling      
Section 9—Engineering Costs

9-49

Table 9-17. Technology Options and Other Costs Included in the Estimated Compliance 

Costs for Each Regulatory Option

Wastestream Technology Option

Regulatory Option

A B C D E F a

Other Costs Not Specific to Wastestream

Solids Transportation      

Solids Disposal      

Impoundment Operation      

Compliance Monitoring      

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

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

to impact the steam electric industry (see Section VIII.C.1 of the preamble). As a result, EPA chose not to conduct 

particular analyses for Option F to the same extent that it did for some of the other options considered.

b – Under Regulatory Option C, EPA would have established zero discharge requirements for bottom ash transport 

water only for units greater than 400 MW.

Table 9-18. 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 a

A 100 $1,069 $78 $0 $0 $0 $7 ($25)

B 100 $1,969 $123 $0 $0 $0 $7 ($25)

C 139 $4,258 $220 $0.1 $0 $24 $7 ($54)

D 181 $5,426 $326 $0.2 $4 $49 $7 ($76)

E 196 $6,031 $360 $0.2 $4 $49 $14 ($76)

a – The values in this column are negative, and presented in parenthesis, because they represent cost savings.

Table 9-19. Cost of Implementation by Regulatory Option [In millions of pre-tax 

2010 dollars] Accounting for CPP

Regulatory 

Option

Number of 

Plants

Capital 

Cost

Annual 

O&M Cost

One Time 

Costs

Recurring Costs

3-year 5-year 6-year 10-year a

A 79 $910 $67 $0 $0 $0 $6 ($19)

B 79 $1,640 $103 $0 $0 $0 $6 ($19)

C 108 $3,462 $180 $0.1 $0 $19 $6 ($42)

D 134 $4,161 $235 $0.2 $3 $32 $6 ($58)

E 145 $4,638 $264 $0.2 $3 $32 $11 ($58)

a – The values in this column are negative, and presented in parenthesis, because they represent cost savings.
Section 9—Engineering Costs

9-50

The compliance costs for each regulatory option presented in Table 9-18 and Table 9-19

exclude generating unit retirements, repowerings, and conversions that have been announced by 

companies and are scheduled to occur by the time the units would have to meet any new 

requirements, based on information obtained by EPA as of August 2014. But they do not reflect 

additional planned generating unit retirements, repowerings, and conversions that have been 

announced since August 2014, (see [ERG, 2015d], “Memorandum to the Steam Electric 

Rulemaking Record: Changes to Industry Profile for Steam Electric Generating Units for the 

Steam Electric Effluent Guidelines Final Rule”). EPA conducted a sensitivity analysis to 

determine how these additional changes in the Steam Electric industry would reduce the total 

annualized compliance costs for the rule. The results of this analysis are presented in the 

“Memorandum to the Steam Electric Rulemaking Record: Changes to Industry Profile for Steam 

Electric Generating Units for the Steam Electric Effluent Guidelines Final Rule.”

9.11 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 costs to meet NSPS or PSNS for new sources are those incremental costs to install and 

operate technology options compared to what a typical new source would do in absence of a 

requirement associated with a technology option.

The incremental costs associated with complying with the NSPS and PSNS options 

named for the final rule vary depending on the types of processes, wastestreams, and waste 

management systems that would have been installed in the absence of the new source 

requirements. EPA estimated capital and O&M costs for nine 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.

• Combustion residual leachate collection and handling.

Although EPA evaluated nine different scenarios based on various combinations of the 

elements discussed above, it determined that two of the scenarios best represent the conditions 

that would likely 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 9-20 identifies the plant 

and genearating unit characteristics that were used for these two scenarios. See the “Steam 

Electric NSPS Costs Methodology” [ERG, 2015e] for a description of the other scenarios 

evaluated as part of the NSPS analysis.
Section 9—Engineering Costs

9-51

Table 9-20. NSPS Compliance Cost Scenarios Evaluated for the Rule

Scenario Characteristics Existing Plant Greenfield Plant

Plant-Level 

Characteristics

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

New 

Generating 

Unit-Level 

Characteristics

Type of FGD System Wet FGD system 

(impoundments as treatment)

Wet FGD system 

(impoundments as treatment)

Bottom Ash Handling Mechanical drag system 

already planned

Mechanical drag system 

already planned

Fly Ash Handling a Dry Dry

Combustion Residual Leachate b No leachate collection in the 

landfill

Landfill leachate collected but 

not treated

NSPS Costs

FGD Yes Yes

Bottom Ash c No No

Fly Ash a No No

Combustion Residual Leachate No Yes

a – All scenarios assume dry fly ash handling because of the current NSPS regulations (40 CFR 423.15(g)).

b – 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 9-21 are more expensive for the 

greenfield plant than for the existing plant.

c – EPA assumed that all new units (at both new and existing plants) will install a MDS to handle bottom ash 

regardless of the ELGs based on information provided in the Steam Electric Survey. Additional information is 

provided in Section 6 of the “Steam Electric NSPS Costs Methodology” [ERG, 2015e].

EPA evaluated new source costs for FGD wastewater, bottom ash transport wastewater, 

and combustion residual leachate. Because the current Steam Electric NSPS already require zero 

discharge for fly ash transport wastewater, EPA did not calculate new source costs for fly ash 

transport water. Additionally, because the technology bases for gasification wastewater and 

FGMC wastewater are already standard industry practices, EPA did not calculate new source 

costs for these wastestreams.

Additionally, EPA determined that the majority of plants that install bottom ash handling 

systems in the last 20 years installed dry handling systems (approximately 80 percent). 

Therefore, EPA determined new source incremental compliance costs for dry bottom ash 

handling would be zero [ERG, 2015e].

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 9-21 presents the estimated capital and O&M costs for each 

regulatory option and each model plant size. The estimated incremental compliance costs for 

each of scenarios evaluated by EPA are included in the memorandum entitled “Steam Electric 

NSPS Costs Methodology.”
Section 9—Engineering Costs

9-52

Table 9-21. Estimated Industry-Level NSPS Costs

Regulatory 

Option

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

A a a a a a a

B 14,700,000 992,000 19,000,000 1,360,000 32,700,000 2,420,000

C 14,700,000 992,000 19,000,000 1,360,000 32,700,000 2,420,000

D 14,700,000 992,000 19,000,000 1,360,000 32,700,000 2,420,000

E b 20,000,000 1,200,000 25,000,000 1,600,000 39,000,000 2,800,000

F b 69,000,000 4,700,000 78,000,000 6,200,000 110,000,000 11,000,000

Existing Plant

A a a a a a a

B 14,700,000 992,000 19,000,000 1,360,000 32,700,000 2,420,000

C 14,700,000 992,000 19,000,000 1,360,000 32,700,000 2,420,000

D 14,700,000 992,000 19,000,000 1,360,000 32,700,000 2,420,000

E b 15,000,000 1,000,000 19,000,000 1,400,000 33,000,000 2,500,000

F b 64,000,000 4,500,000 73,000,000 5,900,000 100,000,000 10,000,000

Source: [ERG, 2015e].

Note: Costs are rounded to three significant figures.

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].

a – The NSPS costs for Regulatory Option A have been withheld to protect confidential business information.

b – The NSPS costs for Regulatory Options E and F have been rounded up to two significant figured to protect confidential business information.
Section 9—Engineering Costs

9-53

9.12 REFERENCES

1. ERG. 2015a. Eastern Research Group, Inc. CBI Final Steam Electric Technical 

Questionnaire Database (Steam Electric Survey). (30 September). DCN SE05903.

2. ERG. 2015b. Eastern Research Group, Inc. FGD & Ash Cost Model with and 

without CCR. (30 September). DCN SE05841. 

3. ERG. 2015c. Eastern Research Group, Inc. Leachate Cost Model. (30 September). 

SE05842. 

4. ERG. 2015d. Eastern Research Group, Inc. “Memorandum to Ron Jordon, EPA: 

Changes to Industry Profile for Steam Electric Generating Units for the Steam 

Electric Guidelines Final Rule.” (30 September). SE05069.

5. ERG. 2015e. Eastern Research Group, Inc. Memorandum to the Steam Electric 

Rulemaking Record: New Source Performance Standards (NSPS) Costing 

Memorandum. (30 September). DCN SE05844.

6. ERG. 2015f. Eastern Research Group, Inc. “Memorandum to the Steam Electric 

Rulemaking Record: Plant-Specific Compliance Cost Estimates for the Treatment of 

FGD Wastewater with Chemical Precipitation Followed by Evaporation.” (30 

September). SE05730. (30 September)

7. ORCR. 2014. U.S. Environmental Protection Agency, Office of Resource 

Conservation and Recovery. Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal 

Combustion Residals (CCR) Final Rule. Washington, D.C. (December).

8. Peters and Timmerhaus. 1991. Plant Design and Economics for Chemical 

Engineers. DCN SE05959.

9. RSMeans. 2015. Building Construction Cost Data, 69th Edition. DCN SE05848.

10. U.S. DOE. 2011. U.S. Department of Energy, Energy Information Administration 

(EIA). Electric Power Annual 2009. Washington, D.C. (January). DCN SE02023.

11. 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.

12. U.S. EPA. 1985. U.S. Environmental Protection Agency. Full-Scale Field 

Evaluation of Waste Disposal from Coal-fired Electric Generating Plants. (August). 

DCN SE02971. 

13. U.S. EPA. 2015a. U.S. Environmental Protection Agency. Incremental Costs and 

Pollutant Removals for Final Effluent Limitation Guidelines and Standards for the 

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

SE05831.

14. U.S. EPA. 2015b. U.S. Environmental Protection Agency. Statistical Support 

Document: Effluent Limitations for FGD Wastewater, Gasification Wastewater, and 

Combustion Residual Leachate for the Final Steam Electric Power Generating 

Effluent Limitations Guidelines and Standards. (30 September). SE05733. 
Section 10—Pollutant Loadings and Removals

10-1

SECTION 10

POLLUTANT LOADINGS AND REMOVALS

This section discusses annual pollutant loadings for the steam electric power generating 

industry and pollutant removal estimates associated with the final rule, as well as several other 

regulatory options. 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 technology option. These are 

also referred to as treated loadings. EPA calculated these loadings assuming that all 

steam electric power plants subject to the requirements would install and operate 

wastewater treatment and pollution prevention technologies equivalent to the 

technology bases for the regulatory options.

• Pollutant Removals. The difference between the baseline loadings and postcompliance loadings for each regulatory option.

Some aspects of the final effluent limitations guidelines and standards (ELGs) (e.g., 

applicability changes) will likely not lead to a change in pollutant loadings for complying plants. 

Other aspects of the ELGs will likely lead to a change in pollutant loadings for a subset of 

complying plants. These plants generally generate the wastestreams for which EPA is 

establishing new effluent limitations or standards. This section describes the detailed pollutant 

loadings evaluation EPA performed for these plants that are likely to reduce pollutant loadings 

associated with the ELGs, as well as other regulatory options named. Specifically, EPA 

determined baseline and post-compliance pollutant loadings for FGD wastewater, fly ash 

transport water, bottom ash transport water, combustion residual leachate (impoundment and 

landfill), gasification wastewater, and flue gas mercury control (FGMC) wastewater.

The currently operating gasification generating units use evaporation systems, which is 

the technology basis for the ELGs. Therefore, EPA determined that the gasification wastewater 

baseline loadings are equal to the post-compliance loadings. Similarly, plants currently manage 

their FGMC wastes so there is no pollutant discharge to surface waters and therefore the FGMC 

wastewater baseline and post-compliance loadings are also equal. The remainder of this section 

applies to FGD wastewater, fly ash transport water, bottom ash transport water, and combustion 

residual leachate.

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 discussed in Section 8. For example, for any plant discharging FGD 

wastewater, EPA calculated both a baseline loading and post-compliance loadings associated 

with two technology bases (i.e., chemical precipitation and chemical precipitation with biological 

treatment). EPA did not evaluate post-compliance loadings associated with chemical 
Section 10—Pollutant Loadings and Removals

10-2

precipitation followed by evaporation because EPA decided not to base the control of pollutants 

in FGD wastewater for existing sources on this technology due to the high cost.112 On a plantlevel 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, 

the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric 

Survey), public comment, industry-submitted data, and 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 Steam Electric Survey or industry-submitted data to determine the plant’s discharge flow 

rate. In cases where these data were insufficient, EPA developed a methodology for estimating 

flow rates. As discussed in Section 9.4.1, EPA also adjusted the baseline, specifically the plantspecific discharge flow rates for the pollutant loading estimates, to account for announced plans 

to retire a generating unit or alter operations that would eliminate the discharge of an applicable 

wastestream.113 The Agency also adjusted for other rulemakings, including the coal combustion 

residual (CCR) rule and the Clean Power Plan (CPP). Section 10.3 provides details on these 

wastewater flow rates.

EPA calculated baseline pollutant loadings and post-compliance 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

day � × Discharge days �

days

year� × Concpollutant �

ug

L � ×

�

2.20462 lb

109 ug � × � 1000 L

264.17 gallons�

Where:

Loadingpollutant = The loadings from a specific pollutant discharged directly to 

surface water, in pounds per year.

 112 EPA did evaluate characterization data for chemical precipitation followed by evaporation in order to estimate 

pollutant loadings associated with those steam electric power plants currently operating this type of treatment for 

FGD wastewater as part of baseline loadings.

113 EPA determined that there would be no baseline pollutant loadings and no associated pollutants removals 

attributable to the ELGs for steam electric generating units that have announced plans to retire, convert to a noncoal 

fuel source, or change/upgrade ash handling practices by the time that the steam electric generating units have to 

meet the ELGs. See the Changes to Industry Profile for Steam Electric Generating Units for the Steam Electric 

Effluent Guidelines Final Rule [ERG, 2015c] for a list of the plants and generating units that were identified as 

retiring, converting to a noncoal fuel, or changing/upgrading ash handling practices.
Section 10—Pollutant Loadings and Removals

10-3

FlowRate = The flow rate of the wastestream being discharged, in gallons per 

day.

Discharge Days = The number of days per year wastewater is discharged.

Concpollutant = The average concentration of a specific pollutant present in the 

wastestream, in micrograms 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 pollutant of 

concern (POC), identified by wastestream in Section 6.6, Table 10-1 provides the percent 

removals expected from well-operated POTWs as reported in the “Memorandum to the 2006 

Effluent Guidelines Program Plan Docket” [ERG, 2005]. For any plant identified as discharging 

a wastestream to a POTW, EPA used the calculated baseline loadings (or post-compliance 

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. 

A list of the TWFs used for this rulemaking can be found in EPA’s memorandum “Review of 

Toxic Weighting Factors in Support of the Final Steam Electric Effluent Limitations Guidelines 

and Standards” [ERG, 2015e]. 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 pollutant-specific TWF to derive a “toxic-equivalent” loading (lbequivalent/yr), or TWPE.114 Section 10.4 discusses the wastestream mass loading (i.e., 

unweighted loadings) and TWPE loadings in more detail.

 114 If the wastestream was 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

Aluminum 91.0%

Ammonia 39.0%

Antimony 66.8%

Arsenic 65.8%

Barium 55.2%

Beryllium 61.2%

Biochemical Oxygen Demand NA

Boron NA

Cadmium 90.1%

Calcium NA

Chemical Oxygen Demand NA

Chloride NA

Chromium 80.3%

Hexavalent Chromium 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
Section 10—Pollutant Loadings and Removals

10-5

Table 10-1. POTW Removals

Analyte Median POTW Removal Percentage

Vanadium 8.3%

Zinc 79.1%

Source: Memorandum 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’s loadings calculations generally build off the POC analysis 

described in Section 6.6; pollutant loadings are only evaluated for those pollutants identified as 

POCs for a specific wastestream.115 EPA used a variety of data sources to generate 

characterization data for the POCs in each evaluated wastestream. EPA used similar data 

collection criteria for data used in loadings calculations as was used for the data to determine 

POCs, the only difference being that data used for loadings represents treated effluent 

wastewater while POC data generally used untreated wastewater data. EPA subjected treated 

effluent data for pollutant loadings to the data quality review criteria for sampling data, Steam 

Electric Survey data, and secondary data, as described in “Development Memorandum for Steam 

Electric Analytical Database for the Final Rule” [ERG, 2015d]. EPA reviewed each data source 

to determine if the data met EPA’s criteria for use in characterizing treated effluent. The 

following general criteria applied across all wastestreams: 

• Sample results must contain sufficient information (i.e., contain method detection 

limits or quantitation limits, provide units).

• Sample locations must be unambiguous and clearly described such that it can be 

categorized by type (e.g., bottom ash pond effluent rather than pond effluent with no 

further definition) and level of treatment.

• Sample must be representative of typical full-scale plant operations (e.g., not a 

simulated sample of partially treated wastewater).

• Sample analysis must be completed using accepted analytical methods for untreated 

wastewater.

• Data must not be duplicative of other accepted data. Where duplicate data exists (e.g., 

submitted by a trade association representing individual plants and also submitted by 

the individual plant), EPA used only accepted data collected from the individual 

plant. 

• For biphasic samples (i.e., those with solids content greater than 1 percent), sample 

analysis must provide results for both phases.

 115 EPA also calculates pollutant loadings for combined ash impoundment effluent, as described in Section 10.2.2. In 

this case, the pollutant loadings were not based on the POC analysis, because there are no data available on 

combined ash transport water outside of impoundment data. In this situation, EPA used all pollutants detected to 

calculate pollutant loadings associated with combined ash impoundments.
Section 10—Pollutant Loadings and Removals

10-6

The following subsections discuss the data used to characterize each of the regulated 

wastestreams, and where relevant, any additional data editing criteria EPA applied to develop the 

data set used for the analysis. EPA generated a separate set of characterization data for baseline 

and each post-compliance technology basis. Sections 10.2.1 through 10.2.3 present the data 

sources and characterization for FGD wastewater, ash transport water, and combustion residual 

leachate, respectively, and any additional data quality criteria used for each individual 

wastestream.

10.2.1 FGD Wastewater Characterization

EPA evaluated effluent data for chemical precipitation, chemical precipitation with 

biological treatment, and chemical precipitation with evaporation to characterize the baseline 

discharges for plants discharging FGD wastewater. Table 10-2 summarizes the data sources that 

met data quality criteria and EPA included in the baseline and post-compliance FGD loadings 

analysis. EPA reviewed all available effluent data from the sources listed in Table 10-2 and 

excluded data that were not usable for developing effluent characterization data for the following 

reasons: 

• Data from commissioning or decomissioning periods.

• Data collected during periods of atypical operation, as identified by the plant.

• Data collected using analytical methods not sufficiently sensitive.116

See Analytical Database Development for the Final Steam Effluent Guidelines (ELG) 

Rule [ERG, 2015f] for more detail on data exclusions and data quality criteria specific to FGD 

wastewater.

Additionally, 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 calculations117:

• 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 

 116 For data used for calculating pollutant loadings and effluent limits for the steam electric effluent guidelines, a 

sufficiently sensitive reporting limit (or a sufficiently sensitive analytical method) means that the analytical method 

is capable of and was used in a manner that most analytical results were above the level of quantitation. In instances 

where most analytical results were below the level of quantitation, sufficiently sensitive means that EPA is not 

aware of any other method approved in 40 CFR Part 136 that can produce substantially lower reporting limits for 

analyses of FGD wastewater.

117 Only in EPA sampling activities were field blank and duplicate samples collected and analyzed. EPA’s Clean 

Water Act (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

10-7

limit for all analytes. J-values, although the laboratory’s best estimate of the pollutant 

concentration, are measurements made below the lowest point on the initial 

calibration curve (i.e., quantitation limit) and thus have greater uncertainty associated 

with their quantitation therefore EPA handled them as half the quanititation limit 

rather than as zero or at the full quanititation limit.

• 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. EPA used field blank results measured above the quantitation limit 

for this analysis (i.e., did not use J-values associated with field blank samples). 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.

- If the sample result was greater than 10 times the field blank result, then the 

sample result was unchanged.

• Duplicate Sample Results: EPA averaged the results from each duplicate sample with 

the results of its original sample. EPA made the following assumptions when 

averaging the duplicate results:

- If one value was quantified and the other value was not measured 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.

- EPA used both qualified and unqualified data 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

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

and FGD purge a

EPA CWA 308 sampling Chemical precipitation effluent

Monitoring data provided by plant Chemical precipitation effluent

RRI Energy’s Keystone Generating 

Station (Keystone)

EPA sampling Chemical precipitation effluent

and FGD purge a

EPA CWA 308 sampling Chemical precipitation effluent

Monitoring data provided by plant Chemical precipitation effluent

Allegheny Energy’s Hatfield’s Ferry 

Electric Plant (Hatfield’s Ferry)

EPA sampling Chemical precipitation effluent

and FGD purge a
Section 10—Pollutant Loadings and Removals

10-8

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

Plant Name Source of Data Set

Wastestreams Represented 

in Data Set

EPA CWA 308 sampling Chemical precipitation effluent

Monitoring data provided by plant Chemical precipitation effluent

NRG Energy’s Dickerson Generating 

Station (Dickerson)

EPA sampling FGD purge a

We Energies’ Pleasant Prairie Power 

Plant (Pleasant Prairie)

EPA sampling Chemical precipitation effluent

and FGD purge a

EPA CWA 308 sampling Chemical precipitation effluent

Monitoring data provided by plant Chemical precipitation effluent

Duke Energy Carolinas’ Belews Creek

Steam Station (Belews Creek)

EPA sampling Biological treatment effluent and 

FGD purge a

EPA CWA 308 sampling Biological treatment effluent

Monitoring data provided by plant Biological treatment effluent and 

FGD purge a

Duke Energy Carolinas’ Allen Steam 

Station (Allen)

EPA sampling Biological treatment effluent and 

FGD purge a

EPA CWA 308 sampling Biological treatment effluent

Monitoring data provided by plant Biological treatment effluent and 

FGD purge a

Enel’s Federico II Power Plant 

(Brindisi)

EPA sampling Evaporation effluent

a – EPA used FGD purge data to estimate settling impoundment effluent concentrations. See Section 10.2.1.1 for 

details on the methodology used to estimate these concentrations.

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 88 plants118 that operate wet FGD systems and 

discharge FGD wastewater. For the FGD dischargers, EPA calculated baseline loadings by 

assigning pollutant concentrations based on the type of treatment system currently in place at the 

plant. EPA assigned treatment in place for this wastewater to one of four classes of treatment: 

surface impoundment, chemical precipitation, biological treatment, and evaporation. As 

discussed in Section 9, EPA used Steam Electric Survey data to determine the baseline FGD 

 118 EPA estimated compliance costs associated with control of FGD wastewater for 87 plants. One plant operates 

only oil-fired generating units and/or units with a generating capacity of 50 MW or less; therefore, plant is subject to 

BAT limitations that are equal to existing BPT requirements. As such, EPA assumed that this plant will not need to 

install the technology basis and, therefore, will not incur compliance costs. Additionally, EPA assumed that this 

plant will continue to discharge FGD wastewater at its current baseline level and will not achieve any pollutant 

removals for the technology options evaluated.
Section 10—Pollutant Loadings and Removals

10-9

wastewater treatment in place. Based on Steam Electric Survey responses, EPA categorized 51 

plants as operating a treatment system more advanced than a surface impoundment119:

• Forty-five plants operate a chemical precipitation system.

• Four plants operate a biological treatment system.

• Two plants operate an evaporation system.

EPA categorized all plants not operating one of these three types of treatment systems as 

operating 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). These types of system are effective at 

removing solids and metals in the particulate phase, but do not remove 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 pollutants in the wastewater. EPA obtained surface impoundment effluent data from a 

steam electric power plant that treats only FGD wastewater in the impoundment. In addition, 

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.120 EPA 

calculated proxy values using the untreated FGD wastewater data to represent impoundment 

effluent concentrations for each analyte using the data for each of these seven EPA sampled 

plants. 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 surface impoundments treating FGD wastewater based on the 

eight plants. 

For pollutants not included in the surface impoundment effluent characterization data but 

in the effluent characterization data for the chemical precipitation technology option, EPA 

transferred the concentrations for these pollutants from the chemical precipitation effluent to the 

surface impoundment effluent (see Section 10.2.1.2). EPA determined that because ammonia, 

biological oxygen demand (BOD), chemical oxygen demand (COD), hexavalent chromium, 

cyanide, nitrate/nitrite, total Kjeldahl nitrogen, and total phosphorus are present in the chemical 

 119 EPA’s categorization of FGD treatment presented here takes into account expected plant operation changes 

resulting from the CCR rule (see Section 9 regarding EPA’s methodology for incorporating these types of changes).

EPA identified 41 plants currently operating a treatment system more advanced than a surface impoundment. An 

additional 10 plants are expected to upgrade FGD wastewater treatment systems as a result of the CCR rule. 120 The methodology used to estimate settling impoundment effluent concentrations is presented in detail in the 

Incremental Costs and Pollutant Removals for Final Effluent Limitation Guidelines and Standards for the Steam 

Electric Generating Point Source Category report [U.S. EPA, 2015].
Section 10—Pollutant Loadings and Removals

10-10

precipitation effluent, they are also present in the untreated FGD wastewater. Therefore, they 

would also be present in the surface impoundment effluent. This assumption results in zero 

pollutant removals for these pollutants for the chemical precipitation technology option. Table 

10-3 presents the average characterization data used to calculate baseline loadings for plants 

currently treating FGD wastewater in a surface impoundment prior to discharge.

Approximately 60 percent of plants discharging FGD wastewater use a more advanced 

treatment system than surface impoundments. For those plants currently operating a chemical 

precipitation system or biological treatment system, EPA used the concentration data sets 

associated with the applicable post-compliance technology option to calculate baseline loadings. 

EPA also calculated a concentration data set for evaporation effluent to characterize loadings for 

plants currently operating these types of treatment systems. Section 10.2.1.2 discusses the 

characterization of chemical precipitation systems. Sections 10.2.1.3 and 10.2.1.4 discuss the 

characterization of chemical precipitation systems with biological treatment or with evaporation 

systems, respectively.

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

Analyte Unit Average Concentration

Classicals

Ammonia ug/L 6,850

Nitrate Nitrite as N ug/L 96,000

Nitrogen, Kjeldahl ug/L 32,900

Biochemical Oxygen Demand ug/L 2,220

Chemical Oxygen Demand ug/L 404,000

Chloride ug/L 7,120,000

Sulfate ug/L 1,240,000

Cyanide, Total ug/L 949

Total Dissolved Solids ug/L 32,500,000

Total Suspended Solids ug/L 27,900

Phosphorus, Total ug/L 319

Total Metals, Metalloids, and Other Nonmetals

Aluminum ug/L 2,080

Antimony ug/L 12.9

Arsenic ug/L 7.59

Barium ug/L 303

Beryllium ug/L 1.92

Boron ug/L 243,000

Cadmium ug/L 113

Calcium ug/L 2,050,000

Chromium ug/L 17.8

Hexavalent Chromium ug/L 5.22
Section 10—Pollutant Loadings and Removals

10-11

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

Analyte Unit Average Concentration

Cobalt ug/L 183

Copper ug/L 21.8

Iron ug/L 1,510

Lead ug/L 4.66

Magnesium ug/L 3,370,000

Manganese ug/L 93,400

Mercury ug/L 7.78

Molybdenum ug/L 125

Nickel ug/L 878

Selenium ug/L 1,170

Silver ug/L 0.925

Sodium ug/L 276,000

Thallium ug/L 13.7

Tin ug/L 100

Titanium ug/L 27.1

Vanadium ug/L 16.4

Zinc ug/L 1,390

Source: [ERG, 2012a – 2012i; NCDENR, 2011].

Note: Concentrations are rounded to three significant figures.

10.2.1.2 Baseline and Post-Compliance Chemical Precipitation Pollutant 

Characterization

As part of the sampling activities described in Section 3, EPA identified and collected 

data from eight plants operating chemical precipitation systems, sometimes in conjunction with 

other technologies, such as biological treatment. The specific operating characteristics of the 

chemical precipitation treatment systems varied. EPA conducted an engineering review of the 

data and identified four systems operating consistently with the chemical precipitation 

technology basis. These four plants, Hatfield’s Ferry, Miami Fort, Keystone, and Pleasant 

Prairie, operate chemical precipitation systems that include hydroxide and sulfide precipitation, 

as well as iron coprecipitation. These four plants burn a variety of coal types with two plants 

burning only bituminous coal, one plant burning only subbituminous coal, and the remaining 

plant using a combination of bituminous and subbituminous coals. EPA determined from the 

engineering review of the data for the remaining five plants, Allen, Belew’s Creek, Dickerson, 

Brindisi, and A2A’s Centrale di Monfalcone (Monfalcone), that these plants should not be 

considered in the evaluation of the chemical precipitation characteristics because they do not 

operate consistently with the technology basis.

The treatment systems at these four plants operating consistently with the chemical 

precipitation technology basis have similar operations; however, the plants have varying 
Section 10—Pollutant Loadings and Removals

10-12

configurations and operating characteristics, such as thickeners, filter presses, sand filters, and 

retention time. Each of these systems was designed and is operated to remove suspended solids 

and dissolved metals from the FGD wastewater to achieve a similar level of pollutant discharge. 

The systems are sized to handle a specific flow rate of FGD wastewater, which means that the 

sizes of the tanks were designed to allow for the residence time required for settling and/or 

reactions to occur to achieve effluent concentrations meeting the plants’ permit limits.

Chemical precipitation effluent characterization data came from multiple data sources, 

including EPA sampling, CWA 308 monitoring, and plant self-monitoring data. These data vary 

between daily, weekly, and monthly results and the number of results for each analyte is not 

consistent. Samples may have also been collected on the same day as EPA’s sampling and CWA 

308 monitoring activities (i.e., duplicate samples may exist across multiple data sources). 

Therefore, EPA calculated the average effluent concentrations for chemical precipitation using 

the following approach to account for variability:

1. Treat all samples collected during any of the four EPA sampling dates as a duplicate 

result. Calculate daily averages for samples on these dates and then calculate a fourday average. EPA is treating the four-day average as an equivalent weekly result. 

2. Calculate the average effluent concentration as an average of the four-day average 

and the remaining sample concentrations.

EPA analyzed the pollutant-specific treatment effectiveness of the chemical precipitation 

treatment technology. In this analysis, EPA reviewed pollutant concentrations at the influent to 

the chemical precipitation system (i.e., FGD purge wastewater) using data from the four plants 

operating this technology basis, Hatfield’s Ferry, Miami Fort, Keystone, and Pleasant Prairie. To 

ensure that the treatment effectiveness could be evaluated, EPA performed an analysis to identify 

pollutants present at treatable levels based on an evaluation of untreated FGD wastewater.121

Where specific pollutants were identified at treatable levels, EPA calculated plant-specific 

percent removals across the chemical precipitation system and evaluated whether the pollutant 

was treated with the treatment technology. For those pollutants identified as treated, EPA used 

the pollutant-specific chemical precipitation effluent concentration for pollutant loadings 

calculations. For those pollutants not identified at treatable levels or not identified as treated, 

EPA used the surface impoundment effluent concentration (see Table 10-3). The Incremental 

Costs and Pollutant Removals for Final Effluent Limitation Guidelines and Standards for the 

Steam Electric Generating Point Source Category report [U.S. EPA, 2015] describes in more 

detail the methodology to develop the chemical precipitation effluent concentrations used for 

pollutant loadings.

Table 10-4 presents the average chemical precipitation effluent concentrations and the 

concentration basis, either surface impoundment or chemical precipitation effluent. EPA used 

these average concentrations to calculate the post-compliance loadings that plants that currently 

operate surface impoundments would discharge if they were to install the chemical precipitation 

technology. EPA also used the average concentrations presented in Table 10-4 to calculate the 

 121 Because the influent to the chemical precipitation system is untreated FGD wastewater, the analysis to identify 

pollutants at treatable levels is identical to the pollutants of concern analysis described in Section 6, however; this 

analysis is only done for the four plants operating the chemical precipitation technology basis.
Section 10—Pollutant Loadings and Removals

10-13

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 four 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 41 other plants as operating chemical precipitations systems. 

However, these 41 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 41 plants, 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. EPA does not have 

sufficient data to characterize the discharges from these 41 plants. The pollutant loadings from 

these plants would be somewhere between the chemical precipitation loadings and the 

impoundment effluent loadings, but EPA could not determine the appropriate concentrations to 

use to estimate loadings. Therefore, as a conservative estimate, EPA assumed the pollutant 

loadings were equivalent to the chemical precipitation effluent loadings.

Table 10-4. Average Effluent Pollutant Concentrations for Chemical Precipitation System

Analyte Unit Average Concentration Concentration Basis

Classicals

Ammonia ug/L 6,850 Chemical Precipitation Effluent

Nitrate Nitrite as N ug/L 96,000 Chemical Precipitation Effluent

Nitrogen, Kjeldahl ug/L 32,900 Chemical Precipitation Effluent

Biochemical Oxygen Demand ug/L 2,220 Chemical Precipitation Effluent

Chemical Oxygen Demand ug/L 404,000 Chemical Precipitation Effluent

Chloride ug/L 7,120,000 Surface Impoundment

Sulfate ug/L 1,240,000 Surface Impoundment

Cyanide, Total ug/L 949 Chemical Precipitation Effluent

Total Dissolved Solids ug/L 24,100,000 Chemical Precipitation Effluent

Total Suspended Solids ug/L 8,590 Chemical Precipitation Effluent

Phosphorus, Total ug/L 319 Chemical Precipitation Effluent

Total Metals, Metalloids, and Other Nonmetals

Aluminum ug/L 120 Chemical Precipitation Effluent

Antimony ug/L 4.25 Chemical Precipitation Effluent

Arsenic ug/L 5.83 Chemical Precipitation Effluent

Barium ug/L 140 Chemical Precipitation Effluent

Beryllium ug/L 1.34 Chemical Precipitation Effluent

Boron ug/L 225,000 Chemical Precipitation Effluent

Cadmium ug/L 4.21 Chemical Precipitation Effluent

Calcium ug/L 1,920,000 Chemical Precipitation Effluent
Section 10—Pollutant Loadings and Removals

10-14

Table 10-4. Average Effluent Pollutant Concentrations for Chemical Precipitation System

Analyte Unit Average Concentration Concentration Basis

Chromium ug/L 6.45 Chemical Precipitation Effluent

Hexavalent Chromium ug/L 5.22 Chemical Precipitation Effluent

Cobalt ug/L 9.30 Chemical Precipitation Effluent

Copper ug/L 3.78 Chemical Precipitation Effluent

Iron ug/L 110 Chemical Precipitation Effluent

Lead ug/L 3.39 Chemical Precipitation Effluent

Magnesium ug/L 3,370,000 Surface Impoundment

Manganese ug/L 12,500 Chemical Precipitation Effluent

Mercury ug/L 0.139 Chemical Precipitation Effluent

Molybdenum ug/L 125 Surface Impoundment

Nickel ug/L 9.11 Chemical Precipitation Effluent

Selenium ug/L 928 Chemical Precipitation Effluent

Silver ug/L 0.925 Surface Impoundment

Sodium ug/L 276,000 Surface Impoundment

Thallium ug/L 9.81 Chemical Precipitation Effluent

Tin ug/L 100 Surface Impoundment

Titanium ug/L 9.30 Chemical Precipitation Effluent

Vanadium ug/L 12.6 Chemical Precipitation Effluent

Zinc ug/L 20.0 Chemical Precipitation Effluent

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 Chemical Precipitation with Biological Treatment 

Characterization

EPA identified and collected data from two plants, Allen and Belews Creek, operating 

chemical precipitation systems in conjunction with biological treatment systems that represent 

the well-operated biological treatment systems that form the technology basis for the final rule. 

After conducting an engineering review of the data, EPA determined that both plants operate 

systems consistent with the chemical precipitation with biological treatment technology option. 

Both plants operate chemical precipitation systems followed by anoxic/anaerobic biological 

treatment systems specifically designed for selenium removal. EPA used the data from these 

plants to represent treatment performance of a chemical precipitation system with biological 

treatment system; however, these plants do not fully represent the technology option because 

neither plant currently uses sulfide precipitation within their chemical precipitation system. 

Therefore, these plants likely do not demonstrate mercury (and other metals) effluent 

concentrations as low as could be achieved by the chemical precipitation (with sulfide 

precipitation) followed by a biological treatment system that forms the basis for the final rule 

(see Section 7 for a complete description of the technology). EPA also collected data from a third 

plant, Dickerson, operating chemical precipitation followed by biological treatment. EPA did not 
Section 10—Pollutant Loadings and Removals

10-15

include data from Dickerson because the biological treatment technology it operates is a 

sequencing batch reactor that is not designed to target selenium removal and is therefore not 

consistent with the technology basis for biological treatment.

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. These data vary between daily, weekly, and monthly results and the number of 

results for each analyte is not consistent. Samples may have also been collected on the same day 

as EPA’s sampling and CWA 308 monitoring activities (i.e., duplicate samples may exist across 

multiple data sources). Therefore, EPA calculated the average effluent concentrations for 

chemical precipitation and biological treatment using the following approach to account for 

variability:

1. Treat all samples collected during any of the four EPA sampling dates as a duplicate 

result. Calculate daily averages for samples on these dates and then calculate a fourday average. EPA is treating the four-day average as an equivalent weekly result. 

2. Calculate the average effluent concentration as an average of the four-day average 

and the remaining sample concentrations.

EPA analyzed the pollutant-specific treatment effectiveness of the biological treatment 

technology. In this analysis, EPA reviewed pollutant concentrations at the influent to the 

biological treatment system (i.e., chemical precipitation effluent) using data from the two plants 

operating this technology basis, Allen and Belews Creek. To ensure that the treatment 

effectiveness could be evaluated, EPA identified pollutants present at treatable levels based on an 

evaluation of untreated and partially treated FGD wastewater. Where specific pollutants were 

identified at treatable levels, EPA calculated plant-specific percent removals across the 

biological treatment system and evaluated whether the pollutant was treated with the treatment 

technology. For those pollutants identified as treated, EPA used the pollutant-specific biological 

treatment effluent concentration for pollutant loadings calculations. For those pollutants not 

identified at treatable levels, or not identified as treated, EPA used the chemical precipitation 

effluent concentration (see Table 10-4). The Incremental Costs and Pollutant Removals for Final 

Effluent Limitation Guidelines and Standards for the Steam Electric Generating Point Source 

Category report [U.S. EPA, 2015] describes in more detail the methodology used to develop the 

biological treatment effluent concentrations used for pollutant loadings.

Table 10-5 presents the average biological treatment effluent concentrations and the 

concentration basis, surface impoundment, chemical precipitation effluent, or biological 

treatment effluent. EPA used these average concentrations to calculate the post-compliance 

loadings that would be discharged by plants currently operating surface impoundments or 

chemical precipitation systems if they were to install all components of the biological technology 

option. EPA also used the average 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 biological treatment system technology basis, presented in Table 

10-5, is based on two plants identified as operating consistently with the technology basis. As 
Section 10—Pollutant Loadings and Removals

10-16

discussed in Section 10.2.1.1, EPA classified four plants as operating biological treatment 

systems. For each plant classified as a baseline biological treatment system, EPA calculated the 

baseline loadings using the average concentration presented in Table 10-5. One of these plants 

does not operate consistently with the technology basis and likely discharges greater pollutant 

concentrations than the system reflecting the technology basis.122 Further, for this plant, the 

baseline and post-compliance loadings are identical and show no additional removals even 

though this plant is being assessed compliance costs to upgrade the system to achieve the 

technology basis.

Table 10-5. Average Effluent Pollutant Concentrations for Chemical Precipitation System 

with Biological Treatment

Analyte Unit Average Concentration Concentration Basis

Classicals

Ammonia ug/L 6,850 Chemical Precipitation Effluent

Nitrate Nitrite as N ug/L 647 Biological Treatment Effluent

Nitrogen, Kjeldahl ug/L 32,900 Chemical Precipitation Effluent

Biochemical Oxygen Demand ug/L 2,220 Chemical Precipitation Effluent

Chemical Oxygen Demand ug/L 404,000 Chemical Precipitation Effluent

Chloride ug/L 7,120,000 Surface Impoundment

Sulfate ug/L 1,240,000 Surface Impoundment

Cyanide, Total ug/L 949 Chemical Precipitation Effluent

Total Dissolved Solids ug/L 24,100,000 Chemical Precipitation Effluent

Total Suspended Solids ug/L 8,590 Chemical Precipitation Effluent

Phosphorus, Total ug/L 319 Chemical Precipitation Effluent

Total Metals, Metalloids, and Other Nonmetals

Aluminum ug/L 120 Chemical Precipitation Effluent

Antimony ug/L 4.25 Chemical Precipitation Effluent

Arsenic ug/L 5.83 Chemical Precipitation Effluent

Barium ug/L 140 Chemical Precipitation Effluent

Beryllium ug/L 1.34 Chemical Precipitation Effluent

Boron ug/L 225,000 Chemical Precipitation Effluent

Cadmium ug/L 4.21 Chemical Precipitation Effluent

Calcium ug/L 1,920,000 Chemical Precipitation Effluent

Chromium ug/L 6.45 Chemical Precipitation Effluent

Hexavalent Chromium ug/L 5.22 Chemical Precipitation Effluent

Cobalt ug/L 9.30 Chemical Precipitation Effluent

Copper ug/L 3.78 Chemical Precipitation Effluent

Iron ug/L 110 Chemical Precipitation Effluent

 122 Of the four baseline biological treatment plants, only three are classified as operating consistently with the 

technology basis.
Section 10—Pollutant Loadings and Removals

10-17

Table 10-5. Average Effluent Pollutant Concentrations for Chemical Precipitation System 

with Biological Treatment

Analyte Unit Average Concentration Concentration Basis

Lead ug/L 3.39 Chemical Precipitation Effluent

Magnesium ug/L 3,370,000 Surface Impoundment

Manganese ug/L 12,500 Chemical Precipitation Effluent

Mercury ug/L 0.0507 Biological Treatment Effluent

Molybdenum ug/L 125 Surface Impoundment

Nickel ug/L 6.30 Biological Treatment Effluent

Selenium ug/L 5.72 Biological Treatment Effluent

Silver ug/L 0.925 Surface Impoundment

Sodium ug/L 276,000 Surface Impoundment

Thallium ug/L 9.81 Chemical Precipitation Effluent

Tin ug/L 100 Surface Impoundment

Titanium ug/L 9.30 Chemical Precipitation Effluent

Vanadium ug/L 12.6 Chemical Precipitation Effluent

Zinc ug/L 20.0 Chemical Precipitation Effluent

Source: [ERG, 2012a; ERG, 2012d; ERG, 2012i; Duke Energy, 2011a-2011b].

Note: Concentrations are rounded to three significant figures.

10.2.1.4 Baseline Chemical Precipitation with Evaporation Characterization

As described in Section 10.1, EPA did not evaluate post-compliance loadings associated 

with chemical precipitation followed by evaporation because EPA decided not to base the 

control of pollutants in FGD wastewater for existing sources on this technology due to the high 

cost. EPA evaluated average effluent concentrations for the discharge from chemical 

precipitation followed by evaporation in order to characterize the pollutants discharged from 

steam electric power plants currently operating this type of treatment for FGD wastewater. EPA 

conducted an engineering review of the data from the two plants operating evaporation systems 

for which EPA has analytical data, Iatan and Brindisi. EPA used data from the Brindisi plant to 

represent the technology option because it is the only sampled plant, in the United States or 

abroad, that matches the technology basis and operates a hydroxide-sulfide chemical 

precipitation system followed by softening, a brine concentrator, and a crystallization system. 

From the engineering review of the data, EPA determined that Iatan does not operate a chemical 

precipitation system followed by evaporation consistent with the technology basis. Iatan’s 

pretreatment system does not include hydroxide or sulfide precipitation or iron coprecipitation, 

and it does not include softening prior to the evaporation system. Therefore, the Iatan plant does 

not represent the technology basis.

To calculate the average pollutant concentrations for the evaporation treatment system 

technology option, EPA first calculated an average concentration by analyte for each of the two 

evaporation wastestreams at the plant (i.e., brine concentrator distillate and crystallizer 
Section 10—Pollutant Loadings and Removals

10-18

condensate) using available sampling data (i.e., 3-day EPA sampling data).123 For this plant, 

EPA collected and analyzed only total concentrations; therefore, EPA did not have hexavalent 

chromium data to use in the analysis.

Using the average concentrations from the two streams (brine concentrator distillate and 

crystallizer condensate), EPA calculated an average concentration for each analyte. EPA 

transferred pollutant concentrations from the chemical precipitation effluent concentrations for 

pollutants that were not characterized in the evaporation data set, similar to what was done for 

surface impoundments as described in Section 10.2.1.1. EPA used chemical precipitation 

concentrations for biochemical oxygen demand, hexavalent chromium, and cyanide. Table 10-6

presents the average evaporation effluent concentrations by analyte. EPA used the average 

concentrations presented in Table 10-6 to calculate the baseline loadings for any plant currently 

operating a chemical precipitation and evaporation treatment system for FGD wastewater 

treatment.

Table 10-6. Average Effluent Pollutant Concentrations for Chemical Precipitation System 

with Evaporation

Analyte Unit Average Concentration

Classicals

Ammonia ug/L 24,300

Nitrate Nitrite as N ug/L 100

Nitrogen, Kjeldahl ug/L 23,500

Biological Oxygen Demand ug/L 2,220

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 25.0

Total Metals, Metalloids, and Other Nonmetals

Aluminum ug/L 100

Antimony ug/L 1.00

Arsenic ug/L 2.00

Barium ug/L 10.0

Beryllium ug/L 1.00

Boron ug/L 3,750

Cadmium ug/L 2.00

 123 EPA used both the brine concentrator distillate and crystallizer condensate streams to calculate the loadings 

because both wastestreams could be discharged. The vapor-compression evaporation system at Brindisi is operated 

as a zero-discharge system with no wastewater being discharged to surface water or POTW. However, the plant 

could choose to discharge both the brine concentrator and the crystallizer condensate streams, together or separately.
Section 10—Pollutant Loadings and Removals

10-19

Table 10-6. Average Effluent Pollutant Concentrations for Chemical Precipitation System 

with Evaporation

Analyte Unit Average Concentration

Calcium ug/L 200

Chromium ug/L 4.00

Hexavalent Chromium ug/L 5.22

Cobalt ug/L 10.0

Copper ug/L 2.00

Iron ug/L 100

Lead ug/L 1.00

Magnesium ug/L 200

Manganese ug/L 10.0

Mercury ug/L 0.0103

Molybdenum ug/L 20.0

Nickel ug/L 2.00

Selenium ug/L 2.00

Silver ug/L 1.00

Sodium ug/L 5,000

Thallium ug/L 1.00

Tin ug/L 100

Titanium ug/L 10.0

Vanadium ug/L 5.00

Zinc ug/L 28.5

Source: [ERG, 2012h].

Note: Concentrations are rounded to three significant figures.

10.2.2 Ash Transport Water Characterization

EPA used data collected during the detailed study, industry-supplied data, and publicly 

available data sources, including data received during public comment, to characterize pollutant 

discharge concentrations for ash transport water. EPA also used data from the Steam Electric 

Survey to characterize discharge flows [ERG, 2015b]. Below is a list of data sources evaluated 

and accepted by EPA to characterize the discharges from ash impoundments:

• EPA ash impoundment sampling data from the detailed study for the Homer City 

plant [U.S. EPA, 2009].

• Electric Power Research Institute (EPRI) Power Plant Integrated Systems - Chemical 

Emissions Study (PISCES) Reports [EPRI, 1997-2001].

• Mitigation of SCR-Ammonia Related Aqueous Effects in a Fly Ash Pond [EPRI, 

2006].
Section 10—Pollutant Loadings and Removals

10-20

• Permit application data (Form 2-C), as provided by member companies of the Utility 

Water Act Group (UWAG) [UWAG, 2008].

• Development Document for Final Effluent Limitations Guidelines, New Source 

Performance Standards, and Pretreatment Standards for the Steam Electric Point 

Source Category, EPA 440-1-82-029, November 1982 (1982 TDD) [U.S. EPA, 

1982].

• Public comments received from Hoosier Energy, including responses to EPA followup questions regarding the data submitted in comments [Hoosier, 2013; Hoosier 

2014].

• Public comments and supplemental data received from the UWAG, including 

responses to EPA follow-up questions [UWAG, 2013; UWAG, 2014].

Section 3 provides details regarding each of the data sources used in the ash 

impoundment loadings. EPA performed a detailed review of each of these data sources and 

evaluated the information available for use. EPA reviewed all available effluent data and 

excluded data that were not usable in the development of effluent characterization data because 

these data did not meet the following criteria in addition to the general criteria listed in Section 

10.2:

• Analytical data must represent individual sample results or plant-level average sample 

concentrations rather than average results representing multiple plants.

• Samples that were collected from impoundments that could not be categorized by 

type (i.e., bottom ash impoundment, fly ash impoundment, combined ash 

impoundment).

• Samples must be at least 75% by volume ash transport water.

• Samples must be representative of actual ash impoundment effluent (e.g., simulated 

impoundment effluent).

See the “Development Memorandum for the Steam Electric Analytical Database for the 

Final Rule” [ERG, 2015d] for more details on the data quality criteria and data exclusions 

specific for ash transport water.

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 purpose of this analysis, EPA used the following criteria to make 

those determinations:

• Fly ash impoundment: An impoundment/outfall that receives at least 75 percent by 

volume fly ash transport water and does not receive bottom ash transport water. The 

impoundment may also receive other types of wastewater (e.g., low volume 

wastewaters, cooling water).

• Bottom ash impoundment: An impoundment/outfall that receives at least 75 percent 

by volume bottom ash transport water and does not receive fly ash transport water. 

The impoundment may also receive other types of wastewater (e.g., low volume 

wastewaters, cooling water).
Section 10—Pollutant Loadings and Removals

10-21

• Combined ash impoundment: An impoundment/outfall where the combination of fly 

ash and bottom ash transport water comprises at least 75 percent by volume of the 

total flow. The impoundment may also receive other types of wastewater (e.g., 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 wastestreams (e.g., cooling water), the concentrations may be 

diluted and thus underestimate the pollutant loadings. EPA reviewed the data and made some 

substitutions to the data sets, as appropriate. 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.124 If 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), EPA treated the nondetects as half of 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 1 day, EPA 

averaged all these data for that specific pollutant and impoundment to get a single representative 

value of an average concentration of that pollutant in the effluent from the fly ash impoundment. 

EPA did not generate an average pollutant concentration for analytes where all results were less 

than the quantitation limit. 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; 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.125 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 all plants identified as discharging fly ash or bottom 

ash transport water.

The technology basis in the final rule for controlling both fly ash and bottom ash is dry or 

closed-loop 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 will be discharged from generating units to 

which the ELGs apply, the corresponding post-compliance discharge loading is zero.

 124 To simplify the discussion, in this 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.

125 The methodology used to calculate the average concentrations for ash impoundment effluent is presented in the 

Incremental Costs and Pollutant Removals for Final Effluent Limitation Guidelines and Standards for the Steam 

Electric Generating Point Source Category report [U.S. EPA, 2015].
Section 10—Pollutant Loadings and Removals

10-22

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

Nitrate-Nitrite (as N) ug/L 2,360 6,070 2,550

Total Kjeldahl Nitrogen ug/L 4,080 1,160 891

Biochemical Oxygen Demand ug/L NA NA 4,670

Chemical Oxygen Demand ug/L NA 20,800 26,000

Chloride ug/L 12,800 28,100 16,300

Sulfate ug/L 409,000 347,000 209,000

Sulfite ug/L NA 4,750 905

Cyanide ug/L NA NA 5.28

Total Dissolved Solids ug/L 469,000 754,000 266,000

Total Suspended Solids ug/L 10,400 19,700 15,300

Fluoride ug/L 276 NA 650

Phosphorus, Total ug/L 71.8 204 196

Total Metals, Metalloids, and Other Nonmetals

Aluminum ug/L 2,230 1,240 1,200

Antimony ug/L NA 28.2 24.6

Arsenic ug/L 36.4 17.4 50.3

Barium ug/L 121 110 188

Beryllium ug/L 3.42 NA 3.86

Boron ug/L 6,630 541 1,960

Bromide ug/L NA 620 NA

Cadmium ug/L 7.63 2.19 1.42

Calcium ug/L 99,300 68,800 74,600

Chromium ug/L 27.4 5.59 21.6

Hexavalent Chromium ug/L NA NA 0.671

Cobalt ug/L 5.67 14.5 6.00

Copper ug/L 68.8 13.9 21.9

Iron ug/L 855 1,420 601

Lead ug/L 13.7 12.1 7.52

Magnesium ug/L 13,600 34,500 15,300

Manganese ug/L 144 1,440 67.5

Mercury ug/L 0.828 0.634 1.18

Molybdenum ug/L 483 29.7 142

Nickel ug/L 30.5 16.5 19.1

Potassium ug/L 8,460 2,960 12,900
Section 10—Pollutant Loadings and Removals

10-23

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 

Selenium ug/L 15.4 11.8 28.0

Silica ug/L 8,570 6,300 5,930

Silver ug/L NA NA 4.33

Sodium ug/L 34,000 53,000 12,400

Strontium ug/L 429 258 NA

Thallium ug/L 10.3 89.4 31.0

Titanium ug/L 4.83 40.9 22.8

Vanadium ug/L NA NA 56.4

Zinc ug/L 226 31.0 72.3

Source: [U.S. EPA, 2009; U.S. EPA, 1982; EPRI, 1997-2001; EPRI, 2006; UWAG, 2008; Hoosier, 2013; Hoosier, 

2014; UWAG, 2013; UWAG, 2014].

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 plants operating impoundments 

containing combustion residuals 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. The pollutants contained in the impoundment leachate were previously in the 

system; by recycling the leachate back into the same impoundment, no additional pollutants are 

added to the system (i.e., the surface impoundment).. The mass loadings that would have been 

discharged as combustion residual leachate are transferred back to the impoundment and that 

mass loading is then discharged from the ash impoundment. Therefore, EPA finds that baseline 

and post-compliance pollutant loadings will be the same for combustion residual impoundment 

leachate and only calculated baseline loadings for impoundment leachate.126

As described in Section 8, EPA evaluated chemical precipitation as a technology option 

for treating combustion residual landfill leachate. EPA used data collected through the Steam 

Electric Survey to calculate average effluent concentrations for untreated combustion residual 

leachate to characterize the combined discharge of impoundment leachate and landfill leachate.

EPA’s Steam Electric Survey required certain plants to collect and analyze samples of 

leachate and report the results of these analyses. EPA requested these plants to sample any 

 126 As explained in Section VIII of the final preamble, combustion residual leachate discharges contributes 

approximately three percent of the toxic weighted pounds discharged collectively by all steam electric power plants. 

While EPA did not include pollutant reductions from combustion residual leachate from impoundments in its 

estimates of pollutant removals associated with chemical precipitation, this would not have changed its conclusion 

to identify surface impoundments as BAT for combustion residual leachate.
Section 10—Pollutant Loadings and Removals

10-24

untreated impoundment and landfill leachate collected from an on-site management unit (i.e., 

impoundment or landfill) containing combustion residuals. EPA used all data provided by the 

plants in the Steam Electric Survey, except for the following:

• For values reported as less than the quantitation limit, EPA assumed the concentration 

was equal to one-half the quantitation limit provided.

• If the plant did not provide a quantitation limit, EPA assumed the concentration was 

equal to the method detection limit.

EPA compiled all untreated combustion residual leachate sampling data reported in the 

Steam Electric Survey from 26 landfills and 15 impoundments. To determine the industry 

average concentrations for a pollutant, EPA first averaged all concentration data provided for 

each individual management unit providing sampling data to calculate a management-unitspecific average concentration. EPA then averaged the management-unit-specific average 

concentrations at each plant to calculate a plant-level average pollutant leachate concentration. 

EPA then used the average plant-level combustion residual leachate to calculate the average 

concentrations across all plants. Table 6-9 presents the average concentrations for untreated 

combustion residual leachate. EPA used these average concentrations to calculate baseline 

loadings for all plants discharging combustion residual impoundment and/or landfill leachate.

As explained in Section 7.4, based on a review of the Steam Electric Survey data, 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 the treatment of 

landfill leachate by chemical precipitation, EPA also transferred the FGD chemical precipitation 

effluent concentrations, identified in Section 10.2.1.2, to the landfill leachate for the purposes of 

calculating post-compliance loadings. In cases where the average concentration of the untreated 

combustion residual leachate is less than the FGD treated concentration for the technology 

option, EPA assumed that the treated concentration was equal to the influent (i.e., untreated 

combustion residual leachate) average concentration. In this case, EPA did not calculate 

additional removals of these particular pollutants by the wastewater treatment system. Table 10-8

presents the average effluent concentration for chemical precipitation treatment of combustion 

residual leachate.

Table 10-8. Average Effluent Pollutant Concentrations for Chemical Precipitation System 

for the Treatment of Combustion Residual Leachate

Analyte Unit Average Concentration

Classicals

Chloride ug/L 413,000

Sulfate ug/L 1,240,000

Total Dissolved Solids ug/L 3,500,000

Total Suspended Solids ug/L 8,590

Total Metals, Metalloids, and Other Nonmetals

Aluminum ug/L 120
Section 10—Pollutant Loadings and Removals

10-25

Table 10-8. Average Effluent Pollutant Concentrations for Chemical Precipitation System 

for the Treatment of Combustion Residual Leachate

Analyte Unit Average Concentration

Antimony ug/L 3.75

Arsenic ug/L 5.83

Barium ug/L 53.2

Beryllium ug/L 1.33

Boron ug/L 22,400

Cadmium ug/L 4.21

Calcium ug/L 408,000

Chromium ug/L 6.45

Cobalt ug/L 9.30

Copper ug/L 3.78

Iron ug/L 110

Lead ug/L 2.37

Magnesium ug/L 118,000

Manganese ug/L 2,720

Mercury ug/L 0.139

Molybdenum ug/L 125

Nickel ug/L 9.11

Selenium ug/L 111

Silver ug/L 0.925

Sodium ug/L 276,000

Thallium ug/L 1.16

Tin ug/L 49.3

Titanium ug/L 9.30

Vanadium ug/L 12.6

Zinc ug/L 20.0

Note: Concentrations are rounded to three significant figures.

EPA identified one plant currently operating a biological treatment system to treat landfill 

leachate (combined with FGD wastewater) and one plant building a biological treatment system 

to treat its combustion residual landfill leachate. EPA does not have analytical data that represent 

landfill leachate treated with biological treatment; therefore, EPA transferred the effluent 

concentrations from the FGD biological treatment, identified in Section 10.2.1.3, to calculate 

baseline loadings for these two plants. In cases where the average concentration of the untreated 

combustion residual leachate is less than the biological treatment FGD effluent concentration, 

EPA assumed that the treated concentration was equal to the untreated combustion residual 

leachate average concentration so as not to associate excess load with these plants. Although 

these two plants do not operate consistently with the technology basis for biological treatment 

and likely discharge greater pollutant concentrations than the system reflecting the technology 
Section 10—Pollutant Loadings and Removals

10-26

basis, EPA calculated identical baseline and post-compliance loadings for these plants and show 

no removals. Table 10-8 presents the average effluent concentration for biological treatment of 

combustion residual leachate.

Table 10-9. Average Effluent Pollutant Concentrations for Biological Treatment of 

Combustion Residual Leachate

Analyte Unit Average Concentration

Classicals

Chloride ug/L 413,000

Sulfate ug/L 1,240,000

Total Dissolved Solids ug/L 3,500,000

Total Suspended Solids ug/L 8,590

Total Metals, Metalloids, and Other Nonmetals

Aluminum ug/L 120

Antimony ug/L 3.75

Arsenic ug/L 5.83

Barium ug/L 53.2

Beryllium ug/L 1.33

Boron ug/L 22,400

Cadmium ug/L 4.21

Calcium ug/L 408,000

Chromium ug/L 6.45

Cobalt ug/L 9.30

Copper ug/L 3.78

Iron ug/L 110

Lead ug/L 2.37

Magnesium ug/L 118,000

Manganese ug/L 2,720

Mercury ug/L 0.0507

Molybdenum ug/L 125

Nickel ug/L 6.30

Selenium ug/L 5.72

Silver ug/L 0.925

Sodium ug/L 276,000

Thallium ug/L 1.16

Tin ug/L 49.3

Titanium ug/L 9.30

Vanadium ug/L 12.6

Zinc ug/L 20.0
Section 10—Pollutant Loadings and Removals

10-27

Note: Concentrations are rounded to three significant figures.

10.3 WASTEWATER FLOW RATES FOR BASELINE AND POST-COMPLIANCE POLLUTANT 

LOADINGS

As discussed in Section 10.1, EPA used plant-specific wastewater flow rates in the 

loadings calculations. EPA used information from the Steam Electric Survey, industry-submitted 

data, and publicly available information on planned retirements or operational changes to 

determine which plants discharge each specific wastestream of concern and the amount of 

wastewater each plant reported discharging. EPA calculated pollutant loadings several different 

ways to evaluate the effect of the ELG on the steam electric power generating industry. EPA 

considered other rulemakings affecting the steam electric industry in its analysis. EPA evaluated 

compliance costs and pollutant loadings taking into account the CCR rule, the CCR rule and the 

CPP rule, and without CCR and CPP. In general, values reported and discussed in this section 

refer to the pollutant loadings analysis with CCR and the loadings with CCR and CPP, unless 

otherwise noted. This section provides more detail on EPA’s methodology for calculating the 

specific wastewater flow rates used to calculate pollutant loadings with CCR. EPA also adjusted 

its baseline to account for the CPP. Because only the proposed version of the CPP was available 

at the time EPA evaluated pollutant loadings, the Agency estimated loadings that account for 

expected changes from the CPP rather than the final CPP. Section 9.4.1 describes how EPA 

adjusted the population for both compliance costs and loadings to account for CPP.

10.3.1 FGD Wastewater Flow Rates for Pollutant Loadings

As described in Section 9, EPA used system-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. As described in Section 9.4.1 the FGD wastewater flows EPA used to 

estimate pollutant loadings were based on data from the Steam Electric Survey and other 

industry provided data and adjusted for the CCR rule. See Section 4.3 of EPA’s Incremental 

Costs and Pollutant Removals for Final Effluent Limitation Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category report for a detailed description of 

EPA’s methodology for incorporating the CCR final rulemaking into the pollutant loadings flow 

rates [U.S. EPA, 2015]. 

10.3.2 Ash Transport Water Flow Rates for Pollutant Loadings

EPA calculated ash impoundment discharge loadings based on the amount of transport 

water discharged. EPA used information from the Steam Electric Survey and industry-submitted 

data to identify the population of plants that have steam electric generating units that generate fly 

ash, bottom ash, or combined ash transport water, send the transport water to a surface 

impoundment system(s), and discharge the transport water to surface waters or POTWs.127 The 

ash transport water flows EPA used to estimate pollutant loadings were based on data from the 

Steam Electric Survey and other industry provided data and adjusted for the CCR rule. See 

Section 4.3 of EPA’s Incremental Costs and Pollutant Removals for Final Effluent Limitation 

 127 As defined in the Steam Electric Survey, impoundments refer to a system of one or more surface impoundments.
Section 10—Pollutant Loadings and Removals

10-28

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

report for a detailed description of EPA’s methodology for incorporating the CCR final 

rulemaking into the pollutant loadings flow rates [U.S. EPA, 2015]. 

EPA identified 144 plants that discharge ash transport water to a surface water or POTW. 

For each plant included in its analysis, EPA calculated a normalized, generating-unit-level fly 

ash transport water, bottom ash transport water, or combined ash transport water discharge flow 

rate. To calculate a generating-unit-level flow, EPA calculated a normalized plant-level flow and 

then applied a unit flow fraction. 

To calculate the plant-level normalized flow, EPA used the following hierarchy to 

determine the ash transport water flow rates128:

• Influent ash transport water flow rates to the impoundments reported in the 

pond/impoundment systems section (Part D) of the Steam Electric Survey, including 

process flow diagrams.

• 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 (Part A) of the 

Steam Electric Survey. 

• Process flow or water balance diagram (Part A).

• Generating-unit-level sluice flow rates (Part C).

Because most generating units, and corresponding 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. 

To calculate a generating-unit-level flow fraction, EPA calculated a normalized flow for 

each generating unit based on sluice flow rates for fly ash and bottom ash reported in Part C of 

the Steam Electric Survey. If the sluice flow data were not reported or incomplete, EPA used the 

amount of coal burned from responses to Part A of the Steam Electric Survey to estimate the 

total fly ash, bottom ash, or combined ash tonnage associated with a generating unit. After 

calculating all generating-unit-level data (either flow rate or tonnage), EPA summed the values 

to the plant level and calculated a generating-unit-level fraction by dividing the individual 

generating unit data by the plant total. 

 128 The Incremental Costs and Pollutant Removals for Final Effluent Limitation Guidelines and Standards for the 

Steam Electric Generating Point Source Category report provides more detail regarding this hierarchy and EPA’s 

methodology for generating impoundment-specific ash impoundment discharge flow rates [U.S. EPA, 2015].
Section 10—Pollutant Loadings and Removals

10-29

Using the plant-level normalized ash flow rates and the calculated unit flow fraction, 

EPA calculated generating-unit-level ash impoundment discharge flow rates for each of the three 

possible types of ash transport waters (i.e., fly, bottom, and combined). 

EPA also reviewed data in the Steam Electric Survey and industry-submitted data, 

including public comments, to identify any additional updates to account for recycle and 

potential double counting. EPA adjusted bottom ash transport water flows in the ash flow input 

table for plants that recycle any of their bottom ash transport water. Where EPA received 

additional plant-specific information in public comments, EPA evaluated the information and 

updated the plant flows appropriately. 

The ash transport water flow rates used for the loadings analysis are not the same data 

used to estimate compliance costs for plants to eliminate fly ash or bottom ash transport water. 

Based on information received from vendors, it is appropriate to estimate the necessary size of 

the ash handling technology options and corresponding compliance costs based on the amount of 

fly ash generated by specific generating units or the capacity of the unit. However, baseline and 

post-compliance loadings are based on the flow rate of ash transport water.

10.3.3 Combustion Residual Leachate Flow Rates for Pollutant Loadings

As described in Section 9, EPA used plant-level combustion residual landfill leachate 

flow rates to calculate compliance costs. EPA used the same combustion residual landfill 

leachate flow rates in the leachate technology cost modules and the landfill leachate loadings to 

ensure consistency between the two estimates. As described in Section 9, EPA did not estimate 

compliance costs for combustion residual impoundment leachate because it determined that 

plants would transfer any impoundment leachate back to the impoundment from which it was 

collected instead of installing a treatment system to meet the limitations. Therefore, EPA 

calculated only baseline loadings for combustion residual leachate from impoundments but it did 

not estimate post-compliance loadings associated with treating leachate from impoundments.

For each impoundment identified as collecting and discharging combustion residual 

leachate, EPA identified the combustion residual impoundment leachate volume discharged each 

year in gallons per day. For those plants that did not report a combustion residual impoundment 

leachate volume in the Steam Electric Survey, EPA estimated a flow rate using data from other 

plants that reported a combustion residual impoundment leachate volume in the Steam Electric 

Survey. EPA first determined a median combustion residual impoundment leachate discharge 

rate per acre of impoundment collecting leachate, based on the impoundment-specific responses 

to Part D of the Steam Electric Survey. EPA then multiplied the median value by a plant’s 

reported impoundment surface area for those individual impoundments that collect combustion 

residual leachate to estimate a flow rate. For plants that did not provide impoundment-specific 

information, EPA determined a median leachate discharge rate per acre of impoundment 

containing combustion residuals, based on plant responses to Part C of the Steam Electric 

Survey. EPA then multiplied this median value by a plant’s reported combustion residual 

impoundment acreage collecting leachate to estimate a flow rate. Finally, for those plants for 

which it could not estimate a value using the other three approaches, EPA estimated the 

combustion residual impoundment leachate volume using the median combustion residual 

impoundment leachate volume for all plants reporting a volume.
Section 10—Pollutant Loadings and Removals

10-30

See Section 4.1.3.2 of EPA’s Incremental Costs and Pollutant Removals for Final

Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category report for more details on the combustion residual impoundment leachate flow 

rate estimation methodology [U.S. EPA, 2015]. 

While EPA adjusted the flow rates for FGD wastewater and ash transport water to 

account for the CCR rule, EPA did not make any such adjustments to the combustion residual 

landfill or impoundment leachate flow rates because none are expected. 

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 discharging 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 for the baseline and post-compliance pollutant loadings 

for each plant associated with each technology option. Using the plant-level loadings by 

wastestream, EPA then calculated 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, several of the technology options 

considered, and each of the main 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 several technology options considered for 

control of FGD wastewater by multiplying the plant-specific flow rate by the concentrations for 

each technology. 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 

evaporation). 

For the post-compliance loadings associated with the chemical precipitation technology 

option, EPA assumed that the discharge loadings calculated for plants currently treating their 

FGD wastewater with a chemical precipitation system, a biological treatment system, or an 

evaporation system remain unchanged from baseline. EPA assumed plants with a baseline 

surface impoundment would install a chemical precipitation treatment system to meet the 

effluent requirements associated with this option. EPA calculated post-compliance loadings for 

these plants by multiplying the average concentration data set associated with chemical 

precipitation systems, presented in Table 10-4, and the plant-specific 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 these plants 
Section 10—Pollutant Loadings and Removals

10-31

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 chemical precipitation 

treatment system followed by biological treatment technology option, EPA assumed the postcompliance loadings calculated for plants currently treating their FGD wastewater with a 

biological treatment system or an evaporation system remain unchanged from baseline. EPA 

assumed plants with a surface impoundment would install a chemical precipitation system with 

biological treatment and plants with a 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 identified two plants transferring FGD wastewater to a POTW. For these two plants, 

EPA assumed that the plant would continue to transfer the wastewater to a POTW and, therefore, 

adjusted the baseline and post-compliance loadings to account for pollutant removals associated 

with POTW treatment.

Table 10-10 presents the FGD wastewater loadings at an industry level for baseline and 

each post-compliance technology option. These loadings are based on the oil-fired generating 

units and those generating units with a generating capacity of 50 megawatts (MW) or less not 

installing the technology basis because they are not facing any more stringent requirements than 

already existed under the previously established BPT regulations. The loadings include only

those pollutants identified as POCs and also exclude the pollutant parameters BOD, 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 10-11 adjusted the results in 

Table 10-10, accounting for the expected closures related to the implementation of the CPP 

(referred to hereafter as “Accounting for CPP”). Table 10-12 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 post-compliance loadings from the baseline loadings. Table 

10-13 adjusted the results in Table 10-12, accounting for the CPP. The loadings for all 

generating units installing the technology basis, including the oil-fired generating units and small 

generating units (i.e., 50 MW or less generating capacity), are presented in EPA’s Incremental 

Costs and Pollutant Removals for Final Effluent Limitation Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category report [U.S. EPA, 2015].
Section 10—Pollutant Loadings and Removals

10-32

Table 10-10. 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

(million gallons 

per day (MGD))

Total Industry Loading

Pounds/Year TWPE/Year

Baseline 88 a 41.7 1,660,000,000 1,880,000

Chemical Precipitation 88 a 38.4 1,620,000,000 1,070,000

Chemical Precipitation with 

Biological Treatment

88 a 38.4 1,610,000,000 925,000

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS and TSS.

Note: Loadings are rounded to three significant figures.

a – One plant operates only oil-fired generating units and/or generating units with a generating capacity of 50 MW 

or less; therefore, this plant is not facing any more stringent requirements than exist under the previously established 

BPT regulations. As such, EPA assumed that this plant will not install the technology basis and, therefore, will not 

incur any compliance costs. Additionally, EPA assumed it will continue to discharge FGD wastewater at its current 

baseline level and will not achieve any pollutant removals for the technology options evaluated.

Table 10-11. 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, Accounting for CPP

Technology Option

Number of 

Plants

Total Industry

Discharge Flow

(MGD)

Total Industry Loading

Pounds/Year TWPE/Year

Baseline 69 32.4 1,290,000,000 1,550,000

Chemical Precipitation 69 30.4 1,260,000,000 842,000

Chemical Precipitation with 

Biological Treatment

69 30.4 1,250,000,000 723,000

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS and TSS.

Note: Loadings are rounded to three significant figures.

Table 10-12. FGD Wastewater Pollutant Removals Excluding BOD, COD, TDS, and TSS 

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

Technology Option

Total Industry Pollutant Removals

Pounds/Year TWPE/Year

Reduction (Baseline –>Chemical Precipitation) 36,800,000 804,000

Reduction (Baseline –>Chemical Precipitation with Biological 

Treatment)

47,200,000 952,000

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS and TSS.

Note: Removals are rounded to three significant figures. The removals may not equal the subtraction of the 

technology option from the baseline using the values in Table 10-10 due to rounding.
Section 10—Pollutant Loadings and Removals

10-33

Table 10-13. FGD Wastewater Pollutant Removals Excluding BOD, COD, TDS, and TSS 

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

Accounting for CPP

Technology Option

Total Industry Pollutant Removals

Pounds/Year TWPE/Year

Reduction (Baseline –>Chemical Precipitation) 26,700,000 706,000

Reduction (Baseline –>Chemical Precipitation with Biological 

Treatment)

35,200,000 826,000

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS and TSS.

Note: Removals are rounded to three significant figures. The removals may not equal the subtraction of the 

technology option from the baseline using the values in Table 10-11 due to rounding.

10.4.2 Ash Transport Water Loadings and TWPE

EPA calculated plant-specific loadings for the baseline discharges and key technology 

options considered for control of ash transport water. EPA estimated pollutant loadings and 

removals for pollutants that were identified as POCs for fly ash transport water, bottom ash 

transport water, or that were identified as constituents of combined ash impoundments.129 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 four plants transferring 

bottom ash transport water to a POTW. For these four plants, EPA adjusted the baseline loadings 

to account for pollutant removals associated with POTW treatment, as described in Section 10.1.

Because EPA considered regulatory options that would establish different effluent 

requirements for fly ash and bottom ash, EPA analyzed the pollutant loadings and removals for 

these two wastestreams separately; therefore, EPA separated the loadings for combined ash 

impoundments into fly ash transport water loadings and bottom ash transport water loadings. To 

do this, EPA used data from the following three EPRI PISCES reports to estimate the breakout 

of the loadings among fly ash and bottom ash contributions specific to each pollutant:

• PISCES Water Characterization Field Study: Sites A and B Report [EPRI, 1997-

2001].

• PISCES Water Characterization Field Study: Site C Report [EPRI, 1997-2001].

• PISCES Water Characterization Field Study: Site D Report [EPRI, 1997-2001].

The PISCES reports include information from several plants operating impoundments 

receiving either fly ash transport water and/or bottom ash transport water. The reports include a 

table presenting loadings associated with each stream entering the impoundment for several 

 129 EPA calculated combined ash pollutant loadings for fly ash transport water and bottom ash transport water POCs, 

as well as biochemical oxygen demand (BOD), cyanide, hexavalent chromium (chromium VI), and silver which 

were identified as constituents of combined fly ash and bottom ash impoundments.
Section 10—Pollutant Loadings and Removals

10-34

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 an analyte-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, and calculated total fly ash and bottom ash transport 

water baseline loadings for each plant [ERG, 2015a].

EPA assumes that all plants currently discharging ash transport water, and subject to the 

ELGs, 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 requirements.

Table 10-14 presents the baseline ash transport water loadings on an industry level. The 

table includes the number of plants discharging each type of ash transport water, the total 

industry discharge flow rate, and the total baseline industry loadings in pounds per year and 

TWPE per year associated with each type of impoundment. The industry-level baseline loadings 

presented in Table 10-14 include only those pollutants identified as POCs and excludes BOD, 

COD, TDS, and TSS (to avoid double counting the loadings for other specific pollutants). See 

Section 6 for a more detailed discussion of the POC evaluation for fly ash and bottom ash 

transport water. Table 10-15 adjusts the results presented in Table 10-14, accounting for the 

CPP. 

Table 10-14. Industry-Level Baseline Ash Impoundment Loadings by Type of 

Impoundment Excluding BOD, COD, TDS, and TSS

Type of Ash 

Impoundment Number of Plants

Total Baseline 

Industry Discharge

Flow

(MGD)

Total Industry Baseline Loading

Pounds/Year TWPE/Year

Fly Ash

Fly Ash Pond 9 25 46,700,000 69,000

Combined Ash 

Pond a

N/C b N/C b 68,100,000 156,000
Section 10—Pollutant Loadings and Removals

10-35

Table 10-14. Industry-Level Baseline Ash Impoundment Loadings by Type of 

Impoundment Excluding BOD, COD, TDS, and TSS

Type of Ash 

Impoundment Number of Plants

Total Baseline 

Industry Discharge

Flow

(MGD)

Total Industry Baseline Loading

Pounds/Year TWPE/Year

Bottom Ash

Bottom Ash Pond 115 200 340,000,000 481,000

Combined Ash 

Pond a

N/C b N/C b 14,800,000 27,400

TOTAL 144 298-315c 469,000,000 733,000

N/C – Not calculated.

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS, and TSS.

Note: Loadings are rounded to three significant figures.

a – The 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 on the EPRI data, as described in 

this section. 

b – After incorporating updates based on the CCR rule, EPA identified a total of 25 plants discharging combined ash 

transport water from combined ash ponds. EPA reduced the baseline loadings (pounds and TWPE) for five of these 

plants due to partial CCR updates (i.e., either a fly ash conversion or a bottom ash conversion associated with 

combined ash transport water). Prior to making the partial CCR updates to those five plants, the total combined ash 

transport water discharge flow is 88 MGD. EPA can’t precisely estimate the change in flow for these five plants; 

however, the total flow for these five plants is approximately 14 MGD. 

c – The total ash transport water discharge flow is presented as a range to reflect the difference between the five 

plants with partial CCR updates. The minimum flow represents the total industry flow excluding the flow associated 

with the five plants. The maximum flow represents the total industry flow including the flow associated with the five 

plants.

Table 10-15. Industry-Level Baseline Ash Impoundment Loadings by Type of 

Impoundment Excluding BOD, COD, TDS, and TSS, Accounting for CPP

Type of Ash 

Impoundment Number of Plants

Total Baseline 

Industry Discharge

Flow

(MGD)

Total Industry Baseline Loading

Pounds/Year TWPE/Year

Fly Ash

Fly Ash Pond 8 25 45,900,000 67,800

Combined Ash 

Pond a

N/C b N/C b 51,600,000 118,000

Bottom Ash

Bottom Ash Pond 84 134 228,000,000 323,000

Combined Ash 

Pond a

N/C b N/C b 11,700,000 21,600
Section 10—Pollutant Loadings and Removals

10-36

Table 10-15. Industry-Level Baseline Ash Impoundment Loadings by Type of 

Impoundment Excluding BOD, COD, TDS, and TSS, Accounting for CPP

Type of Ash 

Impoundment Number of Plants

Total Baseline 

Industry Discharge

Flow

(MGD)

Total Industry Baseline Loading

Pounds/Year TWPE/Year

TOTAL 108 214-228 c 337,000,000 531,000

N/C – Not calculated.

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS, and TSS.

Note: Loadings are rounded to three significant figures.

a – The 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 on the EPRI data, as described in 

this section. 

b – After incorporating updates based on the CCR rule and CPP, EPA identified a total of 20 plants discharging 

combined ash transport water from combined ash ponds. EPA reduced the baseline loadings (pounds and TWPE) for 

three of these plants due to partial CCR updates (i.e., either a fly ash conversion or a bottom ash conversion 

associated with combined ash transport water). Prior to making the partial CCR updates to those three plants, the 

total combined ash transport water discharge flow is 69 MGD. EPA can’t precisely estimate the change in flow for 

these three plants; however, the total flow for these three plants is approximately 13 MGD. 

c – The total ash transport water discharge flow is presented as a range to reflect the difference between the three

plants with partial CCR updates. The minimum flow represents the total industry flow excluding the flow associated 

with the three plants. The maximum flow represents the total industry flow including the flow associated with the 

three plants.

Table 10-16 presents the total industry post-compliance loadings and 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 generating 

units and those generating units with a generating capacity of 50 MW or less not installing the 

technology basis because they are facing no more stringent requirements than already existed 

under the previously established BPT regulations. EPA calculates the pollutant removals by 

subtracting the post-compliance loadings from the baseline loadings. The pollutant removals for 

all generating units installing the technology basis, including the oil-fired generating units and 

small generating units (i.e., 50 MW or less generating capacity), are presented in EPA’s 

Incremental Costs and Pollutant Removals for Final Effluent Limitation Guidelines and 

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

2015]. Table 10-17 adjusts the results presented in Table 10-16, accounting for the CPP.
Section 10—Pollutant Loadings and Removals

10-37

Table 10-16. Estimated Ash Impoundment Pollutant Removals by Regulatory Option 

Excluding BOD, COD, TDS, and TSS 

Regulatory

Option a

Total Industry Loading Total Industry Pollutant Removals b

Pounds/Year TWPE/Year Pounds/Year TWPE/Year

Fly Ash

All Regulatory 

Options

1,490,000 2,880 113,000,000 222,000

Bottom Ash

A, B 354,000,000 509,000 NA NA

C 139,000,000 198,000 216,000,000 311,000

D, E 1,890,000 2,390 353,000,000 506,000

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS, and TSS.

Note: Removals are rounded to three significant figures. 

a – Baseline and Regulatory Options A, B, D, and E assume that oil-fired generating units and generating units with 

a capacity of 50 MW or less do not install the technology basis for all wastestreams. Regulatory Option C assumes 

that oil-fired generating units and generating units with a capacity of 50 MW or less do not install the technology 

basis for FGD wastewater treatment and fly ash, while oil-fired generating units and generating units with a capacity 

of 400 MW or less do not install the technology basis for bottom ash.

b – Compared to baseline.

NA – Not applicable.

Table 10-17. Estimated Ash Impoundment Pollutant Removals by Regulatory Option 

Excluding BOD, COD, TDS, and TSS, Accounting for CPP

Regulatory

Option a

Total Industry Loading Total Industry Pollutant Removals b

Pounds/Year TWPE/Year Pounds/Year TWPE/Year

Fly Ash

All Regulatory 

Options

370,000 631 97,100,000 185,000

Bottom Ash

A, B 240,000,000 345,000 NA NA

C 65,800,000 93,900 174,000,000 251,000

D, E 861,000 896 239,000,000 344,000

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS, and TSS.

Note: Removals are rounded to three significant figures. The removals may not equal the sum of the removals 

presented in the tables in this section from the various wastestreams due to rounding.

a – Baseline and Regulatory Options A, B, D, and E assume that oil-fired generating units and generating units with 

a capacity of 50 MW or less do not install the technology basis for all wastestreams. Regulatory Option C assumes 

that oil-fired generating units and generating units with a capacity of 50 MW or less do not install the technology 

basis for FGD wastewater treatment and fly ash, while oil-fired generating units and generating units with a capacity 

of 400 MW or less do not install the technology basis for bottom ash.

b – Compared to baseline.

NA – Not applicable.
Section 10—Pollutant Loadings and Removals

10-38

10.4.3 Combustion Residual Leachate Loadings and TWPE

EPA calculated plant-specific loadings for the baseline discharges and main technology 

option considered for combustion residual leachate by multiplying the plant-specific flow by the 

concentrations for untreated combustion residual leachate or chemical precipitation effluent. For 

baseline loadings, EPA multiplied the plant-specific combustion residual leachate discharge flow 

rate with the average pollutant concentrations that represent untreated combustion residual 

leachate for impoundments and landfills. EPA identified five plants transferring combustion 

residual leachate to a POTW. For these five plants, EPA adjusted the baseline loadings to 

account for pollutant removals associated with POTW treatment.

For the chemical precipitation technology option, EPA assumed that all plants 

discharging landfill leachate would install that type of treatment system to handle only landfill 

leachate. No plants currently treat leachate with a chemical precipitation system; however, two 

plants do operate/plan to operate biological treatment systems to treat landfill leachate, so all but 

these two plants would need to install treatment to meet the effluent requirements associated with 

this technology option. EPA calculated discharge loadings for these plants using the average 

concentration data set associated with chemical precipitation systems, presented in Section 

10.2.3, and plant-specific combustion residual landfill leachate flow rates. All combustion 

residual impoundment leachate discharges would remain unchanged from baseline.

Table 10-18 presents the combustion residual leachate loadings at an industry level for 

baseline and each post-compliance technology basis. The loadings presented in Table 10-18 are 

based on the oil-fired generating units and those generating units with a generating capacity of 

50 MW or less not installing the technology basis because they are facing no more stringent 

requirements than already existed under the previously established BPT regulations.

130 The 

loadings include only pollutants identified as POCs and 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 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 10-19 adjusts the results shown in Table 10-18 to 

account for the CPP. Table 10-20 presents the pollutant removals, in both pounds per year and 

TWPE per year, for the technology options. EPA calculated the pollutant removals by 

subtracting the post-compliance loadings from the baseline loadings. Table 10-21 adjusts the 

results shown in Table 10-20 to account for the CPP. The loadings for all generating units 

installing the technology basis, including the oil-fired generating units and small generating units 

(i.e., 50 MW or less generating capacity), are presented in EPA’s Incremental Costs and 

Pollutant Removals for Final Effluent Limitation Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category report [U.S. EPA, 2015].

 130 EPA evaluated exclusions on a plant level for combustion residual leachate. Those plants identifying all 

generating units operated at the plant as coal-fired and with a generating capacity of 50 MW or less were assumed 

not to install the technology basis.
Section 10—Pollutant Loadings and Removals

10-39

Table 10-18. Industry-Level Combustion Residual Leachate Loadings Excluding BOD, 

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

Installing Technology Basis

Technology Option

Number of 

Plants

Total Industry

Discharge Flow

(MGD)

Total Industry Loading

Pounds/Year TWPE/Year

Baseline 95 a 9.09 85,400,000 70,300

Chemical Precipitation 95 a 9.09 72,900,000 36,400

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS, and TSS.

Note: Loadings are rounded to three significant figures.

a – One plant operates only oil-fired generating units and/or generating units with a generating capacity of 50 MW 

or less; therefore, this plant is not facing any more stringent requirements than exist under the previously established 

BPT regulations. As such, EPA assumed that this plant will not install the technology basis and, therefore, will not 

incur any compliance costs. Additionally, EPA assumed it will continue to discharge combustion residual leachate at 

its current baseline level and will not achieve any pollutant removals for the technology options evaluated.

Table 10-19. Industry-Level Combustion Residual Leachate Loadings Excluding BOD, 

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

Installing Technology Basis, Accounting for CPP

Technology Option

Number of 

Plants

Total Industry

Discharge Flow

(MGD)

Total Industry Loading

Pounds/Year TWPE/Year

Baseline 70 7.90 74,100,000 61,000

Chemical Precipitation 70 7.90 63,200,000 31,400

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS, and TSS.

Note: Loadings are rounded to three significant figures.

Table 10-20. Combustion Residual Leachate Pollutant Removals Excluding BOD, COD, 

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

Technology Basis

Technology Option

Total Industry Pollutant Removals

Pounds/Year TWPE/Year

Reduction (Baseline –>Chemical Precipitation) 12,500,000 33,800

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS, and TSS.

Note: Removals are rounded to three significant figures. The removals may not equal the subtraction of the 

technology option from the baseline using the values in Table 10-18 due to rounding.
Section 10—Pollutant Loadings and Removals

10-40

Table 10-21. Combustion Residual Leachate Pollutant Removals Excluding BOD, COD, 

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

Technology Basis, Accounting for CPP

Technology Option

Total Industry Pollutant Removals

Pounds/Year TWPE/Year

Reduction (Baseline –>Chemical Precipitation) 10,900,000 29,600

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS, and TSS.

Note: Removals are rounded to three significant figures. The removals may not equal the subtraction of the 

technology option from the baseline using the values in Table 10-19 due to rounding.

10.4.4 Pollutant Loadings and Removals for Regulatory Options

As described in Section 8, EPA evaluated five main regulatory options comprising

various combinations of technology options to control each wastestream. EPA estimated the 

pollutant removals associated with steam electric power plants to achieve compliance for each of 

the main regulatory options. Table 10-22 presents the total industry loadings and pollutant 

removals at baseline and for each of the five regulatory options. The loadings and TWPE values 

presented in these tables include only pollutants identified as POCs. The table presents the 

estimated loadings and pollutant removals based on the oil-fired generating units and generating 

units with a capacity of 50 MW or less not installing the appropriate technology bases. Table 

10-23 adjusts the results shown in Table 10-22 to account for the CPP. The loadings and 

pollutant removals for all generating units installing the technology basis, including the oil-fired 

generating units and small generating units (i.e., 50 MW or less generating capacity), are 

presented in EPA’s Incremental Costs and Pollutant Removals for Final Effluent Limitation 

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

report [U.S. EPA, 2015]. The pollutant-level baseline loadings and pollutant-level removals for 

each regulatory option by wastestream are presented in the memorandum entitled, “Steam 

Electric Pollutant-Level Loadings and Removals by Wastestream” [ERG, 2015g].
Section 10—Pollutant Loadings and Removals

10-41

Table 10-22. Estimated Pollutant Loadings and Removals by Regulatory Option 

Regulatory

Option a

Total Industry Loading Total Industry Pollutant Removals b

Pounds/Year TWPE/Year Pounds/Year TWPE/Year

Baseline 2,210,000,000 2,680,000 - -

A 2,060,000,000 1,650,000 150,000,000 1,030,000

B 2,050,000,000 1,510,000 161,000,000 1,170,000

C 1,830,000,000 1,200,000 376,000,000 1,480,000

D 1,700,000,000 1,000,000 513,000,000 1,680,000

E 1,680,000,000 967,000 526,000,000 1,710,000

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TOC, TDS, and TSS.

Note: Loadings and 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 – Baseline and Regulatory Options A, B, D, and E assume that oil-fired generating units and generating units with 

a capacity of 50 MW or less do not install the technology basis for all wastestreams. Regulatory Option C assumes 

that oil-fired generating units and generating units with a capacity of 50 MW or less do not install the technology 

basis for FGD wastewater treatment and fly ash, while oil-fired generating units and generating units with a capacity 

of 400 MW or less do not install the technology basis for bottom ash.

b – Compared to baseline.

Table 10-23. Estimated Pollutant Loadings and Removals by Regulatory Option, 

Accounting for CPP

Regulatory

Option a

Total Industry Loading Total Industry Pollutant Removals b

Pounds/Year TWPE/Year Pounds/Year TWPE/Year

Baseline 1,700,000,000 2,140,000 - -

A 1,580,000,000 1,250,000 124,000,000 891,000

B 1,570,000,000 1,130,000 132,000,000 1,010,000

C 1,390,000,000 878,000 306,000,000 1,260,000

D 1,330,000,000 785,000 371,000,000 1,350,000

E 1,320,000,000 755,000 382,000,000 1,380,000

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TOC, TDS, and TSS.

Note: Loadings and 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 – Baseline and Regulatory Options A, B, D, and E assume that oil-fired generating units and generating units with 

a capacity of 50 MW or less do not install the technology basis for all wastestreams. Regulatory Option C assumes 

that oil-fired generating units and generating units with a capacity of 50 MW or less do not install the technology 

basis for FGD wastewater treatment and fly ash, while oil-fired generating units and generating units with a capacity 

of 400 MW or less do not install the technology basis for bottom ash.

b – Compared to baseline.
Section 10—Pollutant Loadings and Removals

10-42

10.4.5 Evaluation of Non-Detected Values on Pollutant Loadings 

The sample-specific detection levels for the ash transport water data used for this rule 

vary widely between samples and across plants. To capture the full range of uncertainty EPA 

derived estimates of pollutant loadings using two methods. Method 1 uses both the detect and 

non-detect data (assigning one-half of the detection limit for all non-detects). This is EPA’s 

standard procedure for effluent limitations guidelines as well as Clean Water Act assessment and 

permitting, Safe Drinking Water Act compliance monitoring, and Resource Conservation and 

Recovery Act and Superfund programs. Since the detection levels exhibit considerable variance 

across plants, commenters raised the concern that the loadings data may contain non-detect 

values that may be significantly higher than the range of observed (i.e., detected) values. Method 

2 excludes all non-detect observations whose attributed values (i.e., one-half of the detection 

limit) are higher than the highest detected value for that pollutant in the data set. EPA conducted 

analysis using method 2 in order to place an upper bound on the effect of potential outlier nondetects on the pounds of pollutants removed and TWPEs removed under the final rule.

Although method 1 for handling “non-detects” when identifying loadings for this rule is 

consistent with past precedent, it is important to be transparent about the sensitivity of these 

results to potential outliers. An outlier is a value that appears to diverge from other observations 

in the sample. There are normally two types of outliers. The first is an observation that is simply 

an extreme manifestation of random variation inherent in the data. The second is an observation 

that is an outlier due to differences in experimental procedure [Greene, 2000]. The first type of 

outlier is of less concern here, and would be limited to extreme detected values, which one 

expects to periodically observe. The second type of outlier is of greater concern, as it may not be 

a natural characteristic of the data. 

To isolate the effect of potential outliers for the ash transport water data, EPA used 

method 2 to calculate the averaged pollutant concentrations. The key consideration in such an 

analysis is to establish a rational basis for determining if a non-detect value could potentially be 

considered an outlier. This method used samples where the analyte is detected (“detected 

values”) to evaluate the existence of non-detects that are outliers. The approach we used for this 

alternative analysis isolates attributed non-detect (i.e., one-half of the detection limit) values that 

are above the observed sample of detected values. When there are multiple detected values to 

base this on, such treatment should exclude samples that are outside the normal range of 

variation. Note that to truly eliminate all outliers, one would also eliminate the outliers that are 

non-detects lower than the lowest detected value. Outliers are typically analyzed at both tails of 

the distribution. However, to assess a reasonable upper-bound on cost-effectiveness by 

addressing the concerns with the detection sensitivity of sampling instruments, this alternative 

method focuses only on the high outliers.

EPA first identified the maximum detected value in the dataset for an analyte and then 

excluded all non-detect values higher than that maximum detected value. The pollutant loadings 

and cost effectiveness were then recalculated using the detected values and the remaining nondetected values that were lower than the maximum detected value. After discarding non-detects 

in this manner, calculated results for bottom ash indicate that the mean pollutant concentrations 

for 6 out of 44 analytes change: antimony (-97.78%), cobalt (-99.08%), molybdenum (-64.41%), 

silver (-16.57%), thallium (-99.10%), and titanium (-58.75%). EPA notes that, of the six analytes 
Section 10—Pollutant Loadings and Removals

10-43

that had their means change, five of them had three or fewer detected values. Based on this small 

number of detected values, it is not clear whether the excluded non-detects were truly outliers in 

those cases, as we may not have an accurate distribution of detected data. We also assessed the 

approach of replacing each of the excluded non-detects with the mean detected value, instead of 

removing them from the dataset, but that approach yielded only minor differences compared with 

discarding the non-detect values. 

The pollutant concentrations obtained using methods 1 and 2 resulted in the following 

pollutant removals, as shown in Table 10-24 and Table 10-25. 

Table 10-24. Pollutant Removals – Method 1 Not Excluding High ND

lbs/yr TWPE/yr

Bottom Ash Transport Water (>50 MW) 238,810,677 344,014 

Full Rule (Option D) 371,152,958 1,354,857 

Note: Excludes removals for pollutants not identified as POCs and for BOD, COD, TSS, and TDS.

Table 10-25. Pollutant Removals – Method 2 Excluding High ND

lbs/yr TWPE/yr

Bottom Ash Transport Water (>50 MW) 238,735,119 236,402

Full Rule (Option D) 371,048,709 1,233,553

Note: Excludes removals for pollutants not identified as POCs and for BOD, COD, TSS, and TDS.

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Section 10—Pollutant Loadings and Removals

10-44

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the Final Rule. (30 September). DCN SE05359.

19. ERG. 2015g. Eastern Research Group, Inc. Steam Electric Pollutant-Level Loadings 

and Removals by Wastestream. (30 September). DCN SE05847.

20. EPRI. 1997 - 2001. Electric Power Research Institute. PISCES Water 

Characterization Field Study, Sites A-G. Palo Alto, CA. DCN SE01818 through 

SE01823.

21. EPRI. 2006. Electric Power Research Institute. Mitigation of SCR-Ammonia 

Related Aqueous Effects in a Fly Ash Impoundment: Algal Enhancement and Water 

Chemistry. Palo Alto, CA. DCN SE04742.

22. Greene, W.H. 2000. Econometric Analysis. Saddle River, New Jersey, Prentice Hall.

23. Hoosier. 2013. Hoosier Energy Rural Electric Cooperative. Comments of Hoosier 

Energy on Effluent Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category. (20 September). EPA-HQ-OW-2009-

0819-4471.

24. Hoosier. 2014. Hoosier Energy Rural Electric Cooperative. Hoosier response to 

Post Proposal Information Request. (11 and 14 April). DCN SE04701-04702.
Section 10—Pollutant Loadings and Removals

10-45

25. NCDENR. 2011. North Carolina Department of Environment and Natural 

Resources. State Provided Sampling Data from North Carolina’s Progress Energy 

Roxboro Plant. (June 26). DCN SE01812.

26. U.S. EPA. 1982. U.S. Environmental Protection Agency. Development Document 

for Effluent Limitations Guidelines and Standards and Pretreatment Standards for 

the Steam Electric Point Source Category. EPA-440-1-82-029. Washington, DC. 

(November). DCN SE02933.

27. U.S. EPA, 2009. U.S. Environmental Protection Agency. Steam Electric Power 

Generating Point Source Category: Final Detailed Study Report. EPA 821-R-09-

008. Washington, DC. (October). Available online at: 

http://water.epa.gov/lawsregs/guidance/cwa/304m/archive/upload/2009_10_26_guid

e_steam_finalreport.pdf. 

28. U.S. EPA. 2015. Incremental Costs and Pollutant Removals for Final Effluent 

Limitation Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category. (30 September). DCN SE05831.

29. UWAG. 2008. Utility Water Act Group. Form 2C Effluent Guidelines Database. 

(June 30). DCNs SE02918 and SE02918A1.

30. UWAG. 2013. Utility Water Act Group. Comments on EPA’s Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category. (7 June). EPA-HQ-OW-2009-0819-4655.

31. UWAG. 2014. Utility Water Act Group. UWAG Response to Post Proposal 

Information Request. (1 August). DCN SE04717.
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 is establishing new or revised discharge requirements in the revisions to the Steam 

Electric effluent limitations guidelines and standards (ELGs). Regulated pollutants are pollutants 

for which EPA is establishing 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 (POCs) for each wastestream. The identification 

of POCs for each wastestream is presented in Section 6.6 of this document 

11.1 SELECTION OF REGULATED POLLUTANTS FOR DIRECT DISCHARGERS

Effluent limitations and standards for all POCs often are not necessary to ensure that 

wastewater pollution is adequately controlled because many of the pollutants originate from 

similar sources, have similar treatabilities and are removed by similar mechanisms. Therefore, in 

some instances, it may be sufficient to establish effluent limitations or standards for one or more 

indicator pollutants, which will ensure the removal of other POCs. Based on the information in 

the record, this approach of establishing effluent limitations and standards on a subset of the 

POCs is appropriate for the discharge of some of the wastestreams regulated by this rule. For 

wastestreams where the final rule establishes zero discharge limitations or standards, all POCs 

are directly regulated.

For wastestreams where the final rule establishes numeric effluent limitations or 

standards (best available technology economically achievable (BAT) or new source performance 

standards (NSPS)), EPA considered the following when selecting a subset of pollutants as 

indicators for all regulated pollutants:

• EPA did not set limits for pollutants associated with treatment system additives 

because regulating these pollutants could interfere with efforts to optimize treatment

system operation. 

• EPA did not set limits for pollutants for which the treatment technology was 

ineffective (e.g., pollutant concentrations remained approximately unchanged or 

increased across the treatment system).

• EPA did not set limits for pollutants that are adequately controlled through the 

regulation of another indicator pollutant because they have similar properties and are 

treated by similar mechanisms as the regulated pollutant.

The following sections describe EPA’s pollutant selection analysis for each wastestream.

11.1.1 FGD Wastewater

The final rule establishes separate BAT and NSPS limitations and standards for FGD 

wastewater. BAT limitations are based on a chemical precipitation system followed by 

anoxic/anaerobic biological treatment as the technology basis and NSPS is based on an 
Section 11—Pollutants Selected for Regulation

11-2

evaporation system as the technology basis for the treatment of FGD wastewater, as described in 

13.8

BAT Limitations for FGD Wastewater

EPA included BAT limitations for four pollutants (arsenic, mercury, selenium, and

nitrate/nitrite as N) for FGD wastewater, and a fifth pollutant (TSS) for legacy FGD wastewater 

and FGD wastewater discharged by small or oil-fired units.

131 The regulated pollutant selection 

criteria matrix for the 31 POCs in FGD wastewater for BAT limitations is illustrated in Table 

11-1. The following discussion explains the rationale EPA used to select which of the 31 POCs 

to regulate under BAT for the final rule. EPA acknowledges that a POC may fall under more 

than one criterion for exclusion as a regulated pollutant (e.g., a pollutant may not be effectively 

treated by the BAT technology and could also be used as a treatment chemical). 

• Conventional Pollutants: EPA identified total suspended solids (TSS) as a POC. The 

existing BPT limitations adequately control TSS in discharges of FGD wastewater. In 

addition, EPA set BAT limitations on TSS as an indicator pollutant to control 

particulate metals in discharges of legacy FGD wastewater (from all generating units) 

and discharges of FGD wastewater from small generating units and oil-fired 

generating units. These BAT limitations on TSS are equal to the previously 

promulgated BPT limitations on TSS for low volume waste sources (which prior to 

this final rule included FGD wastewater). 

• Treatment Chemicals: EPA identified and eliminated five POCs that are also used as 

treatment chemicals: aluminum, calcium, iron, phosphorus, and sodium.

• Pollutants Not Effectively Treated by the BAT Technology: EPA eliminated five 

pollutants, ammonia, boron, chloride, cyanide, and total dissolved solids (TDS), 

because the technology basis for the FGD wastewater effluent limitations and 

standards is not demonstrated to reliably treat these pollutants.132

• Pollutants Directly Regulated or Controlled by Regulation of Other Pollutants: The 

remaining pollutants are metals, metalloids, or other nonmetals and nitrate/nitrite as 

N. 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. Most metals are precipitated 

to some degree in the chemical precipitation system, thereby resulting in the removal 

of a wide range of metals. EPA’s design basis for the BAT system uses hydroxide and 

sulfide precipitation, as well as iron coprecipitation. EPA selected arsenic and 

 131 EPA also established BAT limitations for four pollutants (arsenic, mercury, selenium, and TDS) for FGD 

wastewater for plants that accept the limitations for the voluntary incentives program. The following discussion on

“NSPS Limitations for FGD Wastewater” is applicable to the BAT limitations established for the voluntary 

incentives program.

132 While EPA’s pollutant-specific treatment effectiveness analysis performed for FGD wastewater showed some 

removal of ammonia, boron, cyanide, chloride, and TDS in the chemical precipitation system (see Section 10.2.1.2 

for additional details), EPA has determined that the chemical precipitation system is not demonstrated to reliably 

treat these pollutants. 
Section 11—Pollutants Selected for Regulation

11-3

mercury as regulated pollutants and as indicators of effective removals of many other 

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, 

other pollutants such as selenium and nitrate/nitrite as N require additional treatment 

(i.e., biological treatment) to achieve consistent removals. Anaerobic/anoxic 

biological treatment is effective at removing both selenium and nitrate/nitrite as N 

and, therefore, EPA also selected both pollutants for regulation.

NSPS Limitations for FGD Wastewater

EPA also included NSPS for four pollutants: arsenic, mercury, selenium, and TDS. 

The regulated pollutant selection criteria matrix for the 31 POCs in FGD wastewater for 

NSPS limitations is illustrated in Table 11-2. The following discussion explains the rationale 

EPA used to select which of the 31 POCs to regulate under NSPS for the final rule. 

• Conventional Pollutants: EPA identified total suspended solids (TSS) as a POC. The 

previously promulgated limitations (BPT for existing sources; NSPS for new sources 

as promulgated in 1982) adequately control TSS and those limitations are included in 

the NSPS included in the revised ELGs.

• Pollutants Not Effectively Treated by the NSPS Technology: EPA eliminated three

pollutants: ammonia, cyanide, and phosphorus because the technology basis for the 

FGD wastewater effluent limitations and standards is not demonstrated to reliably 

treat these pollutants. 

• Pollutants Directly Regulated or Controlled by Regulation of Other Pollutants: The 

remaining pollutants are metals, metalloids, other nonmetals, nitrate-nitrite as N, 

chloride, and TDS. As described in Section 7, the evaporation system uses steam to 

evaporate the water, producing a distillate stream and a solid residual by-product (i.e., 

crystallized salts). Pollutant removals from this system will depend on the pollutant’s 

solubility and volatility. Pollutants with lower solubility are more easily crystallized 

and removed as part of the solids residuals. EPA selected four pollutants, arsenic, 

mercury, selenium, and TDS to represent different solubilities and volatilities of 

pollutants and act as indicator pollutants for other pollutants. Nitrate-nitrite as N is 

directly regulated by the BAT limitations for FGD wastewater. For NSPS, however, 

EPA determined that limitations for TDS would effectively control discharges of 

nitrate-nitrite as N (which, due to its relatively high solubility and low volatility, 

concentrate in the brine removed as the moisture content of the solids residuals), as 

well as other pollutants such as sodium, bromide, and chloride.
Section 11—Pollutants Selected for Regulation

11-4

Table 11-1. POCs Considered for Regulation for Direct Dischargers (BAT): FGD Wastewater

Pollutant Group Pollutant of Concern Treatment Chemical

Not Effectively Treated

by the BAT Technology

Directly Regulated or 

Controlled by Regulation 

of Another Parameter

Priority Pollutants

Antimony 

Arsenic 

Beryllium 

Cadmium 

Chromium 

Copper 

Cyanide 

Lead 

Mercury 

Nickel 

Selenium 

Thallium 

Zinc 

Nonconventional Pollutants

Aluminum 

Ammonia 

Barium 

Boron 

Calcium 

Chloride 

Cobalt 

Iron 

Magnesium 
Section 11—Pollutants Selected for Regulation

11-5

Table 11-1. POCs Considered for Regulation for Direct Dischargers (BAT): FGD Wastewater

Pollutant Group Pollutant of Concern Treatment Chemical

Not Effectively Treated

by the BAT Technology

Directly Regulated or 

Controlled by Regulation 

of Another Parameter

Manganese 

Nonconventional Pollutants

Molybdenum 

Nitrate/Nitrite as N 

Phosphorus 

Sodium 

Titanium 

Total Dissolved Solids 

Vanadium 

Note: The conventional pollutants identified as POCs for FGD wastewater (oil and grease (O&G) and TSS) are not included in the table because conventional 

pollutants are not regulated under BAT or NSPS limitations and standards.
Section 11—Pollutants Selected for Regulation

11-6

Table 11-2. POCs Considered for Regulation for Direct Dischargers (NSPS): FGD Wastewater

Pollutant Group Pollutant of Concern Treatment Chemical

Not Effectively Treated

by the NSPS Technology

Directly Regulated or 

Controlled by Regulation 

of Another Parameter

Priority Pollutants

Antimony 

Arsenic 

Beryllium 

Cadmium 

Chromium 

Copper 

Cyanide 

Lead 

Mercury 

Nickel 

Selenium 

Thallium 

Zinc 

Nonconventional Pollutants

Aluminum 

Ammonia 

Barium 

Boron 

Calcium 

Chloride 

Cobalt 

Iron 

Magnesium 
Section 11—Pollutants Selected for Regulation

11-7

Table 11-2. POCs Considered for Regulation for Direct Dischargers (NSPS): FGD Wastewater

Pollutant Group Pollutant of Concern Treatment Chemical

Not Effectively Treated

by the NSPS Technology

Directly Regulated or 

Controlled by Regulation 

of Another Parameter

Manganese 

Nonconventional Pollutants

Molybdenum 

Nitrate/Nitrite as N 

Phosphorus 

Sodium 

Titanium 

Total Dissolved Solids 

Vanadium 

Note: The conventional pollutants identified as POCs for FGD wastewater (oil and grease (O&G) and TSS) are not included in the table because conventional 

pollutants are not regulated under BAT or NSPS limitations and standards.

Note: The information in this table is also applicable to BAT limitations for the voluntary incentives program.
Section 11—Pollutants Selected for Regulation

11-8

11.1.2 Combustion Residual Leachate

The final rule establishes BAT limitations for combustion residual leachate to the current 

BPT limitations on TSS for low volume waste sources, and NSPS limitations for arsenic and 

mercury in discharges of new sources of combustion residual leachate based on a chemical 

precipitation system. The NSPS-regulated pollutant selection criteria matrix for the 25 POCs in 

combustion residual leachate is illustrated in Table 11-3. The following discussion explains the 

rationale EPA used to select which of the 25 POCs to regulate under NSPS for the final rule. 

EPA acknowledges that a POC may fall under more than one criterion for exclusion as a 

regulated pollutant (i.e., a pollutant may not be effectively treated by the NSPS technology basis 

and could also used as a treatment chemical). 

• Conventional Pollutants: EPA identified TSS as a POC. EPA set BAT limitations on 

combustion residual leachate from small generating units and oil-generating units 

equal to the BPT limitations on TSS for low volume waste sources. EPA determined 

that TSS is adequately controlled by existing BPT limitations (based on low volume 

waste sources). 

• 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 NSPS Technology: EPA eliminated five 

pollutants, boron, chloride, selenium, sulfate, and TDS, because the technology basis 

for the combustion residual leachate effluent standards is not demonstrated to reliably 

treat these pollutants.

• Pollutants Directly Regulated or Controlled by Regulation of Other Pollutants: The 

remaining pollutants of concern are all metals, metalloids, or other nonmetals. As 

explained above for FGD wastewater, chemical precipitation is effective at removing 

metals present in wastewater, especially when both hydroxide and sulfide 

precipitation mechanisms are used, which is part of the basis for the NSPS 

technology. EPA selected arsenic and mercury as regulated pollutants and as 

indicators of effective removals of many other POCs present in combustion residual 

leachate, such as magnesium and manganese.
Section 11—Pollutants Selected for Regulation

11-9

Table 11-3. Pollutants Considered for Regulation for Direct Dischargers (NSPS): Combustion Residual Leachate

Pollutant Group Pollutant of Concern Treatment Chemical

Not Effectively Treated by 

the NSPS Technology

Directly Regulated or 

Controlled by Regulation of

Another Parameter

Priority Pollutants

Antimony 

Arsenic 

Cadmium 

Chromium 

Copper 

Mercury 

Nickel 

Selenium 

Thallium 

Zinc 

Nonconventional Pollutants

Aluminum 

Barium 

Boron 

Calcium 

Chloride 

Cobalt 

Iron 

Magnesium 

Manganese 

Molybdenum 

Sodium 

Sulfate 
Section 11—Pollutants Selected for Regulation

11-10

Table 11-3. Pollutants Considered for Regulation for Direct Dischargers (NSPS): Combustion Residual Leachate

Pollutant Group Pollutant of Concern Treatment Chemical

Not Effectively Treated by 

the NSPS Technology

Directly Regulated or 

Controlled by Regulation of

Another Parameter

Total Dissolved Solids 

Nonconventional Pollutants Vanadium 

Note: The conventional pollutants identified as POCs for combustion residual leachate (O&G and TSS) are not included in the table because conventional 

pollutants are not regulated under NSPS.
Section 11—Pollutants Selected for Regulation

11-11

11.1.3 Gasification Wastewater

The final rule establishes BAT and NSPS limitations and standards for four pollutants: 

arsenic, mercury, selenium, and TDS. These limitations and standards are based on an 

evaporation system for direct dischargers. The regulated pollutant selection criteria matrix for the 

34 POCs in gasification wastewater is illustrated in Table 11-4. The following discussion 

explains the rationale EPA used to select which of the 34 POCs to regulate under BAT/NSPS for 

the final rule.

• Conventional Pollutants: EPA identified biochemical oxygen demand (5-day) (BOD5) 

and TSS as POCs. TSS is adequately controlled by existing BPT limitations (based on 

low volume waste sources). BOD5 is not subject to BAT limitations.

• Pollutants Not Effectively Treated by the BAT/NSPS Technology: EPA eliminated 

six pollutants, ammonia, chemical oxygen demand (COD), cyanide, nitrate/nitrite as 

N, phosphorus, and total Kjeldahl nitrogen (TKN), because the technology basis for 

the gasification wastewater effluent limitations and standards is not demonstrated to 

reliably treat these pollutants in gasification wastewater.

• Pollutants Directly Regulated or Controlled by Regulation of Other Pollutants: The 

remaining pollutants are metals, metalloids, other nonmetals, salt ions (i.e., chloride 

and sulfate), and TDS. EPA selected three metals, arsenic, mercury, and selenium, to 

represent different volatilities of pollutants and act as indicator pollutants for other 

pollutants. EPA also selected TDS for regulation as an indicator of pollutants (e.g., 

sodium, chloride, bromide) present in the wastewater.
Section 11—Pollutants Selected for Regulation

11-12

Table 11-4. Pollutants Considered for Regulation for Direct Dischargers (BAT/NSPS): Gasification Wastewater

Pollutant Group Pollutant of Concern Treatment Chemical

Not Effectively Treated

by the BAT/NSPS 

Technology

Directly Regulated or 

Controlled by Regulation 

of Another Parameter

Priority Pollutants

Antimony 

Arsenic 

Beryllium 

Cadmium 

Copper 

Cyanide 

Lead 

Mercury 

Nickel 

Selenium 

Thallium 

Zinc 

Nonconventional Pollutants

Aluminum 

Ammonia 

Barium 

Boron 

Calcium 

Chemical Oxygen Demand 

Chloride 

Cobalt 

Iron 
Section 11—Pollutants Selected for Regulation

11-13

Table 11-4. Pollutants Considered for Regulation for Direct Dischargers (BAT/NSPS): Gasification Wastewater

Pollutant Group Pollutant of Concern Treatment Chemical

Not Effectively Treated

by the BAT/NSPS 

Technology

Directly Regulated or 

Controlled by Regulation 

of Another Parameter

Nonconventional Pollutants

Magnesium 

Manganese 

Molybdenum 

Nitrate/Nitrite as N 

Nitrogen, Kjeldahl (TKN) 

Phosphorus 

Sodium 

Sulfate 

Titanium 

Total Dissolved Solids 

Vanadium 

Note: The conventional pollutants identified as POCs for gasification wastewater (BOD5 and TSS) are not included in the table because conventional pollutants 

are not regulated under BAT or NSPS limitations and standards.
Section 11—Pollutants Selected for Regulation

11-14

11.2 REGULATED POLLUTANT SELECTION METHODOLOGY FOR INDIRECT DISCHARGERS

Before establishing pretreatment standards for existing sources (PSES) or pretreatment 

standards for new sources (PSNS) for a pollutant, EPA examines whether the pollutant “passes 

through” a publicly owned treatment works (POTW) to waters of the U.S. or interferes with the 

POTW operation or sludge disposal practices. In determining whether a pollutant passes through 

POTWs for these purposes, EPA generally compares the percentage of a pollutant removed by 

well-operated POTWs performing secondary treatment to the percentage removed by the 

BAT/NSPS technology basis. 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 the BAT/NSPS technology basis. Pretreatment standards are established 

for those pollutants regulated under BAT/NSPS that pass through POTWs.

Under this rule, for those wastestreams regulated with a zero discharge standard, EPA set 

the percentage removed by the technology basis at 100 percent. Because a POTW would not be 

able to achieve 100 percent removal of wastewater pollutants, it is appropriate to set PSES as 

zero discharge; otherwise, pollutants would pass through the POTW. 

For wastestreams for which EPA established numerical limitations, EPA determined the 

pollutant percentage removed by the rule’s technology basis for pollutants selected for regulation 

for BAT (PSES) or NSPS (PSNS). The following pollutants were not analyzed for pass through 

even if selected for regulation under BAT/NSPS: BOD5, TSS, and oil and grease. POTWs are 

designed to treat these pollutants; therefore, they were not considered to pass through.

The following sections present the POTW pass-through analysis:

• Methodology for determining BAT percent removals.

• Methodology for determining POTW percent removals. 

• Results of the POTW pass-through analysis.

11.2.1 Methodology for Determining BAT Percent Removals

EPA calculated percent removals for each selected technology option using the same data 

it used to determine the long-term averages (LTAs) and effluent limitations and standards for the 

selected BAT or NSPS technology. Therefore, EPA subjected the data used to calculate the 

treatment technology percent removals to the same data editing criteria as the data used to 

establish the effluent limitations and standards (see Section 13).

1. For each pollutant and each 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 and for each model plant from 

the site-specific average influent and effluent concentrations using the following 

equation:
Section 11—Pollutants Selected for Regulation

11-15

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 or NSPS technology 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). [U.S. EPA, 1982]

• National Risk Management Research Laboratory (NRMRL) Treatability Database, 

Version 5.0, February 2004 (formerly called the Risk Reduction Engineering 

Laboratory (RREL) database). [U.S. EPA, 2004]

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 use secondary treatment to 

remove pollutants. EPA edited the data to minimize the possibility that low POTW removals 

might simply reflect low influent concentrations instead of treatment effectiveness. Below are 

the criteria used in editing the 50-POTW study data for this:

1. Substitute the standardized pollutant-specific minimum analytical detection limit 

(ML) for values reported as “not detected,” “trace,” “less than (followed by a 

number),” or a number less than the ML.

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.

3. If none of the average pollutant influent concentrations are at least 10 times the 

pollutant ML, then retain average influent values greater than or equal to two times 

the pollutant ML along with corresponding effluent data.

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, which are two times the pollutant ML and 10 times the pollutant ML, 

respectively.

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 under the BAT level of control that were not found in the 50-POTW 
Section 11—Pollutants Selected for Regulation

11-16

database (i.e., selenium and nitrate/nitrite as N), 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 wastewater was used.

3. Pilot-scale and full-scale data were used, while bench-scale data were eliminated.

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 selenium and nitrate compounds for nitrate/nitrite as N.

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 sections 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 wastestreams with 

zero discharge limitations or standards. Zero discharge limitations and standards achieve 100 

percent removal of pollutants; therefore, all pollutants in those wastestreams pass through the 

POTW. 

FGD Wastewater

The technology basis for PSES for FGD wastewater is chemical precipitation followed by 

biological treatment. Table 11-5 presents the BAT treatment technology percent removals and 

POTW removals for FGD wastewater. Because the FGD wastewater BAT effluent limitations 

and standards for arsenic and mercury were transferred from the chemical precipitation system, 

EPA performed the pass-through analysis for arsenic and mercury based on the pollutant 

removals achieved by the chemical precipitation system. All four regulated pollutants were 

determined to pass through POTW secondary treatment and EPA selected them as regulated 

pollutants for PSES.
Section 11—Pollutants Selected for Regulation

11-17

Table 11-5. POTW Pass-Through Analysis (FGD Wastewater) – PSES

Pollutant

Median BAT % 

Removal POTW % Removal

BAT % Removal > 

POTW % 

Removal?

Does Pollutant 

Pass Through?

Arsenic 98.9% a 65.8% Yes Yes

Mercury 99.9% a 90.2% Yes Yes

Nitrate/Nitrite as N 98.7% 90.0% Yes Yes

Selenium 99.8% 34.3% Yes Yes

Source: ERG, 2015.

a – The arsenic and mercury BAT percent removals are based on the chemical precipitation treatment, because the 

BAT effluent limitations were transferred from the chemical precipitation system.

The technology basis for PSNS for FGD wastewater is evaporation. EPA calculated the 

NSPS treatment technology percent removals based on the one plant currently operating the 

technology basis. EPA compared the median percent removal to the POTW removals for FGD 

wastewater. Table 11-6 presents the NSPS treatment technology percent removals and POTW 

removals for FGD wastewater. All four regulated pollutants were determined to pass through 

POTW secondary treatment and EPA selected them as regulated pollutants for PSNS.

Table 11-6. POTW Pass-Through Analysis (FGD Wastewater) – PSNS

Pollutant

Median NSPS % 

Removal POTW % Removal

NSPS % Removal > 

POTW % 

Removal?

Does Pollutant 

Pass Through?

Arsenic 96.3% 65.8% Yes Yes

Mercury 99.9% 90.2% Yes Yes

TDS a 99.9% 0% Yes Yes

Selenium 99.2% 34.3% Yes Yes

Source: ERG, 2015.

a – EPA does not expect POTWs to effectively remove TDS; therefore, EPA set POTW percent removal for TDS to 

zero and assumed this POC passes through POTW secondary treatment.

Combustion Residual Leachate

The technology basis for PSNS for combustion residual leachate is chemical 

precipitation. As explained further in Section 13, EPA is transferring the effluent standards for 

combustion residual leachate from the chemical precipitation technology option for FGD 

wastewater. Therefore, for arsenic and mercury, the technology basis percent removals for 

combustion residual leachate are based on the removals achieved by the chemical precipitation 

system for FGD wastewater. Table 11-7 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 establishing PSNS for both pollutants.
Section 11—Pollutants Selected for Regulation

11-18

Table 11-7. POTW Pass-Through Analysis (Combustion Residual Leachate) – PSNS

Pollutant

Median BAT % 

Removal POTW % Removal

BAT % Removal > 

POTW % 

Removal?

Does Pollutant Pass 

Through?

Arsenic 98.9 % a 65.8% Yes Yes

Mercury 99.9% a 90.2% Yes Yes

Source: ERG, 2015.

a – The arsenic and mercury BAT percent removals are based on FGD wastewater chemical precipitation treatment, 

because the NSPS were transferred from the FGD wastewater chemical precipitation system.

Gasification Wastewater

The technology option for gasification wastewater is evaporation. Table 11-8 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 

establishing PSES and PSNS for all four pollutants.

Table 11-8. 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

Source: ERG, 2015.

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. 1982. U.S. Environmental Protection Agency. Fate of Priority Pollutants 

in Publicly Owned Treatment Works. EPA 440/1-82/303. Washington, DC. 

(September).

3. U.S. EPA. 2004. National Risk Management Research Laboratory (NRMRL) 

Treatability Database, Version 5.0. (February). 

4. ERG. 2015. Eastern Research Group. Pass-through analysis summary (spreadsheet). 

(30 September). DCN SE05896.
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 (CWA) require EPA to consider non-water quality 

environmental impacts (NWQIs), including energy impacts, associated with effluent limitations 

guidelines and standards (ELGs). Accordingly, EPA has considered the potential impact of the 

final rule on energy consumption (including fuel usage), air emissions, and solid waste

generation.133 In addition, EPA evaluated the effects associated with water use. 

EPA determined that the NWQIs associated with the ELGs are acceptable. The sections 

below summarize the NWQIs associated with the ELG requirements for FGD wastewater, 

combustion residual leachate, and fly ash and bottom ash transport water. Because all plants 

generating flue gas mercury control (FGMC) wastewater and gasification wastewater currently 

operate the technologies identified as the basis for BAT, the ELGs will not result in any net 

increase of energy or fuel usage, solid waste generation, or air emissions for these wastestreams. 

As described throughout this section, although the ELGs will result in increases of energy and 

fuel usage, solid waste generation, and air emissions, the increases are small compared to 

national levels of energy/fuel usage, current air emissions from power plants, and current solid 

waste generation from steam electric power plants.

134 In addition, EPA evaluated the effect of 

the technology options on water use and found that the resulting reductions or elimination of 

water use would lead to improvements in water availability in water-stressed areas.

12.1 ENERGY REQUIREMENTS

Steam electric power plants use energy (including fuel) when transporting ash and other 

solids on or off site, operating wastewater treatment systems, operating ash handling systems, or 

operating water trucks for dust suppression. For those plants that are projected to incur costs 

associated with the final rule, 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 or equipment operation. Similarly, as applicable, EPA also estimated 

the decrease in energy use that would result from ceasing wet-sluicing operations and reduced 

use of earthmoving equipment. EPA summed the plant-specific estimate to calculate the net 

increase in energy requirements for the regulatory options considered for the final rule.

To determine potential increases in electrical energy use, EPA estimated the amount of 

energy needed to operate wastewater treatment systems and dry or closed-loop ash handling 

systems. EPA estimated electrical energy use from horsepower ratings of system equipment 

(e.g., pumps, mixers, silo unloading equipment). See EPA’s Incremental Costs and Pollutant 

 133 EPA also evaluated the effect of this rule on energy and fuel usage, solid waste generation, and air emissions for 

new sources. For more information on the NWQIs that EPA evaluated for new sources, see EPA’s memorandum 

“Steam Electric Non-Water Quality Impacts for New Sources” [ERG, 2015a].

134 The final rule will also result in decreases of air emissions for certain pollutants.
Section 12—Non-Water Quality Environmental Impacts

12-2

Removals for the Final 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 needed to operate wastewater treatment systems and dry or closed-loop ash 

handling systems [U.S. EPA, 2015a]. To determine potential decreases in electrical energy use,

EPA estimated the amount of energy saved from ceasing wet-sluicing operations, including the 

wet-sluicing handling system equipment and earthmoving equipment (e.g., front-end loader)

operation at applicable surface impoundments. EPA estimated electrical energy use from 

horsepower ratings of wet-sluicing system pumps and the earthmoving equipment engine. EPA 

estimated energy savings associated with only earthmoving equipment for plants sending FGD 

solids, fly ash, or bottom ash to surface impoundments. See EPA’s memorandum “Steam 

Electric Effluent Guidelines Non-Water Quality Impacts” for more information on the specific 

calculations used to estimate energy savings from ceasing wet-sluicing operations [ERG, 

2015b].Table 12-1 presents the net annual change in annual electrical energy usage associated 

with the main regulatory options considered for the final regulation. Table 12-2 adjusts the 

results shown in Table 12-1, accounting for expected closures related to the implementation of 

the proposed Clean Power Plan (CPP) (referred to hereafter as “Accounting for CPP”).

Energy usage also includes the fuel consumption associated with transportation. EPA 

estimated the need for increased transportation of solid waste and combustion residuals (e.g., 

ash) at steam electric power plants to on-site or off-site landfills, based on plant-specific data,

using open dump trucks. In general, EPA calculated fuel usage based on the estimated amount of 

time spent loading and unloading solid waste and combustion residuals and the fuel consumption 

during idling plus the estimated total transportation distance, number of trips required per year to 

dispose of the solid waste and combustion residuals, and fuel consumption. 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 landfill, and its estimated 

distance from the plant, determines the length of travel time. See EPA’s memorandum “Steam 

Electric Effluent Guidelines Non-Water Quality Impacts” for more information on the specific 

calculations used to estimate fuel consumption associated with the transport and disposal of solid 

waste and combustion residuals [ERG, 2015b].

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 the Final Effluent 

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

Category report for more information on the specific calculations used to estimate water truck

fuel usage [U.S. EPA, 2015a]. Table 12-1 shows the net change in national annual fuel 

consumption associated with the main regulatory options considered for the final rule. Table 

12-2 adjusts the results shown in Table 12-1, accounting for CPP.
Section 12—Non-Water Quality Environmental Impacts

12-3

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

Non-Water Quality 

Impact

Energy Use Associated with ELG

Option A Option B Option C Option D Option E

Electrical Energy Usage

(MWh) 59,400 140,000 248,000 339,000 373,000

Fuel

(Gallons Per Year 

(GPY)) 168,000 169,000 498,000 758,000 766,000

Table 12-2. Industry-Level Energy Requirements by Regulatory Option, Accounting for 

CPP

Non-Water Quality 

Impact

Energy Use Associated with ELG

Option A Option B Option C Option D Option E

Electrical Energy Usage

(MWh) 51,700 102,000 187,000 237,000 264,000

Fuel

(GPY) 133,000 134,000 442,000 556,000 563,000

To provide some perspective on the potential net increase in annual electric energy 

consumption associated with the regulatory options, EPA compared the estimated increase in 

energy usage (MWh), as shown in Table 12-1 and Table 12-2, 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 selected BAT and PSES regulatory option (Regulatory Option D) is 

less than 0.01 percent of the total electricity generated by all electric power plants in 2009 [ERG, 

2015b].

Similarly, EPA compared the additional net fuel consumption (gallons) estimated for the 

regulatory options, as shown in Table 12-1 and Table 12-2, to national fuel consumption 

estimates for motor vehicles in the United States. 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 Regulatory Option D for BAT and PSES will be 0.002

percent of total fuel consumption by all motor vehicles in the United States [ERG, 2015b].

12.2 AIR EMISSIONS POLLUTION

The final rule is expected to affect air pollution through three main mechanisms:

• Additional auxiliary electricity use by steam electric power plants to operate 

wastewater treatment, ash handling, and other systems needed to comply with the 

ELGs.

• Additional transportation-related emissions due to the increased trucking of 

combustion residual waste to landfills.
Section 12—Non-Water Quality Environmental Impacts

12-4

• The change in the profile of electricity generation due to relatively higher costs to 

generate electricity at plants incurring compliance costs for the ELGs.

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 Final Effluent Limitations 

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

additional discussion of the third mechanism [U.S. EPA, 2015b].

Air pollution is generated when fossil fuels are combusted. In addition, steam electric 

power plants generate air emissions from operating transport vehicles, such as dump trucks and 

vacuum trucks, dust suppression water trucks, and earthmoving 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.135 Conversely, decreasing energy use or vehicle 

operation will result in decreased air pollution.

EPA calculated air emissions resulting from increased auxiliary electricity using yearexplicit emission factors projected by the Integrated Planning Model (IPM)136 for CO2, NOx, and 

SO2. The IPM output provides emission factors by plant and North American Electric Reliability 

Corporation (NERC) region that EPA used to determine potential changes in air emissions under 

the final rule. EPA used three IPM run years to reflect variance in annual air emission factors at 

different stages after rule implementation for years 2020, 2025, and 2030. These IPM outputs 

were used to estimate plant-specific and NERC region emission factors for the corresponding 

IPM run years. 

EPA assumed that plants with capacity utilization rates (CUR) of 90.4 percent or less

would generate the additional auxiliary electricity on site and therefore estimated emissions 

using plant-specific and year-explicit emission factors obtained from IPM outputs.

137

EPA assumed that plants with CUR greater than 90.4 percent would draw additional 

electricity for auxiliary power from the grid within the NERC region instead of generating it on 

site. These plants will be using part of its existing generation to power equipment; however, 

other plants within the same NERC region would need to generate electricity to compensate for 

this reduction and meet electricity demands. Therefore, EPA used NERC-average emission 

factors for each year instead of plant-specific emissions factors. 

 135 EPA did not specifically evaluate nitrous oxide emissions as part of the NWQI analysis. To avoid double 

counting air emission estimates, EPA calculated only nitrogen oxide emissions, which would include nitrous oxide 

emissions. 

136 IPM is a comprehensive electricity market optimization model that can evaluate cost and economic impacts 

within the context of regional and national electricity markets. IPM is used by EPA to analyze the projected impact 

of environmental policies on the U.S. power sector.

137 Emission factors are calculated as plant-level emissions divided by plant-level generation.
Section 12—Non-Water Quality Environmental Impacts

12-5

EPA calculated NOX, CO2, and SO2 emissions resulting from changes in auxiliary power 

use based on the incremental auxiliary power electricity consumption, the pollutant-specific 

emission factors, and the timing plants are assumed to install the compliance technology between 

2019 and 2023 and start incurring additional electricity consumption. Similarly, EPA estimated 

the average emission factors for the United States for these three time periods. See the 

memorandum entitled “Steam Electric Effluent Guidelines Non-Water Quality Impacts” [ERG, 

2015b] for more information about EPA’s methodology for estimating air emissions and IPM’s 

emission factors for each regulatory option.

Because IPM was run for Regulatory Options B and D only, EPA used IPM emission 

factors for Regulatory Option B to estimate changes in auxiliary power air emissions for 

Regulatory Option A and IPM emissions factors for Regulatory Option D to estimate changes in 

auxiliary power air emissions for Regulatory Options C and E. The NWQI air emissions 

associated with changes in auxiliary power presented in this document correspond to the year 

2025. EPA selected 2025 because it is the closest run year to the implementation of the rule. 

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 NOx, CO2, and 

SOX. 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 the Final Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category for more specific 

information on the assumptions EPA made for year of the vehicle and annual mileage 

accumulation [U.S. EPA, 2015a]. 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 lists 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

NOX Highway 

(ton/mi) NOX Local (ton/mi)

SOX

(ton/mi) CO2 (ton/mi)

CH4

(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 pollutants except nitrogen oxides.

EPA calculated the air emissions associated with increased operation of transport

vehicles estimated for the regulatory options using the transportation pollutant-specific emission 

rate per mile, the estimated round trip distance to and from the on-site or off-site landfill, and the 

number of calculated trips for one year in the transportation methodology to truck all solid waste 

or combustion residuals to the on-site or off-site landfill.

EPA estimated the annual number of miles that dump or vacuum trucks moving ash or 

wastewater treatment solids to on- or off-site landfills would travel to comply with limits 
Section 12—Non-Water Quality Environmental Impacts

12-6

associated with the main regulatory options. In addition to the trucks transporting the additional 

solid waste, EPA also estimated the annual number of miles that water trucks spraying water 

around landfills and ash unloading areas to control dust would travel. EPA used these estimates 

to calculate the net increase in air emissions for this rulemaking. See EPA’s memorandum 

“Steam Electric Effluent Guidelines Non-Water Quality Impacts” for more information on the 

specific calculations used to estimate transport distance and number of trips per year [ERG, 

2015b]. 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. Table 12-5 adjusts the 

results shown in Table 12-4, accounting for CPP.

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

Transportation by Regulatory Option

Non-Water Quality 

Impact

Air Emissions Associated with the ELG

Option A Option B Option C Option D Option E

NOX

(tons/year) 34.8 71.5 141 196 215

SOX

(tons/year) 44.3 93 158 212 236

CO2

(metric tons/year) 49,300 104,000 194,000 244,000 268,000

CH4

(tons/year) 0.866 1.96 3.54 4.86 5.32

Table 12-5. Industry-Level Air Emissions Associated with Auxiliary Electricity and 

Transportation by Regulatory Option, Accounting for CPP

Non-Water Quality 

Impact

Air Emissions Associated with the ELG

Option A Option B Option C Option D Option E

NOX

(tons/year) 31.1 60.0 118 167 186

SOX

(tons/year) 42.7 86.7 148 196 220

CO2

(metric tons/year) 45,800 90,600 169,000 213,000 237,000

CH4

(tons/year) 0.745 1.43 2.68 3.40 3.77

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 ELG using data from 

IPM. IPM predicts changes in electricity generation due to costs to comply with the regulatory 

options. Therefore, EPA predicts that these changes, either increases or decreases, in electricity 

generation affect the air emissions from steam electric power plants. EPA estimated only the 

changes associated with the IPM predications, one of the three air emission mechanisms, for 

Regulatory Options B and D. The net changes in industry-level annual air emissions associated 

with the selected regulatory options are shown in Table 12-6. Table 12-7 adjusts the results 

shown in Table 12-6, accounting for CPP.
Section 12—Non-Water Quality Environmental Impacts

12-7

Table 12-6. Industry-Level Net Air Emissions for Regulatory Options B and D

Non-Water Quality Impact

Air Emissions Associated with the ELG

Option B Option D

NOx

(tons/year) -3,250 -11,400

SOx

(tons/year) -435 2,450

CO2

(metric tons/year) -1,330,000 -2,310,000

CH4

(tons/year) 1.96 4.86

Table 12-7. Industry-Level Net Air Emissions for Regulatory Options B and D, 

Accounting for CPP

Non-Water Quality Impact

Air Emissions Associated with the ELG

Option B Option D

NOx

(tons/year) -3,260 -11,400

SOx

(tons/year) -441 2,430

CO2

(metric tons/year) -1,350,000 -2,340,000

CH4

(tons/year) 1.43 3.40

To provide some perspective on the potential increase in annual air emissions associated 

with the regulatory options, EPA compared the estimated increase in air emissions associated 

with Regulatory Options B and D to the net amount of air emissions generated in a year by all 

electric power plants throughout the United States. Table 12-8 presents the 2009 emissions 

generated by the electric power generating industry, based on eGRID, and the percentage of 

increased emissions associated with the final rule [U.S. EPA, 2012a]. Table 12-9 adjusts the 

results shown in Table 12-8, accounting for CPP.
Section 12—Non-Water Quality Environmental Impacts

12-8

Table 12-8. Electric Power Industry Air Emissions

Non-Water Quality 

Impact

Value Associated with 

Selected Regulatory Option

(Million Tons)

2009 Emissions by Electric 

Power Generating Industry

(Million Tons)

Increase In Emissions

(%)

Option B

NOx -0.00325 1 -0.326

SOx -0.000435 6 -0.00724

CO2 -1.46 2,403 -0.0612

CH4 0.00000195 95 0.00000206

Option D

NOx -0.0114 1 -1.16

SOx 0.00245 6 0.0408

CO2 -2.55 2,403 -0.106

CH4 0.00000485 95 0.0000051

Table 12-9. Electric Power Industry Air Emissions, Accounting for CPP

Non-Water Quality 

Impact

Value Associated with 

Selected Regulatory Option

(Million Tons)

2009 Emissions by Electric 

Power Industry

(Million Tons)

Increase In Emissions

(%)

Option B

NOx -0.00326 1 -0.327

SOx -0.000441 6 -0.00735

CO2 -1.48 2,403 -0.0618

CH4 0.00000143 95 0.00000151

Option D

NOx -0.0114 1 -1.16

SOx 0.00243 6 0.0406

CO2 -2.58 2,403 -0.108

CH4 0.0000034 95 0.00000358

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, vapor compression 

evaporation). The regulatory options evaluated would increase the amount of solid waste 

generated from FGD and combustion residual leachate wastewater treatment, including sludge 

from chemical precipitation and/or biological treatment. EPA estimated the amount of solid 

waste generated from each technology for each plant and estimates that the BAT/PSES 

regulatory options (Regulatory Options A through E) would increase solids generated annually 

from treatment. Fly and bottom ash are also solid wastes generated at steam electric power 

plants. The regulatory options for BAT and PSES are; however, not expected to alter the amount 

of ash or other combustion residuals generated.
Section 12—Non-Water Quality Environmental Impacts

12-9

See Sections 6 and 9 of EPA’s report titled Incremental Costs and Pollutant Removals for 

the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category for the specific FGD and combustion residual leachate sludge 

generation calculations, respectively [U.S. EPA, 2015a]. The net change in national annual 

sludge production associated with the regulatory options is shown in Table 12-10. Table 12-11

adjusts the results shown in Table 12-10, accounting for CPP.

To provide some perspective on the potential increase in annual solid waste generation 

associated with Regulatory Option D, EPA compared the estimated increase in solid waste 

generation to the amount of solids generated in a year by electric generating 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 regulatory options will be less than 0.001 percent of the total solid waste generated by 

all electric power plants.

Table 12-10. Industry-Level Solid Waste Increases by Regulatory Option

Non-Water Quality 

Impact

Solid Waste Generation with the ELG

Option A Option B Option C Option D Option E

Sludge (Tons/Year) 583,000 596,000 596,000 596,000 794,000

Table 12-11. Industry-Level Solid Waste Increases by Regulatory Option, Accounting for

CPP

Non-Water Quality 

Impact

Solid Waste Generation with the ELG

Option A Option B Option C Option D Option E

Sludge (Tons/Year) 514,000 525,000 525,000 525,000 698,000

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 and bottom ash transport 

water will eliminate or reduce water use associated with wet ash sluicing operating systems. EPA 

estimated the reductions in water use by calculating the amount of ash transport water, 

specifically the amount of water identified as intake process water, that will no longer be 

discharged as part of the final rulemaking. To calculate this reduction, EPA used data from the 

Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric 

Survey) to calculate an average percentage of ash transport water identified as intake water. EPA 

multiplied this percentage by the amount of transport water discharged by each plant to calculate 

the estimated process water reduction. See the memorandum entitled “Steam Electric Effluent 

Guidelines Non-Water Quality Impacts” [ERG, 2015b] for more information.

The technology basis for the selected BAT 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 three plants will choose to reuse some of the FGD 
Section 12—Non-Water Quality Environmental Impacts

12-10

wastewater within the FGD system based on the maximum operating chlorides concentration 

compared to the design maximum chlorides concentration (other plants may also be able to do 

so). To estimate the water reductions associated with the recycled FGD wastewater, EPA used 

data from the Steam Electric Survey to calculate an average percentage of FGD wastewater 

identified as intake 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 the Final Effluent Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category for more information [U.S. EPA, 2015a].

EPA estimates that power plants would reduce the use of water associated with the

implementation of the regulatory options. Table 12-12 presents the expected reduction in process 

water use for each regulatory option evaluated for the ELGs. Table 12-13 adjusts the results 

shown in Table 12-12, accounting for CPP. For a comparison to the estimated amount of intake 

water reduction, Table 12-14 presents the estimated amount of wastewater discharged as 

estimated for the baseline loadings presented in Section 10. 

Table 12-12. Industry-Level Process Water Reduction by Regulatory Option

Non-Water Quality 

Impact

Water Reduction with the ELG

Option A Option B Option C Option D Option E

Water Reduction

(Million Gallons/Day) 44.9 44.9 143 223 223

Table 12-13. Industry-Level Process Water Reduction by Regulatory Option, Accounting 

for CPP

Non-Water Quality 

Impact

Water Reduction with the ELG

Option A Option B Option C Option D Option E

Water Reduction

(Million Gallons/Day) 36.3 36.3 114 155 155

Table 12-14. Estimated Wastewater Discharges at Steam Electric Power Plants

Type of Wastewater

Total Baseline Industry Discharge 

Flow (Million Gallons/Day)

Total Baseline Industry Discharge 

Flow, Accounting for CPP (Million 

Gallons/Day)

FGD Wastewater 41.7 32.4

Ash Transport Water 298-315 214-228

Landfill and Impoundment Leachate 9.09 7.90

Further, EPA’s Office of Policy (OP) National Center for Environmental Economics 

(NCEE) completed a study on the impacts of the Steam Electric ELGs on water withdrawals 

from both surface waterbodies and aquifers in water stressed areas. Because a number of steam 

electric power plants are located in regions that experience regular or intermittent drought 
Section 12—Non-Water Quality Environmental Impacts

12-11

conditions, NCEE analyzed the exposure of steam electric power plants to drought-related 

conditions and quantified the reduced water intake in water-stressed areas. NCEE first analyzed 

plants that would reduce water intake under Regulatory Option D with at least one week of 

water-stressed conditions and found that an annual average of 50 to 53 billion gallons of water 

would no longer be withdrawn from drought-prone areas. Additionally, NCEE analyzed plants 

that would reduce water intake under Regulatory Option D under water-stressed conditions for 5 

to 10 weeks and found that an annual average of 27 to 29 billion gallons of water would no 

longer be withdrawn from drought-prone areas.

NCEE also found that water availability can have several other indirect effects including 

higher electricity prices, increased pollutant emissions, and the impingement and entrainment of

aquatic organisms. For more information, see NCEE’s analysis “Water Withdrawals in Water 

Stressed Areas: Impacts of the Steam Electric Effluent Limitations Guidelines” [NCEE, 2015].

12.5 REFERENCES

1. California Climate Action Registry. 2007. General Reporting Protocol: Reporting 

Entity-Wide Greenhouse Gas Emission, Version 2.2. (March). DCN SE02035.

2. ERG. 2015a. Memorandum to the Steam Electric Rulemaking Record. “Steam 

Electric Effluent Guidelines Non-Water Quality Impacts for New Sources.” 

(September 30). DCN SE05905.

3. ERG. 2015b. Memorandum to the Steam Electric Rulemaking Record. “Steam 

Electric Effluent Guidelines Non-Water Quality Impacts.” (September 30). DCN 

SE05574.

4. NCEE. 2015. National Center for Environmental Economics. Water Withdrawals in 

Water Stressed Areas: Impacts of the Steam Electric Effluent Limitations 

Guidelines. (June). DCN SE05943.

5. U.S. EPA. 2004. U.S. Environmental Protection Agency. 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_Technic

alSupportDocument.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. 2015a. Incremental Costs and Pollutant Removals for Proposed Effluent 

Limitation Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category. (September 30). DCN SE05831.

9. U.S. EPA. 2015b. Benefits and Cost Analysis for the Effluent Limitations Guidelines 

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

(September 30). EPA-821-R-15-005.
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 in the final steam electric ELGs. The effluent limitations guidelines and 

standards are based on long- term average effluent values and variability factors that account for 

reasonable variation in treatment performance within a particular treatment technology over 

time. For simplicity, in the remainder of this section, the final 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 waste stream 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 employing the model treatment technologies (and the associated datasets) forming

the basis for the final limitations. Certain data from these model plants were used to calculate the 

final limitations. Section 13.2 describes why and how EPA either excluded or substituted certain 

data in calculating the limitations. Section 13.3 presents the procedures that EPA used for 

aggregating data. Section 13.4 describes data editing criteria that EPA used to select plant 

datasets in developing the limitations. Sections 13.5 and 13.6 provide an overview of and discuss 

the procedure for estimating the long-term averages, variability factors, and limitations, 

respectively. Section 13.7 describes the rationale for “transferring” limitations in certain cases. 

Sections 13.8 and 13.9 summarize the limitations and engineering review of the limitations, 

respectively.

13.1 DATA SELECTION

In developing the long-term averages, variability factors, and limitations for a particular 

waste stream and a technology option, EPA used wastewater data from plants operating the 

model treatment technology forming the basis for a particular technology option (either Best 

Available Technology Economically Achievable (BAT) or Best Available Demonstrated Control 

Technology (BADCT)). The data sources evaluated include: (i) a sampling program during 

which EPA collected samples (hereafter referred to as “EPA sampling”); (ii) a sampling 

program during which EPA, pursuant to section 308 of the Clean Water Act, directed plants to 

collect samples (hereafter referred to as “CWA 308 sampling”); and (iii) self-monitoring data 

that plants collected and analyzed (hereafter referred to as “plant self-monitoring”).

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 flue gas desulfurization (FGD), combustion residual leachate, and 

gasification waste streams. EPA has used these, or similar criteria, in developing limitations for 

other industries. EPA uses these criteria to select data that reflect performance of the model 

technology in treating the industrial wastes under normal operating conditions. 
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The first criterion requires that the plant have the model technology and that it is 

generally well operated. Applying 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 represented normal operating conditions for 

the plant and equipment. 

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. Applying this criterion enables EPA to select only those plants where the 

commingled wastewaters are not characterized by substantial dilution, sudden large variation in 

wastewater flow rates (i.e., slug loads) that can result in frequent upsets and/or overloads, or 

wastewaters with different types of pollutants than those generated by the waste stream for which 

EPA is establishing effluent limitations.

The third criterion typically ensures that the pollutants are present in the influent at 

sufficient concentrations to evaluate treatment technology effectiveness. To evaluate whether the 

data meet this criterion for the final rule, EPA often uses a long-term average test (or LTA test) 

for plants where EPA possesses both influent and effluent data. EPA has used this test in 

developing regulations for other industries (e.g., the ELGs for the Iron and Steel Point Source 

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, 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 such data do not reflect the 

performance of 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). Consequently, 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.

EPA also applies the fourth criterion in its review of data corresponding to the initial 

commissioning period for treatment systems. When installing a new treatment system, most 

industries undergo a commissioning period to acclimate and optimize the system. During this 

acclimation and optimization process, the effluent concentration values can be highly variable 

with occasional extreme values (high and low). This occurs because the treatment 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 treatment system operators several 
Section 13—Limitations And Standards: Data Selection And Calculation

13-3

weeks or months to gain expertise in operating the new treatment system, which also contributes 

to treatment system variability during the commissioning period. After this initial adjustment 

period, the system should operate at steady state with relatively low variability around a longterm average over many years. Because commissioning periods typically reflect operating 

conditions unique to the first time the treatment system begins operation, EPA generally 

excludes such data in developing the limitations.138 Similarly, power plant decommissioning 

periods represent unique operating conditions associated with the permanent shutdown of the 

power plant, FGD system, and FGD wastewater treatment system,139 and do not represent best 

available control technology economically achievable/new source performance standards 

(BAT/NSPS) level of performance for treatment of FGD wastewater at an operating steam 

electric power plant. Therefore, EPA also excludes data collected during the plant 

decommissioning period in calculating the limitations. 

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. An abbreviated description of the technology options that 

were considered as the basis for numeric effluent limitations more stringent than the previously 

promulgated ELGs in 40 CFR 423 is presented below in this section. See Section 8.2 for a more 

complete discussion of the basis of each of the technology options considered.

For fly ash transport water, bottom ash transport water, and flue gas mercury control 

(FGMC) wastewater, the ELGs require zero discharge of pollutants based on dry handling or 

closed-loop technologies; therefore, EPA did not use effluent concentration data to establish the 

limitations for these waste streams.

 138 Examples of conditions that are typically unique to the initial commissioning period include operator 

unfamiliarity or inexperience with the system and how to optimize/adjust its performance to deal with influent 

wastewater variability and changing conditions, as well as the initial startup of newly installed equipment to ensure 

components operate as intended. 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 (e.g., on the order of days, weeks, or even months). In this latter situation, the plant has 

already established typical operating practices and set points for treatment system components and operators have 

experience operating the treatment system and adjusting its operation to deal with changing conditions. Any 

variability unique to restarting the treatment system can be accommodated, if necessary, by operational practices 

that include closer monitoring of treatment system operating parameters and recirculating any off-specification 

effluent back through the treatment system. 

139 Note that decommissioning periods for an individual generating unit at a multi-unit plant are not the same as a 

plant decommissioning period because wastes from normal operation of the remaining unit(s) will continue. 

Examples of conditions that are unique to the power plant decommissioning periods include the complete shutdown, 

cleaning, decommissioning, and possibly dismantling of the equipment and processes used to generate electricity 

(e.g., boiler operations) which is likely to cause erratic operation of the treatment system. In addition, plant 

decommissioning would include draining and decommissioning the treatment system itself. These conditions differ 

from those associated with the periodic shutdown of generating units and other systems at a plant, whether they be for 

short or extended duration shutdown (e.g., on the order of days, weeks, or even months). In this latter situation, the 

plant has already established typical operating practices and set points for treatment system components and 

operators have experience operating the treatment system and adjusting its operation to deal with changing 

conditions. Any variability unique to the shutdown period can be accommodated, if necessary, by operational 

practices that include closer monitoring of treatment system operating parameters and recirculating any offspecification effluent back through the treatment system.
Section 13—Limitations And Standards: Data Selection And Calculation

13-4

For combustion residual leachate, the final rule establishes limitations for new sources

based on chemical precipitation treatment. The chemical precipitation treatment technology 

option considered for combustion residual leachate is a combination of hydroxide precipitation, 

iron coprecipitation, and sulfide precipitation designed to remove heavy metals. EPA did not 

identify any power plants using that technology to treat combustion residual leachate. Therefore, 

EPA transferred the limitations that EPA calculated based on the use of the chemical 

precipitation technology option to treat FGD wastewater. See Section 13.7 for a detailed 

discussion of the transfer of limitations, and Section 13.7.1 for a discussion specifically about the 

combustion residual leachate limitations.

For FGD wastewater, EPA evaluated three technology options: chemical precipitation (as 

described above for combustion residual leachate); the combination of chemical precipitation 

and anoxic/anaerobic biological treatment; and the combination of chemical precipitation, 

softening, and vapor-compression evaporation. The ELGs establish limitations for existing 

sources (BAT/PSES) based on the combination of chemical precipitation and biological 

treatment (hereafter biological treatment). For the reasons described in Section 13.7.2. EPA 

transferred the limitations for two pollutants (arsenic and mercury) that the Agency calculated 

based on the use of the chemical precipitation technology option to treat FGD wastewater. For 

the other BAT/PSES limitations applicable to FGD wastewater (selenium and nitrate-nitrite as 

N), EPA used data from plants employing the model biological treatment technology. The ELGs 

establish limitations for new sources (NSPS/PSNS) based on the combination of chemical 

precipitation, softening, and vapor-compression evaporation. 

For gasification wastewater, the final rule establishes limitations for new sources based 

on the combination of chemical precipitation, softening, and vapor-compression evaporation.

In certain instances, the final rule establishes limitations for wastewater discharges that 

are equal to previously established best practicable control technology currently available (BPT)

limitations for total suspended solids (TSS). EPA used no new effluent concentration data to 

establish limitations that are set equal to BPT limitations for TSS; therefore, such limitations are 

not discussed in this section. See Section 8 for a more complete discussion of the basis for the 

final regulatory options. 

EPA used specific data sources to calculate the limitations for the different FGD 

wastewater and gasification wastewater treatment technologies. The data sources used to 

calculate effluent limitations for each technology option, by wastestream, are described below.

FGD Wastewater

EPA conducted on-site wastewater sampling, or directed plants to collect samples for 

laboratory analysis by EPA-contracted laboratories, to evaluate the performance of FGD 

wastewater treatment systems at the 10 plants listed below. In some cases, EPA also obtained 

self-monitoring data for the treatment systems at the plants. These plants were selected for 

EPA’s sampling program because the information available to EPA at the start of the sampling 

program indicated that the processes and operations at the plants were representative of other 

plants in the steam electric industry, and that their FGD wastewater treatment systems were 

potential candidates for the technology basis for BAT/BADCT effluent limitations. As described 
Section 13—Limitations And Standards: Data Selection And Calculation

13-5

below, EPA subsequently determined that the treatment systems at some of the plants do not 

reflect the technology bases of the technology options considered for BAT or BADCT.

• Four plants operate chemical precipitation treatment systems that include hydroxide 

precipitation, sulfide precipitation, and iron coprecipitation. These four plants are:

- Duke Energy’s Miami Fort Station (hereafter referred to as Miami Fort).

- RRI Energy’s Keystone Generating Station (hereafter referred to as Keystone).

- Allegheny Energy’s Hatfield’s Ferry Power Station (hereafter referred to as 

Hatfield’s Ferry).

- We Energy’s Pleasant Prairie Power Plant (hereafter referred to as Pleasant 

Prairie).

• Two plants operate a treatment system that includes chemical precipitation followed 

by anoxic/anaerobic biological treatment designed to remove selenium. These two 

plants are:

- Duke Energy Carolina’s Belews Creek Steam Station (hereafter referred to as 

Belews Creek).

- Duke Energy Carolina’s Allen Steam Station (hereafter referred to as Allen). 

• One plant operates a treatment system that includes chemical precipitation followed 

by a sequencing batch reactor (SBR) biological treatment designed to remove 

nutrients, but not selenium. This plant is:

- Mirant Mid-Atlantic’s Dickerson Generating Station (hereafter referred to as 

Dickerson).

• Two plants operate a treatment system that includes vapor-compression evaporation, 

with the evaporation part of the treatment system comprised of two evaporator stages: 

brine concentration and forced-circulation crystallization. These two plants are:

- Enel’s Federico II Power Plant, located in Brindisi, Italy (hereafter referred to as 

Brindisi).

- A2A’s Centrale di Monfalcone Plant, located in Monfalcone, Italy (hereafter 

referred to as Monfalcone).

• One plant operates a treatment system that includes vapor-compression evaporation, 

but with only one stage of evaporation: brine concentration (the resulting brine at this 

plant is mixed with ash and landfilled). This plant is:

‒ Kansas City Power & Light’s Iatan Generating Station (hereafter referred to as 

Iatan).

For the chemical precipitation technology option, EPA evaluated treatment system 

influent and effluent data for the four chemical precipitation plants listed above, as well as 

influent and effluent data for the chemical precipitation treatment stage for the three plants listed 

above that operate some form of biological treatment. The data for these seven treatment 

systems, as well as other data evaluated for the ELGs, showed that chemical precipitation 

systems that include both hydroxide and sulfide precipitation achieve better removals of mercury 
Section 13—Limitations And Standards: Data Selection And Calculation

13-6

and other pollutants than treatment systems that use only hydroxide precipitation. Because of 

this, EPA determined the basis of the technology option should include both hydroxide and 

sulfide precipitation, as well as iron coprecipitation (iron coprecipitation further enhances 

pollutant removals in the treatment system). The only plants that include all elements of the 

technology option are the four chemical precipitation plants (Miami Fort, Keystone, Hatfield’s 

Ferry, and Pleasant Prairie) and, therefore, EPA used the data from these plants to calculate 

effluent limitations for the technology option. None of the three biological treatment plants 

include sulfide precipitation as part of their chemical precipitation treatment stage and, therefore, 

data from Allen, Belews Creek, or Dickerson do not represent treatment that includes all 

elements of the chemical precipitation technology option. Additionally, during the EPA sampling 

episode, the Dickerson plant experienced a significant treatment system upset that adversely 

affected the effluent quality. The sludge bed in the clarifier overturned, releasing previously 

settled solids (particulates, along with formerly dissolved pollutants that had precipitated from 

solution following chemical addition) and increasing the effluent pollutant concentrations. A 

treatment system upset such as this is not indicative of a well-operated system. As a result, EPA 

did not use data from Allen, Belews Creek, or Dickerson to calculate effluent limitations for 

arsenic and mercury for the chemical precipitation technology option.

For the biological treatment technology option, EPA evaluated treatment system influent 

and effluent data for the three biological treatment plants listed above. The biological treatment 

system at Dickerson is a sequencing batch reactor (SBR) designed for nutrient removal and it is 

not designed for effective removal of selenium. EPA’s sampling data confirmed that the SBR 

treatment system does not effectively remove selenium. Because EPA’s basis for the technology 

option includes anoxic/anaerobic biological treatment to remove selenium, and the Dickerson 

plant’s treatment system is not designed to effectively remove this pollutant, EPA did not use 

data from this system in developing the limitations based on biological treatment. The treatment 

systems at Allen and Belews Creek include chemical precipitation followed by anoxic/anaerobic 

biological treatment designed to remove selenium, which is the technology basis for the 

biological treatment technology option. Therefore, EPA used data from Allen and Belews Creek 

to calculate effluent limitations for selenium and nitrate-nitrite as N for the biological treatment 

technology option.140

For the vapor-compression evaporation technology option, EPA evaluated treatment 

system data from three plants: Brindisi, Monfalcone, and Iatan. Brindisi operates a treatment 

system that is the basis for the technology option: a chemical precipitation system followed by 

softening and a vapor-compression evaporation system. EPA used the data from Brindisi to 

develop limitations based on the vapor-compression evaporation technology option for arsenic, 

mercury, selenium, and total dissolved solids (TDS). The Monfalcone plant also operates a 

treatment system that includes the elements that are the basis for the technology option; however,

EPA has only one day of sampling data for this plant. As a result, EPA does not have sufficient 

data from this plant for use in developing effluent limitations. The treatment system at Iatan

(which at the time of EPA’s sampling program was the only plant in the United States using 

evaporation technology to treat FGD wastewater) does not represent the technology that is the 

 140 EPA transferred the limitations for arsenic and mercury for the biological (chemical precipitation followed by

anoxic/anaerobic biological treatment) technology option from the chemical precipitation technology option. See 

Section 13.7.2 for a detailed discussion of the transfer of the limitations.
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13-7

basis for the vapor-compression evaporation technology option and was not used for the 

limitations development. Iatan operates a solids removal process prior to the vapor-compression 

evaporation system, but includes neither a full chemical precipitation system nor a softening step 

to pretreat the wastewater (i.e., to remove a substantial portion of the pollutants, especially the 

dissolved pollutants) prior to sending it to the evaporator. Furthermore, this plant operates a onestage evaporation system and, instead of using 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. At the time of EPA’s sampling program, these were the only two integrated 

gasification combined cycle (IGCC) plant operating in the United States.141

• Tampa Electric Company’s Polk Station (hereafter referred to as Polk).

• Wabash Valley Power Association’s Wabash River Station (hereafter referred to as 

Wabash River).

EPA determined that both Polk and Wabash River use treatment systems that are 

representative of the basis for the vapor-compression evaporation technology option for 

gasification, and thus data from these plants were used to develop the limitations for this 

technology option.

13.1.3 Combining Data from Multiple Sources within a Plant

For this rulemaking, data for most of the model plants came from multiple sources 

including EPA sampling, CWA 308 sampling, or plant self-monitoring. For five plants (Allen, 

Belews Creek, Hatfield’s Ferry, Miami Fort, and Pleasant Prairie), data from multiple sources 

were collected during overlapping time periods and EPA combined these data into a single 

dataset for the plant. For one plant (Keystone), the multiple sources of data were collected during 

non-overlapping time periods. At Keystone, EPA and CWA 308 samples were collected from 

September 2010 through January 2011 and arsenic self-monitoring data were available from 

January 2012 through April 2014. EPA has no information to indicate that these time periods 

represent different operating conditions; therefore, EPA also combined the multiple sources of 

data for Keystone into a single dataset for the plant. This approach is consistent with EPA’s 

traditional approach for other effluent guidelines rulemakings.142 For three plants (Brindisi, Polk, 

 141 A third IGCC plant, Duke Energy’s Edwardsport plant, commenced commercial operation in June 2013. The 

gasification wastewater treatment system at Edwardsport includes evaporation, as well as additional treatment such 

as cyanide destruction. A fourth IGCC plant, Mississippi Power’s Kemper County plant, is projected to begin 

operating in 2016 and reportedly will be a zero discharge plant. 

142 When EPA obtains data from multiple sources (such as the EPA sampling, CWA 308 sampling, and plant selfmonitoring data in this rulemaking) from a plant for the same time period, EPA usually combines the data from 

these sources into a single dataset for the plant for the statistical analyses. In some cases where the sampling data 

from a plant are collected over two or more distinct time periods, EPA may analyze the data from each time period 

separately. In some past effluent guidelines rulemakings, EPA analyzed data as if each time period represented a 
Section 13—Limitations And Standards: Data Selection And Calculation

13-8

and Wabash River) that had data from a single source, it was not necessary to combine data. For 

a list of all the data and their sources (e.g., EPA sampling data) 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, 2015a].

13.2 DATA EXCLUSIONS AND SUBSTITUTIONS

The sections below describe why and how EPA either excluded or substituted certain 

data in calculating the limitations. 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 discussed in Section 13.1.2.

13.2.1 Data Exclusions

After selecting the model plant(s), EPA applied the data selection criteria described 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) the samples 

were analyzed using an analytical method that is not approved in 40 CFR Part 136 for National 

Pollutant Discharge Elimination System (NPDES) purposes; (ii) the samples were analyzed 

using a method that was not a sufficiently sensitive analytical method (e.g., EPA Method 245.1 

for mercury in effluent samples); (iii) the samples were analyzed in a manner that resulted in an 

unacceptable level of analytical interferences; (iv) the samples were collected during the initial 

commissioning period for the treatment system or during the plant decommissioning period; (v) 

the analytical results were identified as questionable due to quality control issues, abnormal 

conditions or treatment upsets, or were analytical anomalies; (vi) the samples were collected 

from a location that is not representative of treated effluent (e.g., secondary clarifier instead of 

final effluent); or (vii) the treatment system was operating in a manner that does not represent 

BAT/NSPS level of performance. See DCN SE05733 for a detailed discussion and list of the 

data that were excluded from development of limitations.

13.2.2 Data Substitutions

In general, EPA used detected values or sample-specific detection limits (i.e., samplespecific quantitation limit, or QL) for non- detected values in calculating the limitations.143

However, there were some instances in which EPA substituted a baseline value for a detected 

value or a sample-specific detection limit that was lower than the baseline value. Baseline 

substitution accounts for the possibility that certain detected or non-detected results may be at a 

lower concentration than generally can be reliably quantified by well-operated laboratories. This 

approach is consistent with the way EPA has calculated limitations in previous effluent 

guidelines rulemakings and is intended to avoid establishing an effluent limitation that could be 

 

different plant when the data were considered to represent fundamentally different operating conditions. This was 

not the case for the Keystone data, so EPA combined all data for the plant into a single dataset. 

143 For the purpose of the discussion of calculating 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 QL.
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biased toward a lower concentration than plants can reliably demonstrate compliance with.144

After excluding all the necessary data as described in Section 13.2.1, EPA compared each 

reported result to a baseline value. Whenever a detected value or sample-specific detection 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 5 micrograms/liter (μg/L) and the laboratory reported a detected value of 3 

μg/L, EPA’s calculations would treat the sample result as being non-detected with a samplespecific detection limit of 5 μg/L.

EPA used the following baseline values for each pollutant in the development of the 

effluent limitations for the steam electric rulemaking:

• Arsenic: 2 μg/L.

• Mercury: 0.5 nanogram/liter (ng/L).

• Nitrate-nitrite as N: 0.05 milligram/liter (mg/L).

• Selenium: 5 μg/L.

• 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.145 The 

baseline values for arsenic and selenium are based on the results of MDL studies conducted by 

well-operated commercial laboratories using EPA Method 200.8 to analyze samples of synthetic 

FGD wastewater [CSC, 2013].

It should be noted that in cases when all concentration values are above the baseline 

value, then the baseline value would have no effect on the concentration values and subsequent

calculated limitations. Effluent data for mercury and TDS were all above the baseline values; 

therefore, EPA did not substitute any baseline values when calculating limitations for these 

parameters. The document entitled Sampling Data Used as the Basis for Effluent Limitations for 

 144 For example, if a daily maximum limit were established at a concentration lower than the baseline value, 

although some laboratories might be able to achieve sufficiently low quantitation levels, it is possible that typical 

well-operated laboratories could not reliably measure down to that level. In such cases, a plant would not be able to 

demonstrate compliance with the limit. A similar situation might arise with monthly average limitations, particularly 

if the limit is at a concentration near the baseline value. EPA does not intend to suggest that the baseline value 

should be established at a level that every laboratory in the country can measure to, or that limitations established for 

the ELGs must be established sufficiently high that every laboratory in the country must be able to measure to that 

concentration; however, it is appropriate to use baseline values that generally can be reliably quantified by welloperated laboratories. This approach achieves a reasonable balance in establishing limitations that are representative 

of treatment system performance and protective of the environment, while at the same time ensuring that plants have

adequate access to laboratories with the analytical capabilities necessary to reliably demonstrate compliance with the 

limitations. 145 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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the Steam Electric Rulemaking [U.S. EPA, 2015a] provides a list of all the effluent data used to 

calculate the limitations, as well as how the values were adjusted using baseline substitution.

In addition to calculating the limitations for each pollutant for each technology option 

adjusting for the baseline values shown above, when appropriate, EPA also calculated effluent 

limitations using all the valid reported results (i.e., without substituting baseline values and/or 

changing the censoring classification of the result). As noted above, the reason for substituting 

baseline values is generally to prevent establishing an effluent limitation that is biased toward a 

lower concentration than plants can reliably demonstrate compliance with. After employing

baseline substitution, the effluent limitation is often unchanged but sometimes is adjusted

upward slightly. For the datasets used in developing limitations for the steam electric ELGs, 

using baseline substitution raised the calculated limitations in a few instances.146 In certain other 

instances, however, EPA found that using baseline substitution had the opposite and unexpected 

effect of lowering the limitations.147 This downward effect on the effluent limitations occurred

because, although using baseline substitution increased the long-term average value slightly, it 

also reduced the variability of the dataset, and the resulting net effect was a lower effluent 

limitation. This means that using baseline substitution in such instances would result in a lower 

effluent limitation than EPA would otherwise calculate directly from the unadjusted dataset. 

Because EPA wanted to ensure that plants can achieve the effluent limitations established by the 

rule, EPA calculated and evaluated both the baseline-adjusted and unadjusted limitations for 

each technology option and used the higher of the two results for the final ELGs. EPA’s 

comparison of the baseline-adjusted and unadjusted effluent limitations is presented in the 

Statistical Support Document: Effluent Limitations for FGD Wastewater, Gasification 

Wastewater, and Combustion Residual Leachate for the Final Steam Electric Power Generating 

Effluent Limitations Guidelines and Standards. 

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 sections below). There are instances in the 

sampling data used in this rulemaking 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 to denote the censoring type for 

detected and non-detected values, respectively.

 146 This occurs for the selenium limitations for gasification wastewater and for FGD wastewater based on 

evaporation technology. 

147 This occurs for selenium and nitrate-nitrite as N in FGD wastewater (based on biological treatment technology)

and for arsenic in FGD wastewater based on chemical treatment technology.
Section 13—Limitations And Standards: Data Selection And Calculation

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The sections 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. 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.

For arsenic at Hatfield’s Ferry and arsenic and mercury from Miami Fort, there were a 

few days with two or three reported self-monitoring samples. These self-monitoring samples 

from the same day were treated as duplicate samples in the calculations. 

In most cases, the duplicate samples 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 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, 2015a].

Table 13-1 summarizes the procedure for aggregating the sample measurements from the 

field duplicates. Aggregating 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 

detection limit (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.
Section 13—Limitations And Standards: Data Selection And Calculation

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13.3.2 Aggregation of Overlapping Samples

At the Allen, Belews Creek, Hatfield’s Ferry, Miami Fort, and Pleasant Prairie plants, 

sampling data were available from EPA sampling, CWA 308 sampling, and plant selfmonitoring. As explained in Section 13.1.3, 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, 2015a].

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 was 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 often uses the LTA test to ensure that the pollutants are present in the influent at sufficient 

concentrations to evaluate treatment effectiveness at the plant for the purpose of calculating 

effluent limitations. By applying 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. For each pollutant for which EPA calculated a limitation, the influent first had 

to pass a basic requirement that 50 percent of the influent measurements for the pollutant 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 percent 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 percent 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,” and it excluded the plant’s effluent data for that pollutant when 

calculating limitations. 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. 
Section 13—Limitations And Standards: Data Selection And Calculation

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After performing the LTA test for the regulated pollutants at each model plant employing 

treatment representing the relevant technology option, EPA found all the datasets passed the 

LTA test except for arsenic and mercury data at Wabash River. Thus, EPA excluded data for 

arsenic and mercury at Wabash River 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 Final 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, 2015b].

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 identify the daily values 

for its limitations 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 discharges on a 

daily basis at a level that is achievable for a plant that targets its treatment at the long-term 

average.148 EPA recognizes that variability around the long-term average occurs during normal 

operations, which means that plants might, at times, discharge at a level that is higher (or lower) 

than the long-term average. To allow for these occasional discharges that are at a higher 

concentration than the long-term average, EPA establishes a daily maximum limitation. A plant 

that consistently discharges at a level near the daily maximum limitation would not be operating 

its treatment system to achieve the long-term average. Targeting treatment to achieve the daily 

maximum limitations, rather than the long-term average, might result in values that frequently 

exceed the limitations due to routine variability in treated effluent.

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 ongoing control, on a 

monthly basis, that supplements controls to achieve the daily maximum limitation. 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. For the plant to 

achieve compliance, these values must result in a monthly average value that is equal to 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 

 148 Put simply, the long-term average is the average concentration that is achieved over a period of time. 

Statistically, the long-term average is the mean of the underlying statistical distribution of the daily effluent values. 

The long-term average is used along with other information about the distribution of the effluent data to calculate 

the effluent limitations.
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enough to reflect a level of performance consistent with the CWA requirement that these effluent 

limitations be based on the best available technology or best available demonstrated control 

technology. 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. 

EPA uses the 99th and 95th percentiles to draw a line at a definite point in the statistical 

distributions that would ensure that plant 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 

reasonably 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 will be able to comply with 

the effluent limitations at all times because EPA has incorporated an appropriate allowance for 

variability in the limitations.

EPA’s methodology for establishing effluent limitations based on certain percentiles of 

the statistical distributions may give the impression that EPA expects occasional exceedances of 

the limitations. This conclusion is incorrect. EPA promulgates limitations that plants are capable 

of complying with at all times by properly operating and maintaining their treatment 

technologies. These limitations are based upon statistical modeling of the data and engineering 

review of the limitations and data. 

Statistical methodology is used as a framework to establish limitations based upon

percentiles of the effluent data. Statistical methods provide a logical and consistent framework 

for analyzing a set of effluent data and determining values from the data that form a reasonable 

basis for effluent limitations. In conjunction with the statistical methods, EPA performs an 

engineering review to verify that the limitations are reasonable based upon the design and 

expected operation of the treatment technologies and the plant process conditions. As part of that 

review, EPA examines the range of performance reflected in the plant datasets used to calculate 

the limitations. The plant datasets represent operation of treatment technology that represents the 

best available technology or best available demonstrated control technology. In some cases, 

however, although these plants were operating model technology, these datasets, or periods of 

time within a dataset, may not necessarily represent the optimized performance of the 

technology. As described in Section 13.2, EPA excluded certain data from the datasets used to 

calculate the effluent limitations. At the same time, however, the datasets used to calculate 

effluent limitations still retain some observations that likely reflect periods of less than optimal 

performance. EPA retained these data in developing the limitations because they help to 

characterize the variability in treatment system effluent. Based on the combined statistical 

modeling and engineering review used to establish the limitations, plants are expected to design 

and operate their treatment systems in a manner that will ensure compliance with the limitations. 

EPA does not expect plants to operate their treatment systems so as to violate the limitations at 

some pre-set rate merely because probability models are used to develop limitations. See Section 

13.9 for details of these comparisons for each pollutant at each plant, as well as a discussion of 

the findings of the engineering review.
Section 13—Limitations And Standards: Data Selection And Calculation

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13.5.3 Compliance with Limitations

EPA promulgates limitations with which plants are able to comply at all times by 

properly operating and maintaining their processes and treatment technologies. Public 

commenters often raise the issue of exceedances or excursions of limitations (i.e., values that 

exceed the limitations), and this rulemaking is no exception. For example, this issue was raised 

in EPA’s rulemaking for the Organic Chemicals, Plastics, and Synthetic Fibers (OCPSF) 

manufacturing industry. EPA’s general approach in that final rule to developing limitations 

based on percentiles is the same as in the final steam electric ELGs, and it was upheld in 

Chemical Manufacturers Association v. U.S. Environmental Protection Agency, 870 F.2d 177, 

230 (5th Cir. 1989):

“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.”

This issue was also raised 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 final rule. EPA’s approach for 

establishing the monthly average limitation was upheld in National Wildlife Federation, et al. v. 

Environmental Protection Agency, 286 F.3d 554, 573 (D.C. Cir. 2002):

“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, 

for example, Rep. No. 92-414, 92d Congress, 2d Sess. 64, reprinted in A Legislative History of 
Section 13—Limitations And Standards: Data Selection And Calculation

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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):

“The court will not second-guess EPA’s expertise with regard to what the 

maximum effluent limits represent. See Nat'l Wildlife, 286 F.3d at 571-73. As 

EPA explains in the Final Development Document, the daily and monthly average 

effluent limitations are not promulgated with the expectation that a plant will 

operate with an eye toward barely achieving the limitations. Final Development 

Document at § 14.6.2. Should a plant do so, it could be expected to exceed these 

limits frequently because of the foreseeable variation in treatment effectiveness. 

Rather, the effluent limitations are promulgated with the expectation that plants 

will be operated with an eye towards achieving the equivalent of the LTA for the 

BAT-1 model technology. Id. However, even operated with the goal of achieving 

the BAT-1 LTA, a plant's actual results will vary. EPA’s maximum daily 

limitations are designed to be forgiving enough to cover the operations of a welloperated model facility 99% of the time, while its maximum monthly average 

limitations are designed to be forgiving enough to accommodate the operations of 

a well-operated model facility 95% of the time. See id. EPA’s choice of percentile 

distribution represented by its maximum effluent limitation under the CWA 

represents an expert policy judgment that is not arbitrary or capricious. See Nat'l 

Wildlife, 286 F.3d at 573” (citation omitted).

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. Exceedances caused by a 

design or operational deficiency, however, are indications that the plant’s performance does not 

represent the appropriate level of control. For the final steam electric ELGs, EPA determined that 

plants can control such exceedances by operating a properly designed treatment system that

includes the necessary process equipment and chemical additives and that is sized to 

accommodate the wastewater flows, and by implementing process and wastewater treatment 

system operational practices such as regular monitoring of influent and effluent wastewater 

characteristics and adjusting dosage rates for chemical additives to target effluent performance 

for regulated pollutants at the long-term average concentration for the BAT/NSPS technology. A 

properly designed and operated treatment system includes characteristics such as periodic

inspection and repair of equipment, use of appropriate redundant equipment such as backup 

pumps, sufficient staffing by trained operators, communications and coordination among 

production and wastewater treatment personnel, close attention to treatment system operating 

parameters and effluent quality, the ability to recognize and correct periods of degraded or 

abnormal operation, and equalization tanks to make wastewater flow and quality more uniform. 

EPA recognizes that, as a result of the final rule, some plants may need to upgrade or 

replace existing treatment systems or improve their treatment systems, process controls, and/or 

treatment system operations to consistently meet the effluent limitations by targeting effluent 
Section 13—Limitations And Standards: Data Selection And Calculation

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concentrations at the long-term average. This is consistent with the CWA, which requires that 

discharge limitations and standards reflect the best available technology economically achievable 

or the best available demonstrated control technology, as well as EPA’s costing approach and its 

engineering judgment developed over years of evaluating wastewater treatment processes at

steam electric power plants and in other industrial sectors.

13.6 CALCULATION OF THE LIMITATIONS

EPA calculated the limitations by multiplying the long-term average by the appropriate 

variability factors. In deriving 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 technology is capable of achieving. This long-term average is 

calculated using data from the model plant (plants with the model technologies) for the 

technology 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 a well-designed and welloperated treatment system(s). This allowance for variation incorporates all components of 

potential variability, including sample collection, sample shipping and storage, and analytical 

variability. EPA incorporates this allowance into the limitations by using the variability factors

that are calculated using data from the model plants. 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 provide an additional assurance that normal fluctuations in a plant’s treatment

process are appropriately 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 above the long-term averages.

The following sections describe derivation of the option long-term averages, option 

variability factors and limitations, and the adjustment made for autocorrelation in the calculation 

of the limitations.

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 to use the statistical 

model, the plant-specific long-term average for each pollutant was the arithmetic mean of the 

available daily concentration values. Appendix B presents an overview of the statistical model 

and describes the procedures EPA used to estimate the plant-specific long-term average.

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 are 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 
Section 13—Limitations And Standards: Data Selection And Calculation

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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 derive 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 at a specific plant, then the statistical model was not used to obtain 

the variability factors for that plant. In these cases, EPA excluded the data for the pollutant at the 

plant from the calculation of the option monthly variability factors. Appendix B describes 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, EPA calculated the daily maximum limitations for each pollutant for each 

technology option by multiplying 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 

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 more similar than measurements taken far apart in time. For example, positive 

autocorrelation would occur if the effluent concentrations 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 were 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 estimate the 

autocorrelation, when there was a correlation of a pollutant available from a similar technology 

and waste stream and the pollutant removal processes were similar, EPA transferred the 

autocorrelation estimates from that treatment technology. Otherwise, EPA set the autocorrelation 

to zero in calculating the limitations, because the Agency did not have sufficient data to reliably 

evaluate whether the data were autocorrelated or to determine whether a valid autocorrelation 
Section 13—Limitations And Standards: Data Selection And Calculation

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estimate could be transferred from a similar technology and waste stream. 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 [Westat, 2015]. The following paragraphs describe the instances where 

EPA was able to estimate autocorrelation and the assumptions made about the autocorrelation 

when there were too few observations to estimate the possible autocorrelation.

For the chemical precipitation treatment option for FGD wastewater (represented by the 

Hatfield’s Ferry, Keystone, Miami Fort, and Pleasant Prairie 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. Table 13-2 lists the autocorrelation 

values used in the limitations calculation for arsenic and mercury for the chemical precipitation 

option.

For the biological treatment technology for FGD wastewater (represented by the 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 incorporated adjustments for autocorrelation 

into the limitations for the biological treatment technology option. Table 13-2 lists the 

autocorrelation values EPA used in the limitations calculation for nitrate-nitrite as N and 

selenium. EPA transferred the arsenic and mercury limitations for the biological treatment 

technology option from the chemical precipitation technology option and therefore incorporated

adjustments to reflect autocorrelation (see Section 13.7).

Table 13-2. Summary of Autocorrelation Values Used in Calculating the Limitations for 

Biological Treatment Technology Option for FGD Wastewater

Treatment 

Technology

Plants Representing the 

Treatment Technology Pollutant

Baseline 

Substitution? a

Correlation Value 

Used for Limit 

Calculation

FGD biological 

treatment Allen, Belews Creek

Selenium

No 0.69

Yes 0.67

Nitrate-nitrite as 

N b

No 0.69

Yes 0.67

FGD chemical 

precipitation 

treatment

Hatfield’s Ferry, 

Keystone, Miami Fort, 

Pleasant Prairie

Arsenic c No

0.86

Yes

Mercury d

No

0.89

Yes

a – As described in Section 13.2.2.

b – There were not enough detected values for nitrate-nitrite as N at Allen and Belews Creek, so EPA was not able 

to evaluate the autocorrelation. However, EPA transferred the autocorrelation from selenium since these two 

chemicals behave similarly in the biological treatment system.

c – EPA estimated the correlation using data from Hatfield’s Ferry.

d – EPA estimated the correlation using data from Hatfield’s Ferry, Miami Fort, and Pleasant Prairie.
Section 13—Limitations And Standards: Data Selection And Calculation

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For the vapor-compression evaporation treatment technology option for FGD wastewater 

(represented by the Brindisi plant), and for the vapor-compression evaporation treatment 

technology option for gasification wastewater (represented by the Polk and Wabash River

plants), EPA was unable to evaluate 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 calculating the limitations because the Agency did not have sufficient 

data to reliably evaluate the autocorrelation or a valid correlation estimate available that could be 

transferred from a similar technology and waste stream.

13.7 TRANSFERS OF THE LIMITATIONS

In some cases, there were no data available for a particular treatment technology option

for a wastestream or EPA determined that the treatment provided by plants using the model 

technology did not fully reflect the performance achievable by operation of all components of the

technology on which the option is based. In these cases, EPA “transferred” limitations for that 

particular technology option from limitations that were calculated using other reliable and 

relevant data. EPA has transferred limitations in other ELG rulemakings, including transferring 

limitations derived from data representing the use of the model technology in an entirely other 

industry. In these cases, transfer of limitations is appropriate where EPA can show that the 

technology is available to the industry, that the technology is transferable to the industry, and 

that the technology is capable of removing the increment required by the limitations. Kennecott 

v. EPA, 780 F.2d 445, 453 (4th Cir. 1985); Reynolds Metals Co. v. EPA, 760 F.2d 549, 561-2 

(4th Cir. 1985).

The following sections describe the two cases in which the limitations in this rulemaking

were transferred: (1) the final new source performance standards (NSPS) applicable to 

combustion residual leachate (based on chemical precipitation), which were transferred from 

limitations derived using data representing treatment of FGD wastewater via chemical 

precipitation and (2) for two out of four pollutants, the final BAT limitations and pretreatment 

standards for existing sources (PSES) applicable to FGD wastewater (based on biological 

treatment), which were also transferred from limitations derived using data representing 

treatment of FGD wastewater via chemical precipitation.

13.7.1 Transfer of Arsenic and Mercury Limitations for Chemical Precipitation to 

Combustion Residual Leachate

The final rule establishes NSPS for combustion residual leachate based on the chemical 

precipitation technology option. EPA transferred the effluent limitations for combustion residual 

leachate based on the chemical precipitation technology option from the limitations calculated 

for FGD wastewater based on the chemical precipitation technology option because EPA does 

not have effluent data for combustion residual leachate treated by technology that represents the

chemical precipitation technology option. 

EPA determined that transfer of the limitations in this case was appropriate because the 

chemical precipitation treatment technology is available to the industry, it can be applied to 

combustion residual leachate in the industry, and it can achieve the pollutant removals necessary 

to meet the final limitations. Based on responses to the Questionnaire for the Steam Electric 
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Power Generating Effluent Guidelines, 39 steam electric power plants use some form of 

chemical precipitation as part of their FGD wastewater treatment system.

149 As described earlier, 

four steam electric power plants use a form of chemical precipitation to treat FGD wastewater 

that represents the chemical precipitation technology option. In addition, a wide range of 

industrial plants nationwide, such as metal products and machinery plants, iron & steel 

manufacturers, metal finishers, and mining operations (including coal mines), have demonstrated 

the use of chemical precipitation technology to remove arsenic and mercury [U.S. EPA, 1983; 

U.S. EPA, 2002; U.S. EPA, 2003]. 

Transferring limitations derived using data representing treatment of FGD wastewater via 

chemical precipitation technology to combustion residual leachate is appropriate because FGD 

wastewater and combustion residual leachate are both associated with combustion wastes and 

contain similar pollutants. EPA identified both arsenic and mercury as pollutants of concern for 

each wastestream (see Section 6.6 of the TDD). As such, both mercury and arsenic are present in 

untreated FGD wastewater and untreated combustion residual leachate at treatable levels. 

The data evaluated for this rulemaking and published literature demonstrate that chemical 

precipitation can effectively remove arsenic and mercury from wastewater, and the precipitation 

(hydroxide and sulfide) and iron co-precipitation processes that make up the chemical 

precipitation technology basis are particularly effective. EPA received no data from stakeholders 

showing otherwise. Although arsenic and mercury are, on average, present in untreated 

combustion residual leachate at a lower concentration than in FGD wastewater, they are still 

present at treatable concentrations and are within the range of concentrations observed in 

untreated FGD wastewater for the plant datasets that EPA used to calculate the limitations for the 

chemical precipitation technology option for FGD wastewater. Therefore, EPA concludes that 

chemical precipitation is capable of removing arsenic and mercury from combustion residual 

leachate to the level necessary to achieve the final effluent limitations. 

13.7.2 Transfer of Arsenic and Mercury Limitations for Chemical Precipitation to 

Biological Treatment for FGD Wastewater

The final rule establishes BAT limitations and PSES applicable to FGD wastewater based 

on the biological treatment technology option. EPA transferred the FGD wastewater effluent 

limitations for arsenic and mercury calculated for the chemical precipitation technology option to 

the biological treatment technology option because EPA determined that certain data from the 

model plants using biological treatment were, in some respects, not representative of a welloperated biological treatment system, as defined for this rule. This transfer of limitations for 

arsenic and mercury is appropriate because data from the steam electric power plants 

representing the chemical precipitation technology option better reflect the effluent 

concentrations that would be attained by the biological treatment technology when it uses all 

features in the technology option that remove arsenic, mercury, and many other metals from the 

wastewater. The technology upon which the biological treatment option is based comprises all 

elements of the chemical precipitation technology option followed by anoxic/anaerobic treatment 

and includes the following: equalization of the influent wastewater; chemical precipitation/co-

 149 Some plants operate a chemical precipitation treatment system in conjunction with other more advanced 

wastewater treatment such as biological treatment or evaporation.
Section 13—Limitations And Standards: Data Selection And Calculation

13-22

precipitation to precipitate and remove both dissolved and particulate forms of the targeted 

pollutants (including pH adjustment, hydroxide precipitation, iron co-precipitation, 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 arsenic and mercury removals achieved by the biological 

treatment. As such, plants using this technology basis would remove pollutants to the same 

degree as plants using the chemical precipitation technology, plus any additional pollutant 

removals achieved by the biological treatment stage. The data for the biological treatment 

technology demonstrates that it is also effectively removes mercury from FGD wastewater, as 

much as 90 percent of the mercury entering the bioreactor. The biological treatment stage also 

further removes other pollutants, including arsenic.

EPA evaluated what the limitations for arsenic and mercury would be if they were based 

on data from the two plants using anoxic/anaerobic biological treatment: Allen and Belews 

Creek. Both of these plants have installed all equipment associated with the model chemical 

precipitation and biological treatment technologies; however, while both plants have the 

capability to add organosulfide chemicals to achieve sulfide precipitation of dissolved mercury 

and other pollutants in the chemical precipitation stage preceding the bioreactors, neither plant 

was actually dosing the organosulfide chemical when the data were collected. As a result, the 

arsenic and mercury effluent data for these plants do not reflect the additional pollutant removals 

that sulfide precipitation can achieve, nor do they reflect a well-operated chemical precipitation 

system or biological treatment system as defined for the technology options. Although some 

plants might meet their NPDES permit limitations using hydroxide precipitation alone, plants 

striving to maximize removals of mercury and other metals also use sulfide addition (e.g., 

organosulfide) as part of the process. 

As is well documented in texts and papers on wastewater treatment, adding sulfide 

chemicals in addition to the alkali provides even greater removals of certain metals due to the 

very low solubility of metal sulfide compounds, relative to metal hydroxides [Palmer et al., 

1988]. For this reason, EPA included the use of hydroxide precipitation, sulfide precipitation, 

and iron co-precipitation in the technology basis for both the chemical precipitation technology 

and the biological treatment technology options. Thus, although both Allen and Belews Creek 

have the technology in place, because neither was actually adding organosulfide, they were not 

optimizing the pollutant removal efficacy of their treatment systems for mercury or arsenic. 

Therefore, the treatment systems at these plants were 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 excessively high influent concentrations of dissolved mercury. Since the 

chemical precipitation treatment stage is less effective at removing dissolved mercury when 

sulfide precipitation is not used, failing to add organosulfide in that stage can allow higher 

concentrations of dissolved mercury and other pollutants to pass through to the biological 

treatment stage. Even though the data evaluated for the ELGs show that the biological treatment 

stage can effectively remove a substantial portion of the mercury entering the bioreactor, the 

overall effluent concentration will be elevated if the treatment system does not incorporate 
Section 13—Limitations And Standards: Data Selection And Calculation

13-23

adequate pretreatment, including sulfide precipitation, in the chemical precipitation stage.150

EPA’s analysis of the performance data for Allen and Belews Creek shows that these plants are 

not adequately treating dissolved mercury, which is attributable to the plants not adding 

organosulfide. In contrast, the model plants identified as using the technology that forms the 

basis for the chemical precipitation technology option 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 treatment 

systems using chemical precipitation/co-precipitation with both hydroxide and sulfide 

precipitation.

As a result, the final rule establishes BAT effluent limitations and PSES for arsenic and 

mercury in FGD wastewater (based on biological treatment) by transferring the limitations 

calculated for the chemical precipitation treatment technology option. EPA notes that it is 

reasonable to expect plants using the biological treatment technology to actually achieve even 

better effluent performance, since the biological treatment stage will remove additional arsenic 

and mercury following the chemical precipitation upon which the arsenic and mercury 

limitations are based.

13.8 SUMMARY OF THE LIMITATIONS

Section 13.8.1 summarizes the plant-specific long-term averages, daily variability factors, 

and monthly variability factors for each pollutant in each treatment technology option, as 

calculated for each plant both with and without the baseline substitution described in Section 

13.2.2. (Section 13.6 describes how EPA uses the plant-specific long-term averages and 

variability factors to derive the long-term average and variability factors for the technology 

option.) Section 13.8.2 summarizes the long-term average and variability factors calculated for 

each pollutant for each of the treatment technology options, as calculated both with and without 

baseline substitution. Section 13.8.2 also presents what the effluent limitations would be for each 

of those scenarios and technology options. Section 13.8.3 summarizes the effluent limitations 

established for FGD wastewater, gasification wastewater, and combustion residual leachate.

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 

 150 The bioreactor removes mercury from the wastewater by both chemical and physical processes. The carbon bed 

in the bioreactors filters out particulate mercury (and other pollutants) that are transferred to the biological stage 

from the chemical precipitation stage. Additionally, the reduction processes in the bioreactors create sulfide 

compounds, which react with mercury and other pollutants to form metal sulfide compounds that precipitate as 

solids and are captured by the carbon bed. If, however, the treatment system has high concentrations of dissolved 

mercury in the influent, the sulfide production in the bioreactors may not be sufficient for creating and removing 

metal sulfide compounds to the extent necessary to meet the effluent limitations. For that reason, it is important for 

the chemical precipitation stage to include organosulfide addition (where chemical dosages can be readily adjusted 

as necessary to accommodate influent concentrations) and enable the majority of sulfide precipitation to occur prior 

to sending the wastewater to the bioreactors. 
Section 13—Limitations And Standards: Data Selection And Calculation

13-24

Electric Rulemaking lists of the data that EPA used to calculate the plant-specific results for each 

of the technology options [U.S. EPA, 2015a].

Chemical Precipitation Treatment Technology Option for FGD Wastewater

Table 13-3 presents the plant-specific results (i.e., long-term averages and variability 

factors) for the chemical precipitation technology option for FGD wastewater. The pollutants 

identified for regulation under this technology option are arsenic and mercury.

Table 13-3. Plant-Specific Results for the Chemical 

Precipitation Technology Option for FGD Wastewater

Pollutant Plant Name Baseline a

Plant-Specific 

Long-Term 

Average

Plant-Specific 

Daily 

Variability 

Factor

Plant-Specific 

Monthly 

Variability 

Factor

Arsenic (μg/L)

Hatfield’s Ferry 0 or 2 9.135 2.098 1.412

Keystone

0 3.064 1.632 1.431

2 3.096 1.615 1.383

Miami Fort 0 or 2 4.298 1.211 1.092

Pleasant Prairie 0 or 2 7.655 2.101 1.410

Mercury (ng/L)

Hatfield’s Ferry 0 or 0.5 118.683 5.321 2.352

Keystone 0 or 0.5 66.878 3.642 1.907

Miami Fort 0 or 0.5 200.007 7.044 2.732

Pleasant Prairie 0 or 0.5 214.609 3.752 1.943

a – Where EPA identifies the baseline as zero, this means that the limitations are not based on the baseline 

substitution approach. Where the resulting value is the same with and without baseline substitution, this means that 

EPA obtained the same result in both cases.

Biological Treatment Technology Option for FGD Wastewater

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 identified for regulation under this technology option are 

arsenic, mercury, nitrate-nitrite as N, and selenium. As explained in Section 13.7.2, EPA 

transferred the limitations for arsenic and mercury for the biological treatment technology option 

from the chemical precipitation treatment technology option. Therefore, the values shown in 

Table 13-3 for arsenic and mercury also apply for limitations based on the biological treatment 

technology option.
Section 13—Limitations And Standards: Data Selection And Calculation

13-25

Table 13-4. Plant-Specific Results for the Biological Treatment 

Technology Option for FGD Wastewater

Pollutant Plant Name Baseline a

Plant-Specific 

Long-Term 

Average

Plant-Specific 

Daily Variability 

Factor

Plant-Specific 

Monthly 

Variability 

Factor

Arsenic (μg/L) b -- -- -- -- --

Mercury (ng/L) b -- -- -- -- --

Nitrate-nitrite as 

N (mg/L)

Allen 0 2.549 16.876 3.841

Belews Creek 0.035 9.360 2.892

Allen 0.05 2.531 16.779 3.846

Belews Creek 0.063 2.402 1.454

Selenium (μg/L)

Allen 0 7.134 3.283 1.589

Belews Creek 7.923 2.779 1.480

Allen 5 7.391 2.873 1.492

Belews Creek 8.013 2.618 1.442

a – Where EPA identifies the baseline as zero, this means that the limitations are not based on the baseline 

substitution approach. Where the resulting value is the same with and without baseline substitution, this means that 

EPA obtained the same result in both cases.

b – Option long-term average and variability factors were transferred from chemical precipitation technology option 

for FGD wastewater.

Vapor-Compression Evaporation Treatment Technology Option for FGD Wastewater

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 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. The 

Brindisi plant ultimately recombines these streams in a distillate tank and then reuses them. 

However, it is possible that a plant may choose to reuse both streams (either in the FGD process 

or another plant process), 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 using 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 at the time sampling data were collected that preclude establishing a combined 

limitation. EPA also considered establishing two sets of effluent limitations, one for each 

effluent stream. Although technically feasible, this approach would require plants to collect and 

analyze separate samples for each effluent stream. EPA determined that establishing separate 

limitations for the effluent streams is unnecessarily burdensome and is not necessary to ensure 

the FGD wastewater is being treated to the effluent quality achievable by operation of the 

evaporation technology. Thus, EPA established a single set of effluent limitations that applies to 

all FGD wastewater prior to discharge (whether as a single stream, combined stream, or multiple 

streams) and concluded this single set of effluent limitations is sufficient to ensure the 

appropriate level of control would be achieved. Because the effluent quality of the two 

wastestreams is not identical, EPA established the limitations based on the stream with the 

higher pollutant concentrations: crystallizer condensate. Setting the limitations on the higher 
Section 13—Limitations And Standards: Data Selection And Calculation

13-26

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 

for FGD Wastewater, Gasification Wastewater, and Combustion Residual Leachate for the Final 

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, 

2015b].

Table 13-5 presents the plant-specific results (i.e., long-term averages and variability 

factors) for the vapor-compression evaporation treatment technology option for FGD 

wastewater. The pollutants identified for regulation under this technology option are arsenic, 

mercury, selenium, and TDS.

Table 13-5. Plant-Specific Results for the Vapor-Compression Evaporation Technology 

Option (Crystallizer Condensate) for FGD Wastewater

Pollutant

Plant 

Name Baseline a

Plant-Specific 

Long-Term 

Average

Plant-Specific 

Daily Variability 

Factor

Plant-Specific 

Monthly 

Variability 

Factor

Arsenic (μg/L) Brindisi 0 or 2 4.0 b -- c -- c

Mercury 

(ng/L) Brindisi 0 or 0.5 17.788 2.192 1.338

Selenium 

(μg/L) Brindisi 0 4.0 a -- c -- c5 5.0 a -- c -- c

TDS (mg/L) Brindisi 0 or 10 14.884 3.341 1.572

a – Where EPA identifies the baseline as zero, this means that the limitations are not based on the baseline 

substitution approach. Where the resulting value is the same with and without baseline substitution, this means that 

EPA obtained the same result in both cases.

b – Long-term average is the arithmetic mean since all observations were non-detected. 

c – All observations were non-detected, so EPA could not calculate variability factors.

Vapor-Compression Evaporation Treatment Technology Option for Gasification 

Wastewater

In developing the limitations for this technology option, EPA calculated the limitations 

using the gasification wastewater data from Wabash River and Polk. The treatment system at 

Wabash River produces one treated effluent stream: condensate from vapor compression 

evaporator. The treatment system for Polk Power Station produces two treated wastewater

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). However, 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 appropriate for use in calculating limitations. Based on its 
Section 13—Limitations And Standards: Data Selection And Calculation

13-27

review of the data for the treatment system, EPA determined 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. For this reason, EPA based the 

limitations for this technology option on effluent data for the vapor compression evaporators at 

Polk and Wabash River. 

Table 13-6 presents the plant-specific results (i.e., long-term averages and variability 

factors) for vapor-compression evaporation treatment as the technology basis for gasification 

wastewater. The pollutants identified for regulation under this technology option are arsenic, 

mercury, selenium, and TDS. As explained in Section 13.4, the data for arsenic and mercury at 

Wabash River failed the data editing criteria; therefore, 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 the Vapor-Compression Evaporation Technology 

Option (Vapor-Compression Evaporator Condensate) for Gasification Wastewater

Pollutant Plant Name Baseline a

Plant-Specific 

Long-Term 

Average

Plant-Specific Daily 

Variability Factor

Plant-Specific Monthly 

Variability Factor

Arsenic 

(μg/L)

Polk 0 or 2 4.00 b -- c -- c

Wabash 

River 0 d 4.00 b -- c -- c

Mercury 

(ng/L) Polk 0 or 0.5 1.075 1.632 1.194

Selenium 

(μg/L)

Polk 0 or 5 288.434 3.083 1.545

Wabash 

River

0 4.534 1.360 1.116

5 5.125 -- c -- c

TDS (mg/L)

Polk 0 or 10 16.512 2.149 1.327

Wabash 

River 0 or 10 13.906 2.818 1.450

a – Where EPA identifies the baseline as zero, this means that the limitations are not based on the baseline 

substitution approach. Where the resulting value is the same with and without baseline substitution, this means that 

EPA obtained the same result in both cases.

b – Long-term average is the arithmetic mean since there are too few detected observations. 

c – Nearly all observations were non-detected, so EPA could not calculate variability factors.

d – After baseline adjustment, EPA excluded the Wabash River arsenic data because it did not pass the LTA test

13.8.2 Summary of the Option-Level Long-Term Averages, Variability Factors, and 

Limitations for Each Treatment Technology Option for FGD, Gasification, and 

Combustion Residual Leachate Wastewaters

This section presents the option-level long-term average and variability factors for each 

pollutant in each of the treatment technology options for FGD, gasification, and combustion 

residual leachate wastewaters. In addition, this section presents what the limitations would be for 

each of the technology options, as calculated with and without baseline substitution. EPA 

obtained these results by combining the plant-specific results for each technology option 
Section 13—Limitations And Standards: Data Selection And Calculation

13-28

presented in Section 13.8.1 (except for combustion residual leachate wastewater because the 

limitations for that wastestream were transferred from the chemical precipitation technology 

option for FGD wastewater). As described in Section 13.6, the option-level long-term average 

for each pollutant is the median of the plant-specific long-term averages. The option-level 

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 arsenic limitations for gasification wastewater based on vaporcompression are each based on data from one plant. As such, the option-level long-term averages 

and variability factors for these options are the same as the plant-specific long-term averages and 

variability factors. Also, in 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 based on the 

detection limit (i.e., “minimum level”).151 Also, EPA is not establishing monthly average 

limitations when the daily maximum limitation is based on the detection limit since no 

appropriate model could be used.

Table 13-7 provides the option-level long-term average, variability factors, and

limitations for each of the FGD, gasification, and combustion residual leachate technology 

options, as calculated both with and without baseline adjustment.

Table 13-7. Option-Level Long-Term Averages, Variability Factors, and Limitations for 

Each of the FGD, Gasification, and Combustion Residual Leachate Technology Options 

with or without baseline Adjustment

Treatment 

Technology 

Option Pollutant Baseline

Option 

LongTerm 

Average

Option 

Daily 

Variability 

Factor

Option 

Monthly 

Variability 

Factor

Daily 

Maximum 

Limitation a

Monthly 

Average 

Limitation a

Chemical 

Precipitation 

for FGD 

Wastewater

Arsenic 

(μg/L)

0 5.976 1.760 1.336 11 8

2 5.976 1.756 1.324 11 8

Mercury 

(ng/L) 0 or 0.5 159.345 4.940 2.233 788 356

Chemical 

Precipitation 

and 

Biological 

Treatment 

for FGD 

Wastewater

Arsenic 

(μg/L) b

0 5.976 1.760 1.336 11 8

2 5.976 1.756 1.324 11 8

Mercury 

(ng/L) b 0 or 0.5 159.345 4.940 2.233 788 356

Nitrate-nitrite 

as N (mg/L)

0 1.292 13.118 3.366 17.0 4.4

0.05 1.297 9.590 2.650 12.5 3.5

0 7.528 3.031 1.535 23 12

 151 As used in this section 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

13-29

Table 13-7. Option-Level Long-Term Averages, Variability Factors, and Limitations for 

Each of the FGD, Gasification, and Combustion Residual Leachate Technology Options 

with or without baseline Adjustment

Treatment 

Technology 

Option Pollutant Baseline

Option 

LongTerm 

Average

Option 

Daily 

Variability 

Factor

Option 

Monthly 

Variability 

Factor

Daily 

Maximum 

Limitation a

Monthly 

Average 

Limitation a

Selenium 

(μg/L) 5 7.702 2.746 1.467 22 12

Chemical 

Precipitation 

and 

Evaporation 

for FGD 

Wastewater

Arsenic 

(μg/L) 0 or 2 4.0 c -- d -- d 4 e -- f

Mercury 

(ng/L) 0 or 0.5 17.788 2.192 1.338 39 24

Selenium 

(μg/L)

0 4.0 c -- d -- d 4 e -- f

5 5.0 c -- d --d 5 e -- f

TDS (mg/L) 0 or 10 14.884 3.341 1.572 50 24

VaporCompression 

Evaporation 

for 

Gasification 

Wastewater

Arsenic 

(μg/L) 0 or 2 4.0 c -- d -- d 4 e -- f

Mercury 

(ng/L) 0 or 0.5 1.075 1.632 1.194 1.8 1.3

Selenium 

(μg/L)

0 146.484 2.222 1.331 326 195

5 146.780 3.083 1.545 453 227

TDS (mg/L) 0 or 10 15.209 2.483 1.389 38 22

Chemical 

Precipitation 

for 

Combustion 

Residual 

Leachate 

Wastewater

Arsenic 

(μg/L) b

0 5.976 1.760 1.336 11 8

2 5.976 1.756 1.324 11 8

Mercury 

(ng/L) b 0 or 0.5 159.345 4.940 2.233 788 356

a – Limitations greater than 1.0 have been rounded upward to the next highest integer, except for limitations for 

mercury based on the vapor-compression evaporation treatment technology option for gasification wastewater and 

limitations for nitrate-nitrite as N for FGD wastewater, which have been rounded up to the next highest tenth 

decimal place.

b – EPA transferred option long-term averages, variability factors, and limitations from the chemical precipitation 

technology option for FGD wastewater.

c – Long-term average is the arithmetic mean since all observations were non-detected. 

d – All observations were non-detected, so EPA could not calculate variability factors.

e – Limitation is set equal to the detection limit.

f – EPA is not establishing monthly average limitations when the daily maximum limitation is based on the 

detection limit.
Section 13—Limitations And Standards: Data Selection And Calculation

13-30

13.8.3 Long-Term Averages and Effluent Limitations for FGD Wastewater, Gasification 

Wastewater, and Combustion Residual Leachate

Table 13-8 and Table 13-9 present the effluent limitations and standards for discharges of 

FGD wastewater, gasification wastewater, and combustion residual leachate from existing and 

new sources in the final rule. As described in Section 13.2, EPA evaluated what the limitations 

would be using baseline substitution, as well as what the limitations would be without adjusting 

for baseline substitution. The limitations established for the rule use the higher result.

Table 13-8 and Table 13-9 also present the long-term average treatment performance 

calculated for the selected treatment technology option. Due to routine variability in treated 

effluent, a power plant that targets its treatment to achieve pollutant concentrations at a level near 

the values of the daily maximum limitation or the monthly average limitation may experience 

frequent values exceeding the limitations. For this reason, EPA recommends that plants design 

and operate the treatment system to achieve the long-term average for the model technology. In 

doing so, a system that is designed to represent the BAT/NSPS level of control would be 

expected to meet the limitations. 

Table 13-8. Long-Term Averages and Effluent Limitations and Standards for FGD 

Wastewater and Gasification Wastewater for Existing Sources

Wastestream Pollutant

Long-Term 

Average

Daily 

Maximum

Limitation

Monthly 

Average 

Limitation

FGD Wastewater

(BAT & PSES)

Arsenic (μg/L) 5.98 11 8

Mercury (ng/L) 159 788 356

Nitrate/nitrite

as N (mg/L) 1.3 17.0 4.4

Selenium (μg/L) 7.5 23 12

Voluntary Incentives Program 

for FGD Wastewater

(BAT only)

Arsenic (μg/L) 4.0 a 4 b --- c

Mercury (ng/L) 17.8 39 24

Selenium (μg/L) 5.0 a 5 b --- c

TDS (mg/L) 14.9 50 24

Gasification Wastewater

(BAT & PSES)

Arsenic (μg/L) 4.0 a 4 b --- c

Mercury (ng/L) 1.08 1.8 1.3

Selenium (μg/L) 147 453 227

TDS (mg/L) 15.2 38 22

a – Long-term average is the arithmetic mean of the quantitation limitations since all observations were not detected.

b – Limitation is set equal to the quantitation limit.

c – EPA is not establishing monthly average limitation when the daily maximum limitation is based on the 

quantitation limit.

Table 13-9. Long-Term Averages and Standards for FGD Wastewater, 

Gasification Wastewater, and Combustion Residual Leachate for New Sources

Wastestream Pollutant

Long-Term 

Average

Daily 

Maximum

Limitation

Monthly 

Average 

Limitation

FGD Wastewater

(NSPS & PSNS)

Arsenic (μg/L) 4.0 a 4 b --- c

Mercury (ng/L) 17.8 39 24
Section 13—Limitations And Standards: Data Selection And Calculation

13-31

Table 13-9. Long-Term Averages and Standards for FGD Wastewater, 

Gasification Wastewater, and Combustion Residual Leachate for New Sources

Wastestream Pollutant

Long-Term 

Average

Daily 

Maximum

Limitation

Monthly 

Average 

Limitation

Selenium (μg/L) 5.0 a 5 b --- c

TDS (mg/L) 14.9 50 24

Gasification Wastewater

(NSPS & PSNS)

Arsenic (μg/L) 4.0 a 4 b --- c

Mercury (ng/L) 1.08 1.8 1.3

Selenium (μg/L) 147 453 227

TDS (mg/L) 15.2 38 22

Combustion Residual Leachate 

(NSPS & PSNS)

Arsenic (μg/L) d 5.98 11 8

Mercury (ng/L) d 159 788 356

a – Long-term average is the arithmetic mean of the quantitation limitations since all observations were not detected.

b – Limitation is set equal to the quantitation limit.

c – EPA is not establishing monthly average limitation when the daily maximum limitation is based on the 

quantitation limit.

d – EPA transferred long-term averages and standards from performance of chemical precipitation in treating FGD 

wastewater.

13.9 ENGINEERING REVIEW OF THE LIMITATIONS

Plants that install treatment technologies to comply with the newly promulgated 

limitations will need to design and operate the systems to meet the limitations at all times. In 

summary, this means:

1. A treatment system that includes the necessary process equipment and chemical 

additives that is sized to accommodate the wastewater flows and is designed to 

target removing the regulated pollutants to meet the long-term average.

2. Proper attention and operation that targets chemical addition rates and other 

operational conditions to the long-term average for the regulated pollutants, 

considers fluctuations in influent wastewater flows and pollutant concentrations, and 

proactively monitors for and responds to fluctuations in effluent pollutant 

concentrations due to abnormal conditions or treatment system upsets.

A properly designed and operated treatment system that represents best available 

technology or best available demonstrated control technology includes characteristics such as 

proper chemical usage, regular inspection and repair of equipment, use of backup systems, 

operator training and performance evaluations, management control, careful communications 

and coordination among production and wastewater treatment personnel, consistent monitoring 

and close attention to treatment system operating parameters and effluent quality, systems and 

processes that recognize and correct periods of degraded or abnormal operation, and equalization 

tanks to make wastewater flow and quality more uniform.

Proper design does not include improperly designed or inadequate treatment facilities 

(including systems targeted to meet the limitations rather than the long-term averages), such as 

treatment systems that lack sufficient equalization tank capacity to dampen fluctuations in 

wastewater flow rates or pollutant concentrations, nor does it include treatment systems that do 
Section 13—Limitations And Standards: Data Selection And Calculation

13-32

not include key process equipment or chemical additives, such as the organosulfides used to 

enhance precipitation of dissolved mercury.

As part of its review of the final limitations, EPA often looks at the data from the model 

plants to see if the data demonstrate that they can comply with the final limitations. It is not 

unusual for EPA to find that one or all of the model plants may need to make treatment 

technology upgrades or improvements to their operation to comply with the final limitations. 

Typically, although most observations in the datasets used to calculate the effluent limitations are 

below the limitations, there are some observations above the limitations. It is reasonable for this 

situation to arise in datasets used to calculate limitations and there are specific steps that plants 

can take that would enable them to improve treatment system performance so that effluent 

concentrations would be in compliance with the limitations at all times. Although EPA selects 

model plants as representing the best available technology or best available demonstrated control 

technology, and they provide the best available data for establishing limitations that reflect 

BAT/NSPS level of treatment, it does not necessarily mean that the plants have their systems 

fully optimized. For example, the NPDES permit for a model plant may not include limitations 

for the regulated pollutant or the NPDES permit limitations may be well above the final 

limitations and what other systems are achieving. Thus, these plants would be expected to have 

data above the limitations (and that do not reflect BAT/NSPS level of control), not because the 

systems are incapable of achieving the limitations, but rather because the existing permit 

limitations do not drive the plants to optimize their pollutant removals. If EPA’s review 

demonstrates that a model plant is not consistently achieving the final limitations, EPA looks at 

the treatment system design and operation for the model plant to determine if it currently meets 

EPA’s expectations for proper design and operation.

152 In this way, EPA confirms that the final 

limitations are reasonable and will be achieved by properly designed and operated systems. 

For this final rule, EPA performed an engineering review to verify that the effluent 

limitations are reasonable based upon the design and expected operation of the control 

technologies. As part of this review, EPA performed two types of comparisons. First, EPA 

compared the effluent limitations for each pollutant against the effluent data from the model 

plants used to develop the limitations. This type of comparison helps to evaluate how reasonable 

the limitations are from an engineering perspective. Second, EPA compared the limitations for 

each pollutant against the influent data at the model plants. This second comparison helps 

evaluate whether the influent concentrations were generally well controlled by the treatment 

system.

Section 13.9.1 presents the results of the comparisons between the limitations and all 

effluent data that were used to calculate the limitations for each technology option. Section 

13.9.2 presents the results of the comparisons between the effluent limitations and the influent 

data values for each technology option. For the detailed results of these comparisons, see the 

memorandum entitled “Effluent Limitations for FGD Wastewater, Gasification Wastewater, and 

Combustion Residual Leachate for the Final Effluent Limitations Guidelines and Standards for 

the Steam Electric Rulemaking” [U.S. EPA, 2015a].

 152 If they do not, EPA includes costs for the model plants to do so.
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13.9.1 Comparison of Limitations to Effluent Data Used As Basis for the Limitations

EPA first compared the daily effluent values to the daily limitations to identify any values 

above the daily limit. The plots that EPA prepared for this first comparison also provide insight 

into how other values (i.e., daily values below the daily limit) compare to the limit. EPA then 

compared the effluent daily values to the monthly average limitations, for those periods where 

there are sufficient data to represent weekly monitoring,

153 and identified those months where the 

average of all daily values for the month is above the monthly limit. As with the comparison to 

the daily limitations, the plots that EPA prepared also provide insight into how monthly averages 

below the monthly limitation compare to the limitation.

After thoroughly evaluating the results of the comparison between the limitations and the 

effluent values used to calculate the limitations (see details below), EPA determined that the 

statistical distributional assumptions used to develop the limitations are appropriate for the data 

(that is, they provide a reasonable “fit” to the actual effluent data) and the limitations for each 

wastestream are reasonable and achievable. (This conclusion is also true for the combustion 

residual leachate limitations based on the chemical precipitation technology since the 

combustion residual leachate limitations were transferred from the limitations derived for the 

chemical precipitation technology option for FGD wastewater.) If a plant properly designs and 

operates its wastewater treatment system to achieve the 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. 

Although the comparison of the limitations to the effluent data identifies some values 

greater than the limitations in the data used to calculate the limitations, for the reasons described 

below, EPA concludes that all plants properly operating and maintaining the appropriate 

technology will be able to comply with the limitations.

In comparing the effluent data to the limitations, EPA noted there are instances where 

one or more daily values in a month are higher than the monthly limit, but the average of all 

results in a month are equal to or less than the monthly average limit. Instances such as these are 

normal and consistent with the way effluent limitations are calculated and implemented in 

NPDES permits. This is illustrated by Hatfield’s Ferry’s arsenic data for February 2010, as 

described below. EPA also identified some cases where only one sample was taken during a 

month and the resulting concentration value for that one sample is above the monthly limit. In 

 153 This approach is consistent with the manner in which EPA calculated the limitations and anticipates plants will 

monitor for compliance with NPDES permits. It is also consistent with the monitoring frequency EPA has generally 

observed in NPDES permits, for those pollutants for which the permit includes effluent limitations. Additionally, it 

is consistent with EPA’s methodology for estimating compliance costs for the final rule, which includes estimated 

operation and maintenance (O&M) costs for weekly compliance monitoring. Furthermore, it is a reasonable 

approach for conducting the engineering review because an assessment that uses data from less frequent monitoring 

may more closely reflect the daily variability than the monthly variability and therefore would not accurately reflect 

whether the monthly limit would have been met. For example, the four weekly samples collected from Hatfield’s 

Ferry in February 2010 are all equal to or below the daily limit of 11 μg/L. One of these observations (11 μg/L) is 

higher than the monthly limit of 8 μg/L. However, the average of all daily values for the month is 7.5 μg/L, which is 

below the monthly limit. 
Section 13—Limitations And Standards: Data Selection And Calculation

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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 average limit.

Based on the results described in the sections below for the comparisons of effluent and 

influent data to the limitations, and information described elsewhere that was evaluated for the 

ELGs, EPA determined that the statistical distributional assumptions are appropriate for the

effluent data and that the daily maximum and monthly average limitations for the rule are 

reasonable and achievable.

Arsenic and Mercury Limitations for FGD Wastewater, Based on Performance of 

Chemical Precipitation Technology

EPA calculated effluent limitations for arsenic and mercury in FGD wastewater based on 

the performance of chemical precipitation treatment technology. These limitations were 

transferred to the biological treatment technology option and thus form the bases for the arsenic 

and mercury limitations applicable to FGD wastewater in the final rule. The Agency calculated 

the limitations using data from four plants: Hatfield’s Ferry, Keystone, Miami Fort, and Pleasant 

Prairie.

• Arsenic – Comparison of effluent data to the daily maximum limit of 11 ug/L:

- All observations for two plants were equal to or below the daily maximum limit 

(24 observations at Keystone; nine observations at Miami Fort). At Pleasant 

Prairie, all but one of the 20 observations were equal to or below the daily limit. 

At Hatfield’s Ferry, 102 observations were equal to or below the daily limit; 28 of 

the 130 total observations at Hatfield’s Ferry were above the daily limit.

• Arsenic – Comparison of effluent data to the monthly average limit of 8 ug/L:

- Only Keystone and Hatfield’s Ferry collected effluent samples with sufficient 

frequency within a month to represent weekly sampling. For the time periods 

where there were sufficient data, EPA calculated the average of the daily values 

collected within a month and compared that average value to the monthly average 

limit. For Keystone, all such monthly average values were below the limit. In fact, 

every daily observation at Keystone was below the monthly limit. For Hatfield’s 

Ferry, there were 12 months when the average value was equal to or below the 

limit; there were 15 months when the average value was above the monthly limit 

(most of those were 1-2 ug/L above the monthly limit). Although Miami Fort did 

not collect samples with sufficient frequency to calculate monthly averages, all of 

the daily observations for the plant were equal to or below the monthly limit and, 

therefore, EPA did not identify any periods of time when the effluent 

concentrations were higher than the limit.

• Mercury – Comparison of effluent data to the daily maximum limit of 788 ng/L:

- All observations at Keystone and Miami Fort were below the daily maximum 

limit (eight observations at Keystone; 68 observations at Miami Fort). Of the 219 

total observations at Hatfield’s Ferry, 217 were below the daily limit and two

were above the daily limit. Of the 375 total observations at Pleasant Prairie, 370 
Section 13—Limitations And Standards: Data Selection And Calculation

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observations were below the daily limit and five were above the daily maximum 

limit.

• Mercury – Comparison of effluent data to the monthly average limit of 356 ng/L:

- Only Hatfield’s Ferry and Pleasant Prairie collected effluent samples with 

sufficient frequency within a month to represent weekly sampling. For the time 

periods where there were sufficient data, EPA calculated the average of the daily 

values collected within a month, and compared that average value to the monthly 

average limit. At Hatfield’s Ferry, all but one of the monthly average values were 

below the limit (39 of the 40 monthly values). For Pleasant Prairie, there were 27 

months when the average value was below the limit; there were 3 months when 

the average value was above the monthly limit. Although Keystone did not collect 

samples frequently enough to calculate monthly averages, all of the daily 

observations for the plant were equal to or below the monthly limit and, therefore, 

EPA did not identify any periods of time when the effluent concentrations were 

higher than the limit. Miami Fort also did not collect samples frequently enough

to calculate monthly averages; however, it is worth noting that 61 of the 68 daily 

observations for the plant were below the monthly limit.

EPA determined that all power plants discharging FGD wastewater, including the plants 

discussed here, are capable of meeting the effluent limitations for arsenic and mercury. While 

there were certain instances where the model plants’ effluent data concentrations are higher the 

final limitations, 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 longterm averages will result in lower effluent concentrations that would comply with the effluent 

limitations. 

Although most observations in the datasets used to calculate the effluent limitations were 

below the limitations, there were some observations above the limitations. As explained above, it 

is reasonable for this situation to arise in datasets used to calculate limitations for the rule, and 

there are specific steps that the plants can take to improve treatment system performance so that 

effluent concentrations would comply with the limitations at all times. Although EPA selected 

these plants as representing the best available technology and they provide the best available data 

for establishing arsenic and mercury effluent limitations that reflect BAT level of treatment for

FGD wastewater, it does not necessarily mean that the plants’ systems are fully optimized, 

especially since the NPDES permits for these plants either do not include limitations for arsenic 

or mercury in their discharges of FGD wastewater or because their NPDES permit limitations are 
Section 13—Limitations And Standards: Data Selection And Calculation

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well above what the system is capable of achieving.154,155,156,157 This is supported by Duke 

Energy’s comments on the proposed effluent guidelines, which state that the “performance of the 

chemical precipitation treatment systems from which EPA’s data relies were optimized to meet 

current facility NPDES permit requirements and may not reflect the system’s maximum 

performance.”158

 154 Pleasant Prairie’s NPDES permit (WI-0043583-06-1) FGD wastewater monitoring requirements include both inplant requirements (Outfall 102, effluent from the FGD blowdown wastewater treatment system) and final outfall 

requirements (Outfall 001, combined discharge to Lake Michigan for five internal outfalls, including cooling tower 

blowdown and FGD wastewater). Outfall 102 includes no effluent limitations for arsenic (requiring only that the 

plant monitor for the pollutant monthly); mercury has a daily limit of 1,500 ng/L (monitored twice weekly), but no 

monthly limit. Outfall 001 includes a daily maximum limit for mercury (and a monitoring requirement but no 

effluent limit for arsenic), but the NPDES permits specifically states that “the FGD effluent may only discharge 

when sufficient flow from other wastewater streams (cooling tower blowdown, low volume wastewater, coal pile 

runoff, or metal cleaning waste basin) is available if necessary to comply with the water quality based effluent 

limitations at Outfall 001.” 

155 Miami Fort’s NPDES permit (OH0009873) FGD wastewater monitoring requirements include both in-plant 

requirements (Outfall 608, FGD wastewater treatment system discharge prior to the ash pond) and final outfall 

requirements (Outfall 002, ash pond discharge, including FGD wastewater, prior to the Ohio River). Outfall 608 

includes no effluent limitations for arsenic or mercury, requiring only that the plant monitor the concentrations of 

these pollutants monthly. Outfall 002 similarly includes no effluent limitations for arsenic or mercury, requiring only 

that the plant monitor the concentrations of these pollutants quarterly. 156 Hatfield’s Ferry Power Station’s NPDES permit (PA0002941) FGD wastewater monitoring requirements include 

both in-plant requirements (Outfall IMP 306, effluent from the FGD scrubber blowdown wastewater treatment 

plant) and final outfall requirements (Outfall 006, which includes ash transport water, coal pile runoff, low volume 

waste and FGD wastewater treatment system effluent). Outfall IMP 306 includes no effluent limit for arsenic, 

requiring only that the plant monitor for the pollutant weekly; the permit includes a mercury daily limit of 10,000 

ng/L and a monthly average limit of 5,000 ng/L (monitored weekly). Outfall 006 includes no effluent limit or 

monitoring requirement for arsenic; the permit includes a mercury daily limit of 4,000 ng/L and a monthly average 

limit of 2,000 ng/L (monitored weekly).

157 Keystone’s NPDES permit (PA0002062) FGD wastewater monitoring requirements include both in-plant 

requirements (IMP 101, discharge from the FGD scrubber blowdown wastewater treatment plant) and final outfall 

requirements (Outfall 001, which includes discharges from the pipeline pigging wastewater treatment facility and 

FGD scrubber blowdown wastewater treatment plant). IMP 101 includes no effluent limit for arsenic, requiring only 

that the plant monitor for the pollutant weekly; the permit includes a mercury daily limit of 8,000 ng/L and a 

monthly average limit of 4,000 ng/L (monitored weekly). Outfall 001 includes similar effluent 

monitoring/limitations, with monitoring required only when pigging wastewater is discharged.

158 Duke Energy’s comments state that “[t]he operation and performance of chemical precipitation systems for FGD 

water treatment is continuing to evolve and improve. The industry’s current chemical precipitation system 

performance data does not accurately reflect optimized performance...”. “The performance of the chemical 

precipitation treatment systems from which EPA’s data relies were optimized to meet current facility NPDES permit 

requirements and may not reflect the system’s maximum performance. For example, operating these systems at 

higher pH levels can increase the percentage of metal removal. Improved treatment chemicals, improved 

clarification and filtration can further increase removal percentages. If necessary, modifications to chemical 

precipitation systems towards optimizing removal of specific constituents, not currently permitted, can result in 

more effective treatment of FGD wastewater.” Duke Energy goes on to state that “Miami Fort has implemented

several improvements to their chemical precipitation process to improve mercury removal. Increasing pH from 

initial startup settings, adding coagulants, and organosulfide metal precipitants have led in favorable results. 

Polymer delivery systems have been modified and the baffling inside the clarifier has also been changed to improve 

solids settling and reduce the Total Suspended Solids (TSS).” Comments of Duke Energy to the United States 

Environmental Protection Agency, p. 13. September 19, 2013. 
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The two plants that have observations above the limitations for arsenic do not have 

specific limitations in their NPDES permits for discharges of arsenic in FGD wastewater. Also, 

only three of the plants have NPDES permit limitations for mercury, and for two of these plants 

the permit limitations are more than 10 times higher than the BAT effluent limitations 

established by the final rule. For this reason, these plants currently do not need to closely monitor 

the concentrations of arsenic and mercury in the treatment system effluent or take steps to 

optimize the removal of these pollutants. This is illustrated by the plants’ operational practices 

for their FGD wastewater treatment systems. Other than Pleasant Prairie targeting an effluent 

concentration that would allow discharges containing mercury at double the concentration 

established for the final rule, none of the plants reported having operational target parameters for 

the allowable level of mercury and arsenic in their effluent.159,160,161

As noted above, the NPDES permit for Hatfield’s Ferry includes no arsenic limitations 

for the effluent from the FGD wastewater treatment system. The NPDES permit daily maximum 

limit for mercury is 10,000 ng/L (5,000 ng/L monthly limit). Additionally, the plant does not 

operate its treatment system to achieve any specific operational targets for arsenic or any other 

metal. Instead, the plant operates the treatment system to maintain pH within an operational 

range, ensure the clarifier indicates good settling of the precipitated floc, and provide adequate 

removal of TSS in the effluent from the sand filters. Because of this, it is reasonable to expect 

that the chemical addition rates for sodium hydroxide, organosulfide, and other additives are not 

optimized for arsenic removal. Pleasant Prairie’s NPDES permit includes a daily maximum limit 

for mercury at 1,500 ng/L in the treatment system effluent, but no monthly limit. The plant’s 

operational target of 1,000 ng/L mercury for the treatment system effluent is very near this 

permit limit. Given the high permit limit and operational target, it is not surprising that a small 

number of observations are above the limitations established by the rule. 

Both plants could take steps to ensure compliance with the final limitations by making 

adjustments to the treatment system operation to target the long-term average performance that 

the effluent limitations are based upon (i.e., 5.98 ug/L for arsenic and 159 ng/L for mercury). 

Operator attention to effluent quality and process control indicators (e.g., wastewater flow rates, 

conductivity, clarifier bed levels, TSS) facilitate steady-state operation of the treatment system, 

as well as alerting operators of system abnormalities or fluctuations in influent quality or flow

rate. 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 

 159 When asked about the operational target parameters for the treatment system, Pleasant Prairie personnel reported 

that they target achieving an effluent concentration below 1,000 ng/L in the effluent from the secondary clarifier. If 

the measured concentration is below 1,000 ng/L, discharge is continuous. If clarifier effluent concentration is in the 

range 1,000-1,500 ng/L, continuous discharge ceases and, depending on samples collected from the effluent tank,

the wastewater is either discharged (if <1,500 ng/L) or recirculated for further processing (if >1,500 ng/L). If the 

clarifier effluent is above 1,500 ng/L, the wastewater is recirculated to the absorber or treatment system equalization 

tank for further processing. DCN SE04328

160 When asked about the operational target parameters for the treatment system, Miami Fort personnel reported that 

they make day-to-day adjustments based on pH, turbidity, and TSS to make sure there is good settling and 

clarification. Depending on settling performance, they may adjust the organosulfide addition. Miami Fort personnel 

reported that they do not target specific metals concentrations for the treatment system effluent. DCN SE04331

161 FirstEnergy personnel stated that the plant did not have any specific operational targets for metals. The FGD 

wastewater treatment system was operated based on maintaining the pH, floc in the clarifier, and TSS in the effluent 

from the sand filter. DCN SE04316
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daily basis (this was included as part of the cost basis for the technology option). Pleasant Prairie 

has effectively used mercury analyzers to alert operators when mercury concentrations begin 

trending upward so that they may take steps (such as altering the dosage rates for chemical 

additives) to adjust treatment system performance to meet their current permit limitations. 

Optimizing the treatment system to target effluent concentrations at the long-term 

average is important, and is relevant to the evaluation of the effluent data for Hatfield’s Ferry 

and Pleasant Prairie. EPA evaluated the results of testing a chemical precipitation system at a 

power plant that, although the treatment system had been in operation for more than a year and 

was operating at a steady-state condition, the plant was able to significantly improve the 

pollutant removal performance merely by altering the dosage rates of the wastewater treatment 

chemical additives.162 The results of this study, as well as other information evaluated for the 

ELGs, supports EPA’s determination that these plants can improve treatment system 

performance and meet the ELG limitations at all times. EPA notes that its compliance cost 

estimates for the final rule include costs for mercury analyzers, organosulfide addition, proper 

dosing of treatment system chemical additives, and increased staffing to operate the treatment 

system.

It is important to note that, although the BAT limitations and PSES for arsenic and 

mercury in the final ELGs are based on chemical precipitation technology,

163 the selected 

BAT/PSES technology option for FGD wastewater actually comprises the combination of 

chemical precipitation followed by biological treatment, which is more effective than chemical 

precipitation treatment alone. The data evaluated for the ELGs for the final rule demonstrate that 

the biological treatment stage reduces levels of 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 (e.g., see the data plots 

and tables in DCN SE05733, showing an average of 31 percent removal of arsenic and 99 

percent removal of mercury across the biological treatment stage at Allen and Belews Creek).

These additional pollutant removals are corroborated by the results of pilot testing 

conducted at Indianapolis Power and Light’s Petersburg power plant, which showed that the 

 162 AEP’s Mountaineer plant operated a chemical precipitation system to treat FGD wastewater, with operation 

targeted to meet only the BPT-based limitations for TSS, pH, and oil and grease. 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 

whereby the permitting authority proposed to add a water quality-based effluent limit for mercury. Based on the 

mercury limitations in the draft permit, AEP conducted a pilot study evaluating three different technologies that 

could be installed to further treat the effluent from the chemical precipitation system. AEP 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 ng/L. Since none of the three 

technologies were achieving the targeted effluent concentrations for the pilot testing, AEP took steps to optimize the 

precipitation of dissolved metals and the removal of precipitants and other suspended solids 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. American 

Electric Power Mercury Removal Effectiveness Report. DCN SE02008.

163 See Section 13.7.2 for a discussion of the transfer of effluent limitations for arsenic and mercury from chemical 

precipitation technology to the selected BAT technology option (chemical precipitation followed by biological 

treatment).
Section 13—Limitations And Standards: Data Selection And Calculation

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biological treatment stage effectively removed both arsenic and mercury.164 Data for a full-scale 

FGD wastewater treatment system at AEP’s Mountaineer plant similarly show effective removal 

of both arsenic and mercury by the biological treatment stage.165 Thus, plants using 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 even 

greater than the removals based on chemical precipitation technology alone.

Selenium and Nitrate-nitrite as N Limitations for FGD Wastewater, Based on Chemical 

Precipitation Followed by Biological Treatment Technology Option for FGD Wastewater

The final rule establishes BAT limitations/PSES for arsenic, mercury, nitrate-nitrite as N, 

and selenium in FGD wastewater based on the biological treatment technology option. As 

mentioned above, the limitations for arsenic and mercury were transferred from the chemical 

precipitation technology option. See the discussion above for the comparison of effluent data to 

the limitations for these two pollutants. EPA calculated the effluent limitations for selenium and 

nitrate-nitrite as N using data from two model plants: Allen and Belews Creek.

• Nitrate-nitrite as N – Comparison of effluent data to the daily maximum limit of 17 

mg/L:

- For both Allen and Belews Creek, all observations were below the daily limit (30 

observations at Allen; 40 observations at Belews Creek). 

• Nitrate-nitrite as N – Comparison of effluent data to the monthly average limit of 4.4 

mg/L:

- Only Belews Creek collected effluent samples frequently enough within a month 

to represent weekly sampling. For the time periods where there were sufficient 

data, EPA calculated the average of the daily values collected within a month, and 

compared that average value to the monthly average limit. All of the monthly 

average values for Belews Creek were below the limit. Although Allen did not 

collect samples with sufficient frequency to calculate monthly averages, all but 

two of the daily observations for the plant were below the monthly limit. The two 

daily observations that were above the monthly limit are associated with a spike 

in effluent concentration that occurred in December 2011.

• Selenium – Comparison of effluent data to the daily maximum limit of 23 ug/L:

 164 Higgins, T., et al. “Recent Applications of Meeting Compliance Challenges through Flue Gas Desulfurization 

(FGD) Wastewater,” Presented at the Power Plant Pollutant Control “MEGA” Symposium. August 19-21, 2014. 

Also see June 6, 2015 email from Tom Higgins (CH2M Hill), presenting data showing the biological treatment stage 

removed 87 percent of the mercury and 84 percent of the arsenic entering that stage. 

165 The FGD wastewater treatment system at AEP’s Mountaineer plant includes chemical precipitation (both 

hydroxide and sulfide precipitation, as well as iron coprecipitation) followed by anoxic/anaerobic biological 

treatment designed to remove selenium. DCN SE05664/SE05645
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- Of the 182 total observations at Allen, 178 were below the daily limit and four

were above the daily limit. Of the 216 total observations at Belews Creek, 214 

were below the daily limit and two were above the daily maximum limit.

• Selenium – Comparison of effluent data to the monthly average limit of 12 ug/L:

- All monthly averages for Allen were below the monthly average. At Belews 

Creek, there were 10 months when the monthly average was equal to or below the 

monthly limit and 2 months when the average was above the limit. Both of these 

months occurred shortly after the end of the initial commissioning period for the 

treatment system on 6/11/2008; the two monthly averages above the monthly 

limit were in August and September 2008.

EPA determined that all power plants discharging FGD wastewater, including the plants 

discussed here, are capable of meeting the effluent limitations for selenium and nitrate-nitrite as 

N. While there were certain instances where the model plants’ effluent data concentrations are 

higher the final limitations, based on its engineering judgment developed over years of 

evaluating wastewater treatment processes for power plants and other industrial sectors, 

including both physical/chemical and biological treatment technologies, 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 averages 

will result in lower effluent concentrations that would comply with the effluent limitations.

Although most observations in the datasets used to calculate the effluent limitations were 

below the limitations, there were some observations above the limitations. It is reasonable for 

this situation to arise in datasets used to calculate limitations for ELGs, particularly when the 

data are from plants that do not have NPDES limitations for the pollutants, and there are specific 

steps that the plants can take to improve treatment system performance so that effluent 

concentrations would comply with the limitations at all times. Although EPA selected these 

plants as representing the best available technology, neither plant’s system is fully optimized for 

removing selenium or nitrate-nitrite because they are not targeting specific effluent levels for 

these pollutants or operationally controlling the treatment system (e.g., adjusting dosages for 

chemical additives or altering bioreactor bed contact time) to maintain effluent concentrations 

below specified concentrations. Neither plant’s NPDES permit includes effluent limitations or 

monitoring requirements for nitrate-nitrite. The NPDES permits for these plants also do not 

include effluent limitations for selenium, although the permits do require them to periodically 

monitor effluent concentrations of selenium.166,167

 166 Allen’s NPDES permit (NC0004979) FGD wastewater monitoring requirements include both in-plant 

requirements (Internal Outfall 005, effluent from the FGD wet scrubber wastewater treatment system) and final 

outfall requirements (Outfall 002, ash pond effluent including FGD wastewater and other wastestreams). Internal 

Outfall 005 includes no effluent limitations or monitoring requirement for nitrate-nitrite as N; selenium also has no 

effluent limit and is required to be monitored monthly. Outfall 002 also includes no effluent limitations or 

monitoring requirement for nitrate-nitrite as N; selenium has no effluent limit and is required to be monitored 

monthly. 

167 Belews Creek’s NPDES permit (NC0024406) FGD wastewater monitoring requirements include both in-plant 

requirements (Internal Outfall 002, treated FGD wet scrubber wastewater to ash settling basin) and final outfall 

requirements (Outfall 003, discharge to the Dan River from the ash settling pond, which contains treated FGD 
Section 13—Limitations And Standards: Data Selection And Calculation

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For selenium at Allen and Belews Creek, EPA identified a small number of observations 

that are above the daily limitation, or where the monthly average is above the monthly limitation. 

As explained above, there are steps plants can take to achieve better treatment system 

performance to ensure compliance with the effluent limitations. EPA evaluated all selenium data 

for the biological treatment technology option (more than 5 years of data for Belews Creek and 

more than 4 years for Allen, excluding the initial commissioning periods for the treatment 

systems). EPA concluded that the observations above the daily limitation reflect periods of less 

than optimum performance of the treatment system and were due either to operators 

inexperienced with this type of treatment system, operators not targeting their treatment systems 

to obtain a specific effluent concentration, or operators failing to either closely monitor treatment 

system performance or to respond in a timely manner to restore the system to steady-state 

condition, or a combination thereof.168 For example, the monthly averages at Belews Creek that 

are above the limitations occurred only 2-3 months following the end of the initial 

commissioning period and are associated with significantly higher daily observations relative to 

other observations in the months immediately following that time, as well as nearly every other 

daily observation for Belews Creek. Likewise, the observations at Allen that are above the daily 

limitation are associated with two periods when the effluent selenium concentrations spike 

upward significantly and the effluent concentration of nitrate-nitrite spiked upward suddenly

during one of those periods. These effluent spikes indicate that the nutrient feed may have been 

insufficient or the bed contact time may not have been long enough to allow the microorganisms 

in the bioreactor to complete the biochemical reduction processes for nitrate-nitrite and selenium. 

Both plants could take steps to ensure compliance with the final limitations by adjusting

the treatment system operation to target the long-term average performance that the effluent 

limitations are based upon (i.e., 1.3 mg/L for nitrate-nitrite as N and 7.5 ug/L for selenium). 

Operator attention to influent and effluent quality and process control indicators (e.g., 

wastewater flow rates, oxidation reduction potential (ORP), TSS, turbidity, gas production rates) 

facilitate steady-state operation of the treatment system, as well as alerting operators of system 

abnormalities or fluctuations in wastewater flow rate or quality (influent or effluent). Significant 

changes in wastewater flow rate, if not managed properly, can affect effluent quality because 

they will affect the bed contact time, as well as potentially affecting the appropriate nutrient 

dosage. The influent ORP provides insight to the amount of nutrient that should be added to 

maintain the appropriate carbon to nitrogen (C:N) ratio to support the microbial activity needed 

to reduce nitrate-nitrite and selenium. The plant should monitor the ORP within the bioreactor to 

 

wastewater and other wastes). Internal Outfall 002 includes no effluent limitations or monitoring requirement for 

nitrate-nitrite as N; selenium also has no effluent limit but must be monitored quarterly. Outfall 003 also includes no 

effluent limitations or monitoring requirement for nitrate-nitrite as N; selenium has no effluent limit but must be 

monitored monthly. 

168 Note that although the Belews Creek selenium data (and other pollutants as well) from mid-2008 may be 

influenced by the initial commissioning period for the treatment system, EPA used these data when calculating the 

final effluent limitations for the biological treatment technology option for FGD wastewater. EPA used these data 

because although EPA believes that, as a general rule, the initial commissioning period will be 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. Comments on the proposed ELGs stated that the 

treatment system operators at Belews Creek reported 6/11/2008 as the end of the initial commissioning period.

Without additional information to confirm whether the initial commissioning period was still in progress after that 

date, EPA concluded that the sampling data should be used when calculating effluent limitations.
Section 13—Limitations And Standards: Data Selection And Calculation

13-42

ensure that the wastewater has sufficient bed contact time with the biomass at low (-300 to -400

megavolts (mV)) ORP for sufficient time for selenium reduction. Properly operating the system 

includes being attentive to changes in pressure drop across the system to ensure the routine 

flush/backwash cycles are occurring often enough. 

EPA notes that the compliance cost estimates for the final rule include costs for ORP 

monitoring of the wastewater influent and within the bioreactor, proper dosing of the nutrient 

additives, chemical feed system to remove free oxidants prior to the bioreactor, and increased 

staffing to operate the treatment system. Some plants may find it desirable to implement 

additional process controls, such as frequent monitoring of nitrates or selenium (e.g., daily or 

once per shift) with available test kits or analyzers, although they are not necessary to operate the 

treatment system properly. Although some of these test kits may not be approved in 40 CFR Part 

136 for NPDES purposes, plants can correlate their analytical results to approved methods (such 

as ICP-MS analysis for selenium) and can use them as another real-time indicator of treatment 

system influent or effluent characteristics for enhanced process control.169 Additionally, 

inexpensive test kits for measuring for oxidants in the treatment system influent are available and 

can be used as another source of information about wastewater characteristics.

Based on the results of this comparison for the biological treatment technology option, 

EPA determined that the statistical distributional assumptions are appropriate for the effluent 

data and that the limitations are reasonable.

Limitations for FGD Wastewater Based on Chemical Precipitation Followed By VaporCompression Evaporation (Arsenic, Mercury, Selenium and TDS)

The final rules establishes NSPS/PSNS for arsenic, mercury, selenium, and TDS in FGD 

wastewater based on the performance of chemical precipitation followed by vapor-compression 

evaporation treatment using data from the Brindisi plant.170 All daily concentration values are 

equal to or below the daily limitations for all parameters. (The data for this plant were not 

collected at sufficient frequency to represent weekly sampling; thus, EPA could not calculate 

monthly averages for comparison to the monthly limit.) After thoroughly reviewing the data, 

EPA determined that the statistical distributional assumptions are appropriate for the effluent 

data and that the limitations are reasonable and achievable.

Limitations for Gasification Wastewater Based on Vapor-Compression Evaporation 

(Arsenic, Mercury, Selenium and TDS)

The final rule establishes BAT limitations/PSES and NSPS/PSNS for arsenic, mercury, 

selenium and TDS in gasification wastewater based on vapor-compression evaporation 

treatment. The Agency calculated the limitations for selenium and TDS using data from two 

 169 Similar to the mercury analyzer included as part of the technology basis for the effluent limitations, these 

additional process control options can provide treatment system operators with additional information, such as the 

influent nitrate-nitrite concentrations (for use in addition to ORP to confirm the appropriate nutrient dosage), 

between stage or effluent nitrate-nitrite concentrations (further confirmation of the nutrient dosage to support 

microbial activity for pollutant reduction), or effluent selenium concentrations. 

170 The final rule also establishes BAT limitations for FGD wastewater that are the same as the NSPS for FGD 

wastewater for plants who opt into the voluntary incentives program.
Section 13—Limitations And Standards: Data Selection And Calculation

13-43

plants: Polk and Wabash River plants. The limitations for arsenic and mercury were based only 

on data from Polk, because the arsenic and mercury data from Wabash River failed the LTA test 

(see Section 3.4 for a discussion of the LTA test). 

For arsenic and mercury, the daily concentration values used to calculate the limitations 

(i.e., from Polk) are below the daily limitations.171 For TDS, all observations for both Polk and 

Wabash River are below the daily limit.

For selenium, all observations for Wabash River were below the daily limit. At Polk, 

there is one observation above the daily limit. As discussed in Section 3.9, 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.172 Based upon its review of the data, EPA concluded if the plant 

designs and operates its treatment system to achieve the option long-term average for the model 

technology, then the plant will be able to comply with the limitations. Furthermore, EPA notes 

that Polk reuses all treated 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. 

The data for these plants were not collected frequently enough to represent weekly 

sampling; thus, EPA could not calculate monthly averages for comparison to the monthly 

limitations.

After thoroughly reviewing the data, EPA concluded that the statistical distributional 

assumption is appropriate for the effluent data and that the limitations are reasonable.

13.9.2 Comparison of Final Limitations to Influent Data

In addition to comparing the limitations to the effluent data used to develop the 

limitations, EPA also compared the pollutant concentrations for the treatment system influent to 

the daily limitations. For all treatment technology options for both FGD and gasification 

wastewater, the minimum, average, and maximum influent concentration values were much 

higher than the long-term average and final limitations. EPA found that influent concentrations 

were generally well-controlled 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.

 171 Although it did not use the arsenic and mercury data for the vapor-compression evaporator condensate at Wabash 

River to calculate the limitations, due to failing the LTA test, EPA nevertheless compared these data to the 

limitations and found that all observations were equal to or below both the daily and monthly limitations. 

172 EPA did not use Polk’s data for the forced circulation evaporator condensate to calculate the limitations due to 

that portion of the treatment system being in an upset condition; therefore, the Agency did not compare these data to 

the effluent limitations.
Section 13—Limitations And Standards: Data Selection And Calculation

13-44

13.10 REFERENCES

1. CSC. 2013. Computer Sciences Corporation. Results of the ICP/MS Collision Cell

Method Detection Limit Studies in the Synthetic Flue Gas Desulfurization Matrix. 

(16 January). DCN SE03872.

2. Palmer, S.A.K., M.A. Breton, T.J. Nunno, D.M. Sullivan, N.F. Surprenant. 1988. 

Metal/Cyanide Containing Wastes Treatment Technologies. DCN SE06421.

3. U.S. EPA. 1983. U.S. Environmental Protection Agency. Development Document 

for Effluent Limitations Guidelines and Standards for the Metal Finishing Point 

Source Category. Washington, DC. (June). EPA-440/1-83/091.

4. U.S. EPA. 2002. U.S. Environmental Protection Agency. Development Document 

for Final Effluent Limitations Guidelines and Standards for the Iron and Steel 

Manufacturing Point Source Category. Washington, DC. (April). EPA-821-R-02-

004.

5. U.S. EPA. 2003. U.S. Environmental Protection Agency. Development Document 

for the Final Effluent Limitations Guidelines and Standards for the Metal Products 

& Machinery Point Source Category. Washington, DC. (February). EPA-821-B-03-

001.

6. U.S. EPA. 2015a. U.S. Environmental Protection Agency. Sampling Data Used as 

the Basis for Effluent Limitations for the Steam Electric Rulemaking. (2 September). 

DCN SE06277.

7. U.S. EPA. 2015b. Statistical Support Document: Effluent Limitations for FGD 

Wastewater, Gasification Wastewater, and Combustion Residual Leachate for the 

Final Steam Electric Power Generating Effluent Limitations Guidelines and 

Standards. (30 September). DCN SE05733.

8. Westat. 2015. Memorandum to Ronald Jordan: “Serial Correlations for Steam 

Electric With and Without Adjustment for Baseline Values.” (21 September). DCN 

SE06279.
Section 14—Regulatory Implementation

14-1

SECTION 14

REGULATORY IMPLEMENTATION

This section provides guidance to permit writers, control authorities and steam electric 

power plants in implementing the revisions to the steam electric ELGs.

14.1 IMPLEMENTATION OF THE LIMITATIONS AND STANDARDS

The requirements in the rule apply to discharges from steam electric power plants

through incorporation into NPDES permits issued by the EPA or authorized states under Section 

402 of the Act and through local pretreatment programs under Section 307 of the Act. Permits or 

control mechanisms issued after the final rule’s effective date must incorporate the ELGs, as 

applicable. Also, under Section 510 of the CWA, states can 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 ELGs in the final rule, Section 

301(b)(1)(C) of CWA requires the permitting authority to impose more stringent effluent 

limitations, as necessary, to meet applicable water quality standards.

14.1.1 Requirements

This rule establishes new BAT, NSPS, PSES, and PSNS requirements for the following 

wastestreams: FGD wastewater, fly ash transport water, bottom ash transport water, FGMC 

wastewater, gasification wastewater, and combustion residual leachate. In some cases, the new 

BAT limitations are equal to previously established BPT limitations. The exact requirements 

may vary depending on the size of the steam electric generating unit, the fuel used in the steam 

electric generating unit, whether the discharge is from an existing or new source, the date on 

which the wastewater is generated, and the discharge type (directly to a surface water or 

indirectly to a POTW). 

The following tables summarize both the requirements from this rule and the previously 

established requirements for FGD wastewater, fly ash transport water, bottom ash transport 

water, FGMC wastewater, gasification wastewater, and combustion residual leachate for 

different scenarios. For the purpose of the requirements for direct dischargers in Table 14-1 and 

the rest of the information in Section 14, legacy wastewater is FGD wastewater, fly ash transport 

water, bottom ash transport water, FGMC wastewater, or gasification wastewater generated prior 

to the date established by the permitting authority that is as soon as possible beginning 

November 1, 2018, but no later than December 31, 2023.173 

 173 For plants voluntarily opting into the voluntary incentives program, legacy wastewater includes all these 

wastewaters, except for FGD wastewater. For plants in the voluntary incentives program, legacy FGD wastewater is 

FGD wastewater generated prior to December 31, 2023.
Section 14—Regulatory Implementation

14-2

Table 14-1. BPT/BAT Limitations for Existing Units > 50 MW and Not Oil-Fired Units; 

Not Also Subject to 1982 NSPS

Wastestream Pollutant Applicable Requirementsa

Date by Which Limits Must 

Be Achieved

FGD wastewater–legacy 

wastewaterb

TSS, Oil and 

Grease

BPT—423.12(b)(11)

BAT—423.13(g)(1)(ii) 

BAT voluntary incentives 

program— 423.13(g)(3)(ii) 

BPT limits must already be met. 

BAT limits must be met when 

they are incorporated into an 

NPDES permit, on or after the 

effective date of the final rule.

FGD wastewater –

generated on or after the 

as soon as possible date 

determined by the 

permitting authority

Arsenic, 

Mercury, 

Selenium, 

Nitrate/Nitrite as 

N

BAT—423.13(g)(1)(i) As soon as possible beginning 

November 1, 2018, but no later 

than December 31, 2023; 

determined by permitting 

authority (must be incorporated 

into an NPDES permit). TSS, Oil and 

Grease

BPT—423.12(b)(11)

FGD wastewater –

generated after Dec. 2023 

by plants in the voluntary 

incentives program 

Arsenic, 

Mercury, 

Selenium, TDS

BAT—423.13(g)(3)(i) Dec. 31, 2023 (must be 

incorporated into an NPDES 

permit).

TSS, Oil and 

Grease

BPT—423.12(b)(11)

Fly ash transport water –

legacy wastewater

TSS, Oil and 

Grease

BPT—423.12(b)(4)

BAT—423.13 (h)(1)(ii)

BPT limits must already be met. 

BAT limits must be met when 

they are incorporated into an 

NPDES permit, on or after the 

effective date of the final rule.

Fly ash transport water – 

generated on or after the 

as soon as possible date 

determined by the 

permitting authority

All BAT—423.13(h)(1)(i)

BPT—423.12(b)(4)

As soon as possible beginning 

November 1, 2018, but no later 

than December 31, 2023; 

determined by permitting 

authority (must be incorporated 

into an NPDES permit).

Flue Gas Mercury Control 

wastewater – legacy 

wastewater

TSS, Oil and 

Grease

BPT—423.12(b)(11) 

BAT—423.13(i)(1)(ii)

BPT limits must already be met. 

BAT limits must be met when 

they are incorporated into an 

NPDES permit, on or after the 

effective date of the final rule.

Flue Gas Mercury Control 

wastewater – generated 

on or after the as soon as 

possible date determined 

by the permitting 

authority

All BAT—423.13(i)(1)(i)

BPT—423.12(b)(11)

As soon as possible beginning 

November 1, 2018, but no later 

than December 31, 2023; 

determined by permitting 

authority (must be incorporated 

into an NPDES permit).

Bottom ash transport 

water - legacy wastewater

TSS, Oil and 

Grease

BPT—423.12(b)(4) 

BAT—423.13(k)(1)(ii)

BPT limits must already be met. 

BAT limits must be met when 

they are incorporated into an 

NPDES permit, on or after the 

effective date of the final rule.
Section 14—Regulatory Implementation

14-3

Table 14-1. BPT/BAT Limitations for Existing Units > 50 MW and Not Oil-Fired Units; 

Not Also Subject to 1982 NSPS

Wastestream Pollutant Applicable Requirementsa

Date by Which Limits Must 

Be Achieved

Bottom ash – generated 

on or after the as soon as 

possible date determined 

by the permitting 

authority

All BAT—423.13(k)(1)(i)

BPT—423.12(b)(4) 

As soon as possible beginning 

November 1, 2018, but no later 

than December 31, 2023; 

determined by permitting 

authority (must be incorporated 

into an NPDES permit).

Combustion residual 

leachate – generated at 

any time

TSS, Oil and 

Grease

BPT—423.12(b)(11) 

BAT—423.13(l)

BPT limits must already be met. 

BAT limits must be met when 

they are incorporated into an 

NPDES permit, on or after the 

effective date of the final rule.

Gasification wastewater –

legacy wastewater

TSS, Oil and 

Grease

BPT—423.12(b)(11) 

BAT—423.13(j)(1)(ii)

BPT limits must already be met. 

BAT limits must be met when 

they are incorporated into an 

NPDES permit, on or after the 

effective date of the final rule.

Gasification wastewater –

generated on or after the 

as soon as possible date 

determined by the 

permitting authority

Arsenic, 

Mercury, 

Selenium, TDS

BAT—423.13(j)(1)(i) As soon as possible beginning 

November 1, 2018, but no later 

than December 31, 2023; 

determined by permitting 

authority (must be incorporated 

into an NPDES permit).

TSS, Oil and 

Grease

BPT—423.12(b)(11)

a – All the applicable regulations are listed in this column, even if one regulation is expansive enough to include the 

requirements of another (e.g., BPT limits for TSS and Oil and Grease, BAT limits for just TSS; or BAT limits for all 

pollutants, BPT limits for just TSS and Oil and Grease).

b – As used in these tables, “legacy wastewater” is wastewater generated prior to the date determined by the 

permitting authority that is as soon as possible beginning November 1, 2018, but no later than December 31, 2023, 

except for FGD wastewater generated by plants in the voluntary incentives program. For plants in the voluntary 

incentives program, legacy FGD wastewater is FGD wastewater generated prior to December 31, 2023. 

Table 14-2. BAT/NSPS Limitations for Existing Units > 50 MW and Not Oil-Fired Units; 

Also Subject to 1982 NSPSa

Wastestream Pollutant

Applicable 

Requirements

Date by Which Standards 

Must Be Achieved

FGD wastewater–

generated at any time

TSS, Oil and Grease 1982 NSPS—

423.15(a)(3)

1982 NSPS must already be 

met.

FGD wastewater –

generated on or after the 

as soon as possible date 

determined by the 

permitting authority

Arsenic, Mercury, 

Selenium, Nitrate/Nitrite 

as N

BAT—

423.13(g)(1)(i)

As soon as possible beginning 

November 1, 2018, but no later 

than December 31, 2023; 

determined by permitting 

authority (must be incorporated 

into an NPDES permit).

Fly ash transport water –

generated at any time

All 1982 NSPS—

423.15(a)(7)

1982 NSPS must already be 

met.
Section 14—Regulatory Implementation

14-4

Table 14-2. BAT/NSPS Limitations for Existing Units > 50 MW and Not Oil-Fired Units; 

Also Subject to 1982 NSPSa

Wastestream Pollutant

Applicable 

Requirements

Date by Which Standards 

Must Be Achieved

Fly ash transport water –

generated on or after the 

as soon as possible date 

determined by the 

permitting authority

All BAT—

423.13(h)(1)(i)

As soon as possible beginning 

November 1, 2018, but no later 

than December 31, 2023; 

determined by permitting 

authority (must be incorporated 

into an NPDES permit).

Flue Gas Mercury 

Control wastewatergenerated at any time

TSS, Oil and Grease 1982 NSPS—

423.15(a)(3)

1982 NSPS must already be 

met.

Flue Gas Mercury 

Control wastewater – 

generated on or after the 

as soon as possible date 

determined by the 

permitting authority

All BAT—423.13(i)(1)(i) As soon as possible beginning 

November 1, 2018, but no later 

than December 31, 2023; 

determined by permitting 

authority (must be incorporated 

into an NPDES permit).

Bottom ash water –

generated at any time 

TSS, Oil and Grease 1982 NSPS—

423.15(a)(6)

1982 NSPS must already be 

met.

Bottom ash – generated 

on or after the as soon as 

possible date determined 

by the permitting 

authority

All BAT—

423.13(k)(1)(i)

As soon as possible beginning 

November 1, 2018, but no later 

than December 31, 2023; 

determined by permitting 

authority (must be incorporated 

into an NPDES permit).

Combustion residual 

leachate – generated at 

any time

TSS, Oil and Grease 1982 NSPS—

423.15(a)(3) 

1982 NSPS must already be 

met.

Combustion residual 

leachate – generated on 

or after the as soon as 

possible date determined 

by the permitting 

authority

TSS BAT—423.13(l) BAT limits must be met when 

they are incorporated into an 

NPDES permit, on or after the

effective date of the final rule.

Gasification wastewater 

– generated at any time

TSS, Oil and Grease 1982 NSPS—

423.15(a)(3)

1982 NSPS must already be 

met.

Gasification wastewater 

- generated on and after 

the as soon as possible 

date determined by the 

permitting authority

Arsenic, Mercury, 

Selenium, TDS

BAT—423.13(j)(1)(i) As soon as possible beginning 

November 1, 2018, but no later 

than December 31, 2023; 

determined by permitting 

authority (must be incorporated 

into an NPDES permit).

a – The plants subject to the 1982 NSPS area also subject to the 2015 BAT.
Section 14—Regulatory Implementation

14-5

Table 14-3. BPT/BAT Limitations for Existing Units (< or Equal To 50 MW or Oil-Fired 

Units); Not Also Subject to 1982 NSPS

Wastestream Pollutant

Applicable 

Requirementsa

Date by Which Limits Must 

Be Achieved

FGD wastewater TSS, Oil and Grease BPT—423.12(b)(11) 

BAT—423.13(g)(2)

BPT limits must already be 

met. BAT limits must be met 

when they are incorporated 

into an NPDES permit, on or 

after the effective date of the 

final rule.

Fly ash transport water TSS, Oil and Grease BPT—423.12(b)(4) 

BAT—423.13(h)(2)

BPT limits must already be 

met. BAT limits must be met 

when they are incorporated 

into an NPDES permit, on or 

after the effective date of the 

final rule.

Flue Gas Mercury Control 

wastewater

TSS, Oil and Grease BPT—423.12(b)(11) 

BAT— 423.13(i)(2)

BPT limits must already be 

met. BAT limits must be met 

when they are incorporated 

into an NPDES permit, on or 

after the effective date of the 

final rule.

Bottom ash transport 

water

TSS, Oil and Grease BPT—423.12(b)(4) 

BAT—423.13(k)(2)

BPT limits must already be 

met. BAT limits must be met 

on the effective date of the 

final rule.

Combustion residual 

leachate 

TSS, Oil and Grease BPT—423.12(b)(11) 

BAT—423.13(l)

BPT limits must already be 

met. BAT limits must be met 

when they are incorporated 

into an NPDES permit, on or 

after the effective date of the 

final rule.

Gasification wastewater TSS, Oil and Grease BPT—423.12(b)(11) 

BAT—423.13(j)(2)

BPT limits must already be 

met. BAT limits must be met 

when they are incorporated 

into an NPDES permit, on or 

after the effective date of the 

final rule.

a – All the applicable regulations are listed in this column, even if one regulation is expansive enough to include the 

requirements of another (e.g., BPT limits for TSS and Oil and Grease, BAT limits for just TSS).
Section 14—Regulatory Implementation

14-6

Table 14-4. BAT/NSPS Limitations for Existing Units (< or Equal To 50 MW or OilFired Units); Also Subject to 1982 NSPSa

Wastestream Pollutant

Applicable 

Requirements

Date by Which Standards 

Must Be Achieved

FGD wastewater–

generated at any time

TSS, Oil and Grease 1982 NSPS—

423.15(a)(3) 

1982 NSPS must already be 

met.

FGD wastewater –

generated on or after the 

as soon as possible date 

determined by the 

permitting authority

TSS BAT—423.13(g)(2) BAT limits must be met when 

they are incorporated into an 

NPDES permit, on or after the 

effective date of the final rule.

Fly ash transport water –

generated at any time

All 1982 NSPS—

423.15(a)(7)

1982 NSPS must already be 

met.

Fly ash transport water –

generated on or after the 

as soon as possible date 

determined by the 

permitting authority

TSS BAT—423.13(h)(2) BAT limits must be met when 

they are incorporated into an 

NPDES permit, on or after the 

effective date of the final rule.

Flue Gas Mercury 

Control wastewatergenerated at any time

TSS, Oil and Grease 1982 NSPS—

423.15(a)(3)

1982 NSPS must already be 

met.

Flue Gas Mercury 

Control wastewater – 

generated on or after the 

as soon as possible date 

determined by the 

permitting authority

TSS BAT—423.13(i)(2) BAT limits must be met when 

they are incorporated into an 

NPDES permit, on or after the 

effective date of the final rule.

Bottom ash water –

generated at any time 

TSS, Oil and Grease 1982 NSPS—

423.15(a)(6)

1982 NSPS must already be 

met.

Bottom ash – generated 

on or after the as soon as 

possible date determined 

by the permitting 

authority

TSS BAT—423.13(k)(2) BAT limits must be met when 

they are incorporated into an 

NPDES permit, on or after the 

effective date of the final rule.

Combustion residual 

leachate – generated at 

any time

TSS, Oil and Grease 1982 NSPS—

423.15(a)(3) 

1982 NSPS must already be 

met.

Combustion residual 

leachate – generated on 

or after the as soon as 

possible date determined 

by the permitting 

authority

TSS BAT—423.13(l) BAT limits must be met when 

they are incorporated into an 

NPDES permit, on or after the 

effective date of the final rule.

Gasification wastewater 

– generated at any time

TSS, Oil and Grease 1982 NSPS—

423.15(a)(3)

1982 NSPS must already be 

met.
Section 14—Regulatory Implementation

14-7

Table 14-4. BAT/NSPS Limitations for Existing Units (< or Equal To 50 MW or OilFired Units); Also Subject to 1982 NSPSa

Wastestream Pollutant

Applicable 

Requirements

Date by Which Standards 

Must Be Achieved

Gasification wastewater 

- generated on and after 

the as soon as possible 

date determined by the 

permitting authority

TSS BAT—423.13(j)(2) BAT limits must be met when 

they are incorporated into an 

NPDES permit, on or after the 

effective date of the final rule.

Table 14-5. 2015 NSPS Limitations for New Sources

Wastestream Pollutant Requirement

Date by Which Limits Must 

Be Achieved

FGD wastewater Arsenic, Mercury, 

Selenium, TDS

2015 NSPS—

423.15(b)(13)

When they are incorporated 

into an NPDES permit for a 

new source, on or after the 

effective date of the final rule.

Fly ash transport water All 2015 NSPS—

423.15(b)(7)

When they are incorporated 

into an NPDES permit for a 

new source, on or after the 

effective date of the final rule.

Flue Gas Mercury Control 

wastewater

All 2015 NSPS—

423.15(b)(14)

When they are incorporated 

into an NPDES permit for a 

new source, on or after the 

effective date of the final rule.

Bottom ash transport 

water

All 2015 NSPS—

423.15(b)(6)

When they are incorporated 

into an NPDES permit for a 

new source, on or after the 

effective date of the final rule.

Combustion residual 

leachate 

Arsenic and Mercury 2015 NSPS—

423.15(b)(16)

When they are incorporated 

into an NPDES permit for a 

new source, on or after the 

effective date of the final rule. TSS, Oil and Grease 2015 NSPS—

423.15(b)(3)

Gasification wastewater Arsenic, Mercury, 

Selenium, TDS

2015 NSPS—

423.15(b)(15)

When they are incorporated 

into an NPDES permit for a 

new source, on or after the 

effective date of the final rule.
Section 14—Regulatory Implementation

14-8

Table 14-6. PSES for Existing Units > 50 MW and Not Oil-Fired Units; Not Also Subject 

to 1982 PSNS

Wastestreama Pollutant Requirement

Date by Which Limits Must 

Be Achieved

FGD wastewater –

generated on or after 

November 1, 2018

Arsenic, Mercury, 

Selenium, Nitrate/Nitrite 

as N

PSES—423.16(e) As of November 1, 2018

Fly ash transport watergenerated on or after 

November 1, 2018

All PSES—423.16(f) As of November 1, 2018

Flue Gas Mercury Control 

wastewater- generated on 

or after November 1, 

2018

All PSES—423.16(h) As of November 1, 2018

Bottom ash transport 

water- generated on or 

after November 1, 2018

All PSES—423.16(g) As of November 1, 2018

Gasification wastewatergenerated on or after 

November 1, 2018

Arsenic, Mercury, 

Selenium, TDS 

PSES—423.16(i) As of November 1, 2018

a – There are no requirements for discharges of combustion residual leachate or any of these wastestreams if the 

wastewater is generated prior to November 1, 2018. There are also no requirements for discharges from units less 

than or equal to 50 MW or oil-fired generating units.

Table 14-7. PSES for Existing Units >50 MW and Not Oil-Fired Units; Also Subject to 

1982 PSNS

Wastestreama Pollutant Requirement

Date by Which Limits Must 

Be Achieved

FGD wastewatergenerated on or after 

November 1, 2018

Arsenic, Mercury, 

Selenium, Nitrate/Nitrite 

as N

PSES—423.16(e) As of November 1, 2018

Fly ash transport water All 1982 PSNS—

423.17(a)(5)

1982 PSNS must already be 

met

Flue Gas Mercury Control 

wastewater – generated 

on or after November 1, 

2018

All PSES—423.16(h) As of November 1, 2018

Bottom ash transport 

water – generated on or 

after November 1, 2018

All PSES—423.16(g) As of November 1, 2018

Gasification wastewater –

generated on or after 

November 1, 2018

Arsenic, Mercury, 

Selenium, TDS

PSES—423.16(i) As of November 1, 2018

a – There are no requirements for combustion residual leachate or any of these wastestreams for wastewater, other 

than fly ash transport water, if generated prior to November 1, 2018. There are also no requirements for units less 

than or equal to 50 MW or oil-fired units.
Section 14—Regulatory Implementation

14-9

Table 14-8. 2015 PSNS for New Sources

Wastestream Pollutant Requirement

Date by Which Limits Must 

Be Achieved

FGD wastewater Arsenic, Mercury, 

Selenium, TDS

2015 PSNS—

423.17(b)(6)

Effective date of the final rule

Fly ash transport water All 2015 PSNS—

423.17(b)(5)

Effective date of the final rule

Flue Gas Mercury 

Control wastewater

All 2015 PSNS—

423.17(b)(7)

Effective date of the final rule

Bottom ash transport 

water

All 2015 PSNS—

423.17(b)(8)

Effective date of the final rule

Gasification wastewater Arsenic, Mercury, 

Selenium and Total 

Dissolved Solids

2015 PSNS—

423.17(b)(9)

Effective date of the final rule

Leachate Arsenic and Mercury 2015 PSNS—

423.17(b)(10)

Effective date of the final rule

14.1.2 Timing 

As shown in Table 14-1 through Table 14-8, the timing of the final rule’s requirements 

for a particular discharge varies depending on the size of the steam electric generating unit, the 

fuel used in the steam electric generating unit, whether the discharge is from an existing or new 

source, the date on which the wastewater is generated, and the discharge type (directly to a 

surface water or indirectly to a POTW). 

The direct discharge effluent limitations in this rule apply only when implemented in an 

NPDES permit issued to a discharger after the effective date of this rule. Under the CWA, the 

permitting authority must incorporate these ELGs into NPDES permits as a floor or a minimum 

level of control. While the rule is effective on its effective date, the rule allows permitting 

authorities to determine the date when the new effluent limitations for FGD wastewater, fly ash 

transport water, bottom ash transport water, FGMC wastewater, and gasification wastewater 

apply to a given discharger. The permitting authority must make these new effluent limitations 

applicable on November 1, 2018 or determine a specified date for a specific discharger. For any 

new effluent limitation that is specified to become applicable after November 1, 2018, the 

specified date must be as soon as possible, but in no case later than December 31, 2023. For 

dischargers in the voluntary incentives program choosing to meet effluent limitations for FGD 

wastewater based on the use of evaporation technology, the date for meeting those limitations is 

December 31, 2023. 

For combustion residual leachate, and for certain wastestreams (FGD wastewater, fly ash 

transport water, bottom ash transport water, FGMC wastewater, and gasification wastewater) at 

oil-fired generating units and small generating units (50 MW or less), the final BAT limitations 

apply on the date that a permit is issued to a discharger, following the effective date of this rule. 

The rule does not build in an implementation period for meeting these limitations, as the BAT 

limitation on TSS is equal to the previously promulgated BPT limitation on TSS in low volume 

waste sources and in ash transport water. 
Section 14—Regulatory Implementation

14-10

Pretreatment standards are self-implementing, meaning they apply directly, without the 

need for a permit. In this rule, the pretreatment standards for existing sources must be met by 

November 1, 2018. 

The requirements for new source direct and indirect discharges (NSPS and PSNS) 

provide no extended implementation period. NSPS apply when any NPDES permit is issued to a 

new source direct discharger, following the effective date of this rule; PSNS apply to any new 

source discharging to a POTW, as of the effective date of the final rule. 

Regardless of when a plant’s NPDES permit will expire and a new permit application 

will be submitted, the plant should immediately begin evaluating how it intends to comply with 

the requirements of the final ELGs. In cases where significant changes in operation are necessary 

for compliance with the new effluent limitations, the plant should discuss such changes with the 

permitting authority and evaluate appropriate steps and a timeline for the changes prior to the 

permit renewal process. 

In cases where a plant’s final NPDES permit will be issued after the effective date of the 

final ELGs, but before November 1, 2018, the permitting authority should apply limitations 

based on the previously promulgated BPT limitations or the plant’s other applicable permit 

limitations until at least November 1, 2018. The permitting authority should also determine what 

date represents the soonest date, beginning November 1, 2018, that the plant can meet the final 

BAT limitations in this rule. The permit should require compliance with the final BAT 

limitations by that date, making clear that in no case shall the limitations begin to apply later than 

December 31, 2023. Once the requirements are incorporated into a permit, this requirement 

assures that the effluent limitations required by the final rule will be met no later than December 

31, 2023 in every issued permit and that the effluent limitations will be enforceable even if the 

permit is administratively continued. For permits that come up for renewal on or after November 

1, 2018, the permitting authority should determine the earliest possible date that the plant can 

meet the limitations in this rule (but in no case later than December 31, 2023), and apply the final 

limitations as of that date (BPT limitations or the plant’s other applicable permit limitations 

would apply until such date). 

As specified by the rule, the “as soon as possible” date determined by the permitting 

authority is November 1, 2018, unless the permitting authority determines another date after 

receiving information submitted by the discharger.174 Assuming that the permitting authority 

receives relevant information from the discharger, in order to determine what date is “as soon as 

possible” within the implementation period, the permitting authority must then consider the 

following factors:

• Time to expeditiously plan (including time to raise capital), design, procure, and 

install equipment to comply with the requirements of the final rule.

• Changes being made or planned at the plant in response to new or existing 

requirements at fossil fuel-fired power plants under the Clean Air Act, as well as 

 174 Even after the permitting authority receives information from the discharger, it still may be appropriate to 

determine that November 1, 2018, is “as soon as possible” for that discharger.
Section 14—Regulatory Implementation

14-11

regulations for the disposal of coal combustion residuals under subtitle D of the 

Resource Conservation and Recovery Act.

• For FGD wastewater requirements only, an initial commissioning period to optimize 

the installed equipment.

• Other factors as appropriate.

With respect to the first factor, the permitting authority should evaluate what operational 

changes are expected at the plant to meet the new BAT limitations for each wastestream, 

including the types of new treatment technologies that the plant plans to install, process changes 

anticipated, and the timeframe estimated to plan, design, procure, and install any relevant 

technologies. As specified in the second factor, the permitting authority must also consider 

scheduling for installation of equipment, which includes a consideration of plant changes 

planned or being made to comply with certain other key rules that affect the steam electric power 

generating industry. As specified in the third factor, for the FGD wastewater requirements only, 

the permitting authority must consider whether it is appropriate to allow more time for 

implementation, in addition to the three years before implementation of the rule begins on 

November 1, 2018, in order to ensure that the plant has appropriate time to optimize any relevant 

technologies. EPA’s record demonstrates that plants installing the FGD technology basis spent 

several months optimizing its operation (initial commissioning period). Without allowing 

additional time for optimization, the plant would likely not be able to meet the limitations 

because they are based on the operation of optimized systems. See Section 14.1.5 for additional 

discussion and examples regarding implementation of the final ELGs into NPDES permits.

The “as soon as possible” date determined by the permitting authority may or may not be 

different for each wastestream. EPA recommends that the permitting authority provide a welldocumented justification for how it determined the “as soon as possible” date in the fact sheet or 

administrative record for the permit. If the permitting authority determines a date later than 

November 1, 2018, the justification should explain why allowing additional time to meet the 

limitations is appropriate, and why the discharger cannot meet the final effluent limitations as of 

November 1, 2018. EPA recommends that the permitting authority consider and discuss factors 

such as the types of new treatment technologies that the plant plans to install, process changes 

anticipated, and the timeframe estimated to install and optimize any relevant technologies. In 

cases where the plant is already operating the BAT technology basis for a specific wastestream 

(e.g., dry fly ash handling system), operating the majority of the BAT technology basis (e.g., 

FGD chemical precipitation and biological treatment, without sulfide addition), or expecting that 

relevant treatment and process changes will be in place prior to November 1, 2018, it would not 

generally be appropriate to allow additional time beyond that date. Regardless, in all cases, the 

permitting authority must make clear in the permit what date the plant must meet the limitations, 

and that date may be no later than December 31, 2023. 

Where a discharger chooses to participate in the voluntary incentives program and be 

subject to effluent limitations for FGD wastewater based on evaporation, the permitting authority 

must allow the plant up to December 31, 2023, to meet those limitations; again, the permit must 

make clear that the plant must meet the final limitations by December 31, 2023.
Section 14—Regulatory Implementation

14-12

14.1.3 Applicability of 1982 NSPS/PSNS

In 1982, EPA promulgated NSPS/PSNS for certain discharges from new generating units. 

Regardless of the outcome of the current rulemaking, those generating units that are currently 

subject to the 1982 NSPS/PSNS will continue to be subject to such standards. In addition, EPA is 

clarifying in the text of the regulation that generating units to which the 1982 NSPS/PSNS apply 

will also be subject to the newly promulgated BAT/PSES requirements because they will be 

existing sources with respect to such new requirements. See Table 14-2 and Table 14-6. 

14.1.4 Legacy Wastewater

For purposes of this rule, “legacy wastewater” is FGD wastewater, fly ash transport 

water, bottom ash transport water, FGMC wastewater, or gasification wastewater that is 

discharged to waters of the U.S. and generated prior to the date determined by the permitting 

authority that is as soon as possible beginning November 1, 2018, but no later than December 31, 

2023 (see preamble Section VIII.C.7).175 Under this rule, legacy wastewater must comply with 

specific BAT limitations, which EPA is setting equal to the previously promulgated BPT 

limitations on TSS in fly ash and bottom ash transport water and low volume waste sources. 

14.1.5 Combined Wastestreams

Most steam electric power plants combine various wastewaters (e.g., FGD wastewater, 

fly ash and bottom ash transport water) and cooling water either before or after treatment. In 

such cases, to derive effluent limitations or standards at the point of discharge, the permitting 

authority typically combines the allowable pollutant concentrations loadings for each set of 

requirements to arrive at a specific limitation or standard, per pollutant, for the combined 

wastestream, using the building block approach or combined waste stream formula (CWF). See 

NPDES Permit Writer’s Manual and 40 CFR part 403.6. For concentration-based limitations, 

rather than mass-based limitations, the effluent limitation or standard for the mixed wastestream 

is a flow-weighted combination of the appropriate concentration–based limitations or standards 

for each applicable wastestream. Such a calculation is relatively straightforward if the individual 

wastestreams are subject to limitations or standards for the same pollutants and the flows of the 

wastestreams are relatively consistent. This, however, is not the case for all wastestreams at 

steam electric power plants.

Because EPA anticipates that permitting authorities will apply concentration-based 

limitations or standards, rather than mass-based limitations or standards, in NPDES permits for 

steam electric power plants, proper application of the building block approach or CWF is 

necessary to ensure that the reduced pollutant concentrations observed in a combined discharge 

reflect proper treatment and control strategies rather than dilution. Where a regulated 

wastestream is combined with a well-known dilution flow, such as cooling water, noncontaminated stormwater, or cooling tower blowdown, the concentration-based limitation for the 

regulated wastestream is reduced by multiplying it by a factor.176 This factor is the total flow for 

 175 For plants in the voluntary incentives program, legacy FGD wastewater is FGD wastewater generated prior to 

December 31, 2023.

176 As is the case with a single regulated wastestream, if the combined wastestream is not discharged, then the 

limitations and standards are not applicable.
Section 14—Regulatory Implementation

14-13

the combined wastestream minus the dilution flow divided by the total flow for the combined 

wastestream. In some cases, a wastestream (e.g., FGD wastewater) containing a regulated 

pollutant (e.g., selenium or mercury) combines with other wastestreams that contain the same 

pollutant, but that are not regulated for that pollutant (e.g., legacy wastewater contained in a 

surface impoundment). In these cases, based on the information in its record, EPA strongly 

recommends that in applying the building block approach or CWF to the regulated pollutant 

(selenium or mercury, in the example above), permitting authorities either treat the wastestream 

that does not have a limitation or standard for the pollutant (legacy wastewater contained in a 

surface impoundment, in the example above) as a dilution flow or determine a concentration for 

that pollutant based on representative samples of that wastestream.177

In all cases where the permitting authority is applying the building block approach or 

CWF, the permitting authority must also determine the flow rate for use in the building block 

approach or CWF. EPA strongly recommends that the permitting authority calculate the flow 

rate based on representative flow rates for each wastestream.

EPA recommends that, where a steam electric power plant chooses to combine two or 

more wastestreams that would call for the use of the building block approach or CWF to 

determine the appropriate limitations or standards for the combined wastestream, the plant 

should be responsible for providing sufficient data that reflect representative samples of each of 

the individual wastestreams that make up the combined wastestream. EPA strongly recommends 

that the representative samples reflect a study of each of the applicable wastestreams that covers 

the full range of variability in concentration and flow for each wastestream. 

EPA anticipates that proper application of the building block approach or CWF will 

result in combined wastestream limitations and standards that will enable steam electric power 

plants to combine certain wastestreams, while also ensuring that the plant is actually treating its 

wastewater as intended by the Act and this rule, rather than simply diluting it. EPA’s record 

demonstrates, however, that combined wastestream limitations and standards at the point of 

discharge, derived using the building block approach or CWF, will be impractical or infeasible 

for some combined wastestreams because the resulting limitation or standard for any of the 

regulated pollutants in the combined wastestream would fall below analytical detection levels. In 

such cases, the permitting authority should establish internal limitations on the regulated 

wastestream, prior to mixing of the wastestream with others, per 40 CFR § 122.45(h) and 40 

CFR § 403.6.178 See Section 14.1.6 for more examples and details about this guidance.

 177 EPA does not recommend that the permitting authority assume that the pollutant is present at a significant level 

in the wastestream that does not have a relevant limitation or standard and just apply the same limitation or standard

for the pollutant to the mixed wastestream. This will not ensure that treatment and control strategies are being 

employed to achieve the limitations or standards, rather than simply dilution. 

178 As described earlier for wastestreams with zero discharge limitations or standards, just because a wastestream

with a numeric limitation or standard is moved, prior to discharge, for use in another plant process, that does not

mean that the wastestream ceases to be subject to the applicable numeric limitation or standard, assuming that the 

wastestream is eventually discharged.
Section 14—Regulatory Implementation

14-14

14.1.6 Implementation Examples

This section presents examples of proper implementation of the BPT and BAT effluent 

limitations in various scenarios. Throughout these examples, EPA discusses both legacy 

wastewater (see Section 8.10), as well as wastewater generated on or after the “applicable date” 

determined by the permitting authority (referred to throughout this section as “newly generated 

wastewater”).

Example 14-1: Plant that Currently Discharges FGD 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 final ELGs. 

Under the final rule, the plant will need to meet the new BAT effluent limitations for the newly 

generated 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, three of 

which are included in the post rule scenarios in Figure 14-1. Under post rule Scenario 1, 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 (at Monitoring Point Z) with the new BAT and the 

previously promulgated BPT effluent limitations for the newly generated FGD wastewater at the 

effluent from the tank-based treatment system (see 40 CFR § 423.12(b)(11) and 40 CFR § 

423.13(g)(1)(i)). 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 be subject to the legacy FGD wastewater BAT limitations 

and the previously promulgated BPT effluent limitations (see 40 CFR § 423.12(b)(11) and 40 

CFR § 423.13(g)(1)(ii)) at Monitoring Point Y.179

Under post rule Scenario 2, 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. 

Under Scenario 2a, the permit may specify monitoring for compliance for the combined 

wastestream at the point of discharge (Monitoring Point Y) using the building block approach as 

described in Section 14.1.4, if the resulting limitation for each regulated pollutant in the 

combined wastestream is above the analytical detection level (see 40 CFR § 423.12(b)(11) and 

40 CFR § 423.13(g)(1)(ii) for legacy FGD wastewater and 40 CFR § 423.12(b)(11) and 40 CFR 

§ 423.13(g)(1)(i) for newly generated FGD wastewater). If the limitations are not above the 

analytical detection level for each regulated pollutant, then as under Scenario 2b, monitoring at 

the point of discharge after commingling newly generated FGD wastewater with legacy 

wastewater contained in the impoundment (Monitoring Point Y) would be unable to demonstrate 

compliance with the limitation for newly generated FGD wastewater (40 CFR § 423.13(g)(1)(i)). 

In this case, EPA recommends measuring for compliance prior to commingling (Monitoring 

Point Z). See 40 CFR 122.46(h). The permit could specify that the plant monitor for compliance 

with the BPT TSS and oil and grease effluent limitations (see 40 CFR § 423.12(b)(11)) for the 

 179 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

14-15

combined wastestream at the point of discharge (Monitoring Point Y) because the legacy FGD 

wastewater and the newly generated wastewater are subject to the same limitations.. 

Under post rule Scenario 3, the plant transfers the newly generated FGD wastewater to 

the existing FGD wastewater impoundment that contains legacy FGD wastewater. The effluent 

from this impoundment is then transferred to the tank-based treatment system. This approach can 

be used if the resulting limitation using the building block approach for the combined 

wastestream for each regulated pollutant in the combined wastestream is above the analytical 

detection level. If this is the case, the plant would demonstrate compliance with the resulting 

limitations at the effluent from the tank-based treatment system (Monitoring Point Y).
Section 14—Regulatory Implementation

14-16

FGD

Wastewater

FGD Wastewater 

Impoundment

Pre Rule

Scenario

Receiving Water

Legacy

FGD Wastewater

Impoundment BPT

BAT

1

Newly Generated 

FGD Wastewater

BPT

BAT

Tank Based 

Treatment

System

Post Rule

Scenario

Receiving Water

Tank Based 

Treatment

System

Legacy and 

Newly Generated 

FGD Wastewater 

BAT Impoundment

2b BPT

BAT

Tank Based 

Treatment

System

Legacy and Newly 

Generated 

FGD Wastewater 

Impoundment BPT

BAT

3 Newly Generated 

FGD Wastewater

BPT

Newly Generated 

FGD Wastewater

Receiving Water

Receiving Water

Point Z Point Y

Tank Based 

Treatment

System

Legacy and 

Newly Generated 

FGD Wastewater 

Impoundment

2a BPT

BAT

Newly Generated 

FGD Wastewater

Point Y

Receiving Water

Point Y

Point Z

Point Y

Point Y

Figure 14-1. Legacy FGD Wastewater Treatment Scenario
Section 14—Regulatory Implementation

14-17

Example 14-2: Plant that Currently Discharges Fly Ash Transport Water and FGMC 

Wastewater

Figure 14-2 presents an example treatment scenario for an impoundment receiving fly ash 

transport water and FGMC wastewater prior to the implementation of the ELGs. Under the final 

rule, the plant will need to meet the zero discharge BAT standard for fly ash transport water and 

FGMC wastewater generated on or after the as soon as possible date determined by the 

permitting authority. In this example, EPA envisions that the plant will have installed a dry fly 

ash handling system to meet the new BAT limitation. However, legacy fly ash transport water 

and FGMC wastewater could still be discharged from the impoundment (e.g., after a rainfall 

event, when dewatering the impoundment for closure) and would be subject to the legacy fly ash 

transport water and FGMC wastewater BAT limitations (see 40 CFR § 423.13(h)(1)(ii) and 40 

CFR § 423.13(i)(1)(ii)) and previously established BPT limitations (see 40 CFR § 423.12(b)(4)) 

at Monitoring Point Y.

Fly Ash

Transport Water 

and FGMC 

Wastewater

Fly Ash 

Transport Water and 

FGMC Wastewater 

Impoundment

Pre Rule

Scenario

Receiving Water

Legacy Fly Ash

Transport Water and 

FGMC Wastewater

Impoundment

Receiving Water

Post Rule

Scenario BPT

BAT

BPT

Note: Fly ash converted to dry handling system.

No newly generated fly ash transport water.

Point Y

Point Y

Figure 14-2. Legacy Fly Ash Transport Water and FGMC Wastewater Treatment Scenario

Example 14-3: Plant that Does not Currently Discharge Fly Ash Transport Water

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. 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.
Section 14—Regulatory Implementation

14-18

Fly Ash 

Transport Water 

Impoundment

No

Discharge

Pre Rule

Scenario

Fly Ash

Generating Transport Water

Unit

Sluicing 

System

Legacy and Newly 

Generated Fly Ash 

Transport Water 

Impoundment No

Discharge

Post Rule

Scenario

Fly Ash

Generating Transport Water* Unit

Sluicing 

System

Note: No changes/modifications are necessary for the system because the 

configuration already meets the 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.

Figure 14-3. Complete Recycle Fly Ash Transport Water Treatment Scenario

Example 14-4: Plant that Currently Discharges Bottom Ash Transport Water

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 sluicing system, but some of the bottom ash transport water is 

discharged to a receiving water. Under the final rule, the plant will need to meet the new zero 

discharge BAT limitation for newly generated bottom ash transport water. In this case, EPA 

envisions that the plant has at least two options for complying with the new limitation, which are 

included in the post rule scenarios in Figure 14-4. Under post rule Scenario 1, 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 be subject to the legacy bottom ash transport water BAT 

limitations (see 40 CFR § 423.13(k)(1)(ii)) and the previously promulgated BPT effluent 

limitations (see 40 CFR § 423.12(b)(4)) at Monitoring Point Y.

Under post rule Scenario 2, the plant would evaluate the water balance for the bottom ash 

system and determine whether the system could operate without discharging to a receiving water. 
Section 14—Regulatory Implementation

14-19

If the plant determines that the system can achieve complete recycle, then the plant can continue 

to operate the existing bottom ash handling system, and ensure that it meets zero discharge (see 

40 CFR § 423.13(k)(1)(i)). 

Bottom Ash Transport 

Water Impoundment

BPT

Pre Rule

Scenario

Bottom Ash

Generating Transport Water

Unit

Sluicing 

System

No

Discharge

Post Rule

Scenario

Newly Generated 

Bottom Ash

Generating Transport Water*

Unit Sluicing 

System

*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.

1

2

Legacy Bottom Ash 

Transport Water 

Impoundment

BPT

BAT

Note for Scenario 1: Bottom ash converted to dry handling system. 

No newly generated bottom ash transport water.

Receiving Water

Receiving Water

Point Y

Point Y

Legacy Bottom Ash 

Transport Water 

Impoundment BPT

BAT

Point Y

Receiving Water

Figure 14-4. Partial Recycle Bottom Ash Transport Water Treatment Scenario 
Section 14—Regulatory Implementation

14-20

Example 14-5: Plant that Generates Gasification Wastewater

Figure 14-5 presents an example treatment scenario, under the final rule, for an IGCC 

plant treating and discharging gasification wastewater prior to the implementation of the ELGs

(see 40 CFR § 423.12(b)(3)). Under the final rule, the plant will need to meet the new BAT 

limitations for newly generated gasification wastewater, in which case, EPA envisions that the 

plant has at least three options for complying with the BAT limitations. These options are 

included in the post rule scenarios in Figure 14-5. Under post rule Scenario 1, the plant would 

continue to treat and discharge the gasification wastewater, while ensuring it is now meeting the 

newly promulgated BAT and BPT limitations for gasification wastewater (40 CFR § 

423.13(j)(1)(i) and 40 CFR § 423.12(b)(11)). 

Under post rule Scenario 2, the plant would evaluate the water balance for the 

gasification process and potentially conclude that the gasification wastewater could be reused 

completely back into the gasification process without treatment and it would no longer require 

discharging to a receiving water. 

Under post rule Scenario 3, the plant would evaluate the water balance for the 

gasification process and potentially conclude that some of the gasification wastewater could be 

reused (with or without treatment) back into the gasification process; however, the plant would 

still require discharging gasification water to a receiving water. In this case, the plant would 

continue to treat and discharge the gasification wastewater, while ensuring it was now meeting 

the newly promulgated limitations (see 40 CFR § 423.13(j)(1)(i) and 40 CFR § 423.12(b)(11)). 
Section 14—Regulatory Implementation

14-21

Gasification

Wastewater

Pre Rule

Scenario

Receiving Water

1 Newly Generated 

Gasification Wastewater

BPT

BAT

Tank Based 

Treatment

System

Post Rule

Scenario

Receiving Water

Tank Based 

Treatment

System 3

BPT

BAT

BPT

Receiving Water

2

Tank Based 

Treatment

System

Gasification 

Wastewater 

Storage No

Discharge

Gasification 

Process

Gasification 

Wastewater 

Storage

Gasification 

Process

Point Y

Point Y

Point Y

Figure 14-5. Gasification Wastewater Treatment Scenario

Example 14-6: Plant that Generates Combustion Residual Leachate and FGD 

Wastewater

Figure 14-6 presents an example treatment scenario, under the final rule, for an 

impoundment that receives combustion residual leachate and FGD wastewater prior to the 

implementation of the ELGs (see 40 CFR § 423.12(b)(3)). Under the final rule, the plant will 

need to meet the new BAT effluent limitations for the newly generated FGD wastewater. EPA 

envisions that the plant has at least two options, which are included in the post rule scenarios in 

Figure 14-6. Under post rule Scenario 1, the plant transfers the newly generated FGD 

wastewater to a 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 BPT effluent limitations for the newly generated FGD wastewater at the effluent 

from the tank-based treatment system at Monitoring Point Z (see 40 CFR § 423.12(b)(11) and 40 

CFR § 423.13(g)(1)(i)). Additionally, the plant would continue to treat and discharge wastewater 

from the surface impoundment which would consist of combustion residual leachate and legacy 
Section 14—Regulatory Implementation

14-22

FGD wastewater, while ensuring it was meeting the newly promulgated BPT and BAT 

limitations for combustion residual leachate and legacy FGD wastewater(see 40 CFR § 423.13(l)

and 40 CFR § 423.12(b)(11)) at Monitoring Point Y. Because the legacy FGD wastewater and 

the combustion residual leachate are subject to the same limitations, the permit could specify that 

the plant monitor for compliance with the BPT TSS and oil and grease effluent limitations for the 

combined wastestream at the point of discharge (Monitoring Point Y). 

Under post rule Scenario 2, the plant would continue to discharge legacy wastewater and 

legacy combustion residual leachate from the surface impoundment and comply in the same 

manner as in Scenario 1. Additionally, the plant would combine newly generated combustion 

residual leachate with newly generated FGD wastewater in the tank-based system. As described 

in Section 14.1.4 and similar to Scenario 2a in Example 14-1, in this case, the permit may 

specify monitoring for compliance for the combined wastestream at the point of discharge 

(Monitoring Point Z) using the building block approach, as applicable. For the legacy FGD 

wastewater and legacy combustion residual leachate contained in the impoundment, the permit 

could specify that the plant monitor for compliance with the BPT TSS and oil and grease effluent 

limitations for the combined wastestream in the impoundment effluent (Monitoring Point Y) 

because the legacy FGD wastewater and the legacy combustion residual leachate are subject to 

the same limitations.
Section 14—Regulatory Implementation

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FGD Wastewater Surface Impoundment Pre Rule

Scenario

Receiving Water

Legacy

FGD and Combustion 

Residual Leachate

Impoundment BPT

BAT

1

BPT

BAT

Tank Based 

Treatment

System

Post Rule

Scenario

Receiving Water

BPT

Receiving Water

Legacy FGD and 

Combustion Residual 

Leachate 

Impoundment

2

BPT

BAT

Newly Generated 

FGD

Point Y

Point Y

Point Z

Point Y

Combustion Residual Leachate

Combustion Residual Leachate

Newly Generated 

Combustion 

Residual Leachate

BPT

BAT

Newly Generated 

FGD Point Z

Tank Based 

Treatment

System

Figure 14-6. Legacy Combustion Residual Leachate Scenario

Example 14-7: Implementation of Size Threshold

Under the final rule, EPA is setting different requirements for discharges of FGD 

wastewater, fly ash transport water, FGMC wastewater, bottom ash transport water, and 

gasification wastewater from certain generating units. Under BAT, all oil-fired generating units 

and generating units with a nameplate capacity of 50 MW or less are subject to new BAT 

limitations that are equal to the previously promulgated BPT effluent limitations (see 40 CFR § 

423.12(b)(4)). 

For the final rule, there is the potential that some generating units at a plant would need to 

comply with a “zero discharge” requirement, while other generating units at the plant would only 

need to comply with the current BPT standards. Figure 14-7 presents an example scenario for a 

plant that has a generating unit with a nameplate capacity of 50 MW or less and another 
Section 14—Regulatory Implementation

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generating unit with a nameplate capacity of greater than 50 MW that both discharge fly ash 

transport water. Under the final rule, if the plant continues to wet sluice the fly ash from the 

generating unit with a nameplate capacity greater than 50 MW, the fly ash transport water for 

that generating unit must be completely reused in a process that does not ultimately discharge to 

receiving waters180, including indirect discharges to POTWs, to be in compliance with the “zero 

discharge” requirement. Therefore, EPA envisions that the plant will have at least two potential 

options to comply with the “zero discharge” requirement for the generating unit with a nameplate 

capacity of greater than 50 MW.

Under post rule Scenario 1, EPA envisions that the plant will have installed a dry fly ash 

handling system on units >50 MW to meet the new zero discharge BAT limitation. However, 

legacy fly ash transport water as well as newly generated fly ash transport water from units less 

than or equal to 50 MW could still be discharged from the impoundment and would be subject to 

the legacy fly ash transport water BAT limitations (see 40 CFR § 423.13(h)(1)(ii)), the fly ash 

transport water BAT limitations for oil-fired and small generating units (see 40 CFR § 

423.13(h)(2)), and the previously established BPT limitations (see 40 CFR § 423.12(b)(4)).

Under post rule Scenario 2, the plant would segregate the fly ash transport water for the 

generating units with a nameplate capacity >50 MW and completely recycle that transport water 

with the specific unit’s wet sluicing system. In this case, they can still discharge the fly ash 

transport water from the generating units less than or equal to 50 MW nameplate capacity while 

meeting the fly ash transport water BAT limitations for oil-fired and small generating units (see 

40 CFR § 423.13(h)(2)), and the previously established BPT limitations (see 40 CFR § 

423.12(b)(4)).

 180 Or be used in the FGD scrubber. See Section VIII.G of the final preamble.
Section 14—Regulatory Implementation

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Fly Ash 

Transport Water 

Impoundment

Pre Rule

Scenario

Receiving Water

Legacy 

Fly Ash Transport Water and 

Newly Generated Fly Ash 

Transport Water 

Impoundment 

for Units ≤ 50 MW

Post Rule

Scenario

Receiving Water

Fly Ash 

Transport Water

(Units ≤ 50 MW)

Fly Ash

Transport Water

(Units > 50 MW)

BPT

BAT

Note: For Scenario 1, fly ash from units >50 MW converted to dry 

handling system. No newly generated fly ash transport water from 

these units. 

BPT

1

Fly Ash Transport Units > 50 MW

Sluicing 

System

Newly Generated 

Fly Ash 

Transport Water

(Units ≤ 50 MW)

Point Y

Point Y

2

Units ≤ 50 MW

Legacy Fly Ash Transport 

Water and Newly 

Generated Fly Ash 

Transport Water 

Impoundment 

for Units ≤ 50 MW

BPT

BAT

Receiving Water

Point Y

No

Discharge

Figure 14-7. Implementation of Size Threshold

Example 14-8: Application of the Building Block Approach; FGD Wastewater with 

Cooling Water

This example evaluates a plant that currently uses an impoundment to treat its FGD 

wastewater. Additionally, the plant operates a recirculating cooling water system and the cooling 

tower blowdown is transferred to an impoundment that receives only cooling tower blowdown. 

The plant currently combines the discharge from both impoundments and measures for 

compliance with the previously established BPT limitations at the combined point of discharge. 

The average FGD wastewater discharge flow rate is 1.2 MGD. The average overflow from the 

cooling tower blowdown impoundment is 113 MGD. The plant currently combines the overflow 

from the two impoundments and measures for compliance with the previously established 
Section 14—Regulatory Implementation

14-26

limitations at the discharge point. The plant wants to continue to commingle the two 

wastestreams prior to monitoring for compliance. In applying the building block approach, EPA 

expects that because the cooling tower blowdown has the potential to have a dilution effect this 

flow will likely be treated as a dilution flow. The following shows the calculation of the 

combined Monthly BAT Limit for arsenic using the building block approach:

CCCCCCCCCCCCCCCC MM MMhllll AAAAAA AA BB BB LL LL =

(1.2 MMMM) × �8 uuuu

LL � + (113 MMMM) × (0 uuuu

LL )

(1.2 MMMMMM) + (113 MMMMMM)

Table 14-9 shows the application of the building block approach for each pollutant 

regulated in FGD wastewater discharges on or after the as soon as possible date. If the combined 

limitation for any pollutant falls below the detection limit for that pollutant, then the plant would 

not be able to demonstrate compliance with the limit and thus EPA recommends measuring for 

compliance prior to combining with the cooling water effluent. See 40 CFR 122.46(h). As 

shown in Table 14-9 below, after applying the building block approach, the combined limitation 

for all pollutants regulated in FGD wastewater except mercury is below the detection level. 

Therefore, limitations at the point of discharge would be impracticable, and the permitting 

authority may impose internal limits to ensure compliance with the BAT FGD limitations. 

Table 14-9. Combined Monthly BAT Limitations Using Building Block Approach

Analyte

Cooling Water 

Allowed 

Concentration 

(ug/L)

FGD Wastewater 

BAT Monthly 

Limits for Final 

Rule

(ug/L)

Calculated 

Combined 

BAT Monthly 

Limita

(ug/L)

Baseline 

Values for 

Analytes

(ug/L)b

Below 

Detection 

Limit?

Arsenic 0 8 0.084 2 Yes

Mercury 0 0.356 0.0037 0.0005 No

Nitrate/Nitrite (as N) 0 3,500 36.8 50 Yes

Selenium 0 12 0.126 5 Yes

Total Suspended 

Solids

0 30,000 315 4,000 Yes

Oil and Grease 0 15,000 158 5,000 Yes

a – EPA estimated the combined effluent concentration assuming that the concentration of each of the pollutants was 

zero in the cooling tower blowdown.

b – EPA determined the baseline values for mercury and nitrate-nitrite as N 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. 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. See TDD Section 13.
Section 14—Regulatory Implementation

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FGD Wastewater

Surface

Impoundment

Pre Rule

Scenario

Receiving Water

FGD Wastewater FGD Impound

Tank Based 

Treatment

System

Post Rule

Scenario

Receiving Water

Point Y

Point Y

Point Z

Cooling Tower 

Blowdown Cooling Water Pond

Cooling Water 

Impound

Cooling Tower 

Blowdown

Figure 14-8. Building Block Approach; FGD Wastewater with Cooling Water

Example 14-9: Application of the Building Block Approach; FGD Wastewater with 

Combustion Residual Leachate

This example evaluates a plant that currently uses an impoundment to treat its FGD 

wastewater and combustion residual leachate. The average FGD wastewater discharge flow rate 

is 1.2 MGD. The average combustion residual leachate flow rate is 0.2 MGD. The plant 

currently measures for compliance with the previously established BPT limitations at the point of 

discharge from the impoundment (Monitoring Point Y), as shown in Figure 14-9. The plant 

wants to continue to commingle the two wastestreams prior to monitoring for compliance. The 

following shows the calculation of the combined Monthly BAT Limit for arsenic using the 

building block approach:

CCCCCCCCCCCCCCCC MM MMhllll AAAAAA AA BB BB LL LL =

(1.2 MMMM) × �8 uuuu

LL � + (0.2 MMMM) × (38.4 uuuu

LL )

(1.2 MMMMMM) + (0.2 MMMMMM)

Table 14-10 shows the application of the building block approach for each pollutant 

regulated in FGD wastewater discharges on or after the as soon as possible date. Because the 

FGD wastewater contains regulated pollutants that are also present in the combustion residual 

leachate, but that are not regulated in combustion residual leachate, EPA determined a 

concentration for each regulated pollutant contributed by the combustion residual leachate. If the 

combined limitation for any pollutant falls below the detection limit for that pollutant, then the 

plant would not be able to demonstrate compliance with the limit and thus EPA recommends 

measuring for compliance prior to combining with the combustion residual leachate (Monitoring 

Point Z). However, as shown in Table 14-10, after applying the building block approach, the 
Section 14—Regulatory Implementation

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combined limitation for all regulated pollutants is above the detection level. Therefore, 

limitations at the point of discharge (Monitoring Point Y) would be practicable. 

Table 14-10. Combined Monthly BAT Limitations Using Building Block Approach

Analyte

FGD Wastewater 

BAT Monthly 

Limits for Final 

Rule

(ug/L)

Combustion 

Residual Leachate 

Allowable 

Concentrationa

(ug/L)

Calculated 

Combined 

BAT Monthly 

Limitb

(ug/L)

Baseline 

Values for 

Analytes

(ug/L)c

Below 

Detection 

Limit?

Arsenic 8 38.4 12.3 2 No

Mercury 0.356 1.06 0.457 0.0005 No

Nitrate/Nitrite (as N) 3,500 NA 3,000 50 No

Selenium 12 111 26.1 5 No

Total Suspended 

Solids

30,000 30,000d 30,000 4,000 No

a – EPA estimated the contribution from combustion residual leachate using data presented in Section 6.

b – EPA estimated the combined effluent concentration for each of the regulated pollutants by using the FGD 

wastewater BAT limits combined with the contribution in the combustion residual leachate.

c – EPA determined the baseline values for mercury and nitrate-nitrite as N 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. 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. See TDD Section 13. The baseline value for total suspended 

solids is from Table 6-1 of the Development Document for Effluent Limitations Guidelines and Standards for the 

Centralized Waste Treatment Industry – Final (EPA 821-R-00-020).

d – Combustion residual leachate BAT Monthly Limits for Final Rule (ug/L).

FGD Wastewater

FGD and Combustion 

Residual Leachate 

Impoundment

Pre Rule

Scenario

Receiving Water

Legacy FGD and 

Combustion Residual 

Leachate 

Impoundment

Newly Generated

FGD

Tank Based 

Treatment

System

Post Rule

Scenario

Receiving Water

Point Y

Point Z Point Y

Combustion 

Residual Leachate BPT

Newly Generated 

Leachate

Figure 14-9. Building Block Approach; FGD Wastewater with Combustion Residual 

Leachate
Section 14—Regulatory Implementation

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14.1.7 Monitoring Requirements

The final rule does not establish the location or frequency of the monitoring 

requirements. NPDES permit regulations at §122.48(b) and pretreatment regulations at 

§403.12(g) require that permits include monitoring requirements, including frequency, that are 

sufficient to yield data representative of the regulated activity. Typically, 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. Also see Chapter 8 of EPA’s 

NPDES Permit Writer’s Manual.

14.1.8 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 CWA 

activities at 40 CFR part 136 for the pollutants for which EPA established new limitations or 

standards in this final rule. 

In some cases, where EPA has promulgated more than one analytical method for a 

pollutant in 40 CFR part 136, the permittee may use any of these methods. This is not the case 

for all pollutants regulated in this final rule. In August 2014, EPA published a rule requiring the 

use of sufficiently sensitive analytical test methods when completing any NPDES permit 

application. The Director must prescribe that only sufficiently sensitive methods be used for 

analyses of pollutants or pollutant parameters under an NPDES permit where EPA has 

promulgated a CWA method for analysis of that pollutant. The rule clarifies that NPDES 

applicants and permittees must use EPA-approved analytical methods that are capable of 

detecting and measuring the pollutants at, or below, the applicable water quality criteria or 

permit limits. 

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. 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 final 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.

FGD wastewater can contain constituents that may interfere with certain laboratory 

analyses, due to high concentrations of total dissolved solids (TDS) or the presence of elements 
Section 14—Regulatory Implementation

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known to cause matrix interferences. To address this issue, EPA developed two standard 

operating procedures (SOPs) that it used in conjunction with EPA Method 200.8 to conduct ICPMS analyses of FGD wastewater during its sampling activities. The SOPs describe critical 

technical and quality assurance procedures that EPA implemented to mitigate anticipated 

interferences and generate reliable data for FGD wastewater. These SOPs represent an approved 

modification allowed under 40 CFR part 136.6. Others have similarly developed SOPs including 

EPRI. These SOPs take a proactive approach toward looking for and taking steps to mitigate 

matrix interferences, including using specialized interference check solutions (i.e., a synthetic 

FGD wastewater matrix). Consistent with the proposed rule, EPA included its SOPs in the final 

record for laboratories contemplating ICP-MS analysis of FGD wastewater, either for adoption 

as currently written or to serve as a framework for developing their own laboratory-specific 

SOPs. 

14.1.9 Non-Chemical Metal Cleaning Wastes

By reserving BAT and NSPS for non-chemical metal cleaning waste in this final rule, the 

permitting authority must establish such requirements based on BPJ for any steam electric power 

plant discharging this wastestream. In permitting this wastestream, some permitting authorities 

have classified it as non-chemical metal cleaning waste (a subset of metal cleaning wastes), 

while others have classified it as a low volume waste source. These wastestreams have different 

BPT limitation under the previously established regulation and the specific NPDES permit 

limitations for this wastestream thus reflect that classification as made by the permitting 

authority. In making future BPJ BAT determinations, EPA recommends that the permitting 

authority examine the historical permitting record for the particular plant to determine how 

discharges of non-chemical metal cleaning wastes have been permitted in the past. Using 

historical information and its best professional judgment, the permitting authority could 

determine that the BPJ BAT limitations should be set equal to existing BPT limitations as 

classified by the permitting authority or it could determine that more stringent BPJ BAT 

limitations should apply. For example, a permit that includes BPT limits for a low volume waste 

classification could include BPJ BAT effluent limitations equivalent to BPT for metal cleaning 

wastes for the non-chemical metal cleaning wastestream. In making a BPJ determination for new 

sources, EPA recommends that the permitting authority consider whether it would be appropriate 

to base standards on BPT limitations for metal cleaning wastes or on a technology that achieves 

greater pollutant reductions.

14.2 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 

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 
Section 14—Regulatory Implementation

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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.

14.3 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 

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.

14.3.1 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 
Section 14—Regulatory Implementation

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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 

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 
Section 14—Regulatory Implementation

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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).

14.3.2 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.

14.3.3 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 

include ammonia, chlorine, color, iron, and total phenols. As this rule does not establish 

limitations or standards for any of these pollutants, this variance is not applicable to this 

particular rule.

14.3.4 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 
Section 14—Regulatory Implementation

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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 final ELGs are to be 

applied on a gross basis.

14.3.5 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 

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.
Section 14—Regulatory Implementation

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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 situations:

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. For sewage sludge that is land 

applied, removal credits may be available for an additional two metals and 14 

organic pollutants. For sewage sludge that is placed on a surface disposal unit, 

removal credits may be available for an additional seven metals and 13 organic 

pollutants. For 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).

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).

14.4 SITE-SPECIFIC WATER QUALITY-BASED EFFLUENT LIMITATIONS

Depending on site-specific conditions and applicable state water quality standards, it may 

be appropriate for permitting authorities to establish water quality-based effluent limitations on 

bromide, especially where steam electric power plants are located upstream from drinking water 

intakes.

Bromides (a component of TDS) are not directly controlled by the numeric effluent 

limitations and standards for existing sources under this final rule (although they would be 

controlled by the NSPS/PSNS for new sources and by the BAT effluent limitations for existing 

sources who choose to participate in the voluntary program and are subject to the final FGD 

wastewater limitations based on use of evaporation technology). 

Bromide discharges from coal-fired steam electric power plants can occur because 

bromide is naturally found in coal and is released as particulates when the coal is burned, or by 

the addition of bromide compounds to the coal prior to burning, or to the flue gas scrubbing 

process, to reduce the amount of mercury air pollution that is also created when coal is burned.
Section 14—Regulatory Implementation

14-36

While bromide itself is not thought to be toxic at levels present in the environment, its 

reaction with other constituents in water may be a cause for concern now and into the future. The 

bromide ion in water can form brominated DBPs when drinking water plants treat the incoming 

source water using certain disinfection processes including chlorination and ozonation. Bromide 

can react with the ozone, chlorine, or chlorine-based disinfectants to form bromate and 

brominated and mixed chloro-bromo DBPs, such as trihalomethanes (THMs) or haloacetic acids 

(HAAs) (see DCN SE01920). Studies indicate that exposure to THMs and other DBPs from 

chlorinated water is associated with human bladder cancer (see DCN SE01981 and DCN 

SE01983). EPA has established the following MCLs for DBPs:

• 0.010 mg/L for bromate due to increased cancer risk from long-term exposure;

• 0.060 for HAAs due to increased cancer risk from long-term exposure; and

• 0.080 mg/L for TTHMs due to increased cancer risk and liver, kidney or central 

nervous system problems from long-term exposure (see DCN SE01909).

The record indicates that steam electric power plant FGD wastewater discharges occur 

near more than 100 public drinking water intakes on rivers and other waterbodies, and there is 

evidence that these discharges are already having adverse effects on the quality of drinking water 

sources. A 2014 study by McTigue et. al. identified four drinking water treatment plants that 

experienced increased levels of bromide in their source water, and corresponding increases in the 

formation of brominated DBPs, after the installation of wet FGD scrubbers at upstream steam 

electric power plants (see DCN SE04503). 

Drinking water utilities are concerned as well, noting that the bromide concentrations 

have made it increasingly difficult for them to meet SDWA requirements for total 

trihalomethanes (TTHMs) (see DCN SE01949). And, bromide loadings into surface waters from 

coal-fired steam electric power plants could potentially increase in the future as more plant 

operators use bromide addition to improve the control of mercury emissions. The American 

Water Works Association requested that EPA “instruct NPDES permit writers to adequately 

consider downstream drinking water supplies in establishing permit requirements for power plant 

discharges” and take other steps to limit adverse consequences for downstream drinking water 

treatment plants. EPA agrees that permitting authorities should carefully consider whether water 

quality-based effluent limitations on bromide or TDS would be appropriate for FGD wastewater 

discharges from steam electric power plants upstream of drinking water intakes. 

EPA regulations at 40 CFR § 122.44(d)(1) require that each NPDES permit shall include 

any requirements, in addition to or more stringent than effluent limitations guidelines or 

standards promulgated pursuant to Sections 301, 304, 306, 307, 318 and 405 of the CWA, 

necessary to achieve water quality standards established under Section 303 of the CWA, 

including state narrative criteria for water quality. Furthermore, those same regulations require 

that limitations must control all pollutants, or pollutant parameters (either conventional, 

nonconventional, or toxic pollutants) which the Director determines are or may be discharged at 

a level which will cause, have the reasonable potential to cause, or contribute to an excursion 

above any state water quality standard, including state narrative criteria for water quality.

Where the DBP problem described above may be present, water quality-based effluent 

limitations for steam electric power plant discharges may be required under the regulations at 40 
Section 14—Regulatory Implementation

14-37

CFR § 122.44(d)(1), where necessary to meet either numeric criteria (e.g., for bromide, TDS or 

conductivity) or narrative criteria in state water quality standards. All states have narrative water 

quality criteria that are designed to prevent contamination and other adverse impacts to the 

states’ surface waters. These are often referred to as “free from” standards. For example, a state 

narrative water quality criterion for protecting drinking water sources may require discharges to 

protect people from adverse exposure to chemicals via drinking water. These narrative criteria 

may be used to develop water quality-based effluent limitations on a site-specific basis for the 

discharge of pollutants that impact drinking water sources, such as bromide. 

To translate state narrative water quality criteria and inform the development of a water 

quality-based limitation for bromide, it may be appropriate for permitting authorities to use 

EPA’s established MCLs for DBPs in drinking water because the presence of bromides in 

drinking water can result in exceedances of drinking water MCLs as a result of interactions 

during drinking water treatment and disinfection processes. The limitation would be developed 

for the purpose of attaining and maintaining the state’s applicable narrative water quality 

criterion or criteria and protecting the state’s designated use(s), including the protection of 

human health. See 40 CFR § 122.44(d)(1)(vi). 

For the reasons described above, during development of the NPDES permit for the steam 

electric power plant, the permitting authority should provide notification to any downstream 

drinking water treatment plants of the discharge of bromide. EPA recommends that the 

permitting authority collaborate with drinking water utilities and their regulators to determine 

what concentration of bromides at the PWS intake is needed to ensure that levels of bromate and 

DPBs do not exceed applicable MCLs. The maximum level of bromide in source waters at the 

intake that does not result in an exceedance of the MCL for DBPs is the numeric interpretation o 

the narrative criterion for protection of human health and may vary depending on the treatment 

processes employed at the drinking water treatment facility. The permitting authority would then 

determine the level of bromide that may be discharged from the steam electric power plant, 

taking into account other sources of bromide that may occur, such that the level of bromide

downstream at the intake to the drinking water utility is below a level that would result in an 

exceedances of the applicable MCLs for DBPs. In addition, applicants for NPDES permits must, 

as part of their permit application, indicate whether they know or have reason to believe that 

conventional and/or nonconventional pollutants listed in Table IV of Appendix D to 40 CFR part 

122, (which includes bromide), are discharged from each outfall. For every pollutant in Table IV 

of Appendix D discharged which is not limited in an applicable effluent limitations guideline, the 

applicant must either report quantitative data or briefly describe the reasons the pollutant is 

expected to be discharged as set forth in 40 CFR § 122.2l(g)(7)(vi)(A), made applicable to the 

States at 40 CFR § 123.25(a)(4). 

In addition to requiring the permit applicant to provide a complete application, including 

proper wastewater characterization, when issuing the permit, the permitting authority can 

incorporate appropriate monitoring and reporting requirements, as authorized under Section 

402(a)(2), 33 U.S.C. 1342(a)(2), and implementing regulations at 40 CFR §§ 122.48, 122.44(i), 

122.43 and 122.41(1)(4). These requirements apply to all dischargers and include plants that 

have identified the presence of bromide in effluent in significant quantities and that are in 

proximity to downstream water treatment plants.
Section 14—Regulatory Implementation

14-38

14.5 REFERENCES

1. Eastern Research Group (ERG). 2012. Final Site Visit Notes: RRI Energy’s 

Keystone Generating Station. (3 November). DCN SE00310.

2. U.S. EPA. 2010. NPDES Permit Writer’s Manual. EPA-833-K-10-001. 

Washington, DC. (September).

3. U.S. EPA. 1989. Industrial User Permitting Guidance Manual. EPA 833/R-89-001. 

Washington, DC. (29 September).

4. 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).

5. 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).

6. U.S. EPA. 2009. Steam Electric Power Generating Point Source Category: Final 

Detailed Study. EPA 821-R-09-008. Washington, DC. (October). DCN SE00003.

7. 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.

8. U.S. EPA. 2012b. Draft FGD ICP/MS Collision Cell Procedure for Trace Element 

Analysis in Flue Gas Desulfurization Wastewaters. (June). DCN SE03835.

9. 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.

10. U.S. EPA. 1993. Method 353.2 Determination of Nitrate-Nitrite Nitrogen by 

Automated Colorimtery. Revision 2.0. (August). Available online at: 

http://water.epa.gov/scitech/methods/cwa/bioindicators/upload/2007_07_10_method

s_method_353_2.pdf.
Appendix A—Survey Design and Calculation of National Estimates

SURVEY DESIGN AND CALCULATION OF NATIONAL ESTIMATES
Appendix A—Survey Design and Calculation of National Estimates

A-1

Appendix A: 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 A.1 of this appendix describes the survey design, and Section A.2 provides a 

summary of the survey responses. Section A.3 discusses the weighting procedures, while Section 

A.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 kth 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 

distribution of the sample frame (plants and generating units) and sample allocation of the plants 

by design stratum.
Appendix A—Survey Design and Calculation of National Estimates

A-3

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, 

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
Appendix A—Survey Design and Calculation of National Estimates

A-4

(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.

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) a

Coal Small All 55 121 0
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) a

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 Burden b 2 6 0

Pet Coke

Small -- 6 6 0

Non-Small -- 3 3 3

Total 504 1,312 97 (7)

a – In parentheses, the number of plants with the leachate system selected with certainty is shown. The sample size 

includes this number.

b – EPA excluded two coal plants from receiving parts E, F, and G to avoid overburdening these plants.

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 Weight a

Coal – Small Entity 55 55 1 -

Coal – Pond Only –FGD 39 39 1 12 3.45

Coal – Pond Only –no FGD 101 b 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.

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
Appendix A—Survey Design and Calculation of National Estimates

A-8

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 192 a 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 112 a 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 

Plants a

Estimated 

Population 

Size b

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.181

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

 181 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.

182 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:

 182 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, nh 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

MODIFIED DELTA-LOG NORMAL DISTRIBUTION
Appendix B—Modified Delta-Log Normal Distribution

B-1

Appendix B: Modified Delta-Lognormal Distribution

Appendix B 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).

Effluent concentrations are often autocorrelated such that concentrations in samples 

collected close together in time are more similar than concentrations from samples collected 

farther apart in time. 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 longterm concentration series, and thus the variance estimates from the sampled days should be 

adjusted for the correlation when estimating the variance for the long-term series. Equations (17) 

and (34) below include autocorrelation adjustments to the basic equations for calculating the 

limits using the modified-delta-lognormal distribution.183 See Section 13 of the Technical 

Development Document for a discussion of using autocorrelation in calculating the limits.

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 power generating industry in developing the long-term 

averages (LTA) and variability factors. A typical effluent data set from EPA sampling, Clean 

Water Act (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 deltalognormal 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 (1963). While this distribution was originally 

developed to model economic data, other researchers have shown the application to 

environmental data [Owen and DeRouen, 1980]. The resulting mixed distributional model, 

which 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 

 183 In response to comments on the proposed rule, EPA reviewed the procedures used to adjust for correlation for 

the proposed rule and used in previous effluent guidelines. The equations for this final rule were previously used for 

the Iron and Steel effluent guidelines except those guidelines used equation (19) instead of equation (18). Since the 

samples for this rule were not collected on sequential days, equation (18) is used.
Appendix B—Modified Delta-Log Normal Distribution

B-2

distribution contained in the discrete distributional spike at zero (i.e., 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 (D) values. This 

modification of the delta-lognormal distribution is illustrated in the figure below.

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

0

Modified Delta-Lognormal Distribution

Censoring Type D ND
Appendix B—Modified Delta-Log Normal Distribution

B-3

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: 

PP (XXDD ≤ ) = 1

δδ � δδii

ii:DDii≤cc

, > 0 (1)

The mean and variance of this discrete distribution can be calculated using the following 

formulas:

EE(XXDD) = 1

δδ�δδii

kk

ii=1

ii

(2)

VV (XXDD) = 1

δδ�δδii( ii − EE(XXDD))2

kk

ii=1

(3)

EPA used the continuous, lognormal portion of the modified delta-lognormal distribution 

to model the detected measurements. The cumulative probability distribution of the continuous 

portion of the modified delta-lognormal distribution can be mathematically expressed as: 

PP (XXCC ≤ ) = Φ �

ll ( ) − μμ

σσ � (4)

where:

X C = A randomly chosen detected measurement.

Φ(·) = The cumulative distribution function of the standard normal 

distribution.

μ and σ = Parameters of the log-normal distribution (the mean and 

standard deviation of the log-transformed concentrations).

The expected value, E(XC), and the variance, Var(XC), of the lognormal distribution can 

be calculated as:

EE(XXcc) = eeee �μμ +

σσ2

2 � (5)

VV (XXCC) = �EE(XXCC)�

2

( eeee(σσ2) − 1) (6)
Appendix B—Modified Delta-Log Normal Distribution

B-4

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:

UU = IIUUXXDD + (1 − IIUU)XXcc (7)

where:

XD = A random non-detect from the discrete portion of the 

distribution.

XC = A random detected measurement from the continuous lognormal 

portion.

UI =

A variable indicating whether any particular random 

measurement, U, is non-detected or detected (i.e., 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 deltalognormal distribution:

PP (UU ≤ ) = � � δδii

ii:DDii≤cc

� + (1 − δδ)Φ�

ll ( ) − μμ

σσ � (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:

EE(UU) = δδ (XXDD) + (1 − δδ)EE(XXCC) (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:

EE(UU2) = δδ (XXDD

2) + (1 − δδ)EE(XXCC

2) (10)
Appendix B—Modified Delta-Log Normal Distribution

B-5

Although written in terms of U, the following relationship holds for all random variables:

EE(UU2) = VV (UU) + �EE(UU)�

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:

VV (UU) = δδ �VV (XXDD) + �EE(XXDD)�

2

� + (1 − δδ) �VV (XXCC) + �EE(XXCC)�

2

� − �EE(UU)�

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, δδii, =

1, ... , kk and the parameters μ and σ of the lognormal distribution for detected values in the 

continuous portion of the distribution.

B.4 Autocorrelation

The correlation among daily measurements can be described by the sequence of 

correlations between observations that are 1 day apart, 2 days apart, 3 days apart, etc. There are 

many time series models that might be considered for modeling this sequence of correlations and 

the associated wastewater measurements. One such model is an AR(1) model, an autoregressive 

model with one parameter, ρρ, the correlation between observations one day apart. If the data are 

consistent with an AR(1) model, the correlation between observations days apart will be ρρdd. 

The AR(1) model is a reasonable model for many series of wastewater measurements when 

applied to the log-transformed concentrations. Based on analysis of the effluent data for this rule, 

EPA has used the AR(1) model for describing the correlations among the steam electric effluent 

measurements. 

Use of the AR(1) model requires estimating ρρ. When the data come from sequential daily 

samples with no values below the detection limit, ρρ can be estimated by the correlation between 

log-transformed measurements separated by one day. When the data are not from sequential 

samples, standard statistical software for time series analysis can be used to estimate ρρ. When the 

data also have non-detects, as in the data used to develop this rule, estimates based on standard 

statistical software can be biased. DCN SE06279 describes the procedures used to estimate the 1-

day lag correlation for the effluent data adjusting for the effect of any non-detects.

EPA estimated the 1-day lag correlation for each analyte within each plant for which 

there were enough data to provide a reasonably precise correlation estimate. When there were 

two or more plants with correlation estimates for a combination of analyte and treatment option, 

EPA averaged the correlations to obtain the correlation used for calculating the limitations. 

Unless specified otherwise, for combinations of analyte and technology option with no 

correlation estimate, EPA assumed the correlation was zero.

In the equations below, EPA used the correlation to calculate the variance of the longterm concentration series from the variance of the observed measurements. The correlation is 

also used when calculating the variance of the monthly mean from the variance of the long-term 

series. As implemented in the equations below, the correlation adjustment affects only the 
Appendix B—Modified Delta-Log Normal Distribution

B-6

variance of the continuous portion of the modified delta lognormal distribution, and the nondetects are assumed to be statistically independent. 

B.5 Plant and Pollutant 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 LTA and variability factor if the dataset contained three or more 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 plant-specific LTA and 

excluded the dataset from the variability factor calculations (since the variability could not be 

calculated in this situation). 

B.6 Parameter Estimates for Modified Delta-Lognormal Distribution of Daily 

Concentrations

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:

δδ̂

ii = 1

�II

nndd

jj=1

� jj = ii�

(13a)

δδ̂ = dd (13b)

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:

EE�(XXDD) = 1

δδ̂

�δδ̂

ii

kk

ii=1

ii

(14)

VV� (XXDD) = 1

δδ̂

�δδ̂

ii

kk

ii=1

� ii − EE�(XXDD)�

2 (15)
Appendix B—Modified Delta-Log Normal Distribution

B-7

The parameters μ and σ of the continuous portion of the modified delta-lognormal 

distribution are estimated from the log-transformed data using:

μμ̂= �ll ( ii)

cc

nncc

ii=1

(16)

σσ�2 = 1

(ρρcc)

�(ll ( ii) − μμ̂)2

cc − 1

nncc

ii=1

(17)

where:

xi = The i

th detected measurement.

nc =

The number of detected measurements (note that n = nd + nc), 

and (ρρcc) is the adjustment for autocorrelation based on the 1-

day lag correlation of the values in the continuous portion of the 

modified delta lognormal distribution (ρρcc).The flow rate of the 

wastestream being discharged, in gallons per day.

For an AR(1) model with a 1-day lag correlation of ρc, the correlation (in the log scale) 

between xi and xj (i ≠ j) is Corr(ln(xi), ln(xj)) =ρc

|i−j|

, where i and j are the sample collection 

dates. Using this, the adjustment for the autocorrelation is:

(ρρcc) = 1 − 1

( − 1)

� � ρρ| −jj|

∈ jj∈ ,jj≠

(18)

where T = {1,...,n} is the set of dates with observed daily values above the detection limit 

(i.e., in the continuous portion of the distribution). For an AR(1) model with n sequential daily 

values, this reduces to:

(ρρcc) = 1 − � 2

( − 1)

� � ρρ

1 − ρρ ��( − 1) − ρρ �1 − ρρ −1�1 − ρρ � (19)

Note that if the daily values are independent (i.e., autocorrelation is not present in the data), then 

(ρρcc) = 1. 

The expected value and the variance of the lognormal portion of the modified deltalognormal distribution can be calculated from the parameter estimates as:
Appendix B—Modified Delta-Log Normal Distribution

B-8

EE�(XXCC) = eeee �μμ̂+

σσ�2

2 � (20)

VV� (XXCC) = �EE�(XXCC)�

2

( eeee(σσ�2) − 1) (21)

Finally, the expected value and variance of the modified delta-lognormal distribution can 

be estimated using the following formulas:

EE�(UU) = δδ̂EE�(XXDD) + �1 − δδ̂�EE�(XXCC) (22)

VV� (UU) = δδ̂ �VV� (XXDD) + �EE�(XXDD)�

2

� + �1 − δδ̂� �VV� (XXCC) + �EE�(XXCC)�

2

� − �EE�(UU)�

2

(23)

Equations (20) through (23) are particularly important in the estimation of the plant LTAs 

and variability factors as described in the following sections. 

B.6.1 Estimation of Plant-Specific LTA

The plant-specific LTA is calculated as follows:

LL = EE�(UU) = δδ̂EE�(XXDD) + �1 − δδ̂�EE�(XXCC) (24)

Section B.6 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 equation (17) cannot be 

calculated. In this case, the LTA is calculated as the arithmetic mean of the available data 

(consisting of detected values and detection limits).

B.6.2 Estimation of the Plant-Specific Daily Variability Factor (VF1)

The plant-specific daily variability factor is the ratio of the 99th percentile of the daily 

concentrations to the LTA and is calculated as follows:

VVVV1 = PP�

99

EE�(UU)

= PP�

99

LL

(25)

The following describes 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.

The cumulative distribution function, p, for a given value c is:

PP (UU ≤ ) = � � δδ̂

ii

ii:DDii≤cc

� + �1 − δδ̂�Φ�

ll ( ) − μμ̂

σσ� � (26)
Appendix B—Modified Delta-Log Normal Distribution

B-9

Under the modified delta-lognormal distribution, if D1 < D2 < ... < Dk are the k observed 

detection limits expressed in increasing order, then the cumulative distribution at each detection 

limit is:

qq�mm = ��δδ̂

ii

mm

ii=1

� + �1 − δδ̂�Φ�

ll ( mm) − μμ̂

σσ� � , = 1 ... kk (27)

If all k of the ˆqm values are below 0.99, then 

PP�

99 = eeee �μμ̂+ σσ� ∙ Φ−1 �

0.99 − δδ̂

1 − δδ̂ �� (28)

where Φ-1

(p) is the pth 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:

PP�

99 =

⎩

⎪

⎨

⎪

⎧ jj ii qq�∗ < 0.99

eeee �μμ̂+ σσ� ∙ Φ−1 �

0.99 − ∑ δδ̂

ii

jj−1

ii=1

1 − δδ̂ �� ii qq�∗ ≥ 0.99 (29)

B.7 Parameter Estimates for Modified Delta-Lognormal Distribution of Monthly 

Averages

To calculate the 4-day variability factor (VF4), EPA assumed 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 in which the discrete portion 

corresponds to averages of four non-detects (assumed to be independent) and the continuous 

portion approximates the distribution of averages involving detected values (which may be 

correlated). The probability that the average involves four non-detects is:

δδ̂

4 = δδ̂4 (30)

To obtain the expected value of the mean of the four daily values, equation (22) is 

modified to indicate that it applies to the average:

EE�(UU�4) = δδ̂

4�EE�(XX�4)DD� + �1 − δδ̂4�EE�(XX�4)CC (31)

where:

( 4 )D X =

The mean of the discrete portion of the distribution of the 

average of four independent concentrations (i.e., when all 

observations are non-detected).
Appendix B—Modified Delta-Log Normal Distribution

B-10

( 4 )C X =

The mean of the continuous lognormal portion (i.e., for averages 

involving one or more detected observations). The flow rate of 

the wastestream being discharged, in gallons per day.

First, EPA assumed that the detection of each measurement is independent. Therefore, 

the probability of the detection of the measurements can be written as δδ̂

4 = δδ̂4. Because the 

measurements are assumed to be independent, the following relationships hold:

EE�((XX�4)DD) = EE�(XXDD) (32)

VV� ((XX�4)DD) = VV� (XXDD)

4

Since the expected value of the daily concentrations and the monthly means are equal:

EE�(UU�4) = EE�(UU) (33)

The variance of the monthly average (represented by ( 4 ) Var U ˆ ) with the correlation 

adjustment is:

VV� (UU�4) = VV� (UU)

4 �1 + 4(ρρcc)� (34)

where the factor 4(ρρcc) is used to adjust for the correlation among the four values in the 

average. This adjustment factor is shown below. Note that the correlation adjustment 

�1 + 4(ρρcc)� is equal to 1.0 if the correlation is zero. Although the calculation of the adjustment 

factor assumes all four weekly concentrations are detected (by using the correlation among 

detected values), in practice the observations used to calculate the monthly average may include 

non-detects.

In general, for a monthly average of m samples:

mm(ρρcc) = 1 � � eeee �ρρcc

|ii−jj|

σσ�2� − 1

eeee(σσ�2) − 1

ii∈SS jj∈SS,ii≠jj

(35)

Where S represents the set of sampling dates within the month.

When four samples are collected 7 days apart, the correlation between detected values 7 

days apart is ρc

7 and equation (35) is equal to:

4(ρρcc) = 2

4�(4 − kk)

3

kk=1

� eeee(ρρcc

7kkσσ�AA

2) − 1

eeee(σσ�AA

2) − 1 �

(36)
Appendix B—Modified Delta-Log Normal Distribution

B-11

Substituting into equation (31) and solving for the expected value of the continuous 

portion of the distribution gives:

EE�(XX�4)CC = EE�(UU) − δδ̂

4EE�(XXDD)

1 − δδ̂

4

(37)

Using the relationship in equation (23) for the averages of four daily values, substituting 

terms from equations (32) to (34) and solving for the variance of the continuous portion of U4

gives:

VV� ((XX�4)CC) =

VV� (UU�4) + �EE�(UU)�

2

− δδ̂

4 �VV� ((XX�4)DD) + �EE�(XXDD)�

2

�

1 − δδ̂

4

− �EE�((XX�4)CC)�

2

(38)

Using equations (20) and (21) and solving for the parameters of the lognormal 

distribution describing the distribution of ( )C X4 gives:

σσ�4

2 = ll � VV� ((XX�4)CC)

�EE�((XX�4)CC)�

2 + 1�

μμ̂

4 = ll �EE�((XX�4)CC)� − σσ�4

2

2

(39)

The average of four 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 discrete portion of 

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*:

i Value of U4 ( * Di ) Probability of occurrence ( * δ i )

1 D1

4

1 δ

2 (3D1 + D2)/4 2

3

1 4δ δ

3 (2D1 + 2D2)/4 2

2

2

1 6δ δ

4 (D1 + 3D2)/4 3

1 2 4δ δ

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, as 

shown below:
Appendix B—Modified Delta-Log Normal Distribution

B-12

PP �UU�4 = ∑ uuii ii

kk

ii=1

4 � = 4!uu1! uu2! ⋯ uukk!

�δδii

uuii

kk

ii=1

(40)

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

B.7.1 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 LTA. 

In this case, the parameter to be estimated is the 95th percentile of the distribution of U4 , which 

represents the average of four samples for a given plant. The monthly variability factor is 

calculated as follows:

VVVV4 = PP�

95

EE�(UU)

= PP�

95

LL (41)

Below is a description of how the 95th percentile is estimated under the assumption that 

U4 has a modified delta-lognormal distribution. The following steps also show how EPA 

accounted for multiple detection limits (for non-detected values) when estimating the 95th

percentile of the monthly average.

The approach to estimating P95 is similar to the approach used to estimate P99 in the 

calculation of daily variability factors, as described above. For m = 1, ..., k*, let

qq�mm = ��δδ̂

ii

∗

mm

ii=1

� + �1 − δδ̂4�Φ �

ll ( mm

∗ ) − μμ̂

4

σσ�4

� (42)

where Φ(·) is the cumulative distribution function of the standard normal distribution.

Now, if all k values of ˆqm defined above are less than 0.95, then the 95th percentile is 

defined as:
Appendix B—Modified Delta-Log Normal Distribution

B-13

PP�

95 = eeee �μμ̂4 + σσ�4 ∙ Φ−1 �

0.95 − δδ̂4

1 − δδ̂4 �� (43)

where Φ-1(p) is the pth percentile of the standard normal distribution. Otherwise, let jj

∗

denote the smallest of the k* values of * Di for which ˆj q ≥ 0.95, and let qˆ *= ˆj q - ˆ* δ j . Then, the 

95th percentile is defined by the following:

PP�

95 =

⎩

⎪

⎨

⎪

⎧ jj

∗ ii qq�∗ < 0.95

eeee �μμ̂

4 + σσ�4 ∙ Φ−1 �

0.95 − ∑ δδ̂

ii

jj−1 ∗

ii=1

1 − δδ̂4 �� ii qq�∗ ≥ 0.95 (44)

B.8 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 (to calculate the variance); however, 

these estimates can be imprecise (as can estimates from larger datasets). As stated in Section B.5, 

EPA developed plant-specific variability factors for datasets that had three or more observations 

with two or more distinct measured concentration values.

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 

LTA. 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 samplespecific detection limits could exceed the detected values. A third criterion was that the daily 

variability factor had to be greater than the monthly variability factor. All plant-specific 

variability factors used for the limitations and standards met these three criteria. 

B.9 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. DCN SE06549.
Appendix B—Modified Delta-Log Normal Distribution

B-14

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 12:129-148. DCN SE06551.

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. DCN SE06546.