United States       Office of Water     EPA-821-R-15-007
             Environmental Protection   Washington, DC 20460  September 2015
             Agency
&EPA        Technical Development
             Document for the Effluent
             Limitations Guidelines and
             Standards for the Steam
             Electric Power Generating
             Point Source Category

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&EPA
   United States
   Environmental Protection
   Agency
   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

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                                                             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

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                                                                         Table of Contents
                               TABLE OF CONTENTS
                                                                                 Page

GLOSSARY	xvm

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

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           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   NPDESForm2C	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
                                          11

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                         TABLE OF CONTENTS (Continued)
                                                                                Page

    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
                                         in

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                         TABLE OF CONTENTS (Continued)
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           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
                                          IV

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                          TABLE OF CONTENTS (Continued)
                                                                                  Page

    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

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                         TABLE OF CONTENTS (Continued)
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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
                                         VI

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           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
                                          vn

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    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
                                        Vlll

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                                                                           List of Tables

                                    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
                                          IX

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                                                                           List of Tables
                              List of Tables (Continued)
                                                                                 Page
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

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                                                                            List of Tables

                               List of Tables (Continued)
                                                                                 Page

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
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                                                                          List of Tables

                              List of Tables (Continued)
                                                                               Page

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
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                              List of Tables (Continued)
                                                                                Page
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
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                                                                            List of Tables
                               List of Tables (Continued)
                                                                                 Page
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
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                              List of Tables (Continued)
                                                                               Page
Table 14-4. BAT/NSPS Limitations for Existing Units (< or Equal To 50 MW or Oil-
      Fired Units); Also Subject to 1982NSPS3	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
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                                                                           List of Figures
                                    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 Coke-
       and 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	7-3 8
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                                                                           List of Figures
                              List of Figures (Continued)
                                                                                 Page
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
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                                                                                Glossary
                                     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)(l) and 304(b)(l) 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.
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                                                                                 Glossary
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.

EJA - 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
                                          xix

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                                                                                 Glossary
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; CCh/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.

Groundwater - 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.
                                           xx

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                                                                                 Glossary
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
                                           xxi

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                                                                                Glossary
Primary paniculate 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.
                                          xxn

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                                                                                Glossary
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.
                                         xxin

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                                                                     Section 1—Background
                                                                       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)(l). The CWA establishes a comprehensive program for protecting our
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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)(l)(B), 33 U.S.C. 1342(a)(l)(B)). Additional limitations are also required in
the permit where necessary to meet WQS. CWA section 301(b)(l)(C), 33 U.S.C. 1311(b)(l)(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)(l)(B), 33 U.S.C.
1314(b)(l)(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: BODs, 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. 131 l(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 (BADCTVNew 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)(l), 33 U.S.C. 1316(a)(l).
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)(l)(B), 33 U.S.C.
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 pass-
through 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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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
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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.
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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)(l)(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)(l).  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 one-
   year 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 862, NOX, and ozone-season NOX react in the
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                                                               Section 1—Background
   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.
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                                                                Section 1—Background
   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 offish 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.
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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.
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                                                             Section 2—Summary of the Final Rule
                                                                           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.

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                                                           Section 2—Summary of the Final Rule
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 oil-
fired 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
! For details on when the following BAT limitations apply, see Section 8.3.

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                                                            Section 2—Summary of the Final Rule
          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.
                                            2-3

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                                                            Section 2—Summary of the Final Rule
       •  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.

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                                                           Section 2—Summary of the Final Rule
       •   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, aftd-recirculating house service
          water systems, and wet scrubber air pollution control systems whose primary purpose
          is particulate removal. Sanitary aad-wastes, air conditioning wastes, and wastewater
          from carbon capture or sequestration systems are not included in this definition.

          (e) The i&m\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
                                          2-5

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                                                 Section 2—Summary of the Final Rule
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;  CCh/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
                                2-6

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                                                           Section 2—Summary of the Final Rule
              generating units, under sections 111, 301, 302, and 307(d)(l)(C) of the Clean Air
              Act, as amended, 42 U.S.C. 7411, 7601, 7602, 7607(d)(l)(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.
                                          2-7

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                                                           Section 3—Data Collection Activities
                                                                        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 coal-
          fired 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.
                                          3-1

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                                                           Section 3—Data Collection Activities
       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

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                                                             Section 3—Data Collection Activities
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 EIA-
860) 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).
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                                                              Section 3—Data Collection Activities
a stratum (i.e., probability sampled stratum). As a result, the survey was distributed to all coal-
and 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
Coal
Petroleum coke
Oil
Gas
Nuclear
Combination a
Number of Facilities
495
9
43
555
63
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 gas-
combined cycle), EPA randomly selected 30 percent of the plants to receive the survey while
adhering to the 10 plant minimum per stratum. Based on this sampling design, 733 plants 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).
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                                                            Section 3—Data Collection Activities
       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.
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                                                       Section 3—Data Collection Activities
      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
Yates, Georgia
Wansley, Georgia
Widows Creek, Alabama
Conemaugh, Pennsylvania
Homer City, Pennsylvania
Pleasant Prairie, Wisconsin
Bailly, Indiana
Seminole, Florida
Big Bend, Florida
Cayuga, New York
Mitchell, West Virginia
Cardinal, Ohio
Bruce Mansfield, Pennsylvania
Roxboro, North Carolina
Belews Creek, North Carolina
Marshall, North Carolina
Mount Storm, West Virginia
Harrison, West Virginia
Mountaineer, West Virginia
Gavin, Ohio
Deely, Texas
Clover, Virginia
JK Spruce, Texas
Fayette Power Project/Sam Seymour, Texas
Ghent, Kentucky
Trimble County, Kentucky
Cane Run, Kentucky
Mill Creek, Kentucky
Brandon Shores, Maryland
Kenneth C Coleman, Kentucky
Gibson, Indiana
Paradise, Kentucky
Wabash River, Indiana
Miami Fort, Ohio
Covanta, Virginia
Month/Year of Site Visit
Dec 2006
Dec 2006
Dec 2006; Sept 2007
Feb2007;Aug2012
Feb 2007; Aug 2007; Aug 2012
Apr 2007; Mar 20 10
Apr 2007
Apr 2007; Jan 2013
Apr 2007; Jul 2007
May 2007
May 2007; Oct 2007
May 2007; Oct 2007; Feb 2010
Oct 2007
Mar 2008
Mar 2008; Oct 2008
Mar 2008
Sept 2008
Sept 2008
Sept 2008; Jan 2009
Sept 2008
Oct 2008
Oct 2008
Oct 2008
Oct 2008
Dec 2008
Dec 2008
Dec 2008
Dec 2008
Jan 2009; Mar 20 10
Feb 2009
Feb 2009
Feb 2009
Feb 2009; Aug 20 10
Apr 2009; Mar 20 10
Jul 2009
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                                                          Section 3—Data Collection Activities
    Table 3-2. List of Site Visits Conducted During the Detailed Study and Rulemaking
Plant Name, Location
Chesterfield, Virginia
Karn-Weadock, Michigan
Kinder Morgan Power, Michigan
Monroe, Michigan
Allen, North Carolina
Cape Fear, North Carolina
Catawba, South Carolina
HB Robinson, South Carolina
FP&L Sanford, Florida
Polk, Florida
Fort Martin, West Virginia
Hatfield's Ferry, Pennsylvania
Keystone, Pennsylvania
Dickerson, Maryland
Dallman, Illinois
Duck Creek, Illinois
latan, Missouri
Edwardsport, Indiana
Torrevaldaliga Nord, Italy
Monfalcone, Italy
Frederico II (Brindisi), Italy
FP&L Manatee, Florida
Wateree, South Carolina
McMeekin, South Carolina
JEA Northside, Florida
John E. Amos, West Virginia
Month/Year of Site Visit
Sept 2009
Sept 2009
Sept 2009
Sept 2009
Oct 2009
Oct 2009
Oct 2009
Oct 2009
Oct 2009
Oct 2009
Feb 2010
Feb 2010
Feb 2010
Mar 20 10
Apr 20 10
Apr 20 10
Apr 20 10
Mar 2011
Apr 20 11
Apr 20 11
Apr 20 11
Nov2011
Jan 20 13
Jan 20 13
Apr 20 14
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.
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                                                           Section 3—Data Collection Activities
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 coal-
          fired plants because the wastestreams of interest for the sampling program data
          objectives are associated with coal-fired power plants.
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                                                             Section 3—Data Collection Activities
       •  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.u

       •  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.
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                                                            Section 3—Data Collection Activities
       •   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.
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                 Table 3-3. Selection Criteria for Plants Included in EPA's Sampling Program in the United States
Plant Name
Belews Creek
Pleasant Prairie
Miami Fort
Allen
Dickerson
Keystone
Hatfield's Ferry
Selection Criteria
Coal-Fired
Boilers
Yes
Yes
Yes
Yes
Yes
Yes
Yes
FGD Treatment System
Chemical
Precipitation
Yesa'c
Yesb
Yesb
Yesa'c
Yesa'c
Yesb
Yesb
Biological
Yesd
No
No
Yesd
Yese
No
No
Type of FGD
System
LSFO
LSFO
LSFO
LSFO
LSFO
LSFO
LSFO
NOx
Controls
SCR
SCR
SCR
SNCR
SNCR
SCR
SNCR
Power Load
Cycling
Baseload
Baseload
Baseload
Cycling
Cycling
Baseload
Baseload
Type of Coal
Eastern Bituminous
Subbituminous
Eastern Bituminous
Bituminous
Eastern Bituminous
Eastern Bituminous
Bituminous,
Subbituminous
Commercial-
Grade Gypsum
By-Product
Yes
Yes
Yes
Yes
Yes
No
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).
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                                                             Section 3—Data Collection Activities
             Table 3-4. Analytical Methods Used for EPA's Sampling Program
Parameter
Method Number
Classical*
Biochemical oxygen demand (BOD5)
Chemical oxygen demand (COD)
Total suspended solids (TSS)
Total dissolved solids (TDS)
Sulfate
Chloride
Ammonia as nitrogen
Nitrate-nitrite as nitrogen
Total Kjeldahl nitrogen (TKN)
Total phosphorus
Total cyanide
SM5210B
EPA 4 10.4
SM 2540 D
SM 2540 C
EPA 300.0
EPA 300.0
EPA 350.1
EPA 353.2
EPA 351.2
EPA 365.1
SM4500CNE
Total and Dissolved Metals
Mercury
Hexavalent chromium (dissolved only)
Antimony, arsenic, cadmium, chromium, copper, lead, nickel, selenium,
silver, thallium, and vanadium
Aluminum, barium, beryllium, boron, calcium, cobalt, iron, magnesium,
manganese, molybdenum, sodium, tin, titanium, and zinc a
EPA 163 IE
EPA 218.6
EPA 200.8 with collision cell
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
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                                                            Section 3—Data Collection Activities
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 BODs,
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].
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                                                            Section 3—Data Collection Activities
       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 latan 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.
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                                                           Section 3—Data Collection Activities
       A report describing the results from the CWA 308 monitoring program is included in the
rulemaking record [ERG, 20121].

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, 201 la]. 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
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                                                          Section 3—Data Collection Activities
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.
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                                                            Section 3—Data Collection Activities
       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 user-
specified constraints such as  environmental, demand, and other operational constraints. The
model uses a long-term dynamic linear programming framework that simulates the dispatch of
generating capacity to achieve a demand-supply equilibrium on a seasonal basis and by region.
In addition to existing capacity, the model also considers new resource investment options,
including capacity expansion at existing plants 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, 201 lb]. 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 11 l(d) Clean Power Plan and the proposed
CAA section 11 l(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 11 l(d) rule for existing
sources was  similar from proposal to final rule. In addition to these air regulations, the IPM
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                                                           Section 3—Data Collection Activities
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
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                                                           Section 3—Data Collection Activities
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, 201 la; Duke
Energy, 201 lb]. 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.
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                                                            Section 3—Data Collection Activities
       •  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
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                                                            Section 3—Data Collection Activities
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.

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                                                             Section 3—Data Collection Activities
       •   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.
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                                                           Section 3—Data Collection Activities
       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
PISCES Wastewater Characterization Field Study, Sites A-G
The Fate of Mercury Absorbed in Flue Gas Desulfurization (FGD) Systems
Flue Gas Desulfurization (FGD) Wastewater Characterization: Screening Study
EPRI Technical Manual: Guidance for Assessing Wastewater Impacts of FGD
Scrubbers
Update on Enhanced Mercury Capture by Wet FGD: Technical Update
Selenium Removal by Iron Cementation from a Coal-Fired Power Plant Flue Gas
Desulfurization Wastewater in Continuous Flow System - A Pilot Study
Laboratory and Pilot Evaluation of Iron and Sulfide Additives with
Microfiltration for Mercury Water Treatment
Impact of Wet Flue Gas Desulfurization (FGD) Design and Operating Conditions
on Selenium Speciation: 2009 Update
Integrated Fly Ash Pond Management: A Field Study of Five Central United
States Pond Systems.
Current Practices for Flue Gas Desulfurization (FGD) Water Management and
Treatment in Ponds
Document Control
Number
DCNs SE01818-SE01823
DCN SE01814
DCN SE01816
DCN SE01817
DCN SE01815
DCN SE0409A2
DCN SE0409A3
DCN SE04369
DCN SE04361
DCN SE04367
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                                                             Section 3—Data Collection Activities
               Table 3-5. Reports and Studies Submitted to EPA from EPRI
Title of Report/Study
Pilot-Scale and Full-Scale Evaluation of Treatment Technologies for the Removal
of Mercury and Selenium in Flue Gas Desulphurization Water
Impact of Wet Flue Gas Desulfurization (FGD) Design and Operating Conditions
on Selenium Speciation: 2010 Update
Review of Water Treatment Technologies for Selenium Removal Implemented at
Power Plants
Evaluation of Mercury Speciation and Its Treatment Implication in Flue Gas
Desulfurization Waters
Thermal Flue Gas Desulfurization Wastewater Treatment Processes for Zero
Liquid Discharge Operations
Selenium Speciation and Management in Wet FGD Systems
Corrosion in Wet Flue Gas Desulfurization (FGD) Systems: Technical Root
Cause Analysis of Internal Corrosion on Wet FGD Alloy Absorbers
Pilot Evaluation of the Anaerobic Membrane Bioreactor Technology for Flue Gas
Desulfurization Wastewater Treatment
Pilot Evaluation of the Pironox™ System for Flue Gas Desulphurization
Wastewater Treatment
Pilot Evaluation of a Fluidized Bed Reactor/Membrane Bioreactor Technology
for Flue Gas Desulfurization Wastewater Treatment
Pilot Evaluation of the ABMet Technology for Flue Gas Desulphurization
Wastewater Treatment
Pilot Evaluation of the ZVI Blue™ Technology for Flue Gas Desulphurization
Wastewater Treatment
Document Control
Number
DCN SE04362
DCN SE04370
DCN SE04363
DCN SE04368
DCN SE04365
DCN SE04364
DCN SE04366
DCN SE05615
DCN SE05616
DCN SE05617
DCN SE05618
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 EIA-
923 collects information from electric power plants and combined heat and power plants in the
United States that have a total generator nameplate capacity greater than 1 MW. The form asks
where the generator(s) 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 kilovolt-
amperes (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.
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                                                           Section 3—Data Collection Activities
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
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                                                          Section 3—Data Collection Activities
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. 201 la. Duke Energy. Industry Provided Sampling Data from Duke Energy's
           Allen Steam Station. (17 August). DCN SE01809.
      2.   Duke. 201 Ib. 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. 2012L 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.
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                                                    Section 3—Data Collection Activities
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/.
     DCNSE02015.
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 SEO1805.
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-l-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.
                                  3-27

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                                                  Section 3—Data Collection Activities
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. 201 la. 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. 201 Ib. 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. EPA-
    HQ-OW-2009-0819-4655. (7 June 2013).
35.  UWAG. 2014. UWAG Response to Post Proposal Information Request. (1 August).
    DCN SE04717.
                                 3-28

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                                                   Section 4—Steam Electric Industry Description
                                                                       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.
                              Electric Generating Plants
              Electric Generating Industry
               (Utilities and Non-Utilities)
                Industrial Non-Utilities
   Non-Steam Electric
   Power Generation
 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
                   Figure 4-1. Types of U.S. Electric Generating Plants
                                          4-1

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                                                      Section 4—Steam Electric Industry Description
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 non-
           utilities 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].
                                            4-2

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                                                       Section 4—Steam Electric Industry Description
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 non-
utilities, 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
22 1 1 1 1 - Hydroelectric Power Generation
22 1 1 12 - Fossil Fuel Electric Power Generation
221113 - Nuclear Electric Power Generation
22 1 1 1 9 - Other Electric Power Generation (includes conversion of other forms of energy,
such as solar, wind, or tidal power, into electrical energy)
22111 - Electric Power Generation (Total)
Plants
295
1,248
79
312
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."
                                            4-3

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                                                      Section 4—Steam Electric Industry Description
plants composing the electric generating industry includes only the utilities and the non-
industrial 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 "non-
steam-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.1?
       •  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).
                                            4-4

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                                                       Section 4—Steam Electric Industry Description
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;

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                                                     Section 4—Steam Electric Industry Description
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 (SCh) 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,
802) 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/parti culate 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.
                                           4-6

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                                                     Section 4—Steam Electric Industry Description
       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 stand-
alone 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 HRSGthen extracts heat
from the combustion turbine exhaust to produce steam and drive a steam turbine/generator.
                                           4-7

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                                                   Section 4—Steam Electric Industry Description
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].
                                          4-8

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                                                          Section 4—Steam Electric Industry Description
f —
Fuel 	 ^ Boiler
(e.g., coal, oil, or gas)
^1 	
T
Boiler
Slowdown
Coal
Storage
>
Gas to
Atmosphere
t
FGDWet 	 . Flue Gas
Scrubber ^ Desulfurization Wastes
A
FIU6GaS > CoNcction > Fly Ash Sluice
System (if wet handling system)
High Pressure Steam
~~~^| ^^^^^ f 	 \ Electric
1"""""^ _. f \ Generator
Steam ^j. 	 \
<> Turbine *\ 1 Chemical
 1 -OR-
V > M. Coolln5 Water Recirculating System
Condensate ^~<^f^
1
I
I 	 n y /
1 \ Hnnlinn /
I \ Tower /
,r I \ / i Equipment
— T— Cleaning
r V T 1 	 . 	 1
L Bottom Ash Boiler Feedwater Make-up 1 1 1
„ ;D.. Handling System Treatment Water T 1
Plnwrlnwn -,u i
Runoff Biowaown Chemical Metal
1 1 Addition Cleaning
T T Wastes
Bottom Ash Sluice Waste
(if wet handling system) (Treatment Residuals)
Figure 4-2. Steam Electric Power Generating Process Flow Diagram
                               4-9

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                                                                                                  Section 4—Steam Electric Industry Description
                                     Fuel (e.g., gas, oil, or
                                         gasified coal)
                                                                                            Electric
                                                                                            Generator
                                                                                                     Metal
                                                                                                    Cleaning
                                                                                                    Wastes
Steam
Turbine
Cycle
                                                                                                           Electric
                                                                                                           Generator
                                                                                                           Once-through Cooling Water
                                                                                                           Once-through Discharge
                                                                                                                  -OR-
                                                                                                            Recirculating System
                                      Heat Recovery
                                     Steam Generator
                                        (HRSG)
Boiler Feedwater
   Treatment
                                  Boiler
                                Slowdown
                                                                                   r
                                                                  Waste
                                                           (Treatment Residuals)
               Make-up
                Water
                            Blowdown
                                         Chemical
                                         Addition
                                        Figure 4-3. Combined Cycle Process Flow Diagram
                                                                  4-10

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                                                                                               Section 4—Steam Electric Industry Description
    Coal/
Petroleum Coke
                   Sweet
                  Syngas
                          Coal/
                        Petroleum
                        Coke Pile
                         Runoff
Heat Recovery Steam
 Genera tor (HRSG)
                                          Cooling
                                           Water
                                                                                                                           Electric
                                                                                                                          Generator
                                            Figure 4-4. IGCC Process Flow Diagram
                                                                4-11

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                                                     Section 4—Steam Electric Industry Description
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.
                                           4-12

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                                                     Section 4—Steam Electric Industry Description
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.
                                           4-13

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                                                                                                     Section 4—Steam Electric Industry Description
       Table 4-2. Distribution of Prime Mover Types for Plants Regulated by the Steam Electric Power Generating ELGs
Steam Electric Prime Movers
Stand- Alone Steam Turbine
Combined Cycle System °
Combined Cycle Steam Turbine d
Combined Cycle Single Shaft (steam
and combustion turbines sharing a
single shaft) f
Combined Cycle Combustion Turbine
Total
2009 EIA
Number of
Plants a
787
(67%)
438
(37%)
416
22
411
1,179
(100%)
Number of
Electric
Generating Units
1,868
(76%)
599
(24%)
550
49
1,013
2,467 s
(100%)
Total Steam or
Combined Cycle
Turbine Capacity
(MW)
555,000
(71%)
224,000
(29%)
81,100
9,570
134,000
780,000
(100%)
Steam Electric Survey
Number of
Plants a
716
(66%)
408
(38%)
408

404
1,079 h
(100%)
Number of
Electric
Generating Units
1,640 b
(74%)
573
(26%)
573

570
2,214 s
(100%)
Total Steam or
Combined Cycle
Turbine Capacity
(MW)
528,000
(71%)
213,000
(29%)
87,700 e

125,000 s
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 (/'. 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.
                                                                     4-14

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                                                                                                      Section 4—Steam Electric Industry Description
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.
                                                                      4-15

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                                                                Section 4—Steam Electric Industry Description
Table 4-3. Distribution of Fuel Types Used by Steam Electric Generating Units
Fossil or Nuclear Fuel a
Coal:
Anthracite Coal
Bituminous Coal
Subbituminous Coal
Lignite Coal
Coal Synfuel
Waste/Other Coal
Blend c
Petroleum Coke
Oil:
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
Waste Oil/Other Oil
Blend c
Gas:
Natural Gas
Blast Furnace Gas
Gaseous Propane
Other Gases
Blend c
Stand-Alone Steam Turbines
Number of
Plants
455-465
1
209
145
10-15
0
17
106
8
55-65
0
1-5
1
0
15-20
o
6
0
0
0
32
171
111
0
0
0
0
Number of Electric
Generating Units
1,080-1,090
1
497
310
10-20
0
18
240
;;
70-85
0
1-5
1
0
20-30
3
0
0
0
46
367
367
0
0
0
0
Total Turbine
Capacity (MW)
328,000-330,000
128
144,000
109,000
7,000-8,000
0
1,660
66,700
751
22,500-23,500
0
200-300
210
0
12,500-13,500
1,480
0
0
0
8,430
71,500
71,500
0
0
0
0
Combined Cycle Steam Turbines b
Number of
Plants
2
0
1
0
0
0
0
1
;
5-10
0
0
0
0
0
4
0
1-5
0
0
400
395
0
0
0
5
Number of Electric
Generating Units
2
0
1
0
0
0
0
1
;
5-15
0
0
0
0
0
7
0
1-5
0
0
562
556
0
0
0
5
Total Turbine
Capacity (MW)
427
0
101
0
0
0
0
326
334
1,400-1,900
0
0
0
0
0
438
0
1,000-1,500
0
0
210,000
210,000
0
0
0
537
                                    4-16

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                                                                                                       Section 4—Steam Electric Industry Description
                            Table 4-3. Distribution of Fuel Types Used by Steam Electric Generating Units
Fossil or Nuclear Fuel a
Nuclear
Total
Stand-Alone Steam Turbines
Number of
Plants
66
716 d
Number of Electric
Generating Units
99
1,640
Total Turbine
Capacity (MW)
104,000
528,000
Combined Cycle Steam Turbines b
Number of
Plants
0
408 d
Number of Electric
Generating Units
0
573
Total Turbine
Capacity (MW)
0
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.
                                                                      4-17

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                                                             Section 4—Steam Electric Industry Description
     Table 4-4. Distribution by Size of Steam Electric Capacity and Plants Regulated by
                           the Steam Electric Power Generating ELGs

Total Steam Electric Capacity b
Percentage of Capacity
Number of Plants
Percentage of Plants
Overall Plant Capacity Range a
0-100
MW
5,040
0.7%
103
9.6%
100-200
MW
9,410
1.3%
88
8.2%
200-300
MW
11,300
1.5%
72
6.6%
300-400
MW
17,600
2.4%
79
7.3%
400-500
MW
17,100
2.3%
61
5.7%
>500 MW
680,000
91.8%
676
62.7%
Total
741,000
100%
1,079 c
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 industry-
weighting 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

Total Steam Electric
Capacity
Percentage of Capacity
Number of Steam Electric
Generating Units
Percentage of Steam
Electric Generating Units
Unit Capacity Range a
0-50
MW
8,010
1.1%
281
12.7%
50-100
MW
23,200
3.1%
305
13.8%
100-200
MW
65,700
8.9%
445
20.1%
200-300
MW
62,200
8.4%
247
11.2%
300-400
MW
72,200
9.7%
207
9.3%
400-500
MW
55,700
7.5%
124
5.6%
>500
MW
454,000
61.3%
605
27.3%
Total
741,000
100%
2,214
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.
                                                 4-18

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                                                      Section 4—Steam Electric Industry Description
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
ESP
Baghouse
Baghouse and ESP
Wet Scrubber
Other
Total
Number of
Plants
335
143
5-15
5-15
20
508-528 a
Number of Coal- and Petroleum
Coke-Fired Steam Electric Units
816
220
10-15
15-25
12
1,080-1,100 a
Number of Oil-Fired
Steam Electric Units
5-10
0
2
0
9
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 industry-
weighting 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,
                                            4-19

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                                                     Section 4—Steam Electric Industry Description
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 parti culates, the layer of parti culates 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.
                                          4-20

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                                                       Section 4—Steam Electric Industry Description
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
Wet-Sluiced
Handled Dry or Removed in
Scrubber a
Handled Either Wet or Dry b
No Handling System Reported
Total
Number of
Plants
57
(11%)
344
(67%)
81
(16%)
32
(6%)
514
Coal- and Petroleum Coke-
Fired Steam Electric Units
Number of
Units
205
713
168
10
1,096
Capacity
(MW)
47,000
(14%)
222,000
(67%)
59,000
(18%)
2,370
(1%)
330,000
Oil-Fired Steam
Electric Units
Number of
Units
10-15
10-15
1-5
61
80-95
Capacity
(MW)
7,500-10,000
(33%)
2,500-5,000
(17%)
500-1,500
(3%)
11,400
(44%)
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 industry-
weighting 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
                                            4-21

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                                                     Section 4—Steam Electric Industry Description
handling systems, or in some instances operate both a wet and a dry fly ash handling system for
an individual generating unit.
    Type of Fly Ash Transport System at Plant Level

      • Wet Handling • Wet and Dry Handling
      O Dry Handling
Source: Steam Electric Survey [ERG, 2015a].

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

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                                                       Section 4—Steam Electric Industry Description
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
Wet Vacuum System (pneumatic) a
Dry Vacuum System b
Pressure System °
Combined Vacuum/Pressure System d
Total e
Number of Plants
1-5
24
5-10
18
45-55 (35-42%)
Number of Units
1-5
50
15-25
36
85-115 (26-35%)
Capacity
(MW)
2,000-3,000
9,400
7,500-10,000
15,800
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 industry-
weighting 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.
                                            4-23

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                                                      Section 4—Steam Electric Industry Description
       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.
                                           4-24

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                                                          Section 4—Steam Electric Industry Description
     Table 4-9. Bottom Ash Handling Practices in the Steam Electric Power Generating
                                            Industry
Bottom Ash Handling
Wet-Sluiced
Handled Dry a
Handled Either Wet or Dry
No Handling System
Reported
Total
Number of
Plants
319(62%)
142 (28%)
26 (5%)
29 (5%)
516
Coal- and Petroleum Coke-Fired
Steam Electric Units
Number of
Units
863
214
6
12
1,096
Capacity
(MW)
286,000 (87%)
39,900 (12%)
2,610 (1%)
1,400 (<1%)
330,000
Oil-Fired Steam Electric Units
Number of
Units
0-5
30-35
0
57
80-95
Capacity
(MW)
0-250 (1%)
10,000-15,000
(51%)
0
11,500(48%)
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 industry-
weighting 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).
                                              4-25

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                                                     Section 4—Steam Electric Industry Description
                                                   °-v     ..     *•
                                                      . • »0              I
                                            _J  .    JK    °  o-   *°
                                           • %.*      '  c?c  cp. ..r*c
                                             *^     •  r,            •  _ • *
   Type of Bottom Ash Transport System at Plant Level

      • Wet Handling • Wet and Dry Handling
      O Dry Handling
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 1'. 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.
                                          4-26

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                                                        Section 4—Steam Electric Industry Description
      Table 4-10. Conversions of Bottom Ash Sluicing Systems Between 2000 and 2009
Type of Dry Bottom Ash
Handling System Installed
Mechanical Drag System
Dry Vacuum System
Dry Pressure System
Other
Total a
Number of Plants
10-15
1-5
0
1-5
12-25 (3-7%)
Number of Units
15-20
5-10
0
1-5
21-35 (2-4%)
Capacity
(MW)
6,500-7,500
250-500
0
100-300
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 862 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.
                                             4-27

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                                                     Section 4—Steam Electric Industry Description
     Reagent Slurry
                                                                        Gas to Stack
                                              Sorbent Slurry Makeup
      Flue Gas
                DryFGD
                Scrubber
 Gas to Particulate
Collector and Stack
                       FGD Reagent Slurry
                                                   Flue Gas
Wet FGD      FGD Solids
Scrubber      Separation
              Recycle
                                                                             FGD Scrubber
                                                                               Purge to
                                                                   FGD Slurry    Wastewater
                                                                   Slowdown    Treatment
           Dry FGD System
                          Recirculating Wet FGD System
                                                  Gas to Stack
                     Sorbent Slurry Makeup
                      FGD Reagent Slurry
                          Flue Gas
               Wet FGD
               Scrubber
                                                          FGD Slurry
                                                        • Discharge to
                                                         Wastewater
                                                          Treatment
                             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, 862 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.
                                           4-28

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                                                     Section 4—Steam Electric Industry Description
       Wet FGD scrubber systems can remove over 90 percent, and in some cases up to 99
percent, of the 862 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
(CaCOs), which react with the sulfur in the flue gas to form calcium sulfite (CaSCb). Scrubbers
can be operated with forced, inhibited, or natural oxidation systems. In forced oxidation systems,
the CaSOs is fully oxidized to produce gypsum (CaSO/r 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 coal-
fired 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).
                                           4-29

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                                                          Section 4—Steam Electric Industry Description
   Table 4-11. Types of FGD Scrubbers in the Steam Electric Power Generating Industry
Type of Scrubber
Circulating Dry
Jet Bubbling Reactor
Mechanically Aided
Packed
Spray
Spray/Tray
Spray Dryer
Tray
Venturi
Other a
No Information b
"Wet" FGD Systems
Number of Plants
0
10-15
0
2
77
58
1
1
10
7
2
Number of Electric
Generating Units
0
30-40
0
4
159
118
1
1
23
15
2
"Dry" FGD Systems
Number of
Plants
11
0
1
1
1-5
0
50
0
1-5
5-10
0
Number of Electric
Generating Units
11
0
1
2
1-5
0
69
0
1-5
7-12
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

Total
Wet FGD Systems
Number of
Plants
150
Number of
Electric
Generating
Units
357
Scrubbed
Capacity a
(MW)
176,000
Dry FGD Systems
Number of
Plants
72
Number of
Electric
Generating
Units
99
Scrubbed
Capacity a
(MW)
32,200
Coal Type
Bituminous
Subbituminous
Lignite
Petroleum Coke
Other/Waste Coal
Blend b
No Information °
86
28
7
1
0
32
4
200
63
9
1
0
80
4
102,000
33,400
5,330
184
0
32,800
2,420
28
29
2
0
1
8
5
40
40
3
0
1
10
5
8,610
16,900
1,320
0
585
1,870
2,850
Type of Oxidation System
Forced Oxidation
113
272
136,000
o
J
4
851
                                               4-30

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                                                              Section 4—Steam Electric Industry Description
          Table 4-12. Characteristics of Coal- and Petroleum Coke-Fired Generating
                                      Units with FGD Systems

Inhibited Oxidation
Natural Oxidation
No Information or NA d
Wet FGD Systems
Number of
Plants
17
25
3
Number of
Electric
Generating
Units
34
51
4
Scrubbed
Capacity a
(MW)
19,600
19,900
1,220
Dry FGD Systems
Number of
Plants
2
5
62
Number of
Electric
Generating
Units
3
10
82
Scrubbed
Capacity a
(MW)
1,480
2,310
27,500
Sorbent
Lime
Limestone
Magnesium-Enhanced
Lime
Magnesium Oxide
Soda Ash
Sodium Hydroxide
Other
No Information d
12
122
13
1
o
6
i
5
4
29
286
29
2
9
2
12
6
9,340
144,000
15,900
740
1,870
277
6,030
3,670
56
14
0
0
0
0
14
0
73
20
0
0
0
0
24
0
24,500
6,660
0
0
0
0
6,380
0
NOx Controls e
SCR
SNCR
None/Other (no
SCR/SNCR)
No Information d
97
13-23
58
2
201
35-40
113
2
116,000
11,500-12,500
46,300
900
27
12
30-40
5
32
14
45-50
5
13,200
4,070
13,500-14,000
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.
                                                  4-31

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                                                    Section 4—Steam Electric Industry Description
    Plants Operating Wet FGD Systems

    O  Plants Operating '.'Jet FGD Systems
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 CaSCb 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 CaSCb) typically require
dewatering prior to sale, disposal, or processing for reuse. The dewatering process used by plants
that generate CaSOs 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
                                          4-32

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                                                    Section 4—Steam Electric Industry Description
wastewater with CaSCb 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.
             1970-1980
1980-1990
1990-2000
  Decade
2000-2010
2010-2014
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 paniculate 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:
                                          4-33

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                                                    Section 4—Steam Electric Industry Description
       •  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 paniculate 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 parti culate 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 parti culate removal
system, then the plant will use a secondary paniculate removal system, typically a fabric filter, to
capture the FGMC wastes. Plants typically inject the carbon downstream of the primary
parti culate 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.
                                          4-34

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                                                   Section 4—Steam Electric Industry Description
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.
                                         4-35

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                                                      Section 4—Steam Electric Industry Description
       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
2000 to Present
1990 to 2000
1980 to 1990
Before 1980
Insufficient Data
Total
Landfills
Total
66
53
102
59
3
283
Number
Lined
55
33
60
31
-
179
Number Collecting
Leachate
51
24
49
22
-
146
Impoundments
Total
88
96
308
593
15
1,100
Number
Lined
77
74
231
180
-
562
Number Collecting
Leachate
30
18
34
66
-
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.
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                                                      Section 4—Steam Electric Industry Description
     Table 4-14. Destination of Combustion Residual Leachate in Steam Electric Power
                                    Generating Industry
Destination
Returned to Management Unit (Impoundment or
Landfill) or Recycled Within the Plant
On-Site Treatment System
Discharged
Other a
Insufficient Data
Total b
Number of Impoundments
48 (47%)
6 (6%)
35 (34%)
21 (20%)
7
110
Number of Landfills
35 (28%)
23 (18%)
86 (68%)
23 (18%)
-
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:
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                                                    Section 4—Steam Electric Industry Description
       •  Slowdown 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 rej ect.
       •  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 coal-
fired 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
                                          4-38

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                                                    Section 4—Steam Electric Industry Description
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., non-
chemical 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.
                                          4-39

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                                                    Section 4—Steam Electric Industry Description
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 IHb) 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.
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                                                     Section 4—Steam Electric Industry Description
       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
Classical*
Ammonia
Nitrate Nitrite as N
Nitrogen, Total Kjeldahl
Biochemical Oxygen Demand
Chemical Oxygen Demand
Chloride
Sulfate
Cyanide, Total
Total Dissolved Solids
Total Suspended Solids
Phosphorus, Total
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
26,800
8.98
42,800
ND(14.7)
88.8
NQ (300)
163,000
1.20
163,000
27.3
0.155
<383
1.80
740
<3.65
NQ (20.0)
NQ (6.75)
1,050
ND (0.100)
1,050
<6.75
NQ (0.0500)
Total Metals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ng/L
ug/L
ug/L
ug/L
ug/L
ug/L
450
2.65
40.0
57.5
ND (2.00)
13,000
NQ (4.00)
24,000
1,540
73.3
400
4,380
7.78
15,800
965
3,530
2,630
4,530
4,900
ND (2.00)
16,000
NQ (200)
ND (2.00)
NQ (4.00)
NQ (20.0)
ND (2.00)
1,540
ND (4.00)
< 2,390
<17.5
NQ (20.0)
14.9
2,020
NQ (2.00)
1,990
101
1,060
NQ (40.0)
27.5
128
ND (2.00)
NQ (10,000)
                                          4-41

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                                                     Section 4—Steam Electric Industry Description
       Table 4-15. Carbon Capture Wastewater 4-Day Average Concentration Data
Analyte
Thallium
Tin
Titanium
Vanadium
Zinc
Unit
ug/L
ug/L
ug/L
ug/L
ug/L
4-Day Average Concentration
PVF Bleed Stream
2.30
ND (200)
NQ (20.0)
19.0
293
Flue Gas Condensate
ND (2.00)
ND (200)
NQ (20.0)
NQ (10.0)
NQ (40.0)
Source: CWA 308 Monitoring [ERG, 2012].
< - Average result includes at least one value measured below the quantitation limit. Calculation uses !/2 the sample-
specific quantitation limit for values below the quantitation limit.
ND - Not detected (number in parenthesis is the quantitation limit).
NQ - Analyte was measured below the quantitation limit for all four results (number shown in parenthesis is the
average quantitation limit), but at least one result was measured above the method detection limit.
Note: Concentrations are rounded to three significant figures.

       According to the 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
                                          4-42

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                                                       Section 4—Steam Electric Industry Description
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].
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                                                      Section 4—Steam Electric Industry Description
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 coal-
fired 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
Full
Partial
Total
Retirement or Fuel
Conversion
145
25
170
Bottom Ash Conversion
17
0
17
Fly Ash Conversion
18
0
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].
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                                                     Section 4—Steam Electric Industry Description
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.

    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
27
Bottom Ash
23
Fly Ash
12
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.
       Table 4-18. Number of Plants Removed from ELG Compliance Costs Due to
                               Implementation of the CPP

Type of Removal
Full
Partial
Total
Total for
Regulatory
Option D
47
19
66

Bottom Ash
38
15
53

Fly Ash
3
5
8

FGD
18
9
27

IGCC
1
0
1
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
(/'. 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.
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                                                   Section 4—Steam Electric Industry Description
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).
           DCNSE00071.
       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/smart-
           energy/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. Available 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/chapterl.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:


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                                             Section 4—Steam Electric Industry Description
    http://wwwl.eere.energy.gov/al/faqs.html and
    http://wwwl.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/gasification-
    plant-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.
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                                                          Section 5—Industry Sub categorization
                                                                        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].
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                                                            Section 5—Industry Sub categorization
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.
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                                                           Section 5—Industry Sub categorization
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.
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                                                           Section 5—Industry Sub categorization
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 non-
chemical), 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
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                                                          Section 5—Industry Sub categorization
metals concentrations, EPA found that all pollutants in untreated FGD wastewater from once-
through 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.
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                                                                              Section 6—
                                             Wastewater Characterization and Pollutants of Concern
                                                                       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).
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                                                                                 Section 6—
                                               Wastewater Characterization and Pollutants of Concern
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 862 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.
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                                                                              Section 6—
                                             Wastewater Characterization and Pollutants of Concern
       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, mag-
lime) 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 (BODs) 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 once-
through 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
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                                                                              Section 6—
                                             Wastewater Characterization and Pollutants of Concern
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 teachability 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
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                                                                                     Section 6—
                                                 Wastewater Characterization and Pollutants of Concern
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

Total
Number of Plants Discharging
100
Average Discharged
Wastewater Flow
(gpd/plant)
451,000
Coal Type a
Bituminous
Subbituminous
Lignite
Blend b
64
15-20
1-5
10-15
488,000
157,000
525,000
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.
                                              6-5

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                                                                                Section 6—
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       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
Classical*
Ammonia as Nitrogen
Nitrate-Nitrite as N
Nitrogen, Kjeldahl
Biochemical Oxygen Demand
Chemical Oxygen Demand
Chloride
Sulfate
Cyanide, Total
Total Dissolved Solids
Total Suspended Solids
Phosphorus, Total
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
13.1
91.4
34.9
8.18
345
7,180
13,300
0.733
33,300
14,500
4.02
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Metals, Metalloids, and other Nonmetals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Hexavalent Chromium
Cobalt
Copper
Iron
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
331,000
28.9
507
2,750
17.5
242,000
127
3,290,000
1,270
NA
245
673
566,000
1,470
3.87
7.07
284
2
266,000
128
2,050,000
4.17
4.76
206
20.1
100
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                                                                                    Section 6—
                                                Wastewater Characterization and Pollutants of Concern
        Table 6-3. Average Pollutant Concentrations in Untreated FGD Wastewater
Analyte
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Tin
Titanium
Vanadium
Zinc
Unit
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Average Total
Concentration
315
3,250,000
85,700
289
273
1,490
3,130
8.18
2,520,000
22.1
164
4,300
1,300
4,110
Average Dissolved
Concentration a
1.00
3,370,000
106,000
7.19
136
973
1,130
1.00
276,000
15.1
100
10
13.4
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
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                                                                                      Section 6—
                                                 Wastewater Characterization and Pollutants of Concern
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 MOD.

 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.
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                                                                                  Section 6—
                                               Wastewater Characterization and Pollutants of Concern
297 billion gallons of bottom ash transport water in 2009, with the average plant generating 2.49
MOD.

     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
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                                                                                  Section 6—
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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 MOD of fly ash transport water and approximately 2.1 MOD 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
Fly Ash
Bottom Ash
Number of Plants Discharging
113
283
Average Discharged Wastewater Flow
(gpd/plant)
3,480,000
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
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                                                                               Section 6—
                                             Wastewater Characterization and Pollutants of Concern
some amount of settling37. Based on the information EPA collected, fly ash transport water
generally contains TSS, IDS, sulfate, chloride, sodium, calcium, copper, and selenium. Bottom
ash transport generally contains TSS, IDS, 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 Deceiving 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.
                                          6-11

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                                                                                     Section 6—
                                                 Wastewater Characterization and Pollutants of Concern
    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
Plants3
Average Flow
Rate
Median Flow
Rate
Range of Flow Rate
Flow Rate per Plant (gpd/plant)
Landfill
Impoundment
Active/Inactive
Active/Inactive
Total
110-120
100-110
150-200
239,000
826,000
574,000
202,000
176,000
157,000
11,700-1,480,000
170-7,880,000
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
Landfill
Impoundment
Unit Operating
Status
Active/Inactive
Active/Inactive
Total
Number of
Plants
90-100
30-40
100-110
Average Discharged Wastewater Flow
(gpd/plant)
70,000-80,000
70,000-80,000
80,000-90,000
Source: Steam Electric Survey [ERG, 2015a].
Note: Wastewater flow rates are rounded to three significant figures.
                                             6-12

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                                                                                     Section 6—
                                                 Wastewater Characterization and Pollutants of Concern
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
Classical*
Chloride
Sulfate
TDS
TSS
ug/L
ug/L
ug/L
ug/L
413,000
1,790,000
3,500,000
35,800
Metals, Metalloids, and other Nonmetals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
2,990
3.75
38.4
53.2
1.33
22,400
10.1
408,000
2,120
38.6
7.58
37,100
2.37
118,000
2,720
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                                                                               Section 6—
                                             Wastewater Characterization and Pollutants of Concern
      Table 6-9. Average Pollutant Concentrations of Combustion Residual Leachate
Analyte
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Tin
Titanium
Vanadium
Zinc
Units
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Average Total Concentration
1.06
1,380
46.5
111
1.63
308,000
1.16
49.3
13.6
1,910
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 (ACT) 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 parti culate 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 parti culate removal system, the
FGMC waste must be collected in a separate paniculate 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 ACT 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 ACT 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
ACT 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
                                          6-14

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                                                                                 Section 6—
                                               Wastewater Characterization and Pollutants of Concern
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 ACT 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 ACT systems and two operating
brominated ACT 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
Brayton Point
Pleasant Prairie
Salem Harbor
Facility C
St. Clair a
Facility L (Run 1) a
Facility L (Run 2) a
Mercury (EPA Method 3052)
Fly Ash Only
(ng/g)
651
158
529
16
111
13
20
With ACI
(ng/g)
1,530
1,180
412
1,151
1,163
38
71
Percent
Increase
135%
648%
-22%
7,094%
949%
190%
252%
Mercury (EPA Method 7473)
Fly Ash Only
(ng/g)
582
147
574
11
NT
NT
NT
With ACI
(ng/g)
1,414
1,177
454
1,090
NT
NT
NT
Percent
Increase
143%
701%
-21%
9,810%
NA
NA
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].
                                           6-15

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                                                                                Section 6—
                                              Wastewater Characterization and Pollutants of Concern
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
Classical*
Ammonia as Nitrogen
Nitrate Nitrite as N
Nitrogen, Kjeldahl
Biochemical Oxygen Demand
Chemical Oxygen Demand
Chloride
Sulfate
Total Dissolved Solids
Total Suspended Solids
Phosphorus, Total
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
175
0.09
603
7.7
101
1,300
2,750
4,575
16
0.47
35
0.05
65
205
823
1,050
11
4,225
2.0
0.19
105
0.07
334
106
462
1,175
1,380
4,400
8.9
0.33
Metals, Metalloids, and Other Nonmetals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Cyanide, Total
Iron
Lead
Magnesium
Manganese
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
mg/L
ug/L
ug/L
ug/L
ug/L
11,475
363
280
118
14
38,250
4.1
19,450
4.0
10
2.0
1.4
2,115
18
5,325
238
100
1.0
4
10
1.0
34,750
2.0
783
4.0
10
2.0
2.3
1,140
1.0
200
10
5,788
182
142
64
7.3
36,500
3.0
10,116
4.0
10
2.0
1.8
1,628
10
2,763
124
                                          6-16

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                                                                               Section 6—
                                              Wastewater Characterization and Pollutants of Concern
               Table 6-11. Untreated Gasification Wastewater Concentrations
Analyte
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Tin
Titanium
Vanadium
Zinc
Units
ng/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Polk
Concentration
70
49
4,950
1,278
1.0
1,675,000
254
100
19
280
77
Wabash River
Concentration
4.3
20
2.0
920
1.0
1,850,000
3
100
10
16
20
Average Polk and
Wabash River
Concentration
37
35
2,476
1,099
1.0
1,762,500
129
100
15
148
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.
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                                                                               Section 6—
                                             Wastewater Characterization and Pollutants of Concern
       •   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.
                                          6-18

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                                                                               Section 6—
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       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
Conventional Pollutants
Priority Pollutants
Nonconventional Pollutants
Pollutant of Concern
Total Suspended Solids
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Cyanide, Total
Lead
Mercury
Nickel
Selenium
Thallium
Zinc
Aluminum
Ammonia as Nitrogen
Barium
Boron
Calcium
Chloride
Cobalt
Iron
Magnesium
Manganese
Molybdenum
Nitrate Nitrite as N
                                          6-19

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                                                                                  Section 6—
                                               Wastewater Characterization and Pollutants of Concern
                    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.
                                           6-20

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                                                                                 Section 6—
                                               Wastewater Characterization and Pollutants of Concern
             Table 6-13. Pollutants of Concern - Combustion Residual Leachate
Pollutant Group
Conventional Pollutants
Priority Pollutants
Nonconventional Pollutants
Pollutant of Concern
Total Suspended Solids
Antimony
Arsenic
Cadmium
Chromium
Copper
Mercury
Nickel
Selenium
Thallium
Zinc
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.
                                           6-21

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                                                                                      Section 6—
                                                 Wastewater Characterization and Pollutants of Concern
                 Table 6-14. Pollutants of Concern - Gasification Wastewater
Pollutant Group
Conventional Pollutants
Priority Pollutants
Nonconventional Pollutants
Pollutant of Concern
Biochemical Oxygen Demand
Total Suspended Solids
Antimony
Arsenic
Beryllium
Cadmium
Copper
Lead
Mercury
Nickel
Selenium
Thallium
Cyanide, Total
Zinc
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].
                                              6-22

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                                                                              Section 6—
                                             Wastewater Characterization and Pollutants of Concern
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 EPRI-
          published 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.
                                         6-23

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                                                                                 Section 6—
                                              Wastewater Characterization and Pollutants of Concern
       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
Conventional Pollutants a
Priority Pollutants
Pollutant of Concern
Total Suspended Solids
Chemical Oxygen Demand
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.
                                           6-24

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                                                                                      Section 6—
                                                  Wastewater Characterization and Pollutants of Concern
               Table 6-15. Pollutants of Concern - Fly Ash Transport Water
Pollutant Group

Nonconventional Pollutants
Pollutant of Concern
Selenium
Thallium
Zinc
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
Conventional Pollutants a
Priority Pollutants
Pollutant of Concern
Total Suspended Solids
Chemical Oxygen Demand
Antimony
Arsenic
                                              6-25

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                                                                                        Section 6—
                                                   Wastewater Characterization and Pollutants of Concern
              Table 6-16. Pollutants of Concern - Bottom Ash Transport Water
Pollutant Group

Nonconventional Pollutants
Pollutant of Concern
Bromide
Cadmium
Chromium
Copper
Lead
Mercury
Nickel
Selenium
Thallium
Zinc
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.
                                               6-26

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                                                                              Section 6—
                                             Wastewater Characterization and Pollutants of Concern
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 ACT systems injecting the carbon upstream of the primary parti culate
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
Conventional Pollutants a
Priority Pollutants
Nonconventional Pollutants
Pollutant of Concern
Total Suspended Solids
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Mercury
Nickel
Selenium
Thallium
Zinc
Aluminum
Ammonia as Nitrogen
Barium
Boron
Calcium
Chloride
Cobalt
                                         6-27

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                                                                              Section 6—
                                             Wastewater Characterization and Pollutants of Concern
                 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
                                         6-28

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                                                                      Section 6—
                                      Wastewater Characterization and Pollutants of Concern
     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).
     DCNSE01816.
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 Multi-
     Pollutant Control. EPA-600-R-08-077. (July). Available online at:
     http://www.epa.gov/nrmrl/pubs/600r08077/600r08077.pdf DCN SE02921.
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                                                         Section 7—Treatment Technologies and
                                                            Wastewater Management Practices
                                                                       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.
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       •  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 BODs 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).
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          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.
                                                               Surface Impoundment
           Zero Discharge
          (51 plants, 3 7%)
                                                            Chemical Precipitation
                       (11 plants, 8%                           (33 plants, 24%)

                           Biological (Anoxic/Anaerobic)
                                   (5 plants, 3%)
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
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                                                        Section 7—Treatment Technologies and
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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."
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                                                            Section 7—Treatment Technologies and
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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 floe that enhances settling of the metals precipitate in downstream
clarification stages.

       Organosulfide precipitation systems use organosulfide chemicals (e.g., trimercapto-s-
triazine (TMT), Nalmet® 1689, sodium sulfide) to precipitate and remove heavy metals, similar
to the set of metals removed in hydroxide precipitation. Plants operating organosulfide
precipitation systems typically use TMT-15®, Nalmet® 1689, MetClear™, 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 MetClear™
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 MetClear™ 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.
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                                                          Section 7—Treatment Technologies and
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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.

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                                                          Section 7—Treatment Technologies and
                                                              Wastewater Management Practices
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
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                                                                                                       Section 7—Treatment Technologies and
                                                                                                           Wastewater Management Practices
FGD Wastewater
                     Polymer
                            Flash
                          Mix Tank
                    r
               Sludge Holding
                   Tank
                                                Lime
                                                 1    1
                                                                               Organosulfide
o
Reactior
O
T Tank 1


•^
                                                                                 Reaction
                                                                                  Tank 2
                 Hydrochloric
                    Acid
                                                  u
                                                     Clarifier
                                                                  I
                                                                              Filter
                                                                               I    Filter
                                                                               '  Backwash
Filter Press
                                           To Sludge Disposal
                                                                                             Filtrate
                                                                                             Sump
                                                                                                             Ferric
                                                                                                            Chloride
                                                             Reaction
                                                              TankS
                                                                     Treated
                                                                    Effluent to
                                                                    Discharge
                                                                    Treated
                                                                    Effluent
                                                                    Recycle
                                                                    Legend
                                                                   • Wastewater Flow
                                                                   ' Intermittent Wastewater Flow
        Figure 7-2. Process Flow Diagram for a Hydroxide and Organosulfide Chemical Precipitation System
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                                                           Section 7—Treatment Technologies and
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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 floe. 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 (BODs) 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.
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                                                          Section 7—Treatment Technologies and
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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
BODs 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 BODs.
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 BODs 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 BODs 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
105°F [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 90°F [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,
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                                                           Section 7—Treatment Technologies and
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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].


FGD
Wastewater
k.

Q
2-
LL C
x— 
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                                                          Section 7—Treatment Technologies and
                                                              Wastewater Management Practices
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].
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       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 nitrate-
nitrite 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 pilot-
scale 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.
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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.
                        Chemical
                     Precipitation Effluent
   Chemical Precipitation
     (See Figure 7-2)
                                        Sodium
                                        Carbonate
o>o
Reaction
 Tank
                                           Clarifier
                                                         Pretreated FGD
                                                          Wastewater
Evaporation System
 (See Figure 7-5}
                                                         Calcium
                                                         Carbonate
         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
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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
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               Deaerator
              Vent to
            Atmosphere
                                            Vent to
                                         Atmosphere
      h
                             FGD Waste
Pretreated FGD
  Wastewater
 Feed/Distillate
Heat Exchanger
                                                           Brine Concentrator/
                                                             Vapor Separator
                                                             Brine
                                                            Recycle
                                                      Brine
                                                     Solution
 Multistage
Compressor/
   Blower
                                                                                                         Concentrated Brine
                                                                                                        	Slurry to: k
        Acid
                                                                                                         Crystallizer;
                                                                                                         Spray Dryer; or
                                                                                                         Fly Ash Conditioning
                                                                                                          Legend
                                  Distillate for
                                Reuse/Discharge
                                                                                                                Liquid Stream
                                                                                                                Gas Stream
                                                                                                                2-Phase Stream
                                Figure 7-5. Process Flow Diagram for an Evaporation System
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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 latan 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
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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.
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       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].

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                                                          Section 7—Treatment Technologies and
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       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 andSulfide Additives with Micro filtration

       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.
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       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 (|im), lOjim, and l|im).
       •   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 high-
efficiency reverse osmosis (HERO™) 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 HERO™ system.

       Although the HERO™ 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 HERO™
system to treat FGD wastewater, some plants with lower TDS and chloride concentrations may
be able to. The HERO™ system is of particular interest for treating boron in FGD wastewaters
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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 titanium-
based oxides were the most prevalent adsorbent at the time of the study. Ferric- and titanium-
based media effectively remove both common forms of arsenic (arsenate and arsenite) and
selenium (selenite) over a wide pH range [EPRI, 2007].

      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 NFUOH. 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
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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,  lona 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
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                                                          Section 7—Treatment Technologies and
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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 wet-
          sluicing 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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       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 filter-
          receivers 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 high-
          pressure 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.


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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.
   Other Handling
  Systems Excludi
   Wet Sluicing
    (570: 80%)
                                     Wet Sluicing
                                     Systems Only
                                       (54, 7%)
                                Combination
                                 Handling
                                 (91, 13%)
                 Syste:
                                                  Other Handling
                                                 Systems Excluding
                                                   Wet Sluicing
                                                    (8,45%)
Wet Sluicing
  ems Only
 (8, 44%)
               'ombination
               Handlina
               (2,11%)
      Coal- and Petroleum Coke-Fired Units
Oil-Fired Units
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 Coke-
and 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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           Wet Vacuum
            Pneumatic
            (11,2%)
    Unknown Dry Ash
  Other/Mechanical
     (10,2%)
Dry Vacuum
(242,43%)
       Combined
     VacuunvPressure
       (119,21%)
                               Pressure
                               (128,23%)
               Other/Mechanical
                  (3,38%)
                                                                                Dry Vacuum
                                                                                  , 62%)
       Conl- and Petroleum Coke-Fired Units
                              Oil-Fired Units
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 waste waters. 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 paniculate 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 by-
product 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.
                                 Feeder Pumps represent the dense ash slurry tank feeder pumps.
                                  GEHO Pumps represent the GEHO piston diaphragm pumps.
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.
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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.
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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
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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 set-
up.
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                                                    To Flyash
                                                     Hopper
                     Aeration Stone
                                                                To
                                                               • Conveying
                                                                Pipe
                                                            Equalizer Valve
                                                             Upper Chamber
                     Aeration Stone
                          Cut-off Gate
                          Lower Chamber
                                                    Lower Gate
                                                 Conveying Pipe
                                                 (Intake Tee)
                   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 wet-
          sluicing 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 wet-
sluicing systems to handle bottom ash, whereas over 95 percent of oil-fired units use systems that
do not use bottom ash transport water. 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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   Other Handling
  Systems that Do Not
  Use Transport Water
    (226,31%)
                                 Wet Sluicing Systems
                                      Only
                                    (488,68%)
            Combination
             Systems
             (3,1%)
 Other Handling
Systems that Do Not
Use Transport Water
   (22,96%)
                               Wet Sluicins Systems
                                   Only
                                  (1,4%)
       Coal-and Petroleum Coke-Fired Units
                Oil-Fired Units
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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  Mechanical Drag
     Systems
    (84,37%)
  Unknown Dry Ash
     Conversion
     (61,27%)
   Dry Vacuum
    (68, 30%)
 Other
(1,1%)
     Dry Pressure
       (12,5%)
                         Dry Vacuum
                          (6,27%)
 Other
(16,73%)
     Coal- and Petroleum  Coke-Fired Units
                               Oil-Fired Units
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 parti culates 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, high-
compressible-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,  20151, McDonough, 2012b].
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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].
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                Incoming Sluice Pipe

                              Underflow
                                 Baffle
                                                              To Settling
                                                              Basin/Tank
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
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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-on-
ignition 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].
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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
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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:
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       •   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.
                                                     Biological
                                                     Treatment
              Surface
           Impoundments
                                                                   Constructed
                                                                    Wetlands
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
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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
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          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 ACT 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 paniculate removal system [ERG, 2015a]. The following describes how these
plants handle their FGMC wastes:

       •   Of the downstream ACT 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 ACT systems handle the FGMC waste dry.
       •   Of the upstream ACT 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 ACT 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.
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                                                          Section 7—Treatment Technologies and
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       •  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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53 EPA is also aware of the Kemper County Energy Facility that will include an IGCC unit. According the operating
company's website, the plant will not discharge any gasification wastewater and, therefore, will not incur any costs
to comply with the ELGs.


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                                                Section 7—Treatment Technologies and
                                                    Wastewater Management Practices
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     SE05088.
69.   WVDEP. 2010. West Virginia Department of Environmental Protection. National
     Pollutant Discharge Elimination System Permit for American Electric Power's
     Mountaineer Plant (WV0048500). (August 6). DCN SE02009.
                                  7-57

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                                                                    Section 8—The Final Rule
                                                                        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.
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                                                                     Section 8—The Final Rule
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 paniculate form of toxic metals.

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                                                                                  Section 8—The Final Rule
Table 8-1. Steam Electric Power Generating Point Source Category Regulatory Options
Wastestreams
FGD
Wastewater
Fly Ash Transport
Water
Bottom Ash
Transport Water
FGMC
Wastewater
Gasification
Wastewater
Technology Basis for BAT/NSPS/PSES/PSNS
Regulatory Options
A
Chemical
Precipitation
Dry Handling
Impoundment (Equal
to BPT)
Dry handling
Evaporation
Combustion Hmpoundment (Equal
Residual Leachate to BPT)
B
Chemical Precipitation
+ Biological Treatment
Dry Handling
mpoundment (Equal to
BPT)
Dry handling
Evaporation
mpoundment (Equal to
BPT)
Non-Chemical [Reserved] [Reserved]
Metal Cleaning
Wastes | |
C
Chemical Precipitation +
Biological Treatment
Dry handling
Dry handling/Closed
oop (for units >400
MW);
Impoundment
(Equal to BPT)(for units
<400 MW)
Dry handling
Evaporation
D
Chemical Precipitation +
Biological Treatment
Dry handling
Dry handling/
Closed loop
Dry handling
Evaporation
Impoundment Hmpoundment
(Equal to BPT) (Equal to BPT)
Reserved] [Reserved]
E 1 F
Chemical Precipitation
+- Biological
Treatment
Dry handling
Dry handling/
Closed loop
Dry handling
Evaporation
Chemical
Precipitation
[Reserved]
Evaporation
Dry handling
Dry handling/
Closed loop
Dry handling
Evaporation
Chemical
Precipitation
Reserved]
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                                                                    Section 8—The Final Rule
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 paniculate form of metals.
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                                                                    Section 8—The Final Rule
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 paniculate form of toxic metals.
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                                                                      Section 8—The Final Rule
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).
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                                                                        Section 8—The Final Rule
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, forty-
five 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.
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                                                                    Section 8—The Final Rule
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 oxidation-
reduction 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

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                                                                    Section 8—The Final Rule
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 well-
designed 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.
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                                                                    Section 8—The Final Rule
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
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                                                                    Section 8—The Final Rule
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 IDS. 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 paniculate 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.

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                                                                     Section 8—The Final Rule
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 !/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.
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                                                                     Section 8—The Final Rule
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 coal-
and 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.
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                                                                     Section 8—The Final Rule
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 closed-
loop 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.
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                                                                     Section 8—The Final Rule
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.
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                                                                    Section 8—The Final Rule
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 well-
demonstrated 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
paniculate 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
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                                                                    Section 8—The Final Rule
(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 quality-
based 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
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                                                                     Section 8—The Final Rule
(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.
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                                                                     Section 8—The Final Rule
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].
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                                                                     Section 8—The Final Rule
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 "FGD-
only" 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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                                                                       Section 8—The Final Rule
Planning Model (IPM)77 using a baseline that reflects impacts from other relevant environmental
regulations (see $\Q 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 Requirements—

       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 CCh),
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].
                                            8-21

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                                                                    Section 8—The Final Rule
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
                                          8-22

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                                                                     Section 8—The Final Rule
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 oil-
fired 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 oil-
fired 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
                                           8-23

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                                                                    Section 8—The Final Rule
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.
                                          8-24

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                                                                    Section 8—The Final Rule

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0 200 400 600 800 1000 1200 1400
Unit Capacity (MW)
  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
                                          8-25

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                                                                    Section 8—The Final Rule
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 a/., 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.
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                                                                     Section 8—The Final Rule
       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)(l)
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)(l) 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)(l), 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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                                                                    Section 8—The Final Rule
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 IDS 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).
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                                                                    Section 8—The Final Rule
       •  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.
                                          8-29

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                                                                    Section 8—The Final Rule
       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 pass-
through 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).


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                                                                      Section 8—The Final Rule
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
Chemical Precipitation for Combustion Residual
Leachate (only for NSPS)
Pollutant
Arsenic
Mercury
Pass Through?
(Yes or No)
Yes
Yes

Chemical Precipitation Plus Biological Treatment
for FGD wastewater
Arsenic
Mercury
Nitrate Nitrite as N
Selenium
Yes
Yes
Yes
Yes

Evaporation for FGD Wastewater (only for NSPS)
Arsenic
Mercury
Selenium
TDS
Yes
Yes
Yes
Yes

Evaporation for Gasification Wastewater
Arsenic
Mercury
Selenium
TDS
Yes
Yes
Yes
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.
                                           8-31

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                                                                    Section 8—The Final Rule
       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)(l), 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.


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                                                                    Section 8—The Final Rule
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.
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                                                                    Section 8—The Final Rule
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
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                                                                    Section 8—The Final Rule
precipitation plus evaporation under this final rule, EPA decided not to apply the anti-
circumvention 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.
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                                                                    Section 8—The Final Rule
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)(l). 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 municipally-
owned 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
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                                                                    Section 8—The Final Rule
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.
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                                                                 Section 8—The Final Rule
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. EPA-
             HQ-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 forNSPS/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 PondMapping Database. (30
             September). DCN  SE05875.
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                                                           Section 8—The Final Rule
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. 20151. 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).
      DCNSE05831.
21.    U.S. EPA. 2015b.  U.S. Environmental Protection Agency. Statistical Support
      Document: Effluent Limitations for FGD Wastewater, Gasification Wastewater,
      and Combustion Residual Leachatefor the Final Steam Electric Power
      Generating Effluent Limitations Guidelines and Standards. (30 September). DCN
      SE05733.
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                                                                  Section 9—Engineering Costs
                                                                         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, 2015 a].

       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.
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                                                                   Section 9—Engineering Costs
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).
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                                                                 Section 9—Engineering Costs
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.
                                          9-3

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                                                                    Section 9—Engineering Costs
       •   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).

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                                                                      Section 9—Engineering Costs
       •   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.
                                              9-5

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                                                                 Section 9—Engineering Costs
       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
                                          9-6

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                                                                   Section 9—Engineering Costs
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].
                                           9-7

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                                                                  Section 9—Engineering Costs
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.

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                                                                 Section 9—Engineering Costs
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).
                                          9-9

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                                                                                                               Section 9—Engineering Costs
                             Table 9-1. Technology Costs Modules Used to Estimate Compliance Costs







Technology Option
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
Technology Cost Module

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b - The Agency calculated the plant-level gasification wastewater costs separate from the cost model. See Section 9.9.
                                                                  9-10

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                                                                   Section 9—Engineering Costs
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].
                                           9-11

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                                                                     Section 9—Engineering Costs
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." 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
A
B
C
D
E
FGD
Wastewater
87
87
87
87
87
Fly Ash
Transport
Water
19
19
19
19
19
Bottom Ash
Transport
Water
0
0
78
141
141
Combustion
Residual
Leachate
0
0
0
0
82
Gasification
Wastewater
3
3
3
3
3
FGMC
Wastewater
0
0
0
0
0
Total a
100
100
139
181
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
A
B
C
D
E
FGD
Wastewater
69
69
69
69
69
Fly Ash
Transport
Water
16
16
16
16
16
Bottom Ash
Transport
Water
0
0
61
103
103
Combustion
Residual
Leachate
0
0
0
0
60
Gasification
Wastewater
2
2
2
2
2
FGMC
Wastewater
0
0
0
0
0
Total a
79
79
108
134
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 (SCh), nitrogen
oxides (NOX), carbon dioxide (CCh), hydrogen chloride (HC1), 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.
                                            9-12

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                                                                   Section 9—Engineering Costs
       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 EP A'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].
                                           9-13

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                                                                 Section 9—Engineering Costs
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.
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                                                                 Section 9—Engineering Costs
       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 por tne CCR mje a disp0sai surface impoundment is generally defined as an impoundment that is not dredged
and all CCRs are left in place in perpetuity.
102 por tjje CCR mie; 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 por tjje 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.
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                                                                 Section 9—Engineering Costs
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
FGD
wastewater











CCR Rule
Decision
New disposal
impoundment
New storage
impoundment
Convert to dry
handling




No decision
New disposal
impoundment
Adjustment to
ELG Baseline
No changes

No changes

Plant has a BAT
chemical
precipitation system
in place


No changes
No changes


Effect on ELG Costs a
No changes

No changes

Plant incurs the following costs:
Mercury analyzer
Compliance monitoring
All biological treatment
system costs (including
transportation/disposal)
No changes
No changes

Effect on ELG
Loadings a
No changes

No changes

Baseline loadings
are based on
chemical
precipitation
treatment in place

No changes
No changes

104 por tjje ££R mje jf 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.
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                                                                  Section 9—Engineering Costs
               Table 9-4. ELG Baseline Changes Accounting for CCR Rule
ELG
Wastestream
Fly ash
transport
water






Bottom ash
transport
water










CCR Rule
Decision
New storage
impoundment


Convert to dry
handling


No decision
New disposal
impoundment
New storage
impoundment


Convert to dry
handling




No decision
Adjustment to
ELG Baseline
Plant dredges fly
ash from
impoundment and
disposes of it
Plant operates a dry
fly ash handling
system for all
generating units
No changes
No changes

Plant dredges
bottom ash from
impoundment and
disposes of it
Plant operates a dry
bottom ash
handling or closed-
loop recycle system
for all generating
units
No changes

Effect on ELG Costs a
Plant incurs full conveyance and
intermediate storage capital and
O&M costs, but does not incur
transport/disposal costs
Plant incurs no fly ash
compliance costs.


No changes
No changes

Plant incurs full conveyance and
intermediate storage capital and
O&M costs, but does not incur
transport/disposal costs
Plant incurs no fly ash
compliance costs.




No changes
Effect on ELG
Loadings a
No changes



Plant has a
baseline fly ash
loading of zero.

No changes
No changes

No changes



Plant has a
baseline bottom
ash loading of
zero.


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].
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                                                                  Section 9—Engineering Costs
       •  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.
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                                                                Section 9—Engineering Costs
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.
     Compliance Monitoring Costs = Sampling Labor Costs + Sampling Materials Costs
       + Sample Preservation Costs + Sample Shipping Costs + Sample Analysis Costs
       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.
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                                                                 Section 9—Engineering Costs
       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)
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                                                                  Section 9—Engineering Costs
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 EP A'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].
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                                                                 Section 9—Engineering Costs
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].
      Total O&M Costs = (-1) x (Impoundment O&M Costs + Earthmoving O&M Costs)
                                   x (Capacity Factor)
       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 wet-
sluicing system to transport the bottom ash to the remote MDS destination.
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                                                                 Section 9—Engineering Costs
          Total 10-Year Recurring Costs = (-1) x (Cost of Earthmoving Vehicle)
       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.
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                                                                   Section 9—Engineering Costs
       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.
     Total Capital Costs = Purchased Equipment Costs + Direct Capital Costs + Indirect
                          Capital Costs + Sludge Disposal Costs
       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 non-
direct costs incurred as a result of installing the treatment  system. The indirect capital costs (e.g.,
ice Purchased equipment installation costs are the costs associated with installing those pieces of purchased
equipment, including piping, instrumentation, calibration, and structural supports.
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                                                                 Section 9—Engineering Costs
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.
         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
       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
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                                                                  Section 9—Engineering Costs
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.
                 Total Recurring 6-Year Costs = Cost of Mercury Analyzer
       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].
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                                                                  Section 9—Engineering Costs
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.
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                                                                 Section 9—Engineering Costs
       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.
       Total Capital Costs = Purchased Equipment Costs + Direct Capital Cost + Indirect
                            Capital Cost + Sludge Disposal Costs
       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.
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                                                                Section 9—Engineering Costs
       •   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 atlOO%).
       •   AnoxKaldnes™ 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.
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                                                                  Section 9—Engineering Costs
       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
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                                                                 Section 9—Engineering Costs
       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
                                          9-31

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                                                                  Section 9—Engineering Costs
[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, 2015 a].

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
Chemical Precipitation
Chemical Precipitation
followed by Biological
Treatment
Number
of Plants
87
87
Total Capital
Cost
($)
$888,000,000
$1,790,000,000
Total O&M
Cost
($/year)
$78,100,000
$123,000,000
6-Year
Recurring
Cost
($/6-year)
$7,420,000
$7,420,000
10-Year
Recurring Cost
($/10-year) a
($20,500,000)
($20,500,000)
Note: Costs are rounded to three significant figures.
Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].
a - The values in this column are negative, and presented in parenthesis, because they represent cost savings.
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                                                                  Section 9—Engineering Costs
 Table 9-6. Estimated Industry-Level Costs for FGD Wastewater Based on Oil-Fired Units
      and Units 50 MW or Less Not Installing Technology Basis, Accounting for CPP
Technology Option
Chemical Precipitation
Chemical Precipitation
followed by Biological
Treatment
Number
of Plants
69
69
Total Capital
Cost
($)
$775,000,000
$1,510,000,000
Total O&M
Cost
($/year)
$67,500,000
$103,000,000
6-Year
Recurring
Cost
($/6-year)
$5,890,000
$5,890,000
10-Year
Recurring Cost
($/10-year) a
($16,100,000)
($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
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                                                                   Section 9—Engineering Costs
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.uo 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


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                                                                   Section 9—Engineering Costs
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.
    Total Capital Costs = Purchased Equipment Costs + Direct Capital Costs + Indirect
                         Capital Costs + Fly Ash Disposal Costs
       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].
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                                                                  Section 9—Engineering Costs
  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
       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.m 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].
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                                                                Section 9—Engineering Costs
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.
                  Total 10-Year Recurring Costs = Cost of Water Truck
       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
                                         9-37

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                                                                 Section 9—Engineering Costs
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 wet-
          sluicing system.
     Total MDS Capital Costs = Conveyance and Intermediate Storage Equipment Costs +
          Direct Capital Costs + Indirect Capital Costs + Bottom Ash Disposal Costs
       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
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                                                                 Section 9—Engineering Costs
data, supplemented with vendor data. EPA used the moisture-conditioned bottom ash tonnage to
estimate the disposal costs, described in Section 9.5.3.
   Total Remote MDS Capital Costs = Conveyance and Intermediate Storage Equipment
     Costs + Direct Capital Costs + Indirect Capital Costs + Bottom Ash Disposal Costs
       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.
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                                                                Section 9—Engineering Costs
     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
       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.
     Total Additional Remote O&M Costs = Chemical Purchase Costs + Chemical Pump
                                     Energy 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 (HC1) consumption, chemical purchase, and freight costs. EPA calculated the
HC1 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 HC1 feed
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                                                                 Section 9—Engineering Costs
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].
     Total Intermediate Storage O&M Costs = Storage Operating Labor Costs + Storage
      Maintenance Labor Costs + Storage Maintenance Materials Costs + Storage Energy
                                         Costs
       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].
        Total Wet-Sluicing O&M Costs = Sluicing Operating Labor Costs + Sluicing
     Maintenance Labor Costs + Sluicing Maintenance Materials Costs + Sluicing Energy
                                         Costs
       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
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                                                                 Section 9—Engineering Costs
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].
    Total MDS O&M Costs = Shared O&M Costs + Intermediate Storage O&M Costs -
                               Wet-Sluicing O&M Costs
       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 Remote MDS O&M Costs = Shared O&M Costs + Additional Remote MDS
                      O&M Costs + Intermediate Storage O&M Costs
       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.
          Total 3-Year Recurring Costs = Cost of Mechanical Drag Chain for MDS
       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
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                                                                Section 9—Engineering Costs
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.
     Total 5-Year Recurring Costs = Cost of Mechanical Drag Chain for Remote MDS +
                    Cost of Rental Tank for Remote MDS Maintenance
       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.
       Bottom Ash Management Costs = Engineering Consulting Cost + Total Capital
           Chemical Feed System Cost + Total O&M Chemical Feed System Cost
       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, 2015 a].
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                                                                   Section 9—Engineering Costs
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
19
Total Capital Cost
($)
$180,000,000
Total O&M Cost
($/year) a
($720,000)
10-Year Recurring Cost
($/10-year) a
($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
16
Total Capital Cost
($)
$135,000,000
Total O&M Cost
($/year) a
($573,000)
10-Year Recurring Cost
($/10-year) a
($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.
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                                                                   Section 9—Engineering Costs
  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
141

Total Capital
Cost
($)
$3,460,000,000

Total O&M
Cost
($/year)
$203,000,000

One-Time
Cost
($)
$202,000
3-Year
Recurring
Cost
($/3-year)
$3,680,000
5-Year
Recurring
Cost
($/5-year)
$48,800,000
10-Year
Recurring
Cost
($/10-year) a
($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
103

Total Capital
Cost
($)
$2,520,000,000

Total O&M
Cost
($/year)
$133,000,000

One-Time
Cost
($)
$179,000
3-Year
Recurring
Cost
($/3-year)
$2,450,000
5-Year
Recurring
Cost
($/5-year)
$32,000,000
10-Year
Recurring
Cost
($/10-year) a
($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
78

Total Capital
Cost
($)
$2,290,000,000

Total O&M
Cost
($/year)
$97,100,000

One-Time
Cost
($)
$112,000
3-Year
Recurring
Cost
($/3-year)
$0
5-Year
Recurring
Cost
($/5-year)
$24,300,000
10-Year
Recurring
Cost
($/10-year) a
($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.
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                                                                 Section 9—Engineering Costs
 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
61

Total Capital
Cost
($)
$1,820,000,000

Total O&M
Cost
($/year)
$77,600,000

One-Time
Cost
($)
$89,700
3-Year
Recurring
Cost
($/3-year)
$0
5-Year
Recurring
Cost
($/5-year)
$18,800,000
10-Year
Recurring
Cost
($/10-year) a
($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
Chemical Precipitation
Number of
Plants
82
Total Capital
Cost
($)
$605,000,000
Total O&M
Cost
($/year)
$34,300,000
6-Year
Recurring Cost
($/6-year)
$7,000,000
10-Year
Recurring Cost
($/10-year)
$0
Note: Costs are rounded to three significant figures.
Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].
                                          9-46

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                                                                  Section 9—Engineering Costs
  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
Chemical Precipitation
Number of
Plants
60
Total Capital
Cost
($)
$478,000,000
Total O&M
Cost
($/year)
$28,600,000
6-Year
Recurring Cost
($/6-year)
$5,120,000
10-Year
Recurring Cost
($/10-year)
$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
Evaporation
Number of
Plants
3
Total Capital
Cost
($)
$0
Total O&M
Cost
($/year)
$192,000
6-Year
Recurring Cost
($/6-year)
$0
10-Year
Recurring Cost
($/10-year)
$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
Evaporation
Number of
Plants
2
Total Capital
Cost
($)
$0
Total O&M
Cost
($/year)
$128,000
6-Year
Recurring Cost
($/6-year)
$0
10-Year
Recurring Cost
($/10-year)
$0
Note: Costs are rounded to three significant figures.
Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2015].
                                           9-47

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                                                                 Section 9—Engineering Costs
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
FGD Wastewater
Fly Ash Transport Water
Bottom Ash Transport Water
Leachate
Gasification Wastewater
Flue Gas Mercury Control Wastes
Technology Option
Chemical Precipitation
Biological Treatment
Evaporation
Dry Fly Ash Handling
Dry or Closed-loop Recycle Bottom
Ash Handling
Chemical Precipitation
Evaporation
Dry Handling
Regulatory Option
A
•/


•/


•/
•/
B
•/
•/

•/


•/
•/
C
•/
S

•/
,/b

•/
•/
D
•/
•/

•/
•/

•/
•/
E
•/
•/

•/
•/
•/
•/
•/
Fa
S

S
•/
•/
•/
S
•/
                                          9-48

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                                                                        Section 9—Engineering Costs
  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
Fa
Other Costs Not Specific to Wastestream




Solids Transportation
Solids Disposal
Impoundment Operation
Compliance Monitoring
•/
•/
•/
•/
•/
•/
•/
•/
•/
•/
•/
•/
•/
•/
•/
•/
•/
•/
•/
•/
•/
S
S
•/
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
A
B
C
D
E
Number of
Plants
100
100
139
181
196
Capital
Cost
$1,069
$1,969
$4,258
$5,426
$6,031
Annual
O&M Cost
$78
$123
$220
$326
$360
One-Time
Costs
$0
$0
$0.1
$0.2
$0.2
Recurring Costs
3-year
$0
$0
$0
$4
$4
5-year
$0
$0
$24
$49
$49
6-year
$7
$7
$7
$7
$14
10-year a
($25)
($25)
($54)
($76)
($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
A
B
C
D
E
Number of
Plants
79
79
108
134
145
Capital
Cost
$910
$1,640
$3,462
$4,161
$4,638
Annual
O&M Cost
$67
$103
$180
$235
$264
One Time
Costs
$0
$0
$0.1
$0.2
$0.2
Recurring Costs
3-year
$0
$0
$0
$3
$3
5-year
$0
$0
$19
$32
$32
6-year
$6
$6
$6
$6
$11
10-year a
($19)
($19)
($42)
($58)
($58)
a - The values in this column are negative, and presented in parenthesis, because they represent cost savings.
                                              9-49

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                                                                 Section 9—Engineering Costs
       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.
                                          9-50

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                                                                   Section 9—Engineering Costs
           Table 9-20. NSPS Compliance Cost Scenarios Evaluated for the Rule
Scenario Characteristics
Plant-Level
Characteristics
New
Generating
Unit-Level
Characteristics
NSPS Costs
Plant Status
Presence of On-Site
Impoundments
Presence of On-Site Landfill
TypeofFGD System
Bottom Ash Handling
Fly Ash Handling3
Combustion Residual Leachate b
FGD
Bottom Ash °
Fly Ash a
Combustion Residual Leachate
Existing Plant
Existing
On-site impoundment with no
additional capacity
On-site landfill with available
capacity
Wet FGD system
(impoundments as treatment)
Mechanical drag system
already planned
Dry
No leachate collection in the
landfill
Yes
No
No
No
Greenfield Plant
Greenfield
No on-site impoundment
On-site landfill to be installed
Wet FGD system
(impoundments as treatment)
Mechanical drag system
already planned
Dry
Landfill leachate collected but
not treated
Yes
No
No
Yes
a-All scenarios assume dry fly ash handling because of the current NSPS regulations (40 CFR423.15(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."
                                           9-51

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                                                                                                                Section 9—Engineering Costs
                                          Table 9-21. Estimated Industry-Level NSPS Costs
Regulatory
Option
Small Unit (350 MW)
Total Capital Cost
($)
Total O&M Cost
($/year)
Medium Unit (600 MW)
Total Capital Cost
($)
Total O&M Cost
($/year)
Large Unit (1,300 MW)
Total Capital Cost
($)
Total O&M Cost
($/year)
Greenfield Plant
A
B
C
D
Eb
Fb
a
14,700,000
14,700,000
14,700,000
20,000,000
69,000,000
a
992,000
992,000
992,000
1,200,000
4,700,000
a
19,000,000
19,000,000
19,000,000
25,000,000
78,000,000
a
1,360,000
1,360,000
1,360,000
1,600,000
6,200,000
a
32,700,000
32,700,000
32,700,000
39,000,000
110,000,000
a
2,420,000
2,420,000
2,420,000
2,800,000
11,000,000
Existing Plant
A
B
C
D
Eb
Fb
a
14,700,000
14,700,000
14,700,000
15,000,000
64,000,000
a
992,000
992,000
992,000
1,000,000
4,500,000
a
19,000,000
19,000,000
19,000,000
19,000,000
73,000,000
a
1,360,000
1,360,000
1,360,000
1,400,000
5,900,000
a
32,700,000
32,700,000
32,700,000
33,000,000
100,000,000
a
2,420,000
2,420,000
2,420,000
2,500,000
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.
                                                                   9-52

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                                                              Section 9—Engineering Costs
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).
           DCNSE02971.
      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.
                                        9-53

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                                                    Section 10—Pollutant Loadings and Removals
                                                                     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 post-
          compliance 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
                                         10-1

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                                                        Section 10—Pollutant Loadings and Removals
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 plant-
level basis, EPA calculates baseline loadings by multiplying the average pollutant concentration
in the discharge by the plant-specific wastewater discharge flow rate to generate the mass of
pollutant discharged per year, in pounds/year.

       EPA used sampling data gathered through its sampling program described in Section 3,
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 plant-
specific 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:
                   /lbs\             /gallons\                  /days\               /ug\
    Loadingpollutant ^—J = FlowRate ^——J x Discharge days {-^) x Concpollutant ^—J

                               /2.204621b\   /    1000L    \
                               \  109ug  ) X \264.17gallonsJ

Where:
       T    ,.                 The loadings from a specific pollutant discharged directly to
       Loadingpollutant     =      f      f   •        j
             01^              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.
                                            10-2

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                                                     Section 10—Pollutant Loadings and Removals
                      The flow rate of the wastestream being discharged, in gallons per
                      .
                      day.
                      The number of days per year wastewater is discharged.

                      The average concentration of a specific pollutant present in the
                         .   .      •                 r*
                      wastestream, in micrograms per liter.
      „.   _
      rlowRate

      Discharge Days

      „
      ConCpollutant
       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:
                                              lbs
                                              ~  X (1-POTWRemOVal)
Where:
    ,.                _
i^Oadingpollutant indirect

T   ,.
Loadmgpollutant        =

_„_„,,_       ,
POTWRemoval       =
                                lbs
                                ~ =L°adingpollutant
                              The loadings from a specific pollutant that is transferred to a
                              T»/~»irii-ir  •   ^  1-  1      •        1 ;
                              POTW prior to discharge, in pounds/year.

                              The loadings from a specific pollutant if it were discharged
                              j-   *i  •       j  /
                              directly, in pounds/year.

                              The estimated percentage of the pollutant loading that will be
                                     ,,    D^T™
                              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 (Ib-
equivalent/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.
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                       Section 10—Pollutant Loadings and Removals
Table 10-1. POTW Removals
Analyte
Aluminum
Ammonia
Antimony
Arsenic
Barium
Beryllium
Biochemical Oxygen Demand
Boron
Cadmium
Calcium
Chemical Oxygen Demand
Chloride
Chromium
Hexavalent Chromium
Cobalt
Copper
Cyanide, Total
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Nitrate Nitrite as N
Nitrogen, Kjeldahl
Phosphorus, Total
Selenium
Silver
Sodium
Sulfate
Thallium
Tin
Titanium
Total Dissolved Solids
Total Suspended Solids
Median POTW Removal Percentage
91.0%
39.0%
66.8%
65.8%
55.2%
61.2%
NA
NA
90.1%
NA
NA
NA
80.3%
NA
10.2%
84.2%
NA
NA
77.5%
NA
40.6%
90.2%
NA
51.4%
90.0%
NA
NA
34.3%
88.3%
NA
NA
53.8%
NA
NA
NA
NA
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                                                      Section 10—Pollutant Loadings and Removals
                               Table 10-1. POTW Removals
Analyte
Vanadium
Zinc
Median POTW Removal Percentage
8.3%
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.
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                                                        Section 10—Pollutant Loadings and Removals
       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.
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                                           Section 10—Pollutant Loadings and Removals
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
Progress Energy Carolinas' Roxboro
Steam Electric Plant (Roxboro)
Duke Energy's Miami Fort Station
(Miami Fort)
RRI Energy's Keystone Generating
Station (Keystone)
Allegheny Energy's Hatfield's Ferry
Electric Plant (Hatfield's Ferry)
Source of Data Set
Monitoring data provided by plant
EPA sampling
EPA CWA 308 sampling
Monitoring data provided by plant
EPA sampling
EPA CWA 308 sampling
Monitoring data provided by plant
EPA sampling
Wastestreams Represented
in Data Set
Settling impoundment effluent
Chemical precipitation effluent
and FGD purge a
Chemical precipitation effluent
Chemical precipitation effluent
Chemical precipitation effluent
and FGD purge a
Chemical precipitation effluent
Chemical precipitation effluent
Chemical precipitation effluent
and FGD purge a
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                                                         Section 10—Pollutant Loadings and Removals
                Table 10-2. Data Sets Used in the FGD Loadings Calculation
Plant Name

NRG Energy's Dickerson Generating
Station (Dickerson)
We Energies' Pleasant Prairie Power
Plant (Pleasant Prairie)
Duke Energy Carolinas' Belews Creek
Steam Station (Belews Creek)
Duke Energy Carolinas' Allen Steam
Station (Allen)
Enel's Federico II Power Plant
(Brindisi)
Source of Data Set
EPA CWA 308 sampling
Monitoring data provided by plant
EPA sampling
EPA sampling
EPA CWA 308 sampling
Monitoring data provided by plant
EPA sampling
EPA CWA 308 sampling
Monitoring data provided by plant
EPA sampling
EPA CWA 308 sampling
Monitoring data provided by plant
EPA sampling
Wastestreams Represented
in Data Set
Chemical precipitation effluent
Chemical precipitation effluent
FGD purge a
Chemical precipitation effluent
and FGD purge a
Chemical precipitation effluent
Chemical precipitation effluent
Biological treatment effluent and
FGD purge a
Biological treatment effluent
Biological treatment effluent and
FGD purge a
Biological treatment effluent and
FGD purge a
Biological treatment effluent
Biological treatment effluent and
FGD purge a
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.
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                                                     Section 10—Pollutant Loadings and Removals
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. 12° 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].
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                                                     Section 10—Pollutant Loadings and Removals
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
Classical*
Ammonia
Nitrate Nitrite as N
Nitrogen, Kjeldahl
Biochemical Oxygen Demand
Chemical Oxygen Demand
Chloride
Sulfate
Cyanide, Total
Total Dissolved Solids
Total Suspended Solids
Phosphorus, Total
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
6,850
96,000
32,900
2,220
404,000
7,120,000
1,240,000
949
32,500,000
27,900
319
Total Metals, Metalloids, and Other Nonmetals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Hexavalent Chromium
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
2,080
12.9
7.59
303
1.92
243,000
113
2,050,000
17.8
5.22
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                                                     Section 10—Pollutant Loadings and Removals
  Table 10-3. Average Effluent Pollutant Concentrations for FGD Surface Impoundments
Analyte
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Tin
Titanium
Vanadium
Zinc
Unit
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Average Concentration
183
21.8
1,510
4.66
3,370,000
93,400
7.78
125
878
1,170
0.925
276,000
13.7
100
27.1
16.4
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
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                                                      Section 10—Pollutant Loadings and Removals
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 four-
            day 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.


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                                                     Section 10—Pollutant Loadings and Removals
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
Classical*
Ammonia
Nitrate Nitrite as N
Nitrogen, Kjeldahl
Biochemical Oxygen Demand
Chemical Oxygen Demand
Chloride
Sulfate
Cyanide, Total
Total Dissolved Solids
Total Suspended Solids
Phosphorus, Total
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
6,850
96,000
32,900
2,220
404,000
7,120,000
1,240,000
949
24,100,000
8,590
319
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Surface Impoundment
Surface Impoundment
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Total Metals, Metalloids, and Other Nonmetals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
120
4.25
5.83
140
1.34
225,000
4.21
1,920,000
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
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 Table 10-4. Average Effluent Pollutant Concentrations for Chemical Precipitation System
Analyte
Chromium
Hexavalent Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Tin
Titanium
Vanadium
Zinc
Unit
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Average Concentration
6.45
5.22
9.30
3.78
110
3.39
3,370,000
12,500
0.139
125
9.11
928
0.925
276,000
9.81
100
9.30
12.6
20.0
Concentration Basis
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Surface Impoundment
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Surface Impoundment
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Surface Impoundment
Surface Impoundment
Chemical Precipitation Effluent
Surface Impoundment
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Source: [ERG, 2012c; ERG, 2012f; ERG, 2012g; ERG, 20121].
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
                                          10-14

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                                                      Section 10—Pollutant Loadings and Removals
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 four-
            day 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
                                          10-15

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                                                       Section 10—Pollutant Loadings and Removals
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
Classical*
Ammonia
Nitrate Nitrite as N
Nitrogen, Kjeldahl
Biochemical Oxygen Demand
Chemical Oxygen Demand
Chloride
Sulfate
Cyanide, Total
Total Dissolved Solids
Total Suspended Solids
Phosphorus, Total
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
6,850
647
32,900
2,220
404,000
7,120,000
1,240,000
949
24,100,000
8,590
319
Chemical Precipitation Effluent
Biological Treatment Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Surface Impoundment
Surface Impoundment
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Total Metals, Metalloids, and Other Nonmetals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Hexavalent Chromium
Cobalt
Copper
Iron
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
120
4.25
5.83
140
1.34
225,000
4.21
1,920,000
6.45
5.22
9.30
3.78
110
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
Chemical Precipitation Effluent
122 Of the four baseline biological treatment plants, only three are classified as operating consistently with the
technology basis.
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                                                     Section 10—Pollutant Loadings and Removals
 Table 10-5. Average Effluent Pollutant Concentrations for Chemical Precipitation System
                               with Biological Treatment
Analyte
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Tin
Titanium
Vanadium
Zinc
Unit
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Average Concentration
3.39
3,370,000
12,500
0.0507
125
6.30
5.72
0.925
276,000
9.81
100
9.30
12.6
20.0
Concentration Basis
Chemical Precipitation Effluent
Surface Impoundment
Chemical Precipitation Effluent
Biological Treatment Effluent
Surface Impoundment
Biological Treatment Effluent
Biological Treatment Effluent
Surface Impoundment
Surface Impoundment
Chemical Precipitation Effluent
Surface Impoundment
Chemical Precipitation Effluent
Chemical Precipitation Effluent
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, latan 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 latan does not operate a chemical
precipitation system followed by evaporation consistent with the technology basis. latan'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 latan 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
                                          10-17

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                                                       Section 10—Pollutant Loadings and Removals
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
Classical*
Ammonia
Nitrate Nitrite as N
Nitrogen, Kjeldahl
Biological Oxygen Demand
Chemical Oxygen Demand
Chloride
Sulfate
Total Dissolved Solids
Total Suspended Solids
Phosphorus, Total
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
24,300
100
23,500
2,220
10,000
1,500
2,500
10,800
2,000
25.0
Total Metals, Metalloids, and Other Nonmetals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
100
1.00
2.00
10.0
1.00
3,750
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.
                                           10-18

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                                                    Section 10—Pollutant Loadings and Removals
 Table 10-6. Average Effluent Pollutant Concentrations for Chemical Precipitation System
                                   with Evaporation
Analyte
Calcium
Chromium
Hexavalent Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Tin
Titanium
Vanadium
Zinc
Unit
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Average Concentration
200
4.00
5.22
10.0
2.00
100
1.00
200
10.0
0.0103
20.0
2.00
2.00
1.00
5,000
1.00
100
10.0
5.00
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].
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                                                   Section 10—Pollutant Loadings and Removals
       •   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 follow-
          up 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).
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                                                      Section 10—Pollutant Loadings and Removals
       •  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 plant-
specific 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 andPollutant Removals for Final Effluent Limitation Guidelines and Standards for the Steam
Electric Generating Point Source Category report [U.S. EPA, 2015].
                                          10-21

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                                                Section 10—Pollutant Loadings and Removals
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
Classical*
Nitrate-Nitrite (as N)
Total Kjeldahl Nitrogen
Biochemical Oxygen Demand
Chemical Oxygen Demand
Chloride
Sulfate
Sulfite
Cyanide
Total Dissolved Solids
Total Suspended Solids
Fluoride
Phosphorus, Total
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
2,360
4,080
NA
NA
12,800
409,000
NA
NA
469,000
10,400
276
71.8
6,070
1,160
NA
20,800
28,100
347,000
4,750
NA
754,000
19,700
NA
204
2,550
891
4,670
26,000
16,300
209,000
905
5.28
266,000
15,300
650
196
Total Metals, Metalloids, and Other Nonmetals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Bromide
Cadmium
Calcium
Chromium
Hexavalent Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Potassium
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
2,230
NA
36.4
121
3.42
6,630
NA
7.63
99,300
27.4
NA
5.67
68.8
855
13.7
13,600
144
0.828
483
30.5
8,460
1,240
28.2
17.4
110
NA
541
620
2.19
68,800
5.59
NA
14.5
13.9
1,420
12.1
34,500
1,440
0.634
29.7
16.5
2,960
1,200
24.6
50.3
188
3.86
1,960
NA
1.42
74,600
21.6
0.671
6.00
21.9
601
7.52
15,300
67.5
1.18
142
19.1
12,900
                                     10-22

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                                                     Section 10—Pollutant Loadings and Removals
   Table 10-7. Average Effluent Pollutant Concentration for Ash Impoundment Systems
Analyte
Selenium
Silica
Silver
Sodium
Strontium
Thallium
Titanium
Vanadium
Zinc
Unit
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Average
Fly Ash
Concentration
15.4
8,570
NA
34,000
429
10.3
4.83
NA
226
Average
Bottom Ash
Concentration
11.8
6,300
NA
53,000
258
89.4
40.9
NA
31.0
Average Combined
Ash Concentration
28.0
5,930
4.33
12,400
NA
31.0
22.8
56.4
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.
                                          10-23

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                                                     Section 10—Pollutant Loadings and Removals
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-unit-
specific 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
Classical*
Chloride
Sulfate
Total Dissolved Solids
Total Suspended Solids
ug/L
ug/L
ug/L
ug/L
413,000
1,240,000
3,500,000
8,590
Total Metals, Metalloids, and Other Nonmetals
Aluminum
ug/L
120
                                          10-24

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                                                     Section 10—Pollutant Loadings and Removals
 Table 10-8. Average Effluent Pollutant Concentrations for Chemical Precipitation System
                   for the Treatment of Combustion Residual Leachate
Analyte
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Tin
Titanium
Vanadium
Zinc
Unit
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Average Concentration
3.75
5.83
53.2
1.33
22,400
4.21
408,000
6.45
9.30
3.78
110
2.37
118,000
2,720
0.139
125
9.11
111
0.925
276,000
1.16
49.3
9.30
12.6
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
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                                                    Section 10—Pollutant Loadings and Removals
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
Classical*
Chloride
Sulfate
Total Dissolved Solids
Total Suspended Solids
ug/L
ug/L
ug/L
ug/L
413,000
1,240,000
3,500,000
8,590
Total Metals, Metalloids, and Other Nonmetals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Tin
Titanium
Vanadium
Zinc
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
120
3.75
5.83
53.2
1.33
22,400
4.21
408,000
6.45
9.30
3.78
110
2.37
118,000
2,720
0.0507
125
6.30
5.72
0.925
276,000
1.16
49.3
9.30
12.6
20.0
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                                                    Section 10—Pollutant Loadings and Removals
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.12? 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.
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                                                      Section 10—Pollutant Loadings and Removals
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].
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                                                    Section 10—Pollutant Loadings and Removals
       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.
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                                                    Section 10—Pollutant Loadings and Removals
       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
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                                                     Section 10—Pollutant Loadings and Removals
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 post-
compliance 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].
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                                                        Section 10—Pollutant Loadings and Removals
  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
Baseline
Chemical Precipitation
Chemical Precipitation with
Biological Treatment
Number of
Plants
88 a
88 a
88 a
Total Industry
Discharge Flow
(million gallons
per day (MGD))
41.7
38.4
38.4
Total Industry Loading
Pounds/Year
1,660,000,000
1,620,000,000
1,610,000,000
TWPE/Year
1,880,000
1,070,000
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
Baseline
Chemical Precipitation
Chemical Precipitation with
Biological Treatment
Number of
Plants
69
69
69
Total Industry
Discharge Flow
(MGD)
32.4
30.4
30.4
Total Industry Loading
Pounds/Year
1,290,000,000
1,260,000,000
1,250,000,000
TWPE/Year
1,550,000
842,000
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
Reduction (Baseline ->Chemical Precipitation)
Reduction (Baseline ->Chemical Precipitation with Biological
Treatment)
Total Industry Pollutant Removals
Pounds/Year
36,800,000
47,200,000
TWPE/Year
804,000
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.
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                                                     Section 10—Pollutant Loadings and Removals
  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
Reduction (Baseline ->Chemical Precipitation)
Reduction (Baseline ->Chemical Precipitation with Biological
Treatment)
Total Industry Pollutant Removals
Pounds/Year
26,700,000
35,200,000
TWPE/Year
706,000
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.
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                                                     Section 10—Pollutant Loadings and Removals
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
Combined Ash
Pond3
9
N/Cb
25
N/Cb
46,700,000
68,100,000
69,000
156,000
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                                                           Section 10—Pollutant Loadings and Removals
        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
Combined Ash
Pond3
TOTAL
115
N/Cb
144
200
N/Cb
298-315c
340,000,000
14,800,000
469,000,000
481,000
27,400
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
Combined Ash
Pond3
8
N/Cb
25
N/Cb
45,900,000
51,600,000
67,800
118,000
Bottom Ash
Bottom Ash Pond
Combined Ash
Pond3
84
N/Cb
134
N/Cb
228,000,000
11,700,000
323,000
21,600
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                                                        Section 10—Pollutant Loadings and Removals
       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
TOTAL
Number of Plants
108
Total Baseline
Industry Discharge
Flow
(MGD)
214-228 c
Total Industry Baseline Loading
Pounds/Year
337,000,000
TWPE/Year
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 (/'. 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.
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                                                            Section 10—Pollutant Loadings and Removals
   Table 10-16. Estimated Ash Impoundment Pollutant Removals by Regulatory Option
                             Excluding BOD, COD, TDS, and TSS
Regulatory
Option a
Total Industry Loading
Pounds/Year
TWPE/Year
Total Industry Pollutant Removals b
Pounds/Year
TWPE/Year
Fly Ash
All Regulatory
Options
1,490,000
2,880
113,000,000
222,000
Bottom Ash
A,B
C
D,E
354,000,000
139,000,000
1,890,000
509,000
198,000
2,390
NA
216,000,000
353,000,000
NA
311,000
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
Pounds/Year
TWPE/Year
Total Industry Pollutant Removals b
Pounds/Year
TWPE/Year
Fly Ash
All Regulatory
Options
370,000
631
97,100,000
185,000
Bottom Ash
A,B
C
D,E
240,000,000
65,800,000
861,000
345,000
93,900
896
NA
174,000,000
239,000,000
NA
251,000
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.
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                                                     Section 10—Pollutant Loadings and Removals
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. 13° 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.


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                                                        Section 10—Pollutant Loadings and Removals
   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
Baseline
Chemical Precipitation
Number of
Plants
95 a
95 a
Total Industry
Discharge Flow
(MGD)
9.09
9.09
Total Industry Loading
Pounds/Year
85,400,000
72,900,000
TWPE/Year
70,300
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
Baseline
Chemical Precipitation
Number of
Plants
70
70
Total Industry
Discharge Flow
(MGD)
7.90
7.90
Total Industry Loading
Pounds/Year
74,100,000
63,200,000
TWPE/Year
61,000
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
Reduction (Baseline ->Chemical Precipitation)
Total Industry Pollutant Removals
Pounds/Year
12,500,000
TWPE/Year
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.
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                                                     Section 10—Pollutant Loadings and Removals
   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
Reduction (Baseline ->Chemical Precipitation)
Total Industry Pollutant Removals
Pounds/Year
10,900,000
TWPE/Year
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].
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                                                            Section 10—Pollutant Loadings and Removals
      Table 10-22. Estimated Pollutant Loadings and Removals by Regulatory Option
Regulatory
Option a
Baseline
A
B
C
D
E
Total Industry Loading
Pounds/Year
2,210,000,000
2,060,000,000
2,050,000,000
1,830,000,000
1,700,000,000
1,680,000,000
TWPE/Year
2,680,000
1,650,000
1,510,000
1,200,000
1,000,000
967,000
Total Industry Pollutant Removals b
Pounds/Year
-
150,000,000
161,000,000
376,000,000
513,000,000
526,000,000
TWPE/Year
-
1,030,000
1,170,000
1,480,000
1,680,000
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
Baseline
A
B
C
D
E
Total Industry Loading
Pounds/Year
1,700,000,000
1,580,000,000
1,570,000,000
1,390,000,000
1,330,000,000
1,320,000,000
TWPE/Year
2,140,000
1,250,000
1,130,000
878,000
785,000
755,000
Total Industry Pollutant Removals b
Pounds/Year
-
124,000,000
132,000,000
306,000,000
371,000,000
382,000,000
TWPE/Year
-
891,000
1,010,000
1,260,000
1,350,000
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.
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                                                      Section 10—Pollutant Loadings and Removals
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 non-
detects 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