United States Office of Water Environmental Protection Washington, DC 20460 September 2015 Agency



# Incremental Costs and

Pollutant Removals for the

Final Effluent Limitations

Guidelines and Standards

for the Steam Electric Power Generating Point Source CategoryTable of Contents

i Table of Contents

Page

1. I NTRODUCTION

.................................................. ................................................... ........ 1-1

2. S TRUCTURE OF C OSTS AND P OLLUTANT L OADINGS M ODELS ......................................... 2-1

2.1 Cost Model .........................................

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

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

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

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

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

2.2 Pollutant Loadings Model ..............................

.................................................. 2-3

2.3 References ........................................

................................................... ............ 2-4

3. D ATA S OURCES

.................................................. ................................................... ....... 3-1

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

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

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

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

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

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

3.2 Technology Vendor Data ..............................

................................................... 3-3

3.3 Field Sampling Program................................

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

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

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

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

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

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

3.6 NPDES Permit Data .................................

................................................... ..... 3-9

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

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

3.9 References ........................................

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

4. D EVELOPMENT OF M ODEL I NPUTS

.................................................. .............................. 4-1

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

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

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

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

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

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

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

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

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

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

4.1.3.2 Impoundment Combustion Residual Leachate Discharge

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

Table of Contents (Continued)

Page

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

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

4.2.2 Fly Ash.............................................

.................................................. 4-15

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

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

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

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

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

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

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

4.4 Pollutant Concentrations ............................

................................................... . 4-28

4.5 Plant Characteristics .............................

................................................... ....... 4-28

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

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

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

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

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

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

4.7 References ........................................

................................................... .......... 4-32

5. G ENERAL M ETHODOLOGY

, T ERMINOLOGY

, AND C OMMON C OST E LEMENTS .................. 5-1

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

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

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

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

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

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

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

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

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

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

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

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

5.3.2 Cost Inputs .........................................

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

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

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

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

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

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

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

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

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

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

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

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

Table of Contents (Continued)

Page

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

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

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

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

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

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

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

5.6 References ........................................

................................................... .......... 5-25

6. FGD W ASTEWATER C OST M ETHODOLOGY

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

6.1 Chemical Precipitation ..............................

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

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

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

6.1.3 Credit for Chemical Precipitation Treatment in Plac e............................ 6-3

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

6.1.5 Key Variables Used in the Capital and O&M Cost Methodologies ....................................... ............................................... 6-7

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

6.2 Biological Treatment ..............................

................................................... ..... 6-97

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

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

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

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

Table of Contents (Continued)

Page

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

6.2.5.1 Purchased Equipment Costs: Biological Treatment System Cost ....................................... ................................. 6-102

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

6.2.5.3 Purchased Equipment Costs: Backwash Recycle Pumps

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

6.3 Evaporation .........................................

................................................... ...... 6-132

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

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

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

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

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

6.3.5.1 Purchased Equipment Costs: Brine Concentrator and Crystallizer Cost ................................. ................................ 6-135

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

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

6.3.5.4 Purchased Equipment Costs: Chemical Feed System

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

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

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

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

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

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

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

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

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

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

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

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

Table of Contents (Continued)

Page

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

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

6.4.1 Biological Treatment Cost: Sodium Bisulfite O&M Cost Analysis .......................................... ................................................. 6- 151

6.4.2 Biological Treatment Cost: Denitrification Cost Anal ysis ................. 6-153

6.5 References ........................................

................................................... ........ 6-154

7. F LY A SH T RANSPORT WATER C OST M ETHODOLOGY

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

7.2 Vactor Truck Collection .............................

................................................... . 7-35

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

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

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

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

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

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

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

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

Table of Contents (Continued)

Page

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

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

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

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

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

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

7.3 References ........................................

................................................... .......... 7-41

8. B OTTOM A SH T RANSPORT WATER C OST M ETHODOLOGY .............................................. 8-1

8.1 Mechanical Drag System...............................

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

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

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

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

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

8.1.4.1 MDS Purchased Equipment Cost: Conveyance Equipment ........................................... .................................. 8-5

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

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

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

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

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

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

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

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

8.1.5.6 MDS Intermediate Storage O&M Costs: Maintenance

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

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

8.1.5.8 MDS Intermediate Storage O&M Costs: Maintenance

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

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

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

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

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

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

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

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

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

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

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

8.2.4.1 Remote MDS Purchased Equipment Cost: Conveyance Equipment ........................................... .................................8-23

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

8.2.4.3 Remote MDS Purchased Equipment Cost: Chemical Feed System ............................................ ......................................8-25

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

Table of Contents (Continued)

Page

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

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

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

8.2.5.1 Remote MDS Conveyance O&M Costs: Mechanical Drag System ........................................ .................................8-30

8.2.5.2 Remote MDS Conveyance O&M Costs: Chemical

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

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

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

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

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

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

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

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

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

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

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

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

8.7 Recurring Costs .....................................

................................................... ..... 8-38

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

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

8.10 References ........................................

................................................... .......... 8-43

9. C OMBUSTION R ESIDUAL L EACHATE C OST M ETHODOLOGY ........................................... 9-1

9.1 Technology Description ...............................

................................................... . 9-1

9.2 Population Costed ...................................

................................................... ...... 9-2

9.3 Input Table...........................................

................................................... ......... 9-2

9.4 Capital Cost Methodology ...........................

................................................... .. 9-3

9.5 O&M Cost Methodology ..............................

................................................... 9-3

9.6 Sludge Disposal Cost ..................................

................................................... .. 9-3

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

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

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

9.10 Results and Summary of Costs .......................

.................................................. 9-4

9.11 References ........................................

................................................... ............ 9-4

10. G ASIFICATION W ASTEWATER C OST M ETHODOLOGY

.................................................. . 10-1

10.1 Population Costed ...................................

................................................... .... 10-1

10.2 Cost Methodology ..................................

................................................... ..... 10-1

10.3 References ........................................

................................................... .......... 10-1

11. FGD W ASTEWATER P OLLUTANT L OADINGS

.................................................. ............. 11-1

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

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

Table of Contents (Continued)

Page

viii 11.1.1.1 Effluent Concentration using FGD Surface Impoundment

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

11.1.1.2 Effluent Characterization Using FGD Purge Wastewater

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

11.1.1.3 Effluent Characterization for Conventional and

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

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

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

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

11.1.5 Pollutant Concentration Basis for Loadings Calculation s .................. 11-12

11.1.5.1 Pollutant Concentrations for Surface Impoundment

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

11.1.5.2 Pollutant Concentrations for Chemical Precipitation

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

11.1.5.3 Pollutant Concentrations for Biological Treatment

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

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

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

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

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

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

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

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

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

11.5 References ........................................

................................................... ........ 11-23

12. A SH T RANSPORT W ATER P OLLUTANT L OADINGS

.................................................. ...... 12-1

12.1 Data Sources ......................................

................................................... ......... 12-2

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Table of Contents (Continued)

Page

ix 12.4 Sensitivity Analyses ...............................

................................................... ... 12-18

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

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

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

12.5 References ........................................

................................................... ........ 12-20

13. C OMBUSTION R ESIDUAL L EACHATE P OLLUTANT L OADINGS ........................................ 13-1

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

13.2 Wastewater Flow Rates .............................

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

13.3 Pollutant Loadings and Toxic-Weighted Pound Equivalent (TWP E)

Results ...........................................

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

13.4 References ........................................

................................................... .......... 13-5

14. G ASIFICATION P OLLUTANT L OADINGS

.................................................. ...................... 14-1

15. S UMMARY OF C OSTS AND P OLLUTANT R EMOVALS BY R EGULATORY O PTION .............. 15-1

16. C LEAN P OWER P LAN

.................................................. ................................................ 16-1

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

16.2 Summary of Costs and Pollutant Removals by Regulatory Option Accounting for the CPP...............................

................................................... 16-2

16.3 References ........................................

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

17. E VALUATION OF C OST AND P OLLUTANT R EMOVAL E STIMATES ................................... 17-1

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

17.2 Verifying Analytical Data against acceptance Specificatio ns .......................... 17-2

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

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

17.5 References ........................................

................................................... .......... 17-5

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

CCR and CPP Appendix B: Plant Specific Incremental Costs and Pollutan t Removal Data With and Without

Accounting for CCRList of Tables

x List of Tables

Page

Table 1-1. Technology Cost Modules Used to Estimate Complia nce Costs for All Regulatory Options ..............................

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

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

Table 2-2. Technology Cost Modules Used to Estimate Complia nce Costs by Regulatory Option ..............................................

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

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

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

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

Table 4-2. Number of Steam Electric Plants and Generatin g Units Expected to Incur Compliance Costs by Wastestream and Regulatory Option Accounting for CCR ........4-33

Table 4-3. Number of Steam Electric Plants and Generatin g Units Expected to Achieve Pollutant Removals by Wastestream and Regulatory Option Ac counting for CCR ......4-33

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

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

................................................... 5-25

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

................................................... 5-27

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

................................................... ....5-28

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

Table 5-5. O&M Costs of 7-Acre Landfill Expansion from CH 2MHILL ................................5-29

Table 5-6. Revised Modular Annual Revenue Requirements by Proc ess Area for Direct Ponding of Nonhardening Ash without Water Reuse .... ....................................5-29

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

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

................................................... .....5-30

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

................................................... ................. 6-156

Table 6-2. Expected Pretreated FGD Wastewater Characterist ics for Design of the Biological Treatment Stage .........................

................................................... ........... 6-156List of Tables

List of Tables (Continued)

Page

xi Table 11-1. Data Sets Used in Developing Effluent Characte rization Data for Surface Impoundments .................................

................................................... ......... 11-25

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

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

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

Table 11-5. Data Sets Used in Developing Effluent Characte rization Data for Chemical Precipitation...............................

................................................... ............ 11-31

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

Table 11-7. Data Sets Used in Developing Effluent Characte rization Data for Biological Treatment ..............................

................................................... ............... 11-33

Table 11-8. Average Effluent Concentration of Chemical Pr ecipitation System with Biological Treatment ..............................

................................................... ............... 11-34

Table 11-9. Data Sets Used in Developing Effluent Characte rization Data for Evaporation Treatment ..............................

................................................... ............ 11-34

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

Table 11-11. Pollutant Concentration Basis for Surface Impo undments ................................ 11-36

Table 11-12. Pollutant Concentration Basis for Chemical Pr ecipitation ................................ 11-37

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

Table 11-14. Pollutant Concentration Basis for Evaporation

................................................. 11-39

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

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

................................................... ............... 11-40

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

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

................................................... ............... 11-40

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

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

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

List of Tables (Continued)

Page

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

................................................... ...... 12-28

Table 12-6. Industry-Level Loadings and Pollutant Removals Excluding BOD, COD, TSS, and TDS and Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis ..........................

................................................... ......... 12-29

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

and TDS ............................................

................................................... .................... 12-30

Table 12-8. Sensitivity Analysis Results for Total Industry Loadings Based on Inclusion of Late Submission UWAG Data Excluding BOD, COD, TSS, an d TDS .................. 12-30

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

Table 13-2. Average Chemical Precipitation Effluent Conc entrations for Combustion

Residual Leachate ...................................

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

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

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

Table 13-4. Industry-Level Combustion Residual Leachate Loa dings Excluding BOD, COD, TDS, and TSS and Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis ..........................

................................................... ...........13-9

Table 13-5. Combustion Residual Landfill Leachate Loadings Removals Excluding BOD, COD, TDS, and TSS and Based on Oil-Fired Units and U nits 50 MW or Less Not Installing Technology Basis ..................

................................................... ....13-9

Table 15-1. Treatment Technologies Basis for Estimating C ompliance Costs and Pollutant Loadings by Regulatory Option ................... ................................................15-3

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

................................................... .........................15-4

Table 15-3. Estimated Pollutant Removals by Regulatory Opti on ...........................................15-4

Table 16-1. Number of Steam Electric Plants and Generatin g Units Expected to Incur Compliance Costs by Wastestream and Regulatory Option Accounting for CCR

and CPP.............................................

................................................... ......................16-4

Table 16-2. Number of Steam Electric Plants and Generatin g Units Expected to Achieve Pollutant Removals by Wastestream and Regulatory Option Ac counting for CCR

and CPP.............................................

................................................... ......................16-4List of Tables

List of Tables (Continued)

Page

xiii Table 16-3. Cost of Implementation by Regulatory Option A ccounting for CCR and CPP [In millions of pre-tax 2010 dollars] ...................

................................................... .....16-5

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

and CPP.............................................

................................................... ......................16-5

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

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

................................................... .....17-7

Table 17-3. Cost Estimate Quality Specifications ........

................................................... ........17-8List of Figures

xiv List of Figures

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

Residual Leachate ...................................

................................................... .................. 2-5

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

................................................... .................... 2-6

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

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

................................................... .... 6-157

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

Figure 6-3. Two-Stage Biological Treatment System (Syste m to follow Chemical Precipitation Pretreatment) .......................

................................................... ............. 6-159

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

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

Figure 6-6. Chemical Precipitation and Softening Pretreatme nt for FGD Wastewater Prior to Evaporation .......................................

................................................... ................ 6-162

Figure 6-7. Process Flow Diagram for an Evaporation Syste m (System to Follow Chemical Precipitation Pretreatment) ...............

................................................... ...... 6-163

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

................................................... ............8-45

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

................................................... .......8-45

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

................................................... .. 12-31Glossary

xv Glossary

Administrator

– The Administrator of the U.S. Environmental Protectio n Agency.

Agency – U.S. Environmental Protection Agency.

BAT – Best available technology economically achievable, as defined by Sections 301(b)(2)(A) and 304(b)(2)(B) of the CWA.

BCT – The best conventional pollutant control technology, applicable to discharges of conventional pollutants from existing industrial point sourc es, as defined by Sections 301(b)(2)(E) and 304(b)(4) of the CWA.

Bioaccumulation – General term describing a process by which chemicals ar e taken up by an organism either directly from exposure to a contaminated m edium or by consumption of food containing the chemical, resulting in a net accumulatio n 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 f urnace or is dislodged from

furnace walls. Economizer ash is included when it is col lected with bottom ash.

BPT –The best practicable control technology currently avai lable as defined by Sections 301(b)(1) and 304(b)(1) of the CWA.

CBI – Confidential Business Information.

CCR – Coal combustion residuals.

Clean Water Act (CWA) – The Federal Water Pollution Control Act Amendments of 1972 (33 U.S.C. 1251 et seq.), as amended e.g., by the Clean Water A ct 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 associa ted with combustion wastewater. In

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

associated with the combustion of other fossil fuels.

Combustion residual leachate – Leachate from landfills or surface impoundments conta ining combustion residuals. Leachate is composed of liquid, in cluding any suspended or dissolved constituents in the liquid, that has percolated through w aste 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 see page and/or leakage from a combustion residual landfill or impoundment unit. Combustion residual le achate includes wastewater from landfills and surface impoundments located on non-adjoinin g property when under the operational control of the permitted facility.Glossary

xvi Direct discharge – (a) Any addition of any “pollutant” or combination of poll utants to “waters of the United States from any “point source,” or (b) any addit ion of any pollutant or combination of pollutants to waters of the “contiguous zone” or the ocea n from any point source other than a vessel or other floating craft which is being used as a me ans of transportation. This definition includes additions of pollutants into waters of the United States from: surface runoff which is collected or channeled by man; discharges through pipes, sewe rs, or other conveyance owned by a State, municipality, or other person which do not lead t o a treatment works; and discharges through pipes, sewers, or other conveyances, leading into p rivately owned treatment works. This term does not include an addition of pollutants by any “indir ect discharger.”

Direct discharger

– A facility that discharges treated or untreated wastewat ers into waters of the

United States.

DOE – Department of Energy.

Dry bottom ash handling system – A system that does not use water as the transport me dium to convey bottom ash away from the boiler. It includes s ystems that collect and convey the ash without any use of water, as well as systems in which b ottom ash is quenched in a water bath and then mechanically or pneumatically conveyed away from t he boiler. Dry bottom ash handling systems do not include wet sluicing systems (such as remot e MDS or complete recycle systems).

Dry fly ash handling system – A system that does not use water as the transport m edium to convey fly ash away from particulate collection equi pment.

Effluent limitation – Under Clean Water Act (CWA) section 502(11), any restricti on, including schedules of compliance, established by a state or the A dministrator on quantities, rates, and concentrations of chemical, physical, biological, and oth er constituents which are discharged from point sources into navigable waters, the waters of the contiguous zone, or the ocean, including schedules of compliance.

EIA – Energy Information Administration.

ELGs – Effluent limitations guidelines and standards.

EO – Executive Order.

EPA – U.S. Environmental Protection Agency.

ESP – Electrostatic precipitator.

Facility – Any NPDES “point source” or any other facility or acti vity (including land or appurtenances thereto) that is subject to regulation under t he NPDES program.

FGD – Flue gas desulfurization.

FGD wastewater

– Wastewater generated from the wet FGD scrubber system that comes into contact with the flue gas or the FGD solids, including but not limited to, the blowdown or purge from the FGD scrubber system, overflow or underflow fr om the solids separation process, FGDGlossary

xvii solids wash water, and the filtrate from the solids d ewatering process. Wastewater generated from cleaning the FGD scrubber, cleaning the FGD solids sep aration equipment, cleaning the FGD solids dewatering equipment, or that is collected in floor drains in the FGD process area is

not considered FGD wastewater.

FGD gypsum – Gypsum generated specifically from the wet FGD scrubber system, including any solids separation or solids dewatering processes.

FGMC – Flue gas mercury control.

FGMC system – An air pollution control system installed or operated for the purpose of removing mercury from flue gas.

FGMC wastewater

– Wastewater generated from an air pollution control sy stem installed or operated for the purpose of removing mercury from flue gas. T his includes wastewater associated with fly ash collection systems when the p articulate control system follows the sorbent injection or other controls to remove mercury f rom flue gas. FGD wastewater generated at plants using oxidizing agents to remove mercury in the FG D 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 s tream and collected by a capture device such as a mechanical precipitator, electrostatic precipitator, and/or fabric filters.

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

included in this definition when it is collected in wet sc rubber air pollution control systems whose primary purpose is particulate removal.

Gasification wastewater

– Wastewater generated at an integrated gasification co mbined cycle operation from the gasifier or the syngas cleaning, combu stion, and cooling processes. Gasification wastewater includes, but is not limited to the following: sour/grey water; CO 2 /steam stripper wastewater; sulfur recovery unit blowdown, and wa stewater resulting from slag handling or fly ash handling, particulate removal, halogen removal , or trace organic removal. Air separation unit blowdown, noncontact cooling water, and runo ff 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, sp ills, and cleaning occurring during normal operation of the gasification operation is not consider ed gasification wastewater.

Ground water

– Water that is found in the saturated part of the ground un derneath 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 so lid waste, sludges, or other process residuals are placed in or on any natural or manmade format ion in the earth for disposal and which is not a storage pile, a land treatment facility, a surface impoundment, an undergroundGlossary

xviii injection well, a salt dome or salt bed formation, an underground mine, a cave, or a corrective action management unit.

Low volume waste sources – Taken collectively as if from on source, wastewater from all sources except those for which specific limitations are otherwise established, including but not limited to the following: wastewaters from ion exchan ge water treatment systems, water treatment evaporator blowdown, laboratory and sampling st reams, boiler blowdown, floor drains, cooling tower basin cleaning wastes, recirculating house se rvice water systems, and wet scrubber air pollution control systems whose primary purpose is par ticulate 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 fr om the bottom of the boiler in a water-filled trough. A drag chain oper ates in a continuous loop to drag bottom ash from the water trough up an incline, which dewaters th e 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 b unker outside the boiler building, from which it is loaded onto trucks and either sold or transport ed to a landfill. The MDS is considered a dry bottom ash handling system because the ash trans port mechanism is the mechanical removal by the drag chain, not the water.

Metal cleaning wastes – Any wastewater resulting from cleaning [with or without chemical cleaning compounds] any metal process equipment including, but no t 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 seco ndary 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, inc luding but not limited to, any pipe, ditch, channel, tunnel, conduit, well, discret e fissure, container, rolling stock, concentrationed animal feed operation, or vessel or other floating craft from which pollutants are or may be discharged. The term does not include agricultura l stormwater discharges or return flows from irrigated agriculture. See CWA section 502(14), 33 U.S.C. 1362(14); 40 CFR 122.2.Glossary

xix POTW – Publicly owned treatment works. See CWA Section 212, 33 U.S.C 1292; 40 CFR 122.2, 403.3.

Primary particulate collection system – The first place in the process where fly ash is col lected, such as collection at an ESP or baghouse. For example, a coal combustion particulate collection system may include multiple steps including a primary partic ulate collection step such as ESP followed by other processes such as a fabric filter whic h would constitute a secondary particulate collection system.

PSES – Pretreatment Standards for Existing Sources.

PSNS – Pretreatment Standards for New Sources.

Publicly Owned Treatment Works – Any device or system, owned by a state or municipality, used in the treatment (including recycling and reclamation) of municipal sewage or commercial or industrial wastes of a liquid nature that is owned by a state or municipality. This includes sewers, pipes, or other conveyances only if they convey w astewater to a POTW providing treatment. See CWA section 212, 33 U.S.C. 1292; 40 CFR 122.2.

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

Remote MDS

– Bottom ash handling system that collects bottom ash at the bottom of the boiler, then uses transport water to sluice the ash to a remote MDS that dewaters bottom ash using a similar configuration as the MDS. The remote MDS is co nsidered a wet bottom ash handling system because the ash transport mechanism is water.

RFA – Regulatory Flexibility Act.

SBA – Small Business Administration.

Sediment – Particulate material lying below water.

Surface water

– as All waters of the United States, including rivers, s treams, lakes, reservoirs,

and seas.

Steam electric power plant wastewater - Wastewaters associated with or resulting from the combustion process, including ash transport water from c oal-, 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 i mpoundments containing combustion

residuals.

Toxic pollutants – As identified under the CWA, 65 pollutants and classes of pollutants, of which 126 specific substances have been designated priority toxic pollutants. See Appendix A to 40

CFR 423.

Transport water

–Wastewater that is used to convey fly ash, bottom ash , or economizer ash from the ash collection or storage equipment, or boiler, and has direct contact with the ash. Transport water does not include low volume, short duration disch arges of wastewater from minor leaksGlossary

xx (e.g., leaks from valve packing, pipe flanges, or piping) or minor maintenance events (e.g., replacement of valves or pipe sections).

UMRA – Unfunded Mandates Reform Act.

Wet bottom ash handling system – A system in which bottom ash is conveyed away from t he boiler using water as the transport medium. Wet bottom ash systems typically send the ash slurry to dewatering bins or a surface impoundment. Wet bottom ash handling systems include systems that operate in conjunction with a traditional wet slui cing system to recycle all bottom ash transport water (remote MDS or complete recycle syste m).

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 tha t generates a water stream that exits the

FGD scrubber absorber.

Wet fly ash handling system – A system that conveys fly ash away from particulat e removal equipment using water as the transport medium. Wet fly ash systems typically dispose of the ash slurry in a surface impoundment.Section 1 – Introduction

1-1 

## 1. INTRODUCTION

This report describes the methodologies used to estimate plant-specific compliance costs (in 2010 dollars) associated with installing and operating the various technologies and practices that make up the regulatory options considered by EPA to revi se the existing ELGs. In addition, this report presents the methodologies used to estimate baseline and post-compliance pollutant loadings and the corresponding pollutant removals associa ted with installing and operating these technologies and practices.

In addition to this report and the Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Gene rating Point Source Category (DCN SE05904), EPA has assembled a supplementary document tit led “Supplemental Costs and Loadings Documentation” (DCN SE05839). This document , which can be found in the Steam Electric Rulemaking Record, includes the follo wing detailed information:

• Spreadsheets documenting development of input tables, cost factors, chemical dosage rates, and other cost elements.

• Detailed cost information provided by vendors (including emails and/or telephone contact reports).

• Equipment specifications provided by vendors.

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

cost curves.

Table 1-1 summarizes the regulatory options EPA analyze d for the final rule. These options vary in the stringency of control and affect t he following wastestreams:

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

• Fly ash transport water.

• Bottom ash transport water.

• Leachate from landfills and surface impoundments contai ning combustion

residuals.

• Flue gas mercury control wastewater.

• Gasification wastewater generated from integrated-gasif ication combined cycle (IGCC) steam electric power plants.

Table 1-1 also identifies the specific technology cost el ements used to estimate compliance costs for each regulatory option and ident ifies the specific section of this report

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

1-2 Table 1-1. Technology Cost Modules Used to Estimate Compliance C osts for All Regulatory Options

Wastestream Technology Option Regulatory Option Report

Section b A B C D E F a

FGD Wastewater Chemical Precipitation X X X X X X 6,11

Biological Treatment X X X X

Evaporation X

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

Bottom Ash Transport Water Dry Bottom Ash Handling/Closed-Loop X c X X X 8,12

Combustion Residual Leachate Chemical Precipitation X X 9,13

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

Flue Gas Mercury Control

Wastes Dry Handling X X X X X X NA

Other Plant

- Level Costs

Solids Transportation X X X X X X 5

Solids Disposal X X X X X X 5

Impoundments X X X X X X 5

Compliance Monitoring X X X X X X 5

NA – Not applicable. EPA determined that, based on current practices, there would be no incremental compliance costs or pollutant loadings for these wastestreams; see Se ction 9.2 of the Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (DCN SE05904). a – During development of the final rule, EPA decided not to base the final rule on Option F for existing sources due primarily to the high cost of that option, particularly i n light of the costs associated with other rulemakings expe cted to impact the steam electric power generating industry ( see Section VIII.C.1 of the preamble). As a result, EPA chose not to conduct particular analyses for Option F to the same extent that it did for some of the other opti ons considered.

b – Sections 5 through 10 of this document include more detaile d descriptions of the cost methodologies for these technology options and Sections 11 through 14 provide more detailed descriptions of the estimated pollutant removals for each technology.

c – Dry bottom ash handling or closed-loop required only for generating units with a capacity greater than or equal to 400 MW. Effluent requirements for bottom ash transport w ater from all other generating units would be set equal to existing BPT limitations for TSS; thus, generating uni ts smaller than 400 MW would not install dry bottom ash handling to comply with the ELGs.

In the remainder of this document, EPA presents the anal ytical results only for Options A through E for existing sources. During development of the f inal rule, EPA decided not to base the final rule on Option F for existing sources due primari ly to the high cost of that option, particularly in light of the costs associated with oth er rulemakings expected to impact the steam electric power generating industry (see Section VIII.C. I of the preamble). As a result, EPA chose not to conduct particular analyses for Option F to the same extent that it did for some of the other options considered.

For each of the regulatory options, EPA estimated plant- specific compliance costs for each of the individual treatment technologies that com prise the regulatory options using the methodologies described in this report. These technology- specific costs, broken down intoSection 1 – Introduction

1-3 capital and operation and maintenance (O&M) (i.e., annual , 3-year, 5-year, 6-year, and 10-year) costs, were then summed, as appropriate, to estimate pl ant-specific costs for each regulatory option. All costs were calculated in 2010 dollars. Note th at the compliance costs calculated for this rulemaking are incremental, meaning they represent t he costs expected to be incurred by plants to revise existing operations to match those that form the bases of the regulatory options.

EPA also estimated plant-specific baseline and post-comp liance pollutant loadings

associated with each of the individual treatment techno logies that comprise the regulatory options, and then summed them, as appropriate, to calcula te industry-level baseline and postcompliance pollutant loadings for each regulatory optio n. EPA then estimated the pollutant removals associated with the regulatory options by subtrac ting the post-compliance pollutant loadings from the baseline pollutant loadings. Note that t hese pollutant removal estimates are incremental, meaning they represent the pollutant removal s expected to be achieved as a result of plants revising existing operations to match those that for m the bases of the regulatory options.

EPA estimated compliance costs and pollutant loadings se veral different ways to evaluate the effect of the final ELG on the steam electric powe r generating industry. EPA considered other rulemakings affecting the steam electric power gener ating industry in its analysis. Under one approach, EPA evaluated compliance costs and pollutan t loadings taking into account changes that plants may make to implement the coal com bustion residuals (CCR) rule (but not the Clean Power Plan (CPP)). The regulatory option co mpliance costs and pollutant loadings that

take into account the CCR rule can be found in Section 15 . Under a second approach, EPA evaluated compliance costs and pollutant loadings taking i nto account changes that plants may make to implement both the CCR rule and the CPP. 1 The regulatory option compliance costs and pollutant loadings that take into account both the CCR a nd CPP can be found in Section 16. Under a third approach, EPA evaluated what the ELG costs and pollutant loadings would be if there were no changes to plant operations due to the CCR rule or CPP (in other words, what these costs and loadings would be if the CCR rule and CP P had not been promulgated). The plant-level estimated compliance costs and pollutant lo adings for this “without CCR and CPP” scenario can be found in Appendix B. In general, values repor ted and discussed in this report refer to the compliance costs and pollutant loadings an alysis with CCR only, unless otherwise

noted.

The following information is described in this report:

• Section 2 describes the structure of the costs and loadi ngs models.

• Section 3 discusses the data sources used to generate the costs, loadings, and pollutant removal estimates.

• Section 4 discusses the costs and loadings models inputs

.

• Section 5 describes the general cost methodology used to e stimate compliance

costs and common cost elements.

1 At the time EPA conducted these analyses, the CPP had not yet been finalized, and thus EPA used the proposed CPP for its analyses.Section 1 – Introduction

1-4 • Section 6 describes the cost methodology for treating F GD wastewater.

• Section 7 describes the cost methodology for eliminati ng the discharge of fly ash
transport water.

• Section 8 describes the cost methodology for eliminati ng the discharge of bottom ash transport water.

• Section 9 describes the cost methodology for treating c ombustion residual

leachate.

• Section 10 describes the cost methodology for treating ga sification wastewater.

• Section 11 describes the methodology used to estimate poll utant loadings and

removals for FGD wastewater.

• Section 12 describes the methodology used to estimate poll utant loadings and removals for both fly ash and bottom ash transport wat er.

• Section 13 describes the methodology used to estimate poll utant loadings and

removals for combustion residual leachate.

• Section 14 describes the methodology used to estimate poll utant loadings and removals for gasification wastewater.

• Section 15 summarizes costs and pollutant loadings and re movals by regulatory option.

• Section 16 described the methodology used to evaluate changes to the steam electric power generating industry resulting from the Cle an Power Plan.

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

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

2-1 

## 2. STRUCTURE OF COSTS AND POLLUTANT LOADINGS

MODELS

EPA created two separate models associated with the regul atory options for the revisions to the steam electric effluent limitations guidelines an d standards (ELGs). The first model calculates plant-specific compliance costs for each t echnology option associated with the regulatory options. The second model calculates plant-spe cific baseline pollutant discharge loadings for each wastestream evaluated, as well as post -compliance pollutant loadings and removals for each technology option for each wastest ream. This section describes the structure of each of these models. All tables and figures referenced i n this section are presented at the end of

the section.

2.1 C OST M ODEL

To generate industry incremental compliance cost estimat es for the steam electric power generating industry, EPA developed a computer-based cost model made up of several individual technology cost modules. The cost model is executed on a personal computer and comprises a collection of programs written in Visual Basic® and data t ables created in Microsoft Access® 2007. Figure 2-1 and Figure 2-2, present flow diagrams of the cos t model. The cost model can be grouped into four main components:

• Plant-Specific Input Data.

• Industry Assumptions/Factors.

• Technology Cost Modules.

• Model Outputs.

Technology cost modules use the relevant input data and in dustry assumptions/factors to calculate plant-specific incremental compliance costs. Each technology cost module calculates costs for a specific cost component (e.g., transportat ion, disposal, ash silo cost, chemical precipitation system cost, etc.) for each plant. The se individual cost components are then summed on a plant level to calculate an overall comp liance cost for each plant for a specific technology option. Table 2-1 lists the technology cost m odules and their use in calculating overall incremental compliance costs for each techno logy option. Table 2-2 shows how the individual technology cost modules are combined for each of the regulatory options considered by EPA. 2

2.1.1 Input Data to Cost Model

The cost model operates on one main input table, called th e cost matrix. The cost matrix identifies which technology options apply to each plant. For example, if Plant X discharges fly ash transport water and untreated flue gas desulfurization (FGD) wastewater, but does not discharge bottom ash transport or combustion residual lea chate, then the cost matrix would

2 The plant-level gasification costs are not calculated in the cost model, but rather, are calculated separate ly. Section 10 describes the plant-level gasification costs and the r esults are presented in Appendix A and B to this report.Section 2 – Structure of Costs and Pollutant Loadings Models

2-2 indicate that this plant requires fly ash and FGD complia nce costs, but does not require bottom ash or combustion residual leachate compliance costs.

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

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

• Fly Ash Data – amount of fly ash generated, amount of tr ansport water generated, number of operating days, type (e.g., baseload, peaking), an d capacity on a steam electric generating unit level.

• Bottom Ash Data – amount of wet bottom ash generated, amoun t of transport water generated, number of operating days, type (e.g., ba seload, peaking), and capacity on a steam electric generating unit level.

• Landfill Data – plant-level indication that an on-site combustion residual landfill is present and whether combustion residual leachate is co llected and discharged.

• Surface Impoundment Data – plant-level indication that a combustion residual impoundment is present and whether combustion residual le achate is collected

and/or treated.

• Treatment-in-Place Data – plant-specific data for plant s already operating relevant treatment systems, such as chemical precipitation, bio logical treatment, and evaporation, including the type of equipment at the plant and its capacity.

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

2.1.2 Industry Assumptions/Factors

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

tables hold the constants and coefficients that the te chnology cost modules use to calculate capital and operation and maintenance (O&M) costs assoc iated with each cost component. In addition, the following industry assumptions/factors data s ets are used by multiple technology

cost modules:

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

dollars.

• Freight Costs – equipment-level shipping costs.

The industry assumptions/factors used by the technology cos t modules are identified within the capital and O&M cost equations in each technolo gy cost module, as described in

Section 5.

2.1.3 Technology Cost Modules

EPA developed the technology cost modules to calculate spe cific cost components, as

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

2-3 • Biological Treatment – calculates capital and O&M cos ts associated with an anoxic/anaerobic biological treatment system.

• Chemical Precipitation – calculates capital, O&M, and recurring costs associated with the chemical precipitation system.

• Evaporation – calculates capital and O&M costs associa ted with the evaporation
system.

• Dry Fly Ash Handling – calculates capital, O&M, and rec urring costs associated with the dry fly ash handling system.

• Dry Bottom Ash Handling – calculates capital, O&M, one- time, and recurring costs associated with the dry and closed-loop recycle bot tom ash handling system.

• Transportation – calculates O&M costs associated with transporting FGD solids, ash, and/or combustion residual landfill leachate solid s to an on-site or off-site

landfill.

• Disposal – calculates capital and O&M costs associated with disposing of FGD, ash, and/or combustion residual landfill leachate solid waste in an on- or off-site

landfill.

• Impoundment Operation – calculates O&M and recurring cost savings associated with no longer operating and maintaining an on-site impound ment.

For each regulatory option, the cost model combines the plant-level outputs from a series of technology cost modules. Table 2-1 shows the various t echnology cost modules that are combined to calculate the technology option costs. The cost model uses Microsoft Access 2007 queries to combine the cost components and calculate a tota l capital and O&M cost for each technology option. Table 2-2 lists the technology cost modules used to calculate the postcompliance cost for each regulatory option.

2.1.4 Model Outputs

The cost model output is a plant-level summary of the incremental technology option compliance costs. Each plant incurring a cost for a s pecified technology is presented in the model output. The incremental compliance costs are presented on two levels: 1) total plant-level cost; and 2) component-level cost. The total plant-level cost includes total capital and total O&M costs incurred by the plant for the technology option. The com ponent-level costs provide more detail showing a breakdown of the individual cost components for each of the technology cost modules. The component-level costs include individual capi tal costs (e.g., equipment, installation, and engineering) and individual O&M costs (e.g., labor, materials, compliance monitoring, and chemicals). Plant-level cost model resu lts are provided by technology option in Appendices A and B (see Sections 6, 7, 8, 9 and 10 for more de tails) and by regulatory option in

Section 15.

2.2 P OLLUTANT L OADINGS M ODEL

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

three databases in Microsoft Access 2007 to calculate bas eline and post-compliance pollutantSection 2 – Structure of Costs and Pollutant Loadings Models

2-4 loadings associated with the discharge of FGD wastewater , fly and bottom ash transport water, and combustion residual leachate, respectively. 3 Each of the three databases contains the following components:

• Input table.

• Baseline concentration data sets.

• Technology option concentration data sets (where appli cable).

• Output baseline and post-compliance pollutant loadings.

All three of the loadings databases were constructed i n a similar fashion. The input tables hold plant-level data needed to calculate the baseline and post-compliance discharge loadings. The input tables for FGD, ash (includes both fly ash and bottom ash), and combustion residual leachate are discussed in more detail in Sections 4.1.1, 4.1 .2, and 4.1.3, respectively. The baseline and technology option concentration data sets consist of analytical data used to calculate the average pollutant concentrations for each wastewat er evaluated with and without the control afforded by the technology options. Because the dry fly as h handling technology option and the dry/closed-loop recycle bottom ash handling technology opti ons result in zero discharge of fly ash and bottom ash transport water, the average technol ogy option pollutant concentrations for fly and bottom ash are zero. The average baseline and te chnology option (i.e., post-compliance) pollutant concentrations, together with data from the input table, are used to calculate baseline and post-compliance pollutant loadings at a plant level. EPA calculates the baseline and postcompliance pollutant loadings in both pounds and toxic-wei ghted pound equivalents (TWPE). 4
See Sections 11 through 14 for more detail on the loadings calculation methodology and results for each technology option.

2.3 R EFERENCES

1. U.S. EPA. 2015. U.S. Environmental Protection Agency. Technical Development Document for the Final Effluent Limtations Guidelines and Standards for the St eam Electric Power Generating Point Source Category . (30 September). DCN SE05904.

3 EPA determined that, based on current practices, there would be no incremental pollutant removals for flue gas mercury control or gasification wastewater. See Sec tion 10 of the Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Powe r Generating Point Source Category [U.S. EPA, 2015].

4 EPA uses toxic weighting factors (TWFs) to account for differences in toxicity across pol lutants. EPA calculated a TWPE value for each pollutant discharged to compare mass loa dings of different pollutants based on their toxicity.Section2– Structure of Costs and Pollutant Loadings Models2-5Figure 2-1. Steam Electric Cost Model Flow Chart for FGD Wastewater and Combustion Residual LeachateSection2– Structure of Costs and Pollutant Loadings Models2-6Figure 2-2. Steam Electric Cost Model Flow Chart for Fly Ashand Bottom Ash Transport WaterSection2– Structure of Costs and Pollutant Loadings Models2-7Table 2-1. Technology Cost Modules Used to Estimate Compliance CostsTechnology OptionTechnology Cost Module

Chemical Precipitation Biological Treatment Evaporation Dry Fly Ash Handling Dry Bottom Ash Handling

a Compliance Monitoring Transportation Disposal Surface Impoundment Operation CostsFGD Wastewater Treatment: Chemical PrecipitationFGD Wastewater Treatment: Chemical Precipitation+ BiologicalTreatmentFGD Wastewater Treatment: Chemical Precipitation + EvaporationFly Ash: Zero dischargeBottom Ash: Zero dischargeCombustion ResidualLeachate Wastewater Treatment:ChemicalPrecipitationGasification WastewaterbNote: EPA did not estimate costs for flue gas mercurycontrol wastewater.a – The technology cost module is called “Dry Bottom AshHandling” module, but it includes a technology option that isa closed-loop recycle system.b– The plant-level gasification costs are not calculatedin the cost model, but rather, are calculated separately. The plant-level gasification costs are described inSection 10 and the results are presented in Appendices Aand B to this report.Section2– Structure of Costs and Pollutant Loadings Models2-8Table 2-2. Technology Cost Modules Used to Estimate Compliance Costs by Regulatory OptionWastestreamTechnology CostModules/Technology OptionRegulatory OptionABCDEFaFGD WastewaterChemical PrecipitationBiological TreatmentEvaporationFly Ash Transport Water Dry Fly Ash HandlingBottom Ash Transport Water Dry Bottom Ash HandlingbcCombustion Residual Leachate Chemical PrecipitationGasification Wastewater EvaporationFlue Gas Mercury Control WastesdZero DischargeOther Costs Not Specific to WastestreamSolids TransportationSolids DisposalImpoundmentsCompliance Monitoringa – During development of the final rule, EPA decided not tobase the final rule on Option F for existing sources dueprimarily to the high cost of that option,particularly in light of the costs associated with otherrulemakings expected to impact the steam electric power generating industry (see Section VIII.C.1 ofthe preamble). As a result, EPA chose not to conduct particular analyses for Option F to the same extent thatit did for some of the other options considered.b – The technology cost module is called the “Dry BottomAsh Handling” module, but it includes a technology optionthat is a closed-loop recycle system.c – Dry bottom ash handling or closed-loop system is required only for generating units with a capacity greater thanor equal to 400 MW. Effluentrequirements for bottom ash transport water from all other generating units would be set equal to existing Best Practicable Control Technology CurrentlyAvailable (BPT) limitations for total suspended solids (TSS); thus generating units smaller than 400 MW would not install dry bottom ash handling tocomply with the ELGs.d – EPA determined that, based on current practices, there would be no incremental compliance costs for flue gasmercury control wastewater; therefore,EPA did not create technology cost modules for this wastestream. However, this wastestream is still consideredin the regulatory options and is thereforepresented in the table with the appropriate technology option.Section 3 – Data Sources

3-1 

## 3. DATA SOURCES

EPA collected and evaluated data from a variety of source s in the course of developing the revisions to the effluent limitations guidelines and standards (ELGs) for the Steam Electric Power Generating Point Source Category (Steam Electri c Category). EPA used these data to develop the industry profile, determine the plant populatio n that will be affected by the rule, evaluate industry subcategorization, identify plant-speci fic operations, and determine wastewater characteristics, technology options, compliance cost s, baseline and pollutant loadings, postcompliance pollutant removals, and non-water quality envir onmental impacts. This section

discusses these data sources used to revise the Steam Elec tric ELGs. Each section presents a data

source and then describes how EPA used data from that source in its compliance cost and pollutant loadings calculations. All tables and figures re ferenced in this section are presented at

the end of the section.

3.1 S TEAM E LECTRIC T ECHNICAL Q UESTIONNAIRE D ATABASE

A principal source of information and data used in developing the ELGs are industry responses to the survey distributed by EPA under the author ity of Section 308 of the Clean Water Act (CWA), 33 U.S.C. 1318. EPA distributed the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey) to 733 power plants in the summer of 2010. EPA designed the industry survey to obtain technical infor mation related to wastewater generation and treatment, and economic information such as costs of wastewater treatment technologies and financial characteristics of potentiall y affected companies. The Steam Electric Survey obtained the following types of information from t he steam electric power generating industry:

• General power plant operations.

• Flue gas desulfurization (FGD) system operations.

• Ash handling operations.

• Pond/impoundment system and other wastewater treatment operations.

• Metal cleaning process operations.

• Pond/impoundment and landfill management practices.

• Pond/impoundment and landfill leachate sampling data.

• Nuclear power operations.

• Economic and financial data.

ERG used the responses from the 733 plants to develop a data base that contained all the responses to the Steam Electric Survey. For more inform ation on the development of the Steam Electric Survey, see Section 3 of the Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Gene rating Point Source Category [U.S. EPA, 2015b]. The remainder of this section describes t he data used in the calculation of compliance costs and pollutant loadings and removals estimates.Section 3 – Data Sources

3-2 3.1.1 Industry Factors

EPA developed specific industry factors to use in the cost equations detailed in Sections 5, 6, 7, 8, 9, and 10 based on evaluation and analysis of the Steam Electric Survey data. For example, many of the operation and maintenance (O&M) l abor rates and hours per year used in the cost model were derived from rates and burdens reported in responses to the Steam Electric Survey. EPA also developed many of the direct and indirec t capital cost factors used in the cost model from Steam Electric Survey data (e.g., installati on and engineering overhead cost factors). Other cost elements (e.g., equipment capacity factors, materials of construction, and chemical dosage rates and sludge generation rates for chemical preci pitation) were derived from Steam Electric Survey responses. The use of Steam Electric Surv ey data to derive industry assumptions/factors is described within the costing metho dology in Sections 5, 6, 7, 8, 9, and 10 and documented in the “Supplemental Costs and Loadings Doc umentation” [ERG, 2015].

3.1.2 Plant Characteristics

The cost methodology uses certain plant-specific Steam Electric Survey data elements as cost model inputs for estimating plant-level compliance costs and generating unit-level compliance costs. Some examples include plant-specific F GD wastewater flow rates, ash generation rates, generating unit nameplate capacity, type of generating unit, generating unit operating hours per day, and technologies currently in plac e. The specific plant characteristic(s) used to calculate compliance costs for each treatment technology are detailed in the input table sections of Sections 6, 7, 8, 9, and 10.

3.1.3 FGD Wastewater Loadings

EPA used responses to the Steam Electric Survey and industry -submitted data to identify the population of plants that operate wet FGD scrubbers and discharge the wastewater to surface water or a publicly owned treatment works (POTW). For this population of plants, EPA used Steam Electric Survey responses to identify the flow r ate of the FGD wastewater and calculate the amount of treated FGD wastewater that is recycled by the plant. EPA also used Steam Electric Survey data to estimate FGD wastewater pollutan t loadings as described further in

Sections 4.1.1 and 11.

3.1.4 Ash Transport Water Loadings

EPA used responses to the Steam Electric Survey and industry -submitted data to identify the population of plants that operate wet fly ash and/or wet bottom ash handling systems and discharge the ash transport water to surface water or a POTW. For this population of plants, EPA used Steam Electric Survey responses and industry-submitted data to identify the discharge flow rate of the fly ash transport water and bottom ash tr ansport water and determined whether the

waters are combined for treatment. EPA also used Steam E lectric Survey responses to calculate the amount of bottom ash transport water that is recy cled by the plant. Additionally, EPA used data from the Steam Electric Survey, industry-submitted da ta, and other data as described in Section 3 of the TDD, to characterize fly ash trans port water, bottom ash transport water, and combined ash transport water, and use that characterizati on to estimate pollutant loadings as

described further in Sections 4.1.2 and 12.Section 3 – Data Sources

3-3 3.1.5 Combustion Residual Leachate Loadings

EPA used responses to the Steam Electric Survey to identi fy the population of plants that collect and discharge combustion residual leachate from landfills and/or impoundments containing combustion residuals to surface water or a POTW . For this population of plants, EPA used Steam Electric Survey responses to identify the flo w rate of the combustion residual

leachate and calculate the amount of combustion residual leachate that is recycled by the plant. EPA also used Steam Electric Survey data to characteriz e the combustion residual leachate

wastestream as well as to estimate the combustion re sidual leachate pollutant loadings as

described further in Sections 4.1.3 and 13.

3.2 T ECHNOLOGY V ENDOR D ATA

EPA gathered data regarding the technologies used in the i ndustry from technology vendors through presentations, conferences, meetings, and e mail and telephone contacts. The data collected informed the development of the detailed st udy, the Steam Electric Survey, technology costs, and loadings estimates.

To gather information on FGD wastewater and combustion res idual leachate treatment for the cost analyses, EPA contacted companies that man ufacture, distribute, or install various components of chemical precipitation, biological, and/or evaporation wastewater treatment. The vendors provided the following types of information for EPA ’s analyses:

• Operating details.

• Performance data.

• Equipment used in the system.

• Capital cost information on a component level and syst em level.

• O&M costs.

• Equipment and system energy requirements.

To gather information on fly ash and bottom ash handling t echniques, EPA also contacted several ash handling and ash storage vendors. The vendors provided the following types of information for EPA’s analyses:

• The type of fly ash and bottom ash handling systems ava ilable for reducing or eliminating ash transport water.

• Equipment, modifications, and demolition required to conv ert wet-sluicing fly ash and bottom ash handling systems to dry ash handling or closed-loop recycle

systems. 5

• Equipment that can be reused as part of the conversion f rom wet to dry handling or in a closed-loop recycle system.

5 Throughout this report, EPA refers to bottom ash system s that eliminate the use of ash transport water as dry a sh handling systems; however, some of these systems (e.g., mechanical drag system) still use water in a quench bat h and, therefore, are not completely dry systems.Section 3 – Data Sources

3-4 • Outage time required to install or convert to the differ ent types of ash handling
systems.

• Maintenance required for each type of system.

• Operating data for each type of system.

• Purchased equipment and other direct and indirect capital costs for fly ash and

bottom ash conversions.

• Specifications for the types of ash storage available (e .g., steel silos or concrete silos) for the different types of handling systems.

• Equipment and installation capital costs associated with the storage of fly ash and

bottom ash.

• Additional equipment needed for redundancy.

• O&M costs for fly ash and bottom ash handling systems.

• System energy requirements.

3.3 F IELD S AMPLING P ROGRAM

EPA’s field sampling program consists of three distinct areas: EPA field sampling from the detailed study; EPA field sampling conducted as part of t he rulemaking; and plant-collected samples analyzed by EPA. Each of these sampling programs is further described in Sections 3.3.1, 3.3.2, and 3.3.3, respectively.

3.3.1 Detailed Study Sampling Data

As part of the detailed study undertaken prior to beginning the rulemaking process, EPA conducted a sampling program to characterize untreated wast ewaters generated by coal-fired power plants, as well as to evaluate treatment technolo gies and best management practices for reducing pollutant discharges. Between July 2007 and October 2008, EPA collected and analyzed samples to characterize wastewater streams a t six coal-fired power plants. EPA analyzed the samples for total metals (including 25 specifi c metals), hexavalent chromium, nitrogen compounds, and other classical analytes. Specific ally, EPA characterized wastewater streams associated with wet FGD systems and ash handl ing operations and evaluated the capability of various types of treatment systems to remo ve metals and other pollutants prior to discharge. Four of the plants sampled operated some type of wet ash handling system (either wet bottom ash handling, wet fly ash handling, or both). The effluent samples collected from the ash surface impoundments at these four plants were collected a s one-day grab samples and represented two fly ash surface impoundments, one bottom ash surface impoundment, and one surface impoundment that received both fly ash and bottom ash wastewater. EPA also collected samples from influent from the fly ash impoundment at o ne of the plants [U.S. EPA, 2009]. The surface impoundments at the four plants were categorized a s follows:

• Cardinal – Fly ash impoundment.

• Homer City – Bottom ash impoundment.

• Mitchell – Fly ash impoundment.Section 3 – Data Sources

3-5 • Widows Creek – Combined ash impoundment.

As described in Section 12.1, data from the detailed study wer e used to identify pollutants of concern in ash transport water and to characterize ash impoundment effluent.

3.3.2 EPA Field Sampling Data

EPA conducted an international sampling program at steam e lectric power plants to

collect wastewater data characterization and treatmen t performance data associated with FGD wastewater and other emerging wastestreams for which cha racterization data were not available (i.e., carbon capture and gasification wastewaters). A s part of this sampling program, EPA conducted on-site sampling activities (i.e., samples were collected directly by EPA), as well as requiring some plants to collect samples for EPA (i.e. , CWA 308 monitoring program).

EPA conducted on-site sampling activities at the following selected plants: 6

• Duke Energy’s Miami Fort Station, Ohio [ERG, 2012a].

• Duke Energy Carolina’s Belews Creek Steam Station, North Carolina [ERG, 2012b].

• We Energies’ Pleasant Prairie Power Plant, Wisconsin [ERG, 2012c].

• Duke Energy Carolina’s Allen Steam Station, North Carolina [ERG, 2012d].

• Mirant Mid-Alantic, LLC’s Dickerson Generating Station

, Maryland [ERG, 2012e].

• NRG Energy’s Keystone Generating Station, Pennsylvania [ERG, 2012f].

• FirstEnergy’s Hatfield’s Ferry Power Station, Pennsylvania [ERG, 2012g].

• Enel’s Federico II Power Plant (Brindisi), Italy [ERG, 2012h].

• A2A’s Centrale di Monfalcon (Monfalcone), Italy [ERG, 2013].

All of the selected plants operate chemical precipitati on wastewater treatment systems to
treat their FGD wastewater. Belews Creek Steam Stati on, Allen Steam Station, and Dickerson Generating Station also operate biological treatment s ystems to further treat the effluent from chemical precipitation treatment. EPA conducted a sampl ing episode at Enel’s Federico II Power Plant (Brindisi), located in Brindisi, Italy, which oper ates an evaporation system.

EPA requested the collection of one-day grab samples fro m a second plant in Italy, A2A’s Centrale di Monfalcone (Monfalcone). Monfalcone ope rates a chemical precipitation followed by evaporation system to treat FGD wastewater . Monfalcone personnel collected samples of the FGD influent to wastewater treatment, t he distillate from the brine concentrator, and the condensate from the crystallizer. Site visit n otes and the corresponding analytical results are included in the rulemaking record [ERG, 2013].

6 Each of the seven plants at which EPA conducted on-site sampling activities also participated in the CWA 308 monitoring program (Miami Fort Station, Hatfield’s Fer ry Station, Allen Steam Station, Belews Creek Steam Station, Dickerson Generating Station, Kystone Generat ing Station, and Pleasant Prairie Power Plant). These se ven plants collected a 24-hour composite sample one day a month for four consecutive months.Section 3 – Data Sources

3-6 3.3.3 CWA 308 Monitoring Data

EPA required a subset of steam electric power plants to co llect samples that were used to supplement the EPA on-site sampling program. Each of the plants selected for the on-site sampling program (except for Brindisi) were required to part icipate in the CWA 308 monitoring program so EPA could further evaluate the variability ass ociated with the FGD wastewater treatment systems’ performance.

For those seven plants, in addition to the samples c ollected by EPA during the four-day on-site sampling event, EPA required the plants to collec t 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) t o participate in its CWA 308 monitoring program. These plants were selected to obtain data about operations or treatment systems because EPA did not have existing data for these processes or treatment technologies. EPA obtained data from the following four plants:

1. Tampa Electric Company’s Polk Station (the first comme rcially operating integrated gasification combined cycle (IGCC) plant at th e time of EPA’s sampling program). 7

2. Wabash Valley Power Association’s Wabash River Statio n (the second commercially operating IGCC plant at the time of EPA’ s sampling program).

3. Appalachian Power Company’s Mountaineer Plant (the only pl ant operating a carbon capture system at the time of EPA’s sampling pro gram).

4. Kansas City Power and Light’s Iatan Station (the only U .S. plant operating an evaporation system for treatment of FGD wastewater a t the time of EPA’s sampling program).

EPA required these four plants to collect four consecutive days of samples at two to four locations specifically identified for each plant. The sample locations were identified to characterize gasification wastewaters, carbon capture wastewaters, and the treatment of FGD wastewater and gasification wastewater by evaporation s ystems. For more information on the field sampling program, see Section 3 of the Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Gene rating Point Source Category [U.S. EPA, 2015b]. For more information about the EPA CW A 308 Monitoring Program, see the memorandum, “Power Plant Monitoring D ata Collected under Clean Water Act Section 308 Authority” [ERG, 2012i].

3.4 I NDUSTRY

- AND S TATE -P ROVIDED D ATA

In addition to monitoring data submitted in the Steam Elec tric Survey and data collected during the EPA sampling program, EPA relied on industry-supplie d data and publicly available

7 Duke Energy’s Edwardsport Power Station and Southern Company ’s Kemper County IGCC Plant also operate an IGCC system; however, neither were in commercial oper ation at the time of EPA’s sampling program.Section 3 – Data Sources

3-7 data sources, including data received during public comment, to characterize pollutant discharge concentrations and evaluate treatment technologies. In some cases, EPA requested information from industry to fully evaluate the data provided or to suppor t additional analyses, including the evaluation of FGD wastewater treatment system perform ance and wastewater characterization of ash transport water and ash impoundment effluent. EPA co llected the following types of information from industry to characterize the evalua ted wastestreams and treatment system performance:

• FGD system information (e.g., identity of the organosul fide additives used in each chemical precipitation treatment system, conditions w ithin each FGD scrubber system during sampling period).

• Pollutant concentrations in FGD purge, FGD chemical precip itation effluent, and FGD biological treatment influent and effluent.

• Ash system information.

• Pollutant concentrations in ash impoundment influent and effluent.

• Pollutant concentrations in source water.

• Amount, source, sulfur content, chlorine content, and t ype of coal burned.

EPA coordinated with the state of North Carolina to obta in additional FGD wastewater characterization data for Progress Energy Carolinas’ Roxboro Steam Plant operating an FGD impoundment and biological treatment system. Additional ly, EPA requested additional monitoring data from plants operating FGD wastewater tre atment systems, specifically those operating FGD chemical precipitation or FGD biological t reatment systems. EPA’s data requests focused on information including coal data, FGD system opera tional information, FGD purge concentrations, and effluent concentrations for arsenic, mercury, selenium, and several other metals achieved by the chemical precipitation and/or the bi ological treatment portions of the FGD wastewater treatment systems over a 2-year period (i.e., January 2012-December 2013).

EPA received public comments on the proposed revisions to the Steam Electric ELGs from industry, in which Duke Energy and Hoosier Energy Rura l Electric Cooperative (Hoosier Energy) submitted data for samples of bottom ash and fl y ash transport water collected at some of their coal-fired steam electric power plants. In so me cases, these groups also provided source water data collected on the same day as the ash transpo rt water samples [Duke Energy, 2013; Hoosier Energy, 2013]. EPA requested and received additional sa mple collection and quality information from Duke Energy and Hoosier Energy and used this additional information to verify the quality of the samples and ensure that the da ta were appropriate for use in wastestream characterization. EPA also requested and received additio nal ash transport water characterization data collected at these or other plants since the public comment submission [Duke Energy, 2014; Hoosier Energy, 2014]. As described in Section 12.1, these da ta were used to identify pollutants of concern in ash transport water and to characterize ash impoundment effluent.

As part of its public comment submission, the Utility Wat er Act Group (UWAG), an industry trade association, provided bottom ash transport water data for 21 plants. In some cases, UWAG also provided source water data collected on the same sample day as the bottom ashSection 3 – Data Sources

3-8 transport water samples. UWAG also supplied a report prepa red by URS Corporation with sampling data for sulfides (as well as some other param eters) collected in 2013 at nine plants [UWAG, 2013]. EPA requested and received additional informati on on the identity of the sampled plants, the sample collection location and me thods used, the selection criteria used by UWAG when developing its data set, and additional informati on to verify the quality of the samples [UWAG, 2014a]. In November 2014, UWAG submitted additio nal sample

characterization data to EPA for consideration in the final steam electric effluent limitations guidelines. The database included bottom ash transport wate r characterization data collected from six steam electric power plants [UWAG, 2014a]. The use of ash transport water data submitted by UWAG in the pollutants of concern and pollutant loadings analyses is described in

Section 12.1.

The information EPA received from industry in public comme nts on the proposed rulemaking, as well as from EPA’s plant-specific data requests is summarized in Table 3-1.

3.5 E LECTRIC P OWER R ESEARCH I NSTITUTE R EPORTS

Electric Power Research Institute (EPRI) is a researc h-oriented trade association for the steam electric industry. EPRI conducts research funded by t he steam electric industry and has extensively studied wastewater discharges from FGD systems and ash impoundments. EPA received technical reports from the trade association an d as part of plant responses to the Steam Electric Survey.

The EPRI reports provided EPA with background information re garding the characteristics of FGD wastewaters and the sampling t echniques used during the program. These reports also provided EPA with information regarding the chara cteristics of discharges from fly ash and bottom ash impoundments and the respective percen tage of pollutant loadings from ash impoundments containing both fly ash and bottom ash trans port water. Additionally, the EPRI reports provided information on the treatment technologies available to treat FGD and ash wastewaters, including findings from pilot-study evaluations . Table 3-2 lists the reports provided to EPA by the trade association that summarize the data collected during several EPRI studies.

The trade association provided EPA with the PISCES Water Characterization Field Study, Sites A-G

reports that summarize the data collected during seven separ ate site visits to characterize wastewater at coal-fired power plants [EP RI, 1997-2001].

For the seven sites sampled, EPA reviewed the reports t o determine the characteristics of the ash impoundments (e.g., type of wastestreams enteri ng the impoundment, pollutant concentrations). The sites were identified as operating t he following type of ash impoundments:

• Site A – Combined ash impoundment.

• Site B – Combined ash impoundment.

• Site C – Combined ash impoundment.

• Site D – Combined ash impoundment.

• Site E – Combined ash impoundment.

• Site F – Bottom ash impoundment and combined ash impoundment.

• Site G – Combined ash impoundment.Section 3 – Data Sources

3-9 As part of its response to the Steam Electric Survey, one steam electric power plant submitted an EPRI study on wastewater discharges from FGD s ystems and ash impoundments at the plant. Mitigation of SCR-Ammonia Related Aqueous Effects in a Fly Ash Pond [EPRI, 2006] presents sampling data from a fly ash impoundment at Ameri can Electric Power’s (AEP) John E. Amos plant. The report was submitted as part of the John E. Amos plant’s response to the Steam Electric Survey. As described in Section 12.1, data from the se EPRI reports were used to identify pollutants of concern in ash transport water and to cha racterize ash impoundment effluent.

3.6 NPDES P ERMIT D ATA

During the detailed study, EPA coordinated efforts with UWAG to create a database of selected National Pollutant Discharge Elimination Syste m (NPDES) Form 2C data from UWAG’s member companies [UWAG, 2008]. The NPDES Form 2C (or an equivalent form used by a state permitting authority) is an application fo r a permit to discharge wastewater that must be completed by existing industrial plants (including ma nufacturing, commercial, mining, and silvicultural operations). This form includes plant inf ormation, data on plant outfalls, process flow diagrams, treatment information, and intake and eff luent characteristics.

The NPDES Form 2C database, compiled and generated by UWAG and provided to EPA, contains information about the outfalls from 86 co al-fired power plants that discharge FGD, ash handling, or coal pile runoff wastestreams. T he database does not include Form 2C information for plants that have neither a wet FGD s ystem nor wet fly ash handling. For example, if a plant has no wet FGD system and the pla nt’s only wet ash handling is for bottom ash sluicing, UWAG did not include its information in the database.

3.7 EPA 1982 T ECHNICAL D EVELOPMENT D OCUMENT

The 1982 Development Document for Effluent Limitations Guidelines and Standards and Pretreatment Standards for the Steam Electric Point Source Category (referred to as “the 1982 TDD”) present the results of studies of the steam elec tric power generating industry that EPA conducted when previously revising the Steam Electric ELGs. This document contains findings, conclusions, and recommendations on control and treatm ent technologies relating to discharges from steam electric power plants. The 1982 TDD includes thr ee separate tables and one appendix that contain ash impoundment effluent characterization data. EPA used information provided throughout the 1982 TDD to identify the types of influent str eams entering each of the ash impoundments used for this loadings analysis [U.S. EPA, 1982]

.

Table V-32, Characteristics of Ash Pond Overflows with Total Suspended Soli ds Concentrations Less than 30mg/L, presents average surface impoundment overflow pollutant concentrations for 11 separate impoundments at 11 plants.

Table V-33, Summary of Ash Pond Overflow Data from Discharge Monitoring R eports

, provides an average pollutant concentration for ash surfac e impoundment effluent for each of the three different types of impoundment systems (i.e., fly ash, bottom ash, combined ash). Additionally, the table identified the number of impoundme nt systems that were used to calculate the average concentration.Section 3 – Data Sources

3-10 Table V-34, Summary of Quarterly TVA Trace Metal Data for Ash Pond Int ake and Effluent Streams , summarizes average plant intake and ash surface impoundme nt effluent pollutant concentrations for 10 plants. The underlying individua l data points used to calculate these averages are presented in Appendix A of the 1982 TDD.

Appendix A, TVA Raw River Intake and Ash Pond Discharge Data , presents individual data points for the averaged data presented in Table V-34 of the 1982 TDD.

3.8 P ROTECTION OF C ONFIDENTIAL B USINESS I NFORMATION

Certain data in the rulemaking record have been claimed as confidential business information (CBI). Due to these CBI claims, EPA has r edacted certain information from the nonCBI version of this report. Additionally, EPA has withhel d CBI as well as some data not claimed as CBI but that could indirectly reveal CBI, from the public docket in the Federal Docket Management System. Furthermore, EPA has aggregated certai n data in the public docket, masked plant identities, or used other strategies to preven t the disclosure of CBI. EPA’s approach to CBI protection ensures that the data in the public docket explains the basis for the final rule, without compromising data confidentiality. This section describes the data claimed as CBI related to the costs and loadings analyses and how EPA determined which data needed to be redacted from the non-CBI version of this report.

During the rulemaking, steam electric power plants and equip ment and chemical vendors submitted data to EPA, some of which were claimed as CBI. These CBI data include costs associated with the installation and operation of the t echnology options evaluated as part of this rulemaking (or individual cost components for the system) and plant operating characteristics, which were used by EPA to estimate the plant-specific cos t estimates and pollutant loadings. In general, there are three different types of CBI cost v alues that were redacted from the non-CBI version of this report:

• Plant-Specific Operating Characteristics Used as Input Val ues to Estimate Costs and Loadings. Generally, EPA used the plant-specific ope rating characteristics from plant responses to the Steam Electric Survey. As part of the responses, plants were able to claim the reported data as CBI and, in many cases, the input values used to estimate plant-specific costs. As a resu lt, the plant-specific costs and pollutant loadings calculated using these CBI values ar e also considered CBI because the input values could be back-calculated using the o utputs and the methodologies and equations provided in this report. For this reason, the appendices to this report, which include the input and output da ta from the costs and loadings models at a plant level, are CBI; however, a sanitized (i.e., non-CBI) version of the appendices is available in the docket. 8

• Vendor-Provided Cost Information. As described in Section 3. 2, EPA obtained data regarding the technologies used in the industry through con tact with equipment and chemical vendors. Some of this information was claimed as CBI

8 The sanitized version of the appendices includes rounded val ues in some cases, in order to protect CBI related to other output values presented in the docket.Section 3 – Data Sources

3-11 by the vendors. In all cases for which vendors provided CBI cost information, EPA was unable to mask the information using other vendor CBI data; therefore, all vendor-provided CBI was redacted from the non-CBI vers ion of this report.

• Industry-Specific Cost Factors Developed by EPA to Estimate Indirect Costs Related to Capital and O&M Costs. EPA also used the plan t-specific data reported in response to the Steam Electric Survey to develo p cost factors to estimate the indirect costs related to capital and O&M costs. The development of these cost factors is described throughout this report. In general, EPA used all the data available for a specific cost element, including bot h CBI and non-CBI data, to develop these cost factors. For some cost factors de veloped by EPA, the aggregated value used for the cost factor (e.g., average or median value) may

reveal CBI data because of other available non-CBI data (i.e., the cost factor is CBI-deducible). EPA’s methodology for determining whether data are CBIdeducible is described in the following paragraphs.

Where an aggregated output includes totals summed from both CBI and non-CBI data, there may be sufficient information available to use t he non-CBI data to deduce (e.g., back calculate) the CBI data. Typically, CBI data can be m asked (i.e., is non-deducible) if it is combined with at least two other CBI data points into an a ggregated value (i.e., at least three CBI values are present, each of which must be associated wit h different companies). In evaluating the number of CBI data points aggregated, EPA reviewed the num ber of companies that provided the CBI data to determine if three or more companies provi ded CBI data. 9

Example of CBI-Deducible Data Determination : EPA has information from the Steam Electric Survey from nine respondents (i.e., plants) operat ed by five companies. Three respondents claimed production data as CBI; the other six p lants did not make any CBI claims on the data. The breakdown of respondents at the plant and com pany level is as shown:

Number of Plant Respondents to

Question Number of Company Respondents to Question

9 Plants (Total) 5 Companies (Total)

3 Plants (CBI) – A, B, and C 2 Companies (CBI):
- One Company Operates A and B
- One Company Operates C

Only two companies submitted CBI data. The company operating plants A and B can determine plant C’s CBI response, because it would have access to eight of the responses (i.e., the six non-CBI responses in the Steam Electric Technical Questionnaire Database , plus two CBI responses for plants A and B). Therefore, if the aggr egated cost factor based on the nine responses was made publicly available, the company operating plants A and B would be able to determine plant C’s CBI data. For this example, EPA would redact the cost factor from the nonCBI version of this report to prevent the disclosure of CBI.

9 EPA’s evaluation of companies with CBI data is based o n the majority owner identified in response to the Steam Electric Survey.Section 3 – Data Sources

3-12 EPA evaluated each cost factor developed for the costing methodology to determine if its

disclosure would allow CBI to be deduced from other data in the public record. Based on its determination, EPA handled all cost factors determined to be CBI-deducible as CBI data and has

redacted those values from the non-CBI version of this report.

EPA also considered factors of company ownership and its effects on CBI deducibilityGiven that at least some company ownership changes have occurred since the proposed Steam Electric ELGs (including known and unknown c hanges), EPA recognized there would be a strong possibility that releasing all waived CBI would release potential CBIdeducible information. For example, the Agency is aware o f a significant number of plants that changed ownership after they completed the Steam Electr ic Survey. With insufficient CBI values due to the continual change of plant ownership, data with no previous CBI deducibility concerns may now become CBI-deducible. See the February 17, 2015 “Memorandum Rationale for Handling Company Ownership Changes in CBI Deducibility Analysi s to Prepare Responses for FOIA Request EPA-HQ-2013-008604” [U.S. EPA, 2015a].

3.9 R EFERENCES

1. AEP. 2014. American Electirc Power. AEP Response to EPA D ata Request. (3 March).

DCN SE04375.

2. Duke Energy. 2011a. Industry Provided Sampling Data from Duke Ener gy's Allen Steam Station. (17 August). DCN SE01809.

3. Duke Energy. 2011b. Industry Provided Sampling Data from Duke Ener gy's Belews Creek Steam Station. (17 August). DCN SE01808.

4. Duke Energy. 2013. Comments of Duke Energy on Effluent Limit ations Guidelines and Standards for the Steam Electric Power Generating Poi nt Source Category. (7 June) EPAHQ-OW-2009-0819-4305.

5. Duke Energy. 2014. Duke Energy Response to EPA Data Request. (4 December and 28 March). DCN SE04331 and SE04360.

6. ERG. 2012a. Eastern Research Group, Inc. Final Sampling Episode Report, Duke Energy’s Miami Fort Station . (13 April). DCN SE01304.

7. ERG. 2012b. Eastern Research Group, Inc. Sampling Episode Report, Duke Energy

Caronlinas’ Belews Creek Steam Station . (13 April). DCN SE01305.

8. ERG. 2012c. Eastern Research Group, Inc. Sampling Episode Report, We Energies’

Pleasant Prairie Power Plant . (13 April). DCN SE01306.

9. ERG. 2012d. Eastern Research Group, Inc. Sampling Episode Report, Duke Energy

Carolinas’ Allen Steam Station . (13 April). DCN SE01307.

10. ERG. 2012e. Eastern Research Group, Inc. Sampling Episode Report, Mirant MidAtlantic, LLC’s Dickerson Generating Station . (13 April). DCN SE01308.Section 3 – Data Sources

3-13 11. ERG. 2012f. Eastern Research Group, Inc. Sampling Episode Report, RRI Energy’s Keystone Generating Station . (13 April). DCN SE01309.

12. ERG. 2012g. Eastern Research Group, Inc. Sampling Episode Report, Allegheny Energy’s Hatfield’s Ferry Power Station . (13 April). DCN SE01310.

13. ERG. 2012h. Eastern Research Group, Inc. Final Site Visi t Notes and Sampling Episode Report for Enel’s Power Plants. (8 August). DCN SE02013.

14. ERG. 2012i. Eastern Research Group, Inc. Power Plant Monit oring Data Collected Under Clean Water Act Section 308 Authority. (27 March). DCN SE 01326.

15. ERG. 2013. Eastern Research Group, Inc. Final Monfalcone Site Visit Notes. (11 March).

DCN SE03795 and SE03796.

16. ERG. 2015. Eastern Research Group, Inc. “Supplemental Cos ts and Loadings Documentation.” (30 September). DCN SE05839.

17. EPRI. 1997 - 2001. Electric Power Research Institute. PISCES Water Characterization Field Study, Sites A-G . Palo Alto, CA. DCNs SE01818-01823.

18. EPRI. 2006. Electric Power Research Institute. Mitigation of SCR-Ammonia Related Aqueous Effects in a Fly Ash Impoundment: Algal Enhancement and Water Chemi stry. Palo Alto, CA. DCN SE04742.

19. FirstEnergy. 2014. FirstEnergy Response to EPA Data Request . (21 February). DCN

SE04379.

20. Hoosier Energy. 2013. Hoosier Energy Rural Electric Coopera tive. Comments of Hoosier Energy on Effluent Limitations Guidelines and Standards f or the Steam Electric Power Generating Point Source Category. (20 September) EPA-HQ-O W-2009-0819-4471.

21. Hoosier Energy. 2014. Hoosier Energy Rural Electric Cooperative. Hoosier response to Post Proposal Information Request. (11 and 14 Ap ril). DCN SE04701-04702.

22. NCDENR. 2011. North Carolina Department of Environment and Nat ural Resources. State Provided Sampling Data from Progress Energy’s Roxbo ro Plant. (26 June). DCN

SE01812.

23. NRG Energy. 2014. NRG Energy Response to EPA Data Request. (21 February). DCN

SE04678.

24. U.S. EPA. 1982. U.S. Environmental Protection Agency. Development Document for Effluent Limitations Guidelines and Standards and Pretreatment Standards for t he Steam Electric Point Source Category . EPA-440-1-82-029. Washington, DC. (November).

25. U.S. EPA. 2009. U.S. Environmental Protection Agency. Steam Electric Power Generating Point Source Category: Final Detailed Study Report . EPA 821-R-09-008.Section 3 – Data Sources

3-14 Washington, DC. (October). Available online at: http://water.epa.gov/lawsregs/guidance/cwa/304m/archive/upl oad/2009_10_26_guide_ste am_finalreport.pdf.

26. U.S. EPA. 2010. U.S. Environmental Protection Agency. Questionnaire for the Steam Electric Power Generating Effluent Guidelines . OMB Approval Number: 2040-0281. Washington, DC. (2 June). DCN SE00402-SE00402A09.

27. U.S. EPA. 2015a. U.S. Environmental Protection Agency. “Mem orandum Rationale for Handling Company Ownership Changes in CBI Deducibility Analysi s to Prepare Responses for FOIA Request EPA-HQ-2013-008604.” (17 February).

28. U.S. EPA. 2015b. U.S. Environmental Protection Agency. Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category . (30 September). DCN SE05904.

29. UWAG. 2008. Utility Water Act Group. UWAG Form 2C Effluent Guidelines Database. (30 June). DCNs SE02918 and SE02918.A1.

30. UWAG. 2013. Utility Water Act Group. Comments on EPA’s P roposed Effluent

Limitations Guidelines and Standards for the Steam Electr ic Power Generating Point Source Category. (7 June) EPA-HQ-OW-2009-0819-4655.

31. UWAG. 2014a. Utility Water Act Group. UWAG Response to Po st Proposal Information Request. (1 August). DCN SE04717.

32. UWAG. 2014b. Utility Water Act Group. Additional Bottom as h Transport Water Data. (25 November). DCN SE05597.

33. We Energies. 2013. Comments to Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Power Genrating Point Source C ategory. 20 September. EPA-HWOW-0819-4475.

34. We Energies. 2014. Response to EPA Data Request. 10 February. DCN SE04666.Section 3 – Data Sources

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

Type of Information Company Plants Reference

Coal Data AEP Mountaineer Plant AEP, 2014

Duke Energy Allen Steam Station, Belews Creek Steam

Station, Miami Fort Steam Station, Roxboro Steam Plant, Mayo Plant, and

Cliffside Steam Station Duke Energy, 2014

First Energy Hatfield’s Ferry Power Station First Energy, 2014

NRG Energy Keystone Generating Station NRG Energy, 2014

We Energies Pleasant Prairie Power Plant We Energies, 2014

FGD System

Information AEP Mountaineer Plant AEP, 2014

Duke Energy Allen Steam Station, Belews Creek Steam

Station, Miami Fort Steam Station, Roxboro Steam Plant, Mayo Plant, and

Cliffside Steam Station Duke Energy, 2014

First Energy Hatfield’s Ferry Power Station First Energy, 2014

NRG Energy Keystone Generating Station NRG Energy, 2014

We Energies Pleasant Prairie Power Plant We Energies, 2014

FGD Impoundment

Effluent Duke Energy

(formerly Progress Energy Carolinas) Roxboro Steam Plant NCDENR, 2011

FGD Purge AEP Mountaineer Plant AEP, 2014

Duke Allen Steam Station, Belews Creek Steam

Station, Miami Fort Steam Station, Roxboro Steam Plant, and Cliffside Steam

Station Duke Energy

, 2011a and 2011b; Duke Energy, 2014; NCDENR, 2011

NRG Energy Keystone Generating Station NRG Energy, 2014

We Energies Pleasant Prairie Power Plant We Energies, 2014

Chemical Precipitation Effluent AEP Mountaineer Plant AEP, 2014

Duke Energy Allen Steam Station, Belews Creek Steam

Station, Miami Fort Steam Station Duke Energy

, 2011a and 2011b; Duke Energy, 2014

First Energy Hatfield’s Ferry Power Station First Energy, 2014

NRG Energy Keystone Generating Station NRG Energy, 2014

We Energies Pleasant Prairie Power Plant We Energies, 201 3 and

2014

Biological Treatment

Influent AEP Mountaineer Plant AEP, 2014

Biological Treatment

Effluent AEP Mountaineer Plant AEP, 2014

Duke Energy Allen Steam Station, Belews Creek Station,

Roxboro Steam Plant Duke Energy, 2011a and 2011b; Duke Energy, 2014; NCDENR, 2011

Ash Impoundment

Effluent Duke Energy Marshall Steam Station, Belews Creek Steam Station, Cliffside Steam Station, Miami Fort Station, East Bend Station Duke Energy , 2013

and

2014Section 3 – Data Sources

3-16 Table 3-1. Summary of Data Submitted by Industry and State Age ncies

Type of Information Company Plants Reference

Hoosier Energy Frank E. Ratts Generating Station Hoosier, 2013 and

2014

UWAG Bottom Ash Database Plant s: Burlington,

Kingston, EC Gaston, Dubuque Generating Station, Kammer Plant, Frank E. Ratts Generating Station, Monroe Power Plant, Gorgas, Crist, Meredosia Power Station, Widows Creek, Greene County, Yates, AmerenUE Sioux Power Plant, River Rouge Power Plant, Bull Run, and five unidentified power plants UWAG, 2013 and

2014

UWAG UWAG Sulfides Data S et Plant s: Kyger

Creek Station, EC Gaston, James H. Miller Jr., Gorgas, and two unidentified power plants UWAG, 2013 2014 a
, and 2014b

Table 3-2. Reports and Studies Submitted to EPA from EPR I

Title of Report/Study Document Control

Number

PISCES Wastewater Characterization Field Study, Sites A

- G DCNs SE01818

– SE01823

The Fate of Mercury Absorbed in Flue Gas Desulfurization (FGD) Systems DCN SE01814

Flue Gas Desulfurization (FGD) Wastewater Characterization: Sc reening Study DCN SE01816

EPRI Technical Manual: Guidance for Assessing Wastewater Impacts of FGD

Scrubbers DCN SE01817

Update on Enhanced Mercury Capture by Wet FGD: Technical Update DCN SE01815

Selenium Removal by Iron Cementation from a Coal

- Fired Power Plant Flue Gas Desulfurization Wastewater in Continuous Flow System – A Pilot Study DCN SE0409A2

Laboratory and Pilot Evaluation of Iron and Sulfide Additives with Microfiltration for Mercury Water Treatment DCN SE0409A3

Impact of Wet Flue Gas Desulfurization (FGD) De sign and Operating Conditions on Selenium Speciation: 2009 Update DCN SE04369

Integrated Fly Ash Pond Management: A Field Study of Five Centr al United States Pond Systems. DCN SE04361

Current Practices for Flue Gas Desulfurization (FGD) Water M anagement and

Treatment in Ponds DCN SE04367

Pilot

- Scale and Full

- Scale Evaluation of Treatment Technologies for the Removal of Mercury and Selenium in Flue Gas Desulphurization Water DCN SE04362

Impact of Wet Flue Gas Desulfurization (FGD) Design and Operating Conditions on Selenium Speciation: 2010 Update DCN SE04370

Review of Water Treatment Technologies for Selenium Removal Imple mented at

Power Plants DCN SE04363

Evaluation of Mercury Speciation and Its Treatment Implication i n Flue Gas Desulfurization Waters DCN SE04368Section 3 – Data Sources

3-17 Table 3-2. Reports and Studies Submitted to EPA from EPR I

Title of Report/Study Document Control

Number

Thermal Flue Gas Desulfurization Wastewater Treatment Processes f or Zero Liquid Discharge Operations DCN SE04365

Selenium Speciation and Management in Wet FGD Systems DCN SE04364

Corrosion in Wet Flue Gas Desulfurization (FGD) Systems : Technical Root Cause Analysis of Internal Corrosion on Wet FGD Alloy Absorbers DCN SE04366

Pilot Evaluation of the Anaerobic Membrane Bioreactor Technology for Flue Gas Desulfurization Wastewater Treatment DCN SE05615

Pilot Evaluation of the PironoxTM System for Flue Gas Desulphurization

Wastewater Treatment DCN SE05616

Pilot Evaluation of a Fluidized Bed Reactor/Membrane Bioreactor Techn ology for Flue Gas Desulfurization Wastewater Treatment DCN SE05617

Pilot Evaluation of the ABMet Technology for Fl ue Gas Desulphurization

Wastewater Treatment DCN SE05618

Pilot Evaluation of the ZVI BlueTM Technology for Flue Gas Desulphur ization

Wastewater Treatment DCN SE05619Section 4 – Development of Model Inputs

4-1 

## 4. DEVELOPMENT OF MODEL INPUTS

This section describes the input data to the costs and load ings models that EPA used to estimate incremental compliance costs and post-complian ce pollutant loadings and removals for

the Steam Electric effluent limitations and standards (ELGs). These data are categorized into one of four groups:

• Wastestream population and flow basis for pollutant load ings.

• Wastestream population and characteristics for costing

.

• Pollutant concentrations.

• Plant characteristics.

All tables and figures referenced in this section are pres ented at the end of the section.

4.1 W ASTESTREAM P OPULATION AND F LOW B ASIS FOR P OLLUTANT L OADINGS

EPA calculated baseline and post-compliance pollutant loa dings for each plant discharging flue gas desulfurization (FGD) wastewater, f ly ash transport water, bottom ash transport water, and/or combustion residual leachate. 10 Pollutant loadings are calculated by multiplying the pollutant concentrations by the wastewate r flow rate.

EPA used data from the Questionnaire for the Steam Electric Power Generating Effluent

Guidelines (Steam Electric Survey) and industry-submitted data to iden tify the population of plants discharging each wastestream and the wastewater flow rates. The steam electric power generating industry is a dynamic industry where changes are o ccurring frequently with a number of steam electric generating units retiring, converting to new type of fuel, or making changes to existing ash handling systems. Because these changes can h ave a market impact on the cost to comply with the ELGs, EPA accounted for planned changes i n the cost and loadings analysis. EPA did not estimate compliance costs or pollutant rem ovals for these generating units identified as retiring or converting to fuels (e.g., biomass, natura l gas) that do not generate wastestreams covered by the ELG prior to implementing the revised ELGs. Similarly, EPA identified those generating units converting to dry fly ash or closed-loop/ dry bottom ash handling based on information from company announcements and through contact with ash handling and

wastewater treatment vendors and excluded these units fro m the cost and loadings analysis because the planned modifications would lead to compliance w ith the final ELGs. EPA identified 170 plants retiring or converting fuels on at least one genera ting unit by 2023, an additional 18 plants converting at least one generating unit to dry fl y ash handling, and 17 plants converting at least one generating unit to closed-loop/dry bottom ash ha ndling. These plants were excluded from the cost and loadings analysis. A list of all pl ants and generating units removed from the costs and loadings analysis as a result of retiring, converting fuels, or converting their ash

10 EPA determined that, based on current practices, there would be no incremental pollutant removals for flue gas mercury control or gasification wastewater; see Sec tion 10 of the Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Powe r Generating Point Source Category [U.S. EPA, 2015].Section 4 – Development of Model Inputs

4-2 handling systems is included in the “Changes to Industry P rofile for Steam Electric Generating

Units for the Steam Electric Effluent Guidelines Final Rule” [ERG, 2015a].

The following sections describe EPA’s methodology for de termining which plants should be included in each wastestream population and the amount of wastewater being discharged by those plants based on data from the Steam Electric Surv ey and industry-submitted data.

4.1.1 FGD Wastewater

EPA used data from the Steam Electric Survey and industr y-submitted data to identify the population of plants that currently discharge or are planning to discharge FGD wastewater to surface water (or a publicly owned treatment works (POTW )) and the type of treatment equipment at each plant. To develop this “FGD Input Table,” EPA used information from Part B of the Steam Electric Survey (Flue Gas Desulfurization (FGD) Systems). EPA then adjusted the population based on those generating units identified as reti ring or converting fuels (see Section 4.1 for additional details regarding the identification of r etirements/fuel conversions). A copy of the “FGD Input Table” is included in the FGD Loadings Datab ase and the FGD and Ash Steam Electric Cost Model [ERG, 2015d; ERG, 2015e]. EPA identified a total of 88 plants that currently operate wet FGD systems and discharge FGD was tewater to surface water (or a POTW). Of these, one plant operates only small generat ing units with a capacity less than or equal to 50 megawatts and thus would not incur costs or demonst rate pollutant removals because it does not need to meet any more stringent requirement th an already existed under BPT regulations. As a result, EPA estimated that 87 plants w ould incur costs and demonstrate pollutant removals to comply with the requirements for F GD wastewater. The remainder of this section describes EPA’s methodology for developing FGD wa stewater flow rates for each of these 88 plants.

EPA used the information from Part B Section 1 (General FGD System Information) to identify those plants that operate a wet FGD system a nd have the potential to discharge FGD wastewater. Some plants operating wet FGD systems wer e excluded from this group for the following reasons:

• The plant did not report a NPDES permit.

• The plant treats the FGD wastewater using an evaporat ion impoundment system that does not discharge to a surface water or POTW.

• The plant reuses all the FGD wastewater with no potent ial for later discharge to

surface water or POTW.

For each plant that discharges FGD wastewater, EPA dete rmined the amount of wastewater that each of its FGD systems contribute t o the plant’s total FGD wastewater discharge in gallons per day (gpd). EPA used the FGD scrubber p urge rate reported in Part B Section 5 (FGD Wastewater Generation) as the FGD sys tem-level wastewater flow rate used in the cost models. For current FGD systems that did not pr ovide a FGD scrubber purge rate in Part B Section 5 (three plants), EPA developed a methodology t o estimate the FGD wastewater flow rate based on other data provided in the Steam Electric Sur vey. Using information from plants that provided data for the FGD scrubber purge, EPA established a relationship between the FGDSection 4 – Development of Model Inputs

4-3 scrubber purge rate reported by each FGD system and the am ount of coal burned at the generating units serviced by each of those wet FGD systems . EPA noted that this relationship was dependent upon the type of coal burned by these generating units; as a result, EPA calculated a value for the FGD wastewater flow per ton of coal for each type of coal: bituminous, subbituminous, lignite, and a blend of any two or more coals. EPA estimated the wastewater flow rate for 3 plants using Equation 4-1.

(4-1) System FGD Wastewater Flow (gpd) = TonsofCoalBurned × Me dianGPDperTonofCoal

where:

TonsofCoalBurned = The reported tons of coal burned per year by the steam electric generating units serviced by the FGD system. Data from Part A Section 8 (Fuel Usage by Steam Electric Generating Unit).

MedianGPDperTonofCoal = The calculated median FGD wa stewater flow rate in GPD per ton of coal burned per year based on the type of coal burned: 0.1454 for bituminous, 0.0392 for subbituminous, 0.2313 for lignite, and 0.1017 or any

coal blend.

See the “Supplemental Costs and Loadings Documentation” for the development of Equation 4-1 and the development of the median FGD wastew ater flow per ton of coal burned [ERG, 2015f; see Appendix 1].

For each plant that, in its response to the Steam Ele ctric Survey, reported plans to install a FGD system prior to January 1, 2014, EPA used the 24-hour avera ge daily design flow rate reported in Part B Section 2 (Planned FGD System Informati on) to identify a system-level FGD wastewater flow rate in gallons per day, assuming the sys tem operates 24 hours per day.

After generating the FGD wastewater flow rates at the FGD system level, EPA then

evaluated announced retirements/fuel conversions to determine which FGD systems would no longer be operating by the time the ELG is implemented a nd adjusted flow rates accordingly. For FGD systems that service generating units for which compani es have announced plans to retire or convert to a different fuel, EPA adjusted the FGD wast ewater flow rate to remove the contribution from those generating units. In cases where all generating units serviced by an FGD system are retiring/converting fuels, EPA changed the FGD wastewater flow rate to zero. In cases where some but not all of the generating units servi ced by an FGD system are retiring/converting fuels, EPA adjusted the flow based on the post-retirement scrubbed capacity using Equation 4-2.

(4-2) System FGD Wastewater Flow (gpd) = Pre-Retirement Syst em FGD Wastewater Flow × PostRetirement Scrubbed Capacity / Pre-Retirement Scrubbed C apacitySection 4 – Development of Model Inputs

4-4 where:

Pre-Retirement System

FGD Wastewater Flow = System-level FGD wastewater flow identified in the Steam Electric Survey as FGD scrubber purge flow or the system FGD wastewater flow estimated using Equation 4-1.

Pre-Retirement Scrubbed Capacity = Total capacity, in megawatts (MW), of the generating units serviced by the FGD system as reported in the Steam Electric Survey.

Post-Retirement Scrubbed Capacity = Total capacity, in MW, of the generating units serviced by the FGD system after removing all generating units identified as retiring or converting fuels as described in

Section 4.5.2.

After generating the FGD system wastewater flow rates , EPA summed each system’s flow rates at each plant to determine the total plant F GD wastewater flow rate used in the costs model. See the “Supplemental Costs and Loadings Documenta tion” for the detailed development of the “FGD Input Table” [ERG, 2015f; see Appendix 2].

4.1.2 Fly Ash and Bottom Ash Transport Water

EPA used data from the Steam Electric Survey and industr y-submitted data to identify the population of steam electric generating units that gener ate fly ash, bottom ash, or combined ash transport water, send the transport water to a surfa ce impoundment system(s), and discharge the transport water to surface waters or POTWs. EPA t hen evaluated whether any of the generating units meeting that criteria were slated for re tirement or fuel conversion and thus would no longer be generating fly ash and bottom ash by th e time the ELG is implemented. Those generating units slated for retirement or fuel conve rsion were excluded from the “Ash Transport Water Input Table.” See Section 4.1 for addition al details regarding the identification of retirements/fuel conversions. Additionally, EPA excl uded all generating units that have announced plans to convert to a dry fly ash handling system from the fly ash portion of the “Ash Transport Water Input Table.” Finally, EPA excluded all gene rating units that have announced plans to convert to a dry bottom ash system or closed-lo op wet system from the bottom ash portion of the “Ash Transport Water Input Table.” A copy of the input table is included in the Ash Loadings Database [ERG, 2015b]. EPA identified a total of 164 plants that discharge ash transport water. The remainder of this section describes EPA’s methodology for identifying these plants and determining the flow rate of ash transport wat er discharged.

EPA populated the “Ash Transport Water Input Table” using the following steps:

Step 1: Identify generating units that use wet sluicing syst ems, using data in Part C, Section 2.1 (Fly Ash Handling – Generating Unit Information ) and Part C, Section 3.1 (Bottom Ash Handling – Generating Unit Informati on).

Step 2: Identify surface impoundment systems that (1) re ceive ash transport wastewater from the generating units identified in Step 1 and (2) discha rge to surface watersSection 4 – Development of Model Inputs

4-5 or POTWs based on Part D Section 3.2 (Wastewater Treat ment Wastewater Flows).

Step 3: Where necessary, supplement incomplete or inco nclusive Part D information with information reported in Part A, Section 2.2 (Outfall Inf ormation), Part C, Section 2.1 (Fly Ash Handling – Generating Unit Information), and Pa rt C, Section 3.1 (Bottom Ash Handling – Generating Unit Information).

In cases where the Part D data differed from Parts A o r C, EPA reviewed the process flow and water balance diagrams to determine whether a ny ash transport water enters the impoundments that were reported as discharging to surface wat er or POTWs.

For each unit included in the “Ash Transport Water Input Ta ble,” EPA calculated a normalized, generating unit-level discharge flow rate for fly ash, bottom ash, and/or combined ash transport water. The discharge flow rate attribute d to each generating unit was calculated by adjusting the plant-level discharge flow rate by the pr oportion the unit contributed to the plantlevel transport water generation flow rate (e.g., a g enerating unit that produced 40 percent of all fly ash transport water generated at a plant was conside red responsible for an equal percentage of the fly ash transport water discharged by the plant). It was necessary to use this approach because the transport water generation and discharge flo w rates typically are not equal, and the discharge flow is the more appropriate value to use for e stimating pollutant loadings and removals. The plant-level normalized discharge flow r ate was determined using data from Part D of the Steam Electric Survey. Data from Part C was us ed to determine the generating unit-level normalized generation flow rate. Using the Part C norm alized flow rate, EPA calculated the proportion of flow attributable to each operating unit and a pplied it to the plant-level normalized flow rate to calculate a generating unit-level normalize d discharge flow. EPA also adjusted the generating unit-level normalized discharge flow to account for any necessary generating unitlevel flow adjustments (e.g., recycle). See Sections 4.1.2.1 through 4.1.2.5 for more specific detail on the development of the generating unit-level no rmalized flow. Also see the “Supplemental Costs and Loadings Documentation” for the detailed calculation of the generating unit-level normalized flows [ERG, 2015f; see Appendix 3].

4.1.2.1 Plant-Level Normalized Flow

EPA reviewed data in the Steam Electric Survey and indust ry-submitted data to determine plant-level ash transport water discharge flow rates by ash type, using the following list of sources, to estimate the “Plant-Level Normali zed Flow (GPD)” for ash transport water flow rates by plant:

• Influent ash transport water flow rates to the impoundme nt reported in Part D (including process flow diagrams). 11

• Percent contributions of ash sluice to plant outfall, multiplied by the total outfall flow rate reported in Part A, Section 2.

11 EPA used ash transport water flow rates from responses to Part D of the Steam Electric Survey where availa ble in an effort to account for any wastewater reuse that may occur prior to the ash transport water being sent to the impoundment.Section 4 – Development of Model Inputs

4-6 • Process flow or water balance diagram in Part A.

Plants do not continuously generate ash transport water a nd, therefore, do not necessarily discharge the wastewater without interruption. The disc harge flow rates used to populate the “Ash Transport Water Input Table” were normalized to have all plants on the same basis of discharging over 365 days. To account for the number of day s of transport water generation, EPA calculated a normalized daily flow rate using Equation 4-3. 12

(4-3) Flow Rate (gpd) = Transport Flow (gpd) × Days Generated (day s) / 365 days

where:

Flow Rate = The normalized daily flow rate of the tra nsport water from all generating units entering the ash impoundment in gpd.

Transport Flow = The reported ash transport water flow rate from all generating units entering the ash impoundment in gpd, as reported in Part D, Part A, or the water balance diagram.

Days Generated The reported number of days the ash tr ansport water is generated/transferred to the ash impoundment from all generating units, as reported in Part D, Part A, or the water balance diagram.

EPA calculated the plant-level normalized flow rate f or each type of ash (i.e., fly ash, bottom ash, combined ash).

4.1.2.2 Part C Normalized Flow

EPA reviewed data submitted in Part C of the Steam Electr ic Survey to determine the flow rate at which ash transport water is generated by e ach generating unit. These data were used to estimate a normalized flow for ash transport water discharged by each generating unit. If the plant provided a gallons per day (GPD) and days per year (DPY ) value in Part C (Table C-3 for fly ash and Table C-19 for bottom ash) for the generating unit, the normalized Part C flow was calculated by generating unit and ash type (i.e., fly ash, b ottom ash, combined ash).

However, the Part C flow data were reported inconsist ently by plants and may actually reflect flows associated with multiple generating units. For example, some plants reported the exact same transport water flow rates for all generati ng units and EPA was unable to determine

12 The approach of normalizing the flow based on the num ber of ash transport days may underestimate the loadings because the ash impoundment will continue to discharge, al though at a lower flow rate, even when ash transport water is not transferred to the ash impoundment because other contributions to the impoundment (e.g., rainfall) will continue to feed the impoundment and will likely become c ontaminated from the ash contained in the impoundment.Section 4 – Development of Model Inputs

4-7 whether the reported flow rate represents the flow fr om each individual generating unit or the combination of all the generating units. To avoid double-count ing ash transport water flow, EPA used only the Part C normalized flow data to calculate t he unit flow fraction (described in Section 4.1.2.2) or in the cases where a plant-level no rmalized flow (described in Section 4.1.2.1) could not be estimated.

4.1.2.3 Unit Flow Fraction

EPA estimated the fraction of ash transport water att ributed to each generating unit using the Part C normalized flow. If the plant provided a gpd and dpyvalue in Part C (Table C-3 for fly ash and Table C-19 for bottom ash) for the generating unit, t he normalized Part C flow was calculated by generating unit and ash type and divided by the su m of the Part C normalized flow of all the generating units to determine the unit flow frac tion.

If the plant did not provide either GPD or DPY in Table C-3 or C-19, EPA estimated a unit fraction by using the ash tonnage conveyed wet from Tabl e C-2 or C-18, instead of the transport water flow rate. The generating unit flow frac tion was calculated by dividing the wet tonnage for a generating unit by the sum of wet tonnage for all generating units.

If the plant did not provide the GPD and DPY information in Table C-3 or C-19, and the ash tonnage conveyed wet was not available, EPA estimat ed the tonnage from the amount of coal burned per generating unit in Part A, Table A-11. To estimate a wet conveyed fly ash tonnage, EPA multiplied the tons of coal burned by the generating uni t in Part A, Table A-11 by 8 percent (assuming 10 percent ash content for the coal and 80 percent of ash generated is fly ash). EPA estimated the wet conveyed bottom ash tonnage by multipl ying the tons of coal burned by the generating unit by 2 percent (assuming 10 percent ash content f or the coal and 20 percent of ash generated is bottom ash). EPA then divided the generatin g unit-level wet ash tonnage by the sum of the wet ash tonnage for all generating units with wet s luicing systems to determine the unit

flow fraction.

4.1.2.4 Generating Unit-Level Normalized Flow

Using the plant-level normalized discharge flow rate a nd the unit flow fraction, EPA calculated generating unit-level normalized discharge flo w rates by multiplying the plant-level normalized flow rate by the unit flow fraction. When pla nt-level flow data were not available, EPA used the Part C Normalized Flow to populate the “Ash Transport Water Input Table.”

4.1.2.5 Additional Flow Adjustments

In addition to the generating unit-level normalized flow, EPA also reviewed data in the Steam Electric Survey and industry-submitted data to ident ify any adjustments necessary to reflect wastewater recycle and potential double-counting o f generating unit-level flows where plants may have reported a total plant flow for all gen erating units at the plant.

First, EPA identified plants that reported they recycl e bottom ash transport water before or after dewatering from Question C3-5 (recycle bottom ash sluice) and Question C3-10 (recycle water from solids removal) in the Steam Electric Sur vey, or other industry-supplied data. EPA reviewed the Part C, Section 3.1 flow data, water balanc e diagrams from Part A, Section 5, Part A, Section 2.2 outfall data, and Part D, Sections 3.1 and 3.2 treatment system diagrams and flowsSection 4 – Development of Model Inputs

4-8 for this subset of data. EPA flagged plants operating a com plete recycle system or those plants that did not discharge bottom ash sluice in 2009, but still h ad the ability to discharge (e.g., emergency discharge outfalls). EPA flagged these generatin g units as “Complete Recycle” in the “Discharge Flag” field in the “Ash Transport Water Input Table” and adjusted the flow to zero. EPA adjusted bottom ash transport water flows in the a sh flow input table for plants that recycle any of their bottom ash transport water [ERG, 2015f; se e Appendix 3].

EPA also reviewed specific plants in the “Ash Transport Water Input Table” that reported identical flow rates (GPD) and generation (DPY) in Tabl e C-3 for fly ash (Part C, Section 2.1) and C-19 for bottom ash (Part C, Section 3.1) for all gener ating units. EPA reviewed Part D, Sections 3.1 and 3.2 treatment system diagrams and flows, P art A, Section 2.2 outfall data, and Part A, Section 5 process flow diagrams to determine if the flows provided in Part C were really generating unit-level or a plant-level flow rates. In add ition, the unit flow fraction was analyzed individually for these plants to determine whether the to nnage ratios were a better source for determining the unit flow fraction. Where the Part C flo w rates for an individual generating unit were less than the plant-level flow rates from Part D or Part A, EPA determined that the reported generating unit flow represents the flow from the indivi dual generating units. Where the Part C flow rates for an individual generating unit matched the p lant-level flow rates from Part D or Part A, EPA determined that the reported generating unit flow represents the total plant-level flow. In cases where the Part C flow did not represent flow on a generating unit-level, EPA adjusted the generating unit-level ash transport water flow rates in the “Ash Transport Water Input Table” accordingly.

4.1.3 Combustion Residual Leachate

EPA used data from the Steam Electric Survey to identify the population of landfills and impoundments containing combustion residuals that collect a nd discharge combustion residual leachate to surface waters or POTWs. The methodology E PA used to estimate the amount of combustion residual leachate discharged from landfills containing combustion residuals is described in Section 4.1.3.1. The methodology EPA used to estim ate the amount of combustion residual leachate discharged from impoundments containing com bustion residuals is described in

Section 4.1.3.2. Section 9 describes the combustion residua l leachate loadings methodology in

detail.

4.1.3.1 Landfill Combustion Residual Leachate Discharge Flow

EPA used data from the Steam Electric Survey to identify the population of active/inactive landfills containing combustion residuals that collect and discharge combustion residual leachate to surface waters or POTWs. To develop t hese input data, EPA used data from Part F, Section 3.1 (Landfill Management Practices) fo r those plants that completed this

section. 13 For all other plants EPA used the information from Pa rt A, Section 4 (Landfills) of the Steam Electric Survey to identify plants that collect the combustion residual leachate generated

at landfills and then estimated the combustion residual leachate flow rates for these plants based

13 Only a subset of plants were required to respond to Par t F of the Steam Electric Survey. Section 3 of the Technical Development Document for the Effluent Limitations Guidelines and S tandards for the Steam Electric Power Generating Point Source Category provides more detail on the Steam Electric Survey [U.S . EPA, 2015].Section 4 – Development of Model Inputs

4-9 on data from plants completing Part F. Additionally, E PA used information from Part A, Section 2.2 (Outfall Information) and water balance diagrams to i dentify the plants that discharge the

collected combustion residual leachate to surface waters or POTWs. The landfill combustion residual leachate flows, and the impoundment combustion r esidual leachate flows described in Section 4.1.3.2, are combined to create the “Combustion Resi dual Leachate Input Table.” A copy of the “Combustion Residual Leachate Input Table” is includ ed in the Combustion Residual Leachate Loadings Database [ERG, 2015c]. EPA identified a total of 85 plants that collect and discharge combustion residual leachate from 109 landfills containing combustion residuals. Of these, two plants operate, or plan to operate, treatment system more advanced than chemical precipitation and one plant operates only small generatin g units with a capacity less than or equal to 50 MW and thus would not incur costs or demonstrate poll utant removals because it does not need to meet any more stringent requirement than already existed under BPT regulations. As a result, EPA estimated that 82 plants would incur costs an d demonstrate pollutant removals to comply with the chemical precipitation requirements fo r landfill combustion residual leachate.

Plants reported their collected combustion residual leacha te flow rates in Part F, Section 3.1 (Landfill Management Practices) of the Steam Elect ric Survey. Because only a subset of plants was required to complete Part F, EPA had specifi c landfill combustion residual leachate flow rates from only 18 plants. For each of these 18 plant s, EPA calculated the ratio of the landfill acreage associated with the collected combustio n residual leachate and the total active/inactive landfill acres at the plant reported i n Part C, Section 1 (Ash Generation) of the Steam Electric Survey. EPA then determined the median v alue for the calculated ratios from the 18 plants and applied the median value to other plants that r eported collecting landfill combustion residual leachate but were not required to com plete Part F. EPA used the median value, along with the reported total active/inactive landfi ll acres reported in Part C, to estimate the total landfill acres for the plant where combusti on residual leachate is collected (referred to as leachate acreage). EPA developed separate estimates f or active and inactive landfills as

follows:

Active Landfills:

(4-4) Leachate Acreage (acre) = Median Leachate Acre Per A ctive Landfill Acre × Landfill Acreage

Inactive Landfills:

(4-5) Leachate Acreage (acre) = Median Leachate Acre Per I nactive Landfill Acre × Landfill AcreageSection 4 – Development of Model Inputs

4-10 where:

Median Leachate Acre Per

Active Landfill Acre = Median ratio of acreage collecting combustion residual leachate at a plant to total landfill acres for active landfills, 0.75.

Median Leachate Acre Per

Inactive Landfill Acre = Median ratio of acreage collecting combustion residuals leachate at a plant to total landfill acres for inactive landfills, 0.05.

Landfill Acreage = Total active/inactive/open landfill acreage at the plan t, as reported in Part C, Section 1 (Ash Generation).

See the “Supplemental Costs and Loadings Documentation” for the discussion on the development of Equations 4-4 and 4-5 [ERG, 2015f; see Appendix 4]

.

EPA also used the data from the 18 plants responding to Par t F, Section 3.1 to generate a relationship between the acreage of landfills that col lect combustion residual leachate and the amount of combustion residual leachate discharged. EPA ass umed that any open landfill, active or inactive, at a given plant would receive similar am ounts of rainfall. Of the 18 plants that discharge combustion residual leachate, the median lea chate discharge rate was 887 gpd per acre

of landfill.

EPA used the following hierarchy to estimate the landfill combustion residual leachate

flow rate for the “Landfill Combustion Residual Leach ate Input Table:”

• EPA used the volume of combustion residual leachate coll ected in 2009, reported in Part F, Section 3.1 of the Steam Electric Survey (L andfill Management Practices).

• EPA used the current landfill-specific surface area from Part F, Section 3.1 of the Steam Electric Survey (Landfill Management Practices) and multiplied by the median leachate discharge rate per acre (887 gpd/acre) [ERG , 2015f; see Appendix 4].

(4-6) Leachate Volume (gpd) = 887 × Leachate Acreage

• EPA used the active/inactive/open landfill acreage, repo rted in Part C, Section 1 (Ash Generation) depending on whether the landfill is ac tive or inactive, and the median leachate discharge flow rate per acre (887 gpd/acre).

Active Landfills:

(4-7)

Leachate Volume (gpd) = 887 × 0.75 × Leachate AcreageSection 4 – Development of Model Inputs

4-11 Inactive Landfills:

(4-8)

Leachate Volume (gpd) = 887 × 0.05 × Leachate Acreage

where:

Leachate Acreage = Total acreage of landfills containing combustion residual at the plant that collect combustion residual leachate, a percentage of the total landfill acres at t he plant (see Equations 4-4 and 4-5).

EPA used the median leachate volume from plants providi ng data in Part F, Section 3.1 of the Steam Electric Survey. The average plant-level combustion residual leachate volume reported by the 18 plants in Part F, Section 3.1 was 46,160 gpd for active landfills and 29,651 gpd for inactive landfills.

During review of the landfill combustion residual leacha te volumes, EPA also investigated the frequency of combustion residual leachate c ollection for the 18 plants with complete Part F, Section 3.1 data. The median frequency of combustion residual leachate collection was 365 days per year. EPA used this value to con vert the combustion residual leachate volumes from gallons per day to gallons per year pr ior to populating the “Landfill Combustion Residual Leachate Input Table.”

4.1.3.2 Impoundment Combustion Residual Leachate Discharge Flow

EPA used data from the Steam Electric Survey to identify plants collecting and discharging combustion residual leachate from impoundment s containing combustion residuals and to calculate a combustion residual leachate discharge flow rate. EPA identified plants that collect combustion residual leachate from impoundments co ntaining combustion residuals using data from Part A, Section 3 (Pond/Impoundments) and Part F, Section 2 (Pond/Impoundment Management Practices) of the Steam Electric Survey. Us ing Part A, Section 2.2 (Outfall Information) and water balance diagrams provided as part of the Steam Electric Survey, EPA identified 46 impoundments (42 active and four inactive) at 25 pl ants discharging leachate from impoundments containing combustion residuals. 14 The impoundment combustion residual leachate flows, and the landfill combustion residual le achate flows described in Section 4.1.3.1,

are combined to create the “Combustion Residual Leachate Input Table,” a copy of which is included in the Combustion Residual Leachate Loadings Data base [ERG, 2015c].

From Part F of the Steam Electric Survey, EPA identif ied 24 impoundments providing

combustion residual leachate flow rate information for impoundments containing combustion residuals. Because only a subset of plants were required to complete Part F of the Steam Electric Survey, EPA used these data to develop a relationship between combustion residual leachate flow and impoundment size to estimate flow for the othe r impoundments that discharge

14 Retired impoundments were excluded from this analysis.Section 4 – Development of Model Inputs

4-12 combustion residual leachate. The Steam Electric Surve y data contain both a combustion residual leachate volume and current impoundment size infor mation for only 21 of those 24 impoundments, based on data from Part D, Section 4.1. Us ing the data for these 21 impoundments, EPA developed an impoundment-level relationshi p between combustion residual leachate volume, in gallons per day, and impoundment square footage. EPA used Equation 4-9 to

calculate the ratio of combustion residual leachate vo lume, in gallons per day, 15 to impoundment square footage for the 21 impoundments for which data were ava ilable.

(4-9)

Leachate Flow Per Impoundment Area Ratio (gpd/ft 2 ) = Normalized Volume of Impoundment Leachate Collected / Cur rent Surface Area

where:

Normalized Volume of Impoundment Leachate

Collected = Volume of impoundment combustion residual leachate collected in 2009 in normalized gallons per day (gpd over 365 days).

Current Surface Area = Current impoundment surface area i n ft 2

.

The median ratio of leachate flow to impoundment area was found to be 0.006334 gpd per square foot (ft 2 ) (or 275.91 gpd/acre). The median leachate flow for all 21 impo undments was 34,560 gpd.

EPA developed a plant-level relationship between the acre age of impoundments that collect leachate from impoundments containing combustion r esiduals and the total active/inactive/open impoundment acreage from Part C, Se ction 1 (Ash Generation) in order to estimate a combustion residual leachate flow for plants that did not provide a current impoundment size. EPA identified 11 plants providing an impoun dment-level flow in Part F and total impoundment area in Part C. EPA used these data to c alculate the ratio of acreage for impoundments collecting leachate to the total acreage of impoundments at the plant using Equation 4-10.

(4-10)

Area Collecting Leachate Per Total Impoundment Area = (Total Surface Area of Impoundments Collecting Leachate × 1 acre / 43560 ft 2 ) / Total Impoundment Acres

where:

Total Surface Area of Impoundments Collecting = Sum of all current surface area for all impoundments containing coal combustion residuals (CCRs) that

15 EPA normalized the flow rates reported in Part F, Se ction 3 based on the gallons per day and days per year reported for leachate generation. EPA recalculated the n ormalized flow rate based on leachate generation over 365 days for each impoundment.Section 4 – Development of Model Inputs

4-13 Leachate collect combustion residual leachate, in ft 2 , from Part D, Section 4.1.

Total Impoundment Acres = Impoundment acres Active/Inact ive/Open Impoundments from Part C, Section 1.

EPA calculated a median ratio of acreage of impoundment s collecting combustion residual leachate to total plant impoundments acreage of 0. 8071. For those plants missing an impoundment-specific leachate flow and an impoundment-spec ific acreage, EPA used Equation 4-11 to first estimate the acreage of impoundments collec ting leachate and Equation 4-12 to estimate the leachate flow for the estimated acreage of impoundments collecting leachate.

(4-11)

Estimated Acreage of Impoundments with Leachate Collecti on (acre) = Median Area Collecting Leachate Per Total Impoundment A cres × Total Impoundment Acres

where:

Median Area Collecting

Leachate Per Total Impoundment Area = Median ratio of total surface area collecting combustion residual leachate to total impoundment acreage, 0.8071 (see Equation 4-10).

Total Impoundment Acres = Impoundment acres Active/Inact ive/Open Impoundments from Part C, Section 1.

(4-12) Leachate Flow Per Plant (gpd) = Estimated Acreage of Im poundments with

Leachate Collection × Median Leachate Flow Per Impoundment Area Ratio

where:

Estimated Acreage of Impoundments with

Leachate Collection = Acreage of impoundments collecting combustion leachate at the plant (see Equation 4-11).

Median Leachate Flow Per Impoundment Area Ratio = Median ratio of amount of combustion residual leachate generated per impoundment area, in gpd per acre, 275.91 gpd/acre.

See the “Supplemental Costs and Loadings Documentation” for the development of Equations 4-9 and 4-12 [ERG, 2015f; see Appendix 5].

EPA used the following hierarchy to determine the appropriate f low rate to populate the “Impoundment Combustion Residual Leachate Input Table.”

• EPA used the normalized volume of leachate collected in 2009 (gpd over 365 days) in Part F of the Steam Electric Survey.Section 4 – Development of Model Inputs

4-14 • For impoundments that did not provide an impoundment-specifi c leachate flow rate in Part F of the Steam Electric Survey, but did pr ovide an impoundment surface area in Part D, EPA used Equation 4-13 to estimate the leachate flow.

(4-13) Leachate Flow Per Impoundment (gpd) = Median Leachate Flo w Per Impoundment

Area Ratio × Current Surface Area

where:

Median Leachate Flow Per Impoundment Area Ratio = Median ratio of amount of combustion residual leachate discharged per impoundment area, in gpd per square foot, 0.006334 gpd/ft 2.

Current Surface Area = Current impoundment surface area i n ft 2

.

• For impoundments that did not provide an impoundment-specifi c combustion residual leachate flow rate in Part F or impoundment sur face area in Part D of the Steam Electric Survey, but did provide a total impoundment a creage in Part C, EPA used Equations 4-11 and 4-12 to calculate the combustion re sidual leachate

flow.

• For plants that did not provide impoundment-specific size dat a in Part D or total impoundment acreage in Part C of the Steam Electric Sur vey, EPA used the median impoundment combustion residual leachate flow rat e for all impoundments responding to Part F, Section 2 (34,560 gpd) for th e combustion residual leachate discharge flow.

4.2 W ASTESTREAM P OPULATION AND C HARACTERISTICS FOR C OSTING

For each plant discharging FGD wastewater, combustion re sidual leachate, gasification wastewater, or operating wet fly or bottom ash handling sys tems, EPA estimated a compliance cost to treat the wastewater or, in the case of ash t ransport water, eliminate the discharge entirely. 16 For FGD wastewater and landfill combustion residual l eachate, the methodology for estimating treatment system costs is based on the volu me of wastewater. For these wastestreams, EPA used the same input data for both costing and pollutant loadings calculations.

EPA also estimated compliance costs associated with e liminating the discharge of ash transport water, by costing plants to convert to either a dry handling or a closed-loop recycle system. The fly ash and bottom ash costs are based o n the amount and type of ash generated by each generating unit. Finally, EPA estimated compliance costs associated with plants discharging gasification wastewater. Since all plants discharging gasification wastewater already operate the Best Available Technology Economically Achievable (BAT) technology that is the basis for the

16 Plants can eliminate the discharge of ash transport wate r by either converting to a dry ash handling system or operat ing a closed-loop ash recycle system.Section 4 – Development of Model Inputs

4-15 effluent limitations in the rule, the only complianc e costs for this wastestream are monitoring

costs.

As described in Section 4.1, EPA used Steam Electric Survey and industry-submitted data to identify the population of plants that is project ed to incur compliance costs associated with the ELGs. EPA did not estimate compliance costs f or all plants and generating units identified as retiring, converting fuels, or converting the ir ash handling systems prior to implementing the ELGs. A list of all plants and genera ting units removed from the costs and loadings analysis as a result of retiring, converting fue ls, or converting their ash handling systems is included in the “Changes to Industry Profile for Steam Electric Generating Units for the Steam Electric Effluent Guidelines Final Rule” [ERG, 2015a]. The following section describes what population of plants is projected to incur FG D, fly ash, bottom ash, leachate, and gasification compliance costs and the specific plant an d generating unit-level characteristics used

to estimate these costs.

4.2.1 FGD Wastewater

EPA used the same input data for both costing and loadings associated with FGD wastewater. For details on the “FGD Input Table,” see Se ction 4.1.1.

4.2.2 Fly Ash

EPA used data from the Steam Electric Survey and industr y-submitted data to identify which plants would incur costs to meet a zero discharge sta ndard for pollutants in fly ash transport water. EPA first identified those plants that operate wet sluicing systems and discharge fly ash transport water. To develop this “Fly Ash Input Ta ble,” EPA used data from Part C (Ash Handling) and Part A (Steam Electric Power Plant Operat ion) of the Steam Electric Survey and plant-specific data submitted by industry through public commen ts to identify what costing elements of the fly ash system would be appropriate for each generating unit and/or plant.

EPA assessed the costs for converting to a dry fly ash handling system on a steam electric generating unit level. EPA examined Steam Electric Survey and industry-submitted data for each generating unit that uses fly ash transport water and appli ed a hierarchical method to determine the appropriate fly ash cost elements for each generati ng unit that operates a wet sluicing system and discharges fly ash transport water. First, generati ng units were flagged as not incurring a cost if the generating unit falls into any of the following sub sets:

• Retired generating units that responded “Yes” to “Is this unit now retired?” in Question A6-1 in Table A-8.

• Generating units that either have already retired or c onverted to dry fly ash handling or have announced plans to do so (eliminating the discharge of fly ash transport water) as identified through industry-submitted data or EPA’s retirement and handling conversion analysis (see Section 4.1).Section 4 – Development of Model Inputs

4-16 • Generating units that did not operate in 2009, indicated by a “No” response to “Operated in 2009” in Question A6-1 in Table A-8. 17

• Gas-fired and nuclear-fueled generating units (these units do not produce ash).

• Generating units that did not generate fly ash, which was determined by the plant either responding “No” to “Is ash generated at any fossil- fueled steam electric generating units at the plant?” in Question C1-1 or because it did not complete Part C, Section 2.1.

• Generating units that reported fly ash generation in Table C-2 and reported dry handling only. These generating units reported all of their fly ash generation as dry conveyed, did not select wet sluicing (hydraulic) in Ta ble C-2, and responded “No” to “Is wet sluicing a type of fly ash handling for t his steam electric generating unit?” in Question C2-2.

• Generating units that indicated both wet and dry fly ash handling by responding “Yes” to “Was fly ash from this steam electric generati ng unit conveyed both wet and dry in 2009?” in Question C2-10. The generating units must a lso have reported that the wet system was operated when the dry sys tem was down due to maintenance in response to Question C2-11 and that no syste m modifications would be required to handle all the fly ash dry in respons e to Question C2-12.

• Generating units that indicated both wet and dry fly ash handling by responding “Yes” to “Was fly ash from this steam electric generati ng unit conveyed both wet and dry in 2009?” in Question C2-10 and indicated in Question C 2-13 that use of the wet fly ash handling system will end before 12/31/2023.

• Generating units that indicated both wet and dry fly ash handling by responding “Yes” to “Was fly ash from this steam electric generati ng unit conveyed both wet and dry in 2009?” in Question C2-10 and responding to Question C 2-11 that the only reason the wet fly ash handling system was operate d in 2009 was because the dry fly ash handling system had not yet been installed.

• Generating units at plants that did not report a National Pollutant Discharge Elimination System (NPDES) permit in Table A-2, indicat ing that they do not discharge to surface water, and did not report an indirect discharge of fly ash transport water to a POTW.

Next, EPA identified the generating units that required a c omplete wet-to-dry fly ash conversion and therefore would incur all associated fly ash capital and O&M cost elements (i.e., conveyance costs, silo costs, pugmill costs, and transpor tation/disposal costs). These generating units were flagged as incurring a cost and identified using the following criteria:

17 Although these generating units may still have the capa bility to operate, since these units were not called upon to operate at any time in 2009, EPA assumes that the company will retire these generating units instead of expending resources to convert their ash handling systems.Section 4 – Development of Model Inputs

4-17 • Generating units responding “Wet sluicing (hydraulic)” in T able C-2 and reporting no dry handling capabilities (Dry Vacuum system, We t Vacuum system (pneumatic), Pressure system, Combined Vacuum/Pressure sys tem, or Mechanical system). Generating units responding “Wet sluicing (hydrauli c)” and “Other”

were handled on an individual basis to determine whether the response in the “Other” field indicated a wet or dry handling system.

• Generating units responding “Wet sluicing (hydraulic)” in T able C-2 as well as reporting any type of dry handling capabilities (Dry Vacuum sy stem, Wet Vacuum system (pneumatic), Pressure system, Combined Va cuum/Pressure system, or Mechanical system), but listed all of the f ly ash generation as wet conveyed in Table C-2. 18

All generating units that were not categorized using the criteria for not incurring any cost or for incurring the cost for a complete wet-to-dry c onversion were determined to currently have both wet and dry fly ash handling capabilities. EPA determ ined that this third group of generating units should only require a subset of the fly a sh cost elements associated with converting to a completely dry fly ash handling system. For example, some generating units would incur capital costs for installing backup or redundant equ ipment. These generating units were flagged for costing based on the responses to Questio ns C2-11 and C2-12.

• Generating units were identified as needing capital and O &M conveyance costs if the respondent selected “Install/increase the capacity o f the dry fly ash conveying equipment” in response to “What modifications would be re quired to handle all the fly ash with the dry fly ash handling system?” in Question C2-12.

• Generating units were identified as needing capital and O &M silo costs if the respondent selected either “Increase the capacity of the silo(s)” or “Increase the number of the silos” in response to “What modification s would be required to handle all the fly ash with the dry fly ash handling s ystem?” in Question C2-12.

• Generating units were identified as needing capital and O &M pugmill costs whenever the unit was identified as needing a silo cost. A dditionally, generating units were identified as needing pugmill costs if the responde nt selected “Modify the loading silos to have the ability to moisture condi tion the ash” in response to “What modifications would be required to handle all the fl y ash with the dry fly ash handling system?” in Question C2-12.

• Generating units were identified as needing transportati on/disposal costs if the respondent selected “Install/increase the capacity of lan dfills” in response to “What modifications would be required to handle all the fl y ash with the dry fly ash handling system?” in Question C2-12, or if the responde nt selected “Wet fly ash handling system operated during times in which the dry fly ash was not

18 Although the plants indicated that these generating units ha d a dry handling system, EPA assumed that a completely new system would be required because the plant di d not use the system at all in 2009. This assumption may overestimate the costs for these generating units.Section 4 – Development of Model Inputs

4-18 marketable” in response to “Indicate why fly ash from th e steam electric generating unit was conveyed both wet and dry in 2009?” in Ques tion C2-11.

• Generating units were identified as needing back-up capita l silo and pugmill costs if the respondent selected “Wet fly ash handling system o perated during times in which the dry fly ash was not marketable” in response to “Indicate why fly ash from the steam electric generating unit was conveyed both wet and dry in 2009?” in Question C2-11 and EPA determined that the plant likely did not have the capabilities for moisture-conditioned unloading based on respon ses to Question C2-25 (Fly Ash Storage Information); [ERG, 2015f; see Append ix 6]. EPA evaluated the O&M costs associated with the dry system compared to a wet sluicing system and determined that operating the dry fly as h handling system is a cost savings compared to operating a wet sluicing system. The refore, O&M costs for the backup silo and pugmill are not calculated as part of the compliance cost estimates; see the [ERG, 2015f; see Appendix 6].

• Generating units were identified as needing capital cost s for conveyance system redundancy (e.g., additional filter-receivers, vacuum pumps, and/or pressure blowers based on the existing system design) if the res pondent selected “Other” in response to “What modifications would be required to hand le all the fly ash with the dry fly ash handling system?” in Question C2-12 and sta ted that some level of redundancy was necessary to handle all fly ash dry at th e plant; [ERG, 2015f; see Appendix 6]. EPA evaluated the O&M costs associated with t he dry system compared to a wet sluicing system and determined that opera ting the dry fly ash handling system is a cost savings compared to operating a we t sluicing system. Therefore, O&M costs for the redundant equipment are not c alculated as part of the compliance cost estimates; [ERG, 2015f; see Appendix 6].

For all generating units included in this partial costs cat egory that handled the fly ash both wet and dry in 2009, EPA evaluated the remaining response s in the “Other” fields for Questions C2-11 and C2-12 on an individual basis to identify any specific cost elements that should/should not be included for those plants/units [ERG, 2015f; see Appendix 6].

Based on responses to the Steam Electric Survey and publicl y available information on planned retirements, fuel conversions and ash handling conve rsions, EPA identified 37 plants, corresponding to 95 generating units, discharging fly ash transport water that would incur either partial or complete wet-to-dry conversion costs if they had to eliminate the discharge of pollutants in fly ash transport water. Of these, eight plants operate 14 generating units that are oil-fired units or small units with a capacity less than or equal to 50 MW and thus would incur no costs to comply with the requirements for fly ash tr ansport water. As a result, EPA estimated that 31 plants 19 operating 81 generating units would incur costs to comply with the requirements for fly ash transport water. For each of these 81 generating units, EPA identified the specific fly ash cost elements needed and collected the other necessary i nput data (i.e., generating unit-level wet fly ash production (in tons per day and days per year), gene rating unit-level dry fly ash

19 Some plants operate steam electric generating units ab ove and below the 50 MW threshold; therefore, the number of plants is not additive.Section 4 – Development of Model Inputs

4-19 production (in tons per day and days per year), operating days for the generating unit, nameplate capacity (in MW), generating unit type, and fly ash trans port water flow rate (in gpd)). 20 See Section 7.1.4 for more information about the specific fie lds for the “Fly Ash Input Table.” A copy of the “Fly Ash Input Table” is included in the FGD an d Ash Steam Electric Cost Model [ERG, 2015d].

4.2.3 Bottom Ash

EPA used data from the Steam Electric Survey and industr y-submitted data to identify those plants that operate wet sluicing systems and disch arge bottom ash transport water. To develop this “Bottom Ash Input Table,” EPA used data from Pa rt C (Ash Handling) and Part A (Steam Electric Power Plant Operation) of the Steam Electric Survey and plant-specific data submitted by industry through public comments to identify what c osting elements of the bottom ash system would be appropriate for each plant.

EPA assessed costs for converting to a system that el iminates the discharge of bottom ash transport water on a steam electric generating unit leve l. EPA examined Steam Electric Survey and industry-submitted data for each generating unit utilizing b ottom ash transport water and applied a hierarchical method to determine the most appropri ate bottom ash cost elements for each unit. First, generating units were flagged as not incurri ng a cost if the unit falls into any of the following subsets:

• Retired generating units that responded “Yes” to “Is this unit now retired?” in A8-

1 in Table A-8.

• Generating units that either have already retired or c onverted to dry bottom ash handling or have announced plans to do so (eliminating the discharge of bottom ash transport water) as identified through industry-submitte d data or EPA’s retirement and handling conversion analysis (see Secti on 4.1).

• Generating units that responded “No” to “Operated in 2009” in A 8-1 in Table A8. 21

• Gas-fired and nuclear-fueled generating units (these units do not produce ash).

• Generating units that do not generate bottom ash generati on, which was determined by the plant either responding “No” to “Is bott om ash generated in any fossil-fueled steam electric generating units at the pl ant?” in Question C3-1 or because it did not complete Part C, Section 3.1.

• Generating units that reported bottom ash generation in Ta ble C-18 but not the use of wet sluicing. These generating units did not select “Wet sluicing” in Table

20 As part of its analysis for the final rule, EPA als o did this for the 12 oil-fired and small generating units that will not incur costs to comply with the requirements for fly ash transport water.

21 Although these generating units may still have the capa bility to operate, since these units were not called upon to operate at any time in 2009, EPA assumes that the company will retire these generating units instead of expending resources to convert their ash handling systems.Section 4 – Development of Model Inputs

4-20 C-18, and selected “No” in response to “Is wet sluicing use d to collect bottom ash for this steam electric generating unit?” in Question C3-3.

• Generating units that reported bottom ash generation in Ta ble C-18 and reported both “Wet Sluicing” and at least one other type of botto m ash handling system, but listed all of the bottom ash generation as “Dry Co nveyed.”

• Generating units that indicated both wet and dry bottom ash handling by responding “Yes” to “Was the bottom ash from this stea m electric generating unit conveyed both wet and dry in 2009?” in Question C3-16 and respo nding in the “Other” field for “What modifications would be required to handle all the bottom ash with a dry bottom ash handling system?” in Questio n C3-18 that the only reason the wet bottom ash handling system was operated i n 2009 was because the dry bottom ash handling system had not yet been installe d.

• Generating units that indicated both wet and dry bottom ash handling by responding “Yes” to “Was the bottom ash from this stea m electric generating unit conveyed both wet and dry in 2009?” in Question C3-16 and repor ting in Question C3-19 that use of the wet bottom ash handling syste m will end before

12/31/2023.

• Generating units at plants that did not report a NPDES per mit in Table A-2, indicating that they do not discharge to surface water, an d did not report an indirect discharge of bottom ash transport water to a P OTW.

Next, EPA identified the generating units that required a c omplete conversion to a system that eliminates the discharge of bottom ash transport water. These generating units were identified using the following criteria:

• Generating units that selected “Wet sluicing” in Table C- 18 and did not report any dry handling capabilities (Mechanical drag system, Dry vacuu m system, Dry pressure system).

• Generating units that selected “Other” were handled on an individual basis to determine whether the response indicated a wet or dry han dling system; [ERG, 2015f; see Appendix 6].

EPA also identified those plants operating wet sluicing s ystems where the bottom ash transport water was recycled and not discharged in 2009, although plants may have the ability to discharge this wastewater (e.g., emergency outfalls). Fo r generating units that responded “Yes” to “Is any of the wet bottom ash sluice water immediat ely recycled back to plant process?” in Question C3-5 and “Immediately recycled back to plant proc ess” to “What is the destination(s)

of the wastewater overflow from solids removal?” in Question C3-10, EPA evaluated the amount of transport water actually discharged. EPA identified pl ants that did not discharge any bottom ash transport water in 2009 as being able to develop a plan to manage the water balance to completely recycle the bottom ash transport water without requiring a discharge. Therefore, these plants were assessed a one-time bottom ash cost, des cribed in more detail in Section 8.5. Because these generating units did not discharge any bottom ash tran sport water in 2009, EPA did notSection 4 – Development of Model Inputs

4-21 estimate bottom ash loadings for these generating units; therefore, these generating units will incur compliance costs but no pollutant reductions. 22

Based on responses to the Steam Electric Survey and publicl y available information on planned retirements, fuel conversions, and ash handling conver sions, EPA identified 172 plants, corresponding to 406 generating units, having the potential to discharge bottom ash transport water that would incur costs if they had to eliminate the discharge of pollutants in bottom ash transport water. Of these, 18 plants operate 32 small gener ating units with a capacity less than or equal to 50 MW and thus would incur no costs to comply with the requirements for bottom ash

transport water. 23 As a result, EPA estimated that 164 plants 24 operating 374 generating units would incur costs to comply with the requirements for bot tom ash transport water. For each of these 374 generating units that discharge bottom ash transpor t water, EPA identified the specific cost elements that apply to the generating unit and colle cted the other necessary input data (i.e., generating unit-level wet bottom ash production (in tons per day and days per year), nameplate capacity (in MW), the operating days for the generating uni t, and the bottom ash transport water rate (in gpd)). 25 Additionally, EPA identified a subset of the plants ha ving a potential to discharge bottom ash transport water (10 plants, correspo nding to 17 generating units) that did not discharge any bottom ash transport water in 2009. For th ese 17 generating units, EPA assigned these units one-time bottom ash costs in the “Bottom Ash Input Table.” See Section 8.1.3 for more information about the specific fields for the “Bottom Ash Input Table.” A copy of the “Bottom Ash Input Table” is located in the FGD and A sh Steam Electric Cost Model [ERG, 2015d].

4.2.4 Combustion Residual Leachate

EPA used the same input data for both costs and loadings as sociated with discharging

combustion residual leachate from landfills. For detai ls on the “Combustion Residual Leachate Input Table,” see Section 4.1.3.1. EPA did not estimate compl iance costs for combustion residual leachate from impoundments (see Section 9.1 for more deta il).

4.2.5 Gasification Wastewater

EPA identified three plants discharging gasification wast ewater. EPA identified these plants through various contacts throughout the steam ele ctric power generating industry. Since all plants discharging gasification wastewater already operate the BAT technology that is the basis for the effluent limitations in the rule, the o nly compliance costs for this wastestream are monitoring costs.

22 EPA estimated bottom ash management costs for only thos e plants that did not discharge bottom ash transport water in 2009 instead of including those plants that recycle a majority (i.e., more than 90 percent) of the bottom as h transport water, as estimated for proposal.

23 Additionally, 97 plants operate 226 generating units with a c apacity less than or equal to 400 MW and thus would incur no costs to comply with requirements for bottom as h transport water under Regulatory Option C.

24 Some plants operate steam electric generating units ab ove and below the 50 MW threshold; therefore, the number of plants is not additive.

25 As part of its analysis for the final rule, EPA als o did this for the 32 small generating units that will not i ncur costs to comply with the requirements for bottom ash transport water.Section 4 – Development of Model Inputs

4-22 4.3 CCR R ULE C OORDINATION M ETHODOLOGY

Because the final CCR rule was promulgated prior to the f inal ELGs, EPA adjusted the final ELG analyses to account for the implementation o f the final CCR rule. To do this, EPA updated its population of plants/generating units and associat ed treatment in place to account for the changes in plant operations that EPA projected under the CCR rule. Sections 4.3.1 and 4.3.2 provide a brief background on the CCR rule and a description o f how EPA used the analysis output from the CCR rule to adjust compliance cost and po llutant loading estimates for the ELGs, respectively. Section 4.3.3 presents the input table used as input for cost and loadings

models.

4.3.1 Background on CCR Rule Costing Approach

The final CCR rule establishes requirements for the ma nagement of impoundments and landfills containing CCRs. Based on the final CCR requirem ents, some plants will alter the operation of their current CCR impoundments, including th e following potential changes in operation:

• Close disposal surface impoundment 26 and open a new disposal surface impoundment in its place.

• Convert disposal surface impoundment to a new storage impound ment. 27

• Close disposal surface impoundment and convert to dry handl ing operations.

• Make no changes to the operation of the disposal surface impoundment.

The CCR rule accounts for the costs of these changes t o the impoundment operations in its costing analyses, along with the other CCR rule re quirements. Some of the inputs and methodologies used to develop the cost estimates for the CCR rule differ from those in the ELG due to differences in data sources and the analytical meth odologies used. The following identifies some of the key differences between the cos ting approaches used by the CCR rule compared to the ELG:

• The CCR rule uses a probabilistic modeling approach to esti mate compliance

costs.

• The CCR rule uses a different population of impoundments based on its survey.

• The CCR rule develops industry-level costs compared to the plant-level costs developed for the ELG.

• The CCR rule uses EIA data for the annual tonnage of as h disposed in its impoundments to estimate costs. ELG costs for fly ash a nd bottom ash use Steam Electric Survey data for the ash tonnage generated by eac h unit.

26 For the CCR rule, a disposal surface impoundment is gene rally defined as an impoundment that is not dredged and all CCRs are left in place in perpetuity.

27 For the CCR rule, a storage impoundment is generally defi ned as an impoundment that is periodically dredged and has its CCR disposed of elsewhere such that it can continue operating indefinitely.Section 4 – Development of Model Inputs

4-23 • The CCR rule evaluates costs over a 100-year time frame

.

Because of these different analytical frameworks, the CCR rule analysis did not produce the uni-level costs that would have enabled EPA to simply s ubtract the CCR rule costs from the ELG cost output. Therefore, EPA developed an approach tha t uses certain analytical outputs from the Regulatory Impact Analysis (RIA) for the CCR rule to evaluate what changes, due to the CCR rule, would occur in the industry prior to the imp lementation of the final ELGs. This approach uses the yearly probabilistic model output from th e CCR rule to evaluate the changes to specific power plants. The CCR rule output included the fo llowing information for each year in the analysis (at an impoundment level):

• Unique ORCR Pond ID (which includes the Energy Information A dministration (EIA) Plant ID).

• Year of analysis (e.g., 2015-2114). 28

• Age of the impoundment.

• Future Management Method (Baseline Scenario), which repres ents the expected decision that the plant will make regarding the impoundme nt in the absence of the CCR rule (i.e., decision made based on compliance with state regulations).

• Probability of surface impoundment converting to a stora ge impoundment and various disposal options (i.e., off-site landfill, exis ting on-site landfill, newly built on-site dug landfill, newly built on-site pile landfill ).

• Probability of surface impoundment closing, converting to dr y handling, and various disposal options (i.e., off-site landfill, exis ting on-site landfill, newly built on-site dug landfill, newly built on-site pile landfill )).

• Probability of surface impoundment closing, converting to dr y handling, and disposal in newly built on-site pile landfill built o n top of closed disposal impoundment;

• Probability of surface impoundment closing and a newly bu ilt on-site disposal surface impoundment opens in its place.

• Probability that surface impoundment has not yet reache d a decision point.

A copy of the CCR rule probabilistic output can be foun d in the “Supplemental Costs and Loadings Documentation” [ERG, 2015f; see Appendix 7].

The final CCR rule evaluated the probability of these s pecific options for only plants that were identified as operating disposal impoundments based on EIA data. 29 For the CCR rule,

28 Office of Resource Conservation and Recovery (ORCR) analyz es decisions related to the CCR rule over a 100- year analysis period. Therefore, there are 100 records fo r each disposal impoundment corresponding to each year of the analysis.

29 For the CCR rule, if a plant reported active wet CCR dis posal in one or more impoundments in its EIA data, EPA considered the largest impoundment (in terms of capacity) at the plant as a CCR disposal impoundment.Section 4 – Development of Model Inputs

4-24 EPA did not evaluate these options for storage impoundme nts because EPA assumed that storage impoundments will operate indefinitely and if a ground wat er contamination event occurs, the plant will build a new storage impoundment (but will not convert to dry handling operations), thus resulting in no change to the plant’s operation or t reatment based on the CCR rule. 30

4.3.2 Methodology for Incorporating CCR Rule Output

Using the probabilistic output from the CCR rule, EPA ev aluated the output to select the most likely compliance approach for the CCR rule for each plant/impoundment. Because the ELG is expected to be fully implemented by December 31, 2023, 31 EPA analyzed the CCR rule probabilistic output in year 2023 to determine the most likel y outcome that plants would have made by that point based on the CCR rule. This was done to identify those changes in operations that plants will make to comply with the CCR rule prio r to implementing the new requirements established by the ELG. For this analysis, EPA summed the probabilities for various disposal options for each main CCR management method decision option listed in Section 4.3.1. For example, to determine the overall probability of the pla nt converting to dry handling, EPA summed the probability for each of the following:

• Probability of surface impoundment closing, converting to dr y handing, and disposal shifts to off-site landfill.

• Probability of surface impoundment closing, converting to dr y handing, and disposal shifts to existing on-site landfill.

• Probability of surface impoundment closing, converting to dr y handing, and disposal shifts to newly built on-site pile landfill.

• Probability of surface impoundment closing, converting to dr y handing, and disposal shifts to newly built on-site dug landfill.

• Probability of surface impoundment closing, converting to dr y handing, and disposal shifts to newly built on-site pile landfill built on top of closed surface impoundment.

EPA summed the various disposal options because the importa nt aspect for this analysis is the determination of what changes will occur in the operation of the impoundment and the ash handling system, because changes in these operations ma y affect the ELG compliance costs. This was done using the CCR probabilistic model output for year 2023 and determining which CCR management method had the highest probability of occurring. In cases where two CCR management methods had the highest and equal probability in y ear 2023 (e.g., 45 percent for conversion to storage impoundments and 45 percent for convers ion to dry handling), the ELG cost analysis assumes the plant will use the CCR man agement method that has the least effect on the ELG (i.e., assuming more costs are borne by the ELG) . This approach is intended to avoid

situations where the ELG is underestimated.

30 For the CCR rule, if a plant did not report active wet CCR disposal in any impoundments in its EIA data, EPA considered all impoundments at the plant to be CCR stora ge impoundments.

31 The final ELGs require that the revised effluent limitat ions shall apply no later than December 31, 2023.Section 4 – Development of Model Inputs

4-25 The CCR Rule’s model essentially assumes that each p lant has just one disposal impoundment and all wet disposal tonnage is associated wi th that disposal impoundment; therefore, for any CCR materials (i.e., fly ash, bot tom ash, FGD solids) reported in EIA as being disposed of in on-site impoundments at those plants, all decisions made regarding the CCR management method selected for the CCR rule are assumed to apply to all generating units that

handle the CCR material wet. 32 For example, if the likely CCR management method sele cted for the CCR rule is determined to be that the impoundment cl oses and plant converts to dry handling, then EPA would make the following assumptions:

1. All generating units with wet fly ash handling at that plant are converted to dry handling under the CCR rule.

2. All generating units with wet bottom ash handling at th at plant are converted to dry handling under the CCR rule.

3. All FGD wastewater generated at the plant is directed t o an FGD chemical precipitation wastewater treatment system under the CC R rule. 33

Table 4-1 presents a list of potential CCR management met hods under the CCR rule and shows which methods (i.e., compliance approaches) would pot entially reduce the cost to comply

with the ELGs.

After determining the most likely CCR management method for the CCR rule, EPA then evaluated how that decision affects the ELG baseline po pulation. Since the final CCR rule was promulgated prior to the ELGs, all costs associated with the compliance approach selected for each plant are accounted for in the costs calculated f or the CCR rule. Similarly, all pollutant removals associated with the compliance approach selecte d for each plant (e.g., ceasing discharge of ash transport water due to converting to dry a sh handling systems) would be attributed to the CCR rule. The following describes how EP A incorporated the CCR rule into the ELG baseline population for each “Group Number” identifie d in Table 4-1:

• Group Number 1
For disposal surface impoundments that are expected to clos e and have a new disposal surface impoundment open in its place, there is no change in operation, or in the amount or characteristics of pollutants disch arged. Therefore, there is no effect on the ELG baseline population.

• Group Number 2
For disposal surface impoundments that are expected to conv ert to a storage impoundment, the CCR material that was previously stored i n the disposal surface impoundment will now be disposed by the plant in an on-site or off-site landfill.

32 This plant-level approach carries through to the ELG anal ysis. To determine which generating units the future management method applies to, EPA identified generating units with wet handling based on responses to the Steam Electric Survey.

33 If the plant had not reported disposal of FGD solids in t he EIA data, EPA would assume that the FGD wastewater at the plant would continue to be transferred to the cur rent baseline treatment system (e.g., surface impoundm ent).Section 4 – Development of Model Inputs

4-26 This change in operations would occur prior to the plant taking action to comply with new requirements established by the ELGs. With the p lant now using a storage impoundment instead of a disposal impoundment, CCRs no longer remain for extended periods in the impoundment. This means that t he plant is now regularly dredging solids from the impoundment and then tra nsporting them to an on-site or off-site landfill for disposal (or, potenti ally, sending the solids to beneficial use). As a result, should the plant later convert to dry ash handling to comply with the ELG, there would be no transport/disposa l attributable to the ELG because these solids are already being hauled to th e disposal site by the plant. In fact, the plant would likely realize cost savi ngs attributable to the ELG by converting to dry ash handling because it costs less to transport and dispose of ash from a dry handling system than disposing of ash stor ed in an impoundment. For FGD wastewater, however, under the operation of th e storage impoundment, only the FGD solids entering the impoundment would need to b e removed, transported, and disposed of under the CCR rule, but under the ELG, the plant would also need to transport and dispose of all treatment system solids resulting from the FGD chemical precipitation and biological tre atment system. Therefore, EPA did not make any adjustments to the ELG baseline popu lation for FGD solids disposal for these plants.

• Group Number 3
For disposal surface impoundments that are expected to clos e and convert to dry handling, EPA assumed that plants will convert their fly ash and bottom ash handling systems to dry systems and the plant will inst all a chemical precipitation system to handle the FGD wastewater. Therefore, EPA adjusted the ELG baseline population as follows for each wastestream: 34

Fly ash transport water: Plant operates a dry fly ash handling and all fly ash is disposed of.

Bottom ash transport water: Plant operates a dry bottom a sh handling and all bottom ash is disposed of.

FGD wastewater: Plant operates a full BAT chemical pre cipitation system and all solids from the chemical precipitation system are dis posed of.

• Group Number 4
For disposal surface impoundments that are not expected to r each a decision point by year 2023, there is no change in operation and, therefor e, there is no effect on the ELG baseline population.

34 The changes to the ELG baseline population only apply to th e CCR materials that the plants reported disposing of in the EIA, in which case, the CCR rule is accounting fo r the costs for the conversion. For example, if a pla nt reported disposal tonnages for fly ash and bottom ash but not for FGD solids, then EPA would apply the ELG baseline population changes described in the bullets to fly ash transport water and bottom ash transport water, but EPA would not make any changes to the ELG baseline populat ion for FGD wastewater.Section 4 – Development of Model Inputs

4-27 For the CCR rule, EPA assumed that storage impoundments will operate indefinitely and if a ground water contamination event occurs, the plant will build a new storage impoundment.

EPA reviewed the EIA data that it used for the CCR rule t o identify the plants operating only storage impoundments under the CCR rule. For these plants , EPA evaluated whether fly ash and/or bottom ash were reported as “disposed” in the EIA data. Because the plants reported to EIA that they are disposing of those CCR materials in places other than the impoundments (e.g., landfill, beneficial reuse), EPA assumed that there wo uld be no incremental change to the transportation and disposal costs for these plants aft er conversion to dry handling operations. For example, if a plant’s current operation consists of w et sluicing fly ash to an impoundment, dredging the solids on an annual basis, and disposing of the solids in an off-site landfill, EPA

assumed that there would be no increase in the costs f or that transportation/disposal compared to trucking the dry fly ash to the same off-site landfill a fter the plant converts to a dry fly ash handling system to comply with the final ELG. As such, E PA flagged these plants and the wastestreams associated with the materials meeting this criteria in Group Number 2 (Disposal Surface Impoundment Converts to Storage Impoundment) to indi cate that all fly ash and/or bottom ash is already disposed of by the plant [ERG, 2015f ; see Appendix 7].

4.3.3 CCR Rule Coordination Input Table

Based on these analyses described in Section 4.3.2, EPA ge nerated the “CCR Input Table” that was used in the costs model and loadings datab ases to adjust the ELG baseline population to account for the final CCR rule.

After adjusting the ELG population to account for the im plementation of the final CCR rule, EPA generated the costs, pollutant loadings, non -water quality impacts, environmental assessment, and benefits of the rule. As such, EPA ha s minimized the degree to which its analyses have potentially “double counted” compliance cos ts and benefits associated with the final ELG and the final CCR rule. A copy of the “CCR I nput Table” is located in the FGD and

Ash Steam Electric Cost Model as well as the models us ed to calculate pollutant loadings [ERG, 2015d]. Table 4-2 presents the number of plants and stream elec tric generating units for which EPA estimated compliance costs associated with the EL G accounting for the CCR rule, and Table 4-3 presents the number of plants and steam electr ic generating units expected to achieve pollutant removals as a result of the ELG accounting fo r the CCR rule.

As discussed earlier in Section 1, EPA conducted a sensiti vity analysis to evaluate estimated compliance costs and pollutant loadings assoc iated with the ELG without including adjustments for the CCR rule. A copy of the plant-s pecific data used to estimate compliance costs for the ELG without adjusting for CCR is located in the FGD and Ash Steam Electric Cost Model [ERG, 2015d]. A copy of the plant-specific data used to estimate pollutant loadings for the ELG without adjusting for CCR is located in the vario us pollutant loadings models (FGD Pollutant Loadings Database or Ash Loadings Database) [ERG, 2015b; ERG, 2015e]. Plant-level compliance cost estimates and pollutant loadings witho ut the CCR rule are included in Appendix B. All compliance cost estimates and pollutant loadings and removals discussed in this report hereafter reflect the baseline population with updates fo r the final CCR rule.Section 4 – Development of Model Inputs

4-28 4.4 P OLLUTANT C ONCENTRATIONS

EPA calculated analyte-level pollutant loadings for eac h of the technology options considered as part of the Steam Electric ELGs. Section s 11 through 14 discuss the calculation of these pollutant loadings in detail. The pollutant loadin gs are calculated from wastestream characterization data collected through EPA sampling acti vities, Steam Electric Survey data, other EPA data requests, and publicly available sources. Sect ions 11 through 14 discuss pollutant loadings for each of the wastestreams considered for re gulation:

• FGD wastewater.

• Fly ash transport water.

• Bottom ash transport water.

• Combustion residual leachate.

• Flue gas mercury control wastewater.

• Gasification wastewater.

4.5 P LANT C HARACTERISTICS

EPA used a variety of plant-specific data from public sourc es and the Steam Electric Survey to develop input tables and cost factors used to calc ulate the plant-specific costs and loadings associated with the revisions to the Steam Elec tric ELGs. Section 4.5 goes into detail on the types of data that were used to adjust the population o f plants incurring compliance costs and pollutant loadings. This section discusses the followin g topics:

• Methodology for identifying existing FGD wastewater treatme nt at plants discharging FGD wastewater and not affected by the CCR r ule (see Section 4.5.1).

• Approach for handling FGD wastewater treatment systems with an average 24- hour FGD wastewater flow greater than or equal to 1,000 gall ons per minute (gpm) (see Section 4.5.2).

• Evaluation of climate information to assess the need f or additional infrastructure at plants located in specific cold climates (see Sectio n 4.5.3).

Further description of how these specific characteristic s were used to adjust an individual cost element is discussed in Sections 6 through 10 as they appl y to each wastestream.

4.5.1 FGD Treatment-in-Place Input

For those plants discharging FGD wastewater and not aff ected by the CCR rule, EPA also documented the type of treatment system they operat e. 35 Table 4-4 includes data on each plant’s current level of treatment for its FGD waste water. For plants currently treating the FGD wastewater using a chemical precipitation, an anoxic/an aerobic biological treatment, or an

35 EPA also evaluated existing FGD wastewater treatment f or those plants effected by the CCR rule in order to more accurately estimate compliance costs and pollutant loadi ngs associated with the sensitivity analysis that eval uates costs and loadings for all generating units without the CC R rule or Clean Power Plan (CPP) rule.Section 4 – Development of Model Inputs

4-29 evaporation system, EPA assessed credit for existing tr eatment systems as part of the costs and loadings models. EPA used survey data and industry-submitted dat a to determine the appropriate level of baseline treatment. A description of how EPA used Steam Electric Survey data to assess the level of treatment in place is presented in Secti ons 6.1.3 and 11.3. A list of all plants adjusted for the costs and loadings analysis as a result of t reatment upgrades announced since the Steam Electric Survey is included in the “Changes to Industry Prof ile for Steam Electric Generating

Units for the Steam Electric Effluent Guidelines Final Rule” [ERG, 2015a]. Table 4-4 lists the plant identification numbers for those plants identifi ed as having some amount of treatment in place for each type of technology.

4.5.2 High-Flow FGD Treatment Systems

EPA categorized five plants with an average 24-hour plant- level FGD wastewater flow rate greater than or equal to 1,000 gpm as “high-flow” plant s. For these plants with high FGD wastewater flows, EPA determined it would be less expensive for a plant to implement additional recycle within the FGD system to allow for i nstalling a treatment system with a lower overall treatment flow rate, rather than install a F GD wastewater treatment system capable of treating the maximum wastewater flow. However, some F GD systems already operate at or near the maximum chlorides operating concentration and, theref ore, would not be able to increase their level of recycle without potentially corroding t he FGD scrubber system.

EPA used data from the Steam Electric Survey to identify the FGD systems with the potential capability to recycle some of the FGD wastewat er and to quantify the amount of recycle that can be accommodated without corroding the F GD scrubber system. Wherever possible, based on a plant’s operating chlorides concentrat ion and maximum design chlorides concentration, EPA adjusted the wastewater flow used t o estimate costs associated with the FGD wastewater treatment system to reflect a smaller FGD wastewater flow. EPA expects that these plants will choose to reuse some of the FGD wastewat er as absorber make-up water, reagent preparation water. EPA’s methodology, described in Sectio n 6, includes capital and operation and maintenance costs associated with a pump and piping to transfer the recycled FGD wastewater from the treatment system back to the scrubb er. EPA’s methodology does not expect plants to modify existing FGD scrubbers to include new re circulation pumps on the absorber.

For all “high-flow” plants without some level of trea tment in place, EPA compared each FGD system’s current operating chlorides level to the spec ified maximum design chlorides limit reported by each plant in Part B, Section 4 (Flue Gas Des ulfurization Systems – Wet FGD System Information) of the Steam Electric Survey. Bas ed on site visit discussions and data from the industry, EPA determined that plants can operate up to 80 percent of the maximum design chlorides level without significant corrosion concerns. 36 As a result, EPA identified any system operating below 80 percent of the plant-specific maximum d esign level threshold reported in the Steam Electric Survey as having the potential to recycle some FGD wastewater. In cases where plants provided public comments indicating a specific chlor ides operating limit lower than the 80 percent of the plant-specific maximum design level thres hold reported in the Steam Electric

36 EPA notes that some plants reported in response to the Steam Electric Survey as operating the FGD scrubber system at or above the maximum design chlorides concentra tion. However, EPA does not believe that is a sustainable approach for the long-term life of the FGD system.Section 4 – Development of Model Inputs

4-30 Survey, EPA used the chlorides value from comments instea d. Three of the five “high-flow” plants were identified as having the potential to impleme nt some level of FGD wastewater recycle. For the other two “high-flow” plants, EPA det ermined that no amount of FGD wastewater recycle could be achieved and, therefore, EPA made no adjustments to the wastewater flow rate and costed these plants to treat the full FGD wastewater flow rate.

For the three “high-flow” plants where EPA determined t hat recycle could be implemented, EPA then calculated a new FGD wastewater treatment flow rate and the flow of the FGD recycle stream. The new FGD wastewater treat ment flow rate was calculated based on the acceptable degree of flow reduction a given system can accommodate without exceeding 80 percent of the plant-specific maximum chlorides limit repo rted in the Steam Electric Survey. EPA used Equations 4-14 and 4-15 to calculate the new FGD wast ewater treatment flow rate. For more discussion on how these equations were developed, see the “Supplemental Costs and Loadings Documentation” [ERG, 2015f; see Appendix 8].

(4-14) Acceptable Degree of Flow Reduction = (Max Design Cl Lev el × 0.8 – Operating Cl Level) / Operating Cl Level

(4-15)

New FGD Wastewater Treatment Flow = Current FGD Wast ewater Treatment Flow / (1+ Additional Recycle Passes)

where:

Max Design Cl Level = Maximum design chlorides concent ration as reported in Part B, Section 2 of the Steam Electric Survey.

Operating Cl Level = Typical operating chlorides concentr ation in the FGD scrubber as reported in Part B, Section 5 of the Steam Electric Survey.

Current FGD Wastewater

Treatment Flow = Current FGD wastewater treatment flow rate as reported in the Steam Electric Survey.

Acceptable Degree of Flow

Reduction = Number of additional scrubber passes that can be achieved based on operating chloride concentration (see Equation 4-14).

The flow of the recycle stream was calculated as the differential between the current FGD

wastewater treatment flow and the new FGD wastewater treatment flow.

EPA developed a “High-Flow FGD Input Table” to hold plant-s pecific information on the five “high-flow” plants evaluated for FGD recycle. The “High-Flow FGD Input Table” is included in the FGD and Ash Steam Electric Cost Model [ER G, 2015d]. Section 6 provides detail on how costs for these high flow plants were e stimated.Section 4 – Development of Model Inputs

4-31 4.5.3 Cold Climate Plants

EPA’s cost methodologies for estimating compliance co sts for FGD wastewater biological treatment and remote mechanical drag systems for bottom ash account for costs associated with constructing and erecting buildings to hous e treatment equipment for plants located in cold climates. For the biological treatment system, these buildings serve to protect microorganisms from freezing and, for the remote mechanica l drag system, the buildings protect equipment from winter exposure and cold temperature as wel l as protect workers during routine

maintenance activities.

Using latitude and longitude data from the Steam Electric Survey, EPA compared the plant location to a map of mean daily minimum temperatur es downloaded from the National Oceanic and Atmospheric Administration’s (NOAA’s) Nationa l Climate Data Center. Figure 4-1 is the map obtained from NOAA’s website. Using the plan t-specific coordinates, EPA identified 38 plants located in areas with a mean daily minimum tem perature at or below 32°F and determined that these plants would require buildings to prote ct wastewater treatment equipment.

EPA developed a “Cold Climate Input Table” table to identify which plants would require additional building costs for bottom ash and/or FG D wastewater biological treatment.

See Sections 6.2.5.6 and 8.2 for more detailed information o n how the specific building costs are handled for FGD wastewater biological treatment and bo ttom ash dry handling technologies, respectively. A copy of the “Cold Climate Input Table” is included in the FGD and Ash Steam Electric Cost Model [ERG, 2015d].

4.6 D ISPOSAL OF C OMBUSTION R ESIDUALS

EPA also used plant-specific data from the Steam Electr ic Survey to develop the input tables used to estimate the transport, disposal, and surfac e impoundment operating costs associated with solids resulting from the ELGs (e.g., dr y ash that was previously deposited in impoundments or solids from the FGD wastewater treatmen t system). Costs associated with transportation and disposal of combustion residuals gener ated as a result of the ELG are based on whether plants utilize an on-site or offsite-landfi ll. Section 4.6.1 provides more detail on the input table associated with transportation and disposal co sts. Costs associated with surface impoundment operation are cost savings based on whether pl ants currently operate an impoundment containing specific types of combustion residuals that will no longer be deposited in an impoundment as a result of the ELG. Section 4.6.2 pr ovides more detail on the input table associated with surface impoundment operation costs.

4.6.1 Combustion Residual Landfills

To estimate transport and disposal costs, EPA evaluated P art A Steam Electric Survey data to determine the population of plants with on-site ac tive or inactive landfills containing combustion residuals including FGD solids, fly ash, and/or bottom ash. This input table, called the “Landfill Input Table,” determines the type of transpo rt and disposal costs (i.e., on-site or off-site) estimated for the plant. EPA assumed that i f a plant already has an on-site landfill, the plant would dispose of the additional wastes generated as a result of the final ELGs in the on-site landfill. If a plant does not have a currently operati ng on-site landfill, EPA assumed that the plantSection 4 – Development of Model Inputs

4-32 would dispose of the combustion residuals at an off-site landfill. A copy of the “Landfill Input

Table” is located in the FGD and Ash Steam Electric Co st Model [ERG, 2015d].

4.6.2 Combustion Residual Surface Impoundments

EPA also evaluated Part A Steam Electric Survey data to de termine the population of the plants operating one or more surface impoundments contai ning combustion residuals. The “Surface Impoundment Input Table” designates the specific co mbustion residual waste(s) (i.e., FGD solids, fly ash, and/or bottom ash) stored in surfac e impoundments located at the plant. A copy of the “Surface Impoundment Input Table” is located in the FGD and Ash Steam Electric Cost Model [ERG, 2015d].

4.7 R EFERENCES

1. ERG. 2015a. Eastern Research Group, Inc. “Changes to Industry Profile for Steam Electric Generating Units for the Steam Electric Effl uent Guidelines Final Rule.” (30 September). DCN SE05069.

2. ERG. 2015b. Eastern Research Group, Inc. Ash Loadings Mo del, Accounting for CCR. (30 September). DCN SE05584.

3. ERG. 2015c. Eastern Research Group, Inc. Combustion Resi dual Leachate Loadings Database. (30 September). DCN SE05840.

4. ERG. 2015d. Eastern Research Group, Inc. FGD and Ash Stea m Electric Cost Model. (30 September). DCN SE05841.

5. ERG. 2015e. Eastern Research Group, Inc. FGD_CCR Loadings Database. (30 September). DCN SE05866.

6. ERG. 2015f. Eastern Research Group, Inc. “Supplemental Cost s and Loadings Documentation.” (30 September). DCN SE05839.

7. U.S. EPA. 2015. U.S. Environmental Protection Agency. Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category . (30 September). DCN SE05904.Section 4 – Development of Model Inputs

4-33 Table 4-2. Number of Steam Electric Plants and Generating Un its Expected to Incur Compliance Costs by Wastestream and Regulatory Option Accounting for CCR

Regulatory Option FGD

Wastewater Fly Ash

Transport

Water Bottom Ash

Transport

Water Combustion

Residual

Leachate Gasification

Wastewater FGMC

Wastewater Total a

A 87 ( 215 units) 19 ( 45 units) 0 0 3 ( 3 units) 0 100 ( 236 units)

B 87 ( 215 units) 19 ( 45 units) 0 0 3 ( 3 units) 0 100 ( 236 units)

C 87 ( 215 units) 19 ( 45 units) 78 ( 147 units) 0 3 ( 3 units) 0 139 ( 306 units)

D 87 ( 215 units) 19 ( 45 units) 141 ( 313 units) 0 3 ( 3 units) 0 181 ( 408 units)

E 87 ( 215 units) 19 ( 45 units) 141 ( 313 units) 82 ( 19 6 units) 3 ( 3 units) 0 196 ( 444 units)

a – The number of plants and generating units incurring cos ts is not additive for each regulatory option because some plants and units may incur costs for multiple wastes treams.

Table 4-3. Number of Steam Electric Plants and Generating Un its Expected to Achieve Pollutant Removals by Wastestream and Regulatory Option Accounting for CCR

Regulatory Option FGD

Wastewater Fly Ash

Transport

Water Bottom Ash

Transport

Water Combustion

Residual

Leachate Gasification

Wastewater FGMC

Wastewater Total a

A 36 ( 89 units) 25 ( 61 units) 0 0 0 0 54 ( 131 units)

B 71 ( 176 units) 25 ( 61 units) 0 0 0 0 86 ( 207 units)

C 71 ( 176 units) 25 ( 61 units) 7 3 ( 137 units) 0 0 0 1 22 ( 273 units)

D 71 ( 176 units) 25 ( 61 units) 1 32 ( 297 units) 0 0 0 1 62 ( 373 units)

E 71 ( 176 units) 25 ( 61 units) 132 ( 297 units) 82 ( 19 6 units) 0 0 1 84 ( 425 units)

a – The number of plants and generating units expected to achie ve pollutant removals is not additive for each regulatory option because some plants and units may achieve removals for multiple wastestreams. Table 4-1. CCR Rule Compliance Approaches and Overlap with E LG Costs/Loadings

Likely Future Management Method (i.e., Compliance Approach) Selected for the

CCR Rule in Year 2023 Group

Number Does Not Affect

ELG Costs & Loadings Affects ELG FGD

and/or Ash Costs & Loadings Affects ELG

Transport & Disposal Costs Disposal Surface Impoundment Closes, New Disposal Surface Impoundment Opens in Place 1 

Disposal Surface Impoundment Converts to Storage Impoundment 2 

Disposal Surface Impoundment Closes, Converts to Dry Handling 3  

Disposal Surface Impoundment

Does Not Reach a Decision Point by Year 2023 4 Section 4 – Development of Model Inputs

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

Highest Level of FGD Wastewater

Technology Steam Electric Survey Plant ID Numbers Plants with Treatment in

Place

Chemical Precipitation 00103, 00771, 01236, 01381, 01402, 02079, 02268, 02297 ,02383, 02536, 03196, 03200, 03265, 03709, 03831, 04122, 04237, 04533, 04679, 05015, 05318, 05477, 05570, 06283, 06377, 06616, 07256, 07785, 08308, 08353, 08661, 09161, 09225, 09671, 09805, 09948

Anoxic/Anaerobic Biological Treatment 02550, 04543, 08661, 09391

Evaporation 03095, 06689Section4– Development of Model Inputs4-35Figure 4-1. Map of Steam Electric Power Plants by Mean Daily Minimum Temperature[Sections 5, 6, 7, and 8 contain Confidential Business Information and have been removed
from this document]Section 9 – Combustion Residual Leachate Cost Methodology

9-1 

## 9. COMBUSTION RESIDUAL LEACHATE COST

METHODOLOGY

Combustion residuals can include flue gas desulfurization ( FGD) solids, fly ash, and/or bottom ash. Some plants collect and discharge combustio n residual leachate from landfills and impoundments containing these combustion residuals. EPA e stimated capital and operation and maintenance (O&M) costs associated with installing an d operating a chemical precipitation treatment system to treat combustion residual leachate from landfills. EPA finds that plants with combustion residual leachate from surface impoundments ar e not likely to incur costs associated with any leachate requirements (see Section 9.1). Where a plant generates both landfill combustion residual leachate and FGD wastewater, EPA e valuated the combustion residual leachate compliance costs separate from the FGD waste water treatment (i.e., those plants discharging combustion residual leachate and FGD wastewa ter would install two separate wastewater treatment systems, one to treat the comb ustion residual landfill leachate and one to treat the FGD wastewater).

The remainder of this section describes the capital and O &M costs associated with treating combustion residual landfill leachate.

9.1 T ECHNOLOGY D ESCRIPTION

EPA estimated compliance costs for plants generating com bustion residual leachate from landfills or surface impoundments to comply with the ef fluent limitations guidelines and standards (ELGs) based on treatment by the chemical prec ipitation technology.

Section 6.1 details EPA’s methodology for calculating p lant-specific costs for a chemical precipitation treatment system for the treatment of FGD wastewater. These same cost methodologies were used to generate plant-level costs for the treatment of combustion residual landfill leachate. The equations presented in Section 6.1 were applied to the flow rate of combustion residual leachate from a landfill containing combustion residuals, referred to as ‘leachate flow’ throughout this section. Section 4.2.4 de scribes EPA’s methodology for estimating leachate flows for those plants identified a s discharging leachate from landfills containing combustion residuals.

Plants that generate surface impoundment leachate will l ikely use a different approach than installing the technology basis to comply with limit ations or standards imposed on combustion residual leachate. EPA determined that 40 percen t of plants generating combustion residual leachate from impoundments containing combustion r esiduals recycle the combustion residual leachate back to the impoundment from which it wa s collected. Additionally, some plants use the impoundment leachate for dust control at a landfill or to moisture-condition ash transported to a landfill. Based on these data, EPA det ermined that if the final rule included a limitation on the discharge of combustion residual leac hate, plants would comply with the limitation by recycling the leachate back to the impoundm ent from which it was generated (or use the leachate for dust control/moisture conditioning) i nstead of installing the technology option to treat and discharge the wastewater because i t is a less expensive alternative. There are negligible costs associated with recycling the leachate back to the impoundment because theSection 9 – Combustion Residual Leachate Cost Methodology

9-2 plant will either: 1) use the existing pump that transfer s the leachate to a separate location to pump it back to the impoundment; or 2) install a pump to t ransfer the leachate to the impoundment, in which case the costs would be offset bec ause the plant no longer needs to operate a separate impoundment (or other treatment system ) to treat the leachate to meet the existing Best Practicable Control Technology Currently A vailable (BPT) effluent limitations prior to its discharge. Therefore, there are no complia nce costs for combustion residual leachate from surface impoundments. Where this section further a ddresses the costing methodology for combustion residual leachate, it refers to the costs a ssociated with the treatment of combustion

residual leachate from landfills.

9.2 P OPULATION C OSTED

An incremental compliance cost for combustion residual leachate is assessed to any plant identified as collecting and discharging leachate from a landfill containing combustion residuals. EPA used data from Part A (Steam Electric Power Plant Operations) and Part F (Management Practices for Ponds/Impoundments and Landfills) of the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey) to identify plants dischargi ng landfill leachate. For the reasons explained in Sectio n 9.1, EPA focused on leachate collection and discharge from active, inactive, or open landfills , and excluded plants that have announced plans to retire generating units prior to December 31, 2023, a s described in Section 4.2. There are no compliance costs for plants that are already planne d to retire all generating units contributing combustion residuals to the landfills prior to implement ation of the ELGs. EPA identified 85 plants as discharging combustion residual landfill leac hate from an active, inactive, or open landfill containing combustion residuals and not retirin g prior to December 31, 2023.

9.3 I NPUT T ABLE

As discussed in Section 4.1.3.1, EPA used Steam Electric S urvey data to identify which plants discharge or have the potential to discharge combus tion residual landfill leachate and

determine the estimated leachate treatment costs for th ese plants. The “Landfill Leachate Input Table” holds all the input data needed to calculate the t echnology option cost for combustion

residual leachate treatment. The table contains the fo llowing fields:

• Plant_id: Steam Electric Survey Plant ID.

• Landfill_id: Steam Electric Survey Landfill ID (only valid for plants completing Part F of the Steam Electric Survey 92 ).

• Landfill_Type: Type of landfill designation (i.e., active or inacti ve).

• Leachate_GPD: Combustion residual leachate flow in gallons per day, f rom Question F3-13 for all plants completing Part F of the S team Electric Survey.

92 Part F of the Steam Electric Survey collects data r elated to the management practices of impoundments and

landfills. As described in Section 3 of the Technical Development Document for the Effluent Limitations Gu idelines and Standards for the Steam Electric Power Generating Point Source Cat egory , [U.S. EPA, 2015], this portion of the survey was distributed to only a subset of coal- and petroleum coke-fired power plants.Section 9 – Combustion Residual Leachate Cost Methodology

9-3 93 Calculated value for all plants that did not complete Part F (Management Practices for Ponds/Impoundments and Landfills).

• CBI Flag: Flag indicating that the resulting costs should be hand led as Confidential Business Information (CBI). CBI flag is mar ked if any data used to populate the input table were marked as CBI by the plant.

Section 4.1.3.1 provides more detail on the methodology used to determine the

combustion residual landfill leachate flow rate. A co py of the “Landfill Combustion Residual Leachate Input Table,” which includes only flow rates for l andfill leachate from the “Combustion Residual Leachate Input Table,” is included in t he Combustion Residual Leachate Steam Electric Cost Model [ERG, 2015].

9.4 C APITAL C OST M ETHODOLOGY

Capital costs associated with chemical precipitation are included in Section 6.1.6. The equations presented in Section 6.1.6 along with the combustio n residual leachate flow rate discussed in Section 9.3 were used to estimate capital cost s associated with a chemical precipitation treatment system to treat combustion res idual landfill leachate.

9.5 O&M C OST M ETHODOLOGY

O&M costs associated with chemical precipitation can be found in Section 6.1.7. The equations presented in Section 6.1.7 along with the combustio n residual leachate flow rate

discussed in Section 9.3 were used to estimate O&M costs a ssociated with a chemical precipitation treatment system to treat combustion res idual landfill leachate.

9.6 S LUDGE D ISPOSAL C OST

EPA determined dewatered sludge generation rates for the chem ical precipitation treatment technology option using the methodology descri bed in Section 6.1.8. Sections 5.3 and 5.4 discuss costs for the transportation and disposal of t he sludge generated by each technology option.

9.7 C OMPLIANCE M ONITORING C OST

All plants costed for a combustion residual leachate wa stewater treatment system incurred a cost for compliance monitoring. Section 5.2 discus ses costs for compliance monitoring.

9.8 S URFACE I MPOUNDMENT O PERATION C OSTS

Section 5.5 discusses cost savings associated with ceasing ope ration of combustion residual surface impoundments. EPA assumes that plants c urrently operating a surface

93 Part F of the Steam Electric Survey collects data r elated to the management practices of impoundments and

landfills. As described in Section 3 of the Technical Development Document for the Effluent Limitations Gu idelines and Standards for the Steam Electric Power Generating Point Source Cat egory , [U.S. EPA, 2015], this portion of the survey was distributed to only a subset of coal- and petroleum coke-fired power plants.Section 9 – Combustion Residual Leachate Cost Methodology

9-4 impoundment for leachate collection will continue to do so and, therefore, there are no cost savings accounted for in the combustion residual landfill leachate costing methodology.

9.9 T REATMENT S YSTEM O UTAGE C OSTS

Combustion residual leachate is defined as liquid that has percolated through or drained from waste or other materials placed in a landfill. T he flow of combustion residual leachate is not critical to the operation of the steam electric pow er plant. Combustion residual leachate flow rate can be intermittent, stopping or starting at any ti me regardless of whether the plant is operating or experiencing a temporary outage for maintenanc e. Because the flow can be stopped or started at any point without effecting plant operation , EPA included no additional costs associated with outage time to enable plants to install and connect the leachate treatment system. The entire treatment system can be installed at any ti me, and then the combustion residual leachate can be rerouted to direct flow through the new t reatment system.

9.10 R ESULTS AND S UMMARY OF C OSTS

As described in Section 2.1.4, EPA’s combustion residual lea chate cost model generated plant-level compliance costs for the chemical precip itation technology option. The cost output generated by the model includes a breakout of specific capita l and O&M cost elements, including equipment costs, direct capital costs, indirect capital costs, operating labor, maintenance labor, and energy costs. The output also includes costs for the common cost elements described in Section 5. The plant-level costs f or the treatment of combustion residual leachate are included in Appendix B.

9.11 R EFERENCES

1. ERG. 2015. Eastern Research Group, Inc. Combustion Residua l Leachate Steam Electric Cost Model. (30 September). DCN SE05842.

2. U.S. EPA. 2015. U.S. Environmental Protection Agency. Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category . (30 September). DCN SE05904.Section 10 – Gasification Wastewater Cost Methodology

10-1 

## 10. GASIFICATION WASTEWATER COST METHODOLOGY

EPA evaluated one technology option (evaporation) for th e treatment of gasification wastewater generated from integrated gasification combined cycle (IGCC) process operations.

10.1 P OPULATION C OSTED

From the Questionnaire for the Steam Electric Power Generating Effluent Guidel ines (Steam Electric Survey) and publicly available data, EPA i dentified three plants currently operating, or planning to operate, IGCC generating units. 94 All three of these plants already operate (or will operate prior to implementation of the final effluent limitations guidelines and standards (ELGs)) the technology option selected as th e Best Available Control Technology Economically Achievable (BAT), evaporation. Because thes e three plants each already operate the BAT technology, there are no incremental capital or O&M costs attributable to the ELG associated with installing and operating the treatment tec hnology.

10.2 C OST M ETHODOLOGY

While no equipment or additional operation and maintenance l abor is required at these plants, EPA did estimate costs associated with addition al compliance monitoring activities. The

final ELGs will establish effluent limitations for:

• Arsenic.

• Mercury.

• Selenium.

• Total dissolved solids.

EPA estimated costs for these three plants to sample and analyze their discharges to assess compliance with the final effluent limitations. Section 5.2 discusses costs for compliance monitoring. Also see the “Supplemental Costs and Loadings Documentation” for the detailed calculation of gasification wastewater compliance co sts [ERG, 2015; see Appendix 100].The plant-level costs for the treatment of gasification wastewater are included in Appendix B.

10.3 R EFERENCES

1. ERG. 2015. Eastern Research Group, Inc. “Supplemental Cos ts and Loadings Documentation.” (30 September). DCN SE05839.

94 EPA is also aware of the Kemper County Energy Facili ty that will include an IGCC unit. According to the operating company’s website, the plant will not discharge a ny gasification wastewater and, therefore, the plant w ill not incur any costs to comply with the ELGs.Section 11 – FGD Wastewater Pollutant Loadings

11-1 

## 11. FGD WASTEWATER POLLUTANT LOADINGS

This section discusses annual pollutant loadings and removal estimates from existing steam electric power plants that discharge flue gas desulf urization (FGD) wastewater. As previously discussed in Section 4.1.1, EPA identified 88 plants 95 that operate wet FGD systems and discharge the FGD wastewater to a surface water or POTW. For these plants, EPA evaluated two technology options as the basis of the final disch arge requirements for FGD wastewater: chemical precipitation and chemical precipitation foll owed by biological treatment. 96 EPA defined baseline loadings, post-compliance pollutant loadings , and pollutant removals for FGD

wastewater as follows:

• Baseline Loadings . Estimated pollutant loadings, in pounds per year, of FG D wastewater discharged directly to surface water or indir ectly to surface water through publicly owned treatment works (POTWs) at the curren t level of treatment (i.e., treatment in place) and prior to imp lementing controls to comply

with the final rule.

• Post-Compliance Loadings . Estimated pollutant loadings, in pounds per year, of FGD wastewater after implementation of the technolog y option. EPA calculated these loadings assuming that all steam electric power plants subject to the requirements would install and operate wastewater treatm ent and pollution prevention technologies equivalent to the technology bas es for the regulatory options (i.e., chemical precipitation and chemical pre cipitation with biological treatment) for FGD wastewater.

• Pollutant Removals . The difference between the baseline loadings and postcompliance loadings for each technology option.

Pollutant loadings calculations require a pollutant-specific concentration and plantspecific discharge flow rate. EPA determined the pollutant- specific concentrations for each plant by evaluating the effluent characterization data and the pollutant-specific treatment effectiveness of each treatment technology, which is further discusse d in Section 11.1. EPA also identified FGD wastewater flow rates for the 88 plants, which is d iscussed in Section 11.2. The remainder of the section (Sections 11.3 and 11.4) describes pollutant lo adings calculations and presents the summary of the results. All tables and figures referenc ed in this section are presented at the end

of the section.

95 One plant operates only oil-fired generating units and/or gene rating units with a generating capacity of 50 MW or less; therefore, this plant is not facing any more s tringent requirements than already existed under preexistin g Best Practicable Control Technology Currently Available (BP T) regulations. As such, EPA assumed that this plant will not install the technology basis and, therefore, will not incur any compliance costs. Additionally, EPA as sumed it will continue to discharge FGD wastewater at its curren t baseline level and will not achieve any pollutant re movals for the technology options evaluated.

96 As discussed in Section 6.3.11, EPA evaluated costs for eva poration but decided not to evaluate evaporation as a technology option for existing sources in the final rule due primarily to its high cost; see “Plant-Specific Co mpliance

Cost Estimates for the Treatment of FGD Wastewater with Chemical Precipitation Followed by Evaporation”for more details [ERG, 2015e].Section 11 – FGD Wastewater Pollutant Loadings

11-2 11.1 E FFLUENT C ONCENTRATION M ETHODOLOGY

EPA collected and received FGD characterization data fro m sources described in Section 3 of this report. In developing the pollutant-specific conce ntrations used in the pollutant loadings calculations, EPA reviewed characterization data that r eflect four treatment systems currently in place at steam electric power plants for FGD wastewat er: FGD surface impoundment effluent, chemical precipitation effluent, chemical precipitati on followed by biological treatment effluent, and evaporation treatment effluent. For effluent concentr ations used to calculate both baseline and post-compliance pollutant loadings, EPA considered eff luent characterization data from plants operating only Best Available Control Technology Economically Achievable (BAT) for chemical precipitation and biological treatment. Two pl ants operate evaporation at baseline; therefore, EPA also used effluent characterization data from this technology to accurately reflect the baseline loadings for these two plants.

EPA also reviewed other data sources outside the FGD data EPA described in Section 3 to determine if additional data were available to support t he analyses. For FGD wastewater, EPA

determined that there were no additional data sources that met the criteria to supplement the EPA sampling program data, Clean Water Act (CWA) 308 monitoring da ta, and the industrysubmitted plant monitoring data that are the basis of the FGD pollutant loadings calculations. A summary of EPA’s review is presented in “Development M emorandum for the Steam Electric Analytical Database for the Final Rule” [ERG, 2015b]. E PA review of available data sources considered the following general criteria applied across a ll wastestreams:

• Sample results must contain sufficient information (i .e., contain method detection limits or quantitation limits).

• Sample locations must be unambiguous and clearly described such that it can be categorized by type (e.g., bottom ash pond effluent rather than pond effluent with no further definition).

• Sample must be representative of typical full-scale plant operations (e.g., not a simulated sample of partially treated wastewater).

• Sample analysis must be completed using accepted analytic al methods for

untreated wastewater.

• Data must not be duplicative of other accepted data. Where dup licate data exists (e.g., submitted by a trade association representing indiv idual plants and also submitted by the individual plant), EPA used only accepted data collected from the individual plant.

For biphasic samples (i.e., those with solids content greater than 1 percent), sample analysis must provide results for both phases.

In its review, EPA also excluded sample-specific data t hat were not usable in the development of effluent characterization data. The data exclusions are documented in detail in the development memorandum [ERG, 2015b]. EPA excluded data fo r a number of reasons, including:Section 11 – FGD Wastewater Pollutant Loadings

11-3 • Identical Sample Results Between Data Sources: Where the same sample results exist for a plant within two or more data sources, EPA in cluded only one of the sample results and excluded the identical results.

• Unavailable Quantitation Limits: EPA treated non-detect results as half the sample-specific quantitation limit for all analytes. T herefore, EPA excluded nondetect sample results that did not have sample-specific quantitation limits.

• Insufficiently Sensitive Analytical Methods or Sample Quality Issues: EPA excluded data that were analyzed using insufficiently sensit ive methods, unless the plants established protocol for sample analysis using t hese methods to account for quality control issues and the sample results achiev ed low reporting limits consistent with the EPA-approved methods. EPA also excl uded sample results noted with sample quality issues, such as excessive holdi ng times, analytical equipment malfunction, or other sample anomalies. EPA describes this evaluation

in Statistical Support Document: Effluent Limitations for FGD Wastewater, Gasification Wastewater, and Combustion Residual Leachate for the Final Ste am Electric Power Generating Effluent Limitations Guidelines and Standards [Westat, 2015].

• Treatment System Initial Commissioning or Plant Decommi ssioning Periods: EPA excluded data collected during the initial commissioning pe riod for the FGD wastewater treatment system or the decommissioning peri od for a steam electric power plant.

• Uncharacteristic or Atypical Operations: EPA conducted a n engineering review of the characterization data to identify operational issues that may influence the outcome of the sample results. EPA also consulted pl ant personnel on system upsets and excluded data that were likely the result of unc haracteristic or atypical operations.

EPA performed the following review, made substitutions, and performed the following analyses with the data, where appropriate, in preparing t he data to use in the effluent

characterization data sets:

• J-Values and Non-Detects: The laboratories performing th e metals analyses provided all the analytical results that were measured abo ve the sample-specific method detection limit (MDL). Therefore, the laborator y results include values flagged with a “J” indicator (i.e., estimated results mea sured above the MDL, but below the quantitation limit). EPA did not use the “J-va lues” in the loadings

calculations. EPA treated all results that were less than the quantitation limit (i.e., J-values and non-detects below the MDL) as half the sa mple-specific quantitation limit (QL) for all analytes, which is consistent with EPA’s approach for handling

non-detects for other data sources.

• Field Blank Analysis: EPA compared the sample results f rom a specific sampling point to the field blank results for the same sampling po int, on the specific day ofSection 11 – FGD Wastewater Pollutant Loadings

11-4 sample collection. For the purpose of the loadings ca lculations, EPA made the following assumptions based on the results of this fiel d blank analysis: 97

— If the sample result was less than five times the fi eld blank result, then the sample result was treated as a non-detect (at a conc entration equal to half the QL).

— If the sample result was between five and 10 times the field blank result, then the sample result was flagged and handled as a qualified va lue.

— If the sample result was greater than 10 times the fie ld blank result, then the sample result was unchanged.

NOTE: EPA used field blank results measured above the quantitation limit for this analysis; J-values associated with field blanks sam ples were not used.

• Duplicate Sample Results: EPA averaged the results fro m each duplicate sample with the results of its original sample. Where a samp le result was not measured above the quantitation limit, flagged as non-detects or J -values, EPA used a concentration equal to half the QL. 98

Using untreated FGD wastewater data (i.e., FGD purge dat a), EPA conducted an analysis to determine pollutants of concern (POCs). In the analys is, EPA identified POCs as pollutants that were present in the wastewater at a sufficient c oncentration and frequency for EPA to consider treatable in the FGD wastewater treatment sys tem [ERG, 2015h; see Appendix 101]. The “FGD Wastewater, Combustion Residual Leachate, an d Gasification Wastewater Pollutants of Concern (POC) Analysis Methodology” for more detai l on the methodology for determining POCs [ERG, 2015d]. EPA estimated pollutant loadings and rem ovals only for pollutants that were identified as POCs. Therefore, for any pollutants t hat were not identified as a POC, EPA did not include the pollutant in the FGD wastewater poll utant loadings estimates. The remainder of Section 11 discusses EPA’s methodology for developing a verage pollutant concentrations and calculating pollutant loadings. Pollutant loadings include only pollutants identified as POCs.

11.1.1 Surface Impoundment Effluent Concentration

Surface impoundments use gravity to remove particulates fro m wastewater, reducing the amount of total suspended solids (TSS) and particulate form s of other specific pollutants in the

97 Only the EPA sampling and CWA 308 monitoring programs co llected field blank samples.

98 Industry-submitted plant monitoring data may have also bee n collected on the same day as EPA’s sampling and CWA 308 monitoring activities (, i.e., duplicate samples m ay exist across multiple data sources). The data vary between daily, weekly, and monthly results and among the number of results between analytes. Therefore, EPA calculated the average effluent concentrations using th ese data sources as follows: 1) Treat all samples colle cted during any of the 4 EPA sampling dates as a duplicate resul t. Calculate daily averages for samples on these dates and then calculate a 4-day average. For pollutant loadings c alculations, the sample results for the 4 days were averaged into a single value. 2) Calculate the average effl uent concentration as an average of the 4-day average and the remaining sample concentrations. See “Revised Meth odology to Calculate Average Effluent Concentrations for Chemical Precipitation and Biological Treatment System s for FGD Wastewater” [ERG, 2015f].Section 11 – FGD Wastewater Pollutant Loadings

11-5 wastewater. EPA categorized all plants not operating c hemical precipitation, biological treatment or evaporation as surface impoundment systems in the bas eline 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 s ystems that do not include hydroxide or sulfide precipitation (e.g., clarifier with polymer addit ion). The operations of these types of systems are effective at removing solids and metals in t he particulate phase but do not achieve removals of dissolved solids, similar to the operatio n of an impoundment. Table 11-1 summarizes the data sources used to develop the impoundment effluent characterization data set and Table 11-2 presents the average effluent concentrations calculated for surface impoundments.

EPA collected or received three different types of char acterization data, which were used to develop the effluent characterization data for FGD sur face impoundments, including:

• Effluent concentrations from a dedicated FGD surface impo undment from one plant.

• Biphasic (i.e., solid and filtrate samples) and dissol ved concentrations of FGD purge analyzed for EPA’s Sampling Program from three plant s.

• Where biphasic concentrations were not available, tota l and dissolved concentrations and TSS concentrations of FGD purge from EPA’s sampling program and industry-submitted data. Four plants contributed this type of

characterization data.

Because the data set includes dedicated FGD surface impound ment data from only one plant, EPA developed an approach for calculating the aver age effluent concentrations from surface impoundments using the impoundment effluent concent rations and calculated impoundment effluent concentrations based on the untreate d FGD purge data. EPA averaged the

effluent concentrations calculated from each of the eight plants to generate the average effluent characterization data set for surface impoundments prese nted in Table 11-2.

11.1.1.1 Effluent Concentration using FGD Surface Impoundment Effl uent
Concentrations

Duke Energy Carolinas’ Roxboro Steam Electric Plant (Ro xboro) operates an FGD surface impoundment that treats FGD purge wastewater and w as the only plant that provided FGD surface impoundment effluent concentrations. EPA use d all available FGD impoundment effluent monitoring data provided by Roxboro to calculate the average effluent concentrations from an FGD surface impoundment.

11.1.1.2 Effluent Characterization Using FGD Purge Wastewater Concent rations

To estimate the effluent concentrations for a surface impoundment based on FGD purge concentration data, EPA assumed that the surface impound ment would achieve only removals of the particulate phase of the sample and, therefore, wo uld not remove pollutants present in the dissolved phase. Because surface impoundments are designed to remove pollutants in the particulate phase and not the dissolved phase, EPA used an effluent TSS concentration of 30 milligrams/liter (mg/L) to estimate the effluent conce ntrations for FGD surface impoundmentsSection 11 – FGD Wastewater Pollutant Loadings

11-6 based on FGD purge concentration data. The TSS concentra tion used as the basis for these calculations (30 mg/L) is the current 30-day average effluent limitation for low-volume

wastewaters set in 40 CFR 423 for BPT.

EPA derived the basis for the assumption that pollutant s in the dissolved phase of the FGD wastewater, primarily metals, are not significant ly treated in a surface impoundment from data presented by the Electric Power Research Institute (EPRI) in the Flue Gas Desulfurization (FGD) Wastewater Characterization: Screening Study , dated March 2006 [EPRI, 2006a]. In that report, EPRI presents FGD blowdown data for eight coal-fi red steam electric power plants. For six of the plants, data are presented for a filtered sa mple, a “settled” sample, and a total sample. In the report, EPRI indicates that the “settled” sampl e was collected by allowing the sample to settle for 1 hour, and then an aliquot was collected fro m 5 inches below the surface of the sample. EPRI’s report states that this “equates to a se ttling velocity of 0.41 ft/hr or an overflow rate of 3.2 million gallons per day/acre” [EPRI, 2006a]. In another EPRI report, EPRI Technical Manual – Guidance for Assessing Wastewater Impacts of FGD Scrubbers , dated December 2006, EPRI references the “settled” sample data from the Flue Gas Desulfurization (FGD) Wastewater Characterization: Screening Study [EPRI, 2006a] and states that they “can be viewed as pond effluent” [EPRI, 2006b].

The FGD blowdown data for the six plants from the Flue Gas Desulfurization (FGD) Wastewater Characterization: Screening Study [EPRI, 2006a] are presented in Table 11-3 and Table 11-4. Table 11-3 presents the data for three of the six plants and Table 11-4 presents the data for the other three plants. After reviewing the data for these six plants, EPA determined that for most of the metal analytes and for most of the p lants, the “settled” results were usually similar to the filtered (or dissolved) concentration fo r the analyte. Therefore, EPA concluded that the effluent from a surface impoundment will not achieve significant removals of pollutants present in the dissolved phase of the sample.

To calculate the surface impoundment effluent concentrat ions, EPA assumed that the total surface impoundment effluent concentration was equal to the sum of the contribution from the solids present in the wastewater and the dissolved c oncentration present in the wastewater. EPA calculated the solid phase contribution with the fol lowing assumptions: 1) the solid phase concentration at the impoundment effluent is equal to th e concentration in the purge, and 2) the TSS concentration of the impoundment effluent is 30 mg/L . EPA also assumed that the dissolved concentration in the impoundment effluent was equal to t he dissolved concentration in the FGD purge because impoundments do not achieve dissolved solids remova ls. EPA used Equation 11-1 to perform this calculation on an analyte-specific basis

.

(11-1)

(ug/L) C mg 1 ug 1000

mg 10 1 kg 1

L mg 30
kg mg C (ug/L) C Dissolved 6 Dry
Settling + ×
× × × =Section 11 – FGD Wastewater Pollutant Loadings

11-7 where:

C Settling = Calculated concentration of the analyte in the ef fluent from a surface impoundment.

C Dry = Dry weight concentration of the analyte in the s olid phase of the wastewater sample.

C Dissolved = Dissolved concentration of the analyte in the wastewater sample.

EPA obtained dissolved concentrations directly from t he analytical data for the FGD purge wastewater. However, the solid phase contribution in Equation 11-1 involved the calculation of the dry weight concentration. EPA obta ined both biphasic and non-biphasic (i.e., total and dissolved and TSS) concentration data and used tw o separate approaches to determine the dry weight concentration using each of these data se ts.

Solid-Phase Concentration Using Biphasic Concentration Data

As part of EPA’s sampling program, EPA required the labora tories analyzing the FGD scrubber purge wastewater to perform a biphasic separation of the FGD purge wastewater sample and analyze both the solid and aqueous phase for ea ch analyte. EPA required the laboratories to perform the analysis only if the waste water sample contained greater than 1 percent solids, which included a total of 12 samples collecte d from Hatfield’s Ferry Power Station (Hatfield’s Ferry), Keystone Generating Stati on (Keystone), and Miami Fort Power Plant (Miami Fort).

EPA used the biphasic concentrations from the FGD purge t o estimate the analytespecific surface impoundment effluent concentrations on a dry weight basis. EPA conducted biphasic analyses at two laboratories. One laboratory pe rformed the analysis of the solids based on the wet solids, while the other laboratory dried the s olids prior to performing the analysis. Therefore, one of the laboratories produced a wet weigh t solid concentration, whereas the other laboratory produced a dry weight solid concentration. To put the concentrations on the same basis, EPA first converted the wet weight solid conce ntrations to dry weight solid concentrations using Equation 11-2.

(11-2)



### phase) solid (of %Solids L mg C

kg 1 L 1 phase)] solid (of %Solids - 1[ - kg mg C

kg mg C sample wet

Dry 

###    

           

× ×        

=

where:

C Dry = Dry weight concentration of the analyte in the s olid phase of the sample.Section 11 – FGD Wastewater Pollutant Loadings

11-8 C sample = Concentration of the analyte in the aqueous phase of the sample.

C wet = Wet weight concentration of the analyte in the s olid phase of the sample.

%Solids (of solid phase) = Percent solids present in t he solid phase of the sample.

Solid-Phase Concentration using Total and Dissolved Concentrations and TSS

EPA did not require laboratories to perform biphasic separ ation of the samples for plants where the FGD purge wastewater samples collected during EP A’s sampling program contained less than 1 percent solids. This included wastewater samp les from Allen Steam Station (Allen), Belews Creek Steam Station (Belews Creek), Dickerson Generating Station (Dickerson), and Pleasant Prairie Power Plant (Pleasant Prairie) FGD wastewater data.

In addition to characterization data collected during EPA’ s sampling program, EPA also evaluated industry-submitted data and identified a subset of th e Allen and Belews Creek monitoring data that contained sample-specific results that included total and dissolved concentrations and TSS concentrations for the same day. In lieu of biphasic results, these three components of the sample results are required to estim ate the concentration of the analyte in the solid phase. Where these three components were not avai lable in the characterization data, EPA

did not use the data to estimate the effluent concentrat ions for surface impoundments.

EPA used Equation 11-3 to calculate dry weight solid concentr ations for a given day for each analyte from these plants.

(11-3)

ug 1000 mg 1
kg mg 10 1

(mg/L) C (ug/L) C - (ug/L) C (mg/kg) C 6

TSS Dissolved Total Dry × × × =

where:

C Dry = Dry weight concentration of the analyte in the s olid phase of the sample.

C Total = Total concentration of the analyte in the sample.

C Dissolved = Dissolved concentration of the analyte in the sam ple.

C TSS = TSS concentration in the sample.

11.1.1.3 Effluent Characterization for Conventional and Nonconventional Pol lutants

Conventional pollutants in EPA’s characterization data set include biochemical oxygen demand (BOD) and TSS. Nonconventional pollutants in EPA’ s data set include total dissolved solids (TDS), chloride, sulfate, ammonia, chemical oxyg en demand (COD), cyanide, nitratenitrite as N, total Kjeldahl nitrogen (TKN), total phosphor us, and total cyanide. To estimate theSection 11 – FGD Wastewater Pollutant Loadings

11-9 effluent concentrations of these pollutants from a sur face impoundment for the seven sampled plants, EPA used information collected from two plants a s part of the sampling program during the detailed study: Tennessee Valley Authority’s Widows C reek Fossil Plant (Widows Creek) and Buckeye Power Company’s Cardinal Power Plant (Cardinal ). The data EPA collected from the Widows Creek plant represented a 1-day sample effluent from a surface impoundment used to treat FGD wastewater, and the data EPA collected fro m Cardinal represented a 1-day effluent from a surface impoundment used to treat fly ash transpor t water. EPA compared the effluent values for the classical analytes for the two plants, as well as the percent removals achieved by the surface impoundments (compared to the samples collec ted at the influent to the surface impoundments). 99 Based on the results of the comparison, EPA made the following assumptions to estimate the surface impoundment effluent concentrat ions for the classical analytes:

• The TSS concentration at the effluent is 30 mg/L, as pre viously discussed in

Section 11.1.1.2.

• The TDS concentration is equal to the FGD purge concentr ation at the influent (i.e., no removal).

• The chloride concentration is equal to the FGD purge concen tration at the influent (i.e., no removal).

• The sulfate concentration is equal to the FGD impoundm ent effluent

concentration. 100

EPA did not estimate concentrations for ammonia, BOD, COD, cyanide, nitrate-nitrite as N, TKN, and total phosphorus in the effluent from a surfa ce impoundment for the plants with sampling data. Although EPA did not develop a methodology t o estimate the effluent concentrations for these analytes, these analytes ar e present in the impoundment effluent because they are present in chemical precipitation effluent, a s demonstrated by the data collected, but are not treated by this type of treatment system. Therefore , to account for these pollutants in the loadings analysis, EPA assumed that the concentrations of these pollutants were equal to the concentrations calculated for chemical precipitation e ffluent (see Section 11.1.5.1).

11.1.2 Chemical Precipitation Effluent Characterization

As part of the sampling activities described in Section 3. 3, EPA identified and collected EPA sampling data and CWA 308 monitoring data from seven plan ts operating chemical precipitation systems, sometimes in conjunction with other technologies, such as biological treatment. The specific operating characteristics of th e chemical precipitation treatment systems varied. EPA conducted an engineering review of the data and identified four systems (Hatfield’s Ferry, Keystone, Miami Fort, and Pleasant Prairie) o perating chemical precipitation with hydroxide and sulfide precipitation (i.e., BAT technology basis). The remaining three plants, which included Allen, Belews Creek, and Dickerson, did not ope rate systems at the time EPA

99 The influent and effluent samples collected from the su rface impoundment do not represent paired samples.

100 EPA observed sulfate removals in the detailed study data from the Widows Creek plant as well as the surface impoundment effluent data from the Roxboro plant. EPA use d the average sulfate concentrations observed from the Roxboro plant to represent the impoundment effluent sulfate concentration.Section 11 – FGD Wastewater Pollutant Loadings

11-10 sampled effluent that represented the BAT technology and , therefore, these plants were not included in the effluent characterization for chemical pr ecipitation. 101

The treatment systems at these four BAT plants have s imilar operations; however, the plants have varying configurations and operating characteris tics, such as thickeners, filter presses, sand filters, and retention time. Each of the se systems was designed and is operated to remove suspended solids and dissolved metals from the FG D wastewater to achieve a similar level of pollutant discharge. The systems are sized to ha ndle a specific flow rate of FGD wastewater, which means that the sizes of the tanks w ere designed to allow for the residence time required for settling and/or reactions to occur in or der to achieve effluent concentrations meeting the plant’s permit limitations.

EPA also requested monitoring data on the chemical precipitation effluent from these plants, as described in Section 3.4. The monitoring data, in conjunction with the EPA sampling and CWA 308 monitoring data, comprise the data sets EPA used t o develop the effluent characterization data for chemical precipitation trea tment. Table 11-5 summarizes the data sources used to develop the effluent characterization data set and Table 11-6 presents the average effluent concentrations calculated for chemical preci pitation. Because pollutant loadings

calculations described in Section 11.3 are based on total co ncentrations, EPA included only total concentrations except for hexavalent chromium, which i s analyzed only as a dissolved

constituent.

11.1.3 Biological Treatment Effluent Characterization

Four plants operate fixed-film anoxic/anaerobic biological treatment systems. 102 Two of these plants, Roxboro and Mountaineer, do not represent the technology basis because Roxboro treats its FGD wastewater with a surface impoundment f ollowed by biological treatment (i.e., no chemical precipitation system) and Mountaineer treats its FGD wastewater with a dedicated chemical precipitation system, but then combines that e ffluent with untreated combustion residual leachate prior to sending it to the biological tr eatment system wastestream; therefore, the effluent data from these plants were not used in develop ing the effluent characterization for biological treatment of only FGD wastewater. EPA iden tified and collected data from two plants, Allen and Belews Creek, operating biological treatment s ystems with chemical precipitation pretreatment that represent the biological treatment t echnology option. These two plants operate chemical precipitation systems followed by anoxic/anaer obic biological treatment systems specifically designed for selenium removal.

101 EPA excluded data from Dickerson because the Dickerson plant was not adding sulfide to the wastewater treatment system at the time of sampling. The plant al so experienced frequent shutdowns and wastewater treatment upsets, and the treatment system is not designed and operate d to remove selenium. Allen and Belews Creek also did not add sulfide in their chemical precipitation systems a t the time of sampling.

102 The Mayo Plant currently operates a biological treatm ent system but has announced plans to install an evaporation treatment system. For the purposes of estimat ing costs and pollutant loadings for the final rule, EPA does not consider this plant as operating a biological tr eatment system, but rather an evaporation treatment syst em. See “Changes to Industry Profile for Steam Electric Gen erating Units for the Steam Electric Effluent Guidelin es Final Rule” for more detail on planned treatment system upgrades [ERG, 2015a].Section 11 – FGD Wastewater Pollutant Loadings

11-11 EPA used the data from Allen and Belews Creek to represent the effluent characterization data of chemical precipitation system with biological treatment system; however, these two plants do not fully represent the technology option bec ause neither plant currently uses sulfide precipitation in the chemical precipitation system. T herefore, the two plants likely do not demonstrate mercury (and other metals) effluent concentr ations as low as could be achieved by a chemical precipitation (with sulfide precipitation) fo llowed by a biological treatment system that forms the basis of the technology option.

EPA has multiple sets of data for these two plants to de velop the effluent characterization data for chemical precipitation followed by biological t reatment, including EPA sampling data, CWA 308 monitoring data, and plant monitoring data. Table 11-7 sum marizes the data sources used to develop the effluent characterization data set an d Table 11-8 presents the average effluent concentrations calculated for chemical preci pitation followed by biological treatment. Because pollutant loadings calculations described in Secti on 11.3 are based on total concentrations, EPA included only total concentrations ex cept for hexavalent chromium, which is analyzed only as a dissolved constituent.

11.1.4 Evaporation Effluent Characterization

EPA developed effluent characterization data for evaporat ion because two plants are planning to install evaporation systems and are considere d to operate this technology at baseline. The evaporation data that EPA collected as part of the C WA 308 monitoring program include data from one plant currently operating in the United Sta tes but not discharging wastewater, as well as one plant in Italy. 103 EPA conducted an engineering review of the data from thes e two plants operating evaporation systems. One plant, Brindi si, operates a hydroxide-sulfide chemical precipitation system followed by softening, a brine concen trator, and crystallization system, which EPA considered as the technology basis for evapora tion. The second plant, Iatan, operates a clarification system, with coagulant and polyelectro lyte addition, followed by a brine concentrator. Because the Iatan system does not include a chemical precipitation system, a softening system, and a crystallizer, EPA does not conside r this plant to represent the evaporation technology basis. Table 11-9 summarizes the da ta sources used to develop the effluent characterization data set and Table 11-10 presents the average effluent concentrations calculated for evaporation. For this plant, EPA collec ted and analyzed 3 days of samples for total

concentrations and did not have dissolved concentration s or hexavalent chromium data to use in the analysis.

EPA calculated the average effluent concentrations for the evaporation treatment system,

as follows:

103 As described in Section 3.3.3, EPA also requested samples fr om a second plant in Italy, A2A’s Centrale de Monfalcone (Monfalcone). Data from Monfalcone consi sts of a single 1-day grab sample collected by Monfalco ne personnel that were not trained in EPA’s sampling protoco ls; therefore, EPA did not include this data in any calculations for the final rulemaking. The pollutant concent rations seen at Monfalcone are comparable to the average effluent concentration for evaporation.Section 11 – FGD Wastewater Pollutant Loadings

11-12 1. Calculate average concentration by analyte for each of the two evaporation wastestreams at the plant (i.e., brine concentrator d istillate and crystallizer condensate).

2. Calculate overall average effluent concentration by ana lyte by averaging the concentrations from the two wastestreams (i.e., brin e concentrator distillate and crystallizer condensate). 104

11.1.5 Pollutant Concentration Basis for Loadings Calculations

Because of the concentration data available, EPA used di fferent populations of plants to generate the various effluent characterization data se ts presented in Table 11-2, Table 11-6, Table 11-8, and Table 11-10. EPA conducted an engineering review of the effluent concentrations across all technologies to determine if r emovals were observed for pollutants expected to be treated by the technology and likewise, if no removals were observed for pollutants that were not expected to be treated. Based on this review, EPA performed substitutions for analyte-specific concentrations where it determined that the pollutant was not being effectively treated in a particular treatment sy stem. Sections 11.1.5.1 through 11.1.5.4 describe the types of substitutions made for each technolog y basis.

11.1.5.1 Pollutant Concentrations for Surface Impoundment Effluent

For pollutants that were not included in the surface impoun dment effluent characterization data, presented in Table 11-2, EPA assume d the concentrations of these pollutants were equal to the pollutant concentrations used f or the chemical precipitation effluent (i.e., Table 11-12), which are further discussed in Section 11.1.2. This includes substitutions of the pollutant concentrations for ammonia, BOD, COD, ch romium (VI), cyanide, nitrate-nitrite as N, TKN, and total phosphorus. EPA concludes that because t hese pollutants are present in the chemical precipitation effluent, they are also presen t in the FGD wastewater and would therefore, also be present in the FGD surface impoundme nt effluent. EPA’s assumption results in EPA accounting for these pollutants in the baseline loadi ngs, but does not result in any estimated pollutant removals in the chemical precipitation system . Table 11-11 provides a summary of EPA’s substitutions of the impoundment effluent character ization data (described in Section 11.1.1) with chemical precipitation pollutant concentratio ns for each of these pollutants and presents the pollutant concentrations for surface impoundm ents that EPA used in the pollutant loading calculations.

11.1.5.2 Pollutant Concentrations for Chemical Precipitation Efflue nt

Prior to using the effluent characterization data for c hemical precipitation (in Section 11.1.2), EPA conducted a separate analysis to ensure that th e collective data set demonstrates positive removals across the chemical precipitation sy stem. EPA reviewed the data set on a plant level to determine whether the pollutant was present at treatable levels and if so, whether the

104 EPA used both the brine concentrator distillate and crystallizer condensate streams to calculate the load ings because both wastestreams could be discharged. The evaporati on system at Brindisi is operated as a zero-discharge system with no wastewater being discharged to surface water or a POTW. The plant could choose to discharge th e brine concentrator and the crystallizer condensate s treams together or separately.Section 11 – FGD Wastewater Pollutant Loadings

11-13 pollutant was effectively treated by the treatment techn ology. In this analysis, EPA reviewed pollutant concentrations at the influent to the chemical precipitation system (i.e., FGD purge wastewater) using data from the four plants operating this technology basis, including Hatfield’s Ferry, Miami Fort, Keystone, and Pleasant Prairie. O n a plant level, EPA identified pollutants at treatable levels by comparing the average purge concentration s to the sample-specific quantitation limit. 105 Pollutants at treatable levels were identified as those present at greater than or equal to 10 times the quantitation limit in at least 10 pe rcent of the influent samples at the plant. If the pollutant is present at treatable levels at any of the plants, then EPA calculated plantspecific percent removals for those plants using the plan t-specific average FGD purge concentration and the plant-specific average chemical pr ecipitation effluent. 106 If the pollutant (ammonia, BOD, COD, chromium (VI), TKN, silver, sulfa te, and tin 107 ) is not present at treatable levels at any of the plants, then EPA set t he chemical precipitation effluent concentration for that pollutant equal to the FGD surfac e impoundment effluent (presented in Table 11-2).

Next, EPA performed a review of the plant-specific pollut ant removals to confirm that each pollutant is being removed across the chemical precip itation treatment system (percent removals greater than zero).

1. For those pollutants where all plant-specific pollutant removals demonstrate positive removals across the chemical precipitation sy stem (i.e., percent removals are greater than zero), EPA set the chemical precipit ation effluent concentration equal to the average chemical precipitation effluent conce ntration for the FGD loadings analysis (presented in Table 11-6).

2. After EPA set the chemical precipitation effluent con centrations for those pollutants in Step 1, it also compared the average chemic al precipitation effluent concentrations to the average FGD surface impoundment effl uent concentrations. EPA performed this comparison because it used different da ta sets to determine concentrations for chemical precipitation (based on four plants) and FGD surface impoundments (based on eight plants). For magnesium and molybdenum, the BAT chemical precipitation effluent concentrations wer e higher than the surface impoundment effluent concentrations. Because of this phen omenon, EPA set the BAT chemical precipitation effluent concentration equal to the surface impoundment effluent concentration for these two pollutan ts.

105 The methodology to identify pollutants at treatable le vels is similar to the methodology used in EPA’s POC analysis; however, this analysis is conducted at the plant level to evaluate treatment effectiveness.

106 For the calculation of the percent removals, EPA used a ll available FGD purge and FGD chemical precipitation system effluent data. EPA did not use only paired sample results or only data from which samples were collect ed on the same day. EPA notes that this treatment effective ness evaluation is not used to determine the exact percent removal achieved by the chemical precipitation system, b ut rather, to evaluate whether the pollutant is removed across the system.

107 As described in Section 11.1.5.1, no methodology exists to estimate impoundment effluent concentrations for ammonia, BOD, COD, chromium (VI), and TKN; therefore, EPA used the chemical precipitation effluent concentrations for both the surface impoundment efflue nt and the chemical precipitation effluent for the loadings analysis.Section 11 – FGD Wastewater Pollutant Loadings

11-14 3. For those pollutants that show positive removal acro ss the chemical precipitation for some plants, but not all plants, EPA reviewed the da ta to assess whether the data collectively demonstrates removal across the tre atment system. This affected the following pollutants: chloride, nitrate-nitrite as N, a nd sodium.

a. Chloride: Two of the four plants had negative removals (Ha tfield’s Ferry and Pleasant Prairie) and one plant had percent removals l ess than 3 percent (Keystone). Miami Fort achieved some removals across the chemical precipitation system. EPA also compared the average FGD purge concentration for the four plants to the average concent ration for the chemical precipitation effluent for the four plants and found the a verage influent concentration was lower than the average effluent conc entration. Additionally, based on a review of literature, EPA did not expect to se e positive removals of chloride across the chemical precipitation treatment sy stem. Based on a collective review of all the data and information, EPA determined that chemical precipitation is not any more effective at r emoving chlorides than FGD surface impoundments; therefore, EPA set the chemi cal precipitation effluent concentration equal to the FGD surface impoundm ent effluent

concentration for chloride.

b. Nitrate-Nitrite as N: One plant had negative removals (Pleasant Prairie) and two plants had removals less than 10 percent (Hatfield’s Ferry and Miami Fort). Keystone achieved some removals of nitrate-nitri te as N. Based on a review of literature, EPA did not expect to see positive removals of nitratenitrite as N across the chemical precipitation treatm ent system. Based on a collective review of all the data and information, EPA determined that chemical precipitation is not any more effective at r emoving nitrate-nitrite as N than FGD surface impoundments; therefore, EPA set th e chemical precipitation effluent concentration equal to the FGD s urface impoundment

effluent concentration for nitrate-nitrite as N

c. Sodium: Three of the four plants have negative removals of sodium. Miami Fort achieved some significant removals of sodium. Bas ed on a review of literature, EPA did not expect to see positive removals o f sodium across the chemical precipitation treatment system. Based on a c ollective review of all the data and information, EPA determined that chemical pre cipitation is not any more effective at removing sodium than FGD surface impoundments; therefore, EPA set the chemical precipitation efflue nt concentration equal to the FGD surface impoundment effluent concentration for sodium.

Table 11-12 presents the pollutant concentrations EPA used t o represent the effluent from the BAT chemical precipitation system used in the poll utant loading calculations, along with the basis for the concentration (i.e., FGD surface impound ment, chemical precipitation). The plantlevel results of EPA’s treatment effectiveness eval uation for chemical precipitation are included in the “Supplemental Costs and Loadings Documentation” [ERG, 2015h; see Appendix 102].Section 11 – FGD Wastewater Pollutant Loadings

11-15 11.1.5.3 Pollutant Concentrations for Biological Treatment Effluent

Similarly to the analysis done for chemical precipita tion, EPA evaluated the pollutantspecific treatment effectiveness of the biological tr eatment technology. For this analysis, EPA reviewed pollutant concentrations at the influent to the biological treatment system (i.e., chemical precipitation effluent) using data from the two plants operating this technology, Allen

and Belews Creek.

For this analysis, EPA used chemical precipitation effl uent and biological treatment

effluent data from Allen and Belews Creek. EPA first r eviewed the influent data for each pollutant at each plant (i.e., chemical precipitation effluent) to identify those pollutants present at

treatable levels. Pollutants at treatable levels were identified as those present at greater than or equal to five times the quantitation limit in at least 10 pe rcent of the influent samples at the plant. 108 If the pollutant is present at treatable levels, then E PA calculated plant-specific percent removals across the biological treatment system for those plants using the plant-specific average chemical precipitation effluent concentration and the plant-specific average biological treatment system effluent concentration. 109 If the pollutant (aluminum, ammonia, antimony, arsenic, barium, beryllium, BOD, cadmium, chromium, chromium (VI), cobalt, copper, cyanide, iron, lead, manganese, molybdenum, TKN, total phosphorus, silver, thallium, tin, titanium, total suspended solids, vanadium, and zinc) is not present at treat able levels at any of the plants, then EPA set the biological treatment effluent concentrati on equal to the pollutant concentration that was determined to be most appropriate for the chemical pre cipitation effluent (i.e., concentration presented in Table 11-12).

Next, EPA performed a review of the plant-specific pollut ant removals to confirm that each pollutant is being removed across the biological trea tment system.

1. For those pollutants where plant-level concentration data from both plants demonstrates positive removals across the biological tr eatment system (i.e., percent removals greater than zero), EPA set the chem ical precipitation followed by biological treatment system effluent concentration equal to the average biological treatment system effluent concentration f or the FGD loadings analysis (i.e., concentration presented in Table 11-8). This affect ed the following pollutants: mercury, nickel, nitrate-nitrite as N, and sele nium.

108 For biological treatment, EPA used five times the quant itation limit instead of 10 times the quantitation limit because the FGD wastewater has already undergone treatment in the chemical precipitation system prior to reach ing the influent to the biological treatment system; ther efore, many of the pollutants have been reduced to lower levels entering the system. The biological treatment system is a portion of the overall BAT system and is not being evaluated as its own BAT technology. EPA has selected fi ve times the quantitation limit because it has been use d in previous ELGs as the level required for evaluating effect ive treatment (e.g., metal products & machinery, transportation equipment cleaning).

109 For the calculation of the percent removals, EPA used a ll available FGD chemical precipitation system efflue nt data and FGD biological treatment system effluent data. EPA did not use only paired sample results or only data from which samples were collected on the same day. E PA notes that this treatment effectiveness evaluation is not used to determine the exact percent removal achieved by the biological treatment system, but rather to evaluate generally whether the pollutant is removed across the sy stem.Section 11 – FGD Wastewater Pollutant Loadings

11-16 2. For those pollutants that show positive removal acro ss the biological treatment system for only one plant, but not both, EPA reviewed the data to assess whether the data collectively demonstrated removal across the tr eatment system. This affected the following pollutants: barium, boron, calci um, chloride, COD, magnesium, sodium, sulfate, and TDS.

a. Barium: EPA compared the average chemical precipitatio n effluent concentration to the average biological treatment eff luent concentration. EPA performed this comparison because it used different da ta sets to determine concentrations for chemical precipitation (b ased on four plants) and biological treatment (based on two plants). For bari um, the biological treatment effluent concentrations were higher than the chemical precipitation effluent concentrations. Based on a review of literature, EPA did not expect barium to be generated across the biologic al system. Based on a collective review of all the data and information, EPA set the chemical precipitation followed by biological treatment system effluent concentration equal to the concentration that was dete rmined to be most appropriate for the chemical precipitation system optio n (i.e., chemical precipitation effluent).

b. Boron: EPA compared the average chemical precipitation effluent concentration to the average biological treatment eff luent concentration. EPA performed this comparison because it used different da ta sets to determine concentrations for chemical precipitation (b ased on four plants) and biological treatment (based on two plants). For boro n, the biological treatment effluent concentrations were higher than the chemical precipitation effluent concentrations. Additionally, rem oval of boron demonstrated at the BAT plants was not consistent with the removal calculated based on the average chemical precipitation effluent concentration and the average biological treatment eff luent concentration. Actual sampling data demonstrate less than 10 percent removal , while the removal between the average chemical precipitation ef fluent and the average biological effluent is 36 percent. Based on a coll ective review of all the data and information, EPA determined that biologica l treatment is not any more effective at removing boron than chemical precipitation; therefore, EPA set the chemical precipitation follow ed by biological treatment system effluent concentration equal to the co ncentration that was determined to be most appropriate for the chemical pre cipitation system option (i.e., chemical precipitation effluent)

.

c. Calcium: EPA compared the average chemical precipitatio n effluent concentration to the average biological treatment eff luent concentration. EPA performed this comparison because it used different da ta sets to determine concentrations for chemical precipitation (b ased on four plants) and biological treatment (based on two plants). For calc ium, the biological treatment effluent concentrations were higher than the chemical precipitation effluent concentrations. Based on a review of literature, EPA did not expect calcium to be generated across the biolo gical system. BasedSection 11 – FGD Wastewater Pollutant Loadings

11-17 on a collective review of all the data and information, EPA set the chemical precipitation followed by biological treatment system effluent concentration equal to the concentration that was dete rmined to be most appropriate for the chemical precipitation system optio n (i.e., chemical precipitation effluent).

d. Chloride: EPA compared the average chemical precipitatio n effluent concentration to the average biological treatment eff luent concentration. EPA performed this comparison because it used different da ta sets to determine concentrations for chemical precipitation (b ased on four plants) and biological treatment (based on two plants). For chlor ide, the biological treatment effluent concentrations were higher than the chemical precipitation effluent concentrations. Actual sampling dat a demonstrate less than 10 percent removal, while the removal between the average chemical precipitation effluent and the average biologi cal effluent is 36 percent. Based on a collective review of all the data a nd information, EPA determined that biological treatment is not any more effe ctive at removing chloride than chemical precipitation; therefore, EPA se t the chemical precipitation followed by biological treatment system e ffluent concentration equal to the concentration that was dete rmined to be most appropriate for the chemical precipitation system optio n (i.e., surface impoundment effluent).

e. COD: Based on a review of literature and because the biol ogical treatment system operates in anaerobic/anoxic stages and not aerob ic stages, EPA did not expect to see positive removal of COD across t he biological treatment system. Based on a collective review of all the data and information, EPA determined that biological treatment is not any more effective at removing COD than chemical precipitation; therefore, EPA set the chemical precipitation followed by biological treat ment system effluent concentration equal to the concentration that was determined to be most appropriate for the chemical precipitation system (i.e., chemical precipitation effluent).

f. Magnesium: EPA compared the average chemical precipita tion effluent concentration to the average biological treatment eff luent concentration. EPA performed this comparison because it used different da ta sets to determine concentrations for chemical precipitation (b ased on four plants) and biological treatment (based on two plants). For magn esium, the biological treatment effluent concentrations were high er than the chemical precipitation effluent concentrations. Actual sampling dat a demonstrate less than 5 percent removal, while the removal between the average chemical precipitation effluent and the average biologi cal effluent is 82 percent. Based on a collective review of all the data a nd information, EPA determined that biological treatment is not any more effe ctive at removing magnesium than chemical precipitation; therefore, EPA set the chemical precipitation followed by biological treatment system e ffluentSection 11 – FGD Wastewater Pollutant Loadings

11-18 concentration equal to the concentration that was dete rmined to be most appropriate for the chemical precipitation system optio n (i.e., FGD surface impoundment effluent).

g. Sodium: EPA compared the average chemical precipitation effluent concentration to the average biological treatment eff luent concentration. EPA performed this comparison because it used different da ta sets to determine concentrations for chemical precipitation (b ased on four plants) and biological treatment (based on two plants). For sodiu m, the biological treatment effluent concentrations were higher than the chemical precipitation effluent concentrations. Actual sampling dat a demonstrate less than 5 percent removal, while the removal between the average chemical precipitation effluent and the average biologi cal effluent is 91 percent. Based on a collective review of all the data a nd information, EPA determined that biological treatment is not any more effe ctive at removing sodium than chemical precipitation; therefore, EPA set the chemical precipitation followed by biological treatment system e ffluent concentration equal to the concentration that was dete rmined to be most appropriate for the chemical precipitation system optio n (i.e., FGD surface impoundment effluent).

h. Sulfate: EPA compared the average biological treatment system effluent concentration for the two plants to the average chemica l precipitation effluent concentration for the two plants and found th e average influent concentration was lower than the average effluent conc entration. Additionally, the removal of sulfate demonstrated at the BAT plants was

not consistent with the removal calculated based on the average chemical precipitation effluent concentration and the average bi ological treatment effluent concentration. Actual sampling data demonstrate less than 5 percent removal while the removal between the average c hemical precipitation effluent and theaverage biological effluent is calculated to be 80 percent. Based on a collective review of all the data and information, EPA determined that biological treatment is not any more effective at removing sulfate than chemical precipitation; therefore, EPA set the chemical precipitation followed by biological treatment system effluent concentration equal to the concentration that was dete rmined to be most appropriate for the chemical precipitation system (i.e ., surface impoundment effluent).

i. TDS: EPA compared the average chemical precipitation ef fluent concentration to the average biological treatment eff luent concentration. EPA performed this comparison because it used different da ta sets to determine concentrations for chemical precipitation (b ased on four plants) and biological treatment (based on two plants). For TDS, the biological treatment effluent concentrations were higher than the chemical precipitation effluent concentrations. Actual sampling dat a demonstrate less than 5 percent removal, while the removal between the average chemical precipitation effluent and the average biologi cal effluent is 46Section 11 – FGD Wastewater Pollutant Loadings

11-19 percent. Based on a collective review of all the data a nd information, EPA determined that biological treatment is not any more effe ctive at removing TDS than chemical precipitation; therefore, EPA set t he chemical precipitation followed by biological treatment system e ffluent concentration equal to the concentration that was dete rmined to be most appropriate for the chemical precipitation system optio n (i.e., chemical precipitation effluent).

Table 11-13 presents the pollutant concentrations EPA used t o represent the effluent from the chemical precipitation and biological treatment sy stem used in the pollutant loading calculations, along with the basis for the concentrat ion (i.e., FGD surface impoundment, chemical precipitation, biological treatment). The pl ant-level results of EPA’s treatment effectiveness evaluation for biological treatment are included in the “Supplemental Costs and Loadings Documentation” [ERG, 2015h; see Appendix 102].

11.1.5.4 Pollutant Concentrations for Evaporation Effluent

Similarly to its review of FGD surface impoundment effl uent concentrations, described in Section 11.1.5.1, EPA substituted concentrations in the eva poration effluent with pollutant concentrations for chemical precipitation in Table 11-8 w here pollutants were not characterized in the evaporation data set. This includes substitutions for BOD, chromium (VI), and cyanide. Table 11-14 provides a summary of EPA’s substitutions of the evaporation effluent characterization data for each pollutant and presents th e pollutant concentrations for evaporation effluent used in the pollutant loading calculations, whic h incorporates EPA’s substitutions. 110

11.2 FGD W ASTEWATER F LOW R ATES

EPA used data from the Questionnaire for the Steam Electric Power Generating Effluent

Guidelines (Steam Electric Survey) to identify plants discharging FGD wastewater and determine the plant’s discharge flow rate. In cases wh ere Steam Electric Survey data were insufficient, EPA developed a methodology for estimating flow rates. Section 4.1.1 describes EPA’s methodology for determining wastewater flow rates for FGD wastewater. In Section 4.5.2, EPA evaluated FGD “high-flow” plants and determined t hat three plants have the potential to recycle some FGD wastewater back to the system and r educe the amount of FGD wastewater that would require treatment.

To account for the recycle flow, EPA calculated a new FGD wastewater flow rate to use in the post-compliance loadings for these plants. EPA used the same FGD wastewater flow rates in the chemical precipitation and the biological treat ment FGD wastewater technology cost modules (discussed in Sections 6.1.4 and 6.2.4) and the FGD w astewater pollutant loadings 111 to

110 Because the evaporation effluent concentrations were use d only to estimate the baseline loadings for those plants that currently operate evaporation systems and EPA di d not use them to evaluate pollutant removals associate d with installing the technology option, EPA did not conduct t he treatment effectiveness analysis for this treatment technology.

111 “High-flow” plants have higher baseline flow rates t han post-compliance flow rates because of the plant’s potential to recycle some of the FGD wastewater. Due t o the differences in flow rates, EPA adjusted post-Section 11 – FGD Wastewater Pollutant Loadings

11-20 ensure consistency among all the FGD estimates. FGD wa stewater flow rates are tabulated in the “FGD Input Table,” which is included in the FGD Loadings Da tabase [ERG, 2015c].

EPA used the “CCR Input Table,” discussed in Section 4.3.3, t o adjust the population of plants discharging FGD wastewater to account for the i mplementation of the final Coal Combustion Residuals (CCR) rule. A copy of the “CCR In put Table” is included in the FGD Loadings Database [ERG, 2015c].

11.3 P OLLUTANT L OADINGS C ALCULATIONS

EPA calculated plant-level pollutant loadings for FGD wastewater at baseline and for each of the treatment technologies evaluated using the plant-specific FGD wastewater flow rate and the average effluent pollutant concentrations for the wastestream, according to Equation 11-4. EPA estimated loadings for the 88 plants that operate a wet FGD system and discharge the

FGD wastewater to a surface water or POTW.

(11-4)

Pollutant Loading (lbs/yr) = Flow Rate × Pollutant Conc entration × 2.20462 lb/1,000,000 mg × 1,000 L / 264.17 gal × 365 days/year

where:

Flow Rate = The FGD wastewater flow rate, in gallons per day.

Pollutant Concentration = The average concentration of a specific pollutant present in the wastestream, in milligrams per liter.

EPA applied different effluent limitations to oil-fire d generating units and generating units with a capacity of 50 megawatts (MW) or less (one pl ant discharging FGD wastewater operates units with a capacity of 50 MW or less). In this case, the plant will not face more stringent requirements than already existed under preexistin g regulations; therefore, postcompliance loadings are set equal to the baseline loading s.

11.3.1 Baseline Loadings

As described at the beginning of this section, baseline load ings are the mass of pollutants discharged in FGD wastewater based on the current level of treatment. For baseline loadings, EPA multiplied the plant-specific FGD wastewater flow rate with the average pollutant concentrations that represent the current level of tre atment EPA assigned to each plant. As described earlier, EPA assigned current level of treatmen t for FGD wastewater using one of four classes of treatment: FGD surface impoundment, chemica l precipitation, biological treatment, and evaporation. Of the 87 plants identified from the Ste am Electric Survey and industry-

compliance loadings to equal baseline loadings for pollutants that are not effectively treated by the BAT system (i .e., chemical precipitation followed by biological treatmen t). This adjustment eliminates artificial pollutant remov als

that would have been a result of the differences in the baseline and post-compliance flow rates, including remo vals for ammonia as N, chloride, cyanide, magnesium, molybde num, total phosphorus, and sodium.Section 11 – FGD Wastewater Pollutant Loadings

11-21 submitted data as operating non-small (i.e., with a capacity of greater than 50 MW) and discharging FGD wastewater, EPA assigned the current l evel of treatment as follows:

• Thirty-six plants currently operating or planning to operate s urface impoundments.

• Forty-five plants currently operating or planning to operate a chemical precipitation system.

• Four plants currently operating or planning to operate a biologi cal treatment
system.

• Two plants currently operating or planning to operate an evapora tion system.

11.3.2 Chemical Precipitation Loadings

For post-compliance loadings associated with the chemi cal precipitation technology option, EPA assumed that plants currently treating FGD wastewater with chemical precipitation systems, biological treatment systems, or evaporation systems do not require additional controls to comply with the final rule. Therefore, these plants remain unchanged from baseline and the pollutant loadings for these plants were set equal to th e baseline pollutant loadings. This assumption may underestimate the estimated pollutant r emovals for plants with a baseline chemical precipitation system that is not equivalent to the technology basis.

EPA assumed that plants operating surface impoundments at b aseline would install chemical precipitation treatment systems to meet the effluent requirements associated with this option. EPA evaluated post-compliance loadings for these plants at the effluent from the chemical precipitation system using the average pollutant concentration data set associated with a chemical precipitation system, presented in Table 11-12, and the plant-specific FGD

wastewater flow rates.

11.3.3 Biological Treatment Loadings

For the post-compliance pollutant loadings associated wit h the chemical precipitation treatment system followed by biological treatment tech nology option, EPA assumed that the post-compliance loadings calculated for plants currently treating their FGD wastewater with biological treatment systems or evaporation systems r emain unchanged from baseline and the pollutant loadings for these plants were set equal to th e baseline pollutant loadings. This assumption may underestimate the pollutant removals for plants with baseline biological treatment systems that are not equivalent to the techn ology basis (i.e., chemical precipitation followed by biological treatment).

EPA assumed that plants with surface impoundments would ins tall chemical precipitation systems with biological treatment, and plants with ch emical precipitation systems (but no biological treatment for selenium removal) would instal l biological treatment systems to meet the effluent requirements associated with this technology op tion. EPA evaluated post-compliance loadings for these plants at the effluent from the bio logical treatment system using the pollutant concentrations associated with a chemical precipitatio n system followed by biological treatment, presented in Table 11-13, and plant-specific FGD wastewater flow rates.Section 11 – FGD Wastewater Pollutant Loadings

11-22 11.3.4 POTW Removals

EPA identified two plants that reported in the Steam Elec tric Survey transferring FGD wastewater to a POTW rather than discharging directl y to surface water. For these plants, EPA adjusted the baseline and post-compliance loadings to acc ount for pollutant removals expected from POTWs for each analyte. Appendix B to this report pro vides the estimated pollutant percent removal expected to be achieved by well-operated POTW s, as reported in the “Memo to the 2006 Effluent Guidelines Program Plan Docket” [ERG, 2006]. F or each plant identified as discharging to a POTW, EPA used the calculated pollutant loadings and the POTW removals shown in Appendix B to calculate the amount of pollutant discharged from the POTW to surface water, according to Equation 11-5.

(11-5) Indirect Pollutant Loading (lb/yr) = Pollutant Loading × (1 - POTW Removal)

where:

Pollutant Loading = The calculated baseline or post-com pliance loadings from a specific pollutant, in pounds/year.

POTW Removal = The estimated percentage of the pollutant loading that will be removed by a POTW.

11.4 P OLLUTANT L OADINGS AND TWPE R ESULTS

In addition to expressing plant-level pollutant loadings in pounds of pollutant discharged per year (described in Section 11.3), EPA used toxic weight ing factors (TWFs) to account for differences in toxicity across pollutants in FGD waste water. 112 EPA calculated a toxic-weighted pound equivalent (TWPE) according to Equation 11-6 for each pollut ant to compare mass loadings between different pollutants based on their toxi city.

(11-6) Pollutant-Specific TWPE = Pollutant-Specific Loading × P ollutant-Specific TWF

EPA also calculated plant-level TWPEs by aggregating the pollutant-specific TWPEs. Using the plant-level mass and TWPE loadings, EPA was then able to calculate the baseline and post-compliance loadings at the industry level for each r egulatory option. The plant-level mass loadings and TWPE loadings are presented in Appendix B. Ta ble 11-15 presents the FGD wastewater loadings on an industry-level for baselin e and each post-compliance technology basis. The table includes the number of plants identified a s discharging FGD wastewater, the total industry flow rate associated with each technology option, and the total industry loading in pounds per year and TWPE per year. Table 11-16 presents the poll utant removals, which EPA

112 A listing of pollutant-specific TWF values can be found in the “Review of Toxic Weighting Factors in Support of

the Final Steam Electric Effluent Limitations Guideline s and Standards” [ERG, 2015g]. EPA has developed TWFs for more than 1,900 pollutants based on aquatic life and human h ealth toxicity data, as well as physical/chemical property data.Section 11 – FGD Wastewater Pollutant Loadings

11-23 calculated by subtracting the technology option loadin gs from the baseline loadings. The pollutant loadings and removals presented in Table 11-15 and T able 11-16 represent the population including adjustments for the CCR rule. The load ings exclude the pollutant parameters BOD, COD, TDS, and TSS because they double-coun t the loadings for specific pollutants already included. Section 15 of this report discusses the use of the FGD wastewater pollutant loadings and estimated pollutant loadings for ot her regulated wastestreams to evaluate the regulatory options considered by EPA.

11.5 R EFERENCES

1. ERG. 2006. Eastern Research Group, Inc. “re: Publicly Own ed Treatment Works (POTW) Percent Removals Used for the TRI Releases2002 Da tabase.” (12 August).

DCN SE02932.

2. ERG. 2015a. Eastern Research Group, Inc. “Changes to Industry Profile for Steam Electric Generating Units for the Steam Electric Effl uent Guidelines Final Rule.” (30 September). DCN SE05069.

3. ERG. 2015b. Eastern Research Group, Inc. “Development Me morandum for the Steam Electric Analytical Database for the Final Rule.” (30 September). DCN SE05876.

4. ERG. 2015c. Eastern Research Group, Inc. FGD_CCR Loadings Database. (30 September). DCN SE05866.

5. ERG. 2015d. Eastern Research Group, Inc. “FGD Wastewater , Combustion Residual Leachate, and Gasification Wastewater Pollutants of C oncern (POC) Analysis Methodology.” (30 September). DCN SE05342.

6. ERG. 2015e. Eastern Research Group, Inc. “Plant-Specific Compliance Cost Estimates

for the Treatment of FGD Wastewater with Chemical P recipitation Followed by Evaporation.” (30 September). DCN SE05730.

7. ERG. 2015f. Eastern Research Group, Inc. “Revised Methodolo gy to Calculate Average Effluent Concentrations for Chemical Precipitation an d Biological Treatment Systems for FGD Wastewater.” (30 September). DCN SE05344.

8. ERG. 2015g. Eastern Research Group, Inc. “Review of Toxic Weighting Factors in Support of the Final Steam Electric Effluent Limitations Guidelines and Standards.” (30 September). DCN SE04479.

9. ERG. 2015h. Eastern Research Group, Inc. “Supplemental Cos ts and Loadings Documentation.” (30 September). DCN SE05839.

10. EPRI. 2006a. Electric Power Research Institute. Flue Gas Desulfurization (FGD) Wastewater Characterization: Screening Study . Palo Alto, CA. (March). Available online at: http://mydocs.epri.com/docs/public/000000000001010162.pdf. Date accessed: 16 May 2008. DCN SE01816.Section 11 – FGD Wastewater Pollutant Loadings

11-24 11. EPRI. 2006b. Electric Power Research Institute. EPRI Technical Manual: Guidance for Assessing Wastewater Impacts of FGD Scrubbers . Palo Alto, CA. (December). Available online at: http://www.epriweb.com/public/000000000001013313.pdf. Date access ed: 16 May 2008. DCN SE01817.

12. Westat. 2015. Statistical Support Document: Effluent Limitations for FGD Wastewater

, Gasification Wastewater, and Combustion Residual Leachate for the Final Ste am Electric Effluent Limitations Guidelines and Standards . (30 September). DCN SE05733.Section 11 – FGD Wastewater Pollutant Loadings

11-25 Table 11-1. Data Sets Used in Developing Effluent Characterizat ion Data for Surface Impoundments

Plant Name Source of Data Set

Duke Energy Carolinas’ Roxboro Steam Plant (Roxboro) State

- submitted p lant monitoring data

Duke Energy’s Miami Fort Station (Miami Fort) EPA on

- site field sampling data

NRG Energy’s Keystone Generating Station (Keystone) EPA on

- site field sampling data

First Energy’s Hatfield’s Ferry Power Station (Hatfield’s Ferry) EPA on

- site field sampling data

NRG Energy’s Dickerson Generating Station (Dickerson) EPA on

- site field sampling data

We Energies’ Pleasant Prairie Power Plant (Pleasant P rairie) EPA on

- site field sampling data

Duke Energy Carolinas’ Allen Steam Station (Allen) EPA on

- site field sampling data

Industry

- submitted p lant monitoring data

Duke Energy Carolinas’ Belews Creek Steam Station (Belew s Creek) EPA on

- site field sampling data

Industry

- submitted plant monitoring data

Source: ERG, 2015b; ERG, 2015d.Section 11 – FGD Wastewater Pollutant Loadings

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

Analyte a Unit Average Concentration

Aluminum ug/L 2,080

Ammonia as N ug/L No Data

Antimony ug/L 12.9

Arsenic ug/L 7.59

Barium ug/L 303

Beryllium ug/L 1.92

Boron ug/L 243,000

Cadmium ug/L 113

Calcium ug/L 2,050,000

Chloride ug/L 7,120,000

Chromium ug/L 17.8

Cobalt ug/L 183

Copper ug/L 21.8

Cyanide ug/L No Data

Iron ug/L 1,5 10

Lead ug/L 4.66

Magnesium ug/L 3,370,000

Manganese ug/L 93,400

Mercury ug/L 7.78

Molybdenum ug/L 125

Nickel ug/L 878

Nitrate-Nitrite as N ug/L No Data

Phosphorus, Total ug/L No Data

Selenium ug/L 1,170

Sodium ug/L 276,000

Thallium ug/L 13.7

Titanium ug/L 27.1

TDS ug/L 32,500,000

TSS ug/L 27,900

Vanadium ug/L 16.4

Zinc ug/L 1,390

Source: ERG, 2015b; ERG, 2015d.

Note: Concentrations are rounded to three significant fi gures. No Data – EPA does not have data for some pollutants identif ied as POCs.

a – All metals concentrations are estimated as the t otal recoverable metals concentrations.. The concentr ations presented are not the expected dissolved metals concentratio ns.Section11 – FGD Wastewater Pollutant Loadings11-27Table 11-3. Characteristics of FGD Blowdown at EPRI Sites P,R, and SParameterUnitsSite PSite RSite SFilteredSettledTotalFilteredSettledTotalFilteredSettledTotalAluminum μg/L 1,000 U 1,000 U26,0001,000 U 1,000 U102,000200 U 1,990174,000Antimony μg/L 50 U 50 U500U 50 U 50 U500U 10 U 10 U500UArsenic μg/L 30 U 30 U300U 30 U 30 U300U 10 U 10 U240Barium μg/L 1,030 1,0602,500U 250 U 250 U2,93060 U 583,040Beryllium μg/L 40 U 40 U400U 40 U 40 U400U 8 U 8 U400UBoron μg/L 255,000 261,000244,000411,000 407,000340,00088,300 87,90085,200Cadmium μg/L 50 U 50 U500U 50 U 50 U500U 37.8 39.6500UCalcium μg/L 4,240,000 4,440,00030,500,000748,000 751,00034,300,000N/A N/AN/AChromium μg/L 100 U 100 U1,030100 U 100 U1,000U 20 U 20 U1,050Chromium VI μg/LCobalt μg/L 100 U 100 U1,000U 100 U 100 U1,000U 55.8 57.71,000UCopper μg/L 100 U 100 U1,000U 321 2984,230U 47.4 68.61,530Iron μg/L 1,000 U 1,63060,9001,000 U 1,000 U185,000200 U 1,850257,000Lead μg/L 50 U 50 U500U 50 U 50 U500U 10 U 10 U500UMagnesium μg/L 4,510,000 4,710,0004,290,0001,140,000 1,150,0001,050,000994,000 1,030,0001,040,000Manganese μg/L 6,390 6,5308,4101,650 1,67014,90013,900 13,80014,200Mercury μg/L 0.55 2.373.67.4 6.491.60.1 1.2103Molybdenum μg/L 532 5492,500U 250 U 250 U2,500U 76.2 79.32,500UNickel μg/L 447 4632,000U 200 U 200 U2,000U 258 2632,000UPotassium μg/L 1,060,000 1,120,000684,00028,000 27,10070,60020,600 22,70098,500Selenium μg/L 1,610 1,6602,9301,810 1,8602,000U 485 5082,000USelenium IV μg/L41435 *Selenium VI μg/L41,700 *Silver μg/L 100 U 100 U1,000U 100 U 100 U1,000U 20 U 20 U1,000USodium μg/L 5,530,000 5,550,0005,340,000943,000 950,000867,000135,000 140,000112,000Strontium μg/LThallium μg/L 100 U 100 U1,000U 100 U 100 U1,000U 20 U 20 U1,000UTitanium μg/L 1,000 U 1,000 U10,000U 1,000 U 1,000 U10,000U 200 U 200 U10,000UVanadium μg/L 250 U 250 U2,500U 250 U 250 U2,500U 50 U 50 U2,500UZinc μg/L 200 U 200 U2,000U 200 U 200 U2,000U 1,080 1,1003,440Acidity mg CaCO3/L 800 780950400 39747054 5070Alkalinity mg CaCO3/L 155 1703,200625 6205,040202 200250Section11 – FGD Wastewater Pollutant Loadings11-28Table 11-3. Characteristics of FGD Blowdown at EPRI Sites P,R, and SParameterUnitsSite PSite RSite SFilteredSettledTotalFilteredSettledTotalFilteredSettledTotalChlorideamg/L 29,200 29,20028,800982 9639791,120 1,1501,180Conductivity μhos/cm 79,000 8070085,0008,570 8,5207,6906,360 6,3905,990Fluorideamg/L 5.812.916.3Hardness as CaCO3mg/LpH pH units 6.7 6.76.77.3 7.27.17.3 7.17.1Sulfateamg/L 2,1804,7503,240TDS mg/L 48,400 48,10057,70012,600 12,80014,200N/A 8,1709,770TKN mg N/L 63.9 7997.333.5 3145.92.9 2.42UTSS mg/L 8 9194,9002 U 2 U170,000N/A 2487,600Observations High TSS and chloride Appears R dumpsdue to solids rather than chloride Low chlorideFlow (gpm avg) No information from siteNo information from site117.5Source: EPRI, 2006a.U = Non-detect.N/A = Not applicable.*Results from Sites S and T for selenium speciation werefrom different samples (collected August 2005) than the other parameters (collected October 2005) at those sites.a – Chloride, fluoride, and sulfate were analyzed by ICP-MS so filtered in analysis. Therefore, “Total,” “Settled,” and “filtered” are all actually the same evaluation so only onewas reported.Section11 – FGD Wastewater Pollutant Loadings11-29Table 11-4. Characteristics of FGD Blowdown at EPRI Sites T,U, and YParameterUnitsSite TSite USite YFilteredSettledTotalFilteredSettledTotalFilteredSettledTotalAluminum μg/L 1,000 U 1,810170,000403 73995525,100 26,30026,500Antimony μg/L 50 U 50 U500U 10 U 10 U10U 14.1 17.716.4Arsenic μg/L 10 U 10 U41515.5 16.317.31.6 5.86.1Barium μg/L 250 U 250 U2,960207 232254225 158136Beryllium μg/L 40 U 40 U400U 8 U 8 U8U 4 U 4 U4UBoron μg/L 360,000 359,000344,00014,900 14,40015,10014,300 17,10017,500Cadmium μg/L 96.7 96.4500U 10 U 16.312.221 21.521.3Calcium μg/L N/A N/AN/A659,000 650,000680,000725,000 737,000757,000Chromium μg/L 100 U 100 U1,000U 20 U 20 U20U 12 35.937.2Chromium VI μg/LCobalt μg/L 100 U 100 U1,000U 20 U 20 U20U 26.7 2828.2Copper μg/L 100 U 1211,000U 136 157152145 158157Iron μg/L 1,000 U 2,060292,000200 U 657974100 U 2,4902,580Lead μg/L 50 U 50 U500U 10 U 10 U10U 5 U 5 U5UMagnesium μg/L 2,550,000 2,510,0002,680,000851,000 838,000873,000199,000 204,000205,000Manganese μg/L 19,300 19,00023,8005,380 5,3505,4801,810 1,8401,840Mercury μg/L 0.44 1.4783.3 7.17.59 9.59.5Molybdenum μg/L 758 7482,500U 86.6 88.789.625 U 34.435.4Nickel μg/L 687 6942,000U 173 17318192.1 96.294.5Potassium μg/L 202,000 195,000241,000329,000 309,000326,00021,900 22,30023,200Selenium μg/L 1,150 1,1602,000U 40 U 40 U40U 131 157172Selenium IV μg/L 90 *4.34Selenium VI μg/L 1,350 *6Silver μg/L 100 U 100 U1,000U 20 U 20 U20U 10 U 10 U10USodium μg/L 389,000 396,000323,0002,540,000 2,400,0002,580,00051,600 51,60052,000Strontium μg/LThallium μg/L 100 U 100 U1,000U 20 U 20 U20U 10 U 14.310UTitanium μg/L 1,000 U 1,000 U10,000U 200 U 200 U200U 100 U 152163Vanadium μg/L 250 U 250 U2,500U 50 U 50 U50U 25 U 25 U25UZinc μg/L 3,480 3,4409,04053 54.2581,290 1,3101,310Acidity mg CaCO3/L 268 23227442.2 4544.2128 124122Alkalinity mg CaCO3/L 200 1362,10076 74755 U 5 U5USection11 – FGD Wastewater Pollutant Loadings11-30Table 11-4. Characteristics of FGD Blowdown at EPRI Sites T,U, and YParameterUnitsSite TSite USite YFilteredSettledTotalFilteredSettledTotalFilteredSettledTotalChlorideamg/L 3,850 3,7503,6503,610 3,6503,610584 589592Conductivity μhos/cm 11,800 11,50011,40013,300 13,40013,4003,620 3,6203,590Fluorideamg/L 48.68.251.6Hardness as CaCO3mg/L5,450 5,5005,7002,860 2,8002,860pH pH units 7.2 7.27.27.3 7.27.36 5.85.9Sulfateamg/L 6,0904,3401,480TDS mg/L N/A 16,40015514,300 14,40014,6004,360 4,3704,350TKN mg N/L 13.8 11.811.439.8 32.537.12.2 2.52.5TSS mg/L N/A 23113,7003 U 18325 U 2.935Observations Oddly low TSS and chlorideLow TSS is due to thickener Oddly low TSS and chlorideFlow (gpm avg) No distinct chloride purge stream Based on chloride content of 9,000 ppm Monthly (for 1hour)Source: EPRI, 2006a.U = Non-detect.N/A = Not applicable.*Results from Sites S and T for selenium speciation werefrom different samples (collected August 2005) than the other parameters (collected October 2005) at those sites.a – Chloride, fluoride, and sulfate were analyzed by ICP-MS so filtered in analysis. Therefore, “Total,” “Settled,” and “filtered” are all actually the same evaluation so only onewas reported.Section 11 – FGD Wastewater Pollutant Loadings

11-31 Table 11-5. Data Sets Used in Developing Effluent Characterizat ion Data for Chemical Precipitation

Plant Name Source of Data Set

First Energy’s Hatfield’s Ferry Power Station (Hatfiel d’s Ferry) EPA on

- site field sampling data

CWA 308 monitoring data

Industry

- submitted p lant monitoring data

NRG Energy’s Keystone Generating Station (Keystone) EPA on

- site field sampling data

CWA 308 monitoring data

Industry

- submitted p lant monitoring data

Duke Energy’s Miami Fort Station (Miami Fort) EPA on

- site field sampling data

CWA 308 monitoring data

Industry

- submitted p lant monitoring data

We Energies’ Pleasant Prairie Power Plant (Pleasant P rairie) EPA on

- site field sampling data

CWA 308 monitoring data

Industry

- submitted plant monitoring data

Source: ERG, 2015b; ERG, 2015d.Section 11 – FGD Wastewater Pollutant Loadings

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

Analyte Unit Average Concentration

Aluminum ug/L 120

Ammonia as N ug/L 6,850

Antimony ug/L 4.25

Arsenic ug/L 5.83

Barium ug/L 140

Bery llium ug/L 1.34

Boron ug/L 225

, 000

Cadmium ug/L 4.21

Calcium ug/L 1,920, 0 00

Chloride ug/L 7,8 20,000

Chromium ug/L 6.45

Cobalt ug/L 9.30

Copper ug/L 3.78

Cyanide ug/L 94 9

Iron ug/L 110

Lead ug/L 3.39

Magnesium ug/L 3,57 0,000

Manganese ug/L 12, 500

Mercury ug/L 0.1 39

Molybdenum ug/L 16 6

Nickel ug/L 9.11

Nitrat e

- Nitrite as N ug/L 9 6,000

Phosphorus, Total ug/L 319

Selenium ug/L 92 8

Sodium ug/L 441, 000

Thallium ug/L 9.81

Titanium ug/L 9.30

TSS ug/L 2 4, 100,000

TDS ug/L 8,590

Vanadium ug/L 12.63

Zinc ug/L 20.0

Source: ERG, 2015b; ERG, 2015d.

Note: Concentrations are rounded to three significant fi gures.Section 11 – FGD Wastewater Pollutant Loadings

11-33 Table 11-7. Data Sets Used in Developing Effluent Characterizat ion Data for Biological Treatment

Plant Name Source of Data Set

Duke Energy Carolinas’ Allen Steam Station (Allen) EPA on

- site field sampling data

CWA 308 monitoring data

Industry

- submitted p lant monitoring data

Duke Energy Carolinas’ Belews Creek Steam Station (Belew s Creek) EPA on

- site field sampling data

CWA 308 monitoring data

Industry

- submitted plant monitoring data

Source: ERG, 2015b; ERG, 2015d.Section 11 – FGD Wastewater Pollutant Loadings

11-34 Table 11-8. Average Effluent Concentration of Chemical Precipi tation System with Biological Treatment

Analyte Unit Average Concentration

Aluminum ug/L 279

Ammonia as N ug/L 8,750

Antimony ug/L 3.70

Arsenic ug/L 3.52

Barium ug/L 313

Beryllium ug/L 1.20

Boron ug/L 143,000

Cadmium ug/L 2.73

Calcium ug/L 2,510,000

Chloride ug/L 4,990,000

Chromium ug/L 2.77

Cobalt ug/L 8.17

Copper ug/L 7.17

Cyanide ug/L 74.3

Iron ug/L 425

Lead ug/L 1.41

Magnesium ug/L 628,000

Manganese ug/L 1,730

Mercury ug/L 0.05 07

Molybdenum ug/L 34.4

Nickel ug/L 6.30

Nitrate

- Nitrite as N ug/L 647

Phosphorus, Total ug/L 115

Selenium ug/L 5.72

Sodium ug/L 41,100

Thallium ug/L 2.36

Titanium ug/L 13. 0

TDS ug/L 13,800 ,000

TSS ug/L 8,650

Vanadium ug/L 4.44

Zinc ug/L 6.32

Source: ERG, 2015b; ERG, 2015d.

Note: Concentrations are rounded to three significant fi gures.

Table 11-9. Data Sets Used in Developing Effluent Characterizat ion Data for Evaporation Treatment

Plant Name Source of Data Set

Enel’s Federico II Power Plant (Brindisi) CWA 308 monitoring data

Source: ERG, 2015b; ERG, 2015d.Section 11 – FGD Wastewater Pollutant Loadings

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

Analyte Unit Average Concentration

Aluminum ug/L 100

Ammonia as N ug/L 24,300

Antimony ug/L 1.00

Arsenic ug/L 2.00

Barium ug/L 10.0

Beryllium ug/L 1.00

Boron ug/L 3,750

Cadmium ug/L 2.00

Calcium ug/L 200

Chloride ug/L 1,500

Chromium ug/L 4.00

Cobalt ug/L 10.0

Copper ug/L 2.00

Cyanide ug/L No Data

Iron ug/L 100

Lead ug/L 1.00

Magnesium ug/L 200

Manganese ug/L 10 .0

Mercury ug/L 0 .0103

Molybdenum ug/L 20.0

Nickel ug/L 2.00

Nitrate

- Nitrite as N ug/L 100

Phosphorus, Total ug/L 25.0

Selenium ug/L 2.00

Sodium ug/L 5,000

Thallium ug/L 1.00

Titanium ug/L 10 .0

TDS ug/L 10,800

TSS ug/L 2,000

Vanadium ug/L 5.00

Zinc ug/L 28.5

Source: ERG, 2015b; ERG, 2015d.

Note: Concentrations are rounded to three significant fi gures. No Data – EPA does not have data for some pollutants identif ied as POCs.Section 11 – FGD Wastewater Pollutant Loadings

11-36 Table 11-11. Pollutant Concentration Basis for Surface Impoundme nts

Analyte Concentration Basis Unit Average Concentration

Aluminum Surface Impoundment ug/L 2,080

Ammonia as N CP Effluent ug/L 6,85 4

Antimony Surface Impoundment ug/L 12. 9

Arsenic Surface Impoundment ug/L 7.59

Barium Surface Impoundment ug/L 303

Beryllium Surface Impoundment ug/L 1.92

Boron Surface Impoundment ug/L 24 3,000

Cadmium Surface Impoundment ug/L 11 3

Calcium Surface Impoundment ug/L 2,050, 000

Chloride Surface Impoundment ug/L 7,120, 000

Chromium Surface Impoundment ug/L 17.8

Cobalt Surface Impoundment ug/L 18 3

Copper Surface Impoundment ug/L 21. 8

Cyanide CP Effluent ug/L 94 9

Iron Surface Impoundment ug/L 1,5 10

Lead Surface Impoundment ug/L 4.66

Magnesium Surface Impoundment ug/L 3,37 0,000

Manganese Surface Impoundment ug/L 93, 400

Mercury Surface Impoundment ug/L 7.78

Molybdenum Surface Impoundment ug/L 125

Nickel Surface Impoundment ug/L 878

Nitrate

- Nitrite as N CP Effluent ug/L 9 6,000

Phosphorus, Total CP Effluent ug/L 319

Selenium Surface Impoundment ug/L 1,1 70

Sodium Surface Impoundment ug/L 27 6,000

Thallium Surface Impoundment ug/L 13.7

Titanium Surface Impoundment ug/L 27. 1

TDS Surface Impoundment ug/L 32, 500,000

TSS Surface Impoundment ug/L 27,9 00

Vanadium Surface Impoundment ug/L 16.4

Zinc Surface Impoundment ug/L 1,39 0

Source: ERG, 2015b; ERG, 2015d.

Note: Concentrations are rounded to three significant fi gures.Section 11 – FGD Wastewater Pollutant Loadings

11-37 Table 11-12. Pollutant Concentration Basis for Chemical Precipi tation

Analyte Concentration Basis Unit Average Concentration

Aluminum CP Effluent ug/L 120

Ammonia as N CP Effluent ug/L 6,85 4

Antimony CP Effluent ug/L 4.25

Arsenic CP Effluent ug/L 5.83

Barium CP Effluent ug/L 140

Beryllium CP Effluent ug/L 1.34

Boron CP Effluent ug/L 22 5,000

Cadmium CP Effluent ug/L 4.21

Calcium CP Effluent ug/L 1,920, 000

Chloride Surface Impoundment ug/L 7,120, 000

Chromium CP Effluent ug/L 6.45

Cobalt CP Effluent ug/L 9.30

Copper CP Effluent ug/L 3.78

Cyanide CP Effluent ug/L 94 9

Iron CP Effluent ug/L 110

Lead CP Effluent ug/L 3.39

Magnesium Surface Impoundment ug/L 3,37 0,000

Manganese CP Effluent ug/L 12, 500

Mercury CP Effluent ug/L 0.139

Molybdenum Surface Impoundment ug/L 125

Nickel CP Effluent ug/L 9.11

Nitrate

- Nitrite as N CP Effluent ug/L 9 6,000

Phosphorus, Total CP Effluent ug/L 319

Selenium CP Effluent ug/L 92 8

Sodium Surface Impoundment ug/L 27 6,000

Thallium CP Effluent ug/L 9.81

Titanium CP Effluent ug/L 9.30

TDS CP Effluent ug/L 24, 100,000

TSS CP Effluent ug/L 8,590

Vanadium CP Effluent ug/L 12.6

Zinc CP Effluent ug/L 20.0

Source: ERG, 2015b; ERG, 2015d.

Note: Concentrations are rounded to three significant fi gures.Section 11 – FGD Wastewater Pollutant Loadings

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

Analyte Concentration Basis Unit Average Concentration

Aluminum CP Effluent ug/L 120

Ammonia as N CP Effluent ug/L 6,85 4

Antimony CP Effluent ug/L 4.25

Arsenic CP Effluent ug/L 5.83

Barium CP Effluent ug/L 140

Beryllium CP Effluent ug/L 1.34

Boron CP Effluent ug/L 22 5,000

Cadmium CP Effluent ug/L 4.21

Calcium CP Effluent ug/L 1,920, 000

Chloride Surface Impoundment ug/L 7,120, 000

Chromium CP Effluent ug/L 6.45

Cobalt CP Effluent ug/L 9.30

Copper CP Effluent ug/L 3.78

Cyanide CP Effluent ug/L 94 9

Iron CP Effluent ug/L 110

Lead CP Effluent ug/L 3.39

Magnesium Surface Impoundment ug/L 3,37 0,000

Manganese CP Effluent ug/L 12, 500

Mercury Bio Effluent ug/L 0.05 07

Molybdenum Surface Impoundment ug/L 125

Nickel Bio Effluent ug/L 6.30

Nitrate

- Nitrite as N Bio Effluent ug/L 64 7

Phosphorus, Total CP Effluent ug/L 319

Selenium Bio Effluent ug/L 5.72

Sodium Surface Impoundment ug/L 27 6,000

Thallium CP Effluent ug/L 9.81

Titanium CP Effluent ug/L 9.30

TDS CP Effluent ug/L 24, 100,000

TSS CP Effluent ug/L 8,590

Vanadium CP Effluent ug/L 12.6

Zinc CP Effluent ug/L 20.0

Source: ERG, 2015b; ERG, 2015d.

Note: Concentrations are rounded to three significant fi gures.Section 11 – FGD Wastewater Pollutant Loadings

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

Analyte Concentration Basis Unit Average Concentration

Aluminum Evaporation Effluent ug/L 100 .0

Ammonia as N Evaporation Effluent ug/L 24

, 3 00

Antimony Evaporation Effluent ug/L 1 .00

Arsenic Evaporation Effluent ug/L 2 .00

Barium Evaporation Effluent ug/L 10 .0

Beryllium Evaporation Effluent ug/L 1 .00

Boron Evaporation Effluent ug/L 3

, 750

Cadmium Evaporation Effluent ug/L 2 .00

Calcium Evaporation Effluent ug/L 200

Chloride Evaporation Effluent ug/L 1

, 500

Chromium Evaporation Effluent ug/L 4 .00

Cobalt Evaporation Effluent ug/L 10 .0

Copper Evaporation Effluent ug/L 2 .00

Cyanide CP Effluent ug/L 94 9

Iron Evaporation Effluent ug/L 100

Lead Evaporation Effluent ug/L 1 .00

Magnesium Evaporation Effluent ug/L 200

Manganese Evaporation Effluent ug/L 10 .0

Mercury Evaporation Effluent ug/L 0.0103

Molybdenum Evaporation Effluent ug/L 20 .0

Nickel Evaporation Effluent ug/L 2 .00

Nitrate

- Nitrite as N Evaporation Effluent ug/L 100

Phosphorus, Total Evaporation Effluent ug/L 25 .0

Selenium Evaporation Effluent ug/L 2 .00

Sodium Evaporation Effluent ug/L 5

, 000

Thallium Evaporation Effluent ug/L 1 .00

Titanium Evaporation Effluent ug/L 10 .0

TDS Evaporation Effluent ug/L 10

, 8 00

TSS Evaporation Effluent ug/L 2

, 000

Vanadium Evaporation Effluent ug/L 5 .00

Zinc Evaporation Effluent ug/L 28.5

Source: ERG, 2015b; ERG, 2015d.

Note: Concentrations are rounded to three significant fi gures.Section 11 – FGD Wastewater Pollutant Loadings

11-40 Table 11-15. Industry-Level FGD Wastewater Loadings Excluding BO D, COD, TDS, and

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

Basis

Treatment Option Number of

Plants Total Industry

Discharge Flow (MGD) a Total Industry Loadings

Pounds/Year TWPE/Year

Baseline 88 b 41.7 1,660,000,000 1,880,000

Chemical Precipitation 88 b 38.4 1,620,000,000 1,070,000

Chemical Precipitation W ith Biological

Treatment 88 b 38.4 1,610,000,000 925,000

Note: Excludes loadings for pollutants not identified as POC s and for BOD, COD, TDS and TSS.

Note: Loadings are rounded to three significant figures.

a – The reduction in total industry discharge flow from bas eline to the technology options is associated with the plants for which EPA assumed that some recycle of the FGD wastewater would occur prior to treatment, as

described in Section 4.5.2.

b – One plant operates only oil-fired generating units and/or generating units with a generating capacity of 50 MW or less; therefore, this plant is not facing any mor e stringent requirements than exist under the previously est ablished 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 curre nt baseline level and will not achieve any pollutant removal s for the technology options evaluated.

Table 11-16. FGD Wastewater Pollutant Removals Excluding BOD, CO D, TDS, and TSS

and Based on Oil-Fired Units and Units 50 MW or Less Not I nstalling Technology Basis

Treatment Option Total Industry Removals

Pounds/Year TWPE/Year

Removal (Baseline

– > Chemical Precipitation) 36,800,000 804,000

Removal (Baseline

– > Chemical Precipitation W ith Bio logical Treatment) 47,200,000 952,000

Note: Excludes loadings for pollutants not identified as POC s and for BOD, COD, TDS and TSS.

Note: Removals are rounded to three significant figures. T he removals may not equal the subtraction of the technology option from the baseline using the values in T able 11-15 due to rounding.Section 12 – Ash Transport Water Pollutant Loadings

12-1 

## 12. ASH TRANSPORT WATER POLLUTANT LOADINGS

This section discusses annual pollutant loadings from exist ing steam electric power plants that discharge ash transport water and pollutant removals estimates associated with the final rule, as well as several other regulatory options. EPA identified 144 plants that discharged ash transport water in 2009 (fly ash transport water, bottom ash transpo rt water, and/or combined ash transport water) and have no plans to retire, convert fuels, or c onvert to dry ash handling prior to December 31, 2023, or convert to complete dry ash handling due to the C oal Combustion Residuals (CCR) rule. For these plants, EPA evaluated zero discharge technology options as one of the bases for final requirements for fly ash and bottom ash transport wate r. For other technology options, EPA applied different effluent limitations to oil-fired generating units and generating units with a specific capacity (50 megawatts (MW) or less or 400 MW or less). I n these cases, the plants will not face more stringent requirements than already existed under pree xisting regulations; thus, postcompliance loadings are set equal to the baseline loading s. EPA defined baseline loadings and postcompliance pollutant loadings for ash transport water as follows:

• Baseline Loadings . Estimated pollutant loadings, in pounds per year, of fl y ash transport water or bottom ash transport water discharged dir ectly to surface water or indirectly to surface water through publicly owned treatmen t works (POTWs) at the current level of treatment (i.e., treatment-in-place ) and prior to implementing controls to comply with the final rule.

• Post-Compliance Loadings . Estimated pollutant loadings, in pounds per year, of fl y ash transport water or bottom ash transport water afte r implementation of the technology option. EPA calculated these loadings assumi ng that all steam electric power plants subject to the requirements would install and ope rate wastewater treatment and pollution prevention technologies equivale nt to the technology bases for the regulatory options (i.e., zero discharge technolog ies).

• Pollutant Removals . The difference between the baseline loadings and postcompliance loadings for each technology option.

Loadings calculations require a pollutant-specific conce ntration and plant-specific discharge flow to determine mass discharge loadings. EPA used a va riety of data sources to generate characterization data for fly ash transport water and bottom ash transport water. To generate the ash loadings, EPA developed three separate sets of characteri zation data to represent the effluent concentrations from fly ash impoundments, bottom ash impo undments, and combined fly ash and bottom ash impoundments. EPA then identified the ash im poundments operating in the industry and categorized them into the three types of impoundments. Finally, EPA calculated ash loadings using flow rate data for each generating unit/impoundment combinat ion and multiplying them by the appropriate concentrations based on the type of impoundme nt.

Section 12.1 presents the data sources used to characterize ash transport water. Section 12.2 discusses the methodology used to calculate the plant-s pecific discharge flow rates, as well as the baseline and technology option pollutant loadings and pollut ant removals. Section 12.3 presents the ash pollutant loadings and toxic-weighted pound equivalents (TWPE). Section 12.4 discussesSection 12 – Ash Transport Water Pollutant Loadings

12-2 sensitivity analyses of the ash loadings. All tables a nd figures referenced in this section are presented at the end of the section.

12.1 D ATA S OURCES

EPA relied on data collected during the detailed study, indust ry-supplied data, and publicly available data sources, including data received during public com ment, to identify pollutants of concern (POCs) in fly ash transport water and bottom ash transport water, and to characterize pollutant discharge concentrations from ash impoundments ( fly ash, bottom ash, and combined ash).

EPA also used data collected in the Questionnaire for the Steam Electric Power Generating Effluent

Guidelines (Steam Electric Survey) to characterize discharge flows . A list of data sources evaluated and accepted by EPA to identify POCs and characterize the discharges from ash impoundments are

listed below:

• EPA ash impoundment sampling data from the detailed study [ U.S. EPA, 2009].

• The Steam Electric Technical Questionnaire Database [E RG, 2015i].

• Bottom Ash Wastewater Evaluation: Interstate Power and Light Co. – Dubuque Generating Station [Interstate, 2004]

• Electric Power Research Institute (EPRI) Power Plant Integrated Systems - Chemical Emissions Study (PISCES) Reports [EPRI, 1997-2001].

• Mitigation of SCR-Ammonia Related Aqueous Effects in a Fly Ash Pond [EPRI, 2006].

• Permit application data (Form 2C), as provided by member comp anies 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 Poi nt Source Category, EPA 440-1-82-029, November 1982 (1982 TDD) [U.S. EPA, 1982].

• Public comments received from Duke Energy, including response s to EPA follow-up questions regarding the data submitted in comments [Duke Energ y, 2013 and 2014].

• Public comments received from Hoosier Energy Rural Elect ric Cooperative, including responses to EPA follow-up questions regarding the da ta submitted in comments [Hoosier Energy, 2013 and 2014].

• Public comments and supplemental data received from UWAG, including responses to EPA follow-up questions and post-proposal data submissions [ UWAG, 2013, 2014a, and 2014b].

EPA performed a detailed review of each of these sources to identify ash transport water characterization data that met EPA’s data acceptance c riteria for inclusion in analyses for identifying POCs and for characterizing discharges of ash t ransport water. EPA determined criteria for data acceptance, described in Table 12-1, and applied the criteria to each of the data sources.Section 12 – Ash Transport Water Pollutant Loadings

12-3 During the data review, EPA extracted information from eac h data source to complete a data review

matrix. Information extracted from each data source in cluded:

• Data source identification.

• Plant identification.

• Wastestream identification (i.e., the type of ash tra nsport water, degree of treatment the sample(s) represent).

• Sample identification (i.e., count of samples, wheth er these samples represented individual data points or averages).

• Data usability (e.g., pollutants, units of measure, collec tion methods, analytical methods, and limits identified).

• Representativeness of wastestream (i.e., appropriate sa mple location, sample quality, typical and full-scale operations).

• Wastestream characterization (e.g., relative contribut ion of wastestreams making up the sample).

Because EPA collected and used data from a variety of sour ces, the data review matrix

allowed EPA to ensure that data were evaluated consistentl y across all sources. EPA’s collection, evaluation, and use of ash data is described in detail in the “Ash Analytical Data Review Memorandum” [ERG, 2015b]. In its review, EPA excluded data th at did not meet the data acceptance criteria and therefore were not usable in the ash POC analysis and/or calculation of pollutant loadings. EPA’s acceptance of each ash data set evaluated during this review is provided in the “Ash Data Review Matrix” [ERG, 2015j]. EPA included ash impoundment effluent data of acceptable quality for use in the pollutant loadings calcul ations in the Steam Electric Analytical Database [ERG, 2015a].

The following sections describe each of the data sources EPA used in the ash analytical database and the creation of a data set of ash impoundme nt effluent concentrations by impoundment type and pollutant. For each set of data from each source, EPA used available information to characterize the impoundment/outfall as either a fly ash impoundment, bottom ash impoundment, or combined ash impoundment. For the purposes of this analysis, the following criteria were used to

create those determinations:

• Fly ash impoundment: An impoundment/outfall that receive s at least 75 percent by volume fly ash transport water and does not receive bott om ash transport water. The impoundment may also receive other types of wastewater (e.g., low-volume wastewaters, cooling water, etc.).

• Bottom ash impoundment: An impoundment/outfall that rece ives 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 wastew ater (e.g., low-volume wastewaters, cooling water, etc.).Section 12 – Ash Transport Water Pollutant Loadings

12-4 • Combined ash impoundment: An impoundment/outfall where the combination of fly ash and bottom ash transport water comprises at least 75 percent by volume of the total flow. The impoundment may also receive other type s of wastewater (e.g., lowvolume wastewaters, cooling water, etc.).

To ensure the wastestreams are representative of ash t ransport water, EPA established the data acceptance criteria listed above, ensuring that at l east 75 percent of the impoundment volume comprises ash transport water. Data characterizing impoun dments that contained less than 75 percent by volume of ash transport water were excluded fr om use in the POC analysis and pollutant loadings analysis because the presence of dilution volume s, such as cooling water, will result in an underestimate of pollutant concentrations.

EPA conducted an analysis to identify POCs for ash tran sport water. EPA included data for fly ash and bottom ash transport water samples but did n ot include combined ash transport water samples in the POC analysis. Due to the limited data set for untreated fly transport water and bottom ash transport water, EPA also included samples r epresenting partially treated fly ash and bottom ash transport water and fly ash and bottom ash i mpoundment effluent to identify POCs for

each wastestream. For wastestreams where EPA is est ablishing zero discharge (i.e., fly ash transport water, bottom ash transport water, and flue gas mercury c ontrol (FGMC) wastewater), the POCs identified for each wastestream are those pollutants t hat are confirmed to be present at sufficient frequency in untreated wastewater samples of that was testream. Because EPA did not need to identify pollutants at a treatable level, EPA determined pa rtially treated ash transport water data and ash impoundment effluent data were also acceptable in the POC analysis.

For some of the ash transport water data, industry also supplied paired source water data to demonstrate that the source water used for ash transport may contribute to the pollutants present in untreated ash transport water. Where paired source water and ash transport water samples were available, EPA reviewed data for the paired source water a nd ash transport water to identify pollutants detected at greater than or equal to two times t he 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 sufficientl y 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 ind icate the presence of the pollutant in ash transport water, EPA reviewed data for ash transport wat er without paired source water data and identified pollutants detected at greater than or equal to two times the pollutant’s baseline value at 10 percent or more of all plants with unpaired samples. EPA used baseline values from the Development Document for Effluent Limitations Guidelines and Standards for t he Centralized Waste Treatment Industry [U.S. EPA, 2000]. More details on EPA’s POC analysis for ash transport water, the data accepted for identifying POCs, and resul ts of the analysis are documented in the memorandum, “Bottom Ash and Fly Ash Transport Water Po llutants of Concern (POC) Analysis Methodology” [ERG, 2015d].

EPA estimated pollutant loadings and removals for pollut ants that were identified as POCs for fly ash transport water, bottom ash transport wate r, or that were identified as constituents ofSection 12 – Ash Transport Water Pollutant Loadings

12-5 combined ash impoundments. 113 Sections 12.1.1 through Section 12.1.8 focus on the data from each data source that was accepted for use in the ash lo adings analysis to estimate average pollutant concentrations of ash impoundment effluents and calculat e the pollutant loadings from ash impoundments. The remainder of Section 12 discusses EPA’s methodology for developing average concentrations and calculating pollutant loadings and appli es only to pollutants identified as POCs.

12.1.1 EPA Detailed Study Ash Impoundment Sampling Data

As discussed in Section 3.3.1, EPA conducted a sampling progr am as part of the detailed study to characterize untreated wastewaters generated by co al-fired steam electric power plants, as well to evaluate treatment technologies and best mana gement practices for reducing pollutant discharges. During the sampling program, EPA identified that four plants operated some type of wet ash handling system, either wet bottom ash handling, wet fly ash handling, or both. EPA collected samples representing two impoundments receiving fly ash t ransport water, one impoundment receiving bottom ash transport water, and one impoundment that received combined fly ash and bottom ash transport water [U.S. EPA, 2009]. The impoundme nts at the four plants were categorized as follows:

• Cardinal – Fly ash impoundment.

• Homer City – Bottom ash impoundment.

• Mitchell – Fly ash impoundment.

• Widows Creek – Combined ash impoundment.

In the proposed rulemaking, EPA included the results represe nting effluent from these four impoundments in the ash analytical database and ash loa dings calculations. Following proposal and review of the public comments, EPA revised the acceptance criteria for ash impoundment effluent concentration data for the final rulemaking to use ash i mpoundment characterization data only from an impoundment or outfall where ash contributions to the impoundment are at least 75 percent ash transport water by volume. For each of the four plants sampled, EPA reviewed available materials to determine if the ash impoundment effluent samples met the acceptance criteria described in Table 12-1. Based on the review of sampling episode reports and pla nt-provided responses to the Steam Electric Survey, EPA identified one plant that had data acceptable for use in characterizing bottom ash impoundment effluent. Sampling data from the other thr ee plants contain less than 75 percent by volume of ash transport water and were not accepted fo r the ash loadings analysis.

EPA included the results from the Homer City plant sam pling episode in the ash impoundment effluent concentrations data set. However, be cause EPA had additional information about these sampling data (e.g., quality control (QC) res ults) and because some of the metals were analyzed using two different analytical methods, EPA’s lo adings methodology included a hierarchy to select which data should be included in the loadings calcu lations. The following are the steps EPA used to identify which concentrations to use in the H omer City bottom ash impoundment

concentrations data set:

113 EPA calculated combined ash pollutant loadings for fly a sh transport water and bottom ash transport water POCs , as well as biochemical oxygen demand (BOD), cyanide, hexava lent chromium (chromium VI), and silver which were identified as constituents of combined fly ash and bottom a sh impoundments.Section 12 – Ash Transport Water Pollutant Loadings

12-6 • EPA received both routine (e.g., EPA Methods 200.7, 200.8) an d low-level (i.e., EPA Method 1638) analytical results for 13 of the 28 metal a nalytes. To determine

whether the routine or low-level measurement should be used in the loadings calculation, EPA developed a decision tree (see Figure 12-1). All of the sampling data for these 13 metal analytes were analyzed by the dec ision tree prior to being used in the loadings calculations. 114

• If the analytes were not measured above the quantitatio n limit, then the concentration was assumed to be one-half the quantitation limit of th e method with the lower reporting limit.

12.1.2 Steam Electric Technical Questionnaire Database

As discussed in Section 3.1, the principal source of inform ation 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 wa stewater generation and treatment, and

economic information such as costs of wastewater trea tment technologies and financial characteristics of potentially affected companies [ERG, 2015i]. The responses were used to evaluate pollution control options for establishing revisions to the ELGs for the Steam Electric Power Generating Point Source Category. EPA used certain inform ation from the 733 plant responses to identify the population of plants that operate ash impound ments, as well as identify the specific wastestreams entering the impoundments and the associat ed discharge flow rates. The type of information used for the ash loadings is described furth er in Section 12.2.

12.1.3 Electrical Power Research Institute Reports

As described in Section 3.5, EPRI provided EPA with the PISCES Water Characterization Field Study, Sites A-G

reports that summarize the data collected during seven separ ate site visits to

characterize wastewater at coal-fired steam electric power plants [EPRI, 1997-2001]. Additionally, EPA received technical reports prepared by EPRI as part of plant responses to the Steam Electric Survey. EPA reviewed these reports submitted for ash impound ment characterization data.

In the proposed rulemaking, EPA included the average results from each of the seven sites sampled in the PISCES reports in the ash impoundment e ffluent concentrations data set. As explained above, following proposal and review of the public comments, EPA revised the acceptance criteria for ash impoundment effluent concen tration data for the final rulemaking (see Table 12-1). For the final rulemaking, EPA reviewed each of the seven site reports to determine if the samples met these acceptance criteria. Based on t he review of the EPRI PISCES reports, EPA identified three sites that had usable ash impoundment eff luent data for the ash loadings analysis for three impoundments. EPA included the individual sample con centrations for each pollutant for each of the sites in the ash impoundment effluent concentra tions data set. The sites were identified as operating the following type of ash impoundments:

114 EPA used the decision tree for all data sets for whic h both routine and low-level analyses were conducted for the same sample. This includes the EPRI PISCES data and UW AG data sets.Section 12 – Ash Transport Water Pollutant Loadings

12-7 • Site C – Combined ash impoundment (samples collected 1996-7).

• Site F – Bottom ash impoundment (samples collected 1998-9).

• Site G – Combined ash impoundment (samples collected 2000).

EPA also reviewed the industry responses to the Steam E lectric Survey for reports with ash impoundment effluent characterization data. Based on the review of the reports, EPA identified one EPRI report that had data acceptable to characterize fly ash impoundment effluent. Mitigation of SCR-Ammonia Related Aqueous Effects in a Fly Ash Pond [EPRI, 2006] presents sampling data from a fly ash impoundment at American Electric Power ’s (AEP) John E. Amos plant. The report was submitted as part of the John E. Amos plant’s respo nse to the Steam Electric Survey. All data confirmed to be representative of fly ash impoundment eff luent were added to the ash impoundment effluent analytical database.

12.1.4 Permit Application Data

As described in Section 3.6, UWAG created a database of se lected National Pollutant Discharge Elimination System (NPDES) Form 2C data from UWAG’s member companies and provided the database to EPA [UWAG, 2008]. The NPDES Form 2C database contains information about the outfalls from 86 coal-fired steam electric po wer plants that discharge FGD, ash transport, or coal pile runoff wastestreams. EPA matched pollutant data from the NPDES Form 2C database to data in Parts A and D of the Steam Electric Survey by NPDES permit number and outfall number to determine which outfalls discharge fly ash transport wa ter, bottom ash transport water, or combined ash transport water. For those NPDES permit IDs that did not match information from the Steam Electric Survey, EPA conducted a manual search to ge nerate a crosswalk between the Form 2C NPDES permit number and the reported NPDES permit numbe r in the Steam Electric Survey. After the NPDES permit numbers were matched, EPA match ed the outfalls in the Form 2C database to those reported in the Steam Electric Survey using th e following hierarchy:

1. Outfall numbers that matched exactly.

2. Outfall numbers that did not match due to different formatt ing.

3. Matching outfall descriptions.

For the final rulemaking, EPA used the information from P arts A and D of the Steam Electric Survey to calculate the percent contribution of the ash transport water to the total outfall

flow rate. For each outfall in the Form 2C database for which 75 percent or more of its flow is from ash transport water (fly, bottom, or the sum of the t wo), which accounts for 26 outfalls, EPA included the reported pollutant concentrations in the ash impoundment effluent concentrations data set. EPA excluded data from one permit application, NPDES outfall MO-0000353-002 (Sioux Power Plant), because UWAG submitted a more complete da ta set for this outfall as part of their public comments to the ELGs; these data included results for additional pollutants not captured in the Form 2C database. EPA included the data set provided by U WAG in place of the Form 2C data in the analytical database because it is more complete . For all other Form 2C data included, when more than one set of pollutant concentrations were pre sented in the database, EPA used the following hierarchy to select data for inclusion in the analytical database:

1. Long-term average concentration.

2. Thirty-day maximum concentration.Section 12 – Ash Transport Water Pollutant Loadings

12-8 3. Daily maximum concentration.

12.1.5 1982 Technical Development Document

The 1982 Development Document for Effluent Limitations Guidelines and Standards and Pretreatment Standards for the Steam Electric Point Source Category (referred to as “the 1982 TDD”) presents the results of studies of the steam ele ctric power generating industry that EPA conducted in revising the Steam Electric Power Generating effluent guidelines [U.S. EPA, 1982]. This development document contains findings, conclusions, and recommendations on control and treatment technology relating to discharges from steam e lectric power plants. Ash impoundment characterization data are provided in three separate ta bles and an appendix contained within the

1982 TDD.

In the proposed rulemaking, EPA included the data representin g effluent from Table V-32, Table V-33, and Table V-34 in the analytical database and ash loadings calculations. Following proposal and review of the public comments, EPA revised th e acceptance criteria for ash impoundment effluent concentration data for the final r ulemaking to use ash impoundment characterization data only from an impoundment that coul d be classified as a fly ash impoundment, bottom ash impoundment, or combined ash impoundment. Additi onally, EPA only accepted data that are comprised of sample-specific results for a pl ant or plant-specific average concentrations. Where plant-specific average concentrations and sample-s pecific results were available, EPA used the sample-specific results.

Based on review of the information provided in the 1982 TDD, EPA identified that Appendix A had data acceptable for use in characterizing ash impoundment effluent. Ash impoundment sample data from Table V-32, Table V-33, and Table V-34 were excluded from the ash loadings analysis for the reasons described below:

Table V-32, Characteristics of Ash Pond Overflows with Total Suspended Soli ds Concentrations Less than 30mg/L presents average impoundment overflow pollutant concentra tions for 11 separate impoundments at 11 plants. These data were not accepted by EPA for use in the ash loadings analysis because the data does not indicate the type of ash impoundment sampled at each plant; therefore, EPA could not categorize the data as representative of fly ash impoundment effluent, bottom ash impoundment effluent, or combined as h impoundment effluent.

Table V-33, Summary of Ash Pond Overflow Data from Discharge Monitoring R eports provides an average pollutant concentration for ash impound ment effluent for each of the three different types of impoundment systems (i.e., fly ash , bottom ash, combined ash). Additionally, the table identified the number of impoundment systems that w ere used to calculate the average concentration. At proposal, EPA included the same number of records of the average concentrations in the ash impoundment concentrations data set as the n umber of impoundments that were used to calculate the average. These data were not accepted by E PA for the final rulemaking because these data represent average concentrations across multiple plants rather than plant-specific average

concentrations.

Table V-34, Summary of Quarterly TVA Trace Metal Data for Ash Pond Int ake and Effluent

Streams summarizes average plant intake and ash impoundment eff luent pollutant concentrations for 10 plants. Although these data were used at proposal, EPA removed the plant-specific averageSection 12 – Ash Transport Water Pollutant Loadings

12-9 effluent pollutant concentration from the ash impoundm ent concentrations data set and replaced these data with individual data points available in Appendix A, TVA Raw River Intake and Ash Pond Discharge Data , of the 1982 TDD.

The impoundment and discharge of ash transport water has long been a standard technique practiced since before 1982; therefore, EPA determined that t hese data were valid for characterization of ash impoundment effluent. Appendix A, TVA Raw River Intake and Ash Pond Discharge Data, presents individual data points for the averaged data presen ted in Table V-34. These data were accepted for use in the ash loadings ana lysis and populated in the ash impoundment effluent concentration data set.

12.1.6 Data Submitted by Duke Energy

EPA received public comments on the proposed rule from D uke Energy, in which Duke Energy submitted data for samples of bottom ash transpo rt water from the Marshall Steam Station (Marshall), a 4-generating unit 2,200 MW coal-fired station, and the Belews Creek Steam Station (Belews Creek), a 2-generating unit 2,400 MW coal-fired statio n [Duke Energy, 2013]. Duke Energy also provided source water data collected on the s ame day as the bottom ash transport water samples. EPA requested additional information to clarify the sample collection procedure, sample quality information, and the selection criteria used by D uke Energy when sampling Belews Creek and Marshall, and to request bottom ash transport water data collected from any other Duke Energy plants.

EPA ultimately requested and received sample collection and quality information from Duke Energy and used these data to interpret, validate, and eva luate the bottom ash transport water data collected at Belews Creek and Marshall against EPA’s acce ptance criteria [Duke Energy, 2014]. As part of Duke Energy’s response to EPA’s information reques t, Duke Energy provided EPA with the “UWAG Bottom Ash Transport Water Sampling Protocol” which describes the sampling method used to collect the samples at Belews Creek and Marshal l [UWAG, 2013b]. EPA reviewed the information in Duke Energy’s response and determined the b ottom ash transport water samples were collected from the discharge pipe prior to mixing or co mingling with any other wastestream or other waters. The samples were allowed to settle in an attempt to simulate treatment from a surface water impoundment and samples of the supernatant were col lected and analyzed. Because the samples from Marshall and Belews Creek were collected before entering the impoundment and were settled for at least one hour, EPA determined that the data were not wholly representative of ash impoundment discharges. These data were instead used in a sensitivity analysis, as described in

Section 12.4.

In Duke Energy’s response to EPA’s data request, Duke Energy also confirmed they also collected bottom ash transport water data at their Eas t Bend Station, Cliffside Steam Station, Cayuga Station, and Miami Fort Station [Duke Energy, 2014]. EPA was provided with these data

and reviewed the data from East Bend Station and Miami Fo rt Station for possible inclusion in the ash loadings analysis. Duke Energy indicated that the b ottom ash samples collected from Cliffside Steam Station (Cliffside) and Cayuga Station were analy zed by UWAG; however, Duke Energy was able to provide data for one split sample collected dur ing the UWAG sampling episode at Cliffside. Because Duke Energy does not have the UWAG lab oratory reports for the Cayuga Station samples, they were unable to provide these additional data to EPA. Data from East Bend StationSection 12 – Ash Transport Water Pollutant Loadings

12-10 and Miami Fort Station were entirely excluded from ash l oadings calculations because they were collected before commingling in the impoundment and not al lowed to settle at all. Samples from Cliffside were collected before entering the impoundment and were settled for at least one hour, EPA determined that the data were not wholly representati ve of ash impoundment discharges. The Cliffside ash transport water data were instead used in a sensitivity analysis (described in Section 12.4).

12.1.7 Data Submitted by Hoosier Energy Rural Electric Cooperative

EPA received public comments on the proposed rule from H oosier Energy Rural Electric Cooperative (Hoosier Energy), in which Hoosier Energy pr ovided data on 32 samples of bottom ash impoundment effluent and fly ash impoundment effluent coll ected between September 2008 and December 2009 at the Frank E. Ratts Generating Station for a Reasonable Potential to Exceed analysis of nine parameters for a permit renewal. Additio nally, Hoosier Energy provided data on 29 samples of fly ash impoundment effluent and 28 samples o f bottom ash impoundment effluent collected for mercury analysis [Hoosier, 2013].

EPA requested that Hoosier Energy provide EPA with any fly ash and/or bottom ash impoundment effluent data collected since December 2009. In addition, EPA requested identification of the specific impoundments (using Impoundm ent IDs reported in the Steam Electric Survey), impoundment dimensions, impoundment treatment oper ations, atypical operations that occurred, and identification of other wastestreams th at enter the impoundment. EPA ultimately received and reviewed the requested sample collection and qua lity information and additional fly ash impoundment effluent and bottom ash impoundment effluen t data collected between 2010 and 2013. These data were reviewed for possible inclusion in the ash loadings analysis [Hoosier, 2014]. All data confirmed to be representative of fly ash impoun dment effluent or bottom ash impoundment effluent were added to the ash impoundment efflue nt analytical database.

12.1.8 Data Submitted by UWAG

Throughout the development of the steam electric ELGs, EPA coordinated with UWAG, an industry trade association representing 198 individual energy companies and three trade associations of energy companies. As part of this coordinat ion, UWAG provided EPA with several ash transport water data sets for EPA’s consideration and use in the characterization of the ash transport water. These UWAG ash transport water data s ubmissions are described in Sections

12.1.8.1 and 12.1.8.2.

12.1.8.1 UWAG Public Comment Data

As part of its public comment submission in September 2013, UWA G provided a table presenting bottom ash transport water data for samples collected from 21 plants [UWAG, 2013a]. The UWAG database samples were collected from 2001 to 2013, wi th samples from 17 plants collected between 2010 and 2013. In some cases, UWAG also provi ded source water data collected on the same sample day as the bottom ash transport wa ter samples. As part of their public comment submission, UWAG also provided a report prepared by URS Corporat ion with 2013 sampling data for sulfides (as well as some other parameters) at nine plants. UWAG masked the identity of all plants included in the bottom ash transport water databa se and sulfides report.Section 12 – Ash Transport Water Pollutant Loadings

12-11 EPA requested additional information and clarification fr om UWAG in order to properly interpret, validate, and evaluate the data to determine if these data met EPA’s acceptance criteria for inclusion in the pollutant loadings analysis. Specificall y, EPA requested UWAG to provide more information about the identity of the sampled plants, the sample collection location and methods used, the selection criteria used by UWAG when developing their data set, information on how nondetect values were handled when calculating average conc entrations, total suspended solids results associated with the samples, and other plant-specific i nformation. EPA ultimately received and reviewed these data for possible inclusion in the ash loa dings analysis [UWAG, 2014a]. 115

For ten of the data sets, UWAG did not identify the ind ividual plants for which it submitted data, nor did it include these plants in Attachments 1 and 2 to its response to EPA follow-up questions. For such data sets, EPA could not confirm whethe r the samples met all the acceptance criteria because the Agency lacked sufficient data about the sources and volumes of wastewater managed by the impoundment (i.e., EPA could not verify that the ash impoundment effluent samples fulfilled the 75 percent or more ash transport wa ter criteria). Additionally, the lack of plant identification precluded EPA from evaluating whether the U WAG data were for impoundments already included in EPA’s ash impoundment effluent data se t.. EPA, therefore, excluded the data from these ten data sets from the loadings analysis. In addition, EPA excluded four data sets because the ash transport water contributions to the s ampled impoundments represented less than 75 percent of the flow into the impoundment, and excluded data from one plant data set where EPA received a more complete version of the data set as pa rt of the public comments submitted by Hoosier Energy (see Section 12.1.7). A total of 15 data set s were entirely excluded from the loadings analysis and the sensitivity analysis.

Also, similar to the Duke Energy data described in Section 12.1.6, nine data sets consist of samples collected prior to mixing or comingling with any oth er wastestream or other waters and were allowed to settle in an attempt to simulate trea tment from a surface water impoundment. Samples from these data sets were collected prior to se ttling either directly from the discharge pipe,(eight data sets) or after the dewatering bin (one da ta set). Because the samples from these data sets were collected before commingling and settling in th e impoundment, EPA determined that the data were not wholly representative of ash impoundment dis charges. 116 These data were instead used in a sensitivity analysis. The result of this sensi tivity analysis is discussed further in Section

12.4.2.

Where data were confirmed to represent ash impoundment eff luent samples and the ash contribution was at least 75 percent of the contributio n by volume to the impoundment (six data

115 EPA’s request for additional information was made on Dece mber 30, 2013. In that request, EPA reminded UWAG that the Agency is operating with a deadline for taking final action on the Steam Electric ELGs and thus requested a response to specific questions no later than January 24, 2014 [U.S. EPA, 2013]. UWAG’s response to EPA’s request for additional information was not received until August 4, 2014, more than six months after the deadline. Although data was received well after the deadline, EPA was able to fully take these data into account for the analyses and ev aluated the data submitted by UWAG against the acceptance criteri a listed in Table 12-1.

116 UWAG presented a comparison of settled sluice pipe sample s to near-effluent discharge point samples at each of the six plants sampled as part of the November 2014 submission. UWAG acknowledged that “whether viewed from the individual facility perspective or as averaged across the six facilities, it is clear that the settled bottom a sh sluice pipe samples substantially overestimate bottom ash effluent poll utant loadings” [UWAG, 2014b].Section 12 – Ash Transport Water Pollutant Loadings

12-12 sets), EPA included these data in the ash impoundment conc entrations data setand further reviewed the data against the acceptance criteria.

12.1.8.2 November 2014 Bottom Ash Transport Water Data

At UWAG’s request, on September 10, 2014, EPA met with repre sentatives from UWAG to discuss the use of the bottom ash transport water data submitted by UWAG in public comments. During this meeting, UWAG indicated that it had collected a dditional bottom ash transport

characterization data. EPA stated that no further data were needed for EPA’s evaluation of bottom ash transport water [U.S. EPA, 2014].

On November 25, 2014, more than two months following the meeti ng with EPA on September 10, 2014, UWAG submitted additional bottom ash tran sport water data and asked EPA to consider it for the final Steam Electric ELGs [UWAG , 2014b]. 117 The late data included bottom ash transport water characterization data collected fr om six steam electric power plants. UWAG provided plant information sheets containing background and opera tional data regarding each of the plants sampled, analytical laboratory and quality contr ol documentation for each sample, and the results of UWAG’s analysis of the results.

By November 25, 2014, EPA had already completed analysis of available ash characterization data for use in the rulemaking, complet ed development of the Steam Electric Analytical Database [ERG, 2015a], and finalized the ash lo adings model used to generate pollutant loadings estimates. Therefore, EPA did not incorporate UWAG’s November 2014 data into the official loadings analysis and other related analyses ( e.g., the Ash Data Review Matrix, the POC analysis). However, EPA did conduct a sensitivity analy sis of the late data that were known to meet EPA’s acceptance criteria, as described further in Secti on 12.4.3.

12.2 L OADINGS C ALCULATION M ETHODOLOGY

EPA estimated ash loadings for all pollutants defined as a POC for fly ash transport water or bottom ash transport water [ERG, 2015d], or that were ide ntified as constituents of combined ash impoundments. Generally, loadings for each pollutant ar e calculated by multiplying a pollutant concentration by an associated flow rate for the wast ewater, according to Equation 12-1.

(12-1)

Load (lb/year) = Flow Rate × Concentration × 2.205 lb / 1,000,000 mg × 3.785 L/gal × 365 days/year

where:

Flow Rate = The normalized flow rate of the wastewater in gallons/day.

117 These data were received 10 months after the January 2014 de adline established by EPA’s December 30, 2013 letter. This was 14 months after the September 2013 close of the co mment period for the proposed rule (more than 17 months after EPA publicly released a pre-publication version of the Federal Register

notice for the proposed rule, soliciting additional pollutant characterization data).Section 12 – Ash Transport Water Pollutant Loadings

12-13 Concentration = The average concentration of a specific pollutant in the wastewater in milligrams per liter (mg/L).

Therefore, to calculate the ash loadings, EPA develope d a methodology to determine the appropriate concentrations to use for each pollutant for e ach type of impoundment system and also developed a methodology to identify the flow rates associa ted with the wastewater. The following sections present the methodologies EPA used to calculate the ash loadings for the steam electric power generating industry.

12.2.1 Impoundment Type Pollutant Concentration Methodology

EPA used the concentration data obtained from the data s ources described in Section 12.1 to calculate the average pollutant concentrations in fly ash impoundment effluent, bottom ash impoundment effluent, and combined ash impoundment effluent. EPA notes that, because the data associated with these impoundments may include other waste streams (e.g., cooling water), the concentrations may be diluted and therefore may underest imate the baseline pollutant loadings and underestimate the post-compliance pollutant reductions. 118 EPA first calculated the average pollutant concentrations for each plant and then calcul ated an average across all plants, using the following steps:

• Construct a plant-specific data set, comprising all accepta ble ash impoundment effluent data for that plant, regardless of the data sour ce.

• Identify the type of impoundment system the data represen ts (i.e., fly ash impoundment, bottom ash impoundment, combined ash impoundment ).

• For each type of ash impoundment at a plant, average the effluent concentrations by pollutant for each day of sampling for any pollutant detected at least once above the quantitation limit (QL). Values reported as non-detects were treated as equal to onehalf the QL or detection limit (DL), depending on the va lue reported. 119

• For each type of ash impoundment at a plant, calculate the average effluent concentration by pollutant over all days of samples.

After calculating a plant-specific average concentrati on for each type of impoundment, EPA calculated an industry average concentration for each poll utant for each type of impoundment. For example, EPA calculated an industry average pollutant co ncentration for a fly ash impoundment effluent by calculating the average concentration acro ss all fly ash impoundments for which EPA had data, using the average plant-specific fly ash impoundm ent effluent pollutant concentrations

118 Because this approach may underestimate the actual pollut ant concentrations for the impoundment effluent if there was no dilution, the baseline pollutant loadings would be unde restimated and result in underestimating the pollutant removals that would be attained by the technology option considered for the rule.

119 Fly ash and bottom ash transport water data include quali fied results where there are insufficient data availab le to determine the respective sample-specific QL. In these i nstances the observation is reported as a “less than” result along with a value, but EPA does not know whether the reported value is the sample-specific DL or QL. For the purpose o f estimating pollutant loadings and removals, EPA assumed the reported value is the QL and used one-half that value in the calculations. In cases where a QL value was not av ailable, EPA used the DL.Section 12 – Ash Transport Water Pollutant Loadings

12-14 calculated above. Table 12-2, Table 12-3, and Table 12-4 present a list of the POCs and the average effluent concentrations calculated for fly ash, bottom ash, and combined ash wastewater, respectively.

12.2.2 Baseline Flow Rate Methodology

EPA used information from the Steam Electric Survey and industry-submitted data to identify the population of plants that have steam elect ric generating units that use wet sluicing for fly ash or bottom ash handling and reported transferring f ly ash, bottom ash, or combined ash transport water to impoundments that discharged to surface w aters or POTWs in 2009. Section 4.1.2 describes the methodology EPA used to develop the “Ash Tra nsport Water Input Table,” which contains the generating unit-level flow rates by impoundmen t ash type used to estimate the fly ash and bottom ash pollutant loadings [ERG, 2015c].

EPA used the “CCR Input Table,” discussed in Section 4.3.3, t o adjust the population of plants discharging fly ash or bottom ash transport wate r to account for the implementation of the final Coal Combustion Residuals (CCR) rule. A copy of th e “CCR Input Table” is included in the Ash Loadings Database [ERG, 2015c].

For the calculation of the baseline loadings, EPA ca lculated loadings associated with the normalized ash transport water flow rates for all gen erating units that are not expected to retire/convert to dry ash handling by December 31, 2023 or conver t to dry ash handling due to the

CCR rule.

12.2.3 Regulatory Option Flow Rate Methodology

EPA evaluated several regulatory options for this industry that affected the generating unit population subject to the final rule. EPA applied differen t effluent limitations to oil-fired generating units and units with a specific steam electric power genera ting capacity. EPA evaluated technology option pollutant loadings for the following populations:

• All oil-fired generating units and generating units less than or equal to 50 MW will not face more stringent requirements than already exist ed under preexisting regulations for fly ash and bottom ash transport water

.

• All oil-fired generating units and generating units less than or equal to 50 MW will not face more stringent requirements than already exist ed under preexisting regulations for fly ash and bottom ash transport water , and generating units less than or equal to 400 MW will not face more stringent requiremen ts than already existed under preexisting regulations for bottom ash transport wat er.

To calculate the fly ash transport water and bottom ash transport water portion of the regulatory option loadings, EPA calculated loadings assoc iated with the normalized ash transport water flow rates for only the generating units that will not face more stringent requirements than already existed under preexisting regulations (i.e., those ge nerating units that will continue wet sluicing ash). For example, if a plant currently has fo ur generating units with wet fly ash handling, but two of the generating units are less than 50 MW, then EPA used the normalized fly ash transport water flow rates for the two generating units that are less than 50 MW to calculate ash loadingsSection 12 – Ash Transport Water Pollutant Loadings

12-15 associated with that regulatory option. For those genera ting units that would need to comply with a zero discharge pollutant requirement, post-compliance pol lutant loadings are zero.

After identifying all the generating units that would not be s ubject to a specific regulatory option and calculating the reduced flow rate for these o ptions, EPA developed a separate “ash flow input table” to reflect the revised flow rates for each re gulatory option used in the ash loadings

calculations.

12.2.4 Ash Loadings Calculation

Using the impoundment ash type flag, EPA multiplied the a verage concentrations for the specific impoundment type by the normalized daily flow rat es included in the “Ash Transport Water Input Table” for the appropriate ash streams. For exampl e, for each generating unit for which EPA calculates ash loadings, the normalized daily fly ash t ransport water flow rate for that generating unit was multiplied by the calculated average fly ash impo undment concentration data to calculate a discharge fly ash loading associated with each pollutant at the plant. EPA used Equation 12-2 to calculate the generating unit-level ash loadings associ ated with fly ash transport water to surface

waters.

(12-2)

FA Unit-Level Load (lb/year) = FA Unit-Level Flow Rate (gpd) × FA Concentration (mg/L) × 2.205 lb / 1,000,000 mg × 3.785 L/gal × 365 Days (dpy)

where:

FA Unit-Level Flow Rate (gpd) = The normalized generating unit-level fly ash transport water flow rate in gallons/day.

FA Concentration (mg/L) = The average concentration of a specific pollutant in the overflow from a fly ash impoundment in mg/L, based on

the data sources described in Sections 12.1 and 12.2.1.

EPA used the same equation to calculate the ash loading s for bottom ash impoundments. In the case of combined ash impoundments, EPA first summed t he fly ash and bottom ash generating unit-level normalized flows for all generating units contri buting to the combined ash impoundment. This “combined ash” flow was used in the equation along with the combined ash impoundment

effluent concentration data set to calculate combined ash loadings. For those generating units transferring the wastewater to a POTW, EPA adjusted the loadings to account for additional removals that would take place at the POTW, according to E quation 12-3. EPA identified four plants transferring bottom ash to a POTW and no plants transferring fly ash or combined ash to a POTW. A list of POTW removals is included in Appendix B.

(12-3) Indirect Pollutant Loading (lb/year) = Pollutant Loading × (1 - POTW Removal)Section 12 – Ash Transport Water Pollutant Loadings

12-16 where:

Pollutant Loading = The calculated baseline or post-com pliance loadings from a specific pollutant, in pounds/year.

POTW Removal = The estimated percentage of the pollutant loading that will be removed by a POTW.

EPA calculates the ash loadings based on the influent impoundment sluice rate, adjusted for any potential recycling that occurs at the plant (as descr ibed in Section 4.1.2). Additionally, the calculation multiplies the ash impoundment overflow c oncentrations, which have likely been diluted by other wastestreams entering the impoundment (e. g., rainfall, stormwater, cooling water, low-volume wastes), by only the flow rate associated w ith the ash transport water stream and not the total ash impoundment effluent flow rate, which may result in underestimating the pollutant loadings associated with ash impoundment discharges but ens ures the loadings represent ash

transport water.

12.2.5 Breakout of Combined Ash Loadings

Because the loadings associated with the combined ash repr esents the combined discharge of fly ash transport water and bottom ash transport wa ter, EPA used data from the EPRI PISCES reports to estimate the breakout of the loadings among fly ash and bottom ash contributions. The Site A, B, C, and D EPRI PISCES reports include a table that presents the loadings to the ash impoundments in kilograms per day (kg/day) for each wastewa ter stream that is entering the impoundment for several metal pollutants. Based on this inf ormation, EPA used the loadings from the fly ash and bottom ash transport water wastestrea ms in the EPRI PISCES reports to break out the calculated combined ash loadings into fly ash loadin gs and bottom ash loadings.

To perform this calculation, EPA first reviewed the infor mation regarding the plants to determine whether the data were appropriate for use in the analysis. EPA made the following

conclusions based on this review:

• Site A was excluded from this analysis of combined ash lo adings because the fly ash transport water is transferred to the ash impoundment o nly during occasional operation; therefore, the fly ash transport water load ings compared to the bottom ash transport water loadings were not representative of th e operations at a typical plant with both wet fly and bottom ash sluicing.

• Site B was included in the analysis as it consists of both fly and bottom ash transport water transferred to the ash impoundment.

• Site C was included in the analysis as it consists of both fly and bottom ash transport water transferred to the ash impoundment.

• Site D has two separate plants at the site (i.e., Plan ts A and B). Plant A has wet fly ash and bottom ash handling for all six generating units an d Plant B has wet bottom ash for two generating units, but wet fly ash for only o ne of the two generating units; therefore, only Plant A fly ash and bottom ash loadings were included in the analysis. Plant B loadings were excluded.Section 12 – Ash Transport Water Pollutant Loadings

12-17 EPA used the fly ash transport water and bottom ash tran sport water loadings presented in the EPRI PISCES reports for the sites described above to calculate a site-specific percent loading for fly ash and bottom ash for each pollutant. For eac h site and available pollutant, EPA calculated the percent of the pollutant loading associated with fly ash and bottom ash relative to the total ash loading. For this calculation, EPA included only the fly as h and bottom ash transport water loadings, even though EPRI included all wastewater sources entering the impoundment, because EPA is evaluating only the combined fly ash and bottom ash t ransport waters and is not considering other wastewater sources. EPA performed this calculation for each pollutant available for each of the three sites and calculated an average percent loadi ng for fly ash and bottom ash for each of the twelve pollutants using the percentage calculated for each of the three sites.

EPA then calculated an overall average percent loading for fly ash transport water and bottom ash transport water for each pollutant using the site-specific percentages. Because EPA did not have data available to calculate an average percent loading for fly ash and bottom ash transport water for all pollutants in the combined ash impoundment da ta set, EPA calculated the average percent loading for fly ash and bottom ash based transport water on the pollutants available, 85.9 and 14.1 percent, respectively, and used this value for the al locate the loading for all other pollutants. Therefore, EPA assumed fly ash transport w ater and bottom ash transport water account for 85.9 and 14.1 percent, respectively, of all combined ash l oadings for those pollutants for which an analyte-specific value could not be calculated using th e EPRI data. These average percent loadings for fly ash and bottom ash are presented in Table 12-5 for each pollutant available. See the “Break Out of Combined Ash Loadings Methodology Memorandum” [ERG, 2015e] for more

details on this calculation.

12.3 P OLLUTANT L OADINGS AND TWPE R ESULTS

In addition to expressing plant-level pollutant loadings in pounds of pollutant discharged per year (described in Section 12.2), EPA used toxic weighting fa ctors (TWFs) to account for differences in toxicity across pollutants in ash waste water. 120 EPA calculated a TWPE according to Equation 12-4 for each pollutant to compare mass loadings bet ween different pollutants based on their toxicity.

(12-4) Pollutant-Specific TWPE = Pollutant-Specific Loading × P ollutant-Specific TWF

EPA also calculated plant-level TWPE by summing the pol lutant-specific TWPE. Using the plant-level mass and TWPE loadings, EPA was then able to calculate the baseline and postcompliance loadings at the industry level for each regula tory option. The plant-level mass loadings and TWPE loadings are presented in Appendix B. Table 12-6 pres ents the results of the ash loadings calculation for fly ash and bottom ash transpo rt water, for both baseline and the dry handling technology options. The table summarizes the i ndustry-level loadings and pollutant reductions in pounds/year and TWPE/year.

120 A listing of pollutant-specific TWF values can be found in the Review of Toxic Weighting Factors in Support of the Final Steam Electric Effluent Limitations Guidelines and Standards [ERG, 2015g]. EPA has developed TWFs for more than 1,900 pollutants based on aquatic life and human health toxi city data, as well as physical/chemical property data.Section 12 – Ash Transport Water Pollutant Loadings

12-18 The pollutant loadings and removals in Table 12-6 include al l POCs except biochemical oxygen demand (BOD), chemical oxygen demand (COD), total suspe nded solids (TSS), total dissolved solids (TDS), as well as sulfide. BOD, COD, TSS, and TDS are pollutant parameters that essentially double-count pollutant-specific loadings.

EPA calculated the pollutant removals by subtracting the technology option loadings from the baseline loadings. The plant-level loadings can be fo und in Appendix B.

The pollutant loadings presented in Table 12-6 are based on oil-fired generating units and those generating units with a generating capacity of 50 MW or less not installing the technology basis because they are not facing any more stringent requir ements than already existed under the previously established regulations. Section 15 of this report discusses the use of the ash wastewater pollutant loadings and estimated pollutant loadings for ot her regulated wastestreams to evaluate the regulatory options considered by EPA.

12.4 S ENSITIVITY A NALYSES

Sections 12.1 through 12.3 describe EPA’s methodology for es timating pollutant loadings

and removals associated with the final rule. In addition to these technology options, EPA also conducted smaller scale sensitivity analyses related to inclusion of additional concentration data sets to determine how small changes to the analytical database would affect the overall industry-level pollutant loadings. EPA conducted the following three sens itivity analyses related to ash transport water pollutant loadings:

1. Analysis to evaluate pollutant loadings associated with inclusion of sulfide in the loadings calculations.

2. Analysis to evaluate pollutant loadings associated with including settled bottom ash transport water concentration data.

3. Analysis to evaluate pollutant loadings associated with including bottom ash transport water data submitted well beyond the close of t he public comment period.

EPA conducted these sensitivity analyses on a previous ve rsion of the pollutant load estimates. EPA recalculated the industry loadings for f ly ash transport water and bottom ash transport water for the final rule and determined that th e difference between the final industry baseline loadings and the previous version of the polluta nt loadings estimates is less than 1 percent in terms of pounds per year. Because the magnitude of this revision to the baseline loadings is very small and the sensitivity analyses also show little change in pollutant loadings/removals, EPA concluded that it was not necessary to update the sensitivit y analyses with the revised baseline loadings because they would still show that there would be little change in the pounds of pollutants in the baseline loadings or removals. The following s ection describes the three sensitivity analysis conducted by EPA related to ash pollutant loadings.

12.4.1 Sulfide Sensitivity Analysis

During the public comment period, EPA received comments from industry asserting that sulfides should not be considered a POC for ash transpor t waters. As such, EPA also conducted sensitivity analyses based on the inclusion or exclu sion of sulfide as a POC for fly ash transportSection 12 – Ash Transport Water Pollutant Loadings

12-19 water and bottom ash transport water. EPA’s POC analys is, described in Section 12.2, determined that sulfide is not a POC for fly ash or bottom ash transport water; therefore, EPA did not calculate loadings for sulfide from fly ash impoundment effluent or bottom ash impoundment effluent in any analyses. Sulfide was detected in samples representing co mbined ash impoundment effluent so EPA did calculate loadings for this constituent from combine d ash impoundment effluent for this sensitivity analysis. The results of this sensitivit y analysis are presented in Table 12-7.

12.4.2 Settled Bottom Ash Sluice Sensitivity Analysis

As described in Section 12.1, EPA identified certain data se ts whose quality did not meet or could not be confirmed for use in the loadings analysis. These data were representative of ash transport water collected prior to commingling with other wastestreams or waters and allowed to

settle for at least one hour before collection of th e supernatant. EPA determined that these data were not sufficiently representative of ash impoundment effl uent. 121 EPA used these data sets supplied by Duke Energy and UWAG, in combination with the data sets a ccepted for use in the loadings calculations, in a sensitivity analysis, as shown in T able 12-7.

The sensitivity analysis shows that the inclusion (or exclusion) of the settled ash transport water data sets has no impact on fly ash transport wat er loadings and a minor impact on the bottom ash transport water loadings in terms of total pounds per year. Inclusion of the settled ash transport water samples results in the industry baseline loadings for bottom ash transport water increasing by 4 percent in terms of pounds per year. The average effluent concentrations for fly ash, bottom ash, and combined ash impoundments calculated as part of these s ensitivity analyses are presented in Appendix B.

12.4.3 Inclusion of Data Submitted Late

As described in Section 12.1.8.2, UWAG provided EPA with a lat e submission of supplemental bottom ash transport water characterizati on data. UWAG’s late data was not sent to EPA until November 2014, and due to the additional time that wo uld have been needed to fully evaluate the late data and revise the pollutant removal a nalyses and other related analyses for the ELGs (e.g., environmental assessments), the late data c ould not be fully incorporated into the loadings analyses. Nevertheless, EPA was able to conduct an abbreviated evaluation of the late data

to determine the effect the late data could have on the l oadings analyses. The sensitivity analysis performed on these data, which included bottom ash transpor t data from three 122 of the six plants in UWAG’s November 2014 data set, is discussed further in the memorandum “Use of UWAG Bottom Ash Transport Water Data” [ERG, 2015h].

The results of this analysis are presented in Table 12-8. Table 12-8 illustrates the impact of

the inclusion of these late submission data on the total industry loadings at baseline. The average

121 UWAG presented a comparison of settled sluice pipe sample s to near-effluent discharge point samples at each of the six plants sampled as part of the November 2014 submission. UWAG acknowledged that “whether viewed from the individual facility perspective or as averaged across the six facilities, it is clear that the settled bottom a sh sluice pipe samples substantially overestimate bottom ash effluent poll utant loadings” [UWAG, 2014b].

122 EPA used data from Kammer, Kyger Creek Station, and Fran k E. Ratts Generating Station.Section 12 – Ash Transport Water Pollutant Loadings

12-20 effluent concentrations for bottom ash impoundments c alculated as part of this sensitivity analysis are presented in Appendix B.

The sensitivity analysis demonstrates that including UWAG ’s November 2014 data would have little impact on both the unweighted (pounds/year) po llutant loadings/removal estimates and other related analyses. Including the subset of the Novemb er 2014 data decreased the estimated unweighted pollutant loadings for bottom ash transport wa ter by approximately 2 percent. Because of the very small impact on bottom ash transport wate r loadings associated with this sample of late data, EPA concluded that the late data would not have a s ignificant impact on the overall loadings, pollutant removal estimates, and related analyses for pur poses of the final steam electric ELGs.

12.5 R EFERENCES

1. Duke Energy. 2013. Duke Energy. Comments of Duke Energy on E ffluent Limitations

Guidelines and Standards for the Steam Electric Power Ge nerating Point Source Category. (7 June) EPA-HQ-OW-2009-0819-4305.

2. Duke Energy. 2014. Duke Energy. Duke Energy Response to EPA Dat a Request. (4 December and 28 March). DCN SE04331 and SE04360.

3. ERG. 2015a. Eastern Research Group, Inc. Analytical Data base for Final Rule. (30 September). DCN SE05359.

4. ERG. 2015b. Eastern Research Group, Inc. “Ash Analytical Data Review Memorandum.” (30 September). DCN SE05567.

5. ERG. 2015c. Eastern Research Group, Inc. Ash Loadings Mo del, Accounting for CCR. (30 September). DCN SE05584.

6. ERG. 2015d. Eastern Research Group, Inc. “Bottom Ash and F ly Ash Transport Water Pollutants of Concern (POC) Analysis Methodology” (30 S eptember). DCN SE04745.

7. ERG. 2015e. Eastern Research Group, Inc. “Break Out of Co mbined Ash Loadings Methodology Memorandum.” (30 September). DCN SE05586.

8. ERG. 2015f. Eastern Research Group, Inc. “Development Memo randum for the Steam Electric Analytical Database for the Final Rule.” (30 September). DCN SE05876.

9. ERG. 2015g. Eastern Research Group, Inc. “Review of Toxic Weighting Factors in Support

of the Final Steam Electric Effluent Limitations Guide lines and Standards.” (30 September).

DCN SE04479.

10. ERG. 2015h. Eastern Research Group, Inc. “Use of UWAG Bott om Ash Transport Water Data.” (30 September). DCN SE05581.

11. ERG. 2015i. Eastern Research Group, Inc. Steam Electric T echnical Questionnaire Database (“Steam Electric Survey”). (30 September). DCN SE05903.Section 12 – Ash Transport Water Pollutant Loadings

12-21 12. ERG. 2015j. Eastern Research Group, Inc. Ash Data Review M atrix. (30 September). DCN

SE05575.

13. ERG. 2015k. Eastern Research Group, Inc. “Draft Ash Load ings Model, Accouting for CCR – Settled Ash Transport Water Sensitivity Analysis.” (30 S eptember). DCN SE05624.

14. ERG. 2015l. Eastern Research Group, Inc. “Draft Ash Loadi ngs Model, Accouting for CCR – UWAG Late Submission Sensitivity Analysis.” (30 Septem ber). DCN SE05625.

15. ERG. 2015m. Eastern Research Group, Inc. “Final Ash Loadin gs Model, Accounting for CCR.” (30 September). DCN SE05584.

16. ERG. 2015n. Eastern Research Group, Inc. “Draft Ash Load ings Model, Accounting for CCR – Sensitivity Analysis Comparison.” (30 September). DCN SE06418.

17. EPRI. 1997 - 2001. Electric Power Research Institute. PISCES Water Characterization Field Study, Sites A-G . Palo Alto, CA. DCNs SE01818-01823.

18. EPRI. 2006. Electric Power Research Institute. Mitigation of SCR-Ammonia Related Aqueous Effects in a Fly Ash Impoundment: Algal Enhancement and Water Chemi stry

. Palo Alto, CA. DCN SE04742.

19. Hoosier Energy. 2013. Hoosier Energy Rural Electric Coopera tive. Comments of Hoosier Energy on Effluent Limitations Guidelines and Standards f or the Steam Electric Power Generating Point Source Category. (20 September). EPA-HQ- OW-2009-0819-4471.

20. Hoosier Energy. 2014. Hoosier Energy Rural Electric Cooperative. Hoosier response to Post Proposal Information Request. (11 and 14 April ). DCN SE04701-04702.

21. Interstate. 2004. Interstate Power and Light Co. Bottom Ash Wastewater Evaluation: Interstate Power and Light Co. – Dubuque Generating Station . Madison, WI. (June). DCN

SE02279.

22. U.S. EPA. 1982. U.S. Environmental Protection Agency. Development Document for Effluent Limitations Guidelines and Standards and Pretreatment Standards for t he Steam Electric Point Source Category . EPA-440-1-82-029. Washington, DC. (November).

23. U.S. EPA 2000. U.S. Environmental Protection Agency. Development Document for Effluent Limitations Guidelines and Standards for the Centralized Waste Tr eatment Industry . EPA-821-R-00-020. Washington, DC (August). Available online at http://water.epa.gov/scitech/wastetech/guide/cwt/upload/ CWT_DD_2000.pdf

24. U.S. EPA. 2009. U.S. Environmental Protection Agency. Steam Electric Power Generating Point Source Category: Final Detailed Study Report . EPA 821-R-09-008. Washington, DC. (October). Available online at: http://water.epa.gov/lawsregs/guidance/cwa/304m/archive/upl oad/2009_10_26_guide_steam _finalreport.pdf. DCN SE00003.Section 12 – Ash Transport Water Pollutant Loadings

12-22 25. U.S. EPA. 2010. U.S. Environmental Protection Agency. Questionnaire for the Steam Electric Power Generating Effluent Guidelines . OMB Approval Number: 2040-0281. Washington, DC. (2 June). DCN SE00402-SE00402A09.

26. U.S. EPA. 2013. U.S. Environmental Protection Agency. Post Proposal Data Request to UWAG – Bottom Ash Data Submitted in Public Comment. (Dece mber 30). DCN SE04711.

27. U.S. EPA. 2014. U.S. Environmental Protection Agency. Meet ing Notes for the Steam Electric Rulemaking Record, September 10, 2014 Meeting with U tility Water Act Group (UWAG) Regarding Proposed Steam Electric ELGS. (Septembe r 10). DCN SE05578.

28. UWAG. 2008. Utility Water Act Group. UWAG Form 2C Effluent Guidelines Database. (30 June). DCNs SE02918 and SE02918A1.

29. UWAG. 2013a. Utility Water Act Group. Comments on EPA’s Proposed Effluent

Limitations Guidelines and Standards for the Steam Electr ic Power Generating Point Source Category. (7 June). EPA-HQ-OW-2009-0819-4655.

30. UWAG. 2013b. Utility Water Act Group. UWAG Bottom Ash Tra nsport Water Sampling Protocol. (2013). DCN SE04360A22.

31. UWAG. 2014a. Utility Water Act Group. UWAG Response to Po st Proposal Information Request. (1 August). DCN SE04717.

32. UWAG. 2014b. Utility Water Act Group. Additional Bottom as h Transport Water Data. (25 November). DCN SE05597.Section 12 – Ash Transport Water Pollutant Loadings

12-23 Table 12-1. Ash Data Acceptance Criteria

POC Analysis Criteria (Ash Transport Water Data Without Paired Source Water Data) POC Analysis Criteria (Paired Source Water & Ash Transport Water Data)

• Sample locations must be unambiguous and clearly described such that it can be categorized by type (e.g., bottom ash impoundment effluent rather than impoundment effluent with no further definition) and level of treatment (e.g., untreated, partially treated).

• Sample must comprise at least 75% by volume ash transport water.

• Sample location must not represent combined fly ash transport water and bottom ash transport

water.

• Analytical data must represent individual sample results or plant-level average sample concentrations rather than average results representing multiple plants.

• For biphasic samples (i.e., those with solids content >1%), sample analysis must provide results for both phases.

• Data must not be from an ash settling test conducted in a column (i.e., a simulated sample of partially treated wastewater).

• Sample must be representative of full-scale, typical plant operations.

• Sample analysis must be completed using accepted analytical methods. a

• Data must not be duplicative of other accepted

data. b

• Sample data must provide sufficient information to identify units. • Sample locations must be unambiguous and clearly described such that it can be categorized by type (e.g., bottom ash impoundment effluent rather than impoundment effluent with no further definition) and level of treatment (e.g., untreated, partially treated).

• Sample must comprise at least 75% by volume ash transport water.

• Sample location must not represent combined fly ash transport water and bottom ash transport

water.

• Analytical data must represent individual sample results or plant-level average sample concentrations rather than average results representing multiple plants.

• Data must contain source water data paired with fly ash or bottom ash transport water.

• Paired source water data must be collected within one day of fly ash or bottom ash transport water sample collection.

• For biphasic samples (i.e., those with solids content >1%), sample analysis must provide results for both phases.

• Data must not be from an ash settling test conducted in a column (i.e., a simulated sample of partially treated wastewater).

• Sample must be representative of full-scale, typical plant operations.

• Sample analysis must be completed using accepted analytical methods. a

• Data must not be duplicative of other accepted

data. b

• Sample data must provide sufficient information to identify units.Section 12 – Ash Transport Water Pollutant Loadings

12-24 Table 12-1. Ash Data Acceptance Criteria

Ash Loadings Analysis (Excludes Sensitivity Analysis Data) Ash Loadings Sensitivity Analysis (Includes Simulated Effluent Data)

• Sample locations must be unambiguous and clearly described such that it can be categorized by type (e.g., bottom ash impoundment effluent rather than impoundment effluent with no further definition) and level of treatment (e.g., untreated, partially treated).

• Sample must comprise at least 75% by volume ash transport water.

• Sample must be representative of actual ash impoundment effluent (not simulated effluent).

• Analytical data must represent individual sample results or plant-level average sample concentrations rather than average results representing multiple plants.

• For biphasic samples (i.e., those with solids content >1%), sample analysis must provide results for both phases.

• Data must not be from an ash settling test conducted in a column (i.e., a simulated sample of partially treated wastewater).

• Sample must be representative of full-scale, typical plant operations.

• Sample analysis must be completed using accepted analytical methods. a

• Data must not be duplicative of other accepted

data. b

• Sample data must provide sufficient information to identify units.

• Non-detect results were not accepted if no limit (e.g., DL, QL) was provided.

• Sample results must represent total (i.e., dissolved results were not accepted except for TDS). • Sample locations must be unambiguous and clearly described such that it can be categorized by type (e.g., bottom ash impoundment effluent rather than impoundment effluent with no further definition) and level of treatment (e.g., untreated, partially treated).

• Sample must comprise at least 75% by volume ash transport water.Sample must be representative of treated wastewater; this includes actual ash impoundment effluent or

simulated effluent.

• Analytical data must represent individual sample results or plant-level average sample concentrations rather than average results representing multiple plants.

• For biphasic samples (i.e., those with solids content >1%), sample analysis must provide results for both phases.

• Data must not be from an ash settling test conducted in a column (i.e., a simulated sample of partially treated wastewater).

• Sample must be representative of full-scale, typical plant operations.

• Sample analysis must be completed using accepted analytical methods. a

• Data must not be duplicative of other accepted

data. b

• Sample data must provide sufficient information to identify units.

• Non-detect results were not accepted if no limit (e.g., DL, QL) was provided.

• Sample results must represent total (i.e., dissolved results were not accepted except for TDS).

a – See “Ash Data Review Matrix” for a list of accepted anal ytical methods [ERG, 2015j].

b – Duplicative data were submitted by associations representi ng individual plants (e.g., UWAG). In such cases, EPA only accepted data submitted by the individual plant and rej ected the duplicative data provided by the association.Section 12 – Ash Transport Water Pollutant Loadings

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

Analyte Unit Average Concentration

Aluminum ug/L 2,230

Arsenic ug/L 36.4

Barium ug/L 12 1

Beryllium ug/L 3.42

Boron ug/L 6,630

Cadmium ug/L 7.63

Calcium ug/L 99, 300

Chloride ug/L 12,8 00

Chromium ug/L 2 7.4

Cobalt ug/L 5.67

Copper ug/L 68.8

Fluoride ug/L 27 6

Iron ug/L 855

Lead ug/L 13.7

Magnesium ug/L 13,6 00

Manganese ug/L 14 4

Mercury ug/L 0. 828

Molybdenum ug/L 483

Nickel ug/L 30.5

Nitrate

- Nitrite as N ug/L 2,360

Nitrogen, Total Kjeldah l ug/L 4,08 0

Phosphorus, Total ug/L 71.8

Potassium ug/L 8,4 60

Selenium ug/L 1 5.4

Silica ug/L 8,57 0

Sodium ug/L 3 4,000

Strontium ug/L 42 9

Sulfate ug/L 4 09

, 000

Thallium ug/L 10.3

Titanium ug/L 4.83

TDS ug/L 46 9,000

TSS ug/L 10,4 00

Zinc ug/L 2 26

Source: ERG, 2015m

Note: Concentrations are rounded to three significant fi gures.Section 12 – Ash Transport Water Pollutant Loadings

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

Analyte Unit Average Concentration

Aluminum ug/L 1,24 0

Antimony ug/L 28.2

Arsenic ug/L 1 7.4

Barium ug/L 110

Boron ug/L 54 1

Bromide ug/L 620

Cadmium ug/L 2.19

Calcium ug/L 68,8 00

COD ug/L 20,8 00

Chloride ug/L 28,1 00

Chromium ug/L 5.59

Cobalt ug/L 14.5

Copper ug/L 13.9

Iron ug/L 1,420

Lead ug/L 12.1

Magnesium ug/L 34,5 00

Manganese ug/L 1,4 40

Mercury ug/L 0. 634

Molybdenum ug/L 29.7

Nickel ug/L 16.5

Nitrate

- Nitrite as N ug/L 6,0 70

Nitrogen, Total Kje ldahl ug/L 1,16 0

Phosphorus, Total ug/L 20 4

Potassium ug/L 2,96 0

Selenium ug/L 11.7

Silica ug/L 6,300

Sodium ug/L 53,0 00

Strontium ug/L 25 8

Sulfate ug/L 34 7 ,000

Sulfite ug/L 4,750

Thallium ug/L 89.4

Titanium ug/L 40.9

TDS ug/L 754, 000

TSS ug/L 19,7 00

Zinc ug/L 31.0

Source: ERG, 2015m

Note: Concentrations are rounded to three significant fi gures.Section 12 – Ash Transport Water Pollutant Loadings

12-27 Table 12-4. Average Effluent Concentration of Combined Ash Impou ndments

Analyte Unit Average Concentration

Aluminum ug/L 1,200

Antimony ug/L 24. 6

Arsenic ug/L 5 0.3

Barium ug/L 18 8

Beryllium ug/L 3.86

BOD ug/L 4,6 70

Boron ug/L 1,960

Cadmium ug/L 1.42

Calcium ug/L 74,6 00

COD ug/L 26,000

Chloride ug/L 16, 300

Chromium ug/L 2 1.6

Chromium (VI) ug/L 0.67 1

Cobalt ug/L 6.00

Copper ug/L 21.9

Cyanide, Total ug/L 5.28

Fluoride ug/L 650

Iron ug/L 601

Lead ug/L 7.52

Magnesium ug/L 15, 300

Manganese ug/L 67. 5

Mercury ug/L 1.18

Molybdenum ug/L 14 2

Nickel ug/L 19.1

Nitrate

- Nitrite as N ug/L 2,55 0

Nitrogen, Total Kjeldahl ug/L 891

Phosphorus, Total ug/L 19 6

Potassium ug/L 12, 900

Selenium ug/L 28.0

Silica ug/L 5,93 0

Silver ug/L 4.33

Sodium ug/L 12, 400

Sulfate ug/L 20 9,000

Sulfite ug/L 905

Thallium ug/L 31.0

Titanium ug/L 22.8

TDS ug/L 26 6

, 000

TSS ug/L 1 5,3 00

Vanadium ug/L 56.4Section 12 – Ash Transport Water Pollutant Loadings

12-28 Table 12-4. Average Effluent Concentration of Combined Ash Impou ndments

Analyte Unit Average Concentration

Zinc ug/L 7 2.3

Source: ERG, 2015m

Note: Concentrations are rounded to three significant fi gures.

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

Ash Surface Impoundments

Analyte Percent Loadings Fly Ash (%) Percent Loadings Bottom Ash (%)

Aluminum 92.5 7.5

Antimony 89.3 10.7

Arsenic 96.0 4.0

Beryllium 96.0 4.0

Calcium 77.7 22.3

Copper 79.6 20.4

Iron 76.4 23.6

Mercury 71.4 28.6

Nickel 77.7 22.3

Selenium 99.0 1.0

Zinc 90.3 9.7

TSS 84.6 15.4

Average 86.9 14.1

Source: ERG, 2015e.Section12 – Ash Transport Water Pollutant Loadings12-29Table 12-6. Industry-Level Loadings and Pollutant Removals Excluding BOD, COD, TSS, and TDS and Based on Oil-FiredUnits and Units 50 MW or Less Not Installing Technology BasisOptionPollutant LoadingsPollutant Removals From BaselineLoad (lb/year)TWPE/yearLoad (lb/year)TWPE/yearFly AshBaseline115,000,000225,000--Zero Dischargefor Generating Units>50 MW1,490,0002,880113,000,000222,000Bottom AshBaseline354,000,000509,000--Zero Discharge forGeneratingUnits>400MW139,000,000198,000216,000,000353,000Zero Discharge for Generating Units > 50 MW 1,890,0002,390311,000,000506,000Source: ERG, 2015mNote: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TSS and TDS.Note: Loadings are rounded to three significant figures.Section 12 – Ash Transport Water Pollutant Loadings

12-30 Table 12-7. Results of Ash Loadings Baseline Calculation Exclud ing BOD, COD, TSS,

and TDS

Type of Ash Impoundment Revised Industry Loading Sensitivity Analysis Loading a

Pounds/Year Pounds/Year

Including Sulfides

Fly Ash 11 5

, 000 ,00 0 11 5

, 000 ,00 0

Bottom Ash 3 54

, 000

, 000 36 8

, 000

, 000

TOTAL 4 69

, 000

, 000 48 3 ,0 00

, 000

Excluding Sulfides

Fly Ash 11 5

, 000

, 000 11 5

, 000 ,00 0

Bottom Ash 3 54

, 000

, 000 36 8

, 000

, 000

TOTAL 4 69

, 000

, 000 48 3 ,0 00

, 000

Source: ERG, 2015k; ERG, 2015n Note: Excludes loadings for pollutants not identified as POC s and for BOD, COD, TSS and TDS. Note: Loadings are rounded to three significant figures. Note: EPA completed these sensitivity analyses with a previous version of the ash analytical data set. Sinc e completion of the sensitivity analysis, EPA recalcula ted industry loadings for fly ash transport water and bot tom ash transport water and determined that they are less than 1 percent different in terms of pounds per year for both

wastestreams. EPA determined that the revision was no t significant enough to warrant reanalysis of and the re sults of the sensitivity analysis would be comparable to the analysis presented. a – Sensitivity analysis loadings include Duke Energy & UWA G settled ash transport water sample data in ash loadings calculations.

Table 12-8. Sensitivity Analysis Results for Total Industry L oadings Based on Inclusion of Late Submission UWAG Data Excluding BOD, COD, TSS, and T DS

Sensitivity Analysis Total Industry Baseline Loadings

Pounds/Year Percent Difference (%)

Bottom Ash Transport Water Baseline Loadings 354,000,000 NA

Inclusion of Late Submission UWAG Bottom Ash Data a 347,000,000 (1.93%)

Source: ERG, 2015l; ERG, 2015n Note: Excludes loadings for pollutants not identified as POC s and for BOD, COD, TSS, and TDS. Note: Loadings are rounded to three significant figures. Note: EPA completed this sensitivity analyses with a pre vious version of the ash analytical data set. Since th e completion of this sensitivity analysis, EPA recalcula ted the industry loadings for fly ash transport water and bottom ash transport water and determined they are less than 1 percent different in terms of pounds per year for both waste st reams. EPA determined that this 1 percent reduction in loadings, coupled w ith the approximately 2 percent change from inclusion of the late submission UWAG bottom ash data, was not significant enough to warrant reanalysis and the results of the sensitivity analysis would be comparable to the analysis presented. a – EPA included results from three plants from the Nove mber 2014 data set where EPA had previously confirmed those ash contributions are at least 75 percent of the contribution, by volume, to the impoundment.Section12 – Ash Transport Water Pollutant Loadings12-31Figure 12-1. Decision Tree for the Analytical Ash DataSection 13 – Combustion Residual Leachate Pollutant Loadings

13-1 

## 13. COMBUSTION RESIDUAL LEACHATE POLLUTANT

LOADINGS

Loadings calculations require a pollutant-specific conce ntration and plant-specific discharge flow to determine mass loadings. EPA calcula ted pollutant loadings for the discharge

of combustion residual leachate from both landfills an d impoundments. EPA used a variety of data sources to generate the characterization data to re present the untreated combustion residual leachate. EPA also generated a separate set of characte rization data to represent the effluent from a chemical precipitation system for the treatment of landfill leachate. Section 13.1 presents the

data sources and characterization data for combustion r esidual leachate and Section 13.2 discusses the flow rates used to calculate pollutant loa dings. All tables referenced in this section are presented at the end of the section.

13.1 W ASTEWATER C HARACTERIZATION AND D ATA S OURCES

EPA used data collected though the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey) to calculate average effluent

concentrations for untreated combustion residual leacha te from landfills/impoundments. As described in Section 9.1, EPA determined that if stringent l imitations were placed on combustion residual leachate from impoundments, the plants operating t hose impoundments would recycle the leachate back to the impoundment from which it was c ollected rather than install the technology basis for the discharge requirements. As a result, EPA determined that the mass loading discharged associated with combustion residual leac hate from impoundments would not be reduced as a result of the discharge limitations. By recycling the leachate back to the impoundment, the mass loadings will eventually be dischar ged from the impoundment outfall. Therefore, EPA determined the post-compliance loadings for combustion residual leachate from impoundments is equal to the baseline loading for combust ion residual leachate from impoundments. For combustion residual leachate from lan dfills, EPA evaluated chemical precipitation as a treatment technology option. EPA c alculated baseline loadings and postcompliance loadings for combustion residual leachate from landfills and impoundments; however, the post-compliance pollutant reductions for im poundments under all regulatory options are zero.

EPA’s Steam Electric Survey required certain plants to c ollect and analyze samples of leachate from landfills and impoundments and report the r esults of these analyses in Part G (Leachate Sampling Data for Ponds/Impoundments and Landfi lls) of the Steam Electric Survey. EPA requested these plants to sample any untreated leacha te collected from an on-site impoundment or landfill containing combustion residuals. E PA used these data to calculate a pollutant concentration data set for use in loadings calc ulations to characterize combustion residual leachate from impoundments and landfills. EPA us ed all data as provided by the plants in the Steam Electric Survey, except for the following :

• For values reported as less than the quantitation limit , EPA assumed the concentration was equal to one-half the quantitation li mit provided.

• If the plant did not provide a quantitation limit, ERG a ssumed the concentration was equal to the method detection level (MDL).Section 13 – Combustion Residual Leachate Pollutant Loadings

13-2 EPA compiled all untreated combustion residual leachat e sampling data reported in the Steam Electric Survey from 26 landfills and 15 impoundments . After reviewing the available

data to determine the subset that could be used to determine average effluent concentrations, EPA conducted an analysis on the untreated combustion resi dual leachate data to determine pollutants of concern (POCs). In the analysis, EPA re viewed characterization data for the combustion residual leachate to identify which pollutants were present in the wastewater and whether those pollutants were present in the wastewate r at a sufficient concentration and frequency to be considered treatable. The detailed result s of the POC analysis is included in “Supplemental Costs and Loadings Documentation” [ERG, 2015 d; see Appendix 101] also see the “FGD Wastewater, Combustion Residual Leachate, an d Gasification Wastewater Pollutants of Concern (POC) Analysis Methodology” [ERG, 2015b] for more detail on the methodology for determining POCs. EPA estimated pollutant loadings and remova ls only for pollutants that were identified as POCs. Therefore, for any pollutants that w ere not identified as a POC, EPA did not include the pollutant in the combustion residual leachate pollutant loadings estimates. The remainder of Section 13 discusses EPA’s methodology for deve loping average concentrations and calculating pollutant loadings and applies only to pollut ants identified as POCs.

To determine the industry average concentrations for a pol lutant, EPA first averaged all concentration data provided for each individual landfill or impoundment for which plants provided sampling data to calculate a landfill- or impoundmen t-specific average concentration. For example, if a plant had three landfills and two im poundments and they collected four samples for each of those management units (i.e., a tot al of 20 samples for each pollutant), EPA calculated an average concentration for each of the t hree landfills and each of the two impoundments (i.e., a total of five average concentratio ns). EPA then averaged the landfill- or impoundment-specific average concentrations at each plant to get a plant-level average pollutant leachate concentration. Using the same example above, E PA averaged the five average concentrations data sets together to get one plant-leve l average concentration. EPA then used the average plant-level combustion residual leachate conce ntration to calculate the average concentrations across all plants. Table 13-1 presents the average concentration for leachate from both landfills/impoundments. EPA used these average conc entrations to calculate baseline loadings for all plants discharging combustion residual l eachate.

As explained in Section 9.3, based on a review of the Ste am Electric Survey data regarding the treatment of the combustion residual landf ill leachate, EPA did not identify any plants currently operating a chemical precipitation sys tem to treat landfill leachate. Therefore,

EPA transferred the limitations and standards from the flue gas desulfurization (FGD) chemical precipitation system. Because EPA does not have analyti cal data that represent treated landfill leachate for the technology options being considered, EPA also transferred the FGD chemical precipitation effluent concentrations, identified in Se ction 11.1.5.2, to the landfill leachate for the purposes of calculating post-compliance loadings. In case s where the average concentration of

the untreated combustion residual landfill leachate is less than the FGD treated concentration for the technology option, EPA assumed that the treated co ncentration was equal to the influent (i.e., untreated leachate) average concentration. In this cas e, EPA did not calculate additional removals of these particular pollutants by the wastewat er treatment system. Table 13-2 presents the chemical precipitation effluent average concentrat ions for leachate. Additionally, EPA identified one plant that currently treats its combust ion residual leachate in a biological treatment system (combined with FGD wastewater) and one plant tha t is building a biological treatmentSection 13 – Combustion Residual Leachate Pollutant Loadings

13-3 system to treat its combustion residual leachate. To es timate the baseline combustion residual leachate discharges from these plants, EPA also transf erred the FGD biological treatment system effluent concentrations, identified in Section 11.1.5.3, to the landfill leachate. In cases where the average concentration of the untreated combustion residual landfill leachate is less than the FGD treated concentration for the technology option, EPA assumed that the treated concentration was equal to the influent (i.e., untreated leachate) average con centration. In this case, EPA did not calculate additional removals of these particular poll utants by the wastewater treatment system. Table 13-3 presents the chemical precipitation followed by biological treatment effluent average

concentrations for leachate.

13.2 W ASTEWATER F LOW R ATES

EPA used information from the Steam Electric Survey to de termine which plants discharge combustion residual leachate from impoundments and/or landfills and the amount of wastewater each plant reported discharging. EPA used plant- level leachate flow rates to calculate baseline and technology option loadings. EPA used the total plant-level leachate flow from the “Combustion Residual Leachate Input Table” to calculate c ompliance costs. Section 4.1.3 describes the methodology used to estimate the leachate flow rates for both landfills and impoundments. A copy of the input table is included in the C ombustion Residual Leachate Loadings Database [ERG, 2015a].

13.3 P OLLUTANT L OADINGS AND T OXIC -W EIGHTED P OUND E QUIVALENT (TWPE)

R ESULTS

EPA multiplied the average pollutant concentrations for each technology presented in Section 13.1 with the plant-specific wastewater flow ra tes presented in Section 13.2 to calculate the mass of pollutant discharged to surface waters for ea ch plant, as applicable. For those plants transferring the wastewater to a publicly owned treatment works (POTW), EPA adjusted the loadings to account for additional removals that would take place at the POTW. EPA identified five plants with non-small steam electric generating unit s (generating units greater than 50 megawatts (MW)) as transferring combustion residual la ndfill leachate to a POTW. For these five plants, EPA adjusted the baseline and post-compliance loadings to account for pollutant removals expected from POTWs for each. Appendix B to th is report provides the percent removal expected from well-operated POTWs, as reported in the Memorandum to the 2006 Effluent Guidelines Program Plan Docket, entitled, “Publicl y Owned Treatment Works (POTW)

Percent Removals Used for the TRI Releases2002 Database” [ERG, 2006]. For each plant identified as discharging to a POTW, EPA used the calcula ted pollutant loadings and the POTW removals shown in Appendix B to calculate the mass of po llutant discharged from the POTW to surface water, according to Equation 13-1.

(13-1) Indirect Pollutant Loading (lb/yr) = Pollutant Loading × (1 - POTW Removal)

where:

Pollutant Loading = The calculated baseline or post-com pliance loadings from a specific pollutant, in pounds/year.Section 13 – Combustion Residual Leachate Pollutant Loadings

13-4 POTW Removal = The estimated percentage of the pollutant loading that will be removed by a POTW.

After calculating these loadings for each plant and was testream, EPA then calculated the TWPE associated with the pollutant discharges. These ca lculations were completed for the baseline and post-compliance pollutant loadings for each plant. Using the plant-level loadings by wastestream, EPA was then able to calculate the basel ine and post-compliance loading at the industry level for each wastestream and regulatory option

.

For the chemical precipitation technology option, EPA assumed that all but the two plants identified as operating biological treatment systems woul d install a chemical precipitation treatment system to treat only the combustion residual landfill leachate flow. No plants currently treat landfill leachate with a chemical precipitatio n system. EPA calculated discharge loadings for these plants using the average concentration data s et associated with chemical precipitation systems (presented in Table 13-2) and plant-specific leacha te flow rates (discussed in Section 4.1.3).

The raw data output of the combustion residual leachat e loadings can be found in Appendix B, along with a table of plant-level loadings in pounds/year and TWPE/year. Table 13-4 presents the combustion residual leachate loadings on an industry level for baseline and each technology option. Table 13-4 presents loadings based o n oil-fired generating units and those generating units with a generating capacity of 50 MW or less not installing the technology basis because they are not facing any more stringent requir ements than already existed under the previously established regulations. The loadings exclude the pollutant parameters biochemical oxygen demand (BOD), chemical oxygen demand (COD), total dis solved solids (TDS), and total suspended solids (TSS) because they double count the loadings f or specific pollutants already included. The table includes the number of plants identified as discharging combustion residual leachate, the total industry flow rate associated with ea ch technology option, and the total industry loadings in pounds per year and TWPE per year.

EPA evaluated applying different effluent limitations to o il-fired generating units and generating units with a capacity of 50 MW or less. For disc harges from these generating units, Best Available Control Technology Economically Achievabl e (BAT) would be set equal to the current Best Practicable Control Technology Currently A vailable (BPT) standard for each of the wastestreams for which EPA is revising the effluent limi tations guidelines and standards (ELGs). For the tables presenting the results of the loadings a nd the pollutant removals in this section, EPA presents two different versions of the tables: one version that includes the loadings and pollutant removals based on all generating units/plants di scharging the wastestream installing the appropriate technology basis, and a second version based o n all oil-fired generating units and generating units with a capacity of 50 MW or less not need ing to install the technology basis

because the current controls are sufficient to meet th e BPT requirements. Section 5 of the Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (TDD) provides more details regarding the analyses of these factors [U.S. EPA, 2015]. Section 8 of the TDD discusses the rationale regarding the decision.Section 13 – Combustion Residual Leachate Pollutant Loadings

13-5 Table 13-5 presents the pollutant removals for combustion residual landfill leachate, in both pounds per year and TWPE per year, for the chemical precipitation technology options. Table 13-5 presents the pollutant removals based on oil-fi red generating units and those generating units with a generating capacity of 50 MW or less not installing the technology basis because they are not facing any more stringent requirem ents than already existed under the previously established regulations. EPA calculated the pollut ant removals by subtracting the technology option loadings from the baseline loadings.

13.4 R EFERENCES

1. ERG. 2015a. Eastern Research Group, Inc. Combustion Resi dual Leachate Loadings Database. (30 September). DCN SE05840.

2. ERG. 2015b. Eastern Research Group, Inc. “FGD Wastewater , Combustion Residual Leachate and Gasification Pollutants of Concern (POC) Analysis Methodology.” (30 September). DCN SE05342.

3. ERG. 2015c. Eastern Research Group, Inc. Steam Electric Technical Questionnaire Database (“Steam Electric Survey”). (30 September). DCN SE05903.

4. ERG. 2015d. Eastern Research Group, Inc. “Supplemental Cos ts and Loadings Documentation.” (30 September). DCN SE05839.

5. U.S. EPA. 2015. U.S. Environmental Protection Agency. Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category . (30 September). DCN SE05904.Section 13 – Combustion Residual Leachate Pollutant Loadings

13-6 Table 13-1. Average Untreated Combustion Residual Leachate Concen trations

Analyte Unit Untreate d Combustion Residual

Leachate Concentration

Aluminum ug/L 2,99 0

Antimony ug/L 3.7 5

Arsenic ug/L 38 .4

Barium ug/L 53 .2

Boron ug/L 22,40 0

Cadmium ug/L 10 .1

Calcium ug/L 40 8

, 000

Chloride ug/L 41 3

, 000

Chromium ug/L 2,1 20

Cobalt ug/L 3 8.6

Copper ug/L 7. 58

Iron ug/L 37, 100

Magnesium ug/L 11 8

, 000

Manganese ug/L 2,7 20

Mercury ug/L 1. 06

Molybdenum ug/L 1,3 80

Nickel ug/L 46 .5

Selenium ug/L 111

Sodium ug/L 308, 000

Sulfate ug/L 1,7 90

, 000

Thallium ug/L 1. 16

TDS ug/L 3, 500

, 000

TSS ug/L 35,8 0 0

Vanadium ug/L 1,91 0

Zinc ug/L 211

Source: ERG, 2015a; ERG, 2015b; ERG, 2015c. Note: Concentrations are rounded to three significant f igures. Note: Includes only those pollutants identified as POCs.Section 13 – Combustion Residual Leachate Pollutant Loadings

13-7 Table 13-2. Average Chemical Precipitation Effluent Concentrat ions for Combustion

Residual Leachate

Analyte Unit Average Concentration

Aluminum ug/L 120

Antimony ug/L 3.75

Arsenic ug/L 5.83

Barium ug/L 53.2

Boron ug/L 22

, 40 0

Cadmium ug/L 4.21

Calcium ug/L 40 8,000

Chloride ug/L 41 3,000

Chromium ug/L 6.45

Cobalt ug/L 9.30

Copper ug/L 3.78

Iron ug/L 110

Magnesium ug/L 11 8,000

Manganese ug/L 2

, 7 20

Mercury ug/L 0.1 39

Molybdenum ug/L 125

Nickel ug/L 9.11

Selenium ug/L 111

Sodium ug/L 27 6,000

Sulfate ug/L 1

, 2 40,000

Thallium ug/L 1.16

TDS ug/L 3,500,000

TSS ug/L 8

, 590

Vanadium ug/L 12.6

Zinc ug/L 20.0

Source: ERG, 2015a; ERG, 2015b; ERG, 2015c. Note: Concentrations are rounded to three significant fi gures. Note: Includes only those pollutants identified as POCs.Section 13 – Combustion Residual Leachate Pollutant Loadings

13-8 Table 13-3. Average Chemical Precipitation followed by Biological T reatment Effluent

Concentration for Combustion Residual Leachate

Analyte Unit Average Concentrati on

Aluminum ug/L 120

Antimony ug/L 3.75

Arsenic ug/L 5.83

Barium ug/L 53.2

Boron ug/L 22

, 40 0

Cadmium ug/L 4.21

Calcium ug/L 40 8,000

Chloride ug/L 41 3,000

Chromium ug/L 6.45

Cobalt ug/L 9.30

Copper ug/L 3.78

Iron ug/L 110

Magnesium ug/L 11 8,000

Manganese ug/L 2

, 7 20

Mercury ug/L 0.05 07

Molybdenum ug/L 125

Nickel ug/L 6.30

Selenium ug/L 5.72

Sodium ug/L 27 6,000

Sulfate ug/L 1

, 2 40,000

Thallium ug/L 1.16

TDS ug/L 3

, 500 ,000

TSS ug/L 8

, 590

Vanadium ug/L 12.6

Zinc ug/L 20.0

Source: ERG, 2015a; ERG, 2015b; ERG, 2015c. Note: Concentrations are rounded to three significant fi gures. Note: Includes only those pollutants identified as POCs.Section 13 – Combustion Residual Leachate Pollutant Loadings

13-9 Table 13-4. Industry-Level Combustion Residual Leachate Loadings Excluding BOD, COD, TDS, and TSS and Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis

Treatment Option Number of

Plants Total Industry

Flow (MGD) Total Industry Loadings

Pounds/Year TWPE/Year

Baseline 95 a 9. 09 85,400,000 70,300

Chemical Precipitation 95 a 9. 09 72,900,000 36,400

Note: Excludes loadings for pollutants not identified as POC s and for BOD, COD, TSS and TDS. Note: Loadings are rounded to three significant figures. a – One plant operates only oil-fired generating units an d/or generating units with a generating capacity of 50 MW or less; therefore, this plant is not facing any mor e stringent requirements than exist under the previously est ablished BPT regulations. As such, EPA assumed that this plant will not install the technology basis and, therefore, will not incur any compliance costs. Additionally, EPA assumed it will continue to discharge combustion residual leachate at its current baseline level and will not achieve any pollutant removals for the technology options evaluated.

Table 13-5. Combustion Residual Landfill Leachate Loadings Removals Excluding BOD, COD, TDS, and TSS and Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis

Technology Option Total Industry Pollutant Removals

Pounds/Year TWPE/Year

Removal (Baseline

– > C hemical P recipitation ) 12,500,000 33,800

Note: Excludes loadings for pollutants not identified as POC s and for BOD, COD, TSS and TDS. Note: Removals are rounded to three significant figures. T he removals may not equal the subtraction of the technology option from the baseline using the values in T able 13-4 due to rounding.Section 14 - Gasification Pollutant Loadings

14-1 

## 14. GASIFICATION POLLUTANT LOADINGS

As discussed in Section 10, the three plants currently d ischarging gasification wastewater already operate the treatment technology considered by EPA to be the Best Available Control Technology Economically Achievable (BAT). As a result, these plants incur costs only associated with compliance monitoring. Additionally, bec ause the currently operating gasification generating units operate evaporation (i.e., t he BAT technology option), EPA determined that the baseline loadings are equal to the post-c ompliance loadings. The removals for gasification wastewater, baseline loadings minus tec hnology option loadings, are equal to zero because all plants are currently operating the tec hnology basis selected as BAT. Therefore, EPA did not estimate baseline or post-compliance load ings for gasification wastewater.Section 15 – Summary of Costs and Pollutant Removals by Regulatory Option

15-1 

## 15. SUMMARY OF COSTS AND POLLUTANT REMOVALS BY

REGULATORY OPTION

EPA evaluated five regulatory options comprising various co mbinations of the technology options considered for each wastestream. Ta ble 15-1 lists each regulatory option that EPA evaluated along with the associated treatment techno logy basis for all of the affected wastestreams. EPA estimated the costs and pollutant lo ading removals associated with steam electric power plants to achieve compliance for each regu latory option under consideration. This section summarizes the total estimated compliance cost s and pollutant removal estimates associated with each regulatory option.

Using the methodologies described in this report, EPA com bined the plant-level estimated compliance costs for the appropriate technolo gy options, based on the information specified in Table 15-1, to generate an industry-level estima ted compliance cost for each regulatory option. Table 15-2 presents the estimated complia nce cost for each of the five regulatory options based on the oil-fired generating units an d generating units with a capacity of 50 megawatts (MW) or less not needing to install the techn ology basis because the current

controls are sufficient to meet the Best Practicable Control Technology Currently Available (BPT) requirements. For each regulatory option, the ca pital costs, annual operation and maintenance costs (O&M), one-time costs, and recurrin g costs are presented. All cost estimates are expressed in terms of pre-tax 2010 dollars.

EPA also estimated the pollutant loading removals assoc iated with steam electric power plants to achieve compliance for each regulatory option un der consideration. Using the methodology described in this report, EPA combined the plant -level pollutant loadings for the appropriate technology options, based on the information specified in Table 15-1, to calculate industry-level estimated pollutant loadings and pollutant r emovals for each regulatory option. Table 15-3 presents the total industry loadings and pollutant removals at baseline and for each of the five regulatory options based on the oil-fired generati ng units and generating units with a capacity of 50 MW or less not needing to install the tec hnology basis because the current controls are sufficient to meet the BPT requirements. EPA excluded the pollutant parameters biochemical oxygen demand (BOD), chemical oxygen demand (COD) , total organic carbon (TOC), total dissolved solids (TDS), and total suspended solids (TSS) from the total loadings and toxic-weighted pound equivalent (TWPE) values presented i n these tables to avoid double counting.

Similarly to the methodology used to calculate industry -level removals, EPA used pollutant-level loadings for each technology option to est imate the removals achieved by steam electric power plants for each of the regulatory option s considered. The pollutant-level baseline loadings and pollutant-level removals for each regulatory option by wastestream are presented in

the memorandum entitled “Steam Electric Pollutant-Level Loadings and Removals for Each Wastestream and Regulatory Option” (DCN SE05847).

EPA also estimated the pollutant loadings removals by poll utant for each regulatory option. Similar to the methodology used to calculate in dustry-level removals, EPA used pollutant-level loadings for each technology option to est imate the removals achieved by steamSection 15 – Summary of Costs and Pollutant Removals by Regulatory Option

15-2 electric power plants for each of the regulatory option s considered. The pollutant-level baseline loadings and pollutant-level removals for each regulatory option by wastestream are presented in

the memorandum entitled “Steam Electric Pollutant-Level Loadings and Removals for Each Wastestream and Regulatory Option” (DCN SE05847).Section15 – Summary of Costs and Pollutant Removals by Regulatory Option15-3Table 15-1. Treatment Technologies Basis for Estimating Compliance Costs and Pollutant Loadings by RegulatoryOptionRegulatoryOptionbTREATMENT TECHNOLOGYaFGD WastewaterFly AshTransportWaterBottom AshTransportWaterCombustionResidualLeachateGasificationWastewaterFlue GasMercuryControlWastesChemicalPrecipitationChemicalPrecipitationwith BiologicalTreatmentChemicalPrecipitation withEvaporationDryVacuumSystemMDS/ RemoteMDSChemicalPrecipitationEvaporationDry VacuumSystemA XXX XBXXX XCXX XcX XDXX X X XEXX X X X XMDS – Mechanical Drag Systema – Table presents only the technology options evaluated for the costs and pollutant removals. All other appropriate technology cost modules wereused to generate the compliance costs (e.g., compliance monitoring, transportation, disposal).b – Regulatory Options A, B, D, and E assume that oil-fired generating units and generating units with a capacityof 50 MW or less do not install thetechnology basis for all wastestreams. Regulatory Option C assumes that oil-fired generating units and generating units with a capacity of 50 MW orless do not install the technology basis for FGD wastewater treatment and fly ash, while oil-fired generating units and generating units with a capacityof 400 MW or less do not install the technology basis forbottom ash.c –Requires only generating units with a capacity of 400 MW ormore to comply with the technology basis.Section 15 – Summary of Costs and Pollutant Removals by Regulatory Option

15-4 Table 15-2. Cost of Implementation by Regulatory Option [In milli ons of pre-tax 2010 dollars]

Regulatory Option a Number of

Plants Capital

Costs Annual

O&M Costs One-Time

Costs Recurring Costs

3

- year 5

- year 6

- year 10

- year b

A 100 $ 1,069 $ 78 $ 0 $ 0 $ 0 $ 7 ($25)

B 100 $ 1,969 $ 123 $ 0 $ 0 $ 0 $ 7 ($5)

C 139 $ 4,258 $ 220 $ 0.1 $ 0 $ 24 $ 7 ($54)

D 181 $ 5,426 $ 326 $ 0.2 $ 4 $ 49 $ 7 ($76)

E 196 $ 6,031 $ 360 $ 0.2 $ 4 4 $ 49 $ 14 ($76)

a – Regulatory Options A, B, D, and E assume that oil-fi red generating units and generating units with a capacity of 50 MW or less do not install the technology basis for al l wastestreams. Regulatory Option C assumes that oil-fir ed generating units and generating units with a capacity of 50 MW or less do not install the technology basis for F GD wastewater treatment and fly ash, while oil-fired gene rating units and generating units with a capacity of 400 MW or less do not install the technology basis for bottom as h.

b

– The values in this column are negative and presented in par enthesis because they represent cost savings.

Table 15-3. Estimated Pollutant Removals by Regulatory Option

Regulatory Option a Total Industry Loadings Total Industry Removal b

Pounds/Year TWPE/Year Pounds/Year TWPE/Year

Baseline 2,210,000,000 2, 680 ,000 NA NA

A 2,060,000,000 1, 650 ,000 15 0 ,000,000 1, 030 ,000

B 2,050,000,000 1, 510 ,000 16 1 ,000,000 1, 170 ,000

C 1,830,000,000 1, 2 00 ,000 37 6 ,000,000 1, 480 ,000

D 1,700,000,000 1,000 ,000 51 3 ,000,000 1, 680 ,000

E 1,680,000,000 96 7 ,000 52 6 ,000,000 1, 710 ,000

Note: Excludes loadings for pollutants not identified as POC s and loadings for BOD, COD, TDS, and TSS. Note: Pollutant loadings and removals are rounded to three significant figures. The removals may not equal the subtraction of the technology option from the baseline due to rounding. NA – Not applicable. a – Baseline and Regulatory Options A, B, D, and E assum e that oil-fired generating units and generating units w ith a capacity of 50 MW or less do not install the technology basis for all wastestreams. Regulatory Option C assum es that oil-fired generating units and generating units wit h a capacity of 50 MW or less do not install the technolo gy basis for FGD wastewater treatment and fly ash, while oil-fired generating units and generating units with a ca pacity of 400 MW or less do not install the technology basis for bottom ash. b – Compared to baseline.Section 16 – Clean Power Plan

16-1 

## 16. CLEAN POWER PLAN

As discussed in Section 1, in addition to estimating com pliance costs and pollutant loadings and removals associated with the effluent limit ations guidelines and standards (ELG) accounting for the Coal Combustion Residual (CCR) rule, EPA also accounted for operational changes expected as part of the Clean Power Plan (CPP) . Section 16.1 describes the methodology EPA used to incorporate the CPP into compli ance costs and pollutant loadings and Section 16.2 presents the estimated compliance cost and poll utant loadings for each of the main regulatory options. The tables referenced in this section appear at the end of the section.

16.1 M ETHODOLOGY FOR I NCORPORATING THE CPP

Because only the proposed CPP was available at the time c ompliance costs were evaluated, EPA took the approach of estimating compliance c osts and pollutant loadings that account for expected changes from the proposed CPP as a pr oxy for the final CPP. EPA accounted for the CPP in the version of the complianc e costs and pollutant loadings that also account for the final CCR rule. The methodologies descr ibed in elsewhere this report and the industry-level estimated compliance costs and industry-le vel estimated pollutant loadings and removals presented in Section 15 do not account for the CP P. As discussed in Section 1.3.3 of

the Technical Development Document for the Effluent Limitations Guideline s and Standards for the Steam Electric Power Generating Point Source Category [U.S. EPA, 2015], the CPP rulemaking is focused on cutting carbon pollution from stea m electric power plants.

EPA used output from the Integrated Planning Model (IPM) to account for the CPP in its analyses. IPM is a multi-regional, dynamic, deterministic linea r programming model of the U.S. electric power sector that provides forecasts of least-c ost capacity expansion, electricity dispatch, and emission control strategies for meeting energy dema nd and environmental, transmission, dispatch, and reliability constraints. During the develop ment of the CPP, EPA used the IPM to predict how industry may respond to that rule. This IPM ou tput for CPP provided insight to steam electric generating unit-level retirements that c ould potentially be triggered by requirements established by the CPP. For purposes of the e ffluent limitations guidelines and standards (ELG) analyses, EPA reviewed the IPM CPP poli cy run outputs for analyses year 2020. Although not necessarily definitive, the IPM output ca n be used to develop a list of steam electric generating unit retirements that form the basis for a reasonable estimate of how actions plants (and power companies) make can affect the complia nce cost and pollutant removal estimates for the ELG. A list of the generating units pr edicted to retire as a result of the CPP by the IPM is included in Appendix A.

To account for these estimated affects for the CPP, EP A generated a second set of compliance cost and pollutant loadings estimates for th e ELG. For this second set of analyses, all generating units that are projected by IPM to close/retire due to the CPP were assumed to be retired prior to implementation of the final ELGs; ther efore, these generating units would not incur any ELG compliance costs. Appendix A of this report i ncludes a table listing plants estimated to incur compliance costs (and associated reducti ons in pollutant discharges) under the ELG by wastestream. This table identifies whether the I PM predicts all generating units at the plant to retire due to the CPP, resulting in zero compl iance costs and zero pollutant removals, orSection 16 – Clean Power Plan

16-2 only some generating units at the plant to retire due to the CPP, resulting in a reduction in compliance costs and pollutant removals, as compared to the ELG estimates that do not account for the CPP. As with the approach used to account for th e final CCR rule, EPA determined that it was not necessary to revise the methodology used to esti mate the compliance costs or pollutant loadings for these analyses.

Table 16-1 presents the number of plants and stream elect ric generating units for which EPA estimated compliance costs associated with the EL G accounting for CCR and CPP and Table 16-2 presents the number of plants and steam electr ic generating units expected to achieve pollutant removals as a result of the ELG accounting fo r CCR and CPP.

16.2 S UMMARY OF C OSTS AND P OLLUTANT R EMOVALS BY R

EGULATORY O PTION
A CCOUNTING FOR THE CPP

As described in Section 15, EPA used the methodologies descri bed in this report to combine the plant-level estimated compliance costs for the appropriate technology options, based on the information specified in Table 15-1, to generate an i ndustry-level estimated compliance cost for each regulatory option. EPA then used the listi ng of projected generating unit retirements based on the CPP IPM policy run to adjust (zero out) compliance costs for those generating units that are expected to retire, as described in Section 16.1. Table 16-3 presents the estimated compliance cost for each of the five regulat ory options accounting for the CPP and based on oil-fired generating units and generating units with a capacity of 50 MW or less not needing to install the technology basis because the curr ent controls are sufficient to meet the BPT requirements. For each regulatory option, the capi tal costs, annual operation and maintenance costs (O&M), one-time costs, and recurrin g costs are presented. All cost estimates are expressed in terms of pre-tax 2010 dollars.

EPA also estimated the pollutant loadings removals assoc iated with the steam electric power plants to achieve compliance for each regulatory option under consideration. As described in Section 15, EPA used the methodologies described in thi s report to combine plant-level pollutant loadings for the appropriate technology options, based on the information specified in Table 15-1, to calculate industry-level estimated pollutant loadings and pollutant removals for each regulatory option. EPA then used the listing of proj ected generating unit retirements based on the CPP IPM policy run to adjust (zero out) the ba seline and the technology option loadings for those generating units that are expected to retire, a s described in Section 16.1. Table 16-4 presents the total industry-level loadings and pollutant removals at baseline and for each of the five regulatory options accounting for the CPP. EPA exc luded the pollutant parameters biochemical oxygen demand (BOD), chemical oxygen demand (COD) , total organic carbon (TOC), total dissolved solids (TDS), and total suspended solids (TSS) from the total loadings and toxic-weighted pound equivalent (TWPE) values presented i n these tables to avoid double counting.

EPA also estimated the pollutant loadings removals by poll utant for each regulatory option [ERG, 2015]. See Appendix A for the plant-level com pliance cost estimates and pollutant loadings for each wastestream.Section 16 – Clean Power Plan

16-3 16.3 R EFERENCES

1. ERG. 2015. Eastern Research Group, Inc. “Steam Electric Pollutant-Level Loadings and Removals for Each Wastestream and Regulatory Option.” ( 30 September). DCN

SE05847.

2. EPA. 2015. U.S. Environmental Protection Agency. Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Elect ric Power Generating Point Source Category . (30 September). DCN SE05904.Section 16 – Clean Power Plan

16-4 Table 16-1. Number of Steam Electric Plants and Generating Un its Expected to Incur Compliance Costs by Wastestream and Regulatory Option Accounting for CCR and CPP

Regulatory Option FGD

Wastewater Fly Ash

Transport

Water Bottom Ash

Transport

Water Combustion

Residual

Leachate Gasification

Wastewater FGMC

Wastewater Total a

A 69 ( 160 units) 1 6 ( 32 units) 0 0 2 ( 2 units) 0 79 ( 174 units)

B 69 ( 160 units) 1 6 ( 32 units) 0 0 2 ( 2 units) 0 79 ( 174 units)

C 69 ( 160 units) 1 6 ( 32 units) 61 ( 114 units) 0 2 ( 2 units) 0 1 08 ( 224 units)

D 69 ( 160 units) 1 6 ( 32 units) 1 03 ( 209 units) 0 2 ( 2 units) 0 1 34 ( 278 units)

E 69 ( 160 units) 1 6 ( 32 units) 1 03 ( 209 units) 60 ( 147 units) 2 ( 2 units) 0 1 45 ( 315 units)

a

– The number of plants and generating units incurring costs is not additive for each regulatory option because some plants and units may incur costs for multiple wastes treams.

Table 16-2. Number of Steam Electric Plants and Generating Un its Expected to Achieve Pollutant Removals by Wastestream and Regulatory Option Accounting for CCR and CPP

Regulatory Option FGD

Wastewater Fly Ash

Transport

Water Bottom Ash

Transport

Water Combustion

Residual

Leachate Gasification

Wastewater FGMC

Wastewater Total a

A 38 ( 86 units) 20 ( 38 units) 0 0 0 0 50 ( 108 units)

B 65 ( 155 units) 20 ( 38 units) 0 0 0 0 7 5 ( 170 units)

C 65 ( 155 units) 20 ( 38 units) 57 ( 106 units) 0 0 0 1 0 0 ( 213 units)

D 65 ( 155 units) 20 ( 38 units) 95 ( 195 units) 0 0 0 1 23 ( 264 units)

E 65 ( 155 units) 20 ( 38 units) 95 ( 195 units) 60 ( 147 units) 0 0 1 38 ( 307 units)

a – The number of plants and generating units expected to achie ve pollutant removals is not additive for each regulatory option because some plants and units may achieve removals for multiple wastestreams.Section 16 – Clean Power Plan

16-5 Table 16-3. Cost of Implementation by Regulatory Option Accounting for CCR and CPP [In millions of pre-tax 2010 dollars]

Regulatory Option a Number of

Plants Capital

Costs Annual

O&M Costs One-Time

Costs Recurring Costs

3

- year 5

- year 6

- year 10

- year b

A 79 $ 910 $ 67 $ 0 $ 0 $ 0 $ 6 ($19)

B 79 $ 1,640 $ 103 $ 0 $ 0 $ 0 $ 6 ($19)

C 108 $ 3,462 $ 180 $ 0.1 $ 0 $ 19 $ 6 ($42)

D 134 $ 4,161 $ 235 $ 0.2 $ 3 $ 32 $ 6 ($ 58 )

E 145 $ 4,638 $ 264 $ 0.2 $ 3 $ 32 $ 11 ($ 58 )

a – Regulatory Options A, B, D, and E assume that oil-fi red generating units and generating units with a capacity of 50 MW or less do not install the technology basis for al l wastestreams. Regulatory Option C assumes that oil-fir ed generating units and generating units with a capacity of 50 MW or less do not install the technology basis for f lue gas desulfurization (FGD) wastewater treatment and fly as h, while oil-fired generating units and generating units with a capacity of 400 MW or less do not install the techno logy basis for bottom ash. b – The values in this column are negative and presented in parenthesis because they represent cost savings.

Table 16-4. Estimated Pollutant Removals by Regulatory Option Accou nting for CCR and

CPP

Regulatory Option a Total Industry Loadings Total Industry Removal b

Pounds/Year TWPE/Year Pounds/Year TWPE/Year

Baseline 1,700,000,000 2, 140 ,000 NA NA

A 1,580,000,000 1, 250 ,000 124,000,000 891 ,000

B 1,570,000,000 1, 130 ,000 13 2 ,000,000 1, 0 1 0 ,000

C 1,390,000,000 878 ,000 306,000,000 1, 26 0 ,000

D 1,330,000,000 785,000 371,000,000 1, 35 0 ,000

E 1,320,000,000 75 5 ,000 382,000,000 1, 380 ,000

Note: Excludes loadings for pollutants not identified as POC s and for BOD, COD, TDS, and TSS. Note: Pollutant loadings and removals are rounded to three significant figures. The removals may not equal the subtraction of the technology option from the baseline due to rounding. NA – Not applicable. a – Baseline and Regulatory Options A, B, D, and E assum e that oil-fired generating units and generating units w ith a capacity of 50 MW or less do not install the technology basis for all wastestreams. Regulatory Option C assum es that oil-fired generating units and generating units wit h a capacity of 50 MW or less do not install the technolo gy basis for FGD wastewater treatment and fly ash, while oil-fired generating units and generating units with a ca pacity of 400 MW or less do not install the technology basis for bottom ash.

b

– Compared to baseline.Section 17- Evaluation of Cost and Pollutant Removal Estimates

17-1 

## 17. EVALUATION OF COST AND POLLUTANT REMOVAL

ESTIMATES

This section describes the activities EPA used to evaluate the compliance cost and pollutant removal estimates described in this report. Plan s for these quality control activities are

detailed in the Quality Assurance Project Plan for the Steam Electric Effluent Gui delines Rulemaking, Version 4 , dated April 5, 2013, and approved on April 19, 2013, (hereafter refe rred to as the QAPP). The activities included:

• Verifying that the collected cost data met the data accept ance specifications presented in Table 2-3 in the QAPP.

• Checking database code, spreadsheet data entry, and calculat ions and documenting these checks for databases and spreadsheets deve loped to estimate costs and pollutant loadings.

• Verifying that the estimated costs met the quality specifi cations presented in Table 2-4 in the QAPP.

All tables referenced in this section are presented at t he end of this section.

17.1 V ERIFYING C OST D ATA A GAINST A CCEPTANCE S PECIFICATIONS

EPA collected information about the costs for steam e lectric power plants to install and operate the wastewater pollution control technologies de scribed in this report, including wastewater treatment systems, ash handling operations, and costs for hauling solid waste for onor off-site disposal. EPA obtained recent (i.e., 2000-2010) cost information from steam electric power plants in response to the Questionnaire for the Steam Electric Power Generating Effluent

Guidelines (Steam Electric Survey), as well as more current (i. e., 2009-2011) cost information from equipment vendors.

The criteria EPA used to evaluate the quality of collect ed pollution control technology cost information are summarized in Table 17-1, along with acceptable values for each criterion.

EPA’s verification of how well the cost data met the quality specifications is presented, by acceptance criterion, in this section.

Currency. With the exception of surface impoundment installations and their operation, EPA collected all costs from steam electric power pla nts, vendors, or documented Internet sources and represented systems installed in 2000 or later, t hus meeting the currency specification.

To estimate the baseline cost for surface impoundment ins tallations and their operation, EPA used two EPA studies evaluating the economics of wast e disposal at coal-fired power plants: U.S. EPA & TVA Economics of Ash Disposal at Coal-fired Power Plants [U.S. EPA and TVA, 1981] and U.S. EPA Full-Scaled Field Evaluation of Waste Disposal from Coal-fired Electric Generating Plants [U.S. EPA, 1985]. These estimates predate the time perio d specifiedSection 17- Evaluation of Cost and Pollutant Removal Estimates

17-2 for the currency criterion; however, these estimates are the “best available” and suitable for the estimate of costs associated with baseline operations.

Technology. EPA obtained costs for equipment appropriate for and demo nstrated to be available for steam electric power plants, including che mical precipitation, anoxic/anaerobic biological metals removal, and evaporation of flue gas de sulfurization (FGD) wastewater and/or combustion residual leachate; dry vacuum fly ash handli ng; mechanical drag system (MDS) or remote MDS for bottom ash handling; and transportation a nd disposal of ash and FGD

wastewater treatment solids.

Accuracy/Reliability. As listed in Table 17-1, the specification for accuracy an d reliability was that quotes be obtained directly from s team electric power plants or from vendors who do business with steam electric power plants. Quotes fo r anoxic/anaerobic biological metals removal and evaporation of FGD wastewater and/or combu stion residual leachate; dry vacuum fly ash handling; and MDS or remote MDS for bottom ash handling were obtained from vendors that do business with steam electric power plants and t hus met this specification.

Although quotes for other equipment were from vendors that m ay or may not directly serve steam electric power plants, they were obtained f rom reputable vendors that sell the type of equipment (including appropriate materials of construction) used for these operations (e.g., chemical precipitation, transport, and disposal). For t his reason, although the quotes in some cases are not from vendors that directly serve steam electric power plants, these quotes meet the criterion that the reported information is “true.”

In addition, as described throughout this report, EPA develo ped industry cost factors for many of the direct and indirect capital cost factors (e.g., installation and engineering overhead cost factors) used in the cost model from Steam Electr ic Survey data. Other cost elements (e.g., equipment capacity factors, materials of construction, and chemical dosage rates and sludge generation rates for chemical precipitation) were als o derived from Steam Electric Survey responses. In this way, EPA met the specification for accuracy and reliability by using industryspecific data.

Comparability. EPA requested steam electric power plants report installa tion and operation costs for ash handling, wastewater treatment , and other waste management (dollars per year) in the Steam Electric Survey, if the system wa s installed in the year 2000 or later. EPA intended to use the reported capital and operating costs to ev aluate comparability. Many respondents did not respond to this question and those who di d respond either did not itemize the total costs, or provided only certain itemized costs. For this reason, EPA could not directly compare costs reported in the responses to the Steam E lectric Survey to prices that EPA obtained for equipment, installation, and shipping. As a result, E PA could not determine the comparability of the collected cost data. However, EPA used reported S team Electric Survey costs to directly develop industry-specific labor rates and indirect cost fa ctors.

17.2 V ERIFYING A NALYTICAL D ATA AGAINST ACCEPTANCE S PECIFICATIONS

EPA collected analytical data representing the influent a nd effluent pollutant concentrations from steam electric power plant wastewa ter treatment systems for use in estimating the baseline and post-compliance loadings for th e industry. Section 3 of this reportSection 17- Evaluation of Cost and Pollutant Removal Estimates

17-3 discusses the data used to estimate the loadings. Some of the data used in the loadings analysis are from EPA’s primary data collection efforts (i.e., EPA’s sampling program), while the remainder of the data came from secondary data (e.g., in dustry-provided monitoring data, Steam Electric Survey data, Electric Power Research Institut e (EPRI) reports, 1974 and 1982 Technical Development Documents (TDDs)).

EPA reviewed the data collected as part of the EPA sampl ing program to evaluate whether they were of sufficient quality for use in the loadings analysis. The data review criteria that EPA used in assessing the quality of the data are desc ribed in Section 5.1.1 of the QAPP. Based on these criteria, EPA developed data review narrat ives for each set of analytical data generated by the sampling program. These data review narrati ves are included in the attachments to the sampling episode reports for each sampling event [ER G, 2012a-2012j; U.S. EPA, 2009]. Based on the review of the analytical data, EPA made dat a point-specific determinations as to whether the data should be included in the loadings analys is.

In addition to the sampling data, EPA also used other seco ndary data sources to estimate the loadings. A summary of the acceptance criteria EPA used to evaluate whether these data were sufficient for use in the loadings analysis can be found in the “Development Memorandum for the Steam Electric Analytical Database for the Final Rule” [ERG, 2015]. This memorandum provides a description specific to the data used to character ize each wastestream, including secondary data sources.

17.3 D EVELOPING AND C HECKING THE C OST AND L OADINGS M ODELS

EPA developed a detailed cost model for estimating total inst alled capital costs and O&M costs for each individual steam electric power plant, as described earlier in this report. EPA also developed a detailed loadings model to estimate the baseli ne and post-compliance loadings for each individual steam electric power plant, as described in Section 10. The model outputs

received several reviews:

• A project engineer checked that the calculations reflec ted the methodologies outlined in this report

. Where the calculations and assumptions documentation di d not agree, EPA determined if the documentation or calcul ations required

corrections and ensured the corrections were made.

• An engineer involved in the models development checked th e accuracy of the calculations in the model’s code/queries by performing hand calculations and comparing the results to the model outputs. Where the mode l and hand calculations resulted in a discrepancy, the model was c orrected and rechecked to ensure the correct calculations were being executed by the mo del.

• An engineer provided independent technical review of the mode l outputs. The outputs were checked to ensure the expected number of rec ords (i.e., the number of known plants incurring costs/discharging). Specificall y for the cost model, the engineer confirmed that the individual cost elements summe d to the calculated total for each category of costs presented in the output ( e.g., the sum of all individual capital cost elements equals the calculated tot al capital cost). The engineer also checked that the cost model output calcula ted the total annualizedSection 17- Evaluation of Cost and Pollutant Removal Estimates

17-4 costs appropriately by calculating the plant-specific val ues in Excel and comparing them to annualized costs presented in the output.

• After each model run, an engineer analyzed the specific model outputs for the expected changes based on industry profile changes or chan ges to the model equations and/or inputs. The engineer performed the following types of checks:

— Confirmed that plants removed from the industry profile no longer had compliance costs or pollutant loadings in all outputs (e.g., FGD biological treatment, fly ash, bottom ash).

— Confirmed that plants identified as incurring compliance c osts/discharging wastewater were included in all applicable cost and loadin gs outputs.

— Confirmed that plants incurring compliance costs also hav e a calculated pollutant loading, where appropriate. 123

— Confirmed that changes to models and/or model inputs, such as flow rates, factors, or equations, resulted in the expected change in t he specific cost elements/loadings in the model outputs.

• The engineer noted issues or discrepancies and the model outputs were corrected. The engineer rechecked the new outputs for all issues iden tified.

• A senior engineer reviewed the costs and loadings by compa ring the estimates for each plant and technology and evaluating whether the tre nds in costs/loadings

reflected the amount of wastewater treated or ash hand led and the baseline waste management strategies.

17.4 E VALUATING C OST E STIMATE Q UALITY

Verification of the completed cost estimates means det ermining if estimated costs meet the data acceptance criteria specified in Table 2-4 of the QAPP. For example, the first acceptance criterion is that the costs meet the requirements for economic analysis. The specifications for this

criterion were that the estimates include both one-ti me costs for equipment purchase, installation, and other direct and indirect capital costs and ongoing opera tion and maintenance costs. The cost estimates fully met these specifications. Table 17-3 repr oduces the QAPP cost estimate quality specifications along with an assessment of whether the estimated costs met the specifications.

To evaluate the reasonableness of the cost estimate, EP A planned to compare its

estimated costs to costs for similar installations at steam electric power plants. EPA sought costs for plants through the Steam Electric Survey but obtaine d only limited information. In some cases, cost estimates provided by plants included initial re search of the technologies, including

123 All plants incurring a compliance cost for FGD waste water are included in the pollutant loading calculations. For plants operating both wet and dry fly ash handling systems , each with the capacity to handle all ash produced at the plant, EPA calculated a pollutant loading but included no com pliance cost. For plants operating wet bottom ash handling systems that did not discharge bottom ash transpor t water in 2009, EPA assessed a compliance cost (see Chapter 8.5) but did not calculate a pollutant loading.Section 17- Evaluation of Cost and Pollutant Removal Estimates

17-5 evaluation of varying configurations and operating conditions, and therefore did not represent today’s expected costs to install the BAT system. For example, for anoxic/anaerobic biological treatment systems, a vendor for this technology indic ated that the design and cost basis for the technology has changed significantly since those early implementations, particularly for low flow (<25 gallons per minute (gpm)) systems, and therefore are not reflective of capital costs that would be incurred today.

In other cases, the systems installed and operated by the steam electric power plants did not match the Best Available Control Technology Econo mically Achievable (BAT) design used by EPA for the technology options (or there wasn’t enough documentation to determine whether the system matched the BAT design). For example, in s ome cases, EPA’s model design basis for ash handling exceeded the rates used in individual plant bid proposals. Therefore, EPA was unable to compare the reported costs to the model estimate s.

More generally, EPA compared summary statistics for co st model outputs to Steam Electric Survey responses for total capital, purchased equip ment, installation, buildings, and site preparation, as well as indirect costs such as engineer ing and construction expenses. EPA found

that labor costs sometimes varied because its cost mo del includes the use of in-house labor for operation and maintenance of the FGD wastewater treat ment system. Contracted labor rates may be significantly higher, leading to higher O&M costs. For example, early implementers of the anoxic/anaerobic biological treatment system typically hired a contractor to operate and maintain their treatment system, which may have led to higher O&M costs reported in the Steam Electric Survey compared to model estimates.

In certain cases, such as for evaporation treatment pr eceded by chemical precipitation and softening, there is only one plant in the United States t hat was operating this technology at the time the responses to the Steam Electric Survey were s ubmitted. The plant operating that system did not provide cost information to EPA in its responses to the Steam Electric Survey. Because

EPA was unable to collect cost data from the Steam Elec tric Survey, EPA relied on the cost data provided by the vendors. EPA notes that cost data were coll ected from two different vendors and

the vendors’ estimates were similar. As described in Se ction 6.3.5, EPA used the cost data from both vendors in developing the evaporation system costs.

17.5 R EFERENCES

1. ERG. 2012a. Eastern Research Group, Inc. Final Sampling Episode Report, Duke Energy

Carolinas’ Belews Creek Steam Station . (13 March). DCN SE01305.

2. ERG. 2012b. Eastern Research Group, Inc. Sampling Episode Report, Allegheny Energy’s Hatfield’s Ferry Power Station . (13 March). DCN SE01310.

3. ERG. 2012c. Eastern Research Group, Inc. Final Sampling Episode Report, Duke Energy

Miami Fort Station . (13 March). DCN SE01304.

4. ERG. 2012d. Eastern Research Group, Inc. Power Plant Moni toring Data Collected Under Clean Water Act Section 308 Authority (“CWA 308 Monito ring Data”). (30 May).

DCN SE01326.Section 17- Evaluation of Cost and Pollutant Removal Estimates

17-6 5. ERG. 2012e. Eastern Research Group, Inc. Sampling Episode Report, Duke Energy

Carolinas’ Belews Creek Steam Station . (13 March). DCN SE01305.

6. ERG. 2012f. Eastern Research Group, Inc. Sampling Episode Report, Duke Energy

Carolinas’ Allen Steam Station . (13 March). DCN SE01307.

7. ERG. 2012g. Eastern Research Group, Inc. Sampling Episode Report, Mirant MidAtlantic, LLC’s Dickerson Generating Station. (13 March). DCN SE01308.

8. ERG. 2012h. Eastern Research Group, Inc. Sampling Episode Report, RRI Energy’s Keystone Generating Station . (13 March). DCN SE01309.

9. ERG. 2012i. Eastern Research Group, Inc. Sampling Episode Report, We Energies’

Pleasant Prairie Power Plant . (13 March). DCN SE01306.

10. ERG. 2012j. Eastern Research Group, Inc. Site Visit Notes and Final Sampling Episode Report, Enel Power Plants . (8 August). DCN SE02013.

11. ERG. 2015. Eastern Research Group, Inc. “Development Me morandum for the Steam Electric Analytical Database for the Final Rule.” (30 September). DCN SE05876.

12. U.S. EPA and TVA. 1981. U.S. Environmental Protection Agency and Tennessee Valley Authority. Economics of Ash Disposal at Coal-fired Power Plants . (October). DCN

SE02970.

13. U.S. EPA. 1985. U.S. Environmental Protection Agency. Full-Scale Field Evaluation of Waste Disposal from Coal-fired Electric Generating Plants . (August). DCN SE02971.

14. U.S. EPA. 2009. U.S. Environmental Protection Agency. Steam Electric Power Generating Point Source Category: Final Detailed Study Report . EPA 821-R-09-008. Washington, DC. (October). Available online at: http://water.epa.gov/lawsregs/guidance/cwa/304m/archive/upl oad/2009_10_26_guide_ste am_finalreport.pdf. DCN SE00003.Section 17- Evaluation of Cost and Pollutant Removal Estimates

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

Acceptance Criterion Description/Definition Specification

Currency ( U

p to D ate) Does the information reflect current

systems? Costs are current (e.g., 2000

- 2010).

Technology Does the information reported reflect an area relevant to the study? Costs reflect systems that serve as the technology basis for steam electric regulatory options.

Accuracy/Reliability Is the information reported true? Obtained from a power plant or a vendor who does business with steam electric power plants.

Comparability Are the costs comparable to costs provided by sources that meet these acceptance criteria? Comparable to other sources, su ch as the Steam Electric Survey.

Source: QAPP Table 2-3.

Table 17-2. Monitoring Data Acceptance Criteria

Type of Data Data Usable to Demonstrate System Performance/Efficiency Data Usable to Estimate Baseline Discharges

Monitoring Data (e.g.,

National Pollutant Discharge Elimination System (NPDES) permit, Discharge Monitoring Reports (DMRs)) 1. Represent full

- scale system operated at applicable steam electric power plant.

2. Influent and effluent data or percent

removal identified.

3. Analytes identified and units included. Identified as discharge, analytes identified and units provided, approved analytical method used,
represent current treatment operations.Section 17- Evaluation of Cost and Pollutant Removal Estimates

17-8 Table 17-3. Cost Estimate Quality Specifications

Acceptance

Criterion:

Cost Estimates Specification Comparison of

Cost Estimate to the Specification

Meet Requirements

for Economic Analysis • Include one

- time costs for equipment purchase and

installation.

• Include one-time costs for treatability and optimizat ion studies, as appropriate.

• Include ongoing O&M costs (annual costs).

• Include periodic O&M costs, as appropriate. • True

• True

• True

• True

Appropriate for

Actual Plant

Locations • Equipment costs, including transportation and installation, reflect the costs for supplies and labor at steam electric power plant locations.

• Operating costs (electricity, diesel fuel, labor, chem icals, etc.) reflect the costs at steam electric power plant

locations. • True

• True

Unit C osts are on Specified, Standard

Year Basis • Input costs escalated to 2010, using R.S. Means

Construction Index or other standard cost index. • True

Complete • Include costs for all elements necessary to implemen t the waste management option. • Reflects EPA’s current understanding.

Accurate ( M odel Input) • Model inputs reflect design assumptions agreed on with project team.

• Model inputs reflect baseline conditions at each plant. • True

• Reflects EPA’s current understanding based on Steam Electric Survey

responses.

Accurate (Calculations) • Model calculations are correct.

• Unit conversions are correct. • True

• True

Reasonable • Order of magnitude of costs is comparable to costs for similar installations at similar plants.

• Cost trends follow the design basis trends (i.e., costs for large plants are greater than the costs for small plant s). • See discussion above

.

• True