United States Office of Water Environmental Protection Washington, DC 20460 April 2013 Agency 

# Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source CategoryAppendix

Table of Contents

Page

C HAPTER 1 I NTRODUCTION ........................................................................................................... 1-1

C HAPTER 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

C HAPTER 3 D ATA S OURCES .......................................................................................................... 3-1 3.1 Steam Electric Technical Ques tionnaire Database ................................................... 3-1 3.1.1 Industry Factors ................................................................................................... 3-1 3.1.2 Plant Characteristics............................................................................................. 3-2 3.1.3 Ash Transport Water Loadings ............................................................................ 3-2 3.1.4 FGD Wastewater Loadings .................................................................................. 3-2 3.1.5 Combustion Residual Landfill Leachate Loadings .............................................. 3-2 3.2 Technology Vendor Data .......................................................................................... 3-3 3.3 Field Sampling Program ........................................................................................... 3-3 3.4 EPA Detailed Study Ash Surface Impoundment Sampling Data ............................. 3-4 3.5 Industry- and State-Submitted Monitoring Data ...................................................... 3-5 3.6 Electric Power Research Institut e (EPRI) PISCES Reports ..................................... 3-5 3.7 Permit Application Data ........................................................................................... 3-6 3.8 EPA 1982 Technical Development Document ......................................................... 3-6 3.9 Protection of Confidential Business Information ..................................................... 3-7 3.10 References ................................................................................................................. 3- 9

C HAPTER 4 D EVELOPMENT OF M ODEL I NPUTS ............................................................................. 4-1 4.1 Wastestream Population and Flow Ba sis for Pollutant Loadings ............................. 4-1 4.1.1 FGD Wastewater .................................................................................................. 4-1 4.1.2 Fly Ash and Bottom Ash Transport Water .......................................................... 4-3 4.1.3 Leachate ............................................................................................................... 4-5 4.2 Wastestream Population and Char acteristics for Costing ......................................... 4-7 4.2.1 FGD Wastewater .................................................................................................. 4-7 4.2.2 Fly Ash ................................................................................................................. 4-7 4.2.3 Bottom Ash ........................................................................................................ 4-10 4.2.4 Leachate ............................................................................................................. 4-11 4.3 Pollutant Concentrations ......................................................................................... 4-11 4.4 Plant Characteristics ............................................................................................... 4-12 4.4.1 Retirements and Conversions ............................................................................ 4-12 4.4.2 FGD Treatment-in-Place Input .......................................................................... 4-13 4.4.3 High Flow FGD Treatment Systems .................................................................. 4-13 4.5 Combustion Residual Disposal ............................................................................... 4-15Table of Contents
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iii 4.5.1 Combustion Residual Landfills.......................................................................... 4-15 4.5.2 Combustion Residual Surf ace Impoundments ................................................... 4-15

C HAPTER 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 ................................................................................... 5-3 5.2.3 O&M Cost Methodology ..................................................................................... 5-3 5.2.3.1 Sampling Labor Cost .................................................................................. 5-4 5.2.3.2 Sampling Material Cost .............................................................................. 5-5 5.2.3.3 Sample Shipping Cost ................................................................................ 5-6 5.2.3.4 Sample Analysis Cost ................................................................................. 5-6 5.3 Transportation Cost Methodology ............................................................................ 5-7 5.3.1 Technology Description ....................................................................................... 5-7 5.3.2 Cost Inputs ........................................................................................................... 5-8 5.3.3 Cost Methodology ................................................................................................ 5-8 5.3.3.1 On-Site Transportation Cost Methodology ................................................ 5-8 5.3.3.2 Off-Site Transportation Cost Methodology ............................................... 5-9 5.4 Disposal Cost Methodology ................................................................................... 5-10 5.4.1 Technology Description ..................................................................................... 5-10 5.4.2 Cost Inputs ......................................................................................................... 5-10 5.4.3 Cost Methodology .............................................................................................. 5-10 5.4.3.1 On-Site Disposal Cost Methodology ........................................................ 5-10 5.4.3.2 Off-Site Disposal Co st Methodology ....................................................... 5-12 5.5 Surface Impoundment Operati on Costs Methodology ........................................... 5-12 5.5.1 Technology Description ..................................................................................... 5-13 5.5.2 Input Table ......................................................................................................... 5-13 5.5.3 Cost Methodology .............................................................................................. 5-14 5.5.3.1 Impoundment O&M Costs ....................................................................... 5-14 5.5.3.2 Impoundment Unitized O&M Costs ........................................................ 5-18 5.5.3.3 Earthmoving Unitized O&M Costs .......................................................... 5-19 5.5.3.4 Impoundment and Earthmoving Capacity Factors ................................... 5-21 5.5.3.5 Surface Impoundment Earthm oving Recurring Costs ............................. 5-21 5.6 Surface Impoundment BMP Costs Methodology ................................................... 5-21 5.6.1 Results and Summary of Costs .......................................................................... 5-22 5.7 References ............................................................................................................... 5-22

C HAPTER 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 Place ......................................... 6-3 6.1.4 Input Table ........................................................................................................... 6-6 6.1.5 Key Variables Used in the Capital and O&M Cost Methodologies .................... 6-6Table of Contents
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iv 6.1.6 Capital Cost Methodology ................................................................................... 6-7 6.1.6.1 Purchased Equipment Costs: Pumps .......................................................... 6-9 6.1.6.2 Purchased Equipment Costs: Tanks ......................................................... 6-14 6.1.6.3 Purchased Equipment Costs: Chemical Feed Systems ............................ 6-33 6.1.6.4 Purchased Equipment Costs: Mixers ........................................................ 6-43 6.1.6.5 Purchased Equipment Costs: Soli ds Contact Clarifiers ........................... 6-51 6.1.6.6 Purchased Equipment Costs: Filter Presses ............................................. 6-54 6.1.6.7 Purchased Equipment Costs: Gravity Sand Filters .................................. 6-56 6.1.6.8 Purchased Equipment Installation Cost .................................................... 6-60 6.1.6.9 Building Cost ............................................................................................ 6-60 6.1.6.10 Land Cost ................................................................................................. 6-61 6.1.6.11 Site Preparation Cost ................................................................................ 6-61 6.1.6.12 Engineering Cost ...................................................................................... 6-62 6.1.6.13 Construction Expenses ............................................................................. 6-62 6.1.6.14 Other Contractors’ Fees ........................................................................... 6-63 6.1.6.15 Contingency Fees ..................................................................................... 6-63 6.1.7 O&M Cost Methodology ................................................................................... 6-64 6.1.7.1 Operating Labor Cost ............................................................................... 6-64 6.1.7.2 Maintenance Labor Cost .......................................................................... 6-64 6.1.7.3 Maintenance Materials Cost ..................................................................... 6-65 6.1.7.4 Chemical Purchase Cost ........................................................................... 6-66 6.1.7.5 Energy Cost .............................................................................................. 6-71 6.1.8 Sludge Disposal Cost ......................................................................................... 6-82 6.1.9 Mercury Analyzer Co st Methodology ............................................................... 6-83 6.1.9.1 Technology Description ........................................................................... 6-84 6.1.9.2 Population Costed .................................................................................... 6-84 6.1.9.3 Capital Cost Methodology ....................................................................... 6-84 6.1.9.4 O&M Cost Methodology ......................................................................... 6-86 6.1.9.5 Recurring Cost Methodology ................................................................... 6-87 6.1.10 Compliance Monitoring Cost ............................................................................. 6-87 6.1.11 Impoundment Operation Cost ............................................................................ 6-87 6.1.12 FGD System Outage Costs ................................................................................ 6-87 6.1.13 Results and Summary of Costs .......................................................................... 6-88 6.2 Biological Treatment .............................................................................................. 6-88 6.2.1 Technology Description ..................................................................................... 6-88 6.2.2 Population Costed .............................................................................................. 6-90 6.2.3 Credit for Biological Treatment in Place ........................................................... 6-90 6.2.4 Input Table ......................................................................................................... 6-91 6.2.5 Capital Cost Methodology ................................................................................. 6-91 6.2.5.1 Purchased Equipment Costs: Biological Treatment System Cost ............ 6-92 6.2.5.2 Purchased Equipment Costs: Heat Exchanger Cost ................................. 6-93 6.2.5.3 Purchased Equipment Costs: Back wash Recycle Pumps Cost ................ 6-96 6.2.5.4 Purchased Equipment Installation Cost .................................................... 6-96 6.2.5.5 Plant Overhead Engineering Cost ............................................................ 6-98Table of Contents
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v 6.2.6 O&M Cost Methodology ................................................................................... 6-99 6.2.6.1 Operating Labor Cost ............................................................................... 6-99 6.2.6.2 Maintenance Labor Cost ........................................................................ 6-100 6.2.6.3 Maintenance Materials Cost ................................................................... 6-100 6.2.6.4 Chemical Purchase Cost ......................................................................... 6-100 6.2.6.5 Energy Cost ............................................................................................ 6-101 6.2.7 Sludge Disposal Cost ....................................................................................... 6-104 6.2.8 Mercury Analyzer Cost .................................................................................... 6-104 6.2.9 Compliance Monitoring Cost ........................................................................... 6-104 6.2.10 Surface Impoundment Operation Cost ............................................................. 6-104 6.2.11 FGD System Outage Costs .............................................................................. 6-104 6.2.12 Results and Summary of Costs ........................................................................ 6-105 6.3 Vapor-Compression Evaporation ......................................................................... 6-105 6.3.1 Technology Description ................................................................................... 6-105 6.3.2 Population Costed ............................................................................................ 6-106 6.3.3 Credit for Vapor-Compression Evaporation Treatment in Place ..................... 6-107 6.3.4 Input Table ....................................................................................................... 6-107 6.3.5 Capital Cost Methodology ............................................................................... 6-107 6.3.5.1 Purchased Equipment Costs: Brine Con centrator and Crystallizer Cost 6-108 6.3.5.2 Purchased Equipment Costs: Softening Equipment Cost ...................... 6-108 6.3.5.3 Purchased Equipment Installation Cost .................................................. 6-108 6.3.6 O&M Cost Methodology ................................................................................. 6-109 6.3.6.1 Operating Labor Cost ............................................................................. 6-109 6.3.6.2 Maintenance Labor Cost ........................................................................ 6-110 6.3.6.3 Maintenance Materials Cost ................................................................... 6-110 6.3.6.4 Chemical Purchase Cost ......................................................................... 6-110 6.3.6.5 Energy Cost ............................................................................................ 6-111 6.3.7 Sludge Disposal Cost ....................................................................................... 6-112 6.3.8 Mercury Analyzer Cost .................................................................................... 6-113 6.3.9 Compliance Monitoring Cost ........................................................................... 6-113 6.3.10 Surface Impoundment Operation Cost ............................................................. 6-113 6.3.11 FGD System Outage Costs .............................................................................. 6-113 6.3.12 Results and Summary of Costs ........................................................................ 6-114 6.4 References ............................................................................................................. 6-114

C HAPTER 7 F LY A SH T RANSPORT W ATER 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 .................................... 7-4 7.1.4 Input Table ........................................................................................................... 7-4 7.1.5 Capital Cost Methodology ................................................................................... 7-6 7.1.5.1 Purchased Equipment Costs: Conveyance Equipment ............................... 7-7 7.1.5.2 Purchased Equipment Cost: Silo ................................................................ 7-8Table of Contents
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vi 7.1.5.3 Purchased Equipment Cost: Pugmill ........................................................ 7-11 7.1.5.4 Purchased Equipment Installation Cost .................................................... 7-12 7.1.5.5 Engineering Costs .................................................................................... 7-14 7.1.6 O&M Cost Methodology ................................................................................... 7-16 7.1.6.1 Conveyance O&M Costs: Operating Labor ............................................. 7-16 7.1.6.2 Conveyance O&M Costs: Maintenance Labor ........................................ 7-17 7.1.6.3 Conveyance O&M Costs: Energy Cost .................................................... 7-18 7.1.6.4 Conveyance O&M Costs: Main tenance Materials ................................... 7-20 7.1.6.5 Conveyance O&M Costs: Maintenance Outage ...................................... 7-21 7.1.6.6 Storage O&M Costs: Operating Labor ..................................................... 7-21 7.1.6.7 Storage O&M Costs: Maintenance Labor ................................................ 7-23 7.1.6.8 Storage O&M Costs: Energy Cost ........................................................... 7-23 7.1.6.9 Storage O&M Costs: Main tenance Materials .......................................... 7-25 7.1.7 Fly Ash Disposal Cost ....................................................................................... 7-26 7.1.8 Impoundment Operation Costs .......................................................................... 7-27 7.1.9 Recurring Costs .................................................................................................. 7-27 7.1.10 Fly Ash Outage Costs ........................................................................................ 7-30 7.1.11 Results and Summary of Costs .......................................................................... 7-30 7.2 Vactor Truck Collection ......................................................................................... 7-30 7.2.1 Technology Description ..................................................................................... 7-30 7.2.2 Population Costed .............................................................................................. 7-30 7.2.3 Input Table ......................................................................................................... 7-31 7.2.4 Capital Cost Methodology ................................................................................. 7-31 7.2.4.1 Total Capital Cost: Vactor Conveyance Equipment ................................ 7-31 7.2.4.2 Total Capital Cost: Vactor Engineering Costs ......................................... 7-31 7.2.5 O&M Cost Methodology ................................................................................... 7-32 7.2.5.1 Total O&M Costs: Vactor Conveyance O&M Cost ................................ 7-33 7.2.5.2 Total O&M Costs: Vactor Storage O&M Cost ........................................ 7-33 7.2.6 Fly Ash Disposal Cost ....................................................................................... 7-34 7.2.7 Impoundment Operation Costs .......................................................................... 7-34 7.2.8 Fly Ash Outage Costs ........................................................................................ 7-35 7.2.9 Results and Summary of Costs .......................................................................... 7-35 7.3 References ............................................................................................................... 7-35

C HAPTER 8 B OTTOM A SH T RANSPORT W ATER 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 ...................... 8-4 8.1.4.2 MDS Engineering Cost .............................................................................. 8-5 8.1.5 O&M Cost Methodology ..................................................................................... 8-6 8.1.5.1 MDS Conveyance O&M Costs: Operating Labor ..................................... 8-6 8.1.5.2 MDS Conveyance O&M Costs: Maintenance Labor ................................. 8-7Table of Contents
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vii 8.1.5.3 MDS Conveyance O&M Costs: Energy Cost ............................................ 8-8 8.1.5.4 MDS Conveyance O&M Costs: Ma intenance Materials ......................... 8-10 8.1.5.5 MDS Storage O&M Cost: Operating Labor ............................................ 8-11 8.1.5.6 MDS Storage O&M Costs: Maintenance Labor ...................................... 8-11 8.1.5.7 MDS Storage O&M Costs: Energy Cost .................................................. 8-12 8.1.5.8 MDS Storage O&M Costs: Maintenance Materials ................................. 8-13 8.1.5.9 Wet Sluicing O&M Costs: Operating Labor ............................................ 8-14 8.1.5.10 Wet Sluicing O&M Costs: Maintenance Labor ....................................... 8-15 8.1.5.11 Wet Sluicing O&M Costs: Energy Cost .................................................. 8-16 8.1.5.12 Wet Sluicing O&M Costs: Maintenance Materials .................................. 8-18 8.1.6 MDS Results ...................................................................................................... 8-18 8.2 Remote Mechanical Drag System .......................................................................... 8-18 8.2.1 Technology Description ..................................................................................... 8-18 8.2.2 Population Costed .............................................................................................. 8-19 8.2.3 Input Table ......................................................................................................... 8-20 8.2.4 Capital Cost Methodology ................................................................................. 8-20 8.2.4.1 Remote MDS Purchased Equipment Cost: Conveyance Equipment ....... 8-20 8.2.4.2 Remote MDS Purchase Equipment Cost: Recycle Pump ........................ 8-21 8.2.4.3 Remote MDS Purchased Equipment Cost: Chemical Feed System ........ 8-22 8.2.4.4 Remote MDS Purchase Equipm ent Installation Cost .............................. 8-24 8.2.4.5 Remote MDS Engineering Cost ............................................................... 8-24 8.2.5 O&M Cost Methodology ................................................................................... 8-25 8.2.5.1 Remote MDS Conveyance O&M Costs: Mechanical Drag System ........ 8-25 8.2.5.2 Remote MDS Conveyance O&M Costs: Chemical Purchase Cost ......... 8-25 8.2.5.3 Remote MDS Conveyance O&M Costs: Energy Cost ............................. 8-26 8.2.5.4 Remote MDS Storage O&M Costs .......................................................... 8-28 8.2.6 Remote MDS Results ......................................................................................... 8-29 8.3 Bottom Ash Disposal Cost ...................................................................................... 8-29 8.4 Impoundment Operation Costs ............................................................................... 8-30 8.5 One-Time Costs ...................................................................................................... 8-30 8.6 Bottom Ash Outage Costs ...................................................................................... 8-31 8.7 Recurring Costs ...................................................................................................... 8-31 8.8 Selection of Dry Bottom As h Handling Technology ............................................. 8-32 8.9 Results and Summary of Costs ............................................................................... 8-32 8.10 References ............................................................................................................... 8-33

C HAPTER 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 Treatment in Place .................................................................................................... 9-3 9.4 Input Table ................................................................................................................ 9- 3 9.5 Capital Cost Methodology ........................................................................................ 9-4 9.5.1 Purchased Equipment Costs: Le achate Transport Pump ..................................... 9-4 9.5.2 Purchased Equipment Costs: Le achate Transport Piping .................................... 9-5 9.6 O&M Cost Methodology .......................................................................................... 9-6Table of Contents
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viii 9.7 Mercury Analyzer Cost ............................................................................................. 9-7 9.8 Sludge Transportation and Disposal Costs ............................................................... 9-7 9.9 Compliance Monitoring Cost ................................................................................... 9-7 9.10 Surface Impoundment Operation Costs .................................................................... 9-7 9.11 Results and Summary of Costs ................................................................................. 9-7 9.12 References ................................................................................................................. 9- 8

C HAPTER 10 P OLLUTANT L OADINGS AND R EMOVALS M ETHODOLOGY ...................................... 10-1 10.1 General Methodology for Estimating Pollutant Removals ..................................... 10-2 10.2 Wastestream Characterizati on and Data Sources ................................................... 10-3 10.2.1 FGD Wastewater Characterization .................................................................... 10-4 10.2.1.1 Baseline FGD Wastewater Characterization ............................................ 10-5 10.2.1.2 Baseline and Post-Compliance On e-Stage Chemical Precipitation Characterization ..................................................................................... 10-10 10.2.1.3 Baseline and Post-Compliance One- Stage Chemical Precipitation and Biological Treatment Characterization .................................................. 10-11 10.2.1.4 Baseline and Post-Compliance One- Stage Chemical Precipitation and Vapor-Compression Evaporati on Characterization ............................... 10-12 10.2.2 Ash Impoundment Wastewater Characterization ............................................ 10-13 10.2.3 Combustion Residual Leachate Wast ewater Characterization ........................ 10-15 10.3 Wastewater Flow Rates for Pollutant Loadings ................................................... 10-16 10.3.1 FGD Wastewater Flow Rates fo r Pollutant Loadings ...................................... 10-16 10.3.2 Ash Transport Water Flow Rates for Pollutant Loadings ................................ 10-16 10.3.3 Combustion Residual Landfill Leachate Flow Rates for Pollutant Loadings.. 10-17 10.4 Baseline and Post-Complia nce Pollutant Loadings and TWPE Results .............. 10-17 10.4.1 FGD Wastewater Loadings and TWPE ........................................................... 10-18 10.4.2 Ash Transport Water Load ings and TWPE ..................................................... 10-19 10.4.3 Combustion Residual Landfill Leachate Loadings and TWPE ....................... 10-22 10.5 References ............................................................................................................. 10-22

C HAPTER 11 S UMMARY OF C OSTS AND P OLLUTANT R EMOVALS BY R EGULATORY O PTION ....... 11-1

C HAPTER 12 E VALUATION OF C OST AND P OLLUTANT R EMOVAL E STIMATES ............................ 12-1 12.1 Verifying Cost Data against acceptance Specifications ......................................... 12-1 12.2 Verifying Analytical Data agains t acceptance Specifications ................................ 12-2 12.3 Developing and Checking the Cost and Loadings Models ..................................... 12-3 12.4 Evaluating Cost Estimate Quality ........................................................................... 12-4 12.5 References ............................................................................................................... 12-5

A PPENDIX

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

List of Tables

Page 1-1. Technology Cost Modules Used to Estim ate Compliance Costs for All Regulatory Options ....................................................................................................................... ...... 1-2 2-1. Technology Cost Modules Used to Estimate Compliance Costs ......................................... 2-7 2-2. Technology Cost Modules Used to Estimate Compliance Costs by Regulatory Option ........................................................................................................................ ...... 2-8 5-1. Compliance Monitoring Labor Requirements .................................................................... 5-24 5-2. Compliance Monitoring Sampling Materials ..................................................................... 5-24 5-3. Compliance Monitoring Sample Analysis .......................................................................... 5-25 5-4. Capital Costs of 7-Acre Landf ill Expansion from CH2MHILL ......................................... 5-25
5-5. O&M Costs of 7-Acre Landfil l Expansion from CH2MHILL ........................................... 5-25 5-6. Revised Modular Annual Revenue Require ments by Process Area for Direct Ponding of Nonhardening Ash without Water Reuse .................................................................. 5-26
5-7. Calculated Unitized Cost Values for Impoundment Operating Costs ................................ 5-26
5-8. Cost Factors Relative to 500 MW Plant ............................................................................. 5-27 6-1. Expected FGD Wastewater Characteristic s for Design of the Biological Treatment Stage ......................................................................................................................... .... 6-122
10-1. POTW Removals ........................................................................................................... . 10-25 10-2. Data Sets Used in the Loadings Calculations ................................................................. 10-26 10-3. Average Effluent Concentrati on of FGD Surface Impoundments ................................. 10-27
10-4. Characteristics of FGD Blowdown at EPRI Sites P, R, and S ....................................... 10-28
10-5. Characteristics of FGD Blowdown at EPRI Sites T, U, and Y ...................................... 10-30 10-6. Average Effluent Concentration of One- Stage Chemical Precipitation System ............ 10-32 10-7. Average Effluent Concentration of One- Stage Chemical Precipitation System With Biological Treatment ................................................................................................... 10-33 10-8. Average Effluent Concentration of One- Stage Chemical Precipitation System With Vapor-Compression Evaporation ................................................................................. 10-34 10-9. Average Effluent Concentration of Ash Surface Impoundment Systems ...................... 10-35 10-10. Average Untreated Landfill L eachate Concentrations ................................................. 10-36 10-11. Industry-Level FGD Wastewater Loadings for All Units ............................................ 10-37 10-12. Industry-Level FGD Wastew ater Loadings Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis ............................................................. 10-37
10-13. FGD Wastewater Pollutant Removals for All Units .................................................... 10-38List of Tables
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x 10-14. FGD Wastewater Pollutant Removals Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis ..................................................................... 10-38 10-15. Percent Loadings for Fly Ash and Bottom Ash in Combined Ash Surface Impoundments .............................................................................................................. 10- 39 10-16. Industry-Level Baseline Ash Impoundment Loadings by Type of Impoundment ....... 10-39 10-17. Fly Ash and Bottom Ash Pollutant Removals for All Units ........................................ 10-40 10-18. Fly Ash and Bottom Ash Pollutant Remova ls Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis ........................................................ 10-40 10-19. Industry-Level Combustion Residual Landfill Leachate Loadings for All Units ........ 10-4010-20. Industry-Level Combustion Residual Landfill Leachate Loadings Based on OilFired Units and Units 50 MW or Le ss Not Installing Technology Basis .................... 10-40
10-21. Combustion Residual Leachate Loadi ngs Removals for All Units .............................. 10-41 10-22. Combustion Residual Leachate Loadings Removals Based on Oil-Fired Units and Units 50 MW or Less Not Inst alling Technology Basis .............................................. 10-41 11-1. Treatment Technologies Basis by Regulatory Option ...................................................... 11-2 11-2. Cost of Implementation by Regulatory Option for All Units ........................................... 11-3 11-3. Cost of Implementation by Regulatory Option Based on Oil-Fired Units and Units 50MW or Less Not Installing Technology Basis ........................................................... 11-3 11-4. Estimated Pollutant Removals by Regulatory Option for All Units ................................ 11-3 11-5. Estimated Pollutant Removals by Regul atory Option Based on Oil-Fired Units and Units 50 MW or Less Not Inst alling Technology Basis ................................................ 11-4 12-1. Pollution Control Technology Cost Data Acceptance Criteria ........................................ 12-7 12-2. Monitoring Data Acceptance Criteria............................................................................... 12-7 12-3. Evaluation of Monitoring Data fo r Use in Loadings Analysis ......................................... 12-8 12-4. Cost Estimate Quality Specifications ............................................................................... 12-9List of Figures

xi List of Figures

Page 2-1. Steam Electric Cost Model Flow Ch art for FGD Wastewater and Combustion Residual Leachate ............................................................................................................ 2-5
2-2. Steam Electric Cost Model Flow Chart for Fly Ash and Bottom Ash Transport Water ...... 2-6 6-1. One-Stage Chemical Pr ecipitation Treatment .................................................................. 6-115 6-2. Solubilities of Metal Hydroxides and Sulfides as a Function of pH ................................ 6-116 6-3. Two-Stage Biological Treatment System (System to follow Chemical Precipitation Pretreatment) ................................................................................................................ 6-117 6-4. Mean Maximum Daily Te mperature for July ................................................................... 6-118 6-5. Location of Plants Incurring Heat Exchanger Costs ........................................................ 6-119 6-6. Chemical Precipitation and Softening Pr etreatment for FGD Wastewater Prior to Vapor-Compression Evaporation ................................................................................. 6-120 6-7. Process Flow Diagram for a Vapor-Com pression Evaporation System (System to Follow Chemical Precipitation Pretreatment) .............................................................. 6-121 8-1. Mechanical Drag System ................................................................................................... ... 8-2 8-2. Remote Mechanical Drag System ...................................................................................... 8-19Chapter 1 – Introduction

1-1 

## CHAPTER 1 INTRODUCTION

The Clean Water Act (CWA) establishes a structure for regulating discharges of pollutants to surface waters of the United States . As part of the implementation of the CWA, EPA issues effluent limitations guidelines and st andards (ELGs) for industrial dischargers. EPA first issued ELGs for the Steam Electric Power Generating Point Source Category in 1974 with subsequent revisions in 1977 and 1982. EPA completed a detaile d study of the industry in 2009 and determined that the current regulations have not kept pace with the significant changes that have occurred in this industry over the last thr ee decades; therefore, EPA is revising the existing ELGs.
This report describes the methodologies used to estimate engineer ing compliance costs (in 2010 dollars) associated with installing and op erating the various tech nologies and practices that make up the regulatory options considered by EPA. In addition, this report presents the methodologies used to estimate baseline and post-compliance pollutant loadings and the corresponding pollutant removals associated with installing and operating these technologies and practices. In addition to this report, EPA has assembled a supplementary document titled Supplemental Costs and Loadings Documentation (DCN SE01825). This document, which can be found in the Steam Electric Rulemaking Recor d, includes the following detailed information:

 Spreadsheets documenting development of inpu t tables, cost factors, chemical dosage rates, and other cost elements;

 Detailed cost information provided by vendors (including in telephone contact reports);

 Equipment specifications pr ovided by vendors; and

 Calculations performed using the cost information, includ ing the generation of cost

curves.
Table 1-1 lists the regulatory options EPA considered for th e steam electric industry to control pollutant discharges from the follo wing wastestreams generated by power plants:

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

 Fly ash transport water from we t fly ash handling systems;

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

 Leachate from landfills and surface impoundme nts containing combustion residuals; 1

 Flue gas mercury control wastewater generated from activated carbon injection mercury control systems;

 Gasification wastewater ge nerated from integrated-gasification combined cycle (IGCC) power plants; and

1 EPA did not calculate compliance cost s to treat leachate generated from impoundm ents containing combustion residuals because EPA believes that plants will comply with the l eachate limit by recycling the leac hate back to the impoundment from which it was generated.Chapter 1 – Introduction

1-2  Nonchemical metal cleaning wastes generatd from cleaning metal process equipment without chemical cleaning compounds.

Table 1-1. Technology Cost Modules Used to Es timate Compliance Costs for All Regulatory Options

Wastestream Technology Option Regulatory Option Report Chapter a 1 3a 2 3b 3 4a 4 5

FGD Wastewater Chemical Precipitation X X X X X X X

6,10 Biological Treatment X X X X X Vapor-Compression Evaporation X Fly Ash Transport Water Dry Fly Ash Handling X X X X X 7,10

Bottom Ash Transport Water Dry Bottom Ash Handling/Closed Loop X X X 8,10
Leachate Chemical Precipitation X X 9,10
Gasification Wastewater Vapor-Compression Evaporation X X X X X X X NA
Flue Gas Mercury Control Wastes Dry Handling X X X X X NA

Nonchemical Metal Cleaning Wastes b Chemical Precipitation NA

Other Plant-Level Costs Solids Transportation X X X X X X X X 5 Solids Disposal X X X X X X X X 5 Impoundments X X X X X X X X 5 Compliance Monitoring X X X X X X X X 5 NA – Not applicable. EPA did not estimate compliance cost s for these wastestreams for reasons described in Section 9.2 of the Technical Development Docume nt for the Proposed Efflu ent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (DCN SE01964).

a Chapters 5-9 of this document include more detailed descriptions of the cost methodologies for these technology options and Chapter 10 provides a more detailed desc ription of the estimated pollutant removals for each technology.

For five of the regulatory options (Options 1, 2, 3, 4, and 5), EPA estimated plant-specific compliance costs for each of the individual trea tment technologies that comprise the regulatory options using the methodology descri bed in this report. These tec hnology-specific costs, broken down into capital and operating and maintenanc e (O&M) (i.e., annual, 3- year, 5-year, 6-year, and 10-year) costs, were then summed as appropr iate to estimate plant-specific costs for each regulatory option. All costs were calculated in 2010 dollars, the baseline year for this rulemaking. Note that the compliance costs calc ulated for this rulemaking are incremental, meaning they represent the costs expected to be incurred as a result of plants revising existing operations to match those that form the bases of the proposed regulatory options.
For the same five options, EPA also estim ated plant-specific baseline and postcompliance pollutant loadings associated with ea ch of the individual treatment technologies thatChapter 1 – Introduction

1-3 comprise the regulatory options, and then summed them as appropriate to calculate industrylevel baseline and post-compliance pollutant load ings for each of the five regulatory options. EPA then estimated the pollutant removals a ssociated with the five regulatory options by subtracting the post-compliance pol lutant loadings from the base line pollutant loadings. Note that these pollutant removal estimates are incr emental, meaning they represent the pollutant removals expected to be achieved as a result of plants revising existing operations to match those that form the bases of the proposed regulatory options.
EPA then used the cost and pollutant removal model outputs for Options 1, 2, 3, 4, and 5 to estimate the costs and pollutant removals fo r Options 3a, 3b, and 4a. The methodologies EPA used to generate the costs and pollutant removals for Options 3a and 3b are described in the memorandum entitled, “Memorandum to the Rule making Record: Methodologies for Estiamting Costs and Pollutant Removals for Steam Electri c ELG Regulatory Optio ns 3a and 3b” (DCN SE03881). The methodologies EPA used to generate the costs and pollutant removals for Option 4a are described in the memorandum entitle d, “Memorandum to the Rulemaking Record: Methodologies for Estimating Cost s and Pollutant Removals for Steam Electric ELG Regulatory Option 4a” (DCN SE03834). The remainder of this report describes the costs and pollutant removals as they relate to the individu al wastestreams or Options 1, 2, 3, 4, and 5.
The following information is described in this report:

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

 Chapter 3 discusses the data sources used to generate the costs, loadings, and pollutant removal estimates;

 Chapter 4 discusses the costs and loadings models inputs;

 Chapter 5 describes the general cost met hodology used to estimate compliance costs and common cost elements;

 Chapter 6 describes the cost met hodology for treating FGD wastewater;

 Chapter 7 describes the cost methodology fo r eliminating the discharge of fly ash transport water;

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

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

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

 Chapter 11 summarizes costs and pollutant loadings and remo vals by regulatory option; and

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

2-1 

## CHAPTER 2 STRUCTURE OF COSTS AND POLLUTANT LOADINGS MODELS

EPA created two separate models associated with the regulatory op tions for the proposed Steam Electric effluent limitations guidelines and standards (ELGs). The first model calculates plant-specific engineering compliance costs fo r each technology option associated with the regulatory options. The second model calculates plant-specific baseline pollutant discharge loadings for each wastestream evaluated, as we ll as post-compliance pollutant loadings and removals for each technology option for each wast estream. This chapter describes the structure of each of these models. All tables and figures refe renced in this chapter are presented at the end of the chapter.

2.1 C OST M ODEL
To generate industry incremental complian ce cost estimates for the steam electric industry, EPA developed a computer-based cost model made up of several individual technology cost modules. The cost model is executed on a personal computer and co mprises a collection of programs written in Visual Basic® and data ta bles created in Micros oft® Access 2007. Figure 2-1 and Figure 2-2, located at the end of this chapter, present fl ow diagram of the cost model. The cost model can be grouped into four main components:

 Plant-Specific Input Data;

 Industry Assumptions/Factors;

 Technology Cost Modules; and

 Model Outputs.
Technology cost modules use the relevant input data and industry assumptions/factors to calculate plant-specific incremental complian ce costs. Each technology cost module calculates costs for a specific cost component (e.g., transp ortation, disposal, ash silo cost, chemical precipitation system cost, etc.) for each plant. These individual cost components are then summed on a plant level to calcu late an overall compliance cost for each plant for a specific technology option. Table 2-1 lists the technology cost modules and their use in calculating overall incremental compliance costs for each technology option. Table 2-2 shows how the individual technology cost modules are combin ed for each of the five regulatory options considered by EPA. Both tables are presented at the end of the chapter.

2.1.1 Input Data to Cost Model
The cost model operates on one main input tabl e, called the cost matrix. The cost matrix identifies which technology options apply to each plant. For example, if Plant X discharges fly ash transport water and untreat ed flue gas desulfurization (FGD) wastewater, but does not discharge bottom ash transport or combustion re sidual leachate, then the cost matrix would indicate that this plant require s fly ash and FGD compliance cost s, but does not require bottom ash or leachate compliance costs.Chapter 2 – Structure of Costs and Pollutant Loadings Models

2-2 Other plant-specific input data to the cost model includes the following:

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

 Fly ash data – amount of wet fly ash gene rated, amount of transport water generated, number of operating days, and capacity on a steam electric generating unit level;

 Bottom ash data – amount of wet bottom as h generated, amount of transport water generated, number of operat ing days, and capacity on a steam electric generating unit level;

 Landfill data – plant-level indication that an on-site combustion residual landfill is present and whether leachate is collected and/or treated;

 Surface impoundment data – plant-level indication that a combustion residual impoundment is present and whether leachat e is collected and/or treated; and

 Treatment-in-place data – plant-specific da ta for plants alread y operating relevant treatment systems, such as chemical pr ecipitation, biological treatment, and vaporcompression evaporation, including the t ype of equipment at the plant and its capacity.
Chapter 4 discusses inputs to th e cost model in greater detail.

2.1.2 Industry Assumptions/Factors
Industry assumptions and factor s are applicable to the enti re industry and are not plant specific. Each technology cost m odule has an individual set of assumptions/factors tables. These tables hold the constants and coefficients that the technology cost modul es use to calculate capital and operating and mainte nance (O&M) costs associated with each cost component. In addition, the following industry assumptions/factor s data sets are used by multiple technology cost modules:

 Cost indices – cost index values from RS Means used to in dex all costs to 2010 dollars; and

 Freight costs –equipment- level shipping costs.
The industry assumptions/factors used by th e technology cost modules are identified within the capital and O&M cost equations in each technology cost module, as described in Chapter 5.

2.1.3 Technology Cost Modules
EPA developed the technology cost modules to calculate specific cost components, as listed below:

 Biological Treatment – calculates capita l and O&M costs associated with an anoxic/anaerobic biological treatment system;Chapter 2 – Structure of Costs and Pollutant Loadings Models

2-3  One-Stage Chemical Precipitation – calculate s capital and O&M costs associated with the one-stage chemical preci pitation system used as the basis for the technology option;

 Vapor-Compression Evaporation – calculates capital and O& M costs associated with the vapor-compression evaporation system used as the basis for the technology option;

 Dry Fly Ash Handling – calculate s capital, O&M, and recurring costs associated with the dry fly ash handling system used as the basis for the technology option;

 Dry Bottom Ash Handling – calculates capit al, O&M, one-time, and recurring costs associated with a dry or closed-loop recycl e bottom ash handling systems used as the basis for the technology option;

 Transportation – calculates O&M costs associ ated with transporting FGD solid waste, ash, and/or landfill leachate solid wast e to an on- or off-site landfill;

 Disposal – calculates capital and O&M cost s associated with disposing of FGD, ash, and/or landfill leachate solid waste in an on- or off-site landfill;

 Impoundment Operation – calculates O&M a nd recurring costs associated with operating and maintaining an on-site impoundment; and

 Impoundment BMP Costs – calculates the annu alized costs associated with BMP for combustion residual impoundments.
For each regulatory option, the cost model combines the plant-level outputs from a series of technology cost modules. Table 2-1 shows the various technology co st modules that are combined to calculate the techno logy option costs. The cost m odel uses Microsoft® Access 2007 queries to combine the cost components and calc ulate a total capital and O&M cost for each technology option. Table 2-2 lists the technology cost modules used to calculate the postcompliance cost for each regulatory option.

2.1.4 Model Outputs
The cost model output is a plant-level su mmary of the incremental technology option compliance costs. Each plant incurring a cost fo r a specified technology is presented in the model output. The incremental compliance costs are presen ted 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 te chnology option. The component-level costs provide more detail showing a breakdown of the individual cost components for each of the technology cost modules. The component-level costs include individual capital costs (e.g., equipment, installation, land, engineering) and individual O&M co sts (e.g., labor, materials, compliance monitoring, chemicals). Plant-level cost model results are provided by technology option in the appendix (see Chapters 6, 7, 8 and 9 for more details) and by regulatory option in Chapter 11.

2.2 P OLLUTANT L OADINGS M ODEL
To calculate industry pollutant removals for the Steam Electric ELGs, EPA developed three databases in Microsoft® Access 2007 to ca lculate baseline and post-compliance pollutant loadings associated with the discharge of FGD wastewater, fly and botto m ash transport water,Chapter 2 – Structure of Costs and Pollutant Loadings Models

2-4 and combustion residual leachate, respectively. Each of the three databases contains the following components:

 Input table;

 Baseline concentration data sets;

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

 Output baseline and post-co mpliance pollutant loadings.
All three of the loadings databases were cons tructed in a similar fashion. The input tables hold plant-level data needed to calculate the baseline and pos t-compliance discharge loadings. The input tables for FGD, ash, and leachate are discussed in more detail in Sections 4.1.1, 4.1.2, and 4.1.3, respectively. The baseline and technology option concentr ation data sets consist of sampling data used to calculate the average po llutant concentrations for each wastewater evaluated with and without the control afforded by the proposed technolo gy options. Because the dry fly ash handling technology option and the dry/closed-loop recycle bottom ash handling technology options result in zero di scharge of fly ash and bottom ash transport water, the average technology option pollutant concentr ations for fly and bottom ash is zero. The average baseline and technology option pollutant con centrations, together with data from the input table, are used to calculate baseline and post-co mpliance pollutant loadings at a plant level. EPA calculates the baseline and post-compliance pollutant load ings in both pounds and toxic-weighted pound equivalents (TWPE). 2 See Chapter 10 for more detail on the loadings calculation methodology and results for each technology option.

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

One-Stage Chemical Precipitation Biological Treatment VaporCompression Evaporation Dry Fly Ash Handling Dry Bottom Ash Handling a Compliance Monitoring Transportation Disposal Surface Impoundment Operation CostsFGD Wastewater Treatment: Chemical PrecipitationFGD Wastewater Treatment: Chemical Precipitation + BiologicalTreatmentFGD Wastewater Treatment: Chemical Precipitation + EvaporationFly Ash: Zero dischargeBottom Ash: Zero dischargeLeachate Wastewater Treatment: Chemical PrecipitationLeachate Wastewater Treatment: Chemical Precipitation +Biological TreatmentNote: EPA did not estimate costs for gasification wastewater, flue gas mercury control wastewater, or nonchemical metal cleaning wastes.aThe technology cost module is called “Dry Bottom Ash Handling”module, but it includes a technology option that is a closed-loop recycle system.Chapter 2 – Structure of Costs and Pollutant Loadings Models2-8Table 2-2. Technology Cost Modules Used to Estimate Compliance Costs by Regulatory OptionWastestreamTechnology Cost Modules/Technology OptionRegulatory Option12345FGD WastewaterChemical PrecipitationBiological TreatmentVapor-Compression EvaporationFly Ash Transport WaterDry Fly Ash HandlingBottom Ash Transport WaterDry Bottom Ash HandlingaLeachateChemical PrecipitationGasification WastewaterbVapor-Compression EvaporationFlue Gas Mercury Control WastesbZero DischargeNonchemical Metal Cleaning WastebChemical PrecipitationOther Costs Not Specific to WastestreamSolids TransportationSolids DisposalImpoundmentsCompliance MonitoringNote: EPA did not estimate costs for gasification wastewater, flue gas mercury control wastewater, or nonchemical metal cleaning wastes.aThe technology cost module is called the “Dry Bottom Ash Handling” module, but it includes a technology option that is a closed-loop recycle system.bEPA did not estimate costs for gasification wastewater, flue gas mercury control wastewater, or nonchemical metal cleaning wastes; therefore, EPA did notcreate technology cost modules for theseswastestreams. However, these wastestreamsare still considered in the regulatory options and are therefore, presentedin the table with the appropriate technology option.Chapter 3 – Data Sources

3-1 

## CHAPTER 3 DATA SOURCES

EPA collected and evaluated data from a variet y of sources in the c ourse of developing the proposed Steam Electric effluent limitations guidelines and standa rds (ELGs). EPA used these data to develop the industr y profile, identify plant-specific operations, determine baseline and post-compliance wastewater characteristics, estimate compliance costs, estimate baseline and post-compliance pollutant loadings, and estim ate pollutant removals associated with the regulatory options. This chapter discusses the data sources used to estimate the compliance costs and pollutant loadings and removals estimates for the proposed Steam Electric ELGs. All tables and figures referenced in this chapter ar e presented at the end of the chapter.

3.1 S TEAM E LECTRIC T ECHNICAL Q UESTIONNAIRE D ATABASE
The principal source of information and data used in developing the ELGs is the industry response to the survey distributed by EPA under th e authority of section 308 of the Clean Water Act (CWA). EPA distributed the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey) to 733 power plants in the summer of 2010. The Steam Electric Survey obtained the following types of information from the steam electric industry:

 General power plant operations;

 Flue gas desulfurization (FGD) system operations;

 Ash handling operations;

 Pond/impoundment system and other wastewater treatment operations;

 Metal cleaning process operations;

 Pond/impoundment and landfill management practices;

 Pond/impoundment and landfill leachate sampling data; and

 Nuclear power operations.
ERG used the responses from the 733 plants to develop a database th at contained all the responses to the survey. For more information on the development of the Steam Electric Survey, see Section 3 of the Technical Development Document fo r the Proposed Effluent Limitations Guidelines and Standards for the Steam El ectric Power Generating Point Source Category (DCN SE01964). The remainder of this section de scribes the data used in the calculation of compliance costs and pollutant loadings estimates.

3.1.1 Industry Factors
EPA developed specific industry fa ctors to use in the cost equa tions detailed in Chapters 5, 6, 7, 8, and 9 based on evaluation and analysis of the Steam Elect ric Survey data. For example, many of the operating and maintena nce (O&M) labor rate s and hours per year used in the cost model were derived from rates and burdens reported in respons es to the survey. EPA also developed many of the direct and indirect capital cost factors used in the cost model from surveyChapter 3 – Data Sources

3-2 data (e.g., installation and engineering overhead cost factors). Other cost elements (e.g., equipment capacity factors, materials of cons truction, and chemical dosage rates and sludge generation rates for chemical precipitation) were derived from survey responses. The use of survey data to derive industry assumptions/fac tors is described with in the costing methodology in Chapters 5, 6, 7, 8, and 9 and documented in the Supplemental Costs and Loadings Documentation (DCN SE01825).

3.1.2 Plant Characteristics
The cost methodology uses certain plant-specific Steam Electric Survey data elements as cost model inputs for estimating plant-leve l compliance costs and generating unit-level compliance costs. Some examples include plan t-specific FGD wastewater flow rates, ash generation rates, type of generating unit, generating unit operating hours per day, and technologies currently in place. The specific plan t characteristic used to calculate compliance costs for each treatment technology are detailed in the input table sections of Chapters 6, 7, 8, and 9.

3.1.3 Ash Transport Water Loadings
EPA used responses to the Steam Electric Surv ey to identify the population of plants that operate wet fly and/or bottom ash handling syst ems and discharge the wastewater to surface water or a publicly-owned trea tment works (POTW). For this population of plants, EPA used survey responses to identify the flow rate of the fly ash and bottom ash transport water, determine whether the waters are combined for treatment, and calculate the amount of treated ash transport water that is recycled by the plan t. EPA also used Steam Electric Survey data to estimate fly ash and bottom ash transport water pollutant loadings as described further in Sections 4.1.2 and 10.3.2.

3.1.4 FGD Wastewater Loadings
EPA used responses to the Steam Electric Surv ey to identify the population of plants that operate wet FGD scrubbers and discharge the wast ewater to surface water or a POTW. For this population of plants, EPA used survey responses to identify the flow rate of the FGD wastewater and calculate the amount of treated FGD wastewater that is recycled by the plant. EPA also used Steam Electric Survey data to estimate FGD wast ewater pollutant loadings as described further in Sections 4.1.1 and 10.3.1.

3.1.5 Combustion Residual Landfill Leachate Loadings
EPA used responses to the Steam Electric Surv ey to identify the population of plants that collect and discharge leachate from landfills containing combustion residuals to surface water or a POTW. For this population of plants, EPA used survey responses to identify the flow rate of the landfill leachate and calculate the amount of landfill leachate th at is recycled by the plant. EPA also used Steam Electric Survey data to characterize the landfill leachate wastestream as well as to estimate the leachate pollutant loadin gs as described further in Sections 4.1.3 and 10.3.3.Chapter 3 – Data Sources

3-3 3.2 T ECHNOLOGY V ENDOR D ATA
EPA obtained data regarding the technologies used in the industry from technology vendors through presentations, conf erences, meetings, and email and phone contacts. The data collected informed the development of the technology costs and loadings estimates.
To gather information on FGD wastewater and combustion residual leachate treatment for the cost analyses, EPA contacted companies th at manufacture, distribu te, or install various components of chemical precipitation, bi ological, and vapor-compression evaporation wastewater treatment systems. The vendors prov ided the following types of information for EPA’s analyses:

 Operating details;

 Performance data;

 Equipment used in the system;

 Capital cost information on a component level and system level;

 O&M costs; and

 Equipment and system energy requirements.
To gather information on fly ash and bottom ash handling techniques, EPA also contacted several ash handling and ash storage vendors. The vendors provided the following types of information for EPA’s analyses:

 The type of fly ash and bottom ash handling systems available for reducing and/or eliminating ash transport water;

 Equipment and demolition required to conve rt wet sluicing fly ash and bottom ash handling systems to an alternate ash handling system, including equipment that can be reused as part of the conversion from a wet to a dry/closed-loop recycle handling system; 3

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

 O&M costs;

 Equipment and installa tion capital costs;

 Dry ash storage specifications; and

 System energy requirements.

3.3 F IELD S AMPLING P ROGRAM
EPA conducted an international sampling prog ram at steam electric power plants to collect wastewater data charac terization and treatment performance data associated with FGD

3 Throughout this report, EPA refers to bo ttom ash systems that eliminate the use of ash trans port water as dry ash handling systems; however, some of these systems (e.g., mechanical drag system) still use water in a quench bach and therefore, are not completely dry systems.Chapter 3 – Data Sources

3-4 wastewater and other em erging wastestreams for which characte rization data were not available (i.e., carbon capture and gasifi cation wastewaters). As part of this sampling program, EPA conducted on-site sampling activities (i.e., samples were collected directly by EPA), as well as requiring some plants to collect samples for th e Agency (i.e., CWA 308 monitoring program).
EPA conducted sampling activities at the following selected plants:

 Duke Energy Carolina’s Belews Creek Steam Station;

 We Energies’ Pleasant Prairie Power Plant;

 Duke Energy’s Miami Fort Station;

 Duke Energy Carolina’s Allen Steam Station;

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

 RRI Energy’s Keystone Ge nerating Station; and

 Allegheny Energy’s Hatfield’s Ferry Power Station.
All of the selected plants operate chemical precipitation wastewater treatment systems to treat their FGD wastewater. Belews Creek, A llen, and Dickerson also operate biological treatment systems to further treat the effluent from chemical precipitation treatment. EPA also conducted a sampling episode at Enel’s Federico II Power Plant (Brindisi), located in Brindisi, Italy. The Brindisi plant operates a chemical pr ecipitation treatment system followed by a vaporcompression evaporation system. EPA also required an additional four plants to participate in the CWA 308 monitoring program and co llect four consecutive days of samples to characterize specific wastestreams for which EPA did not have existing data. The following plants were selected:

 Tampa Electric Company’s Polk Station (i ntegrated gasification combined cycle (IGCC) generating unit);

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

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

 Kansas City Power and Light’s Iatan Station (vapor-compression system).
For more information on the field sampling program, see Section 3 of the Technical Development Document for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (DCN SE01964).

3.4 EPA D ETAILED S TUDY A SH S URFACE I MPOUNDMENT S AMPLING D ATA
As part of the detailed study undertaken prio r to beginning the rulemaking process, EPA conducted a sampling program to characterize un treated wastewaters generated by coal-fired power plants, as well as to eval uate treatment technologies and best management practices for reducing pollutant discharges. Between Ju ly 2007 and October 2008, EPA collected and analyzed samples to characteri ze wastewater streams at six coal-fired power plants. EPA analyzed the samples for total metals (includi ng 25 specific metals), hexavalent chromium, nitrogen compounds, and other cl assical analytes. Specifically, EPA characterized wastewaterChapter 3 – Data Sources

3-5 streams associated with wet FGD systems a nd ash handling operations and evaluated the capability of various types of tr eatment systems to remove metals and other pollutants of concern prior to discharge. Four of th e plants sampled operated some type of wet ash handling system, either wet bottom ash handling, wet fly ash hand ling, or both. The effluent samples collected from the ash surface impoundments at these four pl ants were collected as one-day grab samples and represented two fly ash surface impoundme nts, one bottom ash surface impoundment, and one combined surface impoundment (receiving bot h fly ash and bottom ash wastewater).

3.5 I NDUSTRY
- AND S TATE -S UBMITTED M ONITORING D ATA
In addition to monitoring data submitted in the Steam Electric Survey and data collected during the EPA sampling program, EPA requested long-term self-monitoring data from Duke Energy’s Belews Creek Steam Station and Allen Steam Station to support the evaluation of BAT FGD wastewater treatment syst ems [Duke Energy, 2011a and 2011b]. The data included effluent concentrations for mercury, selenium, and seve ral other metals achieved by the chemical precipitation and the biological treatment portions of the FGD wastewater treatment systems over a 3-year period.
Additionally, EPA coordinated with the stat e of North Carolina to obtain long-term characterization data from Pr ogress Energy Carolinas’ Roxboro Steam Electric Plant for the FGD wastewater treatment influent, FGD impou ndment effluent, and biological treatment effluent, as well as ash impoundment effluent data.

3.6 E LECTRIC P OWER R ESEARCH I NSTITUTE (EPRI) PISCES R EPORTS

EPRI is a research-oriented trade associat ion for the steam electric industry. EPRI conducts research funded by the st eam electric industry and has ex tensively studied wastewater discharges from FGD systems and ash impoundment s. The trade association provided EPA with the PISCES Water Characterizati on Field Study, Sites A-G reports that summarize the data collected during seven separa te site visits to characterize wastew ater at coal-fired power plants.
For each of the seven sites sampled, EPA reviewed the reports to determine the characteristics of the ash impoundments (e.g., ty pe of wastestreams entering the impoundment and pollutant concentrations pres ent). The sites were identified as operating the following type of ash impoundments:

 Site A – Combined ash impoundment;

 Site B – Combined ash impoundment;

 Site C – Combined ash impoundment;

 Site D – Combined ash impoundment;

 Site E – Combined ash impoundment;

 Site F – Bottom ash impoundment & combined ash impoundment; and

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

3-6 Based on its review of the reports, EPA used the average pollutant concentrations, as reported, representing the overflow from the ash impoundments for all seven plants. EPA included the average pollutant concentrati on for each pollutant for each of the eight impoundments in the data set used to calculate ash transport wa ter loadings. Chapter 10 provides more detail on the calculation of ash transport water loadings.

3.7 P ERMIT A PPLICATION D ATA
During the detailed study, EPA coordinated efforts with the Utility Water Act Group (UWAG), an industry trade association, to create a database of select ed National Pollutant Discharge Elimination System (NPDES) Form 2C data from UWAG’s member companies. The NPDES Form 2C (or an equivalent form used by a state permitting authority) is an application for a permit to discharge wastewater that mu st be completed by existing industrial plants (including manufacturing, commercia l, mining, and silvicultural ope rations). This form includes plant information, data on plan t outfalls, process flow diagra ms, treatment information, and intake and effluent characteristics.

The NPDES Form 2C database contains inform ation about the outfalls from 86 coal-fired power plants that discharge FGD, ash handling, or coal pile runoff wastestreams. The database does not include Form 2C information for plants that have neither a wet FGD system nor wet fly ash handling. For example, if a plant has no wet FGD system and the plant’s only wet ash handling is for bottom ash slui cing, UWAG did not include its in formation in the database.
EPA matched pollutant data from the NPDES Fo rm 2C database to da ta in responses to Parts A and D of the Steam Electric Survey by NPDES permit number and outfall number to determine which outfalls contained fly, bottom, or combined ash transport water. For those NPDES permit IDs in the Form 2C database that did not match information from the survey responses, EPA conducted a manual search to ge nerate a crosswalk between the Form 2C NPDES permit number and the reported NPDES pe rmit numbers in the survey responses. After the NPDES permit numbers were matched, EPA corre lated the outfalls in the Form 2C database to those reported in the survey using the following hierarchy:

 Outfall numbers that matched exactly;

 Outfall numbers matched by hand to correct for minor formatting discrepancies (e.g., “Outfall 001” vs. “001”); and

 Matching outfall descriptions.

EPA used the information from Parts A and D of the survey responses to calculate the percent contribution of the ash tr ansport water streams to the tota l outfall flow rate. For each of the 27 outfalls in the Form 2C database for which more than 75 percent of its flow is from ash transport water (fly, bottom, or the combination of the two), EPA include d the average pollutant concentrations in the ash c oncentrations data set.

3.8 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 1982Chapter 3 – Data Sources

3-7 TDD”) presents the results of studies of the steam electric in dustry that EPA conducted when previously revising the Steam El ectric ELGs. This document contains findings, conclusions, and recommendations on control and tr eatment technology relating to discharges from steam electric power plants. The 1982 TDD included three separa te tables that contained ash impoundment characterization data. EPA used data from all th ree tables (described be low) to populate the ash concentrations data set. The Agency used information provided throughout the 1982 TDD to identify the types of influent streams ente ring each of the ash impoundments used for this loadings analysis.

Table V-32, Characteristics of Ash Pond Overflows with Total Suspended Solids Concentrations Less than 30mg/L, presents average surface impoundment overflow pollutant concentrations for 11 separate impoundments at 11 plants. Each of these 11 data sets were included in the ash concentrations data set as one data point per im poundment and pollutant.

Table V-33, Summary of Ash Pond Overflow Data from Discharge Monitoring Reports
, provides an average pollutant concentration for ash surface impoundment effluent for each of the three different types of impoundment system s (i.e., fly ash, bottom ash, combined ash). Additionally, the table iden tified the number of impoundment syst ems that were used to calculate the average concentration; therefore, EPA include d the same number of records of the average concentrations in the ash concentrations data se t as the number of impoundments that were used to calculate the average. For example, EPA include d four separate records of the average fly ash pollutant concentrations from Table V-33 in the ash concentrations data set because the table listed the four impoundments that were used to ca lculate the average concentrations presented.

Table V-34, Summary of Quarterly TVA Tr ace Metal Data for Ash Pond Intake and Effluent Streams , summarizes average plant intake and ash surface impoundment effluent pollutant concentrations for 10 plants. EPA include d the average effluent pollutant concentration for each plant in the ash concentrations data set.

3.9 P ROTECTION OF C ONFIDENTIAL B USINESS I NFORMATION
Certain data in the rulemaking record ha ve been claimed as confidential business information (CBI). Due to these CBI claims, EP A has redacted certain information from this report. Additionally, EPA has withheld CBI, as we ll as some data not claimed as CBI but which could indirectly reveal CBI, from the public doc ket in the Federal Docket Management System. Furthermore, EPA has aggregated certain data in the public docket, masked plant identities, or used other strategies to prevent the disclosure of CBI. The Agency’s approach to CBI protection ensures that the data in the public docket both ex plain the basis for the proposed rule and provide the opportunity for public comment, without co mpromising data confidentiality. This section describes the data claimed as CBI related to the costs and loadings analyses and how EPA determined which data needed to be redacted from this report.
During the rulemaking, steam electric power plants and equipment and chemical vendors submitted data to EPA, some of which were cl aimed as CBI. These CBI data include costs associated with the installation and operation of the technology options eval uated as part of this rulemaking (or individual cost components for th e system) and plant operating characteristics, which were used by EPA to estimate the plant-speci fic cost estimates and pollutant loadings. InChapter 3 – Data Sources

3-8 general, there are three different types of CBI co st values that were redacted from the nonCBI version of this report:

 Plant-specific operating characteristics used as input values to estimate costs and loadings. Generally, EPA collected the plant-sp ecific operating characteristics from plant responses to the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey). As pa rt of the responses, plants were able to claim the reported data as CBI a nd, in many cases, the input values used to estimate plant-specific costs were claimed CBI . As a result, the plant-specific costs and pollutant loadings calcul ated using these CBI values are also considered CBI because the input values could be back -calculated using the outputs and the methodologies and equations provided in this report. For this reason, the appendices to this report, which include the input a nd output data from the costs and loadings models at a plant level, are CBI.

 Vendor-provided cost information. As described in Section 3.2, EPA obtained data regarding the technologies used in the industry through contact with equipment and chemical vendors. Some of this information was claimed as CBI by the vendors. In all cases for which vendors provided CBI co st information, EPA was unable to mask the information using other vendor CBI data ; therefore, all vendor-provided CBI was redacted from the nonCBI version of this report.

 Industry-specific cost factors developed by EPA to estimate indirect costs related to capital and O&M costs. EPA also used the plant-specific data reported in response to the Steam Electric Survey to develop cost fact ors to estimate the indirect costs related to capital and O&M costs. The development of these cost factors are described throughout this report. In general, EPA used all the data available for a specific cost element, including both CBI and nonCBI data, to develop these cost factors. For some cost factors developed by EPA, the a ggregated value used for the cost factor (e.g., average or median value) may reveal CBI data because of other available nonCBI data (i.e., the cost factor is CBI deducible). EPA’s methodology for determining CBI-deducible data is de scribed in the following paragraphs.
Where an aggregated output includes tota ls summed from both CBI and non-CBI data, the CBI responses may be deducible. Typically, CBI data can be masked (i.e., is non-deducible) if it is combined with at least two other CBI data points into an aggregated value (i.e., at least three CBI values are present, each of which must be associated with different companies). In evaluating the number of CBI data points aggreg ated, EPA reviewed the number of companies that provided the CBI data to determine if three or more companies provided CBI data.
Example of CBI Deducible Data Determination : EPA has information from the Steam Electric Survey from nine responde nts (i.e., plants) operated by five companies. Three respondents claimed producti on data as CBI, the other six did not make any CBI claims on the data. The breakdown of respondents at the plant and company level is as shown:Chapter 3 – Data Sources

3-9 Number of Plant Respondents to Question Number of Company Resp ondents to Question 9 plants (total) 5 companies (total)

3 plants (CBI) – A, B, and C 2 companies (CBI):
- One company operates A and B
- One company operates C

Only two companies submitted CBI data. The company operating plants A and B can determine plant C’s CBI response, because it would have access to eight of the responses (i.e., the six nonCBI responses in the Steam Electric Technical Questionnaire Database , plus two CBI responses for pl ants A and B). Therefore, if the aggregated cost factor based on the nine responses were made publicly available, the company operating plants A and B would be able to determine plant C’s CBI data. For this example, EPA would redact the cost factor from the nonCBI version of this report to prevent the disclosure of CBI.
EPA evaluated each cost factor developed fo r 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 determ ined to be CBI-deducible as CBI data and has redacted those values from the nonCBI version of this report.

3.10 R EFERENCES

1. Duke Energy. 2011a. Industry Provided Sampli ng Data from Duke Energy's Allen Steam Station. (17 August). DCN SE01809.
2. Duke Energy. 2011b. Industry Provided Sampli ng Data from Duke Energy's Belews Creek Steam Station. ( 17 August). DCN SE01808.Chapter 4 – Development of Model Inputs

4-1 

## CHAPTER 4 DEVELOPMENT OF MODEL INPUTS

This chapter describes in detail the input data to the costs and loadings models that EPA used to estimate incremental compliance cost s and post-compliance pollutant loadings and removals for the Steam Electric effluent limita tions and standards ( ELGs). These data are categorized into one of four groups:

 Wastestream population and flow basis for pollutant loadings;

 Wastestream population and char acteristics for costing;

 Pollutant concentrations; and

 Plant characteristics.
All tables and figures referenced in this chap ter are presented at the end of the chapter.

4.1 W ASTESTREAM P OPULATION AND F LOW B ASIS FOR P OLLUTANT L OADINGS
EPA calculated baseline and post-complian ce pollutant loadings for each plant discharging flue gas desulfuriz ation (FGD) wastewater, fly as h transport water, bottom ash transport water, and/or combustion residual landfill leachate. Pollutant loadings are calculated by multiplying a specific pollutant-level concentrat ion by a wastewater flow rate. The following sections describe EPA’s methodology for determini ng which plants should be included in each wastestream population and the amount of wastewater being discharged by those plants based on information from the Questionnaire for the Steam Elect ric Power Generating Effluent Guidelines (Steam Electric Survey).

4.1.1 FGD Wastewater
EPA used data from the Steam Electric Survey to identify the population of plants that discharge FGD wastewater to surface water (o r a publicly owned treatment works (POTW)) and the type of treatment equipment each plant currently has in place. To develop this “FGD Input Table,” EPA used information from Part B of the Steam Electric Survey (Flue Gas Desulfurization (FGD) Systems). A copy of the “FGD Input Table” is located in the appendix. EPA identified a total of 117 plants that operate wet FGD systems and discharge FGD
wastewater.

EPA used the information from Part B Secti on 1 (General FGD System Information), to identify those plants that have the potential to discharge FGD wastewater . Some plants operating wet FGD systems were excluded from th is group for the following reasons:

 The plant did not report a NPDES permit;

 The plant treats the FGD wa stewater using an evaporat ion impoundment system that completely recycles the water back to the FGD system; or

 The plant reuses all the FGD wastewater with no potential of later discharge to surface water or POTW.Chapter 4 – Development of Model Inputs

4-2 For each plant included in the “FGD Input Tabl e”, EPA also identified a plant-level FGD wastewater flow rate in gallons per day (gpd). For plants opera ting more than one FGD system, the sum of the purge rates for the individual FGD systems was included in the “FGD Input Table”. For each FGD system currently operating, EPA used the purge rate reported in Part B Section 5 (FGD Wastewater Gene ration), as the basis for the cost models. For current FGD systems that did not provide a FGD wastewater fl ow rate in Part B Sect ion 5 (27 plants), EPA developed a methodology to estimate the purge fl ow based on other data provided in the Steam Electric Survey. Using information from plants that did report an FGD wastewater flow, EPA established a relationship between the wastewater flow rate and the amount of coal burned at generating units serviced by wet FGD systems. EPA noted that th is relationship was dependent upon the type of coal burned by these generating units ; and as a result calc ulated a value for the FGD flow per ton of coal for each type of co al: bituminous, subbituminous, lignite, and a blend of any two or more coals. EPA estimated the wa stewater flow rate for 27 plants using Equation 4-1.
FGD Wastewater Flow (gpd) = Tonsof CoalBurned × MedianGPDperTonofCoal (4-1 )

where:

TonsofCoalBurned = The reported tons of coal burned per year by the steam electric units serviced by the FGD system. Data from Part A Section 8 (Fuel Usage by Steam Electric Generating Unit), and MedianGPDperTonofCoal = The calculated median FGD wastewater flow rate in GPD per ton of coal burned per year based on the type of coal burned: 0.1454 for bituminous, 0.0392 for subbituminous, 0.2313 for lignite, and 0.1017 or any coal blend.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A53) for the discussion on the development of Equation 4- 1 and the development of the median FGD wastewater flow per ton of coal burned.
For each plant planning to install a FGD sy stem prior to January 1, 2014, EPA used the 24-hour average daily design flow rate reported in Part B Section 2 (Planned FGD System Information), to calculate a plant-level FGD wast ewater flow rate in gallons per day, assuming the system operates 24 hours per day. In two cases , plants did not provide a design flow rate for planned FGD systems or reported that it was not yet known. To account for the lack of flow rate data provided in the survey responses, EP A developed a methodology for estimating the FGD wastewater flow rate fo r planned FGD systems.
EPA first developed a relationship between the generating unit capacity (megawatts (MW)) and tons of coal burned per day using data from each coal-fired steam electric generating unit based on the type of coal burned:Chapter 4 – Development of Model Inputs

4-3 Bituminous Coal
Coal Burned per Day (tons) = 0.0014 × Capacity 2 + 5.7189 × Capacity + 606.1 ( 4-2 )

Subbituminous Coal
Coal Burned per Day (tons) = 7.4416 × Capacity 1.0685 ( 4-3 )

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

Any Combination of Two or More Coal Types
Coal Burned per Day (tons) = 9.6541 × Capacity 0.9858 ( 4-5 )

where:

Capacity = The reported generatin g capacity of the steam electric unit in MW from Part A Section 6 (Steam Electric Generating Unit Information).

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A54) for the discussion on the development of Equations 4-2 through 4-5.
Using Equations 4-2 through 4-5, EPA calculate d the amount of coal burned per day for each steam electric unit not providing the inform ation in Part A Section 6 (Steam Electric Generating Unit Information). The amount of coal burned per year was calculated by multiplying the amount of coal burned per day by the numbe r of days the unit opera ted in 2009, reported in Part A Section 6. All units missing the number of days of operation, or planned steam electric generating units not reporting da ys of operation, were all baseload type units. EPA used the median number of days of operation, 311 days, for all baseload units. EPA used the estimated amount of coal burned per year to calculate an FGD wastewater flow rate, in gpd, for the two planned FGD systems not reporting a design flow.

4.1.2 Fly Ash and Bottom Ash Transport Water

EPA used data from the Steam Electric Su rvey to identify the population of surface impoundments that receive fly ash, bottom as h, or combined ash transport water and that discharge to surface waters. To develop this “A sh Transport Water Input Table,” EPA used the information from the Steam Electric Survey to iden tify those plants that di scharge all or some of their ash transport water and how much of that as h transport water is bein g discharged. A copy of the input table is included in the appendix. EPA id entified a total of 248 plants that discharge ash transport water from 269 discrete outfalls.
EPA populated the “Ash Transport Water Input Table” using the following steps:Chapter 4 – Development of Model Inputs

4-4  Identify surface impoundments that discha rge to surface waters based on Part D Section 3.2 (Ponds/Impoundment System or Wastewater Treatment System Effluent Flows);

 Determine if those surface impoundments re ceive any ash transport water based on Part D Section 3.1 (Ponds/Impoundment Syst em or Wastewater Treatment System Influent Flows); and

 EPA supplemented incomplete or inconclusi ve Part D information with information reported in Part A Section 2.2 (Outfall In formation), Part C Section 2.1 (Fly Ash Handling – Generating Unit Information) , and Part C Section 3.1 (Bottom Ash Handling – Generating Unit Information).

In cases where the Part D data differed from Parts A or C, EPA further reviewed the process flow diagrams to help identify whether a ny ash transport water enters the specific surface impoundment and whether any amount of recycle occurs.
For each surface impoundment included in the “Ash Transport Water Input Table,” EPA also identified the flow rate associated with the fly ash transport water, bottom ash transport water, or combined ash transport water. Data included in the Steam Electric Survey do not include impoundment discharges br oken out by type of waste; as a result, EPA used the data available from the survey to calculate the amount of ash transport water discharged from each impoundment. EPA used the following hierarchy to populate the “Ash Transport Water Input Table” with ash transport water effluent flow rates for all impoundments indicating that 100 percent of the influent is discharged:

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

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

 Percent contributions of ash transport water to a plant outfall multiplied by the total outfall flow rate reported in Part A Section 2.
For combined ash surface impoundments, EPA combined the fly ash transport water and bottom ash transport water flow rates to calculate a combined ash transport water flow rate for the surface impoundment for the purpos es of the “Ash Transport Water Input Table;” therefore, each ash surface impoundment that discharges has only one entry in the “Ash Transport Water Input Table.”
For surface impoundments that do not discharge 100 percent of the influent, EPA used information from other parts of the Steam Electric Survey to estimate the amount of evaporation or recycle achieved by each plant. EPA used da ta from Parts D, C, and A to calculate the percentage of ash transport recycl ed within the ash sluice system and the percentage of transport water discharged to surface water or POTWs. In cases where data from the various survey sections were not in agreement, EPA further revi ewed the water balance diagram to help identify the level of recycle.
Plants do not generate ash transport water constantly and theref ore do not necessarily discharge the wastewater without interruption. The discharge fl ow rates used to populate the “Ash Transport Water Input Table” were normalized to have all plants on the same basis ofChapter 4 – Development of Model Inputs

4-5 discharging over 365 days. Using St eam Electric Survey data, EPA identified the number of days that the ash transport water was reported to be transferred to the surface impoundment or generated from the ash handling system. To account for the number of days of generation, EPA calculated a normalized daily fl ow rate using Equation 4-6. 4

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

where:

Impoundment Transport Water Flow = The reported ash transport wa ter flow rate discharged from each surface impoundment in gallons/day, and Days Generated = The reported number of days that ash transport water is generated/transferred to the ash surface impoundment.

4.1.3 Leachate

EPA used data from the Steam Electric Survey to identify the population of active/inactive landfills containi ng combustion residuals that colle ct leachate and discharge to surface waters. To develop this “Landfill Leachate Input Table,” EPA used the information from Part A Section 4 (Landfills) of the survey al ong with information from Part A Section 2.2 (Outfall Information) and water balance diagrams to identify the landfills that collect and discharge leachate to surface wate r. A copy of the “Landfill Leachat e Input Table” is located in the appendix. EPA identified a to tal of 102 plants that collect and discharge leachate from 114 landfills containing combustion residuals.
Plants reported their collected leachate volumes in Part F Section 3.1 (Landfill Management Practices) of the Steam Electric Su rvey. Because only a subset of plants were required to complete Part F, EPA had specific landfill leachate volumes from 18 plants. For each of these 18 plants, EPA calculated the ratio of th e landfill acreage associated with the collected leachate and the total active/inactive landfill acres at the plant reported in Part C Section 1 (Ash Generation) of the survey. EPA then determined the median value and applied this value to plants that reported collecting la ndfill leachate but were not requi red to complete Part F. EPA used the median value, along with the reported total activ e/inactive landfi ll acres reported in Part C, to estimate the total landfill acres for the plan t where leachate is collected (referred to as leachate acreage). EPA developed separate estima tes for active and inactiv e landfills as follows:

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

4 The approach of normalizing the flow based on the number of days generating ash transpor t water may underestimate the loadings. Even when ash transport water is not transferred to the ash impoundment the impoundment will continue to discharge, although at a lower flow rate, because othe r contributions (e.g., rainfa ll) will continue to feed the impoundment and will like ly become contaminated from the as h contained in the impoundment.Chapter 4 – Development of Model Inputs

4-6 Inactive Landfills
Leachate Acreage (acre) = 0.05 × Landfill Acreage ( 4-8 )

where:

Landfill Acreage = Total active/inactiv e/open landfill acreage at the plant, as reported in Part C Se ction 1 (Ash Generation).

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A62) for the discussion on the development of Equations 4-7 and 4-8.
EPA also used the data from the 18 plants re sponding to Part F Section 3.1 to generate a relationship between the acreage of landfills containing combustion residuals that collect leachate and the amount of leachate discharged. EPA assumed that any open landfill, active or inactive, at a given plant woul d receive similar amounts of rainfall. Of the 18 plants that discharge leachate, the median leachat e discharge rate was 887 gpd per acre.
EPA used the following hierarchy to estimat e the landfill leachate flow rate for the “Landfill Leachate Input Table:”

 EPA used the volume of leachate collected in 2009, reported in Part F Section 3.1 of the Steam Electric Survey (Landfill Management Practices).

 EPA used the current landfill-specific surf ace area from Part F Section 3.1 of the survey (Landfill Management Practices) and multiplied by the median leachate discharge rate per acre (887 gpd/acre). The specific data from the Steam Electric Survey used to calculate th is value can be found in the Supplemental Costs and Loadings Documentation (DCN SE01825.A62).
Leachate Volume (gpd) = 887 × Leachate Acreage ( 4-9 )

 EPA used the active/inactive/open landfill acreage, reported in Part C Section 1 (Ash Generation) depending on whether the landfil l is active or inactive, and the median leachate discharge flow rate per acre (887 gpd/acre).

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

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

where:

Leachate Acreage = Total acreage of landfills containing combustion residual at the plant that co llect leachate, a percentageChapter 4 – Development of Model Inputs

4-7 of the total landfill acres at the plant (see Equations 4-7 and 4-8).

During review of the landfill leachate volumes, EPA also investigated the frequency of leachate collection for the 18 plants with co mplete Part F Section 3.1 data. The median frequency of leachate collection was 365 days pe r year. EPA used this value to convert the leachate volumes from gallons per day to gall ons per year prior to populating the “Landfill Leachate Input Table.”
EPA identified two plants that did not provide landfill acreage data in Part C Section 1 of the Steam Electric Survey. To estimate the landfill leachate flow rate for these two plants, EPA used the median leachate volume from plants prov iding data in Part F Section 3.1 of the survey. The average plant-level leachate volume reported by the 18 plants in Part F Section 3.1 was 46,160 gpd for active landfills and 29,651 gpd for inactive landfills.

4.2 W ASTESTREAM P OPULATION AND C HARACTERISTICS FOR C OSTING
For each plant discharging FGD wastewater and/or combustion residual landfill leachate and all plants operating wet fly or bottom ash handling systems, EPA estimated a compliance cost to treat wastewater or eliminate the discharge of ash tran sport water entirely. 5 EPA estimated compliance costs associated with inst alling a wastewater trea tment system to treat FGD wastewater and landfill leachate. The methodol ogy for estimating treatment system costs is based on the flow of wastewater through the sy stem. For FGD wastewater and landfill leachate, EPA used the same input table for both cost ing and pollutant load ings calculations.
EPA also estimated compliance costs associat ed with eliminating the discharge of ash transport water, by costing plants to convert to either a dry handling or a closed-loop recycle system. These costs are based on the amount and type of ash generated by each plant. The following sections describe what population of pl ants incurs fly ash and bottom ash compliance costs and the specific plant and generating unit-le vel characteristics needed to estimate these
costs.

4.2.1 FGD Wastewater
EPA used the same input data for both costi ng and loadings associated with discharging FGD wastewater. For details on the “FGD Input Table” see Section 4.1.1.

4.2.2 Fly Ash
EPA used data from the Steam Electric Survey to identify the population of plants that would incur costs under the proposed regulatory options. EPA first identified those plants that operate wet sluicing systems and discharge fly as h transport water. To develop this “Fly Ash Input Table,” EPA used data from Part C (Ash Handling) and Part A (Steam Electric Power

5 Plants can eliminate the discharge of ash transport water by either converting to a dry as h handling system or operating a closed-loop ash recycle system.Chapter 4 – Development of Model Inputs

4-8 Plant Operation) of the survey . to identify what costing elements of the fly ash system would be appropriate for each plant.
EPA assessed the costs for converting to a dry fly ash handling system on a steam electric generating unit level. EPA examined survey da ta for each generating unit utilizing fly ash transport water and applied a hierarchal met hod to determine the appropriate fly ash cost elements for each generating unit. First, units were flagged as “No_cost” if the unit falls into any of the following subsets:

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

 Generating units that did not operate in 2009, indicated by a “N o” response to Question A6-1 in Table A-8. 6

 Generating units at a plant that did not rece ive Part C of the survey (i.e., Version 4 plants: gas-fired plants, gas-combined cy cle plants, and nuclear power plants, and those plants kicking out of the survey in Part A), which are not expected to produce ash.

 Generating units that did not report fly as h generation, either by responding “No” to Question C1-1 or not completing a copy of Part C Section 2.1.

 Generating units that repor ted fly ash generation in Table C-2 and reported dry handling only. These units re ported all of their fly as h generation as dry conveyed, did not select wet sluicing (hydraulic) in Table C-2, a nd responding “No” to C2-2.

 Generating units that indi cated both wet and dry fly ash handling by responding “Yes” to Question C2-10. The units must also have reported that no system modifications would be require d to handle all the fly ash dry in response to Question C2-12.

 Generating units that indi cated both wet and dry fly ash handling by responding “Yes” to Question C2-10 and indicated that use of the wet fly ash handling system will end before 1/1/2014 in Question C2-13.

 Generating units that indi cated both wet and dry fly ash handling by responding “Yes” to Question C2-10 and responding to Question C2-11 that the only reason the wet fly ash handling system was operated in 2009 was because the dry fly ash handling system had not yet been installed.

 Generating units at plants that did not report a National Pollutant Discharge Elimination System (NPDES) permit in Ta ble A-2, indicating that they do not discharge to surface water, and did not re port an indirect discharge of fly ash transport water to a POTW.
Next, EPA identified the genera ting units that required a co mplete wet-to-dry fly ash conversion and therefore will incur all associated fly ash cost elements (i.e., conveyance costs, silo costs, pugmill costs, and transportation/disposal costs). These units were flagged as ”All_cost” and identified using the following criteria:

6 Although these units may still have the capab ility to operate, EPA assumes that the co mpany will retire these units instead of investing money for as h handling conversions.Chapter 4 – Development of Model Inputs

4-9  Generating units responding “Wet sluicing ( hydraulic)” in Table C-2 and reporting no dry handling capabilities (Dry Vacuum sy stem, Wet Vacuum system (pneumatic), Pressure system, Combined vacuum/pressure system, or Mechanical system). Units responding “Wet sluicing ( hydraulic)” and “Other” were handled on an individual basis to determine whether the response in the “Other” field i ndicated a wet or dry handling system.

 Generating units responding “Wet sluicing (hydraulic)” in Table C-2 as well as reporting any type of dry handling capabili ties (Dry Vacuum system, Wet Vacuum system (pneumatic), Pressure system, Combined vacuum/pressure system, or Mechanical system), but listed all of the fly ash generation as wet conveyed in Table C-2. 7

All generating units that were not categorized as ‘No_cost” or “All_cost” have both wet and dry fly ash handling capabilities, and ther efore should only require partial fly ash cost elements to convert to a completely dry fly as h handling system. These units were flagged for costing based on the responses to Questions C2-11 and C2-12.

 Generating units were identified as need ing conveyance costs if the respondent selected “Install/increase the capacity of the dry fly ash conveying equipment” in response to Question C2-12.

 Generating units were identified as needing silo costs if th e respondent selected either “Increase the capacity of the silo(s)” or “Inc rease the number of th e silos” in response to Question C2-12.

 Generating units were identified as n eeding pugmill costs any time a unit was identified as needing a silo cost. Additionally, units were identified as needing pugmill costs if the respondent selected “Mod ify the loading silos to have the ability to moisture condition the ash” in response to Question C2-12.

 Generating units were identified as needi ng transportation/disposal costs if the respondent selected “Install/increase the cap acity of landfills” in response to C2-12, or if the respondent selected “Wet fly as h handling system operated during times in which the dry fly ash was not marketab le” in response to Question C2-11. Additionally, a unit was identified as needi ng transportation/disposal costs any time it was identified as needing a silo or pugmill cost.
For all generating units included in this par tial costs category that handled the fly ash both wet and dry in 2009, EPA evaluated response s in the “Other” fields for Questions C2-11 and C2-12 on an individual basis to identify any specific cost elem ents that should/should not be included for those plants/units.
EPA identified 78 plants, corresponding to 197 generating units, discharging fly ash transport water that would incur costs to eliminat e the discharge of fly ash transport water. Of these, 12 plants, corresponding to 27 generating un its, are oil-fired units or small units with a capacity less than or equal to 50 megawatts. For all 197 generating units, EPA identified the

7 Although the plants indicated that these un its had a dry handling system, EPA assumed that a completely new system would be required because the plant did not use the system at all in 2009. This assumption ma y overestimate the costs for these units.Chapter 4 – Development of Model Inputs

4-10 specific fly ash cost elements needed, and collecte d the other necessary input data (i.e., unit-level wet fly ash production (in tons per day and days per year), operati ng days, capacity (in MW), and fly ash transport water flow rate (in gpd)). See Section 7.1.4 for more information about the specific fields for the “Fly Ash Input Table.” A copy of the “Fly Ash InputTable” is included in the appendix.

4.2.3 Bottom Ash
EPA used data from the Steam Electric Survey to identify the population of plants that operate wet sluicing systems and discharge bottom ash transport wa ter. To develop this “Bottom Ash Input Table,” EPA used data from Part C (A sh Handling) and Part A (Steam Electric Power Plant Operation) of the survey. to identify what costing elements of the bottom ash system would be appropriate for each plant.
Costs for converting to a system that elimin ates the discharge of bottom ash transport water are assessed on a steam electric generating un it level. EPA examined survey data for each generating unit utilizing bottom ash transport wate r and applied a hierarchal method to determine the most appropriate bottom ash cost elements fo r each unit. First, generating units were flagged as “No_cost” if the unit falls in to any of the following subsets:

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

 Generating units that did not operate in 2009, those responding “No” to A8-1 in Table A-8. 8

 Generating units at a plant not completing Part C of the survey (i.e., Version 4 plants: gas-fired plants, gas-combined cycle plan ts, and nuclear power plants, and those plants kicking out of the survey in Part A), which are not exp ected to produce ash.

 Generating units not repor ting bottom ash generation, e ither by responding “No” to C3-1 or not completing a copy of Part C Section 3.1.

 Generating units \reporting bottom ash gene ration in Table C-18 but not reporting the use of wet sluicing. These units did not se lect “Wet sluicing” in Table C-18, and selected “No” in response to C3-3.

 Generating units reporting bottom ash genera tion in Table C-18 and reported both “Wet Sluicing” and at least one other type of bottom as h handling system, but listed all of the bottom ash generation as “Dry Conveyed.”

 Generating units that indi cated both wet and dry bottom ash handling by responding “Yes” to Question C3-16 and responding in the “Other” field for Question C3-18 that the only reason the wet bottom ash hand ling system was operated in 2009 was because the dry bottom ash handling sy stem had not yet been installed.

 Generating units that indi cated both wet and dry bottom ash handling by responding “Yes” to Question C3-16 and reporting th at use of the wet bottom ash handling system will end before 1/1/2014 in Question C3-19.

8 Although these units may still have the capab ility to operate, EPA assumes that the co mpany will retire these units instead of investing money for as h handling conversions.Chapter 4 – Development of Model Inputs

4-11  Generating units at plants that did not report a NPDES permit in Table A-2, indicating that they do not discharge to su rface water, and did not report an indirect discharge of bottom ash tr ansport water to a POTW.
Next, EPA identified the units that required a conversion to a system that eliminates the discharge of bottom ash transport water. These units were identified using the following criteria:

 Generating units selecting “Wet sluicing” in Table C-18 and not reporting any dry handling capabilities (Mechanical drag sy stem, Dry vacuum system, Dry pressure system).

 Generating units selecting “Other” were ha ndled on an individual basis to determine whether the response indicated a wet or dry handling system.
Further, EPA identified plants operating wet sluicing systems where the majority of the bottom ash transport water is recycled. For gene rating units that responded “Yes” to Question C3-5 and “Immediately recycled back to plant process” to Question C3-10, EPA evaluated the amount of transport water actually discharged. EPA identified plants that discharged only a small amount (10 percent) of total bo ttom ash transport water as bei ng 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 assess ed a one-time bottom ash cost, described in more detail in Section 8.5.
EPA identified 226 plants, corresponding to 581 generating units, discharging bottom ash transport water that would incur costs to elim inate the discharge of the bottom ash transport water. Of these, 13 plants, corresponding to 53 ge nerating units, are oil-fire d units or small units with a capacity less than or equal to 50 mega watts. For all 581 genera ting units, EPA identified the specific cost elements that apply to the unit, and collected the other nece ssary input data (e.g., capacity (in MW), the operating days, and the bottom ash transport water rate (in gpd)). Additionally, EPA identified a s ubset of plants (27 plants, co rresponding to 53 generating units) discharging only a small percenta ge of their bottom ash transpor t water. For all 53 generating units, EPA assigned these units bo ttom ash management costs in the “Bottom Ash Input Table.” See Section 8.1.3 for more information about th e specific fields for the “Bottom Ash Input Table”. A copy of the “Bottom Ash Input Table” is located in the appendix.

4.2.4 Leachate
EPA used the same input data for both costi ng and loadings associated with discharging landfill leachate. For details on the “Landf ill Leachate Input Table” see Section 4.1.3.

4.3 P OLLUTANT C ONCENTRATIONS
EPA calculated analyte-level pollutant loadings for each of the technology options considered as part of the Steam Electric efflue nt limitation guidelines and standards (ELGs). Chapter 10 discusses the calculation of these pollutant loadings in detail. The pollutant loadings are calculated from wastestream characterizati on data collected through EPA sampling activities, Steam Electric Survey data, and publicly availa ble sources. Chapter 10 discusses pollutant loadings for each of the wastestr eams considered for regulation:Chapter 4 – Development of Model Inputs

4-12  FGD wastewater;

 Fly ash transport water;

 Bottom ash transport water;

 Impoundment and Landfill leachate;

 Flue gas mercury control wastewater;

 Gasification wastewater; and

 Nonchemical metal cleaning waste.
For each wastestream, EPA describes the pollu tant concentrations used to calculate analyte-level loadings for each technology option.

4.4 P LANT C HARACTERISTICS
EPA used a variety of plant-specific data from public sources and the Steam Electric Survey to develop input tables and cost factors used to calcul ate the plant-specific costs and loadings removals associated with the proposed Steam Electric ELGs. The Agency used information gathered through the Steam Electric Survey on current ash handling techniques and FGD wastewater treatment technolog ies to identify which plants would be affected by revisions to the Steam Electric ELGs. EPA also used plant characteristics identified in the Steam Electric Survey and publicly available data from operating companies and technology vendors to determine how plants are alrea dy currently operating, or plan to be operating by 2014, compared to the proposed bases for the technology options. EPA analyzed plants for possible existing FGD treatment and ash handling practices to accoun t for existing treatment when calculating compliance costs and estimating baseline pollutant loadings.

4.4.1 Retirements and Conversions
The steam electric industry is a dynami c industry where changes are occurring frequently, in terms of plants adding new air po llution controls or making changes to existing ash handling systems. Because of these changes, EPA attempted to account for planned changes in the cost and loadings analysis. Therefore, wher e EPA had information regarding a plant planning to retire generating units, convert fuels to eliminate producing combustion residual waste, upgrade FGD or leachate wastewater treatment system s, or convert one or more units to a dry fly ash or bottom ash handling system, EPA excluded thes e units from the cost and loadings analysis because the planned modifications would lead to compliance with the proposed ELGs.
EPA identified 30 plants as retiring, or c onverting, at least one generating unit by 2014. These units were excluded from the cost and lo adings analysis. EPA is also aware of several plants planning system level modifications to FGD wastewater treatment, leachate treatment, and/or fly ash and bottom ash handl ing that will enable them to comply with the proposed ELGs. Some plants are installing vapor-compression eva poration systems to treat their FGD wastewater while other plants are conve rting impoundment-based wet sluicing systems to closed-loop recycle systems and eliminating the discharge of ash transport water. These units were also excluded from the costs and loadings analysis. A list of all units removed from the costs and loadings analysis as a result of retiring, convertin g fuels, or treatment upgrades is included in theChapter 4 – Development of Model Inputs

4-13 “Changes to Industry Profile for Steam Electric Ge nerating Units for the Steam Electric Effluent Guidelines Proposed Rule” (DCN SE02033).

4.4.2 FGD Treatment-in-Place Input
In addition to identifying each plant’s to tal FGD wastewater flow rate, EPA also documented plants with treatment-in-place fo r the three FGD wastew ater technology options. The “Treatment-In-Place Input Tabl e” includes data on each plant’s current level of treatment for its FGD wastewater. For plants currently treati ng the FGD wastewater using one-stage chemical precipitation, anoxic/anaerobic bi ological treatment, or vapor– compression evaporation system, EPA assessed credit for these treatment systems as part of the costs and loadings models. More detail on how treatment in place is assessed for bo th costs and loadings is located in Sections 6.1.3 and 10.2.1 and also in the Supplemental Costs and Loadings Documentation (DCN SE01825). Below is a list of the plant identification numbers for those plants identified as having some amount of treatment in place for each type of technology. 9

FGD Wastewater Technology Plants With Treatment in Place Chemical Precipitation 00103, 00771, 01236, 01381, 01402, 02079, 02268, 02297 ,02383, 02536, 02550, 03095, 03146, 0319 6, 03200, 03265, 03709, 03831, 04122, 04237, 04533, 04543, 0467 9, 05015, 05318, 05477, 05570, 06283, 06377, 06616, 07256, 0778 5, 07884, 08308, 08353, 08661, 09161, 09225, 09671, 09805, 09948 Anoxic/Anaerobic Biological Treatment 02550, 04543, 06689, 08661, 09391

Vapor-Compression Evaporation 00217

4.4.3 High Flow FGD Treatment Systems
EPA categorized 12 plants with an average 24 -hour plant-level FGD wastewater flow rate greater than 1,000 gpm as a “high flow” plant. Fo r these high flows, EPA believes it would be more cost efficient for a plant to implement a dditional recycle within the FGD system with a lower overall FGD treatment flow rate, rather than design and install a FGD wastewater treatment system capable of treating the maximum wastewater flow. However, some FGD systems already operate at or near the maximum chlorides desi gn concentration and, therefore, would not be able to increase their level of recycle without potentially corroding the FGD scrubber system.
EPA used data from the Steam Electric Survey to identify the FGD systems with the potential capability to recycle the FGD wastew ater and the amount of recycle that can be accommodated. For all “high flow” plants withou t some level of treatment in place, EPA compared each FGD system’s current operating ch lorides level to the specified maximum design chlorides limit provided in Part B Section 4 (Flue Gas Desulfurization Systems – Wet FGD System Information). Based on site visit discussi ons and data from the industry, EPA determined that plants can operate up to 80 percent of the maximum design chlorides level without significant corrosion concerns. As a result, EP A identified any system operating below 80

9 EPA acknowledges that plants discharging FGD wastewater will continue to upgrade a nd/or install new treatment systems. EPA will reassess the list of plants and level of treatment in place a ssessed to plants discharging FGD wastewater prior to the fin al rule.Chapter 4 – Development of Model Inputs

4-14 percent of the maximum design level threshold as having the potential to recycle some FGD wastewater. Five of the 12 high flow plants were identified as having the potential to implement some level of FGD wastewater recycle.

EPA then calculated a new FGD treatment flow rate and the flow of the FGD recycle stream for these five plants. The new FGD treat ment flow rate was cal culated based on the number of recycle passes a given system can accommodate without exceeding 80 percent of the maximum chlorides limit. EPA used Equations 4-12 and 4-13 to calculate the new FGD treatment flow rate. For more discussion on how these equations were developed, see the Supplemental Costs and Loadings Documentation (DCN SE01825.A55).

Additional Recycle Passes = (Max Design Cl Level × 0.8 – Operati ng Cl Level)/ Operating Cl Level (4-12)

New FGD Treatment Flow = Curre nt FGD Treatment Flow / (1+ Additional Recycle Passes) (4-13)

where:

Max Design Cl Level = Maximum design chloride concentration based on the material of constructed of the FGD scrubber as reported in Part B Section 2 of the Steam Electric Survey, Operating Cl Level = Operating chlori de concentration of the FGD scrubber as reported in Part B Sec tion 2 of the Steam Electric Survey,
Current FGD Treatment Flow = Current FGD wastewater treatment flow rate as reported in the Steam Electric Survey, and Additional Recycle Passes = Number of additional scrubber passes that can be achieved based on operating chloride concentration (see Equation 4-12).

The flow of the recycle stream was calculate d as the differential between the current FGD treatment flow and the new discharge flow.
Included as part of the “High Flow FGD Input Table” is a flag to identify which plants operate a dedicated FGD surface impoundment. EPA determined it to be cost prohibitive for these high flow plants to install equalization tanks versus continuing to operate a surface impoundment. It is likely that these plants will use the dedicated impoundment in place of the equalization tanks and routesome of the impoundment effluent to the FGD wastewater treatment system, while the remainder is recycled to th e FGD system, which will increase the chlorides level in the system to within 80 percent of th e maximum design chlorides level. EPA identified seven of these 12 high flow plants with a dedi cated FGD surface impoundment. These plants will not incur a cost for equali zation tanks in Section 6.1.6.2.Chapter 4 – Development of Model Inputs

4-15 EPA developed a “High Flow FGD Input Tabl e” to hold plant-specific information on the 12 high flow plants. The data held in this input table include the current FGD wastewater flow or original purge flow rate (gpd) and the calculated recycle stream flow (gpd) for the five FGD recycle plants. Additiona lly, the “High Flow FGD Input Table” contains a flag identifying which plant operates a dedicated FGD surface impoundme nt. The “High Flow FGD Input Table” is included in the appendix. Chapter 6 provides deta il on how costs for these high flow plants were estimated.

4.5 C OMBUSTION R ESIDUAL D ISPOSAL
EPA also used plant-specific data from th e Steam Electric Survey to develop the input tables used to estimate the transport, di sposal, and surface impoundment operating costs associated with ash handling, FGD wastewater tr eatment, and landfill leachate treatment. Costs associated with transportation and disposal of combustion residuals are based on whether plants utilize an on-site or offsite-landfill. Sec tion 4.5.1 provides more detail on the input table associated with transportation and disposal co sts. Costs associated with surface impoundment operation are based on whether plants operate an impoundment containing specific types of combustion residuals. Section 4.5.2 provides more detail on the input tabl e associated with surface impoundment operation costs.

4.5.1 Combustion Residual Landfills
To estimate transport and disposal costs, EPA evaluated Part A Steam Electric Survey data to determine the population of plants with on-site active or inac tive landfills containing combustion residuals including FGD solids, fly ash, and/or bottom ash. This input table determines the type of transport and disposal costs (e.g., on-site or off-site) estimated for the plant. EPA assumed that if a plant already has an on-site landfill, the plant would dispose of the additional wastes generated as a result of the pr oposed ELGs in the on-site landfill. If a plant does not have a currently operating on-site landfill , EPA assumed that the plant would dispose of the additional wastes at an off-site landfill.

4.5.2 Combustion Residual Surface Impoundments

EPA also evaluated Part A Steam Electric Su rvey data to determine the population of the plants operating one or more surface impoundments containing combustion residual wastes. The “Surface Impoundment Input Tabl e” designates the specific com bustion residual waste (i.e., FGD solids, fly ash, and/or bottom ash) stored at surface impoundments located at the plant.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-1 

## CHAPTER 5 GENERAL METHODOLOGY, TERMINOLOGY, AND COMMON COST ELEMENTS

EPA estimated the capital and annual operating and maintenance (O&M ) costs associated with implementing treatment technologies fo r each technology option under consideration. Additionally, EPA estimated costs for specific recu rring cost elements that are not incurred on an annual basis. Therefore, EPA in cluded additional 3-, 5-, 6-, and 10-year recurring cost elements in the compliance cost methodology. Section 5.1 pr ovides further detail on the components included in the capital and O&M costs.
Certain capital and O&M costs, such as tr ansportation and disposal of solids, are applicable to more than one technology option. For example, the cost methodology for disposing of combustion residual solid waste in a landfill is the same for each type of waste. Thus, EPA was able to use the same cost module for these costs for the different technology options, varying the input values and factors (i.e., type, amount, and density of waste) as appropriate depending on the technology option and wastestream (flue gas desulfurization (F GD), fly ash, or bottom ash). These common cost elements that utili ze the same cost module for more than one technology option include compliance monitoring, transportation and disposal of solid waste (e.g., FGD wastewater treatment solids, fly ash, and bottom ash), operation and maintenance of combustion residual surface impoundments, and best management practices (BMPs) for combustion residual surface impoundments. See Sections 5.2 through 5.6 for more details regarding these specific cost elements. All tabl es and figures referenced in this chapter are presented at the end of the chapter.

5.1 G ENERAL C OST M ETHODOLOGY AND T ERMINOLOGY
To estimate the compliance costs for the technology options, EPA evaluated both direct and indirect capital costs and O&M costs. These costs were estimated using data obtained from treatment technology vendors and responses to the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey).
Capital costs are defined as a one-time expense incurred to bring a project to an operable status. These types of expenses include equipm ent, land, and buildings. EPA used the following cost components to estimate capital costs associ ated with each technology option, as appropriate:

 Direct Capital Costs

- Purchased equipment – the cost of all equipment needed for the treatment or handling system, including pumps, clarifiers, silos, sumps, tanks, reactors, filters, and various other items.

- Equipment installation – the cost to install all of the purchased equipment, including piping, instrument ation/calibration, electrical equipment, mechanical equipment, structural supports, insulation, and paint.

- Buildings –the cost associated with constructing structur es to house treatment or handling system equipment, operator rooms, or other operations associated with the system. This element includes cost s associated with building plumbing,Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-2 heating, ventilation, dust collection, air conditio ning, lighting, telephones, intercoms, painting, sprinklers, and fire alarms.

- Site preparation – the cost associated with site clearing, demolition, grading, roads, walking areas, and fences.

- Land –the cost for the purchase of all necessary property and survey fees.

 Indirect Capital Costs

- Engineering contracts –the cost for process design and general engineering, cost engineering, consulting fees, supervision, and inspections.

- Contingency –the cost that may result from incomplete design, unforeseen and unpredictable conditions, or the complexity and uncertainties involved in cost estimating at a conceptual level.

- Construction –the cost for temporary construction offices, roads, communications, fencing, construction tool s and equipment, permits, taxes, and insurance.
The specific capital cost elements evaluated for each technology opti on are detailed in the following chapters.
Operating and maintenance costs include all costs associated with operating and maintaining the system on a day-to -day basis. These types of expe nses include labor, materials, energy, and chemicals. EPA used the followi ng cost components to estimate O&M costs associated with each tech nology option, as appropriate:

 Operating labor – the labor costs for plant staff to operate the treatment or handling system.

 Maintenance labor – the labor costs for plant staff to maintain the treatment or handling system.

 Maintenance materials – the costs associated with r outine replacement of materials and equipment due to consum ption or wear and tear.

 Energy –the cost for the energy used to operate equipment associated with the system, including pumps, mixers , and other equipment.

 Chemicals –the cost for all chemical additive s used in the treatment or handling system.
The specific O&M cost elements evaluated fo r each technology opti on are detailed in the following chapters.
In addition to one-time capital costs a nd annual O&M costs, EPA also evaluated recurring costs that occur less frequently th an once a year. These recurring costs include expenses for items that need to be purchased every few years. EPA assessed recurring costs for equipment purchased every 3, 5, 6 or 10 years based on the requirements of the technology option. These cost elements are listed separately in each cost output and are detailed in the appropriate technology option chapters.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-3 5.2 C OMPLIANCE M ONITORING C OST M ETHODOLOGY
Where a regulatory option would establish requirements for pollutants not currently regulated in the existing ELGs, EPA calculate d plant-level compliance monitoring costs for plants to sample and analyze th eir discharges to assess their co mpliance with proposed effluent limitations. Compliance monitoring costs includ e costs for sampling and analysis of FGD wastewater and leachate effluent discharges. Note that there are no compliance monitoring costs for the conversion from wet fly ash and bottom ash systems to dry systems because these conversions eliminate the discha rge of ash tran sport water.

5.2.1 Monitoring Requirements
Monitoring requirements for FGD wastewater and leachate effluent discharges differ by treatment technology used: 10

Chemical precipitation . For each plant that discharges FGD wastewater and/or leachate, EPA estimated costs for weekly analysis for arsenic and mercury. Costs are included as a chemical precipitation O&M cost.
Chemical precipitation follo wed by biological treatment . For each plant that discharges FGD wastewater and/or leachate, EPA estimated co sts for weekly analysis for arsenic, selenium, and mercury. 11,12 Costs are included as a bi ological treatment O&M cost.
Chemical precipitation followed by vapor-compression evaporation . For each plant that discharges FGD wastewater, EPA estimated costs for weekly analysis for arsenic, selenium, mercury, and total dissolved solids. Costs are considered as a vapor-c ompression evaporation O&M cost.

5.2.2 Capital Cost Methodology
EPA did not include costs to purchase cap ital equipment for compliance monitoring associated with the proposed ELGs because power plants covered under the requirements of 40 CFR 423 already own and/or operate sampli ng equipment for effluent monitoring.

5.2.3 O&M Cost Methodology
Compliance monitoring O&M costs were calculated using Equation 5-1.

10 EPA is proposing to set limits on arsenic, mercury, selenium, and total dissolved solids for IGCC wastewater. EPA will include monitoring costs associated with these pollutants for the final rule. EPA expects these monitori ng costs to be roughly 63,000 dollars per plant.

11 EPA is proposing to set limits on arsenic, selenium, merc ury, and nitrate/nitrite for FGD wastewater under options based on biological treatment. EPA is also proposing to set limits on arsenic and mercury for landfill leachate under options based on chemical precipitation. In cases where FGD wastewater and leachate are treated using the same treatment system, the more stringent limits requirements will apply. As a result, plants discharging both FGD wastewater and leachate and FGD wastewater alone are assessed monitoring costs for arseni c, selenium, and mercury. Plants discha rging only landfill leachate are assessed monitoring costs for arsenic and mercury.

12 EPA is proposing to set limits on arsenic, selenium, merc ury, and nitrate/nitrite for FGD wastewater under options based on biological treatment. EPA will include mon itoring costs associated with nitrate/nitr ite for the final rule. EPA expects these a dded monitoring costs to be approxima tely $1,664 per plant annually.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-4 Compliance Monitoring Cost (2010$/yr) = Sampling Labor Cost + Sampling Materials Cost + Sample Shipping Cost + Sample Analysis Cost (5-1)

where:

Sampling Labor Cost = The cost associat ed with the plant labor required to conduct the sampling activit ies (see Section 5.2.3.1), Sampling Material Cost = The cost of mate rials needed to colle ct and preserve the wastewater samples (see Section 5.2.3.2), Sample Shipping Cost = The cost of sh ipping the wastewater samples to the laboratory for analysis (see Section 5.2.3.3), and Sample Analysis Cost = The cost to an alyze wastewater samples (see Section 5.2.3.4).

For plants that discharge both FGD wastewat er and leachate, EPA calculated compliance monitoring costs for both wastestreams, based on the assumption that the wastewaters are generated at separate locations and are not commingled for discharge (i.e., 2 × Compliance Monitoring Cost (2010$/yr)).

5.2.3.1 Sampling Labor Cost
Sampling labor costs are those associated with plant personn el collecting and analyzing wastewater samples. EPA assumed that each wa stestream would be sampled weekly, with two operators needed to collect the samples using the protocol s in EPA Method 1669. EPA assumed that the operators would collect samples at onl y one location for each wastestream because the additional monitoring requirements associated with the proposed ELGs will only be applied at one location per wastestream. Table 5-1 (located at the end of the chapter) lists the estimated sample labor requirements (in hours per year (hr/ yr)) overall and by task by type of plant staff.
EPA calculated the sampling labor cost by mu ltiplying the annual number of labor hours by the labor rate. EPA determined a wastewater treatment system operator labor rate of [Redacted] (2009$) based on the median operating la bor rate reported in responses to Question D6-2 of the Steam Electric Survey by plants th at operate FGD wastewater chemical precipitation treatment (with and without subsequent bi ological or vapor-compression evaporation treatment). 13 EPA determined a plant environmental coordinator labor ra te of $37.04/hr (2010$) based on the U.S. Bureau of Labor Statistics da ta for environmental engineers [U.S. Bureau of Labor Statistics, 2010]. As the operator labor ra te was provided in 2009 dollars, the cost basis was adjusted to 2010 dollars using the 2009 a nd 2010 RSMeans Historical Cost Indices (180.1 and 183.5, respectively) [RSMeans, 2011].

13 The wastewater operator labor rate of [Redacted] is th e median FGD wastewater treat ment operator labor rate based on survey data in 2009$. EPA will index the value ap propriately with cost index data from RS Means for the final rule.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-5 Sampling Labor Cost (2010$/yr) = (Operator Labor Rate × Operat or Hours × 2010 Cost Index/2009 Cost Index) + (Environm ental Coordinator Labor Rate × Environmental Coordina tor Hours) = [Redacted] (5-2)

where:

Operator Labor Rate = [Redacted] (2009$), Operator Hours = 364 hr/yr (see Tabl e 5-1 located at the end of the chapter),
Environmental Coordinator Labor Rate = $37.04/hr (2010$),

Environmental Coordinator Hours = 18 hr/yr (see Table 5-1 located at the end of the chapter), 2009 Cost Index = 180.1, and
2010 Cost Index = 183.5.

5.2.3.2 Sampling Material Cost
Sampling material and supply costs are the costs associat ed with the materials and supplies, such as personal protective equipmen t, sampling containers, and other supplies, required for plant personnel to co llect and analyze samples. Table 5-2 (located at the end of the chapter) provides a detailed list of sampling ma terials and their costs (in 2010$/sampling event). EPA estimated the annual sampling material cost by multiplying the sampling materials cost per sampling event by the number of sampling events per year. As all sampling material costs were provided by vendors in 2011 dollars, the cost ba sis was adjusted to 2010 dollars using the 2010 and 2011 RSMeans Historical Co st Indices (183.5 and 185, re spectively) [RSMeans, 2011].

Sampling Materials Cost (2010$/yr) = Sampling Ma terials Cost Per Event × Annual Number of Sampling Events × (2010 Cost Index/2011 Cost Index) = $22,194 or $22,246 14 (5-3)

where:

Sampling Materials Cost per Event = $430.30/sampling event (2011$), except vaporcompression evaporation, $431.30/sampling event (2011$), (see Table 5-2 located at the end of the chapter), 15

Annual Number of Sampling Events = 52 sampling events/yr,

14 Costs for chemical precipitation syst ems and biological treatment system s are $22,194 while costs for vaporcompression evaporation systems are $22,246.

15 There are additional costs for the vapor-compression eva poration system because of the additional bottle needed to analyze for TDS.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-6 2010 Cost Index = 183.5, and
2011 Cost Index = 185.

5.2.3.3 Sample Shipping Cost
EPA estimated the costs for shipping the samp les to laboratories using the cost of a sample shipment and the total number of sample shipments per year and that samples would be sent to two different laboratories, one for analys is of low-level mercury and one for analysis of other metals. EPA assumed that one of the laborato ries would be able to analyze the samples for total dissolved solids and nitrate/nitrite. EPA assumed that each sample shipment to each laboratory would cost $40. As vendors provided sample shipping costs in 2011 dollars, the cost basis was adjusted to 2010 do llars using the 2010 and 2011 RSM eans Historical Cost Indices (183.5 and 185, respectively) [RSMeans, 2011]. EPA estimated sample shipment costs using the Equation 5-4.

Sample Shipping Cost (2010$/yr) = Sample Shipme nt Cost × Number of Sample Shipments per Event × Annual Number of Sampling Events × (2010 Cost Index/2011 Cost Index) = $4,126 (5-4)

where:

Sampling Shipment Cost = $40/shipment (2011$), Number of Sample Shipments per Event = 2 per event,

Annual Number of Sampling Events = 52 sampling events/yr,

2010 Cost Index = 183.5, and
2011 Cost Index = 185. Sampling Shipment Cost = $40/shipment (2011$),

5.2.3.4 Sample Analysis Cost
EPA calculated sample analysis costs using th e cost of analyzing each sample that would be collected per sampling event and the number of sampling events per year. EPA based the sample analysis costs on the costs the Agency incurred during its field sampling program. Table 5-3 (located at the end of the ch apter) provides a detailed list of sample analyses and their costs (in 2010$/sampling event). EPA estimated the annual sample analysis cost by multiplying the sample analysis cost per sampling event by the nu mber of sampling events per year as shown by the equation below. Because sample analysis costs were provided by vendors in 2011 dollars, the cost basis was adjusted to 2010 dollars us ing the 2010 and 2011 RSMean s Historical Cost Indices (183.5 and 185, resp ectively) [RSMeans, 2011].Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-7 Sample Analysis Cost (2010$/yr) = Sample Analysis Cost Per Event × Annual Number of Sampling Events × (2010 Co st Index/2011 Cost Index) = $16,247 or $16,763 16 (5-5)

where:

Sample Analysis Cost per Event = $315/sampling event (2011$), except vaporcompression evaporation, $325/sampling event (2011$), (see Table 5-3 located at the end of the Chapter), 17

Annual Number of Sampling Events = 52 sampling events/yr,

2010 Cost Index = 183.5, and

2011 Cost Index = 185.

5.3 T RANSPORTATION C OST M ETHODOLOGY
Steam electric power plants can reuse, marke t/sell, or give away combustion residuals. Alternatively, plants can transpor t combustion residuals to a dispos al site (e.g., la ndfill). For the proposed ELGs, EPA conservatively included costs for plants to transpor t all solid waste to a landfill because not all plants have the means to market/sell or give away the combustion residuals. For plants that are capable of mark eting the combustion residuals, EPA’s estimated compliance costs will be overestimated for the following reasons:

 The estimated compliance costs include costs for transporting the solid waste to an on- or off-site landfill, which may not be needed depending on location and timing of the beneficial reuse; and

 The estimated compliance costs do not acc ount for the additiona l revenue stream generated from selling the solid waste.

5.3.1 Technology Description
All combustion residuals (i.e., fly ash, botto m ash, and FGD wastewat er treatment solids) can be transported to on-site or off-site landfills in an open dump truck. For plants with existing on-site landfills already containing combustion re siduals, EPA included costs to dispose of any additional combustion residuals resulting from comp liance with the ELGs in an on-site landfill, by either expanding the existing landfill or building a new landfill to accommodate the additional waste. For plants that do not have existing on-site la ndfills (or their on-site landfills do not

16 Costs for chemical precipitation syst ems and biological treatment system s are $16,247 while costs for vaporcompression evaporation systems are $16,763.

17 There are additional costs for the vapor-compression eva poration system because of the additional analysis for TDS. Also note that the costs for the analysis of the metals is likely overestimated because during EPA’s sampling program, EPA analyzed for a suite of metals, but the plan ts will only be required to analyze for one or two of the metals (depending on wastestream), which should result in a reduced cost for the metals analyses.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-8 contain combustion residuals), EPA included co sts to dispose of the additional combustion residuals in an off-site non-hazardou s landfill.

5.3.2 Cost Inputs
EPA used Steam Electric Survey data to id entify which plants ha ve existing on-site landfills containing combustion residuals. For al l plants identifying at least one open landfill containing combustion residuals in Part A Sectio n 4 (Landfills) of the Steam Electric Survey, EPA estimated compliance costs for on-site trans portation of ash and FGD solids. For all other plants (i.e., those without an open landfill c ontaining combustion residuals), EPA estimated compliance costs for off-site transportation of the ash and FGD solids. The flags for whether a plant has an on-site or off-site landfill are contained in the “T ransportation Input Table” within the cost model.
EPA based plant-level compliance costs fo r transporting combus tion residuals on the total amount of incremental waste generated at each plant associated with the proposed options. The technology cost modules associated with ea ch treatment technology (i.e., fly ash, bottom ash, one-stage chemical precipitation, one-stage chem ical precipitation with biological treatment, and one-stage chemical precipitation with vapor-c ompression evaporation) calculate the tonnage of incremental moisture-conditioned combustion resi duals requiring disposal in a landfill at the plant level. See the discussion fo r the individual technology options for more detail on the solids generated by each treatment technology in Chapters 6, 7, 8, and 9. The output of these technology cost modules is used as the input for the transportation t echnology cost module.

5.3.3 Cost Methodology
Both the on-site and off-site transportation cost methodologies use cost equations based on the dry tonnage of waste requiring disposal for each treatment technology. EPA used the following bulk density values to convert the wet tonnage valu es that are output from the individual technology cost modules to a dry tonnage value that c ould be used in the Transportation Cost Module:

 EPA estimated the bulk density of FGD wastewater treatment solids to be 74.6 pounds per cubic foot (estimated based on 50 percent density of water and 50 percent density of hydrated lime); and

 EPA estimated the bulk density of fly as h and bottom ash to be 45 pounds per cubic foot (based on input from Clyde Bergem ann Power Group (CBPG, formerly Delta Ducon) for dry ash). 18

5.3.3.1 On-Site Transportation Cost Methodology
EPA assumed that plants identified in the “Transportation Input Ta ble” as having on-site landfills would continue to dispose of any additional combustion residual in the same on-site

18 EPA made the following assumptions: the moisture of the fl y ash as transported will be 13 percent, as determined from survey data (the median value re ported in Table C-6) and the moisture of the bottom ash transported will be 20 percent, as determined from survey data (the median value reported in Table C-23).Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-9 landfill. EPA estimated transportation costs for plants with an on-site landfill using the estimated amount of solid waste (i.e., moistened fly ash, moistened bottom ash, and/or FGD wastewater treatment solids) and an on-site specific unitized cost value, in dollars per ton, based on information provided by EPA’s Office of Re source Conservation and Recovery (ORCR) developed using the Remedial Action Cost Engineering Requirements (RACER) software version 10.4. EPA used a cost of $3.257 in 2011 do llars per ton for tran sporting solid waste a distance of one mile one way to an on-site la ndfill. EPA confirmed ORCR’s assumption of a one mile one way transport distance is consistent with the median distance to an on-site landfill of 1.3 miles reported by respondents to the Steam Elect ric Survey. EPA deflated this dollar per ton value to 2010 dollars using the 2010 and 2011 RSM eans Historical Cost Indices. Equation 5-6 estimates the total cost for transporting combustion residual waste to an on-site landfill.
Total Cost (2010$) = Dry tons × 3.257 ($ /ton) × (2010 Cost Index/2011 Cost Index) (5-6)

where:

Dry tons = The dry volume of wa ste being transported to an onsite landfill in tons per year, 2010 Cost Index = 183.5, and

2011 Cost Index = 185.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A65) for details on the development of Equation 5-6.

5.3.3.2 Off-Site Transportation Cost Methodology
EPA assumed that plants identified in the “Transportation Input Ta ble” as not having an on-site landfill would dispose of any combustion residual in an off-site landfill. EPA used the RACER 2010 model to estimate the cost of tran sporting moistened fly ash, bottom ash, and/or FGD wastewater treatment so lids. Using RACER, EPA calculated a cost of $9.234 in 2011 dollars per ton to transport solid waste a one-way distance of 25 miles to an off-site landfill. EPA deflated this dollar pe r ton value to 2010 dollars using th e 2010 and 2011 RSMeans Historical Cost Indices. Equation 5-7 estimates the total cost for transportation of solid waste to an off-site landfill.
Total Costs (2010$) = Dry tons × 9.234 ($/to n) × (2010 Cost Index / 2011 Cost Index) (5-7)

where:

Dry tons = The dry volume of wast e being transported to an offsite landfill in tons per year, 2010 Cost Index = 183.5, and

2011 Cost Index = 185.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-10 See the Supplemental Costs and Loadings Documentation (DCN SE01825.A65) for details on the development of Equation 5-7.

5.4 D ISPOSAL C OST M ETHODOLOGY
As described in Section 5.3.1, EPA conservatively determined costs for plants to dispose of combustion residuals requiring disposal in a landfill to comply with the ELGs. EPA estimated costs for on-site or off-site disposal based on th e flags from the “Transportation Input Table.” To the extent plants are able to market/sell thes e residuals, EPA has overestimated the costs of disposal and has not acc ounted for revenue associat ed with other options.

5.4.1 Technology Description
EPA estimated capital and O&M disposal costs for an on-site landfill. Capital costs include the construction of th e landfill, liner, additional groundwater monitoring, leachate collection system, and closures associated with the expansion of an existing landfill. EPA used a unitized cost value (in dollar per ton) that represents the capita l cost components for an onsite landfill and the estimated amount of solid wa ste produced from the implementation of technology options. EPA used a similar unitized cost approach to estimate the O&M costs based on the estimated amount of additional solid wast e produced and a unitized cost value (in dollar per ton), that represents the costs associated with operating the landf ill. The cost methodology addresses both capital costs a nd O&M costs associated with onsite disposal (see Section 5.4.3.1 for more detail).

Costs associated with off-site landfills are limited to the fee associated with using the landfill, also known as the tipping fee, which is discussed in more detail in Section 5.4.3.2.

5.4.2 Cost Inputs
The cost inputs used to calculate on-site and off-site disposal costs are similar to those used in the transportation cost module. The flags for on-site or off-site landfill from the “Transportation Input Table” are used to determine wh at type of disposal co st each plant will be assessed. The dry waste tonnage for each wastes tream, calculated in the transportation cost module, is also used as an i nput for the disposal costs.

5.4.3 Cost Methodology

5.4.3.1 On-Site Disposal Cost Methodology
The cost methodologies presented in this section discuss the ca pital and O&M costs associated with expanding an on-site landfill. EPA found that there was limited costing data associated with landfill construction/expansi on provided in response to the Steam Electric Survey data. And for the limited data that was provided, EPA was unable to determine the specific elements that were included as part of the landfill construction/ expansion. As a result, EPA used information from a 2009 planning-lev el cost estimate pr epared by CH2MHILL for construction, operation, and closure costs associ ated with a 7-acre expa nsion of an existing landfill in Hilo, HI [CH2MHILL, 2009]. EPA used the cost estimate from the CH2MHILL studyChapter 5 –General Methodology, Terminology, and Common Cost Elements

5-11 because it includes the most recent data in th e most useful format. EPA searched for other costing data in the Steam Electric Survey and se arched other publicly av ailable data, but these sources did not include cost estimates to c onstruct/expand a landfill that includes a liner, groundwater monitoring, a nd leachate collection.

Capital Costs In the cost estimate prepared by CH2MHILL, the capital costs include construction of the landfill, liner, additional groundwater monitoring, leachate collection system and closures. Table 5-4 (located at the end of the chapter) summarizes the high and low capital costs included in the study. The costs presented in the CH2MHILL study represent a 7-acre expansion for an added capacity of 328,000 tons of solid waste. EPA calcula ted a high and low capital cost per ton of waste based on the data provide d in the study. Capital costs fo r the landfill expansion ranged from $19.52 per ton to $28.85 per ton.
Using the high cost estimates from the CH2MHILL study and the RSMeans Historical Cost Index to index costs from 2009 to 2010, EPA us ed Equation 5-8 to estimate the capital costs for disposing of additional solid waste in an on-site landfill.
Total Capital Costs (2010$) = Dry tons × 28.85 ($/ton) × (2010 Cost Index / 2009 Cost Index) (5-8)

where:

Dry tons = The dry volume of wast e being transported to an offsite landfill in 2009 in tons, 2010 Cost Index = 183.5, and
2009 Cost Index = 180.1.

O&M Costs Similar to capital costs, EPA used the 2009 cost estimate from CH2MHILL to estimate the O&M costs associated with expanding a landfill. Table 5-5 (located at the end of the chapter) summarizes the high and low O&M costs included in the study. Using these costs along with the total added capacity of 328,000 tons of solid wa ste, EPA calculated a high and low O&M cost per ton of waste. O&M costs for the landfill ex pansion ranged from $6.12 per ton to $8.04 per
ton.
Using the high cost estimate from the study and the RSMeans Historical Cost Index to index costs from 2009 to 2010, EPA used Equation 5- 9 to estimate O&M costs for disposing of additional combustion residual solid waste in an onsite landfill.
Total O&M Costs (2010$) = Dry tons × 8.04 ($ /ton) × (2010 Cost Index / 2009 Cost Index) (5-9)Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-12 where:

Dry tons = The dry volume of wast e being transported to an offsite landfill in tons per year, 2010 Cost Index = 183.5, and
2009 Cost Index = 180.1.

5.4.3.2 Off-Site Disposal Cost Methodology
EPA assumed that plants not having an on-site combustion residual la ndfill will transport any additional solid waste to an off-site landfi ll. The tipping fees associated with disposal in these off-site landfills is generally assessed on a per-ton-of-waste basis. To estimate the cost incurred by each plant, EPA calcu lated a weighted average national tipping fee to apply to all plants expected to incur off-site disposal fees. EPA used state-le vel tipping fees and calculated a national weighted average based on the total combustion residual disposed in off-site landfills by each state as identified in the Steam Electric Su rvey, assuming all plants would likely dispose of their solid waste in the same state in which they are located. The cost for off-site disposal of solid waste was calculated to be $40.99 per ton in 2011 dollars. This value was indexed to 2010 dollars using the RSMeans Historical Cost Indice s. Equation 5-10 estimates the cost of disposing of additional solid waste in an offsite landfill.
Total Costs (2010$) = Dry tons × 40.99 ($ /ton) × (2010 Cost Index / 2011 Cost Index) (5-10)

where:

Dry tons = The dry volume of wast e being transported to an offsite landfill in tons per year, 2010 Cost Index = 183.5, and

2011 Cost Index = 185.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A66) for details on the development of Equation 5-10.

5.5 S URFACE I MPOUNDMENT O PERATION C OSTS M ETHODOLOGY
Implementation of the technology options will reduce, and in some cases eliminate, the management of FGD wastewater, ash transport water, and combustion residuals in on-site impoundments. EPA therefore expects plants wi ll experience cost savings in operating these impoundments. To calculate the incremental cost savings that may be realized under the technology options, EPA estimated the annual O&M and recurring costs associated with managing these wastewaters and combustion resi duals in on-site impoundments. EPA estimated annual O&M and 10-year recurri ng costs associated with im poundment operations using the equations provided in this section.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-13 5.5.1 Technology Description
To calculate the incremental compliance cost of the technology options, EPA estimated the annual O&M and recurring costs associat ed with managing these wastewaters and combustion residuals in on-site impoundments. Additionally, EPA estimated capital costs associated with some waste water discharg es identified as new sources. See ERG’s memorandum “New Source Performance Sta ndards (NSPS) Costing Memorandum” (DCN SE02129) for the specific new source capital cost equations associated with impoundment operations.
Surface impoundments are designed to remove particles from wastewater using gravity sedimentation. Plants pump FGD slurry blowdo wn, fly ash transport water, and bottom ash transport water through pipes from the FGD sc rubber, fly ash hoppers, and bottom ash hoppers, respectively, to surface impoundments for treatment. After the plant pumps the wastewater(s) to the impoundment, the combustion resi dual solids fall out of suspensi on and settle near the front end of the impoundment. The overflow from the impoundment is either discharged to surface water, transferred to a public ly owned treatment works (POTW) , or recycled back to plant operations. Some plants operate a ch emical addition system to adjust the pH prior to discharge or recycle. Many plants dredge the combustion residua l solids in the impoundme nt for disposal in a landfill. Additionally, some plants use the combus tion residual solids as part of the impoundment design (e.g., placing solids in st acks both dewater the solids a nd to redirect the flow of wastewater through an impoundment based on plan t design). Plants use different types of earthmoving equipment to remove these solids from the impoundment (e.g., backhoe, front-end loader).
For each technology option evaluated, EPA es timated the amount of wastewater or combustion residuals no longer expected to be managed in on-site impoundments and the associated cost savings. Impound ment O&M costs are the costs a ssociated with operating the:

 Wastewater transport system (i.e., pipelines , vacuum source) pumping the wastewater from the FGD scrubber or ash hoppers to the impoundment;

 Impoundment site (i.e., general operation of the impoundment, removing/stacking of combustion residual materials, inspections);

 Wastewater treatment system (e.g., pH control); and

 Water recycle system at the impoundment (if applicable).
Earthmoving O&M costs are the costs asso ciated with operating the earthmoving equipment the operation of earthmoving e quipment (i.e., backhoe) required for removing/stacking combustion residual materials at the impoundment site. EPA also identified recurring costs for earthmoving equipment associated with re placing the specific type of equipment (i.e., the backhoe).

5.5.2 Input Table
EPA used Steam Electric Survey data to identify plants that have at least one impoundment, not designated as re tired or planned, containing at least one type of combustionChapter 5 –General Methodology, Terminology, and Common Cost Elements

5-14 residual. Using data from the Steam Electric Survey, EPA flagged the specific type(s) of combustion residual(s) (e.g., FGD solids, fly as h, bottom ash) reported to be stored in impoundments at the plant. EPA calculated increm ental impoundment operating costs for plants reporting at least one impoundme nt, containing combustion resi duals, in Part A Section 3 (Ponds/Impoundments) of the Steam Electric Surve y. EPA calculated these co sts as part of the total compliance costs for FGD wastewater, fly ash, and bottom ash. That is, incremental impoundment operating costs are included in the compliance cost estimates for each separate wastestream evaluated at the plant depending on th e types of combustion residuals stored in the impoundment. For example, if a surface impoundment is flagged as containing FGD wastes and bottom ash, EPA estimated the amount of FGD solid s and bottom ash solids are transferred to the impoundment (in tons) and evaluated impoundment savings for FGD solids as part of the FGD compliance cost estimates and evaluated im poundment savings for bottom ash as part of the bottom ash compliance cost estimates. The flag s for the presence of one or more combustion residual impoundments are included in the “Surfa ce Impoundment Input Table.” A copy of this input table is includ ed in the appendix.
EPA estimates plant-level costs for operat ing combustion residua l impoundments based on the total amount of combustion residuals curren tly handled wet at the plant. EPA estimated the total amount of fly ash and bottom ash wastes using the total amount of wet ash conveyed in 2009 using data in response to the Steam Electri c Survey (Tables C-2 and C-18). EPA estimated the total amount of FGD solids handled wet using the FGD wastewater flow rate (in gallons per day (gpd)) and the average total suspended so lids (TSS) concentration from EPA’s Field Sampling Program. See Section 5.5.3.1 for the speci fic equation used to estimate FGD solids in the wastewater.

5.5.3 Cost Methodology
EPA estimated the incremental impoundment and earthmoving O&M and recurring costs using information in reports summarizing two EPA studies evaluating the economics of waste disposal at coal-fired po wer plants: U.S. EPA/TVA Economics of Ash Disposal at Coal-fired Power Plants (1981) and U.S. EPA Full-Scaled Field Evaluation ofWaste Disposal from Coalfired Electric Generating Plants (1985). EPA determined that a combination of the data presented in both studies could be used to estimate the O&M and recurring costs associated with operating a combustion residual impoundment. EPA selected both data sources to combine unitized cost (annual dollars per ton of ash) information with information on how costs vary based on plant size (megawatts (MW)).

5.5.3.1 Impoundment O&M Costs
EPA estimated the incremental impound ment O&M costs using Equation 5-11.
Total O&M Impoundment Costs = (-1) x (Impound ment Operating O&M Costs + Impoundment Earthmoving O&M Costs) (5-11)Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-15 where:

Impoundment Operating O&M Costs = Incremental impoundment operating costs, and

Impoundment Earthmoving O&M Costs = O&M cost associated with the incremental earthmoving equipment required.

Impoundment Operating O&M Costs EPA estimated the incremental impoundment operating costs for all applicable combustion residuals at the plant using the plan t MW factor described in Section 5.5.3.4 and the calculated combined ash unitized cost values for impoundment operating costs described in Section 5.5.3.2 and presented in Table 5-7 (located at the end of the chapter).
First, EPA calculated the plant-specific si ze factor, based on plant size in MW, and the plant-specific unitized cost. The values for thes e equations were developed using the two reports described in Section 5.5.3. The plan t-specific size factor is calcul ated using Equation 5-26 and is used along with the impoundment operating un itized cost, discussed in Section 5.5.3.2, to calculate the plant-specific uni tized cost using Equation 5-12.
Plant-Specific Unitized Cost = (Impoundment Operating Unitized Cost) × (Plant MW Factor) (5-12)

where:

Impoundment Operating Unitized Cost = The 2010 unitized annual cost to operate a combustion residual impoundment presente d in Table 5-7 (located at the end of the chapter). EPA used the unitized cost value $7.35 per ton of com bustion residual for all combustion residuals. See Section 5.5.3.2 for a more detailed description of the unitized cost values, and Plant MW Factor = Factor to adjust combination residual handling costs based on plant capacity. See Equation 5-26.

Next, EPA calculated the incremental impoundme nt operating costs for each applicable type of combustion residual at the plant. Fo r FGD impoundment operating costs, EPA estimated the amount of combustion residuals (in tons) usi ng FGD wastewater flow, in gpd, and an average TSS concentration from EP A’s Field Sampling Program.
Fly Ash Impoundment Operating Costs ($/yr)= (-1) x (Plant Specific Unitized Cost) × (Conditioned Dry Fly Ash for Disposal) (5-13)

Bottom Ash Impoundment Operating Costs ($/yr)= (-1 ) x (Plant Specific Unitized Cost) × (Plant Bottom Ash Tonnage) (5-14)Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-16 FGD Impoundment Operating Cost s ($/yr) = (-1) × (Plant Specific Unitized Cost) × [(FGD Wastewater Flow) × (Average TSS Concentr ation) × (3.785 L/gal) x (0.001 g/mg) × (1.102 x 10 -6 tons/g) x (365 dpy)] (5-15)

Total Impoundment Operating O&M Costs ($/y r)= Fly Ash Impoundment Operating Costs + Bottom Ash Impoundment Operating Cost s + FGD Impoundment Operating Costs (5-16)

where:

Conditioned Dry Fly Ash for Disposal = The total fly ash tonnage, dry basis, for each plant in tons per year (tpy). This value is calculated by multiplying the wet fly ash generation rate (in tons per day (tpd)) by the wet fly ash conveying days (in days per year (dpy)) for each unit, and then summing the unit level values to the plant level. These values are used in the transport and disposal fly ash methodology, as described in Section 7.1.7,
Plant Bottom Ash Tonnage = The total bottom ash tonnage, dry basis, for each plant in tons per year. This value is calculated by multiplying the wet bottom ash generation rate (in tpd) by the wet bottom ash conveying days (in dpy) for each unit, and then summing the unit level values to the plant level. These values are used in the transport and landfill bottom ash methodology, as described in Section 8.3,
FGD Wastewater Flow = F GD wastewater flow rate in gpd as reported in the Steam Electric Survey (see Section 4.1.1), and Average TSS Concentration = The average influent TSS concentration, in milligrams per liter (mg/L), for FGD wastewater treatment influent sampled as part of the EPA Steam Electric Rulemaking effort. These data also include long-term monitoring data from all applicable plants. The average FGD wastewater influent TSS concentration value is 16,513 mg/L.

Impoundment Earthmoving Equipment O&M Costs
EPA estimated the incremental earthmovi ng equipment costs for all applicable combustion residuals at the plant using the plan t MW factor described in Section 5.5.3.4 and the calculated 2010 unitized co st value associated with a front-e nd loader described in Section 5.5.3.3.
First, EPA calculated the plant-specific si ze factor, based on plant size in MW, and the plant-specific unitized cost. The values for thes e equations were developed using the two reports described in Section 5.5. The plant- specific size factor is calculat ed using Equation 5-26 and is used along with the front-end loader unitized co st, discussed in Section 5.5.3.3, to calculate the plant-specific unitized co st using Equation 5-17.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-17 Plant-Specific Front-End Loader Unitized Cost ($/ton) = (Front-End Loader 2010 Unitized O&M Cost) × (Plant MW Factor) (5-17)

where:

Front-End Loader 2010 Unitized O&M Cost = The 2010 unitized cost value that represents the operation and maintenance of the front-end loader used to redistribute ash at an impoundment. This value was calculated to be $2.49 $/ton, and Plant MW Factor = Factor to adjust combination residual handling costs based on plant capacity. See Equation 5-26.

Next, EPA calculated the incremental ear thmoving O&M costs for each applicable combustion residual at the plant. For FGD im poundment operating cost s, EPA estimated the amount of combustion residuals (in tons) using th e plant’s FGD wastewater flow, in gpd, and an average TSS concentration from EPA’s Field Sampling Program.

Fly Ash Impoundment Earthmoving Costs = (-1) × (Plant-Specific Front-End Loader Unitized Cost) × (Conditioned Dry Fly Ash for Disposal) (5-18)

Bottom Ash Impoundment Earthmoving Costs = (-1) × (Plant-Specific Front-End Loader Unitized Cost) × (Plant Bottom Ash Tonnage) (5-19)

FGD Impoundment Earthmoving Costs = (-1) × (Plant-Specific Front -End Loader Unitized Cost)

× [(FGD Wastewater Flow) x (Average TSS Co ncentration) × (3.785 L/gal) × (0.001 g/mg) × (1.102 x 10 -6 tons/g) × (365 dpy)] (5-20)

Total Impoundment Earthmoving O&M Costs = Fly Ash Impoundment Operating Costs + Bottom Ash Impoundment Operating Cost s + FGD Impoundment Operating Costs (5-21)

where:

Conditioned Dry Fly Ash for Disposal = The total fly ash tonnage, dry basis, for each plant in tpy. This value is calculated by multiplying the wet fly ash generation rate (in tpd) by the wet fly ash conveying days (in dpy) for each unit, and then summing the unit level values to the plant level. These values are used in the tran sport and disposal fly ash methodology, as described in Section 7.1.7.,
Plant Bottom Ash Tonnage = The total bottom ash tonnage, dry basis, for each plant in tpy. This value is calculated by multiplying the wet bottom ash generation rate (in tpd) by the wet bottom ash conveying days (in dpy) for each unit, and then summing the unit-level values to the plant-level. These values are used in the transport and landfill bottom ashChapter 5 –General Methodology, Terminology, and Common Cost Elements

5-18 methodology, as described in Section 8.3,

FGD Wastewater Flow = F GD wastewater flow rate in gpd as reported in the Steam Electric Survey (see Section 4.1.1), and Average TSS Concentration = The average influent TSS concentration, in milligrams per liter (mg/L), for FGD wastewater treatment influent sampled as part of the EPA Steam Electric Rulemaking effort. These data also include long-term monitoring data from all applicable plants. The average FGD wastewater influent TSS concentration value is 16,513 mg/L.

5.5.3.2 Impoundment Unitized O&M Costs
This section explains how EPA calculated the impoundment operating unitized cost (in $/ton) used in the equations to estimate impoundment O&M costs described in Section 5.5.3.1. EPA calculated impoundment O&M cost s using unitized cost data pr ovided in U.S. EPA/TVA’s 1981 study report. The 1981 U.S. EPA/TVA study is a report that compares capital and O&M costs for five different methods of ash disposal at a 500 MW co al-fired power plant. For the impoundment unitized cost values, EPA used the costs in the 1981 U.S. EPA/TVA study associated with the wet sluicing of ash to a su rface impoundment without water recycle scenario described in the study [U.S. EPA/TVA, 1981]. EPA us ed the cost and ash tonnage data from the 1981 study to calculate a unitized cost (dollar pe r ton) that includes costs for annual O&M only (excluding annualized capital cost s, inflation, and discounts over time) based on combined ash tonnage. The study provides unitized costs associated with the following modular process areas:

 Collection : includes the ash hoppers, a portion of the water supply systems, and the fly ash pneumatic systems including the vacuum producers;

 Transportation : includes the air separators, a po rtion of the water supply systems, the ash pumps, the pipeline systems, trucks , the storage silos and moisturizers, the bottom ash dewatering bins, and the remova l of ash from temporary impoundments;

 Disposal Site : includes the impoundments and landfills, including all mobile equipment except that used to load and haul ash; and

 Water Treatment and Recycle : includes the treatment systems, pumps and return lines, and the bottom ash water systems.
For fly ash impoundments, EPA used the annual O&M data for all process areas excluding (1) collection. EPA ex cluded the collection process area because the operation and maintenance associated with ash will still occu r even after implementation of the proposed rule (i.e., there is no cost savings). This unitized cost includes the annual O&M for conveying the fly ash from the hopper to the impoundme nt, and any wastewater treatment necessary for discharge.
For bottom ash impoundments, EPA used the annual O&M data for all process areas excluding (1) collection and (2 ) transportation. EPA defines the conveyance portion of the system to include sluicing equipment, asso ciated piping, and pumps in the Steam ElectricChapter 5 –General Methodology, Terminology, and Common Cost Elements

5-19 Survey; the 1981 study defined these same proce ss components as the transportation process area. EPA excluded the transportation process area based on the characteristics of the two technology operations evaluated for bottom ash, as described in the following paragraph.
The two technology options EPA considered fo r bottom ash transport water include the mechanical drag system (MDS) and the remote MDS. Both systems use the same equipment for handling bottom ash. However, the remote MDS c ontinues to operate the existing transportation portion of the wet sluicing system (i.e., pumps, pipeline systems) to transport the bottom ash sluice to a remote MDS, compared to the MDS th at is located directly underneath the boiler and doesn’t require the use of the existing sluice system (see Sections 8.1.1 and 8.2.1). Because the main difference between the two t echnology options is the sluice syst em used to transport ash to the remote destination, EPA included a cost savings component for the MDS cost methodology to differentiate between th e two technology options. Theref ore, EPA did not include transportation as part of the impoundme nt operation cost estimates because:

 The MDS cost methodology already estimates the O&M costs that are saved from eliminating the need for the wet sluicing system; and

 The remote MDS still requires using the existi ng wet sluicing system to transport that bottom ash sluice to the remote destination.

EPA did not account for reductions in the wet sluicing operations as part of the fly ash handling conversion methodology (i.e., the estimated cost reduction associated with the wet sluicing operations is not included in the fly ash conversion methodology (see Chapter 7); however, is included as part of the impoundment operation savi ng methodology); therefore, the cost savings associated with the conveyance por tion of the fly ash handling system are included in the impoundment cost estimates. This is diffe rent than bottom ash because the estimation of the wet sluicing costs is include d in the bottom ash conversion methodology (see Chapter 8) and is therefore removed from the impound ment operation savings for bottom ash.
Table 5-6 (located at the end of the chapter) presents the re-calculated totals for annual costs. EPA combined the fly and bottom ash costs to determine a combined ash unitized cost for the impoundment savings calculations for fly ash, bottom ash, and FGD solids. Table 5-7 (located at the end of the chapter) presents the fly, bottom, and combined unitized cost, calculated by dividing the revised to tal O&M costs by total ash tonnage.

5.5.3.3 Earthmoving Unitized O&M Costs
In addition to the impoundment operation unitized costs described in Section 5.5.3.2, EPA also estimated the costs associated with operating earthmoving equipment at combustion residual impoundments to scoop solids out of the in fluent channels, move the influent pipes to new locations, or build up the berms of th e combustion residual impoundments. For the earthmoving unitized cost values, EPA used the co sts with the holding pond and landfill scenario described in the 1981 U.S. EPA/TVA study [U.S . EPA/TVA, 1981]. EPA used this scenario because it includes costs for mobile equipment, defined as comprising a ll trucks and earthmoving equipment. The mobile equipment requirements ar e based on the quantity, moisture content, and bulk density of the ash and truck specifications a nd operating profiles estab lished for the specific operating conditions.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-20 Based on knowledge from site visits rega rding removing combustion residuals from impoundments, EPA assumed that the front-end loader at the im poundment site was the most applicable piece of mobile equipment for removing combustion residuals. EPA also assumed that only one front-end loader per type of combusti on residual would be purchased per plant that operates a combustion residual impoundment. 19 For example, if a plant transfers both FGD solids and bottom ash to an impoundment (or two sepa rate impoundments) and the plant is identified for FGD and/or bottom ash compliance costs, EPA assumed that the plant would have purchased two front-end loaders. Based on the 1981 U.S. EPA/TVA study, the 2010 capital cost of one front-end loader would be $402,687. EPA assumed that the life of a front-end loader is 10 years.
Based on the modular annual revenue requireme nts (O&M) by type of equipment for the holding pond and landfill scenario in the 1981 study, the to tal direct costs for mobile equipment are $945,600 (1984 dollars) for 171,600 tons of ash. 20 Excluding the annualized capital charges (consistent with the impoundme nt operating costs methodology), th e total indirect costs for mobile equipment are $450,400 (1984 dollars). 21, 22 Because there are no specific O&M costs per piece of mobile equipment, EPA estimated that the O&M cost associated with the front-end loader would be proportional to the percentage of the capital cost for the front-end loader compared to the total capital cost for all mob ile equipment applicable to the holding pond and landfill scenario ($402,687/$2,936,960 = 13.7 percent). EPA then applied this percentage to the total O&M costs to determine a unitized cost value. EPA developed the earthmoving O&M unitized costs using Equa tions 5-22 through 5-25.
Total O&M ($) = $945,600 + $450,400 = $1,396,000 ( 5-22 )

Front-End Loader O&M ($) = 0.137 × $1,396,000 = $191,252 (5-23)

Front-End Loader Unitized O&M Co st ($/ton) = $191,252 / 171,600 tons = $1.11/ton (5-24)

Front-End Loader 2010 Unitized O&M Cost ($/t on) = $1.11/ton × 2010 Cost Index / 1984 Cost Index = $2.49/ton (5-25)

where:

1984 Cost Index = 82.0, and

2010 Cost Index = 183.5.

19 EPA recognizes that some plants may have more than one front-end loader for combustion residuals removal, while other plants may not require any equipment to remove combustion residuals.

20 Total direct costs include operating la bor, diesel fuel, and maintenance.

21 Total indirect costs include pl ant and administrative overhead.

22 See Table B-6 of Economics of Ash Disposal at Coal-fired Power Plants (U.S. EPA, 1981) for more detailed information.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-21 5.5.3.4 Impoundment and Earthmoving Capacity Factors
Next, EPA calculated factors for estimating un itized costs for plants of different sizes, using data presented in EPA’s report Full-Scale Field Evaluation ofWaste Disposal from Coalfired Electric Generating Plants [U.S. EPA, 1985]. The data EPA used from the 1985 study are presented in Table 5-8 (located at the end of the chapter), which presents the calculated cost factors relative to a 500 MW plant for fly ash and bottom ash. From these data, EPA calculated the average cost factor relative to the 500 MW pl ant to get a “combined ash calculated factor,” The calculated values are presented in the “Combined ($/ton)” rows. EPA determined the following equation to estimate cost factors for combustion residual handli ng based on plant size (MW).
Plant MW Factor = 7.569 × (Plant Size) -0.32 ( 5-26 )

where:

Plant Size = Plant size in MW. For FGD costs, the MW value is the plant nameplate capacity fr om responses to Question A1-13 in the Steam Electric Survey. For fly and bottom ash, the MW value is the sum of the MW for the units incurring costs at the plant.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A68) for details on the development of Equation 5-26.

5.5.3.5 Surface Impoundment Earthmoving Recurring Costs
Additionally, EPA calculated 10-year recurr ing costs associated with operating the earthmoving equipment (i.e., a backhoe or front-e nd loader). EPA calculated the total 10-year recurring costs by determining the cost and aver age expected life of a backhoe. EPA determined the 2010 cost of the earthmoving equipment to be $402,687, assumed th at the expected life of a backhoe is 10 years, and assuming that each plant will operate one backhoe.

5.6 S URFACE I MPOUNDMENT BMP C OSTS M ETHODOLOGY
Although implementing the technology options w ill reduce, and in some cases eliminate, FGD wastewater, ash transport water, and comb ustion residuals managed in on-site surface impoundments, some surface impoundments may rema in open. EPA is considering BMPs as part of all of the regulatory options evaluated fo r the proposed ELGs. To better inform this consideration, EPA calculated BMP costs for the impoundments that are expected to continue operating after complying with the ELGs. The BMPs include remedial actions (e.g., slope repairs, drawing down water leve ls, controlling vegetation) and in creases in inspection frequency from 17 to 52 times annually. These manageme nt practices will help prevent future impoundment failures that have the potentia l to devastate the surrounding communities.
To estimate impoundment BMP costs, which may be beyond the current state requirements, EPA reviewed the combustion residual impoundments at plants incurringChapter 5 –General Methodology, Terminology, and Common Cost Elements

5-22 compliance costs for FGD wastewater, fly ash trans port water, and/or bottom ash transport water. For purposes of estimating BMP costs, EPA made some assumptions regarding the continued use of existing impoundments. Because these impound ments can contain multiple sources of combustion residuals, the probability that th e impoundment will remain open depends on the regulatory option [ERG, 2013]. For example, if an impoundment contains FGD wastewater and bottom ash transport water, the impoundment would remain open based on the proposed Regulatory Option 3, which affect s only FGD and fly ash transpor t wastewaters. EPA expects the probability that a plant may elect to close the impoundment to be high based on the proposed Regulatory Option 4, which affect s all wastestreams of interest. Therefore, EPA estimated impoundment BMP costs for this impoundment for Regulatory Option 3; however, EPA estimated zero BMP costs for Regulatory Option 4.
EPA estimated an annualized cost for each impoundment determined to remain open, based on the regulatory option. For each of th ese impoundments, EPA estimated that the remedial actions will require $10,000 annually per impoundment. EPA estimated the costs for the additional inspections based on inform ation contained in Exhibit 3K of the Regulatory Impact Analysis for EPA’s Proposed RCRA Regul ation of Coal Combustion Residues (CCR) Generated by the Electric Utility Industry [ORCR, 2010]. EPA used the information regarding the labor hours and labor rate fo r recording keeping and weekly inspections to estimate the costs of the additional inspections. Based on this in formation, EPA estimated that the additional inspections will cost approximately $3,000 annua lly. Therefore, the total annual cost per impoundment is approximately $13,000.

5.6.1 Results and Summary of Costs
EPA calculated plant-level BMP costs for each of the five regulatory options being considered. The cost output includes the total nu mber of surface impoundments at each plant that contain combustion residuals along with an indi cation of the number of impoundments closed under each regulatory option and the number of impoundments receiving BM P costs. The list of plant-level costs for implementing impoundme nt BMPs is included in the appendix.

5.7 R EFERENCES

1. CH2MHILL 2009. Planning-Level Cost Estimat es for Landfill Options. Dan Pitzler and Cory Hinds. (27 March). DCN SE02954.
2. Eastern Research Group (ERG). 2013. Memorandum to the Steam Electric Rulemaking Record: Pond Closure Analysis Me morandum. (19 April). DCN SE02125.
3. The Envirobix Group, 2007. 2007 Chartwell Gate Price Survey Progress Report. The Envirobix Group. (9 April). DCN SE02012.
4. RSMeans. 2011. Building Construction Cost Data, 69th Edition. DCN SE02952.
5. U.S. Department of Labor, Bu reau of Labor Statistics. 2010. May 2009 National Occupational Employment and Waste Estimates, United States. Washington, D.C. (May). DCN SE02024.
6. U.S. EPA, 1985. Full-Scale Field Evaluation of Waste Disposal from Coal-fired Electric Generating Plants. (August). DCN SE02971.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-23 7. U.S. EPA and Tennessee Valley Authority (T VA), 1981. Economics of Ash Disposal at Coal-fired Power Plants . (October). DCN SE02970..
8. U.S. EPA, Office of Resource Conserva tion and Recovery (ORCR). 2010. Regulatory Impact Analysis for EPA’s Proposed RCRA Regulation of Coal Combustion Residues (CCR) Generated by the Electric Utility Indus try. Washington, D.C. (30 April). DCN SE02969.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

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

Task Number of Staff Required for Task a Time Needed per Staff for Task (Hours/Task) Number of Events per Year b Total Time Needed (Hours/Yr) Set up composite sampler 2 0.75 52 78 Collect 1st mercury manual composite sample (with field blank) 2 0.5 52 52
Collect 2nd mercury manual composite sample 2 0.25 52 26
Collect 3rd mercury manual composite sample 2 0.25 52 26 Collect 4th mercury manual composite sample 2 0.25 52 26 Collect arsenic/selenium sample from composite sampler 2 1 52 104
Pack and ship samples to laboratory 1 1 52 52 Review and report data 1 1.5 12 18 Total wastewater treatment sy stem operator (hours/yr): Total plant environmental coordinator (hours/yr): 364 18

a EPA assumed that wastewater treatment system operato rs would perform all tasks except for reviewing and reporting data, which EPA assumed the plant environmental coordinator would perform.

b EPA assumed all tasks would be performed weekly, except for reviewing and reporting data, which EPA assumed would be performed monthly.

Table 5-2. Compliance Monitoring Sampling Materials

Item Cost Per Item (2011$/Item) Number of Items Required Per Sampling Event Cost Per Sampling Event

(2011$/Event) Tyvek coverall $5.50 2 $11 Dust mask $0.50 2 $1 Gloves (pair) $0.24 20 $4.80 Mercury sample container (pre-cleaned, 250-mL glass) $3 2 a $6 Arsenic/selenium sample container (pre-cleaned, 500-mL plastic) $5 1 $5 Total dissolved solids sample container (pre-cleaned, 1-L) $1 1 b $1 Shroud for mercury sample collection $1.50 4 $6 Carboy (pre-cleaned, 10-L) $90 1 $90 Field blank water (ASTM Type 1, 1-L) $12.50 1 $12.50 Vented cap (pre-cleaned) $60 1 $60 Composite sample pump-off cap (pre-cleaned) $38 1 $38 Portable cleanbox (pre-cleaned) $30 1 $30 T-splitter tubing set (pre-cleaned) $90 1 $90 Composite sample pump-off tubing set (pre-cleaned) $70 1 $70 Plastic tarp $3 2 $6 Total sampling materials costs, other than vapor-compression evaporation (2011$/sampling event): Total sampling materials cost s, vapor-compression evapor ation (2011$/sampling event): $430.30
$431.30

a Two sample containers are needed fo r sample and field blank analysis.

b Applicable for vapor-compression evaporation effluent sampling only.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

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

Analysis Cost Per Analysis (2011$/Analysis) Number of Analysis Required Per Sampling Event Cost Per Sampling Event (2011$/Event) Mercury (EPA Method 1631E) $65 2 a $130 Arsenic and selenium (EPA Method 200.8 with collision cell) $185 1 $185
Total dissolved solids $10 1 b $10 Total sample analysis costs, other than vapor-compression evaporation (2011$/sampling event): Total sample analysis costs, vapor-compression evaporation (2011$/sampling event): $315

$325

a Two sample containers needed for sample and field blank analysis.

b Applicable for vapor-compression evaporation effluent sampling only.

Table 5-4. Capital Costs of 7-Acre Landfill Expansion from CH2MHILL
Low (2009$) High (2009$) Expansion - Construction $3,200,160 $3,200,160 Leachate treatment system (wetlands) construction $1, 956,000 $4,847,000 Landfill gas collection $47,000 $213,000 Groundwater wells $45,000 $45,000 Closure $1,156,000 $1,156,000 Total Capital Cost $6,404,160 $9,461,160 Source: CH2MHILL, 2009.

Table 5-5. O&M Costs of 7-Acre La ndfill Expansion from CH2MHILL
Low (2009$) High (2009$) Landfill stormwater management $60,000 $0 Leachate O&M $ 100,000 $ 200,000 Leachate treatment upgrades (annual) $42, 000 $103,000 Added groundwater monitoring $23,000 $23,000 Annual post closure care $277,000 $333,000 Total O&M Cost $502,000 $659,000 Source: CH2MHILL, 2009.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

5-26 Table 5-6. Revised Modular A nnual Revenue Requirements by Process Area for Direct Ponding of Nonhardening Ash without Water Reuse

Cost Category Fly Ash Modular Process Areas 1,000 dollars (1984) Bottom Ash Modular Process Areas 1,000 dollars (1984)

2 3 4 Revised Subtotal 3 4 Revised Subtotal
Direct Costs Operating labor 9.00 6.40 0.20 15.60 1.50 0.10 1.70 Process reagents 0.00 0.00 2.90 2.90 0.00 0.70 0.70
Water 5.50 0.00 0.00 5.50 0.00 0.00 0.00 Electricity 10.30 0.50 0.70 11.50 0.20 0.20 0.40 Process maintenance 57.00 0.00 4.00 61.00 0.00 1.00 1.00 Pond maintenance 0.00 177.00 0.00 177.00 44.00 0.00 44.00 Sampling and analysis 0.00 2.10 16.80 18.90 2.10 16.80 18.90 Total direct costs 81.80 186.00 24.60 292.40 47.80 18.80 66.60

Indirect Costs Plant and administration overheads (60% of total direct costs less water and electricity) 39.60 111.30 14.34 165.24 28.56 11.16 39.72
Total Total annual O&M cost 121.40 297.30 38.94 457.64 76.36 29.96 106.32 Source: U.S. EPA/TVA, 1981.

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

Type of Cost Total O&M 1984 $ Ash Tonnage 1984 Index 1984 Unitized Cost ($/ton) 2010 Index 2010 Unitized Cost ($/ton) Fly ash 457,640 137,280 82 3.33 183.5 7.46 Bottom ash 106,320 34,320 82 3.09 183.5 6.93 Combined ash 563,690 171,600 82 3.28 183.5 7.35 Source: U.S. EPA/TVA, 1981. Note: The costs presented in this table are the EPA-calculated unitized costs for the impoundment savings cost methodology; excluding the “collection” modular process area for fly ash and bottom ash and the “transportation” modular process area for bottom ash.Chapter 5 –General Methodology, Terminology, and Common Cost Elements

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

Type of Cost Plant Size (MW) Min Range 1982 $ Max Range 1982 $ Average 1982 $ Average Cost Factor Relative to

500 MW

Plant Fly ash ($/ton) 250 15.7 28.9 22.3 1.27 Fly ash ($/ton) 500 12.3 22.7 17.5 1 Fly ash ($/ton) 1000 9.7 18.2 13.95 0.79 Fly ash ($/ton) 2000 7.7 14.2 10.95 0.625 Bottom ash ($/ton) 250 18.4 34.2 26.3 1.21 Bottom ash ($/ton) 500 15.2 28.1 21.65 1 Bottom ash ($/ton) 1000 12.1 22.4 17.25 0.79 Bottom ash ($/ton) 2000 9.7 17.9 13.8 0.63 Combined ash ($/ton) 250 NA NA NA 1.24 Combined ash ($/ton) 500 NA NA NA 1 Combined ash ($/ton) 1000 NA NA NA 0.797 Combined ash ($/ton) 2000 NA NA NA 0.632 Source: U.S. EPA, 1985. NA – Not applicable.Chapter 6 - FGD Wastewater Cost Methodology

6-1 

## CHAPTER 6 FGD WASTEWATER COST METHODOLOGY

EPA estimated capital, operating and mainte nance (O&M), 6-, and 10-year recurring costs associated with in stalling three technology opti ons for FGD wastewater:

 One-Stage Chemical Precipitation;

 One-Stage Chemical Precipitation fo llowed by Biological Treatment; and

 One-Stage Chemical Precipitation follo wed by Vapor-Compre ssion Evaporation.
EPA estimated the chemical precipitation, bi ological treatment, and vapor-compression evaporation system costs separately, and then summed the costs generated by the appropriate technology cost modules to achieve the total technology option costs (i.e., the chemical precipitation costs were added to the biological treatment a nd vapor-compression evaporation costs to calculate the total costs for the tec hnology option). This chapter presents the cost methodologies used for chemical precipitation (S ection 6.1), biological tr eatment (Section 6.2), and vapor-compression evaporation (Section 6.3). All tables and figures referenced in this chapter are presented at the end of the chapter.

6.1 C HEMICAL P RECIPITATION
EPA estimated capital and O&M costs associ ated with installi ng and operating a onestage chemical precipitation treatment system to treat flue gas desulfuri zation (FGD) wastewater, specifically designed and operated to remove merc ury and arsenic (and other heavy metals). All costs are estimated in 2010 dollars.

6.1.1 Technology Description
Chemical precipitation involves forming a se parable solid substance from a solution, typically by converting the solubl e constituents to insoluble form s. The precipitated solids are then removed from solution by flocculation follo wed by sedimentation and/or filtration. Figure 6-1 at the end of this chapter shows a typical one-s tage chemical precipita tion process for metals removal for FGD wastewater. A chem ical precipitant is added to the metal-containing water in a stirred reaction vessel. The dissolv ed metals are converted to an insoluble form by a chemical reaction between the soluble metal and the pr ecipitant. Precipitation is caused by adding chemical precipitants that adjust the pH of the water to the mi nimum solubility of the target metal(s) (see Figure 6-2). 23 The suspended particles are then flo cculated and settled in a clarifier. Multiple precipitants can remove metals in a va riety of forms with diffe ring solubilities (e.g., metal hydroxides and metal sulfides). Also, usin g multiple stages of precipitation and solids separation can be used to remove multiple targ et metals that exhibit minimum solubility at different pH levels. Filtration ca n also be used for wastewater polishing to remove remaining suspended metal precipitates.

23 Figure 6-2 shows the minimum solubilities of common metals at various pH values. This figure was developed based on empirical studies using single metal solutions in reagent-free water. Minimum metal solubilities in complex wastewater may differ from those shown in Figure 6-2.Chapter 6 - FGD Wastewater Cost Methodology

6-2 Hydroxide precipitation is the predominant t ype of chemical precipitation used by the steam electric industry for FGD wastewater treatm ent. Hydroxide precipitation typically involves using calcium hydroxide (lime) as the precipitant to convert dissolv ed metals to insoluble metal hydroxides. The reaction is illust rated by the following equation:

M n+ + 0.5nCa(OH) 2 → M(OH) n + 0.5nCa 2+

The effluent metals concentrations attain ed by hydroxide precipitation depend on the metals present, precipitant used, the reaction conditions (especially pH ), and the presence of other materials that may inhibit or enhance pr ecipitation. Specifically, to enhance precipitation, the steam electric power generating industry commonl y adds the chemical reagent ferric chloride to induce iron coprecipitation, whereby dissolved metals and metal hydroxides are enmeshed by iron precipitates, improving their removal. While the mechanics of iron coprecipitation reactions are not understood in all cases, the following is an example reaction:

M n+ + FeCl 3 + 3H 2 O → Fe(OH) 3 •M + 3H +

Some steam electric power plants use sulf ide precipitation in a ddition to hydroxide precipitation. Sulfide precipitation typically uses organosulfide as the precipitant to convert dissolved metals to insoluble metal sulfides. The sulfide precipitation process can (for many metals) achieve lower effluent metals concentra tions than hydroxide precipitation because metal sulfides often have lower solubility limits th an metal hydroxides (see Figure 6-2). The sulfide precipitation reaction is illustrated by the following equation:

M n+ + 0.5nS 2- → MS 0.5n
EPA has based compliance cost estimates on a one-stage chemical precipitation technology to treat FGD wastewater generated by the steam elec tric industry, specifically designed and operated to remove the target metals mercury and arsenic, as well as other metals that are pollutants of concern (see Figure 6-1). Th is technology can be operated as either standalone metals treatment or for metals treatment preceding either biologic al treatment or vaporcompression evaporation.
EPA based the design on an evaluation of the one-stage FGD chemical precipitation treatment systems operated by three steam electri c power plants sampled by EPA whose effluent data were used to represent the best performa nce of FGD chemical precipitation. EPA used the performance data from these plants to de velop Best Available Technology Economically Achievable (BAT) limitations and Best Availa ble Demonstrated Control Technology (BADCT, also referred to as New Source Performance Sta ndards (NSPS)) standards. For the purposes of the discussion in this document, these three plan ts are referred to as the “BAT plants” for the chemical precipitation technology option for FGD wastewater. Major components of the design basis for this technology include:

 Equalization tank;

 Reaction tank 1 for lime addition to a pH set point of 8.5 S.U. to 9.2 S.U.;

 Reaction tank 2 for organosulfide addition;Chapter 6 - FGD Wastewater Cost Methodology

6-3  Reaction tank 3 for ferric chloride addition;

 Chemical feed systems;

 Solids contact clarifier;

 Sand filters;

 Treated wastewater tank;

 Sludge filter press; and

 Sludge holding tank.

6.1.2 Population Costed

Based on information from the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey), EPA id entified 117 plants discharging FGD
wastewater. 24 EPA estimated costs for these 117 plan ts to install a one -stage chemical precipitation system to treat th eir FGD wastewater. EPA identified plants that have announced plans to retire generating units prior to D ecember 31, 2014 as described in Section 4.4.1. There are no conversion costs for plant th at are already planned to retire prior to implementation of the Steam Electric effluent limitations guidelines and standards (ELGs).

6.1.3 Credit for Chemical Precipi tation Treatment in Place
EPA evaluated plant responses to the Steam Electric Survey for the 117 plants identified as discharging FGD wastewater to determine whether chemical precip itation technologies are currently in place to treat FGD wastewater. As appropriate, these plants were given credit for having “treatment in place” for any system elements that matched the chemical precipitation design basis. EPA estimated compliance costs for these plants for only the system elements they did not have in place.
Based on a review of survey responses, EPA id entified a total of 41 plants that either operated chemical precipitation systems FGD wastewater trea tment in 2009, or planned to operate systems prior to January 1, 2014. EPA did not identify any plants planning to install and operate systems after January 1, 2014. For this analysis, EPA did not assign treatment in place credit for plants that (1) operated chemical preci pitation systems to treat wastewaters other than FGD wastewater (e.g., chemical pr ecipitation of metals cleaning wastewater), or (2) operated FGD wastewater treatment technol ogies other than chemical preci pitation (e.g., solids settling in surface impoundments, solids separation technologies such as clarifiers w ithout precipitation).
EPA gave full treatment-in-place credit to the BAT plants and those plants with existing treatment beyond BAT. The only costs these plan ts are estimated to incur are compliance monitoring costs and costs for a mercury an alyzer, described in Sections 5.2 and 6.1.9 respectively.

24 When the group of plants excluding oil-fired uints and units with a capacity of 50 MW or less is evaluated, the population of plants discharing FGD wastewater includes 116 plants.Chapter 6 - FGD Wastewater Cost Methodology

6-4 For the remaining plants operating FGD chem ical precipitation systems, EPA assessed each of the major equipment components usi ng the general methodology listed below. Certain plant-specific deviations are described in the Supplemental Costs and Loadings Documentation (DCN SE01825.A82).

 Equalization tank and mixer – The chemi cal precipitation design basis includes equalization with 24-hour residence time. EPA identified all plants with existing equalization tanks as having equalization in place; however, plants reporting less than 24-hour residence time were assessed onl y partial credit (see the Equalization Tank Cost discussion within Section 6.1.6.2 for the partial cr edit methodology).

 Reaction tanks and mixers – Treatment in place for reaction tanks was assessed as follows:

- Plants currently adding lime (or alternative precipitant such as caustic), organosulfide, and ferric chloride rece ived full treatment-in-place credit for reaction tanks, regardless of th e number of existing reaction tanks.

- Plants with three or more existing reacti on tanks received full treatment-in-place credit for reaction tanks, regardle ss of current chemical addition.

- Plants without lime or caustic addition were costed for reaction tank 1.

- Plants without organosulfide or ferric chlo ride addition, and with fewer than three existing reaction tanks, were costed for reaction tanks 2 and/or 3.

 Chemical feed systems (including chemical storage tanks) – Treatment-in-place credit for chemical feed systems was assessed as follows:

- Plants currently adding chemicals include d in the BAT design basis were assumed to have their respective chemical feed systems and received full treatment-inplace credit for these systems.

- Plants that do not currently add organosulfide, but reported the capability to add organosulfide in response to Question D5 -6 of the survey, received full treatmentin-place credit for an organosulfide feed system.

- Plants that do not currently add lime (or alternative precipitant such as caustic) or ferric chloride were costed for these feed systems.

- Plants that do not currently add polymer or acid were assumed not to need to add these chemicals for operation of their chem ical precipitation systems and were not costed for these chemical feed systems.

 Solids contact clarifier (including sludge pumps) – Plants with existing clarifier(s) were assumed to have adequate clarificati on treatment in place, regardless of the number, type, or capacity of the clarifiers.

 Sand filters – Plants with existing sand or other gravity filtration were assumed to have adequate filtration treatment in place, regardless of the number, type, or capacity of the filters.

 Treated wastewater tank – Plants with existing treated wastewater tank(s) were assumed to have adequate holding capacity, regardless of the number or capacity of the treated wastewater tanks.Chapter 6 - FGD Wastewater Cost Methodology

6-5  Sludge filter press (including feed/pressurizat ion pumps) – Plants with existing sludge filter press(es) were assumed to have adequate sludge dewatering capability, regardless of the number, type, or capacity of the filter presses.

 Sludge holding tank and mixer - Plants w ith existing sludge holding tanks were assumed to have adequate sludge holding capacity, regardless of the number or capacity of the sludge holding tanks.

 Biological treatment or vapor-compression evaporation feed tank – Plants with existing biological treatment or vapor-compr ession evaporation were assumed to have adequate wastewater holding capacity in plac e, regardless of the number and capacity of these holding tanks.

 Wastewater pumps – All plants operating chemical precipitation were assumed to have adequate wastewater pumps.
EPA assumed that plants with existing F GD chemical precipita tion would not incur additional incremental O&M costs as a result of any costed treatment upgrades. One exception is compliance monitoring costs, which were included for all plants. Another exception is chemical addition, which was assessed as follows:

 Plants currently not adding lime (or alte rnative precipitant such as caustic), organosulfide, or ferric chloride were cost ed for the full target chemical dosage for these chemicals.

 Plants that add organosulfide and/or ferric chloride, but in dosages less than the target chemical dosages, were costed for the in cremental chemical addition required to achieve the target chemical dosage. The incremental chemical dosage required was calculated as the difference between the targ et chemical dosage and the current plant dosage.

 Plants adding lime or alternative precipitan t, regardless of dosage, were assumed to have adequate precipitant dosage.

 Plants not currently adding polymer or acid were assumed not to need these chemicals for operation of their chemical precipitation systems.
EPA did not estimate cost savings for plants c onsidered to have treatment in place that “goes beyond” the technology options. For exampl e, if EPA identified a plant with chemical dosage rates that exceed the required dosages fo r the technology option, EPA did not assume that the plant would reduce their ch emical dosage rates and receive a corresponding cost savings.
As discussed previously, some plants curren tly treat their FGD wastewater in surface impoundment systems. EPA’s cost estimates are ba sed on the assumption that plants will redirect their FGD wastewater from the surface impoundme nt systems to a new tank-based chemical precipitation system. For plants identified as “high flow” FGD plants (see Section 4.4.3) and flagged in the input table as having dedi cated FGD surface impoundments, EPA evaluated whether it would be cost effective for these plants to install equalization tanks to hold all of the FGD wastewater flow or to continue operating a dedicated FGD surface impoundment. For these high flow plants, EPA determined that cont inuing to operate an FGD surface impoundment would be more cost effective th an installing equalization tanks for the full FGD wastewater flow.Chapter 6 - FGD Wastewater Cost Methodology

6-6 Therefore, EPA assessed an equalization treatment in place credit for these high flow plants with dedicated FGD surface impoundments based on the assu mption that the plants would continue to operate their surface impoundments. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A56) for additional information.

6.1.4 Input Table
As discussed in Section 4.1.1, EPA used survey da ta to identify which plants discharge or have the potential to discharge FGD wastewat er and estimated FGD wastewater compliance costs for these plants. The “FGD Input Table” ho lds certain plant-specif ic data needed to calculate the technology option cost for all F GD wastewater treatment technologies. The “FGD Input Table” contains the following fields:

 Plant_id: Survey Plant ID.

 FGD_Wastewater_gpd : The flow rate of FGD wastew ater at each plant in gallons per day.

 CBI_FGD_Cost : Flag indicating that the resu lting FGD cost estimate should be considered confidential business information (CBI). CBI flag is marked if any data used to populate the input table we re marked as CBI by the plant.

 Retired?: Flag indicating that the plant has id entified that it will be retiring on or before 12/31/2014.
The discussion of the “FGD Input Table” in Section 4.1.1 provides more detail on the methodology used to determine which plants disc harge FGD wastewater a nd the plant-specific FGD wastewater flow rate. A copy of the “FGD Input Table” is included in the appendix.

6.1.5 Key Variables Used in the Capi tal and O&M Cost Methodologies
Certain variables are used throughout the ch emical precipitation, biological treatment, and vapor-compression evaporation methodologies when estimating capital and O&M costs for plants. These key variables are defined and described below.

 FGD Wastewater Flow GPM : Wastewater flow rate in gallons per minute (gpm) as provided by plants in response to Question B5-2 of the survey. 25 This flow is used to size and cost the wastewater forwarding pum ps that transfer FGD wastewater from the FGD system to the FGD treatment system equalization tank.

 FGD Wastewater Flow GPD : Wastewater flow rate in gallons per day (gpd) as provided by plants in response to Question B5-2 of the survey. It is used to calculate FGD wastewater treatment flow, which is used throughout Section 6.1 of this report. FGD Wastewater Flow GPD is also used in Section 6.1.6.2 to size and cost the FGD treatment system equalization tank (assu ming 24-hour equalization residence time) and in Section 6.1.7.1 to calculate the annua l cost of operating labor for the FGD treatment system.

25 Typical amount of FGD scrubber purge (or slurry discharge) sent to wastewater treatment or discharge.Chapter 6 - FGD Wastewater Cost Methodology

6-7  FGD Wastewater Treatment Flow GPM : Average plant flow ra te after equalization in gpm. EPA calculated this flow rate assu ming that the wastewater treatment plant operates 24 hours per day (hpd) and 365 days pe r year (dpy). It is calculated as FGD Wastewater Flow GPD/(24 hpd × 60 minutes per hour). This flow is used to size the majority of components in the FGD treatment system. Note that when estimating purchased equipment costs, EPA assume d a minimum FGD Wast ewater Treatment Flow GPM of 20 gpm.

 Capacity Factor : The capacity factor accounts for the difference between the maximum design flow rate and typical flow rate of the FGD wastewater treatment system (see Question D5-3 of the survey). That is, treatment systems are sized based on maximum design flow to accommodate e xpected variation in FGD wastewater treatment flow rates. EPA determined a me dian capacity factor of [Redacted] based on an assessment of the ratio of maximum design flow to typical flow at plants operating FGD wastewater chem ical precipitation treatment systems, as calculated based on responses to Question D5-3 of the survey. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A45) for additional information.

 Sludge Factor : Ratio of the design sludge genera tion rate to the FGD Wastewater Treatment Flow GPM. After excluding obvi ously erroneous Steam Electric Survey responses, EPA selected a median factor of 0.4. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A34) for additional information.

 Miles : Miles transported for estimating freight costs of purchased equipment for the FGD treatment system. EPA assumed that eq uipment would need to be transported 500 miles, on average.

 Flatbed Truck Cost : The cost for a full equipment shipment via flatbed truck transported approximately 500 miles. EPA ba sed this cost [Redacted] on information from Siemens

. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A41) for additional information.

 Truck Weight Capacity : The maximum shipping weight a dry van truck can hold. EPA assumed a truck can transport shipme nts up to 45,000 lbs, based on information from FreightCenter.com . See the Supplemental Costs and Loadings Documentation (DCN SE01825.A1) for additional information.

6.1.6 Capital Cost Methodology
Total capital costs to treat FGD wastewater with one-stage chemical precipitation are obtained by adding the following cost elements:
Total Capital Cost = Purchased Equipment Cost + Purchased Equipment Installation Cost + Building Cost + Land Cost + Site Preparation Cost + Engineering Cost + Construction Expenses + Other Contractor Fees + Contingency Fees

All costs were adjusted to 2010 dollars us ing the RSMeans Histor ical Cost Index.
Purchased equipment costs for the one-stage chemical precipitation system include the following:Chapter 6 - FGD Wastewater Cost Methodology

6-8  Purchase of treatment equipment to include:

- Pumps,

- Tanks,

- Chemical feed systems,

- Mixers,

- Clarifiers,

- Filter presses, and

- Sand filter;

 Purchase of associated ancillary equipmen t such as piping, valves, and controllers; and

 Freight.
EPA did not include costs for spare parts, bu t instead estimated duplicate costs or excess capacity for certain equipment such as pumps and sand filters. (EPA did estimate costs for replacement parts – see Mainte nance Materials Cost in S ection 6.1.7.3.) EPA also did not estimate sales tax based on the assumption that sp ecialized chemical preci pitation equipment is generally not purchased locally. Finally, EPA di d not include costs for duties based on the assumption that equipment would not be im ported from outside the United States.
EPA estimated purchased equipment costs by requesting quotes from vendors for a variety of equipment sizes to accommodate FGD wastewater flow rates ranging from approximately 7 to 1,000 gpm and 10,000 to 1,000,000 gpd. Note, however, that EPA assumed a minimum FGD Wastewater Treat ment Flow GPM of 20 gpm for the purpose of costing equipment only.
For certain equipment, EPA performed regr ession analyses by plotting equipment cost/size data point pairs and developing an equa tion for the best curve fit. The cost equations calculated to fit the cost curves were mo st commonly polynomial, but may be linear, exponential, or logarithmic. For other equipmen t, EPA developed stepwise cost functions by assigning a set cost to each of multiple ranges of flow rates (e.g., cost X for flows ranging from A to B, cost Y for flows ranging from C to D, and so on). For yet other equipment, EPA developed cost functions based on cost per unit m easure (e.g., cost per gallon for tanks) or cost per discrete unit (e.g., cost per discrete chemi cal feed points), which were calculated using information provided by vendors. Where appropria te, EPA used a combination of the methods described above.
Freight costs are also included in the purchas ed equipment cost e quations. Freight costs were either provided as separa te costs by the vendor or calc ulated based on weight using FreightCenter.com. Full truck frei ght costs were obtained from Fr eightCenter.com (dry van truck freight) and Siemens (flatbed truc k freight). FreightCenter.com indi cated that the cost to ship a full dry van truckload a distan ce of 500 miles would be approximately $1,400 and that a typical truck can hold up to 45,000 pounds [ERG, 2013; See Appendix A1]. Siemens indicated that the flat bed truck freight cost is [Redacted] [ERG, 2013; See Appe ndix A41]. EPA assumed a typical transport distance of 500 miles, yielding a cost of [Redacted].Chapter 6 - FGD Wastewater Cost Methodology

6-9 Because vendors provided all equipment cost s in 2011 dollars, EPA adjusted the cost basis to 2010 dollars using the 2010 and 2011 RSM eans Historical Cost Indices (183.5 and 185, respectively) [RSMeans, 2011].

6.1.6.1 Purchased Equipment Costs: Pumps
EPA developed pump cost equations based on co st estimates provided by Weir Minerals [ERG, 2013; See Appendix A2]. Weir Minerals pr ovided cost estimates for a variety of flow rates for each type of pump. Cost estimates in clude the cost for the equipment, accessories, motors, and V drive. All pumps are rubber-l ined to accommodate the high chloride concentrations (2,000 to 40,000 parts per milli on (ppm)) present in FGD wastewater. EPA plotted cost vs. flow rate for each type of pump and developed best fit equations to calculate
costs.
EPA estimated pump freight costs based on weight and a shipping distance of approximately 500 miles using quotes from Frei ghtCenter.com [ERG, 20 13; See Appendix A7]. The freight costs were compar ed to the equipment costs a nd a pump freight factor was developed. Freight costs for pumps were equal to approximately 3 to 4 percent of purchase costs. EPA used a factor of 4 percent (i.e., Pump Freight Factor = 1.04).
Total pump costs are obtained by adding costs for each type of pump as described by Equation 6-1.
Total Pump Cost = Wastewater Feed Pump Cost + Wastewater Forwardi ng Pump Cost + Sludge Recycle/Transfer Pump Cost + Filter Pre ss Feed/Pressurization Pump Cost + Treated Wastewater Discharge Pump Cost + Sump Pu mp Cost + Lime Slurry Transfer Pump Cost (6-1)

Wastewater Feed Pump Cost EPA assumed that plants will use existing FGD wastewater feed pumps to move FGD wastewater from the FGD system to the equa lization tank of the new chemical precipitation treatment system (or to the existing FGD wastew ater impoundment, for certain high flow plants (see Section 4.4.3). Therefore, EPA assumed no capital or operating and maintenance costs were required for wastewater feed pumps.

Wastewater Forwarding Pump Cost EPA costed two 100 percent capacity skid -mounted, horizontal cen trifugal pumps to move FGD wastewater from the equa lization tank(s) to reaction tank 1.

Wastewater Forwarding Pump Co st (2011$) = [2941 × ln(Capacity Factor × FGD Wastewater Flow GPM) – 3090.1] × WWFPump Qty × Pump Freight Factor (6-2)

where:

Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted],Chapter 6 - FGD Wastewater Cost Methodology

6-10 FGD Wastewater Flow GPM = FGD wastewater flow rate in gpm as reported in the Steam Electric Survey (see Section 6.1.5), WWFPump Qty = Number of wast ewater forwarding pumps, 2, and
Pump Freight Factor = Fact or that accounts for freight cost as a percentage of purchase cost (see Section 6.1.6.1), 1.04.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A2 and SE01825.A3) for details on the de velopment of Equation 6-2.

Sludge Recycle/Transfer Pump Cost EPA costed six sludge recycle/tr ansfer pumps (two for each of two clarifiers (see Section 6.1.6.5) and two for recycling sludge from the clarif iers to reaction tank 1) for each plant. These pumps are 100 percent capacity skid-mounte d, rubber-lined, progressive cavity sludge recycle/transfer pumps.
Sludge Recycle/Transfer Pump Cost (2011$) = [0.0841 × (Sludge Factor × FGD Wastewater Treatment Flow GPM) 2 – 7.2394 × (Sludge Factor × FGD Wast ewater Treatment Flow GPM) + 7683.8] × Sludge Pump Qty × Pump Freight Factor (6-3)

where:

Sludge Factor = Factor to estimate the sludge generation rate based on the FGD Wastewater Treatment Flow GPM (see Section 6.1.5), 0.4,

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpmnormalized for 24 hpd operation (see Section 6.1.5), Sludge Pump Qty = Number of sludge recycle/transfer pumps, 6, and
Pump Freight Factor = Fact or that accounts for freight cost as a percentage of purchase cost (see Section 6.1.6.1), 1.04.

Filter Press Feed/Pressurization Pump Cost Filter press pump costs were not estimated se parately but are instead included within the filter press purchase costs (see Section 6.1.6.6). EPA assumed one pump per filter press and costed three filter presses for each FGD wastew ater treatment system. The filter press design structure is flexible to allow any pump to feed any press.

Treated Wastewater Discharge Pump Cost EPA costed two 100 percent capacity skid-m ounted, horizontal centr ifugal pumps to act as treated wastewater discharge pumps, carrying th e wastewater out of the chemical precipitation system.Chapter 6 - FGD Wastewater Cost Methodology

6-11 Treated Wastewater Discharge Pump Cost (2011$) = [0.0049 × (Capacity Factor × FGD Wastewater Treatment Flow GPM) 2 + 8.2408 × (Capacity Factor × FGD Wastewater Treatment Flow GPM) + 7758.6] × Pump Freight Factor × Effluent Pump Qty (6-4)

where:

Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted],

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), Effluent Pump Qty = Number of treat ed wastewater discharge pumps, 2, and
Pump Freight Factor = Fact or that accounts for freight cost as a percentage of purchase cost (see Section 6.1.6.1), 1.04.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A2 and SE01825.A4) for details on the de velopment of Equation 6-4.

Sump Pump Cost EPA costed two 100 percent capacity skid-mounted, sump pumps.
Sump Pump Cost (2011$) = [15.799 × (Capacity Factor × FGD Wastewater Treatment Flow GPM) + 7685.9] × Pump Freight Factor × Sump Pump Qty (6-5)

where:

Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted],

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), Sump Pump Qty = Number of sump pumps, 2, and
Pump Freight Factor = Fact or that accounts for freight cost as a percentage of purchase cost (see Section 6.1.6.1), 1.04.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A2 and SE01825.A5) for details on the de velopment of Equation 6-5.

Lime Slurry Transfer Pump Cost The lime slurry feed system does not require lime slurry transfer pumps (see Section 6.1.6.3).Chapter 6 - FGD Wastewater Cost Methodology

6-12 FGD Recycle Pump and Piping Cost For “high flow” plants (see Section 4.4.3), EP A costed two 100 percent capacity skidmounted, horizontal centrifugal pumps (same pum p type as the Wastewater Forwarding Pump) to move wastewater from the equalization tank( s) or surface impoundment system back to the FGD system. 26 EPA costed these pumps for only those “h igh flow” plants identified as having an operating chloride concentration of less than 80 percent of the de sign concentration.
FGD Recycle Pump Cost (2011$) = [2941 × ln(Cap acity Factor × New FGD Treatment Flow) – 3090.1] × FGDRecPump Qty × Pump Freight Factor (6-6)

where:

Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted],

New FGD Treatment Flow = The flow rate of FGD wastew ater recycled back to the FGD scrubber in gallons per minute (see Section 4.4.3 and Equation 4-13), FGDRecPump Qty = Number of FGD recycle pumps, 2, and
Pump Freight Factor = Fact or that accounts for freight cost as a percentage of purchase cost (see Section 6.1.6.1), 1.04.

EPA also costed each “high flow” plant im plementing recycle for a length of fiberglass reinforced plastic (FRP) pipe to transport th e FGD wastewater from the equalization tank or FGD surface impoundment back to the FGD system. The total cost of the piping is dependent on both the size and the length of piping need ed. Pipe size is a step function based on FGD wastewater flow rate. Pipe length was determin ed using data from responses to the Steam Electric Survey.
For “high flow” plants continuing to opera te dedicated FGD surface impoundments, EPA used latitude and longitude data from responses to Questions A3-2 and A5-1 to calculate a distance from the center of the plant to the FGD surface impoundment identified in the survey. EPA assumed that the FGD system is located wi thin the main plant area. From these plantspecific surface impoundment distances, EPA calculate d the average distance to the FGD surface impoundment to be 4,481 feet.
For “high flow” plants without a dedicat ed FGD surface impoundment, EPA assumed the FGD wastewater will be recycled from the equalization ta nks back to the FGD system. To calculate this distance, EPA took an average of the distance between the FGD system and the wastewater treatment system, as reporte d in Part D Section 2 Question D2-7 (Pond/Impoundment System and Wa stewater Treatment System Id entification) of the Steam

26 Of the 12 “high flow” plants, seven operate dedicated FGD surface impoundments. As discussed in Section 4.4.3, EPA determined that it would be more cost effective for th ese plants to continue to operate these ponds in place of installing equalization tanks. EPA costed the remaining five “high flow” plants to install and operate equalization tanks.Chapter 6 - FGD Wastewater Cost Methodology

6-13 Electric Survey. EPA calculated the average di stance between the FGD system and the FGD wastewater treatment system to be 1,610 feet.
EPA also estimated freight costs for the pi ping based on weight a nd a shipping distance of approximately 500 miles using quotes from Fr eightCenter.com. Freight costs were equal to approximately 8 percent of purchase costs (i.e., Freight Factor = 1.08).
EPA used a step-wise function based on FGD r ecycle flow, pipe size, and pressure drop to calculate the total cost of piping from the equalization tank or FGD surface impoundment back to the FGD system.

 For FGD recycle flow ≤ 158,400 gpd (2 inch pipe)

- Pipe Cost (2011$) = $11.13 dollars per f oot × PipeLength × PipeFreightFactor

 For 158,400 gpd < FGD recycle flow ≤ 288,000 gpd (3 inch pipe)

- Pipe Cost (2011$) = $15.40 dollars per f oot × PipeLength × PipeFreightFactor

 For 288,000 gpd < FGD recycle flow ≤ 576,000 gpd (4 inch pipe)

- Pipe Cost (2011$) = $19.65 dollars per f oot × PipeLength × PipeFreightFactor

 For 576,000 gpd < FGD recycle flow ≤ 1,008,000 gpd (6 inch pipe)

- Pipe Cost (201$) = $24.01 dollars per f oot × PipeLength × PipeFreightFactor

 For 1,008,000 gpd < FGD recycle flow ≤ 1,584,000 gpd (8 inch pipe)

- Pipe Cost (2011$) = $31.20 dollars per f oot × PipeLength × PipeFreightFactor

 For 1,584,000 gpd < FGD recycle flow ≤ 2,880,000 gpd (10 inch pipe)

- Pipe Cost (2011$) = $41.00 dollars per f oot × PipeLength × PipeFreightFactor

 For 2,880,000 gpd < FGD recycle flow ≤ 4,320,000 gpd (12 inch pipe)

- Pipe Cost (2011$) = $51.81 dollars per f oot × PipeLength × PipeFreightFactor

where:

FGD recycle flow = The flow rate of FGD wastewater recycled back to the scrubber in gpd, from the “High Flow FGD Input Table” (see Section 4.4.3), PipeLength = The length of pipe required based on the method of equalization (tank or existing FGD surface impoundment). Distance is 1,610 feet for an equalization tank and 4,481 f eet for an existing FGD surface impoundment, and Pipe Freight Factor = Fact or that accounts for freight cost as a percentage of purchase cost, 1.08.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A55) for details on the development of Equation 6-6 and the equations used to estimate pipe cost.Chapter 6 - FGD Wastewater Cost Methodology

6-14 6.1.6.2 Purchased Equipment Costs: Tanks
This section describes EPA’s developmen t of cost equations for tanks, including wastewater and sludge tanks, and chemical storage and pr eparation tanks. EPA obtained tank costs for wastewater and sludge tanks construc ted of FRP from Augusta Fiberglass and tanks constructed of carbon steel from Fisher Tank Company and Bendel Tank and Heat Exchanger Corporation.
The cost model estimates costs for plants to install and operate wastewater and sludge tanks as required for the chemical precipitati on treatment systems. Based on an evaluation of survey responses regarding wastewater treat ment tank materials of construction, and in consideration of estimated costs, EPA assumed th e equalization tank will be constructed of lined carbon steel while the reaction ta nks, sludge tanks, effluent ta nks, and feed tanks will be constructed of FRP. All tanks ar e open top designed to operate at atmospheric pressure and include ancillary equipment such as structur al supports, ladders, access walkways, piping, and valves. Many of the tanks require mixers, wh ich are costed separately in Section 6.1.6.4.
EPA calculated tank sizes using wastewater fl ow rate and tank hydraulic residence time. EPA determined the target residence time for each tank based on an evaluation of the residence times of the tanks operated by the BAT plants. Ta nks do not require a capacity factor because EPA’s evaluation of tank residence times for BAT plants accounts for excess capacity.
FRP tank costs are primarily based on tank capacity. Additionally, the vendor (Augusta Fiberglass) indicated that, to account for nozzles , baffles, or other needed ancillary equipment, tank costs should be escalated by 15 percent, which EPA has included as a factor in Equations 6-7 and 6-8.
For tanks from 10,000 to 50,000 gallons in volume:
Cost (2011$) = $1.25/gal × Tank Size × Ancillary Equipment Factor (6-7)

For tanks from 50,000 to 250,000 gallons in volume:
Cost (2011$) = $2/gal × Tank Size × Ancillary Equipment Factor (6-8)

where:

Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Tank Size = The size of the tank, in gallons, calculated by multiplying the FGD wastewater flow by the residence time required. Tank size equatio ns specific to the type of tank (e.g., reaction tank 1) are provided in the description for each tank type, presented later in this section.Chapter 6 - FGD Wastewater Cost Methodology

6-15 Augusta Fiberglass stated th at tanks smaller than 10,000 gall ons (which equates to a FGD wastewater treatment flow rate of 56 gpm) would need to be costed on a case-by-case basis. Augusta Fiberglass stated that the primary difference in costs between tanks 10,000 to 50,000 gallons in size and 50,000 to 250,000 gallons in size is that the smaller size tanks can be shopfabricated and shop-erected while the larger tank s must be shop-fabricated and field-erected; therefore, EPA assumed tanks less than 10,000 gall ons in size can also be shop-erected and can be costed using the same equation as for tanks 10,000 to 50,000 gallons in size.
Augusta Fiberglass stated th at the maximum feasible tank size for a shop-fabricated, field-erected tank is 250,000 gallons. Beyond this size, tanks must be built en tirely at the plant, requiring the vendor to construct a shop on site as well. Therefore, in those cases where FRP tanks larger than 250,000 gallons are required, multip le tanks of equal size are costed using the same pricing as tanks 50,000 to 250,000 gallons in size. For example, for a plant requiring a 260,000 gallon tank, two 130,000 gall on tanks are costed.
Additionally, Augusta Fiberglass provided frei ght cost estimates in dollars per mile for certain tank sizes [ERG, 2013; See Appendix 10]. EPA developed a cost function based on the data provided to estimate fr eight costs based on tank volume.
Tank Freight Cost (2011$) = Miles × 0.0454 × (Tank Size) 0.5481 (6-9)

where:

Miles = Expected average tank shipping distance, in miles, between tank supplier and plant, 500, and Tank Size = The size of the tank, in gallons, calculated by multiplying FGD wastewater flow by the residence time of the tank. Tank size equations specific to the type of tank are provided in the descriptions for each tank type, presented later in this section.

EPA obtained costs for shop-fabricated car bon steel tanks from Bendel Tank and Heat Exchanger Corporation (Bendel) and costs for field-fabricated carbon steel tanks from Fisher Tank Company.

Bendel indicated the maximum size carbon stee l tank that could be shop-fabricated is 70,000 gallons [ERG, 2013; See Appendix 13]. EPA requested purchase and freight costs for tanks ranging in size from 2,000 gallons to 70,000 gallons. Based on information provided by Bendel, EPA developed Equations 6-10 and 6- 11 for tank purchase and freight costs.
Tank Purchase Cost (201 1$) = 0.9412 × Tank Size + 4117.6 (6-10)

Tank Freight Cost (2011$) = 0.064 × Tank Size + 522.06 (6-11)Chapter 6 - FGD Wastewater Cost Methodology

6-16 where:

Tank Size = The size of the tank, in gallons, calculated by multiplying the FGD wastewater flow by the residence time of the tank. Tank size equations specific to the type of tank are provided in the descriptions for each tank type, presented late r in this section.

Due to the corrosive nature of FGD wastewater , the carbon steel tanks require a liner and/or coating. EPA requested liner and co atings costs and information from TSE, Inc., a representative of Tnemec Company. The vendor recommended usi ng Tnemec’s Series 61 Tneme-Liner system and provided an estimated installed cost of $8- 10 per square foot of internal tank surface area[ERG, 2013; See Appendix 13]. Th e installed cost incl udes the cost of the material, surface preparation, and labor to insta ll a multicoated epoxy lining system. Based on information from the liner and tank vendors, EPA developed an expr ession for the internal surface area of a tank based on the tank’s volume and multiplied this expression by the liner cost per square foot to develop a liner cost equation. To be conservative, EPA assumed a liner cost of $10 per square foot. EPA used Equation 6-12 to estimate liner costs.
Liner Cost (2011$) = Liner Cost Pe r Square Foot × 2.0885 × (Tank Size) 0.6282 (6-12)

where:

Liner Cost Per Square Foot = The installed cost, in do llars, of Tnemec’s Series 61 Tneme-Liner system per square foot of internal surface area of the tank, $10, and Tank Size = The size of the tank, in gallons, calculated by multiplying FGD wastewater flow by the residence time of the tank. Tank size equations specific to the type of tank are provided in the descriptions for each tank type, presented late r in this section.

The total cost for carbon stee l tanks up to 70,000 gallons can be calculated as the sum of the tank purchase cost (Equation 6-10), tank fr eight cost (Equation 6-11), and liner cost (Equation 6-12).
Cost (2011$) = Tank Purchase Cost + Tank Freight Cost + Liner Cost (6-13)

Cost (2011$) = (0.9412 × Tank Si ze + 4117.6) + (0.064 × Tank Size + 522.06) + [Liner Cost Per Square Foot × 2.0885 × (Tank Size) 0.6282 ] (6-14)

where:

Liner Cost Per Square Foot = The installed cost, in do llars, of Tnemec’s Series 61 Tneme-Liner system per square foot of internal surfaceChapter 6 - FGD Wastewater Cost Methodology

6-17 area of the tank, $10, and

Tank Size = The size of the tank, in gallons, calculated by multiplying FGD wastewater flow by the residence time of the tank. Tank size equations specific to the type of tank are provided in the descriptions for each tank type, presented late r in this section.

Fisher Tank Company indicated that field-fabricated tank sizes range from 30,000 gallons to 10 million gallons. EPA requested costs for five tank sizes ranging from 30,000 gallons to 1.5 million gallons. The cost estimates provided by Fisher Tank Company included all material, labor, and equipment necessary to design, supply, fabr icate, transport, erect, and test the tanks at the plant site, as well as transportation [E RG, 2013; See Appendices 16 and 17]. Additionally, flake glass interior linings are included in the tank cost estimates. Based on the estimates provided, EPA developed Equation 6-15 for car bon steel tanks over 70,000 gallons in size.
Cost (2011$) = -6×10 -8 × (Tank Size) 2 + 0.628 × (Tank Size) + 503999 (6-15)

where:

Tank Size = The size of the tank, in gallons, calculated by multiplying FGD wastewater flow by the residence time of the tank. Tank size equations specific to the type of tank are provided in the descriptions for each tank type, presented late r in this section.

Because the cost estimates provided already included transportation and liner costs, no additional terms are necessary.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A8 through A19, A81, and A85) for additional information regarding the devel opment of the equations used to estimate the costs associated with FRP and steel tanks.

Equalization Tank Cost The purpose of the equalization tank is to accu mulate wastewater to reduce wastewater variability and to optimize the size, effectiv eness, and operating costs for the subsequent treatment units. The cost varies based on flow rate. The following equations are used to cost tanks with the specified ranges of FGD Wa stewater Flow GPD (see Section 6.1.5 for a discussion of FGD Wastewater Flow GPD). The hydraulic residence time (HRT) for the equalization tank(s) is assumed to be one day (i.e., 24 hours). EPA costed lined carbon steel equalization tanks.
Because lined carbon steel tanks can be provi ded in sizes up to 10 million gallons in volume, EPA assumed one equalization tank woul d be sufficient for all plants, with the exception of “high flow” plants (discussed in Section 4.4.3).Chapter 6 - FGD Wastewater Cost Methodology

6-18 EPA first calculated equalization tank size using the equations for carbon steel tanks described earlier in this section:
Equalization Tank Size (gal) = FGD Wastew ater Flow GPD × Equalization Tank HRT (6-16)

where:

FGD Wastewater Flow GPD = FGD wastewater flow rate in gpd as reported in the Steam Electric Survey (see Section 6.1.5), and Equalization Tank HRT = The hydraulic resi dence time of the equalization tank in days, 1.

EPA then calculated the equalization ta nk cost based on the size of the tank.
For tanks less than or equal to 70,000 gallons in size EPA estimate d costs using Equation 6-17.
Equalization Tank Cost (2011$) = (0.9412 × Equalization Tank Size + 4117.6) + (0.064 × Equation Tank Size+ 522.06) + [Liner Cost Pe r Square Foot × 2.0885 × (Equalization Tank Size) 0.6282 ] (6-17)

where:

Liner Cost Per Square Foot = The installed cost, in do llars, of Tnemec’s Series 61 Tneme-Liner system per square foot of internal surface area of the tank, $10, and Equalization Tank Size = Equalization tank size, in gallons (see Equation 6-16).

For tanks greater than 70,000 gallons in size EPA estimated costs using Equation 6-18.
Equalization Tank Cost (2011$) = -6×10 -8 × (Equalization Tank Size) 2 + 0.628 × (Equalization Tank Size) + 503999 (6-18)

where:

Equalization Tank Size = Equalization tank size, in gallons (see Equation 6-16).

For plants with equalization treatment in pl ace, EPA first determined the residence time of their existing equalization equi pment based on their response to Question D5-2 of the Steam Electric Survey. If their response is 24 hours or more equalization re sidence time, or if the plant did not report a residence time, then EPA assu med the plant has adequa te equalization capacity. If their response was less than 24 hours equali zation residence time, then EPA estimated costs for the additional equalization capacity needed using the cost equations listed above and substituting the variable “FGD Wast ewater Flow GPD” with “Treatment In Place GPD” which isChapter 6 - FGD Wastewater Cost Methodology

6-19 the amount of the FGD wastewater flow GPD that cannot be handl ed by the existing equalization equipment. Treatment In Place GPD is calculated using Equation 6-19.
Treatment In Place GPD (gpd) = [(24 – Current HRT) / 24] × FGD Wastewater Flow GPD (6-19)

where:

Current HRT = Current chemical precipitation equali zation residence time as reported in response to Question D5-2 of the Steam Electric Survey, in hours, and
FGD Wastewater Flow GPD = FGD wastewater flow rate in gpd as reported in the Steam Electric Survey (see Section 6.1.5).

Reaction Tank 1 Cost EPA costed one FRP reaction tank 1 per plant, with a residence time of 3 hours (i.e., 180 minutes) based on a review of the BAT plants. In reaction tank 1, the wastewater pH is raised using lime to precipitate the soluble metals as insoluble hydroxides and oxyhydroxides. The reaction tank also desaturates the gypsum in the wastewater, which prevents gypsum scale formation in the downstream wast ewater treatment equipment. To desaturate the gypsum, some of the sludge from the downstream primary clarif ier is recycled back to reaction tank 1 to provide seed crystals for gypsum nucleation. The cost varies ba sed on flow rate. EPA created a step-wise function based on tank si ze (as described for FRP tanks earlier in this section) to estimate the cost for reaction tank 1. The following equations are used to cost tanks with the specified FGD wastewater flow rate ranges.
The tank size breakpoint in the equations described for FRP tanks (Equation 6-7) is 50,000 gallons. EPA then calculated the maximum fl ow rate, in gpm, that can be accommodated by a reaction tank 1 size of 50,000 gallons.
Reaction Tank 1 Breakpoint (gpm) = 50,000 gal / Reaction Tank 1 HRT = 278 gpm (6-20)

where:

Reaction Tank 1 HRT = The hydraulic re sidence time of Reaction Tank 1, in minutes, 180.

Next, EPA calculated the size of re action tank 1 using Equation 6-21.
Reaction Tank 1 Size (gal) = FGD Wastewater Treatment Flow GPM × Reaction Tank 1 HRT (6-21)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), andChapter 6 - FGD Wastewater Cost Methodology

6-20 Reaction Tank 1 HRT = The hydraulic re sidence time of reaction tank 1, in minutes, 180.

Based on the FGD wastewater flow, the cost model then chooses which of the following equations to use to calculate the tank cost. The firs t term in the equation calculates the cost of the tank itself while the second term in the equation calculates freight costs.

For FGD Wastewater Treatment Flow GPM le ss than or equal to the Reaction Tank 1 Breakpoint GPM (i.e., tanks less than or equal to 50,000 gallons in size) EPA used Equation 6-22.
Reaction Tank 1 Cost (2011$) = $1. 25/gal × Reaction Tank 1 Size × Ancillary Equipment Factor + Miles × 0.0454 × (Reaction Tank 1 Size) 0.5481 (6-22)

where:

Reaction Tank 1 Size = Reaction tank 1 si ze, in gallons (see Equation 6-21),
Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Miles = Expected average tank shipping distance, in miles, between tank supplier and power plant, 500.

For FGD Wastewater Treatment Flow GPM gr eater than the Reaction Tank 1 Breakpoint (i.e., tanks greater than 50,000 gallons in size) EPA used Equation 6-23.
Reaction Tank 1 Cost (2011$) = $2/ gal × Reaction Tank 1 Size × Ancillary Equipment Factor + Miles × 0.0454 × (Reaction Tank 1 Size) 0.5481 (6-23)

where:

Reaction Tank 1 Size = Reaction tank 1 si ze, in gallons (see Equation 6-21),
Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Miles = Expected average tank shipping distance, in miles, between tank supplier and power plant, 500.

Reaction Tank 2 Cost and Reaction Tank 3 Cost
EPA costed one FRP reaction tank 2 and one FRP reaction tank 3 per plant, each with a residence time of 1 hour based on a review of th e BAT plants. In reaction tank 2, organosulfide is added, primarily to remove mercury and aid in the settling of precipita tes. In reaction tank 3, ferric chloride is added to aid in precipitation of heavy metals . The cost varies based on flow rate. Both tanks are the same size as the residence times are the same. The following equations are used to cost tanks with the specif ied FGD wastewater flow rate ranges.Chapter 6 - FGD Wastewater Cost Methodology

6-21 The tank size breakpoint in the equations described for FRP tanks (Equation 6-7) is 50,000 gallons. EPA then calculated the maximum fl ow rate, in gpm, that can be accommodated by a reaction tank 2 size of 50,000 gallons.
Reaction Tank 2 Breakpoint (gpm) = 50,000 gal / Reaction Tank 2 HRT = 833 gpm (6-24)

where:

Reaction Tank 2 HRT = The hydraulic re sidence time of reaction tank 2, in minutes, 60.

Next, EPA calculated reaction ta nk 2 size using Equation 6-25.
Reaction Tank 2 Size (gal) = FGD Wastewater Treatment Flow GPM × Reaction Tank 2 HRT (6-25)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and Reaction Tank 2 HRT = The hydraulic re sidence time of reaction tank 2, in minutes, 60.

Based on the FGD wastewater flow, the cost model then chooses which of the following equations to use to calculate the tank cost. The firs t term in the equation calculates the cost of the tank itself while the second term in the equation calculates freight costs.

For FGD Wastewater Treatment Flow GPM le ss than or equal to the Reaction Tank 2 Breakpoint (i.e., tanks less than or equal to 50,000 gallons in size) EPA used Equation 6-26.
Reaction Tank 2 Cost (2011$) = $1. 25/gal × Reaction Tank 2 Size × Ancillary Equipment Factor + Miles × 0.0454 × (Reaction Tank 2 Size) 0.5481 (6-26)

where:

Reaction Tank 2 Size = Reaction tank 2 size, in gallons, (see Equation 6-25),
Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Miles = Expected average tank shipping distance, in miles, between tank supplier and power plant, 500.

For FGD Wastewater Treatment Flow GPM greater than Reacti on Tank 2 Breakpoint (i.e., tanks greater than 50,000 gallons in size) EPA used Equation 6-27.Chapter 6 - FGD Wastewater Cost Methodology

6-22 Reaction Tank 2 Cost (2011$) = $2/ gal × Reaction Tank 2 Size × Anci llary Equipment Factor + Miles × 0.0454 × (Reaction Tank 2 Size) 0.5481 (6-27)

where:

Reaction Tank 2 Size = Reaction tank 2 size, in gallons, (see Equation 6-25),
Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Miles = Expected average tank shipping distance, in miles, between tank supplier and power plant, 500.

Reaction tank 3 is defined in the same way as reaction tank 2. EPA assumed that one FRP reaction tank 3 with a 1-hour (i.e., 60 minute) re sidence time would be sufficient for all of the plants.
The tank size breakpoint in the equations described for FRP tanks (Equation 6-7) is 50,000 gallons. EPA then calculated the maximum fl ow rate, in gpm, that can be accommodated by a reaction tank 3 size of 50,000 gallons.
Reaction Tank 3 Breakpoint (gpm) = 50,000 gal / Reaction Tank 3 HRT = 833gpm (6-28)

where:

Reaction Tank 3 HRT = The hydraulic re sidence time of reaction tank 3, in minutes, 60.

Next, EPA calculated reaction tank 3 size using Equation 6-29.
Reaction Tank 3 Size (gal) = FGD Wastewater Treatment Flow GPM × Reaction Tank 3 HRT (6-29)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and Reaction Tank 3 HRT = The hydraulic re sidence time of reaction tank 3, in minutes, 60.

Based on the FGD wastewater flow, the cost model then chooses which of the following equations to use to calculate the tank cost. The firs t term in the equation calculates the cost of the tank itself while the second term in the equation calculates freight costs.

For FGD Wastewater Treatment Flow GPM le ss than or equal to the Reaction Tank 3 Breakpoint (i.e., tanks less than or equal to 50,000 gallons in size) EPA used Equation 6-30.Chapter 6 - FGD Wastewater Cost Methodology

6-23 Reaction Tank 3 Cost (2011$) = $1. 25/gal × Reaction Tank 3 Size × Ancillary Equipment Factor + Miles × 0.0454 × (Reaction Tank 3 Size) 0.5481 (6-30)

where:

Reaction Tank 3 Size = Reaction tank 3 size, in gallons, (see Equation 6-29),
Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Miles = Expected average tank shipping distance, in miles, between tank supplier and power plant, 500.

For FGD Wastewater Treatment Flow GPM gr eater than the Reaction Tank 3 Breakpoint (i.e., tanks greater than 50,000 gallons in size) EPA used Equation 6-31.
Reaction Tank 3 Cost (2011$) = $2/ gal × Reaction Tank 3 Size × Ancillary Equipment Factor + Miles × 0.0454 × (Reaction Tank 3 Size) 0.5481 (6-31)

where:

Reaction Tank 3 Size = Reaction tank 3 size, in gallons, (see Equation 6-29),
Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Miles = Expected average tank shipping distance, in miles, between tank supplier and power plant, 500.

Flash Mix Tank and Flocculation Tank Cost
The solids contact clarifier ve ndor indicated that a flash mix and flocculation tank is generally not required fo r polymer addition prior to the solids contact clarifier (i.e., polymer is added in line); therefore, EPA did not calculate costs for flash mix and flocculation tanks. Note that of the three BAT plants, one injects polymer in line, one a dds polymer in a dedicated flash mix/splitter tank, and [Redacted].

Treated Wastewater Tank Cost EPA costed one effluent tank per plant with a residence time of one hour, based on the BAT plants. EPA assumed that shop -built FRP tanks would serve as the treated wastewater tanks at all of the plants. The efflue nt tanks hold the treated wastewat er prior to discharge or other reuse/recycling. For stand-alone ch emical precipitation treatment sy stems, these tanks are located after chemical precipitation, at the end of the treatment syst em. For chemical precipitation followed by biological treatment or vapor-compre ssion evaporation, these tanks are located at the end of the biological treatment or vapor-compression evap oration systems. The cost varies based on flow rate as shown in the following equations with the following GPM flow rate ranges.Chapter 6 - FGD Wastewater Cost Methodology

6-24 Because the maximum size for shop-built FRP tanks is 50,000 gallons, multiple tanks are costed for plants with large flow rates requiring additional volume.

Treated WW Tank Qty = Treated WW Tank HRT × FGD Wastewater Treatment Flow GPM / 50,000 gal (rounded up to the nearest whole number) (6-32)

where:

Treated WW Tank HRT = The hydraulic residence time of each treated wastewater tank, in minutes, 60, and

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5).

Next, EPA calculated the size of each trea ted wastewater tank using Equation 6-33.
Treated WW Tank Size (gal) = FGD Wastewater Treatment Flow GPM × Treated WW Tank HRT / Treated WW Tank Qty (6-33)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5),
Treated WW Tank HRT = The hydraulic residence time of each treated wastewater tank , in minutes, 60, and Treated WW Tank Qty = The number of tr eated wastewater tanks, rounded up to the nearest whole number (see Equation 6-32).

The cost model then calculates the cost of the tank itself (the first term in Equation 6-34), plus freight costs (the second term in Equation 6-34).
Treated Wastewater Tank Cost (2011$) = [$1.25/gal × Treated WW Tank Size × Ancillary Equipment Factor + Miles × 0.0454 × (Treated WW Tank Size) 0.5481 ] × Treated WW Tank Qty (6-34)

where:

Treated WW Tank Size = Treated wastewater tank size, in gallons, (see Equation 6-33), Treated WW Tank Qty = The number of tr eated wastewater tanks, rounded up to the nearest whole number, (see Equation 6-32), Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Miles = Expected average tank shipping distance, in miles,Chapter 6 - FGD Wastewater Cost Methodology

6-25 between tank supplier and power plant, 500.

Sludge Holding Tank Cost EPA costed one FRP sludge holding tank per pl ant, based on the BAT plants. The sludge tank receives sludge from the clarifiers. The cost varies based on flow rate.
The tank size breakpoint in the equations described for FRP tanks (Equation 6-7) is 50,000 gallons. EPA calculated the maximum flow rate, in gpm, that can be accommodated by a sludge holding tank size of 50,000 gallons.
Sludge Holding Tank Breakpoint (gpm) = 50,000 gal / Sludge Holding Tank HRT = 417 gpm (6-35)

where:

Sludge Holding Tank HRT = Factor representing the ratio of sludge tank size to the FGD wastewater flow rate, 120. This factor is not a residence time; however, the factor is calculated in the same way as the wastewater tank residence times and its unit is minutes.

Next, EPA calculated sludge hol ding tank size using Equation 6-36.
Sludge Holding Tank Size (gal) = FGD Wastew ater Treatment Flow GPM × Sludge Holding Tank HRT (6-36)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and Sludge Holding Tank HRT = Factor representing the ratio of sludge tank size to the FGD wastewater flow rate, in minutes, 120.

Based on the FGD wastewater flow, the cost model then chooses which of the following equations to use to calculate the tank cost. The firs t term in the equation calculates the cost of the tank itself while the second term in the equation calculates freight costs.
For FGD Wastewater Treatment Flow GPM less than or equal to the Sludge Holding Tank Breakpoint (i.e., tanks less than or equa l to 50,000 gallons in size) EPA used Equation 6-37.
Sludge Holding Tank Cost (2011$) = $1.25/gal × Sludge Holding Tank Size × Ancillary Equipment Factor + Miles × 0.0454 × (Sludge Holding Tank Size) 0.5481 (6-37)Chapter 6 - FGD Wastewater Cost Methodology

6-26 where:

Sludge Holding Tank Size = Sludge holding tank size, in gallons, calculated as described previously in th is section, (see Equation 6-36), Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Miles = Expected average tank shipping distance, in miles, between tank supplier and power plant, 500.

For FGD Wastewater Treatment Flow GPM greater than the Sludge Holding Tank Breakpoint (i.e., tanks greater than 50,000 gallons in size) EPA used Equation 6-38.
Sludge Holding Tank Cost (2011$) = $2/gal × Sl udge Holding Tank Size × Ancillary Equipment Factor + Miles × 0.0454 × (Sludge Holding Tank Size) 0.5481 (6-38)

where:

Sludge Holding Tank Size = Sludge holding tank size, in gallons, calculated as described previously in th is section, (see Equation 6-36), Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Miles = Expected average tank shipping distance, in miles, between tank supplier and power plant, 500.

Biological or Vapor-Compression Evaporati on Treatment System Feed Tank Cost When chemical precipitation treatment is fo llowed by a biological or vapor-compression evaporation treatment system, EPA costed one additional FRP feed tank per plant with a 30- minute residence time. EPA determined the design residence time of the feed tank based on an evaluation of feed tanks operated by two steam electric power plants sampled by EPA whose effluent data were used to represent the best performance of FGD biologi cal treatment. This tank is located after chemical precipitation to hold the effluent from the chemical precipitation system and to act as a feed tank for the biological or vapor-compression evaporation treatment systems. The cost varies based on flow rate.
The tank size breakpoint in the equations described for FRP tanks (Equation 6-7) is 50,000 gallons. EPA then calculated the maximum flow rate, in gpm, that can be accommodated by a feed tank size of 50,000 gallons.
Bio VC Feed Tank Breakpoint (gpm) = 50,000 gal / Bio VC Feed Tank HRT = 1,667 gpm (6-39)Chapter 6 - FGD Wastewater Cost Methodology

6-27 where:

Bio VC Feed Tank HRT = The hydraulic residence time of the biological or vapor-compression evaporati on treatment system feed tank, in minutes, 30.

Next, EPA calculated the biol ogical or vapor-compression ev aporation feed tank size using Equation 6-40.
Bio VC Feed Tank Size (gal) = FGD Wastewat er Treatment Flow GPM × Bio VC Feed Tank HRT (6-40)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and BioVC Feed Tank HRT = The hydraulic re sidence time of the biological or vapor-compression evaporati on treatment system feed tank, in minutes, 30.

Based on the FGD wastewater flow, the co st model chooses which of the following equations to use to calculate the tank cost. The firs t term in the equation calculates the cost of the tank itself while the second term in the equation calculates freight costs.

For FGD Wastewater Flow GPM less than or equal to the Bio VC Feed Tank Breakpoint (i.e., tanks less than or equal to 50,000 ga llons in size) EPA used Equation 6-41.
Biological or Vapor-Compression Evaporation Treatment System Feed Tank Cost (2011$) = $1.25/gal × Bio VC Feed Tank Size × Ancillary Equipment Factor + Miles × 0.0454 × (Bio VC Feed Tank Size) 0.5481 (6-41)

where:

Bio VC Feed Tank Size = Biological or vapor-compression eva poration treatment system feed tank size, in gallons, (see Equation 6-40), Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Miles = Expected average tank shipping distance, in miles, between tank supplier and power plant, 500.

For FGD Wastewater Treatment Flow GPM greater than the Bio VC Feed Tank Breakpoint (i.e., tanks greater than 50,000 gallons in size) EPA used Equation 6-42.Chapter 6 - FGD Wastewater Cost Methodology

6-28 Biological or Vapor-Compression Evaporation Treatment System Feed Tank Cost (2011$) = $2/gal × Bio VC Feed Tank Size × Ancillary Equipment Factor + Miles × 0.0454 × (Bio VC Feed Tank Size) 0.5481 (6-42)

where:

Bio VC Feed Tank Size = Biological or vapor-compression eva poration treatment system feed tank size, in gallons, (see Equation 6-40), Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Miles = Expected average tank shipping distance, in miles, between tank supplier and power plant, 500.

Filtrate Sump Cost EPA included costs for plants to construct a concrete basin to act as a filtrate sump receiving filtrate from the filter presses and othe r miscellaneous floor drain wastewater from the wastewater treatment plant within the site preparation costs described in Section 6.1.6.11.

Chemical Preparation and Storage Tanks EPA estimated costs for plants to install and operate the chemical preparation and storage tanks required for chemical pr ecipitation treatment systems. Ba sed on input from vendors, EPA expects organosulfide and polymer to be deliver ed and stored onsite in totes and, therefore, organosulfide and polymer chemical storage tanks are not required. 27 Ferric chloride and/or hydrochloric acid storage tanks are costed for thos e plants estimated to consume more than one 275-gallon tote of either of these chemicals per day. 28

EPA estimated the costs for chemical st orage tanks based on the costs for FRP wastewater and sludge tanks provided by Augusta Fiberglass [ERG, 2013; See Appendix 23]. All tanks are designed to operate at atmospheric pressure. EPA requested that purchase costs provided by vendors also include an cillary equipment, such as structural supports, ladders, access walkways, piping, and valves. EPA requested vendor costs for varying sizes of chemical preparation and storage tanks appr opriate for wastewater flow ra tes ranging from 7 to 700 gpm, and EPA created a cost function using costs obtained from the vendor to extrapolate or interpolate costs for each plant base d on FGD wastewater flow rate.
EPA assumed that shop-built FRP tanks would se rve as the chemical storage tanks at all of the plants, except those expect ed to use totes for storage. Because the maximum size for shopbuilt FRP tanks is 50,000 gallons, EPA costed multiple tanks where more storage is needed.

27 See Sections 6.1.6.3 and 6.1.7.4 for discussion of costing errors associated with EPA’s organosulfide and polymer purchase, freight, storage, and feed systems.

28 EPA neglected to estimate costs for the purchase or lease of totes for plants assumed to store ferric chloride and hydrochloric acid onsite in totes. EPA estimates tote purc hase costs would be $2,850 per plant for plants requiring totes for onsite storage of only one of the chemicals (i.e., ferric chloride or hydrochloric acid), and $5,700 per plant for plant requiring totes for onsite storage of both ferric chloride and hydrochloric acid.Chapter 6 - FGD Wastewater Cost Methodology

6-29 EPA calculated the chemical st orage tank sizes based on the chemical dosages (gallons of chemical added per gallon wastewat er treated) and the amount of ch emical the plant is expected to store on site (in days). EPA assumed that a pl ant will need to store 15 days worth of chemical on site (i.e., enough chemical to perform the n eeded chemical additions for 15 days, based on input from vendors).
Note: see Section 6.1.6.3 (Chemical Feed System s Cost) for a discussion of the chemical dose conversion factors used in the ch emical storage tank cost equations.
Lime Slurry Preparation and Storage Tank Cost . The lime slurry feed system for which the vendor provided costs includes a combined pr eparation and storage tank, as described in Section 6.1.6.3. Therefore, EPA did not develop separate cost equations for these tanks.
Ferric Chloride Storage Tank Cost . EPA costed storage tanks for 35 percent concentration ferric chloride for plants with FGD wastewater flow rates gr eater than the trigger flow rate calculated as described below. The tr igger flow rate is calc ulated assuming plants requiring more than one tote of ferric chloride per day would install a st orage tank, while plants requiring less than one tote of ferric chloride per day would not install a storage tank. EPA used Equation 6-43 to calculate the ferr ic chloride trigger flow rate.

FeCl3 Tank WW Flow Limit (gpm) = (Tote Volume × Totes Per Day / Min Per Day) / (Ferric Chloride Dose × FeCl3 Dose Factor × Capacity Factor × Liter to Gallon Factor) (6-43)

where:

Tote Volume = The volume, in gall ons, of a standard size chemical tote, 275, Totes Per Day = The maximum number of totes of chemical a plant requires per day above whic h a plant would install a chemical storage tank, 1, Min Per Day = Number of minutes per day, 1440,

Ferric Chloride Dose = Amount of ferric chloride, in g/ L, needed to treat the FGD wastewater in the chem ical precipitation system as determined in Section 6.1.7.4,
FeCl3 Dose Factor = Factor to convert dose from grams of neat chemical per liter of FGD wastewater to liters of chemical solution per liter of FGD wastewater. See the discussion for Liquid Feed Systems in Section 6.1.6.3 for further details, Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted], andChapter 6 - FGD Wastewater Cost Methodology

6-30 Liter to Gallon Factor = Unit conversion f actor, equal to 1, which converts liters of chemical solution per liter of wastewater to gallons of chemical solution per ga llon of wastewater. It is calculated as:

ଷ.଻଼ହ ௅ ௪௔௦௧௘௪௔௧௘௥

௚௔௟ ௪௔௦௧௘௪௔௧௘௥ ൈ ௚௔௟ ௖௛௘௠௜௖௔௟ ௦௢௟ᇱ௡
ଷ.଻଼ହ ௅ ௖௛௘௠௜௖௔௟ ௦௢௟ᇱ௡ .

As described above, if the FGD Wastewater Tr eatment Flow GPM is less than the FeCl3 Tank WW Flow Limit, EPA assumed that the plant will use totes to store the ferric chloride and, therefore, assumed no costs asso ciated with a storage tank. If the FGD Wastewater Treatment Flow GPM is greater than the FeCl3 Tank WW Flow Limit, th en EPA costed a storage tank using tank size and quantity.
The tank quantity is calculated by dividing the required storage amount of FeCl3 by the maximum size for shop-built FRP tanks, as shown in Equation 6-44.
FeCl3 Tank Qty = FeCl3 Rate × FeCl3 Storag e Time /50,000 gal (rounded up to the nearest whole number) (6-44)

where:

FeCl3 Rate = Ferric chloride vol umetric addition rate in gph. See Ferric Chloride Feed System Cost in Section 6.1.6.3 for details, and FeCl3 Storage Time = The hours of suppl y of ferric chloride the plant stores on site. EPA assumed a plant would keep up to 15 days’, or 360 hours’, worth of FeCl3 on site.
FeCl3 Rate = Ferric chloride vol umetric addition rate in gph. See Ferric Chloride Feed System Cost in Section 6.1.6.3 for details, and

Next, EPA calculated the FeCl 3 tank size using Equation 6-45.
FeCl3 Tank Size (gal) = FeCl3 Rate × FeCl3 Storage Time / FeCl3 Tank Qty (6-45)

where:

FeCl3 Rate = Ferric chloride vol umetric addition rate in gph. See Ferric Chloride Feed System Cost in Section 6.1.6.3 for details, FeCl3 Storage Time = The hours of suppl y of ferric chloride the plant stores on site. EPA assumed a plant would keep 15 days’, or 360 hours’, worth of ferric chloride on site, andChapter 6 - FGD Wastewater Cost Methodology

6-31 FECl3 Tank Qty = The number of FeCl 3 storage tanks required, rounded up to the nearest whole nu mber (see Equation 6-44).
FeCl3 Rate = Ferric chloride vol umetric addition rate in gph. See Ferric Chloride Feed System Cost in Section 6.1.6.3 for details,

The tank(s) are then costed as follows. The fi rst term in Equation 6-46 calculates the cost of the tank itself while the second term in Equation 6-46 calcula tes freight costs.
Ferric Chloride Storage Tank Cost (2011$) = [$1.25/gal × FeCl3 Tank Size × Ancillary Equipment Factor + Miles × 0.0454 × (FeCl3 Rate × FeCl3 Storage Time / FeCl3 Tank Qty) 0.5481 ] × FeCl3 Tank Qty (6-46)

where:

FeCl3 Tank Size = FeCl3 tank size, in gallons (see Equation 6-45),
Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Miles = Expected average tank shipping distance, in miles, between tank supplier and power plant, 500.

Hydrochloric Acid Storage Tank Cost . EPA costed storage tanks for 32 percent concentration hydrochloric acid for plants with FGD wastewater flow rates greater than the trigger flow rate calculated as described below. The trigger flow rate is calculated assuming plants requiring more than one tote of hydrochl oric acid per day would install a storage tank, while plants requiring less than one tote of hydrochloric acid per day would not in stall a storage tank.
HCl Tank WW Flow Limit (gpm) = (Tote Vo lume × Totes Per Day / Min Per Day) /

(Hydrochloric Acid Dose × HCl Dose Factor × Lite r to Gallon Factor × Capacity Factor × Liter to Gallon Factor) (6-47)

where:

Tote Volume = The volume, in gall ons, of a standard size chemical tote, 275, Totes Per Day = The maximum number of totes of chemical a plant requires per day above whic h a plant would install a chemical storage tank, 1, Min Per Day = Number of minutes per day, 1440,
Hydrochloric Acid Dose = Amount of hydrochloric acid, in g/L, needed to treat the FGD wastewater in the chemical precipitationChapter 6 - FGD Wastewater Cost Methodology

6-32 system, as determined in Section 6.1.7.4,

HCl Dose Factor = Factor to convert dose from grams of neat chemical per liter of FGD wastewater to liters of chemical solution per liter of FGD wastewater. See the discussion for Liquid Feed Systems in Section 6.1.6.3 for further details, Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted], and
Liter to Gallon Factor = Unit conversion f actor, equal to 1, which converts liters of chemical solution per liter of wastewater to gallons of chemical solution per ga llon of wastewater. It is calculated as:
ݎ݁ݐܽݓ݁ݐݏܽݓ ܮ 3.785

ݎ݁ݐܽݓ݁ݐݏܽݓ ݈݃ܽ ൈ ݊Ԣ݈݋ݏ݈݃ܽ ݄݈ܿ݁݉݅ܿܽ ݊Ԣ݈݋ݏ ݄݈ܿ݁݉݅ܿܽ ܮ3.785

As described above, if the FGD Wastewater Treatment Flow GPM is less than the HCl Tank WW Flow Limit, EPA assume d that the plant will use totes to store the hydrochloric acid and, therefore, assumed no costs associated with a storage tank. If the FGD Wastewater Treatment Flow GPM is greater than the HCl Ta nk WW Flow Limit, then EPA costed a storage tank using tank size and quantity.
The tank quantity is calculated by dividi ng the required storage amount of HCl by the maximum size for shop-built FRP tanks.
HCl Tank Qty = HCl Rate × HCl Storage Time/50,000 gal (rounded up to the nearest whole number) (6-48)

where:

HCl Rate = Hydrochloric acid volu metric addition rate in gph. See Hydrochloric Acid Feed System Cost in Section 6.1.6.3 for details, and HCl Storage Time = The hours of s upply of hydrochloric acid the plant stores on site. EPA assumed a plant would keep 15 days’, or 360 hours’, wort h of hydrochloric acid on site.

Next, EPA calculated the HCl tank size using Equation 6-49.
HCl Tank Size (gal) = HCl Rate × HCl Storage Time / HCl Tank Qty (6-49)Chapter 6 - FGD Wastewater Cost Methodology

6-33 where:

HCl Rate = Hydrochlorice acid volu metric addition rate in gph. See Hydrochloric Acid Feed System Cost in Section 6.1.6.3 for details, HCl Storage Time = The hours of s upply of hydrochloric acid the plant stores on site. EPA assumed a plant would keep 15 days’, or 360 hours’, wort h of hydrochloric acid on site, and HCl Tank Qty = The number of HCl storage tanks required, rounded up to the nearest whole number (see Equation 6-48).

The tank(s) are then costed as follows. The fi rst term in Equation 6-50 calculates the cost of the tank itself while the second term in Equation 6-50 calcula tes freight costs.
Hydrochloric Acid Storage Tank Cost ( 2011$) = [$1.25/gal × HCl Tank Size × Ancillary Equipment Factor + Miles × 0.0454 × (HCl Tank Size) 0.5481 ] × HCl Tank Qty (6-50)

where:

HCl Tank Size = HCl tank size, in gallons (see Equation 6-49),
HCl Tank Qty = The number of HCl storage tanks required, rounded up to the nearest whole number (see Equation 6-48), Ancillary Equipment Factor = Factor that accounts for nozzles, baffles, and other ancillary equipment, 1.15, and Miles = Expected average tank shipping distance, in miles, between tank supplier and power plant, 500.

6.1.6.3 Purchased Equipment Costs: Chemical Feed Systems
EPA developed chemical feed system cost e quations based on cost per feed point data provided by Enpro-Tech [ERG, 2013; See Appendi ces 20, 21, and 22]. Enpro-Tech provided the maximum reasonable addition rate that could be provided by each feed point and the cost for each feed point. EPA calculated the chemical addition rate required for each plant, and determined the number of feed points that woul d be required. EPA used the following equations to calculate the chemical addition rate (gpm) and the cost of feed systems. Note: each liquid feed system includes two 100 percent capacity pumps.
The total cost for chemical feed systems is made up of the following cost elements:

 Lime feed system cost,

 Ferric chloride feed system cost,

 Organosulfide feed system cost,Chapter 6 - FGD Wastewater Cost Methodology

6-34  Polymer feed system cost, and

 Hydrochloric acid feed system cost.

Lime Feed System Cost EPA obtained cost estimates from Enpro-Tech for their SiloPacTM lime feed system. Each lime slurry feed system includes one or more storage silo(s), a volumetric feeder, a control system, a mix tank, and two peristaltic slurry pumps . Solid hydrated lime is stored in the silos and processed into a 10 percent by-we ight slurry within the system.
The cost of the lime feed system is driven by the cost of the storage silos. EPA assumed each plant would keep up to 15 days’ worth of lime onsite. EPA developed an equation to calculate the required lime storage volume based on the dose, wastewater flow rate, and storage time. Using cost estimates provided by the vendor , EPA then developed an equation relating the cost of the lime feed to the required lime storage volume [ERG, 2013; See Appendices 20, 21, and 22]. EPA added $10,000 to the cost equation to account for freight and training, based on input from the vendor.
EPA first calculated the mass addition rate of lime, in grams per minute, required to treat FGD wastewater (referred to as the Lime Dose Rate) using Equation 6-51.
Lime Dose Rate (gpm) = Hydrated Lime Do se × FGD Wastewater Treatment Flow GPM × Capacity Factor × 3.78 L/Gal (6-51)

where:

Hydrated Lime Dose = Amount of lime in, g/L, needed to treat the FGD wastewater in the chemical precipitation system, as determined in Section 6.1.7.4,

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation(see Section 6.1.5), and Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted].

Next, EPA calculated the volumet ric addition rate of lime, in gpm, required to treat FGD wastewater (referred to as the Lime Volume Rate) using Equation 6-52.
Lime Volume Rate (gpm) = Lime Dose Rate / (1,000 g/kg × Lime Density × 3.78 L/gal) (6-52)

where:

Lime Dose Rate = The mass addition rate of lime, gpm, (see Equation 6-51), and Lime Density = The density of lime, in kg/L, 0.5.Chapter 6 - FGD Wastewater Cost Methodology

6-35 Next, EPA calculated the volume, in cubic f eet, of the supply of lime the plant would store on site using Equation 6-53.
Lime Storage Volume (ft 3 ) = Lime Storage Time × Lime Volume Rate / 7.48 gal/ft 3 (6-53)

where:

Lime Storage Time = The minutes of supply of lime the plant stores on site. EPA assumed a plant would keep 15 days’, or 21,600 minutes’, worth of lime on site, and
Lime Volume Rate = The volumetric addi tion rate of lime required to treat FGD wastewater, in gp m (see Equation 6-52).

Finally, EPA calculated the cost of the lime slurry feed system using Equation 6-54.
Lime Slurry Feed System Cost (2011$) = 0.0004 × (Lime Storage Volume) 2 + 17.487 × Lime Storage Volume + 193013 + Li me Feed Freight Cost (6-54)

where:

Lime Storage Volume = The supply of lime the plant stores on site, ft 3 , (see Equation 6-53)and Lime Feed Freight Cost = Cost for frei ght and training for the lime slurry feed system, $10,000.

For liquid feed systems (i.e., chemical feed systems other than lime), a factor must be applied to convert the dose from grams of neat ch emical per liter of FGD wa stewater to liters of chemical solution per li ter of FGD wastewater:

Dose Conversion Factor L chemical sol'n g neat chemical =
1

Concentration g neat chemical g chemical sol'n × Density kg chemical sol'n L chemical sol'n × 1000 g chemical sol'n kg chemical sol'n

Using the dose conversion fact or and chemical dose, EPA next calculated the volumetric addition rate for each liquid chemical using Equation 6-55.

Volumetric Chemical Addition Rate (gpd) = Dose × Dose Factor × 3.785 L wastewater/gal wastewater × gal chemical/3.785 L chemical × FGD Wastewater Treatment Flow GPM × Capacity Factor (6-55)

where:

Dose = Amount of chemical, in g/L, needed to treat the FGDChapter 6 - FGD Wastewater Cost Methodology

6-36 wastewater in the chemical precipitation system, as determined in Section 6.1.7.4,
Dose Factor = Factor to convert dos e from grams of neat chemical per liter of FGD wastewater to liters of chemical solution per liter of FGD wastewater,
FGD Wastewater Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted].

The vendor also stated that typical liquid feed systems weigh no more than 500 pounds and have dimensions of approximately 3’x 3’x 5’ . The vendor estimated freight for these systems would be approximately $300.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A24 and SE01825.A25) for more discussion on the deve lopment of Equations 6-51 through 6-55.

Ferric Chloride Feed System Cost EPA assumed a 35 percent concentrati on of ferric chloride in solution.

The vendor stated for chemical addition rate s less than 100 gallons per hour (gph), a system using small peristaltic pumps would be sufficient at a cost of $5,000 per system. For chemical addition rates greater than 100 gph, the vendor recommended a conservative cost estimate of $15,000 per feed point. While the ve ndor did not provide an upper limit for the chemical addition rate that can be handled by the larger feed system, EPA assumed an upper limit of 200 gph. For plants requiring chemical addition rates greater than 200 gph, EPA costed multiple feed points (systems).
To calculate the cost for each feed point, EPA first calculated the dose conversion factor to convert the dose from grams of neat chemical per liter of FGD wast ewater to liters of chemical solution per li ter of FGD wastewater.
FeCl3 Dose Factor = 1/ (FeCl3 C oncentration × FeCl3 Density × 1,000 g/kg) (6-56)

where:

FeCl3 Concentration = The concentrati on of ferric chloride in solution, 35 percent (0.35), and FeCl3 Density = The density of ferri c chloride solution, in kg/L, 1.41.

EPA then calculated the volum etric addition rate, in gall ons per hour, using Equation 6-57.Chapter 6 - FGD Wastewater Cost Methodology

6-37 FeCl3 Rate (gph) = Ferric Chlori de Dose × FeCl3 Dose Factor × Liter to Gallon Factor × FGD Wastewater Treatment Flow GPM × Capacity Factor × 60 min/hr (6-57)

where:

Ferric Chloride Dose = Amount of ferric chloride, in g/L, needed to treat the FGD wastewater in the chem ical precipitation system, as determined in Section 6.1.7.4,

FeCL3 Dose Factor = Factor to convert dose from grams of neat chemical per liter of FGD wastewater to liters of chemical solution per liter of FGD wastew ater (see Equation 6-56),
Liter to Gallon Factor = Unit conversion f actor, equal to 1, which converts liters of chemical solution per lit er of FGD wastewater to gallons of chemical solution per gallon of FGD wastewater. It is calculated as:
3.785 L wastewater gal wastewater × gal chemical sol'n 3.785 L chemical sol'n
FGD Wastewater Treatment Flow GPM= = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and

Next, EPA calculated the number of ferric chlo ride feed points (systems) using Equation 6-58.
FeCl3 Feed Point Qty = FeCl3 Rate / 200 gph (rounded up to the nearest whole number) (6-58)

where:

FeCl3 Rate = Ferric chloride volum etric addition rate in gph (see Equation 6-57).

The ferric chloride feed system cost was th en calculated based on the volumetric addition rate. For FeCl3 rates less than or equal to 100 gph, EPA used Equation 6-59.
Ferric Chloride Feed System Cost (2011$) = FeCl3 Feed Point Qty × ($5,000 + Liquid Feed Freight Cost) (6-59)

where:

FeCl3 Feed Point Qty = The number of ferric chloride feed points required to treat FGD wastewater, rounde d up to the nearest whole number (see Equation 6-58), and Liquid Feed Freight Cost = The freight cost for a liquid feed system, $300.Chapter 6 - FGD Wastewater Cost Methodology

6-38 For FeCl3 rates greater than 100 gph, EPA used Equation 6-60 to calculate the ferric chloride feed system cost.

Ferric Chloride Feed System Cost (2011$) = FeCl3 Feed Point Qty × ($15,000 + Liquid Feed Freight Cost) (6-60)

where:

FeCl3 Feed Point Qty = The number of ferric chloride feed points required to treat FGD wastewater, rounde d up to the nearest whole number (see Equation 6-58), and Liquid Feed Freight Cost = The freight cost for a liquid feed system, $300.

Organosulfide Feed System Cost EPA assumed a neat organosulfide concentr ation that is diluted to a 0.5 percent organosulfide solution within the feed sy stem prior to addition to reactor tank 2. 29

EPA assumed that the orga nosulfide feed system can handle up to 20 gpm of organosulfide solution at a cost of $15,000 per f eed point (assumption transferred from vendor information for the polymer feed system discussed in this section). For plants requiring chemical addition rates greater than 20 gpm, EPA costed multiple feed points (systems).
To calculate the cost for each feed point, EPA first calculated the dose conversion factor to convert the dose from grams of neat chemical per liter of FGD wast ewater to liters of chemical solution per li ter of FGD wastewater.
Sulfide Dose Factor = 1/ (Sulfide C oncentration × Sulfide Density × 1,000 g/kg) (6-61)

where:

Sulfide Concentration = The concentrat ion of organosulfide in solution, 0.5 percent (0.005), and Sulfide Density = The density of or ganosulfide solution, in kg/L, 1.225.

EPA then calculated the volumetric add ition rate, in gpm, using Equation 6-62.
Sulfide Rate (gpm) = Organosulfide Dose × Sulf ide Dose Factor × Liter to Gallon Factor × FGD Wastewater Treatment Fl ow GPM × Capacity Factor (6-62)

29 EPA’s cost methodology is inconsistent in that this discussion of organosulfide feed systems assumes use of a liquid feed system while the chemical purchase cost discussion in Section 6.1.7.4 assumes purchase as a solid. For the final rule, EPA will reevaluate the organosulfide purcha se, freight, storage, and feed system methodologies and revise them as appropriate. In the interim, EPA considers the magnitude of the current estimated costs to be appropriate.Chapter 6 - FGD Wastewater Cost Methodology

6-39 where:

Organosulfide Dose = Amount of organos ulfide, in g/L, needed to treat the FGD wastewater in the chem ical precipitation system, as determined in Section 6.1.7.4,
Sulfide Dose Factor = Factor to convert dose from grams of neat chemical per liter of FGD wastewater to liters of chemical solution per liter of FGD wastew ater (see Equation 6-61),
Liter to Gallon Factor = Unit conversion f actor, equal to 1, which converts liters of chemical solution per lit er of FGD wastewater to gallons of chemical solution per gallon of FGD wastewater. It is calculated as:
3.785 L wastewater

gal wastewater × gal chemical sol'n
3.785 L chemical sol'n .,
FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted].

Next, EPA calculated the number of organosulfide feed point s (systems) using Equation 6-63.
Sulfide Feed Point Qty = Organosulfide Ra te / 20 gpm (rounded up to the nearest whole number) (6-63)

where:

Organosulfide Rate = Organosulfide volumetric addition rate in gpm (see Equation 6-62).

EPA calculated the organosulfide feed system cost based on the volumetric addition rate.
Organosulfide Feed System Cost (2011$) = Sulf ide Feed Point Qty × ($15,000 + Liquid Feed Freight Cost) (6-64)

where:

Sulfide Feed Point Qty = The number of organosulfide feed points required to treat FGD wastewater, rounde d up to the nearest whole number (see Equation 6-63), and Liquid Feed Freight Cost = The freight cost for a liquid feed system, $300.Chapter 6 - FGD Wastewater Cost Methodology

6-40 Polymer Feed System Cost EPA assumes a neat polymer concentration that is diluted to a 0.5 percent polymer solution within the feed system prior to addition to the solids contact clarifier. 30

The vendor stated that a polymer feed syst em handling up to 20 gpm of polymer solution addition would cost $15,000 per feed point (system) . For plants requiring chemical addition rates greater than 20 gpm, EPA costed multiple feed points.
To calculate the cost for each feed point, EPA first calculated the dose conversion factor to convert the dose from grams of neat chemical per liter of FGD wast ewater to liters of chemical solution per li ter of FGD wastewater.
Polymer Dose Factor = 1/ (Polymer C oncentration × Polymer Density × 1,000 g/kg) (6-65)

where:

Polymer Concentration = The concentrat ion of polymer in solution, 0.5 percent (0.005), and Polymer Density = The density of polymer solution, in kg/L, 1.04.

EPA then calculated the volumetric add ition rate, in gpm, using Equation 6-66.
Polymer Rate (gpm) = Polymer Dose × Polymer Dose Factor × Liter to Gallon Factor × FGD Wastewater Treatment Flow GPM × Capacity Factor (6-66)

where:

Polymer Dose = Amount of polymer, in g/L, needed to treat the FGD wastewater in the chemical precipitation system, as determined in Section 6.1.7.4, Polymer Dose Factor = Factor to convert dose from grams of neat chemical per liter of FGD wastewater to liters of chemical solution per liter of FGD wastew ater (see Equation 6-65),
Liter to Gallon Factor = Unit conversion f actor, equal to 1, which converts liters of chemical solution per lit er of FGD wastewater to gallons of chemical solution per gallon of FGD wastewater. It is calculated as:
3.785 L wastewater

gal wastewater × gal chemical sol'n
3.785 L chemical sol'n ,

30 EPA’s cost methodology is inconsistent in that this discussion of polymer feed systems assumes use of a liquid feed system while the chemical purchase cost discussion in Section 6.1.7.4 assumes purchase as a solid. For the final rule, EPA will reevaluate the polymer purchase, freight, stor age, and feed system methodologies and revise them as appropriate. In the interim, EPA c onsiders the magnitude of the current estimated costs to be appropriate.Chapter 6 - FGD Wastewater Cost Methodology

6-41 FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted].

Next, EPA calculated the number of polymer feed points (systems) using Equation 6-67.
Polymer Feed Point Qty = Polymer Rate / 20 gpm (rounded up to the ne arest whole number) (6-67)

where:

Polymer Rate = Polymer volumetric addition rate in gpm (see Equation 6-66).

The polymer feed system cost was then cal culated based on the volumetric addition rate using Equation 6-68.
Polymer Feed System Cost (2011$) = Polymer Feed Point Qty × ($15,000 + Liquid Feed Freight Cost) (6-68)

where:

Polymer Feed Point Qty = The number of polymer feed points required to treat FGD wastewater, rounded up to the nearest whole number (see Equation 6-67), and Liquid Feed Freight Cost = The freight cost for a liquid feed system, $300.

Hydrochloric Acid Feed System Cost EPA assumed a 32 percent concentration of hydrochloric acid in solution.
This feed system will add hydrochloric acid to the system after final clarification (e.g., after the solids contact clarifier). The vendor stated that for chemical addition rates less than 100 gph, a system using small peristaltic pumps woul d be sufficient at a cost of $5,000 per system. For chemical addition rates greater than 100 gph, the vendor recommended a conservative cost estimate of $15,000 per feed point. While the ve ndor did not provide an upper limit for the chemical addition rate that can be handled by the larger feed system, EPA assumed an upper limit of 200 gph. For plants requiring chemical addition rates greater than 200 gph, EPA costed multiple feed points (systems).
To calculate the cost for each feed point, EPA first calculated the dose conversion factor to convert the dose from grams of neat chemical per liter of FGD wast ewater to liters of chemical solution per li ter of FGD wastewater.
HCl Dose Factor = 1/ (HCl Con centration × HCl Density × 1,000 g/kg) (6-69)Chapter 6 - FGD Wastewater Cost Methodology

6-42 where:

HCl Concentration = The concentrati on of hydrochloric acid in solution, 32 percent (0.32), and HCl Density = The density of hydroc hloric acid solution, in kg/L, 1.159.

EPA then calculated the volum etric addition rate, in gall ons per hour, using Equation 6-70.

HCl Rate (gph) = Hyrdochloric Acid Dose × HC l Dose Factor × Liter to Gallon Factor × FGD Wastewater Treatment Flow GPM × Capacity Factor × 60 min/hr (6-70)

where:

Hydrochloric Acid Dose = Amount of hydrochloric acid, in g/L, needed to treat the FGD wastewater in the chemical precipitation system, as determined in Section 6.1.7.4),
HCl Dose Factor = Factor to convert dose from grams of neat chemical per liter of FGD wastewater to liters of chemical solution per liter of FGD wastew ater (see Equation 6-69),
Liter to Gallon Factor = Unit conversion f actor, equal to 1, which converts liters of chemical solution per lit er of FGD wastewater to gallons of chemical solution per gallon of FGD wastewater. It is calculated as:
3.785 L wastewater

gal wastewater × gal chemical sol'n
3.785 L chemical sol'n ,
FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted].

Next, EPA calculated the numb er of hydrochloric acid feed points (systems) using Equation 6-71.
HCl Feed Point Qty = HCl Rate / 200 gph (rounded up to the nearest whole number) (6-71)

where:

HCl Rate = Hydrochloric acid volu metric addition rate in gph (see Equation 6-70).

The hydrochloric acid feed system cost wa s then calculated based on the volumetric addition rate:Chapter 6 - FGD Wastewater Cost Methodology

6-43 For HCl rates less than or equal to 100 gph EPA used Equation 6-72.
Hydrochloric Acid Feed System Cost (2011$) = HCl Feed Point Qt y × ($5,000 + Liquid Feed Freight Cost) (6-72)

where:

HCl Feed Point Qty = The number of hydr ochloric acid feed points required to treat FGD wastewater, rounded up to the nearest whole number (see Equation 6-71), and Liquid Feed Freight Cost = The freight cost for a liquid feed system, $300.

For HCl rates greater than 100 gph, EPA used Equation 6-73.
Hydrochloric Acid Feed System Cost (2011$) = HCl Feed Point Qt y × ($15,000 + Liquid Feed Freight Cost) (6-73)

where:

HCl Feed Point Qty = The number of hydr ochloric acid feed points required to treat FGD wastewater, rounded up to the nearest whole number (see Equation 6-71), and Liquid Feed Freight Cost = The freight cost for a liquid feed system, $300.

6.1.6.4 Purchased Equipment Costs: Mixers

EPA costed mixers for certain costed ta nks, with one mixer per costed tank. EPA obtained vendor cost information for mixers base d on an example plant’s information that was provided to the equipment vendor Ph iladelphia Mixing Solutions. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A26 through SE01825.A29) for additional information. To calculate the mixer cost for each plant, EPA multiplied the plant’s tank size by cost factors it developed using the example plant and vendor cost information. For each plant, mixer costs are determined based on tank size th erefore, no capacity factor is required.
Freight costs for mixers are not available on a per-mixer basis. One flatbed truck is needed to ship all of the mixe rs required for the system. The freight cost estimate for one truck (lot of mixers) is [Redacted] [ERG, 2013; See Appendix 41].

Mixers Cost = Equalization Tank Mixer Cost + Reaction Tank 1 Mixer Cost + Reaction Tank 2

Mixer Cost + Reaction Tank 3 Mixer Cost + Sl udge Holding Tank Mixer Cost + Lime Slurry Preparation Tank Mixer Cost + Filtrate Sump Mixer Cost + Flatbed Truck Cost

For each type of mixer, EPA first calculated the torque of the mixer based on the example plant’s data. Torque is ca lculated in pound force inch (lbf·in) using Equation 6-74.Chapter 6 - FGD Wastewater Cost Methodology

6-44 Torque (lbf·in) = 33,000 (lbf·ft/min) × 12 in/ft × Mixer Horsepower (hp) / [2 × π × Mixer Speed (rpm)] (6-74)

EPA assumed the ratio of cost to torque and torque to volume would be constant for each type of mixer, regardless of si ze, based on engineering judgment.

Equalization Tank Mixer Cost As discussed in Section 6.1.6.2, EPA costed on e equalization tank pe r plant; therefore, EPA also costed one equalization tank mixer pe r plant, other than “high flow” plants. To estimate mixer purchase costs, EPA first calculat ed the example plant’s equalization tank mixer torque.
Example Plant Eq Mixer Torque (lbf·in) = 33,000 (lbf·ft/min) × 12 in/ft × Example Plant Eq Mixer HP / (2 × π ×Example Plant Eq Mixer RPM) (6-75)

where:

Example Plant Eq Mixer HP = The example plant’s equalization tank mixer’s horsepower, provided in documentation for the example plant, and Example Plant Eq Mixer RPM = The example plant’s equalization tank mixer’s speed, in revolutions per minute (rpm), provided in documentation for the example plant.

EPA then calculated the cost factors Cost Per Unit Torque and Torque Per Unit Volume based on cost data provided by the vendor for the example plant’s mixer and tank size. EPA assumed that these cost factors are valid for all equalization tank mixers, regardless of size, based on engineering judgment.

Eq Mixer Cost per Torque ($/lbf·in) = Example Plant Eq Mixer Cost / Example Plant Eq Mixer Torque (6-76)

where:

Example Plant Eq Mixer Cost = The cost of the equalization tank mixer used by the example plant (provided by equipment vendor), and Example Plant Eq Mixer Torque = The torque of the equalization tank mixer used by the example plant, (see Equation 6-75).

Eq Mixer Torque per Volume (lbf·in/ft 3 ) = Example Plant Eq Mixer Torque / Example Plant Eq Tank Size (6-77)Chapter 6 - FGD Wastewater Cost Methodology

6-45 where:

Example Plant Eq Tank Size = The size, in gallons, of th e example plant’s equalization tank, and Example Plant Eq Mixer Torque = The torque of the equalization tank mixer used by the example plant, (see Equation 6-75).

EPA then calculated the plant-specific equalization tank mixer cost by multiplying the plant-specific equalization tank size calculated previously (see the Equalization Tank Cost discussion in Section 6.1.6.2) by the e qualization tank mixer cost factors.
Equalization Tank Mixer Cost (2011$) = Equaliza tion Tank Size × Eq Mixer Torque per Volume × Eq Mixer Cost per Torque (6-78)

where:

Equation Tank Size = The calculated equalization tank size, (see Section 6.1.6.2 and Equation 6-16), Eq Mixer Torque per Volume = The calculated torque per volume for the equalization tank mixer, (see Equation 6-77), and Eq Mixer Cost Per Torque = The calculated cost of the mixer per unit torque for the equalization tank mixer, (see Equation 6-76).

Reaction Tank 1 Mixer Cost EPA costed one reaction tank 1 (see Secti on 6.1.6.2) and, therefore, one reaction tank 1 mixer for each plant. To calculate mixer costs, EPA first calculated the example plant’s reaction tank 1 mixer torque.
Example Plant Rxn1 Mixer Torque (lbf·in) = 33,000 (lbf·ft/min) × 12 in/ft × Example Plant Rxn1 Mixer HP / (2 × π × Example Plant Rxn1 Mixer RPM) (6-79)

where:

Example Plant Rxn1 Mixer HP = The example plant’s reaction tank 1 mixer’s horsepower, provided in documentation for the example plant, and Example Plant Rxn1 Mixer RPM = The example plant’s reaction tank 1 mixer’s speed, in rpm, provided in documentation for the example plant.

EPA then calculated the cost factors Cost Per Unit Torque and Torque Per Unit Volume based on cost data provided by the vendor for the example plant’s mixer and tank size. EPA assumed that these cost factors are valid for all reaction tank 1 mixers, rega rdless of size, based on engineering judgment.Chapter 6 - FGD Wastewater Cost Methodology

6-46 Rxn1 Mixer Cost per Torque ($/lbf·in) = Exam ple Plant Rxn1 Mixer Cost / Example Plant Rxn1 Mixer Torque (6-80)

where:

Example Plant Rxn1 Mixer Cost = The cost of the reaction tank 1 mixer used by the example plant (provided by equipment vendor), and Example Plant Rxn1 Mixer Torque = The torque of the reaction tank 1 mixer used by the example plant, (see Equation 6-79).

Rxn1 Mixer Torque pe r Volume (lbf·in/ft 3 ) = Example Plant Rxn1 Mi xer Torque / Example Plant Rxn1 Tank Size (6-81)

where:

Example Plant Rxn1 Tank Size = The size, in gallons, of the example plant’s reaction tank 1, and Example Plant Rxn1 Mixer Torque = The torque of the reaction tank 1 mixer used by the example plant (see Equation 6-79).

EPA then calculated the plant-specific reaction tank 1 mixer cost by multiplying the plant-specific reaction tank 1 si ze calculated previously (see th e Reaction Tank 1 Cost discussion in Section 6.1.6.2) by the reaction tank 1 mixer cost factors.
Reaction Tank 1 Mixer Cost (2011$) = Reaction Ta nk 1 Size × Rxn1 Mixer Torque per Volume × Rxn1 Mixer Cost per Torque (6-82)

where:

Reaction Tank 1 Size = The calculated reaction tank 1 size, (see Section 6.1.6.2 and Equation 6-21), Rxn1 Mixer Torque per Volume = The calculated torque per volume for the reaction tank 1 mixer, (see Equation 6-81), and Rxn1 Mixer Cost per Torque = The calculated cost of the mixer per unit torque for the reaction tank 1 mixer, (see Equation 6-80).

Reaction Tank 2 Mixer Cost EPA costed one reaction tank 2 (see Secti on 6.1.6.2) and, therefore, one reaction tank 2 mixer for each plant. To calculate mixer costs, EPA first calculated the example plant’s reaction tank 2 mixer torque.
Example Plant Rxn2 Mixer Torque (lbf·in) = 33,000 (lbf·ft/min) × 12 in/ft × Example Plant Rxn2 Mixer HP / (2 × π × Example Plant Rxn2 Mixer RPM) (6-83)Chapter 6 - FGD Wastewater Cost Methodology

6-47 where:

Example Plant Rxn2 Mixer HP = The example plant’s reaction tank 2 mixer’s horsepower, provided in documentation for the example plant, and Example Plant Rxn2 Mixer RPM = The example plant’s reaction tank 2 mixer’s speed, in rpm, provided in documentation for the example plant.

EPA then calculated the cost factors Cost Per Unit Torque and Torque Per Unit Volume based on cost data provided by the vendor for the example plant’s mixer and tank size. EPA assumed that these cost factors are valid for all reaction tank 2 mixers, rega rdless of size, based on engineering judgment.
Rxn2 Mixer Cost per Torque ($/lbf·in) = Exam ple Plant Rxn2 Mixer Cost / Example Plant Rxn2 Mixer Torque (6-84)

where:

Example Plant Rxn2 Mixer Cost = The cost of the reaction tank 2 mixer used by the example plant (provided by equipment vendor) , and Example Plant Rxn2 Mixer Torque = The torque of the reaction tank 2 mixer used by the example plant, (see Equation 6-83).

Rxn2 Mixer Torque pe r Volume (lbf·in/ft 3 ) = Example Plant Rxn2 Mixer Torque / Example Plant Rxn2 Tank Size (6-85)

where:

Example Plant Rxn2 Tank Size = The size, in gallons, of the example plant’s reaction tank 2, and Example Plant Rxn2 Mixer Torque = The torque of the reaction tank 2 mixer used by the example plant, (see Equation 6-83).

EPA then calculated the plant-specific reaction tank 2 mixer cost by multiplying the plant-specific reaction tank 2 size calculated previously (s ee the Reaction Tank 2 Cost and Reaction Tank 3 Cost discussion in Section 6.1.6.2) by the reaction tank 2 mixer cost factors.
Reaction Tank 2 Mixer Cost (2011$) = Reaction Ta nk 2 Size × Rxn2 Mixer Torque per Volume × Rxn2 Mixer Cost per Torque (6-86)

where:

Reaction Tank 2 Size = The calculated reaction tank 2 size, (see Section 6.1.6.2 and Equation 6-25),Chapter 6 - FGD Wastewater Cost Methodology

6-48 Rxn2 Mixer Torque per Volume = The calculated torque per volume for the reaction tank 2 mixer, (see Equation 6-85), and Rxn2 Mixer Cost per Torque = The calculated cost of the mixer per unit torque for the reaction tank 2 mixer, (see Equation 6-84).

Reaction Tank 3 Mixer Cost EPA costed one reaction tank 3 (see Secti on 6.1.6.2) and, therefore, one Reaction Tank 3 Mixer for each plant. To calculate mixer costs, EPA first calculated the example plant’s reaction tank 3 mixer torque.
Example Plant Rxn3 Mixer Torque (lbf·in) = 33,000 (lbf·ft/min) × 12 in/ft × Example Plant Rxn3 Mixer HP / (2 × π × Example Plant Rxn3 Mixer RPM) (6-87)

where:

Example Plant Rxn3 Mixer HP = The example plant’s reaction tank 3 mixer’s horsepower, provided in documentation for the example plant, and Example Plant Rxn3 Mixer RPM = The example plant’s reaction tank 3 mixer’s speed, in rpm, provided in documentation for the example plant.

EPA then calculated the cost factors Cost Per Unit Torque and Torque Per Unit Volume based on cost data provided by the vendor for the example plant’s mixer and tank size. EPA assumed that these cost factors are valid for all reaction tank 3 mixers, rega rdless of size, based on engineering judgment.
Rxn3 Mixer Cost per Torque ($/lbf·in) = Exam ple Plant Rxn3 Mixer Cost / Example Plant Rxn3 Mixer Torque (6-88)

where:

Example Plant Rxn3 Mixer Cost = The cost of the reaction tank 3 mixer used by the example plant (provided by equipment vendor), and Example Plant Rxn3 Mixer Torque = The torque of the reaction tank 3 mixer used by the example plant, (see Equation 6-87).

Rxn3 Mixer Torque pe r Volume (lbf·in/ft 3 ) = Example Plant Rxn3 Mi xer Torque / Example Plant Rxn3 Tank Size (6-89)

where:

Example Plant Rxn3 Tank Size = The size, in gallons, of the example plant’s reaction tank 3, andChapter 6 - FGD Wastewater Cost Methodology

6-49 Example Plant Rxn3 Mixer Torque = The torque of the reaction tank 3 mixer used by the example plant, (see Equation 6-87).

EPA then calculated the plant-specific reaction tank 3 mixer cost by multiplying the plant-specific reaction tank 3 size calculated previously (s ee the Reaction Tank 2 Cost and Reaction Tank 3 Cost discussion in Section 6.1.6.2) by the reaction tank 3 mixer cost factors.
Reaction Tank 3 Mixer Cost (2011$) = Reaction Ta nk 3 Size × Rxn3 Mixer Torque per Volume × Rxn3 Mixer Cost per Torque (6-90)

where:

Reaction Tank 3 Size = The calculated reaction tank 3 size, (see Section 6.1.6.2 and Equation 6-29), Rxn3 Mixer Torque per Volume = The calculated torque per volume for the reaction tank 3 mixer, (see Equation 6-89), and Rxn3 Mixer Cost per Torque = The calculated cost of the mixer per unit torque for the reaction tank 3 mixer, (see Equation 6-88).

Sludge Holding Tank Mixer Cost EPA costed one sludge holding tank (see S ection 6.1.6.2) and, therefore, one sludge holding tank mixer for each plan t. To calculate mixer costs, EPA first calculated the example plant’s sludge holding tank mixer torque.

Example Plant Sldg Mixer Torque (lbf·in) = 33,000 (lbf·ft/min) × 12 in/ft × Example Plant Sldg Mixer HP / (2 × π × Example Plant Sludge Mixer RPM) (6-91)

where:

Example Plant Sldg Mixer HP = The example plant’s sludge holding tank mixer’s horsepower, provided in documentation for the example plant, and Example Plant Sldg Mixer RPM = The example plant’s sludge holding tank mixer’s speed, in rpm, provided in documentation for the example plant.

EPA then calculated the cost factors Cost Per Unit Torque and Torque Per Unit Volume based on cost data provided by the vendor for the example plant’s mixer and tank size. EPA assumed these cost factors are valid for all sludge holding tank mixers, regardless of size, based on engineering judgment.

Sldg Mixer Cost per Torque ($/lbf·in) = Exampl e Plant Sldg Mixer Cost / Example Plant Sldg Mixer Torque (6-92)Chapter 6 - FGD Wastewater Cost Methodology

6-50 where:

Example Plant Sldg Mixer Cost = The cost of the sludge holding tank mixer used by the example plant (provided by equipment vendor), and Example Plant Sldg Mixer Torque = The torque of the sludge holding tank mixer used by the example plant, (see Equation 6-91).

Sldg Mixer Torque pe r Volume (lbf·in/ft 3 ) = Example Plant Sldg Mixe r Torque / Example Plant Sldg Tank Size (6-93)

where:

Example Plant Sldg Tank Size = The size, in gallons, of the example plant’s sludge holding tank, and Example Plant Sldg Mixer Torque = The torque of the sludge holding tank mixer used by the example plant, (see Equation 6-91).

EPA then calculated the plant-specific sludge holding tank mixer cost by multiplying the plant-specific sludge holding tank size calculate d previously (see the Sludge Holding Tank Cost discussion in Section 6.1.6.2) by the sl udge holding tank mixer cost factors.
Sludge Holding Tank Mixer Cost (2011$) = Slud ge Holding Tank Size × Sldg Mixer Torque per Volume × Sldg Mixer Cost per Torque (6-94)

where:

Sludge Holding Tank Size = The calculated sludge holding tank size, (see Section 6.1.6.2 and Equation 6-36), Sldg Mixer Torque per Volume = The calculated torque per volume for the sludge holding tank mixer, (see Equation 6-93), and Sldg Mixer Cost per Torque = The calculated cost of the mixer per unit torque for the sludge holding tank mixer (see Equation 6-92).

Lime Slurry Preparation Tank Mixer Cost The lime slurry feed system for which th e vendor provided costs includes associated mixer costs. See Section 6.1.6.3 for more details.

Filtrate Sump Mixer Cost EPA costed one filtrate sump (see Section 6.1.6.2 ) and, therefore, one filtrate sump mixer for each plant. The filtrate sump mixer cost is dependent on the size of the sump. EPA estimated sump size using information provided by a BAT plan t that provided these design details in its Steam Electric Survey response.
Sump Size (gal) = Sump HRT × FG D Wastewater Treatment Flow GPM (6-95 )Chapter 6 - FGD Wastewater Cost Methodology

6-51 where:

Sump HRT = Factor representing the ratio of sump size to FGD wastewater treatment flow, in minutes. It is not a true residence time, because the majority of the wastewater will not reach the filtrate sump; however, the factor is calculated in the same way as the wastewater tank residence times. Its value is 132 minutes, and

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5).

EPA assumed that the cost factors Torque Pe r Unit Volume and Cost Per Unit Torque for the filtrate sump are the same as those calcula ted for the equalization tank, because the filtrate sump contents are transferred to the equalization tank. Additionall y, the purpose of the mixer in both the equalization tank and the filtrate sump is to keep solids susp ended, as opposed to distributing chemicals and aidi ng in precipitation and floccula tion as with the other tanks’ mixers. See the Equalization Tank Mixer Cost discu ssion in this section for detailed calculations.
EPA then calculated the plant-specific sump mixer cost by multiplying the plant-specific sump size by the equalization tank mixer cost factors.
Filtrate Sump Mixer Cost (2011$) = Sump Size × Eq Mixer Torque per Volume × Eq Mixer Cost per Torque (6-96)

where:

Sump Size = The calculated sump size in gallons, (see Equation 6-95), Eq Mixer Torque per Volume = The calculated torque per volume for the equalization tank mixer, (see Equation 6-77), and Eq Mixer Cost Per Torque = The calculated cost of the mixer per unit torque for the equalization tank mixer, (see Equation 6-76).

6.1.6.5 Purchased Equipment Costs: Solids Contact Clarifiers

EPA obtained vendor costs for solids contact clar ifiers based on the clarifiers used by the BAT plants. EPA estimated the cost of two 75 per cent capacity solids contact clarifiers to settle solids generated in the treatment system. EPA reque sted vendor costs for solids contact clarifiers appropriate for FGD wastewater flow rates ranging from 7 to 700 gpm. EPA requested that purchase costs also include anci llary equipment, such as structural supports, ladders, access walkways, piping, and valves. The vendors provided costs for solids contact clarifiers including internal equipment, but not including the clar ifier tank. Walker Process Equipment provided costs for clarifier mechanisms suitable for flow rates under 100 gpm, and Siemens provided costs for clarifier mechanisms suitable for fl ow rates from 100 to 700 gpm [ERG, 2013; See Appendices 30 , 31, and 32]. Costs provided by Walker Process Equipment and Siemens are forChapter 6 - FGD Wastewater Cost Methodology

6-52 all carbon steel equipment lined with epoxy. The majority of the plants sampled by EPA used clarifiers made of carbon stee l or carbon steel lined with ep oxy, while some used carbon steel lined with other materials.

The total solids contact clarifier cost includes the following cost elements:

 Clarifier Mechanism Cost, and

 Clarifier Tank Cost.

Clarifier Mechanism Cost EPA developed a step-wise cost equation fo r the solids contact clarifiers. The cost equation used for a particular pl ant is chosen based on 75 percen t of FGD Wastewater Treatment Flow GPM (see Section 6.1.5) multip lied by the capacity factor. For flow rates greater than 700 gpm, EPA developed a cost function usi ng the data available from Siemens.
Freight costs are not available for the solid s contact clarifier m echanism. EPA assumes that the flat freight co st of $3,000 previously obtained for an other clarifier mechanism previously evaluated by EPA also applies to th e solids contact clarifier mechanism.
The cost equation used for each clarif ier flow rate is identified below:
Clarifier Flow (gpm) = 0.75 × FGD Wastewater Treatment Flow GPM × Capacity Factor (6-97)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted].

 For Clarifier Flow ≤ 30 gpm:
Clarifier Mechanism Cost (2011$) = ($65,000 + Clarifier Fr eight Cost) × Clarifier Qty

 For 30 gpm < Clarifier Flow ≤ 75 gpm:
Clarifier Mechanism Cost (2011$) = ($80,000 + Clarifier Fr eight Cost) × Clarifier Qty

 For 75 gpm < Clarifier Flow ≤ 100 gpm:
Clarifier Mechanism Cost (2011$) = ($118,000 + Clarifier Fr eight Cost) × Clarifier Qty

 For 100 gpm < Clarifier Flow ≤ 140 gpm:
Clarifier Mechanism Cost (2011$) = ($122,000 + Clarifier Fr eight Cost) × Clarifier QtyChapter 6 - FGD Wastewater Cost Methodology

6-53  For 140 gpm < Clarifier Flow ≤ 250 gpm:
Clarifier Mechanism Cost (2011$) = ($130,000 + Clarifier Fr eight Cost) × Clarifier Qty

 For 250 gpm < Clarifier Flow ≤ 350 gpm:
Clarifier Mechanism Cost (2011$) = ($150,000 + Clarifier Fr eight Cost) × Clarifier Qty

 For 350 gpm < Clarifier Flow ≤ 470 gpm:
Clarifier Mechanism Cost (2011$) = ($162,000 + Clarifier Fr eight Cost) × Clarifier Qty

 For 470 gpm < Clarifier Flow ≤ 550 gpm:
Clarifier Mechanism Cost (2011$) = ($168,000 + Clarifier Fr eight Cost) × Clarifier Qty

 For 550 gpm < Clarifier Flow ≤ 700 gpm:
Clarifier Mechanism Cost (2011$) = ($185,000 + Clarifier Fr eight Cost) × Clarifier Qty
For Clarifier Flow > 700 gpm, EPA used Equation 6-98.
Clarifier Mechanism Cost ( 2011$) = (114.49 × Clarifier Flow + 105986 + Clarifier Freight Cost) × Clarifier Qty (6-98)

where:

Clarifier Flow = Flow rate of FGD wastewater through the clarifier in gpm (see Equation 6-97), Clarifier Qty = Number of so lids contact clarifiers, 2, and
Clarifier Freight Cost = Flat rate freight cost for solids contact clarifier delivery, $3,000.

Solids Contact Clarifier Tank Cost Walker Process Equipment provided the dimensi ons of the tank that would be appropriate for each clarifier [ERG, 2013; See Appendix 33]. EP A used this information to calculate the volume of each tank and develop a relationship between the required clar ifier tank volume and the clarifier flow rate. EPA then used this volume to calculate the cost of a carbon steel tank to serve as the tank for each clarifier. EPA used the cost equations discussed in Section 6.1.6.2.

First, EPA calculated the clarifier flow as described in Equation 6-97.
Second, EPA calculated the requ ired clarifier tank size us ing Equation 6-99, which was developed using information provided by the vendor [ERG, 2013; See Appendix 33].
Clarifier Tank Size (gal) = 337.8 × Clarifier Flow + 6388.8 (6-99)Chapter 6 - FGD Wastewater Cost Methodology

6-54 Third, EPA applied the following cost equa tion developed in Section 6.1.6.2 for carbon steel tanks, Equation 6-13, usi ng the clarifie r tank size.

For Clarifier Tank Size ≤ 70,000 gal:
Clarifier Tank Cost (2011$) = [(0.9412 × Clar ifier Tank Size + 4117.6) + (0.064 × Clarifier Tank Size + 522.06) + Liner Cost Per Squa re Foot × (2.0885 × Clarifier Tank Size 0.6282 )] × Clarifier Qty (6-100)

For Clarifier Tank Size > 70,000 gal:

Clarifier Tank Cost (2011$) = (-6×10 -08 × Clarifier Tank Size 2 + 0.628 × Clarifier Tank Size + 503999) × Clarifier Qty (6-101)

where:

Liner Cost Per Square Foot = The installed cost, in do llars, of Tnemec’s Series 61 Tneme-Liner system per square foot of internal surface area of the tank, $10,
Clarifier Tank Size = Calculated clar ifier tank size, in gallons, and
Clarifier Qty = Number of solids contact clarifiers, 2.

6.1.6.6 Purchased Equipment Costs: Filter Presses
EPA requested vendor costs for varying sizes of filter presses assuming FGD wastewater flow rates through the system ranging from 7 to 700 gpm. EPA applied the sludge factor of 0.4 (see Section 6.1.5) to the range of FGD wastewat er flows, resulting in estimated design sludge flow rates of 2.8 to 280 gpm. Therefore, EPA request ed filter press costs fo r this sludge flow rate range. Based on the data provided by Andritz Separation, EPA developed the following cost function to extrapolate and interpolate cost s for each plant [ERG, 2013; See Appendix 35]. Included in the cost of each filter press is the co st of one filter press feed pump. For plants with FGD Wastewater Treatment Fl ow GPM of 350 gpm or less, EPA costed two 100 percent capacity, filter presses, each with a feed pump. Fo r plants with FGD Wast ewater Treatment Flow GPM greater than 350 gpm, EPA costed three 50 percent capacity, filter presses, each with a feed pump, for each plant.
The vendor provided unit purchase cost in formation for three filter press sizes, by capacity: 25 cubic feet (small), 250 cubic feet (medium), and 350 cubic feet (large). Based on the weights of the empty filter presses, EPA assumed that one truck would be required to ship the smallest size filter press and two trucks would be required to ship a medium or large size filter press. Based on information from FreightCenter.com and Siemens, the freight cost for a full truck may range from $1,400 to [Redacted]. EPA compared the freight cost to the vendorprovided unit purchase costs of the filter presses to develop a filter press freight cost factor of 1 percent.Chapter 6 - FGD Wastewater Cost Methodology

6-55 For plants with an FGD wastewater flow less than or equal to 350 gp m, filter presses are costed using Equation 6-102.
Filter Press Cost (2011$) = Filter Press Freigh t Factor × Filter Press Qty × (2382.1 × Sludge Factor × FGD Wastewater Treatment Flow GPM + 173777) (6-102)

where:

Filter Press Qty = Number of filter presses; for plants with an FGD Wastewater Treatment Flow GPM less than or equal to 350 gpm (see Section 6.1.5), 2, Filter Press Freight Factor = Factor that accounts for frei ght cost as a percentage of purchase cost, 1.01, Sludge Factor = Factor to estimate the sludge generation rate based on the FGD Wastewater Treatment Flow GPM (see Section 6.1.5), 0.4, and

FGD Wastewater Treatment Flow GPM = FGD wastewater flow in gpm normalized for 24 hpd operation (see Section 6.1.5).

For plants with an FGD wastewater flow gr eater than 350 gpm, filte r presses are costed using Equation 6-103.
Filter Press Cost (2011$) = Filter Press Freigh t Factor × Filter Press Qty × [2.7768 × (Sludge Factor × FGD Wastewater Treatment Flow GPM) 2 + 394.03 × Sludge Factor × FGD Wastewater Treatment Flow GPM + 195398] (6-103)

where:

Filter Press Qty = Number of filter presses. For plants with an FGD Wastewater Treatment Flow GPM greater than 350 gpm (see Section 6.1.5), 3, Filter Press Freight Factor = Factor that accounts for frei ght cost as a percentage of purchase cost, 1.01, Sludge Factor = Factor to estimate the sludge generation rate based on the FGD Wastewater Treatment Flow GPM (see Section 6.1.5), 0.4, and

FGD Wastewater Treatment Flow GPM = FGD wastewater flow in gpm normalized for 24 hpd operation (see Section 6.1.5).

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A35 through SE01825.A38) for more details on the develo pment of Equations 6-102 and 6-103.Chapter 6 - FGD Wastewater Cost Methodology

6-56 6.1.6.7 Purchased Equipment Costs: Gravity Sand Filters
EPA requested vendor costs for various sizes of continuous backwash gravity sand filters appropriate for FGD wastewater flow rates ranging from 7 to 700 gpm. EPA created a cost function using costs obtained from the vendor to interpolate costs for each plant. Siemens provided costs of their standard sized units. The cost model assigns costs using a step function based on the treatment system flow ra te [ERG, 2013; See Appendix 39 and 40].

EPA costed at least two 100 percent capacity continuous ba ckwash gravity sand filters per plant. Where more than two filters are needed to accommodate FGD wastewater flow (determined as described later in this section), EPA costed the quantity of filters equal to the number of filters needed to provide 200 percent capacity.

Siemens indicated that one flat bed truck per unit would be requi red to transport the filters. The truck freight cost, as provided by th e vendor, is [Redacted]. EPA assumed a transport distance of 500 miles, yielding a cost of [Redacted] per truck or [Redacted] per filter unit. Additionally, separate freight co sts are incurred to transport sa nd. EPA calculated sand freight costs based on the amount of sand required for each filter and the truck costs and capacities calculated previously (see Section 6.1.5).
For each plant, EPA first calculated the exp ected FGD wastewater design flow, in gpm, through the wastewater treatment system.
Expected Design Flow (gpm) = Capacity Fa ctor × FGD Wastewater Treatment Flow GPM (6-104)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted].

Cost equations were selected ba sed on the expected design flow.
For plants where the expected design flow was less than or equal to 20 gpm, EPA used Equation 6-105.
Continuous Backwash Gravity Sand Filters Cost (2011$) = ($68,000 × Sand Filter Qty) + (Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost / Truck Weight Capacity) (6-105)

where:

Sand Filter Qty = Number of sand filters ; within this flow rate range, two sand filters are required,Chapter 6 - FGD Wastewater Cost Methodology

6-57 Sand Weight = Amount of sand, in lbs, required for each sand filter unit; for the unit associated w ith this flow rate range, [Redacted] of sand are required,
Flatbed Truck Cost = The cost for a full equipment shipment via flatbed truck approximately 500 miles (see Section 6.1.5), [Redacted], and Truck Weight Capacity = The maximum shipping weight a dry van truck can hold (see Section 6.1.5), 45,000 lbs.

For plants where the expected design flow wa s greater than 20 gpm and less than or equal to 100 gpm, EPA used Equation 6-106.
Continuous Backwash Gravity Sand Filters Cost (2011$) = ($80,000 × Sand Filter Qty) + (Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost / Truck Weight Capacity) (6-106)

where:

Sand Filter Qty = Number of sand filters ; within this flow rate range, two sand filters are required, Sand Weight = Amount of sand, in lbs, required for each sand filter unit; for the unit associated w ith this flow rate range, [Redacted] of sand are required,
Flatbed Truck Cost = The cost for a full equipment shipment via flatbed truck approximately 500 miles (see Section 6.1.5), [Redacted], and Truck Weight Capacity = The maximum shipping weight a dry van truck can hold (see Section 6.1.5), 45,000 lbs.

For plants where the expected design flow was greater than 100 gpm and less than or equal to 200 gpm, EPA used Equation 6-107.
Continuous Backwash Gravity Sand Filters Cost (2011$) = ($98,000 × Sand Filter Qty) + (Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost /Truck Weight Capacity) (6-107)

where:

Sand Filter Qty = Number of sand filters ; within this flow rate range, two sand filters are required, Sand Weight = Amount of sand, in lbs, required for each sand filter unit; for the unit associated w ith this flow rate range, [Redacted] of sand are required,Chapter 6 - FGD Wastewater Cost Methodology

6-58 Flatbed Truck Cost = The cost for a full equipment shipment via flatbed truck approximately 500 miles (see Section 6.1.5), [Redacted], and Truck Weight Capacity = The maximum shipping weight a dry van truck can hold (see Section 6.1.5), 45,000 lbs.

For plants where the expected design flow was greater than 200 gpm and less than or equal to 300 gpm, EPA used Equation 6-108.
Continuous Backwash Gravity Sand Filters Cost (2011$) = ($180,000 × Sand Filter Qty) + (Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost / Truck Weight Capacity) (6-108)

where:

Sand Filter Qty = Number of sand filters ; within this flow rate range, two sand filters are required, Sand Weight = Amount of sand, in lbs, required for each sand filter unit; for the unit associated w ith this flow rate range, [Redacted] of sand are required,
Flatbed Truck Cost = The cost for a full equipment shipment via flatbed truck approximately 500 miles (see Section 6.1.5), [Redacted], and Truck Weight Capacity = The maximum shipping weight a dry van truck can hold (see Section 6.1.5), 45,000 lbs.

For plants where the expected design flow was greater than 300 gpm and less than or equal to 500 gpm, EPA used Equation 6-109.
Continuous Backwash Gravity Sand Filters Cost (2011$) = ($98,000 × Sand Filter Qty) + (Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost / Truck Weight Capacity) (6-109)

where:

Sand Filter Qty = Number of sand filters; within this flow rate range, four sand filters are required, Sand Weight = Amount of sand, in lbs, required for each sand filter unit; for the unit associated w ith this flow rate range, [Redacted] of sand are required,
Flatbed Truck Cost = The cost for a full equipment shipment via flatbed truck approximately 500 miles (see Section 6.1.5), [Redacted], andChapter 6 - FGD Wastewater Cost Methodology

6-59 Truck Weight Capacity = The maximum shipping weight a dry van truck can hold (see Section 6.1.5), 45,000 lbs.

For plants where the expected design flow was greater than 500 gpm and less than or equal to 700 gpm, EPA used Equation 6-110.
Continuous Backwash Gravity Sand Filters Cost (2011$) = ($180,000 × Sand Filter Qty) + (Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost / Truck Weight Capacity) (6-110)

where:

Sand Filter Qty = Number of sand filters; within this flow rate range, four sand filters are required, Sand Weight = Amount of sand, in lbs, required for each sand filter unit; for the unit associated w ith this flow rate range, [Redacted] of sand are required,
Flatbed Truck Cost = The cost for a full equipment shipment via flatbed truck approximately 500 miles (see Section 6.1.5), [Redacted], and Truck Weight Capacity = The maximum shipping weight a dry van truck can hold (see Section 6.1.5), 45,000 lbs.

Based on conversations with the vendor, fo r flow rates greater than 700 gpm, EPA assumed that the large si ze filter press is applicable for wast ewater flows up to 350 gpm per filter when multiple units are used. Therefore, EPA developed Equation 6-111 to calculate the number of sand filters required
Sand Filter Qty = 2 × Expected Design Flow / 350 gpm (rounded up to the nearest whole number) (6-111)

For plants where the expected design flow was greater than 700 gpm EPA used Equation 6-112 to estimate sand filter costs.
Continuous Backwash Gravity Sand Filters Cost (2011$) = ($180,000 × Sand Filter Qty) + (Flatbed Truck Cost × Sand Filter Qty) + (Sand Weight × Sand Filter Qty × Flatbed Truck Cost / Truck Weight Capacity) (6-112)

where:

Sand Filter Qty = Number of sand filters,
Sand Weight = Amount of sand, in lbs, required for each sand filter unit; for the unit associated w ith this flow rate range, [Redacted] of sand are required,Chapter 6 - FGD Wastewater Cost Methodology

6-60 Flatbed Truck Cost = The cost for a full equipment shipment via flatbed truck approximately 500 miles (see Section 6.1.5), [Redacted], and Truck Weight Capacity = The maximum shipping weight a dry van truck can hold (see Section 6.1.5), 45,000 lbs.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A39 through SE01825.A42) for more detail on the devel opment of Equations 6-104 through 6-112.

6.1.6.8 Purchased Equipment Installation Cost
EPA determined these direct costs by multip lying plant-purchased equipment costs by a factor. The factor was determined based on resp onses to Question D6-3 of the Steam Electric Survey. To develop this factor, EPA first calcul ated, for each plant that completed Question D6- 3 specific to FGD wastewater chemical precip itation treatment, the ratio of each plant’s purchased equipment installation costs to their purchased equipm ent cost. After calculating this ratio for all applicable responses, EPA selected the factor, [Redacted], as the median ratio. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A43) for additional information.
EPA used Equation 6-113 to calculate pur chased equipment installation costs.
Purchased Equipment Installation Cost (2010$) = Installation Factor × Purchased Equipment Cost (6-113)

where:

Installation Factor = The median rati o over all the plants of each plant’s purchased equipment inst allation costs to their purchased equipment cost, [Redacted], and Purchased Equipment Cost = The total purchased equipm ent cost required to treat FGD wastewater with one-st age chemical precipitation (Sections 6.1.6.1 through 6.1.6.7).

6.1.6.9 Building Cost
EPA determined these direct costs by multip lying plant purchased equipment costs by a factor generated based on responses to Question D6-3 of the Steam Electric Survey. To develop this factor, EPA first calculated, for each plant that completed Question D6-3 specific to FGD wastewater chemical precipitati on treatment, the ratio of each pl ant’s buildings costs to their purchased equipment cost. After ca lculating this ratio for all app licable responses, EPA selected the factor, [Redacted], as the median ratio. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A43) for additional information.Chapter 6 - FGD Wastewater Cost Methodology

6-61 Note that EPA considered whether plants locat ed in the northern United States with cold winter temperatures are more likely to use buildi ngs than plants located in the southern United States. However, EPA found no basis to diffe rentiate building cost s based on location.
EPA used Equation 6-114 to calculate buildings costs.
Building Cost (2010$) = Building Fa ctor × Purchased Equipment Cost (6-114)

where:

Building Factor = The median ratio over all the plants of each plant’s buildings costs to their purchased equipment cost, [Redacted], and Purchased Equipment Cost = The total purchased equipm ent cost required to treat FGD wastewater with one-st age chemical precipitation (Sections 6.1.6.1 through 6.1.6.7).

6.1.6.10 Land Cost

To assess the need for land costs, EPA review ed the responses to Question D6-3 of the Steam Electric Survey for each plant that comple ted this question specific to FGD wastewater chemical precipitation treatment. Based on this re view, EPA determined that of the 20 plants included in this dataset, [Redacted] reported either zero costs or did not re port any costs for land. For the remaining [Redacted] plants, reported land costs were very low (approximately 1 percent of purchase equipment costs). Accordingl y, EPA assumed zero costs for land. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A43) for additional information.

6.1.6.11 Site Preparation Cost
EPA determined site preparation direct co sts by multiplying plant purchased equipment costs by a factor generated base d on responses to Question D6-3 of the Steam Electric Survey. To develop this factor, EPA first calculated, for each plant that completed Question D6-3 specific to FGD wastewater chemi cal precipitation treatment, the ratio of each plant’s site preparation costs to their purchased equipment cost . After calculating this ratio for all applicable responses, EPA selected the factor, [Red acted], as the median ratio. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A43) for additional information.
EPA used Equation 6-115 to calcu late site preparation costs.
Site Preparation Cost (2 010$) = Site Prep Factor × Purchased Equipment Cost (6-115)

where:

Site Prep Factor = The median ratio over all the plants of each plant’s site preparation costs to their purchased equipment cost,Chapter 6 - FGD Wastewater Cost Methodology

6-62 [Redacted], and

Purchased Equipment Cost = The total purchased equipm ent cost required to treat FGD wastewater with one-st age chemical precipitation (Sections 6.1.6.1 through 6.1.6.7).

6.1.6.12 Engineering Cost
EPA determined engineering costs by multiplying plant purchased equipment costs by a factor generated based on responses to Question D6-3 of the Steam Electric Survey. To develop this factor, EPA first calculated, for each pl ant that completed Question D6-3 for FGD wastewater chemical precipitation treatment, the ratio of the sum of each plant’s two engineering costs (Engineering Contr act Firm Costs and Owner’s Overhe ad Engineering Costs) to their purchased equipment. After calcula ting this ratio for all applicab le responses, EPA selected the factor, [Redacted], as the median ratio. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A43) for additional information.
EPA used Equation 6-116 to calculate engineering cost:
Engineering Cost (2010$) = Engineeri ng Factor × Purchased Equipment Cost (6-116)

where:

Engineering Factor = The median ratio over all the plants of the sum of each plant’s two engineering co sts and their purchased equipment cost, [Redacted], and Purchased Equipment Cost = The total purchased equipm ent cost required to treat FGD wastewater with one-st age chemical precipitation (Sections 6.1.6.1 through 6.1.6.7).

6.1.6.13 Construction Expenses
EPA determined construction expenses by multiplying plant purchased equipment costs by a factor generated based on responses to Qu estion D6-3 of the Steam Electric Survey. To develop this factor, EPA first calculated, for each plant that completed Question D6-3 for FGD wastewater chemical precipitation treatment, the ratio of each plan t’s construction costs to their purchased equipment cost. After ca lculating this ratio for all app licable responses, EPA selected the factor, [Redacted], as the median ratio. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A43) for additional information.
EPA used Equation 6-117 to cal culate construction expenses.
Construction Expenses (2010$) = Construc tion Factor × Purchased Equipment Cost (6-117)Chapter 6 - FGD Wastewater Cost Methodology

6-63 where:

Construction Factor = The median ratio over all the plants of the sum of each plant’s construction costs to their purchased equipment cost, [Redacted], and Purchased Equipment Cost = The total purchased equipm ent cost required to treat FGD wastewater with one-st age chemical precipitation (Sections 6.1.6.1 through 6.1.6.7).

6.1.6.14 Other Contractors’ Fees
EPA determined other contractor’s fees by multiplying plant purchased equipment costs by a factor generated based on responses to Qu estion D6-3 of the Steam Electric Survey. To develop this factor, EPA first calculated, for each plant that completed Question D6-3 for FGD wastewater chemical precipitation treatment, the ratio of each plant’ s other contractor’s fees to their purchased equipment cost. After calculating this ratio for all applicable responses, EPA selected the factor, [Redacted], as the median ratio. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A43) for additional information.
EPA used Equation 6-118 to calcu late other contractor’s fees.
Other Contractor’s Fees (2010$) = Contra ctor Factor × Purchased Equipment Cost (6-118)

where:

Contractor Factor = The median rati o over all the plants of each plant’s other contractor’s fees to their purchased equipment cost, [Redacted], and Purchased Equipment Cost = The total purchased equipm ent cost required to treat FGD wastewater with one-st age chemical precipitation (Sections 6.1.6.1 through 6.1.6.7).

6.1.6.15 Contingency Fees
To assess the need for contingency fees, EP A reviewed the responses to Question D6-3 of the Steam Electric Survey for each plant th at completed this question specific to FGD wastewater chemical precipita tion treatment. Based on this re view, EPA determined that 90 percent of the plants reported e ither zero costs or did not report any costs for contingencies. EPA assumed that contingency costs for the remaining 10 percent of plants are site-specific and not representative of the industry. Accordingly, EP A assumed zero costs for contingencies. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A43) for additional information.Chapter 6 - FGD Wastewater Cost Methodology

6-64 6.1.7 O&M Cost Methodology
O&M costs comprise all costs related to operating and maintaining the chemical precipitation wastewater treatment system. O& M costs include the sum of the following:

 Operating Labor Cost,

 Maintenance Labor Cost,

 Maintenance Material Cost,

 Chemical Purchase Cost, and

 Energy Cost.

6.1.7.1 Operating Labor Cost
EPA calculated operating labor costs for each plant based on plant FGD Wastewater Flow GPD (see Section 6.1.5). To calculate co sts, EPA developed Equation 6-119, provided below, relating operating labor co st to FGD wastewater flow using responses to Question D6-2 of the Steam Electric Survey specific to FGD wa stewater chemical prec ipitation treatment. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A44) for additional information. As plant’s provided the operating labor cost in 2009 dollars, EPA adjusted the cost basis to 2010 dollars using the 2009 and 2010 RS Means Historical Cost Indices (180.1 and 183.5, respectively) [RSMeans, 2011].

Operating Labor Cost (2010$/yr) = 0 .2719 × (FGD Wastewater Flow GPD × 365) 0.7789 × 2010 Cost Index/2009 Cost Index (6-119)

where:

FGD Wastewater Flow GPD = FGD wastewater flow in gpd as reported in the Steam Electric Survey (see Section 6.1.5), 2009 Cost Index = 180.1, and

2010 Cost index = 183.5.

6.1.7.2 Maintenance Labor Cost
EPA calculated maintenance labor costs by multiplying plant FGD Wastewater Treatment Flow GPM (see Section 6.1.5) by two cost factors: Mainte nance Labor Rate and Maintenance Labor Factor. EPA determined the co st factors based on responses to Question D6- 2 of the Steam Electric Survey specific to FGD wastewater chemical precipitation treatment. To develop the Maintenance Labor Ra te, EPA selected the median reported maintenance labor rate, [Redacted]. To develop the Maintenance Labor F actor, EPA first calculate d, for each plant that completed Question D6-2 for FGD wastewater chem ical precipitation treatment, the ratio of the number of hours per year needed to maintain the chemical precipitation treatment systems and the plant’s annual FGD wastewater treatment flow. After calculating this ratio for all applicable responses, EPA selected the factor [R edacted] as the median ratio. See the Supplemental CostsChapter 6 - FGD Wastewater Cost Methodology

6-65 and Loadings Documentation (DCN SE01825.A46) for additional information. As plants provided the maintenance labor ra te in 2009 dollars, EPA adjusted the cost basis to 2010 dollars using the 2009 and 2010 RSMeans Historical Cost Indices (180.1 and 183.5, respectively) [RSMeans, 2011].
EPA used Equation 6-120 to calculate annual maintenance labor costs.
Maintenance Labor Cost (2010$/y r) = (Maintenance Labor Rate × Maintenance Labor Factor ×

FGD Wastewater Treatment Fl ow GPM × Minutes Per Year/M illion Gallon Factor) × (2010 Cost Index/2009 Cost Index) (6-120)

where:

Maintenance Labor Rate = The median cost, in dollar s per hour, of a chemical precipitation system mainte nance worker, [Redacted],
Maintenance Labor Factor = Median hours per year per million gallons of FGD wastewater treated per year required to maintain the chemical precipitation system, [Redacted],

FGD Wastewater Treatment Flow GPM = FGD wastewater flow in gpm normalized for 24 hpd operation (see Section 6.1.5),
Minutes Per Year = Factor to conve rt between minutes and years, 525,600 min/yr,
Million Gallon Factor = Factor to co nvert between millions of gallons and gallons, 1,000,000 gal/million gal, 2009 Cost Index = 180.1, and

2010 Cost index = 183.5.

6.1.7.3 Maintenance Materials Cost

EPA calculated maintenance materials co sts by multiplying plant FGD Wastewater Treatment Flow GPM (see Section 6.1.5) by a cost factor. EPA determined the cost factor based on responses to Questions D6-2 of the Steam Electric Survey specifi c to FGD wastewater chemical precipitation treatment. To develop the f actor, EPA first calculat ed, for each plant that completed Question D6-2 for FGD wastewater chem ical precipitation treatment, the ratio of the maintenance materials costs per year and the plant’s annual FGD wastew ater treatment flow. After calculating this ratio for all applicable resp onses, EPA selected the factor [Redacted] as the median ratio. See the Supplemental Costs and Loadings Documentation (DCN SE01825.46) for additional information. As plants provided the maintenance materials cost in 2009 dollars, EPA adjusted the cost basis to 2010 dollars using th e 2009 and 2010 RSMeans Historical Cost Indices (180.1 and 183.5, respectively) [RSMeans, 2011].
EPA used Equation 6-121 to calculate annual maintenance materials costs.Chapter 6 - FGD Wastewater Cost Methodology

6-66 Maintenance Materials Cost ( 2010$/yr) = (Maintenance Material s Factor × FGD Wastewater Treatment Flow GPM × Minutes Per Year/Million Gallon Facto r) × (2010 Cost Index/2009 Cost Index) (6-121)

where:

Maintenance Materials Factor = The cost, in dollars per year per million gallons of FGD wastewater treated per year, of maintenance materials for the chemical precipitation system, [Redacted],

FGD Wastewater Treatment Flow GPM = FGD wastewater flow in gpm normalized for 24 hpd operation (see Section 6.1.5),
Minutes Per Year = Factor to conve rt between minutes and years, 525,600 min/yr,
Million Gallon Factor = Factor to co nvert between millions of gallons and gallons, 1,000,000 gal/million gal, 2009 Cost Index = 180.1, and

2010 Cost index = 183.5.

6.1.7.4 Chemical Purchase Cost
EPA estimated the chemical purchase costs by multiplying the chemical dosage rate (expressed in grams of chemical per liter of wa stewater flow) by the plant flow rate and by the chemical cost (expressed in dollars per t on) for each treatment chemical required. EPA determined the chemical dosage rates based on the average chemical dosage rates used by the BAT plants during sampling, listed below [ERG, 2013; See Appendix 47]:

 Hydrated lime is added to reaction tank 1 at a dosage of [Redacted];

 Organosulfide is added to reaction tank 2 at a dosage of [Redacted];

 Ferric chloride is added to reacti on tank 3 at a dosage of [Redacted];

 Polymer is added inline prior to the solids contact clarifier at a dosage of [Redacted]; and

 Hydrochloric acid is added prior to sand filtration at a dosage of [Redacted].
EPA obtained the following chemical purchas e costs from chemical suppliers [ERG, 2013; See Appendix 48]:

 Hydrated lime at [Redacted] per ton;

 Organosulfide at [Redacted] per ton; 31,32

31 EPA’s cost methodology is inconsistent in that this discussion assumes organosulfide and polymer purchase as solids while the feed system discussion in Section 6.1.6. 3 assumes injection as liquids. For the final rule, EPA willChapter 6 - FGD Wastewater Cost Methodology

6-67  Ferric chloride at [Red acted] per dry ton;

 Polymer at [Redacted] per ton; 31 and

 Hydrochloric acid (32 percen t) at [Redacted] per ton.
EPA developed a weighted chemical freight cost of $62.79 per ton, based on the required quantities of the various chemicals and their de nsities, and freight cost information by weight from FreightCenter.com. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A49) for additional information.
As plants provided the chemical purchase co sts in 2011 dollars, EPA adjusted the cost basis to 2010 dollars using the 2010 and 2011 RSM eans Historical Cost Indices (183.5 and 185, respectively) [RSMeans, 2011]. The annual chemical purchase cost is calculated by Equation 6-122.
Chemical Purchase Cost (2010$/yr) = (Hydrated Lime Cost + Organosulfide Cost + Ferric Chloride Cost + Polymer Cost + Hydrochl oric Acid Cost) × 2010 Cost Index/2011 Cost Index (6-122)

The remainder of this section discusses the development of the purchase costs for each of the required treatment chemicals.

Hydrated Lime Cost
Hydrated Lime Cost (2011$/yr) = Hydrated Lime Dose × (Hydrated Lime Unit Cost + Chemical Freight Cost) × FGD Wastewater Treatment Flow GPM × Liters Per Gallon × Minutes Per Year / (Hydrated Lime Concentration × Grams Per Ton) (6-123)

where:

Hydrated Lime Dose = Amount of lime, in grams per liter, n eeded to treat the FGD wastewater in the chem ical precipitation system, [Redacted], Hydrated Lime Unit Cost = Lime cost, in dollars per ton of lime, [Redacted],

Chemical Freight Cost = The weighted cost per ton to ship the various chemicals needed to operate the chemical precipitation system to the plant, $62.79,

FGD Wastewater = FGD wastewater flow in gpm normalized for 24 hpd

reevaluate the organosulfide and polymer purchase, freight, storage, and feed system methodologies and revise them as appropriate. In the interim, EPA considers the magnitu de of the current estimated costs to be appropriate.

32 EPA inappropriately used bulk quantity rather than drum/bulk bag quantity organosulfide purchase costs. Correcting this error would double organosulfide purchase costs. EPA notes, however, that organosulfide represents only a small percentage of tota l chemical purchase costs.Chapter 6 - FGD Wastewater Cost Methodology

6-68 Treatment Flow GPM operation (see Section 6.1.5),

Hydrated Lime Concentration = Concentration of lime in the form it is purchased,100 percent,
Liters Per Gallon = Factor to conve rt between liters and gallons, 3.7854 liters/gal,
Minutes Per Year = Factor to conve rt between minutes and years, 525,600 min/yr, and

Grams Per Ton = Factor to conve rt between grams and tons, 907,185 g/ton.

Organosulfide Cost
Organosulfide Cost (2011$/yr) = Organosulfide Dose × (Organos ulfide Unit Cost + Chemical Freight Cost) × FGD Wastewater Treatment Flow GPM × Liters Per Gallon × Minutes Per Year / (Organosulfide Concentration × Grams Per Ton) (6-124)

where:

Organosulfide Dose = Amount of organosul fide, in grams per liter, needed to treat the FGD wastewater in the chemical precipitation system, [Redacted], Organosulfide Unit Cost = Organosulfide cost, in dolla rs per ton of organosulfide, [Redacted], Chemical Freight Cost = The weighted cost per ton to ship the various chemicals needed to operate the chemical precipitation system to the plant, $62.79,

FGD Wastewater Treatment Flow GPM = FGD wastewater flow in gpm normalized for 24 hpd operation (see Section 6.1.5), Organosulfide Concentration = Concentration of organosulfide in solution as purchased, 100 percent,
Liters Per Gallon = Factor to conve rt between liters and gallons, 3.7854 liters/gal,
Minutes Per Year = Factor to conve rt between minutes and years, 525,600 min/yr, and

Grams Per Ton = Factor to conve rt between grams and tons, 907,185 g/ton.Chapter 6 - FGD Wastewater Cost Methodology

6-69 Ferric Chloride Cost
Ferric Chloride Cost (2011$/yr) = Ferric Chloride Dose × (Ferric Chloride Unit Cost + Chemical Freight Cost) × FGD Wastewater Treatment Flow GPM × Liters Per Gallon × Minutes Per Year / (Ferric Chloride Concentration × Grams Per Ton) (6-125)

where:

Ferric Chloride Dose = Amount of ferric chloride, in gr ams per liter, needed to treat the FGD wastewater in the chemical precipitation system, [Redacted],
Ferric Chloride Unit Cost = Ferric chloride cost, in dolla rs per ton of ferric chloride, [Redacted], Chemical Freight Cost = The weighted cost per ton to ship the various chemicals needed to operate the chemical precipitation system to the plant, $62.79,

FGD Wastewater Treatment Flow GPM = FGD wastewater flow in gpm normalized for 24 hpd operation (see Section 6.1.5),
Ferric Chloride Concentration = Dry weight concentratio n of ferric chloride in solution,100 percent,
Liters Per Gallon = Factor to conve rt between liters and gallons, 3.7854 liters/gal,
Minutes Per Year = Factor to conve rt between minutes and years, 525,600 min/yr, and

Polymer Cost
Polymer Cost (2011$/yr) = Polymer Dose × (Polymer Unit Cost + Chemical Freight Cost) × FGD Wastewater Treatment Flow GPM × Liters Per Gallon × Minutes Per Year / (Polymer Concentration × Grams Per Ton) (6-126)

where:

Polymer Dose = Amount of polymer, in grams per liter, needed to treat the FGD wastewater in the chemical precipitation system, [Redacted], Polymer Unit Cost = Polymer cost , in dollars per ton of polymer, [Redacted], Chemical Freight Cost = The weighted cost per ton to ship the various chemicals needed to operate the chemical precipitation system to the plant, $62.79,Chapter 6 - FGD Wastewater Cost Methodology

6-70 FGD Wastewater Treatment Flow GPM = FGD wastewater flow in gpm normalized for 24 hpd operation (see Section 6.1.5), Polymer Concentration = Concentration of polymer in solution as purchased,100 percent,
Liters Per Gallon = Factor to conve rt between liters and gallons, 3.7854 liters/gal,
Minutes Per Year = Factor to conve rt between minutes and years, 525,600 min/yr, and

Grams Per Ton = Factor to conve rt between grams and tons, 907,185 g/ton.

Hydrochloric Acid Cost
Hydrochloric Acid Cost (2011$/yr) = Hydrochloric Acid Dose × (Hydrochloric Acid Unit Cost + Chemical Freight Cost) × FGD Wastewater Treatment Flow GP M × Liters Per Gallon × Minutes Per Year / (Hydrochloric Acid Concentration × Grams Per Ton) (6-127)

where:

Hydrochloric Acid Dose = Amount of hydrochloric acid, in grams per liter, needed to treat the FGD wastewater in the chemical precipitation system, [Redacted], Hydrochloric Acid Unit Cost = Hydrochloric acid cost, in dollars per ton of hydrochloric acid, [Redacted], Chemical Freight Cost = The weighted cost per ton to ship the various chemicals needed to operate the chemical precipitation system to the plant, $62.79,

FGD Wastewater Treatment Flow GPM = FGD wastewater flow in gpm normalized for 24 hpd operation (see Section 6.1.5), Hydrochloric Acid Concentration = Concentration of hydrochloric acid in solution as purchased, 32 percent,
Liters Per Gallon = Factor to conve rt between liters and gallons, 3.7854 liters/gal,
Minutes Per Year = Factor to conve rt between minutes and years, 525,600 min/yr, and

Grams Per Ton = Factor to conve rt between grams and tons, 907,185 g/ton.Chapter 6 - FGD Wastewater Cost Methodology

6-71 6.1.7.5 Energy Cost
EPA determined overall chemical precipitati on energy requirements (in kilowatt hour (kWh)) by calculating the power requirements pe r day for each piece of equipment based on information, largely in the form of horsepow er, provided by equipment vendors. EPA assumed 24-hour-per-day operation of all tr eatment system equipment except the filter press. To calculate the annual energy requirements, EPA multiplied the daily requirements by 365 days per year.
The total annual energy requirement is calculated using Equation 6-128.
Annual Energy Requirement (kWh/yr) = (Waste water Feed Pump Energy + Wastewater Forwarding Pump Energy + Sludge Recycle/ Transfer Pumps Energy + Filter Press Feed/Pressurization Pumps Energy + Treated Wa stewater Pumps Energy + Sump Pump Energy + Lime Slurry Pump Energy + FGD Recycle Pump Energy + Lime Feed System Energy + Ferric Chloride Feed System Energy + Organosulfide Feed System Energy + Polymer Feed System Energy + Hydrochloric Acid Feed System En ergy + Equalization Tank Mixer Energy + Reaction Tank 1 Mixer Energy + Reaction Tank 2 Mixe r Energy + Reaction Tank 3 Mixer Energy + Sludge Holding Tank Mixer Energy + Lime Slurry Preparation Tank Mixer Energy + Filtrate

Sump Mixer Energy + Solids Contact Clarifier Energy + Filter Press Energy + Sand Filters Energy) × 365 Days Per Year (6-128)

To calculate annual energy costs, EPA then multiplied the total annual energy requirement by the average national energy cost of 4.05 cents per kWh (2009$) as determined based on data reported by the U.S. Energy in formation Administration in Table 8.2 of the Electric Power Annual 2009 for fossil plants in the United States [U.S. DOE, 2011]. As the energy cost was provided in 2009 dollars, EPA adju sted the cost basis to 2010 dollars using the 2009 and 2010 RSMeans Historical Cost Indi ces (180.1 and 183.5, respectively) [RSMeans, 2011]. The chemical precipitation cost modul e outputs both overall energy requirements and energy costs to allow flexibility for furt her analyses of this cost element.

Energy Cost (2010$/yr) = National En ergy Cost × Annual Energy Requirement × (2010 Cost Index/2009 Cost Index) (6-129)

where:

National Energy Cost = $0.0405/kWh (2009$),
Annual Energy Requirement = Annual power requirements to operate all equipment required for chemical precipi tation of FGD wastewater, in kWh/yr, 2009 Cost Index = 180.1, and

2010 Cost index = 183.5.

For the purpose of estimating non-water qu ality environmental impacts, EPA also converted energy consumption in kWh/yr to energy load in MW using Equation 6-130.Chapter 6 - FGD Wastewater Cost Methodology

6-72 Energy Load (MW) = Annual Energy Requirement / (24 hpd × 365 dpy × 1,000 kW/MW) (6-130)

Pump electricity requirements are based on th e horsepower (hp) of each pump motor. EPA developed equations predicting the hor sepower of a pump motor based on the FGD wastewater flow. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A50) for additional information. EPA c onverted horsepower to kilowatts and calculated kilowatt-hours assuming 24-hour ope ration. Where excess pumps are costed for redundancy, this excess capacity, placed in standby, is not co nsidered in the electricity requirements.
Tanks have no energy requirement.
Regarding liquid chemical feed systems, Enpr o-Tech indicated that each liquid chemical feed system (e.g., ferric chloride , polymer) requires at most a 1⁄2 hp motor. The liquid feed system energy requirement is calculated based on the hor sepower of the require d motor and the number of feed points required to treat the wa stewater, as defined in Section 6.1.6.3.
To calculate the mixer energy requiremen ts, EPA assumed the mixer torque is proportional to mixer horsepower (see Section 6.1.6.4). EPA calculated th e ratio of horsepower to torque for each of the example plant’s mixers . EPA multiplied this value by the plant-specific torque, calculated as the torque per volume, multiplied by the tank size. The detailed equations are defined below. Note that the mixer and ta nk size calculations are described in Sections 6.1.6.4 and 6.1.6.2, respectively.

Wastewater Feed Pump Energy EPA assumed that plants will use existing FGD wastewater feed pumps to move FGD wastewater from the FGD system to the equa lization tank of the new chemical precipitation treatment system (or to the existing FGD impou ndment, for certain “high flow” plants (see Section 4.4.3). Therefore, EPA assumed there ar e no incremental energy requirements for these pumps.
Wastewater Forwarding Pump Energy The wastewater forwarding pump energy requ irements are determined with Equation 6-131.
Wastewater Forwarding Pump Energy (kWh/day) = (0.0151 × Capacity Factor × FGD Wastewater Treatment Flow GPM + 2.0191) × hp KW Factor × Operating Hours (6-131)

where:

Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted],

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5),Chapter 6 - FGD Wastewater Cost Methodology

6-73 hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Sludge Recycle/Transfer Pumps Energy The sludge recycle and transfer pump energy requirements are based on the lime slurry pump energy requirements. Three sludge pumps ar e included in calculating energy requirements: one for each clarifier and one for sludge recy cle. The sludge pump energy requirements are determined with Equation 6-132.
Sludge Recycle/Transfer Pumps Energy (k Wh/day) = (0.0205 × Sludge Factor × FGD Wastewater Treatment Flow GPM + 0.7831) × hp KW Factor × Operating Hours × 3
pumps (6-132)

where:

Sludge Factor = Factor to estimate the sludge generation rate based on the FGD Wastewater Treatment Flow GPM (see Section 6.1.5), 0.4,

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Filter Press Feed/Pressurization Pumps Energy The energy requirements for filter press feed/pressurization pumps are included in the filter press electricity requirements.

Treated Wastewater Discharge Pumps Energy Where wastewater flow rates trigger the co sting of multiple treated wastewater tanks, multiple pumps are costed. Note that the quantity of treated wastewater tanks is calculated in Section 6.1.6.2. The treated wastewater discha rge pump energy requirements are determined using Equation 6-133.

Treated Wastewater Pumps Energy (kWh/day) = (0.0182 × Capacity Factor × FGD Wastewater Treatment Flow GPM + 0.6031) × hp KW F actor × Operating Hours × Treated WW Tank Qty (6-133)Chapter 6 - FGD Wastewater Cost Methodology

6-74 where:

Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted],

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, Operating Hours = System ope rating hours per day, 24, and
Treated WW Tank Qty = The number of tr eated wastewater tanks, rounded up to the nearest whole number (see Section 6.1.6.2 and Equation 6-32).

Sump Pump Energy The sump pump energy requirements ar e determined with Equation 6-134.
Sump Pump Energy (kWh/day) = (0.0229 × Capac ity Factor × FGD Wastewater Treatment Flow GPM + 0.9268) × hp KW Factor × Operating Hours (6-134)

where:

Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted],

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Lime Slurry Pump Energy Lime slurry pump energy requirements are in cluded in the energy requirements of the lime feed system.

FGD Recycle Pump Energy The FGD recycle pump energy requirements, associated with certain “high flow” plants (see Section 4.4.3), are determined using Equation 6-135.
FGD Recycle Pump Energy (kWh/day) = (0.0151 × Capacity Factor × FGD Wastewater Treatment Flow GPM + 2.0191) × hp KW Factor × Operating Hours (6-135)Chapter 6 - FGD Wastewater Cost Methodology

6-75 where:

Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted],

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Lime Feed System Energy EPA assumed that the lime feed system en ergy requirement is primarily pump energy consumption. Enpro-Tech indicate d that a typical lime feed syst em includes slurry pumps with capacities of up to 40 to 60 gpm. EPA estimated a pump horsepower to be equal to that of one [Redacted] lime slurry pump, based on pump in formation provided by Weir Minerals [ERG, 2013; See Appendix 6].
Lime Slurry Feed System Energy (kWh/day) = [Redacted] × hp KW Factor × Operating Hours (6-136)

where:

hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Ferric Chloride Feed System Energy
FeCl3 Feed System Energy (kWh/day) = FeCl3 Feed Point Qty × Feed hp × hp KW Factor × Operating Hours (6-137)

where:

FeCl3 Feed Point Qty = The number of ferric chloride feed points required to treat FGD wastewater, rounde d up to the nearest whole number (see Section 6.1.6.3 and Equation 6-58), Feed hp = The horsepower required by the motor used in a liquid feed system, 0.5 hp, hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.Chapter 6 - FGD Wastewater Cost Methodology

6-76 Organosulfide Feed System Energy
Organosulfide Feed System Energy (kWh/day) = Sulfide Feed Point Qty × Feed hp × hp KW Factor × Operating Hours (6-138)

where:

Sulfide Feed Point Qty = The number of organosulfide feed points required to treat FGD wastewater, rounde d up to the nearest whole number (see Section 6.1.6.3 and Equation 6-63), Feed hp = The horsepower required by the motor used in a liquid feed system, 0.5 hp, hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Polymer Feed System Energy
Polymer Feed System Energy (kWh/day) = Polyme r Feed Point Qty × Feed hp × hp KW Factor × Operating Hours (6-139)

where:

Polymer Feed Point Qty = The number of polymer feed points required to treat FGD wastewater, rounded up to the nearest whole number (see Section 6.1.6.3 and Equation 6-67), Feed hp = The horsepower required by the motor used in a liquid feed system, 0.5 hp, hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Hydrochloric Acid Feed System Energy
HCl Feed System Energy (kWh/day) = HCl Feed Point Qty × Feed hp × hp KW Factor × Operating Hours (6-140)

where:

HCl Feed Point Qty = The number of hydr ochloric acid feed points required to treat FGD wastewater, rounded up to the nearest whole number (see Section 6.1.6.3 and Equation 6-71),Chapter 6 - FGD Wastewater Cost Methodology

6-77 Feed hp = The horsepower required by the motor used in a liquid feed system, 0.5 hp, hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Equalization Tank Mixer Energy
Eq Mixer HP (hp) = Eq Mixer Torque Per Volu me × Equalization Tank Size × Example Plant Eq Mixer HP / Example Plant Eq Mixer Torque (6-141)

Equalization Tank Mixer Energy (kWh/day) = Eq Mixer HP × hp KW Factor × Operating Hours (6-142)

where:

Eq Mixer Torque Per Volume = The calculated torque per volume for the equalization tank (see Section 6.1.6.4 and Equation 6-77), Equalization Tank Size = The calculate d equalization tank size (see Section 6.1.6.2 and Equation 6-16), Example Plant Eq Mixer HP = The example plant’s equalization tank mixer’s horsepower (see Section 6.1.6.4), Example Plant Eq Mixer Torque = The torque of the equalization tank mixer used by the example plant (see Section 6.1.6.4), hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Reaction Tank 1 Mixer Energy
Rxn1 Mixer HP (hp) = Rxn1 Mixer Torque Per Vo lume × Reaction Tank 1 Size × Example Plant Rxn1 Mixer HP / Example Plant Rxn1 Mixer Torque (6-143)

Reaction Tank 1 Mixer Energy (kWh/day) = Rx n1 Mixer HP × hp KW Factor × Operating Hours (6-144)

where:

Rxn1 Mixer Torque Per Volume = The calculated torque per volume for the reaction tank 1 mixer (see Section 6.1. 6.4 and Equation 6-81),
Reaction Tank 1 Size = The calculated reaction tank 1 size (see Section 6.1.6.2 and Equation 6-21),Chapter 6 - FGD Wastewater Cost Methodology

6-78 Example Plant Rxn1 Mixer HP = The example plant’s reaction tank 1 mixer’s horsepower (see Section 6.1.6.4), Example Plant Rxn1 Mixer Torque = The torque of the reaction tank 1 mixer used by the example plant (see Section 6.1.6.4), hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Reaction Tank 2 Mixer Energy
Rxn2 Mixer HP (hp) = Rxn2 Mixer Torque Per Vo lume × Reaction Tank 2 Size × Example Plant Rxn2 Mixer HP / Example Plant Rxn2 Mixer Torque (6-145)

Reaction Tank 2 Mixer Energy (kWh/day) = Rx n2 Mixer HP × hp KW Factor × Operating Hours (6-146)

where:

Rxn2 Mixer Torque Per Volume = The calculated torque per volume for reaction tank 2 mixer (see Section 6.1.6.4 and Equation 6-85),
Reaction Tank 2 Size = The calculated reaction tank 2 size (see Section 6.1.6.2 and Equation 6-25), Example Plant Rxn2 Mixer HP = The example plant’s reaction tank 2 mixer’s horsepower (see Section 6.1.6.4), Example Plant Rxn2 Mixer Torque = The torque of the reaction tank 2 mixer used by the example plant (see Section 6.1.6.4), hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Reaction Tank 3 Mixer Energy
Rxn3 Mixer HP (hp) = Rxn3 Mixer Torque Per Vo lume × Reaction Tank 3 Size × Example Plant Rxn3 Mixer HP / Example Plant Rxn3 Mixer Torque (6-147)

Reaction Tank 3 Mixer Energy (kWh/day) = Rx n3 Mixer HP × hp KW Factor × Operating Hours (6-148)

where:

Rxn3 Mixer Torque Per Volume = The calculated torque per volume for reaction tank 3 (see Section 6.1.6.4 and Equation 6-89),Chapter 6 - FGD Wastewater Cost Methodology

6-79 Reaction Tank 3 Size = The calculated reaction tank 3 size (see Section 6.1.6.2 and Equation 6-29), Example Plant Rxn3 Mixer HP = The example plant’s reaction tank 3 mixer’s horsepower (see Section 6.1.6.4), Example Plant Rxn3 Mixer Torque = The torque of the reaction tank 3 mixer used by the example plant (see Section 6.1.6.4), hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Sludge Holding Tank Mixer Energy
Sldg Mixer HP (hp) = Sldg Mixer Torque Per Volume × Sludge Holdi ng Tank Size × Example Plant Sldg Mixer HP / Exam ple Plant Sldg Mixer Torque (6-149)

Sludge Holding Tank Mixer Energy (kWh/day) = Sldg Mixer HP × hp KW Factor × Operating Hours (6-150)

where:

Sldg Mixer Torque Per Volume = The calculated torque per volume for the sludge holding tank mixer (see Section 6.1.6.4 and Equation 6-93), Sludge Holding Tank Size = The calculated sludge holding tank size (see Section 6.1.6.2 and Equation 6-36), Example Plant Sldg Mixer HP = The example plant’s sludge holding tank mixer’s horsepower (see Section 6.1.6.4), Example Plant Sldg Mixer Torque = The torque of the sludge holding tank mixer used by the example plant (see Section 6.1.6.4), hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Lime Slurry Preparation Tank Mixer Energy EPA did not cost lime slurry preparation tank mixers because mixers were included in the overall feed system cost. Because separate mixe rs were not required, EPA did not calculate lime slurry preparation tank mi xer energy requirements.Chapter 6 - FGD Wastewater Cost Methodology

6-80 Filtrate Sump Mixer Energy
Sump Mixer HP (hp) = Eq Mixer Torque Per Vo lume × Sump Size × Example Plant Eq Mixer HP / Example Plant Eq Mixer Torque (6-151)

Filtrate Sump Mixer Energy (kWh/day) = Sump Mixer HP × hp KW Factor × Operating Hours (6-152)

where:

Eq Mixer Torque Per Volume = The calculated torque per volume for the equalization tank (see Section 6.1.6.4 and Equation 6-77), Sump Size = The calculated sump size in gallons (see Section 6.1.6.4 and Equation 6-95), Example Plant Eq Mixer HP = The example plant’s equalization tanks mixer’s horsepower (see Section 6.1.6.4), Example Plant Eq Mixer Torque = The torque of the equalization tank mixer used by the example plant (see Section 6.1.6.4), hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Solids Contact Clarifiers Energy EPA calculated energy requirements for two so lids contact clarifie rs per plant. The energy requirements include the mixer drive en ergy requirements and th e scraper drive energy requirements. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A50) for additional information.
The mixer drive horsepower ranges from 2 to 5 hp depending on the size of unit. EPA developed the following equation relating mixe r drive horsepower to FGD wastewater flow.

SC Mixer Drive hp (hp) = 0.005 × Capacity Fact or × FGD Wastewater Treatment Flow GPM + 1.5 (6-153)

where:

Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted], and

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5).

The solids contact clarifier vendor indicated the scraper drive horsepower is 0.25 hp for the biggest clarifier. EPA assumed the scrape r drive horsepower was the same for all units.Chapter 6 - FGD Wastewater Cost Methodology

6-81 Solids Contact Clarifier Energy (kWh/day) = 2 × (SC Mixer Drive hp + Scraper Drive hp) × hp KW Factor × Operating Hours (6-154)

where:

SC Mixer Drive hp = Horsepower of th e solids contact clarifier mixer drive (see Equation 6-153), Scraper Drive hp = Horsepower of the so lids contact clarifier scraper drive, 0.25 hp, hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

Filter Press Energy Andritz Separation provided electricity requi rements for filter presses appropriate for three sludge flow rates. EPA developed Equati on 6-155 based on the data provided to predict electricity requirements based on the average plan t flow rate after equa lization in gallons per minute. Andritz Separation costed filter presse s assuming operation of 15 cycles per day where each cycle lasted 1.5 hours. Note that the quanti ty of filter presses is calculated in Section 6.1.6.6. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A51) for additional information.

Filter Press Energy (kWh/day) = Filter Press Qty × (0.047 × Sludge Factor × FGD Wastewater Treatment Flow GPM + 4.1937) × hp KW Fact or × FP Cycles Per Day × FP Hours Per Cycle (6-155)

where:

Filter Press Qty = Number of filter presses; based on the FGD Wastewater Treatment Flow GPM, (see Section 6.1.6.6), Sludge Factor = Factor to estimate the sludge generation rate based on the FGD Wastewater Treatment Flow GPM (see Section 6.1.5), 0.4,

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, FP Cycles Per Day = The number of filter press cycles operated per day, 15, and FP Hours Per Cycle = The number of hour s per filter press cycle, 1.5 hours.Chapter 6 - FGD Wastewater Cost Methodology

6-82 Sand Filters Energy The only major power requirement associated with sand filters is the motive air requirement of the process. It ranges from [Redact ed] standard cubic feet per minute (scfm) at a minimal pressure of [Redacted] psi. This air can be supplied by air comp ressor systems that are in the [Redacted] hp range. Note that the quant ity of sand filters is calculated in Section 6.1.6.7.
Sand Filter Energy (kWh/day) = Sand Filter Qty × Filter hp × hp KW Factor × Operating Hours (6-156)

where:

Sand Filter Qty = Number of sand filters; based on FGD Wastewater Treatment Flow GPM, (see Section 6.1.6.7), Filter hp = Horsepower of the air compressor system needed to fulfill the sand filter motive air requirements, [Redacted]. hp KW Factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, and Operating Hours = System operating hours per day, 24.

6.1.8 Sludge Disposal Cost
EPA determined dewatered sludge generation rates for chemical precipitation treatment by multiplying a flow-normalized dewatered sludge generation rate (expressed in tpd/gpm) by the plant FGD wastewater flow rate. The flow- normalized dewatered sludge generation rate was determined based on responses to Question D3-2 of the Steam Electric Survey specific to FGD wastewater chemical precipita tion treatment. EPA selected the median flow-normalized dewatered sludge generation rate, [Redacted] tons per day per gallon per minute of FGD wastewater flow. See the Supplemental Costs and Loadings Documentation (DCN SE01825.52) for additional information. EPA then calculate d the annual sludge generation using Equation 6-157.

Annual Sludge Generation (tons/yr) = Sludge Gene ration Rate × FGD Wastewater Treatment Flow GPM × 60 min/hr × 24 hr/day × 365 day/year (6-157)

where:

Sludge Generation Rate = Median sludge generation per FGD wastewater treated, in tons per day per gallon per minute of FGD wastewater flow, [Redacted], and

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5).Chapter 6 - FGD Wastewater Cost Methodology

6-83 Additionally, EPA calculated th e bulk density of the sludge based on the composition of the sludge for use in calculating costs for transp ortation and disposal of chemical precipitation sludge. EPA assumed that 50 percent of the sludge would be water, and the remaining 50 percent would be an equal mix of gypsum, hydrated lime, and limestone.

EPA calculated the bulk de nsity using Equation 6-158.
Sludge Bulk Density (lb/ft 3 ) = 0.5 × Water Density + 0.5 × (Gypsum Density + Hydrated Lime Density + Limestone Density)/3 (6-158)

where:

Water Density = The density of wa ter in pounds per cubic foot, 62.4,
Gypsum Density = The density of gypsum in pounds per cubic foot, 143.5,
Hydrated Lime Density = The density of hydrated lime in pounds per cubic foot, 30, and Limestone Density = The density of limestone in pounds per cubic foot, 87.

The resulting sludge bul k density is 74.6 lb/ft 3

.
Sections 5.3 and 5.4 discuss costs for the tran sportation and disposal of sludge from the chemical precipitation system.

6.1.9 Mercury Analyzer Cost Methodology

EPA estimated costs associated with installi ng and operating an an alyzer to determine mercury concentrations in the treated effluent stream of the FGD wastewater and landfill leachate treatment systems. Based on site visits, untreated FGD wastewater can contain elevated mercury concentrations based on a variety of different plant oper ating characteristics. A properly designed and operated BAT system should be ab le to accommodate these elevated mercury concentrations and remain in compliance with th e proposed ELGs. However, to ensure that the effluent discharged from the FGD wastewater system meet the proposed ELGs, EPA included costs for a mercury analyzer and extra equipm ent to analyze mercury in the discharge and recycle the discharge for further treatment if nece ssary. Using this equipment will allow plants to test the mercury in the effluent several time s a day (at most 200 samples per week) and be provided with immediate feedback on the efflue nt quality of the treated water to ensure compliance with the ELGs. This mercury analyzer is meant as a proces s control aid and to provide extra assurance that the sy stem is operating as designed. If the system is not operating as designed and wastewater is not in compliance, the plant can recycl e the treated water back to the equalization tank and adjust the system (i.e., a dd additional chemicals) to further treat the wastewater to meet the proposed ELGs. This section discusses the technology, population costed, and the specific costs associated with installing and operating the mercury analyzer.Chapter 6 - FGD Wastewater Cost Methodology

6-84 6.1.9.1 Technology Description
EPA included the costs for a mercury analyz er in the overall costs for the chemical precipitation system for FGD wastewater and landfill leachate to monitor the concentration of mercury in the treated effluent stream. Along wi th the analyzer, EPA included costs for a pump and length of piping to route treat ed effluent from the effluent tank back to the equalization tank at the beginning of the wastewater treatment system. 33 This approach will allow the plant to recycle any effluent that does not meet mercury effluent limits back through the treatment system. By monitoring the mercury effluent concentr ation, plants will be able to adjust chemical dosages and recycle flow to ensure effluent limits will not be exceeded.

6.1.9.2 Population Costed

EPA included the cost to insta ll and operate a mercury analyzer for all plants discharging FGD wastewater and landfill leachate. The plants incurring costs for a mercury analyzer are the same set of plants incurring compliance m onitoring costs associat ed with mercury.

6.1.9.3 Capital Cost Methodology
Capital costs associated with installing the mercury analy zer include the cost of the mercury analyzer, as well as the equipment needed to recycle off-specification effluent back to the beginning of the treatment system. This equipment includes a set of recycle pumps and a length of fiberglass-rei nforced plastic pipe.

Mercury Analyzer EPA assessed each plant an initia l capital cost to purchase th e mercury analyzer prior to the start-up of the chemical pr ecipitation system. Based on comm unication with Milestone, Inc, EPA estimates the cost of one mercury an alyzer to be $85,307 in 2010 dollars. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A67) for additional information.

Recycle Pump EPA costed two 100 percent capacity, skid-m ounted, horizontal centrifugal pumps to recycle treated effluent from the treated wast ewater tank to the equa lization tank. These pumps are modeled off the treated wastewater disc harge pumps found in one-stage chemical precipitation (see Section 6.1.6.1 and Equation 6-4).
Recycle Pump (2010$) = [0.0049 × (Capacity Fact or × FGD Wastewater Treatment Flow GPM) 2 + 8.2408 × (Capacity Factor × FGD Wastewater Treatment Flow GPM) + 7758.6] × Pump Freight Factor × Recycle Pump Qt y × (Cost Index 2010/Cost Index 2011) (6-159)

33 Typically, wastewater treatment system s are designed to include a pump and length of piping to route treated effluent from the effluent tank back to the equalization tank. Including this cost as part of the mercury analyzer cost estimate may be an overestimate.Chapter 6 - FGD Wastewater Cost Methodology

6-85 where:

Capacity Factor = Factor that acc ounts for design flow, [Redacted] (see Section 6.1.5),

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), Recycle Pump Qty = Number of treat ed wastewater recycle pumps, 2,
Pump Freight Factor = Fact or that accounts for freight cost as a percentage of purchase cost, 1.04 (S ee Section 6.1.6.1), Cost Index 2010 = 183.5, and

Cost Index 2011 = 185.

Recycle Piping EPA costed a length of fiberglass-reinforced plas tic pipe to span from the treated effluent tank back to the equalization tank. EPA used da ta from Question D2-7 of the Steam Electric Survey to determine the average footprint fo r an FGD wastewater treatment system. To conservatively estimate the piping distance, EPA a ssumed the total area to be a rectangle and that the piping would be run around the perimeter of the system from one corner to the corner diagonally opposite. Using this methodology, the av erage pipe length was determined to be 713 feet. EPA developed Equation 6-160 to calculate the cost of the pipi ng and adjusted the result to 2010 dollars using cost indices from RSMeans.

Piping Cost (2010$) = PipeCost × Distance × PipeFreightFactor × Cost Index2010/Cost Index 2011 (6-160)

where:

PipeCost = Cost of the fiberglass- reinforced plastic pipe in dollars per foot; see table below for values, Distance = 713 feet,
PipeFreightFactor = Factor that accounts for freight cost as a percentage of purchase cost, 1.002, Cost Index 2010 = 183.5, and

Cost Index 2011 = 185.Chapter 6 - FGD Wastewater Cost Methodology

6-86 FGD Wastewater Flow Range (gpm) Pipe Cost ($/foot) 0-125 2.09 125-250 2.95 250-450 3.96 450-1,050 6.05 1,050-1,850 8.03 1,850-2,900 10.05 2,900-4,150 12.02 Source: FRPpiping.com.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A67) for additional information.

6.1.9.4 O&M Cost Methodology
O&M costs associated with the mercury analy zer include the cost of consumables needed to operate the analyzer, which in clude catalyst tubes and an amalga mator, as well as the cost of electricity to operate the recycle pumps.

Mercury Analyzer Consumable Costs Based on discussions with Milestone, Inc, a vendor of the mercury analyzer, EPA estimates that each plant will be able to analyze approximately 200 samples per week. Based on data from the vendor, this sampling frequency w ould result in replacing consumables once every quarter, or four times per year. EPA used Equati on 6-161 to calculate the y early cost associated with consumables for the mercury analyzer. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A67) for additional information.

Cost of Consumables (2010$/year) = Consumable Unit Cost × Consumable Frequency × (Cost Index 2010/Cost Index 2011) (6-161)

where:

Consumable Unit Cost = $600 in 2011 dollars,
Consumable Frequency = Four times per year,

Cost Index 2010 = 183.5, and

Cost Index 2011 = 185.

Recycle Pump Electricity Cost EPA assumed that only one recycle pump woul d be operating at any one time. Electricity costs for the recycle pump are modeled after the electricity require ments of the treated wastewater discharge pump for one-stage chemical precipitation (see Section 6.1.7.5 and Equation 6-132). Electricity requirement s are calculated using Equation 6-162.Chapter 6 - FGD Wastewater Cost Methodology

6-87 Recycle Pumps Elec (kWh/day) = (0.01820151 × Capac ity Factor × FGD Wastewater Treatment Flow GPM + 0.6031) × hp KW factor × Operating Hours (6-162)

where:

Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted],

FGD Wastewater Treatment Flow GPM = FGD wastewater treatment flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), hp KW factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp (see Section 6.1.7.5), and Operating Hours = System operating hours per day, 24.

Electricity costs are calculated by multiplying the total electricity requirement in kWh by the average national energy cost of 4.05 cents per kWh (2009$) as determined based on data reported by the U.S. Energy Information Admini stration of the Electric Power Annual 2009 for fossil plants in the United States[U.S. DOE, 2011]. Equation 6-162 calculates the cost in 2009 dollars is indexed to 2010 dollars using values from RSMeans [RS Means, 2011].

6.1.9.5 Recurring Cost Methodology
Recurring costs refer to a cost incurred by the plant at some interval other than annually. While the mercury analyzer will be purchased as a capital cost element, before start-up of the wastewater treatment system, the analyzer will ne ed to be replaced at six year intervals. EPA estimates the cost of one mercury analyzer to be $85,307 in 2010 dollars. See the Supplemental Costs and Loadings Documentation (DCN SE01825.A67) for additional information.

6.1.10 Compliance Monitoring Cost

Section 5.2 discusses costs fo r compliance monitoring of ch emical precipitation system effluent.

6.1.11 Impoundment Operation Cost

Section 5.5 discusses cost savi ngs associated with closi ng combustion re sidual surface impoundments.

6.1.12 FGD System Outage Costs
EPA considered the impact of a plant outage re quired to install the chemical precipitation treatment system. Based on an evaluation of ve ndor and survey information, EPA determined that connecting the wastewater treatment system to the existing FGD system can be completed during regularly scheduled outages. The entire tr eatment system can be installed prior to a scheduled outage, and then the necessary tie-in can occur during a regularly scheduled outage.Chapter 6 - FGD Wastewater Cost Methodology

6-88 Therefore, there are no costs for plant outages during installation of th e chemical precipitation treatment system.

6.1.13 Results and Summary of Costs

As described in Section 2.1.4, EPA’s cost m odel generated plant-le vel compliance costs for the one-stage chemical precipitation tec hnology option. The cost output generated by the model includes a breakout of specific capital and O&M cost elements, including equipment costs, installation costs, operati ng labor, maintenance labor, and energy costs. The output also includes costs for the common cost elements desc ribed in Chapter 5. A list of the plant-level costs for the chemical precipitation tec hnology option is included in the appendix.

6.2 B IOLOGICAL T REATMENT
EPA estimated capital and O&M costs asso ciated with instal ling a fixed-film anoxic/anaerobic biological treatment system to tr eat FGD wastewater. This system is designed to follow a chemical precipitation system (S ection 6.1) that includes a biological treatment system feed tank (Section 6.1.6.2). Th e primary purpose of the biologi cal treatment system is to remove selenium from the FGD wastewater; ho wever, this technology is also effective in removing nitrates, sulfates, and other metals like mercury. All costs were estimated in 2010 dollars.
Throughout this section “FGD wast ewater treatment flow” refe rs to the normalized FGD wastewater flow rate following wa stewater equalization in the ch emical precipitation system in gallons per minute. This flow rate is the FGD wastewater flow (gpd) co nverted to gallons per minute assuming 24 hour operation of the wastewat er treatment system (see Section 6.1.5).

6.2.1 Technology Description
EPA selected an anoxic/anaerobic biological system as the biological treatment design basis because of the system’s proven selenium removals of greater than 99 percent in FGD wastewater. Figure 6-3 (located at the end of this chapter) show s a typical two-stage biological treatment system for treating FGD wastewater. Th e system uses up-flow, fixed-film granular activated carbon (GAC) bed bioreact ors, inoculated with a proprie tary, site-specific mixture of bacterial cultures, through which the FGD wastewater passes. The bacterial cultures, maintained in an anoxic/anaerobic reductive en vironment, reduce dissolved sele nium species (i.e., selenate and selenite) to particulate elementa l selenium [Sonstegard, et al., 2008]. 34 This reaction is illustrated by the following equation:

SeO 4 2- + Organic Carbon → SeO 3 2- + Organic Carbon → Se 0 + CO 2 +H 2 O

Denitrifying organisms within the bioreactors reduce nitrate to nitrogen gas, which is released to the atmosphere as described by the equation below. A nutrient blend is added to the FGD wastewater to provide a carbon source for the denitrifying organisms.

34 Oxidation reduction potential (ORP) drops across the system, ranging from +220 to +300 mV in the influent to - 200 to -300 mV in the effluent [Sonstegard, et al., 2008].Chapter 6 - FGD Wastewater Cost Methodology

6-89 NO 3 - + Organic Carbon → NO 2 - + Organic Carbon → N 2 + CO 2 + H 2 O

Reactor conditions also promote sulfide produc tion, which results in sulfide precipitation of trace metals such as mercury, zinc, copper, ni ckel, lead, and others as shown by the following equation:

H 2 S + M 2 → MS + 2H +

where:

M = Metal [Sonstegard, et al., 2008].

Elemental selenium and other precipitated metals accumulate within the biomatrix until the system is backwashed. During backwash, higher backwash flow fluidi zes the bioreactor bed, releasing trapped solids, precipitated metals, a nd excess biomass into the backwash wastewater [Sonstegard, et al., 2008]. The backwash wastewater is then returned to the FGD wastewater chemical precipitation system, where the solids and precipitated meta ls are separated and removed with the chemical precipitation sludge.

To estimate costs for this tr eatment technology, EPA first evaluated data from site visits, sampling episodes, and long-term monitoring data provided by industry to determine the average effluent quality of FGD wastewat er after treatment with the BA T chemical precipitation system, as described in Section 6.1. These data are pres ented in Table 6-1 (locat ed at the end of the chapter). EPA provided these data to a biologi cal treatment system vendor, who then developed the specific anoxic/anaerobic bi ological treatment system design and system-level costs presented in this report based on their evalua tion of these wastewater characteristics. The biological treatment system design developed by the vendor consists of a series of two bioreactors operating in parallel trains. The number of trains and the size of the bioreactors are dependent on plant-specific FGD wastewater flow rate. For flow rates greater than 40 gpm, the vendor provided costs for customized field-erected biological treatment systems. For flow rates less than 40 gpm, the vendor provided costs for a low-flow, pre-fabri cated modular reactor.
EPA costed the biological treatment system to be backwashed once a month with a vendor-recommended operating protocol of rotating backwash cycles weekly for the individual bioreactors. Staggering the backwash cycles eases handling and minimizes instantaneous wastewater flows through the system. Alt hough backwashing occurs weekly, backwash wastewater is held in a tank to allow it to be slowly and continuously returned to the FGD wastewater chemical precipita tion system. Equation 6-163 describes the estimated backwash flow generated, assuming the FGD wastew ater characteristics in Table 6-1.
Backwash Flow (gpm) = [Redacted] × FGD Wastewater Treatment Flow GPM (6-163)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow in gpm normalized for 24 hpd operation (see Section 6.1.5).Chapter 6 - FGD Wastewater Cost Methodology

6-90 See the Supplemental Costs and Loadings Documentation (DCN SE01825.A57) for additional information on the derivation of Equation 6-159.
The biological treatment system used to estima te costs operates at an optimal temperature of 95°F and a maximum temperature of 105°F. Based on site visits, sampling, and long-term monitoring data, FGD wastewater temperatures can be greater th an 105°F, especially during the warmer seasons, in certain geographic locations, and may require cooling prior to entering the biological treatment system. Ther efore, EPA included costs for a heat exchanger for certain southern plants determined to require cooli ng of FGD wastewater (s ee Section 6.2.5.2) [ERG, 2013; See Appendix 57].
Major components of the design basis for the biological treatment system include:

 Two bioreator tanks (i.e., two r eactors in series per train);

 Nutrient feed system and storage;

 Backwash system and backwash wastewater tank; and

 Heat exchangers (for certain southern plants).

6.2.2 Population Costed

Based on information from the Steam El ectric Survey, EPA identified 117 plants discharging FGD wastewater. 35 EPA estimated costs for these 117 plants to install a one-stage chemical precipitation system with biological tr eatment to treat FGD wastewater. The population costed is the same as that described for FGD wastewater chemical precipitation. EPA identified plants that have announced plans to retire generating units prior to December 31, 2014 as described in Section 4.4.1. There are no conversion costs for plant that are already planned to retire prior to implementation of the ELGs.

6.2.3 Credit for Biological Treatment in Place
EPA evaluated plant responses to the Steam Electric Survey to determine whether biological treatment for selenium removal is cu rrently in place to treat FGD wastewater. As appropriate, these plants were given credit for having “treatme nt in place” to ensure that incremental costs associated with compliance with the tech nology options are accurately assessed.
EPA assessed treatment in place credit for bot h portions of the treatment system, the chemical precipitation pretreatme nt portion and the biological tr eatment portion of the treatment system. Section 6.1.3 describes the treatment in pl ace credit given to plants currently operating chemical precipitation treatment systems. Based on a review of responses to the Steam Electric Survey, EPA identified a total of five plan ts operating the biologi cal treatment technology included in the basis for the biological treatment technology op tion for treating FGD

35 When the group of plants excluding oil-fired units and uni ts with a capacity of 50 MW or less is evaluated, the population of plants discharging FGD wastewater includes 116 plants.Chapter 6 - FGD Wastewater Cost Methodology

6-91 wastewater. 36 All five plants received full treatment- in-place credit for the biological treatment system. Only two of these plants operate BAT systems that include a chemical precipitation system followed by the anoxic/anaerobic biologi cal treatment system targeting selenium removal. These two BAT plants also received full treatment-in-place credit for a one-stage chemical precipitation system. These BAT plants with complete one-stage chemical precipitation systems with biological treatment incur only co mpliance monitoring costs and the costs for a mercury analyzer (see Section 6.1.9) for the technology option including both chemical precipitation and biological tr eatment. The remaining three plants incur some level of incremental costs to either modify an existing chemical precipitation sy stem to meet BAT or install a complete chemical precipitation system.

6.2.4 Input Table
The biological treatment cost module uses data from the “FGD Input Table,” discussed in Section 6.1.4. One additional data field is incl uded in the “FGD Input Table” for use in the biological treatment cost calcu lations, which is a ‘Heat_Excha nger_Cost’ flag. This flag identifies all plants that will be costed for a heat exchanger, as described in Section 6.2.5.2.
A copy of the “FGD Input Table” used in the biological treatment module is included in the appendix.

6.2.5 Capital Cost Methodology
Total capital costs were calculated for each plant as the sum of purchased equipment costs, installation costs, a nd plant engin eering costs.
Total Capital Costs = Purchased Equipment Cost + Purchased Equipment Installation Cost + Plant Overhead Engineering Cost

EPA assumed zero land costs ba sed on responses to the Steam Electric Survey indicating that plants incurred zero or very little expense (approximately 1 percent of purchased equipment costs) associated with acquiri ng land for FGD wastewater treatm ent systems. The costs provided by the biological treatment system vendor alread y include costs associat ed with other capital investments such as buildings, engineering and construction. As a result, EPA did not include additional incremental costs associated with these cost categories.
ERG calculated purchased equipment capital co sts for each plant as the sum of purchased equipment costs for the bioreactor s and associated equipment, the heat exchanger (for applicable plants), and the backwash recycle pump. As a ll equipment costs were provided by vendors in 2011 dollars, EPA adjusted the cost basis to 2010 dollars using the 2010 and 2011 RSMeans Historical Cost Indices (183.5 a nd 185, respectively) [RSMeans, 2011].

36 Through additional information collection during the ru lemaking, EPA identified a sixth plant that operates a suspended-growth biological treatment system that targets the removal of selenium. This plant is incurring biological treatment costs for the bi ological treatment technology option b ecause EPA has no performance data to show that the system can meet the proposed selenium limits.Chapter 6 - FGD Wastewater Cost Methodology

6-92 See the Supplemental Costs and Loadings Documentation (DCN SE01825.A57) for additional information on the derivation of the equa tions used to estimate the plant-level capital
cost.

6.2.5.1 Purchased Equipment Costs: Biological Treatment System Cost
The vendor provided cost curves and correspon ding cost equations to estimate the plantlevel costs for the biological treatment system. These cost equations include the following cost components:

 Two-stage bioreactor system (i.e., two reactors in series per train) with a 10-hour residence time for the system, operating 24 hours per day and 365 days per year. System-level costs include the followi ng purchased equipment and associated ancillary equipment:

- All process pumps, valves, and instruments,

- Process and instrument compresse d air system, valves, and lines,

- Nutrient system, storage tank, and pumping,

- Process piping and supports,

- Concrete bioreactor tank walls and fl oor with epoxy-coat ed rebar and epoxy flake-glass coating,

- Concrete backwash supply and backwash wastewater tank walls and floor with epoxy-coated rebar and epoxy flake-glass coating,

- Concrete process and utility sump with pumps,

- Support steel, access stairs, walkways, grating, handrails,

 Process equipment building with HVAC (conc rete floor, block structure with steel roof);

 Engineering, commissioning, and project mana gement labor (the project structure is executed by a consortium between the vendor and contractor with a balance of plant engineering as a s ub-contractor); and

 Construction equipment, materials, and labor.
The biological treatment system cost equatio ns apply to two different FGD wastewater treatment flow ranges: greater th an or equal to 40 gpm (custo mized field-erected system) and less than 40 gpm (pre-fabri cated modular reactor).

For FGD Wastewater Treatment Flow GP M < 40 gpm EPA used Equation 6-164.
Biological Treatment Equipment Cost (2011$) = [Redacted] (6-164)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater treatment flow in gpm normalized for 24 hpd operation (see Section 6.1.5), andChapter 6 - FGD Wastewater Cost Methodology

6-93 Backwash Flow = The backwash flow rate in gallons per minute (see Section 6.2.1and Equation 6-163).

For FGD Wastewater Treatment Flow GPM ≥ 40 gpm EPA used Equation 6-165.
Biological Treatment Equipment Cost (2011$) = [Redacted] (6-165)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and Backwash Flow = The backwash flow rate in gallons per minute (see Section 6.2.1 and Equation 6-163).

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A57) for additional information on the deri vation of Equations 6-164 and 6-165.

6.2.5.2 Purchased Equipment Costs: Heat Exchanger Cost
EPA estimated heat exchanger and related cost s for facilities with in set latitudinal and longitudinal coordinates. The coordinates were determined based on average ambient temperature data. EPA examined climate maps from the National Oceanic and Atmospheric Administration’s (NOAA’s) National Climate Da ta Center for average monthly maximum temperatures for the nation. Figure 6-4 (located at the end of this chapter) illustrates the national mean maximum daily temperatures for the month of July. 37 Specifically, the red and dark red regions indicate average July temperatures of 90°F or greater. Based on these findings, EPA determined the following latitudinal and long itudinal coordinates encompassing a significant portion of the red shaded regions (also illustrated in shaded blue in Figure 6-5 located at the end of this chapter):

 South of 35°0 ́0 ́ ́N; or

 Between 35°0 ́0 ́ ́N and 40°37 ́30 ́ ́N and west of 108°0 ́0 ́ ́W; or

 Between 35°0 ́0 ́ ́N and 40°37 ́30 ́ ́N a nd between 90°0 ́0 ́ ́W and 105°0 ́0 ́ ́W.
EPA costed plants located within these coor dinates (39 plants) for heat exchangers in conjunction with the biological treatment system. Those plants flagged as requiring a heat exchanger are identified in the “Heat Exchanger Input Table.” A copy of “Heat Exchanger Input Table” used in the biological treatmen t module is included in the appendix.
Due to potentially high chlorides concentra tions in FGD wastewater, several vendors, including WCR, Inc., Tranter, and Funke, recommended titanium plate and frame heat

37 EPA examined similar maps for June, August, and September; however, July’s maximum temperatures were farthest reaching geographically and assumed to best capture geographical regions expected to experience ambient temperatures that may cause FGD scrubb er purge wastewater temperatures to require cooling prior to biological treatment.Chapter 6 - FGD Wastewater Cost Methodology

6-94 exchangers. EPA based heat exchanger cost equa tions on cost estimates provided by these heat exchanger vendors for a carbon steel frame heat ex changer consisting of 0.5 millimeter titanium plates. EPA included costs for one titanium plate and frame heat exchanger and two cooling water pumps. Cooling water cost equations are based on quotes by Sulzer for a single-stage process pump.
EPA estimated cooling water requirements using heat transfer Equations 6-166 and 6-167.

Q = mC p Δ T (6-166)

Q h = Q c (6-167)

where:

Q = Amount of heat to dissip ate from FGD wastewater by the cooling water, m = Mass flow rate of the FGD wastewater or cooling water,
C p = Specific heat capacity of the FGD wastewater or cooling water,
Δ T = Temperature difference between the inlet and outlet,

Q h = Amount of heat dissipated from the FGD wastewater (hot material), and Q c = Amount of heat absorbed by the cooling water (cold material).

EPA calculated the cooling water flow rate required to cool the FGD wastewater based on the following assumptions:

 FGD Wastewater

- Temperature drop from T h1 =120°F to T h2 = 95°F,

- Specific heat capacity, C ph , of 0.85 Btu/lb-F, and

- Density, ρ h , 9.163 lb/gallon.

 Cooling Water

- Temperature increase from T c1 =70 °F to T c2 =85°F,

- Specific heat capacity, C pc , of 1 Btu/lb-F, and

- Density, ρ c , of 8.33 lb/gallon.
Using these assumptions, EPA derived Equation 6-168 to estimate the cooling water flow rate as a function of FGD wastewater flow.Chapter 6 - FGD Wastewater Cost Methodology

6-95 Cooling Water Flow Rate (gpm) = FGD Wastewater Treatment Flow GPM × ((C ph × (T h1 – T h2 )

× ρ h ) / (C pc × (T c2 – T c1 ) × ρ c )) (6-168)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5),

C ph = Specific heat capacity of the FGD wastewater,

C pc = Specific heat capacity of the cooling water,

T h1 = Initial temperature of the FGD wastewater,

T h2 = Final temperature of the FGD wastewater,

T c1 = Initial temperature of the cooling water,

T c2 = Final temperature of the cooling water,

ρ h = The density of the FGD wastewater, and

ρ c = The density of the cooling water.

EPA estimated the capital cost for the heat exchanger and cooling water pumps, applicable to each of the 39 plants identified as requiring FGD wastewat er cooling. EPA also estimated freight costs for the cooling water pum ps based on weight and a shipping distance of approximately 500 miles using quotes from Frei ghtCenter.com [ERG, 20 13; See Appendix 58]. Freight costs were equal to appr oximately 3 to 4 percen t of purchase costs (i.e., Freight Factor = 1.04). EPA also estimated the freight costs for th e heat exchanger based on weights provided by the vendor. Heat exchanger freight costs were equal to approximately 5 percent of the purchased cost (HE_Freight_Factor =1.05).
EPA calculated heat exchanger capital cost using Equation 6-169.
HE Equipment Cost (2011$) = (0.0059 × (FGD Wa stewater Treatment Flow GPM + Backwash

Flow) 2 + 11.304 × (FGD Wastewater Treatment Flow GPM + Backwash Flow) + 2643.6) × HE_Freight_Factor (6-169)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), Backwash Flow = The backwash flow rate in gallons per minute (see Section 6.2.1 and Equation 6-163), and HE_Freight_Factor = Factor that acc ounts for freight cost for the heat exchanger as a percentage of purchase cost, 1.05.Chapter 6 - FGD Wastewater Cost Methodology

6-96 See the Supplemental Costs and Loadings Documentation (DCN SE01825.A58) for additional information on the derivation of Equation 6-169.
EPA calculated cooling water pumps capital cost using Equation 6-170.
Cooling Water Pump Cost (2011$) = (-0.0017 × (Cooling Water Flow) 2 + 9.9408 × (Cooling Water Flow) + 3392.8) × Pump Fr eight Factor × CW_Pump Qty) (6-170)

where:

Cooling Water Flow = The cooling wate r flow rate required in gallons per minute, (see Equation 6-168), Pump Freight Factor = Factor that accounts for freight cost as a percentage of purchase cost (see Section 6.1.5), 1.04, and CW_Pump Qty = Number of cooling water pumps, 2.

6.2.5.3 Purchased Equipment Costs: Ba ckwash Recycle Pumps Cost
EPA estimated costs for two 100 percent cap acity skid-mounted, horizontal centrifugal backwash recycle pumps to transfer the backwa sh wastewater from the backwash wastewater tank to the equalization tank in the chemical prec ipitation system. Cost estimates were provided by Weir Minerals and include the cost for pumps, accessories, motors and V drives. EPA estimated pump freight costs using the same fr eight factor as for the cooling water pumps.

Backwash Recycle Pump Cost ( 2011$) = (0.0049 × (Backwash Flow) 2 + 8.2408 × (Backwash Flow) + 7758.6) × Pump Freight Factor × BW_Pump Qty (6-171)

where:

Backwash Flow = The backwash flow rate in gallons per minute (see Section 6.2.1 and Equation 6-163), Pump Freight Factor = Factor that accounts for freight cost as a percentage of purchase cost (see Section 6.1.5), 1.04, and BW_Pump Qty = Number of backwash recycle pumps, 2.

6.2.5.4 Purchased Equipment Installation Cost
EPA estimated installation capital costs for th e biological treatment system for each plant using two different installation cost factors. The first factor (Bioreactor Installation Factor) was provided by the vendor and is specific to instal lation of the biological treatment system. The second factor (Plant Installation Factor) was dete rmined based on responses to the Steam Electric Survey and applies to installati on of the heat exchanger, cooling water pumps, and backwash recycle pumps.Chapter 6 - FGD Wastewater Cost Methodology

6-97 Using these installation factors, EPA estimated biological treatment system installation capital costs for each plant using Equation 6- 172. As vendors provided all equipment costs in 2011 dollars, EPA adjusted the cost basis to 2010 dollars using the 2010 and 2011 RSMeans Historical Cost Indices (183.5 a nd 185, respectively) [RSMeans, 2011].
Installation Capital Cost (2010$) = [(Bioreactor Installation Factor × Biological Treatment Equipment Cost) + (Plant Installation Factor × {HE Equipment Cost + Cooling Water Pump Cost + Backwash Recycle Pump Cost })] × (2010 Cost Index/2011 Cost Index) (6-172)

where:

Bioreactor Installation Factor = Factor that accounts for co st to install the biological treatment system as a percentage of the biological treatment equipment cost, Biological Treatment Equipment Cost = Cost to purchase the equipment associated with the biological treatment system in 2011 dollars,
Plant Installation Factor = F actor that accounts for cost to install heat exchanger, cooling water pump, and backwash recycle pump as a percentage of the purchased equipment cost, HE Equipment Cost = Capital cost a ssociated with purchasing the heat exchanger in 2011 dollars, Cooling Water Pump Cost = Capital cost associated with purchasing the cooling water pump in 2011 dollars, Backwash Recycle Pump Cost = Capital cost associated w ith purchasing the backwash recycle pump in 2011 dollars, 2010 Cost Index = 183.5, and

2011 Cost Index = 185.

Bioreactor Installation Factor Based on information provided by the biologi cal treatment system vendor the bioreactor system installation cost factors vary by F GD wastewater flow ra nge as listed below:

For FGD wastewater treatment flow < 40 gpm EPA used Equation 6-173.

Bioreactor Installation Factor = [Redacted] (6-173)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and Backwash Flow = The backwash flow rate in gallons per minute (see Section 6.2.1 and Equation 6-163).Chapter 6 - FGD Wastewater Cost Methodology

6-98 For FGD wastewater treatment fl ows from greater than or equal to 40 gpm to less than or equal to 1,000 gpm EPA used Equation 6-174.

Bioreactor Installation Factor = [Redacted] (6-174)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and Backwash Flow = The backwash flow rate in gallons per minute (see Section 6.2.1 and Equation 6-159).

For FGD wastewater treatment flow s > 1,000 gpm EPA used Equation 6-175.

Bioreactor Installation Factor = [Redacted] (6-175)

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A57) for additional information on the deriva tion of Equations 6-173 through 6-175.

Plant Installation Factor EPA used the installation factor of [Red acted] developed for chemical precipitation treatment of FGD wastew ater (see Section 6.1.6.8).

6.2.5.5 Plant Overhead Engineering Cost
The equipment capital cost equa tion does not include plant ov erhead engineering costs. Based on responses to the Steam Electric Survey for plants operating chemical precipitation or biological treatment of FGD wast ewater, plant engineering overh ead costs ranged from 1 to 10 percent of the equipment costs (median = [R edacted]) [EPA, 2013; See Appendix 59]. EPA estimated plant overhead engineering cost as a fraction of the total purchased equipment cost using Equation 6-176.

Plant Overhead Engineering Cost (2010$) = [Redacted] × Biological Treatment Equipment Capital Cost (6-176)

Equipment Capital Cost (2010$) = [Biological Tr eatment Equipment Cost + HE Equipment Cost + Cooling Water Pump Cost + Backwash Recycle Pump Cost] × (2010 Cost Index/2011 Cost Index) (6-177)

where:

Biological Treatment Equipment Cost = Cost to purchase the equipment associated with the biological treatment system in 2011 dollars, HE Equipment Cost = Capital cost a ssociated with purchasing the heatChapter 6 - FGD Wastewater Cost Methodology

6-99 exchanger in 2011 dollars,

Cooling Water Pump Cost = Capital cost associated with purchasing the cooling water pump in 2011 dollars, Backwash Recycle Pump Cost = Capital cost associated w ith purchasing the backwash recycle pump in 2011 dollars, 2010 Cost Index = 183.5, and

2011 Cost Index = 185.

6.2.6 O&M Cost Methodology
O&M costs associated with biological treat ment for each plant include the following:

 Operating labor cost,

 Maintenance labor cost,

 Maintenance materials cost,

 Chemical purchase cost,

 Energy cost,

 Sludge disposal cost, and

 Compliance monitoring cost.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A57 and SE01825.A60) for additional informa tion on the derivation of the e quations used to estimate the plant-level O&M cost for the biological treatment system.

6.2.6.1 Operating Labor Cost
The biological treatment system vendor provi ded a breakdown of tasks and labor required to operate and maintain the biological treatment system. For these data, EPA determined that 0.4375 full-time equivalent (FTE) workers are requi red for system operati on on all shifts [ERG, 2013; See Appendix 57]. EPA determined an operat ing labor rate of [Redacted] (2010$) based on the median operating labor rate reported in re sponse to Question D6-2 of the Steam Electric Survey by plants that operate FGD wastewater chemical precipitation treatment (with and without subsequent bi ological treatment). 38 Finally, EPA calculated operating labor costs for each plant by converting the number of FTE workers to annual number of hours worked, and then multiplying by the operating labor rate.

Operating Labor Cost (2010$/yr) = Operating Labor Rate × Number of Workers × 24 hr/day × 365 day/yr (6-178)

38 The median FGD wastewater treatment operator labor rate based on survey data is in 2009$. EPA will index the value appropriately with cost index da ta from RS Means for the final rule.Chapter 6 - FGD Wastewater Cost Methodology

6-100 where:

Operating Labor Rate = The median F GD wastewater treatment operator labor rate as reported in the Steam Electric Survey, [Redacted] (2010$), 38 and
Number of Workers = Number of FTEs associated with operating activities, 0.4375 .

6.2.6.2 Maintenance Labor Cost
The biological treatment system vendor provi ded a breakdown of tasks and labor required to operate and maintain the biological treatment system. For these data, EPA determined that 0.0625 FTE workers are required for system ma intenance on all shifts [ERG, 2013; See Appendix 57]. EPA determined a maintenance la bor rate of [Redacted] (2010$) based on the median maintenance labor rate reported in re sponse to Question D6-2 of the Steam Electric Survey by plants that operate FGD wastewater chemical precipitation treatment (with and without subsequent biological treatment). Finally, EPA calculate d maintenance labor costs for each plant by converting the number of FTE workers to annual number of hours worked, and then multiplying by the maintenance labor rate.
Maintenance Labor Cost (2010$/yr) = Maintena nce Labor Rate × Number of Workers × 24 hr/day × 365 day/yr (6-179)

where:

Maintenance Labor Rate = The median FGD wastewater treatment maintenance labor rate as reported in the Steam Electric Survey, [Redacted] (2010$), and
Number of Workers = Number of FTEs associated with maintenance activities, 0.0625 FTE.

6.2.6.3 Maintenance Materials Cost
EPA developed Equation 6-180 to estimate the maintenance materials cost based on an evaluation of O&M costs reported in response to Question D6-2 of the Steam Electric Survey by plants that operate FGD wastewater chemi cal precipitation treatment (with and without subsequent biological treatment ) [ERG, 2013; See Appendix 60].
Maintenance Material Cost (2010$/yr) = [Redacted] × (Energy Cost + Chemical Purchase Cost + Operating Labor Cost + Maintenance Labor Cost) (6-180)

6.2.6.4 Chemical Purchase Cost
The biological treatment system vendor calcu lated the required nutrient dosage of [Redacted]. The vendor also provided an averag e nutrient cost of [Redacted]. EPA estimated nutrient purchase cost by multiplying the nutrien t dosage rate by the FGD wastewater treatmentChapter 6 - FGD Wastewater Cost Methodology

6-101 flow rate and the nutrient cost [ERG, 2013; See Appendix 57]. As the vendor provided the nutrient cost in 2011 dollars, EPA adjusted the cost basis to 2010 dolla rs using the 2010 and 2011 RSMeans Historical Cost Indices ( 183.5 and 185, respectively) [RSMeans, 2011].
Chemical Purchase Cost (2010$/yr) = Nutrient Cost × Nutrient Dosage × FGD Wastewater Treatment Flow GPM × 60 min/hr × 24 hr/day × 365 day/yr × (2010 Co st Index/2011 Cost Index) (6-181)

where:

Nutrient Cost = Average nutrient cost, [Redacted],
Nutrient Dosage = Amount of nutrient s required per 1,00 0 gallons of FGD wastewater [Redacted],

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), 2010 Cost Index = 183.5, and

2011 Cost Index = 185.

6.2.6.5 Energy Cost
EPA determined overall biological treatme nt energy consumption (in kWh/yr) by calculating and summing the annual power consum ption for each piece of equipment. EPA assumed continuous operation of all equipment. To calculate energy costs, EPA then multiplied the total annual energy requirement by the nation al energy cost of 4.05 cents per kWh (2009$) as determined based on data reported by the U.S. Energy information Administration in Table 8.2 of the Electric Power Annual 2009 for fossil plants in the United States [U.S. DOE, 2011]. As the energy cost was provided in 2009 dollars, EP A adjusted the cost basis to 2010 dollars using the 2009 and 2010 RSMeans Historical Cost I ndices (180.1 and 183.5, respectively) [RSMeans, 2011].
Energy Cost (2010$/yr) = National Energy Cost × [Biological Treatment System Energy Consumption + BW Pump Energy Consumption + CW Pump Energy Consumption] × (2010 Cost Index/2009 Cost Index) (6-182)

where:

National Energy Cost = $0.0405/kWh (2009$),
Biological Treatment System Energy Consumption = Energy consumption for the biological treatment system, kWh/yr,

BW Pump Energy Consumption = Energy consumption for backwash recycle pumps, kWh/yr,Chapter 6 - FGD Wastewater Cost Methodology

6-102 CW Pump Energy Consumption = Energy consumption for cooling water pumps, kWh/yr,

2009 Cost Index = 180.1, and

2010 Cost Index = 183.5.

For the purpose of estimating non-water qu ality environmental impacts, EPA also converted energy consumption in kWh/yr to energy load in MW using Equation 6-183.
Energy Load (MW) = [Biological Treatment System Energy Consumption + BW Pump Energy Consumption + CW Pump Energy Consumption] / (24 hpd × 365 dpy) × 1 MW / 1000 kW (6-183)

where:

Biological Treatment System Energy Consumption = Energy consumption for bi ological treatment system, kWh/yr,

BW Pump Energy Consumption = Energy consumption for backwash recycle pumps, kWh/yr, CW Pump Energy Consumption = Energy consumption for cooling water pumps, kWh/yr,

Biological Treatment System Energy The biological treatment system vendor pr ovided the system en ergy requirement of 0.00036 kWh/gallon FGD wastewater treated [ERG , 2013; See Appendix 57]. EPA calculated the annual biological treatment system energy consumption using Equation 6-184.

Biological Treatment System Energy Consumpti on (kWh/yr) = Biological System Requirement × (FGD Wastewater Treatment Flow GPM + B ackwash Flow) × 60 min/hr × 24 hr/day × 365 day/yr (6-184)

where:

Biological System Requirement = Biological treatment system energy requirement, 0.00036 kWh/gallon FGD wastewater,

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), and Backwash Flow = The backwash flow rate in gallons per minute (see Section 6.2.1 and Equation 6-163).Chapter 6 - FGD Wastewater Cost Methodology

6-103 Pump Energy Pump electricity consumption is based on the horsepower of each pump motor. EPA converted horsepower to kilowatts and calcula ted kilowatt-hours assuming 24 hour operation. As pump sets of two were costed for redundancy, pumps placed in standby were not considered in calculating electricity requirements.
Based on data from the equipment vendor, backwashing occurs on a weekly basis as described in Section 6.2.1. To be conservative, EPA assumed that the backwash recycle pumps would operate continuously in some capacity, either to move backwash from the bioreactors to the backwash tank or to transfer the backwash from the tank to the chemical precipitation treatment system.
BW Pump Energy Consumption (kWh/yr) = (0.0182 × Backwash Flow + 0.6031) × hpKWfactor× BW OpPump Qty × 60 mi n/hr × 24 hr/day × 365 day/yr (6-185)

where:

Backwash Flow = The backwash flow rate in gallons per minute (see Section 6.2.1 and Equation 6-163), hpKWfactor = 0.7456 KW/hp (to convert horsepower to kilowatts), and BW OpPump Qty = Number of b ackwash recycle pumps normally operating, 1.

Based on operations at facilities with exis ting heat exchangers prior to biological treatment, heat exchangers are likely to be operated for only a portion of the year. Accordingly, EPA assumed that heat exchangers and their a ssociated cooling water pumps would be operated six months of the year (an overestimate of th e amount of time the heat exchanger would be needed based on available data).
CW Pump Energy Consumption (kWh/yr) = (0.0165 × (Cooling Water Flow) + 1.9854) × hpKWfactor × CW OpPump Qty × 60 min/ hr × 24 hr/day × Operating Days (6-186)

where:

Cooling Water Flow = Cooling water fl ow rate in gallons per minute (see Section 6.2.5.2 and Equation 6-168), hpKWfactor = 0.7456 KW/hp (to convert horsepower to kilowatts),
CW OpPump Qty = Number of coo ling water pumps normally operating, 1, and Operating Days = Number of days h eat exchanger will be operating, 183 days/yr.Chapter 6 - FGD Wastewater Cost Methodology

6-104 Heat Exchanger Energy As cooling water and FGD wast ewater are circulated thro ugh the heat exchanger via pumps, the heat exchanger itself does not consume energy.

6.2.7 Sludge Disposal Cost
Sludge generated by the biological treatment system is contained within the backwash wastewater, which is recycled to the FGD wastewater chemical precipitation system and is ultimately removed with the chem ical precipitation sludge. Accordi ng to the biological treatment system vendor, the backwash water contains ap proximately [Redacted]. EPA used the equation provided by the vendor to estimate the annual am ount of dry solids generated, assuming the FGD wastewater characteristics in Table 6-1 (located at the end of the chapter). The estimated composition of the solids is [Redact ed] [ERG, 2013; See Appendix 57].
Backwash Dry Solids (tons/y r) = [Redacted] × 60 min/hr × 24 hr/day × 365 day/year (6-187)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5).

Sections 5.3 and 5.4 discuss costs for the tran sportation and disposal of sludge from the chemical precipitation system.

6.2.8 Mercury Analyzer Cost

Section 6.1.9 discusses costs to install and operate a merc ury analyzer and effluent recycle system. The mercury analyzer costs are incurred only once for an entire wastewater treatment system. Therefore, for plants expected to install a chemical pr ecipitation and biological treatment system to meet the proposed ELGs, EP A included the cost for one mercury analyzer for the entire system.

6.2.9 Compliance Monitoring Cost

Section 5.2 discusses costs fo r compliance monitoring of bi ological treatment effluent.

6.2.10 Surface Impoundment Operation Cost

Section 5.5 discusses cost savi ngs associated with closi ng combustion re sidual surface impoundments.

6.2.11 FGD System Outage Costs
EPA considered the impact of a plant outage re quired to install the biological treatment system. Based on an evaluation of vendor and survey information, EPA determined that connecting the wastewater treatment system to the existing FGD system can be completed duringChapter 6 - FGD Wastewater Cost Methodology

6-105 regularly scheduled outages. The entire treatment system can be installed prior to a scheduled outage, and then the necessary tie-in can occur during a regularly schedu led outage. Therefore, there are no costs for plant outages during inst allation of the biologi cal treatment system.

6.2.12 Results and Summary of Costs

As described in Section 2.1.4, EPA’s cost m odel generated plant-le vel compliance costs for the one-stage chemical precipitation follo wed by biological treatment technology option. The cost output generated by the model includes a breakout of specific capital and O&M cost elements, including equipment costs, installation costs, operating labor, maintenance labor, and energy costs. The output also includes costs for the common cost elements described in Chapter 5. A list of the plant-level costs for the chem ical precipitation with biological treatment technology option is included in the appendix.

6.3 V APOR -C OMPRESSION E VAPORATION
EPA estimated capital and O&M costs associ ated with installi ng a vapor-compression evaporation treatment system to treat FGD wast ewater. This system is designed to follow a chemical precipitation system (Section 6.1) th at includes a vapor-compression evaporation treatment system feed tank (Section 6.1.6.2). The purpose of the vapor-com pression evaporation system is to concentrate the F GD wastewater contaminants (e.g., me tals, dissolved nutrients) into a solid cake for disposal and genera te a clean distillate stream, wh ich can be reused in the plant process or discharged. All costs were estimated in 2010 dollars.
Throughout this section “FGD wast ewater treatment flow” refe rs to the normalized FGD wastewater flow rate following wa stewater equalization in the ch emical precipitation system in gallons per minute. This flow rate is the FGD wastewater (gpd) converted to gallons per minute assuming 24 hour operation of the wastewat er treatment system (see Section 6.1.5).

6.3.1 Technology Description
EPA used the design of the vapor-compressi on evaporation system based on information provided by vendors (GE and HPD), as well as information collected during EPA’s sampling visit at plants in Italy operat ing this technology. Figure 6-6 and Fi gure 6-7 (located at the end of this chapter) show a typical vapor-compression evaporation system for treatment of FGD wastewater. The system is de signed to operate 24 hours per day and 365 days per year and includes the following major components:

 Water softener to reduc e calcium and magnesium;

 Vapor-compression evaporation brine concen trator to reduce water volume by more than 80 percent of the influent flow; and

 Forced-circulation crystallizer for further wa ter recovery and brine concentration to produce a solid salt cake for disposal.
Before entering the vapor-compression evapor ation system, FGD wast ewater is usually pretreated to remove calcium and magnesium salts, as shown in Figure 6-6. Excessive concentrations of calcium and magnesium salts in the FGD wastewater can pose difficulties forChapter 6 - FGD Wastewater Cost Methodology

6-106 the forced-circulation crystallizer. To prevent this , plants can pretreat the FGD wastewater using chemical precipitation and a lime-softening proc ess upstream of the brine concentrator. With water softening, the magnesium and calcium ions precipitate out of th e wastewater and are replaced with sodium ions, producing an aqueous solution of sodium chloride that can be more effectively treated with a forced-c irculation crystallizer [Shaw, 2008].
Figure 6-7 presents a process flow diagram for a vapor-compression evaporation system. When a vapor-compression evaporation system is us ed to treat FGD wastewat er, the first step is to adjust the pH of the FGD wastewater to a pproximately 6.5 S.U. Additionally, some plants add an antiscalant to the wastewater prior to th e evaporation system [E RG, 2012]. Following pH adjustment, the FGD wastewater goes through a heat exchanger to bring th e wastestream to its boiling point. From the heat exchanger, the wastew ater stream is sent to the deaerator, where the noncondensable materials such as carbon dioxide and oxygen, are vented to the atmosphere [ERG, 2012].

From the deaerator, the wastestream enters the sump of the brine concentrator. Brine from the sump is pumped to the top of the brine c oncentrator and enters the heat transfer tubes. While falling down the heat transfer tubes, part of the solution is vaporized and then compressed and comes in contact with the she ll side of the brine c oncentrator (i.e., the out side of the tubes). With the temperature difference between the compressed vapor and the brine solution, the compressed vapor transfers heat to the brin e solution, which flashes to a vapor, and the compressed vapor cools and condenses as distilled water [ERG, 2012].
The condensed vapor (i.e., dist illate water) can be recycled back to the FGD process, used in other plant operations (e.g., boiler make-up water), or discharged. If the plant uses the distillate for other plant operati ons that generate a discharge st ream (e.g., used as boiler make-up and ultimately discharged as boiler blowdown) , then the FGD process/wastewater treatment system is not truly zero discharge. Therefore, operating a vapor-compression evaporation system does not guarantee that the FGD process/wastewat er treatment system achieves zero discharge.
The concentrated brine slurry from the brine co ncentrator tubes falls into the sump and is recycled with the feed (FGD wastewater) to the t op of the brine concentrator. Typically, the plant continuously withdraws a small amount from the su mp and transfers it to a final drying process. To prevent scaling within the brine concentrat or caused by the gypsum in the FGD wastewater, the brine concentrator is seeded with calcium sulfate. The calcium salts preferentially precipitate onto the seed crystals instead of the tube surfaces of the brine concentrator. If the treatment system is preceded by chemical precipitation and softening, the brine concentrator can typically concentrate the FGD scrubber pur ge five to 10 times, which reduces the inlet FGD scrubber purge water volume by 80 to 90 percent [Shaw, 2008].

6.3.2 Population Costed

Based on information from the Steam El ectric Survey, EPA identified 117 plants discharging FGD wastewater. 39 EPA estimated costs for these 117 plants to install a one-stage

39 When the group of plants excluding oil-fired units and units with a capacity of 50 MW or less is evaluated the population of plants discharging FGD wastewater includes 116 plants.Chapter 6 - FGD Wastewater Cost Methodology

6-107 chemical precipitation system with vapor-compre ssion evaporation to treat FGD wastewater. The population costed is the same as that describe d for FGD wastewater chemical precipitation and biological treatment. EPA identifie d plants that have announced pl ans to retire generating units prior to December 31, 2014 as described in Se ction 4.4.1. There are no conversion costs for plant that are already planned to retire pr ior to implementation of the ELGs.

6.3.3 Credit for Vapor-Compression E vaporation Treatment in Place
EPA evaluated plant responses to the Steam Electric Survey to determine whether vaporcompression evaporation is currently in place fo r treatment of FGD wast ewater. As appropriate, these plants were given credit for having “treat ment-in-place” to ensure that incremental costs associated with compliance with the t echnology options are accurately assessed.
EPA assessed treatment in place credit for bot h portions of the treatment system, the chemical precipitation pretreat ment portion and the vapor comp ression evaporation portion of the treatment system. Section 6.1.3 describes the treatment in place credit given to plants currently operating chemical preci pitation treatment systems. Base d on a review of responses to the Steam Electric Survey, EPA identified one plant using vapor-compression evaporation to treat FGD wastewater. 40 While this plant receives full treatment-in-place credit for the vaporcompression evaporation system the plant does not currently operate a complete one-stage chemical precipitation (see Section 6.1) as a pre-treatment step. This plant does incur incremental costs to modify the FGD wastew ater treatment system to meet BAT.

6.3.4 Input Table
The vapor-compression evaporation cost module uses data from the “FGD Input Table” (see Section 6.1.4). A copy of this input table is included in the appendix.

6.3.5 Capital Cost Methodology
EPA calculated total capital costs for each pl ant as the sum of the purchased equipment costs and installation costs:
Total Capital Costs = Purchased Equipment Cost s + Purchased Equipment Installation Cost

EPA assumed zero land costs ba sed on responses to the Steam Electric Survey indicating that plants incurred zero or ve ry little expense (approximate ly one percent of purchased equipment costs) associated with acquiring la nd for FGD wastewater treatment systems. EPA assumes that other capital costs associated with buildings, site prepar ation, engineering and construction are included in the costs provided by the vendors.
EPA calculated purchased equipment capital cost s for each plant as the sum of purchased equipment costs for the softener, brine concentr ator, and crystallizer. As vendors provided all

40 Through additional information collected during the rulema king, EPA identified two additional plants that plan to install a vapor-compression evaporation system to treat FGD wastewater by 2014 when the rule is promulgated. EPA identified these systems after completing the comp liance cost calculations; therefore, compliance cost estimates currently show a cost for these two plants.Chapter 6 - FGD Wastewater Cost Methodology

6-108 equipment costs in 2009 dollars, EPA adjusted th e cost basis to 2010 dollars using the 2010 and 2009 RSMeans Historical Cost Indices ( 183.5 and 180.1, respectively) [RSMeans, 2011].

See the Supplemental Costs and Loadings Documentation (DCN SE01825.61) for additional information on the derivation of the equa tions used to estimate the plant-level capital cost of the vapor-compression evaporation system.

6.3.5.1 Purchased Equipment Costs: Brine Concentrator and Crystallizer Cost
GE and HPD provided cost data for purchas ing brine concentrator and crystallizer equipment for two different flow rates [ERG, 2013; See Appendix 61]. Based on these data, EPA developed Equation 6-188 to estimate the cost of brine concentrator and cr ystallizer equipment.
Brine Concentrator & Crystallizer Equipment Cost (2009$) = [Redacted] (6-188)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5).

6.3.5.2 Purchased Equipment Costs: Softening Equipment Cost
According to HPD, FGD wastewater soft ening accounts for [Redacted] of the total purchased equipment costs for the vapor-com pression evaporation system [ERG, 2013; See Appendix 61]. EPA developed Equation 6-189 to es timate the softening equipment costs based on this information.
Softening Equipment Cost (2009$) = Softening Cost Factor × Brin e Concentrator & Crystallizer Equipment Cost (6-189)

where:

Softening Cost Factor = Factor to calcu late the purchased cost of softening equipment based on the purchased cost of brine concentrator and crystallizer equipment, [Redacted], and
Brine Concentrator & Crystallizer Equipment Cost = The cost associated with purchasing the brine concentrator and crystallizer equipment associated with the vapor-compression evaporation system in 2009 dollars (see Equation 6-188).

6.3.5.3 Purchased Equipment Installation Cost
EPA developed Equation 6-190 to estimate cap ital cost equipment installation costs based on information provided by HPD a nd GE [ERG, 2013; See Appendix 61].Chapter 6 - FGD Wastewater Cost Methodology

6-109 Installation Cost (2010$) = Instal lation Cost Factor × [Brine Concentrator & Crystallizer Equipment Cost + Softening Equipment Co st] × (2010 Cost Inde x/2009 Cost Index) (6-190)

where:

Installation Cost Factor = Factor to calculate the in stallation cost based on the total purchased equipment cost, [Redacted],
Brine Concentrator & Crystallizer Equipment Cost = Cost to purchase the brine concentrator and crystallizer equipment in 2009 dollars (see Equation 6-188),

Softening Equipment Cost = Cost to purchase the softening equipment in 2009 dollars (see Equation 6-189), 2010 Cost Index = 183.5, and

2009 Cost Index = 180.1.

6.3.6 O&M Cost Methodology
O&M costs for each plant consist of all cost s related to operating and maintaining the vapor-compression evaporation system. EPA calcu lated total O&M costs as the sum of the following O&M cost components:

 Operating labor cost,

 Maintenance labor cost,

 Maintenance materials cost,

 Chemical purchase cost,

 Energy cost,

 Sludge disposal cost, and

 Compliance monitoring cost.

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A61) for additional information on the derivation of the eq uations used to estimate the plant-level O&M cost of the vapor-compression evaporation system.

6.3.6.1 Operating Labor Cost
Operating labor cost includes labor costs for plant staff to operate the vapor-compression evaporation system. EPA assumed one operator, 24 hours per day is required to operate the system based on observations during a site vis it to a U.S. plant operating a vapor-compression evaporation system to treat FGD wastewater. EPA determined an operating labor rate of [Redacted] (2010$) based on the median operating labor rate reported in response to Question D6-2 of the survey by plants that operate FGD wastewater chemical preci pitation treatment (withChapter 6 - FGD Wastewater Cost Methodology

6-110 and without subsequent vapor-compre ssion evaporation system treatment). 41 Finally, EPA calculated operating labor costs for each plant by converting the number of workers to annual number of hours worked, and then multiplying by the operating labor rate.

Operating Labor Cost (2010$/yr) = Operating Labor Rate × Number of Workers × 24 hr/day × 365 day/yr (6-191)

where:

Operating Labor Rate = The median F GD wastewater treatment operator labor rate as reported in the Steam Electric Survey, [Redacted] (2010$), and
Number of Workers = Number of FTEs a ssociated with oper ating activities, 1.

6.3.6.2 Maintenance Labor Cost

Maintenance labor cost includes labor cost s for plant staff to maintain the vaporcompression evaporation system. Vapor-compre ssion evaporation system vendor information was insufficient for use in estimating maintenance labor costs; therefore, EPA used maintenance labor costs from chemical precipitation treatm ent of FGD wastewater (see Section 6.1.7.2 and Equation 6-120).

6.3.6.3 Maintenance Materials Cost
Vapor-compression evaporation system vendor information was insufficient for use in estimating maintenance materials costs; therefor e, EPA used maintenance materials costs from chemical precipitation treatment of FGD wast ewater (see Section 6.1.7.3 and Equation 6-121).

6.3.6.4 Chemical Purchase Cost
Chemical requirements for the vapor-compressi on evaporation system consist of soda ash used for wastewater softening. HPD provided cost data for chemical purchase for one flow rate [ERG, 2013; See Appendix 61]. EPA developed a we ighted chemical freight cost of $60.57 per ton, based on the required quantities of the soda ash, its density, and freight cost information by weight from FreightCenter.com . EPA developed Equations 6-192 and 6-193 to estimate the chemical purchase cost.
Soda Ash Usage (lb/hr) = [Redacted] (6-192)

Chemical Cost (2010$) = Soda Ash Usage × 1 ton/2,000lb × 24 hr/day × 365 day/yr × (Soda Ash Cost + Chemical Freight) × ( 2010 Cost Index/2009 Cost Index) (6-193)

41 The median FGD wastewater treatment operator labor rate based on survey data is in 2009$. EPA will index the value appropriately with cost index da ta from RS Means for the final rule.Chapter 6 - FGD Wastewater Cost Methodology

6-111 where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), Soda Ash Cost = Cost of soda ash provided by vendor, [Redacted],
Chemical Freight = $60.57 (2009$)/ton,

2010 Cost Index = 183.5, and

2009 Cost Index = 180.1.

6.3.6.5 Energy Cost
EPA calculated energy costs for each plant as the sum of energy costs for the softener, brine concentrator, and crystallizer.
Energy Cost (2010$) = Brine Concentrator & Cr ystallizer Energy Cost + Softening Energy Cost (6-194)

Brine Concentrator & Crystallizer Energy EPA calculated energy consumption (kWh) for the brine concentrator and crystallizer using Equation 6-195, which was developed from information provided by GE and HPD for two different flow rates [ERG, 2013; See Appendix 61].
Brine Concentrator & Crystallizer Energy Consumption (kWh/yr) = [Redacted] (6-195)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5).

Softening Energy EPA calculated energy consumption (kWh) for FGD wastewater softening using Equation 6-196, which was developed based on info rmation provided by HPD for one flow rate [ERG, 2013; See Appendix 61].
Softening Energy Consumption (kWh/yr) = [Redacted] (6-196)

where:

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5).Chapter 6 - FGD Wastewater Cost Methodology

6-112 To calculate energy costs, EPA multiplied energy consumption by the national average energy cost of 4.05 cents per kWh (2009$) as determined by the U.S. Energy Information Administration in Table 8.2 of the Electric Power Annual 2009 for fossil plants in the United States [U.S. DOE, 2011]. As the energy cost was provided in 2009 dollars, EPA adjusted the cost basis to 2010 dollars using the 2009 and 2010 RS Means Historical Cost Indices (180.1 and 183.5, respectively) [RSMeans, 2011].
Plant Energy Cost (2010$/yr) = [Brine Concen trator & Crystallizer Energy Consumption +

Softening Energy Consumption] × National Energy Cost × (2010 Cost Index/2009 Cost Index) (6-197)

where:

Brine Concentrator & Crystallizer Energy Consumption = Annual amount of energy consumed by the brine concentrator and crystalli zer equipment in kWh,

Softening Energy Consumption = Annual amount of energy consumed by the softening equipment in kWh, National Energy Cost = $0.0405/kWh in 2009 dollars,

2010 Cost Index = 183.5, and

2009 Cost Index = 180.1.

For the purpose of estimating non-water qu ality environmental impacts, EPA also converted energy consumption in kWh/yr to energy load in MW using Equation 6-198.
Energy Load (MW) = [Brine Concentrator & Crystallizer Energy Consumption + Softening Energy Consumption] / (24 hpd × 365 dpy) × 1 MW / 1000 kW (6-198)

where:

Brine Concentrator & Crystallizer Energy Consumption = Annual amount of energy consumed by the brine concentrator and crystalli zer equipment in kWh, and

Softening Energy Consumption = Annual amount of energy consumed by the softening equipment in kWh.

6.3.7 Sludge Disposal Cost
The vapor-compression evaporation system generates both softening sludge and crystallizer sludge. According to HPD, softening sludge and crystallizer sludge are generated at rates of 51.43 lb/hr and 17.14 lb/hr for each gpm of FGD wastewater flow [ERG, 2013; See Appendix 61]. Based on this information, EPA calculated sludge generation rates using Equations 6-199 and 6-200.Chapter 6 - FGD Wastewater Cost Methodology

6-113 Softening Sludge (tons/yr) = Softening Sludge F actor × FGD Wastewater Treatment Flow GPM × (1 ton/2,000 lb) × 24 hpd × 365 dpy (6-199 )

Crystallizer Sludge (tons/yr) = Cr ystallizer Sludge Factor × F GD Wastewater Treatment Flow GPM × (1 ton/2,000 lb) × 24 hpd × 365 dpy (6-200)

where:

Softening Sludge = Amount of sludge generated annually by the softening equipment, Softening Sludge Factor = 51.43 lb/hr-gpm,

FGD Wastewater Treatment Flow GPM = FGD wastewater flow rate in gpm normalized for 24 hpd operation (see Section 6.1.5), Crystallizer Sludge = Amount of sludge generated annually by the crystallizer, and Crystallizer Sludge Factor = 17.14 lb/hr-gpm.

Sections 5.3 and 5.4 discuss costs for the tran sportation and disposal of sludge from the chemical precipitation system.

6.3.8 Mercury Analyzer Cost

Section 6.1.9 discusses costs to install and operate a merc ury analyzer and effluent recycle system. The mercury analyzer costs are incurred only once for an entire wastewater treatment system. Therefore, for plants expected to install a chemical precipitation and vaporcompression evaporation system to meet the pr oposed ELGs, EPA included the cost for one mercury analyzer for the entire system.

6.3.9 Compliance Monitoring Cost

Section 5.2 discusses costs fo r compliance monitoring of vapor-compression evaporation distillate effluent.

6.3.10 Surface Impoundment Operation Cost

Section 5.5 discusses cost savi ngs associated with closi ng combustion re sidual surface impoundments.

6.3.11 FGD System Outage Costs
EPA considered the impact of a plant outag e required to install the vapor-compression evaporation treatment system. Based on an eval uation of vendor and survey information, EPA determined that connecting the wastewater treatm ent system to the existing FGD system can beChapter 6 - FGD Wastewater Cost Methodology

6-114 completed during regularly scheduled outages. The en tire treatment system can be installed prior to a scheduled outage, and then the necessary tie-in can occur during a regularly scheduled outage. Therefore, there are no costs for plant outages duri ng installation of the vaporcompression evaporation treatment system.

6.3.12 Results and Summary of Costs

As described in Section 2.1.4, EPA’s cost m odel generated plant-le vel compliance costs for the one-stage chemical precipitation with vapor-compression evaporation technology option. The cost output generated by the model includes a breakout of specific capital and O&M cost elements, including equipment costs, installation costs, operating labor, maintenance labor, and energy costs. The output also includes costs for the common cost elements described in Chapter 5. A list of the plant-level costs for the ch emical precipitation with vapor-compression evaporation technology option is included in the appendix.

6.4 R EFERENCES

1. Eastern Research Group, Inc (ERG). 2012. Fina l Site Visit Notes and Sampling Episode Report for Enel’s Power Plants. (8 August). DCN SE02013.
2. Eastern Research Group, Inc (ERG). 2013. Supplemental Costs and Loadings Documentation. (19 April). DCN SE01825.
3. RSMeans. 2011. Building Construction Cost Data, 69th Edition. (January). DCN SE02952.
4. Shaw, William A. 2008. “Benef its of Evaporating FGD Purge Water.” Power. (March). 59-63. Available online at: http://www.powermag.com/powerwe b/archive_article.asp?a=60- F_WM&y=2008&m=march. Date accesse d: March 14, 2008. EPA-HQ-OW-2006-0771- 1564.
5. Sonstegard, J., et al. 2008. Full Scale Oper ation of GE ABMET® Biolocial Technology for the Removal of Selenium from FGD wastewaters. IWC-08-31. (January). DCN SE02955.
6. U.S. Department of Energy (DOE). 2011. U.S. Department of Energy, Energy Information Administration (EIA). Elect ric Power Annual 2009. Washington, DC. (4 January). DCN SE02023.Chapter 6 - FGD Wastewater Cost Methodology

6-115 Figure 6-1. One-Stage Chemic al Precipitation TreatmentChapter 6 – FGD Wastewater Cost Methodology

6-116 Figure 6-2. Solubilities of Metal Hydroxide s and Sulfides as a Function of pHChapter 6 – FGD Wastewater Cost Methodology6-117Figure 6-3. Two-Stage Biological Treatment System (System to follow Chemical Precipitation Pretreatment)Chapter 6 – FGD Wastewater Cost Methodology6-118Figure 6-4. Mean Maximum Daily Temperature for JulySource: NOAA/NESIS/NCDC Climate Maps of the United Stateshttp://cdo.ncdc.noaa.gov/cgi-bin/climaps/climaps.plChapter 6 – FGD Wastewater Cost Methodology6-119Figure 6-5. Location of PlantsIncurring Heat Exchanger CostsChapter 6 – FGD Wastewater Cost Methodology6-120Figure 6-6. Chemical Precipitation and Softening Pretreatment for FGD Wastewater Prior to Vapor-CompressionEvaporationChapter 6 – FGD Wastewater Cost Methodology6-121Figure 6-7. Process Flow Diagram for a Vapor-Compression Evaporation System (System to Follow Chemical PrecipitationPretreatment)Chapter 6 – FGD Wastewater Cost Methodology

6-122 Table 6-1. Expected FGD Wastewater Characte ristics for Design of the Biological Treatment Stage
Analyte Unit Average Min Max TOTAL Arsenic μg/L 3.45 1.8 6.4 Mercury ng/L 12200 72.9 53300 Selenium μg/L 873 87 2150 DISSOLVED Arsenic μg/L 3.05 1.5 5.4 Mercury ng/L 15800 ND 50000 Selenium μg/L 871 86.5 2100 CLASSICALS Biochemical Oxygen Demand mg/L 2.36 ND 7.4 Chemical Oxygen Demand mg/L 224 79 455 Total Suspended Solids mg/L 14.1 1.2 70.5 Total Dissolved Solids mg/L 15800 7150 26000 Sulfate mg/L 5000 1200 16000 Nitrate Nitrite as N mg/L 58.6 13 160
ND – Non-DetectChapter 7– Fly Ash Transport Water Cost Methodology

7-1 

## CHAPTER 7 FLY ASH TRANSPORT WATER COST METHODOLOGY

Because of the development of ash handling sy stems that require little to no water, as well as the ability to market dry fly ash, plan ts have been converting handling operations on existing steam electric generating units from we t sluicing operations to systems that do not transport the ash with water. EPA estimated th e capital, operating and ma intenance (O&M), and 10-year recurring costs associated with converting wet fly ash handling systems (specifically wet fly ash sluicing systems) to dry fly ash hand ling systems. EPA evaluated the following two technology options for fly ash transport water:

 Dry vacuum fly ash handling system; and

 Vactor truck collection system.
The following sections describe the technol ogy basis and methodology used to estimate the compliance costs associated with converting from wet fly ash handling systems to a dry vacuum ash handling system or a vactor truc k collection system. Sec tion 7.1 describes the methodology for converting to a dry vacuum fly ash handling system, and Section 7.2 describes the methodology for converting to a v actor truck collection system.

7.1 C ONVERSION OF W ET F LY A SH H ANDLING S YSTEMS TO D RY V ACUUM F LY A SH H ANDLING S YSTEMS
Plants operating wet fly ash handling systems use a vacuum created by water flowing through an eductor to draw the fly ash away from the hoppers. These water jet eductors, also known as venturi eductors, use the kinetic energy of the water to create the vacuum for the dry portion of the ash handling system. The ash is pulled to a separato r/transfer tank, where it combines with the water flowing through the sluice pipes for transport to the ash impoundment. Plants usually have a sluice stream for each individual electrostatic precipitators (ESP) or set of hoppers, with the sluice water flowing continuously to maintain the necessary vacuum and prevent solids from settling in the piping. Alternatively, some plants use venturi-type wet scrubbers to remove fly ash. EPA estimated the costs required to retrofit wet fly ash handling systems and convert them to a dry vacuum fly ash handling system. EPA developed a costing approach for th ree separate portions of the system:

 Conveyance. The portion of the fly ash handlin g system from the bottom of the collection hopper to the inte rmediate storage destinat ion. The conveyance includes the mechanical exhauster, piping, valves, a nd filter-separators necessary to pull and convey ash from the bottom of the hopper. EPA calculated conveyance costs at the steam electric generating unit level.

 Intermediate Storage. The destination to which the dr y fly ash is conveyed from the bottom of the hopper. The intermediate stor age contains the structure itself (e.g., the silo), including the vacuum equipment n ecessary to receive the ash from the conveyance lines, and the unloading equipm ent necessary for moisture conditioningChapter 7– Fly Ash Transport Water Cost Methodology

7-2 prior to transportation and disposal. 42 EPA calculated intermedia te storage costs at the plant level.

 Transportation/Disposal. The trucking equipment and operation that move the dry fly ash to its final destination (i.e., on-s ite or off-site landfill). EPA calculated transport/disposal costs at the plant level.
EPA calculated total costs for each plant as the sum of the conveyance costs for each steam electric generating unit requiring fly ash hand ling conversion costs, as well as intermediate storage and transportation and di sposal costs for the conversion of wet to dry fly ash handling. All costs were estimated in 2010 dollars.

7.1.1 Technology Description
The dry vacuum fly ash handling system uses a mechanical exhauster to move air to entrain and convey dry fly ash pa rticles away from the hoppers to storage silos. EPA based the design and cost of the replacement dry vacuum ash handling system on information collected from vendors (Clyde Bergemann Power Group ( CBPG, formerly Delta Ducon) and United Conveyance Corporation), as well as information collected from industry through site visits and the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey).
Based on the information from CPBG, EPA estimated costs for a dry vacuum handling system including the following components:

 Air inlet branch line valves;

 Segregating branch line valves;

 Hopper isolation valves;

 Ash intake valves;

 Large flange (LF) pipe for branch lines (two rows each);

 LF pipe for header to silo;

 Elbows: PERMA/flow IWB (90 Degree);

 Elbows: PERMA/flow IWB (45 Degree);

 Laterals: PERMA/flow IWB (45 Degree);

 Couplings;

 Pipe supports: 3 feet maximum to support steel;

 Filter-Receiver:

 Bag filter with specified cloth area,

 Receiver tank with stone box inlet,

42 Plants may have a silo; however, they may need to inst all the equipment for moisture-conditioning ash prior to unloading. Therefore, the intermediate storage costs are based on two cost indicators, one for the silo and one for the pugmill.Chapter 7– Fly Ash Transport Water Cost Methodology

7-3  Airlock with two PERMA/flo V valves,

 Equalizing valve,

 Broken bag detector,

 Vacuum breaker;

 Vacuum pumps:

 Rated for specified ACFM at 15” Hg system vacuum and surge,

 Motor,

 Butterfly valves for selection,

 Sound enclosure, and

 Lot miscellaneous instru mentation and control.
The specified sizing of the branch lines, el bows, laterals, couplings, valves, and motors differ based on the required size of the system. EPA determined the size of the system from the fly ash generation rate of each unit requi ring a retrofit [ERG, 2013; See Appendix 69].
Using this system, the dry fly ash is conveyed to a steel or concrete si lo of an appropriate size to hold three days’ worth of dry fly ash. EPA determined whether to use steel versus concrete silos for plants based on which material provided the more economical option. The steel silo includes the following components:

 Steel silo;

 Level indicators, manway, and jib crane;

 Aeration system; and

 Pugmill unloaders.
The concrete silo includes the following components:

 Concrete silo;

 Jumpform concrete silo walls;

 Roof;

 Bin floor;

 Equipment floor;

 Aeration system; and

 Pugmill unloaders.
EPA assumed that the fly ash would be unloaded from the silo, moisture-conditioned, and disposed of in an on-site or off-site landfill. Pugmill unloaders mix dry ash and water to a desired moisture content while the ash is transferred fr om the silo to a transport vessel. EPA assumed that each silo would at least have two mo isture conditioning unloaders for redundancy [ERG, 2013; See Appendix 69].Chapter 7– Fly Ash Transport Water Cost Methodology

7-4 7.1.2 Population Costed
Based on information from the Steam Electric Survey, EPA identified 76 plants, corresponding to 194 units, discharg ing fly ash transport water wit hout any plans to convert to dry handling or having the capac ity to handle all the fly ash dry, from coal- and oil-fired units. 43,44 EPA identified the units planning to convert to dry handling from responses in the Steam Electric Survey stating a planned convers ion, the projected date for the conversion, and the end use of the wet sluicing system. Additiona lly, EPA identified plants that have announced plans to retire generating units or convert to dry fly ash handling prior to December 31, 2014, as described in Section 4.4.1. Finally, EPA identifie d units with enough capacity to handle all fly ash with a dry handling system from responses in the Steam Electric Survey stating that no modifications to the existing fly ash handling syst em would be required to handle all of the fly ash dry. There are no conversion costs for generating units that are already planned to be retired or converted to dry fly ash handling systems b ecause the plant will conve rt/retire these units without the implementation of the Steam Electri c effluent limitations guidelines and standards (ELGs). Additionally, there are no conversion costs for generating units that have both wet and dry fly ash handling systems where the dry system is capable of handling all of the fly ash because the plant would be capable of operating without the wet sluicing system. EPA estimated compliance costs for these 76 plants to convert wet sluicing systems to dry vacuum systems.

7.1.3 Fly Ash Handling Equipment Reused in the Conversion
The conversion from wet to dry fly ash ha ndling for a unit requires new equipment to pnuematically convey the ash; however, some pieces of the existing wet fly ash handling system can be retained for use with the dry vacuum ash handling syst em. Specifically, based on input from CPBG, EPA assumed that the existing vacu um hopper equipment and branch lines can be retained and therefore did not include costs fo r this equipment [ERG, 2013; See Appendix 69].

In addition, based on data from the Steam Elect ric Survey and site visits, EPA determined that a single steam electric ge nerating unit may be equipped with both wet and dry handling capabilities. Therefore, depending on the equi pment already operating at the plant, and the capacity of that equipment, complete conversion costs are not applicable to all steam electric generating units. As appropriate, plants with wet and dry handling systems were given credit for having this equipment at the plant and flagged in the “Fly Ash Input Table” accordingly (see Section 4.2.2).

7.1.4 Input Table

As discussed in Section 4.2.2, EPA used data from the Steam Electric Survey to identify which plants operate one or more fly ash sluicing systems. These plants all incur some level of costs for converting to dry fly ash handling, except those plants that have the capacity to handle

43 When the group of plants excluding oil-fired unts and un its with a capacity of 50 MW or less is evaluated the population of plants discharing fly ash transport water includes 66 plants, corresponding to 170 units.

44 EPA only includes those oil-fired units wet sluicing fly ash more than 100 days out of the year. Oil-fired units wet sluicing fly ash less than 100 days out of the year are included in the population described in Section 7.2.2.Chapter 7– Fly Ash Transport Water Cost Methodology

7-5 both wet and dry ash. The “Fly Ash Input Table” hol ds all the input data n eeded to calculate the compliance costs for these plants. The “Fly As h Input Table” contains the following fields:

 Plant_id: Survey Plant ID.

 Seunit_id : Survey Steam Electric (SE) Unit ID.

 No_cost : Flag indicating that the unit will not incur costs for its fly ash system.

 Conveyancecost : Flag indicating that the unit will require a fly ash conveyance retrofit.

 Silocost : Flag indicating that the unit w ill require increased silo capacity

 Pugmillcost : Flag indicating that the unit will re quire installation of pugmills for ash conditioning.

 Market_landfill : Flag indicating that the unit operated a wet fl y ash handling system because the fly ash was not marketable or respondent indicated that an increase in landfill capacity would be required to handle all of the fly ash dry.

 Wet_tpd : The amount of fly ash handled wet in t ons per day (tpd) (dry weight basis) from Table C-2

. For units that handled fly ash wet in 2009 and did not report this value, it has been calculated by multiplying the tons of coal burned in the unit in 2009 by 8 percent (assuming 10 percent ash conten t for the coal and 80 percent of ash generated is fly ash). This value is then divided by the number of days the unit operated in 2009, as reported in Table A-8, to get an estimate of the amount of wet fly ash handled wet in tons per day.

 Wet_dpy : Number of days fly ash was conveyed wet in 2009 in days per year (dpy) from Table C-2. If the number of days was not reported, the number is assumed to be the same as the number of operating days.

 Dry_tpy : The amount of fly ash handled dry in tpd (dry weight basis) from Table C2

.

 Dry_dpy : Number of days fly ash was conveye d dry in 2009 in dpy from Table C-2.

 Unit_type : Type of unit, as indicated in Table A-8 (i.e., baseload, cycling, intermediate, and peaking).

 Produce_hpd : Estimate of the number of hours pe r day (hpd) the unit operates. EPA assumed units identified as baseload, interm ediate, or cycling in Table A-8 operate 24 hpd and peaking units, as identifi ed in Table A-8, operate 12 hpd.

 Convey_hpd : Estimate of the number of hpd the unit conveys fly ash. EPA assumed all units convey fly ash 12 hpd.

 Operating_days : Number of days the unit operated in 2009. Value populated from responses in Table A-8. If the number of days was not reported, the number is assumed to be the reported days per y ear of wet ash production in Table C-2.

 MW : The unit capacity (in megawatts (MW)) from steam turbine capacity in Table A-8.

 Retired? : Flag indicating that the plant has id entified that it will be retiring on or before 12/31/2014.Chapter 7– Fly Ash Transport Water Cost Methodology

7-6  FlowRate_GPD : Fly ash sluice flow rate from Table C-3.
Section 4.2.2 discusses the methodology used to determine the a ppropriate level of costing for each steam electric unit and the spec ific Steam Electric Survey questions. A copy of the “Fly Ash Input Table” is included in the appendix.

7.1.5 Capital Cost Methodology
Total capital costs for each plant were calcu lated as the sum of the following purchased equipment costs and installation costs:

 Purchased equipment costs,

 Purchased equipment installation costs,

 Plant overhead engineering costs, and

 Fly ash disposal costs.
Purchased equipment costs are the costs asso ciated with purchasing all equipment to retrofit all generating units currently collecting fly ash with a wet slui cing system with a dry vacuum conveyance system. EPA calculated purchased equipment costs by summing the costs of dry vacuum conveyance system(s), the concrete or steel silo(s), silo aeration equipment, and pugmill(s). EPA calculated equipment costs for conveyance on a generati ng unit level and silo and pugmill equipment costs at a plant level. EPA estimated conveyance, silo, and pugmill equipment costs using a relationship between capital costs and wet fly ash generation rate obtained from industry vendors.
EPA estimated installation capital costs fo r the fly ash handling conversion for each plant, including all system elem ents, using an installation factor determined from Steam Electric Survey data. EPA supplemented this information with cost data from industry vendors to determine an installation factor for the conveya nce and intermediate storage system elements. EPA estimated the installation costs by appl ying the calculated factor to the purchased equipment cost.
Plant overhead engineering costs were dete rmined from Steam Electric Survey data. Based on survey responses, EPA calculated a medi an installation factor for the conveyance and intermediate storage system elements. EPA estimated the overhead costs by applying the calculated factor to the purchased equipment and inst allation costs.

EPA calculated the amount of moisture -conditioned fly ash generated from the conversion using wet fly ash genera tion rates at the plant-level a nd an average moisture content of fly ash from the Steam Electric Survey, supplemented with vendor data. EPA used the moisture-conditioned fly ash tonnage to estimate the disposal costs (see Section 7.1.7).

EPA assumed zero land costs base d on data from site visits and discussions with plants who have already converted from wet fly ash ha ndling to dry fly ash handling. EPA assumed that other capital costs associated w ith buildings, site preparation, e ngineering, and construction were included in the costs provided by the vendors.Chapter 7– Fly Ash Transport Water Cost Methodology

7-7 7.1.5.1 Purchased Equipment Costs: Conveyance Equipment
EPA estimated unit-level capital costs for the purchase of equipment to convert from a fly ash wet sluicing system to a dry vacuum system. EPA then summed these unit-level costs to calculate plant-level conveyance equipment costs. EPA made the assumpti ons listed below based on information obtained from vendors and survey responses:
EPA costed 500 feet of conveyance from the generating unit to a silo(s). Based on a review of questionnaire responses, EPA found th at 81 percent of dry vacuum systems (and 91 percent of dry vacuum system retrofits) convey fl y ash less than or equal to one tenth of a mile (approximately 500 feet). In addition, CBP G indicated conveyance distance does not significantly impact the overa ll cost of the system.
EPA did not include costs for hopper and br anch line equipment given that this equipment can be reused from existing fly ash wet sluicing systems, as described in Section 7.1.3.
EPA developed capacity factors to account for variability in fly ash generation rates. For base load, cycling, and intermedia te generating units, EPA assumed a capacity factor of two; for peaking generating units, EPA assumed a capacity factor of four.
EPA assumed a conveyance rate of 12 hpd for all generating units.

EPA used vendor data to estimate costs for conveyance systems with fly ash conveyance rates up to a maximum of 50 tpd. If a conveyance rate for a unit was calculated to be greater than 50 tpd, EPA costed multiple vac uum systems of equal size.

The Supplemental Costs and Loadings Documentation (DCN SE01825.A70) contains more detail on the information obtained from vendors and the Steam Electric Survey used to estimate conveyance equipment costs.

EPA determined the size and cost of c onveyance equipment based on the unit fly ash conveyance rate (in tons per hour (tph)), which was calculated using Equation 7-1.
Unit Wet Fly Ash Conveyance Rate (tph) = (Uni t Wet Fly Ash Generation Rate × Maximum Conveying Capacity Facto r) / (Unit Conveying Time) (7-1)

where:

Unit Wet Fly Ash Generation Rate = Amount of wet fly ash produ ced by the generating unit in tpd (see Section 4.2.2), Maximum Conveying Capacity Factor = Factor to adjust capacity to account for variability in fly ash generation rates: 2 (for based load/cycling/intermediate units)4 (for peak units), and Unit Conveying Time = 12 hpd.Chapter 7– Fly Ash Transport Water Cost Methodology

7-8 EPA accounted for the maximum conveying capac ity factor to adjust the size of the costed fly ash handling system to handle the ma ximum amount of fly ash that may be generated at a given time based on the expect ed fluctuation in unit operations.
EPA determined the number of dry vacuum sy stems to be costed, as well as the new unit fly ash conveyance rate based on th e number of dry systems needed for the generating unit, using Equations 7-2 and 7-3.
Number of Unit Vacuum Systems = Round Up (Unit Wet Fly Ash Conveyance Rate / 50 tph) (7-2)

Recalculated Unit Wet Fly Ash Conveyance Rate (tph) = Unit Wet Fly Ash Conveyance Rate / Number of Unit Vacuum Systems (7-3)

where:

Unit Wet Fly Ash Conveyance Rate = Amount of wet fly ash produ ced by the generating unit in tpd (see Section 4.2.2), and
Number of Unit Vacuum Systems = The number of vacuum systems required (see Equation 7-2).

CBPG provided EPA with estimated costs for the purchase of equipment to convert wet fly ash conveyance systems to dry fly ash conveya nce systems for various sized systems. From these data, EPA developed Equation 7-4 to es timate dry fly ash conveyance equipment cost.

Unit-Level Dry Fly Ash Conveyance Equipment Capital Cost (2010$) = (9,791 × Recalculated Unit Wet Fly Ash Conveyance Rate + 23,372) × Number of Unit Vacuum Systems (7-4)

where:

Recalculated Unit Wet Fly Ash Conveyance Rate = Recalculated wet fly ash conveyance rate to evenly distribute wet fly ash among number of vacuum systems required (see Equation 7-3), and
Number of Unit Vacuum Systems = The number of vacuum systems required (see Equation 7-2).

EPA calculated plant-level total conv eyance equipment costs by summing the conveyance equipment cost for each generating unit.
Conveyance Equipment Capital Cost (2010$) for Plant = ∑ Unit-Level Dry Fly Ash Conveyance Equipment Capital Cost (7-5)

7.1.5.2 Purchased Equipment Cost: Silo
EPA estimated plant-level capital costs for pur chasing equipment to provide dry fly ash storage capacity for the convert ed units based on Equation 7-6.Chapter 7– Fly Ash Transport Water Cost Methodology

7-9 Cost (2010$) for Plant = Silo Capital Cost + Other Equipment Silo Cost (7-6)

EPA first assessed the need for additional storage capacity for each generating unit. EPA then summed the additional storage capacity re quired across all units and estimated the total additional storage required at the plant level. EPA made the assumptions listed below based on information obtained from vendors a nd Steam Electric Survey responses:

 EPA costed silos constructed of steel or concrete and sized for three days (i.e., 72 hours) of storage capacity to avoid the need to unload ash during weekends.

 EPA assumed that plants will install the cheaper silo (steel or concrete) based on the amount of fly ash generated at the plant level.

 EPA used a dry fly ash density of 45 lb/ft 3

.

 EPA used vendor data to estimate costs fo r steel silos ranging in size up to a maximum of 80,000 ft 3 and concrete silos ranging in size up to a maximum of 12,800 tons of dry fly ash (569,000 ft 3 based on an ash density of 45 lbs/ ft 3 ). EPA did not cost silos with a storage cap acity greater than 12,800 tons, based on cost information from Marietta Silos [ERG, 2013; See Appendix 71].

EPA determined the size and cost of additi onal storage capacity ba sed on the sum of the unit fly ash generation rates (reported in the St eam Electric Survey, in tpd) for the generating units requiring additional storage. Using inform ation from CBPG and Marietta Silos, EPA determined that steel silos are more cost effective for plants with a plant-level wet fly ash generation rate less than 60 tpd. EPA first estimate d the number of steel s ilos required and their size using Equations 7-7, 7-8, and 7-9. 45

Steel Silo Size (ft 3 ) = 2,000 lb/ton ⁄ Fly Ash Density × (Plant We t Fly Ash Generation Rate × 3 days) (7-7)

Number of Steel Silos = Round Up (Steel Silo Size / 80,000 ft 3 ) (7-8)

Recalculated Steel Silo Size (ft 3 ) = Steel Silo Size / Number of Silos (7-9)

where:

Fly Ash Density = 45 lb/ft 3 , and
Plant Wet Fly Ash Generation Rate = Sum of the wet fly ash produced for all generating units at the plant in tpd.

CBPG provided EPA with estimated costs for th e purchase of various sized steel silos for temporary storage of fly ash. The costs include equipment for unloading a nd fluidizing the fly ash. From these data, EPA developed Equation 7-10 to estimate steel silo capital cost.

45 The plant-level wet fly ash generation rate is equal to the sum of the unit fly ash generation rate for all units producing wet ash at the plant.Chapter 7– Fly Ash Transport Water Cost Methodology

7-10 Steel Silo Capital Cost (2010$) = (14.81 × Recal culated Steel Silo Size + 10,089) × Number of Steel Silos (7-10)

where:

Recalculated Steel Silo Size = Recalculated steel silo size to evenly distribute wet fly ash among number of silos required (see Equation 7-9), and
Number of Steel Silos = Number of steel silos re quired (see Equation 7-8).

Because vendor costs include unloading and fluidizing equipment, no additional silo equipment is required.
EPA calculated concrete silo capital costs for plants with a plant-level wet fly ash generation rate greater than 60 tpd. EPA first es timated the number and size of concrete silos required using Equations 7-11, 7-12, and 7-13.
Concrete Silo Design Tonnage (tons) = Pl ant Wet Fly Ash Generation Rate × 3 days (7-11)

Number of Concrete Silos = Round Up (Concrete Silo Design Tonnage) / 12,800 tons (7-12)

Recalculated Concrete Silo Size (ton s) = Concrete Silo Design Tonnage / Number of Concrete Silos (7-13)

where:

Plant Wet Fly Ash Generation Rate = Sum of the wet fly ash produced for all generating units at the plant in tpd.

Marietta Silos provided EPA with estimated costs for the purchase of various sized concrete silos for temporary stor age of fly ash, including costs for the concrete silo, walls, roof, bin floor, and equipment floor. From these da ta, EPA developed Equation 7-14 to estimate concrete silo capital costs.

Concrete Silo Capital Cost (2010$) = [( 0.005 × (Recalculated Concrete Silo Size) 2 ) + (519.8 × Recalculated Concrete Silo Size) + 44,379] × Number of Concrete Silos (7-14)

Because Marietta Silos’ concre te silo costs did not include any unloading and fluidizing equipment costs, EPA applied the unloading an d fluidizing equipment costs from CBPG using Equation 7-15.
Other Equipment Concrete Silo Cost (2010$) = [(173.3 × Recalculated Concrete Silo Size) + 52,105] × Number of Concrete Silos (7-15)Chapter 7– Fly Ash Transport Water Cost Methodology

7-11 See the Supplemental Costs and Loadings Documentation (DCN SE01825.A71) for more detail on the development of Equations 7-6 through 7-15.

7.1.5.3 Purchased Equipment Cost: Pugmill
EPA estimated plant-level capital costs for the purchase of pugmills to moisten the fly ash prior to disposal in landfills (i.e., the si los discussed in Section 7.1.5.2 are not designed for dry unloading of dry fly ash). 46 EPA made the assumptions listed below in estimating plant-level capital costs for purchasing pugmills based on info rmation obtained from vendors, site visits, and Steam Electric Survey responses:

 EPA costed each silo for at least two pugmills for redundancy.

 EPA assumed an ash unloading time of 16 hpd, five days per week (dpw). EPA based these times on observations during site visits of ash unloading during two shifts per day and no ash unloading over weekends.

 EPA used vendor data from CPBG to cost pugmills with a maximum ash conditioning/unloading rate of 150 tph. If EPA estimated a pugmill would have an ash conditioning/unloading rate of greater than 150 tpd, EPA costed multiple pugmills of equal size.
EPA determined the size and cost of pugmills based on the silo ash unloading rate (in tph), which was calculated using Equation 7-16. The pugmill capacity factor, 1.4, provides additional pugmill capacity to avoid having to unload ash during weekends (seven days/five days).
Silo Ash Unloading Rate (tph) = Plant Wet Fl y Ash Generation Rate / Number of Silos × (Pugmill Capacity Factor) / Pugmill Operating Time (7-16)

where:

Plant Wet Fly Ash Generation Rate = Sum of the wet fly ash produced for all generating units at the plant in tpd (see Section 4.2.2),
Number of Concrete or Steel Silos = Number of silos needed to storage three days worth of the wet ash that is conve rt to dry handling (see Equation 7-8), Pugmill Capacity Factor = Factor applied to the pugmill unloading time to allow for enough capacity to unload seven days worth of ash within five days, 1.4, and

46 Since EPA has based its compliance cost estimates on the a ssumption that the fly ash will be disposed of in an onsite or off-site landfill, the ash silos are costed for a configuration that includes moisture conditioning of the ash as it is loaded into trucks. EPA did not include costs for dry unloading into vacuum trucks since ash loaded in this manner is too dry for landfill disposal. Should a plant choo se to also install dry unloading capability for the fly ash and market its beneficial use and avoid landfill disposal, the costs for the dry unloading capability will be more than offset by the avoided landfill disposal costs and potential revenue associated with selling the ash for beneficial use.Chapter 7– Fly Ash Transport Water Cost Methodology

7-12 Pugmill Operating Time = 16 hpd.

EPA determined the number of pugmills to be costed using Equation 7-17, with a minimum of two pugmills costed.
Number of Pugmills = [Round Up (Silo Ash Unloading Rate / 150 tph)] (7-17)

If Number of Pugmills ≥ 2, then Number of Pugmills = Number of Pugmills; if Number of Pugmills < 2, then Number of Pugmills = 2.
CBPG indicated that the cost of a 150 tph pugmill is $245,000. Therefore, EPA calculated the pugmill capital costs using Equation 7-18.

Pugmill Capital Cost (2010$) = (Number of Pu gmills × $245,000) × Number of Concrete Silos (or Number of Steel Silos) (7-18)

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A71) for more detail on the development of Equations 7-16 through 7-18.

7.1.5.4 Purchased Equipment Installation Cost
Purchased equipment installation includes th e installation of all equipment, piping, instrumentation/calibrati on, electrical equipment, mechanical equipment, structural supports, insulation, and painting. EPA estimat ed installation capital costs fo r the conversion of wet fly ash handling systems for each plant by multiplying plant purchased equipment costs by installation cost factors developed from vendor and Steam Electric Survey cost data.
To develop an installation cost factor for conveyance equipment, EPA evaluated responses to Question C2-34, Table C-11 (Pur chased Equipment and Purchased Equipment Installation Costs) of the Steam Electric Surve y. Specifically, EPA calculated the ratio of the purchased equipment installati on cost and the purchased equi pment costs; calculated ratios ranged from <0.1 to 7, with a median ratio of a pproximately 0.7. EPA also calculated installation cost ratios based on conveyance cost informa tion provided by United Conveyance Corporation (UCC); these ratios ranged from 1 to 3. Based on this information, EPA selected a Conveyance Install Factor of 2 [E RG, 2013; See Appendix 70].
Using this conveyance installation cost fact or, EPA estimated the installation costs for conveyance equipment using Equation 7-19.
Conveyance Equipment Installation Capital Co st (2010$) = Conveyance Install Factor × Conveyance Equipment Capital Cost (7-19)

where:

Conveyance Install Factor = Factor that accounts for installation cost as a percentage of purchase cost, 2, andChapter 7– Fly Ash Transport Water Cost Methodology

7-13 Conveyance Equipment Capital Cost = Cost for purchasing conveyance equipment (see Section 7.1.5.1 and Equation 7-5).

To develop an installation cost factor for st orage equipment, EPA evaluated responses to Question C2-42, Table C-14 (Purchased Equipment and Purchased Equipment Installation Costs) of the Steam Electric Survey. Specifically, EPA ca lculated the ratio of the purchased equipment installation cost and the purchased equipment costs; calculated ratios ranged from <0.01 to 8.12, with a median ratio of [Redacted]. Although no vendor cost information was available specifically for storage equipment, EPA consider ed the calculated cost ratios derived from conveyance cost information provided by UCC (c alculated ratios ranged from 1 to 3). Based on this information, EPA selected a Storage Inst all Factor of 2 [ERG, 2013; See Appendix 71].

Because the concrete silo costs from Mari etta Silos include the installation of the concrete silo (i.e., a c oncrete silo cannot be c onstructed and shipped, it must be poured on site), the installation capital costs for concrete silos were calculated differently from the installation capital costs for steel silos. For the concrete silo s, the installation costs were calculated excluding the concrete portion of the silo costs.

EPA estimated the installation costs fo r a steel silo using Equation 7-20.
Steel Silo Installation Capital Co st (2010$) = Storage Install Factor × [Steel Silo Capital Cost + Pugmill Capital Cost] (7-20)

where:

Storage Install Factor = Factor that accounts for installation cost as a percentage of purchase cost, 2, Steel Silo Capital Cost = Cost for pur chasing steel silos (see Section 7.1.5.2 and Equation 7-10), and Pugmill Capital Cost = Cost for purchasing pugmills (see Section 7.1.5.3 and Equation 7-18)

EPA estimated the installation costs fo r a concrete silo using Equation 7-21.
Concrete Silo Installation Cap ital Cost (2010$) = Storage Insta ll Factor × [Other Equipment Concrete Silo Capital Cost + Pugmill Capital Cost] (7-21)

where:

Storage Install Factor = Factor that accounts for installation cost as a percentage of purchase cost, 2, Other Equipment Concrete Silo Capital Cost = The unloading and fluidizing equipment costs for a concrete silo (see Section 7.1.5.2 and Equation 7-15), andChapter 7– Fly Ash Transport Water Cost Methodology

7-14 Pugmill Capital Cost = Cost for purchasing pugmills (see Section 7.1.5.3 and Equation 7-18).

EPA estimated installation capital costs for converting wet fly ash handling systems to dry fly ash systems by summing the costs associ ated with installing th e conveyance equipment and the storage equipment.

Total Installation Capital Cost (2010$) = (Conve yance Equipment Installation Capital Cost) + (Storage Installation Capital Cost) (7-22)

where:

Conveyance Equipment Installation Capital Cost = Cost to install the conveyance equipment for a dry vacuum fly ash conversion, (see Equation 7-19), and

Storage Installation Capital Cost = Cost to install the silo eq uipment for a dry vacuum fly ash conversion, which is equal to either the Steel Silo Installation Capital Cost, (s ee Equation 7-20), or the Concrete Silo Installation Capital Cost, (see Equation 7-21), depending on which type of silo is installed for the unit.

7.1.5.5 Engineering Costs
EPA determined engineering overhead costs by multiplying the purchased and installation equipment costs by a factor for c onveyance equipment and silo equipment. EPA determined these factors based on survey respons es to Questions C2-34 (conveyance costs) and C2-42 (silo costs). To determine the Conve yance Overhead Factor, EPA calculated the percentage of engineering overhead costs to the to tal costs, provided in response to Question C2- 34 of the Steam Electric Survey, using E quation 7-23 [ERG, 2013; See Appendix 70].
Ratio = Engineering Overhead Conveyance Costs/(Total Capital Conveyance Costs – Engineering Overhead Conveyance Cost) (7-23)

where:

Engineering Overhead Conveyance Costs = Engineering overhead costs for conveyance equipment provided in Question C2-34, and Total Capital Conveyance Costs = Capital costs for conveyan ce equipment provided in Question C2-34.

EPA calculated the median ratio based on a ll responses, 0.02454, and used that as the Conveyance Overhead Factor.Chapter 7– Fly Ash Transport Water Cost Methodology

7-15 To determine the Silo Overhead Factor, EPA calculated the ratio of engineering overhead costs to the total costs, provi ded in response to Question C2- 42 of the Steam Electric Survey, using Equation7-24 [ERG, 2013; See Appendix 71].
Ratio = Engineering Overhead Silo Costs/(Total Capital Silo Costs – Engineering Overhead Silo Cost) (7-24)

where:

Engineering Overhead Silo Costs = Engineering overhead cost s for silos provided in Question C2-42, and Total Capital Silo Costs = Capital co sts for silos provided in Question C2-42.

EPA calculated the median ratio based on all responses, 0.0082, and used that as the Silo Overhead Factor.
EPA used Equation 7-25 to estima te engineering overhead costs.
Engineering Overhead Costs (2010$) = ([Conveyance Equipment Capital Cost + Conveyance

Equipment Installation Capital Cost] × Conveya nce Overhead Factor) + ([Silo Equipment Capital Cost + Silo Equipment Installation Cost] × Silo Overhead Factor) (7-25)

where:

Conveyance Overhead Factor = Factor that accounts for e ngineering overhead costs as a percentage of purchase and installation costs for the conveyance portion of the system, 0.02454,
Silo Overhead Factor = Factor that a ccounts for engineering overhead costs as a percentage of purchase and installation costs for the silo portion of the system, 0.0082, Conveyance Equipment Capital Cost = Cost for purchasing conveyance equipment (see Section 7.1.5.1 and Equation 7-5), Conveyance Equipment Installation Capital Cost = Cost for installing the conveyance equipment (see Section 7.1.5.4 and Equation 7-19),

Silo Equipment Capital Cost = Cost for purchasing steel or concrete silos (see Section 7.1.5.2 and Equations 7-10 or 7-14 and 7-15), and Silo Equipment Installation Cost = Cost for installing the steel or concrete silo (see Section 7.1.5.4 and Equations 7-20 or 7-21).Chapter 7– Fly Ash Transport Water Cost Methodology

7-16 7.1.6 O&M Cost Methodology
O&M costs for each plant consist of all cost s related to operating and maintaining the conveyance and storage equipment associated wi th the dry vacuum fly ash handling systems. EPA calculated total O&M costs as the sum of conveyance O&M costs and storage O&M costs.
Total conveyance O&M costs for conveyance sy stems were calculated as the sum of the following O&M cost components:

 Conveyance operating labor cost,

 Conveyance maintenance labor cost,

 Conveyance maintenance materials cost,

 Conveyance maintenance outage cost,

 Conveyance chemical purchase cost, and

 Conveyance energy cost.
Total storage O&M costs for dry fly ash storage systems were calculated as the sum of the following O&M cost components:

 Storage operating labor cost,

 Storage maintenance labor cost,

 Storage maintenance materials cost,

 Storage chemical purchase cost, and

 Storage energy cost.

7.1.6.1 Conveyance O&M Costs: Operating Labor
The conveyance operating labor costs include labor costs for ash handling system operators to operate the conveyance systems. EP A estimated unit-level op erating labor costs and then summed these unit-level costs to calculate pl ant-level operating labor costs. EPA calculated operating labor costs for each unit by multiplyin g the operating labor rate by the number of required operator hours per year.
To determine the operating labor rate, EPA eval uated labor rates reported in response to Question C2-36, Table C-12 (Operating Labor Rate & Maintenance Labor Rate) of the Steam Electric Survey. Reported operating labor rates fo r generating units with dry vacuum systems ranged from [Redacted]/hr to $77.00/hr (median of $47.50/hr), while maintenance labor rates ranged from [Redacted]/hr to [Redacted]/hr (m edian of $41.54/hr). As conveyance system O&M may be performed by the same personnel, EPA sele cted an overall operati ng labor rate as the median of the entire Steam Electric Survey data set, $46.36/hr (2010$). EPA evaluated survey responses to Question C2-36, Table C-12 (Ope rating Labor Staffing/Consumption). Reported operator hours per day [Redacted] ranged from 0 .2 to 35 hpd, with a median and average of 2.4 and 6.2 hours per day, respectively. EPA selected th e median value, 2.4 hpd, for use in the cost methodology [ERG, 2013; See Appendix 70].Chapter 7– Fly Ash Transport Water Cost Methodology

7-17 EPA calculated the unit operator hours per year using Equation 7-26.

Conveyance Unit Operator Hours = Conve yance Unit Operator Hours per Day × Number of Operating Days per Year × Number of Unit Vacuum Systems (7-26)

where:

Conveyance Unit Operator Hours per Day = Number of hours per day that the conveyance equipment is operated, 2.4 hpd,

Number of Operating Days per Year = Number of days the genera ting unit is operated per year (see Section 4.2.2), and
Number of Unit Vacuum Systems = Number of unit vacuum systems costed (see Section 7.1.5.1 and Equation 7-2).

EPA calculated the Conveyance Unit Oper ating Labor Cost using Equation 7-27.
Conveyance Unit Operating Labor Cost (2010$/ yr) = Conveyance Operating Labor Rate × Conveyance Unit Operator Hours (7-27)

where:

Conveyance Operating Labor Rate = $46.36/hr (2010$), and

Conveyance Unit Operator Hours = Number of hours per year that the conveyance equipment is operated, (see Equation 7-26).

EPA estimated the total Conveyance Operati ng Labor Costs at the plant by summing the labor hours for all conveyance units at the plant using Equation 7-28.
Conveyance Operating Labor Cost (2010$/yr) = ∑ Conveyance Unit Operating Labor Cost (7-28)

7.1.6.2 Conveyance O&M Costs: Maintenance Labor
The maintenance labor costs include labor costs for plant staff to maintain the conveyance systems. EPA estimated unit-level ma intenance labor costs and then summed these unit-level costs to calculate plant-level maintenance labor costs. EPA calculated maintenance labor costs for each unit by multiplying the mainte nance labor rate by the number of required maintenance hours per year.
Because conveyance system O&M may be performed by the same personnel, EPA selected an overall operating and maintenan ce labor rate, as disc ussed in Section 7.1.6.6 ($46.36/hr). EPA calculated unit maintenan ce hours per year by multiplying the unit maintenance hours per year by the number of unit vacuum systems costed. EPA determined maintenance hours per year based on an evalua tion of responses to Question C2-36, Table C-12Chapter 7– Fly Ash Transport Water Cost Methodology

7-18 (Maintenance Labor Staffing/Consumption) of the Steam Electric Survey. Reported maintenance hours per year [Redacted] ranged from 40 to 7,300 hours per year for ash handling system maintenance, with a median and average of 413 and 963 hours per year, respectively. EPA selected an overall unit maintenance hours per year as the median of the Steam Electric Survey data set, 413 hours per year [ERG, 2013; See A ppendix 70]. EPA determined the number of unit vacuum systems costed as described in Section 7.1.5.1.
EPA calculated the Conveyance Unit Mainte nance Labor Cost using Equation 7-29.
Conveyance Unit Maintenance Labor Cost (2010$/ yr) = Conveyance Maintenance Labor Rate × Conveyance Maintenance Hours × Number of Unit Vacuum Systems (7-29)

where:

Conveyance Maintenance Labor Rate = $46.36/hr (2010$),

Conveyance Maintenance Hours = 413 hpy, and

Number of Unit Vacuum Systems = Number of unit vacuum systems costed (see Section 7.1.5.1 and Equation 7-2).

EPA calculated the total Conveyance Maintena nce Labor Costs per plant using Equation 7-30.
Conveyance Maintenance Labor Cost (2010$/yr) = ∑ Conveyance Unit Maintenance Labor Cost (7-30)

7.1.6.3 Conveyance O&M Costs: Energy Cost
Fly ash conveyance systems require energy to operate the mechanical vacuum pumps that move air to entrain and convey dr y fly ash particles away from th e hoppers to the storage silos.
EPA estimated vacuum pump energy consumption (in kilowatt hours per year (kWh/yr)) as a function of pump horsepower. EPA determ ined unit-level vacuum pump horsepower based on the recalculated unit fly ash c onveyance rate (determined as described in Section 7.1.5.1 and Equation 7-3) using the following step func tion provided by CBPG [E RG, 2013; See Appendix 69]:

 For Recalculated Unit Wet Fly Ash Conveyance Rate ≤ 11 tph:

- Vacuum Pump Horsepower = 75 hp

 For Recalculated Unit Wet Fly As h Conveyance Rate > 11 tph and ≤ 21 tph:

- Vacuum Pump Horsepower = 125 hp

 For Recalculated Unit Wet Fly As h Conveyance Rate > 21 tph and ≤ 32 tph:

- Vacuum Pump Horsepower = 200 hpChapter 7– Fly Ash Transport Water Cost Methodology

7-19  For Recalculated Unit Wet Fly Ash Conveyance Rate > 32 tph:

- Vacuum Pump Horsepower = 250 hp
EPA summed the unit-level energy requireme nts to calculate plant-level energy consumption using Equations 7-31 and 7-32.
Conveyance Unit Energy Consumption (kWh/yr) = Vacuum Pump Horsepower × 0.745699 kW/HP × Number of Pumps × Number of Unit Vacuum Systems × Unit Conveying Time × Unit Operating Days (7-31)

where:

Vacuum Pump Horsepower = Pump Horsepower for Recalculated Unit Fly Ash Conveyance Rate, Number of Pumps = Numb er of vacuum pumps required to operate the conveyance system, two, per input from CBPG,
Number of Unit Vacuum Systems = Number of unit vacuum systems costed (see Section 7.1.5.1 and Equation 7-2), Unit Conveying Time = 12 hpd, and
Unit Operating Days = Number of days each generating unit operated per year (see Section 4.2.1).

Conveyance Energy Consumption (kWh/yr) = ∑ Conveyance Unit Energy Consumption (7-32)

To calculate energy costs, EPA multiplied the conveyance energy consumption by the average national energy cost of 4.05 cents pe r kWh (2009$), as determined based on data reported by the U.S. Energy Information Admini stration in Table 8.2 of the Electric Power Annual 2009 for fossil plants in the United Stat es [U.S. DOE, 2011]. As the energy cost was provided in 2009 dollars, EPA adjusted the co st basis to 2010 dollars using the 2009 and 2010 RSMeans Historical Cost Indices (18 0.1 and 183.5, respectively) [RSMeans, 2011].
Conveyance Energy Cost (2010$/yr) = Nati onal Energy Cost × Conveyance Energy Consumption × (2010 Cost Index/2009 Cost Index) (7-33)

where:

National Energy Cost = $0.0405/kWh (2009$),
Conveyance Energy Consumption = Plant-level energy consump tion associated with the conveyance equipment, 2009 Cost Index = 180.1, and

2010 Cost Index = 183.5.Chapter 7– Fly Ash Transport Water Cost Methodology

7-20 For the purpose of estimating non-water qu ality environmental impacts, EPA also converted energy consumption in kWh/yr to energy load in MW using Equation 7-34.
Conveyance Unit Energy Load (MW) = C onveyance Unit Energy Consumption / (Unit Conveying Time × Unit Operating Days) × 1 MW / 1000 kW (7-34)

where:

Conveyance Unit Energy Consumption = The annual unit-specif ic energy consumption associated with conveyance in kWh/yr, Unit Conveying Time = 12 hpd, and
Unit Operating Days = Number of days each generating unit operated per year (see Section 4.2.2).

EPA summed the unit-level energy load for all units at the plant to calculate the plantlevel energy consumption.
Conveyance Energy Load for Plant (MW) = ∑ Conveyance Unit Energy Load (7-35)

7.1.6.4 Conveyance O&M Costs: Maintenance Materials

EPA included costs for maintenance materials, such as routine replacement of materials and equipment due to consumption or wear a nd tear. EPA developed Equation 7-36 to estimate maintenance material costs using the O&M cost s reported in response to the Steam Electric Survey for generating units with dry vacuum sy stems. Specifically, EPA evaluated responses to Question C2-36, Table C-12 (Maintenance Materials) of the Steam Electric Survey, calculating the ratio of reported maintenance material costs to the total sum of operating labor, maintenance labor, energy, and other O&M cost s. EPA selected the median ratio of 0.332 as the conveyance maintenance materials cost fact or [ERG, 2013; See Appendix 70].
Conveyance Maintenance Materials Cost (2010$/y r) = Conveyance Maintena nce Materials Cost Factor × (Conveyance Operating Labor Cost + Conveyance Maintenance Labor Cost + Conveyance Energy Cost) (7-36)

where:

Conveyance Maintenance Materials Cost Factor = Factor that accounts for mate rial costs as a percentage of O&M cost, 0.332,

Conveyance Operating Labor Cost = Includes labor costs for ash handling system operators to operate the conveyance systems (see Section 7.1.6.1 and Equation 7-28), Conveyance = Includes labor costs a ssociated with maintaining theChapter 7– Fly Ash Transport Water Cost Methodology

7-21 Maintenance Labor Cost conveyance systems (see Section 7.1.6.2 and Equation 7-30), and Conveyance Energy Cost = Energy costs associated w ith operating the mechanical vacuum pumps (see Section 7.1.6.3 and Equation 7-32).

7.1.6.5 Conveyance O&M Costs: Maintenance Outage
EPA considered the impact of plant outages required to maintain dry fly ash handling systems compared to wet fly ash handling system s. EPA reviewed responses to Question C2-24 of the Steam Electric Survey regarding the numbe r of outage days for all dry systems. Based on these data, EPA determined that for dry syst ems, there were 1.42 days of outage for 178,089 days in operation, and for wet systems, ther e were 0.58 days of outage for 87,482 days in operation. EPA also compared the number of out age days to the number of operating days on a plant-level for all dry and wet systems and determ ined that the median number of outage days was zero for both the wet and dry systems. EPA conc luded that the relative days of outage for a dry vacuum system is comparable to the relative days of outage for a wet system on an industryand plant-level basis. Therefore, there are no increased costs associated with maintenance outages for the dry vacuum systems, relative to wet sluicing systems.

7.1.6.6 Storage O&M Costs: Operating Labor
The storage operating labor cost s include labor costs for ash handling system operators to operate the water trucks used for dust suppression and the fly ash intermediate storage systems. EPA calculated the storage operating labor cost using Equation 7-37.

Storage Operating Labor Cost = Operating Labor Cost, Water Trucks + Operating Labor Cost, Intermediate Storage Systems (7-37)

Operating Labor Cost, Water Trucks EPA calculated operating labor costs for operating water trucks for each plant by multiplying the operating labor rate by the number of required operator hours per day, the number of operating days per year, and the num ber of silos costed. To determine the operating labor rate, EPA selected the national average lo aded labor rate of $18.47/ hr (2009$) for industrial truck/tractor operators as reported by the U.S. Bureau of Labor Statistics [U.S. Bureau of Labor Statistics, 2010]. EPA determined operator hours per day based on an evaluation of responses to Question C2-44, Table C-15 (Operating Labor (Wat er Trucks Only) Staffing/Consumption) of the Steam Electric Survey. Reported operator hou rs per day to operate the water trucks [Redacted] ranged from [Redacted] hpd, with a median of [Redacted] hpd. EPA selected an overall unit operator hours per da y as the median of the survey data set, [Redacted] hpd. EPA calculated the number of operating days per year as the number of calendar days generating units operated in 2009 on a plant-level as determined based on responses to Question A6-1, Table A-8 (Steam Electric Units) of the survey, w ith a maximum of 260 days per year. 47 The number of

47 EPA’s analysis of maxing out the number of calendar days that generating units operated in 2009 at 260 days per year does not directly compare to the assumption that wate r trucks will only be operated on weekdays. For example,Chapter 7– Fly Ash Transport Water Cost Methodology

7-22 silos costed was determined as described in Section 7.1.5.2. As the labor rate was provided in 2009 dollars, EPA adjusted the cost basis to 2010 dollars using the 2009 and 2010 RSMeans Historical Cost Indices (180.1 and 183.5, respec tively) [RSMeans, 2011]. EPA calculated water truck operating labor costs using Equa tion 7-38 [ERG, 2013; See Appendix 71].
Operating Labor Costs, Water Trucks = Wate r Truck Operating Labor Rate x Water Truck Operator Hours per Day x Water Truck Oper ating Days per Year x Number of Silos (7-38)

where:

Water Truck Operating Labor Rate = National average loaded labor rate of $18.47/hr (2009$) for industrial truc k/tractor operators as reported by the U.S. Bureau of Labor of Statistics, Water Truck Operator Hours per Day = The overall unit operator hours per day as the median of the survey data set, [Redacted], Water Truck Operating Days per Year = The plant-level number of calendar days generating units operated in 2009 as determined by the operating days for each generating unit at the plant (see Section 4.2.2) with a maximum of 260 days per year, and Number of Silos = Number of silos, either steel or c oncrete, required to store the dry fly ash (see Section 7.1.5.2 and Equation 7-8 or 7-12).

Operating Labor Cost, Intermediate Storage Systems EPA calculated operating labor costs to operate the fly ash intermediate storage systems for each plant by multiplying the operating labor rate by the number of required operator hours per year and the number of silos costed. To de termine the operating labor rate, EPA evaluated labor rates reported in response to Question C2 -44, Table C-15 (Operating Labor (All Other) Rate & Maintenance Labor Rate) of the Steam Electric Survey. Reporte d operating labor rates for operating fly ash silos ranged from $14.00/ hr to $77.00/hr (median of $39.00/hr), while maintenance labor rates for maintaining fly ash silos ranged from $23.60/hr to $77.00/hr (median of $40.00/hr). As intermediate storage system O&M may be performed by the same personnel, EPA decided not to distinguish between O&M labor rates and instead sel ected an overall labor rate as the median of the entire questi onnaire dataset, $40.00/hr (2010$). EPA calculated operating labor costs for the storage of fly ash using Equation 7-39 [ERG, 2013; See Appendix 71].
Operating Labor Cost, Intermediate Storage Sy stems (2010$/yr) = Storage Operating Labor Rate × Storage Operator Hours Per Year × Number of Silos (7-39)

a plant may operate 260 days during th e year, in which case EPA assumed that the water trucks were operating on all 260 weekdays. However, for any weekend day that the plant was operating, EPA exp ects that the water trucks weren’t really operating and therefore, EPA is likely ove restimating the number of days that the water trucks operated for that plant.Chapter 7– Fly Ash Transport Water Cost Methodology

7-23 where:

Storage Operating Labor Rate = Storage labor rate, $40.00/hr (2010$),

Storage Operator Hours Per Year = Number of hours a worker is needed to operate the intermediate storage equipment, 352 hpy, and Number of Silos = Number of silos, either steel or c oncrete, required to store the dry fly ash (see Section 7.1.5.2 and Equation 7-8 or 7-12).

7.1.6.7 Storage O&M Costs: Maintenance Labor

Maintenance labor costs include labor costs for plant staff to maintain the intermediate storage systems. EPA calculated maintena nce operating labor costs by multiplying the maintenance labor rate by the number of require d maintenance hours per y ear and the number of silos costed. EPA selected a maintenance labor rate equal to the operating labor rate, as discussed in Section 7.1.6.6 ($40.00/hr). EPA determined ma intenance hours per year based on responses to Question C2-44, Table C-15 (Maintenance Labor Staffing/Consumption) of the Steam Electric Survey. The reported maintenance hours per ye ar for 33 silos ranged from [Redacted] to [Redacted] hours per year, with a median and average of 295 and 529 hours per year, respectively. EPA selected an overall unit maintenance hours per year as the median of the questionnaire data set, 295 hours per year [ERG, 2013; See Appendix 71]. EPA calculated the storage maintenance labor costs using Equation 7-40.
Storage Maintenance Labor Cost (2010$/yr) = Storage Maintenance Labor Rate × Storage Maintenance Hours Per Year × Number of Silos (7-40)

where:

Storage Maintenance Labor Rate = $40.00/hr (2010$) (see Section 7.1.6.6),

Storage Maintenance Hours Per Year = Number of hours a worker is needed to maintain the intermediate storage system, 295 hpy, and Number of Silos = Number of silos, either steel or c oncrete, required to store the dry fly ash (see Section 7.1.5.2 and Equation 7-8 or 7-12)

7.1.6.8 Storage O&M Costs: Energy Cost
Energy requirements for fly ash intermediate storage consist of th e energy required to operate the pugmills for the costed silos. EP A used Equation 7-41 to estimate pugmill energy consumption (in kWh/yr) [ERG, 2013; See Appendix 71].
Energy Consumption, Intermediate Storage Systems (kWh/yr) = Pugmill Horsepower × 0.745699kW/HP × Number of Pugmills × Op erating Time × Operating Days (7-41)Chapter 7– Fly Ash Transport Water Cost Methodology

7-24 where:

Pugmill Horsepower = 50 hp, based on assumption that a 150 tph pugmill conditioning fly ash with a de nsity of 45 lb/ft3 requires 50 hp, Number of Pugmills = Number of required pugmills (see Section 7.1.5.3 and Equation 7-17), Operating Time = Hours per day the pugmill is conditioning ash; EPA assumed ash conditioning is 16 hpd, and Operating Days = The plant-level number of calendar days generating units operated in 2009 as determined by the operating days for each generating un it (see Section 4.2.2) with a maximum of 260 days per year.

To calculate energy costs, EPA multiplied the plant energy consumption by the national average energy cost of 4.05 cents per kWh (2009$), based on data reported by the U.S. Energy Information Administration in Table 8.2 of the Electric Power Annual 2009 for fossil plants in the United States [U.S. DOE, 2011]. As the energy cost was provide d in 2009 dollars, EPA adjusted the cost basis to 2010 dollars using th e 2009 and 2010 RSMeans Historical Cost Indices (180.1 and 183.5, respectively) [RSMeans, 2011].
Energy Cost, Intermediate Storage System s (2010$/yr) = National Energy Cost × Energy Consumption, Intermediate Storage Syst ems × (2010 Cost Index/2009 Cost Index) (7-42)

where:

Energy Consumption, Intermediate Storage Systems = Annual energy consumed by the intermediate storage equipment (i.e., pugmills) in kWh/yr,

National Energy Cost = $0.0405/kWh (2009$),

2009 Cost Index = 180.1, and

2010 Cost Index = 183.5.

For the purpose of estimating non-water qu ality environmental impacts, EPA also converted energy consumption in kWh/yr to energy load in MW using Equation 7-43.
Energy Load, Intermediate Storage Systems (MW) = Energy Consumption, Intermediate Storage Systems / (Operating Time × Operating Days) × 1 MW / 1000 kW (7-43)

where:

Energy Consumption, = Annual energy cons umed by the intermediate storageChapter 7– Fly Ash Transport Water Cost Methodology

7-25 Intermediate Storage Systems equipment (i.e., pugmills) in kWh/yr,

Operating Time = Hours per day the pugmill is conditioning ash; EPA assumed ash conditioning is 16 hpd, and Operating Days = The plant-level number of calendar days generating units operated in 2009 as determined by the operating days for each generating un it (see Section 4.2.2) with a maximum of 260 days per year.

7.1.6.9 Storage O&M Costs: Maintenance Materials

Maintenance materials costs include costs fo r routine material replacement, equipment replacement due to consumption or wear and tear , and fuel for the water trucks. EPA calculated Maintenance Materials Storage O&M Costs using Equation 7-44

Maintenance Material Cost = Routine Mainte nance Materials Cost + Water Truck Fuel Cost (7-44)

Routine Maintenance Materials Cost EPA included costs for maintenance materials, such as routine material replacement and equipment replacement due to consumption or w ear and tear. EPA developed Equation 7-45 to estimate maintenance material costs using the O& M costs reported in response to Question C2- 44, Table C-15 (Maintenance Materials) of the St eam Electric Survey. EPA calculated the ratio of reported maintenance material costs to the total sum of operating la bor, maintenance labor, energy, and other O&M costs. EPA selected th e median ratio of 0.20 as the maintenance materials cost factor [E RG, 2013; See Appendix 71].

Routine Maintenance Materials Cost (2010$/yr) = (Storage Main tenance Material Cost Factor × [Storage Operating Labor Cost + Storage Maintenance Labor Cost + Storage Energy Cost]) (7-45)

where:

Storage Maintenance Material Cost Factor = Factor that accounts for mate rials cost as a percentage of O&M cost, 0.20, Storage Operating Labor Cost = Operating labor costs to operate the fly ash intermediate storage sy stems for each plant (see Section 7.1.6.6 and Equation 7-37), Storage Maintenance Labor Cost = Labor costs for plant staff to maintain the intermediate storage systems (see S ection 7.1.6.7 and Equation 7-40), and Energy Cost, Intermediate Storage Systems = Cost to operate the mechanical vacuum pumps (see Section 7.1.6.8 and Equation 7-42).Chapter 7– Fly Ash Transport Water Cost Methodology

7-26 Water Truck Fuel Costs EPA used the Equation 7-46 to estimate the wate r truck fuel cost for the trucks spraying water around the silo and landfill area for dust co ntrol based on fuel cost data of $2.391/gal from the Regulatory Impact Analysis for EPA’s Propos ed RCRA Regulation of Coal Combustion Residues (CCR) Generated by the Electric Utility Industry [ORCR, 2010]. EPA used the water truck operator hours per day and water truck opera ting days described in Section 7.1.6.6 for the water truck operating labor cost. EPA assumed that the water truck would travel a total of 3.6 miles every hour based on distance to an on-site landfill, as discussed in Section 5.3.3.1. EPA estimated the average gas mileag e, 7.5 miles/gallon, using data fr om a water truck vendor [ERG, 2013; See Appendix 71]. The number of water trucks was determined using the methodology described in Section 7.1.9.
Water Truck Fuel Cost (2010$/yr) = ([Water Tr uck Operator Hours Per Day × Water Truck Operating Days × Water Truck Distance Per Hour / Water Truck Gas Mileage × Water Truck Fuel Cost] × Total Number of Additional Water Trucks) (7-46)

where:

Water Truck Operator Hours Per Day = [Redacted] (see Section 7.1.6.6),

Water Truck Operating Days = Number of calendar days generating units operated in 2009 on a plant level with a maximum of 260 days per year (see Section 7.1.6.6),
Water Truck Distance Per Hour = 3.6 miles/hour,

Water Truck Gas Mileage = 7.5 miles/gal,

Water Truck Fuel Cost = $2.391/gal, and

Total Number of Additional Water Trucks = Number of additional water trucks required for dust suppression at the plant (excluding those already onsite) for the additional as h handled dry after the conversion (see Section 7.1.9 and Equation 7-53).

7.1.7 Fly Ash Disposal Cost
EPA determined the cost of dry fly ash dis posal based on the amount of fly ash converted from wet handling to dry handling. Because EPA has costed the ash to be conditioned in the pugmills prior to disposal, EPA determined the final moisture content of the fly ash based on responses to Question C2-25, Table C-6 (Per cent Moisture of the Fly Ash Entering the Destination) of the Steam Electric Survey. The av erage moisture content reported by plants that transport fly ash by truck to a landfill was 13 pe rcent. Based on this information, EPA calculatedChapter 7– Fly Ash Transport Water Cost Methodology

7-27 the amount of fly ash to be disposed, accounting for ash conditioning, using Equation.7-47 [ERG, 2013; See Appendix 72].
Conditioned Dry Fly Ash fo r Disposal (tons/yr) = [ ∑ (Unit Wet Fly Ash Generation Rate × Unit Operating Days) ] / (1 - Pugmill Moisture Content) (7-47)

where:

Unit Wet Fly Ash Generation Rate = Amount of wet fly ash produ ced by the generating unit in tpd (see Section 4.2.2), Unit Operating Days = Number of da ys each generating unit operated in 2009 (see Section 4.2.2), and Pugmill Moisture Content = 13 percent.

EPA also calculated conditioned fl y ash density using Equation 7-48.
Conditioned Dry Fly Ash Density = [ (Pugmill Moisture Content) × (Density of Water)] + [(Density of Fly Ash) × (1 – Pugmill Moisture Content)] = 47.3 lb/ft 3 (7-48)

where:

Pugmill Moisture Content = 13 percent,

Density of Water = 62.4 lb/ft 3 , and
Density of Fly Ash = 45 lb/ft 3 (dry weight).

The conditioned fly ash density is used to ca lculate the amount of wet fly ash plants will need to transport and dispose of in a landf ill. Sections 5.3 and 5.4 discuss costs for the transportation and disposal of the dry fly ash generated by converting wet fly ash handling systems to dry vacuum fly ash handling systems.

7.1.8 Impoundment Operation Costs
Section 5.5 discusses cost savings associat ed with ceasing operation of combustion residual surface impoundments.

7.1.9 Recurring Costs
EPA calculated 10-year recurring costs asso ciated with operating the water trucks involved with dust control around th e fly ash silo and landfills. EP A calculated the total 10-year recurring costs by determining the number of wa ter trucks required for each plant based on ash tonnage, the cost of the water trucks, a nd the expected life of water trucks.Chapter 7– Fly Ash Transport Water Cost Methodology

7-28 EPA determined the number of water trucks required at each plant based on the wet and dry fly ash tonnage generated at the plant. B ecause some plants operate both wet and dry handling systems, EPA used the dry fly ash tonnag e at the plant to estimate the number of water trucks the plant already operates. The unit fly ash dry generation rate (in tpd) and dry conveying days (in dpy) were determined for each genera ting unit at each plant from the responses to Question C2-1, Table C-2 of the Steam Electric Survey.
Plant-Level Dry Fly Ash (tons) = ∑ (Unit Dry Fly Ash Genera tion Rate x Dry Conveying Days) (7-49)

where:

Unit Dry Fly Ash Generation Rate = The amount of dry fly ash produced by the generating unit in tpd (see Section 4.2.2), and Dry Conveying Days = The number of days dry fly ash was conveyed at each generating unit (see Section 4.2.2).

EPA determined the number of water trucks the plant already operates based on the plantlevel dry fly ash (in tons, from Equation 7-49) using the step function shown in Equation 7-50, found in ORCR’s Regulatory Impact Analysis for EPA’s Proposed RCRA Regulation of Coal Combustion Residues (CCR) Generated by the Electric Utility Industry [ORCR, 2010]:

Number of Water Trucks at Plant = (7-50)

 For Plant-Level Dry Fly Ash (tons) ≤ 391,000:
Number of Water Trucks at Plant = One Truck

 For Plant-Level Dry Fly Ash (tons) > 391,000 and ≤ 1,173,000:
Number of Water Trucks at Plant = Two Trucks

 For Plant-Level Dry Fly Ash (tons) > 1,173,000 and ≤ 1,955,000:
Number of Water Trucks at Plant = Three Trucks

 For Plant-Level Dry Fly Ash (tons) > 1,955,000:
Number of Water Trucks at Plant = Four Trucks
To determine the number of additional water trucks required for dust suppression, EPA calculated the total number of water trucks needed by the plant for all fly ash generated, wet and dry. EPA calculated the total fly ash tonnage using Equation 7-51 a nd determined the number of water trucks needed using the step function pr esented in Equation 7-52, which is similar to Equation 7-50.
Plant-Level Total Fly Ash (tons) = Plant Le vel Dry Fly Ash (tons) + [Unit Wet Fly Ash Generation Rate x Wet Conveying Days]) (7-51)Chapter 7– Fly Ash Transport Water Cost Methodology

7-29 where:

Plant-Level Dry Fly Ash = The total dry fly ash tonnage (in a dry weight basis) generated at the plant on an annual basis (see Equation 7-49), Unit Wet Fly Ash Generation Rate = The amount of wet fly ash produced by the generating unit in tpd (see Section 4.2.2), and Wet Conveying Days = The number of da ys wet fly ash is conveyed at each generating unit (see Section 4.2.2).

Number of Water Trucks Needed = (7-52)

 For Plant-Level Total Fly Ash (tons) ≤ 391,000:
Number of Water Trucks at Plant = One Truck

 For Plant-Level Total Fly Ash (tons) > 391,000 and ≤ 1,173,000:
Number of Water Trucks at Plant = Two Trucks

 For Plant-Level Total Fly Ash (tons) > 1,173,000 and ≤ 1,955,000:
Number of Water Trucks at Plant = Three Trucks

 For Plant-Level Total Fly Ash (tons) > 1,955,000:
Number of Water Trucks at Plant = Four Trucks
After determining the number of trucks needed for all fly ash (wet and dry) generated at the plant, EPA subtracted the total number of water trucks the plant already operates from the total number of water trucks needed. EPA used Equations 7-53 and 7-54 to calculate the total recurring costs for water tr ucks at the plant-level.

Total Number of Additional Water Trucks = Nu mber of Water Trucks Needed – Number of Water Trucks at Plant (7-53)

Recurring Cost (2010$) = Total Number of Ad ditional Water Trucks × Cost of Water Truck (7-54)

where:

Cost of Water Truck = $104,500 (in 2010$).

From vendor contact information, EPA determin ed that the average life of a water truck used for dust suppression is 10 years. Therefore, the recurring costs for th e water trucks at the plant are estimated to be the total water truck costs, every 10 years.Chapter 7– Fly Ash Transport Water Cost Methodology

7-30 7.1.10 Fly Ash Outage Costs
EPA considered the impact of a plant outage required to install the dry fly ash handling system. Based on an evaluation of vendor and survey information, EPA determined that connecting the fly ash handling system installati ons can be completed during regularly scheduled outages. The entire conveyance and storage system s can be constructed a nd installed prior to a scheduled outage, and then the necessary tie-in can occur during a regularly scheduled outage. Therefore, there are no costs for plant outages during installation of th e dry fly ash handling system.

7.1.11 Results and Summary of Costs

As described in Section 2.1.4, EPA’s cost m odel generated plant-le vel compliance costs for converting wet fly ash handling systems to dr y vacuum systems. The cost output generated by the model includes a breakout of specific capital and O&M cost elements, including equipment costs, installation costs, operating la bor, maintenance labor, and energy costs. The output also includes costs for the common cost elements. Chapter 5 discusses these common cost elements that include transporta tion and disposal of combustion re sidual. A list of the plant-level costs for the dry fly ash handling technol ogy option is included in the appendix.

7.2 V ACTOR T RUCK C OLLECTION
For oil-fired units that operate fewer than 100 days per year, EPA used a different approach for estimating capital and O&M costs becau se of the small amount of fly ash generated from these units. This approach included piping the fly ash away from the primary particulate collection system using a vactor truck operated by a third-party contractor.

7.2.1 Technology Description
For oil-fired generating units that operate fewer than 100 days per year, EPA assumed a conversion identical to that report ed by an oil-fired power plant in response to the Steam Electric Survey. This conversion consisted of installing a new piping system from the existing fly ash collection hoppers, underneath the electrostatic precip itator (ESP) or fabric filter (i.e., baghouse), to a roll-off vacuum container. During ope ration, ash accumulates in the existing fly ash collection hoppers. On an as needed basis (i .e., when the collection hoppers begin to reach capacity), a contract vendor uses a vactor truck vacuum pump to pull the fly ash stored in the collection hoppers throu gh the new piping system into the roll-off vacuum container. The vendor then transports the roll-off vacuum container to an off-site landfill for ash disposal.

7.2.2 Population Costed
[Redacted] oil-fired units at [Redacted] pl ants reported generating fly ash in 2009. Of these, [Redacted] wet sluiced their fly ash less th an 100 days out of the year, discharged the fly ash sluice to surface water, and reported no plan s to end or change operations. EPA estimated costs for converting these [Redacted] generating un its from wet fly ash handling systems to a dryChapter 7– Fly Ash Transport Water Cost Methodology

7-31 vactor truck system. 48 The remaining oil-fired units, those wet sluicing their ash more than 100 days out of the year, are included in the population presented in Section 7.1.2.

7.2.3 Input Table
Oil-fired units operating less than 100 days per year are included in the “Fly Ash Input Table” described in Section 7.1.4. The oil-fired units wi ll be flagged in a sepa rate field identified as ”Oil_fired” and the operating days for each ge nerating unit are listed in the ”Operating Days” field. All other fields of data contained in the “Fly Ash Input Table” will be completed for the oil-fired units. A copy of the “Fly Ash Input Table” is located in the appendix.

7.2.4 Capital Cost Methodology
EPA calculated total capital costs for each plant as the sum of the purchase and installation of the new pipe to convey dry fly ash from the fly ash collection hoppers to the rolloff vacuum container. EPA used Equation 7-55 to calculate the total capital cost.
Total Capital Cost = Vactor Conveyance E quipment Cost + Vactor Engineering Costs (7-55)

7.2.4.1 Total Capital Cost: Vactor Conveyance Equipment
EPA developed the conveyance capital cost e quations based on total capital cost data provided in response to the Steam Electric Survey by one oil-fire d power plant that converted from wet sluicing to a vactor truck system. EPA used Equation 7-56 to estimate conveyance costs for oil-fired units operati ng less than 100 days per year.
Unit Vactor Conveyance Cost (2010$) = ($13,90 0/0.53 tpd) × (Unit Wet Fly Ash Generation Rate) (7-56)

where:

Unit Wet Fly Ash Generation Rate = The amount of wet fly ash produced by the generating unit in tpd (see Section 4.2.2).

EPA calculated plant-level vactor conveyan ce costs by summing the unit-level costs at each plant, according to Equation 7-57.
Plant Vactor Conveyance Cost (2010$) = ∑ Unit Vactor Conveyance Cost (7-57)

7.2.4.2 Total Capital Cost: Vactor Engineering Costs
Engineering costs include costs for proce ss design and general engineering, cost engineering, consulting fees, supervision, and inspection. EPA assumed that the engineering costs incurred for oil-fired vact or truck conversions include th e owner’s overhead engineering

48 No plants are evaluated for this population when the group of plants excluding oil-fired unts and units with a capacity of 50 MW or less is evaluated.Chapter 7– Fly Ash Transport Water Cost Methodology

7-32 costs. EPA determined engineering overhead co sts by multiplying the purc hased and installation equipment costs by a factor for conveyance equipment and silo equipment. EPA determined these factors based on responses to Questions C2 -34 (conveyance costs) in the Steam Electric Survey. To determine the Conveyance Overhead Factor, EPA calculated the percentage of engineering overhead costs to the total costs pr ovided in the survey responses using Equation 7-58.
Percentage = Engineering Overhead Cost s / (Total Capital Conveyance Costs – Engineering Overhead Cost) (7-58)

where:

Vactor Engineering Overhead Costs = Engineering overhead costs for vactor conveyance equipment provided in survey Question C2-34, and Total Capital Vactor Conveyance Costs = Capital costs for vactor conveyance equipment provided in survey Question C2-34.

EPA calculated the median of all the pe rcentages, 0.02454, and used that as the Conveyance Overhead Factor.
EPA used Equation 7-59 to es timate engineering costs.
Vactor Engineering Costs (2010$) = Plant Conve yance Capital Cost × Conveyance Overhead Factor (7-59)

where:

Conveyance Overhead Factor = Factor that accounts for e ngineering overhead costs as a percentage of purchase and installation costs for the conveyance portion of the system, 0.02454, and Plant Conveyance Capital Cost = Cost for purchasing vactor conveyance equipment (see Section 7.2.4.1 and Equation 7-57).

7.2.5 O&M Cost Methodology
EPA calculated total O&M costs for each plant as the sum of all costs related to operating and maintaining the conveyance and storage equi pment required to convert wet fly ash handling systems to dry fly ash handling systems. EPA used Equation 7-60 to ca lculate the total O&M costs for oil-fired units operati ng less than 100 days per year.

Total O&M Cost, Oil Units < 100 Days = Plant Vactor Conveyance O&M Cost + Plant Vactor Storage O&M Cost (7-60)Chapter 7– Fly Ash Transport Water Cost Methodology

7-33 where:

Plant Vactor Conveyance O&M Cost = Plant-level vactor conveya nce O&M costs (see Section 7.2.5.1), and Plant Vactor Storage O&M Cost = Plant-level vactor stor age O&M costs (see Section 7.2.5.2).

7.2.5.1 Total O&M Costs: Vactor Conveyance O&M Cost
Conveyance O&M costs consist of the contract vendor’s fee for annual collection of the dry fly ash into the roll-off vacuum container. EPA developed the O&M cost equations based on O&M cost data provided in re sponse to the Steam Electric Surv ey by one oil-fired power plant that converted from wet sluici ng to a vactor truck system.
Unit Conveyance O&M Cost (2010$/yr) = ( $75,105/0.53 tpd × 30 days) × Unit Wet Fly Ash Generation Rate × Unit Operating Days (7-61)

where:

Unit Wet Fly Ash Generation Rate = The amount of wet fly ash produced by the generating unit in tpd (see Section 4.2.2), and Unit Operating Days = Number of da ys each generating unit operated in 2009 (see Section 4.2.2).

EPA calculated plant-level vactor conveya nce O&M costs by summing the unit-level costs at each plant, according to Equation 7-62.
Plant Vactor Conveyance O&M Cost (2010$/yr) = ∑ Unit Conveyance O&M Cost (7-62)

All other plant O&M costs associated with th e dry fly ash conveyance are assumed to be captured by the vendor’s fee, negligible, or no t applicable (i.e., operating labor, maintenance labor, maintenance materials, chemical purchase, and energy).

7.2.5.2 Total O&M Costs: Vactor Storage O&M Cost
Storage O&M costs consist of the rental f ee for the roll-off vacuum container. EPA developed a roll-off vacuum container rental rate of $300 per week based on O&M cost data provided in response to the Steam Electric Survey by one oil-fire d power plant that converted from wet sluicing to a storage vactor truck syst em. Also based on survey data, EPA assumed that each day of generating unit operation per year corresponds to one week of roll-off vacuum container rental, subject to a maximum of a fu ll-year rental. The number of unit operating days per year was determined based on responses to Question A6-1, Table A-8 (Steam Electric Units) of the Steam Electric Survey.
For Unit Operating Days ≤ 52 dpy, EPA used Equation 7-63 to calculate the storage O&M cost.Chapter 7– Fly Ash Transport Water Cost Methodology

7-34 Unit Vactor Storage O&M Cost ( 2010$) = $300 × Unit Operating Days (7-63)

where:

Unit Operating Days = Number of days each generating unit operated per year (see Section 4.2.2).

For Unit Operating Days > 52 dpy, EPA used Equation 7-64 to calculate the storage O&M cost.
Unit Vactor Storage O&M Cost (2010$) = $300 × 52 ( 7-64 )

EPA calculated plant-level vactor storage O& M costs by summing the unit-level costs at each plant, according to Equation 7-65.
Plant Vactor Storage O&M Cost (2010$/yr) = ∑ Unit Vactor Storage O&M Cost (7-65)

All other plant O&M costs associated with the dry fly ash storage are assumed to be captured by the rental fee, negligible, or not appl icable (i.e., operating labor, maintenance labor, maintenance materials, chemical purchase, and energy).

7.2.6 Fly Ash Disposal Cost
EPA estimated disposal capital costs for th e dry fly ash generated by converting wet fly ash handling systems to a dry vactor truck colle ction system using the same methodology as that used for converting wet fly ash handling systems at coal-fired power pl ants as described in Section 7.1.7. However, because oil ash is neve r moisture conditioned with a pugmill unloader, EPA calculated the total amount of fly ash associated with oil units using Equation 7-66.
Plant Wet Fly Ash Generation Rate (tons/yr) = ∑ (Unit Wet Fly Ash Generation Rate × Wet Conveying Days) (7-66)

where:

Unit Wet Fly Ash Generation Rate = Amount of wet fly ash produced by each generating unit in tpd, (see Section 4.2.2), and Wet Conveying Days = The number of da ys wet fly ash is conveyed at each generating unit (see Section 4.2.2).

Sections 5.3 and 5.4 discuss costs for the tr ansportation and disposal of dry fly ash generated by converting wet fly ash handling syst ems to dry vactor truc k collection systems.

7.2.7 Impoundment Operation Costs
Section 5.5 discusses cost savings associat ed with ceasing operation of combustion residual surface impoundments.Chapter 7– Fly Ash Transport Water Cost Methodology

7-35 7.2.8 Fly Ash Outage Costs
EPA considered the impact of a plant outage required to install the dry vactor truck collection system. Because these sy stems are only installed on units that operated less than 100 days per year, EPA determined that piping syst em can be constructed and installed without interference to unit operations, and then the necessary tie-in can occur during a period of time when the unit is not operating. Therefore, there are no costs for plant outages during installation of the dry vactor tr uck collection system.

7.2.9 Results and Summary of Costs

As described in Section 2.1.4, EPA’s cost m odel generated plant-le vel compliance costs for converting wet fly ash handling systems to dr y vacuum systems. The cost output generated by the model includes a breakout of specific capital and O&M cost elements, including equipment costs, installation costs, operating la bor, maintenance labor, and energy costs. The output also includes costs for the common cost elements. Chapter 5 discusses these common cost elements that include transporta tion and disposal of combustion re sidual.. A list of the plant-level costs for the dry fly ash handling technol ogy option is included in the appendix.

7.3 R EFERENCES

1. Eastern Research Group, Inc (ERG). 2013. Supplemental Costs and Loadings Documentation. (19 April). DCN SE01825.
2. RSMeans. 2011. Building Construction Cost Data, 69th Edition. (January). DCN SE02952.
3. U.S. Department of Energy (DOE). Energy In formation Administration (EIA). Electric Power Annual 2009. Washington, DC. (4 January) DCN SE02023.
4. U.S. Department of Labor, Bu reau of Labor Statistics. 2010. May 2009 National Occupational Employment and Waste Estimates, United States. Washington, D.C. (May). DCN SE02953.
5. U.S. EPA, Office of Resource Conserva tion and Recovery (ORCR). 2010. Regulatory Impact Analysis for EPA’s Proposed RCRA Regulation of Coal Combustion Residues (CCR) Generated by the Electric Utility Indus try. Washington, D.C. (30 April). DCN SE02969.Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-1 

## CHAPTER 8 BOTTOM ASH TRANSPORT WATER COST METHODOLOGY

EPA evaluated the following two technology op tions for bottom ash transport water:

 Mechanical drag system; and

 Remote mechanical drag system.
EPA estimated capital, operating and mainte nance (O&M), three- year recurring, fiveyear recurring, and 10-year recurring costs as sociated with convert ing bottom ash handling systems from wet sluicing to a mechanical drag sy stem or a remote mechanical drag system for generating units generating bottom ash. EPA selected these two systems as the basis for the dry and closed-loop recycle systems, respectively, based on system operation data from vendors and operation data from the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey). The complia nce costs estimated by EPA include the conveyance system conversion, the additional requ ired bottom ash storage, the transport and disposal of the bottom ash, and impoundment ope ration costs associated with the change in bottom ash handling.
EPA estimated costs for both the mechanical drag system and remote mechanical drag system. The cost estimates reflect fully erected and commissioned systems, including equipment, controls, foundations, and field la bor. EPA selected the technol ogy associated with the lowest estimated annualized cost (at a plant level) for the combined system conversion, transport and disposal, and impoundment operatio n costs as the cost basis fo r the plant. All costs were estimated in 2010 dollars.

8.1 M ECHANICAL D RAG S YSTEM

8.1.1 Technology Description

Plants operating wet bottom ash handling systems hydraulically convey (i.e., sluice with water) bottom ash from the grinders to either an ash impoundment or dewatering bin. In such a system, ash from the grinders is fed onto a conveying line where it is diluted into slurry and pumped to the ash impoundment or dewatering storage bins.
Mechanical drag system (MDS) consists of a water bath trough located at the throat of the bottom of the boile r with a chain conveyor (a pair of chai ns with crossbars a ttached at regular intervals) that slowly moves along the trough, pu shing the bottom ash solids to the end of the boiler. At the end of th e boiler, the bottom ash drops onto an in clined conveyor that dewaters the solids and moves them out of the boiler to a nearby storage area.
EPA based the design and cost for installati on of an MDS or remote MDS on information collected from vendors, as well as information co llected from the industry through site visits and the Steam Electric Survey. The MDS costs consist of a complete replacem ent system, as shown in Figure 8-1, from the boiler throat to and incl uding a single semi-dry bottom ash storage silo located within 200 feet of the boiler [ERG, 2013; See Appendix 73]. This complete replacement system includes the water bath trough underneath the boiler and chain co nveyor to remove theChapter 8 – Bottom Ash Transport Water Cost Methodology

8-2 bottom ash solids, along with the single semi -dry bottom ash storage silo. The complete replacement also includes the demolition of the previously existing bottom of the boiler and wet sluicing system.

Graphic re-printed with permission from United Conveyor Corporation [UCC, 2009].
Figure 8-1. Mechanical Drag System

8.1.2 Population Costed
EPA evaluated MDS costs for each plant requiring conversion from wet bottom ash handling to dry or closed-l oop bottom ash handling. Based on information from the Steam Electric Survey, EPA identified 253 plants, co rresponding to 634 units, discharging bottom ash transport water, without any plan s to convert to dry handling or having the capacity to handle all the bottom ash dry, from coal- and oil-fired units. 49 EPA identified the units planning to convert to dry handling or closed-loop re cycle systems from responses in the Steam Electric Survey stating a planned conversion, the projected date for the conversion, and the end use of the wet sluicing system. Additionally, EPA identified pl ants that have announced plans to retire generating units or convert to dry or closed-l oop recycle bottom ash handling prior to December 31, 2014, as described in Section 4.4.1. Finally, EPA identified units with enough capacity to handle all bottom ash with a dry handling system from responses in the Steam Electric Survey stating that no modifications to the existing bottom ash handling system would be required to handle all of the bottom ash dry. There are no co nversion costs for gene rating units that are already planned to be convert ed to dry or closed-loop recy cle bottom ash handling systems because the plant will retire/convert the system without the implementation of the Steam Electric effluent limitations and guidelines (ELGs). Additionally, there are no conversion costs for generating units that have both wet and dry botto m ash handling systems where the dry system is capable of handling all of the bottom ash because the plant would be capable of operating without the wet sluicing system. EPA estimated compliance costs for these 634 generating units to convert wet sluicing systems to an MDS.

49 When the group of plants excluding oil-fired unts and un its with a capacity of 50 MW or less is evaluated the population of plants discharing bottom ash transport includes 240 plants, corresponding to 581 units.Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-3 8.1.3 Input Table
As discussed in Section 4.2.3, EPA used survey da ta to identify which plants discharge or have the potential to discharge bottom ash transport water. These plants all incur some level of cost for converting to dry bottom ash handling. Th e “Bottom Ash Input Table” holds all the input data needed to calculate the compliance costs for these plants . The “Bottom Ash Input Table” contains the following fields:

 Plant_id: Survey Plant ID.

 Seunit_id: Survey Steam Electric (SE) Unit ID.

 No_cost: Flag indicating that the unit will not incur costs for its bottom ash system.

 Cost: Flag indicating that the unit will in cur costs for its bottom ash system.

 Boiler_type: Type of boiler as indicated in Table C-18 (i.e., wet-bottom, drybottom).

 Wet_tpd: The amount of bottom ash handled wet in tons per day (dry weight basis) from Table C-18. For units that handled bottom ash wet in 2009 and did not report this value, EPA calculated a value by multiply ing the tons of coal burned in the unit in 2009, as reported in Table A-11, by two percent (assuming 10 percent ash content for the coal and 20 percent of ash generate d is bottom ash). EPA then divided this value by the number of days the unit operated in 2009, as reported in Table A-8, to estimate the amount of bottom ash handl ed wet in tons per day (tpd).

 Unit_type: Type of unit as indicated in Table A-8 (i.e., baseload, cycling, intermediate, or peaking).

 Produce_hpd: Estimate of the number of hours per day (hpd) the unit operates. EPA assumed units identified as baseload, inte rmediate, or cycling in Table A-8 operate 24 hpd and peaking units, as identified in Table A-8, operate 12 hpd.

 Convey_hpd: Estimate of the number of hours per day the unit conveys bottom ash. EPA assumed units identified as baseloa d, intermediate, or cycling in Table A-8 convey bottom ash six hpd and units identified as peaking convey bottom ash three hpd. For MDSs, EPA assumed bottom ash is conveyed continuously during operation, therefore, convey_hpd equals produce_hpd.

 Operating_days: Number of days the unit opera ted in 2009. EPA populated this value from the days of operation in Table A- 8. If days of operation were not reported, EPA assumed the operating days to be equa l to the reported days per year under in Table C-18.

 MW: The unit capacity (in megawatts (MW)) from Table A-8.

 FlowRate_GPD: Bottom ash sluice flow rate from Table C-19.

 Retired?: Flag indicating that the plant has iden tified that it will be retiring on or before 12/31/2014.
The discussion of the “Bottom Ash Input Tabl e” in Section 4.2.3 provi des more detail on the methodology used to determine the appropriate le vel of costing for each steam electric unit. A copy of the “Bottom Ash Input Tabl e” is included in the appendix.Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-4 8.1.4 Capital Cost Methodology
Capital costs for the MDS includes fully er ected and commissioned systems, including equipment, controls, foundations, and field labo r (e.g., installed equipment costs). The capital costs for the MDS do not include the costs for buildings or land because EPA assumed zero land costs based on data from site visi ts and discussions with plants who have already converted from wet bottom ash handling to dry bottom ash ha ndling. EPA assumes that other capital costs associated with buildings, site preparation, engi neering and construction ar e included in the costs provided by the vendors.
EPA calculated capital costs for each plant as the sum of purchased and installed conveyance equipment costs for the MDS (inc luding intermediate storage), plant-level engineering costs, and bottom ash dispos al costs, as described by Equation 8-1.
MDS Capital Cost (2010$) = Conveyance & Inte rmediate Storage Equipment Costs + Plant Overhead Engineering Costs + Bottom Ash Disposal Costs (8-1)

8.1.4.1 MDS Purchased Equipment Cost: Conveyance Equipment
EPA estimated unit-level capital costs for purchase and installation of equipment to convert a wet sluicing system to a MDS. EPA th en summed these unit-level costs to calculate plant-level conveyance and intermediate stor age capital costs. EPA made the following assumptions based on information obtained from vendors and Steam Electric Survey responses:
EPA costed the demolition of the existing bottom of the boiler and wet bottom ash sluicing system.

EPA costed the MDS to remove bottom ash from the boiler to a semi-dry silo within 200 feet of the boiler. EPA estimated costs for bot h the conveyance system and the semi-dry bottom ash storage silo.
For units with a capacity of less than or equa l to 500 MW, EPA costed the system for two 50 horsepower (hp) motors; for units with grea ter than 500 MW capacity, EPA costed two 75 hp
motors.
The system design does not include operation as a closed-loop syst em (i.e., the water leaving the system with the bottom ash does not need to be collected, coole d, and returned to the system), thereby eliminating the need for a heat exchanger.
Clyde Bergemann Power Group (CBPG, formerly Delta Ducon) provided cost data for the purchase and installation of equipment required for the conversion, from which EPA developed Equation 8-2 to estimate the MDS conve yance equipment cost. Because all installed equipment costs were provided in 2010 dollars, no adjustment of the cost basis was required.
MDS Conveyance Unit Capital Cost (2010$) = 20,083 × Capacity + 3,000,000 (8-2)Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-5 where:

Capacity = Generating unit capacity (see Section 4.2.3).

EPA calculated the plant-level MDS conveya nce capital cost by summing the unit-level costs at each plant, according to Equation 8-3.
Plant MDS Conveyance Capital Cost (2010$) = ∑ MDS Conveyance Unit Capital Cost (8-3)

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A74) for more detailed information on the development of Equations 8-2 and 8-3.

8.1.4.2 MDS Engineering Cost
Engineering costs include process design and general engineering, en gineering consulting fees, supervision, and inspection. EPA determined engineering overhead costs by multiplying the purchased and installation equipm ent costs by a factor for conveya nce and intermediate storage: Bottom Ash Engineering Factor. Because the MD S capital costs (i.e., Plant MDS Conveyance Capital Cost) include both conveyance and intermed iate storage costs, EPA combined the factors for conveyance and intermediate storage. To de termine the MDS Engineering Overhead Factor, EPA calculated the ratio of engi neering overhead costs to the to tal costs provided in the Steam Electric Survey using Equation 8-4 [ERG, 2013; See Appendix 74].
Ratio = MDS Engineering Overhead Costs / (MDS Total Capital Costs – MDS Engineering Overhead Cost) (8-4)

EPA calculated the median ratio for all ge nerating units that pr ovided MDS costs in response to the Steam Electric Survey, 0.01765, and us ed that as the MDS Engineering Overhead Factor.
EPA used Equation 8-5 to estimate engineering overhead costs.
MDS Unit Engineering Cost (2010$) = MDS Conve yance Unit Capital Cost × MDS Engineering Overhead Factor (8-5)

where:

MDS Conveyance Unit Capital Cost = Capital costs for purchase and installation of equipment to convert a wet sluicing system to an MDS (see Section 8.1.4.1 and Equation 8-2), and MDS Engineering Overhead Factor = EPA determined this factor based on responses to Questions C3-39 (conveyance costs) and C3-47 (intermediate storage costs) in the Steam Electric Survey, 0.01765.Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-6 EPA calculated the plant-level MDS engineeri ng cost by summing the unit-level costs at each plant, according to Equation 8-6.
Plant MDS Engineering Cost (2010$) = ∑ MDS Unit Engineering Cost (8-6)

8.1.5 O&M Cost Methodology

O&M costs consist of all costs related to operating and maintaini ng the conveyance and storage equipment associated with the MDS. Si nce the MDS does not require the operation of the existing wet sluicing equipment, EPA subtracted the estimated O&M costs associated with operating wet sluicing equipment from the O&M co sts associated with operating the MDS. No chemical costs are associated with the MDS or wet sluicing system. EP A used Equation 8-7 to calculate total MDS O&M costs.

MDS O&M Costs = MDS Conveyance O&M Costs + MDS Storage O&M Costs – Wet Sluicing O&M Costs (8-7)

EPA calculated the O&M costs associated w ith conveyance, storage, and wet sluicing using Equations 8-8, 8-9, 8-10.

MDS Conveyance O&M Costs = MDS Conveyance Operating Labor Cost + MDS Conveyance Maintenance Labor Cost + MDS Conveyance Ma intenance Materials Cost + MDS Conveyance Energy Cost (8-8)

MDS Storage O&M Costs = MDS Storage Opera ting Labor Cost + MDS Storage Maintenance Labor Cost + MDS Storage Maintenance Ma terials Cost + MDS Storage Energy Cost (8-9)

Wet Sluicing O&M Costs = Wet Sluicing Operat ing Labor Cost + Wet Sluicing Maintenance Labor Cost + Wet Sluicing Maintenance Ma terials Cost + Wet Sluicing Energy Cost (8-10)

All variables are defined in the following sections.

8.1.5.1 MDS Conveyance O&M Costs: Operating Labor
MDS conveyance operating labor cost include s labor costs for ash handling system operators to operate the conveyance systems (i .e., the MDS). EPA estimated unit-level operating labor costs and then summed these unit-level cost s to calculate plant-level operating labor costs. EPA calculated operating labor costs for each unit by multiplying the operating labor rate by the number of required oper ator hours per year.
EPA assumed that the same operator could be working on either the fly ash conveyance system or the bottom ash conveyance system; ther efore, EPA used the overall fly ash operating labor rate, $46.36/hr (2010$), for both fly ash and bottom ash conveyance operating and maintenance costs. See Section 7.1.6.1 for deta ils on how this rate was determined. EPA determined operator hours per day based on respons es to Question C3-41, Table C-28 (Operating Labor Staffing/Consumption) of the Steam Electric Survey. The reported operator hours per day for [Redacted] units operating mechanical drag systems ranged from [Redacted] to [Redacted]Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-7 hours per day, with a median and average of [Redacted] and [Redacted] hours per day, respectively. EPA selected an overall unit operator hours per day as the median of the survey data set, [Redacted] hours per day [ERG, 2013 See Appendix 75].
EPA calculated operator hours pe r year using Equation 8-11.
MDS Unit Operator Hours per Year (hpy) = MDS Operator Hours per Day x Operating Days (8-11)

where:

MDS Operator Hours per Day = Number of hours per day the MDS system requires an operator, [Redacted] hpd, and Operating Days = Number of days per year the generating unit operated in 2009 (see Section 4.2.3).

EPA calculated the MDS Conveyance Unit Oper ating Labor Cost using Equation 8-12.
MDS Conveyance Unit Operating Labor Cost (2 010$/yr) = Operating Labor Rate × Unit MDS Operator Hours Per Day × Operating Days (8-12)

where:

Operating Labor Rate = $46.36/hr (2010$),
MDS Operator Hours Per Day = [Redacted] hpd, and

Operating Days = Number of days per year the generating unit operated in 2009 (see Section 4.2.3).

EPA estimated the total MDS Conveyance Operating Labor Costs at the plant by summing the labor costs for all MDS conveyanc e units at the plant using Equation 8-13.
Plant MDS Conveyance Operating Labor Cost (2010$/yr) = ∑ MDS Conveyance Unit Operating Labor Costs (8-13)

8.1.5.2 MDS Conveyance O&M Costs: Maintenance Labor
The maintenance labor costs include labor costs for plant staff to maintain the MDS conveyance systems. EPA estimated unit-level ma intenance labor costs and then summed these unit-level costs to calculate plant-level maintenance labor costs. EPA calculated maintenance labor costs for each unit by multiplying the mainte nance labor rate by the number of required maintenance hours per year.
Because bottom ash system O&M may be performed by the same personnel, EPA selected an overall operating and maintenan ce labor rate, as disc ussed in Section 8.1.5.1Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-8 ($46.36/hr). EPA calculated unit ma intenance hours per year usi ng responses to Question C3-41, Table C-28 (Maintenance Labor Staffing/Consump tion) of the Steam Electric Survey. Reported maintenance hours per year for [Redacted] ge nerating units operating MDSs ranged from [Redacted] to [Redacted] hours per year for ash ha ndling system maintenance, with a median and average of [Redacted] and [Redacted] hours per year , respectively. EPA selected an overall unit maintenance hours per year as the median of th e Steam Electric Survey data set, [Redacted] hours per year [ERG, 2013; See Appendix 75].

MDS Conveyance Unit Maintenance Labor Cost (2010$/yr) = Maintenan ce Labor Rate × MDS Maintenance Hours Per Year (8-14)

where:

Maintenance Labor Rate = $46.36/hr (2010$), and

MDS Maintenance Hours Per Year = [Redacted] hpy.

EPA estimated the total MDS Conveyance Ma intenance Labor Costs at the plant by summing the labor costs for all MDS conveyanc e units at the plant using Equation 8-15.
Plant MDS Conveyance Maintena nce Labor Cost (2010$/yr) = ∑ MDS Conveyance Unit Maintenance Labor Cost (8-15)

8.1.5.3 MDS Conveyance O&M Costs: Energy Cost
MDS conveyance systems require energy to ope rate the chain conveyor that moves the bottom ash to the end of the boiler, and the inc lined conveyor that dewate rs the ash and moves it to the nearby storage area. Bottom ash conveya nce energy consumption (in kilowatt hours per year (kWh/yr)) is a function of motor horsepower . EPA determined unit-level motor horsepower based on unit capacity in MW using the follo wing step function provided by CPBG:

 For Unit Capacity ≤ 500 MW: Motor Horsepower = 50 hp

 For Unit Capacity > 500 MW: Motor Horsepower = 75 hp
EPA estimated unit-level motor energy cons umption and then summed these unit-level requirements to calculate plant-level ener gy consumption. Unit energy consumption was calculated by multiplying the motor horsepower by the conveying time and operating days. EPA assumed each system would have two motors for redundancy. Because the MDS is a continuous ash removal system, the conveying time is equal to the unit operating time. EPA assumed that base load, intermediate, and cycling units produce/convey bottom ash 24 hours per day, while peaking units produce/convey bottom ash 12 hours per day. EPA determined the type of unit (e.g., base load, peaking) based on data from the “Bottom Ash Input Table” (see Section 4.2.3) [ERG, 2013; See Appendix 73].Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-9 MDS Conveyance Unit Energy Consumpti on (kWh/yr) = Motor Horsepower × 0.745699 kW/HP× MDS Conveying Time × Operating Days × Number of Motors (8-16)

where:

Motor Horsepower = 50 hp (unit capacity ≤ 500 MW), 75 hp (unit capacity > 500 MW), MDS Conveying Time = 24 hpd (base load, intermediate, cycling units), 12 hpd (peaking units), Operating Days = The number of da ys each generating unit operated in 2009 (see Section 4.2.3), and
Number of Motors = 2.

EPA calculated the plant-level MDS conve yance energy consumption by summing the unit-level consumption at each pl ant, according to Equation 8-17.
Plant MDS Conveyance Energy Consumption (kWh/yr) = ∑ MDS Conveyance Unit Energy Consumption (8-17)

To calculate energy costs, EPA multiplied the plant energy consumption by the average national energy cost of 4.05 cents per kWh (2009$) as determined based on data reported by the U.S. Energy Information Administration in Table 8.2 of the Electric Power Annual 2009 for fossil plants in the United States [U.S. DOE , 2011]. As the energy cost was provided in 2009 dollars, EPA adjusted the cost basis to 2010 do llars using the 2009 and 2010 RSMeans Historical Cost Indices (180.1 and 183.5, resp ectively) [RSMeans, 2011].
Plant MDS Conveyance Energy Cost (2010$/y r) = National Energy Cost × Plant MDS Conveyance Energy Consumption × (2010 Cost Index/2009 Cost Index) (8-18)

where:

National Energy Cost = $0.0405/kWh (2009$),
Plant MDS Conveyance Energy Consumption = The energy consumed at the plant level by the operation of the motors used to operate the MDS conveyors, in kWh/yr, (see Equation 8-17), 2009 Cost Index = 180.1, and

2010 Cost Index = 183.5.

For the purpose of estimating non-water qu ality environmental impacts, EPA also converted energy consumption in kWh/yr to energy load in MW using Equation 8-19.Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-10 MDS Conveyance Unit Energy Load (MW) = MDS Conveyance Unit Energy Consumption / (MDS Conveying Time × Operating Days) × 1 MW / 1000 kW (8-19)

where:

MDS Unit Conveyance Energy Consumption = The energy consumed at the unit level by the operation of the motors used to operate the MDS conveyors, in kWh/yr, (see Equation 8-16), MDS Conveying Time = 24 hpd (base load, intermediate, cycling units); 12 hpd (peak units), and Operating Days = The number of da ys each generating unit operated in 2009, (see Section 4.2.3).

EPA estimated the total MDS Conveyance En ergy Load at the plant by summing the energy load for all MDS conveyance un its at the plant using Equation 8-20.
Plant MDS Conveyance Energy Load (MW) = ∑ MDS Conveyance Unit Energy Load (8-20)

8.1.5.4 MDS Conveyance O&M Costs: Maintenance Materials

EPA included costs for maintenance materials, such as routine replacement of materials and equipment due to consumption or wear a nd tear. EPA developed the equation below to estimate maintenance materials cost using the operating and maintenance costs reported in response to the Steam Electric Survey for ge nerating units with MDSs. Specifically, EPA evaluated responses to Question C3-41, Table C-28 (Maintenance Materials) of the Steam Electric Survey, calculating the rati o of reported maintenance material costs to the total sum of operating labor, maintenance labor, energy, and other O&M costs. EPA selected the median ratio, [Redacted], as the maintenance material s cost factor [ERG, 2013; See Appendix 75].
MDS Conveyance Maintenance Material Cost (2010$/yr) = MDS Conveyance Maintenance Material Cost Factor × (Plant MDS Conveyance Operating La bor Cost + Plant MDS Conveyance Plant Maintenance Labor Cost + Plant MDS Conveyance Energy Cost) (8-21)

where:

Plant MDS Conveyance Maintenance Material Cost Factor = Factor that accounts for mate rials cost as a percentage of O&M cost, [Redacted],

Plant MDS Conveyance Operating Labor Cost = Includes labor costs for ash handling system operators to operate the MDS conveyance systems (see Section 8.1.5.1 and Equation 8-13), Plant MDS Conveyance Maintenance Labor Cost = Includes labor costs associated with maintaining the MDS conveyance systems (see Section 8.1.5.2 and Equation 8-15), andChapter 8 – Bottom Ash Transport Water Cost Methodology

8-11 Plant MDS Conveyance Energy Cost = Energy costs associated w ith operating the MDS (see Section 8.1.5.3 and Equation 8-18).

8.1.5.5 MDS Storage O&M Cost: Operating Labor
EPA calculated MDS storage operating labor cost s to operate the bottom ash intermediate storage systems for each plant by multiplying the operating labor rate by the number of required operator hours per year. To de termine the operating labor rate, EPA evaluated labor rates reported in response to Question C3-49, Tabl e C-31 (Operating Labor Rate & Maintenance Labor Rate) of the Steam Electric Survey. Reported operating labor rates ranged from [Redacted]/hr to [Redacted]/hr (median rate of [Redacted]/hr), while maintenance labor rates ranged from [Redacted]/hr to [Redacted]/hr (med ian rate of [Redacted]/hr). As intermediate storage system O&M may be perf ormed by the same personnel, EPA decided not to distinguish between operating and maintenance labor rates and in stead selected an overall labor rate as the median of the entire survey dataset, [Red acted]/hr (2010$) [ERG, 2013; See Appendix 76].
EPA determined storage opera tor hours per year based on responses to Question C3-49, Table C-31 (Operating Labor (All Other) Staffing /Consumption) of the Steam Electric Survey. Reported operator hours per year for [Redacted ] silos and other storage areas ranged from [Redacted] to [Redacted] hpy for ash storage op eration, with a median of [Redacted] hpy. EPA selected an overall unit operator hours per year as the median of the questionnaire data set, [Redacted] hpy [ERG, 2013; See Appendix 76].

MDS Storage Operating Labor Cost (2010$/yr) = MDS Storage Operati ng Labor Rate × MDS Storage Operator Hours (8-22)

where:

MDS Storage Operating Labor Rate = The labor rate associat ed with operating the MDS storage system, [Redacted]/hr, and MDS Storage Operator Hours = The number of hours per year an operator is needed to oversee the MDS storage system, [Redacted] hpy.

8.1.5.6 MDS Storage O&M Costs: Maintenance Labor

Maintenance labor costs include labor costs for plant staff to maintain the intermediate storage systems. EPA calculated maintenance labor costs by multiplying the maintenance labor rate by the number of required maintenance hour s per year. EPA selected a maintenance labor rate equal to the operating labor rate (All Other) as discussed in Section 8.1.5.5 ([Redacted]/hr). EPA determined maintenance hours per year ba sed on responses to Question C3-49, Table C-31 (Maintenance Labor Staffing/Consumption) of the Steam Electric Survey. Reported maintenance hours per year for [Redacted] silos and other stor age areas ranged from [Redacted] to [Redacted] hpy for storage maintenance, with a median [Redacted] hpy. EPA selected an overall unit maintenance hours per year as the median of th e questionnaire data set, [Redacted] hpy. EPA calculated the maintenance labo r for the MDS storage using Equation 8-23 [ERG, 2013; See Appendix 76].Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-12 MDS Storage Maintenance Labor Cost (2010$/yr ) = MDS Storage Maintenance Labor Rate × MDS Storage Maintenance Hours (8-23)

where:

MDS Storage Maintenance Labor Rate = The labor rate associated with MDS storage, [Redacted]/hr, and

MSD Storage Maintenance Hours = The annual number of hours spent conducting maintenance activities on MDS storage equipment, [Redacted] hpy.

8.1.5.7 MDS Storage O&M Costs: Energy Cost
Energy requirements for bottom ash intermediate storage consist of the energy required to operate the unloading pump for the costed silos. EPA determined unloading pump energy consumption (in kWh/yr) based on a pump hor sepower of 50 hp, multiplied by the operating time and the operating days. 50 EPA assumed the plants unload the bottom ash from the silos 16 hpd. The number of operating days per year was calculated as the number of calendar days generating units operated in 2009 from the “B ottom Ash Input Table” (see Section 4.2.3) summed to a plant-level, with a maximum of 260 dpy. EPA used Equation 8-24 to estimate unloading pump energy consumption (in kWh/yr) [ERG, 2013; See Appendix 73].
MDS Storage Energy Consumption (kWh/y r) = Unloading Pump Horsepower × 0.745699 kW/HP × MDS StorageOperating Time × Operating Days (8-24)

where:

Unloading Pump Horsepower = 50 hp,

MDS Storage Operating Time = 16 hpy, and

Operating Days = Number of days at least one generati ng unit operated at the plant, with a maximum of 260 days per year.

To calculate energy costs, EPA multiplied the plant energy consumption by the average national energy cost of 4.05 cents per kWh ( 2009$), based on data reported by the U.S. Energy Information Administration in Table 8.2 of the Electric Power Annual 2009 for fossil plants in the United States [U.S. DOE, 2011]. As the energy cost was provide d in 2009 dollars, EPA adjusted the cost basis to 2010 dollars using th e 2009 and 2010 RSMeans Historical Cost Indices (180.1 and 183.5, respectively) [RSMeans, 2011].

50 Assumed the same horsepower provided for pugmills, in Section 7.1.6.8.Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-13 MDS Storage Energy Cost (2010$/yr) = Natio nal Energy Cost × MDS Storage Energy Consumption × (2010 Cost Index/2009 Cost Index) (8-25)

where:

National Energy Cost = $0.0405/kWh (2009$),
MDS Storage Energy Consumption = The annual energy consump tion of the MDS storage equipment in kWh/yr, 2009 Cost Index = 180.1, and

2010 Cost Index = 183.5.

For the purpose of estimating non-water qu ality environmental impacts, EPA also converted energy consumption in kWh/yr to energy load in MW using Equation 8-26.
MDS Storage Energy Load (MW) = MDS Storage Energy Consumption / (MDS Storage Operating Time × Unit Operating Days) × 1 MW / 1000 kW (8-26)

where:

MDS Storage Energy Consumption = The annual energy consump tion of the MDS storage equipment in kWh/yr MDS Storage Operating Time = 16 hpd, and

Operating Days = Number of days at least one generati ng unit operated at the plant, with a maximum of 260 dpy.

8.1.5.8 MDS Storage O&M Costs: Maintenance Materials

Maintenance materials cost includes costs for routine replacement of materials and equipment due to consumption or wear and t ear. EPA developed Equation 8-27 to estimate maintenance materials cost based on an evalua tion of operating and maintenance costs reported in response to the Steam Electric Survey for plants with a silo or outdoor pile. Specifically, EPA evaluated responses to Question C3-49, Table C-31 (Maintenance Materials) of the Steam Electric Survey, calculating the rati o of reported maintenance material costs to the total sum of operating labor, maintenance labor, energy, and othe r O&M costs. EPA selected the median ratio of 0.962 as the maintenance materials cost fact or. EPA calculated MDS Maintenance Materials Storage O&M Costs using Equation 8-27 [ERG, 2013; See Appendix 76].
MDS Maintenance Materials Storage Costs ( 2010$/yr) = MDS Maintenance Materials Cost Factor × (MDS Storage Operating Labor Cost + MD S Storage Maintenance Labor Cost + MDS Storage Energy Cost) (8-27)Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-14 where:

MDS Maintenance Material Cost Factor = Factor that accounts for mate rials cost as a percentage of O&M cost, 0.962, MDS Storage Operating Labor Cost = Labor costs to operate the MDS intermediate storage systems for each plant (see Section 8.1.5.5 and Equation 8-21), MDS Storage Maintenance Labor Cost = Labor costs for plant staff to maintain the intermediate storage systems (see S ection 8.1.5.6 and Equation 8-22), and MDS Storage Energy Cost = Costs to operate the unloading pump for the costed silo (see Section 8.1.5.7 and Equation 8-24).

8.1.5.9 Wet Sluicing O&M Costs: Operating Labor
Operating labor cost includes la bor costs for ash handling syst em operators to operate the wet sluicing conveyance systems. EPA estimated the unit-level operating labor costs and then summed these to calculate plan t-level operating labor cost. EP A calculated an operating labor cost for each unit by multiplying the operating labor rate by the number of required operator hours per year.
To determine the operating labor rate, EPA eval uated labor rates reported in response to Question C3-41, Table C-28 (Operating Labor Rate & Maintenance Labor Rate) of the Steam Electric Survey. Reported operating labor rates fo r generating units with wet sluicing systems ranged from $23.48/hr to $59.93/hr (median of $ 35.00/hr), while maintenance labor rates for generating units with wet slui cing systems ranged from $23.60/hr to $69.11/hr (median of $42.00/hr). Because O&M for the wet sluicing syst em may be performed by the same personnel, EPA decided not to distinguish between opera ting and maintenance labor rates and instead selected an overall labor rate as the median of the entire survey data set, $39.00/hr (2010$) [ERG, 2013; See Appendix 77].
The number of unit operator hours per year was calculated by multiplying the unit operator hours per day by the number of operating days per year for that unit. EPA determined operator hours per day based on responses to Question C3-41, Table C-28 (Operating Labor Staffing/Consumption) of the Steam Electric Survey. Reported operator hours per day for 10 units operating wet sluicing systems ranged from [Redacted] to [Redacted] hours per day, with a median of 8 hpd. EPA selected an overall unit operator hours per day as the me dian of the survey dataset, 8 hpd. EPA determined the number of unit operating days per y ear based on data from the “Bottom Ash Input Table” (see Sec tion 4.2.3) [ERG, 2013; See Appendix 77].
Wet Sluicing Unit Operating Labor Cost (2010$/y r) = Wet Sluicing Operating Labor Rate × Wet Sluicing Operator H ours × Operating Days (8-28)Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-15 where:

Wet Sluicing Operating Labor Rate = $39.00/hr (2010$),

Wet Sluicing Operator Hours = 8 hpd, and

Operating Days = The number of da ys each generating unit operated in 2009 (see Section 4.2.3).

EPA calculated the plant-level wet sluici ng operating labor by summing the unit-level wet sluicing operating labor costs according to Equation 8-29.
Plant Wet Sluicing Operati ng Labor Cost (2010$/yr) = ∑ Wet Sluicing Unit Operating Labor Cost (8-29)

8.1.5.10 Wet Sluicing O&M Costs: Maintenance Labor

Maintenance labor cost includes labor costs for plant staff to maintain the conveyance systems. EPA estimated unit-level maintenance la bor costs and then summed these to calculate plant-level maintenance labor cost. EPA calcula ted a maintenance labor cost for each unit by multiplying the maintenance labor rate by the number of required maintenance hours per year.
EPA selected a maintenance labor rate equal to the operating labor ra te as discussed in Section 8.1.5.9 ($39.00/hr). EPA determined mainte nance hours per year based on responses to Question C3-41, Table C-28 (Maintenance Labor St affing/Consumption) of the Steam Electric Survey. Reported maintenance hours per year [Red acted] ranged from [Redacted] to [Redacted] hpy for ash handling system maintenance, with a median of 512 hpy. EPA selected an overall unit maintenance hours per year as the median of the survey data set, 512 hpy [ERG, 2013; See Appendix 77].
Wet Sluicing Unit Maintenance Labor Cost (201 0$/yr) = Wet Sluicing Maintenance Labor Rate × Wet Sluicing Maintenance Hours (8-30)

where:

Wet Sluicing Maintenance Labor Rate = $39.00/hr (2010$), and

Wet Sluicing Maintenance Hours = 512 hpy.

EPA calculated the plant-level wet sluicing maintenance labor by summing the unit-level wet sluicing maintenance labor co sts according to Equation 8-31.Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-16 Plant Wet Sluicing Maintenance Labor Cost (2010$/yr) = ∑ Wet Sluicing Unit Maintenance Labor Cost (8-31)

8.1.5.11 Wet Sluicing O&M Costs: Energy Cost
The energy requirements for wet bottom ash sluicing systems consist of the energy required to operate the sluice pump that provides sluice water to transport bottom ash from the grinders to either an ash impoundment or dewatering bin . Wet bottom ash conveyance energy consumption (in kWh/yr) is a function of pu mp horsepower. EPA estimated sluice unit pump horsepower using the same horsepo wer equation as that develope d for sump pumps for chemical precipitation of flue gas desulf urization (FGD) wastewater (s ee Section 6.1.7.5). EPA calculated the pump horsepower using Equation 8-32.
Sluice Unit Pump Horsepower (hp) = (0.022 × (Ash Sluice Flow Rate / 60 min/hr / 24 hpd) + 0.926 (8-32)

where:

Ash Sluice Flow Rate = Generating unit sp ecific flow rate of bottom ash sluice water (see Section 4.2.3).

EPA estimated unit-level pump energy cons umption and then summed these unit-level requirements to calculate plant-level energy cons umption using the equations listed below. Unit energy consumption was calculated by multiplying the pump horsepower by the conveying time and operating days. EPA assumed that base load, intermediate, and cyclin g units produce bottom ash 24 hours per day and convey ash six hours pe r day, while peaking units produce bottom ash 12 hours per day and convey ash three hours per day. The type of unit (e.g., base load, peaking) and number of operating days per year for each unit costed were based on data found in the “Bottom Ash Input Table” (see Section 4.2.3). EP A used Equation 8-33 to estimate wet sluicing energy consumption (in kWh/yr).

Wet Sluicing Unit Energy Consumption (kWh /yr) = Sluice Unit Pump Horsepower × 0.745699 kW/HP × Wet Sluicing Unit Conve ying Time × Operating Days (8-33)

where:

Sluice Unit Pump Horsepower = Required horsepower to operate the sluice pump (see Equation 8-32), Wet Sluicing Unit Conveying Time = 6 hpd (base load, intermediate, cycling units);3 hpd (peak units), and Operating Days = The number of da ys each generating unit operated in 2009 (see Section 4.2.3).

EPA calculated the plant-level wet sluici ng energy consumption by summing the unitlevel wet sluicing energy consumption according to Equation 8-34.Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-17 Plant Wet Sluicing Energy Consumption (kWh/yr) = ∑ Wet Sluicing Unit Energy Consumption (8-34)

To calculate energy costs, EPA multiplied the plant-level wet sluicing energy consumption by the average national energy cost of 4.05 cents per kWh (2009$) as determined based on data reported by the U.S. Energy In formation Administration in Table 8.2 of the Electric Power Annual 2009 for fossil plants in the United States [U.S. DOE, 2011]. As the energy cost was provided in 2009 dollars, EPA adju sted the cost basis to 2010 dollars using the 2009 and 2010 RSMeans Historical Cost Indi ces (180.1 and 183.5, respectively) [RSMeans, 2011].
Wet Sluicing Energy Cost (2010$/yr) = Nationa l Energy Cost × Plant Wet Sluicing Energy Consumption × (2010 Cost Index/2009 Cost Index) (8-35)

where:

National Energy Cost = $0.0405/kWh (2009$),
Plant Wet Sluicing Energy Consumption = The annual amount of energy consumed by the MDS wet sluicing system, in kWh/yr, 2009 Cost Index = 180.1, and

2010 Cost Index = 183.5.

For the purpose of estimating non-water qu ality environmental impacts, EPA also converted energy consumption in kWh/yr to energy load in MW using Equation 8-36.
Wet Sluicing Unit Energy Load (MW) = Wet Slui cing Unit Energy Consump tion / (Wet Sluicing Unit Conveying Time × Operating Days) × 1 MW / 1000 kW (8-36)

where:

Wet Sluicing Unit Energy Consumption = The annual amount of energy consumed by the bottom ash wet sluicing system, in kWh/yr, Wet Sluicing Unit Conveying Time = 6 hpd (base load, intermediate, cycling units); 3 hpd (peak units), and Operating Days = The number of da ys each generating unit operated in 2009 (see Section 4.2.3).

EPA calculated the plant-level wet sluicing energy load by summing the unit-level wet energy load according to Equation 8-37.
Plant Wet Sluicing Energy Load (MW) = ∑ Wet Sluicing Unit Energy Load (8-37)Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-18 8.1.5.12 Wet Sluicing O&M Costs: Maintenance Materials
Wet sluicing maintenance materials cost includes costs for routine replacement of materials and equipment due to consumption or wear and tear. EPA developed the equation below to estimate the maintenance materials co st based on an evaluati on of O&M costs reported in response to the Steam Electric Survey for generating units with wet sluicing bottom ash handling systems. Specifically, EPA evaluated su rvey responses to Question C3-41, Table C-28 (Maintenance Materials) of the Steam Elect ric Survey, calculating the ratio of reported maintenance material costs to the total sum of opera ting labor, maintena nce labor, energy, and other O&M costs. EPA selected the median ra tio of 0.945 as the maintenance materials cost factor [ERG, 2013; See Appendix 77]. EPA calcula ted the Wet Sluicing Maintenance Materials Costs using Equation 8-38.
Wet Sluicing Maintenance Materi al Costs (2010$/yr) = Wet Sluici ng Maintenance Material Cost Factor × (Plant Wet Sluicing Operating Labor Cost + Plant Wet Sluicing Maintenance Labor Cost + Wet Sluicing Energy Cost) (8-38)

where:

Wet Sluicing Maintenance Material Cost Factor = Factor that accounts for mate rials cost as a percentage of O&M cost, 0.945,

Plant Wet Sluicing Operating Labor Cost = Labor costs to operate the wet sluicing conveyance system for each plant (see Section 8.1.5.9 and Equation 8-29), Plant Wet Sluicing Maintenance Labor Cost = Labor costs for plant staff to maintain the wet sluicing conveyance system (see Section 8.1.5.10 and Equation 8-31), and Wet Sluicing Energy Cost = Cost to operate the sluice pump (see Section 8.1.5.11 and Equation 8-33).

8.1.6 MDS Results
EPA estimated costs for all plants listed in the “Bottom Ash Input Table” to convert from wet bottom ash handling to MDS. A list of th e plant-level costs for the MDS bottom ash handling technology option is included in the appendix.

8.2 R EMOTE M ECHANICAL D RAG S YSTEM

8.2.1 Technology Description
The remote MDS operates by sluicing the bot tom ash to a water trough and sump located in an area away from the boiler where an MDS dewaters the ash and conveys it to storage.
EPA based the design and cost of the repl acement ash handling sy stem on information collected from vendors (CBPG), as well as inform ation collected from the industry through siteChapter 8 – Bottom Ash Transport Water Cost Methodology

8-19 visits and the Steam Electric Survey. The remote MDS consists of a complete system added onto the existing bottom ash slurry line. This remote MDS, as shown in Figure 8-2, consists of a single remote mechanical drag conveyor and a se mi-dry storage silo. The remote MDS consists of a water bath tank, accepting the bottom ash sl uice, and a drag chain conveyor. The existing slurry line is redirected to f eed the remote MDS. EPA assumes the conveyor overflows into a single sump pit from which transport water will be recycled back to the boiler area. All bottom ash sluice water sent to the remote MDS will be r ecycled back to the process to achieve complete recycle. [ERG, 2013; See Appendix 78].

Graphic re-printed with permission from United Conveyor Corporation [UCC, 2012].
Figure 8-2. Remote Mechanical Drag System

8.2.2 Population Costed
EPA evaluated remote MDS costs for each plant requiring conversion from wet bottom ash handling to dry or closed-loop recycle botto m ash handling. Based on information from the Steam Electric Survey, EPA identified 253 plan ts, corresponding to 634 units, discharging bottom ash transport water, without any plans to convert to dry handli ng or having the capacity to handle all the bottom ash dry, from coal- and oil-fired units. 51 EPA identified the units planning to convert to dry handli ng or closed-loop recycle system s from responses in the Steam Electric Survey stating a planned conversion, the projected date for the conversion, and the end use of the wet sluicing system. Additionally, EPA identified plants that have announced plans to retire generating units or conve rt to dry or closed-loop recycl e bottom ash handling prior to December 31, 2014, as described in Section 4.4. 1. Finally, EPA identified units with enough capacity to handle all bottom ash with a dry ha ndling system from responses in the Steam Electric Survey stating that no modifications to the existing bottom ash handling system would

51 When the group of plants excluding oil-fired unts and un its with a capacity of 50 MW or less is evaluated the population of plants discharing bottom ash transport includes 240 plants, corresponding to 581 units.Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-20 be required to handle all of the bottom ash dry. There are no conversion costs for generating units that are already planned to be converted to dry bottom ash handling or closed-loop recycle systems because the plant will retire/convert the system without the implementation of the ELGs. Additionally, there are no conve rsion costs for generating units that have both wet and dry bottom ash handling systems where the dry system is capable of handling all of the bottom ash because the plant would be capable of operating without the wet sluicing system. EPA estimated compliance costs for these 634 generating un its to convert to a remote MDS.

8.2.3 Input Table
EPA used the same inputs as in the MDS me thodology to estimate remote MDS costs. For more information on the specif ic input values, see Section 8.1.3.

8.2.4 Capital Cost Methodology
Capital costs for the remote MDS includes fully erected and commissioned systems, including equipment, controls, f oundations, and field labor (e.g., installed equipment costs). The capital costs for the remote MDS do not include the costs for buildings or land because EPA assumed zero land costs based on data from site visits and discussions with plants who have already converted from wet bottom ash handlin g to dry or closed-l oop recycle bottom ash handling. EPA assumed that other capital costs associated with buildings, site preparation, engineering, and constructi on were included in the cost s provided by the vendors.
EPA calculated plant-level capital costs as th e sum of costs for purchased and installed conveyance equipment for the remote MDS (incl uding intermediate storage), the recycle pump, the chemical feed system, and engineering overh ead costs. The remote MDS capital cost is the sum of the following costs:

 Conveyance equipment cost,

 Recycle pump cost,

 Chemical feed system cost,

 Purchase equipment installation cost, and

 Engineering cost.

8.2.4.1 Remote MDS Purchased Equipment Cost: Conveyance Equipment
EPA estimated unit-level capital costs for purchase and installation of equipment to convert a wet sluicing system to a remote MD S. EPA then summed these unit-level costs to calculate plant-level conveyance equipment costs. EPA made the following assumptions based on information obtained from vendors a nd Steam Electric Survey responses:
The existing bottom of the boiler and wet bottom ash sluicing system will continue to be used. EPA costed moving of the sluice line to the new location of the remote MDS.
EPA costed individual conveyor systems with a semi-dry bottom ash storage silo for each generating unit. (Note th at this may overestimate compliance costs for the proposed rule becauseChapter 8 – Bottom Ash Transport Water Cost Methodology

8-21 multiple units at a plant could use the same re mote MDS which would result in lower overall costs.)

EPA assumed the overflow from the remote MDS is equal to the ash sluice flow rate of the system.
EPA costed the addition of hydrochloric acid (H Cl) to the sump to decrease the pH of the overflow to neutral (7 S.U.). 52 EPA did not include costs for inst alling a clarifier, assuming that any solids generated by pH adjustment will eventually be removed by the remote MDS conveyor.
CBPG provided cost data for the purchase and installation of equipment required for the conversion, from which EPA developed the follo wing remote MDS conveyance equipment cost equation. Since all installed equipment costs were provided in 2010 dollars, no adjustment of the cost basis was required.
Remote MDS Unit Conveyance Equipment Cost (2010$) = 14,227 × Capacity + 2,000,000 (8-39)

where:

Capacity = Generating unit capacity (see Section 4.2.3).

EPA calculated the plant-level remote MDS conveyance equipment costs by summing the unit-level remote MDS conveyance equi pment costs according to Equation 8-40.

Plant Remote MDS Conveyance Equipment Cost (2010$) = ∑ Remote MDS Unit Conveyance Equipment Cost (8-40)

See the Supplemental Costs and Loadings Documentation (DCN SE01825.A78) for details on the development of Equations 8-38 and 8-39.

8.2.4.2 Remote MDS Purchase Equipment Cost: Recycle Pump
EPA estimated the recycle pump costs us ing Equation 8-41, provided below. EPA assumed the same pump type and estimated cost s using the same cost equation developed for sump pumps for chemical precipitation of FG D wastewater (see Sect ion 6.1.6.1). Because pump costs were provided by vendors in 2011 dollars, EPA adjusted the cost basis to 2010 dollars using the 2010 and 2011 RSMeans Historical Cost Indices (183.5 and 185, respectively) [RSMeans, 2011].

Remote MDS Unit Recycle Pump Cost (2010$) = 15.79 × (Ash Sluice Flow Rate / 60 min/hr / 24 hpd + 7,685) × Pump Quantity × Freight Fact or × (2010 Cost Index/2011 Cost Index) (8-41)

52 Not all systems will require chemical addition for pH control to operate as complete recycle; however, EPA estimated this cost for all remote MDS system installations.Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-22 where:

Ash Sluice Flow Rate = The ash sluice fl ow rate for each generating unit, (see Section 4.2.3), Pump Quantity = 1 pump,
Freight Factor = 1.04,

2010 Cost Index = 183.5, and

2011 Cost Index = 185.

EPA calculated the plant-level remote MDS recycle pump cost by summing the unit-level remote MDS recycle pump cost according to Equation 8-42.
Plant Remote MDS Recycle Pump Cost (2010$) = ∑ Remote MDS Unit Recycle Pump Cost (8-42)

8.2.4.3 Remote MDS Purchased Equipment Cost: Chemical Feed System
EPA assumed the same HCl feed system and estimated costs using the same cost equations as those developed for chemical pr ecipitation of FGD wastew ater (see Section 6.1.6.3). EPA determined the size and cost of the feed system based on the chemical consumption, which was calculated based on chemical dosage.
EPA calculated a chemical dosage of 0.000112 g of neat HCl/L of bottom ash sluice wastewater based on the amount of HCl needed to reduce bottom ash sluice wastewater pH from 8.5 S.U. to 7 S.U. EPA determined the bottom ash sluice wastewater pH of 8.5 S.U. based on review of available data in five Electric Powe r Research Institute’s Plant Integrated Systems Chemical Emissions Studies (ERPI PICSES) repor ts. These reports indicated bottom ash sluice wastewater pH of less than 7 S.U. at two plants (pH ranged from 4.3 to 6.9 S.U.), neutral at one plant (pH ranged from 5.8 to 7.9 S.U.), and greater than 7 S.U. at two plants (pH ranged from 7.7 to 9.4 S.U.). Based on this information, EPA a ssumed that bottom ash sluice wastewater is typically more basic than acidic, and EPA used the pH values from the plant with the highest pH to calculate the required chemical dosage. Due to plant-to-plant fluctuatio ns in pH, some plants might need to reduce pH using acid while othe r might need to increase pH using sodium hydroxide (also known as caustic). Therefore, EP A’s estimated costs for an HCl feed system were assumed to represent a variety of pH adjust ment scenarios that may be required at plants.
To calculate unit chemical consumption, EPA converted the chemical dosage from grams of neat HCl to 32 percent HCl solution and then multiplied by the unit bottom ash sluice flow rate, as shown by Equations 8-43 and 8-44.
Dose Conversion Factor (L/g) = 1 / (Concen tration × Density × 1,000 g/kg) = 0.00270 L HCl solution / g neat HCl (8-43)Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-23 where:

Concentration = 32 per cent HCl solution, and
Density = 1.159 kg/L for 32 percent HCl solution.

Remote MDS Unit Chemical Consumption (gal/day) = Dose × Dose Conversion Factor × 3.785 L of wastewater/gal of wastew ater × 1 gal of chemical/3.785 L of chemical × Ash Sluice Flow Rate (8-44)

where:

Dose = 0.000112 g of neat HCl/ L ash sluice wastewater,

Dose Conversion Factor = 0.00270 L HCl solution/g neat HCl, and

Ash Sluice Flow Rate = The ash sluice flow rate for each generating unit (see Section 4.2.3).

Chemical feed system costs vary by unit chemical consumption, based on the ranges shown by Equations 8-45 and 8-46. EPA adjusted the chemical feed system costs provided by vendors in 2011 dollars to 2010 dollars usi ng the 2010 and 2011 RSMeans Historical Cost Indices (183.5 and 185, resp ectively) [RSMeans, 2011].
For Remote MDS Unit Chemical Consumption ≤ 2,400 gpd, EPA used Equation 8-45.
Remote MDS Unit Chemical Feed System Cost (2010$) = ($5,000 + Feed System Freight) × (2010 Cost Index/2011 Cost Index) (8-45)

For Remote MDS Unit Chemical Consumption > 2,400 gpd, EPA used Equation 8-46.
Remote MDS Unit Chemical Feed System Cost (2010$) = ($15,000 + Feed System Freight) × (2010 Cost Index/2011 Cost Index) (8-46)

where:

Feed System Freight = $300,

2010 Cost Index = 183.5, and

2011 Cost Index = 185.

EPA calculated the plant-level remote MDS chemical feed system cost by summing the unit-level remote MDS chemical feed sy stem cost according to Equation 8-47.Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-24 Plant Remote MDS Chemical Feed System Cost (2010$) = ∑ Remote MDS Unit Chemical Feed System Cost (8-47)

8.2.4.4 Remote MDS Purchase Equipment Installation Cost
Purchased equipment installation includes th e installation of all equipment, piping, instrumentation/calibrati on, electrical equipment, mechanical equipment, structural supports, insulation, and painting. EPA estimated installati on capital costs for the purchased recycle pump and the chemical feed system. EPA assumed an installation cost factor for the remote MDS purchased equipment similar to that of fly as h, two times the purchase equipment costs for the recycle pump and chemical feed system (see Section 7.1.5.4).

8.2.4.5 Remote MDS Engineering Cost
Engineering costs include costs for proce ss design and general engineering, cost engineering, consulting fees, supervision, and inspection. EPA assumed that the engineering costs incurred for bottom ash conversions incl ude owner’s overhead en gineering costs. EPA determined engineering overhead costs by multipl ying the purchased and installation equipment costs by a factor for conveyance and intermediate storage. The factor was determined based on survey response to Questions C3-39 (conveyance costs) and C3-47 (inter mediate storage costs). Because the remote MDS capital costs include bo th conveyance and intermediate storage, EPA combined the factors for conveyance and inte rmediate storage for a value of 0.01765 [ERG, 2013; See Appendix 78].
EPA used Equations 8-48 and 8-49 to es timate plant-level engineering costs.
Remote MDS Unit Capital Cost (2010$) = Remote MDS Unit Conveyance Equipment Cost +

Remote MDS Unit Recycle Pump Cost + Remote MDS Unit Chemical Feed System Cost + Remote MDS Unit Installation Cost (8-48)

Remote MDS Unit Engineering Cost (2010$) = Re mote MDS Unit Capital Cost × Remote MDS Engineering Factor (8-49)

where:

Remote MDS Engineering Factor = 0.01765,

Remote MDS Unit Conveyance Equipment Cost = Cost of the conveyance equipment associated with each generating unit (see Section 8.2.4.1 and Equation 8-39),
Remote MDS Unit Recycle Pump Cost = Cost of the recycle pump for each generating unit (see Section 8.2.4.2 and Equation 8-41),
Remote MDS Unit Chemical Feed System Cost = Cost associated with the chemical feed systems needed for each generating unit (see Section 8.2.4.3 and Equation 8-45 or 8-46), andChapter 8 – Bottom Ash Transport Water Cost Methodology

8-25 Remote MDS Unit Installation Cost = The cost to install al l remote MDS purchased equipment for each generating unit (see Section 8.2.4.4).

EPA calculated the plant-level remote MDS engineering cost by summing the unit-level remote MDS engineering cost according to Equation 8-50.
Remote MDS Engineering Cost (2010$) = ∑ Remote MDS Unit Engineering Cost (8-50)

8.2.5 O&M Cost Methodology
O&M costs for each plant consist of all cost s related to operating and maintaining the conveyance and storage equipment required to c onvert wet bottom ash handling systems to the remote MDS.
EPA used Equation 8-51 to calculate tota l O&M costs for remote MDS. Because the remote MDS requires the continued operation of the existing wet sluicing equipment operated by plants, the estimated O&M costs associated with operating of the wet sluicing equipment were not subtracted from the O&M costs for the re placement remote MDS as a cost savings.

Remote MDS O&M Costs = Remote MDS Conve yance O&M Cost + Remote MDS Storage O&M Cost (8-51)

Remote MDS conveyance O&M costs and remote MDS storage O&M costs are calculated using Equations 8-52 and 8-53.

Remote MDS Conveyance O&M Costs = MDS Conveyance O&M Cost + Remote MDS O&M Chemical Purchase Cost + Remote MDS O&M Energy Cost (8-52)

Remote MDS Storage O&M Costs = MDS Storage O&M Cost (8-53)

8.2.5.1 Remote MDS Conveyance O&M Co sts: Mechanical Drag System
The MDS conveyance O&M costs are pres ented in Sections 8.1.5.1 through 8.1.5.4. EPA has determined that all of th ese costs are applicable to plants installing remote MDSs.

8.2.5.2 Remote MDS Conveyance O&M Cost s: Chemical Purchase Cost
The chemical requirement for remote MDSs consist of HCl added to the sump to decrease the pH of the overflow to neutral. HCl costs are a function of HCl consumption, calculated in gallons of 32 percent HCl solution in gpd, as described in Section 8.2.4.3, and converted to tons/year using Equation 8-54.
Remote MDS Unit Chemical Consumption (tons/yr) = Remote MDS Unit Chemical Consumption × HCl Solution Density × 3.785 L/gal × 2.205 lb/kg × 1 ton/2,000 lb × Operating Days (8-54)Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-26 where:

Remote MDS Unit Chemical Consumption = Amount of HCl consumed by the chemical feed system each day (see Section 8.2.4.3 and Equation 8-43), HCl Solution Density = 1.159 kg/L fo r 32 percent HCl solution, and
Operating Days = The number of da ys each generating unit operated in 2009, (see Section 4.2.3).

To calculate chemical purchase costs, EPA multiplied HCl consumption by the sum of the chemical purchase and freight costs using Equation 8-55. EPA adjusted the chemical and freight costs that were provided by vendors in 2011 dollars to 2010 dolla rs using the 2010 and 2011 RSMeans Historical Cost Indices ( 183.5 and 185, respectively) [RSMeans, 2011].
Remote MDS Unit Chemical Cost (2010$) = Remote MDS Unit Chemical Consumption × (HCl Cost + HCl Freight Cost) × ( 2010 Cost Index/2011 Cost Index) (8-55)

where:

Remote MDS Unit Chemical Consumption = Amount of HCl consumed by the chemical feed system each day (see Section 8.2.4.3 and Equation 8-44), HCl Cost = [Redacted]/ton (2011$) (see Section 6.1.7.4),
HCl Freight Cost = $65.91/ton in (2011$),

2010 Cost Index = 183.5, and

2011 Cost Index = 185.

EPA calculated the plant-level remote MDS chemical cost by summing the unit-level remote MDS chemical cost according to Equation 8-56.
Remote MDS Chemical Cost (2010$/yr) = ∑ Remote MDS Unit Chemical Cost (8-56)

8.2.5.3 Remote MDS Conveyance O&M Costs: Energy Cost
Energy requirements unique to the remote MD S include the energy required to operate the pump that returns transport water from the su mp pit back to the boiler area, and the energy required to operate the HCl feed pump. EPA dete rmined this additional energy consumption (in kWh/yr) by calculating and summing the annual pow er consumption for these two pumps for each unit, and then summing these unit-level co nsumptions to calculate plant-level energy consumption using Equations 8-57through 8-59.
Pump energy consumption (in kWh/yr) is a function of pump horsepower. EPA estimated sluice pump horsepower using the same horsepower equation as th at developed for sump pumps for chemical precipitation of FG D wastewater (see Section 6.1.7.5) . The ash sluice rate, in gpd,Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-27 was determined for each generating unit at each plant from the responses to Question C3-3, Table C-19 (Average Sluice Water Flow Rate) of the Steam Electric Survey.
Remote MDS Unit Sluice Pump Horsepower (hp) = 0.022 × (Ash Sluice Flow Rate / 60 min/hr / 24 hpd) + 0.926 (8-57)

where:

Ash Sluice Flow Rate = The ash sluice fl ow rate for each generating unit (see Section 4.2.3).

For the HCl feed pump, EPA used the same hor sepower as that developed for feed pumps for chemical precipitation of FGD wa stewater, 0.5 hp (see Section 6.1.7.5).
Remote MDS Unit Feed Pump Horsepower (hp) = 0.5 hp

In calculating energy consumption, EPA assu med that baseload, intermediate, and cycling units produce bottom ash 24 hours per da y and convey ash six hpd, and that peaking units produce bottom ash and convey ash three hpd. The type of unit and operating days per year for each unit costed is included in the “B ottom Ash Input Table” (see Section 4.2.3).
Remote MDS Unit Energy Consumption (kWh/yr) = (Remote MDS Unit Sluice Pump Horsepower + Remote MDS Unit Feed Pump Horsepower) × 0.745699 kW/HP × Remote MDS Unit Conveying Time × Operating Days (8-58)

where:

Remote MDS Unit Sluice Pump Horsepower = Horsepower required by the unit sluice pump (see Equation 8-57),

Remote MDS Unit Feed Pump Horsepower = 0.5 hp,

Remote MDS Unit Conveying Time = 6 hpd (baseload, intermedia te, cycling units); 3 hpd (peaking units), and Operating Days = The number of da ys each generating unit operated in 2009, (see Section 4.2.3).

EPA calculated the plant-level remote MDS energy consumption by summing the unitlevel remote MDS energy consumption according to Equation 8-59.
Plant Remote MDS Energy Consumption (kWh/yr) = ∑ Remote MDS Unit Energy Consumption (8-59)

To calculate energy costs, EPA multiplied the plant energy consumption by the average national energy cost of 4.05 cents per kWh (2009$) as determined based on data reported by theChapter 8 – Bottom Ash Transport Water Cost Methodology

8-28 U.S. Energy information Administration in Table 8.2 of the Electric Power Annual 2009 for fossil plants in the United States [U.S. DOE , 2011]. As the energy cost was provided in 2009 dollars, EPA adjusted the cost basis to 2010 do llars using the 2009 and 2010 RSMeans Historical Cost Indices (180.1 and 183.5, resp ectively) [RSMeans, 2011].
Remote MDS Energy Cost (2010$/yr) = Nationa l Energy Cost × Plant Remote MDS Energy Consumption × (2010 Cost Index/2009 Cost Index) (8-60)

where:

National Energy Cost = $0.0405/kWh (2009$),

Plant Remote MDS Energy Consumption = Annual amount of energy consumed by the remote MDS in kWh/yr (see Equation 8-59), 2009 Cost Index = 180.1, and

2010 Cost Index = 183.5.

For the purpose of estimating non-water qu ality environmental impacts, EPA also converted energy consumption in kWh/yr to energy load in MW using Equation 8-61.

Remote MDS Unit Energy Load (MW) = Remo te MDS Unit Energy Consumption / (Remote MDS Unit Conveying Time × Operating Days) × 1 MW / 1000 kW (8-61)

where:

Remote MDS Unit Energy Consumption = Annual amount of energy consumed by the remote MDS at each generating unit in kWh/yr, (see Equation 8-58),
Remote MDS Unit Conveying Time = 6 hpd (base load, intermediate, cycling units); 3 hpd (peaking units), and Operating Days = The number of da ys each generating unit operated in 2009 (see Section 4.2.3).

EPA calculated the plant-level remote MDS energy load by summing the unit-level remote MDS energy load according to Equation 8-62.
Remote MDS Energy Load (MW) = ∑ Remote MDS Unit Energy Load (8-62)

8.2.5.4 Remote MDS Storage O&M Costs
EPA determined that the storage O&M costs fo r remote MDSs are the same as those for MDSs, described in Sections 8.1.5.5 through 8.1.5.8.Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-29 8.2.6 Remote MDS Results
EPA estimated costs for all plants listed in the “Bottom Ash Input Table” to convert from wet bottom ash handling to a remote MDS. A list of the plant-level costs for the remote MDS bottom ash handling technology is included in the appendix.

8.3 B OTTOM A SH D ISPOSAL C OST
EPA determined the cost of dry bottom ash transportation and disposal based on bottom ash generation rates. However, bottom ash genera tion rates reported in the Steam Electric Survey are in tons per day on a dry we ight basis, while bottom ash requiring disposal includes some moisture content, which increases the weight of the ash. EPA, therefore, determined the bottom ash moisture content to account for the increased weight. EPA de termined the moisture content of the bottom ash based on responses to Questio n C3-32, Table C-23 (Percent Moisture of the Bottom Ash Entering the Destination) of the Steam Electric Survey. The average moisture content reported by plants that transport bottom ash by truck to a landfill was 20 percent. Based on this information, EPA developed Equation 8-63 to adjust the bottom as h generation rate to account for ash moisture. EPA determined the un it bottom ash generation rate (in tpd) for each generating unit at each plant from the survey re sponses to Question C3-2, Table C-18 (Typical Amount of Wet Conveyed Bottom Ash Produced (repo rted in tpd on a dry weight basis)). The number of unit operating days per year was de termined based on responses to Question A6-1, Table A-8 (Steam Electric Units) of the Steam Electric Survey [ERG, 2013; See Appendix 79].

Dewatered Bottom Ash Genera tion Rate (tons/yr) = [ ∑ (Unit Bottom Ash Generation Rate × Operating Days) ] / (1 – Bottom Ash Moisture Content) (8-63)

where:

Unit Bottom Ash Generation Rate = The amount of wet botto m ash generated by each generating unit (see Section 4.2.3), Operating Days = The number of da ys each generating unit operated in 2009 (see Section 4.2.3), and
Bottom Ash Moisture Content = 20 percent.

EPA also calculated dewatered bottom as h density using Equation 8-64. For this calculation, EPA assumed a bottom ash density of 45 lb/ft 3 (dry weight), the same as that for dry fly ash.
Dewatered Bottom Ash Density (lb/ft 3 ) = [ (Bottom Ash Moisture Conten t) × (Density of Water)] + [(Density of Bottom Ash) × (1 – Bo ttom Ash Moisture Content)] = 48.5 lb/ft 3 (8-64)

where:

Bottom Ash Moisture Content = 20 percent,Chapter 8 – Bottom Ash Transport Water Cost Methodology

8-30 Density of Water = 62.4 lb/ft 3 , and
Density of Bottom Ash = 45 lb/ft 3 (dry weight).

The dewatered bottom ash density was used to calculate the total tons of bottom ash that need to be transported and disposed of in a landfill. This value was used to calculate transportation and disposal costs. Sections 5.3 an d 5.4 describe transportation and disposal costs for the dry bottom ash generated by the MDS or remote MDS.

8.4 I MPOUNDMENT O PERATION C OSTS

Section 5.5 describes cost savi ngs associated with closi ng combustion re sidual surface impoundments.

8.5 O NE -T IME C OSTS
Based on data from plant site visits and info rmation in the survey, EPA determined that some plants operated bottom ash wet sluicing syst ems as closed-loop recycle systems. EPA also determined that some plants recycle a majority of their bottom ash sluice but still discharge a small portion of bottom ash sluice water as emerge ncy discharges or via other plant operations (e.g., re-used and discharged with FGD wastewater). For those plants recy cling the majority of their bottom ash sluice, EPA assumed that a one- time engineering cost would be appropriate to completely close the bottom ash sluice recycle loop to eliminate the discharge of bottom ash transport water.
To determine the plants that should receive the one-time bottom ash management cost, EPA reviewed bottom ash sluice recycle and di scharge amounts reported in Part C Section 3.1, along with the water balance diag rams provided in the Steam Elect ric Survey. EPA identified the plants that should receive the one-time bottom ash management co sts as those plants recycling more than 90 percent of their sluice or only discharging bottom ash sluice through emergency outfalls. Based on industry knowledge and contract or fees, EPA developed an estimate for a contractor to come on site and develop a plan fo r the plant to close up the bottom ash discharge.

EPA assumed that the contract or will require a total of 200 hours to complete the plan, including two week-long trips to the plant. Therefore, EPA us ed Equations 8-65, 8-66, and 8-67 to estimate these one-time costs:
Bottom Ash One-Time Cost (2010$) = Contractor Labor + Travel Cost (8-65)

The contractor labor and trav el costs were estimated usi ng Equations 8-66 and 8-67.
Contractor Labor (2010$) = Numb er of Hours × Contractor Rate (8-66)

where:

Number of Hours = EPA estimated num ber of hours for the contractor to complete the plan, 200, andChapter 8 – Bottom Ash Transport Water Cost Methodology

8-31 Contractor Rate = EPA estimate of the contractor rate, $100/hr.

EPA estimated the travel costs for th e two week-long trips using Equation 8-67.
Travel Cost (2010$) = (Number of Travel Days × Hotel Cost × Escalation Rate) + (Number of Travel Days × Food Cost) + (Num ber of Trips × Airfare Costs) (8-67)

where:

Number of Travel Days = Number of work days in a two week period, 10 days.
Hotel Cost = The 2011 federal per diem rate for hotels based on standard continental United States (CONUS) rates,
Escalation Rate = An escal ation factor to account for potential increases in hotel costs based on location, 1.25 (i.e., 25 percent), Number of Travel Days = Total comb ined length of the trips in days, 14,
Food Cost = The 2011 federal per diem rate for meals and incidentals based on standard CONUS rates, Number of Trips = EPA estimate of the number of trips required, two, and

Airfare Costs = EPA estimate of the r ound trip airfare for the contractor to travel to the plant, $500.

Based on these assumptions, EPA estimates that the total one-time costs for a plant to hire a contractor to close th e discharge of a bottom ash recy cle system would be $22,422. This estimate assumes no capital improvements.

8.6 B OTTOM A SH O UTAGE C OSTS
EPA considered the impact of a plant outage required to convert wet bottom ash handling systems to MDS and remote MDS. Based on an evaluation of vendor and survey information, EPA determined that most MDS and remote MDS installations can be completed during regularly scheduled outages. Specifically, for the 23 units that reported conversions to an MDS, only one required an outage outsi de a regularly scheduled outage to complete the installation. For remote MDSs, the entire system can be instal led prior to a scheduled outage, and then the necessary tie-in can occur during a regularly sche duled outage. Therefore, there are no costs for plant outages during in stallation of the MD S or remote MDS.

8.7 R ECURRING C OSTS
For both the MDS and remote MDS, the drag chain needs to be pe riodically replaced. Based on information provided by the UCC, the life of a drag chain varies from two to three years for the MDS to four to six years fo r the remote MDS [ERG, 2013; See Appendix 80]. Because the MDS drag chain is underneath the boiler and can potentially be damaged by largeChapter 8 – Bottom Ash Transport Water Cost Methodology

8-32 chunks of falling bottom ash, EPA assumed that the MDS drag chain would need to be replaced every three years. Because the remote MDS dr ag chain receives bottom ash slurry where the bottom ash has already undergone grinding, EPA assumed that the remote MDS drag chain would need to be replaced every five years. Based on cost information provided by UCC, EPA estimated drag chain replacement costs of $175,000 per unit, including labor and materials [ERG, 2013; See Appendix 80]. Plant-level drag ch ain replacement costs equal the sum of unitlevel replacement costs.

8.8 S ELECTION OF D RY B OTTOM A SH H ANDLING T ECHNOLOGY
For each plant requiring conversion from wet bottom ash handling to dry or closed-loop bottom ash handling, EPA evaluated the costs fo r both the MDS and remote MDS technologies and then selected the technology with the lowest total annualized cost.
Cost annualization is a way of combining one -time costs (such as capital costs) and O&M costs (which are incurred ever y year) and spreading them out evenly over an analytical timeframe, creating a cost incurred each year fo r purposes of comparison. Cost annualization uses the following inputs: 1) the estimated cost s (capital, O&M, one-time, periodic); 2) a discount rate that reflects the co st of capital to the affected pl ants; and 3) an assumed timeframe over which to annualize costs. EPA selected a 7 pe rcent discount rate, wh ich is the real (i.e., inflation rate factored out) cost of capital as estimated by the U.S. Office of Management and Budget [OMB, 2003] and which EPA generally uses in regulatory analyses in cases where the actual cost of capital is unknown. EPA selected a time frame of 20 years based on the expected operational life of the dry/closed-loo p recycle bottom ash handling technology.
EPA used Equations 8-68 and 8-69 to calcu late total annualized costs for MDS and remote MDSs.
For MDS, EPA used Equation 8-68.
Total Annualized Cost (2010$/y ear) = (MDS Capital Cost × 7%/{1 – [1 / (1 + 7%) 20 ]}) + MDS O&M Cost +MDS Recurring Cost / 3 (8-68)

For Remote MDS EPA used Equation 8-69.
Total Annualized Cost (2010$/year ) = (Remote MDS Capital Cost × 7%/{1 – [1 / (1 + 7%) 20 ]}) + Remote MDS O&M Cost + MDS Recurring Cost / 5 (8-69)

8.9 R ESULTS AND S UMMARY OF C OSTS
As described in Section 2.1.4, EPA’s cost m odel generated plant-le vel compliance costs for converting wet bottom ash handling systems to an MDS or remote MDS. The cost output generated by the model includes a breakout of specific capital and O&M cost elements, including equipment costs, installation cost s, operating labor, maintenance labor, and energy costs. The output also includes costs for the common cost elements. Chapter 5 discusses these common cost elements that include transportation and disposal of combustion residual. A list ofChapter 8 – Bottom Ash Transport Water Cost Methodology

8-33 the plant-level costs for the dry/closed-loop recycle bottom ash handling technology option is included in the appendix.

8.10 R EFERENCES

1. Eastern Research Group, Inc (ERG). 2013. Supplemental Costs and Loadings Documentation. (19 April). DCN SE01825.
2. RSMeans. 2011. Building Construction Cost Data, 69th Edition. (January). DCN SE02952.
3. United Conveyor Corporation (UCC). 2009. Wet- to-Dry Conversion: Bottom Ash & Fly Ash Systems. (January). DCN SE02042.
4. United Conveyor Corporation (UCC). 2012. Re mote SFC Bottom Ash Handling System. (27 November). DCN SE02968.A3.
5. U.S. Department of Energy (DOE). 2011. En ergy Information Administration (EIA). Electric Power Annual 2009. Washingt on, DC. (4 January). DCN SE02023.
6. U.S. Office of Management and Budget (OMB). 2003. Circular A-4. (17 September). DCN SE03572.Chapter 9 – Combustion Residual Leachate Cost Methodology

9-1 

## CHAPTER 9 COMBUSTION RESIDUAL LEACHATE COST METHODOLOGY

Combustion residuals can include flue gas de sulfurization (FGD) solids, fly ash, and/or bottom ash. EPA estimated capital and operating a nd maintenance (O&M) costs associated with installing and operating a one-stage chemical precipitation wastewat er treatment system to treat combustion residual landfill leachate. Landfill l eachate treatment options include one-stage chemical precipitation or one-stage chemical prec ipitation with biological treatment. EPA finds that plants with combustion residual leachat e from surface impoundments will not incur costs associated with any proposed leachate require ments (see Section 9.1). Where a plant generates both landfill leachate and FGD wa stewater, EPA evaluated the leachate compliance costs in conjunction with FGD wastewater treatment (i.e ., those plants discharg ing leachate and FGD wastewater would use only one wa stewater treatment system to treat the combined leachate and FGD wastewater flow). 53 For plants that do not have FGD wastewater, however, EPA calculated the cost for a chemical precipitation to treat onl y the landfill leachate using the equations in Section 6.1 associated with one-stage chemical precip itation [ERG, 2012].
The following section describes the capital and O&M costs associated with treating combustion residual landfill leachate that are in addition to the equipment and O&M costs described in Sections 6.1 and 6.2 for chem ical precipitation and biological treatment, respectively.

9.1 T ECHNOLOGY D ESCRIPTION
EPA estimated compliance costs for plants ge nerating combustion resi dual leachate from landfills or surface impoundments to comply w ith the effluent limitations guidelines and standards (ELGs) based on one of the following two technology options:

 One-stage chemical precipitation; and

 One-stage chemical precipitation followed by biological treatment.
Sections 6.1 and 6.2 detail EPA’s methodology fo r calculating plant sp ecific costs for a one-stage chemical precipitation wastewater treatme nt system and a biological treatment system respectively, for the treatment of FGD wastewater. These same co st methodologies were used to generate plant-level costs for the treatment of landfill leachate. The equations presented in both sections were applied to the flow rate of leachate from a landfill containing combustion residuals, referred to as ‘leachate flow’ througho ut this section. Section 4.2.4 describes EPA’s methodology for estimating leachate flows for thos e plants identified as discharging leachate from landfills containing combustion residuals.

53 The technology option for combustion residual landfill leachate is one-stage chemical precipitation while the technology option for FGD wastewater is one-stage chemical precipitation followed by biological treatment. While the plant could technically meet the proposed leachate lim itations and standards with only a one-stage chemical precipitation system, installing two sepa rate treatment systems for the leachat e and FGD wastewater would be more expensive than a single system that subjects leachate to both chemical precipitation and biological treatment.Chapter 9 – Combustion Residual Leachate Cost Methodology

9-2 EPA acknowledges that landfills can be locate d some distance away from the plant. According to survey data, the average onsite landfill is 1.3 miles from the plant center. As a result, EPA estimated costs for all plants to in stall a series of pumps and piping to transport landfill leachate from the landfill wh ere it is collected to the main plant area (i.e., 1.3 miles away, where the wastewater treatment sy stem is most likely located). 54 Sections 9.5 and 9.6 provide more detail on the methodology used to estimate capital equipment and O&M costs associated with the additional equipment needed to tr ansfer landfill leachate back to the plant.
Plants that generate surface impoundment leach ate will likely use a different approach than installing the technology basis to comply with limitations or standards based on either of the technology options. EPA determined that 36 pe rcent of plants generating leachate from combustion residual impoundments recycle the leach ate back to the ash/FGD impoundment from which it was collected. Additionally, some plants use the impoundment leachate for dust control at a landfill or to moisture condition ash trans ported to a landfill. Based on these data, EPA believes that if the proposed rule included a limit on the discharge of combustion residual leachate, plants would comply with the limit by recycling the leachate back to the ash/FGD impoundment from which it was generated (or use the leachate for dust control/moisture conditioning) instead of installing the technology option to treat and discharge the wastewater because it is a less expensive altern ative. There are negligible cost s associated with recycling the leachate back to the ash/FGD impoundment beca use the plant will either: 1) use the existing pump that transfers the leachate to a separate location to pum p it back to the impoundment; or 2) install a pump to transfer the leachate to th e impoundment, in which case the costs would be offset because the plant no longer needs to opera te a separate impoundment (or other treatment system) to treat the leachate to meet the exis ting best practicable c ontrol technology currently available (BPT) effluent limits prior to its discha rge. Therefore, there are no compliance costs for combustion residual surface impoundment leachate. Where this section further addresses the costing methodology for combustion residual leachate, it refers to the costs associated with the treatment of combustion residual landfill leachate.

9.2 P OPULATION C OSTED
An incremental compliance cost for leachat e is assessed to any plant identified as collecting and discharging leachate from a landfill containing combustion residuals. EPA used survey data from Part A (Steam Electric Po wer Plant Operations) and Part F (Management Practices for Ponds/Impound ments and Landfills) of the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey) (to identify plants discharging landfill leachate. EPA focused on leachate collection and discharge from active, inactive, or open landfills. EPA identified 102 plants as discharging landfill leachate from an active, inactive, or open landfill containing combustion residuals. 55 EPA identified plants th at have announced plans to retire generating units prior to December 31, 2014 as described in Section 4.4.1. There are no conversion costs for plant that ar e already planned to retire prior to implem entation of the ELGs.

54 Since EPA has estimated costs for all plants to transport leachate from the landfill to a treatment system located at the main plant area, this will overestimate costs for plants choosing to install the treatment system closer to where the leachate is collected.

55 When the group of plants excluding oil-fired units and units with a capacity of 50 MW or less is evaluated the population of plants discharging land fill leachate includes only 101 plants.Chapter 9 – Combustion Residual Leachate Cost Methodology

9-3 9.3 T REATMENT IN P LACE
For those plants discharging both combusti on residual leachate and FGD wastewater, one wastewater treatment system is costed to handl e the combined flow. EPA identified only one plant that operates a biological treatment system, without chemical precipitation pretreatment, to treat the combustion residua l landfill leachate genera ted at the plant prior to discharge; EPA did not identify any plants that currently operate a chemical precipitation system to treat combustion residual landfill leachate. 56 However, there are plants that have treatment in place for FGD wastewater and discharge combustion residual landfill leachate.
Of the plants identified as having some le vel of treatment in place for FGD chemical precipitation (Section 6.1.3), 29 plants also di scharge landfill leachate. EPA conducted an analysis to determine if the existing FGD wastewat er treatment system at these plants would be sufficient to treat the amount of combustion residual landfill leach ate produced at the plant in addition to the FGD wastewater that is currently being treate d. EPA compared the design flow rate (reported in Part D Secti on 5.1 of the Steam Electric Survey ) for each treatment system to the plant-specific wastewater flow (i.e., FGD wastewater plus combustion residual landfill leachate). If this new flow FGD wastewater pl us combustion residual landfill leachate was less than the specified design flow rate for the existing chemical precipitation system, EPA determined that the existing system could suppor t the additional flow. EPA identified 10 plants that had sufficient capacity to handle the a dditional combustion residual landfill leachate flow; however, 19 plants did not have sufficient capacit y. For these 19 plants, EPA estimated costs for an additional one-stage chemical precipitati on treatment system or one-stage chemical precipitation followed by biological treatment syst em, sized to treat only the combustion residual landfill leachate [ERG, 2013; See Appendix 63]. 57

EPA developed an input table, the “Leachate Cost Matrix,” to hold information on which types of treatment system costs each plant w ould incur based on whether or not the plant discharges both FGD wastewater and leachate an d whether the plant has an existing treatment system for FGD wastewater.

9.4 I NPUT T ABLE
As discussed in Section 4.1.3, EPA used Steam Electric Survey data to identify which plants discharge or have the potential to discharge combustion residual landfill leachate and determine the estimated leachate treatment cost s for these plants. The “Landfill Leachate Input Table” holds all the input data needed to calculate the techno logy option cost for leachate treatment. The “Landfill Leachate Input Table” contains the following fields:

56 EPA identified this system after completing the complian ce cost calculations; therefore, compliance cost estimates currently show a cost for the biological treatment system fo r this plant. This update will be incorporated into the final rule.

57 This approach may overestimate costs for these 19 plants . It may be more cost effective for these plants to upgrade the existing FGD treatment system rather than install a separate treat ment system for the landfill leachate. EPA estimated costs for a separate treatment system due to insufficient information regarding the existing FGD treatment system at these 19 plants and the speci fic upgrades required to accomocate the leachate.Chapter 9 – Combustion Residual Leachate Cost Methodology

9-4  Plant_id: Survey Plant ID.

 Landfill_id: Survey Landfill ID (only valid for plants completing Version 1 of the Steam Electric Survey).

 Landfill_Type: Type of landfill designation (i.e. active or inactive).

 SumofLdfl_Leach_Vol_GPD: Leachate production in 2009 in gallons per day, from Question F3-12 of the Steam Electric Survey (only completed for plants completing Version 1 of the survey).

 Ldfl_SA: Surface area of individua l landfills with leachate collection, from Question F3-2 of the Steam Electric Survey (only co mpleted for plants completing Version 1 of the survey).

 Landfills_Acre: Total landfill acreage from Question C1-2 of the Steam Electric Survey.

 Leachate_GPD: Leachate flow in gallons per day, from Question F3-13 for all plants completing Version 1 of the Steam Electric Survey. Calculated value for all plants that did not complete Part F (Managem ent Practices for Ponds/Impoundments and Landfills).

 CBI Flag: Flag indicating that the resulting costs should be handled as CBI. CBI flag is marked if any data used to populate the input table were marked as CBI by the plant.

 Retired?: Flag indicating that the plant has id entified that it will be retiring on or before 12/31/2014.
Section 4.1.3 provides more detail on the methodology used to determine the landfill leachate flow rate and a discussion of the “L andfill Leachate Input Table.”. A copy of the “Landfill Leachate Input Table” is included in the appendix.

9.5 C APITAL C OST M ETHODOLOGY
Capital costs associated with one-stage chemical precipita tion and one-stage chemical precipitation with biological tr eatment is included in Secti ons 6.1.6 and 6.2.5, respectively. The following subsections only provide detail on cap ital cost components unique to costing the combustion residual leachate treatment systems. EPA calculated the cost to transport leachate from the landfill site back to the main plant for treatment. The additional pieces of equipment needed to transport the leachate back to the main plant area include leachate transport pumps and a section of stainless steel pipe. 58

9.5.1 Purchased Equipment Costs: Leachate Transport Pump
EPA costed four 100 percent capacity. skid-m ounted, horizontal centrifugal pumps to move leachate from the landfill (or leachate collec tion area) to the location of the wastewater treatment system, assumed to be near the center of the plant. EPA designed two of these pumps

58 Plants may also install fiberglass reinforced plastic (FRP ) piping to transport the l eachate. EPA is evaluating both piping costs to determine which is more cost effective and will update the cost estimate post-proposal as appropriate.Chapter 9 – Combustion Residual Leachate Cost Methodology

9-5 to function as booster pumps to the two ma in pumps. These pumps are modeled off the wastewater forwarding pumps costed for the one-s tage chemical precipitation treatment system (see Section 6.1.6.1). EPA used Equation 9-1 to estimat e the capital cost of the leachate transport pump:

Leachate Transport Pump Cost (2010$) = Leach ate Pump Qty × [2914 × ln(Capacity Factor × Leachate GPM) – 3090.1] × Pump Freight F actor × (Cost Index 2010 / Cost Index 2011) (9-1)

where:

Leachate Pump Qty = Number of pumps costed, four,
Capacity Factor = Equipmen t sizing factor (see Section 6.1.5), [Redacted], Leachate GPM = Leachate flow in gallons per minute (see Section 4.1.3),
Pump Freight Factor = Fact or that accounts for freight cost as a percentage of purchase cost, 1.04 (see Section 6.1.6.1), Cost Index 2010 = 183.5, and

Cost Index 2011 = 185.

9.5.2 Purchased Equipment Costs: Leachate Transport Piping
EPA costed a length of stainless steel pipe to span from the landfill back to the main plant area. As described in Section 9.1, EPA estimated that the median distance from an on-site landfill to the plant center is 1.3 miles. EPA developed the follow ing equation to calculate the cost of the piping; note that th e cost per foot of pipe changes based on the size (e.g., diameter) of pipe needed.
EPA also estimated freight costs for the pi ping based on weight a nd a shipping distance of approximately 500 miles using quotes from Fr eightCenter.com. Freight costs were equal to approximately 0.9 percent of purchase co sts (i.e., Freight Factor = 1.009).
Leachate Transport Piping Cost (2010$) = Pipe Cost × Distance × Pipe Freight Factor ×Cost Index 2010 / Cost Index 2011 (9-2)

where:

Pipe Cost = Cost of the stainless steel pipe in dollars per foot, (see below for calculated values based on flow rate),
Distance = Estimated distance from an on-site landfill to treatment system at the plant cente r, 6,864 feet (1.3 miles), Pipe Freight Factor = Fact or that accounts for freight cost as a percentage of purchase cost,1.009,Chapter 9 – Combustion Residual Leachate Cost Methodology

9-6 Cost Index 2010 = 183.5, and

Cost Index 2011 = 185.

 For leachate flow in gpd 0 – 158,400 gpd: Pipe Cost = 8.80 dollars per foot

 For leachate flow in gpd 158,400 – 288,000 gpd: Pipe Cost = 18.45 dollars per foot

 For leachate flow in gpd 288,000 – 576,000 gpd: Pipe Cost = 26.30 dollars per foot

 For leachate flow in gpd 576,000 GPD – 1,008,000 gpd: Pipe Cost = 47.55 dollars per foot

 For leachate flow in gpd 1,008,000 – 1,584,000 gpd: Pipe Cost = 73.92 dollars per foot

 For leachate flow in gpd 1,584,000 – 2,880,000 gpd: Pipe Cost = 126.10 dollars per foot

9.6 O&M C OST M ETHODOLOGY
O&M costs associated with one-stage chemical precipitation and biol ogical treatment can be found in Sections 6.1.7 and 6.2.6, respectively. EP A identified electricity used to operate the leachate transport pumps as the only O&M cost a ssociated with the additional equipment needed to transfer leachate from the collectio n location to the treatment system.
EPA modeled the electricity costs for the l eachate transport pumps after the electricity requirements of the wastewater forwarding pum p for one-stage chemical precipitation (see Section 6.1.7.5). Electricity requi rements were calculated assumi ng only two of the four pumps are operating at any one time, using Equation 9-3.

Leachate Transport Pump Electricity (kWh/yea r) = (0.0151 × Capacity Factor × Leachate GPM + 2.0191) × hp KW Factor × Operating Hours × 365 dpy × Leachate Pump Qty / 2 (9-3)

where:

Capacity Factor = Equipment sizing factor (see Section 6.1.5), [Redacted], Leachate GPM = Leachate flow in gallons per minute (see Section 4.1.3),
hp KW factor = Factor to conve rt horsepower to kilowatts, 0.7456 KW/hp, Operating Hours = Operating h ours of the system, 24 hpd, andChapter 9 – Combustion Residual Leachate Cost Methodology

9-7 Leachate Pump Qty = Number of pumps costed, four.

EPA added the annual electricity requirement of the leachate transpor t pump to the total electricity requirement of the one-stage chem ical precipitation system (see Section 6.1.7.5).

9.7 M ERCURY A NALYZER C OST
All plants costed for either a combustion re sidual leachate treatment system or an FGD treatment system incurred costs to install and ope rate a mercury analyzer and treated effluent recycle system. Section 6.1.9 discusses costs to install and operate a mercury analyzer and effluent recycle system.. For those plants costed for two separate treatment systems, one for FGD wastewater and one for combustion residual l eachate alone, EPA incl uded mercury analyzer costs for each treatment system.

9.8 S LUDGE T RANSPORTATION AND D ISPOSAL C OSTS
EPA determined dewatered sludge generati on rates for the chemical precipitation treatment technology option using the methodology previously described in Section 6.1.8. EPA estimated the solids generated from the chemic al precipitation with biological treatment technology option using the met hodology described in Section 6.2.7.

Sections 5.3 and 5.4 discuss costs for the transportation and disposal of the sludge generated by each technology option.

9.9 C OMPLIANCE M ONITORING C OST
All plants costed for either a combustion residual leachate treatment system or an FGD treatment system incurred a cost for complia nce monitoring. Section 5.2 discusses costs for compliance monitoring.

9.10 S URFACE I MPOUNDMENT O PERATION C OSTS
Section 5.5 discusses cost savings associat ed with ceasing operation of combustion residual surface impoundments. EPA assumes th at plants currently operating a surface impoundment for leachate collection will continue to do so.

9.11 R ESULTS AND S UMMARY OF C OSTS
As described in Section 2.1.4, EPA’s combusti on residual leachate cost model generated plant-level compliance costs for the one-stage chemical precipitation technology option and the chemical precipitation with biolog ical treatment technology opti on. The cost output generated by the model includes a breakout of specific capital and O&M cost elements, including equipment costs, installation costs, operati ng labor, maintenance labor, and energy costs. The output alsoChapter 9 – Combustion Residual Leachate Cost Methodology

9-8 includes costs for the common cost elements desc ribed in Chapter 5. A list of the plant-level costs for each technology opti on is included in the appendix. 59

EPA used information contained in the “Leachate Cost Matrix” to estimate compliance costs under Option 4. For this regulatory option plants treating FGD wast ewater alone or FGD wastewater and leachate with the same treatment system are required to comply with effluent limitations associated with the biological trea tment system, while treatment systems handling only combustion residual leachate are required to comply with the effluent limitations associated with chemical precipitation. EPA has included sepa rate tables in the appendix to represent the estimated costs associated with Option 4.

9.12 R EFERENCES

1. Eastern Research Group, Inc (ERG). 2013. Supplemental Costs and Loadings Documentation. (19 April). DCN SE01825.

2. RSMeans. 2011. Building Construction Cost Data, 69th Edition. (January). DCN SE02952.

59 Because EPA evaluated costs for the treatment of combus tion residual leachate with FGD wastewater, where both are discharged and could be combined in the same syst em, EPA did not calculate costs to treat the combustion residual leachate separately for each plant. For those plants where the combustion residual leachate and FGD wastewater are expected to be co mbined, EPA only calculated costs fo r the combined treatment system.Chapter 10 –Pollutant Loadings and Removals Methodology

10-1 

## CHAPTER 10 POLLUTANT LOADINGS AND REMOVALS METHODOLOGY

This chapter discusses annual pollutant load ings and removal estimates for the steam electric industry for each pr oposed regulatory option. EPA estimated the pollutant loadings and removals from existing steam electric power plants to evaluate the effectiveness of the treatment technologies, estimate benefits gained from re moving pollutants discharged from plants, and evaluate the cost-effectiveness of the regulatory options in redu cing the pollutant loadings. EPA defined baseline and post-compliance pollutant loadings as follows:

 Baseline Loadings . Pollutant loadings, in pounds per year, in steam electric wastewater being discharged to surface water or through publicly owned treatment works (POTWs) to surface water prior to im plementing controls to comply with the proposed rule.

 Post-Compliance Loadings . Estimated pollutant loadings, in pounds per year, in steam electric wastewater after implementa tion of the proposed rule; these are also referred to as treated loadings. EPA calcula ted these loadings assuming that all steam electric power plants woul d operate wastewater treatme nt and pollution prevention technologies equivalent to the techno logy bases for the regulatory option.

 Pollutant Removals . The difference between the baseline loadings and postcompliance loadings for each regulatory option.
Some aspects of the proposed effluent limita tions guidelines and st andards (ELGs) (e.g., applicability changes) would likely not lead to a change in pollutant load ings. Other aspects of the proposed ELGs would likely lead to a change in pollutant loadings for a subset of plants. These plants typically are the plants that gene rate one or more of the wastestreams for which EPA is proposing new limitations or standards. This section describes the detailed pollutant loadings evaluation EPA performed to quantify the removal in pollutant loadings associated with the regulatory options for the proposed ELGs. Sp ecifically, EPA determined baseline and postcompliance pollutant loadings for the following wastestreams: flue gas desulfurization (FGD) wastewater, fly ash transport water, bottom ash transport water, combustion residual leachate, gasification wastewater, and flue gas mercury control wastewater. 60 The currently operating gasification generating units operate vapor-c ompression evaporation systems (i.e., the technology basis for the preferred option); therefor e, EPA determined that the baseline loadings are equal to the post-compliance loadings. Simila rly, plants currently manage their flue gas mercury control wastes in a way th at avoids pollutant discharge to surface waters, so the baseline loadings for these wastewaters are also equa l to the post-compliance loadings. Additionally, because nonchemical metal cleaning wastes are al ready subject to the proposed best available control technology (BAT) limitations, based on th e current best practi cable control technology (BPT) standard, the plants generating and di scharging nonchemical metal cleaning wastes are

60 As described in Section 9.1, EPA expects that plants generating surface impoundment leachate will comply with the regulation by returning the leachat e back to the impoundment from which it was generated, which will result in no net increase/decrease in the pollutant loadings from th e plant. Therefore, EPA did not assess compliance costs or pollutant loadings associated with surface impoundment leachate. EPA did, ho wever, calculate pollutant loadings associated with landfill leachate.Chapter 10 –Pollutant Loadings and Removals Methodology

10-2 already meeting these standards. In addition, EP A is proposing to exempt from new limitations and standards any nonchemical metal cleaning wast es generated and authorized for discharge without copper and iron limits. As a result, all faci lities are either alrea dy in compliance or will be exempt from the requirements and , therefore, EPA finds that the baseli ne loadings are equal to the post-compliance loadings. The remainder of this chapter applies to FGD wastewater, fly ash transport water, bottom ash transport water, and combustion residual l eachate. All tables and figures referenced in this chapter are presented at the end of the chapter.

10.1 G ENERAL M ETHODOLOGY FOR E STIMATING P OLLUTANT R EMOVALS
For each plant discharging an evaluated wast estream (i.e., FGD wastewater, ash transport water, and combustion residual leachate), EPA calc ulated plant-level pollutant removals for each of the technology options evaluated for that wast estream. For example, for any plant discharging FGD wastewater, EPA calculated a ba seline loading and loadings associated with each treatment option (i.e., one-stage chemical precipitation, one -stage chemical precip itation with biological treatment, and one-stage chemical precipitati on with vapor-compressi on evaporation). On a plant-level basis, EPA calculates baseline loadings by multiplying the average pollutant concentration in the discharge by the plant-specific wastewater discharge fl ow rate to generate the mass of specific pollutant di scharged per year, in pounds/year.
EPA used sampling data, gathered through the EPA sampling program described in Section 3.3, as well as publicly available sources , to characterize the ba seline loading and postcompliance loading concentrations for each ev aluated wastestream. S ection 10.2 presents the data sources and average discharge pollutant co ncentrations for the baseline and each of the technology options associated with the evaluated wastestreams.
Next, for each evaluated wastestream discharg ed by a specific plant, EPA used data from the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey) to determine the plant’s discharge fl ow rate. In cases where survey data were insufficient, EPA developed a methodology for es timating flow rates. Section 10.3 provides details on these wastewater flow rates.
EPA calculated baseline pollutant loadings a nd post compliance treatment loadings for each plant discharging an evaluated wastestream us ing the plant-specific wastewater flow for the wastestream and the average pollutant concentr ation of the specific wastestream according to Equation 10-1.
Pollutant Loading (lbs/yr) = Flow Rate × Pollutant Concentrati on × 2.20462 lb/10,000,000 mg × 1,000 L / 264.17 gal (10-1)

where:

Flow Rate = The flow rate of th e wastestream being discharged, in gallons per year (gpy), and Pollutant Concentration = The average concentration of a specific pollutant present in the wastestream, in milligrams per liter.Chapter 10 –Pollutant Loadings and Removals Methodology

10-3 EPA identified several plants that report tran sferring wastewater to a POTW rather than discharging directly to surface water. For these plants, EPA adjusted the baseline loadings to account for pollutant removals expected from POTWs for each analyte. For each pollutant of concern (POC), Table 10-1 provi des the percent removal expected from well-operated POTWs, as reported in the Memo to the 2006 Effluent Guidelines Program Plan Docket [ERG, 2006]. For any plant identified as discharg ing a wastestream to a POTW, EP A used the calculated baseline loadings and the values shown in Table 10-1 to calculate the amount of pollutant discharged from the POTW to surface water according to Equation 10-2.

Indirect Pollutant Loadin g (lb/yr) = Pollutant Loading × (1- POTW Removal) (10-2)

where:

Pollutant Loading = The loadings from a specific pollutant if it were discharged directl y, in pounds/year, and POTW Removal = The estimated percenta ge of the pollutant loading that will be removed by a POTW.

In addition to expressing pollutant loadings in pounds of pollutant discharged per year, EPA uses toxic weighting factors (TWFs) to account for differences in toxicity across pollutants. 61 EPA calculated a toxic-weighted pound equi valent (TWPE) value for each pollutant discharged to compare mass loadings of different pollutants based on thei r toxicity. To perform this comparison, EPA multiplied the mass loadings of pollutant in pounds/year by the pollutantspecific TWF to derive a “toxic-equivalent” lo ading (lb-equivalent/yr), or TWPE. Section 10.4 discusses the wastestream mass loading (i.e., unwe ighted loadings) and TWPE loadings in more detail.

10.2 W ASTESTREAM C HARACTERIZATION AND D ATA S OURCES
As discussed earlier, loadings calculations require a pollutant-speci fic concentration to determine the mass loadings. EPA used a variety of data sources to generate characterization data for each evaluated wastestream. For each wa stestream, EPA excluded all pollutants that were not measured above the quantitation limit in all of the samples representing the baseline effluent discharges for that spec ific wastestream. Therefore, if a pollutant was measured above the quantitation limit at least once in the baseline effluent concentration dataset, that pollutant was included in the loadings analysis. EPA generated a separate set of characterization data for baseline and each post-compliance technology basis. Section 10.2.1 presents the data sources and characterization for FGD wastewater, Section 10. 2.2 presents ash transport water, and Section 10.2.3 presents combustion residual landfill leachate.

61 A listing of pollutant-specific TWF values can be found in the Toxic Weighting Factor Development in Support of CWA 304(m) Planning Process [ERG, 2006]. EPA has developed TWFs for more than 1,900 pollutants based on aquatic life and human health toxicity data, as well as physical/chemical property data.Chapter 10 –Pollutant Loadings and Removals Methodology

10-4 10.2.1 FGD Wastewater Characterization
EPA is considering three technology options as the basis of proposed discharge requirements for FGD wastewater: one-stage chemical precipitation, one-stage chemical precipitation with biological tr eatment, and one-stage chemic al precipitation with vaporcompression evaporation. Table 10-2 summarizes the concentration data sets that were included in the baseline and post-compliance FGD loadings analysis and their sources. EPA performed the following review, made substitutions, as appropria te, and performed the following analyses with the sampling data results, where appropriate, prior to using them in the technology option loadings calculations: 62

 J-Values and Non-Detects : The laboratories performing the metals analyses provided all the analytical results that were m easured above the sample-specific method detection limit (MDL). Therefore, the laborat ory results include values flagged with a “J” indicator (i.e., results measured above the MDL, but below the quantitation limit). EPA did not use the “J-values” in the load ings calculations. EPA treated all results that were less than the quantitation limit (i.e., J-values and non-detects below the MDL) as half the sample-specific quantitation limit for all analytes.

 Field Blank Analysis : EPA compared the sample results from a specific sampling point to the field blank resu lts for the same sampling point , on the specific day of sample collection. For the purpose of th e loadings calculati ons, EPA made the following assumptions based on the resu lts of this fiel d blank analysis:

 If the sample result was less than five times the field blank result, then the sample result was treated as a non-detect;

 If the sample result was between five a nd 10 times the field blank result, then the sample result was flagged and ha ndled as a qualified value; and

 If the sample result was greater than 10 tim es the field blank result, then the sample result was unchanged.
Note: EPA used field blank results measur ed above the quantitation limit for this analysis; J-values associated with field blanks sample s were not used.

 Duplicate Sample Results : EPA averaged the results fr om each duplicate sample with the results of its original sample. EPA made the following assumptions when averaging the duplicate results:

 If one value was quantified and the ot her value was not quantified above the quantitation limit, then EPA used one-half the sample-specific quantitation limit for the non-quantified result in calculating the average;

 If both values were not quantified above th e sample-specific quantitation limit, then EPA used one-half the quantitation limit fo r both non-quantified results in calculating the average; and

 Both qualified and unqualified data were used in the calculation.

62 Only EPA sampling activities collected and analyzed fi eld blank and duplicate samples. EPA CWA 308 sampling program did not include duplicate sample an alysis therefore, only the field blank analysis was conducted on this data set. The plant-provided self-monitoring data included no field blank or duplicate samples.Chapter 10 –Pollutant Loadings and Removals Methodology

10-5 The following subsections discuss the specific data used to calcul ate the mass and TWPE loadings for each option, starting w ith the baseline characterization.

10.2.1.1 Baseline FGD Wastewater Characterization

As discussed in Section 4.1.1, EPA identified 117 plants that operate wet FGD systems and discharge FGD wastewater. For the FGD disc hargers, EPA calculated baseline loadings by assigning pollutant concentrations based on the type of treatment sy stem currently in place at the plant. EPA assigned treatment in place for this wa stewater for one of four classes of treatment: surface impoundment, chemical precipitation, bi ological treatment, and vapor-compression evaporation. As discussed in Section 4.1.1, EPA used survey data to determine the baseline FGD wastewater treatment in place. Based on surv ey responses, EPA categorized 47 plants as operating a treatment system more advanced than a surface impoundment:

 Forty plants operate a one-stag e chemical precipitation system;

 Five plants operate a bi ological treatment system; 63 and

 One plant operates a vapor-compression evaporation system. 64

EPA categorized all plants not operating one of these three ty pes of treatment systems as impoundment systems in the baseline loadings ca lculations. 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 sy stems that do not include hydroxi de or sulfide precipitation (e.g., clarifier with polymer addition). The operations of these types of systems are effective at removing solids and metals in the particulate pha se but do not achieve removals of dissolved solids, similar to the operation of an impoundment.
Surface impoundments use gravity to remove pa rticulates from wastewater, reducing the amount of TSS and particulate forms of other specific pollutants in the wastewater. EPA’s sampling program collected and analyzed the untreated FGD wastewater from seven steam electric power plants operating wet FGD system s that use either chemical precipitation or chemical precipitation followed by biological treatment to treat th e FGD wastewater (see Section 3.3 for a description of these sampling activities and plants). Based on an alytical data for the untreated FGD wastewater at these sampled plan ts, EPA estimated the effluent concentration from a surface impoundment by assuming the surf ace impoundment will remove most of the particulate phase metals from the wastewater but not dissolved. EPA calculated proxy values representing impoundment effluent concentrations for each analyte using the data for each of these seven EPA sampled plants. The met hodology for calculating these proxy values is described below. EPA also obtained surface impound ment effluent data from a steam electric power plant that treats only FGD wastewater in an impoundme nt. EPA averaged the surface

63 Six plants currently operate biological treatment systems, but at the time the costs and loadings were developed, EPA had only identified five plants with biological treatment systems. Therefore, only five of the six plants were identified as having biological tr eatment in place for these analyses.

64 Through additional information collected during the rulema king, EPA identified two additional plants that plan to install a vapor-compression evaporation system to treat FGD wastewater by 2014 when the rule is promulgated. EPA identified these systems after completing the polluta nt removals; therefore, pollutant removal estimates currently show removals under the vapor- compression evaporation technology option.Chapter 10 –Pollutant Loadings and Removals Methodology

10-6 impoundment data along with the estimated impound ment effluent concentrations from the seven sampled plants for each analyte to generate an average effluent concentration data set for FGD surface impoundments based on the eight plan ts. Table 10-3 presents the average characterization data used to calculate baseli ne loadings for plants currently treating FGD wastewater in a surface impoundment prior to discharge.
Approximately 40 percent of plants discharg ing FGD wastewater use a more advanced treatment system. For those plants currently ope rating a one-stage chemical precipitation system, biological treatment system, or vapor-compr ession evaporation system, EPA used the concentration data sets associated with th e post-compliance technology options to calculate baseline loadings. Section 10.2.1.2 discusses th e characterization of one-stage chemical precipitation systems. Sections 10.2.1.3 and 10.2.1.4 discuss the characterization of one-stage chemical precipitation systems with biological tr eatment or with vapor-compression evaporation systems, respectively.

Calculating FGD Settling Pond Effluent Concentrations As described earlier, EPA used the FGD wast ewater data collected during the sampling program and monitoring data provided by Progr ess Energy Carolinas’ Roxboro Steam Electric Plant (Roxboro) to estimate the effluent concen trations from a surface impoundment used to treat FGD wastewater. EPA made the following assumpti ons and performed the following analyses to calculate the loadings associ ated with the effluent from a FGD surface impoundment:

 Metal Concentrations in the Solid Phase : As part of EPA’s sampling program, the laboratories analyzing the sc rubber purge wastestreams were required to perform a biphasic separation of the scrubber purge sample and analyze both the solid and aqueous phase for each analyte. EPA only required the laboratory to perform the analysis if the wastewater sample contai ned greater than one percent solids. Both laboratories performed the biphasic separati on for the FGD wastewater samples from Hatfield’s Ferry, Keystone, and Miami Fo rt; however, one laboratory performed the analysis of the solids based on the wet so lids, while the other laboratory dried the solids prior to performing the analysis. Th erefore, one of the laboratories produced a wet weight solid concentration, whereas th e other laboratory produced a dry weight solid concentration. To put the concentrati ons on the same basis, EPA converted the wet weight solid concentrations to dry we ight solid concentrations using Equation 10-3.

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                

         

 (10-3)

where:

C Dry = Dry weight concentration of the analyte in the solid phase of the sample,Chapter 10 –Pollutant Loadings and Removals Methodology

10-7 C sample = Concentration of the anal yte in the aqueous phase of the sample,

C wet = Wet weight concentration of the analyte in the solid phase of the sample, and %Solids (of solid phase) = Percent solids present in th e solid phase of the sample.

Additionally, EPA calculated so lid phase concentrations for the plants where the FGD wastewater sample contained less than one percent solids. EPA performed this calculation for the Allen, Belews Creek, Dickerson, and Pleasant Prairie FGD wastewater data. EPA used Equation 10-4 to calculate dry weight solid concentrations for each analyte from these plants.

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     (10-4)

where:

C Dissolved = Dissolved concentration of the analyte in the sample,

C Dry = Dry weight concentration of the analyte in the solid phase of the sample,

C Total = Total concentration of the analyte in the sample, and

C TSS = Total suspended solids concentration in the sample.

 Calculating Settling Pond Effluent Concentr ations for Metals from FGD Wastewater Data : To estimate the effluent concentrati ons of metals from a surface impoundment used to treat FGD wastewaters based on scrubber purge concentration data, EPA assumed that the surface impoundment w ould only achieve removals of metals present in the particulate phase of the samp le and, therefore, would not remove metals present in the dissolved phase. EPA also assumed that the surface impoundment would achieve an effluent TSS concentrati on of 30 mg/L, which is the current 30-day average effluent limit for low-volume wa stewaters set in 40 CFR 423 for the best practicable control technol ogy currently available. EPA used this methodology to estimate the surface impoundment effluent conc entration for all data collected from the sampled plants. EPA derived the basis for the assumption that the metals in the dissolved phase of the FGD wastewater are not significantly trea ted in a surface impoundment from data presented by the Electric Power Resear ch Institute (EPRI) in the Flue Gas Desulfurization (FGD) Wast ewater Characterization: Screening Study, dated March 2006 [EPRI, 2006a]. In that report, EPRI pres ents FGD blowdown data for eight coalfired power plants. For six of the plants, da ta are presented for a filtered sample, aChapter 10 –Pollutant Loadings and Removals Methodology

10-8 “settled” sample, and a total sample. In the report, EPRI indicates that the “settled” sample was collected by allowing the sample to settle for one hour, and then an aliquot was collected from five inches be low the surface of the sample. EPRI’s report states that this “equates to a settling velocity of 0.41 ft/h r or an overflow rate of 3.2 million gallons per day/acre” [EPRI, 2006a]. In another EPRI report, EPRI Technical Manual – Guidance for Assessing Wastewat er Impacts of FGD Scrubbers, dated December 2006, EPRI references the “settled” sample data from the Flue Gas Desulfurization (FGD) Wastew ater Characterization: Scre ening Study and states that they “can be viewed as pond effluent” [EPRI, 2006b].
The FGD blowdown data for the six plants from the Flue Gas Desulfurization (FGD) Wastewater Characterization: Screening Study [EPRI, 2006a ] are presented in Table 10-4 and Table 10-5. Table 10-4 presents the data for three of the six plants, and Table 10-5 presents the data for the other three plants. After re viewing the data for these six plants, EPA determined that for mo st of the metal analytes and for most of the plants, the “settled” results were usua lly similar to the filtered (or dissolved) concentration for the analyte. Therefore, EPA concluded that the effluent from a surface impoundment will not achieve significan t removals of metals present in the dissolved phase of the sample.
To calculate the surface impoundment effluent concentrations, EPA assumed that the total surface impoundment effluent concen tration was equal to the sum of the contribution from the solids present in the wastewater and the dissolved concentration present in the wastewater. EPA assumed that the concentration of the metal present in the solid phase of the sample at the effluent is equal to the concentration of the metal present in the solid phase of the sample in the FGD wastewater. Additionally, EPA assumed a TSS concentration of 30 mg/L at the effluent. These two assumptions allowed EPA to calculate the solid phase contribution to the total concentration in the surface impoundment effluent. Additionall y, EPA assumed that the dissolved concentration in the effluent was equal to the dissolved concentration in the FGD wastewater. Finally, EPA assumed that the total concentrat ion in the surface impoundment effluent is equal to the solid phase contribution plus the dissolved phase contribution. Equation 10-5 was us ed to perform this calculation.

(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       (10-5)

where:

C Dissolved = Dissolved concentration of the analyte in the wastewater sample,

C Dry = Dry weight concentration of the analyte in the solid phase of the wastewater sample, and

C Settling = Calculated concentration of the analyte in the effluent from a surface impoundment.Chapter 10 –Pollutant Loadings and Removals Methodology

10-9  Estimating Settling Pond Effluent Concentrations for Classicals : To estimate the effluent concentrations of classicals from a surface impoundment for the seven sampled plants, EPA used information colle cted from two plants as part of the sampling program during the detailed study: Tennessee Valley Authority’s Widows Creek Fossil Plant (Widows Creek) and Buckeye Power Company’s Cardinal Power Plant (Cardinal). The data EPA collected from the Widows Creek plant represented the effluent from a surface impoundment used to treat FGD wastewater and the data EPA collected from Cardinal represented the effluent from a surface impoundment used to treat fly ash transport water. EP A compared the effluent values for the classical analytes for the two plants, as well as the percent removals achieved by the surface impoundments (compared to the samples collected at the influent to the surface impoundments). 65 Based on the results of the comparison, EPA made the following assumptions to estimate the settli ng pond effluent concentrations for the classical analytes:

- TSS: EPA assumed a concentration of 30 mg/L, based on the assumption for the metals calculation methodology;

- TDS: EPA assumed the concentration at th e effluent is equal to the influent concentration (i.e., no removal);

- Chloride: EPA assumed the concentration at the effluent is equal to the influent concentration (i.e., no removal); and

- Ammonia, biological oxygen demand (BOD), chemical oxygen demand (COD), cyanide, nitrate/nitrite, sulfate, total Kjeldahl nitrogen (TKN), and total phosphorus: EPA did not estimate a concen tration for these pollutants in the effluent from a surface impoundments for the plants with sampling data. 66

EPA then took the Roxboro monitoring data a nd calculated an averag e concentration for each analyte for which data were available. Using the average Roxboro surface impoundment effluent concentrations and the calculated e ffluent surface impoundment concentrations for each of the sampled plants, EPA calculated an av erage concentration for each analyte. This calculation resulted in an overall average concentration for each analyte, which EPA then used to calculate the loadings.
Finally, although EPA did not develop a me thodology to estimate the effluent concentrations for COD, cyanide, nitrate/ nitrite, and total phosphorus from a surface impoundment based on the FGD wastewater concentr ations, EPA believes that these analytes are present in the effluent from the surface impoundme nt. Therefore, to account for these pollutants in the loadings analysis, EPA assumed that the co ncentrations of these pollutants were equal the concentrations calculated for the one-stage chem ical precipitation system effluent. Table 10-3 presents the average concentration data used to calculate baseline loadings for plants currently treating FGD wastewater with a surf ace impoundment prior to discharge.

65 The influent and effluent samples collected from th e surface impoundment do not represent paired samples.

66 BOD, COD, TKN, and total phosphorus do not have TWFs and therefore, do not contribute to the calculated TWPE for the FGD loadings.Chapter 10 –Pollutant Loadings and Removals Methodology

10-10 10.2.1.2 Baseline and Post-Compliance One- Stage Chemical Precipitation Characterization
As part of the sampling activities describe d in Section 3.3, EPA identified and collected data from seven plants operating chemical preci pitation systems, sometimes in conjunction with other technologies, such as biol ogical treatment. The specific operating characteristics of the chemical precipitation treatment systems varie d. EPA conducted an engineering review of the data and identified three systems operating consistently with the one-stage chemical precipitation technology basis. These three plants operate one -stage chemical precipitation systems that include the addition of organosulfide.
The treatment systems at these plants have similar operations; however, the plants do have varying configurations and ope rating characteristics, such as thickeners, filter presses, sand filters, and retention time. Each of these systems was designed and is operated to remove suspended solids and dissolved metals from the FGD wastewater to achieve a similar level of pollutant discharge. The systems are sized to ha ndle a specific flow rate of FGD wastewater, which means that the sizes of the tanks were designed to allow for the residence time required for settling and/or reactions to occur in order to achieve efflue nt concentrations meeting the plant’s permit limits.
To calculate the pollutant concentrations for the one-stage chemical precipitation technology option, EPA first calculat ed an average concentration for each analyte using only the four-day EPA sampling data for each plant for which data were available. EPA included only total concentrations except for hexavalent chromium, which is analyzed only as a dissolved constituent. EPA then calculated an average conc entration for each analyte at each plant by using the four CWA 308 monitoring data results along with the average of the four-day EPA sampling data (i.e., treating these as five results and calculating the average).
Using the average concentrations from the th ree plants, as calculated above, EPA then calculated an overall average concentration for each of the analytes shown in Table 10-6. EPA used this average concentration to calculat e the post-compliance loadings that would be discharged by plants that curre ntly operate surface impoundments if they were to install the chemical precipitation technology. EPA also used th e average concentrations presented in Table 10-6 to calculate the baseline lo adings for any plant currently operating a chemical precipitation treatment system as FGD wastewater treatment.
As explained above, the values presented in Ta ble 10-6 reflect three plants identified as operating consistently with the technology basis, and EPA has applied these values to all plants that operate chemical precipitation systems as th eir baseline concentrat ions. As discussed in Section 10.2.1.1, EPA classified 38 ot her plants as operating chemi cal precipitations systems. However, these 38 plants do not operate their ch emical precipitation system in the same manner as the technology basis (or have all the compone nts included in the tech nology basis) and would likely discharge greater pollutant concentrations than the systems reflecting the technology basis. Further, for these 38 plants that operate chemical precipitation systems that are not equivalent to the technology basis, the baseline and post- compliance loadings ar e identical, and EPAChapter 10 –Pollutant Loadings and Removals Methodology

10-11 calculates no removals for these plants, even though these plants are being assessed compliance costs to upgrade the system to opera te similarly to the technology basis. 67

10.2.1.3 Baseline and Post-Compliance One-Stage Chemical Precipitation and Biological Treatment Characterization

EPA identified and collected data from tw o plants operating chemical precipitation systems in conjunction with biolog ical treatment systems that represent the biological treatment technology option for the proposed rule. After co nducting an engineering review of the data, EPA determined that both plants operate syst ems consistent with the one-stage chemical precipitation with biological tr eatment technology option. Both of the sampled plants operate chemical precipitation systems followed by a noxic/anaerobic biological treatment systems specifically designed for selenium removal. EPA used the data from both plants to represent treatment performance of a one-stage chemical precipitation system with biological treatment system; however, these two plants do not fully represent the technology option because neither plant currently uses sulfide precipitation in the chemical precipitation syst em. Therefore, the two plants likely do not demonstrate mercury (and other metals) effluent concentrations as low as could be achieved by the one-stage chemical prec ipitation (with sulfide precipitation) followed by a biological treatment system that forms the basis of the option (see Section 6.2 for complete description).
EPA has multiple sets of data for these tw o plants, including EPA sampling data, Clean Water Act (CWA) 308 sampling data, and self-monito ring data, to calculate pollutant loadings associated with this technology op tion. To calculate the average po llutant concentrations for the biological treatment system technology option, EP A first compared long-term self-monitoring data provided by the plants to EPA sampling data and CWA 308 monitoring data to determine which analytes were represented in different se ts of data. In cases where an analyte was not represented in the long-term self-monitoring data , but was represented in the EPA sampling and CWA 308 monitoring data, EPA aver aged the four-day EPA sampling results and then combined that average with the four CW A 308 monitoring data results (i.e ., EPA treated them as five results) for each plant. EPA then averaged these five results to calculate an overall plant-level average concentration for each of those analytes. In cases where an analyte was represented in the long-term self-monitoring data provided by th e plant, the EPA sampling data, and the CWA 308 monitoring data, EPA averaged all sample results to calculate a plant-level average concentration for each analyte. When combini ng the industry self-monitoring data with EPA’s sampling results (both four-day EPA sampling and CWA 308 monitoring), there were some instances of overlap with two sample results o ccurring on the same day. In these cases, the two results were averaged together to calculate one average concentration for each day of sampling before calculating an average concentration for each analyte.
Using the average concentrations from th e two BAT plants, EPA calculated an overall average concentration for each analyte. These ar e presented in Table 10-7. EPA used the average concentrations to calculate the post-compliance loadings that would be discharged by plants currently operating surf ace impoundments or chemical precipitation systems if they were to install all components of the biological technology opti on. EPA also used the average

67 This approach results in an underestimate of the pollutant removals achieved by these 38 plants.Chapter 10 –Pollutant Loadings and Removals Methodology

10-12 concentrations presented in Tabl e 10-7 to calculate the baseline loadings for any plant currently operating chemical precipitation a nd a biological treatment system as FGD wastewater treatment.
The average concentration used to calculate baseline and post-compliance loadings for the chemical precipitation and bi ological treatment system tec hnology basis, presented in Table 10-7, is based on two plants iden tified as operating consistently with the technology basis. As discussed in Section 10.2.1.1, EPA cl assified five plants as op erating biological treatment systems. 68 For each plant classified as a baseline bi ological treatment system, EPA calculated the baseline loadings using the average concentratio n presented in Table 10-7. Two of these plantsdo not operate consistently with the technology basis and likely discharge greater pollutant concentrations than the system reflecting the technology basis. 69 Further, for these two plants, the baseline and post-compliance loadings are id entical and show no additional removals even though these plants are being assessed compliance costs to upgrade the sy stem to achieve the technology basis. 70

10.2.1.4 Baseline and Post-Compliance One-Stage Chemical Precipitation and VaporCompression Evaporation Characterization
EPA conducted an engineering review of the data for the two plants operating vaporcompression evaporation system. Because only one plant matches the technology basis and operates a hydroxide-sulfide chemical precip itation system followed by softening, a brine concentrator, and crystallization system, EPA us ed data from this plant to represent the technology option.
To calculate the average pollutant concentr ations for the vapor-compression evaporation treatment system technology option, EPA first calcu lated an average concen tration by analyte for each of the two wastestreams at the plant (i.e., brine concentrator distillate and crystallizer condensate) using available sampling data (i.e., three-day EPA sampling data). For this plant, EPA collected and analyzed only total concentr ations; therefore, the Agency did not have dissolved concentrations or hexavalent chromium data to use in the analysis.
Using the average concentrations from the tw o streams (i.e., brine co ncentrator distillate and crystallizer condensate), EPA calculated an overall average concentration for each analyte, shown in Table 10-8. 71 EPA used this average concentra tion to calculate the post-compliance loadings that would be discharged by plants currently operating surface impoundments, chemical precipitation systems, or biological treatment systems if they were to install all components of the vapor-compression evaporation technology option. EPA also used the av erage concentrations

68 Six plants currently operate biological treatment systems, but at the time the costs and loadings were developed, EPA had only identified five plants with biological treatment systems. Therefore, only five of the six plants were identified as having biological tr eatment in place for these analyses.

69 Of the total five baseline biological treatment plants, only three are classified as oper ating consistently with the technology basis.

70 This approach results in an underestimate of the pollutant removals achieved by these two plants.

71 EPA used both the brine concentrator distillate and cr ystallizer condensate streams to calculate the loadings because both wastestreams could be disc harged. The vapor-compression system at Brindisi is operated as a zerodischarge system with no wastewater being discharged to surface water or a POTW. The plant could choose to discharge the brine concentrator and the crystallizer condensate st reams together or separately.Chapter 10 –Pollutant Loadings and Removals Methodology

10-13 presented in Table 10-8 to calcu late the baseline loadings fo r any plant currently operating chemical precipitation and a vapor-compressi on evaporation treatment system as FGD
wastewater treatment.

10.2.2 Ash Impoundment Wastewater Characterization
During this rulemaking effort, EPA relied on publicly available data sources to characterize the effluent stream from ash impou ndments at steam electric power plants; these sources are listed below:

 EPA ash impoundment sampling data from the detailed study [U.S. EPA, 2009],

 Electric Power Research Institute (EPRI) Po wer Plant Integrated Systems-Chemical Emissions Study (PISCES) Reports [EPRI, 1997-2001],

 Permit application data, as provided by memb er companies of the Utility Water Act Group (UWAG) [UWAG, 2008],

 Development Document for Final Effluent Limitations Guidelines, New Source Performance Standards, and Pretreatment St andards for the St eam Electric Point Source Category , EPA 440-1-82-029, November 1982 (1982 TDD) [U.S. EPA, 1982], and

 The Steam Electric Technical Ques tionnaire Database [ERG, 2012a].
Each of the five data sources was discussed in Chapter 3. EPA used information available from each data source to characterize the impound ment/outfall as either a fly ash impoundment, bottom ash impoundment, or combined ash impoundme nt. For the purposes of this analysis, EPA used the following criteria to make those determinations:

 Fly ash impoundment: An impoundment/outfall th at receives fly ash transport water and does not receive bottom ash transport water or any other combustion residual wastes. The impoundment may also receive other types of wastewater (e.g., low volume wastewaters, cooling water).

 Bottom ash impoundment: An impoundmen t/outfall that receives bottom ash transport water and does not receive fly as h transport water or any other combustion residual wastes. The impoundment may also receive other types of wastewater (e.g., low volume wastewaters, cooling water).

 Combined ash impoundment: An impoundment /outfall that receives both fly ash transport and bottom ash transport water. The impoundment may also receive other types of wastewater (e.g., low volum e wastewaters, cooling water).

EPA used the concentration data obtained from the data sources described in Chapter 3 to calculate the average pollutant concentration in fly ash transport water, bottom ash transport water, and combined ash transport water. EPA notes that, because the data associated with these impoundments may include other wastestreams (e.g., cooling water), the concentrations may beChapter 10 –Pollutant Loadings and Removals Methodology

10-14 diluted and therefore, may underestimate the pollutant loadings. 72 For each data point, EPA first identified the type of impoundment system th e data represents (i.e., fly ash impoundment, bottom ash impoundment, combined ash impoundm ent). EPA then calculated an average pollutant concentration for each impoundment for which EPA had data. For example, if a plant had pollutant concentration data for their fl y ash impoundment for more than one day, EPA averaged all the fly ash impoundment concentration data for that sp ecific pollutant to get a single value to represent the average co ncentration of that pollutant in the effluent from the fly ash impoundment. Equation 10-6 was used to calculate the average concentrati on of a pollutant in the effluent from a fly ash impoundment.
Fly Ash Impoundment Concentration = the averag e across all concentration results for each pollutant = Σ Fly Ash Impoundment Concentration / Number of data points (10-6)

EPA used the same equation to calculate the average concentration of a pollutant in the effluents from bottom ash impoundments and co mbined ash impoundments. For some data sources, there may only be one data point, and therefore, the aver age is the same as the single data point. When performing this calculation, EPA reviewed the data and, as appropriate, made some substitutions to the data sets. EPA set nonde tects equal to one-half the quantitation limit for the detailed study sampling data be cause EPA knew the quantitation limit. 73 For the other data sets (i.e., EPRI, 1982 TDD, and Form 2C), EPA c ould not confirm whether the non-detect results were presented as less than the quantitation lim it or less than the MDL (or some other value); therefore, EPA set the non-detect s equal to the value provided.
After calculating an average concentration fo r each type of impoundment at the plantspecific level, EPA calculated an industry-level average pollutant concentration for each type of impoundment for which EPA had data by averaging the plant-level average concentrations for each type of impoundment. For example, EPA calculated an industry average pollutant concentration for a fly ash impoundment by calcul ating the average concentration across all fly ash impoundments for which EPA had data, using the average plant-specific fly ash impoundment pollutant concentr ations from Equation 10-6.
Industry Fly Ash Impoundment Con centration = average across all c oncentration results for each pollutant = Σ Fly Ash Impoundment Concentration / Number of Fly Ash Impoundments (10-7)

EPA used the same equation to calculate the industry average concen tration of pollutants in the effluent from bottom ash impoundment s and combined ash impoundments. Table 10-9 presents the average pollutant concentration for all three types of ash impoundments (i.e., fly ash impoundment, bottom ash impoundment, and comb ined ash impoundment). EPA used these average concentration data sets to calculate the baseline load ings for discharges from ash impoundments.

72 Because this approach may underestimate the actual pollu tant concentrations for th e impoundment effluent if there was no dilution, the baseline pollutant loadings would be underestimated and result in underestimating the pollutant removals that would be attained by the technology option considered for the proposed rule.

73 To simplify the discussion, for the purpose of Section 10.2.2 the term “non-detect” is used to refer to both values measured below the quantitation limit and those values measured below the detection limit.Chapter 10 –Pollutant Loadings and Removals Methodology

10-15 The technology option under consideration fo r both fly ash and bottom ash is dry ash handling or closed-loop recycle system. These systems do not discharge ash transport water; therefore, the average effluent concentration associated with the proposed technology option is zero. Because no ash transport water is discharg ed, the post-compliance discharge loading is

zero.

10.2.3 Combustion Residual Leachate Wastewater Characterization

As described in Section 9.1, EPA determin ed that combustion residual impoundments will recycle the leach ate back to the impoundment from which it was collected rather than install the technology basis for the di scharge requirements. EPA does not expect this recycled impoundment leachate to alter the discharge lo adings of the impoundment in any way. By recycling leachate generated by the impoundment b ack into the same impoundment no additional pollutants are added to the system (i.e., the su rface impoundment). The pollutants contained in the impoundment leachate were previously in the system; adding these pollutants back to the system at the concentrations found in the leachate will not alter the system as a whole. Therefore, EPA finds that baseline and post-compliance po llutant loadings will be the for combustion residual impoundment leachate. Therefore, the re mainder of this section only discusses the pollutant concentrations associated with combustion residual landfill leachate.
As described in Chapter 9, EPA evalua ted two technology options for treating combustion residual landfill leachate: one-stage chemical precipitation and one-stage chemical precipitation with biological treatment. EPA used data co llected though the Steam Electric Survey to calculate average effluent concentrations for untreated combustion residual landfill leachate.
EPA’s Steam Electric Survey required certain plants to collect and analyze samples of landfill leachate and report the re sults of these analyses in Part G (Leachate Sampling Data for Ponds/Impoundments and Landfills) of the survey. EPA requested these plants to sample any untreated landfill leachate collected from an on-site landfill containing combustion residuals. EPA used these data to calculate an active and in active pollutant concentration data set for use in loadings calculations. EPA used all data as provi ded by the plants in the survey, except for the following:

 For values reported as less than the repor ting limit, EPA assumed the concentration was equal to one-half the reporting limit provided.

 If the plant did not provid e a reporting limit, ERG assumed the concentration was equal to the MDL.
EPA compiled all untreated landfill leachate sa mpling data reported in the Steam Electric Survey from 26 landfills and spli t them into groups based on th e landfill type (i.e., active or inactive). The responses to the survey included da ta from 22 active combustion residual landfills and four inactive combustion residu al landfills. To determine the industry average concentrations for a pollutant, EPA first averaged all concentr ation data provided for each individual landfill providing sampling data to calcu late a landfill-specific aver age concentration. EPA then averaged the landfill-specific average concentrati ons at each plant based on the landfill type (i.e., active or inactive) to get a plant-level average pollutant leachate concentration for each landfillChapter 10 –Pollutant Loadings and Removals Methodology

10-16 type. EPA then used the average plant-level combustion residual landf ill concentration to calculate the average concentrations across a ll plants. Table 10-10 presents the average concentration for leachate from active and inactive landfills. EPA used these average concentrations to calculate baseline loadings for all plants discharg ing combustion residual landfill leachate.
As explained in Section 9.3, based on a re view of the Steam Electric Survey data regarding the treatment of the combustion residu al landfill leachate, EPA did not identify any plants currently operating a chem ical precipitation system to treat landfill leachate. Therefore, EPA transferred the limitations and standards from the FGD chemical precipitation system. Because EPA does not have analytical data th at represent treated landfill leachate for the technology options being consider ed, EPA also transferred th e FGD chemical precipitation effluent concentrations, identified in Section 10.2.1.2, to the landfill leachate for the purposes of calculating post-compliance loadings. In cases wher e the average concentration of the untreated active or inactive combustion residual landfill leac hate is less than the FGD treated concentration for the technology option, EPA assumed that the tr eated concentration was equal to the influent (untreated leachate) average c oncentration. In this case, EPA did not calculate additional removals of these partic ular pollutants by the wastewater treatment system.

10.3 W ASTEWATER F LOW R ATES FOR P OLLUTANT L OADINGS
As discussed earlier, EPA used plant-specifi c wastewater flow rates in the loadings calculations. EPA used information from the Steam Electric Survey to determine which plants discharge each specific wastestream of concer n and the amount of wastewater each plant reported discharging. Each of the following sections provides mo re detail on EPA’s methodology for calculating the specific wastewater flow rates used in th e loadings calculations.

10.3.1 FGD Wastewater Flow Rates for Pollutant Loadings
As described in Section 6.1.4, EPA used plant- level FGD wastewater flow rates from the “FGD Input Table” to calculate compliance costs. FGD loadings estimates use the same plantlevel FGD wastewater flow rates. Section 4.1.1 describes the methodology used to populate the “FGD Input Table.” EPA used the same FGD wastew ater flow rates in both the FGD wastewater technology cost modules as well as the FGD wastew ater loadings to ensu re consistency between the two estimates. A copy of the input table is included in the appendix.

10.3.2 Ash Transport Water Flow Rates for Pollutant Loadings

As discussed in Section 4.1.2, EPA used Steam Electric Survey data to identify which plants discharge or have the potential to discha rge fly ash or bottom ash transport water. Ash surface impoundment loadings are calculated for each of these plants based on the amount of ash transport water discharged. The “Ash Transpor t Water Input Table” holds all the input data needed to calculate the baseline loadings fo r ash surface impoundments. The “Ash Transport Water Input Table” contains the following fields:

 Plant_id: Survey Plant ID.

 EIA ID : EIA Plant ID.Chapter 10 –Pollutant Loadings and Removals Methodology

10-17  System_ID : Survey Pond System ID.

 Influent : Flag to identify the influent to th e surface impoundment system (e.g. fly ash transport water, bottom ash transport water, fly and bottom ash transport water, or combined ash transport water).

 Surface Impoundment Type : Flag to identify the type of surface impoundment. This identifier is based on the type of tran sport water held by the surface impoundment. The flag can be fly ash, bottom ash, or combined ash for surface impoundments containing both fly and bottom ash transport water.

 Ash Flow (GPD) over 365 days : The flow of ash transport water into the surface impoundment in gallons per day. This flow rate has been normalized for continuous flow over 365 days per year.

 Ash Flow CBI : Flag indicating that the ash trans port water flow should be considered CBI. CBI flag is marked if any data used to populate the input table was marked as CBI by the plant.

 Calculated Ash Flow : Flag to identify which ash flow values were estimated.

 Retired?: Flag indicating that the plant has id entified that it will be retiring on or before 12/31/2014.
Section 4.1.2 provides more detail on the me thodology used to determine the ash flow rate and a discussion of the “Ash Transport Wate r Input Table” in. A copy of the “Ash Transport Water Input Table” is in cluded in the appendix.

10.3.3 Combustion Residual Landfill Leachate Flow Rates for Pollutant Loadings
As described in Section 9.4, EPA used plant- level leachate flow rates from the “Landfill Leachate Input Table” to calculate compliance cost s. Leachate loadings estimates use the same plant-level flow rates. Section 4.1.3 describe s the methodology used to populate the “Landfill Leachate Input Table.” EPA used the same landf ill leachate flow rates in both the leachate technology cost modules as well as the leachate loadings to ensu re consistency between the two estimates. A copy of the input tabl e is included in the appendix.

10.4 B ASELINE AND P OST -C OMPLIANCE P OLLUTANT L OADINGS AND TWPE R ESULTS
As discussed in Section 10.1, EPA multiplied th e average pollutant concentrations for each wastestream presented in Section 10.2 with the plan t-specific wastewater flow rates presented in Section 10.3 to calculate the amount of pollutant discharged to su rface waters for each plant and wastestream, as applicable. For those plants transferring the wastewater to a POTW, EPA adjusted the loadings to acc ount for additional removals that would take place at the POTW. After calculating these loadings for each plant a nd wastestream, EPA then calculated the TWPE associated with the pollutant discharges. These calculations were completed for the baseline and post-compliance pollutant loadings for each plan t associated with each technology option. Usingthe plant-level loadings by wastestream, EPA was then able to calculate the baseline and postcompliance loading at the industry level fo r each wastestream and regulatory option. The following section discusses the specific loadings and TWPE calculations for each wastestream and each technology option being considered. The section also presents the industry-levelChapter 10 –Pollutant Loadings and Removals Methodology

10-18 loadings for each wastestream. The pollutant-l evel baseline loadings and pollutant-level removals for each regulatory option by wastes tream are presented in the memorandum entitled, “Steam Electric Pollutant-Level Loadings and Removals for Each Wastestream and Regulatory Option” (DCN SE03970).

EPA is proposing to apply diffe rent effluent limits to oil- fired units and units with a capacity of 50 MW or less. For discharges from these generating units, BAT would be set equal to the current BPT standard for each of the wast estreams for which EPA is proposing revisions to the ELGs. For the tables presenting the results of the loadings and the pollutant removals in this section, EPA presents two different versions of the tables: one ve rsion that includes the loadings and pollutant removals based on all generati ng units/plants discharg ing the wastestream installing the appropriate technology basis, and a second version based on all oil-fired units and units with a capacity of 50 MW or less not needing to install the technology basis because the current controls are sufficient to meet the BPT requirements.

Section 5 of the Technical Development Document for the Proposed Effluent Limitations Guidelines and Standards for the Steam Elect ric Power Generating Point Source Category (TDD) provides more details regarding the analys es of these factors. Section 8.1.3 of the TDD discusses the rationale regarding the decision.

10.4.1 FGD Wastewater Loadings and TWPE
EPA calculated plant-specific loadings for each of the technology options considered for FGD wastewater. For baseline loadings, EPA multiplied the plant-specific FGD wastewater discharge flow rate with the aver age pollutant concentrations that represent the current level of treatment at the plant (i.e., surface impoundment, chemical precipitation, bi ological treatment, or vapor-compression evaporation). EPA identified th ree plants transferring FGD wastewater to a POTW. For these three plants, EPA adjusted th e baseline loadings to account for pollutant removals associated with POTW treat ment, as described in Section 10.1.
For the post-compliance loadings associated with the one-stage chemical precipitation technology option, EPA assumed that the discharg e loadings calculated for plants currently treating their FGD wastewater with one-stag e chemical precipitation systems, biological treatment systems, or vapor-compression evapor ation systems remain unchanged from baseline. EPA assumed that plants with baseline surface impoundments would install one-stage chemical precipitation treatment systems to meet the effluent requirements associated with this option. EPA calculated post-compliance loadings for these plants using the average concentration data set associated with one-stage chemical precipit ation systems, presented in Table 10-6, and plantspecific FGD wastewater flow rates. As descri bed in Section 10.2.1.2, for each plant classified as a baseline chemical precipitat ion system, EPA used the same chemical precipitation effluent concentrations to calculate the baseline and post- compliance loadings, even if the system was not equivalent to the technology basis. This underes timates the pollutant removals being achieved by the treatment system because EPA does not calcul ate any removals for these plants, even though some of these plants are being assessed comp liance costs to upgrade the system to operate similarly to the technology basis.Chapter 10 –Pollutant Loadings and Removals Methodology

10-19 For the post-compliance pollutant loadings associated with the one-stage chemical precipitation treatment system followed by biological treatment technology option, EPA assumed that the post-compliance loadings calcul ated for plants currently treating their FGD wastewater with biological treatment systems or vapor-compression evaporation systems remain unchanged from baseline. EPA assumed that pl ants with surface impoundments would install one-stage chemical precipitation systems with biological treatmen t, and plants with one-stage chemical precipitation systems (but no biological treatment for selenium removal) would install biological treatment systems to meet the efflue nt requirements associat ed with this technology option. EPA calculated the post-compliance load ings for these plants using the average concentration data set associated with one-s tage chemical precipitation systems followed by biological treatment, presented in Table 10-7, and plant-specific FGD wastewater flow rates.
For the post-compliance pollutant loadings associated with the one-stage chemical precipitation treatment system followed by vapo r-compression evaporation option, EPA assumed that the post-compliance loadings calculated for plants currently treating their FGD wastewater with this type of system remain unchanged from baseline. EPA assumed that plants with any other current treatment method (i.e., surface impound ment, chemical precipitation, or biological treatment) would install one-stage chemical precipitation treatmen t systems with vaporcompression evaporation to meet the effluent re quirements associated with this technology option. EPA calculated the post-compliance load ings for these plants using the average concentration data set associated with one-sta ge chemical precipitation systems with vaporcompression evaporation, presented in Table 10- 8, and plant-specific FGD wastewater flow
rates.
The raw data output of the FGD wastewater loadings database is included in the appendix, along with a table of plant-level lo adings in pounds/year a nd TWPE/year. Table 10-11 and Table 10-12 present the FGD wastewater loadi ngs on an industry-level for baseline and each post-compliance technology basis. Table 10-11 pr esents the loadings based on all units discharging FGD wastewater need ing to install the appropriate technolo gy basis, and Table 10-12 presents the loadings based on the oil-fire d units and units with a capacity of 50 MW or less not needing to install the t echnology basis. The loadings ex clude the pollutant parameters BOD, COD, total dissolv ed solids (TDS), and total suspe nded solids (TSS) because they double count the loadings for specific pollutants already included. The table includes the number of plants identified as discharging FGD wastewater, the total industry flow rate associated with each technology option, and the total industry load ing in pounds per year and TWPE per year. Table 10-13 and Table 10-14 pres ent the pollutant removals, in both pounds per year and TWPE per year, for the various technol ogy options. Table 10-13 presents the pollutant removals based on all units discharging FGD wast ewater needing to in stall the appropriate technology basis and Table 10-14 presents the pollutant removals based on the oil-fired units and units with a capacity of 50 MW or less not needing to install the technology basis. EPA calculated the pollutant removals by subtracting the technology option lo adings from the baseline loadings (or a less stringent technology option).

10.4.2 Ash Transport Water Loadings and TWPE
EPA calculated plant-specific loadings for th e baseline discharges and the technology option considered for ash transport water. Fo r baseline loadings, EPA multiplied the plant-Chapter 10 –Pollutant Loadings and Removals Methodology

10-20 specific ash transport water discharge flow rate fo r each type of ash transport water (i.e., fly ash, bottom ash, or combined ash transport water) by the appropriate average concentration data set for the type of discharge. For example, for each fly ash impoundment, EPA multiplied the normalized discharge flow rate described in Section 10.3.2 for the plant’ s fly ash impoundment by the average concentration data set associated with fly ash impoundment s presented in Section 10.2.2. EPA identified four plants transferring bottom ash transport water to a POTW and no plants transferring fly ash transport water to a POTW. For these four plants, EPA adjusted the baseline loadings to account for pollutant re movals associated with POTW treatment, as described in Section 10.1.

As described in Section 10.2.2, EPA collected ash transport water characterization data for fly ash impoundments, bottom ash impoundme nts, and combined ash impoundments. As such, EPA calculated loadings for each of these di fferent types of impoundments at a plant-level. Because EPA considered regulatory options that w ould establish different effluent requirements for fly ash and bottom ash, EPA analyzed the po llutant loadings and removals for these two wastestreams separately; therefore, EPA separa ted the loadings for combined ash impoundments into fly ash loadings and bottom ash loadings. EP A used data from the EPRI PISCES reports to estimate the breakout of the loadings among fly ash and bottom ash contributions. As discussed in Section 3.6, the PISCES reports include information from several sites operating impoundments receiving either fly as h transport water or bottom ash transport water. The Site A, B, C, and D EPRI PISCES repor ts include tables that present the loadings to the ash impoundments in kg/day for each wastewater st ream that is entering the impoundment for several metal pollutants. Based on this informati on, EPA used the loadings from the fly ash and bottom ash transport water streams in the EPRI PISCES reports to breakout the calculated combined ash loadings into fly as h loadings and bottom ash loadings.
To perform this calculation, EPA first review ed the information regarding the plants to determine whether the data were appropriate fo r use in the analysis. EPA made the following conclusions based on this review:

 Site A was excluded from the analysis because the fly ash transport water is only transferred to the ash impoundment during oc casional operation; therefore, compared to bottom ash transport water loadings, the fly ash transport water loadings were not representative of the operations at a typi cal plant with both wet fly and bottom ash sluicing operations.

 Site B was considered to be a representati ve plant and therefore was included in the analysis.

 Site C was considered to be a representati ve plant and therefore was included in the analysis.

 Site D has two separate plants at the site (i.e., Plants A and B). Plant A has wet fly ash and bottom ash for all six units, and Pl ant B has wet bottom ash for two units, but wet fly ash for only one of the two units; therefore, only Plant A fly ash and bottom ash loadings were included in the anal ysis. Plant B loadings were excluded.
EPA used the fly ash transport water and bo ttom ash transport water loadings presented in the EPRI PISCES reports for the sites descri bed above to calculate a site-specific percentChapter 10 –Pollutant Loadings and Removals Methodology

10-21 loading for fly ash and bottom ash for each pollutant . For example, for Site C, the aluminum fly ash loading is 190 kg/day and the bottom ash load ing is 7.8 kg/day; therefore, EPA calculated a total ash loading of 197.8 kg/day, an d the percent loading of alumin um for fly ash is 96.1 percent and the percent loading of aluminum for bottom ash is 3.9 pe rcent. For this calculation, EPA only included the fly ash and bottom ash loadings , even though EPRI included all wastewater sources entering the impoundment, because EPA is only evaluating the combined ash sluice water and is not considering ot her wastewater sources. EPA performed this calculation for each pollutant available for each of the three sites. EPA then calculated an average percent loading for fly ash and bottom ash for each pollutant using the percentage calculated for each plant. These average percent loadings for fly ash and bottom ash are presented in Table 10-15 for each pollutant available.
Because the percent loading for fly ash is cons istently higher than the bottom ash percent loading for all of the pollutants available, EPA assumed that the fly ash loading would be higher for the pollutants for which data were not avai lable. Therefore, EPA calculated the average percent loading for fly ash and bottom ash based on the pollutants availabl e, 86 and 14 percent, respectively, and assumed this value for the pe rcent breakout for all the other pollutants for which loadings were calculated for combined ash impoundments.
For both fly ash and bottom ash transport wate r, EPA is considering only one technology option: eliminating ash transport water discharge, either by conversion to dry ash handling (fly ash and bottom ash MDS) or conversion to a cl osed-loop recycle system (bottom ash remote MDS). EPA assumes that all plants currently di scharging ash transport water will install dry handling systems for fly ash a nd will operate wet-sluicing bo ttom ash handling systems as a closed-loop recycle system (i.e., zero discharge) or will convert to dry bottom ash handling, resulting in post-compliance loadings of zero fo r fly and bottom ash transport water pollutants for those plants subject to the proposed requirements.
The raw data output of the ash impoundment loadings database can be found in the appendix, along with a table of plant-level loadin gs in pounds/year and the plant-level loadings in TWPE/year. Table 10-16 presen ts the results of the baseline ash impoundment loadings on an industry level. The table include s the number of impoundments di scharging each type of ash transport water, the total industr y discharge flow rate, and the total industry loadings in pounds per year and TWPE per year associated with each type of impoundment. The industry loadings presented in Table 10-16 exclude the pollutant parameters BOD, COD, TDS, and TSS because they double count the loadings for specific pollutants already incl uded. Table 10-17 and
Table 10-18 present the pollutant removals, in both pounds per year and TWPE per year, between the baseline and the dry handling tec hnology option. Table 10-17 pr esents the pollutant removals based on all units discharging ash tran sport water needing to install the dry handling systems and
Table 10-18 presents the pollutant removals based on the oil-fired and units with a capacity of 50 MW or less not needing to instal l the dry handling/closed-loop recycle systems. EPA calculates the pollutant re movals by subtracting the tech nology option loadings from the baseline loadings.Chapter 10 –Pollutant Loadings and Removals Methodology

10-22 10.4.3 Combustion Residual Landfill Leachate Loadings and TWPE
EPA calculated plant-specific loadings for each of the technology options considered for combustion residual landfill leachate. For baseline loadings, EPA multiplied the plant-specific leachate discharge flow rate with the average po llutant concentrations that represent untreated combustion residual landfill leachate. EPA identified seven plants transferring landfill leachate to a POTW. For these seven plants, EPA adjusted th e baseline loadings to account for pollutant removals associated with POTW treatment.
For the one-stage chemical precipitation t echnology option, EPA assumed that all plants would install this type of treatment system. No plants currently treat l eachate with a one-stage chemical precipitation system, so all plants would need to install treatment to meet the effluent requirements associated with this option. Some plants can use existing FGD treatment systems, but these systems would also need to be m odified to achieve BAT limits. EPA calculated discharge loadings for these plan ts using the average concentrati on data set associated with onestage chemical precipitation systems, discusse d in Section 10.2.3, and plant-specific leachate flow rates, discussed in Section 4.1.3.
For the one-stage chemical precipitation treatment system with biological treatment technology option, EPA assumed that al l plants would install this t ype of treatment to meet the effluent requirements associated with this technology option. EPA calculated the discharge loadings for these plants using the average conc entration data set asso ciated with one-stage chemical precipitation systems followed by biologi cal treatment, presented in Section 10.2.3, and plant-specific leachate flow ra tes, discussed in Section 4.1.3.
The raw data output of the leachate loadings can be found in the appendix, along with a table of plant-level loadings in pounds/year and the TWPE/y ear. Table 10-19 and Table 10-20 present the combustion residual landfill leachate loadings on an industry-level for baseline and each technology option. Table 10-19 presents load ings based on all units discharging landfill leachate needing to install the appropriate tec hnology basis and Table 10-20 presents loadings based on the oil-fired units and units with a capac ity of 50 MW or less not needing to install the technology basis. The loadings exclude the pollu tant parameters BOD, COD, TDS, and TSS because they double count the loadings for sp ecific pollutants already included. The table includes the number of plants id entified as discharging landfill leachate, the tota l industry flow rate associated with each technology option, and th e total industry loadings in pounds per year and TWPE per year. Table 10-21 and Table 10-22 present the pollutant removals, in both pounds per year and TWPE per year, for the various technology options. Tabl e 10-21 presents the pollutant removals based on all units discharg ing landfill leachate needing to install the appropriate technology basi s. Table 10-22 presents the pollutant removals based on the oil-fired units and units with a capacity of 50 MW or less not needing to install the technology basis. EPA calculated the pollutant removals by subtracting the technology op tion loadings from the baseline loadings (or a less stri ngent technology option).

10.5 R EFERENCES

1. Duke Energy. 2011a. Industry Provided Samp ling Data from Duke Energy’s Belews Creek Steam Station. ( 17 August). DCN SE01808.Chapter 10 –Pollutant Loadings and Removals Methodology

10-23 2. Duke Energy. 2011b. Industry Provided Sampling Data from Duke Energy’s Allen Steam Station. (17 August). DCN SE01809.
3. Eastern Research Group (ERG). 2005. Memo randum to 2006 Effluent Guidelines Program Plan Docket, From Ellie Codding a nd Deb Bartram, ERG, re: Publicly Owned Treatment Works (POTW) Percent Removals Used for the TRI Releases2002 Database. (12 August). DCN SE02932.
4. Eastern Research Group (ERG). 2006. Toxic We ighting Factor Development in Support of CWA 304(m) Planning Pr ocess. (June). DCN SE01952.
5. Eastern Research Group (ERG). 2012a. Steam Electric Technical Questionnaire Database (“Steam Electric Survey”) . (19 April). DCN SE01958.
6. Eastern Research Group (ERG). 2012b. Fina l Sampling Episode Report, Duke Energy Carolinas’ Belews Creek Steam Station. (13 March). DCN SE01379.
7. Eastern Research Group (ERG). 2012c. Fina l Sampling Episode Report, We Energies’ Pleasant Prairie Power Plant. (13 March). DCN SE01414.
8. Eastern Research Group (ERG). 2012d. Non-CB I_Final Sampling Episode Report, Duke Energy Miami Fort Station. (13 March). DCN SE01304.
9. Eastern Research Group (ERG). 2012e. Fina l Sampling Episode Report, Duke Energy Carolinas’ Allen Steam Sta tion. (13 March). DCN SE01372.
10. Eastern Research Group (ERG). 2012f. Fina l Sampling Episode Report, Mirant MidAtlantic, LLC’s Dickerson Generati ng Station. (13 March). DCN SE01385.
11. Eastern Research Group (ERG). 2012g. Fi nal Sampling Episode Report, Allegheny Energy’s Hatfield’s Ferry Power Station. (13 March). DCN SE01391.
12. Eastern Research Group (ERG). 2012h. Fina l Sampling Episode Report, RRI Energy’s Keystone Generating Sta tion. (13 March). DCN SE01406.
13. Eastern Research Group (ERG). 2012i. Fina l Sampling Episode Report and Site Visit Notes, Enel’s Federico II Power Pl ant (Brindisi). (8 August). DCN SE02013.
14. Eastern Research Group (ERG). 2012j. Fina l Power Plant Monitoring Data Collected Under Clean Water Act Section 308 Authority (“CWA 308 Monitoring Data”). (30 May). DCN SE01326.
15. Electric Power Research Institute (EPRI). 1997 - 2001. PISCES Water Characterization Field Study, Sites A-G. Pa lo Alto, CA. DCNs 01818-01823.
16. Electric Power Research Institute (EPRI). 2006a. Flue Gas Desulfurization (FGD) Wastewater Characteriza tion: Screening Study. 1010162. Palo Alto, CA. (March). Available online at: http://mydocs.epri.com/docs/public/000000000001010162.pdf. Date accessed: 16 May 2008. DCN 01816.
17. Electric Power Research Institute (EPRI). 2006b. EPRI Technical Manual: Guidance for Assessing Wastewater Impact s of FGD Scrubbers. 1013313. Palo Alto, CA. (December). Available online at: http://www.ep riweb.com/public/000000000001013313.pdf. Date accessed: 16 May 2008. DCN 01817.
18. Progress Energy. 2011. Industry Provided Sa mpling Data from Progress Energy’s Roxboro Plant. (26 June). DCN SE01812.Chapter 10 –Pollutant Loadings and Removals Methodology

10-24 19. Utility Water Act Group (UWAG). 2008. Form 2C Effluent Guidelines Database. (30 June). DCNs 02918 and 02918A.
20. U.S. EPA. 1982. Development Document for Effluent Limitations Guidelines and Standards and Pretreatment Standards for the Steam Electric Point Source Category. EPA-440-1-82-029. Washington, DC. (November). DCN 02933.
21. U.S. EPA. 2009. Steam Electric Power Genera ting Point Source Category: Final Detailed Study Report. EPA 821-R-09-008. Washington, DC. (October). Available online at: http://water.epa.gov/lawsregs/guidance/ cwa/304m/archive/upload/2009_10_26_guide_ste am_finalreport.pdf. DCN 00003.Chapter 10 –Pollutant Loadings and Removals Methodology

10-25 Table 10-1. POTW Removals
Analyte POTW Removal Percentage Aluminum 91.0% Ammonia 39.0% Antimony 66.8% Arsenic 65.8% Barium 55.2% Beryllium 61.2% Biochemical Oxygen Demand NA Boron NA Cadmium 90.1% Calcium NA Chemical Oxygen Demand NA Chloride NA Chromium 80.3% Chromium (VI) NA Cobalt 10.2% Copper 84.2% Cyanide, Total NA Iron NA Lead 77.5% Magnesium NA Manganese 40.6% Mercury 90.2% Molybdenum NA Nickel 51.4% Nitrate Nitrite as N 90.0% Nitrogen, Kjeldahl NA Phosphorus, Total NA Selenium 34.3% Silver 88.3% Sodium NA Sulfate NA Thallium 53.8% Tin NA Titanium NA Total Dissolved Solids NA Total Suspended Solids NA Vanadium 8.3% Zinc 79.1% Source: ERG, 2006. NA – Not applicable.Chapter 10 –Pollutant Loadings and Removals Methodology

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

Plant Name Source of Data Set Wastestreams Represented in Data Set a Progress Energy Carolinas’ Roxboro Steam Electric Plant (Roxboro) Monitoring data provided by plant Surface impoundment effluent

Duke Energy’s Miami Fort Station (Miami Fort) EPA sampling Chemical precipitation effluent EPA CWA 308 monitoring sampling Chemical precipitation effluent

RRI Energy’s Keystone Generating Station (Keystone) EPA sampling Chemical precipitation effluent EPA CWA 308 monitoring sampling Chemical precipitation effluent

Allegheny Energy’s Hatfield’s Ferry Electric Plant (Hatfield’s Ferry) EPA sampling Chemical precipitation effluent EPA CWA 308 monitoring sampling Chemical precipitation effluent

Duke Energy Carolinas’ Belews Creek Steam Station (Belews Creek) EPA sampling Biological treatment effluent EPA CWA 308 monitoring sampling Biological treatment effluent

Monitoring data provided by plant Biological treatment effluent Duke Energy Carolinas’ Allen Steam Station (Allen) EPA sampling Biological treatment effluent EPA CWA 308 monitoring sampling Biological treatment effluent

Monitoring data provided by plant Biological treatment effluent Enel Brindisi EPA sampling Vapor-compression evaporation effluent Note: EPA excluded data from the We Energies’ Pleasant Pr airie Power Plant (Pleasant Prairie) in the loadings calculation because the Pleasant Prairie FGD wastewater treatment system consists of a two-stage chemical precipitation system, which is more advanced than the one- stage chemical precipitation system used as the bases for the chemical precipitation technology option. In addition, EPA excluded data from the Mirant Mid-Atlantic, LLC’s Dickerson Generating Station (Dickerson) in the loadings calculation because the Dickerson plant was not adding organosulfide chemicals to the wastewat er treatment system at the time of sampling. The plant also experienced frequent shutdowns, and wastewater treatment upsets, and the treatment system is not designed and operated to remove selenium.

a The three plants with data used for chemical precipita tion effluent characterization operate one-stage chemical precipitation systems.Chapter 10 –Pollutant Loadings and Removals Methodology

10-27 Table 10-3. Average Effluent Concen tration of FGD Surface Impoundments
Analyte Unit Average Concentration Classicals Ammonia ug/L NA Nitrate Nitrite as N ug/L 67,300 Nitrogen, Kjeldahl ug/L NA Biochemical Oxygen Demand ug/L NA Chemical Oxygen Demand ug/L 418,000 Chloride ug/L 7,320,000 Sulfate ug/L 1,240,000 Cyanide, Total ug/L 1,190 Total Dissolved Solids ug/L 28,600,000 Total Suspended Solids ug/L 27,900 Phosphorus, Total ug/L 404 Total Metals Aluminum ug/L 2,080 Antimony ug/L 13 Arsenic ug/L 6.8 Barium ug/L 303 Beryllium ug/L 1.9 Boron ug/L 243,000 Cadmium ug/L 112 Calcium ug/L 2,050,000 Chromium ug/L 18 Chromium (VI) ug/L NA Cobalt ug/L 183 Copper ug/L 21 Iron ug/L 1,510 Lead ug/L 4.7 Magnesium ug/L 3,370,000 Manganese ug/L 93,100 Mercury ug/L 5.6 Molybdenum ug/L 125 Nickel ug/L 878 Selenium ug/L 1,110 Silver ug/L 0.93 Sodium ug/L 276,000 Thallium ug/L 13 Tin ug/L 100 Titanium ug/L 27 Vanadium ug/L 16 Zinc ug/L 1,390 Sources: ERG, 2012b-2012h; Progress Energy, 2011. Note: Concentrations are rounded to three significant figures. NA – Not applicable.Chapter 10 –Pollutant Loadings and Removals Methodology10-28Table 10-4. 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 200250Chapter 10 –Pollutant Loadings and Removals Methodology10-29Table 10-4. 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 CaCO3 mg/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 thanchloride Low chlorideFlow (gpm avg) No information fromsite No information from site 117.5Source: EPRI, 2006a.U = Non-detect.*Results from sites S and T for selenium speciation were from different samples (collected August 2005) than the other parameters (collected October 2005) at those sites.a – Chloride, fluoride, and sulfate were analyzed by ICP-MS sofiltered in analysis. Therefore,“Total”, “Settled”, and “filtered” are all actually the same evaluation soonly one was reported.Chapter 10 –Pollutant Loadings and Removals Methodology10-30Table 10-5. 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 U5UChapter 10 –Pollutant Loadings and Removals Methodology10-31Table 10-5. 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 CaCO3 mg/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 chloride Low TSSis 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 1 hour)Source: EPRI, 2006a.*Results from sites S and T for selenium speciation were from 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 sofiltered in analysis. Therefore,“Total”, “Settled”, and “filtered” are all actually the same evaluation soonly one was reported. U = Non-detect..Chapter 10 –Pollutant Loadings and Removals Methodology

10-32 Table 10-6. Average Effluent Concentration of One-Stage Chemical Precipitation System
Analyte Unit Average Concentration Classicals Ammonia ug/L 8,120 Nitrate Nitrite as N ug/L 67,300 Nitrogen, Kjeldahl ug/L 27,000 Biochemical Oxygen Demand ug/L 3,130 Chemical Oxygen Demand ug/L 418,000 Chloride ug/L 8,940,000 Sulfate ug/L 5,980,000 Cyanide, Total ug/L 1,190 Total Dissolved Solids ug/L 23,100,000 Total Suspended Solids ug/L 6,560 Phosphorus, Total ug/L 404 Total Metals Aluminum ug/L 155 Antimony ug/L 5.0 Arsenic ug/L 4.5 Barium ug/L 163 Beryllium ug/L 1.00 Boron ug/L 279,000 Cadmium ug/L 3.8 Calcium ug/L 2,330,000 Chromium ug/L 9.1 Chromium (VI) ug/L 5.3 Cobalt ug/L 10 Copper ug/L 2.0 Iron ug/L 127 Lead ug/L 1.00 Magnesium ug/L 3,340,000 Manganese ug/L 13,600 Mercury ug/L 0.17 Molybdenum ug/L 215 Nickel ug/L 5.6 Selenium ug/L 455 Silver ug/L 1.00 Sodium ug/L 420,000 Thallium ug/L 8.6 Tin ug/L 100 Titanium ug/L 10 Vanadium ug/L 15 Zinc ug/L 18 Sources: ERG, 2012d; ERG, 2012g; ERG, 2012h; ERG, 2012j. Note: Concentrations are rounded to three significant figures.Chapter 10 –Pollutant Loadings and Removals Methodology

10-33 Table 10-7. Average Effluent Concentratio n of One-Stage Chemical Precipitation System With Biological Treatment
Analyte Unit Average Concentration Classicals Ammonia ug/L 8,750 Nitrate Nitrite as N ug/L 79 Nitrogen, Kjeldahl ug/L 12,100 Biochemical Oxygen Demand ug/L 1,740 Chemical Oxygen Demand ug/L 156,000 Chloride ug/L 6,720,000 Sulfate ug/L 1,380,000 Cyanide, Total ug/L 74 Total Dissolved Solids ug/L 14,100,000 Total Suspended Solids ug/L 8,210 Phosphorus, Total ug/L 115 Total Metals Aluminum ug/L 155 Antimony ug/L 2.0 Arsenic ug/L 4.6 Barium ug/L 323 Beryllium ug/L 0.97 Boron ug/L 125,000 Cadmium ug/L 2.5 Calcium ug/L 2,970,000 Chromium ug/L 2.2 Chromium (VI) ug/L 3.0 Cobalt ug/L 10 Copper ug/L 2.7 Iron ug/L 302 Lead ug/L 1.00 Magnesium ug/L 741,000 Manganese ug/L 1,960 Mercury ug/L 0.067 Molybdenum ug/L 20 Nickel ug/L 2.6 Selenium ug/L 5.0 Silver ug/L 2.3 Sodium ug/L 46,100 Thallium ug/L 1.9 Tin ug/L 100 Titanium ug/L 10 Vanadium ug/L 5.0 Zinc ug/L 4.8 Sources: ERG, 2012b; ERG, 2012e; ERG, 2012j, Duke Energy, 2011a – 2011b. Note: Concentrations are rounded to three significant figures.Chapter 10 –Pollutant Loadings and Removals Methodology

10-34 Table 10-8. Average Effluent Concentratio n of One-Stage Chemical Precipitation System With Vapor-Co mpression Evaporation
Analyte Unit Average Concentration Classicals Ammonia ug/L 24,300 Nitrate Nitrite as N ug/L 100 Nitrogen, Kjeldahl ug/L 23,500 Chemical Oxygen Demand ug/L 10,000 Chloride ug/L 1,500 Sulfate ug/L 2,500 Total Dissolved Solids ug/L 10,800 Total Suspended Solids ug/L 2,000 Phosphorus, Total ug/L 25 Total Metals Aluminum ug/L 100 Antimony ug/L 1.00 Arsenic ug/L 2.0 Barium ug/L 10 Beryllium ug/L 1.00 Boron ug/L 3,750 Cadmium ug/L 2.0 Calcium ug/L 200 Chromium ug/L 4.0 Cobalt ug/L 10 Copper ug/L 2.0 Iron ug/L 100 Lead ug/L 1.00 Magnesium ug/L 200 Manganese ug/L 10 Mercury ug/L 0.0103 Molybdenum ug/L 20 Nickel ug/L 2.0 Selenium ug/L 2.0 Silver ug/L 1.0 Sodium ug/L 5,000 Thallium ug/L 1.0 Tin ug/L 100 Titanium ug/L 10 Vanadium ug/L 5.0 Zinc ug/L 28.5 Source: ERG, 2012i. Note: Concentrations are rounded to three significant figures. NA – Not applicable.Chapter 10 –Pollutant Loadings and Removals Methodology

10-35 Table 10-9. Average Effluent Concen tration of Ash Surface Impoundment Systems

Analyte Unit Average Fly Ash Concentration Average Bottom Ash Concentration Average Combined Ash Concentration Classicals Ammonia (as N) mg/L 0.62 0.24 0.27 Nitrate-Nitrite as N mg/L 2.51 9.65 2.53 Total Kjeldahl Nitrogen mg/L 0.41 1.36 3.39 Biochemical Oxygen Demand mg/L 1.5 1 4 Chloride mg/L 107 53.5 16.4 Sulfate mg/L 709 1,170 203 Sulfide (as S) mg/L 1.01 0.51 0.52 Sulfite (as SO3) mg/L 2 26.7 1.63 Cyanide mg/L NA NA 0.01 Total Dissolved Solids mg/L 1,362 1,260 262.4 Total Suspended Solids mg/L 8.06 8.36 13.8 Fluoride mg/L NA NA 0.15 Hexane Extractable Material mg/L 6.25 2.5 6 Nitrogen, Total Organic (as N) mg/L 0.65 3.28 0.51 Oil and Grease mg/L 2.13 3.67 2.83 Silicon-Gel Treated Hexane Extractable Material mg/L 2 NA 2.5 Phosphorus (as P) mg/L 0.12 0.36 0.28 Total Metals Aluminum mg/L 0.46 0.59 1.11 Antimony mg/L 0.028 0.093 0.024 Arsenic mg/L 0.042 0.018 0.064 Barium mg/L 0.13 0.078 0.2 Beryllium mg/L 0.003 0.004 0.005 Boron mg/L 4.67 2.24 1.97 Cadmium mg/L 0.006 0.008 0.008 Calcium mg/L 102 186 70.7 Chromium mg/L 0.017 0.014 0.02 Hexavalent Chromium mg/L 0.005 0.001 0.012 Cobalt mg/L 0.014 0.048 0.012 Copper mg/L 0.042 0.027 0.04 Iron mg/L 1.81 2.44 0.58 Lead mg/L 0.03 0.037 0.027 Magnesium mg/L 18.8 97.3 15.3 Manganese mg/L 0.041 0.13 0.62 Mercury mg/L 0.001 0.001 0.002 Molybdenum mg/L 0.43 0.065 0.14 Nickel mg/L 0.035 0.13 0.035 Selenium mg/L 0.035 0.013 0.03 Silica mg/L NA NA 5.93 Silver mg/L 0.003 0.004 0.008Chapter 10 –Pollutant Loadings and Removals Methodology

10-36 Table 10-9. Average Effluent Concen tration of Ash Surface Impoundment Systems

Analyte Unit Average Fly Ash Concentration Average Bottom Ash Concentration Average Combined Ash Concentration Sodium mg/L 298 106 21.3 Thallium mg/L 0.011 0.12 0.049 Tin mg/L 0.025 0.34 0.15 Titanium mg/L 0.008 0.11 0.029 Vanadium mg/L 0.11 0.01 0.044 Yttrium mg/L 0.003 0.003 0.003 Zinc mg/L 0.17 0.094 0.085 Sources: U.S. EPA, 2009; U.S. EPA, 1982; EPRI, 1997 – 2001; UWAG, 2008. Note: Concentrations are rounded to three significant figures. NA – Not applicable.

Table 10-10. Average Untreated Landfill Leachate Concentrations

Analyte Unit Untreated Active Landfill Concentration Untreated Inactive Landfill Concentration Classicals Chloride ug/L 542,000 11,100 Sulfate ug/L 1,910,000 1,070,000 Total Dissolved Solids ug/L 3,860,000 1,670,000 Total Suspended Solids ug/L 41,400 4,210 Total Metals Aluminum ug/L 5,030 100 Antimony ug/L 4.6 4.9 Arsenic ug/L 46 10 Barium ug/L 57 50 Beryllium ug/L 1.9 0.47 Boron ug/L 20,500 3,640 Cadmium ug/L 2.7 1.9 Calcium ug/L 481,000 386,000 Chromium ug/L 4.9 1.6 Cobalt ug/L 84 3.8 Copper ug/L 10 1.7 Iron ug/L 59,000 95 Lead ug/L 1.4 0.47 Magnesium ug/L 115,000 33,700 Manganese ug/L 4,360 355 Mercury ug/L 1.4 0.01 Molybdenum ug/L 1,880 995 Nickel ug/L 69 43 Selenium ug/L 74 84 Silver ug/L 0.68 0.42 Sodium ug/L 327,000 16,700 Thallium ug/L 1.3 0.96 Tin ug/L 11 13Chapter 10 –Pollutant Loadings and Removals Methodology

10-37 Table 10-10. Average Untreated Landfill Leachate Concentrations

Analyte Unit Untreated Active Landfill Concentration Untreated Inactive Landfill Concentration Titanium ug/L 17 15 Vanadium ug/L 3,240 6.2 Zinc ug/L 154 58
Source: Steam Electric Survey ERG, 2012a. Note: Concentrations are rounded to three significant figures.

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

Treatment Option Number of Plants Total Industry Discharge Flow (MGD) a Total Industry Loadings Pounds/Year TWPE/Year Baseline 117 65.4 3,240,000,000 3,030,000 One-Stage Chemical Precipitation 117 56.8 3,650,000,000 1,490,000 One-Stage Chemical Precipitation With Biological Treatment 117 56.8 2,080,000,000 408,000

One-Stage Chemical Precipitation With Evaporation/Crystallization 117 56.8 10,600,000 33,000

Note: Excludes loadings fo r BOD, COD, TSS and TDS. Note: Loadings are rounded to three significant figures. a - The reduction in total industry discharge flow from ba seline to the technology options is associated with the plants for which EPA assumed that some recycle of th e FGD wastewater would occu r prior to treatment, as described in Section 4.4.3.

Table 10-12. Industry-Level FGD Wastewater L oadings Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis

Treatment Option Number of Plants Total Industry Discharge Flow (MGD) Total Industry Loadings Pounds/Year TWPE/Year Baseline 117 65.4 3,240,000,000 3,030,000 One-Stage Chemical Precipitation 117 56.8 3,650,000,000 1,490,000 One-Stage Chemical Precipitation With Biological Treatment 117 56.8 2,080,00,000 411,000

One-Stage Chemical Precipitation With Evaporation/Crystallization 117 56.8 13,500,000 36,400

Note: Excludes loadings fo r BOD, COD, TSS and TDS. Note: Loadings are rounded to three significant figures. a - The reduction in total industry discharge flow from ba seline to the technology options is associated with the plants for which EPA assumed that some recycle of th e FGD wastewater would occu r prior to treatment, as described in Section 4.4.3.Chapter 10 –Pollutant Loadings and Removals Methodology

10-38 Table 10-13. FGD Wastewater Pollutant Removals for All Units

Treatment Option Total Industry Removals Pounds/Year TWPE/Year Removal (Baseline –> One-Stage Ch emical Precipitation) -419,000,000 a 1,540,000 Removal (Baseline –> One-Stag e Chemical Precipitation With Biological Treatment) 1,160,000,000 2,620,000

Removal (Baseline –> One-Stag e Chemical Precipitation With Evaporation/Crystallization) 3,220,000,000 2,990,000

Note: Excludes loadings fo r BOD, COD, TSS and TDS. Note: Removals are rounded to three significant figures. The removals may not equal the subtraction of the technology option from the baseline using the values in Table 10-11 due to rounding. a – Characterization data used to estimate pollutant concentrations for baseline FGD surface impoundments does notinclude concentration data for ammonia, hexavalent chromium, and TKN. These pollutants are included in the postcompliance loadings and as a result appear to increase in concentration from baseline to technology option.

Table 10-14. FGD Wastewater Pollutant Removals Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis

Treatment Option Total Industry Removals Pounds/Year TWPE/Year Removal (Baseline –> One-Stage Ch emical Precipitation) -417,000,000 a 1,530,000 Removal (Baseline –> One-Stag e Chemical Precipitation With Biological Treatment) 1,160,000,000 2,620,000

Removal (Baseline –> One-Stag e Chemical Precipitation With Evaporation/Crystallization) 3,220,000,000 2,990,000

Note: Excludes loadings fo r BOD, COD, TSS and TDS. Note: Removals are rounded to three significant figures. The removals may not equal the subtraction of the technology option from the baseline using the values in Table 10-12 due to rounding. a – Characterization data used to estimate pollutant concentrations for baseline FGD surface impoundments does notinclude concentration data for ammonia, hexavalent chromium, and TKN. These pollutants are included in the postcompliance loadings and as a result appear to increase in concentration from baseline to technology option.Chapter 10 –Pollutant Loadings and Removals Methodology

10-39 Table 10-15. Percent Loadings for Fly Ash and Bottom Ash in Combined Ash Surface Impoundments

Analyte Percent Loadings Fly Ash (%) Percent Loadings Bottom Ash (%) Aluminum 92.5 7.5 Antimony 89.3 10.7

Arsenic 96.0 4.0 Beryllium 96.0 4.0 Calcium 77.7 22.3 Copper 79.6 20.4

Iron 76.4 23.6 Mercury 71.4 28.6 Nickel 77.7 22.3 Selenium 99.0 1.0

Zinc 90.3 9.7 TSS 84.6 15.4 Average 86.9 14.1 Source: EPRI, 1997 – 2001

Table 10-16. Industry-Level Baseline As h Impoundment Loadings by Type of Impoundment

Type of Ash Impoundment Number of Impoundments Total Baseline Industry Discharge Flow (MGD) Total Industry Baseline Loadings Total Industry PostCompliance Loadings a

Pounds/Year TWPE/Year Pounds/Year TWPE/Year Fly Ash

Fly Ash Impoundment 16 61.7 237,000,000 688,000 3,800,000 11,000

Combined Ash Impoundment b 80 262 c 241,000,000 1,830,000 2,950,000 22,500

Bottom Ash

Bottom Ash Impoundment 174 327 1,660,000,000 2,420,000 5,100,000 7,290

Combined Ash Impoundment b 80 262 c 44,900,000 295,000 550,000 3,610

TOTAL 272 651 2,180,000,000 5,240,000 12,400,000 44,400 Note: Excludes loadings for BOD, COD, TSS, and TDS. Note: Loadings are rounded to three significant figures.

a The post-compliance loadings present represent the loadings based on oil-fired units and units 50 MW or less not installing the technology basis. The post-compliance loadings for all units is zero.

b The combined impoundment loadings were calculated based on the data used in the loadings calculations but then the total combined ash impoundment loadings were split between fly ash and bottom ash based on EPRI data, described in this section.

c The total discharge flow from all combined impoundments is 262 MGD. The fly ash contribution and bottom ash contribution cannot be determined with the data provided in the Steam Electric Survey.Chapter 10 –Pollutant Loadings and Removals Methodology

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

Surface Impoundment Treatment Option Total Industry Removals

Pounds/Year TWPE/Year Fly Ash Removal (Baseline –> Technology Option) 478,000,000 2,520,000 Bottom Ash Removal (Baseline –> Technology Option) 1,700,000,000 2,720,000 Note: Excludes loadings for BOD, COD, TSS, and TDS. Note: Removals are rounded to three significant figures. The removals may not equal the subtraction of the technology option from the baseline using the values in Table 10-16 due to rounding.

Table 10-18. Fly Ash and Bottom Ash Pollutant Removals Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis
Type of Ash

Surface Impoundment Treatment Option Total Industry Removals

Pounds/Year TWPE/Year Fly Ash Removal (Baseline –> Technology Option) 471,000,000 2,490,000 Bottom Ash Removal (Baseline –> Technology Option) 1,700,000,000 2,710,000 Note: Excludes loadings for BOD, COD, TSS, and TDS. Note: Removals are rounded to three significant figures. The removals may not equal the subtraction of the technology option from the baseline using the values in Table 10-16 due to rounding.

Table 10-19. Industry-Level Combustion Residua l Landfill Leachate Loadings for All Units

Treatment Option Number of Plants Total Industry Flow (MGD) Total Industry Loadings

Pounds/Year TWPE/Year Baseline 102 7.90 89,800,000 56,500 One-Stage Chemical Precipitation 102 7.90 80,900,000 20,900 One-Stage Chemical Precipitation With Biological Treatment 102 7.90 61,800,000 13,600

Note: Excludes loadings fo r BOD, COD, TSS and TDS. Note: Loadings are rounded to three significant figures.

Table 10-20. Industry-Level Combustion Resi dual Landfill Leachate Loadings Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis

Treatment Option Number of Plants Total Industry Flow (MGD) Total Industry Loadings

Pounds/Year TWPE/Year Baseline 102 7.90 89,800,000 56,500 One-Stage Chemical Precipitation 102 7.90 80,900,000 20,900 One-Stage Chemical Precipitation With Biological Treatment 102 7.90 61,800,000 13,600

Note: Excludes loadings fo r BOD, COD, TSS and TDS. Note: Loadings are rounded to three significant figures.Chapter 10 –Pollutant Loadings and Removals Methodology

10-41 Table 10-21. Combustion Residual Leacha te Loadings Removals for All Units

Technology Option Total Industry Pollutant Removals
Pounds/Year TWPE/Year Removal (Baseline –> One-Stage Chemical Precipitation) 8,900,000 35,600 Removal (Baseline –> One-Stag e Chemical Precipitation With Biological Treatment) 28,000,000 42,900

Note: Excludes loadings fo r BOD, COD, TSS and TDS. Note: Removals are rounded to three significant figures. The removals may not equal the subtraction of the technology option from the baseline using the values in Table 10-19 due to rounding.

Table 10-22. Combustion Residual Leachate Loadings Removals Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis

Technology Option Total Industry Pollutant Removals
Pounds/Year TWPE/Year Removal (Baseline –> One-Stage Chemical Precipitation) 8,900,000 35,600 Removal (Baseline –> One-Stag e Chemical Precipitation With Biological Treatment) 28,000,000 42,900

Note: Excludes loadings fo r BOD, COD, TSS and TDS. Note: Removals are rounded to three significant figures. The removals may not equal the subtraction of the technology option from the baseline using the values in Table 10-20 due to rounding.Chapter 11 – Summary of Costs and Pollutant Removals by Regulatory Option

11-1 

## CHAPTER 11 SUMMARY OF COSTS AND POLLUTANT REMOVALS BY REGULATORY OPTION

EPA evaluated five regulatory options co mprising various combinations of the technology options considered for each wastestream. Table 11-1 lis ts each regulatory option that EPA evaluated along with the associated treat ment technology for all of the affected wastestreams. The Agency estimated the costs and pollutant loading removals associated with steam electric power plants to achieve compliance for each regulatory option under consideration. This section summarizes the to tal estimated compliance costs and pollutant removal estimates associated with each regulatory option. All tabl es and figures referenced in this chapter are presented at the end of the chapter.
Using the methodologies described in this report, EPA combined the plant-level estimated compliance costs for the appropriate tec hnology options, based on the information specified in Table 11-1, to gene rate an industry-level estimated compliance cost for each regulatory option. Table 11-2 presents the estimat ed compliance cost for each of the five regulatory options based on all units discharging the various wastestreams installing the appropriate technology basis. Table 11-3 presents the estimated co mpliance cost for each of the five regulatory options based on the oil-fired units and units 50 MW or less not needing to install the appropriate technology basis. For each regul atory option, the capital costs, annual operating and maintenance costs, one-time costs, and recu rring costs are presented. All cost estimates are expressed in terms of pre-tax 2010 dollars.
EPA also estimated the pollutant loading rem ovals associated with steam electric power plants to achieve compliance for each regul atory option under consideration. Using the methodology described in Chapter 10, EPA combined the plant-level pollut ant loadings for the appropriate technology options, based on the inform ation specified in Table 11-1, to calculate industry-level estimated pollutant loadings a nd pollutant removals for each regulatory option. Table 11-4 presents the total industr y loadings and pollutant removals at baseline and for each of the five regulatory options base d on all units discharging the vari ous wastestreams installing the appropriate technology basi s. Table 11-5 presents the total industry loadings and pollutant removals at baseline and for each of the five regulatory options based on the oil-fired units and units 50 MW or less not needing to install the appropriate te chnology basis. EPA excluded the pollutant parameters biochemical oxygen dema nd (BOD), chemical oxygen demand (COD), total dissolved solids (TDS), and total suspended soli ds (TSS) from the total loadings and toxic weighted pound equivalent (TWPE) values pres ented in these tables to avoid double counting.Chapter 11 – Summary of Costs and Pollutant Removals by Regulatory Option11-2Table 11-1. Treatment TechnologiesBasis by Regulatory OptionRegulatoryOptionTreatment TechnologyaFGD WastewaterFly AshTransportWaterBottomAshTransportWaterCombustion ResidualLeachateGasificationWastewaterFlue GasMercuryControlWastesNonchemicalMetalCleaningWasteChemicalPrecipitationChemicalPrecipitationWithBiologicalTreatmentChemicalPrecipitationWith VaporCompressionEvaporationDryVacuumSystemMDS/RemoteMDSChemicalPrecipitationChemicalPrecipitationWithBiologicalTreatmentVaporCompressionEvaporationDryVacuumSystemChemicalPrecipitation1X X X2X X X3X X X X X4X X X XbX X X5X X X X X X XaTable only presents the technology option evaluated for the costs and pollutant removals. All other appropriate technology cost modules were used to generatethe compliance costs (e.g., compliance monitoring, transportation, disposal).bAny plant discharging both FGD wastewater and combustion residual leachate was assumed to combine the two wastestreams and treat them with the samesystem, except at certain plantswhere the plant already had FGD wastewater treatment in place, as described in Section 9.3. Therefore, for plants where the twowastestreams were assumed to be combined, the combustion residual leachate costs and pollutant loadings were evaluated based onchemical precipitation withbiological treatment.Chapter 11 – Summary of Costs and Pollutant Removals by Regulatory Option

11-3 Table 11-2. Cost of Implementation by Regulatory Option for All Units [In millions of pre-tax 2010 dollars]

Regulatory

Option Number of Plants Capital Costs Annual O&M Costs One Time Costs Recurring Costs

3-year 5-year 6-year 10-year 1 117 $1,460 $194 $0 $0 $0 $10 ($33) 2 117 $2,510 $257 $0 $0 $0 $10 ($33) 3 167 $2.927 $437 $0 $0 $0 $10 ($57) 4 294 $8,206 $1,016 $0.6 $33 $69 $16 ($146) 5 294 $11,970 $1,782 $0.6 $33 $69 $19 ($146)

Table 11-3. Cost of Implementation by Regu latory Option Based on Oil-Fired Units and Units 50MW or Less Not Installing Technology Basis [In millions of pre-tax 2010 dollars]

Regulatory

Option Number of Plants Capital Costs Annual O&M Costs One Time Costs Recurring Costs

3-year 5-year 6-year 10-year 1 116 $1,450 $194 $0 $0 $0 $10 ($33) 2 116 $2,499 $257 $0 $0 $0 $10 ($33) 3 155 $2,897 $434 $0 $0 $0 $10 ($54) 4 277 $8,011 $988 $0.6 $28 $65 $16 ($137) 5 277 $11,755 $1,753 $0.6 $28 $65 $19 ($137)

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

Regulatory Option Total Industry Loadings Total Industry Removal a

Pounds/Year TWPE/Year Pounds/Year TWPE/Year

Baseline 5,500,000,000 8,320,000 0 0

1 5,920,000,000 6,780,000 -419,000,000 1,540,000

2 4,350,000,000 5,700,000 1,160,000,000 2,620,000

3 3,870,000,000 3,180,000 1,630,000,000 5,140,000

4 2,150,000,000 426,000 3,350,000,000 7,890,000

5 91,500,000 53,800 5,410,000,000 8,270,000 Note: Excludes loadings for BOD, COD, TDS, and TSS. Note: Pollutant loadings and removals are rounded to three significant figures. The removals may not equal the subtraction of the technology option from the baseline due to rounding.

a Compared to baseline.

b Characterization data used to estimate pollutant concen trations for baseline FGD surface impoundments does notinclude concentration data for ammonia, hexavalent chromium, and TKN. These pollutants are included in the postcompliance loadings and as a result appear to increase in concentration from baseline to technology option.Chapter 11 – Summary of Costs and Pollutant Removals by Regulatory Option

11-4 Table 11-5. Estimated Pollutant Removals by Re gulatory Option Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis

Regulatory Option Total Industry Loadings Total Industry Removal a

Pounds/Year TWPE/Year Pounds/Year TWPE/Year
Baseline 5,500,000,000 8,320,000 0 0

1 5,920,000,000 6,790,000 -417,000,000 b 1,530,000

2 4,350,000,000 5,710,000 1,160,000,000 2,620,000

3 3,880,000,000 3,220,000 1,630,000,000 5,100,000

4 2,170,000,000 474,000 3,340,000,000 7,850,000

5 107,000,000 102,000 5,400,000,000 8,220,000 Note: Excludes loadings for BOD, COD, TDS, and TSS. Note: Pollutant loadings and removals are rounded to three significant figures. The removals may not equal the subtraction of the technology option from the baseline due to rounding.

a Compared to baseline.

b Characterization data used to estimate pollutant concen trations for baseline FGD surface impoundments does notinclude concentration data for ammonia, hexavalent chromium, and TKN. These pollutants are included in the postcompliance loadings and as a result appear to increase in concentration from baseline to technology option.Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates

12-1 

## CHAPTER 12 EVALUATION OF COST AND POLLUTANT REMOVAL ESTIMATES

This chapter describes the activities EPA us ed to evaluate the compliance cost and pollutant removal estimates described in this repor t. Plans for these quality control activities are detailed in the Quality Assurance Project Plan for the Steam Electric Effluent Guidelines Rulemaking, Version 4 , dated April 5, 2013 and approved on April 19, 2013 (hereafter, the QAPP). The activities included:

 Verifying that the collected cost data met the data accepta nce specifications presented in QAPP Table 2-3;

 Checking database code, spreadsheet data entry, and calculati ons and documenting these checks for databases and spreadsheets de veloped to estimate costs and pollutant loadings; and

 Verifying that the estimated costs met the quality specifications presented in QAPP Table 2-4.
All tables referenced in this chapter ar e presented at the end of the chapter.

12.1 V ERIFYING C OST D ATA AGAINST ACCEPTANCE S PECIFICATIONS

EPA collected information about the costs for steam electric power plants to install and operate the wastewater pollution control technologies described in this report, including wastewater treatment systems, ash handling opera tions, and costs for hauling solid waste for onor off-site disposal. EPA obtained recent (i.e., 2000 – 2010) cost information from power plants in response to the Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey), as well as more cu rrent (i.e., 2009 - 2011) cost information from equipment vendors.
The criteria EPA used to evaluate the quali ty of collected pollution control technology cost information are summarized in Table 12-1, along with acceptable valu es for each criterion. EPA’s verification of how well the cost data me t the quality specifications is presented, by acceptance criterion, in this section.

Currency. With the exception of surface impoundmen t installations and their operation, EPA collected all costs from power plants, vendors, or documented Internet sources and represented systems installed in 2000 or later, thus meeti ng the currency specification.

To estimate the baseline cost for surface im poundment installations and their operation, EPA used two EPA studies evaluating the economi cs of waste disposal at coal-fired power plants: U.S. EPA/TVA Economics of Ash Disposal at Coal-fired Power Plants (1981) and U.S. EPA Full-Scaled Field Evaluation of Waste Disposal from Coal-fir ed Electric Generating Plants (1985). These estimates predate the time period sp ecified for the currency criterion; however, these estimates are the “best available” and suitab le for the estimate of costs associated with baseline operations.Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates

12-2 Technology. EPA obtained costs for equipment appr opriate for and demonstrated to be available for steam electric power plants, in cluding chemical preci pitation, anoxic/anaerobic biological metals removal, and vapor-compre ssion evaporation of FG D wastewater and/or combustion residual landfill leachate; dry vacuum fly ash handling; mechanical drag system (MDS) or remote MDS for bottom ash handling; a nd transportation and disposal of ash and FGD wastewater treatment solids.

Accuracy/Reliability. As listed in Table 12-1, the specification for accuracy and reliability was that quotes be obtained directly from steam electric power plants or from vendors who do business with steam electric power plants. Quotes for anoxic/anaerobic biological metals removal and vapor-compression evaporation of FGD wastewater and/or combustion residual landfill leachate; dry vacuum fly ash handling; and MDS or remote MDS for bottom ash handling were obtained from vendors that do busin ess with power plants and thus met this specification.
Although quotes for other equipment were from vendors that may or may not directly serve power plants, they were obt ained from reputable vendors th at sell the type of equipment (including appropriate material s of construction) used for these operations (e.g., chemical precipitation, transport, disposal). For this r eason, although the quotes in so me cases are not from vendors that directly serve power plants, these quotes meet the criterion that the reported information is “true.”

In addition, as described thr oughout this report, EPA develope d industry cost factors for many of the direct and indirect capital cost fa ctors (e.g., installation a nd engineering overhead cost factors) used in the cost model from su rvey data. Other cost elements (e.g., equipment capacity factors, materials of construction, and chemical dosage rates and sludge generation rates for chemical precipitation) were also derived from survey res ponses. In this way, EPA met the specification for accuracy and reliability by using industry-specific data.

Comparability. EPA requested power plants report in stallation and operation costs for ash handling, wastewater treatment, and other waste management (dollars per year) in the Steam Electric Survey, if the system was installed in the year 2000 or later. EPA intended to use the reported capital and operating cost s to evaluate comparability. Many respondents did not respond to this question and those who did respond either di d not itemize the total co sts, or only provided certain itemized costs. For this reason, EPA c ould not directly compare costs reported in the responses to the Steam Electric Su rvey to prices that EPA obtained for equipment, installation, and shipping. As a result, EPA could not determin e the comparability of th e collected cost data. However, EPA used reported survey costs to di rectly develop industry- specific labor rates and indirect cost factors.

12.2 V ERIFYING A NALYTICAL D ATA AGAINST ACCEPTANCE S PECIFICATIONS
EPA collected analytical data representi ng the influent and effluent pollutant concentrations from steam electric power plan t wastewater treatment systems for use in estimating the baseline and post-compliance loadi ngs for the industry. Chapter 3 of this report discusses the data used to estimate the loadings. So me of the data used in the loadings analysis are from EPA’s primary data collection effo rts (i.e., EPA’s sampling program), while theChapter 12 – Evaluation of Cost and Pollutant Removal Estimates

12-3 remainder of the data came from secondary da ta (e.g., industry-provided monitoring data, Steam Electric Survey data, EPRI reports, 1974 and 1982 TDDs).
EPA reviewed the data collected as part of the EPA sampling program to evaluate whether it was of sufficient quality for use in the loadings analysis. The data review criteria that EPA used in assessing the quality of the data are described in Section 5.1.1 of the QAPP. Based on these criteria, EPA developed data review narratives for each se t of analytical data generated by the sampling program. These data review narra tives are included in the attachments to the sampling episode reports for each sampling ev ent [ERG, 2012a – 2012i, EPA, 2009]. Based on the review of the analytical data, EPA made data point-specific determinations as to whether the data should be included in the loadings analysis.
In addition to the sampling data, EPA also used other secondary data sources to estimate the loadings. Table 12-2 presents the acceptance criteria EPA us ed to evaluate whether these data were sufficient for use in the loadings analysis . Table 12-3 presents the evaluation of each of these secondary data sources to the monitoring data ac ceptance criteria.

12.3 D EVELOPING AND C HECKING THE C OST AND L OADINGS M ODELS
EPA developed a detailed cost model for es timating total installed capital costs and operating and maintenance costs for each individual power plant, as described earlier in this report. EPA also developed a detailed loadings model to estimate the baseline and postcompliance loadings for each individual power plant, as described in Chapter 10. The model outputs received se veral reviews:

 A project engineer checked th at the calculations reflect ed the methodologies outlined in this report

. Where the calculations and assumpti ons documentation did not agree, EPA determined if the documentation or calculations required corrections and ensured the corrections were made.

 An engineer involved in the models de velopment checked the accuracy of the calculations in the models code/queri es by performing hand calculations and comparing the results to the model outputs. Where the model and hand calculations resulted in a discrepancy, the model was corrected and re-checked to ensure the correct calculations were being executed by the model.

 An engineer provided indepe ndent technical review of the model outputs. The outputs were checked to ensure the expected nu mber of records (i.e., the number of known plants incurring costs/discha rging). Specifically for the cost model, the engineer confirmed that the individual cost elements summed to the calculated total for each category of costs presented in the output (e.g., the sum of all individual capital cost elements equals the calculated total capital cost). The engineer also checked that the cost model output calculated the total a nnualized costs appropri ately by calculating the plant-specific values in excel and comp aring them to annualized costs presented in the output.

 After each model run, an engineer analy zed the specific model outputs for the expected changes based on industry prof ile changes or changes to the model equations and/or inputs. The engineer pe rformed the following types of checks:Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates

12-4  Confirmed that plants rem oved from the industry profile no longer had compliance costs or pollutant loadings in all outputs (e.g., FGD biological treatment, fly ash, bottom ash);

 Confirmed that plants identified as incurring compliance costs/discharging wastewater were included in all ap plicable cost and loadings outputs;

 Confirmed that plants incu rring compliance costs also ha ve a calculated pollutant loading, where appropriate; 74 and

 Confirmed that changes to models and/or mode l inputs, such as flow rates, factors, or equations, resulted in the expected change in the specific cost elements/loadings in the model outputs.

 The engineer noted issues or discrepancies and the mode l outputs were corrected. The engineer re-checked the new out puts for all issues identified.

 A senior engineer reviewed the costs a nd loadings by comparing the estimates for each plant and technology, and evaluating wh ether the trends in costs/loadings reflected the amount of wastewater treated or ash handled and the baseline waste management strategies.

12.4 E VALUATING C OST E STIMATE Q UALITY
Verification of the completed cost estimates means determining if estimated costs meet the data acceptance criteria specified in Tabl e 12-4 of the QAPP. For example, the first acceptance criterion is that the costs meet the requirements for economic analysis. The specifications for this criterion were that the es timates include both one-t ime costs for equipment purchase, installation, and other direct and indirect capital costs and on-going operating and maintenance costs. The cost estimates fully me t these specifications. Table 12-4 reproduces the QAPP cost estimate quality specifications along with an assessment of whether the estimated costs met the specifications.

To evaluate the reasonableness of the co st estimate, EPA planned to compare its estimated costs to costs for sim ilar installations at power plan ts. EPA sought costs for plants through the Steam Electric Survey but obtained only limited information. In some cases, cost estimates provided by plants include d initial research of the tec hnologies, including evaluation of varying configurations and operati ng conditions, and therefore did not represent today’s expected costs to install the BAT system. For example, fo r anoxic/anaerobic biological treatment systems, a vendor for this technology indicated that the design and cost basis for the technology has changed significantly since those early implemen tations, particularly for low flow (<20 gpm) systems, and therefore are not reflective of capital costs that would be incurred today.
In other cases, the systems installed and ope rated by the power plants did not match the BAT design used by EPA for the technology options (or there wasn’t enough documentation to

74 All plants incurring a compliance cost for FGD wastewater are included in the pollutant loading calculations. For plants operating both wet and dry fly ash handling systems, each with the capacity to hand le all ash produced at the plant, EPA calculated a pollutant loading but included no compliance cost. For plants operating wet bottom ash handling systems that did not discharge bottom ash transport water in 2009, EPA assessed a compliance cost (see Section 8.5) but did not calculate a pollutant loading.Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates

12-5 determine whether the system matched the BAT design). For example, in some cases, EPA’s model design basis for ash handling exceeded the rates used in individual plant bid proposals. Therefore, EPA was unable to compare the reported costs to the model estimates.
More generally, EPA compared summary sta tistics for cost model outputs to survey responses for total capital, purchas ed equipment, installation, build ings, and site preparation, as well as indirect costs such as engineering and construction expe nses. EPA found that labor costs sometimes varied because its cost model include s the use of in-house labor for operation and maintenance of the FGD wastewater treatment system. Contracted labor rates may be significantly higher, leading to higher O&M costs. For example, early implementers of the anoxic/anaerobic biological treatment system typically hired a contractor to operate and maintain their treatment system, which may have led to higher O&M costs reported in the survey compared to model estimates.
In certain cases, such as for vapor-com pression evaporation treatment preceded by chemical precipitation and softening, there is only one plant in the Un ited States that was operating this technology at the time the respons es to the Steam Electric Survey were submitted. The plant operating that system did not provide cost information to EPA in its responses to the Steam Electric Survey. Because EPA was unable to collect cost data from the Steam Electric Survey, EPA relied on the cost data provided by the vendors. EPA notes that cost data were collected from two different vendors and the vendor s’ estimates were similar. As described in Section 6.3.5, EPA used the cost data from both vendors in developi ng the vapor-compression evaporation system costs.

12.5 R EFERENCES

1. Eastern Research Group (ERG). 2012a. Fina l Sampling Episode Report, Duke Energy Carolinas’ Belews Creek Steam Station. (13 March). DCN SE01379.
2. Eastern Research Group (ERG). 2012b. Final Sampling Episode Report, We Energies’ Pleasant Prairie Power Plant. (13 March). DCN SE01414.
3. Eastern Research Group (ERG). 2012c. Non- CBI_Final Sampling Episode Report, Duke Energy Miami Fort Station. (13 March). DCN SE01304.
4. Eastern Research Group (ERG). 2012d. Fina l Sampling Episode Report, Duke Energy Carolinas’ Allen Steam Sta tion. (13 March). DCN SE01372.
5. Eastern Research Group (ERG). 2012e. Fina l Sampling Episode Re port, Mirant MidAtlantic, LLC’s Dickerson Generati ng Station. (13 March). DCN SE01385.
6. Eastern Research Group (ERG). 2012f. Fi nal Sampling Episode Report, Allegheny Energy’s Hatfield’s Ferry Power Station. (13 March). DCN SE01391.
7. Eastern Research Group (ERG). 2012g. Fina l Sampling Episode Report, RRI Energy’s Keystone Generating Sta tion. (13 March). DCN SE01406.
8. Eastern Research Group (ERG). 2012h. Final Sampling Episode Report and Site Visit Notes, Enel’s Federico II Power Pl ant (Brindisi). (8 August). DCN SE02013.Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates

12-6 9. Eastern Research Group (ERG). 2012i. Fina l Power Plant Monitoring Data Collected Under Clean Water Act Section 308 Authority (“CWA 308 Monitoring Data”). (30 May). DCN SE01326.
10. U.S. EPA. 2009. Steam Electric Power Genera ting Point Source Category: Final Detailed Study Report. EPA 821-R-09-008. Washington, DC. (October). Available online at: http://water.epa.gov/lawsregs/guidance/ cwa/304m/archive/upload/2009_10_26_guide_ste am_finalreport.pdf. DCN 00003.Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates

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

Acceptance Criterion Description/Definition Specification Currency (up to date) Does th e 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 tr ue? Obtained from a power plant or a vendor who does business with steam electric power plants. Comparability Are the costs comparable to costs provided by sources that meet these acceptance criteria? Comparable to other sources, such as the Steam Electric Survey.

Source: QAPP Table 2-3.

Table 12-2. Monitoring Data Acceptance Criteria

Type of Data Data Usable to Demonstrate System Performance/ Efficiency Data Usable to Estimate Baseline Discharges Monitoring Data (e.g., NPDES permit, DMRs) (1) Represent full-scale system operated at applicable steam electric power plant. (2) Influent and effluent data or percent removal identified. (3) Analytes identified and units included. Identified as discharge, analytes identified and units provided, approved analytical method used, represent current treatment operations.Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates

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

Source Type of Data Evaluation of Data Duke Energy Submitted Monitoring Data for Belews Creek and Allen Data representing the influent and effluent from the full-scale FGD wastewater treatment system. These data meet all acceptance criteria for use in treatment performance and baseline estimates

State Submitted Monitoring Data for Roxboro Data representing the influent and effluent from the full-scale FGD wastewater treatment system. EPA used the effluent from the settling pond, which is the influent to the biological treatment system for use in the baseline estimates. Although these data do not represent effluent discharges, EPA considers the data to be representative of FGD pond effluent data because the total suspended solids (TSS) concentrations were less than 30 mg/L a . These data meet all other acceptance criteria. Steam Electric Survey Part G Sampling Data Data representing the untreated leachate collected from landfills containing combustion residuals. EPA used the untreated leachate data for use in baseline estimates. Although these data do not represent effluent discharges, EPA considers the data to be representative of leachate discharges because the TSS concentrations were less than 30 mg/L b . These data meet all other acceptance criteria. EPRI PISCES Reports Data representing the effluent discharges from ash impoundments. Also contains loading breakouts for all components entering the impoundment. EPA used the ash impoundment effluent data for use in baseline estimates. Although these data represent operations from the late 1990s, EPA notes that the constituents of coal and the ash impoundment operations have not changed since that time and are still repr esentative of discharges today. These data meet all other acceptance criteria. UWAG Provided Form 2C Data Data representing the effluent discharges from outfalls containing FGD and/or ash wastestreams. EPA used the outfall data for use in baseline estimates. Although the analytical methods used were not identified in the data set, the data were collected as part of the Form 2C process; therefore, EPA assumed that the plants used approved methods specified by the permitting authority. These data meet all other acceptance criteria. 1982 TDD Data representing the ash impoundment overflows. EPA used the ash impoundment effluent data from the TDD for use in baseline estimates. Although the analytical methods used were not identified in the data set, the data were obtained from EPA regional offices and the Tennessee Valley Authority; therefore, EPA assumed that these entities used approved methods. Additionally, although these data represent operations from the late 1970’s, EPA notes that the constituents of coal and the ash impoundment operations have not changed since that time and are still representative of discharges today. These data meet all other acceptance criteria.

a There are 53 results for TSS in the dataset. Of these 53 results, only 6 have TSS values greater than 30 mg/L.

b There are 232 results for TSS in the da taset. Of these 232 results, only 35 have TSS values greater than 30 mg/L.Chapter 12 – Evaluation of Cost and Pollutant Removal Estimates

12-9 Table 12-4. Cost Estimate Quality Specifications

Acceptance Criterion: Cost Estimates Specification Comparison of Cost Estimate to the Specification Meet requirements for economic analysis Include one-time costs for equipment purchase and installation. Include one-time costs for treatability and optimization studies, as appropriate. Include on-going operating and maintenance costs (annual costs). Include periodic operating and maintenance costs, as appropriate. True

True

True

True

Appropriate for actual plant locations Equipment costs, including transportation and installation, reflect the costs for supplies and labor at steam electric power plant locations. Operating costs (electricity, di esel fuel, labor, chemicals, etc.) reflect the costs at steam electric power plant locations. True

True

Unit costs are on specified, standard year basis Input costs escalated to 2010, using R.S. Means Construction Index or other standard cost index. True

Complete Include costs for all elem ents necessary to implement the waste management option. Reflects EPA’s current understanding. Accurate (model input) Model inputs reflect design assumptions agreed on with project team. Model inputs reflect baseline conditions at each plant. True

Reflects EPA’s current understanding based on Steam Electric Survey responses.
Accurate (calculations) Model calculations are correct. Unit conversions are correct. True True Reasonable Order-of-magnitude of costs is comparable to costs for similar installations at similar plants. Cost trends follow the design basis trends (i.e., costs for large plants are greater than the costs for small plants). See discussion above

TrueAppendix



## AppendixAppendix

A1-1 All Appendix Tables have been Redacted to protect information claimed as Confidential Business Information (CBI).