United States

Environmental 

Protection Agency

Solid Waste

Report to Congress

Wastes from the Combustion

of Fossil Fuels

Volume 2 – Methods, Findings,

and Recommendations

Office of Solid Waste and

Emergency Response 

Washington, DC 20460

EPA 530-R-99-010

March 1999
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 iii

TABLE OF CONTENTS

Page

1.0 INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1

1.1 BACKGROUND OF REPORT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1

1.2 PURPOSE AND SCOPE OF REPORT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1

1.3 CONTENTS AND ORGANIZATION OF REPORT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-2

1.4 GENERAL METHODS AND INFORMATION SOURCES . . . . . . . . . . . . . . . . . . . . . . 1-3

1.4.1 Industry Overview, Waste Generation, and Current Management Practices . . . . 1-3

1.4.2 Waste Characterization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-4

1.4.3 Overview of Risk Assessment Methodology and Results . . . . . . . . . . . . . . . . . . . 1-4

1.4.4 Damage Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-8

1.4.5 Existing Regulatory Controls Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-9

1.4.6 Waste Management Alternatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-10

1.4.7 Cost and Economic Impact Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-11

1.5 DECISION-MAKING PROCESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-11

2.0 INDUSTRY OVERVIEW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1

2.1 DESCRIPTION AND COMPARISON OF INDUSTRY SECTORS . . . . . . . . . . . . . . . . . 2-1

2.2 TRENDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-2

2.3 ENVIRONMENTAL JUSTICE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-5

3.0 COMANAGED WASTES AT COAL-FIRED UTILITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1

3.1 WASTE GENERATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1

3.1.1 Boiler Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-4

3.1.2 Air Pollution Control Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-6

3.1.3 Fuel Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-6

3.1.4 Supporting Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-9

3.2 WASTE CHARACTERISTICS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-12

3.2.1 Large-Volume and Low-Volume Utility Coal Combustion Wastes as

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

3.2.2 Comanaged Utility Coal Combustion Wastes . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-15

3.2.3 Wastes from Coburning Coal and Other Fuels . . . . . . . . . . . . . . . . . . . . . . . . . . 3-20

3.3 CURRENT MANAGEMENT PRACTICES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-21

3.3.1 Unit Types and Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-21

3.3.2 Types of Waste Managed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-23

3.3.3 Unit Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-28

3.3.4 Environmental Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-28

3.3.5 Beneficial Uses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-34

3.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE

ENVIRONMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-38

3.4.1 Potential Ground-Water Risks to Human Health . . . . . . . . . . . . . . . . . . . . . . . . . 3-38

3.4.2 Potential Above-Ground Multi-Pathway Risks to Human Health and the

Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-43

3.4.3 Documented Damages to Human Health and the Environment . . . . . . . . . . . . . 3-47

3.4.4 Compliance History of the Fossil Fuel Electric Power Industry . . . . . . . . . . . . . 3-50

3.4.5 Minefill Risks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-51

3.5 EXISTING REGULATORY CONTROLS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-53

3.5.1 Regulations Addressing Air Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-53
Report to Congress on Wastes from the Combustion of Fossil Fuels

iv March 1999

3.5.2 Regulations Addressing Water Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-56

3.5.3 Regulations Addressing Solid and Hazardous Waste . . . . . . . . . . . . . . . . . . . . . 3-58

3.6 WASTE MANAGEMENT ALTERNATIVES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-62

3.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS . . . . . . . . . . . . . . . . . . . . . . . . . 3-63

3.7.1 Overview and Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-63

3.7.2 Incremental Compliance Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-66

3.7.3 Compliance Cost Impact on Plants as a Function of Plant Size . . . . . . . . . . . . . 3-66

3.7.4 Industry Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-68

3.8 FINDINGS AND RECOMMENDATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-69

3.8.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-69

3.8.2 Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-69

3.8.3 Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-73

4.0 NON-UTILITY COAL COMBUSTION WASTES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1

4.1 WASTE GENERATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-3

4.1.1 Boiler Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-4

4.1.2 Air Pollution Control Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-5

4.1.3 Fuel Usage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-7

4.1.4 Supporting Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-8

4.2 WASTE CHARACTERISTICS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-9

4.3 CURRENT MANAGEMENT PRACTICES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-10

4.3.1 Unit Types and Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-11

4.3.2 Types of Waste Managed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-11

4.3.3 Environmental Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-12

4.3.4 Beneficial Uses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-14

4.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE

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

4.4.1 Potential Ground-Water Risks to Human Health . . . . . . . . . . . . . . . . . . . . . . . . . 4-15

4.4.2 Potential Above-Ground Multi-Pathway Risk to Human Health and the

Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-17

4.4.3 Documented Damages to Human Health and the Environment . . . . . . . . . . . . . 4-17

4.5 EXISTING REGULATORY CONTROLS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-18

4.5.1 Regulations Addressing Air Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-19

4.5.2 Regulations Addressing Water Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-21

4.5.3 Regulations Addressing Solid and Hazardous Waste . . . . . . . . . . . . . . . . . . . . . 4-23

4.6 WASTE MANAGEMENT ALTERNATIVES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-26

4.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS . . . . . . . . . . . . . . . . . . . . . . . . . 4-26

4.7.1 Overview and Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-27

4.7.2 Incremental Compliance Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-27

4.7.3 Compliance Cost Impact on Facilities as a Function of Size . . . . . . . . . . . . . . . . 4-28

4.7.4 Industry Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-30

4.8 FINDINGS AND RECOMMENDATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-30

4.8.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-30

4.8.2 Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-31

4.8.3 Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-33

5.0 FLUIDIZED BED COMBUSTION WASTES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1

5.1 WASTE GENERATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1

5.1.1 Fluidized Bed Combustion Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-3

5.1.2 Air Pollution Control Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-5
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 v

5.1.3 Fuel and Sorbent Use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-6

5.1.4 Supporting Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-8

5.2 WASTE CHARACTERISTICS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-9

5.2.1 Physical Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-9

5.2.2 Chemical Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-9

5.3 CURRENT MANAGEMENT PRACTICES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-12

5.3.1 Unit Types and Locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-13

5.3.2 Types and Volumes of Wastes Managed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-13

5.3.3 Unit Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-14

5.3.4 Environmental Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-14

5.3.5 Beneficial Uses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-16

5.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE

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

5.4.1 Potential Ground-Water Risks to Human Health . . . . . . . . . . . . . . . . . . . . . . . . . 5-17

5.4.2 Potential Above-Ground Multi-Pathway Risks to Human Health and the

Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-19

5.4.3 Documented Damages to Human Health and the Environment . . . . . . . . . . . . . 5-20

5.5 EXISTING REGULATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-20

5.5.1 Regulations Addressing Air Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-21

5.5.2 Regulations Addressing Water Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-23

5.5.3 Regulations Addressing Solid and Hazardous Waste . . . . . . . . . . . . . . . . . . . . . 5-25

5.6 WASTE MANAGEMENT ALTERNATIVES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-28

5.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS . . . . . . . . . . . . . . . . . . . . . . . . . 5-28

5.7.1 Overview and Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-28

5.7.2 Incremental Compliance Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-30

5.7.3 Compliance Cost Impact on Facilities as a Function of Size . . . . . . . . . . . . . . . . 5-30

5.7.4 Industry Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-32

5.8 FINDINGS AND RECOMMENDATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-32

5.8.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-32

5.8.2 Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-33

5.8.3 Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-35

6.0 OIL COMBUSTION WASTES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1

6.1 WASTE GENERATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-3

6.1.1 Combustion Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-5

6.1.2 Air Pollution Control Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-6

6.1.3 Fuel Usage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-7

6.1.4 Supporting Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-10

6.2 WASTE CHARACTERISTICS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-10

6.2.1 Physical Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-10

6.2.2 Chemical Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-11

6.2.3 Leaching and Hazardous Waste Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . 6-11

6.3 CURRENT MANAGEMENT PRACTICES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-14

6.3.1 Facilities Generating OCWs Only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-15

6.3.2 Facilities Generating Both OCWs and Coal Combustion Wastes . . . . . . . . . . . . 6-18

6.3.3 Beneficial Uses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-19

6.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE

ENVIRONMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-20

6.4.1 Potential Ground-Water Risks to Human Health . . . . . . . . . . . . . . . . . . . . . . . . . 6-20
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6.4.2 Potential Above-Ground Multi-Pathway Risks to Human Health and the

Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-22

6.4.3 Documented Damages to Human Health and the Environment . . . . . . . . . . . . . 6-22

6.5 EXISTING REGULATORY CONTROLS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-23

6.5.1 Regulations Addressing Air Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-23

6.5.2 Regulations Addressing Water Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-26

6.5.3 Regulations Addressing Solid and Hazardous Waste . . . . . . . . . . . . . . . . . . . . . 6-28

6.6 WASTE MANAGEMENT ALTERNATIVES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-30

6.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS . . . . . . . . . . . . . . . . . . . . . . . . . 6-30

6.7.1 Overview and Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-31

6.7.2 Incremental Compliance Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-32

6.7.3 Compliance Cost Impact on Plants as a Function of Plant Size . . . . . . . . . . . . . 6-33

6.7.4 Industry Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-34

6.8 FINDINGS AND RECOMMENDATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-34

6.8.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-34

6.8.2 Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-35

6.8.3 Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-37

7.0 NATURAL GAS COMBUSTION WASTES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-1

7.1 TECHNOLOGY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-1

7.2 FINDINGS AND RECOMMENDATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-2

7.2.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-2

7.2.2 Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-2

7.2.3 Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-2

REFERENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . R-1

GLOSSARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . G-1
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 vii

LIST OF FIGURES

Figure 1-1. Exposure Pathways for Human Receptors .................................... . 1-5

Figure 1-2. Exposure Pathways for Ecological Receptors ................................. . 1-6

Figure 2-1. Relative Size of Fossil Fuel Combustion Industry Sectors ........................ . 2-2

Figure 2-2. FFC Waste Generation Compared to Other Wastes ............................. . 2-3

Figure 2-3. Projected Utility Generating Capacity ....................................... . 2-4

Figure 2-4. Projected Fuel Consumption by Fossil Fuel Combustion Industry Sectors ........... . 2-5

Figure 3-1. Number of Coal-Fired Utility Power Plants by State ............................ . 3-2

Figure 3-2. Approximate Ash Distribution by Coal Combustion Technology .................. . 3-5

Figure 3-3. Air Pollution Control Technologies Used at Coal-Fired Utilities .................. . 3-8

Figure 3-4. Trend in Utility Coal Combustion Waste (UCCW) Management Unit Type ........ . 3-23

Figure 3-5. Geographic Distribution of Utility Coal Combustion Waste (UCCW) Management

Units ................................................................ . 3-24

Figure 3-6. Comanagement Volumes in Units Responding to EPRI Survey .................. . 3-26

Figure 3-7. Size Distribution of Management Units for UCCW ............................ . 3-29

Figure 3-8. Trend in Liner Utilization in Comanagement Units ............................ . 3-31

Figure 3-9. Liner Types for Comanagement Units ...................................... . 3-32

Figure 3-10. Comanagement Unit Cover Types ......................................... . 3-33

Figure 3-11. Trend in Comanagement Unit Ground-Water Monitoring ....................... . 3-35

Figure 4-1. Non-Utility Fossil Fuel Combustion Sector by Fuel Type ........................ . 4-1

Figure 4-2. Number of Non-Utility Coal Combustors by State .............................. . 4-2

Figure 4-3. Comparison of Utility and Non-Utility Conventional Coal Combustion Technologies . . . 4-5

Figure 4-4. Distribution of Coal-Fired Boilers by Capacity ................................ . 4-6

Figure 4-5. Particulate Control Technologies Used at Coal-Fired Non-Utilities ................ . 4-7

Figure 4-6. Comparison of Leachate Characteristics of Utility and Non-Utility Wastes ......... . 4-10

Figure 4-7. Combined Management of CCWs with Other Wastes at Non-Utilities ............. . 4-12

Figure 4-8. Types of Liners at Non-Utility CCW Landfills ............................... . 4-14

Figure 5-1. Number of Fluidized Bed Combustion Facilities ............................... . 5-2

Figure 5-2. Capacities of Conventional and FBC Boilers .................................. . 5-5

Figure 5-3. Capacities of Utility and Non-Utility FBC Units ............................... . 5-6

Figure 5-4. Particulate Control Technologies Used at FBC Facilities ........................ . 5-7

Figure 5-5. FBC Landfill Liner Types ................................................ . 5-16

Figure 6-1. Number of Utility Power Plants Burning Oil .................................. . 6-2

Figure 6-2. Capacity of Utility Oil-Fired and Coal-Fired Boilers ............................ . 6-6

Figure 6-3. Particulate Control Technologies at Oil-Fired Utilities .......................... . 6-7

Figure 6-4. Oil Consumption by Utilities and Non-Utilities ................................ . 6-9

Figure 7-1. Number of Gas-Fired Power Plants by State .................................. . 7-1
Report to Congress on Wastes from the Combustion of Fossil Fuels

viii March 1999

LIST OF TABLES

Table 3-1. Total Generation of Large-Volume Utility Coal Combustion Waste (UCCW) . . . . . . . . . 3-3

Table 3-2. Low-Volume Waste Generation Rates at Coal-Fired Utilities . . . . . . . . . . . . . . . . . . . . . . 3-4

Table 3-3. Distribution of Utility Conventional Coal Combustion Technologies . . . . . . . . . . . . . . . . 3-6

Table 3-4. Ash Content and Fuel Usage by Coal-Fired Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-8

Table 3-5. General Composition of Selected Low-Volume Wastes . . . . . . . . . . . . . . . . . . . . . . . . . 3-14

Table 3-6. Total Concentration Data for Coal Mill Rejects (ppm) . . . . . . . . . . . . . . . . . . . . . . . . . . 3-15

Table 3-7. Summary of Hazardous Waste Characteristics for Low-Volume Wastes . . . . . . . . . . . . 3-16

Table 3-8. Facility Average Concentrations of Trace Constituents in Comanaged Wastes . . . . . . . 3-17

Table 3-9. Facility Average Leachate Concentrations for Comanaged Wastes . . . . . . . . . . . . . . . . . 3-19

Table 3-10. Fuel Mixtures with Waste Characterization Data Available for Comparison to UCCWs 3-20

Table 3-11. Unit Type by Power Generating Capacity for Utility Coal Combustion Waste (UCCW)

Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-25

Table 3-12. Low-Volume and Large-Volume Waste Compared by Management Unit . . . . . . . . . . . 3-27

Table 3-13. Low-Volume Wastes Most Commonly Comanaged . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-27

Table 3-14. Management Unit Size for UCCW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-28

Table 3-15. Environmental Controls at UCCW Comanagement Units . . . . . . . . . . . . . . . . . . . . . . . . 3-30

Table 3-16. Beneficial Use of Utility Coal Combustion Wastes in 1997 . . . . . . . . . . . . . . . . . . . . . . 3-36

Table 3-17. Constituents Remaining after Screening Analysis for Coal-Fired Utility Comanaged

Wastes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-41

Table 3-18. Comparison of Deterministic and Monte Carlo Risk Model Results for Comanaged

Waste Ground-Water Pathway Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-42

Table 3-19. Comparison of Adult and Child Risk Model Results for Comanaged Waste GroundWater Pathway Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-43

Table 3-20. Comparison of Adult and Child Risk Model Results for Comanaged Waste AboveGround Ingestion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-45

Table 3-21. Summary of Ecological Risk Results for Comanaged Waste Impoundments . . . . . . . . . 3-47

Table 3-22. Damage Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-48

Table 3-23. State Regulatory Controls on UCCW Landfills . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-59

Table 3-24. Current State Regulatory Controls on CCW Surface Impoundments . . . . . . . . . . . . . . . . 3-59

Table 3-25. State Waste Management Requirements Applicable to UCCWs in Selected States . . . . 3-60

Table 3-26. Management Alternatives for Coal-Fired Utility Comanaged Waste and Segregated Mill

Rejects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-63

Table 3-27. Cost Components Included in Landfill and Impoundment Designs . . . . . . . . . . . . . . . . . 3-64

Table 3-28. Design Parameters Assumed for Small, Medium, and Large Landfills and

Impoundments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-65

Table 3-29. Plant-Level Impact of Incremental Compliance Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-67

Table 3-30. Incremental Compliance Cost by Plant Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-68

Table 3-31. Industry Economic Impacts, Coal-Fired Utility Comanaged Wastes . . . . . . . . . . . . . . . . 3-69

Table 4-1. Fuel Usage by Coal-Fired Non-Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-7

Table 4-2. Types of Wastes Comanaged with Non-Utility CCWs . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-13

Table 4-3. Environmental Controls at Non-Utility CCW Landfills . . . . . . . . . . . . . . . . . . . . . . . . . . 4-13

Table 4-4. Non-Utility FFC Waste Beneficial Uses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-15

Table 4-5. Comparison of Deterministic and Monte Carlo Risk Model Results for Non-Utility Coal

Combustion Waste Ground-Water Pathway Scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-16

Table 4-6. Comparison of Adult and Child Risk Model Results for Non-Utility Coal Combustion

Waste – Ground-Water Pathway Scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-16

Table 4-7. Potential Damage Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-18
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 ix

Table 4-8. State Regulatory Controls on Non-Utility Coal Combustion Waste Landfills . . . . . . . . . 4-24

Table 4-9. State Waste Management Requirements Applicable to Non-Utility CCWs in Selected

States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-24

Table 4-10. Management Alternatives for Non-Utility Coal Combustion Waste . . . . . . . . . . . . . . . . 4-26

Table 4-11. Design Parameters Assumed for Small, Medium, and Large Landfills . . . . . . . . . . . . . . 4-28

Table 4-12. Cost Estimates for Non-Utility CCW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-29

Table 4-13. Facility-Level Economic Impacts, Non-Utility CCW . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-30

Table 4-14. Industry-Level Economic Impacts, Non-Utility CCW . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-31

Table 5-1. Primary Fuels Used by FBC Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-7

Table 5-2. Sorbent and Bed Materials Used at FBC Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-8

Table 5-3. Facility Average Concentrations of Trace Constituents in FBC Wastes . . . . . . . . . . . . . 5-10

Table 5-4. Facility Average TCLP Results for FBC Wastes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-11

Table 5-5. FBC Waste Management Unit Sizes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-14

Table 5-6. Environmental Controls at FBC Waste Management Units . . . . . . . . . . . . . . . . . . . . . . . 5-15

Table 5-7. Beneficial Uses of FBC Wastes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-17

Table 5-8. Comparison of Deterministic and Monte Carlo Risk Model Results for FBC Waste

Ground-Water Pathway Scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-19

Table 5-9. Comparison of Adult and Child Risk Model Results for FBC Waste Ground-Water

Pathway Scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-19

Table 5-10. Current State Regulatory Controls on FBC Landfills . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-27

Table 5-11. State Waste Management Requirements Applicable to FBC Wastes in Selected States . 5-27

Table 5-12. Management Alternatives for Non-Utility CCW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-28

Table 5-13. Design Parameters Assumed for Small, Medium, and Large FBC Landfills . . . . . . . . . . 5-29

Table 5-14. Plant-Level Impact of Incremental Compliance Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-31

Table 5-15. Industry-Level Economic Impacts (FBC Wastes) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-32

Table 6-1. Locations of Utilities with Oil-Fired Baseload Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-2

Table 6-2. Particulate Control by Size of Utility Oil Combustion Unit . . . . . . . . . . . . . . . . . . . . . . . . 6-7

Table 6-3. Relative Removal Efficiencies of Particulate Control Technologies . . . . . . . . . . . . . . . . . 6-8

Table 6-4. Relative Ash Content by Weight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-8

Table 6-5. Facility Average Concentration of Selected Constituents in OCWs . . . . . . . . . . . . . . . . 6-12

Table 6-6. Facility Average TCLP Results for OCWs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-13

Table 6-7. Frequency of Toxicity Characteristic Exceedences for OCWs . . . . . . . . . . . . . . . . . . . . 6-14

Table 6-8. Combinations of OCW Managed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-15

Table 6-9. Comanagement of OCWs and Low-Volume Wastes . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-16

Table 6-10. OCW Management Surface Impoundment System Sizes . . . . . . . . . . . . . . . . . . . . . . . . . 6-17

Table 6-11. Comparison of Deterministic and Monte Carlo Risk Model Results for Oil Combustion

Waste – Ground-Water Pathway Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-21

Table 6-12. Predicted Time to Reach Risk for Oil Combustion Waste – Deterministic Scenarios . . . 6-21

Table 6-13. Comparison of Adult and Child Risk Model Results for Oil Combustion Waste –

Ground-Water Pathway Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-22

Table 6-14. Potential Damage Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-23

Table 6-15. State Waste Management Requirements Applicable to OCWs in Selected States . . . . . . 6-29

Table 6-16. Management Alternatives for OCW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-31

Table 6-17. Cost Components Included in OCW Solid Settling Basin Designs . . . . . . . . . . . . . . . . . 6-32

Table 6-18. Design Parameters Assumed for Small, Medium, and Large OCW SSBs . . . . . . . . . . . . 6-32

Table 6-19. Plant-Level Impact of Incremental Compliance Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-33

Table 6-20. Incremental Compliance Cost by Plant Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-34

Table 6-21. Industry Economic Impacts, Oil Combustion Wastes . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-34

Table 7-1. Natural Gas-Fired Generating Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-2
Report to Congress on Wastes from the Combustion of Fossil Fuels

x March 1999

LIST OF BOXES

Box 3-1. Conventional Coal Combustion Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-5

Box 3-2. Air Pollution Control Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-7

Box 3-3. Types of Waste Management Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-22

Box 3-4. Environmental Control Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-30

Box 5-1. Fluidized Bed Combustion (FBC) Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-4

Box 5-2. Environmental Control Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-15

Box 5-3. Beneficial Uses of FBC Wastes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-18

Box 6-1. Oil-Fired Steam Electric Boiler Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-5
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 1-1

1.0 INTRODUCTION

1.1 BACKGROUND OF REPORT

Section 3001(b)(3)(A)(I) of the Resource Conservation and Recovery Act (RCRA) excludes

certain large-volume wastes generated primarily from the combustion of coal or other fossil fuels from

being regulated as hazardous waste under Subtitle C of RCRA, pending completion of a Report to

Congress required by Section 8002(n) and a determination by the U.S. Environmental Protection Agency

(EPA) Administrator either to promulgate regulations under Subtitle C or to deem such regulations as

being unwarranted.

In 1988, EPA published the required Report to Congress on wastes from the combustion of coal

by electric utility power plants (EPA, 1988). In the Report to Congress, EPA responded to one of the

requirements of Section 8002(n) of RCRA. The report, however, did not address the following:

• Wastes generated by utilities burning fossil fuels other than coal

• Wastes from non-utility boilers burning any type of fossil fuel.

In 1991, a suit was filed on behalf of the Bull Run Coalition (an Oregon citizens group) based on

the absence of a final ruling by EPA on the wastes studied in the 1988 Report to Congress and on other

large-volume wastes generated primarily from the combustion of coal or other fossil fuels. As a result,

the Agency entered into a Consent Decree (Civil Action 91-2345, D.D.C. June 30, 1992), which

established a schedule for EPA to complete the regulatory determinations for all fossil fuel combustion

(FFC) wastes. FFC wastes were divided into two categories: (1) fly ash, bottom ash, boiler slag, and

flue gas emission control waste from the combustion of coal by electric utilities and independent

commercial power producers, and (2) all remaining wastes subject to RCRA Sections 3001(b) and

8002(n). On August 9, 1993, EPA published a determination for the first category of wastes, concluding

that regulation under Subtitle C for these wastes was not warranted. To make an appropriate

determination for the second category or “remaining wastes,” EPA decided that additional study was

necessary. Under the current court-ordered deadlines, the Agency must publish this Report to Congress

by March 31, 1999, and issue a regulatory determination by October 1, 1999.

1.2 PURPOSE AND SCOPE OF REPORT

EPA presents this Report to Congress on Wastes from the Combustion of Fossil Fuels as a

complement to the 1988 Report to Congress. This report was prepared in response to the requirements of

Section 8002(n) of RCRA, which directs EPA to provide a detailed and comprehensive study on the

sources and quantities of certain large-volume wastes generated primarily from the combustion of coal or

other fossil fuels, potential human health and environmental impacts posed by the management of these

wastes, alternatives to current practices, and costs of such alternatives. This report also prepares EPA for

its regulatory determination on the remaining wastes, scheduled to be completed by October 1, 1999.

This report addresses the remaining wastes from FFC only. As defined in the 1992 Consent

Decree, remaining wastes comprise the following:

• Fly ash, bottom ash, boiler slag, and flue gas emission control wastes from the combustion

of coal by electric utility power plants, when such wastes are mixed with, codisposed,

cotreated, or otherwise comanaged with other wastes generated in conjunction with the

combustion of coal or other fossil fuels
Report to Congress on Wastes from the Combustion of Fossil Fuels

1-2 March 1999

• Any other wastes subject to Section 8002(n) of RCRA, except fly ash, bottom ash, boiler

slag, and flue gas emission wastes from coal combustion by electric utilities.

For the purposes of this report, EPA has termed the first category of remaining wastes listed

above as “comanaged utility coal combustion wastes” (“comanaged wastes” for short). EPA further

subdivided the second category of remaining wastes as follows:

• Wastes from the combustion of mixtures of coal and other fuels (“coburning”) by utilities

• Wastes from the combustion of coal by non-utilities

• Wastes from fluidized bed combustion of fossil fuels (by utilities and non-utilities)

• Wastes from the combustion of oil (by utilities and non-utilities)

• Wastes from the combustion of natural gas (by utilities and non-utilities).

In this study, EPA presents its current understanding of the generation, management, disposal,

and reuse of these remaining wastes from FFC. EPA addresses the following eight study factors required

by Section 8002(n) of RCRA:

1. The source and volumes of such materials generated per year

2. Present disposal and utilization practices

3. Potential danger, if any, to human health and the environment from the disposal and reuse of

such material

4. Documented cases in which danger to human health or the environment from surface runoff

or leachate has been proved

5. Alternatives to current disposal methods

6. The costs of such alternatives

7. The impacts of those alternatives on the use of coal and other natural resources

8. The current and potential utilization of such materials.

1.3 CONTENTS AND ORGANIZATION OF REPORT

The report is organized into seven chapters that address the study factors required under Section

8002(n) of RCRA. Chapter 2 provides an overview of FFC in the United States, including a brief

description of the utility and non-utility sectors and a discussion of projected trends for the industry. 

Chapters 3 through 7 parallel the categories of remaining wastes listed above in Section 1.2. Chapter 3

focuses on comanaged utility coal combustion waste and also covers coburning by utilities. Chapter 4

examines non-utility coal combustion waste. Chapters 5 and 6 discuss fluidized bed combustion wastes

and oil combustion wastes, respectively. Chapter 7 focuses on natural gas combustion wastes. Chapters

3 through 6 each provide overviews of their relevant sectors; describe the wastes generated, their

characteristics, and volumes; and examine current waste management practices, potential and

documented dangers to human health and the environment, existing regulatory controls, waste

management alternatives, and costs and economic impacts. Chapter 7 presents a brief overview of

natural gas combustion technology (additional discussion of natural gas combustion wastes is not
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 1-3

warranted because of minimal waste generation). Finally, each of the chapters presents the Agency’s

findings and tentative recommendations for the regulatory determination.

1.4 GENERAL METHODS AND INFORMATION SOURCES

1.4.1 Industry Overview, Waste Generation, and Current Management Practices

The introductory, waste generation, and current management practices sections of this report

provide a general overview and background on the FFC industry. Much of the descriptive information in

these sections was adapted from the standard industry texts and other references listed at the end of this

report. Statistical data describing the industry, combustion technologies, waste generation rates, and

waste management practices were derived from several major sources, including the following:

1. The 1994 Edison Electric Institute (EEI) Power Statistics Database (EEI, 1994), which

incorporates the 1993 Energy Information Administration (EIA) 767 Database

2. The 1990 U.S. EPA National Interim Emission Inventory (EPA, 1990)

3. The 1997 Council of Industrial Boiler Owners (CIBO) Non-Utility Survey (CIBO, 1997a)

4. The 1997 CIBO Fluidized Bed Combustion (FBC) Survey (CIBO, 1997b)

5. The 1997 Electric Power Research Institute (EPRI) Comanagement Survey (EPRI, 1997a)

6. EPRI’s report summarizing results of the Comanagement Survey (EPRI, 1997b)

7. EPRI’s report, Oil Combustion By-Products: Chemical Characteristics, Management

Practices, and Groundwater Effects (EPRI 1998a)

8. CIBO’s report, Report to the U.S. Environmental Protection Agency on Fossil Fuel

Combustion Byproducts from Fluidized Bed Boilers (CIBO, 1997c)

9. The U.S. Department of Energy’s (DOE) Coal Combustion Waste Management Study

(DOE, 1993).

Publications 6 through 9 are available in the EPA docket. Although the electronic databases (1 through

5) are not in the docket, EPA’s methodology for analyzing these databases and the results of these

analyses are presented in EPA documents prepared in support of this study (i.e., the Technical

Background Document for the Report to Congress on Remaining Wastes from Fossil Fuel Combustion: 

Industry Statistics and other documents). These documents can be found in the EPA docket.

The waste management sections of this report also describe current beneficial uses of FFC

wastes. To characterize the prevalence, methods, and effects of beneficial use of FFC wastes, EPA

compiled and reviewed a variety of publicly available information. The purpose of this review was to

identify (1) those uses with the potential to expand as alternatives to current management practices, and

(2) those uses with the potential for environmental impacts worthy of further consideration in the risk

assessment portion of this study. Literature reviewed by EPA included descriptions of existing and

emerging uses, feasibility studies, environmental performance studies, economic evaluations, reviews of

regulatory requirements, case studies, and usage statistics. The specific sources reviewed are identified
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in the Technical Background Document titled Beneficial Use of Fossil Fuel Combustion Wastes,

available in the EPA docket.

1.4.2 Waste Characterization

To describe the physical, chemical, and leachate characteristics of FFC wastes, EPA relied upon

analytical data submitted voluntarily by the industry. In summarizing and performing statistical analyses

of these data, EPA used several standard procedures. First, values reported as below a detection limit

were assigned a value equal to one-half the detection limit for purposes of statistical analysis. Second,

because the Agency was more interested in variation between facilities than variation within individual

facilities, much of the characterization was performed using facility-averaged values. That is, multiple

measurements from a single site were averaged, and the resulting population of facility averages was

used to generate summary statistics.

Major sources used to characterize FFC wastes include the following:

1. EPRI site reports for coal-fired utilities comanaging wastes (EPRI, 1991, 1992, 1994a,

1994b, 1996a, 1996b, 1997c, 1997d, 1997e, 1997f, 1997g, 1997h, 1997i, 1997j, 1997k,

1997l)

2. EPRI’s Guidance for Comanagement of Mill Rejects at Coal-fired Power Plants (EPRI,

1999)

3. EPRI’s PCDDs and PCDFs in Coal Combustion By-Products (EPRI, 1998b)

4. EPRI’s Characterization of Byproducts from Coburning with Coal in Utility Boilers (EPRI,

1997m)

5. EPRI’s oil combustion byproducts database (EPRI, 1997n)

6. Characterization data submitted in response to CIBO’s FBC Survey (CIBO, 1997b)

7. Summary data for coal-fired stoker boilers provided by CIBO (CIBO, 1998).

Publications 1 through 4 are available in the EPA docket. Although the electronic databases (5 through

7) are not in the docket, EPA’s methodology for analyzing these databases and the results of these

analyses are presented in EPA documents prepared in support of this study (i.e., the Technical

Background Document for the Report to Congress on Remaining Wastes from Fossil Fuel Combustion: 

Waste Characterization and other documents). These documents can be found in the EPA docket.

1.4.3 Overview of Risk Assessment Methodology and Results

EPA conducted a very comprehensive multi-pathway risk assessment for this report. For both

human health and ecological risk, a wide range of exposure paths, exposure routes, and receptors was

considered. Figures 1-1 and 1-2 depict the full range of such combinations. This comprehensive

approach reflects advances in risk assessment techniques made since the previous fossil fuel combustion

Report to Congress (1988) and the previous Regulatory Determination (1993).
March 1999 1-5 Figure 1-1. Exposure Pathways for Human Receptors
1-6 March 1999 Figure 1-2. Exposure Pathways for Ecological Receptors
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March 1999 1-7

The methodology involved, first, preliminary “screening” to determine if “worst-case”

contaminant levels (measured levels close to or within the source) present a threat to human health, and

second, if a potential threat was determined in the “screening” phase, fate and transport modeling to

determine exposure to a receptor. For ecological risk assessment, the emphasis was on modeling to

determine exposure and risk to any of the multitude of possible receptors (see Figure 1-2).

As part of the risk assessment process for this study, EPA submitted the multi-pathway risk

assessment to external peer review. The human health ground-water risk assessment and non-groundwater risk assessment were reviewed by two primary peer reviewers, and the ecological risk assessment

was reviewed by two different primary peer reviewers. Subsequent to peer review, EPA performed a

variety of sensitivity and uncertainty analyses to derive a best estimate of risks for each of the scenarios

modeled. Peer review comments and sensitivity and uncertainty analyses can be found in the docket.

The “screening” phase of the analysis was purposely structured to avoid the likelihood of

removing from further analysis any contaminant that might pose a threat. While the 1993 screening

analysis prescribed for ground water that measured contaminant levels exceed selected health-based

numbers by a factor of 10, and that at least 10 percent of samples must show such an exceedance, this

risk assessment prescribed no such threshold. Even one health-based number exceedance for a reported

maximum concentration level required modeling. This was a very conservative approach; in essence,

modeling dictated that very few chemicals were screened out. The same approach guided the nonground-water human health assessment (no non-ground-water modeling was accomplished in 1993).

The primary ground-water model utilized by EPA’s Office of Solid Waste (OSW), known as

EPACMTP (see Section 3.4), provided the basis for the risk results denoted. This model has been peer

reviewed as well as reviewed by EPA’s Science Advisory Board. In an effort to confirm general trends

and results, and to provide further insight into the sensitivity of results to changes in significant input

variables, the electric power industry’s MYGRT model was run in selected cases. While there were

differences in modeled results, general confirmation of times to peak concentration were found. The

methodology used for the non-ground-water analysis, for both human health and ecological risk, involves

a complex series of linked spreadsheets embodying a multitude of input variables; as noted, all modeling

procedures are described in detail in Sections 3.4, 4.4, 5.4, and 6.4, and in the documents found in the

docket in support of this Report to Congress.

Under RCRA, EPA’s OSW is required to conduct nationwide risk assessments. Where disposal

facilities are located regionally, the analysis is of course tailored to regional conditions. For this report,

the four industry segments—coal-fired utilities, oil-fired utilities, combustors utilizing fluidized bed

technology (FBCs), and the amorphous collection of “all other” burners of any fossil fuel—presented

different modeling problems. For the essentially nationwide sets of coal-fired utilities and the “all other”

collection, EPA used a nationwide environmental data set; for both the FBC facilities and the oil-fired

utilities, the data sets were tailored as much as possible to the regions where these units are found.

All data for the risk assessments but for basic nationwide or regional descriptive environmental

data (which were taken from existing EPA data bases) were provided voluntarily by the industry

potentially to be regulated. As noted in the documents provided for the docket, the industry-provided

data varied in their representativeness. For the oil-fired utilities and the FBC facilities, some 30 percent

of the sites were well represented. For the coal-fired utilities, fewer than 1 percent of landfills were

represented in industry-collected samples, and some 3 percent of impoundments were so represented. 

However, previously existing leachate data were used to supplement the industry samples.
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In essence, a great deal of judgment had to be exercised to provide any assurance that the

contaminant data provided by industry were sufficient for analysis. A very extensive sensitivity analysis

was performed to aid in this process (for details, see in particular the documents provided in the docket

supporting this Report to Congress). All modeling input variables of known modeling significance were

varied alone and in combinations of up to three at a time to test for uncertainty. Still, industry-provided

contaminant data presented a problem. EPA tested these at up to three times reported levels but did not

test for the possibility that even higher levels might exist. Uncertainty still exists as to the nationwide

representativeness of this key input variable.

For minefills, wherein ash wastes are disposed, EPA is continuing its analysis. This includes

both surface and deep mines. While surface minefills may be simulated much like landfills, deep

minefills present many complex problems. Also, the industry, depending on the particular siting issues,

has many mitigating options available. A discussion of this issue is found in Section 3.4 of this Report to

Congress.

1.4.4 Damage Analysis

In its evaluation of remaining FFC wastes, EPA evaluated damage cases in the same way as in

previous Reports to Congress for RCRA §8002 wastes (i.e., the 1993 Report to Congress on Cement Kiln

Dust and the 1990 Report to Congress on Special Wastes from Mineral Processing). Specifically, EPA

used a “test of proof” in these reports to identify documented damage cases. As discussed in later

sections of this Report to Congress, EPA identified a number of cases in which contaminants are present

in environmental media surrounding FFC sites, but the available data were insufficient to qualify the sites

as documented damage cases based on the “test of proof” described below.

Section 8002(o)(4) of RCRA requires that EPA’s study of remaining FFC wastes examine

“documented cases in which danger to human health or the environment has been proved.” To address

this requirement, EPA defined danger to human health or the environment in the following manner. 

First, danger to human health includes both acute and chronic effects (e.g., directly observed health

effects such as elevated blood-lead levels). Second, danger to the environment includes the following

types of impacts: (1) significant impairment of natural resources (e.g., contamination of any current or

potential source of drinking water with contaminant concentrations exceeding drinking water and/or

aquatic ecological standards), (2) ecological effects resulting in degradation of the structure or function

of natural ecosystems and habitats, and (3) effects on wildlife resulting in damage to terrestrial or aquatic

fauna (e.g., reduction in species’ diversity or density, or interference with reproduction).

As stipulated in RCRA §8002(o)(4), EPA is statutorily required to examine proven cases of

danger to human health or the environment. Accordingly, EPA developed “tests of proof” for the abovementioned Reports to Congress to determine if documentation available on a case provides evidence that

danger or damage has occurred, and uses the same methodology here. These “tests of proof” comprise

three separate tests; a case that satisfies one or more of these tests is considered “proven.” The tests are

as follows:

• Scientific investigation. Damages are found to exist as part of the findings of a scientific

study. Such studies should include both formal investigations supporting litigation or a state

enforcement action, and the results of technical tests (such as monitoring of wells). 

Scientific studies must demonstrate that damages are significant in terms of impacts on

human health or the environment. For example, information on contamination of a drinking

water aquifer must indicate that contaminant levels exceed drinking water standards.
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March 1999 1-9

• Administrative ruling. Damages are found to exist through a formal administrative ruling,

such as the conclusions of a site report by a field inspector, or through existence of an

enforcement action that cited specific health or environmental damages.

• Court decision. Damages are found to exist through the ruling of a court or through an outof-court settlement.

For many sites studied for this report, EPA employed a fourth “test.” Specifically, damages must

be attributable to FFC wastes. The non-utility universe encompasses many types of facilities. EPA

found that FFC wastes could be found at many industrial sites at which damages have occurred. 

However, the observed damages were generally unrelated to FFC wastes. Therefore, to be considered a

proven damage case, EPA required sufficient information to determine that FFC wastes were not only

present, but clearly implicated, in the reported damage.

1.4.5 Existing Regulatory Controls Analysis

This report characterizes regulations addressing air pollution, water pollution, and solid and

hazardous waste. Air regulations were analyzed primarily for their historical and potential future impact

on waste generation. The analysis focused on federal programs and was based on a review of the

relevant regulations and experience with the application of these programs to the FFC universe.

Water regulations were analyzed to provide background on their impact on waste management

practices and because of their potential for controlling direct release of FFC wastes to surface water. 

Because state programs implement and must be at least as stringent as the federal program, the analysis

focused on federal requirements as a lowest common denominator. As for air regulations, the analysis

was based on a review of the relevant regulations and experience with the application of these programs

to the FFC universe.

The analysis of solid and hazardous waste regulations focused on state implementation of solid

waste controls on FFC wastes under Subtitle D of RCRA. State solid waste management regulations

were analyzed first on a nationwide scale, using survey data for all 50 states, and second on a more

detailed level, using case studies of selected states.

For analysis on a nationwide scale, data on state solid waste management regulations in all 50

states were compiled from four sources, all of which are available in the EPA docket:

1. The Association of State and Territorial Solid Waste Management Officials’ (ASTSWMO)

Non-municipal, Subtitle D Waste Survey (ASTSWMO, 1996)

2. EPA’s State Requirements for Industrial Non-Hazardous Waste Management Facilities

(EPA, 1995b)

3. A survey of state waste management controls conducted as part of CIBO’s Report to the

U.S. Environmental Protection Agency on Fossil Fuel Combustion Byproducts from

Fluidized Bed Boilers (CIBO, 1997c)

4. The American Coal Ash Association’s (ACAA) State-by-State Summaries of Solid Waste

Regulations (ACAA, 1996).
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The ACAA summaries were used to characterize the exemption status of FFC wastes in all 50

states. The ASTSWMO and CIBO survey results were combined to characterize the types of regulatory

controls imposed on FFC waste management units. The EPA review data were used to describe daily

cover/fugitive dust controls (not surveyed by ASTSWMO) to confirm the other survey data for the states

with the largest capacity in each generating sector, and to provide additional descriptive information.

The ASTSWMO and CIBO results agreed in the majority of cases. In cases in which the two

sources disagreed, the ASTSWMO data were used because the results were more detailed and better

documented. In the analysis, the combined data were used to generate summary statistics on the nature

and stringency of state solid waste management controls in all 50 states. In the case of coal combustion

wastes, these data also were compared to historical data from the 1988 Report to Congress (EPA, 1988)

to draw conclusions about trends in state regulation.

To further characterize state implementation, EPA examined in detail programs in several (two to

five) selected states for each FFC waste sector. The specific states were selected to maximize the

percentage of generating capacity covered in each sector while making efficient use of available

resources. For example, much of the regulatory controls information was collected during visits to state

agencies to collect waste management and damage case information. The analysis of each state included

review of regulations, discussions with state officials, comparison with observed management practices,

and review of published summary information, including that which can be found in the CIBO report and

the survey publications cited above. The results of this detailed analysis are summarized here and

presented in more detail in the supporting documents contained in the EPA docket.

1.4.6 Waste Management Alternatives

Because the risk assessment identified potential risks from unlined waste management units and

in certain other situations as noted below, EPA considered alternative risk mitigation strategies. The

alternative management practices considered depended on the waste and the current practice for which

potential risk was found. The appropriate chapters of this report discuss these alternatives in detail. 

They may be summarized as follows:

• The ground-water risk assessment identified potential risk for comanaged waste from coalfired utilities managed in landfills and surface impoundments, non-utility coal combustion

waste managed in landfills, fluidized bed combustion waste managed in landfills, and oil

combustion waste managed in landfills and solids settling basins. The risk mitigation

alternatives for these cases are consistent with the design requirements for municipal solid

waste landfills under Subtitle D of RCRA. The alternatives are, in fact, similar to current

management practices at some FFC facilities (e.g., facilities with lined waste management

units). Thus, the alternatives considered would reflect a change in management practices

only for part of the FFC universe (e.g., that part using unlined disposal).

• The above-ground risk assessment identified potential risk for comanaged waste from coalfired utilities, non-utility coal combustion waste, and fluidized bed combustion waste when

used in agricultural applications. For these cases, a variety of management alternatives was

considered, ranging from a ban to a concentration-based limit on wastes intended for

agricultural use.

• The ecological risk assessment identified potential risk from immersion in surface

impoundments containing comanaged waste from coal-fired utilities. This report does not

suggest specific mitigation alternatives for this ecological risk.
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• EPA identified comanagement of mill rejects (specifically, their pyrite component) with

coal combustion wastes as a practice of potential concern. Because the Agency currently is

evaluating a voluntary industry proposal for mill reject management, this report does not

consider specific mitigation alternatives for mill rejects.

• EPA identified minefilling of FFC wastes as a practice of potential concern. The Agency

currently is seeking more information on this practice.

1.4.7 Cost and Economic Impact Analysis

For FFC wastes disposed in landfills and impoundments/basins, EPA analyzed the costs for

economic impacts of the alternative Subtitle D management practices as follows:

• The Agency estimated the incremental compliance costs associated with Subtitle D

compliance. The calculation of incremental cost made allowances for those sites already in

compliance. (EPA is aware that some combustors have undertaken a liner program in

conjunction with state programs.)

• Based on the incremental compliance costs, EPA analyzed economic impacts at the firm

level.

• Finally, based on the incremental compliance costs, EPA assessed economic impacts at the

industry level.

This analysis was very detailed, as discussed in Sections 3.7, 4.7, 5.7, and 6.7.

For pyrite management and for agricultural use alternatives, the Agency has not as yet conducted

a cost and impact analysis. The pyrite management proposals are the industry’s, voluntarily submitted

for Agency review, while the costs associated with agricultural use alternatives are expected to be very

low in view of the very limited and competitive market for such materials. (The small amounts of ash

going to agricultural use can be accommodated easily by other disposal practices. Also, it should be kept

in mind that the utility industry alone generates more than $200 billion in annual sales; the agricultural

use market, to the extent that it exists at all as a viable market, pales in comparison.)

At the time of publication of this Report to Congress, both risk assessment and potential risk

mitigation issues relating to minefill disposal remain unresolved. With respect to surface mines, EPA is

considering, subject to stakeholder comment, requiring risk mitigating actions as discussed in Section 3.4

of this report. In many cases, these are already practiced. With respect to underground mines, EPA is

also considering requiring certain risk mitigating actions, as denoted in Section 3.4. Cost and economic

impact analysis will be conducted as these issues are clarified.

No cost or economic analysis was conducted for mitigating the potential ecological risk. This is

not to suggest that EPA believes the analysis to be without merit; such risks have also been reported in

prior studies. Stakeholder comment is invited on this issue.

1.5 DECISION-MAKING PROCESS

In the Agency's part 1 fossil fuel combustion regulatory determination (58 FR 42466, 8/9/93), the

Agency applied a three-step decision-making process. Under this procedure, the Agency first considers

the potential impacts of the wastes in question on human health and the environment. If EPA finds there
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may be significant impact, the Agency next considers whether there is a need for regulation under RCRA

Subtitle C in light of existing waste management practices and existing regulatory controls imposed by

states under authorities other than Subtitle C. The Agency also considers whether Subtitle C would

effectively address problems associated with the waste without imposing significant unnecessary

controls. Finally, if the Agency concludes that additional regulation under Subtitle C is warranted, EPA

considers the potential economic impacts and affects on operations and beneficial uses of the wastes

from such regulation on the industry.

In this report, EPA has continued to consider the factors previously utilized in the three-step

decision-making process, since the Agency believes that these factors appropriately reflect the statutory

criteria in Section 8002 of RCRA that EPA must consider in issuing this report. The Agency has

modified somewhat, however, how those factors are considered in formulating its recommendations. 

Rather than apply the statutory criteria in rigid, stepwise fashion, EPA has considered the totality of the

relevant factors (i.e., the potential environmental and human health impacts, the need, if any, for

additional regulation and, finally, the potential impacts of imposing regulation under subtitle C in

developing the report’s recommendations). The step-wise approach to making regulatory determinations

assumes that it is possible to reach readily discernable, yes-or-no decisions regarding each step in the

decision-making process. As we gain experience in evaluating Bevill wastes, however, we have learned

that such clear-cut answers may not be possible for each individual decision-making criterion, and that it

may be necessary to balance all the relevant factors to reach the appropriate recommendation. For

example, where a particular waste poses some potential risk, but existing controls are wholly inadequate

and regulation under subtitle C would not cause severe economic dislocation, a determination to regulate

the waste may be appropriate. Conversely, where a waste poses more substantial risks but existing

controls are generally adequate and the costs of subtitle C controls would be substantial, continuing the

exemption might be the appropriate outcome. In both cases, each individual decision criterion may not

yield a definitive regulatory determination. Instead, considering the totality of the relevant factors would

be most likely to yield a rational conclusion consistent with our statutory mandate. Thus, EPA will take

this approach in this report and the regulatory determination to follow, which the Agency believes is

consistent with the broad decision-making discretion that Congress intended EPA to exercise in making

regulatory determinations for Bevill wastes.
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2.0 OVERVIEW OF INDUSTRIES USING FOSSIL FUEL COMBUSTION

This chapter provides an overview of the fossil fuel combustion (FFC) in the United States,

compares in general terms the industry sectors covered by this report, and discusses future trends for the

industry. This chapter also addresses discusses generic issues, such as environmental justice, that are not

specific to the waste type categories that are the subject of the remaining chapters of this report.

2.1 DESCRIPTION AND COMPARISON OF INDUSTRY SECTORS

In 1997, the United States produced more than 72 quadrillion British thermal units (Btu) of

energy. More than 80 percent of this total was produced from fossil fuels, primarily coal, natural gas,

and oil. The United States also consumed more than 25 quadrillion Btu of imported energy, nearly all of

it in the form of oil or natural gas. After accounting for exports, total U.S. energy consumption in 1997

was 94.2 quadrillion Btu, with the majority of consumption in fossil fuels (EIA, 1997e). A substantial

portion of these fossil fuels were combusted by entities in two major categories: utilities and nonutilities.

Utilities combust fossil fuels to produce electricity, which is then sold to end users. For purposes

of this report, the utility sector comprises both traditional electric utilities and independent power

producers that are not engaged in any other industrial activity. Utilities include private investor-owned

operations and public nonprofit organizations. Using a variety of fuels and technologies, the utility

sector accounts for the majority of electricity generated in the United States. This electricity is produced

not only by FFC, but also by nuclear power plants, hydroelectric facilities, and alternative sources (e.g.,

solar and geothermal). FFC, however, is the most significant of these sources, accounting for nearly 67

percent of the electricity produced in 1997. Coal is the most significant of the fossil fuels, accounting for

more than 50 percent of electricity produced (EIA, 1998a).

Electricity production is not the primary industrial activity of non-utility FFCs. The non-utility

sector encompasses a wide variety of industrial, commercial, and institutional facilities with varying

environmental and economic characteristics. Industrial facilities combust fossil fuels to generate power,

heat, or steam for use in manufacturing processes. Many of these industrial non-utilities are found in the

chemical manufacturing, pulp and paper, food products, and metals industries (EPA, 1990). Commercial

facilities include retail, assembly, warehouse, and office establishments that combust fossil fuels for uses

including heating, cooling, ventilating, lighting, cooking, refrigeration, and powering office equipment. 

Institutional facilities include educational, health care, government, and other public buildings that

combust fossil fuels for uses similar to those at commercial facilities. Combustion of fossil fuels

accounts for more than 70 percent of the energy delivered to non-utilities. Electricity purchased from

utilities accounts for most of the rest (EIA, 1998a).

For purposes of this report, the utility and non-utility FFC industry is divided into the following

sectors:

• Coal-fired utilities (including utilities that coburn coal and other fuels)

• Coal-fired non-utilities

• Fluidized bed combustion facilities, both utility and non-utility

• Oil-fired facilities, both utility and non-utility

• Natural gas-fired facilities, both utility and non-utility.
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Figure 2-1. Relative Size of Fossil Fuel Combustion Industry Sectors*

Figure 2-1 compares the relative size of each of these sectors, both in terms of equivalent

electricity generating capacity and FFC waste generation. Coal-fired utilities dominate the industry in

terms of electrical generating capacity and quantity of waste generated. For purposes of this study, largevolume wastes from coal-fired utilities are relevant only when they are comanaged with low-volume

combustion wastes. As discussed in Chapter 3, however, the majority of utility coal combustion wastes

are comanaged. Therefore, the share of waste generation shown in Figure 2-1 for coal-fired utilities

generally represents comanaged coal combustion waste.

While coal accounts for a relatively smaller share of non-utility electricity generating capacity,

coal-fired non-utilities still generate a significant quantity of waste. Fluidized bed combustion facilities

account for only a fraction of electrical generating capacity, but generate a relatively large quantity of

waste. Oil-fired facilities, in spite of their share of generating capacity, generate relatively small amounts

of waste. Natural gas combustion generates virtually no solid waste.

For additional perspective, Figure 2-2 compares FFC waste generation to the generation of other

types of waste in the United States. This figure shows the relatively large quantity of waste generated by

FFC and emphasizes the significance of coal combustion as a contributor to the quantities generated.

2.2 TRENDS

The U.S. Department of Energy’s Energy Information Administration (EIA) projects that total

U.S. energy consumption will increase from 94 to 119.9 quadrillion Btu between 1997 and 2020, an

average annual increase of 1.1 percent. This growth in consumption is expected to include increasing

demand for electricity from utilities as well as increasing consumption of fossil fuels at non-utilities

(EIA, 1998a).
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Figure 2-2. FFC Waste Generation Compared to Other Wastes

Sources: EPA, 1993a; EPA, 1998a; EPA, 19987b; EPA, 1997a

While this represents a decrease in the rate of growth of demand for electricity, new utility

generation capacity still will be needed to meet the additional demand and to replace retiring units

(including units representing half of current nuclear capacity). The EIA projects that 363 gigawatts of

new generation capacity, representing more than 1,000 new plants, will be needed by 2020 (EIA, 1998a).

This new capacity will drive a gradual change in the fuels used by the utility sector. Changes in

power plant technology and economics, along with recent changes in environmental regulations, will

limit the construction of new coal-fired utility plants (EIA, 1998a). In estimating the impact of recently

proposed new air emissions regulations, EPA predicted that coal-fired capacity would not increase

through 2010 (EPA, 1997b). The EIA similarly predicts only limited additions to coal-fired capacity

through 2010. Instead, utilities will invest in combined-cycle or combustion turbine technology fueled

by natural gas or both oil and gas. Between 2010 and 2020, however, the EIA projects increasing

demand for new coal-fired plants due to increasing natural gas costs and nuclear retirements. As a result

of increasing oil prices, oil-fired steam plants are expected to be replaced by turbine technologies through

2020 (EIA, 1998a). Figure 2-3 shows the EIA’s projections for utility capacity reflecting these changes.

Although limited new coal-fired capacity is expected through 2020, coal consumption by utilities

is expected to increase due to increased utilization of existing generating capacity. This increase in coal

consumption is not expected to match the rate of increase in previous decades, however. Natural gas

consumption is expected to increase dramatically, consistent with the addition of new gas-fired capacity. 

Oil consumption by utilities is expected to fall significantly as a result of expected increases in oil prices

(EIA, 1998a).

For non-utilities, the EIA projects modest growth in energy use. In the industrial sector,

increasing energy demand associated with increasing industrial output will be moderated by more energy
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Figure 2-3. Projected Utility Generating Capacity

 Source: EIA, 1998a

efficient technologies and relatively low growth in energy-intensive industries. In this sector, modest

growth in coal use for boiler fuel is expected, with more significant growth in oil and natural gas

consumption. Slow growth is expected in the commercial sector due to increased efficiency standards

and declining growth in commercial floor space compared to previous decades. The relative share of

individual fossil fuels is not expected to change dramatically for commercial uses (EIA, 1998a).

Based on the trends discussed above, Figure 2-4 adapts EIA data to the sectors discussed in this

report. Figure 2-4 shows expected trends in FFC for each sector. Note that for oil, Figure 2-4 shows

residual oil use only, since this is expected to account for nearly all oil combustion waste generation. 

Forecasts for 1997 through 2020 show the following:

• A moderate increase in the consumption of coal by utilities (26 percent)

• A less significant increase in the consumption of coal by non-utilities (16 percent)

• A decline in the consumption of residual oil by utilities and non-utilities (13 percent)

• A large increase in the consumption of natural gas by utilities and non-utilities combined

(55 percent).

Separate forecasts are not available for the fluidized bed combustion sector. Most of the use of

this technology is reflected in the consumption of coal by utilities and non-utilities. Because of the fuel

flexibility, efficiency, and emissions characteristics of fluidized bed combustion units, EPA projects that

use of the technology has the potential to increase at a rate greater than that of conventional coal

combustion. The potential impacts of these changes in fuel consumption on waste generation are

discussed in appropriate chapters of this study.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 2-5

Figure 2-4. Projected Fuel Consumption by Fossil Fuel Combustion Industry Sectors

 Source: EIA, 1998a, Appendix A

2.3 ENVIRONMENTAL JUSTICE

In addition to the eight study factors specifically identified in Section 8002(n) of RCRA, EPA is

interested in determining whether there are environmental justice issues associated with the management

of the remaining wastes from FFC. The Agency’s risk modeling results indicate that subsistence farmers

and their children may face potential health risks from the management of FFC wastes. The prospect that

subsistence farmers may be of low-income or minority status suggests that there might be environmental

justice issues associated with FFC waste management. Subsistence farmers, however, are hypothetical,

highly exposed receptors modeled as part of the above-ground multimedia risk assessment. The

prevalence of subsistence farming around existing FFC sites is not known. The Agency is interested in

receiving additional information regarding the extent to which subsistence farming actually occurs near

these facilities. EPA also is interested in learning of concerns related to environmental justice (i.e., the

fair treatment of people of all cultures, incomes, and educational levels with respect to environmental

hazards) associated with the management of FFC wastes.
Report to Congress on Wastes from the Combustion of Fossil Fuels

2-6 March 1999
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-1

3.0 COMANAGED WASTES AT COAL-FIRED UTILITIES

In its 1993 Regulatory Determination (58 FR 42466, 8/9/93), EPA retained the exclusion from

hazardous waste regulation under Subtitle C of the Resource Conservation and Recovery Act (RCRA) for

four large-volume coal combustion wastes from utilities and independent power producers when

managed alone. These wastes are fly ash, bottom ash, boiler slag, and flue gas desulfurization (FGD)

wastes. These four large-volume utility coal combustion wastes (UCCWs) are relevant for purposes of

this study when they are comanaged with low-volume combustion wastes. Comanagement occurs when a

waste management unit receives both large-volume UCCWs and other wastes that are generated ancillary

to, but as a necessary part of, the combustion and power generation processes. These other wastes are

termed “low-volume” wastes to distinguish them from the four high-volume UCCWs. Chapter 3 focuses

on these low-volume combustion wastes and the practice of comanaging these wastes with large-volume

UCCWs. This chapter also considers wastes from the combustion of mixtures of coal and other fuels

(“coburning”) by utilities.

SECTOR OVERVIEW

EPA described the coal-fired utility sector in great detail in the 1988 Report to Congress. Coal

remains the primary fossil fuel used by electric utilities in the United States. In 1997, coal accounted for

more than half of the electricity generated in the United States (EIA, 1997e). The Edison Electric

Institute Power Statistics Database (EEI, 1994) identifies 440 coal-fired utility power plants in the United

States operating more than 1,200 individual boilers. As discussed in Chapter 2, EPA expects little

increase in coal-fired generating capacity through the year 2010. Some growth in coal consumption by

utilities is expected due to increased utilization of existing generating capacity (EIA, 1998).

As shown in Figure 3-1, the electrical generating capacity of coal-fired utilities is concentrated in

the Northeast and Midwest. While the largest numbers of facilities are located in these regions, coalfired utility power plants are found in nearly every state. Within states, facility sites vary from urban to

rural. Because of the large volume of waste generated, onsite waste management is typical. As

discussed in detail in Section 3.3, comanagement is practiced at the majority of coal-fired utilities. 

Therefore, the geographic distribution of power plants presented in Figure 3-1 also is generally

descriptive of the universe of comanaged waste sites that are the subject of this study.

3.1 WASTE GENERATION

Coal-fired utilities may generate as many as four large-volume UCCWs and a variety of lowvolume wastes. The generation of large-volume UCCWs depends upon boiler technology (see Section

3.1.1), air pollution control technology (see Section 3.1.2), and fuel type (see Section 3.1.3). Largevolume UCCWs include:

• Fly ash. The uncombusted material carried out of the boiler along with the flue gases.

• Bottom ash. Uncombusted material that settles to the bottom of the boiler. Bottom ash

does not melt and, therefore, remains in the form of unconsolidated ash.

• Boiler slag. Uncombusted material that settles to the bottom of the boiler. Slag, unlike

bottom ash, forms when operating temperatures exceed ash fusion temperature and remains

in a molten state until it is drained from the boiler bottom.

• Flue gas desulfurization waste. Waste produced during the process of removing sulfur

oxide gases from the flue gases.
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3-2 March 1999

Figure 3-1. Number of Coal-Fired Utility Power Plants by State

Low-volume wastes are generated as a result of supporting processes (see Section 3.1.4) that are

ancillary to, but a necessary part of, the combustion and power generation processes. Low-volume

wastes include the following:

• Coal pile runoff. Runoff and drainage produced by precipitation falling on coal storage

areas.

• Coal mill rejects/pyrites. Waste produced by onsite processing of coal prior to use.

• Boiler blowdown. Waste continuously or intermittently removed from boilers that

recirculate water to maintain water quality.

• Cooling tower blowdown and sludge. Wastes removed periodically from recirculating

cooling tower systems to maintain water quality.

• Water treatment sludge. Wastes resulting from treatment of makeup water for the steam

cycle or for non-contact cooling. Treatment processes resulting in sludge generation may

include settling, flocculation, softening, filtration, and reverse osmosis.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-3

• Regeneration waste streams. Wastes resulting from periodic cleaning and regeneration of

ion exchange beds used to remove mineral salts from boiler makeup water.

• Air heater and precipitator washwater. Wastes resulting from the periodic cleaning of

the outside (fireside) of heat exchanging surfaces (i.e., the side exposed to hot combustion

products).

• Boiler chemical cleaning waste. Wastes resulting from periodic cleaning of the inside

(waterside) of boiler tubes with chemical solutions.

• Floor and yard drains and sumps. Wastewaters collected by drains and sumps, including

precipitation runoff, piping and equipment leakage, and wash water.

• Laboratory wastes. Wastes generated in small quantities during routine analysis of coal,

intake water, wastes, and other samples at a plant site.

• Wastewater treatment sludge. Sludge generated from the treatment in settling basins or

other treatment facilities of any or all of the liquid waste streams described above.

Table 3-1 reports the quantity of each large-volume UCCW generated in 1997. The total

quantity generated has increased steadily over the last decade (ACAA, 1996b; ACAA, 1998). Projected

future increases in the consumption of coal by utilities (see Chapter 2) also are expected to result in

increases in ash generation, albeit at a slower rate than in past decades.

The relative contribution of each waste type has changed over time. For example, since 1994,

the quantity of boiler slag has decreased, while the quantity of FGD waste has increased dramatically

(ACAA, 1996b; ACAA, 1998). These changes in relative share are likely due to changes in use of

combustion technology, fuel, and pollution control technology. Each of these factors is discussed in

greater detail below. The increase in FGD waste generation has been driven, in part, by the requirements

of Title IV of the Clean Air Act (see Section 3.5). Recent and forthcoming regulatory developments

(see Section 3.5) are expected to result in continued increases in the generation of FGD waste.

Table 3-2 lists typical facility-level generation rates for those low-volume wastes for which data

are available. No comprehensive data exist on the total quantities of low-volume wastes generated in the

United States. For purposes of this study, however, the total quantities generated are less significant than

the quantities that are comanaged with large-volume UCCWs. Section 3.3 presents the available data on

the quantities of waste comanaged and the frequency with which comanagement occurs.

UCCW Type Tons Generated in 1997 Percent

Fly Ash 60,264,791 57%

Bottom Ash 16,904,663 16%

Boiler Slag 2,741,614 3%

FGD Waste 25,163,394 24%

Total 105,074,462 100%

Source: ACAA, 1998

Table 3-1. Total Generation of Large-Volume Utility Coal Combustion Waste (UCCW)
Report to Congress on Wastes from the Combustion of Fossil Fuels

3-4 March 1999

3.1.1 Boiler Technology

The quantities of ash and slag generated depend in part on the combustion technology used. 

Currently, three conventional technologies for coal combustion are in use: pulverized coal (PC) boilers,

stokers, and cyclones. All three conventional technologies involve combustion of coal in a boiler to heat

water and produce steam. The steam is then used to generate electricity; in some cases, a portion of the

steam may be used to provide heat. The three conventional technologies differ in design, particularly in

the type and the size of the coal particle to be burned, fuel delivery mechanisms, and the combustion

conditions inside the boiler furnace. The 1988 Report to Congress described each of these technologies

in detail. Box 3-1 provides an overview description of these technologies and their waste generation

implications.

Figure 3-2 shows how combustion technology affects the distribution of ash and slag.

Table 3-3 shows how the capacity of utility conventional coal combustion is distributed among

boiler technologies. Because of their efficiency, PC boilers are the most common technology used by

utilities. PC technology is well suited to large capacity applications where high efficiency is desired. 

The dominance of PC technology contributes to the large percentage of fly ash generated by utilities.

EPA is aware that there are other emerging technologies for combustion coal and other fossil

fuels (for example, pressurized fluidized bed combustion, discussed briefly in Chapter 5) that may have

different effects on waste generation and characteristics. Because of data availability issues, however,

this chapter focuses on technologies in current commercial application.

Low-Volume Waste Typical Generation Rate

Coal Pile Runoff Variable depending on rainfall

Coal Mill Rejects 7.5 to 12 tons per year per megawatt capacity (plants burning highsulfur eastern coal)

Boiler Blowdown 0.1 to 1 percent of steam flow; 148 to 290 gallons per day per

megawatt (recirculating steam systems only)

Cooling Tower Blowdown and Sludge 20 to 65 percent of cooling water flow; 1 to 30 gallons per day per

megawatt (recirculating cooling systems only)

Water Treatment Sludge Variable depending on treatment technology and water intake rates

Regeneration Waste Streams 40 to 104 gallons per day per megawatt

Air Heater and Precipitator Washwater (includes other

fireside washwaters)

3 to 18 gallons per day per megawatt capacity

Boiler Chemical Cleaning Waste 125 gallons per megawatt, once every 2 to 5 years

Floor and Yard Drains and Sumps, Laboratory Wastes 30 to 100 gallons per day per megawatt

Wastewater Treatment Sludge Variable depending on treatment technology and discharge rates

Sources: EPA, 1992, 1996; EPRI, 1997b; VDEQ, 1994

Table 3-2. Low-Volume Waste Generation Rates at Coal-Fired Utilities
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-5

PC Boilers 

Dry-Bottom 80% Fly Ash 20% Bottom Ash

Wet-Bottom 50% Fly Ash 50% Slag

Stokers 

Spreader 35–60% Fly Ash 40–50% Bottom Ash & Slag

Other 10% Fly Ash 90% Bottom Ash & Slag

Cyclones 30% Fly Ash 70% Slag

Sources: CIBO, 1996c; Stultz and Kitto, 1992; and Elliot, 1989

Figure 3-2. Approximate Ash Distribution by Coal Combustion Technology

Pulverized Coal (PC) Boilers. PC boilers, also known as pulverizers, burn finely ground coal suspended in air. 

Because of the large surface area created by pulverizing the coal and the air turbulence created in PC boilers, the

coal burns very efficiently and completely. The efficiency of combustion in a PC boiler affects the relative

quantity of waste generated. These boilers generally achieve more complete combustion of coal constituents than

do stokers. As a result, there is less unburned carbon in PC boiler ash and, in turn, a lower volume of waste

generated, all else being equal.

Because of the small fuel size and the suspended combustion process, most of the ash remaining after combustion

in a PC boiler is entrained in the furnace exit gas, becoming fly ash. The remainder of ash falls to the bottom of

the furnace as bottom ash. In most pulverizers, referred to as dry-bottom furnaces, bottom ash remains in a dry,

free-flowing ash form. Pulverizers burning coal with lower ash fusion temperatures, however, are designed as

wet-bottom or slag-tap furnaces. In these units, bottom ash flows out of the furnace in molten form and cools into

a slag. The proportion of bottom ash generated is greater in wet-bottom designs.

Stokers. Stoker technology feeds coal mechanically onto a grate within a furnace. Stoker feed and grate systems

include a variety of designs, with the three major categories being underfeed, overfeed (or mass fed), and spreader

stokers. The categories differ in the location and method of coal feeding and the design of the grate (moving,

vibrating, or stationary).

Spreader stokers, which are the most common type, generate 40 to 65 percent bottom ash. The bottom ash may be

a free-flowing ash or a fused clinker. Fly ash comprises the remaining 35 to 60 percent of spreader stoker waste. 

By comparison, overfeed and underfeed stokers do not incorporate suspension burning and have lower air

velocities than spreader stokers. Therefore, they generate a lower proportion of fly ash, about 10 percent. The

bottom ash from overfeed stokers can range from free-flowing ash to fused slag, while that from underfeed

stokers is typically clinker or slag.

Cyclones. Cyclones burn crushed coal in a horizontal cylindrical barrel attached to the side of the boiler furnace. 

The cyclone design was developed to burn low ash-fusion temperature coals (i.e., slagging coals) without the

need for pulverization and with slightly more flexibility in fuel feed characteristics than pulverizers. This

technology creates a cyclone-like air circulation pattern that causes smaller particles to burn in suspension, while

larger particles adhere to a molten layer of slag that forms on the barrel walls. Because they are designed

specifically to generate a layer of molten slag, most of the waste generated by cyclones is in this form. Molten

slag flows out of the cyclone barrel through a slag tap and through the furnace bottom where it typically is cooled

in a tank.

Sources: CIBO, 1997c; Stultz and Kitto, 1992; Elliott, 1989

Box 3-1. Conventional Coal Combustion Technologies
Report to Congress on Wastes from the Combustion of Fossil Fuels

3-6 March 1999

3.1.2 Air Pollution Control Technologies

Air pollution control (APC) technologies used to meet the needs of coal-combustion facilities

may be broadly categorized as particulate controls and flue gas controls. The technologies of most

relevance in the latter category are those for control of sulfur oxide emissions. The capture of fly ash is

governed by the particulate control technology used—fly ash leaving the boiler must be removed from

the gas stream in which it is entrained or it will be released to the atmosphere. When high sulfur coal is

burned, utilities sometimes apply desulfurization technologies to remove sulfur dioxide from the flue gas

to meet Clean Air Act requirements (see Section 3.5). The 1988 Report to Congress described both

particulate control and desulfurization technologies in detail. Box 3-2 provides an overview description

of these technologies.

Figure 3-3 shows the frequency with which coal-fired utilities utilize each type of APC

technology. Overall, nearly all coal-fired utilities incorporate some type of particulate control, primarily

because this is the most economical way to meet air quality regulations (see Section 3.5). ESPs are most

common because this is the primary APC technology used at PC boilers. Mechanical collectors are most

common for stokers, which generate the larger fly ash particles for which mechanical collection is

efficient. Stokers and some other units sometimes use combination systems in which a mechanical

collector is followed by an ESP or fabric filter. The types of APC technologies used have high removal

efficiencies, as discussed in Box 3-2. The prevalence of particulate control, combined with these high

removal efficiencies, results in a high percentage of fly ash capture at coal-fired utilities.

Desulfurization technology is not as common as particulate control but still is prevalent enough

that a significant quantity of FGD waste is generated. The percentages shown in Figure 3-3 are based on

1994 data. Since that time, several large facilities have added desulfurization units in response to Title

IV of the Clean Air Act (see Section 3.5), contributing to recent increases in FGD waste generation. 

Recent and forthcoming regulatory developments (see Section 3.5) are expected to result in increased use

of FGD technology and an associated increase in quantities of FGD waste. These developments also are

expected to increase the use of low sulfur coal, discussed in the next section.

3.1.3 Fuel Types

Coal burned by utilities in the United States is classified by rank: anthracite, bituminous,

subbituminous, and lignite. These ranks reflect the degree of metamorphism of the coal and typically

correspond to the geologic age of the coal deposit and to the heating value of the coal. Anthracite coal is

the oldest rank and has the highest heating value, while lignite is the youngest and has the lowest heating

value (Stultz and Kitto, 1992). Table 3-4 shows the usage of each rank by utilities in 1997, along with

typical ash content. The quantity of ash and slag generated is affected by the ash content of the fuel. 

Ash content is, in part, determined by the rank of the coal.

Combustion Technology Number of Boilers

Capacity

(megawatts equivalent) Percent of Capacity

Pulverized Coal Boilers 1,068 294,035 92%

Stokers 94 1,077 <1%

Cyclones 89 25,727 8%

Total 1,251 320,839 100%

Source: EEI, 1994

Table 3-3. Distribution of Utility Conventional Coal Combustion Technologies
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March 1999 3-7

In addition to coal rank, ash content depends on the specific coal producing region, mine, seam,

and production method. To reduce maintenance and waste management costs and to meet particulate

emissions standards, utilities have, over time, increased their use of coal with a lower ash content. Over

the past two decades, the average ash content of coal used by U.S. utilities has decreased consistently,

from 13.5 percent in 1975 (DOE, 1993) to 9.22 percent in 1996 (EIA, 1996f). This reduction

corresponds to the increased use of coal from Wyoming, which has a relatively low ash content (EIA,

1996f). In addition, coal characteristics can be, and often are, changed prior to combustion through

cleaning. Approximately 70 percent of coal used by electric utilities is cleaned in some way. In some

cases, these cleaning processes can reduce ash content by as much as 50 to 70 percent (Stultz and Kitto,

1992). In part because of the trend toward lower ash content, the increase in ash generation over time has

not kept pace with the general increase in coal use.

The type of coal burned also affects the distribution of the ash and slag waste streams generated

by combustion. For example, because softer lignite coals tend to have a lower ash fusion temperature,

they tend to generate boiler slag rather than bottom ash.

Particulate Control Technologies

Electrostatic Precipitators (ESPs). ESPs are the most common particulate control technology used by coal-fired

utilities. An ESP generates a high intensity electrical field that causes ash particles to acquire an electrical

charge and migrate to an oppositely charged collecting surface. For typical coal-fired utilities, this process

results in a collection efficiency of greater than 99 percent.

Fabric Filters. Fabric filters, also known as baghouses, capture ash as the exit gas passes through a series of

porous filter bags. Baghouses have an efficiency of greater than 99 percent.

Mechanical Collectors. Mechanical collectors, most commonly known as cyclones or multicyclones, force a

cyclonic flow of the exit gas. This flow causes ash particle to be thrown against the walls of the collector and

drop out of the gas. Cyclones are most effective for larger particles; collection efficiency drops well below 90

percent for the smallest particles.

Scrubbers. Wet scrubbers are the least common particulate control technology. In scrubbers, water is used to

trap particulates entrained in the flue gas. Scrubbers can collect large particles at efficiencies greater than 99

percent, but efficiency may be less than 50 percent for particles smaller than 1 or 2 micrometers. Scrubbers also

demand high energy consumption for high efficiency and produce a wet effluent to be disposed.

Desulfurization Technologies

Desulfurization technologies are categorized as recovery systems and non-recovery systems. Recovery systems

are those that produce FGD wastes that are suitable for reuse, for example, in wallboard (see Section 3.6.2 for

discussion of use in wallboard). Non-recovery systems produce FGD waste that must be disposed. Nonrecovery systems are further classified as wet and dry systems. Wet systems scrub and saturate flue gas with a

slurry of water and a sorbent (usually lime or limestone) that reacts to remove sulfur from the gas in the form of

a sludge. Dry systems typically contact flue gas with a sorbent slurry in a spray dryer without saturating the gas

with water. The dry reaction product is then collected along with fly ash in a fabric filter or ESP. Wet systems

are more effective at removing sulfur dioxide and, therefore, are used by a larger proportion of generators. 

However, because of their use of liquids, wet systems produce more waste than do dry systems.

Sources: Stultz and Kitto, 1992; EPA, 1998c; Elliott, 1989; DOE, 1993

Box 3-2. Air Pollution Control Technologies
Report to Congress on Wastes from the Combustion of Fossil Fuels

3-8 March 1999

Figure 3-3. Air Pollution Control Technologies Used at Coal-Fired Utilities

* Mechanical collector followed by fabric filter or ESP.

Source: EEI, 1994

Because FGD waste is generated in removing sulfur oxide gases from the flue gas stream, the

amount of FGD waste generated depends on the sulfur content rather than the ash content of the fuel. 

Furthermore, when utilities burn low sulfur coal, they often can meet regulatory requirements without the

application of desulfurization technology and, therefore, without generating FGD waste.

The sulfur content of coal varies geographically across the United States. Some Iowa coals

contain as much as 8 percent sulfur by weight, while western coal deposits (e.g., Montana and Wyoming)

average less than 1 percent sulfur (Stultz and Kitto, 1992). The sulfur content of coal also can be

reduced through cleaning to remove pyrites (iron sulfide minerals that are oxidized to produce sulfur

oxide gases during the combustion process). The average sulfur content of coal burned by electric

utilities in 1996 was just over 1 percent by weight but ranged from more than 3 percent in states relying

on Midwestern coal to less than 0.5 percent in some western states (EIA, 1996f). A number of utilities

recently have switched to low-sulfur coal in response to regulatory requirements (EIA, 1997f). Recent

and forthcoming regulatory developments (see Section 3.5) are expected to result in increased use of lowsulfur coal in the future.

Coal Class Ash Content Utility Usage in 1997 (1,000 tons) Percent of Total Usage

Anthracite 4 to 19% 1,013 < 1%

Bituminous 3 to 32%

821,823 91%

Subbituminous 3 to 16%

Lignite 4 to 19% 77,524 9%

Total 900,360 100%

Sources: Ash content CIBO, 1997c; fuel usage EIA, 1998b

Table 3-4. Ash Content and Fuel Usage by Coal-Fired Utilities
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-9

In addition to coal, coal-fired utilities sometimes combust other fuels in combination with coal. 

This practice of mixing fuels is known as “coburning.” Wastes from mixtures of coal and other fuels

containing up to 50 percent other fuels are considered remaining wastes subject to this study. The types

of materials that have been coburned in such mixtures include (EPRI, 1997m; IEA, 1996):

• Agricultural refuse

• Auto shredder fluff

• Bark and other wood

• Biomass

• Boiler cleaning wastes

• Contaminated soils and other wastes from manufactured gas plant sites

• Mill rejects

• Oil combustion wastes

• Paper mill sludges

• Peat

• Petroleum coke and petroleum coke/limestone blends

• Railroad ties

• Refuse derived fuel

• Regeneration waste streams

• Sewage sludge

• Straw

• Tire derived fuel

• Used oil.

In addition, EPA is aware that ongoing technological advancement has developed the potential

for combusting other coal-fuel mixtures and other non-coal fossil fuels (for example, Orimulsion fuel,

discussed briefly in Chapter 6). Because of data availability issues, however, this chapter focuses on

fuels burned in current commercial application.

3.1.4 Supporting Processes

The generation of low-volume wastes primarily is associated with processes that support the

combustion process or make use of the products of combustion. These supporting and enabling

processes accompany combustion at all coal-fired utilities. The following common supporting processes

can be significant with respect to low-volume waste generation:

• Coal storage

• Coal processing

• Steam generation

• Cooling

• Water treatment

• Cleaning and maintenance

• Wastewater treatment.

The paragraphs below describe these processes and their waste generation aspects. The large

number and wide variety of low-volume wastes generated at coal-fired utilities correspond to the variety

of these processes.
Report to Congress on Wastes from the Combustion of Fossil Fuels

3-10 March 1999

Coal Storage

The low-volume waste, coal pile runoff, is associated with coal storage. The coal utilized at

utilities is usually stockpiled onsite to ensure an adequate supply. The amount of fuel stored is generally

proportional to the capacity of the combustion process. Particularly for large capacity utilities, the

amount required may be quite large. In fact, regulations for some public utilities require that a minimum

60- to 90-day supply be stored at the plant (Stultz and Kitto, 1992). A 90-day reserve of coal amounts to

600 to 1,800 cubic meters of storage capacity per megawatt plant capacity (EPA, 1996).

Typically, storage of such large volumes of coal is in open stockpiles, as this has proven to be the

most economically efficient storage method. These piles usually are uncovered and exposed to

precipitation, resulting in the potential intermittent generation of runoff. Coal pile runoff typically must

be collected to prevent contamination of the local environment. The characteristics of the runoff depend

upon the type and age of the coal, the pile shape, and the precipitation characteristics. Waste generation

rates vary depending on the footprint of the pile (i.e., the basal area) and the local precipitation.

Coal Processing

Coal usually is delivered to utilities in large pieces and must, at a minimum, be reduced in size

prior to combustion. The extent and nature of additional processing will depend on the desire of the user

to reduce ash and sulfur content and upon the size and feed characteristics requirements of the

combustion technology. Coal processing results in the removal of various materials, commonly termed

coal mill rejects, that may include rocks, metal fragments, hard coal, and other minerals, such as pyrites. 

The quantity of these low-volume wastes will be highly variable depending on the coal source and

processing technology (EPRI, 1997b). An important component of the rejects wastestream is pyrite, a

hard iron sulfide (FeS2). As will be discussed in subsequent sections, these pyrites are associated with

acid generation concerns within waste management areas, often requiring isolation from water and

oxygen in order to minimize those concerns.

Steam Generation

The steam generation process can entail the generation of the low-volume waste called boiler

blowdown. All of the fossil fuel combustion technologies described in this report are used to heat water

and generate steam, which in turn is used to generate electricity. In the steam generation process,

products of combustion often travel from the boiler into a series of other components, such as

superheaters, economizers, and/or air heaters. There are a variety of boiler and system designs; all serve

the purpose of absorbing heat from combustion and converting water into steam (Stultz and Kitto, 1992).

After the high-temperature, high-pressure steam generated in the boiler components is used to

generate electricity or for other industrial use, a large volume of low-pressure “dead” steam remains. 

This steam typically is condensed into water to be recirculated back through the boiler in a closed loop

(EPA, 1996). Dissolved solids and suspended salts in the boiler water increase with continued

circulation through the steam cycle. To prevent excessive buildup of these constituents, some water is

removed, either periodically or continuously, and replaced with purified feed water (EPRI, 1997b). This

bleed waste stream, commonly referred to as boiler blowdown, may contain contaminants built up during

the steam cycle, precipitated solids, corrosion products, and chemical additives. The volume of boiler

blowdown can range from 0.1 to 10 percent of the total steam flow, depending on boiler design.
Report to Congress on Wastes from the Combustion of Fossil Fuels

1

 Large-volume UCCWs transported/mixed with certain non-contact cooling waters fell within the scope of

EPA’s 1993 Regulatory Determination (58 FR 42466). Because of the continuous use of these process waters, the

Agency does not consider them wastes and they are outside the scope of this study. However, discussion of the

generation and characteristics of these waters is relevant because effluent and sludge from treatment of these and

other plant wastewaters do fall within the definition of low-volume waste.

March 1999 3-11

A few plants (less than 10 percent of the coal-fired utility population, according to the 1994

Edison Electric Institute [EEI] database) do not recirculate boiler water, instead using a once-through,

non-recirculating steam system. These systems do not generate boiler blowdown (EPA, 1996).

Cooling

Cooling processes can result in the generation of low-volume wastes, such as cooling tower

blowdown and sludge.1

 In plants with a recirculating steam system, condensation of “dead” steam occurs

by transferring heat to cooling water. This cooling water does not directly contact the steam but takes on

the waste heat by flowing through a heat exchanger called a condenser. This process requires a constant

flow of large volumes of chilled cooling water, which itself may be supplied in either a once-through or

recirculating system. More than 70 percent of coal-fired utilities reporting cooling system information in

the 1994 EEI database use recirculating cooling systems. To control bacterial growth, utilities sometimes

add biocides, such as chlorine compounds, to their cooling water systems. The use of chlorine

compounds can cause toxic chlorinated organic byproducts to form in discharges from cooling water

systems. Because of concerns about these compounds, there has been an increasing trend in the use of

alternative biocides (e.g., bromine and nonoxidizing biocides, such as quaternary ammonium compounds

and bromonitrostyrene) that do not form highly toxic byproducts (EPA, 1996).

In recirculating cooling water systems, heat picked up in the condenser must be transferred to the

atmosphere by means of cooling towers, cooling ponds, or spray canals before the water is returned to the

system. Cooling towers and spray canals or ponds promote evaporative cooling. As a result, some water

must be removed and replaced with fresh water to prevent impurities from becoming concentrated in the

recirculating cooling system. The quantity removed can range from 20 to 65 percent of the cooling water

flow rate (EPA, 1996). The water removed is referred to as cooling tower blowdown. Also, over time,

solids can collect in the bottom of cooling towers. This cooling tower sludge is periodically removed and

disposed (EPRI, 1997b).

Water Treatment

Treatment of water prior to use in a fossil fuel combustion system may generate low-volume

wastes, including treatment sludges and regeneration wastes. Losses of water from within the steam

cycle typically require that operators use makeup water in the system. In addition, closed-loop, noncontact cooling systems may require makeup water. The makeup water usually must be treated to

remove dissolved gases, suspended solids, and dissolved chemical salts that would negatively impact the

efficiency of the operation. Required treatment processes may include clarification, filtration, reverse

osmosis, and/or lime softening. These operations will usually generate water treatment wastes, such as

sludges. The characteristics of this treatment sludge will depend upon the source water characteristics

and the treatment process used.

Another type of makeup water treatment is the use of an ion exchange process to remove mineral

salts. The ion exchange beds are a resin that requires periodic rinsing with an acidic or basic solution to

regenerate the resin (i.e., remobilize and backflush the contaminants removed by the resin). These waste
Report to Congress on Wastes from the Combustion of Fossil Fuels

3-12 March 1999

streams are commonly referred to as regenerant solutions (EPA, 1996). Furthermore, when regeneration

of the resin is no longer possible, the spent resin is disposed and may be comanaged (EPRI, 1997b).

Cleaning and Maintenance

Cleaning processes intermittently generate low-volume wastes, including air heater and

precipitator washwater and boiler chemical cleaning waste. The heat exchanging surfaces of steam

generating systems require periodic cleaning to remove deposits and maintain efficiency. The fireside

surfaces (i.e., the side exposed to hot combustion products) of components, including boilers,

superheaters, economizers, and precipitators, collect ash, dust, and corrosion products. These surfaces

are cleaned using steam, water, or an alkaline solution. Hardened deposits may require mechanical

removal (EPRI, 1997b). The fireside surfaces of air heaters (which use flue gases to preheat combustion

input air) also collect ash and dust. These surfaces are cleaned with water or an alkaline solution, often

more frequently than other fireside surfaces (EPA, 1996). The resulting washwaters are low-volume

wastes.

The waterside surfaces of boiler tubes collect scale in the form of precipitated salts and corrosion

products. Chemical solutions must be used infrequently to remove this scale and prevent restriction of

water flow. Depending on the boiler contaminants present, cleaning solutions may include alkalis, acids,

and chelants. There is some evidence of a trend by utilities toward using less toxic cleaning solutions. 

For example, one utility reported switching from hydrochloric acid to citric acid in 1995 (EPRI, 1992). 

The waste resulting from chemical cleaning is commonly termed boiler chemical cleaning waste. Both

boiler chemical cleaning wastes and fireside cleaning wastes are sometimes termed metal cleaning wastes

(EPRI, 1997b).

Wastewater Treatment

At fossil fuel combustion facilities, a variety of liquid streams (including low-volume wastes, ash

handling waters, and site runoff) may require treatment prior to discharge. Required treatment processes

will vary depending on the combination of streams treated and on discharge requirements. These

operations will usually generate treatment wastes, such as sludges. The characteristics of this treatment

sludge will depend upon the source water characteristics and the treatment process used.

3.2 WASTE CHARACTERISTICS

By definition, comanaged wastes consist of one or more low-volume wastes in combination with

one or more large-volume UCCWs. Therefore, this section briefly describes the characteristics of lowvolume wastes and UCCWs as generated prior to discussing the characteristics of comanaged wastes. 

The section concludes with a discussion of the available data on wastes from coburning by utilities.

3.2.1 Large-Volume and Low-Volume Utility Coal Combustion Wastes as Generated

As part of its 1988 Report to Congress (EPA, 1988) and 1993 Regulatory Determination (58 FR

42466), EPA presented substantial data characterizing large-volume UCCWs and certain low-volume

wastes. Detailed characterization is not included here. Instead, this section presents an overview of

earlier characterization efforts, along with analyses based on more recent data for selected wastes.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-13

Physical and Chemical Characteristics

Each of the large-volume wastes can exist as a dry solid or wet slurry, depending on collection

and management technology. Other physical characteristics vary from waste type to waste type. Fly ash

is typically generated and collected as a solid but may be transported by sluicing. This type of waste

consists primarily of particles between 5 and 100 microns (EPA, 1988). Fly ash typically has a round

shape resulting from the high temperatures used in a pulverized coal boiler (CIBO, 1997c). Bottom ash

and slag can be generated from a wet-bottom or dry-bottom pulverized-coal boiler. The bottom ash

collected from a dry-bottom system can be transported in a dry state or sluiced. Bottom ash and boiler

slag consist of larger particles than fly ash, ranging from 0.1 millimeter (100 microns) to 10 millimeters

in diameter (EPA, 1988). Bottom ash has a coarse angular structure, while boiler slag consists of angular

particles with a glassy appearance (CIBO, 1997c). FGD waste can be generated from a dry sorbent

system or a wet scrubber system. Wet systems generate waste with slightly smaller particle size (0.001 to

0.05 millimeters) than dry systems (0.002 to 0.074 millimeters). Wet systems also generate a filter cake

or similar wet solid (16 to 43 percent moisture), while waste from dry systems contains no liquids

(USDA, 1998).

Oxides of silicon, iron, aluminum, and calcium compose 95 percent of the weight of both bottom

and fly ash. These constituents also are present in significant quantities in boiler slag (EPA, 1988). 

Calcium sulfate is the principal constituent of limestone-based FGD waste. Large-volume wastes also

contain trace metals. Mean concentrations of arsenic, barium, beryllium, boron, copper, and vanadium

are highest in fly ash. Bottom ash has mean contaminant levels lower than fly ash for most constituents. 

Mean concentrations of antimony, lead, mercury, selenium, and zinc are highest in FGD waste.

Several studies have included testing of organic constituents in large-volume UCCWs, including

polynuclear aromatic hydrocarbons (PAHs) and dioxins. Although an exhaustive review of organics data

has not been conducted, based on available information, total and leachable organics are generally

reported to be at or below analytical detection limits (EPRI, 1987; EPA, 1982).

Because low-volume wastes are generated throughout the combustion process and its ancillary

activities, the characteristics of these wastes are extremely variable. EPA does not have comprehensive

data characterizing every type of low-volume waste that might be comanaged with large-volume coal

combustion wastes. Table 3-5 presents the principal physical and chemical characteristics of several

major types of low-volume waste.

EPA has identified coal mill rejects (and particularly their pyrite component) as a low-volume

waste of particular concern. If mismanaged, these materials have the potential to oxidize and generate

acids that could leach metals from surrounding materials to ground and surface waters. Table 3-6

presents recent characterization data for coal mill rejects.

Leaching and Hazardous Waste Characteristics

In the 1988 Report to Congress and 1993 Regulatory Determination, EPA evaluated whether

large-volume wastes exhibited any of the four characteristics of hazardous waste: corrosivity, reactivity,

ignitability, and toxicity. EPA determined that large-volume UCCWs are unlikely to be corrosive,

reactive, or ignitable. EPA also found that metals generally are not found in leachate above the toxicity

characteristic (TC) levels. Only three metals—cadmium, chromium, and arsenic—were detected in any

ash or sludge samples above the TC levels and then only infrequently. Other constituents of largevolume UCCW not on the EPA toxicity characteristic list (e.g., boron, copper, nickel, vanadium, and
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3-14 March 1999

zinc) were evaluated for potential risks to human health and the environment in 1988 and 1993. In

particular, boron was cited as a cause of vegetative damage in the 1993 Regulatory Determination.

Based on available information and engineering judgment, EPA does not expect any low-volume

waste to be ignitable, and EPA does not expect low-volume wastes other than mill rejects (potentially) to

be reactive. Table 3-7 summarizes the results of this analysis. Because of the variable physical

characteristics of these wastes, the data represent a combination of analysis methods: toxicity

characteristic leaching procedure (TCLP) or extraction procedure (EP) leachate data for solid wastes

and sludges, and measurement of dissolved analytes for aqueous wastes.

Table 3-7 shows that certain low-volume combustion wastes sometimes display the RCRA

characteristics of toxicity and/or corrosivity. Specifically, boiler chemical cleaning wastes, coal pile

runoff, and demineralizer regeneration wastes displayed hazardous characteristics in at least one analyzed

sample. Table 3-7 shows that no samples of coal mill rejects as generated exhibited the characteristics of

toxicity or corrosivity. However, EPA believes that coal mill rejects containing significant levels of

Low-Volume Waste Principal Physical or Chemical Characteristics

Coal Pile Runoff Acidic or alkaline solution (depending on coal type) with uncombusted coal particles. 

May contain calcium, metals, silica, chloride, sulfate, and dissolved and suspended

solids.

Coal Mill Rejects Hard coal, quartz, and iron sulfides (pyrites) that cannot be ground by mills.

Boiler Blowdown Alkaline solution of boiler feed water with low dissolved solids. May contain chlorides,

sulfates, calcium and magnesium salts, precipitated solids, corrosion products, and

chemical additives, such as phosphates, sodium hydroxide, sodium sulfite, hydrazine,

and chelating agents.

Cooling Tower Blowdown and

Sludge

Similar to makeup water, with biocides, anti-corrosives, and other additives. Sludge

contains settled solids. Contaminants may include calcium and magnesium salts, metal

oxides, asbestos, biofouling inhibitors, zinc, phosphonates, sulfuric acid, chlorine, wood

preservatives, suspended solids, carbonates, nitrates, and sulfates.

Water Treatment Sludge Sludge from the treatment of makeup water.

Regeneration Waste Streams and

Other Water Treatment Wastes

Strong acid and base regeneration solutions, with concentrated makeup water

contaminants. May contain calcium, metals, sodium, chlorides, sulfates, and organics.

Air Heater and Precipitator

Washwater

Aqueous solution with suspended ash from fireside cleaning. May include a source of

alkalinity for pH control. May contain metals, dissolved or suspended solids, and

polynuclear hydrocarbons from soot deposits.

Boiler Chemical Cleaning Waste Aqueous weak acid or base solution containing residual cooling system additives. May

contain ammonium sulfate, ammonium carbonate, oxidizing agents, metals, hydrochloric

or other acids, phosphates, fluorides, organic compounds, caustics, and silica. 

Floor and Yard Drains and Runoff Low solids aqueous waste with soil, ash, some uncombusted coal, oil and grease, and

phosphates and surfactants.

Laboratory Wastes Miscellaneous aqueous wastes expected to be represented by above. May be acidic or

alkaline and may contain methylene chloride, phthalates, silica, phosphorous, hydrazine,

and sodium.

Wastewater Treatment Sludge Sludge from management of several of the above wastes.

Sources: EPA, 1988, 1996; EPRI, 1991, 1992, 1994a, 1994b, 1996a, 1996b, 1997b, 1997c, 1997d, 1997e, 1997f, 1997g, 1997h, 1997i,

1997j, 1997k, 1997l, and 1999

Table 3-5. General Composition of Selected Low-Volume Wastes
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March 1999 3-15

pyrites may be reactive, due to their reactive sulfide content. Because of the low number of samples

available (between 2 and 15 samples for each waste type), no attempt was made to extrapolate the

frequency of RCRA characteristic exceedences to the population as a whole.

3.2.2 Comanaged Utility Coal Combustion Wastes

Physical and Chemical Characteristics

From a physical standpoint, comanaged wastes are similar to large-volume UCCWs, especially in

cases where the UCCWs are managed with low-volume aqueous wastes or only small quantities of lowvolume solid wastes. For example, a solid sample of comanaged ash managed under these conditions has

a similar particle size and gross physical characteristics (e.g., oxides of aluminum, silicon, iron, and

calcium) as the ash when generated.

Differences in physical properties between comanaged wastes and high-volume wastes can be

apparent in localized areas of a waste management unit. Comanaged wastes generally show some 

Constituent Mean Range

Major Constituents (maximum concentration greater than approximately 1 percent)

Calcium 91,700 6,700–267,000

Iron 132,400 9,500–357,300

Magnesium 14,200 1,800–60,300

Manganese 8,500 100–146,100

Potassium 6,100 50–19,100

Trace Constituents

Arsenic 104 1.50–447

Barium 370 48.0–1,070

Cadmium 3.78 3.5–9

Chromium 64.8 9–3,380*

Copper 23.5 4.5–69

Lead 18.4 4.5–121

Mercury 0.35 0.04–0.88

Nickel 48.3 9–464

Selenium 11.1 2.5–50

Silver 12.6 4.5–41

Zinc 23.05 4.5–225

* Considered to be an outlier; not included in calculation of mean

Note: Values below the detection limit were treated as one-half the detection limit.

Source: EPRI, 1999

Table 3-6. Total Concentration Data for Coal Mill Rejects (ppm)
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3-16 March 1999

properties of each material. For example, comanagement of fly ash in a section of a pond receiving coal

pile runoff results in a mixture resembling combusted and uncombusted coal particles, while

comanagement of coal mill rejects and bottom ash results in a mixture resembling a coarse angular and

glassy material with oxidized iron (EPRI 1991, 1992, 1994a, 1994b, 1996a, 1996b, 1997c, 1997d, 1997e,

1997f, 1997g, 1997h, 1997i, 1997j, 1997k, and 1997l).

The chemical characteristics of comanaged wastes are dependent on the type and quantity of

low- and large-volume wastes present. EPA has characterized comanaged waste using “as managed”

samples from 17 comanaging utility sites. The Agency has compared the comanagement practices at

these facilities to industry-wide practices as described by EPRI comanagement survey results. Based on

this comparison, EPA concluded that comanagement practices at sampled sites are similar to industrywide practices or reflect a greater degree of comanagement than at the sites in the general population. 

Therefore, the characterization data presented here are considered representative of the range of waste

combinations that are managed by the industry.

Table 3-8 presents waste characterization data for comanaged wastes in impoundments and

landfills. Of constituents of potential concern, barium, strontium, and manganese are present in the

highest concentrations. These findings are similar to the characteristics of large-volume UCCWs as

presented in the 1988 Report to Congress. Additionally, Table 3-8 shows that the characteristics of

comanaged wastes collected from landfills and impoundments are generally within an order of magnitude

of each other. A much smaller number of landfills are represented in the data, which may contribute to

uncertainty in those results.

As discussed in the previous section, EPRI has provided a limited quantity of data on organic

constituents in comanaged wastes. The data generally indicate that these constituents are not present at

levels above detection limits. EPA evaluated the data available on the presence of dioxins and furans in

comanaged wastes. Very few samples had concentrations of individual compounds above detection

limits. The most toxic compound, 2,3,7,8-TCDD, was not detected in any of the 17 samples from 11

Low-Volume Waste Exceedences of RCRA Characteristics

Coal pile runoff Exceedences for cadmium, chromium, lead, selenium, and silver

in one or more samples

Coal mill rejects No exceedences; potentially reactive when significant levels of

pyrites are present

Boiler blowdown No exceedences

Cooling tower blowdown and sludge No exceedences

Regeneration waste streams and other water treatment

wastes

Exceedences for pH, chromium, and lead in one or more samples

Air heater and precipitator washwater No exceedences

Boiler chemical cleaning waste Exceedences for pH, chromium, and lead in one or more samples

Floor and yard drains and runoff No exceedences

Sources: EPA, 1988; EPRI, 1991, 1992, 1994a, 1994b, 1996a, 1996b, 1997c, 1997d, 1997e, 1997f, 1997g, 1997h, 1997i, 1997j, 1997k,

and 1997l

Table 3-7. Summary of Hazardous Waste Characteristics for Low-Volume Wastes
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March 1999 3-17

sites. Compositing the concentrations of all compounds of interest using their respective 2,3,7,8-TCDD 

equivalency factors, the samples displayed 2,3,7,8-TCDD equivalent concentrations from below

detection to 2.1 ng/kg (approximately one order of magnitude above typical detection limits). By

comparison, a reference sample of municipal waste incinerator fly ash had a 2,3,7,8-TCDD equivalent

concentration of 1,460 ng/kg (parts per trillion) (EPRI, 1998b).

Coal contains and emits low levels of naturally occurring radiation (Radian, 1988). 

Concentrations of radionuclides in coal vary with coal rank and origin. For example, uranium and

thorium concentrations in U.S. coals range from below 0.01 parts per million (ppm) to roughly 75 ppm,

based on analyses of more than 6,000 samples (EPA, 1995c). However, the geometric mean

concentrations of uranium and thorium for the same sample population are 1.2 ppm and 2.2 ppm,

respectively. These concentrations correspond to activities of roughly 0.41 pCi/g and 0.24 pCi/g,

respectively. Because they do not volatilize, these elements generally concentrate in coal ash, such that

activity levels in the ash increase relative to the radioactivity in source coal (EPA, 1989a). EPA

estimates an average increase of roughly 10×, such that average activity levels for curanium and thorium

are 4 pCi/g and 2.4 pCi/g, respectively.

Constituent

Managed in Surface Impoundments Managed in Landfills

Mean Range Mean Range

Arsenic 40 6.7–150 20 6.2–38

Barium 1,600 150–8,400 2,900 1,800–3,800

Beryllium 8.4 0.88–16 n/a n/a

Boron 190 0.03–420 n/a n/a

Cadmium 6 0.20–24 n/a n/a

Chromium 85 5.7–290 50 35–78

Cobalt 29 4.7–42 n/a n/a

Copper 78 2.2–150 105 97–120

Lead 42 5–150 17 6.5–29

Manganese 280 55–660 460 200–820

Nickel 68 1.5–160 51 33–65

Selenium 37 0.025–320 14 0.8–32

Silver 5.2 0.03–14 n/a n/a

Thallium 27 10.6–48 n/a n/a

Strontium 1,040 1–4,800 2,100 1,100–2,650

Vanadium 120 20–350 86 23–160

Zinc 150 17–860 84 35

*All measurements identified as below detection limit were assigned a value equal to one-half the detection limit for use in the calculations. 

All concentrations are facility-averaged; i.e., multiple measurements from a single site are averaged, and the resulting population of facility

averages used to generate the statistics in this table.

n/a = data not available

Sources: EPRI, 1991, 1992, 1994a, 1994b, 1996a, 1996b, 1997c, 1997d, 1997e, 1997f, 1997g, 1997h, 1997i, 1997j, 1997k, and 1997l

Table 3-8. Facility Average Concentrations of Trace Constituents in Comanaged Wastes

(parts per million) (whole waste)*
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3-18 March 1999

EPA has reviewed radionuclide concentrations in coal and ash in connection with other

regulatory programs (EPA 1989a, 1989b, 1995c). One of these studies examined potential exposures of

worker and nearby resident to radioactivity from ash released from coal pile through wind and runoff

erosion. Exposure from direct contact, inhalation, and ingestion were estimated to fall below natural

background radiation exposure levels even for a worker standing on the ash pile (EPA, 1989a). In

addition, EPA is currently studying coal combustion wastes as part of a larger study of naturally

occurring radioactive materials (NORM). The report from this NORM study is expected to be published

later in 1999. Due to the low expected risks associated with radionuclides in coal ash, and to prevent

duplication of effort with the NORM study, EPA eliminated radionuclides from further consideration in

this study.

Based on these characterization results, EPA concludes that metals are the class of constituents

potentially of concern in comanaged wastes. Section 3.4 discusses the potential risks of metals in these

wastes to human health and the environment.

Leaching and Hazardous Waste Characteristics

EPA evaluated whether comanaged waste exhibited any of the four characteristics of hazardous

waste: corrosivity, reactivity, ignitability, and toxicity. Based on available information and professional

judgment, EPA does not expect any comanaged wastes to be ignitable or reactive. To evaluate

corrosivity, EPA examined pH data from pore waters (i.e., interstitial water from borings of waste

managed in surface impoundments that represents leachate from the solid wastes and liquids from the

comanaged liquid low-volume wastes). None of these samples exceeded the limits for corrosivity (pH

less than or equal to 2 or greater than or equal to 12.5).

EPA evaluates the characteristic of toxicity using TCLP results. Examining available TCLP

results for comanaged wastes, the Agency found that none of the 27 samples exhibited leachate

concentrations in excess of the regulatory standard. Thus, comanaged wastes are not expected to exhibit

the RCRA characteristic of toxicity.

EPA does not conclude from these TCLP results, however, that comanaged wastes are incapable

of mobilizing constituents at levels of concern. Specifically, pore water (i.e., interstitial water from

borings) from some comanaged wastes shows concentrations above the TCLP regulatory limits. EPA

used pore waters from impoundments to represent the range of concentrations of potentially hazardous

constituents mobilized in comanaged wastes. These data were used instead of TCLP data for evaluating

impoundment leachate because (1) they represent actual leachate conditions at the sampled sites, and

(2) a larger and more representative database exists for pore water analyses than for TCLP analyses. On

the other hand, the TCLP data are believed to better represent leaching conditions at landfills than would

pore water data from impoundments.

Therefore, the leachate data in Table 3-9 use pore water data to represent leachate from 

impoundments and TCLP data to represent leachate from landfills. To maximize the sample size, the

table includes TCLP results from wastes managed in both impoundments and landfills in the column

representing landfills. Evaluation of the pore water data shows that the highest concentrations of arsenic

are associated with a site with significant quantities of coal mill rejects comanaged with fly and bottom

ash. One other facility contributed high arsenic values, but it is not evident that mill rejects are

comanaged in significant quantities at that site. No other significant effects from comanagement are

evident from the data.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-19

Constituent

RCRA

Standard

Managed in Surface Impoundmentsa Managed in Landfillsb

Mean Range Mean Range

RCRA Toxicity Constituents

Arsenic 5.0 1.57 0.0075–9.64 0.0382 0.000875–0.236

Barium 100.0 2.1 0.001–27.4 1.06 0.114–3.63

Cadmium 1.0 0.0341 0.00099–0.250 0.00542 0.00015–0.0443

Chromium 5.0 0.175 0.00075–0.746 0.0211 0.00067–0.0589

Lead 5.0 0.0838 0.000766–0.468 0.00365 0.00106–0.00675

Mercury 0.2 0.00080 0.00080–0.00080 0.00005 0.000005–0.000118

Selenium 1.0 0.214 0.00325–1.03 0.0686 0.00483–0.440

Silver 5.0 Not calculated c 0.00134 0.0006–0.00225

Non-RCRA Constituents

Aluminum n/a n/a n/a 3.69 0.155–11.7

Antimony n/a Not calculated c 0.00431 0.00105–0.0125

Beryllium n/a Not calculated c 0.00151 0.00005–0.00675

Boron n/a n/a n/a 3.26 0.103–9.63

Calcium n/a n/a n/a 549 44.9–1,110

Cobalt n/a Not calculated c 0.00758 0.00192–0.0167

Copper n/a 0.131 0.00085–0.67 0.0307 0.00105–0.087

Iron n/a n/a n/a 1.09 0.0058–10.75

Magnesium n/a n/a n/a 48.5 2.71–184

Manganese n/a n/a n/a 0.766 0.0444–2.23

Nickel n/a 0.701 0.005–8.328 0.0253 0.0066–0.0508

Potassium n/a n/a n/a 5.44 2.33–10.9

Sodium n/a n/a n/a 1379 1,253–1,545

Sulfate n/a n/a n/a 479 14.0–2,025

Thallium n/a Not calculated c 0.00528 0.00185–0.0152

Vanadium n/a 0.242 0.01195–0.800 0.0399 0.0054–0.122

Zinc n/a 1.65 0.0121–2.31 0.192 0.018–1.16

a Leachate represented by pore water samples; i.e., the laboratory-extracted interstitial waters from borings of waste managed in surface

impoundments. b TCLP results for samples of waste managed in both surface impoundments and landfills. c The constituent was not detected in any samples, or detected in a small number of samples, and therefore meaningful statistical values

cannot be calculated.

All measurements identified as below detection limit were assigned a value equal to one-half the detection limit. All concentrations are

facility-averaged: i.e., multiple measurements from a single site are averaged, and the resulting population of facility averages used to

generate the statistics in this table.

n/a = data not available

Sources: EPRI, 1991, 1992, 1994a, 1994b, 1996a, 1996b, 1997c, 1997d, 1997e, 1997f, 1997g, 1997h, 1997i, 1997j, 1997k, and 1997l

Table 3-9. Facility Average Leachate Concentrations for Comanaged Wastes (mg/l)
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3-20 March 1999

Table 3-9 includes the eight RCRA-regulated metals plus other constituents of comanaged

wastes. Of these, the eight RCRA-regulated metals plus antimony, beryllium, boron, cobalt, copper,

manganese, nickel, thallium, vanadium, and zinc are considered further in Section 3.4 for their potential

risk to human health and the environment.

3.2.3 Wastes from Coburning Coal and Other Fuels

EPRI provided a summary of characterization data for wastes from the combustion of a variety of

fuels and fuel mixtures that are sometimes coburned with coal (EPRI, 1997m). The data included both

TCLP and total concentration analyses and comprised a small number of samples of wastes derived from

each variety of different fuel mixtures. EPA compared the EPRI data to the data for UCCWs collected

for the 1993 Regulatory Determination. Because of the small number of samples available for most

individual fuel mixtures, EPA pooled the data reflecting samples of mixtures with similar components

and similar characteristics into categories for comparison. Table 3-10 shows the specific fuel mixtures

included in each category.

Comparing total concentration data, EPA found that some types of fuel mixtures resulted in

wastes with potentially higher levels of metals than UCCWs. Comparing TCLP data, EPA found that

results were similar or below those for UCCW, with a few exceptions. Based on these comparisons, the

available data indicate that, while leachate levels generally appear similar, coburning certain fuel

mixtures may result in higher concentrations of some metals in the whole waste. This observation,

however, is based on a limited number of samples for the wastes for coburning. The available data are

not sufficient to draw statistically significant conclusions. The available data also do not indicate the

Category

Specific Mixtures Included in Category

Total Concentration Data TCLP Data

Wood and Biomass wood, biosludge/wood, railroad ties wood

Mixed Plastics mixed plastics/coal, mixed

plastics/coal/lime

mixed plastics/coal,

mixed plastics/coal/lime

Peat Mixtures peat, peat/coal, peat/RDF,

peat/coal/RDF, peat/coal/RDF/lime,

peat/coal/packaging material,

peat/coal/mixed plastics/lime

peat, peat/RDF

Oil Combustion Wastes oil ash/coal

(limited number of constituents)

none

Refuse Derived Fuel (RDF) Mixtures RDF/lime, RDF/wood chips RDF/wood chips

Manufactured Gas Plant (MGP) Wastes MGP holder material/coal, MGP

contaminated soil/coal

MGP holder material/coal,

MGP-contaminated soil/coal,

spent oxide box wastes/coal

Petroleum Coke Mixtures petroleum coke/coal, petroleum

coke/coal/MGP contaminated soil

petroleum coke/coal

Tire Derived Fuel (TDF) Mixtures TDF/coal

(limited number of constituents)

TDF/coal

Table 3-10. Fuel Mixtures with Waste Characterization Data Available

for Comparison to UCCWs
Report to Congress on Wastes from the Combustion of Fossil Fuels

2

 The EPRI comanagement survey was voluntary and, thus, a complete population count was not expected. 

This explains the smaller number of power plants covered by the survey.

March 1999 3-21

percentages of each fuel component associated with the various mixtures sampled. Finally, data are not

available on the chemical composition of the individual components of each mixture. Therefore, it is not

possible to determine the source of elevated metals concentrations (i.e., it is not possible to say with

certainty if the elevated concentrations result from the coal or the other fuels in the mixtures).

In addition to providing data on the inorganic constituents discussed above, EPRI’s report on

coburning (EPRI, 1997m) discusses organic constituents in combustion wastes from the various fuel

mixtures. According to EPRI, most leachate and total composition analyses were below detection levels

for organics. Fuel mixtures with some detected values included petroleum coke, mixed plastics, peat

mixtures, RDF mixtures, MGP waste mixtures, and TDF mixtures. Detected organics included benzene,

cyanide, dioxins, furans, PCBs, chlorobenzene, chlorophenol, and polycyclic aromatic hydrocarbons. 

Complete data on organics, however, are not presented in the report.

3.3 CURRENT MANAGEMENT PRACTICES

EPA used three sources of data to characterize UCCW comanagement practices:

• The 1994 EEI Power Statistics Database (EEI, 1994)

• The 1993 DOE study (DOE, 1993)

• The 1997 EPRI comanagement survey (EPRI, 1997a).

The EEI and DOE data cover the entire utility population. Because the majority of utilities

comanage large-volume and low-volume wastes, data from these sources are believed to be

representative of comanaging utilities as well. The EPRI comanagement survey specifically collected

information on comanagement practices. The survey was voluntary and did not cover the entire utility

population. However, the EPRI survey sample encompasses the majority of large-volume UCCW

disposed in terms of volume (two thirds of the total generated in 1995). Based on comparison with data

from the other sources, the EPRI sample appears representative of the population of UCCW management

units in terms of the types of units included.

3.3.1 Unit Types and Location

Waste management units common at utility coal combustion facilities include landfills and

surface impoundments. Box 3-3 defines these units. UCCWs at a facility may be managed together in

the same waste management unit, or different UCCWs may be disposed in separate units. For example,

fly ash may be sluiced to one surface impoundment, while bottom ash is managed in another. Also,

different waste management units may service separate combustion units at an individual facility. 

Finally, as described above, UCCWs initially may be managed in a surface impoundment (or series of

impoundments) and then dredged for placement in a landfill. As a result of these practices, a given

combustion facility may have more than one waste management unit. The 1993 DOE study found 618

management units at 450 U.S. coal-fired power plants. The EEI Power Statistics database reports 561

units serving 440 facilities. Responses to the EPRI comanagement survey cover 323 UCCW

management units serving 238 power plants.2
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The three data sources show nearly equal numbers of surface impoundments and landfills. While

slightly more than half of the units in the DOE study and EEI database are surface impoundments, just

under half of the EPRI survey units are surface impoundments.

The population of units that comanage large-volume and low-volume wastes differ little from

those of the UCCW management unit population as a whole. Slightly more than half (54 percent) of the

206 comanagement units in the EPRI survey are surface impoundments. This proportion is similar to the

proportion of impoundments in the EPRI survey population as a whole. Furthermore, it is similar to the

proportion of impoundments found in the other sources describing the population of UCCW management

units.

Although each source shows a similar proportion of unit types, there appears to be a general

trend toward the increasing use of landfills. Figure 3-4 shows that the proportion of landfills among new

units has increased over time, based on the opening dates of the units in the EPRI comanagement survey. 

Units opened since 1970 are more likely to be landfills than surface impoundments.

Three factors may contribute to the trend toward the increasing use of landfills. First, space

constraints at existing utility facilities favor the use of landfilling when new units are required. As

discussed below, because of their greater height and material compaction, landfills can provide greater

UCCW management capacity in smaller areas than surface impoundments. Furthermore, when space

constraints are extreme, utilities must locate new UCCW management units offsite. When located

offsite, landfills may be the preferred unit type because of the lower cost of transporting dry UCCW as

opposed to wet UCCW. Second, New Source Performance Standards (NSPS) under the Clean Water Act

require zero discharge of fly ash handling water (see Section 3.5.2). These requirements encourage the

use of dry ash handling systems and, therefore, landfilling for new generating units. Third, there is an 

Surface impoundments are natural depressions, excavated ponds, or diked basins that typically contain a

mixture of liquids and solids. UCCWs managed in surface impoundments typically are sluiced with water from

the point of generation to the impoundment. The solid UCCWs gradually settle out of this slurry, accumulating at

the bottom of the impoundment. This process leaves a standing layer of relatively clear water at the surface,

which is commonly termed “head.” The distance between the surface of the head and the top edge of the

impoundment is known as “freeboard” and indicates the remaining capacity of the impoundment. The amount of

freeboard in an impoundment may fluctuate as wastes are added, rainfall accumulates, and liquids are removed

for discharge to surface water or recirculated to sluicing operations. Solids that accumulate at the bottom of a

surface impoundment may be left in place as a method of disposal. The impoundment also may be periodically

dewatered and the solids removed for disposal in another unit, such as a landfill.

Landfills are facilities in which wastes are placed for disposal on land. Landfills usually are constructed in

sections called “cells.” Wastes are placed in the active cell and compacted until the predetermined cell area is

filled. Completed cells are sometimes covered with soil or other material, and then the next cell is opened. Cells

may be constructed on top of a layer of previously completed cells, called a “lift.” Landfills are usually natural

depressions or excavations that are gradually filled with waste, although construction of lifts may continue to a

level well above the natural grade. UCCWs managed in landfills may be transported dry from the point of

generation, or they may be placed after dredging from a surface impoundment. Some residual liquids may be

placed along with the dredged solids. Also, liquids may be added during the construction of the landfill for dust

control purposes.

Source: EPA, 1988

Box 3-3. Types of Waste Management Units
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March 1999 3-23

Figure 3-4. Trend in Utility Coal Combustion Waste (UCCW) Management Unit Type

increasing trend toward dry ash handling in general due to a steady increase in beneficial use applications

(see Section 3.6.2), which favor dry ash collection and management.

Figure 3-5 identifies the geographic distribution of UCCW management units in the EEI Power

Statistics database. The map shows the greatest number of units in the upper Midwest and fewer units in

the far west and New England. This is consistent with geographic distribution of coal-fired utilities. Of

more significance, Figure 3-5 indicates that surface impoundments outnumber landfills in the Southeast

and some Midwestern states, while landfills outnumber surface impoundments in Texas and the

Southwest.

Based on data from the DOE study and EEI, the majority of UCCW management units are

located at the generating site. Surface impoundments are almost exclusively found at the generating site

(94 to 95 percent), while approximately half of landfills (49 to 59 percent) are onsite units. The

extensive use of onsite management units likely is due to the large volume of waste generated. Offsite

transportation costs can make onsite disposal more economical.

Power plants with the smallest generating capacity are more likely to use offsite units for UCCW

disposal than are the largest power plants. As discussed above, the majority of offsite units are landfills. 

Thus, smaller generating facilities tend to favor offsite landfilling. Table 3-11 shows the trend toward

offsite disposal for smaller facilities, probably due to space constraints and lower transportation costs for

the smaller volumes of waste generated.

3.3.2 Types of Waste Managed

Individual waste management units at utilities may contain one or more of the large-volume

UCCWs. Nearly 70 percent of the waste management units responding to the EPRI comanagement

survey combine two or more large-volume UCCWs. The most common scenario is the combined
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3-24 March 1999

Figure 3-5. Geographic Distribution of Utility Coal Combustion Waste (UCCW)

Management Units

management of fly ash and bottom ash in a single unit, which is practiced in nearly half of the waste

management units.

In addition to combining large-volume UCCWs, comanagement with low-volume wastes is a

common practice at utilities. Comanagement, in fact, is practiced at the majority of utilities. Of the 253

active UCCW management landfills and surface impoundments in the EPRI survey, 206 (or 81 percent)

comanaged large-volume wastes with at least one low-volume waste. These 206 comanagement units

accounted for nearly 53 million tons (84 percent) of the 63 million tons per year of large-volume UCCW

reported by all active units in the survey.

Both landfills and surface impoundments can comanage large-volume UCCWs and low-volume

wastes. Solid low-volume wastes may be disposed directly in UCCW landfills or sluiced to UCCW

surface impoundments. Liquid low-volume wastes may be sent to UCCW surface impoundments, either

directly, following mixture with other low-volume liquids, or following some form of treatment. Solids

settled from liquid low-volume wastes may be dredged and placed in UCCW landfills. Liquid lowvolume wastes also may be managed in landfills when they are used for dust suppression and ash 
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March 1999 3-25

Generating Capacity

Number of

Plants

Onsite Units Offsite Units

Number Percent Number Percent

0–100 MW 65 48 64% 27 36%

101–300 MW 83 65 72% 25 28%

301–600 MW 93 79 72% 31 28%

601–900 MW 60 64 77% 19 23%

901–1,450 MW 65 73 84% 14 16%

> 1,450 MW 74 101 87% 15 13%

Total 440 430 77% 131 23%

Source: EEI, 1994

Table 3-11. Unit Type by Power Generating Capacity for

Utility Coal Combustion Waste (UCCW) Management

conditioning. In addition to these direct forms of comanagement, liquid low-volume wastes may be

comanaged indirectly, for example, by using them as sluice water for ash or as makeup water in wet FGD

systems. These latter practices represent comanagement, as the low-volume wastes end up in the same

management unit as the large-volume UCCWs.

The EPRI comanagement survey collected data on the comanagement of all of the low-volume

wastes described in Section 3.1 with UCCWs. It also collected data on commingling of UCCWs with

other, more generic waste streams, such as municipal wastes, asbestos, and contaminated soils.

Low-volume wastes can, in fact, be comanaged in very large volumes. This is particularly true

for liquid wastes, some of which can be generated at an individual facility at rates of millions of gallons

per day. Based on EPRI comanagement survey data, solid low-volume wastes are managed in similar

quantities in both surface impoundments and landfills. Much larger quantities of liquid low-volume

wastes are managed in surface impoundments than in landfills. Figure 3-6 compares the volumes of

large-volume and low-volume waste managed in the units responding to the EPRI comanagement survey.

Based on Figure 3-6, the volume of low-volume waste is nearly 20 times the volume of largevolume waste managed. The majority of this waste is low-volume liquid waste managed in surface

impoundments. This seems plausible given the relatively large amounts of liquid used for sluicing ash to

impoundments. A large quantity of low-volume liquid wastes was reported to be disposed of by a few

landfills. This appears to be due to reporting errors in the survey responses. The estimate shown in

Figure 3-6 assumes the median percentage of low-volume liquids reported by landfills is more

representative of the population. Based on this estimate, the total quantity of low-volume waste (solid

and liquid) disposed of in landfills is expected to be less than the quantity of large-volume waste

disposed in these units.

Table 3-12 compares low-volume and large-volume waste quantities on an individual

management unit basis. This table shows that the quantity of comanaged low-volume waste can range

from an insignificant amount compared with large-volume UCCW, to a volume many times larger. In

surface impoundments, the quantity of low-volume waste typically is many times that of large-volume

waste, primarily due to the large quantity of liquids managed in these units. In landfills, the median

value shows that the quantity of low-volume waste is a fraction of that of large-volume waste in many

units.
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Individual surface impoundments and landfills may comanage as many as 15 different lowvolume waste streams. Surface impoundments typically comanage more different waste types (a median

of eight) than do landfills (a median of four). Also, the wastes most frequently comanaged differ for

each type of management unit. Table 3-13 shows the frequency with which comanagement units receive

each type of low-volume waste.

As noted above, facilities may indirectly comanage liquid low-volume wastes by using them

as sluice water for high-volume UCCWs or as makeup water in wet FGD systems. The EPRI

comanagement survey requested information on these practices. Of the 139 respondents that provided

information about UCCW sluice water, 85 do not use low-volume wastes (i.e., they use only lake or river

water or use recirculated pond water, which may not contain low-volume waste). Fifty-four respondents 

* 94 surface impoundments and 57 landfills provided waste quantity data. Assumes 1.3% solids content of liquid wastes.

Note: A large quantity of low-volume liquids was reported by a few landfills. This is believed to be the result of survey reporting errors. The

estimate shown assumes the median value for the period of landfilled waste that is low-volume liquid.

Source: EPRI, 1997a

Figure 3-6. Comanagement Volumes in Units Responding to EPRI Survey*
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March 1999 3-27

(or 39 percent) use at least one low-volume waste as sluice water. These respondents may use as many

as 10 different low-volume wastes as sluice water, although the median is one low-volume waste. Of the

47 respondents that provided information about FGD makeup water, 14 do not use low-volume wastes

(i.e., they use only lake or river water or use recirculated pond water). Thirty-three respondents (or

70 percent) use at least one low-volume waste as FGD makeup. These respondents may use as many as

10 different low-volume wastes as FGD makeup, although the median is two low-volume wastes.

Low-Volume Waste/Large-Volume UCCW

Landfills Surface Impoundments

Number of Units 57 94

Minimum 0% 0%

Maximum –a 248,650%

Median 3.9% 3,361%

Mean 4,214%b 12,646%

a

 The maximum value reported for a landfill is believed to be the result of a survey reporting error and is not presented here.

b

 The mean value calculated for a landfill incorporates a number of values believed to be reporting errors and, thus, is not considered

representative of most landfills.

Note: Percentages shown are a comparison of low-volume waste with large-volume waste on an individual management unit basis.

Source: EPRI, 1997a

Table 3-12. Low-Volume and Large-Volume Waste Compared by Management Unit

Waste

Percent of Landfills

(95 units)

Percent of Surface Impoundments

(111 units)

Coal Pile Runoff 39% 67%

Coal Mill Rejects/Pyrites 64% 70%

Boiler Blowdown 31% 67%

Cooling Tower Blowdown 23% 26%

Water Treatment Wastes 39% 58%

Regeneration Waste Streams 34% 74%

Air Heater or Precipitator Washes 38% 68%

Boiler Chemical Cleaning Wastes 32% 54%

Waste from Floor Drains and Sumps 39% 79%

Other Site Runoff 33% 60%

Miscellaneous Plant Wastes 25% 39%

* Frequencies shown include direct comanagement and indirect comanagement through use as sluice water or FGD makeup water.

Source: EPRI, 1997a

Table 3-13. Low-Volume Wastes Most Commonly Comanaged*
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3.3.3 Unit Size

Table 3-14 presents summary statistics on the capacities and dimensions of UCCW management

units included in the EPRI survey. As shown in the table, landfills as a group have larger capacities than

surface impoundments. This is because surface impoundment capacities are limited by their excavated

depth or the height of their berms, whereas landfill lifts can continue to be constructed above grade,

providing greater ultimate disposal capacity. The units in the EPRI comanagement survey have greater

average capacities than units in the EEI database. This result may be because the EEI database includes

more small generators than the EPRI comanagement survey.

As shown in Table 3-14, the range of sizes for each type of UCCW management unit is great. 

Comparing the mean and median values for each unit type suggests that units are not distributed evenly

throughout this range. Figure 3-7 graphically presents the size distribution of UCCW landfills and

impoundments. Approximately 60 percent of units are less than 4 million cubic yards in capacity. 

Another 20 percent fall between 4 million and 8 million cubic yards. The remaining units are distributed

over a broad range.

3.3.4 Environmental Controls

The EPRI comanagement survey collected information on the use of environmental control

technologies, including liners, covers, leachate collection systems, and ground-water monitoring systems,

at comanagement units. Box 3-4 provides a general description of each of these technologies. The EPRI

comanagement survey also collected information on the types of regulatory permits and ground-water

standards applied to comanagement units. While not control technologies in themselves, permits and

standards are techniques used to ensure environmental control of waste management practices. For

example, permits can dictate the use of specific operating practices and control technologies. Table 3-15

summarizes the use of environmental controls in UCCW comanagement units. The paragraphs below

provide additional details and discussion of each type of environmental control.

An examination of the geographic distribution of new, lined surface impoundments suggests

that liner requirements in several states have changed. The change from unlined to lined surface

impoundments appears concentrated in the states of Georgia, Illinois, Indiana, Kentucky, Missouri, and

Texas. These states account for 44 percent of the active comanagement surface impoundments in the

EPRI survey. In these six states, only six (or 15 percent) of the impoundments opened before 1982 are

lined. On the other hand, all of the impoundments opened since 1982 are lined. Data are available on

Landfills (110 units) Surface Impoundments (107 units)

Capacity

(cubic yards)

Area

(acres)

Height

(feet)

Capacity

(cubic yards)

Area

(acres)

Depth

(feet)

Minimum 2,700 2.6 0.36 115,000 5 1

Maximum 82,000,000 900 150a 63,000,000 1,500 200b

Median 3,850,000 66 31 3,400,000 90 20

Mean 7,434,852 116 43 6,507,405 149 36

a One landfill yielded an estimated height of 356 feet and was omitted from this table. The data did not influence the calculated median

value.

b One surface impoundment yielded 697 feet and was omitted from this table. The data did not influence the calculated median value.

Source: EPRI, 1997a. Height and depth data are derived from the reported capacity and area for each unit.

Table 3-14. Management Unit Size for UCCW
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March 1999 3-29

Figure 3-7. Size Distribution of Management Units for UCCW

 Source: EPRI, 1997a

impoundment requirements in five of these six states (Georgia, Illinois, Indiana, Kentucky, and Texas)

(CIBO, 1997c and EPA’s review of requirement in Indiana). According to these data, these five states

currently determine liner requirements for surface impoundments on a case-by-case basis. Therefore, if

the trend in liner usage is driven by regulatory agencies in these states, it appears to result from a change

in permitting policies rather than written regulations.

Liners

Table 3-15 presents liner data from the EPRI comanagement survey. The DOE study and the EEI

Power Statistics database are in close agreement on the percentages of surface impoundments and

landfills with a liner present. All three sources show that landfills are more frequently lined than surface
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3-30 March 1999

impoundments. This difference may be the result of two factors. First, state solid waste management

regulations are more likely to mandate liners for landfills. As discussed in Section 3.5, many states do

not impose specific design requirements (such as liners) on surface impoundments. When requirements

are imposed, they typically are determined on a case-by-case basis. Second, as discussed above, newer

units are more likely to be landfills than surface impoundments. These newer units would also be more

likely to incorporate the latest environmental controls and regulatory requirements, such as liners.

For both landfills and surface impoundments, there is an increasing trend in the use of liners in

newer units, as shown in Figure 3-8. This trend is consistent with the fact that liners are a modern

development in the design of waste management units. This trend also may be the result of changing

state regulations or permitting policies. As discussed in Section 3.5, new regulations or policies

requiring liner usage typically affect only new units and do not apply retroactively to existing units.

Liners. A liner is a barrier placed underneath a landfill or on the bottom and/or sides of a surface impoundment. 

Depending on their construction, liners can slow or prevent the release of leachate from a landfill or liquids from

a surface impoundment to underlying soils and ground water. Liners can consist of compacted soil, compacted

clay, a synthetic material or membrane, or a combination of barrier types.

Covers. A cover, or cap, is a barrier placed over the top of a waste management unit. Covers can prevent

precipitation runoff from becoming contaminated by contact with waste, prevent or slow percolation of

precipitation into the unit, and prevent windblown transport of waste. Like liners, covers can consist of

compacted clay, synthetic materials or membranes, or a combination of materials. Covers also may be a layer of

soil or sand. Final covers are those placed upon closure of a unit. Intermediate covers also may be placed on

closed or inactive portions of a unit, particularly completed cells of a landfill. Daily covers are sometimes

placed at landfills at the end of a day’s operation.

Leachate Collection Systems. A leachate collection system is a series of drains placed beneath a unit, typically

a landfill. These systems collect leachate for treatment or disposal, thus preventing it from reaching soils,

ground water, or surface water.

Ground-Water Monitoring Systems. Ground-water monitoring systems consist of one or several wells drilled

in the vicinity of a unit. Samples from these wells are periodically collected and analyzed. Ground-water

monitoring is not strictly an environment control but rather a warning system. Ground-water samples that

display contamination may trigger regulatory requirements to mitigate or eliminate the source of contamination.

Box 3-4. Environmental Control Technologies

Environmental Control

Landfills Surface Impoundments

Number

Reporting Data

Percent

with Control

Number

Reporting Data

Percent

with Control

Liner 94 57% 111 26%

Cover 72 94% 47 30%

Leachate Collection 95 43% 111 1%

Ground-Water Monitoring 95 85% 111 38%

Ground-Water Performance Standards 94 77% 107 48%

Regulatory Permits 94 94% 110 85%

Source: EPRI, 1997a

Table 3-15. Environmental Controls at UCCW Comanagement Units
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March 1999 3-31

Figure 3-8. Trend in Liner Utilization in Comanagement Units

 Source: EPRI, 1997a

Figure 3-9 displays the types of liners incorporated in the design of comanagement units

responding to the EPRI survey. The most common liner material for both types of unit is compacted

clay. Compacted clay typically has lower permeability than natural soils and, thus, serves as a better

barrier between leachate and ground water. Several units reported using geotextile or composite liners. 

Several landfills reported using compacted ash as a liner.

Covers

As shown in Table 3-15, 94 percent of landfills and 30 percent of surface impoundments utilize

some type of cover. Figure 3-10 details the types of covers used at these comanagement units. The data

for currently active units probably are not indicative of the types of final covers that will be used when
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3-32 March 1999

Figure 3-9. Liner Types for Comanagement Units

the units are closed. The results for landfills likely reflect interim cover on completed cells or daily

cover used in active cells. Active landfills most commonly use sand, soil, or compacted clay for these

purposes. Some active surface impoundments also use covers, usually soil or sand. The results for

surface impoundments probably reflect cover placed on closed or full sections of active impoundments. 

Interpreting the percentages shown for impoundments is difficult. It is unclear whether the 70 percent of

facilities answering “none” have closed, uncovered sections, or if their answer was intended to indicate

that they have no closed sections.

Examining cover types used on currently closed units can provide a better sense of the types of

final cover that will be applied to currently active comanagement units at the end of their useful life. 

Because of the design of the survey, the closed units were not required to indicate whether they

comanaged low-volume waste. Three of the 57 closed units, however, did respond that they comanaged. 

All three of these are surface impoundments, two of which have compacted clay covers. The remaining

surface impoundment did not provide cover information. An examination of all closed units provides a

larger sample of cover information. Given the prevalence of comanagement, it is likely that many of

these units comanaged low-volume waste at some time. Figure 3-10 shows cover types for closed units

included in the EPRI survey. The survey responses, other than for the three surface impoundments

discussed above, did not indicate whether closed units were surface impoundments or landfills. Of the

53 closed units that provided cover information, 81 percent used some type of cover. The most common

type is soil or sand, although almost a quarter used compacted clay.

Leachate Collection

As shown in Table 3-15, 43 percent of the comanagement landfills in the EPRI survey include a

leachate collection system. Very few surface impoundments (1 percent) have leachate collection. This

difference may result from the difficulty of incorporating leachate collection systems into an

impoundment design. It may also be the result of state solid waste management regulations dictating

collection systems for landfills but not surface impoundments. As discussed in Section 3.5, many states
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March 1999 3-33

Figure 3-10. Comanagement Unit Cover Types

 Note: Percentages for active landfills and active surface impoundments do not sum to 100 percent due to rounding.

 Source: EPRI, 1997a

do not impose specific design requirements (such as leachate collection systems) on surface

impoundments. When requirements are imposed, they typically are determined on a case-by-case basis.

Because a leachate collection system, like a liner, is an environmental control that is usually part

of the initial design and construction of a unit, increasing use of these systems in newer units might be

expected. Examination of the EPRI data, however, shows no such trend. Leachate collection appears to

have been a part of comanagement unit design since the early 1960s, with new units no more likely than

their predecessors to incorporate this control.
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Ground-Water Monitoring

As shown in Table 3-15, 85 percent of landfills have some form of ground-water monitoring,

compared with 38 percent of surface impoundments. This difference may be the result of state solid

waste management regulations dictating ground-water monitoring for landfills but not surface

impoundments. As discussed in Section 3.5, many states do not impose specific requirements on surface

impoundments.

When requirements are imposed, they typically are determined on a case-by-case basis. Figure

3-11 shows an increasing trend in the use of ground-water monitoring at newer comanagement units. 

The trend appears particularly noticeable for surface impoundments. Although ground-water monitoring

can be implemented at any point in the life of a waste management unit, it may be more likely in newer

units because of more recent changes in state regulations or permitting policies. The operating permits

for newer units may reflect new state ground-water monitoring requirements, whereas those for older

units may not.

Ground-Water Performance Standards

As shown in Table 3-15, ground-water performance standards apply to 77 percent of

comanagement landfills but only 48 percent of surface impoundments. The types of standards applied

include numerical water quality standards, such as federal maximum contaminant limits (MCLs), and

nondegradation standards under which current conditions are compared with past measurements. Some

units, particularly landfills, have standards tailored for the particular site. The EPRI survey did not

identify the consequences if ground-water standards were exceeded. Thirty-one of the units subject to

ground-water performance standards (25 of them surface impoundments) do not have to monitor ground

water. Therefore, it is unlikely that exceedences would be detected at these facilities.

Regulatory Permits

The EPRI comanagement survey collected information on whether units were covered by a

regulatory permit and on the nature of the permitting agency (i.e., state, federal, or local). As shown in

Table 3-15, the majority of comanagement facilities operate under a permit. Landfills are slightly more

likely to face permitting requirements than are surface impoundments. In most cases, the permitting

agency is a state government. Fourteen units (seven each of landfills and surface impoundments) are

subject to the requirements of more than one permitting authority. Information on the degree of

environmental protection required by these permits was not collected in the EPRI survey.

3.3.5 Beneficial Uses

In addition to traditional waste management in landfills and surface impoundments, UCCWs can

be used in a variety of applications. Table 3-16 shows that substantial quantities of UCCWs currently are

diverted from traditional management into beneficial use. An examination of historical data indicates

that beneficial use of UCCWs has increased steadily over the past three decades (ACAA, 1996b; ACAA,

1998). Given the prevalence of comanagement, EPA believes that the quantities of UCCW used in some

of these applications include comanaged wastes.

Categories of beneficial use include cement and concrete products, construction fills (including

structural fill, flowable fill, and road base), agricultural uses, waste management applications, mining

applications, and incorporation into other products. These beneficial uses are in varying stages of

development. Some, such as minefilling and use in cement, have received widespread acceptance. 

Others are at the stage of pilot testing or bench-scale examination.
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March 1999 3-35

Figure 3-11. Trend in Comanagement Unit Ground-Water Monitoring

Source: EPRI, 1997a

The paragraphs below discuss the extent to which comanaged wastes may be amenable for these

beneficial uses. Box 3-5 describes some of the major uses that may be potential management alternatives

for comanaged wastes.

The extent to which comanaged wastes are amenable to beneficial use depends upon the specific

use being considered. Some of the most developed uses, particularly in cement and waste stabilization,

have met with success because of the pozzolanic or cementitious properties of some UCCWs (meaning

that these wastes react with lime and water or water alone to form a hard matrix). Other uses, such as

structural fill, snow and ice control, and blasting grit, take advantage of the physical properties (size

and shape) of UCCWs. Agricultural uses have received some attention because of UCCW chemical

properties (lime content and the presence of trace metal nutrients). The differences between comanaged 
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3-36 March 1999

UCCWs and UCCWs managed alone may be of less concern when the comanaged wastes are used in

applications solely to enhance the physical characteristics of a material (i.e., flowability, compressibility,

and unit weight). However, changes in the chemical composition of UCCWs when comanaged may

affect their advantageous pozzolanic or cementitious properties, particularly in applications benefitting

from the incorporation of fly ash. Also, the management of UCCWs prior to their use can affect the

types of uses for which they are amenable. According to the American Coal Ash Association’s (ACAA)

statistics, when UCCWs are managed in a surface impoundment prior to use, they are much less likely to

be used for cement or concrete products and much more likely to be used in structural fills, mining

applications, or as blasting grit (ACAA, 1998).

Comanagement may have a particular impact on cement and concrete applications. As shown in

Table 3-16, the major application of fly ash, and that of UCCWs taken together, is in the production of

cement and concrete products. When used alone, fly ash imparts added flowability to fresh concrete due

to its spherical shape and fineness. Additionally, the pozzolanic properties of fly ash increase the

comprehensive strength and the durability of the final concrete product. Excessive amounts of unburned

carbon, high moisture, and low amounts of silicon, aluminum, and iron oxides in fly ash when improperly

managed or when comanaged can increase its variability and interfere with the chemical reactions,

ultimately degrading the quality of the cement or concrete product. This is of particular concern in

structural grade concrete. Therefore, the American Society for Testing and Materials (ASTM) has

Beneficial Use

Volume in Tons

Percent of

Fly Ash Generation

Bottom

Ash Boiler Slag FGD Waste All Wastes

Cement and Concrete Products 9,421,903 604,705 10,755 202,423 10,239,786 9.7%

Structural Fill 2,877,535 1,384,327 84,669 91 4,346,622 4.1%

Waste Stabilization/Solidification 3,117,947 206,368 0 15,428 3,339,743 3.2%

Road Base/Subbase 1,417,600 1,286,585 792 17,797 2,722,774 2.6%

Blasting Grit/Roofing Granules 0 159,749 2,288,581 0 2,448,330 2.3%

Mining Applications 1,413,567 162,638 0 104,690 1,680,895 1.6%

Wallboard 0 0 0 1,603,762 1,603,762 1.5%

Snow and Ice Control 0 723,615 56,057 0 779,672 0.7%

Mineral Filler 285,580 130,888 108,796 0 525,264 0.5%

Flowable Fill 386,158 15,260 0 0 401,418 0.4%

Agriculture 34,571 8,197 0 55,644 98,412 0.1%

Other 362,501 414,572 29,200 183,527 989,800 0.9%

Total Use 19,317,362 5,096,905 2,578,851 2,183,360 29,176,482 26.8%

Total Generation 60,264,791 16,904,663 2,741,614 25,163,394 105,074,462 100.0%

Percent of Generation Used 31.5% 27.7% 92.9% 7.9% 26.8%

Note: Individual values may not sum to totals due to rounding.

Source: ACAA, 1998

Table 3-16. Beneficial Use of Utility Coal Combustion Wastes in 1997
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-37

Construction Fills. Construction fills include structural fills, flowable fills, and road base and subbase

applications. Most of the bottom ash and a considerable portion of the fly ash utilized are applied in

construction fills. This application of UCCWs ranks second following the use of UCCWs in concrete and

cement products. In structural fills (e.g., backfills, embankments, area fills), fly ash and bottom ash replace

natural materials and provide additional benefits not obtained with conventional fill materials, such as low

compressibility, light unit weight, high shear strength, and pozzolanic properties. Unlike structural fills,

flowable fills, such as backfills and grouts, are placed in slurried form and, therefore, benefit from the added

flowability and strength development imparted by UCCWs. In road bases and subbases, the addition of UCCWs

allows for greater long-term strength development.

Waste Stabilization/Solidification. Because of their alkalinity and presence of solids, UCCWs are used to

chemically fix potentially hazardous wastes in a solid matrix. Through stabilization, hazardous organic and

inorganic constituents are immobilized and prevented from being released to the environment. Stabilization may

occur with or without solidification. Solidification consists, primarily, of converting soils, liquids, and sludges

into a solid, structurally sound material prior to disposal or further utilization of the material. Waste stabilization

and solidification represent the third largest beneficial use of UCCWs.

Blasting Grit/Roofing Granules. More than 2 million tons of UCCW, including almost all of the boiler slag

and some bottom ash generated in 1997, were used as blasting grit and roofing granules. Like sand, boiler slag

particles are used in sand-blasting operations and as roofing granules.

Mining Applications. Mining applications of UCCWs include controlling acid mining drainage, backfilling,

blending mine soils and spoils, and revegetation. UCCWs are used in remediation activities at coal mines

primarily because of their ability to neutralize the effects of acid drainage from mines and associated wastes. 

Mine subsidence problems from abandoned underground mines also are remediated by the use of these wastes as

backfills. In addition, UCCWs are applied at the surface to promote vegetative growth and serve as a soil cover

to prevent water infiltration to mine wastes.

Snow and Ice Control. Bottom ash and boiler slag are used as a substitute of salt for road de-icing operations. 

Approximately 780 thousand tons were used in 1997.

Mineral Fillers. Mineral fillers include a variety of fine particles that are incorporated into a broad range of

industrial products. UCCWs have been used or evaluated for use as substitutes for commercial fillers in asphalt

products, plastics, metal alloys, and fertilizers. The uses receiving the most attention are fly ash and boiler slag

in asphalt and plastics. Fly ash also has been proposed as a mineral filler in carpet backing, vinyl flooring,

joining and caulking compounds, industrial coatings and paints, and insecticides and pesticides. FGD sludges

may have some potential as mineral fillers but have received little detailed scientific or engineering evaluation. 

Finally, because natural gypsum filler products have attained some commercial acceptance, FGD gypsum also

has been considered for use as a filler, particularly in coated paper and joining compounds.

Agriculture. Fly ash, bottom ash, and FGD sludge are used for agricultural soil amendment. In general, these

wastes can benefit agricultural systems by changing physical and chemical characteristics of soils, thus

improving crop yield. UCCWs affect the chemical properties of soils by supplying essential plant nutrients for

crop production and by modifying the soil to create a more favorable medium for plant growth. Physical

changes brought about by UCCW amendments include reduced bulk density and increased aeration and water

filtration. The potential benefits of using UCCWs in agriculture include alleviating soil trace elemental

deficiencies, modifying soil pH, and increasing levels of needed calcium (Ca) and sulfur (S), infiltration rates,

depth of rooting, and drought tolerance.

Sources: ACAA, 1996b; ACAA, 1998; EPA, 1998h

Box 3-5. Potential Beneficial Uses for Comanaged Wastes
Report to Congress on Wastes from the Combustion of Fossil Fuels

3-38 March 1999

developed standard specifications for fly ash used as a mineral admixture in Portland cement concrete. 

Guided by these requirements, generators may use specialized fly ash management practices when use in

concrete is intended. These practices include segregating fly ash, as well as processing or cleaning the

waste, prior to its use. In many cases, these standards and preprocessing operations may preclude the use

of comanaged fly ash.

Another beneficial application considered waste-specific and, consequently, not suitable for

comanaged waste utilization is wallboard production. Because of its similarities to natural gypsum,

gypsum produced from FGD sludge is used as a substitute for the former in the manufacture of

wallboard. The strength per unit weight provided by FGD gypsum greatly depends on its purity. 

Impurities such as fly ash, as well as lime and limestone found in FGD gypsum, could adversely affect

the quality of the raw material and the final wallboard product.

The potential for beneficial use of comanaged wastes may be greatest in lower technology

applications with less stringent specifications and where large volumes of material are needed. The

feasibility of any specific use, of course, should be based on a detailed evaluation of the specific waste

and its potential impacts in application.

3.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE

ENVIRONMENT

Because of data limitations, EPA could not evaluate the site-specific potential for and historic

occurrence of damages throughout the universe of existing coal-fired utility comanaged waste sites. 

Instead, EPA developed a methodology for estimating the potential risks associated with comanaged

wastes relying on limited site-specific and industry-wide data, together with appropriate nationwide

modeling techniques. Site-specific and regional data provided for this analysis to EPA were combined

with nationwide environmental modeling data available to EPA from other modeling studies and from

EPA’s nationwide modeling database. EPA developed waste management scenarios representative of

industry practices and environmental settings. To provide confidence in its model results, EPA

conducted sensitivity analyses focusing on the driving model variables, and particularly on parameters

for which only limited data were available. EPA also examined a wide range of state agency and EPA

information sources to determine the past occurrence of damages at comanaged waste sites.

Previous work by EPA concluded that the greatest potential for harm from FFC wastes was

associated with the potential for ground-water contamination (EPA, 1988; EPA, 1993b). Current EPA

risk assessment policy also requires consideration of comprehensive human health risk (ground water and

non-ground water) and ecological impacts. Accordingly, this FFC waste risk assessment included two

components: the ground-water pathway human health risk assessment and the above-ground multipathway human health and ecological risk assessment. Section 3.4.1 presents the technical approach to

and results of the ground-water pathway human health risk assessment for comanaged wastes. Section

3.4.2 presents the results of the above-ground multi-pathway risk assessment, which was conducted in

close coordination with the ground-water study. Section 3.4.3 discusses potential and documented

damage cases.

3.4.1 Potential Ground-Water Risks to Human Health

This section summarizes EPA’s approach to and findings of its ground-water risk assessment

efforts. Results of this study were originally presented in the Technical Background Document for the

Supplemental Report to Congress on Remaining Fossil Fuel Combustion Wastes, Revised Draft Final

(EPA, 1998d). EPA received peer reviewer and industry comment on the June 1998 study (Peer Review
Report to Congress on Wastes from the Combustion of Fossil Fuels

3

 Available chromium data for comanaged wastes were limited to total chromium, which were used as a

conservative estimate of hexavalent chromium (CrVI) for screening purposes.

4

 Only two samples of comanaged waste leachate showed mercury concentrations above detection levels. 

Despite the low frequency of detection, mercury was carried forward in the analysis.

5

 This is in contrast with earlier FFC Waste (1993), Cement Kiln Dust, and Mineral Processing Waste

studies, in which a dilution factor of 10 was assumed to reflect a 10:1 dilution of leachate in ground water.

March 1999 3-39

of Fossil Fuel Combustion Risk Assessments: Original Comments from Peer Reviewers, July 1998) and

developed revised results in the October 1998 Fossil Fuel Combustion Waste Risk Assessment: Revised

Groundwater Analysis and Sensitivity Results (EPA, 1998f). Original reports and comments are

available in the docket supporting this report.

Overview of Approach

EPA followed a multistep assessment process including screening, deterministic modeling, and

probabilistic modeling to determine the nationwide potential for risks to human health from ground-water

contamination. EPA considered three individual receptors: an adult resident, a young child resident

(age 1–10), and a child resident (age 1–19). For each receptor, EPA developed separate risk estimates

for two waste scenarios: surface impoundments and landfills. See Chapter 2 of the Technical

Background Document for the Supplemental Report to Congress on Remaining Fossil Fuel Combustion

Wastes, Revised Draft Final (June 1998), available in the docket, for further discussion of the overall

approach.

To identify the waste constituents of potential concern, EPA first performed a “screening-level”

assessment. Screening involves comparing waste leachate concentrations with human health-based

concentrations (toxicity levels) to identify and eliminate from consideration those leachate constituents

too dilute to present risk even before transport in ground water to a receptor. The data provided to EPA

indicated that no organic compounds of concern are present in the ash. EPA found that many metals of

concern may be present in FFC waste leachates at concentrations greater than the corresponding healthbased benchmarks. Therefore, EPA focused its screening efforts on the following: antimony, arsenic,

barium, cadmium, chromium,3

 lead, mercury,4 nickel, selenium, silver, thallium, vanadium, and zinc. For

screening purposes, no dilution factor was assumed; leachate concentrations were compared directly with

toxicity levels.5

EPA selected the Composite Model for Leachate Migration with Transformation Products v1.2

(EPACMTP) to model the movement in ground water of metals of concern released from waste landfills

and surface impoundments. Waste management scenarios were developed for use with EPACMTP using

site-specific, industry-wide, and general nationwide information to estimate values for parameters

describing waste and management unit properties (e.g., unit size, waste density), unit environmental

settings (e.g., recharge rate, soil properties, ground-water velocity), and contaminant properties (e.g.,

retardation factors). Each scenario was used to predict the peak metals concentrations expected to occur

in a nearby drinking water well during a 10,000-year study period. Comparing the predicted peak

concentration with the health-based benchmarks, EPA estimated the risk to an individual receptor

exposed through ingestion of the contaminated drinking water.

EPA calculated estimated risks for each scenario by selecting combinations of variables most

likely to produce high-end (to include the 95th percentile of all possible risks) results. EPA then

performed probabilistic modeling to determine where the deterministic results fell within a distribution of
Report to Congress on Wastes from the Combustion of Fossil Fuels

6

 Note that since the number of values available for each constituent was generally less than 20, the 95th

percentile value generally was set equal to the maximum value observed.

3-40 March 1999

estimated risks. Finally, EPA performed sensitivity analyses to improve its confidence in the overall

estimate of risks. EPA varied individual variables and combinations of variables throughout wide ranges

of values, finding that model results changed very little except in response to the most sensitive

parameters (e.g., waste management unit size, waste concentration, receptor well location, contaminant

retardation rate). As part of the sensitivity analysis, EPA compared EPACMTP model results with the

output of an industry-sponsored model, MYGRT v 2.0, and found general agreement between the models

with respect to predicted down-gradient concentration and time to reach risk when similar input values

were used.

Calculation of Benchmarks

The starting point for the ground-water pathway risk assessment was the calculation of healthbased benchmark concentrations (“health-based levels” [HBLs] sometimes referred to as health-based

numbers or HBNs). Each HBL represents the concentration of a contaminant in drinking water to which

a specified receptor is exposed above which adverse health effects may be expected to result. The value

is calculated from a combination of toxicological information, ingestion rate, frequency and duration, and

receptor body weight.

Screening Assessment Results

As discussed in Section 3.2, EPA developed a profile of comanaged waste characteristics using

industry-provided data collected from comanaged waste landfills and impoundments. For

impoundments, EPA relied upon in situ pore water samples taken from waste drill cores. For landfills,

EPA used both laboratory leachate tests developed using the TCLP, and industry-provided water extract

data from in situ solids samples collected from several landfills. EPA calculated the 95th percentile waste

concentration for each metal of concern in comanaged wastes and compared it to the corresponding

HBL.6

 The results of the screening exercise, shown in Table 3-17, determined those constituents that

could be eliminated from further consideration, and those constituents warranting additional

consideration.

In the table that follows, and for all subsequent risk discussions, screening and modeling results

are expressed in terms of cancer risk or hazard quotients (HQ). Cancer risk, always expressed in powers

of ten, refers to the incremental individual lifetime risk of developing cancer. For this study, arsenic is

the only known carcinogen for which risks were calculated. For all other constituents of concern, results

are expressed as HQ. An HQ equals the modeled concentration level divided by the HBL.

It is important to note that the screening approach employed did not rule out many metals of

potential concern. In fact, the HQ for most metals was less than 10, such that employing a fixed groundwater dilution factor at this step would have eliminated many more metals from additional consideration. 

However, because preliminary modeling indicated that the predicted dilution factors might sometimes be

less than 10, EPA elected to adopt the more conservative approach described here.

Modeling Scenarios Considered

EPA developed contaminant transport model scenarios to estimate the level of ground-water

contamination that might result from the release of comanaged waste leachate from management units. 
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-41

Waste management scenarios were developed for use with EPACMTP using site-specific and industrywide information to estimate values for parameters describing the following:

• Waste and management unit properties (e.g., unit size, saturated hydraulic conductivity)

• Unit environmental settings (e.g., weather, soil properties, ground-water velocity and

volume)

• Contaminant properties (e.g., retardation factors).

EPA developed a central tendency scenario by setting all EPACMTP model parameter input

values at or near the midpoint of the range of values for the industry. EPA also developed a high-end

scenario by setting the two most significant parameters (waste concentration and receptor well location)

at their respective high ends. In addition to the high-end deterministic scenario, EPA used the Monte

Carlo capabilities of EPACMTP to perform a probabilistic assessment of risk for each waste management

scenario. The Monte Carlo analysis resulted in a distribution of risk estimates from 2,000 model runs in

which each of the model’s input parameters was allowed to vary independently. In accordance with

EPA’s current policy, with respect to measuring occurrence of risk, high-end risks and Monte Carlo

results are emphasized.

For comanaged utility wastes, EPA modeled landfills and surface impoundments. Risks from

minefills were evaluated using other analytical techniques primarily, as discussed below, due to

difficulties in modeling the movement of water through mining disturbed strata. (As noted in the

Constituent

Observed 95th Percentile

Concentration (mg/L) Screening Result 

Wastes Managed in Surface Impoundments

Arsenic 9.64 Risk = 3.3×10–2

Cadmium 0.156 HQ = 6.0

Chromium (as VI) 0.746 HQ = 5.0

Lead 0.468 31 times action level

Nickel 8.33 HQ = 8.1

Selenium 1.03 HQ = 4.0

Vanadium 0.8 HQ = 2.2

Zinc 23.1 HQ = 1.5

Wastes Managed in Landfills

Arsenic 0.24 Risk = 8.3×10–4

Barium 3.6 HQ = 1.0

Cadmium 0.044 HQ = 1.7

Selenium 0.44 HQ = 1.7

Thallium 0.015 HQ = 3.7

Notes: Constituents were evaluated at their high-end (95th percentile) concentration. Constituents that screen out are as follows: antimony,

barium, copper, mercury, and silver for surface impoundments; antimony, chromium, copper, lead, mercury, nickel, silver, and zinc for

landfills. Landfill data are calculated as presented in the October 10, 1998, Sensitivity Analysis.

Source: EPA, 1998d (Chapter 5)

Table 3-17. Constituents Remaining after Screening Analysis

for Coal-Fired Utility Comanaged Wastes
Report to Congress on Wastes from the Combustion of Fossil Fuels

3-42 March 1999

discussion of minefills, it is possible to approximate surface mine transport using the landfill scenario,

under certain conditions. The landfill scenario can not be used to approximate underground mine

transport, however.) Risk from agricultural application of comanaged waste is discussed in the nonground-water section below.

A complete listing of model input values is presented in the June 1998 Technical Background

Document for the Supplemental Report to Congress on Remaining Fossil Fuel Combustion Wastes,

Revised Draft Final (EPA, 1998d) and the October 1998 Fossil Fuel Combustion Waste Risk Assessment:

Revised Groundwater Analysis and Sensitivity Results (EPA, 1998f). All the above may be found in the

docket supporting this report.

Modeling Results

Table 3-18 summarizes selected results from the deterministic and probabilistic analyses of risk

from comanaged wastes for the adult receptor. Overall, EPA found that the risks associated with all

modeled constituents of concern, except for arsenic, fell below an HQ of 1 or a lifetime cancer risk of

1×10–6. Potential risks associated with arsenic in both the landfill and the surface impoundment high-end

deterministic scenarios exceeded 1×10–6.

Comparison of the deterministic and Monte Carlo results reveals that the deterministic results

always exceeded the 95th percentile Monte Carlo result. For example, none of the 2,000 Monte Carlo

simulation combinations of parameter values performed for arsenic for the surface impoundment scenario

yielded a risk estimate as high as the high-end deterministic result. Similarly, the high-end risk for

arsenic, chromium, nickel, and selenium from the comanaged waste landfill exceeded 99 percent or more

of the corresponding Monte Carlo simulation results. At the 95th percentile level, the arsenic risks

predicted by the Monte Carlo simulations of the landfill and surface impoundment scenarios were

roughly 1 order of magnitude or more below the corresponding risks estimated for the high-end

scenarios.

EPA also considered the time at which risks were predicted to result from the release of

constituents of concern in each of the scenarios. EPA found that the concentration of arsenic in ground

water at the receptor well would not reach the HBL for arsenic (e.g., achieve a risk level of 1×10–6) for

Scenario Constituenta

Deterministic

Risk, Central

Tendency

Deterministic

Risk, High-End

Corresponding

Monte Carlo

Percentile

Monte Carlo

95th Percentile

CSb Arsenic 3×10–6 5×10–4 >100 1.6×10–5

CLb Arsenic 4×10–7 3×10–4 >99.9 4.3×10–5

Chromium HQ <1 HQ = 0.2 >99.4 HQ = 0.1

Nickel HQ <1 HQ <0.1 >100 HQ = 0.01

Selenium HQ <1 HQ = 0.8 >100 HQ = 0.1

a

 All other metals modeled resulted in HQ <1

b

 CS = comanaged waste impoundment; CL = comanaged waste landfill

Note: Results shown are those from the October 10, 1998 Sensitivity Analysis

Table 3-18. Comparison of Deterministic and Monte Carlo Risk Model Results for

Comanaged Waste Ground-Water Pathway Scenarios
Report to Congress on Wastes from the Combustion of Fossil Fuels

7

 See EPA, 1998d, page 5-33.

8

 Ibid. The value shown here is for the FBC landfill. Based on sensitivity analyses and the change from

porewater to TCLP concentrations for landfill waste characterization, the time to reach peak will equal or exceed the

value reported for the FBC landfill.

March 1999 3-43

roughly 500 years.7 For the landfill, the predicted time to reach a risk of 1×10–6 or more was found to

exceed 3,500 years.8

Table 3-19 summarizes the estimated risks to adult and child receptors for the high-end

deterministic scenarios for comanaged wastes. Overall, the results show that for noncarcinogens the

risks for young children increased roughly twofold compared to the adult receptors. For arsenic, the risk

for young children increased roughly 25 percent compared to the adult receptors.

3.4.2 Potential Above-Ground Multi-Pathway Risks to Human Health and the

Environment

Human Health Risks

This section summarizes EPA’s approach to and findings of its above-ground human health risk

assessment efforts. Results of this study were originally presented in Non-groundwater Pathways,

Human Health and Ecological Risk Analysis for Fossil Fuel Combustion Phase 2 (EPA, 1998e). EPA

received peer reviewer and industry comment on the June 1998 study (Peer Review of Fossil Fuel

Combustion Risk Assessments: Original Comments from Peer Reviewers, July 1998) and subsequently

developed revised results. Original reports and comments are available in the docket supporting this

report.

Overview of Approach

As in the case for the ground-water risk assessment (Section 3.4.1), EPA conducted a broad

above-ground risk assessment to estimate potential risks associated with direct and indirect exposure to

wastes and waste contaminated media. EPA employed the Indirect Exposure Methodology (IEM) used in

several previous Office of Solid Waste (OSW) risk assessments (e.g., Cement Kiln Dust, Hazardous

Scenario Constituenta

High End Deterministic Risk

Adult Young Child Child

CSb Arsenic 5×10–4 6.3×10–4 4.4×10–4

CLb Arsenic 3×10–4 3.8×10–4 2.6×10–4

Chromium HQ = 0.2 HQ = 0.35 HQ = 0.22

Nickel HQ = 0.1 HQ = 0.2 HQ = 0.1

Selenium HQ = 0.8 HQ = 1.4 HQ = 0.9

a

 All other modeled metals yielded HQ <1

b

 CS = comanaged waste impoundment; CL = comanaged waste landfill

Note: Results shown are from the October 10, 1998, Sensitivity Analysis.

Table 3-19. Comparison of Adult and Child Risk Model Results for

Comanaged Waste Ground-Water Pathway Scenarios
Report to Congress on Wastes from the Combustion of Fossil Fuels

3-44 March 1999

Waste Identification Rule). Using IEM, EPA estimated the concentration of constituents of concern in

air, soils, and plant and animal tissues resulting from airborne and waterborne releases of comanaged

wastes. EPA then estimated the human health risks associated with exposure to the contaminated media

for a wide range of exposure scenarios. To provide confidence in its model results, EPA conducted

sensitivity analyses for each scenario, constituent, and receptor, focusing in particular on those driving

parameters for which only limited information was available.

IEM considers two major release mechanisms: wind erosion and surface water erosion and

runoff. EPA concluded that these releases may occur in three comanaged waste scenarios: active

landfills, dewatered surface impoundments without cover, and agricultural application projects where

comanaged wastes are employed as soil amendment. Estimation of waste management unit sizes and

waste characteristics for these scenarios was coordinated with the ground-water risk assessment for

consistency. For each scenario, EPA considered the following transport pathway and exposure routes:

• Inhalation of contaminants transported through air emission and dispersion. Only

concentrations of respirable PM 10 were considered for the inhalation exposure route.

• Ingestion of soil contaminated through deposition of air emissions and contaminated runoff. 

For the soil amendment scenario, soil was contaminated by intended application of the

waste product.

• Ingestion of fruits and vegetables contaminated through direct deposition to the plant and

deposition to soil with subsequent plant uptake. For root vegetables, contamination results

from deposition to soil followed by root uptake.

• Ingestion of beef and dairy products contaminated through cows’ ingestion of contaminated

soil, grain, forage, and silage. These media are contaminated via the same mechanisms

stated above.

• Ingestion of fish taken from an effected stream located near a waste management unit or

agricultural field, and contaminated by runoff, erosion, or direct deposition.

For each release pathway and exposure route, EPA considered a variety of receptors. These

included an adult and child resident near the waste management unit, a subsistence farmer and child of

subsistence farmer for the agricultural application scenario, and a subsistence fisher.

For each receptor, EPA calculated risk based on toxicological information, receptor-specific

exposure assumptions, and the predicted concentration of constituents of concern in the contaminated

media. EPA calculated central tendancy risks by setting all IEM model parameter input values at or near

the midpoint of the range of values for the industry. EPA also calculated high-end risks determining the

pair of parameters that, when placed at their respective high-end values, yield the highest estimate of risk

for the specific scenario.

Overview of Modeling Results

In essence, no risks from the ingestion exposure route were found in excess of 10–6 (cancer), or

with HQs in excess of 1, except for arsenic in the case of agricultural applications and when managed in

an onsite active landfill. For both the landfill and the impoundment, for arsenic, ingestion risks were

found at the 10–6 level for both the farmer and the child of the farmer. In the agricultural use scenario,

EPA found arsenic risks from this composite and complex pathway to be at five times the 10–5 level (a
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-45

level consistent with the findings of EPA’s ongoing cement kiln dust evaluation in which the arsenic

waste concentrations were similar to, but slightly below on average, those of FFC total wastes). While

some other risks at the “10–6 or hazard quotient of 1" margin were found, the very conservative nature of

the analysis combined with the intrinsic cementitiousness of the ash (meaning it will harden and not

blow, erode, or runoff as readily as otherwise—a consideration difficult to simulate) together lead EPA

to conclude, with the same data sufficiency caveat as for ground water, that only the agricultural use nonground-water pathway poses meaningful risk.

Table 3-20 summarizes the differences between adult and children’s above-ground risk where the

risk exceeded 10-6.

Risks in the 10–6 range were found for inhalation exposure route for chromium. It should be

noted that only total chromium was reported. For this assessment chromium was modeled as the more

toxic chromium VI valence—a conservative assumption. This, coupled with other conservative

assumptions (including the cementitiousness issue) leads EPA to believe that there are no plausible

excess risks from the inhalation exposure route.

Ecological Risks

EPA has developed explicit guidelines to evaluate the ecological risks associated with chemical

and non-chemical stressors (see EPA, 1998g). Consequently, EPA developed a technical approach that

was consistent with the guidelines and addressed the management goal for the ecological risk analysis,

succinctly stated as follows: “to evaluate the potential for adverse ecological effects associated with the

management and/or use of comanaged FFC residuals anywhere within the contiguous United States.”

The Guidelines (EPA, 1998g) describe the three basic phases that frame the ecological risk

assessment process: problem formulation, analysis, and risk characterization. In brief, these phases may

be summarized as follows:

• Problem formulation phase. During this phase, the problem statement is developed within

the context of stated management goals and constraints on resources and timeframe. The

endpoints for the analysis are selected, a conceptual model is developed, and an analysis

plan is prepared for estimating exposure concentrations and risks. The conceptual model

identifies ecological receptors potentially at risk and relevant exposure pathways. For

rulemakings intended to be national in scope, assessment endpoints and measures of adverse

effects are often chosen to be broadly applicable across the United States.

Scenario Constituent

High End Deterministic Risk

Adult* Child

Utility Coal Landfill Arsenic 2.5×10–6 1.7×10–5

Utility Coal Dewatered

Impoundment

Arsenic 2.1×10-6 2.0×10–6

FBC Waste Landfill Arsenic 1.0×10-6 8.2×10-6

* High-end deterministic risk from ingestion. The very slight differences for the landfills are not considered significant, primarily due to the

cementitiousness of the ash.

Table 3-20. Comparison of Adult and Child Risk Model Results for

Comanaged Waste Above-Ground Ingestion
Report to Congress on Wastes from the Combustion of Fossil Fuels

9

 Resource constraints, in combination with analytical difficulties associated with estuaries, did not permit

specific estuarine analysis.

3-46 March 1999

• Analysis phase. The analysis phase involves the use of simulation models to predict

constituent concentrations in the environment to which ecological receptors are exposed

(i.e., exposure profile). In addition, this phase describes how ecotoxicological data are used

to develop appropriate measures of adverse effects to various ecological receptors (i.e.,

stressor-response profile). The simulation models are mathematical constructs that

represent fate and transport processes from source releases into various environmental

media where they may be taken up by plants and animals.

• Risk characterization phase. Characterizing ecological risks often involves the

comparison of predicted exposure concentrations to chemical stressor concentration limits

(CSCLs) for soil, sediment, and surface water intended to represent de minimus risks to

wildlife. The comparison of predicted exposure concentrations to CSCLs is generally

referred to as the HQ approach and provides a quantitative indication of the potential for

adverse ecological effects. The HQ results are accompanied by a narrative explanation of

the assumptions, limitations, and uncertainties inherent in the assessment. The relevance of

the findings to the management goals and the ecological significance of potential effects (as

indicated by the HQ values) also are discussed.

The ecological risk analysis was implemented using a tiered approach that proceeded from

conservative onsite screening evaluations to increasingly detailed assessments of representative

ecological receptors exposed to chemical releases simulated from comanagement facilities (e.g., surface

impoundments, landfills). Chemical concentrations in comanagement facilities were identified from

available data distributions and high-end (approximating the 95th percentile) and central-tendency

(approximating the 50th percentile) concentrations were simulated. The same fate and transport models

used to simulate chemical movement through the environment and resulting human exposures also were

used to predict ecological exposures. In essence, the similarity in exposure pathways for human and

ecological receptors allows similar fate and transport models to be used for both components of the

analysis.9

 The exposure concentrations predicted for environmental media in generalized freshwater and

terrestrial habitats were compared to the CSCLs for representative ecological receptors, including species

of mammals, birds, and amphibians, as well as collections of soil, sediment, and surface water organisms. 

Because the intent of this analysis was to identify the potential for adverse ecological effects,

conservative benchmarks for “no adverse response” were chosen whenever they were available. These

benchmarks often are based on subchronic studies at low chemical concentrations for sensitive endpoints,

such as developmental effects. For amphibians, however, the adverse effects benchmarks were based on

relatively high levels of lethality (typically 50-percent lethality).

The risk estimates (i.e., HQ results) for landfills and land application units suggest that

ecological risks associated with the release and surface transport of chemicals of concern are not likely to

be significant for these management/use practices. Because these results are generally based on no

effects levels for mammals and birds, it is expected that even threatened and endangered mammalian and

avian species are unlikely to receive exposures that would warrant concern. It is difficult, however, to

provide unequivocal support to that assertion without the benefit of a more site-based analytical

framework. In addition, the subsurface pathway was not evaluated in this analysis, and there is some

concern that this pathway may be significant in areas with high water tables that intersect critical

wetlands and estuarine systems.
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March 1999 3-47

The risk estimates for comanaged coal ash surface impoundments and associated drainage

systems indicate that this scenario is of special concern. Wildlife frequently utilize surface

impoundments and nearby wetlands as part of their habitat and, in particular, the HQ ratios for

amphibians indicate that the chemical concentrations in surface impoundments may be associated with

high levels of lethality (i.e., the CSCLs for amphibians correspond to 50-percent lethality). Amphibian

sensitivity to these trace metals has been demonstrated in case studies on FFC residuals, and selenium

and aluminum are believed to be particularly toxic to amphibian species. In contrast, the risk estimates

shown for mammals and birds may predict more subtle effects on reproductive capacity and the HQ

ratios are based on no adverse response levels. In addition, the probability of wildlife being directly

exposed to surface impoundment water will vary depending on the surrounding habitat and the location

of the impoundment, so there is considerable uncertainty associated with these risk estimates. The most

likely receptor to be exposed would be avian species that are able to circumvent barriers to forage or nest

in pond areas. Transitory exposures to migratory birds are possible during seasonal migrations and

longer-term exposures are possible depending upon the nesting behavior of a given species. Although

this exposure scenario may affect relatively few species, the local effects on a particular species or

habitat may be undesirable. Table 3-21 summarizes the HQ results for surface impoundments for highend and central-tendency chemical concentrations.

3.4.3 Documented Damages to Human Health and the Environment

Summary of Findings

EPA identified a total of six sites at which comanagement of coal combustion wastes has

occurred and which meet the “test of proof” for damage cases (see Section 1.4.3). Five of these sites

were previously identified in the 1988 Report to Congress and the 1993 Regulatory Determination (58

FR 42473, 8/9/93). A sixth site was more recently identified by EPA. Detrimental effects from these

sites included the presence of contaminants in drinking water wells above MCLs and vegetative damage

in wetlands or streams.

EPA finds that most of the sites showing damages are older unlined units. In most cases, the

units are closed and stopped receiving wastes in the 1980s and may not have used management practices

similar to those used today. At the same time, the damage cases demonstrate the potential for comanaged

wastes to present a danger to drinking water supplies or the environment.

Based on information available and consideration of EPA’s “tests of proof,” EPA identified the

cases in Table 3-22 as potential damage cases.

Constituent High-End HQ Central Tendency HQ Receptor Group

Aluminum 10 1 Amphibians

Arsenic 19 <1 Birds

Boron 16 <1 Amphibians

Selenium

29,622 153 Mammals

5 <1 Amphibians

a For this pathway, standing water samples collected from surface impoundments were used to represent media

concentrations. No fate and transport modeling was conducted.

Table 3-21. Summary of Ecological Risk Results for Comanaged Waste Impoundmentsa
Report to Congress on Wastes from the Combustion of Fossil Fuels

10 Based on the limited data discussed in Section 3.2.3, waste from coburning coal and petroleum coke may

be higher in vanadium on average than UCCWs. Therefore, ash from petroleum coke may be a more likely source

of vanadium than ash from coal combustion.

3-48 March 1999

Damages from Comanaged Wastes Identified in the 1988 Report to Congress and 1993

Regulatory Determination

In the 1988 Report to Congress, EPA identified two sites that meet the “test of proof” criterion

for damage cases. In preparing the 1993 Regulatory Determination, EPA identified four additional sites

meeting the test of proof. EPA determined that four of these six damage cases were associated with

comanagement. These findings were presented in the 1993 Regulatory Determination. With the

exception of one site (i.e., Faulkner), EPA did not conduct further research or investigation of these

sites beyond what was presented in the record for the 1993 Regulatory Determination. The four

comanagement sites are discussed below.

• Chisman Creek, Virginia (described in the 1988 Report to Congress). Fly ash and bottom

ash from the burning of coal and petroleum coke were managed in a disposal pit. The site

was on the National Priority List as of 1988. Drinking water wells became green from

vanadium and selenium contamination, and contained selenium above the primary MCL and

sulfate above the secondary MCL.10

Damage Case Wastes Present Event Test of Proof Comment

Coal-Fired Utility Comanaged Wastes

Chisman Creek (VA)

(88)

Petroleum coke and

coal ash landfill

Vanadium, selenium, and

sulfate in ground-water

wells

Scientific/

Administrative

Other possible sources

of contamination; 1 of 2

major cases cited in

Report to Congress

Faulkner Offsite

Disposal Facility (MD)

Coal ash and pyritic mill

rejects

Landfill and collection

pond seepage and

discharges resulted in

plant and fish impacts to

adjacent wetlands; pH

the major COC

Scientific/

Administrative

Remediation included

pond liners, landfill

cover, and sequestration of pyrites

DPC – Old E.J.

Stoneman Ash Pond

(WI)

Coal ash, demineralizer

regenerant, other water

treatment wastes

‘Gross contamination’ by

pond cited by State –

MCL exceedences of Cd,

Cr, Zn, and sulfate; B

near 5 mg/L in private

well

Administrative Closure plan required

relocating town water

supply well

Basin Electric W.J.

Neal Station (ND)

Coal ash and sludge;

comanaged wastes

probable

Cr and other metals

detected in downgradient

sediments, ground water

Administrative

(limited information

available)

Site closed and capped

and pending NFRAP

(No Further Remedial

Action Planned)

VEPCO – Possum

Point (VA)

Coal ash, pyrites, oil

ash, water treatment

wastes, and boiler

cleaning wastes

Ground water

contaminated with Cd

and Ni, attributed to

pyrites and oil ash 

Administrative Response included

sequestration of oil ash,

pyrites, and metal

cleaning wastes to

separate lined units.

Table 3-22. Damage Cases
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-49

• Possum Point, Virginia (described in the 1993 Supplemental Analysis). At this site, oil

ash, pyrites, boiler chemical cleaning wastes, coal fly ash, and coal bottom ash were

comanaged in an unlined pond, with solids dredged to a second pond. Levels of cadmium

above 0.01 mg/L were recorded prior to 1986 (the primary MCL is 0.005 mg/L). After that

time, remedial actions were undertaken to segregate wastes (oil ash and low volume wastes

were believed to be the source of contamination). Following this action, cadmium

concentrations were below 0.01 mg/L.

• Faulkner, Maryland (initially described in the 1993 Supplemental Analysis). Pyrites, fly

ash, and bottom ash were comanaged in unlined landfills. In 1991, the state of Maryland

found that water quality in a nearby stream and creek were degraded by landfill leachate,

with effects including orange staining from iron precipitation and low pH (3 to 4). 

Vegetative damages also were observed. An underlying aquifer was found to be affected by

the landfill leachate. The acidic leachate was believed to have resulted from pyrite

oxidation. Remedial measures at the site included closure and capping of older units,

installation of liners in newer units, and discontinuing mill reject comanagement at the

facility.

• Old E.J. Stoneman Ash Pond, Wisconsin (described in the 1993 Supplemental Analysis). 

Ash, demineralizer regenerant, and sand filter backwash were managed in an unlined pond

from the 1950s to 1987. Nearby private drinking water wells had elevated levels of sulfate

and boron relative to background. Monitoring wells installed around the pond showed

exceedences of the primary MCL for cadmium and chromium, but these constituents were

not detected in the drinking water wells. As a result of the presence of indicator parameters

in the drinking water wells, the state concluded that other parameters may reach the wells in

the future and therefore required the operator to close the site and provide alternative

drinking water to the affected residences.

Additional Damages Identified Since 1993

Since 1993, EPA has become aware of additional candidate damage cases involving comanaged

wastes. EPA used information supplied by EPRI regarding 14 comanagement sites, as well as other case

study reports, and conducted a search of the Comprehensive Environmental Response, Compensation,

and Liability Act of 1980 (CERCLA) Information System. In a number of cases, EPA found that

comanagement units have affected ground-water quality, a conclusion which is supported by EPRI’s

work. Only one of the cases reviewed by EPA, however, meets the Agency’s “test of proof” to be

considered a damage case for purposes of this investigation. This case, the Basin Electric Surface

Impoundment (BESI) site, was identified through the CERCLA information system. Significant findings

regarding this site are summarized below.

The BESI site at the WJ Neal Station in Velva, North Dakota, is an unlined, diked impoundment

that received various construction debris and ash from the burning of sunflower seed hulls as well as fly

ash and sludge from a nearby coal-fired power plant from the 1950s until the late 1980s. A site

inspection report and power cooperative records from BESI confirmed that fly ash and sludge from

BESI’s coal-fired power plant were deposited in the impoundment. Monitoring efforts and negotiations

for plant closure began in 1982 after chromium was found at 8.15 parts per million (ppm) in the sludge

pond, in excess of the standard for chromium. A Preliminary Assessment in 1989 indicated migration of

contaminants into the underlying aquifer that supplies Velva with drinking water, although sampling data

were not provided. Areas of soil contamination within the impoundment were consolidated and the
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3-50 March 1999

impoundment was capped when the site was closed in 1990. EPA has concluded the contamination was

a result of activity that occurred before the cap was in place.

3.4.4 Compliance History of the Fossil Fuel Electric Power Industry

To further characterize the environmental impacts of the fossil fuel electric power generation

sector, EPA examined the sector’s compliance, enforcement, and legal history. The data utilized in this

section were gathered from the 1997 Fossil Fuel Electric Power Generation Sector Notebook (EPA,

1997c), which obtained data from EPA’s Integrated Data for Enforcement Analysis (IDEA) database

system. Since the IDEA system accesses data through Standard Industrial Classification (SIC) codes,

information in the Sector Notebook deals only with those facilities whose primary SIC codes indicate the

potential for power generation activities.

A review of the compliance history of the industry in the 5 years from 1992 to 1997 indicates the

following:

• Of the 3,270 facilities identified as power generators, approximately 66 percent (2,166)

were inspected during the 5-year period.

• The 14,210 inspections conducted during the 5-year period lead to 403 facilities having 789

enforcement actions taken against them.

• The sector had an average enforcement-action-to-inspection ratio of 0.06 during this 5-year

period.

A comparison with other sectors identified by the Sector Notebook project revealed the

following:

• When compared to sectors with similar number of facilities, a much higher percentage of

facilities in the power generation sector were inspected during this 5-year period. 

Moreover, the number of inspections during the 5 years for the fossil fuel electric power

generation sector is more than three times the number conducted in most other sectors.

• The enforcement-action-to-inspection ratio of 0.06 during the 5-year period is one of the

lower rates of the listed sectors.

In addition, a comparison of the data across sectors by environmental statute indicates that both

inspections and enforcement actions at electric power facilities are driven by air regulations. The

majority of electric power facility inspections (57 percent) and enforcement actions (59 percent) are

under the Clean Air Act (CAA).

Lastly, the number of major environmental cases to affect the fossil fuel electric power industry

is small. Even though there were 789 total enforcement actions between 1992 and 1997, there were few

major cases involving fossil fuel electric power generation facilities. Since 1992, there have been at least

13 such actions. None of the cases were for violations of regulations directly related to the management

of solid or hazardous wastes. The 13 cases were broken out as follows:

• Six cases under the CAA (emissions standards for asbestos, nitrogen oxide monitoring

violations, and sulfer dioxide violations)

• Two cases under the Clean Water Act (CWA) (discharge permit violation, wetlands)
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March 1999 3-51

• Two cases under the Toxic Substances Control Act (TSCA) (polychlorinated biphenhyls, or

PCBs)

• Two cases under the Emergency Planning and Community Right-to-Know Act (EPCRA)

(release in excess of reportable quantities)

• One multimedia case (CWA, EPCRA, and TSCA).

The average penalty associated with these cases was more than $150,000.

The two most significant cases against fossil fuel electric power generation facilities included

CWA violations by Potomac Electric Power Company (PEPCO) and CAA violations by Public Service

Electric & Gas (PSE&G). In the PEPCO case, the violations occurred between 1988 and 1993, during

which time a site supervisor either pumped or oversaw the pumping of polluted water from holding

ponds into an adjacent swamp. PEPCO discovered the illegal discharge and informed EPA. The consent

decree provides for a penalty of $975,000. Because the violation was self-disclosed, no criminal charges

were brought against the company or its officers.

In United States v. Public Service Electric & Gas, PSE&G was charged with violating the CAA,

specifically the National Emissions Standards for Hazardous Air Pollutants (NESHAP) for asbestos. An

off-duty EPA inspector noticed a pile of old pipes in a yard. A subsequent inspection of the old gascracking operation revealed the NESHAP violations. PSE&G was required to pay a civil penalty of

$230,000 and complete an extensive worker training and notification program.

3.4.5 Minefill Risks

EPA has found that operators may use or dispose of UCCWs in a variety of mining applications. 

Ash has been used for surface mine reclamation, mine subsidence control, mine water management,

waste stabilization, and other applications. In addition, surface and underground mines have been used

for locating ash and/or sludge landfills. While currently available statistics indicate that beneficial use in

mine environments accounts for less than 2 percent of large volume wastes generated (ACAA, 1998),

EPA believes that mine use and disposal of FFC wastes may increase. 

EPA believes that, under ideal circumstances, placement of wastes in mines should present no

increased risks to human health and the environment relative to conventional landfills. In fact, minefills

could result in net environmental benefits relative to conventional landfills through avoided development

of Greenfield space for UCCW disposal, improvement of disturbed mine lands through contouring,

revegetation and reduced infiltration to mine workings, and abatement of acid mine drainage through

neutralization and diversion. Both surface and underground minefills, however, may present existing or

potentially emerging conditions that are quite distinct from ideal landfill conditions with respect to

environmental risks. Some potential minefill conditions are introduced below.

• Fractured flow. Many surface mines are characterized by underlying fractured

hydrogeologic formations that may permit channel flow of contaminated ground water. 

Moreover, underground mines may present channels for mine water movement that extend

for miles. Fractured flow conditions present the possibility that contaminated ground water

can move considerable distances to reach potential receptors.

• Acid mine drainage. Many coal mine environments, particularly in the eastern United

States, are impacted by acid mine drainage (AMD), in which sulfide minerals associated
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3-52 March 1999

with the coal seam oxidize in the presence of air and water to produce sulfuric acid. The

resulting acidic leachate can mobilize constituents of concern from surrounding host rock. 

Some mine reclamation projects rely on the available alkalinity of UCCWs to reduce the

potential for generation of acid from sulfide minerals in mine spoils. In other cases, the

hope is that alkaline UCCWs will neutralize mine waters already impacted by pyrite

oxidation. If the available alkalinity in UCCWs is consumed by AMD, however, continued

leaching may mobilize the constituents of the ash or sludge.

• Intersection with ground water. Many surface and underground mines are completed

below the natural level of ground water surrounding the excavation. During active

operations, mine water must be pumped from the mine pit or void to allow access to the

resource. In such instances, mine water will flood the mine workings once active operations

cease. Some mine placement projects rely on the self-cementing or augmented cementing

properties of UCCWs to seal mine workings and limit mine water intrusion. Other projects

have demonstrated that, once placed, UCCWs may harden to form mine water diversions. 

Placement of UCCWs in mines completed below the water table will result in inundation of

the wastes. Inundation may result in continued leaching of constituents of concern from the

wastes.

EPA intends to evaluate the risks associated with mine placement of FFC wastes. Gaps in

currently available information and modeling complications prevented EPA from completing its

evaluation of minefill risks for this report. 

Case studies, when available, are preferable to modeling; however, EPA does not have detailed

case studies that present sufficient information to evaluate the performance of minefill projects. Many of

the sites for which the Agency does have information lack background characterization and well location

information such that pre- and post-placement conditions cannot be compared and conditions below the

fill cannot be related to the fill activities.

EPA currently lacks sufficient information to generalize about the background conditions at mine

sites. The potential transport of constituents of concern depends in part on the geochemical conditions of

receiving waters. Background pH plays an especially important role in precipitation/dissolution

chemistry as leachate enters ground water. EPA has demonstrated the sensitivity of EPACMTP to

changes in pH for some metals of concern; however, the Agency has insufficient information to

characterize the background conditions in ground waters at surface and underground coal mines. 

Background characterization is especially important in minefill evaluation because many mine sites are

characterized by very poor existing ground-water quality, including low pH.

Another important consideration is depth to ground water. The depth to ground water can play

an important role in attenuating constituents of leachate released from waste management units. EPA is

aware that some states restrict the placement of UCCWs in beneficial use projects from placement within

some minimum distance above ground water. Most of the site-specific information that EPA has

obtained to date, however, does not indicate the depth to ground water.

EPA also has insufficient information on the design of actual minefill projects. The Agency has

reviewed limited technical information on a variety of minefill projects, but lacks sufficient information

to generalize about the size, depth, and environmental controls (e.g., liners, covers, monitoring)

characterizing minefill projects nationwide. EPA is aware that some operators amend existing mine

spoils with UCCWs in conjunction with reclamation plans. EPA is unaware of typical mixing ratios in
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March 1999 3-53

such projects. Similarly, the Agency needs information about typical resulting permeability ranges for

combined ash and spoils or other fill materials.

Minefill scenarios present significant modeling challenges as well. First, EPACMTP does not

accommodate fractured flow conditions. As a result, underground and some surface mine situations

cannot be modeled using this tool. Further, EPA has not developed or identified a model suitable for

predicting the emergence of acid generating conditions within UCCW minefills. Of equal importance,

EPA has not identified a model suitable for predicting the consumption of alkalinity in UCCW materials

by AMD intrusion into the fill.

3.5 EXISTING REGULATORY CONTROLS

EPA’s objective in this section was to identify and evaluate the existing regulatory controls that

pertain to the comanagement of UCCWs. The regulatory analysis is directed toward addressing the

question of whether existing regulations are adequately protecting human health and the environment. 

The analysis also is helpful in understanding waste generation and current management practices.

The sections below discuss regulations addressing air pollution, water pollution, and solid and

hazardous waste, respectively. Air regulations are relevant primarily because of their effect on waste

generation. Water regulations have an influence both on waste generation and management and, in

particular, address the impact of UCCWs on surface waters. Solid and hazardous waste regulations are

of the greatest interest because they directly govern waste management practices.

The sections below describe federal regulations in each of these areas. In many cases, the

implementation of these federal programs is carried out by the states; therefore, where appropriate,

aspects of state implementation also are discussed. Because the nuances of state implementation are of

particular importance with respect to solid waste regulation, that section discusses state programs in

detail. Where appropriate, that section also describes state control on two beneficial uses of concern to

EPA: minefilling and soil amendment.

3.5.1 Regulations Addressing Air Pollution

The CAA is intended to protect and enhance the quality of the nation’s air resources. The most

relevant of the CAA requirements include the following:

• National Ambient Air Quality Standards (NAAQS) for particulate matter (PM)

• NAAQS for sulfur dioxide

• Title IV acid rain provisions

• NAAQS for ozone

• National Emissions Standards for Hazardous Air Pollutants (NESHAP).

Historically, CAA requirements have been a significant factor affecting the generation and

collection of certain large-volume UCCWs (specifically fly ash and FGD waste). Recent and

forthcoming changes in these requirements also may impact waste generation or characteristics, as

discussed below.
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3-54 March 1999

NAAQS for Particulate Matter

The NAAQS for PM establish maximum concentrations of PM with diameter less than or equal

to 10 micrometers (PM10) in the ambient air. These standards are among the factors motivating the use

of particulate control technologies at coal-fired utilities. EPA recently proposed to lower the size

criterion to 2.5 micrometers, which may affect the volume of fly ash collected and selection of control

technology; however, final standards will not be issued for at least 5 years, so the impact of the new size

criterion is difficult to predict at this time.

The NAAQS for PM are implemented through New Source Performance Standards and State

Implementation Plans.

New Source Performance Standards (NSPS). The NSPS subject newly constructed or

modified units to specific PM emissions limits. These limits may be met by changing fuel types,

modifying combustion conditions, or installing control devices. The applicability of the NSPS and the

specific limits imposed vary with the age and size of the combustion unit, with older and smaller units

less likely to be subject to the NSPS. Specifically, the regulation of facilities can be considered in the

following four categories.

• 40 CFR 60 Subpart D governs the standards of performance for new fossil fuel-fired steam

generators that were constructed or underwent major modification after August 17, 1971. 

Subpart D affects only units that are capable of burning fossil fuels at greater than 73

megawatts (MW) of heat input rate.

• Subpart Da affects utility units with the capacity to fire fuel at greater than 73 MW heat

input rate that commenced production or major modification after September 18, 1978.

• Subpart Db affects coal-fired units with the capacity to fire fuel at greater than 29 MW of

heat input rate that commenced construction or modification after June 19, 1984.

• Subpart Dc governs coal-fired units constructed or modified after June 9, 1989, with

capacity to fire fuel at less than 29 MW but greater than 8.7 MW of heat input rate.

Under the NSPS regulations, facilities that were in operation before the dates stated in each of

the four subparts are considered “grandfathered” and would not be subject to the newer standards, unless

they underwent a major modification.

State Implementation Plans (SIPs). The performance standards above can be enforced by a

federal, state, or local regulatory agency. There are additional CAA regulations that could require a coalfired unit to install a particulate removal device notwithstanding the grandfather clause in Subparts D,

Da, Db, and Dc. SIPs may impose, on a state-by-state basis, PM controls of varying stringency on

specific sources or categories of sources, including coal-fired utilities. Such controls are required under

Title I of the CAA if a particular area is in nonattainment for the NAAQS for a criteria pollutant such as

PM. For this reason, SIP controls will generally be more stringent in such nonattainment areas. In

attainment areas, the prevention of significant deterioration (PSD) program requires new sources to apply

Best Available Control Technology (BACT), which must be at least as stringent as NSPS.
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March 1999 3-55

NAAQS for Sulfur Dioxide and Title IV Acid Rain Requirements

Together, the NAAQS for sulfur dioxide and the Title IV Acid Rain Requirements are a factor in

the use of FGD technology at coal-fired utilities. Like the NAAQS for PM, the NAAQS for sulfur

dioxide establish a maximum concentration of sulfur dioxide in the ambient air. The NAAQS for sulfur

dioxide are implemented through NSPS and SIPs. The functioning and applicability of the sulfur dioxide

NSPS requirements are similar to those for PM, although there is less variation based on age and size.

Each of the four categories of coal-fired utilities regulated under Subparts D, Da, Db, and Dc is

subject to the same requirement: sulfur dioxide emissions must be less than 520 nanograms per joule

(ng/J) of heat input. Facilities with greater than 22 MW of heat input capacity generally also must

achieve a 10 percent reduction in their sulfur dioxide emissions, based on the potential concentration in

fuel. An additional category of coal-fired facilities, those constructed or modified after June 9, 1989, and

between 2.9 and 8.7 MW heat input capacity, also must meet the 520 ng/J standard, but may do so based

on certification from the fuel supplier that the sulfur content of the fuel is low enough to meet the

standards.

In addition to NSPS, states may impose controls through their SIPs to meet the sulfur dioxide

NAAQS. These controls may vary in stringency depending on attainment status and may be placed on

specific sources or categories of sources, including coal-fired utilities.

The Title IV acid rain provisions provide additional impetus for the application of FGD

technology at coal-fired utilities. These provisions require specific reductions of sulfur dioxide

emissions via the following:

• Installing FGD equipment

• Switching to low sulfur fuel

• Purchasing emissions allowances from other sources that have exceeded their reduction

requirements.

Affected sources are allowed complete flexibility in choosing among these options. The current

phase of the Title IV program affects several hundred of the largest generating units at utilities. Between

1992 and 1996, more than half of the affected facilities chose to switch to low sulfur coal in response to

the requirements; however, 16 utilities chose to install FGD equipment at 27 generating units accounting

for 14,101 MW of capacity (about 5 percent of 1997 utility coal-fired capacity) (EIA, 1997f). This

decision contributed to the growth in generation of FGD waste during the period.

EPA is currently evaluating further requirements for lower sulfur dioxide standards and

emissions that could increase desulfurization waste generation and/or continue to increase the use of low

sulfur coal. EIA projects that an additional 26,400 MW of capacity (about 9 percent of 1997 capacity)

will be retrofit with FGD technology in response to the next phase of requirements (EIA, 1998a). FGD

waste generation would increase as a result of these retrofits.

NAAQS for Ozone

The NAAQS for ozone establish a maximum concentration of ozone in the ambient air. EPA

recently lowered this concentration from 0.12 ppm to 0.08 ppm. The new standard allows four

exceedences of the maximum in a region over a 3-year period. EPA expects states will meet the new
Report to Congress on Wastes from the Combustion of Fossil Fuels

11 The RIA was based on a slightly more stringent ozone standard that allowed only three exceedences over

a 3-year period and also incorporated the impacts of proposed changes to the PM standard that have not yet been

finalized. Still, the general trends forecast by the RIA are expected to be valid for purposes of this analysis.

3-56 March 1999

standard by amending their SIPs to limit nitrogen oxide emissions at utilities. In proposing the new rule,

EPA published a Regulatory Impact Analysis (RIA) forecasting changes in the operating practices of

utilities that could result from these SIP modifications (EPA, 1997b).11 As a result of the new regulations,

utilities are expected to invest in new combined cycle gas-fired units and oil- or gas-fired combustion

turbines rather than coal-fired plants to provide new capacity. Coal-fired capacity is not expected to

increase through 2010 (EPA, 1997b). EIA similarly predicts only limited additions to coal-fired capacity

through 2010 (EIA, 1998a). Therefore, utility generation of ash is expected to increase more slowly than

in the past, even with continued growth in the utility industry.

The RIA also estimates that some existing coal-fired plants will retrofit scrubbers to comply with

the regulations. This could result in an increase in FGD waste generation. Also, plants that add

scrubbers are expected to switch from low-sulfur Western coal to less expensive Eastern coal, which

could result in some changes in waste characteristics (EPA, 1997b).

NESHAP

Under the NESHAP, EPA is required to establish technology-based standards for 189 hazardous

air pollutants (HAPs). These standards are to be set on an industrial category basis and will apply to

facilities (major sources) that emit greater than 10 tons/year of any one HAP or greater than 25 tons/year

of any combination of HAPs.

EPA has studied HAP emissions from utility coal-fired steam generating units and found that

mercury from coal-fired utilities is the HAP of greatest concern. Dioxins and arsenic (primarily from

coal-fired plants) also are of potential concern. EPA has deferred any determination as to whether

regulations to control HAP emissions from utilities are appropriate and necessary. EPA is continuing to

collect data on mercury emissions from coal-fired plants (EPA, 1998c). If HAP regulations are

promulgated in the future, they could affect the characteristics or quantity of FFC solid wastes.

3.5.2 Regulations Addressing Water Pollution

Under the CWA, the National Pollutant Discharge Elimination System (NPDES) controls

discharges to waters of the United States. The controls required under NPDES affect the collection and

management of UCCWs. In states authorized by EPA, these controls are implemented through state

programs (often termed State Pollutant Discharge Elimination Systems, or SPDES). Because state

programs must be at least as stringent as the federal program, the discussion here focuses on federal

requirements as a lowest common denominator. NPDES requirements apply differently to two categories

of discharges: process wastewaters and stormwater runoff.

NPDES Requirements for Process Wastewaters

The NPDES requirements that apply to process wastewaters from coal-fired utilities are those for

the steam electric point source category under 40 CFR Part 423. These requirements apply to facilities

“primarily engaged in the generation of electricity for distribution and sale” (i.e., utilities). Under these

requirements, each discharge requires an individual NPDES permit with numeric limitations based on

Best Practicable Control Technology Currently Available (BPT), Best Available Technology
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-57

Economically Achievable (BAT), or New Source Performance Standards (NSPS). Facilities that

discharge to publicly owned treatment works (POTWs) rather than directly to surface waters face

Pretreatment Standards for Existing Sources (PSES) similar to BAT or Pretreatment Standards for New

Sources (PSNS) similar to NSPS.

For the steam electric point source category, the NPDES process wastewater requirements most

relevant to collection and management of large-volume UCCWs are total suspended solids (TSS) limits

placed on fly ash handling and bottom ash handling waters. When these UCCWs are managed wet,

facilities may have to settle or otherwise remove a certain amount of UCCW from the handling water to

meet the TSS limits prior to discharge. Thus, the requirements control the direct release of fly ash and

bottom ash to surface waters. In addition, the NSPS include a zero discharge requirement for fly ash

handling water. As discussed in Section 3.3, this requirement may be partially responsible for the trend

toward dry ash management in newer units.

The NPDES requirements for process water also have elements that are relevant to low-volume

combustion wastes. These requirements include technology-based limits on the following waste streams: 

all waste streams (PCBs and pH); all low-volume wastes (TSS and oil and grease); chemical metal

cleaning waste (TSS, oil and grease, copper, iron); once-through cooling water (chlorine); cooling tower

blowdown (chlorine, chromium, zinc, 126 priority pollutants); and coal pile runoff (TSS). These

requirements control the release of the indicated constituents from management units to surface waters. 

To meet these limits, facilities may have to treat their low-volume wastes either prior to comanagement

or in the comanagement unit.

EPA has reserved NPDES limitations on non-chemical metal cleaning wastes and FGD waters

for future rulemakings. Future requirements may affect the characteristics of the low-volume wastes as

managed or of the combined wastes.

NPDES Requirements for Stormwater

NPDES stormwater requirements apply to stormwater runoff from FFC facilities (e.g., runoff

from operating areas, ash handling areas, waste management units). Facilities can meet these

requirements by including stormwater in their individual NPDES permit or seeking coverage under a

general permit by submitting a Notice of Intent (NOI). When stormwater discharges are covered under

an individual permit, control and monitoring requirements will be facility-specific, subject to the

judgment of the permit writer.

When covered by a general stormwater permit, requirements include implementation of a

stormwater pollution prevention plan, “reasonable and appropriate” control measures, and 1 or 2 years of

monitoring and reporting. No site visit by regulators is required under the general permit. Under the

general permit approach, coal-fired utilities have a great deal of flexibility in selecting appropriate

control measures for runoff that may have contacted large-volume CCWs. The general permit

requirements include recommended best management practices for stormwater at steam electric facilities,

landfills, treatment works, and construction areas greater than 5 acres. The requirements are additive

across industrial sectors. For example, a utility with an onsite ash landfill must meet both steam electric

and landfill requirements.

Because the stormwater program is relatively new and managed only by authorized NPDES

states, the number of facilities with general versus individual permits is not known. EPA handles NOIs

for 10 nonauthorized states. In these states, 700 steam electric facilities (including non-utility

combustors) have filed for general permits.
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3-58 March 1999

3.5.3 Regulations Addressing Solid and Hazardous Waste

EPA regulates the management of solid and hazardous waste through Subtitles C and D of

RCRA. Subtitle C of RCRA establishes a “cradle-to-grave” management system for wastes that are

considered hazardous because they fail tests based on physical and chemical characteristics (i.e., toxicity,

corrosivity, ignitability, and reactivity) or because they are listed as hazardous by EPA. Federal

regulations establish stringent environmental and administrative controls that must be applied to

management of these wastes. Coal-fired utility comanaged wastes are currently exempt from federal

regulation as hazardous waste under Subtitle C pending this Report to Congress and the subsequent

regulatory determination. Therefore, these wastes are subject to the requirements of Subtitle D of the

RCRA as nonhazardous solid waste.

Implementation of Subtitle D is the responsibility of individual states, but nothing prevents states

from imposing stringent requirements (including hazardous waste requirements) on FFC wastes. 

Currently, 44 states (representing 96 percent of utility coal-fired generating capacity) duplicate the

federal policy exempting UCCWs from hazardous waste regulations. The other six states (Kentucky,

Tennessee, Washington, New Jersey, Maine, and California) do not exempt UCCWs from hazardous

waste regulation. In these states, any UCCWs that fail the hazardous waste characteristic tests would be

subject to state hazardous waste requirements and managed in units that meet permitting, design,

operating, corrective action, and closure standards.

As discussed in Section 3.2, UCCWs seldom fail the hazardous waste characteristic tests. 

Therefore, the majority of UCCWs would be subject to state requirements under Subtitle D because they

do not fail the hazardous waste characteristic tests and/or are generated in the 44 states that duplicate the

federal exemption. The 1988 Report to Congress presented data on such state regulations from a 1983

Utility Solid Waste Activities Group survey. Under 1983 regulations, most states required permits for

landfills managing UCCWs, at least on a case-by-case basis; however, a smaller percentage of states had

the authority to impose physical controls or monitoring requirements on these landfills (see Table 3-23). 

The 1988 Report to Congress also found that state regulations only “indirectly addressed” waste

management in surface impoundments.

More recent data (CIBO, 1997c; EPA, 1995b; ASTSWMO, 1995; ACAA, 1996a) show that the

majority of states now have authority to impose physical controls and monitoring requirements on

UCCW landfills, at least on a case-by-case basis. Table 3-23 compares state regulatory authority with

respect to UCCW landfills reported in the 1988 Report to Congress to current data. Table 3-24 shows

data on current state regulatory authority with respect to surface impoundments. No earlier data

comparable to that for landfills in the 1988 Report to Congress was available for surface impoundments. 

Comparing current regulations for surface impoundments with those for landfills, the percentage of states

with at least case-by-case regulatory authority is similar for both types of units; however, EPA’s

examination of case study states, discussed below, found that when states impose requirements on

impoundments, they typically do so on a case-by-case basis.

The data in Tables 3-23 and 3-24 show that states currently have more authority to impose

controls on UCCW management units than in previous years. In addition to regulatory permits, the

majority of states are now able to require siting controls, liners, leachate collection systems, groundwater monitoring, closure controls, daily (or other operational) cover, and fugitive dust controls. EPA

believes that the use of such controls has the potential to mitigate risks, particularly ground-water

pathway risks, from comanaged waste disposal. The adequacy of this mitigation depends on the extent to

which states are exercising their authority in situations in which climate, geology, site-specific

conditions, and waste characteristics justify it.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-59

Section 3.3 of this report found that nearly all of the active UCCW comanagement landfills

surveyed are subject to regulatory permits and ground-water monitoring requirements. Just more than

half of the surveyed landfills are lined and just under half have leachate collection systems. A lesser

percentage of active UCCW comanagement surface impoundments have similar controls. These

statistics suggest that states have exercised their authority to impose controls at landfills, and to a lesser

1988 Report to Congress Current

Number of

Statesb

Percent of

Statesc

Percent of

Capacityd

Number of

Statesb

Percent of

Statesc

Percent of

Capacityd

HW Exemptiona 43 86% 88% 44 88% 96%

Permit Onsite 41 82% 75% 41 82% 77%

Permit Offsite 49 98% 94% 48 96% 95%

Siting Controls 30 60% 54% 46 96% 92%

Liner 11 22% 24% 43 86% 87%

Leachate Collection Systems 20 40% 31% 42 84% 79%

Ground-Water Monitoring 28 56% 60% 46 92% 89%

Closure Controls 27 54% 59% 45 90% 91%

Cover and/or Dust Controls Not surveyed 49 98% 96%

a

 Exemption from state hazardous waste regulations for CCWs

b

 Number of states with authority to impose the indicated requirement, either by regulation or on a case-by-case basis

c

 Percent of surveyed states with authority

d

 Percent of surveyed utility generating capacity represented by states with authority

Sources: EPA, 1988; CIBO, 1997c; ASTSWMO, 1995; EPA, 1995b; and ACAA, 1996a

Table 3-23. State Regulatory Controls on UCCW Landfills

Hazardous Waste Number of Statesb Percent of Statesc Percent of Capacityd

Hazardous Waste Exemptiona 44 88% 96%

Permit Onsite 45 92% 87%

Permit Offsite 45 94% 88%

Siting Controls 41 87% 81%

Liner 45 92% 91%

Leachate Collection Systems 33 73% 68%

Ground-Water Monitoring 44 96% 94%

Closure Controls 43 91% 88%

a

 Exemption from state hazardous waste regulations for CCWs

b

 Number of states with authority to impose the indicated requirement, either by regulation or on a case-by-case basis

c

 Percent of surveyed states with authority

d

 Percent of surveyed utility generating capacity represented by states with authority

Note: No earlier base year data (similar to that from the 1988 Report to Congress for landfills) were available for surface impoundments.

Sources: CIBO, 1997c; ASTSWMO, 1995; ACAA, 1996a

Table 3-24. Current State Regulatory Controls on CCW Surface Impoundments
Report to Congress on Wastes from the Combustion of Fossil Fuels

3-60 March 1999

extent at surface impoundments. Furthermore, Section 3.3 found increasing trends in the use of liners

and ground-water monitoring at newer units, both landfills and surface impoundments. This finding

suggests that states are increasingly applying their regulatory authority as new units are introduced. To

further examine state implementation of solid waste requirements on UCCW comanagement units, EPA

examined in greater detail the regulations applicable in five states: Indiana, Pennsylvania, North

Carolina, Wisconsin, and Virginia. These five states account for almost 20 percent of coal-fired utility

electrical generation capacity. Table 3-25 summarizes the requirements in each of these five states.

Table 3-25. State Waste Management Requirements Applicable to UCCWs

in Selected States

Indiana

Landfill

Requirements

Landfills are classified according to TCLP results for the wastes to be disposed. Specific design

requirements depend on the class of the landfill. Based on available characterization data, most

comanaged wastes would be subject to Type III landfill requirements. Requirements for these include

clay liner (thickness of 3 feet), siting restrictions, fugitive dust control, weekly cover, soil erosion control,

2-foot clay cap at closure, and revegetation at closure. Leachate collection systems are not required

but may be used in some cases to relax the liner thickness requirements. Type I and II landfill

requirements are more stringent. Type IV landfills, with less stringent requirements, may receive

wastes with leachate concentrations below MCLs.

Impoundment

Requirements

Regulations do not dictate any specific design, operating, or ground-water monitoring requirements. 

Requirements may be imposed on a case-by-case basis in individual permits.

Grandfather

Clause

Facilities that existed prior to September 1989 may continue to operate, but any expansions at these

facilities must comply with the requirements above.

Pennsylvania

Landfill

Requirements

Landfills are classified according to TCLP results for the wastes to be disposed. Specific design

requirements depend on the class of the landfill. Based on available characterization data, most

comanaged wastes would be amenable to Class III landfills. Requirements for these include siting

restrictions, a 4-foot attenuating soil base (or 1 foot per 4 feet of waste), fugitive dust control, daily

cover, soil erosion control, ground-water monitoring, 2-foot clay cap at closure, and revegetation at

closure. Class I and II landfill requirements are more stringent.

Impoundment

Requirements

Surface impoundments (including those that store waste for less than 1 year) are classified according

to TCLP results for the wastes to be disposed. Specific design requirements depend on the class of

the impoundment. Based on available characterization data, most comanaged wastes would be

subject to Class II requirements. Requirements for these include siting restrictions, composite liner,

leachate detection system, leachate collection system, minimum freeboard requirements, structural

integrity requirements, ground-water monitoring, 2-foot clay cap at closure, and revegetation at closure.

Grandfather

Clause

Units permitted prior to July 4, 1992, were required to modify their operations to comply with the above

requirements by July 4, 1997. Liner and leachate collection requirements may be modified if the

operator could demonstrate that the unit had not caused unacceptable ground-water degradation.

Minefill

Requirements

UCCWs must meet TCLP limits for disposal at a Class III landfill. Ground-water monitoring is required.

Soil Amendment

Requirements

UCCWs must meet pH limits. State agency notification and runoff and erosion controls required. 

There are siting limitations.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-61

North Carolina

Landfill

Requirements

Industrial waste landfills must demonstrate that their design will ensure that the state ground-water

standards are not exceeded at the compliance boundary. The design criteria for demonstrating this

include a composite liner, leachate collection system, and cap at closure. Alternatively, the operator

may submit ground-water modeling results that demonstrate, based on hydrologic and climatic

conditions and waste characteristics, that the standards will be met.

Impoundment

Requirements

Regulations do not dictate any specific design, operating, or ground-water monitoring requirements. 

Requirements may be imposed on a case-by-case basis in individual permits.

Grandfather

Clause

To continue operating after January 1, 1998, landfills operating prior to October 1, 1995, must

demonstrate that their original design or proposed design changes will meet the ground-water

standards. State has the authority to require design modifications if ground-water modeling methods or

results are inadequate.

Wisconsin

Landfill

Requirements

Requirements include clay or composite liners, leachate collection systems, fugitive dust controls,

2-foot clay cap at closure, revegetation at closure, and ground-water monitoring. State may modify the

requirements for landfills designed to receive “high-volume” industrial waste, specifically coal ash

waste, on a case-by-case basis. 

Impoundment

Requirements

Surface impoundments must meet siting requirements and have leachate collection systems and liners,

unless an exemption is granted by the state. Ground-water monitoring of surface impoundments is

optional.

Grandfather

Clause

Landfills with plan of operations approved prior to July 1, 1996, are exempt from liner and leachate

collection requirements. For landfills constructed prior to February 1, 1988, the state may require

ground-water monitoring on a case-by-case basis.

Virginia

Landfill

Requirements

For comanaged wastes, industrial landfills must characterize the wastes entering the unit and submit

and abide by a management plan for commingling the wastes. Design requirements include leachate

collection systems, run-on controls, liner (1 foot of compacted clay or equivalent), cap at closure,

fugitive dust controls, ground-water monitoring. A double liner system in which the primary liner is

synthetic may be used in lieu of ground-water monitoring. For fly ash and bottom ash from the

combustion of fossil fuels, periodic cover or dust control measures such as surface wetting or crusting

agents are required. Industrial landfills must conduct ground-water monitoring.

Impoundment

Requirements

Monitoring required. No other specific design or operating requirements. Requirements may be

imposed on a case-by-case basis in individual permits. Impoundments may be closed with waste in

place only if the closure requirements are established in the facility’s permit. Otherwise, regulations

require (1) removal of all liquids, wastes, and system components at closure, or (2) stabilization of

remaining wastes, installation of a cover, and post-closure ground-water monitoring.

Grandfather

Clause

Landfills permitted prior to 1988 must submit a monitoring plan but may continue operating without

retrofits as long as they do not expand.

Minefill

Requirements

Use in structural fills, mine reclamation, or mine refuse disposal requires notification and development

of design, operation, and closure plans. UCCWs thus used must not exceed the toxicity characteristic

levels for metals. Fugitive dust and run-on and runoff controls and 18 inches of cover at closure

required.

Soil Amendment

Requirements

Agricultural uses of CCW are exempt from the solid waste regulations provided they meet the

requirements of the Virginia Department of Agriculture and Consumer Services.
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3-62 March 1999

Based on this analysis, it appears that state requirements have become increasingly stringent over

time. States vary in their approaches to regulating UCCW landfills. For example, the Indiana and

Pennsylvania programs impose requirements tailored to the characteristics of the waste. North Carolina

may impose requirements based on site-specific modeling. In Virginia, requirements apply generically to

all industrial wastes. Wisconsin may modify its requirements specifically for landfills designed to

receive coal combustion ash. In several of the states studied, UCCWs may be disposed of in landfills that

are “grandfathered” out of requirements imposing design requirements such as liners. Regulations in

many of the states studied do not impose specific design requirements on surface impoundments that

comanage UCCWs. When these states impose requirements on impoundments, they typically do so on a

case-by-case basis.

3.6 WASTE MANAGEMENT ALTERNATIVES

Comanaged Wastes in General

The risk assessment in Section 3.4 identified potential ground-water pathway risks to human

health from comanaged waste in unlined management units. Mitigation of these potential risks might be

accomplished through the use of technologies that prevent or contain and collect leachate from

comanaged waste landfills and surface impoundments. Specifically, EPA identified the combination of

technologies in Table 3-26 as an alternative that would be practical and effective to target and mitigate

the potential ground-water risk. The technologies identified in the table are considered further in the cost

and economic impact analysis. These technologies also are consistent with those required under

Subtitle D of RCRA. Other risk mitigation approaches (not considered in Section 3.7) might incorporate

different design and operating standards for existing landfills and surface impoundments different from

those established for new landfills and surface impoundments containing the same wastes. Also, such

approaches might include an exemption for certain units that can demonstrate they pose no threat to

human health or the environment. For example, when EPA implemented design-based standards for

Subtitle C hazardous waste surface impoundments, an exemption was allowed for certain surface

impoundments, provided that these impoundments could demonstrate that alternative design and

operating practices, together with location characteristics, would prevent the migration of hazardous

constituents into ground or surface water at least as effectively as liners and leachate collection systems.

Comanaged Mill Rejects/Pyrites

Coal mill rejects (and particularly their pyrite component) have been identified as a low-volume

waste of particular concern (see Sections 3.1, 3.2, and 3.4.3). Because EPA currently is evaluating

voluntary industry guidance for mill rejects management, alternatives for this waste stream are not

evaluated here.

Agricultural Use and Minefilling

Of the beneficial uses discussed in Section 3.3.5, agricultural use may be of environmental

concern, based on the non-ground-water risk assessment that found potential arsenic risks to human

health from this practice. An approach for mitigating this potential risk might include a standard limiting

the arsenic concentration in wastes intended for this use. Because of the small quantity of waste that

would be affected by such an alternative, EPA has not estimated cost for such an approach. Minefilling

also may be of concern, particularly when wastes are placed below the water table. EPA is seeking

further information on this practice.
Report to Congress on Wastes from the Combustion of Fossil Fuels

12 Because the Agency currently is evaluating a voluntary industry proposal for mill reject management,

costs for mill rejects alternatives are not considered here.

March 1999 3-63

3.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS

This section discusses the costs and economic impacts of risk mitigation alternatives for coalfired utility comanaged wastes. Details of this analysis, together with a background describing this

complex industry, are documented as part of the EPA docket.

3.7.1 Overview and Methodology

In estimating costs and economic impacts for comanaged waste at coal-fired utilities, EPA relied

on the descriptive information for this sector presented previously in this chapter. Salient features are

reviewed below. It is important to bear in mind as these costs and impacts are reviewed that this industry

is large, generating more than $200 billion in sales annually.

EPA’s analysis began with the 353 coal-fired plants identified in the 1993 U.S. Department of

Energy (DOE) Energy Information Administration (EIA) 767 database that have electrical generation

capacities of at least 10 MW. This was supplemented by data (e.g., the frequency of comanagement, the

frequency of landfills and impoundments, waste generation rates) provided by the industry and discussed

in previous sections of this chapter. The Agency recognizes that there are uncertainties in working with a

database of this magnitude; the cost uncertainty discussed below reflects this.

EPA estimated the incremental compliance cost of the risk mitigation alternative for comanaged

waste described in Section 3.6.12 As described in that section, this requires generators to construct

composite-lined landfills and impoundments for comanaged wastes. The cost estimate summed the costs

of five categories: initial capital costs, recurring capital costs, annual operating and maintenance costs,

closure costs, and annual post-closure costs. Table 3-27 identifies the specific components included in

each cost category.

Landfill Impoundment

Comanaged Waste

Design includes filter fabric, 1' sand layer, 2' clay liner,

synthetic liner (high-density polyethelene [HDPE]), leachate

collection system, and ground-water wells.

Operation includes environmental monitoring, leachate

collection and treatment.

Closure requirements include 6" topsoil and vegetation, filter

fabric, 1.5' sand layer, 2' clay layer, synthetic liner, and a

cover drainage system.

Post-closure includes environmental monitoring, landscape

maintenance, slope maintenance, inspection, and

administration.

Design includes filter fabric, 1' sand layer, 2' clay liner,

synthetic (HDPE) liner, leachate collection system, and

ground-water wells.

Operation includes environmental monitoring, leachate

collection and treatment.

Closure requirements include 6" topsoil and vegetation, filter

fabric, 1.5' sand layer, 2' clay layer, synthetic (HDPE) liner,

added fill to achieve slope, and cover a drainage system.

Post-closure includes environmental monitoring, landscape

maintenance, slope maintenance, inspection, and

administration.

Table 3-26. Management Alternatives for Coal-Fired Utility Comanaged Waste and

Segregated Mill Rejects
Report to Congress on Wastes from the Combustion of Fossil Fuels

3-64 March 1999

For these comanaged utility wastes, the cost estimate was based on opening new management

units to replace existing landfills and impoundments that currently do not meet the requirements

described in Section 3.6. Because of this, the estimate included the costs of the purchase of land to site

new units where required.

Variations on this approach might substantially reduce the total costs incurred. For example,

EPA might allow existing impoundments to be used as is for a period (say, 10 years) and only then

drained, dredged, and lined in place. Such approaches would reduce the total (discounted) compliance

cost by both deferring cost and reducing the number of units above baseline to be lined. The Agency has

not yet estimated the cost of such variations, but anticipates a significant reduction below the $800 to

$900 million annual total shown below (possibly by some 50 percent).

The cost estimate utilized unit cost data from engineering cost literature and vendor quotation

to develop costs for three different landfill and impoundment sizes. The three sizes were defined to

characterize the range of management unit sizes (i.e., capacity, area, depth) observed in practice. 

Table 3-28 provides insight into design features that underlie this costing.

Category Landfill Cost Components Impoundment Cost Components

Initial Capital Costs Land purchase

Site development

Excavation

Filter fabric

1' sand

2' clay liner

Synthetic (HDPE) liner

Leachate collection

Ground-water wells

Indirect capital costs

Land purchase

Site development

Excavation

Filter fabric

1' sand

2' clay liner

Synthetic (HDPE) liner

Leachate collection

Ground-water wells

Indirect capital costs

Recurring Capital Costs (5-yrs) Heavy equipment (dump truck, bulldozer,

sheepsfoot roller, water truck)

Indirect capital costs

Not applicable

Annual O&M Costs Heavy equipment operation

Environmental monitoring

Leachate collection and treatment

Environmental monitoring

Leachate collection and treatment

Closure Costs 6" topsoil and vegetation

Filter fabric

1.5' sand

2' clay

Synthetic (HDPE) liner

Cover drainage system

Indirect closure costs

6" topsoil and vegetation

Filter fabric

1.5' sand

2' clay

Synthetic (HDPE) liner

Added fill to achieve slope

Cover drainage system

Indirect closure costs

Annual Post-Closure Costs Environmental monitoring

Landscape maintenance

Slope maintenance

Inspection

Administration

Environmental monitoring

Landscape maintenance

Slope maintenance

Inspection

Administration

Table 3-27. Cost Components Included in Landfill and Impoundment Designs
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-65

Using regression analysis, these were converted to data supporting a single cost equation. 

Annualized costs were then estimated as a function of waste generation rate on a plant-specific basis. 

Total industry costs were derived by summing the plant-specific cost estimates derived for the 353

identified coal-fired plants.

Using the methodology described above, the Agency developed costs and economic impacts as

set forth in the following three sections: incremental compliance cost, compliance cost impact on plants

as a function of plant size, and industry impact. Incremental compliance costs are the costs of risk

mitigation practices over and above the cost of current management practices. (Thus, for those facilities

currently meeting the requirements described in Section 3.6, incremental costs are zero.) Using

incremental compliance costs as an indicator of potential cost burden, the analysis examined impacts on

individual plants as a function of plant size. This was performed using pro forma financial statements for

three representative plant sizes as a basis against which to compare incremental compliance costs. For

industry impact evaluation, the use of econometric models to perform the analysis was considered and

rejected. The primary reason for this was that partial equilibrium analysis at this time would imply a

level of precision that cannot be supported, given the uncertainty surrounding ongoing deregulation of

Parameter Landfill Impoundment

Sizes small

(tons/year) medium

large

9,650

96,500

965,000

7,220

72,200

722,000

Depth

(feet) small

medium

large

small

medium

large

Pile design

1.0

1.0

3.0

Combination fill design

10.0

31.0

58.6

10.0

20.0

20.0

Height

(feet) small

medium

large

small

medium

large

Pile design

25.0

30.5

79.4

Combination fill design

14.8

40.5

79.4

0

0

0

Area

(acres) small

medium

large

small

medium

large

Pile design

13.5

239.1

479.2

Combination fill design

13.0

44.1

228

21.4

106.3

1,023

Note: Landfill designs considered include a “pile design” constructed primarily above grade and a “combination fill design” constructed both

above and below grade.

Table 3-28. Design Parameters Assumed for Small, Medium, and Large

Landfills and Impoundments
Report to Congress on Wastes from the Combustion of Fossil Fuels

3-66 March 1999

the industry. The industry-level analysis thus focuses on two measurements to assess economic impact:

the number of affected facilities and the magnitude of incremental compliance costs relative to the value

of electricity sales. These are used to build to an indication of the effect on supply and demand

relationships and possible impact on price.

3.7.2 Incremental Compliance Cost

Key variables in estimating incremental compliance cost were the number of affected plants,

current management practices (i.e., the number currently meeting the requirements described in

Section 3.6), estimated waste generation quantities, and costs of key components (e.g., liners). All of

the estimates shown assume a 40-year operating life for management units.

EPA’s estimate of incremental compliance cost is some $860 million per year, using the most

likely values for all the input variables. If all variables were to combine at either the high or low end, a

much wider range of incremental compliance cost would result. It is EPA’s judgment, however, that the

likely range would be $800 to $900 million per year, based on reasonable estimates of uncertainty in the

input variables and the low probability that all variables would combine at either their high- or low-end

values.

In the estimates above, liner construction accounts for most of the estimated cost. Liner

construction costs are driven by the area to be covered, which makes the incremental unit costs for

impoundments higher because of their large area-to-depth ratio. Also, the smaller percentage of

impoundments currently estimated to be lined (see Section 3.3.4) increases the total incremental cost for

impoundments.

Note that the costs above are incremental (above current costs). Annual costs were discounted at

7 percent to 1998 dollars based on Office of Management and Budget (OMB) guidance, with no inflation

built into out-year estimates. Also, it was presumed that compliance would be required immediately, and

that amortization would take place over 40 years for both landfills and impoundments.

3.7.3 Compliance Cost Impact on Plants as a Function of Plant Size

A full analysis of the potential for deregulation to affect this analysis was considered but not

undertaken because of resource limitations and the high degree of uncertainty associated with

deregulation. EPA recognizes that such an analysis might show impacts different from those presented

below.

EPA believes that the ability of industry to pass through cost increases will be limited for two

general reasons. First, large portions of the electric power generation industry would not be directly

affected (e.g., nuclear power plants) and thus opportunities to pass on costs will be limited. Second, the

electric utility industry is rapidly changing from a regulated, regional market structure to an open and

presumably competitive multiregional (if not national) market. This may reduce the potential to pass on

increased costs. Therefore, this analysis includes no analytical consideration of price effects.

Economic impacts at the plant level will depend on several major factors, including quantity of

fuel used, quality of fuel, profitability, and production technology. To assess these impacts across the

range of plants, EPA estimated financial data for model plants representing three size ranges: large

(burning greater than 1.5-million tons of coal per year), medium (burning between 750,000 and 1.5-

million tons of coal per year), and small (burning less than 750,000 tons of coal per year). The large and

medium model facilities are representative of investor-owned utilities and the small facility is more
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-67

representative of a publicly owned utility. Table 3-29 compares incremental compliance costs to

revenues and net income for these three model plants. The incremental compliance costs used in this

analysis reflect EPA’s best estimate based on most likely values of the relevant input variables.

The incremental compliance cost for comanaged wastes should not impact the financial viability

of coal-fired plants. This appears true even for plants transitioning from the worst case unlined

management unit to a composite-lined unit. For example, a large, investor-owned utility (IOU) coal-fired

plant with more than 1,000 MW of generating capacity is estimated to comply for about $6.16 million per

year (or about $16 per ton of waste). Based on typical annual revenues and cost, compliance costs would

increase overall costs by 1.5 percent of revenues. Without any price adjustments, net income before

taxes for this investor-owned plant would be reduced from about 13 to 11.5 percent and remain at more

than $49 million per year. EPA recognizes that such profit margin reductions may be considered

significant by the individual utility.

Financial impacts on a medium-sized IOU coal-fired plant with about 370 MW of generating

capacity suggest it should also remain financially viable. Costs would increase by about 1.6 percent of

revenues, with profitability (before tax) at about 11.4 percent of revenue, with net income after

compliance of more than $16 million per year. (Incremental compliance costs are estimated at about

18.31 per ton of comanaged waste, or about $2.2 million per year.)

Because of higher unit compliance costs and lower net income margins, smaller, publicly owned

coal-fired plants would incur relatively higher impacts. For example, an average small publicly owned

plant with about 180 MW of capacity is estimated to comply for about $1.3 million per year (about

$25.70 per ton of comanaged waste). Based on typical revenues and costs, compliance costs for a small

coal-fired utility would increase overall costs about 2.1 percent. This would reduce net income, without

price adjustments, from about 9 percent to 6.9 percent of revenue, or to about $4 million per year.

Table 3-30 shows how the estimated population of affected facilities breaks down by the three

size categories represented by the model plants. It also compares the incremental compliance costs

estimated for the model plants to average sales for individual plants in each size category. As noted

above, incremental compliance costs range from 1.5 percent of sales for large plants to 2.1 percent of

sales for small plants.

Large Coal Plant

Investor-Owned Utility

Medium Coal Plant

Investor-Owned Utility

Small Coal Plant

Publicly Owned Utility

$1,000’s

Percent of

Revenues $1,000’s

Percent of

Revenues $1,000’s

Percent of

Revenues

Revenues from Electricity 426,000 100% 142,000 100% 60,000 100%

Baseline Before Tax Net Income 55,380 13.0% 18,400 13.0% 5,400 9.0%

Expected Incremental Compliance Costs

(replace unlined management unit with

composite-lined unit)

6,165 1.5% 2,197 1.6% 1,285 2.1%

Expected Post-Compliance Net Income 49,215 11.5% 16,203 11.4% 4,115 6.9%

Table 3-29. Plant-Level Impact of Incremental Compliance Costs
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3.7.4 Industry Impacts

As noted, the U.S. electric power industry is entering an era of major restructuring. Given the

uncertainty surrounding this restructuring, the use of econometric models to perform the industry impact

analysis was rejected. Partial equilibrium analysis at this time would imply a level of precision that

cannot be supported, given the uncertainty surrounding ongoing deregulation of the industry. The total

cost of compliance compared to total industry sales, however, should still serve as a good proxy for

estimating industry effects.

The electric power generating industry, including fossil fuel, hydroelectric, nuclear, and other

fuel sources, was a $212 billion per year industry in 1996. To provide perspective on the possible

incidence of compliance cost, the following characteristics of the electric utility industry are noted:

• An average price to consumers of 6.86 cents per kilowatt hour (kWh) in 1996, which can

vary from less than 3 cents per kWh for industrial customers of a federal utility to more than

15 cents per kWh for residential customers of a northeastern investor-owned utility

• Annual electricity consumption of 3,120 billion kWh (1997) or 11,860 kWh per capita

• Approximately 3,200 entities selling electricity with industry ownership, including the

following:

– 243 investor-owned utilities (7.6 percent of all utilities) producing 76 percent of U.S.

electricity sales (2,343 billion kWh and $167 billion or $687 million per entity)

– 2,014 smaller public utilities (mainly municipalities and other local government entities

and 63 percent of all utilities) producing only 14.5 percent of the electricity sales (451

billion kWh and $27 billion or $13 million per entity)

– 932 cooperatives (29 percent of all utilities) producing 8 percent of industry sales (241

billion kWh and $17 billion or $18 million per entity)

– 10 federal utilities (0.3 percent of all utilities) accounting for 0.6 percent of electricity

sales (50 billion kWh and $1.3 billion or $130 million per federal utility)

• Increasing trends in the use of coal and declining trends in the use of oil, as discussed in

Chapter 2 of this report.

Based on the best estimate of costs presented above, the electric utility industry would incur

about $860 million in incremental annualized compliance costs. As shown in Table 3-31, this would

represent 0.4 percent of the industry’s value of shipments. It would be concentrated in the coal-fired

Size Category

Number

of Plants

Percent

of Plants

Plant Sales

($million/year)

Compliance Cost

($million/year)

Percent

of Sales

Large (>1.5-million tons/year of coal) 148 42% $426 $6.2 1.5%

Medium (750,000 to 1.5-million tons/year of coal) 61 17% $142 $2.2 1.6%

Small (<750,00 tons/year of coal) 144 41% $60 $1.3 2.1%

Table 3-30. Incremental Compliance Cost by Plant Size
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utility component, which accounts for about 56 percent of all electricity generated in the United States. 

Individual operators likely would take this effect into consideration, along with several other factors, in

assessing how soon to close marginal coal plants and what type of new plants to build. This implies that

a possible effect of the identified risk mitigation alternative would be a shift to alternative energy

sources.

The high cost of compliance reflecting this mitigation action is but a very small percentage of

revenues. If, as noted at the start of Section 3.7, above, a risk mitigation strategy embodying allowance

for continuing but phased-down utilization of existing impoundments and landfills is considered, this

percentage of revenues would be driven even lower; perhaps down to as low as 0.2.

Coal-fired plants might attempt to pass costs to consumers in the form of higher prices. This

would be restricted by competition from unaffected plants (i.e., hydroelectric and nuclear). Investorowned utilities, representing only about 8 percent of utility operators, would be the major determinants of

price effects as they control about 80 percent of electric energy sales (as well as the majority of large

coal-fired plants). Investor-owned utilities also are merging and consolidating operations rapidly and

will be the primary players in a more open and national electricity market.

3.8 FINDINGS AND RECOMMENDATIONS

3.8.1 Introduction

Based on the information collected for this Report to Congress, this section presents a summary

of the Agency’s main findings presented under headings that parallel the organization of this chapter. It

then presents the Agency’s tentative conclusions concerning the disposal and beneficial uses of

comanaged wastes generated at coal-fired utilities, including wastes from the burning of petroleum coke

and the coburning of other fuels with coal as identified in this chapter.

3.8.2 Findings

Sector Profile

• There are about 450 coal-fired power plants located throughout the United States. Most

states have at least one coal fired utility plant. The eastern United States has a larger

concentration of plants than the western United States.

• There are approximately 1,250 coal-burning boilers in operation at coal-fired power plants. 

A particular plant can have multiple boiler (generating) units.

• Coal-fired power plants account for more than 50 percent of the electricity produced in the

United States. There is a wide range of electrical generating capacity represented in the

population of power plants. Coal-fired plants can range in size from less than 50 megawatts

(MW) to more than 3,000 MW. The amount of wastes generated at these plants is generally

proportional to the amount of electricity generated.

Industry Sales ($ million/year) Compliance Cost ($ million/year) Percent of Sales

$212,000 $862.4 0.4%

Table 3-31. Industry Economic Impacts, Coal-Fired Utility Comanaged Wastes
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• Coal-fired power plants are located in diverse environments. Power plants are located in

areas that vary widely in population density, geography, precipitation, and general climate. 

Two common factors in siting coal-fired plants are (1) location near a major body of surface

water, such as a lake or river as a source of cooling water, and (2) locating to accommodate

economical transport of the large amounts of coal required to generate electricity.

Waste Generation and Characteristics

• About 105-million tons of large volume coal combustion wastes (i.e., fly ash, bottom ash,

boiler slag, flue gas desulfurization [FGD] sludge) are generated annually at coal-fired

power plants.

• Utilities generate a variety of low-volume wastes that result from supporting processes that

are ancillary to, but a necessary part of, the combustion and power generation process. 

Examples include coal pile runoff, boiler blowdown, and boiler chemical cleaning wastes.

• The total amount of the numerous low-volume wastes generated at these plants is not well

established, but estimates vary from less than one-half to several times the amount of largevolume wastes. Most of the low-volume wastes are aqueous. Water comprises a substantial

portion of the aqueous low-volume wastes.

• The constituents of concern in the large-volume wastes are trace elements, metals in

general, and the eight RCRA metals in particular. No organic constituents, including

dioxins, and no radionuclides were identified at potential levels of concern in these wastes.

• The large-volume and low-volume wastes are managed in many different combinations. 

Metals are the only class of constituents of concern in the comanaged wastes.

• A few of the individual low-volume wastes, such as boiler chemical cleaning wastes and

demineralizer regenerant, occasionally test as characteristically hazardous for toxicity

and/or corrosivity; however, none of the comanaged waste mixtures tested characteristically

hazardous for corrosivity, reactivity, or ignitability. There were no toxicity characteristic

exceedences observed in TCLP samples of comanaged wastes, although there were

infrequent exceedences observed in some in situ pore water samples.

Waste Management Practices

• An estimated minimum of 80 percent of the large-volume wastes are comanaged with lowvolume wastes. (The comanaged wastes are the subject of this chapter.)

• The most frequent industry practice for comanaged wastes is disposal in landfills or surface

impoundments. There are approximately 600 of these waste management units serving coalburning power plants, with nearly equal numbers of landfills and impoundments. Most

impoundments and about half of the landfills are located at the generating site.

• The waste management units are large in scale, typically 60 acres for a landfill and 90 acres

for an impoundment. There is an increasing industry trend to use landfills instead of

impoundments for disposal, due partly to Clean Water Act new source regulations that

encourage dry handling of fly ash by setting a zero wastewater pollutant discharge standard.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 3-71

• The utility sector in recent years has increasingly installed more environmental controls for

comanaged waste facilities. Prior to 1975, fewer than 20 percent of the waste management

units (landfills and impoundments) were lined. Today, more than one-half of the landfills

and one quarter of the impoundments are lined. Other examples of in-place controls include

leachate collection, ground-water monitoring, and operation under regulatory permits, each

of which has a high rate of implementation at landfill management units, and significant

implementation at surface impoundment management units.

• A significant portion of these wastes are reused. Nearly 27 percent of the large-volume

wastes are currently managed through beneficial uses. Some portion of these reused wastes

are actually comanaged wastes. The potential for increased reuse of these wastes currently

appears to be limited, based on demand for the products and services where the wastes are

used.

Potential Risks and Damage Cases

• EPA conducted a risk assessment that found a lack of potential human health risk for

virtually all waste constituents. Arsenic was the one constituent for which the Agency

identified potential human health risks via the ground-water pathway where these wastes are

managed in unlined landfills and surface impoundments. The identified risk is based on

high-end risk scenarios in EPA’s risk modeling analysis for human ingestion of well water

influenced by releases from the waste management unit. The time to reach the health-based

level for arsenic in ground water at the receptor well is about 500 years for the modeled

surface impoundment case and in excess of 3,500 years for the modeled landfill case.

• EPA conducted a risk assessment that found a lack of potential human health risk for

virtually all waste constituents. Arsenic was the one constituent for which the Agency

identified potential human health risks via non-ground-water pathways where these wastes

are used as soil amendments for agricultural purposes. The identified risk is based on highend risk scenarios in EPA’s risk modeling analysis, for human ingestion exposure routes.

• Based on hypothetical exposure scenarios, the Agency identified potential ecological risks

where these wastes are managed in surface impoundments from selenium (mammals),

although potential risks were also found from arsenic (birds), aluminum (amphibians), and

boron (amphibians). This is based on direct exposure of the receptors to the waters in

surface impoundments.

• The Agency identified a total of six damage cases associated with management of these

wastes. Each case involved older, unlined waste management units. The releases in these

cases were basically confined to the vicinity of the facilities and did not affect human

receptors. None of the damages caused effects on human health.

• Damage cases and other problem management cases are dominated by chronic incidents,

such as leaks and occasional runoff as opposed to catastrophic incidents, such as sudden

releases or spills.

• If not managed properly, pyritic wastes (in mill rejects) have the potential to generate acid

that can mobilize constituents in the comanaged wastes and contribute to risk.

• The Agency has very limited information with which to conduct a risk assessment on the

practice of minefilling the comanaged wastes and, therefore, cannot quantify the risks
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associated with this practice at this time. Minefilling includes disposal of wastes by

placement in mine voids and placement of wastes in mine voids for reclamation purposes.

• Some natural arsenic levels in U.S. soils have the potential to pose higher risks than the risk

identified with the level of arsenic that may be contributed by these wastes for non-groundwater pathways.

Existing Regulatory Controls, State and Federal Requirements

• The utility industry has a significant level of installed environmental controls for these

wastes, and is increasingly implementing control measures that mitigate the potential human

health risks identified in this study.

• States increasingly have begun to impose controls on coal combustion waste management

units. The majority of states now have regulatory permit programs (45 states) as well as the

authority to require siting controls (41), liners (45), leachate collection systems (33),

ground-water monitoring (44), and closure controls (43) for management of these wastes. 

Many states also have authority to require daily or other operational cover and fugitive dust

controls.

• There are significant existing federal environmental controls that affect waste management

practices in this sector. These include new source performance standards under the Clean

Water Act that encourage dry fly ash handling, which has likely contributed to the recent

industry trend away from the use of wet ash handling (sluicing ash) to impoundments. 

Significant federal authorities also exist to address site-specific problems and damages at

existing waste management sites under RCRA Section 7003 and CERCLA Sections 104 and

Section 106, when situations pose threats to human health and the environment.

• The rate of environmental compliance inspections at fossil fuel electric power generation

facilities is among the highest for any industrial sector. Moreover, the rate of enforcement

actions compared to the inspection rate is among the lowest for any industrial sector. Since

1992, there have been about 13 major environmental cases involving fossil fuel electric

power generating facilities, none of which was for violations directly related to management

of solid or hazardous wastes.

Potential Costs and Impacts of Regulation 

• The Agency estimates that the total annual incremental compliance costs for mitigation of

the potential arsenic risks identified in this study would be between $800 and $900 million

(1998$). These costs represent replacement of existing unlined management units with

lined management units, and implementing ground-water monitoring and leachate collection

and treatment. These measures do not represent implementation of full Subtitle C

requirements, but rather modifications of such requirements that could potentially be

adopted under Section 3004(x) of RCRA.

• If these wastes were to be regulated under full Subtitle C, virtually all existing facilities

would be required to invest substantial funds and resources to modify existing management

practices. The total annual cost of full Subtitle C requirements would considerably exceed

the $800- to $900-million (1998 $) estimate above.
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March 1999 3-73

• If beneficial uses of these wastes were subject to any regulation under Subtitle C, possibly

all beneficial use practices and markets would cease.

• The cost of compliance with RCRA Subtitle C by coal-burning power producers could

reduce the amount of coal consumed in favor of other fuels. Depending on the extent of

specific Subtitle C regulation, the cost of generating electricity by burning coal could

substantially increase.

3.8.3 Recommendations

Following are the Agency’s recommendations for the wastes covered in this chapter. The

recommendations are based on EPA’s analysis of the eight Congressionally mandated study factors

(Section 1.2). These conclusions are subject to change based on continuing information collection,

continuing consultations with other government agencies and the Congress, and comments and new

information submitted to EPA during the comment period and any public hearings on this report. The

final Agency decision on the appropriate regulatory status for these wastes will be issued after receipt

and consideration of comments as part of the Regulatory Determination, which will be issued within 6

months.

1. The Agency has tentatively concluded that disposal of these wastes should remain exempt from

RCRA Subtitle C.

The Agency has tentatively concluded that the comanaged wastes generated at coal-fired utilities,

including petroleum coke combustion wastes as well as wastes from other fuels co-fired with coal,

generally present a low inherent toxicity, are seldom characteristically hazardous, and generally do not

present a risk to human health and the environment. Current management practices and trends and

existing state and federal authorities appear adequate for protection of human health and the

environment. State programs increasingly require more sophisticated environmental controls, and tend to

focus on utility waste management due to the high waste volumes. For example, the frequency of

environmental inspections at utilities is among the highest of all the major industry sectors in the United

States. Most of the landfills and 40 percent of the impoundments implement ground-water monitoring,

reflecting the states’ focus on this industry sector. In addition, the Agency has identified relatively few

damages cases. Although one damage case identified arsenic as a constituent of concern, none of the

damage cases affected human receptors. These types of facilities are typically located in areas of low

population and thus present infrequent opportunity for human exposure. The industry trend, as detailed

in this chapter, is to line waste disposal units and to use dry ash handling techniques at new facilities; dry

ash handling eliminates the use of impoundments for waste management. Currently, more than one-half

of the active landfills are lined. Although one-quarter of all existing active impoundments are lined,

about 45 percent of the impoundments constructed since 1975 have been lined.

If these wastes were listed as hazardous, and therefore regulated under Subtitle C, coal

combustion units would be required to obtain a Subtitle C permit, which would unnecessarily duplicate

existing State requirements, and would establish a series of waste unit design and operating requirements

for these wastes that would most often be in excess of requirements to protect human health and the

environment. The estimated total annual cost to mitigate the potential arsenic risk identified in this study

exceeds $800 million. This cost does not represent implementation of full Subtitle C controls, but rather

Subtitle C requirements modified by RCRA 3004(x) factors to target the identified risks. The Agency

estimates that the total cost of full Subtitle C controls would be several times this amount. Full Subtitle

C controls include location restrictions, manifesting, liners, leachate collection, ground-water monitoring,

covers, dust control, closure controls, financial assurance, and corrective action.
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3-74 March 1999

For these reasons, EPA tentatively concludes that Subtitle C is inappropriate to address any

problems associated with disposal of these wastes and that the continued use of site and region specific

approaches by the states is more appropriate for addressing the limited human health and environmental

risks that may be associated with disposal of these wastes. For the issues discussed below involving

agricultural use and management of these wastes in mines (minefill), the Agency is still considering

whether some regulation under RCRA Subtitle C may be warranted.

The Agency identified several situations where pyrite materials (sulfur-bearing components of

mill rejects) comanaged with coal combustion wastes might have been of concern. The pyritic waste

materials had turned acidic and may have caused localized environmental damage. One such situation is

considered to be a damage case. While mismanagement of these pyritic wastes can theoretically cause

problems because of their inherent chemical properties, such evidence is rare, and the Agency has no

means of systematically evaluating the extent to which they would cause or contribute to risks. To

address the problem management situations, the Agency has engaged the utility industry in a program to

ensure that these particular wastes are appropriately managed, as reflected in the industry’s development

of technical guidance and an industry education program concerning proper management of pyritic

materials. The Agency is encouraged by the industry program, and has tentatively concluded that

additional regulation of pyrite disposal is not necessary. EPA, however, will follow-up with oversight on

the industry’s progress with management of these wastes, and will revisit this issue if necessary.

The Agency identified potential ecological risks from selenium (mammals), although potential

risks were also found from arsenic (birds), aluminum (amphibians), and boron (amphibians) for coal

combustion wastes that are comanaged in surface impoundments. While the waters in surface

impoundments can theoretically pose risks to birds, mammals, and amphibians exposed to them, the

Agency has no actual information about the scale and frequency at which receptors are actually exposed,

and therefore cannot quantify the magnitude of the actual ecological impacts at these facilities. No

documented or anecdotal ecological impact information was available with which to compare with the

risk modeling results. Moreover, the Agency was unable to identify any feasible risk mitigation practices

for these very large impoundments other than to continue to rely on the Clean Water Act new source

standards to move the industry toward dry handling of the coal combustion wastes. (Dry handling

methods do not involve surface impoundments and therefore do not present the ecological risks identified

for impoundments.) Outright elimination of the large impoundments would impose extremely high costs

on the operators. The benefits to be derived from elimination of impoundments are uncertain due to

unavailability of information on actual receptor exposure rates and impacts as described above. The

Agency solicits information on the practices and techniques that may be effective in mitigating the

potential ecological risks, considering the large surface areas involved at these facilities.

2. The Agency has tentatively concluded that most beneficial uses of these wastes should remain

exempt from RCRA Subtitle C.

No significant risks to human health and the environment were identified or believed to exist for

any beneficial uses of these wastes, with the possible exception of minefill and agricultural use as

discussed below. This is based on one or more of the following reasons for each use or resulting product: 

absence of identifiable damage cases, fixation of the waste in finished products which immobilizes the

material, and/or low probability of human exposure to the material.

3. The Agency is tentatively considering the option of subjecting practices involving the use of these

wastes for agricultural purposes (i.e., as a soil nutrient supplement or other amendment) to some

form of regulation under Subtitle C.
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As mentioned above, the Agency identified potential risk from exposure to arsenic in these

wastes when they are used for agricultural purposes. The risks identified with this practice are of

sufficient concern to consider whether some form of control under Subtitle C is appropriate, given the

increasing trend for use of these materials as agricultural amendments. An example of such controls

could include regulation of the content of these materials such that arsenic concentrations could be no

higher than that found in agricultural lime. On the other hand, imposition of controls under Subtitle C

may not be warranted if sufficient protection may be afforded by the Agency engaging the industry to

establish voluntary controls on this practice. An example of such voluntary controls could consist of an

agreement to limit the level of arsenic in these materials. The Agency solicits comment on its tentative

conclusion and specific approaches that could be pursued to address the concern. While the part 1

regulatory determination exempted all beneficial uses for the large-volume coal combustion wastes, the

tentative conclusion for the comanaged wastes would also affect the status of the part 1 wastes for

agricultural use. This is because the source of the identified risk is the metal content of the coal

combustion wastes. The Agency has no information indicating that any of the comanaged low-volume

wastes significantly affect the identified potential risks and, therefore, the risks should be comparable for

the wastes subject to the part 1 regulatory determination. Additionally, the Agency considers its current

risk analysis for this practice to be more thorough than that conducted for the part 1 wastes, and

accordingly believes it proper to reconsider the part 1 wastes in this respect.

As indicated in the summary above, although the practice of minefilling these wastes is within

the scope of this study, the Agency currently lacks sufficient information with which to adequately assess

risk associated with this practice. Several factors make the practice of minefilling difficult to assess. 

First, minefill is occurring in areas where there are often pre-existing environmental concerns, such as

acid mine drainage. With its existing data the Agency is unable to determine if elevated contaminants in

ground water are due to minefill practices, or rather are associated with pre-existing problems or

conditions. Second, although minefill in a surface pit has similarities to landfill situations we have

modeled, both surface and subsurface minefill raises complexities beyond the landfill model. Third,

these operations, with their pre-existing concerns, may require very site-specific determinations that do

not lend themselves to national standards.

The Agency solicits comment on whether there are some minefill practices that are universally

poor and warrant specific attention. For example, the Agency has found several situations where cement

kiln dust placed in direct contact with the ground-water table has created problems. EPA specifically

seeks comment on whether coal or other fossil fuel combustion wastes used as minefill and placed in

direct contact with the water table would create other environmental concerns, and if that specific

practice should be regulated. Last, with a few exceptions, use of these wastes as minefill is generally a

recent practice and therefore long-term practices and environmental data cannot be assessed. The

potential for risks associated with this practice may be of sufficient concern to consider whether some

form of control under Subtitle C is appropriate, given the increasing trend for use of these materials as

minefill. The Agency’s focus is on potential risks that may be posed via the ground-water and surface

pathways from use of these wastes as minefill. The Agency solicits additional information in the form of

additional case studies of actual minefill situations, with the following types of information: minefill

project design including areal extent, volumes, depth, environmental controls, mine spoils mixing ratio;

characterization of combustion wastes that are involved; the background, pre-existing conditions in

ground water at the mine location; and the depth to ground water at the mine location. The Agency is

also interested in obtaining information on analytical modeling tools that can simulate fractured flow

conditions and facilitate prediction of alkalinity consumption by acid mine drainage intrusion into the

combustion wastes. The Agency will consider such comments and information in the formulation of the

Regulatory Determination.
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Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 4-1

Figure 4-1. Non-Utility Fossil Fuel Combustion Sector by Fuel Type

4.0 NON-UTILITY COAL COMBUSTION WASTES

Non-utility fossil fuel combustors do not produce and sell electricity as their primary industrial

activity. Non-utility combustors are commercial, industrial, and institutional facilities that use fossil

fuels in boilers to generate steam. Steam thus produced is used to generate electricity for captive use, to

provide heat, or as a production process input. This chapter focuses on coal-fired non-utilities because of

their much larger waste generation relative to other non-utilities. Coal combustion accounts for only 22

percent of non-utility fossil fuel generating capacity, but is responsible for the majority (greater than 99

percent) of non-utility fossil fuel combustion waste, as shown in Figure 4-1. Oil-fired boilers (covered in

Chapter 6) and natural gas-fired boilers (covered in Chapter 7) account for larger shares of capacity, but

generate very little waste. In addition to non-utility coal combustion waste (CCW), this chapter covers

wastes from non-utilities combusting petroleum coke and coburning coal and other fuels.

Note that non-utilities, for purposes of this study, do not include independent power producers

(sometimes called non-utilities in the electric power industry). Large-volume CCWs from independent

power producers, when managed alone, were covered by the 1993 Regulatory Determination. 

Comanaged CCWs from independent power producers are covered in Chapter 3.

Sector Overview

The coal-fired non-utility sector is small relative to the coal-fired utility sector. In 1997, nonutilities consumed approximately 76 million tons of coal, compared to the 921 million tons consumed by

utilities and independent power producers. Industrial facilities (as opposed to commercial or institutional

combustors) account for the majority (92 percent) of non-utility coal usage (EIA, 1997e). The major

industries accounting for a significant portion of coal-fired non-utility generating capacity include paper

and allied products, chemicals and allied products, food and kindred products, primary metals, and

transportation equipment (EPA, 1990). The 1990 U.S. EPA National Interim Emissions Inventory

identifies 958 non-utility coal combustors in the United States operating nearly 2,300 individual boilers. 
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Figure 4-2. Number of Non-Utility Coal Combustors by State

As discussed below, this figure is from a source that may underestimate the total number of non-utilities,

but likely captures the majority of non-utility CCW generated. Note that cement kilns that burn fossil

fuels are not included in the non-utility population covered by this study because these facilities are

covered by the Report to Congress on Cement Kiln Dust.

As discussed in Chapter 2, non-utility coal combustion is expected to increase slowly through the

year 2020. As shown in Figure 4-2, non-utility coal combustors are spread throughout the United States,

with the largest numbers in the Northeast and Midwest. Most non-utility coal-fired electrical generation

capacity is located in the same regions. Within states, facility settings vary from urban to rural. As

discussed in Section 4.3, non-utilities practice both onsite and offsite waste management. Offsite waste

management units are expected to be located near the generating facility in most cases. Therefore, the

geographic distribution of combustion facilities presented in Figure 4-2 also approximates the universe of

waste management locations.

The 1990 U.S. EPA National Interim Emissions Inventory is a major source used in this study to

characterize the non-utility coal combustion universe. This database includes information on major

stationary point sources of air emissions. As such, it captures only the largest non-utility facilities; many

small non-utility fossil fuel combustors are not included in the database. These small facilities, however,

are expected to represent only a small percentage of the total capacity of the non-utility universe and are
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1

 Small facilities are disproportionately populated by natural gas- and oil-fired units, which generate small

or negligible quantities of solid waste. Small facilities burn less fuel, resulting in lower waste generation. Finally,

small units are less likely to be fitted with air pollution control devices, decreasing the quantity of fly ash collected.

March 1999 4-3

unlikely to generate significant quantities of waste.1 Therefore, this source is representative of facilities

that generate the majority of non-utility CCW. The database contains incomplete information from EPA

Regions 9 and 10, thus underrepresenting facilities in some Western states.

4.1 WASTE GENERATION

Coal-fired non-utilities have the potential to generate the same four large-volume CCWs as

utilities:

• Fly ash. Uncombusted material carried out of the boiler along with flue gases.

• Bottom ash. Uncombusted material that settles to the bottom of the boiler. Bottom ash

does not melt and therefore remains in the form of unconsolidated ash.

• Boiler slag. Uncombusted material that settles to the bottom of the boiler. Slag forms when

operating temperatures exceed ash fusion temperature, and remains in a molten state until it

is drained from the boiler bottom.

• Flue gas desulfurization (FGD) waste. Waste produced during the process of removing

sulfur oxide gases from flue gases (less likely to be generated at non-utilities than utilities,

as discussed below).

As for utilities, the generation of these CCWs depends upon boiler technology (Section 4.1.1),

air pollution control technology (Section 4.1.2), and fuel usage (Section 4.1.3). There are no

comprehensive data on industry-wide generation of these non-utility CCWs. An annual ash generation

rate, however, can be derived for coal-fired non-utilities using the data in the 1990 U.S. EPA National

Interim Emission Inventory database (EPA, 1990). For these facilities, the estimated annual rate of

CCW generation is approximately 5.8 million tons per year (EPA, 1997d). This estimate is significantly

less than the quantity of CCWs generated by utilities due to the smaller total capacity of the non-utility

sector and the factors discussed below (Sections 4.1.1 through 4.1.3). Because slow growth in non-utility

consumption of coal is expected (see Chapter 2), dramatic increases in non-utility CCW generation are

not expected.

Like utilities, non-utilities can generate low-volume combustion wastes as a result of supporting

processes (see Section 4.1.4) that are ancillary to, but a necessary part of, the combustion and power

generation processes. These low-volume wastes include the following:

• Coal pile runoff. Produced by precipitation falling on coal storage areas (less likely to be

generated at non-utilities than utilities, as discussed below).

• Coal mill rejects/pyrites. Produced by onsite processing of coal prior to use (less likely to

be generated at non-utilities than utilities, as discussed below).

• Boiler blowdown. Waste that is continuously or intermittently removed from boilers that

recirculate water.
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• Cooling tower blowdown and sludge. Wastes removed periodically from closed-loop

cooling systems.

• Water treatment sludge. Wastes resulting from treatment of makeup water for the steam

cycle or for non-contact cooling.

• Regeneration waste streams. Wastes resulting from periodic cleaning of ion exchange

beds used to remove mineral salts from boiler makeup water.

• Air heater and precipitator washwater. Wastes resulting from the periodic cleaning of

the fireside (i.e., the side exposed to hot combustion products) of heat exchanging surfaces.

• Boiler chemical cleaning waste. Wastes resulting from the periodic cleaning of the inside

(waterside) of boiler tubes with chemical solutions.

• Floor and yard drains and sumps. Wastewaters collected by drains and sumps, including

precipitation runoff, piping and equipment leakage, and washwater (may include wastes not

associated with combustion processes).

• Laboratory wastes. Wastes generated in small quantities during laboratory analyses at the

facility (may include wastes not associated with combustion processes).

• Wastewater treatment sludge. Sludge generated from the treatment in settling basins or

other treatment facilities of liquid waste streams, including those above and others not

associated with combustion processes.

Non-utilities would be expected to generate smaller quantities of these wastes, consistent with

their smaller unit size (see Section 4.1.1). In some cases, non-utilities may generate insignificant

quantities of some low-volume wastes (see Section 4.1.4).

In addition to large-volume CCWs and low-volume wastes, non-utility combustors have the

potential to generate a wide range of process wastes unrelated to the combustion of fossil fuels,

consistent with the variety of industries represented by these facilities. These process wastes may be

disposed along with combustion wastes. No comprehensive data exist on the quantity of low-volume

wastes or non-combustion process wastes generated at non-utilities. For purposes of this study, however,

the total quantity generated is less significant than the quantity comanaged with large-volume wastes. 

Section 4.3 presents the available data on the quantities of waste comanaged and the frequency of

comanagement.

4.1.1 Boiler Technology

Coal-fired non-utilities use the same conventional combustion technologies as coal-fired utilities:

pulverized coal (PC) boilers, stokers, and cyclones. All three conventional technologies involve

combustion of coal in a boiler to heat water and produce steam. The steam may then be used to provide

process heat or generate electricity. Note that when non-utilities generate electricity, they generally do

so for onsite use rather than retail sale like the utilities and independent power producers covered in

Chapter 3. The three conventional technologies differ in design, particularly in the type and the size of

the coal particle to be burned, fuel delivery mechanisms, and the combustion conditions inside the boiler

furnace. Chapter 3 provides a description of these technologies and their waste generation implications.
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March 1999 4-5

Figure 4-3. Comparison of Utility and Non-Utility

Conventional Coal Combustion Technologies

Figure 4-3 compares the technologies used in the non-utility sector to those in the utility sector. 

The figure shows that, while PC boilers predominate for utilities, both PC boilers and stokers are

significant for non-utilities. Based on average capacity, non-utility units (14 megawatts average

capacity) are smaller than utility units (256 megawatts average capacity). Examining the size distribution

of individual boilers in Figure 4-4 confirms this observation. The majority of boilers in the non-utility

industry are in the 0 to 50 megawatt equivalent range, while those in the utility industry range from 10 to

1,000 megawatts. This size difference is most obvious for PC boilers, however. Non-utility PC boilers

are much smaller than those in the utility sector. Stokers in both populations are similar in size.

These differences in boiler technology have implications with respect to non-utility CCW

generation. The generally smaller boiler size for non-utilities means lower fuel usage, and, in turn, less

waste generation on a per-boiler basis. The greater proportion of stokers means greater waste generation

per unit of energy generated, due to the lower efficiency of these units. The greater proportion of stokers

also suggests a lesser percentage of the CCW generated will be in the form of fly ash.

4.1.2 Air Pollution Control Technologies

Air pollution control (APC) technologies used to meet the needs of coal combustion facilities

may be categorized broadly as particulate controls and flue gas controls. The technologies of most

relevance in the latter category are those for control of sulfur oxide emissions. As at utilities, the capture

of non-utility fly ash is governed by the particulate control technology used. Fly ash leaving the boiler

must be removed from the gas stream in which it is entrained or it will be released to the atmosphere. 

Generation of FGD waste results from the use of FGD technology. Chapter 3 describes both particulate

control and desulfurization technologies.
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4-6 March 1999

Figure 4-4. Distribution of Coal-Fired Boilers by Capacity

Figure 4-5 shows data on particulate control devices employed at non-utilities. Due to their

smaller size, non-utilities are less likely to be subject to particulate control regulations than utilities (see

Section 4.5). As a result, a significant proportion of non-utilities does not use particulate controls or

apply only low efficiency controls, such as gravity collection. This latter technique involves collecting

fly ash that falls out of flue gas due to gravity at points where flow changes. Gravity collection has a low

efficiency (less than 10 percent) compared to more complex particulate control devices. Units with

gravity collection as their only control thus collect smaller quantities of fly ash. The proportion of units

without particulate controls (or with low efficiency controls) leads to lower collection of fly ash in the

non-utility sector.

Still, a large number of coal-fired non-utilities do employ high efficiency particulate control

devices. These devices are most commonly mechanical collectors. This is because of the large

proportion of stokers in the non-utility population. Stokers generate larger fly ash particles for which

mechanical collection is efficient.

Of non-utility generating units that provided sulfur dioxide emissions information in the 1990

National Interim Emissions Inventory, only 4 percent reported using FGD technologies with the potential

to generate FGD waste. A few units reported controlling sulfur dioxide emissions through combustion

modifications or using particulate control technologies. The infrequent use of desulfurization technology

for non-utilities may result from differences in regulatory requirements between large utility boilers and

smaller non-utilities (see Section 4.5). Because of this, non-utilities as a group generate much less FGD

waste than do utilities.
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March 1999 4-7

Figure 4-5. Particulate Control Technologies Used at Coal-Fired Non-Utilities

4.1.3 Fuel Usage

The quantity of ash and slag generated is affected by the ash content of the fuel. Ash content is,

in part, determined by the rank of the coal: anthracite, bituminous, subbituminous, or lignite. These

ranks reflect the degree of metamorphism of the coal and typically correspond to the geologic age of the

coal deposit and to the heating value of the coal. Anthracite coal is the oldest rank and has the highest

heating value, while lignite is the youngest and has the lowest heating value (Stultz and Kitto, 1992). 

Table 4-1 shows the usage of each rank by non-utilities in 1990, along with typical ash content. Nonutilities use the same four classes of coal as do utilities; however, a large percentage of non-utility use is

bituminous coal.

In addition to coal rank, ash content depends on the specific coal producing region, mine, seam,

and production method. The ash content of coal burned by non-utilities varies from state to state. On

Coal Class Ash Content

Non-Utility Usage in 1990

(1,000 tons) Percent of Total Usage

Anthracite 4–19% 609 1%

Bituminous 3–32% 56,762 89%

Subbituminous 3–16% 2,576 4%

Lignite 4–19% 3,998 6%

Total 63,945 100%

Sources: CIBO, 1997c; EPA, 1990

Table 4-1. Fuel Usage by Coal-Fired Non-Utilities
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4-8 March 1999

average, however, ash content of non-utility coal is less than that of utility coal, 7.58 percent compared to

9.22 percent in 1996 (EIA, 1998c).

The type of coal burned also affects the distribution of the ash and slag waste streams generated

by combustion. For example, because softer lignite coals tend to have a lower ash fusion temperature,

they tend to generate boiler slag rather than bottom ash.

Like utilities, coal-fired non-utilities may burn other non-coal fossil fuels, such as petroleum

coke (see Section 5.1.3), or coburn coal with other fuels (see Section 3.1.3). No data are available on the

extent of these practices at non-utilities. Their impacts on waste generation and characteristics, however,

are expected to be similar to those discussed in Chapters 3 (for coburning) and 5 (for petroleum coke).

4.1.4 Supporting Processes

The generation of low-volume wastes primarily is associated with processes that support the

combustion process or make use of the products of combustion. Some of the same supporting and

enabling processes can accompany combustion at coal-fired non-utilities as at utilities, including the

following:

• Coal storage

• Coal processing

• Steam generation

• Cooling

• Water treatment

• Cleaning and maintenance.

Chapter 3 describes these processes in detail. The paragraphs below describe potential

differences in these processes at non-utilities with respect to waste generation. Little quantitative

information is available on the quantities of low-volume wastes generated at non-utilities.

Coal Storage and Processing

Because of their small capacity, coal-fired non-utilities generally do not store large quantities of

fuel onsite; therefore, they are less likely to generate significant coal pile runoff. Also, because of their

small capacity, non-utilities are less likely to conduct onsite coal cleaning. The large proportion of

stokers, which require less extensive feed processing than PC boilers, in the population means less need

for coal processing at non-utilities. Therefore, many non-utilities may not generate coal mill rejects

(including pyrites).

Steam Generation, Cooling, and Water Treatment

These processes generate low-volume wastes, including boiler blowdown, cooling tower

blowdown, water treatment wastes, and regenerant wastes. The quantities of these wastes generated are

related to the quantity of water used in the steam and cooling cycles, which in turn is related to

combustion capacity. Because of their smaller capacity, non-utilities generally use less water in

combustion-related processes, and, therefore, may generate smaller quantities of these wastes. In

addition, some non-utilities use steam directly for heat in industrial processes rather than to generate

electricity. In some cases, this practice may reduce the need for cooling, and in turn reduce the

generation of wastes associated with the cooling cycle.
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March 1999 4-9

Cleaning and Maintenance

Cleaning processes intermittently generate low-volume wastes, including air heater and

precipitator washwater and boiler chemical cleaning waste. Because of their small size, some non-utility

combustors may require less frequent cleaning, using lower volumes of cleaning solution, than utilities. 

This can result in a lesser generation of cleaning wastes. For example, boiler fireside cleaning may take

place so infrequently at a small non-utility combustor that the amount of cleaning waste generated over

the life of the facility may be small. Eighteen coal-fired non-utilities reported the quantity of boiler

fireside wash water and boiler waterside chemical cleaning rinse generated in response to a voluntary

survey by the Council of Industrial Boiler Owners (CIBO). The plants reported a combined average

annual volume of 35,941 gallons for both wastes (CIBO, 1997a).

4.2 WASTE CHARACTERISTICS

Analytical data to broadly characterize non-utility combustion wastes are not available. EPA,

however, believes that non-utility CCW characteristics are similar to those of utility CCWs. The greater

use of stoker technology in the non-utility sector does raise the possibility of differences in waste

characteristics. Such differences might stem from differences in combustion conditions and fuel feed

characteristics between stokers and the PC boilers used extensively by utilities. The available data,

however, do not indicate that these differences are significant for the purpose of evaluating risk to human

health and the environment.

CIBO provided a summary of leaching test results for fly ash and grate ash from stoker boilers

(CIBO, 1998). CIBO obtained these data by voluntary survey of 33 facilities (non-utility and utility) with

stoker boilers. Figure 4-6 compares these data with the leachate data for utility CCWs (from PC boilers)

collected for the 1993 Regulatory Determination. For most of the constituents examined, mean

concentrations in stoker ash are similar to or less than those in PC boiler ash. Also for most constituents,

the range of concentrations observed for stoker ash are similar to or within the corresponding ranges for

PC boiler ash. For selenium, the concentrations observed in stoker ash appear to be in the upper end of

the range of concentrations observed in PC boiler ash. However, the maximum reported concentration

for selenium in stoker ash appears to be an artifact of a high detection limit (0.5 milligrams per liter) in

the analysis used for at least two samples. This detection limit drives the maximum concentration and

inflates the mean concentration shown in Figure 4-6.

No data are available for organic constituents, dioxins, or radiation in non-utility CCWs. Based

on the observed similarity of non-utility and utility CCWs with respect to metals, however, these other

characteristics are not expected to be significantly different for non-utility CCWs. Data also are not

available characterizing the smaller amounts of FGD waste expected to be generated by non-utilities. 

There is no reason, however, to expect non-utility FGD wastes to have significantly different

characteristics than utility FGD wastes. Finally, the effects on waste characteristics of burning non-coal

fossil fuels, such as petroleum coke, or coburning coal and other fuels, are expected to be similar to those

discussed in Sections 3.2.3 and 5.2.

Based on the observed similarity of non-utility and utility CCWs with respect to constituents of

concern, the risk assessment for non-utility CCWs relies on data for comanaged utility CCWs. 

Comanaged utility waste data were chosen, rather than data representing large-volume non-utility CCWs

alone, because of the high rate of comanagement in the non-utility sector (see Section 4.3) and because

the comanaged waste data are more extensive than the CIBO stoker ash data.
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2

 The selection criterion considered both coal-fired and oil-fired boilers in an effort to collect information

for this section and Chapter 6 of this report; however, the state files contained little information regarding oil-fired

boilers. Therefore, the state file information ultimately obtained covered coal-fired non-utilities only.

4-10 March 1999

Figure 4-6. Comparison of Leachate Characteristics of Utility and Non-Utility Wastes

4.3 CURRENT MANAGEMENT PRACTICES

This section covers the management of wastes from the combustion of coal at non-utilities that

use conventional (non-fluidized bed combustion) combustion technologies. The Agency evaluated two

sources of data on this topic. The first is the CIBO non-utility survey (CIBO, 1997a). This was a

voluntary survey of CIBO member companies and a select list of other companies known to operate

non-utility boilers, conducted in support of this EPA effort. CIBO obtained responses from more than

50 coal-fired non-utilities. EPA believes this sample of facilities is representative of the non-utility

population in terms of industries covered and boiler and air pollution control technologies used.

The second source is regulatory permit file information EPA collected on the generation and

management of fossil fuel combustion (FFC) wastes from selected non-utilities in six states (Illinois,

North Carolina, Virginia, New York, Pennsylvania, and Wisconsin). These six states were selected

based on their large populations of non-utility boilers, both coal-fired and oil-fired.2

 The information

available from this effort varies from state to state, depending on the information requirements of state

regulations. For example, identification of waste management unit types was possible in five of the

states, while extensive information on environmental controls was available in only three. Information

from the search of state permit file information is used in this report to supplement the CIBO non-utility

survey results.
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3

 Information on management unit types was not available for the sixth state from which EPA collected

information.

March 1999 4-11

4.3.1 Unit Types and Location

Twenty-six coal-fired non-utility facilities provided information on waste management unit type

in the CIBO non-utility survey. These 26 facilities appear to operate a total of 27 waste management

units. This count assumes one management unit for each facility that reported a given management

practice. For example, it assumes one surface impoundment for each facility that reported using a

surface impoundment, when, in fact, the facility might have several impoundments. Thus, this analysis is

based on a lower bound on the number of waste management units.

The available data indicate landfilling is the primary practice for non-utility CCWs, with few

facilities operating surface impoundments. The 27 units identified in the CIBO non-utility survey

include 25 landfills and only two surface impoundments. Of the 49 units identified in five of the states

from which EPA obtained information,3

 42 (or 86 percent) are landfills. The other seven units include

four surface impoundments, a land application facility, and two units of unknown type. Non-utility waste

management units also appear to include a large proportion of offsite units. The 25 landfills in the CIBO

non-utility survey include eight commercial units (32 percent), which would be located offsite. The

survey did not distinguish between onsite and offsite management for landfills owned by the respondent. 

Because the review of state permit file information was directed at facilities operating captive disposal

units, the units identified in that effort all are onsite; however, other information collected during the

review of permit files suggests that the majority of non-utility CCWs are managed offsite in at least three

of the six states (Illinois, New York, and Pennsylvania). This is based on information from

Pennsylvania’s Residual Wastes Database and observations reported by officials in the other states.

A possible explanation for the predominance of landfills and the larger proportion of offsite units

in the non-utility population is the power generating capacity of these facilities. As discussed in Chapter

3, the smaller coal-fired utilities tend to dispose offsite in landfills, most likely because of economies of

scale and available space. If similar trends hold for non-utilities, one would expect a larger proportion of

landfills and offsite units for these small facilities as well.

4.3.2 Types of Waste Managed

As at utilities, large-volume CCWs at non-utilities frequently are combined for management. 

Sixty-one percent (31 of 51) of coal-fired non-utilities providing information in the CIBO non-utility

survey manage bottom ash and fly ash in the same unit. Just under half (4 of 9) of the facilities

generating FGD waste manage this waste in the same unit as fly ash.

As discussed in Section 4.1, non-utilities have the potential to manage large-volume CCWs with

a great variety of other wastes because they may generate both low-volume combustion wastes and

wastes from other processes. Figure 4-7 describes the combined management of other wastes with nonutility CCW, based on the CIBO non-utility survey. As shown in Figure 4-7, commingling of largevolume CCWs and other wastes at non-utilities appears to be as common as at utilities (see Section 3.3). 

The state permit file information generally supports this observation. For onsite landfills in two of the

three states for which information on combined management is available, 90 percent or more of the units

combine FFC wastes and other wastes (9 of 10 landfills in North Carolina and 17 of 18 landfills in

Wisconsin). On the other hand, in Pennsylvania, most non-utility CCW that is managed onsite is

managed separately in monofills. For offsite landfills, quantitative data are not available from the state 
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4-12 March 1999

files concerning the prevalence of comanagement; however, offsite landfills are likely to include

commercial units that accept a variety of wastes in addition to CCWs.

Table 4-2 details the specific types of wastes reported in the CIBO non-utility survey. Lowvolume combustion wastes comanaged include the same types reported for utilities, although coal mill

rejects (pyrites) in particular are comanaged less frequently at non-utilities. This is likely because, as

discussed in Section 4.1, coal mill rejects are less likely to be generated at non-utilities. The table also

shows a number of types of non-combustion wastes. Wastes identified in the state permit file

information include an even greater variety of non-combustion wastes: construction debris, paper and

wood mill waste, bark, lime, wood ash, spent alum mud, pulp fiber, incinerator ash, dimethylterephthalate, terephthalate acid, wastewater treatment sludge, aluminum sludge, filter cake, reactor

bottoms, spodumene ore residue, decrepitation kiln solids, asbestos, metallurgical process residues, filter

pads, plastics, pipe insulation, scrap metal, fibrets, crushed coal, masonry waste, paper products, sand,

oily soil, and sulfite liquor.

4.3.3 Environmental Controls

Information was available on environmental controls including liners, leachate collection,

ground-water monitoring, and runoff controls from the state permit files in three of the six states studied

(North Carolina, Virginia, and Wisconsin). In addition, the CIBO non-utility survey collected

information on the use of liners and issuance of regulatory permits. Table 4-3 summarizes this

information.

The state permit file data suggest that environmental controls are common at non-utility landfills;

however, the state permit file sample may be biased in this regard. Because they were identified through

state permit files, these units are subject to some form of regulatory oversight (e.g., permit review,

inspections, monitoring). This regulatory oversight may have resulted in the imposition of environmental

controls at these units. The liner data from the CIBO non-utility survey, which show a much lower

percentage of landfills with controls, support the hypothesis that the state permit file data reflect a sample

bias toward environmental controls. Based on this, the prevalence of environmental controls at nonutility landfills may be less than that at utilities.

Figure 4-7. Combined Management of CCWs with Other Wastes at Non-Utilities
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March 1999 4-13

Environmental Control

Number of Units Reporting

Data on Each Controla Percent with Controla Data Source

Liner 19 16% CIBO non-utility survey

27 52% State permit files

Leachate Collection 30 67% State permit files

Runoff Control 6 100% State permit files

Ground-Water Monitoring 34 94% State permit files

Regulatory Permit 23b 65%b CIBO non-utility survey

a The number of facilities reporting data on the presence or absence of each control type was different for each control type. For example, it

was possible to determine the presence or absence of leachate collection systems at 30 facilities. Twenty of these 30 (67 percent) had

leachate collection systems. The other 10 (33 percent) did not. Information on leachate collection systems was not available for units

other than these 30. b Data presented is number of non-utility plants, not number of management units. Unit-specific information was not available. Three of the

facilities counted as unpermitted indicated that permits are required, but have not yet been issued. Once these permits have been issued,

the percentage of permitted non-utility facilities would increase to 78 percent.

Table 4-3. Environmental Controls at Non-Utility CCW Landfills

Waste Type

Number of

Non-Utilities

Percent of Plants

Reporting (25 facilities)

Low-Volume Combustion Wastes

Boiler Blowdown 8 32%

Demineralizer Regenerant/Rinses 6 24%

Coal Mill Rejects/Pyrites 6 24%

Water Treatment Wastes 6 24%

Boiler Cleaning Chemical Waste 5 20%

Air Preheater/Precipitator Wash Waste 4 16%

Cooling Tower Blowdown 3 12%

Coal Storage Pile Runoff 2 8%

Other Wastes*

Wastewater Treatment Sludges/Residuals 8 32%

General Site Runoff 7 28%

Floor Drains/Sumps 6 24%

Laboratory Wastes 5 20%

Miscellaneous Plant Wastes 5 20%

Domestic/Municipal Wastes 3 12%

Contaminated/Dredged Soils 2 8%

Other Unspecified Wastes 5 20%

* Wastes not clearly related to combustion processes were categorized as other wastes.

Source: CIBO, 1997a

Table 4-2. Types of Wastes Comanaged with Non-Utility CCWs
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4-14 March 1999

Figure 4-8. Types of Liners at Non-Utility CCW Landfills

Liners

As discussed above, the CIBO data suggest a much lower percentage of landfills are lined than

the state permit file information may indicate. It is unclear which sample is more representative,

although the state permit file units are not geographically representative and are probably biased toward

having liners. Figure 4-8 shows the types of liners reported in the state permit file information. Only

limited data exist for non-utility surface impoundments. The two impoundments in the CIBO non-utility

survey are unlined.

4.3.4 Beneficial Uses

Current statistics are not available on the quantities of non-utility CCWs that are utilized;

however, available data indicate that beneficial use of these wastes does indeed occur. The small sample

of facilities responding to the CIBO non-utility survey (CIBO, 1997a) provided information on whether

they utilize some of their CCW. Table 4-4 summarizes these responses. Overall, 56 percent of

respondents described one or more beneficial uses. The uses reported are the same as those described for

utility CCWs, with cement and concrete and construction fill uses being reported most commonly. These

results are consistent with the statistics showing these uses to be the most common for utility CCW.

Based on these results and because of the similarities between utility and non-utility CCWs, EPA

believes that nearly all of the beneficial uses described for utilities also are applicable to non-utility

wastes. In some cases, economic barriers to the commercialization of these uses for non-utility CCWs

may exist because of the smaller volumes of waste generated. Individual non-utility generators may not

be able to competitively market their byproducts for uses (such as construction fill) that require large

volumes of CCW. The extent of such barriers, as well as techniques for overcoming them, require

further investigation.
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4.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE

ENVIRONMENT

4.4.1 Potential Ground-Water Risks to Human Health

Section 3.4 provides a discussion of the methodology employed by EPA in assessing risks from

coal-fired utility comanaged wastes. EPA followed a similar approach for wastes from the non-utility

sector, with several important differences. First, EPA initially obtained very few data on the

characteristics of wastes generated in non-utility boilers. To overcome this data gap, EPA used the waste

characterization data developed for the utility comanaged waste sector to represent wastes from nonutilities. As non-utility data were developed and provided by industry (CIBO, 1998), EPA compared

utility and non-utility waste characteristics as a function of fuel, boiler type, and boiler size to

corroborate the initial assumption that the wastes from the sectors are similar (see Section 4.3). Second,

EPA found the primary differences between the sectors, from a risk assessment standpoint, to be in waste

management practices and waste unit sizes. Non-utility boiler operators were found to generate smaller

quantities of wastes overall, and to manage these wastes either in small onsite landfills or large onsite or

offsite units containing primarily other non-FFC wastes. EPA found the proportion of FFC wastes in

most mixed waste disposal units to be small, and, therefore, judged the risks from such units attributable

to FFC wastes to be similarly small. EPA, therefore, focused its examination of ground-water pathway

risks on small onsite landfills. Finally, EPA found that non-utility boilers reflect a geographic

distribution distinct from the larger utilities, and so modified its modeling scenarios accordingly.

Note that EPA did not model risks from minefilling of non-utility FFC wastes. EPA believes

minefill practices to be the same for utility and non-utility operators. See Section 3.4.5 for an overview

of EPA concerns and data limitations for minefills.

Beneficial Use

Number of Facilities

Reporting Percent

Do Not Utilize 22 44%

One or More Beneficial Use* 28 56%

Cement/Concrete 18 36%

Flowable Fill 6 12%

Structural Fill 14 28%

Road Base/Subbase 13 26%

Miinefill 8 16%

Agricultural Use 7 14%

Waste Stabilization 5 10%

Snow and Ice Control 3 6%

Blasting Grit/Roofing Granules 1 2%

Mineral Filler 1 2%

Total 50 100%

 * Total shown is less than the sum of individual uses because a facility may employ more than one beneficial use.

Note: Data shown are for the 50 (of 51) facilities that provided beneficial use information.

Source: CIBO, 1997a

Table 4-4. Non-Utility FFC Waste Beneficial Uses
Report to Congress on Wastes from the Combustion of Fossil Fuels

4-16 March 1999

Scenario Constituentb

Deterministic

Risk, Central

Tendency

Deterministic

Risk, High-End

Corresponding

Monte Carlo

Percentile

Monte Carlo 95th

Percentile

NMa Arsenic 1.4×10-8 1.8×10-4 99 6.5×10-6

Barium HQ <1 HQ = 0.2 99 HQ = 0.002

a

NM = non-utility onsite monofill (i.e., managing CCWs and low-volume combustion wastes, but not other non-combustion industrial wastes). b

Constituents are limited to those for which estimated risks exceeded target values in the April 1998 Draft Final Report. Revised nickel

screening results were HQ <1 so modeling results are not reproduced here. All other metals modeled yielded an HQ <1

Note: Results shown are those from the October 10, 1998, Sensitivity Analysis.

Table 4-5. Comparison of Deterministic and Monte Carlo Risk Model Results for NonUtility Coal Combustion Waste Ground-Water Pathway Scenario

Non-Utility Ground-Water Risk Findings

Table 4-5 summarizes selected results from the deterministic and probabilistic analyses of risk

from non-utility coal combustion wastes for the adult receptor. Overall, EPA found that the risks

associated with all modeled constituents of concern, except for arsenic, fell below a hazard quotient (HQ)

of 1 or lifetime cancer risk of 1×10-6. Potential risks associated with arsenic in the high-end deterministic

scenario exceeded 1×10-4.

Comparison of the deterministic and Monte Carlo results reveals that the deterministic results

exceed the 95th percentile Monte Carlo results. Specifically, 99 percent of the 2,000 Monte Carlo

simulation combinations of parameter values exceed the deterministic high-end results for arsenic and for

barium. Even at the 95th percentile level, the risks predicted by the Monte Carlo simulations were almost

two orders of magnitude below the corresponding risks estimated for the high-end scenario.

In essence, using coal-fired utility comanaged waste characteristics data for the non-utility

analysis, EPA found cancer risk from arsenic from onsite landfills to be similar to those found for

comanaged wastes, at the 1×10-4 level. EPA also considered the time at which risks were predicted to

result from the release of constituents of concern. EPA found that the concentration of arsenic in ground

water at the receptor well would not reach the health-based levels (HBL) for arsenic (i.e., achieve a risk

level of 1×10-6) for more than 1,400 years.

Table 4-6 summarizes the estimated risks to adult and child receptors for the high-end

deterministic scenario for non-utility CCWs. Overall, the results show that risks to the two child types

and adult were similar.

Scenario Constituentb

High-End Deterministic Risk

Adult Young Child Child

NMa Arsenic 1.8×10-4 2.3×10-4 1.6×10-4

Barium HQ = 0.2 HQ = 0.3 HQ = 0.2

a

NM = Non-utility on-site monofill (i.e., managing CCWs and low-volume combustion wastes, but not other non-combustion industrial wastes). b

All other metals modeled yielded HQ <1

Note: Results shown are from the October 10, 1998, Sensitivity Analysis

Table 4-6. Comparison of Adult and Child Risk Model Results

for Non-Utility Coal Combustion Waste – Ground-Water Pathway Scenario
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 4-17

4.4.2 Potential Above-Ground Multi-Pathway Risk to Human Health and the

Environment

Human Health Risk

Similar to the results discussed in Section 3.4.2, no plausible non-ground-water risks were found

for the non-utility wastes except in the event of possible use in agricultural applications, where risks

would be similar to those noted for the utility wastes (in excess of 10-5).

Ecological Risk

No ecological risks were found for this category of ash in that no disposal in large surface

impoundments was noted.

4.4.3 Documented Damages to Human Health and the Environment

Summary of Findings

EPA collected information on the generation and management of combustion residues at nonutilities from six states (Illinois, New York, North Carolina, Pennsylvania, Virginia, and Wisconsin). 

Detailed, facility-specific information for about 50 sites was collected from conversations with State

personnel and the review of facility-specific files at state offices. Based on this review, EPA concluded

that none of these sites meet the “test of proof” for damage cases. Although releases of waste have been

documented and ground-water monitoring results show exceedences of standards in some cases,

documentation was not available which would satisfy the EPA tests of proof for damage cases.

EPA also reviewed four Superfund Records of Decision (ROD) involving non-utility CCWs

(codisposed with other wastes). In one of these decisions (Wheeler Pit, Wisconsin, ROD/R05-90/130),

no principal threat warranting treatment has been identified. In a second decision (U.S. DOE Feed

Materials Production Center), FFC wastes were found not to contribute to contamination.

In the remaining two cases, non-combustion wastes are codisposed with CCWs and the source of

the ash (utility or non-utility) is unspecified. In one case, the Lemberger landfill (Wisconsin, ROD/R05-

91/186), the source material does not implicate, or rule out, contributing influences from CCWs. In the

second case, Salem Acres (Massachusetts, ROD/ROI-93/078), an area used as a fly ash waste pile is

identified as a potential source of risk.

Based on information available and in consideration of EPA’s “tests of proof,” EPA identified

the cases in Table 4-7 as potential damage cases.

Cases Meeting Test of Proof

The Salem Acres (Massachusetts) National Priority List site comprises unlined sludge lagoons

containing tannery wastes (typical components include chromium and greases), contaminated soil areas,

a landfill, a debris pile, and a fly ash pile. Wastes were disposed at the site from the mid 1940s to 1969;

the source of the ash (utility or non-utility) was not described in the source documents. The volume of

fly ash is estimated to be 9,600 cubic yards; the volume of lagoon sludge is estimated to be 21,000 cubic

yards. Therefore, the ash represents a significant percentage of the overall waste volume present. 

Ground-water monitoring showed arsenic to be present below its maximum contaminant limit. The ROD

concluded that several areas of the site, including the fly ash pile, pose health risks exceeding risk

management criteria. Ground-water risks from antimony and manganese also were identified.
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An old gravel pit, the Lemberger Landfill (Wisconsin) was used for waste disposal from 1940 to

about 1980. Wastes disposed included general refuse, power plant fly ash (1969 to 1977) and bottom ash

(1969 to 1976), and municipal solid waste. Other industrial wastes also were disposed at a nearby site. 

Environmental effects and damages included the seepage of landfill leachate into adjacent property,

presence of volatile organic compounds in drinking water wells, the presence of organic compounds in

surface water, and potential effects from direct soil or waste contact. Inorganic constituents detected in

the ground water include barium, cadmium, and chromium. The source of contamination was identified

as the landfilled waste, although specific wastes were not identified in the ROD as contributing or not

contributing to the ground-water contamination.

Evaluation of the sites is complicated by three factors: disposal ceased at least 10 years ago, noncombustion wastes are mixed with CCWs at each of the sites, and the information does not specify if

CCWs result from utility or non-utility operations. These two cases, however, meet EPA’s tests of proof

as damage cases for purposes of this study.

4.5 EXISTING REGULATORY CONTROLS

EPA’s objective in this analysis was to identify and evaluate the existing regulatory controls that

pertain to the management of non-utility CCWs. The regulatory analysis is directed toward addressing

the question of whether existing regulations adequately protect human health and the environment. The

analysis also is helpful in understanding waste generation and current management practices.

The sections below discuss regulations addressing air pollution, water pollution, and solid and

hazardous waste, respectively. Air regulations are relevant primarily because of their effect on waste

generation. Water regulations have an influence both on waste generation and management and, in

particular, address the impact of CCWs on surface waters. Solid and hazardous waste regulations are of

the greatest interest because they directly govern waste management practices.

The sections below describe federal regulations in each of these areas. In many cases, the

implementation of these federal programs is carried out by the states. Therefore, where appropriate,

Damage Case Wastes Present Event Test of Proof Comment

Salem Acres (MA) Large volume; many

other wastes present

including MSW and

ISW

PAHs, VOCs, PCBs,

and metals, including

As and Cr, in soils,

surface waters, and

ground water

Administrative

(on NPL)

Contribution of FFC wastes to

damage not separable from

other wastes. Remedial

measures include excavation,

treatment, and removal of

sludges and soils; proposed

fixation with fly ash; Subtitle C

capping if performance criteria

are not met

Lemberger Landfill, Inc.

(WI)

Comanaged wastes;

many other materials

including MSW, with

adjacent site receiving

ISW

Elevated concentrations of As, Cr, and Pb

onsite, plus VOCs,

PCBs

VOCs in private wells

initiated action

Administrative

(on NPL)

>$20 million cleanup

Contribution of FFC wastes to

damage not separable from

other wastes

Table 4-7. Potential Damage Cases
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 4-19

aspects of state implementation also are discussed. Because the nuances of state implementation are of

particular importance with respect to solid waste regulation, state solid waste programs are discussed in

detail. Where appropriate, state controls on two of the CCW beneficial uses of concern to EPA—

minefilling and soil amendment—are described.

4.5.1 Regulations Addressing Air Pollution

The federal Clean Air Act (CAA) is intended to protect and enhance the quality of the nation’s

air resources. The CAA requirements most relevant to non-utilities include the following:

• National Ambient Air Quality Standards (NAAQS) for particulate matter (PM)

• NAAQS for sulfur dioxide

• NAAQS for ozone

• National Emissions Standards for Hazardous Air Pollutants (NESHAP).

Title IV acid rain provisions, the fifth set of requirements that affect fossil fuel combustors as a group,

currently apply only to the largest coal-fired utility generating units, and, therefore, are not relevant for

non-utility units. Historically, CAA requirements have been a significant factor affecting the generation

and collection of certain non-utility CCWs (specifically fly ash and FGD waste). Recent and

forthcoming changes in these requirements also may impact waste generation or characteristics, as

discussed below.

NAAQS for Particulate Matter

The NAAQS for PM establish maximum concentrations of PM with diameter less than or equal

to 10 micrometers (PM10) in the ambient air. These standards are among the factors motivating the use

of particulate control technologies at FFC facilities. EPA recently proposed to lower the size criterion to

2.5 micrometers, which may affect the volume of fly ash collected and selection of control technology;

however, final standards will not be issued for at least 5 years, so the impacts of the new standard are

difficult to predict at this time.

The NAAQS for PM are implemented through New Source Performance Standards and State

Implementation Plans.

New Source Performance Standards (NSPS). The NSPS subject newly constructed or

modified units to specific PM emissions limits. These limits may be met by changing fuel types,

modifying combustion conditions, or installing control devices. The applicability of the NSPS and the

specific limits imposed vary with the age and size of the combustion unit, with older and smaller units

less likely to be subject to the NSPS. Specifically, the regulation of non-utilities can be considered in the

following three categories (one of the four categories discussed for coal-fired utilities in Chapter

3—facilities subject to Subpart Da—applies specifically to utilities; therefore, it is not relevant to nonutilities):

• 40 CFR 60 Subpart D governs the standards of performance for new fossil fuel-fired steam

generators that were constructed or underwent major modification after August 17, 1971. 

Subpart D affects only units that are capable of burning fossil fuels at greater than 73

megawatts (MW) of heat input rate.

• Subpart Db affects coal-fired units with the capacity to fire fuel at greater than 29 MW of

heat input rate that commenced construction or modification after June 19, 1984.
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• Subpart Dc governs coal-fired units constructed or modified after June 9, 1989, with

capacity to fire fuel at less than 29 MW but greater than 8.7 MW of heat input rate.

The NSPS requirements discussed above apply to all fossil fuel steam generating units, utility or

non-utility. Non-utilities, however, tend to have smaller capacities than utilities, and, therefore, are more

likely captured by those NSPS requirements that apply to smaller capacity units (i.e., Subparts Db and

Dc). Under the NSPS regulations, facilities that were in operation before the dates stated in each of the

subparts are considered “grandfathered” and would not be subject to the newer standards unless they

underwent a major modification.

State Implementation Plans (SIPs). The performance standards above can be enforced by a

Federal, State, or local regulatory agency. There are additional CAA regulations that could require a

coal-fired unit to install a particulate removal device notwithstanding the grandfather clause in Subparts

D, Db and Dc. SIPs may impose, on a state-by-state basis, PM controls of varying stringency on specific

sources or categories of sources, including coal-fired non-utilities. Such controls are required under Title

I of the CAA if a particular area is in nonattainment for the NAAQS for a criteria pollutant such as PM. 

For this reason, SIP controls will generally be more stringent in such nonattainment areas. In attainment

areas, the prevention of significant deterioration (PSD) program requires new sources to apply Best

Available Control Technology (BACT), which must be at least as stringent as NSPS.

NAAQS for Sulfur Dioxide

Like the NAAQS for PM, the NAAQS for sulfur dioxide establish a maximum concentration of

sulfur dioxide in the ambient air. The NAAQS for sulfur dioxide are implemented through NSPS and

SIPs. The functioning and applicability of the sulfur dioxide NSPS requirements are similar to those for

PM, although there is less variation based on age and size.

Each of the three categories of coal-fired non-utilities regulated under Subparts D, Db, and Dc is

subject to the same requirement: sulfur dioxide emissions must be less than 520 nanograms per joule

(ng/J) of heat input. Facilities with greater than 22 MW of heat input capacity generally also must

achieve a 10-percent reduction in their sulfur dioxide emissions, based on the potential concentration in

fuel. An additional category of coal-fired facilities, those constructed or modified after June 9, 1989, and

between 2.9 and 8.7 MW of heat input capacity, also must meet the 520 ng/J standard, but may do so

based on certification from the fuel supplier that the sulfur content of the fuel is low enough to meet the

standards.

In addition to NSPS, states may impose controls through their SIPs to meet the sulfur dioxide

NAAQS. These controls may vary in stringency depending on attainment status and may be placed on

specific sources or categories of sources, including coal-fired non-utilities.

In spite of the similarities in NAAQS programs for sulfur dioxide for utilities and non-utilities,

the prevalence of FGD technologies among non-utilities is less than that among utilities (see Section 4.1). 

This may be because Title IV requirements currently do not apply to non-utilities, because of the lack of

percent reduction requirements on these smaller facilities, because of differences in fuel characteristics,

and/or because of differences in SIP requirements for non-utilities.

NAAQS for Ozone

The NAAQS for ozone establish a maximum concentration of ozone in the ambient air. EPA

recently lowered this concentration from 0.12 parts per million (ppm) to 0.08 ppm. The new standard
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March 1999 4-21

allows four exceedences of the maximum in a region over a 3-year period. EPA expects states will meet

the new standard by amending their SIPs to limit nitrogen oxide emissions at utilities. Therefore, the

recent changes are not expected to affect non-utilities (and, in turn, non-utility waste generation)

significantly.

NESHAP

Under the NESHAP, EPA is required to establish technology-based standards for 189 hazardous

air pollutants (HAPs). These standards are to be set on an industrial category basis and will apply to

facilities that emit greater than 10 tons/year of any one HAP or greater than 25 tons/year of any

combination of HAPs.

EPA has not specifically studied HAP emissions from non-utility coal combustors. Because

NESHAP will be set on an industrial category basis, when promulgated, the impact of these regulations

on waste generation and characteristics may vary depending on the industrial sector of the non-utility

combustor.

4.5.2 Regulations Addressing Water Pollution

Under the federal Clean Water Act, the National Pollutant Discharge Elimination System

(NPDES) controls discharges to waters of the United States. As discussed below, the controls required

under NPDES affect the collection and management of CCWs. In states authorized by EPA, these

controls are implemented through state programs (often termed State Pollutant Discharge Elimination

Systems, or SPDES). Because state programs must be at least as stringent as the federal program, the

discussion here focuses on federal requirements as a lowest common denominator. NPDES requirements

apply differently to two categories of discharges: process wastewaters and stormwater runoff.

NPDES Requirements for Process Wastewaters

Non-utility coal combustors face NPDES requirements for process wastewaters that are specific

to their industrial sectors. In most cases, under these requirements each discharge requires an individual

NPDES permit with numeric limitations based on Best Practicable Control Technology Currently

Available (BPT), Best Available Technology Economically Achievable (BAT), or New Source

Performance Standards (NSPS). Facilities that discharge to publicly owned treatment works (POTWs)

rather than directly to surface waters face Pretreatment Standards for Existing Sources (PSES) similar to

BAT or BPT or Pretreatment Standards for New Sources (PSNS) similar to NSPS.

As discussed in Section 4.3, non-utility CCWs are rarely managed wet (although they may be

conditioned with liquids during management for dust control). Therefore, the NPDES process

wastewater requirements generally are not relevant to management of these wastes. In those cases in

which these wastes are managed wet, the most relevant requirements are total suspended solids (TSS)

limits. The specific NPDES effluent standards applicable to a non-utility depend on the facility’s

industrial category. Effluent standards expected to apply to large numbers of non-utility fossil fuel

combustors include those for the following industry categories:

• Pulp, paper, and paperboard (40 CFR Part 430)

• Organic chemicals, plastics, and synthetic fibers (40 CFR Part 414)

• Inorganic chemicals manufacturing (40 CFR Part 415)

• Textile mills (40 CFR Part 410)

• Timber products processing (40 CFR Part 429)
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• Iron and steel manufacturing (40 CFR Part 420)

• Sugar processing (40 CFR Part 409)

• Grain mills (40 CFR Part 406).

The standards for these categories include TSS limits, and these limits are applicable to nearly all

of the industrial subcategories covered under each category. Some subcategories are subject to zero

discharge requirements. Based on the SIC codes reported by non-utilities in the 1990 U.S. EPA National

Emissions Inventory database, these industrial category requirements are expected to cover roughly 20

percent of non-utility fossil fuel combustors. A number of other facilities are scattered through other

industrial categories, many of which are also subject to TSS limits. Some facilities (such as institutional

fossil fuel combustors) may not be subject to the specific standards of any industrial category. In these

cases, the specific effluent limitations would be determined on a case-by-case basis as part of the nonutility’s individual NPDES permit.

In addition, the steam electric category NPDES requirements applicable to utilities also may be

incorporated in individual permits at non-utilities to supplement their industrial category requirements. 

Application of steam electric requirements to relevant waste streams at non-utility fossil fuel combustors

is left to the best professional judgement of the individual permit writer (EPA, 1996). The steam electric

category NPDES requirements place TSS limits directly on fly ash handling and bottom ash handling

waters. In addition, the NSPS for the steam electric category include a zero discharge requirement for fly

ash handling water.

In those cases in which non-utility CCWs are managed wet, the TSS and zero discharge

requirements discussed above are relevant as follows. Facilities may have to settle or otherwise remove a

certain amount of waste solids from the handling water to meet the TSS limits prior to discharge. Zero

discharge requirements effectively eliminate the release of waste solids to surface water; thus, the

requirements control the direct release of fly ash, bottom ash, and any treatment solids to surface waters.

NPDES Requirements for Stormwater

NPDES stormwater requirements apply to stormwater runoff from FFC facilities. Stormwater

runoff may include runoff from operating areas, ash handling areas, and waste management units. Like

the process wastewater requirements, stormwater requirements have been established on an industrial

sector basis. The NPDES stormwater requirements, however, are additive across industrial sectors. 

Therefore, steam electric stormwater requirements apply to non-utilities just as they apply to utilities. 

A chemical manufacturer, for example, operating a fossil fuel-fired boiler must meet both chemical

manufacturing and steam electric requirements.

Facilities can meet the stormwater requirements by including stormwater in their individual

NPDES permit or seeking coverage under a general permit by submitting a Notice of Intent (NOI). 

Individual permit control and monitoring requirements will be facility-specific, subject to the judgment

of the permit writer.

When covered by a general stormwater permit, requirements include implementation of a

stormwater pollution prevention plan, “reasonable and appropriate” control measures, and 1 or 2 years of

monitoring and reporting. No site visit by regulators is required under the general permit. Under the

general permit approach, non-utilities have a great deal of flexibility in selecting appropriate control

measures for runoff that may have contacted CCWs. The general permit requirements include

recommended best management practices for stormwater at steam electric facilities, landfills, treatment

works, and construction areas greater than 5 acres. Because these requirements are additive across
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 4-23

industrial sectors, if the hypothetical chemical manufacturer described above also operated an onsite ash

landfill, that facility would have to meet landfill requirements in addition to chemical manufacturing and

steam electric requirements.

Because the stormwater program is relatively new and managed only by authorized states, the

number of facilities with general versus individual permits is not known. EPA handles NOIs for 10

nonauthorized states. In these states, 700 steam electric facilities (both utility and non-utility) have filed

for general permits.

4.5.3 Regulations Addressing Solid and Hazardous Waste

EPA regulates the management of solid and hazardous waste through Subtitles C and D of the

federal Resource Conservation and Recovery Act (RCRA). Subtitle C of RCRA establishes a “cradle-tograve” management system for wastes that are considered hazardous because they fail tests based on their

physical and chemical characteristics (i.e., toxicity, corrosivity, ignitability, and reactivity) or because

they are listed as hazardous by EPA. Federal regulations establish stringent environmental and

administrative controls that must be applied to the management of these wastes. Non-utility coal

combustion wastes are currently exempt from federal regulation as hazardous waste under Subtitle C

pending this Report to Congress and the subsequent regulatory determination. Therefore, these wastes

currently are subject to the requirements of Subtitle D of RCRA as nonhazardous solid waste.

Implementation of Subtitle D is the responsibility of individual states, but nothing prevents states

from imposing more stringent requirements (including hazardous waste requirements) on FFC wastes. 

Currently, 44 states (representing 87 percent of non-utility coal-fired electrical generation capacity)

duplicate the federal policy exempting CCWs from hazardous waste regulations. The six remaining

states (Kentucky, Tennessee, Washington, New Jersey, Maine, and California) do not exempt CCWs

from hazardous waste regulation. In these states, non-utility CCWs that fail the hazardous waste

characteristic tests are subject to hazardous waste requirements. These wastes, therefore, must be

managed in units that meet permitting, design, operating, corrective action, and closure standards.

Based on available characterization data, however, non-utility CCWs seldom are expected to fail

the hazardous waste characteristic tests. The majority of non-utility CCWs would be subject to state

requirements under Subtitle D because they do not fail the hazardous waste tests and/or are generated in

the 44 states that duplicate the federal exemption. States generally regulate onsite waste management

units that handle only non-utility CCWs using the same regulatory approaches used for utility CCW

management units. They often regulate units, both onsite and offsite, that manage non-utility CCWs

along with other nonhazardous industrial wastes in accordance with industrial Subtitle D programs. 

These programs are expected to be essentially the same as those applicable to CCW-only management

units. Detailed review of regulations in several states supports the view that states regulate non-utility

CCWs in the same manner as utility CCWs.

Table 4-8 shows data on state regulatory authority with respect to non-utility CCW landfills. 

These data show that the majority of states have the authority to require permits and to impose physical

controls and monitoring requirements on non-utility landfills, at least on a case-by-case basis. The types

of regulatory controls include siting controls, liners, leachate collection systems, ground-water

monitoring, closure controls, daily (or other operational) cover, and fugitive dust controls. EPA believes

that the use of such controls has the potential to mitigate risks, particularly ground-water pathway risks,

from comanaged waste disposal. The sufficiency of this mitigation depends on the extent to which states

are exercising their authority in situations in which climate, geology, site-specific conditions, and waste

characteristics affect the magnitude of the risk.
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Section 4.3 summarizes the use of regulatory permits and environmental controls at non-utility

waste management units. The available data suggest that states have exercised their authority to impose

controls, although perhaps to a lesser extent at non-utilities than at utilities. To further examine state

implementation of solid waste requirements on non-utility CCWs, EPA examined in greater detail the

regulations applicable in five states: Indiana, Pennsylvania, Wisconsin, North Carolina, and Virginia. 

These five states account for more than 20 percent of coal-fired non-utility electrical generation capacity. 

Table 4-9 summarizes the requirements in each of these five states. Because surface impoundments are

uncommon for non-utilities, this analysis focuses on landfill regulations.

Based on this detailed analysis, it appears that state requirements have become increasingly

stringent over time. States vary in their approaches to regulating non-utility CCW landfills. For

example, programs in Indiana and Pennsylvania impose requirements tailored to the characteristics of the

waste. North Carolina may impose requirements based on site-specific modeling. In Virginia,

requirements apply generically to all industrial wastes. Wisconsin may modify its requirements

specifically for landfills designed to receive coal combustion ash. In several of the states studied, CCWs

may be disposed of in older landfills that are “grandfathered” out of requirements imposing design

requirements such as liners.

Table 4-9. State Waste Management Requirements Applicable to Non-Utility CCWs

in Selected States

Indiana

Landfill

Requirements

Landfills are classified according to TCLP results for the wastes to be disposed. Specific design

requirements depend on the class of the landfill. Based on available characterization data, most nonutility CCWs would be amenable to Type III landfills. Requirements for these include clay liner

(thickness of 3 feet), siting restrictions, fugitive dust control, weekly cover, soil erosion control, 2-foot

clay cap at closure, and revegetation at closure. Leachate collection systems are not required but may

be used in some cases to relax the liner thickness requirements.

Grandfather Clause Facilities that existed prior to September 1989 may continue to operate, but any expansions at these

facilities must comply with the requirements above.

Number of Statesb Percent of Statesc Percent of Capacityd

Hazardous Waste Exemptiona 44 88% 87%

Permit Onsite 41 82% 82%

Permit Offsite 48 96% 96%

Siting Controls 46 96% 89%

Liners 43 86% 88%

Leachate Collection Systems 42 84% 81%

Ground-Water Monitoring 46 92% 90%

Closure Controls 45 90% 94%

Cover and/or Dust Controls 49 98% 96%

a

 Exemption from state hazardous waste regulations for coal combustion wastes

b

 Number of states with authority to impose the indicated requirement, either by regulation or on a case-by-case basis

c

 Percent of surveyed states with authority

d

 Percent of surveyed generating capacity represented by states with authority

Sources: CIBO, 1997c; ASTSWMO, 1995; EPA, 1995b; and ACAA, 1996a

Table 4-8. State Regulatory Controls on Non-Utility Coal Combustion Waste Landfills
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 4-25

Pennsylvania

Landfill

Requirements

Landfills are classified according to TCLP results for the wastes to be disposed. Specific design

requirements depend on the class of the landfill. Based on available characterization data, most nonutility CCWs would be amenable to Class III landfills. Requirements for these include siting restrictions,

a 4-foot attenuating soil base (or 1-foot-per-4-feet of waste), fugitive dust control, daily cover, soil

erosion control, ground-water monitoring, 2-foot clay cap at closure, and revegetation at closure.

Grandfather Clause Units permitted prior to July 4, 1992 were required to modify their operations to comply with the above

requirements by July 4, 1997. Liner and leachate collection requirements may be modified if the

operator can demonstrate that the unit has not caused unacceptable ground-water degradation.

Minefill

Requirements

CCWs must meet TCLP limits for disposal at a Class III landfill. Ground-water monitoring is required.

Soil Amendment

Requirements

CCWs must meet pH limits. State agency notification and runoff and erosion controls are required. 

There are siting limitations.

North Carolina

Landfill

Requirements

Industrial waste landfills must demonstrate that their design will ensure that the state ground-water

standards are not exceeded at the compliance boundary. The design criteria for demonstrating this

include a composite liner, leachate collection system, and cap at closure. Alternatively, the operator

may submit ground-water modeling results that demonstrate, based on hydrologic and climatic

conditions and waste characteristics, that the standards will be met.

Grandfather Clause To continue operating after January 1, 1998, landfills operating prior to October 1, 1995 must

demonstrate that their original design or proposed design changes will meet the ground-water

standards. The state has the authority to require design modifications if ground-water modeling

methods or results are inadequate.

Wisconsin

Landfill

Requirements

Requirements include clay or composite liners, leachate collection systems, fugitive dust controls, 2-foot

clay cap at closure, revegetation at closure, and ground-water monitoring. The state may modify the

requirements for landfills designed to receive “high-volume” industrial waste, specifically coal ash waste,

on a case-by-case basis.

Grandfather Clause Landfills with plan of operations approved prior to July 1, 1996, are exempt from liner and leachate

collection requirements. For landfills constructed prior to February 1, 1988, the state may require

ground-water monitoring on a case-by-case basis.

Virginia

Landfill

Requirements

There are separate programs for industrial landfills and sanitary landfills. While sanitary landfills

primarily manage household waste, they are allowed to receive nonhazardous industrial solid wastes,

such as CCWs. Offsite landfills may be either industrial or sanitary landfills; onsite landfills are expected

to be industrial landfills.

For industrial landfills, design requirements include leachate collection systems, run-on controls, liner (1

foot of compacted clay or equivalent), cap at closure, fugitive dust controls, and ground-water

monitoring. A double liner system in which the primary liner is synthetic may be used in lieu of groundwater monitoring. For fly ash and bottom ash from the combustion of fossil fuels, periodic cover or dust

control measures such as surface wetting or crusting agents are required.

For sanitary landfills, design requirements include leachate collection systems, run-on and run-off

controls, composite liner, cap at closure, revegetation at closure, daily cover, fugitive dust control, and

ground-water monitoring. Air pollution control residues (such as fly ash) should be incorporated into the

working face of the landfill and periodically covered to prevent them from becoming airborne.
Report to Congress on Wastes from the Combustion of Fossil Fuels

4-26 March 1999

Grandfather Clause Landfills permitted prior to 1988 must submit a monitoring plan, but may continue operating without

retrofits as long as they do not expand.

Minefill

Requirements

Use in structural fills, mine reclamation, or mine refuse disposal requires notification and development of

design, operation, and closure plans. CCWs thus used must not exceed the toxicity characteristic levels

for metals. Fugitive dust and run-on and runoff controls and 18 inches of cover at closure are required.

Soil Amendment

Requirements

Agricultural uses of CCW are exempt from the solid waste regulations provided they meet the

requirements of the Virginia Department of Agriculture and Consumer Services.

4.6 WASTE MANAGEMENT ALTERNATIVES

The risk assessment identified potential ground-water pathway risks to human health from nonutility CCWs managed in unlined landfills. Mitigation of these potential risks might be accomplished

through the use of technologies that prevent or contain and collect leachate from non-utility CCW

landfills. Specifically, EPA identified the combination of technologies in Table 4-10 as an alternative

that would be practical and effective to target and mitigate the potential ground-water risk. The

technologies shown in Table 4-10 are considered further in the cost and economic impact analysis

(Section 4.7). Section 4.7 includes the option of sending waste to an offsite commercial landfill

employing these technologies as well as the option of constructing such a unit on site. Note that these

technologies are consistent with those required under Subtitle D of RCRA.

In addition to landfill disposal, agricultural use may be of environmental concern, based on the

above-ground risk assessment that found potential arsenic risks to human health from this practice. An

approach for mitigating this potential risk might include a standard limiting the arsenic concentration in

wastes intended for this use. Because of the small quantity of waste potentially affected, EPA has not

estimated cost for such an alternative. Minefilling also may be of concern, particularly when wastes are

placed below the water table. EPA is seeking further information on this practice.

4.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS

This section discusses the costs and economic impacts of risk mitigation alternatives for nonutility CCWs. Details of this analysis, together with a background describing the variety of industries

represented, are documented as part of the EPA docket.

Landfill

Design includes filter fabric, 1' sand layer, 2' clay liner, synthetic high-density polyethelene (HDPE) liner, leachate collection

system, and ground-water wells.

Operation includes environmental monitoring, leachate collection and treatment.

Closure requirements include 6" topsoil and vegetation, filter fabric, 1.5' sand layer, 2' clay layer, synthetic (HDPE) liner, and

a cover drainage system.

Post-closure includes environmental monitoring, landscape maintenance, slope maintenance, inspection, and administration.

Table 4-10. Management Alternatives for Non-Utility Coal Combustion Waste
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 4-27

4.7.1 Overview and Methodology

In estimating costs and economic impacts for non-utilities, EPA used a similar approach to that

described in Section 3.7.1 for coal-fired utilities. Salient distinctions between the utility analysis and this

non-utility analysis are reviewed below.

EPA’s analysis for non-utilities began with 958 facilities identified in the 1990 U.S. EPA

National Interim Emissions Inventory database (EPA, 1990). EPA estimated the incremental compliance

cost of the risk mitigation alternative described in Section 4.6. As described in that section, this requires

generators to construct onsite composite-lined landfills or transport waste to an offsite commercial

Subtitle D landfill. The more economical method was assigned to each plant depending upon its estimate

annual CCW generation rate.

The cost estimate summed costs in five categories: initial capital costs, recurring capital costs,

annual operating and maintenance costs, closure costs, and annual post-closure costs. The specific

components included in each cost category were the same as those in the utility analysis (see Section

3.7.1). As in the utility analysis, the cost estimate employed three different landfill sizes. Table 4-11

identifies the design features for non-utility landfills.

As in the utility analysis, a single cost equation was developed, annualized costs were estimated

as a function of facility-specific waste generation, and total industry costs were derived by summing the

facility-specific estimates. Costs and economic impacts are set forth in the following three sections:

incremental compliance cost, compliance cost impact on facilities as a function of size, and industry

impact. Incremental compliance costs are the costs of risk mitigation practices over and above the cost

of current management practices. Using incremental compliance costs as an indicator of potential cost

burden, the analysis examined impacts on individual facilities as a function of size. Unlike for the utility

analysis, this was performed using industry average sales for only the average and large facilities. 

Detailed financial profiles of representative “model” facilities were not developed for the non-utility

sector because of the data collection requirements and multiplicity of facilities involved.

For the industry impact evaluation, the use of econometric models was considered and rejected

because of the diversity of industrial and institutional sectors potentially affected. The industry-level

analysis, therefore, focuses on the same two measurements used in the utility analysis: the number of

affected facilities and the magnitude of incremental compliance costs relative to the value of electricity

sales.

4.7.2 Incremental Compliance Cost

EPA’s estimate of incremental compliance cost for non-utility coal combustors is approximately

$103 million per year. This compliance cost would be distributed across the range of industries

represented by non-utility combustors. Table 4-12 summarizes the details of this cost estimate by nonutility industry SIC code. As with the utility sector, delayed compliance, were this to be considered,

would result in far lower costs.

Note that the costs shown are incremental (above current costs). Annual costs were discounted

at 7 percent to 1998 dollars, with no inflation built into out-year estimates. Also, it was presumed that

compliance would be required immediately, and that amortization would take place over 40 years.
Report to Congress on Wastes from the Combustion of Fossil Fuels

4-28 March 1999

4.7.3 Compliance Cost Impact on Facilities as a Function of Size

EPA believes that the ability of industry to pass through cost increases will be limited because

only a small share of plants within the affected industries operate coal-fired boilers. Competition from

unaffected facilities would restrict the ability of facilities facing incremental compliance costs to increase

prices. Therefore, this analysis includes no analytical consideration of price effects.

As discussed previously in this chapter, non-utility CCWs are generated by a wide variety of

industrial and institutional facilities that generate electricity or energy for primarily internal use. In

general, the affected facilities represent a small share of an industry or economic sector, and fossil fuel

use and costs are a relatively small part of production inputs and costs. The most common types of

facilities affected include pulp and paper mills, food processing facilities, chemical manufacturers,

cement manufacturers, and educational institutions/universities.

The order of magnitude of expected facility-level impacts can be demonstrated by examining one

industry sector as an example. In 1992, the Bureau of the Census reported there were about 15,000 

Parameter Non-Utility Ash Landfill

Sizes small

(tons/year) medium

large

150

5,000

15,000

Depth

(feet) small

medium

large

small

medium

large

Pile design

1.0

1.0

1.0

Combination fill design

3.3

17.4

43.6

Height

(feet) small

medium

large

small

medium

large

Pile design

15.0

25.0

25.0

Combination fill design

4.3

22.2

28.1

Area

(acres) small

medium

large

small

medium

large

Pile design

0.4

5.6

15.7

Combination fill design

0.5

3.5

6.5

Note: Landfill designs considered include a “pile design” constructed primarily above grade and a “combination fill design”

constructed both above and below grade.

Table 4-11. Design Parameters Assumed for Small, Medium, and Large Landfills
Report to Congress on Wastes from the Combustion of Fossil Fuels

4

 In these estimates, sales are in 1992 dollars and compliance costs in 1998 dollars. Therefore, the figures

shown may overestimate impacts.

March 1999 4-29

establishments engaged in food processing (SIC 20) with an annual value of shipments of $281 billion. 

Based on these numbers, the average food processing facility had approximately $19 million per year in

sales. In comparison, only 98 food processing facilities—those burning coal—would be expected to

incur incremental compliance costs. Annualized, these costs are estimated to be $9.7 million, or about

$100,000 per facility per year. Thus, for this industry, less than 1 percent of the facilities would incur

any impacts. The cost would equal about 0.5 percent of annual sales for each facility.4

 Most affected

facilities, however, are expected to be relatively large as only large facilities can usually justify captive

coal-fired boiler operations. In 1992, the food processing industry contained 2,788 facilities that

employed 100 or more employees. These larger facilities had a combined value of shipments of

SIC Code Industry Number of Facilities Incremental Costs

20 Food and Kindred Products 98 $9.7

21 Tobacco Manufactures 11 $0.9

22 Textile Mill Products 59 $3.2

25 Furniture and Fixtures 35 $0.1

26 Paper and Allied Products 140 $24.4

28 Chemicals and Allied Products 114 $23.8

29 Petroleum and Coal Products 12 $0.7

30 Rubber and Miscellaneous Plastics Products 21 $1.5

32 Stone, Clay, and Glass Products 17 $1.3

33 Primary Metal Industries 44 $4.1

34 Fabricated Metal Products 21 $1.2

35 Industrial Machinery and Equipment 26 $1.6

36 Electric and Electronic Equipment 15 $0.9

37 Transportation Equipment 61 $3.4

49 Electric, Gas, and Sanitary Services 44 $12.3

80 Health Services 58 $2.5

82 Educational Services 77 $5.3

92 Justice, Public Order, and Safety 26 $0.9

97 National Security and International Affairs 17 $0.7

Other SICs 53 $4.5

Unknown SICs 9 $0.3

Totals 958 $103.3

Table 4-12. Cost Estimates for Non-Utility CCW

(1998 million $/yr, annualized)
Report to Congress on Wastes from the Combustion of Fossil Fuels

4-30 March 1999

$225 billion or $81 million per facility. Thus, if the 98 affected facilities were all large, still only 1 in 30

would be affected and the incremental compliance costs would be 0.1 percent of annual sales.

Table 4-13 shows similar comparisons for other major non-utility industry sectors. The sectors

presented include food processing facilities, pulp and paper mills, chemical manufacturers, primary

metals manufacturers, and transportation equipment manufacturers. Together, these five industries

account for approximately 80 percent of non-utility CCW generation, based on data from the 1990

U.S. EPA National Interim Emissions Inventory. In general, facilities in these sectors should not incur

significant overall cost burdens; however, the incremental cost could significantly affect their energy use

practices by causing some facilities to switch from internal generation to external purchase, similar to the

practices of most facilities in the affected industries, to avoid the regulatory burden and to obtain cheaper

energy.

4.7.4 Industry Impacts

This analysis addresses the major non-utility industries shown in Table 4-14. For example, the

food processing sector would incur incremental costs of $9.7 million per year; however, the food

processing sector was a $448-billion-per-year industry in 1995. Thus, incremental compliance costs

would represent less than 0.002 percent of overall market value. Moreover, only about 1 out of every

150 facilities would be affected directly. Similar results are evident for other major non-utility industry

sectors, as shown in Table 4-14.

4.8 FINDINGS AND RECOMMENDATIONS

4.8.1 Introduction

Based on the information collected for this Report to Congress, this section presents a summary

of the Agency’s main findings presented under headings that parallel the organization of this chapter. It

then presents the Agency’s tentative conclusions concerning the disposal and beneficial uses of wastes

generated at non-utilities, including wastes from the burning of coal and petroleum coke and the

coburning of other fuels with coal as identified in this chapter.

Sector

Number of

Affected

Facilities Facility Size

Average

Facility Sales

(1992 $ million/yr)

Average Facility

Incremental

Compliance Cost

(1998 $ million/yr)

Compliance Cost as

a Percentage

of Sales

Food Processing 98 Average

Large

$19

$81

$0.10

$0.10

0.5%

0.1%

Pulp and Paper 140 Average

Large

$118

$151

$0.17

$0.17

0.2%

0.1%

Chemical

Manufacturing

141 Average

Large

$26

$157

$0.21

$0.21

0.8%

0.1%

Primary Metals 44 Average

Large

$21

$85

$0.09

$0.09

0.4%

0.1%

Transportation

Equipment

61 Average

Large

$35

$217

$0.06

$0.06

0.2%

0.03%

Note: Large facilities are establishments with more than 100 employees.

Table 4-13. Facility-Level Economic Impacts, Non-Utility CCW
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 4-31

4.8.2 Findings

Sector Profile

• There are no comprehensive data on industry-wide generation of non-utility coal

combustion wastes. The Agency was able to characterize the sector profile based on major

stationary point sources of air emissions but not the smaller combustors. On this basis, the

Agency identified 958 major non-utility burners of coal, petroleum coke, and other fuels

that are coburned with coal. The eastern United States has a larger concentration of these

facilities than the western United States.

• There are approximately 2,300 boilers in operation at the major non-utility facilities.

• Non-utilities burn these fuels for a variety of purposes, including manufacturing process

steam production, hot water, space heating, and captive electric power generation. They

include industrial, commercial, and institutional facilities. They are located in diverse

environments, including areas that vary widely in population density, geography,

precipitation, and general climate.

Waste Generation and Characteristics

• Non-utility burners of coal and petroleum coke generate the same types of large-volume and

low-volume wastes as utilities. They employ the same types of combustion technologies

and combustion support processes as the utilities. The major non-utility facilities generate

nearly 6-million tons per year of the high-volume wastes.

• Wastes from non-utility burners appear to be similar to their counterpart utility wastes. 

Similarly, the constituents of concern are trace metal elements, particularly the eight RCRA

metals.

• The total quantities of low-volume wastes generated at these facilities is not well

established; however, the aggregate quantities are much lower than utility low-volume

wastes.

Sector

Industry Sales

($billion/yr)

Incremental Compliance

Cost ($billion/yr)

Compliance Cost as a

Percentage of Sales

Food Processing $448 $0.010 0.002%

Pulp and Paper $52 $0.024 0.050%

Chemical Manufacturing $362 $0.024 0.010%

Primary Metals $180 $0.004 0.002%

Transportation Equipment $463 $0.003 0.001%

Other Industrial/Institutional Not estimated $0.026 ---

Note: Sales are in 1995 dollars and compliance costs in 1998 dollars. Therefore, the percentages shown may overestimate

impacts.

Table 4-14. Industry-Level Economic Impacts, Non-Utility CCW
Report to Congress on Wastes from the Combustion of Fossil Fuels

4-32 March 1999

Waste Management Practices

• Landfills appear to be the predominant type of waste management unit for the disposal of

wastes. Limited information suggests that the majority of combustion wastes are disposed

in offsite landfills. Surface impoundments appear to be the only other type of waste

management unit employed, and they are infrequently used.

• Combustion wastes are more frequently comanaged with low-volume wastes or a diverse

range of other (unrelated) industrial wastes as opposed to separate management.

• Comprehensive statistics are not available on the amounts of these wastes that serve

beneficial uses. Available information suggests that use of these materials as a component

in cement and concrete and as construction fill are the most common beneficial uses.

Potential Risks and Damage Cases

• EPA conducted a risk assessment that found a lack of potential human health risk for

virtually all waste constituents. Arsenic was the one constituent for which the Agency

identified potential human health risks via the ground-water pathway where the combustion

wastes are managed alone or comanaged with low-volume wastes in landfills. The

identified risk is based on high-end risk scenarios in EPA’s risk modeling analysis for

human ingestion of well water influenced by releases from the waste management unit. The

time to reach the health-based level for arsenic in ground water at the receptor well is

estimated to be in excess of 1,400 years.

• EPA conducted a risk assessment that found a lack of potential human health risk for

virtually all waste constituents. Arsenic was the one constituent for which the Agency

identified potential human health risks via non-ground-water pathways where these wastes

are used as soil amendments for agricultural purposes. The identified risk is based on highend risk scenarios in EPA’s risk modeling analysis for human ingestion exposure routes.

• No ecological risks were identified for management of wastes in this sector.

• No damage cases were identified for this sector that exclusively involve these wastes,

although this finding is based on rather limited information. Two superfund National

Priority List sites were identified that involve coal combustion wastes. These sites are

considered to be damage cases, but other wastes unrelated to the generation of CCWs were

comanaged at these sites, and there is uncertainty about the contributing influences of the

CCWs. Arsenic was identified as a constituent of concern in these two damage cases, but

because of the mixed wastes, it could not be conclusively attributed to the CCW component.

• Some natural arsenic levels in U.S. soils have the potential to pose higher risks than the risk

identified with the level of arsenic contributed by these wastes for non-ground-water

pathways.

Existing Regulatory Controls, State and Federal Requirements

• The major facilities in the non-utility sector have a significant level of installed

environmental controls for these wastes that mitigate the potential human health risks

identified in this study.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 4-33

• States have increasingly begun to impose controls on these wastes. The states vary

somewhat in their approaches to regulating these wastes; however, in aggregate, there is

existing state authority to impose substantial regulatory controls on these wastes. For

example, there exists authority at the state level to impose siting controls, liners

requirements, leachate collection systems, and permit procedures for more than 80 percent

of the generated wastes. There exists additional authority at the state level to impose

ground-water monitoring requirements, closure controls, and dust/cover controls for more

than 90 percent of the generated wastes.

Potential Costs and Impacts of Regulation

• The Agency estimates that the total annual incremental compliance costs for mitigation of

the potential arsenic risks identified in this study would be approximately $100 million

(1998$). These costs represent replacement of existing unlined management units with

lined management units, and implementing ground-water monitoring and leachate collection

and treatment. These measures do not represent implementation of full Subtitle C

requirements, but rather modifications of such requirements that could potentially be

adopted under Section 3004(x) of RCRA.

• If these wastes were to be regulated under full Subtitle C, virtually all existing facilities

would be required to invest substantial funds and resources to modify existing management

practices. The total annual cost of full Subtitle C requirements would considerably exceed

the $100 million (1998 $) estimate above.

• If beneficial uses of theses wastes were subject to Subtitle C requirement, possibly all

beneficial use practices and markets would cease.

4.8.3 Recommendations

Following are the Agency’s recommendations for the wastes covered in this chapter. The

recommendations are based on EPA’s analysis of the eight Congressionally mandated study factors

(Section 1.2). These conclusions are subject to change based on continuing information collection,

continuing consultations with other government agencies and the Congress, and comments and new

information submitted to EPA during the comment period and any public hearings on this report. The

final Agency decision on the appropriate regulatory status for these wastes will be issued after receipt

and consideration of comments as part of the Regulatory Determination, which will be issued within 6

months.

1. The Agency has tentatively concluded that disposal of these wastes should remain exempt from

RCRA Subtitle C.

As with the utility coal combustion wastes addressed in Chapter 3, the Agency has tentatively

concluded that the non-utility CCWs, including wastes from petroleum coke combustion and from other

fuels that are co-fired with coal, and also low-volume wastes where they are managed with the

combustion wastes, generally present a low inherent toxicity, are seldom characteristically hazardous,

and generally do not present a risk to human health and the environment. State programs increasingly

require more sophisticated environmental controls at these types of facilities. There are few damage

cases and none of the identified damage cases exclusively involved these wastes or affected human

receptors. These types of facilities are typically located in areas of low population and thus present

infrequent opportunity for human exposure. The Agency believes that no significant ecological risks are

posed by disposal of these wastes. The predominant practice is to manage these wastes in landfills, with
Report to Congress on Wastes from the Combustion of Fossil Fuels

4-34 March 1999

a much lower frequency of using impoundments. Environmental controls are common at the landfills. 

For example, nearly all implement ground-water monitoring and runoff controls, and two-thirds have

leachate collection. Overall, the Agency believes that when these wastes are disposed, regulation under

Subtitle C authority is not warranted. For the issues discussed below involving agricultural use and

management of these wastes in mines (minefill), the Agency is still considering whether some regulation

under RCRA Subtitle C may be warranted.

There is a very small segment of non-utility coal burners that generates mill rejects, a lowvolume waste, that may be comanaged with the CCWs. The Agency has the same concerns about the

potential for problem management situations involving pyritic materials as described for utilities in

Chapter 3. Although the Agency did not identify any of these situations at non-utility facilities during

this study, it is engaging the non-utility sector in a program to ensure that these particular wastes are

appropriately managed. This effort parallels the pyrites management program described for utilities in

Chapter 3. EPA will follow-up with oversight on the industry’s management of these wastes, and will

revisit this issue if necessary.

2. The Agency has tentatively concluded that most beneficial uses of these wastes should remain

exempt from Subtitle C.

No significant risks to human health and the environment were identified or believed to exist for

any beneficial uses of these wastes, with the possible exception of minefill and agricultural use as

discussed below. This is based on one or more of the following reasons for each use or resulting product:

absence of identifiable damage cases, fixation of the waste in finished products which immobilizes the

material, and/or low probability of human exposure to the material.

3. The Agency is tentatively considering the option of subjecting practices involving the use of these

wastes for agricultural purposes (i.e., as a soil nutrient supplement or other amendment) to some

form of regulation under Subtitle C.

As mentioned above, the Agency identified potential risk from exposure to arsenic in these

wastes when they are used for agricultural purposes. The risks identified with this practice may be of

sufficient concern to consider whether some form of control under Subtitle C is appropriate, given the

increasing trend for use of these materials as agricultural amendments. An example of such controls

could include regulation of the content of these materials such that arsenic concentrations could be no

higher than that found in agricultural lime. On the other hand, imposition of controls under Subtitle C

may not be warranted if sufficient protection may be afforded by the Agency engaging the industry to

establish voluntary controls on this practice. An example of such voluntary controls could consist of an

agreement to limit the level of arsenic in these materials. The Agency solicits comment on its tentative

conclusion and specific approaches that could be pursued to address the concern.

Non-utility burners of coal, particularly those that generate significant quantities of combustion

wastes, may have opportunities for their wastes to be minefilled, that is, permanently placed in mine

voids similar to the practice with some utility combustion wastes. As discussed in Chapter 3, the Agency

currently lacks sufficient information with which to adequately assess risk associated with this practice

and, therefore, to decide whether this practice should remain exempt from Subtitle C. For the same

reasons discussed in Chapter 3's recommendations, the Agency solicits comment on whether there are

some minefill practices that are universally poor and warrant specific attention. EPA also seeks comment

on whether coal or other fossil fuel combustion wastes used as minefill and placed in direct contact with

the water table would create environmental concerns, and if that specific practice should be regulated. 

The Agency’s focus is on potential risks that may be posed via the ground-water and surface pathways

from use of these wastes as minefill.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 5-1

5.0 FLUIDIZED BED COMBUSTION WASTES

Fluidized bed combustion (FBC) is an emerging technology for the combustion of fossil and

other fuels. Coal is the most common fossil fuel burned by FBC facilities, although some facilities burn

waste coal, petroleum coke, or other fuels. This chapter covers FBC wastes from facilities combusting

all types of fossil fuels (e.g., including petroleum coke). FBC makes up only a portion of the fossil fuel

combustion (FFC) universe—approximately 1 percent of fossil fuel-fired capacity. The potential for

increased use of the technology and the potential differences in waste characteristics, however, led EPA

to consider FBC wastes separately from coal combustion wastes from conventional technologies in its

1993 Regulatory Determination (58 FR 42466, 8/9/93). For the same reasons, FBC is presented

separately for analysis in this report.

SECTOR OVERVIEW

FBC technology is used in both the utility and non-utility sectors. Approximately half of the

facilities using FBC technologies are utilities or independent power producers. Facilities in the food

products and pulp and paper industries, along with educational institutions, make up most of the nonutility FBC facilities. Other industries represented include chemicals and allied products, petroleum

refining, transportation equipment, wholesale trade, and research services. Also included are municipal

government buildings and one correctional facility.

Although FBC technology accounts for a small proportion of capacity relative to the other

sectors considered in this report, use of the technology has increased dramatically over the last 20 years. 

In 1978, there were four plants with four FBC boilers in the United States. As of December 1996, there

were 84 facilities with 123 FBC boilers representing 4,951 megawatts of equivalent electrical generating

capacity (CIBO, 1997c). Furthermore, the fuel flexibility, efficiency, and emissions characteristics of

FBC boilers are such that use of the technology has the potential to increase in the future.

Figure 5-1 shows the geographic distribution of FBC facilities. While these facilities are

distributed throughout the United States, Pennsylvania and California account for the largest numbers of

plants. Pennsylvania accounts for more than 20 percent of capacity and California more than 10 percent. 

As discussed in Section 5.3, FBC facilities practice both onsite and offsite waste management. Offsite

waste management units are located near the generating facility in most cases. Therefore, the geographic

distribution of combustion facilities presented in Figure 5-1 also is generally representative of the

universe of waste management unit locations.

5.1 WASTE GENERATION

The two main waste streams generated in FBC processes are listed below:

• Bed ash (or bottom ash). Spent bed material and fuel ash removed from the boiler bottom.

• Fly ash. Ash removed from the entrained air stream.

As for the wastes from conventional combustion technologies discussed in Chapters 3 and 4, the

generation of FBC wastes is governed by combustion technology (Section 5.1.1), air pollution control

technology (Section 5.1.2), and fuel usage (Section 5.1.3). Unlike the wastes from conventional

technologies, FBC wastes comprise not only uncombusted material from the fuel, but also spent

incombustible bed material, as discussed below.
Report to Congress on Wastes from the Combustion of Fossil Fuels

5-2 March 1999

Figure 5-1. Number of Fluidized Bed Combustion Facilities by State

No comprehensive industry-wide data exist on the generation of FBC wastes. In 1996, however,

in support of this study, the Council of Industrial Boiler Owners (CIBO) sent a voluntary questionnaire to

every fossil fuel-fired FBC plant, both utility and non-utility, in the United States (CIBO, 1997b). This

survey collected general facility information, characterized process inputs and outputs, gathered data on

waste generation and characteristics, and captured details of FBC waste management practices. Thirtynine FBC facilities provided waste generation information in response to the survey. By extrapolating

from the generation rates reported by these 39 respondents, CIBO estimates total FBC waste generation

in 1995 to be between 9,091,600 and 13,150,560 short tons, with the most likely estimate being

9,417,500 short tons (CIBO, 1997c). This estimate is only about 10 percent of the total quantity of utility

CCWs generated, because there are far fewer FBC facilities, most of which have lower capacity than a

typical utility. On a per-megawatt basis, however, FBC units generate a larger quantity of waste than

comparable conventional combustion units. The reasons for this increased waste generation are

discussed in the sections below.

Like conventional combustors, FBC units generate low-volume combustion wastes as a result of

supporting processes (see Section 5.1.4) that are ancillary to, but a necessary part of, the combustion and

power generation processes. These low-volume wastes include the following:

• Coal pile runoff. Runoff and drainage produced by precipitation falling on coal storage

areas (not generated at petroleum coke-fired FBC facilities).
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March 1999 5-3

• Coal mill rejects. Produced by onsite processing of coal prior to use (not generated at

petroleum coke-fired FBC facilities).

• Boiler blowdown. Waste that is continuously or intermittently removed from boilers that

recirculate water.

• Cooling tower blowdown and sludge. Wastes removed periodically from closed-loop

cooling systems.

• Water treatment sludge. Wastes resulting from treatment of make-up water for the steam

cycle or for non-contact cooling.

• Regeneration waste streams. Wastes resulting from periodic cleaning of ion exchange

beds used to remove mineral salts from boiler make-up water.

• Air heater and precipitator washwater. Wastes resulting from the periodic cleaning of

the fireside (i.e., the side exposed to hot combustion products) of heat exchanging surfaces.

• Boiler chemical cleaning waste. Wastes resulting from the periodic cleaning of the inside

(waterside) of boiler tubes with chemical solutions.

• Floor and yard drains and sumps. Wastewaters collected by drains and sumps, including

precipitation runoff, piping and equipment leakage, and wash water.

• Laboratory wastes. Wastes generated in small quantities during routine analysis of coal,

intake water, wastes, and other samples at a plant site.

• Wastewater treatment sludge. Sludge generated from the treatment in settling basins or

other treatment facilities of any or all of the liquid waste streams described above.

FBC facilities would be expected to generate smaller quantities of these wastes, consistent with their

smaller unit size (see Section 5.1.1). In some cases, other characteristics of FBC technology may reduce

the generation of some of these wastes (see Section 5.1.4).

In addition to FBC wastes and low-volume combustion wastes, non-utility FBC facilities have

the potential to generate a wide range of non-combustion process wastes, consistent with the variety of

industries represented by these facilities. These process wastes may be managed together with

combustion wastes. No comprehensive data exist on the quantity of these non-combustion process

wastes generated at non-utility FBC facilities.

5.1.1 Fluidized Bed Combustion Technology

Box 5-1 provides a general overview of FBC technology. Such technology presents several

advantages over conventional processes in terms of fuel flexibility, combustion efficiency, and reduction

of emissions:

• Fuel Flexibility. The temperatures in FBC systems are below the ash softening temperature

for most fuels. In addition, the mixing of fuel with incombustible bed material creates a

high thermal inertia. These conditions allow for stable ignition and combustion of even low

grade fuels and make the FBC process insensitive to fuel characteristics such as moisture

and ash content (Stultz and Kitto, 1992).
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5-4 March 1999

• Combustion Efficiency. FBC processes allow for efficient combustion even at the low

temperatures used because of the relatively long residence time of fuel in the bed, the heat

transfer between incombustible bed material and fuel, and the gas/solids contact created by

the fluidizing conditions (CIBO, 1997c).

• Emissions Control. The low temperatures also limit the generation and emission of

nitrogen oxides. Furthermore, a sorbent material, typically limestone, often makes up a

portion of the bed material. This sorbent, along with the low temperature, allows the

efficient capture of sulfur oxides (CIBO, 1997c).

The FBC technologies discussed in Box 5-1 operate at atmospheric pressure. An advanced form

of FBC, called Pressurized Fluidized Bed Combustion (PFBC), currently is under development. PFBC

systems are similar to other FBC systems, but operate under pressure. Because of the pressurized

operation, the combustion air in PFBC systems contains more oxygen per unit volume, allowing more

intense combustion in smaller combustion units. Also, because the combustion off-gases are pressurized,

they can be passed through both a turbine and a steam boiler in sequence, allowing greater combustion

efficiency. Only one PFBC system currently is in operation at the commercial scale (EERC, 1997) and

this facility is a research facility. Because this emerging technology has not yet received commercial

application, limited data are available on PFBC wastes and waste management practices. Therefore, this

chapter applies to wastes from the more developed atmospheric FBC systems.

In FBC processes, fuel is burned on a bed of incombustible material (e.g., sand and limestone) while combustion

air is forced upward at high velocities, making the particles flow as a fluid. The fuel typically is a solid

(frequently coal), although FBC can burn gas and liquid fuels as well. When coal is fed to an FBC boiler, it

usually is crushed to 0.25 inches, a size between that used by stokers and pulverizers. FBC temperatures are

below those for conventional processes—bed temperatures are maintained between 1,500F and 1,600F. The

bed material often includes a sorbent, such as limestone, that allows the capture of sulfur oxides without the endof-stack scrubbers often required for conventional coal combustion processes. There are two primary types of

FBC systems: bubbling fluidized beds and circulating fluidized beds. The differences between the two depend

mainly on the bed particle diameter and gas flow velocity.

Bubbling fluidized bed systems have air velocities of 5 to 12 feet per second and larger bed particle size. These

conditions result in a dense bed (45 pounds per cubic foot) with a well-defined surface. Excess air passes

through the bed in the form of bubbles. A small amount of bed material entrained in the gas stream (a maximum

of 25 percent of the combustion gas weight) may be recycled back to the furnace to maximize combustion

efficiency and sulfur capture.

Circulating fluidized bed systems have greater air velocities (as high as 30 feet per second) and finer particle

sizes. As a result, the fluid bed is less dense (35 pounds per cubic foot) and has no well-defined top surface. 

Bed and fuel material are distributed uniformly throughout the furnace, although density declines as particles

move upward. Particle entrainment increases in these systems such that large quantities of bed material must be

recaptured from the gas stream and recirculated back to the furnace to maintain bed inventory.

Sources: CIBO, 1997c; Stultz and Kitto, 1992; Elliott, 1989

Box 5-1. Fluidized Bed Combustion (FBC) Technology
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March 1999 5-5

Figure 5-2. Capacities of Conventional and FBC Boilers

The partitioning of FBC waste between fly ash and bed ash depends on combustion technology. 

In bubbling fluidized beds, waste generated is mostly bed material: fuel ash, lime (if used as sulfur

sorbent), calcium sulfate (formed by the reaction of sulfur with the sorbent), and sand or other inert bed

material. On the other hand, fly ash represents most of the waste generated by circulating fluidized beds

(Stultz and Kitto, 1992).

In general, FBC facilities are small in capacity. Figure 5-2 compares the capacity distribution of

FBC units to that of conventional coal-fired boilers in both the utility and non-utility sectors. Figure 5-3

shows the distribution of utility and non-utility FBC units in each capacity category. Utility FBC units,

although larger on average than non-utility FBC units, are smaller than typical conventional coal-fired

utility boilers. Non-utility FBC units are similar in capacity to the small conventional boilers used by

non-utilities. As a result of their small capacity, FBC units would be expected to generate less waste on a

per-boiler basis, all other factors being equal. Also, the high combustion efficiency of FBC units would

tend to result in lower waste generation on a per-unit basis. The presence of spent bed and sorbent

materials and the potentially greater ash content of the fuel, however, more than counteract this

reduction, as discussed in Section 5.1.3.

5.1.2 Air Pollution Control Technologies

Just like conventional combustion facilities, the capture of FBC fly ash is governed by the

particulate control technology used. Fly ash leaving the boiler must be removed from the gas stream in

which it is entrained or it will be released to the atmosphere. Because FBC technologies capture sulfur

oxides using a sorbent within the combustion bed, they do not require the application of separate flue gas
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5-6 March 1999

Figure 5-3. Capacities of Utility and Non-Utility FBC Units

desulfurization (FGD) technologies; however, FBC units can use the same basic particulate control

technologies as those used at conventional coal-fired utilities. Chapter 3 describes these technologies.

Figure 5-4 shows data on particulate control devices used at FBC facilities. FBC units are as

likely as conventional coal-fired utilities to apply particulate controls. This is due to two factors. First,

all circulating fluidized bed processes use some form of particulate control to accomplish the

recirculation of bed material. Second, all FBC facilities are relatively new. Thus, they are subject to

regulatory controls on air emissions despite their smaller size, as discussed in Section 5.5. FBC facilities

tend to use fabric filters for particulate control rather than the electrostatic precipitators (ESPs) that are

common for coal-fired utilities. Like ESPs, however, fabric filters provide for efficient collection of fly

ash.

5.1.3 Fuel and Sorbent Use

The quantity of FBC waste generated is affected by the ash content of the fuel. Ash content is, in

part, determined by the rank of the coal: anthracite, bituminous, subbituminous, or lignite. In addition to

coal rank, ash content depends on the specific coal-producing region, mine, seam, and production

method. Because of their fuel flexibility, FBC boilers burn a wider range of fuels than do conventional

coal-fired boilers. Table 5-1 shows the primary fuels used by facilities responding to the CIBO FBC

Survey.

FBC facilities that burn coal show a breakdown by coal rank similar to that observed for

conventional coal facilities: primarily bituminous, followed by subbituminous and lignite. Some FBC

facilities, however, may burn coal with higher ash content than conventional boilers. Furthermore, in

addition to coal, FBC facilities burn waste coal and other fuels. Waste coal includes culm (anthracite 
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March 1999 5-7

Figure 5-4. Particulate Control Technologies Used at FBC Facilities

coal refuse) and gob (bituminous coal refuse) and results from the coal-cleaning processes used to

separate standard coal from its impurities. Waste coals are higher in ash and lower in carbon content

(and therefore lower in fuel value) than standard coals. Several FBC facilities reported burning

petroleum coke as a primary fuel. Petroleum coke is the heavy residual from petroleum cracking

processes. Its characteristics vary widely depending on the process used. One facility reported burning

natural gas (CIBO, 1997c).

Type of Fuel Fuel

Number of

Facilities Mass of Fuel (tons) Percent of Total Mass

Coal Anthracite Coal 0 0 0%

Bituminous Coal 20 7,384,624 42%

Subbituminous Coal 4 2,306,910 13%

Lignite Coal 2 2,086,227 12%

Waste Coal Anthracite Culm 6 2,604,863 15%

Bituminous Gob 5 2,089,268 12%

Other Petroleum Coke 5 895,658 5%

Natural Gas 1 191,601 1%

Total 43 17,559,151 100%

Source: CIBO, 1997b

Table 5-1. Primary Fuels Used by FBC Facilities
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5-8 March 1999

While smaller capacities and greater efficiency may reduce waste generation at FBC facilities

relative to that at conventional coal-combustion facilities, the use of higher ash content fuels at some

facilities tends to counteract this reduction. The presence of spent bed and sorbent materials further

counteract this reduction. Spent bed and sorbent material can compose a significant proportion of the

waste generated from FBC technology. Table 5-2 presents data on the types and quantities of sorbent

and bed material used by FBC facilities in 1995. Limestone is the most commonly used material and

serves as a sorbent for sulfur dioxides. Sand is the most common incombustible bed base. Other

materials include clay and gravel as bed material and ammonia and urea to control nitrogen oxide

emissions.

5.1.4 Supporting Processes

The generation of low-volume combustion wastes primarily is associated with processes that

support the combustion process or make use of the products of combustion. Some of the same

supporting and enabling processes can accompany combustion at FBC facilities as at conventional

facilities, including the following:

• Coal storage

• Coal processing

• Steam generation

• Cooling

• Water treatment

• Cleaning and maintenance.

Chapter 3 describes these processes in detail. The paragraphs below describe potential

differences in these processes at FBC facilities with respect to waste generation. Little quantitative

information is available on the quantities of low-volume combustion wastes generated at FBC plants.

Coal Storage and Processing

The FBC population includes a large percentage of small capacity units. These small capacity

units are less likely to store large quantities of fuel onsite than conventional coal-fired utilities. 

Therefore, these facilities are less likely to generate coal pile runoff than conventional coal-fired utilities. 

Also, because of their fuel feed tolerance, FBC plants are less likely to conduct onsite coal cleaning than

conventional coal-fired utilities. Therefore, FBC plants generally do not generate coal mill rejects

(pyrites). No information is available on wastes from the storage and processing of fuels other than coal

(e.g., petroleum coke).

Non-Combustible Commodities Number of Plants Total Annual Usage (tons)

Limestone 36 2,420,820

Sand 20 16,154

Other 7 3,002

Total 63 2,439,976

Source: CIBO, 1997b

Table 5-2. Sorbent and Bed Materials Used at FBC Facilities
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March 1999 5-9

Steam Generation, Cooling, and Water Treatment

These processes generate wastes including boiler blowdown, cooling tower blowdown, water

treatment wastes, and regenerant wastes. The quantities of these wastes generated are related to the

quantity of water used in the steam and cooling cycles, which in turn is related to combustion capacity. 

Because of their smaller capacity, FBC units generally use less water in the combustion process than

conventional utilities and, therefore, may generate smaller quantities of these wastes. In addition, some

non-utility FBC plants may use steam directly for heat in industrial processes rather than to generate

electricity. In some cases, this practice may reduce the need for cooling, and in turn reduce the

generation of wastes associated with the cooling cycle.

Cleaning and Maintenance

Cleaning processes intermittently generate low-volume wastes including air heater and

precipitator washwater and boiler chemical cleaning waste. Because of the lower operating temperatures

compared to conventional coal combustion technologies, FBC units may require less frequent cleaning

than conventional boilers. The small capacities of some units also may require smaller quantities of

cleaning solutions than required at conventional coal-fired utilities. These factors can result in lesser

generation of cleaning wastes at FBC units than at conventional coal combustors.

5.2 WASTE CHARACTERISTICS

5.2.1 Physical Characteristics

FBC fly ash is a solid composed of fine particles, similar in size to that generated by pulverized

coal combustors. Sixty to 90 percent of FBC fly ash particles are finer than 100 microns. FBC fly ash

particles are less rounded than those from conventional combustion processes because of the lower

combustion temperatures. FBC bed ash also is a solid particulate, with a size that varies depending on

fuel and sorbent characteristics. FBC bed ash particle size varies from 0.1 to 2 millimeters (CIBO,

1997c).

5.2.2 Chemical Characteristics

Both FBC fly ash and bed ash contain non-combustible mineral matter, sorbent material, and

unburned carbon. The major constituents of FBC waste are calcium, sulfur, silicon, iron, aluminum,

magnesium, and potassium. As with conventional coal combustion waste (CCW), most of these

constituents are present in the form of oxides. Due to the presence of sorbent material, however, FBC

wastes have a higher content of calcium and sulfate and a lower content of silica and alumina than

conventional CCWs (CIBO, 1997c). In addition, the amount of unburned carbon in FBC ash is quite

small because of the low concentration of fuel in the bed. The carbon content in a fluidized bed burning

bituminous coal typically is less than 1 percent (Stultz and Kitto, 1992). Like conventional CCWs, FBC

waste constituents include trace metals. Table 5-3 presents typical concentrations for these constituents.

Leachate and Hazardous Waste Characteristics

Using data available on the composition of FBC wastes, EPA evaluated whether the waste

exhibited any of the four characteristics of hazardous waste: corrosivity, reactivity, ignitability, and

toxicity. Based on available information and engineering judgment, EPA does not believe that FBC

wastes are reactive, ignitable, or corrosive. FBC waste cannot be considered corrosive under EPA’s

definitions because the characteristic does not apply to solid materials.
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5-10 March 1999

EPA evaluates the characteristic of toxicity using Toxicity Characteristic Leaching Procedure

(TCLP) results. Table 5-4 presents typical TCLP results for FBC wastes for a number of constituents. 

These include the eight metals regulated under the Resource Conservation and Recovery Act (RCRA)

and several other constituents. Data also are available from Extraction Procedure (EP) tests (a test

previously used by EPA to evaluate toxicity) for many of these same constituents. The EP results are

generally similar to or lower than the TCLP results shown in Table 5-4. The exceptions are antimony,

arsenic, chromium, mercury, and zinc in fly ash and aluminum, beryllium, and zinc in bed ash, which

appear in EP results at somewhat higher levels. The discussion below addresses the leachate data first

for RCRA-regulated constituents, then for non-RCRA-regulated constituents.

Constituent

Fly Ash Bed Ash Combined Ash

Mean Range Mean Range Mean Range

Antimony 33.4 0.125–259 40.1 0.125–361 14.3 0.065–62

Arsenic 38.1 2.8–176 25.1 2.5–80 25.1 1.4–77.2

Barium 542 31.3–2,690 190 7.3–453 258 39.2–690

Beryllium 3.31 1.08–11.5 3 0.5–8 2.97 0.148–9.5

Boron 366 0.025–2,470 79.1 0.025–304 149 1.25–1,670

Cadmium 1.79 0.013–6.68 1.79 0.0125–7.16 1.53 0.009–5.9

Chromium 46 5.17–97.1 36.4 4.1–86 43.7 12–181

Cobalt 22.3 2.5–79.8 16.9 1.4–75.8 5.6 0.6–18.7

Copper 40.5 2–99 17.5 1.65–37.1 40.1 1.9–192

Lead 30.3 1.03–105 18.9 0.848–58 23.2 0.45–67

Manganese 223 0.05–548 311 52.2–751 88.7 20–211

Mercury 7.86 0.00005–129 1.43 0.00005–16.2 0.431 0.0113–1.68

Molybdenum 13.9 2.35–48.6 20.8 6–63.4 9.65 0.125–41

Nickel 179 6.25–923 190 1–945 142 0.77–985

Selenium 19.5 0.47–166 5.45 0.152–45 5.86 0.404–18

Silver 2.35 0.05–11.6 8.75 0.05–87.6 2.75 0.479–21.8

Thallium 9.46 1.25–39 7.63 0.5–25 5.56 0.09–12.5

Vanadium 771 36.4–3,830 987 12–5,240 144 26.3–5,000

Zinc 53 24–143 64.7 17.4–399 3150 11–45,300

Notes: Encompasses wastes generated by facilities burning all types of fuel reported in the CIBO survey (i.e., coal, waste coal, and

petroleum coke). All measurements identified as below detection limit were assigned a value equal to one-half the detection limit for use in

the calculations. All concentrations are facility-averaged; i.e., multiple measurements from a single site were averaged, and the resulting

population of facility averages was used to generate the statistics in this table.

Source: CIBO, 1997b

Table 5-3. Facility Average Concentrations of Trace Constituents in FBC Wastes

(parts per million)
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March 1999 5-11

Based on the TCLP and EP data for the eight RCRA metals, FBC wastes rarely exhibit the

RCRA characteristic of toxicity. Only one FBC site of 24 (4 percent) for which data are available had

any samples of waste for which TCLP or EP analyses exceeded the regulatory threshold. At this site, a

Constituent

RCRA

Standard

Fly Ash Bed Ash Combined Ash

Mean Range Mean Range Mean Range

RCRA Toxicity Constituents

Arsenic 5.0 0.0498 0.0125–0.17 0.0369 0.0025–0.125 0.102 0.0023–0.365

Barium 100.0 3.40 0.0175–42 0.613 0.025–2.5 1.22 0.0223–10.5

Cadmium 1.0 0.0193 0.0005–0.09 0.0175 0.0005–0.051 0.0181 0.00125–0.096

Chromium 5.0 0.0577 0.01–0.141 0.0526 0.0025–0.14 0.0667 0.0033–0.25

Lead 5.0 0.113 0.0025–0.505 0.0715 0.0025–0.235 0.13 0.001–1

Mercury 0.2 0.000661 0.00005–0.00192 0.00116 0.00025–0.005 0.00198 0.00005–0.0169

Selenium 1.0 0.0739 0.002–0.2 0.0415 0.002–0.158 0.0584 0.00413–0.175

Silver 5.0 0.0258 0.005–0.053 0.0533 0.005–0.25 0.0253 0.0038–0.145

Non-RCRA Constituents

Antimony n/a 0.224 0.0095–0.66 0.218 0.025–0.52 0.121 0.00065–0.27

Beryllium n/a 0.00947 0.00005–0.025 0.01085 0.00005–0.025 n/a n/a

Boron n/a 0.447 0.06–0.76 1.328 0.13–2.6 3.2 0.0367–26.7

Cobalt n/a 0.0725 0.0025–0.19 0.125 0.025–0.225 0.106 0.0065–0.4

Copper n/a 0.042 0.0025–0.077 0.0403 0.0275–0.0633 0.0574 0.00188–0.203

Manganese n/a 0.190 0.00125–0.6 0.403 0.05–1.27 0.208 0.00208–0.507

Molybdenum n/a 0.168 0.11–0.32 0.16 0.119–0.2 0.108 0.0125–0.21

Nickel n/a 0.0926 0.0025–0.3 0.119 0.0167–0.28 0.121 0.0025–0.46

Thallium n/a 0.0229 0.0208–0.025 0.0356 0.025–0.0463 n/a n/a

Vanadium n/a 0.105 0.025–0.185 0.941 0.025–1.858 n/a n/a

Zinc n/a 0.111 0.0025–0.35 0.141 0.015–0.51 0.114 0.0025–0.38

n/a = data not available

Notes: Encompasses wastes generated by facilities burning all types of fuel reported in the CIBO survey (i.e., coal, waste coal, and

petroleum coke). All measurements identified as below detection limit were assigned a value equal to one-half the detection limit for use in

the calculations. All concentrations are facility-averaged; i.e., multiple measurements from a single site were averaged, and the resulting

population of facility averages was used to generate the statistics in this table. Statistics presented here are based on a varying number of

samples, depending on the constituent. For details, refer to the Technical Background Document for the Report to Congress on Remaining

Wastes from Fossil Fuel Combustion: Waste Characterization.

Source: CIBO, 1997b

Table 5-4. Facility Average TCLP Results for FBC Wastes (mg/l)
Report to Congress on Wastes from the Combustion of Fossil Fuels

1

 At another facility, one sample for selenium was reported as a non-detect with a detection limit more than

twice the regulatory level. If assigned a value of one-half the detection limit according to the approach used in this

report, the sample would be counted as an exceedence; however, given that no other samples exceeded the

regulatory threshold for selenium, this apparent exceedence was assumed to be an artifact of the high detection limit

and not counted here.

2

 The facility average TCLP concentration of vanadium at the single petroleum coke-fired facility for which

data are available was 1.86 mg/l for bed ash and 0.185 mg/l for fly ash. By comparison, all vanadium analyses were

below detection limits at the single coal-fired facility where vanadium was sampled.

5-12 March 1999

facility that burns waste coal, the only sample of fly ash analyzed for mercury exceeded the threshold for

that metal.1

In addition, as shown in Table 5-4, TCLP data (and, in some cases, EP data) are available for a

number of other non-RCRA-regulated constituents, including antimony, beryllium, boron, cobalt, copper,

manganese, molybdenum, nickel, thallium, vanadium, and zinc. These constituents of potential concern

are considered further in Section 5.4 along with the eight RCRA-regulated metals for their potential risk

to human health and the environment.

A few respondents to the CIBO survey also provided data on organic constituents in FBC waste

leachate. Of 102 analyses for various organics from seven facilities, 97 (or 95 percent) were below

detection limits. The five analyses above detection limits were from a single facility. This facility

reported concentrations of 0.1 milligrams per liter (mg/l) each for benzene, chlorobenzene, 1,4-

dichlorobenzene, trichloroethylene, and tetrachloroethylene. These concentrations are well below the

RCRA regulatory threshold for these constituents (0.1 mg/l compared to 0.5 mg/l, 100 mg/l, 7.5 mg/l,

0.5 mg/l, and 0.7 mg/l for each constituent, respectively). Analyses for 24 other organics at the same

facility were below detection limits. The leachate data presented in this section include facilities burning

all types of fuel. There is a possibility that facilities burning petroleum coke may leach higher

concentrations of certain metals, due to higher concentrations of these metals in the fuel. To investigate

this possibility, EPA compared TCLP and EP results for FBC facilities burning petroleum coke to those

for facilities burning other fuels (mainly coal). The available data on petroleum coke-fired FBC wastes

are sparse. On a constituent-by-constituent basis, data are available for a maximum of three of the five

petroleum coke-fired facilities. In addition, the majority of samples are below detection limits for all

constituents other than barium, vanadium, and zinc. Although the data are somewhat limited, trace

constituent concentrations for petroleum coke-fired FBC wastes are similar to or less than levels in coalfired FBC wastes, except for vanadium.2

 Thus, coal-fired FBC wastes are considered the bounding case

in terms of waste characteristics, and EPA relied on the coal-fired FBC data in its risk assessment

analysis for FBC wastes.

5.3 CURRENT MANAGEMENT PRACTICES

Unlike the other wastes covered by this study, the majority of FBC waste is not disposed in

traditional waste management units. Instead, most FBC waste is beneficially used, primarily in

minefilling. Sections 5.3.1 through 5.3.4 characterize the management units used for that portion of FBC

waste that is disposed. Section 5.3.5 covers beneficial uses and minefilling.

Two sources of data are available to characterize management practices for FBC wastes. The

first is the CIBO FBC survey (CIBO, 1997b) conducted in 1996. In addition, four of the landfills

covered in the Electric Power Research Institute (EPRI) utility comanagement survey (EPRI, 1997a), also

conducted in 1996, reported managing FBC waste. One of these facilities responded to the CIBO FBC
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March 1999 5-13

survey, but the other three did not. The EPRI responses from these three additional units are analyzed

here along with the CIBO responses. This analysis treats the CIBO respondents plus the three EPRI

respondents as a single sample. The 23 facilities in this sample cover 27 percent of all U.S. facilities

using FBC. The estimated quantity of FBC waste managed by the surveyed waste management units is

about 2.1-million tons per year, or 22 percent of the total estimated FBC waste generated. The sample

facilities include utilities and non-utilities and are geographically representative of the full population,

with the exception that Pennsylvania and Illinois appear to be underrepresented in the sample.

5.3.1 Unit Types and Locations

The 23 facilities in the combined sample reported a total of 25 waste management units: 12

onsite landfills, 5 offsite landfills, 4 onsite surface impoundments, and 4 units of unknown type. These

data show landfilling as the most common FBC waste management practice, accounting for 81 percent of

the units whose type (i.e., landfill or surface impoundment) is known. The proportion of landfills for

FBC wastes is greater for FBC wastes than for utility CCWs. In addition, of the four impoundments

identified, three are operated by the same company. The fourth impoundment is a conventional utility

CCW management unit in which FBC wastes also are disposed. Therefore, EPA believes the identified

impoundments represent unusual cases.

The FBC waste management units in the sample are relatively new. One of the surface

impoundments was constructed in 1974, but the remaining units all were constructed after 1981. This

may be due to the relatively recent adoption of FBC technology. New facility construction may include

new waste management units to serve the facility. Where this new facility construction includes FBC

technology (as opposed to cases in which FBC is a retrofit at an older facility), the FBC waste would

consequently be managed in these new waste management units. The age distribution of FBC waste

management units also may help explain the predominance of landfills, if the FBC sector follows the

general trend found for utility CCW management (see Section 3.3).

5.3.2 Types and Volumes of Wastes Managed

The two types of FBC waste, fly ash and bed ash, are frequently combined and managed

together. Combined management with other, non-FBC wastes, however, is less common for FBC wastes

than for other types of FFC waste. Only 10 (or 40 percent) of the 25 FBC waste management units for

which data are available reported managing FBC wastes with other wastes. In addition, two of the offsite

landfills did not report comanagement, but are described as municipal solid waste landfills. Presumably,

in these landfills, FBC wastes are managed along with municipal solid waste, bringing the total to 12

units (48 percent) that practice combined management. This compares to comanagement by 84 percent

of conventional utility CCW management units.

In management units that combine FBC wastes with other wastes, the types of waste managed

are as variable for FBC waste management units as those for CCW management units. The types of

waste comanaged include conventional CCWs, low-volume combustion wastes (e.g., metal cleaning

wastes, cooling tower blowdown, boiler blowdown, regenerant wastes, and coal pile runoff), and noncombustion wastes (e.g., municipal waste, wastewater treatment sludge, dredged soils, wastepaper

deinking sludge, and construction debris). One facility, a utility with a conventional coal boiler in

addition to an FBC boiler, comanages coal mill rejects. The quantities of non-FBC waste managed range

from several times to a fraction of the quantity of FBC waste.
Report to Congress on Wastes from the Combustion of Fossil Fuels

5-14 March 1999

5.3.3 Unit Size

Table 5-5 shows summary statistics on the dimensions of FBC waste management units. These

data show that FBC waste management units are smaller than typical conventional utility CCW

management units (see Section 3.3). While most FBC landfills are clustered around the median size, two

units in the population are much larger, with capacities of 5-million and 6.1-million cubic yards.

5.3.4 Environmental Controls

The CIBO FBC survey collected information on liners, covers, leachate collection systems,

ground-water monitoring systems, and regulatory permits. These environmental controls are defined in

Chapter 3. The CIBO FBC survey also collected information on several other types of environmental

controls, described in Box 5-2.

Table 5-6 summarizes the use of environmental controls in FBC waste management units. Based

on these data, the frequencies of environmental controls for FBC waste management units are similar to

corresponding frequencies for utility comanagement units. The following discussion provides additional

details on each type of environmental control.

Liners

As shown in Table 5-6, the frequencies of liner use for FBC waste landfills are similar to those

for utility CCW units (see Section 3.3). Figure 5-5 displays the types of materials used for FBC landfill

liners. One surface impoundment reported a synthetic liner. Two other impoundments reported being

constructed on bedrock, while the fourth reported an in situ clay liner.

Covers, Compaction, and Dust Suppression

Based on the data in Table 5-6, FBC waste landfills appear less likely than utility CCW

comanagement units to use covers (see Section 3.3). It is unclear, however, whether respondents

interpreted the question about cover as relating to current daily or interim cover or final cover at closure. 

If responses relate to final cover, then the lower percentage for FBC waste landfills is not surprising. All

of the respondents are currently active, and, therefore, would not have final cover and, as relatively new 

Landfills Surface Impoundments

Capacity

(cubic yards)

Area

(acres)

Height

(feet)

Capacity

(cubic yards)

Area

(acres)

Depth

(feet)

Number of Units 13 11 10 3 2 2

Minimum 350,000 17 17 2,240,000 28 70

Maximum 6,100,000 96 75 5,600,000 55 125

Median 1,500,000 38 52 4,000,000 41 98

Mean 2,063,461 38 51 3,946,667 41 98

Note: Not all units in the sample reported all three measurements (area, height or depth, and capacity). Where a unit reported two of the

three dimensions, the third was derived from the other two. For example, if a landfill reported only capacity and area, the design height was

calculated by dividing the reported capacity by the area.

Sources: CIBO, 1997b; EPRI, 1997a

Table 5-5. FBC Waste Management Unit Sizes
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 5-15

units, may not yet have plans for cover at closure. If responses relate to daily cover, the low number may

be partially explained by the use of dust suppression and compaction (as controls with a similar purpose

to daily cover). Nearly all FBC waste landfills use dust suppression and/or compaction.

Dust Suppression/Control. Dust suppression, typically used at landfills, usually involves conditioning the

waste with water or other liquid before and during transport and placement. The purpose of this activity is to

prevent airborne transport of waste and to reduce inhalation exposure to site workers.

Run-On and Runoff Controls and Collection Systems. Examples of run-on and runoff controls include

curbs, dikes, and diversion ditches. Run-on controls prevent precipitation runoff from other parts of a site from

reaching waste management areas, preventing this runoff from becoming contaminated by contact with waste

and/or creating leachate by percolation through waste. Runoff controls and collection systems prevent

precipitation runoff from the waste management unit, which may be contaminated by contact with waste or carry

waste particles, from being transported offsite.

Compaction. Compacting waste after placement can reduce or prevent wind and water erosion of the waste and

subsequent release to the environment. Under the right circumstances, where voids are minimized, compaction

also can reduce the permeability of the waste, slowing the creation and release of leachate.

Surface Water and Air Monitoring Systems. Similar to ground-water monitoring systems, surface water and

air monitoring systems comprise periodic collection and analysis of surface water or air samples near a waste

management unit. These systems serve as a warning that a release is occurring through the air or that a surface

water body is being contaminated.

Box 5-2. Environmental Control Technologies

Environmental Control

Landfills Surface Impoundments

Number

Reporting Data

Percent

with Control

Number

Reporting Data

Percent

with Control

Liner* 12 42% 4 25%

Cover 13 62% 3 67%

Leachate Collection 17 59% 4 50%

Run-on and Runoff Control and/or Collection 14 93% 4 100%

Dust Suppression 11 91% 3 67%

Compaction 11 55% 3 33%

Ground-Water Monitoring 16 77% 3 100%

Surface Water Monitoring 14 29% 4 50%

Air Monitoring 13 8% 3 0%

Regulatory Permits 17 89% 4 100%

*Does not count bedrock or other in situ materials as a liner.

Source: CIBO, 1997b; EPRI, 1997a

Table 5-6. Environmental Controls at FBC Waste Management Units
Report to Congress on Wastes from the Combustion of Fossil Fuels

5-16 March 1999

Figure 5-5. FBC Landfill Liner Types

Just like CCW comanagement units, the results for surface impoundments are difficult to

interpret. The two impoundments reporting covers may have placed caps on closed or full portions. 

Alternatively, these units may have reported covers to reflect standing liquid maintained above the waste

layer in the impoundment. For impoundments reporting compaction or dust suppression, the responses

could be interpreted by three scenarios: (1) that compaction or dust suppression are used on dry,

inactive, or closed areas of the impoundment; (2) that dust suppression or compaction are practiced

during dry transport of waste, prior to placement in the impoundment; or (3) that waste is transported wet

or wastes are managed under water in the impoundment, therefore preventing dust generation.

Regulatory Permits

As shown in Table 5-6, the proportions of FBC waste management units subject to permit

requirements are similar to those for CCW comanagement units (see Section 3.3). Some of the

respondents provided information about the permitting agency, as well as indicated whether the unit had

one or more permits. Six of the surveyed units (four landfills and two impoundments) had multiple

permits. In each case, the permitting agency was a state government, although one unit had both a state

and a county permit.

5.3.5 Beneficial Uses

Like conventional CCWs, FBC wastes may be applied to useful purposes as an alternative to

traditional waste management. In fact, according to CIBO survey statistics, the majority of FBC wastes

currently are beneficially used. Table 5-7 shows data on the current developed uses of FBC wastes. The

most dominant use of these wastes is in minefills, followed by waste stabilization, construction fills, and

agricultural uses. Box 5-3 provides a brief discussion of these uses.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 5-17

5.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE

ENVIRONMENT

5.4.1 Potential Ground-Water Risks to Human Health

Section 3.4 provides a discussion of the methodology employed by EPA in assessing risks from

coal-fired utility comanaged wastes. EPA followed a similar approach for wastes from fluidized bed

combustion, with several important differences. First, waste characterization data for FBC wastes

provided to EPA reflect wastes generated at a large portion of generators nationwide. All data were

generated using TCLP or EP Toxicity methods, and these data were combined to provide as large a

sample set as possible. Second, EPA found that very few FBC unit operators managed their wastes in

impoundments. Moreover, the majority of these few impoundments are lined or constructed on bedrock. 

Therefore, EPA limited its modeling efforts to landfill scenarios. Finally, EPA found that FBC boilers

reflect a geographic distribution distinct from utilities, and so modified its modeling scenarios

accordingly.

Information provided by CIBO indicates that minefilling is common for FBC wastes. As

discussed in Section 3.4.5, minefill risks were not evaluated using EPACMTP due to data and model

limitations.

Findings–FBC Wastes Ground Water Human Health Risk Assessment

Table 5-8 summarizes selected results from the deterministic and probabilistic analyses of risk

from FBC wastes for the adult receptor. Overall, EPA found that the risks associated with all modeled

constituents of concern, except for antimony, arsenic, beryllium, and chromium, fell below a hazard

quotient (HQ) of 1 or a lifetime cancer risk of 1×10-6. Potential risks associated with arsenic in the highend deterministic scenario exceeded 1×10-4.

Comparison of the deterministic and Monte Carlo results reveals that the deterministic results

generally exceed the 95th percentile Monte Carlo results. None of the 2,000 Monte Carlo simulation

combinations of parameter values performed for any constituent yielded a risk estimate as high as the

corresponding high-end deterministic result. Even at the 95th percentile level, the risks predicted by the

Monte Carlo simulations were two orders of magnitude or more below the corresponding risks estimated

for the high-end scenario.

Use Category Quantity (thousand tons) Percent of Generation*

Mining Applications 3,629 61.0%

Waste Stabilization 351 5.9%

Construction Fills 302 5.1%

Agricultural Use 66 1.1%

Cement and Concrete Products 5 0.9%

Other 79 1.3%

Total 4,432 74.5%

* Percent of total waste generation reported by survey respondents.

Note: Percentages might not sum due to rounding.

Source: CIBO, 1997c

Table 5-7. Beneficial Uses of FBC Wastes
Report to Congress on Wastes from the Combustion of Fossil Fuels

3

 EPA, 1998d, p. 5–33.

4

 Ibid. Note that the time to risk calculated for beryllium in the draft report was the time to reach the CSFbased HBL. The MCL is greater than the HBL and so the time to reach the MCL must be at least as great as the

time to reach the HBL.

5-18 March 1999

EPA also considered the time at which risks were predicted to result from the release of

constituents of concern. EPA found that the concentration of arsenic in ground water at the receptor well

would not reach the health-based level (HBL) for arsenic (i.e., achieve a risk level of 1×10-6) for more

than 3,000 years.3

 The times to reach the antimony HBL and the beryllium MCL in ground water were

predicted to be nearly 6,000 years and greater than 6,500 years, respectively.4

Mining Applications. According to CIBO survey statistics, FBC wastes are most often utilized in mining

applications. FBC wastes can be beneficially used in coal mine remediation activities, including the control of

acid mining drainage, backfilling, blending mine soils and spoils, and revegetation. The alkaline characteristics

of FBC wastes make them useful as a neutralizing buffer to dampen or eliminate the self-sustaining acid mining

drainage generation. FBC waste has a significant quantity of unreacted sorbent (i.e., lime or limestone) that

contributes to this buffer capability. FBC wastes mixed with conventional coal combustion fly ash and other

mine spoils also have been used successfully. Another use of FBC waste is as backfill material to neutralize

acidity at mine pits, and to prevent mine subsidence from abandoned underground mines. In order to neutralize

the acidity of mine soils and spoils, significant quantities of mine wastes are mixed with FBC wastes. This also

is performed in an effort to create a topsoil amenable to revegetation at mine sites.

Waste Treatment. FBC wastes also are applied in the treatment and management of hazardous waste. The

primary objective of solidification and stabilization processes is to chemically fix potentially hazardous wastes in

a solid matrix. Mixtures using FBC wastes have been found to stabilize the acidic components and trace

constituents found in hazardous waste in a cost-effective manner.

Construction Fills. The granular and cementitious properties of FBC wastes and their free lime content are

useful in various civil engineering applications. These wastes are applied as stabilizing agents in subgrade or

subbase soils (e.g., road and road base construction, low-strength backfilling). Like lime, FBC wastes improve

the compaction and load bearing capabilities and lower the plasticity of clays or silty soils. Moreover, FBC

wastes introduce some degree of cementitious bonding not obtained with the addition of lime alone.

Agricultural Use. Besides increasing the pH of the soils, FBC waste also provides increased solubility. The

gypsum contained in FBC waste has a significant impact on soil chemical and physical properties. Specifically,

it has the potential to improve filtration, reclaim high sodium soils, increase rooting in acid subsoils due to the

reduction of aluminum toxicity, and supply calcium and sulfur to plants. Increasing rates of FBC waste

application have also been found to decrease soil extractable zinc, manganese, phosphorous, and potassium. 

Lastly, the ash content acts as a supplier of macro- and micro-nutrients essential to plant growth. The major

problems associated with FBC residue use for agricultural purposes are high alkalinity and salinity, which may

reduce plant growth at high application rates. 

Cement and Concrete Products. The volume of FBC wastes used in concrete products has been minimal. 

Several factors including slow setting and expansion of the concrete product with time have been experienced,

even when FBC wastes are mixed with fly ash. Still, studies are being conducted to understand the cementing

action, strength development, and stability of concretes that use only FBC wastes and fly ash as binders (i.e.,

concretes that do not contain Portland cement).

Sources: CIBO, 1997c; EPA, 1998h

Box 5-3. Beneficial Uses of FBC Wastes
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 5-19

Considering the low hazard quotients, the very low probabilistic risk, and the long time to reach a

level of risk for beryllium, antimony, and chromium, EPA eliminated these metals from further

consideration for this pathway.

Table 5-9 summarizes the estimated risks to adult and child receptors for the high-end

deterministic scenario for FBC wastes. Overall, the results show that for non-carcinogens the risks for

young children increased roughly twofold compared with the adult receptors. For arsenic, risks changed

very little between the receptors.

5.4.2 Potential Above-Ground Multi-Pathway Risks to Human Health and the

Environment

Human Health Risk Findings

No cancer risk in excess of 10-6 or non-cancer HQ in excess of 1 were found, except for agricultural

application. Risks to farmer and child were approximately 10-5 for the pathway.

Scenario Constituenta

Deterministic

Risk, Central

Tendency

Deterministic

Risk, High-End

Corresponding

Monte Carlo

Percentile

Monte Carlo

95th Percentile

FLb Antimony HQ <1 HQ = 12 >100 HQ = 0.007

Arsenic 1×10-8 4.3×10-4 >100 2×10-6

Beryllium HQ <1 HQ = 1.4 >100 HQ <0.001

Chromium HQ <1 HQ = 1.1 >100 HQ = 0.002

a

 All other metals modeled resulted in HQ <1

b

 FL = FBC waste landfill

Note: Results shown are those from the October 10, 1998, Sensitivity Analysis.

Table 5-8. Comparison of Deterministic and Monte Carlo Risk Model Results for FBC

Waste Ground-Water Pathway Scenario

Scenario Constituenta

High-End Deterministic Risk

Deterministic Risk,

Central Tendency

Deterministic Risk,

High-End

Monte Carlo

95th Percentile

FLb Antimony HQ = 12 HQ = 20.8 HQ = 13.4

Arsenic 4.3×10-4 5.4×10-4 3.8×10-4

Beryllium HQ = 1.4 HQ = 2.4 HQ = 1.6

Chromium HQ = 1.1 HQ = 1.9 HQ = 1.2

a

 All other metals modeled resulted in HQ <1

b

 FL = FBC waste landfill

Note: Results shown are those from the October 10, 1998, Sensitivity Analysis.

Table 5-9. Comparison of Adult and Child Risk Model Results

for FBC Waste Ground-Water Pathway Scenario
Report to Congress on Wastes from the Combustion of Fossil Fuels

5-20 March 1999

Ecological Risk Findings

No ecological risk was found, but EPA had no characterization data with which to assess FBC

impoundments. Given that landfill risks for human health risk approximate those for utilities, it is likely,

based on total constituent analysis, that ecological risks similar to those for utility impoundments would

exist for the few reported FBC impoundments.

5.4.3 Documented Damages to Human Health and the Environment

EPA relied on a report prepared by CIBO to assess releases and damage cases to human health or

the environment involving FBC wastes (CIBO, 1997c). In addition, while not specifically directed at

FBC non-utilities, EPA’s examination of state file information for non-utilities in six states did not

identify any additional incidents related to FBC waste management sites. This indicates that the state

officials contacted were unaware of any damage cases related to FBC non-utilities. EPA has not

specifically pursued other references to further identify other FBC waste management sites with

documented releases or damages.

The CIBO report identified eight sites managing FBC wastes where ground- or surface-water

contamination was observed. In seven of the cases, the contamination appears to be related to preexisting conditions (based, for example, on evidence of upgradient ground-water contamination). At the

eighth site, insufficient historical information was available and the contaminant found in the ground

water (lead) was found to be inconsistent with those typically present in FBC wastes. EPA concluded

from the review of these eight cases that contamination likely resulted from other sources; therefore, the

observed damages do not result from FBC waste management. More detailed discussion of these eight

sites are presented in the Technical Background Document for the Report to Congress on Remaining

Wastes from Fossil Fuel Combustion: Potential Damage Cases, as well as in the CIBO report.

5.5 EXISTING REGULATIONS

EPA’s objective in this analysis was to identify and evaluate the existing regulatory controls that

pertain to the management of FBC wastes. The regulatory analysis is directed toward addressing the

question of whether existing regulations adequately protect human health and the environment. The

analysis also is helpful in understanding waste generation and current management practices.

The sections below discuss regulations addressing air pollution, water pollution, and solid and

hazardous waste, respectively. Air regulations are relevant primarily because of their effect on waste

generation. Water regulations have an influence both on waste generation and management, and, in

particular, address the impact of FBC wastes on surface waters. Solid and hazardous waste regulations

are of the greatest interest because they directly govern waste management practices.

The sections below describe federal regulations in each of these areas. In many cases, the

implementation of these federal programs is carried out by the states. Therefore, where appropriate,

aspects of state implementation also are discussed. Because the nuances of state implementation are of

particular importance with respect to solid waste regulation, that section discusses state programs in

detail. Where appropriate, that section also describes state control on two of the beneficial uses of

concern to EPA: minefilling and soil amendment.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 5-21

5.5.1 Regulations Addressing Air Pollution

The federal Clean Air Act (CAA) is intended to protect and enhance the quality of the nation’s

air resources. The CAA requirements most relevant to FBC wastes include the following:

• National Ambient Air Quality Standards (NAAQS) for particulate matter (PM)

• NAAQS for sulfur dioxide

• Title IV acid rain provisions

• NAAQS for ozone

• National Emissions Standards for Hazardous Air Pollutants (NESHAP).

Historically, CAA requirements have been a significant factor affecting the generation and collection of

FBC wastes. Recent and forthcoming changes in these requirements also may impact waste generation or

characteristics.

NAAQS for Particulate Matter

The NAAQS for PM establish maximum concentrations of PM with diameter less than or equal

to 10 micrometers (PM10) in the ambient air. These standards are among the factors motivating the use

of particulate control technologies at FFC facilities. EPA recently proposed to lower the size criterion to

2.5 micrometers, which may affect the volume of fly ash collected and selection of control technology;

however, final standards will not be issued for at least 5 years, so the impacts of the new standard are

difficult to predict at this time.

The NAAQS for PM are implemented through the following regulatory mechanisms: New

Source Performance Standards and State Implementation Plans, described below.

New Source Performance Standards (NSPS). The NSPS subjects newly constructed or

modified units to specific PM emissions limits. These limits may be met by changing fuel types,

modifying combustion conditions, or installing control devices. The applicability of the NSPS and the

specific limits imposed vary with the age and size of the combustion unit, with older and/or smaller units

less likely to be subject to the NSPS. Specifically the regulation of facilities can be considered in four

categories.

• 40 CFR 60 Subpart D governs the standards of performance for new fossil fuel-fired steam

generators that were constructed or underwent major modification after August 17, 1971. 

Subpart D affects only units that are capable of burning fossil fuels at greater than 73

megawatts (MW) of heat input rate.

• Subpart Da affects utility units with the capacity to fire fuel at greater than 73 MW heat

input rate that commenced production or major modification after September 18, 1978.

• Subpart Db affects coal-fired units with the capacity to fire fuel at greater than 29 MW of

heat input rate that commenced construction or modification after June 19, 1984.

• Subpart Dc governs coal-fired units constructed or modified after June 9, 1989, with

capacity to fire fuel at less than 29 MW but greater than 8.7 MW heat input rate.

With the exception of Subpart Da, which applies specifically to utilities, the NSPS requirements

apply to all FBC units, utility or non-utility. Non-utilities, however, tend to have smaller capacities than
Report to Congress on Wastes from the Combustion of Fossil Fuels

5-22 March 1999

utilities. Also, FBC units, in general, tend to be smaller and newer than conventional units. Therefore,

FBC units, and particularly non-utility FBC units, are more likely captured by those NSPS requirements

that apply to smaller capacity, newer units (i.e., Subparts Db and Dc). Note that under the NSPS

regulations, facilities that were in operation before the dates stated in each of the four subparts are

considered “grandfathered” and would not be subject to the newer standards unless they underwent a

major modification.

State Implementation Plans (SIPs). The performance standards above can be enforced by a

federal, state, or local regulatory agency. There are additional CAA regulations that could require an

FBC unit to install a particulate removal device notwithstanding the grandfather clause in Subparts D,

Da, Db, and Dc. SIPs may impose, on a state-by-state basis, PM controls of varying stringency on

specific sources or categories of sources, including FBC facilities. Such controls are required under Title

I of the CAA if a particular area is in nonattainment for the NAAQS for a criteria pollutant such as PM. 

For this reason, SIP controls will generally be more stringent in such nonattainment areas. In attainment

areas, the prevention of significant deterioration (PSD) program requires new sources to apply Best

Available Control Technology (BACT), which must be at least as stringent as NSPS.

NAAQS for Sulfur Dioxide and Title IV Acid Rain Requirements

Like the NAAQS for PM, the NAAQS for sulfur dioxide establish a maximum concentration of

sulfur dioxide in the ambient air. The NAAQS for sulfur dioxide are implemented through NSPS and

SIPs. The functioning and applicability of the sulfur dioxide NSPS requirements are similar to those for

PM, although there is less variation based on age and size.

Each of the four categories of FBC facilities regulated under Subparts D, Da, Db, and Dc is

subject to the same requirement: sulfur dioxide emissions must be less than 520 nanograms per joule

(ng/J) of heat input. Facilities with greater than 22 MW of heat input capacity generally also must

achieve a 10-percent reduction in their sulfur dioxide emissions, based on the potential concentration in

fuel. An additional category of FBC units, those constructed or modified after June 9, 1989, and between

2.9 and 8.7 MW of heat input capacity, also must meet the 520 ng/J standard, but may do so based on

certification from the fuel supplier that the sulfur content of the fuel is low enough to meet the standards. 

Finally, FBC units firing only waste coal are subject to a more stringent percent reduction requirement: a

20-percent reduction in their sulfur dioxide emissions, based on the potential concentration in fuel.

In addition to NSPS, states may impose controls through their SIPs to meet the sulfur dioxide

NAAQS. These controls may vary in stringency depending on attainment status and may be placed on

specific sources or categories of sources, including FBC units.

The Title IV acid rain provisions provide additional impetus for the application of FGD

technology at utilities. These provisions require specific reductions of sulfur dioxide emissions via the

following:

• Installing FGD equipment

• Switching to low sulfur fuel

• Purchasing emissions allowances from other sources that have exceeded their reduction

requirements.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 5-23

Affected sources are allowed complete flexibility in choosing among these options. The current

phase of the Title IV program affects several hundred of the largest generating units at utilities. These

requirements, therefore, do not currently apply to non-utility FBC units. EPA is currently evaluating

further requirements for lower sulfur dioxide standards and emissions.

Because they capture sulfur oxides using a sorbent within the combustion bed, FBC units

generally do not require the application of separate FGD technologies to comply with the Title IV acid

rain provision or the NAAQS for sulfur dioxide. In fact, these regulations may have been a contributing

factor in the development and commercialization of FBC technology.

NAAQS for Ozone

The NAAQS for ozone establish a maximum concentration of ozone in the ambient air. EPA

recently lowered this concentration from 0.12 parts per million (ppm) to 0.08 ppm. The new standard

allows four exceedences of the maximum in a region over a 3-year period. EPA expects states will meet

the new standard by amending their SIPs to limit nitrogen oxide emissions at utilities. In proposing the

new rule, EPA published a Regulatory Impact Analysis (RIA) forecasting changes in the operating

practices of utilities that could result from these SIP modifications (EPA, 1997b). The RIA, however, did

not specifically estimate the impact of these regulations on the subset of utilities utilizing FBC

technology. Therefore, the impact on this segment is uncertain. The recent changes are not expected to

affect non-utilities (and, in turn, non-utility FBC waste generation) significantly.

NESHAP

Under the NESHAP, EPA is required to establish technology-based standards for 189 hazardous

air pollutants (HAPs). These standards are to be set on an industrial category basis and will apply to

facilities (major sources) that emit greater than 10 tons/year of any one HAP or greater than 25 tons/year

of any combination of HAPs.

EPA has studied HAP emissions from utility coal-fired steam generating units (including FBC

units) and found that mercury from coal-fired utilities is the HAP of greatest concern. Dioxins and

arsenic (primarily from coal-fired plants) also are of potential concern. EPA has deferred any

determination as to whether regulations to control HAP emissions from utilities are appropriate and

necessary (EPA, 1998c). If such regulations were promulgated, they could affect the characteristics or

quantities of FFC solid wastes.

EPA has not studied HAP emissions specifically for non-utility FBC facilities. Because

NESHAP will be set on an industrial category basis, when promulgated, the impact of these regulations

on FFC waste generation and characteristics may vary depending on the industrial sector of the nonutility FBC facility.

5.5.2 Regulations Addressing Water Pollution

Under the federal Clean Water Act, the National Pollutant Discharge Elimination System

(NPDES) controls discharges to waters of the United States. The controls required under NPDES affect

the collection and management of FBC wastes. In states authorized by EPA, these controls are

implemented through state programs (often termed State Pollutant Discharge Elimination Systems, or

SPDES). Because state programs must be at least as stringent as the federal program, the discussion here

focuses on federal requirements as a lowest common denominator. NPDES requirements apply

differently to two categories of discharges: process wastewaters and stormwater runoff. Neither the
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5-24 March 1999

NPDES process wastewater or NPDES stormwater requirements make a distinction between

conventional and FBC units. Distinctions may apply, however, between utilities and non-utilities.

NPDES Requirements for Process Wastewaters

The NPDES requirements that apply to process wastewaters from utility FBC facilities are those

for the steam electric point source category under 40 CFR Part 423. These requirements apply to

facilities “primarily engaged in the generation of electricity for distribution and sale” (i.e., utilities). 

Non-utility FBC facilities face NPDES requirements for process wastewaters that are specific to their

industrial sector. In most cases, under these requirements each discharge requires an individual NPDES

permit with numeric limitations based on Best Practicable Control Technology Currently Available

(BPT), Best Available Technology Economically Achievable (BAT), or New Source Performance

Standards (NSPS). Facilities that discharge to publicly owned treatment works (POTWs) rather than

directly to surface waters face Pretreatment Standards for Existing Sources (PSES) similar to BAT, or

Pretreatment Standards for New Sources (PSNS) similar to NSPS.

As discussed in Section 5.3, FBC wastes are rarely managed wet. Therefore, the NPDES process

wastewater requirements generally are not relevant to management of these wastes. In those unusual

cases where FBC wastes are managed wet, the most relevant requirements are total suspended solids

(TSS) limits.

At non-utilities, the specific NPDES effluent standards applied depend on industrial category. 

Effluent standards with potential applicability to non-utility FBC facilities include those for the following

industry categories:

• Pulp, paper, and paperboard (40 CFR Part 430)

• Organic chemicals, plastics, and synthetic fibers (40 CFR Part 414)

• Inorganic chemicals manufacturing (40 CFR Part 415)

• Grain mills (40 CFR Part 406).

The standards for all of these categories include TSS limits, and these limits are applicable to nearly all

of the industrial subcategories covered under each category. Some subcategories are subject to zero

discharge requirements. Some FBC facilities are found in other industrial categories, many of which are

also subject to TSS limits. Some facilities (such as education institutions) may not be subject to the

specific standards of any industrial category. In these cases, the specific effluent limitations would be

determined on a case-by-case basis as part of the individual NPDES permit for the facility.

At utilities, the steam electric category NPDES requirements place TSS limits directly on fly ash

handling and bottom ash handling waters. In addition, the NSPS for the steam electric category include a

zero discharge requirement for fly ash handling water. These steam electric requirements also may be

incorporated in individual permits at non-utilities to supplement their industrial category requirements. 

Application of steam electric requirements to relevant waste streams at non-utility fossil fuel combustors

is left to the best professional judgment of the individual permit writer (EPA, 1996).

In the few cases in which FBC wastes are managed wet, the TSS and zero discharge

requirements discussed above are relevant as follows. Facilities may have to settle or otherwise remove a

certain amount of waste solids from the handling water to meet the TSS limits prior to discharge. Zero

discharge requirements effectively eliminate the release of waste solids to surface water. The

requirements control the direct release of fly ash, bed ash, and any treatment solids to surface waters.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 5-25

NPDES Requirements for Stormwater

NPDES stormwater requirements apply to stormwater runoff from FFC facilities, which may

include runoff from operating areas, ash handling areas, and waste management units. Like the process

wastewater requirements, stormwater requirements have been established on an industrial sector basis. 

The NPDES stormwater requirements, however, are additive across industrial sectors. Therefore, the

steam electric requirements apply to both utility and non-utility FBC facilities. A chemical manufacturer,

for example, operating an FBC unit must meet both chemical manufacturing and steam electric

stormwater requirements.

Facilities can meet the stormwater requirements by including stormwater in their individual

NPDES permit or seeking coverage under a general permit by submitting a Notice of Intent (NOI). 

Individual permit control and monitoring requirements will be facility-specific, subject to the judgment

of the permit writer.

When covered by a general stormwater permit, requirements include implementation of a

stormwater pollution prevention plan, “reasonable and appropriate” control measures, and 1 or 2 years of

monitoring and reporting. No site visit by regulators is required under the general permit. Under the

general permit approach, facilities have a great deal of flexibility in selecting appropriate control

measures for runoff that may have contacted FBC wastes. The general permit requirements include

recommended best management practices for stormwater at steam electric facilities, landfills, treatment

works, and construction areas greater than 5 acres. Because these requirements are additive across

industrial sectors, if the hypothetical chemical manufacturer described above also operated an onsite ash

landfill, that facility would have to meet landfill requirements in addition to chemical manufacturing and

steam electric requirements.

Because the stormwater program is relatively new and managed by authorized states, the number

of facilities with general versus individual permits is not known. EPA handles NOIs for 10

nonauthorized states. In these states, 700 steam electric facilities (utilities and non-utilities) have filed

for general permits.

5.5.3 Regulations Addressing Solid and Hazardous Waste

Subtitle C of RCRA establishes a “cradle-to-grave” management system for wastes that are

considered hazardous because they fail tests based on physical and chemical characteristics (i.e., toxicity,

corrosivity, ignitability, and reactivity) or because they are listed as hazardous by EPA. Federal

regulations establish stringent environmental and administrative controls that must be applied to

management of these wastes. FBC wastes are currently exempt from federal regulation as hazardous

waste under Subtitle C pending this Report to Congress and the subsequent regulatory determination. 

Therefore, these wastes are subject to the requirements of Subtitle D of RCRA as nonhazardous solid

waste.

Implementation of Subtitle D is the responsibility of individual states, but nothing prevents states

from imposing more stringent requirements (including hazardous waste requirements) on FBC wastes. 

FBC units are located in 30 of the 50 states. EPA characterized the waste management requirements in
Report to Congress on Wastes from the Combustion of Fossil Fuels

5

 Four states (Colorado, Florida, Georgia, and Pennsylvania) indicated in the CIBO survey that they impose

different requirements based on the combustion technology used. EPA supplemented the survey data with specific

information from its review of regulations in Pennsylvania. EPA did not collect specific data on FBC waste

requirements in the other three states. These three states account for less than 10 percent of FBC equivalent

electrical generating capacity.

5-26 March 1999

27 of these 30 states using survey and other data sources.5 All of these states regulate FBC wastes under

the same programs as CCWs from conventional combustion processes.

Currently, 24 of the 27 states for which data are available (representing 86 percent of the

surveyed FBC generating capacity and 78 percent of FBC capacity overall) duplicate the federal policy

exempting CCWs (including those from coal-fired FBC) from hazardous waste regulations. The three

remaining states (Washington, Maine, and California) do not exempt FBC wastes from state hazardous

waste regulation. In these states, any FBC wastes that fail the hazardous waste characteristic tests would

be subject to state hazardous waste requirements and managed in units that meet permitting, design,

operating, corrective action, and closure standards.

As discussed in Section 5.2, FBC wastes seldom fail the hazardous waste characteristic tests. 

Therefore, the majority of FBC wastes would be subject to state requirements under Subtitle D because

they do not fail the hazardous waste characteristic tests and/or are generated in the states that duplicate

the federal exemption. Table 5-10 describes state regulatory authority with respect to FBC landfills in

the 27 states for which data are available. These data show that the majority of states have the authority

to require permits and to impose physical controls and monitoring requirements on FBC landfills, at least

on a case-by-case basis. The types of regulatory controls include siting controls, liners, leachate

collection systems, ground-water monitoring, closure controls, daily (or other operational) cover, and

fugitive dust controls. EPA believes that the use of such controls has the potential to mitigate risks,

particularly ground-water pathway risks, from FBC waste disposal. The adequacy of this mitigation

depends on the extent to which states are exercising their authority in situations in which climate,

geology, site-specific conditions, and waste characteristics affect the magnitude of the risk.

Section 5.3 of this report found that most of the FBC waste landfills surveyed are subject to

regulatory permits and ground-water monitoring requirements and nearly all incorporate dust suppression

and run-on or runoff controls. Just over half of those surveyed have covers and leachate collection

systems and just under half are lined. These statistics suggest that states have exercised their authority to

impose control at FBC waste management units. To further examine state implementation of solid waste

requirements on FBC wastes, EPA examined in greater detail the regulations applicable in two states:

Pennsylvania and California. These two states are ranked first and second in FBC generating capacity. 

Together, they account for more than 30 percent of total U.S. FBC electrical generation capacity. Table

5-11 summarizes the requirements in these states. Because surface impoundments are seldom used for

FBC wastes, this analysis focuses on landfill regulations.

Examination of these two states reveals some variation in approaches to implementing Subtitle D

requirements for FBC landfills. Both Pennsylvania and California subject FBC wastes to regulations that

impose requirements tailored to the characteristics of the waste. The program in California, however,

contains special provisions that apply to nonhazardous FBC wastes. The state allows generators of FBC

wastes that do not test hazardous to utilize facilities in the “standardized” regulatory tier. Nonhazardous

FBC wastes disposed in these facilities are subject to less stringent requirements, regardless of their

characteristics.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 5-27

Table 5-11. State Waste Management Requirements Applicable to FBC Wastes

in Selected States

Pennsylvania

Landfill

Requirements

Landfills are classified according to TCLP results for the wastes to be disposed. Specific design

requirements depend on the class of the landfill. Based on available characterization data, most FBC

wastes would be amenable to Class III landfills. Requirements for these include siting restrictions, a 4-foot

attenuating soil base (or 1-foot-per-4 feet of waste), fugitive dust control, daily cover, soil erosion control,

ground-water monitoring, 2-foot clay cap at closure, and revegetation at closure.

Grandfather

Clause

Units permitted prior to July 4, 1992, were required to modify their operations to comply with the above

requirements by July 4, 1997. Liner and leachate collection requirements may be modified if the operator

could demonstrate that the unit had not caused unacceptable ground-water degradation.

Minefill

Requirements

FBC wastes must meet TCLP limits for disposal at a Class III landfill. Ground-water monitoring is required. 

Soil Amendment

Requirements

FBC wastes must meet pH limits. State agency notification and runoff and erosion controls are required. 

There are siting limitations.

California

Landfill

Requirements

Any FBC wastes failing hazardous waste characteristic tests are subject to state hazardous waste

management requirements. However, based on available characterization data, most FBC wastes would

be managed under the non-hazardous solid waste program. Under this program, FBC wastes may be

managed in special “nonhazardous ash disposal/monofill facilities” which fall into the state’s “standardized”

regulatory tier. FBC wastes also may be managed in solid waste landfills in the more stringently regulated

“full permit” tier.

“Nonhazardous ash disposal/monofill facilities” tier are required to obtain a standardized permit and are

subject to minimum operating standards including siting restrictions, control of windblown material, and

drainage control.

Number of Statesa Percent of Statesb Percent of Capacityc

Permit Onsite 23 85% 94%

Permit Offsite 27 100% 100%

Siting Controls 25 93% 96%

Liner 23 85% 91%

Leachate Collection Systems 23 85% 95%

Ground-Water Monitoring 25 93% 97%

Closure Controls 25 93% 94%

Cover and/or Dust Controls 27 100% 100%

Corrective Action 22 81% 96%

a

 Number of states with authority to impose the indicated requirement, either by regulation or on a case-by-case basis.

b

 Percent of the 27 surveyed states with authority. For testing requirements, percent of 17 states providing information on these

requirements.

c

 Percent of FBC generating capacity in the 27 surveyed states represented by states with authority.

Sources: CIBO, 1997c; EPA, 1995b; ASTSWMO, 1995; ACAA, 1996a

Table 5-10. Current State Regulatory Controls on FBC Landfills
Report to Congress on Wastes from the Combustion of Fossil Fuels

5-28 March 1999

Grandfather

Clause

Information not available.

Minefill

Requirements

Information not available.

Soil Amendment

Requirements

Information not available.

5.6 WASTE MANAGEMENT ALTERNATIVES

The risk assessment identified potential ground-water pathway risks to human health from FBC

wastes managed in unlined landfills. Mitigation of these potential risks might be accomplished through

the use of technologies that prevent or contain and collect leachate from FBC landfills. Specifically,

EPA identified the technologies in Table 5-12 as an alternative that would be practical and effective to

target and mitigate the potential ground-water risk. The technologies shown in Table 5-12 are considered

further in the cost and economic impact analysis (Section 5.7). Section 5.7 includes the option of

sending waste to an offsite commercial landfill employing these technologies, as well as the option of

constructing such a unit on site. Note that these technologies are consistent with those required under

Subtitle D of RCRA.

Of the beneficial uses discussed in Section 5.3.5, agricultural use may be of environmental

concern, based on the non-ground-water risk assessment that found potential arsenic risks to human

health from this practice. An approach for mitigating this potential risk might include a standard limiting

the arsenic concentration in wastes intended for this use. The cost estimate for FBC waste includes

consideration of a more stringent approach: a ban on agricultural use. Minefilling also may be of

concern, particularly when wastes are placed below the water table. EPA is seeking further information

on this practice.

5.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS

This section discusses the costs and economic impacts of risk mitigation alternatives for FBC

wastes. Details of this analysis are documented as part of the EPA docket.

5.7.1 Overview and Methodology

In estimating costs and economic impacts for FBC facilities, EPA used a similar approach to that

described in Section 3.7.1. Salient distinctions between the analysis in Section 3.7 and this analysis are

reviewed below.

Landfill

Design includes filter fabric, 1' sand layer, 2' clay liner, synthetic high-density polyethelene (HDPE) liner, leachate collection

system, and ground-water wells.

Operation includes environmental monitoring and leachate collection and treatment.

Closure requirements include 6" topsoil and vegetation, filter fabric, 1.5' sand layer, 2' clay layer, synthetic (HDPE) liner, and a

cover drainage system.

Post-closure includes environmental monitoring, landscape maintenance, slope maintenance, inspection, and administration.

Table 5-12. Management Alternatives for Non-Utility CCW
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 5-29

EPA’s analysis for FBC facilities began with 84 FBC facilities identified in the CIBO FBC

Report (CIBO, 1997c). Half of these are in the electric service sector. EPA estimated the incremental

compliance cost of the risk mitigation alternative described in Section 5.6. As described in that section,

this requires generators to construct onsite composite-lined landfills or transport waste to an offsite

commercial Subtitle D landfill. The more economical method was assigned to each plant depending

upon its estimated annual FBC waste generation rate.

The cost estimate summed costs in five categories: initial capital costs, recurring capital costs,

annual operating and maintenance costs, closure costs, and annual post-closure costs. The specific

components included in each cost category were the same as those in the analysis for coal-fired utility

comanaged waste (see Section 3.7.1). As in that analysis, the cost estimate for FBC facilities employed

three different landfill sizes. Table 5-13 identifies the design features for FBC landfills.

For FBC wastes, the cost estimate was based on alternative management for the quantity of FBC

wastes currently disposed in landfills that do not meet the requirements described in Section 5.6. EPA

also estimated the additional, incremental cost if the large quantity of FBC waste currently minefilled and

Parameter Landfill

Sizes small

(tons/year) medium

large

5,000

50,000

500,000

Depth

(feet) small

medium

large

small

medium

large

Pile design

1.0

1.0

3.0

Combination fill design

17.1

51.8

75.1

Height

(feet) small

medium

large

small

medium

large

Pile design

25.0

25.0

84.9

Combination fill design

21.4

20.3

74.6

Area

(acres) small

medium

large

small

medium

large

Pile design

7.3

106.6

207.2

Combination fill design

4.6

24.5

111.8

Note: Landfill designs considered include a “pile design” constructed primarily above grade and a “combination fill design” constructed both

above and below grade.

Table 5-13. Design Parameters Assumed for Small, Medium, and Large FBC Landfills
Report to Congress on Wastes from the Combustion of Fossil Fuels

5-30 March 1999

used in agriculture also were subject to the alternative management practices. This latter cost would

reflect a ban on minefilling and agricultural use. This is discussed below.

As in the analysis for coal-fired utility comanaged waste, a single cost equation was developed,

annualized costs were estimated as a function of facility-specific waste generation, and total industry

costs were derived by summing the facility-specific estimates. Costs and economic impacts are set forth

in the following three sections: incremental compliance cost, compliance cost impact on facilities as a

function of size, and industry impact.

Incremental compliance costs are the costs of risk mitigation practices over and above the cost of

current management practices. Using incremental compliance costs as an indicator of potential cost

burden, the analysis examined impacts on individual facilities as a function of size. As in Section 3.7,

this was performed using pro forma financial statements for three representative plant sizes. As for the

conventional coal-fired utility sector, the use of econometric models for the industry impact evaluation

was considered and rejected because of the uncertainty surrounding ongoing deregulation of the electric

power industry and the diversity of industrial and institutional sectors potentially affected. The industrylevel analysis, therefore, focuses on the number of affected facilities and the magnitude of incremental

compliance costs relative to the value of electricity sales.

5.7.2 Incremental Compliance Cost

EPA’s estimate of the incremental compliance cost for FBC facilities is approximately $32

million per year. If the quantities of FBC waste currently used in minefill and agricultural applications

were subject instead to the risk mitigation alternative of Section 5.6, the additional incremental

compliance cost would be an estimated $52 million per year (for a total of some $84 million per year). 

As discussed above, this latter cost would reflect a ban on minefilling and agricultural use. Variations on

this approach, as noted, could substantially reduce the total incremental compliance cost with

approximately $32 million being the floor. A limit on the arsenic concentration in FBC wastes destined

for agricultural use, for example, would affect a smaller quantity of waste than a ban on agricultural use. 

Although the quantity of waste in agricultural use is small relative to quantities used in minefilling, this

variation would still result in a decrease in compliance costs.

Costs, again, are incremental (above current costs). Annual costs were discounted at 7 percent to

1998 dollars, with no inflation built into out-year estimates. Also, it was presumed that compliance

would be required immediately, and that amortization would take place over 40 years. As with the utility

and non-utility sectors, delayed compliance, were this to be considered, would result in much reduced

costs.

5.7.3 Compliance Cost Impact on Facilities as a Function of Size

EPA believes that the ability of industry to pass through cost increases will be limited because

only a small share of plants within the affected industries operate FBC units. Competition from

unaffected facilities would restrict the ability of facilities facing incremental compliance costs to increase

prices. Therefore, this analysis includes no analytical consideration of price effects.

Also, the analysis below excludes costs for quantities currently used in mining and agriculture.

The minefilling issue is discussed in detail in Section 3. If minefilling were to be banned, the impacts

shown below would increase roughly in proportion to the compliance costs given in Section 5.7.2.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 5-31

As discussed previously in this chapter, about half of the 84 FBC facilities are operated/owned

by entities in the electric service industry (i.e., independent power producers and utilities). The

remaining FBC waste generating facilities include about 7 operated by universities or colleges, about 15

operated by large businesses such as Archer Daniels Midland, General Motors, Iowa Beef Processors,

Exxon, and Fort Howard Paper, and the balance—about 20—operated by various small businesses or

unknown operators. Thus, EPA addressed the electric power segment of FBC facilities separately from

the more broad-based industrial/institutional FBC facilities.

Electric Power Sector

Based on the incremental compliance cost estimate, 42 FBC waste generators in the electric

power industry would incur incremental compliance costs of about $15.2 million per year, or about

$361,000 per facility. Economic impacts at the plant level will depend on several major factors,

including quantity of fuel used, quality of fuel, profitability, and production technology. To assess these

impacts across the range of plants, EPA estimated financial data for model plants representing three size

ranges: large (generating capacity of 100 MW), medium (generating capacity of 50 MW), and small

(generating capacity of 30 MW). These model facilities are representative of independent power

producers. Table 5-14 compares incremental compliance costs to revenues and net income for these

three model plants.

The incremental compliance cost for FBC waste should not impact the financial viability of FBC

facilities in the electric service sector. This appears true even for plants transitioning from the worst case

unlined landfill to a composite-lined landfill. For example, a large FBC independent power plant with

100 MW of generating capacity is estimated to comply for about $520,000 per year (or about $13 per ton

of waste). Based on typical annual revenues and cost, compliance costs would increase overall costs by

1.4 percent of revenues. Without any price adjustments, net income before taxes for a typical FBC

facility would be reduced from about 10 percent to 8.6 percent and remain at nearly $3.3 million per

year. EPA recognizes that such profit margin reductions may be considered significant by the individual

firm.

Financial impacts on a medium-sized FBC independent power plant suggest it should also remain

financially viable. Costs would increase by about 1.5 percent of revenues, with profitability (before tax)

at 6.5 percent of revenue and net income levels after compliance of more than $1.2 million per year. 

(Annual incremental compliance costs are estimated at $14 per ton of FBC waste, or about $280,000 per

Large FBC Independent

Power Producer

Medium FBC

Independent Power

Producer

Small FBC Independent

Power Producer

$1,000’s

Percent of

Revenues $1,000’s

Percent of

Revenues $1,000’s

Percent of

Revenues

Revenues from Electricity 37,840 100% 18,900 100% 11,400 100%

Baseline Before Tax Net Income 3,780 10.0% 1,510 8.0% 790 7.0%

Expected Incremental Compliance

Costs (replace unlined management

unit with composite-lined unit)

520 1.4% 280 1.5% 190 1.7%

Expected Post-Compliance Net Income 3,260 8.6% 1,230 6.5% 600 5.3%

Table 5-14. Plant-Level Impact of Incremental Compliance Costs
Report to Congress on Wastes from the Combustion of Fossil Fuels

5-32 March 1999

year.) Small FBC independent power plants would incur slightly higher impacts at about 1.7 percent of

revenues.

Industrial/Institutional Sectors

As for conventional non-utility combustors, industrial and institutional FBC facilities include a

wide variety of facilities that generate electricity or energy for primarily internal use. The vast majority

of firms in these sectors, however, do not operate FBC units or burn coal at all. Because of the smaller

number of affected FBC facilities, FBC facilities represent an even smaller share of the corresponding

industry sectors than do conventional non-utility combustors. As for conventional non-utilities, fossil

fuel use and costs are a relatively small part of production inputs and costs. Therefore, the conclusions

presented in the paragraph above generally also are applicable to industrial and institutional FBC

facilities.

5.7.4 Industry Impacts

This analysis addresses the overall industry and the general implications for market supply of

selected industries.

Approximately half of all FBC facilities, as noted, are in the electric generating sector. 

Department of Energy data show that independent power producers as a group generated 61.4 billion

kWh from coal fired generating capacity. Assuming this output is valued at $0.07 per kWh, the

equivalent market value of this output would be $4.3 billion. Assuming all FBC electric power facilities

fall in this special power generating segment, incremental compliance costs would equal about 0.3

percent of the segment’s general market value, as shown in Table 5-15.

Institutional/industrial FBC facilities include a broad variety of industry sectors similar to that

reflected in the conventional non-utility combustion population. Because of their small numbers, FBC

facilities account for an even smaller share of these industry sectors. Thus, the industry-wide economic

impacts from industrial and institutional FBC facilities are expected to be similar to or less significant

than those presented in Section 4.7.4.

5.8 FINDINGS AND RECOMMENDATIONS

5.8.1 Introduction

Based on the information collected for this Report to Congress, this section presents a summary

of the Agency’s main findings presented under headings that parallel the organization of this chapter. It

then presents the Agency’s tentative conclusions concerning the disposal and beneficial uses of FBC

wastes as discussed in this chapter.

Sector

Industry Sales

($ billion/yr)

Incremental Compliance

Cost ($ billion/yr)

Compliance Cost as a

Percentage of Sales

FBC Independent Power $4.3 $0.015 0.3%

FBC Industrial/Institutional Not estimated * $0.017 *

* Given the similar variety of sectors and smaller number of facilities, impacts are expected to be similar to or less significant

than those for conventional non-utilities (see Section 4.7.4).

Table 5-15. Industry-Level Economic Impacts (FBC Wastes)
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 5-33

5.8.2 Findings

Sector Profile

• There are about 84 facilities with a total of 123 FBC boilers in the United States. The

facilities are distributed throughout the United States, but Pennsylvania and California

together have 29 facilities.

• Commercial-scale FBC technology is relatively new in the United States. Its use has

increased during the past 20 years, and the trend appears to be continuing.

• The advantages of FBC over conventional processes include flexibility in fuel grades,

combustion efficiency, and emissions control.

Waste Generation and Characteristics

• Nearly 10-million tons of combustion wastes are generated annually by FBC units. The

wastes comprise mostly fly ash and bottom ash (called bed ash).

• These wastes contain relatively high residual levels of lime (which is introduced with fuel to

control sulfur emissions) and often exhibit self-cementing properties.

• The types of low-volume wastes generated by FBC operations are similar to those generated

at facilities that use conventional boiler technologies, such as pulverized coal boilers

commonly used at utility facilities. Based on limited available data, the characteristics of

FBC low-volume wastes are also similar to the counterpart utility low volume wastes at

facilities that employ conventional boiler technologies.

• The constituents of concern in the combustion wastes are trace metal elements, in particular

the eight RCRA metals. No organic constituents and no radionuclides were identified at

potential levels of concern in these wastes.

• FBC wastes seldom test characteristically hazardous. Only one constituent, mercury, in one

sample at one facility (out of 24 facilities for which data are available) exceeded the

regulatory level.

• Based on limited data, none of the combustion wastes appears to be characteristically

corrosive, reactive, or ignitable.

Waste Management Practices

• The predominant FBC waste disposal practice is placement in landfills. The typical landfill

is about 40 acres in size. Surface impoundments are rarely used to manage these wastes. 

These wastes are monofilled and to a lesser extent are comanaged with low-volume wastes

and/or other industrial wastes.

• The current trend for environmental controls at FBC waste management units is toward use

of liners, cover, leachate collection, dust suppression, and surface and ground-water

monitoring.
Report to Congress on Wastes from the Combustion of Fossil Fuels

5-34 March 1999

• A significant portion of FBC wastes is reused. About 75 percent of the wastes are currently

managed through beneficial uses. The largest single beneficial use is in minefill, including

mine reclamation, which accounts for about 60 percent of the generated wastes. Other

beneficial uses include waste stabilization (6 percent), construction fill (5 percent), and

agricultural use (1 percent).

Potential Risks and Damage Cases

• EPA conducted a risk assessment that found a lack of potential human health risk for

virtually all waste constituents. Arsenic was the one constituent for which the Agency

identified potential human health risks via the ground-water pathway for FBC wastes that

are managed in unlined landfills. The identified risk is based on high-end risk scenarios in

EPA’s risk modeling analysis for human ingestion of well water influenced by releases from

the waste management unit. The time to reach significant risk in ground water is estimated

to be in excess of 3,000 years.

• EPA conducted a risk assessment that found a lack of potential human health risk for

virtually all waste constituents. Arsenic was the one constituent for which the Agency

identified potential human health risks via non-ground-water pathways where these wastes

are used as soil amendments for agricultural purposes. The identified risk is based on highend risk scenarios in EPA’s risk modeling analysis, for human ingestion exposure routes.

• The Agency did not perform a risk analysis for management in impoundments because they

are rarely used and the known impoundments are lined; however, the Agency believes that

there should be no significant ground-water risks posed by lined waste management units.

• The Agency identified no ecological risks associated with management of FBC wastes.

• The Agency identified no documented damage cases associated with the management of

FBC wastes.

• Some natural arsenic levels in U.S. soils have the potential to pose higher risks than the risk

identified with the level of arsenic contributed by these wastes for non-ground-water

pathways.

Existing Regulatory Controls, State, and Federal Requirements

• The FBC sector has a significant level of installed environmental controls for these wastes. 

Most of the active FBC waste landfills are subject to regulatory permits and ground-water

monitoring requirements; nearly all incorporate dust suppression and surface runon/runoff

controls. Nearly half are lined and have leachate collection systems and covers.

• States increasingly have begun to impose controls on FBC waste management units. In

addition to regulatory permit programs, the majority of states now have the authority to

require siting controls, liners, leachate collection systems, ground-water monitoring, closure

controls, daily or other operational cover, and fugitive dust controls for management of

these wastes.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 5-35

Potential Costs and Impacts of Regulation

• The Agency estimates that the total annual incremental compliance costs for mitigation of

the potential arsenic risks identified in this study would be approximately $32 million

(1998$). These costs represent replacement of existing unlined management units with

lined management units, and implementing ground-water monitoring and leachate collection

and treatment. These measures do not represent implementation of full Subtitle C

requirements, but rather modifications of such requirements that could potentially be

adopted under Section 3004(x) of RCRA.

• If these wastes were to be regulated under full Subtitle C, virtually all existing facilities

would be required to invest substantial funds and resources to modify existing management

practices. The total annual cost of full Subtitle C requirements would considerably exceed

the $32 million (1998 $) estimate above.

• If beneficial uses of theses wastes were subject to Subtitle C requirements, possibly all

beneficial use practices and markets would cease. If so, the impact on waste management

practices would be substantial, considering that about 75 percent of FBC wastes are reused.

5.8.3 Recommendations

Following are the Agency’s recommendations for the wastes covered in this chapter. The

recommendations are based on EPA’s analysis of the eight Congressionally mandated study factors

(Section 1.2). These conclusions are subject to change based on continuing information collection,

continuing consultations with other government agencies and the Congress, and comments and new

information submitted to EPA during the comment period and any public hearings on this report. The

final Agency decision on the appropriate regulatory status for these wastes will be issued after receipt

and consideration of comments as part of the Regulatory Determination, which will be issued within

6 months.

1. The Agency has tentatively concluded that disposal of these wastes should remain exempt from

RCRA Subtitle C.

As with the utility and non-utility coal combustion wastes addressed in Chapters 3 and 4, the

Agency has tentatively concluded that FBC wastes, including wastes from petroleum coke combustion

and from other fuels that are co-fired with coal, and also low-volume wastes where they are managed

with the combustion wastes, generally present a low inherent toxicity, are seldom characteristically

hazardous, and generally do not present a risk to human health and the environment. State programs

increasingly require more sophisticated environmental controls at these types of facilities. For example,

most all of the FBC landfills are subject to regulatory permits and ground-water monitoring

requirements; nearly all implement dust suppression and runon/runoff controls. No documented damage

cases were identified and no significant ecological risks were identified. These types of facilities are

typically located in areas of low population and thus present infrequent opportunity for human exposure. 

Although arsenic was identified from EPA modeling to pose a potential risk at unlined landfills, there

were no documented problem or damage cases identified with arsenic as a constituent of concern. The

predominant practice is to manage these wastes in landfills, with a much lower frequency of using

impoundments. Nearly half of the landfills are lined and more than half have leachate collection systems

and covers. Overall, the Agency believes that regulation under Subtitle C authority is not warranted

when these wastes are disposed. For the issues discussed below involving agricultural use and

management of these wastes in mines (minefill), the Agency is still considering whether some regulation

under RCRA Subtitle C may be warranted.
Report to Congress on Wastes from the Combustion of Fossil Fuels

5-36 March 1999

2. The Agency has tentatively concluded that most beneficial uses of these wastes should remain

exempt from Subtitle C.

No significant risks to human health and the environment were identified or believed to exist for

any beneficial uses of these wastes, with the possible exception of minefill and agricultural use as

discussed below. This is based on one or more of the following reasons for each use or resulting product:

absence of identifiable damage cases, fixation of the waste in finished products which immobilizes the

material, and/or low probability of human exposure to the material.

3. The Agency is tentatively considering the option of subjecting practices involving the use of these

wastes for agricultural purposes (i.e., as a soil nutrient supplement or other amendment) to some

form of regulation under Subtitle C.

As mentioned above, the Agency identified potential risk from exposure to arsenic in these

wastes when they are used for agricultural purposes. The risks identified with this practice may be of

sufficient concern to consider whether some form of control under Subtitle C is appropriate, given the

increasing trend for use of these materials as agricultural amendments. An example of such controls

could include regulation of the content of these materials such that arsenic concentrations could be no

higher than that found in agricultural lime. On the other hand, imposition of controls under Subtitle C

may not be warranted if sufficient protection may be afforded by the Agency engaging the industry to

establish voluntary controls on this practice. An example of such voluntary controls could consist of an

agreement to limit the level of arsenic in these materials. The Agency solicits comment on its tentative

conclusion and specific approaches that could be pursued to address the concern..

A significant amount of FBC waste, about 60 percent, is used for minefill. Of this amount, large

quantities are used specifically for reclamation of old surface coal mine working. EPA recognizes that

mine reclamation practices with the highly alkaline FBC wastes can have some significant, positive

environmental benefits. For example, the FBC wastes contribute to neutralizing acid mine drainage at

the old mine workings, and when mine reclamation activities are completed, new productive uses may

be made of the land. The Agency also realizes that there are a number of well-managed state mine

reclamation programs that oversee the application of FBC wastes. RCRA, however, does require the

Agency to review the management of these wastes. As discussed in Chapter 3's recommendations, the

potential for risks associated with this practice may be of sufficient concern to consider whether some

form of control under Subtitle C is appropriate, given the increasing trend for use of these materials as

minefill. The Agency, however, currently lacks sufficient information with which to adequately assess

risk associated with this practice and therefore to decide whether this practice should remain exempt

from Subtitle C. The Agency solicits comment on whether there are some minefill practices that are

universally poor and warrant specific attention. For example, the Agency has found several situations in

which cement kiln dust placed in direct contact with the ground-water table has created problems. EPA

also seeks comment on whether coal or other fossil fuel combustion wastes used as minefill and placed in

direct contact with the water table would create environmental concerns, and if that specific practice

should be regulated. The Agency’s focus is on potential risks that may be posed via the ground-water

and surface pathways from use of these wastes as minefill.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-1

6.0 OIL COMBUSTION WASTES

Oil combustion is used by utilities to generate electricity and by non-utilities to generate

electricity, heat, or steam for a variety of operations. The analysis of oil-fired combustion processes and

wastes in this report is based primarily on electric utility data. EPA has included available

characterization information and analysis of non-utility operations in this study. Only a portion of the

oil combustion facility population generates significant amounts of combustion waste. This portion

comprises steam electric plants that burn residual fuel oil and is described further in Section 6.1.

SECTOR OVERVIEW

Petroleum products account for a substantial portion of the energy consumed in the United

States—nearly 40 percent in 1997 according to the Energy Information Administration (EIA, 1998a). 

Most of this, however, is in the form of motor gasoline and other fuels used in the transportation sector. 

Only a fraction of U.S. petroleum consumption is by utilities and non-utility combustors, and only part of

this is residual fuel oil, which is the only form likely to generate significant quantities of combustion

waste (EIA, 1998a).

In the utility sector, the total amount of electricity generated by oil is small relative to the total

generation of electricity. Electricity from oil combustion is less than 3 percent of a total that includes

hydroelectric and nuclear as well as fossil fuel combustion (FFC) (EIA, 1998a). As discussed in Chapter

2, oil combustors represent a much smaller portion of utility FFC capacity than coal combustors. Oil

combustion is, however, the dominant utility power source for certain regions of the United States

(e.g., Florida, Hawaii, the Northeast) and the territories (Puerto Rico, the Virgin Islands, and Guam).

Additionally, oil has a history of use in support of utilities that burn coal for their baseload but

use oil units to meet peak needs. These peakload units are used to supply electricity during periods of

high electricity demand. The predominant characteristic of the peaking unit is the ability to startup and

shutdown relatively rapidly, a characteristic that coal-fired units are unable to provide, but to which oil

and gas are well-suited. Oil also may be used in coal-fired boilers for startup and flame stabilization. 

This practice, however, was covered by the 1993 Regulatory Detemrination.

As of December 1994, there were 177 utility facilities in the United States and its territories that

combusted oil (EEI, 1994). Some of these facilities burned only oil, some operated both oil-fired boilers

and boilers fired by other fossil fuels, and other facilities used oil as alternate fuel in units that primarily

burned other fossil fuels. Figure 6-1 shows the geographic distribution of these facilities. Only 40 of

these facilities are baseload oil-fired generators. Because of this, the location of facilities shown in the

figure does not closely mirror the concentration of oil-fired utility capacity in the United States.

In fact, the concentration of oil-fired utility capacity corresponds more closely to the presence of

large, oil-fired baseload units in certain regions of the country. Table 6-1 shows the location of these

baseload units. It is these baseload units that are likely to generate significant quantities of oil

combustion waste on a regular basis. Thus, while utility oil combustion waste has the potential to be

generated in a number of locations, generation and management of significant quantities of this waste

takes place primarily in the Northeast, mid-Atlantic, and Florida.
Report to Congress on Wastes from the Combustion of Fossil Fuels

1

 As discussed in Chapter 4, because the 1990 National Interim Emissions Inventory captures only the

largest non-utilities, it likely underestimates the total number of non-utility fossil fuel combustors. The small

facilities that are not included in the database, however, are unlikely to generate significant quantities of waste. 

6-2 March 1999

Figure 6-1. Number of Utility Power Plants Burning Oil (in whole or in part) by State

Oil-fired non-utilities represent a much larger number of facilities than do utilities. The 1990

U.S. EPA National Interim Emissions Inventory (EPA, 1990) includes more than 2,000 facilities with oilfired units.1

 These facilities, however, account for only about 25 percent more generating capacity than

Location Number of Facilities

Florida 11

Islands (GU, HI, PR, VI) 13

New England (MA, ME, CT) 6

Mid-Atlantic (NY, NJ, MD, DE) 10

Total 40

Source: EEI, 1994

Table 6-1. Locations of Utilities with Oil-Fired Baseload Units
Report to Congress on Wastes from the Combustion of Fossil Fuels

These facilities burn less fuel because of their capacity and are less likely to operate air pollution control devices. 

March 1999 6-3

oil-fired utilities. Equivalent electrical generating capacity is approximately 54,000 megawatts (MW) for

oil-fired non-utilities (EPA, 1990) compared to 43,000 MW for oil-fired utilities (EEI, 1994). Unlike

utilities, oil-fired non-utilities are distributed throughout the United States and in a variety of settings

(urban to rural). As discussed in Section 6.1, the fuel and air pollution control technology characteristics

of non-utilities indicate they are a less significant source of oil combustion waste than are utilities.

Despite its significance within certain niches (i.e., regional power generation, peakload units,

non-utility use), the quantity of oil used to generate power is decreasing. The last 20 years have seen a

significant drop in the use of fuel oil by utilities, from over 600-million barrels (25.2-billion gallons) in

1978 to only 86-million barrels (3.6-billion gallons) in 1995 with the steepest decline between 1978 to

1985 (EPRI, 1998a). This trend corresponds to a decline in construction of new oil-fired utility plants. 

While over 100 units were constructed during the 1960s and 1970s, the Electric Power Research Institute

(EPRI) reports that only three new units have been brought on line since 1980. EPRI additionally reports

that many oil units have been, or are being, converted to burn both natural gas and oil to provide

additional flexibility in economical fuel choice (EPRI, 1998a).

As discussed in Chapter 2, the declining trend for oil combustion is expected to continue during

the next two decades. Oil-fired utility steam plants are expected to be replaced by combustion turbine

technologies. As a result, while industrial combustion of residual oil is expected to grow modestly, this

growth will be more than counter balanced by a dramatic reduction for oil-fired utilities (EIA, 1998a).

6.1 WASTE GENERATION

The generation of large-volume wastes from oil combustion depends on combustion technologies

(Section 6.1.1), air pollution control technologies (Section 6.1.2), and fuel type (Section 6.1.3). Oil

combustion wastes (OCWs) consist primarily of the following:

• Fly ash. The fine particles entrained in the flue gas leaving the boiler. If present, a

particulate control system will capture some part of these particles. Additionally, particles

may adhere to equipment through which the flue gas is routed (e.g., the air preheater) or be

knocked down in other units (e.g., the economizer). These particles are removed during

equipment cleanout and are often described as washwater solids. Washwater solids usually

are similar to, and managed along with, fly ash captured in the air pollution control system.

• Bottom ash. The heavier fraction of the waste stream that collects in the bottom of the

boiler and is removed either manually or by gravity. Bottom ash includes a small amount of

boiler slag that adheres to the boiler surfaces. The slag fraction must be removed by

chiseling, jackhammering, sootblowing, or sandblasting.

In addition to the large-volume combustion wastes, oil combustors generate certain low-volume

wastes similar to those generated by coal combustors. These low-volume wastes are the result of

supporting processes (see Section 6.1.4) that are ancillary to, but a necessary part of, the combustion and

power generation processes. These wastes may include the following:

• Boiler blowdown. Waste that is continuously or intermittently removed from boilers that

recirculate water.
Report to Congress on Wastes from the Combustion of Fossil Fuels

2

 According to EPRI, a conservative “high” estimate would be about 70,000 tons, assuming most waste is

handled wet and then dewatered to 60 percent water content. 

6-4 March 1999

• Cooling tower blowdown and sludge. Wastes removed periodically from closed-loop

cooling systems.

• Water treatment sludge. Wastes resulting from treatment of makeup water for the steam

cycle or for noncontact cooling.

• Regeneration waste streams. Wastes resulting from periodic cleaning of ion exchange

beds used to remove mineral salts from boiler makeup water.

• Air heater and precipitator washwater. Wastes resulting from the periodic cleaning of

the outside (fireside) of heat exchanging surfaces.

• Boiler chemical cleaning waste. Wastes resulting from the periodic cleaning of the inside

(waterside) of boiler tubes with chemical solutions.

• Floor and yard drains and sumps. Wastewaters collected by drains and sumps and

include miscellaneous drainage from the plant site, including precipitation runoff, piping

and equipment leakage, and washwater.

• Laboratory wastes. Wastes generated in small quantities during routine analysis of fuel,

intake water, wastes, and other samples at a plant site.

Finally, at most oil-fired utilities, fly ash (and sometimes bottom ash) is transported wet to solids

settling basins (SSBs) (see Section 6.3), often using equipment washwater. Often, low-volume wastes

also are managed in these basins. The periodic dredging of solids from these basins results in the

generation of a waste stream known as SSB solids. SSB solids are composed of fly ash and solids settled

from washwater and other low-volume wastes.

Comprehensive industry-wide data on the generation of OCWs are not available. Estimates by

EPRI are available for the utility sector. Extrapolation has been made based on these estimates and

relative fuel usage in order to also characterize waste generation in the non-utility sector.

For the utility sector, EPRI has estimated that between 15,000 and 90,000 tons of oil ash are

“generated” annually. As discussed in Section 6.1.2, only a portion of the fly ash generated is collected. 

An estimated total of 23,000 tons of OCW were collected by utility oil combustors in 1995 (EPRI,

1998a).2

 This quantitative estimate is less than one one-thousandth of the quantity of large-volume utility

coal combustion wastes generated in 1997 (105-million tons).

For oil-fired non-utilities, less total ash is expected to be generated because of air pollution

control technologies and fuel characteristics (see Sections 6.1.2 and 6.1.3). EPA estimates that 5,500

tons of ash should be generated annually by non-utility oil combustion operations. While non-utilities

and utilities burn comparable amounts of residual oil, the limited application of air pollution control

devices at non-utilities results in significantly lower aggregate ash generation. Using EPA’s estimate in

the 1990 U.S. EPA National Interim Emission Inventory (EPA, 1990) (5,245 oil-fired boiler units in the

non-utility sector), the average non-utility OCW generation rate would be just over 1 ton per unit per

year.
Report to Congress on Wastes from the Combustion of Fossil Fuels

3

Oil-fired CT ash, however, is covered by this study.

March 1999 6-5

The portion of OCW generated that represents bottom ash versus fly ash varies greatly depending

on fuel type and combustion technology. In some cases, the quantity of bottom ash generated is so low

that it is collected infrequently. EPRI, in a study of 17 utility oil combustors, found the amount of

bottom ash collected to be between 6 percent and 25 percent of the amount of fly ash (EPRI, 1998a). A

general rule of thumb in the industry is that 70 percent of the ash generated (emitted and collected)

should be fly ash versus 30 percent bottom ash (Stultz and Kitto, 1992).

Little information is available on the rates at which low-volume wastes are generated at oil-fired

utilities; however, EPRI reports that oil-fired units typically generate boiler fireside washwater at a rate

of 7 gallons per day per MW. EPRI estimates air preheater washwater generation to be at a rate of 17.6

gallons per day per MW, or 2.5-million gallons per year for a 400-MW baseload unit (EPRI, 1998a).

6.1.1 Combustion Technology

Two technologies are currently used for oil combustion: steam electric boilers and combustion

turbines (CT). Combustion turbine operations use exhaust from oil combustion directly to drive turbines

that produce electricity. Because the exhaust must be free of particulates (e.g., ash) that would damage

the turbine, natural gas or high-grade fuel oil (i.e., distillate oil) is typically burned. Thus, ash generation

from this technology is reportedly low. For example, one CT facility discussed in the EPRI 1998 Oil

Combustion By-Products Report generated about one-half ton of bottom ash per year (EPRI, 1998a). 

Because CTs produce little ash, the focus of this discussion will be on steam electric boilers.3

Oil-fired steam electric units are conceptually similar to coal combustion units: they combust oil

in a boiler to produce steam, which is in turn used to provide heat or steam or drive turbines that generate

electricity. Box 6-1 provides a general overview of this technology. Oil-fired steam electric boilers,

especially in the utility sector, burn a relatively low grade and, therefore, less expensive oil (i.e., residual

oil, typically Number 6 fuel oil). As discussed in Section 6.1.3, the combustion of this type of fuel

results in the generation of significant amounts of OCW.

In steam electric generation, atomized oil and preheated air are combined in a boiler and combusted. Oil for

combustion is atomized to very small droplets, producing high surface to volume ratios. Atomization may be

accomplished mechanically, with the pressure of the fuel itself providing the energy for atomization, or with the

assistance of pressurized steam or compressed air. The residual oils typically used for steam generation require

heating to reduce their viscosity prior to atomization. The atomized fuel is injected into the furnace in a fine

mist through specially designed burners.

The burners disperse the fuel stream into a stream of preheated combustion air. In a typical oil combustion unit,

air entering the boiler is preheated in a heat exchange unit (i.e., an air preheater). These are typically rotating,

basket-shaped devices that pass alternately through the flue gas (i.e., hot gas leaving the boiler) and combustion

air streams (i.e., unheated air entering the boiler). Heat recovered from the flue gas is transferred to the

incoming air to increase boiler efficiency. Air preheaters collect ash from the flue gas and must periodically be

cleaned to maintain maximum efficiency.

Sources: Stultz and Kitto, 1992; EPRI, 1998a

Box 6-1. Oil-Fired Steam Electric Boiler Technology
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-6 March 1999

Figure 6-2. Capacity of Utility Oil-Fired and Coal-Fired Boilers

Oil-fired utility boilers are smaller on average than coal-fired boilers. This is because the oilfired utility population contains a higher proportion of small units, as shown in Figure 6-2. Nearly all of

the small units shown in Figure 6-2, however, are peaking, cycling, or standby units. Baseload oil-fired

boilers (average 269 MW) are similar in size to coal-fired utility boilers (average 256 MW). Based on

the average size reported in the 1990 U.S. EPA National Interim Emissions Inventory (just over 10 MW

equivalent), oil-fired non-utility boilers are much smaller than utility boilers. Because of their smaller

size, oil-fired non-utility boilers generate less ash on a per-boiler basis and likely are subject to less

frequent cleanout.

6.1.2 Air Pollution Control Technologies

Because of the low sulfur content of the fuel, oil combustion units typically do not require flue

gas desulfurization (FGD) technology; therefore, oil combustion does not generate FGD waste.

Although oil-fired utilities are subject to particulate matter restrictions similar to those for coalfired utilities, particulate controls are utilized much less frequently at oil-fired facilities than at coal-fired

plants. As shown in Figure 6-3, the majority (nearly two-thirds) of utility generating units that combust

oil either as primary or as alternate fuel do not utilize particulate control equipment. This is due to three

factors:

1. Because of the relatively low ash content of the fuel (see Section 6.1.3), the rate of emission

may be low enough to not require control.

2. The physical size of a large fraction of oil fly ash (see Section 6.2) is below that currently

regulated under the Clean Air Act (CAA).

3. The size (i.e., MW capacity) of many of the facilities (see Section 6.1.1) is such that they

fall below thresholds for regulation under the CAA (see Section 6.5).
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-7

Figure 6-3. Particulate Control Technologies at Oil-Fired Utilities

While particulate control use for oil-fired units overall is low, the larger utility oil combustion

facilities are more likely to incorporate controls (see Table 6-2). As size decreases, oil-fired utilities are

less likely to apply controls. Because of their smaller size distribution, oil-fired non-utilities are expected

to be even less likely than utilities to apply controls. This, in turn, would mean less fly ash is collected

for management in the non-utility sector.

The same technologies are used to control particulates at oil-fired utilities as at coal-fired

utilities. Chapter 3 provides general descriptions of these technologies. When applied at oil-fired units,

the collection efficiencies of these technologies varies due to fly ash characteristics and combustion

conditions, as shown in Table 6-3. Even at its most effective, oil ash capture is less efficient than coal

ash capture. The lower collection efficiency means less fly ash to be managed by oil combustors.

6.1.3 Fuel Usage

Like ash from coal combustion, oil ash results from uncombusted materials in the fuel; therefore,

OCW generation is affected by the ash content of the fuel. The ash content of fuel oils varies depending 

Utility Units* with Capacity

Percent of Total Units

within Size Category

Percent of Total in Size Category

with Particulate Control

Over 500 MW 14% 39%

Between 101 and 500 MW 42% 39%

Under 100 MW 44% 29%

* 354 units at 177 facilities burned oil in whole or in part in 1994

Source: EEI, 1994

Table 6-2. Particulate Control by Size of Utility Oil Combustion Unit
Report to Congress on Wastes from the Combustion of Fossil Fuels

4

EPA’s 1993 Regulatory Determination covered coal combustion wastes where oil is used as a start-up fuel

and for flame conditioning.

6-8 March 1999

on type. Fuel oils are classified according to the point of production in the distillation process, which

separates crude oil into various oil fractions according to vapor pressure. For purposes of this discussion,

the significant fractions resulting from distillation are distillate oils (including No. 1, No. 2, and No. 4

fuel oils) and residual oils (including No. 5 and No. 6 fuel oil and Bunker C oil). Because oil-fired

boilers provide a wide range of fuel flexibility, the same burner technology can be used to combust a

variety of fuel oil grades.

As shown in Table 6-4, all types of fuel oil have a much lower ash content than coal. This is a

significant factor contributing to the much lower generation of waste by oil combustors. Furthermore, of

the types of fuel oil, only residual oil has a significant ash content. Distillate oil generates little or no

ash.

As presented in Figure 6-4, most of the oil burned by electric utilities is residual fuel oil. At

utilities, distillate oil, which is more costly than residual oil, is used mainly for boiler startup prior to

combusting residual oil and coal.4

 The less expensive residual oils, particularly No. 6, are the primary

Fuel Control Conditions

Removal

Efficiencies Comments

Oil Mechanical Normal operations 30% Due to the small particle size of oil fired systems;

particularly in units with reburn systems

Unusual operating conditions

(upsets, dirty oil, cleanouts)

up to 85% Capturing larger particles associated with unusual

conditions

Electrostatic

Precipitators

(ESP)

Older combustion units 40–60% Less efficient; carbon factor*

Newer combustion units 70–90% Smaller particle size and higher carbon content*

than coal ash

Coal Mechanical Normal operations up to 90% Most efficient for largest particles

Electrostatic

Precipitators

Normal operations 99% Large particles, lower carbon content

*A higher carbon content results in a lower resistivity of fly ash and, therefore, less effective collection by the electric field in an ESP.

Sources: EPRI, 1998a; Stultz and Kitto, 1992; EPA, 1998c; Elliott, 1989; DOE, 1993

Table 6-3. Relative Removal Efficiencies of Particulate Control Technologies

Type of Fossil Fuel Percent of Ash by Weight

Coal: Anthracite and Lignite

Bituminous

Average: 1975

1996

4 to 19%

3 to 32%

13.5%

9.22%

Oil: Residual Oil (No. 6 fuel oil)

Distillate Oil (No. 2 fuel oil)

less than 1% (0.009 to 0.16)

negligible

Sources: CIBO, 1997c; DOE, 1993; EIA, 1996f; EPRI, 1998a

Table 6-4. Relative Ash Content by Weight
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-9

Figure 6-4. Oil Consumption by Utilities and Non-Utilities

 Source: EIA, 1997f

fuels for oil-fired utilities (EPRI, 1998a). Non-utility fuel usage, in contrast, favors the distillate oils. As

a result, despite the greater total oil-fired capacity of non-utilities, utilities burn more residual oil and,

thus, generate more waste. The total annual amount of residual oil used by utilities is about 800-million

gallons more (about 26 percent) than that used by non-utilities.

Fuel characteristics affect waste generation in other, less direct ways as well. For example,

corresponding to its low ash content, fuel oil contains a large carbon content. Because of this, significant

amounts of carbon may remain unburned, contributing to the waste volume. Certain plants reinject fly

ash back into the boiler to increase the burn efficiency, lower the waste carbon, and reduce the net

quantity of waste generated.

In addition to the inherent amount of non-carbon material in the original fuel, additives to the

fuel account for some of the waste residual. EPRI reports that fuel additives are assumed to add a factor

of two to the inorganic ash fraction. The most common additives are magnesium-based compounds

added to control slagging and corrosion caused primarily by vanadium in the oil; the amount added

typically varies in proportion to the amount of vanadium present.

In addition to residual and distillate fuel oils, some oil-fired utilities in the United States have

considered burning a new type of fuel, called Orimulsion. Orimulsion is the trademark name of a fuel

produced in Venezuela that is a mixture of water (30 percent) and bitumen (70 percent), a heavy

hydrocarbon. Orimulsion performs similarly to No. 6 fuel oil and can be burned using existing oil-fired

boilers. Worldwide, only a few facilities, primarily in Japan and Canada, have begun firing Orimulsion

on a commercial basis. No facilities in the United States currently burn Orimulsion. Therefore, this

chapter focuses on wastes from standard fuel oils.
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-10 March 1999

6.1.4 Supporting Processes

The generation of low-volume combustion wastes is associated primarily with processes that

support the combustion process or make use of the products of combustion. Some of the same

supporting and enabling processes can accompany combustion at oil-fired facilities as at coal-fired

facilities, with the obvious exceptions of coal storage and coal processing. Little if any fuel oil

processing occurs at oil combustion sites. Thus, the types of supporting processes at oil combustors

include the following:

• Steam generation

• Cooling

• Water treatment

• Cleaning and maintenance.

Chapter 3 describes these processes in detail. The discussion below describes some aspects of

these processes that are relevant to waste generation at oil combustors; however, quantitative information

on the amounts of low-volume combustion wastes generated at oil combustors is scarce.

The supporting process of primary concern at oil-fired utilities is equipment cleaning operations. 

Boiler chemical cleaning wastes and equipment washwater frequently are comanaged with OCWs in the

settling basins that generate SSB solids (see Section 6.3). At oil-fired utilities, cleanout operations

addressing fireside equipment (boilers, flues, hoppers, and stacks) are performed periodically (e.g.,

yearly or less frequently) while units are not operating. Deposits in fireside equipment are typically

removed using high pressure water, although alkaline (caustic) or acidic solutions may be used. Heat

exchange units such as the air preheaters and economizers are typically cleaned more often (e.g.,

quarterly, monthly) to maintain boiler efficiency. Slag on the walls of boilers may in some circumstances

require physical cleaning (i.e., jackhammering or chiseling); in other cases compressed air (i.e.,

sootblowing) may be used (EPRI, 1998a).

6.2 WASTE CHARACTERISTICS

The available data to characterize OCWs are from utilities. The Agency believes that OCWs at

non-utilities have the same characteristics as those at utilities due to the use of the same fuel types and

combustion technologies.

6.2.1 Physical Characteristics

Oil fly ash is a solid composed of fine particles. The particles are characterized by a smaller size

distribution than coal fly ash. The typical median diameter is a few microns compared to median

diameter of 10 to 20 microns for bituminous coal ash. Eighty percent of oil fly ash particles are smaller

than 15 microns in diameter (EPRI, 1998a).

Oil bottom ash also is a solid, but is made up of heavier particles that are not entrained in flue

gas. Some bottom ash may form a fused solid in the boiler that must be broken up to be removed.

OCWs (particularly fly ash and sometimes bottom ash) often are sluiced to SSBs, where they are

managed along with equipment washwaters and other plant wastewaters. Solids settled from these basins

are known as SSB solids and are composed primarily of fly ash captured either in particulate control

units or in operational equipment (economizers, air preheaters) (EPRI, 1998a). Because they result from

wet management, SSB solids have a much higher moisture content than other OCWs.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-11

6.2.2 Chemical Characteristics

Major constituents of oil fly ash include silicon, iron, sulfur, magnesium, vanadium, aluminum,

sodium, calcium, nickel, and potassium. These constituents are present primarily in the form of oxides. 

In most cases, their presence can be traced to the inorganics contained in fuel oil. Magnesium content

may be high when it is used as a fuel additive to control slagging. Most of the unburned carbon from oil

combustion is partitioned into the fly ash stream; oil fly ash may contain 30 to 80 percent unburned

carbon. For the calculation of ash generation discussed in Section 6.1, EPRI used the value of 67 percent

unburned carbon.

Bottom ash, in contrast, contains little unburned carbon. It is generally higher in silicon than fly

ash, with other major constituents present in similar concentrations to fly ash. Because they are

composed primarily of fly ash from the particulate control operations and the air preheater and

economizers, SSB solids are chemically similar to fly ash in their major constituents. A notable

difference is in the iron content in the SSB solids, presumably resulting from precipitation during

treatment (EPRI, 1998a).

Based on available data on organics (see Section 6.2.3), dioxins, and nonmetallic inorganics,

EPA believes metals are the class of constituents of concern in OCW. Oil ash can contain high levels of

vanadium and nickel, and varying levels of other trace elements. Table 6-5 presents observed

concentrations for these constituents.

6.2.3 Leaching and Hazardous Waste Characteristics

Using data available on the composition of OCWs, EPA evaluated whether the waste exhibited

any of the four characteristics of hazardous waste: corrosivity, reactivity, ignitability, and toxicity. Based

on available information and professional judgment, EPA believes that OCWs are not reactive or

ignitable. Fly ash and bottom ash cannot be considered corrosive under EPA’s definitions because the

characteristic does not apply to solid materials. Furthermore, pH data are available for 29 samples of

OCW from six sites (presumably from ash sluice water or liquids entrained in SSB solids). None of

these samples exceeded the limits for corrosivity (pH less than or equal to 2 or greater than or equal to

12.5). The range of pH exhibited by these samples was 2.97 to 10.8.

EPA evaluates the characteristic of toxicity using Toxicity Characteristic Leaching Procedure

(TCLP) results. Table 6-6 presents observed TCLP results for OCWs for a number of constituents. 

These include the eight metals regulated under the Resource Conservation and Recovery Act (RCRA)

and several other metal constituents. Data also are available from Extraction Procedure (EP) tests (a test

previously used by EPA to evaluate toxicity) for most of these same constituents (plus several others). 

The EP results are generally similar to or lower than the TCLP results shown in Table 6-6, with the

exception of arsenic in bottom ash and arsenic and mercury in SSB solids, which appear in EP results at

somewhat higher levels. The discussion below addresses the leachate data first for RCRA-regulated

constituents, then for non-RCRA-regulated constituents.

Based on the TCLP and EP data for the eight RCRA metals, OCWs exhibit the RCRA

characteristic of toxicity only infrequently. Table 6-7 summarizes data on the frequency of exceedences

of the toxicity characteristic. Out of 176 samples analyzed by TCLP or EP, only 11 (6 percent) exceeded

the regulatory threshold for one or more of the characteristic metals; however, these exceedences were

spread across a relatively large number of sites. Seven sites out of the 40 for which data are available (18

percent) had at least one sample that exceeded a regulatory threshold. Details of these exceedences are

as follows:
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-12 March 1999

• Chromium was the metal with the most exceedences (five); most of these were in samples of

solids from equipment washwater. Chromium exceeded the threshold in four samples of

wash solids collected at three sites and in one of three samples of bottom ash at a fourth site.

• The site that had an exceedence for chromium in bottom ash also exceeded the threshold for

lead in two of three bottom ash samples.

• Arsenic exceeded the threshold in one of two samples of bottom ash at one site and one of

four samples of composite ash at another site.

• The site that had an exceedence for arsenic in composite ash also exceeded the threshold for

cadmium in two of four samples of composite ash (one of these samples was the same one

displaying the characteristic for arsenic).

• One of nine samples of fly ash from one site exceeded the threshold for selenium. The eight

other samples of fly ash from the same site did not exceed the threshold; seven of these were

below detection limits.

Constituent

Fly Ash Bottom Ash SSB Solids

Mean Range Mean Range Mean Range

Arsenic 82.0 34.0–198 23.5 3.6–52 210 6.28–1,650

Barium 907 330–2,500 594 248–820 317 7.18–980

Boron 35.9 21.3–50.4 33.5 12–55 160 160–160

Cadmium 6.98 2.92–9.93 3.12 0.50–4.77 5.5 0.2–21.7

Chromium 1,016 138–4,000 205 33–675 456 13–1,250

Cobalt 233 233–233 n/a n/a 51 51–51

Copper 587 270–920 789 154–2,860 2,250 69–16,460

Lead 515 288–1,334 108 57–176 622 46–1,773

Manganese 331 120–698 327 200–520 868 72–2,600

Mercury 5.96 0.06–23.5 0.993 0.081–2.80 0.22 0.108–0.38

Nickel 9,997 4,300–24,562 13,654 1,950–44,136 9,410 2,410–32,350

Selenium 11.1 0.4–17.7 6.07 2.16–10 13.4 0.79–35.0

Silver 3.16 1.06–5.98 n/a n/a 3.9 0.05–9.7

Vanadium 48,816 22,528–110,647 55,541 8,749–200,000 31,580 880–69,670

Zinc 1,735 880–2,009 458 183–744 830 74–4,010

Note: All measurements identified as below detection limit were assigned a value equal to one-half the detection limit for use in the

calculations. All concentrations are facility-averaged; i.e., multiple measurements from a single site are averaged, and the resulting

population of facility averages used to generate the statistics in this table. Statistics presented here are based on a varying number of

samples, depending on the constituent. For details, refer to the Technical Background Document for the Report to Congress on Remaining

Wastes from Fossil Fuel Combustion: Waste Characterization.

n/a = data not available

Source: EPRI, 1997a

Table 6-5. Facility Average Concentration of Selected Constituents in OCWs

(parts per million)
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-13

Thus, while OCWs overall rarely display the toxicity characteristic, a fraction of sites have a single OCW

stream that exceeds the threshold for one or more metals in a large percentage of samples.

TCLP and EP leachate data also are available from 25 sites for toxic organics in OCWs. Of 57

samples, only 6 resulted in analyses above detection limits for one or more organics (one sample for

benzene, one for chloroform, one for methyl ethyl ketone, two for chloroform and methyl ethyl ketone,

and one for chloroform and 1,2-dichloroethane). None exceeded the regulatory thresholds for toxicity. 

Because of the low frequency of detection and EPA’s experience with these specific organics as often

being the result of laboratory contamination at reported levels, the Agency concludes that organics are

not of further concern for OCWs.

Table 6-6 also shows TCLP data for three non-RCRA-regulated constituents: cyanide, nickel,

and vanadium. Nickel and vanadium show high leachate concentrations, consistent with their high total

concentrations in OCWs. Both these metals are considered further in Section 6.4, along with the RCRA

toxicity constituents, in terms of their risk to human health and the environment. Cyanide was detected

in only one of three samples at one site—insufficient data with which to evaluate its risk to human health

and the environment. In addition, EP data are available for a number of other non-RCRA constituents,

including calcium, chloride, copper, fluoride, iron, magnesium, manganese, nitrate, nitrite, sodium,

sulfate, and zinc. Of these, copper, manganese, and zinc are considered further in Section 6.4.

Analyte

RCRA

Standard

Fly Ash Bottom Ash SSB Solids

Mean Range Mean Range Mean Range

RCRA Toxicity Constituents

Arsenic 5.0 0.319 0.01–1.5 0.391 0.025–3 0.0666 0.0015–0.321

Barium 100.0 0.370 0.105–1 1.88 0.025–12.9 0.647 0.09–1.7

Cadmium 1.0 0.160 0.005–0.520 0.130 0.00075–0.62 0.0187 0.005–0.04

Chromium 5.0 0.447 0.005–1.17 0.387 0.02–3.44 0.0621 0.005–0.279

Lead 5.0 0.164 0.03–0.325 1.23 0.012–13.4 0.0824 0.01–0.0625

Mercury 0.2 0.00108 0.0001–0.0025 0.00133 0.0001–0.00563 0.00269 0.0001–0.0005

Selenium 1.0 0.0622 0.0025–0.183 0.0887 0.0025–0.250 0.0605 0.0025–0.302

Silver 5.0 0.0248 0.00052–0.05 0.0542 0.0002–0.175 0.0353 0.005–0.145

Non-RCRA-Regulated Constituents

Cyanide n/a n/a n/a 0.264 0.264–0.264 n/a n/a

Nickel n/a n/a n/a 30.7 3.3–58 28.8 13–44.5

Vanadium n/a 397 36.4–882 211 33.2–513 114 0.01–448

Note: All measurements identified as below detection limit were assigned a value equal to one-half the detection limit for use in the

calculations. All concentrations are facility-averaged; i.e., multiple measurements from a single site are averaged, and the resulting

population of facility averages used to generate the statistics in this table. Statistics presented here are based on a varying number of

samples, depending on the constituent. For details, refer to the Technical Background Document for the Report to Congress on Remaining

Wastes from Fossil Fuel Combustion: Waste Characterization.

n/a = data not available

Source: EPRI, 1997a

Table 6-6. Facility Average TCLP Results for OCWs (mg/l)
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-14 March 1999

6.3 CURRENT MANAGEMENT PRACTICES

The primary source used to evaluate the current waste management practices for oil combustion

wastes was a recent study by EPRI of oil combustion byproducts (EPRI, 1998a) that contains detailed

summaries of waste management practices at 17 large utility facilities that operate oil-fired units. 

Combined, these facilities reportedly account for 32 percent of oil-fired utility generating capacity and 46

percent of utility No. 6 fuel oil consumption. Of the 17 facilities, EPA used 15 for its characterization of

the current management of oil combustion waste. One facility was not included because it was a

combustion turbine unit; the second facility was disregarded because, although an oil facility, it was in

backup status and was reportedly seldom used. This facility, furthermore, had no particulate controls and

did not wash equipment. It reportedly was used so infrequently that routine cleaning was not necessary.

The management of OCWs varies depending on the type of waste (bottom ash, fly ash, lowvolume wastes) and the type of facility (oil-fired facilities versus plants with both coal-fired and oil-fired

units); therefore, the 15 facilities studied were divided into two groups: those that generated both CCWs

and OCWs onsite (2 facilities) and those that generated only OCWs (13 facilities). Of this later group,

eight also burned gas, while the remaining five were strictly oil operations. The common management

practices observed at oil-fired utilities include onsite settling basins and offsite landfills, with a few

onsite landfills (monofills handling only OCWs) represented.

Information regarding presence or characterization of management units at non-utility facilities

combusting oil is not available. As discussed in Section 6.1, volumes of OCW are expected to be significantly smaller at non-utilities. Accordingly, onsite management units dedicated solely to OCWs (as

observed at oil-fired utilities) are unlikely except at the largest non-utilities. Those few non-utilities that

TC Metal

Total Numbers Toxicity Characteristic Exceedences

Sites Samples Number of Samples Percent of Samples Number of Sites Percent of Sites

Arsenic 40 169 2 1% 2 5%

Barium 40 169 0 0% 0 0%

Cadmium 40 168 2 1% 1 3%

Chromium 40 176 5 3% 4 10%

Lead 40 176 2 1% 1 3%

Mercuryb 40 169 0 0% 0 0%

Selenium 40 175 1 1% 1 3%

Silver 40 168 0 0% 0 0%

All TC Metals 40 176 11 6% 7 18%

a Table compares individual sample concentration data for fly ash, bed ash, composite ash, SSB solids, wash solids, and “other as h” analyzed

by TCLP or EP, to the RCRA regulatory levels. b One sample for mercury was reported as a non-detect with a detection limit more than twice the regulatory level. If assigned a value of onehalf the detection limit according to the standard approach used in this report, the sample would be counted as an exceedence. However,

given that no other samples approached the regulatory threshold for mercury, this apparent exceedence was assumed to be an artifact of

the high detection limit and not counted here.

Source: EPRI, 1997a

Table 6-7. Frequency of Toxicity Characteristic Exceedences for OCWsa
Report to Congress on Wastes from the Combustion of Fossil Fuels

5

 One of the 13 facilities had no particulate controls and did not collect fly ash.

March 1999 6-15

generate significant amounts of OCW likely manage the waste similarly to utilities. The smaller nonutilities likely manage OCW dry in offsite units or onsite in combination with non-combustion waste.

6.3.1 Facilities Generating OCWs Only

Ash Management

At facilities that generate only oil combustion wastes, oil fly ash and bottom ash are typically

managed separately (see Table 6-8). Most commonly, fly ash is sluiced wet to a settling basin after

collection by particulate control technology. This occurred at 10 of the 12 facilities that captured fly

ash.5

 The remaining two facilities operate oil-fired baseload generation units and manage their oil fly ash

in the following ways. One of these two facilities chemically thickens the ash slurry (and, on an “asneeded” basis, solids dredged from an onsite surface impoundment). The thickened material is drum

filtered to dewater the material to about 50 percent solids. The filter cake drops into a rolloff box for

immediate transportation to an offsite destination (landfill or vanadium recovery depending on the

market). The supernatant from the filter operation is managed in surface impoundments with

washwaters. This facility also collects bottom ash dry for offsite transport. The second of these facilities

pneumatically transports its fly ash directly to an unlined onsite ash basin (landfill) where it is disposed

with bottom ash. The facility operates a separate surface impoundment for washwaters.

The most common practice for the oil bottom ash is to collect it dry and transport it to an offsite

destination (11 of the 13 facilities). Reportedly, the offsite destination is usually a landfill, unless the

market is favorable for utilizing vanadium content in the ash. The remaining two facilities manage their

oil bottom ash as follows. One of these facilities sluices its oil bottom ash to a surface impoundment

(this is the facility that collects and manages no oil fly ash). The second facility transports its oil bottom

ash dry directly to an onsite ash basin (landfill), where it is disposed with oil fly ash.

Low-Volume Waste Management

The practice of comanaging low-volume wastes is as prevalent for OCWs as it is for CCWs. 

Table 6-9 shows the frequency of comanaging OCWs and low-volume wastes for the 13 facilities

studied. Because these “low-volume” wastes are liquid, they are typically managed in large quantities. 

For a typical site, the EPRI oil combustion report estimates a volume of 2.1-million gallons per year of

the low-volume wastes, compared with 5-million gallons per year of fly ash sluice water.

Description of Management Number of Sites Percent

Bottom ash and fly ash managed separately 9 69%

Bottom ash mixed with dredged solids from fly ash impoundments 2 15%

Bottom ash and fly ash comanaged dry in onsite landfill (ash basin) 1 8%

No particulate controls to collect fly ash; bottom ash collected 1 8%

Total 13 100%

Source: EPRI, 1998a

Table 6-8. Combinations of OCW Managed
Report to Congress on Wastes from the Combustion of Fossil Fuels

6

 Only one of the 13 facilities reported leaving the solids in its basin. No fly ash is collected at this facility,

it operates no baseload units, and the two basins were designed for other purposes, are cement-lined, and have very

large capacities.

6-16 March 1999

The most common practice (11 of the 13 facilities) is for low-volume wastes to be comanaged in

the same impoundments with fly ash. The two remaining facilities include one that disposes all ash dry

in a landfill and a second that sends all ash offsite; these two facilities both operate impoundments for

low-volume waste management. The types of low-volume waste most commonly comanaged are fireside

washwaters, boiler chemical cleaning wastes, and equipment washwater and floor drains.

Settling Basin Solids Management

Solids from the surface impoundments (commonly called SSB solids) typically are dredged on an

“as-needed” basis. The solids may be composed of several materials. At three of the EPRI oil

combustion report sites, wastewater in the fly ash impoundments is specifically noted as being treated

with coagulants (ferrous chloride and/or polymers) to precipitate metals and promote settling. This

practice effectively results in commingling of fly ash with wastewater treatment sludge; other facilities

also are likely to be using some chemicals in treatment. Ten of the 13 facilities sluice fly ash to these

settling basins and their solids, therefore, contain fly ash as well as any treatment sludges. At one facility

the solids include all the bottom ash generated. Solids from all facilities will include fly ash components

that were captured in fireside equipment (air preheaters, economizers, stacks, fireside boiler surfaces)

and subsequently washed down. Facilities that commingle boiler chemical cleaning waste for treatment

also will have solids precipitated from this waste stream.

The most common practice for the SSB solids is to dredge them, dewater them, and transport

them to an offsite destination.6

 Reportedly, the typical destination is an offsite landfill, unless the market

is favorable for either utilizing vanadium content in the solids or using the solids in concrete applications.

Management Unit Description – Surface Impoundments

The surface impoundments used to manage sluiced ash and comanaged low-volume wastes at the

13 facilities in the study ranged from a tenth of an acre to nearly 13 acres (see Table 6-10). OCW waste

management unit sizes range from small deep sump-like basins (the smallest acreage SSB unit is also the

relatively deepest unit) to very large, relatively shallow surface impoundments. The system with the

smallest capacity (just under 3,000 cubic yards) is only a half acre in surface area and between 3- and

Description of Management Number of Facilities Percent

Comanagement of OCW and Low-Volume Wastes

Low-volume waste comanaged with fly ash

Low-volume waste comanaged with bottom ash

11

(10)

(1)

85%

(77%)

(8%)

No Comanagement 2 15%

Total 13 100%

Source: EPRI, 1998a

Table 6-9. Comanagement of OCWs and Low-Volume Wastes
Report to Congress on Wastes from the Combustion of Fossil Fuels

7

 EPA calculated the adjusted average using 11 of the 13 facilities because two of the facilities operated

units that were designed for other uses. The sizes of these units were significantly disproportionate to the amount of

OCW wastewater managed. 

March 1999 6-17

4-feet deep. The adjusted average7 size unit was a 1-acre system; the median after adjustment was 1.1

acres. The typical settling basin system has two ponds. Concrete sump-type basins tend to be smaller

and deeper; ponds used for percolation/evaporation range larger but shallower (average depth for pond

units was 4.4 feet).

Figure 6-3 describes the types of liners employed in the OCW surface impoundments for the 13

facilities studied. Based on EPRI data, about two-thirds of the OCW surface impoundments are lined. 

The unlined impoundments are all located in the southeast Atlantic or southeast Gulf coasts and are

percolation basins designed to discharge to ground water. This practice of discharging to ground water is

allowed under Florida’s state wastewater permits. State ground-water standards are applied to these units

outside a specified zone of discharge. According to the EPRI oil combustion report, two of these unlined

percolation basins at one site were cleaned and rebuilt in 1995 to alleviate trace metal movement. The

rebuilding included the addition of a sand filter layer to retain fine particles and a crushed limestone

base. Two unlined percolation basins at another site also have crushed limestone bases. Although these

designs do not prevent leachate as a liner would, they may serve as a form of environmental control

because the limestone can provide pH control and the filter layer may slow the migration of certain other

constituents in leachate. Ground-water monitoring is practiced at 50 percent or more of the onsite SSBs.

Limited data for these units suggest a trend toward the increasing use of liners. Three of the

OCW surface impoundments were lined only recently—two in 1993 and one in 1996. In addition, one

site that currently operates two lined impoundments historically used a single unlined basin. 

Furthermore, the major producer of power in Florida has verbally declared its intent to eventually line all

units.

Management Unit Description – Landfills and Wastepiles

As noted above, the final disposition for most of the ash and SSB solids is in land-based disposal

units, except when markets for vanadium recovery or other alternative use are favorable. With two

exceptions, the waste is shipped offsite. No data are available on liners or other environmental controls

employed at the offsite landfills.

Size Description Adjusted Average b Range (min–max)

Area 1.0 acres 0.1–12.8 acres

Capacity 9,038 cubic yards 2,968–123,655 cubic yards

Relative Depth c 6.5 feet 1.8–21.5 feet

a Size data are for combined settling basin system; SSB systems range in number of actual units from 1 to 4 with 2 being the most common. b Two facilities were removed from this average as the units were originally designed for other uses and the sizes were significantly

disproportionate to amount of wastewater managed (if included area would be 2.8 acres and capacity 26671 yd3

). c Calculated using capacity and surface area, does not account for side slopes configuration.

Note: Depth data are derived from the reported capacity and area for each site.

Source: EPRI, 1998a

Table 6-10. OCW Management Surface Impoundment System Sizesa
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-18 March 1999

Figure 6-3. Liners Used in OCW Surface Impoundments

In the two instances of onsite management, some limited information was available in the EPRI

report. Ground-water monitoring is performed at both sites. One facility utilizes an ash basin to which

oil combustion fly ash and bottom ash are conveyed by dry collection and transport. Although it does not

receive equipment washwaters or other plant wastewaters, the basin is described in the EPRI oil

combustion report as part of a larger wastewater treatment complex, and appears from the accompanying

map to be a cell built on the edge of a larger unit. It is unclear if standing water is maintained in the

basin. The basin reportedly is unlined. The owners have indicated to EPRI that they intend to close the

unit and ship ash offsite in the future. The second unit is described as a stabilized ash pad. The pad

receives solids that are dredged from oil combustion fly ash surface impoundments and stabilized with a

cement-based mixture. The pad has an asphalt cover and vegetated sides.

6.3.2 Facilities Generating Both OCWs and Coal Combustion Wastes

At facilities that generated both coal and oil combustion wastes, OCWs typically are comanaged

with certain coal combustion wastes. Two facilities in the EPRI study were coal plants that each

operated three coal-fired units along with a single oil-fired unit; these facilities are discussed below.

Ash Management

At both facilities, particulate controls in the form of electrostatic precipitators are used to capture

oil fly ash. Neither facility reinjects oil fly ash into their oil units. One facility, however, does route

about 70 percent of its oil fly ash to coal-fired units, where the high carbon content is reburned; any

residue from this reburning is captured with the coal ash. The remaining oil fly ash at this facility, as

well as all oil fly ash at the second facility, is sluiced to a surface impoundment system for treatment. 

The oil fly ash at both operations was at one point sent offsite for vanadium recovery. Both operations

indicated that recent changes to low nitrogen oxide (NOX) burners resulted in increased carbon content in

the ash, making the relative proportion of the vanadium less and the recovery economics unfavorable.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-19

Oil bottom ash from both operations is managed separate from oil fly ash; in one case it is comanaged

with coal bottom ash. One facility collects it dry and trucks it to an offsite landfill. The second facility

sluices the bottom ash to an impoundment that also manages bottom ash from the coal units. The

combined coal and oil bottom ash is used for structural fill or construction applications; the majority of

this waste would be expected to be coal ash.

Low-Volume Waste Management

All the low-volume wastes typical of oil-fired units are managed together with oil fly ash at these

two facilities. These are routed at both facilities to pond-based wastewater treatment systems. All

wastewaters at these two coal plants (e.g., bottom ash pondwater, coal pile runoff, floor drains) are

routed to the same system; therefore, all oil fly ash and low-volume wastes from oil combustion are

comanaged with low-volume wastes from the coal operations. Solids from these wastewater treatment

impoundments are dredged at both facilities and sent to landfills, one onsite and the other offsite. Lime

is added to both systems for pH control. Thus, wastewater treatment sludge is a component of the solids

that settle from the wastewater.

Management Unit Description

The two facilities manage their OCWs in units similar to the SSBs used for oil-fired utilities. 

The facility that reburns most of its fly ash and ships its bottom ash to an offsite landfill (i.e., manages

little ash in the SSB) uses a 1-acre SSB system. The three-basin system is unlined. Solids dredged from

this basin are shipped offsite to a landfill; no data about this unit’s environmental controls are available. 

The facility that slurries all its fly ash, coal pile runoff, and bottom ash pond water operates a larger 2.8-

acre SSB system. This two-basin system is high density polyethelene (HDPE)-lined. Dredged solids

from this system are landfilled in a very large (i.e., over 60 acres as shown on map) landfill. The landfill, 

operated under a Massachusetts state permit, has 11 cells, 2 of which are currently active. The two active

cells have double HDPE liners, leak detection, and leachate collection systems. At least 1 foot of

standing water is maintained in the active cells to control fugitive dust. The nine inactive cells have

single synthetic liners and are capped with a polyvinyl chloride cover, a drainage layer, and a soil top

cover that has been seeded with grass.

6.3.3 Beneficial Uses

While comprehensive statistics do not exist on the quantities of OCW serving beneficial uses,

there exist a few applications with the potential to serve as alternatives to traditional waste management

for these wastes. In particular, the high metal content present in OCWs can make them a valuable

resource for metals recovery. Vanadium, either in the form of oxides or carbides, may be recovered from

oil fly ash and bottom ash through high-temperature or leaching processes. In turn, oil ash vanadium

compounds are incorporated primarily as alloying agents or hardeners in steel manufacturing. While the

vanadium in fly ash needs to be extracted prior to its addition into the smelting furnace, oil bottom ash

can be added to the furnace directly due to its low carbon content. In addition to the steel industry,

recovered vanadium compounds also serve as oxidation catalysts or as plasma-sprayed coatings in other

industrial applications. The amounts of vanadium currently recovered from oil ash or utilized in any of

the applications mentioned above are unknown. Reportedly, vanadium recovery from oil ash has been

conducted, when economically viable, with OCW from 10 of the 17 oil-fired facilities studied by EPRI. 

Two of these facilities discontinued this practice in the early 1990s, following the installation of low

nitrogen oxide (NOX) burners, which increased the carbon content in the oil ash and affected the costeffectiveness of the vanadium recovery process. One of the facilities reported sending all of its oil ash

for vanadium recovery (EPRI, 1998a).
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-20 March 1999

Some use of OCWs in construction applications also has been reported. Approximately half of

the oil-fired facilities studied by EPRI reported sending some portion of their OCWs offsite for use in

concrete products, as structural fills and roadbed fills, when the opportunity was available (EPRI, 1998a).

OCWs have not been used extensively for other beneficial use applications like those described

in Chapters 3 and 5 for CCWs and FBC wastes. Since the quantities of OCW are much lower than those

of CCWs and FBC wastes, the use of oil wastes may not be economically feasible in applications

requiring large volumes of material. In addition, the high content of vanadium, nickel, aluminum, and

molybdenum presents a barrier to OCW utilization, particularly as soil amendment.

6.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE

ENVIRONMENT

Section 3.4 provides a discussion of the methodology employed by EPA in assessing risks from

coal-fired utility comanaged wastes. EPA followed a similar approach for wastes from oil-fired boilers,

with several important differences. First, as with FBC wastes, EPA received waste characterization data

for sites representing roughly 30 percent of the generator population and an even greater percentage of

wastes generated industry-wide. TCLP and EP Toxicity data were grouped to provide as large a sample

population as possible. Second, EPA found that oil-fired utility waste generation and management

practices differ significantly from those of their coal-fired counterparts (see Section 6.3). Oil-fired

utilities commonly manage oil ash in very small onsite solids settling basins, from which ash is

periodically removed for final disposal in an onsite or offsite landfill or for offsite processing for

vanadium recovery. Offsite commercial landfills receiving oil ash typically are expected to be lined

facilities (as discussed in Section 6.3 and 6.5). Accordingly, EPA developed scenarios for small unlined

landfills and impoundments only. Finally, EPA found that oil-fired utilities reflect a geographic

distribution distinct from coal-fired utilities, and so modified its modeling scenarios accordingly.

6.4.1 Potential Ground-Water Risks to Human Health

Table 6-11 summarizes selected results from the deterministic and probabilistic analyses of risk

from OCWs for the adult receptor. EPA found that the risks associated with all modeled constituents of

concern, except for arsenic, nickel, and vanadium, fell below a hazard quotient (HQ) of 1 or a lifetime

cancer risk of 1×10-6. Potential high-end risks associated with arsenic in the landfill and surface

impoundment (solid settling basin) high-end deterministic scenarios exceeded 1×10-5. Further, the

predicted high-end HQs for nickel and vanadium exceeded 1 in both management unit scenarios; this was

especially so for vanadium.

Comparison of the deterministic and Monte Carlo results reveals that the deterministic results

generally exceeded the 95th percentile Monte Carlo results. For example, none of the 2,000 Monte Carlo

simulation combinations of parameter values performed for nickel yielded a risk estimate as high as the

corresponding high-end deterministic results. The deterministic result exceeded the 95th percentile

Monte Carlo result for all constituents for the surface impoundment. This was not the case, however, for

the landfill scenario. The 95th percentile Monte Carlo results for the landfill exceeded the deterministic

results for arsenic and vanadium. These differences reflect the small number of data points in the sample

population for several key variables, including waste concentration and management unit size, and are

considered of little significance.

EPA also considered the time at which risks were predicted to result from the release of

constituents of concern. As shown in Table 6-12, EPA found that the concentration of arsenic in ground

water at the receptor well downgradient of the surface impoundment and the landfill would not reach the 
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-21

health-based level (HBL) for arsenic (i.e., achieve a risk level of 1×10-6) for roughly 400 and 2,800 years,

respectively. The times to reach the nickel and vanadium HBLs in ground water below the surface

impoundment were considerably smaller at 50 and 10 years, respectively. The predicted near-term

observations of nickel and vanadium in ground water also were corroborated by observations of these

metals in ground water below actual waste management units (see Section 6.4.3).

Table 6-13 summarizes the estimated risks to adult and child receptors for the high-end

deterministic scenario for OCWs. Overall, the results show that for non-carcinogens the risks for young

children increased roughly twofold compared with the adult receptors. For arsenic, risks stayed at the

10-5 level for both adult and child.

Scenario Constituenta

Deterministic

Risk, Central

Tendency

Deterministic

Risk, High-End

Corresponding

Monte Carlo

Percentile

Monte Carlo

95th Percentile

OSb Arsenic 1×10-12 7×10-5 97.75 2.6×10-5

Nickel HQ <1 HQ = 28 >100 HQ = 0.005

Vanadium HQ <1 HQ = 680 >99.9 150

OMb Arsenic 1×10-15 2×10-5 93.45 3×10-5

Nickel HQ <1 HQ = 1.8 >100 HQ = 0.05

Vanadium HQ <1 HQ = 6.7 85.9 HQ = 21

a

All other metals modeled resulted in HQ <1

b

OS = oil ash impoundment; OM = oil ash landfill

Note: Results shown are those from the October 10, 1998, Sensitivity Analysis.

Table 6-11. Comparison of Deterministic and Monte Carlo Risk Model Results

for Oil Combustion Waste

Ground-Water Pathway Scenarios

Scenario Constituenta Time to Risk (years)

OSb Arsenic 400

Nickel 50

Vanadium 10

OMb Arsenic 2,800

Nickel 900

Vanadium 80

a

All other modeled metals yielded HQ <1

b

OS = oil ash impoundment; OM = oil ash landfill

Note: Results are from the April 1998 Draft Final Report.

Table 6-12. Predicted Time to Reach Risk for Oil Combustion Waste –

Deterministic Scenarios
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-22 March 1999

6.4.2 Potential Above-Ground Multi-Pathway Risks to Human Health and the

Environment

Human Health Risk Findings

No significant non-ground water human health risks were identified for landfill or impoundment

scenarios.

Ecological Risk Findings

EPA found no significant ecological risks associated with releases from onsite landfills. EPA did

not evaluate risks associated with standing waters in solids settling basins. However, because these

basins are very small and because they are located within industrial facilities, the Agency believes that

ecological impacts from direct exposure to these basin waters would be very small.

6.4.3 Documented Damages to Human Health and the Environment

EPA identified a total of nine sites managing oil combustion wastes that have ground-water

contamination. Seven of the nine sites were documented in EPRI’s oil combustion report (EPRI, 1998a). 

The two other sites were identified in supporting documentation for the 1993 Regulatory Determination

and from RCRA Corrective Action records. EPA determined that ground water has been affected at all

of these sites, though not always above maximum contaminant levels (MCLs) or other state standards. 

EPA, however, found that only one of these sites, the Possum Point, Virginia, facility previously

described in the 1993 Supplemental Analysis and Section 3.4.3 of this Report, met the “test of proof” for

a damage case.

Many of the sites evaluated are located next to the ocean or other large bodies of water where

releases to ground water are discharged to surface water and no drinking water wells would be located

between the management unit and the surface water. EPA did not find any cases of drinking water

contamination or other environmental damages resulting from these releases. Additionally, most or all

unlined units are operated under state permit allowing exceedences of ground-water standards close to

the management unit but which must be met outside the zone of discharge. EPA found insufficient

evidence of state action at these sites to meet the test of proof.

Scenario Constituenta

High-End Deterministic Risk

Adult Young Child Child

OSb Arsenic 7×10-5 8.8×10-5 6.2×10-5

Nickel HQ = 28 HQ = 48.4 HQ = 31.4

Vanadium HQ = 680 HQ = 1,176.4 HQ = 761.6

OMb Arsenic 2×10-5 2.5×10-5 1.8×10-5

Nickel HQ = 1.8 HQ = 3.1 HQ = 2.0

Vanadium HQ = 6.7 HQ = 11.6 HQ = 7.5

a

All other modeled metals yielded HQ<1

b

OS = oil ash impoundment; OM = oil ash landfill

Note: Results shown are those from the October 10, 1998 Sensitivity Analysis.

Table 6-13. Comparison of Adult and Child Risk Model Results for Oil

Combustion Waste – Ground-Water Pathway Scenarios
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-23

At two sites studied by EPA (Ft. Meyers, Florida; Possum Point, Virginia), the state required

removal of oil ash waste from the management units. At the Possum Point facility, exceedences of

constituents above primary MCLs were observed, while at the Fort Meyers facility no exceedences of

MCLs were determined. Therefore, only the Possum Point facility (previously described in Section

3.4.3, damage cases related to comanaged coal combustion wastes) meets EPA’s test of proof for

identifying cases of damage.

Based on information available and consideration of EPA’s “tests of proof,” EPA identified the

cases in Table 6-14 as potential damage cases.

6.5 EXISTING REGULATORY CONTROLS

EPA’s objective in this analysis was to identify and evaluate the existing regulatory controls that

pertain to the management of oil combustion wastes. The regulatory analysis is directed toward

addressing the question of whether existing regulations are adequately protecting human health and the

environment. The analysis also is helpful in understanding waste generation and current management

practices.

The sections below discuss regulations addressing air pollution, water pollution, and solid and

hazardous waste, respectively. Air regulations are relevant primarily because of their effect on waste

generation. Water regulations have an influence both on waste generation and management and, in

particular, address the impact of OCWs on surface waters. Solid and hazardous waste regulations are of

the greatest interest because they directly govern waste management practices.

The sections below describe federal regulations in each of these areas. In many cases, the

implementation of these federal programs is carried out by the states; therefore, where appropriate,

aspects of state implementation also are discussed. Because the nuances of state implementation are of

particular importance with respect to solid waste regulation, that section discusses state programs in

detail.

6.5.1 Regulations Addressing Air Pollution

The CAA is intended to protect and enhance the quality of the nation’s air resources. CAA

requirements have been a significant factor affecting the generation and collection of certain OCWs

(specifically, fly ash). The CAA requirements most relevant to OCWs include the following:

• National Ambient Air Quality Standards (NAAQS) for particulate matter (PM)

• NAAQS for sulfur dioxide

• NAAQS for ozone

• National Emissions Standards for Hazardous Air Pollutants (NESHAP).

Damage Case Wastes Present Event Test of Proof Comment

Oil Combustion Wastes

VEPCO – Possum

Point (VA)

Coal ash, pyrites, oil

ash, water treatment

wastes, and boiler

cleaning wastes

Ground water

contaminated with Cd

and Ni, attributed to

pyrites and oil ash

Administrative Response included

sequestration of oil

ash, pyrites, and metal

cleaning wastes to

separate lined units

Table 6-14. Potential Damage Cases
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-24 March 1999

Title IV acid rain provisions, the fifth set of requirements that affect fossil fuel combustors as a

group, currently apply only to the largest coal-fired utility generating units and, therefore, are not

relevant for oil-fired units. Historically, CAA requirements have been a significant factor affecting the

generation and collection of certain OCWs. Recent and forthcoming changes in these requirements also

may impact waste generation or characteristics, as discussed below.

NAAQS for Particulate Matter

The NAAQS for PM establish maximum concentrations of PM with diameter less than or equal

to 10 micrometers (PM10) in the ambient air. These standards are among the factors motivating the use

of particulate control technologies at FFC facilities. EPA recently proposed to lower the size criterion to

2.5 micrometers, which may affect the volume of fly ash collected and selection of control technology. 

Final standards, however, will not be issued for at least 5 years, so the impact of the new size criterion is

difficult to predict at this time.

The NAAQS for PM are implemented through New Source Performance Standards and State

Implementation Plans.

New Source Performance Standards (NSPS). The NSPS subjects newly constructed or,

importantly in the case of oil-fired utilities, modified units to specific PM emissions limits. These limits

may be met by changing fuel types, modifying combustion conditions, or installing control devices. The

applicability of the NSPS and the specific limits imposed vary with the age and size of the combustion

unit, with older and/or smaller units less likely to be subject to the NSPS. Specifically, the regulation of

facilities can be considered in four categories.

• 40 CFR 60 Subpart D governs the standards of performance for new fossil fuel-fired steam

generators that were constructed or underwent major modification after August 17, 1971. 

Subpart D affects only units that are capable of burning fossil fuels at greater than 73

megawatts (MW) of heat input rate.

• Subpart Da affects utility units with the capacity to fire fuel at greater than 73 MW heat

input rate that commenced production or major modification after September 18, 1978.

• Subpart Db affects units with the capacity to fire fuel at greater than 29 MW of heat input

rate that commenced construction or modification after June 19, 1984.

• Subpart Dc governs units constructed or modified after June 9, 1989, with capacity to fire

fuel at less than 29 MW but greater than 8.7 MW of heat input rate.

With the exception of Subpart Da, which applies specifically to utilities, the NSPS requirements apply to

all oil-fired steam generating units, utility or non-utility. Non-utilities, however, tend to have smaller

capacities than utilities and, therefore, are more likely captured by those NSPS requirements that apply to

smaller capacity units (i.e., Subparts Db and Dc). Note that under the NSPS regulations, facilities that

were in operation before the dates stated in each of the four subparts are considered “grandfathered” and

would not be subject to the new performance standards unless they underwent a major modification.

State Implementation Plans (SIPs). The performance standards above can be enforced by a

federal, state, or local regulatory agency. There are additional CAA regulations that could require an oilfired unit to install a particulate removal device notwithstanding the grandfather clause in Subparts D,

Da, Db, and Dc. SIPs may impose, on a state-by-state basis, PM controls of varying stringency on
Report to Congress on Wastes from the Combustion of Fossil Fuels

8

 The RIA was based on a slightly more stringent ozone standard that allowed only three exceedences over

a 3-year period and also incorporated the impacts of proposed changes to the PM standard that have not yet been

finalized. Still, the general trends forecast by the RIA are expected to be valid for purposes of this analysis.

March 1999 6-25

specific sources or categories of sources, including oil combustion facilities. Such controls are required

under Title I of the CAA if a particular area is in nonattainment for the NAAQS for a criteria pollutant

such as PM. For this reason, SIP controls will generally be more stringent in such nonattainment areas. 

In attainment areas, the prevention of significant deterioration (PSD) program requires new sources to

apply Best Available Control Technology (BACT), which must be at least as stringent as NSPS.

NAAQS for Sulfur Dioxide

Similar to the NAAQS for PM, the NAAQS for sulfur dioxide establish a maximum

concentration of sulfur dioxide in the ambient air. The NAAQS for sulfur dioxide are implemented

through NSPS and SIPs. The functioning and applicability of the sulfur dioxide NSPS requirements are

similar to those for PM.

Each of the first three categories of oil-fired facilities regulated under Subparts D, Da, and Db is

subject to the same requirement: sulfur dioxide emissions must be less than 340 nanograms per joule

(ng/J) of heat input. Under Subpart Dc, facilities constructed or modified after June 9, 1989, with heat

input capacity between 2.9 MW and 29 MW must limit emissions to less than 215 ng/J heat input. 

Facilities with greater than 22 MW heat input capacity generally also must achieve a 10-percent

reduction in their sulfur dioxide emissions, based on the potential concentration in fuel. Facilities

constructed or modified after June 9, 1989, and between 2.9 and 8.7 MW heat input capacity may meet

the standard based on certification from the fuel supplier that the sulfur content of the fuel is low enough

to meet the standard.

In addition to NSPS, states may impose controls through their SIPs to meet the sulfur dioxide

NAAQS. These controls may vary in stringency depending on attainment status and may be placed on

specific sources or categories of sources, including oil-fired units.

Because of the low sulfur content of fuel oil and the ability to switch fuel easily, the NAAQS for

sulfur dioxide have not led to extensive use of FGD technology at oil-fired facilities.

NAAQS for Ozone

The NAAQS for ozone establish a maximum concentration of ozone in the ambient air. EPA

recently lowered this concentration from 0.12 to 0.08 parts per million (ppm). The new standard allows

four exceedences of the maximum in a region over a 3-year period. EPA expects states will meet the new

standard by amending their SIPs to limit nitrogen oxide emissions at utilities. In proposing the new rule,

EPA published a Regulatory Impact Analysis (RIA) forecasting changes in the operating practices of

utilities that could result from these SIP modifications.8

 The RIA estimates that total utility capacity will

increase by the year 2010. As a result of the new regulations, however, utilities are expected to invest in

new combined cycle gas-fired units and oil- or gas-fired CTs to provide this new capacity. Oil-fired

steam generating capacity is not expected to increase (EPA, 1997b; EIA, 1998a); therefore, utility

generation of ash is not expected to increase dramatically, even with future expansion of the utility

industry.
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-26 March 1999

NESHAP

Under the NESHAP, EPA is required to establish technology-based standards for 189 hazardous

air pollutants (HAPs). These standards are to be set on an industrial category basis and will apply to

facilities that emit greater than 10 tons/year of any one HAP or greater than 25 tons/year of any

combination of HAPs.

EPA has studied HAP emissions from utility oil-fired steam generating units and found that

nickel from oil-fired utilities is a HAP of potential concern. EPA has deferred any determination as to

whether regulations to control HAP emissions from utilities are appropriate and necessary (EPA, 1998c). 

If such regulations were promulgated, they could affect the characteristics or volumes of FFC solid

wastes.

For non-utility oil combustors, EPA has not specifically studied HAP emissions. Because

NESHAP will be set on an industrial category basis, when promulgated, the impact of these regulations

on OCW generation and characteristics may vary depending on the industrial sector of the non-utility oil

combustor.

6.5.2 Regulations Addressing Water Pollution

Under the federal Clean Water Act, the National Pollutant Discharge Elimination System

(NPDES) controls discharges to waters of the United States. As discussed below, the controls required

under NPDES affect the collection and management of CCWs. In states authorized by EPA, these

controls are implemented through state programs (often termed State Pollutant Discharge Elimination

Systems, or SPDES). Because state programs must be at least as stringent as the federal program, the

discussion here focuses on federal requirements as a lowest common denominator. NPDES requirements

apply differently to two categories of discharges: process wastewaters and stormwater runoff. Neither

the NPDES process wastewater or NPDES stormwater requirements make a distinction between oil-fired

and coal-fired units. Distinctions may apply, however, between utilities and non-utilities.

NPDES Requirements for Process Wastewaters

The NPDES requirements that apply to process wastewaters from oil-fired utilities are those for

the steam electric point source category under 40 CFR Part 423. These requirements apply to facilities

“primarily engaged in the generation of electricity for distribution and sale” (i.e., utilities). Oil-fired nonutilities face NPDES requirements for process wastewaters that are specific to their industrial sector. In

most cases, under these requirements each discharge requires an individual NPDES permit with numeric

limitations based on Best Practicable Control Technology Currently Available (BPT), Best Available

Technology Economically Achievable (BAT), or New Source Performance Standards (NSPS). Facilities

that discharge to publicly owned treatment works (POTWs) rather than directly to surface waters face

Pretreatment Standards for Existing Sources (PSES) similar to BAT, or Pretreatment Standards for New

Sources (PSNS) similar to NSPS.

The majority of OCWs (and particularly fly ash) are managed wet. For these wastes, the most

relevant requirements are total suspended solids (TSS) limits.

At non-utilities, the specific NPDES effluent standards applied depend on industrial category. 

Effluent standards expected to apply to large numbers of non-utility fossil fuel combustors include those

for the following industry categories:
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-27

• Pulp, paper, and paperboard (40 CFR Part 430)

• Organic chemicals, plastics, and synthetic fibers (40 CFR Part 414)

• Inorganic chemicals manufacturing (40 CFR Part 415)

• Textile mills (40 CFR Part 410)

• Timber products processing (40 CFR Part 429)

• Iron and steel manufacturing (40 CFR Part 420)

• Sugar processing (40 CFR Part 409)

• Grain mills (40 CFR Part 406).

The standards for all of these categories include TSS limits, and these limits are applicable to nearly all

of the industrial subcategories covered under each category. Some subcategories are subject to zero

discharge requirements. Based on the Standard Industrial Classification (SIC) codes reported by nonutilities in the 1990 U.S. EPA National Interim Emissions Inventory (EPA, 1990) database, these

industrial category requirements are expected to cover roughly 20 percent of non-utility fossil fuel

combustors. A number of other facilities are scattered through other industrial categories, many of which

are also subject to TSS limits. Some facilities (such as institutional fossil fuel combustors) may not be

subject to the specific standards of any industrial category. In these cases, the specific effluent

limitations would be determined on a case-by-case basis as part of the non-utility’s individual NPDES

permit.

At utilities, the steam electric category NPDES requirements place TSS limits directly on fly ash

handling and bottom ash handling waters. In addition, the NSPS for the steam electric category include a

zero discharge requirement for fly ash handling water. These steam electric requirements may also be

incorporated in individual permits at non-utilities to supplement their industrial category requirements. 

Application of steam electric requirements to relevant waste streams at non-utility fossil fuel combustors

is left to the best professional judgment of the individual permit writer (EPA, 1996).

Because of these requirements, when OCWs are managed in surface impoundments or settling

basins, facilities may have to settle or otherwise remove a certain amount of waste solids from the

handling water to meet the TSS limits prior to discharge. Zero discharge requirements effectively

eliminate the release of waste solids to surface water. Thus, the requirements control the direct release of

fly ash, bed ash, and any treatment solids to surface waters.

NPDES Requirements for Stormwater

NPDES stormwater requirements apply to stormwater runoff from FFC facilities, which may

include runoff from operating areas, ash handling areas, and waste management units. Like the process

wastewater requirements, stormwater requirements have been established on an industrial sector basis;

therefore, the steam electric requirements apply to non-utilities just as they apply to utilities. A chemical

manufacturer, for example, operating a fossil fuel-fired boiler must meet both chemical manufacturing

and steam electric stormwater requirements.

Facilities can meet the stormwater requirements by including stormwater in their individual

NPDES permit or seeking coverage under a general permit by submitting a Notice of Intent (NOI). 

Individual permit control and monitoring requirements will be facility-specific, subject to the judgment

of the permit writer.

When covered by a general stormwater permit, requirements include implementation of a

stormwater pollution prevention plan, “reasonable and appropriate” control measures, and 1 or 2 years of

monitoring and reporting. No site visit by regulators is required under the general permit. Under the
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-28 March 1999

general permit approach, oil-fired facilities have a great deal of flexibility in selecting appropriate control

measures for runoff that may have contacted OCWs. The general permit requirements include

recommended best management practices for stormwater at steam electric facilities, landfills, treatment

works, and construction areas greater than 5 acres. Because these requirements are additive across

industrial sectors, an oil-fired utility with an onsite ash landfill, for example, must meet both steam

electric and landfill requirements.

Because the stormwater program is relatively new and managed by authorized states, the number

of facilities with general versus individual permits is not known. EPA handles NOIs for 10

nonauthorized states. In these states, 700 steam electric facilities (utility and non-utility) have filed for

general permits.

6.5.3 Regulations Addressing Solid and Hazardous Waste

EPA regulates the management of solid and hazardous waste through Subtitles C and D of the

RCRA. Subtitle C of the RCRA establishes a “cradle-to-grave” management system for wastes that are

considered hazardous because they fail tests based on their physical and chemical characteristics (i.e.,

toxicity, corrosivity, ignitability, and reactivity) or because they are listed as hazardous by EPA. Federal

regulations establish stringent environmental and administrative controls that must be applied to

management of these wastes. OCWs, whether generated at a utility or non-utility, are currently exempt

from federal regulation as hazardous waste under Subtitle C pending this Report to Congress and the

subsequent regulatory determination. Therefore, these wastes are currently subject to the requirements of

Subtitle D of the RCRA as nonhazardous solid waste.

Implementation of Subtitle D is the responsibility of individual states, but nothing prevents states

from imposing more stringent requirements (including hazardous waste requirements) on FFC wastes.

Although federal policy currently exempts OCW, like CCW, from Subtitle C regulation, state adoption of

this exemption is not as extensive for OCW as for CCW. Only 26 states extend the federal exemption to

OCW. These 26 states, however, represent more than 80 percent of oil-fired utility capacity. In the other

states, any OCWs that fail the hazardous waste characteristic tests would be subject to state hazardous

waste requirements and managed in units that meet permitting, design, operating, corrective action, and

closure standards.

OCWs fail the hazardous waste characteristic tests only infrequently; therefore, the majority of

OCWs that do not fail the hazardous waste characteristic tests and/or are generated in the states that

duplicate the federal exemption generally would be subject to less stringent state requirements under

Subtitle D. In the CIBO survey, 20 states (accounting for 60 percent of oil-fired utility capacity)

indicated that their waste management requirements for oil combustion wastes differed from those for

coal combustion wastes. To characterize these differing requirements, EPA examined solid waste

regulations pertaining to OCWs in four states: Florida, New York, Massachusetts, and Pennsylvania. 

These states account for more than half of the oil-fired utility electric generating capacity. Table 6-15

summarizes the requirements in each of these five states.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-29

Table 6-15. State Waste Management Requirements Applicable to OCWs

in Selected States

Florida

Landfill

Requirements

Landfills must not cause ground water or surface water quality to exceed minimum standards outside a

specified zone of discharge. Requirements include composite or double liners, leachate collection

systems, run-on/runoff controls, ground-water monitoring, a cap including a geomembrane layer at

closure, and revegetation at closure. State imposes a more stringent requirements as necessary due to

site-specific conditions and types of waste disposed.

Impoundment

Requirements

Regulations do not dictate any specific design requirements. Impoundments may be permitted to

discharge to ground water as long as they do not cause ground-water quality to exceed minimum

standards outside a specified zone of discharge.

Utility Siting

Requirements

Utilities with generating capacity of 75 MW or greater must receive a certification to construct and operate

under the Power Plant Siting Act. The certification process explicitly includes consideration of ash

generation and the impacts of onsite solid waste management. This includes consideration of natural or

manmade liners and leachate and runoff controls. The granting of certification can be subject to

restrictions and requirements on any aspect of operation, including solid waste management.

Grandfather

Clause

Landfills constructed before July 6, 1993, are exempt from the liner, leachate collection, and run-on/runoff

control requirements.

New York

Landfill

Requirements

State has separate programs for landfills that accept mixed solid waste (including municipal solid waste

landfills) and industrial or commercial waste monofills. Either may receive OCWs.

Mixed solid waste landfill requirements include two composite liners, leachate collection systems, groundwater monitoring, daily cover requirements, cover at closure, and revegetation at closure.

Industrial and commercial waste monofills are subject to similar requirements as those for mixed solid

waste landfills; however, the state may impose additional or less stringent requirements based on the

volume and characteristics of the waste. In practice, single composite liners typically have been required

for these monofills.

Impoundment

Requirements

Regulations do not impose any specific design requirements on surface impoundments managing OCW.

Grandfather

Clause

Landfills permitted prior to October 9, 1993, are not required to retrofit liners or leachate collection

systems, except for expansions of the facility.

Massachusetts

Landfill

Requirements

Specifically because of concerns about vanadium in oil ash, the state has developed an interim policy

placing conditions on the disposal of OCWs from utilities. Coal and oil ash mixtures from utilities and

OCWs from non-utilities are subject to the policy on a case-by-case basis.

Under the interim policy, disposal of oil ash is subject to written approval. The waste may be disposed

only at landfills with lined active disposal areas and leachate collection systems. It must be delivered

damp to control fugitive dust and must be covered daily to prevent fugitive vanadium emissions. When

landfilled according to the policy, OCWs may be handled similarly to residential refuse. They are not

considered “special wastes,” which, under Massachusetts regulations, are nonhazardous wastes that

require particular management controls to prevent adverse impact.

Impoundment

Requirements

Regulations do not impose any specific design requirements on surface impoundments that manage

OCWs. Units may be permitted to discharge to ground water.

Grandfather

Clause

No specific grandfather clause; interim policy has been in place since 1983. 
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-30 March 1999

Pennsylvania

Landfill

Requirements

Landfills are classified according to TCLP results for the wastes to be disposed. Specific design

requirements depend on the class of the landfill. Based on available characterization data, OCWs would

sometimes require management in Class I or Class II units, with Class III management allowed for about

60 percent of waste. Liners are required for all classes, with liner type determined by class. Leachate

collection and detection are required for Class I and II units. All classes are subject to the following: siting

restrictions, fugitive dust control, daily cover, soil erosion control, ground-water monitoring, 2-foot clay cap

at closure, and revegetation at closure.

Impoundment

Requirements

Surface impoundments (including those that store waste for less than one year) are classified according

to TCLP results for the wastes to be disposed. Specific design requirements depend on the class of the

impoundment. Based on available characterization data, some OCWs would require management in

Class I units, with Class II management allowed for about 80 percent of waste. Liners are required for all

classes, with liner type determined by class. All classes also are subject to the following: siting

restrictions, leachate detection system, leachate collection system, minimum freeboard requirements,

structural integrity requirements, ground-water monitoring, 2-foot clay cap at closure, and revegetation at

closure.

Grandfather

Clause

Units permitted prior to July 4, 1992, were required to modify their operations to comply with the above

requirements by July 4, 1997. Liner and leachate collection requirements may be modified if the operator

could demonstrate that the unit had not caused unacceptable ground-water degradation.

Based on this detailed analysis, it appears states have varied in their application of solid waste

management requirements to OCW landfills. For example, Pennsylvania’s program imposes

requirements tailored to the characteristics of the waste. Massachusetts’ interim policy specifically

addresses concerns over vanadium in OCWs. According to discussion with Florida waste management

officials, the combination of solid waste and power plant siting regulations have not, in practice, resulted

in any permit requirements specifically tailored to the onsite management of oil ash. Thus, Florida’s and

New York’s programs apply generically to industrial wastes. In these states, OCWs may be disposed of

in landfills that are “grandfathered” out of requirements imposing design requirements such as liners.

Regulations in three of the four states studied do not impose specific design requirements on

surface impoundments that are commonly used to store OCWs. Two of these states permit discharges to

ground water from these units.

6.6 WASTE MANAGEMENT ALTERNATIVES

The risk assessment identified potential ground-water pathway risks to human health from OCW

in unlined landfills and impoundments. Mitigation of these potential risks might be accomplished

through the use of technologies that prevent or contain and collect leachate from OCW landfills and

surface impoundments. Specially, EPA identified the combination of technologies in Table 6-16 as an

alternative that would be practical and effective to mitigate the potential ground-water risk. The

technologies identified in the table are considered further in the cost and economic impact analysis. 

These technologies also are consistent with those required under Subtitle D of RCRA.

6.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS

This section discusses the costs and economic impacts of risk mitigation alternatives for OCWs. 

Because of the quantity of waste generated and availability of data, the analysis focuses on wastes

generated by oil-fired utilities only. Details of this analysis are documented as part of the EPA docket.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-31

Landfill Impoundment

Design includes filter fabric, 1' sand layer, 2' clay liner,

synthetic (HDPE) liner, leachate collection system, groundwater wells.

Operation includes environmental monitoring and leachate

collection and treatment.

Closure requirements include 6" topsoil and vegetation, filter

fabric, 1.5' sand layer, 2' clay layer, synthetic (HDPE) liner,

cover drainage system.

Post-closure includes environmental monitoring, landscape

maintenance, slope maintenance, inspection, administration.

Design includes filter fabric, 1' sand layer, 2' clay liner,

synthetic (HDPE) liner, leachate collection system, synthetic

liner for sludge drying basin, ground-water wells.

Operation includes environmental monitoring, leachate

collection and treatment, solids settling and dewatering

followed by disposal in landfill meeting standards at left.

Closure requirements include final solids dredging and

dewatering followed by disposal in landfill meeting standards

at left, pressure washing sludge drying basin, 6" topsoil and

vegetation, 1.5' soil layer, leachate sampling.

Table 6-16. Management Alternatives for OCW

6.7.1 Overview and Methodology

In estimating costs and economic impacts for oil-fired utilities, EPA used a similar approach to

that described in Section 3.7.1 for coal-fired utilities. Salient distinctions between the analysis in

Section 3.7 and this analysis are reviewed below.

EPA’s analysis began with the 89 oil-fired plants identified in the 1993 U.S. Department of

Energy (DOE) Energy Information Administration (EIA) 767 database that have electrical generating

capacities of at least 10 MW. EPA estimated the incremental compliance cost of the risk mitigation

alternative described in Section 6.6. The cost estimate required oil-fired utilities to construct composite

lined solids settling basins (SSBs). Because the few onsite landfills identified currently are lined and

assuming that offsite landfills are compliant with Subtitle D, no incremental costs were estimated for

OCW landfills.

The cost estimate summed costs in the following categories: initial capital costs, annual

operating and maintenance costs, and closure costs. Recurring capital costs and post-closure costs were

minimal for management units as small as the oil SSBs. Table 6-17 identifies the specific cost

components included in each cost category for oil-fired utilities.

Similar to the analysis for coal-fired utilities, the cost estimate for OCWs employed three

different SSB sizes. Table 6-18 identifies the design features for these basins. A single cost equation

was developed, annualized costs were estimated as a function of facility-specific waste generation, and

total industry costs were derived by summing the facility-specific estimates. Costs and economic impacts

are set forth in the following three sections: incremental compliance cost, compliance cost impact on

facilities as a function of size, and industry impact.

Incremental compliance costs are the costs of risk mitigation practices over and above the cost of

current management practices. Using incremental compliance costs as an indicator of potential cost

burden, the analysis examined impacts on individual facilities as a function of size. As in Section 3.7,

this was performed using pro forma financial statements for three representative plant sizes. For the

industry impact evaluation, the use of econometric models was considered and rejected for the same

reasons discussed in Section 3.7. The industry-level analysis, therefore, focuses on the number of

affected facilities and the magnitude of incremental compliance costs relative to the value of electricity

sales.
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-32 March 1999

6.7.2 Incremental Compliance Cost

Key variables in estimating incremental compliance cost were the same as those discussed in

Section 3.7.2. EPA’s estimate of incremental compliance cost is some $1.7 million per year, using the

most likely values for all the input variables. The potential range of annual incremental compliance costs

is from $1.0 million to $3.5 million, allowing for uncertainty in the input variables.

Category Cost Components

Initial Capital Costs Site development (access road, drainage ditch)

Excavation

Discharge structure

Filter fabric

1' sand

2' clay liner

Synthetic (HDPE) liner

Leachate collection

Synthetic liner for sludge drying basin

Ground-water wells

Indirect capital costs

Annual O&M Costs Dredging

Ash dewatering

Operating and maintenance labor

Electricity

Offsite Subtitle D landfill ash disposal

Environmental monitoring

Leachate collection and treatment

Closure Costs Pressure wash sludge drying basin

Final ash dredging, dewatering and Subtitle D disposal

6" topsoil and vegetation

1.5' soil

Leachate sampling

Indirect closure costs

Table 6-17. Cost Components Included in OCW Solid Settling Basin Designs

Parameter SSB

Sizes small

(dry tons/year) medium

large

36

172

923

Depth small

(feet) medium

large

8.0

11.0

12.0

Area small

(acres) medium

large

0.3

1.0

2.5

Table 6-18. Design Parameters Assumed for Small, Medium, and Large OCW SSBs
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-33

Note that the costs above are incremental (above current costs). Annual costs were discounted at

7 percent to 1998 dollars, with no inflation built into out-year estimates. Also, it was presumed that

compliance would be required immediately, and that amortization would take place over 40 years.

6.7.3 Compliance Cost Impact on Plants as a Function of Plant Size

As discussed in Section 3.7.3, this analysis does not include the potential impact of the ongoing

restructuring of the utility industry and includes no analytical consideration of price effects.

Economic impacts at the plant level will depend on several major factors, including quantity of

fuel used, quality of fuel, profitability, and production technology. To assess these impacts across the

range of plants, EPA estimated financial data for model plants representing three size ranges: large

(burning greater than 750,000 barrels of oil per year), medium (burning between 250,000 and 750,000

barrels of oil per year), and small (burning less than 250,000 barrels of oil per year). These model

facilities are representative of publicly owned utilities. Table 6-19 compares incremental compliance

costs to revenues and net income for these three model plants. The incremental compliance costs used in

this analysis reflect EPA’s best estimate based on most likely values of the relevant input variables.

Thus, the incremental compliance cost for OCWs should not impact the financial viability of oilfired plants. For a large publicly owned oil-fired plant generating about 1.2-billion kWh per year, costs

would be expected to increase only $43,000 annually. This would increase costs by about 0.1 percent of

annual revenue and thus reduce net income from 9.0 percent of revenue to 8.9 percent of revenue. Net

income would thus be reduced from $6.48 million to $6.43 million per year.

Small and medium-sized oil-fired plants (generating from 50- to 300-million kWh per year)

would be more significantly affected but still remain financially viable. Waste management costs would

be in the range of $200 to $500 per dry ton; however, total compliance costs, as a percent of revenue,

would climb about 0.2 to 0.4 percent only. Annual net income for these plants would decline about

$12,000 to $29,000 per year, depending on the size of the plant. If such plants could increase prices to

offset oil waste management costs, they would need only to increase from the representative baseline

price of 6 cents per kWh to 6.02 cents per kWh to regain the pre-compliance position.

Table 6-20 shows how the estimated population of affected facilities breaks down by the three

size categories represented by the model plants. It also compares the incremental compliance costs

estimated for the model plants to average sales for individual plants in each size category. Based on this

criterion, incremental compliance costs range from 0.1 to 0.4 percent of sales.

Large Oil Plant

Publicly Owned Utility

Medium Oil Plant

Publicly Owned Utility

Small Oil Plant

Publicly Owned Utility

$1,000’s

Percent of

Revenues $1,000’s

Percent of

Revenues $1,000’s

Percent of

Revenues

Revenues from Electricity 72,000 100% 18,000 100% 3,000 100%

Baseline Before Tax Net Income 6,480 9.0% 1,620 9.0% 210 7.0%

Expected Incremental Compliance Costs

(replace unlined management unit with

composite-lined unit)

43 0.1% 29 0.2% 12 0.4%

Expected Post-Compliance Net Income 6,437 8.9% 1,591 8.8% 198 6.6%

Table 6-19. Plant-Level Impact of Incremental Compliance Costs
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-34 March 1999

6.7.4 Industry Impacts

The electric power generating industry, including fossil fuel, hydroelectric, nuclear, and other

fuel sources, was a $212 billion per year industry in 1996. Other economic characteristics of the electric

utility industry are discussed in Section 3.7.4, along with information on the current restructuring of the

U.S. electric power industry.

Based on the estimate of costs presented above, if OCWs were subject to risk mitigation

alternatives, the electric utility industry would incur about $1.7 million in incremental annualized

compliance costs. As shown in Table 6-21, this would represent less than one-tenth of 1 percent of the

value of sales even if the oil-fired segment of the industry only is considered. Thus, the cost of

compliance would be a very small percentage of revenues.

Because impacts as a percent of sales would be an order of magnitude less, oil-fired plants would

have less need to pass through costs in the form of higher prices than would coal-fired plants if both were

subject to risk mitigation alternatives. But again, the ability to pass through costs, even if quite modest,

would be restricted by competition from unaffected plants.

6.8 FINDINGS AND RECOMMENDATIONS

6.8.1 Introduction

Based on the information collected for this Report to Congress, this section presents a summary

of the Agency’s main findings presented under headings that parallel the organization of this chapter. It

then presents the Agency’s tentative conclusions concerning the disposal and beneficial uses of

comanaged wastes generated at facilities that burn oil.

6.8.2 Findings

Sector Profile

• There are about 177 utility and more than 2,000 non-utility facilities that burn oil. Oilburning facilities are located throughout the United States, but utility facilities in particular

are concentrated in the eastern United States and in California.

Size Category

Number of

Plants

Percent of

Plants

Plant Sales

($ million/year)

Compliance Cost

($ million/year)

Percent

of Sales

Large (>750,000 barrels/year of oil) 43 35% $72 $0.04 0.1%

Medium (250,000 to 750,000 barrels/year of oil) 15 17% $18 $0.03 0.2%

Small (<250,00 barrels/year of oil) 31 48% $3 $0.01 0.4%

Table 6-20. Incremental Compliance Cost by Plant Size

Industry Sales ($ billion/year) Compliance Cost ($ billion/year) Percent of Sales

$4.3 $0.002* 0.05%

* Rounded up from $1.7 million

Table 6-21. Industry Economic Impacts, Oil Combustion Wastes
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-35

• Non-utilities burn oil for a variety of purposes, including production of manufacturing

process steam, space heating, and captive power generation. They include industrial,

commercial, and institutional facilities. They are located in diverse environments, including

areas that vary widely in population density, geography, precipitation, and general climate.

• There is a declining trend of oil combustion, and the trend is expected to continue for the

next two decades. While industrial combustion of oil is expected to grow modestly, it will

be more than counterbalanced by gas turbine technologies replacing oil-fired utility steamcycle processes.

Waste Generation and Characteristics

• Large-volume OCWs comprise primarily fly ash and bottom ash. Low-volume wastes

associated with the burning of oil are similar in type and characteristics to those described

previously for coal combustion, although comprehensive information on the amounts is not

available. Examples of similar low-volume wastes at coal and oil combustors include boiler

blowdown, ion exchange regeneration wastes, and boiler chemical cleaning waste.

• The utility sector generates an estimated 23,000 tons of OCWs annually. This is less than

0.1 percent of the quantity of coal combustion wastes generated by the utility sector.

• Comprehensive waste quantity information for the non-utility oil burning sector is not

available. The Agency estimates that a maximum of 18,000 tons of OCWs are generated

annually by the non-utility sector. Of this amount, the Agency estimates about 5,500 tons

are collected; the remainder are released with stack gases. On average, this collected

amount would equate to about 1 ton per year per boiler unit.

• The constituents of concern in OCWs are trace metal elements. No organic constituents,

including dioxins, were identified at potential levels of concern in these wastes.

• OCWs only infrequently exhibit the RCRA toxicity characteristic. Six percent of the

samples in the Agency’s database exceeded the RCRA regulatory level for one or more of

the eight RCRA metals. These sample were represented by 7 of the 40 sites in the database. 

The exceedences involved chromium, arsenic, cadmium, and selenium.

• Although not RCRA metals, both nickel and vanadium in whole waste and leachate are

present at relatively high levels. Nickel and vanadium can range up to 4 percent and 20

percent, respectively, in the whole waste. These metals are naturally present in the source

crude oil. Vanadium levels can be high enough in OCWs to make it economically feasible

to process the wastes for recovery of vanadium.

• Based on the available data and engineering judgment, OCWs are not reactive, ignitable, or

corrosive.

Waste Management Practices

• OCWs are managed alone by some facilities and are comanaged with low-volume wastes at

other facilities. Utilities most often comanage oil fly ash with low-volume wastes in onsite

impoundments (settling basins), and eventually transfer and manage the solids in landfills. 

Bottom ash is typically managed dry and placed in landfills.
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-36 March 1999

• Settling basins used for onsite management are typically small, about 1 acre in size. Both

concrete-lined basins and unlined percolation/evaporation basins are in use by the utility

industry. The unlined basins are designed to discharge to ground water.

• Waste management survey information and anecdotal information suggests a recent trend

toward the increased use of liners for impoundments.

• There are several beneficial uses of OCWs. These include vanadium recovery, use in

concrete products, and use in structural fill materials. Comprehensive statistics do not exist

on the total amounts of waste that are managed through beneficial uses.

Potential Risks and Damage Cases

• EPA conducted a risk assessment that found a lack of potential human health risk for most

waste constituents. The Agency did identify potential human health risks via the groundwater pathway where these wastes are managed in unlined landfills and surface

impoundments for arsenic (cancer), nickel (non-cancer), and vanadium (non-cancer). The

identified risks are based on high-end risk scenarios in EPA’s risk modeling analysis for

human ingestion of well water influenced by release from the waste management unit. The

time to reach the health-based level for arsenic in ground water at the receptor well ranges

from 400 to 2,800 years. For nickel and vanadium, the times to reach the health-based

levels are 50 years and 10 years, respectively.

• The Agency identified no potential human health risks via non-ground-water pathways.

• The Agency believes there is no significant ecological risk posed by the relatively small

onsite surface impoundments and landfills used to manage these wastes.

• The Agency identified one damage case associated with management of these wastes, which

involved elevated levels of cadmium. The release was basically confined to the vicinity of

the facility and did not affect human receptors.

Existing Regulatory Controls, State, and Federal Requirements

• The utility industry, the sector that collects the majority of these wastes, has a significant

level of installed environmental controls for managing these wastes. All of the identified

landfills and about 60 percent of the impoundments used to manage these wastes are

currently lined. The recent trend for utility facilities is toward liners and ground-water

monitoring controls for these wastes.

• States have increasingly begun to impose controls on OCW management units. The

majority of states have regulatory permit programs, as well as general authority to require

siting controls, liners, leachate collection systems, ground-water monitoring, closure

controls, daily or other operational cover, and fugitive dust controls for waste management.

• In a few states with significant generation of OCWs, newer landfills must have liners and

other controls, but older landfills do not have to be retrofit with these controls.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 6-37

• In a few states with significant generation of OCWs, there are no specific design

requirements for surface impoundments used to store or manage these wastes. At least two

of these states permit discharges to ground water from the impoundment units.

Potential Costs and Impact of Regulation

• The Agency estimates that the total annual incremental compliance costs for mitigation of

the potential risks identified in this study (arsenic, nickel, vanadium by ground-water

pathway) would be nearly $2 million (1998$). These costs represent replacement of

existing unlined management units with lined management units, and implementing ground

water monitoring and leachate collection and treatment. These measures do not represent

implementation of full Subtitle C requirements, but rather modifications of such

requirements that could potentially be adopted under Section 3004(x) of RCRA.

• If these wastes were to be regulated under full Subtitle C, virtually all existing facilities

would be required to invest substantial funds and resources to modify existing management

practices. The total annual cost of full Subtitle C requirements would considerably exceed

the $2 million (1998$) estimate above.

• If beneficial uses of these wastes were subject to Subtitle C requirements, possibly all

beneficial use practices and markets would cease.

6.8.3 Recommendations

Following are the Agency’s recommendations for the wastes covered in this chapter. The

recommendations are based on EPA’s analysis of the eight Congressionally mandated study factors

(Section 1.2). These conclusions are subject to change based on continuing information collection,

continuing consultations with other government agencies and the Congress, and comments and new

information submitted to EPA during the comment period and any public hearings on this report. The

final Agency decision on the appropriate regulatory status for these wastes will be issued after receipt

and consideration of comments as part of the Regulatory Determination, which will be issued within 6

months.

1. The Agency is considering two approaches to address the potential risks that may be posed by

disposal of these wastes. One approach would be regulatory using Subtitle C authority and the

other would be to encourage voluntary changes in industry practices.

The Agency found in many cases that OCWs, whether managed alone or comanaged with lowvolume wastes, are seldom characteristically hazardous and may not present a significant risk to human

health and the environment. These cases include situations in which the wastes are managed in lined

units with adequate cover. The Agency believes that no significant ecological risks are posed by disposal

of these wastes. Only one damage case was identified and it did not affect human receptors.

In light of the results of EPA’s risk assessment, however, the Agency is concerned about

situations in which the wastes are managed in unlined units, particularly comanagement in settling basins

and impoundments that are designed and operated to discharge to ground water. As discussed in this

chapter, the Agency’s risk analysis suggests that three metals may pose potential ground-water pathway

risks at such facilities: arsenic, nickel, and vanadium. While there is a trend in recent years to line new

units and the Agency has anecdotal information that some facilities are preparing to either line or close

their unlined units, the Agency has particular concerns with the high levels of nickel and vanadium in the
Report to Congress on Wastes from the Combustion of Fossil Fuels

6-38 March 1999

wastes and in the leachate that is being discharged to ground water. The Agency’s risk analysis

identified high hazard quotients and short time periods to exceedence of health-based risk criteria at

potential ground-water receptor locations for nickel and vanadium. The risks identified with these

practices may be of sufficient concern to consider whether tailored regulations are necessary to target the

potential risks. On the other hand, since the recent industry and state regulatory trends have been toward

liners and ground-water monitoring for these waste disposal units, sufficient protection may be obtained

by facilitating this trend and engaging the industry to voluntarily establish the appropriate controls. An

example would be to line the existing unlined units and, where appropriate, to implement ground-water

monitoring. The Agency solicits comment on its tentative conclusion, specific approaches that could be

pursued to address these concerns, and the identification of only one damage case.

2. The Agency has tentatively concluded that the existing beneficial uses of these wastes should

remain exempt from Subtitle C.

There are few existing beneficial uses of these wastes, which include components of cement,

concrete, and construction fill as discussed in this chapter. No significant risks to human health exist for

the identified beneficial uses of these wastes. This is based on one or more of the following reasons for

each use: absence of identifiable damage cases, fixation of the waste in finished products which

immobilized the material, and/or low probability of human exposure to the material. In the case of

vanadium recovery operations, a valuable product is being produced; however, if the wastes resulting

from the metal recovery processes are hazardous, they will be subject to the existing hazardous waste

requirements.

Unlike coal combustion wastes, these wastes are not known to be used in minefill or agricultural

applications. These wastes are not generated at rates high enough to justify their transport and use for

filling mine voids. There are no known benefits to using these wastes for agricultural purposes.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 7-1

Figure 7-1. Number of Gas-Fired Power Plants by State

7.0 NATURAL GAS COMBUSTION WASTES

Natural gas is the second most significant fossil fuel used by utilities in the United States. In

1996, gas-fired units accounted for approximately 20 percent of utility generating capacity, but only

9 percent of utility electricity generated. This generation rate represents a decline of 15 percent from

the level reported in 1995 due in part to a substantial increase in the cost of gas in 1996. (Use of

hydroelectric, oil-fired, and geothermal sources increased in 1996 to make up for the decrease in use of

gas) (EIA, 1998a). Many gas-fired units are used to generate power during periods of peak demand. 

Figure 7-1 shows the locations of gas-fired power plants. Gas-fired units generate virtually no solid

waste. Thus, although a significant portion of capacity is represented by gas combustors, this study does

not include extensive analysis of natural gas combustors. The Agency intends to continue the exemption

from Resource Conservation and Recovery Act (RCRA) Subtitle C for gas combustors.

7.1 TECHNOLOGY

As shown in Table 7-1, natural gas combustion accounts for a substantial fraction of both utility

and non-utility generating capacity. Natural gas combustion technologies are similar to those used for oil

combustion. In gas-fired steam electric boilers, gas is injected into the furnace in the presence of excess

air. The same burner designs used for oil also are used to inject and combust natural gas. In fact, many

combustion units can utilize either oil or gas. Unlike oil, natural gas does not require preparation

(atomization) for mixing with combustion air (Stultz and Kitto, 1992). Because of its negligible ash 
Report to Congress on Wastes from the Combustion of Fossil Fuels

7-2 March 1999

content, combustion of natural gas generates virtually no solid waste; therefore, this study focuses

primarily on coal-fired and oil-fired combustors.

7.2 FINDINGS AND RECOMMENDATIONS

As discussed above, combustion of natural gas generates virtually no solid waste; therefore,

further analysis of the RCRA 8002(n) study factors is not warranted for gas fuels. EPA intends to

continue the exemption from RCRA Subtitle C for gas combustors.

7.2.1 Introduction

Based on the information collected for this Report to Congress, this section presents a summary

of the Agency’s main findings presented under headings that parallel the organization of this chapter. It

then presents the Agency’s tentative conclusions concerning the wastes from burning natural gas.

7.2.2 Findings

Sector Profile

• There are nearly 800 gas-fired boilers in the utility sector that represent about 22 percent of

utility power generating capacity.

• There are about 6,900 gas-fired boilers in the non-utility sector that represent about onethird of the non-utility power generating capacity.

Waste Generation and Characteristics

• There is virtually no solid waste that results from the combustion of natural (fossil fuel) gas.

7.2.3 Recommendations

Following are the Agency’s recommendations for the wastes covered in this chapter. The

recommendations are based on EPA’s analysis of the eight Congressionally mandated study factors

(Section 1.2). These conclusions are subject to change based on continuing information collection,

continuing consultations with other government agencies and the Congress, and comments and new

information submitted to EPA during the comment period and any public hearings on this report. The 

final Agency decision on the appropriate regulatory status for these wastes will be issued after receipt

and consideration of comments as part of the Regulatory Determination, which will be issued within

6 months.

Sector

Number of

Gas-Fired Boilers

Gas-Fired Capacity

(megawatts equivalent)

Total Sector Capacity

(megawatts equivalent)

Percent

Gas-Fired

Utility 788 104,961 469,272 22%

Non-Utility 6,907 46,663 148,021 32%

Total 7,695 151,624 621,884 24%

Because these capacity data are from different sources and different points in time, the percentages should be treated only as estimates.

Sources: EEI, 1994; EPA, 1990

Table 7-1. Natural Gas-Fired Generating Capacity
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 7-3

1. The Agency has tentatively concluded that it will retain the Subtitle C exemption for natural gas

combustors.

The Agency has tentatively concluded that it will retain the Subtitle C exemption for natural gas

combustors. The Agency solicits comment on whether it is appropriate to retain or remove the Subtitle C

exemption for natural gas combustion since there are no solid wastes generated by the process.
Report to Congress on Wastes from the Combustion of Fossil Fuels

7-4 March 1999
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 R-1

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Draft Report. Submitted to the Office of Solid Waste, prepared by Science Applications

International Corporation, Reston, Virginia. October.

EPA. 1998a. Characterization of Municipal Solid Waste in the United States: 1997 Update. Office of

Solid Waste, Municipal and Industrial Solid Waste Division. May.

EPA. 1998b. Characterization of Construction and Demolition Debris in the United States. Office of

Solid Waste, Municipal and Industrial Solid Waste Division. June.

EPA. 1998c. Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating

Units – Final Report to Congress. Volume 1. Office of Air Quality Planning and Standards. 

EPA-453/R-98-004a. February.

EPA. 1998d. Technical Background Document for the Supplemental Report to Congress on Remaining

Fossil Fuel Combustion Wastes: Ground-water Pathway Human Health Risk Assessment. 

Revised Draft Final. Office of Solid Waste. June.

EPA. 1998e. Non-groundwater Pathways, Human Health and Ecological Risk Analysis for Fossil Fuel

Combustion Phase 2 (FFC2). Draft Final. Prepared for EPA by the Research Triangle Institute,

Raleigh, North Carolina. April.

EPA. 1998f. Fossil Fuel Combustion Waste Risk Assessment: Revised Groundwater Analysis and

Sensitivity Results. October.

EPA. 1998g. Ecological Risk Assessment Guidelines.

EPA. 1998h. Technical Background Document: Beneficial Use of Fossil Fuel Combustion (FFC)

Wastes. Prepared by Science Applications International Corporation, McLean, Virginia. 

October.

EPRI (Electric Power Research Institute). 1987. Inorganic and Organic Constituents in Fossil Fuel

Combustion Residue, Volume 1: A Critical Review. EP-5176. August.

EPRI. 1991. Comanagement of Coal Combustion By-Products and Low-Volume Wastes: A

Southeastern Site. Final Report, EN-7545. Electric Power Research Institute. November, 1991.

EPRI. 1992. Comanagement of Coal Combustion By-Products and Low-Volume Wastes: A Midwestern

Site. Interim Report, TR-100955. August.

EPRI. 1994a. Calcium-Based Flue Gas Desulfurization Sludge Disposal Sites. Final Report,

TR-103914. Electric Power Research Institute. April, 1994.

EPRI. 1994b. Sodium-Based Flue Gas Desulfurization Sludge Disposal Ponds. Final Report,

TR-103915. April.

EPRI. 1996a. Comanagement of Coal Combustion By-Products and Low-Volume Wastes: A

Southwestern Site. Final Report, TR-105673. June.
Report to Congress on Wastes from the Combustion of Fossil Fuels

March 1999 R-5

EPRI. 1996b. Evaluation of the Co-Management of High Volume Combustion By-Products with Other

Utility Wastes: CL Site. Revised Draft Report. December.

EPRI. 1997a. Coal Combustion By-Products and Low-Volume Wastes Comanagement Survey. 

Electronic Database. June.

EPRI. 1997b. Coal Combustion By-Products and Low-Volume Wastes Comanagement Survey. Draft

Report. June.

EPRI. 1997c. Evaluation of the Co-Management of High Volume Combustion By-Products with Other

Utility Wastes: MO Plant. Draft Report. April.

EPRI. 1997d. Field Evaluation of the Comanagement of Utility Low-Volume Wastes with High-Volume

Combustion By-products: AP Site. Draft Report. June.

EPRI. 1997e. Field Evaluation of the Comanagement of Utility Low-Volume Wastes with High-Volume

Combustion By-products: SX Site. Draft Report, TR001015. June 1997.

EPRI. 1997f. Field Evaluation of the Comanagement of Utility Low-Volume Wastes with High-Volume

Coal Combustion By-products: P4 Site. Final Report, TR 108420. July.

EPRI. 1997g. Field Evaluation of the Comanagement of Utility Low-Volume Wastes with High-Volume

Coal Combustion By-products: OK Site. Draft Report, TR 108421. July.

EPRI. 1997h. Field Evaluation of the Comanagement of Utility Low-Volume Wastes with High-Volume

Coal Combustion By-products: HA Site. Draft Report. August.

EPRI. 1997i. Field Evaluation of the Comanagement of Utility Low-Volume Wastes with High-Volume

Coal Combustion By-products: FC Site. Draft Report, TR 108425. August.

EPRI. 1997j. Field Evaluation of the Comanagement of Utility Low-Volume Wastes with High-Volume

Coal Combustion By-products: LS Site. Final Report, TR 108422. August.

EPRI. 1997k. Field Evaluation of the Comanagement of Utility Low-Volume Wastes with High-Volume

Coal Combustion By-products: PA Site. Final Report, TR 108427. August.

EPRI. 1997l. Field Evaluation of the Comanagement of Utility Low-Volume Wastes with High-Volume

Coal Combustion By-products: CY Site. Final Report, TR 108426. August.

EPRI. 1997m. Characterization of Byproducts from Coburning with Coal in Utility Boilers. Draft

Report. August.

EPRI. 1997n. Oil Combustion By-Products Database. Electronic database. July.

EPRI. 1998a. Oil Combustion By-Products: Chemical Characteristics, Management Practices, and

Groundwater Effects. March.

EPRI. 1998b. PCDDs and PCDFs in Coal Combustion By-Products (CCBS). Final Report. March.
Report to Congress on Wastes from the Combustion of Fossil Fuels

R-6 March 1999

EPRI. 1999. Guidance for Comanagement of Mill Rejects at Coal-fired Power Plants. Draft,

TR-108994. January.

Elliott, Thomas, ed. 1989. Standard Handbook of Power Plant Engineering. New York: McGraw-Hill.

IEA (International Energy Agency Coal Research). 1996. Confiring of Coal and Waste. IEACR/90. 

August.

Morin, Roger A. 1994. Regulatory Finance: Utilities' Cost of Capital. Arlington, VA: Public Utilities

Reports, Inc.

PUR (Public Utilities Reports, Inc.). 1994. The Electric Industry in Transition. Series of conference

papers, June 14–15, Albany, New York.

Radian Corporation. 1988. Assessment of NORM Concentrations in Coal Ash and Exposure to Workers

and Members of the Public. Prepared for the Utility Solid Waste Activities Group (USWAG). 

June.

R.S. Means. 1997. Site Work and Landscape Cost Data. 16th annual edition. R.S. Means Company,

Inc., Kingston, Massachusetts.

R.S. Means. 1998a. Environmental Remediation Cost Data – Assembles. 4th annual edition. R.S.

Means Company, Inc., Kingston, Massachusetts, and Delta Technologies Group, Inc.,

Englewood, Colorado.

R.S. Means. 1998b. Environmental Remediation Cost Data – Unit Price. 4th annual edition. R.S.

Means Company, Inc., Kingston, Massachusetts, and Delta Technologies Group, Inc.,

Englewood, Colorado.

Stultz, S.C. and J.B. Kitto, eds. 1992. Steam: Its Generation and Use. Barberton, Ohio: Babcock &

Wilcox.

USDA (U.S. Department of Agriculture). 1998. Agricultural Uses of Municipal, Animal and Industrial

Byproducts. Conservation Research Report Number 4. January.

VDEQ (Virginia Department of Environmental Quality). 1994. Cogeneration of Steam and Electric

Power: Pollution Prevention Opportunities and Options. Office of Pollution Prevention. 

September.
Report to Congress on Wastes from the Combustion of Fossil Fuels

*

 References for this glossary include EIA, 1997d; EPA, 1988; CIBO, 1997c, and Stultz and Kitto, 1992.

March 1999 G-1

GLOSSARY*

ACAA – American Coal Ash Association.

air heater or air preheater – device that uses flue gases to preheat combustion input air.

air heater and precipitator washwater – wastes resulting from the periodic cleaning of the fireside

(i.e., the side exposed to hot combustion products) of heat exchanging surfaces.

air monitoring system – periodic collection and analysis of air samples near a waste management unit.

alkalinity – the amount of carbonates, bicarbonates, hydroxides, and silicates or phosphates in a liquid. 

Reported as grains per gallon, pH, or parts per million of carbonate. Indicated by a pH of greater than 7.

anthracite – a hard black lustrous rank of coal (see coal rank).

APC – air pollution control.

ash – incombustible material in fuel that can become waste after combustion.

ash fusion temperature – the temperature at which a cone of coal or coke ash exhibits certain melting

characteristics.

ASTM – American Society for Testing and Materials.

ASTSWMO – Association of State and Territorial Solid Waste Management Officials.

backfill – a project in which an excavation area is refilled with earth or other materials.

BACT – Best Available Control Technology under the Clean Air Act.

baghouse – an air pollution abatement device used to trap particulates by filtering gas streams through

large fabric bags usually made of glass fibers.

baseload – that portion of electricity demand from a station or boiler that is practically constant for long

periods.

baseload unit – an electrical generating unit that is used to supply baseload, and thus is operated

continuously at an essentially constant rate.

BAT – Best Available Technology Economically Achievable under the Clean Water Act.

bed ash – spent bed material and fuel ash (bottom ash) that settle on the bottom of an FBC boiler.

bituminous coal – A common dense black rank of coal (see coal rank).
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BMP – best management practice under the Clean Water Act.

boiler – a closed vessel in which heat from an external combustion source (such as a fossil fuel) is

transferred to produce hot water or generate steam.

boiler blowdown – waste generated by removal of a portion of boiler water for the purpose of reducing

solid concentration or discharging sludge.

boiler chemical cleaning waste – waste resulting from the cleaning of boiler surfaces using chemical

solutions.

boiler slag – melted and fused particles of ash that collect on the bottom of the boiler. Slag forms when

operating temperatures exceed ash fusion temperature.

bottom ash – large ash particles that settle on the bottom of a boiler. Bottom ash does not melt and

therefore remains in the form of unconsolidated ash.

BPT – Best Practicable Control Technology Currently Available under the Clean Water Act.

Btu – British Thermal Unit, a unit of heat energy.

bubbling fluidized bed system – a fluidized bed combustion system in which excess air passes through

the bed in the form of bubbles. These systems have air velocities of 5 to 12 feet per second and larger

bed particle size than circulating fluidized bed systems. These conditions result in a dense bed (45

pounds per cubic foot) with a well-defined surface.

Bunker C fuel oil – a residual fuel oil, also characterized as No. 6 fuel oil, which is used for commercial

and industrial heating, electricity generation, and to power ships.

CAA – Clean Air Act.

CCW – coal combustion waste.

CERCLA – the Comprehensive Environmental Response, Compensation, and Liability Act, commonly

referred to as Superfund.

CIBO – Council of Industrial Boiler Owners.

circulating fluidized bed system – a fluidized bed system that has high air velocities (as high as 30 feet

per second) and fine particle sizes. As a result, the fluid bed is less dense (35 pounds per cubic foot) and

has no well-defined top surface. Large quantities of bed material are recaptured from the gas stream and

recirculated back to the furnace to maintain bed inventory.

CMTP – Composite Model for Leachate Migration with Transformation Products.

coal cleaning – the act of processing coal prior to combustion to change its characteristics (e.g., size, ash

content, and/or sulfur content).

coal pile runoff – surface water runoff produced by precipitation falling on coal storage areas.
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coal mill rejects – solid waste produced by onsite processing of coal in a mill prior to use.

coal rank – a system of classifying coal corresponding to its degree of metamorphism, geologic age, and

heating value. Ranks include anthracite, bituminous, subbituminous, and lignite, with anthracite being

the oldest and lignite being the youngest.

cogeneration – the production of electricity and another form of useful thermal energy (steam or hot

water) from a single source.

combustion turbine (CT) – a system that uses exhaust from combustion (typically of oil or natural gas)

directly to drive turbines.

compaction – the act of compacting waste after placement to reduce or prevent wind and water erosion

of the waste and subsequent release to the environment.

condenser – a device that converts low-pressure steam back to water by transferring heat to a cooling

water system.

cooling tower/cooling pond – recirculating cooling water system used to transfer heat picked up in the

condenser to the atmosphere by evaporative cooling.

cooling tower basin sludge – solids that collect in the bottom of cooling towers and must be removed

periodically and disposed.

cooling tower blowdown – water withdrawn from the cooling system in order to control the

concentration of impurities in the cooling water.

corrosivity – see RCRA Subtitle C characteristics.

cover – a barrier placed on top of a waste management unit.

culm – refuse from the cleaning of anthracite coal.

CWA – Clean Water Act.

cyclone furnace – A combustion technology that creates a cyclone-like air circulation pattern causing

smaller particles to burn in suspension, while larger particles adhere to a molten layer of slag that forms

on the barrel walls. 

demineralizer regenerant and rinses – see regeneration waste streams.

dioxin – general term for polychlorinated dibenzo-p-dioxins (PCDDs), a class of toxic chemicals.

distillate fuel oil – one of the petroleum fractions produced in conventional distillation operations. 

Included are products known as No. 1, No. 2, and No. 4 fuel oils.

dry scrubber – a flue gas desulfurization system in which the resulting byproduct is a dry, typically fine,

powder.
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dust suppression/control – conditioning waste with water or other liquid before and during transport

and placement to prevent airborne transport of the waste and to reduce inhalation exposure to site

workers.

economizer – a device for transferring heat from combustion exhaust to boiler input water.

EEI – Edison Electric Institute.

EEI database – 1994 EEI Power Statistics Database.

EIA – The U.S. Department of Energy’s Energy Information Association.

electrostatic precipitator (ESP) – an air pollution control device that imparts an electrical charge to

particulates in a gas stream, causing them to collect on an electrode. 

EP – Extraction Procedure.

EPACMTP – EPA’s Composite Model for Leachate Migration with Transformation Products.

EPRI – Electric Power Research Institute.

fabric filter – see baghouse.

FGD – flue gas desulfurization.

flue gas – the gaseous products of combustion that exit a boiler through a flue or stack.

flue gas desulfurization (FGD) technology – device that is used to remove sulfur oxides from flue gas

after combustion.

flue gas desulfurization (FGD) waste – waste that is generated during the process of removing sulfur

oxide gas from the flue gas after combustion.

fluidized bed combustion (FBC) – a combustion process in which fuel is burned on a bed of

incombustible material (e.g., sand and limestone) while combustion air is forced upward at high

velocities, making the particles flow as a fluid.

fly ash – suspended, uncombusted ash particles carried out of the boiler along with flue gases.

fossil fuel – a naturally occuring organic fuel, including coal, oil, and natural gas.

Furan – general term for polychlorinated dibenzofurans (PCDFs), a class of toxic chemicals.

generating unit – a combination of one or more boilers operated together to produce electricity or other

useable thermal energy. May include one or more turbines, fuel processing systems, and/or air pollution

control devices.

gigawatt (GW) – one billion watts.
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gob – refuse from the cleaning of bituminous coal.

ground water monitoring system – one or several wells from which samples of ground water are

periodically collected and analyzed.

HAP – Hazardous Air Pollutant under the Clean Air Act.

HDPE – high density polyethylene.

ignitability – see RCRA Subtitle C characteristics.

kilowatt (kW) – one thousand watts.

landfill – a facility or part of a facility in which wastes are placed for disposal in or on land.

leachate – the liquid resulting from water percolating through waste.

leachate collection system – a series of drains and tubing placed beneath a waste management unit,

typically a landfill, that collect leachate for treatment or disposal.

lift – the depth of a cell in a landfill.

lignite – a brownish-black rank of coal (see coal rank).

lime – calcium oxide (CaO).

limestone – calcium carbonate (CaCO3).

liner – a barrier placed underneath a landfill or on the bottom and/or sides of a surface impoundment.

MCL – maximum contaminant level.

mechanical collector – an air pollution control device that forces a cyclonic flow of the exit gas. This

flow causes ash particles to be thrown against the walls of the collector and drop out of the gas.

megawatt (MW) – one million watts.

minefill – a project involving placement of fossil fuel combustion wastes in mine voids, whether for

purposes of disposal or for beneficial uses such as mine reclamation.

monofill – a landfill that contains only one type of waste.

NAAQS – National Ambient Air Quality Standards under the Clean Air Act.

natural gas – a fossil fuel consisting of a mixture of hydrocarbon and nonhydrocarbon gases found

beneath the Earth’s surface.

NESHAP – National Emissions Standards for Hazardous Air Pollutants under the Clean Air Act.
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No. 1 fuel oil – A light distillate fuel oil intended for use in vaporizing pot-type burners.

No. 2 fuel oil – A distillate fuel oil for use in atomizing-type burners for domestic heating or for

moderate capacity commercial-industrial burner units.

No. 4 fuel oil – a fuel oil for commercial burner installations not equipped with preheating facilities. It is

used extensively in industrial plants. This grade is a blend of distillate fuel oil and residual fuel oil

stocks.

No. 5 fuel oil – a residual fuel oil of medium viscosity.

No. 6 fuel oil – a residual fuel oil used for commercial and industrial heating, electricity generation, and

to power ships. Includes Bunker C fuel oil.

non-utility – for purposes of this study, an entity that combusts fossil fuel and whose primary

commercial activity is not the production of electricity (see utility).

NPDES – National Pollution Discharge Elimination System under the Clean Water Act.

NSPS – New Source Performance Standards under either the Clean Water Act or Clean Air Act.

OCW – oil combustion waste.

particulates – fine liquid or solid particles such as dust, smoke, mist, fumes, or smog, found in the air or

emissions.

PCB – polychlorinated biphenyls, a class of toxic chemicals.

PCDD – polychlorinated dibenzo-p-dioxin.

PCDF – polychlorinated dibenzofuran.

PDWS – Primary Drinking Water Standards established by the Safe Drinking Water Act.

peakload – the maximum electricity demand from a facility or boiler that occurs during a specified

period of time.

peakload unit or peaking unit – an electrical generating unit that is used to supply peakload, and thus is

used intermittently during periods of high demand.

percolation basin – a surface impoundment in which liquids are allowed to discharge (percolate) into

the ground.

petroleum coke – solid carbaceous residue remaining in oil refining stills after the distillation process.

PM – particulate matter.

pore water – interstitial water from borings of waste managed in surface impoundments.
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POTW – Publicly Owned Treatment Works.

pozzolanic – forming a strong, slow-hardening cement-like substance when mixed with lime or other

hardening material.

PSD – prevention of significant deterioration under the Clean Air Act.

PSES – Pretreatment Standards for Existing Sources under the Clean Water Act.

pulverized coal (PC) boiler or pulverizer – a combustion technology that burns finely ground coal in

suspension.

PVC – polyvinyl chloride.

pyrites – iron sulfide (FeS2) minerals that may oxidize during the combustion process to generate sulfur

oxide gases. Pyrites may be a component of coal mill rejects.

RCRA – Resource Conservation and Recovery Act, as amended (Pub. L. 94-580). The legislation under

which EPA regulates solid and hazardous waste.

RCRA Subtitle C characteristics – criteria used to determine if an unlisted waste is a hazardous waste

under Subtitle C of RCRA.

corrosivity – a solid waste is considered corrosive if it is aqueous and has a pH less than or equal

to 2 or greater than or equal to 12.5, or if it is a liquid and corrodes steel at a rate greater than

6.35 millimeters per year at a test temperature of 55C.

toxicity – a solid waste exhibits the characteristic of toxicity if, after extraction by a prescribed

EPA method, it yields a metal concentration 100 times the acceptable concentration limits set

forth in EPA’s primary drinking water standards.

ignitability – a solid waste exhibits the characteristic of ignitability if it is a liquid with a

flashpoint below 60o

C or a non-liquid capable of causing fires at standard temperature and

pressure.

reactivity – a waste is considered reactive if it reacts violently, forms potentially explosive

mixtures, or generates toxic fumes when mixed with water, or if it is normally unstable and

undergoes violent change without deteriorating.

reactivity – see RCRA Subtitle C characteristics.

regeneration waste streams – wastes resulting from periodic cleaning of ion exchange beds used to

remove mineral salts from boiler makeup water.

reinjection – the act of returning fly ash to a boiler to use any residual carbon content as fuel.

residual fuel oil – the heavier oils that remain after the distillate fuel oils and lighter hydrocarbons are

distilled away in refinery operations. Included are No. 5 fuel oil, Navy Special, and No. 6 fuel oil (which

includes Bunker C fuel oil).
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RIA – Regulatory Impact Analysis.

run-on and runoff control and collection system – Run-on controls prevent precipitation runoff from

other parts of a site from reaching waste management areas. Runoff controls and collection systems

prevent precipitation runoff from the waste management unit from being transported offsite.

scrubber – an air pollution control device used to remove particulates or contaminant gases from flue

gas (see wet scrubber and dry scrubber).

SDWS – Secondary Drinking Water Standards established by the Safe Drinking Water Act.

SIC – Standard Industrial Classification.

SIP – State Implementation Plan under the Clean Air Act.

slag – molten or fused solid matter.

sluice water – liquid used to transport combustion waste or other material.

sluiced ash – combustion waste that has been transported using liquid.

slurry – a mixture of insoluble matter in a fluid.

SPLP – Synthetic Precipitation Leaching Procedure.

spray canal – recirculating cooling water system used to transfer heat picked up in the condenser to the

atmosphere by evaporative cooling.

SSB – solids settling basin.

Standard Industrial Classification (SIC) code – a code developed by the U.S. government that

categorizes businesses into groups with similar economic activities.

steam electric boiler – a system that combusts fuel in a boiler to produce steam, which in turn is used to

provide heat or steam or drive turbines.

stoker – a combustion technology using a mechanically operated fuel feeding mechanism to distribute

solid fuel over a grate for combustion.

subbituminous coal – an intermediate ranked coal between lignite and bituminous with more carbon and

less moisture than lignite (see coal rank).

superheater – a device that follows a boiler and uses exhaust gases from combustion to raise the

temperature of steam generated in the boiler.

surface impoundment – a facility that is a natural topographic depression, artificial excavation, or diked

area formed primarily of earthen materials (although it may be lined with artificial materials), which is

designed to hold an accumulation of liquid wastes containing free liquids.
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surface water monitoring system – periodic collection and analysis of surface water samples near a

waste management unit.

TCLP – Toxicity Characteristic Leaching Procedure.

toxicity – see RCRA Subtitle C characteristics.

TSS – total suspended solids.

UCCW – utility coal combustion waste.

unit – see generating unit or waste management unit.

USWAG – Utility Solid Waste Activities Group.

utility – a private or public organization that generates, transmits, distributes, or sells electricity. For

purposes of this study, includes independent power producers regulated under the Public Utility

Regulatory Policies Act (PURPA).

waste management unit – a structure, typically a landfill or surface impoundment, in which waste is

placed for disposal or storage.

wastewater treatment sludge – waste generated from the treatment in settling basins or other treatment

facilities of liquid waste streams.

water treatment sludge – waste resulting from treatment of makeup water for the steam cycle or for

non-contact cooling.

watt – a unit of electrical power.

wet scrubber – a device utilizing a liquid, designed to separate particulate matter or gaseous

contaminants from a gas stream by one or more mechanisms such as absorption, condensation, diffusion,

or inertial impaction.
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