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Profile Of The
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NOTEBOOKS
EFA Office Of Compliance Sector Notebook Project
-------
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
f8 1997
THE ADMINISTRATOR
Message from the Administrator
Since EPA's founding over 25 years ago, our nation has made tremendous progress in protecting
public health and our environment while promoting economic prosperity. Businesses as large as
iron and steel plants and those as small as the dry cleaner on the corner have worked with EPA to
find ways to operate cleaner, cheaper and smarter. As a result, we no longer have rivers catching
fire. Our skies are clearer. American environmental technology and expertise are in demand
around the world.
The Clinton Administration recognizes that to continue this progress, we must move beyond the
pollutant-by-pollutant approaches of the past to comprehensive, facility-wide approaches for the
future. Industry by industry and community by community, we must build a new generation of
environmental protection.
The Environmental Protection Agency has undertaken its Sector Notebook Project to compile,
for major industries, information about environmental problems and solutions, case studies and
tips about complying with regulations. We called on industry leaders, state regulators, and EPA
staff with many years of experience in these industries and with their unique environmental issues.
Together with an extensive series covering other industries, the notebook you hold in your hand is
the result.
These notebooks will help business managers to understand better their regulatory requirements,
and learn more about how others in their industry have achieved regulatory compliance and the
innovative methods some have found to prevent pollution in the first instance. These notebooks
will give useful information to state regulatory agencies moving toward industry-based programs.
Across EPA we will use this manual to better integrate our programs and improve our compliance
assistance efforts.
I encourage you to use this notebook to evaluate and improve the way that we together achieve
our important environmental protection goals. I am confident that these notebooks will help us to
move forward in ensuring that in industry after industry, community after community ~
environmental protection and economic prosperity go haj^in hand.
Carol M. Browner
R«cycl*d/R*cyclib!« Printed with Vegetable OH Based Inks on 100% Recycled Paper (40% Postconsumer)
-------
Fossil Fuel Electric Power Generation
Sector Notebook Project
EPA/310-R-97-007
EPA Office of Compliance Sector Notebook Project
Profile of the Fossil Fuel Electric Power Generation Industry
September 1997
Office of Compliance
Office of Enforcement and Compliance Assurance
U.S. Environmental Protection Agency
401 M St., SW (MC 2223-A)
Washington, DC 20460
For sale by the U.S. Government Printing Office
Superintendent of Documents, Mail Stop: SSOP, Washington, DC 20402-9328
ISBN 0-16-049399-4
Sector Notebook Project
September 1997
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Fossil Fuel Electric Power Generation
Sector Notebook Project
This report is one in a series of volumes published by the U.S. Environmental Protection Agency
(EPA) to provide information of general interest regarding environmental issues associated with
specific industrial sectors. The documents were developed under contract by Abt Associates
(Cambridge, MA), Science Applications International Corporation (McLean, VA), and Booz-
Allen & Hamilton, Inc. (McLean, VA). This publication may be purchased from the
Superintendent of Documents, U.S. Government Printing Office. A listing of available Sector
Notebooks and document numbers is included at the end of this document.
All telephone orders should be directed to:
Superintendent of Documents
U.S. Government Printing Office
Washington, DC 20402
(202)512-1800
FAX (202) 512-2250
8:00 a.m. to 4:30 p.m., EST, M-F
Using the form provided at the end of this document, all mail orders should be directed to:
U.S. Government Printing Office
P.O. Box 371954
Pittsburgh, PA 15250-7954
Complimentary volumes are available to certain groups or subscribers, such as public and
academic libraries, Federal, State, and local governments, and the media from EPA's National
Center for Environmental Publications and Information at (800) 490-9198. For further
information, and for answers to questions pertaining to these documents, please refer to the
contact names and numbers provided within this volume.
Electronic versions of all Sector Notebooks are available via Internet on the Enviro$en$e World
Wide Web. Downloading procedures are described in Appendix A of this document.
Cover photograph courtesy of Arizona Electric Power Cooperative, Inc.
Sector Notebook Project
September 1997
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Fossil Fuel Electric Power Generation
Sector Notebook Project
Sector Notebook Contacts
The Sector Notebooks were developed by the EPA's Office of Compliance. Questions relating
to the Sector Notebook Project can be directed to:
Seth Heminway, Coordinator, Sector Notebook Project
US EPA Office of Compliance
401 M St., SW (2223-A)
Washington, DC 20460
(202) 564-7017
Questions and comments regarding the individual documents can be directed to the appropriate
specialists listed below.
Document Number
EPA/310-R
EPA/310-R
EPA/310-R
EPA/310-R
EPA/310-R
EPA/310-R
EPA/310-R
EPA/310-R
EPA/310-R-
EPA/310-R
EPA/310-R
EPA/310-R
EPA/310-R-
EPA/310-R-
EPA/310-R-
EPA/310-R
EPA/310-R-
EPA/310-R-
EPA/310-R-
EPA/310-R-
EPA/310-R-
EPA/310-R-
EPA/310-R
EPA/310-R-
EPA/310-R-
EPA/310-R-
EPA/310-R-
EPA/310-R-
-95-001.
-95-002.
-95-003.
-95-004.
-95-005.
-95-006.
-95-007.
-95-008.
-95-009.
-95-010.
-95-011.
-95-012.
-95-013.
-95-014.
-95-015.
95-016.
-95-017.
-95-018.
97-001.
97-002.
97-003.
97-004.
97-005.
97-006.
97-007.
97-008.
97-009.
97-010.
Industry
Dry Cleaning Industry
Electronics and Computer Industry
Wood Furniture and Fixtures Industry
Inorganic Chemical Industry
Iron and Steel Industry
Lumber and Wood Products Industry
Fabricated Metal Products Industry
Metal Mining Industry
Motor Vehicle Assembly Industry
Nonferrous Metals Industry
Non-Fuel, Non-Metal Mining Industry
Organic Chemical Industry
Petroleum Refining Industry
Printing Industry
Pulp and Paper Industry
Rubber and Plastic Industry
Stone, Clay, Glass, and Concrete Ind.
Transportation Equip. Cleaning Ind.
Air Transportation Industry
Ground Transportation Industry
Water Transportation Industry
Metal Casting Industry
Pharmaceuticals Industry
Plastic Resin and Manmade Fiber Ind.
Fossil Fuel Elec. Power Generation Ind.
Shipbuilding and Repair Industry
Textile Industry
Sector Notebook Data Refresh, 1997
Contact
Joyce Chandler
Steve Hoover
Bob Marshall
Walter DeRieux
Maria Malave
Seth Heminway
Scott Throwe
Anthony Raia
Anthony Raia
Jane Engert
Anthony Raia
Walter DeRieux
Tom Ripp
Ginger Gotiiffe
Maria Eisemann
Maria Malave
Scott Throwe
Virginia Lathrop
Virginia Lathrop
Virginia Lathrop
Virginia Lathrop
Jane Engert
Emily Chow
Sally Sasnett
Rafael Sanchez
Anthony Raia
Belinda Breidenbach
Seth Heminway
Phone (202)
564-7073
564-7007
564-7021
564-7067
564-7027
564-7017
564-7013
564-6045
564-6045
564-5021
564-6045
564-7067
564-7003
564-7072
564-7016
564-7027
564-7013
564-7057
564-7057
564-7057
564-7057
564-5021
564-7071
564-7074
564-7028
564-6045
564-7022
564-7017
Sector Notebook Project
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FOSSIL FUEL ELECTRIC POWER GENERATION INDUSTRY
(SIC 4911, 493)
TABLE OF CONTENTS
LIST OF TABLES iv
LIST OF FIGURES vi
LIST OF ABBREVIATIONS AND ACRONYMS vii
I. INTRODUCTION TO THE SECTOR NOTEBOOK PROJECT 1
A. Summary of the Sector Notebook Project 1
B. Additional Information 2
II. INTRODUCTION TO THE FOSSIL FUEL ELECTRIC POWER GENERATION
INDUSTRY 3
A. Introduction, Background, and Scope of the Notebook 3
B. Characterization of the Fossil Fuel Electric Power Generation Industry 4
1. Product Characterization 5
2. Industry Size and Geographic Distribution of the Fossil Fuel Electric Power
Generation Industry 5
3. Industry Size and Geographic Distribution of Traditional Utilities 7
4. Industry Size and Geographic Distribution of Nonutilities 13
5. Economic Trends ; 19
III. INDUSTRIAL PROCESS DESCRIPTION 23
A. Industrial Processes in the Fossil Fuel Electric Generation Industry 23
1. Steam Turbine Generation 23
2. Internal Combustion Generation 32
3. Gas Turbine Generation 33
4. Combined-Cycle Generation 34
5. Cogeneration 35
6. Supporting Operations 36
B. Raw Material Inputs and Pollution Outputs 38
1. Fossil Fuels and Other Raw Material Inputs 38
2. Pollutant Outputs 40
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IV. WASTE RELEASE PROFILE 47
A. Available Solid Waste Release Data for the Fossil Fuel Electric Power Generation
Industry 47
B. Available Water Release Information for the Fossil Fuel Electric Power
Generation Industry 51
C. Available Air Emissions Data for the Fossil Fuel Electric Power Generation
Industry 53
1. Annual Emissions Estimated by the Department of Energy,
Energy Information Administration 53
2. AIRS Database Annual Estimated Releases for the Electric
Power Generation Industry 54
3. Hazardous Air Pollutant Emissions Estimates for Fossil Fuel Electric Utility
Steam Generating Units 56
V. POLLUTION PREVENTION OPPORTUNITIES 71
A. Pollution Prevention Technologies in the DOE Clean Coal Technology
Demonstration Program 72
1. Emerging Technologies 72
2. Coal Processing for Clean Fuels 76
B. Other Pollution Prevention Technologies 77
C. Other Pollution Prevention and Waste Minimization Opportunities 79
1. Process or Equipment Modification Options 79
2. Inventory Management and Preventative Maintenance for
Waste Minimization 85
3. Potential Waste Segregation and Separation Options 86
4. Recycling Options 87
5. Facility Maintenance Wastes 89
6. Storm Water Management Practices 92
7. Training and Supervision Options 94
8. Demand-Side Management Programs 94
VI. SUMMARY OF APPLICABLE FEDERAL STATUTES AND REGULATIONS .... 95
A. General Description of Major Statutes 95
B. Industry-Specific Requirements 106
C. Pending and Proposed Regulatory Requirements 116
VH. COMPLIANCE AND ENFORCEMENT HISTORY 119
A. Fossil Fuel Electric Power Generation Industry Compliance History 123
B. Comparison of Enforcement Activity Between Selected Industries 125
C. Review of Major Legal Actions 130
1. Review of Major Cases 130
2. Supplemental Environmental Projects 131
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VIII. COMPLIANCE ASSURANCE ACTIVITIES AND INITIATIVES 133
A. Sector-Related Environmental Programs and Activities 133
B. EPA Voluntary Programs 134
C. Trade Association/Industry Sponsored Activity 137
1. Environmental Programs 138
2. Summary of Trade Associations 138
IX.
CONTACTS/ACKNOWLEDGMENTS/RESOURCE MATERIALS/
BIBLIOGRAPHY
143
APPENDIX A - INSTRUCTIONS FOR DOWNLOADING THIS NOTEBOOK A-l
Sector Notebook Project
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LIST OF TABLES
Table 1: Comparison of Utility and Nonutility Electric Power Generation (1995) 6
Table 2: Revenues From Major Utility Generators (1995) 9
Table 3: Top Ten Investor-Owned Utilities Ranked by Revenue From Sales to
Ultimate Consumers (1995) 9
Table 4: Top Ten Publicly Owned Generator Utilities Ranked by Megawatt Sales
to Ultimate Consumers (1994) 10
Table 5: Existing Capacity of All U.S. Utilities by Prime Mover (fossil fuels,
renewable fuels, and other fuels) (1995) 12
Table 6: Fossil-Fueled Utility Capacity by Prime Mover (1995) .12
Table 7: Utility Generating Capability and Net Generation by Energy Source (1995) ... 13
Table 8: Major SIC Codes and Industrial Categories Where Nonutility Power
Generation Activities Are Found 16
Table 9 : Existing Capacity of Nonutilities by Prime Mover (1995) 18
Table 10: Nonutility Capacity by Fossil Fuel Energy Source (1995) 18
Table 11: 1995 Nonutility Net Generation by Primary Fossil Fuel Energy Source and
Type of Producer (thousand megawatthours) 19
Table 12: Characteristics of Various Types of Stokers 26
Table 13: Summary of Typical Waste Streams and Pollutants Generated at Fossil
Fuel Electric Power Generation Facilities Based on Fuel Type 43
Table 14: Generation and Disposition of Utility Fly and Bottom Ash, 1994 (thousand
short tons) 48
Table 15: Generation and Disposition of Utility FGD Sludge, 1994 (thousand short
tons) 49
Table 16: Estimated Nonutility Generation of Coal Ash, 1990 50
Table 17: List of Pollutants Reported in 1992 PCS Data from Steam Electric Facilities .. 52
Table 18: Estimated 1995 Emissions From Fossil Fuel Steam Electric Generating
Units at Electric Utilities by Fuel Type (thousand short tons) 53
Table 19: Criteria Pollutant Releases (short tons/year) 55
Table 20: Estimated Releases of TRI Chemicals 58
Table 21: Median Emission Factors Determined From Test Report Data, and Total
1990 and 2010 HAP Emissions, Projected With the Emission Factor
Program for Inorganic HAPs From Coal-Fired Units 61
Table 22: Median Emission Factors Determined From Test Report Data, and Total
1990 and 2010 HAP Emissions, Projected With the Emission Factor Program
for Inorganic HAPs From Oil-Fired Units 62
Table 23: Median Emission Factors Determined From Test Report Data, and Total
1990 and 2010 HAP Emissions, Projected With the Emission Factor Program
for Inorganic HAPs From Gas-Fired Units 63
Table 24: Median Emission Factors From Test Report Data, and Total 1990 and 2010
HAP Emissions, Projected With the Emission Factor Program for Organic
HAPs From Coal-Fired Units 64
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Table 25: Median Emission Factors from Test Report Data, and Total 1990 and 2010
HAP Emissions, Projected with the Emission Factor Program for Organic
HAPs from Oil Fired Units 68
Table 26: Median Emission Factors From Test Report Data, and Total 1990 and 2010
HAP Emissions, Projected With the Emission Factor Program for Organic
HAPs From Gas-Fired Units 70
Table 27: Summaries of Clean Coal Technologies Under DOE's Clean Coal
Technology Demonstration Program 73
Table 28: Pollution Prevention Opportunities for Reducing Cooling Tower Emissions ... 81
Table 29: Pollution Prevention Options for Fireside Washes 82
Table 30: Pollution Prevention Options for Boiler Cleaning Wastes 85
Table 31: Inventory Management and Preventative Maintenance Waste Minimization
Opportunities 87
Table 32: Current and Potential Uses for Fly Ash 88
Table 33: Pollution Prevention Opportunities For Facility Maintenance Wastes 91
Table 34: Common Pollution Prevention Practices for Managing Runoff at Coal
Storage and Handling Areas 92
Table 35: Storm Water Pollution Prevention Opportunities at Fossil Fuel Electric
Power Generation Facilities 93
Table 36: New Source Performance Standards 109
Table 37: Waste Streams and Pollutants Regulated Under National Effluent Limitation
Guidelines for the Steam Electric Generating Point Source Category 113
Table 38: Five-Year Enforcement and Compliance Summary for the Fossil Fuel
Electric Power Generation Industry 124
Table 39: One-Year Enforcement and Compliance Summary for Selected Industries ... 126
Table 40: Five-Year Enforcement and Compliance Summary for Selected Industries ... 127
Table 41: Five-Year Inspection and Enforcement Summary by Statute for Selected
Industries 128
Table 42: One-Year Inspection and Enforcement Summary by Statute for Selected
Industries 129
Table 43: List of Power Plants That Participated in the Environmental Leadership
Program For 1995 and 1996 135
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LIST OF FIGURES
Figure 1: Total Utility and Nonutility Electric Power Net Generation Based on Fuels (1995) . 7
Figure 2: Total Utility Electricity Sales to Ultimate Consumers 8
Figure 3: Geographic Distribution of U.S. Utility Electric Power Net Generation 11
Figure 4: Nonutility Capacity by Type of Producer 15
Figure 5: Geographic Distribution of U.S. Nonutility Electric Power Net Generation 17
Figure 6: Steam Turbine Generation 25
Figure 7: Stoker Coal Feeder 27
Figure 8: Typical Cyclone Coal Burners 28
Figure 9: Tangential Firing Pattern 29
Figure 10: Flow Pattern of Horizontal Firing 30
Figure 11: Flow Pattern of Arch Firing 31
Figure 12: Typical Bubbling Fluidized-Bed Boiler 32
Figure 13: Simple Gas Turbine Cycle 33
Figure 14: Combined Cycle with Heat Recovery 34
Figure 15: Cogeneration Plant Schematic 36
Figure 16: Waste Streams Generated at a Typical Fossil Fuel Electric Power Generation
Plant 44
Sector Notebook Project
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Fossil Fuel Electric Power Generation
Sector Notebook Project
LIST OF ABBREVIATIONS AND ACRONYMS
ACAA American Coal Ash Association
AEE Association of Energy Engineers
AEPCO Arizona Electric Power Cooperative
AFS AIRS Facility Subsystem (CAA database)
AIRS Aerometric Information Retrieval System (CAA database)
APPA American Public Power Association
ANL Argonne National Laboratory
B ACT Best Available Control Technology
BIFs Boilers and Industrial Furnaces (RCRA)
BOD Biochemical Oxygen Demand
BPJ Best Professional Judgment
BTU British Thermal Unit
CAA Clean Air Act
CAAA Clean Air Act Amendments of 1990
CaCl2 Calcium Chloride
C API Clean Air Power Initiative
CCGT Combined-Cycle Gas Turbine
CCP Coal Combustion Product
CCT Clean Coal Technology Demonstration Project (DOE)
CERCLA Comprehensive Environmental Response, Compensation, and Liability Act
CERCLIS CERCLA Information System
CEQ Council for Environmental Quality
CFC Chlorofluorocarbon
CHIEFs Clearing House of Inventory Emissions Factors
CO Carbon Monoxide
CO2 Carbon Dioxide
COD Chemical Oxygen Demand
CP&L Carolina Power and Light
CSI Common Sense Initiative
CWA Clean Water Act
D&B Dun and Bradstreet Marketing Index
DOE Department of Energy
DSA Dimensionally stable
DSM Demand Side Management
EA Environmental Assessment
EDS Effluent Data Statistics System
EEI Edison Electric Institute
EIA Energy Information Administration (DOE)
EIS Environmental Impact Statement
ELP Environmental Leadership Program
EMS Environmental Management System
Sector Notebook Project
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Fossil Fuel Electric Power Generation
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EPA U.S. Environmental Protection Agency
EPACT Energy Policy Act of 1992
EPCRA Emergency Planning and Community Right-to-Know Act
EPRI Electric Power Research Institute
EPSA Electric Power Supply Association
EWG Exempt Wholesale Generators
FAC Free Available Chlorine
FBC Fluidized Bed Combustion
FERC Federal Energy Regulatory Commission
FGD Flue Gas Desulfurization
FIFRA Federal Insecticide, Fungicide, and Rodenticide Act
FINDS Facility Indexing System
FONSI Finding of No Significant Impact
HAPs Hazardous Air Pollutants (CAA)
HCFC Hydrochloroflourocarbon
HSDB Hazardous Substances Data Bank
HSWA Hazardous and Solid Waste Amendments of 1984
IDEA Integrated Data for Enforcement Analysis
ICCR Industrial Combustion Coordinated Rulemaking
IGCC Integrated Coal Gasification Combined-cycle
IPP Independent Power Producer
KW Kilowatt
LAER Lowest Achievable Emissions P.ate
LDR Land Disposal Restrictions (RCRA)
LEPC Local Emergency Planning Committee
MACT Maximum Achievable Control Technology (CAA)
MCL Maximum Contaminant Level
MCLG Maximum Contaminant Level Goal
MEK Methyl Ethyl Ketone
MSDS Material Safety Data Sheet
MW Megawatt
NAAQS National Ambient Air Quality Standards (CAA)
NAFCOG North American Fuel Cell Owner Group
NAFTA North American Free Trade Agreement
NAICS North American Industry Classification System
NCDB National Compliance Database (for TSCA, FIFRA, EPCRA)
NCP National Oil and Hazardous Substances Pollution Contingency Plan
NEPA National Environmental Policy Act
NERC North American Reliability Council
NEIC National Enforcement Investigation Center
NESHAP National Emission Standards for Hazardous Air Pollutants
NGFC Natural Gas Fuel Cell
NMHC Non-Methane Hydrocarbon
NO2 Nitrogen Dioxide
NOV Notice of Violation
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NOX Nitrogen Oxide
NPDES National Pollutant Discharge Elimination System (CWA)
NPL National Priorities List
NRECA National Rural Electric Cooperative Association
NRC National Response Center
NSR New Source Review
NSPS New Source Performance Standards (CAA)
OAR Office of Air and Radiation
OAQPS Office of Air Quality Planning and Standards
OEC A Office of Enforcement and Compliance Assurance
OIT Office of Industrial Technology (DOE)
OPA Oil Pollution Act
OPPTS Office of Prevention, Pesticides, and Toxic Substances
OSHA Occupational Safety and Health Administration
OSW Office of Solid Waste
OSWER Office of Solid Waste and Emergency Response
OTAG Ozone Transport Assessment Group
OW Office of Water
P2 Pollution Prevention
PAH Polycyclic Aromatic Hydrocarbon
Pb Lead
PCB Polychlorinated Biphenyl
PCS Permit Compliance System (CWA Database)
PEPCO Potomac Electric Power Company
PETC Pittsburgh Energy Technology Center
PM Particulate Matter
PMN Premanufacture Notice
POTW Publicly Owned Treatment Works
PSD Prevention of Significant Deterioration (CAA)
PSES Pretreatment Standards for Existing Sources
PSNS Pretreatment Standards for New Sources
PSE&G Public Service Electric and Gas
PT Total Particulate Emissions
PUHCA Public Utility Holding Company Act
PURPA Public Utility Regulatory Policies Act
QF Qualifying Facility (PURPA)
RACT Reasonably Achievable Control Technology
RCRA Resource Conservation and Recovery Act
RCRIS RCRA Information System
RDF Refuse Derived Fuel
SARA Superfund Amendments and Reauthorization Act
SDWA Safe Drinking Water Act
SEP Supplementary Environmental Project
SERC State Emergency Response Commission
SIC Standard Industrial Classification
Sector Notebook Project
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Fossil Fuel Electric Power Generation
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SIP State Implementation Plan (CAA)
SO2 Sulfur Dioxide
SOX Sulfur Oxides
TCRIS Toxic Chemical Release Inventory System
TDSS Total Dissolved Suspended Solids
TOC Total Organic Carbon
TRC Total Residual Chlorine
TRI Toxic Release Inventory
TRIS Toxic Release Inventory System
TSCA Toxic Substances Control Act
TSDF Treatment, Storage, or Disposal Facility (RCRA)
TSS Total Suspended Solids
UARG Utility Air Regulatory Group
UIC Underground Injection Control (SDWA)
UST Underground Storage Tanks (RCRA)
USWAG Utility Solid Waste Activities Group
UWAG Utility Water Act Group
VOC Volatile Organic Compound
Sector Notebook Project
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September 1997
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Fossil Fuel Electric Power Generation
Section I. Intro, to the Sector Notebook Project
FOSSIL FUEL ELECTRIC POWER GENERATION INDUSTRY
(SIC 4911,493)
I. INTRODUCTION TO THE SECTOR NOTEBOOK PROJECT
LA. Summary of the Sector Notebook Project
Integrated environmental policies based upon comprehensive analysis of air,
water, and land pollution are a logical supplement to traditional single-media
approaches to environmental protection. Environmental regulatory agencies
are beginning to embrace comprehensive, multi-statute solutions to facility
permitting, enforcement and compliance assurance, education/outreach,
research, and regulatory development issues. The central concepts driving
the new policy direction are that pollutant releases to each environmental
medium (i.e., air, water, and land) affect each other and that environmental
strategies must actively identify and address these inter-relationships by
designing policies for the "whole" facility. One way to achieve a whole
facility focus is to design environmental policies for similar industrial
facilities. By doing so, environmental concerns that are common to the
manufacturing of similar products can be addressed in a comprehensive
manner. Recognition of the need to develop the industrial "sector-based"
approach within the U.S. Environmental Protection Agency (EPA) Office of
Compliance led to the creation of this document.
The Sector Notebook Project was originally initiated by the Office of
Compliance within the Office of Enforcement and Compliance Assurance
(OECA) to provide its staff and managers with summary information for 18
specific industrial sectors. As other EPA offices, states, the regulated
community, environmental groups, and the public became interested in this
project, the scope of the original project was expanded to its current form.
The ability to design comprehensive, common sense environmental
protection measures for specific industries depends on knowledge of several
interrelated topics. For the purposes of this project, the key elements chosen
for inclusion are general industry information (economic and geographic); a
description of industrial processes; pollution outputs; pollution prevention
opportunities; Federal statutory and regulatory framework; compliance
history; and a description of partnerships that have been formed between
regulatory agencies, the regulated community, and the public.
For any given industry, each topic listed above could alone be the subject of
a lengthy volume. However, in order to produce a manageable document,
however, this project focuses on providing summary information for each
topic. This format provides the reader with a synopsis of each issue and
references where more in-depth information is available. Text within each
profile was researched from a variety of sources and was usually condensed
Sector Notebook Project
1
September 1997
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Fossil Fuel Electric Power Generation
Section I. Intro, to the Sector Notebook Project
I.E.
from more detailed sources pertaining to specific topics. This approach
allows for a wide coverage of activities that can be further explored based
upon the citations and references listed at the end of this profile. To check
the information included, each notebook went through an external review
process. The Office of Compliance appreciates the efforts of all those who
participated in this process who enabled the development of more complete,
accurate, and up-to-date summaries. Many of those who reviewed this
notebook are listed as contacts in Section DC and may be sources of additional
information. The individuals and groups on this list do not necessarily
concur with all statements within this notebook.
Additional Information
Providing Comments
The OECA Office of Compliance plans to periodically review and update the
notebooks and will make these updates available both in hard copy and
electronically. If you have any comments on the existing notebook, or if you
would like to provide additional information, please send a hard copy and
computer disk to the EPA Office of Compliance, Sector Notebook Project
(2223-A), 401 M Street, SW, Washington, DC 20460. Comments can also
be uploaded to the Enviro$en$e World Wide Web for general access to all
users of the system. Follow instructions in Appendix A for accessing this
system. Once you have logged in, procedures for uploading text are available
from the on-line Enviro$en$e Help System.
Adapting Notebooks to Particular Needs
The scope of the industry sector described in this notebook approximates the
national occurrence of facility types within the sector. In many instances,
industries within specific geographic regions or states may have unique
characteristics that are not fully captured in these profiles. The Office of
Compliance encourages state and local environmental agencies and other
groups to supplement or repackage the information included in this notebook
to include more specific industrial and regulatory information that may be
available. Additionally, interested states may want to supplement the
"Summary of Applicable Federal Statutes and Regulations" section with state
and local requirements. Compliance or technical assistance providers may
also want to develop the "Pollution Prevention" section in more detail.
Please contact the appropriate specialist listed on the opening page of this
notebook if your office is interested in assisting us in further development of
the information or policies addressed within this volume. If you are
interested hi assisting hi the development of new notebooks for sectors not
covered in the original 18, please contact the Office of Compliance at (202)
564-2395.
Sector Notebook Project
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Fossil Fuel Electric Power Generation
Section II. Introduction to the Industry
II. INTRODUCTION TO THE FOSSIL FUEL ELECTRIC POWER GENERATION
INDUSTRY
This Sector Notebook addresses the fossil fuel electric power generation
industry, which comprises the majority of the total electric power generation
industry. This subset of the industry includes only facilities that use either
coal, petroleum, or gas as the energy source to generate electricity and does
not include facilities that use nuclear or renewable (e.g., wood, solar) energy
sources exclusively. However, this subset would include power generation
activities at facilities that use both fossil fuels and another energy source. In
addition, the scope of this profile is further limited to address only those
facilities that generate electricity either as a primary activity or as an ancillary
activity. The profile does not include facilities and activities associated with
the transmission and distribution of electricity.
II.A Introduction, Background, and Scope of the Notebook
Fossil fuel electric power generation facilities are classified under Standard
Industrial Classification (SIC) code 49, which includes establishments
engaged in electric, gas, and sanitary services. These facilities can be further
classified under the following three- and four-digit SIC codes from the
Standard Industrial Classification (SIC) Manual of the Office of
Management and Budget.
SIC 4911 - Electric Services: Establishments that are engaged in the
generation, transmission, and/or distribution of electric energy for sale.
SIC 493 - Combination Electric and Gas, and Other Utility Services:
Establishments providing electric or gas services in combination with
other services. Establishments are classified here only if one service does
not constitute at least 95 percent of revenues.
It should be noted that these SIC codes do not make the necessary
distinctions between fuels used and generation versus transmission and
distribution activities. Data available to characterize the fossil fuel electric
power generation industry that use these SIC codes also may not distinguish
between these categories of facilities. Where these categories of facilities
and/or activities cannot be distinguished in the available data, it will be so
noted within the profile.
Fossil fuel electric power generation facilities are also classified under a new
system called the North American Industry Classification System (NAICS),
which replaced the existing SIC codes in January 1997. The NAICS
classification code for fossil fuel electric power generation is 221112.
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Power generation facilities and activities exist in association with both
traditional utilities or nonutility power producers. Traditional utilities are the
regulated industry that produces and provides electricity for public use. Prior
to 1980, nonutilities consisted of industrial manufacturers that produced
electricity for their own use. Currently, nonutilities not only consist of
industrial manufacturers, but also other industrial groups that provide
electricity and other services for their own use and/or for sale to others.
These categories are discussed further below.
This section provides background information on the size, geographic
distribution, electricity production, sales, and economic condition of the
fossil fuel electric power generation industry. The type of facilities described
within the document are also described in terms of their SIC codes.
Additionally, this section lists the largest companies in terms of sales.
H.B Characterization of the Fossil Fuel Electric Power Generation Industry
The U.S. Department of Energy's (DOE) Energy Information Administration
(EIA) collects, evaluates, and disseminates information on the fossil fuel
electric power generation industry. This information is published annually.
In addition, industry trade associations collect information.
Available statistics on the fossil fuel electric power generation industry
typically characterize the industry in terms of capacity, generating capability,
net generation, and revenues. These terms are defined as follows:
Capacity is the amount of electric power delivered or required for which
a generator, turbine, or system has been rated by the manufacturer.
Capability is the maximum load that a generating unit can be expected
to carry under specified conditions for a given period of time without
exceeding approved limits of temperature or stress. The net capability of
a generating unit is always less than the rated capacity.
Net generation is the total amount of electricity generated minus the
electricity used by the facility itself.
Revenue is the total amount of money received by a firm from sales of
its products and/or services, gains from the sales or exchange assets,
interest and dividends earned on investments, and other increases in the
owner's equity except those arising from capital adjustments.
The following sections briefly summarize information available to
characterize the industry.
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II.B.1 Product Characterization
The product in fossil fuel electric power generation is electricity. Ancillary
activities associated with the generation of electricity may generate other
products, however. For example, cogeneration systems produce electricity,
as well as another form of usable energy (i.e., steam or heat). In addition,
utilities with SIC code 493 may produce other products, such as gas. These
other products are beyond the scope of this profile.
II.B.2 Industry Size and Geographic Distribution of the Fossil Fuel Electric
Power Generation Industry
In general, the power generation industry comprises both traditional and
nontraditional electric-producing companies. They are called "utility" and
"nonutility" power producers, respectively. A key difference between
utilities and nonutilities is that utilities own generation, transmission, and
distribution functions. Thus, utilities are "vertically" oriented. Nonutilities,
on the other hand, generally own only generation capabilities. Often, the
nonutilities must rely on utilities to sell the electricity they produce.
A utility power producer is generally defined as any person, corporation,
municipality, State political subdivision or agency, irrigation project, Federal
power administration, or other legal entity that is primarily engaged in the
retail or wholesale sale, exchange, and/or transmission of electric energy. In
1995, there were 3,199 utilities in the United States; however, only 700 of
these utilities generated electric power. The remainder were electric utilities
that purchased wholesale power from others for the purpose of distribution
over their lines to the ultimate consumer. The 700 utilities that generated
power had a total of 3,094 power plants or stations.1
A nonutility power producer is defined as any person, corporation,
municipality, State political subdivision or agency, Federal agency, or other
legal entity that either (1) produces electric energy at a qualifying facility
(QF)a as defined under the Public Utility Regulatory Policies Act (PURPA)
or (2) produces electric energy but is primarily engaged in business activities
other than the sale of electricity. In 1995, there were 4,190 nonutility power-
generating facilities. Generation by nonutility power producers accounted for
approximately 12 percent of the total U.S. electric generation. Fifty-six
percent of the electricity generated by nonutilities was sold to electric
utilities.2
a To receive status as a QF under PURPA, a facility must meet certain ownership, thermal output size, and
efficiency criteria established by the Federal Energy Regulatory Commission (FERC). QFs are guaranteed that
electric utilities will purchase their output at a reasonable price.
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Table 1 provides electric power generation statistics for the year 1995 that
allows comparison between electric power generation by both utilities and
nonutilities based on the fuels used.
Table 1: Comparison of Utility and Nonutility Electric Power Generation (1995)
Energy
Source
Fossil
Nuclear
Hydroelectric*
Renewable
and other"
Total
Utility Generation
(thousand megawatthours)
2,021,064
673,402
293,653
6,409
2,994,528
Nonutility Generation
(thousand megawatthours)***
287,696
(t)
14,515
98,295
400,505
Total U.S. Generation
(thousand megawatthours)
2,308,760
673,402
308,168
104,704
3,395,033
" Includes hydroelectric, conventional, and pumped storage.
" Includes geothermal, solar, waste, wind, photovoltaic, and biomass; projects for which there were two primary energy
sources; and projects that did not identify the primary energy source. Nonutility data includes nuclear.
*** Totals may not equal sum of components because of independent rounding.
* Nonutility facilities using nuclear are including under "Renewable and other."
Sources: (a) Electric Power Annual, 1995, Volume I. U.S. Department of Energy, Energy Information Administration,
Washington, DC. July 1996. DOE/EIA-0348(95/1); and (b) 1995 Capacity and Generation of Non-Utility Sources of
Energy. Prepared by the Edison Electric Institute, Washington, DC. November 1996.
Based on these numbers and as shown hi Figure 1, fossil fuel electric power
generation represented 68 percent of the total U.S. electric power generation
industry's total production of electricity in that year (both utility and
nonutility combined). Nuclear energy represented 20 percent, renewable
energy sources represented about 12 percent, and other energy sources
represented less than 1 percent of the electricity production.
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Figure 1: Total Utility and Nonutility Electric Power Net
Generation Based on Fuels (1995)
Renewable Other
12% <1%
Nuclear
20%
Fossil
68%
In general, statistics on utility and nonutility electric power production are
not aggregated. The following sections provide a more in-depth discussion
of the information available to characterize the utility and nonutility electric
power generators.
II.B.3 Industry Size and Geographic Distribution of Traditional Utilities
Ownership Categories and Revenues
Electric utilities are divided into four ownership categories: investor-owned,
publicly owned, cooperative-owned, and Federally owned. These categories
are described as follows:
Investor-owned utilities produce a return for investors. They either
distribute profits to stockholders as dividends or reinvest the profits.
Investor-owned utilities are regulated entities that are granted a service
monopoly in certain geographic areas and are obliged to serve all
consumers and charge reasonable prices.
Publicly-owned utilities are non-profit local government agencies (e.g.,
municipalities, counties, States, and public utility districts) that serve
communities and nearby consumers at cost, returning excess funds to the
consumer in the form of community contributions, economic and
efficient facilities, and lower rates.
Cooperative utilities are owned by their members and are established to
provide electricity to those members. Cooperatives typically provide
electric service to small rural communities of 1,500 or less.
Federal electrical utilities do not generate power for profit. The Federal
government is primarily a producer and wholesaler of electricity, and
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preference in the purchase of the electricity is given to publicly owned
and cooperative electric utilities.
In 1995, there were 244 investor-owned, 2,014 publicly owned, 10 Federal,
and 931 cooperative utilities. Figure 2 shows the percentage of 1995 U.S.
electricity sales to ultimate consumers based on ownership type. Total sales
were 1,013 billion kilowatthours. Only a portion of these utilities own and/or
operate fossil fuel electric power generation capacity.
Figure 2: Total Utility Electricity Sales to Ultimate Consumers3
Cooperative Federal
8% 2%
Publicly
Owned
15%
Investor-
Owned
75%
Among the ownership classes, investor-owned utilities account for more than
75 percent of all retail sales and revenues. In 1995, revenues from major
utility generators totaled 208 billion dollars. Table 2 provides the revenues
from major utility generators based on ownership category. Tables 3 and 4
list the 1995 top ten investor-owned and publicly owned utilities based on
revenues from sales and megawatts sales to ultimate consumers, respectively.
It should be noted that these data are for all electric utility activities, not just
those that generate electricity.
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Table 2: Revenues From Major Utility Generators (1995)
Ownership Category
Investor-Owned
Publicly Owned
Cooperative
Federal
Total
Revenue (billion $)
164
26
17
1
208
Source: Electric Power Annual 1995, Volume II. U.S. Department of Energy, Energy Information Administration,
Washington, DC. July 1996. DOE/EIA-0384(95)/2.
Table 3: Top Ten Investor-Owned Utilities Ranked by Revenue From Sales
to Ultimate Consumers (1995)
Utility Name
Southern California Edison Co.
Pacific Gas and Electric Co.
Commonwealth Edison Co.
Texas Utilities Electric Co.
Florida Power & Light Co.
Consolidated Edison Co. - NY, Inc.
Virginia Electric & Power Co.
Georgia Power Co.
Public Service Electric & Gas
Duke Power Co.
Subtotal
Revenue (thousand dollars)
7,575,448
7,569,507
6,634,832
5,450,444
5,325,258
5,005,860
3,979,071
3,972,189
3,886,566
3,843,227
53,242,403
% of Total
4.64
4.63
4.06
3.34
3.26
3.07
2.44
2.43
2.38
2.35
32.61
Source: Financial Statistics of Major U.S. Investor-Owned Electric Utilities - 1995. U.S. Department of Energy, Energy
Information Administration, Washington, DC. December 1996. DOE/EIA-0437/(95)/l.
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Table 4: Top Ten Publicly Owned Generator Utilities Ranked by Megawatt Sales
to Ultimate Consumers (1994)
Utility Name
City of Los Angeles (CA)
Salt River Project (AZ)
Power Authority of State of NY
San Antonio Public Service Board (TX)
City of Seattle (WA)
Jacksonville Electric Authority (FL)
Sacramento Municipal Utility District (CA)
South Carolina Public Service Authority
City of Austin (TX)
Omaha Public Power District (NE)
Subtotal
Megawatt Sales
20,430,075
16,058,298
13,212,615
13,027,064
8,874,039
8,817,618
8,458,156
7,423,460
7,308,134
7,066,940
110,676,399
% of Total
8.61
6.77
5.57
5.49
3.74
3.72
3.57
3.13
3.08
2.98
46.65
Source: Financial Statistics of Major U.S. Publicly-Owned Electric Utilities - 1994. U.S. Department of Energy, Energy
Information Administration, Washington, DC. December 1995. DOE/EIA-0437/(94)/2.
Geographic Distribution of Utilities
Fossil fuel electric power generation by utilities occurs across the United
States. Figure 3 provides the total electric power net generation for each
State. Higher values for net generation from utilities generally mirror higher
population densities and industrial centers. The States with the highest utility
net generation included were California, Texas, Illinois, Ohio, Pennsylvania,
and Florida. The amount and geographical distribution of capacity by energy
source are a function of availability and price of fuels and/or regulations.
Energy sources used by utilities generally show a geographical pattern, such
as significant coal and petroleum-fired capacity in the East and gas-fired
capacity in the Coastal South.4
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Figure 3: Geographic Distribution of U.S. Utility Electric Power Net Generation
Source: Electric Power Annual, 1995, Volume I and II. U.S. Department of Energy, Energy
Information Administration, Washington, DC. July 1996. DOE/EIA-0348(95)/1&2.
Existing Utility Capacity and Electricity Generation
In general, electric power generation utilities use several technologies to
generate electric power. These technologies, known as prime movers, are
steam turbines, gas turbines, internal combustion engines, combined-cycle,
hydraulic turbines, and others (e.g., geothermal, solar, and wind). Combined-
cycle facilities use a technology in which electricity is produced from
otherwise lost heat exiting from one or more gas (combustion) turbines. The
exiting heat is routed to a conventional boiler or to a heat recovery steam
generator for utilization by a steam turbine in the production of electricity.
This process increases the efficiency of the generating unit. Table 5 shows
the 1995 existing capacity that employs these technologies and the percent
of total U.S. utility capacity. Steam turbines are associated with 77 percent
of the total U.S. utility capacity.
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Table 5: Existing Capacity of All U.S. Utilities by Prime Mover
(fossil fuels, renewable fuels, and other fuels) (1995)
Prime Mover
Steam Turbines*
Gas Turbines
Internal Combustion
Combined-Cycle (gas and steam)
Hydraulic Turbines (hydroelectric)
Others
Total
Generating Capacity
(megawatts)"
579,647
58,329
4,985
14,578
91,114
1,888
750,542
Percent of Total U.S.
Capacity
77
7
>1
2
12
>1
100
* Includes nuclear generators.
" Total may not equal sum of components because of independent rounding.
Source: Inventory of Power Plants in the United States, as of January 1, 1996. U.S. Department of Energy,
Energy Information Administration, Washington, DC. December 1996. DOE/EIA-0095(95).
Not all of the existing capacity uses fossil fuels. Only a subsection of steam
turbine, gas turbine, internal combustion, and combined-cycle capacity
(657,539 megawatts) uses fossil fuels. More than 75 percent of the total
existing capacity is fossil-fueled. Table 6 presents the 1995 capacity that
used fossil fuels for each prime mover. In 1995, approximately 86 percent
of the fossil-fueled electric power generation capacity was from steam turbine
systems.
Table 6: Fossil-Fueled Utility Capacity by Prime Mover (1995)*
Prime Mover
Steam Turbine
Gas Turbine/Internal Combustion
Total
Generating Capacity
(megawatts)
475,860
73,166
549,026
% of Fossil-Fueled Capacity
86
14
100
Includes combined-cycle capacity.
Source: Inventory of Power Plants in the United States, As of January 1, 1996. U.S. Department of Energy,
Energy Information Administration, Washington, DC. December 1996. DOE/EIA-0095(95).
Fossil fuel-fired steam electric utilities had the capability to produce 445,627
megawatts of electricity, or more than 50 percent of the net generating
capability at U.S. electric utilities. Gas turbine and internal combustion
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facilities combined had the capability to produce 61,424 megawatts of
electricity, or 11.5 percent of generating capability at U.S. electric utilities in
1995.
In 1995, coal was used as the energy source to generate the most electricity
in the utility industry, accounting for net generation of 1,652,914 thousand
megawatthours of electricity, consuming 829,007 thousand short tons of coal.
Gas-fired generators generated 307,306 thousand megawatthours, consuming
3,196,507 million cubic feet of gas, and petroleum-fired generators generated
60,844 thousand megawatthours of electricity, consuming 102,150 thousand
barrels of petroleum (not including petroleum coke). Many utility generators
have the flexibility to switch fuel sources in response to market conditions.
Table 7 provides the 1995 U.S. utility generating capacity and net generation
for each fossil fuel energy source.
Table 7: Utility Generating Capability and Net Generation by Energy Source (1995)
Energy Source
Coal
Gas
Petroleum
Total
Generating Capability
(megawatts)
301,484
135,749
70,043
507, 276
Net Generation
(thousand megawatthours)
1,652,914
307,306
60,844
2,020,822
Source: Electric Power Annual, 1995, Volume 1. U.S. Department of Energy, Energy Information
Administration, Washington, DC. July 1996. DOE/EIA-0348(95/1).
II.B.4 Industry Size and Geographic Distribution of Nonutilities
Nonutility Classifications
There are three categories of nonutilities:
Cogeneration is the major technology used among nonutility power
producers. This technology, which is discussed in greater detail in
Section III, is the combined production of electric power and another
form of useful energy (e.g., heat or steam). To receive QF status under
PURPA, a cogeneration facility must meet certain operating criteria to
"produce electrical energy and another form of useful thermal energy
through the sequential use of energy." Depending upon the technology
used, a facility may also be required to meet specific efficiency criteria.
QFs are guaranteed that electric utilities will purchase their output at the
incremental cost that an electric utility would incur to produce or
purchase an amount of power equivalent to that purchased from QFs.
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QFs are also guaranteed that electric utilities will provide backup service
at prevailing (non-discriminatory) rates.
Fossil-fueled steam turbine systems are used in most industrial
applications of cogenerating processes, while gas turbine systems are
used in most other processes (e.g., commercial). Diesel engine systems
are limited in their application to cogeneration because they provide less
useable process heat per unit of electric power input.
Small Power Producers are designated under PURPA regulations based
on fuel consumption of a renewable energy source greater than 75
percent. This means that most nonutility fossil fuel electric power
generators are not likely to carry this designation. In limited cases
however, a facility may use fossil fuel in conjunction with a renewable
energy source.
Other Nonutility Generators are facilities not classified in the previous
categories that produce electric power for their own use and for sale to
electric utilities. These facilities include:
- Independent power producers (IPPs)
- Nonqualifying cogenerators
Exempt wholesale generators (EWGs)
Other commercial and industrial establishments.
FERC defines IPPs as producers of electric power other than QFs that are
unaffiliated with firanchised utilities in the IPP's market area and that for
other reasons lack significant market power. The IPPs may lack market
power due to siting or access to transmission. The EWGs are engaged
exclusively in the business of wholesale electric generation and are exempt
from corporate organizational restrictions under the Public Utility Holding
Company Act of 1935.
In 1995, the makeup of the nonutility industry, based on capacity, included
76.2 percent cogenerators, 15.8 percent small power producers, and 8 percent
other nonutility producers. Figure 4 illustrates the percent capacity of the
different classes of nonutility power producers.5
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Figure 4: Nonutility Capacity by Type of Producer
Small Power
Producers
16%
Other
Nonutilities
8%
Cogenerators
76%
Qualified facilities comprised 78 percent of the total nonutility capacity in
1995. Non-qualified facilities were 12.9 percent of the capacity.
Nonutility power generation facilities and activities may be found in
association with commercial and industrial facilities. Table 8 lists SIC codes
and industries where power generation facilities and activities may be found.
In 1995, nonutility generation capacity within the chemical industry (SIC
Code 28) accounted for 21 percent of the nonutility capacity and 23 percent
of the total nonutility generation. The paper industry (SIC Code 26)
accounted for 17 percent of the nonutility capacity and 18 percent of the
generation. The coal, oil, and gas mining and refining industries (SIC Codes
12, 13, and 29) accounted for 12 percent of the total nonutility capacity and
13 percent of the generation.6
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Table 8: Major SIC Codes and Industrial Categories Where Nonutility
Power Generation Activities Are Found
Major SIC Code
Industrial Category
01,02
07
10
12
13
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
42,45,47,48,49
53,54,55,58
60,65
70,72,80, 82, 83, 84,86,87
91,92,97
Agricultural Production - Crops, Livestock, and Animals
Agricultural Services
Metal Mining
Coal Mining
Oil and Gas Extraction
Food and Kindred Products
Tobacco Products
Textile Mill Products
Apparel & Other Finished Fabric Products
Lumber and Wood Products (Except Furniture)
Furniture and Fixtures
Paper and Allied Products
Printing, Publishing, and Allied Industries
Chemicals and Allied Products
Petroleum Refining and Related Industries
Rubber and Miscellaneous Plastics Products
Leather and Leather Products
Stone, Clay, Glass, and Concrete Products
Primary Metal Industries
Fabricated Metal Products (Except Machinery)
Industrial and Commercial Machinery/Computer Equipment
Electronic and Other Electrical Equipment
Transportation Equipment
Measuring, Analyzing, and Controlling Instruments
Jewelry, Silverware, and Plated Silver
Transportation, Communications, Electric, Gas, and Sanitary Services
Retail Trade
Finance, Insurance, and Real Estate
Services
Public Administration
Source: Directory of U.S. Cogeneration, Small Power, and Industrial Power Plants. June 1995.. Giles, Ellen and Fred Yost. Twelfth
Edition. Utility Data Institute, A Division of McGraw- Hill Company. UDI-2018-95.
Geographic Distribution ofNonutilities
Fossil fuel electric power generation by nonutilities occurs all across the
United States. Figure 5 provides the total nonutility electric power net
generation for each State. As with the utilities, higher values for net
generation for nonutilities generally mirror higher population densities and
industrial centers. The States with the highest nonutility net generation
included were California, Texas, Virginia, New York, Florida, and New
Jersey.
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Figure 5: Geographic Distribution of U.S. Nonutility Electric Power Net Generation
Source: Electric Power Annual Volume I and II. July 1995. U.S. Department of Energy, Energy
Information Administration, Washington, DC. DOE/EIA-0348(95)/1&2.
Existing Nonutility Capacity and Electricity Generation
As in the traditional utilities, nonutilities use steam turbines, gas turbines,
internal combustion engines, hydraulic turbines, and combined-cycle systems
to generate electricity. Steam turbines accounted for 42 percent of all the
capacity and combined-cycle generating systems accounted for 27 percent.
Table 9 provides existing 1995 nonutility generating capacity by prime
mover technology.
The majority (more than 68 percent) of existing 1995 nonutility capacity is
attributed to fossil-fueled electricity production.7 Many facilities are able to
switch from one fossil fuel to another if the fuel supply is interrupted or the
economics warrant it. Some facilities are even able to switch from fossil
fuels to renewable energy sources, while still others can use combustors that
can burn two or more different fuels simultaneously, in varying
combinations, to generate a desired heat output. Thus, the nonutility industry
can be very adaptable, depending upon the type of equipment at a facility and
based on economic conditions. Table 10 provides the 1995 nonutility
capacity associated with each fossil fuel energy source.
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Table 9 : Existing Capacity of Nonutilities by Prime Mover (1995)
Prime Mover
Steam Turbines
Combined-Cycle
Gas Turbines
Internal Combustion
Hydraulic Turbines
Others*
Total
Generating Capacity
(megawatts)
28,192
17,417
12,081
2,018
3,410
3,297
66,415
Percent of Total U.S.
Capacity
42
27
18
3
5
5
100
* Includes nuclear generators.
Source; 1995 Capacity and Generation ofNonutility Sources of Energy. Edison Electric Institute, Washington,
DC. November 1996.
Table 10: Nonutility Capacity by Fossil Fuel Energy Source (1995)
Fossil Fuel
Gas
Coal
Petroleum
Total
Generating Capacity
(megawatts)
33,221
10,324
1,657
45,202
Percent of Total Fossil Fuel
Nonutility Capacity
73
23
4
100
Source: 1995 Capacity and Generation ofNonutility Sources of Energy. Edison Electric Institute, Washington,
DC. November 1996.
The majority of the nonutility power producers use fossil fuels to generate
electricity. Fossil fuels accounted for more than 287 million megawatthours,
which was 72 percent of the total electricity produced by nonutilities in
1995.8
Gas was the fossil fuel used to generate the most electricity in the nonutility
industry, providing a total of 213 million megawatthours of electricity in
1995. Coal was used to produce 70 million megawatthours of electricity,
and petroleum was used to produce 4 million megawatthours of electricity.
Table 11 provides 1995 nonutility generation by power producer class and
energy source.
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Table 11: 1995 Nonutility Net Generation by Primary Fossil Fuel Energy Source and Type
of Producer (thousand megawatthours)
Energy Source
Gas
Coal
Petroleum
Total
Cogenerators
200,080
63,440
3,957
267,477
Small Power
Producers
0
0
0
0
Other Nonutility
Power Producers
13,357
6,740
121
20,218
Total U.S.
Nonutility
Generation
213,437
70,180
4,079
287,696
Source: 1995 Capacity and Generation of Nonutility Sources of Energy. Edison Electric Institute, Washington,
DC. November 1996.
II.B.5 Economic Trends
Change in Structure of the Utility Electric Power Industry
Utility electric power generation is one of the largest industries that remains
regulated in the United States. Change is rapidly occurring in this industry
due to the issuance by the FERC of Orders 888 and 889 (dated April 24,
1996), which encourage wholesale competition. Order 888 deals with issues
of open access to transmission networks and stranded costs; Order 889
requires utilities to establish systems to share information on the availability
of transmission capacity. To date, many States have initiated activities
related to retail competition, and legislative proposals have been introduced
into the U.S. Congress on restructuring the electric power industry.
With a competitive industry structure eminent, investor-owned utilities have
been downsizing staff and reorganizing their company structures to lower
costs. They have lowered costs by taking advantage of lower fuel prices and
modifying fuel acquisition procedures. This has resulted in lower operation
and maintenance costs. Some large investor-owned utilities have begun to
expand their business investments into such areas as energy service
companies; oil and gas exploration, development, and production; foreign
ventures; and telecommunications. Numerous utilities are planning to
improve their position in a competitive market through mergers and
acquisitions. In 1995, 13 investor-owned utilities merged or had mergers
pending.9
Publicly owned and cooperative utilities are expected to be affected by the
posturing of the investor-owned companies. Although they can sell
electricity at a competitive price, increased competition from investor-owned
utilities and electricity marketing companies may require them to lower costs.
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Many have already begun to reduce staff and engage in other cost-cutting
measures. Mergers are also expected to occur among public utilities,
however, not at the same rate as the investor-owned.
Stranded costs are a major concern for this industry as they move to a
competitive market. Stranded costs are costs that have been incurred by the
utilities to serve their consumers but cannot be recovered if the consumers
choose other electricity suppliers. Estimates of stranded costs have been
from $10 to $500 billion. Currently, utilities are looking for ways to
mitigate stranded costs, and regulators are looking at alternatives for
recovering these costs.10
The structure of the electric power industry is undergoing other changes. In
the past, the electric power industry has been dominated ,by utilities,
especially regulated investor-owned utilities. It is expected that utility
generators will continue to dominate capacity in the United States, increasing
from 703 gigawatts in 1995 to 724.4 gigawatts in 2015. In addition,
nonutilities will continue to increase their role in the industry. Recent
legislation has had an effect. For example, PURPA in 1978 has allowed QF
status, and the Energy Policy Act of 1992 (EPACT) has removed constraints
on utility ownership of significant shares of nonutility producers. In 10 years
(1985-1995), the nonutility role in U.S. electric power industry has grown
from 4 percent to 11 percent of the total generation.11
With the advent of a more competitive market, a new type of firm called
"power marketers" has arisen in the electric power generation industry.
Power marketers buy electric energy and transmission and other services
from utilities, or other suppliers, and resell the products for profit. This
practice started in the late 1980s, and growth in this market has increased
competition in the wholesale market. Nine wholesale marketers existed in
1992; 180 existed by the end of 1995. The growth and success of power
marketers signal a potential for fundamental change in the wholesale
electricity business.
Projected Growth in the Power Generation Industry
Demands for electricity have slowed in recent years due to several factors.
These factors include market saturation of electric appliances, improvements
in equipment efficiency, utility investments in demand-side management
programs, and legislation establishing more stringent equipment efficiency
standards. In the 1960s, electricity demand grew by more than 7 percent a
year. By the 1980s, this growth had slowed to only 1 percent per year. A
further decline in growth is expected into the next century.12
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Section II. Introduction to the Industry
Despite the slower demand growth, 319 gigawatts of new generating capacity
are expected to be needed by 2015. This need is both a result of the demand
and because of the amount of capacity that is expected to be retired. In
particular, approximately 38 percent of the existing nuclear capacity is
expected to be retired, in addition to 16 percent of the existing fossil-fueled
steam turbine capacity. Of the new capacity needed, 81 percent is projected
to be combined-cycle or combustion turbine technology expected to be fueled
with natural gas or both oil and gas. Both of these technologies supply peak
and intermediate capacity, but combined-cycle units can also be used to meet
baseload requirements.
Before building new capacity, many utilities are exploring other alternatives
to meet the growth demand. Some of these alternatives are life extension and
repowering, power imports, demand-side management programs, and
purchase from cogenerators. Even with these alternatives, a projected 1,063
new plants (assuming approximately 300 megawatts capacity per plant) will
be needed by 2015 to meet the growing demand and to offset the
retirements.13
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Section II. Introduction to the Industry
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Section III. Industrial Process Description
HI. INDUSTRIAL PROCESS DESCRIPTION
This section describes the major industrial processes within the fossil fuel
electric power generation industry, including the materials and equipment
used and the processes employed. The section is designed for those
interested in gaining a general understanding of the industry and for those
interested in the interrelationship between the industrial process and the
topics described in subsequent sections of this profile ~ pollutant outputs,
pollution prevention opportunities, and Federal regulations. This section
does not attempt to replicate published engineering information that is
available for this industry. Section IX lists available resource materials and
contacts.
This section describes commonly used production processes, associated raw
materials, the by-products produced or released, and the materials either
recycled or transferred offsite. This discussion, coupled with schematic
drawings of the identified processes, provide a concise description of where
wastes may be produced in the process. This section also describes the
potential fate (via air, water, and soil pathways) of these waste products.
III.A Industrial Processes in the Fossil Fuel Electric Generation Industry
The majority of the electricity generated in the United States today is
produced by facilities that employ steam turbine systems.14 Other fossil fuel
prime movers commonly used include gas turbines and internal combustion
engines. Still other power generation systems employ a combination of the
above, such as combined-cycle and cogeneration systems. The numbers of
these systems being built are increasing as a result of the demands placed on
the industry to provide economic and efficient systems.
The type of system employed at a facility is chosen based on the loads, the
availability of fuels, and the energy requirements of the electric power
generation facility. At facilities employing these systems, other ancillary
processes must be performed to support the generation of electricity. These
ancillary processes may include such supporting operations as coal
processing and pollution control, for example. The following subsections
describe each system and then discuss ancillary processes at the facility.
III.A.I Steam Turbine Generation
The process of generating electricity from steam comprises four parts: a
heating subsystem (fuel to produce the steam), a steam subsystem (boiler and
steam delivery system), a steam turbine, and a condenser (for condensation
of used steam). Heat for the system is usually provided by the combustion
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Section III. Industrial Process Description
of coal, natural gas, or oil. The fuel is pumped into the boiler's furnace. The
boilers generate steam in the pressurized vessel in small boilers or in the
water-wall tube system in modern utility and industrial boilers. Additional
elements within or associated with the boiler, such as the superheater,
reheater, economizer and air heaters, improve the boiler's efficiency.
Wastes from the combustion process include exhaust gases and, when coal
or oil is used as the boiler fuel, ash. These wastes are typically controlled to
reduce the levels of pollutants exiting the exhaust stack. Bottom ash, another
byproduct of combustion, also is discharged from the furnace.
High temperature, high pressure steam is generated in the boiler and then
enters the steam turbine. At the other end of the steam turbine is the
condenser, which is maintained at a low temperature and pressure. Steam
rushing from the high pressure boiler to the low pressure condenser drives the
turbine blades, which powers the electric generator. Steam expands as it
works; hence, the turbine is wider at the exit end of the steam. The
theoretical thermal efficiency of the unit is dependent on the high pressure
and temperature hi the boiler and the low temperature and pressure in
condenser. Steam turbines typically have a thermal efficiency of about 35
percent, meaning that 35 percent of the heat of combustion is transformed
into electricity. The remaining 65 percent of the heat either goes up the stack
(typically 10 percent) or is discharged with the condenser cooling water
(typically 55 percent).
Low pressure steam exiting the turbine enters the condenser shell and is
condensed on the condenser tubes. The condenser tubes are maintained at a
low temperature by the flow of cooling water. The condenser is necessary for
efficient operation by providing a low pressure sink for the exhausted steam.
As the steam is cooled to condensate, the condensate is transported by the
boiler feedwater system back to the boiler, where it is used again. Being a
low-volume incompressible liquid, the condensate water can be efficiently
pumped back into the high pressure boiler.
A constant flow of low-temperature cooling water in the condenser tubes is
required to keep the condenser shell (steam side) at proper pressure and to
ensure efficient electricity generation. Through the condensing process, the
cooling water is warmed. If the cooling system is an open or a once-through
system, this warm water is released back to the source water body. In a
closed system, the warm water is cooled by recirculation through cooling
towers, lakes, or ponds, where the heat is released into the air through
evaporation and/or sensible heat transfer. If a recirculating cooling system
is used, only a small amount of make-up water is required to offset the
cooling tower blowdown which must be discharged periodically to control
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Section III. Industrial Process Descrintion
the build-up of solids. Compared to a once-through system, a recirculated
system uses about one twentieth the water.15 Figure 6 presents a typical
steam generation process.
There are several types of coal-fired steam generators. A description of each
follows. The classification of these generators is based on the characteristics
of the coal fed to the burners and the mode of burning the coal. Coal-fired
steam generation systems are designed to use pulverized coal or crushed coal.
Before the coal is introduced to the burners, it must be processed, as
discussed hi Section III.A.6.
Figure 6: Steam Turbine Generation
Fuel
Steam
Generator
s
Electrical
Generator
Healer
Cooling Water (In)
Cooling Water (out)
Condenser
Train
Exhaust <3as
Stoker-Fired Furnace
Stoker-fired furnaces are designed to feed coal to the combustion zone on a
traveling grate. Stokers can be divided into three general groups, depending
on how the coal reaches the grate of the stoker for burning. The three general
types of stokers are (1) underfeed, (2) overfeed, and (3) spreader
configurations. Table 12 presents the general characteristics of these three
general types of stokers. Figure 7 presents a schematic of a stoker coal
feeder.
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Section III. Industrial Process Description
Table 12: Characteristics of Various Types of Stokers
Stoker Type and Subclass
Burning Rate *
(BTU/hr/ftz)
Characteristics
Spreader
Stationary
Traveling grate
Vibrating grate
450,000
750,000
400,000
Capable of burning a wide range of coals, best
in handling fluctuating loads, high fly ash
carry over, low load smoke.
Overfeed
Chain grate and
traveling grate
Vibrating grate
600,000
400,000
Low maintenance but difficult in burning
caking coals.
Low maintenance but difficult in burning
weakly caking coals, smokeless operation.
Underfeed
Single or double
retort
Multiple retort
400,000
Capable of burning caking coals and a wide
range of coals, high maintenance, low fly ash
carry over, suitable for continuous load
operation.
* Maximum amount of British thermal units per hour per square foot of grate hi the stoker.
Source: Coal Handbook, Robert Meyers (Ed.). Marcel Dekker, Inc. New York, NY, 1981 as referenced in
Wastes from the Combustion of Coal by Electric Utility Power Plants. Report to Congress. US. Environmental
Protection Agency, Office of Solid Waste. Washington, DC. February 1988. EPA/530-SW-88-002.
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Figure 7: Stoker Coal Feeder
^"-o
Coal Gate
Chilli F««l«
Rotor
AlrTuyir*
Source: Standard Handbook of Power Plant Engineering. Elliot, Thomas C. ed.
McGraw-Hill, Inc. New York NY. 1989. Reproduced with permission of the
McGraw-Hill Companies.
In a cyclone-fired furnace, fuel is fired under intense heat and air is injected
tangentially to create a swirling motion as shown in Figure 8. The resulting
hot gases exit through the cyclone bore into the cyclone in the furnace. Ash
becomes a molten slag that is collected below the furnace. Coal is the
primary cyclone fuel, but oil and gas are used as startup, auxiliary, and main
fuels.
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Figure 8: Typical Cyclone Coal Burners
Burner
Cyclone
Furnace
End Views
Tertiary Primary Air
Air and Coal,
Side Views
Tertiary
Air
Orifice-
Scroll Burner Primary Air and Coal \
Coal Primary
Air
\
Coal
Vortex Burner
Primary Ai
" \
Coal
Primary Air
Primary Coal
Air
Tertiary Air ^v
Orifice
Radial Burner
Source: Steam, Its Generation and Use; 40th Edition. Stultz and Kitto, eds. Babcock
and Wilcox, Barbeton, OH. 1992. Reproduced with permission from the Babcock and
Wilcox Co.
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Tangential-Fired Furnace
In a tangential-fired furnace, both air and fuel are projected from the corners
of the furnace along lines tangent to a vertical cylinder at the center. A
rotating motion is created, allowing a high degree of mixing. This system
provides great flexibility for multiple fuel firing (see Figure 9).16
Figure 9: Tangential Firing Pattern
Main Fuel
Nozzle
Secondary-
Air
Dampers
Source: Standard Handbook of Power Plant
Engineering. Elliot, Thomas C. ed. McGraw-Hill, Inc.
New York, NY. 1989. Reproduced with permission of
the McGraw-Hill Companies.
Horizontal or Wall-Fired Furnace
In horizontal or wall-fired systems, pulverized coal and primary air are
introduced tangentially to the coal nozzle. The degree of air swirl and the
contour of the burner throat establish a recirculation pattern extending several
throat diameters into the furnace. The hot products of combustion are
directed back toward the nozzle to provide the ignition energy necessary for
stable combustion. In this system, burners are located in rows on the front
wall (see Figure 10) or both front and rear walls.17
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Figure 10: Flow Pattern of Horizontal Firing
Air A
AirB
AirC
AirD
Burner B
Burner A
Burner D
Burner C
Source: Standard Handbook of Power Plant Engineering. Elliot,
Thomas C. ed. McGraw-Hill, Inc. New York, NY. 1989.
Reproduced with permission of the McGraw-Hill Companies.
Arch-Fired Systems
Vertical-fired systems are used to fire solid fuels that are difficult to ignite,
such as coals with moisture and ash-free volatile matter of less than 13
percent. In this system, the pulverized coal is discharged through a nozzle
surrounded by heated combustion air. High-pressure jets are used to prevent
fuel-air streams from short circuiting. The firing system produces a looping
flame with hot gases discharging at the center (see Figure 11).18
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Figure 11: Flow Pattern of Arch Firing
Upper
Front
(or Rear)
Wall
High Pressure
Jet Air
Primary Air and
Pulverized Coal
Secondary Air
Arch
Tertiary Air
Admission
"U"-Shaped
Vertical
Pulverized-Coal
Flame
Furnace Enclosure
(Refractory Lined)
Source: Standard Handbook of Power Plant Engineering. Elliot,
Thomas C. ed. McGraw-Hill, Inc. New York, NY. 1989.
Reproduced with permission of the McGraw-Hill Companies.
Fluidized-Bed Combustors
In fluidized-bed combustors, fuel materials are forced by gas into a state of
buoyancy. The gas cushion between the solids allows the particles to move
freely, thus flowing like a liquid. By using this technology, SO2 and NOX
emissions are reduced because an SO2 sorbent, such as limestone, can be used
efficiently. Also, because the operating temperature is low, the amount of
NOX gases formed is lower than those produced using conventional
technology.
Fluidized-bed combustors are divided into two categories: circulating
fluidized-beds and bubbling fluidized-beds (see Figure 12). Fluidized-bed
combustors can operate at atmospheric pressure or in a pressurized chamber.
In the pressurized chamber, operating pressures can be 10 to 20 times the
atmospheric pressure. Pressurized fluidized-bed furnaces provide significant
gain in overall thermal efficiency over atmospheric fluidized-bed furnances.19
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Figure 12: Typical Bubbling Fluidized-Bed Boiler
Secondary
Superheater
Water-Cooled
Walls
Top of Bed
Bubbling
Bed
Primary Superheater
Economizer
Dust Collector
Superheater and
Boiling Surface
Distributor
Plate Windbox
Source: Adapted from Steam, Its Generation and Use; 40th Edition.
Stultz and Kitto, eds. Babcock and Wilcox, Barbeton, OH. 1992.
Reproduced with permission from the Babcock and Will Cox. Co.
Fluidized-bed combustion allows for the use of high sulfur coals, high
fouling and slagging fuels, and low British Thermal Unit (BTU) fuels. High
ash coals burned hi fluidized-beds require less preparation than hi pulverized
coal combustors. Additionally, fiuidized-bed combustors require less
maintenance than pulverized coal combustors.
III.A.2 Internal Combustion Generation
Internal combustion generating units, also known as diesel engines, have one
or more cylinders in which fuel combustion occurs. Internal combustion
generating units convert the chemical energy of fuels into mechanical energy
in a design similar to an automobile engine. Attached to the shaft of the
generator, the engine provides the mechanical energy to drive the generator
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to produce electricity. Internal combustion generating units for power plants
are typically designed to operate on either four- or two-stroke cycles.
Internal combustion generators are small and range in capacity from 2 to 6
megawatts. They are more efficient than gas turbines.20 In addition, capital
costs are low, they are easily transported, and they can generate electricity
almost immediately upon startup. For this reason, internal combustion
generators are often used for small loads and for emergency power.21
III.A.3 Gas Turbine Generation
Gas turbine systems operate in a manner similar to steam turbine systems
except that combustion gases are used to turn the turbine blades instead of
steam. In addition to the electric generator, the turbine also drives a rotating
compressor to pressurize the air, which is then mixed with either gas or liquid
fuel in a combustion chamber. The greater the compression, the higher the
temperature and the efficiency that can be achieved in a gas turbine. Exhaust
gases are emitted to the atmosphere from the turbine. Unlike a steam turbine
system, gas turbine systems do not have boilers or a steam supply,
condensers, or a waste heat disposal system. Therefore, capital costs are
much lower for a gas turbine system than for a steam system.
In electrical power applications, gas turbines are typically used for peaking
duty, where rapid startup and short runs are needed. Most installed simple
gas turbines with no controls have only a 20- to 30-percent efficiency. Figure
13 presents a schematic of a simple gas turbine system.
Figure 13: Simple Gas Turbine Cycle
Fuel
Compressor
Exhaust
Turbine
Generator
Source: Standard Handbook of Power Plant Engineering. Elliot,
Thomas C. ed. McGraw-Hill, Inc. New York, N.Y. 1989.
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III.A.4 Combined-Cycle Generation
Combined-cycle generation is a configuration using both gas turbines and
steam generators. In a combined-cycle gas turbine (CCGT), the hot exhaust
gases of a gas turbine are used to provide all, or a portion of, the heat source
for the boiler, which produces steam for the steam generator turbine. This
combination increases the thermal efficiency over a coal- or oil- fueled steam
generator. The system has an efficiency of about 54 percent, and the fuel
consumption is approximately 25 percent lower. Combined-cycle systems
may have multiple gas turbines driving one steam turbine (see Figure 14).22
Figure 14: Combined Cycle with Heat Recovery
Cooling Water {In)
Cooling Walw (out)
Tnln
ExhauatGa*
There are four major classifications of combined-cycle facilities:
Gas Turbine Plus Unfired Steam Generator: A steam generator is
installed at the discharge of a gas turbine to recover the heat in the gas
turbine exhaust so as to create steam in the steam generator. The fuel is
fired only hi the gas turbine.
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Gas Turbine Plus Supplementary-Fired Steam Generator: A portion
of the oxygen in the gas turbine exhaust is used to support further
combustion in a supplementary firing system in the connecting duct
between the gas turbine and the steam generator.
Gas Turbine Plus Furnace-Fired Steam Generator: This generator is
the same as the gas turbine plus supplementary-fired steam generator,
except that essentially all of the oxygen from the gas turbine exhaust is
used to support further combustion.
Supercharged Furnace-Fired Steam Generator Plus Gas Turbine:
A steam generator is placed between the air compressor and the gas
turbine. The air compressor is used to pressurize the boiler where the fuel
is fired. The products of combustion that have been cooled within the
boiler are then discharged through a gas turbine.
In addition, integrated coal gasification combined-cycle (IGCC) units are
combined systems that are in the demonstration stage, but are expected be in
commercial operation by the year 2000. In an IGCC system, coal gas is
manufactured and cleaned in a "gasifier" under pressure, thereby reducing
emissions and particulates. The coal gas then is combusted in a CCGT
generation system.
III.A.5 Cogeneration
Cogeneration is the merging of a system designed to produce electric power
and a system used for producing industrial heat and steam. Cogeneration
accounted for 75 percent of all nonutility power generation in 1995.23 This
system is a more efficient way of using energy inputs and allows the recovery
of otherwise wasted thermal energy for use in an industrial process.
Cogeneration technologies are classified as "topping cycle" and "bottoming
cycle" systems, depending on whether electrical (topping cycle) or thermal
(bottoming cycle) energy is derived first.
Most Cogeneration systems use a topping cycle. This is shown as a steam
turbine topping system in Figure 15. The process steam shown in Figure 15
is condensed as it delivers heat to an industrial process, and the resulting
return condensate is returned back to the boiler as shown.
Facilities that cogenerate may be eligible for QF status under PURPA. To
qualify, the facility must produce electric energy and "another form of useful
thermal energy through sequential use of energy," and meet certain
ownership, operating, and efficiency criteria established by FERC (See 18
CFR Part 292). In a topping cycle system, the fuel is used to generate power
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with a steam boiler or gas turbine cycle combustor. The waste heat from the
power generation process is then used in an industrial process.24
Figure 15: Cogeneration Plant Schematic
Boiler
Generator
Return condensate
Source: Standard Handbook of Power Plant Engineering. Elliot, Thomas C. ed.
McGraw-Hill, Inc. New York, NY. 1989. Reproduced with permission of the
McGraw-Hill Companies.
III.A.6 Supporting Operations
Many operations associated with fossil fuel electric power generation
facilities are not directly involved in the production of electricity but serve
in a supporting role. This section discusses some of the major supporting
processes.
Coal Processing
Fifty-seven percent of coal used in power plants is transported from mines by
rail.25 Coal is also transported by truck and barge. Once coal arrives at the
plant, it is unloaded to live storage, dead storage, or directly to the stoker or
hopper. Live storage is an enclosed silo or bunker next to conveyors leading
to the pulverizer. Dead storage is exposed outdoors and is the backup supply.
Coal unloading devices depend on the size and type of plant. Coal arriving
by rail may be unloaded directly into the storage area or to conveyors leading
directly to generation units. Coal arriving by barge is unloaded by buckets,
which are part of coal towers or unloading bridges.26 Coal shipped by truck
generally needs little equipment for unloading.
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Precautions must be taken in the transportation and storage of coal. In
transporting coal during warmer months and in dry climates, dust suppression
. may be necessary. Dust suppression is typically accomplished through the
use of water, oil, or calcium chloride (CaCl2). In winter months, antifreeze
chemicals are applied to the coal. Because coal oxidizes easily in open air,
it should be stored in layered piles to minimize air flow. Hot areas should be
removed from the pile to prevent fire; water should not be added to reduce
the heat, since the water increases the air flow and, therefore, would increase
the oxidation of the coal.
Coal may be cleaned and prepared before being either crushed or pulverized.
Impurities in coal, such as ash, metals, silica, and sulfur, can cause boiler
fouling and slagging. Coal cleaning can be used to reduce sulfur in the coal
to meet sulfur dioxide (SO2) emissions regulations. Cleaning the coal is a
costly process that increases its fuel efficiency, yet reduces the size of the
particles. Coal cleaning is typically performed at the mine by using gravity
concentration, flotation, or dewatering methods. Some smaller stoker plants
purchase pre-cleaned, pre-crushed coal.27
Coal is transported from the coal bunker or silo to be crushed, ground, and
dried further before it is fired in the burner or combustion system. Many
mechanisms can be used to grind the coal and prepare it for firing.
Pulverizers, cyclones, and stokers are all used to grind and dry the coal.
Increasing the coal's particle surface area and decreasing its moisture content
greatly increases its heating capacity. Once prepared, the coal is transported
within the system to the combustion system, or boiler. Devices at the bottom
of the boilers catch ash and/or slag.
Air Pollution Control Processes
Air pollution control devices found in fossil fuel-fired systems (particularly
steam electric power facilities) include particulate removal equipment, sulfur
oxide (SOx) removal equipment, and nitrogen oxide (NOx) removal
equipment. Particulate removal equipment includes electrostatic precipitators,
fabric filters, or mechanical particulate collectors, such as cyclones. SOX
removal equipment includes sorbent injection technologies and wet and dry
scrubbers. Both types of scrubbers result in the formation of calcium sulfate
and sulfite as waste products. NOX emission control systems include low
NOX burners and selective catalytic or non-catalytic reduction technologies.
The selective catalytic and non-catalytic reduction technologies convert
oxides of nitrogen into nitrogen gas and water.
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Other Processes to Mitigate Environmental Impacts
Control technologies are used at many utility electric power generation
facilities to mitigate the environmental impacts of cooling water intake
structures. These technologies may include intake screening systems, passive
intake system (physical exclusion devices), or fish diversion and avoidance
systems. Technologies used to mitigate thermal pollution include cooling
towers, cooling ponds or lakes, and sprinklers. Other control technologies
may include recycling and reuse equipment for metals recovery; evaporators;
and physical, chemical, and biological wastewater treatment.
III.B Raw Material Inputs and Pollution Outputs
The primary raw material used in fossil fuel electric power generation is the
fossil fuel needed as the energy source to drive the prime mover (i.e.,
turbine). Fossil fuels employed in the United States predominantly include
coal, petroleum, and gas. Other inputs include water (for cooling and steam
generation) and chemicals used for equipment cleaning and maintenance.
Pollution outputs include solid waste pollution, wastewater pollution, air
pollution, and thermal pollution. The following subsection discusses the
major sources of raw materials and the sources of emissions associated with
the power generation industry.
III.B.l Fossil Fuels and Other Raw Material Inputs
The major types of fossil fuels used for electricity generation in the United
States are coal, petroleum, gas. Other fossil fuels used include petroleum
coke, refinery gas, coke oven gas, blast furnace gas, and liquefied petroleum
gas. These latter fuels are used much less frequently and, therefore, will not
be discussed in this notebook.
Coal
Coal is the most abundant fossil fuel in the United States and the most
frequently used energy source for U.S. electricity generation. More than one-
half of all electricity generated by utilities comes from coal-fired facilities.28
Although the use of coal has decreased since the 1970s, some areas of the
country use coal almost exclusively.
Coals used for electric power generation are very heterogeneous and. vary in
content, depending on the location of the mine. The major chemical makeup,
which includes carbon, hydrogen, and oxygen, also contains impurities, such
as minerals and sulfur. These impurities are a major concern because they
contribute to the pollutants produced during combustion of the coal.
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Of all the fossil fuel used for electricity generation, coal requires the most
extensive processing, handling, storage, and loading and unloading facilities.
Coal firing requires the use of crushers, pulverizers, ash handling equipment,
dust control, emissions control equipment, and soot blowers.
Petroleum
Gas
Petroleum, or crude oil, is the source of various fuel oils used as the energy
source for power generation. As an energy source, petroleum accounts for
less than five percent of all electricity receipts in the United States. However,
numerous utilities in the New England States, New York, Florida, and
Hawaii still rely on petroleum as an energy source.29
Most petroleum used for power generation is refined prior to use. Typical
fuel oils include fuel oil numbers 4, 5, and 6 (heavy oil) and constitute the
majority of all petroleum receipts at electric utilities. Smaller amounts of fuel
oil number 2 (light oil) are used typically for startup and flame stabilization
of the boilers.30 Other less frequently used sources include topped crude,
kerosene, and jet fuel.
Fuel oils used for electricity generation require special handling, storage, and
loading and unloading facilities. Oil requires ash handling equipment, dust
control, emissions control equipment, soot blowers, and, in some instances,
wanning and heating facilities.
Gas is used less than coal as a primary fuel source at power generation
utilities. Gas is widely used for industrial electric power generation,
however. Gas is used in those areas of the United States where it is readily
accessible or in States in which environmental laws for air emissions are
stringent (e.g., California). Many of the facilities that use gas also use
petroleum in dual-fired generating units. The use of one fuel over the other
is based on economics.
Natural gas must be treated to produce commercial fuel. Natural gas
comprises primarily methane and ethane. Natural gas suitable for use as a
fuel in power generation facilities must be at least 70-percent methane,
60-percent propane, or 25-percent hydrogen. The fuel may come in either a
gaseous or liquid form.31
Gas has one advantage over other fuels in that it is a cleaner burning fuel.
Therefore, some electric utilities use gas in order to comply with
environmental regulations. Gas used for generating electricity requires
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Fossil Fuel Electric Power Generation
Section HI. Industrial Process Description
relatively little special handling (piping) and may or may not require storage
facilities.
Other Inputs
In addition to fossil fuels, electric power generation requires other material
inputs. These inputs include (1) water for steam condensation and equipment
cooling, (2) lime or limestone, as a sorbent for pollution control equipment,
(3) chlorine and/or biocides to prevent biofouling of steam condensers and
cooling towers, (4) chemical solvents, oils, and lubricants for equipment
cleaning and maintenance.
HI.B.2 Pollutant Outputs
Pollutants are generated as byproducts from the burning of fossil fuels to
generate electricity. The combustion process releases highly regulated
pollutants, such as NOX, carbon monoxide (CO), particulate matter (PM),
SO2, volatile organic compounds (VOCs), organic hydrocarbons, and trace
metals, into the air. Combustion waste, the majority of which is ash waste,
is created during combustion processes using coal or oil for fuel. Non-
combustion wastes, such as cooling, process, and storm waters, that are
discharged from fossil fuel electric power generation facilities have the
potential to release pollutants (e.g., chlorine, heavy metals, and thermal
pollution) into surface waters. The following discussion highlights each of
the waste streams created during the generation of fossil fuel electric power.
Air Emissions
Air emissions from the stack gases from coal- and oil-fired boilers include
four of six criteria pollutants regulated through the National Ambient Air
Quality Standards (NAAQS) under the Clean Air Act (CAA) as amended:
NOX, CO, SO2, and PM. Amounts of SO2 emitted depend largely on the
amount of sulfur present in the coal or oil and the method used to generate
steam.
Other emissions regulated by the CAA commonly contained in emission
gases are total organic carbon (TOC) as methane, non-methane hydrocarbons
(NMHC), and VOCs. Traces of lead, another criteria pollutant, and other
metals and minerals are also found. These metals are present in the coal and
oil. Sulfur is also found in these fuels (more in coal than in oil), and fly ash
is the product of sulfur and other mineral materials that do not combust.
Fugitive dust from coal piles and fuel handling equipment is another source
of participates. In addition, fugitive emissions of VOCs can arise from coal
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Fossil Fuel Electric Power Generation
Section III. Industrial Process Description
piles during low temperature devolatilization. Thermal rise plumes are also
discharged from cooling towers. These plumes contain such pollutants as heat
and some trace materials in the water vapor.
Compared to a fossil-fueled steam turbine generating system with no air
pollution controls, a gas-fired power generation system with no controls
emits less tonnage of NOX and SO2 and trace amounts of TOC, particulate
matter, and CO.
Combined-cycle gas turbines have virtually no SO2 emissions because of the
purity of natural gas. Because oil and coal are not used, solid waste is
eliminated, and CO2, NOX, and thermal pollution are cut by 60 percent.
Cogeneration is considered a pollution prevention technology. Other benefits
of cogeneration are reduced fuel consumption and lower air emissions.
Because of their smaller size, however, cogeneration systems in the United
States tend to have lower stack heights. Therefore, air emissions to the
immediate atmosphere contribute to increased local pollution.
Combustion Wastes
Two principal wastes are associated with the combustion of fossil fuels: ash
waste and flue gas desulfurization (FGD) wastes. The quantities of these
wastes generated depend upon the fossil fuel burned.
Ash waste -Two types of ash are generated during combustion of fossil fuels:
bottom ash and fly ash. Ash that collects at the bottom of the boiler is called
bottom ash and/or slag. Fly ash is a finer ash material that is borne by the
flue gas from the furnace to the end of the boiler. Bottom ashes are collected
and discharged from the boiler, economizer, air heaters, electrostatic
precipitator, and fabric filters. Fly ash is collected in the economizer and air
heaters or is collected by the particulate control equipment. Coal-fired
facilities generate the largest quantity of ash; gas facilities generate so little
that separate ash management facilities are not necessary. Fly and bottom
ash may be managed separately or together in landfills or in wet surface
impoundments.
Ashes differ hi characteristics depending upon the content of the fuel burned.
For coal, the chemical composition of ash is a function of the type of coal
that is burned, the extent to which the coal is prepared before it is burned, and
the operating conditions of the boiler. These factors are very plant- and coal-
specific. Generally, however, more than 95 percent of ash is made up of
silicon, aluminum, iron, and calcium in their oxide forms, with magnesium,
potassium, sodium, and titanium representing the remaining major
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Fossil Fuel Electric Power Generation
Section III. Industrial Process Description
constituents. Ash may also contain a wide range of trace constituents in
highly variable concentrations. Potential trace constituents include antimony,
arsenic, barium, cadmium, chromium, lead, mercury, selenium, strontium,
zinc, and other metals.
Flue gas desulfurization waste - If coal or oil is the fuel source, the FGD
control technologies result in the generation of solid wastes. Wet
lime/limestone scrubbers produce a slurry of ash, unreacted lime, calcium
sulfate, and calcium sulfite. Dry scrubber systems produce a mixture of
unreacted sorbent (e.g., lime, limestone, sodium carbonates, calcium
carbonates), sulfur salts, and fly ash. Sludges are typically stabilized with fly
ash. Sludges produced in a wet scrubber may be disposed of in
impoundments or below-grade landfills, or they may be stabilized and
disposed of in landfills. Dry scrubber sludges may be managed dry or wet.
Non-Combustion Wastes
Non-combustion wastes can be categorized into contact and noncontact
wastes. Contact wastes come in contact with combustion wastes and,
therefore, contain the same constituents as the combustion wastes. In many
cases, these contact wastes are managed with the combustion wastes. Non-
contact wastes do not come in contact with ashes or FGD wastes and may be
managed separately. Table 13 summarizes the typical waste streams,
potential pollutants, and ways of managing these pollutants. Figure 16 shows
where the waste streams are generated at a typical steam electric power plant.
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Section III. Industrial Process Description
Table 13: Summary of Typical Waste Streams and Pollutants Generated at Fossil Fuel Electric
Power Generation Facilities Based on Fuel Type
Fuel Type Wastes/Pollutant
Coal
Oil
Gas
Process wastes
Pollutants
Process wastes
Pollutants
Process wastes
Pollutants
Air Emissions
Flue gas and heat -
thermal rise plume.
SO2, NOX, CO2, CO
(more from small
boilers), VOCs, TOC,
PM, metals, sulfur.
Flue gas and heat -
thermal rise plume.
Low SO2, NOX (as NOX
particulate), CO2 ,
sulfur, and PM
compared to coal.
Metals and TOC.
Flue gas.
Low Nox, and SO2
compared to oil and
coal. Thermal pollution
is 60% less than coal.
Combustion Wastes
Bottom ash, fly ash, and
FGD wastes
desulfurization, and fly
ash.
Heavy metals, ferrous
sulfate, sulfuric acid,
sulfate, CaSO3, and CaO.
Bottom ash and fly ash.
VOCs and heavy metals.
None.
None.
Non-Combustion Wastes
Contact*: ash transport, gas-side boiler
cleaning,* FGD blowdown, coal pile
runoff, pyrite waste, floor drains.
Noncontact: once-through cooling
water,* cooling system blowdown,*
boiler blowdown,* water-side boiler
cleaning,* demineralizer regenerent.*
Chlorine, organic chemicals, metals,
pH, TSS, TDSS, ferrous sulfate,
sulfuric acid, metals, pyrite.
Contact*: ash transport, gas-side boiler
cleaning,* FGD blowdown, floor
drains.
Noncontact: once-through cooling
water,* cooling system blowdown,*
boiler blowdown,* water-side boiler
cleaning,* demineralizer regenerent.*
Chlorine, organic chemicals, metals,
pH, TSS, TDSS, ferrous sulfate,
sulfuric acid, metals.
Contact*: infrequent gas-side boiler
cleaning,* floor drains.
Noncontact: once-through cooling
water,* cooling system blowdown,*
boiler blowdown,* water-side boiler
cleaning,* demineralizer regenerent.*
Chlorine, organic chemicals, metals,
pH, TSS, TDSS, metals.
* Waste streams at facilities with steam turbines. t In contact with combustion wastes.
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Section III. Industrial Process Description
Figure 16: Waste Streams Generated at a Typical Fossil Fuel Electric
Power Generation Plant
Fugitive Oust
Flue Gas ,
Note; SOT-Selectlve Catalytic
Reduction DeNO. System
FGD-FlueGas
Desulfurlzatlon System
FGD Byproduct
Gypsum or
Landfill Sludge
Low
Volume
Wastes
Source: Adapted from Steam, Its Generation and Use, 40th Edition. Stultz and Kitto, eds.
Babcock and Wilcox, Barbeton, OH. 1992. Reproduced with permission from the Babcock and
Wilcox Co.
Contact Non-Combustion Wastes
Metal and boiler cleaning waste (gas-side) - Gas-side metal and boiler
cleaning wastes are produced during maintenance of the gas-side of the
boiler, including the air preheater, economizer, superheater, stack, and
ancillary equipment. Residues from coal combustion (soot and fly ash) build
up on the surfaces of the equipment and must be removed periodically. This
buildup is typically removed with plain, pressurized water containing no
chemical additives. Wastewaters are sometimes neutralized and metals
precipitated. At coal plants, the wastewater is most often put into the ash
ponds without treatment.
Ash transport wastewater - Ash produced from the combustion of coal or
oil is typically collected in a sluice water that is then sent to settling ponds for
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Section III. Industrial Process Description
disposal. The ash settling pond discharge may contain dissolved and
suspended solids, heavy metals (nickel, iron, vanadium), organometalic
compounds, and magnesium compounds when magnesium oxides are used
for corrosion control.
Flue gas desulfurization blowdown - Slowdown from FGD systems is
discharged when the recycled liquor begins to build up chlorine. The
discharge contains calcium sulfate, calcium chloride, and sodium chloride.
Depending upon fly ash carryover, the wastewater may contain metal ions.
Coal pile runoff- Open storage of coal allows contact with rain and/or other
precipitation. These storm waters react with the minerals in the coal to
produce a leachate contaminated with ferrous sulfate and sulfuric acid. The
lowpH of the leachate reacts with the coal, thereby accelerating dissolution
of metals in the coal.
Pyrite waste - Coal mills or pulverizers reduce the size of the feed coal going
into the boiler. During this process, various impurities, such as hard coal,
rocks, and pyrites (an iron-based mineral), are mechanically separated from
the feed stream. This solid waste is typically collected and fed into the
bottom ash transport system and eventually co-disposed with the ash in either
a landfill or an impoundment.
Floor drains - Floor and yard drains collect rainfall, seepage, leakage
wastewaters from small equipment cleaning operations, process spills, and
leaks. As a result, the pollutants found in the wastewaters are variable. The
waste streams may contain coal dust, oil, and detergents.
Noncontact. Non-combustion Wastes
Once-through cooling water - When a steam turbine is used to drive the
electric generator the process is called "steam electric." Steam electric units
require large amounts of cooling water for steam condensation and efficient
thermal operation. The cooling water flow rate through the condenser is by
far the largest process water flow, normally equating to about 98 percent of
the total process water flow for the entire unit, hi a once-through cooling
water system, water is usually taken into the plant from surface waters, but
sometimes ground waters or municipal supplies are used. The water is
passed through the condenser where it absorbs heat and is then discharged to
a receiving water. Chlorine, which is added intermittently to the cooling
water to control biofouling, is a pollutant of concern in cooling water
discharge. Heat is also a concern.
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Section III. Industrial Process Description
Cooling tower blowdown - Cooling water is recirculated when the water
supply is inadequate to sustain a once-through system or when thermal
discharges are regulated or undesirable, ha a system that recirculates cooling
water, heat from the water is transferred to the atmosphere via cooling
towers, cooling ponds, or spray facilities. The recirculated water eventually
builds up dissolved solids and suspended matter. Cooling tower blowdown
(a percentage of the recirculated water) is discharged regularly and additional
fresh makeup water is treated and added into the recirculating system to
relieve this buildup of solids. Pollutants of concern in cooling tower
blowdown discharges include chlorine, organic chemicals, and trace metals
from biofouling and corrosion control.
Boiler blowdown - Water to make steam may be recirculated and eventually
build up impurities in the boiler. This water is periodically purged from the
system. Boiler blowdown is typically alkaline, is low in total dissolved
solids, and contains chemical additives used to control scale and corrosion.
Blowdown also contains trace amounts of copper, iron, and nickel.
Metal and boiler cleaning waste (water-side) - Metal cleaning wastes are
produced during cleaning of the boiler tubes, superheater, and condenser
located on the water-side or steam-side of the boiler. Scale and corrosion
products build up in the boiler and must be removed with chemical cleaning
using an acid or alkaline solution. The composition of the waste solvents
depends on the construction material of the feedwater system, but largely
consists of iron with lesser amounts of copper, nickel, zinc, chromium,
calcium, and magnesium. Spent solvents may be treated in numerous ways:
(1) neutralization and then discharge, (2) evaporation in other operating
boilers onsite, (3) dedicated holding ponds, (4) mixing with rinsate and
sending to ash impoundments, or (5) disposal offsite.
Demineralizer Regenerant - Boiler systems may require treatment of boiler
makeup water prior to use. Ion exchange resins used in the treatment of the
water accumulate cations and anions removed from the raw water. These
resins are regenerated using a strong acid, such as sulfuric acid, or a strong
base, such as sodium hydroxide. Regenerant wastes contain dissolved ions
removed from the raw wastewater and excess acid or base. Often, the waste
is directed into the ash impoundment for disposal or to a settling pond with
other liquid wastes prior to discharge.
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Fossil Fuel Electric Power Generation
Section IV. Chemical Releases and Transfers
IV. WASTE RELEASE PROFILE
This section provides estimates and reported quantities of wastes released
from the fossil fuel electric power generation industry. Currently, this
information is not available from the Toxics Release Inventory (TRI) under
the Emergency Planning and Community Right-to-Know Act (EPCRA).
However, regulations promulgated on May 1,1997, would require facilities
that combust coal and/or oil for the purpose of generating power for
distribution in commerce to begin reporting in 1999 (for the period from
January 1 to December 31, 1998). Because TRI reporting is not currently
required, other sources of waste release data have been identified for this
profile.
This section comprises three subsections. The first section provides available
data on releases of solid wastes from fossil fuel electric power generation
facilities. The second section provides available data on releases to surface
waters. A third section provides available data on releases of criteria
pollutants and hazardous pollutants to the air.
IV.A Available Solid Waste Release Data for the Fossil Fuel Electric Power Generation
Industry
As described previously, the primary solid waste releases from coal- and oil-
fired steam electric facilities are fly ash and bottom ash produced during the
combustion process. An increasing number of facilities must condition flue
gases to remove sulfur compounds, which results in the generation of another
solid waste typically referred to as FGD sludge. The following tables present
aggregated ash and FGD sludge generation estimates for utility and nonutility
steam electric facilities.
Table 14 presents the estimated quantity of fly and bottom ash (combined)
for utility boilers in 1994. Coal ash figures have been derived from 1994
DOE, EIA Form EIA-767 utility survey responses. These responses are
compiled by the Edison Electric Institute (EEI) hi their Power Statistics
Database.32 The oil ash figures were developed by the Electric Power
Research Institute (EPRI) based on utility-provided estimates, as well as
extrapolations based on oil consumption and particulate collection
efficiencies for individual plants. Gas-fired facilities are not presented in the
table because gas combustion does not generate measurable quantities of
particulate ash. In general, coal-fired utilities produce ash at approximately
10 percent of the fuel consumption rate. This high rate of production
confirms that ash management can represent an important operational
consideration at coal plants. In contrast, oil-fired utilities produce much less
than 0.1 percent of the total ash produced by the coal-fired facilities. This
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Section IV. Chemical Releases and Transfers
figure reflects the low ash content of oil compared with coal, the typically
lower requirements for particulate collection devices at coal-fired facilities,
the small average particle size of oil ash, and the small contribution that oil
currently makes to total U.S. electricity generation.
Table 14: Generation and Disposition of Utility Fly and Bottom Ash, 1994 (thousand short tons)
Fuel Type
Coal*
Coal/Gas
Coal/Nuclear
Coal/Oil
CoatfOil/Gas
Coal/Wood
Subtotal Coal
OH"
Totals
Number
of
Plants
404
32
2
26
2
1
467
73
540
Quantity
Sold
12,122
830
279
368
1
0
13,600
n/a
13,600
Quantity
Removed by
Contractor
8,762
546
0
401
41
0
9,750
n/a
9,750
Quantity
Landfilled
24,849
636
0
303
45
0
25,833
n/a
25,833
Quantity
Ponded
19,929
133
26
470
0
0
20,558
n/a
20,558
Quantity
Used Onsite,
Given Away,
or Disposed
of in Other
Ways
4,014
83
29
180
0
0
4,306
n/a
4,306
Total
Quantity
Collected
for the
Record
Year (1994)
69,676
2,228
334
1,722
87
0
74,047
23
74,070
* Coal ash values provided in EEI Power Statistics Database (1994 Data). Prepared by Utility Data Institute, McGraw-Hill,
Washington, DC. 1995. Plants include only those reporting coal as primary or secondary fuel. Includes 88 facilities
reporting zero waste generation: 26 facilities reported zero fuel consumption and 62 facilities did not exceed the capacity
and/or ash generation reporting thresholds for the DOE EIA 767 Survey.
" Oil ash values are for 1995. Source: Oil Combustion By-Products - Chemical Characteristics and Management
Practices: Draft Report. Electric Power Research Institute, Palo Alto, California. March 1997.
Table 14 also indicates the range of management options employed by
utilities in managing coal ash. While the figure varies considerable between
operators and sites, roughly one-third of all U.S. utility coal ash finds its way
to some type of beneficial use project. Of the material remaining in
traditional disposal environments, the majority is managed in onsite
impoundments or landfills. These units vary in size, design, and
environmental controls, depending on the age, the State, and the operator.
Table 15 presents similar findings for utility FGD sludge generation and
management. Again, the data reflect utility responses to the Form EIA-767,
as compiled by EEI in the Power Statistics Database. Note that there are no
oil-fired utility boilers equipped with FGD scrubbers. The quantity of FGD
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Section IV. Chemical Releases and Transfers
sludge generated at a given plant is a function of the sulfur content of the coal
consumed, the total quantity of coal consumed, the type of scrubber
Table 15: Generation and Disposition of Utility FGD Sludge, 1994 (thousand short tons)
Fuel Type
Coal
Coal/Gas
Coal/Nuclear
Coal/Oil
Coal/Oil/Gas
Coal/Wood
Totals
Number
of
Plants
71
4
0
2
1
0
78
Quantity
Sold
118
106
0
18
0
0
242
Quantity
Removed by
Contractor
759
6
0
5
0
0
770
Quantity
Landfilled
8,286
479
0
55
33
0
8,853
Quantity
Ponded
4,082
0
0
0
0
0
4,082
Quantity
used onsite,
given away,
or disposed
of in other
ways
708
5
0
0
0
0
713
Total
Quantity
Collected
for the
record year
(1994)
13,953
596
0
78
33
0
14,660
Source: EEI Power Statistics Database (1994 Data). Prepared by Utility Data Institute, McGraw-Hill, Washington, DC.
1995.
employed, the efficiency of reaction of the scrubber, and other factors. The
majority of FGD sludge is managed in onsite landfills or impoundments.
Table 16 presents an estimate of the 1990 coal ash generation by nonutility
fossil fuel combustors, broken out by major industrial category. Based on
EPA Office of Air and Radiation's 1990 Paniculate Inventory Database
(Version 3), the ash figures are derived from the estimated 1990 coal
consumption and coal ash content for the boiler population. The table
includes all coal combustors permitted as major sources of criteria pollutants
under the CAA and, therefore, includes many combustors that do not produce
electricity. The electric generators, however, may be expected to represent the
largest of the nonutility combustors and the greatest portion of the fuel usage
by that population, such that the estimates shown provide at least a fair
picture of the ability of the population to generate ash.
Compared with the utility coal ash estimates presented above, the nonutility
universe represents only roughly 5 percent of the total U.S. ash generation.
This fact reflects the generally small boiler size and the small aggregate coal
consumption represented by nonutility combustors. Two industry categories,
paper and chemicals manufacturing, represent 50 percent of all nonutility
coal consumption, with only five industry categories accounting for more
than 80 percent of all nonutility coal consumption.
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Section IV. Chemical Releases and Transfers
Table 16: Estimated Nonutility Generation of Coal Ash, 1990
Standard Industrial Classification
2600-2699, Paper and Allied Products
2800-2899, Chemicals and Allied Products
3300-3399, Primary Metals Industries
2000-2099, Food and Kindred Products
4900-4999, Electric, Gas, and Sanitary Services
3700-3799, Transportation Equipment
2200-2299, Textile Mill Products
1400-1499, Mining and Quarrying of Non-Metallic
Minerals, Except Fuels
3800-3899, Measuring, Analyzing, and Controlling
Instruments
3000-3099, Rubber and Miscellaneous Plastic Products
TOTALS (Top Ten Ash Producing SIC Categories)
Percentage of Total Universe
TOTALS (Complete Nonutility universe)
Number of
Facilities
139
116
45
94
29
57
58
7
1
20
566
76
749
Number
of Boilers
243
276
85
151
83
162
101
15
3
37
1,156
79
1,467
Total
Capacity
(MMBTU)
61,348
54,031
20,344
21,391
30,234
14,581
7,272
6,620
1,976
3,779
221,576
89
249,437
Estimated
Ash
Generation
(1,000 tons)
1,189
1,025
500
402
392
125
107
76
66
63
3,945
93
4,263
Source: Nonutility Fossil Fuel Combustion: Sources and Volumes - Revised Draft Report. Prepared for U.S.EPA, Office of
Solid Waste by Science Applications International Corporation, McLean, VA. December 1996.
As discussed previously, steam electric facilities may generate a variety of
other solid wastes. These may include boiler and cooling water treatment
wastes, coal mill rejects, boiler cleaning wastes, and a variety of smaller
waste streams incidental to power generation of ancillary activities. At coal
plants, these waste streams typically are small compared with ash and sludge
generation. At oil- and gas-fired plants, they may represent the largest solid
wastes present at the site. Unfortunately, available data sources do not
provide credible estimates of the total quantity of these materials generated
at utility and nonutility steam electric sites.
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Section IV. Chemical Releases and Transfers
IV.B Available Water Release Information for the Fossil Fuel Electric Power Generation
Industry
The EPA Office of Water, Office of Science and Technology, Engineering
and Analysis Division, has collected water release data in evaluating the need
for revisions to the 1982 Effluent Limitations Guidelines and Standards for
the Steam Electric Point Source Category. The EPA has identified 53
chemicals (29 priority and 24 nonconventional) as pollutants of interest in
wastewaters discharged from steam electric power generation facilities.
These pollutants were identified in the EPA Permit Compliance System
(PCS) database. The PCS is a computerized information management system
maintained by the EPA Office of Enforcement. The PCS contains data on
permit conditions, monitoring, compliance, and enforcement data for
facilities regulated by the National Pollutant Discharge Elimination System
(NPDES) Program. The information contained in the database is generally
limited to only those facilities that have been classified as "major" by EPA
based on factors such as effluent design flow and physical, chemical, and
locational characteristics of the discharge. Information on facilities
designated as "minor" is not required to be entered into the PCS database.
The data collected included 1992 records of pollutant releases from facilities
with primary SIC codes 4911 and 4931. Approximately 512 facilities were
identified in PCS as "major" steam electric facilities. Please note that
facilities that use nuclear energy to drive steam turbines are also covered in
the universe evaluated under this study. An option in the PCS system called
Effluent Data Statistics (EDS) was used to generate the annual loading
values. For the purposes of the effluent guideline study, the EDS-derived
data were subjected to numerous refinements in an attempt to overcome
limitations in the database. These refinements included review of the data by
monitored facilities, as arranged by the Utility Water Act Group (UWAG)
and the EEL The industry still contends, however, that the loadings of
pollutants in these data are over estimated.33 Therefore actual loadings
cannot be provided in this Sector Notebook.
Table 17 provides a list of the pollutants found in the 1992 PCS data for
steam electric effluents.
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Section IV. Chemical Releases and Transfers
Table 17: List of Pollutants Reported in 1992 PCS Data from Steam Electric Facilities*
Priority
Pollutant
X
X
X
X
X
X
X
X
X
X
X
X
Pollutant
Iron
Chlorine
Aluminum
Boron
Fluoride
Boric Acid
Zinc
Barium
Magnesium
Copper
Ammonia
Iron Sulfate
Manganese
Chromium, trivalent
Nickel
Lead
Arsenic
Chromium
Selenium
Bromine
Hydrogen Sulfide
Chromium, hexavalent
Cadmium
Vanadium
Cyanide
Phenol
Hydrazine
Priority
Pollutant
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Pollutant
Trichloromethane
Beryllium
Ethylene glycol
Nitrosomorphpline, N-
Mercury
Pentachlorophenol
Silver
Thallium
Antimony
Molybdenum
Benzonitrile
Titanium
Polychlorinated biphenyls, NOS
Dichloromethane
Tetrachloroethane
Dibenzofuran
Toluene
Xylene
Lithium
Benzene
Ethylbenzene
Phenanthrene
Pyrene
PCB-1254
PCB-1260
Chlorophenol, 2-
' Based on estimated data supplied by members (representing 80 facilities) of the electric utility industry.
Source: Preliminary Data Summary for the Steam Electric Point Source Category. U.S. Environmental Protection Agency, Office of
Water, Washington, D. C. July 1996. (EPA-921-R-96-010).
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Section IV. Chemical Releases and Transfers
IV.C Available Air Emissions Data for the Fossil Fuel Electric Power Generation
Industry
Three existing sources of data for estimating the releases to the air from the
fossil fuel electric power generation industry were identified. The following
sections discuss the available data and associated limitations.
IV.C.l Annual Emissions Estimated by the Department of Energy, Energy
Information Administration
Emissions data for traditional utility steam electric facilities that generate 10
or more megawatts electricity using fossil fuels are derived or obtained
directly from information collected in an annual survey by the DOE EIA.
This survey (Form EIA-767) is a restricted-universe census used to collect
boiler-specific data from almost 900 electric utility power plants. The
emissions are calculated based on fuel consumption data and using emission
factors from the EPA report AP-42, Compilation of Air Pollutant Emission
Factors and reduction factors for control equipment, where applicable. The
CO2 emissions are estimated using additional information about fuel quality.
Table 18 provides the estimated 1995 emissions for utility fossil fuel steam
electric generating units that generate 10 or more megawatts electricity.
Table 18: Estimated 1995 Emissions From Fossil Fuel Steam Electric Generating Units at
Electric Utilities by Fuel Type (thousand short tons)
Fuel
Coal
Gas
Petroleum
Net Generation
(thousand megawatts)
1,652,914
307,306
60,844
SO2
11,248
1
321
NOX
6,508
533
92
C02
1,752,527
161,969
50,878
Source: Electric Power Annual 1995, Volume 2. Energy Information Administration, Department of
Energy, Washington, DC. DOE/EIA-0348(95)/2. December 1996.
As indicated in the table, the majority of the emissions from utility fossil fuel
steam electric generating units come from coal-burning facilities. This is due
in part because there is more coal-fired capacity than other fossil-fueled
capacity in use. SO2 emissions are higher in coal-burning facilities due to the
higher sulfur content in coals than in other fuels. The average sulfur content
in coals ranges from 0.3 percent in the West to approximately 2.5 percent in
the East. Petroleum burned at utility power plants ranges from almost no
sulfur to about 3.5 percent. The amount of sulfur contained in natural gas is
relatively small.
Sector Notebook Project
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Fossil Fuel Electric Power Generation Section IV. Chemical Releases and Transfers
The Form EIA-767 does not collect data for facilities employing internal
combustion engines, gas turbines, or combined-cycle systems or steam
electric plants generating less than 10 megawatts electricity. The EIA
conducted a study in 1991 to estimate air emissions from these generating
units, using a methodology similar to that used on the larger steam electric
facilities. The study indicated that emissions of SO2, NOX, and CO2 are less
than 0.1,1.2, and 1.1 percent, respectively, of total utility air emissions.34
The EIA collects similar fuel consumption and quality information for
nonutility power producers. However, EIA provides only aggregate statistics
on estimated emissions for all fuels (fossil and renewable energy sources) and
does not separate out emissions for fossil-fueled facilities. These statistics
are not provided in this document since the capacity of nonutility generation
using nonrenewable energy sources is large.
IV.C.2 AIRS Database Annual Estimated Releases for the Electric Power
Generation Industry
The Aerometric Information Retrieval System (AIRS) is an air pollution data
delivery system managed by the Technical Support Division in EPA's Office
of Air Quality Planning and Standards (OAQPS), located in Research
Triangle Park, North Carolina. The AIRS is a national repository of data
related to air pollution monitoring and control. It contains a wide range of
information related to stationary sources of air pollution, including the
emission of a number of air pollutants that may be of concern within a
particular industry. States are the primary suppliers of data to AIRS. Data
are used to support monitoring, planning, tracking, and enforcement related
to implementation by EPA staff, the scientific community, other countries,
and the general public. The following criteria pollutant emissions and
estimated TRI pollutant release data for the fossil fuel electric power
generation industry were extracted from this database.
AIRS Estimated Criteria Pollutant Emissions
The AIRS database contains data on criteria pollutants: CO, NOX, particulate
matter (PM) of 10 microns or less (PM10), total particulate emissions (PT),
SO2, and VOCs. Criteria pollutant releases for the fossil fuel electric power
generation industry were accessed using SIC codes 4911 and 4931. It should
be noted that accessing the data using SIC codes does not allow the
segregation of emissions for facilities that use fossil fuels from facilities that
use nuclear, renewable, or a combination of fuels. Therefore, the annual
emissions taken from the AIRS database will overestimate the emissions
from the fossil fuel subsector of the power generation industry. Table 19
Sector Notebook Project 54 September 1997
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Fossil Fuel Electric Power Generation
Section IV. Chemical Releases and Transfers
presents the criteria pollutant data available for this industry. Pollutant
releases for other industries are also included in the table.
Table 19: Annual Air Pollutant Releases (tons/year)
Industry Sector
Metal Mining
Nonmetal Mining
Lumber and Wood Production
Furniture and Fixtures
Pulp and Paper
Printing
Inorganic Chemicals
Organic Chemicals
Petroleum Refining
Rubber and Misc. Plastics
Stone, Clay and Concrete
Iron and Steel
Nonferrous Metals
Fabricated Metals
Electronics and Computers
Motor Vehicles, Bodies, Parts and Accessories
Dry Cleaning
Transportation
Metal Casting
Pharmaceuticals
Plastic Resins and Synthetic Fibers
Textiles
Fossil Fuel ElectricPower Generation
Ship Building and Repair
CO
4,670
25,922
122,061
2,754
566,883
8,755
153,294
112,410
734,630
2,200
105,059
1,386,461
214,243
4,925
356
15,109
102
128,625
116,538
6,586
16,388
8,177
366,208
105
NO2
39,849
22,881
38,042
1,872
358,675
3,542
106,522
187,400
355,852
9,955
340,639
153,607
31,136
11,104
1,501
27,355
184
550,551
11,911
19,088
41,771
34,523
5,986,757
862
PM10
63,541
40,199
20,456
2,502
35,030
405
6,703
14,596
27,497
2,618
192,962
83,938
10,403
1,019
224
1,048
3
2,569
10,995
1,576
2,218
2,028
140,760
638
PT
173,566
128,661
64,650
4,827
111,210
1,198
34,664
16,053
36,141
5,182
662,233
87,939
24,654
2,790
385
3,699
27
5,489
20,973
4,425
7,546
9,479
464,542
943
SO2
17,690
18,000
9,401
1,538
493,313
1,684
194,153
176,115
619,775
21,720
308,534
232,347
253,538
3,169
741
20,378
155
8,417
6,513
21,311
67,546
43,050
13,827,511
3,051
voc
915
4,002
55,983
67,604
127,809
103,018
65,427
180,350
313,982
132,945
34,337
83,882
11,058
86,472
4,866
96,338
7,441
104,824
19,031
37,214
74,138
27,768
57,384
3,967
Source: U.S. EPA Office of Air and Radiation, AIRS Database, 1997.
AIRS Estimated TRI Pollutant Emissions
Data were collected from the AIRS database by the EPA Office of Pollution
Prevention and Toxics, Environmental Assistance Division, Toxics Release
Inventory Branch in support of the TRI expansion project discussed
Sector Notebook Project
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Fossil Fuel Electric Power Generation
Section IV. Chemical Releases and Transfers
previously. The data set that was downloaded included the most recent data
available for each facility up to and including 1995 data. The data presented
in Table 20 are estimates of TRI releases based on air releases reported in the
AIRS Facility Subsystem (AFS) from facilities within SIC codes 4911 and
4931. The data contain quantities of directly reported TRI chemicals, as well
as quantities of additional TRI chemicals extrapolated from reported releases
of PM and VOCs. The PM and VOC releases were matched with chemical
profiles contained in the SPECIATE database (Version 1.5). The SPECIATE
is a computerized format of the EPA Air Emissions Species Manual and is
available for download from the Clearing House of Inventory and Emissions
Factors (CHIEFs). The data presented are based only on apportionment of
"original" species profiles hi the SPECIATE database ~ those species
profiles that were developed specifically for the source of the release where
it has been applied. Despite the use of only the highest quality profiles hi the
SPECIATE database, these data should only be used as a preliminary
indication of potential releases and not as actual air releases. These data have
been provided for illustrative purposes only and should not be used in
comparisons with other release data.
IV.C.3 Hazardous Air Pollutant Emissions Estimates for Fossil Fuel Electric
Utility Steam Generating Units
Estimates of hazardous air pollutant (HAP) emissions from fossil fuel
electric utility steam generating units have been developed by OAQPS and
are reported hi a report entitled, Study of Hazardous Air Pollutant Emissions
from Electric Utility Steam Generating Units - Interim Final Report
(Volumes 1-3).35 These estimates are based on emissions test data from 52
units obtained from extensive emission tests by the EPRI, DOE, the Northern
States Power Company, and EPA. The testing program covered a wide range
of facility types with a variety of control scenarios. Therefore, the data are
considered to be generally representative of fossil fuel utility steam electric
generating units as a whole. This study estimated the average annual
emissions for each of 684 power plants. A total of 67 HAPs were identified
in the emission testing program as potentially being emitted from these
facilities.
It should be noted that the report states that because of the small sample sizes
for specific boiler types and control scenarios, there are uncertainties in the
data. Therefore, the data for individual plants may either underestimate or
overestimate the actual emissions. According to the report, the average
annual emissions estimates will be roughly within a factor of plus or minus
three of the actual annual emissions. However, it is recognized that the
analysis had numerous limitations, such as not including data on potential
upsets or unusual operating conditions, and it is possible that the range of
Sector Notebook Project
56
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Fossil Fuel Electric Power Generation
Section IV. Chemical Releases and Transfers
uncertainty is greater. Tables 21, 22, and 23 present data on estimated
inorganic HAPs from coal-fired, oil-fired, and gas-fired utility steam electric
facilities. Tables 24, 25, and 26 present data on estimated organic HAPs
from coal-fired, oil-fired, and gas-fired utility steam electric facilities.
Sector Notebook Project
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Fossil Fuel Electric Power Generation
Section IV. Chemical Releases and Transfers
Table 20: Estimated Releases of TRI Chemicals *
CAS
NO.
71556
79005
95636
106934
95501
107062
106990
541731
106467
112345
124174
111900
111773
111762
1 10805
111159
109S64
90437
101779
75070
107028
79107
107131
7429905
7664417
62533
120127
7440360
7440382
1332214
7440393
56553
71432
218019
50328
100447
7440417
92524
7726956
141322
123728
7440439
Chemical Name
1,1,1-Trichloroethane (Methyl chloroform)
1 , 1 ,2-Trichloroethane
1 ,2,4-Trimethylbenzene
1,2-Dibromoethane (Ethylene dibromide)
1 ,2-DichIorobenzene
1,2-Dichloroe thane (Ethylene dichloride)
1,3-Butadlene
1,3-Dichlorobenzene
1 ,4-Dichlorobenzene
2-(2-Butoxyethoxy)ethanol
2-(2-Butoxyethoxy)ethanoI acetate
2-(2-Ethoxyethoxy)ethanol
2-(2-Methoxyethoxy)ethanol
2-Butoxyethanol
2-Ethoxyethanol
2-Ethoxyethyl acetate
2-Mcthoxyethanol
2-PhcnylphenoI
4,4'-MethyIenedianiIine
Acctaldehyde
Acrolcin
Acrylic acid
Acrylonitrile
Aluminum (fume or dust)
Ammonia
Aniline
Anthracene
Antimony
Arsenic
Asbestos (friable)
Barium
Benz(a)anthracene
Benzene
Bcnzo(a)phenanthrene
Bcnzo(a)pyrene
Benzyl chloride
Beryllium
Biphcnyl
Bromine
Butyl acrylate
Butylaldehyde
Cadmium
Total Releases
(pounds per year)
52,923,638
422,954
264,682
1,820,797
22,292
35,222,942
7,443,883
672
378,018
103,100
0
885,978
0
21,929,191
998,125
111,202
60
8,507
43
2,010,699
1,528,324
3,657
783,041
75,792,629
43,518,590
311,982
139,265
1,789,097
9,329,119
8,123
1,435,995
1,839
149,967,605
1,609
1,381
0
10,997
85,493
949,230
11,240
110,921
13,733,816
Sector Notebook Project
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Fossil Fuel Electric Power Generation
Section IV. Chemical Releases and Transfers
Table 20 (continued): Estimated Releases of TRI Chemicals *
CAS
NO.
75150
56235
7782505
108907
75456
75003
67663
74873
126998
75729
7440473
7440484
7440508
8001589
1319773
98828
110827
108930
84742
75718
75092
76142
131113
106898
140885
100414
74851
107211
75218
7782414
50000
64186
76131
7647010
78842
67630
7439921
108383
108316
7439965
7439976
67561
Chemical Name
Carbon disulfide
Carbon tetrachloride
Chlorine
Chlorobenzene
Chlorodifluoromethane (HCFC-22)
Chloroethane (Ethyl chloride)
Chloroform
Chloromethane (Methyl chloride)
Chloroprene
Chlorotrifluoromethane (CFC-13)
Chromium
Cobalt
Copper
Creosote
Cresol (mixed isomers)
Cumene
Cyclohexane
Cyclohexanol
Dibutyl phthalate
Dichlorodifluoromethane (CFC-12)
Dichloromethane (Methylene chloride)
Dichlorotetrafluoroethane (CFC-1 14)
Dimethyl phthalate
Epichlorohydrin
Ethyl acrylate
Ethylbenzene
Ethylene
Ethylene glycol
Ethylene oxide
Fluorine
Formaldehyde
Formic acid
Freon 113 [Ethane, l,l,2-trichloro-l,2,2,-trifluoro-]
Hydrochloric acid
Isobutyraldehyde
Isopropyl alcohol (mfg-strong acid process)
Lead
m-Xylene
Maleic anhydride
Manganese
Mercury
Methanol
Total Releases
(Pounds per Year)
27,330,674
81,376
71,501,754
171,894
162,070
31,182,710
13,340
178,484
57,294
9,053
2,632,999
211,262
3,058,579
0
239,994
725,684
96,418,561
6,031
1,248,555
97,414
1,414,455,336
5,847
669,536
66,000
117,509
68,347,539
53,298,159
76,627
541,571
6,068,173
61,211,875
467,279
7,587,241
5,809,931
109,758
32,059,970
72,091,837
32,874,142
324,171
2,969,118
394,924
44 028 966
Sector Notebook Project
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Section IV. Chemical Releases and Transfers
Table 20 (continued): Estimated Releases of TRI Chemicals
CAS
NO.
96333
78933
108101
80626
74953
101688
101688
76153
68122
71363
1 10543
91203
7440020
7697372
98953
95476
106423
85018
108952
7723140
85449
123386
115071
75569
78922
7782492
7440224
100425
7664939
75650
127184
7440280
108883
79016
75694
7440622
108054
75014
1330207
7440666
Chemical Name
Methyl acrylate
Methyl ethyl ketone
Methyl isobutyl ketone
Methyl methacrylate
Melhylene bromide
Mcthylenebis(phenylisocyanate)(MBI)
Methylenebis(phenylisocyanate) (MDI)
Monochloropentafluoroethane (CFC-115)
N,N-Dimethylformamide
n-Butyl alcohol
n-Hcxane
Naphthalene
Nickel
Nitric acid
Nitrobenzene
o-Xylcne
p-Xyicne
Phcnanthrene
Phenol
Phosphorus (yellow or white)
Phthalic anhydride
Propionaldehyde
Propylene (Propene)
Propylene oxide
sec-Butyl alcohol
Selenium
Silver
Styrcne
Sulfuric acid
Tcrt-Butyl alcohol
TetrachloroethyIene(Perchloroethylene)
Thallium
Toluene
Trichloroethylene
Trichlorofluoromethane (CFC-1 1)
Vanadium (fume or dust)
Vinyl acetate
Vinyl chloride
Xylcne (mixed isomers)
Zinc (fume or dust)
Total Releases
(Pounds per Year)
0
91,926,327
20,020,683
16,208
52,241
130
130
6,199
2,700,310
12,653,277
107,548,181
434,275
7,884,920
214,564
0
41,115,640
2,327,391
84,032
15,017,545
7,980,941
2,491,887
49,400
45,955,707
183,593
990,420
173,886
289,686
28,155,503
1,320,503
4,660
14,623,885
<1
421,985,085
27,838,379
1,315,878
7,256,367
1,011,166
10,200,715
191,013,108
20,353,738
* Data in this table should not be used for comparison with other environmental data from other sources. It is only provided for
illustrative purposes. Please note the limitations of the data explained in the text.
Sector Notebook Project
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Fossil Fuel Electric Power Generation
Section IV. Chemical Releases and Transfers
Table 21: Median Emission Factors Determined From Test Report Data, and Total 1990 and
2010 HAP Emissions, Projected With the Emission Factor Program for Inorganic HAPs
From Coal-Fired Units *
Coal-Fired Units:
Inorganic HAPs
Antimony
Arsenic
Beryllium
Hydrogen Chloride
Hydrogen Cyanide
(HCN) t
Hydrogen Fluoride
Cadmium
Chromium
Cobalt
Lead
Manganese
Mercury
Nickel
Phosphorous (P)n
Selenium
Number of
Stack
Factors:
PM
Control "
7
21
12
15
All HCN
factors were
combined
14
18
22
10
21
21
20
21
AH P Factors
were
Combined
19
Median
Stack
Factor: PM
Control
(Ib/trillion
Btu)*"
1.4
2.9
0.45
21,000
Number of
Factors: 5
4,200
0.72
8.4
2.7
4.8
15
3.9
8.3
Number of
Factors: 10
62
Number of
Stack
Factors:
PMand
SO2
Control"
4
8
5
9
Median
Factor: 28
Ib/trillion Btu
6
9
10
6
9
9
10
10
Median Stack
Factor: PM
and SO2
Control
(Ib/trillion
Btu)"
0.13
0.9
0.14
1,290
106
1
4
1
5.8
15
3.4
5.2
Median Factor 31 Ib/trillion Btu
9
8
Estimate
d Total
1990
Emission
s (tons)
11
54
6.6
137,000
240
19,500
1.9
70
21
72
180
51
48
270
190
Estimated
Total 2010
Emissions
(tons)
14
62
7.6
150,000
320
25,600
2.3
83
27
83
232
65
57
350
230
* Compounds are listed in the following sequence: inorganic, organic, and dioxin/furan/polycyclic aromatic
hydrocarbons (PAHs). Median emission factors were determined from organic HAP concentrations at the stack,
control device outlet, or boiler outlet when at least one of typically three measured flue gas concentrations was
detected.
** Stack factors for inorganic HAPs were taken from test reports when at least one of typically three measured
flue gas concentrations was detected. These factors were not used to develop the estimated emissions.
*** Since the inorganic emissions were not directly estimated from stack factors, total emissions of inorganic
HAPs projected with the computer program and from median stack factors will vary.
f Nationwide hydrogen cyanide emissions were detected from stack emission factors and not from emission
median factors.
tf Nationwide phosphorous emissions were detected from stack emission factors and not from emission median
factors.
Source: Study of Hazardous Air Pollutant Emission from Electric Utility Steam Generating Units Interim Final
Report, Volumes 1-3. U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards.
Research Triangle Park, NC. EPA-453/R-96-013b. October 1996.
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Section IV. Chemical Releases and Transfers
Table 22: Median Emission Factors Determined From Test Report Data, and Total 1990 and 2010 HAP
Emissions, Projected With the Emission Factor Program for Inorganic HAPs From Oil-Fired Units *
Oil-Fired Units:
Inorganic HAPs
Arsenic
Beryllium
Cadmium
Chromium
Cobalt
Hydrogen Chloride
Hydrogen Fluoride
Lead
Manganese
Mercury
Nickel
Phosphorous (P)f
Selenium
Number of
Stack
Factors: PM
Control "
2
2
1
4
2
4
3
3
3
3
4
A11P
Factors were
Combined
1
Median
Stack
Factor: PM
Control
Ob/trillion
Btu)'"
0.32
0.33
0.32
3.7
6.1
2900
230
2.6
15
0.24
180
Number of
Factors: 3
1.4
Number of
Stack Factors:
NoPM
Control "
8
4
9
8
3
2
2
8
9
3
9
Median
Stack
Factor: No
PM Control
(Ib/trillion
Btu) *"
5.3
0.21
1.6
5.7
27
2300
140
9
16
0.48
410
Median Factor 1 10 Ib/trillion
Btu
8
3.8
Estimated
Total 1990
Emissions
(tons)
5
0.45
1.7
4.7
20.3
2870
144
10.6
9.5
0.25
389
68
1.7
Estimated
Total 2010
Emissions
(tons)
2.5
0.23
0.87
2.4
10.3
1456
73
5.3
4.8
0.13
197
34
0.84
* Compounds are listed in the following sequence: inorganic, organic, and dioxin/furan/polycyclic aromatic
hydrocarbons (PAHs). Median emission factors were determined from organic HAP concentrations at the
stack, control device outlet, or boiler outlet when at least one of typically three measured flue gas
concentrations was detected.
" Stack factors for inorganic HAPs were taken from test reports when at least one of typically three measured
flue gas concentrations was detected. These factors were not used to develop the estimated emissions.
*"* Since the inorganic emissions were not directly estimated from stack factors, total emissions of inorganic HAPs
projected with the computer program and from median stack factors will vary.
* Nationwide phosphorous emissions were detected from stack emission factors and not from emission median
factors.
Source: Study of Hazardous Air Pollutant Emission from Electric Utility Steam Generating Units Interim Final
Report Volumes 1-3. U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards.
Research Triangle Park, NC. EPA-453/R-96-013b. October 1996.
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Section IV. Chemical Releases and Transfers
Table 23: Median Emission Factors Determined From Test Report Data, and Total 1990 and 2010
HAP Emissions, Projected With the Emission Factor Program for Inorganic HAPs From Gas-Fired Units *
Gas-Fired Units: Inorganic
HAPs
Arsenic
Cadmium
Chromium
Cobalt
Lead
Manganese
Mercury
Nickel
Phosphorous
Number of Stack
Factors: No PM
Control
2
1
2
1
2
2
2
2
1
Median Stack
Factor: No PM
Control
(Ib/trillion Btu)
0.14
0.044
0.96
0.12
0.37
0.3
<0.38
2.3
2.2
Estimated Total
1990 Emissions
(tons)
0.16
0.054
1.2
0.14
0.44
0.37
0.0016
2.3
1.3
Estimated Total
2010 Emissions
(tons)
0.25
0.086
1.9
0.23
0.68
0.59
0.0024
3.5
2
Compounds are listed in the following sequence: inorganic, organic, and dioxin/furan/polycyclic aromatic
hydrocarbons (PAHs). Median emission factors were determined from organic HAP concentrations at the
stack, control device outlet, or boiler outlet when at least one of typically three measured flue gas
concentrations was detected.
Source: Study of Hazardous Air Pollutant Emission from Electric Utility Steam Generating Units Interim Final
Report Volumes 1-3. U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards.
Research Triangle Park, NC. EPA-453/R-96-013b. October 1996.
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Section IV. Chemical Releases and Transfers
Table 24: Median Emission Factors From Test Report Data, and Total 1990 and 2010 HAP Emissions,
Projected With the Emission Factor Program for Organic HAPs From Coal-Fired Units
Coal-Fired Units: Organic HAP
1,1,2-Trichlorocthane
2-chloroacctophcnonc
2,4 -Dinitro toluene
Acctaldchydc
Acctophcnone
Acrolcin
Benzene
Benzyl chloride
Bis{2-cthylhcxyl) phthalate
Bromoform
Carbon distil fide
Carbon tetrachloridc
Chlorobcnzcnc
Chloroform
Cumcnc
Dibutyl phthalate
Ethylbcnzcne
Ethylchloridc
Methylchloroform
Ethylcncdichloride
Formaldehyde
Hcxanc
Hcxachlorobcnzcnc
Isophoronc
Methylbromlde
Methylchloridc
McUiylcthylketonc
Methyliodidc
Methylisobutyl kctone
Mcthylmcthacrylate
Methyltcrtbutylcthcr
Mcthylcncchloridc
Number
of
Emission
Factors
l
3
3
12
7
6
20
1
9
1
8
2
2
2
1
5
5
1
4
3
15
2
1
2
6
3
6
1
3
1
1
5
Median
Emission
Factor
(Ib/trillion
Btu)
4.7
0.29
0.015
6.8
0.68
3.3
2.5
0.0056
4.1
6.6
4.3
3.3
3.2
3.2
0.29
2.8
0.40
2.4
3.4
3.1
4.0
0.82
0.079
24
0.88
5.9
8.0
0.40
4.9
1.1
1.4
13
Computer
Program:
1990 Total
Tons
40
2.4
0.13
58
5.8
28
21
0.048
35
57
37
28
27
28
2.5
24
3.5
20
29
27
35
6.9
0.68
200
7.7
51
69
3.4
42
9.3
12
110
Computer
Program:
2010 Total
Tons
53
3.2
0.17
76
7.7
37
28
0.063
46
75
48
37
36
36
3.2
32
4.6
27
38
35
45
9.1
0.89
270
10
67
90
4.5
53
12
16
150
Sector Notebook Project
64
September 1997
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Fossil Fuel Electric Power Generation
Section IV. Chemical Releases and Transfers
Table 24 (continued) : Median Emission Factors From Test Report Data, and Total 1990 and 2010 HAP
Emissions, Projected With the Emission Factor Program for Organic HAPs From Coal-Fired Units
Coal-Fired Units: Organic HAP
n-nitrosodimethylamine
Naphthalene
n,p-cresol
o-cresol
p-cresol
perylene
Pentachlorophenol
Phenol
Phthalicanhydride
Propionaldehyde
Quinoline
Styrene
Tetrachloroethylene(PerchloroethyIene)
Toluene
Trans 1,3-dichloropropene
Trichloroethylene
Vinyl acetate
Vinylidnechloride
Xylene
o-xylene
m,p-xylene
Total TEQ' for 2,3,7,8-tetra-chlorodibenzo-p-dioxin
2,3,7,8-tetrachloride-benzo-p-dioxin
1,2,3,7,8-pentachlorodi-benzo-p-dioxin
1,2,3,4/7,8-hexachlorodi-benzo-p-dioxin
1,2,3,6,7,8-nexachlorodi-benzo-p-dioxin
1,2,3,7,8,9-hexachlorodi-benzo-p-dioxin
1,2,3,4,6,7,8-heptaehlorodi-benzo-p-dioxin
Heptachlorodi-benzo-p-dioxin
Hexachlorodi-benzo-p-dioxin
Octachlorodi-benzo-p-dioxin
Pentachlorodi-benzo-p-dioxin
Number
of
Emission
Factors
l
11
2
3
1
1
1
10
1
4
1
7
5
17
1
1
1
2
2
5
8
-
4
3
4
4
4
9
6
8
6
6
Median
Emission
Factor
(Ib/trillion
Btu)
0.68
0.77
0.68
1.7
0.95
0.075
0.0082
6.1
4.9
10
0.053
3.1
3.1
3.6
4.7
3.1
0.42
9.7
4.7
0.82
1.5
-
1.6 xlO-6
4.3 x 10-*
9.7 x 10*
5.8 x 10-6
7.3 x 10*
5.7 x 10*
l.lxlO"4
2.4 x lO'5
5.8 x 10'5
9.8x10*
Computer
Program:
1990 Total
Tons
5.9
6.6
5.8
14
8.2
0.65
0.070
52
42
89
0.46
27
27
31
40
27
3.5
84
40
6.9
13
1.5 xlO-4
1.4 xlO-5
3.7 x 10'5
8.3 x 10-5
5.0 x lO'5
6.3 x lO'5
4.9 xlO-5
9.2 xlO"4
2.1 x 10-"
5.0 xlO"
8.5 x 10-5
Computer
Program:
2010 Total
Tons
7.7
8.7
7.6
19
11
0.85
0.093
69
56
120
0.61
35
35
41
53
35
4.6
110
53
9.1
17
2.0 x 10-"
1.9 xlO-5
4.8 x 10-5
l.lxlO"4
6.6 x 10-5
8.3 x lO'5
6.5 x lO'5
1.2x10-'
2.7 x 10-4
6.6 x 10"4
l.lxlO-4
Sector Notebook Project
65
September 1997
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Fossil Fuel Electric Power Generation
Section IV. Chemical Releases and Transfers
Table 24 (continued) : Median Emission Factors From Test Report Data, and Total 1990 and 2010 HAP
Emissions, Projected With the Emission Factor Program for Organic HAPs From Coal-Fired Units
Coal-Fired Units: Organic HAP
Tctrach!oridc-bcnzo-p-dioxin
2,3,7,8-tetraehloritIe-benMfuran
1 ,2,3,7,8-pcntachlorodi-benzofuran
2,3,4,7,8-pentachIorodi-benzofuran
1,2,3,4,7,8-hcxachlorodi-benzofuran
1^,3,6,7,8-hcxachlorodi-benzofuran
1 ,2,3,7,8,9-hexachIorodi-bcnzofiiran
2,3,4,6,7,8-hcxachIorodi-benzofuran
1,2,3,4,6,7,8-heptachIorodi-benzofiiran
1,2,3,4,7,8,9-hcptachlorodi-benzoftiran
Heptachlorodi-bcnzofuran
Hcxachlorodi-benzofuran
Octachlorodl-benzofuran
Pcntachlorodi-bcnzofuran
Tctrachloridc-bcnzofuran
1 -methylnaphthalcne
2-chloronaphthalcnc
2-mcthylnaphthalenc
Acenapihenc
Accnapthylene
Anthracene
I3cnz(n)anthraccne
Bcnzo{a)pyrcnc
Bcnzo(e)pyrene
Qenzo(b)fluoranthcnc
Benzo(b+k)fluoranthcne
Bcnzo(k)fluoranthcne
Bcnzo(g,h,i)pcrylcnc
Biphcnyl
Chjyscne
Dibcnzo(a,h)anthacene
Fluoranthcnc
Number
of
Emission
Factors
9
8
5
5
6
5
4
5
8
4
8
8
10
9
10
2
2
6
6
5
4
4
6
1
1
1
1
2
1
4
1
6
Median
Emission
Factor
(Ib/trillion
Btu)
7.1 x 10"6
3.9 x 10"6
2.4 xlO"6
1.0 xlO'5
l.SxlO-5
4.0 x 10-6
8.5 x 10*
1.6xlO-5
2.0 xlO'5
1.7 xlO-1
2.4 x 10-5
1.9 xlO'5
1.7xlO'5
1.8 xlO'5
1.2 xlO'5
0.0085
0.04
0.024
0.008
0.0042
0.0042
0.0021
0.001
0.0012
0.0081
0.0016
0.0036
0.0032
0.34
0.0026
0.0003
0.007
Computer
Program:
1990 Total
Tons
6.1 x 10'5
3.4 x lO'5
2.1 x 10'5
9.0 x 10-5
LlxlO4
3.4x10-'
7.3 x lO'5
1.4 xlO"4
1.7 xlO"4
1.5 xlO'3
2.1 x lO"4
1.6 xlO"1
1.4 xlO"4
1.6 xlO"4
1.0 xlO"4
0.076
0.35
0.2
0.07
0.036
0.036
0.018
0.0088
0.01
0.07
0.014
0.031
0.028
3.1
0.022
0.003
0.06
Computer
Program:
2010 Total
Tons
8.0 x lO'5
4.5 x 10-5
2.8 x 10-5
1.2x10^
1.5 x 10"4
4.5 x 10'5
9.6 xlO'5
1.8 xlO"4
2.2 xlO"1
2.0 x 10-'
2.7 x ID"4
2.1 x 10"4
1.9 xlO"4
2.1 x 10-4
1.3 xlO-4
0.1
0.46
0.26
0.09
0.047
0.047
0.002
0.012
0.014
0.092
0.018
0.04
0.036
4
0.03
0.004
0.082
Sector Notebook Project
66
September 1997
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Fossil Fuel Electric Power Generation
Section IV. Chemical Releases and Transfers
Table 24 (continued) : Median Emission Factors From Test Report Data, and Total 1990 and 2010 HAP
Emissions, Projected With the Emission Factor Program for Organic HAPs From Coal-Fired Units
Coal-Fired Units: Organic HAP
Fluorene
Indeno(l ,2,3 -c,d)pyrene
Phenanthrene
Pyrene
Number
of
Emission
Factors
5
2
7
4
Median
Emission
Factor
(Ib/trillion
Btu)
0.013
0.0064
0.032
0.009
Computer
Program:
1990 Total
tons
0.11
0.054
0.031
0.081
Computer
Program:
2010 Total
tons
0.15
0.072
0.36
0 103
Toxic equivalent emissions.
Source: Study of Hazardous Air Pollutant Emission from Electric Utility Steam Generating Units-Interim Final Report, Volumes 1-3. U.S.
Environmental Protection Agency, Office of Air Quality Planning and Standards. Research Triangle Park, NC. October 1996. EPA-453/R-
96-013b.
Sector Notebook Project
67
September 1997
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Fossil Fuel Electric Power Generation
Section IV. Chemical Releases and Transfers
Table 25: Median Emission Factors From Test Report Data, and Total 1990 and 2010 HAP
Emissions, Projected With the Emission Factor Program for Organic HAPs From
Oil-Fired Units
Oil-Fircd Units: Organic HAPs
Benzene
Ethylbcnzcne
Formaldehyde
Melhylchloroform
Methylcneehloride
Naphthalene
Phenol
Tctrachlorocthylcne (Perchloroethylene)
Toluene
Vinyl acetate
o-Xylcnc
m,p-Xylcnc
Total TEQ* for 2,3,7,8-tetra-chlorodibenzo-p-dioxin
2,3,7.8-tetrachloride-bcnzo-p-dioxin
1,2,3,7,8-pcntachlorodi-benzo-p-dioxin
1.2,3,4,7,8-hcxachIorodi-bcnzo-p-dioxin
1,2,3,6,7,8-hcxachlorodl-benzo-p-dioxin
1,2,3,7,8,9-hexachIorodi-benzo-p-dioxin
1,2.3,4,6,7,8-hcptachlorodi-benzo-p-dioxin
Hcptach!orodi-bcnzo-p-dioxin
Hcxachlorodi-benzo-p-dioxin
Octachlorodi-bcnzo-p-dioxin
Pentachlorodi-benzo-p-dioxin
Tctfichloridc-benzo-p-dioxin
2,3,7,8-tetrachloride-bcnzofuran
1 ,2.3,7,8-pcntachlorodi-bcnzofuran
2,3,4.7,8-pentachlorodi-benzoftiran
1,2,3,4,7,8-hexachIorodi-benzofuran
1 ,2,3,6,7,8-hcxachlorodl-benzofuran
Number of
Emission
Factors
i
6
2
9
3
2
4
2
1
6
2
1
2
_
1
2
1
2
2
2
2
2
1
2
2
2
2
2
2
2
Median
Emission
Factor
(Ib/trillion
Btu)
8.2
1.4
0.49
30
7.6
32
0.33
24
0.55
8
5.2
0.84
1.4
6.5 x 10"6
5.8 x 10*
1.2 xlO-5
5.4 x 10-5
8.3 x 10*
2.0 x 10-5
2.0 x 10-5
8.1 x 10-*
2.3 x 10'5
5.8 xlO"6
5.7 x 10*
4.6 x lO"6
4.3 x 10-*
4.8 x 10*
6.1 x 10*
3.8 xlO*
Computer
Program:
1990 Total
Tons
5
0.88
0.29
19
4.6
20
0.21
15
0.34
4.9
3.2
0.51
0.82
1.1 x 10-5
4.5 x 10*
3.5 x 10*
7.6x10*
3.3 x 106
5.1 x 10*
1.2xlO'3
1.2xlO'5
5.0 x 10*
1.4 xlOJ
3.5 x 10*
3.4 x 10*
2.9x10*
2.6 x 10*
3.0x10*
3.7 x 10*
2.3 x 10*
Computer
Program:
2010 Total
Tons
2.6
0.45
0.15
9.5
2.4
10
0.1
7.5
0.17
2.5
1.6
0.26
0.42
5.4x10*
2.0x10*
1.8x10*
3.9 x 10*
1.7x10*
2.6 x 10*
6.2 x 10*
6.2 x 10*
2.5 x 10*
7.3 x 10*
1.8x10*
1.8 x 10*
1.4x10*
1.3x10*
1.5x10*
1.9x10*
1.2x10*
Sector Notebook Project
68
September 1997
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Fossil Fuel Electric Power Generation
Section IV. Chemical Releases and Transfers
Table 25 (continued): Median Emission Factors From Test Report Data, and Total 1990 and 2010
HAP Emissions, Projected With the Emission Factor Program for Organic HAPs From
Oil-Fired Units
Oil-Fired Units: Organic HAPs
1,2,3,7,8,9-hexachlorodi-benzofiiran
2,3,4,6,7,8-hexachlorodi-benzofuran
1,2,3,4,6,'7,8-heptachIorodi-benzofuran
1,2,3,4,7,8,9-heptachlorodi-benzofuran
Heptachlorodi-benzofuran
Hexachlorodi-benzofuran
Octachlorodi-benzofuran
Pentachlorodi-benzofiiran
Tetrachloride-benzofuran
2-methylnaphthalene
Acenaphthene
Acenaphthylene
Anthracene
Benz(a)anthracene
Benzo(b+k)fluoranthene
Benzo(g,h,i)perylene
Chrysene
Dibenzo(a,h)anthracene
Fluoranthene
Fluorene
Indeno(l ,2,3-c,d)pyrene
Nitrobenzofluoranthene
Nitrochrysene/benzanthracene
Phenanthrene
Pyrene
Number of
Emission
Factors
2
1
1
1
1
2
1
2
2
4
2
1
2
3
2
2
3
2
6
5
2
1
1
9
6
Median
Emission
Factor
(Ib/trillion
Btu)
5.8 xlO*
4.8 x ID"6
9.4 xlO"6
l.OxlO'5
1.5 x 10"6
9.6 x 10-6
1.0 x lO'5
7.3 x 10"6
5.0 xlO-6
0.017
0.38
0.017
0.015
0.03
0.033
0.021
0.021
0.0081
0.016
0.021
0.024
0.015
0.016
0.025
0.037
Computer
Program:
1990 Total
Tons
3.5 xlO"6
3.0 x 10-6
5.7 x 10-*
6.2 x 10^
8.8 x 10-'
5.8 x 10-6
6.2 x 10-6
4.4 xlO"6
3.1 x 10-°
0.01
0.22
0.01
0.0093
0.018
0.02
0.013
0.013
0.005
0.0097
0.013
0.014
0.0092
0.0098
0.015
0.022
Computer
Program: 2010
Total Tons
1.8 xlO-6
1.4 xlO-6
3.0 x 10"6
3.2 x 10"6
4.4 x 10-'
3.0 xlO-6
3.2 xlO*
2.2 x 10-6
1.5 xlO"6
0.0052
0.11
0.0052
0.0047
0.0092
0.01
0.0065
0.0066
0.0025
0.0049
0.0065
0.0073
0.0047
0.005
0.0077
0.011
* Toxic equivalent emissions
Source: Study of Hazardous Air Pollutant Emission from Electric Utility Steam Generating Units-Interim Final Report, Volumes 1-3. U.S.
Environmental Protection Agency, Office of Air Quality Planning and Standards. Research Triangle Park, NC. October 1996. EPA-453/R-96-
Sector Notebook Project
69
September 1997
-------
Fossil Fuel Electric Power Generation
Section V. Pollution Prevention Opportunities
Table 26: Median Emission Factors From Test Report Data, and Total 1990
and 2010 HAP Emissions, Projected With the Emission Factor Program for Organic HAPs From
Gas-Fired Units
Gas-Fired Units: Organic HAPs
Benzene
Formaldehyde
Naphthalene
Toluene
2-methylnaphthalene
Fluoranthcne
Fluorene
1-phenanthrene
Pyrene
Number of
Emission
Factors
1
8
2
2
2
1
1
2
1
Median
Emission
Factor
(Ib/trillion
Btu)
1.4
35.5
0.7
10
0.026
0.0028
0.0026
0.013
0.0049
Computer
Program:
1990 Total
Tons
1.8
55
0.66
13
0.025
0.0034
0.0034
0.016
0.0061
Computer
Program: 2010
Total Tons
2.7
83
1
19
0.038
0.0055
0.0051
0.024
0.0094
Source: Study of Hazardous Air Pollutant Emission from Electric Utility Steam Generating Units-Interim Final Report,
Volumes 1-3. U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards. Research Triangle Park,
NC. October 1996. EPA-453/R-96-013b.
Sector Notebook Project
70
September 1997
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Fossil Fuel Electric Power Generation Section V. Pollution Prevention Opportunities
V. POLLUTION PREVENTION OPPORTUNITIES
The best way to reduce pollution is to prevent it in the first place. Some
companies have creatively implemented pollution prevention techniques that
improve efficiency and increase profits while at the same time minimizing
environmental impacts. This can be done in many ways, such as reducing
material inputs, re-engineering processes to reuse byproducts, improving
management practices, and employing substitution of toxic chemicals. Some
smaller facilities are able to actually get below regulatory thresholds just by
reducing pollutant releases through aggressive pollution prevention policies.
The Pollution Prevention Act of 1990 established a national policy of
managing waste through source reduction, which means preventing the
generation of waste. The Pollution Prevention Act also established as
national policy a hierarchy of waste management options for situations in
which source reduction cannot be implemented feasibly. In the waste
management hierarchy, if source reduction is not feasible the next alternative
is recycling of wastes, followed by energy recovery, and waste treatment as
a last alternative.
hi order to encourage these approaches, this section provides both general and
company-specific descriptions of some pollution prevention advances that
have been implemented within the fossil fuel electric power generation
industry. While the list is not exhaustive, it does provide core information
that can be used as the starting point for facilities interested hi beginning their
own pollution prevention projects. This section provides summary
information from activities that may be, or are being implemented by this
sector. When possible, information is provided that gives the context in
which the technique can be used effectively. Please note that the activities
described in this section do not necessarily apply to all facilities that fall
within this sector. Facility-specific conditions must be carefully considered
when pollution prevention options are evaluated, and the full impacts of the
change must examine how each option affects air, land and water pollutant
releases.
Coal is considered the primary energy source for power generation now and
in the future. Coal is relatively abundant and inexpensive. However,
environmental impacts associated with coal combustion, most notably, acid
rain, represent a cost to the environment and human health. This section
emphasizes technologies for coal-fired electric power generation plants, but
includes pollution prevention practices that apply to other fossil fuel electric
plants as well. Many of the technologies and practices may be employed in
existing plants, in the repowering of existing plants, and in the design and
construction of new plants.
Sector Notebook Project
71
September 1997
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Fossil Fuel Electric Power Generation
Section V. Pollution Prevention Opportunities
V.A Pollution Prevention Technologies in the DOE Clean Coal Technology
Demonstration Program
The DOE is charged with protecting the Nation's energy interests. In
recognition of the vital role of coal as a sustainable energy source, DOE
vigorously researches and promotes ways to reduce the environmental
impacts associated with coal combustion under the Clean Coal Technology
Demonstration (CCT) Program. Specific goals of the CCT Program include
(1) increasing the efficiency of electricity production and (2) enhancing the
efficient and cost effective use of U.S. coal reserves, while ensuring
achievement of national and environmental goals.
One way in which the CCT Program progresses towards these goals is by
building a portfolio of advanced, coal-based technology demonstration
projects. Included in the portfolio are technologies that result in improved
efficiency with fewer environmental consequences. The technologies
demonstrated under the CCT Program include commercially viable
processes, as well as projects whose commercial viability is still being
explored. These technologies may be categorized as (1) power systems, (2)
environmental control devices, and (3) clean coal processing. Pollution
prevention technologies being demonstrated under the CCT Program are
included under the categories labeled "power systems" and "clean coal
processing." Technologies categorized as "environmental control devices"
may not be considered pollution prevention technologies; however, they may
enable the recovery of pollutants for subsequent reuse/resale in products.
A brief discussion of emerging power systems and coal processing
technologies being demonstrated under the CCT Program is provided below.
DOE's Clean Coal Technology Demonstration Program, Program Update
1995 (April 1996) provides a more detailed discussion.
V.A.1 Emerging Technologies
Pollution prevention opportunities in advanced coal-fired power systems are
realized by the increase in overall efficiency of the combustion (electricity
produced per amount of fuel) resulting in the reduction of environmental
pollutants released. Efficiency of a technology is determined by the portion
of energy hi fuel that is converted into electricity. Thus, the process of
combustion and heat transfers are critical variables. In considering advanced
technologies, one must consider the environmental transfer of wastes from
one media to another. Unless the transfer represents a more manageable form
of the waste, there may be little or no environmental gain.
Sector Notebook Project
72
September 1997
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Fossil Fuel Electric Power Generation
Section V. Pollution Prevention Opportunities
A brief description of power system technologies is provided below. While
none of the technologies described are currently commercially viable, they
may be in the future. Table 27 summarizes demonstration projects for power
system technologies funded by DOE and participating companies.
Table 27: Summaries of Clean Coal Technologies Under DOE's Clean Coal Technology
Demonstration Program
Demonstration: Pressurized Fluidized-Bed Combustion Combined-cycle. Tidd Proiect-The Ohio Power
Company
Status: Completed on the 70 MW scale, future testing on 340 MW scale planned.
Size: 55 MW steam turbine, 15 MW gas turbine
Efficiency; Combustion efficiency of 99.6%. Heat rate efficiency of 33.2percent
Environmental Benefits: SO2 removal of up to 95%. Resulting NOX emissions ofO. 15-0.33lb/million Btu.
Demonstration: Inteerated Gasification Combined-cycle Repowerine Project
Status: Currently still in design stage.
Size: 65 MW
Projected Efficiency: Heat efficiency of approximately 43%.
Environmental Benefits: Expected CO2 reduction, improved efficiency over coal-fired plant -with flue gas
desulfurization.
Demonstration: Indirect Fired Cycle-Repowering. Pennsylvania Electric Co. Warren Station. Unit No. 2
Status: Currently still in design stage.
Size: 62.4 MW
Projected Heat Rate: 9,650 BTU/KWh (31.3% improvement over existing).
Environmental Benefits: Eliminates the need for hot gas cleanup systems.
Demonstration: Coal Diesel Combined-Cycle Project. Arthur D. Little. Inc.
Status: Currently in design stage.
Size: 14 MW
Projected Efficiency: Heat efficiency of approximately 48%.
Environmental Benefits: Emissions reductions to levels of50%-70% below NSPS.
Demonstration: Slagging Combustor. Heavy Clean Coal Project. Alaska Industrial Development and Export
Authority. Golden Valley Electric Association
Status: Currently in construction stage.
Size: 50 MW
Projected Efficiency: Projected SO2 removal of 90%, NOX emissions/million BTU emissions of less than 0.015
Ib/million BTU, particulates of 0.0015 Ib/million BTU.
Environmental Benefits: SO2, NOX, particulates emissions reductions.
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Fluidized-Bed Combustion
Section V. Pollution Prevention Opportunities
Fluidized bed combustion (FBC) technology includes three designs:
atmospheric, pressurized, and two-stage bubbling bed. Although FBC
technology is not yet widespread in the industry, it allows any kind of fuel to
be burned while controlling the emission of SO2 without the use of a flue gas
scrubbing device. In the FBC process, a sorbent, such as crushed limestone,
is introduced with pulverized coal in the combustion chamber. Air forced
into the combustion chamber suspends the coal-limestone mixture. Sulfur,
released from the coal, combines with the sorbent to form a solid waste that
is relatively easy to handle and dispose of. The advantage of FBC
technology is that it creates a turbulent environment conducive to a high rate
of combustion and a high rate of sulfur capture and allows for lower
operating temperatures than conventional boilers. Because operating
temperatures are below the threshold of thermally induced NOX formation,
NOX emissions are reduced. In addition, the operating temperature tends to
be below the ash fusion range for coal, resulting in less wastes present in
fireside wash waters and less frequent cleaning requirements.
Integrated Gasification Combined-cycle
In the IGCC, coal is converted into a gaseous fuel, purified, and combusted
in a gas turbine generator to produce electricity. The constituents react to
produce a fuel gas. Heat from the exhaust gas is recovered and used to
generate steam, which produces additional electricity. Gasification is a
process in which coal is introduced to a reducing atmosphere with oxygen or
air and steam. In some systems, a limestone sorbent is added to the gasifier
for sulfur removal. The environmental advantages of IGCC include:
High efficiency
Removal of nitrogen, sulfur, and particulates prior to the addition of
combustion air, thereby lowering the volume of gas requiring treatment
Sulfur in the gas is in the form of hydrogen sulfide, which is removable
to a greater extent than SO2
NOX removal of more than 90 percent
Reduced CO2 emissions compared to traditional coal-fired boilers.
Currently, gas cleanup in IGCC requires the gas to be cooled; however, hot
gas cleanup systems are being developed that will remove 99.9 percent of the
sulfur and result in a saleable sulfur product. The IGCC system is well suited
for repowering because it can use the existing steam turbine, electrical
generator, and coal-handling facilities in most cases.
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Indirect-Fired Cycle
Section V. Pollution Prevention Opportunities
An indirect-fired cycle operates such that coal or biomass combustion
products do not come hi direct contact with gas turbine components. Instead,
heated gases pass on the shell side of an air heater. On the tube side of the
air heater, compressed gas is heated and passes through a gas turbine. The
environmental advantage is that this eliminates the need for hot gas cleanup
since the corrosive and abrasive fuel products do not come into direct contact
with the turbines. Heat is recovered from air heater exhaust and is used to
produce steam, which powers a steam turbine. In addition, corrosive gas
products do not come into direct contact with the turbine, thereby eliminating
the need for hot gas cleanup. Although the technology is still in the design
stage, the efficiency is expected to be 20 percent greater than that of a
pulverized coal plant. Furthermore, SO2 reductions of 90 percent, as well as
reduced NOX and particulate emissions, are expected.
Integrated Gasification Fuel Cell
An integrated gasification fuel cell system consists of a coal gasifier with a
gas cleanup system, a fuel cell, an inverter, and a heat recovery system. Coal
gas, made through the reaction of steam, oxygen, and limestone, is introduced
to a fuel cell composed of an anode and a cathode and separated by an
electrolytic layer. The fuel cell converts the chemical energy of the gas to
direct current electrical energy and generates heat, and an inverter converts
direct current to alternating current. A heat recovery system delivers heat to
a bottoming steam cycle for further generation of electricity. Pollution
prevention is realized by improved emissions reduction associated with the
gas cleanup system and solid waste reduction.
Coal-Fired Diesel
Diesel generators are modified to accept a coal/water slurry as a fuel source.
Environmental control systems are typically installed to remove NOX, SO2,
and particulates. The advantage of a coal-fired diesel system is that it is well
suited to small generators (below 50 megawatts). In addition, it is estimated
to result in emissions reduction of 50 percent below New Source
Performance Standards. Similarly, coal-oil mixture technology can replace
up to 50 percent of fuel oil with pulverized coal for burning in conventional
oil or gas burners.
Slagging Combustor
In a slagging combustor, coal is burned at very high combustion temperatures
outside the furnace cavity, and combustion gasses pass into the boiler, where
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heat exchange takes place. In a conventional boiler, the ash enters the boiler
and collects on boiler tubes, thus decreasing the efficiency of heat exchange.
Alternatively, the high temperature of the slagging combustor causes ash to
form slag, which is collected in cyclones. The advantage of the slagging
combustor is that it prevents a loss in heat exchange efficiency that would
occur from ash accumulation on boiler tubes.
V.A.2 Coal Processing for Clean Fuels
Pollution prevention entails removal of the pollutants from coal in the
precombustion stage. This is accomplished through coal cleaning, whereby
pollutants are removed without altering the solid state of the coal, or by
conversions (gasification or liquefaction), which represent transformations
in the state of the coal.
Coal Cleaning
Most coal cleaning occurs at the mouth of the mine. The cleaning method
depends on the size of the coal pieces. Typically, coal is cleaned by pulsing
currents of water through a bed of coal in a jig to separate the impurities from
the coal. Coal cleaning can be achieved through physical, biological, or
chemical means. Physical cleaning is the most common method and involves
the separation of coals to obtain coals with lower ash content. A lower ash
content helps in meeting particulate emissions standards and results in lower
operating and maintenance costs associated with ash handling. Coal cleaning
can also reduce the trace metal content, thus reducing trace metal content in
ashes. Furthermore, cleaning is effective in removing sulfur from coal. This
is sulfur that may otherwise end up as SO2 emissions. There is a tradeoff
between sulfur reduction and energy recovery.36 It should be noted, however,
that a reduction in energy recovery is associated with sulfur removal.
A study cited in a report written by the Virginia Department of
Environmental Quality compared two FBC conceptual plant designs using
mine-run coal versus washed coal. The washed coal facility reduced SO2
emissions by more than 50 percent on the basis of equivalent heat input and
sulfur removal. The NOX emissions from the washed coal are about one-third
lower in comparison to mine-run coal based on equivalent heat input. In
addition, the washed coal facility was physically smaller, had lower
installation costs, required less storage area for limestone and ash, used less
water, and generated less high-volume wastes.
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Coal Gasification
Section V. Pollution Prevention Opportunities
Gasification is the process of converting coal to a gaseous fuelcoal gas
followed by chemical cleaning. Coal gas has the benefit of burning as
cleanly as natural gas. The process entails coal gas reacted with steam and
an oxidant in a reducing atmosphere. If air is the oxidant, a low-BTU gas
results; if oxygen is the oxidant, a medium-BTU gas results.
Mild Gasification
V.B
In mild gasification, coal is heated in a oxygen-free reactor, which produces
gaseous, solid, and liquid products. The environment in the reactor drives off
the condensed, volatile hydrocarbons and leaves behind carbon. The benefit
of mild gasification is that it produces multiple fuels and feedstocks using
medium temperature treatment of coal.
Coal Liquefaction
Hydrogen added to coal increases the fuel's ratio of hydrogen to carbon to a
level similar to that of petroleum-based fuels. Coprocessing is a liquefaction
process, whereby heavy petroleum residue combined with coal produces a
liquid fuel. The liquids can be cleaned of sulfur and ash prior to use as a fuel
and have higher thermal efficiencies (60-70 percent range), high product
yield, and potentially marketable byproducts, such as gasoline.
Other Pollution Prevention Technologies
Cogeneration
Cogeneration is the production of electricity and heat from a single power
plant unit. Because of the heat recovery aspect, Cogeneration itself is a
pollution prevention strategy. In Cogeneration, heat that would otherwise be
released from a steam turbine, gas turbine, or diesel engine is recaptured and
used to heat buildings or other industrial processes or to generate additional
electricity. In fact, whereas the typical efficiency at a fossil fuel electric plant
is around 33 to 38 percent, cogenerators can obtain up to 80-percent
efficiency because of the heat recaptured. The heat recovered comes mainly
from the flue gases.37
Cogeneration plants were originally industrial applications. They are still
used primarily to provide power for industries, hotels, universities, etc., yet
they are increasingly being designed for larger capacities and are competing
with utilities for power production. Cogeneration plants may be owned by
an industrial company, supplying its own power, or they may be owned by
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small entrepreneurial companies. Besides size requirements, factors such as
type of fuel to burn, methods of recapturing heat, and control of emissions,
should be considered when evaluating cogeneration as a power source.
DOE's Office of Industrial Technology (OIT) has several projects underway
to promote cogeneration, which is a commercially available technology. For
example, OIT teamed up with Riegel Textile Corporation to design and test
an innovative 4.3 MW high-back-pressure steam cogeneration system using
a modified coal-fired boiler. The turbine exhaust (225 psig at 570 degrees
Fahrenheit) is hot enough to be used for process heating and can also be used
to drive an existing low-pressure turbine to generate additional electricity.
In 1994,17 such systems were in operation.38
Repowering
Repowering is a way in which power generation facilities can improve and
increase both the production and efficiency of standard thermal generating
facilities. Repowering options include expanding a unit's size or changing
the type or quality of the fuel used. In most cases, it involves partial or
complete replacement of the steam supply system and usually a more or less
complete retention, refurbishment, and reuse of the turbine/generator. Many
of the technologies listed above are appropriate for repowering.
Fuel Cells
Natural gas fuel cell (NGFC) energy systems improve gas utilization and
efficiency. Like batteries, fuel cells are based on the principles of
electrochemistry, except that they consume fuel to maintain the chemical
reaction. The most common electrochemical reaction in a fuel cell is that of
hydrogen with oxygen. The oxygen is usually derived from the air, and the
hydrogen is usually obtained by steam-reforming fossil fuel. Natural gas is
the most common fuel; however, other fuels can be used: peaked-shaved gas,
air-stabilized gas from local production such as landfills, propane, or other
fuels with high methane content. Fuel Cells, being electrochemical, are more
efficient than combustion systems. In addition, emissions are reduced from
typical gas systems because there is no combustion of fossil fuel. Although
many fuel cells are being researched, developed, and demonstrated around
the world, only one system is commercially available at this time. It is a 200
kW phosphoric acid fuel cell system.39
Because emissions are reduced, State and local air quality regulating agencies
have begun to grant and/or consider exemptions from air quality permitting
requirements. For example, after extensive emissions testing, the South
Coast Air Quality Management District has granted NGFC's exemption in
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the Los Angeles area. Exemptions have also been granted by the Santa
Barbara Air Quality Management District, the Bay Area Air Quality
Management District, and the State of Massachusetts. These exemptions may
create economic incentives to install NGFC systems to avoid permitting fees
and violation fines, or to take advantage of emissions credits. A Federal
incentive program is being managed by the DOE Morgantown Energy
Technology Center to reduce the cost of the fuel cell by $1,000 per kW.40
Additional information on this technology may be obtained from the North
American Fuel Cell Owner Group (NAFCOG), an independent users group
comprised of owners and operators of NGFCs.
V.C Other Pollution Prevention and Waste Minimization Opportunities
In addition to the technologies discussed previously, several other pollution
prevention methods can be employed. Some of the methods are common
solutions applicable to a wide range of facilities; others are more tailored to
site-specific situations. Some of the methods are relatively simple, whereas
others require more technological modifications. This section includes not
only physical tasks, but management and training steps that foster pollution
prevention.
V.C.I Process or Equipment Modification Options
Fuel Sources
As discussed under the CCT Program, the initial fuel source may be
examined as a potential pollution prevention opportunity. Clean coal
technologies remove the pollutants prior to the major processes of electrical
generation. But on a case-by-case basis, one can also consider the option of
using fuels that are naturally lower in pollutants. Low-sulfur coals produce
less SO2 emissions, and there is less pollution associated with coal pile
runoff. However, a tradeoff exists in that most low-sulfur coal in the United
States is "low rank" (i.e., it has a higher ash and moisture content). Several
operational difficulties stem from switching from high-rank to low-rank coal.
Nonetheless, processing techniques to improve the BTU and remove sulfur
from low-rank coals are being developed. For example, SynCoal (Western
Energy Company) is a technology that produces a fuel with a 0.5 percent
sulfur content, a moisture content of greater than 5 percent, a heating value
of 11,800 Btu per pound, and ash content of approximately 9 percent.
Another related technology that has been researched extensively is co-firing
using refuse derived fuel (RDF) pellets and coal in power plants. In 1992,
DOE's OIT, in cooperation with several organizations, operated a power
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plant with a mixture of coal and up to 25 percent RDF pellets. The project
found that the mixture resulted in reduced acid gas emissions. The CAA
amendments of 1990 allow the combustion of up to 30 percent municipal
solid waste hi coal plants. The results of this project are facilitating
commercialization of the co-combustion technology.
Cooling Water
Cooling water is used hi steam turbine electric power plants and is circulated
through the condenser to condense the steam left after the generation of
electricity. The resulting condensate can then be pumped back into the high-
pressure boiler. Cooling systems may be once-through, where cooling water
is discharged into a receiving water body after use, or recirculating, which
involves the use of cooling towers, lakes, or ponds. Scaling of heat exchange
equipment and piping occurs from cooling water contact and reduces the
efficiency of the equipment. To prevent scaling, chemical additives, such as
polyphosphates, polyester, phosphates, and polyacrylates, are added to
cooling water. In the past, cooling tower treatment chemicals contained
hexavalent chromium. Recent regulations have restricted the use of chrome-
based treatment to reduce the associated public health and environmental
impacts. As a result, industry has switched to non-chrome treatment
chemicals.
Corrosion, fostered through aeration of cooling water in cooling towers, is
another problem. A number of different chemicals such as zinc, molybdate,
silicate, polyphosphate, aromatic azole, carboxylate, and sometimes chromate
are added to cooling water for corrosion control. Fouling and biological
growth are commonly controlled through the addition of polyester,
phosphates, polyacrylates, non-oxidizing biocides, chlorine, and bromine.
Pollution prevention opportunities for cooling water address minimizing
chemical additives and conserving water. Table 28 presents a few general
pollution prevention recommendations for reducing cooling tower emissions.
First and foremost, a facility can determine the optimum chemicals for the
prevention of biologic growth and corrosion. In general, chlorinated biocides
are less toxic than brominated biocides, and polyphosphate and organo-
phosphate inhibitors are less toxic than chromate corrosion inhibitors.
Another possible means to reduce the need for chemical additives for control
of scaling is magnetic water conditioning.
Widespread attention has focused on ozone treatment in lieu of common
biocide use. Ozone acts to rupture bacterial cells through oxidation.
Reductions in scaling, biofouling, and overall toxics may be realized from
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ozone. It has been successful mainly in once-through cooling water systems
for power plants. Drawbacks in the use of ozone treatment include (1) the
potential for corrosion in cooling towers, unless careful dosing is practiced
to maintain the oxidation-reduction potential rate and (2) ozone treatments
have been shown to exhibit rapid fouling on high temperature surfaces such
as would be found in recirculating systems. In addition, health and safety
issues associated with worker exposure to ozone must be considered.
Table 28: Pollution Prevention Opportunities for Reducing Cooling Tower Emissions
Pretreat makeup water: Pretreating the makeup water to cooling towers reduces the chemical treatment
requirements for scale and corrosion control and can increase the number of times cooling water may be recycled
before blowdown.
Use inert construction materials: Polyethylene, titanium, and stainless steel are relatively nonreactive
compared to carbon steel and require lesser quantities of scale and corrosion inhibitors.
Install automatic bleed/feed controllers and bypass feeders: By installing this equipment on the cooling
towers, facilities have reduced volumes of cooling tower chemicals, as well as energy costs, labor, and water.
Recirculate the cooling water: When possible, cooling tower water should be recirculated instead of cycling
once-through the system.
Use chlorinated biocides: Facilities can use chlorinated biocides instead of brominated biocides to reduce the
toxicity of biocides.
Sources: Fact Sheet: Eliminating Hexavalent Chromium from Cooling Towers. City of Los Angeles Board of
Public Works, Hazardous and Toxic Materials Office. Undated; Fact Sheet: Water and Chemicals Reduction for
Cooling Towers. North Carolina Department of Environmental Health and Natural Resources, Pollution
Prevention Program. May 1987; Pollution Prevention/Environmental Impact Reduction Checklist for Coal-Fired
Power Plants. U.S. Environmental Protection Agency, Office of Federal Activities. Undated.
Fireside Washes
In the combustion of fossil fuels, products of incomplete combustion will rise
with gas and collect on boiler tubes and heat transfer units. Fireside wastes
consist primarily of bottom ash and damaged refractory brick, which may be
contaminated with heavy metals from the ash. As the buildup increases, the
heat exchange efficiency decreases. Periodically, the buildup is removed by
applying a large volume of water to the boiler surfaces. The wash water
contains trace metals (nickel, chromium, iron, vanadium, and zinc), calcium,
sodium, chlorides, nitrates, sulfates, and organics contained in suspended
soot. The resulting waste is a wet ash sludge. This sludge may be co-
managed for disposal with large volume combustion waste (fly ash, bottom
ash, FGD sludge) or managed separately with other low-volume wastes and
treated through physical or chemical precipitation, as well as pond
evaporation.
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Soot blowers use steam, air, or water to clean fireside fouled heat transfer
surfaces. The removed soot and ash deposits are either reintroduced into the
combustion process, redeposited for easier removal, or captured by
particulate control equipment. Sonic horns generate sound waves that cause
the heat transfer surface to vibrate and dislodge soot and ash. Manual
cleaning includes brushing, sweeping, and vacuuming.
Abrasive cleaning methods remove contaminants by blasting a compound at
the substrate. Typical blasting compounds are sand, walnut shells, or carbon
dioxide pellets. The abrasive cleaning technology field is changing rapidly.
New materials that may remove soot and ash without damaging the boiler
tubes and refractory include plastic beads, sodium bicarbonate, and,
potentially, liquid CO2.
Table 29 provides some examples of pollution prevention opportunities for
fireside washes.
Table 29: Pollution Prevention Options for Fireside Washes
Options
Use cleaner fuels
Use alternative cleaning methods
Recycle or reuse fireside wastes
Comments
Natural gas is the cleanest burning fossil fuel, but availability limits
widespread use. Cleaner burning fuel oils and coals are available but
may be cost-prohibitive.
Soot blowers and sonic horns may be used to reduce the need for
washing. Dry ash has higher potential for reuse. Abrasives may be
used but add to waste created.
Lime sludge from treatment may be sold to copper smelters.
Vanadium recovery from fuel oil ash may be feasible. Coal ash can
be used as a substitute for cement in concrete or as structural fill.
Source: Industrial Pollution Prevention Handbook. Freeman, Harry M., ed. McGraw Hill, Inc. 1995.
Boiler Chemical Cleaning Wastes
The purpose of boiler cleaning is to remove scale from the inside (water side)
of boiler tubes. The waste generated contains spent cleaning solution and the
scaling components: copper, iron, zinc, nickel, magnesium, and chromium.
Certain cleaning agents target certain types of boilers and deposits. Boiler
cleaning wastewaters may be difficult to treat and, in some cases, fall under
the jurisdiction of the Resource Conservation and Recovery Act (RCRA) as
a hazardous waste.
One way to minimize the volume of boiler cleaning wastes is to optimize the
cleaning frequency. Specific practices that help to optimize cleaning
frequency include:
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Maintaining records of operations
Conducting biweekly chemical analysis to define normal cycle chemistry
Sampling tubes annually
Determining the location and/or type of deposits through ultrasonic
imaging, thermocouples, removable test strips, and fiberscopic
inspections.
Controlling the chemistry of the boiler feed water is a significant way to
control the rate of scaling. Generally, boiler water is treated through fine
filtration, chemical treatment, reverse osmosis, and/or ion exchange to
remove minerals. Other constituents in the boiler water targeted for removal
may include oxygen and carbon dioxide.
While most utilities use hydrazine and morpholine in the chemical treatment
of boiler feed water, an elevated oxygen treatment process has been
demonstrated that results hi the accumulation of a finer-grained, more
unified, magnetite layer that necessitates less frequent cleaning. To create
this condition, oxygen or hydrogen peroxide is added to condensate at a pH
of 7 to 7.5, oxygen and ammonia are added at a pH of 8 to 8.5, and ammonia
is added at a pH of 9 or greater, until ammonia concentrations of 250 parts
per billion are reached.
The boiler cleaning frequency may be decreased by reducing the amount of
oxygen entering the boiler due to leaks in the system. Leaks can be corrected
through inspection and replacement of seals on steam cycle components.
Maintenance schedules and monitoring techniques are effective practices in
preventing leaks. Furthermore, maintaining high quality performance of the
oxygen deaerators will also help to prevent oxygen ingress.
Another effective pollution prevention technique is determining the optimum
frequency of boiler cleanouts. Utilities should clean the boilers based on the
actual deposit thickness instead of according to a predetermined schedule.
According to a survey performed by EPRI, one California utility monitors
both scale thickness and composition by means of small, retrievable test
strips placed inside the boiler. Base unit boilers are now cleaned about once
every 72 months, and cycling units are cleaned once every 48 months. Other
California utilities report cleaning schedules as often as once every 24
months.41
On-line cleaning involves boiler cleaning while the boiler remains in
operation. This can be done by injection of a sodium poly-acrylate additive
into the boiler feedwater to a concentration of 400 mg/L. The most critical
outer layer of magnetite is removed, but an inner layer remains. This method
requires less cleaning time than traditional boiler cleaning, uses less
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Fly Ash
hazardous chemicals, and results in a more easily handled waste. The
drawbacks of on-line cleaning include the risk of contaminating the steam
turbine, less deposits removed, and potentially poor copper removal. Cost
savings associated with the use of this technology at a 300-MW unit have
been estimated to be $25,000 to $30,000 per year.42
Sodium bicarbonate-based blast media can be used in association with
specifically designed delivery systems to meet a wide range of cleaning
needs, including general facility maintenance (e.g., floor cleaning, paint
stripping and boiler tube cleaning). Sodium bicarbonate blasting is becoming
increasingly common in the electric utility industry.43
In areas where water costs are high, utilities may choose to reuse their boiler
chemical cleaning wastewater as makeup for cooling towers, fly ash
scrubbers, or flue gas desulfurization systems.44 Also, depending on the
composition of the chemical cleaning sludge, it may be economically feasible
to recycle the sludge for its metal content. Arizona Electric Power
Cooperative (AEPCO), Incorporated, for example, uses this cleaning
material, rather than face potentially expensive disposal costs. The EiPA, the
Arizona Department of Environmental Quality, the California Department of
Toxic Substances Control, and the Occupational Safety and Health
Administration approved the use of by products from chemical cleaning from
AEPCO's boilers. AEPCO sells the by-product to Pacific Gas & Electric
Company for hydrogen sulfide gas abatement at its Geysers Power Plant, a
geothermal power generation facility.45
Table 30 lists pollution prevention opportunities for boiler cleaning wastes.
Fly ash is typically collected in the flue of the combustion unit and
transported to a centralized containment area for treatment and storage. Both
wet ash transport and dry collection are commonly practiced. Some facilities
use wet ash, creating a slurry as the mechanism for transport. The
disadvantage of wet ash transport is that it increases the volume of the ash
waste and it must eventually be separated out and treated. In contrast, a dry
process control electrostatic precipitator avoids the added volume due to
water and allows the collection of a dry product for recycling and/or
beneficial reuse.
Chemical Substitutions
Several process modifications described previously have required material
substitution (e.g., switching fuels). However, material substitutions are not
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Table 30: Pollution Prevention Options for Boiler Cleaning Wastes
Options
Improve boiler water supply
Control boiler water chemistry
Reduce contaminant ingress
Base cleaning on fouling
Use on-line cleaning
Reuse wastewater
Reuse lime sludge
Control H2S-
Comments
Regenerate ion exchange resins promptly. Install reverse osmosis
equipment ahead of ion exchange systems to reduce mineral loading
and reduce regeneration frequency.
Use hydrazine to control dissolved oxygen and morpholine to
control carbon dioxide.
Improve equipment seals to prevent air and cooling water leaks into
the boiler.
Use coupons to measure scale buildup and schedule cleaning
accordingly.
Sodium polyacrylate injection may be used to remove deposits
without having to shut down boiler. Further research required.
Wastewater may be used for cooling tower makeup or as feedwater
to ash scrubbers and flue gas desulfurization units. Some
pretreatment and/or segregation may be required.
Sludges from lime treatment of chemical cleaning wastes may be
sold to copper smelters for reuse.
Ethylenediamine-tetraacetic acid (EDTA)-based cleaning processes
can produce Fe-EDTA, which is an effective chelating agent for H2S
control.
Source: Adapted from Industrial Pollution Prevention Handbook. Freeman, Harry M., ed. McGraw Hill, Inc. 1995.
V.C.2
limited to major processes. Sometimes, toxic chemicals are used
unnecessarily on a wide-scale basis for a variety of operations and
maintenance activities (e.g., cleaning, lubrication). By substituting less toxic
chemicals, a facility can avoid unnecessary risks associated with worker
exposure and the potential for release into the environment. The first step in
determining the viability of material substitutions is to inventory the
chemicals used at the site. The chemical can be evaluated as to its hazard
potential, its necessity, and possible alternatives. For example, San Diego
Gas and Electric Company determined several different solvents onsite could
be replaced by just a few different solvents. By eliminating the wide array
of solvents, the company is now able to install a solvent recovery unit, which
will reduce the amount of solvent waste.
Inventory Management and Preventative Maintenance for Waste
Minimization
Fossil fuel electric power generation facilities, like many industrial facilities,
.use solvents and other chemicals for everyday operations. Everyday
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operations include parts washing, lubricating, general cleaning, and
degreasing application during plant and equipment maintenance activities.
Often, chemical wastes generated by these operations are made up of out-of-
date, necessary, off-specification, and spilled or damaged chemical products.
Actual costs for materials used include not only the cost of the original
product, but also the costs of disposal. Inventory management and
preventative maintenance are ways these facilities can decrease the amounts
of chemical wastes generated in a cost-effective manner.
There are two categories of inventory management including inventory
control and material control. Inventory control includes techniques to reduce
inventory size, reduce toxic and/or hazardous chemical use, and increase
current inventory turnover. Material control includes the proper storage and
safer transfer of materials. Proper material control will ensure that materials
are used efficiently to reduce waste and preserve the ability to recycle the
wastes.
Corrective and preventative maintenance can reduce waste generation. A
well run preventative maintenance program will serve to identify the potential
for releases and correct problems before material is lost and/or considered a
waste. New or updated equipment can use process materials more efficiently,
producing less waste. Table 31 provides examples of inventory management
and preventative maintenance waste minimization techniques that can be
used at fossil fuel electric power generation facilities.
V.C.3 Potential Waste Segregation and Separation Options
Fossil fuel electric power generation facilities can reduce their waste disposal
costs by carefully segregating their waste streams. In particular, facilities
should segregate RCRA nonhazardous wastes from hazardous wastes to
reduce the quantity of waste that must be disposed of as a hazardous waste.
For example, facilities should segregate used oil from degreasing solvents
because uncontaminated used oil can be recycled or fed into the boiler as a
supplemental fuel. Oil contaminated with polychlorinated biphenyls (PCBs)
should be segregated from other used oils. Absorbent material that is not
fully saturated with oils, etc., should be stored separately from saturated
material so that it can be reused. Recycling companies typically offer a
higher price for segregated recyclables (e.g., clean office paper, scrap metal)
than mixed waste streams.
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Table 31: Inventory Management and Preventative Maintenance Waste Minimization
Opportunities
Inventory Management
Inventory Control
Purchase only the quantity of material needed for the job or a set period of time
Evaluate set expiration date on materials, especially for stable compounds, to determine if they could be extended.
Search the inventory at other company sites for available stock before ordering additional material
Purchase material in the proper quantity and the proper container size. If large quantities are needed, purchase in bulk. If the
material has a short shelf-life or small quantities are needed, purchase in small containers
If surplus inventories exist, use excess material before new material are ordered
Contact supplier to determine if surplus materials can be returned. If not, identify other potential users or markets
Evaluate whether alternative, non-hazardous substitutes prior to purchase and checked for acceptance at the facility.
Material Control
Reduce material loss through improved process operation, increased maintenance and employee training to identify sources of loss
Handle and manage wastes to allow recycling.
Maintenance Programs
Operational and Maintenance Procedures
Reduce raw material and product loss due to leaks, spills, and off-specification products
Develop employee training procedures on waste reduction
Evaluation the need for operational steps and eliminate practices that are unnecessary
Collect spilled or leaked material for re-use whenever possible
Consolidate like chemicals and segregate wastes to reduce the number of different waste streams and increase recoverability.
Preventive Maintenance Programs
Perform maintenance cost tracking
Perform scheduled preventive maintenance and monitoring
Monitor closely "Problem" equipment or processes that are known to generate hazardous waste (e.g., past spills).
Source: Adapted from "ComEd Operation and Maintenance Manual" and "Pollution Prevention Success" Fact Sheets. Received From
Edison Electric Institute. July 1997.
V.C.4 Recycling Options
With the exception of cooling water and used oil, fly ash represents the
greatest waste component at fossil fuel plants. For this reason, recycling
options for fly ash present a significant opportunity for pollution prevention.
Typical uses include incorporating fly ash into construction materials, such
as asphalt or cement. However, new uses are being found every day. Table
32 lists existing and potential marketable uses for fly ash. More information
about the production and use of fly ash and other coal combustion materials
can be obtained from the American Coal Ash Association.46
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Section V. Pollution Prevention Opportunities
Table 32: Current and Potential Uses for Fly Ash
Current Uses for Fly Ash
Flowable fill
Soil stabilization
Lightweight aggregate building material
Roofing materials
Roofing granules
Plastics, paint
Filter cloth precoat for sludge dewatering
Pipe bedding
Structural fills
Concrete and block Portland cement
Mine reclamation
Agricultural enhancement
Road paving: as a sub-base or fill material under a paved road
Potential Uses for Fly Ash
Ingredient of golf ball coverings
Flue gas reactants
An additive to sewage sludge for use as a soil conditioner
An alkali reactivity minimizer in concrete aggregate
The footprint of a structure, a paved parking lot, sidewalk, walkway, or similar structure
The Carolina Power and Light (CP&L) is successful in selling 80 to 100
percent of the fly ash generated at three coal-fired power plants. The CP&L
estimates capital costs to be $1 to $2/ton of fly ash and operation and
maintenance costs to be $3 to $4/ton of fly ash. The ash sales revenues have
resulted hi reduced disposal costs. Duke Power has experienced similar
success. Duke Power has sold more than 230,000 tons of fly ash and 65,400
tons of bottom ash for use hi concrete production. Other markets for the fly
ash included plastic manufacturing and asphalt production. In addition, Duke
Power donated 30,000 tons of bottom ash to the State of North Carolina to
use as a base in road construction.
It should be noted that uses for fly ash vary greatly according to market
conditions and transportation costs. In addition, for most uses, the ash must
have a low carbon content. However, available commercial technologies can
separate the ash into carbon-rich and carbon-poor fractions.
Pollution prevention associated with boiler blowdown was discussed
previously; however, boiler blowdown water may potentially be recycled
and used as makeup to cooling tower waters and flashing blowdown to
generate additional steam. This is accomplished through the regeneration of
demineralizer waters.
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Sulfur is produced .through the cleaning of fuels and ores and the use of clean
scrubbers. Recycling options include the following:
Substituting sulfur for Portland cement and water to act as a binding
agent to produce a durable, acid-resistant concrete
Using sulfur in protective coatings to improve the resistance of
conventional building materials to chemical and other stresses; fabric can
be impregnated with sulfur and additive materials to produce flexible or
rigid lining materials
Using sulfur as an asphalt extender or as an asphalt replacement to totally
eliminate the need for asphalt.
The FGD units can produce sulfur, sulfuric acid, gypsum, or some non-
saleable sludge material. Select FGD units can produce saleable materials,
as indicated in the following examples:
Gypsum can be processed into a quality gypsum grade for resale to wall
board producers or sold for use in cement manufacturing.
Sodium sulfate and sulfuric acid can be produced for resale.
An electron beam scrubbing system can be used to produce ammonium
sulfate and ammonium nitrate for sale as a fertilizer supplement.
A pozzolanic stabilization reaction process can be implemented where
lime-based reagent is added to scrubber sludge and fly ash to create a
mineral product suitable for roadway base course. (Pozzolans are
siliceous or siliceous/aluminous materials that, when mixed with lime and
water, form cementitious compounds.)
V.C.5 Facility Maintenance Wastes
In addition to the wastes associated with the power production operations,
fossil fuel electric power generation facilities also generate wastes from
support operations, such as facility and equipment maintenance, storage
areas, transportation, and offices. Pollution prevention techniques can greatly
reduce many of these waste streams for relatively little cost.
Table 33 highlights several basic pollution prevention options for equipment
and facility maintenance. All of the options involve the use of commercially
available equipment that is already in widespread use. In addition to the
options described in Table 33, common pollution prevention options include:
Establishing preventive maintenance programs for equipment
Testing fluids prior to changing them
Purchasing equipment to enable recycling of antifreeze, solvents, and
oil/water mixtures
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Section V. Pollution Prevention Opportunities
Purchasing longer lasting/reusable absorbent materials and rags
Laundering rags offsite instead of disposing of them
Using steam cleaning equipment or sodium bicarbonate blast systems for
general facility cleaning
Purchasing electric-powered vehicles for onsite use
Upgrading bulk storage equipment and spill prevention practices
Improving spill containment equipment and equipment for transferring
fluids
Using low- or no-VOC paints for facility maintenance and restricting
color choices
Recycling office paper, cardboard, plastics, scrap metals, wood products,
etc.
Purchasing products with recycled content
Finding alternatives to replace ozone depleting substances (e.g.,
refrigerants, fire suppression, degreasers)
Practicing integrated pest management to reduce the use of pesticides in
grounds maintenance operations
Using less toxic products for custodial operations.
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Table 33: Pollution Prevention Opportunities For Facility Maintenance Wastes
Options
Comments
Rotating Equipment Maintenance
Use high quality fluids
Routinely monitor fluid condition
Use nonleak equipment
Clean and recycle dirty fluids
Use waste oils as boiler fuel
While costing more initially, high quality fluids may last twice as
long in service.
Waste fluid generation can be reduced by switching to a
replacement schedule based on fluid condition. Low-cost testing
services can provide detailed information.
Use dry disconnect hose couplings, self sealing lock nuts, and
elastomeric flange gaskets to reduce oil leakage. Canned or
magnetically driven pumps, bellow valves, and bellow flanges are
also effective.
Dirty fluids may be cleaned for extended use by small filtration
devices. More complex systems may use centrifugation or vacuum
distillation.
This depends on boiler size, PCB content, and halogen content of
the waste oil. Would not apply to synthetic hydraulic fluids.
Facility Maintenance
Eliminate use of hazardous materials
Replace tricarboxylic acid (TCA) and
chlorofluorocarbons (CFCs) with non-
ODS cleaners
Use high transfer efficiency painting
equipment
Use an enclosed cleaning station
Avoid the removal of leaded paint
Major accomplishments have been made in this area, including
eliminating the use of PCBs, asbestos insulation, chromium-based
cooling water treatment chemicals, and leaded paints.
Petroleum distillate and D-limonene blends are effective cleaners for
electrical equipment. Detergents are good for general purpose
cleaning but must be kept out of yard drains and oil water
separators.
Brushes, rollers, and hand mitts are very efficient but labor-
intensive. Airless spray is common for field use since a source of
clean, dry ah- is not required.
Several air districts mandate the use of enclosed gun cleaners and
prohibit the spraying of cleanup solvent into the air.
Removal of lead-based paint should only be performed when the
paint fails to provide adequate protection. Use wet blasting or
vacuum collective devices to prevent the generation of leaded paint
dust.
Source: Industrial Pollution Prevention Handbook. Freeman, Harry M., ed. McGraw-Hill Inc 1995
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V.C.6 Storm Water Management Practices
An important pollution prevention consideration at fossil fuel electric power
generation plants is the management of runoff. Coal pile runoff is perhaps
the most significant. Coal pile runoff results from precipitation coming into
contact with coal storage piles. The most effective way to eliminate coal pile
runoff is to store coal indoors. In many instances, this is not feasible, at
which point, pollution prevention turns to managing runoff. A facility's
storm water pollution prevention plan should address storm water controls
(e.g., dikes, levies) and the potential for reuse of storm water. Coal-handling
areas also represent potential for coal pollutants to contaminate storm water.
Table 34 lists practices that can prevent pollutants in coal from contaminating
storm water.
Table 34: Common Pollution Prevention Practices for Managing Runoff at
Coal Storage and Handling Areas47
Consider rail transport of coal over barge transport, because the potential impacts to water are
lessened.
Cover coal off-loading areas, crushers, screens, and conveyors to reduce dust emissions.
Cover coal storage piles or store in silos to prevent contact with precipitation and to minimize dust.
Spray coal piles with anionic detergents. This will reduce the acidic content of the pile by reducing
bacterial oxidation of sulfide minerals.
Configure a storm water collection system based on slopes, collection ditches, diversions and storage,
and treatment ponds.
If settling ponds exist, consider recycling the dredgings.
Some of the practices listed in the table are applicable to fly ash storage and
handling areas, as well as coal pile runoff. For example, if dry ash transport
is employed, covers will prevent dust and contact with precipitation. Other
areas of concern with respect to storm water pollution prevention include fuel
and chemical handling and storage areas where there is potential for spills.
Table 35 provides some recommended practices that apply to these areas.
Ideally, these practices should be addressed in a facility's storm water
pollution prevention plan.
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Section V. Pollution Prevention Opportunities
Table 35: Storm Water Pollution Prevention Opportunities at
Fossil Fuel Electric Power Generation Facilities
Areas of Concern
Fuel Oil Unloading Areas
Chemical Unloading/Loading Areas
Miscellaneous Loading/Unloading Areas
Liquid Storage Tanks
Large Bulk Fuel Storage Tanks
Oil-Bearing Equipment Storage Areas
Ash-Loading Areas
Areas Adjacent to Disposal Ponds
Material Storage Areas
Storm Water Pollution Prevention Opportunities
Use containment curbs to contain spills
Station personnel familiar with spill prevention and response
procedures at areas during deliveries to ensure quick response for
leaks or spills
Use spill and overflow protection technologies
Use containment curbs to contain spills
Cover area
Station personnel familiar with spill prevention and response
procedures at areas during deliveries to ensure quick response for
leaks or spills
Use grading, berming, and curbing to minimize runon
Locate equipment and vehicles so leaks can be controlled in
existing containment and flow diversion system
Cover area
Use dry cleanup methods
Use containment curbs to contain spills
Use spill and overflow protection technologies
Use containment curbs to contain spills
Use level grades and gravel surfaces to retard flow and limit
spread of spills
Collect storm water in perimeter ditches
Establish procedures to reduce or control tracking of ash or
residue from ash loading areas
Clear ash from building floor and immediately adjacent roadways
of spillage, debris, and excess water before each loaded vehicle
departs
Reduce ash residue, which can be tracked onto access roads
traveled by residue trucks or residue handling vehicles
Reduce ash residue on exit roads leading into and out of residue-
handling areas
Use level grades
Collect runoff in graded swales or ditches
Implement erosion protection measures at steep outfall sites
Provide cover for material
Source: Preamble to NPDES Storm Water Multi-Sector General Permit for Industrial Activities (60 FR 50974 Friday,
September 29, 1995).
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V.C.7 Training and Supervision Options
While the major pollution prevention gains are achieved through process
controls and reuse/recycling, many day-to-day common sense practices are
relatively easy and inexpensive to incorporate. Through training, these
practices can become effective means of pollution prevention. Examples of
proactive employee behavior includes training for careful use and disposal of
cleaners and detergents to prevent them from entering floor and yard drains.
If these substances do enter the drains, they may interfere with oil/water
separators. Good housekeeping will ensure optimum performance of these
treatment units.
V.C.8 Demand-Side Management Programs
In the past, electric utilities have implemented demand-side management
(DSM) programs to achieve two basic objectives: energy efficiency and load
management. Through these demand-side programs, the utilities have
successfully reduced toxic air emissions and achieved cost effectiveness for
both the utility and the consumer, mainly by deferring the need to build new
power plants.48 The energy efficiency goal has been achieved primarily by
reducing the overall consumption of electricity from specific end-use devices
and systems by promoting high-efficiency equipment and building design.
With the advent of deregulation and restructuring in the utility power
generation industry, DSM programs appear to be diminishing. The industry
is reducing DSM spending and experiencing a reduction in the rate of growth
on energy savings. Among other factors, the potential for restructuring could
affect the utilities interest hi energy savings or may create new types of DSM
activities.
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Section VI. Federal Statutes and Regulations
VI. SUMMARY OF FEDERAL STATUTES AND REGULATIONS
This section discusses the Federal regulations that may apply to this sector.
The purpose of this section is to highlight and briefly describe, the applicable
Federal requirements, as well as to provide citations for more detailed
information. This sections includes:
Section VI. A, a general overview of major statutes
Section VLB, a list of regulations specific to this industry
Section VI.C, a list of pending and proposed regulations.
The descriptions within Section VI are intended solely for general
information. Depending upon the nature or scope of the activities at a
particular facility, these summaries may or may not necessarily describe all
applicable environmental requirements. Moreover, they do not constitute
formal interpretations or clarifications of the statutes and regulations. For
further information, readers should consult the Code of Federal Regulations
and other state or local regulatory agencies. This section also provides EPA
hotline contacts for each major statute.
VI.A General Description of Major Statutes
Resource Conservation and Recovery Act
The Resource Conservation And Recovery Act of 1976, which amended the
Solid Waste Disposal Act, addresses solid (Subtitle D) and hazardous
(Subtitle C) waste management activities. The Hazardous and Solid Waste
Amendments (HSWA) of 1984 strengthened RCRA's waste management
provisions and added Subtitle I, which governs underground storage tanks
(USTs).
Regulations promulgated pursuant to Subtitle C of RCRA (40 CFR Parts
260-299) establish a "cradle-to-grave" system governing hazardous waste
from the point of generation to disposal. RCRA hazardous wastes include the
specific materials listed in the regulations (listed wastes). Listed wastes are
designated with a specific code. Hazardous wastes designated with the code
"P" or "U" are commercial chemical products including technical grades,
pure forms, off-specification products, sole-active-ingredient products, or
spill or container residues of these products. "P" wastes are considered
acutely hazardous and are subject to more stringent requirements. Hazardous
wastes from specific industries/sources are designated with the code "K" and
hazardous wastes from non-specific sources are designated with the code "F."
Materials that exhibit a hazardous waste characteristic (i.e., ignitability,
corrosivity, reactivity, or toxicity) are designated with the code "D."
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Section VI. Federal Statutes and Regulations
Regulated entities that generate hazardous waste are subject to waste
accumulation, manifesting, and record keeping standards. Facilities generally
must obtain a permit either from EPA or from a State agency that EPA has
authorized to implement the permitting program if they store hazardous
wastes for more than 90 days before treatment or disposal. Facilities may
treat hazardous wastes stored in less-than-ninety-day tanks or containers
without a permit. Subtitle C permits contain general facility standards, such
as contingency plans, emergency procedures, record keeping and reporting
requirements, financial assurance mechanisms, and unit-specific standards.
RCRA also contains provisions (40 CFR Part 264 Subpart S and §264.101)
for conducting corrective actions that govern the cleanup of releases of
hazardous waste or constituents from solid waste management units at RCRA
treatment, storage, and disposal facilities.
Although RCRA is a Federal statute, many States implement the RCRA
program. Currently, EPA has delegated authority to implement various
provisions of RCRA to 47 of the 50 States and two U.S. territories.
Delegation has not been given to Alaska, Hawaii, or Iowa.
Most RCRA requirements are not industry specific but apply to any company
that generates, transports, treats, stores, or disposes of hazardous waste. The
following list highlights important RCRA regulatory requirements:
Identification of solid and hazardous wastes (40 CFR Part 261) lays
out the procedure every generator must follow to determine whether the
material in question is considered a hazardous waste or a solid waste or
is exempted from regulation.
Standards for generators of hazardous waste (40 CFR Part 262)
establishes the responsibilities of hazardous waste generators including
obtaining an EPA ID number, preparing a manifest, ensuring proper
packaging and labeling, meeting standards for waste accumulation units,
and fulfilling record keeping and reporting requirements. Providing they
meet additional requirements described in 40 CFR Part 262.34,
generators may accumulate hazardous waste for up to 90 days (or 180 or
270 days depending on the amount of waste generated and the distance
the waste will be transported) without obtaining a Subtitle C permit.
Land disposal restrictions (LDRs) (40 CFR Part 268) are regulations
prohibiting the disposal of hazardous waste on land without prior
treatment. Under the LDRs program, materials must meet LDR treatment
standards prior to placement in a RCRA land disposal unit (landfill, land
treatment unit, waste pile, or surface impoundment). Generators of waste
subject to the LDRs must provide notification of such to the designated
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Section VI. Federal Statutes and Regulations
treatment, storage, and disposal (TSD) facility to ensure proper treatment
prior to disposal.
Used oil management standards (40 CFR Part 279) impose
management requirements affecting the storage, transportation, burning,
processing, and re-refining of the used oil. For parties that merely
generate used oil, regulations establish storage standards. For a party
considered a used oil processor, re-refiner, burner, or marketer (i.e., one
who generates and sells off-specification used oil directly to a used oil
burner), additional tracking and paperwork requirements must be
satisfied.
RCRA contains unit-specific standards for all units used to store, treat, or
dispose of hazardous waste, including tanks and containers. Tanks and
containers used to store hazardous waste with a high volatile organic
concentration must meet emission standards under RCRA. Regulations
(40 CFR Part 264-265, Subpart CC) require generators to test the waste
to determine the concentration of the waste, to satisfy tank and container
emissions standards, and to inspect and monitor regulated units. These
regulations apply to all facilities that store such waste, including large
quantity generators accumulating waste prior to shipment off-site.
Underground storage tanks containing petroleum and hazardous
substances are regulated under Subtitle I of RCRA. Subtitle I regulations
(40 CFR Part 280) contain tank design and release detection
requirements, as well as financial responsibility and corrective action
standards for USTs. The UST program also includes upgrade
requirements for existing tanks that must be met by December 22, 1998.
Boilers and industrial furnaces (BIFs) that use or burn fuel containing
hazardous waste must comply with design and operating standards. The
BIF regulations (40 CFR Part 266, Subpart H) address unit design,
provide performance standards, require emissions monitoring, and restrict
the type of waste that may be burned.
The EPA RCRA, Superfund and EPCRA Hotline, at (800) 424-9346, responds
to questions and distributes guidance regarding all RCRA regulations. The
RCRA Hotline operates -weekdaysfrom 9:00 a.m. to 6:00p.m. ET, excluding
Federal holidays.
Comprehensive Environmental Response, Compensation, and Liability Act
The Comprehensive Environmental Response, Compensation, and Liability
Act (CERCLA), a 1980 law known commonly as Superfund, authorizes EPA
to respond to releases, or threatened releases, of hazardous substances that
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Section VI. Federal Statutes and Regulations
may endanger public health, welfare, or the environment. In addition,
CERCLA enables EPA to force parties responsible for environmental
contamination to clean it up or to reimburse the Superfund for response costs
(including remediation costs) incurred by EPA. The Superfund Amendments
and Reauthorization Act (SARA) of 1986 revised various sections of
CERCLA, extended the taxing authority for the Superfund, and created a
free-standing law, SARA Title HI, also known as the Emergency Planning
and Community Right-to-Know Act.
The CERCLA hazardous substance release reporting regulations (40 CFR
Part 302) direct the person hi charge of a facility to report to the National
Response Center (NRC) any environmental release of a hazardous substance
that equals or exceeds a reportable quantity. Reportable quantities are listed
in 40 CFR §302.4. A release report may trigger a response by EPA or by one
or more Federal or State emergency response authorities.
The EPA implements hazardous substance responses according to procedures
outlined in the National Oil and Hazardous Substances Pollution Contingency
Plan (NCP) (40 CFR Part 300). The NCP includes provisions for permanent
cleanups, known as remedial actions, and other cleanups referred to as
removals. The EPA generally takes remedial actions only at sites on the
National Priorities List (NPL), which currently includes approximately 1,300
sites. Both EPA and states can act at sites; however, EPA provides
responsible parties the opportunity to conduct removal and remedial actions
and encourages community involvement throughout the Superfund response
process.
The EPA RCRA, Superfiind and EPCRA Hotline, at (800) 424-9346, answers
questions and references guidance pertaining to the Superfund Program.
The CERCLA Hotline operates weekdays from 9:00 a.m. to 6:00 p.m. ET,
excluding Federal holidays.
Emergency Planning And Community Right-To-Know Act
The Superfund Amendments and Reauthorization Act of 1986 created
EPCRA, a statute designed to improve community access to information
about chemical hazards and to facilitate the development of chemical
emergency response plans by State and local governments. The EPCRA
required the establishment of State emergency response commissions
(SERCs), which are responsible for coordinating certain emergency response
activities and for appointing local emergency planning committees (LEPCs).
The EPCRA and the EPCRA regulations (40 CFR Parts 350-372) establish
four types of reporting obligations for facilities that store or manage specified
chemicals:
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Section VI. Federal Statutes and Regulations
EPCRA §302 requires facilities to notify the SERC and LEPC of the
presence of any extremely hazardous substance (the list of such
substances is in 40 CFR Part 355, Appendices A and B) if it has such
substance in excess of the substance's threshold planning quantity and
directs the facility to appoint an emergency response coordinator.
EPCRA §304 requires the facility to notify the SERC and LEPC in the
event of a release equaling or exceeding the reportable quantity of a
CERCLA hazardous substance or an EPCRA extremely hazardous
substance.
EPCRA §311 and §312 require a facility at which a hazardous chemical,
as defined by the Occupational Safety and Health Act, is present in an
amount exceeding a specified threshold to submit to the SERC, LEPC,
and local fire department material safety data sheets (MSDSs) or lists of
MSDS's and hazardous chemical inventory forms (also known as Tier I
and II forms). This information helps the local government respond in
the event of a spill or release of the chemical.
EPCRA §313 applies to facilities covered in SIC major groups 10
(except 1011,1081, and 1094), 12 (except 1241), or 20 through 39; SIC
codes 4911,1193, and 4939 (limited to facilities that combust coal and/or
oil for the purposes of generating power for distribution in commerce);
or 4935 (limited to facilities regulated under RCRA, Subtitle C), or 5169,
or 5171, and 7389 (limited to facilities primarily engaged in solvent
recovery services on a contract or fee basis). These facilities must also
have 10 or more employees and manufacture, process, or use specified
chemicals in amounts greater than threshold quantities. Facilities that
meet these criteria must submit an annual toxic chemical release report.
This report, commonly known as the Form R, covers releases and
transfers of toxic chemicals to various facilities and environmental media
and allows EPA to compile the national TRI database.
All information submitted pursuant to EPCRA regulations is publicly
accessible, unless protected by a trade secret claim.
The EPA RCRA, Superfund and EPCRA Hotline, at (800) 424-9346, answers
questions and distributes guidance regarding the EPCRA regulations. The
EPCRA Hotline operates weekdays from 9:00 a.m. to 6:00 p.m. ET,
excluding Federal holidays.
Clean Water Act
The primary objective of the Federal Water Pollution Control Act, commonly
referred to as the Clean Water Act (CWA), is to restore and maintain the
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chemical, physical, and biological integrity of the Nation's surface waters.
Pollutants regulated under the CWA include "priority" pollutants, including
various toxic pollutants; "conventional" pollutants, such as biochemical
oxygen demand (BOD), total suspended solids (TSS), fecal coliform, oil and
grease, andpH; and "nonconventional" pollutants, including any pollutant not
identified as either conventional or priority.
The CWA regulates both direct and indirect discharges. The NPDES
Program (CWA §502) controls direct discharges into waters of the U.S.
Direct discharges or "point source" discharges are from sources such as pipes
and sewers. NPDES permits, issued by either EPA or an authorized State
(EPA has authorized 42 States to administer the NPDES Program), contain
industry-specific, technology-based limits and may also include additional
water quality-based limits, and establish pollutant monitoring requirements.
A facility that intends to discharge into the Nation's waters must obtain a
permit prior to initiating its discharge. A permit applicant must provide
quantitative analytical data identifying the types of pollutants present in the
facility's effluent. The permit will then set the conditions and effluent
limitations on the facility discharges.
A NPDES permit may also include discharge limits based on Federal or State
water quality criteria or standards that were designed to protect designated
uses of surface waters, such as supporting aquatic life or recreation. These
standards, unlike the technological standards, generally do not take into
account technological feasibility or costs. Water quality criteria and
standards vary from State to State and site to site, depending on the use
classification of the receiving body of water. Most States follow EPA
guidelines, which propose aquatic life and human health criteria for many of
the 126 priority pollutants.
Storm Water Discharges
In 1987, the CWA was amended to require EPA to establish a program to
address storm water discharges. In response, EPA promulgated the NPDES
storm water permit application regulations. These regulations require
facilities with the following storm water discharges to apply for a NPDES
permit: (1) a discharge associated with industrialjtGtiyily, (2) a discharge
from a large or medium municipal storm sewer system, or (3) a discharge that
EPA or the State determines to contribute to a violation of a water quality
standard or is a significant contributor of pollutants to waters of the United
States.
The term "storm water discharge associated with industrial activity" is a
storm water discharge from 1 of 11 categories of industrial activity defined
at 40 CFR 122.26. Six of the categories are defined by SIC codes, while the
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other five are identified through narrative descriptions of the regulated
industrial activity. If the primary SIC code of the facility is one of those
identified in the regulations, the facility is subject to the storm water permit
application requirements. If any activity at a facility is covered by one of the
five narrative categories, storm water discharges from those areas where the
activities occur are subject to storm water discharge permit application
requirements.
Those facilities/activities that are subject to storm water discharge permit
application requirements are identified in the following list:
Category I: Facilities subject to storm water effluent guidelines, new
source performance standards, or toxic pollutant effluent standards.
Category ii: Facilities classified as SIC 24-lumber and wood products
(except wood kitchen cabinets); SIC code 26-paper and allied products
(except paperboard containers and products); SIC code 28-chemicals and
allied products (except drugs and paints); SIC code 291-petroleum
refining; and SIC code 311-leather tanning and finishing; SIC code 32
(except 323)-stone, clay, glass, and concrete, 33-primary metals, 3441-
fabricated structural metal, and 3 73-ship and boat building and repairing.
Category iii: Facilities classified as SIC code 10-metal mining; SIC
code 12-coal mining; SIC code 13-oil and gas extraction; and SIC code
14-nonmetallic mineral mining.
Category iv: Hazardous waste treatment, storage, or disposal facilities.
Category v: Landfills, land application sites, and open dumps that
receive or have received industrial wastes.
Category vi: Facilities classified as SIC code 5015-used motor vehicle
parts; and SIC code 5093-automotive scrap and waste material recycling
facilities.
Category vii: Steam electric power generating facilities.
Category viii: Facilities classified as SIC code 40-railroad
transportation; SIC code 41-local passenger transportation; SIC code 42-
trucking and warehousing (except public warehousing and storage); SIC
code 43-U.S. Postal Service; SIC code 44-water transportation; SIC code
45-transportation by air; and SIC code 5171-petroleum bulk storage
stations and terminals.
Category ix: Sewage treatment works.
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Category x: Construction activities except operations that result in the
disturbance of less than five acres of total land area.
Category xi: Facilities classified as SIC code 20-food and kindred
products; SIC code 21-tobacco products; SIC code 22-textile mill
products; SIC code 23-apparel related products; SIC code 2434-wood
kitchen cabinets manufacturing; SIC code 25-furniture and fixtures; SIC
code 265-paperboard containers and boxes; SIC code 267-converted
paper and paperboard products; SIC code 27-printing, publishing, and
allied industries; SIC code 283-drugs; SIC code 285-paints, varnishes,
lacquer, enamels, and allied products; SIC code 30-rubber and plastics;
SIC code 31-leather and leather products (except leather and tanning and
finishing); SIC code 323-glass products; SIC code 34-fabricated metal
products (except fabricated structural metal); SIC code 35-industrial and
commercial machinery and computer equipment; SIC code 36-electronic
and other electrical equipment and components; SIC code 37-
transportation equipment (except ship and boat building and repairing);
SIC code 38-measuring, analyzing, and controlling instruments; SIC code
39-miscellaneous manufacturing industries; and SIC code 4221-4225-
public warehousing and storage.
To determine whether a particular facility falls within one of these categories,
consult the regulation.
Pretreatment Program
Another type of discharge that is regulated by the CWA is one that goes to
a publicly-owned treatment works (POTWs). The national pretreatment
program (CWA §307(b)) controls the indirect discharge of pollutants to
POTWs by "industrial users." Facilities regulated under §307(b) must meet
certain pretreatment standards. The goal of the pretreatment program is to
protect municipal wastewater treatment plants from damage that may occur
when hazardous, toxic, or other wastes are discharged into a sewer system
and to protect the quality of sludge generated by these plants. Discharges to
a POTW are regulated primarily by the POTW itself, rather than the State or
EPA.
The EPA has developed technology-based standards for industrial users of
POTWs. Different standards apply to existing and new sources within each
category. "Categorical" pretreatment standards applicable to an industry on
a nationwide basis are developed by EPA. In addition, another kind of
pretreatment standard, "local limits," are developed by the POTW in order to
assist the POTW in achieving the effluent limitations in its NPDES permit.
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Regardless of whether a State is authorized to implement either the NPDES
or the pretreatment program, if it develops its own program, it may enforce
requirements more stringent than Federal standards.
Spill Prevention. Control and Countermeasure Plans
The 1990 Oil Pollution Act requires that facilities that could reasonably be
expected to discharge oil hi harmful quantities prepare and implement more
rigorous Spill Prevention Control and Countermeasure (SPCC) Plan required
under the CWA (40 CFR §112.7). There are also criminal and civil penalties
for deliberate or negligent spills of oil. Regulations covering response to oil
discharges and contingency plans (40 CFR Part 300), and Facility Response
Plans to oil discharges (40 CFR §112.20) and for PCB transformers and
PCB-containing items were revised and finalized in 1995.
EPA's Office of Water, at (202) 260-5700, will direct callers that questions
about the CWA to the appropriate EPA office. EPA also maintains a
bibliographic database of Office of Water publications -which can be
accessed through the Ground Water and Drinking Water Resource Center,
at (202) 260-7786.
Safe Drinking Water Act
The Safe Drinking Water Act (SDWA) mandates that EPA establish
regulations to protect human health from contaminants in drinking water.
The law authorizes EPA to develop national drinking water standards and to
create a joint Federal-State system to ensure compliance with these standards.
The SDWA also directs EPA to protect underground sources of drinking
water by controlling underground injection of liquid wastes.
The EPA has developed primary and secondary drinking water standards
under its SDWA authority. The EPA and authorized States enforce the
primary drinking water standards, which are contaminant-specific
concentration limits that apply to certain public drinking water supplies.
Primary drinking water standards consist of maximum contaminant level
goals (MCLGs), which are non-enforceable, health-based goals, and
maximum contaminant levels (MCLs), which are enforceable limits set as
close to MCLGs as possible, considering cost and feasibility of attainment.
The SDWA Underground Injection Control (UIC) Program (40 CFR Parts
144-148) is a permit program that protects underground sources of drinking
water by regulating five classes of injection wells. The UIC permits include
design, operating, inspection, and monitoring requirements. Wells used to
inject hazardous wastes must also comply with RCRA corrective action
standards in order to be granted a RCRA permit and must meet applicable
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RCRA land disposal restrictions standards. The UIC permit program is
primarily State-enforced, since EPA has authorized all but a few States to
administer the program.
The SDWA also provides for a Federally-implemented sole source aquifer
program, which prohibits Federal funds from being expended on projects that
may contaminate the sole or principal source of drinking water for a given
area, and for a State-implemented wellhead protection program which is
designed to protect drinking water wells and drinking water recharge areas.
The EPA Safe Drinking Water Hotline, at (800) 426-4791, answers questions
and distributes guidance pertaining to SDWA standards. The Hotline
operates from 9:00 am. through 5:30 p.m. ET, excluding Federal holidays.
Toxic Substances Control Act
The Toxic Substances Control Act (TSCA) granted EPA authority to create
a regulatory framework to collect data on chemicals in order to evaluate,
assess, mitigate, and control risks that may be posed by their manufacture,
processing, and use. TSCA provides a variety of control methods to prevent
chemicals from posing unreasonable risk.
The TSCA standards may apply at any point during a chemical's life cycle.
Under TSCA §5, EPA has established an inventory of chemical substances.
If a chemical is not already on the inventory and has not been excluded by
TSCA, a premanufacture notice (PMN) must be submitted to EPA prior to
manufacture or import. The PMN must identify the chemical and provide
available information on health and environmental effects. If available data
are not sufficient to evaluate the chemical's effects, EPA can impose
restrictions pending the development of information on its health and
environmental effects. The EPA can also restrict significant new uses of
chemicals based upon factors such as the projected volume and use of the
chemical.
Under TSCA §6, EPA can ban the manufacture or distribution in commerce
of, limit the use of, require labeling for, or place other restrictions on
chemicals that pose unreasonable risks. Among the chemicals EPA regulates
under §6 authority are asbestos, CFCs, and PCBs.
The EPA TSCA Assistance Information Service, at (202) 554-1404, answers
questions and distributes guidance pertaining to TSCA standards. The
Service operates from 8:30 a.m. through 4:30 p.m. ET, excluding Federal
holidays.
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Clean Air Act
Section VI. Federal Statutes and Regulations
The Clean Air Act and its amendments, including the Clean Air Act
Amendments (CAAA) of 1990, are designed to "protect and enhance the
nation's air resources so as to promote the public health and welfare and the
productive capacity of the population." The CAA consists of six sections,
known, as titles, that direct EPA to establish national standards for ambient
air quality and for EPA and the States to implement, maintain, and enforce
these standards through a variety of mechanisms. Under the CAAA, many
facilities will be required to obtain permits for the first tune. State and local
governments oversee, manage, and enforce many of the requirements of the
CAAA. The CAA regulations appear at 40 CFR Parts 50-99.
Pursuant to Title I of the CAA, EPA has established NAAQS to limit levels
of criteria pollutants, including carbon monoxide (CO), lead (Pb), NO2, PM,
ozone, SO2, and volatile organic compounds (VOCs). Geographic areas that
meet NAAQS for a given pollutant are classified as attainment areas; those
that do not meet NAAQS are classified as non-attainment areas. Under
section 110 of the CAA, each State must develop a State Implementation
Plan (SIP) to identify sources of air pollution and to determine what
reductions are required to meet Federal air quality standards. Revised
NAAQS for particulates and ozone were proposed in 1996 and may go into
effect as early as late 1997.
Title I also authorizes EPA to establish new source performance standards
(NSPS), which are nationally uniform emission standards for new stationary
sources falling within particular industrial categories. NSPS are based on the
pollution control technology available to that category of industrial source.
Under Title I, EPA establishes and enforces national emission standards for
hazardous air pollutants (NESHAPs), which are nationally uniform standards
oriented towards controlling particular HAPs. Title I, section 112(c) of the
CAA further directed EPA to develop a list of sources that emit any of 188
HAPs and to develop regulations for these categories of sources. To date,
EPA has listed 174 categories and developed a schedule for the establishment
of emission standards. The emission standards will be developed for both
new and existing sources based on maximum achievable control technology
(MACT). The MACT is defined as the control technology achieving the
maximum degree of reduction in the emission of the HAPs.
Title II of the CAA pertains to mobile sources, such as cars, trucks, buses,
and planes. Reformulated gasoline, automobile pollution control devices,
and vapor recovery nozzles on gas pumps are a few of the mechanisms EPA
uses to regulate mobile air emission sources.
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Title IV of the CAA establishes a SO2 and NO2 emissions control program
designed to reduce the formation of acid rain. Reduction of sulfur dioxide
releases will be obtained by granting to certain sources limited emissions
allowances, which, beginning hi 1995, will be set below previous levels of
SO2 sulfur dioxide releases. Reduction of nitrogen will be obtained by
required reduction of nitrogen oxides from power plants and new cars.
Title V of the CAA of 1990 created a permit program for all "major sources"
(and certain other sources) regulated under the CAA. One purpose of the
operating permit is to include in a single document all air emissions
requirements that apply to a given facility. States are developing the permit
programs in accordance with guidance and regulations from EPA. Once EPA
approves a State program that state will issue and monitor permits.
Title VI of the CAA is intended to protect stratospheric ozone by phasing out
the manufacture of ozone-depleting chemicals and restrict their use and
distribution. Production of Class I substances, including 15 kinds of CFCs
and chloroform, were phased out (except for essential uses) in 1996.
The EPA Clean Air Technology Center, at (919) 541-0800, provides general
assistance and information on CAA standards. The Stratospheric Ozone
Information Hotline, at (800) 296-1996, provides general information about
regulations promulgated under Title VI of the CAA, and the EPA EPCRA
Hotline, at (800) 535-0202, answers questions about accidental release
prevention under CAA §112(r). In addition, the Clean Air Technology
Center's website includes recent CAA rules, EPA guidance documents, and
updates of EPA activities (http://www.epa.gov/ttn then select Directory and
then CATC).
VLB Industry Specific Requirements
Since the 1960s, there has been an increased public awareness that industrial
growth, as well as its inherent need for energy produced using fossil fuels, is
accompanied by the release of potentially harmful pollutants into the
environment. Hence, the fossil fuel electric power generation industry has
become one of the most highly regulated industries. In addressing
environmental issues, the industry has moved from providing not only the
lowest cost energy, to providing the lowest cost energy with an acceptable
impact on the environment. Air pollution control has been of most concern,
with a significant percentage of the cost of a power plant going towards the
purchase of air pollution control equipment. However, control of hazardous
effluent discharges and proper management and disposal of solid wastes have
also been key concerns. This section summarizes the current major Federal
regulations affecting the fossil fuel electric power generation industry.
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National Environmental Policy Act
The National Environmental Policy Act of 1969 (NEPA) applies to all
Federal agencies and to Federal actions that may significantly impact the
environment. The NEPA requires that all Federal agencies prepare detailed
statements assessing the environmental impact of, and alternatives to, major
Federal actions that may significantly affect the quality of the human
environment. Implementing regulations are issued by the Council on
Environmental Quality (CEQ) at 40 CFR Parts 1500-1508. NEPA
implementing regulations that are most applicable to the fossil fuel electric
power generation industry can be found at 40 CFR Part 6 (EPA) and 10 CFR
Part 1021 (DOE). Each government agency has issued its own implementing
regulations under NEPA. The types of Federal activities associated with
fossil fuel electric power generating facilities that may be subject to NEPA
requirements include siting, construction, and operations of federally owned
facilities, federally issued NPDES, RCRA, and air permits, and federally
issued operation licenses.
Each Federal activity subject to NEPA must follow certain environmental
review procedures. If there is enough information to determine at the outset
that the Federal action will cause a significant effect on the environment, then
an environmental impact statement (EIS) must be prepared. If there is
insufficient information available, an environmental assessment (EA) must
be prepared to assist the agency in determining if the impacts are significant
enough to require an EIS. If the assessment shows the impacts not to be
significant, the agency must prepare a finding of no significant impact.
(FONSI). Further stages of the Federal activity may then be excluded from
the NEPA requirements.
Clean Air Act
Numerous existing standards and programs under the Clean Ah- Act may
affect the fossil fuel electric power generation industry. These regulations
and programs include Title I New Source Performance Standards, Title III
National Emissions Standards for Hazardous Air Pollutants, Title IV Acid
Rain Program, and Title V Operating Permits Program. The NAAQS under
Title I may affect the industry indirectly through permits.
National Ambient Air Quality Standards
Regulations for NAAQS do not directly affect the fossil fuel electric power
generation industry because they are not applied to sources. Rather, these
standards are applied to the ambient air in a particular area. Fossil fuel
electric power generators may be indirectly affected by these standards if
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they are located in or near an area with nonattainment status. In meeting
NAAQS, States develop and implement SIPs that prescribe use of reasonably
available control technologies (RACTs) for major sources. In addition, as
fossil fuel electric power generation facilities are typically one of the largest
emitters of criteria pollutants, they may be targeted for more stringent
controls implemented through operating permits.
The NAAQS currently exist for the following criteria pollutants (40 CFR
Part 50): PM10, SO2, CO, Pb, ozone, andNOx.
On July 16, 1997, new and/or revised standards for particulate matter and
ozone were promulgated. The regulations revise the current primary standard
by adding a new annual PMZS (or PM "fine") standard set at 15 micrograms
per cubic meter (|J.g/m3) and a new 24-hour PM2 5 standard set at 65 ug/m3.
These regulations revise the current 1-hour primary standard for ground level
ozone by adding an 8-hour standard set at 0.08 ppm (the 1-hour standard will
eventually be phased out).
Among the tools proposed for implementing these new ambient standards is
a trading plan for emissions from utilities. The new standards will require
local controls in 2004 for ozone and 2005 for particulate matter, with
compliance by 2007 and 2008, respectively.
A group called the Ozone Transport Assessment Group (OTAG) was formed
between EPA, the Environmental Council of States, and various industry and
environmental groups. The primary objective of OTAG is the collective
assessment of the ozone transport problem and the development of a strategy
for reducing ozone pollution on a regional scale.
New Source Review and New Source Performance Standards
New source review (NSR) requirements in 40 CFR §52.21 (b)(l)(I)(a)-(b)
apply to all new facilities and may apply to expansions of existing facilities
or process modifications. The NSRs are typically conducted by State
agencies in accordance with their SIP. SIPs are the primary tool for meeting
NAAQS and are administered through State and local agencies.
Prevention of significant deterioration (PSD) reviews are performed for areas
meeting NAAQS. Nonattainment reviews are performed for areas violating
the NAAQS. In nonattainment areas, permits may be issued to require new
sources to meet lowest achievable emission rate (LAER) standards.
Operators of the new sources must procure reductions hi emission of the
same pollutants from other sources in the nonattainment area in equal or
greater amounts to the emissions from the new source. These "emission
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Section VI. Federal Statutes and Regulations
offsets" may be banked and traded through the State agencies. In PSD areas,
permits require the best available control technology (BACT), and the
operator must conduct continuous air monitoring for one year prior to the
startup of the new source to determine the effects that the new emissions may
have on air quality.
Under NSPS, given at 40 CFR Part 60, EPA sets standards for LAER and
BACT for the following subcategories of the fossil fuel electric power
generation industry:
Subpart D: Standards of Performance for Fossil-Fuel-Fired Steam
Generators for Which Construction Is Commenced After
August 17, 1971
Subpart Da: Standards of Performance for Fossil-Fuel-Fired Steam
Generators for Which Construction Is Commenced After
September 18, 1978
Subpart Db: Standards of Performance for Industrial-Commercial-
Institutional Steam Generating Units
Subpart DC: Standards of Performance for Small Industrial-
Commercial-Institutional Steam Generating Units
Subpart GG: Standards of Performance for Stationary Gas Turbines.
The standards in each subcategory apply to units of a specified size and
age. Table 36 provides the NSPS.
Table 36: New Source Performance Standards
Emission
SO2
NOX
PM
Opacity
Standards
General standard for various levels of ng/J (Ib/mm Btu) heat input and %
reduction, depending on fuel type and sulfur content (see 40 CFR Subparts D, Da,
Db, and DC).
For gas turbines, no gases in excess of 0.015% by volume (at 15% O2 by volume)
or with sulfur contents in excess of 0.8% by weight shall be burned.
Between 0.2 and 0.8 Ib/mm BTU, depending on category of combustion. For gas
turbines, NOX standards specified hi equation hi 60.332(a)(l) or (2) as directed in
60.332(b), (c), and (d).
Between 0.05 and 0.20 Ib/mm BTU, unless a low nitrogen fuel is used, in which
case compliance is based on results of performance tests.
20%.
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National Emission Standards for Hazardous Air Pollutants
Current regulations at 40 CFR Part 61 provide standards for eight substances
identified as air toxics: vinyl chloride, mercury, beryllium, radon,
radionuclides, benzene, asbestos, and arsenic. Under Title III of the CAA,
EPA is required to identify source categories of 188 HAPs or toxic air
pollutants and then issue (at 40 CFR Part 63) MACT standards for each
source category according to a prescribed schedule. The standards are to be
based on best demonstrated control technologies or practices within the
regulated industry. Eight years after a MACT is installed on a source, EPA
is required to evaluate the risk levels remaining at the facilities and determine
whether additional controls are needed to reduce the risk to acceptable levels.
(
The EPA has issued an initial list of categories of major and area sources that
will be subject to regulation under Section 112 (57 FR 31576). The list
contains numerous sources from the fossil fuel electric power generation
industry, and standards are currently being developed under the Industrial
Combustion Coordinated Rulemaking (see Section VI.C.).
Acid Rain Program
The 1990 amendments to the CAA added a new provision (Title IV) to
control acid deposition. Title IV of the CAAA sets primary goals to reduce
annual emissions of both SO2 and NO2.
Upwards of 20 million tons of SO2 are emitted annually in the United States.
Most of this amount is from the burning of fossil fuels by electric utilities.
Because acid rain is a problem, Title IV requires EPA to reduce SO2
emissions to 10 million tons below the 1980 level. Reduction hi SO2 will be
attained in two phases by a marketable emission allowance program (40 CFR
Part 73). Phase I, which became effective in January 1995, required 110
power plants to reduce their emissions to a level equivalent to the product of
an emissions rate of 2.5 pounds (Ibs) of SO2/mmBtu times an average of their
1985-1987 fuel use. Plants that use certain control technologies to meet the
Phase I reduction requirements received a 2-year extension of compliance
until 1997. The new law also allows for special allocation of 200,000 annual
allowances per year, in each of the 5 years of Phase I, to power plants in
Illinois, Indiana, and Ohio.
Under the new requirements, utilities may trade allowances within their
systems and/or buy or sell allowances to and from other affected sources.
Phase I facilities were allocated allowances based on historic fuel
consumption and a specific emission rate. One allowance equals the right to
emit one ton of SO2. Affected facilities are required to turn into the EPA one
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Fossil Fuel Electric Power Generation
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allowance for each ton emitted in a calendar year. Unused allowances may
be sold, traded, or banked by the facilities. Power plants that do not have
sufficient allowances to cover annual emissions are subject to fees and
requirements to offset the excess emissions the following year.
Power plants that emit less than 1.2 Ibs of SO2/mmBtu are allowed to
increase emissions by 20 percent until the year 2000.
Phase II of the CAAA SO2 reduction requirement becomes effective January
1, 2000, and affects all utilities generating at least 25 MW of electricity.
These requirements require approximately 2,128 electric power utilities to
reduce emissions to a level equivalent to the product of an emissions rate of
1.2 Ibs of SO2/mmBtu times the average of their 1985-1987 fuel use. SO2
emissions from electric utilities will be capped at 8.95 million tons per year.
Title IV of the CAAA requires a 2 million ton reduction in NOX emissions
from 1980 levels. The EPA has developed regulations to help reduce NOX
emissions that may affect the fossil fuel electric power generation industry.
As hi the SO2 reduction program, the NOX Emission Reduction Program is
being implemented in two phases for two categories of coal-fired electric
utility boilers. The NOX program differs from the SO2 program in that it
neither "caps" the NOX emissions, nor utilizes an allowance trading system.
Phase I of the program for "Group I" boilers was effective on January 1,
1996, and affected dry-bottom wall fired boilers and tangentially fired boilers
that are required to meet NOX performance standards (40 CFR Part 76).
Regulations for Phase II of the NOX reduction program were promulgated in
December 1996. These rules become effective in the year 2000. These
regulations set lower emission limits for Group 1 boilers. In addition, the
regulation establishes initial NOX emission limitations for Group 2 boilers.
Group 2 boilers include boilers applying cell burner technology, cyclone
boilers, wet bottom boilers, and other types of coal-fired boilers.
Facilities covered by the Acid Rain Program must apply for an Acid Rain
Permit. Most utilities must apply for permits in either Phase I or Phase II of
the program. Two categories of utility units may be eligible for exemption:
small new units burning clean fuels and retired units. Some cogeneration
units are not covered under the program.
To support the mandated reductions in SO2 and NOX, the 1990 CAAA also
required EPA to issue regulations requiring facilities to install continuous
emissions monitoring systems (40 CFR Part 75). Fossil fuel electric power
generation units over 25 megawatts and new units under 25 megawatts that
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Section VI. Federal Statutes and Regulations
use fuel with a sulfur content greater than .05 percent by weight are required
to measure and report emissions under the Acid Rain Program.
Federal/State Operating Permits Programs
Title V of the CAAA requires the development of a comprehensive
permitting program to control air emissions from major stationary sources.
Major sources include those that emit 100 tons/year or more of VOCs or
criteria pollutants, 10 tons/year or more of any single toxic air pollutant, or
25 tons/year or more of a combination of toxic air pollutants. This program
is modeled after the NPDES program under the CWA and serves to bring
together all of the requirements concerning air emissions that apply to
affected sources. Like the NPDES program, administration of the operating
permit program is also delegated to States with approved programs.
This program requires all significant sources of air emissions to obtain
permits. In general, utility fossil fuel steam electric power plants are all
considered major sources, so they will most likely be required to obtain
permits. Other types of fossil fuel electric power generation facilities, such
as those employing small gas turbines, may not be considered a major source
and may not be required to apply for a permit. Any operational change that
increases emissions above specified limits will most likely necessitate permit
modifications. Permit terms are determined by State regulations for
delegated programs but may not exceed 5 years.
Clean Water Act
Wastewater discharges from fossil fuel electric power generation facilities
released to waters of the United States are covered under the CWA. Any
point source discharge is required to apply for, and obtain, an NPDES permit
(40 CFR Part 122). Permits may be issued by EPA or a State, depending
upon whether the State has a delegated program. The NPDES permits serve
to regulate point source discharges by establishing pollutant limitations and
other special conditions. Facilities discharging to a POTW may be required
to obtain a permit from a POTW that has an approved pretreatment program.
Current technology-based effluent limitations guidelines and pretreatment
standards for discharges from the steam electric generating point source
category were promulgated in 1982 (40 CFR Part 423). The waste streams
covered and parameters limited are summarized in Table 37 below.
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Table 37: Waste Streams and Pollutants Regulated Under National Effluent Limitation
Guidelines for the Steam Electric Generating Point Source Category
Type of Waste Stream
All discharges
Bottom ash transport waters and low volume waste
sources
Chemical boiler metal cleaning wastes
Non-chemical metal cleaning wastes
Fly ash transport water (including economizer ash)
Once-through cooling water
Cooling tower blowdown
Coal pile runoff
BAT Effluent Limitations Guidelines
pH , PCBs
TSS, oil and grease
TSS, oil and grease, iron, and copper
Reserved (low volume wastewater limits apply)
No discharge allowed (based on the availability of dry
disposal methods and the potential for reuse of fly ash
transport water)
Total residual chlorine (TRC) or free available chlorine
(FAC), depending on facility's generating capacity
FAC, chromium, zinc, other 126 priority pollutants where
they are found in chemicals used for cooling tower
maintenance
TSS
In general, steam electric facilities built after 1982 are considered new
sources and must comply with the 1982 effluent limitations. Less stringent
guidelines may apply for facilities constructed between 1974 and 1982 (see
1974 guidelines and standards). Steam electric generating facilities that have
been repowered are considered new sources.
Steam electric facilities that discharge to a POTW may be required to meet
pretreatment standards for existing sources (PSES) or for new sources
(PSNS). General pretreatment standards applying to most industries
discharging to a POTW are described in 40 CFR Part 403. Pretreatment
standards applying specifically to the steam electric generating point source
category are listed in 40 CFR §§423.16 and 17.
Beyond the applicable technology-based effluent limitations described above,
permits may also establish technology-based limits for other pollutants based
on the application of best professional judgement (BPJ). Permit limits and
special conditions may also be established based on water quality
considerations. Thermal limitations are often placed hi permits for steam
electric power plants based on Section 316(a) of the CWA and water quality
considerations. Additionally, permits may require the performance of a
demonstration study and implementation of control technologies to minimize
adverse environmental impacts from cooling water intake structures.
Storm water discharges associated with any industrial activity onsite at a
fossil fuel electric power generation facility are covered under the National
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Storm Water Program. Steam electric power generating activities are listed
as one of the categories of industrial activities subject to the storm water
permit application requirements (category vii). The regulations at 40 CFR
Part 122.26 require facilities discharging storm water from 1 of the 11
categories of industrial activities to apply for a storm water permit if the
storm water discharges to waters of the United States. In most permits,
facilities are required to develop and implement a storm water pollution
prevention plan. However, limitations and other special conditions may be
included on a case-by-case basis. Some permits may include the numeric
effluent limitation guideline for coal pile runoff. Storm water discharges
associated with other industrial activities at fossil fuel electric power
generation facilities are typically not subject to numeric limits, however.
Resource Conservation and Recovery Act
The 1980 Solid Waste Disposal Act Amendments conditionally exempted
from regulation under Subtitle C large volume wastes, including fly ash
waste, bottom ash waste, boiler slag waste, and flue gas emission control
waste generated primarily from the combustion of coal or other fossil fuels
(RCRA §3001). Section 8002(n) of RCRA directed EPA to study these
wastes.
In 1993, EPA issued a regulatory determination addressing large volume
wastes (fly ash, bottom ash, boiler ash, boiler slag, and flue gas emission
control wastes) generated by coal-fired utility power plants, including
independent power producers not engaged in any other industrial activity.
The regulatory determination stated that these wastes should not be regulated
as Subtitle C wastes when they are managed separately from other wastes.
A similar determination for other large volume fossil fuel combustion wastes
and co-managed wastes was deferred pending additional studies.
Wastes exempt from hazardous waste regulation (currently all wastes from
fossil fuel combustion) are addressed by Subtitle D of RCP.A (for
nonhazardous solid wastes). There are currently no Federal nonhazardous
waste regulations. As a result, fossil fuel electric power generation waste
management is addressed solely by the States, either through their general
industrial solid waste programs or through specific programs for fossil fuel
combustion wastes. These State programs vary considerably.
Subtitle I of RCRA has stringent requirements for underground petroleum
and hazardous substances storage tank (UST) systems with 110-gallon or
greater capacity. Any storage of fuels in USTs onsite at a fossil fuel electric
power generation facility would be covered under these regulations at 40
CFR Part 280.
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Section VI. Federal Statutes and Regulations
Subtitle C of RCRA provides for a comprehensive cradle to grave system of
management for hazardous waste and includes rules governing waste
disposal on land; recycling and generators; and treatment, storage, or disposal
facilities (TSDFs). Low volume fossil fuel combustion wastes not co-
managed with ash, slag, or flue gas desulfurization wastes and other wastes
that are not directly associated with the combustion process are not exempted
from hazardous waste regulation. As such, they are hazardous wastes if they
are listed as hazardous wastes from non-specific sources (e.g., spent solvents)
or if they exhibit one or more of the RCRA hazardous waste characteristics
of toxicity, corrosivity, reactivity, and ignitability. The identification of
specific listed wastes and the definitions of the hazardous waste
characteristics are listed in 40 CFR Part 261.
Fossil fuel electric power generating plants do not typically generate large
quantities of hazardous waste. Furthermore, the requirements and costs of
operating an onsite hazardous waste TSDF are extensive. Therefore, most
electric power generating facilities send any generated hazardous waste to
offsite RCRA-permitted commercial TSDFs for permanent disposal.
Some steam electric power generating plants co-fire their boilers with
hazardous wastes (e.g., spent solvents), along with their primary fossil fuel
source. Such facilities are subject to RCRA regulation under the BIF Rule
(40 CFR Part 266, Subpart H). The BIF Rule includes operating condition
requirements, as well as testing requirements, for air emissions and residuals
to ensure adequate destruction of toxic constituents.
Emergency Planning and Community Right-to-Know Act
In a recent rulemaking (62 FR 23834, May 1,1997), EPA expanded the list
of industry groups subject to reporting requirements under Section 313 of
EPCRA (61 FR 33587). The expanded list of industry groups includes
electric utilities classified hi the following SIC codes: 4911 Electric Services,
4931 Electric and Other Services Combined, and 4939 Combination Utilities,
Not Elsewhere Classified. EPCRA Section 313 now requires electric
generating facilities that combust coal and/or oil for the purpose of
generating electricity for distribution in commerce to evaluate their chemical
use and management activities to determine potential reporting
responsibilities. Section 313 establishes annual requirements for amounts
released and otherwise managed of "section 313 chemicals" (a list of more
than 650 chemicals and chemical categories).
For each Section 313 chemical or chemical category, covered facilities must
report total routine and accidental amounts entering each environmental
media, as well as onsite waste management via, and offsite transfers for,
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Section VI. Federal Statutes and Regulations
disposal, waste treatment, energy recovery and recycling, and onsite source
reduction activities. This information is submitted on the TRI reporting form
called Form R if the facility has met or exceeded certain thresholds. The first
period of reporting for this industry will be on or before July 1,1999, for the
period from January 1 to December 31, 1998. Reporting will be required
annually thereafter. For additional information on these new TRI reporting
requirements, contact the Emergency Planning and Right-to-Know Hotline
at (800) 535-0202 (in Virginia and Alaska (703) 412-9877; TDD (800) 553-
7672).
VI.C Pending and Proposed Regulatory Requirements
Clean Air Act Amendments of 1990
Hazardous Air Pollutants
In response to requirements under Section 112 of the CAA as well as Section
129, EPA is developing a unified set of Federal air emission regulations for
industrial combustion sources. This rulemaking effort is being called the
Industrial Combustion Coordinated Rulemaking (ICCR).
The ICCR will cover sources from industrial/institutional/commercial boiler,
process heaters, industrial/commercial and other solid waste (not including
hazardous, medical, or large municipal) incinerators, stationary gas turbines,
and stationary internal combustion engines. These sources are not limited to
use of fossil fuels and have the potential to emit both HAPs and criteria
pollutants. This rulemaking effort will produce approximately seven separate
regulations, six of which are expected to be finalized by November 2000.
For additional information on the ICCR, contact Fred Porter, U.S. EPA
Office of Air and Radiation, at (919) 541-5251.
Section 112(n) requires that EPA perform studies to evaluate the health risks
associated with emissions of toxic air pollutants from electric utility steam
generating units. Electric utility steam generating units are defined as any
fossil fuel-fired combustion unit of more than 25 MW electric that serves a
generator that produces electricity for sale. Cogenerators that supply more
than one-third of their potential electric output capacity and more than 25
MW output to any utility power distribution system for sale will also be
covered. A preliminary study has been completed and was issued as an
interim final in October 1996. Additional studies will be performed, as well
as an in-depth study of potential public health concerns due to mercury
emissions from utilities. These findings will be published in a report to
Congress at a later date and will include costs and technologies available to
control these emissions and recommendations as to whether regulations are
needed for air toxics emissions from this industry. For additional
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Section VI. Federal Statutes and Regulations
information on this study, contact Bill Maxwell, U.S. EPA Office of Air and
Radiation, at (919) 541-5430.
Clean Water Act
Effluent Limitations Guidelines and Standards and Pretreatment Standards
for the Steam Electric Point Source Category
The existing 1982 effluent limitations guidelines and standards and
pretreatment standards for wastewater discharges from the Steam Electric
Point Source Category are currently being reviewed by the Office of Water.
A preliminary study has been completed by the Office of Water to evaluate
the guidelines and standards based on current technical feasibility,
environmental factors, economic impacts, and utility to permit writers. The
study was performed because the steam electric power generating industrial
category is considered as a candidate for possible regulatory revisions in the
future. For additional information, contact Joe Daly, U.S. EPA Office of
Water, at (202) 260-7186.
Cooling Water Intake Structure Regulations
Section 316(b) of the Clean Water Act requires that "...any standard
established pursuant to Section 301 or 306... and applicable to a point source
shall require that the location, design construction, and capacity of cooling
water intake structures reflect the best technology available for minimizing
adverse environmental impact." Since fossil fuel electric power generators
with steam turbines withdraw by far the greatest quantity of cooling water of
any single industrial sector, it is expected that this industry will be the most
affected by this requirement. Although some EPA regions and States have
developed programs to minimize impacts from cooling water structures, no
uniform national standards or implementing regulations are currently in
force. As set forth in a consent decree (Cronin v. Browner), EPA has
initiated the information collection activities needed to develop proposed
regulations to address impacts from the intake of cooling water by 1999.
Final EPA action is scheduled for the year 2001. For additional information
on the Section 316(b) rulemaking effort, contact Deborah Nagle, U.S. EPA
Office of Water, at (202) 260-2656.
Resource Conservation and Recovery Act
A regulatory determination on whether large volume wastes at utility oil-
fired, nonutility coal- and oil-fired, and fluidized bed combustion power
plants and co-managed large volume wastes at all utility and nonutility coal-
and oil-fired electric generation facilities should be considered hazardous
wastes under Subtitle C is expected to be finalized in 1998, pending
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Section VI. Federal Statutes and Regulations
additional data collection. For additional information, contact Dennis Ruddy,
U.S. EPA Office of Solid Waste, at (703) 308-8430.
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VII. COMPLIANCE AND ENFORCEMENT HISTORY
Until recently, EPA has focused much of its attention on measuring
compliance with specific environmental statutes. This approach allows the
EPA to track compliance with CAA, RCRA, CWA, and other environmental
statutes. Within the last several years, the EPA has begun to supplement
single-media compliance indicators with facility-specific, multimedia
indicators of compliance, hi doing so, EPA is in a better position to track
compliance with all statutes at the facility level and within specific industrial
sectors.
A major step in building the capacity to compile multimedia data for
industrial sectors was the creation of EPA's IDEA system. The IDEA has the
capacity to "read into" EPA's single-media databases, extract compliance
records, and match the records to individual facilities. The IDEA system can
match air, water, waste, toxics/pesticides/EPCRA, TRI, and enforcement
docket records for a given facility and generate a list of historical permit,
inspection, and enforcement activity. IDEA also has the capability to analyze
data by geographic area and corporate holder. As the capacity to generate
multimedia compliance data improves, EPA will make available more in-
depth compliance and enforcement information. Additionally, sector-specific
measures of success for compliance assistance efforts are being developed.
Compliance and Enforcement Profile Description
Using inspection, violation and enforcement data from the IDEA system, this
section provides information regarding the historical compliance and
enforcement activity of this sector. In order to mirror the facility universe
reported hi the Toxic Chemical Profile, the data reported within this section
consist of records only from the TRI reporting universe. With this decision,
the selection criteria are consistent across sectors with certain exceptions.
For the sectors that do not normally report to the TRI program, data have
been provided from EPA's Facility Indexing System (FINDS) which tracks
facilities hi all media databases. Please note, in this section, EPA does not
attempt to define the actual number of facilities that fall within each sector.
Instead, the section portrays the records of a subset of facilities within the
sector that are well defined within EPA databases.
As a check on the relative size of the full sector universe, most notebooks
contain an estimated number of facilities within the sector according to the
Bureau of Census. For the fossil fuel electric power generation industry,
statistics about the industry are collected by the DOE EIA (see Section II).
With sectors dominated by small businesses, such as metal finishers and
printers, the reporting universe within EPA databases may be small in
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comparison to Census data. However, the group selected for inclusion in this
data analysis section should be consistent with this sector's general make-up.
Following this introduction is a list defining each data column presented
within this section. These values represent a retrospective summary of
inspections and enforcement actions, and reflect solely EPA, State, and local
compliance assurance activities that have been entered into EPA databases.
To identify any changes in trends, the EPA ran two data queries: one for the
past five calendar years (April 1,1992, to March 31,1997) and the other for
the most recent 12-month period (April 1,1996, to March 31, 1997). The
5-year analysis gives an average level of activity for that period for
comparison to the more recent activity.
Because most inspections focus on single-media requirements, the data
queries presented in this section are taken from single media databases.
These databases do not provide data on whether inspections are state/local or
led by EPA. However, the table breaking down the universe of violations
does give a crude measurement of EPA's and States' efforts within each
media program. The presented data illustrate the variations across EPA
regions for certain sectors.3 This variation may be attributable to state/local
data entry variations, specific geographic concentrations, proximity to
population centers, sensitive ecosystems, highly toxic chemicals used in
production, or historical noncompliance. Hence, the exhibited data do not
rank regional performance or necessarily reflect which regions may have the
most compliance problems.
Compliance and Enforcement Data Definitions
Facility Indexing System - This system assigns a common facility number
to EPA single-media permit records. The FINDS identification number
allows EPA to compile and review all permit, compliance, enforcement, and
pollutant release data for any given regulated facility.
Integrated Data for Enforcement Analysis - This data integration system
can retrieve information from the major EPA program office databases.
IDEA uses the FINDS identification number to link separate data records
from EPA's databases. This allows retrieval of records from across media
or statutes for any given facility, thus creating a "master list" of records for
that facility. Some of the data systems accessible through IDEA are: AIRS
(Office of Air and Radiation), PCS (Office of Water), RCRIS (Resource
EPA Regions include the following states: I (CT, MA, ME, RI, NH, VT); II (NJ, NY, PR, VI); III (DC, DE, MD,
PA, VA, WV); IV (AL, FL, GA, KY, MS, NC, SC, TN); V (IL, IN, MI, MN, OH, WI); VI (AR, LA, NM, OK, TX);
VII (IA, KS, MO, NE); VIII (CO, MT, ND, SD, UT, WY); DC (AZ, CA, HI, NV, Pacific Trust Territories); X (AK,
ID, OR, WA).
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Conservation and Recovery Information System, Office of Solid Waste),
NCDB (National Compliance Data Base, Office of Prevention, Pesticides,
and Toxic Substances), CERCLIS (Comprehensive Environmental and
Liability Information System, Superfund), and TRIS (Toxic Release
Inventory System). IDEA also contains information from outside sources
such as Dun and Bradstreet and the Occupational Safety and Health
Administration (OSHA). Most data queries displayed in Sections IV and VII
of this notebook were conducted using IDEA.
Data Table Column Heading Definitions
Facilities in Search are based on the universe of TRI reporters within the
listed SIC code range. For industries not covered under TRI reporting
requirements (metal mining, nonmetallic mineral mining, electric power
generation, ground transportation, water transportation, and dry cleaning), or
industries hi which only a very small fraction of facilities report to TRI (e.g.,
printing), the notebook uses the FINDS universe for executing data queries.
The SIC code range selected for each search is defined by each notebook's
selected SIC code coverage described in Section II.
Facilities Inspected indicates the level of EPA and state agency inspections
for the facilities in this data search. These values show what percentage of
the facility universe is inspected in a one-year or five-year period.
Number of Inspections measures the total number of inspections conducted
in this sector. An inspection event is counted each time it is entered into a
single media database.
Average Time Between Inspections provides an average length of time,
expressed in months, between compliance inspections at a facility within the
defined universe.
Facilities with One or More Enforcement Actions expresses the number
of facilities that were the subject of at least one enforcement action within the
defined time period. This category is broken down further into federal and
state actions. Data are obtained for administrative, civil/judicial, and
criminal enforcement actions. Administrative actions include Notices of
Violation (NOVs). A facility with multiple enforcement actions is only
counted once in this column, e.g., a facility with three enforcement actions
counts as one facility.
Total Enforcement Actions describes the total number of enforcement
actions identified for an industrial sector across all environmental statutes.
A facility with multiple enforcement actions is counted multiple times, e.g.,
a facility with three enforcement actions counts as three.
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State Lead Actions shows what percentage of the total enforcement actions
are taken by state and local environmental agencies. Varying levels of use
by states of EPA data systems may limit the volume of actions recorded as
state enforcement activity. Some states extensively report enforcement
activities into EPA data systems, while other states may use their own data
systems.
Federal Lead Actions shows what percentage of the total enforcement
actions are taken by the United States Environmental Protection Agency.
This value includes referrals from state agencies. Many of these actions
result from coordinated or joint state/federal efforts.
Enforcement to Inspection Rate is a ratio of enforcement actions to
inspections, and is presented for comparative purposes only. This ratio is a
rough indicator of the relationship between inspections and enforcement. It
relates the number of enforcement actions and the number of inspections that
occurred within the one-year or five-year period. This ratio includes the
inspections and enforcement actions reported under the CWA, CAA, and
RCRA. Inspections and actions from the TSCA/FIFRA/ EPCRA database
are not factored into this ratio because most of the actions taken under these
programs are not the result of facility inspections. Also, this ratio does not
account for enforcement actions arising from non-inspection compliance
monitoring activities (e.g., self-reported water discharges) that can result in
enforcement action within the CAA, CWA, and RCRA.
Facilities with One or More Violations Identified indicates the percentage
of inspected facilities having a violation identified in one of the following
data categories: In Violation or Significant Violation Status (CAA);
Reportable Noncompliance, Current Year Noncompliance, Significant
Noncompliance (CWA); Noncompliance and Significant Noncompliance
(FIFRA, TSCA, and EPCRA); Unresolved Violation and Unresolved High
Priority Violation (RCRA). The values presented for this column reflect the
extent of noncompliance within the measured time frame, but do not
distinguish between the severity of the noncompliance. Violation stains may
be a precursor to an enforcement action, but does not necessarily indicate that
an enforcement action will occur.
Media Breakdown of Enforcement Actions and Inspections four
columns identify the proportion of total inspections and enforcement actions
within EPA air, water, waste, and TSCA/FIFRA/EPCRA databases. Each
column is a percentage of either the "Total Inspections," or the "Total
Actions" column.
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VILA Fossil Fuel Electric Power Generation Industry Compliance History
This section examines the historical enforcement and compliance data on the
fossil fuel electric power generation sector. As noted earlier, these data were
obtained from EPA's IDEA system. The five exhibits within this section
provide both a 5-year and a 1 -year review of the data from the sector and also
provide data from other sectors for comparison purposes. It should be noted
that the data are accessed in the IDEA database system through SIC codes.
Therefore, only those facilities whose primary SIC codes indicate the
potential for power generation activities can be accessed (see Section II).
This means that the data retrieved from IDEA may be more inclusive (e.g.,
include transmission and distribution facilities). Other industry facilities that
have associated power generation activities cannot be identified because their
primary SIC codes do not indicate power generation.
Table 38 provides an overview of the reported compliance and enforcement
data for the fossil fuel electric power generations sector over the past 5 years
(April 1992 to April 1997). These data are also broken out by EPA Regions
thereby permitting geographical comparisons. A few points evident from the
data are listed below. As shown, 3,270 facilities were identified through
IDEA with SIC codes that indicate power generation may be occurring (see
discussion above). Of those, approximately 66 percent (2,166) were
inspected in the last 5 years. Other points of interest include:
14,210 inspections were conducted over the last 5 years. Of the 3,166
facilities inspected, on average, each received over 6 inspections in the
past 5-year period.
The 14,210 inspections resulted in 403 facilities having enforcement
actions taken against them. At those 403 facilities, there were a total of
789 enforcement actions; therefore, each facility averaged nearly 2
enforcement actions over the 5-year period.
The average enforcement to inspection rate is 0.06, with the rate across
the regions ranging from 0.02 to 0.13. There appears to be no correlation
between State versus Federal lead on the inspections and the enforcement
to inspection rate.
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Fossil Fuel Electric Power Generation Section VII. Compliance and Enforcement History
VII.B Comparison of Enforcement Activity Between Selected Industries
Tables 39 and 40 allow the compliance history of the fossil fuel electric
power generation sector to be compared to the other industries covered by the
industry sector notebooks. Comparisons between Tables 39 and 40 permit
the identification of trends in compliance and enforcement records of the
various industries by comparing data covering the last 5 years (April 1992 to
April 1997) to that of the past year (April 1996 to April 1997). As shown in
the data, the 3,270 fossil fuel electric power generation facilities is the sixth
largest number of facilities identified through IDEA, with ground
transportation having the most facilities with 7,786. However, while
approximately 66 percent of the fossil fuel electric power generation facilities
have been inspected in the past 5 years, only 41 percent of the ground
transportation facilities have been inspected. Other points of interest from
the 5-year summary include:
The number of inspections over the past 5 years for fossil fuel electric
power generation facilities (14,210) is more than 3 times the amount
conducted in most other sectors.
The enforcement to inspection rate of 0.06 over the past 5 years is one of
the lower rates of the listed sectors.
Points of interest from the 1-year summary include:
The 1,318 fossil fuel electric power generation facilities inspected in the
past year places this sector among the top four sectors for number of
facilities inspected.
The total number of inspections in this sector is 2,430 which compares
with the number of inspections performed in the ground transportation
and non-metallic mining sectors, but is 1.5 to 17 times more than the
other sectors which range from 1,436 down to 141.
The enforcement to inspection rate of 0.06 is about average among all the
sectors, with the lowest being 0.01 (dry cleaning) and the highest being
0.23 (petroleum refining). This is relatively constant with the 5-year
average for the fossil fuel electric power generation sector.
Tables 41 and 42 provide a more in-depth comparison between the fossil fuel
electric power generation sector and others by organizing inspection and
enforcement data by environmental statute. As in the previous Tables
(Tables 39 and 40), the data cover the last 5 years (Table 41) and the last
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