Agency
821-R-06-015
Interim Detailed Study Report for the
Steam Electric Power Generating
Point Source Category
U.S. Environmental Protection Agency
Engineering and Analysis Division
Office of Water
1200 Pennsylvania Avenue, NW
Washington, D.C. 20460
November 2006
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ACKNOWLEDGMENT AND DISCLAIMER
This report was prepared with the technical support of Eastern Research Group,
Inc. under the direction and review of the Office of Science and Technology. Neither the United
States Government nor any of its employees, contractors, subcontractors, or their employees
make any warrant, expressed or implied, or assume any legal liability or responsibility for any
third party's use of, or the results of such use, of any information, apparatus, product, or process
discussed in this report, or represents that its use by such party would not infringe on privately
owned rights.
The primary contact regarding questions or comments on this document is:
Ron Jordan
U.S. EPA Engineering and Analysis Division (6233Q)
1200 Pennsylvania Avenue, NW
Washington, D.C. 20460
(202) 566-1003 (telephone)
(202) 566-1053 (fax)
Jordan.Ronald@epa.gov
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Detailed Study Report - November 2006 Table of Contents
TABLE OF CONTENTS
Page
1.0 INTRODUCTION 1-1
2.0 DATA SOURCES 2-1
2.1 Department of Energy 2-1
2.1.1 Energy Information Administration 2-1
2.1.2 Other DOE Programs of Interest 2-2
2.2 EPA and State Permitting Authorities 2-3
2.2.1 Permit Compliance System 2-3
2.2.2 Toxics Release Inventory 2-4
2.2.3 NPDES Permits and Fact Sheets 2-5
2.2.4 Section 316(b) - Cooling Water Intake Structures Supporting
Documentation/Data 2-5
2.2.5 Office of Research and Development 2-6
2.2.6 1974 and 1982 Technical Development Documents for the
Steam Electric Power Generating Point Source Category 2-6
2.2.7 1996 Preliminary Data Summary for the Steam Electric
Power Generating Point Source Category 2-7
2.2.8 Office of Enforcement and Compliance Assistance Sector
Notebook 2-7
2.3 Department of Commerce Economic Census 2-7
2.4 Electric Power Industry, Vendors and Other Sources 2-7
2.4.1 Utility Water Act Group 2-8
2.4.2 Electric Power Research Institute 2-8
2.4.3 U.S. Geological Survey's COALQUAL Database 2-9
2.4.4 National Research Council 2-9
2.4.5 Wastewater Treatment Equipment Vendors 2-9
2.4.6 Literature and Internet Searches 2-10
3.0 STEAM ELECTRIC INDUSTRY PROFILE 3-1
3.1 Overview of the Electric Generating Industry 3-1
3.1.1 Types of Facilities within the Electric Generating Industry 3-1
3.1.2 Industrial Classifications of the Electric Generating Industry 3-2
3.2 General Description of Steam Electric Processes and Wastewater
Sources 3-3
3.2.1 Stand-Alone Steam Electric Process and Wastewater
Sources 3-3
3.2.2 Combined Cycle System Process and Wastewater Sources 3-12
3.3 Demographics of the Electric Generating Industry 3-14
3.3.1 Overview of the Electric Generating Industry 3-15
3.3.2 Regulated Steam Electric Generating Industry 3-16
4.0 SELECTED ENVIRONMENTAL REGULATIONS AFFECTING THE STEAM ELECTRIC
INDUSTRY 4-1
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Detailed Study Report - November 2006 Table of Contents
TABLE OF CONTENTS (Continued)
Page
4.1 Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating Point Source Category (40 CFR 423) 4-1
4.2 Clean Water Act Section 316(b) - Cooling Water Intake Structures 4-2
4.3 Clean Air Act 4-5
4.4 Resource Conservation and Recovery Act 4-6
5.0 STEAM ELECTRIC INDUSTRY WASTEWATER CHARACTERIZATION 5-1
5.1 Identification of the PCS and TRI Steam Electric Data 5-2
5.2 Annual Pollutant Loadings 5-4
5.2.1 TRI Wastewater Releases and Transfers 5-4
5.2.2 PCS Wastewater Discharges 5-6
5.3 Concentration Analyses of Steam Electric Pollutants 5-6
5.4 Sources and Concentrations of the Pollutants of Interest in Steam
Electric Waste Streams 5-10
5.4.1 Copper 5-14
5.4.2 Aluminum 5-14
5.4.3 Arsenic 5-15
5.4.4 Boron 5-15
5.4.5 Chlorine 5-17
5.4.6 Mercury 5-18
5.4.7 Nickel and Zinc 5-19
5.4.8 Total Suspended Solids 5-19
5.5 Pollutant Control Technologies and Practices 5-20
5.5.1 Cooling Water Pollutant Control Technologies 5-20
5.5.2 Zero Liquid Discharge Systems 5-23
6.0 ALTERNATIVE-FUELED STEAM ELECTRIC FACILITIES 6-1
6.1 Alternative-Fueled Steam Electric Processes and Wastewaters 6-1
6.1.1 Solid Fuels 6-2
6.1.2 Gaseous Fuels 6-4
6.1.3 Geothermal 6-5
6.1.4 Solar 6-6
6.1.5 Summary of NPDES Permit Review 6-6
6.2 Demographic Data 6-7
6.3 Summary 6-9
7.0 STEAM AND AIR CONDITIONING SUPPLY FACILITIES 7-1
7.1 Overview of the Steam and Air Conditioning Supply Sector 7-1
7.2 Summary of Available Data and Information 7-2
7.2.1 Permit Compliance System 7-2
7.2.2 Toxics Release Inventory 7-5
7.2.3 Energy Information Administration 7-5
7.2.4 NPDES Permit Review 7-6
7.3 Conclusion 7-6
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Detailed Study Report - November 2006 Table of Contents
TABLE OF CONTENTS (Continued)
Page
8.0 COMBINATION UTILITY WASTEWATERS 8-1
8.1 Overview of the Combination Utilities, NEC Sector 8-1
8.2 Summary of Available Data and Information 8-2
8.2.1 Toxics Release Inventory 8-2
8.2.2 Permit Compliance System 8-2
8.2.3 Energy Information Administration 8-6
8.2.4 NPDES Permit Review 8-8
8.3 Conclusion 8-9
9.0 INDUSTRIAL NON-UTILITIES 9-1
9.1 Overview of Industrial Non-Utilities 9-1
9.1.1 Relative Size of Industrial Non-Utilities 9-2
9.1.2 Fuels Used by Industrial Non-Utilities 9-2
9.2 Demographic Data for Fossil-Fueled Industrial Non-Utilities 9-3
9.2.1 Prime Movers/Generating Units 9-4
9.2.2 Fossil Fuel Types 9-7
9.3 Wastewater Characterization 9-7
9.4 Review of Industrial Non-Utility Discharge Permits 9-16
9.5 Conclusions 9-17
10.0 REFERENCES 10-1
in
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Detailed Study Report - November 2006 List of Tables
LIST OF TABLES
Page
3-1 Distribution of U.S. Electric Generating Facilities by NAICS Code 3-15
3-2 Distribution of TRI Electric Generating Facilities by SIC Code 3-15
3-3 Distribution of PCS Electric Generating Facilities by SIC Code 3-16
3-4 Distribution of Prime Mover Types Within the Regulated Steam Electric
Industry 3-18
3-5 Distribution of Fuel Types Within the Regulated Steam Electric Industry 3-19
3-6 Distribution of Fuel Types Used by Steam Electric Generating Units 3-20
3-7 Distribution of Regulated Steam Electric Capacity, Facilities, and
Generating Units by Size 3-21
4-1 Current Effluent Guidelines and Standards for the Steam Electric Power
Generating Point Source Category 4-3
5-1 Waste Streams from the Steam Electric Industry and Pollutants Typically
Associated with the Discharge 5-1
5-2 Comparison of PCS Discharge Data for All Electric Generating Facilities
vs. Regulated Steam Electric Facilities 5-3
5-3 Steam Electric TRI 2002 Pollutant Loads 5-5
5-4 Steam Electric PCS 2002 Pollutant Loads for Selected Pollutants 5-7
5-5 Summary of Average Pollutant Discharge Concentrations Reported to PCS 5-9
5-6 Summary of Average Pollutant Discharge Concentrations Reported to
PCS by Waste Stream 5-11
5-7 Summary of Pollutant Analysis 5-13
5-8 Biocide Usage in the Steam Electric Industry 5-17
5-9 Steam Electric Facilities Currently Operating ZLD Systems 5-25
6-1 Comparison of Available Coal Ash, Municipal Solid Waste Ash, and Wood
Ash Composition Data 6-3
6-2 Summary of Alternative-Fueled Steam Electric Facilities, by Fuel/Energy
Source Type 6-8
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Detailed Study Report - November 2006 List of Tables
LIST OF TABLES (Continued)
Page
7-1 Steam and Air Conditioning Supply Facilities Identified in 2002 PCS
Database 7-3
7-2 PCS 2002 Pollutant Loads for Steam and Air Conditioning Supply
Facilities 7-4
8-1 Combination Utilities Identified in 2002 PCS Database 8-3
8-2 PCS 2002 Pollutant Loads for Combination Utilities, NEC 8-5
8-3 Summary of EIA Data for Combination Utilities 8-7
9-1 Summary of Fossil-Fueled, Steam Electric Industrial Non-Utilities,
byNAICSCode 9-5
9-2 Distribution of Prime Mover Types Among Fossil-Fueled,
Steam Electric Industrial Non-utilities 9-6
9-3 Distribution of Fuel Types Among Fossil-Fueled, Steam Electric Industrial
Non-utilities 9-8
9-4 Fossil-Fueled, Steam Electric Industrial Non-Utilities Identified in PCS 9-10
9-5 Top 20 Pollutants Released from Industrial Facilities Operating a Fossil-
Fueled, Steam Electric Non-Utility 9-11
9-6 Top Pollutants Discharged by Industries Operating Fossil-Fueled Steam
Electric Non-Utilities 9-13
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Detailed Study Report - November 2006 List of Figures
LIST OF FIGURES
Page
3-1 Steam Electric Process Flow Diagram 3-4
3-2 Diagram of a Once-Through Cooling System 3-7
3-3 Diagram of a Recirculating Cooling System 3-8
3-4 Flue Gas Desulfurization (FGD) System 3-10
3-5 Combined Cycle Process Flow Diagram 3-13
3-6 Trend Toward Increased Operation of CCSs Within the Regulated Steam
Electric Industry 3-22
5-1 ZLD Boron Mitigation System for FGD Wastes 5-26
VI
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Detailed Study Report - November 2006
LIST OF ACRONYMS
API American Petroleum Institute
ASTM American Society for Testing and Materials
BART Best available retrofit technology
BAT Best available control technology economically achievable
BCT Best conventional pollutant control technology
BLM Bureau of Land Management
BOD5 5-day biochemical oxygen demand
BPJ Best professional judgment
BPT Best practicable control technology currently available
CAA Clean Air Act
CaCOs Limestone
CAIR Clean Air Interstate Rule
CAMR Clean Air Mercury Rule
Ca(OH)2 Lime
CaSOs Calcium sulfite
CAVR Clean Air Visibility Rule
CCH Chlorine and Chlorinated-Hydrocarbon Manufacturing
CCR Coal combustion residue
CCS Combined cycle system
CCT Clean Coal Technology
CFR Code of Federal Regulations
Cl Chlorine
Cb Chlorine gas
COALQUAL USGS's Coal Quality Database
COD Chemical oxygen demand
CPO Chlorine-produced oxidants
Cr Chromium
CRC Combined residual chlorine
Cu Copper
CURC Coal Utilization Research Council
CWA Clean Water Act
DMRs Discharge monitoring reports
DOE U.S. Department of Energy
EIA U.S. DOE's Energy Information Administration
ELGs Effluent limitations, guidelines, and standards
EPA U.S. Environmental Protection Agency
EPRI Electric Power Research Institute
ESP Electrostatic precipitator
FAC Free available chlorine
FAO Free available oxidants
Fe Iron
FGD Flue gas desulfurization
FR Federal Register
GPM Gallons per minute
HRSGs Heat recovery steam generators
IEP Innovations for Existing Plants
vii
List of Acronyms
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Detailed Study Report - November 2006
List of Acronyms
LIST OF ACRONYMS (Continued)
IGCC Integrated gasification combined cycle
Ib-eq Pound-equivalent
MDL Method detection level
MGD Million gallons per day
MGY Million gallons per year
MSW Municipal solid waste
MVR Mechanical vapor recompression
MW Megawatt
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NEC Not elsewhere classified
NESHAP National Emissions Standards for Hazardous Air Pollutants
NETL U. S. DOE's National Energy Technology Lab
Ammonia
2SO4 Ammonium sulfate
NH4HSO4 Ammonium bisulfate
NO Nitrogen monoxide
NO2 Nitrogen dioxide
NOX Nitrogen oxides
NPDES National Pollutant Discharge Elimination System
NRC National Research Council
NRECA National Rural Electric Cooperative Association
NRMRL U. S. EPA's National Risk Management Research Laboratory
NSPS New source performance standards
OAP Office of Atmospheric Programs
OAQPS U. S. EPA's Office of Air Quality Planning and Standards
OAR Office of Air and Radiation
OCPSF Organic Chemicals, Plastics & Synthetic Fibers Manufacturing
OECA U.S. EPA's Office of Enforcement and Compliance Assurance
O&G Oil and grease
ORD U. S. EPA's Office of Research and Development
OSW U.S. EPA's Office of Solid Waste
OW Office of Water
PCBs Polychlorinated biphenyls
PCS Permit Compliance System
POTWs Publicly owned treatment works
ppm Parts per million
PSES Pretreatment standards for existing sources
PSNS Pretreatment standards for new sources
RCRA Resource Conservation and Recovery Act
RDF Refuse-derived fuel
RICE Reciprocating internal combustion engine
SCR Selective catalytic reduction
SEGS Solar Electric Generating Stations
SIC U.S. Standard Industrial Classification
SMCRA Subsurface Mining Control and Reclamation Act
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Detailed Study Report - November 2006
List of Acronyms
SNCR
S02
SO3
IDS
Total P
TRC
TRI
TRO
TSS
TWF
TWPE
USCB
USGS
USWAG
UWAG
ZLD
Zn
LIST OF ACRONYMS (Continued)
Selective non-catalytic reduction
Sulfur dioxide
Sulfur trioxide
Total dissolved solids
Total phosphorus
Total residual chlorine
Toxics Release Inventory
Total residual oxidants
Total suspended solids
Toxic-weighting factor
Toxic-weighted pound equivalents
U.S. Census Bureau
U.S. Geological Survey
Utility Solid Waste Activities Group
Utility Water Act Group
Zero liquid discharge
Zinc
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Detailed Study Report - November 2006 Chapter 1 - Introduction
1.0 INTRODUCTION
Section 304(m) of the Clean Water Act (CWA) requires EPA to develop and
publish a biennial plan that establishes a schedule for the annual review and revision of national
effluent limitations guidelines and standards (ELGs) required by Section 304(b). EPA last
published an Effluent Guidelines Program Plan in 2004 [64 FR 53705; September 2, 2004].
During its 2005 screening-level analysis of discharges from categories with
existing regulations, EPA determined that the Steam Electric Power Generating Point Source
Category, regulated at 40 CFR 423 (i.e., the regulated steam electric industry), ranked second in
discharges of toxic and nonconventional pollutants. For more information on the development of
the category ranking, see the 2005 Screening-Level Analysis report [U.S. EPA, 2005a]. Because
of these findings, EPA conducted a more detailed study of this category.
During this detailed study, EPA first verified that the pollutant discharges
reported to the Permit Compliance System (PCS) and Toxics Release Inventory (TRI) for 2002
accurately reflect the current discharges of the industry. EPA also performed an in-depth
analysis of the reported pollutant discharges, and reviewed technology innovation and process
changes. Additionally, EPA evaluated certain electric power and steam generating activities that
are similar to the processes regulated for the Steam Electric Power Generating Point Source
Category, but that are not currently subject to ELGs.
In August 2005, EPA published its Preliminary Effluent Guidelines Plan for 2006
[70 FR 51042; August 29, 2005] and the Preliminary Engineering Report: Steam Electric
Detailed Study [U.S.EPA, 2005b]. Since that time, EPA continued to collect data and
information about the steam electric industry and, in particular, focused its efforts on the
following specific objectives for the study:
• To identify the key pollutants and sources of those pollutants discharged
by the regulated steam electric industry.
• To identify and assess available pollution control technologies and best
management practices within the industry to address significant pollutant
discharges.
• To evaluate the wastewaters from certain activities not currently regulated
by ELGs, which may be similar in nature to the waste streams regulated
by 40 CFR 423. EPA examined the following types of waste streams and
activities:
— Wastewaters from the combustion/gas turbine portion of combined
cycle systems (CCSs).
— Wastewaters associated with facilities that generate electric power
using steam to drive a turbine, but whose energy/heat source used
to produce the steam is not a fossil or nuclear fuel. These energy
sources may include combustible fuels, such as municipal solid
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Detailed Study Report - November 2006 Chapter 1 - Introduction
wastes, wood and wood wastes, and landfill gas, or renewable
energy sources, such as solar power and geothermal energy.
— Wastewaters associated with steam supply facilities that generate
steam for distribution and sale, but that do not primarily use that
steam to drive a turbine and produce electric power.
— Wastewaters associated with facilities providing a combination of
electric power and other utility services. EPA specifically focused
the study on those combination utilities that generate electric
power by using steam to drive a turbine.
— Wastewaters associated with industrial non-utilities that generate
electric power using steam to drive a turbine, but that are not
primarily engaged in distributing and selling that electric power.
These industrial steam electric non-utilities provide auxiliary
electric power to an industrial process (e.g., chemical
manufacturing, petroleum refining). EPA's focus for these
facilities is on the waste streams generated by the electric power-
generating non-utilities, and not the other waste streams generated
by the primary industrial processes at the facility.
EPA determined that the currently available data provide an incomplete picture of
the wastewaters generated by the regulated steam electric industry; however, they do suggest that
several process waste streams are primarily driving the pollutant loads discharged by these
facilities and that control technologies and management practices capable of achieving
significant pollutant reductions are technologically feasible.
EPA intends to continue its detailed study of the Steam Electric industry in its
2007/2008 planning cycle. The current evaluation allowed EPA to identify targeted areas of
concern for which EPA needs to collect additional data. The focus of further study is expected to
concentrate primarily on better characterizing pollutant sources and available pollution control
technologies/practices for the pollutants responsible for the majority of the toxic-weighted
pollutant loadings from steam electric facilities. One aspect of this further study will assess the
significance of air-to-water cross media pollutant transfers associated with air pollution controls.
In conducting this additional study, EPA's Office of Water will coordinate its efforts with
ongoing research and other activities being undertaken by other EPA offices, including the
Office of Research and Development (ORD), the Office of Solid Waste (OSW), and the Office
of Air Quality Planning and Standards (OAQPS) and the Office of Atmospheric Programs
(GAP), both in the Office of Air and Radiation (OAR).
EPA also investigated certain activities not currently regulated by the Steam
Electric effluent guidelines, as described above. Based on the information in EPA's
administrative record for this industry, EPA determined that revising the applicability of 40 CFR
423 to include these facilities is not warranted at this time.
This report, Interim Detailed Study Report for the Steam Electric Power
Generating Point Source Category ("Detailed Study Report"; EPA-821-R-06-015; DCN 3401),
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Detailed Study Report - November 2006 Chapter 1 - Introduction
describes the status of EPA's detailed study of the steam electric industry as of June 2006. It
documents the data and information that EPA used to support decisions with respect to the
current Steam Electric ELGs and the 2006 Effluent Guidelines Program Plan.
The report is organized into the following chapters:
• Chapter 2 discusses the data sources used in the detailed study;
• Chapter 3 presents a profile of the industry, including a description of the
steam electric process, sources of wastewater, and available demographic
data;
• Chapter 4 summarizes the existing regulations for this industry and other
regulations currently under development;
• Chapter 5 discusses wastewater characteristics and selected wastewater
control technologies and other best management practices used by the
steam electric industry;
• Chapter 6 describes steam electric facilities and processes that utilize
energy sources other than fossil or nuclear fuels;
• Chapter 7 presents a profile of the steam supply industry, including a
process description, sources of wastewater, and available demographic
data;
• Chapter 8 discusses combination utilities;
• Chapter 9 describes industrial non-utility steam electric processes and
wastewater sources; and
• Chapter 10 presents the references cited in this report.
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Detailed Study Report - November 2006 Chapter 2 - Data Sources
2.0 DATA SOURCES
This chapter describes the data sources EPA utilized for its detailed study of the
steam electric industry1. EPA used data from three primary data sources: the U.S. Department of
Energy's (DOE's) Energy Information Administration (EIA), the PCS, and the TRI. EPA also
reviewed data from other regulations impacting steam electric facilities, as well as data provided
by trade associations, vendors, and other sources.
It should be noted that EPA used data from a single calendar year whenever
possible, to allow data from the multiple sources to be combined in the analyses. At the time this
detailed study was initiated, EPA used 2002 data, the most recent TRI data available.
2.1 Department of Energy
DOE promotes scientific and technological innovation in support of its mission to
advance the national, economic, and energy security of the United States. DOE's goals toward
achieving this mission include applying advanced science and nuclear technology to the U.S.'s
defense, promoting a diverse supply and delivery of reliable, affordable, and environmentally
sound energy, advancing scientific knowledge, and providing for the permanent disposal of the
U.S.'s high-level radioactive waste. In this detailed study of the steam electric industry, EPA
used information on electric generating facilities from DOE's EIA data collection forms and
obtained background information on the steam electric industry from various DOE research
publications.
2.1.1 Energy Information Administration
EIA is a statistical agency of the DOE that collects information on existing U.S.
electric generating facilities and associated equipment to evaluate the current status and potential
trends in the industry. EPA used information from two of EIA's data collection forms: Form
EIA-860, Annual Electric Generator Report, and Form EIA-767, Steam Electric Plant Operation
and Design Report. These forms are discussed below.
Form EIA-860
Form EIA-860 collects information annually for all electric generating facilities
that have or will have a nameplate rating of one megawatt (MW) or more, and are operating or
plan to be operating within five years of the filing of the Annual Electric Generator Report. The
data collected in Form EIA-860 are associated only with the design and operation of the
generators at facilities [U.S. DOE, 2002a]. EPA used the following information from Form EIA-
860 to characterize the steam electric industry:
• Company Name;
• Facility Name;
1 The steam electric industry generally comprises all facilities that produce electricity using steam-driven turbines.
Refer to Chapter 3 for additional information.
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Detailed Study Report - November 2006 Chapter 2 - Data Sources
• North American Industry Classification System (NAICS) code;
• Nameplate Capacity - The maximum rated output of a generator;
• Prime Mover - The engine, turbine, water wheel, or similar machine that
drives an electric generator;
• Energy Source - The primary source providing the power that is converted
to electricity through chemical, mechanical, or other means; and
• Month and year of initial operation.
Form EIA-767
Form EIA-767 collects information annually from all electric generating facilities
with a total existing or planned, organic-fueled or renewable steam electric generating unit that
has a nameplate rating of 10 MW or larger. The data collected in Form EIA-767 is associated
with the operation and design of the entire facility. EPA used Form EIA-767 primarily for
information on the type of cooling systems used by the steam electric industry, as well as the
number of facilities using wet scrubber flue gas desulfurization (FGD) [U.S. DOE, 2002b]. EPA
used the following data elements from Form EIA-767:
• Type of system;
• Type of tower;
• Type of FGD system;
• Flow rates; and
• Source water.
One of the limitations of using data from Form EIA-767 is that the cooling system
information is required only for facilities that have a nameplate capacity larger than 100 MW;
therefore, not every facility reporting to Form EIA-767 provides information about their cooling
system. Although no information was available from this source for smaller facilities, EPA was
able to incorporate cooling system information for 51 facilities with a nameplate capacity less
than 100 MW through Section 316(b) Cooling Water Intake Structures rulemaking support
documents, as described in Section 2.2.4.
2.1.2 Other DOE Programs of Interest
DOE manages various programs that guide the research of novel technologies for
coal-fired power plants. Programs found to be especially pertinent to the steam electric industry
are described below:
• Clean Coal Technology (CCT) Program: This program is sponsored by
DOE, the Electric Power Research Institute (EPRI)2, and the Coal
Utilization Research Council (CURC). The goals for the CCT Program
: Section 2.4.2 described additional research EPRI is conducting.
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Detailed Study Report - November 2006 Chapter 2 - Data Sources
are to achieve near-zero emissions from coal-fired power plants and to
efficiently capture and sequester carbon.
• Innovations for Existing Plants (IEP) Program: This program is managed
by DOE's National Energy Technology Lab (NETL) and advances novel
technologies for coal-fired power plants, including the control of mercury
and nitrogen oxides (NOX) and technologies to improve the quality of coal
utilization by-products.
From the information published through these DOE research programs, EPA
obtained background information on current steam electric technologies, specifically pollution
control technologies for coal-fired steam electric facilities.
2.2 EPA and State Permitting Authorities
For this detailed study of the steam electric industry, EPA collected information
from the Agency's databases, publications, and state permitting authorities. EPA obtained
information on pollutant releases from the electric generating industry from the PCS and TRI
databases, information on current permitting practices for the steam electric industry from a
review of selected National Pollutant Discharge Elimination System (NPDES) permits,
information from a survey of the industry conducted in support of the Section 316(b) Cooling
Water Intake Structures rulemaking, and background information on the steam electric industry
from documents prepared during the development and revision of the ELGs for the Steam
Electric Power Generating Point Source Category, last promulgated in 1982.
2.2.1 Permit Compliance System
EPA's Office of Enforcement and Compliance Assurance (OECA) manages PCS,
which is a national data system that contains permit, compliance, and enforcement status
information on facilities with NPDES permits. Facilities that discharge wastewaters directly to
surface waters of the United States are required to obtain NPDES permits from EPA or state
permitting authorities. NPDES-permitted facilities submit Discharge Monitoring Reports
(DMRs) to their permitting authorities in accordance with their permit requirements, and the
permitting authorities input these DMR data to PCS.
The permitting authorities are required only to input DMR data for facilities that
they judge to be major sources of pollutants (i.e., facilities that are likely to significantly impact
receiving streams if they discharge without control). Thus, PCS identifies all facilities with
NPDES permits, but does not contain pollutant discharge data for all of these facilities. Because
permitting authorities are not required to input DMR data for minor sources, the data available
for minor sources are limited in PCS.
EPA created the PCSLoads2002 database [U.S. EPA, 2006a] using the PCS
pollutant discharge data from 2002 and various database development tools. In addition to
calculating pollutant mass loads, PCSLoads2002 estimates the hazard of the pollutant mass loads
by multiplying the pounds of pollutants discharged by the pollutant-specific toxic weighting
factors (TWFs). This results in an estimate of toxic-weighted pound equivalents (TWPEs).
PCSLoads2002 uses the TWFs traditionally used in the ELG Program to quantify the relative
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Detailed Study Report - November 2006 Chapter 2 - Data Sources
toxicity of pollutant discharges. For additional information on the development of
PCSLoads2002, see the 2005 Annual Screening-Level Analysis report [U.S. EPA, 2005a].
EPA made modifications and updates to PCSLoads2002 that were specific to the
steam electric industry based on public comment and additional data review. The revised
pollutant loads and concentrations presented in Chapter 5 reflect these changes. For additional
information on these modifications and updates, see the memorandum entitled "Changes Made
to the PCSLoads2002 Database Based on Facility-Specific Comments" [ERG, 2006].
2.2.2 Toxics Release Inventory
The TRI database contains information on toxic chemical releases that are
reported annually to EPA by facilities meeting size, industrial classification, and chemical
activity criteria. These facilities report the amounts of toxic chemicals released to the
environment, as well as the amounts of toxic chemicals transferred in wastes to off-site locations,
including discharges to publicly owned treatment works (POTWs). The TRI chemical releases
are reported as pounds per year.
Steam electric facilities are required to report to TRI if the facility meets all of the
following criteria3:
• Number of Employees: A facility must have 10 or more full-time
employees or their equivalent. EPA defines a "full-time equivalent" as a
person who works 2,000 hours in the reporting year.
• Industrial classification: The operations of the facility are primarily
classified within U.S. Standard Industrial Classification (SIC) codes 4911,
4931, or 4939 and the facility combusts coal and/or oil for the purpose of
generating electric power for distribution in commerce.
• Activity Thresholds: A facility must conduct an activity threshold analysis
for every chemical and chemical category on the current TRI list to
determine whether it manufactures, processes, or otherwise uses each of
those chemicals at or above the appropriate activity threshold.
Based on the above criteria, natural gas- or nuclear-powered electric power
generating facilities are not required to report toxic chemical releases to EPA. If an electric
power generating facility combusts any amount of coal or oil to generate electricity for
distribution in commerce, the entire facility (including the non-coal/oil combustion processes) is
subject to TRI reporting requirements. EPA considers kerosene and petroleum coke as "oil" for
TRI reporting purposes [U.S. EPA, 2000].
EPA used the toxic chemical release data from the 2002 TRI reporting year to
create the TPJReleases2002 database [U.S. EPA, 2006b]. In this detailed study of the steam
electric industry, EPA used TPJReleases2002 to compute a TWPE for each TRI chemical
3 All facilities meeting this criteria report to EPA, even if no releases of the toxic chemical occurred during the
reporting year.
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discharged with facility wastewaters. For additional information on TRI reporting and the
development of TRIReleases2002, see the 2005 Annual Screening-Level Analysis report [U.S.
EPA, 2005a].
2.2.3 NPDES Permits and Fact Sheets
The CWA requires direct dischargers (i.e., industrial facilities that discharge
process wastewaters from any point source into receiving waters) to control their discharges
according to ELGs and water-quality-based effluent limitations within NPDES permits.
EPA reviewed selected NPDES permits and, where available, accompanying fact
sheets to identify the sources of wastewater at steam electric facilities and to determine how the
wastewaters are currently regulated (i.e., parameter limits and the basis for parameter selection).
As part of EPA's NPDES permit review, Agency personnel contacted state permit writers to
obtain additional information or clarify permit information. Information obtained from the
NPDES permit review has been included in this report, where appropriate. The NDPES permits
and fact sheets reviewed for the study are located at EPA Docket ID No. OW-2004-0032.
2.2.4 Section 316(b) - Cooling Water Intake Structures Supporting
Documentation/Data
For the CWA section 316(b) Cooling Water Intake Structures rulemaking, EPA
conducted a survey of steam electric utilities and steam electric non-utilities that use cooling
water, as well as facilities in four other manufacturing sectors: Paper and Allied Products (SIC
code 26), Chemical and Allied Products (SIC code 28), Petroleum and Coal Products (SIC code
29), and Primary Metals (SIC code 33). The survey requested the following types of
information:
• General plant information, such as plant name, location, and SIC codes;
• Cooling water source and use;
• Design and operational data on cooling water intake structures and cooling
water systems;
• Studies of the potential impacts from cooling water intake structures,
conducted by the facility; and
• Financial and economic information about the facility.
Although the Section 316(b) survey was used to create guidelines for cooling
water intake structures, the cooling water system information collected in the survey is useful for
this study of the steam electric industry. EPA used the information provided by the Section
316(b) survey in the following analyses:
Linking EIA facility information to the TRI and PCS discharges;
Identifying the type of cooling systems used by facilities; and
Identifying industrial non-utilities.
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Refer to Section 4.2 of this report for additional information about the section
316(b) regulations.
2.2.5 Office of Research and Development
EPA's ORD is currently evaluating the impact of air pollution controls on the
characteristics of coal combustion residues (CCRs). Specifically, ORD is studying the potential
cross-media transfer of mercury and other metals from flue gas, fly ash, and other residues
collected from coal-fired boiler air pollution controls and disposed of in landfills or surface
impoundments, with the key route of release being leaching into groundwater or subsequent
release into surface waters, re-emission of mercury, and bioaccumulation. ORD is also
examining the use of CCRs in asphalt, cement, and wallboard production.
This research seeks to better understand potential impacts from disposal practices
and beneficial use of CCRs. The research includes taking a holistic approach, calculating life-
cycle environmental tradeoffs that compare beneficial use applications with and without using
CCRs. The outcome of this research will help to identify potential management practices of
concern where cross-media transfers may occur.
In addition, the ORD research is intended to provide methodologies and data for
quantifying potential benefits and environmental tradeoffs from CCR utilization. Another
outcome is the development and application of a leach testing framework that evaluates a range
of materials and the different factors affecting leaching for the varying field conditions in the
environment.
EPA's OW consulted with ORD during this industry study, including reviewing a
February 2006 report [U.S. EPA, 2006c] to better understand the current research on CCRs and
assess the potential for CCRs from air pollution controls to impact surface water quality.
Sections 4.3 and 4.4 of this report include more information about air pollution control
regulations and ongoing OSW rulemaking efforts to manage CCRs.
2.2.6 1974 and 1982 Technical Development Documents for the Steam Electric
Power Generating Point Source Category
The 1974 Development Document for Effluent Limitations Guidelines and New
Source Performance Standards for the Steam Electric Power Generating Point Source Category
(hereinafter the 1974 Development Document) [U.S. EPA, 1974] and the 1982 Development
Document for Effluent Limitations Guidelines and Standards and Pretreatment Standards for the
Steam Electric Point Source Category (hereinafter the 1982 Development Document) [U.S.
EPA, 1982] present the results of studies of the steam electric industry that EPA conducted in
developing the Steam Electric ELGs. These development documents contain findings,
conclusions, and recommendations on control and treatment technology relating to discharges
from steam electric facilities. In this detailed study, EPA used the information presented in the
1974 and 1982 Development Documents for historical background on the Steam Electric ELGs,
for information on sources of pollutants, and as a point of reference.
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2.2.7 1996 Preliminary Data Summary for the Steam Electric Power Generating
Point Source Category
EPA prepared the 1996 Preliminary Data Summary for the Steam Electric Power
Generating Point Source Category (hereinafter the Preliminary Data Summary) to provide
technical support for a possible revision of the Steam Electric ELGs [U.S. EPA, 1996]. This
Preliminary Data Summary contains descriptions of the steam electric process and information
on the pollutants released in each of the different types of waste streams. Additionally, the
Preliminary Data Summary includes information regarding changes that were beginning to occur
in the steam electric industry at the time of publication. EPA used the data and information
presented in the 1996 Preliminary Data Summary as a point of reference in this detailed study.
2.2.8 Office of Enforcement and Compliance Assistance Sector Notebook
The OECA Sector Notebook, Profile of the Fossil Fuel Electric Power
Generation Industry [U.S. EPA, 1997], contains the following information:
• Industry profile using 1995 data;
• Industrial process descriptions;
• Chemical releases and transfers;
• Pollution prevention opportunities; and
• Regulatory summary.
In this detailed study of the steam electric industry, EPA supplemented data from
EIA, PCS, and TRI with background information from the Sector Notebook.
2.3 Department of Commerce Economic Census
The Economic Census provides a detailed portrait of the U.S. economy once
every five years. The 2002 Economic Census covers nearly all of the U.S. economy in its basic
collection of facility statistics, and provides the following information by NAICS code:
• Number of companies;
• Number of establishments (i.e., facilities);
• Number of employees; and
• Number of establishments by size range, based on number of employees.
The Economic Census provides an upper limit of the number of facilities
performing steam electric generating operations in the United States. The Census data overstate
the steam electric numbers by including electric generating facilities that do not specifically use
steam turbines (e.g., facilities using only gas turbines). For this reason, EPA used the Census
data only as a point of reference in this detailed study.
2.4 Electric Power Industry, Vendors and Other Sources
EPA obtained additional information on steam electric processes, technologies,
wastewaters, pollutants, and regulations from the following sources.
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2.4.1 Utility Water Act Group
The Utility Water Act Group (UWAG) is a trade association that represents the
utility electricity producers. Since early 2005, EPA staff have met and corresponded with
representatives of UWAG on multiple occasions to discuss the detailed study and certain
inconsistencies and gaps in PCS data. UWAG has provided the following types of data and
information regarding the steam electric industry:
• Reports related to chlorine use, including a comparison of continuous and
intermittent exposure of four species of aquatic organisms to chlorine and
the formation and fate of trihalomethanes in power plant cooling water
systems;
• A list of National Rural Electric Cooperative Association (NRECA)
members;
• Comments, including facility-specific corrections to the PCSLoads2002
database;
• The Utility Industry Action Plan for the Management of Coal Combustion
Products [USWAG, 2006], submitted to EPA's OSW by the Utility Solid
Waste Activities Group (USWAG);
• American Coal Ash Association's Coal Combustion Products Production
and Use Survey (2001-2003) [ACAA, 2003];
• UWAG voluntary survey data including: (1) biocide management
techniques; (2) retrofit of dry fly ash handling technologies; (3) typical
wastewater discharges from combined cycle facilities; and (4) beneficial
use of ash;
• Discussion of representativeness of survey data; and
• Correspondence responding to questions on technologies and practices in
use by industry.
Information provided by UWAG to EPA as of June 2006 has been included in this
report, where appropriate. For more information regarding specific information that has been
provided to EPA, see Docket ID No. OW-2004-0032.
2.4.2 Electric Power Research Institute
EPRI conducts research on issues associated with energy and the environment
that are facing the electric power industry. Founded in 1973 as a private, public-interest, not-for-
profit organization, EPRI manages a science and technology program that addresses current
issues as well as future technology options for nearly every aspect of electricity generation,
delivery, and use. EPRI's specific programs of interest to this study include:
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• The Technology Innovation research and development program that
advances novel technologies in all areas of the electricity sector;
• The Mercury, Metals, and Organics in Aquatic Environments program
that mitigates the risks associated with these pollutants in aquatic
environments; and
• The Integrated Facilities Water Management program that delivers
information, technologies, and practical tools and guidelines for biological
fouling control, wastewater treatment, advanced cooling alternatives, and
water recycling and reuse at industrial facilities.
EPA gained insight into how issues and technologies related to the steam electric
industry are currently being researched through EPRI's published information. Specifically,
EPA obtained background information on the pollutants of interest to this steam electric detailed
study.
2.4.3 U.S. Geological Survey's COALQUAL Database
Since the middle 1970s, the U.S. Geological Survey (USGS) has maintained a
national coal quality database, containing data compiled on more than 13,000 coal samples
collected by USGS and cooperative state geological surveys. For each sample, 136 parameters
are recorded, including data on location and sample description, analytical data from American
Society for Testing and Materials (ASTM) tests, and USGS tests for major, minor, and trace
elements. The COALQUAL database [USGS, 1998] contains coal quality data for 7,430 coal
samples that represent complete-bed thicknesses at various localities. All elemental data are
reported in parts-per-million (ppm). EPA used data from the COALQUAL database to identify
constituents of coal and the range of concentrations associated with certain metals, such as boron
and mercury.
2.4.4 National Research Council
In response to a request from Congress regarding concern over the use of CCRs as
backfill for mining operations, EPA commissioned an independent study of the health, safety,
and environmental risks associated with this practice. The National Research Council (NRC)
established the Committee on Mine Placement of Coal Combustion Wastes, which addressed the
potential issues of using CCRs in mines. For this detailed study, EPA reviewed a prepublication
copy of NRC's report, Managing Coal Combustion Residues in Mines [NRC, 2006]. This NRC
report provides background information for this detailed study on potential cross-media transfers
of pollutants from CCR solids/slurries to water. Section 4.4 of the detailed study report contains
additional summary information about current EPA solid waste rulemaking efforts.
2.4.5 Wastewater Treatment Equipment Vendors
EPA contacted companies that manufacture, distribute, or install various
components of pollutant removal systems, including dehalogenation systems and pollutant
mitigation systems. EPA obtained information about the operation of these systems and the type
and cost of the equipment used.
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2.4.6 Literature and Internet Searches
EPA conducted internet and literature searches to obtain information on the steam
electric industry. These searches focused on various aspects of the steam electric process (those
regulated by the Steam Electric ELGs and certain processes outside the scope of the ELGs),
wastewaters and pollutants originating from these steam electric processes, and existing
regulations for steam electric facilities. Information obtained from the internet and literature
searches has been included in this report, where applicable.
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3.0 STEAM ELECTRIC INDUSTRY PROFILE
This chapter describes the Steam Electric Power Generating Point Source
Category (as defined at 40 CFR 423.10) in relation to the electric generating industry as a whole.
Electric generating facilities use various types of prime movers driven by an
energy source to produce electricity. DOE's EIA defines a prime mover as the engine, turbine,
water wheel, or similar machine that drives an electric generator, or a device that converts energy
to electricity directly (e.g., photovoltaic solar and fuel cell(s)) [U.S. DOE 2006a]. The types of
prime movers include steam turbines, gas turbines, internal combustion engines, combined-cycle
systems, hydraulic turbines, and others.
For the purposes of discussions presented in this report, EPA is using the
following definitions for various subgroups of electric generating facilities:
• Electric generating industry: Comprises utilities and non-industrial non-
utilities primarily classified within SIC codes 4911, 4931, and 4939.
Section 3.1.1 describes utilities and non-industrial non-utilities in greater
detail.
• Steam electric industry: Comprises electric generating facilities (as
defined above) that produce electricity for distribution and sale using
steam to drive a turbine/electricity generator.
• Regulated steam electric industry: Comprises steam electric facilities (as
defined above) within the Steam Electric Power Generating Point Source
Category, as defined at 40 CFR 423.10. These facilities primarily utilize
fossil or nuclear fuels to drive a steam turbine used to produce electricity
for distribution and sale.
3.1 Overview of the Electric Generating Industry
This chapter describes the types of facilities that compose the overall electric
generating industry. As described above, the regulated steam electric industry is included within
this general industrial sector.
3.1.1 Types of Facilities within the Electric Generating Industry
Electric generating facilities may be categorized as one of the following types:
1. Utility: A corporation, person, agency, authority, or other legal entity or
instrumentality that owns and/or operates facilities for the generation,
transmission, distribution, or sale of electric energy for use primarily by
the public. Utilities provide electricity within a designated franchised
service area and file forms listed in 18 CFR Part 141. Per EIA, facilities
that qualify as cogenerators or small power producers under the Public
Utility Regulatory Policies Act are not considered electric utilities [U.S.
DOE, 2006a].
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2. Non-industrial non-utility: A corporation, person, agency, authority, or
other legal entity or instrumentality that owns electric generating capacity
and is not an electric utility. Non-utility power producers include
qualifying cogenerators, qualifying small power producers, and other non-
utility generators (including independent power producers) without a
designated franchised service area, and that do not file forms listed in 18
CFRPart 141 [U.S. DOE, 2006a]. Like utilities, non-industrial non-
utilities' primary purpose is producing electric power for distribution and
sale.
3. Industrial non-utility: Industrial non-utilities are similar to non-industrial
non-utilities except their primary purpose is not the distribution and sale of
electricity. This category includes electric generators that are colocated
with other manufacturing activities such as chemical manufacturing or
pulp and paper mills.
The applicability of the existing Steam Electric ELGs includes establishments
"...primarily engaged in the generation of electricity for distribution or sale... " as defined at 40
CFR 423.10. As such, the electric generating industry, including regulated steam electric
facilities, comprises both utilities and non-industrial non-utilities. Industrial non-utilities are not
within the scope of the existing Steam Electric ELGs applicability, since they are not primarily
engaged in producing electricity for distribution or sale.
3.1.2 Industrial Classifications of the Electric Generating Industry
The electric generating industry is generally categorized by three SIC codes:
• 4911 - Electric services: Establishments engaged in the generation,
transmission, and/or distribution of energy for sale.
• 4931 - Electric and other services combined: Establishments primarily
engaged in providing electric services in combination with other services
when the electric services are the major part of the services, but are less
than 95 percent of the total services.
• 4939 - Combination utilities, not elsewhere classified (NEC):
Establishments primarily engaged in providing combinations of electric,
gas, and other services, not elsewhere classified.
In 1997, the SIC system was replaced by NAICS. SIC codes 4911, 4931, and
4939 are now captured under NAICS code 2211 - Electric Power Generation, Transmission, and
Distribution, which includes establishments that may perform one or more of the following
activities:
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1. Operate generation facilities that produce electric energy;
2. Operate transmission systems that convey the electricity from the
generation facility to the distribution system; and
3. Operate distribution systems that convey electric power received from the
generation facility or the transmission system to the final consumer
[USCB, 2002].
The following specific NAICS codes apply to steam electric facilities:
• 221112 - Fossil Fuel Electric Power Generation;
• 221113 - Nuclear Electric Power Generation; and
• 221119 - Other Electric Power Generation.
It should be noted that these SIC/NAICS codes include all electric generating
facilities, not just steam electric facilities. For example, some of the facilities included in SIC
4911 generate electricity solely by way of combustion/gas turbines or hydroelectric turbines (i.e.,
steam is not used to move the turbine).
Industrial non-utilities are not categorized within the electric generating SIC and
NAICS codes described above, since their primary purpose is not the distribution or sale of
electricity. Industrial non-utilities provide electrical power to the industrial operation with which
they are typically colocated. As such, these facilities tend to identify themselves within the SIC
or NAICS code of the primary industrial operation performed at the site.
Because industrial non-utilities are not included in the regulated steam electric
industry, they are not included in the information presented in this chapter, but are discussed in
greater detail in Chapter 9 of this report.
3.2 General Description of Steam Electric Processes and Wastewater Sources
This section describes the steam electric generating process and the wastewater
streams that are generated by each of the primary unit operations. This section is divided into
discussions of the stand-alone steam electric process and that used by CCSs.
3.2.1 Stand-Alone Steam Electric Process and Wastewater Sources
Steam electric facilities generate electricity using a process that includes: 1) a
steam generator (i.e., boiler); 2) a steam turbine/electrical generator; and 3) a condenser. Figure
3-1 illustrates the stand-alone steam electric process, in which a combustible fuel is used as the
energy source to generate steam. The existing Steam Electric ELGs specifically regulate
wastewaters discharged by steam electric facilities that use fossil-type fuel (e.g., coal, oil, or gas)
or nuclear fuel to generate the steam. However, other fuel sources such as municipal solid
wastes or wood wastes may also be used to produce the steam used in a steam electric process.
Chapter 6 of this report discusses steam electric processes that use alternative fuel sources.
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Gas to
Atmosphere
Fuel
(e.g., coal, oil, or gas)
Air Pollution
Control Wastes
Fly Ash Sluice
(if wet handling system)
Chemical
Addition
Once-through Cooling Water
^-Once-through Discharge
-OR-
Recirculating System
Bottom Ash Sluice Waste
(if wet handling system) (Treatment Residuals)
Sources: U.S. EPA, 1996 and U.S. EPA, 1997
Figure 3-1. Steam Electric Process Flow Diagram
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As shown in Figure 3-1, fuels are fed to a boiler where they are combusted to
generate steam. Boilers may have superheaters, reheaters, economizers, and air heaters to
improve efficiency. The high-temperature, high-pressure steam leaves the boiler and enters the
turbine generator. As it moves from the high-pressure boiler to the low-pressure condenser, the
steam drives the turbine blades. During the process, the steam expands, and the lower-pressure
steam enters the condenser, where it is condensed by the cooling water flowing through
condenser tubes. The condensation process creates the low pressure required to increase the
efficiency of the turbine. The condensate travels back to the boiler where it is reheated for use in
the turbine [U.S. EPA, 2005b].
The steam cycle described above, known as the Rankine cycle, is referred to at 40
CFR 423.10 as the "steam water system" and is referred to throughout the remaining sections of
this report as the "steam/water system." The 1974 Development Document refers to this cycle as
the "water-steam cycle" and includes in its description the following major stages: steam
generation; conversion of steam into mechanical energy in a turbine; steam condensation;
conversion of mechanical energy into electrical energy by electrical generator; and the
reintroduction of condensed steam into the boiler. The 1974 Development Document states that
the steam exiting the turbine "could be exhausted directly to the atmosphere thus avoiding the
requirement for condensers or condenser cooling water, but with poor cycle efficiency and a
requirement for large quantities of high purity water" [U.S. EPA, 1974].
Instead of being exhausted, the noncondensed, low-pressure steam exiting a
turbine from a steam electric process may be used in other processes, such as with cogeneration
facilities4. In these cases, the spent steam is typically condensed downstream of the steam
electric process at the point of use, which maintains the efficiency of the steam turbine. The
wastewaters from these separated condensation stages may not be permitted as part of the steam
electric process. Some of the industrial non-utilities discussed in Chapter 9 are cogeneration
facilities. It is possible that some of the alternative-fueled steam electric facilities discussed in
Chapter 6 are also cogeneration facilities.
The nuclear-fueled steam electric process uses the same steam/water system as
described above for the stand-alone steam electric process; however, the process differs in that
nuclear fission within a reactor core gives off the heat required for steam generation. No fuel is
combusted and no ash is generated in a nuclear-fueled steam electric process. Instead, heat is
transferred from the reactor core by creating steam in boiling water reactors or creating
superheated water in pressurized-water reactors. Wastewaters from nuclear reactors may contain
radioactive material. The steam turbine/electric generator and condenser portions of the nuclear-
fueled steam electric process are the same as those described in this section for the stand-alone
steam electric process [U.S. DOE, 2006b].
The following subsections describe the wastewaters associated with the stand-
alone steam electric process and briefly discusses the types of pollutants that are typically present
in these wastewaters. Chapter 5 of this report discusses in detail the pollutants found in steam
electric process wastewaters.
4 A cogeneration facility is defined as "a generating facility that produces electricity and another form of useful
thermal energy (such as heat or steam), used for industrial, commercial, heating, or cooling purposes" [U.S. DOE,
2006a].
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3.2.1.1 Fly and Bottom Ash Sluice
Combusting coal and oil in steam electric boilers produces a residue of the
noncombustible constituents of the fuel that is referred to as ash. The ash consisting of heavy
particles that collect at the bottom of the boiler is referred to as bottom ash. The ash consisting
of finer particles that are light enough to be transferred by the flue gas is referred to as fly ash.
Fly ash may be collected in an economizer, air heater, or particulate control equipment. Fly ash
and bottom ash may be handled in a wet or dry fashion and may be transferred together or
separately. Wet handling systems produce slurries of ash, referred to as sluices, that are typically
transferred to wet surface impoundments. Ash handled in a dry fashion is typically transferred to
landfills. Coal-fired facilities typically generate large quantities of both fly and bottom ash. Oil-
fired facilities typically produce less ash than coal-fired facilities, and most of that is fly ash.
Natural gas-fired facilities do not generate ash. The characteristics of ash depend on the type of
fuel combusted, how it is prepared prior to combustion, and the operating conditions of the
boiler. Fly and bottom ash sluices typically contain heavy metals, including priority pollutants
[U.S. EPA, 1982].
3.2.1.2 Metal Cleaning Wastes
According to 40 CFR 423.11, "The term metal cleaning waste means any
wastewater resulting from cleaning [with or without chemical cleaning compounds] any metal
process equipment, including, but not limited to, boiler tube cleaning, boiler fireside cleaning,
and air preheater cleaning." Chemicals are used to remove scale and corrosion products that
accumulate on the boiler tubes and retard heat transfer. The major constituents of boiler cleaning
wastes are the metals of which the boiler is constructed, typically iron, copper, nickel, and zinc.
Boiler firesides are commonly washed with a high-pressure water spray against the boiler tubes
while they are still hot. Fossil fuels with significant sulfur content will produce sulfur oxides
that adsorb on air preheaters. Water with alkaline reagents is often used in air preheater cleaning
to neutralize the acidity due to the sulfur oxides, maintain an alkaline pH, and prevent corrosion.
The types of alkaline reagents used include soda ash, caustic soda, phosphates, and detergent.
3.2.1.3 Once-Through Cooling Water
In the steam electric process, a constant flow of cooling water is required to
maintain steam condensation and a low pressure in the condenser. In once-through cooling
water systems, the cooling water is withdrawn from a body of water, flows through the
condenser, and is discharged back to the body of water. Figure 3-2 presents a diagram of a once-
through cooling system. Steam electric facilities using a once-through system use large amounts
of water, with an average flow rate of approximately 230 million gallons per day (MOD) per
cooling water system5 [U.S. EPA, 2006b]. Facilities may add chlorine or other biocides to the
water to control the biofouling on the condenser tubes. The biocides kill the microbiological
species that build up on the condenser tubes to allow for efficient heat transfer. Chapter 5
5 EPA calculated a discharge rate of 230 MOD from a once-through cooling system using PCS flow data available
for 64 facilities and 80 waste streams identified as once-through cooling water [U.S. EPA, 2006b]. The 1982
Development Document states that the average flow rate through a once-through cooling system was 305 MOD,
based on industry survey data [U.S. EPA, 1982]. The 1996 Preliminary Data Study states that the once-through
cooling water flow rate for a 1,150-MW coal-fired power plant is approximately 1,440 MOD [U.S. EPA, 1996].
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discusses in more detail the steam electric industry's use of biocides and the technologies and
practices used to minimize their discharge.
Condenser
Cooling Water / \ Cooling Water
Intake / /\ \ Discharge
Figure 3-2. Diagram of a Once-Through Cooling System
3.2.1.4 Recirculating Cooling Tower Slowdown
A recirculating cooling system recirculates the cooling water required to maintain
steam condensation and a low pressure in the condenser. After the water passes through the
condenser, the heated water is typically sent to a cooling tower to lower the temperature of the
water. The heated water enters the cooling tower at the top and falls down the packing material
in the tower. Air flows upward through the tower, and as the air contacts the droplets of water,
some of the water evaporates. The high surface area of the packing material enhances
evaporation. As water evaporates, the latent heat required to evaporate the water is transferred
from the cooling water to the air, cooling the water. Because some of the water evaporates, the
cooling water flow rate is decreased during the process. Additionally, a small amount of water
must be discharged periodically to control the build-up of solids, which is referred to as "cooling
tower blowdown." Therefore, fresh make-up water is added to the system to keep the flow rate
constant.
Figure 3-3 presents a diagram of a recirculating cooling system. Steam electric
facilities using a recirculating system use much smaller amounts of water than facilities using
once-through cooling systems, with an average flow rate of approximately 6.04 MOD per
cooling water system6 [U.S. EPA, 2006b]. EPA estimated that recirculating systems require
only about five percent of the water that once-through systems require [U.S. EPA, 1982]. Some
of the available data suggest that recirculating systems may discharge less than one percent of
that from once-through systems (refer to Footnotes 5 and 6).
6 EPA calculated a flow rate of 6.04 MOD for discharges from a recirculating cooling system using PCS flow data
available from 111 facilities and 174 waste streams identified as cooling tower blowdown [U.S. EPA, 2006b]. The
1982 Development Document stated that the average blowdown flow rate from a recirculating cooling system was
0.94 MOD, based on industry survey data [U.S. EPA, 1982]. The 1996 Preliminary Data Summary stated that the
cooling tower blowdown flow rate from a 1,150-MW coal-fired power plant ranges from 13.6 MOD to 36.6 MOD,
depending on the cycle of concentration (i.e., number of times the water is reused in the system prior to blowdown)
[U.S. EPA, 1996].
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Make-upWater
Cooling
Tower
RecirculatedCoolii
Water
Cooling Tower
Slowdown
Figure 3-3. Diagram of a Recirculating Cooling System
As in once-through systems, facilities may add chlorine, other oxidizing biocides,
or nonoxidizing biocides to recirculating systems to control the biofouling on the condenser
tubes and the cooling tower packing material. Chapter 5 discusses in more detail the steam
electric industry's use of biocides and the technologies and practices used to minimize their
discharge.
3.2.1.5
Coal Pile Runoff
Coal-fueled steam electric facilities typically maintain an outdoor reserve of coal.
Rainwater can dissolve inorganic salts or cause chemical reactions in coal storage piles and carry
away pollutants in the runoff. The quantity of runoff depends upon the amount of rainfall, and
the amount of contaminants generated depends upon residence time of water within the coal pile.
Coal pile runoff is typically acidic due to the oxidation of iron sulfide, which produces sulfuric
acid, and ferric hydroxide or ferric sulfate. Coal pile runoff may contain high concentrations of
copper, iron, aluminum, nickel, and other constituents present in coal [U.S. EPA, 1982].
3.2.1.6
Air Pollution Control Wastes
Due to the new air regulations for the steam electric industry (Clean Air Interstate
Rule (CAIR) and Clean Air Mercury Rule (CAMR), discussed in Chapter 4), EPA expects that
the use of wet air pollution control devices will increase at steam electric facilities. The two air
pollution control devices that will likely be installed to meet the requirements of the new CAIR
rule are FGD (for sulfur dioxide (862) control), and selective catalytic reduction (SCR) (for
control of NOX). These two processes are described in the following subsections.
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Flue Gas Desulfurization
FGD systems are used by power plants to control the 862 emissions from the
facility. Wet scrubber systems are the most common; however, dry and spray dry FGD systems
also exist [U.S. EPA, 2003]. This detailed study focused on wastewaters from wet FGD systems
only.
Wet scrubbers work by contacting the gas streams with a liquid stream containing
a sorbent, which effects mass transfer. The sorbents typically used for SC>2 absorption are lime
(Ca(OH)2) and limestone (CaCO3). Equations 3-1 and 3-2 show the reactions that occur between
these sorbents and 862, producing calcium sulfite (CaSO3).
CaCO3 (s) + SO2 (g) -> CaSO3 (s) + CO2 (g) (3-1)
Ca(OH)2 (s) + S02 (g) -> CaS03 (s) + H2O 0) (3 -2)
In some wet systems (e.g., limestone forced oxidation), the CaSO3 is oxidized to
produce gypsum (CaSO4*2H2O):
CaSO3 (s) + '/2 O2 (g) + H2O (i) -> CaSO4 (s)*H2O (s) (3-3)
While these systems are more costly to operate, they afford large coal-fired plants
benefits beyond the traditional wet scrubber system [U.S. EPA, 2003]. Unlike CaSO3, which
must typically be disposed of in landfills or surface impoundments, gypsum can be marketed for
use in building materials (e.g., wallboard) [U.S. EPA, 2006c].
Typically, FGD systems can remove over 90 percent of the 862 in the flue gas.
During the scrubbing process, metals and other particulates, including boron, mercury7, and
selenium, that were not removed from the flue gas stream by the electrostatic precipitators
(ESPs) may be transferred to the scrubber blowdown. The average flow rate for FGD scrubber
blowdown is approximately 0.35 MGD8. Figure 3-4 presents a diagram of an FGD system.
Regulations that limit the emissions of SC>2 and promote the use of wet scrubbers
have the potential to create new wastewater streams at electric utilities. For example, wet FGD
systems create a sludge by-product that is generally between 5 and 10 percent solids [U.S. EPA,
2006c], which may require dewatering prior to disposal or processing for reuse.
7 ESPs capture particulate-bound mercury and FGD systems capture soluble mercury compounds. Available data
indicate that elemental mercury may be oxidized in an SCR unit (particularly when bituminous coal is being used).
This enhances the amount of oxidized mercury in the gas stream that may then be removed in the downstream wet
FGD system [U.S. EPA, 2005c].
8 EPA calculated a flow rate of 0.35 MGD for discharges from FGD scrubber blowdown using PCS flow data
available from 10 waste streams identified as being associated with FGD [U.S. EPA, 2006a]; however, available
data on FGD wastewaters is limited. FGD system information was reported by 183 steam electric facilities to the
EIA in Form EIA-767 [U.S. DOE, 2002b]. EPA also estimates that steam facilities with FGD systems account for
approximately 33 percent of the total U.S. steam electric capacity, based on information collected from the electric
generating industry [U.S. EPA, 2006d]. Some facilities that have FGD may commingle the waste stream with the
ash pond wastewater, making it difficult to identify these specific waste streams in PCS. FGD wastewaters are
currently regulated among the low-volume wastes generated at steam electric facilities [40 CFR 423.11 (b)].
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Chapter 3 - Steam Electric Industry Profile
Sorbent Slurry Makeup
FGD
Scrubber
Flue Gas
FGD Scrubber
Bl owdow n /SI udge
Figure 3-4. Flue Gas Desulfurization (FGD) System
During the 1982 rulemaking, EPA identified FGD wastes as a potential waste
stream for regulation. At the time, there were approximately 34 facilities that had FGD systems
and another 42 systems that were under construction [U.S. EPA, 1982]. From the data collected
for the rulemaking, EPA concluded that there were insufficient data to characterize the pollutant
loadings from FGD processes and that additional studies would be needed.
EPA subsequently obtained data from Form EIA-767, and identified 183 steam
electric plants that used a wet scrubber FGD system in the United States in 2002 [U.S. DOE,
2002b]. EPA estimates that the use of wet SO2 scrubbers will double by 2015 due to the CAIR
[U.S. EPA, 2006d].
Selective Catalytic Reduction
SCR is a technology used to control NOX emissions in the flue gas from the boiler.
In SCR, ammonia (NH3) is injected into the flue gas upstream of a catalyst, such as vanadium or
titanium. The NOX in the flue gas (comprising mainly nitrogen monoxide (NO) with lesser
amounts of nitrogen dioxide (NO2)) reacts with the NH3 in the presence of oxygen and the
catalyst to form nitrogen and water:
4NO + 4NH3 + O2 -> 4N2 + 6 H2O
2NO2 + 4NH3 + O2 -> 3N2 + 6H2O
(3-4)
(3-5)
In addition to these primary reactions, a fraction of the SO2 in the flue gas may be
oxidized to sulfur trioxide (SO3), and other side reactions may produce ammonium sulfate
((NH4)2SO4) and ammonium bisulfate (NH4HSO4) as by-products:
SO2 + Vi O2 -> SO3
2NH3 + SO3 + H2O -> (NH4)2SO4
NH3 + SO3 + H2O -> NH4HSO4
3-10
(3-6)
(3-7)
(3-8)
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Detailed Study Report - November 2006 Chapter 3 - Steam Electric Industry Profile
These by-products can foul and corrode downstream equipment. The extent to
which they are formed depends upon various factors within the process, including the sulfur
content of the coal used in the boiler and the amount of excess NHa in the system. Unreacted
NH3 present in the flue gas from the SCR is commonly termed ammonia slip [CCT, 1997].
Facilities may use different configurations based on the particular operations of
the system, including placing the SCR upstream of the air heater9 and other emission control
devices such as FGD and particulate controls (e.g., ESP). Although not directly associated with
SCR, there are waste streams impacted by this technology, specifically FGD wastewaters and air
heater wash water. As previously explained, unreacted NFL? (i.e., ammonia slip) and SOs by-
product creates (NFLt^SC^ and NFLjHSO/t, which can deposit in the air heater and must be
removed through periodic washes. Ammonia slip is also removed in ESP ash and in the FGD
slurry. Since NFL? is soluble, it will likely partition into the wastewater discharged from the
facility [Wright, 2003].
In addition to reducing the ammonia slip, installing an 863 removal system before
the air heater may further reduce the amount of (NFL^SO/t, and NH4HSO4 formed and deposited
in the air heater and, consequently, the amount of NFL? in the air heater wash water [Wright,
2003].
3.2.1.7 Wastewaters from Boiler Feedwater Treatment
Steam electric facilities treat boiler feedwater to prevent scale formation.
Suspended and dissolved solids are removed from the boiler feedwater using clarification,
filtration, ion exchange, reverse osmosis, evaporation, or softening.
Clarification agglomerates solids in a stream and separates them by settling.
Solids produced in the clarification process include sulfates, chlorides, and carbonates. Filtration
may be used alone or with another treatment process to remove suspended solids from the boiler
feedwater. Ion exchange is the most common method of treating boiler feedwater because it can
remove all mineral salts in one unit. The process uses a bed of electrically charged cationic or
anionic resin beads to attract chemical ions of the opposite charge. A solution is used to
backwash, or "regenerate," the bed. The waste solution from the regeneration process typically
does not contain significant amounts of suspended solids, but does contain sulfates and
carbonates that precipitate readily. The softening process uses lime and/or soda ash to
precipitate chemicals in the boiler feedwater: calcium precipitates as calcium carbonate, and
magnesium precipitates as magnesium hydroxide. The evaporation process purifies boiler
feedwater through vaporization and condensation. Evaporation wastes may be high in suspended
solids. In the reverse osmosis process, a semipermeable membrane, which is permeable to water
and impermeable to salt, separates two solutions of different salt concentrations. High pressure
(higher than osmotic pressure) is applied to one of the solutions, which causes fresh water to pass
through the membrane, and thus causes one solution to become more saline and the other to
become less saline [U.S. EPA, 1982].
9 The air preheater utilizes the heat contained in the flue gas to increase the temperature (via heat exchange) of the
air injected into the boiler for combustion.
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Detailed Study Report - November 2006 Chapter 3 - Steam Electric Industry Profile
3.2.1.8 Boiler Blowdown
In drum-type boilers, in which steam is in equilibrium with boiler water, boiler
water impurities are concentrated in the liquid phase. A small amount of water must be
discharged periodically from drum-type boilers to control the build-up of solids, both dissolved
and suspended. This discharge, which may be continuous or intermittent, is referred to as "boiler
blowdown."
The sources of impurities in boiler blowdown are the intake water, internal
corrosion of the boiler, and chemicals added to the boiler system. Impurities from the intake
water are typically soluble inorganic species (e.g., Na+, K+, Cl", and S(V2) and precipitates
containing calcium and magnesium cations. Boiler corrosion typically contributes soluble and
insoluble species of iron, copper, and other metals to the boiler water. Steam electric facilities
add various chemicals to the boiler feed water to control corrosion, scale formation, pH, and
solids deposition. These chemical additives may contribute chromium, copper, phenol,
phosphate, and other chemical species to the boiler water [U.S. EPA, 1982].
3.2.1.9 Other Low-Volume Wastewaters
In addition to wet scrubber air pollution control systems, boiler feedwater
treatment systems, and boiler blowdown, the definition of low-volume wastewater sources at 40
CFR 423.11 includes laboratory and sampling streams, floor drains, cooling tower basin cleaning
wastes, and recirculating house service water systems.
3.2.2 Combined Cycle System Process and Wastewater Sources
Some electricity generators use CCSs to produce electricity. A CCS is a
combination of one or more combustion/gas turbine electric generating units and one steam
turbine electric generating unit. Gas turbines, which are similar to jet engines, are typically
fueled with natural gas, but may also be fueled with clean oil, often during times of peak energy
demand.
In CCSs, gas turbines are connected to generators that produce electricity. Hot
exhaust gases (i.e., waste heat) from the gas turbines are transported to heat recovery steam
generators (HRSGs) to generate steam to drive an additional turbine. The steam turbine is
connected to a generator (which may be a different generator or the same generator that is
connected to a gas turbine) that produces additional electricity. Thus, CCSs use steam turbine
technology to increase the efficiency of the gas turbines. Figure 3-5 illustrates the CCS process.
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Chapter 3 - Steam Electric Industry Profile
Gas
Turbine
Cycle
Fuel (e.g., gas, oil, or
gasified coal)
Air-
Compressor
Combustion
Chamber
Gas
Turbine
I—Hot Exhaust Gases—3
Steam
Turbine
Cycle
Electric
Generator
-Exhaust Gases-
-Steam'
-Condensate'
Heat Recovery
Steam Generator
(HRSG)
Figure 3-5. Combined Cycle Process Flow Diagram
Some CCSs use a technology termed "gasification" to create gaseous fuel from
solid or liquid fossil fuels. Gasification creates synthesis gas (syngas), which consists mainly of
carbon monoxide and hydrogen gas from fossil fuels, such as vacuum residue, heavy oil,
petroleum coke, and coal, by a partial oxidation process [Chiyoda, 2006]. CCSs that use this
gasification technology are known as integrated gasification combined cycle (IGCC) systems. In
IGCC systems, syngas is purified and combusted in a gas turbine generator to produce
electricity. Heat from the exhaust gas is recovered and used to generate steam to produce
additional electricity. IGCC facilities are thermodynamically more efficient than traditional
steam electric facilities.
Currently, there are 20 to 25 gasification plants in operation around the world that
generate electricity and approximately 35 additional gasification facilities in various stages of
development, design, and construction. The total installed global capacity amounts to 24,000
MW of electricity with an annual growth rate of about 10 percent [U.S. DOE, 2006c]. IGCC is
less common in the United States than in other countries10; however, several U.S. facilities are
investigating IGCC and others have definite plans to build IGCC systems in the future.
The operation of steam electric units within CCSs is virtually identical to stand-
alone steam electric units, with the exception of the boiler. In a CCS, the gas turbines and
HRSGs functionally take the place of the boiler of a stand-alone steam electric unit. The other
There are currently two commercial-scale, coal-based IGCC facilities in the United States: the 262-MW Wabash
River IGCC Repowering Project in Indiana and the 250-MW Tampa Electric Polk Power Station IGCC Project in
Florida [U.S. EPA, 2006e].
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Detailed Study Report - November 2006 Chapter 3 - Steam Electric Industry Profile
two major components of steam electric units within CCSs, the steam turbine/electric generator
and steam condenser, are virtually identical to those of stand-alone steam electric units. Thus,
the wastewaters and pollutants generated from the steam/condensation side of the CCS process
are the same as those from the stand-alone steam electric process. These wastewaters include
cooling water and steam condensate water treatment wastes.
Wastewaters associated with the CCS steam water system (e.g., HRSG, steam
turbine, and condenser) are currently regulated by the Steam Electric ELGs [U.S. EPA, 1989].
EPA researched available information about CCS combustion/gas generating unit wastewaters to
determine whether the wastewaters generated by the gas generating unit of a CCS are similar to
the steam electric wastewaters already regulated by the Steam Electric ELGs.
According to comments received in 1996 from EPA regional and state authorities,
gas turbines may generate wastewaters from emissions control, equipment cooling, and
equipment turbine cleaning [U.S. EPA, 1996]. Gas turbines require clean-burning fuels, and
thus, CCS gas turbines do not discharge ash wastewaters. Although the amount of wastewaters
from the gas turbines is relatively low, they may contain similar pollutants and concentrations as
the regulated steam electric wastewaters. Wastewaters from IGCC facilities are also likely to
contain similar pollutants originating from the gasification process, upstream of the gas turbine.
Additionally, IGCC facilities may discharge wastewater associated with gasifier slag (coal ash)
[U.S. EPA, 2006e].
EPA has found no additional data to date that provide information about the
specific pollutants or concentrations likely to be found in CCS gas turbine wastewaters. The
wastewaters generated by gas turbines may warrant further consideration and study.
3.3 Demographics of the Electric Generating Industry
As previously explained in Section 2.0, EPA analyzed the available demographic
information for the year 2002 collected by the U.S. DOE and other government sources (e.g.,
TRI and PCS) to characterize the industry. This section presents available demographic data and
other information for the electric generating industry.
EPA obtained the demographic data presented in this section of the report
primarily from the PCSLoads2002 v.4 database [U.S. EPA, 2006a], the 2002 EIA database
(Form EIA-860) [U.S. DOE, 2002a], as well as the 2002 Economic Census [USCB, 2002].
Electric generating facilities that report to the PCS are identified within SIC codes 4911, 4931,
and 4939. Electric generating facilities are identified in the EIA data as typically reporting under
NAICS code 22 - Utilities11. The 2002 Economic Census data include more specific industry
sector information at the six-digit NAICS code level.
11 NAICS code 22 - Utilities is defined as establishments providing the following utility services: electric power,
natural gas, steam supply, water supply, and sewage removal. Excluded from this sector are establishments primarily
engaged in waste management services [USCB, 2002].
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Chapter 3 - Steam Electric Industry Profile
3.3.1
Overview of the Electric Generating Industry
According to the Economic Census, there were 2,138 electric generating facilities
in the United States in 2002, 61 percent of which are characterized primarily as using fossil or
nuclear fuel [USCB, 2002]. Table 3-1 presents the distribution of facilities among each of the
electric generating NAICS codes.
Table 3-1. Distribution of U.S. Electric Generating Facilities by NAICS Code
NAICS Code - Description
221111
221112
221113
221119
- Hydroelectric Power Generation
- Fossil Fuel Electric Power Generation
- Nuclear Electric Power Generation
- Other Electric Power Generation
22111 - Electric Power Generation (Total)
Facilities
416
1,233
78
411
2,138
Source: USCB, 2002.
EPA extracted TRI data reported in 2002 for all facilities within SIC codes 4911,
4931, and 4939. Of the 692 electric generating facilities that reported to TRI, only 376 (54
percent) reported manufacturing, processing, or using listed toxic chemicals at or above their
reporting thresholds, which resulted in wastewater discharges of that chemical [U.S. EPA,
2006b]. Table 3-2 shows the distribution of the TRI facilities by SIC code.
Table 3-2. Distribution of TRI Electric Generating Facilities by SIC Code
SIC
Code
4911
4931
4939
Total
Total
Facilities
Reporting
639
45
8
692
Facilities Reporting
No Discharge of
TRI Chemicals
to Water
289
20
7
316
Facilities Reporting
Direct Discharge of
TRI Chemicals
320
19
1
340
Facilities Reporting
Indirect Discharge
of TRI Chemicals
12
o
J
0
15
Facilities Reporting
Both Direct and
Indirect Discharge of
TRI Chemicals
18
3
0
21
Source: U.S. EPA, 2006b.
EPA also extracted all PCS data reported by major and minor sources within SIC
codes 4911, 4931, and 4939 for the study. In the PCS database, 885 electric generating facilities
reported wastewater data in 2002. Of the 885 facilities, 556 (63 percent) are major dischargers
and 329 are minor dischargers. Table 3-3 shows the distribution of the PCS facilities by SIC
code.
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Detailed Study Report - November 2006 Chapter 3 - Steam Electric Industry Profile
Table 3-3. Distribution of PCS Electric Generating Facilities by SIC Code
SIC Code - Description
4911 -Electric Services
493 1 - Electric and Other Services Combined
4939 - Combination Utilities, NEC
Total
Major Dischargers
547
9
0
556
Minor Dischargers
266
42
21
329
Total
813
51
21
885
Source: U.S. EPA, 2006a.
NEC - Not elsewhere classified.
The data reported to PCS and TRI were used in this study to characterize the
wastewater generated by the electricity generating industry, and are discussed in greater detail in
Chapter 5.
Combination utilities (SIC code 4939) by definition include facilities other than
electricity generating facilities; therefore, only a fraction of the few facilities reporting to PCS
and TRI as combination utilities are believed to be electricity generating facilities. As such, the
analyses of the PCS and TRI data presented in this report do not include combination utilities.
EPA investigated this industry classification during the study as a potential new subcategory for
the Steam Electric ELGs. Chapter 8 of this report discusses the Combination Utilities industry in
further detail.
Finally, EPA examined the data on electricity generating facility operations that
were reported to the EIA in 2002. Form EIA-860 contains records for 16,413 electricity
generators having at least one MW of capacity operated at 5,137 facilities for calendar year 2002
[U.S. DOE, 2002a]. These facilities include both electricity generating facilities and industrial
non-utilities.
Subsection 3.3.2 presents additional demographic data obtained through the 2002
EIA database specific to the regulated steam electric industry.
3.3.2
Regulated Steam Electric Generating Industry
Because Form EIA-860 contained the most detailed information on facility type,
energy source, and capacity, EPA used these data from EIA to develop a demographic profile of
the electric generating industry currently regulated by the Steam Electric ELGs. As mentioned in
the previous subsection, these records include data from all facilities that produce electricity, not
specifically steam electric facilities. EPA defined the subset of EIA data for the regulated steam
electric industry based on the NAICS code, prime mover, and energy source reported.
All electric generating facilities (i.e., utilities, non-industrial non-utilities, and
industrial non-utilities) report information about each of their generating units to the EIA in
Form EIA-860, and each facility identifies a "primary purpose" code for its operations that is
equivalent to their NAICS code. Utilities and non-industrial non-utilities report under the
general NAICS code 22, while industrial non-utilities report under the particular NAICS code for
their primary industry. Because both utilities and non-industrial non-utilities are regulated by the
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Detailed Study Report - November 2006 Chapter 3 - Steam Electric Industry Profile
Steam Electric ELGs, their EIA data are combined for the purposes of presenting the available
EIA data for the regulated steam electric industry.
EPA identified the subset of electric generating facilities in the EIA database that
are steam electric as those operating at least one prime mover that utilizes steam. The following
generating unit or prime mover types are included in the demographic data for the steam electric
industry presented in this report:
• Steam turbine;
• CCS - steam turbine portion; and
• CCS - single shaft (i.e., the combustion/gas turbine and steam turbine are
used together to drive a single generator).
For the purposes of this report, EPA combined the data reported for the two types
ofCCSsinEIA.
Finally, EPA identified the subset of steam electric facilities that are currently
regulated by the Steam Electric ELGs that report using a fossil or nuclear fuel as the primary
energy source for the steam electric generating unit. The following fossil or nuclear fuel types
are included in the demographic data for the regulated steam electric industry presented in this
section of the report (abbreviations used by EIA are presented in parentheses):
• Anthracite coal, bituminous coal;
• Lignite coal;
• Subbituminous coal;
• Petroleum coke;
• Waste/other coal;
• Distillate fuel oil;
• Residual fuel oil;
• Jet fuel;
• Kerosene;
• Oil-other and waste oil (e.g., crude oil, liquid by-products, oil waste,
propane (liquid), re-refined motor oil, sludge oil, tar oil);
• Natural gas; and
• Nuclear (e.g., uranium, plutonium, thorium).
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Chapter 3 - Steam Electric Industry Profile
Using the criteria for the prime mover type and energy source described above for
all facilities (utilities and non-industrial non-utilities) reporting a primary purpose/NAICS code
of 22, EPA estimates that 1,157 regulated steam electric facilities reported to the EIA in 2002.
These facilities are estimated to operate 2,597 stand-alone steam generators or combined cycle
systems, which have a total steam turbine capacity of 621,799 MW12 [U.S. DOE, 2002a].
Table 3-4 shows the distribution of the types of steam electric prime movers used
by facilities subject to the Steam Electric ELGs. The table presents the numbers of facilities,
generating units, and capacities for each type of steam electric prime mover. Based on the 2002
EIA data, virtually all (93 percent) of the steam-generated electricity produced by the regulated
industry is done so through stand-alone steam turbines, which are also the most prevalent type of
steam electric prime mover used.
Table 3-4. Distribution of Prime Mover Types Within the Regulated Steam Electric
Industry
Steam Electric Prime Mover
Stand- Alone Steam Turbine
CCS Steam Turbine
Total
Number of
Facilities"
891
(77%)
303
(26%)
1,157
(100%)
Number of
Generating Units
2,210
(85%)
387
(15%)
2,597
(100%)
Total Steam
Turbine Capacity
(MW)
578,282
(93%)
43,517
(7%)
621,799
(100%)
Source: U.S. DOE, 2002a.
aBecause a single facility may operate multiple generating units of various types, the number of facilities by prime
mover type is not additive. There are 1,157 facilities in the industry that operate at least one steam electric
generating unit powered by either fossil or nuclear fuel.
In the 2002 EIA database, an estimated 303 regulated steam electric facilities
reported operating at least one fossil-fueled CCS. The total CCS capacity is estimated to be
112,451 MW, 39 percent of which is generated via steam-turned generators (i.e., both the steam
portion of multishaft CCSs and single-shaft CCSs). Approximately 43,500 MW of capacity is
produced via steam-driven CCS generators, which accounts for seven percent of the electricity
produced by the regulated steam electric industry [U.S. DOE, 2002a].
Table 3-5 shows the distribution of fossil and nuclear fuels used in the regulated
steam electric industry. Table 3-6 shows the distribution of fossil and nuclear fuels to power
each type of steam electric prime mover. The 2002 EIA data demonstrate that more than half of
the steam-generated electricity currently produced by the regulated steam electric industry is
primarily fueled by coal used in stand-alone steam turbines.
The EIA database contains 1,152 facilities reporting a total of 2,592 steam electric units, and an additional 5
facilities reporting at least one CCS combustion/gas turbine only. EPA assumes these additional five facilities are
each operating a single steam turbine as part of their CCS, even though it was not reported to EIA. The total steam
turbine capacity does not include the unknown capacities for the five CCS steam electric turbines that are assumed
in the total number of facilities and generating units.
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Chapter 3 - Steam Electric Industry Profile
Table 3-5. Distribution of Fuel Types Within the Regulated Steam Electric Industry
Fossil or Nuclear Fuela
Coal:
Anthracite Coal, Bituminous Coal
Subbituminous Coal
Lignite Coal
Waste/Other Coal
Petroleum Coke
Oil:
Residual Fuel Oil
Distillate Fuel Oil
Natural Gas
Nuclear
Total
Number of
Facilities1"
513
(44%)
360
126
18
17
12
(1.0%)
90
(7.8%)
74
17
548
(47%)
66
(5.7%)
1,157
(100%)
Number of
Generating Units
1,255
(48%)
935
273
30
17
14
(0.5%)
190
(7.3%)
163
27
1,029
(40%)
104
(4.0%)
2,597
(100%)
Total Steam
Turbine Capacity
(MW)C
332,923
(54%)
229,465
87,364
14,753
1,341
824
(0.1%)
34,532
(5.6%)
32,443
2,089
148,586
(24%)
104,933
(17%)
621,799
(100%)
Source: U.S. DOE, 2002a.
aNo steam electric generating units were reported to use jet fuel, kerosene, or waste/other oil in the 2002 EIA
database.
bBecause a single facility may operate multiple generating units utilizing differing fuel types, the number of facilities
by fuel type is not additive. There are 1,157 facilities in the industry that operate at least one steam electric
generating unit powered by either fossil or nuclear fuel.
°The total steam electric capacity shown does not equal the sum of the steam electric capacities for each fuel type
due to rounding errors.
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Detailed Study Report - November 2006 Chapter 3 - Steam Electric Industry Profile
Table 3-6. Distribution of Fuel Types Used by Steam Electric Generating Units
Fossil or Nuclear Fuel"
Coal:
Anthracite Coal, Bituminous
Coal
Subbituminous Coal
Lignite Coal
Waste/Other Coal
Petroleum Coke
Oil:
Residual Fuel Oil
Distillate Fuel Oil
Natural Gas
Nuclear
Total
Number of Generating Units
Stand-Alone Steam
Turbines
1,254
(57%)
934
273
30
17
14
(0.6%)
180
(8.1%)
157
23
658
(30%)
104
(4.7%)
2,210
(100%)
CCS Steam Turbinesb
1
(0.26%)
1
0
0
0
0
(0%)
10
(2.5%)
6
4
371
(96%)
0
(0%)
387b
(100%)
Total
1,255
(48%)
935
273
30
17
14
(0.5%)
190
(7.3%)
163
27
1,029
(40%)
104
(4.0%)
2,597
(100%)
Source: U.S. DOE, 2002a.
aNo steam electric generating units were reported to use jet fuel, kerosene, or waste/other oil in the 2002 EIA
database.
bThe database contains a total of 382 CCS steam turbines, with an additional five facilities reporting at least one
CCS gas turbine only. EPA assumes there is an additional five CCS steam turbines in operation, even though they
were not reported to EIA. The numbers of CCS steam turbines shown for each fuel type do not account for these
five units that are assumed in the total.
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Chapter 3 - Steam Electric Industry Profile
The second most prevalent fuel used by the regulated steam electric industry is
natural gas, which is used to produce nearly 25 percent of the steam-generated electricity from
this segment of the industry. According to the 2002 EIA data, 30 percent of stand-alone steam
turbines are powered by natural gas. Nearly all CCSs (96 percent) are fueled by natural gas;
however, a small number were also reported to be fueled by oil. The facility that reported coal
for its CCS is PSI Energy's Wabash River Plant, which is one of two known IGCC units
operating in the United States. Therefore, it should be noted that this "coal-fired" CCS is
actually powered by syngas provided through coal gasification [U.S. DOE, 2002a]. Section
3.2.2 contains additional information about IGCC systems.
Table 3-7 presents the steam electric capacity, as well as the number of regulated
steam electric facilities and generating units, distributed by overall plant capacity13. According
to these 2002 EIA data, the majority of steam electric facilities and generating units, as well as
the majority of the electricity provided by the regulated steam electric industry, is from the
largest capacity facilities (>500 MW).
Table 3-7. Distribution of Regulated Steam Electric Capacity, Facilities, and Generating
Units by Size
Overall Plant
Capacity"
Total Steam
Electric Capacity
(MW)
Percentage of
Capacity
Number of
Facilities
Percentage of
Facilities
Number of Steam
Electric
Generating Units
Percentage of
Steam Electric
Generating Units
0-50
MW
2,966
0.48%
133
11%
222
8.5%
50-100
MW
6,621
1.1%
128
11%
225
8.7%
100-200
MW
16,592
2.7%
159
14%
297
11%
200-300
MW
17,106
2.8%
92
8.0%
183
7.0%
300-400
MW
17,365
2.8%
66
5.7%
146
5.6%
400-500
MW
22,812
3.7%
63
5.4%
150
5.8%
>500
MW
538,337
87%
511
44%
1,369
53%
Total
621,799b
100%
1,157C
100%
2,597C
100%
Source: U.S. DOE, 2002a.
aPlant capacity includes electricity produced by both steam and non-steam generating units, as well as through the
use of non-fossil/non-nuclear energy sources.
bThe total steam electric capacity shown does not equal the sum of the steam electric capacities for each size
category due to rounding errors.
°It is estimated that there are a total of 1,157 facilities in the 2002 EIA database that operate 2,597 steam electric
generating units. The database contained 1,152 facilities reporting a total of 2,592 steam electric units, and an
additional five facilities reporting at least one CCS gas turbine only. EPA assumes these additional five facilities are
each operating a single steam turbine as part of their CCS, even though it was not reported to EIA. The number of
facilities and generating units shown for plant capacity range do not account for these five CCS steam electric
turbines that are assumed in the totals.
The overall plant capacity includes all electric power generated by the facility, including electricity produced by
non-steam generators and through the use of non-fossil/non-nuclear energy sources.
3-21
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Detailed Study Report - November 2006
Chapter 3 - Steam Electric Industry Profile
In general, electricity produced by coal-fired steam electric generating units
increased rapidly in the 1970s, but has since leveled off. Increases in the regulated industry's
capacity in recent years coincide with increases in natural gas-fired electricity generating units,
according to the 2002 EIA database [U.S. EPA, 2005b].
Nearly 83 percent of the regulated steam electric facilities that reported operation
of a CCS indicated the system was constructed or started up as early as 1982, the year the Steam
Electric ELGs were last revised [U.S. DOE, 2002a]. According to the 2002 EIA data and as
shown in Figure 3-6, an increasing number of regulated steam electric facilities have installed
(i.e., started up) a new CCS since roughly 198514.
W
4*
3
|
4*
£>
•o
J§
OX)
P§
o
A
s
s
50
45
§40
.335
W)
.330
I25
a! 20
:115
lio
5
0
CCS Start-Up Year
Figure 3-6. Trend Toward Increased Operation of CCSs Within the Regulated Steam
Electric Industry
Source: U.S. DOE, 2002a
Note that the number of facilities shown for each year is not cumulative. They represent the number of facilities
that reported operation of a CCS that was initially started up within that year. In addition, these data reflect CCSs
that were in operation in 2002. They do not include CCSs that may have existed in previous years, but were shut
down or otherwise not in operation as of 2002.
3-22
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Detailed Study Report - November 2006 Chapter 4 - Selected Environmental Regulations
4.0 SELECTED ENVIRONMENTAL REGULATIONS AFFECTING THE STEAM ELECTRIC
INDUSTRY
This chapter presents a brief overview of selected regulations affecting steam
electric facilities.
4.1 Effluent Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category (40 CFR 423)
The Federal Water Pollution Control Act of 1972 established a structure for
regulating discharges of pollutants to surface waters of the United States. As part of the
implementation of the Act, EPA issued ELGs for industrial dischargers. EPA issued the first
ELGs for the Steam Electric Power Generating Point Source Category (i.e., the Steam Electric
ELGs) in 1974 with subsequent revisions in 1977 and 1982. The Steam Electric ELGs are
codified at 40 CFR 423 and include limitations for the following waste streams:
• Once-through cooling water;
• Cooling tower blowdown;
• Fly ash transport water;
• Bottom ash transport water;
• Metal cleaning wastes;
• Coal pile runoff; and
• Low-volume waste sources, including but not limited to wastewaters from
wet scrubber air pollution control systems, ion exchange water treatment
systems, water treatment evaporator blowdown, laboratory and sampling
streams, boiler blowdown, floor drains, cooling tower basin cleaning
wastes, and recirculating house service water systems (sanitary and air
conditioning wastes are not included) [40 CFR 323.1 l(b)].
The 1982 promulgation reserved the following four types of waste streams for
future rulemaking:
• Non-chemical metal cleaning wastes;
• FGD wastewater (Note: this wastewater source is covered by the current
ELGs among low-volume waste sources);
• Runoff from materials storage and construction areas (other than coal
storage); and
• Thermal discharges.
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Detailed Study Report - November 2006 Chapter 4 - Selected Environmental Regulations
The current ELGs are summarized in Table 4-1 and are applicable to:
"... discharges resulting from the operation of a generating unit by an
establishment primarily engaged in the generation of electricity for distribution
and sale which results primarily from a process utilizing fossil-type fuel (coal, oil,
or gas) or nuclear fuel in conjunction with a thermal cycle employing the steam
water system as the thermodynamic medium." (§423.10)
Currently, 40 CFR Part 423 does not apply to facilities that primarily use a
renewable fuel source (e.g., wood waste, municipal solid waste) to power the steam electric
generators or fossil- or nuclear-powered steam electric generating facilities that do not sell a
majority of the electricity produced.
4.2 Clean Water Act Section 316(b) - Cooling Water Intake Structures
Section 316(b) of the CWA requires EPA to ensure that the location, design,
construction, and capacity of cooling water intake structures reflect the best technology available
to minimize adverse environmental impacts. Such impacts include death or injury to aquatic
organisms by impingement (being pinned against screens or other parts of a cooling water intake
structure) or entrainment (being drawn into cooling water systems and subjected to thermal,
physical, or chemical stresses). The CWA section 316(b) regulations were developed in three
phases:
• Phase I, promulgated on December 18, 2001 [66 FR 65256], covers new
facilities that use cooling water intake structures to withdraw water from
waters of the United States and that have or require a NPDES permit.
New facilities subject to the Phase I regulations include those that have a
design intake flow of greater than 2 MGD and that use at least 25 percent
of the water withdrawn for cooling purposes.
• Phase II, promulgated on July 9, 2004 [69 FR 41576], establishes
performance standards and other requirements for cooling water intake
structures at large existing electric generating plants that use at least 50
MGD of water from waters of the United States.
Phase III, promulgated on June 16, 2006 [71 FR 35006], establishes
requirements for intake structures at new offshore and coastal oil and gas
extraction facilities that have a design intake flow of greater than 2 MGD
and that use at least 25 percent of the water withdrawn for cooling
purposes.
Manufacturing facilities, existing electric generating facilities with a design intake
flow of less than 50 MGD, and existing offshore oil and gas extraction facilities are not subject
to section 316(b) national categorical requirements. CWA section 316(b) requirements for
existing facilities not covered under the Phase II rule are implemented through NPDES permits
on a case-by-case, best professional judgment (BPJ) basis [U.S. EPA, 2006f].
4-2
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Detailed Study Report - November 2006
Chapter 4 - Selected Environmental Regulations
Table 4-1. Current Effluent Guidelines and Standards for the Steam Electric Power
Generating Point Source Category
Waste Stream
All Waste Streams
Low-Volume
Wastes
Fly Ash Transport
Bottom Ash
Transport
Metal Cleaning
Wastes
Chemical
Non-chemical
Once-Through
Cooling
Cooling Tower
Blowdown
Coal Pile Runoff
BPTa
pH: 6-9b
PCBs: Zero
discharge
TSS: 100/30
O&G: 20/15
TSS: 100/30
O&G: 20/15
TSS: 100/30
O&G: 20/15
TSS: 100/30
O&G: 20/15
Cu: 1.0/1.0
Fe: 1.0/1.0
See Metal Cleaning
Wastes above
See Metal Cleaning
Wastes above
FAC: 0.5/0.2
FAC: 0.5/0.2
TSS*: 50
BATa
PCBs: Zero
discharge
No limitation0
No limitation0
No limitation0
See Chemical Metal
Cleaning Wastes
below
Cu: 1.0/1.0
Fe: 1.0/1.0
[3]
Reserved
TRC: 0.20 max or
BPTif<25MW
FAC: 0.5/0.2
126P: Zero
discharge, except:
Cr: 0.2/0.2
Zn: 1.0/1.0
No limitation0
NSPSa
pH: 6-9b
PCBs: Zero
discharge
TSS: 100/30
O&G: 20/15
Zero discharge
TSS: 100/30
O&G: 20/15
See Chemical Metal
Cleaning Wastes
below
TSS: 100/30
O&G: 20/15
Cu: 1.0/1.0
Fe: 1.0/1.0
Reserved
TRC: 0.20 max or
BPTif<25MW
FAC: 0.5/0.2
126P: Zero
discharge, except:
Cr: 0.2/0.2
Zn: 1.0/1.0
TSS*: 50
PSESandPSNS3
PCBs: Zero
discharge
No limitation"1
Zero discharge
(PSNS only)
No limitation for
PSESd
No limitation"1
See Chemical Metal
Cleaning Wastes
below
Cu: 1.0
[4]
Reserved
No limitation6
126P: Zero
discharge, except:
Cr: 0.2/0.2
Zn: 1.0/1.0
No limitation"1
Sources: 40 CFR 423; 47 FR 52290 - 52309.
Refer to the Acronyms List, provided on page vii of this report. Additional notes are provided below.
FAC: 0.5/0.2 - 0.5 mg/L instantaneous maximum, 0.2 mg/L average during chlorine release period. Discharge is
limited to 2 hrs/day/unit. Simultaneous discharge of chlorine from multiple units is prohibited. Limitations are
applicable at the discharge from an individual unit prior to combination with the discharge from another unit.
TRC: 0.20 max - 0.20 mg/L instantaneous maximum. TRC = FAC + CRC. TRC discharge is limited to 2
hrs/day/unit. TRC is applicable to plants > 25 MW, and FAC is applicable to plants < 25 MW. The TRC limitation
is applicable at the discharge point to surface waters of the United States and may be subsequent to combination
with the discharge from another unit.
126P: zero discharge -126 priority pollutants from added maintenance chemicals (refer to App. A to 40 CFR 423).
At the permitting authority's discretion, compliance with the zero-discharge limitations for the 126 priority
pollutants may be determined by engineering calculations, which demonstrate that the regulated pollutants are not
detectable in the final discharge by the analytical methods in 40 CFR part 136.
TSS*: 50 - 50 mg/L instantaneous maximum on coal pile runoff streams. No limitation on TSS for coal pile runoff
flows > 10-year, 24-hour rainfall event.
aThe limitations for TSS, O&G, Cu, Fe, Cr, and Zn are presented as daily maximum (mg/L)/30-day average (mg/L).
For all ELGs, where two or more waste streams are combined, the total pollutant discharge quantity may not exceed
the sum of allowable pollutant quantities for each individual waste stream. BPT, BAT, and NSPS allow either mass-
or concentration-based limitations.
bThe pH limitation is not applicable to once-through cooling water.
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Detailed Study Report - November 2006 Chapter 4 - Selected Environmental Regulations
Table 4-1 (Continued)
°BAT limitations for the conventional pollutants, TSS and O&G, were withdrawn from the CFR (in the 1982
promulgation) because these pollutants are covered under BCT. In the 1982 promulgation, EPA reserved BCT for
the steam electric industry. Refer to 47 FR 52293.
dln the 1982 promulgation, EPA withdrew the 1977 PSES requirement for O&G for all waste streams (47 FR
52293).
eThere are no pretreatment standards (except the PCB prohibition) because no known facilities discharge once-
through cooling water to POTWs [47 FR 52294].
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Detailed Study Report - November 2006 Chapter 4 - Selected Environmental Regulations
4.3 Clean Air Act
Electric utility generating units that fire fossil fuels are subject to several
regulations under the Clean Air Act (CAA). These regulations include CAIR, CAMR, Clean Air
Visibility Rule (CAVR), Acid Rain Program, NSPS, and National Emissions Standards for
Hazardous Air Pollutants (NESHAP). Each of these regulations is summarized briefly below:
• CAIR. Published in 2005, CAIR will regulate SO2 and NOX emissions to
help states achieve the National Ambient Air Quality Standards (NAAQS)
for ozone and fine particulate matter. The rule permanently caps emissions
(tons per year) across 28 eastern states and the District of Columbia. The
Phase I Caps for NOX and SO2 will take effect in 2009 and 2010,
respectively. The lower Phase II caps for both SO2 and NOX take effect in
2015. States must meet the caps by establishing emission limitations or
participating in a regional cap and trade program. EPA anticipates that
states will achieve these standards by primarily focusing on reducing the
emissions from the power generating industry.
• CAMR. Published in 2005, this rule established a national cap and trade
program for mercury emissions from power plants. Plants will be able to
meet the first phase cap in 2010 using the same technologies currently
used to control SO2 and NOX in complying with CAIR. The second phase
cap in 2018 is expected to require facilities to use mercury-specific control
technologies to comply.
• CAVR. On June 15, 2005, EPA finalized amendments to the July 1999
regional haze rule. These amendments apply to the provisions of the
regional haze rule that require emission controls known as "best available
retrofit technology" (BART) for industrial facilities emitting air pollutants
that reduce visibility by causing or contributing to regional haze. The
pollutants that reduce visibility include fine particulate matter and
compounds that contribute to its formation, including SO2 and others. The
amendments include final guidelines, known as BART guidelines, for
states to use in determining which facilities must install controls and the
type of controls the facilities must use. States that adopt the CAIR cap
and trade program for SO2 and NOX are allowed to apply CAIR controls as
a substitute for controls required under BART because the analysis
concluded that CAIR controls are "better than BART" for electric
generating units in the states subject to CAIR.
• Acid Rain. The acid rain program established a national cap and trade
program for SO2 emissions from fossil fuel-fired power plants. Phase I
began in 1995 and affected 445 mostly coal-fired electric utility plants
located in 21 eastern and midwestern states. Phase II, which began in the
year 2000, lowered the emission caps on the Phase I plants and also
capped emissions on all units nationwide with more than 25 MW of
capacity and fired by coal, oil, or gas. The program also established
emission limitations for NOX.
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Detailed Study Report - November 2006 Chapter 4 - Selected Environmental Regulations
• NSPS. These regulations established limitations on 862, particulate
matter, NOX, and mercury emitted from new, modified, or reconstructed
electric utility boilers. EPA proposed amendments to the SC>2, particulate
matter and NOX NSPS in February 2005 [70 FR 9706] and adopted the
final amendments in February 2006 [71 FR 9866]. EPA finalized the
mercury NSPS in May 2005 [70 FR 28606] and issued the final notice of
reconsideration (which amended the NSPS) on June 9, 2006 [71 FR
33388].
The SC>2 standard for units burning high-sulfur coals requires
approximately a 95-percent reduction of emissions, which requires FGD.
Units burning low-sulfur coals can achieve the standard with
approximately 80 percent reduction, which can be met using a spray dryer.
Spray dryers do not generate a wastewater stream. The NOX emission
limitations require the use of SCR or selective non-catalytic reduction
(SNCR). The particulate matter NSPS can be met using an electrostatic
precipitator (ESP) or baghouse.
EPA established separate NSPS limits for mercury for four ranks of coal
(bituminous, subbituminous, lignite, and coal refuse) and one process
(IGCC). Facilities can meet the mercury NSPS emission limitations using
the same technologies used to meet the SC>2 and NOX NSPS emission
limitations.
• NESHAP. This regulation regulates hazardous air pollutant emissions
from the following: industrial, commercial, and institutional boilers and
process heaters [70 FR 76918; December 28, 2005], as well as combustion
turbines and reciprocating internal combustion engines (RICEs).
4.4 Resource Conservation and Recovery Act
The management of CCRs (e.g., fly ash, bottom ash, boiler ash, boiler slag, and
flue gas emission control wastes) is subject to regulations under the Resource Conservation and
Recovery Act (RCRA). In 1993, EPA completed a hazard study of CCR waste disposal and
recommended that CCRs be regulated at the state level as RCRA Subtitle D wastes. The 1993
action also affirmed that CCRs should be excluded from RCRA Subtitle C hazardous waste
regulations [58 FR 42466; August 9, 1993]. Again in 2000, EPA completed a follow-up study of
low-volume, comanaged wastes15 and issued a regulatory determination that these wastes be
exempted from Subtitle C regulations [65 FR 32214; May 22, 2000]. No federal regulations
currently exist for solid wastes from steam electric facilities; instead, they are managed by state
solid waste programs or specific programs for fossil fuel combustion wastes [U.S. EPA, 2006c].
At that time, however, concerns were raised over the disposal of CCRs in surface
impoundments and landfills as well as the use of CCR as backfill in mining operations. EPA's
OSW is currently developing federal regulations under RCRA Subtitle D to address issues
15 Comanaged wastes are low-volume wastes that are comanaged with the high-volume CCRs [U.S. EPA, 2006c].
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Detailed Study Report - November 2006 Chapter 4 - Selected Environmental Regulations
related to disposal to surface impoundments and landfills, which include the potential for
pollutants to be transferred from the solid wastes to ground or surface waters. For coal mining
operations, OSW is working with the U.S. Department of Interior's Office of Surface Mining to
address these issues under the Subsurface Mining Control and Reclamation Act (SMCRA).
In addition, increased use of air pollution control technologies to meet new
emission requirements (described previously in this chapter) may impact the pollutants found in
CCRs. OSW is working with ORD and EPA's National Risk Management Research Laboratory
(NRMRL) to evaluate the impact of air pollution control on the characteristics of CCRs,
including understanding the potential environmental impacts from the disposal and beneficial use
of CCRs. The outcome of this research will help to identify potential management practices of
concern where cross-media transfers may occur. In addition, it will provide methodology and
data for quantifying potential benefits and environmental tradeoffs from CCR utilization [U.S.
EPA, 2006c].
With respect to the use of CCRs as backfill in mines, EPA commissioned a study
of the risks by the NRC. The NRC has issued a report presenting the results of this study [NRC,
2006] (additional information about this report is presented in Section 2.4.4).
4-7
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Detailed Study Report - November 2006 Chapter 5 - Wastewater Characterization
5.0 STEAM ELECTRIC INDUSTRY WASTEWATER CHARACTERIZATION
This chapter analyzes available data to characterize the waste streams discharged
from steam electric facilities and the technologies and practices used in the industry to control
the discharge of wastewater pollutants. Table 5-1 presents an overview of the types of pollutants
associated with the various waste streams, based on data previously collected by EPA during the
1974 and 1982 rulemaking efforts and the 1996 Preliminary Data Summary, data provided by
UWAG and EPRI, and currently available pollutant data from TRI, PCS, and literature. Section
3.2.1 of this report describes waste streams from this industry.
Table 5-1. Waste Streams from the Steam Electric Industry and Pollutants Typically
Associated with the Discharge
Process Waste Stream
Cooling Water: Once-
Through or Cooling Tower
Blowdown
Ash Handling: Bottom or
Fly Ash
Coal Pile Runoff
Water Treatment
Boiler Blowdown
Flue Gas Desulfurization
Waste from Wet Scrubbers
Maintenance Cleaning
Other Low-Volume Waste
Streams
Pollutants
Chlorine, iron, copper, nickel, aluminum, boron, chlorinated organic compounds,
suspended solids, brominated compounds, non-oxidizing biocides
TDS, TSS, sulfate, calcium, chloride, magnesium, nitrate, aluminum, antimony,
arsenic, boron, cadmium, chromium, copper, cyanide, iron, lead, mercury, nickel,
selenium, silver, titanium, thallium, vanadium, zinc, various metal oxides, carbon
residuals
Acidity, COD, calcium, silica, chloride, sulfate, TDS, TSS, aluminum, antimony,
arsenic, boron, beryllium, cadmium, chromium, copper, iron, lead, magnesium,
manganese, mercury, nickel, selenium, silver, thallium, vanadium, zinc
Clarification: aluminum sulfate, sodium aluminate, ferrous sulfate, ferrous
chloride, calcium carbonate
Filtration: suspended solids
Ion Exchange: calcium and magnesium salts, iron, copper, zinc, aluminum,
manganese, potassium, soluble sodium, chlorides, sulfates, organics, sulfuric acid,
sodium hydroxide
Evaporation: salts (type depends on intake water characteristics)
Softening: calcium carbonate, magnesium hydroxide, sodium salts
Chlorides, sulfates, metals, precipitated solids containing calcium and magnesium
salts, soluble and insoluble corrosion products, chemical additives
A slurry of ash, unreacted lime, calcium sulfate/gypsum, calcium sulfite, TDS, TSS,
and remaining trace constituents of coal (including, but not limited to aluminum,
arsenic, boron, copper, iron, mercury, nickel, selenium, and zinc)
Oil, grease, phosphates, nitrites, suspended solids, dissolved solids, iron, nickel,
chromium, vanadium, zinc, magnesium salts, polynuclear hydrocarbons, acidity,
alkalinity, oil
Suspended solids, dissolved solids, oil and grease, phosphates, surfactants, acidity,
methylene chloride, phthalates, BOD5, COD, fecal coliform, and nitrates
Note: this table is intended to present the types of pollutants that are commonly expected to be found in various
steam electric process waste streams, as supported by the sources reviewed during this study. It is presented here for
informational purposes and does not necessarily provide a complete characterization of the waste streams.
Refer to the Acronyms List, provided on page vii of this report.
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Detailed Study Report - November 2006 Chapter 5 - Wastewater Characterization
5.1 Identification of the PCS and TRI Steam Electric Data
The primary data sources used in these analyses are described in Chapter 2 of this
report. This section presents additional information on the criteria used in identifying the subset
of data from the 2002 PCS and TRI databases that represent the regulated steam electric industry.
As described in Section 3.1, the regulated steam electric industry is defined by the
current ELGs for the Steam Electric Power Generating Point Source Category at 40 CFR 423.10
as facilities "primarily engaged in the generation of electricity for distribution and sale which
results primarily from a process utilizing fossil-type fuel (coal, oil, or gas) or nuclear fuel in
conjunction with a thermal cycle employing the steam/water system as the thermodynamic
medium."
In the PCS and TRI databases, facilities are categorized by SIC codes. The
electric generating industry comprises the following three SIC codes:
• 4911 -Electric services;
• 4931 - Electric and other services combined; and
• 4939 - Combination utilities, not elsewhere classified.
As explained in Section 3.3.1 of this report, facilities that were categorized as
combination utilities within SIC code 4939 were excluded from the analyses presented for the
regulated steam electric industry. This industry classification was instead investigated as a
potential new subcategory for the current Steam Electric ELGs. The combination utilities
industry is further discussed in Chapter 8 of this report.
While facilities categorized within SIC codes 4911 and 4931 are primarily
engaged in the generation of electricity, they are not necessarily regulated steam electric
facilities for the following two reasons:
1. The facility may not use fossil or nuclear fuels; and/or
2. The facility may not use a steam/water system as the thermodynamic
medium16.
EPA linked the PCS database to the EIA database to determine how well SIC
codes 4911 and 4931 represent the regulated steam electric industry17. By linking the facility
records contained in these databases, EPA was able to associate the PCS wastewater discharge
information with the EIA design and operation data. There are 864 electric generating facilities
within SIC codes 4911 and 4931 that reported discharges in the 2002 PCS database [U.S. EPA,
2006a] and 1,157 regulated steam electric facilities in the EIA database [U.S. DOE, 2002a]18.
EPA was not able to link all 864 PCS electric generating facilities to the EIA data due to
insufficient information contained in one or more databases. Of the 864 PCS electric generating
16 Refer to the electric generating industry subgroup definitions, provided in Section 3.0 of this report.
17 For more details on how EPA linked the PCS and TRI databases to the EIA database, see the Preliminary
Engineering Report: Steam Electric Detailed Study [U.S. EPA, 2005b].
18 For more details on how EPA estimated the number of regulated steam electric facilities from the EIA database,
see Section 3.3.2.
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Detailed Study Report - November 2006
Chapter 5 - Wastewater Characterization
facilities, EPA identified 588 in the 2002 EIA data. All but four of these facilities are believed to
be regulated steam electric facilities, based on their available EIA data.
To determine how well the available PCS data for electric generating facilities
within SIC codes 4911 and 4931 represent the regulated steam electric industry, EPA compared
the amount discharged by the 864 electric generating facilities to the amount discharged by the
584 facilities believed to be within the regulated steam electric industry. The discharge amounts
are presented as TWPEs19. This comparison is presented in Table 5-2.
Table 5-2. Comparison of PCS Discharge Data for All Electric Generating Facilities
vs. Regulated Steam Electric Facilities
Type of
Discharger
Major
Minor
Total
All
Electric Generating Facilities"
Number of
Facilities
556
308
864
Pollutant Load
(TWPE)
979,632
77,499
1,057,131
Regulated
Steam Electric Facilities'1
Number of
Facilities
490
94
584
Pollutant Load
(TWPE)
917,221
49,694
966,915
Percentage of
Total Load
Represented by
Regulated
Steam Electric
Facilities
94%
64%
91%
Sources: U.S. EPA, 2006a and U.S. DOE, 2002a.
Includes all facilities that reported to PCS within SIC codes 4911 and 4931.
blncludes the subset of PCS electric generating facilities that are believed to be regulated steam electric facilities
(based on available EIA data).
Although, only 584 out of the 864 PCS electric generating facilities are believed
to be regulated steam electric facilities (i.e., 86 percent), their discharges account for
approximately 91 percent of the total discharged by all electric generating facilities.
EPA used this comparison to validate using the PCS discharge data from all
electric generating facilities to represent the regulated steam electric industry in these analyses.
The linkage between the PCS and EIA databases demonstrates that the majority of the electric
generating industry reporting discharges to PCS are regulated steam electric facilities (at least 68
percent overall), and that most of the reported pollutant loads (91 percent overall) are attributable
to these regulated steam electric facilities.
While 276 of the 864 PCS electric generating facilities are not known to be
regulated steam electric facilities, the discharges from non-steam-electric facilities are likely to
be minimal, consisting of metal cleaning and other low-volume wastes. Therefore, including
these facilities should not grossly impact the PCS pollutant loadings analyses for the regulated
steam electric industry.
To compute a TWPE for each parameter reported, the estimated mass (in pounds) of the chemical discharged is
multiplied by its TWF. Additional information on the calculation of TWPE and the PCS loading calculations can be
found in the 2005 Screening-Level Analysis Report [U.S. EPA, 2005a].
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Detailed Study Report - November 2006 Chapter 5 - Wastewater Characterization
5.2 Annual Pollutant Loadings
During the preliminary review of the steam electric industry, EPA identified the
pollutants reported to be discharged by steam electric facilities, and created a preliminary
ranking of these pollutants by discharge load and TWPE. Since the publication of the
Preliminary Engineering Report: Steam Electric Detailed Study20', EPA revised the pollutant
rankings by incorporating the following changes:
• Updating facility-specific data, based on public comments to the 2006
Preliminary Plan [70 FR 51042; August 29, 2005], including correcting
certain loading calculations to better account for batch discharges and
intake pollutants (completed on a site-specific basis);
• Revising the average number of days used to estimate biocide discharges,
based on UWAG survey data [UWAG, 2005a];
• Including data from minor dischargers in the calculation of pollutant
loadings; and
• Deleting chlorine releases and transfers reported in the TRI database from
the calculation of pollutant loadings.
EPA examined wastewater data reported to PCS and TRI in evaluating the annual
pollutant loadings from the steam electric industry. Section 5.2.1 discusses the TRI data and
5.2.2 discusses the PCS data.
5.2.1 TRI Wastewater Releases and Transfers
Table 5-3 presents the pollutant loads reported to TRI in 2002 for electric
generating facilities within SIC codes 4911 and 4931. The pollutant loads in Table 5-3 (shown
as "Total Load" in pounds and TWPE) include both direct discharges to surface waters and
indirect discharges (i.e., transfers to POTWs, accounting for estimated POTW removals).
Table 5-3 shows that metal discharges contribute most of the TWPE for the
industry. Several of the metals, especially arsenic, mercury, and selenium, are typically
associated with discharges from coal-fired steam electric facilities because these chemicals are
constituents of coal.
20The Preliminary Engineering Report: Steam Electric Detailed Study [U.S. EPA, 2005b] describes the preliminary
analyses of the steam electric industry that EPA conducted in 2005.
5-4
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Detailed Study Report - November 2006 Chapter 5 - Wastewater Characterization
Table 5-3. Steam Electric TRI2002 Pollutant Loads
Chemical Name"
Arsenic and Arsenic Compounds
Copper and Copper Compounds
Lead and Lead Compounds
Mercury and Mercury Compounds
Manganese and Manganese Compounds
Selenium and Selenium Compounds
Zinc and Zinc Compounds
Nickel and Nickel Compounds
Chromium and Chromium Compounds
Vanadium and Vanadium Compounds
Polycyclic Aromatic Compounds
Thallium and Thallium Compounds
Barium and Barium Compounds
Beryllium and Beryllium Compounds
Cobalt and Cobalt Compounds
Dioxin and Dioxin-Like Compounds
Nitrate Compounds
Ammonia
Antimony and Antimony Compounds
Polychlorinated Biphenyls
Hexachlorobenzene
Toluene
N-Hexane
Molybdenum Trioxide
1 ,2,4-Trimethylbenzene
Methanol
Hydrogen Fluoride
Hydrochloric Acid (1995 and After "Acid
Aerosols" Only)
Sulfuric Acid (1 994 and After "Acid Aerosols"
Only)
Formic Acid
Benzo(g,h,i)Perylene
Total for all Pollutants
Number of
Facilities
Reporting
Chemical
119
196
249
153
188
29
206
172
159
103
9
16
242
17
45
2
3
45
14
1
1
2
3
2
3
1
3
3
1
1
9
368
Total Load
(pounds)1*
92,117
300,568
37,671
505
494,560
28,723
264,899
111,532
88,999
124,599
28
2,363
846,321
1,303
10,692
0.000042
516,350
95,043
5,053
0.0012
0.020
4,200
6.7
253
6.7
6,604
2,720
315
5.0
13
22
3,035,469
Total Load
(TWPE)"
372,277
190,807
84,383
59,169
34,833
32,208
12,420
12,147
6,737
4,361
2,791
2,427
1,685
1,377
1,222
443
386
105
62
41
39
24
0.24
0.20
0.19
0.10
0.015
0.0077
0.0067
0.0048
NA
819,943
Percentage of
Total TWPE
45%
23%
10%
7%
4%
4%
1.5%
1.5%
0.8%
0.5%
0.3%
0.3%
0.2%
0.17%
0.15%
0.05%
0.05%
0.01%
0.01%
0.01%
<0.01%
<0.01%
<0.01%
<0.01%
<0.01%
<0.01%
0.01%
0.01%
0.01%
0.01%
NA
100%
Source: U.S. EPA, 2006b.
aThis table includes discharges of all pollutants reported to TRI in 2002 by steam electric facilities except for chlorine, as
discussed in Section 5.2.1.
bThe Total Load (pounds and TWPE) include both direct surface water discharges and indirect discharges (i.e., transfers to
POTWs, accounting for the POTW removals).
NA - Not applicable. EPA has not developed a toxic weighting factor for this pollutant.
5-5
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Detailed Study Report - November 2006 Chapter 5 - Wastewater Characterization
In this analysis, EPA deleted the chlorine releases and transfers that were reported
to TRI because the TRI chemical "chlorine" refers to chlorine gas (Cb), not total residual
chlorine (TRC). Thirteen steam electric facilities reported chlorine discharges to TRI in 2002.
The February 2000 TRI Guidance for Electricity Generating Facilities describes chlorine
releases as follows:
"No releases to water of chlorine are typically expected. Chlorine reacts very
quickly with water to form HOC1, C1-, and H+. Although this is an equilibrium
reaction, at a pH above 4, the equilibrium shifts almost completely toward
formation of these products. Therefore, essentially zero releases of chlorine to
water are expected to occur under normal circumstances." [U.S. EPA, 2000]
From Table 5-3, the top TRI pollutants identified for the steam electric industry
are arsenic and copper, each contributing over 100,000 TWPE.
5.2.2 PCS Wastewater Discharges
Table 5-4 presents the top 15 pollutant loads (by TWPE) estimated from the PCS
discharge data reported in 2002, as well as loads for four additional pollutants that were included
in the study. These loads incorporate the corrections previously described in Section 5.2. As a
result of these corrections, the pollutant load estimates have changed since the publication of the
2005 Preliminary Engineering Report: Steam Electric Detailed Study [U.S. EPA, 2005b]. Note,
however, that the top five PCS pollutants, aluminum, arsenic, boron, chlorine, and copper, (each
contributing more than 100,000 TWPE) have not changed as a result of the corrections.
The detailed study focused its research efforts on the top five pollutants by
TWPE; however, EPA also collected and analyzed PCS data for several other pollutants for
which it received comments. The additional pollutants included in these analyses are mercury,
nickel, zinc, five-day biochemical oxygen demand (BODs), total suspended solids (TSS), and
total phosphorus (total P). The 2002 PCS loads for these additional pollutants are included in
Table 5-4. The results of the analyses and research on these 11 pollutants of interest are
described in the remaining sections of this chapter.
5.3 Concentration Analyses of Steam Electric Pollutants
EPA used available data in PCS to compute the range, average, and median
concentrations that were reported for each of the 11 pollutants of interest. Table 5-5 presents
these data, along with the number of times the pollutant was detected.
Facilities report pollutant discharge data to PCS as a maximum quantity, average
quantity, maximum concentration, average concentration, or minimum concentration. EPA used
only the average concentration data reported from both major and minor dischargers from the
year 2002 for this analysis. EPA also only included average concentration measurements that
were reported with an associated flow rate. These average concentration data were available for
628 of the 864 major and minor electric generating facilities reporting to PCS.
5-6
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Detailed Study Report - November 2006 Chapter 5 - Wastewater Characterization
Table 5-4. Steam Electric PCS 2002 Pollutant Loads for Selected Pollutants
Pollutant
Copper
Aluminum
Arsenic
Boron
Chlorine
Selenium
Lead
Fluoride
Iron
Mercury
Cadmium
Zinc
Manganese
Hexavalent Chromium
Cyanide
Nickel
TSS
BOD5
Total P
Total for all Pollutants"
Number of
Facilities
Reporting >0
Pounds of
Pollutant
214
53
55
28
279
68
44
13
176
31
25
163
41
12
12
53
605
172
79
718
Total Load
(pounds)
318,114
3,040,130
46,359
1,007,098
257,551
28,892
8,822
488,405
2,709,160
111
541
237,219
108,565
12,068
3,981
27,948
502,018,895
3,618,349
1,809,019
20,239,849,061
Total Load
(TWPE)
201,946
196,670
187,352
178,473
131,135
32,398
19,762
17,094
15,171
13,019
12,513
11,122
7,647
6,234
4,446
3,044
NA
NA
NA
1,057,131
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
17
NA
NA
NA
Source: U.S. EPA, 2006a.
aThe totals shown represent all facility pollutant load data reported to PCS in 2002. The table shows individual
pollutant loads for the top 15 pollutants (by TWPE), as well as an additional four pollutants that were selected for
the study.
NA - Not applicable. EPA has not developed TWFs for these pollutant parameters. EPA only ranked pollutants for
which it has developed a TWF and calculated TWPE loads.
5-7
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Detailed Study Report - November 2006 Chapter 5 - Wastewater Characterization
For average concentration measurements reported as below the detection limit,
EPA assumed that the average concentration was equal to one-half the detection limit if at least
one other sample from that outfall was detected. Alternatively, EPA assumed the average
concentration was equal to zero if the pollutant was not detected in any of the samples reported
from the outfall. EPA included only non-zero concentrations in determining the ranges (i.e.,
minimums and maximums) in the reported average concentrations, as well as in determining the
medians and averages of reported concentrations. Of the 11 pollutants included in the analysis,
only four are specifically limited by national discharge standards for the steam electric industry
[40 CFR 423]: chlorine, copper, zinc, and TSS21. According to the available PCS data, these
four pollutants were mostly discharged at concentrations below the current regulatory limits.
EPA compared effluent discharge concentrations to the pollutant's detection limit.
Detection limits can vary based on a number of factors, including the specific analytical method
and wastewater matrix. Because the parameters may be measured by different methods, Table
5-5 presents a "sample-specific median" method detection level (MDL). The median MDL is
calculated from all reported MDLs reported to PCS for the parameter. MDLs are reported only
when the pollutant is not detected in the sample; therefore, the median MDL shown may not
reflect actual MDLs for samples in which the pollutant was detected.
EPA reviewed the average concentration data that were available in PCS to
determine the number of times a pollutant was detected at 10 times the sample-specific median
MDL. EPA believes that average pollutant concentrations at this level provide a sufficient level
of confidence that the pollutant is present in the waste stream. That is not to say, however, that if
a pollutant is measured at concentrations less than 10 times the detection limit, it is not present in
the waste stream. On the contrary, and particularly with steam electric wastewaters, the presence
of some pollutants may be masked due to extreme dilution when low-volume, high-strength
waste streams are combined with high-volume, low-strength waste streams. This is especially
important in the case of persistent and bioaccumulative pollutants, such as mercury, which can
pose significant hazards to human health and the environment even at low concentrations. While
effects of this dilution may appear to minimize their presence in the final effluent, the hazard
associated with the discharge may be significant.
Boron, aluminum, total phosphorus, zinc, and arsenic were all detected at this
level more than 10 percent of the time. Boron discharged from fossil fuel facilities was detected
in nearly all reported samples (99 percent) at levels greater than 10 times the sample-specific
median MDL. Copper, chlorine, nickel, TSS, mercury, and BODs were all detected at levels
greater than 10 times the sample-specific median MDL less than 10 percent of the time.
21 Arsenic, mercury, and nickel are also regulated under 40 CFR 423 as priority pollutants. These pollutants must
not be detectable in cooling tower blowdown.
5-8
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Detailed Study Report - November 2006 Chapter 5 - Wastewater Characterization
Table 5-5. Summary of Average Pollutant Discharge Concentrations Reported to PCS
Pollutant
Copper
Aluminum
Arsenic
Boron:
Fossil Fuel
Nuclear
Chlorine
Mercury
Zinc
Nickel
TSS
BOD5
Total P
Existing
Regulatory
Limit"
(«g/L)
1,000
NR
NR
NR
NR
200
NR
1,000
NR
30,000
NR
NR
Number
of
Detects
1,250
367
106
85
5
1,131
36
1,003
169
9,695
735
411
Number
of Non-
Detects
275
37
105
0
6
449
65
161
98
1,181
182
9
Range of
Concentrations
(«g/L)b
0.0005 - 50,000
1-73,100
0.22 - 394
1.99-369,000
0.5-11,300
0.005-3,380
0.0002 - 40.56
0.03 - 10,700
0.14-1,950
33.3 - 3,592,000
250-117,000
5 - 70,000
Average
Concentration
(ug/L)"
307
2,297
57
44,813
1,937
152
o
J
174
115
16,305
7,285
904
Average
Concentration
for Detected
Values
(«g/L)
339
2,407
70
44,813
4,261
171
4
190
132
17,621
8,236
923
Median
Concentration
(ug/L)b
18
360
40
4,760
1
54
0.1
37
30.1
6,000
4,800
200
Sample-
Specific
Median
MDL
(ug/L)
10
100
8
i
50
4
20
40
4,000
4,000
75
Number of
Detects Greater
than 10x
Sample-Specific
Median MDL
110
98
24
84
2
91
1
159
10
273
11
95
Percentage of
Detects
Greater than
10 x Sample-
Specific
Median MDL
7.2%
24%
11%
99%
18%
5.8%
1.0%
14%
3.7%
2.5%
1.2%
23%
Source: U.S. EPA, 2006g.
aSee 40 CFR 423. Limits shown are either average of daily values for 30 days or the average concentration limit.
bFor average concentration measurements reported as below the detection limit, EPA assumed that the average concentration was equal to one-half the detection limit if at
least one other sample from that outfall was detected. If the pollutant was not detected in any of the samples reported from the outfall, it was not included in the analysis.
NR - Not regulated.
MDL - Method detection limit.
-------
Detailed Study Report - November 2006 Chapter 5 - Wastewater Characterization
EPA next evaluated the reported effluent concentrations for four of the identified
pollutants by waste stream, shown in Table 5-6. Where possible, EPA identified the type of
waste stream being reported in PCS. If insufficient information was available, EPA classified
the waste stream as "unknown." EPA used the same methodologies for analyzing the pollutant
concentrations for this analysis as was previously discussed. EPA compared the sample-specific
median MDL to the average concentration and identified discharges that were greater than 10
times the sample-specific MDL. EPA also identified the number of facilities and the number of
discharge pipes (outfalls) that were included in the analysis.
EPA performed the concentration analysis by waste stream for the top pollutants
identified through the pollutant loads analysis, excluding chlorine. EPA did not separate the
chlorine concentrations by waste streams because it had already identified cooling water systems
as the primary source of chlorine discharges.
5.4 Sources and Concentrations of the Pollutants of Interest in Steam Electric
Waste Streams
EPA identified the top five pollutants (copper, aluminum, arsenic, boron, and
chlorine) by TWPE that were reported to be discharged by the steam electric industry in PCS and
TRI, as discussed in Section 5.2. These top pollutants contributed 100,000 or more TWPE, and
account for 85 percent of the total steam electric PCS TWPE and 69 percent of the total steam
electric TRI TWPE. EPA also evaluated pollutants that were identified in public comments to
the 2006 Preliminary Plan [70 FR 51042; August 29, 2005]: BOD5, mercury, nickel, total
phosphorus, TSS, and zinc. This section presents information on each pollutant, including the
wastewater sources that are typically associated with the pollutant and typical concentrations of
the pollutant in steam electric waste streams22.
EPA reviewed the 1974 and 1982 Development Documents to determine if TSS
limits were previously set at a level to control other pollutants. EPA also used the concentration
analysis by waste stream to determine whether the average or median concentration is greater
than 10 times the sample-specific median MDL and which waste stream had pollutant
concentrations at these levels. Table 5-7 summarizes the current pollutant data and preliminary
conclusions.
Although not specifically discussed in this section, EPA anticipates greater
amounts of nitrogen compounds, selenium, and other metals in steam electric wastewaters as a
result of the increasing use of air pollution controls. SCR systems used to control NOX in boiler
emissions will increase ammonia use, and some of this ammonia and other nitrogen-containing
by-products are expected to be contained in the cleaning wastewater from these systems. Other
wet air pollution controls (e.g., FGD) are also believed to contribute selenium and other metals to
steam electric wastewaters.
Typical concentrations presented in this section are based on data previously collected by EPA during the 1974
and 1982 rulemaking efforts.
5-10
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Detailed Study Report - November 2006 Chapter 5 - Wastewater Characterization
Table 5-6. Summary of Average Pollutant Discharge Concentrations Reported to PCS by Waste Stream
Pollutant
Copper,
Total
Aluminum,
Total
Waste stream
Unknown Discharge
Cooling Tower
Slowdown
Other Cooling Water
Ash Handling Discharges
Coal Pile Runoff
Metal Cleaning Waste
Low- Volume Waste
Boiler Blowdown
Final Effluent
Stormwater
Flue Gas Desulfurization
Waste
Wastewater Treatment
Total
Unknown Discharge
Cooling Tower
Blowdown
Other Cooling Water
Ash Handling Discharges
Coal Pile Runoff
Metal Cleaning Waste
Low- Volume Waste
Stormwater
Wastewater Treatment
Total
Number of
Detects
392
48
81
160
16
45
151
3
164
22
5
163
1,250
128
42
11
47
38
0
24
34
43
367
Number
of Non-
Detects
63
11
9
46
15
50
28
0
0
0
8
45
275
19
2
0
1
0
2
0
1
12
37
Range of
Concentrations
(ug/L)11
0.0013 - 35,820
0.06 - 1,000
0.0005 - 50,000
1 - 124
5-3,550
0.006 - 1,260
0.0101-800
13-86
0.0275 - 357.3
1 - 532
4-20
1.5-350
9.5 - 8,708
3-5,100
240 - 2,000
25-6,180
100-73,100
ND
70 - 5,520
1 - 1,528
67.5 - 1,900
Average
Concentration
(ug/L)11
126
100
3,505
15
903
94
62
43
34
81
8
25
307
666
905
591
1,079
16,157
ND
2,200
286
348
2,297
Average
Concentration
for Detected
Values
(ug/L)
138
117
3,894
15
1,183
109
67
43
34
81
11
27
339
731
947
591
1,101
16,157
ND
2,200
295
348
2,407
Median
Concentration
(ug/L)'
18
30.4
11
12.6
10
20
32.75
31
15.15
71.55
5
16
335
530
460
434
1,000
ND
2,060
231
260
Sample-
Specific
Median
MDL
(ug/L)
10
10
10
10
10
10
10
10
10
10
10
10
100
100
100
100
100
100
100
100
100
Number of
Detects Greater
than 10* Sample-
Specific Median
MDL
33
12
13
1
6
8
16
0
13
2
0
6
110
32
13
1
17
17
0
15
1
2
98
Is Avg. Cone.
>10x Sample-
Specific
Median MDL
Yes
No
Yes
No
Yes
No
No
No
No
No
No
No
No
No
No
Yes
Yes
No
Yes
No
No
Number of
Discharge
Pipes
64
12
12
27
5
29
18
1
23
6
2
24
223
22
5
1
7
5
1
2
3
5
51
Number of
Facilities
54
10
10
21
5
29
15
1
15
3
2
23
155
17
3
1
6
5
1
2
3
5
34
-------
Detailed Study Report - November 2006
Chapter 5 - Wastewater Characterization
Table 5-6 (Continued)
Pollutant
Arsenic,
Total
Boron-Fossil
Fuel
Boron-
Nuclear
Waste stream
Unknown Discharge
Cooling Tower
Blowdown
Ash Handling Discharges
Coal Pile Runoff
Metal Cleaning Waste
Low- Volume Waste
Final Effluent
Flue Gas Desulfurization
Waste
Wastewater Treatment
Total
Other Cooling Water
Ash Handling Discharges
Stormwater
Flue Gas Desulfurization
Waste
Wastewater Treatment
Total
Unknown Discharge
Nuclear Discharges
Total
Number of
Detects
24
1
50
1
0
0
28
1
1
106
10
15
10
38
12
85
3
2
5
Number
of Non-
Detects
25
0
3
15
3
14
0
0
45
105
0
0
0
0
0
0
6
0
6
Range of
Concentrations
(ug/L)11
1.1 - 156
0.22
1.76-394
10-30
ND
ND
13.8-216
10
10-20
200 - 800
1.99- 1,860
10000 - 38,000
2210 - 369,000
340 - 1,450
0.5-4
10,000- 11,300
Average
Concentration
(ug/L)11
35.6
0.2
84.2
12.0
ND
ND
66.8
10.0
11.4
57
561
1,057
23,100
93,356
758
44,813
1
10,650
1,937
Average
Concentration
for Detected
Values
(ug/L)
45.0
0.2
88.8
30.0
ND
ND
66.8
10.0
20.0
70
561
1,057
23,100
93,356
758
44,813
2
10,650
4,261
Median
Concentration
(ug/L)'
12
0.22
54.5
10
ND
ND
65
10
10
600
1,290
24,000
87,050
615
1
10,650
Sample-
Specific
Median
MDL
(ug/L)
8
8
8
8
8
8
8
8
8
1
1
1
1
1
1
1
Number of
Detects Greater
than 10* Sample-
Specific Median
MDL
4
0
18
0
0
0
2
0
0
24
10
14
10
38
12
84
0
2
2
Is Avg. Cone.
>10x Sample-
Specific
Median MDL
No
No
Yes
No
No
No
No
No
No
Yes
Yes
Yes
Yes
Yes
No
Yes
Number of
Discharge
Pipes
13
1
7
3
1
4
3
1
5
38
2
3
1
5
1
12
1
1
2
Number of
Facilities
11
1
7
3
1
2
3
1
5
28
1
2
1
3
1
7
1
1
2
Source: U.S. EPA, 2006g.
"For average concentration measurements reported as below the detection limit, EPA assumed that the average concentration was equal to one-half the detection limit if at least one other sample from that outfall was
detected. If the pollutant was not detected in any of the samples reported from the outfall, it was not included in the analysis.
ND - Not detected.
MDL - Method detection limit.
-------
Detailed Study Report - November 2006 Chapter 5 - Wastewater Characterization
Table 5-7. Summary of Pollutant Analysis
Pollutant
Boron:
Fossil Fuel
Nuclear
Aluminum
Arsenic
Copper
Chlorine
Zinc
Mercury
Nickel
Total P
TSS
BOD5
Existing
Regulatory
Limit
(ug/L)
NR
NR
NR
NR
1,000
200
1,000
NR
NR
NR
30,000
NR
Previously
Controlled with
Surrogate
Parameter (i.e.,
TSS)?
Not discussed
Not discussed
Not discussed
No
No
No
Not discussed
Not discussed
Not discussed
Not discussed
NA
Not discussed
Is Average
Concentration
>1QX Sample-
Specific Median
MDL?a
Yes
Yes
Yes
Yes
Yes
No
No
No
No
Yes
No
No
Is Median
Concentration
>10X Sample-
Specific Median
MDL?a
Yes
Yes
Yes
No
No
No
No
No
No
No
No
No
Waste Streams
with Average or
Median
Concentration
>10X Sample-
Specific Median
MDL
FGD waste,
stormwater, ash
handling,
wastewater
treatment, and
cooling water
Not analyzed
Low-volume
waste, coal pile
runoff, and ash
handling
Ash handling
Cooling water,
coal pile runoff,
cooling tower
blowdown, and
metal cleaning
waste
NA
NA
NA
NA
Not analyzed
NA
NA
aPCS data showing concentrations >10X MDL demonstrates that the pollutants are present in significant
concentrations. Concentrations <10X MDL are inconclusive because there is insufficient information to determine
whether other waste streams are diluting the concentrations.
NA - Not Applicable.
NR - Not Regulated.
Not Discussed - The Development Documents did not specifically mention a correlation between the control of the
pollutant and TSS.
Not Analyzed - A waste stream concentration analysis was not performed on the pollutant.
5-13
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Detailed Study Report - November 2006 Chapter 5 - Wastewater Characterization
5.4.1 Copper
Copper is a pollutant associated with metal cleaning, for which it is limited to
discharges of 1 mg/L. Copper is also present in cooling water systems as a result of the
dissolution of copper ions from the tubes and into the water, as well as corrosion. Because it is
added as a boiler system maintenance chemical to prevent scale formation, copper is present in
low-volume waste streams, such as boiler blowdown. Copper is also associated with coal-fired
plants as a constituent of coal [U.S. EPA, 2000]. From analyses supporting the 1982 rulemaking,
copper has been shown to increase in concentration in recirculating cooling water systems by
100 ug/L or more, and be present in boiler blowdown in discharge concentrations of up to 140
ug/L [U.S. EPA, 1982].
Except for chemical metal cleaning wastes and cooling tower blowdown, copper
was not previously regulated under 40 CFR 423 because it was not detected or because it was
detected in amounts too small to be effectively reduced by wastewater treatment technologies
[U.S. EPA, 1982]. In the case of coal pile runoff, copper was believed to be sufficiently
controlled through the regulation of TSS [U.S. EPA, 1982]; however, it should also be noted that
for ash pond overflows, EPA concluded that there was no correlation between TSS values and
copper concentrations in the water [U.S. EPA, 1982].
Average copper concentrations reported for coal pile runoff and "other cooling
water" were more than 10 times the sample-specific median MDL; however, the coal pile runoff
concentrations are driven by six measurements reported by one facility, out of a total of 21
measurements from four facilities. If the six measurements from the one facility are removed
from the analysis, the average copper concentration for coal pile runoff is 15 ug/L, which is just
above the sample-specific median MDL. The "other cooling water" concentrations are driven by
eight measurements reported by one facility, out of a total of 90 measurements from 10 facilities.
If the eight measurements from the one facility are removed from the analysis, the average
copper concentration for "other cooling water" is 24 ug/L, which less than 10 times the sample-
specific median MDL. The median discharge concentration of approximately 10 ug/L is two
orders of magnitude less than the average concentration.
It should be noted that while the pollutant concentration in some waste streams is
not high, the total loading of that pollutant discharged to the environment can be still be
significant. This is particularly the case with high-volume waste streams, such as cooling water
discharges.
5.4.2 Aluminum
Aluminum is associated with coal-fired plants as a constituent of the coal.
Aluminum oxide may be present in coal ash in amounts ranging between 4 and 44 weight
percent [U.S. EPA, 1982]. Wastewater streams associated with coal, such as ash handling and
coal pile runoff, can become contaminated with aluminum.
Aluminum was previously identified as a constituent of coal pile runoff, but was
not specifically regulated. There are several factors that affect the presence of aluminum (and
other metals) in coal pile runoff, including the pH of the drainage, the type of coal, the size of the
coal, climatic conditions, and other factors [U.S. EPA, 1982]. Aluminum is likely controlled to
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some degree by the control of TSS, but there is no demonstrated correlation between TSS and
aluminum concentrations.
For aluminum, the highest reported concentrations (73,100 ug/L) are associated
with coal pile runoff. However, the reported discharge concentrations are primarily driven by 10
measurements from one facility, out of a total of 38 measurements from five facilities. If the 10
measurements from the one facility are removed from the analysis, the average aluminum
concentration for coal pile runoff is 880 ug/L, which is less than 10 times the sample-specific
median MDL. Higher concentrations of aluminum discharges (up to 6,000 ug/L) are also
associated with low-volume wastes and ash handling. Because aluminum is a constituent of
coal, it is not surprising that aluminum is present in waste streams associated with coal, such as
coal pile runoff. EPA identified best management practices as a way that aluminum discharges
from coal pile runoff could be prevented [U.S. EPA, 1974]. Aluminum is not currently regulated
by the Steam Electric ELGs.
5.4.3 Arsenic
Arsenic is also associated with coal-fired power plants as a constituent of coal.
Wastewater streams associated with coal, such as ash handling and coal pile runoff, can become
contaminated with arsenic; however, the arsenic content of coal can vary widely depending on
the coal's rank (e.g., bituminous, lignite, subbituminous) and the region of the country in which
the coal originates. For example, bituminous coal from Alabama has an arsenic content of 53
ug/g, while subbituminous coal from Wyoming has an arsenic content of 0.69 ug/g [U.S. EPA,
2000]. In general, coal from Alabama has an average arsenic content of 72.4 ug/g, while on
average, coal in the United States has an arsenic content of 24.6 ug/g [USGS, 1998].
Except for cooling tower blowdown, arsenic was not previously regulated under
steam electric because EPA found that it was not detected or was detected in amounts too small
to be effectively reduced by wastewater treatment technologies [U.S. EPA, 1982]. It should also
be noted that in the 1982 Development Document, EPA specifically concluded that there was no
correlation between TSS values and arsenic in ash pond overflows [U.S. EPA, 1982].
The average arsenic concentrations associated with ash handling waste streams
were greater than 10 times the sample-specific median MDL. Arsenic was detected at this level
in 34 percent of the available PCS data (i.e., in 18 out of 53 records); however, the median
arsenic concentration associated with ash handling waste streams was less than 10 times the
sample-specific median MDL. In the 1982 rulemaking, EPA identified chemical precipitation as
a potential control technology for arsenic discharges from ash handling waste streams [U.S.
EPA, 1982].
5.4.4 Boron
Boron is a pollutant associated with both nuclear and fossil-fuel type steam
electric plants. EPA's finding with respect to boron discharged from each of these sources are
summarized below.
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Boron from Fossil-Fuel Plants
In fossil-fuel plants, boron is associated with coal-fired plants specifically as a
constituent of the coal. Coals vary in terms of their trace metal composition depending on their
rank (e.g., bituminous, lignite, subbituminous) and the region of the country in which they
originate. For example, coal from Alabama has a boron content of 28.2 ug/g, while on average,
coal in the United States has a boron content of 47.9 ug/g [USGS, 1998]. Therefore, wastewater
streams associated with coal, such as wet ash handling and coal pile runoff, can become
contaminated with boron.
In addition, waste streams generated by FGD systems can also contain amounts of
boron removed from the flue gas emissions (see Section 3.2.1.6 for a discussion of FGD). FGD
systems remove sulfur dioxide from the exhaust of coal-fired power plants, and by extension
these waste streams may be a source of boron and other coal constituents (e.g., arsenic and other
metals).
Boron was not previously identified as a pollutant of concern for the steam
electric industry because no practicable treatment was reported [U.S. EPA, 1974]. It is likely
controlled to some degree by controlling TSS, but there is no demonstrated correlation between
TSS and boron concentrations [U.S.EPA, 1974].
For boron discharged from fossil-fuel plants, EPA determined that highest
reported concentrations reported in PCS were associated with FGD systems. Average
concentrations ranged from 2,210 to 369,000 ug/L, with a median reported concentration of
87,050 ug/L. Boron was also reported in high concentrations associated with stormwater
(median concentration of 24,000 ug/L). Because boron is a constituent of coal, it is not
surprising that boron is present in FGD waste streams. EPA identified a zero liquid discharge
brine concentrator/spray dryer system that is designed to remove boron and other metals from
FGD waste streams (see Section 5.5.2 for more details). Boron is not currently regulated by 40
CFR423.
Boron from Nuclear-Fueled Plants
In nuclear plants, boron is typically used to absorb neutrons, which controls the
fate of the fission chain reaction [EaglePicher, 2002]. Various forms of boron compounds,
including boric acid and sodium pentaborate, may be added to the primary coolant system to help
control the long-term stability of the system [EaglePicher, 2002]. Boron-enriched zirconium
diboride and erbium boride may be used as nuclear fuel additives to control the absorption of
neutrons to better control the reaction. EPA determined that possible sources of boron
discharges from nuclear facilities include the following [UWAG, 2005b] [UWAG, 2006a] [69
FR 18654; April 18,2004]:
• High conductivity waste tank;
• Radioactive waste hold-up tank;
• Standby liquid control drain tank;
• Steam generator blowdown;
• Spent fuel pond; and
• Treatment processes.
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For boron discharged from nuclear plants, EPA estimated the highest reported
average concentrations were over 11,300 ug/L, and the median of the average concentrations was
10,650 ug/L.
5.4.5
Chlorine
Chlorine and chlorine-based compounds are primarily used as biocides in power
plant cooling water systems to control biofouling in either closed- or open-loop systems.
Biofouling is the collection of slime-forming organisms (fungi, bacteria) or larger organisms
(clams, mussels) on the water side of the condenser tubes, which inhibits heat exchange.
Chlorine's effectiveness as a biofouling control agent also makes it an aquatic environmental
concern due to its potential direct impact when residual chlorine is released.
Some steam electric facilities currently use alternatives to chlorine-based
oxidizing biocides, such as brominated compounds, for biofouling control. Other alternatives
include non-oxidizing biocides, such as ammonium compounds, aromatic hydrocarbons, copper
salts, potassium salts, and many others [Sprecher, 2000].
UWAG conducted a survey of its members and provided the results to EPA
[UWAG, 2005a]. In the survey, UWAG obtained information regarding biocide usage in the
industry. Table 5-8 summarizes the relative number of facility respondents using various types
of biocide.
Table 5-8. Biocide Usage in the Steam Electric Industry
Biocide
Chlorine-based compounds only
Bromine-based compounds only
Both chlorine and bromine based compounds
Both chlorine or bromine and non-oxidizing biocide
Non-oxidizing biocides only
Ozonation
Total Units Using Biocides
Number
of Units
414
44
70
8
7
2
545
Percentage of Survey
Respondents
49.3%
5.2%
8.3%
0.95%
0.83%
0.2%
64.8%
Source: UWAG, 2006b.
Chlorine was identified previously as a key pollutant for this industry. During
sampling in support of the 1982 rulemaking, net discharges of TRC were as high as 7,100 ug/L
in once-through and recirculating systems [U.S. EPA, 1982]. Chlorine is currently regulated as
TRC in once-through cooling system wastewaters, and as free available chlorine (FAC) for
recirculating cooling tower system wastewaters. Brominated compounds are regulated as total
residual oxidants (TRO) by 40 CFR 423 for once-through cooling water from plants having a
total rated electric generating capacity of 25 MW or more if the intake water contains bromides
[40 CFR 423.11 (a)]. Non-oxidizing biocides are not directly regulated by 40 CFR 423, but the
ELG limitation of no detectable priority pollutants in cooling tower blowdown would apply.
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According to the available PCS average concentration data for the TRC and FAC
parameters, chlorine is typically discharged at levels much lower than the current ELG limits.
EPA has identified a number of best management practices as well as treatment technologies to
achieve nondetectable quantities of chlorine in cooling water effluent (see Section 5.5.1 for more
details).
It should be noted that while the pollutant concentration in some waste streams is
not high, the total loading of that pollutant discharged to the environment can be still be
significant. This is particularly the case with high-volume waste streams, such as cooling water
discharges.
5.4.6 Mercury
Mercury is a trace constituent of all fossil fuels, including coal, oil, and natural
gas [U.S. EPA, 2001a]. The trace metal composition of coals varies depending on their rank
(e.g., bituminous, lignite, subbituminous) and the region of the country in which they originate.
The average mercury content in coal is 0.17 mg/kg [USGS,1998]. Wastewater streams
associated with coal, such as ash handling and coal pile runoff, can become contaminated with
mercury.
Mercury is associated with waste streams from FGD systems because it is a
constituent of coal and FGD systems are capable of scrubbing metals out of the flue gas streams
(i.e., soluble mercury compounds are expected to be captured by wet FGD systems). EPRI
commented that power plants with FGDs are likely to have higher mercury concentrations in
wastewater discharges.
Likewise, the use of SCR systems is expected to increase the amount of mercury
removed from the facility exhaust stream. Mercury that is adsorbed to fly ash and other
particulates is also likely to be removed by other paniculate matter control devices. In addition
to FGD and SCR, many steam electric facilities use wet fly ash handling systems, which allows
mercury to be transformed from the flue gas exhaust and into wastewater from the air pollution
control devices, and subsequently into surface waters. Further, available data indicate that
elemental mercury may be oxidized in an SCR unit (particularly when bituminous coal is being
used) [U.S. EPA, 2005b]. This increases the amount of oxidized mercury in the gas stream that
may then be removed in a downstream wet FGD system.
As described in Chapter 4 of this report, CAMR establishes limits on mercury
emissions from the steam electric industry. The first phase of the regulation should not require
that the industry implement mercury-specific control technologies to meet the limits. Facilities
may continue to use existing SC>2 and NOX control technologies required by CAIR, such as FGD
and SCR. The use of wet FGD systems to capture 862 is expected to double by 2015 in response
to CAIR [U.S. EPA, 2006c].
EPRI provided data on mercury concentrations detected in steam effluents in the
1990s. EPRI's data, using the 1600 series methods for detecting trace metals, showed effluent
concentrations on the order of 0.01 ug/L, which was lower than reported in the 2002 PCS data (3
ug/L on average). The EPRI sampling data were collected from seven facilities, while the PCS
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data include measurements from 22 facilities. EPRI did not identify which waste streams were
sampled in their analyses and, therefore, EPA cannot determine if one data source is better or
more accurate than the other. The minimum level of quantitation for Method 1631 is 0.5 ng/L
[U.S. EPA, 2002]. EPRI also noted that conventional sampling and analytical methods should be
able to achieve detection limits below 0.2 |ig/L.
Mercury was reported to be discharged by only 42 out of the 864 facilities
reporting to PCS; however, mercury was reported to be discharged by 153 of the 375 facilities
reporting to TRI. Therefore, the mercury loads represented in Table 5-4 may be underestimated
because many facilities are not required by their NPDES permits to monitor mercury discharges.
In this detailed study, EPA researched available information on IGCC technology
(discussed previously in Section 3.2.2) as having the potential to reduce the mercury and other
metals released to the water and air from traditional coal-fired boilers. IGCC technology offers
opportunities to remove mercury and other trace metals (e.g., cadmium and selenium) from the
coal-derived syngas prior to combustion, thus reducing the levels of these contaminants in ash
and air pollution control wastes.
5.4.7 Nickel and Zinc
Nickel and zinc are both constituents of coal and, like mercury, can be found in
wastewaters associated with the coal and ash. In addition, zinc is often used in corrosion
inhibitors, and therefore can also be found in cooling water system discharges.
Nickel was detected in slightly more than 60 percent of the reported samples;
however, it was detected at more than 10 times the sample-specific MDL in only 3.7 percent of
the samples. The average concentration was 115 ug/L with a median concentration of 31 ug/L.
Zinc is typically (more than 80 percent) detected in all reported samples, but is
detected at 10 times the sample-specific MDL in only about 14 percent of the samples. The zinc
concentrations were on the order of those for nickel. The average concentration was 174 ug/L
with a median concentration of 37 ug/L, well below the existing ELG limit of 1,000 ug zinc/L.
The average concentration is primarily driven by three facilities that reported concentrations
greater than 1,000 ug/L, out of 1,117 measurements from 109 facilities.
5.4.8 Total Suspended Solids
TSS is a pollutant of concern for this industry and is already regulated under the
current ELGs. TSS is an indicator of the effectiveness of solids separation processes. In
addition to electric generating process sources, the level of TSS found in steam electric process
wastewaters can also be affected by chemical treatment of the wastewater, as certain compounds
are precipitated from the waste stream.
EPA identified TSS for further review in the Preliminary Engineering Report:
Steam Electric Detailed Study because of its large pollutant loading [U.S. EPA, 2005b]. EPA
determined that the vast majority of discharges reported for TSS are well below the current ELG
limits (i.e., 30 or 50 mg/L, depending on the waste stream), with an average concentration of 16
mg/L and a median concentration of 6 mg/L, based on 10,752 measurements from 525 facilities.
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5.5 Pollutant Control Technologies and Practices
This section summarizes potential treatment and control technologies for selected
pollutants of interest contained in wastewaters of the steam electric industry, based on
information obtained to date for this detailed study. Wastewaters from steam electric plants vary
in quality and quantity; however, pollutants in these wastewaters can often be controlled in a
uniform manner. The technologies described in this section are available or currently in use by
facilities in the steam electric industry. The discussion of technologies is organized by type of
waste stream.
5.5.1 Cooling Water Pollutant Control Technologies
As described in Section 3.2, cooling water is used in the steam electric process to
condense the steam used to drive the turbine and generate electricity. As the cooling water
passes through the condenser, microbiological species, such as bacterial slimes and algae, stick
to and begin growing on the condenser tubes. This growth is known as biofouling, which
reduces heat transfer, decreases flow, and accelerates corrosion of the condenser. There are also
various macro-organisms, such as mussels, mollusks, and clams, which can inhibit condenser
performance. Steam electric facilities use biocides, such as chlorine, to control biofouling.
5.5.1.1 Dry Cooling Technology
The vast majority of water used by traditional steam electric facilities is related to
cooling water systems. Due in part to water shortages that exist in arid parts of the world, some
power plants have implemented dry cooling technology. Dry cooling systems reduce cooling
water use by 99 percent compared to once-through cooling systems, and 4 to? percent compared
to recirculating cooling water systems (e.g., cooling towers) [U.S. EPA, 2001b].
Dry cooling systems transfer heat to the atmosphere without water evaporation.
There are two types of dry cooling systems for power plant applications: direct dry cooling and
indirect dry cooling. Direct dry cooling systems utilize air to directly condense steam, while
indirect dry cooling systems use a closed-cycle water cooling system to condense steam, and the
heated water is then air cooled. Indirect dry cooling generally applies to retrofit situations at
existing power plants because a water-cooled condenser would already be in place for a once-
through or recirculated cooling system. The most common type of direct dry cooling systems
(towers) for new power plants are recirculated cooling systems with mechanical draft towers.
Natural draft towers are infrequently used for installations in the United States [Micheletti,
2002].
5.5.1.2 Recirculating Cooling Water Systems
In a recirculating system, cooling water is used to cool equipment and steam,
absorbing heat in the process. The water is then cooled and recirculated to the beginning of the
system to be used again for cooling. Recirculating the cooling water in a system vastly reduces
the amount of cooling water needed. On average, recirculating cooling systems reduce the
cooling water flow rate between 92 and 95 percent compared to once-through cooling systems,
depending on the water source [U.S. EPA, 2001b]. The method most frequently used to cool the
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water in a recirculating system is through a cooling tower (see Section 3.2.1.4 for more details on
recirculating cooling water systems).
5.5.1.3 Biocide Management Practices for Once-Through Cooling Systems
This section describes biocide management practices in use at steam electric
facilities with once-through cooling systems, including low-level biocide application, natural
decay of total residual oxidants (TRO)/free available oxidants (FAO), and dehalogenation.
Low-Level Biocide Application
Typically, facilities perform an optimization study to determine what chemical
regime would provide the best results for the plant. A low-level biocide application is the usual
treatment option used by facilities with once-through cooling systems. Based on the results of
the optimization study, the facility can add a specific amount of biocide that will treat the
biofouling in the condensers and still meet the NPDES permit limit or achieve a nondetectable
biocide concentration. Alternatively, the facility may inject enough biocide to meet the
biological demand with the option to dehalogenate if residuals exist [UWAG, 2006c].
Natural Decay ofTRO/FAO with No Dehalogenation System
Facilities can naturally decay TRO/FAO by using a discharge canal or by
commingling treated condenser cooling water with untreated condenser cooling water prior to
discharge [UWAG, 2006c]. Commingling treated and untreated condenser cooling water
requires the facility to have multiple condenser cooling systems and the ability to chlorinate each
unit independently. To do this, the facility installs the injection point of the chlorine system at or
near each of the condenser inlet boxes [U.S. EPA, 1982]. This practice allows the TRO/FAO to
naturally decay because there is less natural dechlorination before the condenser (i.e., if the
chlorine was injected into the waste stream at the intake point, instead of right before the
condenser), which minimizes chlorine use. In addition, there is some natural dechlorination after
the cooling water exits the condenser outlet box. Because there are multiple condenser cooling
systems, the untreated cooling water will have some biological demand that will naturally decay
some of the remaining biocide from the treated cooling water.
Dehalogenation
Dehalogenation is the process of adding a reducing agent, typically sulfur dioxide,
sodium bisulfite, or ammonium bisulfite, to a waste stream to consume the oxidizing biocide
present. The bisulfite compounds can be fed as either a solid or liquid, and sulfur dioxide is used
as a gas [UWAG, 2006c]. Chlorine is the most commonly used biocide, and sulfur dioxide is the
most commonly used dehalogenation chemical, due to its ease of handling and low cost. The
chlorine in the wastewater, in the form of hypochlorous acid, oxidizes the sulfur dioxide and
produces chloride and sulfate ions.
Water and wastewater treatment facilities have used dehalogenation extensively
since 1926 [U.S. EPA, 1982]; this technology is also currently in use at many steam electric
power plants. It is a proven technology that can reduce the residual oxidant levels in wastewater
to trace or nondetectable concentrations. For more information regarding the use of
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dehalogenation systems at steam electric power plants, see Section VII of the 1982 Development
Document [U.S. EPA, 1982].
5.5.1.4 Biocide Management Practices for Recirculating Cooling Systems
This section describes biocide management practices in use at steam electric
facilities with recirculating cooling systems, including natural decay of TRO/FAO,
dehalogenation, and detoxification of non-oxidizing biocides.
Natural Decay of TRO/F AO with No System Discharge
One way that facilities can reduce the amount of biocide discharged is to isolate
(shut down) the cooling system blowdown until the biocide has naturally decayed to an
acceptable level. Once the facility has confirmed that the biocide is at an acceptable level, the
cooling system blowdown is reopened and discharge resumes.
Some facilities are unable to shut down their cooling system blowdown during
chlorination because their cooling towers are controlled by the conductivity present in the
cooling water. If during chlorination, the conductivity of the wastewater within the cooling
system reaches a certain level, the cooling system will blowdown regardless [IDNR, 2006a].
UWAG also stated that while the blowdown is shut off, there is a buildup of
calcium carbonate in the cooling water, which can scale and corrode the cooling tower. If
calcium carbonate builds at a facility to the point that scaling and corrosion become too severe,
the facility would have to take the unit offline for acid treating.
Dehalogenation
See Section 5.5.1.3 for a discussion of dehalogenation systems.
Detoxification for Non-Oxidizing Biocides
Non-oxidizing biocides control the growth of microbiological organisms
differently than oxidizing biocides. Instead of oxidizing the organisms, the non-oxidizing
biocides interfere with the metabolism of the organisms. After the organisms are dead, they
often release hold of the condenser tubes and are washed away with the passing cooling water.
Non-oxidizing biocides are mainly used in recirculating cooling systems, but can be used with
once-through cooling systems to control macrobiological organisms such as Asiatic clams. Non-
oxidizing biocides are typically used as a supplement to oxidizing biocides, but can be used for
primary biofouling control [UWAG, 2006c].
Facilities that use non-oxidizing biocides to control biofouling need to deactivate
the biocide residual prior to discharge. To detoxify the biocide, facilities typically shut down the
cooling system blowdown and add bentonite clay to the system, which absorbs excess biocide in
the water. The facility confirms that the biocide concentration is at an acceptable level prior to
reopening the cooling system blowdown. UWAG stated that if the cooling tower blowdown is
discharged to an ash pond, bentonite clay normally does not need to be added because the fly ash
will absorb the residual biocide [UWAG, 2006c].
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5.5.2 Zero Liquid Discharge Systems
Zero liquid discharge (ZLD) systems have been implemented at steam electric
power plants to eliminate all types of process wastewaters, including cooling tower blowdown,
boiler blowdown, coal pile runoff, ash pond overflow, FGD wastes, and other miscellaneous
waste streams.
ZLD systems eliminate liquid waste stream discharge and recycle high-purity
water for reuse in the process, thereby reducing plant water consumption by 10 to 90 percent.
They are based on the use of a brine concentrator, in combination with other evaporators, spray
dryers, and crystallizers.
• Brine Concentrator - Seeded-slurry, falling-film evaporators that convert
highly saturated industrial wastewaters into distilled water for reuse. With
a typical brine concentrator, 95 to 99 percent of wastewater can be
recovered as high-purity distillate (<10 mg/L total dissolved solids). Brine
concentrators are specific types of falling film evaporators used to treat
wastewaters saturated in scaling constituents such as calcium sulfate or
silica.
• Evaporators - Vertical-tube, falling-film evaporators that convert
industrial wastewaters into distilled water for reuse in the plant. With a
typical evaporator, 95 to 99 percent of wastewater can be recovered as
high-purity distillate (<10 mg/L total dissolved solids).
• Spray Dryers/Crystallizers - Crystallizers that preconcentrate the
wastewater to reduce the remaining wastewater to solids. Crystallizer
systems use mechanical vapor recompression (MVR) technology to
recycle the steam vapor, which is clean enough to reuse in the plant. The
solid cake produced by the crystallizer is easy to handle and suitable for
landfill disposal.
In the original rulemaking, EPA identified the brine concentrator (vapor-
compression evaporation system) as a potential technology to recover and recycle water from the
cooling tower blowdown and other low-volume waste streams. The 1974 Development
Document concluded the following regarding the use of brine concentrators to control low-
volume wastes23:
"The application of evaporative brine concentrators to low-volume waste stream
effluents after chemical treatment is not known to have been achieved. Therefore,
some technical risks may be involved in applying this technology directly to low-
volume wastewater of power plants." [U.S. EPA, 1974]
23 The low-volume waste streams in the 1974 analysis include the following: boiler blowdown, demineralizer
blowdown, ash sluicing water blowdown, coal pile runoff, SO2 scrubber blowdown (i.e., FGD), treated sewage
effluent, boiler cleaning waste, and cooling tower blowdown.
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Since the 1974 regulation, the steam electric industry has started using this
technology to control low-volume wastes, such as boiler blowdown and cooling tower
blowdown.
Table 5-9 lists plants with ZLD systems in place. This list is provided to
demonstrate the use of the technology in this industry. It is not intended to be an exhaustive list
of U.S. facilities operating ZLD systems.
Detailed Example of a Boron Mitigation ZLD System for FGD Wastes
EPA identified a ZLD system being designed to control boron discharges from
FGD scrubber blowdown from the City of Springfield's Dallman Power plant in Illinois. EPA
contacted the manufacturer to obtain additional information regarding the design and
implementation of this pollutant control technology. This system is designed specifically to treat
the FGD scrubber blowdown from the Dallman Power Plant, which has a flow rate of
approximately 120 GPM and contains 2 to 2.5 percent solids.
As described in Section 3.2.1.6, FGD is a process used to control the sulfur
dioxide emissions from coal-fired power plants. A wet or dry scrubber using a sorbent, usually
lime or limestone, scrubs the flue gas with the sorbent slurry and produces calcium sulfite, which
is removed in the blowdown from the scrubber. In addition to boron, the scrubber blowdown
contains other metals in the flue gas, such as mercury, arsenic, and selenium, which originate
from the coal used to fuel the plant.
Figure 5-1 presents a process flow diagram of the ZLD boron mitigation system.
The first step of this treatment system is to adjust the pH of the FGD scrubber blowdown to
approximately 6.5 by adding acid to the waste stream. The facility then pumps the acidified
scrubber blowdown through a heat exchanger to bring the waste stream to its boiling point. The
waste stream continues to a deaerator where the noncondensable materials such as carbon
dioxide and oxygen are vented to the atmosphere [Aquatech, 2006b].
From the deaerator, the waste stream enters the sump of the brine concentrator.
Brine from the sump is pumped to the top of the brine concentrator and enters the heat transfer
tubes. While falling down the heat transfer tubes, a portion of the solution is vaporized and then
compressed and introduced to the shell side of the brine concentrator. The temperature
difference between the vapor and the brine solution causes the vapor to condense as pure water.
The condensed vapor (distillate) waste stream of clean water is produced at a rate of 108 GPM.
The distillate is recycled to the boiler as make-up water. [Aquatech, 2006b].
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Table 5-9. Steam Electric Facilities Currently Operating ZLD Systems
Plant Name
Stanton Energy
Center3
AES Ironwood
Cedar Bay
Cogeneration
Plant
Gila River
Power
Texas
Independent
Energy
Guadalupe
Power Plant
Griffith Energy
LLC
Arlington
Valley Power
Bechtel Power
Corporation
Panda Energy
Plant Location
Orlando, FL
Lebanon, PA
Jacksonville,
FL
Gila Bend, AZ
Marion, TX
Kingman, AZ
Arlington, AZ
Northampton,
PA
Brandywine,
MD
Plant Type
Gas-fired
combined
cycle
Coal
Combined
cycle
Combined
Cycle
Gas-fired
combined
cycle
Combined
Cycle
Culm
Gas-fired
combined
cycle
Date of
Operation
Summer
1995
2001
January
1994
2006
Aug 2003
January
1995
September
1996
Flow
(GPM)
600
200
150
2,400
5,600
230
1,675
1,000
280
Capacity
(MW)
700
250
2,200
1,000
520
Technologies
Brine
concentrator and
2 crystallizers
Brine
concentrator,
crystallizer, RO,
and EDI
Brine
concentrators (2)
and crystallizer
Pretreat with
clarifiers and
multimedia
filtration. Brine
concentrators (2)
and RO (4).
Brine
concentrator,
crystallizer, and
EDI
HERO™ (RO)
system followed
by evaporation
pond
HERO™ (RO)
system followed
by evaporation
pond
Evaporators
Spray-film®
evaporator
Types of
Wastewater
Cooling
tower
blowdown
Cooling
tower
blowdown
Cooling
tower
blowdown
Cooling
tower
blowdown
Cooling
tower
blowdown
Cooling
tower
blowdown
Cooling
tower
blowdown
Cooling
tower
blowdown;
demineralizer
waste
Cooling
tower
blowdown
Source: Aquatech, 2006a; GE, 2006.
aA new 285-MWIGCC plant is currently being designed for this site.
EDI - Electrodeionization.
GPM - Gallons per minute.
HERO™ - High Efficiency Reverse Osmosis.
MW - Megawatt.
RO - Reverse osmosis
5-25
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Detailed Study Report - November 2006
Chapter 5 - Wastewater Characterization
to
a\
FGD
Scrubber
Slowdown
Acid In
Deaerator
4
Vent to
Atmosphere
Vent to
Atmosphere
Brine Concentrator/
Vapor Separator
Feed/Distallate
Heat Exchanger [ ^\ )
Distillate Out
Source: Aquatech, 2006b.
Figure 5-1. ZLD Boron Mitigation System for FGD Wastes
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Detailed Study Report - November 2006 Chapter 5 - Wastewater Characterization
The concentrated brine slurry, approximately 20 to 25 percent solids, is again
recycled with a small amount continuously withdrawn and sent to the spray dryer. Because the
waste stream is 10 times more concentrated, the flow rate of the solution is 10 times less, or 12
GPM, leaving the concentrator. From the brine concentrator, the concentrated slurry is sent to a
spray dryer. The slurry is fed to the top of the spray dryer and is sprayed down the shaft. Hot air
is fed up through the bottom of the dryer and evaporates the remaining water in the slurry. The
hot air and the evaporated water are vented to the atmosphere, while the solids fall to the bottom
of the dryer for collection. The pH treatment and the precipitation of the metals during the
process ensures that they will not be vented to the atmosphere with the flue gas from the spray
dryer [Aquatech, 2006b].
The solids removed from the system are typically sent to a landfill. However, like
fly ash, FGD waste can be recycled and used for other various applications. The FGD materials
can be used in the following applications:
• Raw material for wallboard;
• Fill material for structural applications and embankments;
• Feed stock in the production of cement;
• Raw material in concrete products and grout; and
• Ingredient in waste stabilization and/or solidification [U.S. EPA, 2006h].
Although the system is referred to as a "boron mitigation system," it can remove
other metals from the waste stream. It can also be designed to treat other waste streams
associated with power generation. According to the manufacturer, the reason this system was
termed a "boron mitigation system" is because boron was the pollutant of most concern for this
facility [Aquatech, 2006b].
The brine concentrator can achieve a concentration of only approximately 20 to
25 percent solids, so the solids present in the incoming stream limit its use; however, if the
incoming waste stream is already 20 to 25 percent solids, it could be sent directly to the spray
dryer. The manufacturer has already built several ZLD systems for power plants outside of the
United States that control flow rates from 700 to 800 GPM [Aquatech, 2006b].
The manufacturer stated that this system could be used to treat the FGD scrubber
blowdown from any power plant that uses a wet scrubber. They estimate that there are between
50 and 100 facilities in the United States that are using wet scrubbers for FGD [Aquatech,
2006b]. According to the EIA information collected in 2002, there are approximately 183
facilities that use wet scrubbers for FGD [U.S. DOE, 2002b].
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Detailed Study Report - November 2006 Chapter 6 - Alternative-Fueled Steam Electric Facilities
6.0 ALTERNATIVE-FUELED STEAM ELECTRIC FACILITIES
This chapter describes EPA's study of alternative-fueled steam electric facilities,
which produce electricity for distribution and sale using steam that is created by means other
than fossil-fueled or nuclear-fueled process. In this chapter, alternative-fueled steam electric
facilities refer to those facilities that produce steam by combusting a solid or gaseous alternative
fuel, those that use steam from geothermal reservoirs (geothermal steam electric facilities), and
those that produce steam using the sun's energy (solar steam electric facilities).
Wastewater generated by alternative-fueled steam electric processes is not
currently regulated by the Steam Electric ELGs, since their electricity does not result
"... primarily from a process utilizing fossil-type fuel (coal, oil, or gas) or nuclear fuel...", as
defined at 40 CFR 423.10. As part of the detailed study of the steam electric industry, EPA
investigated alternative-fueled steam electric facilities to determine whether a revision to the
current Steam Electric ELGs may be warranted to include these types of steam electric
wastewaters.
EPA reviewed NPDES permits for a prioritized subset of alternative-fueled steam
electric facilities to identify sources of wastewater and determine how the wastewaters are
currently regulated (e.g., whether the Steam Electric ELGs are applied using BPJ). EPA used
information available from the EIA to identify steam electric facilities that reported using an
alternative fuel in 2002 and identified 207 facilities. From this group, EPA selected a subset of
28 facilities that represents each reported alternative fuel type and a significant percentage of the
total alternative-fueled steam electric energy capacity. After searching public web sites and
contacting state permitting authorities directly, EPA acquired NPDES permits for 13 of the 28
targeted facilities.
This chapter presents EPA's findings on alternative-fueled steam electric facilities
that were obtained through the NPDES permit review, which included communications with
permitting authorities, and a literature search.
6.1 Alternative-Fueled Steam Electric Processes and Wastewaters
The steam electric generating process used at alternative-fueled steam electric
facilities is similar to that used by all steam electric facilities, as described in Section 3.2, in the
sense that they use a steam/water system as the thermodynamic medium to produce electricity.
In alternative-fueled steam electric facilities, steam (which may or may not be produced in a
boiler) is used to drive a steam turbine/electric generator and the steam is condensed by
noncontact cooling.
The following subsections describe the steam electric process, sources of
wastewater, potential wastewater pollutants, and current permitting practices for various types of
alternative-fueled steam electric facilities.
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Detailed Study Report - November 2006 Chapter 6 - Alternative-Fueled Steam Electric Facilities
6.1.1 Solid Fuels
Steam electric facilities fueled by solid alternative fuels (e.g., municipal solid
waste, wood solid waste, agricultural by-products, and tires) use a similar (if not identical)
process as those facilities that are currently regulated under 40 CFR Part 423. These alternative-
fueled steam electric facilities combust a solid fuel, typically in a boiler, to produce steam. This
combustion process generates ash. The steam produced powers a steam turbine/electric
generator. The steam exiting the turbine is condensed with cooling water and the condensate is
typically fed back to the boiler. Thus, steam electric facilities fueled by solid alternative fuels
generate the same types of wastewaters as those currently regulated under 40 CFR Part 423. As
described in Section 3.2.1, these wastewaters include fly ash and/or bottom ash sluice (slurry),
metal cleaning wastes, once-through cooling water and/or recirculating cooling tower blowdown,
fuel storage runoff, boiler feedwater treatment wastes, boiler blowdown, and other low-volume
wastes [CEPA 2006a] [CEPA, 2006b] [U.S. DOE, 2000] [IDNR, 2006b] [Fairfax, 2006] [U.S.
EPA, 2006i] [FDEP, 2006].
The following subsections describe the types of solid alternative fuels included in
EPA's study of alternative-fueled steam electric facilities.
Municipal Solid Waste
Typical constituents of municipal solid waste (MSW) include paper, paperboard,
yard waste, plastics, metals, glass, food waste, wood, rubber, leather, and textiles. Refuse-
derived fuel (RDF) is produced from MSW through processing steps, which involve, at
minimum, coarse shredding of the MSW and magnetic separation of ferrous metals [Kirk-
Othmer, 2006a].
At the time of the initial 1974 Steam Electric ELGs, EPA identified one steam
electric plant in the United States as using RDF for 10 percent of its fuel [U.S. EPA, 1974]. The
1974 Development Document also stated that incinerating "garbage" produces moderate
amounts of hydrogen chloride, and that EPA should continue to study the disposal of the
effluents from steam electric facilities using these alternative fuels.
EPA obtained data on the pollutant concentrations found in MSW ash and coal
ash. Although the compositions of these ashes vary significantly depending on the type of
material that is combusted and the location that the ash is sampled, EPA noted general
differences between MSW ash and coal ash. As shown in Table 6-1, MSW ash can contain
significantly higher amounts of barium, cadmium, mercury, molybdenum, nickel, selenium, and
zinc than coal ash.
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Detailed Study Report - November 2006
Chapter 6 - Alternative-Fueled Steam Electric Facilities
Table 6-1. Comparison of Available Coal Ash, Municipal Solid Waste Ash, and Wood Ash
Composition Data
Component
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chloride
Chromium (III)
Chromium (VI)
Chromium - Total
Cobalt
Copper
Cyanide
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Potassium
Selenium
Silicon
Silver
Sodium
Strontium
Thallium
Titanium
Vanadium
Zinc
Coal Ash
(ppm)
60,000 - 157,000
10.4 - 169.6
210-310
14-618
7-10
3,100 - 125,600
3,000 - 163,000
900 - 60,200
ND-0.08
5.6-39.3
123 - 242
300 - 2,800
6,500-31,900
7.6-36.1
302,000-331,000
560 - 1,200
7,700-11,600
13 -378
Municipal Solid Waste
Ash
(ppm)
2.9-50
79 - 2,700
ND - 2.4
24 - 174
0.18-100
12 - 1,500
1.7-91
40 - 5,900
31 -36,600
700 - 16,000
14-3,130
0.05 - 17.5
2.4 - 290
13 - 12,910
0.1-50
12 - 640
92 - 46,000
Wood Ash
(ppm)
9-11.58
1-28.5
130 - 527
ND-2
1 - 16.9
1-16
382.35-3,200
43
0.7-4
16.8-33.55
4.6 - 20
31.3-176.5
0.08-6
7.7 - 142.5
ND-0.6
3.0-14
11 -50
23,220 - 59,918
ND-20
ND-4
934.25-3,110
ND-70.5
22-27
130 - 886
Source: Evangelou, 1996; Otero-Rey, 2003; Narukawa, 2003; Kirk-Othmer, 2000a; CEP A, 2006b; WAI 2003.
ND - Not detected.
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Detailed Study Report - November 2006 Chapter 6 - Alternative-Fueled Steam Electric Facilities
Wood Solid Waste
Wood wastes combusted in steam electric processes typically consist of chipped
lumber and residuals from sawmills or other forest industry operations, including bark, trim ends,
sawdust, and planer shavings [Kirk-Othmer, 2000a].
EPA obtained data on the pollutant concentrations found in wood ash. As
described for MSW ash, EPA noted general differences between wood ash and coal ash. Wood
ash generally has a lower metal content (e.g., arsenic, boron, molybdenum, nickel, and selenium)
than coal ash; however, as shown in Table 6-1, wood ash often contains higher amounts of
potassium and zinc, and may contain slightly higher amounts of barium, cadmium, and mercury,
than coal ash.
In the 1982 Development Document, EPA acknowledged that wood, sugar cane,
and other crops could be combusted in coal-type boilers and that".. .the utilization of biomass
materials as a heat source for steam electric generation will increase as demands are placed on
the coal industry to provide cleaner fuel at low prices." [U.S. EPA, 1982] This statement implies
that combusting these products result in cleaner emissions to air than those of coal combustion.
Agricultural By-Products
Typical types of agricultural by-products combusted in steam electric processes
include bagasse (plant residue) from sugar-refining operations, rice hulls, orchard and vineyard
prunings, cotton gin trash, and the by-products of many other food and fiber-producing
operations. Agricultural wastes are relatively low in metals content, and the ash often contains a
lower metals content than coal and wood ash [Kirk-Othmer, 2006a].
Tires
Scrap tires can be combusted in steam electric processes either in shredded form,
which is known as tire-derived fuel, or whole tires. Scrap tires, which have a high heating value,
are often used as a supplement to other fuels, such as coal or wood. Tires produce roughly the
same amount of energy as oil and roughly 25 percent more energy than coal, by weight. The ash
residues from tire-derived fuel may contain lower heavy metals content than some coals [U.S.
EPA, 20061].
6.1.2 Gaseous Fuels
Steam electric facilities fueled by gaseous alternative fuels (e.g., landfill gas and
blast-furnace gas) use a similar (if not identical) process as those facilities that are fueled by
natural gas and are currently regulated under 40 CFR Part 423. These alternative-fueled steam
electric facilities combust a gaseous fuel in a boiler to produce steam; however, like the natural
gas combustion process, the gaseous alternative fuel combustion process does not generate ash.
The steam produced powers a steam turbine/electric generator. The steam exiting the turbine is
condensed with cooling water and the condensate is typically fed back to the boiler. Thus, steam
electric facilities fueled by gaseous alternative fuels generate the same types of wastewaters as
those currently regulated under 40 CFR Part 423 and described in Section 3.2.1, except for fly
ash and/or bottom ash sluice (slurry).
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Detailed Study Report - November 2006 Chapter 6 - Alternative-Fueled Steam Electric Facilities
The following subsections describe the types of gaseous alternative fuels included
in EPA's study of alternative-fueled steam electric facilities.
Landfill Gas
Landfill gas consists approximately 50 percent methane and 50 percent inerts,
which is generated in landfills as bacteria degrade organic matter. This gas mixture can be
captured and processed for use as fuel in steam electric plants. During processing, a portion of
the inerts are typically removed from landfill gas, which results in a fuel with a higher heating
value [U.S. EPA, 2006J] [CEC, 2006]. A steam electric plant fueled with landfill gas is similar
to a steam electric plant fueled with natural gas in terms of fuel composition (natural gas and
landfill gas are both comprised primarily of methane) and overall process. [PDEP, 2006]
Blast Furnace Gas
Blast furnace gas is the waste gas generated in a blast furnace when iron ore is
reduced to metallic iron using coke. Blast furnace gas has a relatively low heating value because
it largely comprises nitrogen, carbon monoxide, and carbon dioxide. It is often combined with
natural gas for combustion in steam electric processes. All steam electric facilities that reported
using blast furnace gas as a primary energy source in the 2002 EIA database reported using a
fossil fuel as the secondary energy source. Blast furnace gas may be used in steam electric
boilers to ensure combustion of carbon monoxide to meet emissions regulations, and to generate
steam from the combustion of the blast furnace gas and/or from the waste heat from the blast
furnace.
6.1.3 Geothermal
In the geothermal steam electric process, geothermal fluids (typically steam) are
extracted from geothermal reservoirs and are used to power steam turbine/electric generators.
No fuels are combusted to produce steam. Steam exiting the turbines is condensed with cooling
water and the condensate is injected into the geothermal reservoir. Geothermal steam electric
plants generate steam condensate wastewater and condenser cooling wastes (typically cooling
tower blowdown) [CEPA, 2006c].
EPA addressed geothermal electric generation in developing both the 1974 and
1982 Steam Electric ELGs. The 1982 Development Document states that geothermal fluids are
disposed of by reinjection to the subsurface geothermal reservoir after use [U.S. EPA, 1982].
Permit writers confirmed this statement, indicating that geothermal steam electric plants do not
typically have NPDES permits because they do not discharge their wastewater to surface waters
[CEPA, 2006c] [CEPA, 2006d]. These facilities inject wastewater underground into the
geothermal steamfield reservoirs for two major reasons [CEPA, 2006c] [CEPA, 2006d] [U.S.
DOE, 2006d]. First, injecting water into the steamfield reservoirs is required to maintain steam
production [CEPA, 2006c] [U.S. DOE, 2006d]. Second, the geothermal steam condensate from
the steam electric generating process contains high levels of salts and metals, specifically arsenic
and boron, which would be costly to remove to meet limits for discharge to surface waters
[CEPA, 2006c] [CEPA, 2006d].
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Detailed Study Report - November 2006 Chapter 6 - Alternative-Fueled Steam Electric Facilities
If discharged to surface waters without treatment, geothermal wastewaters would
significantly impact the environment due to the high salts and metals concentrations. According
to the Geothermal Energy Association, the geothermal industry takes steps to prevent
contaminating groundwater as geothermal condensate is piped down to geothermal reservoirs.
This injection is "regulated by the EPA to coincide with the Underground Injection Control
Program requirements and the BLM [Bureau of Land Management] and state well construction
requirements." [GEA, 2006]
6.1.4 Solar
Solar electric generating plants concentrate sunlight onto receivers using various
reflecting devices. Heat transfer fluid is heated as it flows through the receivers and is used to
create steam, which, in turn, is used to create electricity in conventional steam
turbine/generators. Most solar electric plants that use parabolic trough reflectors to concentrate
sunlight (such as the Solar Electric Generating Stations (SEGS) plants in the Mojave Desert, CA)
create cooling water, boiler blowdown, and demineralizer wastewater. These wastewaters are
typically discharged to an evaporation pond [U.S. DOE, 2006b]. Many solar electric plants burn
natural gas when necessary to meet electrical demands [U.S. DOE, 2006b] [Kirk-Othmer,
2000b].
According to the 1982 Development Document, all solar electric generating
plants at that time were developmental; however, EPA acknowledged that more systems would
be developed in the future as traditional fossil fuels were depleted [U.S. EPA, 1982].
6.1.5 Summary of NPDES Permit Review
Below is a breakout of the types of alternative fuels used by the 13 alternative fuel
facilities whose NPDES permits EPA reviewed (number of permits reviewed):
• Municipal solid waste (4);
• Wood waste (4);
• Agricultural by-products (1);
• Blast furnace gas (1);
Tires (1);
• Landfill gas (1); and
• Geothermal (1).
Based on the limited number of permits reviewed and communications with
permitting authorities, 40 CFR Part 423 (i.e., 423-based) limits and other requirements do not
appear to be consistently applied to wastewaters generated by alternative-fueled processes. EPA
was not able to determine any trends in the regulation of wastewaters based on alternative fuel
type; however, EPA was able to make some general observations about types of wastewaters and
determine some general trends in the way the wastewaters are regulated.
EPA found that some of the permits reviewed contained relatively few 423-based
limits. In each of these cases, the process wastewaters are not discharged to surface waters.
Specific examples include geothermal electric wastewaters that are reinjected into underground
geothermal reservoirs, agricultural by-product-fueled steam electric wastewaters that are
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Detailed Study Report - November 2006 Chapter 6 - Alternative-Fueled Steam Electric Facilities
discharged to percolation ponds (these are permitted via state groundwater monitoring program),
and other process wastewaters from indirect dischargers.
In most cases for direct dischargers, the majority of the applicable steam electric
parameters are regulated with BPJ limits. The bases used for these BPJ limits vary, and may
include 40 CFR Part 423 or more stringent state water quality standards, or general permitting
requirements. The basis for parameter selection is generally the state water quality standards.
Specifically, for condenser cooling wastewaters of direct dischargers, chlorine discharges are
limited in some fashion, but zero discharge of priority pollutants is not addressed in multiple
permits.
A small portion of the permits wholly incorporated the requirements of 40 CFR
Part 423. These permits are unique in that the facilities use a fossil fuel in addition to the
alternative fuel to generate electricity, or the permit only specifies the use of a fossil fuel. In at
least one of these cases, the fossil-fueled steam electric wastewaters have separate limits then the
alternative-fueled steam electric wastewaters.
Roughly half of the permits reviewed indicated that the facility does not directly
discharge all of its wastewater. For example, some wastewaters are discharged indirectly,
discharged to percolation ponds, or recycled. In one case, a landfill gas-fueled steam electric
facility uses water supplied by a neighboring steel plant for its boilers. The steam electric
facility in turn, transfers its boiler blowdown wastewater back to the steel plant.
6.2 Demographic Data
The 2002 EIA database identifies 207 facilities that reported a NAICS code of 22
(Utilities) and the use of an alternative fuel as a primary energy source to drive a steam turbine.
Some of these facilities use alternative fuels in combination with a fossil- or nuclear-type (i.e.,
423-type) fuel. Three of the 207 steam electric facilities report a fossil fuel as a primary energy
source, in addition to an alternative fuel. Approximately 33 percent of the 207 facilities report
using both an alternative fuel and a fossil fuel to power the same generator (the fossil fuel is
reported as the secondary or tertiary energy source).
The average alternative energy capacity for alternative-fueled facilities in the
2002 EIA database is less than 50 MW. Excluding geothermal steam electric facilities, the 162
alternative-fueled facilities produce less than one percent of the electricity produced by the fossil
or nuclear-fueled steam electric facilities currently regulated by 40 CFR 423. EPA did not
include geothermal steam electric facilities in this calculation because they are generally
assumed not to discharge wastewater [CEPA, 2006c] [CEPA, 2006d] [U.S. DOE, 2006d]. Table
6-2 presents a breakdown of facility energy capacity by fuel type. See Section 3.3.2 of this
report for additional detail on the demographics of the regulated steam electric industry.
EPA is not aware of any analyses demonstrating that pollutant loadings are
correlated to electric power generated; however, EPA believes it is reasonable to assume that
alternative-fueled facilities will produce smaller pollutant loadings than those produced by steam
electric facilities with energy capacities that are one or two orders of magnitude larger.
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Detailed Study Report - November 2006
Chapter 6 - Alternative-Fueled Steam Electric Facilities
Table 6-2. Summary of Alternative-Fueled Steam Electric Facilities, by Fuel/Energy
Source Type
Fuel/Energy Source
Number of Facilities
Total Steam Turbine Capacity
(MW)
Regulated Steam Electric Industry
Fossil and Nuclear Fuel
1,157
621,799
Alternative-Fueled Steam Electric Facilities
Municipal Solid Waste
Wood Solid Waste
Landfill Gas
Solar
Agricultural By-products
Blast-Furnace Gas
Other
Tires
Other Biomass Solids
Other Gas
Total for Alternative-Fueled Facilities
(excluding Geothermal)
Geothermalb
66
63
11
9
6
2
1
2
1
1
162a
45
2,586
1,726
212
410
249
152
78
57
18
3
5,491
2,987
Source: U.S. DOE, 2002a.
alt is possible that some of these 162 alternative-fueled facilities may be cogeneration facilities, as discussed in
Section 3.2.1.
bSteam electric processes using geothermal energy sources are assumed not to generate wastewater [CEPA, 2006c]
[CEPA, 2006d] [U.S. DOE, 2006d].
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Detailed Study Report - November 2006 Chapter 6 - Alternative-Fueled Steam Electric Facilities
6.3 Summary
Information obtained from EPA's NPDES permit review and literature search
indicate that steam electric plants that combust an alternative fuel within a boiler utilize a similar
(if not identical) process as those facilities currently regulated under 40 CFR 423 that combust a
fossil fuel to generate steam. Many of these alternative-fueled plants also combust fossil fuels to
generate the steam, typically within the same generating unit. This indicates a similarity between
the combustion side of alternative-fueled processes and the typical regulated steam electric
process. This also indicates that differences in the wastewaters, originating from the combustion
side of the alternative-fueled and regulated steam electric processes, are likely due to pollutants
originating from the fuel source.
Additionally, information obtained from EPA's study of alternative-fueled steam
electric facilities indicates that these facilities use condenser cooling systems that are similar to
those used by regulated steam electric facilities. The NPDES permit review indicates that
biocides are used in these cooling systems and the direct discharges are limited by NPDES
permit limits for alternative-fueled facilities; therefore, the characteristics of the cooling system
wastewaters of alternative-fueled steam electric facilities are likely similar to those of regulated
steam electric facilities.
Based on EPA's limited permit review, 423-based limits and other requirements
do not appear to be consistently applied to wastewaters generated by alternative-fueled
processes. While some of the permits reviewed for the study contained limits on the steam
electric pollutants of interest, not all of the pollutants are addressed. Additional data are needed
to fully characterize the pollutants/concentrations in the wastewaters from the cooling water
systems and the combustion/boiler side of the steam electric process for alternative-fueled
systems types to determine their similarity to fossil-fueled steam electric wastewaters, and
whether there are significant concerns with their discharge.
Available data from the 2002 EIA indicate that alternative-fueled steam electric
facilities are not contributing a large amount of electricity compared to the regulated steam
electric industry and are not likely discharging a significant amount of wastewater to the
environment. Little information has been collected, however, about the pollutants and associated
concentrations in the wastewater discharged from steam electric processes using these various
types of alternative fuels.
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Detailed Study Report - November 2006 Chapter 7 - Steam & Air Conditioning Supply Facilities
7.0 STEAM AND AIR CONDITIONING SUPPLY FACILITIES
EPA develops ELGs for specific categories of industrial dischargers (i.e., point
source categories). The point source categories, which may be divided into sub categories, are
generally defined by the products made or services rendered and the processes used to make
these products or provide these services. As part of the 304(m) review process, EPA conducts
screening-level analyses using existing environmental data in the PCS and TRI databases to
investigate discharges from industrial point source categories and prioritize these categories for
additional review [U.S. EPA, 2005a].
Facilities with data in PCS and TRI are identified by a four-digit SIC code;
however, most point source categories are not defined by SIC code, but by a description of the
wastewater pollutant generating activity. During screening-level analyses, EPA investigates SIC
codes reported by facilities with discharge information in PCS and TRI and divides the SIC
codes into groupings, generally according to whether the industry is already regulated by existing
ELGs. One of these groupings is Potential New Subcategories of Existing Point Source
Categories, which includes industry sectors not subject to existing ELGs. EPA then considers
whether the industry's processes, operations, and wastewaters generated are such that it would be
appropriately included as a new subcategory of an existing point source category.
During the 2005 screening-level review, EPA identified SIC codes 4939 and 4961
as potential new subcategories of the Steam Electric Power Generating Point Source Category at
40 CFR 423. SIC code 4939 facilities are utilities providing a combination of electrical, gas, and
other services. SIC code 4961 facilities are steam and air conditioning suppliers producing
and/or distributing steam and heated or cooled air for sale [U.S. EPA, 2005a].
In determining whether these two industrial sectors are appropriate subcategories
to the Steam Electric Power Generating Point Source Category, EPA examined available data
and information on the processes and sources of wastewater generated by the candidate sector, as
well as the potential pollutants contained in those wastewaters. EPA then determined whether
the characteristics of the processes and wastewater are similar enough to those of the currently
regulated steam electric industry to add the industrial sector as a new subcategory to the ELGs.
Chapter 8 discusses EPA's study of the Combination Utilities, NEC sector (SIC
code 4939). This chapter discusses the Steam and Air Conditioning Supply sector (SIC code
4961) and the results of EPA's examination of the processes and wastewaters that are generated
by steam supply facilities.
7.1 Overview of the Steam and Air Conditioning Supply Sector
According to the 2002 Economic Census, 63 establishments are engaged in steam
and air conditioning supply24 in the United States [USCB, 2002]. Examples of facilities within
the Steam and Air Conditioning Supply sector include the following:
24 The 2002 Economic Census is based on NAICS. The NAICS code for steam and air conditioning supply (22133)
corresponds directly to SIC code 4961.
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Detailed Study Report - November 2006 Chapter 7 - Steam & Air Conditioning Supply Facilities
• Air conditioning supply services;
• Cooled air suppliers;
• Distribution of cooled air;
• Chilled water suppliers;
• Geothermal steam production;
• Steam heating systems (suppliers of heat); and
• Steam supply systems, including geothermal.
Many of these facilities generate steam; however, this steam is not typically used
to generate electricity. Thus, many steam supply facilities would be regulated by 40 CFR Part
423 if not for the language at 40 CFR 423.10 limiting the applicability to facilities "primarily
engaged in the generation of electricity."
7.2 Summary of Available Data and Information
This section summarizes data and information that were available for the Steam
and Air Conditioning Supply sector during EPA's study of this sector. EPA reviewed data for
SIC code 4961 reported to PCS and TRI. To obtain additional information about electric
generators the facilities in this SIC code may be operating, EPA matched these facilities to those
that reported to EIA. EPA also reviewed selected NPDES permits for the steam supply facilities
that were identified in PCS.
These sources provided information about potential types of wastewater generated
by steam supply facilities, as well as the relative number of these facilities that are likely to
generate and discharge wastewater. For those wastewater-generating steam supply facilities
included in PCS, EPA examined the typical flow rates reported and wastewater parameters
currently regulated for this industry.
7.2.1 Permit Compliance System
EPA extracted all data reported to PCS for facilities within SIC code 4961.
Seventeen steam and air conditioning supply facilities reported to PCS in 2002 [U.S. EPA,
2006a] and only one of these facilities is classified as a major discharger. Table 7-1 summarizes
these facilities along with their calculated total TWPE loads. See the 2005 Annual Screening-
Level Analysis report [U.S. EPA, 2005a] for discussion of EPA's method of calculating TWPE.
Table 7-1 also indicates whether chlorine, TRO, chlorine-produced oxidants (CPO), or metal
parameters are discharged from the facility.
7-2
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Detailed Study Report - November 2006 Chapter 7 - Steam & Air Conditioning Supply Facilities
Table 7-1. Steam and Air Conditioning Supply Facilities Identified in 2002 PCS Database
NPDES ID
CO0039551
CT0004014
DC0000035
IL0072320
MD0061930
MD0065986
MD0066249
MD0066877
NJO 109673
OK0002461
SC0045560
SD0025445
SD0025569
SD0025798
SD0026026
TN0065447
TX0008851
Name
Pitkin Iron Corporation
Hartford Steam Co.c'd
GSA-NCR Hold (Central Htg Pit)
SIU-Carbondaled
Trigen-Energy Baltimore
Baltimore City Housing Auth.
Trigen-Baltimore Energy Corp.d
Trigen-Energy Baltimore"1
Central Heat Plant Bldg 2401
Trigen-Tulsa Energy Corpd
Council Energy
St Mary's Hospital
Haakon School District No 27-1
St Joseph's Indian School
Edgemont, City Of - Geothermal
Nashville Thermal Transfer Cor
Texas Medical Central
City
Glenwood Springs
Hartford
Washington
Carbondale
Baltimore
Baltimore
Baltimore
Baltimore
New Hanover Township
Tulsa
Orangeburg
Pierre
Philip
Chamberlin
Edgemont
Nashville
Houston
Total Load
(TWPE)a
0
2,386
0
0.323
0
0
0.000514
0.0218
0
0.718
0
0
0
0
0
0
0
Cl/TRO/CPO
Reported1"
TRO
Cl
CPO
Cl
Metals
Reported
Zn, Cu, Pb
Fe
Cu
Source: U.S. EPA, 2006a.
aEPA was able to calculate TWPE loads for five facilities reporting concentration and flow data for pollutants for which EPA has developed a TWF. Zero (0)
TWPE loads indicate either the facility did not report both concentration and flow data and/or the facility reported only parameters for which EPA has not
developed a TWF (e.g., TSS, BOD5).
bCl - Chlorine; TRO - Total residual oxidants; and CPO - Chlorine produced oxidants (EPA has not developed TWFs for TRO and CPO; therefore, these loads
are not included in TWPE totals).
°This facility is a major discharger.
dThe NPDES permits for the facilities shown in bold were reviewed by EPA for the detailed study.
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Detailed Study Report - November 2006
Chapter 7 - Steam & Air Conditioning Supply Facilities
While there are records in the PCSLoads2002 database for 17 steam and air
conditioning supply facilities, not all of these facilities reported both wastewater flow and
pollutant concentration data. Therefore, EPA was able to calculate loads for only 14 of the 17
steam and air conditioning supply facilities reported in PCS. Table 7-2 presents the calculated
pollutant loads for these 14 facilities.
Table 7-2. PCS 2002 Pollutant Loads for Steam and Air Conditioning Supply Facilities
Pollutant
Copper
Lead
Zinc
Chlorine
Iron
Sulfate
Total Dissolved Solids
Chemical Oxygen Demand
Total Suspended Solids
Oil and Grease
BOD5
Dissolved Oxygen
Total Residual Oxidants
Chlorine Produced Oxidants
Total Organic Carbon
Hydrocarbons, IN H2O,IR,CC14 Ext.
Chromat.
Petrol Hydrocarbons, total
Total
Number of
Facilities
Reporting Load
2
1
1
2
1
1
4
3
11
4
3
1
1
1
1
1
1
14
Load
(Ibs/year)
1,931
503
706
1.45
51
6,735
9,681,114
35,128
31,477
4,465
1,919
1,402
540
39
36
17
o
J
9,766,068
TWPI
(% of Total TWPE)
1,226
(51%)
1,127
(47%)
33
(1.4%)
0.74
(0.03%)
0.29
(0.01%)
0.04
(0.001%)
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
2,387
Source: U.S. EPA, 2006a.
NA - Not applicable. EPA has not developed TWFs for these pollutant parameters.
EPA was able to calculate TWPE loads for five of the 14 facilities, as these
facilities reported flow and concentration data for pollutants for which EPA has developed
TWFs. The total TWPE discharged by these five facilities is 2,387 pound equivalents (Ib-eq),
which is approximately 0.2 percent of the TWPE discharged by electric generating facilities
within SIC codes 4911 and 493125. Copper, lead, and zinc account for greater than 99 percent of
the total TWPE reported by steam and air conditioning supply facilities. One company, the
25 The total TWPE reported for the electric generating industry (i.e., facilities within SIC codes 4911 and 4931, as
described in Section 5.1) was approximately 1.1 million Ib-eq in 2002 [U.S. EPA, 2006a].
7-4
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Detailed Study Report - November 2006 Chapter 7 - Steam & Air Conditioning Supply Facilities
Hartford Steam Company, reported more than 99 percent of the total reported TWPE. As
described in Section 7.2.4, this facility supplies steam and chilled water, but does not produce
electricity.
According to the 2002 PCS data, 15 of the 17 steam and air conditioning supply
facilities reported nonzero wastewater discharge flows that ranged between 0.2 and 20,691
million gallons per year (MGY). The facility flows averaged 1,430 MGY, which is significantly
less than a typical electric generating facility26.
The PCS data have some limitations. In particular, only the parameters regulated
by the facilities' NPDES permits are reported in PCS. In addition, not all minor discharge data is
reported in PCS27. EPA estimates that the PCS data represent approximately 27 percent of the
Steam and Air Conditioning Supply sector, based on the 2002 Census data for this SIC code.
Although EPA acknowledges that the PCS wastewater data are limited, this small percentage of
steam and air conditioning supply facilities contained in PCS also indicates that much of this
industry either does not generate wastewater or comprises minor dischargers that are not
included in PCS.
7.2.2 Toxics Release Inventory
EPA extracted data reported to TRI in 2002 for all facilities within SIC code
4961. Only one steam and air conditioning supply facility reported to TRI in 2002; however, it
reported no discharge of TRI chemicals to water [U.S. EPA, 2006b].
7.2.3 Energy Information Administration
As discussed in Section 3.3.2, the EIA annually collects detailed information from
facilities that operate electric generators producing one MW or more of electricity. The data
include facility type, generator type, fuel/energy source, and capacity; however, facilities are
classified either as Utilities28 (NAICS code 22) or within another industrial sector (i.e., industrial
non-utilities; see Chapter 9).
To estimate the number of steam and air conditioning supply facilities that operate
an electric generator, EPA searched the 2002 EIA database [U.S. DOE, 2002a] for each of the 17
steam and air conditioning supply facilities identified in the PCS database. By matching parent
companies, facility names, and locations, EPA was able to identify 1 of the 17 PCS steam and air
conditioning supply facilities within the 2002 EIA data. According to the EIA, the Hartford
Steam Company, the only major discharger identified in PCS, operated a natural gas-powered
steam generator in 2002; however, EPA determined that this is not the case, based on
information contained in the facility's NPDES permit (Section 7.2.4 discusses this in more
detail).
26 The average flow rate reported by the electric generating industry (i.e., facilities within SIC codes 491 1 and 493 1,
as described in Section 5.1) was approximately 70,000 MGY [U.S. EPA, 2006a].
Data for minor dischargers are reported to PCS by the permitting authorities, at their discretion.
27
28 NAICS code 22 - Utilities is defined as establishments providing the following utility services: electric power,
natural gas, steam supply, water supply, and sewerage removal. Excluded from this sector are establishments
primarily engaged in waste management services [USCB, 2002].
7-5
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Detailed Study Report - November 2006 Chapter 7 - Steam & Air Conditioning Supply Facilities
7.2.4 NPDES Permit Review
In researching the operations, waste streams, and existing discharge requirements
currently applied to steam and air conditioning supply wastewaters, EPA reviewed NPDES
permits for 5 of the 17 steam and air conditioning supply facilities identified in the 2002 PCS
database. These five facilities reported both flow and concentration data to PCS in 2002
(facilities are shown in bold print in Table 7-1).
All five facilities generate steam; however, none use the steam to generate
electricity. Some of the facilities produce chilled water in addition to steam. The five facilities
generate wastewaters that are similar to those of a steam electric utility, including boiler
blowdown, coal pile runoff, and cooling tower blowdown. The cooling water waste streams and
cooling tower blowdown listed in some the permits may be associated with the chilled water
production process.
Some of the permits reviewed showed that 40 CFR 423 standards were used as
the basis for BPJ limits, although not all of the steam electric regulated pollutants are necessarily
included in the steam and air conditioning supplier permits. Only one permit includes a
limitation on TRC and two permits include only monitoring requirements for either TRC or
TRO.
Upon review of the permit for the Hartford Steam Company, EPA learned that, in
addition to steam and chilled water production, the facility used to generate electricity with
excess steam; however, the electricity generation portion of the process has been closed since
1995. The permit has retained the limits of 40 CFR 423 as the basis for the current wastewater
discharge requirements. This facility continues to report significant discharges of TRO, zinc,
copper, and lead in PCS. This facility also reports a total discharge flow rate that is two orders
of magnitude greater than the next highest flow rate reported by another steam and air
conditioning supplier, and is the same order of magnitude as the average flow rate reported by
steam electric utilities within SIC codes 4911 and 493129.
7.3 Conclusion
The steam production processes and wastewater pollutants of steam and air
conditioning suppliers are likely to be similar to those generated by the steam electric generating
units regulated under 40 CFR 423; however, it appears that there are relatively few of these
facilities in the United States (according to the 2002 Economic Census, there are only 63)
[USCB, 2002]. In addition, it appears that the wastewater discharge rates from this industry are
significantly less on average than those of electricity generators within SIC codes 4911 and
4931. EPA has not identified data demonstrating that these steam and air conditioning supply
facilities are discharging significant loadings of toxic pollutants, and therefore concludes that
revising the applicability of 40 CFR Part 423 to include these facilities is not warranted at this
time.
29 The average flow rate reported by the electric generating industry (i.e., facilities within SIC codes 4911 and 4931,
as described in Section 5.1) was approximately 70,000 MGY [U.S. EPA, 2006a].
7-6
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Detailed Study Report - November 2006 Chapter 8 - Combination Utility Wastewaters
8.0 COMBINATION UTILITY WASTEWATERS
As described in Chapter 7, in the 2005 Screening-Level Analysis report [U.S.
EPA, 2005a], EPA reviewed discharge information reported by facilities within SIC codes 4939
and 4961 to TRI and PCS to determine if these facilities have operations and wastewater
characteristics similar enough to those in the Steam Electric Power Generating Point Source
Category, to consider these two industry sectors (or certain facilities within the sector) as
potential new subcategories.
Chapter 7 of this report discusses EPA's study of the Steam and Air Conditioning
Supply sector (SIC code 4961). This chapter describes the Combination Utilities, NEC sector
(SIC code 4939) and the results of EPA's examination of the processes and wastewaters
generated by steam supply facilities.
8.1 Overview of the Combination Utilities, NEC Sector
As previously described in Section 3.1.2, Combination Utilities, NEC are defined
by the U.S. Census Bureau (USCB) as:
"Establishments primarily engaged in either providing electric services in
combination with other services, with electric service as the major part though
less than 95 percent of the total or providing gas services in combination with
other services, with gas services as the major part though less than 95 percent."
[USCB, 2000]
According to the USCB's Comparative Statistics, there were 1,989 combination
utilities in the United States in 1997 [USCB, 2000]; however, not all of these facilities are
relevant to the detailed study. By definition, the Combination Utilities, NEC sector comprises
facilities that perform services other than electric power generation, and more specifically
services other than steam electric power generation.
Based on the screening-level analysis, EPA determined that the wastewaters
generated by facilities classified as Combination Utilities, NEC (SIC code 4939) are not
currently subject to existing ELGs; however, Combination Utilities, NEC by definition includes
facilities that generate electric power, albeit in combination with providing other utility services.
Because at least a portion of these facilities are expected to be engaged in the generation of
electricity for distribution and sale [40 CFR 423.10], EPA determined that the electric
generating activities performed at some combination utilities might be appropriately addressed as
a new subcategory to the Steam Electric Power Generating Point Source Category. In the
screening-level analysis, EPA also examined the pollutants reported in TRI and PCS to be
discharged by these facilities and determined that they are similar to those discharged by the
currently regulated steam electric industry [U.S. EPA, 2005a].
For these reasons, EPA included combination utilities in the detailed study to
determine whether it would be appropriate to revise the scope of the Steam Electric ELGs to
include such facilities.
8-1
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Detailed Study Report - November 2006 Chapter 8 - Combination Utility Wastewaters
8.2 Summary of Available Data and Information
This section summarizes data and information that were available for the
Combination Utilities, NEC sector. EPA reviewed data for SIC code 4939 reported to TRI and
PCS and matched applicable facilities found in these databases to those that reported to EIA to
obtain additional information about electric generators they may be operating. EPA also
reviewed a select number of NPDES permits for the combination utilities identified in PCS.
These sources provided information about potential types of wastewater generated
by combination utilities, as well as the relative number of these facilities that are likely to
discharge wastewater. For those combination utilities included in PCS that reported wastewater
discharges, EPA examined the typical flow rates reported and wastewater parameters currently
regulated by their NPDES permits.
8.2.1 Toxics Release Inventory
EPA extracted data reported to TRI in 2002 for all facilities within SIC code
4939. Only eight combination utilities reported to TRI, and of these, only one reported a direct
release to water (barium and barium compounds with a TWPE of 0.003). The remaining seven
reported no discharge of a TRI chemical to water [U.S. EPA, 2006b]. TRI does not specifically
identify the process source(s) of the wastewater and pollutants discharged.
8.2.2 Permit Compliance System
EPA also extracted all data reported to PCS in 2002 for facilities within SIC code
4939. PCS contains data for 21 combination utilities, all classified as minor dischargers [U.S.
EPA, 2006a]. Table 8-1 summarizes these facilities along with their total TWPE loads reported
in the database. The 2005 Annual Screening-Level Analysis report [U.S. EPA, 2005a] discusses
EPA's method of calculating TWPE. Table 8-1 also indicates whether chlorine or metal
parameters are monitored at the facility.
While the PCSLoads2002 database has records for 21 combination utilities, not
all of these facilities reported wastewater flow and pollutant concentration data to determine
pollutant loads. EPA was able to calculate loads for 16 of the 21 combination utilities reported
in PCS. Table 8-2 summarizes the total load and TWPE for each pollutant reported by these 16
combination utilities. The pollutants reported most often by these facilities were TSS, BOD5,
and ammonia.
The total TWPE discharged by these 16 facilities is approximately 1,700 Ib-eq,
less than 0.2 percent of the TWPE discharged by electric generating facilities within SIC codes
4911 and 493130. Nearly all of the TWPE (99 percent) was reported for chlorine and nitrate
discharges by four facilities.
30 The total TWPE reported for the electric generating industry (i.e., facilities within SIC codes 4911 and 4931, as
described in Section 5.1) was approximately 1.1 million Ib-eq in 2002 [U.S. EPA, 2006a].
8-2
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Detailed Study Report - November 2006
Chapter 8 - Combination Utility Wastewaters
Table 8-1. Combination Utilities Identified in 2002 PCS Database
NPDES ID
AR0034363
CO0042447
CO0044580
IL0042625
IL0045527
IL0045535
IL0045543
IL0048593
IL0052817
IL0059072
IL0059391
IL0070904
IL0071030
NE0124133
NY0005894
NY0106259
NY0201138
NY0226416
NY0259055
Name"
*Shumaker Public Service Corporation0
*Tri-State Generation and Transmission
Association0'"1
Colorado Springs, City Of
Lake Arispie Water Co, Inc.
Consumers 11 Water-Candlewick
* Consumers Illinois Water Company -
Woodhaven Division0
Aqua Illinois-Woodhaven
Otter Creek Lake Utility Stp
Stonewall Utility Co Stp
Illinois Power-Hydrostatic
Cedar Bluff Utilities, Inc.
Lone Oak Subdivision Stp
Emmett Utilities Inc. Stp
Sargent Underground Tank
Glenwood Landing Energy Center°'d
American Ref-Fuel Niagara Lp°'d
1 1th Street Conduit
Freeport (V) Power Plant #2d'e
Dte Tonawanda LLC
City
East Camden
Rifle
Colorado Springs
Princeton
Poplar Grove
Sublette
Sublette
Davis
Oakbrook Terrace
Decatur
Dunlap
Murphysboro
Colchester
Sargent
Glenwood Landing
Niagara Falls
New York
Freeport
Buffalo
Total Loadb
(TWPE)
103
130
0
0
0.371
0.117
0.0972
0.226
0.211
0
0.0103
0.00859
0
0
0.0175
6.74
0.0588
0.00128
0
Chlorine
Reported
Cl
Cl
Cl
Metals
Reported
Zn
Cr-6, Fe, Zn
Fe
Al, Cr, Cu, Fe, Zn
oo
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Detailed Study Report - November 2006
Chapter 8 - Combination Utility Wastewaters
Table 8-1 (Continued)
NPDES ID
OH0041335
TX0054038
Name"
*Shelly Materials, Inc. - Price Inland
Terminal0
*Matagorda Waste Disposal and Water
Supply Corporation0
City
Belpre
Matagorda
Total Loadb
(TWPE)
0.0135
1,443
Chlorine
Reported
Cl
Metals
Reported
Mn
oo
Source: U.S. EPA, 2006a.
aEPA was able to calculate TWPE loads for 14 facilities reporting concentration and flow data for pollutants for which EPA has developed a TWF. Zero (0)
TWPE loads indicate that either the facility did not report both concentration and flow data and/or that the facility only reported parameters for which EPA has
not developed a TWF (e.g., TSS, BOD5).
bPlant names appear in the table as they do in the 2002 PCS data extraction, unless the complete name was available in the NPDES permit (see Note c).
facilities shown in bold were targeted by EPA for NPDES permit review. EPA was able to acquire and review five of these permits for the detailed study.
These five permits are denoted with an asterisk (*) in the table.
dThese combination utilities were also identified in the 2002 EIA database (refer to Table 8-3).
According to the 2002 EIA data, this combination utility does not operate a steam electric generating unit; therefore, EPA did not select this facility for NPDES
permit review.
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Detailed Study Report - November 2006
Chapter 8 - Combination Utility Wastewaters
Table 8-2. PCS 2002 Pollutant Loads for Combination Utilities, NEC
Pollutant
Chlorine
Nitrogen, Total Nitrate (as N)
Zinc
Nitrogen, Ammonia
Aluminum
Copper
Chloride
Iron
Hexavalent Chromium
Sulfate
Chromium
Manganese
Bis(2-Ethylhexyl)phthalate
Hexachlorcyclopentadiene
Benzene
Xylene
Toluene
Ethylbenzene
Phenol and Phenolics
Total Dissolved Solids
Total Suspended Solids
BOD5
Dissolved Oxygen
Oil & Grease
Total Priority Volatiles
Base/Neutral Compounds
Total
Number of Facilities
4
1
3
9
1
1
1
3
1
1
1
1
1
1
2
3
3
2
1
1
15
9
2
1
1
1
16
Total Load
0bs)
3,027
39,227
148
2,421
28
4
29,839
183
1
26,353
2
2
0.4
0.1
1
3
1
2
0.09
850,993
44,710
18,796
16,677
1,322
3
3
1,033,748
Total Load
(TWPE)
1,541
126
7
3
2
2
1
1
1
0.1
0.1
0.1
0.1
0.1
0.04
0.01
0.006
0.003
0.003
NA
NA
NA
NA
NA
NA
NA
1,684
Source: U.S. EPA, 2006a.
NA - Not applicable. EPA has not developed toxic weighting factors for these pollutant parameters.
8-5
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Detailed Study Report - November 2006 Chapter 8 - Combination Utility Wastewaters
Several pollutants that are characteristically found in steam electric process
wastewaters are discussed in Section 5.2. Several of these are reported to be discharged by
combination utilities, including zinc, copper, and aluminum. Chlorine, also a typical steam
electric wastewater pollutant, accounts for 92 percent of the TWPE; however, it was only
reported to be discharged by four facilities.
According to the 2002 PCS data, 16 of the 21 combination utilities reported non-
zero wastewater discharge flows that ranged between 0.6 and 177 MGY. The facility flows
averaged 51 MGY, which is significantly less than a typical electric generating facility31.
The PCS data does have some limitations. In particular, only the parameters
regulated by the facilities' NPDES permits are reported in PCS. In addition, not all minor
discharge data is reported in PCS32. EPA estimates that only one percent of the Combination
Utilities, NEC sector are represented in PCS, based on the 1997 USCB data for this SIC code.
Although it is acknowledged that the PCS wastewater data are limited, this small number of
combination utilities contained in PCS also indicates that much of this industry either does not
generate wastewater or comprises minor dischargers that are not included in PCS.
8.2.3 Energy Information Administration
As discussed in Section 3.3.2, the EIA annually collects detailed information from
facilities that operate electric generators producing one MW or more of electricity. The data
include facility type, generator type, fuel/energy source, and capacity; however, facilities are
classified either as Utilities33 (NAICS code 22) or within another industrial sector (i.e., industrial
non-utilities; see Chapter 9). The EIA database does not specifically identify facilities as
combination utilities.
To estimate the number of combination utilities that operate an electric generator,
EPA searched the 2002 EIA database [U.S. DOE, 2002a] for each of the 21 combination utilities
identified in thePCSLoads v.04 database [U.S. EPA, 2006a]. By matching parent companies,
facility names, and locations, EPA was able to identify 4 of the 21 PCS combination utilities
within the 2002 EIA data. Of these four combination utilities, three reported operating steam
electric generators. Table 8-3 summarizes the EIA data found for these four facilities.
31 The average flow rate reported by the electric generating industry (i.e., facilities within SIC codes 4911 and 4931,
as described in Section 5.1) was approximately 70,000 MGY [U.S. EPA, 2006a].
32 Data for minor dischargers are reported to PCS by the permitting authorities, at their discretion.
33 NAICS code 22 - Utilities is defined as establishments providing the following utility services: electric power,
natural gas, steam supply, water supply, and sewage removal. Excluded from this sector are establishments primarily
engaged in waste management services [USCB, 2002].
8-6
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Detailed Study Report - November 2006
Chapter 8 - Combination Utility Wastewaters
Table 8-3. Summary of EIA Data for Combination Utilities
Plant Name"
American Ref-Fuel of
Niagara b
Glenwoodb
Plant No. 2
*Rifle Generating Station b
Parent Company"
American Ref-Fuel Co.
Key Span Generation LLC
Freeport Village of Inc.
Tri-State Generation and
Transmission Association,
Inc.
State
New York
New York
New York
Colorado
Prime Movers
Steam turbines
Steam turbines
Combustion/gas
turbines
Internal combustion
engine
Combustion/gas turbine
Combined cycle
system
Primary Fuel
Municipal solid waste
Natural gas
Distillate fuel oil
Distillate fuel oil
Distillate fuel oil
Natural gas
Nameplate Capacity
(MW)
50
228
110
19.2
18.1
108.3
(39 MW from the
steam turbine)
oo
Source: U.S. DOE, 2002a.
aPlant and parent company names appear in the table as they do in the 2002 EIA database, unless the complete name was available in the NPDES permit (see
Note b).
facilities shown in bold were among those targeted by EPA for NPDES permit review (see also Table 8-1). EPA was able to acquire and review one of these
permits for the detailed study, which is denoted with an asterisk (*) in the table.
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Detailed Study Report - November 2006 Chapter 8 - Combination Utility Wastewaters
8.2.4 NPDES Permit Review
In researching the operations, waste streams, and existing discharge requirements
currently applied to combination utility wastewaters, EPA reviewed NPDES permits for a select
number of the 21 combination utilities identified in the 2002 PCS database.
Since the Combination Utilities, NEC sector includes facilities engaged in
operations and services other than electric power generation, EPA targeted the permit review on
combination utilities that were most likely to be generating electricity, based on available EIA
data and the pollutants reported to be discharged. EPA initially identified 7 of the 21
combination utilities for NPDES permit review:
1. The three fossil-fuel driven steam electric facilities identified in the 2002
EIA database;
2. Three facilities having the highest total TWPE (each greater than 100
TWPE); and
3. One additional facility that reported monitoring data for a metal
(manganese).
These seven facilities are shown in bold print in Tables 8-1 and 8-3.
After searching public web sites and contacting state permitting authorities
directly, EPA acquired NPDES permits for five of the seven targeted facilities.
EPA found through the permit review that only one of the five combination
utilities is an electric generating facility. The Tri-State Generating and Transmission
Association, Inc. facility in Rifle, Colorado operates a natural gas-powered CCS with a steam
generator capacity of 39 MW. According to the 2003 Summary of Rationale for the permit, the
Rifle facility is an electric peaking power generation plant categorized by the permitter to be
within SIC code 4911 - Electric Services. Until 2002, the facility was operated in conjunction
with a large greenhouse that utilized steam heat provided by the facility. The facility still
provides steam heat to the greenhouse; however, the peaking plant and greenhouse are currently
under separate ownership [CDPHE, 2003].
The NPDES permit for this facility also indicated that the cooling tower
blowdown contributes 50 to 70 percent of the total discharge, which is intermittent due to the
sporadic demand for electric power from this peaking facility. The wastewater discharged by
this facility is currently limited by the requirements of the Steam Electric ELGs34, since it meets
the applicability at 40 CFR 423.10 [CDPHE, 2003].
EPA found the remaining four facilities to be wastewater treatment and water
supply plants. None of these facilities reported an electric generating unit to the EIA. In
addition, the limited amount of information on the waste streams provided in the permits
34
The permit did not address limitations on copper and iron discharged with chemical metal cleaning wastewaters.
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Detailed Study Report - November 2006 Chapter 8 - Combination Utility Wastewaters
indicated they had little in common with the waste streams expected from a steam electric
generating facility, as previously described in Section 3.2. Since these facilities do not appear to
be "... primarily engaged in the generation of electricity for distribution and sale..." [40 CFR
423.10], they do not meet the current applicability of the Steam Electric ELGs. Further, the
processes and wastewaters generated by these non-electric-generating facilities are not similar to
those of the regulated steam electric industry.
8.3 Conclusion
Based on the USCB's description of the Combination Utilities, NEC industrial
sector and available information about the wastewater discharged by these facilities, EPA
concludes that the Combination Utilities, NEC sector, as defined by SIC code 4939, is not an
appropriate subcategory for the current Steam Electric Power Generating Point Source Category.
EPA's review of NPDES permits for a select number of facilities classified within
the Combination Utilities, NEC sector in PCS revealed that wastewater-generating activities
performed at these facilities may be classified within other existing SIC codes, including Electric
Services, Sewerage Systems, and Water Supply. Except for one facility that was primarily a
steam electric facility, the permits did not indicate that the PCS combination utilities produce
electricity, even as an auxiliary activity. Though EPA did not find an example in the permits
reviewed, it is possible that a combination utility could operate a steam electric generating unit in
addition to performing its primary activity.
EPA also determined that this industrial sector does not generate a large volume
of wastewater. This estimate is based on the small number of combination utilities that report
wastewater discharges included in PCS. The wastewater discharge flow rates reported to PCS
from combination utilities are three orders of magnitude lower on average than those reported by
electric generating facilities within SIC codes 4911 and 4931, and the total pollutant load
discharged by combination utilities is a very small fraction of the load discharged by electric
generators.
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Detailed Study Report - November 2006 Chapter 9 - Industrial Non-Utilities
9.0 INDUSTRIAL NON-UTILITIES
This chapter describes EPA's review of steam electric generators located at
facilities within various industrial sectors to produce electricity and/or thermal output primarily
to support the activities performed at the facility. These industrial non-utilities include
cogenerators35, small power plants, and other non-utility generators, and do not generally
produce electric power for distribution and sale.
As part of the detailed study of the steam electric industry, EPA investigated
industrial non-utilities to determine whether a revision to the current Steam Electric ELGs to
include these types of steam electric wastewaters may be warranted.
This chapter presents EPA's findings to date obtained through available sources
of information on industrial non-utility processes and wastewaters, including available
demographic and wastewater characterization data and wastewater discharge permits for
industrial facilities operating a steam electric non-utility on site.
9.1 Overview of Industrial Non-Utilities
The steam electric generating process used at industrial non-utilities is similar to
that used by all steam electric facilities, as described in Section 3.2. A boiler or HRSG is used to
generate steam that is in turn used (at least in part) to drive an electric generator or turbine.
Finally, the steam is condensed through noncontact cooling before it is returned to the boiler.
Since the processes are similar, EPA expects that industrial non-utilities generate wastewater
from the same sources as do regulated steam electric facilities.
One key factor that differentiates industrial non-utilities from regulated steam
electric facilities is they do not produce electricity primarily for distribution and sale. EPA
conducted this review because, given the processes involved in these operations, many industrial
non-utilities would be regulated by the Steam Electric ELGs except for the language at 40 CFR
423.10 limiting the applicability to facilities "... primarily engaged in the generation of electricity
for distribution and sale..." With the exception of certain instances (e.g., certain subcategories
of the Pulp, Paper and Paperboard ELGs; see 40 CFR 430.01(m)), industrial non-utilities are not
directly regulated by ELGs.
EPA identified industrial non-utilities for this detailed study through data
collected in 2002 by the EIA. Industrial facilities that operate an electric power generator having
at least one MW of capacity report to the EIA each year. Included in these data is the facility' s
primary NAICS code. EPA identified industrial non-utilities in the 2002 EIA data as those
reporting NAICS codes other than 22 - Utilities (as described previously in Section 3.3.2).
EPA examined the 2002 EIA data to determine the relative size of industrial non-
utilities, as well as the types of fuels used by industrial non-utilities to generate the steam. These
data are described in Section 9.1.1. EPA also performed a more detailed analysis of the EIA data
for the subset of industrial non-utilities that utilize fossil fuels to power a steam generator.
35 A cogenerator is defined as "a generating facility that produces electricity and another form of useful thermal
energy (such as heat or steam), used for industrial, commercial, heating, or cooling purposes" [U.S. DOE, 2006a].
9-1
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Detailed Study Report - November 2006 Chapter 9 - Industrial Non-Utilities
Section 2.9 presents a more detailed summary of the available demographic data for fossil-
fueled, steam electric industrial non-utilities.
9.1.1 Relative Size of Industrial Non-Utilities
According to the 2002 EIA data, there are 908 industrial non-utilities, most of
which (nearly 80 percent) produce a relatively low amount of electric power (no more than 50
MW) [U.S. DOE, 2002a]. These 908 industrial non-utilities include facilities operating both
steam and non-steam generating units (e.g., stand-alone combustion turbines, internal
combustion engines, and hydraulic turbines) powered by either fossil or non-fossil fuel types.
No nuclear-powered industrial non-utilities were reported to EIA in 2002.
To compare, only 11 percent of regulated steam electric facilities produce less
than 50 MW of electricity. In fact, nearly half of the regulated steam electric industry comprises
facilities that generate more than 500 MW of electric power [U.S. DOE, 2002a]. Section 3.3.2
contains additional information on the regulated steam electric industry.
9.1.2 Fuels Used by Industrial Non-Utilities
Industrial non-utilities may be fueled either by a fossil fuel (e.g., coal, oil, or
natural gas) or an alternative, non-fossil fuel often derived from a by-product of the primary
industrial process. These non-utilities may also utilize a combination of fossil and non-fossil
fuels to power the steam electric generating unit. No industrial non-utilities were found to use
nuclear fuels [U.S. DOE, 2002a].
The following non-fossil fuels were reported to the EIA by industrial non-utilities
as the primary fuel for the steam electric generating unit (abbreviations used by EIA are
presented in parentheses):
• Agricultural Crop Byproducts, Straw, Energy Crops (AB);
Municipal Solid Waste (MSW);
• Wood and Wood Waste Solids (e.g., paper pellets, railroad ties, utility
poles, wood chips) (WDS);
• Other Biomass Solids (e.g., animal manure and waste, solid byproducts)
(OBS);
Black Liquor (BLQ);
• Wood Waste Liquids (e.g., red liquor, sludge wood, spent sulfite liquor)
(WDL);
• Blast Furnace Gas (BFG);
• Purchased Steam (PS);
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Detailed Study Report - November 2006 Chapter 9 - Industrial Non-Utilities
• Other Biomass Gases (e.g., digester gas, methane) (OBG);
• Other Gas (e.g., butane, coal processes, coke-oven, refinery) (OG); and
• Other Fuels (e.g., batteries, chemicals, coke breeze, hydrogen, pitch,
sulfur, tar coal) (OTH).
In 2002, 193 steam electric industrial non-utilities reported using at least one of
these alternative fuel types. Among these non-fossil fuel types, BLQ and WDS were the most
prevalently used primary fuels for steam electric power generation by industrial non-utilities
[U.S. DOE, 2002].
As previously mentioned, it is not uncommon for an industrial non-utility to use
more than one type of fuel; in fact, these facilities often will use a combination of fossil and non-
fossil fuels to power the same steam electric generating unit. For example, several industrial
non-utilities that reported using natural gas as the primary fuel also reported using BLQ and OG
as alternates, as did several coal-burning industrial non-utilities. In addition, several of the 193
primarily non-fossil-fueled industrial non-utilities reported using coal, oil, or natural gas as
alternate fuels for the steam electric generating unit [U.S. DOE, 2002].
9.2 Demographic Data for Fossil-Fueled Industrial Non-Utilities
This section describes the demographic data available from EIA for fossil-fueled,
steam electric industrial non-utilities, including the specific industries represented in the data, the
steam electric power generating capacities, the types of prime movers used, and the fossil fuels
used by each.
EPA identified industrial non-utilities through data collected in 2002 by EIA for
facilities reporting a primary NAICS code other than 22 - Utilities. Similar to the analysis of the
regulated steam electric industry described in Section 3.3.2, EPA used the NAICS code, prime
mover, and energy source information reported in Form EIA-860 to develop a demographic
profile for steam electric industrial non-utilities. EPA identified the subset of industrial non-
utilities in the EIA database that are steam electric as those operating at least one prime mover
that utilizes steam, produced by burning a fossil fuel, to generate electricity.
Using the criteria for the prime mover type and fossil fuel described above for
facilities reporting a primary purpose/NAICS code other than 22, EPA estimates that 314 fossil-
fueled, steam-electric, industrial non-utilities reported to the EIA in 2002. These facilities are
estimated to operate 683 stand-alone steam generators or CCSs36, which have a total steam
turbine capacity of 10,879 MWs37 [U.S. DOE, 2002a]. This industrial non-utility steam turbine
36 Refer to Section 3.2.2 for a description of the combined cycle system of electric power generation.
37 The EIA database contains 312 facilities reporting a total of 681 steam electric units, and an additional 2 facilities
reporting at least one CCS combustion/gas turbine only (one each in the chemical manufacturing and petroleum and
coal products manufacturing industries). EPA assumes these additional two facilities are each operating a single
steam turbine as part of their CCS, even though it was not reported to EIA. The total steam turbine capacity does
not include the unknown capacities for the two CCS steam electric turbines that are assumed in the total number of
facilities and generating units.
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Detailed Study Report - November 2006 Chapter 9 - Industrial Non-Utilities
capacity is less than two percent38 of the electricity produced by the regulated steam electric
industry.
Table 9-1 summarizes the industries that reported industrial non-utilities to the
EIA in 2002, the number of facilities, and the number of fossil fuel-burning steam electric
generating units. The top five industries reporting operation of non-utilities, by steam electric
capacity include:
• Chemical Manufacturing;
• Paper Manufacturing;
• Primary Metal Manufacturing;
• Food Manufacturing; and
• Petroleum and Coal Products Manufacturing [U.S. DOE, 2002a].
The top five industries comprise an estimated 222 non-utilities operating 481
steam generating units and producing 9,235 MW of steam electric power (85 percent of the
steam electric capacity of all fossil-fueled, steam-electric industrial non-utilities reported to EIA)
[U.S. DOE, 2002a]. The remainder of this section presents more detailed demographic
information for these five industries.
9.2.1 Prime Movers/Generating Units
Table 9-2 shows the distribution of the types of steam electric prime movers used
by industrial non-utilities within each of the top five industries. The table presents the numbers
of facilities and generating units, and capacities for each type of steam electric prime mover.
Based on the 2002 EIA data, industrial non-utilities generate most of their electricity (71 percent)
through stand-alone steam turbines, which is also the most prevalent type of steam electric prime
mover used by the regulated steam electric industry, as discussed in Section 3.3.2.
One exception to this among the top five industries is the petroleum and coal
products manufacturing industry, which reported operating more CCSs than stand-alone steam
turbines in 2002 [U.S. DOE, 2002a]. Comments received from the American Petroleum Institute
(API) indicate that most petroleum refineries utilize natural gas or residual gases from the
refinery process to power a gas/combustion turbine, the waste heat of which is used to produce
steam either to generate additional electric power or to be used directly within the refining
process [API, 2005]. According to API's description of petroleum refinery non-utilities, not only
are these facilities using CCSs, but that they are also considered to be cogenerators (i.e., steam is
produced both to power a generator and to use in other operations).
38 EPA estimates that the total steam electric generating capacity of the regulated steam electric industry in 2002 was
621,799 MW (refer to Section 3.3.2) [U.S. DOE, 2002a].
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Detailed Study Report - November 2006
Chapter 9 - Industrial Non-Utilities
Table 9-1. Summary of Fossil-Fueled, Steam Electric Industrial Non-Utilities,
by NAICS Code
NAICS Code - Description
325 - Chemical Manufacturing
322 - Paper Manufacturing
33 1 - Primary Metal Manufacturing
3 1 1 - Food Manufacturing
324 - Petroleum and Coal Products Manufacturing
Total for Top 5 Industries, by Capacity
611 -Educational Services
3345 - Navigational, Measuring, Electromedical, and
Control Instruments Manufacturing
4911 -Postal Service
221 -Utilities
3 122 - Tobacco Manufacturing
336 - Transportation Equipment Manufacturing
3 14 - Textile Product Mills
327 - Nonmetalic Mineral Product Manufacturing
212 - Mining (except Oil and Gas)
622 - Hospitals
92 - Public Administration
326 - Plastics and Rubber Products Manufacturing
21 1 - Oil and Gas Extraction
333 - Machinery Manufacturing
521 - Monetary Authorities - Central Bank
332 - Fabricated Metal Product Manufacturing
321 - Wood Product Manufacturing
481 - Air Transportation
814 - Private Households
482 - Rail Transportation
561 - Administrative and Support Services
624 - Social Assistance
5 14 - Information Services and Data Processing Services
562212 - Solid Waste Landfill
Total
Number of
Facilities
59
84
12
44
23
222
(71%)
33
1
1
3
3
3
5
3
2
9
5
1
10
2
1
1
2
1
1
1
1
1
1
1
314
(100%)
Number of
Generating
Units
144
177
26
92
42
481
(70%)
70
12
1
5
5
7
14
9
5
17
11
4
20
7
2
2
2
1
1
2
1
2
1
1
683
(100%)
Total Steam
Turbine Capacity
(MW)
3,147
3,125
1,158
1,001
804
9,235
(85%)
456
205
178
114
101
92
84
77
66
60
57
40
34
24
12
10
9
8
6
4
2
2
1
1
10,879
(100%)
Source: U.S. DOE, 2002a.
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Detailed Study Report - November 2006
Chapter 9 - Industrial Non-Utilities
Table 9-2. Distribution of Prime Mover Types Among Fossil-Fueled,
Steam Electric Industrial Non-utilities
Steam Electric Prime Mover
Number of Facilities'*
Number of
Generating Units
Total Steam Turbine
Capacity
(MW)
All Industrial Non-utilities
Stand- Alone Steam Turbine
CCS
Total
256
(82%)
61
(19%)
314
585
(86%)
98
(14%)
683
7,832
(72%)
3,046
(28%)
10,879
NAICS 325 - Chemical Manufacturing
Stand- Alone Steam Turbine
CCS
Total
39
20
59
100
44
144
1,093
2,054
3,147
NAICS 322 - Paper Manufacturing
Stand- Alone Steam Turbine
CCS
Total
81
4
84
172
5
177
3,054
71
3,125
NAICS 331 - Primary Metal Manufacturing
Stand- Alone Steam Turbine
CCS
Total
12
0
12
26
0
26
1,158
0
1,158
NAICS 311 - Food Manufacturing
Stand- Alone Steam Turbine
CCS
Total
41
4
44
88
4
92
976
25
1,001
NAICS 324 - Petroleum and Coal Products Manufacturing
Stand- Alone Steam Turbine
CCS
Total
11
12
23
21
21
42
352
452
804
Source: U.S. DOE, 2002a.
aBecause a single facility may operate multiple generating units of various types, the number of facilities by prime
mover type is not additive. The totals reflect the number of industrial non-utilities that are operating at least one
steam electric generating unit powered by a fossil fuel.
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Detailed Study Report - November 2006 Chapter 9 - Industrial Non-Utilities
9.2.2 Fossil Fuel Types
Table 9-3 shows the distribution of the fossil fuels used by industrial non-utilities
by capacity, and specifically broken out for the top five industries. The 2002 EIA data
demonstrate that fossil-fueled industrial non-utilities generally use either coal or natural gas to
fuel their steam electric generators; however, some industries tend to favor a particular type of
fossil fuel. For example, most primary metal manufacturing and food manufacturing non-
utilities reported using coal, while most chemical manufacturing and petroleum/coal products
manufacturing non-utilities reported using natural gas [U.S. DOE, 2002a]. These trends coincide
with the predominant types of generators used in these industries (i.e., nearly all CCSs are
powered by natural gas).
9.3 Wastewater Characterization
EPA examined pollutant load data available in the PCSLoads2002 database [U.S.
EPA, 2006a] for the industrial facilities identified in the EIA database as operating a fossil-
fueled, steam electric non-utility. Out of the 314 EIA industrial non-utilities, EPA identified
PCS records for 67 major dischargers and 14 minor dischargers that reported wastewater flow
and pollutant concentration data, such that pollutant loads could be determined39.
It should be noted that the industry-specific pollutant loads presented in this
section represent the subset of facilities within the industry that were identified as operating a
fossil-fueled, steam electric non-utility at their site. Table 9-4 summarizes the number of
industrial facilities identified as operating a fossil-fueled, steam electric non-utility and that
provided pollutant load information to PCS.
EPA analyzed the PCS pollutant load data reported by the 81 industrial facilities
operating fossil-fueled steam electric generating unit(s) on site. Table 9-5 summarizes the top 20
pollutants discharged, based on the TWPE loads for the 81 industrial facilities, along with the
number of facilities for which the load was calculated. The PCS data does have some
limitations; in particular, only the parameters regulated by the facilities' NPDES permits are
reported in PCS.
Since the industrial facilities' primary purpose of operation is other than
electricity production, it is likely that many of the chemicals listed in Table 9-5 are not
associated with electricity production.
39 For more information on how pollutant loads were calculated using the 2002 PCS data, refer to Chapter 2 of the
2002 Screening-Level Analysis report [U.S. EPA, 2005a].
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Detailed Study Report - November 2006
Chapter 9 - Industrial Non-Utilities
Table 9-3. Distribution of Fuel Types Among Fossil-Fueled, Steam Electric
Industrial Non-utilities
Fossil Fuef
Number of
Facilities'1
Number of
Generating Units
Total Steam
Turbine
Capacity
(MW)C
All Industrial Non-utilities
Coal:
Anthracite Coal, Bituminous Coal (BIT)
Subbituminous Coal (SUB)
Lignite Coal (LIG)
Petroleum Coke (PC)
Oil:
Residual Fuel Oil (RFO)
Distillate Fuel Oil (DFO)
Waste/Other Oil (WO)
Natural Gas (NG)
Total
119
(38%)
101
17
1
4
(1%)
25
(8%)
17
7
1
170
(54%)
314
308
(45%)
269
36
3
5
(1%)
44
(6%)
32
11
1
324
(47%)
683
4,744
(44%)
3,956
425
363
218
(2%)
320
(3%)
284
28
8
5,597
(51%)
10,879
NAICS 325 - Chemical Manufacturing
Coal (BIT and SUB)
Oil (DFO and WO)
Natural Gas (NG)
Total
12
2
44
59
48
3
92
144
512
12
2,623
3,147
NAICS 322 - Paper Manufacturing
Coal (BIT and SUB)
Petroleum Coke (PC)
Oil (DFO and RFO)
Natural Gas (NG)
Total
34
2
9
41
84
85
3
14
75
177
1,540
157
194
1,234
3,125
NAICS 331 - Primary Metal Manufacturing
Coal (BIT and LIG)
Oil
Natural Gas (NG)
Total
7
0
5
12
14
0
12
26
900
0
258
1,158
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Detailed Study Report - November 2006
Chapter 9 - Industrial Non-Utilities
Table 9-3 (Continued)
Fossil Fuef
Number of
Facilities'1
Number of
Generating Units
Total Steam
Turbine
Capacity
(MW)C
NAICS 311- Food Manufacturing
Coal (BIT and SUB)
Oil(DFOandRFO)
Natural Gas (NG)
Total
29
2
14
44
63
3
26
92
888
12
101
1,001
NAICS 324 - Petroleum and Coal Products Manufacturing
Coal
Petroleum Coke (PC)
Oil (DFO)
Natural Gas (NG)
Total
0
2
1
19
23
0
2
3
36
42
0
61
2
740
804
Source: U.S. DOE, 2002a.
aNo steam electric generating units were reported to use jet fuel, kerosene, or waste/other coal, or nuclear fuel in the
2002 EIA database.
bBecause a single facility may operate multiple generating units utilizing differing fuel types, the number of facilities
by fuel type is not additive. EPA estimates there are 314 industrial non-utilities operating at least one steam electric
generating unit powered by a fossil fuel.
°The total steam electric capacity shown does not equal the sum of the steam electric capacities for each fuel type
due to rounding errors.
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Detailed Study Report - November 2006 Chapter 9 - Industrial Non-Utilities
Table 9-4. Fossil-Fueled, Steam Electric Industrial Non-Utilities Identified in PCS
Facility Type"
Major
Dischargers
Minor
Dischargers
Total Number of Industrial
Non-Utilities in PCS
(% of EIA facilities)
NAICS 325 - Chemical Manufacturing (59 industrial non-utilities in EIA)
Organic Chemicals, Plastics & Synthetic
Fibers (OCPSF)
Chlorine and Chlorinated-Hydrocarbon
Manufacturing (CCH)
Pharmaceutical Manufacturing
Explosives Manufacturing
Inorganic Chemicals Manufacturing
Total
6
5
2
1
1
15
1
0
0
0
0
1
7
5
2
1
1
16
(27%)
NAICS 322 - Paper Manufacturing (84 industrial non-utilities in EIA)
Pulp, Paper and Paperboard
(Pulp & Paper)
Total
19
19
3
3
22
22
(26%)
NAICS 331 - Primary Metal Manufacturing (12 industrial non-utilities in EIA)
Iron and Steel Manufacturing
Nonferrous Metals Manufacturing
Ferroalloy Manufacturing
Total
5
2
1
8
0
0
0
0
5
2
1
8
(67%)
NAICS 311 - Food Manufacturing (44 industrial non-utilities in EIA)
Sugar Processing
Grain Mills
Canned and Preserved Fruits and
Vegetables Processing
Miscellaneous Foods and Beverages
Total
9
2
1
0
12
1
2
0
1
4
10
4
1
1
16
(36%)
NAICS 324 - Petroleum and Coal Products Manufacturing (23 industrial non-utilities in EIA)
Petroleum Refining
Total
9
9
0
0
9
9
(39%)
Remaining Industrial Facility Types in PCS
Metal Finishing
Educational Services
Cement Manufacturing
Ore Mining and Dressing
Rubber Manufacturing
Total
2
0
1
1
0
67
2
o
J
0
0
1
14
4
o
J
1
1
1
81
(26%)
Source: U.S. EPA, 2006a.
"The facility types listed in this table are covered by existing point source categories, as well as other industry
groupings identified during the 2005 screening-level analysis [U.S. EPA, 2005a].
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Chapter 9 - Industrial Non-Utilities
Table 9-5. Top 20 Pollutants Released from Industrial Facilities Operating a Fossil-Fueled,
Steam Electric Non-Utility
Pollutant
Polychlorinated Biphenyls"
Molybdenum
Sulfide
Chlorine
Lead
Fluoride
Silver
Aluminum
Copper
Mercury
Hexachlorobenzene
Cyanide
Zinc
Chloride
Nitrogen, Ammonia
Nickel
Nitrogen, Total Nitrite (as N)
Selenium
Hexavalent Chromium
Boron
Total
Number of
Facilities
Reporting
1
1
9
24
19
3
2
6
24
5
2
10
21
6
38
15
1
3
6
1
81
Total Load
(pounds)
25
717,011
45,441
105,729
14,084
358,547
761
170,484
9,031
45
2
3,531
66,075
126,159,200
1,568,672
13,964
3,822
937
1,419
3,837
Total Load
(TWPE)
845,395
144,434
127,300
53,833
31,548
12,549
12,538
11,029
5,733
5,238
4,441
3,944
3,098
3,072
2,361
1,521
1,427
1,051
733
680
1,276,340
Percentage of
Total TWPE
66%
11%
10%
4%
2%
1%
1%
0.9%
0.4%
0.4%
0.3%
0.3%
0.2%
0.2%
0.2%
0.1%
0.1%
0.08%
0.06%
0.05%
100%
Source: U.S. EPA, 2006a.
"The polychlorinated biphenyl load shown above was reported to be discharged from a single metal finishing
facility, also found to operate a steam electric generator.
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Detailed Study Report - November 2006 Chapter 9 - Industrial Non-Utilities
In Chapter 5 of this report, EPA discussed 11 pollutants discharged by steam
electric facilities that were identified either as among the top five discharged by the steam
electric industry by TWPE or through specific comments provided for consideration by the
study. Seven of these 11 pollutants of interest are among the top 20 discharged by the 81
industrial facilities operating a fossil-fueled, steam electric non-utility, including:
• Chlorine;
• Aluminum;
• Copper;
• Mercury;
• Zinc;
• Nickel; and
• Boron.
Again, the PCS data present only those pollutants for which the facilities are
required by their NPDES permits to report. Four pollutants that were reported most frequently
are chlorine, copper, zinc, and nickel; however, these were only reported by between 19 and 30
percent of the 81 industrial facilities. Only between one and six of the 81 industrial facilities
reported aluminum, mercury, and boron loads. These seven "steam electric" pollutants account
for less than six percent of the total TWPE reported by the 81 industrial facilities.
Table 9-6 summarizes the top 10 pollutant TWPE loads discharged by facilities
within the industries identified in Section 9.2 as generating the most electricity from fossil-
fueled, steam electric non-utilities operated on site. Again, while many of the industrial facilities
discharge pollutants characteristically found in fossil-fueled steam electric process wastewaters,
these facilities discharge many other types of pollutants that likely originate from the primary
industrial processes performed at these facilities. The specific sources of wastewater pollutants
within the various facility processes (e.g., the pollutants and associated loads specifically
originating from the steam electric non-utility) cannot be determined from the PCS data.
Chlorine, commonly used as a biocide in steam electric cooling water systems,
was reported by 24 of the 81 industrial facilities, with a TWPE of nearly 54,000 pound-
equivalents (Ib-eq). Four out of the five industries shown in Table 9-6 reported chlorine with the
second highest TWPE among the reported discharges within each industry; however, EPA
expects chlorine to also be used in the primary processes performed by these industries, and thus
present in significant amounts in the process wastewaters. For example, the chemical
manufacturing facilities reporting chlorine included the following types of facilities:
• OCPSF manufacturers;
• Pharmaceutical manufacturers;
• Chlorine and chlorinated-hydrocarbon manufacturers; and
• Explosives manufacturers.
EPA makes similar conclusions about the other three industries reporting high
chlorine loads: Paper Manufacturing; Primary Metal Manufacturing; and Food Manufacturing.
9-12
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Detailed Study Report - November 2006 Chapter 9 - Industrial Non-Utilities
Table 9-6. Top Pollutants Discharged by Industries Operating Fossil-Fueled Steam Electric Non-Utilities
Pollutant
Number of
Facilities Reporting
the Pollutant
Total Load
(pounds)
TWPE
(Ib-eq)
Percentage of
Total TWPE
NAICS 325 - Chemical Manufacturing
Sulfide
Chlorine
Mercury
Hexachlorobenzene
Copper
Chloride
Lead
Cyanide
Nickel
Nitrogen, Total Nitrite (as N)
Total
1
9
1
2
10
2
7
4
9
1
16
33,546
50,007
38
2
5,524
120,117,637
1,012
1,589
13,273
3,822
93,978
25,462
4,476
4,441
3,507
2,925
2,267
1,775
1,446
1,427
144,239
65%
18%
3%
3%
2%
2%
2%
1%
1%
1%
100%
NAICS 322 - Paper Manufacturing
Aluminum
Chlorine
Zinc
Nitrogen, Ammonia
2,3,7,8-Tetrachlorodibenzofuran(TCDF)
Copper
Cyanide
Manganese
Nickel
Ammonia
Total
2
6
5
9
1
5
1
2
2
2
22
143,246
16,670
19,076
409,739
IxlO'5
407
229
4,014
218
9,461
9,267
8,488
894
617
552
258
256
58
24
14
20,475
45%
42%
4%
3%
3%
1%
1%
0.3%
0.1%
0.1%
100%
VO
-------
Detailed Study Report - November 2006
Chapter 9 - Industrial Non-Utilities
Table 9-6 (Continued)
Pollutant
Number of
Facilities Reporting
the Pollutant
Total Load
(pounds)
TWPE
(Ib-eq)
Percentage of
Total TWPE
NAICS 331 - Primary Metal Manufacturing
Lead
Chlorine
Fluoride
Cyanide
Zinc
Copper
Aluminum
Arsenic
Cadmium
Benzo(a)pyrene
Total
6
2
2
4
5
3
2
2
2
2
8
11,839
26,896
277,220
1,704
35,518
2,218
21,042
102
18
3
26,520
13,694
9,703
1,903
1,665
1,408
1,361
411
408
317
57,964
46%
24%
17%
3%
3%
2%
2%
0.7%
0.7%
0.5%
100%
NAICS 311 - Food Manufacturing
Sulfide
Chlorine
Magnesium
Nitrogen, Ammonia
Total Potassium (as K)
Chloride
Calcium
Sodium
Sulfate
Ammonia
Total
2
4
3
8
1
3
3
3
1
1
16
5,392
11,884
554,115
227,163
86,116
2,095,519
1,071,349
4,173,146
159,014
42
15,105
6,051
480
342
91
51
30
23
1
0.1
22,173
68.1%
27.3%
2.2%
1.5%
0.4%
0.2%
0.1%
0.1%
0.004%
0.0003%
100%
VO
-------
Detailed Study Report - November 2006
Chapter 9 - Industrial Non-Utilities
Table 9-6 (Continued)
Pollutant
Number of
Facilities Reporting
the Pollutant
Total Load
(pounds)
TWPE
(Ib-eq)
Percentage of
Total TWPE
NAICS 324 - Petroleum and Coal Products Manufacturing
Sulfide
Silver
Selenium
Mercury
Nitrogen, Ammonia
Lead
Copper
Chromium
Chloride
Phenol and phenolics
Total
6
1
1
1
9
1
2
6
1
7
9
6,503
752
929
6
422,355
203
323
2,012
3,946,043
2,824
18,217
12,392
1,042
738
636
455
205
152
96
79
34,085
53%
36%
3%
2%
2%
1%
0.6%
0.4%
0.3%
0.2%
100%
VO
Source: U.S. EPA, 2006s.
-------
Detailed Study Report - November 2006 Chapter 9 - Industrial Non-Utilities
Besides the uncertainty of the specific process sources of chlorine and other
pollutants reported in PCS, EPA notes that there are other confounding factors that preclude a
direct comparison of the industrial non-utility chlorine discharges to those of the steam electric
industry. Based on data provided by the steam electric industry, EPA substantially revised
downward the chlorine discharge estimates for steam electric facilities to reflect that not all
steam electric facilities chlorinate their cooling water systems, and those that do chlorinate are
limited by their permits (and the Steam Electric ELGs) to only two hours per day per generating
unit, and that the mean number of days these facilities chlorinate is 182 days per year40. EPA did
not make similar adjustments to the data for industrial non-utilities because comparable data for
chlorination practices at industrial non-utilities are not available. In addition and as previously
stated, in many cases the effluent data for industrial non-utilities include other waste streams that
may contribute chlorinated compounds on a daily basis.
9.4 Review of Industrial Non-Utility Discharge Permits
EPA reviewed NPDES permits for 28 industrial facilities operating a steam
electric industrial non-utility on site to determine the extent to which steam electric process
wastewater is segregated from other process wastewaters and whether Steam Electric ELGs are
applied on the basis of BPJ. These facilities use either a fossil fuel or other non-fossil fuel to
power the steam electric generating unit(s), and were identified within the following four
industries:
• Chemical Manufacturing;
• Paper Manufacturing;
• Primary Metal Manufacturing; and
• Petroleum and Coal Products Manufacturing.
EPA found that the NPDES permits for the facilities within these industries rarely
provide enough detail about the facility waste streams to identify the steam electric process
wastewaters; however, some permits generally described waste streams that could include the
non-utility waste streams or waste streams from other on-site operations (e.g., "cooling water,"
"boiler blowdown"). Final effluent wastewaters from industrial sites are commingled at the
point of discharge, if not upstream.
The 28 facilities are covered by seven existing industrial point source ELGs. As
expected, EPA determined that wastewaters discharged from these industrial sites are often
regulated at a minimum by the ELGs for the primary industrial process (e.g., OCPSF, Petroleum
Refining). Rarely do the discharge requirements incorporate 40 CFR 423-based limits.
EPA researched three of these seven existing ELGs to determine whether the
waste streams from the non-utility operations were included in determining the final effluent
limitations. The Pulp, Paper & Paperboard ELGs (40 CFR 430) specifically defines its regulated
process wastewater (in certain subparts) as including wastewaters generated by colocated non-
utility power plants (see 40 CFR 430.01(m)).
40 This correction to the steam electric facility records in the PCSLoads2002 database is discussed in Chapter 5.
9-16
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Detailed Study Report - November 2006 Chapter 9 - Industrial Non-Utilities
Comments received from the American Petroleum Institute (API) stated that
petroleum refinery non-utilities primarily generate wastewater from boiler and cooling tower
blowdown and demineralizer streams that are typically permitted as low-contaminant streams
(i.e., low concentrations of toxics, oxygen demand, and nonconventional pollutants). API also
commented that these streams possess the same wastewater characteristics as the petroleum
refining wastewater with which they are commingled prior to discharge [API, 2005].
While the Pulp, Paper, & Paperboard ELGs were developed incorporating
wastewaters from on-site steam electric power plants, this is not the case for all industrial ELGs.
For example, the standards that regulate wastewater generated from the iron & steel
manufacturing industry (40 CFR 420) do not incorporate nonprocess wastewaters, such as those
from an on-site steam electric power plant (e.g., noncontact cooling water).
In many cases, the primary industry ELGs (or the permit for the industrial facility
discharge) either contains a less stringent limit or does not address the pollutants included in the
Steam Electric ELGs, most notably chlorine41 (regulated as FAC or TRC by the Steam Electric
ELGs). For example, this is the case for the Pulp, Paper, & Paperboard ELGs, which include
wastewaters generated from on-site power plants, but do not currently regulate chlorine
discharges.
9.5 Conclusions
While steam electric industrial non-utilities utilize similar operations and are
expected to generate wastewater that is similar to that of the regulated steam electric industry,
industrial non-utilities are generally much smaller, in terms of overall capacity. In addition,
some industrial non-utilities are fueled by non-fossil-fuel/non-nuclear energy sources, typically
associated with the industrial processes present.
Since the types and concentrations of pollutants found in steam electric process
wastewaters are primarily driven by the type of fuel used, there are may be differences between
the wastewater generated by certain industrial non-utilities using non-fossil fuels and that
generated by regulated steam electric facilities that use coal, petroleum coke, oil, natural gas, or
nuclear fuel. In addition, because industrial non-utilities tend to be smaller in terms of electric
power production, the relative volume of wastewater discharged by these facilities is likely to be
less than that discharged by regulated steam electric facilities.
The available wastewater characterization data for industrial non-utilities is
inconclusive. While some of the reported loads for pollutants characteristically found in steam
electric wastewaters are significant, at least a portion of these loads are probably generated by
processes at the site other than steam electric power generation. However, EPA could not
determine from the available data how much of the pollutant load is attributed to the steam
electric processes.
41 As discussed previously in Chapter 5, chlorine is commonly used by steam electric facilities as a biocide in the
cooling water system. Although EPA did not gather specific information about the chemicals used by industrial
non-utilities as biocides, EPA expects that at least some industrial non-utilities use biocide chemicals similar to
those used in the steam electric industry, such as chlorine and chlorinated compounds.
9-17
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Detailed Study Report - November 2006 Ch apter 10- References
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