Environmental Protection Agency
STUDY OF NON-HAZARDOUS WASTES
FROJf. COAL-FIRED- ELECTRIC UTILITIES
DRAFT FINAL REPORT*
15 DECEMBER. 1978
Prepared, for:
Michael Osborne - Task Officer
Industrial.Environmental Research Laboratory
Office of Research and Development
Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Under Contract No. 68-02-2608
J^ A^ McSorley - Project Officer
. Prepared by:
B. F. Jones
J.» ,S.,, Sherman
D,' 'L.' Jernigan
:E« P..-'Hamilton III \
D. M. Ottmers
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DISCLAIMER
This draft report is being made available for informa-
tion purposes only. The report has not been through U.S. Environ-
mental Protection Agency review. Distribution of this draft does
not signify that the contents necessarily reflect the views and
policies of the U.S. Environmental Protection Agency, not does
mention of trade names or commercial products constitute endorse-
ment or recommendation for use.
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TABLE OF CONTENTS
Pat
LIST OF TABLES v
LIST OF FIGURES viii
1.0 EXECUTIVE SUMMARY .. 1
1.1 Characterization of Electric Utility
Industry 3
1.2 Characteristics of Solid Wastes 7
1.3 Waste Disposal Practices 13
1.3.1 Current Disposal Practices 14
1.3.2 Economic Impact of RCRA 16
1.3.3 Alternate Disposal Technologies ... 20
1.4 Utilization of Utility Wastes 22
1.5 Conclusions and Recommendations 25
2.0 CHARACTERIZATION OF ELECTRIC UTILITY INDUSTRY . 29
2.1 Fuels Characterization 29
2.2 Economic Characterization 38
2.2.1 Capital Expenditures 41
2.2.2 Operating and Maintenance Expenditures 50
2.2.3 Income and General Economic Impacts
of the Utility Sector 50
2.3 Regulatory Characterization 53
2.4 Summary 57
3.0 CHARACTERISTICS OF" SOLID
WASTES 59
3.1 Types and Quantities of FGC By-Products .. 59
3.2 Characterization of Coal 74
3.3 Chemical Properties of FGC By-Products ... 76
3.3.1 Chemical Characterization of Ash .. 76
3.3.2 Eastern vs Western Coal Fly Ashes . 79
3.3.3 Chemical Characterization of
Scrubber Solids 79
3.4 Physical Properties of FGC By-Products ... 80
3.4.1 Physical Properties of Fly Ash .... 82
3.4.2 Physical Properties of Bottom Ash . 83
3.4.3 Physical Properties of FGD Sludge . 83
3.5 Structural Properties 84
3.5.1 Compaction Properties 84
3.5.2 Unconfined Compressive Strength ... 86
3.5.3 Permeability 87
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TABLE OF CONTENTS
(Cont'd)
Page
3.6 Leaching Characteristics 89
3.6.1 Coal Ash Leachates 90
3.6.2 Leaching of FGD Scrubber Sludge ... 93
4.0 WASTE DISPOSAL PRACTICES 98
4.1 Disposal Methods and Practices 98
4.1.1 Disposal Methods 98
4.1.1.1 Alternatives for Collection
and Disposal 102
4.1.1.2 Pond Designs 103
4.1.1.3 Landfill Designs 105
4.1.2 Disposal Practices 107
4.1.2.1 Fly Ash Disposal 108
4.1.2.2 Bottom Ash Disposal 110
4.1.2.3 Scrubber Sludge Disposal 112
4.1.2.4 Distance to Disposal Site 114
4.2 Economic Impact of RCRA 115
4.2.1 Interpretation of RCRA 117
4.2.1.1 Location Considerations 119
4.2.1.2 Performance Considerations 120
4.2.1.3 EPA Opinions on Enforcement
Options 121
4.2.2 Costing Basis for Enforcement.
Scenarios 122
4.2.2.1 Development of Potential
Enforcement Scenarios . . . 122
4.2.2.2 Development of Engineering
Data 123
4.2.2.3 Development of Cost Factors 131
4.2.3 Estimated Cost of Compliance 132
4.2.3.1 Assumptions 132
4.2.3.2 Existing Plants 136
4.2.3.3 New Plants 139
4.2.3.4 Costs for Existing Plus
New Plants 143
4.2.4 Summary of Cost Analysis 145
ii
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o
5.0
TABLE OF CONTENTS
(Cont'd)
4.3
Alternative Disposal Technologies
4.3.1 Mine Disposal
4.3.1.1 Process Description . . . '. .
4.3.1.2 Technical Considerations
4.3.1.3 Economics . . .•
4.3.1.4 Assessment of Information
Needs
4.3.2 Ocean Disposal
4.3.2.1 Process Description
4.3.2.2 Economics
4.3.2.3 Assessment of Information
Needs
4.3.3 Land Farming
UTILIZATION OF UTILITY WASTES
5.1.
Fly Ash Utilization Practices
5.1.1 Partial Replacement of Cement
in Concrete and Concrete Products
Page
146
146
148
150
150
151
151
152
154
155
156
157
159
161
5.1.2 Base and Subbase in Road Construction 162
5.2
5.3
5.4
5.5
5.1.3 Cement Manufacture
5.1.4 Lightweight Aggregate
5.1.5 Filler in Asphalt Mix
5.1.6 Future Uses
Bottom Ash Utilization Practices
5.2.1 Use in Manufacture of Cement
5.2.2 Lightweight Aggregate and Aggregate
in Road Construction
5.2.3 Filler in Asphalt Mix
5.2.4 Abrasive Material for Skid Control
Under Snow or Icing Conditions on
Roads
5.2.5 Other Uses
Utilization of FGD on Scrubber Sludge . . .
Factors Limiting Waste Utilization
Regenerable FGD Processes
164
165
166
167
168
169
170
171
172
172
173
174
176
111
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TABLE OF CONTENTS
(Cont'd)
Page
5.5.1 Wellman-Lord 178
5.5.2 Magnesium Oxide Slurry Adsorption 179
5.5.3 Aqueous Absorption with Citrate
Buffering 180
5.5.4 Integrated Cat-Ox Process 180
5.5.5 Aqueous Carbonate Process 181
5.5.6 Advanced Technology Processes .... 181
5.5.7 Economic Comparison of Regenerable
Processes with Wet Scrubbing Lime/
Limestone Throwaway Systems 182
5.5.8 Possible Impact of Regenerable
Processes 183
REFERENCES 190
APPENDIX A 198
APPENDIX B 200
APPENDIX C 202.
APPENDIX D 263
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LIST OF TABLES
Number Page
1-1 Typical Quantities and Qualities of Ash and
Scrubber Sludge for Model 1000 MW Power Plant.. 8
1-2 Summary of Estimated Cost of Compliance
(MID 1979 Dollars) , 19
1-3 U.S. Ash Utilization in 1977 23
2-1 Inventoried U. S. Coal-Fired Capacity in 1976... 32
2-2 Distribution of Inventoried Coal-Fired Capa-
city with EPA Regions 33
2-3 NERC Generation Projections, 1976-1986 36
2-4 Annual Coal Requirements (Millions of Tons)
for the U.S. Utility Industry as Estimated
by NERC 37
2-5 Relative Market Shares of Electric Utility
Types in the United States for 1977 40
2-6 Electric Utility Capital Expenditures - 1977
and 1978 42
2-7 Price-Book Ratios (PBR's) for Investor-
Owned Utilities in June, 1974 48
2-8 Distribution of Operating Expenses (Percent)... 49
2-9 Electric Utility Maintenance Costs - 1977'
and 1978 51
2-10 Investory-Owned Utility Income (Millions of
Dollars 52
3-1 Basic Assumptions in By-Product Scenarios 61
3-2 Design Basis of Eight Scenarios for Waste
Quantities 62
3-3 By-Product Production Rates for Eight
Scenarios 71
3-4 Chemical Composition of Fly Ashes According to
Coal Rank - Major and Minor Species (Weight
Percent) 77
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LIST OF TABLES
(Cont'd)
Page
3-5 Trace Element Composition of FGD Sludge Solids
(Concentration in ppm) 81
3-6 Range of Moisture-Density Relations of FGC
Waste Products ' 86
3-7 Assumptions of Dry and Wet Bulk Densities of
FGC Waste Products 85
3-8 Concentration of Major Chemical Species in
Coal Ash Liquors (Concentration in Mg/£) 91
3-9 Water Quality Parameters Significant to Waste
Disposal at Trapper Mine 92
3-10 Concentration of Trace Element Species in
Coal Ash Liquors (Concentration in mg/£) 94
3-11 Levels of Chemical Species in FGD Sludge
Liquors and Elutriates 96
4-1 Fly Ash Collection and Disposal Practices 109
4-2 Fly Ash Disposal Practices by Quantity of Ash.. 110
4-3 Bottom Ash Collection and Disposal Practices... Ill
4-4 Bottom Ash Disposal Practices by Quantity
of Ash 112
4-5 Distance from Plant to Waste Disposal Site 115
4-6 Design Basis - for 1000 MW Coal-Fired Power
Plant 125
4-7 Solid Waste Generation Rates for 1000 MW Coal-
Fired Power Plant 126
4-8 Dry and Wet Bulk Densities of FGD Waste
Products 127
4-9 Volumetric Generation Rates for Solids and
Sludges from a 1000 MW Plant 127
4-10 Land Requirements in Square Meters for a 1000
MW Coal-Fired Power Plant 129
vi
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LIST OF TABLES
(Cont'd)
Page
4-11 Comparison of Assumptions Between 1000 MW
Plant and TVA Cost Evaluation 130
4-12 Cost Estimates for Solid Waste Disposal
from a 1000 MW Plant 133
4-13 Estimate of Revenue Requirements for Existing
Disposal Facilities - 1970-1978 136
4-14 Estimate of the Cost of Disposal for Moving
the Disposal Site for 16.1 Kilometers from
the Plant Cost 138
4-15 Estimated Cost for Disposal for Planned and
Future Facilities to the Year 1985 with no
Additional Regulations 141
4-16 Estimated Cost for Disposal for Planned and
Future Facilities to the Year 1985 with
Restrictions Imposed by RCRA 142
4-17 Estimated Additional Disposal Costs Resulting
from RCRA for Planned and Future Coal-Fired
Facilities to the Year 1985 143
4-18 Relative Comparative Cost of Pond Liners 144
4-19 Summary of Estimated Cost of Compliance (Mid
1979 Dollars) 147
5-1 Comparative Results 158
5-2 Ash.Collection and Utilization 1977 (Million
Tons) 160
5-3 Comparison of Capital Investment and Operating
Costs for FGD Systems 500 MW Coal-Fired
Generating Plant 184
vii
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LIST OF FIGURES
Number Page
1-1 Distribution of Coal-Fired Generating Stations
and Coal-Fired Capacity by States (1976) 5
2-1 Existing and Planned Generating Capability
as Estimated by NERC 30
2-2 NERC Reliability Regions 35
2-3 Investor-Owned Electric Utility Security Sales
and Capital Expenditures (Billions of Dollars). 44
2-4 Fixed Cost-Coverage Ratio for Investor-Owned
Electric Utilities 1969-1977 46
2-5 Estimated Electric Utility Revenue Require-
ments - 1972-2000 54
3-1 Waste Streams of a Typical Steam Electric
Generating Station 60
3-2 Byproduct Production Rates wtibT Eastern Coal,
Low Oxidation, High Utilization, and Current
Regulations 63
3-3 Byproduct Production Rates with Eastern Coal,
Low Oxidation, Low Utilization, and Current
Regulations 64
3-4 Byproduct Production Rates with Eastern Coal,
Low Oxidation, High Utilization, and Future
Regulations 65
3-5 Byproduct Production Rates with Eastern Coal,
High Oxidation, High Utilization, and Future
Regulations 66
3-6 Byproduct Production Rates with Western Coal,,
Low Oxidation, High Utilization, and Current
Regulations .1 67
3-7 Byproduct Production Rates with Western Coal,
Low Oxidation, Low Utilization, and Current
Regulations 68
3-8 Byproduct Production Rates with Western Coal,
Low Oxidation, High Utilization, and Future
Regulations 69
viii
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LIST OF FIGURES
(Cont'd)
3-9 Byproduct Production Rates with Western Coal,
High Oxidation, High Utilization, and Future
Regulations 70
4-1 Common Disposal. Alternatives for Fly Ash
(Separate Collection of Fly Ash and S02) 99
4-2 ' Common Disposal Alternatives for FGD Scrubber
Sludge 100
4-3 Common Disposal Alternatives for Combined
Fly Ash and FGD Scrubber Sludge 101
4-4 Pond Designs 104
4-5 Landfill Designs 106
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1.0 EXECUTIVE SUMMARY
•
The production of electrical energy in the U.S. in the
near future will place greater emphasis on the utilization of
coal. It has been reported that between 1976 and 1986 the coal-
fired capacity in the U.S. will increase by 60% or 160,000 Mw.
Emissions from these plants are controlled by the Clean Air
Amendment of 1977 and result in the production of large masses
of fly ash and scrubber sludge. In lieu of commercial utiliza-
tion, disposal of these solid wastes must be conducted in a
manner which is consistent with the requirements of the.Resource
Conservation and Recovery Act of 1976 (RCRA) .
Radian Corporation was contracted by the Environmental
Protection Agency (EPA) to provide the EPA Office of Solid
Waste with a preliminary basis for responsible agencies to
evaluate the definitions and possible -regulations required for
assessing the impact of implementation of RCRA Section 4004
as it may apply to the utility industry.
The objective of this study was accomplished through
the completion of four tasks. The first task consisted of a
characterization of the utility industry, including the number
of plants, distribution by size and EPA region, and the general
economic status of the industry. Results of this task can be
used to assess the impact of implementation of RCRA Section 4004
on federal and state regulatory agencies and on the utility.
States and utilities in the Ohio Valley will be hit the hardest
by implementation.
The second task determined quantities of flue gas clean-
ing (FGC) wastes - fly ash, bottom ash and scrubber sludge - as
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produced by a number of possible scenarios for a "model" 1000 Mw
plant. The chemical, physical, structural and leaching pro-
perties of the waste were discussed. The characteristics and
mass of the FGC waste affect disposal methodology, disposal costs
and potential environmental effect. Approximately 62 million dry
metric tons of ash and 2.7 million dry metric tons of sludge
were produced in 1977. Fly ashes from western coals can
stabilize scrubber sludges better than ashes from eastern coals
because of the higher calcium content and alkalinity of western
coals. Stabilization consists of lower permeability and higher
structural strength.
Disposal practices for FGC wastes were addressed in
Task 3. A° distinction was made between ponding versus land-
filling. An average distance of 3 miles from the plant was
was determined. The economic impact of RCRA Section 4004 was
assessed to the degree possible consistent with the scope of work
and available information. Information gained in this task
provides part of the basis for determination of the impact of
regulations pertaining to solid waste disposal. Preliminary
assessment of the data indicate that RCRA could have a signifi-
cant impact on the current and future disposal practices of the
utilities and could have economic impact on the utility industry
as a whole. Alternate disposal methods such as mine disposal,
ocean disposal and landfarming were also examined. Mine disposal
either in surface or deep mines is the most technically possible
and environmentally acceptable alternate to ponding and landfilling,
The final task area involved evaluation of the methods
of the utilization of fly ash, bottom ash and scrubber sludge.
Both current and future recovery methods were identified and
evaluated with respect to technical, geographical, environmental
and economic considerations. Although regenerable processes
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are in full-scale operation at several U.S. plants in 1978, it
is not foreseen that these regenerable processes will signifi-
cantly reduce the industry-wide quantity of FGD scrubber sludge
in the near term. In specific instances where the sulfur or
sulfuric acid by-products can be marketed, regenerable processes
can reduce the FGC waste quantities and allow collection and
utilization of dry fly ash without the need for using fly ash to
fix scrubber sludge. Utilization of FGC waste products is
important in that it reduces the quantity requiring disposal,
conserves natural resources and can generate revenues to offset
collection and disposal costs. Ash utilization was 21 percent
in 1977 while sludge utilization was nil. Research and incentives
to increase utilization of the FGC by-products are needed.
A summary of the findings of this study follows:
1.1 Characterization of Electric Utility Industry
The characterization of the utility industry consisted
of the number of coal-fired plants organized according to in-
ventories within the ten EPA regions and also within each of the
states. The total coal-fired capacity was also delineated in
the same manner. The financial status of the utility industry
was also assessed. These characterizations will provide in-
formation to each of the states and each of the EPA regions in
assesing their level of effort in implementing RCRA Section 4004.
Results of this task also summarize the financial status of the
utility industry and provide a partial basis for interpreting
the economic impact of Section 4004 on the utility.
Utility owned,coal-fired generating plants in the
United States were inventoried for the year 1976. There were 171
utilities owning approximately 399 coal-fired power plants.
These 399 plants had a total coal-fired capacity of 202,380 mega-
watts (Mw) .
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The distribution of this coal-fired generating capa-
city by state in 1976 is shown in Figure 1. The number of
utility-owned, coal-fired plants within each state is indicated in
parenthesis. The EPA regions are indicated by heavier border
lines. Most are in EPA regions III (60 plants), IV (72), V (141.)
and VII (49). These same four regions also accounted for 85 per-
cent of the electrical energy produced from coal. Region IV<
(50,000 Mw) and Region V (69,000 Mw) accounted for over 50 per-
cent of the total U.S. coal-fired capacity. Significant growth
is anticipated in the southern and western EPA regions.
In 1976, approximately 25 percent of the plants had
less than 100 Mw capacity. Approximately 40 percent of 157
plants had capacities between 100 and 500 Mw. There were 72
plants with coal-fired capacities of 500 to 1000 Mw and 57 plants
in the 1000-2000 Mw range. Only 12 plants had capacities greater
than 2000 Mw. The average coal-fired capacity of all plants was
approximately 500 Mw.
Approximately 78 percent of the installed generating
capacity in the U.S. is operated by investor-owned utility
companies, serving about 78 percent.of the nation's utility
customers. Public power systems (10 percent of capacity, 12
percent of customers), rural electric cooperatives (2 percent,
10 percent) and TVA (10 percent, 0 percent) own and serve the
remainder. Each electric utility company, public power system,
or cooperative operates as regulated monopoly in a designated
service area. The industry is highly capital investment-inten-
sive. It has experienced diffuculty in raising capital during
recent years due to decreasing bond ratings and increasing interest
charges. During these years, investor-owned utility companies
have experienced difficulties in raising capital through stock
sales; price-book ratios less than 1.0 have been consistently
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(2) plants
2.3 x 1000 Mw
Lege
• (2)
| 2.3
VI
I
Number of coal-fired plants
Coal-fired generating capacity
EPA region,designating boundaries|
are indicated in bold lines.
Figure 1-1. Distribution of coal-fired generating stations
and coal-fired capacity by states (1976)
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reported. While the industry's financial condition has improved
somewhat since 1974 (the worst year), it has not sufficiently
recovered to be considered healthy. Financial analysts believe
that (1) inflation levels of 4 percent per year could cause
improvements, (2) Inflation levels of 5 to 6'percent per year are
only tolerable, and (3) inflation rates' in excess of 10 percent
per year could restrict investment to the point that additional
rate increases would be required in order to finance capital
expenditures.
Utility regulation affects both plant construction and
rates charged for services. Typical licensing times for coal-
fired power plants range from 33 to 49 months. The licensing
procedure may require up to 50 permits from a number of different
regulatory agencies. Customer rate bases approved by rate com-
missions between 1974 and. 1977 have reflected returns on common
equity ranging from 10.6 to 11.8 percent. In early 1978 a return
on common equity of about 12 percent was considered reasonable by
financial analysts. Current capital costs for coal-fired plants
reflected in these rate bases range from $450 to $800
per installed kilowatt capacity. Credit for costs of construction
work in progress (CWIP) may or may not be reflected in the rate
base, depending on the discretion of the governing rate commission.
Generally, credit for CWIP, if granted, is based upon the financial
state of the company, and it allows financing through rate increases
rather than through the money market. Future revenue requirements,
which will eventually be reflected in rate bases, have been esti-
mated to range from about 3
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capacity (35%). Region VI and other parts of the west are
forecast to have significant growth during the next few years.
Consequently, the states' agencies and EPA region staff of these
regions will bear the bulk of the implementation of Section 4004.
The bond ratings of the utility have been low since 1973 and
price-book ratios of less than 1.0 have been consistently
reported. Consequently the utility industry is not financially
healthy.
1.2 Characteristics of Solid Wastes
The quality of coal fired in the boiler is the single
most important variable affecting both the quality and quantity
of ash and scrubber sludge produced. The quantities and quali-
ties of ash and sludges produced by burning western and eastern
coals in a "model" 1000 Mw power plant are shown in Table 1.
The coal is the source of the minerals, both major and trace
elements which comprise the fly ash and bottom ash. The quantity
of scrubber sludge produced is largely a function of the sulfur
content of the coal. The coal is also a major source of the
chlorides and volatile trace elements found in the scrubber
liquor. The makeup water and sorbent (lime or limestone) are
other sources of dissolved species in the scrubber liquor.
The environmental impact and consequently the disposal
methodology for reducing or minimizing this environmental impact
is significantly affected by the quantity and characteristics of
the FGC waste by products: fly ash, bottom ash and scrubber
sludge. The factors influencing quantity which have been
characterized by a number of scenarios include coal quality,
scrubber type and operation, and emission regulations. The
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TABLE 1-1 TYPICAL QUANTITIES AND QUALITIES OF
ASH AND SCRUBBER SLUDGE FOR MODEL 1000 MW
POWER PLANT
Western Coal
Eastern Coal
Quantities
(Dry Metric Tons/yr)
Current Regulations*
Fly Ash & Bottom Ash
Scrubber Sludge
Future Regulations**
Scrubber Sludge
Qualities
Chemical
Fly Ash
Scrubber sludge
Structural
Fly Ash
Fly Ash/Scrubber
Sludge in Mixture
Naturally Oxidized
Scrubber Sludge
Leaching
Fly Ash
270,000
17,000
102,000
> high alkalinity
Cement-like properties can
stabilize scrubber sludge
Higher sulfate content
Stable
Stable
Unstable
High pH
408,000
336,000
Low calcium, low alkalinity,
even acidic In some cases.
Cement-like properties with
addition of line.
Higher sulfite content
Stable with adequate mois-
ture control and compaction.
Stable with adequate mois-
ture control and compaction
Unstable
pH alkaline to acidic gen-
erally higher solubilities
^Current regulations (1978) Maximum S02 emissions of 1.2 Ibs SO2/10s Btu.
Particulate emissions reduced by 99%.
**Future regulations proposed 9/19/78 -SOj concentration in flue gas reduced
by 85% or to .2 Iba S02/10S Btu.
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chemical, physical, structural and leaching properties of
each of the three wastes have been discussed based on available
information.
Chemical and physical properties of the material dictate
to a large extent the structural and leaching properties of the
material. Structural properties describe the structural stabil-
ity of the disposal material and future uses of the reclaimed
land. Leaching properties are a major consideration in evaluat-
ing the potential for groundwater or surface water contamination.
Results of this task are summarized in the following paragraphs.
The firing of western coal (9,000 Btu/lb, 87, ash, and
0.37. sulfur) in a 1000 Mw generating plant can result in 218,000
dry metric tons of fly ash per year (99% removal) and 54,000 dry
metric tons of bottom ash per year. Approximately 17,000 dry
metric tons or 50,000 wet metric tons (35% solids) of scrubber
sludge would be produced with current S02 regulations of a maxi-
mum emission of 1.2 Ibs S02/106 Btu and representative scrubber
operations. Stricter particulate regulations will not signifi-
cantly impact the quantities of fly ash produced either from
«
eastern or western coal. An expected S02 regulation of 85 per-
cent removal will increase the scrubber sludge quantity of this
1000 Mw plant from the 17,000 to 102,000 dry metric tons to
113,000 dry tons per year. The firing of eastern coal (11,000
Btu/lb, 15% ash, and 3% sulfur) in the same 1000 Mw plant results
in 408,000 dry metric tons/year of ash and 336,000 dry metric
tons/year of scrubber sludge under current regulations.
The effect of scrubber operation on the quantity of
by-products was evaluated. The use of forced oxidation in a
limestone scrubbing process will increase the quantity of dry
scrubber sludge by 20 to 30 percent, but can be offset by
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improved dewatering and settling properties. Approximately 20
to 30 percent more scrubber sludge will be produced with a lime
or limestone stoichiometry of 1.5 (67% utilization) than with a
stoichiometry of 1.1 (907, utilization).
Fly ash is made of fine particulates similar in texture
to Portland cement, with specific gravities ranging from 2 to 3.
Chemically, it primarily consists of silicon, aluminum and iron
compounds. In addition, western ashes have significant quanti-
ties of calcium, magnesium, sodium and sulfur compounds. The
calcium compounds of the fly ash are responsible for the cement-
like qualities the western fly ash displays when mixed with water
or with wet scrubber sludge.
These western fly ash disposal materials have displayed
a higher degree of structural, stability and impermeability than
equivalent mixtures made with eastern bituminous fly ashes. The
unconfined compressive strength of western fly ash disposal
materials are reported to range from less than 100 psi to over
5000 psi. For comparison, a car exerts 30 psi on the surface
while a person walking exerts 5 psi. Permeability coefficients
of the western fly disposal materials varied from 10"s to 10~10
cm/sec. Permeability coefficients less than 10"s cm/sec are
considered low. For example, permeability coefficients of 10"7
cm/sec and lower are specified as suitable for lining.
Adequate structural stability for disposal can be
achieved using eastern fly ashes with moisture control and
compaction. Because of the pozzolanic nature of the eastern fly
ashes, lime can be added to reduce the permeability further and
to enhance the structural stability.
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Bottom ash is collected in the bottom of the boiler
as a coarse, angular particle ranging from 50 microns to 1 inch
in diameter, similar to fine gravel and sand. Consequently,
it has a high porosity with permeability coefficients, typically
ranging from 10"l to 10"3 cm/sec. It displays no cohesive qual-
ities. With respect to major species, it is chemically very
similar to its respective fly ash. However, leachable constituents
are. significantly lower, in part due to its fused condition and
reduced surface area.
The principal components found in scrubber solids are
the calcium sulfite coprecipitate, gypsum and calcium carbonate.
The scrubber liquor will be composed primarily of calcium,
magnesium, sodium, chloride, sulfite, carbonate and sulfate. •
The relative concentration of the liquid and solid phase chemical
species will be dependent on the S02 and oxygen concentration in
the flue gas, the type of scrubber system, the quality of sorbent
and makeup water, and the operation of the scrubber.
Scrubber sludges as received from a clarifier are not
structurally stable and have relatively high permeabilities. In
general, scrubber sludges behave as cohesiveless materials dis-
playing unconfined compressive strengths less than 20 psi. In
many cases the scrubber aludges are not structurally stable.
Permeability coefficients of 10"3 to 10"* cm/sec are reported
for settled and drained FGD scrubber sludges. By applying more
extensive dewatering techniques (e.g., vacuum filtration or
centrifugation) and compaction techniques the permeability
coefficients can be reduced to 10"* to 10"5 cm/sec, and the
structural properties enhanced. Upon stabilization with either
western fly ash, eastern fly ash and lime, or with some commer-
cial fixation techniques, unconfined compressive strengths in
excess of 100 psi can be acheived. Disposal materials with these
properties are structurally stable and relatively impermeable.
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The leaching of fly ash, bottom- ash and scrubber sludge
is important with respect to possible ground-water or surface
water contamination. The concentration of major species in the
FGD scrubber sludge is high particularly in comparison with that
of the ash leachate. During the active stages of sludge or ash/
sludge disposal, the characteristics of the leachate will be
dominated by the quality of the adherent scrubber liquor and will
contain high concentrations of chloride, sulfate and total dis-
solved solids (sodium and magnesium in some cases). After the
original adherent scrubber liquor is leached, the solubilities of
calcium sulfite hemihydrate, gypsum and calcium carbonate will
control the concentration of major species.
Trace element concentrations in the leachate are highly
variable and are dependent upon the chemical characteristics of
the leaching solution, the pH, temperature, the solubility of the
compound containing the trace element and the concentration in
the solid phase. A review of available field leaching data of
FGC waste products fly ash, bottom ash and scrubber sludge has
revealed that the average reported concentration of all chemical
species were below the September 12, 1978 RCRA criteria for
toxicity. The average concentration of the following chemical
species have exceeded or were near the federal drinking water
standards or irrigation water quality parameters:
Arsenic Chromium Manganese Molybdenum
Boron Fluorine Mercury Selenium
Application of the same evaluation criteria to FGD sludge liquors '
and elutriates indicates that the average concentration of the
same elements plus cadmium exceeded either the drinking or
irrigation water quality criteria. These water criteria were
not meant for evaluation of FGC waste leachates but are used here
for reference in lieu of applicable concentration standards for
FGC leachates.
-12-
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In summary, western subbituminous coal produces less
ash and scrubber sludge than eastern bituminous coal does in
producing the same amount of electricity. If the expected air
regulation of 85 percent S02 removal is applied, the quantity of
scrubber sludge produced by an installation firing western coal
will be increased substantially. This effect is minima': for
units firing eastern coal. Western coals, in general, produce a .
fly ash which has significantly higher calcium concentrations and
higher alkalinity than that produced by eastern coal. The higher
calcium concentrations and available alkalinity have been correlated
with the capability of the western fly ashes to stabilize struc-
turally the scrubber sludge without the addition of lime and
other fixation additives.
Permeabilities below 10"s cm/sec and unconfined com-
press ive strength in excess of 100 psi can be achieved upon
stabilization with either western fly ash, eastern fly ash and
lime, or other fixation techniques. The quality of leachates
from FGD scrubber sludge will initially be governed by the quality
of the adherent scrubber liquor and later by the solubility
of the solid phase. The average reported concentration of arsenic,
boron, chloride, chromium, fluorine, manganese, mercury, moly-
bdenum, selenium and sulfate exceeded federal drinking and irri-
gation water criteria.
1.3 Waste Disposal Practices
This task investigated current disposal methodologies
employed by the utility industry in the disposal of their FGC
by-products, fly ash, bottom ash and scrubber sludge. The pre-
valence of these practices in 1978 was determined and then pro-
jected into- the future. Alternate disposal technologies which
-13-
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may be applicable in the future were also considered. An analysis
of the transportation distance from point of origin to the final
disposal site was made in order to assess the economic impact of
disposal.
The economic impact of implementation of RCRA. was
estimated by interpreting the RCRA relative to the disposal
of nonhazardous solid wastes from the electric utility industry.
In the absence of a sufficient data base, the cost of RCRA com-
pliance was estimated by (1) making "reasonable" assumptions
regarding existing and new plant situations and (2) applying
engineering and cost data for a typical coal-fired plant to
calculate the nationwide cost of compliance for a hypothetical
enforcement scenario.
1.3.1 Current Disposal Practices
Current practices for disposing of solid waste products
generated by coal-fired utility plants were determined from two
data sources. One source was the Federal Power Commission Form
67 data tape which contained information reported by the utility
companies to the FPC for the year ending December 31, 1974.
Selected utility plants were contacted and the literature was
searched to supplement the Form 67 data and provide more current
information.
Data for 1978 were obtained from 64 plants producing
over one-third of the fly ash and bottom ash concerning their mode
of disposal, quantities, utilization, distance to disposal site
and disposal costs. Information on sludge disposal practices
was obtained from other recent reports.
-14-
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Disposal of FGC by-products can be placed in two gen-
eral categories, ponding or landfilling. Significantly more
fly ash is currently disposed of in landfills (51 percent) than
in ponds (34 percent). However, more plants use ponding of the
fly ash than landfilling. Current bottom ash disposal practices
favor ponding (44 percent) over landfilling (29 percent). The
test of the ash is either utilized or disposed of in undisclosed
methods (paid disposal or other).
Future trends are anticipated to favor landfilling.
Sufficient data was not available to determine the percentages
of disposal sites which are utilizing linings and/or monitoring
wells.
Information on the amounts of scrubber sludge ponded.
versus landfilled or other modes was not available on a consistent
and meaningful basis either from the FPC data tape or from con-
tacts with the utilities. This is principally due to the fact
that scrubber sludge is produced as a wet product in slurry form.
There was lack of consistency in reporting amounts based upon a
dry product versus a slurry with varying percentages of solids
on a weight basis. However, applicable documentation estimated
that in 1977 approximately three million tons of FGD scrubber
sludge on a dry weight basis were produced. Of the 30 plants
producing sludge, 60 percent employed ponding and 40 percent
employed landfill. Five of these plants stabilize the scrubber
sludge by mixing with fly ash and lime (three have contracted with
I. U. Conversion Systems). Two plants stabilize by blending with
alkaline ash (one has contracted with Research Cottrell). One
plant uses Dravo's Calcilox method for stabilization of the scru^-oer
sludge followed by ponding. Of the 37 utilities who have scrubber
-15-
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plans announced, 51 percent will use landfilling as opposed to
ponding. This increase in percentage (40 percent to 51 percent)
of plants choosing landfilling over ponding indicates a trend
towards landfilling.
In order to characterize current disposal practice in
terms of distance from generating plant to ultimate disposal site
(whether pond or landfill), selected utilities responsible for
producing over one-third of the fly ash and bottom were contacted.
The tabulation of this data indicated that approximately 93
percent of fly ash and bottom ash is transported less than five
miles from generation point to disposal point. The mean distance
from plant to disposal site was 3.0 miles. The average distance
each ton of ash was transported was slightly less than 2.7 miles.
This information is more valuable in predicting costs than just
a breakdown between on-site vs off-site costs. However, it is
highly probable that the majority of disposal sites within five
miles of the generating plant are located on-site.
1.3.2 Economic Impact of RCRA
The enforcement function of RCRA is intended to be per-
formed by the states. The state agencies will have considerable
flexibility in classifying sites as sanitary landfills or open
dumps and determining both compliance options and compliance
schedules for facilities classified as open dumps. Under current
circumstances, it was not possible to determine the number of
facilities potentially affected by RCRA or the course of action
facilities will have to take. For these reasons, the economic
evaluation was based on hypothetical enforcement scenarios as
opposed to an estimate of the cost of compliance for the whole
industry.
-16-
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The economic evaluation was accomplished by estimating
the costs for (1) potential enforcement options relating to RCRA
and (2) current disposal practices. The analysis involved
scenarios for existing and planned (or future) plants. The cost
estimates were based on costing various disposal options for a
"typical" 1,000 MW coal-fired plant. These cost factors were
then used to determine the cost of compliance by applying them
to the entire generating capacity assumed to be affected.
Several key assumptions were necessary to estimate the
economic impact of RCRA.. Some of these assumptions have a sound
basis. However, others are subject to question. The assumptions
are presented only as being reasonable and should not be con-
strued as being the only reasonable assumption. Furthermore,
the economic estimate presented here should be evaluated in light
of these key assumptions.
The potential impact of RCRA on existing plants was
assumed to be limited to plants beginning operation after 1970.
The plants were assumed to have to move disposal from the current
distance of 4.8 kilometers (3 miles) to 16.1 kilometers (10 miles)
New landfill sites were assumed to be necessary to protect ground-
water. Ponds were assumed to be lined. It was assumed that
(1) the landfill and ponding cost factors developed for the
"typical" 1000 MW coal-fired plant could be applied to the
1970-1976 distribution of existing generating capacity and (2)
one-half of the existing capacity would have to move their dis-
posal sites.
For planned (or future) plants, the primary assumption
was that all plants would be affected by RCRA. The projected
capacity to be constructed in the 1975-1985 period was taken to
be 160,000 Mw, or 160 "typical" 1000 MW plants. The primary
-17-
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effect of RCRA was assumed to be distance from plant to disposal.
The average distance from plant to disposal was assumed to be
8.0 kilometers (5 miles) for RCRA as opposed to 4.8 kilometers
without RCRA. As with existing plants, all ponds were assumed
to be lined and the cost factors for the "typical" 1000 M5J plants
were assumed applicable.
A summary of the estimated cost of compliance with
RCRA is presented in Table 1-2. The cost of well monitoring
($4,000,000/yr) has been included in the revenue requirements for
the existing and planned facilities.
It is estimated that the capital Investment costs re-
lated to disposal of electric utility nonhazardous solid waste
will increase 36 percent or approximately one billion dollars due
to compliance with RCRA. Annual revenue requirements, however,
are estimated to increase only 5-6 percent, from 1.20 billion to
1.27 billion dollars per year.
In general, the cost data used indicate that the cost
of disposal rises sharply with the distance from the plant.
Ponding is economical only at very short distances. At greater
distances, the cost of pumping is very high. The cost of liners
is also very important. The cost differences between clay liners
and synthetic liners may vary by 50 percent or more. When the
capital investment is in the range of 10 to 50 million dollars per
plant, a difference of 50 percent is large.
The assumptions that have the greatest effect on the
cost estimates are the ones concerning (1) how the plants would
comply with RCRA associated regulations, (2) what those regula-
tions might be, and (3) the applicability of the cost data
-18-
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TABLE 1-2. SUMMARY OF ESTIMATED COST OF COMPLIANCE
(MID 1979 DOLLARS)
Capital Investment Costs ($) Revenue Requirements ($/yr)
Estimated Cost Estimated Current Estimated Cost Estimated Current or
of Compliance with Predicted of Compliance Predicted Cost - No
with RCRA Cost - No RCRA with RCRA RCRA
Existing* 49,075,000 0 68,725,000 55,350,000
Plants
(1970-1978
Construction)
Planned and 3,631,750,000 - 2,699,650,000 1,202,700,000. 1,148,140,000
Future
^ Facilities
& (1978-1985)
Total Costs 3.680,825,000 - 2,699,650,000 1,271,425,000 - 1,203,490,000
Net Costs 981,175,000 67,935,000
*AR8iimlne SOX out of Compliance
-------
for the generalized calculations made in this study. Several
important factors were not included in the analysis of the cost
of compliance. One important question is the fate of any existing
disposal facilities abandoned because of danger to groundwater.
If such facilities are forced to remove the waste materials
and recover the site, the costs would be very high. If the
facility is allowed to cover ponds or landfills and abandon them,
the impact will be limited to the costs associated with the mature
retirement of the facility.
Another important cost consideration that was not in-
cluded in the study was the cost of building a levee to protect
ponds from flooding. As the potential impact of the levee on
flood water retention is a major factor, a study must first be
conducted to determine if such structures can provide protection
while allowing passage of flood water. If levees can be constructed
that will be in compliance with these restrictions, the cost of
construction and maintenance will be highly site dependent.
1.3.3 Alternate Disposal Technologies
Three alternate disposal techniques - mine disposal,
ocean disposal and landfarming - have been considered.
Of the three techniques, disposal in mine is the most
promising. Disposal in surface mines is the most technically
feasible for several reasons. Surface mines offer substantial
capacity, ease of disposal, future resource recovery, and in many
cases close proximity to sludge sources. One potential benefit
of disposal in deep mines is in preventing mine subsidence.
Mine disposal in general should be considered a viable disposal
alternative. The suitability of a mine will be site-specific
-20-
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and depend on factors such as geographical location, site
geology and site hydrology. Provided transportation distances
are not excessive and lining is not required, surface mine
disposal can be less expensive than ponding or landfilling.
More work is needed to study waste/mine interaction both chemi-
cal and physical. Other studies could discuss the potential for
mine disposal on a regional basis.
Significant questions have been raised as to the
environmental acceptability of ocean dumping of FGC wastes.
Four principal impacts have been identified: Benthic sedi-
mentation, suspended solids, increased chemical oxygen demand
and trace element contamination. Existing regulations and
regulatory initiatives do not favor any new ocean dumping
However, the disposal of stabilized FGD sludge blocks in ocean
as manmade reefs appears promising. Costs of disposal have been
estimated to range from $4.00 to $12.50 per dry ton of sludge.
Additional research is required to characterize the chemical,
physical and biological interaction with the ocean environment.
Landfarming does not seem to be a viable option because
of a lack of nutrients, the potential for excessive concentrations
of trace elements and the large volume of solid waste involved.
In summary, disposal practices of the utilities equally
favor ponding and landfilling. Future trends slightly favor
landfilling. Disposal in surface and underground mines is tech-
nically and economically feasible and consequently may see in-
creased usage as a disposal site. The mean distance from the
plant to disposal site is 3 miles. RCRA Section 4004 will
result in increased disposal costs to the utility industry as a
whole. Current practices of some utilities will meet RCRA
Section 4004 requirements and consequently will feel little
economic impact. Sites of other utilities will require sub-
stantial upgrading which will result in significantly higher dis-
posal costs. -21-
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1.4 Utilization of Utility Wastes
For coal-fired utility plants, recovery practices
are directed toward the utilization of the fly ash, bottom ash
and/or boiler slag and flue gas desulfurization scrubber sludge
in some form. Utilization of the by-produces would be desirable
in that
1) it reduces the quantity of wastes requiring
disposal thus reducing disposal costs and
potential adverse environmental impacts
of disposal, and
2) it conserves other U.S. natural resources
and can result in income to offset the
costs of disposal.
In 1977 total U.S. production of fly ash, bottom ash
and boiler slag was 67.3 million tons with 14.0 million tons
successfully recovered and utilized for a utilization of 20.7
percent.
Several areas of fly ash, bottom ash and boiler slag
utilization have been proven technically feasible. These areas
are summarized in Table 1-3.
The utilization of calcium sulfite/sulfate based FGD
scrubber sludge has been much more limited than that of ash.
Utilization of scrubber sludge is more one of conceptual
development and testing for recovery rather than actual wide-
spread utilization. Possible uses for scrubber sludges are (1)
recovery of chemicals, (2) manufacture of building materials,
(3) structural fill, (4) paving materials, (5) soil stabilization
in agriculture and (6) environmental pollution control. Only the
-22-
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TABLE 1-3. U.S. ASH UTILIZATION IN 1977
Total Ash Collected
(10s tons)
Total Ash Commercially
Utilized ' -
(10 8 tons)
Utilization (%)
Raw Material - Portland
Cement
Type 1 - P Cement
Partial Replacement of
Cement in Concrete
Lightweight Aggregate
Structural Fills &
Embantocent 3
Road Base and Subbase
Asphalt Filler
Ice Control
Blasting Grit and
Roofing Material
Miscellaneous
Fly
Ash
48.5
4.2
10
7
37
3
30
4
3
-
3
Bottom
Ash
14.1
2.8
—
3
—
5
33
8 .
-
3.6
15
Boiler
Slag
5.2
3.0
3
-
—
-
8
2
-
14
50
23
-23-
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production of gypsum wallboard and the utilization of gypsum
in making Portland cement have any possibility as a signifi-
cant outlet for scrubber sludge in the foreseeable future.
Regenerable SO2 processes have the capability of
reducing the tonnage of sJudge while producing commercial by-
products with demonstrated markets. Regenerable SO2 processes
eliminate the calcium sulfite/sulfate scrubber sludge while
producing either sulfur or sulfuric acid. Another advantage of
regenerable processes is that they make more ash available for
utilization, since some of the ash would otherwise be required to
stabilize the scrubber sludge.
Marketability of sulfur and/or sulfuric acid would
appear to be limited for the next 10-12 years on any widespread
basis. In general, existing sources of sulfur and sulfuric acid
are available to meet demand. However, in certain locations
unique conditions might create a local market. After 1990,
marketability of sulfur and sulfuric acid derived from fossil
fuel S02 may very well be enhanced because deposits of sulfur
presently being mined along the Gulf Coast are expected to be
depleted.
Regenerable processes do require a pre-scrubber
system prior to the S02 removal system to remove fly ash and
chlorides. The pre-scrubber waste stream will be small (5-10
percent) compared to the typical scrubber sludge waste stream,
but will also have to be evaluated carefully as an environmental
hazard due to its high proportion of soluble species.
-24-
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In summary, utilization of FGC by-products is impor-
tant in terms of reducing environmental impact, conserving
natural resources and boosting the economy. The majority of the
fly ash is used as a fill material. Bottom ash is principally
used as a fill material and for skid control. The largest
portion of the boiler slag is used as blasting grit and roofing
material. Current utilization of F6D scrubber sludge is
practically zero. Regenerable processes in a limited scale can
replace the scrubber sludge with either sulfur or sulfuric acid.
1.5 Conclusions and Recommendations
The solid wastes produced by coal-fired electric
utilities were examined with regard to the requirements of
Section 4004 of the Resource Conservation and Recovery Act.
The study involved four major tasks: (1) characterization of
the electric utility industry, (2) characterization of the solid
wastes, (3) waste disposal practices, and (4) utilization of
utility wastes.
The following conclusions have been drawn based upon
the results of this study:
1) Implementation of Section 4004 of the
RCRA will be borne primarily by the
states and EPA staffs in Regions III,
IV, V and VII. These regions account
for over 85 percent of the coal-fired
capacity in 1976. The coal-fired
capacity of Region VI and other western
states will undoubtedly increase in the
near future.
-25-
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2) Technical information available at this
/v <*pp**r$
time indfcataj that the majority of utility
solid wastes are nonhazardous and, as such,
will require disposal in sanitary landfills.
Furthermore, fly ash, bottom ash, and
scrubber sludge mixtures can be stabilized
to improve structural strength and reduce
permeability. However, sufficient hydrologi-
cal data from existing disposal sites are
not available for adequate assessment of the
degree to which existing sites qualify as
sanitary landfills.
3) The use of western coal is more desirable
in that its combustion produces 33 percent
less fly ash and 95 percent less scrubber
sludge than eastern coal under current S02
and particulate regulations. The potential
future regulation of 85 percent S02 removal
remove part of this incentive to use western
coal. Western coal has the added advantage
of producing alkaline fly ashes which are
capable of stabilizing FGD scrubber sludges.
4) The economic impact of RCRA was estimated
to be roughly 1 billion dollars in capital
investment and 70 million dollars in annual
revenue requirements for a hypothetical
enforcement scenario involving the modifica-
tion of disposal sites for approximately
20,000 Mw of existing capacity and 160,000 Mw
of planned capacity. It should be emphasized
that these costs are only rough estimates and
highly dependent upon the scenario basis and
key assumptions.
-26-
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5) Utilization of utility wastes should be
strongly encouraged because it reduces
the environmental impact of disposal,
conserves natural resources and could
boost the economy. Utilization may be
increased by eliminating the three major
areas of resistance: (1) technical
limitations compared to alternative
materials, (2) institutional barriers
related to .poor understanding or
inadequate market development, and
(3) possible environmental concerns
related to some uses. Regenerable S02
control processes will probably not
significantly reduce the industry-wide
production of.solid wastes, although
these processes can reduce the solid
waste disposal requirements for a
particular utility where local markets
exist for sulfur and sulfuric acid.
Additional effort can be recommended in many areas
examined by the study. Three major areas requiring further work
are listed below:
1) Additional effort is required to determine
the probability of existing disposal sites
being classified as open dumps and thus
needing upgrading. This will require
documentation of existing information
and then an intensive characterization
of all existing disposal'sites.
-27-
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2) Further research is needed to correlate
the leachability of solid wastes with coal
quality, degree of coal pulverization,
type and operation of boiler, type and
operation of control equipment, and
disposal methodology. Results of this
research will allow the selection of a
disposal technology (prior to construction
of the power plant) which will insure no
adverse effects on the environment.
3) An aggressive program is needed to eliminate
the three areas of resistance to utility
waste utilization. First, technical limita-
tions in comparison to alternative materials
must be surmounted through research and
development. For example, in light of an
impending mineral crisis, basic research and
development should be funded to develop
extraction processes for minerals and trace
•elements from FGC by-products. Second,
institutional barriers related to a poor
industry or user industries must be removed.
Marketing of these by-products needs encourage-
ment, perhaps through financial credits of
some sort. Third, where potential environ-
mental concern exists, policy decisions based
upon the relative merits of a particular
application compared to the environmental
Impact of landfilling or ponding must be
made.
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2.0 CHARACTERIZATION OF ELECTRIC UTILITY INDUSTRY
For the purposes of this study, the United States
electric utility industry was characterized in terms of two
items: fuels and economics. Of particular interest in the
fuels area is that fraction of power plants which burn coal,
either exclusively or in combination with other fuels. In terms
of economics, both the general state of the industry and the
regulatory climate under which it functions are of interest.
These topics will be discussed in the following subsections.
2.1 Fuels Characterization
Electric power is usually produced commercially through
the operation of AC generator, or alternator, which is driven by
a prime mover. Almost 70 percent of these prime movers are steam
turbines powered by boilers which consume fossil fuel (either
coal, oil, or gas). Figure 2-1 shows the relative importance of
all prime movers in 1976, 1981, and 1986, as reported by the
National Electric Reliability Council (NERC).l As can be seen,
coal is singularly the most important fuel, and it will probably
remain the most important through this period.
For this study, all utility-owned coal-fired power -
plants* existing in 1976 were inventoried. This inventory was.
based on 1974 FPC (now FERC) Form 67 data updated through 1976
by utilizing data in the 1977-1978 Electrical World Directory of
Electric Utilities.2 In some cases, data were verified through
*For this study, a coal-fired power plant is defined as a facility
consisting of one or more generating units, which burns coal alone
or in combination with other fuels and which produced electricity
for sale to the general public. Some boilers in the plant may
not be equipped to burn coal. A coal-fired unit, for this study,
is a unit equipped to burn coal, regardless of actual fuels con-
sumed.
-29-
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GENERATION SOURCE
1
g
u
COMBUSTION ?JS3INE
C2-2407-;
FIGURE 2-1. EXISTING AND PLANNED GENERATING
CAPABILITY AS ESTIMATED BY NERC (SOURCE: REF. 1)
-30-
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comparison with other reported data1'3'1*'3 and Radian proprietary
data. Results of this inventory are summarized for the 10 EPA
regions in the 48 contiguous United States. These regions are
as follows:
Region I - Maine, Vermont, New Hampshire, Rhode
Island, Massachusetts, Connecticut
Region II - New York, New Jersey
Region III - Pennsylvania, Delaware, West Virginia,
District of Columbia, Maryland, Virginia
Region IV - Kentucky, Tennessee, North Carolina,
South Carolina, Georgia, Alabama, Florida,
Mississippi
Region V - Wisconsin, Michigan, Illinois, Indiana,
Ohio, Minnesota
Region VI - Texas, Arkansas, Louisiana, Oklahoma,
New Mexico
Region VII - Nebraska, Kansas, Iowa, Missouri
Region VIII - Montana, North Dakota, South Dakota,
Wyoming, Colorado, Utah
Region IX - Arizona, California, Nevada
Region X - Washington, Oregon, Idaho
Table 2-1 shows the number of facilities with coal-fired units,
the electric megawatt (Mw) capacity of these facilities, the
amount of coal-fired capacity in Mw, and the average size in Mw
of a coal-fired unit for each region. Table 2-2 gives the actual
size distribution of coal-fired capacity for each region. For
the nation, there were 399 plants inventoried, with 65 percent
having coal-fired capacity less than 500 Mw. There were 57 plants
with coal-fired capacity from 1000 to 1999 Mw and there were 12
plants whose coal-fired capacity was in excess of 2000 Mw-.--- These
largest plants were in Region III (2 plants), Region IV (4 plants),
Region V (3 plants), and Regions VI, VII, IX (1 plant each).
Most of the coal-fired plants were in Regions V (151), IV (72),
III (60) , and VII (49). These plants account for about 85 percent
of the coal-fired capacity in the nation and are located in the
Midwest and South (areas which have traditionally relied upon
-31-
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TABLE 2-1
INVENTORIED U.S. COAL-FIRED CAPACITY IN 1976
i
to
EPA Region
I
II
III
IV
V
VI
VII
VIII
IX
X
No. Plants with
Coal-Fired Units
Total Plant
Capacity
Total Coal-
Fired Capacity
Average Coal-Fired
Capacity Per Plant
(Mw)
7
16
60
72
151
5
49
33
5
1
3,441.
7,438.09
43,580.19
53,063.06
73,197.81
5,172.2
15,505.17
9,177.7
4,444.
1,329.8
3,295.89
6,333.96
39,474.80
50,153.7
68,832.58
5,172.2
14,264.76
9,171.2
4,351.
1,329.8
470.84
395.87
657.91
696.58
455.84
1,034.44
291.12
277.92
870.2
1.329.8
U.S. Total
Inventoried
for 1976
399
216,349.02
202,379.89
507.22
-------
TABLE 2-2
i
CO
LO
I
EPA No. Plants with
Region Coal-Fired Units
I 7
II 16
III 60
IV 72
V 151
VI 5
VII 49
VIII 33
IX 5
X 1
INVENTORIED COAL-FIRED CAPACITY WITHIN EPA REGIONS
Number of Plants with Given Coal-Fired Capacity
<100 MM
2
2
6
9
46
1
19
15
1
0
100-499 MM
3
9
30
29
55
0
18
11
2
0
500-999 MM
1
4
7
16
27
1
10
6
0
0
1000-1999 Mw
1
1
15
14
20
2
0
1
1
1
>2000 MM
0
0
2
4
3
1
1
0
1
0
U.S. Total
Inventoried
for 1976
399
101
157
72
57
12
-------
coal). Data by state for capacity and size distribution for
these plants, and all others inventoried are given in Appendices
A and B and all plants are itemized by EFA region and state in
Appendix C. Nationwide total coal-fired generating capacity as
inventoried was 202,380 Mw in 1976. This megawatt figure is 5.8
percent higher than the widely accepted NERC estimate1 of 191,336
Mw in 1976, probably because (1) nameplate data used may be differ-
ent in some cases, (2) the Radian data may have included some
plants under construction in 1976, and (3) the Radian data did
not include some plants which, while equipped to burn coal,
burned little or none during 1976. Consequently, while some of
these Radian data may be subject to review and revision, it is
believed that this inventory provides reasonable data on size and
location of coal-fired plants existing in 1976.
Industry based projections of coal-fired capacity and
coal consumption in 1981 and 1986 have been made by NERC1 for the
contiguous NERC regions (shown in Figure 2-2).* These projections
are shown for capacity in Table 2-3 and consumption in Table 2-4.
As can be seen from these tables, the use of coal will vary widely
across the country, with NPCC (most of EPA Regions I and II)
utilizing the least amount and ECAR (including most of EFA Region
V and parts of Regions III and IV), the most. The fastest growing
coal-using regions, in terms of reliance on coal as a fuel, are
ERGOT (17.3 percent per year) and SPP (12.4 percent per year),
both of which are primarily in EPA Region VI. In some regions,
the relative importance of coal is seen to be decreasing, although
total nationwide installed coal capacity is forecasted by NERC
to be increasing at the rate of approximately 5.8 percent per
year between 1976 and 1981 and approximately 5.2 percent per year
between 1981 and 1986. Reliance on western coal is also seen to
*NERC estimates are not delineated by individual states. Cross-
reference can be made using the EPA regions in Section 2.1 to
obtain very rough estimates of coal capacity in each EPA region.
-34-
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1 - ECA& • East Central Ar«* Reliability Coordination Agreeoent
2 - ERGOT - Electric Reliability Council of Texaa
3 • MAAC - Mid-Atlantic Area Council
4 - MAIB - lfid-Ag»rlc* Inc»rpool K«cvork
S - MASCA - Mld-Conela«ne Ar*« Rallabilicy Coordinacloa AgnoMic
6 - HPCC • HorthMac Power Coordlaactsg Council
7 . SEBC . Souctx«*»c«rn Elacczic Raliabtlity Council
3 • SP? - Souehmscarn Powar Pool
9 - WSCC - W«sc«rn System Coordlnacing Council
Figure 2-2
NERC RELIABILITY REGIONS
-35-
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TABLE 2-3
i
CO
NERC GENERATION PROJECTIONS. 1976-1986
NERC
Region
1-ECAR
2-ERCOT
3-MAAC
4-MAIN
5-MARCA
6-NPCC
7-SERC
8-SPP
9-WSCC
U.S.
TOTAL
Coal-Fired
Capacity
(Mw)
62.620
2,360
14,057
26,014
9,964
3.737
51,936
5,084
15,564
191.336
1976*
7. of Total
Capacity
for NERC
Region
81.7
6.9
33.7
66.1
49.3
7.6
52.1
11.8
17.3
38.7
1981
Coal-Fired
Capacity
(MW)
t
76,154
10,711
14,730
30,574
17,704
4,035
58,585
15,954
24,736
253,362
% of Total
Capacity
for NERC
Region
79.0
23.5
29.8
58^2
62.8
7.6
44.9
27.2
21.3
40.2
1986
Coal-Fired
Capacity
(MO
88,101
18, 999
16,989
37, 297
21,422
5,337
74,574
30,384
32,978
326,081
{ of Total
Capacity
for NERC
Region
73.8
34.1
27.1
56.4
60.8
8.4
43.4
38.1
23.0
40.9
*Actual capacity.
Source: Ref. 2.
-------
TABLE 2-4
ANNUAL COAL
REQUIREMENTS (MILLIONS OF
UTILITY INDUSTRY AS
NERC
Region
1-ECAR
2-ERCOT
3-MAAC
4-MAIN
i 5-MARCA
LO
T4 6-NPCC
7-SERC
8-SPP
9-WSCC
U.S.
TOTAL
1976*
Western
Lignite
0
12.
0
0
9.9
0
0
0
0
21.9
Western
Coal
6.7
0
0
12.9
12.4
0.8
0
9.1
39.9
87.8
Other
Coal
135.5
0
32.9
38.5
6.1
7.0
104.3
0
0
324.3
. !
Total
Coal
142.2
12.0
32.9
57.3
24.4
7.8
104.3
9.1
39.9
434.0
Western
Lignite
0
30.3
0
0
15.8
0
0
0
0
46.2
TONS)
FOR THE
U.S.
ESTIMATED BY NERC
1981
Western
Coal
12.2
15.7
0
21.7
30.6
1.4
1.4
57.7
78.1
218.8
Other
Coal
157.5
0
38.6
52.2
5.7
8.7
121.6
0
0
384.3
Total
Coal
169.7
46.0
38.6
74.0
52.1
10.1
123.0
57.7
78.1
649.3
Western
Lignite
0
58.0
0
0
24.7
0
0
7.0
0
89.8
1986
Western
Coal
20.9
18.2
0
30.9
39.5
1.8
9.2
113.4
103.1
336.9
Other
Coal
198.2
0
41.6
57.2
5.8
12.0
137.9
0
0
452.7
Total
Coal
219.1
76.2
41.6
88.1
70.0
13.8
147.1
120.4
103.1
879.4
*Actual coal requirements.
Source: Ref. 3
-------
increase at a rapid rate during this period, while total coal
consumption is expected to increase at a rate of about 8.4 per-
cent per year until 1981, when it will increase at a rate of
about 6.3 percent per year until 1986. Any effects of a revised
New Source Performance Standard for SO2 on western coal develop-
ment were not estimated.
Thus it can be seen that the use of coal as- a boiler
fuel in the electric power industry will continue to be highly
important, especially in some regions. While overall nationwide
coal growth is expected, reliance will decrease in some regions,
although these decreases will probably be offset by rapid increases
in reliance in other regions, especially in the Southwest. Pres-
ently, about 400 plants, with a total capacity of about 200,000
Mw, utilize coal as a fuel. Most of these plants are in the
Midwest and South. Consequently, coal for use as a boiler fuel
is now and will probably continue to be of great importance to
the U.S. electric power industry.
2.2 Economic Characterization
The electric utility industry is different from most
other industries in the United States because it is one of the
most, if not the most, capital investment-intensive industry.*
In the past, the ratio of investment to revenue for the electric
utility industry has been reported to be at least 15 times higher
than that for general business.5 Total installed fixed plant
facilities (generating units, transmission lines, etc.) were
valued at between 150 and 180 billion dollars in 1976.7 This
capital investment intensity requires that the utility industry
utilize considerably more long-term financing (such as bond) than
does general industry. Consequently, the effects of inflation
*0nly the railroads might have as much capital investment in fixed
physical plant.
-38-
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and uncertainty in the economy are considerably more important
than for general industry. Moreover, the industry is highly
regulated and cannot make investment decisions in the same
manner as general business. Therefore, the industry cannot be
fairly compared with and must be viewed apart from general busi-
ness. Over the last several years, the financial strength of
the industry has significantly declined with falling bond ratings
and stock selling for less than book value. While the financial
state of the industry has improved somewhat since the low point
in 1974, the general state is still only marginal, with reduced
investment at high interest rates, diminished buyer interest, and
extremely high sensitivity to inflation and uncertainty in both
the economy and the regulatory process.
Four types of electric utilities exist in the United
States today: (1) the investor-owned utility company, (2) the
municipal or state-owned utility or public power district (PPD),
(3) the rural electric cooperative (co-op) and (4) the Federal
agency. Table 2-5 illustrates the market shares of each of the
nation's customers and operating 95.6 percent of the nation's
generating capacity.a As can be seen, investor-owned utilities
account for 78.3 percent of nationwide installed capacity and
serve 77.6 percent of the customers. Municipal and state agencies
and PPD's constitute the next largest market share. Each "individual
utility (company, agency, or co-op) is franchised to operate-as a
monopoly within a certain specified geographical area, and the
rates which it may charge its customers are regulated by govern-
ment at some level. Consequently, the economic structure'of the
electric utility industry is very unique. In this section, the
economic status of the industry will be discussed.
-39-
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TABLE 2-5
RELATIVE MARKET SHARES OF ELECTRIC UTILITY
TYPES IN THE UNITED STATES FOR 1977
Type
Percent of
Installed
Capacity
Percent of
Customers
Served
Investor-Owned
Muni, State, and PPD's
Co-op's
Federal Agencies
77.6
12.4
10.0
0.0
U.S. Total
100.0
Source: Ref 8, p., 75.
100.0
-40-
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2.2.1 Capital Expenditures
As previously mentioned, the fixed plant requirements
of the electric utility industry are enormously high relative to
those experienced by general business. For example, prior to 1973,
a fossil-fueled single or twin unit 250-1300 Mw power plant costs
about $150 per kilowatt installed capacity. In 1977, the cost
had tripled to about $450 per kilowatt, and it is estimated to be
about $800 per kilowatt in 1985, although some costs in this
latter range have already been reported.* This capital cost
escalation from 1973 to 1977 was roughly four times the annual
rate of inflation (in percent per year) for the same period.10
As a further example of the high capital costs faced by the
industry, a 345 KV* double, circuit transmission line generally
costs about $165,000 per mile and up, depending on^ terrain, right-
of-way costs, labor costs, etc.11
Capital expenditures for 1977 and 1978 are shown in
Table 2-6 according to geographical region. These regions are
given by state as follows:
New England - Maine, Vermont, New Hampshire, Rhode
Island, Massachusetts, Connecticut
Middle Atlantic - New York, New Jersey, Pennsylvania
South Atlantic - West Virginia, Virginia, Maryland,
Delaware, District of Columbia, North
Carolina, South Carolina, Georgia,
Florida
East South Central - Kentucky, Tennessee, Mississippi,
Alabama
West South Central - Arkansas, Louisiana, Oklahoma,
Texas
East North Central - Wisconsin, Michigan, Illinois,
Indiana, Ohio
*345 KV is a median transmission voltage. In general, trans-
mission voltages presently range from 138 KV to 765 KV in the
United States, with higher voltage lines presently under develop-
ment.
-41-
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TABLE 2-6
Geographic Region
New England
Middle Atlantic
East North Central
West North Central.
South Atlantic
East South Central
West South Central
Mountain
Pacific
U.S. Total
ELECTRIC UTILITY CAPITAL EXPENDITURES - 1977 AND 1978
1977
Total Maintenance Costs
Millions of Dollars
766.6 (97. 4%)
3,106.2 (91.8%)
5,515.7 (92.3%)
3,071.9 (42.9%)
3,905.3 (84.6%)
2,466.7 (32.9%)
3,376.0 (75.1%)
1,821.1 (6*4.8%)
3,592.4 (53.5%)
1978
Total Budgeted
Maintenance Costs
Millions of Dollars
963.0 (96.0%)
3,318.0 (98.7%)
6,406.0 (89.4%)
4,052.9 (46.0%)
4,613.4 (86.9%)
2,670.1 (28.1%)
3,939.0 (72.8%)
2,183.1 (67.4%)
4,542.2 (60.8%)
27,621.8 (71.5%)
32,687.6 (71.0%)
Percent Growth
In Maintenance
Costs
+23.6
+ 6.8
+16.1
+31.9
+18.1
+ 8.2
+16.7
+19.9
+26.4
+18.3
Source: Ref (6), pp. 82-82
^Percent of spending in investor-owned sector in parentheses.
-------
West North Central - North Dakota, South Dakota, Kansas,
Nebraska, Minnesota, Iowa, Missouri
Mountain - Montana, Idaho, Wyoming, Nevada, Utah, New
Mexico, Colorado, Arizona
Pacific - Washington, Oregon, California
The breakdown of capital expenditures according to the type of
utility (e.g., investor owned, co-op, municipalities, etc.) is
delineated in Appendix D. As. can be seen in Table 2-6, capital
spending was about 60 billion dollars in 1977 and 1978, with
about 71 percent of the spending in the investor-owned sector.
During this two-year period, capital spending requirements were
growing for almost all types in almost all regions, with a new
national growth rate of 18.3 percent per year, or about three
times the rate of inflation as measured by the GNF deflator.12
Consequently, Table 2-6 illustrates the large capital expendi-
tures are primarily financed through borrowed money. Investor-
owned utilities generally borrow money through the sales of
securities, such as common and preferred stock, bonds, etc.
Figure 2-3 shows these sales, as well as capital expenditures,
for the years 1967 through' 1977. It may be seen that total
securities sales for investor-owned companies are increasing at an
average rate of about 12 percent per year, with stock sales pre-
sently about equal to bond sales. However, stock sales are
increasing at a rate slightly less than total sales, while public
bond sales are increasing at a rate of only about 8 percent per
year. Capital expenditures, on the other hand, are increasing at
about 18 percent per year. Other types of electric utilities
usually finance their capital expenditures through the sale of bonds
Because of the importance of bonds in capital formation,
the interest rate paid is a good measure of industry strength -
the stronger the company, the lower the interest rate. This
strength is measured by the bond rating of the company and/or
its fixed charge-coverage ratio. The bond rating, which influences
-43-
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•TOTAL
CAPITAL
EXPENDITURES
TOTAL
SECURITY
SALES
STOCK SALES
. (Canon i Preferred)
PUBLIC BONOS.
DEBENTURES, ETC.
SALES
PRIVATE 30NOS.
DEBENTURES, ETC.
SALES
1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977
YEAR
02-3407-1
Figure 2-3
INVESTOR-OWNED ELECTRIC UTILITY
SECURITY SALES AND CAPITAL EXPENDITURES
(BILLIONS OF DOLLARS)
(Source: Ref. 6, pp. 79 & 101)
-44-
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the interest rate paid, reflects marketplace conditions and
historical payback records and is reported by Standard & Poor's
(S&P) and Moody's. Prior to the early 1970's, utility bonds were
considered extremely safe investments; most had AA or AAA S&P
ratings, reflecting about the lowest interest rates existing for
utility bonds.13 By the early 1970's, some bond ratings had
dro.pped slightly (namely several issues of Consolidated Edison and.
Public Service Gas and Electric of Newark, New Jersey). However,
the fuel crisis of 1973-1974 caused a drastic change in the utility
bond market, and culminated in 1974 with Con Ed's first skipping
of a quarterly dividend since 1885.1If This financial crisis, il-
lustrated by the Con Ed case, became widespread in the industry.
Utility bond ratings began to fall until, in 1978, Texas Utilities,
Inc., was the sole remaining investor-owned utility with an AAA.
bond rating.13
This reduction in the ability to raise capital is also
evident in the fixed charge-coverage ratio for bonds. The pre-tax
fixed charge-coverage ratio is defined as
FCCR. » pre-tax income
capital charges
The pre-tax FCCR represents the ability to pay back borrowed funds.
Generally an AAA bond rating corresponds to a pre-tax FCCR of 4
(i.e., the company can pay back the interest on its investments 4
times) and an A bond rating corresponds roughly to an FCCR of about
3. If the pre-tax FCCR is below 2.3, the utility reaches a limita-
tion preventing it from selling additional bonds.1* The nationwide
average pre-tax FCCR's for investor-owned utilities for 1969 to
1977 are shown in Figure 2-4. As can be seen, the average FCCR
dipped close to 2.3 in 1974 from a high of 3.64 in 1969. The
FCCR for Con Ed actually dipped below this tolerance level.1"*
While the nationwide FCCR's have been increasing, the financial
status of the industry is still nowhere near that prior to the
1970's in terms of bond ratings.
-45-
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PRE-TAX
FIXED CHARGE-COVERAGE
RATIO (FCCR)
4.0
3.0
2.3
2.0
"NO-SALE
THRESHOLD"
YEAR
1969 1970 1971 1972 1973 1974 1975 1976 1977
02-340r-t
Figure 2-4
FIXED COST-COVERAGE PATIO FOR 'INVESTOR-OWNED
ELECTRIC UTILITIES 1969-1977
(Sources: Ref. 6, Ref. 15, Ref. 16)
-46-
-------
As for common stock, the same trends are evident in the
price-book ratio.1* The price-book ratio is defined*as
(current selling price of common stock)
~~(book value of common stock)
The book value of the stock is derived from common equity and is
defined11* as -->
(total capital investment in plant)-(accumulated-
m ' depreciation)
* (number of shares issued)
A priee-book ratio greater than 1.00 is required to raise new
capital. By 1974, PBR's in the Northeast had declined to 0.55;
Con Ed's FBR was 0.20, the lowest in the nation. The national
average PBR was 0.76. The highest FBR (Southwestern Public
Service) was 1.40. Table 2-7 shows the PBR's for investor-owned
utilities during this period. As can be seen, all the utilities
except those in Texas, Oklahoma, and parts of Arkansas, Louisiana,
Montana, Wyoming, Oregon, and Washington had PBR's less than 1.00.
Those utilities in the Midwest, East, and South, and in southern
California and Nevada had the lowest PBR's. While PBR's, like
bond ratings, have improved somewhat since this time (up to a
nationwide average of 1.01 at the end of 1977)8, the average PBR
was 0.98 for 36 new issues of common stock in the first half of
1978,ls and 15 percent of the issues had PBR's between -Q.827o and
0.89.
Although utility stocks have fared well recently when
compared to the S&P 500 industrials,ls it is evident that the
industry is still not as strong financially, from a capital stand-
point, as it has been in the past, and that it will be faced
with rising capital costs in the future. Furthermore, the
ability to raise capital is closely connected to the inflation
rate. Standard and Poors reports that inflation was the most
important financial factor in the period 1965-1974, causing signi-
ficant increases in interest rates and financing requirements.7
While inflation rates of 4 percent per year are desirable and
-47-
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TABLE 2-7
PRICE-BOOK RATIOS (PBR'S) FOR
INVESTOR-OWNED UTILITIES IN JPNE. 1974
Geographic Region PBR(>1.00 J3 acceptable^
New England
Maine 0.60-0.69
Remainder <0.60
Middle Atlantic
Pennsylvania 0.80-0.9 9
Remainder <0.60
South Atlantic
West Virginia 0.70-0.79
Virginia <0.60
Delaware 0.80-0.9 9
Parts of Florida 0.70-0.99
Remainder 0.60-0.69
East South Central
Parts, of Kentucky 0.80-0.99
Remainder 0.70—0.79
West South Central
Parts of Arkansas 0.70-0.79
Parts of Arkansas and Louisiana 0.80-0.99
Remainder including parts of Arkansas
and Louisiana >1.00
East North Central
Michigan <0.6Q
Missouri, Parts of Iowa and Kansas 0.70-0.79
Parts of Kansas and Iowa 0.60-0.69
Remainder including part of Iowa 0.80-0.99
Mountain
Parts of Wyoming and Montana >1.00
New Mexico and part of Arizona 0.60-0.69
Nevada <0.60
Remainder 0.70-0.79
Pacific
Parts of California and Washington <0*60
Parts of California and Oregon 0.60-0.69
Parts of California 0.70-0.79
Parts of California, Oregon and Washington. 0.80-0.99
Parts of Washington and Oregon >1.00
Source: Ref. 14, p. 41
-43-
-------
TABLE 2-8
DISTRIBUTION OF OPERATING EXPENSES (PERCENT)
1977* 1976 1975 1974 1973
Total Operating Expenses 31,410 26,175 23,293 19,542 13,512
(millions of dollars)
Constituent Percentages:
Fuel 63.7% 62.17. 62.1% 60.8% 49.5%
Maintenance 11.1 11.1 10.8 11.5 14.5
Other 24.2 26.8 27.1 27.7 36.0
^Estimated by Edison Electric Institute
Source: .Ref (8), pp. 100-101.
-49-
-------
rates of 5 to 6 percent per year are tolerable given present
regulatory trends, inflation rates exceeding 10 percent per year
(i.e., "dougle-digit inflation") could jeopardize dividend rates,
further restrict common stock pricing, and would require signifi-
ficantly higher equity returns obtainable only through additional
rate increases. In short, the industry is not out of economic
trouble yet and may face more problems.
2.2.2 Operating and Maintenance Expenditures
Other major utility expenditures are in the operations
area. Table 2-8 shows the distribution of operating expenses
for the years 1973 through 1977. It may be seen that fuel cost
is the largest constituent of these expenses, rising from 49.5
percent in 1973 to 64.7 percent in 1977, with,.an abrupt jump in
1974 at the time of the fuel crisis. Fuel cost constituent
growth is about 2 percent per year as a fraction of total operat-
ing costs. Fuel costs presently account for about 37 percent of
before-taxes expenditures, or about $20.3 billion in 1977, 8 and
these costs are expected to increase in the future.
Maintenance costs, accounting for about 11 percent of
total operating expenses, are detailed for 1977 and 1978 in
Table 2-9. Over these 2 years, about $10 billion has been spent
on maintenance of physical plant. Growth in maintenance charges
escalated about 10.5 percent over the period 1977-1978. The vast
majority of these costs (almost 80 percent nationwide) were borne
by the investor-owned segment.
2.2.3 Income and General Economic Impacts of the Utility
Sector
Table 2-10 shows investor-owned electric utility income
for 1973 through 1977. As can be seen, while total income is
-50-
-------
TABLE 2-9
i
U)
Geographic Region
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
ELECTRIC UTILITY MAINTENANCE COSTS - 1977 AND 1978
1977
Total Maintenance Costs
Millions of Dollars
200.0 (87.9%)
963.2 (99.4%)
920.7 (90.1%)
357.7 (66.7%)
691.5 (89.9%)
365.4 (34.1%)
335.6 (70.6%)
197.9 (66.6%)
535.7 (53.8%)
1978
Total Budgeted
Maintenance Costs
Millions of Dollars
213.6 (90.1%)
1,044.6 (99.4%)
1,020.1 (91.4%)
388.7 (68.0%)
785.7 (88.7%)
429.6 (34.4%)
355.2 (74.4%)
224.9 (68.0%)
583.6 (51.8%)
Percent Growth
in Maintenance
Costs
+ 6.8%
+ 8.5
+10.8
+ 8.7
+13.6
+17.6
+ 5.8
-H3.7
+ 8.9
U.S. Total
4,567.7 (79.0%)
5,046.0 (79.1%)
+10.5
Source: Ref (8), p. 97.
^Percent borne by investor-owned companies in parentheses.
-------
TABLE 2-10
INVESTOR-OWNED UTILITY INCOME (MILLIONS OP DOLLARS)
Total Electric Revenue
Other Income
Extraordinary Income
1977*
55,175
2,800
0
1976
47,080
3,105
0
1975
41,855
2,666
19
1974
34,970
3,515
1973
27,526
1.982
0
Total Income
57,975
50,185
44.540
38.485
29,508
1
Ul
ro
i
Operating Expenses
Depreciation
Taxes
Capital Charges
Extraordinary Expenses
Dividends
Retained Earnings
Dividends - percent of total
income
Retained Earnings - percent
of total income
31,410
4,700
8,520
5,320
0
5,810
2,215
10%
4%
26,175
4.240
7,221
5,566
7
5,118
1.872
10.2%
4%
23,293
3,814
6,212
5,184
0
4,415
1,587
9.9%
3.8%
19,542
30360
4,898
4.615
76
3,818
1,328
9.9%
3.8%
13,512
3,012
4,553
3,642
62
3,424
1,427
11.6%
5.2%
*Estiraated by Edison Electric Institute.
Source: Ref (8), p. 100.
-------
rising, the percent paid out in dividends or retained as earnings
has decreased from about 16 percent to about 14 percent. This
factor indicates that capital is more difficult to raise than in
1973, although the situation is seen to have improved slightly
since 1974. The table also indicates that, while electric revenue
is increasing at a rate of about 15 percent per year, operating
costs are increasing at about IS percent per year. These data
further indicate that the industry is not as well off financially
as in the past and may face more problems in the future.
NERC has estimated that 20 percent of the generation
needed by 1986 is not yet under construction and is subject to
potential unintentional delay.l One of the reasons cited is the
uncertain financial climate, which affects the utility segment
more than general business because of high long-term capital
investment requirements. This uncertain climate consequently has
secondary effects on a number of other industries including equip-
ment suppliers and large consumers due to uncertainty in con-
struction,17 and can thus have significant effects on the national
economy.
2.3 Regulatory Characterization
As previously mentioned, the electric utility industry
is a regulated industry, both economically and otherwise. How-
ever, the total regulatory process eventually effects the
industry's economic state, since all costs must be either passed
through or absorbed.
Future revenue requirements for U.S. electric utilities
have been estimated.*8 These requirements are shown in Figure
2-5 and are reflected in the consumer's rate base. This rate
The rate base is schedule of charges for electric service
(usually in cents per KWH) which are reflected in the consumer's
electric bill.
-53-
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AVERAGE
REVENUE REQUIREMENTS
*/KUH
(1976 DOOMS)
2.0
1.0
0.0
HIGH
IEAR
1970 1975
1990
»985
1990
1995
2000
02-3407-1
Figure 2-5
ESTIMATED ELECTRIC UTILITY
REVENUE REQUIREMENTS - 1972-2000
(Source: Ref. 11)
-54-
-------
base should provide a return on common equity sufficient to
attract investors; the allowed rate is usually about 12 percent.l"
However, return on common equity was reported to have been 10.6
percent in 1974, 11.5 percent in 1976, and 11.8 percent in 1977
on a nationwide basis,8 less than the rate normally allowed.
Furthermore, lately some utilities have been required to pass
through savings obtained through capital spending to increase
efficiency rather than being allowed to earn a return in that
investment.
Capital expenditures inevitably will affect rate bases,
since interest and dividends must be paid to finance capital con-
struction. Operating costs also affect rate bases as witnessed
by the recent rate escalations due to rising fuel costs. Gen-
erally rate regulation agencies or commissions require some form
of justification for new expenditures (either capital or operating)
prior to inclusion in a rate base, and regulators may order utili-
ties to take steps to reduce costs or to pass savings through to
consumers.
The rate-setting procedure generally includes an
evaluation of the company's general financial condition, operating
costs, present capital investment (i.e., value of equipment in
service) and, in some cases, the cost of construction work in
progress (CWIP).19 Proposed project costs are never allowed for
inclusion in a rate base. In general, a certain percentage of
the costs for CWIP may be allowed to be included in a rate base
depending on the financial condition of the company. . However,
some states do not allow any inclusion of CWIP costs in rate bases;
they require that equipment be installed and operating or that
capital plant be built and in service before any returns on equity
are allowed. This latter practice requires that the utility
finance capital expenditures through the money market prior to
-55-
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construction rather than through rate increases, effectively
reducing actual return on equity during the construction period.
Any costs incurred in either this or any other fashion are
usually made up eventually through rate increases.
As was previously mentioned, electric rate?, must allow
a~return on equity sufficient to attract investors;, otherwise,
spiraling rate increases and reduced financial integrity are the
results. In 1977, 88 investor-owned electric utility companies
received rate increases amounting to $2.6 billion, and 12 compan-
ies in 10 states were ordered to cut rates by about $167 million.
This compares to 1976, when 83 companies were granted increases
of $2.4 million. The ratios of amounts received to amounts
requested were 52 percent in 1976 and 53.8 percent in 1977.
After rates are set, if the utility or consumers believe that the
regulatory action was unjust, legal avenues are generally avail-
able for appeal.
In terms of plant design and construction itself, most
regulatory agencies require that permits be granted by appropriate
agencies before a plant may be built. In some cases, this process
can require up to 50 permits from numerous agencies, with many
permits requiring public-hearings, legal findings, and extensive
studies.20 This permitting procedure affects the timing and cost
of plant construction, especially if mistakes in studies, bad
scheduling, or failure to meet agency needs occur. Careful plan-
ning and preliminary work with key agencies can serve to reduce
the potential for difficulties in the licensing procedure, thus
reducing overall plant cost and hastening completion. For a
typical coal-fired power plant, the licensing procedure requires
from 45 to 43 months in states with siting regulations and 39 to
45 months in states with no siting regulations. Site selection
-56-
-------
generally requires an additional 12 months prior to licensing for
both of the above cases. After licensing, construction requires
about 42 months. For units added at existing sites, site selec-
tion updating requires from 6 to 12 months and licensing requires
from 33 to 44% months.20
2.4 Summary
Coal-fired plants in the United States were inventoried
for the year, 1976. There were 399 plants with coal-fired capa-
city of 202,380 Mw, about 5.8 percent higher than widely accepted,
industry-based NERC estimates. This discrepancy is probably due
to differences in data and in definitions. Of these 399 plants,
most are in EPA Regions III, IV, V, and VII, although significant
future growth is anticipated to Region VI and other parts of the
West. Total coal-fired generation in 1986 has been estimated to
be 326,081 Mw, and constitutes 40.9 percent of total capacity.
In terms of economics, the electric utility industry
operates as a regulated monopoly, with designated service areas.
The industry is probably the most capital investment-intensive
in the nation, and it has experienced difficulty in raising funds
during recent years with decreasing bond ratings and price-book
ratios less than 1.0 (stock selling at prices below book value).
Utility regulation affects rates, plant construction, and the
general economic health of the industry. Typical plant licensing
times range from 33 to 49 months for coal-fired power plants, and
rate bases approved between 1974 and 1977 have reflected returns
on common equity ranging from 10.6 to 11.8 percent, below the 12
percent rate usually considered to be reasonable by industry and
most regulators. Because of the long-term capital investment
requirements of the industry, its general economic state is more
sensitive to inflation and uncertainty than is that for general
-57-
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business. The uncertain regulatory climate also places the
industry in a less sound position than unregulated general
industry. Reduced investor confidence has caused higher interest
rates, lower bond ratings, and most common stock sales at prices
below book value. Consequently, the economic state of the -
industry is not as healthy as in the past. While the economic
situation has improved somewhat since 1974, it appears that the
recent financial problems faced by the industry are not over yet.
Furthermore-, current capital costs for coal-fired plants reflected
in these present rate bases range from $450 to $800 per installed
kilowatt capacity, and are rising rapidly, thus causing further
-uncertainty and making capital requirements even more important.
-50-
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3.0 . CHARACTERISTICS OF SOLID WASTES
With the trend towards increased utilization of the
vast coal reserves across the United States, more and more atten-
tion is being focused on the chemical and physical characteriza-
tion of residual by-products of coal combustion. Coal-fired power
plants, produce voluminous quantities of fly ash, bottom ash, and-
scrabber sludge each day. Full characterization of these flue gas
cleaning (FGC) by-products is required if potential hazards asso-
ciated with waste emission into the natural and populated environ-
ments are to be understood.
This section presents the state of the technology regard-
ing raw wastes generated from a coal-fired power plant. The types
and quantities of the principal FGC by-products will be presented
for a number of typical scenarios using a "model" 1000 Mw coal-
fired power plant in order to place the disposal problem in per-
spective. The source of combustion products, the coal, will be
characterized so that the correlations between source and product
can be discussed. A comprehensive description of the chemical,
physical, engineering and leaching properties of FGC wastes—fly
ash, bottom ash, and scrubber sludge—will be presented. Distin-
guishing characteristics of coals and their combustion products
as they relate to their places or origin (i.e., eastern vs. western
U.S. coal fields) will be emphasized.
3.1 Types and Quantities of FGC By-Products
There are a number of small waste streams or materials
associated with any steam-electric generating plant. However, with
coal-fired power stations there are three major by-products of
coal combustion and flue gas cleaning: fly ash, bottom ash, and
scrubber sludge. The relationship of these waste streams with a
typical coal-fired generating station is depicted by Figure 3-1.
Input materials are also identified.
-59-
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FLUE GAS
ClltHICA! S
I
e>
o
i
IKfAItU
UAUR
CHEMICALS
RAW
HATER
SIEAH
. GENERATING
v H BOHER
PVRIIES
CUAI I'lLE
HIINflK HATER
SCRIIUOER
SLUDGE
RAM
WATER
REFRACTORY COOI ING
AND
DOTTOH ASH SLUICING
1 t
MET SltllCE
B0110H HATER
ASM
02-3176-3
Figure 3-1. Waste streams' of a typical steam electric generating station.
-------
The three coal combustion products--fly ash, bottom ash,
and scrubber sludge--pose a major solid waste disposal problem if
for no other reason than the large quantity produced by a single
generating plant. For perspective, the quantities of fly ash,
bottom ash, and scrubber sludge produced by a "model" 1000 Mw
coal-fired generating station have been calculated for a number
of scenarios. Factors affecting waste quantities which have been
considered are coal quality, scrubber type and operation, and both
current.(1978) and future emission standards (as proposed in Fed-
eral Register. September 19, 1978)2l for S02 and particulates. A
summary of the assumptions for the various scenarios follows.
TABLE 3-1. BASIC ASSUMPTIONS IN BY-PRODUCT SCENARIOS
Rated Electrical Capacity
Thermal Efficiency
Stream Factor
Heating Value
Ash Content (as burned)
Sulfur Content
Fraction of Sulfur Emitted as SO 2
Fly Ash: Bottom Ash Ratio
Western
Sub — b i tuninous
1000 Mw
35%
80%
9000 Btu/lb
8%
0.8%
0.95%
80:20
Eastern
Bituminous
1000 MW
35%
80%
11,000 Btu/lb
15%
3%
0.95%
80:20
Eight scenarios have been selected to.illustrate the
effects of pertinent variables on the production quantities of fly
ash, bottom ash, and scrubber sludge as they leave the collection
system. The design basis for these scenarios is summarized in
Table 3-2. The eight scenarios are shown in Figures 3-2 through
3-9. Production rates of the fly ash, bottom ash, and scrubber
sludge are summarized in Table 3-3.
-61-
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TABLE 3-2. DESIGN BASIS OF EIGHT SCENARIOS FOR WASTE QUANTITIES
Coal Characteristics
Scenario
1
2
3
4
5
6
7
8
Type1
E
E
E
E
W
W
W
W
Btu/lb
11
11
11
11
9
9
9
9
,000
,000
,000
,000
,000
,000
,000
,000
Ash*
15
15
15
15
8
8
8
8
Sulfur
(X)
3.0
3.0
3.0
3.0
0.8
0.8
0.8
0.8
Scrubber
Sorbent3
L
L.S
L
L.S
L
L.S
L
L.S
Parameters
Stoichiometry*
1
1
1
1
1
1
1
1
.1
.5
.1
.1
.1
.5
.1
.1
Oxidation
(X)
15
15
15
100
15
15
15
100
Regulations
Fly Ash SO 2
99X removal 1.2 Ib S02/106 Btu
Allowable5
01 II
" 85X removal6
08 81
80 1.2 Ib SOa/106 Btu5
00 II
M 85X removal6
00 II
i
Western subbituminous; E » Eastern bituminous
2Residue after combustion in boiler
3L = Lime; L.S. = Limestone
''Molar ratio of lime or limestone (calcium) to mole of SO2 removal
5Current 1978 New Source Performance Standards
6Proposed New Source Performance Standards (1978)
-------
1.2 Ibs SOa/106 BTU
BASIS SCENARIO 1
Eastern Coal - 11000 BTU/lb, 1SZ Ash, 31 Sulfur
152 Oxidation
1.1 Lime stolchiometry
99% Fly ash collection
1.21b S02/106 DTU allowable
i
o\
u>
Fly
Ash
Removal
Reaction
Tank
8.6 lbs/106 BTU
38 dry metric tons/hr
Coal
Steam \
|Generating
Boiler 1
V
6.8 Iba dry sludge/108 BTU
86 metric tons/hr @ 35% solids
Dewatered
Bottom Ash
2.2 lbs/10* BTU
13 metric tons/hr
752 solids
Figure 3-2.
i i
Byproduct production rates with eastern coal, loy oxidation, high utilization
and current regulations. ;
-------
1.2 Ibs S02/106 BTU
BASIS SCENARIO 2
Eastern Coal - 11000 BTU/lb, 15% Ash, 3% Sulfur
1SZ Oxidation
1.5 Limestone stoichiometry
99% Fly ash collection
1.2 Ibs S02/10* BTU allowable
cr»
*-
i
Fly
Ash
Removal
8.6 lbs/10* BTU
38 dry metric tons/hr
/SteamS.
Generating)
Coal
Boiler
H 1
1
Dewatered
Bottom Ash
2.2 lbs/106 BTU
13 metric tons/hr @ 75% solids
*
8.6 Ibs dry sludge/108 BTU
110 metric tons/hr @ 35%
solids
Figure 3-3. Byproduct production rates with eastern coal, low oxidation,, low utilization,
and current regulations. i ;
-------
.41 Ibs S02/106 BTU
BASIS SCENARIO 3
Eastern Coal - 11000 BTU/lb 15% Ash, 3% Sulfur
15% Oxidation
1.1 Lime stolchlometry
99% Fly ash collection
85% SO2 removal
Ul
i
Ply
Ash
Removal
8.6 lbs/106 BTU
38 dry metric tons/hr
H5 team \
iterating
Roller
ir I
Dewatered
Bottom Ash
2.2 lbs/106 BTU
13 metric tons/hr @ 75% solids
8.1 Ibs dry sludge/106 BTU
103 metric tons/hr @ 35% solids
Figure 3-4. Byproduct production rates with eastern coal, low oxidation, high
utilization, and future regulations. ! . i
07-3IIO-*
-------
BASIS SCENARIO 4
Eastern Coal - 11000 BTU/lb, 15% Ash, 3% Sulfur
100% Oxidation
1.1 Limestone stoichiometry
99% Fly ash collection
85% SO2 removal
Iba SOa/106 BTU
Coal
Fly
Ash
Removal
Reaction
Tank
8.6 lbs/106 BTU
38 dry metric tons/hr
L
( Steam J
Generating!
-HBoilerl
Dewatered
Bottom Ash
2.2 lbs/10* BTU
13 metric tons/hr @ 75% solids
§
lOol Ibs dry sludge/10* BTU
128 metric tons/hr @ 35% solids
Figure 3-5. Byproduct production rates with eastern coal, high oxiiationg high
utilization, and future regulations.
i
-------
1.2 Ibs SOa/106 BTU
BASIS SCENARIO 5
Western Coal - 9000 BTU/lb, Q% Ash,.8% Sulfur
15% Oxidation
1.1 Lime stolchlometry
99% Fly ash collection
1.2 Ibs SOa/10* BTU allowable
Coal
Steam
(Genera ti
Boiler
J
Dewatered
Bottom Ash
1
Fly
Ash
Reaction
Tank
5.6 lbs/10* BTU
25 dry metric tons/hr
H
1.4 lba/106 BTU
8.4 metric tons/hr @ 75% solids
.35 Ibs dry sludge/10* BTU
4.5 metric tons/hr @ 35% solids
Figure 3-6.
Byproduct production rates with western coal, low oxidation, high utilization,
and current regulations. > < ;
-------
Ibs SOa/106 BTU
BASIS SCENARIO 6
Western Coal - 9000 BTU/lb, 8X Ash, .82 Sulfur
15Z Oxidation
1.5 Limestone stolchiometry
99% Fly ash collection
1.2 Ibs SOj/106 BTU allowable
CD
I
/:
25 dry metric tons/hr
Steam
i\
.45 Ibe dry sludge/108 BTU
5.7 metric tons/hr @ 35% solids
Coal
1
Dewatered
Bottom Ash
^ 1.4 lbs/108 BTU
8.4 metric tons/hr @ 75Z solids
Figure 3-7. Byproduct production rates with western coal0| low oxidation,, low utilization,,
and current regulations. t j
-------
BASIS SCENARIO 7
Western Coal - 9000 DTU/lb, 82 Ash, .8% Sulfur
152 Oxidation
1.1 Lime stoichlometry
99% Fly ash collection
85% SO2 Removal
,2 Ibe S02/106 BTU
vo
i
r
Fly
Ash
Removal
^ 5.6 lbs/106 BTU
25 dry metric tons/hr
2.6 Ibs dry sludge/10* BTU
34 metric tons/hr @ 35X solids
Coal
i
Dewatered
Bottom Ash
^ 1.4 lbs/106 BTU
8.4 metric tons/hr @ 75% solids
Figure 3-8. Byproduct production rates with western coal,' low oxidation, high utilization,
and future regulations. | i
U?-1I7» 7
-------
.2 Ibe SOa/106 BTU
BASIS SCENARIO 8
Western Coal - 9000 BTU/lb, 8Z Ash, .82 Sulfur
100% Oxidation
1.1 Limestone stoichiometry
99% Fly ash collection
85% SO2 Removal
o
i
Fly
Ash
Removal
Reaction
Tank
». 5.6 lbs/108
25 dry metric tons/hr
:k«e«se
( Steam N
3.3 Ibs dry
42 metric
aludge/108 BTU
r @ 35% solids
Coal
|6enerating|
J Boiler
1 I
1
Dewatered
Bottom Ash
1.4 lbs/106 BTU
8,4 metric tons/hr @ 75% solids
Figure 3-9. Byproduct production rates with western coal,, high oxidation, high utilization,
and future regulations. i \
-------
TABLE 3-3. BY-PRODUCT PRODUCTION RATES FOR EIGHT SCENARIOS
Coul
St:imurln Type
1 E
2 E
J K
4 K
5 W
u . M
7 U
U U
Oxidation
IA.W
Low
Low
High
Low
Low
Low
High
Utilization
High
Low
High
High
High
l.nw
High
High
Regulations
Current
Current
Future
Future
Current
Current
Future
Future
Fly Aah
Iha/JO* Btu
(dry metric
tonu/hr)
8.6
(38)
8.6
(18)
8.6
(38)
8.6
(18)
5.6
(25)
5.6
(25)
5.6
(25)
5.6
(25)
- Dot ton Ash
Iba/ 10* Btu
(metric tona/hr 8
751 sol Ida)
2.2
(13)
2.2
(13)
2.2
(13)
2.2
(13)
1.4
(8.4)
1.4
(8.4)
1.4
(8.4)
1.4
(8.4)
Scrubber Sludge
dry lba/10' Btu
(Metric tona/hr £
3SZ sol Ida)
6.8
(86)
8.6
(110)
8.1
(103)
10.9
(128)
0.15
(4.5)
0.45
(5.7)
2.6
(34)
1.1
(42)
Stack RulBulona
Iba
Partlculalaa/
10* Btu
.086
.086
.086
.086 .
.056
.056
.056
.056
Iba S02/
10C Btu
1.2
1.2
0.41
0.41
1.2
1.2
0.2
0.2
-------
Dry collection of Che fly ash is assumed either by
electrostatic precipitation or baghouses. A wet bottom boiler
is assumed for the collection of bottom ash. Data presented in
Table 3-3 indicate that over 90% of fly ash is collected dry
~and over 80% of bottom ash is collected wet. S02 is typically
removed in a wet limestone or lime scrubber, precipitated as cal-
cium sulfite or sulfate salts, and then thickened with a. clari-
fier to 35% solids. Simultaneous collection of fly ash in a wet
scrubber has not been depicted but can easily be calculated by
taking the production rate in dry tons and dividing it by .35
(35% solids) and then adding it to the production rate of wet
SOz scrubber sludge.
Current federal New Source Performance Standards22
(NSFS, 1978) require at least 99% reduction in particulate load-
ing and a mfl-g-ttmtm allowable S02 emission of 1.2 Ibs of S02 per
10s Btu. Proposed regulations require an 85% reduction in the
flue gas SOz concentration.21 Future regulations for reducing
particulate emissions have not been considered as they will not
significantly impact waste quantities of ash.
Lime and limestone wet S02 scrubbers have been con-
sidered because they represent the principal technologies being
used by industry to control SO* emission. A purity of 98% has
been selected for the lime and limestone.
For limestone as the sorbing reagent, a stoichiometric
ratio of 1.5 moles of limestone to 1.0 mole of S02 sorbed has
been chosen as representative of current technology with 1.0
stoichiometry for future reference when improvements in scrubbing
technology allow a reduction in the excess of sorbent. A stoichio-
metric ratio of 1:1 has been assumed for. lime as currently feas-
ible in 1978. The effect of 15% oxidation has been estimated for
both current and future performance standards (proposed in September
-72-
-------
19, 1978 Federal Register).21 Forced oxidation has been proposed
as a trend in future scrubber operation..
The following conclusions have been drawn from an exam-
ination of the eight scenarios (Figures-3-2 through 3-9) which
depicted the effects of coal type, scrubber type .and operation,
and NSFS regulations.
• The firing of eastern coal in a 1000 Mw
generating station results in significantly
larger quantities of both ash and scrubber
sludge.
• Under current regulations (1978) for maximum
permissible emissions, eastern coal results
in 2000% more scrubber sludge and 50% more
ash than western coal.
• Future regulation (proposed in September 19,
1978 Federal Register) will not significantly
affect ash production rates from either eastern
or western coal or with the scrubber sludge
generated by the firing of eastern coal.
• Assuming a required 85% removel in future S02
emission regulations (proposed in September
19, 1978 Federal Register), seven times as
much scrubber sludge will be produced by a
1000 Mw western coal-fired power plant than
under current regulations of 1.2 Ib S02/10S
Btu. An 85% S02 removal regulation will not
significantly increase the scrubber sludge
rates produced from a unit firing eastern
coal.
• Forced oxidation will increase the mass of
scrubber sludge by 20-30%. This increase
can be offset to some degree by improved
dewatering and settling properties.
• Stoichiometries of 1.5 for either lime or
limestone will result in approximately 20-30%
higher scrubber sludge masses than with 1.1
stoichiometries.
-73-
-------
3.2 Characterization of Coal _ .
Coal is classified into "grades" on the basis of its
fixed carbon, percent volatility and heat content, and its agglom=
-erating characteristics (ASTM Part 26, 1977).23 the caloric con°
tentr I.e., its value as a fuel (Btu/lb), is a good general indi-
cation of its classification. Coal grades range in descending.
value of Btu content from bituminous to subbituminous to lignite,
with certain categorial variations within. . - _ • .
Coal grade variability is highly correlative with the
geographic location and geologic structure of a coal basin. These
factors, together with the nature of the coalification process and
timely environmental conditions, are what contribute to the chem°
ical and physical properties of any given coal type. Such pro-
perties include:
• heat content (Btu value),
• moisture content,
• ash content,
• sulfur content,
• distribution of major and minor constituents, and
• trace element concentrations.
During the combustion of a coal, the combustion waste
products are fractionated into three separate parts:
• fly ash - the ash fraction entrained with the
flue gas,
• bottom ash - collected wet or dry at furnace
bottom, and
• volatiles - either scrubbed or emitted to the
atmosphere.
-74-
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The chemical and physical properties of these different
combination products and their proportionate ratios vary with re-
spect to the coal type being fired. For example, eastern coals
are characteristically higher in sulfur content as compared to
western coals. This feature of a higher percent sulfur is parti-
cularly noteworthy because of the higher sulfur.dioxide content
in the flue gas emissions following combustion of an'eastern
coal. The characteristic differences in the waste products re-
sulting from burning eastern vs. western coal will be discussed
in the following sections.
t
The inorganic constituents of the coal are comprised
of minerals derived from the surrounding lithology and incorporated
into the coal seam. These inorganic constituents can be divided
into three classes based on concentration expressed in the oxide
form:
• Major - >5%,
• Minor - .1% * 5%, and
• Trace - <.!%.
The major elements found in the inorganic phase of all
coals include silicon, aluminum, and iron. Calcium and, in some
cases, sodium and magnesium occur in western coals as major inor-
ganic constituents. Compounds of these major elements typically
account for 90% of the total ash content. The concentration and
distribution of these major species will have a major effect on
the reactivity of the fly ash and, to some extent, on the distri-
bution of coal sulfur between the flue gas and ash.
Minor inorganic constituents found in all coals include
potassium, titanium, phosphorous, magnesium, sodium, and, in some
cases, barium, strontium, manganese, and boron. Trace element
concentrations, <.!% content, are highly variable among the dif-
ferent coal types.
-75-
-------
3.3 Chemical Properties of FGC By-Products
Three types of chemical properties will be discussed.-
Major elements form the chemical compounds which are responsible .
for the chemical, physical, structural, and leaching properties of
the flue gas cleaning (FGC) products--fly ash, bottom ash and
-scrubber sludge. Trace element concentrations are of environmen-
tal concern with respect to leaching and possible ground water
or surface water contamination. Alkalinity and calcium content
are of particular importance in the differentiation of western
and eastern coal fly ash and its effect on the stabilization of
scrubber sludge.
3.3.1 Chemical Characterization of Ash
The elements forming the major and minor chemical con-
stituents of fly ash are summarized in Table 3-4 according to
coal rank. Analyses of ashes have shown that the. fly ash and
bottom ash fractions contain a similar distribution of most of
the major elements. The iron content has been reported to be
noticeably higher in bottom ashes than in its respective fly ash.
The sulfate (S03) levels were reported to be lower in bottom ash;
calcium concentrations were very similar although the leachable
calcium levels were higher with fly ash. This is in part due to
the fused condition of the bottom ash particles.
The crystalline materials most often identified in fly
ash by X-ray diffraction include silica (a-quartz), s-calcium
sulfate (anhydrite), iron oxides (hematite, a-Fe203, and magne-
tite) , and aluminum silicate (mullite). Sometimes calcium
oxide (lime) and/or magnesium oxide (periclase) are present.
There can be major differences between the fly ash and
the bottom ash in the quantities of certain trace elements they
-76-
-------
TABLE 3-4. CHEMICAL COMPOSITION OF FLY ASHES ACCORDING
TO COAL RANK ~ MAJOR AND MINOR SPECIES
(WEIGHT PERCENT)
Eastern lltusilnous Western
Cliesilcal Spec lea
Sudlua (Ixlde. Na,0
Putaaulm Oxide, KjO
HagncaliM Oxide. MgO
Calclun Oxide, CaO
Silicon Dioxide, SlOj
AliwlnuB Oxldu, AljOi
Iron Oxide. FejO,
Tltanlua Dioxide, TIO,
I'liiiBiilnirouii Pentoxlde, PtOf
Sulfur Trluxlde, SOi
Range
0.05-2.04
0.92-4.00
0.50-5.50
0.26-13.15
36.00-57.00
16.25-30.30
3.88-15.40
1.00-2.50
<0. 02-0.42
0.09-1.10
Hud Ian
0.51
2.53
1.24
2.88
48.76
21.26
16.44
1.45
2.71
0.78
Total Ho. of
Observations
21
20
23
21
22
22
23
19
16
17
Ranpe
0.15-2.14
0.50-1.80
1.10-5.90
1.80-30.40
31.00-64.80
18.70-37.00
3.07-21.50
0.68-1.6b
0.19-0.70
0.10-5.23
Suh-bltualnous
Median
1.04
0.99
2.96
13.81
49.69
21.04
6.48
1.09
0.38
1.66
Total Ho. of
Observations
8
8
12
12
9
12
12
11
6
12
Western Lignite
Rank*
0.60-8.10
0.20-1.02
3.3-12.75
11.7-31.44
2.20-46.1
10.7-25.3
2. 9-14. IS
0.52-1.60
< 0.02 -0.76
0.12-7.20
Median
1.4S
0.50
6.79
22.29
30.69
15.48
8.87
0.74
0.25
3.14
Total Ho. of
Observations
a
8
10
10
a
10
10
a
5
8
Sources: 24, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36.
-------
contain. For example, selenium concentration is generally an
order of magnitude higher in fly ash than in bottom ash. Arsenic,
boron, and fluorine are more concentrated in the fly ash .than the
bottom ash by a factor of two or more due to the volatility of
these elements.
In receme years, several independent studies*V*5
have been made investigating the trace element .composition of
coal and its combustion products. Although the studies included .
sampling of systems varying drastically in size_-and design, the
systems analyzed are generally consistent regarding trace ele-
ments, some of which are hazardous at high concentrations.
Certain of these trace elements are preferentially concentrated
in or on the fine fly ash particulates.2 *
arsenic selenium sulfur
cadmium copper zinc
lead molybdenum antimony
beryllium gallium
Other elements which tend to be emitted to the
atmosphere as vapors are:
mercury bromine
chlorine sulfur
All other elements tend to be concentrated in approximately equal
proportions in the fly ash and bottom ash residues.
The loss of weight on ignition is often taken to be a
measure of unburned carbon in the fly ash. A higher loss occurs
in the fine fraction. The typical range for loss of ignition of
a fly ash is from <.05 to 7 percent.
-73-
-------
Moisture content of fly ash is low and is usually less
than one percent for fly ash collected dry.
3.3.2 Eastern vs Western Coal Fly Ashes
The grade of coal which is the major fuel source in
the eastern half of the United States is bituminous coal of med-
ium to high volatility. Western coal is mostly subbituminous and
lignite. On this basis, generalizations can be made to distin-
guish between eastern and western coal fly ashes. Examples of
the differences between eastern and western coal ashes are shown
in Table 3-4.
Two of the most important differences between eastern
and western coal fly ashes are the calcium concentration and
available alkalinity. Western coal fly ashes in general have •
higher calcium concentrations and available alkalinity. These
parameters have been correlated with the capability of western
coal ashes to stabilize scrubber sludge without the addition of
other fixation additives.26
3.3.3 Chemical Characterization of Scrubber Solids
The principal components of limestone or lime scrubber
solids are the calcium sulfite coprecipitate, gypsum and calcium
carbonate. The concentration of the species will be dependent
upon the S02 and oxygen concentration in the flue gas prior to
scrubbing, the type of scrubber system and the operation of the
scrubber.
With low oxidizing conditions, calcium sulfite hemi-
hydrate is the principal solid phase product. Small quantities
of calcium sulfate will be coprecipitated with the sulfite. The
calcium sulfite-sulfate coprecipitate has the formula, 37
-79-
-------
Ca j(l-x) S03 + (x) S0,»j • % H 0
where:
0 < x < ,.16
Gypsum, i.e., calcium sulfate dihydrate will be formed when the. . .
natural oxidation rate is high or when forced oxidation is. util- .
i zed.'.Calcium carbonate from either unreacted limestone, or from
carbonation of the lime (CaO) will be found in varying degrees.
Small concentrations of other species are also found in the solid
phase.
Trace element concentrations in the sludge will be de°
pendent to a large extent on (1) the quality of the sorbent and
the make-up water, and (2) the trace element content of the coal.
Reported values are summarized in Table 3-5 as a function of coal
type.
3.4 Physical Properties of FGC By-Products
The physical properties of importance with respect to
disposal are:
• particle morphology
• particle size distribution
• specific gravity
• solids content
These parameters will have direct bearing on compaction, settling
rate, and dewaterability and an indirect bearing on the permeabil-
ity.
-30-
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TABLE 3-5. TRACE ELEMENT COMPOSITION OF PGD SLUDGE SOLIDS
(CONCENTRATION IN ppm)
Identification: Plant A Plant B Plant C
Coal lypu: Uualern Low-Sulfur Wcatern lav-Sulfur Eastern High-Sulfur
Surbent: Line Limestone LlMatone
Am Inony
Arsenic:
ILirliw
Beryl Him
Boron
Cailnlun
CliroMlii*
Cupper
Fluorine
Mcrrury
Hnlyl'demm
NUkel
Sulenlun
Vanaiilim
21 lie '•
C..h.ilr
COtMKHTS;
4.1
4.0
500
1.5
68.7
0.40
1.6
18.9
1017
1.6
56.
<0.010
81.
11.
4.11
<50
11.9
Electrostatic pre-
clpltator for fly
aeb control upatreaa
uf uc rubber
21.7
17.7
111.9
219.8
287.8
595.7
140.5
202.4
311.7
46.7
7.5
12.
4400
1.0
211.
1.1
4.0
104.
950.
2.4
2.4
147.
0.46
8.0
26.0
1.8
<100
169
Electrostatic pte-
clpl^ator for fly
ash control upstreaa
of scrubber
Plant 0 Plant B Plant P
Eastern High-Sulfur Eastern Hl|h-8ulfur Saatern High-Sulfur
Llneatone l.lBeatone l.l»e
6.7
6.7
<20
1.8
41.8
25
5.2
65
266
5.9
190
140
0.101
9.6
75.2
2.1
<100
2050
Scrubber used for
both part Icul ate and
i SOa control
1.9
12.9
90.6
169.7
' 155.1
251.0
147.1
215.1
110.8
4.4
10.4
2.8
98.2
87.1
54.1
159.2
21.6
117.4
166.1
15.8
Sources: 38, 39.
-------
3.4.1 Physical Properties of Fly Ash
The particle size distribution of a fly ash will depend
upon chemical composition, boiler type, and firing conditions.
The size distribution of the collected fly ash will, also be af-
fected by the method of collection. Ashes collected by electro-
static precipitation and baghouses tend to have a higher percentage.
of fine particles than those collected mechanically.
Fly ash particles are very fine, varying in size from
2: 0.5 to 100 microns and averaging from 8 to 30 microns. The
morphological characteristics of the fly ash are diverse and are
particle size-dependent. One recent study has identified eleven
morphological particle types in the fly ash produced by a low
sulfur, high ash, high moisture western coal.1*0 The finest frac-
tion is composed primarily of 'unopaque solid spheres. The coarsest
fraction is composed of cenospheres (lightweight hollow spheres)
20 to 100 microns in diameter. These cenospheres are caused by
evolution of nitrogen and carbon dioxide inside fused silicate
particles in the boiler. Because of their low density, these
"floaters" become a suspended solids problem in disposal ponds.
Specific gravities of representative U.S. fly ashes
ranged from 1.97 to 2.85.2S One of the primary factors correlated
with specific gravity is the iron oxide content.1*1'1*2 Minnich
also indicated that particle size distribution was important in
addition to the iron oxide content. **l The specific gravity, i.e.,
density, of the particle will have a bearing on the bulk density
of the compacted or settled by-product and consequently will affect
disposal volumes.
-32-
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3.4.2 Physical Properties of Bottom Ash
Bottom ash is collected in either ash or slag form
depending on the design of the boiler. The ash produced in a
dry bottom boiler is comprised of coarse, angular particles with
porous surfaces. Wet bottom boilers produce heavy, angular
particles which are termed slag. These typically black particles
have a glass-like appearance.
Bottom ash in comparison to fly ash is much coarser,
ranging from 50 microns to one inch in diameter. This is
equivalent to the range bounded by fine gravel to fine sand.
The specific gravity of 6 eastern bottom ashes has been
reported to range from 2.28 to 2.78 with the iron oxide content
an important factor.1*1 The range for bottom ashes in the U.S.
can be expected to be broader, "2 to 3.
3.4.3 Physical Properties of FGD Sludge
Particle morphology, particle size distribution, speci-
fic gravity, and solids content are particularly affected by the
scrubber system design and operation and the chemical composition
of the solids.
The coprecipitate of calcium sulfite hemihydrate formed
under normal nonnucleating conditions will appear as platelets
.5 to 2 microns in thickness and from 2 to 40 microns in length
and width. The ratio of length to width will be approximately
2:1. Under nucleating conditions, e.g., rapid dissolution of
lime, the calcium sulfite crystals may randomly nucleate on the
surfaces of existing sulfite crystals, leading to a dendritic
-83-
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3.5 Structural Properties
Compaction and settling properties give an indication
of- the disposal volume involved in disposal in landfills and
ponds, respectively. Triaxial shear tests and unconfined corn-
pressive strength tests are indicative of the load bearing capa-
city- of the disposal site. The load bearing capacity,- in turn,.
indicates the structural stability of the solid waste material
during and after disposal. Permeability coefficients are closely
related to these structural properties and can directly affect
the quantity of leachate from the disposal site.
3.5.1 Compaction Properties _ _
Compaction tests are performed to determine the opti-
mum water content for placing the material at maximum density.
Placing of the landfilled material at the optimum moisture and
maximum density will insure minimum settlement and permeability
and maximum shear strength. It also reduces the land require-
ments for disposal. Optimum moisture contents and maximum unit
dry densities, i.e., the compaction properties, of fly ash, bot-
tom ash, scrubber sludges-, and mixtures of fly ash and scrubber
sludge have been reported by a number of investigators . 2S '2 7 '"*l'"5'"~ '1*s
Compaction properties of fly ashes, bottom ashes, and scrubber
sludges as determined by these investigators are summarized in
Table 3-6. The addition of fly ash to the scrubber sludges at
1:1 ash to sludge ratio or higher reduced .the optimum moisture
content of the sludge by 5 to 20 percentage points and increased
the compacted density of 80 to 320 kg/m3 (5-20 lb/ft3). Using
these results, representative moistures and densities have been
selected in calculating disposal volumes of the various disposal
options discussed in Section 4. The moistures and densities for
these options are presented in Table 3-7.
-04-
-------
TABLE 3-7. ASSUMPTIONS OF DRY AND WET BULK DENSITIES OF FGC WASTE PRODUCTS
I
CO
Dry Bulk Density
Product
Fly Ash
Bottom Ash
Scrubber Sludge
Fly Ash + Scrubber Sludge
Specific
Gravity
2.
2.
2.
2.
55
55
55
55
@
Optimum 70% 65% 50%
Solids
(Ibs dry solids/ft3)
95
90
80
95
76
76
76
76
(kilograms of
Fly Ash
Bottom Ash
Scrubber Sludge
Fly Ash + Scrubber Sludge
2.
2.
2.
2.
55
55
55
55
1520
1440
1280
1520
1220
1220
1220
1220
67
67
67
67
45
45
45
45
dry solids/m3)
1070
1070
1070
1070
720
720
720
720
Wet Bulk
Density
Optimum 70% 65% 50%
Solids
(Ibs total/ft3)
112
110
104
112
108
108
108
108
(kilograms of
1790
1760
1670
1790
1730
1730
1730
1730
103
103
103
103
89
89
89
89
wet solids/m3)
1650
1650
1650
1650
1430
1430
1430
1430
-------
TABLE 3-6. RANGE OF MOISTURE-DENSITY RELATIONS
OF FGC WASTE PRODUCTS
Product
Fly Ash
Bottom Ash
Sulfite Rich
Sulfate Rich
Sludge
Sludge
*0ptimum Moisture Content - grains
Optimum Moisture
Content*
16-312
14-25%
31-52%
14-32%
of water per gram of
Compacted Dry
Density of Dry Solid
kg/ar" Ib3/ft3
1140-1650 71-103
1170-1870 73-117
1040-1350 65-84
.1310-1550 82-97
dry solid
3.5.2 Unconfined Compressive Strength
The load bearing capacity of the disposal material can
be determined by unconfined compressive strength measurements of
cohesive products and triaxial shear tests of cohesiveless mater-
ials. The load bearing capacity in pounds per square inch (psi)
is a measure of the structural stability of the disposal material.
The use of the disposal site after reclamation will depend in part
on the structural stability. That is, can it be used as an indus-
trial building site or must it be a park or undeveloped site. The
load bearing capacity also is a rough indication whether the mater-
ial can be worked as a landfill with typical earth-moving equipment
or must it be contained in a pond. For rough comparative purposes,
a person walking on the disposal material exerts approximately .35
kg/cm2 (5 psi), a car, approximately 2.1 kg/cm2 (30 psi), and a truck
or other heavy equipment, approximately 4.2 kg/cm2 (60 psi). A
material having low or negligible unconfined compressive strength
is a cohesiveless material.
-36-
-------
In general, scrubber sludges behave as cohesiveless ma-
terials, having unconfined compressive strengths less than 1.4 kg/
cm2 (20 psi)."5 Some ashes and ash/sludge mixtures, particularly
those eastern coal ashes containing little calcium or available
alkalinity, display very little cohesive properties with unconfined
compression strengths reported at less than 4.2 kg/cm2 (60 psi).26
Unconfined compressive strength tests are applicable to
those products displaying cohesive properties. Typically, such
hydrated products are western coal fly ashes, eastern coal fly
ashes to which lime has been added, mixtures of scrubber sludges
with these ashes, and scrubber sludge stabilized with other com-
mercially available techniques.
Unconfined compressive strengths of ash/sludge mixtures
vary considerably but have been reported in the literature from
less than 7 kg/cm2 (100 psi) to as high as 350 kg/cm2 (5000 psi).26
The latter strength is equivalent to typical ready-mix Portland
cement concrete. The calcium content and available alkalinity
of the ash, type of sludge, the ash to sludge ratio, the amount
of lime addition, the water content, and curing time were all
factors instrumental to this wide range of unconfined compressive
strengths.2-6'27
3.5.3 Permeability
The permeability coefficient of the waste product will
depend upon
• particle morphology,
• particle size distribution,
-87-
-------
• porosity or void ratio of in-situ material, and
... « unconfined compressive strength, i.e., the redue°
- -- - tion of pore volume which accompanies the forma-
tion of the hydration products.
: _:— The particle size distribution of bottom ash is similar.
to that- of sand and fine gravel. Settled or compacted bottom ash
has a high porosity (high void ratio) and displays no. cohesive.
properties. It has the high permeability that one. would expect..
Permeability coefficients of 10"l to 10"3 cm/sec-are -typically.
reported.1*1 Permeabilities of compacted fly ash are significantly .
lower, ranging from 10"* cm/sec to 10"lo cm/sec.26 The higher
value (10°°* cm/sec) is more typical of uncompacted eastern coal
fly ashes and the lower permeabilities are representative of com-
pacted hydrated alkaline western coal ashes.
Permeabilities of 10"3 to 10"" cm/sec are reported as
a typical range for settled and drained FGD sludges. By applying
compaction and more extensive dewatering techniques, permeabili-
ties of 10"" to 10"s and in some cases less than 10~s cm/sec can
be achieved. Fly ash addition decreases the permeability of a
sludge even further by filling in interstitial spaces of the FGD
sludge with fine fly ash particles. This limits the flow of
liquids through the media and decreases the permeability to as
low as 10"s cm/sec.
Western coal ash addition to sludge or the addition of
lime and eastern coal ash to the sludge can lower the porosity
and permeability in yet another way. Hydration reactions consume
the pore water replacing it with the solid phase hydration pro-
ductions responsible for increased unconfined compressive strength.
Permeability coefficients as low as 10~10 cm/sec have been observed.
Reduction of one to two orders of magnitude are more typical.
-G8-
-------
3.6 Leaching Characteristics
The leaching behavior of coal ash and sludge is consi-
dered for several reasons. First, collected fly ash constitutes
a major utility flue gas cleaning waste. Secondly, with the im-
plementation of the Clean Air Act Amendments of 1977, increased
quantities of S02 scrubber sludge will be produced.. Thirdly,
when combined ash and sludge disposal operations are practiced,
certain leachate parameters are generally dominated by the ash
constituents, while others are more strongly influenced by sludge
components. The concentrations of many trace elements in ash-
sludge liquor are derived primarily from the ash, while others
are derived from the scrubber sludge. In addition, concentra-
tions of major species and total dissolved solids will be governed
by the scrubber solids and adherent scrubber liquor.
The disposal of these FGD wastes may result in a poten-
tial source of ground water and surface water contamination if
improperly managed. The concentration of the major species in
the leachate as well as the trace element content may pose a prob-
lem. In lieu of being able to predict the concentration of chem-
ical species in the leachate based on the chemical properties of
ash and sludge, available field data will be evaluated and tabu-
lated for FGC by-products from eastern and western coals. Addi-
tional research is necessary for predicting leaching quality from
a knowledge of chemical characteristics of the coal, ash and/or
sludge, and from laboratory leaching data.
-89-
-------
One of the major problems associated with the evalua-
tion of leaching data is the accuracy of the analytical results
particularly with respect to the trace elements determination.
Chemical characterizations of the same sample by different labora=
tories produce significantly different results with respect to
key -trace elements. Errors in the results within a given labora-
tory can be from several sources, some of which are contamination
of sample or standards, analytical interference from the other ;
species present in the sample, sorption of the trace elements
into or onto the walls of the sample storage container, desorp-
tion of trace elements from the wall. These errors or uncertain-
ties in the analytical results can and do in many cases preclude
the meaningful assessment of the laboratory or field leaching
studies.
The following subsection summarizes readily available
data concerning leaching data from coal ashes and FGD sludges.
In many cases analytical methods and error analyses were not docu-
mented adequately.
3.6.1 Coal Ash Leachates
The concentration range and median values of major spe-
cies measured in studies of field ash leachates have been summar-
ized in Table 3-8. The sources of information for all leachate
tables are summarized at the bottom of the table. The data re-
ported in Table 3-8 have been organized, where possible, into
eastern coal ash leachates and western coal ash leachates. In-
terim drinking water standards and recommended water quality para-
meters for irrigation water are summarized in Table 3-9.
The concentrations of major species including calcium,
magnesium, sodium, potassium, and sulfate are higher in western
ash leachates than eastern ash leachates. The only exception
-90-
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TABLE 3-8. CONCENTRATION OF MAJOR CHEMICAL SPECIES IN
COAL ASH LIQUORS* (CONCENTRATION IN mg/A)
Species
Calcium (Ca*2)
Magnesium (Kg**)
Sodium (Na**)
Potassium (K+l)
Iron (Fe*2)
Aluminum (Al+)
Chloride (Cl"1)
Sulfate
-------
TABLE 3-9. FEDERAL WATER QUALITY PARAMETERS
NATIONAL INTERIM PRIMARY DRINKING WATER STANDARDSSl
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Nierate (as N)
Selenium
Silver
Fluoride (avg)
PROPOSES NATIONAL SECONDARY
Chloride
Copper
Iron
Manganese
PH
Sulfaca
TDS
Zinc
LIMITS FOR IRRIGATION USE (
A"j irm^ntrm
Arsenic
Beryllium
Boron
Cadmium
Chromium
Cobalt
Copper
Fluoride
Iron
Lead
Lithium
Manganese
Molybdenum
Nickel
Selenium
Vanadium
Zinc
TDS
pH"
0.03 ag/Z
1.0 mg/Z
OoOl mg/Z
OoOS mg/Z . .
0.05 mg/Z
. 0.002 mg/Z .--.-
16oO mg/Z
OcOl mg/t
O.OS mg/i
2,4 ag/fc2
DR12IKING WATER REGULATIONS52
230 mg/4
1 sg/£
0.3 sg/£
0.05 mg/Jl
6,5 - 8.5
250 og/£
500 ag/H
5 mg/Z
)F CONTTNUOUSLY-CSED WATER33
5.0 mg/2.
1.0 ag/Z
0.10 og/Z
0.75 mg/Z
0.01 og/Z
0.10 ag/Z
0.05 ag/Z
0.2 mg/Z
1.0 mg/Z
5.0 ag/Z
5.0 ag/Z
2.5 ag/Z
0.2 mg/Z
0.01 ag/Z
0.2 ag/Z
0.02 ag/Z
0.10 ag/Z
2.0 ag/Z
5000 ag/Z
4.5 - 9.0
-92-
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'was an eastern ash leachate with an extremely low pH, 2.9-3.7.
In view of the inertness and low surface area of the bottom ash
relative to that of the fly ash, the lower end of each range is
more characteristic of the leachability of the bottom ash while
the median to higher end is more characteristic of fly ash leachate.
: The data base on trace elements in coal ash leachates
is continuing to grow but, like trace element analysis or ash it-
self ,..the data remain sketchy in several respects. The concen-
tration ranges and median'of selected trace elements are summar-
ized in Table 3-10 for western and eastern coal ash leachates.
The average concentration of inorganic chemical species
as measured in leaching samples collected from ash ponds and/or
landfills exceeded drinking water or irrigation water parameters
by a factor of ten. The concentration must be less than 10 times
the primary drinking water standards for the waste material to be
indicated as non-hazardous under RCRA. The following elements
had average concentrations which were near to the drinking and/or
irrigation water quality criteria presented in Table 3-9.
Arsenic Fluorine Molybdenum
Boron Manganese Selenium
Chromium Mercury
These species will bear monitoring. Zinc, cadmium, manganese,
and lead were near to the RCRA (10X) criteria in two eastern ash
disposal sites. These high concentrations were probably the re-
sult of the low pH (<3) of the leachate.
3.6.2 Leaching of FGD Scrubber Sludge
The quality and quantity of the leachate from the FGD
disposal material is expected to be the worst during the initial
-93-
-------
TABLE 3=10. CONCENTRATION OF TRACE ELEMENT SPECIES
IN COAL ASH LIQUORS* (CONCENTRATION IN
mg/i)
Baa Cent Coal Aah Leaehata
Speelea
Antiaony
Arsenic
Barime
BeryUiM
Bocon
CadBlu»
ChroBiu*
Cobalt
Copoer
Cyanide
Fluorina
Iron
GarMoatm
Laad
Manganese
Mercury
Molybdemai
Nickel
Salaoliw
Silvar
UraniuB
Vanadiua)
Zinc
Kin.
0.003
-------
stage, of disposal and will be primarily a function of the quality
of the scrubber liquor. The water present in the disposal site
will be_ the adherent scrubber liquor which will be high in total
dissolved solids. The total dissolved solids will increase the
solubility of the solids due to increased ionic strength and ionic
complexation. As the wastes age and leach, the chemical quality
of the leachates will improve and will be governed by the dissolr.
ution of the solid phases as opposed to the quality of the adher-
ent scrubber liquor.
. . The quality of the scrubber liquor will be significantly
affected by the scrubber system design and operating parameters,
the characteristics of system input materials, and the nature of
operation of the particulate control device.
The composition of the scrubber liquor will be signi-
ficantly affected by the liquor residence time which is affected
by the evaporation loss in the scrubber and the solids content of
the sludge leaving the scrubber system. The major source of
chloride in the scrubber liquor is the coal. Magnesium sources
include the lime or limestone sorbent and in some cases, magnesium
addition to control scaling. The quality of the make-up water
will also be important in view of the large cycles of concentra-
tion, as high as 50 in some cases. Trace elements in the scrubber
liquor are contributed by the coal, additives, and make-up water.
Concentrations of major and trace element species in
FGD scrubber liquor and elutriates for lime and limestone systems
are summarized in Table 3-11 for both eastern and western coals.
The concentrations of chloride, sulfate, and total dissolved solids
are consistently higher than the irrigation standards. Scrubber
liquor cannot be used as irrigation water without some kind of
treatment.
-95-
-------
TABLE 3-11. LEVELS OF CHEMICAL SPECIES IN FGE SLUDGE
LIQUORS AND ELUTRIATES*
Eastern Coals Western Coals
Aluminum
Aaciaoay
Ayiaaie
aszrUiua
Boron
Cfdmtwm
Calcium
Cazoaiua
Cobalt
Copper
Iroo
Magnesium
Lead
Mercury
Molybdenum
Mickal
Jotassioa
Seleaium
Sodium
Zinc
Chloride
Fluoride
Sulfice
Sulfaea
IDS
PI
a*age in
Liquor (pom)
0.26-0.6
0.46-1.6
< 0.004-2. 2
< 0.0003-0. 03
2-41
0.003-0.3
470-2,600
0.001-2.8
<0. 002-0.1
0.002-1.3
0.02-0.1
420-2730
0.002-0.33
<0. 01-9.0
0.0006-0.07
3.3
0.03-0.91
22-41
<0. 003-2. 7
22-20, 000b
0.01-27
420-3.000
1.4-70
4.3-110
720-30, 000b
2,300-70,000
7.1-12.3
Median
(pea)
_ A
=4
0.13
0.013
»«.
-------
The major species present in the leachate after the
leaching of the adherent scrubber liquor result from the dissolu-
tion of the gypsum, limestone, and calcium sulfite hemihydrate in
the scrubber solids. For this reason, the concentration of the
major-species in the leachate will be limited by the solubility
of these crystalline species. Experimental studies of scrubber
sludge containing some gypsum have shown that the* calcium con-
centration will be from 600 to 700 mg/liter and the sulfate concen-
tration will be 1500 to 1600'mg/liter. Total dissolved solids
will typically range from 2200 to 2600 mg/liter at steady state.26
These steady-state concentrations will be unavoidable since they
are dictated by the solubility of gypsum. Concentrations of cal-
cium and sulfate can be lower than these values when working with
a calcium sulfite sludge containing little or no gypsum. Here,
concentrations will be limited by both the solubility of the cal-
cium sulfite hemihydrate and oxidation.
Trace element concentrations are highly variable as
evidenced by the wide range for most species. Here again, no
chemical species exceeded RCRA criteria for toxicity. The con-
centration of arsenic, boron, cadmium, chromium, fluoride, man-
ganese, mercury, and selenium do warrant monitoring in that the
average concentration exceeded the drinking water or irrigation
water quality parameters.
-97-
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4.0 WASTE DISPOSAL PRACTICES
-' - - The various disposal methods currently employed by coal?
fired utility plants are addressed in this section. The disposal
methods commonly used are discussed followed by presentation of
survey data establishing the number of existing and planned facili°
ties either using or planning to use each type of disposal practice.
The costs' associated with the disposal methods are established and
used to provide a rough cost estimate for implementation of RCRA.
Alternative disposal practices, methods not in common used today,
are also evaluated from technical, environmental and economic
standpoints.
4.1 Disposal Methods and Practices
The common disposal practices currently in use in the
coal-fired electric utility industry are described in the follow-
ing pages. Survey data describing the number of plants using each
type of method is also presented. The data describing the percent-
age of plants using each type of disposal method were used in
Section 4.2 to define the costs of current and future disposal.
4.1.1 Disposal Methods
The various alternatives commonly used for fly ash and
scrubber sludge collection and disposal are diagrammed in Figures
4-1, 4-2, and 4-3. These diagrams focus on fly ash and scrubber
sludge to the exclusion of bottom ash because of the greater quanti-
ties of these materials generated. The alternatives for bottom ash
disposal are more limited and less complicated in terms of disposal
alternatives. Ultimate disposal of any of these wastes is in a
pond or landfill, either lined or unlined.
-98-
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VO
VO
I
1
Aah Sluiced
to 1'ond
I
Hauled Co
Landfill by
Company
Ply Ash ''
J
1
Dry Collection
(ES1» or
Mechanical )
\
i
Met Collection
(Scrubber
System)
1
Dry Ash
Removal
i
i
« * L u.i j Combined Fly
Dry Ash Mixed . . . _ . . '
With Scrubber Jf* S"U^b"
Sludge Slud8e Sluiced
" to Pond
1
Hauled Off
Site— Paid
Disposal
Ash Given Away
to Agency or
Croup at No
2ost to Company
J
Fly Ash
Slurry
to Pond
FIGURE 4-1
COMMON DISPOSAL ALTERNATIVES FOR FLY ASH!
(SEPARATE COLLECTION OF FLY ASH AND S02)
-------
Scrubber Sludge
Ponding
of
O
O
I
Pond-
ing
l)uw,i(i!riii|j & Fix-
ation Ot SlUtlttU
by Olending with
Dry Ply Ash
Kami-
I Land- I
tUllmj
Douacuriug 6 Klx-
atioit of Sludge
by Blendinu with
Dry Ply Aali & Lint
jl.un4-
Uuwaterinit t FU-
aclou of Sludge
by Cokiaorcial
Procose
l-'orctid Oxidation
of Sludge to
Cypeun Before or
After Collection
Poud-
Illtt
]l
Land-
Ipond-I
*n« I
Land-
iilling
-
!FIGURE 4-2 !
i
!
COMMON DISPOSAL ALTERNATIVES FOR FGD SCRUBBER SLUDGE
I
-------
Sluicing of
Mixture
to Pond
i
h-1
O
t-1
I
Ply Ash and
Scrubber Sludge
Combined
Oeuaterlng
and
Fixation
Forced
Oxidation of
FGD Sludge
to Gypsum
FIGURE 4-3
COMMON DISPOSAL ALTERNATIVES FOR
COMBINED FLY ASH AND FGD SCRUBBER SLUDGE
. I
-------
4.1.1.1 Alternatives for Collection and Disposal _-_-- __ -_
" Collection and disposal of fly ash is commonly performed
in either a wet or dry mode as shown in Figure.4-1. While the ash
material may be collected dry, as with an electrostatic precipita-
tor or a baghouse, wet sluicing may then be employed to convey the
ash to a disposal pond. Where wet sluicing and ponding are not -
employed, the material is usually hauled by truck.to landfill • • _.
disposal. If the ash is collected with a wet system, as with a
wet venturi, disposal is usually accomplished by subsequent pump-
ing to a pond in slurry form. The choice of pumping a water mix-
ture of the ash or transporting dry is often site specific and
highly dependent upon the method of collection.
In addition to direct disposal of fly ash, it is often
advantageous to mix fly ash and scrubber sludge together to take
advantage of the increased stabilization and fixation resulting
from the mixture. This material can be used as a very effective
pond liner, as discussed in the section, on chemical and physical
properties.
In dry form, the ash is either hauled to a landfill by
the utility company, or hauled offsite by a company paid to dispose
of the material, or even given away or sold to a company using the
material in some commercial process. Most of the dry material
leaving the plant ends up in landfills. The landfill sites are
rarely lined.
In the case of ponding of wet sluiced fly ash or com-
bined fly ash and scrubber sludge, the ponds can be lined or un-
lined. Common liners include clay and synthetic liners. A
stabilized mixture of fly ash and scrubber sludge can also serve
as an effective oond liner.
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Figure 4-2 illustrates various disposal options for
scrubber sludge. Basically, the options involve direct ponding
or dewatering. In either case, the sludge can be mixed with
(1) fly ash or fly ash and lime or (2) a number of other materials
used for commercial fixation processes. In the case of a pre-
dominantly sulfite sludge, material can also be .fully oxidized
to gypsum before ponding or dewatering. If dewatering is not
used, the sludges are commonly pumped at 10-15. percent solids.
Sludges can undergo partial dewatering and pumped to ponds at
20-35 percent solids. The sludges can be vacuum filtered to 50-60
percent solids and trucked or otherwise hauled to the landfill.
The options for disposal of combined fly ash and scrubber
sludge, such as that generated from a combined particulate and S02
scrubber, are presented in Figure 4-3. The options for disposal
are basically the same as those presented in Figure 4-2. The
combined sludge can be pumped directly to a pond, either fully
oxidized to gypsum or as a sulfite sludge. The sludge can be de-
watered and fixed and, depending on the extent of dewatering,
either ponded or landfilled.
In every case where ponding is used, either for dewatered
sludges or the slurry pumped directly to ponds, the solids can be
removed and landfilled after settling. Common designs for ponds
and landfills are presented in the following pages.
4.1.1.2 Pond Designs
The common types of designs for ponds are the diked pond,
the incised pond, and the side hill pond. Figure 4-4 gives con-
figurations for the three types of pond designs. The side hill
pond shown in the figure is advantageous in an area of hilly
terrain where a level area for constructing a diked pond or
incised pond is not readily available. The advantage of the side
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Side Hill Fond
Diked Fond
FIGURE 4-4
POND DESIGNS
Incised Pond
-104-
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hill pond is that it uses the natural slope of the terrain to pro-
vide one or two sides of the pond. If the angle of the sloping
terrain is too great, a large pond must be constructed utilizing
the contour of the hill or the bank on the downhill side must be
high.
Both the diked pond and incised pond are constructed on
a relatively level site. The incised pond is such that the special
volume of the pond is located entirely below the surrounding ground
level. Since excavation is necessary for the incised pond, it is
advantageous when bedrock is not encountered or where groundwater
will not cause drainage problems. The incised pond does not re-
quire space for dike construction or a suitable material for con-
struction and the incised pond may be an advantage where such fac-
tors are important. The diked pond is the most common type en-
countered. This type may be constructed above grade utilizing ex-
traneous dike material or it may be constructed below ground level
utilizing excavated material for full or partial dike construction.
Not shown in Figure 4-4, but sometimes used, is ponding
in an existing basin such as an abandoned strip mine or a quarry.
4.1.1.3 Landfill Designs
The most common landfill designs are shown in Figure 4-5.
The figure shows the side hill landfill. As in the case of the
side hill pond, this type of landfill is advantageous and most .
often utilized in areas of hilly terrain where the natural slope
of one side of a hill or valley may provide containment. The
side hill landfill must be properly prepared to insure stability.
The structurally, simplest form of landfill which may be
utilized with level terrain is the heaped landfill. Even though
this design is simplest in terms of site preparation and offers
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Side Hill Landfill
Heaped Landfill
Configuration
^
FIGURE 4-5
LANDFILL DESIGNS
Valley Fill
Disposal
Configuration
-106-
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advantages in terms of slope stability and ground-water pollution,
it is often an "eye sore" in relation to the surrounding terrain
and may not be preferred because of its visibility.
The valley fill design, which is the most common type of
landfill used, is often the most complex in terms of original site
preparation. Natural valleys or ravines are often sources of
surface-water runoff and may have springs along, side slopes. .In
such cases, surface water and groundwater control is necessary to
avoid accumulation of water and the development of a leachate prob-
lem. Drainage must be provided and often water is diverted under
the landfill and collected in order to control erosion and/or pol-
lution.
4.1.2 Disposal Practices
The previous discussion covered the methods of solid
waste disposal. In the following pages, the current mix of dis-
posal practices at coal-fired utilities is described. Fly ash,
bottom ash and scrubber sludge are evaluated for percentage of
each disposed by each of the methods addressed earlier.
Several sources of information were evaluated to provide
the data presented in this section. The initial data collection
effort involved obtaining a copy of the most current Federal Power
Commission tape for their Form 67 data. This tape contained infor-
mation for the year ending 31 December 1974. The FPC data indicated
that some 390 plants burned some percentage of coal as a boiler
fuel. The data covering disposal practices were not as specific in
terms of how the wastes are handled as were needed. In addition,
the cost data on disposal were a composite figure containing the
costs of both collection and disposal. It was not possible to
calculate disposal costs from these data.
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- - In order to provide the needed data on disposal practices,
Radian contacted 64 coal-fired utility plants. ..These plants, most
of:which began operation in the period 1970-1978, were characterized
according to the disposal method used for each.type.of solid waste,
the total coal-fired generating capacity of the plant, the solid
wastes collection equipment and the type of FGD systems used. The.
data obtained in this effort were supplemented with in-house data
and-the results of studies done by other companies. The data
obtained through the Radian initiated contact of.selected utilities
are more up-to-date and more extensive than the ETC data primarily
due to the fact that plant personnel were questioned in some de-
tail about the disposal method, the quantity of materials, the
use of pond liners, and the mechanism of disposal. In this way,
any confusion about the definition between landfill and ponding
was resolved.
Sixty-four coal-fired utility plants representing 50,900
Mw of generating capacity were contacted. Most of the detailed
data presented in this section come from 45 of the 64 plants.
These 45 plants were able to provide the full extent of informa-
tion requested. The only requested information not provided by
the plants was cost data relating to disposal. This was primarily
due to the fact that records are not kept to provide easy access
to such data. Most of these plants are relatively large and
represent a total generating capacity of 35,832 Mw. The mean per
plant capacity is about 800 Mw.
4.1.2.1 Fly Ash Disposal
The data on fly ash covers the methods of collection, the
amounts disposed of, and the methods of disposal. The collection
methods and disposal practices for the 64 plants is presented in
Table 4-1.
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TABLE 4-1
FLY ASH COLLECTION AND DISPOSAL PRACTICES
Number of Plants Percent of Plants
_ Method Reporting Method Reporting Method
I. Collection
Dry Electrostatic Precipitator 39 61
Mechanical (Baghouse, etc.) 8 . 13
Wet Electrostatic Precipitator 4 6
Particulate Scrubber 2 3
Other - 11 17
Total 64 100
II. Disposal
Ash Pond 26 40
Conveyed to Landfill (Dry) 19 30
Paid Disposal 11 17
Sale of Fly Ash 35
Intermediate Ponding followed
by Landfill 3 5
Other 2 3
Total 64 100
The data indicate that a majority of the plants surveyed
use ESF's to collect dry fly ash. However, most of these plants
dispose of the ash by ponding. Thirty percent haul the dry fly
ash to landfill disposal. Five percent use landfill of settled
ash after ponding.
The data indicate that approximately 17 percent pay
another company to dispose of the ash and five percent sell the ash
directly to some company. In addition, a significant amount of the
fly ash removed by paid disposal may be sold and utilized. Thus,
the total amount of ash utilized is difficult to determine from the
disposal data. The fraction indicated "other" is fly ash given
away or otherwise disposed at no cost to the utility.
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The data on the amount of fly ash disposed by each method
is presented in Table 4-2. These data were obtained from the 45
plants providing more detailed data as compared to the whole sur-
vey of 64 plants.
TABLE 4-2
FLY ASH DISPOSAL PHACTICES BY QUANTITY OF ASH
Amount Percent
Disposal Method (103 metric tons/yc.) of Total
Ponded 3,148 34
Landfill 49763 51
Paid Disposal 1,415 15
Sold — ~
Other 3, —
Total 9,329 100
A comparison of Table 4-1 and 4-2 indicates that while a
greater number of plants use ponding of fly ash, the greatest
quantity of material is disposed by landfill. Of the 45 plants
contacted, none sold their fly ash but some of the paid disposal
includes material that was eventually sold.
4.1.2.2 Bottom Ash Disposal
The data on bottom ash obtained from the survey covered
collection method, the amounts disposed of, and the methods of dis-
posal. Collection methods and primary disposal practices for the
64 plants are presented in Table 4-3.
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TABLE 4-3
BOTTOM ASH COLLECTION AND DISPOSAL PRACTICES
Method
I. Collection •
Wet Sluiced
Dry Conveyor
Other
II. Disposal
Total
Ash Pond
Conveyed to Landfill (Dry)
Paid Disposal
Sale of Bottom Ash
Intermediate Ponding Followed
by Landfill
Other
Total
Number of Plants
Reporting Method
52
11
1
64
24
17
8
6
6
3
64
Percent of Plants
Reporting Method
81
17
2
100
38
27
12
9
9
5
100
The data indicate that, on a plant basis, the vast
majority wet sluice bottom ash but less than half of these plants
use ponding for disposal. It is not known why this discrepancy
exists. Mechanical dewatering and dry disposal of bottom ash is
not a common practice.
The data on the amount of bottom ash disposed of by each
method are presented in Table 4-4. These data were obtained from
the 45 plants providing more detailed data.
These data indicate that, from a quantity standpoint,
the most common method of disposal is ponding. These data tend
to confirm the data for disposal methods on a per plant basis pre-
sented in Table 4-3 as to the use of ponding over landfill for
disposal.
-Ill-
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TABLE 4-4
BOTTOM ASH DISPOSAL PBACTICES BY QUANTITY OF ASH
Amount Percent
Disposal Method (10 metric tons/yr.) of Total
Ponded . 1,763 44
.Landfill 1,138 __29
Paid Disposal 671 16
Sold 444 . a
Total 4,016 100
4.1.2.3 Scrubber Sludge Disposal
The data obtained from the 1974 Form 67 or from addi-
tional contact with 64 plants were not sufficient to cover solid
wastes from flue gas desulfurization processes. To enable
evaluation of FGD disposal practices, additional data was gathered
on 30 plants utilizing 302 scrubbers. The plants began operation
in the period 1970 to 1978. Data sources used to generate the
list of 30, include an EPRI report by Michael Baker, Jr., Inc.ss
a PEDCO report, ss and various in-house information. The data pro-
vide information on the disposal practices, treatment prior to
disposal and disposal site preparation. The data do not include
waste generation rates on a per plant basis.
Of the 30 plants operating S02 removal systems, all utilize
a wet scrubbing system. The source of alkalinity (calcium for the
calcium-sulfur reaction) does not vary. The plants use either
limestone, lime, fly ash or a combination of the three. The total
amount of sludge generated is highly dependent on the source of calcium.
The total generating capacity of the 30 plants amounted to
approximately 12000 Mw. Some 18 plants totaling 8,700 Mw utilize
pond disposal of the sludges while 12 plants totaling 3,400 Mw utilize
landfilling. In many cases, fly ash and scrubber sludge are removed
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together. However, complete information on how many plants do
this was not available. In many cases, the fly ash is removed . . '
in a dry collection system, such as an ESP, prior to the scrubber
and landfilled while the scrubber sludge is ponded.
Of the 18 plants ponding scrubber sludge, eight pump
the collected sludge to the pond site without any further treat-
ment (dewatering, thickening, or commercial fixation). The re-
maining ten plants all utilize thickening processes prior to
ponding of the sludge but only one plant is utilizing a commer-
cial fixation process in conjunction with ponding while two uti-
lize forced oxidation of the sulfite sludge to gypsum.
Among the 12 plants utilizing landfilling of scrubber
sludge, seven use some method of stabilization involving either a
commercial process or blending of sludge with fly ash or a fly ash/
lime mixture. Three plants provide commercial fixation. For the
five plants providing no stabilization prior to landfilling, one
dewaters and landfills direct while the other four plants (located
in arid climates) utilize intermediate ponds for evaporation and
eventually excavate sludge from the holding ponds for landfill.
The same data sources mentioned earlier, provided data
on the planned practices among some 38 power plants contracted for
SO2 removal systems or under a letter of intent to do so by April 1,
1978. These plants should begin operation by 1986. The generating
capacity of these additional 38 plants is 26,700 Mw. The survey of
the planned scrubber systems indicate a slight tendency to use land-
filling of dry waste over ponding. Specifically, 19 units (11,500
Mw) will utilize landfill and 17 (13,700 Mw) will use ponding with
two plants being undecided as to disposal alternative.
For future planned installations using ponding, ten of
17 will not treat the sludge in anyway prior to ponding. Of the
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remaining seven, six will utilize dewataring techniques prior to
ponding and one will use a settling pond. One plant will provide
forced oxidation without thickening and another plans to contract
for utilization of the Dravo commercial fixation process with pond-
ing.
--""- Some type of stabilization and/or fixation is planned
for 16 of the 19 new units landfilling sludge. Four plan to con-
tract for use of the IUCS commercial fixation process. The re-
maining units are planning to use some other form of stabilization.
The methods are to blend either lime and fly ash with sludge (1-
unit) or fly ash alone with sludge (11-units), all after some form
of dewatering (centrifugation, vacuum filtration or mechanical
thickening). The three installations not planning to use any
means of stabilization will landfill sludge that has been de-
watered by vacuum filtration.
4.1.2.4 Distance to Disposal Site *
As the distance from the plant to the disposal site is
a prime factor in the cost, of disposal and in characterizing
existing disposal practices, data was obtained from 54 coal-fired
power plants. These data are presented in Table 4-5. The data
are presented by distance intervals. The mean distance from
plant to disposal site was three miles.
The information was obtained in the form of .distance
to disposal site as opposed to on-site or off-site disposal as
this information is believed to be more relevant for the pur-
poses of this report.
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TABLE 4-5
DISTANCE FROM PLANT TO WASTE DISPOSAL SITE
Percent of Plant Percent of Waste
in Interval in Interval
Less than 0.8 kilometers 26.8 7.22
0.8 kilometers to 1.4 kilometers 16.0 .24.49
1.6 kilometers to 4.7 kilometers 21.4 36.50
4.8 kilometers to 7.0 kilometers 19.6 24.52
8.0 kilometers to 15.9 kilometers 7.2 4.77
16.1 kilometers to 32.0 kilometers 5.4 1.08
Greater than 32.1 kilometers ?.* 1.42
100.0 100.00
A significant factor regarding the distance analysis is
the fact that nearly 93 percent of all bottom ash and fly ash from
the representative 54 plants is transported less than 8 kilometers
(5 miles) form the generating plant to the ultimate disposal site.
This is a strong indication that the cost of transporting large
volume wastes over distances is generally avoided.
The data presented in Table 4-5 are intended to portray
the practices currently used in the utility industry in the United
States. In addition, the mean distance from the plant to disposal
sites was 4.8 kilometers (3 miles) for this representative group
and is intended to be realistic for the industry as a whole.
4.2 Economic Impact of RCRA
The economic impact of Section 4004 of RCRA on the
electric utility industry is addressed in this section. The pri-
mary objective was to quantify the economics of compliance with
RCRA. Inherent in this development was the assumption that fly
ash, scrubber sludge and bottom ash resulting from the burning
of coal in power plants are non-hazardous wastes under the defini-
tions of the Act.
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The basic approach used in this section involved devel°
opment of an enforcement scenario, design of a typical plant to
describe the quantities and types of wastes to be.disposed of,
development of the cost of disposal for the typical plant, and
use of the disposal cost data to estimate the cost of the com-
liaaee scenario.
The analysis of the economics of compliance with RCKA
was based on defining disposal options for a "typical" coal-fired
power plant. The typical plant has a name plate capacity of 1000
Mw. Options for the plant included burning either high sulfur
eastern coal or low sulfur western coal. The nationwide cost of
compliance was estimated from using the costs developed for the
various disposal options for the typical plant.
A direct calculation of the cost of compliance for the
industry on a nationwide scale was not performed. This was not
possible for essentially two reasons. First, there is consider-
able uncertainty in how the regulations will be interpreted and
enforced. Second, determination of which plants are not in com-
pliance required extensive information on disposal practices on
a plant by plant basis. In the first case, there is considerable
flexibility inherent in the enforcement mechanism preventing pre-
cise determination of how RCRA will be enforced. Ultimately the
enforcement mechanism will be a state and local function and will
be dictated by local disposal conditions based on options avail-
able to the plants. In the second case, a necessary level of
detail concerning current disposal practices and the environmental
effects of the practices was not available and therefore, deter-
mination of which plants or facilities are not in compliance was
not possible.
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The following discussion includes an analysis of the
Resource Conservation and Recovery Act as it may pertain to solid
waste disposal in the electric utility industry, the development
of several enforcement scenarios, a typical or base case for the..
economics and some hypothetical impacts of the various enforce-
ment scenarios. This analysis does emphasize wet scrubbing as'a
mean's of S02 and fly ash removal. As currently proposed (9/19/78)21
air regulations for coal-fired power plants tend to encourage the
use of scrubbers. :
4.2.1 Interpretation of RCRA
The development of potential enforcement scenarios was
accomplished with input from both the written documents and from
conversations with the EPA regional offices. Although no claim
is made suggesting that the proposed regulations will be enforced
as outlined in this section, the enforcement scenarios were neces-
sary to define what the impacts might be on the typical plant.
The site-specific nature of the regulations as written and the
flexibility given to the states in both classifying facilities and
regulating possible clean-up make it impossible to define exactly
what actions will be taken. This situation made it necessary to
use the hypothetic enforcement scenarios as a means of assessing
potential impacts.
The general interpretations of the proposed regulation
were based on an analysis of the Resource Conservation and Recov-
ery Act of 1976s7 and the proposed classification criteria pub-
lished in the 6 February 1978 Federal Register.38
One of the stated objectives of RCRA is "to prohibit
future open dumping on the land and to require conversion of
open dumps to facilities which do not pose a danger to the en-
vironment or to health".
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The objective is to be accomplished by state and federal
cooperation through the development of state plans aided by fed-
eral economic and technical support. The responsibilities of the
states in these "state plans" are to: (1) identify the responsi-.
bilteies of state, local, and regional authorities in the implemen-
tation of the "state plan"; (2) to prohibit the establishment of
new open dumps within the state; and (3) to require that..all
solid waste be disposed of in sanitary landfills or in an environ-
mentally safe manner.. The plans will provide for closing or up-
grading of existing open dumps.
The main engineering point is the distinction between an
open dump and a sanitary landfill. This point is further clari-
fied in RCRA in that "a facility may be classified as a sanitary
landfill and not as an open dump only if there is no reasonable
probability of adverse effects on health or the environment from
the disposal of solid wastes at such facilities." The probab-
ility of adverse effects must then involve the character of the
wastes, the manner of disposal and the location of the disposal
site.
The mechanism of enforcement starts with the require-
ment, set forth in RCRA, that an inventory be made of all exist-
ing disposal facilities in the U.S. which are open dumps and that
this inventory be published. The states, under the proposed rules
published in the Federal Register, have responsibility for pre-
paring the inventory.
As currently proposed, the considerations of importance
in determining whether a site is an open dump or a sanitary land-
fill involve both location and performance factors. These are
discussed below.
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4.2.1.1 Location Considerations
The sites are not to be located, in general, "in envir-
onmentally sensitive areas when feasible alternatives exist un-
less it can be clearly demonstrated that no significant adverse
impact on the ecosystem or human health" will result. The envi-
ronmentally sensitive areas which are addressed in this section
are: (1) wetlands, (2) flood plains, and (3) sole source aqui-
fers. Those, then become the primary location: Judgements. While
these environmental units have been defined, they have not been
fully mapped for all the states. In general, it is advised not to
locate new facilities or expand old facilities in such areas
unless no other feasible and/or economical alternatives exist.
For wetlands, new disposal sites may not be placed in
designated areas and existing operation may not be continued un-
less a NPDES permit is obtained under Section 402 of the FWPCA
Amendment of 1972.59
For flood plains, the establishment of any new facility
or expansion of any old facility in a flood plain must not cause
increased flooding during the base flood or be constructed in such
a way as to be inundated during flood episodes. Facilities can
be located in such flood plains if it can be demonstrated that
they will not adversely affect water quality or flood flow capa-
city.
Sole source aquifers are to be protected from any degra-
dation of water quality. In general, no solid waste disposal
facility is to be located in a sole source recharge zone unless no
feasible alternatives exist.
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4.2.1.2 Performance Considerations
- The performance standards tend to emphasize two points: :
(1) permitting for new facilities (NPDES) and (2) proof that
existing or planned facilities, particularly those within environ-
mentally sensitive areas, are the only feasible.options available.
to the industry and that they will have no adverse effects on the
environment. Of particular concern is protection.of groundwater,
even if the site is not in an environmentally sensitive area.
-: In determining compliance with the regulations, applica-
tion of the best practicable controls is specified in conjunction
with environmental monitoring to determine any adverse impacts.
All facilities must be "so located, designed, constructed, operated
and maintained in order to emphasize the use of best practicable
controls and to allow a determination of compliance based on site-
r 58
specific evaluation of these control technologies..." Although
environmental monitoring is encouraged, it is pointed out that
-"the state may determine it is not necessary to monitor if the
facility is such that no adverse effect is expected because of
low volume or inert or innocuous wastes and because the control
technologies and practices are considered (by the state) to
achieve the environmental standards." It is up to the states
to determine a compliance schedule for any facilities judged as
not in compliance.
From this review of the proposed regulation the follow-
ing points were concluded:
• The states and local agencies will have
considerable flexibility in determining
what existing sites are open dumps, in
the development of compliance schedules
and in determination of what actions,
designs, and controls are considered
acceptable.
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• The regulations emphasize both location
and performance standards which make it
impossible to determine how many plants
will be affected.
4.2.1.3 EPA Opinions on Enforcement Options
All of the EPA regional offices were contacted in an
attempt to define three items: (1) if the environmentallly.sen-.
sitive areas have been mapped, C2) if any estimate of the number
of facilities affected has been made, and (3) what, if any, inter-
pretations the regional offices have made concerning enforcement.
The responses were used to develop reasonable enforcement scenarios.
They were solicited on an informal basis and are not to be con-
strued as official statements of policy.
The answers from the regional offices to these informally
presented questions demonstrated a considerable variance in inter-
pretation of the proposed regulations. There were some definite
general conclusions, however. While some of the states are cur-
rently developing or have recently developed maps of wetlands,
these are not generally available. The flood plains have been
mapped by HUD. Some sole source aquifers have been designated.
However, many of the regional offices are of the opinion that
additional aquifers may be designated in the future.
On the question of enforcement, many of the regional
offices expressed the opinion that there will be considerable
flexibility in how the various states enforce RCRA. This flexi-
bility will be caused as much by the local disposal conditions as
by the regulatory climate in the specific states. Most of the
regional offices expressed the opinion that enforcement will
necessarily proceed on a case-by-case basis and that generalized
conclusions regarding non-compliance are not possible under the
circumstances.
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Another important opinion presented by many of .the re~
gional offices is that case-by-case review of existing facilities
will probably be oriented toward proof of environmental damage as
opposed to a presumption of guild based on location. In other
words, just because a site is located in a wetland does not mean
that environmental damage will occur. The primary concern appears
to be with groundwater protection.
4.2.2 Costing Basis for Enforcement Scenarios
The development of a costing basis for estimating the
impact of RCEA was performed in three steps: _.:
1) Development of a potential enforcement scenario,
2) Development of engineering data describing
disposal options for a "typical" coal-fired
plant, and
3) Development of cost factors for the disposal
options.
4.2.2.1 Development of Potential Enforcement Scenarios
As explained earlier, flexibility in the methods of en-
forcement is expected when RCRA is implemented. Compliance
options were developed for the purpose of providing a reasonable
enforcement scenario. The general scenarios are summarized
below. Plants are divided into existing facilities and planned
(future) facilities.
• Existing disposal sites declared open dumps
(located in wetlands, flood plains, sole source
aquifers or known to be contamination ground-
water) and the sites are closed. New disposal
sites are located outside the environmentally
sensitive areas and all ponds are lined to pro-
tect groundwater.
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• New plants to be constructed will generally avoid
environmentally sensitive areas and will provide
for maximum protection of groundwater through
lining of all ponds.
The potential impact of RCRA on existing facilities
was assumed to be limited to newer plants, those that began
operation after 1970. The data for existing plants presented
in Section 4.1.2 was used to describe existing operations at
these plants. The plants were assumed to have to move disposal
for the current distance of 4.8 kilometers or 3 miles (average)
to 16.1 kilometers (10 miles) from the plants. The increase in
the average distance to disposal is assumed to be necessary to
protect groundwater. New landfill sites are assumed to be neces-
sary to protect groundwater. New landfill sites are assumed to
be located in impermeable areas or areas where groundwater quality
is not in danger from such facilities. Ponds are assumed to be
located outside environmentally sensitive areas, away from ground-
water resources and are assumed to be lined for further protection.
For planned facilities, the primary assumption is that
all plants will be affected by RCRA. The primary effect is
assumed to be the distance from plant to disposal. As siting of
disposal facilities will be a concern in the planning stage for
the whole plant, it is assumed that the average distance from
plant to disposal site will increase over the current average of
4.8 kilometers. As the plants can take this into account in
siting the plant, the new distance is assumed to be less than
the 16.1 kilometers used for the existing plants. The distance
used was 8 kilometers. It was also assumed that all ponds would
be lined, regardless of groundwater conditions.
4.2.2.2 Development of Engineering Data
The typical plant, characterized for the purpose of
quantifying the impact of enforcement, was based on 1000 Mw "name
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plate" capability with a 35 percent thermal efficiency. To cover
a typical range of coal properties and operating conditions, the
-design data presented in Table 4-6 were used. The assumptions
made on all design data are based on typical data for the industry.
SO2 scrubbers using limestone were assumed for the purpose of .
meeting air quality regulations for S02 emissions..
r.\
- - • -.--:: - Regulatory assumptions were made for both current, .regula-
tions- and proposed future regulations. These regulatory condition?.
were chosen to illustrate any impacts on solid waste generation . -
to be expected from future regulations- The final regulations for
new source performance have not been adopted. The regulatory ~.
assumptions used are listed below.
Current Proposed
Regulations Regulations
Fly Ash Removal 99% 997,
SO z Removal 1.2 Ib S02 85%.
106 Btu
(Allowable Discharge)
The operating conditions, coal properties and regula-
tions assumed were used to calculate the solid wastes generated
by the "typical" plant. These are presented in Table 4-7.
The dominant impact of the proposed regulations is for
scrubber sludge at plants burning low sulfur coal. This impact
is taken as the difference between existing sludge generation
rates and the rates to be generated assuming implementation of
the proposed regulations. The difference for high sulfur coal
is only slight.
The densities for the solid wastes listed in the pre-
vious table are summarized in Table 4-8.. These figures were
used to estimate the volumes of solids generated. In addition
to the assumptions concerning density, the water content of the
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TABLE 4-6
DESIGN BASIS - FOR 1000 MW COAL-FIRED POWER PLANT
Coal Type
Plant Design Data
Stream Factor, hr/yr
First Year
Average 30 yr. life
Thermal Efficiency, %
Fly Ash to Bottom Ash
Ratio
Plant Life
New, yr.
Existing, yr.
Coal Data
Heat Value (Wet), Btu/lb
Ash Content (As
Burned, %
Sulfur Content, 78
Flue Gas Cleanup
Percent of Sulfur in
Coal Converted to S02 , %
Fly Ash Removal
Scrubber, %
Dry Removal (ESP,
Baghouse) , %
Scrubber Design
Limestone Stoichiometry*
Percent Solids in Efflu-
ent from FGD System, %
Ratio of Sulfite to Sul-
fate in Scrubber Sludge
Western Coal
.
7,000
4,350
35
80/20
30
25
9,000
8'
0.8
95
99
99
1.5
15
85/15 •
Eastern Coal
7,000
4,350
35
80/20
30
25
11,000
15
3
95
99
99
1.5
15
85/15
*Ratio of moles limestone added to moles S02 removal.
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TABLE 4-7
SOLID WASTE GENERATION RATES FOR
1000 MW COAL-FIRED POWER PLANT
Fly Ash
Bottom Ash
Scrubber Sludge
Current
Regulations22
Proposed
Regulations2 x
Fly Ash and
Scrubber Sludge
Combined
Current
Regulations2 z
Proposed
Regulations2 *
Solid Waste Rates,
Western Coal
Dry 50%
Solids Solids
25.0
6.3
2.0
15.0
26.9
39.9
4.0
29.9
65%
Solids
53.9
79.8
65%
Solids
3.1
25.4
70%
.Solids
38.5
57.1
Metric tons/hr.
Eastern Coal
Dry
Solids
38.2
9.5
38.3
45.8
76.5
84.0
50%
Solids
76.6
91.6
65%
Solids
117.9
128.8
65% -
Solids
58.9
70.5
70%
Solids
109.8
119.7
-126-
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of the settled sludges were also assumed. The volume of material
for ultimate disposal is very dependent on the percent solids.
The volumetric waste generation rates are summarized in Table 4-9.
TABLE 4-8. DRY AND WET BULK DENSITIES OF FGD WASTE PRODUCTS
Fly Ash
Bottom Ash
Scrubber Sludge
Fly Ash and
Scrubber Sludge
Specific
Gravity
2.55
2.55
2.55
2.55
Dry Bulk Density
-------
There were two basic disposal practices used for the
calculations in this study. They were ponding .and landfill.
Although ponding can be considered a form of landfill, the. method
of solids handling and equipment required are different. For
landfill of dry solid or dewatered sludges, it. is assumed that
some form of trench filling will be used as described-in the pre-
vious section. Landfills can be located in areas, suitable for...
this type of disposal and not require liners. . ---- .-.--:.
Ponds are assumed to be 9.1 meters deep, rectangular
shape and contained by dikes with a three to one slope. In actual
practice, the depth and shape of the ponds will be determined by
local conditions. The ponds are assumed to provide a thirty-year
lifetime. The land area needed to dispose of sludges was calcu-
lated and are summarized in Table 4-10. The land requirements
needed for ultimate disposal depends on the final settled volume
which in turn depends on the water content. The data in the table
reflect the considerable difference between eastern and western
coal in terms of pond requirements.
In order to protect ponds from flooding, it was assumed
that dikes or levees would be constructed. These would have to
be designed so as not to interfere with flood waters or cause in-
creased upstream flooding. Should it be impossible to design and
construct a flood protection dike under these restrictions, it was
assumed that disposal would have to be located outside the flood
plain. The dike referred to for flood protection is a diversion
structure and is different from the dikes forming the pond walls.
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TABLE 4-10
LAND REQUIREMENTS IN SQUARE METERS FOR
A 1000 MW COAL-FIRED POWER PLANT
PONDING
Wet Sluiced Fly Ash
Wet Sluiced Bottom Ash
Scrubber Sludge
Current Regulations21
.Proposed Regulations21
Fly Ash and Scrubber Sludge
Combined
Current Regulations 22
Proposed Regulations21
LANDFILL*
Dry Disposal Fly Ash
Dry Disposal of Scrubber
Sludge (Dewatered to 50%
Solids)
Current Regulations 22
Proposed Regulations21
Dry Disposal of Fly Ash
and Scrubber Sludge Combined
(Dewatered to 657. Solids)
Current Regulations 22
Proposed Regulations21
Western Coal
364
93
49
372
393
668
Western Coal
295
49
372
393
668
Eastern Coal
. 563
138
951
1,141
1,275
1,404
Eastern Coal
453
951
1,141
1,275
1,404
*Both ponds and landfills are 9.1 meters deep (30 feep)
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TABLE 4-11 COMPARISON OF ASSUMPTIONS
BETWEEN 1000 MW PLANT AND TVA COST EVALUATION
Western Eastern
TVA Study Coal Coal
Plant Size, MW 500 1,000 1,000
Coal Data
Heating Value (Wet), Btu/lb 10,000 9,000.:. 11,.000.
Ash Content, % 16 8 : 15
Sulfur Content, % 3.5 0.8 3
Yearly Operating Time, Hrs.
New Plant - 7,000 7,000 7,000
Average Over-Plant Lifetime 4,350 4,350 4,350
Life of New Plant, yrs. 30 30 30
Scrubber Data
Limestone Stoichiometry 1.5 1.5 1.5
for Scrubbing Operations
Percent of SO 2 Converted:to:
Calcium Sulfate, % 15 15 15
Calcium Sulfite, % 85 85. 85
Solids Content of
Slurry from Scrubber, % 15 15 15
Solids Content After
Clarifier, % 35 35 35
Percent Solids of
Settled Sludge:
Scrubber Sludge Only, % 50 50 50
Fly Ash & Scrubber Sludge, % 50 65 65
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4.2.2.3 Development of Cost Factors
The economics of the various disposal options were esti-
mated using published data. Most of the cost data used were taken
from the EPA report 600/7-78-023a "Economics of Disposal of Lime/
Limestone Scrubbing Wastes; Untreated and Chemically Treated
Wastes."81
While the exact cost to a specific power plant will vary
widely depending on the type of coal burned, available disposal
conditions and existing equipment at the plant, the cost figures
are presented as reasonable "ballpark" numbers and give a rough
cost estimate for compliance with the assumed enforcement scenario.
The published data used were for a specific coal and plant design.
These conditions were very nearly the same as for the eastern coal
used in this study. The coal properties for the western coal were
considerably different, however.
To compensate for the difference between eastern and
western coals, it was necessary to estimate the impact associated
with the lower ash and sulfur content of the western type coal.
The cost data used to develop the estimates for this study included
an assessment of the effect of ash content and sulfur content on
the economics of disposal. Linear interpolations were made using
these data to estimate the base cost for western coal. The
reductions in the costs of disposal resulting from the lower ash
and sulfur rates were partially offset by the slightly higher
coal rate required. The higher burn rate for coal resulted from
the lower heating value of the western coal as opposed to the coal
used in the cost study. A comparison of the significant assump-
tions between the various coals is presented in Table 4-11.
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The cost of landfill disposal of dry solids is generally
cheaper than wet sluicing of these materials if the disposal site..
(pond or landfill) is three miles or more from the plant. The
-cost of land for disposal can be expected to vary considerably
from one location to another. The primary advantage of this method
of disposal is the low capital cost resulting from the absence of
-expensive* pumping or dewatering equipment. Although site, prepar-
ation was taken into account, it was assumed that liners will not
be necessary for landfill type operations.
Table 4-12 contains the cost estimates used for the eval~
uation of the disposal options. These cost figures were used to
estimate the cost of compliance associated with the enforcement
scenario. The table includes both capital and operating costs
for each option. These figures are presented in dollars per kilo-
watt for capital investment and mills per kilowatt hour for rev-
enue requirements. The data can be used to assess the impact on a
specific plant given the capacity and operating characteristics of
the plant. The cost figures represent reasonable "average" fig-
ures to the extent that 1000 Mw represents an average plant.
4.2.3 Estimated Cost of Compliance
The cost factors summarized in the previous table were
used to estimate the cost of compliance of the enforcement scenario.
The results of this analysis are presented in the following pages.
4.2.3.1 Assumptions
Several key assumptions were necessary to estimate the
economic impact of RCRA. Some of these assumptions have a
reasonable basis. However, others are; subject to question.
-132-
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TABLE 4-12
COST ESTIMATES*FOR SOLID WASTE
DISPOSAL FROM A 1000 MW PLANT
t.
2.
3.
4.
5.
6.
7.
8.
9.
10.
U.
12.
13.
14.
IS.
16.
• Oeeimi j?a««n
(tow Plants Scrubber Sludge
aaA Flyaah — IS Percent
Solid* Puaped 4.8 Kllomear*
to day-Uaad Pond.
Five Tear Old Plants Saae
M Huabar 1.
Hew Plant: Scrubber Sludge
(only) — 15 Percent Solid*
Pooped 4.8 Kiloaeter*
day-Lined Pood.
rive Tear Old Planes Sea*
a* Huaber 3.
Hew Plants Sea* aa Huaber 1
except Puapad 8 Kilometer*
Bee Plants Sea* aa Humber 1
and 3 Except Puaped 16.1
KUoaeter*.
Her Plants Tiy Ash Only.
Trucked 4.8 Kiloaeter* u
Landfill.
Hew Plants Fly Aah Only.
Trucked eo Disposal 16.1
Uloaeten.
Hew Plants Ply Aah Only.
tfet Sluiced eo Pond 4.8
Ktloaeter*.
Hew Plants Fly Aah Only.
Wet Sluiced eo Pond* 16.1
sUloaeter*.
Hew Plant: Saaa aa Huaber
1 Except Clarified ea 35
Percent Solid* Before Pumping.
Hew Plants Clarified and
Filtered to 60 Percent
Solid*; Trucked 4.8 Kilo-
meter*.
Hew Plant: Saae a* Huaber U
Except Puaped 16.1 Kilometers
Hew Plant: Sane a* Huaber 12
Trucked 16.1 Kilooeter* co
Landfill,
Hew Plant: Saae aa Number 1
Except Pond Lined with Syn-
thetic Pond Lining Coating
Sl.JO/yd1.
Hew Plant: Saae aa Nuaber 15
Except Coat of Lining la
S4.50/yd*.
wm
Capital Cose
do's) is/ian
17.27S
12.920
11.240
8.400
21,050
29,350
390
430
11.240
19.100
15.620
6,670
19.520
7.250
20,250
24,730
17.3
12.9
11.2
8.4
21.1
29.4
0.4
0.4
11.2
19.1
*
15.6
6.7
19.5
7.3
20.3
24.7
• CVTn VUBi.
Revenue
(10*$/yrt
3.920
3.400
-
2.670
2.310
4.920 '
fr.6SO
1.560
2,060
2.670
4.550
3.830
3.790
3,740
5.180
' 4.460
5.360
Requlrooonc*
(Milla/Kwhrl
0.56
0.49
0.38
0.33
0.70
4
0.95
0.22
0.29
0.38
*
0.65
0.55
0.54
0.78
0.74
0.64
0.77
Capital
(IP'S)
31,920
23.880
21.070
15.760
38.890
54.220
392
660
14.000
23.780
30.970
12.330
45.580
13.400
37.400
45.680
Si
Coae
(S/PO
31.9
23.8
•
21.1
15.8
38.9
54.2
0.6
0.7
14.0
23.8
31.0
12.3
45.6
13.4
37.4
45.7
utern coal
Revenue
(10'S/VT)
6.730
5,840
4.530
3.920
• 8.440
11.460
2.380
3,140
3,200
5.450
6,580
6.490
9.850
8,890
7,650
9,200
Requirement*
•
0.97
0.84
0.66°
0.37
1.21
1.64
0.34
0.44
0.46
0.78
"
0.94
0.93
1.41
1.27
1.10
1.32
Untreated and Chemically Treated Uaatea" Haeional Fertilizer Development) Canter. Tanneaaee Valley Authority.
TVA stOL 4-123. EPA-600/7-78-023a, February 1978.
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Therefore, the assumptions are presented only as being reasonable.
and are not to be construed as being the only reasonable assump-
tions nor necessarily the best assumptions. Furthermore, the
estimate of the economic impact of RCRA presented in this section -
should be evaluated in light of these key assumptions.
'Two sets of assumptions were made: one set for existing
planes and one for new plants. For existing plants, the assum-
ptions- 'are concerned with : (1) what plants are currently doing in
terms of disposal, (2) the cost of current operations, (3) the
number of plants affected by RCRA and (4) how the plants will
react to the new regulations. For future plants, the assumptions
cover (1) what disposal methods the plants will need, (2) how
RCRA will influence disposal and (3) the number of plants affected.
The specific assumptions made to enable an estimate to
be made of the cost of enforcement are presented below.
Assumptions for Existing Plants
Only plants starting operation since 1970 will be affected by
RCRA.
The total capacity of plants starting operation in the period
1970-1976 is 42,500 Mw, based on the absolute increase in coal
consumption by electric utilities over this time period (FEA
report*1). The average size of existing plants is assured to
be 1000 Mw, resulting in an estimated 43 new plants.
Of these plants, 82 percent burn eastern-type coal and 18 per-
cent burn western-type coal.
The distribution of disposal practices for the 42,500 Mw of
facilities is the same as the results as presented in Section
4.1 of this report.
The economic data presented in the TVA report are applicable
to the plants.
No estimate is made of the cost to cover and abandon existing
facilities.
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7. The average distance of current disposal practices is 4.8 kilo-
meters (3 miles).
8. Plants will need to relocate their disposal an average of 16.1
kilometers (10 miles) for the plant.
9. The plant will use the cheapest disposal method at the new
disposal site.•
10. The cheapest disposal method is assumed to be the cheaper
for the TVA report.
11. The TVA data for 5-year old plants can be used to estimate the
cost of current disposal.
12. The additional costs of RCRA will be the capital cost and
moving the ponds an average of 16.1 kilometers. The additional
revenue requirements will be the difference between these at
16.1 kilometers (using liners) and current operations 4.8
kilometers.
Assumptions for New Plants (Future^Construction)
1. The projected impact of RCRA on new plants is limited to those
projected to be constructed by 1985.
2. The projected capacity to be constructed in the period 1975-
1985 is 160,000 Mw or assuming 1,000 Mw plants approximately
160 plants (FEA report80).
3. Of these plants, 77 percent are projected to burn an eastern-
type coal and 23 percent are projected to burn a western-type
coal.
4. The distribution of disposal methods for these plants will be
the same as estimated for currently planned but not yet con-
structed facilities.
5. The economic data for disposal practices presented in the TVA
report can be used to predict disposal cost.
6. The addition of location criteria plus the other'RCRA regula-
tions will result in plants having to locate disposal an average
of some 8 kilometers from the plant as opposed to 4.8 kilometers
for no RCRA regulations.
7. The added cost associated with RCRA is the difference between
requiring 3 meters of clay liner at all ponds and an average
distance of 8 kilometers versus the cost of disposal as cur-
rently performed.
8. Landfill will be located in areas where no danger to ground-
water exists and, therefore, no liners will be required.
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4-2.3.2 Existing Plants
- --- • The estimate of the cost of RCRA for existing plants ..- ..
involved several calculations. The first calculation was the
estimate of the cost of current disposal practice... As the
•capital' investment for a new disposal site is .independent of any
past capital expenses, the cost of current operations .was based on
only the revenue requirements (operation and maintenance costs). __:
The mix of disposal practices established in Section 4.1.2 was used
to estimate the total megawatt capacity of facilities disposing of .
each waste with each disposal method. The capacity figures were
then multiplied by modified cost factors based upon the cost * .
estimates from Table 4-12 (in mills/kw-hr) to give the revenue
requirements in dollars per hour. An assumed operating factor of
7,000 hr/yr was then used to estimate the annual revenue require-
ments. The annual revenue requirements calculated in this manner
thus represent annual costs during early plant life as opposed to
costs averaged over the entire plant life. In later years, the
annual revenue requirements will be lowered. The results of these
calculations are presented below in Table 4-13.
TABLE 4-13
ESTIMATE OF REVENUE REQUIREMENTS FOR EXISTING DISPOSAL FACILITIES -
1970-1978
Capacity (In Mw) Revenue
of Plants Using Requirements
Material Method of Disposal Disposal Method ($/yr)
Fly Ash Ponded 10,400 $28,230,000
Landfilled 15,600 $29,750,000
Scrubber
Sludge Ponded 5,220 $19,250,000
Dewatered &
Landfilled 2,100. $ 7,350,000
Fly Ash &
Scrubber Ponded 3,480 $18,920,000
Sludge Dewatered &
Combined Landfilled 1.400 $ 7.200.000
Total 38,200 $110,700,000
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The estimate of the cost of existing disposal is
$110,700,000 per year. This cost represents 38,200 Mw or 90
percent of the assumed total capacity of plants. The remaining
10 percent use paid disposal, sell the material, or do not
specify the exact disposal method. This cost estimate presented
has ignored this 10 percent of capacity and assumes that disposal
costs are balanced by utilization revenues for. this segment.
—: The next step involved estimating the cost of compliance
with RCRA. The assumed impact on the plants was that the average
distance to disposal would be 16.1 kilometers (10 miles), as
opposed to 4.8 kilometers (3 miles) at present, and that all ponds
would use clay liners. As established in the previous section on
costs, as the distance to the disposal site increases, the costs
go up dramatically. It was, therefore, assumed that the plants
would use the most economical means of disposal for the new dis-
posal facilities.
The cost data used in this study indicate that at a dis-
tance of 16.1 kilometers, the most economical disposal method is
dewatering of sludges to 60 percent solids followed by trucking
to landfill. It was, therefore, assumed that plants currently
pumping sludges to ponds would install dewatering facilities. The
cost of moving the facilities, both capital expenses and revenue
requirements, are presented below in Table 4-14.
The net cost for the scenario is the estimated cost
of compliance minus the existing costs. If all of the existing
plants are assumed to be out of compliance, the net cost increase
for RCRA is $98,150,000 (98,150,000-0) in capital investment and
$24,600,000/yr (135,300,000-110,700,000) in revenue requirements.
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TABLE 4-14
ESTIMATE OF THE COST. OF DISPOSAL FOR MOVING THE
DISPOSAL SITE FOR 16,1 KILOMETERS FROM THE PLANT COST
Material
Fly Ash
Scrubber
Sludge
Fly Ash and
Scrubber
Sludge
..Combined.
Disposal
Method
Landfill
Dewatered and Tracked
to Landfill
Dewatered and Trucked
to Landfill
Total
Investment Revenue
Capacity in Capital Requirement
(Mv) ($} C$/vr)
26,000
7,320
4,880
38,200
11,960,.000 $ 66 9 600,000
42,540,000 34,780,000
43,650,000 23,920,000
98,150,000 135,300,000
For comparative purposes, the cost of using the same
current mix of disposal methods but moved to 16.1 kilometers
from plant was estimated. For this scenario, the cost was
$467,290,000 for capital investment and $171,550,000/yr for
revenue requirements. For capital investments, this presents a
376 percent increase over the minimal cost estimate presented
above. The increase in revenue requirements was 27 percent.
Most of this difference is in expensive pumping equipment and
the cost of clay lining for the ponds.
One additional cost not included in the cost numbers is
the cost of monitoring wells. Such wells could be used to moni-
tor groondwater quality around the pond or landfill site to insure
that leachate contamination is not occurring. An estimated cost
for such monitoring is $25,000 per plant per year. This estimate
is based using 3 wells at an average depth of 100 feet. Samples
are assumed to be taken regularly (once per month) and analyzed
for major species and any trace toxic pollutants suspected as being
-138-
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present. The first year cost includes the cost of drilling the
well and any equipment associated with it. Thereafter, the cost
may decrease if the sampling interval and number of samples to
be analyzed remains the same. This additional yearly cost would
total $1,075,000 for the 43 plants. While this represents a
significant expense, the amount is rather small compared to the
overall cost of the scenario.
For reasons of estimating an impact, it is assumed that
Cl) half of the existing capacity addressed in this study would
have to move their disposal sites, and (2) all the plants are
assumed to use groundwater monitoring. Thus, the cost impact of
RCRA for existing plants is:
Capital Investment $49,075,000
Revenue Requirements 13,375,000/yr
4.2.3.3 New Plants
The estimate of the cost of RCRA. for planned or future
facilities to come on line by 1985 involved two calculations.
The first step involved estimating the cost of disposal assuming
the plants will not be affected in any way by disposal regulations
other than the current ones. In this case, the plants are
assumed to use the mix of disposal methods found for currently
planned facilities and presented in Section 4.1.2. These plants
are assumed to comply with currently proposed air quality regula-
tions as presented in Section 4.2.1.
The second step involved estimating the cost of disposal
assuming RCRA would cause the facilities to locate disposal an
average'of 8 kilometers from the plant but that the mix of dis-
posal methods would remain the same. All ponds are assumed to be
lined with 0.3 meters of clay.
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The projected increase in megawatt capacity of coal°
fired units to the year 1985 is 160,000 Mw. This figure was taken
from the Federal Energy Administration's "1976 National Energy .
Outlook."80 The average capacity was assumed to be 1,000 Mw
resulting in 160 plants covered by the projection period. It is
assumed that only 20 percent of the facilities would line ponds in
the absence of RCRA type regulations. The average distance from
plant to disposal site was assumed to remain the same as is ..
currently the case (4.8 kilometers). : ;
The projected cost of disposal for the 160,000 Mw of
capacity was calculated and is summarized below in Table 4-IS. -
It should be noted that these capacity figures cannot be summed
to yield 160,000 Mw. The distribution of plant capacity among the
disposal methods listed in Table 4-15 is based upon the percentages
of disposal practices obtained from the plant survey for planned
construction. The disposal methods listed in Table 4-15 represent
greater than 90 percent of the disposal options being considered.
Since cost estimates were not available for these minority options,
these costs (and the associated plant capacities) were ignored
in the cost figures presented in Table 4-15. Thus, the cost
estimates presented are equivalent to assuming that the disposal
costs are balanced by the utilization credits for the minority
options not considered. In any case, this assumption should intro-
duce only a small error.
The cost of disposal assuming RCEA will result in an
increase in the average disposal distance of 3.2 kilometers and
require lining of all ponds to protect groundwater was calculated.
The mix of disposal methods was assumed to be the same as the pre-
vious development. These results are presented in Table 4-16. The
higher cost of pumping sludges as compared with landfill operations
is readily seen in the case for fly ash disposal. In this develop-
ment, the capital costs associated with landfill of dry solids is
very low.
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TABLE 4-15 ESTIMATED COST FOR DISPOSAL FOR
PLANNED AND FDTDRE FACILITIES TO THE YEAR 1985
WITH NO ADDITIONAL REGULATIONS
Capacity (In Capital
Revenue
Material
Fly Ash
Scrubber Sludge
Method of Mv) of Plants Investment
Disposal Using Method ($)
Ponded (15Z solids)
Landfill
Ponded (15Z solids)
Ponded (dewatered
48,000
48,000
28,890
20,070
556,310,000
26,600,000
471,370,000
302,400,000
Requirements
($/yr)
174,020,000
104,960,000
92,280,000
90,590,000
Fly Ash and
Scrubber
Sludge
Combined
to 35Z solids)
Dewatered and 41,280
Landfilled
Ponded (15Z solids) 19,260
Ponded (dewatered 13,380
to 35Z solids)
Dewatered and 27,520
Landfilled
Total
245,270,000
476,560,000
318,090,000
303,050,000
2,699,650,000
188,120,000
138,480,000
197,810,000
161,880,000
1,148,140,000
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TABLE 4-16 ESTIMATED COST FOR DISPOSAL FOR
PLANNED AND FUTURE FACILITIES TO THE YEAR 1985
WITH RESTRICTIONS IMPOSED BY RCRA
Material
Fly Ash
Scrubber Sludge
Capacity (la
Method of Mw) of Plants
Disposal Using Method
Ponded USZ solids) 48,000
Landfill ' 48,000
Ponded (15% solids) 28,890
Ponded (dewatered 20,070
Capital
Investment
(« .
769,930,000
26,600,000
652,450,000
430,250,000
Revenue
Requirements
($/yr>. •
177,850,00
114,280.,000
142,830,000
96,420,000
Fly Ash and
Scrubber
Sludge
Combined
to 352 solids
Dewatered and 41,280
Landfilled
Ponded (15Z solids) 19,260
Ponded (dewatered 13,380
to 35Z solids)
Dewatered and 27,520
Landfilled
Total
287,820,000 235,490,000
659,690,000
440,760,000
364,250,000
3,631,750,000 1,198,700,000
141,200,000
95,700,000
194,930,000
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The estimated cost increase of RCRA for planned and
future facilities is summarized in Table 4-17. These cost can
be derived from the differences in total costs presented in
Table 4-15 and 4-16. In addition, estimated costs of groundwater
monitoring have been included in the total revenue requirement
increase resulting from RCRA.
TABLE 4-17.
ESTIMATED ADDITIONAL DISPOSAL COSTS
RESULTING FROM RCRA FOR PLANNED AND
FUTURE COAL-FIRED FACILITIES TO THE
YEAR 1985.
Estimated Disposal Cost with RCRA
Estimated Disposal Costs without
RCRA
Estimated Cost Increase of RCRA
Groundwater Monitoring Costs
Capital
Investment
($)
3,631,750,000
2,699,650,000
932,100,000
Revenue
Requirements
($/yr)
1,198,700,000
1,148,140,000
50,560,000
4,000,000
Additional Costs of RCRA Including
Monitoring
$ 932,100,000
4.2.3.4 Costs for Existing Plus New Plants
$ 54,500,000
Within the context of the stated limitations, the esti-
mate of the cost of compliance with RCRA for coal-fired electric
utilities was made by adding the cost of existing facilities to
the costs for the planned and future facilities. The capital
investment cost through the year 1985 (using mid-1979 dollars) is
$981,175,000. The annual revenue requirements are $67,935,000/yr
which includes the costs of groundwater monitoring. These costs
represent an estimate of the added expense of RCRA, that is the
cost over and above the cost of disposal in the absence of such
regulations.
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One Important factor that needs mention is the cost of
liners. Much of the analysis of compliance with RCRA is based on
the assumed need to line ponds with some impermeable .layer to slow
or prevent the intrusion of leachate into groundwater. The costs
developed here used a layer of 0.3 meters of clay. The permeability
of clay is dependent on the physical properties of the specific
type of clay and a range of permeabilities are commonly reported
CO ^ «0 ^
for clay. These are typically in the range of 10 to 10 - .cm/sec.
There are numerous liners available that can achieve this perfor-
mance, including a mixture of fly ash and scrubber sludge in some
cases. Synthetic liners such as ployethylene, polyvinyl chloride
or butyrubber, and others can achieve greater protection from
a leachate penetration standpoint. The cost of commercially avail-
able liners is rather high, however.
Using the TVA study81 as a basis for cost comparison,
the relative costs for the various liner options are presented
in Table 4-18. Note that the capital investment for the synthetic
liner costing $4.50 per square meter is some 86 percent greater
than for no liner. It is some 55 percent greater than for clay
liners while the operating costs are 77 percent greater than no
liner and 116 percent greater than for clay liners.
TABLE 4-18
RELATIVE COMPARATIVE COST OF POND LINERS51
No Liner Synthetic Liners
(Base Case) Clav. $1.5Q/m2 $4.50/m2
Relative Capital Cost 1.00 1.20 1.50 1.90
Relative Revenue 1.00 0.82 1.40 1.77
Requirements
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4.2.4 Summary of Cost Analysis
The assumptions that have the greatest effect on
the c.ost estimates are the ones concerning (1) how the plants
would comply with RCRA associated regulations, (2) what those
regulations might be, and (3) the applicability of the cost .data
for the generalized calculations made in this study. Several
important factors were not included in the analysis of the cost
of compliance. One important question is the fate of any existing
disposal facilities abandoned because of danger to groundwater.
If such facilities are forced to remove the waste materials
and recover the site, the costs would be very high. If the
facility is allowed to cover ponds or landfills and abandon them,
the impact will be limited to the costs associated with the
mature retirement of the facility.
Another important cost consideration that was not in-
cluded in the study was the cost of building a levee to protect
ponds from flooding. As the potential impact of the levee on
flood water retention is a major factor, a study must first be
conducted to determine if such structures can provide protection
while allowing passage of flood water. If levees can be- constructed
that will be in compliance with these restrictions, the cost
of construction and maintenance will be highly site dependent.
The cost estimate that was generated was based on the
approach of costing various disposal options for a "typical"
1,000 Mw coal-fired plant. These cost data were used to estimate
the cost for the entire generating capacity assumed to be affected.
This approach is in contrast to calculating the answer on a per
plant basis or per ton or cubic meter of waste material. The
cost data presented in the previous section along with the plant
design data can be used to generate these and other calculations
methods.
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In general, the cost data used to indicate that the
cost of disposal rises sharply with the distance from the plant.
Ponding is economical only at very short distances.. At greater
distances, the cost of pumping is very high. The cost of liners
-is also very important. The cost differences between clay
liners and synthetic liners may vary by 50 percent or more. .When
the capital investment is in the range of 10 to 50. million dollars
per plant, a difference of 50 percent is large..
: A summary of the cost evaluation used to estimate, .the
cost of compliance with RCRA is presented in Table 4-19. The cost
of well monitoring has been added to the revenue requirements for
the two classifications of facilities.
4.3 Alternative Disposal Technologies
The discussion of disposal methods thus far has centered
on the technologies in widest use today. The environmental impacts
and disposal costs have been linked directly to them. In this
section, alternative disposal technologies that show some potential
for disposal of the large volume of wastes generated in coal-fired
power plants are evaluated. These are mine disposal, ocean dis-
posal, and landfarming. For each method, the advantages and dis-
advantages are addressed, the regulatory restrictions are discussed
and the general cost considerations are evaluated.
4.3.1 Mine Disposal
The large number of mines in the United States represent
a considerable potential for the disposal of power plant wastes and
solid wastes in general. At this time, there are over 15,000 mines
within the United States which produce over 0.5 billion tons/year
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TABLE 4-19 SUMMARY OF ESTIMATED COST OF COMPLIANCE
(MID 1979 DOLLARS)
Capital Investment Costs ($) Revenue Requirements ($/yr)
Estimated Cost Estimated Current Estimated Cost Estimated Current or
of Compliance with Predicted of Compliance Predicted Cost - No
with RCRA Cost - No RCRA with RCRA RCRA
Existing^ 49,075,000 0 68,725,000 55,350,000
Plants
(1970-1978
Construction)
Planned and 3,631,750,000 - 2,699,650,000 1,202,700,000. 1,148,140,000
Future
Facilities
(1978-1985)
Total Costs 3,680,825,000 - 2,699,650,000 1,271,425,000 - 1,203,490,000
Net Costs 981,175,000 67,935,000
*Afiflum1nR 50% out of Compliance
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of coal and 2.5 billion tons/year of minerals. Much of this capa-
city is not suitable for mine disposal purposes.62 Any number
of reasons may be sufficient to rule out a particular mine as a
potential disposal site. The mining method, local geological
conditions and hydrology must all be considered.
4.3.1«1 Process Description . -_.__.
The two primary variables in the overall process of
mine disposal are the mine type or mining method and.the actual
waste handling method. In terms of technical feasibility, the.
following four mine types have been ranked in terms of disposal
potential:sz
• Surface coal mines,
• Underground room-and-pillar coal mines,
c Underground room-and-pillar limestone
mines, and
• Underground room-and-pillar lead/zinc mines.
This ranking was based on the estimated capacity for
sludge, ease of disposal, prevention of future resource recovery
and general proximity to sludge sources. Mine configuration and
mining methods have been found to have relatively little influ-
ence on the environmental acceptability and operational feasi-
bility of the disposal method, except as they are related to
local geology and hydrology.*9
The method of waste placement must be compatible with
ongoing mine operations where the mine is still active. Compat-
ibility with existing physical conditions must also be a consider-
ation in the case of abandoned mines. Sludge placement may be
accomplished in surface mines either in the working pit, in the
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spoil banks, or mixed in with the overburden. The exact method
chosen depends on site specific mine conditions and operational
procedures. In underground mines the primary methods available
for waste placement are hydraulic backfilling in the case of a
slurry and either mechanical or pneumatic stowing in the case of
dry wastes. r,
In the feasibility study previously mentioned49 ,
three different mine sites were evaluated for the disposal of :
FGD sludge. One potential benefit from this disposal practice
emphasized in the report was the prevention or*reduction in mine
subsidence problems associated with specific mining practices.
The three mines studies in detail were all underground coal
mines. After evaluating the physical nature of the three sites,
the specific mine configurations, and local impacts and con-
straints, the following conclusions were drawn:
"Mine disposal of lime/limestone scrubber sludge
produced from flue gas desulfurization processes
is attractive from the standpoint of providing
an environmentally acceptable disposal means.
The sludge material in combination with aggregate
also appears to be of utility in the prevention
of mine subsidence. Potential benefits are seen
in controlling acid mine drainage and preventing
mine fires both chemically and by sealing voids
in the mine fill material.
Generally, there appear to be no insurmountable
environmental obstacles to sludge disposal in
deep mines. Each potential disposal site,
however, must be investigated to determine the
hydrogeologic controls on mine-water flow, and
the location of recharge and discharge areas.
In particular, either the geohydrologic
environment must effectively contain the
sludge and its associated water or the
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formation fluids in the environment must be of
equal or poorer quality than that which is derived
from the emplaced material. .Of concern in the .
geohydrologic evaluation are existence of any
freshwater aquifers, fractures in the overburden,,
local piezometric head relations, discharge points
to surface streams, and especially the water-
solids ratio of the sludge."
r..\
4.3.1.2 Technical Considerations . - __
In evaluating the suitability of a particular mine
site for the disposal of any solid wastes, a number of specific
factors must be evaluated. The critical or limiting factor will ..
vary from site to site. The following factors are important in
evaluating any mine disposal plan:
c physiography and regional setting,
« site geology/stratigraphy,
c surface-water hydrology/quality,
• ground-water hydrology/quality,
• mine configuration,
• mine method,
• solid waste characterization (physical and
chemical), and
• waste handling/placement method.
4.3.1.3 Economics
The economic analysis of mine disposal is based on an
evaluation of alternative FGD disposal practices1*5. The
analysis is based on waste sludge from a 500-megawatt power plant
burning eastern"coal (3.0 percent sulfur, 10.0 percent ash and
0.39 kilograms coal/kwh). This plant produces 331,000 metric tons/
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year of dry sludge including ash. The sludge and ash is available
either as dry filter cake (50 percent solids), as 35 percent solids
slurry (thickener underflow), or as treated sludge. No costs are
included for sludge processing, except in the case of treated
sludge where excavation costs are included. Capital costs are
based on a 1978 completion of construction.
Disposal costs were estimated for six different mine
disposal options. The options included both treated and un-
treated sludges, and both onsite and offsite mines. The costs
for the onsite disposal of untreated sludge (or treated, soil-
like sludges) including transfer and intermediate storage ranged
from $2.20 to $3.85 per dry metric ton. This compates to $7.15
to $8.80 per dry metric ton for offsite disposal. For the disposal
of treated sludges requiring the use of ponds or impoundments,
these costs increased by $2.20 to $2.75 per metric ton to account
for excavation costs. Costs do not include site monitoring.
4.3.1.4 Assessment of Information Needs
A good background of general information exists con-
cerning the disposal of FGD wastes in mines. Much of this infor-
mation is of a theoretical nature which therefore leaves many
practical questions unanswered. More work needs to be done con-
cerning waste/mine interaction, both chemical and structural.
Additional studies should address the potential of this disposal
method on a regional basis.
4.3.2 Ocean Disposal
The ocean disposal offers little potential for disposal
of power plant wastes. From a technical standpoint it is a
feasible method for disposal, but at the current time strict
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regulations under both the Marine Protection Research Sanctuaries
Act of 197283'5* and EPA Ocean Dumping Regulations ss
tend to prohibit this method. There are many serious questions
concerning the short and long term harmful effects to benthic
communities as well as other biological communities resulting
from the dumping of large volumes of flue gas cleaning wastes.
At the present time it is unlikely that permits would be issued
for such disposal unless it can be proven that all other alter-
natives are more harmful.
While it is agreed that this method of disposal offers
little promise at this time, the process description, the
findings of several studies on the subject and the estimated
costs of disposal are addressed in this section.
4.3.2.1 Process Description
Several technological options are available for ocean
disposal. The sludge itself may be handled as a slurry or
dewatered previous to being transported. The dewatering may
be to heavy sludge (35% solids) or to a brick-like form (60-70%
solids). Transportation to the disposal site may be by pipeline
in the case of a slurry or by barge with dewatered sludges. The
disposal sites may be on the continental shelf (shallow water)
or in the deep ocean.
The nature of the sludge during and after disposal
must be considered. Dewatered sludges and slurries will dis-
perse and become diluted as they fall through the water column
during disposal operations. Brick-like treated sludges and
dewatered sludges with a sufficiently high solids content will
fall as a cohesive mass through the water until they reach the
bottom. In evaluating the option of ocean disposal for coal-
fired utility wastes, each of these factors must be considered.
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In a recent study*5 by Arthur D. Little, Inc. for the
Office of Research and Development, U.S. Environmental Protection
Agency the following four ocean dumping scenarios were chosen
for analysis:
• dispersed dumping on the continental shelf,
• conventional dumping off the continental
shelf (deep ocean),
• dispersed dumping off the continental shelf,
and
• concentrated dumping of treated sludges.
Each of these scenarios were evaluated from a purely
mechanistic approach. No consideration was given to regulations
or legal constraints.
The preferred method for ocean dumping, in the absence
of regulatory constraints, involves the use of conventional
bottom-dump barges on the continental shelf.
There are four principal categories of potential
impact for FGD sludge disposal in the ocean. These categories are:
benthic sedimentation, sludge suspended in the water column,
sulfite-rich sludge and trace contaminants. The primary poten-
tial impact of benthic sedimentation is the creation of unsuitable
habitats on the ocean bottom due to the fine-grained nature of
most sludges and the lack of acceptable nutrient levels. The
impact of the suspended sediments in the water column is estimated
to be dependent on the chemical composition of the sludge and on
feeding habits and sensitivities of fish populations. The intro-
duction of sulfite-rich sludge into the ocean environment is of
interest for two reasons. First, sulfite is measurably toxic;
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and second, it exerts an oxygen demand on surrounding waters.
There are several factors which would determine the severity of
impact from sulfite-rich sludge on the ocean environment,
including the dissolution rates of the sludge, water pH and
dilution in the area of the dump. In a similar fashion, the
impact from trace contaminants is estimated to be highly variable,
A study by the State University of New York, Stony
Brook is presently examining the use of stabilized FGD sludge
blocks to create artificial reefs for marine habitats.ss In
a two-phase study both laboratory and in-situ tests are being
conducted. The study was performed in an estuarine area but
the results have some applicability to open ocean disposal as
well. Preliminary results indicate that:
• calcium and certain other species show
rapid initial solubilization which slows
as equilibrium is reached,
• no appreciable trace metal leaching was
noted,
• sludge compressive strength increases with
increased exposure to sea water, and
• in the in-situ tests, benthic organisms
attached themselves to the submerged
blocks within two weeks of submersion.
4.3.2.2 Economics
The Arthur D. Little, Inc., study1*5 developed cost
estimates for five ocean disposal options. The five options
were:
• on-shelf disposal of untreated sludge,
• on-shelf disposal of treated, brick-like
sludge,
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• off-shelf disposal of untreated filter
cake,
• off-shelf disposal of thickener under-
flow, and
• off-shelf disposal of treated, brick-like
sludge.
An eastern power plant with ready access to the ocean
was assumed. The disposal of untreated filter cake (with ash)
on the shelf was estimated at $4.40 to $5.50 per dry metric ton
of sludge. Treated sludge requiring ponds or impoundments would
cost $2.20 to $2.75 to cover the cost of excavation. Deep ocean
(off-shelf) disposal costs $3.30 to $4.40 per dry metric ton
more than on-self disposal. Thickener underflow disposal costs
$1.10 more per metric ton than filter cake disposal. These cost
estimates do not include monitoring or sludge processing costs.
4.3.2.3 Assessment of Information Needs
While a sufficient amount of information does not
exist to justify the current restrictions as ocean disposal,
there are several information gaps that could be addressed.
Some estimates have been made concerning the chemical and
physical interactions between sea water and sludge, but infor-
mation concerning biological impacts of sludge disposal in the
ocean environment is needed. It may be necessary to propose
changes in existing ocean dumping regulations, should the
results of ongoing research indicate that ocean disposal of
power plant wastes is an acceptable method. The acceptability
argument must be taken in light of the potentially harmful
effects of land disposal as compared to ocean disposal of these
waters.
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4.3.3 Land Farming
Very little information is currently available on
the potential for landfarming, adding FGD sludges and solids
to the soil. As little or no nutrient material is available
from these wastes they are not a potential fertilizer. The
cost of spreading the material, particularly the large quantities
available, would be rather prohibitive when considering this
as a disposal option.
There may be some limited applicability as a soil
conditioner, however. Where soils tend to be too acidic, basic
fly ash material which has the opposite characteristics could
be used to neutralize the soil. High sodium soils and clays
can be stabilized to some degree with the addition of high
calcium fly ashes. In such cases the disposal costs could be
passed on to the user as opposed to the plant. The quantities
needed would not encompass the entire output, however. Such
cases would tend to be highly site specific and this method
is not believed to offer a potential for widespread use.
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5.0 UTILIZATION OF UTILITY WASTES
For coal-fired utility plants, recovery practices may
be directed toward fly ash, bottom ash and/or boiler slag and
flue gas desulfurization scrubber sludge utilization in some
form. In 1977 total U.S. production of fly ash, bottom ash and
boiler slag was 67.8 million tons with 14.0 million tons success-
fully recovered and utilized.87 This is more than three times
that used by any other world nation during the same time period.
However, this 14 x. 106 tons corresponded to only 21 percent
utilization compared with values for England and Wales of 41
percent, for France of 42 percent, and for Germany of 60 percent.
88,69,70 There are, of course, inherent differences in avail-
ability of raw materials and marketability in each country which
account for differences.
Utilization of ash is expected to continue to in-
crease in the United States as indicated in Table 5-1 with
trends dating back to 1966.s7'71 The increasing reliance on
coal as a utility fuel with attendant increases in ash produc-
tion may very well mean that the percent of utilization will
not increase, and may decrease despite efforts to promote ash
utilization through increased market visibility and technolog-
ical development. Competitive utilization of ash based upon
market development or technological improvement in recovery or
recycle methods would be desirable from both the standpoint of
total resource utilization and of reduction in the quantity of
waste requiring disposal.
The utilization of calcium sulfite/sulfate based FGD
scrubber sludge is and has been much more limited even than
that of ash. In addition, definitive data on the actual amount
of material utilized is not readily available. In effect, the
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TABLE 5-1
COMPARATIVE RESULTS
1966* 1974 1975 1976 1977
ASH COLLECTED
Fly Ash 17.1 40.4 42.3 42.8 48.5
Bottom Ash B.I 14.3 13.1 14.3 14.1
Boiler Slag 4.8 4.6 4.8 5.2
TOTAL ASH COLLECTED - TONS x 10* 25.2 59.5 60.0 61.9 67.8
ASH UTILIZED
I Fly Aah 1.4 3.4 4.5 5.7 ' 6.3
^ Bottom Ash 1.7 2.9 3.5 4.5 4.6
0° Boiler Slag 2.4 1.8 2.2 3.1
TOTAL ASH UTILIZED - TONS x 10'
PERCENT OF ASH UTILIZED
'i Fly Ash 7.9 8.4 10.6 13.3 13.0
% Bottom Ash 21.0 20.3 26.7 31.5 32.6
•/. Boiler Slag 50.0 40.0 45.8 60.0
PERCENT OF TOTAL ASH UTILIZED 12.1 14.6 16.4 20.0 20.7
* Flrsc year that data was taken.
** 1967-1973 data omitted from tabulation because of space limitation.
Source: Reference 67.
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situation with regard to scrubber sludge utilization is more
one of conceptual development and testing rather than actual wide-
spread utilization. On recent summary of conceptual developments72
listed the following possible uses for scrubber sludges: (1)
recovery of chemicals, (2) manufacture of building materials,
(3) structural fill, (4) paving materials, (5) soil stabiliza-
tion in agriculture and (6) environmental pollution control.
Among all of the concepts evaluated, it was concluded that only
the production of gypsum wallboard and the utilization of gypsum
in making Portland cement have any possibility .as a significant
outlet for scrubber sludge in the foreseeable future. This
conclusion, of course, assumes that the collection process in
the FGD system involves forced oxidation of the scrubber sludge
to gypsum with separate disposal of waste product in a manner
that allows recovery.
It can be seen, that many conceived uses of scrubber
sludge parallel uses of ash. Since ash utilization is more deve-
loped and ash is a superior product to FGD scrubber sludge in
many of these parallel uses, significant utilization of FGD wastes
is not expected when it is unlikely that the percentage utilization
of ash itself will increase. This conclusion is not to minimize
the significance of the total quantity of FGD scrubber sludge that
might be utilized in a given location where market considerations
create a need for the raw material in such processes as Portland
cement production and in wallboard manufacture.
5.1 Fly Ash Utilization Practices
Fly ash utilization practices in the United States
during 1977 are summarized in Table 5-2. The two major areas
of commercial utilization were in the partial replacement of
cement in concrete and concrete products and in the structural
landfill embankments and road construction. Lightweight
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TABLE 5-2
ASH COLLECTION AND UTILIZATION 1977
(Million Tons)
Fly Ash
Tons x 10*
O
I
1. TOTAL ASH COLLECTED
2. ASH UTILIZED
3. UTILIZATION PERCENTAGE
A. COMMERCIAL UTILIZATION
a. Mixed with raw material
before forming cement
clinker
b. Mixed with cement clinker
or mixed with cement (Type
1-P cement)
c. Partial replacement of cement
In concrete and blocks
d. Lightweight: aggregate
e. Fill material for roads
, construction sites, land
reclamation, ecology dikes, etc.
f. Stabilizer for road bases,
parking areas, etc.
g. Filler In asphalt mix
h. Ice control
1. Blast grit and roofing
granules
J. Miscellaneous
B. ASH REMOVED FROM PLANT SITES
AT NO COST TO UTILITY
C. ASH UTILIZED FROM DISPOSAL
SITES AFTER DISPOSAL COSTS
Source; Reference 67.
TIT
25
2
20
3
2
3
7
26
100
Bottom Ash
Tons x 10*
ifbl
Boiler Slag
(If sepa-
rated from
Bottom Ash
Tons x 10*
HZ
U.
3
20
22
9
17
22
122
13
48
22
A
100
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aggregate use in the United states was surprising low, 120,000
tons, accounting for only 2 percent of the total utilized. This
is in contrast to the significant use within England and Wales
of 353,000 tons or 8 percent of total utilized.58 Other uses
in the U.S. included mixing with cement or cement clinker, road'
base stabilizer, and asphalt mix filler.
5.1.1 Partial Replacement of Cement in Concrete and Concrete
Products
Fly ash used as replacement material for cement in con-
crete has been found to produce beneficial effects provided good
quality control is maintained along with specifications for the
fly ash utilized. Some of the beneficial effects are: (1) re-
duced water requirements (2) improved workability of the concrete,
(3) improved finishing qualities, (4) reduction in heat generation
during hardening reactions (5) increased strength for a given
cement composition, (6) reduction in permeability and absorption,
(2) improved resistance to chemical attack, (8) improvement in
uniformity of strength development and (9) decreased cost of
concrete manufacturer at a given quality.73 However, the
realization of some or all of these benefits rather than detri-
mental effects such as difficulty in control of air content,
slow strength grain, poor freezing and thawing resistance depend
upon attention to physical specification and quality control
regarding such factors as fineness uniformity, moisture content,
air entrainment, and composition and particle size of the fly
ash utilized.
Recently, the American Society for Testing and Mater-
ials adopted and published standard specifications (ASTM C618-77) ""*
for the use of fly ash as a pozzolan in concrete manufacture. Fly
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ashes were classified in these specifications as either derived
from burning (1) anthracite or bituminous coal or (2) lignite .
or subbituminous coal with physical and chemical requirements
given for each class. The specifications covered such parameters
as combined percentages of SiOa, A1203 and FeiOa, maximum SOj,
maximum moisture content, maximum loss on ignition, maximum MgO
content, mtf*jmm Na20, particle fineness, pozzolanic activity
index, soundness and uniformity requirements. The adoption and
acceptance of these standards should enhance this avenue for
fly ash utilization.
It is reasonable to expect an increase in use of fly
ash as an admixture in concrete production provided there is
aggressive marketing and attention to quality control. However,
a major factor in the economic competitiveness of fly ash as a
pozzolan is transportation costs. This factor may limit wide-
spread utilization in the foreseeable future to those areas of
the country where there is reasonably close proximity of plants
generating fly ash as a waste product to areas of active con-
struction utilizing significant quantities of fly ash-based
concrete. It is unlikely that fly ash transported over long
distances would be economically competitive with other available
materials.
5.1.2 Base and Subbase in Road Construction
Demand for aggregate materials in base and subbase
construction in the United States runs into billions of tons
each year.75 In some parts of the country there exists both
a shortage of suitable material and existing material on a
limited basis that is increasingly costly. A potential market
for fly ash exists in areas of the county where large amounts of
bottom ash, boiler slag or fly ash are produced and there is
a limited supply of road construction material.
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However, in spite of the fact that tests on fly ash
used in road construction have shown that it is comparable to
other aggregates in terms of structural specifications, resistance
to its use still must be overcome because of a lack of know-
ledge of its beneficial properties on the part of engineers.
There is a natural tendency to utilize experience-proven
natural aggregate where it is available even though testing has
demonstrated the validity of fly ash use. Nonetheless, more
than thirty states under the increasing pressure to find low-
cost road construction materials have developed specifications
for the use of power plant ash in new construction as well as
maintenance programs. In addition, the Federal Highway Adminis-
tration has sponsored research programs designed to increase the
use of ash in road construction.71
Even though technical utilization of fly ash for road
construction as a subbase or base material seems adequately
demonstrated, there seem to be two limiting factors to its use.
In the limited sense, transportation from a generating plant to
site use is a controlling factor. It has been found that
transportation distances of greater than 50 miles by truck or
100 miles by rail make the use of fly ash unattractive.75 In
the more general sense, there is concern over possible contamination
of water supplies by leachate that might result from water in
contact with fly ash used in road construction. Unless the fly
ash was effectively "sealed" from surface water contact by an
asphalt or concrete covering, then concern over leachate potential
will continue to exist. However, the actual threat from leaching
is not known and testing would be required to establish actual
results. Any such testing would likely be site-specific to a
high degree and would not answer questions of leachate potential
in any general sense. Despite possible limitations, the use of
fly ash in base and subbase construction is definitely expected
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Co increase and be especially significant in areas of the country
where natural aggregate materials are in low supply and coal-
fired electrical generation occurs on a large scale.
5.1.3 Cement Manufacture
Fly ash has been used in cement manufacture both by
mixing fly ash with finished Portland cement and by intergrinding
with Portland cement clinker prior to forming a finished product.
Several companies now manufacture a type I-P cement containing
fly ash. There are ASTM and Federal specifications covering
the required properties of such cements and basically permit
any suitable pozzolan (including fly ash) to be utilized along
as specifications for the final product are met. The I-P type
of cement is used for general construction purposes upon which
specifications are built. These specifications permit both
interblending or intergrinding in the manufacture of cement but
stipulate that the pozzolan constitute from 15-40 weight percent
(ASTM)77 or 15-35 weight percent (Federal) 'of the finished pro-
duct.
In addition to the above, fly ash has been and is used
in several locations as a raw material in the manufacture of
Portland cement. In most cases, the fly ash is used to compensate
for deficiencies in material composition such as alumina and
usually constitutes no more than 5-10 percent by weight of the
final product. Fly ash as a raw material is not bound by any
specifications, since specifications are applied rigorously to
the final product and the fly ash looses its physical identity
in the final product. When fly ash is used as a raw material
to provide certain chemical constituents, its use is limited by
the fly ashes variable composition particularly as it relates
to possible high values of magnesium, sulfate and alkalies.
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Limiting factors to the use of fly ash in cement manu-
facture either as a pozzolan or raw material are often the
same as those affecting fly ash use in concrete manufacture,
namely, market inpenetrability due to low confidence in a by-
product, concern over variable composition of fly ash, constancy
of supply and economic concern over transportation costs if
long distance hauling is involved. As in the case of concrete
manufacture, use should continue to increase with aggressive
marketing and acceptance of specifications provided the manu-
facture is taking place in a geographical location where
supplies are available from power plants without inhibiting
transportation costs.
5.1.4 • Lightweight Aggregate
Production of mineral aggregates in the U.S. now
amounts to more than 2 billion tons on an annual basis and all
aggregates combined constitute the largest single mined com-
modity in the United States.75 However, the supply is decreasing
and in certain areas of the country (particularly some indus-
trial or metropolitan areas) demand for natural mineral aggre-
gates for construction purposes exceeds locally available supplies
Consequently, the search has been made for substitute materials
with fly ash and bottom ash coming under both consideration and
actual use. With increasing energy costs and subsequent
costs in transportation there has been a driving force to find
suitable replacement aggregates in the local area rather than
transport over large distances. Therefore, there is definite
potential for growing use of fly ash as a lightweight aggregate
in many parts of the country where there is a coupling of
shortages and coal-fired generating plants in the same area.
There are apparently few significant technical limitations to
the use of fly ash for lightweight aggregate, and it is feasible
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that this particular application holds promise for the greater
percentage increase in fly ash utilization among all categories
of use. Possible limitations which may require further atten-
tion in the future are variable density 'among fly ash sources
and a potential for water contamination through leaching for some
applications of lightweight aggregate use.
5.1.5 Filler in Asphalt Mix
Mineral fillers have been used for some time to in-
crease the stability and durability of asphalt paving surface.
Normally the mineral filler constitutes no more than four percent
by weight.78 Materials which have been used for this purpose
include limestone dust, volcanic ash, hydrated lime, powdered
shale, Portland cement, bentonite clay, mineral sludges and
fly ash.
From a technical view point, the major limitation on
use of fly ash as a filler is its poor traction characteristics.
However, it does provide adequate overall paving characteristics
and since filler specifications allow the use of a low grade
fly ash from the standpoint of quality control, its cost is
attractive in comparison with other filler options. Consequently,
in areas where a reasonably constant supply is available from
the utility in close proximity to the point of use, a signi-
ficant outlet market for fly ash should be sustained. However,
since the use is largely seasonal and the percentage use of
filler is small, the asphalt filler market could not be an
outlet for much more than one million tons per year and would
be localized in certain areas of the country.
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5.1.6 Future Uses
Beyond the "major" outlets for power plant fly ash
mentioned above, numerous other uses have been conceptualized
or demonstrated to some degree with several deserving special
mention. In some instances, these other uses await the sur-
mounting of technical problems, and in other cases market
awareness of the feasibility and advantages of the product or
particulate use must be developed. An example of a future
potential use requiring technological breakthrough for economic
competitiveness is mineral recovery from fly ash. Much research
has been done and methods for extracting alumina, magnetite or
other minerals do exist. However, these processes are not capable
of competing with more established processes in some cases and
in others the market does not exist because of a readily
available supply of the mineral.
By the year 2000, the minerals deficit in the United
States will exceed the energy deficit; the trade deficit in
minerals may be as high $100 billion dollars witnin 25 years.79
Currently, U.S. sources for 22 of the 74 non-energy essential
minerals are almost completely dependent on foreign sources. Of
the crucial 12 elements, seven are imported in quantities greater
than 50% of our need.79 Utilization of the aluminum content of
the fly ash can completely offset bauxite imports currently.90
Zinc concentrations in the fly ash are equivalent to zinc mined
from commercial sources. In light of an impending minerals
crisis and a critical shortage of certain industrially crucial
trace elements, the presence of these constituents in fly ash
and the large amounts of fly ash available are strong reason
and justification for basic research and development of extrac-
tion processes and incentives on the state and national level
for the effective use of these constituents as a valuable
natural resource.
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A possible use, requiring market development in the
U.S., is the production of gas concrete or lightweight concrete
as a building material. Large amounts of fly ash are utilized
for this purpose in Europe where this product has become a
widely used and popular construction material. In Europe, the
material has been found to reduce construction costs by as much
as 20-30 percent over conventional brick and the use has steadily
grown in over twenty countries.78 Were this use to gain
favor in the U.S., manufacture of gas concrete could become a
major use of fly ash in the future.
Other uses providing a significant outlet for fly
ash are soil amendment, production of cenospheres and utilization
in mineral based insulation.
All of the above discussion of actual and potential
fly ash utilization assume that the material is available in an
unmixed form through dry collection-procedures such as electro-
static precipitation or mechanical collection. There is some-
what of a tendency to date to find air quality control systems
at increasing numbers of utility plants in which fly ash is
collected in large portions along with SOz in a wet scrubbing
system with limestone or lime as the sorbent material. The
resulting mixture of wet fly ash and scrubber sludge does not
have the same properties as separately collected fly ash and
could not be used in many of the applications discussed above.
If fly ash utilization is a desirable goal and proves financially
beneficial in some instances, the altering of properties
through wet collection along with SQz should be avoided.
5.2 Bottom Ash Utilization Practices
In many instances, bottom ash can be used in a parallel
fashion to fly ash. There are general similarities to con-
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stituents on a chemical basis, but chere are significant dif-
ferences in composition on. the basis of those constituents.
In addition, there are significant differences in particle
morphology and physical characteristics. For example, fly ash
is typically a fine material of glassy spheres, whereas bottom
ash 'Is typically a more coarse material of a cinder-like nature.
Therefore, some of the uses are significantly different from
those of the fly ash.
In addition to the bottom ash obtained from dry boiler
operations, boiler slag is another distinctive mineral byproduct
of combustion resulting from wet boiler operations. The uses
of bottom ash and boiler slag overlap to a large extent, and
consequently, their uses will be considered together. On a
percentage basis the utilization of bottom ash and boiler slag
exceed that of fly ash. This is shown in Table 5-2 for utili-
zation of ash for 1977.S7 However, it must be realized that
the uses of bottom ash and boiler slag have been limited in
nature. The significantly lower quantities of bottom ash and
boiler slag being produced result in a higher percentage of
utilization than fly ash rather than more extensive outlets
for these materials over fly ash.
5.2.1 Use in Manufacture of Cement
Bottom ash finds some use as a mineral filler in the
manufacture of cement. In actuality, the bottom ash is used
as a raw material in the production of cement clinker and as a
means of providing required mineral mass balance. In 1974, this
particular use amounted to less than one million tons 7l, but this
outlet is still one of the major utilizations of bottom ash in
the United States.
Bottom ash as a raw material ingredient in cement manu-
facture parallels the advantages and disadvantages given for
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fly ash used in this manner, because both serve as an extender
for mineral constituents. The market for this use should not
only be sustainable in the future, but should see growth with
a corresponding increase in all types of construction.
5.2.2 Lightweight Aggregate and Aggregate in Road Construction
The growth in use of lightweight aggregates (a
doubling of use is expected in the next 10 to 20 years) and the
shortages expected to occur in certain urban areas has been
mentioned in the section above on use of fly ash as lightweight
aggregate.
Bottom ash has found use as a lightweight aggregate
in construction needs and has been utilized as an aggregate
(gravel) material in road base construction. Extensive testing
has been done on the physical and structural characteristics
of bottom ash and boiler slag for various purposes in road
construction.81 This has included use for nonstabilized bases,
stabilized bases (either Portland cement or bituminous stabilized),
bituminous paving mixtures and underdrain filter material. It
has been generally concluded that bottom ash and slag can provide
properties comparable to those resulting from natural aggre-
gates, but that the specifications developed for the use of
material aggregates require modification to achieve the best
results when using power plant aggregates. With modification,
performance of the power plant aggregates in road construction
can equal or exceed that found for natural aggregates.
As in the case of fly ash, the increasing acceptance
of bottom ash and boiler slag as aggregate materials and the
development of appropriate specification for their particular
unique properties will provide an outlet in those areas of the
country where large amounts of coal-fired wastes are being
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produced. Fortuitously, a number of urban areas expected to
have shortages of natural aggregates are located in regions of
the country where large amounts of power plant aggregate are
being produced. The proximity should reduce transportation
costs to the point where the ash products are economically
attractive. Consequently, aggregate use represents one of the
better alternatives for increasing.utilization in the future.
5,2.3 Filler in Asphalt Mix
Both bottom ash and boiler slag have been used in
asphaltic concrete for paving purposes, although boiler slag
has a more extensive history of such use. Boiler slag received
considerable promotion after World War II as a desirable
surfacing aggregate under the trade name of "Black Beauty"
with the heaviest use coming in the midwestern United States.92
Even though more extensive quantitative data is needed, asphaltic
surfaces with boiler slag as an aggregate poses anti-skid pro-
perties as compared to such a natural aggregate as limestone
sand.
Bottom ash in asphaltic paving has been most extensively
used in West Virginia where since 1972, dry bottom ash has
been cold mixed with emulsified asphalt and used to pave rural
secondary roads.81 The performance of such surfaces has been
reported as favorable to this point, with good experience also
being reported in supply of the materials from the power plants
involved. In addition-, extensive testing of bottom ash and
boiler slag for asphaltic surface production has been conducted
at West Virginia University. That testing clearly established
the feasibility of both materials in asphalt mix provided
specifications are modified to accomodate the unique nature
these by-products. Additional laboratory and field testing
should be conducted with bottom ash and slag from the burning of
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subbituminous and lignite coals because the bulk of experience
has been obtained with eastern bituminous coals. However, the
West Virginia results have paved the way for acceptance of
this use and there is no reason why this market cannot be
successfully developed.
5.2.4 Abrasive Material for Skid Control Under Snow or
Icing Conditions on Roads
Because bottom ash is a cinder-like material with angular
particles, it has found rather extensive use by highway and
road departments to improve traction as a gut material on icy
roads and bridges. In fact, several plants gave away bottom ash
at no cost to highway or city road departments for the purpose
of skid control at a number of locations. As natural aggregates
become less available and more expensive, it is likely that
power plant bottom ash and boiler slag will become more attractive
because of their excellent traction properties, and utilities
will be able to move beyond "give-away" of this product to
active sale.
There is no major technical limitation for this use of
bottom ash. As it gains acceptance by engineers and as natural
aggregate use becomes less attractive, this outlet will grow
where power plants are advantageously situated and can guarantee
constant and adequate supply during crucial periods of need.
5.2.5 Other Uses
A growing interest is apparent at present in the use
of boiler slag grit material in cleaning - blasting replacing
sand. This interest is not just a matter of unavailability of
sand or other commonly used material, but there are apparently
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tangible technical advantages for boiler slag based upon its
properties. Bottom ash has been used to control mine subsidence,
to neutralize and abate acid mine drainage, and as a structural
fill material particularly in enbankment areas where drainage
is a problem.
Parallel to the case with fly ash, both bottom ash and
boiler slag are candidate precursor materials for mineral
extraction or trace element extraction. The demand for this use,
the technical limitations, the potential for future development
and the need for incentives are identical to those points dis-
cussed earlier in regard to fly ash.
5.3 Utilization of FGD on Scrubber Sludge
The basic overview of potential uses of FGD sludge and
actual practices has already been given at the beginning of the
discussion on waste utilization. Actual use at the present time
is nil and no widespread efforts are being made to develop
utilization. There is active interest in some recovery possibilities
such as the production of elemental sulfur. However, that part-
icular potential is one awaiting research and development that
will lead to a process that is economically competitive with more
conventional sulfur production processes. The production of
sulfur and sulfuric acid will be discussed in Section 5.5.
As more FGD systems begin to utilize stabilization
procedures with landfill of sludge, the modified and stabilized
sludge might find an outlet for use in structural fills and
enbankments. Often, the stabilized sludge contains significant
amounts of fly ash either as a result of the stabilization
process or through mixing of stabilized sludge and fly ash at
disposal. The structural properties of stabilized sludge are
such that it would frequently be advantageous for landfill
involving landscaping architecture or strip mine reclamation.
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5.4 Factors Limiting Waste Utilization
A survey of current utilization of by-product material
from flue gas cleaning processes at coal-fired utility plants
indicates that there are at least three areas of resistance or
limitation to their 'increased use. These areas -are (1) technical
limitations in comparison to alternative materials, (2) insti-
tutional barriers related to poor understanding of the by-
products and failure to develop markets by either the utility
industry or user industries, and (3) possible environmental con-
cerns related to some uses.
When one considers the growing volume of waste material
that must be dealt with in an economically and environmentally
satisfactory manner, removing or reducing these barriers becomes
a high priority item. In some instances, technical limitations
preclude further significant progress for a given application,
but in other cases basic research and development will surmount
obstacles. The most damaging barriers are apparently human and
corporate, but seemingly can be overcome by concerted efforts.
Utility companies have previously been concerned primarily with
the production of electricity. Marketing of waste by-products
has been secondary. Wastes have been viewed as a nuisance and
liability rather than as a potential asset to be sold and produced
along with electricity. Not only must the utility companies
envision the importance of marketing their waste products, but
they must aggressively develop markets with the educational pro-
cess being a key role in overcoming the reluctance on the part
of many users to use a waste product because of fears involving
chemical and physical variability of the material, lack of
specifications for its use in their manufacturing processes, and
fear of a lack of constant supply depending upon the vagaries of
plant operation. Once a market is developed, plant operations
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must be geared to accommodate the customer using the waste
product and provide maximum cooperation in regard to access to
waste facilities of loading and transportation and cooperative
efforts in monitoring quality control..
Finally, for those uses where a potential environmental
concern exists, policy decisions based upon the relative merits
of use in a particular application compared to the environmental
impact of landfilling or ponding must be made so that a climate
of uncertainty regarding future regulations does not exert an
inhibiting effect on use.
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5.5 Regenerable FGD Processes
This section will discuss regenerable FGD processes
and the possible impact that this technology could have on the
quantity and type of waste produced through flue gas cleaning
associated with coal-fired electrical generation. Regenerable
processes combine absorption of S02 by a suitable alkaline
reagent system with a second step which regenerates the sorbent
material and produces a by-product such as sulfuric acid or
elemental sulfur. In comparison, the more widely used wet
scrubbing systems throw away any solid waste produced. The
previous examination of the use of calcium sulfate/sulfite
scrubber sludge led to the conclusion that the beneficial
utilization was limited in the immediate future with no large
scale use at the present time.
In essence, the regenerable processes described here
replace large volumes of scrubber sludge with an alternative
by-product (HjSO* or S). Given the limited utilization of
scrubber sludge, the comparison of throw-away systems with
regenerable processes must be made not only between the eco-
nomics of operating the systems, but the overall product pro-
cessing from regenerable processes, and specifically, the
potential market for by-products.
A brief description of selected regenerable processes
will be given for those processes which have the most success-
ful operating history. The following five processes have been
considered as they have or soon will be demonstrated and tested
on a coal-fired boiler of 50 megawatts rating or higher.
• WeiIman-Lord
• Magnesium Oxide Slurry Adsorption
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'• Aqueous Absorption with Citrate Buffering
• Integrated Cat-Ox Process
• Aqueous Carbonate Process
Following the discussion of these demonstrated systems,
selected "advanced" technology processes which might improve
the state-of-the-art of regenerable process technology will be
identified.
Reduction of disposal waste volume is a major driving
force for regenerable processes. In part, the advantage of a
regenerable process is dependent upon this waste reduction, i.e.
a marketable by-product taking the place of a throwaway product.
The combination of growth in coal-fired capacity and more strin-
gent environmental standards will lead to very large increases
in total waste (both ash and FGD scrubber sludge) to be managed
through the balance of the century. It has been estimated,83 for
example, based upon current S02 emission standards, that if all
new units install nonregenerable FGD systems, that the wastes
produced from those plants will be approximately 20 million dry
tons annually (ash and FGD sludge) by 1980 with nearly one-half
being ash. This compares with the approximately 3 million tons
of dry FGD sludge being produced .at 1977 levels. The total wastes
would grow to be about 80 million dry tons in 1990 and 155 million
tons by 1998 if nonregenerable systems are utilized. Also, the
total waste volume would conservatively be doubled from these dry
amounts if 50 percent moisture in the wastes is assumed.
Use of regenerable FGD systems can substantially reduce
the volume of sludge produced even though total wastes (because
of ash) will still be high. Again, with current emission stan-
dards, it has been estimated83 that if half the new units install
regenerable systems and one-half lime/lime stone throwaway systems,
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then the total waste volume in 1990 would be 60 million tons
(dry) rather than the 80 million given above with approximately
40 million tons of the waste being ash. The total quantity of
waste still represents a significant technological challenge for
proper disposal environmentally or from the standpoint of new
developments in waste product utilization. Nonetheless, the
impact of regenerable systems is seen by the estimated 20 million
ton reduction in FGD sludge produced by the installation of re-
generable systems in only one-half the units between the present
and 1990.
Beyond reduction in the amount of FGD waste, regenerable
processes must ultimately be demonstrated as advantageous from the
standpoint of the following factors which will be discussed in
the final section dealing with the possible impact of regenerable
processes:
• Waste streams which are produced in regenerable
systems and requiring disposal
• Immediate and longer-range marketability of
possible by-products (H2SOi» or S)
• Feasibility of stockpiling by-products such
as elemental sulfur in'anticipation of a
future market
5.5.1 Wellman-Lord
The Wellman-Lord recovery process coupled with the
Allied Chemical SOz to S process has been in operation since
June, 1977, at Northern Indiana Public Service, Dean H. Mitchell
Plant with 115 Mw capacity. Performance testing was completed
prior to June, 1977. Actual performance data during a 12-day
acceptance test period revealed (1) 91 percent removal efficiency
for S02, (2) particulate emissions of 0.04 lbs/106 Btu, and (3)
production of a sulfur product of 99.9 percent purity.
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The Wellman-Lord process is based upon the reaction of
a sodium sulfite solution with SOz to produce sodium bisulfite.
Fly ash and chlorides are removed separately and prior to S02
scrubbing. Some sodium sulfate is produced in the process and
must be purged in the regeneration process before recovered
Na2S03 is returned to the absorber. Thermal regeneration in an
evaporator to produce Na2S03, water and a concentrated stream
of SO2 is used. The S02 stream can be used to produce either
sulfuric acid or elemental sulfur.
5.5.2 Magnesium Oxide Slurry Adsorption
The magnesium oxide process has been in operation
since September, 1975, at Philadelphia Electric's Eddystone
No. 1A Plant with a generating capacity of 120 Mw. In this
particular operation, performance testing demonstrated S02
removal efficiencies exceeding 95 percent. A 98 percent H2SO<»
product was produced along with regenerated MgO to be used in
the absorption process. The H2SO<» product was marketable.
Unit reliability was disappointing during performance testing
with cumulative availability being only 32 percent with a
longest continuous run of 140 hours.
A wet scrubbing system composed of an aqueous slurry
of magnesium oxide sorbs S02 to produce magnesium sulfite. The
slurry is dried and calcined to regenerate the MgO and produce
an S02 stream. Fly ash and chlorides are removed upstream to
avoid contamination of the regenerative process. When used for
scrubbing with utility boilers, the process is fairly mechanically
complex which has contributed to maintenance problems and low
availability.
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5.5.3 Aqueous Absorption with Citrate Buffering
The citrate buffered absorption process was developed
by the Bureau of Mines for industrial boiler applications with
Bureau of Mines operation on a 1,000 scfm pilot unit on a lead
sintering furnace tail gas for a 2-year period. An EPA/Bureau
of Mines co-sponsored demonstration unit is scheduled to begin
operation in 1978 involving a coal-fired utility unit.
In this process, flue gas is cleaned prior to SO2
absorption to remove fly ash and chlorides. The aqueous stream
carrying absorbed S02 is transported to a regenerator where it
is converted to elemental sulfur by the reaction: SOa + 2H2S t
3S 4- 2HzO. The HzS for this regeneration reaction can be pro-
duced by reacting two thirds of the sulfur produced with a
reducing gas.
5.5.4 Integrated Cat-Ox Process
This particular regenerable process was tested exten-
sively during a demonstration program in which the Cat-Ox system
was retrofitted to the Unit No. 4 boiler at the Illinois Power
Company's Wood River Station. The Cat-Ox process utilizes cata-
lytic oxidation of SOa to SOs using vanadium pentoxide catalyst
in a bed fixed arrangement. The S02 is then passed into a 75 to
80 percent sulfuric acid stream for absorption.
An upstream electrostatic precipitator operated at
850° to 900° (400° to 500°F above normal) removes particulates
and the heated flue gas passes across the vanadium pentoxide
bed where S02 is converted to S03 with 95 to 99 percent effi-
ciency. Even though several operational problems were encoun-
tered at the Wood River Plant, the problems should be solvable
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by design and construction changes since the components of the
process have been successfully tested. The process is not com-
plex and has low raw material and utility requirements among
demonstrated regenerable processes. However, the developer
seems to have discontinued marketing of the process.
5.5.5 Aqueous Carbonate Process
A 100 Mw FGD demonstration plant using the aqueous
carbonate process is under program planning sponsored jointly
by the Empire State Electric Energy Research Corporation and
EPA. The particular process is the one developed by Atomics
International and uses an aqueous solution of sodium carbonate
to remove S02 in a spray dryer scrubber. The process produces
elemental sulfur as a by-product utilizing solid carbon as the
reducing agent.
Even though a detailed history of demonstration does
not exist in this country the basic process has been evaluated
in detail for large coal-fired generating plants (500 and 1000
Mw) in terms of capital investment and operating costs and the
process holds promise an an advanced regenerable FGD process.
5.5.6 Advanced Technology Processes
The regenerable processes described above while having
a degree of demonstrated success do have additional technological
problems to be improved upon or overcome. Beyond reliability
and efficiency in S02 removal, the systems require the maximum
mechanical and chemical simplicity possible, retrofit capability,
scale-up potential, load following capability and sub-process
separability. In addition, the economics of operation, particu-
larly raw material requirements and utility (energy) requirements
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for the regeneration step, must be competitive with the
non-regenerable processes which are currently in more wide-
spread use.
The following selected processes are new technologies
which might improve upon existing technologies.
• Aqueous Adsorption/Steam Stripping to
produce Concentrated S02 Stream.
• Reduction Processes for Producing Sulfur
from SO2
• Direct Reduction of Sodium Sulfur Oxides
• Advanced Technology Involving Forced
Oxidation in Throw-Away Systems
5.5.7 Economic Comparison of Regenerable Processes with Wet
Scrubbing Lime/Limestone Throwaway Systems
One important factor governing the advantages of regen-
erable processes in comparison to the more widely used throwaway
systems is cost, both in terms of initial capital investment and
also in terms of annual operating expenses. In computing the cost
factor for a regenerable process, a revenue figure for by-product
sale is normally credited against the costs of collection and dis-
posal. This assumes, of course, that a market for the product
exists and that the product is of a quality to be sold as comparable
in nature to the same product from more established sources. This
may not be a valid assumption as will be discussed later, but such
revenue credits are normally assumed in computing costs for regen-
erable processes.
-182-
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Table 5-3 gives a comparison of both capital costs and
annualized operating costs for a selected group of regenerable
processes and also for limestone scrubbing. Disposal costs have
been included in the limestone scrubbing case while a credit for
product sale has been given to the regenerable processes. The
comparisons are for the same base case. Both the source of the
information and base case assumptions are given. While projec-
tions of costs are not without areas of uncertainty, the data
does illustrate that regenerable processes in many instances are
competitive economically with limestone scrubbing. As is the
case with nearly any developing technology, these processes have
met with varying degrees of success in terms of system reliability
and on line availability. In most cases the technical base exists
to "de-bug" the systems and overcome chemical and mechanical prob-
lems provided an incentive exists.
If technical problems are surmountable and costs are
roughly comparable, then the decision "for" or "against" regener-
able processes must be made on the basis of total by-product
utilization and the feasibility of marketing both bottom ash and
fly ash as well as sulfur or sulfuric acid as a by-product of
regeneration.
5.5.8 Possible Impact of Regenerable Processes
It has been reported8* that between the present and
1990, coal-fired electrical generating capacity will expand by
at least 120,000 Mw, through approximately 250 new units con-
suming 360 million tons of coal annually. The necessity of
meeting air quality standards (1978) on the coal-fired plants
will add a. very significant increment to cost of generation.
The additional cost is estimated to average 40 percent of new
unit capital costs for control of all pollutants and an annual
-183-
-------
TABLE 5-3
COMPARISON OF CAPITAL INVESTMENT AND OPERATING COSTS FOR
FGD SYSTEMS 500 MW COAL-FIRED GENERATING PLANT*
Annualized Operating
Capital Costs Costs
($/kw) (mills/kwh)
1. Limestone Scrubbing 96 4.27
2. Double Alkali 102 4.64
3. MgO 104 4.26
4. Wellman-Lord 113 5.89
l_i
oo Generating Plant, 90% S02 removal, 35 wt % sulfur coal (dry)
i Source: Reference 85
-------
operation and maintenance cost increment of 100 percent while
creating a heating rate penalty of 15 percent. For the entire
U.S. utility industry, these additional control requirements
add 60 billion to capital costs, one billion in annual opera-
ting costs and require that an additional 50 million tons of
coal be burned annually in the time period. These estimstres
dramatically reveal the fact that even moderate improvements
in costs and technological efficiencies of pollution control
systems (e.g. - regenerable processes) translate into the bil-
lion dollar economic scale.
In terms of waste volume, the combination of growth
in coal-fired capacity and more stringent environmental stan-
dards will lead to very large increases in total waste (both ash
and FGD scrubber sludge) to be managed through the balance of
the century. It has been estimated,83 for example, based upon
current S02 emission standards that if all new units install
nonregenerable FGD systems, that the wastes produced from those
plants will be approximately 20 million dry tons annually (ash
and FGD sludge) by 1980 with nearly one-half being ash. This
compares with the approximately 3 million tons of dry FGD sludge
being produced at 1977 levels. The total wastes would grow to
be about 80 million dry tons' in 1990 and 155 million tons by
1998 if nonregenerable systems are utilized. Also, the total
waste volume would conservatively be doubled from these dry
amounts if 50 percent moisture in the wastes is assumed.
Use of regenerable FGD systems can substantially
reduce the volume of sludge produced even though total wastes
(because of ash) will still be high. Again, with current emis-
sion standards, it has been estimated82 that if one-half the new
units install regenerable systems and one-half lime/limestone
throwaway systems, then the total waste volume in 1990 would be
-185-
-------
60 million tons (dry) rather than the 80 million given above
with approximately 40 million tons of the waste being ash. The
total quantity of waste still represents a significant techno-
logical challenge for both proper disposal and for waste product
utilization. Nonetheless, the impact of regenerable systems is
seen by the estimated 20 million ton reduction in FGD sludge
produced by the installation of regenerable systems in only one-
half the units between the present and 1990.
Generally speaking, regenerable processes are designed
in such a way that fly ash must be removed from the flue gas prior
to process of S02 removal and regeneration. Consequently, fly
ash and bottom ash are collected separately and may be maintained
as separate products from the by-product of regeneration. There-
fore, all products are potentially marketable on a segregated
basis which may be a distinct advantage. In addition, since
scrubber sludge is essentially eliminated, fly ash which might
be needed to stabilize sludge can now be marketed. In the
future, it may be necessary to utilize greater and greater
amounts of potentially saleable fly ash to stabilize scrubber
sludge if throwaway processes are being used. Therefore, it is
possible that one resultant advantage of regenerable processes
would be that more fly ash could be utilized in a direct fashion
rather than being used to stabilize FGD scrubber waste.
Beyond the need of regenerable processes to demonstrate
technical and economic competitiveness with throwaway FGD systems,
there are other limitations to be considered. As regenerable
processes undergo further development it is likely that a pre-
scrubber system (prior to SOz removal) will be necessary to
remove certain chemical species from the flue gas which would
interfere in the regeneration step with by-product manufacture.
-186-
-------
If such species, for example, as chloride are not removed they
ultimately would become a contaminant to a sulfur or sulfuric
acid by-product stream. The waste from such a prescrubber system
must also be disposed of in an environmentally, acceptable manner,
and although it would be a smaller stream (probably on the order
of five to ten percent as large as a typical wet scrubbing F6D
stream) it will also be expected to contain more soluble species
than a typical calcium sulfate/sulfite F6D stream. Consequently,
the prescrubber waste system must be considered as a significant
limitation on regenerable processes even though it represents
a smaller quantity. Research will be required to determine the
impact of this waste.
Perhaps, the single most significant limitation on
regenerable processes taken as a whole, is the finiteness of
markets for both sulfur and sulfuric acid as by-products. The
ability to sell by-products at a competitive price is obviously
a crucial principle in the desirability and feasibility of any
regenerable process. Beyond certain specific locations where
a local market may appear to exist, there does not appear to be
a sufficient market in the immediate future for the sulfur or
sulfuric acid that would be produced if all of the current units
equipped with throwaway FGD systems were replaced with a regener-
able process. This can be illustrated in the case of sulfuric
acid.
Projections indicate that the United States consumption
of sulfuric acid will be about 43 million tons86 by 1980 and that
existing technology for its production can meet this need. There
are approximately 100 producers now at 200 locations. In an
earlier section, two base case electrical generating plants were
designed. Both were for 1000 Mw coal-fired generating plants
with 80 percent on-stream plant factors and 35 percent thermal
-187-
-------
efficiency. The amount of sulfuric acid chat could be produced
each year for each plant was calculated assuming that both could
be operated at 90 percent efficiency for S02 collection and at
90 percent efficiency for conversion of S02 to sulfuric acid by-
product. Case 1 assumed the burning of an eastern bituminous
coal (11,000 Btu/lb heating value and 3% sulfur with 95% of ,S
emitted as SOz) and Case 2 the burning of a western sub-bitumi-
nous coal (9,000 Btu/lb heating value and 0.80% sulfur with 95%
of S emitted as SOz). The amounts of sulfuric acid produced
annually under each case with the assumptions given above were: •
Case 1 - 220,000 tons annually
Case 2 - 72,000 tons annually
For Case 1, the 220,000 tons of H2SC% produced repre-
sents 0.5 percent of the expected 1980 consumption of HzSCs and
the 72,000 tons for Case 2 represents 0.17 percent of that total.
It has been estimated that coal-fired capacity will increase by
120,000 Mw between the present and 1990. If all new capacity
involved S02 removal by regenerable processes producing H2SOi»
with conditions approximating those above, then the HzSOu
produced under Case 1 conditions would be 26,400,000 tons and
8,640,000 tons under Case 2. These amounts would represent 61.3
percent and 20.1 percent of the 1980 H2SOi» consumption. While
it is expected that a growth in HzSOi, consumption will occur
between 1980 and 1990, the above amounts indicate that total
conversion of a coal-fired capacity to H2SOi» producing regener-
able processes would have the effect of producing approximately
40 percent of the total consumed for a rough average.
Because existing sources of H2SOu production are
expected to keep pace with needs through 1990, it is probable
that the marketing of power plant by-product H2SO-+ will be
-188-
-------
highly site-specific. There will undoubtedly be situations
where some utility plants will find a strong local market for
by-product HzSO* because existing manufacturers are not supplying
a given local need. In other instances, it is likely that the
market would be saturated, thus making penetration difficult.
Production of sulfur and sulfuric acid must be con-
sidered as interrelated. Approximately 81 percent of H2SO^ is
produced with elemental sulfur as the raw material. Sulfur also
has large outlets for use in diesel fuel treatment, fertilizers,
hydrotreating, insecticides and as a vulcanizing agent in rubber
manufacture. Presently, most U.S. sulfur is mined by the Frasch
process from .underground deposits along the Gulf Coast. It is
expected that these deposits will be largely depleted by the end
of the century. Therefore, beyond 1980, it is expected that
sulfur from the burning of fossil fuels or extracted from large
deposits of gypsum will be looked to as primary sources. Because
of the importance of HzSO* and hence sulfur to the U.S. economy,
it is possible that the marketability of by-product sulfur or
sulfuric acid from regenerable SOz removal processes could become
considerably enhanced. Therefore, stockpiling might be one
alternative for utilities which could not find an immediate mar-
ket outlet for by-product sulfur. Stockpiling of sulfuric acid
is not considered highly likely because of technical problems,
but stockpiling of elemental sulfur would be feasible if incen-
tives existed. Based upon realistic needs by the end of the
century, stockpiling "of elemental sulfur produced in a regener-
able FGD process on coal-fired electrical generating plants could
very well be in the national interest. Governmental policy might
be needed to create an incentive for the utilities to handle S02
emissions in such a manner.
-189-
-------
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75. Collins, Robert J. Waste Products as a Potential Replace-
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APPENDIX A
INVENTORIED COAL-FIRED CAPACITY
BY STATE FOR 1976
(Includes some units which may have been
under construction and some which, while equipped
to burn coal, had little or
no coal consumption.)
-198-
-------
State
Alabama
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
EPA
Begion
17
IX
71
IX
Till
I
HI
District of Columbia III
Florida
Georgia
Idaho
Illinois
XxedlAOA
Iowa
Kansas
Kentucky
Tiffiij § ^ qns
Main*
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Haapshire
Hew Jersey
Hew Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Shade Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
0. S. TOTAL
Inventoried
for 1976
17
17
X
7
7
711
711
17
-71
I
IZZ
I
7
7
17
711
Till
711
IX
I
11
71
11
17
Till
7
71
X
111
I
17
Tin
17
71
Till
I
III
X
III
V
VIII
Ho. Plant*
With Coal-
Fired Units
10
3
0
0
8
0
2
0
6
10
0
26
27
22
8
16
0
0
3
4
27
16
0
16
3
3
2
1
6
3
10
13
6
33
0
0
32
2
9
6
3
2
5
0
9
1
12
20
3
399
Total Plant
Capacity
(WO
7991.02
2334
0
0
2319.73
0
439.3
0
4703.7
8138.9
0
17.131.46
11.790.21
3200.38
2631.4
6333.1
0
0
4343.3
2692.12
12.299.03
2773.93
0
8733.19
939.54
938
1910
306
4470.94
2872.2
2967.15
11.711
1205.5
23.692.61
0
0
20.133.82
242.88
3870.94
542.9
10.090.4
2300
923.65
0
6618.12
1329.3
12.023.45
5510.55
3046.36
216,349.02
Total Coal-
Fired Capacity
(MO
7975.74
2441
0
0
2514.25
0
439.5
0
3992.3
7773.2
0
16,033.56
11.358.85
3077.32
2157.4
6431.1
0
0
3353
2642.39
11,038.45
2747.95
0
8092.04
939.54
938
1910
459
3373.71
2872.2
2960.23
10,905
1205.5
22,203.34
0
0 .
13,027.62
194.5
2983.46
542.9
10,090.4
2300
923.65
0
5629.82
1329.3
12,004.36
5250.45
3045.36
202,379.39
Average Coal-
Fired Capacity
per Plant
(MO
797.37
813.67
0
0
314.28
0
229.73
0
665.47
777.52
0
616.67
428.11
139.38
269.68
. 401.94
0
0
670.6
660.6
408.83
171.73
0
505.73
313.18
312.67
955
459
562.29
957.4
296.03
838.85
200.92
634.38
0
0
563.36
97.23
90.5
1261.3
1150
134.73
0
625.54
1329.8
1000.41
262.52
609.07
507.22
-199-
-------
APPENDIX B
SIZE DISTRIBUTION OF COAL-FIRED CAPACITY
BY STATE FOR 1976
(Includes some units which may have been
under construction and some which, while equipped
to burn coal, had little or
no coal consumption.)
-200-
-------
No. of Planes with Given
Coal-fired Capacity per Plant
State
Alabama
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
District of Columbia
Florida
Georgia
Idaho
Illinois
T™rf< mv,m
Iowa
Kansas
Kentucky
T^wi4 a4 Mfll
Main*
Maryland
MassArhiiff^fttfl
^TMgl^
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
Hew Hampshire
New Jersey
New Mexico
Hew Tork
forth Carolina
North Dakota
Ohio
Oklahona
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
U. S. TOTAL
Inventoried
for 1976
EPA
Region
17
IX
71
IX
Till
I
in
HI
17
17
X
7
7
Ttt
7K
17
71
I
III
I
7
7
17
Tit
7ZZZ
TIT
DC
I
II
71
II
17
Tin
7
71
X
III
I
IV
Till
17
71
VIII
I
III
X
III
V
VIII
with Coal-
Fired Units
10
3
0
0
a
0
2
0
6
10
0
26
27
22
8
16
0
0
3
4
27
16
0
16
3
3
2
1
6
3
10
U
6
33
0
0
32
2
9
6
8
2
3
0
9
1
12
20
5
399
<100
MH
2
1
0
0
3
0
0
0
1
1
0
3
8
12
3
4
0
0
0
1
. 11
8
0
4
1
0
0
0
0
1
2
0
2
9
0
0
S
1
1
3
0
0
2
0
1
0
0
7
2
101
100-499
ME
2
1
0
0
3
0
2
0
1
4
0
10
a
9
3
7
0
0
2
I
9
7
0
4
1
2
1
1
3
0
6
7
3
11
0
0
17
1
7
1
1
0
3
0
4
0
5
10
0
157
300-999
MH
2
0
0
0
2
0
0
0
2
2
0
6
8
0
2
4
0
0
1
1
4
1
0
7
1
1
0
0
2
1
2
2
1
6
0
0
3
0 .
1
0
3
0
0
0
2
0
1
2
_2
72
1000-1999
MH
4
0
0
0
0
0
0
0
2
2
0
7
3
1
0
1
0
0
2
1
2
0
0
0
0
0
1
0
1
0
0
2
0
7
0
0
7
0
0
0
3
2
0
0
2
1
4
1
^•B
37
>2000
"" MH
0
1
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
1
0
0
1
0
0
0
0
0
1
0
2
0
2
0
0
0
0
0
0
1
0
0
0
0
0
2
0
JJ
12
-201-
-------
APPENDIX C
INVENTORIED COAL-FIRED CAPACITY
BY EPA REGION, STATE AND PLANT FOR 1976
(Includes some units which may have been
under construction and some which, while equipped
to burn coal, had little or
no coal consumption.)
-202-
-------
EPA REGION I
(Connecticut, Maine, Massachusetts,
New Hampshire, Rhode Island, Vermont)
-203-
-------
STATE: Connecticut
TOTAL
TOTAL COAL-FIBZD
PLANT CAPACITY CAPACITY
NAME OWNER(S) (MW) (MW)
No coal-fired capacity
-204-
-------
STATE: Maine
TOTAL
TOTAL COAL-FIBED
PLANT CAPACITY CAPACITY
NAME OWNER(S) . (MW) (MW)
No coal-fired capacity.
-205-
-------
STATE: Massachusetts
TOTAL
TOTAL COAL-FIRED
PLANT
NAME
Riverside
Brayton Point
Salem Harbor
West Springfield
OWNER(S)
Holyoke Water Power Co.
New England Power Co.
New England Power Co.
Western Mass. Electric Co.
CAPACITY
(MW)
47.39
1611.25
805.25
228.23
CAPACITY
(Mff)
27. 251
1600.25
805.25
209.64
1 Riverside Plant has 2 700 Ib. coal boilers and 2 200 Ib. oil boilers on a
single low pressure header to produce low pressure steam. Electricity is
generated only in the winter.
-206-
-------
STATE: New Hampshire
TOTAL
TOTAL COAL-FIRED
PLANT CAPACITY CAPACITY
NAME OWNES(S) (MW) (MW)
Merrlmack Public Service Co. of N. H. 506 459
-207-
-------
STATE: Rhode Island
TOTAL
TOTAL COAL-FIRED
PLANT CAPACITY CAPACITY
SAME OWNER(S) (MW) (MW)
Manchester Street Narragansett Electric Co. 132 132
South Street Narragansett Electric Co. 110.88 62.5
-208-
-------
STATE; Vermont
TOTAL
TOTAL COAL-FIEZD
PLANT CAPACITY CAPACITY
SAME OWNER(S) (MW) (MW)
No coal-fired capacity.
-209-
-------
EPA REGION II
(New Jersey, New York)
-210-
-------
STATS; New Jersey
PLANT
NAME
OWNER(S)
TOTAL
CAPACITY
(MW)
TOTAL
COAL-FIRED
CAPACITY
(MW)
England Atlantic City Electric Co. 437.605 275
Deepwater Atlantic City Electric Co. 306 226
Bergen Public Service Elec. & Gas Co. 712 650.432
Burlington Public Service Elec. & Gas Co. 1017.65 455-
Hudson Public Service Elec. & Gas Co. 1229.68 1114.48
Mercer Public Service Elec. & Gas Co. 768 652.8
-211-
-------
STATE:
New York
PLANT
NAME
OWNER(S)
TOTAL
CAPACITY
(MO
TOTAL
COAL-FIRED
CAPACITY
(MO
Goudey
Greenidge
Hickling
Jennison
Milliken
Huntley
Dunkirk
Rochester #3 (Beebe)
Rochester #7 (Russell)
Lovett
New York State Elec. & Gas Co. 145.75 145.75
New York State Elec. & Gas Co. 170 170
New York State Elec. & Gas Co. 70 70
New York State Elec. & Gas Co. 60 60
New York State Elec. & Gas Co. 275.5 270
Niagara-Mohawk Power Co. 720.7 720
Niagara-Mohawk Power Co. 560.7 560
Rochester Gas & Electric Corp. 215.2 215.2
Rochester Gas & Electric Corp. 252.6 252.6
Orange & Rockland Utilities, Inc. 496.7 496.7
-212-
-------
EPA REGION III
(Delaware, District of Columbia, Maryland,
Pennsylvania, Virginia, West Virginia)
-213-
-------
STATE; Delaware
TOTAL
TOTAL COAL-FIRED
PLANT CAPACITY CAPACITY
SAME OWNES(S) (MW)
Indian River Delmarva Power & Light 340 340
Delaware City Delmarva Power & Light 119.5 119.5
-214-
-------
STATE; District of Columbia
TOTAL
, TOTAL COAL-FIRED
PLANT CAPACITY CAPACITY
NAME OWNER(S) (MW) (MW)
No coal-fired capacity.
-215-
-------
STATE; Maryland
PLANT
NAME
OWNEB(S)
TOTAL
CAPACITY
(MW)
TOTAL
COAL-FIRED
CAPACITY
(MW)
Morgantown Potomac Electric Power Co. 1360 1112
Chalk Point Potomac Electric Power Co. 1310 1262
Dickerson Potomac Electric Power Co. 561 548
Smith Potomac Edison Co. 109.5 109.5
Wagner Baltimore Gas & Electric Co. 1004.8 321.5
-216-
-------
STATE; Pennsylvania
PLANT
SAME
Elrama
Phillips
Cheswick
Portland
Titus
Crawford
Front Street
Homer City
Seward
Shawville
Warren
Williamsburg
Conemaugh
Brunner Island
Holtwood
Martins Creek
Sunbury
Mbntour
New Castle
Eddystone
Southwark
Barbadoes
Chester
Cromby
Delaware
Richmond
Armstrong
Mitchell
Sprlngdale
Hatfield's Ferry
Hunlock Creek
Keystone
OWNES(S)
Duquesne Light Co.
Duquesne Light Co.
Duquesne Light Co.
Metropolitan Edison Co.L
Metropolitan Edison Co.l
Metropolitan Edison Co.
Pennsylvania Electric Co.
Pennsylvania Electric Co.2
Pennsylvania Electric Co.
Pennsylvania Electric Co.
Pennsylvania Electric Co.
Pennsylvania Electric Co.
Pennsylvania Power & Light Co.
Pennsylvania Power & Light Co.
Pennsylvania Power & Light Co.
Pennsylvania Power & Light Co.
Pennsylvania Power & Light Co.
Pennsylvania Power & Light Co.
Pennsylvania Power Co.
Philadelphia Electric Co.
Philadelphia Electric Co.
Philadelphia Electric Co.
Philadelphia Electric Co.
Philadelphia Electric Co.
Philadelphia Electric Co.
Philadelphia Electric Co.
West Perm Power Co.
West Penn Power Co.
West Penn Power Co.
West Penn Power Co.1*
UGI Corp.
Jersey Central Power & Light5
TOTAL
CAPACITY
(MO
425
315
525
426.7
225
116.7
118.8
1326
280.23
646
135.7
25
1882.9
1566.98
183.
1168,
.2
.5
415.28
.7
.3
1641.
431.
1463
422.75
192.75
174.75
353.75
318.75
909
326.4
448.7
215.38
1728
45.6
1680
Co-owner:
Co-owner:
3 Co-owners:
TOTAL
COAL-FIBED
CAPACITY
(MW)
425
315
525
426.7
225
46.7
118.8
1320
280.23
640
84.6
25
1872
1558.73
75
1163
409.78
1641.7
425.8
665
356
134
124
351
250
275
326.4
299.2
215.38
1728
45.6
1680
Pennsylvania Electric Co.
New York State Electric & Gas Co.
Pennsylvania Electric Co.; Potomac Electric Power Co.; Atlantic City
Electric Co.; Baltimore Gas & Electric Co.; Delmarva Power & Light Co.;
Public Service Electric & Gas of N.J. ; Metropolitan Edison Co.;
Philadelphia Electric Co.
Co-owner: Potomac Edison Co.; Monongahela Power Co.
Co-owners: Pennsylvania Power & Light; Atlantic City Electric Co.; Baltimore
Gas & Electric; Public Service Electric & Gas Co.; Delmarva Power
& Light; Philadelphia Electric Co.
-217-
-------
STATE; Virginia
PLANT
NAME
OWNER(S)
TOTAL
CAPACITY
(JOT)
TOTAL
COAL-FIRED
CAPACITY
(MO
Clinch River
Glen Lyn
Brantly
Potomac River
Bremo Bluff
Chesterfield
Portsmouth
Possum Point
Yorktown
Appalachian Power Co. 669 669
Appalachian Power Co. 337.5 337.5
City of Danville, Water, Gas & 39.13 . 29
Electric
Potomac Electric Power Co. 458 458
Virginia Electric Power Co. 254.28 254.28
Virginia Electric Power Co. 1484.4 1484.4
Virginia Electric Power Co. 649.64 649.64
Virginia Electric Power Co. 1469 1373
Virginia Electric Power Co. 1257 375
-218-
-------
STATE; West Virginia
PLANT
SAME
Cabin Creek
Kawawha River
Amos '
Philip Sporn
Albright
Fort Martin
Rivesville
Willow Island
Harrison
gammer
Mitchell
Mt. Storm
OWNER(S)
Appalachian Power Co.
Appalachian Power Co.
Appalachian Power Co . l
Appalachian Power Co.1
Monongahela Power Co.
Monongahela Power Co . 2
Monongahela Power Co.
Monongahela Power Co.
Monongahela Power Co.2
Ohio Power Co.
Ohio Power Co.
Virginia Electric Power Co.
TOTAL
CAPACITY
(MW)
170
426
2775.2
1060
209.25
1152
109.75
215
2052
675
1498.18
1681.07
TOTAL
COAL-FIRED
CAPACITY
(MW)
170
426
2775.2
1060
209.25
1152
109.75
215
2052
675
1498.18
1662.48
1 Co-owner: Ohio Power Co.
2 Co-owner: West Perm Power Co.
Potomac Edison Co.
-219-
-------
EPA REGION IV
(Alabama, Florida, Georgia, Kentucky,
Mississippi, North Carolina, South Carolina,
Tennessee)
-220-
-------
STATE: Alabama
PLANT
NAME
McWilliams
Tombigbee
Barry
Chlckasaw
Gas ton
Gads en
Gorgas
Greene County
Colbert
Widows Creek
OWNER(S)
Alabama Electric Co-op
Alabama Electric Co-op
Alabama Power Co.
Alabama Power Co.
Alabama Power Co.
Alabama Power Co.
Alabama Power Co.
Alabama Power Co . 1
Tennessee Valley Authority
Tennessee Valley Authority
TOTAL
CAPACITY
(MW)
55.28
75
1525
120
880
120
1341.25
500
1396.5
1977.99
TOTAL
COAL-FIBZD
CAPACITY
(MW)
40
75
1525
120
880
120
1341.25
500
1396.5
1977.99
1 Co-owner: Mississippi Power Co.
-221-
-------
STATE; Florida
TOTAL
TOTAL COAL-FIBED
PLANT ' CAPACITY CAPACITY
NAME OWNER(S) (MO (MO
Crystal River Florida Power Co. 964.3 523.8
Crist Gulf Power Co. 1045 970
Smith Gulf Power Co. 344.4 305
Scholz Gulf Power Co. 80 80
Gannon Tampa Electric Co. 1076 1062
Big Bend Tampa Electric Co. 1196 1052
-222-
-------
STATE; Georgia
PLANT
NAME
Arkwright
Atkinson
Hammond
McDonough
Mitchell
Yates
Bowen
Wans ley
Harllee Branch
Plant Crisp & Crisp
OWNER(S)
Georgia Power Co.
Georgia Power Co.
Georgia Power Co.
Georgia Power Co.
Georgia Power Co.
Georgia Power Co.
Georgia Power Co.
Georgia Power Co.1
Georgia Power Co.
Crisp County Power Conm.
TOTAL
CAPACITY
(MO
190.58
318.72
800
568.8
288.2
1250
2319.4
833
1539.7
30.5
TOTAL
COAL-FIBED
CAPACITY
(MO
160
240
800
490
170
1250
2280.0
833
1539.7
12.5
Hydro
1 Co-owner: Munic. Electric Authority of Georgia
-223-
-------
STATE: Kentucky
PLANT
NAME
Coleman
Reid
Cooper
Dale
Henderson #1
Big Sandy
Brown
Ghent
Green River
Pineville (4 mile)
Tyrone
Cane Run
Paddy's Run
Mill Creek
Smith
Owensboro #1
OWNER(S)
Big Rivers Electric Corp. •
Big Rivers Electric Corp.1
East Kentucky Power Co-op
East Kentucky Power Co-op
Henderson Municipal Power & Light
Kentucky Power Co.
Kentucky Utilities Co.
Kentucky Utilities Co.
Kentucky Utilities Co.
Kentucky Utilities Co.
Kentucky Utilities Co.
Louisville Gas & Electric Co.
Louisville Gas & Electric Co.
Louisville Gas & Electric Co.
Owensboro Public Utilities
Owensboro Public Utilities
TOTAL
CAPACITY
(MW)
455
370
354
194
51.5
1002.6
706
525
242
34
137
1004
360
660
415
45
TOTAL
COAL-FIRED
CAPACITY
(MO
455
370
354
194
49.5
1002.6
706
525
242
34
75
988
316
660
415
45
1 Co-owner: Henderson Municipal Power & Light
-224-
-------
STATE; Mississippi
TOTAL
TOTAL COAL-FISED
PLANT CAPACITY CAPACITY
.NAME OWNER(S) (MW) (MW)
No coal-fired capacity.
-225-
-------
STATE: North Carolina
PLANT
NAME
OWNER(S)
Cape Fear
Ashevllle
Lee
Roxboro
Weatherspoon
Sutton
Belews Creek
Buck
Cliffside
Dan River
Marshall
River Bend
Allen
Carolina Power & Light Co.
Carolina Power & Light Co.
Carolina Power & Light Co.
Carolina Power & Light Co.
Carolina Power & Light Co.
Carolina Power & Light Co.
Duke Power Co.
Duke Power Co.
Duke Power Co.
Duke Power Co.
Duke Power Co.
Duke Power Co.
Duke Power Co.
TOTAL
CAPACITY
(MO
465
392
498
1720
314
652
2200
488
770
369
2025
678
1140
TOTAL
COAL-FIRED
CAPACITY
(MO
381
392
407
1705
176
607
2200
364
770
284
2025
454
1140
-226-
-------
STATE: South Carolina
PLANT
NAME
OWNER(S)
TOTAL
CAPACITY
(MW)
TOTAL
COAL-FIRED
CAPACITY
-------
STATE: Tennessee
TOTAL
TOTAL COAL-FIRED
PLANT
NAME
Allen
Bull Run
Gallatin
Sevier
Kingston
Watts Bar
Cumberland
Johns onville
OWNES(S)
Tennessee Valley Authority
Tennessee Valley Authority
Tennessee Valley Authority
Tennessee Valley Authority
Tennessee Valley Authority
Tennessee Valley Authority
Tennessee Valley Authority
Tennessee Valley Authority
CAPACITY
990
950
1255.2
846.5
1723.5
240
2600
1485.2
CAPACITY
(MO
990
950
1255.2
846.5
1723.5
240
2600
1485.2
-228-
-------
EPA REGION V
(Illinois, Indiana, Michigan, Minnesota,
Ohio, Wisconsin)
-229-
-------
STATE:
Illinois
PLANT
NAME
Coffeen
Grandtower
Hutsonville
Meredosia
Edwards
Wallace
Klncaid
Powerton
Will County
Fisk
Crawford
Oixon
Joliet
Waukegan
Joppa
Hennepin
Vermillion
Baldwin
Wood River
Marion
Dallman
Lakeside
Fairfield
Venice #2
Winnetka
Mt. Camel
OWNER(S)
Central 111. Pub. Serv.
Central 111. Pub. Serv.
Central 111. Pub. Serv.
Central 111. Pub. Serv.
Central 111. Light Co.
Central 111. Light Co.
Commonwealth Edison Co.
Commonwealth Edison Co.
Commonwealth Edison Co.
Commonwealth Edison Co.
Commonwealth Edison Co.
Commonwealth Edison Co.
Commonwealth Edison Co.
Commonwealth Edison Co.
Electric Energy, Inc.
111. Power Co.
111. Power Co.
111. Power Co.
111. Power Co.
South 111. Power Co-op
Springfield Water, Light & Power
Springfield Water, Light & Power
Fairfield Munic. Elec. Dept.
Union Electric Co.
Village of Winnetka
Mt. Cannel Public Utility Co.
TOTAL
CAPACITY
(MW)
1005.46
194.64
200
564.06
725
275
1319.4
1785.6
1268.85
860.58
805.12
122.2
1944.8
1084.75
1041
311
186
1815
651
114
160
141
16.5
500
25.5
15
TOTAL
COAL-FIHED
CAPACITY
(MW)
1005.46
194.64
150
354.36
725
275
1319.4
1785.6
1268.85
546.58
597.52
119
1787.4
932.75
1041
311
186
1815
651
114
160
141
16.5
500
25.5
15
-230-
-------
STATS: Indiana
PLANT
NAME
OWNER(S)
TOTAL
CAPACITY
(MO
TOTAL
COAL-FIRED
CAPACITY
(MO
State Line
Crawfordsville
Washington Ave.
Ratts
Breed
Tanners Creek
Twin Branch
Clifty Creek
Stout
Pritchard
Perry
Petersburg
Logansport
Bailly
D. H. Mitchell
Michigan City
Peru
Edwardsport
Noblesville
Gallagher
Wabash River
Cayuga
Whitewater Valley
Culley
Warrick #4
Jasper
Washington
Commonwealth Edison Co.
Crawfordsville Elec. Lt. & Power
Frankfort City Lt. & Power Dept.
Hoosier Eng. Div. Ind. State. Rec.
Indiana & Michigan Elec. Co.
Indiana & Michigan Elec. Co.
Indiana & Michigan Elec. Co.
Indiana Kentucky Elec. Co.*
Indianapolis Power & Light Co.
Indianapolis Power & Light Co.
Indianapolis Power & Light Co.
Indianapolis Power & Light Co.
Logansport Munic. Utilities
Northern Indiana Public Serv.
Northern Indiana Public Serv.
Northern Indiana Public Serv.
City of Peru Utilities
Public Service Co. of Indiana
Public Service Co. of Indiana
Public Service Co. of Indiana
Public Service Co. of Indiana
Public Service Co. of Indiana.
Richmond Power & Light
Southern Indiana Gas & Electric
Southern Indiana Gas & Electric
Jasper Munic. Elec. Utilities
Washington City Lt. & Power
967.69
967.69
23.5
50
233.2
450
1098
244.76
1290
777.85
364
58.5
649.58
56
649.5
581.6
736
37
165
106
637
889
1024
93
414.93
161.5
14.5
18
23.5
32.5
233.2
450
1098
237.5
1290
704.35
361.25
58.5
641.43
39
615.6
529.4
736
37
165
106
637
881
1013
93
414.93
161.5
14.5
18
Co-owner: Ohio Valley Electric Corp.
-231-
-------
STATE:
Michigan
PLANT
NAME
Cobb
Morrow
Kara
Campbell
Weadock
Whiting
Mistersky
DeYoung
Eckert
Erickson
Ottawa
Advance
Harbor Beach
Marysville
River Rouge
St. Clair
Monroe
Conners Creek
Pennsalt
Trenton Channel
Wyandotte North
Port Huron
Warden
Presque Isle
£3canaba
Wyandotte
Shiras (Marquette)
OWNER(S)
Consumers Power Co.
Consumers Power Co.
Consumers Power Co.
Consumers Power Co.
Consumers Power Co.
Consumers Power Co.
City of Detroit Pub. Ltng.
Holland Brd. Pub. Wrks.
Lansing Brd. of Water & Light
Lansing Brd. of Water & Light
Lansing Brd. of Water & Light
Northern Michigan Elec. Co-op
Detroit Edison Co.
Detroit Edison Co.
Detroit Edison Co.
Detroit Edison Co.
Detroit Edison Co.
Detroit Edison Co.
Detroit Edison Co.
Detroit Edison Co.
Detroit Edison Co.
Detroit Edison Co.
Upper Peninsula Power Co.
Upper Peninsula Power Co.l
Upper Peninsula Power Co.
City of Wyandotte
Marquette Brd. Lt. & Power
TOTAL
CAPACITY
(MW)
510.6
221
1135
670.6
635.1
345.6
204
97.75
386
165
82.7
40
125
200
852.5
1798
3024.35
495.5
37
713.75
41.5
11.75
17.7
338.87
28-. 88
64
56.88
TOTAL
COAL-FIRED
CAPACITY
(MW)
510.6
186
1135
650
614.5
325
80
77.75
386
165
81.5
40
121
200
260
1450
3010.6
490
37
700
41.5
6.25
17.7
338.87
28.88
49
36.3
Co-owner: Upper Peninsula Generating Co.
-232-
-------
STATE: Minnesota
PLANT
NAME
Aurora (Syl Laskin)
Bosvell
King
Black Dog
High Bridge
Minnesota Valley
Riverside
Wilmarth
Red Wing
New Ulm
Silver Lake
Elk River
Plant #1
Willmar
Hoot Lake
Ortonville Gener. Plant
OWNER(S)
Minn. Power & Lt. Co.
Minn. Power & Lt. Co.
North. States Power Co.
North. States Power Co.
North. States Power Co.
North. States Power Co.
North. States Power Co.
North. States Power Co.
North. States Power Co.
New Ulm Publ. Utilities Conm.
Rochester Dept. Public Utilities
United Power Assn.
Virginia Dept. Pub. Utils.
Willmar Municipal Pub. Utils.
Otter Tail Power Co.
Otter Tail Power Co.
TOTAL
CAPACITY
(ME)
110
492.6
560
412
339
47
334
25
25
53.5
101
68
34.5
29.35
128
15
TOTAL
COAL-FIBED
CAPACITY
(MW)
110
492.6
560
412
339
47
334
25
25
51
101
45.5
34.5
29.35
127
15
-233-
-------
STATE:
Ohio
PLANT
NAME
Cardinal
Muskingum River
Philo*
Tidd
Woodcock
AshCabula
Avon Lake
East Lake
Lake Shore
Conesville
Picway
Post on
Edgewater
Gorge
Mad River
Miles
Burger
Torn to
Norwalk
Gavin
Kyger Creek
Piqua
Miami Fort
Beckj ord
Conesville #4
Stuart
Hutch ings
Tait
Bayshore Station
Acme
Orrville
Painesville
Columbus
Hamilton
* In deactivated reserve - 12/76.
OWNER(S)
Ohio Power Co. 1
Ohio Power Co.
Ohio Power Co.
Ohio Power Co.
Ohio Power Co.
Cleveland Elec. Illuminating
Cleveland Elec. Illuminating
Cleveland Elec. Illuminating2
Cleveland Elec. Illuminating
Columbus & Southern Ohio Elec.
Columbus & Southern Ohio Elec.
Columbus & Southern Ohio Elec.
Ohio Edison Co.
Ohio Edison Co.
Ohio Edison Co.
Ohio Edison Co.
Ohio Edison Co.
Ohio Edison Co.
Ohio Edison Co.
Ohio Edison Co.
Ohio Electric Co.
Ohio Valley Elec. Corp.
Piqua Mun. Power System
Cinncinnati Gas & Elec. Co.3
Cinncinnati Gas & Elec. Co.1*
Cinncinnati Gas & Elec. Co.1*
Cinncinnati Gas & Elec. Co.4
Dayton Power & Light
Dayton Power & Light
Toledo Edison Co.
Toledo Edison Co.
Orrville Municipal Util.
Painesville Elec. Div.
City of Columbus
Hamilton Municipal
- 12/76.
•fuel from Elec. World Dir. of
TOTAL
CAPACITY
(Mtf)
1190
1466.8
295
222.22
42.5
640
1307
1289
518
850.25
422.02
245.75
242.97
87.5
134.92
279.96
550.42
175.75
1990.24
32.38
2600
1075
59
1051
1432.8
825.05
2451.15
447
460
655.48
307.5
89.1
56.5
52.6
147.75
TOTAL
COAL-FIRED
CAPACITY
(MW)
1190
1466.8
295
222.22
42.5
440
1117
1257
514
836.5
170.75
232
192.87
87.5
75
250
544
175.75
1979.54
31.38
2600
1075
39
844
1188
825.05
2440
414
449
639.48
307.5
88.5
56.5
39. 5t
78
Utilities 1977-1978
Co-owner: Buckeye Power, Inc.
Co-owner: Duquesne Light Co.
Co-owner: Dayton Power & Light
Co-owner: Columbus & Southern Ohio Elec.
Co.; Dayton Power & Light
-234-
-------
STATE:
Wisconsin
PLANT
NAME
OWNER(S)
TOTAL
CAPACITY
(MO
TOTAL
COAL-FIBZD
CAPACITY
(MO
Alma
Genoa #3
Stonemsn
Bay Front
Manitowoc
River Street
North Oak Creek
Port Washington
South Oak Creek
Valley
East Wells B
Edge Water
Dewey
Rock River
Blackhawk
Columbia #1
Blount Street
Wildwood
Pulliam
Weston
Dairyland Power Co-op 208
Dairyland Power Co-op 350
Dairyland Power Co-op 52
Lake Superior Dist. Power Co. 82.2
Manitowoc Pub. Utilities 69
Menasha Elec. & Water'Util. 33.49
Wisconsin Electric Power Co. 500
Wisconsin Electric Power Co. 420
Wisconsin Electric Power Co. 1190
Wisconsin Electric Power Co. 272.42
Wisconsin Elec. Power Co. 13.7
Wisconsin Power & Light Co.1 449.94
Wisconsin Power & Light Co. 200
Wisconsin Power & Light Co. 333.9
Wisconsin Power & Light Co. 50.4
Wisconsin Power & Light Co.2 521
Madison Gas & Electric 195.5
Marshfield Elec. & Water Dept. 41.5
Wisconsin Public Service Corp. 392.5
Wisconsin Public Service Corp. 135
208
350
52
82.2
69
32.64
500
400
1170
269.67
13.7
449.94
200
150
50
521
195.5*
29
372.5
135
* Assumed based on multi-fuel from Electrical World Dir. of Utilities 1977-1978
1 Co-owner: Wisconsin Public Service Co.
2 Co-owner: Wisconsin Public Service Co.; Madison Gas & Electric
-235-
-------
EPA REGION VI
(Arkansas, Louisiana, New Mexico, Oklahoma, Texas)
-237-
-------
STATE; Arkansas
TOTAL
TOTAL COAL-FIRED
PLANT CAPACITY CAPACITY
NAME OWNER(S) (MW) (MW)
No coal-fired capacity
-238-
-------
STATS; Louisiana
TOTAL
TOTAL COAL-FIXED
PLANT CAPACITY CAPACITY
SAME OWNER(S) (MW)
Jfo coal-fired capacity
-239-
-------
STATE; New Mexico
TOTAL
TOTAL COAL-F1EED
PLANT CAPACITY CAPACITY
NAME OWNER(S) (MW) (MW)
Four Corners Arizona Public Service Company1 2208.2 2208.2
San Juan Public Service Company of N.M.2 652 652
i
Raton Raton Public Service Co. 12 12
1 Co-owners: Tucson Gas & Electric
Southern California Edison
Public Service Company of New Mexico
Salt River Project
El Paso Electric
2Co-owners: Tucson Gas & Electric
-240-
-------
STATE; Oklahoma
TOTAL
TOTAL COAL-FIKED
PLANT CAPACITY CAPACITY
NAME OWNER(S) (MW) (MW)
No coal-fired capacity
-241-
-------
STATE: Texas
TOTAL
TOTAL COAL-FI5ED
PLANT CAPACITY CAPACITY
SAME OWNER(S) (MW) (MW)
Big Brown Texas Power & Light Company1 1130 1150
Monticello Texas Power & Light Company1 1150 1150
1Co-owners: Dallas Power & Light
Texas Electric Service Company
-242-
-------
EPA REGION VII
(Iowa, Kansas, Missouri, Nebraska)
-243-
-------
STATE; iowa
PLANT
NAME
Lansing
Kapp
Dubuque
Bridgeport
Burlington
Muscatine
Pella
Humboldt
Wisdom
Fair
Boone
Sixth Street
Prairie Creek #4
Sutherland
Riverside
Neal
Maynard
Hawkeye
Carrol
Eagle Grove
Council Bluffs
Des Moines
OWNER(S)
Interstate Power Company
Interstate Power Company
Interstate Power Company
Iowa Southern Utilities Company
Iowa Southern Utilities Company
Muscatine Brd. of Wtr. & Lt.
Pella Munic. Pwr. & Lt.
Cornbelt Power Co-op
Cornbelt Power Co-op
Eastern Iowa Lt & Pwr Co-op
Iowa Electric Lt & Pwr
Iowa Electric Lt & Pwr
Iowa Electric Lt & Pwr
Iowa Electric Lt & Pwr
Iowa-Illinois Gas & Elec. Co.
Iowa Public Serv. Co.1
Iowa Public Serv. Co.
Iowa Public Serv. Co.
Iowa Public Serv. Co.
Iowa Public Serv. Co.
Iowa Pwr. & Light Co.
Iowa Pwr. & Light Co.
TOTAL
CAPACITY
(MO
61.5
227.28
77
71
211.95
108
43.5
49
39
55
27
105
140
149.5
283.41
1022.94
77.4
19
10
7.5
138.7
276.9
TOTAL
COAL-FIEED
CAPACITY
(MO
59.5
212.28
58*
71
211.95
108
43.5
49
39
55
27
105
140
149.5
201.65
1017.44
77.4
19
10 '
7.5
138.7
276.9
*Single header unit - 3 of the 4 boilers on the header can burn coal.
1 Co-owners: Iowa Power & Light
Iowa-Illinois Gas & Elec. Co.
Iowa Southern Utilities
-244-
-------
STATE; Kansas
TOTAL
TOTAL COAL-FIRED
PLANT
NAME
Neosho
La Cygne
Ri vert on
Kaw
Quindaro #2
Quindaro #3
Lawrence
Tecumseh
OWNER(S)
Kansas Gas & Electric
Kansas City Pwr. & Lt.1
Empire Dist. Elec. Company
Kansas City 3rd. of Pub. Utils.
Kansas City Brd. of Pub. Utils.
Kansas City Brd. of Pub. Utils.
Kansas Pwr & Lt. Company
Kansas Pwr & Lt. Company
CAPACITY
(MO
113.5
858.7
157.5
156
164
228
575.7
378
CAPACITY
(MO
40*
858.7
80
156
45
228
529.7
220
*Coal units on cold reserve.
1 Co-owner: Kansas Gas & Electric
-245-
-------
STATE: Missouri
PLANT
NAME
OWNER(S)
TOTAL
CAPACITY
(MO
TOTAL
COAL-FIRED
CAPACITY
(MO
Asbury
Montrose
Northeast
Grand Ave
Hawthorn
Green
Sibley
Rush Island
Sioux
Labadie
Meramec
Fulton n
Thomas Hill
New Madrid
Columbia
Lake Road (Lakeside)
Empire District Elec. Co.
Kansas City Pwr & Lt.
Kansas City Pwr & Lt.
Kansas City Pwr & Lt.
Kansas City Pwr & Lt.
Missouri Public Serv. Co.
Missouri Pub. Serv. Co.
Union Elec. Co.
Union Elec. Co.
Union Elec. Co.
Union Elec. Co.
Fulton Brd. Pub. Wrks.
Associated Elec. Co-op
City of New Madrid1
Columbia Water & Lt Dept
St. Joseph Lt & Pwr Co.
200
546
468
99
836
49.5
523.5
555.04
978
2220
800
44.15
483
600
97.5
235.5
200
546
135
99
836
49.5
523.5
555.04
978
2220
800
11.5
303
600
85
150.5
1 Co-owner - Associated Electric Co-op
-246-
-------
STATE: Nebraska
TOTAL
TOTAL COAL-FISED
PLANT CAPACITY CAPACITY
NAME OWNER(S) (MW) (MW)
Kramer Nebraska Public Power District 113 113
Sheldon Nebraska Public Power District 225 225
North Omaha Omaha Public Power District 600 600
-247-
-------
EPA REGION VIII
(Colorado, Montana, North Dakota
South Dakota, Utah, Wyoming)
-248-
-------
STATE; Colorado
TOTAL
TOTAL COAL-FIBZD
PLANT CAPACITY CAPACITY
NAME OWNER(S) (MW) (MW)
Hayden Salt River Project1 465.4 465.4
Nucla Colorado-Ute Electric Assoc. 34.5 . 34.5
Comanche Public Service Co. of Colorado 700 700
Arapahoe Public Service Co. of Colorado 232 232
Cameo Public Service Co. of Colorado 66 66
Cherokee Public Service Co. of Colorado 715.5 710.0
Canon City Cent. Telephone & Utility Corp. 42.35 42.35
Drake City of Colorado Springs 264 264
Co-owner: Colorado UTE Electric Association
-249-
-------
STATE; Montana
TOTAL
TOTAL COAL-FIRED
PLANT CAPACITY CAPACITY
NAME OWHER(S) (MW) (MQ
Lewis and Clark Montana-Dakota Utilities SO 50
Colstrip Montana Power Company1 716.74 716.74
Corette , Montana Power Company1 172.8 172.8
1 Co-owner: Puget Sound Power and Light Company
-250-
-------
STATE; North Dakota
TOTAL
TOTAL COAL-FIBED
PLANT CAPACITY CAPACITY
NAME OWKER(S) (MW) (MW)
Leland Olds Basin Electric Power Co-op 650 650
Neal Basin Electric Power Co-op 30 30
Young Minnkota Power Co-op 240 240
Heskett Montana-Dakota Utility Co. 100 100
Beulah Montana-Dakota Utility Co. 13.5 13.5
Stanton United Power Association 172 172
-251-
-------
STATS; South Dakota
PLANT
NAME
OWNER(S)
TOTAL
CAPACITY
(MO
TOTAL
COAL-FISED
CAPACITY
(MW)
Kirk
Ben French
Big Stone
Aberdeen Gen. Pit.
Mitchell Gen. Pit.
Lawrence
Black Hills Power & Light Co.
Black Hills Power & Light Co.
Northwestern Public Serv. Co.1
Northwestern Public Serv. Co.1
Northwestern Public Serv. Co.1
Northern States Power Company
31.
32
419.
7,
7,
45
31.5
22
419.4
7.5
7.5
45
LCo-owners: Otter Tail Power Company
Montana-Dakota Utilities Company
-252-
-------
STATE; Utah
TOTAL
TOTAL COAL-FIHED
PLANT CAPACITY CAPACITY
NAME OWNER(S) (MW) (MW)
Carbon Utah Power & Light Company 166 166
Huntington #2 Utah Power & Light Company 446.4 446.4
Gadsby Utah Power & Light Company 241 • 241
Hale Utah Power & Light Company 62.75 62.75
Cedar Steam Cal.-Pacific Utility Company 7.5 7.5
-253-
-------
STATS; Wyoming
TOTAL
TOTAL COAL-FISED
PLANT CAPACITY CAPACITY
NAME OWNER(S) (MW) (MW)
Simpson Black Hills Power & Light Co. 27.68 27.68
Osage Black Hills Power & Light Co. 35.5 .34.5
Jim Bridger Pacific Power & Light Company1 1525.67 1525.67
Johnston Pacific Power & Light Company 750.31 750.31
Naughton Utah Power & Light Company 707.2 707.2
1Co-owner: Idaho Power and Light
-254-
-------
EPA REGION IX
(Arizona, California, Nevada)
-255-
-------
STATE:
PLANT
NAME
Arizona
OWNER(S)
TOTAL
CAPACITY
(MO
TOTAL
COAL-FIRED
CAPACITY
(MO
Apache
Cholla
Navajo
Arizona Elec. Power Co-op
Arizona Public Service Co.
t
Salt River Project1
168
116
2250
75
116
2250
1 Co-owner: Los Angeles Oept. of Water & Power; U. S. Bureau of Reclamation;
Arizona Public Service; Nevada Power-Co.; Tucson Gas & Electric
-256-
-------
STATE: California
TOTAL
TOTAL COAL-FISED
PLANT CAPACITY CAPACITY
NAME OWNER(S) (MM) (MW)
No coal-fired capacity.
-257-
-------
STATE: Nevada
TOTAL
TOTAL COAL-FISED
PLANT CAPACITY CAPACITY
NAME OWNER(S) (MO - (MW)
Gardner Nevada Power Co. 330 330
Mohave Nevada Power Co.1 1580 1580
1 Co-owners: Southern California Edison Co.; Los Angeles Dept. of Water &
Power; Salt River Project
-258-
-------
EPA REGION X
(Idaho, Oregon, Washington)
-259-
-------
STATE; Idaho
TOTAL
TOTAL COAL-FIBED
PLANT CAPACITY CAPACITY
NAME • OWNES(S) (MW) (MM)
No coal-fired capacity.
-260-
-------
STATS; Oregon
TOTAL
TOTAL COAL-FIEED
PLANT CAPACITY CAPACITY
SAME OWNES(S) (MM) (MW)
No coal-fired capacity.
-261-
-------
STATE; Washington
TOTAL
TOTAL COAL-FIRED
PLANT CAPACITY CAPACITY
NAME OWNER(S) (MW) (MW)
Centralia Pacific Power & Light Co.l 1329.8 1329.8
Co-owners: Washington Water Power Co.; Puget Sound Power & Light Co.;
Portland General Electric Co.; City of Seattle; City of Tacoma;
P.U.D. No. 1 of Snohomlsh County; F.U.D. No. 1 of Gray Harbor
County
-262-
-------
APPENDIX D
ELECTRIC UTILITY CAPITAL AND
MAINTENANCE EXPENSE DATA
-263-
-------
1978 ELECTRIC UTILITY CAPITAL EXPENDITURES
i
N>
CT>
£-
I
Geographical Region
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
Total Capital
Spending
(millions of dollars)
963.0
3,318.0
6,406.0
4,052.9
4,613.4
2,670.1
3,939.0
2,183.1
4,542.2
% Investor-
Owned
96.0
98.7
89.4
46.0
86.9
28.1
72.8
67.4
50.8
% Muni, State,
and PPD's
3.1
0.1
4.6
20.2
5.8
4.2
10.3
20.3
31.2
% Co-op's
0.9
1.2
6.0
33.5
6.2
17.3
16.5
9.9
0.5
% Federal
Agencies
.
-
0
0.3
1.1
50.4
0.4
2.4
17.5
U.S. Total
32,687.6
71.0
11.6
10.5
6.9
Source: "1978 Annual Statistical Report," Electrical World. Vol. 189, No. 6, March 15, 1978, p. 83.
-------
1977 ELECTRIC UTILITY CAPITAL EXPENDITURES
Ul
i
Geographical Region
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
Total Capital
Spending
(millions of dollars)
766.6
3,106.2
5,515.7
3,071.9
3,905,3
2,466.7
3,376.0
1,821.1
3,592.4
% Investor-
Owned
97.4
91.8
92.3
42.9
84.6
32.9
75.1
64.8
53.5
% Muni, State,
and PPD's
1.4
7.3
3.1
25.0
7.7
3.5
8.6
20.5
26.3
% Co-op's
1.2
0.9
4.6
31.2
7.0
18.8
16.2
12.3
0.5
% Federal
Agencies
-
0
0.9
0.7
44.8
0.1
2.4
19.7
U.S. Total
27,621.8
71.5
11.6
10.0
6.9
Source: "1978 Annual Statistical Report," Electrical World, Vol. 189, No. 6, March 15, 1978, p. 82.
-------
PERCENT GROWTH IN ELhCTRIC UTILITY
a\
CAPITAL EXPENDITURES 1977-1978
Geographical Region
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
U.S. Total
Total
+25.6%
+ 6.8
+16.1
+31.9
+18.1
+ 8.2
+16.7
+19.9
+26.4
+18.3
Investor-Owned
+23.7%
+14.9
+12.5
+41.7
+21.4
- 7.5
+13.0
+24.6
+20.2
+17.4
Muni, State,
and PPD's
+174.5%
- 98.5
+ 74.6
+ 6.1
- 10.2
+ 28.1
+ 39.7
+ 19.1
+ 50.2
+ 19.6
CO-Op'8
Federal
Agencies
+ 5.8%
+50.6
+50.1 0.0%
+41.7 -53.5
+ 4.5 +72.4
- 0.1 +21.7
+19.1 +858.0
-3.8 +21.1
+10.9 +12.2
+23.5 +18.5
Source: "1978 Annual Statistical Report," Electrical World. Vol. 189, No. 6, March 15, 1978.
-------
1977 ELECTRIC UTILITY MAINTENANCE COSTS
i
ro
Geographic Region
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
Total Maintenance Costs
(millions of dollars)
200
963
920
357
691
365
335
197
535
.0
.2
.7
.7
.5
.4
.6
.9
.7
% Investor-
Owned
89.
99.
90.
66.
89.
34.
70.
66.
53.
9
4
1
7
9
1
6
6
8
% Muni, State,
and PPD's
8
0
5
15
3
10
6
13
31
.9
.2
.9
.9
.9
.1
.6
.9
.5
% Co-ops
1
0
4
12
6
8
11
7
0
.2
.4
.0
.7
.0
.2
.0
.6
.6
% Federal
Agencies
0
4
0
47
11
11
14
-
.0+
.6
.2
.6
.8
.9
.1
U.S. Total
4,567.7
79.0
9.1
4.7
7.2
Source: "1978 Annual Statistical Report," Electrical World. Vol. 189, No. 6, March 15, 1978.
-------
1978 BUDGETED ELECTRIC UTILITY MAINTENANCE COSTS
i
N>
CTi
00
Geographic Region
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
U.S. Total
Total Budgeted
Maintenance Costs
(millions of dollars)
1
1
213.
,044.
,020.
388.
785.
429.
355.
224.
583.
6
6
1
7
7
6
2
9
6
% Investor- % Muni, State,
Owned and PPD's
90
99
91
68
88
34
74
68
51
.1
.4
.4
.0
.7
.4
.4
.0
.8
8.
0.
4.
13.
4.
10.
7.
13.
33.
7
2
5
7
9
0
0
3
3
Z Co-ops
1.
0.
3.
13.
6.
7.
12.
7.
0.
2
4
9
9
1
9
2
7
6
% Federal
Agencies
0.
4.
0.
47.
6.
11.
14.
-
Of
4
3
7
4
0
3
5,046.0
79.1
8.9
4.9
7.1
Source: "1978 Annual Statistical Report," Electrical World. Vol. 189, No. 6, March 15, 1978.
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PERCENT GROWTH IN ELECTRIC UTILITY
MAINTENANCE COSTS, 1977-1978
i
to
us
I
Geographic Region
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
U.S. Total
Total
+ 6.8
+ 8.5
+10.8
+ 8.7
+13.6
+17.6
+ 5.8
+13.7
+ 8.9
+10.5
Investor-Owned
+ 7.0
+ 8.4
+12.4
+10.7
+12.1
+18.6
+11.5
+15.9
+ 4.9
+10.6
Muni, State,
and PPD's
+ 4.3
+ 8.2
-14.5
- 6.4
+41.7
+17.3
+11.3
+ 8.8
+15.0
+ 9.0
Co-op ' a
+10.1
+34.3
+11.6
+18.2
+17.2
+12.4
+17.8
+15.7
+14.3
+15.9
Federal
Agencies
-
+17.6
+ 4.2
+30.9
+17.8
r42.3
+ 2.4
+10.5
+ 7.4
Source: "1978 Annual Statistical Report," Electrical World. Vol. 189, No. 6, March 15, 1978.
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