£EPA
United States
Environmental Protection
Agency
Office of
Planning and Evaluation
Washington OC 20460
EPA 440/1-80/029-e
Auflu«1980
Planning and Evaluation
Economic Analysis
for the Proposed Revision
of Steam-Electric
Utility Industry
Effluent Limitations
Guidelines
-------
ECONOMIC ANALYSIS
FOR THE PROPOSED REVISION OF
STEAM-ELECTRIC UTILITY INDUSTRY
EFFLUENT LIMITATIONS GUIDELINES
OFFICE OF PLANNING AND EVALUATION
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
PROJECT OFFICER
JEFFREY WASSERMAN
AUGUST 1980
-------
This document is available in limited quantities
through the Office of Planning and Evaluation,
Jeffrey Wasserman, (202 - 755-4803).
This document will subsequently be available through
the National Technical Information Service,
Springfield, Virginia 22151.
-------
PREFACE
The attached document is a contractor's study prepared
for the Office of Planning and Evaluation of the Environmental
Protection Agency ("EPA"). The purpose of the study is to
analyze the economic impact which could result from the
application of alternative BAT, PSES, NSPS, PSNS guidelines
established under the Federal Water Pollution Control Act
(the Act), as amended.
The study supplements the technical study ("EPA Development
Document") supporting the proposal of regulations under the
Act. The Development Document surveys existing and potential
waste treatment control methods and technologies within particular
industrial source categories and supports proposed limitations
based upon an analysis of the feasibility of these limitations
in accordance with the requirements of the Act. Presented in
the Development Document are the investment and operating costs
associated with various alternative control and treatment
technologies. The attached document supplements this analysis
by estimating the broader economic effects which might result
from the required application of various control methods and
technologies.
The study has been prepared with the supervision and
review of the Office of Planning and Evaluation of the EPA.
This report was submitted in fulfillment of Contract No.
68-01-5840 by Temple, Barker & Sloane, Inc. This report
reflects work completed as of August 1980.
This report is being released and circulated at
approximately the same time as publication in the Federal
Register of a notice of proposed rule making. The study
is not an official EPA publication. It will be considered
along with the information contained in the Development
Document and any comments recieved by EPA on either document
before or during proposed rule making proceedings necessary
to establish final regulations. Prior to final promulgation
of regulations, the accompanying study shall have standing
in any EPA proceeding or court proceeding only to the extent
that it represents the views of the contractor who studied
the subject industry. It cannot be cited, referenced, or
represented in any respect in any such proceeding as a
statement of EPA's views regarding the steam-electric utility
industry.
-------
CONTENTS
I. EXECUTIVE SUMMARY
II. DESCRIPTION OF THE ELECTRIC UTILITY INDUSTRY
III. PLANT- AND INDUSTRY-LEVEL EFFECTS OF THE PROPOSED
EFFLUENT LIMITATIONS GUIDELINES
-------
I. EXECUTIVE SUMMARY
This report provides an economic and financial analysis
of proposed revisions to the effluent limitations guidelines for
best available technology economically achievable (BAT), new
source performance standards (NSPS), and pretreatment standards
as applied to the steam-electric utility industry. The economic
evaluation is based on technical findings and cost data supplied
by the United States Environmental Protection Agency (EPA) and
its technical contractors in published reports. A final eco-
nomic assessment will be prepared when the regulations are pro-
posed.
In developing the effluent limitations guidelines, EPA has
considered discharge standards for ten waste streams:
• Bottom ash transport water
• Fly ash handling water
• Recirculating cooling water
• Once-through cooling water
• Metal cleaning wastes
• Low volume wastes
• Boiler blowdown
• Coal pile runoff
• Chemical handling runoff
• Flue gas desulfurization waste water
At present, however, this report covers only the economic ef-
fects associated with BAT and pretreatment standards for once-
through and recirculating cooling water and NSPS for both cool-
ing water streams and for fly ash transport water. For the re-
maining waste streams the Agency has decided either not to re-
quire controls beyond those necessary to meet best practicable
control technology (BPT) standards or to postpone consideration
of regulations until more data concerning waste stream consti-
tuents and treatment technology effectiveness become available.
-------
1-2
The following sections will briefly summarize the major
findings of the economic analysis in the four main areas exam-
ined in this report. These areas are:
• A physical and economic profile of the
industry.
• An estimate of the economic effects of
the proposed regulations on individual
utilities and on the electric utility
industry.
• An assessment of the costs of the regula-
tions relative to the amounts of pollu-
tants removed; and
• A determination of the effects of the
regulations on industry growth, employ-
ment, capital availability, and other fac-
tors as appropriate.
Profile of the Industry
The electric utility industry consists of about 750 indi-
vidual utilities operating approximately 2,000 power plants
with a combined operating capacity of approximately 588,000
megawatts (MW). Only the steam sector of the industry would
be affected by the proposed regulations. This sector accounts
for nearly 80 percent of the industry's capacity and 85 percent
of the electricity generated annually. In the future the capa-
city of the industry is expected to grow at an overall annual
rate of slightly more than 3 percent. The steam sector of the
industry with a faster annual growth rate of 4.1 percent will
increase its share of total industry capacity to over 85 percent
by 1995.
The electric utility industry is the most capital-intensive
industry in the United States. Its 1980 planned capital expend-
itures of $34 billion represent about 16 percent of total capi-
tal expenditures by U.S. industry. During the decade from 1979
to 1989 the industry will spend a further $381.2 billion (1980
dollars). To finance these expenditures it will raise $222 bil-
lion from external sources.
Expenditures for pollution control equipment by the electric
utility industry account for about one-third of total pollution
control expenditures by U.S. industry. The industry spent $2.9
billion in 1979 and it anticipates spending a further $3.6 billion
-------
1-3
in 1980 on air, water, and solid waste pollution control equipment.
Between one-third and one-fourth of the industry's annual pollution
control expenditures go to water pollution control.
Recently the electric utility industry has been adversely
affected by high interest rates and steep inflation. As a re-
sult of increasing costs of fuel, materials, and labor, average
consumer charges have increased sharply. Meanwhile, electric
utility stock prices fell by an average of 7.2 percent and as
of December 31, 1979, the average market to book value ratio of
electric utility stocks reached its lowest level since mid-1975.
In March 1980 interest rates on Moody's Aa rated electric util-
ity stocks reached tUeir highest value (14 percent) in the his-
tory of the industry.
Economic Effects of the Proposed Regulations
The regulations currently being proposed will not add
significantly to the cost of generating electricity. As shown
in Table 1-1 consumer charges will increase by one twenty-fifth
of one percent and capital expenditures will increase by one-
fiftieth of one percent as a result of compliance with the
regulations. Although the industry will spend up to $80 mil-
lion annually to comply and its cumulative capital expendi-
tures will increase by $200 million over the period 1980-1995,
these increases are very small relative to baseline industry
costs.
Table 1-1
OVERALL FINANCIAL EFFECTS OF THE PROPOSED
EFFLUENT LIMITATIONS GUIDELINES
(Increase over baseline in 1980 dollars)
Cumulative Capital Expenditures
Millions of Dollars
Percent of Baseline
Revenue Requirements
Millions of Dollars
Percent of Baseline
Operation and Maintenance Expense
Millions of Dollars
Percent of Baseline
Consumer Charge
Mills per KUH
Percent of Baseline
1985 1990
$120
.05%
$60
.04%
$40
.05%
$150
.03%
$70
.04%
$60
.06*
1995
$200
.02%
$80
.04%
$70
.07%
.02 .02 .02
.04% .04% .04%
Electrical Week, May 26, 1980.
-------
1-4
At the individual plant level the economic effects of the
proposed regulations are significant only at small plants that
are more than 25 years old. At these plants a combination of
low capacity factors and short remaining depreciable lives re-
sult in increases of 1.3 to 3.5 percent in the cost of gener-
ating electricity. Since most utilities also operate newer and
larger plants this increase in the cost of generating electric-
ity will not translate into similar increases in consumer
charges. At newer and larger plants which account for most of
the industry's capacity the cost of generating electricity
will increase by 0.02 percent.
Cost-Effectiveness
The proposed regulations are more stringent than best
practicable technology regulations for chlorine and for the 129
priority pollutants. The cost of chlorine removal increases
dramatically from a cost of between $.77 and $4.55 for the
first 17.4 million pounds of chlorine removed to $862 per pound
for the final 34,000 pounds removed. This difference reflects
not higher plant-level costs, which are roughly equivalent, but
much lower quantities of chlorine present at certain plants.
Zinc, chromium, and chlorinated phenols in cooling water
waste streams would also be eliminated by restrictions on the
use of chemical additives containing the 129 priority pollu-
tants. There would be no cost associated with using alterna-
tive chemicals not containing chlorinated phenols, and the cost
of eliminating chromium and zinc would be $11 and $53 per pound
respectively.
Effects on Industry Growth and Other Factors
Given the magnitude of the electric utility industry, the
costs of the proposed regulations are insufficient to have an
appreciable effect on its operating characteristics. The in-
dustry's financial parameter most affected by the proposed regu-
lations is operation and maintenance expenses. Even this finan-
cial parameter, however, increases by less than one-tenth of
one percent as a result of industry compliance with the regula-
tions. No other financial parameter increases by more than
one-twentieth of one percent.
-------
II. DESCRIPTION OF THE ELECTRIC
UTILITY INDUSTRY
This chapter briefly describes the electric utility indus-
try's physical and financial characteristics to provide a basis
for an assessment of the effects of the proposed effluent limita-
tions guidelines on the industry. First, the physical configura-
tion of the industry at the national, company, and plant levels
is described emphasizing those aspects of the industry that are
most likely to affect the overall costs of compliance with the
proposed regulations. Second, financial aspects of the industry,
including company revenues, total industry capitalization, and
external financing requirements, are discussed. Finally, some
of the more important issues facing the industry in the years
ahead are described.
PHYSICAL DESCRIPTION OF THE
ELECTRIC UTILITY INDUSTRY
By any measure, the electric utility industry is large.
Comprising about 750 individual utilities operating over 2,600
steam and non-steam power plants, it has a total peak generating
capacity of nearly 600,000 megawatts and in 1979 it generated
2,295 billion kilowatt-hours of electricity. In the process of
generating electricity the industry utilizes over 60 trillion
gallons of water annually for cooling, generating steam, and
transporting ash and other wastes. The electric utility industry
uses more water than any other industrial group in the nation.
In the future, the industry is expected to grow at an annual
rate of about 3.1 percent (although estimates of future growth
vary widely). Growth in the steam sector of the industry will
be somewhat more rapid—about 4.1 percent .per year. By 1995,
there will be about 4,150 power plants wifh a generating capa-
city of 1,003,800 MW.
The power plant is the basic production unit of the electric
utility industry, and the cost of complying with the revised BAT
regulations will depend on the physical characteristics of each
power plant. Plant characteristics that are most likely to af-
fect costs of compliance with the effluent limitations guidelines
that EPA either has considered or is proposing are: plant type,
capacity, age, fuel type, and discharge and cooling system type.
In the sections that follow each of these characteristics will
be described.
-------
II-2
Plant Type
For the purposes of this analysis the electric utility in-
dustry can be divided broadly into two plant types—steam and
non-steam. Steam plants use steam to drive a turbine which in
turn rotates an electric power generator. Steam is generated
primarily by burning fossil fuels or, in a nuclear plant, by a
nuclear fission reaction. Non-steam plants use either water
(in a hydroelectric plant), a jet-like engine (in a gas turbine
plant), or an internal combustion engine to rotate the generator.
The effluent limitations guidelines under review cover only
power plants with steam boilers. Forty percent of all existing
power plants have steam boilers. These steam-electric plants
(referred to as the "steam sector" of the industry) represent
79 percent of the capacity and 85 percent of the generation
of the electric utility industry. Details on the present and
future generating capacity of the steam sector of the electric
utility industry are shown in Table II-l.
Table II-l
PRESENT AND FUTURE CAPACITY
OF THE ELECTRIC UTILITY INDUSTRY
(capacity in gigawatts at year end)
1978 1985
Generating Capacity
Total Industry
Steam Sector
573.8
453.3
750.3
614.4
1990
834.9
695.7
1995
1,003.8
855.4
Source: DOE Inventory of Powerplants (1979), TBS
estimates.
Capacity
Plant capacities range from less than 10 MW for small
peaker plants to well over 1,000 MW for very large baseload
plants. As shown in Table II-2, the distribution of plants by
number of plants differs from the distribution by capacity.
While slightly over 45 percent of the plants have capacities
of less than 200 MW, less than 7 percent of the capacity is in
these plants. Nearly 12 percent of the existing plants are in
the 0-25 MW category, yet these plants represent only 0.3 per-
cent of the generating capacity- Conversely, the 35 percent
of the plants in the over-500 MW category account for over 81
-------
II-3
percent of the generating capacity. Moreover, large plants
are generally baseload units which operate at high capacity
factors, while small plants are most frequently used to sup-
plement baseload capacity during periods of peak demand. Con-
sequently, large plants account for a greater percentage of
total electric power generation than they do of total gener-
ating capacity.*
Table 1 1-2
YEAR-END 1978 DISTRIBUTION OF STEAM-ELECTRIC PLANTS
BY SIZE CATEGORY1
Total MW in Category
Percent of Total
Capacity
Number of Plants
Percent of Total Plants
0-25 MM 26-100 MW 101-200 MW 201-350 MM
1,273 9,466 16,777 24,125
0.3* 2.1* 4.0* 5.3*
98 172 115 87
11.6* 20.4* 13. 7X 10.3*
Over
351-500 MW 500 MW Total
33,282 368,342 453,265
7.0* 81.3* 100.0*
79 291 842
9.4* 34.6* 100.0*
Excludes plants with zero net dependable capacity.
Source: DOE Inventory
of Powerplants (1979).
Plant Age
The age of plants affected by the revised effluent limita-
tions guidelines influences the economic impact of pollution
control expenditures. Most plants have depreciable lives of
30 to 35 years. If pollution control equipment is installed
at a 25-year-old plant, the investment may be amortized only
over the plant's remaining 5- to 10-year depreciable life, re-
sulting in high annual depreciation charges. Annual costs are
lower, therefore, for the same equipment installed at newer
plants. In most cases, the physical life of a plant exceeds
its depreciable life but for the purposes of economic analysis,
pollution control expenditures should be amortized over the
remaining depreciable life.
The number and capacity of plants in each category is based
on the 1979 DOE Inventory of Powerplants database. Plants
listed in the DOE Inventory as having a net dependable capacity
of zero were excluded.
-------
II-4
The age distribution of existing steam-electric power
plants shows a definite correlation between plant size and age.
As shown in Exhibit II-3, nearly 75 percent of the capacity
has been built since 1960 and almost 90 percent of this capacity
is in plants larger than 500 MW. By way of contrast only 54
percent of the capacity built prior to 1960 is in plants larger
than 500 MW. Table II-3 illustrates these results in terms of
age of the median, most recently built, and oldest quartiles
of plants in each size category.
Table II-3
BOILER IN-SERVICE DATE FOR OLDEST, MEDIAN, AND
MOST RECENTLY BUILT QUARTILES IN SELECTED
PLANT SIZE CATEGORIES
Quartile
Oldest
Median
Most Recently
Built
Source: DOE
0-25
Pre-
1945
1950
1955
Inventory of
Plant Size
26-100 101-200
Pre- 1950
1945
1950 1955
1960 1960
Powerplants (1979).
Category (MW)
201-350 351-500 >500 Total
1950 1950 1965 1960
1955 1960 1970 1970
1965 1970 1975 1975
Fuel Type
Steam-electric plants use four major fuels—coal, oil, gas
and nuclear energy. As shown in Table II-4, coal-fired plants '
with an average capacity of nearly 650 MW account for slightly
more than 50 percent of total capacity with just over 40 percent
of the plants. Oil plants average 462 MW and make up 22 percent
of steam-electric capacity with 26 percent of the plants. With
thflnV6thge capa°Uy of 327 MW' gas P^ts are generally smaller
than other plants and contribute only 15 percent of total
acity with 25 percent of the plants/ Nuclear plants on
hand average 1 400 MW and account for 12 percent of steam-ele
capacity with 5 percent of the plants. Finally, plants using
unknown multiple or "other" fuels such as refuse constTtutl
2 percent of the plants but less than 1 percent of capacity
-------
II-5
Fuel
Coal
on
Gas
Nuclear
Unknown
Multiple
Other
Total
Source:
Table II-4
DISTRIBUTION OF CAPACITY
AND PLANTS BY FUEL TYPE
1978
Number
352
220
209
38
18
3
2
842
DOE, Inventory of Powerplants
Capacity (MM)
227,366
101,701
68,371
53,825
551
1,412
39
453,265
(1979).
As shown in Table II-5, the mix of fuel types used by
steam-electric power plants is expected to change dramatic-
ally over the next 10 years. Depending on future petroleum
prices, the stringency of federal fuel-use regulations, and
the availability of capital for coal conversion, oil and gas
capacity may decrease to less than half of what it is now by
1990 or 1995. Given the growth in other fuel types, this de-
cline will mean that oil and gas generation will account for
less than 10 percent of total generation by 1995 as compared
to 39 percent in 1979.
The future of nuclear capacity is less certain. Increas-
ing construction costs, siting difficulties, and the aftermath
of the events at Three Mile Island may serve to dampen a rising
trend in nuclear capacity. On the other hand, many major util-
ities remain committed to a program of major nuclear construc-
tion. Consequently, in its latest "Annual Electrical Industry
Forecast," Electrical World projects that nuclear construction
will decline from previously projected levels more as a func-
tion of a low peak demand growth rate than as a result of the
Three Mile Island incident.2 According to Electrical World,
by 1995 nuclear plants will account for approximately 23 per-
cent of total generating capacity, nearly double the current
proportion of nuclear capacity.
'Electrical World, "30th Annual Electrical Industry Forecast,"
September 15, 1979, p. 62.
-------
II-6
Table II-5
STEAM-ELECTRIC CAPACITY
CATEGORIZATION BY FUEL TYPE
(capacity in gigawatts)
Coal Capacity
Number of Plants
Oil/Gas Capacity
Number of Plants
Nuclear Capacity
Number of Plants
1985
301.8
467
173.5
438
1990 1995
365.1
565
157.4
397
139.0 173.1
98 122
473.9
734
100.4
253
281.0
198
Source: Electrical World, Sept. 15, 1979,
and TBS estimates.
Coal capacity will clearly increase both in absolute terms
and as a percent of total capacity over the next 15 years. The
extent of this increase will depend on the increase in total
demand, the decrease in oil and gas capacity, and the future of
nuclear power plants. Given escalating oil prices and federal
government policies mandating conversion from oil to coal, coal
capacity will increase at the expense of oil and gas capacity.
To the extent that nuclear capacity additions fall short of
current projections, the shortfall will be made up by coal if
total capacity reaches projected levels.
FINANCIAL AND ECONOMIC DESCRIPTION
OF THE ELECTRIC UTILITY INDUSTRY
An understanding of the economic struture and operating
characteristics of the electric utility industry is important
to put in perspective the costs of the proposed regulations.
The following section will examine three key areas that will
influence the level of economic effects resulting from compli-
ance with the proposed regulations. These areas are industry
economics and financing, the present financial condition of the
industry as a whole, and company economics and financing.
-------
II-7
Industry Economics and Financing
The electric utility industry is the most capital-intensive
industry in the United States. Its current planned capital ex-
penditures amount to $34 billion in 1980.3 This figure repre-
sents about 16 percent of the total capital expenditures of
all U.S. business in 1980. During the next decade the electric
utility industry will require large amounts of capital for
system expansion and pollution control expenditures. From 1965
to 1978 the capitalization of the investor-owned sector of the
industry increased from $62.6 billion to $174.9 billion, or by
178 percent. In the 10 years from 1979 to 1989, the capitaliza-
tion of the electric utility industry will rise by a further
169 percent to $468.1 billion (1980 dollars). The industry
will spend over $381.2 billion during the next decade. To
finance these expenditures, approximately $222.0 billion will
have to be raised from the sale of bonds, preferred stock, and
common stock.
As a result of increasing costs of fuel, materials, and
labor, the average price paid by the consumer (omitting any
costs due to the proposed effluent limitations guidelines)
will rise from 45.9 mills per kilowatt-hour in 1980 to 7.3.5
mills in 1985. If the effects of inflation are removed, the
cost of generating electricity will remain relatively constant,
increasing only by 6 percent by 1985 and decreasing by approxi-
mately 4 percent between 1985 to 1995. The decrease in the
real cost of generating electricity between 1985 and 1995 re-
sults from a leveling off in the rate of increase in peak elec-
tricity demand. As a result of this leveling off, generating
capacity will be added at a slower rate and capital charges
will decrease.
The electric utility industry accounts for about one-
third of total expenditures for pollution control equipment
by U.S. industry. According to an annual survey of industry
spending plans by McGraw-Hill, the industry spent $2.9 billion
in 1979 and anticipates spending $3.6 billion in 1980 for air,
water, and solid waste control. Also according to the McGraw-
Hill survey, water pollution control expenditures in 1980 are
expected to decrease by approximately 7 percent to 872 mil-
lion from their 1979 level of $938 million. This level of ex-
penditure will amount to more than one-quarter of all spending
by U.S. industry for water pollution control.4
3
Electrical World, September 15, 1979.
4Electrical Week, May 26, 1980.
-------
II-8
Industry financial and operating projections through 1995
are shown in Exhibits II-6 through 11-12, and are summarized
in Table II-6. The exhibits and the table are "baseline" pro-
jections. That is, they exclude the impacts of the proposed
effluent limitations guidelines and the revised new source
performance standards for air as promulgated on June 11, 1979.
They assume that all power plants are in compliance with best
practicable technology standards.
Table II-6
BASELINE ELECTRIC UTILITY INDUSTRY
FINANCIAL AND OPERATING STATISTICS*
(dollar figures in billions of current dollars)
Total Capacity (GW)
Total Energy Sales (GWH X 103)
Total Capitalization?
Annual Operating Revenues
Average Consumer Charge
(mills per KWH)
Cumulative Capital Expenditures
from 1979 to Year
Cumulative External Financing
from 1979 to Year
19653 19753 1978
236.1 508.4 579
957.1 1,738.0 2,017
$62.6 $167.4 $219
$15.2 $46.9 $69
15.9 27.0 34
Includes both steam and non-steam sectors.
2
Investor-owned utilities' capitalization increased by 26
publicly owned utilities.
aSource: Statistical Yearbook,
Source: Exhibits 1 1-4 through
Edison Electric Institute,
11-10.
a 1985D 1990b
.3 750
.8 2,651
.0 $371
.9 $194
.6 73
$263
$147
percent to
1978.
.3 834.9
.8 3,183.1
.8 $701.6
.9 $329.0
.5 103.4
.0 $710.9
.0 $434.2
account for
1995b
1,003.8
3,776.8
$1,683.9
$590.3
156.3
$1,958.9
$1,292.2
Present Financial Condition of
the Electric Utility Industry
The electric utility industry's financial condition was
adversely affected by high interest rates and steep inflation
during 1979. Based on the Salomon Brothers 100-company index,
average electric utility stock prices fell by 7.2 percent in
-------
II-9
1979. Deducted from an average yield of 10.1 percent, this
decline resulted in an average total return of 2.9 percent.
This return compares to the average return on the Dow Jones In-
dustrial index of 10.2 percent and the Standard & Poors 400
Industrial Index return of 18.4 percent. The average market/
book value ratio of the 100-company electric utility index as
of December 31, 1979, was 78 percent, the lowest value since
mid-1975. Moreover, the interest rate on Moody's Aa rated
electric utility bonds issued in March 1980 was almost 14
percent, the highest rate in the history of the industry.
Prospects for the future are uncertain—an oil shortage
caused by political turmoil in the Middle East would directly
increase costs for many eastern utilities which rely heavily
on oil. Other utilities would be affected indirectly as tight
oil supplies spur inflation and as costs of alternative fuels
rise with increased demand. Higher costs of electricity could
reinforce the trend toward greater conservation of electricity
by consumers.
To improve its financial health, the utility industry will
have to budget its expenditures carefully. Sales are not ex-
pected to increase as rapidly as they did in the past, and the
cost of fuel and power plant construction will continue to rise
even in the absence of foreign supply problems. Some utilities
may find it difficult to finance all the construction projects
they would like; however, a reduction in demand forecasts and
high reserve margins as a result of the continued slow growth
in electricity sales may reduce the need for construction of
new capacity. Conversely, additional pollution control expendi-
tures increase the number of potential utility projects without
increasing the supply of capital.
Company Economics and Financing
The company is the basic financial unit of the electric
utility industry. It is at the company level that the costs of
the proposed effluent limitation guidelines will be financed.
Increased operating and capital costs will be aggregated by
the company and passed on to customers.
Company size can be measured in any number of ways, but
most common are operating revenues, generating capacity, and
number of customers. These factors are all related, however,
and the discussion here will focus on operating revenues.
The distribution of companies by operating revenue reflects a
high degree of concentration in the industry. While 87 percent
-------
11-10
of the companies have revenues below $150 million, these com-
panies account for only 17 percent of the generating capacity.
Companies with over $700 million in revenues account for less
than 2 percent of the companies and 31 percent of the generating
capacity.
The number of plants owned by a company is a function of
company size, and the number of plants owned by a company can
greatly influenc-e the impact of the effluent limitation guide-
lines. For a small company with one or two generating plants
the probability is that either all or none of the company facil-
lities will be affected. Larger companies with several gener-
ating stations will usually have a plant mix that results in a
less than universal effect.
Company size also often determines a company's financial
and operating strategy. Small companies frequently plan on
very little capacity expansion, expecting instead to meet sales
and demand growth by purchasing additional electricity from
other, larger companies. As a result, their planned level of
capital expenditures can appear disproportionately low compared
to those of large companies. Additional expenditures required
to comply with effluent limitations guidelines could cause a
relatively large percentage increase in construction expendi-
tures. Large companies usually have more ambitious capital
expenditure programs which would dilute the effects of addi-
tional expenditures for pollution control equipment.
ISSUES CONFRONTING THE
ELECTRIC UTILITY INDUSTRY
In addition to escalating fuel prices and government policy
which, as was noted above, are resulting in a changing mix of
fuel types in the industry, a number of other issues cause un-
certainty concerning the future of the industry. The major
such issues include:
• The effect of rising prices, conservation,
government energy policy, and load manage-
ment on the demand for electricity;
• The future of nuclear power;
• The difficulty in siting new power plants; and
• Coal conversion.
-------
11-11
Actual growth in demand in the past several years has been
lower than either the historical rate of growth in demand or
the rate projected by government agencies and the electric
utility industry. For example, since 1973 demand for electric-
ity has grown at an annual rate of 2.9 percent as compared to
7.6 percent in the six years prior to 1973. In 1978 and 1979
government and industry sources consistently overestimated
growth in peakload demand with projections ranging from 3.5 to
5.4 percent as compared to actual growth in 1979 of 0.6 percent,
In the future, numerous factors will continue to influence
demand growth and the exact outcome is uncertain. The cost of
electricity will continue to rise with increasing fuel and capi-
tal costs, both of which have consistently outpaced inflation.
In addition, government incentives for conservation and an in-
creasing public awareness of the need for conservation will
undoubtedly have some impact on energy use.
Incentives to increase the use of existing power plants
rather than build additional plants are becoming greater as new
plant sites become more difficult to find and as costs of new
plant construction rise. Load management will be one means of
increasing the use of available capacity. This approach will
involve increased use of plants during off-peak hours, accom-
plished through the use of rates which encourage off-peak use,
and the use of sophisticated methods to interrupt segments
of the load for short periods each day, thus reducing the over-
all peak.
The future of nuclear power is another important issue
facing the electric utility industry. Siting problems, regula-
tory difficulties, and the erratic operating performance of
some nuclear plants have increased the uncertainty involved in
estimating the cost of future nuclear power plants. Depending
on the assumptions used, nuclear power does not always have a
clear economic advantage over coal-generated power. While many
experts feel nuclear power could regain its advantage if the
regulatory and siting process were streamlined, it is unclear
when or if this will ever happen. In the meantime, many util-
ities are canceling orders for nuclear plants and building
coal-fired plants which will generate additional air and water
pollutants.
-------
11-12
The siting of new power plants, both fossil and nuclear,
has become an important issue in the past few years. The water
consumption, fuel handling and transportation problems, emis-
sions, safety considerations, and visual impact of a 1,000 MW
power plant make siting a difficult and lengthy process. The
regulatory proceedings required for new plant approval have
also become more complex and time-consuming. As a result, the
time from plant inception to operation has increased to ten
years for nuclear plants and seven to eight for coal plants.
These delays have substantially raised the price of plant con-
struction. The cost increases on new plants could limit the
amount of funds available for other expenditures, such as
pollution control equipment.
Finally, coal conversion will be a major issue facing
electric utilities. Rising oil and gas prices will act as the
major incentive for utilities to shift away from these fuels.
This trend will be reinforced by reductions in the use of oil
and gas mandated by the federal government. The Fuel Use Act
severely limits the use of oil and gas in new utility boilers,
and under the Power Plant Petroleum Conservation Act being
drafted, the federal government may mandate a 50 percent reduc-
tion in utility oil use by 1990. It is uncertain at this time,
however, how the cost of conversion to coal will be financed
and how the nation's coal supply and transportation network
will accommodate a greatly increased demand for coal.
-------
11-13
Exhibit II-l
NUMBER OF EXISTING STEAM-ELECTRIC POWER PLANTS
BY FUEL TYPE AND SIZE
(number of plants)
Fuel Type
Existing (1979)
Coal
Oil/Gas
Nuclear
Other
Total
0-25 MW
35
48
0
15
98
26-
100 MW
63
102
2
5
172
Plant
101-
200 MW
36
76
2
1
115
Size Categories
201-
350 MW
38
48
0
1
87
351-
500 MW
35
44
0
0
79
More Than
500 MW
145
111
34
1
291
\.
Total
352
429
38
23
842
Source: DOE Inventory of Powerplants (1979).
-------
11-14
Exhibit II-2
CAPACITY OF EXISTING AND NEW STEAM-ELECTRIC POWER PLANTS
BY FUEL TYPE AND SIZE
1978-1995
(gigawatts)
Fuel Type
Existing (1978)
Coal
• Oil/Gas
Nuclear
Other
Total
Additions
(1978-1985)
Coal
Oil /Gas
Nuclear
Total
Additions
(1986-1995)
Coal
Oil/Gas
Nuclear
Total
Total Additions
(1978-1995)
Plant Size Categories
26- 101- 201- 351- More Than
0-25 MW 100 MW 200 MW 350 MW 500 MW 500 MW Total
.46 3.46 5.59 10.47 14.77 192.61 227.37
.67 5.69 10.71 13.33 18.52 121.16 170.07
0 .16 .35 0 0 53.31 53.83
.14 .16 .13 .32 0 1.25 2.10
1.27 9.47 16.78 24.12 33.29 368.33 453.37
79.20
19.80
85.40
184.40
187.30
.20
142.10
329.60
514.00
Source: DOE Inventory of Powerplants,
-------
11-15
Exhibit II-3
DISTRIBUTION OF STEAM-ELECTRIC CAPACITY BY PLANT SIZE AND IN-SERVICE YEAR
Plant Age
Category
Pre-1960
MW
Percent of
Age Category
_
1961-1970
MW
Percent of
Age Category
Post-1970
MW
Percent of
Age Category
Total
MW
Percent of
Age Category
0-25
1,154
1
344
.3
20
.01
1,518
.3
26-100
6,656
5.6
2,157
1.6
1,135
.6
9,948
2
PI
101-200
12,926
10.8
4,052
3.0
1,543
.8
18,521
4
ant Size Category
201-350
17,362
14.5
6,570
4.8
3,942
2
27,874
6
351-500
16,749
14
9,630
7.1
7,539
3.8
33,918
7
>500
64,968
54
112,844
83
184,502
93
362,314
80
Total
119,815
100
I
135,597
100
198,681
100
454,093
100
Percent
of Total
Capacity
26
30
44
100
Source: DOE Inventory of Powerplants; 1979.
-------
11-16
Exhibit II-4
BASELINE PROJECTIONS
PTm GROSS ADDITIONS TO GENERATING PLANT
INCLUDING CONVERSIONS TO COAL AND OIL
(gigawatts)
1979
I960
I9BI
1982
1983
1984
I9B5
1986
198?
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
TOTM.
CAPrtCITV
414.9
639.1
656. B
663.9
705.3
728.1
750.3
766.1
777.3
790.5
811.4
835.1
861.6
891.3
924.7
962.0
1003.9
1050.9
1103.6
1162.6
TOTAL FOS5H
AtitiTNS. &UD10TAL
31.0
25.4
20.9
30.2
24.6
26.2
25.9
19.7
15.7
17.6
26.0
29.8
37.6
42.2
46.3
SI. 6
56.8
56.3
63.5
69.4
15.0
14.0
8.4
14.0
10. 1
9.3
12.1
6.8
4.9
9.1
22.6
27.2
29. 3
30.0
20.4
18.9
19.2
22.9
25.8
28.1
(.(Ml.
13.1
13.8
7.5
13.3
10. 1
9.3
12.1
6.8
4.7
9.1
22.6
27.2
29.3
30.0
20.4
18.0
19.2
22.9
25.8
28.1
Oil.
1.8
.2
.9
.7
.0
.0
.0
.0
.2
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
IMS
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
HUCLEiVi
9.3
8.5
8.6
14.5
14.3
16.6
13.6
12.4
10.2
7.8
2.8
1.0
6.5
10.3
24.0
11.6
35.5
30.6
34.4
37.5
HVHRO PUMPED PEflttR
5.7
.6
^ -i
.2
.1
.0
.0
.0
.0
• .0
* .0
" .0
.0
.0
.0
.0
.0
.0
.0
.0
' .3
1.7
2.J
.8
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
'.0
.0 .
.0
.0
.0
.8
.6
.»
.7
.1
.3
.2
.5
.6
_ y
.6
1.6
1.8
1.9
1.9
2.0
2.1
2.6
3.3
3.8
Source: TBS.
-------
11-17
Exhibit II-5
BASELINE PROJECTIONS
PTm TOTAL GENERATION BY DRIVER
INCLUDING CONVERSIONS TO COAL AND OIL
(billion KWH)
1979
1980
1981
1982
1983
1984
1965
1984
1987
1988
1989
1990
1991
1992
1993
1994
1995
1994
1997
1998
TOtrtl.
GEHER.
2295.0
2340.9
2472.0
2598.1
2702.0
2804. A
2914.0
30.71.8
3134.7
3255.9
3376.3
3497.9
3420.3
3747.0
387B.2
4013.9
4150.4
4291.5
4437.4
4568.1
COAL
IOAB.7
1088.9
1155.3
1223.0
1276.0
1321.3
1363.6
1435.2
1469.7
1557.8
1689.8
IB39.2
1985.1
2121.4
2194.8
2232.3
2262.7
2311.7
2359.7
2408.4
Oil.
401.2
376.5
371.0
356.0
336.2
319.4
301.5
265.6
272.2
268.9
241.2
211.6
175.7
140.5
108.0
87.9
69.6
57.3
45.7
35.6
GriS
207.4
195.6
194.6
189.1
183.3
176.9
170.7
166.7
163.6
158.8
141.6
123.4
100.4
78.2
56.3
45.4
33. 9
27.0
20.5
15.1
NUCUriR
276.9
340.6
392.8
466.6
539.5
621 .9
692.0
763.6
832.4
685.7
913.5
926.5
963.2
1012.4
1126.4
1265.3
1410.6
1528.9
1652.6
1778.9
HVriRI)
270.3
266.5
275.9
277.4
278.4
277.9
276.1
281.2
216.6
290. 2
293.8
296.1
295.4
292.9
218.6
281.7
273.7
266.9
259.3
251.1
fUHHK
34.7
39.2
47.5
50.6
51.2
51.6
52.2
53.3
54.8
56.1
57.4
58.4
58.8
58.9
58.6
57. B
56.7
55.9
54.8
53.6
PErtKER
33.7
33.3
34.8
35.3
35.4
35.5
35.7
36.3
37.4
38.3
3V. 1
40.6
41. B
42.0
43.5
43.4
43.2
43.9
44.7
45.6
-------
11-18
Exhibit II-6
BASELINE PROJECTIONS
ELECTRIC UTILITY INDUSTRY CAPACITY
(million KW and billion KWH)
197"
1980
198)
1992
1983
1994
1985
1986
1987
19S8
1989
1990
1991
1992
1993
1991
1995
PEAK
KU
410.7
4 1 4 . 4
439.3
45°. 0
470 1 7
501.3
524.3
547.4
571.5
596.6
422.9
650.3
678.2
707.4
737.8
769.6
801 :?
KUH
GEN
2295.0
2340.9
2472.0
25?9. I
2702.0
2804.6
2914.0
3021.8
3136.7
3255.9
3376.3
3497.9
3620.3
3747.0
3878.2
4013.9
4150.4
NET KUH
SALES
2098. ')
2130.2
2249.5
2364.2
2458.8
2552.2
2651.8
2749.9
2854.4
2962.9
3072.5
3183.1
3294.5
3409.8
3529.1
3652.7
3776.8
12/31
CAPACITY
616.8
63°.0
657.0
683.7
705.2
728.1
750.3
765.9
777.2
790.3
911.3
834.9
861 .5
891 .2
924.6
962.0
1003.8
TOTAL.
AIHiNS
31 .1
25 . 4
20.?
30.2
2*.«
26.2
25.9
19.7
15.7
17.4
26.0
29. 8
37.6
42.2
46.3
51.6
56.8
TOTAL
RETIRED
T T
'.'. • C_
3 . 1
3.2
3.2
3.3
3.3
3.8
3.9
4.4
4.4
4.9
6.1
1 1.1
12.5
12.?
14.3
14.9
-------
11-19
Exhibit II-7
BASELINE PROJECTIONS
PTm FUELS CONSUMED FOR GENERATION OF ELECTRICITY
INCLUDING CONVERSIONS TO COAL AND OIL
(conventional steam and peaking units)
TOTAL COAL OIL
GENERATION <(1ft TONS) (riH BBL5) (BCR
1979 2295.0 505.0 737.5 2382.9
1980 23-10.9 512.9 694.9 2254.0
1*9! 2472.0 544.0 638.0 22*6.7
!992 2598.! 571.5 663.6 2186.1
1983 2702.0 598.9 635.3 2115,2
l°84
1985
1986
1987
1988
1989
1990
1991
I 992
1993
1994
1995
1996
1997
1998
290
-------
11-20
Exhibit II-8
BASELINE PROJECTIONS
ELECTRIC UTILITY INDUSTRY FINANCIAL FORECASTS
(dollar figures in billions of 1980 dollars;
consumer charge in mills)
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1979
1980
1981
1982
1983
196-1
I9S5
198-6
1997
1968
1989
1990
1991
1992
1993
1994
1995
CUIP
19.23
51.64
59.56
55.74
53.87
48.22
41.86
42.55
52.04
67.38
93.07
102.16
117.33
131.32
143.88
155.87
167.05
CUriM
CE
20.31
53.35
89.16
124.90
158.04
189.04
217.88
247.53
292.58
326.97
381.23
4-14.96
516.70
595.48
682.36
778.21
382.03
CE
20.31
33.04
35.80
35.75
33.14
31.00
28.83
29.65
35.05
44.39
54.26
63.73
71.74
78.78
86.88
95.85
103.82
CUMM
- CUIP
31.53
58.0°
91.76
1 16.10
146.85
179.28
210.99
236.96
259. 29
284.35
318.04
356.52
405.53
461.62
526.22
599.42
680.52
CE -
CUIP
31-51
26.56
23.66
34.65
30.45
32.43
31.70
25.97
22.33
25.06
33.69
38.48
49.01
56.09
64.60
73.20
81.10
CIJHM
EX FIN
7.66
27.62
•19.91
71.97
90.77
tO/. 57
121.93
137.00
157.20
185.69
222.04
266.12
315.80
370.22
430.14
496.08
566.80
EXT
FIN
7.66
19.95
22.30
2 1 . 95
18.91
16.79
14.36
15.07
20. 19
' 28.50
36.34
44.09
49.68
54.41
59.92
65.94
70.72
CUHH
OPER
87.06
IS-!. 77
290. -1 2
40;>.<)3
519.61
644.65
773.58
904.49
1038.43
1181.17
1326.70
1474.79
1625.95
1785.10
1951 .03
2123.93
2304.79
OPER
REV
97.06
97 . 7 !
105.65
12.00
i;?.i<*
25.04
28.93
30.90
133.95
H2.75
145.53
148.09
151.15
159. 16
165.93
172.90
180.86
0*M
5J.9I
62. 9 1
7 1 . 33
76.36
79.36
85.56
88.29
88,23
69.62
97.56
-------
11-21
Exhibit II-9
BASELINE PROJECTIONS
ELECTRIC UTILITY INDUSTRY FINANCIAL FORECASTS
(dollar figures in billions of current dollars;
consumer charge in mills)
1979
1980
1981
1982
1983
1984
1985
1996
1987
1988
1989
1990
1991
1992
1993
1994
1995
1979
1960
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
CU.TP
45.16
51.64
64.86
66.16
69.64
67.63
63.29
69.28
91.68
128.56
170.87
226.95
281.49
340.28
402.64
471.10
545.27
CL'MM
CE
18.63
51.67
90.67
133.10
175.94
219.41
263.01
311.29
373.04
457.75
569.37
710.93
383.06
1087-18
1330.31
1620.00
1958.88
CE
18.63
33.04
38.99
42.43
42.84
43.48
43.60
48.23
61.75
84.71
111.62
141.57
172.13
204.13
243.13
289.69
338.88
CUHM
- CUIP
29. 92
55. -18
81.26
122.39
161.75
207. 23
255.16
297.45
336.80
384.63
•153.94
539.41
657.00
802.33
983.10
1204.33
1469.04
CE -
CUIP
29.92
26.56
25.77
41.13
39.36
45.49
47.93
42.29
39.35
47.83
69.31
85.48
117.59
145.34
180.77
221.23
264.71
CUriH
EX FIN
7.03
26.99
51 .27
77.32
101.76
125.32
147.03
171.58
207.16
261.53
336.28
•J34.22
553.42
694.42
862.10
1061.38
1292.22
EXT
FIN
7.03
19.95
24.28
26.06
24.44
23.56
21.72
24.54
35.58
54.37
74.76
97.94
119.20
141 .00
167.69
199.28
230.83
CUMH
OP Eft
7?.tT;
177.59'
292.6-*
425.59
577.07
752.43
947.36
1160.51
1396.52
1668.8?
1968.2-!
2297.22
2659.87
3072.27
3536.61
4059. 17
4649.51
OPER
REV
79.37
97.71
115.05
132.95
151.48
175.37
194.93
213.15
236.01
272.37
299.34
328.98
362.65
412.40
464.34
522.56
590.34
Ort
-»9.<6
62. 9 i
77.68
90.A4..t.
02.59
20.00
33.19
-13.67
57.91
8f>. l
-------
III. PLANT- AND INDUSTRY- LEVEL EFFECTS
OF THE PROPOSED EFFLUENT LIMITATIONS
GUIDELINES ON THE STEAM-ELECTRIC INDUSTRY
The economic effects of the proposed effluent limitations
on the electric utility industry were examined at two levels:
the individual power plant and the entire electric utility
industry. Economic effects at the company level were not ex-
amined separately because the cost of compliance for an indi-
vidual utility is simply the sum of the costs for all power
plants that it operates. These costs would be diluted by non-
steam generating facilities operated by the utility.
This chapter will present the results of both the plant-
level and industry-level analysis of the economic effects of
the proposed regulations. At this time the Agency is propos-
ing guidelines that require controls beyond BPT for the fol-
lowing waste streams: once-through and recirculating cooling
water from existing direct dischargers, recirculating cooling
water from existing indirect dischargers, and cooling water as
well as fly ash transport water from new plants. The remain-
ing waste streams are either being proposed with no additional
requirements beyond BPT or reserved for future consideration.
Since the cost of compliance with potential regulations on
the ash transport waters are much higher than those of the
proposed regulations, the costs and economic effects described
in this analysis represent only a small portion of the poten-
tial costs of effluent limitations guidelines for the electric
utility industry.
REGULATIONS
The proposed effluent limitations guidelines are incorpo-
rated in four separate proposed regulations: best available
technology, new source performance standards, pretreatment
standards for existing sources, and pretreatment standards for
new sources. The proposed standards will require the follow-
ing treatments:
• For once-through cooling water: a chlorine
minimization program at all direct discharg-
ing plants that chlorinate (approximately 334
plants) and, in addition, dechlorination at
all plants that fail to meet a standard of
0.14 milligrams per liter total residual
chlorine (TRC) through chlorine minimization
(167 plants).
-------
III-2
• For recirculating cooling water: declorination
at all direct discharging plants that chlorinate
(approximately 197 plants) and use of alterna-
tive chemicals at plants using scaling and cor-
rosion inhibitors and biocides containing the
129 priority pollutants.
• For other waste streams (ash handling waters at
existing plants, low volume and metal cleaning
wastes, boiler blowdown, and runoff from coal
piles and chemical handling areas): no controls
beyond those already required by BPT standards.
• For indirect discharging plants (those discharg-
ing into publicly owned treatment works): no
limitations on effluent chlorine concentrations,
but, as for direct dischargers, use of alterna-
tive biocides and scaling and corrosion inhibi-
tors at recirculating cooling water plants using
the 129 priority pollutants.
• For new plants: zero discharge of fly ash trans-
port water and cooling water limits similar to
those for existing direct discharging plants.
The following sections will describe the effects of requiring
these technologies first at the plant level and then at the
industry level.
PLANT-LEVEL EFFECTS
To determine the effects of the proposed regulations on
individual power plants, several model plants were developed to
represent a range of plant sizes, ages, and other character-
istics. The cost of generating electricity at each of the model
plants was calculated and the additional cost associated with
complying with the proposed regulations was then determined. Each
of these steps is described below.
Selection of Model Plants
Three criteria were used in the selection of model plants
for the plant-level analysis—size, age, and cooling system type.
As will be discussed below, these criteria were selected to en-
compass both those plants that would be most affected by the
proposed regulations and those plants that account for most of
the industry's generating capacity.
-------
III-3
Size
Since the costs of compliance with the proposed regulations vary
predictably with plant size, three plant sizes were examined—
25, 100, and 1,000 MW-1 The 25 and 100 MW plants were used
to identify economic effects on small plants which account for
a major portion of the total number of steam-electric plants.
For example, 56 percent of all steam-electric plants have capac-
ities of less than 350 MW. The 1,000 MW plants, on the other
hand, represent the less numerous plants with capacities greater
than 500 MW, which account for approximately 80 percent of the
industry's capacity.
Plant age is an important determinant of the plant-level
effects of the proposed effluent limitations guidelines. Three
major age-related factors influence plant-level compliance
costs:
• Retrofit premiums,
• Plant design, and
• Remaining depreciable lives.
A critical distinction in the analysis is that between new and
existing plants. In the future, plants will be designed taking
into account the proposed effluent limitations, avoiding retro-
fit premiums and design changes that the proposed guidelines
may necessitate for existing plants. Shorter depreciable lives,
on the other hand, differentiate recently built existing plants
from older plants.
Retrofit premiums are the costs over and above normal costs
of installing pollution control equipment which result from the
necessity of working around existing facilities and connecting
equipment to a facility which was not originally designed for
such equipment. In addition to these cost premiums, old plants
may be limited in the amount of land available on-site to house
newly mandated equipment.
The plant-level analysis for regulations not currently being
proposed is considerably more complex in that costs of compli-
ance with these regulations are much greater and vary less
predictably with plant size.
-------
III-4
Plant design may be considered a form of retrofit costs,
but it is useful to differentiate it from conventional retrofit
costs. In the case of plant design, additional costs result
not from the need to install pollution control equipment around
existing equipment, but from the need to change the operating
characteristics of the plant. Among the technologies considered
by the Agency, the clearest example of the influence of plant
design is dry fly ash handling. If existing plants were required
to install dry fly ash handling systems, they would incur the
substantial costs of removing existing wet systems and install-
ing dry systems. New plants, on the other hand, will incur no
additional costs by installing dry systems because the new plant
costs of the two systems are approximately equivalent. For this
reason, there is no incremental cost associated with the NSPS
requirement for dry fly ash handling.
The remaining depreciable life of a plant affects the
period over which the capital costs of pollution control equip-
ment can be amortized. The older the plant is when the effluent
limitations guidelines go into effect, the shorter the amortiza-
tion period for, pollution control equipment installed. A shorter
amortization period at a given interest rate results directly
in a higher annual capital cost of compliance with the proposed
regulations.
For purposes of the plant-level analysis, the age of exist-
ing plants was based on the median age of plants in each size
category in the DOE Inventory of Powerplants. A 25 MW new plant
was not considered because few plants smaller than 100 MW are
currently being built on a non-experimental basis.
Cooling System Type
Three different types of plants were analyzed at the plant
level—once-through plants that would comply through chlorine
minimization alone, once-through plants requiring chlorine
minimization and dechlorination, and recirculating cooling
water plants. Since indirect discharging plants would not be
required to meet chlorine limitations and very few indirect
discharging plants using priority pollutant-containing biocides
and scaling and corrosion inhibitors were identified by the
308 survey, indirect dischargers were not considered separately
in the analysis.
-------
III-5
Plants Selected for Analysis
The costs of complying with the regulations being proposed
by the Agency at this time do not vary by fuel type. Conse-
quently, fuel type was not an important criteria in the selec-
tion of model plants for this portion of the analysis. All
model plants selected were coal plants because this fuel type
accounts for 50 percent of the generating capacity in the steam-
electric industry. Only the baseline cost of generating elec-
tricity would have differed, however, if nuclear or oil and
gas plants had been selected for the plant-level study-
As shown in Table III-l, five plants were selected for the
economic impact analysis of the regulations currently being pro-
posed. The existing plants selected for analysis are 10 to 30
years old and have capacity factors of 25 to 60 based on industry
averages for those size categories. The two new plants examined
have a capacity factor of 60.
Table III-l
MODEL PLANT CHARACTERISTICS
Capacity
(MW)
25
100
100
1000
1000
In-Service
Year
1950
1950
New
1970
New
Capacity
Factor
25
25/50
60
60
60
Capacity factors for plants larger
than 100 MM based on industry-wide
averages as reported in Electrical
World, October 1, 1979, p. 59; for
plants smaller than 100 MW based on
comparisons of actual generation to
available generating capacity.
Determination of Baseline Costs
of Generating Electricity
Using the model plant physical and operating characteris-
tics described above, the cost of generating electricity at
each model plant was computed. Costs included:
• Capital related charges (depreciation and
interest),
-------
III-6
• Fuel expenses,
• Non-fuel direct operating and maintenance ex-
penses ,
• Indirect expenses (transmission, distribution,
and administration expenses), and
• Taxes other than income tax.
Since the majority of existing plants are expected to com-
ply with the proposed regulations in 1984, costs were projected
to 1984 in real terms. Capital related charges were annualized
on a pretax basis assuming a total plant life of 35 years using
the capital recovery method. These charges were then added to
annual fuel, operating and maintenance, transmission, distribu-
tion, and administration expenses and taxes other than income
taxes to obtain a total annual cost of generating electricity.
This cost was divided by total plant annual electric power gen-
eration based on the plant's capacity and capacity factor to
develop a cost on a per kilowatt-hour basis.
New plant baseline costs were developed using a similar
methodology. Construction on new plants was assumed to begin
in 1980 and the plants were assumed to commence operation in
1987. Table III-2 lists plant-level baseline costs for new
and existing plants.
Table II1-2
BASELINE COSTS OF GENERATING ELECTRICITY
AT MODEL PLANTS SELECTED FOR ANALYSIS
(1980 dollars)
Cost in Mills per
Kilowatt-Hour
Plant Capacity (MW) Fuel Type New Plants Existing Plants
25
100
1,000
1,000
Coal
Coal
Coal
Nuclear
53.1
44.6
39.4
36.7
33.0
25.0
21.8
Analysis of Plant-Level Compliance
Technical compliance costs for the various waste streams
were provided by the Agency's technical contractor. Exhibit III-l
lists the capital, operation and maintenance, and total annual
costs for the proposed technologies as used in this analysis.
-------
III-7
As shown in Table III-3, the costs of compliance with pro-
posed cooling water standards in no case amount to more than
3.5 percent of the cost of generating electricity. This cost
would be incurred by a 25 MW plant with a once-through cooling
system and instituting a chlorine minimization program as well
as dechlorinating. At the opposite end of the spectrum, the
largest cost incurred by a 1,000 MW plant would be less than
one-tenth of one percent of the baseline cost of generating
electricity.
INDUSTRY-LEVEL COSTS
This section extends the plant-level analysis of the ef-
fects of compliance with proposed effluent limitations guidelines
to the entire electric utility industry. The objectives of the
industry-level analysis were (1) to develop an accurate estimate
of the total costs to be borne by the electric utility industry
and its customers as a result of compliance with the proposed
effluent guidelines, and (2) to determine the effects of the
increased costs on the physical and financial operations of the
utility industry.
Methodology and Assumptions
TBS's approach to assessing the effects of the proposed
effluent limitation guidelines on the electric utility industry
consisted of the following basic steps:
• Develop baseline projections using TBS's Policy
Testing Model (PTm) of the electric utility
industry,
• Develop projections incorporating the proposed
effluent limitations guidelines, and
• Evaluate changes relative to baseline projec-
tions resulting from the additional levels of
regulation.
Baseline Projections
The baseline projections are a forecast of electric util-
ity industry financial conditions, assuming a continuation of
-------
III-8
ni anj.
r 1 ant
Capacity
(MM)
25
100
1,000
25
100
1,000
25
100
1,000
(
25
100
1,000
N/A = Not
Plant wi
Table III-3
INCREMENTAL PLANT LEVEL COSTS OF COMPLIANCE
WITH PROPOSED COOLING WATER STANDARDS
(1980 dollars)
New Plants Existing Plants
Mills per Percent of Mills per Percent of
Kilowatt-Hour Baseline Kilowatt -Hour Baseline
Once-Through Cooling Water
(chlorine minimization)
N/A N/A .405 1.10
.032 .077 .05/.10* .16/.31*
.003 .007 .003 .01
Once-Through Cooling Water
(chlorine minimization and dechlorination)
N/A N/A 1.27 3.46
.137 .26 .18/.42* .55/1.27*
.024 .05 .02 .08
Recirculating Cooling Water
(dechlorination)
N/A N/A .47 1.28
.033 .062 .06/.12* .18/.36*
.003 .008 .004 .02
Recirculating Cooling Water
use of alternative scaling and corrosion inhibitors)
N/A N/A .003 .008
.001 .002 .001/.002* .003/.006*
.001 .002 .001 .003
applicable.
th a 25 percent capacity factor.
-------
III-9
current regulatory policies but excluding any costs for water
pollution control other than the best practicable control
technology (BPT) currently available. These projections pro-
vide a benchmark for assessing the effects of the proposed
effluent limitations guidelines.
The baseline projections rely heavily on the following
assumptions:
• Overall growth in peak electricity demand at
an average of 3.1 percent per year during the
period 1980-2000.
• A changing fuel mix in the industry
—Oil and gas capacity declining by 46
percent by 1995 and generation by oil
and gas plants declining by 50 percent
in the same period as these plants are
utilized less intensively.
—Nuclear capacity maintaining a signifi-
cant share of overall generating capacity,
rising from 11.2 percent in 1980 to 28.0
percent in 1995.
The baseline does not include the cost of federal air pol-
lution control regulations for new power plants. No water pol-
lution control costs are included in the baseline other than
the costs associated with BPT. These expenses have been included
in the base capital cost of generation facilities and are not
separable.
Projections with Proposed Regulations
To assess the national effects of the proposed effluent
limitations guidelines, projections were made incorporating the
proposed regulation and suggested treatment technologies while
all other assumptions remained unchanged from the base case.
This approach was used to allow compilation of the costs
either by waste stream or by regulation (BAT, NSPS, or pre-
treatment).
Results of the National-Level Analysis
The purpose of the national-level analysis is to provide a
measure of the electric utility industry's cost of complying
with the proposed effluent limitations guidelines. The increases
over baseline projections of financial parameters attributable
-------
111-10
to the proposed effluent limitations guidelines can be used to
examine their economic effects. Four financial parameters were
selected for this analysis:
• Capital Expenditures—the increase in cumula-
tive capital expenditures for 1980 over the
baseline projections of cumulative capital
expenditures.
• Annual Revenue Requirements—the increase in
the annual revenues required by the industry
over baseline revenues to pay for pollution
control equipment. This parameter includes
revenues required to cover both annual capital
charges and operating and maintenance expenses.
• Operation and Maintenance Expenses—the increase
over baseline projections of operating costs.
• Average Consumer Charges—the increase in the
average cost per kilowatt-hour of electricity,
based on sales forecasts and projections of
revenue requirements.
Table III-4 lists the industry's baseline for the four financial
parameters described above for the years 1985, 1990, and 1995.
Table III-4
BASELINE PROJECTIONS FOR KEY
ELECTRIC UTILITY INDUSTRY FINANCIAL PARAMETERS
(dollar figures in billions of 1980 dollars)
Cumulative Capital
Expenditures from 1980*
Annual Revenue Requirements
Operation and
Maintenance Expenses
Average Consumer Charge
(mills/KWH)
1985
$217.88
128.93
88.29
48.62
1990
$444.96
148.09
99.49
46.52
1995
$882.03
180.86
100.63
47.89
Cumulative Capital Expenditures are for 1980-1985, 1986-1990,
1991-1995, and include AFDC.
Costs of Proposed Technologies
Treating cooling water from once-through cooling systems
with chlorine minimization and dechlorination will increase
-------
III-ll
capital costs by $70 million through 1985 and $90 million
through 1990. The increase in capital costs is no more than
0.03 percent of baseline capital expenditures in any period.
Revenue requirements, operating and maintenance expenses, and
consumer charges show similar increases, never exceeding four
one-hundreths of one percent of baseline figures for these
financial parameters (Table III-5).
Table
III-5
FINANCIAL EFFECTS OF PROPOSED EFFLUENT
LIMITATIONS GUIDELINES FOR ONCE-THROUGH
AND RECIRCULATING COOLING MATER
(increase over baseline in 1980 dollars)
Once-Through Cooling Water
(chlorine minimization and
dechlorination)
Cumulative Capital Expenditures
Millions of Dollars
Percent of Baseline
Revenue Requirements
Mi 11 ions of Dollars
Percent of Baseline
Operation and Maintenance Expense
Millions of Dollars
Percent of Baseline
Consumer Charge
Mills per KUH
Percent of Baseline
Recirculating Cooling Water
(dechlorination and alternative
scaling and corrosion inhibitors)
Cumulative Capital Expenditures
Millions of Dollars
Percent of Baseline
Revenue Requirements
Millions of Dollars
Percent of Baseline
Operation and Maintenance Expense
Millions of Dollars
Percent of Baseline
Consumer Charge
Mills per KWH
Percent of Baseline
1985 1990
$ 70 $ 90
.03* .02%
$ 30 $ 40
.02% .03%
$ 20 $ 30
.02% .03%
.01 .01
.02% .02%
$ 50 $ 60
.02% .01%
$ 30 $ 30
.02% .02%
$ 20 $ 30
.02% .03%
.01 .01
.02% .02%
1995
$130
.01%
$ 40
.02%
$ 40
.04%
.01
.02%
$ 70
.01%
$ 40
.02%
$ 30 •
.03%
.01
.02%
-------
111-12
The costs of treating cooling water from recirculating
cooling systems with dechlorination and, where necessary, using
scaling and corrosion inhibitors that do not contain the 129
priority pollutants are similar in magnitude to costs for once-
through systems. Cumulative capital expenditures increase by
$50 million in 1985 and an additional $20 million investment
is required through 1995, an increase of 0.02 to 0.01 percent
over baseline expenditures. Increases in revenue requirements,
operation and maintenance expenses, and consumer charges are
similarly low.
Most of the costs of the regulations being proposed at this
time would be incurred under BAT regulations. Compliance with
the proposed standards by existing direct discharging plants
would account for approximately 60 percent of the capital ex-
penditures incurred by the industry through 1995 as a result of
the proposed regulations. New plants covered by the proposed
NSPS regulations would account for the remaining 40 percent of
additional capital expenditures through 1995. The proposed
NSPS regulations also include a requirement for dry fly ash
handling. However, since the new plant cost of a dry fly ash
handling system is equivalent to that of a wet system, there
is no incremental cost associated with this NSPS requirement.
The proposed pretreatment standards do not include the most
costly component of the proposed BAT and NSPS standards—the
chlorine limits. Consequently, the only cost incurred by in-
direct dischargers is the minimal cost of using alternative
scaling and corrosion inhibitors.
Cost-Effectiveness of Proposed Technologies
The cost per pound of chlorine removal at plants with re-
circulating cooling systems is significantly greater than it
is at plants with once-through systems. As shown in Table III-6,
nationally chlorine minimization at all plants with once-through
cooling systems will, in 1985, remove 13 million pounds per year
of chlorine at a cost of $.77 per pound. Plants failing to meet
the 0.14 mg/1 standard and requiring dechlorination in addition
to chlorine minimization will remove an additional 4.4 million
pounds of chlorine annually at a cost of $4.55 per pound. Plants
with recirculating systems, on the other hand, would remove only
34,800 pounds of chlorine at a cost of $862.07 per pound.
The high cost of chlorine removal by dechlorination at
plants with recirculating cooling water results not from the
cost of the technology but from the low flow volumes of cooling
tower blowdown as compared to volumes from once-through cooling
systems. Information made available by the Agency's technical
-------
111-13
Table III-6
COST-EFFECTIVENESS OF CHLORINE REMOVAL TECHNOLOGIES
(1980 dollars)
Once-Through Cooling Hater
Chlorine Minimization
Dechlorlnatlon
Recirculating Cooling Water
Oechlorination
Millions of
Pounds of
Chlorine
Removed
(198S)
13.0
4.4
.03
Cost per
Pound of
Chlorine
Removed
0.77
4.55
862.07
contractor indicates that flow volumes for cooling tower blow-
down can be 100 to 300 times smaller than once-through cooling
water flows for plants with equivalent capacity. Chlorine con-
centrations are only slightly higher for plants with recircu-
lating systems. Consequently, although revenue requirements for
the three technologies are of the same magnitude, the smaller
quantities of chlorine removed at plants with recirculating
systems result in much higher costs per pound of chlorine re-
moved at these plants.
Under the proposed regulations, zinc and chromium would
be eliminated from recirculating cooling water waste streams
through the use of scaling and corrosion inhibitors not contain-
ing these priority pollutants. The cost of eliminating zinc
(73,000 pounds per year) is approximately $11 per pound and that
of eliminating chromium (17,000 pounds per year) is $53 per
pound. In addition 67,000 pounds of chlorinated phenols would
be eliminated by the use of biocides not containing the 129
priority pollutants. Since alternatives to these biocides exist
at approximately the same cost, there is no cost associated
with their use.
CONCLUSIONS
The regulations currently being proposed would not signif-
icantly affect the electric utility industry. None of the key
industry financial parameters examined increases by more than
one-tenth of one percent as a result of industry compliance
with the regulations and both the cost of generating electricity
and average consumer charges increase by one twenty-fifth of
one percent.
-------
111-14
Individual utilities and the industry as a whole should not
experience significant difficulties raising sufficient capital
to comply with the regulations. The maximum capital expenditure
potentially incurred by any single plant is $165,700 spent by
a 1,000 MW plant requiring both chlorine minimization and de-
chlorination. This figure compares to a $300 to $500 million
investment required for a recently completed 1,000 MW plant.
Nationally, while the $150 million industry capital expenditures
in the period 1980-1990 is not an insignificant sum of money,
it is dwarfed by industry baseline capital expenditures of $445
billion.
At the plant level the only plants that incur significant
increases in the cost of generating electricity are very small,
old plants used to provide power during periods of peak demand.
Since these plants generate only a very limited portion of an
individual utility's total electrical output, cost increases
incurred by them would not translate into equivalent increases
in consumer charges.
The only cost of the proposed regulations that appears sig-
nificant is the cost of chlorine removal at plants with recircu-
lating cooling systems. These plants incur one-half of the
annual national cost of chlorine removal, yet they account for
only 0.2 percent of the chlorine removed nationally. The regu-
lations requiring dechlorination at plants with recirculating
cooling systems are not economically burdensome; however, their
cost-effectiveness is much lower than that of regulations with
once-through cooling.
At this time the Agency is gathering more information con-
cerning ash transport waters. Control of these streams is sig-
nificantly more expensive than it is for cooling water streams.
For example, cumulative capital expenditures for dry fly ash
handling by existing plants would amount to $2.8 to $3.5 billion
(depending on the plant capacity cutoff selected) as compared
to $200 million for cooling water. The costs for dry fly ash
handling are examined in greater detail in TBS's April 1980
Draft Economic Analysis for the Revision of the Steam-Electric
Utility Industry Effluent Limitations Guidelines.
-------
Exhibit 111-1
COST OF TECHNOLOGIES FOR PROPOSED REGULATIONS1
(1980 dollars)
Plant Size
(Mw)
25
100
1,000
Plant Size
(Mw)
25
100
1,000
Once-Through Cooling Water
Chlorine Minimization
Annual
Operation and
Maintenance Cost
per Kilowatt
$.37
.09
.01
Capital Cost
per K 1 1 owatt
$1.45
.37
.04
Total
Annual Cost
per Kilowatt
$.89
.23
.02
Chlorine Minimization and Dech lor (nation
Annual
Operation and
Maintenance Cost
per K 1 1 owatt
$.80
.36
.08
Capital Cost
per K 1 1 owatt
$4.52
1.29
.17
Total
Annual Cost
per K 1 1 owatt
$2.81
.92
.13
Reclrculating Cooling Water
Dech 1 or 1 nation
Annual
Operation and
Maintenance Cost
per K 1 1 owatt
$.24
.06
.01
Capital Cost
per Kl 1 owatt
$2.45
.61
.06
Total
Annual Cost
per Kilowatt
$1.03
.26
.02
Alternative Scaling and Corrosion Inhibitors
Annual
Operation and
Maintenance Cost
per Kilowatt
$.07
.05
.04
~ A
Capital Cost
per Kl 1 owatt
$0
0
0
Total
Annual Cost
per Kilowatt
$.07
.05
.04
1Total annual costs Include annualIzed capital costs for existing plants and annual operation and maintenance costs.
------- |