U.S. DEPARTMENT OF COMMERCE
National Technical Information Service
PB-254 308
Economic and Financial Impacts of
Federal Air and Water Pollution
Controls on the Electric Utility Ind.
Temple, Barker & Sloane, Inc.
Prepared For
Environmental Protection Agency
.
May 1976
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EPA-230/3-76-013
ECONOMIC AND FINANCIAL IMPACTS OF
FEDERAL AIR AND WATER
POLLUTION CONTROLS
ON THE ELECTRIC UTILITY INDUSTRY
TECHNICAL REPORT
prepared for
ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF PLANNING a EVALUATION
TEMPLE, BARKER & SLOANE, INC,
15 WALNUT STREET
WELLESLEY HILLS, MASSACHUSETTS 02181
MAY 1976
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BfBLIOCRAPMlC DATA
SHEET
1. Report No.
EPA 230/3-76-013
4. Title and Subtitle
Economic and Financial Impact of Federal
Air and Water Pollution Controls on the Electric
Utility Industry - Technical Report
5. Report Date Date
May 1976 Issued
6.
7. Author(s)
Temple, "Barker and Sloane, Incorporated
8. Performing Organization Kept.
No.
9. Performing Organization Name and Address
Temple, Barker and Sloane, Incorporated
15 Walnut Street
Wellesley Hills, Massachusetts 02181
10. Project/Task/Work Unit No.
11. Contract/Grant No.
68/01/2803
12. Sponsoring Organization Name and Address
Office of Planning and Evaluation
Environmental Protection Agency
401 M Street, S.W.
Washington, D.C. 20460
13. Type of Report & Period
Covered
Final
14.
15. Supplementary Notes
16. Abstracts xhe study focused on the determination of changes in the financial profile of
the electric utility industry which are likely to result from federal air and water
pollution controls for the 1975-1990 period. The analysis provides operating and
financial projections at the national and regional levels as well as a detailed dis-
cussion of the financing needs and problems of the industry in the context of trends and
cycles in corporate business financing. In addition, the study includes an analysis of
the secondary impacts of the legislation on major industrial users of electricity.. The
research effort concluded that capital expenditures for plants in service will increase
by $25.0 billion (1975 dollars) during the 1975-1985 period, of which $19.3 billion
must be raised in the capital markets. The direct impact of the regulations upon the
average residential customer's electric bill will be an increase of $2.80 per month by
1985 (1975 dollars). Assuming the industry is able to pass on the costs of pollution
control equipment to its customers and offer investors a competitive return on equity
(approximately 14 percent). the industry will generally be able to obtain the financing
required. The study contains two parts: the firs
is an executive summary, bound separately; the
second is a six-volume technical report which
inol.udef) all methodological nnd annlytical deta11
17. Key Words and Document Analysts. 17a. Descriptors
17b. Identifiers/Open-Ended Terms
17c. COSATI Ficld/firoup
18. Availrtbility Stntrmcni
Release Unlimited
19. Security Clans (This
Hcpori)
JH*i
20. Sr.^niy rTnhS (TIiio
!'.«««•
1INC .I.ASSLI-MKP
CORM NTlO-nn (M(tv. in--MI KNIXWSI'.I) I1Y ANSI AND IINIvSCo.
THIS FORM MAY BK REPRODUCED
21. No. of "aprs
••USCOMM-DC 8263-P74
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FOREWORD
This report is the result of a major program of
studies sponsored by the Environmental Protection Agency
as part of its continuing effort to assess the economic
impacts of its regulatory programs. Unlike many of EPA's
other industry economic studies where the focus is on the
impact of a particular regulation, this study was aimed at
examining the combined effect of all of EPA's direct regu-
latory programs on the electric utility industry. This was
an ambitious objective and in some instances it was not
possible to take every regulation into account due to the
lack of data or the absence of final regulations; however,
it was possible to focus quantitatively on the most signif-
icant programs, primarily those dealing with air and water
pollution control.
In addition to providing an assessment of the
combined impact of EPA's regulatory programs, a major objec-
tive of this study was to advance the methodologies used
in previous studies so as to provide more accurate conclu-
sions as well as provide a better foundation for future
studies. This was done in many cases by making use of more
up-to-date or previously unused data in areas such as in-
dustry production cost and pollution control cost. However,
advances also may have been made in the basic analytical
techniques used for impact analysis.
In sponsoring this study the EPA wanted to make
an independent assessment of the electric utility industry.
Although the overall conclusions are endorsed by the Agency,
there may be instances in which technical judgments of the
contractor differ from those of the EPA. Similarly, assump-
tions used in the study that are of a policy nature should
not be construed as an indication of EPA policy intentions.
This report was prepared for EPA by Temple, Barker
& Sloane, Inc. of Wellesley Hills, Massachusetts under contract
number 68-01-2803. Additional copies are available through
the National Technical Information Service, Springfield,
Virginia 22151. Further information concerning this and
other economic studies conducted by EPA can be obtained
through the Office of Planning and Evaluation, U.S. Environ-
mental Protection Agency.
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TABLE OF CONTENTS
TECHNICAL REPORT
Preface (ix)
Structure of the Report (xi)
VOL, I CHARACTERIZATION OF THE ELECTRIC
UTILITY INDUSTRY DURING 1960-1975
1960-1965: Security and Prosperity 1-3
1966-1973: Uncertainty and Adversity 1-6
1974: The Nadir? 1-12
VOL, II NATIONAL BASELINE PROJECTIONS
1 INTRODUCTION AND SUMMARY OF BASELINE
CASE FINANCIAL PROJECTIONS FOR THE
ELECTRIC UTILITY INDUSTRY II-l
Approach II-l
Summary of Baseline Case Financial
Projections II-4
Comparison with Alternative Scenarios II-8
2 BASELINE DEMAND PROJECTIONS 11-13
3 BASELINE CAPACITY AND GENERATION
PROJECTIONS 11-18
Capacity 11-19
Capacity Factors and Generation 11-30
4 COST FACTORS 11-33
Capital Cost Factors 11-33
Operating and Maintenance Cost Factors 11-37
(iii)
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Paste
5 FINANCIAL POLICIES AND COSTS 11-42
Industry Structure 11-42
Capital Structure and Capital Costs 11-43
Accounting Practices 11-45
Taxes 11-46
VOL, III NATIONAL FINANCIAL IMPACTS
1 INTRODUCTION AND CONCLUSIONS III-l
HISTORY OF THE REGULATIONS AND
AMOUNT OF CAPACITY AFFECTED II1-4
History of the Clean Air Act
Regulations III-4
History of Federal Water Pollution
Control Regulations III-7
Capacity Impacted by Federal
Air and Water Regulations III-8
CAPITAL EXPENDITURES IMPACTS
OF AIR AND WATER REGULATIONS II1-20
Capital Expenditures by Regulation I11-20
Timing of Capital Expenditure
Requirements II1-22
Capital Expenditures by Type of
Pollution Control Equipment II1-23
Capital Expenditures to Make
up Capacity Losses II1-26
Other Air Regulations 111-28
OTHER FINANCIAL AND ENERGY IMPACTS II1-32
External Financing Requirements 111-32
Operation and Maintenance Costs 111-34
Operating Revenues and Consumer
Charges Impacts III-35
(iv)
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Page
Impact on the Average Residential
Bill for Electricity 111-36
Energy Impacts III-39
ASSUMPTIONS FOR ANALYSIS OF
THE AIR REGULATIONS II1-42
Capacity Affected by the Regulations 111-43
Capital Costs 111-48
Operation and Maintenance Costs 111-50
Capacity Loss/Energy Penalty 111-51
Financing 111-52
ASSUMPTIONS FOR ANALYSIS OF
WATER REGULATIONS III-53
Capacity Affected 111-55
Capital and Operation and
Maintenance Cost Estimates 111-65
COMPARISON OF CURRENT ANALYSIS OF WATER
REGULATIONS AND DECEMBER 1974 RESULTS II1-70
VOL, IV FINANCING IN CAPITAL MARKETS
1 INTRODUCTION AND SUMMARY CONCLUSIONS
CONCERNING ELECTRIC UTILITY FINANCING IV-1
Introduction IV-1
Summary Conclusions IV-2
2 RECENT TRENDS AND CYCLES IN
CORPORATE BUSINESS FINANCING IV-6
The Need for Corporate Financing IV-7
Corporate Sources of Funds IV-9
Inflation and the Need for External Funds IV-11
External Funds Raised in Financial Markets IV-13
The Cyclical Patterns of External Funds IV-14
(v)
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Page
The Changing Corporate Balance Sheet IV-15
Corporate External Funds Within
The Financial System IV-16
Corporate Financing in 1975 IV-18
FUTURE PROJECTIONS OF CORPORATE
FINANCIAL NEEDS IV-19
The Determinants of External Financing IV-19
Three Alternative Scenarios for
1975-1985 IV-22
Corporate External Needs in Competition
with Other Sectors of the Economy IV-26
The Supply and Demand for Funds
in Three Alternative Scenarios IV-29
Variations Within a Credit Cycle IV-34
Conclusions IV-34
ELECTRIC UTILITY INDUSTRY FINANCIAL
RESULTS AND FINANCING, 1960-1975 IV-36
1960-1965: Growth and Prosperity IV-36
1966-1973: Growth Without Prosperity IV-40
1974: Financial Nadir? IV-48
1975 IV-52
PROJECTIONS OF ELECTRIC UTILITY
INDUSTRY FINANCING, 1975-1985 IV-54
The Industry's Financing Requirements IV-54
Investor-Owned Electric Utility Needs
Versus Available Funds and Total
Corporate Needs IV-55
Projected Financial Strength of
Investor-Owned Utilities IV-60
Concluding Comments IV-66
(vi)
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FINANCING PROBLEMS OF INDIVIDUAL SYSTEMS IV-68
Three Categories of Financial Health IV-68
Intercompany Comparisons of Returns
and Interest Coverage IV-71
Determinants of Interest Coverage Ratios IV-75
Conclusions Concerning Electric
Utility Financing Problems IV-78
VOL, V REGIONAL IMPACT PROJECTIONS
1 INTRODUCTION AND SUMMARY OF REGIONAL
IMPACT PROJECTIONS V-l
2 REGIONAL BASELINE PROJECTIONS V-5
Operating Projections V-7
Financial Projections V-12
3 REGIONAL POLLUTION CONTROL IMPACTS V-19
Methodology V-19
Impact of Pollution Control Compliance
Measured by Consumer Charges V-21
Impacts Projected Region by Region V-23
Summary of Regional Capital Expenditures
and Operating and Maintenance Expenses V-41
VOL, VI SECONDARY IMPACTS
1 INTRODUCTION AND OVERALL CONCLUSION VI-1
Introduction VI-1
Overall Conclusion VI-1
2 IMPACTS ON THE MAJOR USERS OF ELECTRICITY VI-4
Methodology VI-5
Major Assumptions VI-8
Possible Refinement VI-10
(vii)
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IMPACTS UPON THE U.S. SULFUR INDUSTRY
AND ADDITIONAL SECONDARY IMPACTS VI-12
Sulfur Industry VI-12
Other Areas VI-26
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PREFACE
Th-is report has been submitted to the Environmental
Protection Agency in fulfillment of contract No. 68-01-2803
by Temple, Barker & Sloane, Inc., 15 Walnut Street, Wellesley
Hills, Massachusetts.
The research methodology employed in this study is
based on a computerized Policy-Testing model (PTm) of the elec-
tric utility industry. This model is one of a series of in-
dustry models developed by Temple, Barker & Sloane,Inc. (TBS) to
project the economic and financial implications of alternative
policy options in the form of industry structure, rates and
method of expansion, financial strategies, regulatory actions,
taxation policy, economic conditions, etc. PTm(Electric Util-
ities) was initially developed by Drs. Howard W. Pifer and
Michael L. Tennican, both of TBS, to assist the National Power
Survey's Technical Advisory Committee on Finance in preparing
its projections. It later served as the methodology for the
Environmental Protection Agency's evaluation of the economic
impact of its effluent guidelines upon the electric utility
industry.
TBS wishes to express its gratitude to the many
organizations and individuals who contributed to this study.
The work has benefited from the cooperation of the industry's
Clean Air Coordinating Committee and its predecessor, the
Utility Water Act Group. The comments of the many people in
EPA, other Agencies, and the industry who reviewed the earlier
versions of this report have also made a substantial contri-
bution to this final product. Particular thanks is due to
our project managers at EPA, James M. Speyer and James R. Ferry,
for the special efforts they also put into the study.
(ix)
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STRUCTURE OF THE REPORT
The scope of this study spans several aspects of
the general topic: the economic and financial impacts of
federal pollution control regulations on the electric utility
industry. Each major study area has become the subject of a
separate volume in order to segment the report into logical,
manageable pieces. The definition of the volumes and their
sequence in the report also reflect the TBS study approach.
The Executive Summary to the report has been printed under
separate cover. The volumes in this document are:
Volume I.
Volume II.
Volume III.
Volume IV.
Volume V.
Volume VI.
An historical overview of the electric utility
industry during the past fifteen years, in order
to provide a context in which to consider the
projections into the future.
The baseline projections (1975-1985) for the
industry before consideration of pollution con-
trol expenditures, to establish a basis for
estimating and evaluating future impacts.
The direct economic and financial impacts of
pollution control on the electric utility in-
dustry, in terms of capital expenditures, exter-
nal financing, operating expenses, and so on.
The ability of the industry to obtain the capital
financing identified in Volume III from the nation's
capital markets.
The regional variations in the direct impacts of
pollution control in the industry.
The extent of secondary impacts resulting from
the increased costs and the operation of pollution
control equipment in the industry.
(xi)
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ECONOMIC AND FINANCIAL IMPACTS OF
FEDERAL AIR AND WATER POLLUTION CONTROLS
ON THE ELECTRIC UTILITY INDUSTRY
VOLUME I
CHARACTERIZATION OF THE
ELECTRIC UTILITY INDUSTRY
DURING 1960-1975
MAY 1976
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VOLUME I
TABLE OF CONTENTS
Page
List of Exhibits (I-iii)
1960-1965: Security and Prosperity 1-3
1966-1973: Uncertainty and Adversity . 1-6
1974: The Nadir? 1-12
(T-i)
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VOLUME I
LIST OF EXHIBITS
Exhibit
1-1 Annual Growth in Peak Demand and Energy Sales;
Total Electric Utility Industry, 1960-1973
1-2 Selected Demand, Energy, and Capacity Statistics;
Total Electric Utility Industry, 1960-1974
1-3 Cost Per Kilowatt of Capacity—Newly Constructed
Plants; Total Electric Utility Industry,
1960-1974
1-4 Average Industry Heat Rates; Total Electric
Utility Industry, 1960-1974
1-5 Average Industry Fuel Cost Per Million Btu;
Total Electric Utility Industry, 1960-1974
1-6 Cost Per Kilowatt-Hour; Privately Owned Class
A&B Electric Utilities in the United States;
Electric Department, 1960-1973
1-7 Average Residential Bills and Overall Average
Revenue Per Kilowatt-Hour; Total Electric
Utility Industry, 1960-1973
1-8 Number of Customers and Average Kilowatt-Hour
Usage Per Customer; Total Electric Utility
Industry, 1960-1973
1-9 Assets Per Dollar of Revenue; Privately Owned
Class A&B Electric Utilities in the United
States; Electric Department, 1960-1973
(I-iii)
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VOLUME I
CHARACTERISTICS OF THE ELECTRIC UTILITY
INDUSTRY DURING 1960-1975
This volume briefly describes the changing character-
istics of the electric utility industry from 1960 to 1975.
This volume is intended as background for the projections
and analyses of the later volumes of this study.
Electrical energy is of major importance to the U.S.
economy. The use of energy in all forms in Othe United States
grew at an annual rate of 4.4 percent from 1960 to 1973.
During the same period, the use of electrical energy grew at
an annual rate of 7.3 percent. By 1974, electricity accounted
for approximately 23 percent of all energy used in the country,
up from 16 percent in 1960.
The sheer scale of the electric utility industry
causes its activities to be of major importance and concern.
The industry has large revenues: Investor-owned utilities,
which account for about 78 percent of total electric sales to
final consumers, had revenues of roughly $35 billion in 1974.
However, the industry is distinguished particularly by its
extremely high plant investment per dollar of revenue. Total
investor-owned electric utility assets, excluding the natural
gas assets held by combination gas and electric companies,
reached over $143 billion in 1974. Moreover, an increasing
portion of the industry's large annual capital expenditures,
over $16 billion in 1974, in recent years has been financed
from external sources.
Although most of the published commentaries on the
industry focus on investor-owned companies, the electric utility
industry also comprises publicly-owned and cooperative systems.
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1-2
In number, almost two-thirds of the 3,500 separate electrical
systems in the United States are publicly owned. A few of the
federal and state systems—such as the Bonneville Power
Authority, the Tennessee Valley Authority, and the County
Public Utility Districts in the state of Washington—generate
enormous amounts of electricity and are, in fact, large sup-
pliers to investor-owned systems. However, most of the
publicly-owned and cooperative systems in the country are
small entities engaged in distribution only. In contrast,
the approximately 500 investor-owned companies account for
nearly 79 percent of the generating capacity, total assets,
and electrical generation. Publicly-owned systems have nearly
a 20 percent share of capacity, assets, and generation. Co-
operative systems account for under 2 percent of capacity,
assets, and sales. There has been a slight shift toward
investor-owned and cooperative and away from publicly-owned
utilities over the past fifteen years, but this change has
been very small.
In this report, the historical analysis will focus
primarily on the investor-owned systems, for which data are
readily available. The projections of future industry capital
expenditures and financing needs will, however, cover all
sectors of the industry and are presented in Volumes II and III
of this report. The access to and the costs of financing dif-
fer, of course, across public and private firms. The potential
problems of the investor-owned utilities in raising capital in
the future will be of primary concern in Volume IV.
Until the mid 1960s, the electric utility industry
had enjoyed a record of steady and predictable growth.
In the latter half of the 1960s, however, a multiplicity of
changes began to upset the industry's dependable historical
trends, and uncertainty began to envelop the entire process of
decision making in the electric utility industry.
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1-3
The result of this uncertainty was an end to both
predictability and relatively secure decision making. In
their place has come genuine concern over the most appropriate
way to meet the demands and challenges now facing the industry.
1960-1965: SECURITY AND PROSPERITY
The early 1960s was a period of decreasing costs of
electrical energy, of increasing electricity consumption, and
of general prosperity for the electric utility industry. The
yearly growth in kilowatt-hour sales during the 1960-1965
period ranged narrowly between 5.5 percent 'and 7.7 percent,
averaging 6.9 percent (Exhibit 1-1). The industry's growth
in peak demand, and hence in its need for capacity, was similar,
as is also shown in Exhibit 1-1. Thus, despite construction
lead times of several years for new generation capacity, the
industry could predict future demand well enough so as to be
assured of meeting that demand without having to build large
amounts of excess capacity. At the company level there was,
of course, more variability in demand, but even there much of
the variation was the result of relatively predictable factors
such as the growth in population, the growth in industrial
activity, and the like.
Evolutionary technical changes in the design and
operating performance of generation equipment took place
during this period. (Nuclear technology was on the horizon,
but few substantial orders were placed until 1965.) The
changes mostly took the form of increasing unit size and in-
creasing operating pressures and temperatures, which enabled
scale efficiencies in construction and decreased heat rates
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1-4
in operation. The declining trend in costs per kilowatt
of capacity over this period is shown in Exhibit 1-3.
Because of the industry's rapid growth, which in
turn was stimulated by the declining real price of electrical
energy, the newer equipment rapidly accounted for a major
proportion of the industry's total generation capacity. Thus,
the design advantages of the new capacity, coupled with de-
clining fuel costs, enabled the industry to hold constant or
reduce fuel and other generation costs and generation-re-
lated depreciation charges per kilowatt hour despite general
2
price level increases (see Exhibit 1-6).
Exhibit 1-6 also shows that during this period
transmission expenses, distribution expenses, general selling
and administrative costs, and taxes also trended downward.
The operations and maintenance cost decreases reflect the
net effect of a variety of factors, including technological
improvements and increasing electrical consumption per cus-
tomer. What is most important is that the industry's total
cost per kilowatt-hour declined significantly from 1960
to 1965.
Because of regulatory controls on the industry's
earnings, the industry's declining costs were accompanied
by almost commensurate declines in the average prices paid
by consumers (see Exhibit 1-7). It should be noted that
ratet a measure of a generating station's efficiency in converting
thermal energy to electric energy* is the number of British thermal units
in the fuel required to generate one kilowatt hour.
2The data in this exhibit and all subsequent references to balance sheet
and income statement items show adjustments by TBS to reflect only
the electric operations of combination gas and electric companies.
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1-5
the cost of any given amount of consumption declined only
slightly, as is shown in Exhibit 1-7. However, to promote
the use of electricity and reflect the relatively low in-
3
cremental costs of supplying more energy to a typical customer,
the industry's price structure reflected substantial decreases
in the price per kilowatt-hour with increasing amounts of
consumption per period. As a result, as consumption per customer
increased (see Exhibit 1-8), average revenues per kilowatt-
hour decreased.
Because increases in the numbers of customers
(extensive growth) and increases in the average kilowatt hour
usage per customer (intensive growth) more than offset
declines in revenues per kilowatt hour, the industry's total
revenues grew at a rate of 5.8 percent from 1960 to 1965, or
from $10.1 billion to $13.4 billion (Exhibit 1-9). As shown in
Exhibit 1-8, the number of customers grew at a rate of 2.2
percent from 1960 to 1965, while the kilowatt-hours sold per
customer grew at a rate of 4.6 percent per year, far out-
weighing the 1.2 percent decline experienced in revenues per
kilowatt-hour (Exhibit 1-7).
These years were good ones for the electric utility
industry: problems were predictable and manageable, uncer-
tainty was at a minimum, and all the factors underlying prosperity
Customers whose increased energy consumption acme at the time of a utility's
peak demand would, of course, receive high incremental costs. For a
discussion of the costs of service as a function of a customer's time
profile of consumption, the supplying system's demand profile, etc.,
see, for example, TBS's study for the Federal Energy Administration,
A Study of Electric Utility Costs, Demand, and Rate Structures, 1975
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1-6
4
were operating in favor of the industry. These years also
were good ones for consumers of electricity because the price
per kilowatt-hour was declining. All that would change, but
few anticipated that from the vantage point of the early 1960s.
1966-1973: UNCERTAINTY AND ADVERSITY
Beginning in 1966, a number of adverse changes oc-
curred which had severely affected the industry's situation by
the end of 1973. The prosperous and predictable nature of the
electric utility industry changed for the worse; relative
certainty was replaced by uncertainty and a difficult environ-
ment. The changes affecting the industry did not happen all
at once and did not stem from the same root. Rather, the in-
dustry was beset over a relatively brief period of time with
trends which were gaining momentum in the last half of the
decade. Five of these were to have a dramatic and disastrous
effect on the industry as it moved into the 1970s.
The Credit Crunch
While it can be argued that the cost of money was
destined to go up anyway as the economy began to overheat in
the late 1960s, the credit crunch of 1966 caused a dramatic
rise in the cost of money. As an example, Moody's industrial
bond rate, which by 1965 had remained virtually constant for
seven years, rose steadily from 1966 until, in 1970, the
bond rate was almost double what it had been five years
earlier. The cost—and ultimately the availability—of debt
had obvious implications for the electric utility industry.
4~
^Earningss capital expenditurest cash flow,, and financing considerations
are discussed in detail in Chapter 4 of Volume IV, "Electric Utility
Industry Financial Results and Financing."
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1-7
Inflation
Chronic inflation had been an irritant in the
economy for some time, but by the late 1960s the rate of
cost increases for most companies was outrunning productivity
gains. Most important for electric utilities, inflation was
particularly felt in the capital goods industries, thereby in-
creasing the cost of building new utility plants—an event
destined to have a significant effect on the utility companies.
Equipment Shortages
Parts and equipment shortages began to appear during
the second half of the 1960s. Much of this was due to capacity
shortages in an overheated economy. The result for the electric
utility industry was delays in new plant construction, with
the attendant higher ultimate costs that such delays in-
variably bring: higher capital costs because projects re-
quired longer financing prior to being placed in service, and
higher interim operating costs because newer, more efficient
plants did not get on stream when expected and utilities were
forced to rely on more costly older plants or more expensive
purchased power in the meantime.
The Environmental Movement
The momentum of the environmental movement increased
greatly in the late 1960s. While it can be argued that the
costs of electricity--and hence electric rates—had never
reflected true "environmental costs," the impact of this
movement was felt in three principal ways. First, it affected
the cost of fuel to electric utilities as state and local govern-
ments placed sulfur restrictions on fuels. Second, environmental
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1-8
protection hearings caused delays in the construction programs
of many utilities, causing higher labor, administrative, and
financing costs and slowing down the retirement of older,
high-cost generating plants beyond planned dates. Finally,
the installation and operation of pollution control equipment
aggravated the capital and operating cost problems beginning
to afflict the industry.
Fuel Cost Increases
The cost of fuel always has been an important com-
ponent in the cost of electric power. Until the latter part
of the 1960s, cost trends were downward. Productivity improve-
ments in the coal industry, together with an abundant supply
of interruptible and off-peak gas, kept the prices of fuel
down. Then the cost of all fuels began to rise. The closing
of the Suez Canal in 1967 caused tanker rates to increase,
and at about the same time the oil exporting countries began
upward revisions in both posted prices and taxes. The result,
of course, was higher-priced oil. The price of coal also began
to increase, spurred by the rise in the price of oil and also
by th© neod for Investment to ;lmprovo health and safety con-
ditions and by the rise in foreign demand for metallurgical
coal. Finally, the Federal Power Commission began to permit
increases in the price of interstate natural gas. This ob-
viously affected those utilities dependent on that fuel source,
but it also relieved the competitive pressure on alternative
fuels, thereby allowing the prices of coal and oil to rise.
Thus, the impact of the credit crunch, inflation,
equipment shortages, the environmental movement, and fuel cost
increases—all events that were emerging in the late 1960s—
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1-9
combined to change dramatically the prosperous and predictable
future of the electric utility industry.
The events of the late 1960s resulted in a significant
change in the nature of the electric utility industry. The
industry had entered into a period of growth without prosperity--
a period, in fact, where growth was responsible for much of
the lack of prosperity. The most significant changes occurred
in three major areas: the rate of growth in energy usage and
in peak demand; the increases in capacity additions and in
the unit cost of capacity; and the increases in operating and
interest costs.
Energy and Peak Demand
The industry continued to grow in the late 1960s
and early 1970s. From 1966 to 1973, the annual growth in
demand increased both in level and in uncertainty as compared
to the early 1960s. The range in peak demand growth from 1966
to 1973 was from 5.0 percent to 11.5 percent, averaging 8.1
percent. Similarly, energy consumption growth rates ranged
from 5.4 percent to 9.0 percent from 1966 through 1973,
averaging 7.1 percent (see Exhibit 1-1). The increased un-
certainty in the electric utility industry's growth was per-
haps undramatic compared to the problems of predicting demand
in many other industries. The consequence of this level of
uncertainty in the electric utility industry was nonetheless
important because the construction of the nuclear units then
being planned required ~a lead time of approximately ten years.
Even small differences in compound growth rates over such a
Energy is the total amount of electricity used over a period of time;
it is expressed in kilowatt-hours.
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1-10
period result in large differences in projected capacity
requirements at the end of the period.
Capacity Additions and Unit Costs
The increased average growth rate of peak demand
over the 1966-1973 period increased the rate of capacity
additions and consequent capital expenditures. A partial
offset was reduced reserve margins in generating capacity
resulting, in part because of unanticipated delays, in
bringing new capacity into service (see Exhibit 1-2). None-
theless, capital expenditure requirements burgeoned because of
the industry's rapid rate of capacity additions and because of
rapidly escalating average costs per kilowatt of capacity.
Two factors brought about a dramatic rise in the
cost per kilowatt of capacity after 1966. First, fossil-
fueled units began to reach a size at which efficiencies of
scale diminished or disappeared. Second, the industry
began to build nuclear units, which involved higher capital
costs and longer construction lead times. Exhibit 1-3 high-
lights the particular problem experienced with nuclear fueled
generating units: The cost of these units escalated at
spectacular rates. As a consequence, average costs per kilo-
watt increased substantially—despite the inclusion in these
averages of a number of internal combustion peaking units with
low capital costs (see Exhibit 1-3).
Operating and Interest Costs
The industry was able to maintain relatively constant
operating costs per kilowatt-hour over the entire decade of
the 1960s, but this trend turned around abruptly in 1970
(Exhibit 1-6). Until 1970, economies of scale and technological
-------
1-11
improvements permitted the industry to reduce or to hold
constant generation, transmission, and distribution operations,
and maintenance costs other than fuel costs. Fuel costs per
Btu declined or held relatively constant as coal productivity
increased and as users of coal with high transportation costs
switched to cleaner and often lower cost residual oil. In
addition, the ceiling on natural gas prices imposed by the
Federal Power Commission (FPC) held this fuel at a very low
cost. (See Exhibit 1-5 for fuel cost trends.) Finally,
because of accelerated depreciation and investment tax credits,
income taxes decreased over: the decade. (See Exhibit 1-6
for more detail.) In 1970, however, surging fuel costs and
general inflationary pressures increased the cost per kilowatt- .
hour for the first time since World War II. Moreover, as is
shown in Exhibit 1-4, no longer did decreasing heat rates help
offset the effect of higher basic fuel costs. Thus, from 1969
to 1972, the escalation in total costs per kilowatt-hour was
quite rapid, rising from 1.49 cents to 1.73 cents per kilowatt-
hour.
Interest costs also grew rapidly during the 1966-1973
period, from $903 million in 1966 to $3.15 billion in 1973. This
increase reflected the combined impact of two factors: first,
much higher interest on new debt issues than the rates on out-
standing debt; and second, substantial increases in the industry's
volume of outstanding debt.
Thus, several factors had turned against the industry
by 1973 and created a financial dilemma: prosperity no longer
automatically accompanied growth, and financing growth in a
way equitable to investors and consumers alike became a critical
issue. The year 1974 offered no solutions.
-------
1-12
1974; THE NADIR?
The electric utility industry data for 1974 make
it painfully clear that the ill winds of the previous several
years blew with hurricane force in 1974. Bludgeoned by the
quantum increases in most fossil fuel prices following the
Arab oil embargo in late 1973, exhorted by government and in-
dustry officials to conserve energy, and perhaps mindful of
the accelerating problems of the U.S. economy, consumers held
their use of electrical energy to levels almost identical
to those of 1973. In fact, Usage per customer declined in
1974. Total residential consumption increased only 0.1 per-
cent, total commercial usage dropped 1.1 percent, and total
c
industrial sales grew only 0.3 percent. The industry's
rate of growth in summer peak demand also declined sharply to
1.6 percent, but not enough to avoid a decline in the indus-
7
try's load factor. As a consequence, although a few fore-
casters held tenaciously to the belief that the industry's
growth rate in energy and demand soon would return to its
previous track, most members and observers of the industry
were left with a pervasive uncertainty concerning the future—
a fear that the industry's peak demand would grow more rapidly
than its energy output, further reducing load factors.
Capacity additions for 1974 had been determined
years before by construction programs—and industry capacity
was increased by 7 percent during th© year. This new capacity,
i
together with the lack of growth in energy sales, caused a ma.ior
deterioration in those factors measuring utilization: the
industry's reserve margin increased to 27.2 percent from 20.8
percent the year before, and the highest annual reserve margin
£*
Source and Disposal of Electricity* Volume 42, Edison Electric Institute.
j
Electric Power Survey, Edison Electric Institute^ October 1974.
-------
1-13
since 1963; the capacity f actor--perhaps the best measure of plant
utilization—fell to 48.1 percent from 51.3 percent the year before
and held its lowest level in at least 15 years (see Exhibit 1-2).
Operating costs and interest costs also did not
fare well in 1974. While the heat rate improved slightly,
the cost of fuel increased by a quantum amount. Fuel costs—
driven by a more than doubling in the price of oil—reached
89 cents per million Btu, almost doubling the 1973 cost.
As a result, total operating costs sustained a sizeable
increase—up 45 percent in one year. Similarly, interest
charges for the industry increased 28 percent in 1974 from
the year before as the embedded interest rate increased from
5.95 percent to 6.38 percent.
As mentioned earlier, net industry capacity increased
7 percent in 1974 over the earlier year. This was accompanied,
however, by another large increase in the cost per unit of
installed capacity—from $195 to $266 per kilowatt, a 36 per-
cent increase—so the impact on financial requirements and
on existing book investments was proportionately larger than
the capacity additions of the year before.
Complete data for 1975 are not yet available, but in-
formed estimates provide an indication of what the operating
situation may have been for the industry. The highlights
of 1975 are outlined below:
• Electricity consumption increased about 2 percent
above levels experienced in 1974
• Peak demand increased a "nominal" amount during
the year—probably about the same as energy con-
sumption
-------
1-14
• Generating capacity increased 7 to 8 percent,
implying that additions in 1975 were about the
same as in 1974
• Utilization factors fell further in 1975 from
the very low levels of 1974
- The reserve margin probably increased to above
30 percent from the 27.2 percent figure achieved
the year before
- The capacity factor probably fell to below 46
percent from 48.1 percent in 1974
• Operating costs once again increased significantly
in 1975
- Fuel costs—which account for two-thirds of
total operating and maintenance costs—reached
102 cents per million Btu, a 15 percent in-
crease, over 1974
- Stringent cost-cutting programs begun in 1974
were continued in 1975, so that operating and
maintenance costs (ex-fuel) probably went up
less rapidly than wage rates in 1975
• Interest rates for the industry on new long term
debt issues declined in 1975 by about three-fourths
of a percent.
Thus, both good news and bad news about the industry's
operating factors emerged from 1975. Clearly, some of their
cost trends either had been reversed or at least had been
slowed, and consumption of electrical energy resumed some
growth, albeit small. But some major cost trends were still
unfavorable, caused in part by low utilization rates.
-------
Exhibit 1-1
ANNUAL GROWTH IN PEAK DEMAND AND ENERGY SALES
Total Electric Utility Industry
1960-1973
Years
1960-1961
1961-1962
1962-1963
1963-1964
1964-1965
1961-1965 Growth Rate
1965-1966
1966-1967
1967-1968
1968-1969
1969-1970
1970-1971
1971-1972
1972-1973
1966-1973 Growth Rate
Growth in Peak Demand
of Kilowatts (%)
6.0*
7.3*
6.6*
8.5*
6.5
7.0
9.2
5.0
11.5
8.3
6.6
6.4
9.3
7.8
8.1
Growth In
Kilowatt-Hour
Sales (%">
5.5
7.7
7.1
7.2
7.1
6.9
9.0
6.5
8.6
8.7
6.4
5.4
7.6
7.9
7.1
I
h*
Oi
*In 1960, '1962, and 1963 there was a December non-coincident peak load.
Growth is calculated on actual peak and not summer peak of Exhibit 12.
Source: Statistical Yearbook of the Electric Utility Industry,
Edison Electric Institute, 1973
-------
SELECTED DEMAND, ENERGY, AND CAPACITY STATISTICS
Total Electric Utility Industry
1960-1974
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
Capacity at
Time of Summer
Peak Load (UW)
170,600
184,700
193,600
205,300
216,500
228,900
240 , 700
257,950
278,950
300 , 300
326,900
353,250
381,700
415,500
444,400
Non-Coincident
Summer Peak
Load (MW)
132,800
141,000
149 , 050
159,450
175,000
186,300
203,350
213,450
238,00
257,650
274,650
292 , 100
319,150
343,900
349,250
Output (KWH in
Millions)
764,900
799,800
860,200
921,800
986,800
1 , 060 , 100
1,152,900
1,221,500
1,327,200
1 , 446 , 00
1,536,400
1,617,100
1,752,200
1,868,800
-Jr.871.7QQ
Reserve
Margin %
28.5
31.0
29.9
28.8
23.7
22.9
18.4
20.8
17.2
16.6
19.0
20.9
19.6
20 . 8
27.2 __„
Capacity
Factor %
51.0
49.4
50.7
51.3
51.9
52.9
54.7
54.1
54.2
55.0
53.7
52 . 3
52.3
51.3
_ 4S - *
Load
Factor %*
65.6
64.8
70.1
66.0
64.2
65.0
64.7
65.3
63.5
64.1
63.9
68.2
62.5
62.0
_61.2
"Source:
Non-coincident summer peak load x number of
Statistical Yearbook of the Electric Utility Industry,
Institute, Table 6S, 1973.
hours in the year
Edison Electric
H
t
I?
-------
1-17
Exhibit 1-3
COST PER KILOWATT OF CAPACITY—NEWLY CONSTRUCTED PLANTS
Total Electric Utility Industry
1960-1974
i
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
Growth Rate
1966-1974
In-Service
Cost
All
Plants
$135
106
139
144
116
109
85
118
128
149
141
137
180
195
266
10.4%
In-Service
Cost
Nuclear
Plants
$138***
—
410***
382***
—
—
—
156
190
213
147
155
183
260
354
12.4%****
Estimated
Cost as of
Order Date,
Nuclear
Plants *
n.a.
n.a.
n.a.
n.a.
n.a.
$119
121
146
157
209
222
300
404
456
558
18.7%
Revised
Cost
Estimate as
of 1974,
Nuclear
Plants **
n.a.
n.a.
n.a.
n.a.
n.a.
$199
260
354
413
395
370
475
458
456
558
12.1%
n.a. = not available
*Cost per KW for nuclear plants estimated at time order placed
for all units ordered in the year in table,
**Cost per KW for nuclear plants based on best information
available in 1974 for all units ordered in the year in table.
***Based on very small sample
****1968-1974
Source: Steam Electric Plant Construction Cost 1972, Federal Power
Commission; Power Engineering (August 1974)
-------
1-18
BTU PER
KILOWATT
HOUR
10,800 I—
10,700
10,600
10,500
10/100
10,300
10,200
10,100
EXHIBIT 1-1
AVERAGE INDUSTRY HEAT RATES
TOTAL ELECTRIC UTILITY INDUSTRY
1960 - 1974
I I I I 1 I I I I I I I 1 1 1
1960 1962 1961 1966 1968 1970 1972 1971
Source: Edison Electric Institute, Statistical Yearbook of the
Electric Utility Industry
-------
1-19
EXHIBIT 1-5
AVERAGE INDUSTRY FUEL COST PER MILLION BTU
TOTAL ELECTRIC UTILITY INDUSTRY
1960 - 197
-------
Exhibit 1-6
COST PER KILOWATT-HOUR
Privately Owned Class A&B Electric Utilities in the United States
Electric Department
1960-1973
(cents)
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
Total
Cost
1.63
1.63
1.60
1.57
1.54
1.51
1.49
1.48
1.48
1.49
1.55
1.65
1.72
1.84
Operating and Maintenance
Trans- Distrit-
Fuel Generation mission bution
.29 .19 .03 .15
.29 .19 .03 .14
.29 .19 .03 .13
.28 .19 .03 .13
.28 .19 .03 .13
.27 .19 .02 .12
.28 .19 .02 .12
.28 .20 .02 .12
.29 .20 .02 .11
.30 .21 .03 .11
.35 .22 .03 .12
.41 .25 .03 .12
.44 .26 .03 .12
.50 .29 .03 .12
General
Selling &
Adminis-
tration
.21
.21
.21
.21
.20
.20
.19
.18
.18
.18
.18
.19
.19
.19
Depreciation
and
. Amorti-
zation
.21
.21
.21
.21
.21
.21
.20
.20
.20
.20
.20
.21
.21
.22
Non-
Income
Taxes
.20
.19
.19
.19
.19
.18
.18
.19
.19
.19
.20
.21
.21
.22
AFDC*
(.02)
(.01)
(.01)
(.01)
(.01)
(.01)
(-01)
(.02)
(.03)
(.04)
(.05)
(.07)
(.08)
(.09)
Fed. & State
Income Tax
(Current &
Dpforrpd)
.25
.26
.24
.23
.23
.21
.20
.18
.18
.17
.13
.12
.12
.12
I
to
o
n/a=not available
*Allowance for Funds During Construction prorated by ratio of the change in Gross Electric Plant to the change in
Total Gross Plant.
Source: Statistics of Privately Owned Electric Utilities in the United States. Federal Power Commission,
1967, 1972, and 1973; TBS estimates.
-------
1-21
Exhibit 1-7
AVERAGE RESIDENTIAL BILLS AND OVERALL AVERAGE REVENUE PER KILOWATT-HOUR
Total Electric Utility Industry
1960-1973
Average Bill for
Residential Service
Year
1960
1961
1962
1963
1964
1965
1961-1965
Growth Rate
1966
1967
1968
1969
1970
1966-1970
Growth Rate
1971
1972
1.973
1971-1073
Growth Rate
500 kWh
$10.62
10.64
10.66
10.64
10.61
10.41
- .4%
10.34
10.37
10.37
10.32
10.51
+ .2%
11.13
11.99
12.56
+6.1%
250 kWh
$7.44
7.45
7.48
7.48
7.43
7.38
- .2%
7.34
7.37
7.38
7.40
7.51
+ .4%
7.84
8.35
8.67
+4 . 9%
Revenue Per kWh
All Customers
1.69
-------
1-22
Exhibit 1-8
NUMBER OF CUSTOMERS AND AVERAGE KILOWATT-HOUR USAGE PER CUSTOMER
Total Electric Utility Industry
1960-1973
Period
1960
1961
1962
1963
1964
1965
1961-1965
Growth Rate
1966
1967
1968
1969
1970
1966-1970
1 Growth Rate
1971
1972
1973
1971-1973
Growth Rate
Total Customers
58,870,000
60,130,000
61,324,000
62,857,000
64,148,000
65,558,000
+2.2%
66,910,000
68,168,000
69,716,000
70,929,000
72,485,000
+2.0%
74,265,000
76,150,000
78,461,000
+2.7%
kWh Per Customer
11,605
11,986
12,656
13,218
13,880
14,543
+4.6%
15,528
16,240
17,246
18,429
19,195
+5.7%
19,746
20,718
21,708
+4 . 2%
Source: Edison Electric Institute, Statistical Yearbook of
the Electric Utility Industry. 1973;
-------
1-23
Exhibit 1-9
ASSETS PER DOLLAR OF REVENUE
Privately Owned Class A&B Electric Utilities in the United States
Electric Department
1960-1973
(1)
Year
1960
1961
1962
1963
1964
1965
1961-1965
Growth Rate
1966
1967
1968
1969
1970
1971
1972
1973
1966-1973
Growth Rate
(2) ,
Gross
Electric Plant
Investment
(millions)
$ 45,456
48,090
50,699
53,474
56,326
59,703
5.6%
64,066
69,617
76,026
83,671
93,303
104,300
116,644
130,840
10 . 3%
(3)
Operating
. Revenues
(millions)
$ 10,116
10,666
11,392
12,018
12,673
13,400
5.8%
14,374
15,225
16,359
18,023
19,791
22,322
25,355
29,104
10.2%
(4)
Gross Plant
Per Dollar Of
Revenue
(2K(3)
$ 4.49
4.51
4.45
4.45
4.44
4.46
—
4.46
4.57
4.65
4.64
4.71
4.67
4.60
4.50
—
Source: Statistics of Privately Owned Electric Utilities in
the United States. Federal Power Commission, 1967
1972, and 1973.
-------
ECONOMIC AND FINANCIAL IMPACTS OF
FEDERAL AIR AND WATER POLLUTION CONTROLS
ON THE ELECTRIC UTILITY INDUSTRY
VOLUME II
NATIONAL BASELINE PROJECTIONS
MAY 1976
-------
VOLUME II
TABLE OF CONTENTS
Page
List of Exhibits
Chapter
1
INTRODUCTION AND SUMMARY OF BASELINE
CASE FINANCIAL PROJECTIONS FOR THE
ELECTRIC UTILITY INDUSTRY
Approach
Summary of Baseline Case Financial
Projections
Comparison with Alternative Scenarios
BASELINE DEMAND PROJECTIONS
BASELINE CAPACITY AND GENERATION
PROJECTIONS
Capacity
Capacity Factors and Generation
COST FACTORS
Capital Cost Factors
Operating and Maintenance Cost Factors
FINANCIAL POLICIES AND COSTS
Industry Structure
Capital Structure and Capital Costs
Accounting Practices
Taxes
II-l
II-l
II-4
11-8
11-13
11-18
11-19
11-30
11-33
11-33
11^37
11-42
11-42
11-43
11-45
11-46
Appendix
II-A PTm(ELECTRIC UTILITIES) RESEARCH
METHODOLOGY
11-75
-------
VOLUME II
LIST OF EXHIBITS
Exhibit
II-l PTm Sales and Capacity Assumptions; U.S.
Electric Utility Industry (1973-1990)
II-2 PTm Gross Additions to Generating Plant
Including Conversions to Coal and Oil (1973-1990)
II-3 PTm Total Generation by Fuel Type Including
Conversions to Coal and Oil (1973-1990)
II-4 PTm Total Capacity by Fuel Type (1973-1990)
II-5 PTm Fuels Consumed for Generation of Electricity
Conventional Steam and Peaking Units (1973-1990)
II-6 PTm Baseline Financial Projections (1975 dollars)
II-7 PTm Baseline Financial Projections (current dollars)
II-8 Baseline Financial Projections Summary for
Selected Years
II-9 Financial Projections of Previous Baseline
Conditions
11-10 Financial Projections Summary Based on Previous
Load Growth Assumptions and Current Cost Escalation
Factors
11-3,1 Financial Projections Summary Based on Historic
Growth Rates
11-12 Financial Projections Summary Based on FPC
Capacity Additions
11-13 Capacity Factors by Fuel Type and Ownership
Category, For Representative Years
11-14 Estimates of Capital Costs for Nuclear Units,
1970-1990
11-15 Fossil Unit Capital Expenditure Cost Assumptions,
1970-1990
-------
Exhibit
11-16 Estimates of Capital Costs for Fossil-Fueled
and Hydraulic Units, 1970-1990
11-17 Implications of Industry Projections of Capital
Costs In Terms of Escalation Rates, 1972-1990
11-18 Pattern of Cash Flows for Capital Projects;
Annual Expenditure of Funds
11-19 Forecasts of Electric Demand Growth
11-20 Electrical World Projections: Total Sales,
System Output, Peak Load, Capability,
and Margin
11-21 Coal and Oil Conversions, 1975-1980
11-22 Fuel Cost Assumptions, 1974-1990
11-23 Financial Assumptions: Capital Costs, Capital Mix,
Tax Rates
11-24 GNP Deflator; For Use in Constant Dollar Analysis
11-25 Income Statement for Investor-Owned Electric
Utilities
11-26 Balance Sheet for Investor-Owned Electric
Utilities
11-27 Applications and Sources of Funds for Investor-
Owned Electric Utilities
II-A-1 Interactions between the Environment and the
Physical and Financial Characteristics of the
Electric Utility Industry
II-A-2 Determinants of Plant and Equipment in Service and
in Construction for the Electric Utility Industry
II-A-3 Determinants of Uses of Funds for the Electric
Utility Industry
II-A-4 Determinants and Composition of Total Sources of
Funds for the Electric Utility Industry
II-A-5 Determinants of Revenues, Expenses, and Profits
for the Electric Utility Industry
(Il-iv)
-------
CHAPTER I
INTRODUCTION AND SUMMARY OF BASELINE CASE
FINANCIAL PROJECTIONS FOR THE ELECTRIC UTILITY INDUSTRY
This volume of the report presents financing pro-
jections for the electric utility industry before taking into
account the impact of federal pollution control requirements.
These projections constitute a "baseline" against which pol-
lution control cost estimates will be evaluated.
TBS has devoted substantial effort to developing and
validating the baseline projections because they are key to
the impact analysis; both the projections themselves and the
method for representing the industry's operations and accounting
are used in the impact analysis pahse. The general approach
used in the overall study has been first to project conditions
in the industry in the absence of pollution control regulations
(the baseline case), then to project conditions with the
regulations and, finally, to measure the impacts by contrasting
one set of conditions with the other. The following section
describes in more detail the key elements of the baseline pro-
jections.
APPROACH
The approach which TBS has followed to develop and
present the baseline projections has three major elements:
First, TBS selected five financial indicators as summary statis-
tics descriptive of the detailed financial projections devel-
oped for the purposes of this report. The summary statistics
are:
-------
II-2
© Capital Expenditures
9 External Financing
© Operating Revenues
© Operating & Maintenance Costs
« Average Consumer Charges
These indicators are used in the later volumes to compare
the baseline conditions with those resulting from the use of
alternative sets of operating projections. The indicators are
more fully explained at the end of this chapter in the context
of specific financial baseline projections.
A second element of TBS' approach was to rely upon
public data sources. TBS used, to the maximum extent possible,
actual operating data through 1975 and projected and announced
operating characteristics developed by industry sources and
by other research organizations which specialize in such fore-
caseing activities. The focus of the TBS effort has been on
the determination of the financial implications of various con-
ditions and courses of action and not upon developing a unique
set of operating projections. Therefore, the approach had
depended upon gathering and integrating existing projections
on demand for electricity, capacity additions, fuel costs,
capacity factors, and so on. The existing projections are
then reconciled with other sources of data such as:
© Historical data
o Emerging trends discussed in relevant literature
o Specific new data such as announced cancellations,
new construction costs or fuel prices.
-------
II-3
A critical dimension of the reconciliation process has been
to achieve a degree of consensus from practitioners and
policy-makers on the validity of the operating projections
which TBS has adopted. The areas in which significant
discussion has occurred and for which the most uncertainty
exists include:
o
Demand: the rate at which sales and peak
load will grow over the next fifteen years.
Events described in Volume I, such as the energy
crisis, general economic conditions, and environ-
mental concerns have upset traditional growth pat-
terms and rate structures;
New capacity or construction: the amount of
new capacity which the industry should build (or
postpone) to meet the projected level of sales.
Because of the uncertainties in future sales
growth patterns, it has become difficult to plan
the rate at which such additions will be required;
New plant costs and fuel prices: These major
capital and operating costs continue to be sub-
ject to the vagaries of inflation and market forces,
While many estimates have been supplied in this
area, a high degree of uncertainty remains, par-
ticularly in the projection of costs for coal,
oil and uranium and therefore in the projections of
future plant type as well;
Financial and accounting structure: Finally,
though perhaps less important, there are uncer-
tainties related to the financial costs and
accounting conventions affecting the industry.
Each of these areas is discussed more fully in Chapters 3
through 5.
The third element of TBS' approach is the use of
TBS1 Policy-Testing model of the electric utility industry,
(Electric Utilities) to trace through the detailed accounting
and financial implications of the projected operating conditions
-------
II-4
described above. PTm, which is at the heart of the TBS ap-
proach, is described in some detail in Appendix A, with
special attention to the financial module.
The final portion of this chapter presents the
summary financial statistics for the baseline projections and
a brief description of the key operating projections from
which the baseline financial projections were derived.
In the presentation, two conventions have been
followed and are worth mentioning at the outset. First, while
PTm performs calculations in current dollars so as to ac-
curately reflect the impact of price inflation on depreciation
tax shields, etc., most of the text discusses the projections
in terms of constant 1975 dollars so as to aid the reader's
understanding of the magnitude of the number in relation to
the industry's current financial statistics. Second, while
the calculations are done on a yearly basis for the 1975-1990
period, for simplicity the text generally focuses on aggregate
numbers for the overlapping periods 1975-1980 and 1975-1985.
SUMMARY OF BASELINE CASE FINANCIAL PROJECTIONS
The financial projections are based upon the conditions
which TBS determined best describe the future of the electric
utility industry. They are, of course, subject to the uncer-
tainties described above. While each area is discussed in
subsequent chapters, sales growth rates and levels of
capacity additions are briefly included here, because they
are critical assumptions to the baseline projections. TBS has
used an annual growth rate in sales of 6.1 percent for the
1975-1980 period and 5.3 percent annually from 1981 through
1990. Both rates are well below the growth rates of the decade
-------
II-5
prior to 1974. They reflect those forecasts made after the
energy crisis and are discussed in Chapter 2. The capacity
additions projected for the next ten years reflect the
industry's inability to respond rapidly to a decline in
growth rates. Thus, despite cancellations and postponements
of new capacity, the industry's generating capacity is pro-
jected to grow more rapidly than demand through 1980. For
the 1981-1990 period, capacity additions are assumed to be
sufficient to maintain a capacity reserve margin of at least
20 percent, a generally-accepted objective in the industry.
The table and discussion below summarize the
financial projections. Exhibit II-8 provides financial data
for specific years in greater detail.
SUMMARY OF BASELINE FINANCIAL PROJECTIONS
(1975 dollars)
1975-1980
Capital Expenditures
(billions)
- Net of Change in Construc-
tion Work in Progress 118.3
External Financing
(billions)
Operating & Maintenance
Costs
Operating Revenues
Average Consumer
Charge (mills/kwh at end
of period)
89.8
267.3
469.0
31.7
1975-1985
237.1
191.2
510.3
903.9
32.0
Source: Exhibits II-6 and II-8, PTm (Electric
Utilities) Projections and Assumptions
-------
II-6
Capital Expenditures are defined as the cumulative
cash expenditures for the plant and equipment which is placed,
in service during any given year. The expenditures reported
are thus net of any change in construction work in progress
(CWIP). Further, this definition refers only to cash outlays
actively required by the utilities and does not include
allowance for funds during construction (AFDC). As an exam-
ple, the baseline projections for the next decade (1975-
1985) indicate that capital expenditures net of changes in
CWIP'will total $237.1 billion in constant 1975 dollars.
In addition, CWIP will increase from $28.5 billion at the
end of 1974 to $63.0 billion at the end of 1985, an increase
of $34.6 billion. Thus, total expenditures for plant and
equipment during the next decade will be $271.7 billion—
the sum of $237.1'billion in the form of capital expenditures
for equipment placed in service and $34.6 billion in terms
of additions to the CWIP account. These latter expenditures
are then allocated to the time period in which that equip-
ment is placed into service.
External Financing requirements are the sum of
long-term debt, preferred stock and common stock issues in
any given year, including the refinancing of maturing long-
term debt. These capital market requirements during the
next decade are expected to total $191.2 billion in constant
1975 dollars—approximately 80.6 percent of capital expendi-
tures during the same period. The remaining funds required
to finance the industry's expenditures for additions to
plant in service and to CWIP will be generated internally in
the form of retained earnings, depreciation and tax deferrals.
Actually, the 1975-1985 period encompasses 11 years; however, reference
within this report will be made as if this time period were a "decade."
-------
II-7
Operating and Maintenance Costs consist of all
the direct costs of operation of the electric utilities. Fuel
represents the largest single component of these costs. His-
torically (prior to 1974), fuel accounted for slightly under
half of total operation and maintenance expenses. One result
of the rapid escalation in fuel prices during 1974 has been
to increase that share to approximately 60 percent. The TBS
baseline projection is that total operating and maintenance
expenses will amount to $267.3 billion in the 1975-1980 period
and $510.3 billion through 1985.
Operating Revenues represent the total amount of
money paid by utility customers for electricity in a given
period. To put it another way, operating revenues are the
amount required by the utilities to cover operating, capital,
and other costs. As such, it represents the best basis for
measuring the potential impact on consumers of pollution
control regulations which require capital investments as well
as direct operating costs. The baseline projections for
total utility operating revenues are $469.0 billion in the
1975-1980 period, and $903.9 billion through 1985 (1975
dollars). These figures indicate an average annual revenue
rate of approximately $82 billion, up from about $50 billion
in 1974 (notated in 1975 dollars).
Average Consumer Charges are obtained by dividing
operating revenues by total sales to ultimate customers. Thus,
they represent the average cost of electrical energy per
kilowatt-hour. This average charge is expected to increase
slightly in real terms from 29.6 mills per kilowatt-hour in
1975 to 32.0 mills per kilowatt-hour in 1985. In current
dollar terms, consumer charges per kilowatt-hour are expected
to increase from 29.6 mills in 1975 to 53.5 mills in 1985—
-------
II-8
an increase of about 6.1 percent per year which is primarily
due to inflation. ,
/•
COMPARISON WITH ALTERNATIVE SCENARIOS
It is against this base of financial results that
the cost of pollution control will be measured. However,
before proceeding in the discussion of the components
(demand, capacity, costs and other financial parameters)
which underlie these results, it is well to consider briefly
the financial results based on three alternative projections
of sales growth or additions to capacity. They are included,
in part, to illustrate how sensitive the financial indica-
tors are to changes in the operating projections.
Financial Summary: Based Upon December 1974
Baseline Projections
The baseline projections above differ somewhat
from the baseline projections made by TBS and published by
EPA, in December 1974, in Economic Analysis of Effluent
Guidelines—Steam Electric Power Plants. There are two key
reasons. First, the current baseline is driven by an up-
dated forecast of load growth which assumes that the electric
utility industry will not return to its historic rate of
growth, but will grow more slowly in the future. Second,
capital and operating cost factors have been revised upward
primarily to reflect continued high rates of cost escalation
in the construction industry and to reflect the quantum
increase in fossil fuel prices which occurred during 1974.
The December 1974 projections will often be referred to
as "previous" baseline projections.
-------
II-9
The following summary illustrates the major finan-
o
cial indicators as they appeared prior to accounting for
these two factors.
FINANCIAL SUMMARY: PREVIOUS BASELINE CONDITIONS
(1075 dollars)
Capital Expenditures
(billions)—Net of
change in CWIP
External Financing
(billions)
Average Consumer Charge
(mills/kwh at end of
period)
1975-1980
$107.3
78.0
29.5
1975-1985
$247.3
177.7
28.2
Source: TDS, Economic Analysis of Effluent
Guidelines—Steam Electric Power Plants,
December 1974
The specific changes which affected capital expenditures are
presented below for the short and long term:
CHANGE IN BASELINE CAPITAL EXPENDITURES
(billion* of 1075 dollar*)
PREVIOUS BASELINE
+ Change due to
Load Growth
+ Change due to
Cost Escalation
- CURRENT BASELINE
1975-1980
$107.3
(8.8)
1975-1985
$247.5
(64.7)
It should be noted that all constant dollar estimates from the EPA
report in December 1974 have been adjusted in the current analysis
to a 1975 base.
-------
11-10
Exhibits I1-9 and 11-10 provide selected data which summarize
(1) the previous baseline; and (2) the combination of the
growth projections contained in the previous baseline with
the revised cost factors. The table above highlights the
differences in capital expenditures detailed in Exhibits II-8
through 11-10.
Financial Summary Based Upon Historic
Load Growth
While these data provide a comparison of the TBS
baseline with the baseline utilized in previous EPA analyses,
other comparisons can be made to evaluate, for example, the
effect of returning to historic growth levels. Exhibit 11-11
provides selected summary data for this condition.
The financial implications of returning in 1976
to the historic growth pattern of 7.2 percent annually and
continuing at that level through 1990 are as follows:
FINANCIAL SUMMARY: HISTORIC GROWTH RATES
(1975 dollars)
Capital Expenditures
(billions)
External Financing
(billions)
Average Consumer Charges
(mills/kwh at end of
period)
1975-1980 1975-1985
$119.5
116.2
31.2
$333.1
312.44
33.4
Source: Exhibit 11-11, PTm (Electric Utilities)
-------
11-11
Capital expenditures in the short run would not
be significantly impacted since the stream of capacity addi-
tions scheduled during the 1975-1980 period is the same.
However, the capacity additions required to maintain an
adequate reserve margin (e.g., 20 percent) during the early
1980s would increase from 149.2 to 275.7 million kilowatts.
These capacity expansion plans would require an additional
$94.2 billion in capital expenditures and $121.2 billion in
external financing during the next decade. In addition,
internally generated funds would drop from 20 percent of
capital requirements to less than 10 percent. The net effect
of historic growth on the consumer would be an increase in
1985 consumer charges of approximately 4 percent.
Financial Summary Based upon Federal Power
Commission Capacity Additions with TBS
Growth Projections
If the TBS baseline projections regarding sales
and peak demand growth are used, but the capacity additions
schedule announced by the Federal Power Commission is adhered
to, then the financial profile is as follows:
FINANCIAL SUMMARY: PPC ADDITIONS AND
TBS GROWTH RATE
(1975 dollars)
Capital Expenditures
(billions)
External Financing
(billions)
Average Consumer Charge
(mills/kwh at end
of period)
1975-1980
$130.5
94.4
32.1
1975-1985
$239.7
190.7
31.9
Source: Exhibit 11-12, PTm (Electric Utilities)
-------
11-12
Over the long run, the construction of generating
capacity as currently planned differs little from the base-
line conditions. The FPC announced additions would result
in 10.4 percent more capacity placed in operation from 1975-
1980 than the baseline projection, but 12.3 percent less in
the 1981-1985 period. The total additions over the entire
period would be the same as in the baseline case.
Since more capacity is placed into service in the
late 1970s, capital expenditures and external financing re-
quirements during this period would increase by about 10
percent and consumer charges would increase by about 2 per-
cent . However, these additions would temper the capacity
requirements in the early 1980s, resulting in a net inprease
of only $1.8 billion dollars in capital expenditures and a
marginal decline in external financing requirements during
3
the next decade. Consumer charges would not differ from
the baseline case by 1985. Exhibit 11-12 provides selected
data for specific years under this scenario.
The following chapters present the data and assump-
tions upon which the baseline projections are based. Various
elements of the baseline projections are listed in Exhibits
II-l to II-8 for reference.
The decline in-external financing requirements follows from the
earlier inclusion of capital expenditures into the rate base.
-------
11-13
CHAPTER 2
BASELINE DEMAND PROJECTIONS
A basic component of projections for the electric
utility industry is demand. "Demand" is a term often used
loosely to refer either to peak demand or to energy consumed
over a period of time. In this report, energy consumed over
a year's time will be referred to as "sales." The rate of
energy consumption at any point in time will be referred to
as "demand" or "load." The highest rate of consumption during
a year will be referred to as "peak demand" or "peak load."
Peak load growth determines the industry's total capacity needs
The ratio of energy sales to peak demand influences the mix
of types of capacity, that is, baseload or peaking capacity,
built to meet total peak demand. The following discussion
covers sales and peak load growth both as they actually oc-
curred between 1960 and 1975 and as they are projected for
1976 through 1990.
It should be noted that demand analysis is becom-
ing more precise and detailed because of the current interest
on the part of regulatory commissions and other government
bodies in rate structure modifications. Rate structure
changes may affect future demand patterns and, therefore,
may also affect the other determinants of the industry's
financial profile: capacity, costs, and financial structure.
However, because the magnitude of the impact of such rate
structure changes is at present unclear, the demand projec-
tions used for this analysis do not presume such changes.
The pattern of demand as it has existed in the past
and as it is projected for this report is summarized in the
following table.
-------
11-14
SUMMARY OF BASELINE DEMAND PROJECTIONS
I960 196S 1970 1975 1980 Ig85
Sales to Ultimate
Customers (billions
of kilowatt-hours) 883.2 953.4 1,391.4 1.736.5 2,334.7 3,022.5
5-year Growth Rate - 6.9% 7.9% ' 4.5% 6.1% 5.3%
Non-Coincident
Peak Demand (mil-
lions of kilowatts) 133.0 186.9 275.4 358.1 476.0 613.3
5-yuar Growth Rate - 7.0% 8.1% 5.4% 6.9% 5.2%
Source: Exhibit* II-l, II-2. II-3, PTm (Electric Utilities)
1990
3,913.0
5.3%
794.0
5.3%
The data shown for the period 1960-1975 represent
actual industry experience. During most of that period
(1960-1973), the electric utility industry sustained a rela-
tively constant rate of growth, equal to 7.3 percent in terms
of sales to ultimate customers and 7.6 percent in terms of
peak load demand. In 1974, however, sales to ultimate
customers actually declined by 0.1 percent, while peak de-
mand increased by only 1.6 percent. These substantial de-
clines in growth rates were primarily the result of both
price and non-price induced energy conservation following
tho Arab oil embargo. Many observers felt that by 1975
peak demand growth rates would return to historical levels,
and perhaps even make up for the 1974 decline.
Neither of these expectations seems to have
materialized. The data for 1975 indicate that sales to
ultimate customers and peak demand increased by approxi-
mately 2 percent over 1974 levels, a rate that falls far
short of a return to earlier patterns. Sales growth in the
first twelve weeks of 1976 has been 5.9 percent above the
year-earlier level, but is inconclusive evidence of any
long-term trend.
-------
11-15
The baseline projections for demand in the 1976
through 1980 period are based on growth rates somewhat below
the historical experience. Specifically, the baseline pro-
jections assume growth in sales to ultimate customers of
6.1 percent for 1976-1980, 5.3 percent for 1981-1985, and
5.3 percent for 1986-1990. The rates of growth in peak
demand are 5.9 percent, 5.2 percent, and 5.3 percent, re-
spectively. The TBS projections are based primarily on
forecasts made by others, modified where appropriate to re-
flect the industry's actual experience in 1974 and 1975. A
brief comparison of these and various other projections is
presented below.
A first comparison can be made between the TBS
baseline projections and the projections published in an
earlier study by TBS for EPA, Economic Analysis of Effluent
Guidelines—Steam Electric Power Plants, December 1974. The
following table summarizes the differences in growth assump-
tions used in the two projections.
CHANGE IN DEMAND ASSUMPTIONS
T08 Demand Project lono TBS December 1974 Dxmand Projections
Sales to Non-Coincident Sales to Non-Coincident
Ultimate Customer* Peak Demands Ultimate Customers Peak Demando
1974 -0.1%*
1975
1976-1980
1981-1985
1986-1999
actual; from
2.1*
6.1
5.3
5.3
Edison Electric
1.6%* -3.4%
8.1" 2.7
5.9 7.1
5.2 6.6
5.3 5.5
Institute
1.0%
4.C
6.5
6.0
5.5
This comparison in demand projections relates to the compari-
son of financial projections presented in Chapter 1, page 5.
-------
11-16
The TBS projections can also be compared to pro-
jections made by other analysts of the electric utility
industry and by representatives of the industry itself.
These projections fall into two classes:
(1) Forecasts made prior to the Arab oil embargo
of 1973; and
(2) Forecasts developed since the oil embargo,
especially those made since the industry's
1974-1975 reduction in sales growth.
The sales growth rates projected for 1975-1985 for represen-
tative sources in these two categories are presented in the
following tables.
(i)
DEUAND FORECASTS DEVELOPED
USING PRE-CMBARGO INDUSTRY DATA
Source Pub.Date
Electrical World (9/73)
National Electric
Reliability Council (4/74)
National Power Survey
(TAC-Flnunce)"historic
growth CBM" (12/74)
National Power Survey
(Forecast Review
Task Force) (8/76)
Projected Independence
(FEA - $7 oil) (11/74)
1975-1980 1975-1985
7.0%
7.5%
7.1%
9.1%
6.6%*
6.5%
7.1%
7.1%
7.0%
6.9%
(2)
DEUAND FOKKCASTS DEVELOPED
USING POST-EMUARGO ASSUMPTIONS
Source
Electrical World
Electrical World
National Power Survey
(TAC-Flnance) "moder-
ate growth case"
Project Independence
(FEA - $11 oil)
Sales Growth
Pub.Date 1975-1980 1975-1985
(9/74)
(8/75)
(12/74)
(11/74)
6.1%
6.7%
7.1%
5.5%*
5.3%
6.2%
6.6%
5.7%
"Baaed on 1872-1880 figures
-------
11-17
A return to the historic rate of growth of approxi-
mately 7.5 percent per year 1976-1980, such as is character-
istic of the pre-embargo forecasts, would result in sales to
ultimate customers in 1980 of 2,493 billion kilowatt-hours,
a level 6.3 percent above the TBS baseline forecast for 1980,
The projections in the second table are more in keeping with
those which TBS has adopted. Exhibits 11-19 and 11-20 pro-
vide additional detail on comparative forecasts in selected
years.
-------
11-18
CHAPTER 3
BASELINE CAPACITY AMD
GENERATION PROJECTIONS
The second major set of operating projections for
the electric utility industry concerns the industry's capacity
and its annual output (generation). Capacity is the amount
of electric power (measured in kilowatts) which existing plants
are capable of producing at a given moment. Generation is
the amount of electric energy (measured in kilowatts per hour)
actually produced by the existing capacity over some period of
time.
The projections of capacity levels for future years
result from estimates of several individual elements: capacity
additions by fuel type; conversions of existing gas and oil
generating capacity to coal and oil; capacity retirements; and
reserve margins. The use of capacity projections in calculating
generation by fuel type depends upon estimates of utilization
rates or capacity factors for plants in each fuel category.
The TBS projection of total capacity and generation
and the related individual elements are based on the examina-
tion and, as necessary, the modification of existing projec-
tions developed by other organizations and industry specialists.
This chapter presents the projections and describes the func-
tion of each element.
-------
11-19
CAPACITY
Installed Capacity in 1974
The profile of capacity by fuel type as it existed
in 1974 (the base year for the projections) serves as a point
of reference for highlighting the changes which are projected
for the future. In 1974, generation capacity totaled 476
million kilowatts, 71.3 percent of which was accounted for by
fossil-fueled units. Hydroelectric capacity was second in
importance with 11.6 percent of the total, while nuclear and
peaking capacity represented 6.6 and 8.7 percent, respectively.
The 1974 level for hydroelectric power represented
a decline in share from previous years, but nuclear and peaking
units significantly increased in their share of capacity by
1974. The table below summarizes the installed capacity by fuel
type as it existed in 1974.
1974 UNITED STATES
INSTALLED GENERATION CAPACITY
Installed Capacity Percentage of
(million kw) Total Capacity
Generator Type
Fossil
Coal 185.
Oil 66.
Gas 87.
Nuclear
Hydroelectric
Pumped Storage
Peaking Units
1974
339.4
8
3
4
31.6
55.4
8.3
_41.3
476.0
Source: EEI, FPC publications; coal, oil
percentages resulted from a computerized
pp. 3-44 NCA Steam Electric Plant Factors
1974
71.3
54.7
19.5
25.7
3.6
11.6
1.7
' . 8^7
99.9%
and gas capacity
analysis of Table I ,
, 1973
-------
11-20
Total Capacity Projections (1975-1990)
The trends which were becoming apparent in 1974 con-
tinue to be reflected in the baseline capacity projections for
the period of analysis. The table below summarizes the pro-
jections by prime mover.
NATIONAL BASELINE SUMMARY
CAPACITY MIX BY PRIME MOVER SELECTED
PRIME MOVER
Coal
Oil
Gas
Nuclear
Hydro
Pumped
Peaks r
TOTAL
(millions
1975
196.2
72.3
89.2
40.7
57.6
8.5
44.8
509 . 4
Source: Exhibit II-3,
YEARS
of kilowatts)
1980
276.8
96.1
48.2
79.7
66.4
11.8
52.0
1985
332.9
91.2
41.0
132.0
73.5
16.3
64.1
1990
434.6
85.5
33.0
219.8
85.7
23.8
85.6
631.0 751.0 968.0
PTm (Electric Utilities)
Total capacity is estimated to double between 1974 and
1990. However, the most prominant development in the projection
period is the shift in share by fuel types. Oil-fired units
will increase slightly as a percent of total capacity through
1978, then drop to about 15.2 percent in 1980 as a result of
conversions to coal and a slowed rate of oil-fired additions.
By 1990, there will be negligible additions utilizing oil,
causing the share of capacity accounted for by such units to
fall to slightly under 9 percent. Nuclear power plants, on the
other hand, will probably continue to grow in their share of
the total, even though some plants expected to be in service
by 1975 and the late 1970s have already been cancelled or post-
poned. Natural gas is projected to undergo a significant drop
in share of total capacity, from almost 18.4 percent in 1974
-------
11-21
to 3.4 percent by 1990. As with oil, this drop is the result
of both conversions to other fossil fuels and a slowed rate of
new additions. All of these shifts in relative share of total
capacity are integrally tied to the characteristics of addi-
tions to capacity.
Capacity Additions
The projections of capacity beyond 1974 are driven
primarily by the type, timing and amount of additions which
the industry has scheduled for future years. Those plants have
been radically modified as a result of the changes in prices
and sales growth precipitated by the oil embargo and other fac-
tors. As a result, many postponements and cancellations of
new units occurred in 1974 and 1975. Nevertheless, it appears
that the industry has been optimistic about the need for fur-
ther postponements and cancellations. This optimistic posture
has occurred based on the assumption that growth rates would
recover sharply during 1975 and is reflected in the Federal
Power Commission's published announcements of additions (April
1975). If the reported level of capacity additions was com-
bined with the TBS baseline projections for sales, the resulting
capacity would far exceed the level of demand and an adequate
reserve margin by 1980. Even if growth rates were to return
to historic levels during the 1976-1980 period, the FPC re-
ported additions would still result in reserve margins in ex-
cess of the industry standard. Furthermore, the announced
Reserve margins are discussed on page 11-27. In the examples which project
on the basis of FPC additions3 the first would represent a reserve margin
of over SO percent, the second would yield a 24 percent reserve margin.
-------
11-22
additions do not seem to fully reflect the impact of natural
gas curtailments and/or Federal Energy Administration actions
to restrict generation from oil and gas. Therefore, in de-
veloping the baseline capacity projections for the 1976-1980
period TBS has modified the FPC additions to compensate for
the above-mentioned uncertainties in the following manner:
BASELINE CHANCES FROM PPC ADDITIONS
(Millions of kilowatts)
1076
1977
1078
1979
1980
Baseline
Additions
26.1
26.9
28.7
27.4
92.3
FPC
Addition!)
2C.6
28.3
31.9
32.2
40.4
Percent
Decrease
2%
6
10
IS
20
While the table above illustrates total percentage decreases
from FPC additions, these decreases are not evenly distributed
among fuel types. A further illustration in the table below
specifies by year and fuel type the percentage of FPC additions
which TBS has eliminated in its projection of capacity additions
8TEAH ELECTRIC POSTPONEMENTS
AKD/OR CANCELLATIONS AS % OK FPC ANNOUNCED
.ADDITIONS
Year
In-Service
. 107C
1977
1978
1079
1080
Coal
0%
0
0
0
0
Oil
0%
IS
50
60
70
Gas
33%
67
100
100
100
ftuclrar
01
10
20
20
20
All hydroelectric and pumped storage projects were assumed to
be completed on schedule. Additional peaking units were sched-
uled to begin operation in 1977 through 1980 where required to
meet the above-mentioned baseline capacity additions schedule.
-------
11-23
Nuclear and coal generation capacity are expected
to account for almost 88 percent of the additions by 1980,
and 82 percent between 1985 and 1990. While the nuclear share
of total additions will increase to 38.7 percent in 1980, coal
additions will represent almost half of the new additions.
Three years ago observers expected nuclear power to reach a
50 percent share by 1980.
There are a number of factors which have caused re-
visions in the type of capacity which is expected to dominate
additions. The pressure to find alternatives to oil and gas
continues: coal and nuclear power are currently the only poten-
tial candidates for use on a large scale, although each has
constraints to its further growth. The use of coal will be
hampered by the amounts of Western low-sulfur coal that will
actually be mined and shipped. Strip mining legislation, other
environmental restrictions and limited rail capacity may slow
the production of Western coal. On the other hand, increasing
concerns over various safety issues associated with nuclear
generation continue to affect the utilization of existing
plants and delay the planning and construction of new nuclear
units. In addition, complications which havp arisen concerning
the Hupply and coat of uranium have tiauued further delays and
/
postponements. Given the long lead times required for plan-
ning, licensing, siting, designing, and constructing nuclear
plants, each delay casts further doubt on the expansion of
nuclear-based generating capacity. Finally, analyses of cost
factors had previously attributed an operating cost advantage
to nuclear power and a capital cost advantage of coal genera-
tion. However, escalating capital costs for both types of
units along with higher nuclear operating costs have made it
difficult to cite cost advantages in support of one form of
energy over the other for purposes of projecting additions
during the next 15 years.
-------
11-24
The net result of these factors seems to be a swing
to coal as the dominant source of new generating capacity.
Nuclear units will be constructed at a significant rate—over
one-third of all additions—but at rates below earlier es-
timates. Present projections place total nuclear capacity at
79.7 million kilowatts by 1980 and 132.0 million by 1985.
Coal capacity will total 276.8 million kilowatts in 1980 and
332.9 million by 1985.
The overall trend for fossil additions will peak
by 1979 with additions of 19..'2-and 16.7 million kilowatts in
1979 and 1980, respectively, when early postponements go into
service. Then, during the 1980s, total fossil additions will
decline slightly as oil and gas additions cease entirely.
This trend is being hastened by the Federal Energy Administra-
tion's desire to minimize reliance on oil and gas and the po-
tential deregulations of natural gas which would make it
uneconomic as a boiler fuel. As a result, natural gas capacity
additions are expected to be negligible by 1977; oil additions
will also be negligible by 1981.
Peaker, hydroelectric, and pumped storage additions
are expected to maintain a steady share of total capacity
additions.
NATIONAL BASELINE SUMMARY
CAPACITY ADDITONS BY PRIME MOVER
SELECTED YEARS
(millions
of kilowatts)
PRIME MOVER 1975-1980
Coal
Oil
Gas
Nuclear
Hydro
Pumped
Paaker
TOTAL
Source: Exhibit
Utilities)
79.0
17.6
4.4
48.0
11.4
3.5
13.6
177.5
II-2, PTm
1975-1985
149 . 2
17.6
4.4
100.3
18.8
8.0
23.6
326.9
(Electric
-------
11-25
Gas and Oil Conversions
Another dimension of capacity projections is the con-
version of some gas units to coal or oil and some oil units to
coal. These conversions stem from the rising costs of gas and
oil, the curtailment of gas supplies, and federal conversion
orders from FEA. Statistics for the conversions from 1974-
1980 have been projected from EPA and FPC estimates and com-
piled in a study by Foster Associates. The estimated capacity
which will be converted in the absence of the Clean Air Act
during the 1975-1980 period is listed below.
GAS AND OIL CAPACITY CONVERSIONS
SINCE 1975
(million kilowatts, cumulative)
1975
1976
1977
1978
1979
1980
Source:
Gas to Coal
0.1
1.8
3.7
5.5
7.9
9.2
Gas to Oil Oil
0.5
5.3
10.5
15.8
21.0
to Coal
0.4
1.1
3.4
4.9
6.4
26.3 11.1
Foster Associates, Impact of Natural Gas
Curtailments
(August 1975)
on Electric Utility
, Exhibit 11-21
Plants
These conversions are included in the capacity pro-
jections as additions to the coal and oil components.
-------
11-26
Capacity Retirements
Some portion of existing capacity is scheduled to
2
be removed from service each year. However, increasing re-
serve margins, higher capital costs, declining revenues,
along with increased cancellations and postponements, may
have a noticeable impact on capacity retirements through 1980.
The combination of these factors may create a financial en-
vironment in which utilities find it more attractive to extend
the life of existing capacity than to construct and finance
new facilities. On the other hand, these same factors may
create an environment in which the utilities attempt to de-
crease excessive operating and maintenance expenses and
fuel costs by accelerating the retirement of older units.
Such retirements occur when capacity additions which were
scheduled and begun before demand growth slackened are too
close to completion to be cancelled or rescheduled.
In light of this uncertain situation, TBS has ex-
amined several rates of capacity retirements and has selected
those suggested by National Power Survey TAC-Finance Committee
for fossil fuels, and by EEI for hydro and peaking generation.
The retirement projections for selected years are displayed in
the following table.
2
It should be noted that units which undergo drastically reduced loads
(i.e., are not actually retired) are still included in the overall
capacity projections.
-------
11-27
PLANT RETIREMENTS
CUMULATIVE - FROM 1975
(millions of kilowatts)
1975 1980 1985
Total 2.4 22.0 51.2
1990
84.2
Source: Exhibit I1-3, PTm (Electric
Utilities)
The retirements for the individual fuel types are
outlined in the following chart.
RETIREMENT RATES
Type of Capacity
Fossil
Nuclear
Conventional Hydro
Peaking Units
Pumped Storage
Percent Retired Annually
1972-1990
0.4,% 1972-73
0.5% 1974
0.6% 1975
0.7% 1976-80
1.2% 1981-90
No retirements through
1990
0.1%
1.0%
1972-90
1972-90
No retirements through
1990
Source: 1972-95, EEO; 1976-90, National Power Survey
Reserve Margins
Reserve margins are the amount of generating capacity
which the industry has available in excess of the level required
by annual non-coincident peak demand. The amount of capacity
-------
11-28
which must be added is determined by the projected level of
g
peak demand plus a reserve margin of at least 20 percent.
Some observers within the industry have warned that
excessive postponements and/or cancellations could result
in capacity shortages by 1980. In fact, however, if peak
demand growth returned to historic levels, the baseline
capacity additions described in this chapter would still be
more than adequate to avoid a serious shortage of generation
capacity; under those conditions the reserve margin in 1980
would be nearly 22 percent.
If, on the other hand, the future growth rates and
capacity additions do parallel those projected by TBS, reserve
margins will decline gradually from the 1975 level of 37.6
percent to 29.4 percent by 1980. This level is still signi-
ficantly above the 20 percent margin. In order to realize
a reserve margin closer to 20 percent in the 1981-1990 period,
TBS has assumed that the capacity added during the 1980s will
be at the level needed in order to reach a 20 percent reserve
margin by 1985 and maintain that level through 1990.
The reserve margins which are implied by the TBS
projections of peak demand and capacity are listed below:
A reserve margin of 20 percent is the industry standard of adequate
capacity.
-------
11-29
RESERVE MARGINS
(1970-1990)
Peak Demand
Reserve
(million kwh) Margins (%)*
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1985
1990
________-__tH a + rtv*^ /*a 1
275.4
293.1
320.2
345.2
350.7
__U*"o 4 os* t A rf«
358.1
381.3
403.8
426.9
450.8
476.0
613.3
794.0
19.0
21.0
19.6
21.6
30.6
37.6
33.4
34.0
32.3
30.8
29.4
20.0
20.0
Source: Historical figures: EEI
Projected
and demand
figures: TBS based on capacity
projected described
previously.
The abrupt increase in reserve margins from 21.6 in
1973 to 30.6 in 1974 was due to the decrease in the peak de-
mand growth rate and the inability of individual utilities to
halt capacity additions already under construction. This
inability meant that, in the short run, excess generation
capacity was built without the proportional increase in peak
demand which would have kept reserve margins closer to the 20
percent level,
-------
11-30
CAPACITY FACTORS AND GENERATION
Capacity Factors
In order to determine operating and maintenance costs
for projected capacity levels, it is necessary to estimate the
rate of equipment utilization by type of fuel used. Conse-
quently, the number of kilowatt hours actually generated (sales
plus generation not sold) by units driven by each type of fuel
must be estimated by assuming capacity factors in order to
4
provide a basis for calculating operating costs. Two sets
of conditions determine capacity factors. First, all units are
subject to both routine maintenance shutdowns and forced outages
which reduce availability. Second, as demand varies, units
with high proportions of variable to fixed costs (such as
peakers) are used as little as possible, whereas units with
high fixed and low variable costs (such as nuclear units) are
operated continuously whenever possible. These conditions have
both been considered by TBS in developing the estimates of capac-
ity factors by fuel type which are presented in Exhibit 11-13.
Capacity factors for nuclear units are based on
optimal usage equal to total availability. The actual exper-
ience with nuclear units to date has been considerably below
the optimal level because of an initial period of about three
years during which the units reach a plateau of generation,
a "power ascendancy curve." In addition, other operational
difficulties have contributed to a low rate of utilization,
4
The capacity factor represents the average percentage of time the unit is
in operation during the year. The capacity factor is calculated by di-
viding the generation (kuh) by the product of capacity available
and 8760 hours.
-------
11-31
though this is projected to improve. For coal units an optimal
utilization rate equal to availability is also used. For oil,
gas, internal combustion and peaking units, the optimal rate
is less than availability primarily because of high fuel costs.
Generation Projections
The amount of electricity which will be generated
from the capacity levels projected—after the capacity addi-
tions, conversions, retirements and capacity factors have
been integrated—will be approximately 2,565.6 billion kilo-
watt-hours by 1980. By that year coal will account for 49.2
percent of the fuel mix breakdown. In 1985, nuclear generation
will have captured some of the fossil share, and will account for
about 22 percent of the total generation. Coal will maintain its
50 percent share through 1990, with the nuclear share reaching
about 28 percent in that year. The following table displays
generation of electricity by the fuels used for selected years.
In addition, Exhibit I1-4 provides the annual generation by
fuel type.
NATIONAL BASELINE SUMMARY
GENERATION MIX BY PRIME MOVER
Coal
Oil
Gas
Nuclear
Hydro
Pumped
Peaker
TOTAL
Source :
1975
857.2
275.5
262.5
192.3
250.0
34.1
36.6
1908 . 2
Exhibit
(billions
1980
1261.4
361.3
142.4
404.1
301.8
49.4
45.1
2565.6
I 1-4, PTm
kwh)
1985
1644 . 9
334.4
122.4
726.7
359.1
73.4
60.5
1990
2135.6
276.8
90.1
1201.1
410.0
105.8
80.5
3321.4 4300.0
(Electric Utilities)
-------
11-32
Fossil Fuel Requirements
These projections of generation mix have an asso-
ciated distribution of fuel requirements. The fuel require-
ments are derived from two types of information: the heat
rates of the units and the Btu content of the fuels. Since
the heat rate varies for old and new units and is complicated
by other factors, the assumptions used to calculate heat rates,
fuel prices and quantities are described more fully in Chapter
4, page I1-5. The Btu content for oil and gas has been as-
sumed to maintain the 1973 levels of 145,225 Btu per gallon
and 1,024 Btu per cubic foot, respectively. Coal is projected
by Sobotka & Co., Inc. to decline from 11,125 Btu/lb. to 10,875
Btu/lb by 1980 and 10,600 by 1985 as a result of increased use
of Western low-Btu low-sulfur coal. TBS has estimated the share
of low-sulfur coal to be about 30 percent by 1985. Given these
assumptions, the quantities of fossil fuels which will be burned
at the generation levels projected above are summarized in the
following table.
FOSSIL FUELS CONSUMED FOR
GENERATION OF ELECTRICITY
SELECTED TEARS
1975
Coal (mm tons) . 387
Oil (mm bbls) 533
Gas (bcf) 2,984
Total Generation
(billion kwb) 1,908
Source: Exhibit I 1-5
1980
.8 610.8
.5 624.5
.0 1,690.3 1
.2 2,565.6 3
, PTm (Electric
1985
807.0 1
599.8
,534.8 1
,321.4 4
Utilities)
1990
,022.9
534.2
,262.3
,300.0
-------
11-33
CHAPTER 4
COST FACTORS
Chapter 4 reviews the TBS estimates of capital
costs and the fuel and non-fuel segments of operating and
maintenance expenses.
CAPITAL COST FACTORS
Unit construction costs for the electric .utility
industry have increased significantly in the last few years
and are projected to continue to escalate through the early
1980s. As an example, the cost of a new coal plant has
risen from an average of $150 per kilowatt (current dollars)
for a plant put into service in 1972 to an estimated cost of
almost $500 for one coming in service in 1980 and of almost
$700 in 1985. These costs exclude pollution control and
AFDC. The cost of a nuclear plant over the same period has
risen from $245 per kilowatt for a plant in service in 1972
to almost $700 in 1980 and $900 in 1985. The causes of
recent and projected construction cost increases include
inflation in the cost of labor and materials, increases in
the complexity of generating units, licensing delays, slip-
page in construction schedules, and the cost and difficulty
of financing.
The capital costs used within this analysis are
summarized in the following table for selected in-service
years.
-------
11-34
UNIT CONSTRUCTION COSTS
In-Service Year Excluding Pollution Control and AFDC
(current dollars per
Nuclear Steam Electric Units
Nuclear Fuel
Conventional Steam Electric Units
Coal-fired
Oil-fired
Gas-fired
Hydraulic Units
Hydrolectric
Pumped Storage
Internal Combustion/Turbine Units
Transmission and Distribution
1972
$245
42
150
160
90
350
116
100
198
Source: Exhibits 11-14 through 11-16, and
kilowatt)
1975
$367
. 60
211
220
135
440
147
125
253
1980
$699
84
498
330
275
650
215
185
336
PTm (Electric
1985
$901
118
698
470
415
920
310
260
423
Utilities)
1990
$1,160
: 166
980
660
580
1,290
430
370
539
Because there is considerable uncertainty in the projected
costs of generating capacity and wide variations among fore-
casters, the TBS estimates should be contrasted with estimates
from other sources. The curve shown on the next page indicates
that the TBS estimates of nuclear plant construction costs
tend to be higher than most through 1980. Comparative costs
for other unit types can be found in Exhibits 11-14 through
11-16.
-------
11-35
NUCLEAR CONSTRUCTION COSTS
FOR IN-SERVICE YEAR, EXCLUDING POLLUTION CONTROL AND AFDC
(current dollars per Mlowatt)
YEAR
1990
1985
1980
1975
1970
Source: Exhibit 11-14
These capital cost estimates reflect rates of cost
escalation ranging from 7 to 15 percent in the late 1970s.
In fact, the range of estimates for all units except coal
indicates a projected rate of escalation of 7 percent per year
throughout the 1980s. The estimates for coal-fired units,
however, indicate that the current 12 percent rate of escala-
tion will be sustained unit 1985. While the' 12 percent is
higher than the rate for nuclear units, the costs per kilowatt
for both types have been re-examined and confirmed by industry
sources. Exhibit 11-17 summarizes capital cost escalation
rates through 1990.
-------
11-36
The capital costs described above are for in-
service dates. However, the spending precedes the date the
plant becomes operational by several years. Although the
generating capacity, related transmission and distribution
equipment, and nuclear fuel placed in service in any given
year are determined by load growth requirements, the actual
construction work begins several years prior to the in-
service date. Moreover, the cash flow associated with
generating plant additions generally precedes the completion
of construction. Changes in the construction work in prog-
ress account generally have constituted a substantial portion
of the capital expenditures by the electric utility industry
in any given year.
In order to approximate the cash progress payments
related to construction requirements, TBS has followed the
assumption of payment schedules as outlined in Exhibit 11-18.
As an example, a $100 million nuclear-fueled generating unit
(with an additional $15 million for nuclear fuel) placed in
service in 1981 would require cash payments of:
EXAMPLE:
1978
1977
1978
1979
1980
1981
Source:
NUCLtAR PLANT
$ 5 million
$15 million
$25 million
$25 million
$15 million
$15 million
Exhibit 11-18
PROGRESS PAYMENTS
-
-
-
-
$13 million
-------
11-37
Similarly, a $100 million fossil-fueled generation unit placed
in service in 1981 with $100 million in related transmission
and distribution equipment would require cash payments of:
1977
1978
1979
1980
1981
EXAMPLE: FOSSIL-FUELED PLANT
PROGRESS PAYMENTS
Fosail Plant
$ 5 million
$20 million
$30 million
$30 million
$15 million
Source: Exhibit 11-18
Transmission and
Distribution
$100 million
OPERATING AND MAINTENANCE COST FACTORS
Operating and maintenance costs, which have been
the major category of electric utility industry costs, can
be separated into fuel and non-fuel components. Such a sep-
aration permits a detailed analysis of fuel costs, which
accounted for nearly 60 percent of utility rate increases
in 1974.
Fuel Costs
As is well known, fuel prices increased dramatically
in 1974, affecting every major industry, but especially the
electric utility industry. Coal prices rose 68 percent over
the 1973 level and oil prices jumped 137 percent. Although
-------
11-38
most observers agree that a repetition of the 1974 increases
is unlikely, the complex nature of the fuel market makes
prices difficult to project with any certainty.
Factors in evidence at the end of 1975 suggested
that coal prices will increase at a rate faster than the
rate of GNP inflation—at perhaps 10 percent through 1980
and 8 percent thereafter. Although most industry sources
are reluctant to forecast coal prices, several upward pres-
sures on prices are apparent. These are decreasing domes-
tic oil and gas reserves-, coal industry labor rate increases
exceeding the GNP rate-, and the potential changes in the
safety requirements of OSHA and MESA, which may.decrease
productivity. TBS has, therefore, assumed a relatively
high escalation rate for the price of coal, at least
through 1980.
Oil price forecasts by various observers seem to
have converged on a rate of price escalation approximately
equal to the GNP inflation rate. TBS has adopted that level
of oil price increases for the 1976-1990 period.
Due to uncertainties regarding the extent of natu-
ral gas curtailments and the likelihood of interstate de-
regulation, TBS assumed in projecting gas prices that:
• Natural gas prices would equal coal prices by
1980 in dollars per million Btu, and
o Natural gas prices would equal oil prices by
1985 in dollars per million Btu.
OSHA: Occupational Safety and Health Administration
MESA: Mining Enforcement and Safety Administration
-------
11-39
These fossil-fuel price assumptions can be summa-
rized as follows:
FOSSIL FUEL PRICE ASSUMPTIONS
(current dollars)
1970
Coal ($/ironBtu)
($/ton)
Oil ($/mmBtu)
($/barrel)
Gas ($/mmBtu)
($/mcf)
Source: Exhibit
$
$
$
$
$
$
0.
7.
0.
2.
0.
0.
31
08
40
45
27
28
1975
$ 0.
$17.
$ 2.
$12.
$ 0.
$ 0.
79
58
03
37
70
72
1980
$ 1
$31
$ 2
$16
$ 1
$ 1
.46
.78
.69
.43
.46
.50
1985
$ 2
$44
$ 3
$20
$ 3
$ 3
.10
.52
.39
.66
.39
.47
1990
$ 3
$65
$ 4
$26
$ 4
$ 4
.09
.51
.32
.37
.32
.42
11-22
Fuels for internal combustion and gas turbine (IC/GT)
units were estimated by examining the relationship between
fuel costs for peaking units and conventional steam electric
plants, as reported in Uniform Statistical Reports. On the
basis of these data, IC/GT fuel costs were estimated to be 10
percent higher than oil- and gas-fired steam electric units in
terms of dollars per million Btu.
Given fossil fuel prices, total fuel costs can be
obtained from the product of fuel prices, heat rates, and
2
generation requirements. TBS assumed that the average heat
rate for existing units would approximate 1972 operations
'Heat Rate: amount of heat required to generate enough steam to produce
one kilowatt-hour1 of electricity.
-------
11-40
and that all capacity additions after 1972 would be more
efficient. Thus, as post-1972 capacity additions increase in
relative terms, the average heat rate will decline. The
average heat rates in terms of Btu per kilowatt-hour are
as follows:
AVERAGE HEAT RATES
(Btu/kwh)
Conventional Steam Electric Units
Coal-fired
Oil-fired
Gas-fired
Internal Combustion/Turbines
Existing
Units
10,269
11,234
10,764
14,000
Capacity
Additions
9,200
9,200
9,500
10,500
Source: EEI Statistical Yearbook (1973) and TBS estimates
Non-Fuel Costs
Operating and maintenance expenses, excluding fuel
have been sub-divided into those associated with generation
equipment and those associated with transmission, distribu-
tion, and other production costs. With the exception of
pumped storage costs, these expenses were computed from FPC
data for investor-owned electric utilities on a kilowatt-hour
3
basis. These non-fuel costs are expected to inflate at the
GNP rate.
Statistics of Privately-Owned Eleotric Utilities, Federal Power
Corm^88^on (1973).
-------
11-41
Assuming that pumped storage will be most closely
linked to nuclear units, operations and maintenance costs for
pumped storage have been estimated from nuclear costs. It is
also assumed that pumped storage has a two-thirds efficiency--
that is, it will take three kilowatt-hours of off-peak power
to produce two kilowatt-hours of on-peak energy.
Projections of non-fuel operating and maintenance
expenses are summarized in the following table:
NON-FUEL. OPERATING & MAINTENANCE EXPENSES
(mills/kwb, current dollars)
fc
Nuclear Steam Electric Units
Conventional Steam Electric Units
Hydraulic Units
Hydroelectric
Pumped Storage
Internal Combustion/Turbines
Transmisoion, Distribution and
Other 0/M Expenses
Source: 1972 data.: atfiti«t^.e»LJ5SL
1975-1990 data: Inflated
1872
1.34
1.08
1.15
2.01
3.32
4.32
at GWP
1975
1.71
1.38
1.47
2.56
4.23
5.50
rate froa
1980
2.27
1.83
.1.95
3.40
5.62
7.30
Dtllitian
1972 baoa
1985
2.86
2.30
2.45
4.28
7.07
9.18
FPC | ( If
1980
3.65
2.94
3.13
6.46
9.02
11.72
73) ;l
-------
11-42
CHAPTER 5
FINANCIAL POLICIES AND COSTS
Chapter 5 briefly describes the assumptions con-
cerning financial policies and costs employed in the PTm
projections. These financial assumptions are important be-
cause of the electric utility industry's long lead time for
construction of generating plants and because of its capital
intensity.
INDUSTRY STRUCTURE
The electric utility industry is the aggregation of
two principal sectors which, while providing essentially the
same service, differ significantly in their financial charac-
teristics. These sectors are the private firms (i.e., investor-
owned) and public agencies (i.e., Federal, state, and municipal).
In terms of generating capacity, generation, direct costs of
new capacity additions, and operating and maintenance costs,
the investor-owned systems account for 78 percent of the U.S.
total, while publicly-owned systems account for the remaining
22 percent. Because the publicly-owned systems have lower
financing costs and tend to have a high percentage of hydro-
electric generation, they account for only 15 percent of
total operating revenues for the industry, while investor-owned
systems account for approximately 85 percent.
TBS assumed that the 1974 ownership structure of the
industry will be maintained throughout the projection period.
Moreover, because almost 80 percent of the electric utility
industry's assets are held by investor-owned companies and
-------
11-43
because there is a paucity of readily available information
on the financial characteristics of those organizations in
the public sector, the two segments of the private sector
are modeled in detail and together serve as a basis for .
estimating certain characteristics of the public sector.
CAPITAL STRUCTURE AND CAPITAL COSTS
In projecting the capitalization of the industry,
TBS assumed that the industry's capital structure ratios
will remain relatively stable. The mix of financing for
investor-dwned utilities, therefore, is determined within
PTm by the following constraints upon their capital struc-
ture:
• Long-term debt—no more than 55 percent,
• Preferred stock—no more than 10 percent, and
• Common equity—at least 35 percent.
To determine future financing charges in total,
future interest rates and equity costs also need to be
projected. The average rate of interest on long-term debt
and the dividend rate on preferred stock have historically
been almost the same. Recent levels of these rates, however,
have been far above historical levels. In 1975, long-term
mortgage bonds for electric utilities ranged roughly from
9.5 percent for Aa bonds to 12 percent for Baa bonds. Given
that the prospect for major reductions in long-term inflation
rates, and therefore in nominal rates of return on financial
securities, is somewhat dim, TBS assumed an 11'^percent rate of
interest on long-term debt and dividends on preferred stock
for 1975-1976, and a 10 percent rate from 1977 on.
-------
11-44
With regard to the cost of common equity, TBS as-
sumed that average consumer charges per kilowatt-hour will
be set at,levels that yield a 14 percent return on common
equity. This assumption is consistent with either a target
14 percent return and no regulatory lag or a target rate in
excess of 14 percent with time lags in the regulatory process.
In recent years the actual return on common equity has averaged
between 10 and 12 percent. However, recent indications are
that regulatory agencies are beginning to adjust allowed re-
turns upward in response to the higher rates of return demanded
by investors under current inflationary conditions. In addi-
tion, TBS assumed a stable dividend payout ratio of 70 percent.
Regulatory agencies in the past have required elec-
tric utilities to capitalize a portion of the financing charges
associated with the funds supporting construction work in
progress. In 1972, the allowance for funds used during con-
struction (AFDC) approximated 6.43 percent of construction work
in progress. This rate has increased roughly in parallel
with financing costs in recent years. TBS has used an 8 per-
cent assumption to reflect the current practice of the indus-
try.
Because the total revenues and costs of the public
sector are computed in PTm as a fraction of the detailed
private sector costs, little in the way of financial assump-
tions is required for the public sector. One assumption,
the ratio of total financing requirements met by internal
versus external sources, is relevant. TBS has followed the
TAC-Finance assumption that 65 percent of total financing
requirements by the public sector will be met from external
sources.
-------
11-45
ACCOUNTING PRACTICES
Internal cash generation in an industry as capital
intensive as the electric utility industry depends importantly
upon the accounting procedures employed. As previously men-
tioned, this analysis assumes that the electric utility indus-
try is segmented into public and investor-owned firms and
that the latter group of utilities is further divided into
those which are required to use flow-through accounting
procedures and those which normalize their tax expenses.
While alternative regulatory accounting practices significantly
affect reported expenses and revenue requirements, they do
not affect actual taxes paid. The liberalized depreciation
and investment tax credit policies allowed by the government
apply equally to both groups.
TBS's projections assume a continuation of the
industry's current regulatory accounting practices. In
particular, it is assumed that 60 percent of the investor-
owned utilities will continue to utilize flow-through accounting,
while 40 percent use normalized accounting. For regulatory
and financial accounting purposes, TBS assumed straight-line
depreciation over 35 years. For tax purposes, depreciation
figures are the maximum allowed and make use of the asset
depreciation range (ADR) and the double-declining balance
depreciation provisions within the tax code. An exception
to the above is nuclear fuel, which is depreciated on a four-
year, straight-line basis for both tax and regulatory purposes.
In addition, a 4 percent investment tax credit (10 percent in
1975 and 1976) is permitted on 80 percent of capitalized expen-
ditures.
-------
11-46
TAXES
Taxes within PTm have been segmented into federal
income tax, state and local income tax, and taxes other than
on income (e.g., property and sales taxes). The tax rates
assumed in developing the projections are:
Percent
• Federal income tax rate 48.0
• State and local income tax rate 4.8
• Other taxes as a percent of revenues 10.5
Exhibit 11-23 summarizes the financial assumptions
described in this chapter.
-------
Exhibit II-l
PTM SALES AND CAPACITY ASSUMPTIONS
U.S. ELECTRIC UTILITY INDUSTRY
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
PEAK
DEMAND
(MM)
345.2
350,7
358.1
381.3
403.8
426.9
450.8
476.0
500.8
526.8
554.2
583.0
613.3
645.8
680.1
716.1
754.0
794.0
PEAK RESERVE
GROWTH MARGIN
(%) (%>
7.8
1.6
2.1
6.5
5.9
5.7
5.6
5.6
5.2
5.2
5.2
5.2
5.2
5.3
5.3
5.3
5.3
5.3
21.6
30.6
37.6
36.4
34.0
32.3
30.8
29.4
28.0
26.0
24.0
22.0
20.0
20.0
20.0
20.0
20.0
20.0
CAPAB
AT PEAK
(MM)
419.7
457.9
492.8
520.0
541.3
564.9
589.6
615.9
641.0
663.8
687.2
711.3
736.0
775.0
816.1
859.3
904.9
952.8
YR END CAPACITY
CAP FACTOR
(MM)
439.8
476.0
509.5
530.6
552.5
578.1
602.2
630.9
656.0
678.8
702.3
726.3
751.0
790.1
831.1
874.4
919.9
967.9
50.5
46.5
44.2
44.8
45.6
46.2
46.9
47.6
48.1
48.9
49.8
50.6
51.5
51.5
51.5
51.5
51.5
51.5
TOTAL GENER
GENER NOT SOLD
(BID
1855.3
1364.9
1908.2
2041.8
2160.2
2287.7
2420.3
2565.6
2701.5
2844.7
2995.5
3154.3
3321.4
3497.5
3632.8
3878.0
4083.6
4300.0
8.2
8.8
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
SALES
(BID
1703.1
1700.8
1736.5
1858.0
1965.8
2081.8
2202.5
. 2334.7
2458.4
2588.7
2725.9
2870.4
3022.5
3182.7
3351.4
3529.0
3716.0
3913.0
SALES
GROWTH
(X>
8.0
-.1
2.1
7.0
5.8
5.9
5.8
6.0
5.3
5.3
5.3
5.3
5.3
5.3
5.3
5.3
5.3
5.3
LOAD
FACTOR
(X)
61.4
60.7
60.8
61.1
61.1
61.2
61.3
61.5
61.6
61.6
61.7
61.8
61.8
61.8
61.8
61.8
61.8
61.8
Source: PTm (Electric Utilities)
-------
Exhibit II-2
PTH GROSS ADDITIONS TO GENERATING PLANT
INCLUDING CONVERSIONS TO COAL AND OIL
(MILLION KILOWATTS)
1973
1974
1975
1976
1977
1978
1979
1980
1931
1982
1983
1984
1985
1986
1987
1988
1939
1990
TOTAL
CAPACITY
439.8
476.0
509.5
530.6
552.5
578.1
602.2
630.9
656.0
678.8
702.3
726.3
751.0
790.1
831.1
874.4
919.9
967.9
TOTAL
ADDTNS.
41.9
38.1
36.1
26.1
26.9
28.7
27.4
32.3
30.6
28.6
29.4
30.0
30.8
45.4
47.7
50.0
52.6
55 • 3
FOSSIL
SUBTOTAL
25.8
17.7
20.4
13.2
16.5
15.0
19.2
16.7
14.4
13.4
13.8
14.1
14.5
21.3
22.4
23.5
24.7
26.0
COAL
19.8
10.2
11.1
8.4
12.4
13.3
17.9
15.9
14.4
13.4
13.8
14.1
14.5
21.3
22.4
23.5
24.7
26.0
OIL
4.9
5.8
6.3
3.9
3.6
1.7
1.3
.8
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
GAS
1.2
1.7
3.0
.9
.5
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
NUCLEAR
5.8
10.5
9.1
8.3
5.4
7.2
5.5
12.5
10.7
10.0
10.3
10.5
10.8
15.9
16.7
17.5
18.4
19.3
HYDRO
2.6
1.0
2.3
1.3
2.3
2.7
.8
2.0
1.5
1.4
1.5
1.5
1.5
2.3
2.4
2.5
2.6
2.0
PUMPED
2.6
1.0
.3
1.5
.3
.8
.2
.4
,9
.9
.9
.9
.9
1.4
1.4
1.5
1.6
1.7
PEAKER
5.0 «
7.9 ^
4.0 00
1.8
2.4
3.0
1.7
.7
3.1
2.9
2.9
3.0
3.1
4.5
4.8
5.0
5.3
5.5
Source: PTm (Electric Utilities)
-------
Exhibit II-3
PTm TOTAL GENERATION BY FUEL TYPE
INCLUDING CONVERSIONS TO COAL AND OIL
(billion kwh)
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985'
1986
1987
1988
1989
1990
TOTAL
GENER.
1855.3
1864.9
1908.2
2041.8
2160.2
2287.7
2420.3
2565.6
2701.5
2844.7
2995.5
3154.3
3321.4
3497.5
3682.8
3878.0
4083.6
4300.0
COAL
852.2
829.1
857.2
917.5
989.0
1064.3
1164.8
1261.4
1330.9
1403.7
1480.2
1560.6
1644.9
1733.8
1827.0
1924.9
2027.7
2135.6
OIL
296.7
278.3
275.5
306.8
335.9
351.5
365.0
361.3
354.9
350.0
345.0
339.8
334.4
322.8
311.2
299.7
288.2
276.8
GAS
328.0
304.6
262.5
237.3
207.3
186.3
165.1
142.4
138.1
134.4
130.5
126.5
122.4
115.9
109.5
103.0
96.6
90.1
NUCLEAR
83.2
113.5
192.3
239.6
270.2
308.6
339.8
404.1
464.3
524.6
588.4
655.7
726.7
813.1
903.5
998.2
1097.3
1201.1
HYDRO
233.0
266.0
250.0
261.2
274.2
287.1
293.1
301.8
311.6
322.7
334.4
346.5
359.1
368.4
378.1
308.2
398,9
410.0
PUMPED
32.0
36.3
34.1
40.7
42.7
46.4
47.5
49.4
53.8
58.3
63.1
68.1
73.4
79.3
85.4
91.9
98.7
105.8
PEAKER
30.1
37.0
36.6
38.6
40.8
43.4
44.9
45.2
48.0
51.0
54.0
57.3
60.6
64.3
68.1
72.1
76.2
80.6
£>.
CO
Source: PTm (Electric Utilities)
-------
Exhibit II-4
PTm TOT'iL CAPACITY BY FUEL TYPE
CAPACITY REPORT
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
PEAK
KU
345.2
350.7
358.1
381.3
403.8
426.9
450.8
476.0
500.8
526.8
554.2
583.0
613.3
645.8
680.1
716.1
754.0
794.0
K*H
£52+
1153.3
!Stt4.9
:^ia.2
?.r-». i. a
rznO.2
zi'.r? . 7
r-'-.ro . 3
TTr:5.6
r*J 1 . 5
2fr*4.7
I-S75.5
3^4.3
ssr.L.4
3»?7.5
3r.l2 . 8
3F.-g . o
49)53.6
4310 . 0
NET NUH
SALES
1703.1
1700.8
1736.5
1858.0
1965.8
20S1.8
2202.5
2334.7
2458.4
2588.7
2725.9
2870.4
3022.5
3182.7
3351.4
3529.0
3716.0
3913.0
12/31
CAPACITY
439,9
476.0
509.4
530.5
552.5
578.1
602.3
631.0
656.0,
678.8
702.2
726.2
751.0
790.0
831.1
874.4
919.8
968.0
TOTAL
ADDNS
41.8
38.1
36.1
26.1
26.9
28.7
27.4
32.3
30.6
28.6
29.4
30.0
30.8
45.4
47.7
50.0
52.6
55.3
TOTAL
RETIRED
1.5
2.0
2.4
5.0
5.0
3.1
3.2
3.3
5.5
5.7
5.9
6.0
6.1
6.2
6.4
6.7
7.0
7.2
CAPACITY REPORT
CAPACITY REPORT
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1909
1989
1990
TOTAL
FOSSIL
323.3
339.4
357.8
366.4
378.4
390.8
407.3
421.1
430.5
438.8
447.3
456.1
465.1
480.8
497.4
515.0
533.5
553.1
COAL
176.3
185.8
196.2
205.7
219.3
235.0
255.4
276.8
288.5
299.2
310.1
321.3
332.9
351 .2
370.4
390.8
412.1
434.6
OIL
60. *
66.3
72.3
79. .£•'
B7.«
92. r
95.*
96-.H
95,2
94. ~
93 .t
92. 2
91."
O f\ *\
VQ • il
89 *F.
87, ?
86- t>
QC: tr
DiJt-'f
GAS
86.2
87.4
89.2
80.9
71.6
63.9
56.0
*o *•>
1O • <£-
46.7
45.4
44.0
42.5
41.0
39.5
38.0
36.4
34.7
33.0
NUCLEAR
21.1
31.6
40.7
49.0
54.5
61.7
67.2
79.7
90.4
100.4
110.7
121.2
132.0
147.9
164.5
182.0
200.4
219.8
HYDRO
54.5
55.4
57.6
58.9
61.1
63.8
64.5
66.4
67.8
69.2
70.6
72.0
73.5
75.7
78.0
80.4
83.0
85.7
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
PUMPED
STORAGE
7.3
8.3
8.5
10.0
10.4
11.2
11.4
11.8
12.7
13.6
14.4
15.3
16.3
17.6
19.1
20.6
22.1
23.8
IC/GT
33.7
41.3
44.8
46.2
48.1
50.6
51.9
52.0
54.6
56. B
59.2
61.6
64.1
68.0
72.1
76.4
80.8
85.6
I
01
o
Source: PTm (Electric -Utilities)
-------
Exhibit II-5
PTM FUELS CONSUMED FOR GENERATION OF ELECTRICITY
INCLUDING CONVERSIONS TO COAL AND OIL
CONVENTIONAL STEAM AND PEAKING UNITS
TOTAL COAL OIL GAS
GENERATION (MM TONS) (MM BBLS) (BCF)
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1855.3
1864.9
1908.2
2041.8
2160.2
2287.7
2420.3
2565.6
2701.5
2844.7
2995.5
3154.3
3321.4
3497.5
3682.8
3878.0
4083.6
4300.0
388.7
376.2
387.0
412.7
449.5
488.8
540.1
591.2
626.1
663.1
702.2
743.7
787.5
827.1
868.5
912.2
958.0
1006.1
579.6
547.4
536.4
591.9
644.4
675.3
701.7
697.1
689.5
685.0
680.2
675.5
670.5
655.0
639.6
624.6
609.9
595.7
3689.3
3456.9
2984.0
2716.5
2394.6
2171.4
1941.2
1690.3
1654.8
1626.5
1596.2
1566.0
1534.8
1478.7
1424.1
1369.2
1315.7
1262.3
Source: PTm (Electric Utilities)
-------
PTm BASELINE FINANCIAL PROJECTIONS
(constant 1975 dollars)
CONSTANT DOLLARS
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
CUIP
28.76
28.49
26.03
28.81
32.47
34.73
38.36
36.81
37.38
40.61
45.60
52.48
63.04
67.11
71.45
76.07
81.01
86.28
CE
23.99
20.66
19.15
19.25
20.84
21.47
22.44
23.44
23.78
25.45
28.26
31.31
36.27
40.86
43.56
46.44
49.50
52.77
CE -
CUIP
17.14
20.93
21.62
16.47
17.18
19.22
18.80
24.99
23.21
22.22
23.27
24.44
25.72
36.80
39.22
41.81
44.56
47.50
EXT
FIN
18.47
15.56
14.28
13.42
14.87
15.03
15.93
16.30
15.90
17.57
19.31
22.16
26.44
30.20
32.03
33.84
35.48
37.67
OPER
REV
40.85
50.30
51.37
56.56
61.21
65.06
69.61
74.03
77.65
82.19
86.70
91.56
96.76
102.19
109.25
116,74
124.66
133.07
CONS
CHRG
23.99
29.57
29.58
30.44
31.14
31.25
31.61
31.71
31.59
31.75
31.81
31.90
32.01
32.11
32.60
33.08
33.55
34.01
I
en
to
CONSTANT DOLLARS
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
CUMM
CE
23.99
44.65
63.80
83.05
103.90
125.37
147.81
171.24
195.03
220.48
248,74
280.05
316.32
357.19
400,75
447.18
496.69
549.46
CUMM
- CHIP
0
• 0
21.62
38.09
55.27
74.49
93.29
118.27
141.49
163.71
186.98
211.41
237.13
273.93
313.15
354.95
399.52
447.02
CUMM
EX FIN
18.47
34.02
48.30
61.72
76.59
91.62
107.56
123.86
139.76
157.33
176.64
198.81
225 . 25
255.45
237.48
321.32
356. iiO
394.48
CUMM
OPER
40.85
91.15
142.52
199.08
260.29
325.35
394.96
469.00
546.65
628.84
715.55
807.10
903.07
1006.05
1115.30
1232.04
1356.70
US 9. 7 7
0+M
21.58
28.63
29.31
32.46
34.94
37.41
40.21
42.76
43.80
46.03
48.43
51.00
53.75
56.42
59 . 34
62.49
65,87
69 . 50
CUMM
0+M
21.58
50.21
79.52
111.97
146.92
184.33
224.54
267.30
311.10
357.13
405.56
456.56
510.31
566.73
626.08
688.56
754.43
823.93
Source: PTm (Electric Utilities)
-------
Exhibit I1-7
PTm BASELINE FINANCIAL PROJECTIONS
(current dollars)
CURRENT DOLLARS
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
CUIP
24.72
25.86
26.03
30.83
37.00
41.87
48.61
48.89
51.98
59.12
69.50
83.75
105.32
117.73
131.60
147.14
164.52
183.98
CE
20.62
18.75
19.15
20.60
23.75
25.89
28.43
31.12
33.07
37.05
43.07
49.97
60.61
71.69
80.24
89.81
100.53
112.53
CE -
CWIP
16.65
17.61
18.98
15.80
17.57
21.02
21.69
30.85
29.98
29.90
32.69
35.73
39.03
59.29
66.36
74.28
83.15
93.07
EXT
FIN
15.87
14,12
14.28
14.36
16.95
18.12
20.19
21.65
22.11
25.57
29.44
35.37
44.18
52.98
59.00
65.46
72.06
80.33
OPER
REV
35.10
45.64
51.37
60.52
69.75
78.44
as. 21
98.31
107.96
119.65
132.15
146.11
161.67
179.27
201.24
225.78
253.16
283.76
CONS
CHRG
20.61
26.84
29.58
32.57
35.48
37.68
40.05
42.11
43.92
46.22
48.48
50.90
53.49
56.33
60.05
63.98
68.13
72.52
CURRENT DOLLARS
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
198V
1990
CUMM
CE
0
0
19.15
39.75
63.50
89.39
117.82
148.95
182.01
219.06
262.13
312.10
372.71
444.39
524.63
614.44
714.97
827.50
CUMM
- CWIP
0
0
18.98
34.78
52.36
73.38
95.07
125.91
155.89
185.79
218.48
254.21
293.24
352.53
418.89
493.16
576 .31
669.38
CUMM
EX FIN
0
0
14,28
28.64
45.58
63.71
83.90
105.54
127.66
153.23
182.67
218.03
262.21
315.20
374.19
439.65
511.71
572.04
CUMM
OPER
0
0
51.37
111.89
181.64
260.08
348.29
446.60
554.56
674.22
806.36
952.47
1114.14
1293.41
1494.65
1720.43
1973.59
2257.35
0+M
18.54
25.98
29.31
34.73
39.82
45.11
50.95
56.78
60.90
67.01
73.81
81.38
89.81
98.98
109.31
120.86
133.77
148.20
CUMM
0+M
0
0
29.31
64.04
103.86
148.97
199.91
256 . 70
317.60
384.61
458.42
539.80
629.61
728.59
837.90
958.76
1092.53
1240.73
I
01
u
Source: PTm (Electric Utilities)
-------
Exhibit I1-8
BASELINE FINANCIAL PROJECTIONS
(dollar figures in billions of 1975 dollars)
1973
1974
1977
1980
1983
1985
1990
Capital Expenditures
Total for year
Total since 1974
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1974
Operating Revenues
Total for year
Total since 1974
Operations and Maintenance Expenses
Total for year
Total since 1974
Consumer Charges (mills/kwh)
Average for year
$ 17.1
$ 28.8
$ 18.5
$ 40.9
$ 21.6
24.0
$ 20.9
$ 28.5
$ 15.6
$ 50.3
$ 28.6
29.6
$ 17.2
53.3
$32.5
$ 14.9
42.6
$ 62.2
169.1
$ 34.9
96.2
31.4
$ 25.0
118.3
$ 36.8
$ 16.3
89.8
$ 74.0
377.9
$ 42.8
217.1
31.7
$ 23.3
187.0
$ 45.6
$ 19.3
142.6
$ 86.7
624.4
$ 48.4
355.4
31.8
$ 25.7
237.1
.$ 63.6
$ 26.4
191.2
$ 96.8
812.7
$ 53.8
460.1
32.0
$ 47.5
447.0
$ 86.3
$ 37.6
360.5
$133.1
1,398.6
$ 69.5
773.7
34.0
net of CHIP increase
n
excludes nuclear fuel, which is included in Capital Expenditures
Source: PTm (Electric Utilities)
-------
Exhibit I1-9
FINANCIAL PROJECTIONS OF PREVIOUS BASELINE CONDITIONS
(dollar figures in billions of 1975 dollars)
1
.Capital Expenditures
Total for year
Total since 1974
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1974
Operating Revenues
Total for year
Total since 1974
2
Operations and Maintenance Expenses
Total for year
Total since 1974
Consumer Charges (mills/kwh)
Average for year
1973
15.2
-
21.5
8.4
-
43.2
-
19.4
-
25.8
1974
10.6
-
20.2
3.3
-
46.1
-
21.2
-
28.4
1977
17.4
47.9
29.0
12.0
35.9
57.5
160.6
28.9
79.5
28.9
1980
21.1
107.3
37.6
15.4
78.0
69.0
355.5
35.6
179.4
29.5
1983
28.6
185.5
47.9
19.5
135.0
81.8
588.5
41.6
299.1
28.4
1985
31.9
247.5
53.6
22.0
177.7
90.9
765.6
45.3
387.7
28.2
1990
39.4
426.1
68.1
25.8
295.1
114.0
1,287.6
54.2
639.9
27.0
Ul
Ul
net of CWIP increase
2
excludes nuclear fuel
Source: PTm (Electric Utilities)
-------
Exhibit 11-10
FINANCIAL PROJECTIONS SUMMARY BASED ON
PREVIOUS LOAD GROWTH ASSUMPTIONS
AND CURRENT COST ESCALATION FACTORS
(dollar figures in billions of 1975 dollars)
Capital Expenditures
Total for year .
Total since 1974
Construction.Work in Progress
End of year
External Financing
Total for year
Total since 1974
Operating Revenues
Total for year.
Total since 1974
Operations and Maintenance Expenses
Total for year
Total since 1974
Consumer Charges (mills/kwh)
Average for year
1973
$ 20.7
$23.4
$11.8
$46.8
$21.6
27.5
1974
$12.8
$ 20.5
$ 3.8
$54.8
$ 27.7
33.3
1977
$ 19.1
52.3
$29.9
$14.2
40.3
$ 63.5
177.0
$ 33.6
93.9
31.6
1980
$. 23.3
115.4
$ 42.6
$ 19.3
89.4
$ 75.4
390.7
39.3
206.0
31.8
1983
$ 32.9
204.1
$ 57.7
$24.1
158.7
$ 91.7
649.5
$ 45.5
337.6
31.4
1985
> 38.2
277.7
$67.2
$28.3
213.0
$103.6
850.5
$49.5
434.3
33.5
1990
$ 50.2
500.1
$ 92.1
$ 35.2
368.9
5 132.7
L362.1
$ 57.5
704.4
31.0
01
net of CHIP increase
excludes nuclear fuel, which is included in Capital Expenditures
Source: PTm (Electric Utilities)
-------
Exhibit 11-11
FINANCIAL PROJECTIONS SUMMARY BASED ON
HISTOfilC GROWTH RATES
(dollar figures in billions of 1975 dollars)
1
Capital Expenditures
Total for year
Total since 1974
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1974
Operating Revenues
Total for year
Total since 1974
2
Operations and Maintenance Expenses
Total for year
Total since 1974
Consumer Charges (mills/kwh)
Average for year
1973
$ 17.1
-
$ 28.3
$ IS. 5
-
$ 40.9
_
$ 21.6
-
24.0
1974
$ 20.9
-
$ 28.5
$ 15.6
-
$ 50.3
_
$ 28.6
-
29.6
1977
$ 17.0
54.9
$ 35.5
$ 16.8
44.9
$ 61.2
168.9
$ 34.9
96.5
30.7
1980
.$ 25.3
119.5
$ 64.5
$ 28.9
116.2
$ 76.6
382 . 1
$ 44.4
219.6
31.2
1983
$ 42.0
238.2
$ 81.2
$ 38.8
214.9
$ 96.5
64.6 . 4
$ 50.7
362.1
31.9
1985
$ 49.4
333.1
$ 98.6
$ 45.5
312.4
$116.2
868.5
$ 58.1
474.5
33.4
1990
$ 77.6
665.0
$147.8
$ 66.6
600.5
$178.2
1,625.7
$ 83.0
835.0
36.2
I
01
,-'••. -net of CVIP increase
•*- - -' 2
•;.v- excludes nuclear fuel, which, is included in Capital
'Source: PTm (Electric Utilities)
-------
Exhibit 11-12
FINANCIAL PROJECTIONS SUMMARY BASED ON
FPC CAPACITY ADDITIONS
(dollar figures in billions of 1975 dollars)
1
Capital Expenditures'
Total for year
Total since 1974
Construction .Work in Progress
End of year
External Financing
Total for year
Total since 1974
Operating Revenues
Total for year
To^tal since 1974
2
Operations and Maintenance Expenses
Total for year
Total since 1974
Consumer Charges (mills/kwh)
Average for year
1973
$ 17.1
-
$ 28.8
$ 18.5
-
$ 40.9
_
$ 21.6
-
24.0
1974
$ 20.9
-
.$ 28.5
$ 15.6
-
$ 50.3
_
$ 28.6
-
29.6
1977
$ 22.2
57.1
$ 36.3
$ 16.3
46.8
$ 61.4
169.6
$ 34.9
96.6
31.3
1980
$. 30.2
130.5
$ 31.4
$ 14.9
94.4
$ 74.9
330.2
$ 42.3
216.0
32.1
1983
$ 21.2
189.6
$ 45.5
$ 18.7
142.2
$ 86.7
628.4
$ 48.1
353.1 '
31.8
1985
? 25.7
239.7
$ 62.9
$ 26.4
190.7
$ 96.3
816.0
$ 53.4
457.1
31.9
1990
$ 47.4
449.3
$ 86.1
$ 36.6
359.5
$132.5
1, 399 . 4
$ 69.0
768.4
33.9
I
O1
00
net of CWIP increase
2
excludes nuclear fuel, which is included in Capital Expenditures
Source: PTm (Electric Utilities)
-------
11-59
Exhibit 11-13
CAPACITY FACTORS BY FUEL TYPE AND OWNERSHIP CATEGORY
For Representative Years
Coal
Oil
Gas
Nuclear*
Hydro
Pumped Storage
Peakers
Investor-Owned
1973
55.1
55.7
43.4
45.0
39.0
45.1
8.0
1980
55.0
48.0
35.0
60.0
45.5
45.1
8.0
1985
55.0
43.0
34.5
60.0
45.5
45.1
8.0
Publicly Owned
1975
55.1
55.7
43.4
45.0
34 . 0
59.4
19.7
1980
55.0
48.0
35.0
60.0
60.0
59.4
19.7
1985
55.0
43,0
34.5
60.0
60.0
59.4
19.7
*Nuclear based upon 3-year power ascendency for new units
averaging: 40 percent in the first year, 55 percent in
the second, and 65 percent in the third and following years,
Source: 1973 figures from Edison Electric Institute
1980, 1985 projected from FPC additions, TBS
demand forecast, and actual 1975 experience
of several utilities.
-------
11-60
Exhibit 11-14
ESTIMATES OF CAPITAL COSTS FOR NUCLEAR UNITS
1970-1990
(in-service dates; figures in current dollars)
Year
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
Historic
Industry
$/kw
119C
134d,.139-148a
150°, 178f
146C, 2259
157C
209C
209-222C
222C
300C
404C
552d
429e, 456°, 725d
449e, 558C
727d
l,042d
Revised
Industry
$/kw
199C
260C, 352b
295b
354C, 367b
368-380b
287b, 413°
490b
370-395°
475C
458C, 599b, 8171
600-700C
702f
850C
850-900h, l,284i, l,120j
TBS
Estimates
$/kw
ISO
199
245
280
S21
367
420
477
542
610
699
736
774
814
857
901
948
99?
1,049
1,104
1,160 ,
Sources:
a) Electrical World. 1973
b) Irvin C. Bupp, et al, Trends in Light Water Reactor Capital Costs
in the United States; Causes and Consequences, 1974, Figure 6.
c) Power Engineering, 1974
d) Atomic Energy Commission, 1974
e) Federal Power Conmission, 1972
f Arthur D. Little, 1973
g) Federal Power Commission—NPS, Technical Advisory Committee-
Finance, The Financial Outlook for the U.S. Electric Power
Industry, December 1974.
.h) Electrical World (re: Detroit Edison), 1/1/76
i) Irvin C. Bupp, "Economics of Nuclear Power," Technology Review. 2/76
j) Business Week (re: Con Edison), 11/17/75
-------
II-61
Exhibit 11-15
FOSSIL UNIT CAPITAL EXPENDITURE COST ASSUMPTIONS
1970 - 1990
(in-service dates, figures in current dollars)
$/KW
800
700
600
500
400
300
200
100
COAL
$960 '
I
I
I
j
I
$/KU
800
700
600
500
400
300
200
100
OIL
1970 1975 1980 1985 1900
1970 1975 1980 1985 1990
GAS
1C
ROD
70(1
non
r.oo
400
300
200
$/KW
800
700
BOO
500
400
300
200
100
YGT
1970 I97.r) 1980 1985 3990
1970 1975 1980 1985 1990
Source: FPC, Klr-ctri f.al World, EEI , U.S. Atomic Energy Commission; coal prices also
reCled. ar.tual 197ft exnerience and projections for selected utilities.
-------
Exhibit 11-16
ESTIMATES OF CAPITAL COSTS FOR FOSSIL-FUELED AND HYDRAULIC UNITS
1970 - 1990
(in-service dates; figures in current dollars)
Year
1970
1972
1975
1976
1978
1979
1980
1981
1983
1984
1985
1990
Fossil Fuel
Coal
Industry
Estimates
$/kw
151-1709
196C, 250b, 327f
474h
8001
310b, 450C, 488 j
362-378d
5889
638C
560d, 722 j, 800'1
740d, 950C
TBS
$/kw
120
150
211
226
342
41S
498
533
610
653
698
980
Oil
Industry
Estimates
$/kw
145-1633
215f
337-352d
3899
463d
664d
TBS
S/kw
240
130
?SO
140
230
300
220
_
-
-
-
-
Gas
Industry
Estimates
$/kw
87-96a
310d
TBS
$/kw
80
90
135
155
210
240
275
-
-
-
-
-
IC/6T
Industry
Estimates
$/kw
90f
100a
110-125f
155-165f
TBS
$/kw
90
100
125
135
160
170
185
200
230
245
260
370
Hydro
Industry
Estimates
$/kw
118-381 e
TBS
$/kw
300
350
440
475
555
600
650
700
800
860
920
1,290
Pumped Storage
Industry
Estimates
$/kw
70-1366
TBS
$/kw
100
116
145
160
185
200
215
235
270
290
310
430
o
to
Sources:
a) Electrical World. 1973
b) Irvin C. Bupp, et al, Trends in Light Water Reactor Capital Costs in the United States: Causes and Consequences. 1974, Figure 6.
c) Power Engineering. 1974
d) Atomic Energy Commission, 1974
e) Federal Power Commission, 1972
f) Federal Power Commission—UPS, Technical Advisory Committee—Finance, The Financial Outlook for the U.S. Electric Power Industry, 12/74
g) Arthur D. Little, 1973
h) Electrical World (re: Buckeye Power) 1/15/76. includes pollution control costs
i) Electrical World (re: No. Indiana Pub. Service, Detroit Edison) 1/1/76
j) Irvin C. Bupp, "Economics of Nuclear Power," Technology Review, 2/76
-------
Exhibit 11-17
IMPLICATIONS OF INDUSTRY PROJECTIONS OF CAPITAL COSTS
IN TERMS OF ESCALATION RATES
1972 - 1990
(percent per year)
Year
1972
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
Fossil Fuel
Coal
12.0
12.0
12.0
12.0
20.5
20.5
20.5
20.5
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
Oil
11.0
11.0
11.0
11.0
8.5
8.5
8.5
8.5
8.5
.
_
_
_
_
_
_
-
.
-
Gas
15.0
15.0
15.0
15.0
15.0
15.0
15.0
15.0
15.0
-
. _
-
-
_
_
-
-
-
-
IC/GT
8.0
8.0
8.0
8.0
8.0
8.0
8.0
8.0
8.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
Hydro
8.0
8.0
8.0
8.0
8.0
8.0
8.0
8.0
8.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
Pumped
Storage
8.0
8.0
8.0
8.0
8.0
8.0
8.0
8.0
8.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
Nuclear
14.4
14 -.4
14.4
14.4
13.6
13.6
13.6
13.6
5.2
5.2
5.2
5.2
5.2
5.2
5.2
5.2
5.2
5.2
5.2
i
O5
U
Source: Derived from annual industry capital cost estimates shown in Exhibits 11-14 and 11-16.
-------
Exhibit 11-18
PATTERN OF CASH FLOWS FOR CAPITAL PROJECTS
ANNUAL EXPENDITURE OF FUNDS (EXCLUDING AFDC)
(percent per year)
Fossil Steam Plants
Nuclear Plants
Nuclear Fuel
Hydro Plants
Pumped Storage
Plants
IC/6T Plants
Transmission &
Distribution
Pollution Control
Capital Equipment
T-5
_
5
-
5
5
-
_
-
T-4
5?
15
-
15
15
-
.
.- -
T-3
2G*
25
-
20
20
• -
-
-
T-2
30S
25
-
20
20
20
' -
20
T-l
30%
15
-
25
25
40
-
40
T
(In-Service Year)
15%
15
100
15
15
40
100
40
OJ
Source: TBS estimates based on examination of representative utility company expenditures.
-------
n-65
Exhibit 11-19
FORECASTS OF ELECTRIC DEMAND GROWTH
(kWh sales in trillions; implied growth percent)
Electrical World 9/74
IGR*
Electrical World 9/75
IGR*
National Electric
Reliability Council 4/74
IGR*
Temple, Barker & Sloane, Inc. ,***
IGR*
NPS - TAC Finance U/74
Historic
IGR*
Moderate
IGR*
FEA Project Independence 11/74
$7 Oil BAU W/Cons.
IGR*
$7 Oil BAU W/0 Cons.
IGR*
$7 Oil ACC W/Cons.
IGR*
$7 Oil ACC W/0 Cons.
IGR*
$11 Oil BAU W/Cons.
IGR*
$11 Oil BAU W/0 Cons.
IGR*
$11 OU ftCr, W/Cons.
IKR*
$11 Oil ACC W/0 Cons.
IGR*
NPS- Task Force on Forecast
Review 8/73
'IGR* '
1972
1.58
1.58
1.58
1.58
1.58
1.58
1.60
1.60
1.60
1.60
1.60
1.60
l.fiO
l.tiCl
1.58
1975
1.86
5.6
1.72
8.2
2.17
11.2
1.74
5.0
1.92
6.7
1.83
5.0
1977
2.11
2.02
2.53
2.20
6.6
2.26
7.2
2.13
5.9
2.15
6.1
1978
2.23
2.15
2.71
2.27
2.31
1980
2.50
6.1
2.37
6.4
3.12
7.5
2.34
6.3
2.71
7.1
2.58
7.1
2.53**
5.9
2.67**
6.6
2.53**
5.9
2.67**
6.. 6
2.46**
5.6
2.59**
6.2
;• «*•
"r.fl
i!,5'J"
6.2
3.17**
9.1
1985
3.24
5.3
3.15
6.5
4.40
7.1
3.02
5.6
3.91
7.6
3.55
6.6
3.37
5.9
3.72
6.9
3.34
5.7
3.69
5.7
3.25
5.7
3.62
6.9
1 . 70
ti.ti
3.56
6.6
4.44
7.0
1990
4.20
5.3
4.01
5.8
3.95
5.5
5.39
6.6
4.64
5.5
5.85
5.7
1995
5.70
6.3
5.27
7.60
5.4
2000
10.18
6.0
*'rhn implied groijth rate ie calculated whenever possible on a five-year incremental basis. For all
studies but FEA'a, a 197S baofi of 1,57? billion kWh Bales ia assumed. FEA assumes a 1972 base of
1,597 billion kUh.
"An implied graoth of 1972-1980 has been calculated.
***Using Electrical World a/71 asaumptiirtia
BAU " Buaineae aa usual
ACC = Accelerated
W/Cons. = With conservation
W/0 Cons. » Without conservation
Sources: National Electric Reliability Council 4/1/74
Electrical World - 24th AEI Forecast 9/73
Electrical World - 25th AEI Forecast 9/74
National Power Survey - TAC Finance 11/74
National Power Survey - Task Force on Forecast Review 8/73
Federal Energy Administration - Project Independence 11/74
-------
11-66
Exhibit 11-20
ELECTRICAL WORLD PROJECTIONS1
TOTAL SALES, SYSTEM OUTPUT, PEAK LOAD, CAPABILITY, AND MARGIN
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1990
1995
Total
Sales
(bill. kWh)
830.8
890.4
953.4
1,039.0
1,107.0
1,202.3
1,307.2
1,391.4
1,466.4
1,577.7
1,703.2
1,738.7
1,864.1
1,994.1
2,109.5
2,233.3
2,361.9
2,504.3
2,608.8
2,753.9
2,910.7
3,070.5
3,241.5
4,195.5
5,695.4
Total
Output
(bill. kWh)
924.0
989.2
1,062.7
1,155.7
1,224.5
1,330.4
1,449.6
1,540.3
1,617.5
1,754.9
1,878.5
1,923.0
2,061.8
2,205.4
2,333.1
2,470.0
2,612.3
2,769.8
2,885.3
3,045.8
3,219.2
3,396.0
3,585.1
4,640.2
6,299.1
Annual Non-
Coin Peak
(mill. kW)
161.3*
175.4
186.8
203.9
214.0
238.6
258.3
275.4
293.1
320.2
345.1
360.6
386.5
411.6
435.9
460.7
486.5
513.6
535.6
564.4
595.6
625.6
661.2
848.9
1,143.2
Capability
At Peak
(mill. kW)
210.6*
217.1
229.6
241.5
258.8
279.8
301.2
327.8
354.6
383.0
417.4
455.5
493.6
527.9
553.6
578.8
600.2
624.4
647.6
673.8
706.3
742.7
780.7
1,002.6
1,349.0
Gross Peak
At Margin
(*)
30.2*
23.7
22.9
18.4
20.8
17.2
16.6
18.7
20.9
19.6
20.9
26.2
27.7
28.2
26.9
25.1
23.3
21.5
20.9
19.3
18.5
18.7
18.0
18.1
18.0
*Peak in winter for 1963 but in ewrmer after 1963 until 1990 when electric heating
could shift peaks to winter.
Source: Edison Electric Institute; Federal Power Commission: Electrical World
^Table reprinted from Electrical World Magazine, September 15, 1974
25th AEI Forecast, Pg. 54.
-------
11-67
Exhibit 11-21
COAL AND OIL CONVERSIONS
1975-1980
Gas to Coal
Gas to Oil
Coal Capacity
(million kw)
Oil Capacity
(million kw)
Baseline Conversions
9.2
26.25
Other Conversions Before Clean Air Act
Oil to Coal
Subtotal
11.1
20.3
(11.1)
15.15
Oil to Coal
Gas to Coal
Gas to Oil
Total
Conversions After Clean Air Act
9.5
9.2
18.7
(9.5)
26.25
18.75
Source: Environmental Protection Agency;
Federal Power Commission data;
Foster Associates, Inc., August 1975
-------
Exhibit 11-22
FUEL COST ASSUMPTIONS
1974-1990
(current dollars)
„ 1971 b
® 1972 b
o 1973*
O. v
g 1974 b
•a 19 75
-------
11-69
Exhibit 11-23
FINANCIAL ASSUMPTIONS
(percent)
-
Capital Costs
Interest Rate, Long-Term Debt (%)
Return on Equity
Dividend Rate, Preferred Stock (%)
Capital Mix
Public Sector:
% Financing from Internal
Sources
Private Sector:
Minimum % Common Equity
Minimum % Common + Preferred
Tax Rates
Federal Income Tax
State Income Tax
Other Taxes, on
Operating Revenues
Investment Tax Credit
% Plant Eligible for
Investment Tax Credit
1975
11.0
14.0
11.0,
35.0
35.0
45.0
48.0
4.8
10.5
10.0
80.0
. 1980
10.0
14.0
10.0
35.0
35.0
45.0
48.0
4.8
10.5
4.0
80.0
1985
10.0
14.0
10.0
35.0
35.0
45.0
48.0
4.8
10.5
4.0
80.0
1990
10.0
14.0
10.0
35.0
35.0
45.0
48.0 1
4.8
10.5
4.0
80.0
Source: Federal Power Commission, Statistics on
Privately Owned Electric Utilities, 1972.
1973.
-------
11-70
Exhibit 11-24
GNP DEFLATOR
FOR USE IN CONSTANT DOLLAR ANALYSIS
Year
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986-2000
GNP Deflator
(1975=100)
141.4
146.1
154.3
170.0
100.0
107.0
114.0
120.6
126.7
132.8
139.0
145.6
152.4
159.7
167.1
-
Annual GNP
Inflation Rate
3.3
5.6
10.2
9.5
7.0
6.5
5.8
5.1
4.8
4.7
4.7
4.7
4.8
4.6
5.0
INFLATION RATES
Pollution
Control
Equipment
-
•
-
-
8.0
8.0
7.0
7.0
7.0
7.0
7.0
6.0
6.0
6.0
5.0
Pollution
Control
O&M
-
-
-
-
7.0
6.5
5.8
5.0
5.0
5.0
5.0
5.0
5.0
5.0
5.0
Source: Deflator and GNP inflation rates from Chase Econometric
Associates, Inc., recomputed to 1975 base year; inflation
rates for pollution control estimated at GNP rate for 0/M
and 1.5 to 2.0 points above GNP for capital equipment.
-------
Exhibit 11-25
INCOME STATEMENT FOR INVESTOR-OWNED ELECTRIC UTILITIES
(BILLIONS OF CURRENT DOLLARS)
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
OPERATING REVENUE
-OPER. + HAINT. EXP.
-0/M EXP. - THERMAL
-0/M EXP. - CHEMICAL
-TAXES (OTHER)
-DEPRECIATION - PLANT
-DEPRECIATION - NUC FUEL
° +AFDC
EBIT
-INTEREST
EBT
-TAXES (INCOME)
+ ITC
NET INCOME
-DIVIDENDS (PREF)
-DIVIDENDS (COMM)
RETAINED EARNINGS
COVERAGE RATIOS t
EBIT/INTEREST
EBIT/INT i PFD DIV
43.7
23.1
.0
.0
3.7
3.9
.3
1.7
14.3
4.9
9.4
3.3
.7
6.8
.8
4.2
1.8
2.9
2.5
51.4
27.4
.0
.0
4.4
4.3
.5
1.8
16.7
5.7
11.0
4.1
.6
7.5
.9
4.6
2.0
2.9
2.5
59.3
31.4
.0
.0
5.0
4.7
.7
2.2
19.5
6.6
13.0
4.9
.3
8.3
1.1
5.1
2.2
3.0
2.6
66.7
35.5
.0
.0
5.7
5.2
.9
2.5
21.9
7.5
14.4
5.5
.4
9.3
1.3
5.6
2.4
2.9
• 2.5
75.0
40.1
.0
.0
6.4
5.7
1.0
2.9
24.6
8.5
16.0
6.1
.4
10.3
1.4
6.2
2.7
2.9
2.5
83.6
44.7
.0
.0
7.1
6.4
1.1
3.1
27.3
9.7
17.7
6.8
.5
11.4
1.6
6.8
2.9
2.8
2.4
91.8
48.0
.0
.0
7.8
7.1
1.4
3.2
30.7
10.8
19.9
7.8
.5
12.6
1.8
7.5
3.2
2.8
2.4
3
101.7
52.8
.0
.0
8.6
7.8
1.7
3.5
34.3
12.1
22.2
8.8
.5
13.9
2.1
8.3
3.5
2.8
2.4
112.3
58.2
.0
.0
9.5
8.5
2.0
4.1
38.1
13.6
24.5
9.7
.5
15.4
2.3
9.1
3.9
2.8
2.4
124.2
64.1
.0
.0
10.6
9.4
2.4
4.9
42.6
15.4
27.1
10.6
.6
17.1
2.7
10.1
4.3
2.8
2.4
137.4
70.8
.0
.0
11.7
10.3
2.8
6.0
47.9
17,7
30.2
11.6
.6
19,3
3,1
11.4
4.9
2.7
2,3
Source: PTm (Electric Utilities)
-------
Exhibit 11-26
BALANCE SHEET FOR INVESTOR-OWNED ELECTRIC UTILIES
(BILLIONS OF CURRENT DOLLARS)
1975
1974
1977
1978
1979
1980
1981
1982
1983
1984
1985
LONG TERM ASSET ACCOUNTS
GROSS PLANT. IN SERVICE
-ACCUM. DEPRECIATION
NET PLANT IN SERVICE
+NUC. FUEL (NET)
+CUIP
NET ELECTRIC PLANT
LONG TERM LIABILITY ACCOUNTS
DEFERRED ITEMS
LONG TERM DEBT
POST 1974
TOTAL
PREFERRED STOCK
POST. 1974
TOTAL
OWNERS EQUITY
POST 1974 CASH ISSUES
POST 1974 RETAINED EARN.
TOTAL
TOTAL CAPITALIZATION
TOTAL LONG TERM LIABILITIES
138.8
34.3
104.5
2.6
20.7
127.9
4.9
25.9
70.6
2.2
12.8
8.3
4,8
44.7
127.8
150.5
38.6
111.8
3.1
24.5
139.5
5.7
33.8
77.5
3.4
14.0
10.7
6.8
49.1
140.4
163.5
43.4
120.2
3.4
29.4
152.9
6.3
43.1
85.7
4.9
15.5
13.8
9.0
54.4
155.4
179.0
48.6
130.4
3.7
33.3
167.4
7.0
52.8
94.7
6.6
17.2
17.1
11.4
.60.1
171.7
194.9
54.3
140.6
4.1
38.7
183.3
7.7
63.8
104.7
8.4
19,0
20.8
14,0
66.4
189.3
217.4
60.7
156.8
4.9
39.0
200.6
8.5
75.4
115.5
10.3
20.9
24.7
17.0
73.3
209.4
239.1
67.7
171.4
5.8
41.4
218.5
9.3
87.3
126.6
12.4
23.0
28.6
20.2
80.4
229.6
260.4
75.5
184.9
6.6
47.1
238.5
10,2
101.3
139.1
14.6
25.2
33.0
23.7
88.3
252.3
283.5
84.1
199.5
7.5
55.3
262.2
11.1
116.8
153.8
17.3
27.9
38.5
27.6
97.7
279.2
308.6
93.5
215.2
8.5
66.5
290.2
12.1
135.6
171.4
20.5
31.1
45.3
32.0
108.9
311.0
335.8
103.7
232.1
9.6
83.5
325.2
13.1
158.5
193.4
24.5
35.1
54.4
36.8
122.9
351.1
132.6 146.1
161.7
178.7
197.5
217.9
239,0
262.5
290.3-
323.1
Source: PTm (Electric Utilities)
364.2
-J
-------
Exhibit 11-27
APPLICATIONS AND SOURCES OF FUNDS
FOR INVESTOR-OWNED ELECTRIC UTILITIES
(BILLIONS OF CURRENT DOLLARS)
1975
1976
1977
1978
1979
1980.
1981
1982
1983
1984
1985
APPLICATIONS OF FUNDS
CAPITAL EXPEND. + AFDC
+REFUNDINGS
TOTAL APPLICATIONS
SOURCES OF FUNDS
INTERNAL GENERATION
RETAINED EARNINGS
+DEPRECIATION-PLANT
+DEPRECIATION-NUC. FUEL
+DEFERRALS
TOTAL
EXTERNAL FINANCING
LONG-TERM DEBT
•(•STOCK (PREF)
+STOCK (COMM)
TOTAL
TOTAL SOURCES
CUM. EXTERNAL FINANCING
16.9
1.7
18.6
1.8
3,9
.3
.9
6.9
8.2
1.2
2.3
11.7
18.6
36.3
Jtiliti
18.2
1.0
19.3
2.0
4.3
.5
.8
7.6
8.0
- 1.3
2.4
11.7
19.3
48.0
es)
21.1
1.0
22.1
2.2
4.7
.7
.7
8.3
•9.2
1.5
3.1
13.8
22.1
61.8
23.1
.7
23.9
2.4
5.2
.9
.7
9.2
9.7
1.6
3.3
14.7
23.9
76.5
25.5
1.0
26.5
2.7
5.7
1.0
.7
10.1
10.9
1.8
3.7
16.4
26.5
92.9
27.9
.9 •
28.8
2.9
6.4
1.1
.9
11.3
11.7 "
2.0
3.9
17.5
28.8
110.5
29.6
.7
30.3
3.2
7.1
1.4
.9
12.6
° 11.9
2.0
3.9
17.8
30.3
128.2
33.1
1.5
34.6
3.5
7.8
1.7
.9
13.9
14.0
2.3
4.4
20.7
34.6
148.9
38.4
.8
39.1
3.9
8.5
2.0
1.0
15.4
15.5
2.7
5.5
23.7
39,1
172.6
44.6
1.2
45.8
4.3
9.4
2.4
1.0
17.1
18.7
3.2
6.8
28.7
45.8
201.4
54.2
.9
55.1
4.9
10.3
2.8
1.0
19.0
22.9
4.0
9.1
36.1
55.1
237.4
,,
i
J
-------
11-75
APPENDIX 11-A
PTM(ELECTRIC UTILITIES)
RESEARCH METHODOLOGY
This appendix on research methodology consists of a
non-technical overview of the logical structure of the computer
model, PTm(Electric Utilities), used to derive the projections
discussed and analyzed in the text of this report. The PTm
model is an extension of a model developed by Drs. Howard W.
Pifer and Michael L. Tennican of Temple, Barker & Sloane, Inc.
to provide projections for the Technical Advisory Committee
on Finance (TAC-Finance) to the 1973-1974 National Power Survey.1
In broad terms, PTm has three main logical components,
which may conveniently be labeled the environmental, physical,
and financial modules. As shown in Exhibit II-A-1, it is assumed
that general economic conditions and other factors outside the
model determine the demand for electricity. Consumer's peak
and average demand, the industry's policy with respect to re-
serve margins, and the equipment, power drain, and generating
efficiency implications of pollution control requirements combine
to determine the industry's physical plant, equipment, fuel, and
labor requirements. These physical requirements and the relevant
factor costs, which are also influenced by economic considera-
tions external to PTm, combine to determine the consequences of
building and operating the capacity needed to meet consumer
demand.
Pifer and Tenniaan gratefully acknowledge the counsel and assistance.
of a number of individuals from industry, the Federal Power Commission,
and various financial institutions associated with the TAC-Finance—
especially Messrs. John Childs, Gordon Corey, Fred Eggerstedt, Robert
Fortune, John Glover, Rene Males, John O'Connor, and Robert Uhler.
Preceding page blank
-------
11-76
These capital asset and operating cash requirements
are met in part by revenues collected from the users of elec-
trical energy and in part by external financing. The amount
of cash provided by operations at any moment is influenced
by regulatory policy (in effect via the allowed revenue
per kilowatt>-hour) , by tax policy (via the effective rate of
taxation after consideration of depreciation tax shields, in-
vestment tax credits, etc.), and by the cost of capital raised
in prior periods. Any shortfall between cash needs and the cash
provided by operations is met by recourse to the capital markets.
Exhibit II-A-1 omits a number of interactions and
feedbacks, two of which are notable. First, if external
financing is to be available, regulatory policy must be such
as to allow revenues per kilowatt-hour sufficient to yield
returns to capital that are adequate in light of prevailing
capital market conditions, tax policy, and pollution control
requirements, all of which may have an impact on the cost of
electrical power and hence on demand. As a second illustration,
because the financial characteristics of the electric utility
industry and of individual utilities may be considerations in
the drafting and administration of pollution control legisla-
tion, pollution control policy in part determines and in part
is determined by the industry's financial profile.
ENVIRONMENTAL MODULE
The model's environmental module has as its primary
function the inputting of assumptions concerning future growth
in the demand for power, current and future pollution control
requirements, equipment and operating costs, etc. The implica-
tions of these policy, economic and technical assumptions are
-------
11-77
then determined in the physical and financial modules of
PTm. PTm is programmed so as to be able to test a wide
variety of policy alternatives through changes in input data.
In testing alternative policies about the coverage and time
phasing of water pollution control requirements, however, modi^
fications to the logical structure of the model itself were
required, so that a series of slightly different models actually
were used to make the projections set out in the body of the
report. Nonetheless, for simplicity we shall in the following
speak of PTm as a single model rather than as a set of related
models.
PHYSICAL PLANT AND
EQUIPMENT MODULE
The primary relationships determining the industry's
physical plant and equipment requirements are shown in Exhibit
II-A-2. Consistent with the assumption that demand will be met,
the industry's gross generation capacity in service at any
moment is determined by the level of demand, the industry's
policy with respect to capacity reserves, and the efficiency im-
pact and operation power drain of pollution control equipment.
These current capacity requirements and the rate of retirement
of old generating units together determine the amount of generating
capacity additions necessary for meeting current demand. With
the inclusion of the pollution control equipment required for
generating capacity currently in service, the additions to in-
service plant and related equipment are fully specified in
physical terms. •
-------
11-78
Given the long time lags involved in constructing
new generating capacity, the industry's plant and equipment
construction at any moment typically includes significant
amounts of work in progress so as to meet future demand as it
materializes. As is shown in Exhibit II-A-2, future demand, fu-
ture reserve factors, future pollution control requirements, and
future retirements—together with the lags in construction-—
determine the plant and equipment additions that are related to
.future demand, i.e., construction in progress. It should be
noted that because the time span between ordering and placing
generating capacity in service is radically different for
peaking units, fossil-fueled baseload plants, and nuclear units,
PTm computes construction work in progress for nuclear and for
non-nuclear plants on different time schedules. Thus average
construction lags are themselves a function of the assumed fu-
ture mix of these various types of generating plants. It might
also be noted that PTm is designed to accept assumptions
about the relative proportions of nuclear and fossil additions
that change over time.
FINANCIAL MODULE
For expositional purposes it is convenient to divide
PTm's financial module into three segments, dealing with:
6 uses of funds,
• sources of funds, and
© revenues, expenses, and profits.
-------
11-79
USES OF FUNDS
The industry's uses of funds depicted in Exhibit II-A-3
are determined primarily by the physical plant and equipment re-
quired to meet current and future demand and by the cost per
unit of this equipment. A second use is the allowance on funds
tied up in plant and equipment in the process of construction.
For simplicity, PTm assumes that the industry's net working
capital remains constant, so that changes in working capital
appear neither as a use nor as a source of funds. Given the
miniscule size of such working capital changes in comparison
to the industry's major sources and uses of funds, such a
simplifying assumption is unlikely to introduce appreciable
error in the absence of fundamental structural changes in the
industry's current assets and payables accounts or in its usage
of short-term debt.
Exhibit II-A-3 shows that once the total physical
amounts of plant and equipment required to meet current and
future demand and the proportions of those amounts accounted
for by nuclear and fossil-fueled plants are determined, the
crucial input assumptions required to convert these physical
quantities into financial terms are the cost per unit of each
type of asset and the schedule of payments required by con-
tractors while such plant and equipment are under construction.
SOURCES OF FUNDS
In the case of the private sector of the electric
utility industry, sources of funds consist of two major elements:
o funds provided by operations, and
• external financing.
-------
11-80
Funds provided by operations are in turn the sum of three in-
ternal sources:
• depreciation ,
• tax deferrals, and
• retained earnings.
For the public sector, it is simply assumed that a per-
centage of total funds used is met from internal sources. As
is shown in Exhibit II-A-4a, any shortfall between total uses and
internal sources is met through external financing.
Exhibit II-A-4b shows these same relationships in a for-
mat that is slightly different and that shows how the private
sector's total required external financing and capital structure
and dividend policies combine to determine:
• cash issues of preferred stock , '
• gross cash offerings of debt, and
• cash issues of common stock.
REVENUES AND
RELATED VARIABLES
The third segment of the financial module determines
total industry revenues, expenses, profits, and related statis-
tics such as price per kilowatt-hour and interest coverage ratios.
The output variables of this revenues segment serve in many
instances as inputs to other segments. For example, the depre-
ciation expense figure computed in the revenue segment is an input
to the sources of funds segment. Conversely, certain of the input
-------
11-81
variables to the revenue segment are based on the output from
the sources and uses segment of the financial module (e.g.,
plant and equipment expenditures provide the base for com-
puting depreciation expense). The structure of the revenue
segment and the interactions between this segment and other
parts of the total model are depicted in Exhibit II-A-5.
As shown at the top of Exhibit II-A-5, profits available
for common stockholders are assumed to be determined completely
by the amounts of the industry's common equity capital and by
2
a rate of return on equity set by regulatory policy. As a
consequence of this assumption, revenues and prices per kilo-
watt-hour of electricity are determined by required profits,
other capital charges, and operating expenses.
Earnings before interest and taxes (EBIT) are simply
the sum of EBT and interest expense and are computed by the
same general process used for preferred dividends. The resul-
tant EBIT figure constitutes one of the five main determinants
of revenues.
Tho socond determinant of revenues, depreciation and
amortization of plant and equipment, is a variable related to
the amount of plant and equipment in service. Presuming that
taxes other than on income consist primarily of property taxes,
a third determinant of revenue, other taxes, is also related
to the amount of plant and equipment in service. Plant and
equipment requirements are in turn determined by both current
demand and pollution control policy.
It should be noted that "poliay" is a term intended to comprise the effect
of both the target rates of return set by individual regulatory bodies and
the administrative lags involved in adjusting prices per kilowatt-hour so
as to achieve such target returns.
-------
11-82
Current consumer demand and the power drains and
operating efficiency losses associated with pollution control
equipment combine to determine the level of operating and
maintenance expenses. This latter expense figure is the fourth
determinant of revenues.
Future consumer demand and pollution control require-
ment^ also determine future in-service plant and equipment
requirements and hence determine the amount of construction
currently in progress. The amount of construction in progress
in turn determines the allowance for funds used during con-
struction, which is another non-cash item, but which also af-
fects—this time diminishes—the level of revenues required
to achieve a given level of profit as determined by regulatory
accounting procedures. This allowance on construction funds
variable is the fifth and last major determinant of revenues.
Net profit is simply the sum of profits available for
common stock and preferred dividends. The amounts of preferred
dividends are determined by the amounts of preferred equity
capital and the average dividend rate on the industry's out-
standing preferred stock. The dividend yield on new preferred
stock issues--and hence the average yield--is in turn deter-
mined over time by the reaction of the capital market to the
industry's offerings.
Earnings before income taxes (EBT) are then set at a
level such that EBT minus taxes will be equal to the required
net profit figure. The tax expense figures (or equivalently,
the effective tax rate) is itself a function of the EBT figure,
which is computed in accordance with regulatory accounting pro-
cedures, and several other factors. The calculations are some-
-------
11-83
what complicated first because various special features
of the tax code (e.g., provisions allowing investment tax
credits and accelerated depreciation) and of regulatory ac-
counting (e.g., the creation of allowances for funds used
during construction as non-cash credits to income) must be taken
into account. As a consequence of these differing provisions,
taxable EBT and regulatory EBT may—and typically do—differ.
Second, as mentioned earlier, there exist two substantially
different regulatory methods for determining the tax expense
figure to be associated with EBT. Normalizing accounting gives
rise to deferred taxes, which is a non-cash charge against in-
come but which nonetheless constitutes an accounting expense
to be covered by revenues if accounting profits to stockholders
are to reach prescribed levels.
A CONCLUDING COMMENT
As has been outlined above, the operating, financial,
tax, regulatory, and accounting relationships and constraints
relevant to making economic and financial projections for the
industry are individually rather simple. However, the number
of these relationships and constraints is so great as to dic-
tate the use of a computer model such as PTm. Moreover, because
of interactions among the various industry relationships and
constraints, attempts to reduce the number of factors through
shortcut approximations are hazardous. Furthermore, such short-
cuts, even if based on careful econometric analyses of histori-
cal data, tend to preclude an examination of the implications
of structural and policy changes.
-------
11-84
PTm was designed not only to compute rapidly the im-
plications of any given set of assumptions about the future,
but also to facilitate the examination of structural and policy
changes. Thus, the model is able conveniently to accept input
assumptions for over 100 variables, such as the current level
of and future changes in: the industry's peak demand; reserve
margins; the mix of nuclear and non-nuclear capacity additions;
unit costs of generating plants, transmission and distribution
capacity, thermal and chemical pollution equipment, etc. PTm
then generates projections for a variety of physical and finan-
cial variables, including: capacity figures for each of the
major segments of the industry; energy losses resulting from
thermal water pollution control standards; income statements,
balance sheets, funds flows, and reconciliations of regulatory
and Internal Revenue Service income tax expense figures and
summary statistics such as interest coverage figures.
-------
Exhibit Il-A-1
INTERACTIONS BETWEEM THE ENVIRONMENT AND THE PHYSICAL AND FINANCIAL
CHARACTERISTICS OF THE ELECTRIC UTILITY INDUSTRY
DEMAND FOR
ELECTRIC POWER
POLLUTION CONTROL
POLICY
GENERAL ECONOMIC
CONDITIONS
TAX AND REGULATORY
POLICY
CAPITAL MARKET
CONDITIONS
PLANT, EQUIPMENT, AND
ELECTRICAL POWER
PRODUCTION REQUIREMENTS
PLANT, EQUIPMENT, AND
OPERATING CASH NEEDS
CASH PROVIDED BY
OPERATIONS
EXTERNAL FINANCING
h-l
I-H
I
00
CJl
: VARIABLES TAKEN AS GIVEN BY PTn
I ] t VARIAP'*" *--r"<»HIirr """
-------
Exhibit II-A-2
DETERMINANTS OF PLANT AND EQUIPMENT IN SERVICE
AND IN CONSTRUCTION FOR THE ELECTRIC UTILITY INDUSTRY
c
DEMAND
irPACT OF FUTURE POLLUTION
1EOUIPHENT ON GENERATING
PLANT EFFICIENCY
REQUIRED.
SOSS CAPACITY
RESERVE
FACTOR
CTREST RESERVE
FACTOR
OF CURRENT POLLUTION
EQUIPMENT ON GENERATING
PLAN' EFFICIENCY
csorarr REQUIRED
CAPACITY
C
CBRSEJIT DEMAND
FUTURE RETIREMENTS
CONSTRUCTION FOR
FUTURE REQUIREMENTS
ADDITIONS TO PLANT AND
EQUIPMENT IN SERVICE AND
IN CONSTRUCTION
POLLUTION CONTROL EQUIPMENT
REOUIREI ;ENTS
CONSTRUCTION FOR
CURRENT REQUIREMENTS
CO
O3
CURRENT RETIREMENTS
KEX
'• VARIABLES TAKEN AS GIVE* BY PT«
| . | : VARIABLES DETERMINED .WITHIH PT«
-------
Exhibit II-A-3
DETERMINANTS OF USES OF FUNDS
FCR THE ELECTRIC UTILITY INDUSTRY
COST PER UNIT OF PLANT
AND EQUIPMENT
PLANT AND EQUIPMENT
.CONSTRUCTION FOR CURRENT
REQUIREMENTS
PLANT AND EQUIPMENT
CONSTRUCTION FOR FUTURE
REQUIREMENTS
EXPENDITURES FOR IN-SERVICE
PLANT AND EQUIPMENT
ALLOWANCE FOR FUNDS
USED FOR CONSTRUCTION
IN PROGRESS
DL_
EXPENDITURES FOR INCREASING
PLANT AND EQUIPMENT
IN CONSTRUCTION
TOTAL USES OF FUNDS
I
GO
C-.OST PER UNIT OF PLANT
AND EQUIPMENT
KEY.
: VARIABLES TAKEN AS GIVEN BY IPTf!
\ \ : VARIABLES DETERMINED WITHIN
-------
Exhibit II-A-4
DETERH1HANTS AND COMPOSITION
OF TOTAL SOURCES OF FUNDS FOR THE ELECTRIC UTILITY INDUSTRY
JSEt
(a)
- TOTAL
USES OF FUNDS
i
^
EXTERNAL
FINANCING
FUNDS PROVIDED
BY OPERATIONS
•" rer
TOTAL USES OF FUNDS
I TOTAL SOURCES OF FUNDS
TOTAL SOURCES OF FUNDS
- DEPRECIATION
\
;
ADDITIONS TO CAPITAL
/
V
DEFERRALS
INITIAL
CAPITAL STRUCTURE
'. VARIABLES TAKE* AS SIVEM BY. FT«
[ j : VARIABLES BETEBKHED «ITHIH PT»
ENDING
CAPITAL STRUCTURE
CASH ISSUES OF PREFERRED
•CASH ISSUES OF DEBT
DEBT RETIREMENTS
DIVIDEND POLICY
CASH ISSUES OF COMMON
RETAINED EARNINGS
PROFIT AVAILABLE FOR
COMMON STOCK
C3
CO
-------
OF
COST
ED STOCK
PREFERRED STOCK
PREFERRED DIVIDENDS
E3SED COST
OF DEBT
DEBT
-.HTEREST
CURREXT DEMAND
OPERATING 8 MAINTENANCE
EXPENSES
to.
: VUUILES TWOS AS C:VE» »r Pin
j | I VA BCttWIUtD H1THI« PTn
Exhibit II-A-5
RETURN ON EQUITY
^
PROFIT AVAILABLE
'FOR COMMON STOCK
/
k.
COMMON EQUITY .
NET PROFIT
EARNINGS BEFORE
INCOME TAXES .
EARNINGS BEFORE
INTEREST & TAXES
REVENUES
DEPRECIATION 6
AMORTIZATION OF
PLANT AND EQUIPMENT
PLANT J EQUIPMENT.
IN SERVICE
PLANT & EQUIPMENT
IN CONSTRUCTION
ALLOWANCE ON FUMDS
USED DURING CONSTRUCTION
-------
ECONOMIC AND FINANCIAL IMPACTS OF
FEDERAL AIR AND WATER POLLUTION CONTROLS
ON THE ELECTRIC UTILITY INDUSTRY
VOLUME III
NATIONAL FINANCIAL IMPACTS
MAY 1976
-------
VOLUME III
TABLE OF CONTENTS
Page
List of Exhibits (III-iii)
Chapter
1 INTRODUCTION AND CONCLUSIONS III-l
2 HISTORY OF THE REGULATIONS AND
AMOUNT OF CAPACITY AFFECTED I I 1-4
History of the Clean Air
Act Regulations I I 1-4
History of Federal Water
Pollution Control Regulations III-7
Capacity Impacted by Federal
Air and Water Regulations III-8
3 CAPITAL EXPENDITURES IMPACTS OF
AIR AND WATER REGULATIONS I II -20
Capital Expenditures by Regulation 111-20
Timing of Capital Expenditure
Requirements I 11-22
Capital Expenditures by
Type of Pollution Control
Equipment II 1-23
CupLt, a.l Expend!, turew to Make Up
Capacity Losses 111-26
Other Air Regulations 111-28
4 OTHER FINANCIAL AND ENERGY IMPACTS I I 1-32
External Financing Requirements II 1-32
Operation and Maintenance Costs 111-34
Operating Revenues and Consumer
Charges Impacts II 1-35
Impact on the Average Residential
Bill for Electricity 111-36
Energy Impacts 111-39
-------
Chapter
5 ASSUMPTIONS FOR ANALYSIS OF
THE AIR REGULATIONS I II1-42
Capacity Affected by the Regulations 111-43
Capital Costs 111-48
Operation and Maintenance Costs 111-50
Capacity Loss/Energy Penalty II1-51
Financing 111-52
6 ASSUMPTIONS FOR ANALYSIS OF
WATER REGULATIONS II1-53
Capacity Affected ; 111-55
Capital and Operation and
Maintenance Cost Estimates III-65
7 COMPARISON OF CURRENT ANALYSIS ,
OF WATER REGULATIONS AND
DECEMBER 1974 RESULTS II1-70
-------
VOLUME III
LIST OF EXHIBITS
Exhibit
III-l Financial Impacts of Air and Water Pollution
Controls for Economic and Non-Federal Reasons,
For Selected Years
III-2 Financial Impacts of Compliance with the Clean
Air Act and Federal Water Pollution Control Act
After 316(a) Exemptions, For Selected Years
III-3 Financial Impacts of Compliance with the Clean
Air Act and Federal Water Pollution Control Act
Before 316(a) Exemptions, For Selected Years
II1-4 Capital Expenditures Impacts of Compliance With
Clean Air Act
III-5 Capital Expenditures Impacts; Effluent Guidelines
Pollution Control Equipment
III-6 Capital Costs Used in Clean Air Act Analysis
III-7 Operations and Maintenance Costs Used in Clean
Air Act Analysis
III-8 Coverage Assumptions for Baseline Conditions For
Coal Units in 1980 and 1985
III-9 Coverage Assumptions for Compliance with Clean
Air Act For Coal Units in 1980 and 1985
III-10 Coverage Assumptions for Compliance with SCS 50
Percent Option For Coal Units in 1980 and 1985
III-ll Coverage Assumptions for Compliance with SCS 90
Percent Option For Coal Units in 1980 and 1985
111-12 1985 Coverage Assumptions for Water Effluent
Guidelines (percent)
111-13 1985 Coverage Assumptions for Water Effluent
Guidelines (kilowatts)
111-14 Capital Cost Growth—Thermal Guidelines
-------
Exhibit
III-15 Annual Operating Cost Growth—Thermal Guidelines
111-16 Capital Cost Growth—1977 Chemical Guidelines
II1-17 Capital Cost Growth—1983 Chemical Guidelines
111-18 Annual Operating Cost Growth—1977 Chemical
Guidelines
III-19 Annual Operating Cost Growth—1983 Chemical
Guidelines
111-20 Capital Cost Growth—Cooling Towers for
Entrainment Guidelines
-------
CHAPTER 1
INTRODUCTION AND CONCLUSIONS
This volume of the report presents the direct effects
of federal pollution control regulations upon the electric
utility industry. The air pollution control impacts are
based primarily upon the results of EPA-sponsored research
by three firms: (1) engineering cost studies of air pollution
control equipment by PEDCO Environmental Specialists, Inc.;
(2) regional coal plant analyses to estimate compliance strat-
2
egies, by Sobotka & Co., Inc.; and (3) economic and financial
evaluations by TBS based upon those cost and compliance esti-
mates. The effluent guidelines impacts are based primarily
upon EPA estimates of compliance levels and unit costs as the
inputs to TBS' economic and financial evaluation.
CONCLUSIONS
The major financial conclusions presented in this
volume are:
• Capital expenditures, net of the increase in
construction work-in-progress, will increase
by $14.5 billion during 1975-1980 and by $25.0
billion in 1975-1985 (1975 dollars).3 Those
impacts represent increases above the industry's
level of baseline capital expenditures of 12.3
and 10.5 percent respectively.
PEDCO Environmental Specialists, Inc., Flue Gas Desulfurization, Process
Cost Assessment (April 30, 1975)3 and Particulate and Sulfur Dioxide
Emission Control Cost Study of the Electric Utility Industry (September
12, 1975).
2
Sobotka & Co. Inc., unpublished analyses submitted to the Environmental
Protection Agency, November 17, 1976.
7
Unless otherwise noted, all dollar figures in this volume refer to 1975
dollars.
-------
III-2
Those increases in capital expenditures will be
spread over the entire eleven-year period, 1975-
1985, with the annual figure ranging from $1.5
billion to $4.2 billion. Furthermore, even after
1985 the regulations will cause a continuing im-
pact in capital expenditures of over $2.0 billion
per year, primarily because all new coal plants ;
will require pollution control equipment of some form.
Scrubbers alone will account for half of the
total capital expenditures impact ($12.8 of the
$25.0 billion). Precipitators will account for
another 25 percent and cooling towers will rep-
resent 16 percent.
External financing to support these expenditures
will increase in the six-year period, 1975-1980,
by $14.5 billion, and in the 1975-1985 period by
$21.9 billion. Those impacts represent increases
above the industry's baseline level of external
financing of 16.1 and 11.5 percent, respectively.
Annual operating and maintenance expenses will
increase 4.0 percent by 1980 and 6.0 percent
by 1985. The annual increase by 1985 will be
$3.2 billion.
Operating revenues and average consumer charges
will have to increase 5.4 percent by 1980 and
6.7 percent by 1985 to cover these costs. The
1985 increase will total $6.5 billion and come
to 2.1 mills per kilowatt-hour sold.
The average residential customer's monthly elec-
tric bill will increase as a result by approxi-
mately $1.80 in 1980 and $2.80 in 1985. In
current dollars, that is, including the effects
of inflation, the impact will be $2.40 per month
in 1980 and $4.70 per month in 1985.
The total direct and indirect impact upon residen-
tial customers, assuming that all non-residential
customer impacts are eventually passed on to con-
sumers in the form of increased product prices,
will be approximately $4.00 per customer per
month by 1980 and $5.80 by 1985.
-------
III-3
tf The energy consumption of the electric utility
industry by 1985 will increase slightly to provide
power to operate the pollution control equipment—
by approximately 0.4 quads (quadrillion Btu) on
a base of 33.2 quads.
These conclusions and the data and analysis supporting
them are the substance of the following chapters. Chapter 2
provides a brief history of the legislation and summarizes
the amount of capacity which will be affected by it through
1985. Chapter 3 then presents the capital expenditures impacts
of the regulations. Chapter 4 follows with a presentation
of all other financial and energy impacts of the regulations.
The next two chapters document the assumptions used in the
analysis pertaining to the air regulations (Chapter 5) and
the water effluent guidelines (Chapter 6). Chapter 7 con-
cludes with a comparison of the current analysis of the water
effluent guidelines against the results published in December
1974.
-------
III-4
CHAPTER 2
HISTORY OF THE REGULATIONS
AND AMOUNT OF CAPACITY AFFECTED
This chapter presents a brief review of the regu-
lations being analyzed and of the amount of generating
capacity which they will affect.
HISTORY OF THE CLEAN AIR ACT REGULATIONS
In 1971, pursuant to the Clean Air Act of 1970,
EPA promulgated primary national ambient air quality stan-
dards for six pollutants (sulfur dioxide, nitrogen oxides,
hydrocarbons, carbon monoxide, and particulates) to protect
public health. The electric utility industry was a principal
source for two of these: sulfur dioxide and particulates.
In 1972, the states submitted State Implementation
Plans (SIPs) which included constant emission limitations to
insure the attainment and maintenance of the ambient air
quality standards. Under the act, compliance was mandated
for stationary sources by mid-1975, with extensions avail-
able through state initiatives up to mid-1977.
According to EPA's analyses of the original SIPs,
the electric utility industry would be unable to comply
within the statutory compliance dates; there simply would
not be adequate availability of stack-gas scrubbers, other
control technologies, and low-sulfur fuels. That shortage
of complying control technologies and fuels came to be re-
ferred to as "the clean fuels deficit."
-------
III-5
In response, EPA adopted a "Clean Fuels Policy"
which urged the states to voluntarily relax sulfur dioxide
regulations which were more stringent than necessary to pro-
tect public health. In addition, EPA embarked upon a policy
of administratively extending compliance dates where pri-
mary standards are not endangered.
Recent events, however, have adversely affected
the compliance outlook for the remainder of the decade.
The oil embargo, subsequent energy policies to reduce im-
ports, natural gas curtailments and the general financial
situation of the utilities raised serious questions regard-
ing existing policies to eliminate the clean fuels deficit.
Consequently, in November 1974, at the request of
the Energy Resources Council (ERG), EPA headed an Interagency
Task Force to analyze the implications of alternative sulfur
dioxide policies. The results of that analysis were an ERC
recommendation and the submission to Congress of an Adminis-
tration-sponsored amendment to the Clean Air Act of 1970
which would:
Permit existing isolated coal-fired power
plants at which Supplementary Control Sys-
tems (SCS)1 are reliable and enforceable to
use SCS to meet ambient air quality standards
and to delay until 1985 the installation of
permanent controls (i.e., scrubbers or low
sulfur coal);
Require all other existing plants to install
permanent controls as expeditiously as possible;
Supplementary Control Systems (SCS) achieve ambient air quality standards
by switching power plants to low sulfur fuels or by reducing generation
during periods in which meteorological conditions would otherwise cause
violations of ground-level air quality standards.
-------
III-6
Require all new plants to meet new source
performance standards (NSPS) or state emis-
sion regulations where more stringent than NSPS.
That recommendation has not been acted upon by Congress at
this writing.
In 1972, the Sierra Club and other environmental
groups filed suit against EPA for failure to promulgate
regulations under the Clean Air Act to prevent the signifi-
cant deterioration of air quality. Both the District Court
of the District of Columbia and the U.S. Court of Appeals
for the District of Columbia Circuit granted the Sierra
Club's motion and required EPA to promulgate significant
deterioration regulations. In June 1973, the Supreme Court,
by a four-to-four vote, affirmed the judgment of the Court
of Appeals.
After extensive public participation and technical
and economic analyses, EPA published Significant Deteriora-
tion Regulations in December 1974, which are based on allow-
able increments of pollutant concentrations for specific
categories of new major industrial sources under an area
classification procedure. Subsequently, the Administration,
as part of the Energy Independence Act of 1975, requested
Congress to consider legislation which would clarify Congres-
sional intent on the prevention of significant deterioration
of air quality. The Administration requested that Congress
carefully examine the potential effects of a significant
deterioration policy, including the consideration of its
complete elimination as well as other alternative approaches,
In addition, Congress was asked to provide explicit guidance
that would allow a balancing of environmental, economic, and
energy concerns in any legislative determination of the
-------
III-7
significant deterioration issue. Discussion and evaluation
of several alternative policies are underway now in both the
Senate and the House of Representatives.
The impacts presented in this volume which relate
to air pollution control are those which result from the
Clean Air Act of 1970. The volume also discusses briefly
the projected effects of the SCS amendment if adopted. At
this time, only brief estimates have been included of the
impacts of the federal nonsignificant deterioration regula-
tions and of the federal nitrogen oxide emission limitation.
HISTORY OF THE FEDERAL WATER POLLUTION
CONTROL REGULATIONS
On March 4, 1974, EPA published a notice of pro-
posed rule-making, announcing its intention to establish
limitations on the discharge of pollutants into waterways
by existing and new point sources within the electric utility
industry. These proposed regulations were promulgated pur-
suant to the relevant sections of the Federal Water Pollution
Control Act of 1972. With respect to thermal pollution, the
proposed rule-making exempted all small units (defined by
the Federal Power Commission as units in plants of 25 mega-
watts or less and in systems of 150 megawatts or less in
total capacity), and all units which were scheduled for re-
tirement prior to 1990.
Interested parties were invited to submit written
comments on the proposed regulations, and EPA held public
hearings in July to afford those who had submitted comments
an opportunity to explain the substance of their position in
-------
III-8
detail. Based upon these written comments, public hearings,
and subsequent interaction among interested parties, the
guidelines were revised.
On October 8, 1974, EPA published in the Federal
Register (39 FR 36186) final guidelines and standards for
steam electric power generation. The final thermal guide-
lines exempt all units placed into service before 1970, and
all but the largest baseload units (defined as units of 500
megawatts or greater) placed into service between January 1,
1970 and January 1, 1974. Thus, the final thermal guidelines
differed from those proposed in March 1974 in terms of the
proportion of existing steam electric units which were
covered by the Act. In addition, the final chemical guide-
lines were modified from those previously proposed.
In December 1974, EPA published its economic analy-
sis of the impact of the final effluent guidelines upon the
electric utility industry (Economic Analysis of Effluent
Guidelines, Steam Electric Powerplants). The impacts pre-
sented in this volume which relate to water pollution control
regulations update that earlier analysis on the basis of
more recent information regarding electricity sales growth,
capacity additions, capital costs, and compliance of the
industry.
CAPACITY IMPACTED BY FEDERAL
AIR AND WATER REGULATIONS
The effect of these regulations will be to require
pollution control equipment to be installed on a significant
share of the electric utility industry's generating plants.
EPA's final chemical effluent guidelines, for example, will
-------
III-9
affect approximately half of all fossil and nuclear power-
plants in the U.S. by 1985. Those affected units will rep-
resent 40 percent of the industry's capacity at that time.
The air regulations, on the other hand, will significantly
impact only coal-fired plants. Again, however, that amounts
to approximately 40 percent of the industry's capacity.
The purpose of this section is to provide an over-
view of the magnitude and types of those impacts. Later
chapters (5 and 6) present EPA's detailed estimates, regu-
4
lation by regulation. This section also presents the data
from a complementary point of.view: it is summarized and
presented by type of capacity affected rather than simply
by regulation.
There are at least five different compliance prob-
lems which are dealt with in this chapter. Three relate to
the water effluent guidelines: thermal pollution, entrain-
ment of organisms in the cooling water, and chemical pollu-
tion. There are two more relating to the air regulations:
sulfur dioxide emissions (S02), and total suspended particu-
late emissions (TSP).
In some cases state and local regulations and even
economic reasons can and do force utilities to install pol-
lution control equipment regardless of the presence or absence
of federal regulations. The most significant example of this
is the installation of cooling towers and the use of closed-
»
cycle cooling systems either to comply with State Water Quality
4
The estimates of the capacity affected which are used in this report were
developed by or for EPA; the capacity which falls under the purview of
the water effluent guidelines was estimated "by EPA regional personnel^ and
that which is affected by the air regulations was furnished by Sobotka
Associates.
-------
111-10
Standards or because of the unavailability of adequate cool-
»
ing water at a plant site. These reasons are expected to
account for approximately 40 percent of all the cooling towers
to be installed in the 1975-1985 .period. The federal regula-
tions therefore will be the cause of cooling tower construction
in only the other 60 percent of the installations.
The one other pollution area in which local and
state regulations and economic reasons are significant is
in the installation of preclpitators to collect particulate
emissions from flue gases. Virtually all coal plants are
now equipped or built with some type of precipitator which
in certain instances will meet the federal standards and in
other instances will require upgrading in efficiency.
The exemption provision in Section 316(a) of the
Federal Water Pollution Control Act is a final significant
factor to recognize in considering the number of plants
affected by EPA's regulations. That provision allows for
exemptions from the thermal regulations if the effluent dis-
charges would not harm marine life in the receiving body of
water. Based upon reports from EPA regional personnel, such
exemptions could exceed 50 percent of the original number of
plants affected. Some of those exempted units are included
in those eventually covered by the State Water Quality Stan-
dards. The later chapters report the extent of these ex-
emptions in some detail, but this chapter deals only with
estimates of the final impacts after exemptions.
The sections below describe briefly the magnitude
of the capacity affected by the regulations in separate
sections for each type of capacity: nuclear, coal, oil, and
-------
III-ll
gas. The discussion is in terms of impacts by 1985 when all
retrofitted units will be in place and when the pollution
control equipment on new sources through 1985 will also be
in service.
Nuclear Plants Impacted
By Effluent Guidelines
The projections presented in Volume II show nuclear
capacity increasing from 8 percent of the industry's total
capacity in 1975 to almost 18 percent in 1985. By the end of
1985 132,000 megawatts of nuclear capacity are projected
to be in service. Its share of total generation will be
even higher because the potential capacity factors for
individual nuclear plants can be well above 70 percent.
Many of these units are projected by EPA to be required
to install pollution control equipment in order to comply
with the federal effluent guidelines. The impact in each
of the three areas of regulation are described briefly below.
First, EPA's final chemical guidelines will require
new expenditures on approximately 52.5 million kw, or 40 per-
cent of the nuclear capacity in service. As the table on
p. 111-12 shows, 70 percent of the nuclear units already in-
service before 1974 will be required to be retrofitted (i.e.,
fitted onto units which are already in operation at that
time) with additional equipment in order to meet the chemical
guidelines. Approximately one-third of the new nuclear units
placed into service in 1974 or later will be required to add
such equipment during design in order to be -in compliance
when the units become operational.
-------
111-12
HUCUAR UNITS
Impact of EPA Effluent Guidelines
(million kw)
Nuclear Capacity
Impacted by Water
Guidelines
Chemical
Thermal (after
316 (a)*
Entrainment
*rwt of coverage for
Pre-1974
units
21.1
14.8
4.6
3.0
Eaonomia Reasons
Source: EPA, Exnibita 111-12 -
1974-1978
units
40.6
13.8
10.1
1.5
111-13
Total
1979-1985 1985
units Capacity
70.3 132.0
23.9 52.5
17.6 32.3
4.5
The capacity affected by the thermal effluent
guidelines is less extensive than for the chemical guidelines.
Many plants are expected to be granted exemptions under
Section 316(a) of the Federal Water Pollution Control Act by
demonstrating that regulations are more stringent than neces-
sary. After excluding those plants with exemptions, 32.3 million
kilowatts or approximately 24 percent of the nuclear plants in
service in 1985 will be required to utilize closed-cycle cooling
systems to meet the federal guidelines. The regulations will
require closed-cycle cooling for 22 to 25 percent of the nuclear
units in service regardless of the plant's age. Approximately
an equal number of nuclear units will be utilizing closed-
cycle cooling for economic reasons and State Water Quality
Standards. The remaining units are not expected to pose an
environmental hazard in terms of the thermal effluent guidelines.
-------
111-13
Some additional cooling towers will be required
by federal entrainment regulations under Section 316(b) of
the Clean Water Act. Some nuclear plants will have to use
closed-cycle cooling to prevent the intake and entrainment
of certain organisms along with cooling water. Overall, an
additional 4.5 million kilowatts will require cooling towers
to comply with the entrainment guidelines. New plants,
however, are expected to meet the guidelines through simple
design changes at no increase in plant or operating costs.
Coal Plants Impacted
By Effluent Guidelines
Coal plants are the only type significantly
affected by both air and water federal regulations. Nuclear
plants are impacted by water regulations but result in no
SO2 or particulate emissions. Oil and gas plants are also
impacted by the water regulations, but gas units produce
no air pollution subject to the federal regulations and oil
units can generally comply with the regulations simply by
3
burning lower sulfur oil at a slight price penalty.
Coal-burning plants accounted for almost 40 percent
of the industry's total capacity at the end of 1974. The
projections presented in Volume II indicate that coal units
will increase to approximately 46 percent of total capacity
by 1985 by increasing in absolute numbers from 186 million
kilowatts in 1974 to 333 million in 1985. Because the coal
units are primarily baseload and cycling units, coal's share
of total generation by the industry is and will continue to
Projected by EPA to be 0.75 to 0.80 mills per kjh in 1975 dollars.
-------
111-14
be slightly higher, ranging from 45 to 51 percent during the
eleven-year period.
EPA's regional personnel estimated impacts of the
effluent guidelines upon fossil capacity in total, without
singling out coal units. Assuming impacts proportional to
the coal share of fossil capacity, the estimates below have
been derived for each of the three areas of effluent guidelines,
First, EPA's chemical guidelines will require addi-
tional equipment and expenditures at slightly over half of all
coal plants by 1985. That ratio is expected to be relatively
constant for plants, built before 1974, those to be completed
between 1974 and 1978, and those built after 1978.
Second, in terms of the thermal guidelines only
69.7 million kw or just over 20 percent of the capacity is
anticipated to require cooling towers and closed-cycle cooling
systems in order to comply with the federal guidelines. In
terms of age of unit, under 10 percent of the pre-1974 units
were expected to install closed-cycle cooling for compliance
with the federal guideline, while just over one-third of the
new units built after that are projected to do so. The
expected level of installation of cooling towers to meet
State Water Quality Standards is low (about 5 percent), but
in combination with those installed for economic reasons,
will be roughly equal to the federal requirement.
Third, the federal regulations covering entrain-
ment, Section 316(b), will require closed-cycle cooling at
approximately 3.4 million additional kw by 1985. Units
completed in 1979 and later years are expected to be designed
-------
111-15
to meet the regulations at no increment in capital or
operating cost.
COAL UNITS
Impact of EPA Effluent Guidelines by 1985
(million kw)
Total
Pre-1974 1974-1976 1977-1985 1985
unitsa units units" Capacity
Coal Capacity 173.5 29.7 129.7 332.9
Impact of Guidelines
Chemical 105.8 16.6 72.6 195.0
Thermal (after
316(a)) 13.9 10.4 45.4 69.7
Entrainment 2.4 1.0 - 3.4
aExolude8 23.1 million Aw expected to be retired by 1985, and includes 11.1
million ka converted from oil to coal under FEA conversion orders and 9.2
million ku converted from gas to coal for economic reasons.
This time period chosen in preference to the 1979 and later period used in
the earlier Effluent Guidelines report for consistency within the present
analysis
Source: EPA, Exhibits 111-12, 111-13
Coal Plants Impacted
By Air Regulations
Under the Clean Air Act of 1970, EPA has published
ambient air quality standards for sulfur dioxide (SOg), total
suspended particulate (TSP) and nitrogen oxide (NOX) emission
levels. States have established State Implementation Plans
(SIPs) for achieving those levels on a state-by-state basis.
Each electric utility company, however, also has a choise of
alternative methods of compliance. The selection of a com-
pliance technology for S0_ is generally the most significant
of the three. First, its cost is usually much higher than
-------
111-16
the costs of meeting the other regulations. Second, its
selection often dictates the mode of compliance of the
others—for example, the use of Western low-sulfur coal
to meet SO2 levels required that money be spent to upgrade
the units' precipitator.
EPA has developed projections of the amount of coal
capacity which will be impacted by the regulations. Further-
more, its contractor, Sobotka Associates, has also estimated
the utilization levels of the various control strategies by
1985. The sections below summarize the degree of impact ex-
pected and the major controls which are anticipated. The
three major compliance strategies expected to be used for SO2
for example are:
• Install and operate scrubbers (flue gas
desulfurization).
« Burn Eastern and Western coal.
• Utilize washing and blending of coals
with different sulfur characteristics.
It was estimated that 224.5 million kw or approxi-
mately 67 percent of the 1985 coal capacity would require con-
trols to meet the federal SO_ regulations and would therefore
need to adopt one of the compliance options. The table on
p. III-17 summarizes the expected breakdown of the three
compliance options for those units.
-------
111-17
COAL UNITS
SO. COMPLIANCE METHODS BY 1983
* (million kw)
Total
Pre-1074 1974-1976 1977-1985 1985
units* ' units units Capacity
Coal Capacity
S0n Compliance Method
- Scrubbers
- Low Sulfur Coal
- Medium Sulfur Coal
- Wasbir.g/Blendlng
Total Requiring Controls
No Additional Controls
Needed
173.5 29.7 . 129.7
42.9 11.5 63.5
1.4 2.2 66.2
21.8 11.4
37.2
103.3 2S.1 129.7
70.2 4.6
332.9
117.9
69.8
33.2
37.2
258.1
74.9
•Excludes 13.1 million to expected to lie retired by 1985, and inaludee 22.2
million fcu converted from oil to ooa.1 under SA conversion orders and 9.i
million to converted from gat to coal for economic racoons.
Source: Sobotka & Co. , Inc. , Exhibit I I 1-9
Scrubbers, it is expected, will be installed on
117.9 million kw by 1985, just over half of all the units
which require controls and just over one-third of all 1985
coal capacity. Low-sulfur coal would be used by just over
one-fifth of all coal plants in 1985. Washing or blending.
will be feasible only at plants which are very close to com-
plying with the regulations now; about 37.2 million kilowatts
will be using this strategy.
To comply with federal particulate regulations,
there are essentially two alternatives for a coal-burning
utility: either (1) install or upgrade an electrostatic
precipitator unit, or (2) in combination with a scrubber,
install a particulate scrubber to accomplish both SOg and
particulate removal.
The selection of compliance technologies for -the SO
and particulate regulations are very interdependent as mentioned.
The table on page 111-18 summarizes the share expected for each
option for compliance with the particulate regulations. It was
estimated by EPA that 261.8 million kw or 78.6 percent of the 1985
-------
111-18
coal capacity would require one of the available compliance
technologies. Precipitators are expected on almost exactly
50 percent of 1985 coal capacity while particulate scrubbers
are projected to be used on the remaining 28 percent.
COAL UNITS
PARTICDLATE COMPLIANCE METHODS BY 1985
(million kw)
Coal Capacity
(million kw)
Particulate Compliance
Method
- Precipitators
- Particulate Scrubbers
Total kw requiring
controls
Pre-1974
units*
173.5
81.3
21.1
102.4
1974-1976
units
29.7
18.2
11.5
29.7
1977-1985
units
129.7
66.2
63.5
129.7
Total
1985
Capacity
332.9
165.7
96.1
261.8
'Excludes 23.1 million few expected to be retired by 1985, and includes 11.1 million
fcu converted from oil to coal under FEA conversion orders and S.2 million fcu con-
verted from gas to coal for economic reasons.
Source: EPA, Exhibit III-9
Control strategies and costs for NOX control have
been difficult to specify. Many plants are expecetd to make
boiler modifications at a cost of approximately $3 per kw to
permit two^-stage combustion or off-stoichiometric firing to
bring NOX emissions into compliance. Other new plants are
expected to incorporate design features to accomplish the same
objective. At this time no definitive projections are avail-
able for incorporation into the impact analysis.
Oil and Gas Units
Oil- and gas-burning electric generating plants are
not affected extensively by federal pollution control regula-
tions for three reasons:
-------
111-19
• First, the water regulations affect pri-
marily new units placed in service in 1974
and later years, a period during which the
construction of oil and gas units is pro-
jected to drop sharply and cease altogether
by 1978 in the case of gas and by 1981 in the
case of oil;
o Second, the SC>2 regulations cover emissions
which gas units do not produce and which
oil units can curtail simply by burning
low-sulfur oil at a fuel price premium of
about fifty cents per barrel with no capital
outlays whatsoever;
o Third, the particulate regulations cover
emissions which are not generally produced
at the specified levels by oil or gas units.
The chemical regulations cover virtually every steam
electric plant in service in 1983 or later, as described above.
For gas-fired units, however, approximately half of the current
capacity is expected to be either converted to other fuels or
retired by 1980 as a result of natural gas curtailments.
The thermal regulations (after accounting for exemp-
tions under Section 316(a) of the Act) will require con-
versions to closed-cycle cooling on approximately 8 percent of
oil capacity and 2 percent of gas capacity by 1985. Entrain-
ment regulations, Section 316(b) of the Act, are projected to
cover approximately 2 percent of both oil and gas capacity by
that year.
-------
111-20
CHAPTER 3
CAPITAL EXPENDITURES IMPACTS OF
AIR AND WATER REGULATIONS
Perhaps the most widely accepted measure of the ef-
fect of pollution control regulations upon the electric util-
ity industry is that of capital expenditures requirements.
That figure provides: (1) an indication of the total financing
impact (from both external and internal sources); (2) a
relative indication of the significance of the requirements
as compared to the baseline projections; and (3) a meaningful
yardstick with which to evaluate potential changes in the reg-
ulations and allowable technologies.
This chapter provides a full discussion of the capi-
tal expenditures impacts. The>next chapter discusses the
financial and energy impacts of pollution control. A separate
volume, Volume IV, will deal with the ability of the electric
utility industry to finance the required capital expenditures
in view of current and projected capital market conditions.
CAPITAL EXPENDITURES BY REGULATION
The table below summarizes the capital expenditures
impacts associated with each regulation. On a national basis
the combined air and water regulations will require approxi-
2
mately 25.0 billion (1975 dollars) of capital expenditures
during 1975-1985 in addition to the planned expenditures of
In this discussion "capital expenditure a" refer to the caah expenditures
associated with unite put into service; capital expenditures excludes
changes in conetruction work in progress and allowances for funds used
during construction,
2'
Unless specifically noted all dollar figures in this chapter will be ex-
pressed in constant 1975 dollars. 1975 dollars are assumed to include
9.5 percent inflation during 197 S.
-------
111-21
the industry of approximately 237.1 billion. Since much of
the retrofitted equipment for existing plants will be installed
by 1980, the 12.3 percent increase in capital expenditures from
1975 to 1980 is slightly higher than the longer term impact
of 10.5 percent from 1975 to 1985.
CAPITAL EXPENDITURES IMPACTS
AIR AND WATER REGULATIONS TO 1980 AND 1985
(billion 1975 dollars)
1975-1980 1975-1985
Baseline Capital
Expenditures 118.3 237.1
Water Regulations
- Chemical +$ 0.6 +$0.9
- Thermal* + 0.3 + 3.5
- Entrainment + 0.0 + 0.5
Subtotal +$0.9 +$5.0
Air Regulations
-S02 +$ 8.6 +$ 11.6
-Particulate + 5.0 + 8.4
Subtotal +$13.6 +$20.0
TOTAL IMPACT +$14.5 +$25.0
*After consideration of aaxmptiona under Se&bion
316(a) of the Clean Water Aat
Source: Exhibits IIX-4 Offld XXX-5
The air regulations require by far the largest capi-
tal outlays. Through 1980, they account for 94 percent of the
total for pollution control, largely due to the time phasing
of the water guidelines which require equipment in place gen-
erally in 1981 and 1982. Over the entire eleven-year period,
moreover, the air regulations account for 80 percent of the
impact. The reasons are the widespread coverage of the air
regulations, affecting over two-thirds of the nation's coal
units, and the relatively high cost of that pollution control
equipment compared to water pollution control equipment.
-------
111-22
The two major categories of air pollution regulations
each account for significant capital expenditure requirements.
The SO2 regulations will cause an increase of $11.6 billion
during 1975-1985, approximately 45 percent of the total effect
in that period. The particulate regulations rank a close
second to SO2. Particulate regulations will require an increase
of approximately $8.4 billion by 1985, which represents 35
percent of the total impact. The next largest regulation
category is far smaller. It is thermal regulations at a level
of $3.6 billion during 1975-1985.
TIMING OF CAPITAL EXPENDITURE REQUIREMENTS
The time phasing of the air regulations requires
that most of the pollution control equipment needed in the next
decade be installed before 1981. The only air pollution con-
trol equipment which will be installed after 1980 will be that
required for new generating units as they come into service.
The water pollution control equipment is generally expected
to come into service in the 1981-1983 period. The resulting
impact on capital expenditures in the short run is depicted
in the chart below.
During the next six years, 1975-1980, the annual in-
crease in capital expenditures for equipment placed into ser-
vice will range from $1.5 to $3.1 billion per year. As the
chart shows, the baseline capital expenditures before the pol-
lution control impact in 1975-1980 are projected to range from
$16.5 to $25.0 billion per year. The impact of the regulations
during that period represents an increase ranging from 9 to 16
percent of the baseline projections and averaging 12 percent
per year.
-------
111-23
ANNUAL CAPITAL EXPENDITURES" OF
THE ELECTRIC UTILITY INDUSTRY
(BILLIONS OF 1975 DOLLARS)
ANNUAL CAPITAL
EXPENDITURES
28
26
7£i
20
18
16
in
12
10
8
6
4
2
—
—
-
—
—
-
-
—
-
-
KEY:
pS'.i"\ POLLUTION
L-iiJ CONTROL
n OTHER
CAP 1 TAL
EXPENDITURES
3.1
2.3
VI, h
- 2-9 3.0
f
. 7 1.5
1.7
16.5
17.2
19.2
18.8
?S.O
M.Z
23.2
1.6
1.6
?2.7
•M ^
1.5
.1.1
1.6
?S,7
1975 1980 1985
YEAR
'MET OF INCREASE IN CWIP AND NET OF AFDC
During the next five-year period, the first year,
1981, has the highest annual capital expenditures impact of
the regulations of the full 1975-1985 perioc - $4.2 billion dol-
lars (1975 dollars) of pollution control equipment coming into
service in that single year. The other four years, 1982-1985,
all show a lower level of capital expenditures impact of $1.5 to
$1.6 billion per year. That impact represents a continuing
expenditure level associated with new generating units as they
come into service. That impact is approximately a 6 percent
annual increase in plant placed into service from 1982 on.
CAPITAL EXPENDITURES BY TYPE
OF POLLUTION CONTROL EQUIPMENT
cost.
Pollution control equipment varies substantially in
The range of unit costs is as broad as the range of im-
-------
111-24
pacts of individual regulations. In fact, the most widespread
costs, chemical effluent costs, are also the lowest on a unit
basis, being at or below $2 per kilowatt, as is shown in the
table below. Cooling tower costs, the table also shows,
can reach as much as $24 per kilowatt for retrofitted units.
However, that is still far below the capital costs of pre-
cipitators for retrofitted units at $45 per kilowatt and
scrubbers at $70 per kilowatt. The range for new units is
even wider, from a capital cost of less than $6 per kilowatt
for the most expensive water treatments to as high as $55 per
kilowatt for the new coal plants which install scrubbers.
Unfortunately, for most utilities, there is not a free
choice among the range of costs in order to meet a standard.
The plant and control problem generally limits the choice
to one or two. For example, if one builds a new coal plant
then one must either install a scrubber or burn low sulfur
coal—both incurring a considerable cost.
COMPARATIVE CAPITAL COSTS
FOR SELECTED POLLUTION CONTROL EQUIPMENT
(1079 dollars per kw)
Retrofitted
Units
New
Units
Water
Chemical Effluent Treatment
(Fossil)*
Mechanical Cooling Tower
Entrainment Screens
(Fossil )b
Air
Scrubber (SOj only)
Scrubber (with Venturl Scrubber)
Low Sulfur Coal (Western)
Washing/Blending
Preclpltator
$ 2.01 $ 1.52
24.09 5.77
1.93 4.08
70.27
86.83
62.40
S.40
45.50
55.50
72.06
65.88
56.00
Costs for nuclear units Zouer than those shown
Coats for nuolear units slightly higher for retrofitted units,
lower for new units
Source: Equipment for Air Treatment: Pedco Environmental
Services, Equipment for Effluent Treatment: EPA.
December, 1974 report.
-------
111-25
The total capital expenditures impacts of each major
category of control equipment is shown in the table below.
The most widespread coverage, to meet chemical guidelines,
encompasses almost 60 percent of all fossil steam and nu-
clear plants—some 355.6 million kw. Even at that coverage
level, though, the total capital expenditure impact associated
with chemical regulations is only $0.9 billion (1975 dollars).
during the 1975-1985 period.
CAPITAL EXPENDITURES 1975-1985 BY TYPE
OF POLLUTION CONTROL EQUIPMENT
(excluding equipment built for
reasons other than compliance
with federal regulations)
Water Regulations
Chemical Treatment
Cooling Towers*
Air Regulations
Scrubbers
o
Precipitators
Boiler Modifications
TOTAL
Amount Built
(million kw)
355.6
136.3
117.9
139.5
69.9
Capital Expenditures
(billion 1975 dollars)
$ 0.9
4.1
12.8
5.9
1.3
$25.0
*For Thermal and Entrainment Guidelines
*12.8 billion inaludee $3.0 billion for partiaulate portion of combination
tambbere
o
Inaludet both nau pwoipitatore and upgrading of mechanical preeipitators
Source: Exhibit* IIX-4, I1I-5, III-9 and 111-13
On the other hand, the expensive forms of pollution
control will also be applied to a significant amount of capac-
ity under the regulations. Scrubbers, for example, will be
installed on approximately 117.9 million kilowatts of capacity
through 1985, while Western low-sulfur coal will be burned at
139.5 million kilowatts.
-------
II1-26
The combination of such broad applications with high
unit costs makes scrubbers and precipitators (largely used for
Western low-sulfur coal) the dollar leaders in installations
through 1985. Scrubbers will account for $12.8 billion, al-
most exactly half of the total air and water impact of $25.0
billion. Precipitators will cost another $5.9 billion in
that period. The three most costly control categories, these
two plus cooling towers, account for 91 percent of the total
impact.
CAPITAL EXPENDITURES TO
MAKE UP CAPACITY LOSSES
Scrubbers, precipitators, cooling towers, and Western
low-sulfur coal have impacts on the effective capacity of the
generating plants which utilize them. The first three require
electricity for operation and thereby reduce the plant's net
output capability. The fourth reduces output because the
average Btu content of Western low-sulfur coals is much lower
than the average coals now burned. In the short run such losses
may be made up through the use of purchased power and increased
utilization of peakers. In the long run, however, additional
baseload or cycling capacity must be built to make up the
losses.
The capital expenditures required to make up capacity
losses which result from the federal pollution control regula-
tions are summarized in the table below. Approximately 16 per-
cent of the total capital expenditures required for pollution
control in 1975-1985 are for this purpose. The total cost for
making up capacity losses will be approximately $1.8 billion
during 1975-1980 and $4.0 billion in the 1975-1985 period.
-------
111-27
Scrubbers account for the largest cost in this area,
requiring makeup additions at a total cost of $1.4 billion
through 1980 and $2.1 billion through 1985. Cooling towers
on nuclear and fossil steam plants are almost as expensive over
the full eleven-year period, at $1.7 billion. Low-sulfur
coal, while discussed a great deal, results in a relatively
small requirement—only $0.1 billion. There are two reasons
for that small impact: First, new plants built after 1976
which will burn Western low-sulfur coal are assumed to incor-
porate design changes which reduce the capacity loss to zero;
and second, very few pre-1976 units are expected to burn
Western low-sulfur coal, in part because of the capacity loss
of over 4 percent which would be incurred.
CAPACITY EXPENDITURES FOR MAKEUP
OF CAPACITY LOSSES DUE TO
POLLUTION CONTROL REGULATIONS
(billion 1975 dollars)
1975-1980
Water Regulations
Cooling Towers $0.2
Air Regulations
Scrubbers $1.4
Low Sulfur Coal 0. 1
Precipltatora 0 . I
TOTAL $1.8
Source: EPA, Pedco estimates of
PTm computation of costs.
1975-1985
$1.7
$2.1
0.1
0.1
$4.0
loss rates ,
-------
111-28
OTHER AIR REGULATIONS
In addition to the impacts described above, capital
expenditures also may be increased to cover the costs of com-
pliance with other federal air emission regulations. There
are at least three such regulations possible at present:
(1) the nitrogen oxide emissions regulation, which has been
promulgated and simply was not included in the analysis;
(2) the significant deterioration regulationsswhich are the
subject of active Congressional and Agency review; and (3)
the proposed Amendments to .the Clean Air Act to permit the
use of Supplemental Control Systems (SCS). The potential
impact of each is discussed briefly below.
NOX Regulations
All plants placed into service in 1977 or later
will be required to comply with EPA's emission regulations
for nitrogen oxide. The two available methods of compliance
both require changes in boiler operation: one is to utilize
two-stage combustion, and the other is to employ off-stoichio-
metric firing. In either case a capital cost will be in-
curred in the range of $3 per kilowatt for new coal units
and $0.30 to $4.00 for new oil and gas units (1975 dollars).
On the basis of the capacity additions projected in Volume II,
the total impact of this regulation on capital expenditures
for plant placed into service will be approximately $200
million to $250 million in 1975-1980 and $450 million to
$500 million in 1975-1985 (1975 dollars).
-------
111-29
Significant Deterioration
Regulations
The significant deterioration regulations were
also excluded from this analysis. That regulation is cur-
rently under examination and its ultimate form is uncertain.
3
A recent report by EPA presented a detailed financial evalu-
ation of several of the proposals for legislative changes in
the area. The impact upon capital expenditures with the use
of 1000 foot stacks under EPA's current guidelines (Federal
Register, December 5, 1974) will be approximately $0.2 billion
in 1975-1990. The impacts of the Senate or House proposals
with EPA's definition of "Best Available Control Technology"
(BACT) would be in the range of $1.2 to $2.1 billion. That
figure would increase, however, to the $11.2 to $11.6 billion
range if the Senate and House definitions of BACT are adopted.
At this time no more conclusive results are available.
SCS Proposal
As mentioned earlier in the volume, EPA and the
Energy Resources Council recommended to Congress an amend-
ment to the Clean Air Act which would permit the use of SCS
in existing coal plants. The use of SCS would be permitted
only on an interim basis, however, with permanent controls
still required by 1985.
The two major options considered for SCS imple-
mentation are:
SCS 50 percent, which would permit SCS
for those electric utility plants which
contribute 50 percent or more of the
^EPA, "A Preliminary Analysis of the Economic Impact on the Electric
Utility Industry of Alternative Approaches to Significant Deterioration,"
February 5, 1976.
-------
111-30
ambient concentration of S00 in their
area;
• SCS 90 percent, which would permit SCS
only for those plants which contribute
90 percent or more of the ambient con-
centration of SOo in their area.
In either of the SCS options were adopted, then
fewer expensive scrubbers would be built during 1975-1980.
Just as many would be built by 1985 as would be built
under the Clean Air Act. During the interim period, how-
ever, the plants using SCS would merely delay their per-
manent compliance installation.
The capital expenditure impacts of the use of SCS
would be to reduce expenditures in the short run in favor of
slightly higher expenditures in the long run, when both SCS
equipment and permanent controls equipment will have been
financed.
SCS-50 is the most liberal SCS policy because it
would enable the largest number of units to operate SCS sys-
tems. Under that policy option, capital expenditures in the
1975-1980 period would drop from the Clean Air Act level by
$1.8 billion. That reduction would be the result of some
plants utilizing less expensive controls by 1980 than if
they had to install permanent controls by that time.
By 1985, however, the SCS-50 option would result
in increased capital expenditures of $3.1 billion higher
than the Clean Air Act level as the plants which had invested
in SCS for the short term were required to install permanent
controls.
-------
111-31
The SCS-90 option is smaller but permits SCS at
fewer plants than SCS-50. The 1975-1980 capital expenditures
impact would be a reduction of $1.3 billion, and in the
1975-1985 period would result in an increase over the Clean
Air Act level of $1.9 billion.
-------
111-32
CHAPTER 4
OTHER FINANCIAL AND
ENERGY IMPACTS
The economic impact of pollution control regula-
tions extends beyond capital expenditures to every facet of
the electric utility;industry. This chapter briefly ad-
dresses the following additional areas of impact of federal
pollution control regulations on the utilities:
• external financing needs
• operation and maintenance
• operating revenues and consumer charges
• the average residential bill for electricity
• a comparison of annual costs on coal and nuclear
units
• capacity losses and energy penalties
EXTERNAL FINANCING REQUIREMENTS
The capital expenditures for pollution control
equipment described above will require a significant amount
of financing by the industry in the nation's debt and equity
markets. The amount of such financing is described briefly
in this section; the financing capability and specific tech-
niques of the industry are the subject of a separate chapter
later in this volume.
The current projections for the industry's external
financing requirements are for approximately $89.8 billion
-------
111-33
(1975 dollars) during 1975-1980, and $191.2 billion for the
eleven-year period of 1975-1985. That level represents an
average of approximately $17 billion per year (1975 dollars)
compared to levels of approximately $4 billion in 1965 and
$12 billion in 1973 (also in 1975 dollars).
. As the chart below indicates, the impacts of the
federal regulations fall primarily in the pre-1981 period.
In the six-year period 1975-1980, increased external financ-
ing of $14.5 billion will be required; in the eleven-year
period 1975-1985, that total increases only to $21.9 billion.
«
During individual years before 1981 the impact ranges from
an increase in external financing needs of from 12 percent
to 19 percent, whereas the average impact in the 1981-1985
years is only approximately 7 percent.
Volume IV*contains a full discussion of the sig-
nificance of these impacts in terms of the industry's ability
to raise this incremental financing.
EXTERNAL FINANCING NEEDS
(BILLIONS OF 1975 DOLLARS)
1.8
28
26
24
22
20
EXTERNAL jg
FINANCING
16
14
12
10
6
4
2
o
•••
-
— •
mm
KEY:
n POLLUTION
CONTROL
FINANCING
. .BASELINE
EXTERNAL
1 1 FINANCING
NEEDS
f
i •*
3.0 2.6 1.2
2 , 2.8
1.8
—
™*
™"
-
—
-
I'l
•^
l.'J
13. '1
I'l. 9
Ib.U
15.9
[6.3
1.7
IS.'
17.6
19.3
1.5
•. "•
S-*
22.2
26.4
1975 .1980 • 1985
YEAR
-------
111-34
OPERATION AND MAINTENANCE COSTS
The operation and maintenance of pollution control
equipment will naturally increase electric utility operation
and maintenance expenses. In addition, however, operation
and maintenance expenses will also increase to reflect the
premium paid on low-sulfur fuels for those utilities comply-
ing with SO2 regulations through the use of low-sulfur oil
or coal.
The total increase in operation and maintenance ex-
penses due to the combined air and water regulations will be
$1.9 billion per year by 1980, and $3.2 billion per year by
1985 (see table below). That represents a 4 percent increase
by 1980 and a 6 percent increase over the baseline projec-
tions by 1985.
As the table shows, the dominant portion of the
impacts is that brought about by the air regulations—over
80 percent of the total.
ANNUAL O/M EXPENSE IMPACTS
(billion 1075 dollars)
1980
Baseline Projection
Impacts:
Water Regulations
Air Regulations
TOTAL
Source: Exhibit III-2
$ 42.8
1985
$53.8
$ 0.5
-------
111-35
OPERATING REVENUES AND CONSUMER
CHARGES IMPACTS
The total annual cost of pollution control in the
electric utility industry is equivalent to the additional
revenues collected from consumers of electricity to cover
those costs. In addition to the direct annual operating
costs and fuel premiums, the revenues also include the appro-
priate amortization charges, interest, other capital costs,
and increases in property and income taxes associated with
pollution control equipment. The increase in operating reve-
nues for an individual year indicates the total costs of
pollution control equipment in operation for that year. The
cumulative increase over a period of years (e.g., 1975-1980)
represents the total amount paid by consumers for pollution
control over the period. The increase in consumer charges
provides a measure of that cost on a kilowatt-hour basis.
The table below summarizes the financial impacts of
the combined federal air and water regulations for selected
years in terms of operating revenues and consumer charges.
The total premium paid by consumers for pollution control is
projected to be approximately $12.2 billion (1975 dollars)
during 1975-1980 and $40.2 billion in the eleven-year period
1975-1985. Those figures represent increases of approxi-
mately 3 and 5 percent resepectively over the baseline pro-
jections.
Consumer charges and operating revenues impacts
at the end of those periods, in 1980 and 1985, indicate in-
creases of approximately 6 percent. The end-of-period figures
are slightly higher than the average figures because the equip-
ment will be phased into service and not in operation through-
out the entire period.
-------
111-36
OPERATING REVENUES AND CONSUMER CHARGES
(1975 dollars)
Consumer Charges (mills/kwh)
- Baseline
- Impact
Operating Revenues (billions)
- Baseline
- Impact
Cumulative Operating Revenues
Since 1974 (billions)
- Baseline
- Impact
Source: Exhibit III-2
1980
31.7
+ 1.7
$ 74.0
+ 3.9
$377.9
+ 12, 2
IMPACTS
1985
32.0
+ 2.1
$ 96.8
+•'• 6.5
$812.7
+ 40.2
The air regulations account for the largest share
of the impacts by a significant margin. Due to their domi-
nant share of both capital expenditures impacts and 0/M
expense impacts, they account for other 80 percent of the
total impacts on operating revenues and consumer charges.
IMPACT ON THE AVERAGE RESIDENTIAL BILL
FOR ELECTRICITY
To view those impacts in perspective, one must
relate them to the average annual or monthly bill paid by
customers. This section focuses on the impact on residential
customers only; Volume VI of this report includes an assess-
ment of the impacts on major industrial/commercial users of
electricity.
-------
111-37
The table below summarizes the projected average
residential electric usage, the related electric bill, and
the impacts of federal pollution control regulations upon
that bill. The number of residential customers has been
increasing at a rate slightly faster than the country's
population growth. The continuation of that trend, together
with U.S. Census Bureau projections of population growth,
indicate that the number of residential customers will grow
from approximately 72.1 million in 1975 to 81.6 million in
1980 and 92.7 million in 1985. The usage per residential
customer is projected to increase at an annual rate slightly
below 4.5 percent over the period 1975-1985. That compares
to an historic rate of just over 6.0 percent per year during
1963-1973.
IMPACT OF POLLUTION CONTROL COSTS
ON THE AVERAGE RESIDENTIAL ELECTRIC BILL
(1975
No. of Residential Customers
(million)
Usage per Residential
Customer (kwh/yoar)
Average Residential Rate
(mills/kwh)
Average Annual Electric Bill
Average Monthly Bill
Direct Impact of Pollution
Control ($/mo.)
Direct and Indirect Impact
of Pollution Control ($/mo
dollars)
1975
72.1
8,155.00
37.66
$307.00
$ 25.60
-
•> -
1980
81.6
10,110.00
40.38
$408.00
$ 34.00
+$ 1.80
+$ 4.00
1985
92.7
12,481.00
40.76
$509 . 00
$ 42.40
+3 2.80
+$ 5.80
Residential rates for electricity have historically
been approximately 50 percent higher than rates to commercial
and industrial customers. The rationale for the difference
-------
111-38
has been that fixed costs of service for transmission and
distribution equipment, lines, and metering equipment are
amortized over many more kilowatt-hours of usage for com-
mercial and industrial customers.than for residential cus-
tomers. The variable costs of electricity generation,
primarily fuel costs, are of course not different for various
customers. Thus the average rate for a customer class is
composed of one component which is a system-wide average
variable cost of generation for all customers, and a second
component which is related to the fixed costs of service for
that customer class alone. .
The projections of the average residential rates
shown in the table have been based upon these assumptions:
first, that the historical pattern of fixed costs allocation
for residential customers versus commercial and industrial
customers will continue; and second, that all increases in
fuel costs will be passed along equally to both customer
classes. On that basis the average residential rate per
kilowatt-hour is expected to increase in real terms through
1977 and then to level out and increase with inflation in
current dollars. The rate is projected to increase from its
1975 level of approximately 37.66 mills per kilowatt-hour to
40.38 mills in 1980 and 40.76 mills in 1985. The average
residential bill, then, is projected to increase on the basis
of increased usage per customer from $25.60 per month in 1975
to approximately $42.40 in 1985.
The direct impact of pollution control expenses in
terms of direct increases in residential electric bills will
be approximately $1.80 per month in 1980 and $2.80 per month
in 1985 (1975 dollars). Those charges represent approximately
5 percent and 7 percent, respectively.
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111-39
Combined direct and indirect impacts have also
been included in the table on the assumption that all impacts
not passed on directly to residential customers would be
charged to industrial and commercial customers, who would
ultimately pass them on to residential customers in the
form of price increases on their products and services. On
that assumption, the eventual direct and indirect impact to
residential customers will be approximately $4.00 per month
in 1980 and $5.80 per month in 1985 (1975 dollars).
ENERGY IMPACTS
Scrubbers, low-sulfur coal, precipitators, and
cooling towers have impacts upon the output capability of
the generating plants which utilize them. Scrubbers, cool-
ing towers, and to a very small degree, precipitators, con-
sume electricity during operation, thereby reducing the net
output of the generating plant. Thus they require that a
larger number of kilowatt-hours be generated than was pre-
viously necessary in order to deliver a given level of
kilowatt-hours to ultimate consumers. The additional energy
required is referred to as an "energy penalty." The reduc-
tion in net capacity of the units affected is referred to
as a "capacity loss."
The burning of low-sulfur coal does not inherently
impact the output of a generating plant. Eastern low-sulfur
coal and some Western low-sulfur coal, for example, have Btu
contents above 11,000 Btu per pound and do not impact a
plant's output. Some Western low-sulfur coal, however, has
a heat content as low as 6,000 to 7,000 Btu per pound. When
that fuel is burned, many boilers and coal-handling systems
simply cannot accommodate the increased tonnage required to
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111-40
maintain the level of electricity generation which was pre-
viously produced with higher quality coal. That reduction
in effective capacity is also referred to as a "capacity
loss."
The capacity losses and energy penalties resulting
from the pollution control equipment which will be installed
to meet federal regulations are summarized in the table below.
CAPACITY LOSSES AND
ENERGY PENALTIES
COMBINED AIR AND WATER REGULATIONS
Total Industry Capacity '
(million kw)
Capacity Losses Since 1974
(million kw)
Cooling Towers
Scrubbers
Low Sulfur Coal
Precipitators
TOTAL
Total Industry Energy (quads*)
Energy Penalties (quads*1)
Cooling Towers
Scrubbers
Precipitators
TOTAL
^quadrillion Btu
Note: values listed as "0.0"
up at this level of detail.
Source: Exhibit III-2
1980
631.0
0.5
3.3
0.2
0.3
4.3
25.7
0.0
0.2
0.0
0.2
are too small
1985
751.0
4.1
4.6
0.2
0.3
9.2
33.2
0.2
0.3
0.0
0.5
to show
The total capacity losses will be approximately 9.2 million
kilowatts by 1985. Those figures indicate the loss of ap-
proximately 1 percent of the industry's total capacity. The
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111-41
increased additions to make up the losses require an increase
of approximately 5 percent in the planned level of capacity
additions to 1985.
The energy penalty which will result from the opera-
tion of pollution control equipment in 1980 and 1985 is ex-
pected to be approximately 0.2 and 0.5 quads, respectively.
The 1985 impact represents between 1 and 2 percent of the
industry's total energy consumption.
In both categories, capacity losses and energy
penalty, scrubbers and cooling towers will have approximately
equal impacts and together will account for almost 90 percent
of the total impacts. It should be noted that these estimates
do not include indirect energy impacts such as energy to mine
limestone for scrubbers or increased fuel consumption to move
Western low-sulfur coal to Eastern markets.
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111-42
CHAPTER 5
ASSUMPTIONS FOR ANALYSIS
OF THE AIR REGULATIONS
This chapter summarizes the inputs to analysis of
the Clean Air Act. The data has been provided by EPA,
Sobotka & Company, arid PEDCo Environmental Specialists,
Inc. It is voluminous and largely contained in Exhibits
I1-6 through 11-11 at the end of this volume. The text
discusses the approach to the analysis and highlights the
most significant inputs. It does not, however, attempt to
repeat every item which is available in an exhibit.
This analysis of the Clean Air Act focused upon
the impacts of complying with the sulfur dioxide (SO,,) and
total suspended particulate (TSP) maximum emission regu-
lations. As noted earlier, some topics were beyond the
scope of this study,such as the nitrogen oxide regulations,
and the significant deterioration regulations.
Furthermore, while the Clean Air Act requires
compliance by all gas- and oil-burning units as well as
coal-fired plants, the financial impacts virtually all fall
on the coal plants. It has been assumed for the analysis,
for example, that all oil-burning units would simply con-
form to the S00 regulation by burning low-sulfur oil at
£t
an incremental cost of 0.8 mills per kilowatt-hour for
plants in service by 1976, and 0.75 mills for new sources
(in 1975 dollars). Consequently, practically the entire
discussion below is devoted to inputs relating to coal
plants.
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CAPACITY AFFECTED BY THE REGULATIONS
EPA and its contractors have developed projections
of the extent to which each of the available SC» and TSP
£
control strategies would be utilized by the industry. The
projections have been developed on the basis of identifying
least cost strategies for each major coal-burning region of
the country. The projections have been expressed in thou-
sand megawatts affected by:
o compliance problem (i.e., S00 or particulate)
£
9 control strategy (i.e., scrubber)
• age of unit—in-service pre-1974, 1974-1976,
and new sources (i.e., post-1976)
o timing of compliance—by 1980, and 1985
The coverages for coal-burning units are
listed in Exhibits III-8 through III-ll. They are also des-
cribed below in four sets.
First, the level of pollution controls in the base-
line indicate that some pollution control equipment would be
utilized by the industry even without the federal regulations.
In the case of the air regulations, this would generally be
due to the existence of local regulations. As shown in
the next table and detailed in Exhibit III-8, approximately
7 percent of coal-fired units by 1980 would be equipped with
pollution control equipment which would satisfy the SC>2 emis-
sion standards even without federal regulations. The total
of 30.4 million kilowatts which would be in compliance, the
cost of which is not included in the impact of the regulations,
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BASELINE S02 COMPLIANCE
FOR COAL UNITS
(million kw)
Scrubbers
Medium-Sulfur Coal
Washing and Blending
TOTAL POLLUTION CONTROL EQUIPMENT
Units Burning Conforming Coal
TOTAL ALREADY IN COMPLIANCE
Capacity Requiring Controls
TOTAL COAL UNITS
Source: EPA, Sobotka & Co. , Inc.
(see Exhibit III-8)
1980
8.3
7.8
18.8
11.6
30.4
232.3
262.7
1985
~277
8.3
7.8
18.8
11.6
30.4
302.5
332.9
Under the baseline conditions only 30.4 million
kilowatts would meet the SO,, standard with no additional
cost whatsoever. Of that, approximately one-third would
simply be burning coal which conforms to the standards.
The others would be plants burning low-sulfur coal, plants
using washing and blending, and a very small number of
primarily demonstration units with scrubbers.
Second, new sources, that is plants put into
service after 1976, will be required to install permanent
controls at the time they become operational. The expected
compliance strategies for such systems are shown in the next
table (and listed in Exhibit III-9).
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111-45
NEW SOURCE (1977 AND LATER UNITS)
CONTROL STRATEGIES
CLEAN AIR ACT
(million kw)
Scrubbers
Western Low-Sulfur Coal
TOTAL WITH POLLUTION CONTROL
EQUIPMENT
Source: 'EPA, Sobotka & Co., Inc.
(See Exhibit III-9)
Coal
1980
29.1
30.4
1985
63.5
66.2
59.5 129.7
The new coal units, of which there are 59.5
million kw by 1980 and 129.7 million kw by 1985, are ex-
pected to be split almost evenly, with 49 percent install-
ing scrubbers and 51 percent burning Western low-sulfur
coal.
Third, 1974-1976 units are expected to meet the
S00 standards through similar strategies, with 48 percent
£t
burning low-sulfur coal and 36 percent installing scrubbers.
The strategies in 1985 will be the same as those in 1980;
once units have adopted a strategy they are assumed to be
permanently committed to it. (See table on next page.)
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111-46
1974-1976 UNITS CONTROL STRATEGIES
CLEAN AIR ANALYSIS
(million kw)
Scrubbers
Medium-Sulfur Coal
Western Low-Sulfur Coal
Precipitators
TOTAL WITH POLLUTION CONTROL
EQUIPMENT
1980
11.5
11.4
2.2
4.6
1985
11.5
11.4
2.2
4.6
29.7 29.7
Source:EPA, Sobotka & Co., Inc. (see Exhibit III-9)
Fourth, the pre-1974 generating units constitute
the largest amount of capacity in service, even through 1985.
As shown in the table on the next page, under the current legis-
lation, scrubbers are expected to be relied upon to bring 49.2
million kilowatts into compliance. The amount of capacity
actually scrubbed (and therefore the size of the scrubbers)
would be 42.9 million kilowatts, or one-fourth of all pre-1974
coal units. Those pre-1974 units would account for half of all
the scrubbers installed through 1980 and one-third of those
installed by 1985. Also under the regulations approximately
13 percent of pre-1974 capacity would burn medium- or low-
sulfur coal and approximately 21 percent would utilize wash-
ing and blending to meet the S02 regulations. The same
compliance strategies are assumed to apply for these units
in 1985 as in 1980.
Coal conversions under the baseline assumptions in
Volume II would be 14.4 million kilowatts of which 11.1 would
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111-47
be from oil and 3.3 would be from gas. Because of the added
cost of complying with the federal air pollution standards,
however, it is expected that oil to coal conversions will
actually be slightly lower (9.5 vs. 11.1 million kw). In
particular, it is assumed that oil-burning plants with SIPs
of less than 1 percent would require a scrubber if converted
to coal, and therefore would either not be converted or
would convert back to oil. The 1.6 million kilowatts in the
table below represent EPA's estimate of such units which
would thereby meet the S02 emission standard. It is expected
that gas' conversions to oil and coal would remain virtually
unchanged as a result of the regulations.
PRE-1974 UNITS CONTROL STRATEGIES
CLEAN AIR ACT ANALYSIS
(million kw)
Covered 1975-1980
Scrubbers
(amount scrubbed)
Medium-Sulfur Coal
Western Low-Sulfur Coal
Washing and Blending
TOTAL WITH POLLUTION CONTROL
EQUIPMENT
Already In-Compliance
Conversion to Oil
TOTAL COAL UNITS*
*See reference on page III-1 of text.
Source: EPA, Sobotka & Co., Inc.
1980 1985
49.2 49.2
(42.9) (42.9)
21.8 21.8
1.4 1.4
37.2 37.2
141.4 141.4
30.4 30.4
1.6 1.6
173.5 173.5
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111-48
CAPITAL COSTS
EPA has relied upon PEDCo's analysis of the best
available engineering information in developing estimates of
the capital costs of each of the alternative control strate-
gies. Exhibit II1-6 displays the capital costs used in the
analysis. For the most expensive and most controversial
units, scrubbers, EPA commissioned an independent study of
operating characteristics, performance, and cost. The study,
which was performed by PEDCo Environmental Specialists, Inc.
was made available to representatives of the utility industry
for their comments.
In identifying the capital costs associated with
the control strategies for coal units, EPA separately speci-
fied the costs on:
new sources, placed into service after
1976, on which the controls were assumed
to be installed during plant or unit
construction
pre-1974 units which must be retrofitted
1974-1976 units which also must be retro-
fitted.
Typical capital costs per kilowatt of capacity
affected are summarized below. The complete list of capital
cost estimates used in the analysis is shown in Exhibit II1-6
See full reference on page III-l.
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II1-49
TYPICAL COSTS FOR CONTROL STRATEGIES
PRE-1974 UNITS
(1975 dollars per kw)
Scrubbers
Medium-Sulfur Coal
Western Low-Sulfur Coal
Washing/Blending
Precipitators (upgrade)
S0_ Only
$70.27"
49.56
5.40
BOTH SO,
TSP Only AND TSP*
$16.56 $86 .'.83
17.40
62.48
17.40
17.40
1.57
17.40
Source: EPA, PEDCo (see Exhibit II1-6)
6.97
The capital costs in the analysis are inflated
at a rate approximately one to two points above the projected
GNP rate of inflation to reflect the rise of construction
costs and the experience of the electric utility industry.
The rates used were 8 percent for 1976-1977, 7 percent for
1978-1982, and 6 percent thereafter.
For purposes of computing depreciation and financing
(discussed later) the coal units to which these controls were
applied were assumed to have the following remaining economic
lives:
new sources, 33 years
1974-1976 units, 30 years
pre-1974 units, 25 years
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111-50
OPERATION AND MAINTENANCE COSTS
The direct operating costs for S02 and particulate
control technologies were also developed from the best avail-
able engineering data. These costs are expressed as incre-
mental costs per kwh which are incurred in addition to the
normal operation and maintenance costs o'f coal-fired units.
Exhibit III-7 displays the operating cost rates used in the
analysis.
The representative costs listed below should be
viewed in the context of national operation and maintenance
costs for coal units in 1975 of approximately 14 mills includ-
ing fuel costs. The costs below do include fuel premiums for
low-sulfur fuel where applicable.
TYPICAL O/M COSTS FOR CONTROL STRATEGIES
PRE-1974 UNITS
(1975
mills/kwh)
S02 ONLY Tsp QNLY
Scrubbers
Medium-Sulfur Coal
Western Low-Sulfur Coal
Washing/Blending
Precipitators
1.40
1.50
1.35
0.67
^
Source: EPA, PEDCo (see Exhibit
r.
0.30
0.21
0.21
0.03
0.21
III-7)
BOTH S09
AND TSP
1.70
1.71
1.56
0.70
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111-51
CAPACITY LOSS/ENERGY PENALTY
Four control strategies for coal units have
capacity losses or energy penalties associated with them
which are not included in either the capital or operating
and maintenance costs above. The extent of the penalties
is listed in the table below. It is assumed that units will
be built with bypasses and that temporary variances would be
granted in the event of scrubber outages. Thus, scrubbers
will not cause a capacity penalty due to forced outages of a
scrubber at times when the rest of a unit is available for
dispatch.
COAL CAPACITY
Scrubbers - energy
penalty
Mediu.n -Sulfur Coal-
capacity derate
Western Low-Sulfur Coal -
capacity derate (loss)*
Precipitator-energy
penaltv
LOSS/ENERGY PENALTY
so2
3.
-
4.
-
Average of Western low-sulfur coal
ooal which have total losses of 5.
Source: EPA, PEDCo
ONLY Tgp
5% 0.
0.
1 0.
ONLY
5%
5
5
BOTH SO
AND TSP^
4.
0.
4.
0%
5
6
0.5 . 0.5
and Southwestern low-sulfur
5 percent and 0, respectively.
The energy penalty incurred by scrubbers repre-
sents the electricity required to operate the scrubbers and
associated equipment. As such it represents an eventual
need for incremental new coal capacity equal ..to 3.5 or 4.0
percent of the capacity being scrubbed. It also requires
the generation of 3.5 to 4.0 percent more kilowatt-hours than
were formerly produced, thereby increasing the direct pro-
duction costs of the system.
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111-52
The capacity derate or capacity loss incurred by
switching a coal unit to low-sulfur coal is distinctly
different. It represents a reduced generation (in contrast
to an increased kilowatt hour need); it must be made up by
increased capacity but requires no net increase in kilowatt-
hour generation.
FINANCING
Financing for the compliance strategies was
assumed to be accommodated through conventional sources of
capital for the electric utility industry. In keeping with
historical balance in the industry, common equity was assumed
to maintain its -35 percent share of total capitalization,
while preferred stock will stay at approximately 10 percent,
and long-term debt will be 55 percent.
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111-53
CHAPTER 6
ASSUMPTIONS FOR ANALYSIS
OF THE WATER REGULATIONS
In December 1974, EPA published its assessment of
the impacts of the final effluent regulations on the electric
utility industry in a report entitled Economic Analysis of
Effluent Guidelines, Steam Electric Powerplants. The ther-
mal and chemical regulations analyzed in that report remain
the same today as they were then. However, industry condi-
tions have changed so much that many of the assumptions in
the previous analysis required updating. This chapter up-
dates the earlier report in four significant ways:
First, it revises the results based on the
reduced growth baseline forecast of demand
and construction (described in Volume II).
Second, it revises the estimates of capac-
ity which will be affected by the regula-
tions on the basis of inputs from the EPA
regional offices.
Third, it includes the impacts of 316(b),
entrainment, regulations.
Fourth, it determines the impacts of the
effluent guidelines for the 1975-1980 and
1978-1985 time periods which are consistent
with the analyses of the air regulations.
Developed by Temple, Barker & Sloane, Inc. tinder contract to EPA. This
chapter is a modification and extension of Chapter III, the "Analysis
of the Final Effluent Guidelines," in the December 1974 report: That
report remains the source for detailed descriptions of the analysis
and for information on three subjects which are not reiterated here:
(1) the preliminary and other proposed thermal guidelines; (2) the en-
vironmental impacts; and (3) the alternative assumptions of the Utility
Water Act Group (UWAG).
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Many of the assumptions which formed the basis for
the previous report were adopted from the analysis conducted
by the Technical Advisory Committee on Finance (TAC-Finance)
for the National Power Survey, 1973. Now, with two years'
more perspective, it is clear that certain of the TAC-Finance
estimates underestimated the long-term impacts of the demand
and cost developments underway in 1973 and 1974.
The major changes required relate to future costs
and future new plant construction activity. New or revised
assumptions have been made for the following items:
coverages (i.e., megawatts affected) of gener-
ating units which will be required by the
federal guidelines to install closed-cycle cooling,
or chemical treatment facilities, or both;
costs and coverages related to compliance
with 316(b), entrainment, regulations;
inflation rates;
financing costs;
baseline capital costs, operating costs, and
demand projections.
On the other hand, the estimates regarding the
basic 1974 costs of compliance have not changed. The follow-
ing assumptions from the December 1974 report have been
incorporated directly into the revised analysis:
© capital costs for closed-cycle cooling and
chemical treatment systems;
o operating costs for such systems;
o capacity penalties for closed-cycle cooling.
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111-55
The remainder of this chapter documents both series
of assumptions used in the current analysis. Coverages are
presented first, then capital and operating costs, and finally
energy penalties.
CAPACITY AFFECTED
In order to obtain more definitive estimates of the
amount of capacity which will be affected by the guidelines,
EPA surveyed the cognizant official in each EPA regional of-
fice. Detailed information was gathered from each on the
coverage of the various effluent guidelines, including thermal
coverages before and after Section 316(a) exemptions, and also
on the extent of closed cycle cooling anticipated for the pur-
poses of compliance with State Water Quality Standards. The
responses varied significantly from region to region, and
because of the differences between sites, receiving water bodies,
plant characteristics, etc. across the regions, it has been
very difficult to check whether a common methodology was ap-
plied consistently across regions. Nonetheless, the percentage
coverages implied by the data were adopted by EPA as the basis
for coverage computations in both the regional and national
analyses. These coverages have been identified for three cate-
gories of capacity corresponding to the presumed construction
status of plants in the industry, namely:
• Pre-1974 units are those in operation at the
time of promulgation of the regulations.
• 1974-1978 units are presumed to be those under
construction in 1974.
e 1979 and later units are presumed to constitute
the "New Sources" category which had not begun
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111-56
begun construction in 1974 and which meet
new source performance standards (NSPS).2
The coverages are presented below for each of
the three water effluent regulation categories of signifi-
cance to electric utilities: thermal, chemical, and
3
entrainment.
Thermal Capacity Coverage Estimates
An evaluation of the impact of the thermal guide-
lines should include those expenditures associated with
conversion to closed-cycle on units existing or under con-
struction and designed for closed-cycle cooling in anticipa-
tion of the Act. At the same time, however, units designed
for closed-cycle cooling for reasons other than environmental
(i.e., for economic reasons) should not be included in
economic and financial impacts of the Act. A majority of
the units which have installed closed-cycle cooling for
economic reasons have done so to compensate for an inade-
quate source of cooling water.
Exist ing Unit_s. The degree to which existing units
would be required to retrofit mechanical draft cooling towers
was a major policy variable in EPA's specification of alter-
native guidelines to be evaluated. The linal guidelines exempt
2
This category was specified for analytic purposes and does not neces-
sarily coincide with the legal definition of New Source Performance
Standards (NSPS). The legal definition states that all sources which
commence construction after promulgation of the final guidelines (that
is, October 4, 1974) must meet NSPS.
2
Exhibits 111-12 and III-1Z detail the percentage and kilowatt coverages,
respectively, for all water regulations by 1985.
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111-57
all units placed into service before 1970 from the require-
ments to meet the limitations on the discharge of heat. Of
the units placed into operation between January 1, 1970 and
January 1, 1974, only the largest baseload units (i.e., those
of 500 megawatt capacity or greater) are subject to effluent
control under the Act,. In addition to the age of the unit,
the specification of these exemptions explicitly includes
unit size as a factor.
These exemptions greatly reduce the proportion of
existing units which are covered by the thermal guidelines.
Based upon the survey of EPA regional-offices, EPA estimated
that these final regulations would cover 70 percent of exist-
ing nuclear capacity and 26 percent of existing non-nuclear
capacity prior to any consideration of additional exemptions
under Section 316(a) of the Act.
Section 316(a) of the Act specifies that any unit
can be exempted from effluent, limitation which is "... more
Hl,r,l,tiK"nt than noooHHary !.<> H.HHUTO thn protection and propa-
gation of a balanced, indigenous population of shellfish,
fish, and wildlife in and on the body of water into which the
discharge is to be made." The survey responses indicated
that only 22 percent of nuclear and 8 percent of non-nuclear
capacity placed into service prior to 1974 (i.e., existing
units) would be required to convert to closed-cycle cooling
after the consideration of Section 316(a) exemptions.
Units Under Construction. Simply stated, all steam
electric generating units placed in service on or after
January 1, 1974 are required to install closed-cycle cooling.
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111-58
However, the impact of the thermal guidelines on generating
units now under construction must be segmented into two cat-
egories since the cost of retrofitting a unit is significantly
greater than the cost of installing mechanical draft cooling
towers or an equivalent technology whenever the unit was de-
signed for such equipment.
In estimating the required coverage for units under
construction (i.e., placed in service 1974-1978), EPA first
segmented this capacity into that which had been designed for
(1) open-cycle, and (2) closed-cycle cooling.
All steam electric generating units which were
designed for open-cycle cooling were assumed to require con-
version prior to the Section 316(a) exemption while only those
units which posed a high environmental risk were required to
meet the thermal guidelines after this exemption. These cover-
age estimates were: 50 percent of nuclear and 16 percent of
non-nuclear capacity before Section 316(a) exemptions, and
25 percent of nuclear and 10 percent of non-nuclear capacity
after Section 316(a) exemptions.
In addition to these conversions from open- to
closed-cycle, the remainder of steam electric generating units
now under construction are planning to install closed-cycle
cooling systems. As previously stated, some proportion of
these units may be doing so in anticipation of the Act's final
guidelines—and therefore, should be included in an assess-
ment of the Act's economic and financial impact. Likewise,
those units which are installing closed-cycle cooling for
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111-59
economic reasons or compliance with State Water Quality
Standards should be evaluated but should not be included in
measuring the overall impact of the Act. EPA has estimated
that 25.5 percent of nuclear and 66.2 percent of non-nuclear
capacity to be placed in service 1974-1978 are planning to
install closed-cycle cooling. EPA estimated that 25 percent
of non-nuclear units were doing so for economic reasons and
0.5 percent were doing so to comply with State Water Quality
Standards (SWQS). The fossil capacity was estimated to be
24.5 percent for economic reasons, 1.7 percent for SWQS, and
40 percent to meet the federal guidelines. EPA further
estimated that only 25 percent would finally be required to
convert after Section 316(a) exemptions.
New Source Units. Once again, all steam electric
generating units are required to install mechanical draft
cooling towers or their equivalent. However, new source
units, defined as those units placed in service after 1978,
are assumed to install closed-cycle cooling for operation at
the time the units are placed in service. Of the units to be
placed in service after 1978, the EPA survey indicated that
50 percent of nuclear and 56 percent of fossil capacity are
assumed to be covered before Section 316(a) exemptions. Coverage
after these exemptions is assumed to be 25 percent of nuclear
and 35 percent of fossil generating capacity. In addition,
EPA previously estimated that 34.5 percent of nuclear and
32.5 percent of fossil capacity would install closed-cycle
cooling for economic reasons during the period 1979-1990;
those estimates are still being used.
Generation Capacity Affected. The total generation
capacity that is required to install mechanical draft dooling
towers or an equivalent technology as a result of the final
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111-60
thermal guidelines, after consideration of those who do so
for economic reasons and those who are expected to receive
Section 316(a) exemptions, i£ summarized in the following
table.
THERMAL GUIDELINES AFTER
316(a) EXEMPTIONS
GENERATION CAPACITY COVERED*
(millions of kw)
Retrofitted
Pre-1974 Units
1974-1978 Units
Subtotal
Planned
1974-1978 Units
1979-1985 Units
Subtotal
TOTAL
1975-1985
30.5
18.4
48.9
20.7
54.8
75.5
124.4
^excluding coverages for economic reaeone
Thus 124.4 million kilowatts of generation capacity
will be required by 1985 to install closed-cycle cooling as
a result of the Act—approximately 16 percent of the genera-
tion capacity in service at that time. Of this amount, 48.9
million kilowatts will have been retrofitted from open- to
closed-cycle. This amounts to 8.5 percent of the generation
capacity in service at the end of 1978 when new source stan-
dards are assumed to be applied and 7.0 percent of capacity
in service at the end of 1983 when the retrofitting must be
completed.
Over half of the generating capacity that is placed
in service by 1985 and is covered by the Act must install
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111-61
closed-cycle cooling at startup. In addition to the capacity
placed in service prior to 1979, 54.8 million kilowatts of the
capacity brought on stream during the period 1979-1985 will be
covered by new source requirements.
In total, 124.4 million kilowatts of generating
capacity will be covered by the guidelines in 1985, excluding
those who install closed-cycle cooling for economic reasons
and those who are expected to receive Section 316(a) exemptions.
Capacity Penalty. The installation of closed-cycle
6 • « i '™™ •"' ~' • ' ""• *•
cooling facilities will require the construction of additional
generating capacity to operate the cooling towers and to com-
pensate for the loss of efficiency resulting from an increase
in turbine back-pressure. This capacity loss, based upon a
1 percent loss for operation of the cooling units and an addi-
tional 2 percent due to increased back-pressure, will approxi-
mate 4 million kilowatts by 1985.
Thermal Installation Schedules. The final effluent
guidelines as published in the Federal Register (39 FR 36186)
specify that all units which require conversion to closed-cycle
cooling must do so prior to July 1, 1981 unless it can be
demonstrated that such conversions would seriously impact sys-
tem reliability. If system performance would be adversely
affected, EPA Regional Administrators or equivalent State
Authorities can accept an alternative schedule of compliance
providing that the alternative schedule requires units repre-
senting at least 50 percent of the affected generating capacity
meet the compliance date, that units representing at least 80
percent comply by July 1, 1982, and the remaining units comply
by July 1, 1983.
-------
111-62
In assessing the economic and financial impact of
the thermal guidelines, EPA specified an installation schedule
which applied the following rules of thumb for retrofitted
units:
• units of 500 megawatts or greater converted
for operation of closed-cycle cooling begin-
ning in 1981;
• units of 300 megawatts but less than 500
megawatts converted for operation in 1982;
and
• all other units converted for operation in
1983.
New source units and those under construction de-
signed for closed-cycle cooling were assumed to have the
cooling system operational at the time that the generating
unit was placed in service.
Chemical Capacity Coverage Estimates
In addition to the above-mentioned thermal guide-
lines, the Act specifies chemical effluent limitations which
range from pH level to suspended solids, to oil and greases,
to metals in waste streams, to chlorine. These final chem-
ical requirements as stipulated by EPA differ somewhat in
concept from the above-mentioned specifications of thermal
guidelines in that initial coverages are required by 1977
with additional, more stringent, requirements by 1983.
EPA originally assumed that all steam electric
generating capacity will be required to meet the chemical
standards. Its survey of the regional offices, however,
-------
111-63
indicated a lower level of coverage: regarding nuclear units,
70 percent for pre-1974 capacity and 34 percent for all later
units; regarding fossil capacity, 61 percent for pre-1974 units
and 56 percent for later units.
Thus the final chemical guidelines will apply to
nearly 356 million kilowatts of generating capacity by 1985.
The levels of coverage specified by the chemical guidelines
are almost three times greater than those associated with the
thermal guidelines over the next decade.
Chemical Installation Schedules. In assessing the
economic and financial impact of the chemical guidelines, EPA
specified separate installation schedules to meet the 1977 and
the 1983 effluent limitation requirements. The installation
schedule for the 1977 guidelines was assumed to be based on
the capacity placed in service prior to 1978. This schedule
is:
• 1974 15 percent of 1977 capacity
• 1975 20 percent of 1977 capacity
• 1976 25 percent of 1977 capacity
• 1977 40 percent of 1977 capacity
Capacity placed into service in 1978 is assumed to meet these
requirements upon placement in service.
In addition to the above schedule, EPA specified
an installation schedule to meet the 1983 guidelines which
required (1) all capacity placed into service after 1978 to
meet the standards at the time of initial operation, and (2)
all earlier generation capacity to meet the standards according
to the following time schedule:
-------
II1-64
o 1979 10.percent of 1978 capacity
• 1980 10 percent of 1978 capacity
• 1981 20 percent of 1978 capacity
o 1982 20 percent of 1978 capacity
• 1983 40 percent of 1978 capacity
Entrainment Coverage Estimates
Entrainment regulations constitute still another type
of water effluent control regulation. Their objective is to pre-
vent, through proper screening and filtration or conversion to
closed-cycle cooling, the intake of living organisms with the
cooling water for a generating unit. These regulations do not
have exemptions or applications for economic reasons. However,
the regulations do not completely cover the industry's steam
electric plants.
The regulations are expected to affect only existing
units and some now in construction. All new units placed in
service in 1979 and later years are expected to meet the regu-
lations through simple design changes without an increase in
plant or operating costs. EPA has developed coverage estimates
only for those units which would be forced to install closed-
cycle cooling to meet this regulation. Approximately 14 percent
of existing nuclear plants and 1.4 percent of existing fossil
plants are expected to fall into that category. Approximately
3.8 percent of the 1974-1978 nuclear units and 3.5 percent of
the 1974-1978 fossil units will also be impacted.
The net effect of the entrainment guidelines will be
to require cooling towers on 4.5 million kilowatts of nuclear
capacity and 7.4 million kilowatts of non-nuclear capacity by
1985. That total of 11.9 million kilowatts represents only 2.0
percent of the total steam electric capacity which will be in
operation in 1985.
-------
111-65
CAPITAL AND OPERATION AND MAINTENANCE
COST ESTIMATES
The capital cost assumptions utilized in the economic
analysis of the effluent guidelines are based on a combination
of engineering estimates and surveys of actual costs experienced
at existing plants wherever possible. As the first step in
estimating the economic and financial impact of the Act, EPA
specified the technical standards which were to be required
in its Development Document of Effluent Limitations Guidelines
and New Source Performance Standards for the Steam Electric
Power Generating Point Source Category ^December 1974). Having
specified the technical standards, EPA then sought technical
sources among the equipment suppliers to the electric utility
^industry and among representative plants within the industry.
The estimates which resulted from that process are
described below for each of the three regulations. In all
cases both the capital costs for equipment and the operation and
maintenance costs are expressed in dollars per kilowatt. Unless
otherwise noted all cost estimates were developed in current dollars
Thermal Guidelines Cost Estimates
The cost estimates for compliance with the thermal
guidelines are based on: (1) a 1974 survey of costs incurred at
existing plants; and (2) the incremental cost of installing
mechanical draft cooling towers instead of open-cycle cooling
on new units. These final cost estimates reflect the many
comments which were submitted to EPA and which with minor ex-
ceptions were acceptable to most representatives of the electric
utility industry. Exhibit I11-14 details the final capital
cost estimates which are summarized in the following table.
-------
111-66"
CAPITAL COST OF THERMAL GUIDELINES
(1975 dollars per kilowatt)
For retrofitted units
For new (planned) units
Non-Nuclear
Units
$24.09
$ 5.77
Nuclear
Units
$29.11
$ 4.54
Source: Exhibit III-
Clearly, the process of installing closed-cycle
cooling on units which currently have open-cycle cooling and
on those units which are under construction and were designed
for open-cycle cooling is much more expensive than the instal-
lation cost of closed-cycle on new units. This results from
the need to (1) dismantle and/or redesign the existing cooling
system, and (2) absorb the total, not incremental, cost of the
additional closed-cycle cooling facilities. The lower incre-
mental cost for nuclear units being planned reflects their
higher cost for open-cycle cooling—a result of plant sites
located at considerable distance from sources of cooling water.
Exhibit HI-IS summarizes the operating costs associated
with thermal guidelines that represent the annual operating
and maintenance expenses for the cooling equipment as well as
associated replacement capacity. In estimating the operational
impacts of closed-cycle cooling, EPA specified a capacity pen-
alty of 3 percent which reflects:
• 2 percent due to increased turbine
back-pressure, and
1 percent due to operating require-
ments for the cooling tower.
-------
111-67
The fuel costs employed for this analysis of operating costs
were based on: (1) an average heat rate of 10,000 Btu per
kilowatt-hour, (2) a fuel mix of 80 percent coal and 20 percent
oil, and (3) 1975 prices of $12.50 per barrel of oil and $20.00
per ton for coal.
Chemical Guidelines Cost Estimates
The cost estimates for compliance with the chemical
guidelines are detailed in Exhibits 111-16 to 111-19. As above,
the estimates have been segmented by type of capacity and age of
units (year in service). The estimates are summarized in the
table below.
CAPITAL COST OF CHEMICAL GUIDELINES
(1975 dollars per kilowatt)
For 1977 Guidelines
Retrofitted Units
New (Planned) Units
For 1983 Guideline.-! •
Retrofitted Units
New (Planned) Units
Non-Nuclear
Units
$ 2.01
1.52
$ 0.68
0.61
Nuclear
Units
$0.68
0.68
$1.92
0.57
Inaivxtntal oott required to moat 1983 guide I inga
in addition to 137? guideline*.
Source: Exhibits 111-16, 111-17
These costs are significantly lower than those for
compliance with the thermal guidelines presented earlier. For
example, the capital cost for retrofitted mechanical draft
cooling towers ranges from approximately $24 to $29 per kilo-
watt (1975 dollars), whereas retrofitted chemical treatment
costs for both the 1977 and 1983 guidelines total less than
$3 per kilowatt. The lower unit cost of the chemical treatment
equipment, however, is partially offset by the fact that the
chemical guidelines impact significantly more generating capac-
ity than the thermal guidelines.
-------
111-68
The operating costs for compliance with the chemical
guidelines are also relatively low. They are detailed in
Exhibits 111-18 and 111-19 and range from a total (for 1977
and 1983 guidelines combined) of $0.31 to $0.69 per kilowatt
per year (1975 dollars).
Entrainment Cost Estimates
Entrainment cost estimates were developed during 1975
by EPA for the equipment associated with its guidelines. Some
plants may incorporate design modifications to prevent organisms
from being drawn into the plants along with the cooling water.
Other plants, however, will be required to convert to closed-
cycle cooling in order to comply. The capital costs for the
latter are detailed in Exhibit 111-20 and are summarized in
the table below.
CAPITAL COST OF ENTRAINMENT GUIDELINES
(1975 dollars per kilowatt)
Non-Nuclear Nuclear
Units
Cooling Towers
Retrofitted units
Units under
construction
Source: Exhibit 111-20
$24.10
24.10
Units
$20.05
19.69
The cooling towers installed to comply with these
guidelines will also result in approximately a 3 percent
energy penalty, as do the cooling towers installed to comply,
with thermal regulations.
-------
111-69
Compliance through the use of design modifications
involves no additional operating expenses. The use of cooling
towers, however, does include an operating cost associated with
generation of the additional electricity to make up the energy
penalty.
-------
111-70
CHAPTER 7
COMPARISON OF CURRENT ANALYSIS
OF WATER REGULATIONS AND DECEMBER 1974 RESULTS
The current cost estimates of compliance with federal
water pollution control regulations have changed from those
published by EPA in December 1974 in the report Economic
Analysis of Effluent Guidelines, Steam Electric Powerplants.
The table below shows two very significant modi-
fications as a result of the revised baseline estimates for
the electric utility industry.
COMPARISON OF DECEMBER 1974 AND REVISED
ECONOMIC IMPACTS OF THERMAL AND CHEMICAL
GUIDELINES*
1974-1983&
December 1974 Estimates
Capital Expenditures
(bill.'ona)
External Financing
(billions)
0/M Expenses
(billions)
Consumer Charges
(mills/kwh at
end of period)
(1974 $)c
•«• $4.7
+ 3.9
+ 0.9
•*• 0.2
(1975 $)d
+ $5.1
+ 4.3
+ 1.0
+ 0.2
Revised
Estimates
(1975$)'
+ $4.5
+ 4.4
+ 2.1
+ 0.4
aCoets for Entrainment Compliance were not estimated in the December
1974 report.
apparent inooneietenay . betaeen time periods of 1974-1983 in the
Deoerrbar 1974 report and 1976-1983 for the revised estimates is
resolved because the megaaatts of oapaoity assumed oovered in 1374
in the earlier analysis have nou been assumed to be oovered in 1975
instead.
°JSsfiibit 88, Eaonomio Analysis of Effluent Guidelines, Steam
Eleotrio Poaerplants, U.S. EPA (Deoenber 1974)
dollars estimated at 9.6 percent inflation above 1974 dollars
-------
111-71
First, capital expenditures requirements
have declined primarily because reduced
growth for the industry means fewer new
units will be built than had previously
been expected.
Second, operations and maintenance ex-
penses and consumer charges have increased
because fuel costs have accelerated the
cost of making up the energy penalties
associated with closed-cycle cooling
systems.
For example, the differences in the capital cate-
gories can be observed easily by comparing the kilowatts of
capacity covered by closed-cycle cooling under the two sets
of assumptions as shown below. Because demand growth has
slackened and many capacity additions have been postponed
or cancelled, the total amount of capacity which will utilize
closed-cycle cooling as a result of the regulations has
declined from 130.9 million kilowatts estimated in 1974 to a
current assumption of 109.0 million kilowatts—a decline of
17 percent.
CAPACITY COVERED BY THERMAL
GUIDELINES, AFTER 316(a) EXEMPTIONS
1974-1983
(millions kw)
a
Type of Capacity
Prior to 1974,
Retrofitted
1974-1978 Retrofitted
Subtotal
1974-1978 Planned
1979-1983 Planned
Subtotal
TOTAL
December 1974
Estimates
10.8C
23.5
34.3
34.4
60.7
95.1
130.9
Revised
Estimates
30.5
18.4
48.9
20.7
39.4
60.1
109.0
Excluding coverages for economic reasons
"Table, page 82, Economic Analysis of Effluent Guidelines,
Steam Electric Powerplants, EPA fDecember 1974)
°oorrected from the 12. 3 figure in the publiahed table;
the remaining difference eterns from lower nuclear capacity
than expected
-------
111-72
However, while the capital-related impacts declined,
the operations and maintenance and consumer charges associated
with the regulations increased significantly as a result of
several factors which are discussed in Volume II in terms of
the revised baseline projections. Those include the following:
• substantial price increases in 1974 and
later years
• increased non-fuel operation and maintenance rates
as a result of labor, materials, and other factors
• the inclusion of.generation not sold in
the total generation requirements.
The analysis published in December 1974 has been
reviewed and accepted widely. The revisions of that report
presented earlier in this volume and reconciled in this chap-
ter represent only changes which stem from revised baseline
projections for the industry, in terms of both construction
plans and cost escalation. The net change from the published
results has been approximately a 17 percent reduction in
kilowatts covered by the expensive thermal guidelines, a
12 percent reduction in capital expenditures impacts, and a
100 percent increase in operations and maintenance expenses
and consumer charges.
-------
Exhibit III-l
FINANCIAL IHPACTS OF AIR AND WATER POLLUTION CONTROLS
FOB ECONOMIC AND NON-FEDERAL REASONS1
FOR SELECTED YEARS
2
(dollar figures in billions of 1975 dollars)^
3
Capital Expenditures
Total for year
Total since 1974
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1974
Operating Revenues
Total for year
Total since 1974
4
Operations and Maintenance Expenses
Total for year
Total since 1974
Consumer Charges (mills/kwh)
Average for year
Capacity Losses (millions of Jn)
Total since 1974
Energy Penalty (Quads)
Total for. year
1980
+0.2
+1.1
+1.9
+1.0
+2.9
+0.4
+1.1
+0.1
+0.5
+0.2
+0.7
+0.4
1985
+0.2
+4.1
+0.4
+0.2
+4.1
+ 1.0
+5.2
+0.4
+2.1
+0.3
+3.8
+0.2
1390
+0.4
+5.7
+0.5
+0.3
+5.4
+ 1.2
+ 10.8
+ 0.6
+4.5
+0.3
+5.9
+0.3
I
-a
w
Includes compliance with State Water quality Standards
o
1975 dollars assume 9.5 percent infljzicn in 1975
net of CUIP increase
4excludes nuclear- fuel
Source: Ptm (Electric Utilities)
-------
Exhibit III-2
FINANCIAL IMPACTS OF COMPLIANCE WITH THE CLEAN AIR ACT
AND FEDERAL WATER POLLUTION CONTROL ACT AFTER 316(a) EXEMPTIONS
FOR SELECTED YEARSl
(dollar figures in billions of 1975 dollars)2
0
Capital Expenditures
Total for year
Total since 1974
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1974
Operating Revenues
Total for year
Total since 1974
4
Operations and Maintenance Expenses
Total for year
Total since 1974
Consumer Charges (mills/kwh)
Average for year
Capacity Losses (millions of kw)
Total since 1974
Energy Penalty (Quads)
Total for year
1980
+3.1
+14.5
+4,2
+2.6
+ 14.5
+3.9
+12.2
+1.9
+5.8
+1.7
+4.3
+0.2
1985
+1.6
+25.0
+3.2
+1.8
+21.9
+6.5
+40.2
+3.2
+19.2
+2.1
+9.2
+0.5
1990
+3.0
+38.3
+4.3
+2.7
+ 33.9
+9.3
+80.4
+4.8
+39.7
+2.4
+16.2
+0.8
excludes impacts of pollution controls for eaonomia and non-Federal reasons
2
1975 dollars assume 9.5 percent inflation in 1975
net of CVIP increase
4
excludes nuclear fuel
Source: PTm (Electric Utilities)
-------
Exhibit III-3
FINANCIAL IMPACTS OF COMPLIANCE WITH THE CLEAN AIR ACT
AND FEDERAL WATER POLLUTION CONTROL ACT BEFORE 316(a) EXEMPTIONS
FOR SELECTED YEARS*
(dollar figures in billions of 1975 dollars)
n
Capital Expenditures
Total for year
Total since 1974
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1974
Operating Revenues
Total for year
Total since 1974
3
Operations and Maintenance Expenses
Total for year
Total since 1974
Consumer Charges (mills/kwh)
Average for year
Capacity Losses (millions of tw)
Total since 1974
Energy Penalty (Quads)
Total for year
1980
+ 3.3
+ 14.8
-i- 7.2
+ 4.2
+ 17.8
+ 4.0
+ 12.5
+ 1.9
+ 5.8
+ 1.7
+ 4.6
+ 0.2
1985
+ 1.7
+29.6
+ 3.4
+ 2.0
+26.4
+ 7.5
+44.8
+ 3.5
+20.5
+ 2.5
+ 13.3
+ 0.7
1990
+ 3.2
+43.9
+ 4.8
+ 2.9
+ 39.1
+ 10.4
+90.3
+ 5.2
+42.9
+ 2.7
+21.7
+ 1.0
I
~J
tn
1975 dollars assume 9. 5 percent i.r.flG.t-ic-n in 1975
2
net of CWIP increase
excludes nualear fuel
*excludes impacts of pollution controls for economic and non-federal reasons
Source: PTra (Electric Utilities)
-------
111-76
Exhibit 111-4
CAPITAL EXPENDITURES IMPACTS
OF COMPLIANCE WITH CLEAR AIR ACT
(Incremental to Baseline Costs)
(billions of 1975 dollars)
Control Used
Flue Gas Desulfurization
Eastern Medium Sulfur Coal
Western Low Sulfur Coal
Equipment Modifications
Precipitators
Washing & Blending
Other Precipitators
SCS2
Total
Flue Gas Desulfurization
Eastern Medium Sulfur Coal
Western Low Sulfur Coal
Equipment Modifications
Precipitators
Washing & Blending
Other Precipitators
SCS2
Total
S02
Compliance
7.5
-
0.6
0.3
0.2
-
-
8.6
9.8
-
1.3
0.3
0.2
:
11.6
TSP1
Compliance
1975-1980
1.8
0.9
- •
1.7
0.0
0.6
-
5.0
[1975-1985
3.0
0.9
-
3.9
0.0
0.6
8.4
Total
9.3
0.9
0.6
2.0
0.2
0.6
13.6
12.8
0.9
1.3
4.2
0.2
0.6
20.0
Total Suspended Partioulate
n
Supplemental Control Syeteme
Source: PTm (Electric Utilities)
-------
111-77
Exhibit III-5
CAPITAL EXPENDITURES IMPACTS
EFFLUENT GUIDELINES POLLUTION CONTROL EQUIPMENT
(billions of 1975 dollars)
Guidelines
Thermal, After 316(a) Exemptions
Entrainment, 316(b)
Chemical
Total
Thermal, After 316(a) Exemptions
Entrainment, 316(b)
Chemical
Total
Fossil
Nuclear
1975-1980
$0.2
0
0.6
$0.8
$0.1
0
0
$0.1
1975-1985
$2.4
0.3
0.8
$3.5
$1.2
0.2
0.1
$1.5
Total
$0.3
0
0.6
$0.9
$3.6
0.5
0.9
$5.0
-------
II1-78
Exhibit III-6
CAPITAL COSTS
USED IN CLEAN AIR ACT ANALYSIS
(1975 dollars per kw)
Control Technology
Scrubbers
Eastern Medium Sulfur Coal
Western Low Sulfur Coal
Washing and Blending
Precipitators (Upgrade)
Conforming Coal
Scrubbers
Eastern Medium Sulfur Coal
Western Low Sulfur Coal
Washing and Blending
Precipitatorn (Upgrade)
Conforming Coal
Scrubbers
Eastern Medium Sulfur Coai
Western Low Sulfur Coal
Washing and Blending
Precipitators (Upgrade)
Conforming Coal
Co
S02
Only
mgliance_Pro
TSP
Only
3lem
Both SC>2
and TSP
Pre-1974 Units
$70.27
- .
49.56
5.4
-
—
$16.56
17.40
17.40
1.57
17.40
45.50
$86.83
17.40
62.48
6.97
-
™"
1974-1976 Units
$55.50
-
12.50
-
-
—
$16.56
35.00
56.00
-
-
45.50
$72.06
35.00
68.50
-
-
~
1977 and Later Units
$55.50
_.
-
-
-
$16.56
~*
-
-
-
$72.06
65.88a
-
-
-
a$16.00 for boiler modification, $49.88 for precipitate? upgrade.
Source: PEDCo Environmental Services, September 1976
-------
111-79
Exhibit III-7
OPERATIONS AND MAINTENANCE COSTS
USED IN CLEAN AIR ACT ANALYSIS
(1975 mills per kwh)
Control Technology
Scrubbers
Eastern Medium Sulfur Coal
Western Low Sulfur Coal
Washing and Blending
Precipitators (Upgrade)
Conforming Coal
Scrubbers
Eastern Medium Sulfur Coal
Western Low Sulfur Coal
Washing and Blending
Precipitators (Upgrade)
Conforming Coal
Scrubbers
Eastern Medium Sulfur Coal
Western Low Sulfur Coal
Washing and Blending
Precipitators (Upgrade)
Conforming Coal
Compliance Problem
S02
Only
]
1.40
1.50
1. 35
0.67
-
1.15
0.67
0.44
-
-
-
TSP
Only
Both SOo
and TSP
Pre-1974 Units
0.30
0.21
0.21
0.03
0.21
—
1.70
1.71
1.56
0.70
-
—
1974-1976 Units
0.30
0.35
0.30
-
-
0.33
1.45
1.02
0.74
-
-
—
1977 and Later Units
1.15
-
-
-
-
—
0.30
-
-
-
-
—
1.45
-
2.45
-
-
—
Source: PEDCo Environmental Services, September 1975
-------
Exhibit III-8
COVERAGE ASSUMPTIONS FOR BASELINE CONDITIONS
FOR COAL UNITS IN 1980 AND 1985
(millions of kilowatts covered to date)
Compliance Problem/Control Strategy
Out of SO^ Compliance
Scrubbers
Medium Sulfur Coal
Western Low Sulfur Coal
Washing & Blending
Supplemental Control Systems (SCS)
Subtotal
Out of TSP2 Compliance
Electrostatic Precipitators
Out of Compliance on Both SO2 and TSP
Scrubbers
Medium Sulfur Coal
Western Low Sulfur Coal
Washing & Blending
Supplemental Control Systems (SCS)
Subtotal
Total with Pollution
Control Equipment
Capacity not Covered
Total
1980
Pre-1974
Units
'
-
-
-
-
_
-
2.0
1.8
-
7.8
_
11.6
11.6
161.9
173.5
1974-1976
Units
-
-
-
-
• _
- -
0.7
6.5
-
-
_
7.2
7.2
22.5
29.7
New
Sources1
-
-
-
-
-
_
•
-
-
-
-
_
-
-•
59.5
59.5
Total
-
-
-
•
-
_
2.7
8.3
-
7.8
_
18.8
18.8
243.9
262.7
1985
Pre-1974
Units
-
-
-
-
-
_
-
2.0
1.8
-
7.8
_
11.6
11.6
161.9
173.5
1974-1976
Units
-
-
-
-
-
_
-
0.7
6.5
-
-
_
7.2
7.2
22.5
29.7
New
Sources1
-
-
-
-
-
_
-
-
-
-
-
_
-
-
129.7
129.7
Total
-
-
-
-
-
- '
• -
2.7
8.3
-
7.8
_
18.8
18.8
314.1
332.9
I
00
o
Placed in service after 1976
2
Total Suspended Partiaulate
Source: Environmental Protection Agency; Sobotka & Co., Inc.
-------
Exhibit II1-9
COVERAGE ASSUMPTIONS FOB COMPLIANCE WITH CLEAN AIR ACT
FOR COAL UNITS IN 1980 AND 1985
(millions of kilowatts covered to date)
Compliance Problem/Control Strategy
Out of S02 Compliance
Scrubbers
Medium Sulfur Coal
Western Low Sulfur Coal
Washing & Blending
Supplemental Control Systems (SCS)
Subtotal
Out of TSP2 Compliance
Electrostatic Precipitators
Out of Compliance on Both 803 and TSP
Scrubbers
— kw Scrubbed & Precipitators
— kw Precipitators Only
Medium Sulfur Coal
Western Low Sulfur Coal
Washing & Blending
Supplemental Control Systems (SCS)
Subtotal
Total with Pollution
Control Equipment
Already in Compliance
Coal Conversion to Oil
Total
1980
Pre-1974
Units
21.8
-
-
17.9
_
39.7
31.8
21.1
6.3
21.8
1.4
19.3
-
69.9
141.4
30.4
1.6
173.5
1974-1976
Units
-
-
-
_
4.6
11.5
-
11.4
2.2
-
_
25.1
29.7
-
-
29.7
New
Sources^
.
-
-
-
_
_
29.1
-
-
30.4
-
_
59.5
59.5
-
-
59.5
Total
21.8
-
-
17.9
_
39.7
36.4
61.7
6.3
33.2
34.0
19.3
_
120.5
230.6
30.4
1.6
262.7
1985
Pre-1974
Units
21.8
-
-
17.9
_
39.7
31.8
21.1
6.3
21.8
1.4
19.3
_
69.9
141.4
30.4
1.6
173.5
1974-1976
Units
_
-
-
-
_
4.6
11.5
-
11.4
2.2
-
_
25.1
29.7
-
-
29.7
New
Sources1
_
-
-
-
_
—
63.5
-
-
66.2
_
—
129.7
129.7
_
-
129.7
Total
21.8
-
-
17.9
_•
39.7
36.4
96.1
6.3
33.2
69.8
19.3
_
224.8
300.9
30.4
1.6
332.9
I
00
Placed in service after 1976
2
Total Suspended Particulate
Source: Environmental Protection Agency; Sobotka & Co., Inc.
-------
Exhibit I11-10
COVERAGE ASSUMPTIONS FOR COMPLIANCE WITH SCS 50 PERCENT OPTION
FOR COAL UNITS IN 1980 AND 1985
(millions of kilowatts covered to date)
Compliance Problem/Control Strategy
Out of S02 Compliance
Scrubbers
Medium Sulfur Coal
Western Low Sulfur Coal
Washing & Blending
Supplemental Control Systems (SCS)
Subtotal
Out of TSP2 Compliance
Electrostatic Precipitators
Out of Compliance on Both SO2 and TSP
Scrubbers
— kw Scrubbed & Precipitators
— kw Precipitators Only
Medium Sulfur Coal
Western Low Sulfur Coal
Washing & Blending
Supplemental Control Systems (SCS)
Subtotal
Total with Pollution
Control Equipment
Already in Compliance
Coal Conversion to Oil
Total
1980
Pre-1974
Units
2.4
2.0
3.9
2.1
29.3
39.7
31.8
5.5
1.3
4.8
7.9
2.6
47.8
69.9
141.4
30.4
1.6
173.5
1974-1976
Units
-
-
-
-
4.6
4.8
-
3.9
7.1
-
9.3
25.1
29.7
-
-
29.7
New
Sources1
-
-
-
-
_
29.1
-
'-
30.4
-
-
59.5
59.5
-
-
59.5
Total
2.4
2.0
3.9
2.1
29.3
39.7
36.4
39.4
1.3
8.7
45.4
2.6
57.1
154.5
230.6
30.4
1.6
262.7
1985
Pre-1974
Units
21.8
-
_
17.9
-
39.7
31.8
21.1
6.3
21.8
1.4
19.3
-
69.9
141.5
30.4
1.6
173.5
1974-1976
Units
_
-
-
-
-
4.6
11.5
-
11.4
2.2
-
-
25.1
29.7
-
-
29.7
New
Sources1
_.
-
-
-
-
-
63.5
-
-
66.2
-
_
129.7
129.7
-
-
129.7
Total
21.8
-
_
17.9
-
39.7
36.4
96.1
6.3
33.2
69.8
19.3
-
224. 8
300.9
30.4
1.6
332.9
I
00
to
Placed in service after 1976
2
Total Suspended Partiaulate
Source: Environmental Protection Agency; Sobotka & Co., Inc.
-------
Exhibit III-ll
COVERAGE ASSUMPTIONS FOR COMPLIANCE WITH SCS 90 PERCENT OPTION
FOR COAL UNITS IN 1980 AND 1985
(millions of kilowatts covered to date)
Compliance Problem/Control Strategy
Out of S02 Compliance
Scrubbers
Medium Sulfur Coal
Western Low Sulfur Coal
Washing & Blending
Supplemental Control Systems (SCS)
Subtotal
Out of TSP2 Compliance
Electrostatic Precipitators
Out of Compliance on Both S02 and TSP
Scrubbers
— kw Scrubbed & Precipitators
— kw Precipitators Only
Medium Sulfur Coal
Western Low Sulfur Coal
Washing & Blending
Supplemental Control Systems (SCS)
Subtotal
Total with Pollution
Control Equipment
Already in Compliance
Coal Conversion to Oil
Total
1980
Pre-1974
Units
N7.5
6.4
2.4
8.2
15.2
39.7
31.8
16.0
3.2
12.7
4.1
9.2
24.7
69.9
141.4
30.4
1.6
173.5
1974-1976
Units
-
-
-
-
_
_
4.6
5.9
-
5.2
8.8
-
5.2
25.1
29.7
-
-
29.7
New
Sources1
-
-
-
-
_
_
-
29.1
.
-
30.4
-
_
59.5
59.5
' -
-
59.5
Total
7.5
6.4
2.4
8.2
15.2
39.7
36.4
51.0
3.2
17.9
43.3
9.2
29.9
154.5
230.6
30.4
1.6
262.7
1985
Pre-1974
Units
21.8
-
-
17.9
_
39.7
31.8
21.1
6.3
21.8
1.4
19.3
-
69.9
141.5
30.4
1.6
173.5
1974-1976
Units
-
-
-
-
-
-
4.6
11.5
-
11.4
2.2
-
-
25.1
29,7
-
-
29.7
New
Sources1
-
-
-
-
-
-
-
63.5
-
-
66.2
-
-
129.7
129.7
-
-
129.7
Total
21.8
—
-
17.9
-
39.7
36.4
96.1
6.3
33.2
69.8
19.3
-
224 . 8
300.9
30.4
1.6
332.9
Placed in service after 1976
2
Total Suspended Partioulate
Source: Environmental Protection Agency;- Sobotka
i
00
CO
Co., Inc.
-------
Exhibit III-12
1985 COVERAGE ASSUMPTIONS
FOR WATER EFFLUENT GUIDELINES
(percent of capacity covered)
Type of Capacity
Pre-1974 Units, Retrofitted
• Fossil
• Nuclear
1974-1978 Units, Retrofitted
• Fossil
• Nuclear
1974-1978 Units, Planned
• Fossil
• Nuclear
1979-1985 Units, Planned
• Fossil •
• Nuclear
State Water
Quality
Standards
9.0%
3.8
0
0
1.7
0.5
1.7
0.4
Economic
Reasons1
0
0
0
0
24.5
25
32.5
34.5
Before
316(a)
26%
70
16
50
40
0
56
50
After
316(a)
8%
22
10
25
25
0
35
25
Chemical
61%
70
0
0
56
34
56
34
Entrainment
316(b)
i.4%
14.0
3.5
3.8
0
0
0
0
These eatimatea ore from the 1974 analysis.
Source: EPA estimates collected''f rom Regional EPA offices, February 1976.
00
-------
111-87
Exhibit 111-15
ANNUAL OPERATING COST GROWTH—THERMAL GUIDELINES
(expressed in current dollars)
All Generating Capacity:
Retrofitted Units
$ per kilowatt
% cost escalation
Non-Nuclear Generating
Capacity: New Units
$ per kilowatt
% cost escalation
Nuclear Generating
Capacity: New Units
$ per kilowatt
% cost escalation
1975 1977 1983 1990
$57.46 $72.95 $106.38 $149.69
12.6% 6.5% 5.0%
$57.49 $72.99 $106.44 $149.77
12.6% 6.5% 5.0%
$26; 77 $29.51 $39.54 $55.64
5.0% 5.0% 5.0%
Source: EPA estimates
-------
111-88
Exhibit II1-16
CAPITAL COST GROWTH—1977 CHEMICAL GUIDELINES
(expressed in current dollars)
Non-Nuclear Generating
Capacity: Placed In
Service Prior to 1974
$ per kilowatt
% cost escalation
Non-Nuclear Generating
Capacity: Placed In
Service 1974-1978
$ per kilowatt
% cost escalation
Nuclear Generating
Capacity: Placed In
Service Prior to 1974
$ per kilowatt
% cost escalation
Nuclear Generating
Capacity: Placed In
Service 1974-1978
$ per kilowatt
% cost escalation
1975 1977 1983 1990
$ 2.01 $ 2.24 $ 3.05 $ 4.30
5.7% 5.3% 5.0%
$ 1.52 $ 1.70 $ 2,32 $ 3.26
5.7% 5.3% 5.0%
$ 0.68 $ 0.77 $ 1.05 $ 1.48
5.8% 5.4% 5.4%
$ 0.68 $ 0.77 $ 1.05 $ 1.48
5.8% 5.4% 5.4%
Source: EPA estimates
-------
111-89
Exhibit 111-17
CAPITAL COST GROWTH--1983 CHEMICAL| GUIDELINES1
(expressed in current dollars)
1975 1977 1983 1990
Non-Nuclear Generating
Capacity: Placed In
Service Prior to 1974
$ per kilowatt $ 0.68 $ 0.76 $ 1.04 $ 1.47
% cost escalation — 5.7% 5.3% 5.0%
Non-Nuclear Generating
Capacity: Placed In
Service 1974-1978
$ per kilowatt $ 0.61 $ 0.68 $ 0.93 $ 1.31
% cost escalation — 5.7% 5.3% 5.0%
Non-Nuclear Generating
Capacity: Placed In
Service 1979-1990
$.per kilowatt $ 1.92 $ 2.15 $ 2.93 $ 4.12
% cost escalation ~ 5.7% 5.3% 5.0%
Nuclear Generating
Capacity: Placed In
Service 1979-1990
$ per kilowatt $ 0.57 $ 0.64 $ 0.87 $ 1.23
% cost escalation — 5.8% 5.4% 5.0%
Theee capital expenditures are in addition to those
required to meet the 197? guidelines.
Source: EPA estimates
-------
II1-90
Exhibit 111-18
ANNUAL OPERATING COST GROWTH—1977 CHEMICAL GUIDELINES
(expressed in current dollars)
1975 1977 1983 1990
Non-Nuclear.Generating
Capacity: Placed In
Service Prior to 1974
$ per kilowatt $ 0.63 $ 0.69 $ 0.92 $ 1.30
% cost escalation — 5.0% 5.0% 5.0%
Non-Nuclear Generating
Capacity: Placed in
Service 1974-1978
$ per kilowatt $ 0.29 $ 0.32 $ 0.43 $ 0.61
% cost escalation -- 5.0% 5.0% 5.0%
Nuclear Generating
Capacity: Placed In
Service prior to 1974
$ per kilowatt $ 0.23 $ 0.26 $ 0.34 $ 0.48
% cost escalation — 5.0% 5.0% 5.0%
Nuclear Generating
Capacity: Placed In
Service 1974-1978
$ per kilowatt $ 0.23 $ 0.26 $ 0.34 $ 0.48
% cost escalation — 5.0% 5.0% 5.0%
Source: EPA estimates
-------
111-91
Exhibit 111-19
ANNUAL OPERATING COST GROWTH--1983 CHEMICAL GUIDELINES1
(expressed in current dollars)
Non-Nuclear Generating
Capacity: Placed in
Service Prior to 1974
$ per kilowatt
• % cost escalation
Non-Nuclear Generating
Capacity: Placed in
Service 1974-1978
$ per kilowatt
% cost escalation
'Non-Nuclear Generating
Capacity: Placed in
Service 1979-1990
$ per kilowatt
% cost escalation
Nuclear Generating
Capacity: Placed in
Service 1979-1990
$ per kilowatt
% cost escalation
1975 1977 1983 1990
$ 0.07 $ 0.08 $ 0.10 $ 0.14
5.0% 5.0% 5.0%
$ 0.02 $ 0.03 $ 0.03 $ 0.05
5.0% 5.0% 5.0%
$ 0.29 $ 0.32 $ 0.43 $ 0.60
5.0% 5.0% 5.0%
•
$ 0.23 $ 0.26 $ 0.34 $ 0.48
— 5.0% 5.0% 5.0%
These annual operating expenditures are in addition to
those required to meet the 1977 guidelines.-.
Source: EPA estimates
-------
111-92
Exhibit 111-20
CAPITAL COST GROWTH—COOLING TOWERS FOR ENTRAINMENT GUIDELINES
(expressed in current dollars)
1975
Non-Nuclear Generating
Capacity: Retrofitted
Units
$ per kilowatt $24.10
% cost escalation
Non-Nuclear Generating
Capacity: New Units
$ per kilowatt $24.10
% cost escalation
Nuclear Generating
Capacity: Retrofitted
Units
$ per kilowatt $29.05
% cost escalation
Nuclear Generating
Capacity: New UnitsJ
$ per kilowatt $19.69
% cost escalation
1977 1983 1990
$26.90 $36.67 $51.60
5.7% 5.3% 5.0%
$26.90 $36.67 $51.60
5.7% 5.3% 5.0%
$32.52 $44.59 $62.74
5.8% 5.4% 5.0%
$22.04 $30.22 $42.52
5.8% 5.4% 5.0%
Unite under conetruatlon
Source: EPA Estimates
-------
ECONOMIC AND FINANCIAL IMPACTS OF
FEDERAL AIR AND WATER POLLUTION CONTROLS
ON THE ELECTRIC UTILITY INDUSTRY
VOLUME IV
FINANCING IN CAPITAL MARKETS
1976
-------
VOLUME IV
TABLE OF CONTENTS
Page
List of Exhibits (IV-iii)
Chapter
1 INTRODUCTION AND SUMMARY CONCLUSIONS
CONCERNING ELECTRIC UTILITY
FINANCING
Introduction IV-1
Summary Conclusions IV-2
2 RECENT TRENDS AND CYCLES IN
CORPORATE BUSINESS FINANCING Iv~6
The Need for Corporate Financing IV-7
Corporate Sources of Funds IV-9
Inflation and the Need for
External Funds IV-11
External Funds Raised in
Financial Markets IV-13
The Cyclical Patterns of
External Funds IV-14
The Changing Corporate Balance
Sheet IV-15
Corporate External Funds Within
the Financial System IV-16
Corporate Financing in 1975 IV-18
3 FUTURE PROJECTIONS OF CORPORATE
FINANCIAL NEEDS IV-19
The Determinants of External Financing IV-19
Three Alternative Scenarios for 1975-1985 IV-22
Corporate External Needs in Competition
With Other Sectors of the Economy IV-26
The Supply and Demand for Funds in
Three Alternative Scenarios IV-29
Variations Within a Credit Cycle IV-34
Conclusions IV-34
(IV-i)ou
-------
Chapter
4
ELECTRIC UTILITY INDUSTRY FINANCIAL
RESULTS AND FINANCING, 1960-1975
1960-1965: Growth and Prosperity
1966-1973: Growth Without Prosperity
1974: Financial Nadir?
1975
IV-36
IV-36
IV-40
IV-48
IV-52
PROJECTIONS OF ELECTRIC UTILITY
INDUSTRY FINANCING, 1975-1985
The Industry's Financing Requirements
Investor-Owned Electric Utility Needs
Versus Available Funds and Total
Corporate Needs
Projected Financial Strength of
Investor-Owned Utilities
Concluding Comments
IV-54
IV-54
IV-55
IV-60
IV-66
FINANCING PROBLEMS OF INDIVIDUAL
SYSTEMS
Three Categories of Financial Health
Intercompany Comparisons of Returns
and Interest Coverage
Determinants of Interest Coverage
Ratios
Conclusions Concerning Electric
Utility Financing Problems
IV-68
IV-68
IV-71
IV-75
IV-78
Appendix
IV-A
THE EFFECTS OF ISSUING STOCK AT
DIFFERENT MARKET PRICES RELATIVE
TO BOOK VALUES
IV-121
(IV-ii)
-------
VOLUME IV
LIST OF EXHIBITS
Exhibit
IV-1 Total Uses of Funds and Financing Need by Year;
Domestic Non-Financial Business Corporations,
1960-1974
IV-2 Uses of Funds and Financing Needs in the Five
Credit Cycles; Domestic Non-Financial Business
Corporations
IV-3 Sources of Funds by Year; Domestic Non-Financial
Business Corporations, 1960-1974
IV-4 Sources of Funds in Five Credit Cycles; Domestic
Non-Financial Business Corporations
IV-5 The Cycles of External Funds—Short-Term Debt,
Long-Term Debt, Net Equity Issues; Non-Financial
Business Corporations
IV-6 Levels of Liquid Assets and Debt Outstanding,
as Percent of GNP; Non-Financial Business
Corporations
IV-7 Net Increase in Financial Liabilities by Year;
Major Economic Sectors, 1960-1974
IV-8 Corporate Business Debt Financing as a Percent
of Total Private Sector Debt Financing
IV-9 Projections of Future Sources and Uses of Funds;
Domestic Non-Financial Business Corporations
IV-10 Savings Behavior of U.S. Households
IV-11 Projections of Total Capital Needs by Year;
Domestic Non-Financial Business Corporations,
1975-1985
IV-12 Net Income; Privately Owned Class A&B Electric
Utilities in the United States Electric Department,
1960-1974
IV-13 Earnings and Dividends; Privately Owned Class A&B
Electric Utilities in the United States Electric
Department. 1960-1974
(IV-Ui)
-------
Exhibit
IV-26 Net Financing Electric Utility Industry Vs.
Non-Financial Business Corporations; Privately
Owned Electric Utilities in the United States
Electric and Gas Departments, 1960-1974
IV-27 Gross Equity Financing Electric Utility Industry
Vs. Total Private Sector; Privately Owned Electric
Utilities in the United States Electric and Gas
Departments, 1960-1974
IV-28 Downgrading of Electric Utility Securities, 1965-
July 1974
IV-29 Issue and Recent Market Prices—15 Recent
Electric Utility Bond Issues
IV-30 Projections of External Financing Requirements
for Investor-Owned Electric Utilities, 1975-1985
IV-31 Illustration of Electric Utility and Corporate Net
External Funds Required as Percent of Net Savings
in the Household Sector
IV-32 Interest Coverage Projections Before Pollution
Control Financing For Investor-Owned Electric
Utilities, 1980 and 1985
IV-33 Interest Coverage Implications of Pollution Control
Financing for Investor-Owned Electric Utilities;
With Historical Capital Mix, 1980 and 1985
•\
IV-34 Interest Coverage Implications of Pollution Control
Financing For Investor-Owned Electric Utilities;
With Equity Only, 1980 and 1985
IV-35 Interest Coverage Implications of Pollution Control
Financing For Investor-Owned Electric Utilities; With
Industrial Revenue Bonds at 6.6 Percent, 1980 and 1985
IV-36 Determinants of Interest Coverage Ratios
IV-37 The Impact of AFDC on Interest Coverage Ratios
(IV-v)
-------
Exhibit
IV-14 Assets Per Dollar of Revenue; Privately Owned Class
A&B Electric Utilities in the United States Electric
Department, 1960-1974
IV-15 Annual Capital Expenditures Vs. Total Assets;
Privately Owned Electric Utilities in the United
States Electric and Gas Departments, 1961-1974
IV-16 Sources of Funds; Privately Owned Class A&B
Electric Utilities in the United States Electric
and Gas Departments, 1960-1974
IV-17 Capital Structure; Privately Owned Class A&B
Electric Utilities in the United States Electric
and Gas Departments, 1960-1974
IV-18 Long- and Short-Term Debt; Privately Owned Class
A&B Electric Utilities in the United States
Electric and Gas Departments, 1960-1974
IV-19 Market Value Vs. Book Value and Price/Earnings
Comparisons; Moody's Public Utility Index,
1960-1974
IV-20 External Sources of Funds; Privately Owned Class
A&B Electric Utilities in the United States Elec-
tric and Gas Departments, 1960-1974
IV-21 Yield and Yield Spreads of Aa Utility Bonds,
1960-1975
IV-22 Interest Charge Coverage; Privately Owned Class
A&B Electric Utilities in the United States
Electric Department, 1960-1974
IV-23 Embedded Interest Rate on Long-Term Debt;
Privately Owned Class A&B Utilities in the
United States Electric Department, 1960-1974
IV-24 Allowance for Funds Used During Construction
Vs. Capital Expenditures; Privately Owned Class
A&B Electric Utilities in the United States
Electric Department, 1960-1974
IV-25 Electric Utility New Plant and Equipment
Expenditures Vs. All Industry Plant and Equipment
Expenditures; Privately Owned Electric Utilities
in the United States, 1960-1974
(IV-iv)
-------
Exhibit
IV-26 Net Financing Electric Utility Industry Vs.
Non-Financial Business Corporations; Privately
Owned Electric Utilities in the United States
Electric and Gas Departments, 1960-1974
IV-27 Gross Equity Financing Electric Utility Industry
Vs. Total Private Sector; Privately Owned Electric
Utilities in the United States Electric and Gas
Departments, 1960-1974
IV-28 Downgrading of Electric Utility Securities, 1965-
July 1974
IV-29 Issue and Recent Market Prices—15 Recent
Electric Utility Bond Issues
IV-30 Projections of External Financing Requirements
for Investor-Owned Electric Utilities, 1975-1985
IV-31 Illustration of Electric Utility and Corporate Net
External Funds Required as Percent of Net Savings
in the Household Sector
IV-32 Interest Coverage Projections Before Pollution
Control Financing For Investor-Owned Electric
Utilities, 1980 and 1985
IV-33 Interest Coverage Implications of Pollution Control
Financing for Investor-Owned Electric Utilities;
With Historical Capital Mix, 1980 and 1985
IV-34 Interest Coverage Implications of Pollution Control
Financing For Investor-Owned Electric Utilities;
With Equity Only, 1980 and 1985
IV-35 Interest Coverage Implications of Pollution Control
Financing For Investor-Owned Electric Utilities; With
Industrial Revenue Bonds at 6.6 Percent, 1980 and 1985
IV-36 Determinants of Interest Coverage Ratios
IV-37 The Impact of AFDC on Interest Coverage Ratios
(rv-v)
-------
IV-I
CHAPTER 1
INTRODUCTION AND SUMMARY CONCLUSIONS
CONCERNING ELECTRIC UTILITY FINANCING
INTRODUCTION
Volumes II and III of this report have discussed the
electric utility industry's future in terms of demand, capacity,
capital expenditures, generation, revenues, operating and
maintenance expenses, etc. under the assumption that the ex-
ternal financing needs consistent with all these other pro-
jections can, in fact, be met. This volume addresses itself
to the validity of that assumption.
Because the electric utility industry's ease of
access to external financing is in part determined by the
industry's own financial strength and in part by overall
capital market conditions, the analysis in this volume com-
prises historical reviews and projections both of total non-
financial corporate financing needs vis-a-vis total U.S.
sources and uses of funds and of total electric utility
financing needs vis-a-vis other non-financial corporations
and total sources and uses of funds. Chapter 2 presents a
discussion of recent trends and cycles in total corporate
financing. Chapter 3 discusses possible future trends in
total corporate financing, in the funds required to finance
governmental and housing expenditures, and in household
savings. Chapter 4 reviews the electric utility industry's
TBS was assisted by Professor Jay Light of the Harvard Business School
in the capital market analysis of this vol-ume and has drawn heavily on
data developed by him for a forthcoming book. Capital Markets.
-------
IV-2
financing history. Chapter 5 then examines the industry's
probable future needs, both before and after consideration
of the requirements associated with federal pollution control
regulations, in the context of total capital market conditions.
Financial projections for the electric utility in-
dustry as a whole tend to obscure variations in the financial
strength and access to financing of firms within the industry.
Chapter 6 discusses these differences among firms and suggests
methods for alleviating the difficulties of the weaker firms
in the industry.
The emphasis in this volume is on investor-owned
firms. The financing needs of public companies are noted
briefly, but are not discussed in detail because of the variety
of entities and patterns of financing involved. Because many
of the public firms depend directly on governmental funding
or on indirect governmental guarantees, their access to
funds is in most instances relatively assured, provided the
governmental unit in charge gives its approval to the fi-
nancing. Thus, most public firms are unlikely to be "crowded
out" in the competition for funds in the capital market be-
cause of weak credit ratings. And, their financing is perhaps
best viewed as part of the financing of the government sector.
SUMMARY CONCLUSIONS
As is discussed in Chapter 5, it is quite probable
that the electric utility industry's future financing needs
will be significantly above historical levels relative to
other corporate financing and to total U.S. sources and uses
of funds. Assuming that household savings in the future
continue to be at their historical average of 6 percent
and assuming that the real growth rate in GNP is 3.5 percent,
-------
IV-3
the industry's future net external financing needs will in-
crease from an historical high of 11.5 percent of household net
savings in the 1970-1974 credit cycle to a level of 12. 5 percent
in the 1975-1985 period even before consideration of pollution
control expenditures. Pollution control financing is pro-
jected to raise the industry's requirements to 14 percent
of net household savings. The foregoing projections presume
a return on equity of 14 percent, a level well above the
level of 11 percent characteristic of recent years. The
'industry's external financing needs would be slightly higher,
and its difficulties in raising these external needs sub-
stantially higher, if returns remain at only 11 percent.
As is discussed in Chapter 3, the productive capac-
ity and energy shortages of 1973 and 1974 have caused some
observers to predict that the electric utilities' financing
will take place in the context of very tight overall capital
market conditions. In these projections, the financing needs
of all non-financial corporations may be as high as 83 percent
of net household savings. If total corporate financing needs
are as high as envisioned in this scenario, it is clear that
utilities will be competing for record levels of funds in
extraordinarily tight capital markets. However, it is within
the power of state regulatory commissions to grant price in-
creases sufficient to enable utilities to "crowd out" many
weaker corporate borrowers. And, the extremely high levels
of total corporate financing needs envisioned in this scenario
will occur with only low probability.
A more likely projection of total corporate financing
needs is that non-financial corporations will require funds
equal to about 63 percent of net household savings. This 63
percent corporate share of net household savings compares with
a 65 percent share in the last credit cycle and a 58 percent
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IV-4
share in the 1967-1970 credit cycle. While this level of
total corporate financing implies relatively tight capital
market conditions, a modest increase in the current financial
health of the electric utility industry should enable it to
compete successfully for the amounts of funds required in the
1975-1985 period.
If total non-financial corporate demand for financing
is lower than the levels of the most recent credit cycle, as
is likely, the future of capital market conditions will be
relatively easy. If so, however, the electric utility indus-
try's share of total corporate financing will be enormous.
Before consideration of pollution control financing, the
industry's needs would rise to 32 percent of the corporate
sector's total. With pollution control financing, the indus-
try's share would rise to 36 percent. Such shares are possible,
but only if utilities have very strong financial statistics.
Unless regulators allow returns on common equity and interest
coverage ratios that allow the electric utility industry to
regain its status.of the 1960s as a low-risk industry,
investors may be very unwilling to commit such a high percentage
of their corporate investment portfolio to the industry.
As is argued in Chapter 6, even if adequate sources
of funds are available for the industry as a whole and even
if the industry's financial strength is, on average, adequate
to enable it to compete effectively for these funds, some
firms may still have difficulty in finding capital. The
industry average ratios have historically been the aggregate
of individual company ratios that vary widely. Thus, if
the industry's average rate of return on equity is just at
or is below the rate of return demanded by investors, a number
of firms would have returns on equity and interest coverage
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IV-5
ratios that would severely hamper their access to external
financing. In fact, some firms are currently unable to finance
desired basic capacity additions and thus can expend funds for
pollution control equipment only by further cuts in their base-
line needs.
Some individual electric utilities may be able to
improve their financial health by further improvements in effi-
ciency and by reductions in service, but the resolution of the
financing difficulties faced currently by a number of utilities
is perhaps more in the hands of regulators. Even if a company,
is able to reduce its operation and maintenance expenses or its
capital investment costs, an improvement in its financial health
requires that the company be allowed to retain some portion of
these savings. Pollution control revenue bonds and reductions in
debt ratios have been advanced as solutions for the financing
problems facing some companies, but TBS's judgment is that neither
will substantially alleviate these companies' financing diffi-
culties. While these alternatives may improve interest coverage,
the first alternative will not help and the second alternative
may hurt these companies' efforts to issue common stock at
reasonable prices. Thus, the basic requirement for returning
ailing companies to financial health is an increase in revenues,
which is within the power of regulatory commissions.
In many instances, the price increase required to restore
individual companies to financial health is simply the relatively
small increase required to bring returns on equity to levels de-
manded in the marketplace by investors. In some instances, however,
the increases may take a form different from those associated with
providing an adequate return on equity. The increases may, for
example, result from a conversion from flow-through accounting
to normalized accounting or from the inclusion of construction
work in progress in a utility's rate base.
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IV-6
CHAPTER 2
RECENT TRENDS AND CYCLES
IN CORPORATE BUSINESS FINANCING
Electric utility financing in recent years has
taken place as part of a rapid increase in financing
needs throughout the1corporate sector. In the late 1960s
and early 1970s, corporate demands for external funds be-
came the largest and fastest growing element of financial
needs throughout the economy. Indeed, in the credit crun-
ches of 1966, 1969-1970, and 1973-1974, these needs became
so large that they created strains throughout financial
markets and "crowded out" other potential borrowers. By 1975,
an increasing recognition of the importance of these growing
and cyclical corporate financial needs was reflected in a
number of projections of future financial markets. Despite
very modest external corporate needs in 1975, a number of
financial forecasters remained concerned about the possibility
of a future "capital shortage" caused in part by the external
financing needs of corporations.
In order to gain insight into future total corporate
external financing needs and capital market conditions, and
thus into future conditions affecting the electric utility
industry, this chapter contains an analytical review of
recent trends in total non-financial corporate financing.
In addition, in order to show their importance within the
overall financial system, these corporate financial needs
will be compared with the financing of other economic sectors.
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IV-7
THE NEED FOR CORPORATE FINANCING
In order to evaluate the underlying demand for
funds in the corporate sector, TBS has focused on the non-
financial corporate business sector as defined in Flow of
Funds Accounts, published by the Federal Reserve Board (FRB).
(This sector includes only domestic non-financial business
corporations, and excludes financial corporations, whose
demands for funds are derived from the financing needs of oth-
ers and whose inclusion would therefore "double-count" some
financing.) Exhibit IV-1, derived from the FRB Flow of Funds
data, displays the total uses of funds, and therefore the
total funds needs, of non-financial business corporations
over the previous 15 years. These total financing needs
have grown from $44 billion in 1960 to $163 billion in 1974.
Total corporate financing needs comprise two
major components:
The need for additional real assets (plant
and equipment, residential construction,
and inventory); and
The need for increased financial assets
(liquid assets, accounts receivable, etc.)
In addition, about 10 percent of the total uses of funds
cannot be categorized due to data deficiencies, and these
are included in the item "discrepancy." As shown by
Exhibit IV-1, new plant and equipment generally accounted
for from 65 to 80 percent of non-financial business cor-
porations' total financing needs in the last 15 years and
is consequently the dominant component of these needs.
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IV-8
Interpretations of the raw data of Exhibit IV-1
are complicated by two factors. First, while the number of
uses of funds has been increasing rapidly, this growth could
simply be due to the overall economic growth and inflation
of recent years. Second, there are apparent cyclical
swings in these and other financial data which may obscure
and confuse the underlying secular trends.
In order to clarify the information as far as
possible, the last two decades have been divided into five
non-overlapping credit cycles which correspond generally
to the economic cycles of recent years: the final two cycles
of the 1950s, the credit cycle of the early 1960s which
culminated in the credit crunch of 1966, the credit cycle
(some would say "mini-cycle") of the late 1960s, and the
credit cycle of 1970-1974 which culminated in the credit
crunch of 1973-1974 . Within each of these credit cycles,
the various corporate uses of funds will be shown as a
percent of gross national product (GNP) to normalize them
in respect to the prevailing size of the economic and financial
system. Most of the data which follow will be displayed
in the same manner, to provide some insights into secular
changes within the last two decades.
More precisely, the cycles are each composed of a series of consecutive
calendar quarters as follows: 1954:3 through 1958:1^ 1958:2 through
1960:4; 1961:1 through 1967:1; 1967:2 through 1970:5; and 1970:4
through 1974:4.
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IV-9
Utilizing these definitions of credit cycles,
Exhibit IV-2 documents the secular trends in corporate finan-
cing needs in connection with GNP over the last two decades.
"Total Financing Needs," the total of all the separate uses of
funds, increases in a relatively steady pattern over these
cycles. The most important source of this increase is plant
and equipment investment, but inventories and net financial
assets also contribute to the secular trend.
CORPORATE SOURCES OF FUNDS
The total financing needs of corporations must
be met from one of two principal sources: internally -generated
o
funds, composed of adjusted retained earnings and deprecia-
tion, or externally raised funds. Exhibit IV-3 shows how
the total financing needs of corporations have been funded
over the last 15 years. Although internally generated funds
gradually have grown from $34.4 billion in 1960 to $81.5 billion
in 1974, as a percentage of total financing needs, they de-
clined from 78 percent in 1960 to only 50 percent in 1974.
Exhibit IV-4 shows these same sources of funds as a per-
centage of GNP over the five credit cycles defined above.
Exhibits IV-3 and IV-4 document what has probably
been the most important recent trend in financial'markets:
the increasing need for external funds to fill the "gap"
between total financing: needs and internally generated
2
Adjusted retained earnings (or adjusted retained profits) are
retained earnings adjusted for inventory valuation profits which
provide no cash flow. See the definitions accompanying Exhibit IV-3
for further explanation.
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IV-10
funds. More precisely, from the first to the third credit
cycle, industry's total financing needs grew substantially,
but they were accompanied by an almost equal expansion of
internally generated funds, which made the external funds
raised in financial markets relatively stable•. Conversely,
from credit cycle 3 to credit cycle 5 total financing needs
continued to increase, but internally generated funds
shrank as a percent of GNP. This resulted in the external
funds raised by non-financial corporations expanding rapidly
from 2.7 percent to 5.1 percent, almost doubling as a per-
cent of GNP. And, of course, the external funds measured
in absolute dollars expanded even more rapidly, as is shown
in Exhibit IV-3.
In addition to external funds raised, it is
useful to have a measure of the net extent to which cor-
porations have demanded funds from the financial system.
While the external funds raised in financial markets with-
drew funds from the financial system, the increase in liquid
financial assets on corporate balance sheets has served as
an offsetting supply of funds. In Exhibit IV-4 this net
measure of corporate financial demands, "net external funds
required," is computed for each past credit cycle. As
shown in Exhibit IV-4, net external funds have also expanded
rapidly, from an average of 2.4 percent of GNP in credit cycle
1 to 4.3 percent of GNP in credit cycle 5.
In brief, these external needs have been the
cause of recent concern about the ability of the U.S. fin-
ancial markets to accommodate needed corporate financing.
Through the last several cycles of expanding investment
needs, the internally-generated funds of corporations
have declined, opening up a severe cash flow "gap" which
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IV-11
could only be filled by external funds. Or, to interpret
the facts somewhat differently, in a time when corporations
have found it increasingly difficult to generate internal
funds, they have nonetheless maintained and even expanded
their rate of investment and then have funded this invest-
ment through external financing, primarily borrowing.
INFLATION AND THE NEED FOR
EXTERNAL FUNDS
One of the most important factors leading to the
external funds requirements of recent cycles has been the ac-
celerating pace of inflation. Inflation affects the opera-
tional financial needs of corporations in several ways.
Inflation (1) raises the current or nominal cost of any new
plant and equipment, inventory, or financial asset expansion
needed to support real growth; (2) raises the cost of replac-
ing the inventories and the plant and equipment that are con-
sumed in the production process; and (3) increases the dollar
amount of financial assets required to maintain a given volume
of real business activity. Consequently, inflation leads to
an expanded need for funds. Inflation has caused much of the
increase in the ratio of total financial needs to GNP shown
in Exhibit IV-2.
Inflation also affects the capacity of firms to
generate funds internally. Inflation leads to higher wage
rates, higher unit labor costs, and increased production
costs. Expectations of inflation affect interest rates and
the level of interest payments.
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IV-12
The corporate income tax system is another major
force through which inflation affects businesses' internal
funds. When computing income for tax purposes, corporations
are allowed to charge depreciation only on the basis of his-
toric cost. As a result, taxable income is overstated in
connection with the cash flows that can be invested in net
new assets by the difference between depreciation based on
historic costs and depreciation based on replacement costs.
Similarly, the interaction of the corporate tax system and
inflation can also produce an unnecessary cash outflow in the
form of higher taxes when inflationary price increases lead
business firms to replace inventories at higher price levels.
Essentially, firms have paid taxes upon inventory profits
which were not available for net new investment.
As illustrated in Exhibits IV-3 and IV-4, total
financing needs increased during the inflationary period
of 1971-1974. However, even though business prices rose
substantially, internal funds did not grow commensurately.
The inflation resulted in wage and salary payments taking a
larger share of th6 total revenues generated by corporations.
An increased outflow of tax payments in connection with the
replacement cost of plant and equipment inventories reduced
internal funds as well.
During inflationary periods there have often been
enormous political pressures to hold down prices. These
pressures can take the form of "jaw-boning" from public
officials, or, as in recent periods, direct controls. Further-
more, in recent years, corporations have found it difficult
to raise prices because of reduced consumer demand. For these
reasons, corporations recently have been unable to maintain
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IV-13
their internally generated funds in inflationary periods,
and increasingly have turned to external sources of funds.
EXTERNAL FUNDS RAISED IN
FINANCIAL MARKETS
External funds can be raised in financial markets
in the form of increased short-term debt, increased long-
term debt, or new equity issues. The principal source of
short-term debt for corporations has been the commercial
banking system. To some extent, large corporations with
prime credit ratings can supplement this use of bank debt
with their own short-term promissory notes, called commer-
cial paper. Some corporations use other sources of short-
term debt such as finance company loans. A special component
of short-term debt, usually called the profit "tax liability,
3
arises through the normal process of paying taxes. Taken
together, however, the profit tax liability, commercial
paper, finance company loans, and other miscellaneous loans
form only a small portion of corporate debt. Recently, bank
debt has dominated the total sources of short-term funds.
Since profit taxes are not paid in cash exactly as they are accrued,
corporations have a short-term liability to the government—profit
taxes payable—at the end of any quarter or year. In times when
profits and taxes are rising, the size of this liability also rises,
providing a form of short-term financing to corporations. In the
1950s, when there was a significant lag in the processing of tax
collections, this short-term liability sometimes was a significant
portion of total short-term finance. Recently, however, as the
schedule of tax collections has accelerated, the profit tax liability
haa become relatively unimportant.
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IV-14
In addition, commercial banks have often made
term loans to corporate business. Over one-third of all
bank loans in recent years have been term loans. These
term loans generally are considered to be intermediate-term
finance, longer than one year (the arbitrary breakpoint for
most definitions of short-term debt) yet shorter than the
typical 15- to 30-year maturities of "long-term debt."
However, because of definition problems and corresponding
deficiencies in the data, all bank loans are included in the
"short-term debt" category in the analysis of this volume.
THE CYCLICAL PATTERNS OF
EXTERNAL FUNDS
This discussion has concentrated thus far
on the secular trends in external financial needs within
the corporate sector, by averaging the observed flows-of-
funds across credit cycles. Within each cycle, however,
there are marked variations in financing activity caused
by the cycles in inventory accumulation and, to a lesser
extent, by plant and equipment spending. Toward the middle
or end of each credit cycle, corporate external funds require-
ments have reached their cyclical peak.
Exhibit IV-5 displays the changing patterns of cor-
porate external funds. In addition to the cyclical nature in
the total of these new funds, there appears to be a cyclical
pattern in their composition. In the early phases of each
credit cycle, long-term sources of funds (particularly
long-term debt) are the principal sources of new funds. To-
wards the middle of each credit cycle, as total new funds
-------
IV-15
are usually accelerating rapidly, a shift occurs away from
a primary reliance upon long-term debt and toward short-
term debt. Toward the end of each credit cycle, in the
economic recession or slow-down, long-term debt resumes
its role as the principal source of external funds.
This typical pattern is evident in the data for
the most recent credit cycle. In 1971 and early 1972, long-.
term capital, particularly long-term debt and net new equity
issues, provided over $41 billion, or about 85 percent of
the new external funds of corporations. In the face of rising
needs in 1973, however, these sources both decreased. By
early 1974, historically large quantities of short-term debt,
over $45.3 billion, had become the mainstay of corporate ex-
ternal financing. Most of this finance was provided through
the commercial banking system, and the size of banks grew
rapidly in this period to accommodate these short-term needs;
however, by the final quarter of 1974 and throughout 1975,
this short-term debt decreased sharply and was replaced once
again by the rapidly growing contribution of long-term funds.
THE CHANGING CORPORATE
BALANCE SHEET
Recently, there have been several important
secular trends in corporate balance sheet ratios: increas-
ing levels of debt in connection with equity, a changing
ratio of short-term debt to long-term debt, and de-
creasing relative levels of liquid asset balances. (Exhibit
IV-6 illustrates the changing levels of debt and liquid assets
as a percent of GNP.) These trends have contributed to a
-------
IV-16
more debt-heavy, and perhaps more fragile, corporate financial
structure.
The limits to these financial trends are not
obvious. On the one hand, corporations in some other coun-
tries have continually operated with debt ratios that are
high by U.S. standards. A comparison with other countries
would suggest the U.S. corporations should have relatively
little to fear from their new financial structures. On the
other hand, some observers recently have suggested that the
corporate sector should not, and indeed will not, increase
its debt financing beyond the levels reached in the mid-1970s.
CORPORATE EXTERNAL FUNDS
WITHIN THE FINANCIAL SYSTEM
Business corporations are only one of the seekers
of funds in the financial markets. The other important
demands come from households (for both home mortgages and
consumer credit) and from governments. The recent patterns
of these other credit demands as compared to corporate
demands are shown in Exhibit IV-7. The dominant conclusion
that emerges from these data is that both corporate external
financing and the borrowing of other sectors rose during
this period. The combination of inflation, fiscal and
mpnetary policies of government, and financing and saving
decisions of various private sectors gave rise to a total
expansion of financial assets and liabilities (credit).
The frequently described rise in corporate external funds
was the dominant factor in this expansion, increasing from
$10 billion in 1960 to $81.5 billion in 1974. It was
accompanied by smaller increases from other sectors. As a
-------
IV-17
result, corporate business liabilities grew from 34 percent
of the total in 1960 to 54 percent of the total in 1974.
The total financing of all sectors is limited by
the rate of growth of total credit, which is determined partly
by the financial decisions of savers and partly by the de-
cisions of the Federal Reserve Board. The various credit
seekers must compete for a limited supply of financing.
Business.corporations appear to be relatively effective
competitors for funds because of their insensitivity to
interest costs. Households appear to be the economic sec-
tor most likely to be "crowded out" during a credit crunch
because of their relative sensitivity to interest costs.
This process is illustrated in Exhibit IV-8, which records
corporate debt financing as a percent of all private sector
debt financing. Corporations have been taking a secularly
increasing percentage of the total financing available to
the private sector. In a credit crunch, when the Federal
Reserve restricted the overall growth of credit but cor-
porate external needs were still large, these percentages
were particularly high.
In 1966-1967, 1970, and 1973-1974, the corporate
sector obtained about 60 percent of the available financing
($62 billion in 1973 and $77.5 billion in 1974) and the
borrowing of households was curtailed severely. Faced with
the high interest costs of these periods, households decided
to reduce their rate of borrowing. This "crowding out" of
households has had important implications for economic
activity. It probably was the primary cause of the great
cycles in new home construction in these periods. While
there is some disagreement as to the reasons involved in
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IV-18
this "crowding out" of home mortgage and other household
borrowings, there is agreement that it has in fact occurred
during each of our recent credit crunches. It is generally
believed that the potential borrowing of small businesses,
larger financially weak businesses, and state and local
governments is also influenced by interest costs, and is
likely to be curtailed during times of tight credit. If the
external financial needs of corporations, particularly large
credit-worthy corporations, grow, the likelihood is that
there will be less financing available for the more interest-
sensitive borrowers: households, small businesses, state
and local government, and large but financially weak corpora-
tions.
CORPORATE FINANCING IN 1975
The severe recession of 1975 resulted in some
major changes in the pattern of corporate financing. Plant
and equipment spending eased somewhat and there was a
massive inventory liquidation. These events combined to
reduce the total financial needs of corporations, while
internally generated funds fell only slightly. The result
was a substantial reduction in the external funds required
raised by non-financial corporations in the first half of
1975, declining in that period to about 1.8 percent of GNP.
Compared with the recent levels of 5 and 6 percent of GNP
shown in Exhibit IV-5, this is a dramatic reduction. Further-
more, liquid asset balances were increased and short-term
debt was drastically reduced by the massive new issues of
long-term debt in 1975. These changes are not particularly
surprising, however, given the recession and especially the
rate of inventory liquidation accompanying the recession of
the last two years.
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IV-19
CHAPTER 3
FUTURE PROJECTIONS OF CORPORATE FINANCIAL NEEDS
As documented in Chapter 2, there has been very
rapid growth in the net external funds required by non-financial
corporations over the last three credit cycles, that is, the
last 15 years. And, these external funds requirements have
at times placed considerable strain on the U.S. financial
markets. Thus, an important factor in judging the ability of
the electric utility industry to meet its future financing
needs is the future external financing needs of other non-
financial corporations. This chapter describes and analyzes
three possible patterns of corporate investment and external
financing requirements through 1985.
THE DETERMINANTS OF EXTERNAL FINANCING
In 1975, the external financing needs of corporations
plummeted, but many observers still expect a future "capital
shortage," caused largely by the investment plans of corpora-
tions. The major projected investment need is to expand
productive capacity. In recent years, the U.S. economy ex-
perienced severe shortages of many economic goods, as installed
productive capacity was insufficient to meet the demands of
the economy, particularly in the basic materials industries
(metals, chemicals, paper, etc.).
The cause of the shortages in the basic materials
industries is complex. First, capacity additions in several
of these industries were modest throughout the 1960s, partic-
ularly in comparison with several earlier periods. Second,
the worldwide economic boom of 1972-1973 contributed to
worldwide shortages in many basic materials. Third, the
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IV-20
devaluation of the dollar made U.S. materials more attractive
on a price basis and thus contributed to U.S. capacity prob-
lems. The high resultant operating ratios in the basic
materials industries during 1973 led many observers to con-
clude that substantial additions to plant capacity will be
required to reduce the threat (or capitalize on the opportunity)
of future demand and supply imbalances and to attenuate wide
price fluctuations in the basic materials industries.
In addition to the basic materials industries, energy
production and conservation may entail major new investment.
The investment in energy production will comprise expenditures
both for oil exploration and for the development of alterna-
tive energy sources. Energy conservation will involve in-
vestments in mass transportation facilities, more efficient
industrial processes and equipment, better insulation, etc.
Furthermore, pollution control expenditures will
increase the plant and equipment spending in a number of key
industries. These expenditures include investments to achieve
compliance for existing capacity or to replace old capacity
that cannot economically be brought into compliance. Moreover,
the effective per unit cost of new plant and equipment addi-
tions will be increased by those requirements.
In view of the possible capacity additions within the
basic materials industries, the possible need for high levels
of investment in energy-producing and energy-consuming indus-
tries, and stricter pollution control requirements, the total
U.S. investment in plant and equipment could be considerable
in coming years. Financing this increased plant and equipment
investment could be a major challenge for the U.S. financial
system in the coming decade.:
-------
IV-21
On the other hand, despite these widely circulated
predictions of increased investment needs, it is not at all
clear that the expected plant and equipment spending will
actually materialize. The economy is just now recovering
from the severe recession of 1974-1975 and capacity utiliza-
tion rates within most industries are very low by historical
standards. Thus, in a broad range of domestic industries,
there is certainly no current shortage of capacity. In
1975, real plant and equipment spending declined, reflecting
the reduced incentives for capacity expansion. Moreover,
the attitudes of many corporate managers towards the trade-off
between growth and profitability may be changing subtly. The
great external financial needs of the early 1970s resulted
from corporate decisions to continue investing in new real
assets, even though the cash returns from existing assets
were severely depressed by historical standards. This was
the basic cause of the large external financing needs in
recent credit cycles.
With the memory of these years still fresh, many
managers may choose to alter their objectives and plans with
respect to expansion. Before embarking on new plant and
equipment expansion plans, they may first require an enlarged
cash flow and profit stream from existing assets, so that the
expansions can be financed in large part through internal
funds. If the internal funds cannot be generated, they may
just scale back their investment in new capacity until the
profits do recover. If, as current readings would suggest,
corporate attitudes and decisions have changed in this way,
they could have important ramifications for both future
investment rates and external financial needs.
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IV-22
THREE ALTERNATIVE SCENARIOS FOR 1975-1985
The current economic and financial cross-currents
make it difficult to estimate the 1975-1985 external financing
requirements of corporations with any confidence or certainty.
On the one hand, the investment needs apparently required
to satisfy both private and public goals seem large. On the
other hand, current capacity utilization figures suggest a
much less immediate need. Additionally, there is a growing
skepticism about private industry's willingness or ability
to undertake this investment without a resurgence in internal
cash flow. The two key related uncertainties are:
• To what extent will corporations undertake
massive new plant and equipment spending?
• To what extent can whatever investment is
undertaken be financed internally, by the
cash available from retained earnings?
Rather than choose one particular point estimate
for each of the key uncertainties, we shall specify a set of
three possible scenarios which bracket the range of probable
outcomes. The three alternative scenarios are described
briefly below.
Scenario 1 is called the High Investment, Depressed
Internal Funds Scenario. In this scenario, it is assumed that
plant and equipment spending will climb to historically high
levels, in order to satisfy many of the needs and requirements
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IV-23
described above. It is also assumed that the recent diffi-
culties of corporations in realizing returns on their existing
assets will continue, so that retained earnings and internal
cash flows will remain depressed. This scenario presumes the
trends of the last several credit cycles toward expanding
corporate financial needs and contracting internally generated
funds will continue. This scenario is perhaps most consistent
with a future economy that is expanding rather rapidly and
that is beset with continuing inflation and depressed corporate
profits.
Scenario 2 is the High Investment, Moderate Internal
Funds Scenario. In this scenario, it is again assumed that
plant and equipment spending will climb to the same histor-
ically high levels assumed in Scenario 1, in order to satisfy
many of the needs and requirements described above. But
it is also assumed that corporate retained earnings and inter-
nal funds will expand, rebounding to the same average frac-
tion of GNP they attained in the 1950s and early 1960s.
Thus, a substantial faction of corporate investment will be
financed internally. This scenario is most consistent with
a future economy that is expanding, perhaps rapidly, but
without the intense inflationary pressure of recent years.
Thus corporations will be able to increase and maintain profit
margins.
In particular, it is assumed that corporate plant and equipment spending
olimbs to 8.8 percent of GNP, averaged over the next credit cycle. This
is a full 1 percent of GNP higher than the experience of the most recent
credit cycles. Thus, relative to the past, plant and equipment spending
is assumed to expand considerably. While it is expressed in somewhat
different terms, this assumed plant and equipment spending is approxi-
mately consistent with the assumptions of several other recent studies.
See, for example: Bosworth, Duesenberry, and Carron, Capital Needs in
the Seventies, Washington: Brookings, 1974; and New York Stock Exchange,
The Need for Equity Capital, February, 1975.
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IV-24
Scenario 3 is the Moderate Investment, Moderate Funds
Scenario. For this scenario it is assumed that plant and
equipment spending declines somewhat from recent levels to a
new level similar to that of the 1950s and early 1960s, Within
this moderately declining total, several categories of capital
spending will undoubtedly continue to increase, specifically
energy-related investment, pollution control expenditures,
and capacity additions within some of the basic materials
industries. Most other capital spending will decrease,
however. As in Scenario 2, it is assumed that corporate
retained earnings and internal funds will rebound to the
average levels they attained in the 1950s and early 1960s.
Therefore, an increasing supply of funds is generated inter-
nally to finance what turns out to be only a moderate rate
of investment, and external funds requirements are reduced.
This scenario is most consistent with a future economy
which is expanding at a slow or moderate rate with lower
inflationary pressures, and in which corporate managers
expand their productive capacity only after they have in-
creased their returns from existing capacity.
As suggested in the brief scenario descriptions
above, plant and equipment spending and adjusted retained
earnings are the key variables for which assumptions have been
made. The other sources and uses of funds have been chosen
to be consistent with past levels, but are adjusted as neces-
sary to be compatible with the assumed conditions in the sce-
narios. Specifically, corporate investment in residential
construction, financial assets, and the discrepancies between them
are equal in all three scenarios, and consistent with earlier
credit cycles. Depreciation and inventories are higher in
the high investment scenarios, to reflect the effects of the
bulge in plant and equipment spending on economic activity,
and, later, depreciation. The detailed assumptions are
. shown in Exhibit IV-9.
-------
IV-25
The table below summarizes the sources and uses
of funds for non-financial business corporations which are
likely to occur in Scenarios 1, 2, and 3. All 'estimates
are shown as a percentage of GNP averaged over a prospective
credit cycle.
COMPARISON OF THREE ALTERNATIVE SCENARIOS
WITH FIVE PREVIOUS CREDIT CYCLES
Credit Cycle 1
1954:3 to 1958
Credit Cycle 2
1958:2 to 1960
Credit Cycle 3
1960:1 to 1967
Credit Cycle 4
1967:2 to 1970
Credit Cycle 5
1970:4 to 1974
Scenario 1
Scenario 2
Scenario 3
(percent of
Plant & Equipment
Spending
:1 6.9
:4 6.5
:1 7.0
:3 7.8
:4 7.7
8.8
8.8
7.2
GNP)
Adjusted Retained
Earnings
2.5
2.2
2.6
1.6
1.0
1.3
2.5
2.5
Net External
Funds Required
2.4
2.1
2.5
3.2
4.3
5.0
3.8
2.4
As the final column in the table above and the
bottom row in Exhibit IV-9 indicate, there is a wide
range of possible net external funds requirements across
the three scenarios. In Scenario 1, the high investment,
depressed retained earnings scenario, the net external funds
required increase to a new high of 5.0 percent of GNP, a
figure larger than in the 1970-1974 credit cycle and substan-
tially larger than in earlier cycles. In Scenario 2, where
profits are assumed to be higher than in 1, the net external
funds requirements are 3.8 percent of GNP, somewhat lower
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IV-26
than in the most recent credit cycle, but still high by his-
torical standards. Finally, in Scenario 3, where investment
is assumed to be lower than in 2, the net external funds
required drop to 2.4 percent of GNP, substantially less than
in recent years, and roughly comparable to requirements in
the three earlier credit cycles.
These net external funds required are a measure
of the extent to which non-financial corporations will have
to rely upon financial institutions and markets for funding;
and, therefore, they are a measure of the pressure corporations
will exert on financial markets. One interpretation of these
results suggests that if the rather high investment rates
anticipated by many economists and reflected in Scenarios 1
and 2 actually occur, then corporations will exert considerable
pressure on the capital markets. If corporate internal sources
of funds remain depressed, then this pressure will be very
high in comparison with all recent experience. Moreover, even
if internal sources recover, the corporate demand for funds
will still be quite high, surpassed only by the levels of
1970-1974. Only if high rates of investment do not occur and
internal funds recover (as in Scenario 3) will the pressure
of corporate net external funds requirements slip back to the
levels of earlier years.
Exhibit IV-11 translates the estimates of financing
needs in all three scenarios - from a percentage of GNP to yearly
dollar estimates. These figures will be compared directly
with electric utility financing requirements in Chapter 5.
CORPORATE EXTERNAL NEEDS IN COMPETITION
WITH OTHER SECTORS OF THE ECONOMY
The external financial needs of corporations are
only one of several important financial needs in the economy.
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IV-27
In addition, the capital projects of state and local govern-
ments are often financed through "municipal" borrowing.
Furthermore, when the federal government experiences a budget
deficit, it is financed through federal borrowing. Finally,
the household sector borrows in the form of both home mort-
gages and consumer credit. These various demands must com-
pete for the net supply of funds, most of which are provided
through financial assets acquired by the household sector.
Because the household sector is the source of most
of the supply drawn on by other economic sectors, the analy-
sis in this section will focus upon the "net financial invest-
ment" of the household sector, where the net financial invest-
ment of households is defined as the net increase in financial
assets (the total supply of financing) minus the net increase
in household borrowing. By subtracting household borrowing,
the analysis excludes amounts which some households supply
to other households. Thus, the focus is on the net financing
provided by households as a sector to all other economic
sectors. For all practical purposes, then, the net financial
demands for funds of the corporate and government sectors
must be financed through the supply of funds provided by
the net financial investment of households.
There are several minor problems with the closed
financial system suggested above. First of all, there are
a number of minor economic sectors excluded from the analysis,
specifically non-corporate businesses and farms. Fortunately,
these sectors are small enough that their omission should
cause no real problems. Secondly, the corporate sector,
state and local governments, or the federal, government actually
could have negative net external financial needs; that is,
they could on balance retire more debt than they raise. In
recent years, however, the corporate sector and state and
local governments as a group have always been borrowers.
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IV-28
A final element excluded from the foregoing analysis
is international sources of funds. When the balance of pay-
ments on current account of the U.S. is deficit, then
foreigners will be supplying net financial investments to
the U.S., and vice versa. In the 1970-1974 period, for
example, the U.S. did experience several periods of substan-
tial deficits, and the rest of the world did provide some
financing. Currently, however, the U.S. is enjoying substan-
tial balance of payments surpluses, so that the funds pro-
vided by the rest of the world are actually negative. In
the current era of floating exchange rates, the most reasonable
forecast of future balance of payments is that, on average,
they will probably be zero. Thus, the most reasonable fore-
cast of net financial investment by the rest of the world
in the U.S. is that it will, on average, be zero. If so, the
financial system of the U.S. can be viewed in isolation from the
rest of the world. The external financial needs of the U.S.
corporations and governments must be equal to the net finan-
cial investment supplied by U.S. households for this to be true.
Because corporate and governmental financial needs
must be supplied by households, the final link in the
analysis is to investigate the savings behavior of households.
For the purposes of this analysis, the "net saving" of
households is defined as the sum of their accumulation of
net financial investment (financial assets minus financial
liabilities) plus the net increase in residential construction
(the dollar value of new houses purchased by households
minus the depreciation of the existing housing stock).
Exhibit IV-10 documents the savings behavior of
households over the five recent credit cycles used in Chapter
1. The data suggest that the rate of households' net savings
-------
IV-29
(as a percent of GNP) has fluctuated between 5.4 and 6.6
percent. Numerous other long-term studies of household
savings behavior in recent decades confirm that net savings
rates fluctuate approximately in this range, with no dis-
n o
cernible long-term secular trend. ' On the other hand,
there has been a drastic shift in the composition of net
household savings across these five credit cycles. In the
credit cycles of the 1950s, the net saving of households was
dominated by the increase in net residential construction.
In the later credit cycles, however, new home construction became
a much less important form of saving, and net financial in-
vestment became the dominant component of saving. Needless
to say, most of this net financial investment was used to
fund the growing net external financing requirements of
business in these periods. The increased funds require-
ments in the corporate sector may well have "crowded out"
additional housing in these years.
THE SUPPLY AND DEMAND FOR FUNDS
IN THREE ALTERNATIVE SCENARIOS
Because of the relatively steady behavior of house-
holds' net saving in recent cycles, it is possible to make
some initial observations about the capacity of the U.S.
financial system to fund various future corporate needs.
It is assumed that households in future credit cycles will
save in the range of 5.5 to 6.5 percent of GNP, about the
range over the last five credit cycles. These net savings
must then be divided between net investment in homes and net
financial investment. The latter is, in turn, divided into
2
The exception to this is the unusual savings rate in times of extreme
economic or political conditions^ e.g., World War II and the Great
Depression.
3
.See, for example, Friedman, M., A Theory of the Consumption Function,
Princeton University Press, 1957.
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IV-3Q
funds for corporate, state and local government, and federal
government financial needs. The table below shows the
magnitude of corporate external requirements, in relation
to households' net saving, assuming the latter to be 6
percent of GNP.
ILLUSTRATIOn OF CORPORATE NET EXTERNAL FUNDS REQUIRED
AS PERCENT OF NET SAVINGS IN THE HOUSEHOLD SECTOR
CREDIT
CYCLE 1
CREDIT
CYCLE 2
CREDIT
CYCLE 3
CREDIT
CYCLE 4
CREDIT
CYCLE 5
PROJECTED
CREDIT CYCLE*
> /?«,;;
83Z SceNABtol
63X SCENARIO 2
402 Scnumo S
.-HOUSEHOLD NET SAVINGS RATE IS AS 8 WHO TO IE II, AS A PERCENT OF CMP.
KEY!
I 1 GOVERNMENT FINANCING AND
I 1 NEN HOME CONSTRUCTION
CORPORATE NET EXTERNAL
REQUIRED
Although the foregoing table may suggest that housing
and governmental financing are a residual, this is not the
case. The governmental sector is a strong competitor for
funds. Therefore, a brief review of the historical and
possible future levels of the other demands for funds must
be analyzed. As Exhibit IV-10 suggests, the net increase
in residential construction has fluctuated from 1.3 to 1.9
percent of GNP in recent credit cycles, down sharply from
-------
IV-31
the 1950s. While demographic and economic factors suggest
that the construction of new housing may remain relatively
depressed, it is difficult to imagine its falling below this
range (1.3 to 1.7 percent) without seriously endangering
national housing goals. From a public policy perspective,
it would be most desirable to maintain enough financial capac-
ity to fund new housing in the vicinity of at least 1.5 per-
cent of GNP.
It is true that, in past periods of credit tightness,
the response of households has, in effect, been to shift funds
from housing to corporations. In the late stages of each of
the recent credit cycles, households have increased substan-
tially their purchases of corporate securities, either directly
through brokers or indirectly through mutual funds and related
vehicles. The process has involved a transfer of household
funds to high-yielding corporate securities and from the
deposit institutions that invest primarily or importantly in
mortgages. This shift of funds from deposits to direct pur-
chases, called disintermediation, has occurred in each of the
recent credit crunches. The magnitude of the diversion of funds
from mortgages may be smaller in the future than in the past.
In recent years, several large and growing off-budget
federal agencies, the Federal National Mortgage Association
(FNMA) and the Federal Home Loan Mortgage Corporation (FHLMC),
have been established to supplement the flow of money to resi-
dential mortgages. These federal agencies are now very effec-
tive competitors for funds in the federal agency securities
market and are likely in the future to step up their activities
in periods of credit stringency so that the flow of funds to
the mortgage markets is somewhat less volatile. If so, the
emergence of these agencies will clearly make it more difficult
for corporations to bid funds away from the mortgage market.
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IV-32
The external financial needs of state and local
governments have accounted for a rather steady but important
amount of financing in recent years. Averaged over recent
credit cycles, the net external financing of state and local
govenrments (that is, the total increase in external financing
minus the increase in financial assets held) has fluctuated
between 0.6 and 0.8 percent of GNP. Despite this stable
history, predictions of future municipal financing needs are
extraordinarily difficult. An abatement of the basic needs
of municipalities seems unlikely. However, the historical
cyclical behavior of state and local governments suggests
they are sensitive to interest rate savings, curtailing their
financing in times of high needs in other sectors. Thus, to
the extent that future increases in the needs of other sectors
over a full cycle manifest themselves in increases in interest
rates, municipal borrowers may be "crowded out" in a high
corporate investment economy.
The final large financial demand, that of the federal
government, has fluctuated widely from year to year. In the
credit cycles of the 1950s, the net external financial needs
of the federal government were approximately zero, because of
the balanced budget philosophy of those years. In the most
recent credit cycle, however, these net external financing
»
needs exceeded 1 percent of GNP. Again predictions of the net
effect of federal taxing and expenditure decisions are perilous.
It seems unreasonable, however, not to consider deficits as a
strong future possibility.
With this background on possible future levels of
financing needs in the housing and governmental sectors, the
financial implications of the three corporate scenarios can
be set in perspective. Under Scenario 1, where corporations
continue to expand their rate of investment without a
recovery in internal funds, the external financing needs
-------
IV-33
of corporations would require virtually all of the net
savings of households, leaving very little available for
new housing, state and local governments, and the federal
4
government. This scenario is indeed a "capital shortage"
scenario, where considerable strains would almost certainly
be placed upon the financial system. Indeed, Scenario 1 is
probably a workable projection only if the government sector
as a whole actually supplies funds to the system. Otherwise,
in order to bring the system to equilibrium, some combination
of new housing, small business, state and local governments,
and financially weak larger corporations would be "crowded
out" in the competition for funds.
Even under Scenario 2, the financial needs of the
corporate sector would appear to be quite large in relation
to potentially available funds. Over 60 percent of house-
holds' net savings would be required to finance corporate
needs, leaving only a modest amount for housing and govern-
ments. Presumably, if the federal government averaged zero
financial needs over the future credit cycle, then Scenario
2 could be realized with a minimum of financial strain. If,
however, the federal government managed its affairs so as
to produce a sizeable net deficit averaged over the credit
cycle, a possibility which most political observers find far
more plausible, then the combined financial needs of the
federal government and the corporate sector would still
"crowd out" some potential borrowers.
4
All of this assumes that the Federal Reserve chooses to expand the
supply of money and bank credit at rates consistent with economic
growth. In the short run, of course, the Federal'Reserve theoretically
could choose to supply enormous amounts of money and credit through
the banks. The result in the long run would be enormous inflation.
We are assuming implicitly an "appropriate" monetary policy in our
analysis; that is, a monetary policy which is tied to real economic
growth.
-------
IV-34
Scenario 3 is the most encouraging scenario, at
least from the perspective of the supply and demand for
funds. In Scenario 3, the external financing needs of cor-
porations are modest in relation to the available supply
of households' net savings. Thus, substantial funds would
be available for new housing, state and local governments,
and the federal government.
VARIATIONS WITHIN A CREDIT CYCLE
The projections above are all stated in terms
of the supply and demand for funds as a percent of GNP,
averaged across a prospective credit cycle. As pointed
out in Chapter 2, however, there are substantial fluctu-
ations in the demands for credit within a cycle. If, on
average, these needs are large, then a typical credit cycle
could be described as a series of subperiods, during some
of which funds are not readily available. During the sub-
period of peak corporate financial needs, there will be
particularly great strains on the financial system. In
Scenario 1, and probably even in Scenario 2, this will be
a time when the corporate financial needs will exceed sub-
stantially the normal sources of supply.
CONCLUSIONS
The preceding discussion considers future finan-
cial flows of funds through a presentation of three alter-
native projections of corporate external needs. The three
alternative scenarios present drastically different
assessments of the potential availability of funds. If
Scenario 1 occurs, there will almost certainly be a sub-
stantial "capital shortage," complete with the crowding out
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IV-35
of weaker economic sectors. If Scenario 2 occurs, the ex-
ternal needs of corporations could probably be financed,
along with moderate new housing and state and local govern-
ment projects, as long as the federal government did not
run at a substantial deficit. If Scenario 3 occurs, corporate
external needs could be easily financed, leaving substantial
funds available for other uses.
These three scenarios were constructed to bracket
the range of probable outcomes. As of early 1976, the moderate
investment projection of Scenario 3 seems more likely than
Scenario 2 and much more likely than Scenario 1. The current
level of capacity utilization and of business concerns about
profitless capacity expansion tend to suggest an attention to
profits and a constraint on investment for at least the next
several years. Thus, there is a good chance that future cor-
porate financial needs can be met without placing undue
strains on the financial system. A more pessimistic appraisal
might emphasize the chance that corporate financial needs
will be very large relative to the potential supply of funds,
placing substantial strains on the financial system. While
the pessimistic scenarios are perhaps ones having a relatively
low probability, they cannot be discounted completely. Over
the entire 1975-1985 decade, however, the high investment-
low profit assumptions in Scenario 1 seem inconsistent with
recent corporate behavior, and thus much less probable than
the assumptions of Scenario 2.
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IV-36
CHAPTER 4
INVESTOR-OWNED ELECTRIC UTILITY
FINANCIAL RESULTS AND FINANCING
1960-1975
Volume I of this report traced the events that
occurred in the late 1960s that changed the nature of the
electric utility .industry, together with the impact of these
changes on the operating results of investor-owned electric
utilities. This chapter outlines the financial results over
this same period.
Briefly, the developments and trends discussed
earlier—credit crunches, inflation, equipment shortages,
the environmental movement, and fuel cost increases—caused
the industry to suffer a number of financing difficulties in
1973 and 1974 and to leave it still in an uncomfortable—if
not precarious—financial condition in early 1976. To high-
light this situation, this chapter first will describe the
industry's financial results and access to capital in the
1960-1965 period, then will contrast the conditions existing
in the 1966-1973 time period. Finally, the chapter concludes
with a review of 1974 performance and available data on 1975
results.
1960-1965: GROWTH AND PROSPERITY
The decreasing costs of electric power, the stable
increases of electricity consumption, the stable or declining
costs of new capacity, and the good reception for utility
securities in the capital markets all combined to result in a
rapid growth in earnings for the industry. Because of regula-
tory lags, cost reductions often led rate reductions by a
-------
IV-37
substantial time span, with the result that the benefits of
these cost reductions accrued in part to the stockholders
of electric utilities. As a result, net income increased
each year, from $1.6 billion in 1960 to $2.4 billion in
1965, an average annual increase of 7.4 percent (see Exhibit
IV-12). Moreover, the industry's return on equity improved
significantly, from 11.6 percent to 12.8 percent (Exhibit
IV-13).
Despite the industry's large and increasing net
income, retained earnings met only a small fraction of the
industry's total need for funds from 1960 to 1965. The
product of the industry's growth rate and capital intensive-
ness (Exhibit IV-14 shows that gross plant and equipment
was about 4.5 times revenues) resulted in yearly capital
expenditures ranging from about $3.2 to $4.0 billion in the
early 1960s or 6.7 to 7.5 percent of each year's initial
total assets (see Exhibit IV-15). Together with modest
yearly changes in net working capital requirements, these
capital expenditures resulted in the yearly funds needs de-
tailed- in. .column 11 of Exhibit IV-16. Retained earnings
supplied only an average" 6"f '~a"bout- 16- percent; of the indus-
try's 1960-1965 funds needs (Exhibit IV-16, page 2)7~~Thisr
relatively small equity fraction was the product of three
factors: common equity constituted less than 40 percent of
the industry «"s total^lHTaTTs^e~^xTfimTs~^^
for detailed financial structure data); return on equity
averaged only about 12 percent (Exhibit IV-13); and nearly two-
thirds of earnings was paid out as dividends (Exhibit IV-13).
As a result, yearly retained earnings in relation to initial
common equity averaged only about 4.0 percent1 and relative
4.0 percent = 12.0 percent x (1.00 - .663), where .662 is the
average dividend payout as a fraction of earnings.
-------
IV-38
o
to initial capitalization averaged only about 1.5 percent.
This latter figure contrasts with yearly capital expendi-
tures averaging about 7 percent of initial total assets
and 8 percent of initial capitalization, because long-term
capital accounted for about 88 percent of total liabilities
and capital.
Depreciation, amortization, and deferred taxes,
i.e., non-cash charges against income, were an important
source of funds from 1960 to 1965 (depreciation and amorti-
zation constituting about 37 percent of total funds needs, and
deferrals about 4 percent), but the industry still relied
heavily on external sources. Although it was trending down-
ward slightly during the early 1960s, 44 percent of the
industry's total funds needs were met by external sources
(Exhibit IV-16b).
Despite its heavy reliance on external financing,
the industry found it extremely easy to issue common equity
for cash. As is evidenced by common equity market prices
generally above book value—in many instances more than 2.0
times book value (Exhibit IV-19)—the returns on equity al-
lowed by regulators during this period were often far above
the minimum rates of return demanded by the suppliers of
equity. The existence of this excess return, i.e., the
rate Of return allowed versus the return available elsewhere
in the capital markets on investments of comparable risk,
meant that the more equity issued by a utility, the better
off its shareholders—if not customers—tended to be.
2
1.5 percent = 4.0 percent x .377, where .377 ia the average ratio of
common equity to total capitalization.
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IV-39
Although this economic logic was perhaps only
dimly perceived by many investors and industry managers,
the 1960-1965 period was one in which the industry employed
a high volume of common equity issues (see Exhibit IV-20),
and thereby increased its common equity to capital ratios
slightly (see Exhibit IV-17). The excess return allowed
by regulators also contributed to a strong yearnings per share
growth pattern (Exhibit IV-13), about 7.5 percent growth per year,
As is discussed in Appendix A, the issuance of common stock
at significant premiums above book value tends to boost the
rate of earnings per share growth above the "normal" case
where growth is equal to the rate of return on equity times
the fraction of earnings retained, i.e., the complement of
r>
the dividend payout ratio.
Although the industry did slightly decrease the
proportions of debt and preferred stock in its capital struc-
ture — from 52.8 percent debt and 10.7 percent preferred in
1960 to 51.5 percent debt and 9.5 percent preferred in 1965 —
the industry's issuance of debt and preferred stock during
this period was nonethless very large, as is shown in Exhibit
IV-16. These issues were well received by conservative in-
stitutional investors and a few individuals. The industry's
stability — in earnings record and future prospects — was one
point in its favor. Secondly, given that the industry's
rate of return on common equity was very high compared to
prevailing interest and preferred dividend rates (Exhibit
IV-21), its interest and preferred dividend expenses were
well covered by earnings (Exhibit IV-22) despite an uptrend
3
Assuming a 12 percent return on common equity and a 70 percent
dividend payout ratio, yearly earnings per share growth—either
with no new stock issues or with issues sold at book value—
would be 3. (T percent} where: 3.6 = 12(1 - .70).
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IV-40
in its average cost of debt (Exhibit IV-23). Thus, the in-
dustry easily met a major portion of its total capitalization
needs via the issuance of long-term debt and preferred stock.
In summary, the early 1960s were prosperous years
for utility managers and investors. Changes were in the wind,
however, and the impact of these changes on the industry's
financial results and financing capabilities is discussed in
the next section.
1966-1973: GROWTH WITHOUT PROSPERITY
Volume I of the report indicated that the consump-
tion of energy grew at an average annual rate of 7.1 percent
in the 1966-1973 period, while the growth in peak demand
grew at an 8.1 percent rate in the same period. The combined
effect of the industry's meeting these demand requirements
while experiencing a more than doubling in the cost of a
kilowatt of installed capacity resulted in an increase in
capital expenditures from $4.0 billion in 1965 to $14.9
billion in 1973 (Exhibit IV-15). This represents an increase
in capital expenditures relative to initial assets from 7.5
percent to 13.5 percent.
In addition, by the end of 1973, because of rapidly
escalating fuel and other costs and slowdowns in collections
of accounts receivable, the industry began to require sig-
nificant amounts of funds for increasing accounts receivable
and inventories. (The industry's total funds needs are shown
in column 11 of Exhibit IV-16.)
Thus, by 1973 the ability to finance continued
growth had become a major concern to the electric utility
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IV-41
industry. The remainder of this section discusses the
internal sources of funds available to the industry, then
external sources, and finally the competition for funds in
the capital markets.
/
Internal Sources of Funds
Caught between rising capital costs and an increas-
ing resistance to rate increases on the part of consumers and
regulators, the industry's earnings available for common
stock managed to grow from $2.3 billion in 1966 to $3.9
billion in 1973 (Exhibit IV-13), but this was a rate of
growth well below that of the industry's total common equity
base (Exhibit IV-17). Thus, the industry's return on equity
dropped sharply from 13.0 percent in 1966 to under 12 percent
in 1970 through 1973 (Exhibit IV-13). Given continued high
payout ratios, retained earnings dropped sharply compared to
increasing total funds needs, from an average of 15.4 percent
in the early 1960s to an average of 8.2 percent in the early
1970s (Exhibit IV-16).
An additional problem was that an increasing per-
centage of reported earnings took the form of a non-cash
credit to income, the allowance for funds used during con-
struction (AFDC). As shown in Exhibit IV-24, AFDC has
grown from under 5 percent of income available for common
stock in 1966 to over 31 percent in 1973. Because AFDC
contributes to earnings without contributing to cash flows,
its rapid increase has caused a number of investors to
question the quality of earnings in recent years.
A further factor contributing to the perceived de-
cline in earnings quality from 1966 to 1973 is the fact that
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IV-42
the capacity being depreciated typically had been constructed
at a cost substantially below the then current replacement
cost for a like unit of capacity, thereby causing an over-
statement of earnings in real terms. Moreover, because about
40 percent of the industry's assets were in regulatory juris-
dictions requiring flow-through accounting, much of the cash
flow benefits of accelerated depreciation and investment tax
credits were used to reduce the rates charged current electric
utility consumers rather than to reduce the industry's ex-
ternal financing requirements and the rates charged future
customers.
These latter factors caused depreciation and de-
ferred taxes to decline in'importance in relation to total
funds used, even though depreciation remained much larger
than retained earnings as a source of funds. As shown in
Exhibit IV-16, depreciation declined from about 37 percent
of funds needs in 1960-1965 to under 22 percent in the early
1970s.
External Sources of Funds
Because the industry's need for funds in the 1966-
1973 period grew more rapidly than its internal sources, its
reliance on external financing went up dramatically. As
shown in Exhibit IV-16b, external funds as a percent of total
needs averaged less than 45 percent in the early 1960s and
were actually trending downward. The ratio shot up above
60 percent in the late 1960s and to average levels near 70
percent in the early 1970s.
Meeting these external financing needs was a
formidable task. A combination of adverse earnings trends
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IV-43
peculiar to the industry, increasing levels of inflation and
hence nominal rates of return demanded by investors, an in-
crease in the demands for financing by other corporate
sectors, and the enormous scale of the industry's needs rela-
tive to total corporate financing had, by the end of 1973,
severely constrained the ability and willingness of many
utilities to meet the terms demanded in the U.S. capital
markets.
In the case of investor-owned utilities, a first
problem was that declining interest coverage ratios greatly
diminished the industry's ease of access to debt financing
(Exhibit IV-22). These declining coverage ratios stemmed
primarily from two causes. First, utilities had to issue
new debt at interest rates of 8 percent or more, or sub-
stantially above embedded rates (see Exhibits IV-21 and
IV-23). Secondly, coverages were hurt by the industry's
decreasing return on equity (Exhibit IV-13). Capital struc-
ture ratios remained relatively constant (Exhibit IV-17),
and thus played little part in the coverage downtrend.
The industry averages mentioned above obscure
important differences between individual electric utility
systems. In the averages are a number of utilities with
coverage ratios near 2.0 times. The 2.0 times coverage
ratio doubtless had important psychological implications
for investors, but even more concretely, it was important
because a 2.0 times coverage requirement was stipulated in
the, indentures of most first mortgage bonds. When coverages
including the interest on the prospective issue fell below
this level, most utility systems were precluded from issuing
additional debt securities ranking equally in security with
their first mortgage bonds and many were precluded from any
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IV-44
additional debt. The coverage ratios described above also
may obscure the fact that many bond indentures limited the
extent to which the allowance for funds used during construc-
tion could be included in earnings for the purpose of calcu-
lating interest coverage. Some indentures altogether
excluded AFDC and other income from consideration in the
calculation of coverage ratios.
Some utilities unable to issue first mortgage bonds
could still add junior long-term debt, such as second mort-
I
gage bonds or debentures. The amounts of such issues were
also typically controlled by the terms either of the system
bonds or of its preferred stock. Moreover, even if allowed,
these junior securities historically sold at spreads of
roughly 25 basis points, i.e., 0.25 percent, above the senior
bonds of the same company. Furthermore, for a company in
earnings coverage trouble, these junior securities might
have been given such a low rating as to necessitate an even
larger yield spread than had been true historically. In
fact, ratings below a Moody's A might have resulted in a
system's having to issue its securities to other than the
usual purchasers of utility debt obligations, which investors
tended to be interested only in high-quality obligations.
In part because of the constraints on and costs of long-term
debt, in part because of a hope that later issues of long-
term debt or equity could be made on more favorable terms,
the industry increased its use of short-term debt (commercial
paper and bank loans) from under $1 billion in the early
1960s to nearly $4 billion in 1973 and issued significant
amounts of intermediate-term (5-year to 10-year) notes
(see Exhibit IV-18).
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IV-45
Preferred stock remained a viable financing alter-
native for the industry through the 1966-1973 period. In
fact, as shown in Exhibit IV-17, the proportion of preferred
stock in the industry's capital structure grew slightly, to
12.1 percent in 1973. As in the case of debt, however, these
new issues went out at increasingly high yields.
Despite the problems attendant to both debt and
preferred stock financing during the 1966-1973 period, common
stock financing was on balance even less attractive to the
industry, so that the percentage of common equity in the in-
dustry's capital structure dropped from 38.2 percent in 1966
to just over 35 percent in the 1970-1973 period. The indus-
try's fundamental problem was that its return on equity de-
clined from 13.0 percent in 1966 to 11.7 percent in 1973,
while the returns demanded by investors increased substan-
tially.
This increased rate of return requirement was
!
primarily due to two reasons. The first was inflation. As
investors sought to preserve roughly constant real returns
on their investments in securities, the nominal required
rates of return on securities in any given risk class were
driven up by amounts corresponding to the rate of inflation.
Secondly, because of increasing uncertainty about the politi-
cal and regulatory environment in which the industry operated,
the investment community appeared to be assigning a higher
degree of risk to the electric utility industry and hence to
be demanding a higher real rate of return than it had in
the past.
As a result of the relative changes in actual and
demanded rates of return, the industry's stock price relative
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IV-46
to book value dropped from an average well over 2.0 in the
1960-1966 period to 0.79 in 1973 (Exhibit IV-19). Similarly,
the industry's price to earnings ratio dropped from about 20
in the early 1960s to 8.1 in 1973.
As detailed in Appendix A, once the industry's
market-to-book ratio fell below 1.0, the issuance of common
stock per se tended to depress future earnings per share
growth, which decline in earnings per share growth—when
anticipated by investors—led to a further reduction in the
industry's market price. Thus, the phenomenon which had
helped fuel the industry's spectacular earnings per share
performance of the early- and mid-1960s was, by 1973, working
in reverse. As a consequence, between 1966 and 1973, the
increase in the number of shares of common stock outstanding
had been almost as great as the growth in net income in the
industry. The growth rate in earnings per share of common
stock was just over 3.1 percent between 1966 and 1973. This
compares with an average increase in net income of 8.2 per-
cent annually during the same period (Exhibit IV-13).
Competitive Demands for Funds
i
To set the foregoing external financing history in
context, it might be noted again that each of the last three
credit cycles has shown a successively larger total demand
for capital, highlighted particularly by long-term financing
needs of corporations. These corporate financing needs have,
in fact, grown to be quite large in comparison to the tradi-
tional supplies of long-term institutional capital, resulting
in the emergence of individuals as new investors in corporate
debt securities. What is important for our purposes is the
the demand for electric utility financing has increased even
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IV-47
more rapidly than total corporate financing needs in the last
14 years, so that it has been an expanding fraction of an
expanding corporate demand for financing.
While the electric utility industry's share of capi-
tal expenditures by all non-financial corporations rose from
an average of under 9 percent in the early 1960s to nearly 15
percent in the 1970s (Exhibit IV-25), the industry came to
represent an even larger share of total non-financial business
financing. The industry's share increased from an average of
about 12 percent in 1961-1966, to 14 percent in 1967-1969, and
to about 18 percent in 1970-1974 (Exhibit IV-26).
The electric utility industry has historically
accounted for an even higher percentage of total corporate
equity financing than of total corporate financing. As shown
in Exhibit IV-26, the industry has accounted for about 40 per-
cent of net equity financing in the early 1960s, about 50
percent in the late 1960s, and about 40 percent from 1970 to
1973. As shown in Exhibit IV-27, the industry's share of the
gross equity financing of the total private sector (including
financial intermediaries) is smaller than its share of net
financing, but shows a strong secular uptrend from the early
1960s to the early 1970s, averaging nearly 29 percent in the
1970-1974 period.
There is considerable cyclical variability in
electric utilities' share of total financing due to sizable
fluctuations in financing by other corporations. Electric
utilities are among the few industries that issue new common
and preferred stock throughout a business cycle. Consequently,
in years when total corporate uses of equity are low, the
electric utility share can be quite large, indeed. In 1974,
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IV-48
for example, investor-owned electric utilities accounted for
93 percent of all new equity financing, a huge jump from the
already high 43 percent level achieved in the 1970-1973
period.
Because total corporate debt financing is less
volatile than total corporate equity financing, the electric
utility share of long-term debt and total long-term financing
is more stable than the equity ratios. From 1970 to 1973,
electric utilities accounted for 19 percent of new long-term
debt and 24 percent of all long-term financing. In 1974
the electric utility share jumped to 26 percent of long-term
debt and 34 percent of all long-term financing.
The increasing credit demands of electric utilities
and other non-financial businesses has led to increased
competition in the search for funds. Moreover, the long
lead times required for building electric generating capac-
ity and the industry's traditional objective of meeting all
demands have meant that utilities have been essentially
unable to tailor their uses of funds to capital market con-
ditions. Thus, the recent decline in the quality of the
industry's securities has left it increasingly exposed to
cyclical variations within the credit markets and, by 1973,
the industry seemed clearly to be feeling the effects of
the increasingly severe competition for available capital.
1974: FINANCIAL NADIR?
The wholesale cutbacks announced in capital
expansion plans during 1974 affected results in that year
very little. The momentum of the electric utility industry's
plant and equipment programs and high rates of cost inflation
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IV-49
combined to result in 1974 capital expenditures that reached
approximately $16.4 billion—up $1.5 billion over the year
before (Exhibit IV-25). In addition, the need for funds
associated with rapid increases in the industry's accounts
receivables and fuels inventories reached nearly $4.5 billion,
Due largely to the more or less automatic flow-
through of fuel cost increases to consumers—but also to
$2.2 billion in rate increases—the industry's revenues
increased by 23.6 percent to $39.1 billion in 1974. These
rate increases, however, fell short of matching increases
in costs other than fuel, and two very significant financial
measures deteriorated:
Net income available for common shareholders
declined 2 percent in 1974, (Exhibit IV-13), and
Return on equity declined to 11.0 percent from
a level of 11.7 percent the year before, this
1974 figure being the lowest level in over
15 years (Exhibit IV-13).
And not only did the level of earnings decline; the quality
of 1974 earnings deteriorated even further. The allowance
for funds used during construction—a non-cash credit to
income—grew again as a percent of income available for
common shareholders. From 31.8 percent of income in 1973,
AFDC increased to 38.4 percent of income in 1974. (See
Exhibit IV-24.)
The industry's imbalance between funds needs and
internal sources resulted in record-high external needs in
1974. These needs totaled $14.8 billion (Exhibit IV-26).
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IV-50
The dismal earnings performance of most companies
in the industry, particularly relative to the inflation-
bloated rates of return demanded by investors in equity
and debt securities, caused the industry to have enormous
difficulties in raising external capital in 1974. Consoli-
dated IJdison's infamous dividend cut of April 1974 and its
forced transfer of generating facilities to a public agency
because of an inability to finance them contributed in no
small way to investors' concerns.
I As a result of the lowered earnings, higher inter-
' est costs, and some shift in the capital structure toward
debt, interest coverage for the industry declined to roughly
2.2 in 1974 (Exhibit IV-22). This decline continued the
steady deterioration from a 5.0 interest coverage in 1966.
Most observers agree that an interest coverage close to 2.0
is extremely dangerous and could result in the debt markets
being substantially closed to a large number of companies.
In fact, a number of companies were constrained in 1974 from
issuing long-term debt by inadequate interest coverage ratios,
i A number of others found that their falling coverages were
leading to an unprecedented number of reductions in bond
quality ratings (see Exhibit IV-28) and consequently higher
interest costs. Even those bonds retaining high quality
ratings had to come to market with record-high coupons (see
Exhibit IV-29). Moreover, a large number of companies chose
to issue intermediate-term notes in an attempt to avoid
having to live with extraordinarily high rates of interest
over the 30-year life of mortgage bonds.
In spite of these difficulties with interest
coverage, the industry was nonetheless able to increase its
net debt financing by $10.3 billion in 1974. In part because
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IV-51
of necessity, the short-term debt portion of this total grew
a record amount in 1974—almost $2.6 billion (Exhibit IV-18).
Preferred stock financing grew in 1974 to $1.8
billion, but new common stock issues fell to $ 2.0 billion,
causing a further decline in the industry's equity to capi-
talization ratio. The industry's inability or unwillingness
to issue enough common stock to maintain capitalization
ratios (much less to maintain interest coverage ratios) is
directly attributable to allowed rates of return on equity
far below the rates demanded by investors. This disparity
manifested itself in a market-to-book ratio of 0.52 and in
a price to earnings ratio of 5.4 in June 1974.
Although the industry's public announcements of
cancellations or deferrals of capital expenditure plans
typically attributed the change to altered estimates of
future growth and capacity requirements, some cancellations
were acknowledged to be related to financing difficulties
and some industry observers feared that other changes in
capacity programs were brought about because of the strained
financial position of some companies in the industry. Since
a major portion of the industry's nuclear plant programs
were delayed or cancelled, a particular fear in some quarters
was that capital constrained companies were being led to make
tradeoffs between capital and operating costs that, in the
long run, would prove detrimental to consumers. This remains
a question open to debate. If the industry's allowed rate
of return long remained at as large a discount from investors'
demands as it was in 1974—in spite of very high current
levels of reserve margins—it appears apparent that consumers
would eventually suffer the economic consequences.
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IV-52
1975
As mentioned in Volume I, complete data for 1975
are not yet available, but informed estimates are available
which provide an indication of what the financial results
and financing situation may have been for the industry.
Highlights of the results and financing situation are
presented below: ;
Capital expenditures for 1975 amounted to
$16.8 billion, up only marginally from the
year before.
Net external financing was $10.2 billion,
or 61 percent of the total need for funds,
including:
—Common stock of $3.4 billion
—Preferred stock of $2.1 billion
—Debt of $4.7 billion, with an addi-
tional $3.0 billion refinanced.
Revenues for 1975 probably increased about
12 percent to $44.3 billion, the largest
portion of the increase coming once again
from fuel cost pass-throughs.
Earnings for 1975 improved over the
depressed levels of the year before,
with
—Total earnings up about 10 percent
—Earnings per share up about 6.5 percent.
Returns on equity increased slightly,
to about 11.3 percent.
Interest coverage ratios improved
significantly, from 2.2 times in 1974
to about 2.5 times in 1975.
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IV-53
In siim, the year 1975 was clearly an improvement
over 1974 for the electric utility industry. It was not a
banner year, but several encouraging signs began to emerge.
First, the seriousness of the industry's difficulties led to
an increasing awareness at many levels that consumers would
sooner or later, and directly or indirectly, bear the costs—
including capital costs—of producing electricity and that
attempts to avoid passing further cost increases to already
irate consumers could redound to their long-run disadvantage.
Second, to the extent that demand growth trends had perma-
nently been reduced, the industry's funds needs would abate,
necessitating less external financing. Third, an increasing
level of discussion concerning peak-period pricing and other
fundamental revisions of traditional rate structures encour-
aged the hope that economically efficient price signals
would contribute to diminishing the required rate of growth
of capacity. Finally, inflation abated somewhat, and to-
gether with the moderate increases in returns allowed by :
rate commissions in 1975, resulted in a discernible increase
in the real rate of return on the industry's common equity.
The net result of all these encouraging trends was a major
improvement by the end of 1975 in the industry's common
stock prices.
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IV-54
CHAPTER 5
PROJECTIONS OF ELECTRIC UTILITY
INDUSTRY FINANCING 1975-1985
This chapter presents an analysis of the electric
utility industry's future external financing needs and its
prospects for meeting those needs over the 1975-1980 and
1975-1985 periods, both before and after consideration of
t;he air and water pollution regulations described in Volume
III. The focus of this chapter is twofold. A first concern
is the size of the investor-owned electric utilities' needs
for funds relative to total sources of funds and to the re-
quirements of the total non-financial corporate sector. A
second concern is the financial strength of the investor-owned
electric companies vis-a-vis their own interest coverage re-
quirements and their competitors for funds in the U.S. capital
markets.
THE INDUSTRY'S FINANCING REQUIREMENTS
As described in Volume II, the electric utility in-
dustry will need external financing of approximately $191.2
billion (1975 dollars) from 1975 to 1985 before consideration
of federally mandated pollution control investments. As is
shown in Exhibit IV-30, $155.0 billion of this total is re-
quired by investor-owned utilities; the remaining $36.2 bil-
lion represents the needs of the public segment of the industry,
As is shown in Exhibit IV-30, the private industry's financing
requirements are approximately $12.2 billion per year from
1975 to 1980 and $16.4 billion per year from 1981 to 1985.
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IV-57
Depending on the scenario chosen to represent the
financing needs of the entire non-financial corporate sector,
the electric utility share of total corporate financing may
be above or below the level of the recent past. The shares
under each of the three corporate scenarios discussed in Chap-
ter 3 are shown in the table below.
INVESTOR-OWNED ELECTRIC UTILITY
1975-1985 EXTERNAL FINANCING INCLUDING POLLUTION CONTROL
(billions of 1975 dollars)
Non-Financial
Corporations
Electric Utility
Financing
Percent of all *
Corporate Financing
Percent of Net
Household Savings
1971-
1974
249
44
. 18%
11.5%
Scenario
1
$1041
174
17%
14.0%
Scenario
2
$'789
174
22%
14.0%
Scenario
3
$484
174
36%
14.3%
If the capital needs of other non-financial corpora-
tions are as high as projected in Scenario 1 of Chapter 3, the
electric utilities' share of total corporate financing from
1975 to 1985 would be 15 percent. That would be below the 18
percent share in the 1970-1974 period (Credit Cycle 5), but
above earlier years. More important, because total corporate
financing needs under Scenario 1 are projected to be at levels
well above those of recent years, the competition for funds
between the corporate sector and other sectors and therefore
the competition for funds within the corporate sector would
doubtless be fierce. Thus, the electric utility industry would
have to demonstrate considerable financial strength merely to
preserve its historical share of corporate financing.
• a
Under Scenario 2, the lower level of total corporate
external financing causes the electric utility industry's pro-
jected share to increase to 20 percent, a level only slightly
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IV-58
above the 18 percent level of the 1970-1974 period. Under Scenario
2, however, the industry would doubtless still encounter some
financing tightness because of the high level of total cor-
porate financing.
While a moderate level of corporate investment as
envisioned in Scenario 3 might suggest a lower level of elec-
tric utility investment than projected in the TBS baseline,
the combination of moderate levels of corporate investment
and high electric utility investment is conceivable. If
.this were to occur, total corporate financing would be well
below the levels prevalent in most recent cycles, and even
below the 1961-1966 level (see Exhibit IV-31), implying easy
capital market conditions. However, the electric utility
industry's share of total corporate financing would be enor-
mous, reaching 32 percent, and perhaps implying problems of
a different sort. The normal tendency of investors is to
diversify their risks and therefore to be reluctant to invest
a high percentage of their portfolios in any one industry.
Nevertheless, if electric utility securities regained the
quality image they enjoyed in the 1960s, such financing prob-
ably could be achieved.
The electric utility industry's share of total cor-
porate long-term financing will be higher than its share of
total financing in all scenarios, but by an amount that is
difficult to predict. As discussed in Chapter 2, total cor-
porate financing historically has comprised considerable short-
term debt. As documented in Chapter 4, little of the total
short-term debt has been attributable to utility borrowings.
As a result, especially in years of cyclical low points in
the long-term finanicng by other corporations, utilities have
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IV-59
represented a large fraction of the total long-term financing
by non-financing corporations. However, because other cor-
porations seem at present to be attempting to reduce their
past levels of reliance on short-term debt, their long-term
financing in the future may increase as a fraction of their
total financing. If so, the utilities' share of long-term
financing may be below past levels, though it doubtless still
will be above the utility industry's share of total financing.
Comparisons After Pollution Control Needs
The financing associated with federal pollution
control represents a 17.8 percent increase in private util-
ities' financing requirements in the 1975-1980 period and a
12.5 percent increase in the 1975-1985 period. As discussed
in the preceding section, the industry's baseline financing
requirements are themselves of a major magnitude, so these
percentage increases result in discernible increases in the
industry's projected share of total U.S. sources of funds and
of total non-financing corporate financing. Assuming net
household savings of 6 percent of GNP and a real GNP growth
rate of 3.5 percent, the electric utilities' needs during the
1975-1985 period would rise from 12.5 percent of net household
savings before pollution control requirements to 14.0 percent
after pollution control. Despite the substantial percentage
increase attributable to pollution control equipment in the
1975-1980 period, the industry's external financing require-
ments including pollution control needs will be slightly lower,
13.8 percent, in the early subperiod than in the full 1975-
1985 period. These results, together with the results for
alternative GNP growth and savings rate assumptions, are shown
in ;j||ve t ab le be low.
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IV-60
INVESTOR-OWNED ELECTRIC UTILITY NET EXTERNAL FUNDS RAISED*
WITH POLLUTION CONTROL EQUIPMENT
1975-1985
(as % of net household savings)*1
' *
Net Household Savings Rate (% of GNP)
1975-1980
3.0%
3.5%
4.0%
5.5% 6.0% 6.5%
15.3%
15.1%
14.8%
14.0%
13.8%
13.6%
12.9%
12.8%
12.^5%
1975-1985
5.5% 6.0% ' 6.5%
15.6%
15.3%
14.8%
14.3%
14.0%
13.6%
13.2%
12.9%
12.5%
*aeeimea net external financing requiremente of $86 billion
from 1975-1980, and $174 billion from 197S-198S
As shown in the table below, the utility industry's
pollution control requirements similarly increase the indus-
try's needs relative to total corporate needs by a discernible
amount. The increase is 2 percentage points in both Scenarios
1 and 2. In the low total corporate investment scenario,
Scenario 3, electric utility financing with pollution control
equipment would Jump 4 points to 36 percent.
INVESTOR-OWNED ELECTRIC UTILITY
1975-1985 EXTERNAL FINANCING NEEDS BEFORE POLLUTION CONTROL
(billions of 1975 dollars)
Non-Financial
Corporations
Electric Utility
Financing
Percent of all
Corporate Financing
Percent of all
Household Savings
Credit
Cycle 5
249
44
18%
11.5%
Scenario
1
$1041
155
15%
12.5%
Scenario
2
$789
155
20%
12.5%
Scenario
3
$484
155
32%
12.8%
PROJECTED FINANCIAL STRENGTH
OF INVESTOR-OWNED UTILITIES
Because of the large scale of the electric utility
industry's future financing needs, the industry's future fi-
nancial strength is a vital factor in determining whether the
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IV-61
industry is able to compete successfully for these funds against
other corporations and other sectors. As discussed in Chapter
4, interest coverage ratios are one important measure of fi-
nancial strength. Returns on common equity are another. The
former controls a company's access to debt financing, the
latter controls its access to common stock financing.
Strength Before Pollution Control Needs
Under the assumptions outlined in Volume II, notably
a 14 percent return on common equity and a 10 percent interest
rate on new issues of debt, the industry's projected external
financing would result in interest coverage ratios for the
investor-owned industry as a whole that decline slightly from
the range of 2.5 to 2.9 in 1976 to the range of 2.4 to 2.7
in 1985 (see Exhibit IV-32). Those ratios would be suffi-
cient, at least under historical capital market conditions,
to enable the industry to meet its external long-term debt
needs.
As is discussed in more detail in Chapter 6 and as
is shown in the following table, interest coverage ratios are
strongly influenced by returns on equity. If the industry's
future return on equity remains at its current level of about
11 percent, then (unless interest rates on new debt issues
drop well below the 10 percent level assumed in this analysis)
the industry's average interest coverages would drop to 2.1 to
2.4 in 1980 and to 2.0 to 2.4 in 1985. As is also documented
in Chapter 6, average interest coverage figures typically are
Because some bond indentures restrict the amoitrit of AFDC which can be
included in earnigs before interest and taxes for the purpose of interest
coverage computation, the range shown in this report represents the
coverage ratios computed with no AFDC in earnings, the worst possible
assumption concerning the stringency of the indenture requirement, and
with all AFDC in earnings, the easiest possible constraint for the
industry to meet.
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IV-62
an aggregate over a wide range of individual utility ratios,
so that an average coverage level of 2.0 to 2.4 implies that
some significant number of individual systems will be under
the 2.0 level typically required in mortgage bond indentures,
Thus, if the industry's future return on equity is held low
relative to interest rates, some firms will find themselves
excluded from the debt market.
COMPARISON OF BASELINE RESULTS UNDER
11% AND 14% RETURN ON EQUITY (ROE)
(billions of 1975 dollars)
14% ROE 11% ROE
External Financing
(1975-198S) 155.0 161.0
Revenues in 1985 96.76 91.09
Interest Coverage in 1985
Including AFDC 2.7 2.4
Excluding AFDC 2.4 2.0
% Change
+4%
-6%
As described above, the return on equity allowed by
regulators is important because of its impact on coverage
ratios. As discussed in Chapter 4, it is also of major im-
portance because of its impact on the industry's common stock
price and its ease of access to equity financing. The issu-
ance of common stock at prices below book value is possible for
brief periods of time, but as is argued in detail in Appendix A,
is infeasible over long periods. Thus, the key to the industry's
ability to raise common equity is a level of allowed return
on equity commensurate with the returns available in the mar-
ket on investments of comparable risk.
The level of return on equity assumed in the analysis
does not greatly affect external financing requirements, total
financing costs, or revenues. As shown in the table above, if
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IV-63
returns on equity are 11 percent rather than 14 percent, so
that the industry's retained earnings are lower, external fi-
nancing requirements increase slightly, by about 4 percent.
The lower return on equity may, of course, result in very much
greater difficulties in raising equity capital. Assuming
that the industry could somehow raise adequate equity and
debt with an 11 percent return on equity, financing costs—
and therefore consumer charges—would be reduced by only 6
percent.
The Effect of Pollution Control Needs
The impact of pollution control financing on the
industry's coverage ratios depends on the strategy employed
by the industry to finance these needs. Three alternative
financing strategies are analyzed below. These assume:
First, that the historical mix of debt,
preferred stock, and equity financing is
used;
Second, that the industry is in enough
difficulty with interest coverage require-
ments that all additional investments for
pollution control must be financed totally
with new common equity issues; and
Third, that all pollution control financing
is done through pollution control revenue
bonds (PCRB's).
Of course, the best future strategy may combine elements of
each of these financing strategies. However, the analysis
of the three polar cases indicates the degree to which the
industry's coverages and revenue impacts are sensitive to
financing strategy. The results of each of these projected
strategies are shown in the table on the following page.
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IV-64
IMPACT OF POLLUTION CONTROL FINANCING
INVESTOR-OWNED SYSTEMS
(billions of 1975 dollars)
New Financing
Long-Term Debt 10.6
Preferred Stock 1.9
Common Stock 6.8
PCRB's
TOTAL 19.3
Coverage Ratio with
AFDC in 1985 2.7
Coverage Ratio without
AFDC in 1985 " 2.4
i§75-1985^Incrernental_Financing
Historical All All
Financing Mix Equity PCRB's
0
0
19.3
19.3
3.1
2.7
0
0
0
19.3
19.3
2.5
2.2
As shown in this table, financing the industry's
total pollution control needs of $19.3 billion over the 1975-
1985 period would result in increments of $10.6 billion in
the industry's long-term debt issues, $1.9 billion in pre-
ferred stock, and $6.8 billion in common stock. As is also
shown in the table, this strategy will tend to maintain the
industry's coverage ratios at pre-pollution control levels
(see Exhibit IV-33). While this additional financing would
not significantly alter interest coverage ratios from the
baseline case, it would cause increases in consumer charges
of 2.3 percent in 1980 and 2.0 percent in 1985 to cover in-
creased financing costs.2
If the industry's coverage ratios or other consid-
erations preclude the use of debt or preferred stock for pol-
lution control financing, the industry's only recourse would
p
These increases in consumer charges are those directly attributable to
the incremental financing brought about by federal pollution control
requirements. AB discussed in Volume 1X1, the total increase in con-
sumer charges including incremental operating and maintenance expenses
is 5. 3 and 6. 7 percent in 1980 and 1985, respectively.
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IV-65
be to attempt to use common stock financing. Exhibit IV-34
and the summary table above show the coverage impacts of fi-
nancing the entire $19.3 billion of pollution control needs
by means of common stock. Interest coverage would increase
because interest charges remain unchanged and because earnings
must increase to provide a return on the additional equity
invested. Assuming that regulators allow a 14 percent return,
interest coverages would increase to the range of 2.7 to 3.1
by 1985. The disadvantage of this strategy is that it would
cause a substantial increase in average consumer charges.
Consumer charges would be 3.7 percent higher in 1980 and 3.3
percent higher in 1985 than before consideration of pollution
control financing costs.
Pollution control revenue bonds, which in effect allow
utilities to issue debt obligations in the name of state agencies
(and thus at interest rates reflecting the favorable tax treat-
ment accorded the recipients of interest on these securities),
are a special source of financing for pollution control equip-
ment , but are not a panacea. PCRB's are not guaranteed by the
issuing agency and hence typically carry bond quality ratings
equal to unsecured debt of the utility using the pollution con-
trol equipment. This rating is generally one notch below the
utility's mortgage bonds. As a result, companies whose mort-
gage debt is rated Baa or a weak A sometimes are hard put to
issue PCRB's. This problem — and the level of interest rates
on issues that do come to market — may be heightened at least
in the short run if large volumes of PCRB's begin to flood the
calendar for municipal securities.
If available, financing with PCRB's is the least
expensive to consumers because the interest rates on such
securities are approximately two-thirds those of other long-
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IV-66
term debt. Nonetheless, they do erode coverage ratios
slightly. Again assuming a 14 percent return on equity, the
coverage ratios under this scenario would decline to the range
of 2.2 to 2.5 in 1985. The impact, listed in Exhibit IV-35
and summarized in the table above, seems slight. In view of
the precarious current positions of many utilities, however,
this drop in coverage could be enough to preclude the use of
PCRB's. In fact, if the industry's future rate of return on
equity is 11 percent instead of 14 percent, then 1985 coverage
ratios would drop to the range of 1.9 to 2.2 As suggested
above, the impact on consumer charges would be lower with
this type of financing than with any other. Relative to the
baseline, this financing strategy would increase consumer
charges by only 1.2 percent in 1980 and 1.0 percent in 1985.
Because the feasibility of even the PCRB financing
strategy depends on the industry's allowed return on equity,
the conclusions reached in the baseline financing discussion
concerning the importance of the industry's returns carry over
to this discussion of pollution control financing. In fact,
because the industry's total financing needs are amplified by
pollution control requirements, the importance of a strong
financing profile is perhaps also amplified.
CONCLUDING COMMENTS
While the effect of the industry's pollution control
requirements is to aggravate an already large financing burden,
the increase is not a quantum change and the remarks applicable
to the baseline projection apply almost without change to the
projections including pollution control. Although a host of
caveats concerning GNP growth rates, net household savings
rates, the financing needs of other corporations and other
-------
IV-67
sectors, etc. are applicable, the conclusion that emerges
from the foregoing analysis can be put simply: Unless the
industry1s allowed return on common equity is commensurate
with the rates of return required in the capital markets,
the industry will, in part, be "crowded out" in the com-
petition for funds by stronger industries and sectors. If
so, pollution control expenditures can be financed only if
expenditures for basic capacity additions are curtailed. On
the other hand, if returns are set adequately high by regu-
latory commissions, the industry's status as a regulated
monopoly offering safe and predictable returns should enable
it to compete effectively for the funds needed for both basic
capacity additions and pollution control equipment. In
short, the feasibility of the external financing projections
of this chapter depends essentially on the decisions of state
regulatory commissions.
-------
IV-68
CHAPTER 6
FINANCING PROBLEMS OF
INDIVIDUAL SYSTEMS
This chapter discusses the factors which govern the
ability of an individual, investor-owned electric utility to
gain access to the capital markets. The discussion is of im-
portance because, even if the capital market has adequate
funds to meet the future needs of electric utilities as a
group and even if the industry's average return on equity and
interest coverages seem adequate to attract investors, the
special problems of individual systems can cause them serious
financing difficulties.
The chapter begins with a characterization of indi-
vidual systems in terms of three categories of financial health,
Recent historical data concerning return on equity and interest
coverage ratios for a sample of companies are presented in the
following section, together with a discussion of the implica-
tions of these data for a company's ability to raise funds.
Then follows a detailed discussion of the determinants of in-
terest coverage. The chapter concludes with some observations
concerning ways to resolve the financing problems of individual
electric utilities.
THREE CATEGORIES OF FINANCIAL HEALTH
As an aid to understanding the implications of the
financial variables discussed in the preceding section, it
is convenient to partition the companies in the electric
utility industry into three categories of financial health
These categories describe the ease of access to financing
-------
IV-69
for companies in each group according to the levels of return
on equity and interest coverage representative of the group.
Although specific levels of return and interest
coverage which are representative today are referenced in
this discussion, the particular level of return which deter-
mines the ability of a company to finance itself will actually
vary over time in response to changes in several factors. As
an example, an electric utility's return on equity must be
considered in relation to the general level of capital market
rates prevailing at any time. In addition, required electric
utility returns are also influenced by investor's risk percep-
tions.
TBS' projections were based on an assumed return on
equity of 14 percent and a 10 percent interest rate on long-
term debt. As discussed in Volume II, these values were
chosen to be roughly consistent with required rates of return
on the industry's securities in 1975. In early 1976, re-
quired rates of return seem to have declined somewhat, and
if this trend persists, the required rates of return for
electric utilities could indeed decline from those described
below.
The first category of financial health comprises those
companies with returns on equity and coverage ratios acceptable
to the traditional buyers of utility securities. Most of the com-
panies satisfying these criteria should have ready access to both
debt and equity financing and should be able to finance both their
baseline capital expenditures and expenditures for pollution control
The return on equity criterion could alternatively be stated in terms
of the market price to book value ratio. The implications of this
measure are discussed in detail in Appendix A.
-------
IV-70
equipment without difficulty. In early 1976, a return on equity
of 13 to 14 percent and an interest coverage of about 2.8 were
financial statistics that tended to result in stock prices at
or above book value and in bond ratings of A or better and hence
gave companies with these statistics relatively easy access to
capital.
A second, broad group of companies comprises those
with returns on equity and interest coverages near the minimum
acceptable to equity and debt investors. Recently the levels
in this category would probably include returns on equity in
the range of 11.1 to 13.0 percent and interest coverages from
2.2 to 2.8. Most companies in this category have had access
to debt financing at reasonable costs. Given the rates of
inflation and levels of uncertainty about the electric utility
industry characteristic of the 1974-1975 period, most companies
in this category might have found it necessary to issue common
stock at a discount from book value, but as of early 1976, some
companies in this range of returns had stock prices above book
value. And, if general rates of price inflation and the returns
demanded by the utility investors drop in the 1976-1985 period—
drop below those of 1974-1975, as seems to be the current con-
sensus of financial economists—such companies should be able
to issue common stock at prices roughly equal to book value.
While companies in this second category typically have some
access to the capital markets, their financial fragility
should be noted. Moreover, their access to debt at reasonable
cost is, at least at present, not unlimited. Thus, without
changes in the regulatory policies of 1975, these companies may
be in the position of having to choose between expenditures for
future capacity expansion and expenditures for pollution control
equipment.
-------
IV-71
A third category of companies, those having low returns
on equity and coverage ratios, are companies that might have
difficulty—perhaps severe difficulty—in financing the capital
expenditures required merely to meet the growth in demand in
their service areas. At the end of 1975, companies with returns
on equity less than 11 percent and coverage below 2.1 were in
this category. For these companies, capital expenditures for
pollution control equipment tend to cause dollar for dollar
reductions in capital expenditures for basic capacity.
It should be noted that, in some instances, companies
may have relatively strong return on equity figures, but weak
coverage ratios and vice versa. The linkages between return on
equity and coverage ratios are analyzed in a later section.
INTERCOMPANY COMPARISONS OF RETURNS AND INTEREST COVERAGE
An examination of the financial data for selected
companies for 1975 reveals major differences in return on
equity and coverage within the industry. These data under-
score the importance of performing financial analysis at
the company level. For example, while the average coverage
ratio for the companies in this sample is about 2.7, there
are a number of companies with coverages well below 2.0.
These electric utilities almost certainly confronted severe
financing difficulties in 1975.
As shown in the table below, the average return on
equity in 1975 was 11.5 percent for normalizing companies and
10.8 percent for flow-through companies. Both average figures
are somewhat below the rates of return demanded by investors in
such securities in 1975; more important, the averages obscure
the severely depressed level of earnings of a significant num-
ber of companies in this sample.
-------
IV-72
RETURN ON EQUITY IN 1975
AVERAGE AND DISTRIBUTION FROM SAMF
Average Return: 11.5 % Normalized
10.8 Flow Through
Distribution of Return in Sample ( as % <
<10% 10-11.0% 11.1-12.0% 12
Normalized
Flow Through
TOTAL
12%
8
20%
6%
10
16%
Source: Investors Management
18%
4
22%
Sciences, as reported
LE DATA
Df 88 sample companies)
.1-13.0% >13% Total
8%
9
17%
8
17% 25%
in Electrical Week
61%
39
100%
Of the 88 companies in the sample, 36 percent had
returns on equity less than 11.0 percent and 20 percent had
returns less than 10 percent. An analysis of the market price
to book value ratios for some of the lower return companies
suggests that these companies doubtless were severely con-
strained in their common stock financing during 1975. Further,
the data below suggest that large companies are by no means
exempt from these financial difficulties. The largest com-
panies in the sample have consistently lower returns on
common equity than the total sample.
RETURN ON EQUITY IN 1975
LARGE SYSTEMS VS. ALL SAUPLE SYSTEMS
Distribution of Return In Sample (as % of total companies in sample)
Largest 30 Companies1
Cumulative
Total Sample
Cumulative
JJ8 Flou-Tljrough and It HomaUtta
Source: Investors Management
< 10. Q*
28 "j
28
20
20
uith higheft
Sciences,
10.W-11.0* ll.«-12.0% 12.1%-13.0%
21". 21% 10%
49 70 80
16 22 17
36 58 75
reasnues
as reoorted in Electrical Week
20%
100
25
100
-------
IV-7 3
Similarly, the table below suggests that there
exist major differences in interest coverage ratios across
companies in the industry. Despite an average coverage for
1975 of 2.7 times when AFDC is included in earnings, 8 of the
119 companies in this sample had interest coverage ratios of
less than 2.0, and when AFDC is excluded from earnings, the
low-coverage group comprises 25 companies, or 21 percent of
the sample.
Aa or Higher
With AFDC
Without AFDC
With AFDC
Without AFDC
Baa
With AFDC
Without AFDC
ELECTRIC UTILITY INTEREST COVERAGES
1975
Number of
Companies
44
53
22
Average
3.4
3.0
2.6
2.3
2.2
1.9
Range of
Expected
Values*
4.2 -2.7
4.0 -2.4
3.2 -2.3
2.9-1.9
2.6 - 1.8
2.4 - 1.4
*90 percent of companies fall within range
Source: R.W. Pressprich & Co., Inc., March 1976
Number of
Companies
Below 2.0
0
1
2
13
b
11
Although the average interest coverage for the top-
rated (Aa or better) companies is 3.0 to 3.4, excluding and
including AFDC, the range comprising 90 percent of the group
is from 4.0 to 2.4 excluding AFDC and 4.2 to 2.7 including
AFDC. For A-rated companies, the average declines to 2. 3 to 2.6,
and there are a number of companies with coverages below 2.0.
-------
IV-74
Finally, among the Baa group, the average coverage including
AFDC is only 2.2, with approximately 90 percent of the cov-
erages falling between 1.8 and 2.6. When AFDC is excluded,
the average drops to 1.9, and 11 of the 22 companies have
coverages below 2.0.
The data above clearly indicate that, even though
the industry average interest coverage ratio of 2.7 in 1975
suggests a comfortable financial position, there was a wide
spread of coverages and return on equity in the industry and
a significant number of companies were in a precarious financial
position. Another factor which represents a possible flaw in
the apparent strength of some companies' coverages is that some
coverages include earnings attributable to revenues subject to
refund. And, for some systems in recent years, these revenues
have represented a significant portion of total earnings.
For such companies, refunds dictated by their regulatory com-
missions could severely damage their returns on equity and
coverage ratios.
The distribution of electric utility companies' re-
turns on equity and interest coverages as of the end of 1975
suggests that approximately 25 to 35 percent of the companies
had returns and coverages high enough to give them reasonably
good access to external financing. Roughly 40 percent of the
industry could be categorized as companies with reasonably
good access to debt capital, though not in unlimited quantities,
and with some access to equity capital, but perhaps at prices
below book value. Roughly 25 to 35 percent of all electric
utility companies were in 1975 in the precarious third category
of firms having low returns, low coverages, and poor prospects
for meeting their full financing needs. Unless regulators
raise the allowed return for this latter group of companies,
-------
IV-75
or otherwise improve their financial profile, most of them will
experience great difficulty in attempting to finance both base-
line expansion and pollution control between 1976 and 1985.
DETERMINANTS OF INTEREST COVERAGE RATIOS
A return on common equity is set directly by the
actions of regulatory agencies; coverage ratios are determined
in part by factors outside the control of commissions. Return
on equity is one determinant of coverage ratios, but coverages
are affected also by a company's average interest rate, its
average income tax rate as shown in its regulatory financial
statements, and the amount of its allowance for funds used
during construction (AFDC). The interactions between the
factors influencing interest coverage ratios can perhaps
best be displayed by means of a series of simple numerical
illustrations.
Exhibit IV-36 sets out some capital structure, cap-
ital cost, and income tax rate assumptions for several hypo-
thetical electric utilities. In each case, an income state-
ment is developed that, working from the bottom up, provides
the appropriate amount of income available for common, divi-
dends for preferred stock, tax payments, and interest. As
shown in Case I, with the interest rates, returns on book
value of equity, and income tax rates characteristic of the
1960s, interest coverages are high enough to meet a 2.00
coverage criterion with ease.
Increases in interest rates, even where returns on
equity are not adversely affected, can have^a severe adverse
impact in coverage ratios. As shown in Case II, as debt
-------
IV-76
costs increase by 4 percentage points relative to Case I,
interest coverage ratios drop from 2.56 to 1.93. Conversely,
lower interest rates would help alleviate the plight of
utilities currently having coverage problems.
Lower interest rates on debt could come about be-
cause of reductions in the current rate of inflation. At
least for the portion of financing represented by pollution
control equipment, lower interest rates could conceivably
also come about from the use of pollution control revenue
bonds. As discussed in preceding chapters, PCRBs pay interest
that is exempt from federal income taxation of the recipient
and, as a result, tend to require lower pretax interest rates
than other securities of comparable risk. Unfortunately,
however, PCRBs typically rank below mortgage bonds in safety.
Thus, their tax advantage is somewhat offset by their risk
disadvantage. At present, the net result of these advantages
and disadvantages is that PCRBs sell at yields only slightly,
if at all, lower than mortgage bonds. And, the PCRBs of com-
panies with low-rated bonds have recently proven hard to sell
even at elevated yields. Thus, while PCRBs may be helpful to
those companies able to issue them at all, they offer no panacea
for companies at the low end of the interest coverage spectrum.
The effective rate of income tax paid by a company
also impacts coverage ratios. As can be seen by comparing Case
III and Case II in Exhibit IV-36, a reduction in the effective
tax rate from 25 percent to 0 percent lowers the required amount
of earnings before interest and taxes and thus severely depresses
coverage ratios. This point is of particular importance because
the effect of flow-through accounting for statutory purposes is
to reduce effective tax rates relative to those in normalizing
companies. Thus, regulatory accounting practices as specified
by the various state commissions can have a ma.jor impact on
-------
IV-77
coverage ratios. Flow-through accounting does, of course,
result in revenue requirements that are lower, at least in
the short run. As can be seen by comparing the required
earnings before interest and taxes in Case II and III, the
25 percent tax rate assumption requires earnings before
interest and tax higher by $14. Although this $14 amount
represents a reduction of more than 10 percent in earnings
before interest and taxes, revenues and consumer charges
would of course decline by much smaller percentage amounts.
Case IV illustrates the fact that higher returns
on equity lead to higher coverage ratios. As can be seen by
comparing Case IV and Case I, however, equal percentage
point increases in the costs of debt, preferred stock and
common stock do not result in returns on equity high enough
to preserve the coverage ratio of Case I. Thus, to the ex-
tent that increases in the general rate of inflation increase
nominal (current dollar) returns on debt and equity by equal
amounts, the higher the rate of inflation, the worse are cov-
erages.
As is shown in Case V, one way of increasing coverage
ratios is to reduce the portion of debt in a company's capital
structure. Unfortunately, unless interest and common stock
costs drop as a result of this capital structure change, the
earnings before interest and tax, and hence operating revenues,
required to cover these capital costs rises. Comparing Case V
and Case IV, the low-debt alternative results in an increase
in coverage ratios from 1.97 to 2.20, but increases the earnings
before interest and tax required by $3.
-------
IV-78
Because "other income" such as AFDC is not fully
includible in "earnings" as defined for interest coverage
purposes in the financing agreements of many utilities, a
final problem is that the higher AFDC is in relation to
required earnings before interest and tax, the less useful
some portion of earnings before interest and tax is for
interest coverage purposes. The amount of required earnings
before interest and tax is unaffected by AFDC, but coverages
are affected. As a result, the higher the rate of a company's
new construction, the greater are both its external financing
needs and its interest coverage problems. Exhibit IV-37 shows
that, for a company with high AFDC, interest coverage as com-
puted for indenture purposes could be radically affected by
a limitation on the amount of AFDC allowed for interest
coverage purposes.
CONCLUSIONS CONCERNING ELECTRIC UTILITY FINANCING PROBLEMS
The foregoing analysis suggests that, even if the
capital markets are large enough to accommodate the electric
utility industry's total needs under current regulatory policy,
some of the companies within the industry will have difficulty
in raising sufficient capital to meet their baseline capital
needs, much less the needs associated with pollution control
equipment. Nonetheless, it is within the power of the current
regulatory system to effect changes that should enable all
companies to meet both baseline and pollution control financing
needs. Put bluntly, regulators need to allow price increases
or force cost reductions resulting in higher returns on equity
and higher interest coverage ratios. Moreover, if the indus-
try's financing requirements grow to constitute a large frac-
tion of total corporate financing, the ratios must be high
enough to make utility debt and equity securities of extremely
high quality.
-------
IV-79
Recent financial data suggest that between 25
and 35 percent of the companies in the industry had returns
on equity and interest coverages low enough at the end of 1975
to put them in a somewhat precarious financial position. Un-
less industry regulators, managers, or some outside force
improves the position of this group vis-a-vis investor de-
mands, this significant segment of the industry will find
it extremely difficult to compete successfully in the markets.
For this group, until financial conditions improve, the com-
panies may not be able to finance all of their projected
expenditures for capacity additions. Thus, pollution control
can be financed perhaps only at the partial expense of expen-
ditures for basic capacity requirements.
As suggested above, regulatory agencies have several
routes for improving the financial statistics of utilities
under their jurisdiction. Most, however, tend to result in
electricity prices that are higher at least in the short run.
These alternatives include increasing returns on common equity,
increasing statutory taxes via conversions (where possible)
from flow-through to normalizing accounting, and reducing
AFDC via allowing companies to include construction work in
progress in the rate base.
-------
Exhibit IV-1
TOTAL USES OF FUNDS AND FINANCING NEED BY YEAR
Domestic Non-Financial Business Corporations
1960-1974
(billions of dollars)
Real Assets
Plant and Equipment
Residential Construction
Inventory
Net Financial Assets
Liquid Assets
Net Trade and
Consumer Credit
New Miscellaneous
Assets
'Discrepancy
Total Financing Need
1960
$38.7
34.6
1.1
3.0
(0.6)
(4.1)
1.4
2.1
6.0
$44.1
1961
$36.3
32.9
1.9
1.5
7.9
3.2
2.6
2.1
5.0
$49.2
1962
$43.6
36.6
2.3
4.7
7.1
3.7
1.5
1.9
4.5
$55.2
1963
$45.2
38.2
2.6
4.3
6.8
4.8
(0.1)
2.1
5.6
$57.6
1964
$51.6
43.7
2.1
5.9
8.2
1.2
2.6
2.8
7.4
$67.2
1965
$62.3
52.3
2.0
7.9
8.0
2.6
2.1
3.3
8.9
$79.2
1966
$76.5
61.1
1.1
14.4
1.9
(3.7)
2.0
3.6
8.3
$86.7
1967
$71.4
61.9
2.3
7.3
9.2
4.8
1.2
3.2
5.9
$86.5
1968
$75.0
66.5
2.1
6.4
11.5
8.0
1.4
2.1
9.6
$96.1
1969
$83.0
74.0
2.9
6.7
6.6
2.3
2.1
2.2
6.0
$96.3
1970
$84.0
75.1
3.3
5.7
4.4
(0.4)
1.6
3.2
6.7
$95.3
1971
$87.2
77.1
4.9
5.1
19.2
10.6
2.5
6.1
10.2
$116.8
1972
$102.5
87.1
D.7
9.7
16.7
4.0
7.9
4.8
14.8
$133.9
1973
$121.5
103.3
5.3
12.9
18.8
6.9
6.5
5.4
13.8
$154.1
1974
$125.9
111.7
3.2
10.9
23.6
13.2
4.0
6.4
13.6
$163.1
<
00
Source: Flow of Funds Statistics. Board of Governors of
the Federal Reserve System, Third Quarter 1975
-------
Exhibit IV-2
USES OF FUNDS AND FINANCING NEEDS IN FIVE CREDIT CYCLES
Danestic Non-Financial Business Corporations
(all data are flows as a percent of 6NP averaged over recent credit cycles)
(third quarter 1954 to fourth quarter 1974)
Total Real Assets
Plant and Equipment
Residential Construction
Inventory
Net Financial Assets
Discrepancy
Total Financing Need
Credit Cycle 1
1954:3 to 1958:1
7.6
6.9
0.2
0.5
0.9
0.9
9.5
Credit Cycle 2
1958:2 to 1960:4
7.2
6.5
0.3
0.4
1.1
1.0
9.3
Credit Cycle 3
1961:1 to 1967:1
8.3
7.0
0.3
1.0
1.1
1.1
10.5
Credit Cycle 4
1967:2 to 1970:3
8.8
7.8
0.3
0.7
1.0
0.7
10.6
Credit Cycle 5
1970:4 to 1974:4
8.9
7.7
0.4
0.8
1.5
1.1
11.4
00
to
Source: Flows of Funds Statistics, Board of Governors of
the Federal Reserve System, Third Quarter 1975
-------
Exhibit IV-3
SOURCES OF FUNDS BY YEAR
Domestic Non-Financial Business Corporations
1960-1974
(billions of dollars)
Total Financing Need
Funds Internally Generated
Adjusted Retained Profits
Capital Consumption
Allowances (Depreciation)
External Funds Raised
Bank Loans and Other
Short-Term Debt
Long-Term Funds
Equity
Long-Term Debt
Mortgage Bonds
Debenturesl
1960
$44.1
34.4
10.1
24.2
9.7
2.1
7.5
1.5
6.0
2.5
3.5
1961
$49.2
35.6
10.1
25.4
13.7
2.8
10.8
2.2
8.6
4.0
4.6
1962
$55.2
41.8
12.7
29.2
13.4
3.9
9.5
0.4
9.1
4.5
4.6
1963
$57.6
43.9
13.1
30.8
13.7
5.5
8.2
(0.6)
8.8
4.9
3.9
1964
$67.2
50.5
17.7
32.8
15.0
6.1
8.9
1.3
7.6
3.6
4.0
1965
$79.2
56.6
21.2
35.2
22.6
13.4
9.2
(0.1)
9.3
3.9
5.4
1966
$86.7
61.2
23.0
38.2
25.6
10.1
15.5
1.1
14.4
4.2
10.2
1967
$86.5
61.5
20.0
41.5
24.9
3.5
21.4
2.2
19.2
4.5
14.7
1968
$96.1
61.7
16.6
45.1
34.4
16.1
18.4
(0.2)
18.6
5.7
12.9
1969
$96.3
60.7
10.9
49.8
35.6
15.5
20.0
3.4
16.6
4.6
12.0
1970
$95.3
59.4
5.8
53.6
35.8
5.2
30.4
5.7
24.7
5.2
19.5
1971
$116.8
68.0
10.3
57.7
48.8
7.0
41.5
11.4
30.1
11.3
18.8
1972
$133.9
78.7
15.7
63.0
55.2
15.9
39.2
10.9
28.3
15.6
12.2
1973
$154.1
84.6
17.1
67.5
69.5
34.9
34.5
7.4
27.1
16.1
9.2
1974
$163.1
81.5
9.0
72.5
81.5
45.3
36.3
4.1
32.2
10.9
21.3
I
00
w
Includes tax exempt financing, 1971 to 1973
Source: Flow of Funds Statistics. Board of Governors of
the Federal Reserve System, Third Quarter 1975
-------
Notes to Exhibit IV-3
Explanation of terms
Total Financing Need: The cash used to finance business activity, including both the cash used to fund
investment in physical assets such as plant and equipment and the value of the increase in physical
inventories, and the cash necessary to fund financial requirements such as net trade credit and
short-term financial assets.
Funds Internally Generated: The funds provided by ongoing operations, including both the cash generated by
earnings and by depreciation.
External Funds Raised: The funds which must be raised externally in the capital markets, either through
intermediaries such as comercial banks or directly through the Issuance of securities.
Adjusted Retained Profits: The cash realized from reported earnings which is available for investment in
the firm (computed by taking profits before taxes, adding repatriated foreign profits, and subtracting
corporate prof 11. taxes, tllvldeml.s, and Ihe Inventory valuation adjustment which measures the component
of profits due solely to increased inventory values.)
Capital Consumption Allowances: The non-cash expense Items including principally depreciation and depletion
allowances which have been subtracted at an earlier stage to yield profits before tax, but which do not.
represent a cash outflow, are Merely an accounting recognition of past cash expenditures.
Equity: The net funds raised from equity sources in the period, including the cash received from gross
new issues of equity minus equity retirements for various purposes.
Long-Term Debt: The net increase in outstanding external long-term debt in the period, including debentures,
bonds, and in recent years some small amounts of tax-exempt pollution control bonds.
»
Long-Terro Funds: The sum of equity and long-term debt.
-------
Exhibit IV-4
SOURCES OF FUNDS IN FIVE CREDIT CYCLES
Domestic Non-Financial Business Corporations
(all data-are flows as a percent of GNP averaged over recent credit cycles)
(third quarter 1954 to fourth quarter 1974)
Total Sources of Funds
Funds Internally Generated
Adjusted Retained Earnings
Capital Consumption
External Funds Raised
Bank Loans and Other
Short-Term Debt
Long-Term Funds
Equity
Long-Term Debt
Increase in Liquid Assets
Net External Funds Required
Credit Cycle 1
1954:3 to 1958:1
9.5
6.9
2.5
4.4
2.5
0.6
1.9
0.4
1.5
0,1
2.4
Credit Cycle 2
1958:2 to 1960:4
9.3
6.9
2.2
4.8
2.4
0.6
1.8
0.4
1.4
0.3
2.1
Credit Cycle 3
1961:1 to 1967:1
10.5
7.7
2.6
5.1
2.7
1.0
1.7
0.1
1.6
0.3
2.5
Credit Cycle 4
1967:2 to 1970:3
10.6
6.9
1.6
5.3
3.7
1.2
2.5
0.3
2.2
0.5
3.2
Credit Cycle 5
1970:4 to 1974:4
11.4
6.4
1.0
5.3
5.1
1.9
3.2
0.7
2.5
0.7
4.3
00
Source: Flow of Funds Statistics, Board of Governors of the Federal Reserve System, Third Quarter 1975
-------
IV-86
EXHIBIT IV-5
THE CYCLES OF EXTERNAL FUNDS-SHORT-TERM DEBT, LONG-TERM DEBT, NET EQUITY ISSUES
NON-FINANCIAL BUSINESS CORPORATIONS
THIRD QUARTER 1954 TO SECOND QUARTER 1974
(SEASONALLY ADJUSTED, SMOOTHED, ANNUAL RATES AS A PERCENT OF GNP)
62
-2%
CREDIT CYCLE 1 CREDIT CYCLE 2
1954:3 TO 1958:1 1958:2 TO 1960:4
CREDIT CYCLE 3
1961:1 TO 1967:1
CREDIT CYCLE 4
1967:2 TO 1970:3
CREDIT CYCLE 5
1970:4 TO 1974:2
KEY:
TOTAL EXTERNAL FUNDS
LONG-TERM DEBT
-—— SHORT-TERM DEBT
NET EQUITY ISSUES
-------
IV-87
EXHIBIT IV-C
LEVELS OF LIQUID ASSETS AND DEBT OUTSTANDING, AS PERCENT OF GNP
NON-FINANCIAL BUSINESS CORPORATIONS
THIRD QUARTER 1954 TO FOURTH QUARTER 1971
20*
LONG-TERM DEBT OUTSTANDING
(BONDS AND MORTGAGES)
oo.
z
QO
SHORT-TERM DEBT OUTSTANDING
2 mi
LIQUID FINANCIAL
ASSETS
CREDIT CYCLE 1
1954:3 TO 1958:1
CREDIT CYCLE 2
1958:2 TO 1060:4
CREDIT CYCLE 3
1961:1 TO 1967:1
CREDIT CYCLE 4
1967:2 TO 1970:3
CREDIT CYCLE 5
1970:4 TO 1974:4
-------
Exhibit IV-7
NET INCREASE IN FINANCIAL LIABILITIES BY YEAR
Major Economic Sectors
1960-1974
(billions of dollars)
Household Borrowing
Residential Home Mortgages
Consumer Credit
Government Borrowing
U.S. Treasury Securities
State/Local
Government Securities
Corporate Business
(non- financial)
External Funds Raised
1960
$10.8
4.6
(2.2)
5.3
9.7
1961
$10.9
0.8
6.7
5.1
13.7
1962
$12.7
5.8
6.2
5.4
13.4
1963
$14.8
7.9
4.1
5.7
13.7
1964
$16.0
8.5
5.4
6.0
15.0
1965
$15.2
9.6
1.3
7.3
22.6
1966
$12.7
6.3
2.3
5.6
25.6
1967
$10.4
4.5
8.9
7.8
24.9
1968
$14.6
10.0
10.3
9.5
34.4
1969
$16.1
10.4
(1-3)
9.9
35.6
1970
$12.5
6.0
12.9
11.3
35.8
1971
$24.2
11.2
26.0
17.5
48.8
1972
$38.4
19.1
13.9
13.8
55.2
1973
$44.2
22.9
7.7
11.9
69.5
1974
$32,6
9.6
12.0
15.7
81.5
I
00
00
list borrowing of the Treasury. A substantial fraction of this debt is purchased by U.S. Trust Funds and the Federal Reserve,
and thus these numbers overstate the "net borrowing of the Federal Government sector." On the other hand, many Federal
agencies have borrowed heavily in recent years. Beaause most of this Federal agency borrowing is "recycled" to the mortgage
market, it is excluded here.
Source: Flow of Funds Statistics. Board of Governors of
the Federal Reserve System, Third Quarter 1975
-------
EXHIBIT IV-8
CORPORATE BUSINESS DEBT FINANCING
AS A PERCENT OF TOTAL PRIVATE SECTOR DEBT FINANCING1
THIRD QUARTER 1954 TO THIRD QUARTER 1974
CREDIT CYCLE 1
1954:3 TO 1958:1
CREDIT CYCLE 2
1958:2 TO 1960:4
CREDIT CYCLE 3
1961:1 TO 1967:1
CREDIT CYCLE 4
1967:2 TO 1970:3
CREDIT CYCLE 5
1970:4 TO 1974:3
•^SPECIFICALLY, THE INCREASE IN CORPORATE SHORT-TERMS AND LONG-TERM DEBT AS A PERCENT OF THE
INCREASE IN CORPORATE SHORT-TERM AND LONG-TERM DEBT PLUS HOME MORTGAGE, FINANCING PLUS
CONSUMER CERDIT.
-------
Exhibit 1V-9
PROJECTIONS OF FUTURE SOURCES AND USES OF FUNDS
Domestic Non-Financial Business Corporations
(all projections are shown as a percent of GNP averaged over a prospective credit cycle)
Total Financing Need
Plant & Equipment
Residential Construction
Inventories
Net Financial Assets
Discrepancy
Total Sources of Funds
Funds Generated Internally
Adjusted Retained Earnings
Depreciation
External Funds Raised
Increase in Liquid Financial Assets
Net External Funds Required
Scenario 1
8.8
0.3
0.8
1.2
1.0
•
6.6
1.3
5.3
5.5
0.5
5.0
Scenario 2
8.8
0.3
0.8
1.2
1.0
7.8
2.5
5.3
4.3
0.5
3.8
Scenario 3
7.2
0.3
0.7
1.2
1.0
7.5
2.5
5.0
2.9
0.5
2.4
to
o
Source: TBS projections
-------
Exhibit IV-10
SAVINGS BEHAVIOR OF U.S. HOUSEHOLDS
(all data as percent of GNP averaged over a credit cycle)
Net Savings
Net Increase In
Residential Construction!
Net Financial
Investment?
Credit Cycle 1
1954:3 to 1958:1
6.3
3.8
2.5
Credit Cycle 2
1958:2 to 1960:4
5.8
3.1
2.7
Credit Cycle 3
1961:1 to 1967:1
5.4
1.9
3.5
Credit Cycle 4
1967:2 to 1970:3
5.5
1.3
4.2
Credit Cycle 5
1970:4 to 1974:4
6.6
1.8
4.8
1
Net Increase in Residential Construction is the dollar value of newly constructed 1- to 4-family homes purchased by
households, minus the depreciation imputed to the existing stock of such homes owned by households. It does not
include changes in the market value of existing homes.
Net Financial Investment is the dollar value of the net purchase of financial assets minus the dollar value of the net
increases in financial liabilities for all households.
<
Source: Federal Reserve Flow of Funds data, second quarter 1975
-------
Exhibit I.V-11
PROJECTIOKS OF TOTAL CAPITAL NEEDS BY YEAR
Domestic Non-Financial Business Corporations
1975-1985
(billions of 1975 dollars)1
Assumptions for:
Real GNP Growth
Level of Plant and Equipment Investment
Level of Retained Earnings
Total Corporate Capital Raised, as % of GNP
Scenario 1
3.5%
High
Low
5.0%
Scenario 2
3.5%
High
High
3.8%
Scenario 3
3.0%
Low
High
2.4%
Scenario 1
GNP
(3.5% growth)
Total Corporate
Capital Raised
(5% GNP)
Scenario 2
GNP
(3.5% growth)
Total Corporate
Capital Raised
(3.8% GNP)
Scenario 3
GNP
(3.0% growth)
Total Corporate
Capital Raised
(2.4% GNP)
1975
1,582
79
1,582
60
1,574
38
1976
1,638
82
1,638
62
1,622
39
1977
1,695
85
1,695
64
1,670
40
1978
1,754
88
1,754
67
1,720
41
1979
1,816
91
1,816
69
1,772
43
1980
1,878
94
1,878
71
1,824
44
1981
1,945
97
1,945
74
1,880
45
1982
2,013
101
2,013
76
1,936
46
1983
2,084
104
2,084
79
1,994
48
1984
2,157
108
2,157
82
2,054
49
1985
2,233
112
2,233
85
2,116
51
Cumulative
1975-1985
20,795
1,041
20,795
789
20 , 162
484
(O
to
1975 dollars assumed
Note: Results assume
to include 9.5 percent inflation over 1974 dollars.
14 percent return on equity.
-------
IV-93
Exhibit IV-12
NET INCOME
Privately Owned Class A&B Electric Utilities in the United States
Electric Department
1960-1974
Year
1960
1961
1962
1963
1964
1965
1961-1965
Growth Rate
1966
1967
1968
1969
1970
1971
1972
1973
1966-1973
Growth Rate
1974
1973-1974
Growth Rate
Net Income
(in millions)
$1,647
1,731
1,887
1,973
2,189
2,363
7.4%
2,516
2,661
2,764
2,962
3,141
3,516
4,110
4,680
8.2%
4,776
2.0%
Note: Income statement data for this exhibit (and others that
pertain to the electric department of combination utilities)
have been adjusted to reflect electric department only as
follows:
1. Interest has been prorated by ratio of net electric
utility plant to net total gas and electric plant, and
2. Allowance for funds during construction (AFDC) has
been prorated by ratio of the change in gross
electric plant to the change in total gross gas
and electric plant.
Source: Statistics of Privately Owned Electric Utilities in the
United States, Federal Power Commission, 1967,1972,
1973 and preliminary 1974
-------
Exhibit IV-13
EARNINGS AND DIVIDENDS
Privately Owned Class A&B Electric Utilities in the United States
Electric Department
1960-1974
(1)
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
(2)
Net Income After
Preferred Dividends
(millions)
1,473
1,550
1,702
1,786
2,001
2,171
2,319
2,440
2,511
2,682
2,810
3,062
3,520
3,948
3,885
(3)
Common Stock
Dividends*
(millions)
$1,008
1,061
1,135
1,233
1,324
1,484
1,544
1,643
1,739
1,824
1,973
2,143
2,304
2,641
2,853
(4)
Payout Ratio
(3)-r(2)
(%)
68.4
68.4
66.7
69.0
66.2
68.3
66.6
67.3
69.2
68.0
70.2
70.0
65.4
66.9
73.4
(5)
Earnings
Per Share
$4 . 12
4.33
4.73
4.99
5.41
5.92
6.30
6.67
6.67
6.92
6.89
7.14
7.73
7.55
7.63
(6)
Return on
Common Equity
(%)
11.6
11.5
11.9 '
11.8
12.5
12.8
13.0
13.0
12.6
12.7
11.9
11.6
11.9
11.7
11.0
<
CO
*Common stock dividends pro rated by ratio of net electric utility plant to net plant.
Source: Statistics of Privately Owned Electric Utilities in the United States.
Federal Power Commission, 1967, 1972, 1973, and preliminary 1974;
Earnings per Share: Survey of Current Business.
-------
IV-95
Exhibit IV-14
ASSETS PER DOLLAR OF REVENUE
Privately Owned Class A&B Electric Utilities in the United States
Electric Department
1960-1974
(1)
Year
1960
1961
1962
1963
1964
1965
1961-1965
Growth Rate
1966
1967
1968
1969
1970
1971
1972
1973
1966-1973
Growth Rate
1974
1973-1974
Growth Rate
(2)
Gross
Electric Plant
Investment
(millions)
$ 45,456
48,090
50,699
53,474
56,326
59,703
5.6%
64 , 066
69,617
76,026
83,671
93,303
104,300
116,644
130,840
10 . 3%
146,007
11.5%
(3)
Operating
Revenues
(millions)
$ 10,116
10,666
11,392
12 , 018
12,673
13,400
5.8%
14,374
15,225
16,359
18,023
19,791
22,322
25,355
29,104
10.2%
37,225
27.5%
(4)
Gross Plant
Per Dollar Of
Revenue
(2)f(3)
$ 4.49
4.51
4.45
4.45
4.44 >
4.46
--
4.46
4.57
4.60
4.64
4.71
4.67
4.60
4.50
•
3.92
—
Source: Statistics of Privately Owned Electric Utilities
in the United States, Federal Power Commission,
1967, 1972, 1973, and preliminary 1974.
-------
Exhibit IV-15
ANNUAL CAPITAL EXPENDITURES VS. TOTAL ASSETS
Privately Owned Electric Utilities in the United States
Electric and Gas Departments
1961-1974
(1)
Year
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
(2)
Annual Capital
Expenditures
(millions)
3,256
3,154
3,319
3,551
4,027
4,932
6,120
7,140
8,294
10,145
11,894
13,385
14,907
16 , 350
(3)
Total
Assets
(millions)
(beginning of year)
44,488
46 , 894
49,183
51,256
53,627
56,313
60,259
65,085
70,976
77,794
87,220
98,045
110,616
124,796
(4)
Percentage
(2)-=-(3)
7.3
6.7
6.7
6.9
7.5
8.8
10.2
11.0
11.7
13.0
13.6
13.7
13.5
13.1
I
(0
OJ
Source: Statistical Yearbook of the Electric Utility Industry,
Edison Electric Institute, 1974
-------
Exhibit IV-16a
SOURCES OF FUNDS
Privately Owned Class A&B Electric Utilities in the United States
Electric and Gas Departments
1960-1974
(millions of dollars)
(1)
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
External Funds
(2)
Common
Stock
130
294
243
181
272
105
148
185
326
744
1,411
2,063
2,282
2,552
1,951
(3)
Preferred
Stock
201
153
201
108
184
208
253
453
461
381
1,147
1,851
2,104
1,629
1,809
(4)
Long-Term
Debt
1,471
1,196
1,356
1,323
1,177
1,328
2,322
2,691
3,046
3,750
5,674
5,455
4,330
5,082
8,428
(5)
Short-Term
Debt
9
(28)
(120)
110
52
348
185
428
481
844
(104)
136
132
1,087
2,578
(6)
Total
1,811
1,615
1,680
1,721
1,685
1,989
2,908
3,757
4,314
5,719
8,128
9,505
8,848
10,350
14 , 766
Internal Funds
(7)
Retained
Earnings
468
495
586
632
731
814
861
893
843
943
950
1,090
1,319
1,427
1,328
(8)
Deferred
Taxes
188
170
161
143
125
115
111
135
163
163
136
293
697
718
1,002
(9)
Depreciation
and
Amortization
1,197
1,298
1,400
1,502
1,585
1,686
1,782
1,902
2,044
2,206
2,411
2,639
2,920
3,270
3,638
(10)
Total
1,853
1,963
2,147
2,277
2,441
2,615
2,754
2,930
3,050
3,312
3,497
4,022
4,936
5,415
5,968
(11)
Total
Funds
3,664
3,578
3,827
3,998
4,126
4,604
5,662
6,687
7,364
9,031
11,625
13,527
13,784
15,765
20 . 734
Compound
Growth Rate
1961-
1965 (4.2)% 0.7 (2.0) 107.7 1.9 11.7 (9.4) 7.1 7.1 4.7
1966-
1973 49.0% 29.3 18.3 15.3 22.9 7.3 25.7 8.6 9.5 16.6
1973-
1974 (24.6)% 11.0 65.8 137.2 42.7 (6.9) 39.5 11.2 10.2 31.5
-------
Exhibit IV-16b
SOURCES OF FUNDS
Privately Owned Class A&B Electric Utilities in the United States
Electric and Gas Departments
1960-1974
(percentages of total funds)
(1)
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
External Funds
(2)
Common •
Stock
3.5
8.2
6.3
4.5
6.6
2:3
2.6
2.8
4.4
8.2
12.1
15.3
16.5
16.2
9.4
(3)
Preferred
Stock
5.5
4.3
5.3
2.7
4.4
4.5
4.5
6.8
6.3
4.2
9.9
13.7
15.3
10.3
8.7
(4)
Long-Term
Debt
40.2
33.4
35.4
33.1
28.5
28.8
41.0
40.2
41.4
41.5
48.8
40.3
31.4
32.2
40.6
(5)
Short -Term
Debt
0.2
(0.8)
(3.1)
2.7
1.3
7.6
3.3
6.4
6.5
9.4
(0.9)
1.0
1.0
6.9
12,4
(6)
Total
49.4
45.1
43.9
43.0
40.8
43.2
51.4
56.2
58.6
63.3
69.9
70.3
64.2
65.6
71.2
Internal
(7)
Retained
Earnings
12.8
13.8
15.3
15.8
17.7
17.7
15.2
13.4
11.4
10.5
8.2
8.0
9.6
9.1
6.4
(8)
Deferred
Taxes
5.1
4.8
4.2
3.6
3.0
2.5
2.0
2.0
2.2
1.8
1.2
2.2
5.0
4.6
4.8
Funds
(9)
Depreciation
and
Amortization
32.7
36.3
36.6
37.6
38.4
36.6
31.5
28.4
27.8
24.4
20.7
19.5
21.2
20.7
17.5
(10)
Total
50.6
54.9
56.1
57.0
59.2
56.8
48.6
43.8
41.4
36.7
30.1
29.7
35.8
34.4
28.8
Source:
Statistical Yearbook of the Electric Utility Industry,
Edison Electric Institute, 1974; Column 5: Federal Power Commission
<
I
Ofi
-------
Exhibit IV-17
CAPITAL STRUCTURE
Privately Owned Class A&B Electric Utilities in the United States
Electric and Gas Departments
1960-1974
(1)
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
(2)
Total
Capitalization
(thousands)
$ 39,840,396
41,743,950
43,707,948
45,335,842
47,499,663
49,505,579
53,053,664
57,261,741
62,267,112
67,949,800
76,482,105
86,178,101
97,080,398
108,347,163
121,686,000
(3) (4) (5)
Common E a u i * 2
Common Stock Retained Total
and Surplus Earnings (3)+(4)
% %
27.1
27.2
27.1
27.7
27.8
27.5
26.1
25.2
24.1
23.4
23.2
23.3
23.5
24.2
23.9
9.4
9.6
10.2
10.2
10.8
11.5
12.1
12.2
12.5
12.6
12.2
11.8
11.6
11.4
10.9
%
36.5
36.8
37.3
37.9
38.6
39.0
38.2
37.4
36.6
36.0
35.4
35.1
35.1
35.6
34.8
(6)
Preferred
Stock
%
10.7
10.4
10.3
10.0
9.6
9.5
9.5
9.6
9.6
9.4
9.8
10.7
11.8
12.1
12.2
(7)
Long-Term
Debt
%
52.8
52.8
52.4
52.1
51.8
51.5
52.3
53.0
53.8
54.6
54.8
54.2
i— i
<
i
-------
Exhibit IV-18
LONG- AND SHORT-TERM"DEBT
Privately Owned Class A&B Electric Utilities in the .United States
Electric and Gas Departments
1960-1974
(!>
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1965-
1974
(2) (3)
Annual
%
Total Debt Change
(thousands)
21,539,601 6.0%
22,475,643 4.3
23,270,077 3.5
24,099,215 3.6
25,107,947 4.2
26,369,789 5.0
28,781,345 9.1
31,838,701 10.6
35,480,498 11.4
39,877,367 12.4
44,639,345 11.9
49,545,612 11.0
54,523,145 10.0
60,821,246 11-6
71,135,000 17.0
(4) (5) (6)
% of
Total Annual
Long-Term Debt %
Debt (4)^-(2) Change
(thousands)
21,034,917 97.7% 8.9%
22,028,356 98.0 4.7
22,912,188 98.5 4.0
23,631,832 98.1 3.1
24,588,965 97.9 4.1
25,502,451 96.7 3.7
27,728,493 96.3 8.7
30,358,468 95.4 9.5
33,519,443 94.5 10.4
37,071,763 93.0 10.6
41,937,530 93.9 13.1
46,707,745 94.3 11.4
51,553,127 94.6 10.4
56,763,481 93.3 10.1
64,499,000 90.7 13.6
Average Annual Increase 8.1%
Ten- Year Average 11.0%
(7) (8) (9)
% of
Total Annual
Short-Term Debt %
Debt (7)f(2) Change
(thousands)
504,684 2.3% 1.9%
447,287 2.0 (11.4)
357,889 1.5 (20.0)
467,383 1.9 30.6
518,982 2.1 11.0
867,338 3.3 67.1
1,052,852 3.7 21.4
1,480,233 4.6 40.6
1,961,055 5.5 32.5
2,805,604 7.0 43.1
2,701,815 6.1 (3.7)
2,837,867 5.7 5.0
2,970,018 5.4 4.7
4,057,765 6.7 36.6
6,636,000 9.3 63.5
w
<
\
H*
O
O
Source: Statistics of Privately Owned Electric Utilities in the United States.
Federal Power Commission, 1967, 1972, 1973, and preliminary 1974.
-------
Exhibit IV-19
MARKET VALUE VS. BOOK VALUE AND PRICE/EARNINGS COMPARISONS
Moody's Public Utility Index
1960-1974
(1)
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
197 r
1972
1973
1974
(2)
k Moody' s Public
Market Value
76.82
99.32
96.49
102.31
115.54
114.86
105.99
98.19
104.04
84.62
88.59
85.56
83.61
60.87
41.17
(3)
Utility Index
Book Value
41.20
42.95
44.88
47.91
50.69
52.68
54.53
57.53
60.97
63.90
67.75
70.24
75.05
76.84
79.94
(4)
Market
to Book
Ratio
1.86
2.31
2.15
2.14
2.28
2.18
1.94
1.71
1.66
1.32
1.31
1.22
1.11
0.79
0.52
(5)
Year-end
Price/Earnings
Ratio
18.6
22.9
20.4
20.5
21.4
19.4
16.8
14.7
15.5
12.2
12.9
12.0
10.8
8.1
5.4
o
I
Source: Moody's Public Utility. Manual, 1975 edition, pages 11-13
-------
Exhibit IV-20
EXTERNAL SOURCES OF FUNDS
Privately Owned Class A&B Electric Utilities in the United States
Electric and Gas Departments
1960-1974
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
Common
Stock
as % of
External Funds
7.1
17.9
13.4
11.2
16.7
6.5
5.4
5.6
8.4
15.2
17.1
22.1
26.1
27.6
16.0
Preferred
Stock
as % of
External Funds
11.2
9.4
11.3
6.7
11.1
12.6
9.4
13.7
12.1
7.8
14.0
19.8
24.2
17.5
14.8
Debt
as % of
External Funds
81.7
72.8
75.3
82.1
72.2
80.9
85.2
80.7
79.5
77.0
68.9
58.1
49.7
54.9
69.2
External
Funds as %
of Total Funds
49.2
45.9
47.0
40.3
39.5
35.6
48.1
49.8
52.1
53.9
70.8
69.3
63.2
58.7
58.7
O
to
Source: Statistical Yearbook of the Electric Utility Industry, Edison
Electric Institute, 1974
-------
IV-103
Exhibit IV-21
YIELD AND YIELD SPREADS OF Aa UTILITY BONDS
1960-1975
(Average for Year)
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
Aa
New Utility
Deferred
Call
%
4.73
4.52
4.36
4.33
4.46
4.57
5.45
5.87
6.61
7.75
8.83
7.74
7.45
7.74
9.27
9.51
Long-Term
Government
Bonds
%
4.07
3.94
4.06
4.08
4.21
4.26
4.72
4.93
5.40
6.28
6.82
6.12
5.95
7.00
7.98
8.25
Yield Spread
(Basis Points
+66
+58
+30
+25
+25
+31
+73
+93
+121
+147
+ 301
+162
+150
+ 74
+ 129
+ 126
Source: Salomon Bros. Analytical Record. December 1975.
-------
Exhibit IV-22
INTEREST CHARGE COVERAGE
Privately Owned Class A&B Electric Utilities in the United States
Electric Department
1960-1974
(dollars in millions)
(1)
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
(2)
Income Before
Interest & Taxes
$ 3,535
3,772
4,016
4,207
4,486
4,685
4,969
5,183
5,588
5,904
5,964
6,454
7,366
8,391
9,058
(3)
Interest*
$ 692
735
779
845
843
890
986
1,132
1,341
1,642
2,044
2,401
2,774
3,264
4,197
(4)
- %
Coverage
5.1
5.1
5.2
5.0
5.3
5.3
5.0
4.6
4.2
3.6
2.9
2.7
2.7
2.6
2.2
*Total interest charges, including that on
short-term obligations
Source: Statistics of Privately Owned Electric Utilities in
the United States, Federal Power Commission, 1967,
1972, 1973, and preliminary 1974
M
-------
Exhibit IV-23
EMBEDDED INTEREST RATE ON LONG-TERM DEBT
Privately Owned Class A&B Electric Utilities in the United States
Electric Department
1960-1974
(dollars in millions)
(1)
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
(2)
Interest
$ 668
705
757
819
813
857
933
1,061
1,240
1,473
1,874
2,236
2,613
2,984
3,606
(3)
Average
LonR-Term Debt
$ 18,466
19,453
20,290
20,991
21,698
22,515
23,926
26,155
28,875
32,052
36,033
40,627
45,254
50,163
56,527
(4)
Embedded
Rate
3.62
3.62
3.73
3.90
3.75
3.81
3.90
4.06
4.29
4.60
5.20
5.50
5.77
5.95
6.38
<
I
Source: Statistics of Privately Owned Electric Utilities in the
United St.iitos. Fcdoral Powpr Commission. 1967, 1972, and 1973; TBS estimate
-------
Exhibit IV-24
AU4V4KCH FOB FUNDS USED PUB I NO CONSTRUCTION
VS. CAPITAL EXPENDITURES
Privately Owned Class A&B Electric Utilities in the United States
Electric Department
1960-1974
(1)
Year
1960
1961
1962
1963
1964
1965
1966
1907
1968
1969
1970
1971
1972
1973
1974
(2)
AFDC*
(millions)
$ 90
76
80
69
72
84
114
171
259
383
548
770
1,011
1,187
1,491
(3)
Capital
Expenditures
(millions)
$ 3,331
3,256
3,154
3,319
3,551
4t027
4,932
G , 1 20
7,140
8,294
10,145
11,894
13,385
14,907
16,350
(4)
Percentage
(2)4- (3)
2.70
2.33
2.54
2.08
2.03
2.09
2.:u
:>..i\i
3.(!3
4.02
5.40
6.47
7 . 55
7.96
9.12
(5)
Net Income
After Preferred
Dividends
(millions)
$1,473
1,550
1,702
1,786
2,001
2,171
2,319
2,440
2,511
2,682
2,810
3,062
3,520
3,948
3,885
(6)
AFDC* as
Percent Of
Column (5)
(2) v (5)
6.0
4.9
4.5
3.6
3.6
3.8
4.9
7.0
10.3
14.3
19.8
25.6
29.4
31.8
38.4
^Allowance for Funds During Construction
Source: Columns (2) and (5):Statistics of Privately Owned Electric
Utilities in the United States, Federal Power Commission,
1967, 1972, 1973, and preliminary 1974.
I
(-*
O
Column (3): Statistical Yearbook of the Electric Utility Industry,
Kdison Electric Institute, 1974.
-------
IV-107
Exhibit IV-25
ELECTRIC UTILITY NEW PLANT AND EQUIPMENT EXPENDITURES
VS. ALL INDUSTRY PLANT AND EQUIPMENT EXPENDITURES
Privately Owned Electric Utilities in the United States
1960-1974
(dollars in billions)
(1)
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
(2)
Electric Utility
Capital
Expenditures
$ 3.33
3.26
3.15
3.32
3.55
4.03
4.93
6.12
7.14
8.29
10.15
11.89
13.39
14.91
16.35
(3)
All Industry
Expenditures
$ 34.6
32.9
36.6
38.2
43.7
52.3
61.1
61.9
66.5
74.0
75.1
77.1
87.1
103.3
111.7
(4)
Percent
(2)f (3)
9.62
9.91
8.61 !
8.69
8.12
7.71 i
8.07 ;
1
8.24 !
10.74 :
11.20 i
j
13.52 !
15.42 1
15.37 |
14.43 |
14 . 64 !
,]
Source: Column (2):
Edison Electric Institute, Statistical Yearbook of
the Electric Utility Industry, 1974
Column (3)
Board of Governors of the Federal Reserve System,
Flow of Funds Statistics
-------
Exhibit IV-26
NBT PIMAHCIUC ELECTRIC UTILTITY INDUSTRY
VS. ROJJ-FIHAHCIAL BUSINESS CORPORATIONS
Privately Owned Electric Utilities in the United States
Electric & Gas Departments
1960-1974
(billions of dollars)
(1)
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
(2)
(3)
(4)
Equity
Non-Financial
Business
Corporation
1.5
2.2
.4
-.6
1.3
-.1
1.1
2.2
-.2
3.4
5.7
11.4
10.9
7.4
4.1
Total
Electric
Utilities
.3
.4
.4
.3
.5
.3
.4
.6
.8
1.1
2.5
3.9
4.4
4.2
3.8
342
(%)
20
18
100
—
38
—
36
27
—
32
44
34
40
57
93
(5)
(6)
(7)
Long-Term Debt
Non-Financial
Business
Corporation
6.0
8.6
9.1
8.8
7.6
9.3
14.4
19.2
18.6
16.6
24.7
30.1
28.3
27.1
32.2
Total
Electric
Utilities
1.5
1.2
1.4
1.3
1.2
1.3
2.3
2.7
3.0
3.7
5.7
5.5
4.3
5.1
8.4
645
(%)
25
14
15
15
16
14
16
14
16
22
23
18
15
19
26
(8)
(9)
(10)
Short -Term Debt
Non-Financial
Business
Corporation
4.3
1.4
3.0
3.9
5.6
11 ! 2
9.9
8.2
13.2
18.8
8.9
5.0
16.0
32.6
40.9
Total
Electric
Utilities
*
*
(.1)
.1
.1
.4
.2
.4
.5
.8
(.1)
.1
.2
1.1
2.6
948
(%)
1
(1)
(3)
3
2
4
2
5
4
4
(1)
2
1
3
6
(11)
(12)
(13)
Total
Non-Financial
Business
Corporation
11.9
12.3
12.5
12.1
14.5
20.4
25.4
29.6
31.5
38.9
39.5
46.8
55.3
67.2
77.2
Total
Electric
Utilities
1.8
1.6
1.7
1.7
1.8
2.0
2.9
3.7
4.3
5.6
8.1
9.5
8.9
10.4
14.8
1U4- 11
(%)
15
13
14
14
12
10
11
13
14
14
21
20
16
15
19
O
00
*less than .05
Source: Federal Reserve Board, Flow of Funds Statistics; Edison Electric Institute, Statistical Yearbook of the
Electric Utility Industry. 1974; Federal Power Commission
-------
Exhibit IV-27
GROSS EQUITY FINANCING ELECTRIC UTILITY INDUSTRY
VS. TOTAL PRIVATE SECTOR
Privately Owned Electric Utilities in the United States
Electric and Gas Departments
1960-1974
(dollars in billions)
(1)
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
Common Stock
(2)
Total
Private
Sector
$ 1,664
3,294
1,314
1,011
2,679
1,547
1,939
1,959
3,946
7,714
7,240
10,459
9,914
7,648
4,017
(3)
Total
Electric
Utilities
5 130
294
243
181
272
105
148
185
326
744
1,411
2,063
.2,281
2,552
1,951
(4)
(3) 4 (2)
%
7.8
8.9
18.5
17.9
10.2
6.9
7.6
9.4
8.3
9.6
19.5
19.7
23.0
33.4
48.6
Preferred Stock
(5)
Total
Private
Sector
3 409
450
422
343
412
725
574
885
637
682
1,290
3,683
3,372
3,375
2,224
(6)
Total
Electric
Utilities
0 201
153
201
108
184
208
253
453
461
381
1,147
1,851
2,104
1,629
1,809
(7)
(6) T (5)
%
49.1
34.0
47.6
31.5
44,7
28.7
44.1
51.2
72.4
55.9
82.5
50.3
62.4
48.3
81.3
Note: The entries in columns (2) and (5) represent gross private sector financing.
This includes funds raised by financial intermediaries, and has no offsetting
entries for reduction in equity, capital through mergers, acquisitions,
liquidations, etc.
Source: Columns (2) and (5): Business Statistics 1973 and Survey of Current
Business, U.S. Department of Commerce, October 1975.
O
CO
Columns (3) and (6): Statistical Yearbgojc^of^jthe Elect rif.
Industry for 1972. Edison Electric Institute, 1974.
-------
IV-110
Exhibit IV-28
DOWNGRADING OF ELECTRIC UTILITY SECURITIES
1965-July 1974
(1)
Y«ar
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
Total
(2)
Total
Actions
0
8
0
6
6
4
5
4
2
31
66
(3)
Aaa
to
Aa
__
2
—
3
2
2
1
1
—
1
12
(4)
Aa
to
A
_._
6
—
3
4
2
1
1
2
12
31
(5)
A
to
Baa
__
—
—
—
—
—
3
2
—
11
16
(6)
Baa
to
Ba
__
—
—
—
—
—
—
--
--
1
1
(7)
Suspended
— —
—
—
—
• —
-„
—
—
--
6
6
Source.: Moody*s Public Utility Manual taken from a
compilation by the Office of Accounting and
Finance, Federal Power Commission.
-------
Exhibit IV-29
ISSUE AND RECENT MARKET PRICES—
15 RECENT ELECTRIC UTILITY BOND ISSUES
Ratine
Aaa
. Aa
Aa
Aa
Aa
Aa
Aa
Aa
Aa
A
A
A
Baa
Baa
Baa
Issue
Date
(1974) Issue
10/2 Texas P&L 10-1/8-2004
9/5 Illinois Power 10-1/2-2004
9/11 Northern Indiana P.S. 10.40-2-004
9/12 Baltimore G&E 10-1/8-1983
10/3 Public Service Elec.& Gas. 12-2004
10/2 Pa. P&L 10-1/8-82
10/31 So. Calif .Edison 9-1981
11/14 West Penn. Power 9-1/4-2004
11/7 Long Island Lighting 9-1/4-1982
10/17 Philadelphia Electric 11-1980
10/22 Dayton P&L 10-1/8-1981
10/30 Louisiana P&L 9-1/2-1981
10/29 Ohio Power 12-1/8-1981
10/30 Jersey Central P&L 12-3/8-1979
11/7 Puget Sound f'&L 10-3/4-1983
Offered
Price
100(plus Int.)
100(plus Int.)
100
99-5/8
100(plus Int.)
100(plus Int.)
99-l/2(plus Int. )
101(plus Int.)
100(plus Int.)
100(plus Int.)
100(plus Int.)
101(plus Int. )
100-5/8(plus Int.. )
101-3/4
100-1/4,
Yield
10.125
10.50
10.40
10 . 19
12.00
10.125
9.10
8.88
9.25
11.00
10.125
9.30
12.00
11.90
10.70
Nov. 22, 1974
or
Last Trade
107
106-3/4
106
103-1/2
108-1/2
104-3/8
103-3/4-101-1/4
96-1/2-97
100-100-1/2
102-1/2
100-1/2-101-1/4
100-3/4
103 Bid
103-1/8
101-1/2
Yield
9.42
9.80
9.78
9.54
11.02
9.34
8.52
9.58
9.21
10.93
9.95
9.35
11.49
11.54
10.49
<
I
Source: Moody's Public Utility Weekly Supplements,1974 Issues.
Wall Street Journal, November 25, 1974
-------
IV-112
Exhibit IV-30
PROJECTIONS OF EXTERNAL FINANCING REQUIREMENTS
FOR INVESTOR-OWNED ELECTRIC UTILITIES
1975-1985
(billions of 1975 dollars)
1975
1976
1977
1978
1979
1980
Subtotal
1981
1982
1983
1984
1985
Subtotal
Total
Before
Consideration of
Pollution Control
11.7
10.9
12.1
12.2
12.9
13.2
73.0
12.8
14.2
15.5
18.0
21.5
82.0
155.0
Required
for Pollution
Control
1.6
1.9
2.1
2.5
2.7
2.2
13.0
1.4
1.0
1.1
1.2
1.6
6.3
19.3
Total
13.3
12.8
14.2
14.7
15.6
15.4
86.0
14.2
15.2
16.6
19.2
23.1
88.3
174.3
Note: Results assume 14 percent return on equity,
Source: PTm (Electric Utilities)
-------
IV-113
EXHIBIT IV-31
ILLUSTRATION OF ELECTRIC UTILITY AND CORPORATE NET EXTERNAL FUNDS REQUIRED
AS PERCENT OF NET SAVINGS IN THE HOUSEHOLD SECTOR
CREDIT
CYCLE 3
CREDIT
CYCLE 1
CREDIT
CYCLE 5
PROJECTED
CREDIT CYCLE*
46*
i.5%
'.58
87,
11.
83% SCENARIO 1
63% SCENARIO 2
40% SCENARIO 3
ELECTRIC
12,5% UTILITY
NET EXTERNAL
FUNDS RAISED**
HOUSEHOLD NET SAVINGS RATE IS ASSUMED TO BE 6% OF GNP.
•'HISTORICAL ELECTRIC UTILITY FINANCING ESTIMATED FROM CALENDAR YEAR
DATA. PROJECTIONS BASED ON 3.5% GNP GROWTH, UPPER LINE INCLUDES
POLLUTION CONTROL FINANCING.
KEY:
GOVERNMENT FINANCING AND
NEW HOME CONSTRUCTION
CORPORATE NET EXTERNAL
FUNDS REQUIRED
ELECTRIC UTILITY
NET EXTERNAL FUNDS
RAISED**
-------
IV-114
Exhibit IV-32
INTEREST COVERAGE PROJECTIONS BEFORE POLLUTION CONTROL FINANCING
FOR INVESTOR-OWNED ELECTRIC UTILITIES
(billions of 1975 dollars)
Allowance for Funds During
Construction (AFDC)
Earnings Before Interest and Taxes
Interest on Long-Term Debt
State and Federal Income Taxes
Preferred Dividends
Earnings Available to Common Stock
Interest Coverage:
Including AFDC
Excluding AFDC
1980
2.3
20.6
7.3
4.7
1.2
7.3
2.8
2.5
1985
3.6
28.7
10.6
6.6
1.9
9.8
2.7
2.4
on long-term debt only
Note: Results assume 14 percent return on equity.
Source: PTm (Electric Utilities)
-------
IV-115
Exhibit IV-33
INTEREST COVERAGE IMPLICATIONS OF POLLUTION CONTROL FINANCING
FOR INVESTOR-OWNED ELECTRIC UTILITIES
WITH HISTORIC CAPITAL MIX
(billions of 1975 dollars)
Allowance for Funds During
Construction (AFDC)
Earnings Before Interest and Taxes
Interest on Long-Term Debt
State and Federal Income Taxes
Preferred Dividends
Earnings Available to Common Stock
Interest Coverage:
Including AFDC
Excluding AFDC
1980
2.6
22.3
8.0
4.9
1.4
8.0
2.8
2.5
1985
3.8
31.2
11.5
7.2
2.0
10.5
2.7
2.4
on long-term debt only
Note: Results assume 14 percent return on equity.
Source: PTm (Electric Utilities)
-------
IV-116
Exhibit IV-34 ;v
INTEREST COVERAGE IMPLICATIONS OF POLLUTION CONTROL FINANCING
FOR INVESTOR-OWNED ELECTRIC UTILITIES
WITH EQUITY ONLY
(billions of 1975 dollars)
Allowance for Funds During
Construction (AFDC)
Earnings Before Interest and Taxes
Interest on Long-Term Debt
State and Federal Income Taxes
Preferred Dividends
Earnings Available to Common Stock
Interest Coverage:
Including AFDC
Excluding AFDC
1980
2.6
23.4
7.3
5.7
1.4
9.1
3.2
2.9
1985
3.8
32.9
10.6
8.1
2.0
12.3
3.1
2.7
on long-term debt only
Note: Results assume 14 percent return on equity.
Source: PTm (Electric Utilities)
-------
IV-117
Exhibit IV-35
INTEREST COVERAGE IMPLICATIONS OF POLLUTION CONTROL FINANCING
FOR INVESTOR-OWNED ELECTRIC UTILITIES
WITH INDUSTRIAL REVENUE BONDS AT 6.6 PERCENT
(billions of 1975 dollars)
Allowance for Funds During
Construction (AFDC)
Earnings Before Interest and Taxes
Interest on Long-Term Debt
State and Federal Income Taxes
Preferred Dividends
Earnings Available to Common Stock
Interest Coverage:
Including AFDC
Excluding AFDC
1980
2.6
21.5
8.2
4.7
1.2
7.3
2.6
2.3
1985
3.8
30.0
11.9
6.6
1.9
9.6
2.5
2.2
on long-term debt only
Note: Results assume 14 percent return on equity,
Source: PTm (Electric Utilities)
-------
Exhibit IV-36
DETERMINANTS OF INTEREST COVERAGE RATIOS
Assumptions
Capital Structure
Debt
Preferred
Common
Capital Costs
Debt
Preferred
Common
Tax Rate
Income Statement
Required Earnings Before Interest and Taxes
Interest
Earnings Before Taxes
Tax
Net Income
Preferred Dividends
Income Available for Common
Interest Coverage Ratio
Cases
I
[ Base^
(Case/
$600
100
300
6%
6%
12%
25%
$ 92
36
$ 56
14
$ 42
6
$ 36
2.56
II
Higher \
Interest]
$600
100
300
10%
6%
12%
25%
$116
60
$ 56
14
$ 42
6
$ 36
1.93
III
[Lower\
\TaxesJ
$600
100
300
10%
6%
12%
0%
$102
60
$ 42
0
$ 42
6
$ 36
1.70
IV
fHighert
I ROE J
$600
100
300
10%
10%
16%
0%
$118
60
$ 58
0
$ 58
10
$ 48
1.97
V
(Less}
ipebtj
$550
100
350
10%
10%
16%
0%
$121
55
$ 66
0
$ 66
10
$ 56
2.20
00
-------
Exhibit IV-37
THE IMPACT OF AFDC ON INTEREST COVERAGE RATIOS
Cases
la
[ Base Case "\
With No AFDC
Ib
/ Base Case \
\With High AFDCj
Income Statement
Operating Income
Other Income (AFDC)
Required Earnings Before Interest and Taxes
Interest
Earnings Before Taxes
Tax
Net Income
Preferred Dividends
Income Available for Common
Income as Defined for Coverage
Interest Coverage Ratio
$ 92
$ 92
36
$ 56
14
$ 42
6
$ 36
$ 92
2.56
$ 62
30
$ 92
36
$ 56
14
.$ 42
6
$ 36
$ 68
1.89
Operating income plus other income up to 10 percent of operating income.
-------
IV-121
APPENDIX IV-A
THE EFFECTS OF ISSUING STOCK
AT DIFFERENT MARKET PRICES RELATIVE TO
BOOK VALUES
The following cases illustrate the earnings per
share consequences of issuing common stock at prices above
and below book value. For simplicity, we shall assume
throughout that the rate of return rg allowed by regulators
is 12 percent on the common equity base at the beginning of
any year and that the dividend payout ratio b is 70 percent.
Assuming for the moment that the industry or any given utility
issues no stock, the industry's total earnings and dividends
will grow at a rate g which is 3.6 percent. A 12 percent
return and a 30 percent retention of this amount (because
dividends are 70 percent of earnings) means that the industry's
common equity grows 3.6 percent per year, that earnings grow
3.6 percent (because the percentage return on equity is con-
stant), and that dividends grow at 3.6 percent (because the
payout ratio is constant). There is a well-known formula
for stock prices in constant growth situations of this sort
which can be written as:
0
Where:
stock price at time 0 relative to
book value;
dividends at time 0 relative to
book value; and
-------
IV-122
k » investors' required rate of return on
investment in stock of this risk class,
Dividends at time 0 can in turn be expressed
as a fraction of book value as follows:
DQ = EQ x b,
Where:
Eo = earnings at time 0 relative to
book value
Earnings relative to book value can in turn be written
simply as:
r
e,
Where:
r = the allowed rate of return on equity
6
If the required rate of return is 10 percent or
15 percent, then the industry's market price relative to
book value is 1.313 or 0.737, respectively. Given that we
have assumed no new issues of common stock, these ratios
hold on a per share basis as well.
Let us consider what happens if the industry's
capital expenditure requirements (or desires) are such as to
necessitate (or prompt) the one-time issuance of common stock,
For simplicity, we shall first assume that investors either
do not anticipate the issuance of common stock or do not
react to its predictable consequences; this will simplify
-------
IV-123
the calculation of the number of shares required to raise a
given dollar amount of equity capital. The effect of correct
anticipations will be discussed second. To make our points
clear, let us consider two illustrative cases. In the first,
let us assume that investors are willing to settle for a 10
percent return for investing in the industry's common equity.
In the second, perhaps either because the risks have increased
or because inflation has shifted the general levels of nominal
(current dollars) required rates of return upward, let us
assume investors demand a 15 percent return. We shall also
assume initially that the industry's need for common equity
capital over time is just met by retained earnings in all
years except one. As above, with the exception of the year
of the stock issue> this means that required equity grows
by 3.6 percent per year, and that earnings, earnings per
share, and dividends per share grow at 3.6 percent per year.
CASE 1: IF ALLOWED RETURNS ON EQUITY ARE GREATER THAN
INVESTORS' REQUIRED RATES OF RETURN, THEN EARNINGS
PER SHARE, DIVIDENDS PER SHARE, AND MARKET PRICES
INCREASE WITH INCREASING GROWTH,
Assumptions
Initial Equity SQ - $1,000,000
Allowed Return r = 12%
on Equity
Earnings EQ = $120,000
Payout Ratio b = .7
Dividends DQ = b x ED = $84,000
Retained Earnings
as Function of a = (1-b) = .3
Profit to
Common
-------
IV-124
Growth in Earnings g = a x r * .036
and Dividends
Shares Outstanding nQ = 100,000
Return Required k = 10%
by Investors
Market Price p. - D0 = $13.13
Per Share (ke - g)nQ
The market price of shares is $13.13 if the shares
are valued at the present value at 10 percent of an infinite
stream of dividends. This price contrasts with a book value
of $10 per share.
Suppose now that there is an external equity fi-
nancing requirement of $100,000 which arises too quickly for
the market to anticipate and hence which is financed at $13.13
per share.
Required Equity A s ~ $100,000
Issue
NUI°^ue5 ShareS A •> = A_L = 7(619 shares
New Equity Balance S^ - $1,100,000
New Earnings EI = $ 132,000
New Dividends D, = $ 92,400
New Total Shares Outstanding n, = 107,619
New Earnings Per Share e, = E, - n, = $l 23
New Dividends Per Share dl * Dl T nl = $0.86
New Market Price Per Share p, = dl
k I
e
-------
IV-125
The effect of the increased equity investment is to
raise earnings, dividends, and market price per share by 2.2
percent. In this instance, because the pre-issue stock price
did not reflect the opportunity to invest $100,000 at a rate
of return above that demanded by the market, both the old
shareholders and the new purchasers of stock received a $0.29
per share "windfall" gain.
If investors correctly anticipate the future need
for common equity financing, then the pre-financing prices
will adjust so as to drive out the post-financing windfall
gain (or loss) to investors. In Case 1, pre-financing prices
reflect the capitalization of the expected post-financing div-
idend stream at 10 percent, thereby boosting the pre-financing
price upward and reducing the number of shares required to
raise $100,000 in new capital. Thus, new investors purchase
their shares at a price that holds their return on investment
to 10 percent; the benefits of the industry's having an oppor-
tunity to invest at above-market returns all accrue to the
original shareholders. Of course, if after the date of pur-
chase of the new shares the industry unexpectedly has yet
another opportunity to invest equity over and above retained
earnings at a favorable rate, the "new" investors would share
in the second round of windfall gains. If both the first and
the second opportunity were correctly anticipated at the time
of the first issue, however, the stock would have risen in
market price so as to reflect all the benefits of both oppor-
tunities and to provide both the first and second rounds of
new purchases with only their required return on investment.
-------
IV-126
CASE 2: IF ALLOWED RETURNS ON EQUITY ARE LESS THAN INVES-
TORS' REQUIRED RATES OF RETURN., THEN EARNINGS PER
SHARE, DIVIDENDS PER SHARE, AND MARKET PRICES
DECREASE WITH INCREASING GROWTH,
Assumptions
Same as Case 1 except:
ke = 15%
$7.37
The market price an investor requiring a 15 percent
return will pay for a $10 book value share is $7.37.
Suppose again that a sudden requirement for exter-
nal equity financing of $100,000 arises too quickly for the
market to anticipate and, hence, is financed at $7.37 per
share.
A s = $100,000
E, = $132,000
An = A S
an = 13 572 shares
P0
n.,^ = 113,572
e-i = E, — nn = $1.16
-------
IV-127
$0.81
PI
Selling stock to meet capital needs when the market
price is below book drives earnings per share, dividends per
share, and market price per share to lower levels.
As in Case 1, the effect of investors' correctly
anticipating the industry's investment of inadequate rates
of return i^ to accentuate the effect of the simplistic
examples. If anticipated, the Case 2 investment would be
reflected in pre-issue stock prices less than $7.37, neces-
sitating the issuance of more than 13,572 shares to raise
$100,000 and thereby exacerbating the investment's damage to
earnings and dividends per share.
-------
ECONOMIC AND FINANCIAL IMPACTS OF
FEDERAL AIR AND WATER POLLUTION CONTROLS
ON THE ELECTRIC UTILITY INDUSTRY
VOLUME V
REGIONAL IMPACT PROJECTIONS
MAY 1976
v-i
-------
VOLUME V
TABLE OF CONTENTS
List of Exhibits
Chapter
1
INTRODUCTION AND SUMMARY OF
REGIONAL IMPACT PROJECTIONS
REGIONAL BASELINE PROJECTIONS
Operating Projections
Financial Projections
REGIONAL POLLUTION CONTROL IMPACTS
Methodology
Impact of Pollution Control Compliance
Measured by Consumer Charges
Impacts Projected Region by Region
Summary of Regional Capital Expenditures
and Operating and Maintenance Expenses
Page
(V-iii)
V-l
V-5
V-7
V-12
V-19
V-19
V-21
V-23
V-41
Appendix
V-A New England (Region I)
V-B Middle Atlantic (Region II)
V^C East North Central (Region III)
V-D West North Central (Region IV)
V-E South Atlantic (Region V)
V-F East South Central (Region VI)
V-G West South Central (Region VII)
V-H Mountain (Region VIII)
V-I Pacific (Region IX)
V-63
V-69
V-75
V-81
V-87
V-93
V-99
V-105
V-lll
(V-i)iv
-------
VOLUME V
LIST OF EXHIBITS
Exhibits
V-l Estimated Installed Generating Capacity;
1972 Baseline Year
V-2 Regional Historical Fossil Trends; Percent
of Generation
V-3 Ultimate Customer Kilowatt-hour Usage and Growth
Rates, 1960-1974
V-4 Regional Projection; Thousands of Customers
and Growth Rates
V-5 Electric Customers as a Percentage of National
Population, 1960-1973
V-6 Regional Historical and Projected Population,
1960-1990
V-7 Regional Generation Not Sold To Ultimate
Customer, 1960-1974
V-8 Regional Baseline Summary Table; Regional
Comparison: Capacity Mix by Prime Mover, 1975 (kw)
V-9 Regional Baseline Summary Table; Regional
Comparison: Generation Mix by Prime Mover,1975 (kwh)
V-10 Regional Baseline Summary Table; Regional
Comparison: Capacity Mix by Prime Mover, 1980 (kw)
V-ll Regional Baseline Summary Table; Regional
Comparison: Generation Mix by Prime Mover,1980 (kwh)
V-12 Regional Baseline Summary Table; Regional
Comparison: Capacity Mix by Prime Mover, 1985 (kw)
V-13 Regional Baseline Summary Table; Regional
Comparison: Generation Mix by Prime Mover,1985 (kwh)
V-14 Regional Coal Capacity by In-Service Year; For
Compliance with Clean Air Act, 1985
V-15 Regional Baseline Projections; Summary of
Cumulative Additions (Adjusted FPC Announcements),
1975-1980
(V-iii)
Preceding page blank
-------
Exhibit
V-16 Regional Baseline Projections; Summary of
Cumulative Additions, 1981-1985
V-17 Regional Baseline Projections; Summary of
Assumptions, 1975
V-18 Regional Baseline Projections; Summary of
Assumptions, 1980
V-19 Regional Baseline Projections; Summary of
Assumpt ions, 19 85
Appendices
Appendices V-A through V-I, as listed in the
Table of Contents, contain the following
exhibits for each region:
1. Capacity Report
2. Financial Baseline Projections
3. Coal Capacity: Coverage for Compliance
with Clean Air Act
4. Nuclear and Fossil Capacity: Coverage
for Compliance with Water Guidelines
5. Impacts of Air and Water
(V-iv)
-------
v-/
CHAPTER 1
INTRODUCTION AND SUMMARY OF
REGIONAL IMPACT PROJECTIONS
The financial impacts of pollution control regu-
lations are discussed in this volume as they occur on a
region by region basis. Volumes I-IV have presented the
baseline projections, impact projections and financial
feasibility analysis at the national level as well as des-
cribing the underlying methodological approach which TBS
has adopted. Those volumes provide the basis for the regional
analysis. The purpose of this volume is to highlight the
differences among regions both in the baseline projections and
in the nature of the impacts likely to be incurred by each
region. The chapters which follow discuss the most signifi-
cant components of the operating and financial projections in
the baseline as they are reflected in selected financial
indicators.
Supplementary information appears in an appendix
for each region; detailed exhibits on the baseline projections
are included at the end of the volume.
SUMMARY OF FINANCIAL IMPACT ANALYSIS
The nine census regions will be affected differentially
by the implementation of the air and water pollution control
regulations. The differences are primarily due to the amount
of generating capacity which falls under the purview of the
Impact projections were not developed for the tenth census region,
Alaska and Hawaii, see the footnote on page V-5.
-------
V-2
regulations. The differences in financial impact can best
be illustrated through the ranges which will exist in ad-
ditional capital expenditures and consumer charges by 1985.
At the national level, it is expected that an in-
crease of $25 billion will be required in capital expenditures
by the end of the 1975-1985 decade. The impacts which will
be incurred on a region-by-region basis range from a high of
$5 billion in the East North Central region to a low of $350
million in New England. In between these extremes, the re-
maining regions will require additional capital expenditures
in the following order: South Atlantic ($4.5)? West South
Central ($3.4), East South Central ($3.4), West North Central
($2.6), Mountain ($2.5), Middle Atlantic ($2.5) and Pacific
($0.6).
While the absolute amount of capital expenditures
needed in some regions is relatively high, that amount may
not represent as significant a proportion of the total capital
outlays as will be the case in regions starting out from a
smaller base. The national average change in additional capital
expenditures as a percent of baseline capital expenditures
(without pollution control) is 10.5 percent. The range among
regions is 2.4 percent (Pacific) to 17.6 percent (West South
Central). Among the other regions, three are above the national
average (Mountain, East South Central and East North Central)
and four are below (West South Central, South Atlantic, Middle
Atlantic and New England). Therefore, the degree of the impact
n
Billions of 1975 dollars. All costs and expenditures presented
in this volume are in 1975 dollars unless otherwise noted.
-------
V-3
varies depending upon whether the focus is on absolute capital
requirements or on the magnitude of the change from a base
level.
The same relationship exists regarding the degree
of impact where consumer charges are used as a measure. The
regions with the largest change do not necessarily have the
highest total consumer charges. The range in increases in
consumer charges because of pollution control is 1.3 to 11.1
.percent by 1985, while the national average is 6.7 percent.
On that basis, the overall ranking from most to least affected
region would be: Mountain (11.1 percent), East South Central
(10.2 percent), West North Central (10.1 percent), West South
Central (9.0 percent), East North Central (8.3 percent), South
Atlantic (5.2 percent), Middle Atlantic (4.1 percent, New
England (1.8 percent), and Pacific (1.3 percent).
Apart from the direct financial impacts, the reg-
ional analysis has identified four key factors which cause
the differences.in impact among regions:
the amount of coal capacity which will have
been added by 1985 - West North Central, East
North Central, East South Central, Mountain
and West North Central will be adding the
most;
the amount of capacity which is affected
by either the air regulations or the water
regulations or both—New England for example
is only slightly impacted by the air regu-
lations while the South Atlantic is covered
by both air and water regulations.
the pollution control strategy selected to meet
the regulations, for example the decision to use
low sulfur coal or scrubbers to comply with the
SO2 regulation.
-------
V-4
the level of electricity usage per customer—
which reflects among other things, the variations
in the use of electrical heating instead of oil
or gas.
The degree to which these factors occur in each region is
further elaborated in Chapter 3.
In addition to the primary causal factors listed
above, the basic characteristics of demand, capacity, costs
and financial structure in each region provide the context
for developing the impact projections. These basic charac-
teristics and their financial implications have been pro-
jected for the 1975-1990 period and are summarized in Chapter
2 which follows.
-------
V-5
CHAPTER 2
REGIONAL BASELINE PROJECTIONS
The regional baseline projections are essentially
the translation of the national baseline projections into
ten geographic subdivisions. The approach used to develop
the regional operating and financial projections for the
baseline case parallels that used at the national level; that is,
.each region's projections were based upon the same computa-
tional logic and types of assumptions. Wherever possible,
data were incorporated which specified differences among regions.
The categories of data used in the regional
projections are described below.
(1) Data which were available uniquely for each
region, such as additions to capacity (1975-
1980), population growth, public and private
ownership shares of capacity, use of flow
through or normalized accounting procedures.
The geographic divisions used in this research effort are the ten Census
regions designated by the Bureau of the Census. The states in each
region are illustrated on Page 2. These ten regions vary somewhat
from the states covered by each of the ten EPA regional offices and
the regions used by the Federal Power Commission. The Census regions
were selected because the FPC regions are not coterminous with state
boundariess and the electric utilities industry data as well as Census
data is more compatible with the ten Census regions. Alaska (Region X)
and Hawaii are not included in the impact analysis because of the un-
availability of financial data.
-------
§
r>
w
a
09
G
09
§
o
O
O
M
§
CO
0)
-------
V-7
(2) Data which were available uniquely for each
region on an historic basis, but which could
not be appropriately extrapolated into the
future were used to compute ratios of each
region's experience relative to the national
figures. Fuel costs and other operating and
maintenance costs are two examples.
(3) On certain topics no historical experience by
region had been compiled and data was available
only at the national level. In some cases, this
data could be allocated by region. Energy con-
servation , for example, is a relatively new
characteristic of demand which can be allocated by
region on the basis of kilowatt hour usage per
customer.
(4) And, finally, there were some data available
only at the national level, such as capital
costs and rates of retirement, which were
applied uniformly to each region.
Exhibits V-l through V-7 and V-17 through V-19
provide the regional information which was used as the basis
for the operating and financial projections.
OPERATING PROJECTIONS
Demand
Estimates of demand growth are based upon each
region's historical pattern of growth in number of customers
and number of kilowatt-hours per customer. The historical
growth pattern in usage per customer is then tempered by
allocating a share of the national level of energy conservation.
From these factors the sales to ultimate customers can be
projected. The table below presents each region's projected
annual growth rate (1975-1985) in kilowatt hours and the total
projected sales for selected years.
-------
V-8
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
Alaska fc Hawaii
National
'based on kuh aalet to
ANNUAL DEMAND GROWTH RATE AND
BY REGION
Annual Growth Rate*
1975-1985 (%)
5.8
4.6
4.8
5.4
7-4
3.5
8.1
5.7
5.0
6.4
S.7
ultimate euatomere
TOTAL SALES
Total Sales (billions kwh)
1975
70.9
236.1
328.6
102.8
294.2
159.3
215.4
79.8
242.8
6.8
1980
95.9
301.8
423.9
136.0
429.4
192.9
323.5
107.4
314.5
9.6
1985
124.3
370.1
525.1
•173.2
599.5
224.5
463. 5
138.3
389.0
12.7
Source: PTm (Electric Utilities)
An examination of the patterns in the annual de-
mand growth rate, by region, shows that about half the re-
gions are above and half below the national average of 5.7
percent. Only two regions, West South Central (8.1 percent)
and East South Central (3.5 percent), differ substantially
in either direction, the other regions are clustered around
the national growth rate. East South Central has had the
highest usage of electricity per customer in the country (see
Exhibit V-3) so the low growth rate over the 1975-1985 per-
iod may indicate a saturation of usage per customer. In addi-
tion, the slow growth rate reflects the historical pattern
of a very slow rate of population growth and, therefore, a
small rate of increase in new customers. The West South Cen-
tral and South Atlantic regions are characterized by rapid
population growth (Exhibit V-4), a high percentage of genera-
tion not sold (Exhibit V-7), and fairly rapid growth of usage
-------
V-9
per customer (Exhibit V-3). These three factors contribute
to the high level of required additions to capacity which
are discussed in the following section.
Capacity Additions
The sales levels of electricity dictate an amount
of capacity sufficient to supply those levels. From a starting
point of the.actual level of installed capacity by fuel type
in 1974, new additions are projected for each year. The pro-
cedure followed to project capacity additions for the short
term (1975-1980) was the use of the modified Federal Power
Commission's announced capacity additions for each region.
The projections of capacity additions in 1981 and later are
2
based on maintaining at least 20 percent reserve margin.
Projected capacity additions are largest for the South Atlan-
tic, West South Central, and East North Central regions. These
three regions are also among the four regions with the lar-
gest amount of existing capacity (see Exhibit V-ll).
An examination of capacity additions by fuel type
(Exhibits V-15, V-16) indicates the mix of fuels projected
for the next decade. The coal share of total capacity and
of additions is shown in the table below. Coal is not pro-
jected to be the dominant fuel in the capacity additions for
the Northeast coastal regions (New England and Middle Atlan-
tic) or the Pacific region. The regions in northern mid-con-
tinent (West North Central, East North Central, and Mountain)
have traditionally been high users of coal and will continue
2
Part One, Volume II of this report describes the approach which incor-
porates announced capacity additions, examines the consequences of
various alternative approaches, and covers the questions of short-term,
versus long-term projections for capacity additions.
-------
V-10
to add coal capacity. However, the West South Central re-
gion, previously a heavy consumer of gas for electricity gen-
eration, will be placing more emphasis on coal the next de-
cade. At the national level, slightly under one-half of the
additions to capacity are expected to be coal based by 1985.
Exhibits V-8, V-10, and V-12 summarize total capacity pro-
jections by fuel type. Other operating projections such as
total generation and cumulative additions by fuel type appear
in Exhibits V-9, V-ll, V-13, V-15, and V-16.
TOTAL CAPACITY AND CAPACITY ADDITIONS BY 1985
.Cumulative (1975-1985) Total Coal
Total Capacity Capacity Additions Additions
(million kw) (million kw) (million kw)
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
Alaska b Hawaii
National
Source: Exhibits V-15.
28.9
90.3
125.9
54.2
141.0
64.3
114.2
46.7
83.8
1.9
751.0
V-18, V-19;
11.2
29.1
49.1
25.7
66.1
27.7
63.6
25.7
30.4
0.4
326 . 9
PTm (Electric Utilities). -
-0-
4.3
29.3
19.8
24.3
10.2
39.0
18.4
4.7
0.1
149,2
-------
V-ll
Cost Factors
In projecting the financial implications of the
operating conditions of the electric utility industry by re-
gion, two categories of costs must be considered: capital
costs and operating costs. Capital costs for new capacity
are applied uniformly across all regions and are fully dis-
cussed in Volume II. Operating costs are covered below.
Operating and maintenance costs include fuel (ex-
cept nuclear), and non-fuel costs. Fuel costs have been
responsible for a large portion of recent rate increases at the
national level. Depending upon the mix of fuels used in each
region, fuels are also a major element of operating costs, by
region. In order to reflect the relative differences by fuel
type, the fuel cost component at the regional level is based on
the relationship of regional fuel prices to the average na-
tional price for each fuel. Exhibits 11-17 through 11-19
present the fuel price index by region for 1975, 1980, and
1985. New England and the Middle Atlantic generally show the
highest prices for all fuel types.
The non-fuel costs component is also based on the
relationship between non-fuel operating and maintenance costs
by region to the national average. Again, New England and
the Middle Atlantic are experiencing the highest costs among
the regions, as is illustrated in Exhibits 11-17 through 11-19.
Financial Structure
The logic which represents the financial structure
of the electric utility industry at the national level is
replicated in the regional projections. Only the data which
designates the share by ownership type (public or private)
-------
V-12
as a percent of capacity is unique to each region. Exhibits
V-17 through V-19 illustrate that in four of ten regions,
New England, Middle Atlantic, East North Central, and South
Atlantic, the public ownership share is less than 10 percent.
In five of the remaining six regions the public share ranges
from 18 to 61 percent. Among the investor-owned firms, the
percentage breakdown between those using normalized and those
using flow-through accounting is also apportioned in a manner
unique to each region. Exhibits V-17 through V-19 provide
the assumptions used in this category.
FINANCIAL PROJECTIONS3
The financial profile which is implied by the re-
gional projections of the utility industry's operations is
described by the same indicators as are used at the national
level:
• Capital Expenditures
• External Financing
• Operating & Maintenance Costs
• Operating Revenues
• Average Consumer Charges
Capital Expenditures are the expenditures for plant
and equipment placed in service during any given year. These
expenditures are primarily the result of the additions to
capacity made in response to the projected level of sales and
peak demand. The table below summarizes the level of capital
expenditures by region in the short-run (1975-1980) and over
the 1975-1985 decade. The table also illustates the differences
among regions of the average capital expenditure cost per kilo-
watt, which reflects the mix of fuels used in each region.
^Financial information was not available for Alaska, and Hawaii.
-------
V-13
CAPITAL EXPENDITURES FOR GENERATION*
AS REFLECTED IN CAPACITY ADDITIONS
(1975 dollars)
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
Alaska & Hawaii
National***
Capital Exp.»*
1975-1980
(billions)
$ 4.13
11.32
18.48
8.47
21.43
15.18
16.58
10.23
12.22
n.a.
Capital Exp.
Avg. Cost/kw 1975-1985
1975-1980* (billions)
$526
497
402
308
466
473
311.
363
440
n.a.
$ 9.30
24.16
35.35
15.64
51.24
21.50
40.15
16.73
22.48
n.a.
$118.27 $413 $237.13
'This measure excludes $23S/Taj standard cost for transmission and distribution plant and
"Capital expenditures are
"*Rvn national baseline -
Source: PTm (Electric
net of the change
Alaska and Hawaii
Utilities)
in CHIP
account for differences in
total dollars.
Avg. Cost/kw
1975-1985*
$577
577
467
355
522
523
378
398
486
n.a.
$472
equipment
By the end of the 1975-1985 decade the average
cost per kilowatt ranges from $355 to $577. The four re-
gions with the highest cost per kilowatt, New England,
Middle Atlantic, South Atlantic and East South Central, plan
to add nuclear capacity of 40 to 60 percent of capacity
additions through 1985 (see Exhibit V-8). During the same
period, the West South Central region will no longer maintain
the lowest cost per kilowatt because of a shift from gas
(the least expensive fossil fuel) to coal and nuclear power,
since gas additions are projected to cease after 1977. West
North Central, which does maintain the lowest average cost
per kilowatt, is one of the slower growing regions and will
meet a large part of its future demand with the addition of
peaking units.
-------
V-14
Despite the range in average costs among regions,
the total capital expenditures are primarily a direct func-
tion of the level of additions. Capital expenditures, in
fact, are highest in the South Atlantic, East North Central,
and West South Central regions where capacity additions are
also greatest. Those three regions account for 48 percent of
the total capital expenditures in the 1975-1990 period and
54 percent in the 1975-1985 decade. They also account for
over 50 percent of the projected additions by 1985. Overall,
there is a wide range of capital expenditure levels among
regions, ranging from $9 billion to $51 billion for 1975-1985.
External Financing. The level and timing of capital
expenditures and the attendant requirements for external fi-
nancing are of major concern to the electric utilities. Ex-
ternal financing requirements are primarily a function of the
level of capital expenditures and will range from a low of
$6.7 billion in the next ten years in New England, to a high
of $39.1 billion in South Atlantic. The table below presents
these requirements by region for the short-term and the period
through 1985. The remaining funds required to finance capital
i
expansion will be generated internally from retained earnings,
depreciation, and tax deferrals.
-------
V-15
EXTERNAL FINANCING
DURING 1975-1980 and 1975-1985
(billions 1975 dollars)
1975-1980 1975-1985
New England $ 2.77 $ 6.74
Middle Atlantic 5.12 14.95
East North Central 11.42 23.40
West North Central 5.00 10.28
South Atlantic 12.51 39.09
East South Central 8.96 13.17
West South Central 16.38 37.81
Mountain 7.39 12.37
Pacific 7.58 15.48
Alaska & Hawaii n.a. n.a.
Nat tonal•» $89.84 $191.23
'Tha J$7i-1980 ('..'t'/od n'flcale modified i't'C announced
capacity additions
"PTin National Baseline Projections
Source: Exhibit V 8-10. PTm Electric Utilities
Operating Costs and Revenues. Operating and
maintenance costs consist of all direct costs of operation;
operating revenues must cover these operating costs as well
as taxes and cost of capital. The operating costs are a
significant component of rates, which are in turn, the most
visible and politically volatile aspect of electricity pro-
duction and consumption. The operating costs are also
a measure of fuel costs (except nuclear), generation, operating
conditions and utilization patterns.
In 1974, the variations of operating costs among
regions on a kilowatt-hour basis began to be driven increasingly
by the types of fuel used to generate electricity. The rise
in all fuel costs since 1974, and the uncertainties of supply
have caused fuel costs to play a dominant role in. deter-
mining levels of operating and maintenance costs. The table
below illustrates the differences in the projected annual costs
for operating and maintenance and the distribution of these
costs on a per kilowatt hour basis.
-------
V-16
OPERATION AND MAINTENANCE
COSTS
(1078 dollars)
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
; East South Central
West South Central
Mountain
Pacific
Alaska fc Hawaii
National**
'billiono of dollar*
1980*
$ 2.38
7.45
7.75
2.32
8.42
2.57
4.49
1.40
4.65
n.a.
42.76
Hllls/kwh
1980
23.0
23.5
17.0
15.8
17.1
12.4
12.3
11.0
13.6
n.a.
16.7
1985*
$ 2.69
8.63
10.03
3.28
11.19
3.11
5.63
2.04
5.39
n.a.
53.75
Hills/kwh
1985
20.1
22.2
17.0
17.5
16.3
12.9
10.7
12.5
12.8
n.a.
16.2
"from national baseline runt
Source: PTro (Electric
Utilities)
The total cost reflects the number of kilowatt hours generated,
the cost per kilowatt hour illustrates more directly the effect
of fuel costs.
New England and the Middle Atlantic, which are
heavy oil users, may sustain even higher fuel costs than are
currently projected. Those regions with substantial usage
of hydroelectric power — East South Central, Mountain, and
Pacific have a lower cost per kilowatt-hour, although not
the lowest annual costs for operating and maintenance since
these costs are a direct result of the total number of kilo-
watt hours generated. The projected increase in gas prices
and greater usage of coal will cause an increase in cost
per kilowatt-hour in West South Central.
The revenues which are required to cover these costs
are most clearly reflected in consumer charges (discussed in
-------
V-17
the following section). Exhibit 2 in the appendix for each
region indicates that the South Atlantic region is projected
consistently to have the highest level of operating revenues.
The amount of revenues is determined by the number of cus-
tomers, the growth in the usage per customer, and finally,
the level of consumer charges. The South Atlantic is among
the highest region on all of these measures.
Average Consumer Charges are obtained from dividing
4
operating revenues by total sales to ultimate customers.
Thus, they represent the average cost of electrical energy
per kilowatt-hour sold. The table below presents consumer
charges by region for selected years.
CONSUMER CHARGES BY REGION
FOR SELECTED YEARS
(mllls/kwh)
Now England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
Alaska & Hawaii
National"
•Ai-tu-il EL'I Stntiuiicul Y,.
"Ad.!t,ntfii to Wi (tollarn
1974*
36.4
34.4
22.6
22.8
24.1
14.9
18.2
18. 5
18.4
29.4
23.0
.ir!
-------
V-18
The consumer charges in the table do not manifest
the same range in mills per kilowatt-hour as do operation
and maintenance costs; the difference is primarily accounted
for by differences in capital costs. However, the New En-
gland and Middle Atlantic regions consistently maintain the
highest charges to customers. Most regions cluster closely
around the national average; only the Pacific region attains
noticeably lower charges in 1985 than the national average,
or than the other regions. The West South Central region's
consumer charges, in line with the aforementioned increases
in gas costs and the change in generation mix, are projected
to be just 10 percent lower than the national average in
1985, as compared to 26 percent lower in 1975.
The projections presented in this chapter provide
a basis for the comparison of the financial conditions which
are likely to exist as a result of compliance with pollution
control regulations. The following chapter discusses the
result of that comparison for each region.
-------
V-19
CHAPTER 3
REGIONAL POLLUTION CONTROL IMPACTS
The financial impact analysis of the pollution con-
trol regulations is presented from two perspectives: first,
on a comparative basis for all regions using consumer charges
as a measure of impact, the second on a non-comparative
basis which focuses on the change in capital expenditures,
external financing, and operating and maintenance costs within
each region. The region by region discussion also relates
the levels of expenditures and costs to the characteristics
of generating capacity and the amount of capacity affected
by the regulations in each region. The impacts become readily
apparent when the costs associated with pollution control
are compared to the baseline financial projections. On the
other hand, discussion of the results for each of the nine regions
can be cumbersome and repetitive. As a result, the material
included in this chapter covers the most essential elements
common to all regions. Additional detail can be found in the
appendices and exhibits at the end of the volume.
METHODOLOGY
As for the national impact analysis presented in
Volume III, the methodology for the regional analysis has re-
quired developing industry projections for 1975-1990 which
include the costs of complying with federal pollution control
regulations. The pollution control impacts then have been
determined by comparing those projections to the baseline
projections above which exclude federal pollution control
costs.
-------
V-20
This analysis includes three important inputs with
respect to pollution control costs and compliance stragegies:
Pollution Control Equipment Costs
Capital and annual costs used in the regional analysis
for pollution control equipment were the same as those des-
cribed in Chapter 3 of Volume III. It was assumed that the
effect of site-specific factors would outweigh any variation
in regional construction costs and, therefore, the plant unit
costs used for each region were identical.
Capacity Affected by Air Regulations
TBS determined the amounts of coal capacity affected
by the air regulations by using estimates developed for EPA
by Sobotka and Co., Inc. Sobotka employed a coal supply and
demand balance model to assign least-cost strategies for
burning coal in an environmentally acceptable manner (meeting
o
SIP's or NSPS ) to each plant in the country. Regional ag-
gregations of these strategies were then provided to EPA
along with the incremental cost of complying coal. Particulate
compliance status was provided by PEDCO-Environmental. Detailed
exhibits in Appendices A through I document the control strategies
used in each region by 1985.
Capacity Affected by Water Regulations
The estimates which TBS used to designate capacity
affected by the thermal, chemical and entrainment regulations
1 Volume III diacuaaea the hiatory and intent of the regulations and covers
all terminology and major iaauee aaeoaiated with compliance.
2State Implementation Plane (SIP)
New Source Performance Standards (NSPS)
-------
V-21
were developed by the national and regional offices of EPA.
EPA surveyed the water permit officers in each EPA regional
office to obtain estimates of the megawatts of capacity (nuclear
and fossil) affected by the final thermal effluent guidelines
(both before and after Sec. 316(a) determinations), the
chemical guidelines, the entrainment regulations (Sec. 316(b)
of the Federal Water Pollution Control Act), and the various
State Water Quality Standards (SWQS). Appendices A through
I also include the results of this survey.
IMPACT OF POLLUTION CONTROL COMPLIANCE
AS MEASURED BY CONSUMER CHARGES
Consumer charges represent the average cost of
3
electrical energy per kilowatt hour. Consumer charges bring
into one number the relationship between the operating, capital
and other costs, and the sales to ultimate customers. They
are also stated on a per unit basis. As such, consumer charges
are a consistent measure for comparison among regions of the
potential impact of pollution control regulations which re-
quire capital investments as well as direct operating costs.
Nationally, the average impact on consumer charges
is 6.7 percent by 1985. By region, this impact varies from
as low as 1.3 percent to 11.1 percent. The largest impact
will take place in the Mountain and West North Central regions,
where the increased cost will be about 4 mills (1975 dollars)
per kwh, or 10 to 11 percent. These two regions will add
significant coal capacity during 1975 to 1985 and are among
the smallest regions in capacity and generation (see Exhibits
V-12 and V-13). For this reason, the high absolute costs are
spread over a small base and, therefore, have a large impact.
Kilowatt-hours will be abbreviated as fa)h in the remaining sections of
this chapter.
-------
V-22
The three regions, East South Central, East North
Central, and West South Central, will experience a moderately
high impact of 2.6 to 2.8 mills per kwh or 8 to 10 percent.
During the decade, all three regions will add large amounts
of both coal and nuclear capacity. In the East South Central
and East North Central regions, coal and nuclear additions
will be added to an already large volume of coal capacity,
while in the West South Central area, the mix of additions
will shift the generation away from usage of natural gas.
A moderate impact of 4 to 5 percent, slightly below
the national average, is expected in the South and Middle
Atlantic regions. The absolute change will be 1.6 to 1.9
mills per kwh for meeting both air and water pollution con-
trol regulations.
The remaining two regions, New England and Pacific,
have very limited coal capacity and plan little or no new
coal units. In both of these regions, the impact for com-
pliance with pollution control regulations will be less than
2 percent, or under one mill per kilowatt-hour.
The following table indicates the impact on com-
sumer charges of current air and water regulations across
regions. The four levels of impact—high, moderately high,
moderate and low—are shown as separate categories on the
table.
-------
V-23
IMPACT OF CURRENT LEGISLATION
AIR AND WATER REGULATIONS ON
CONSUMER CHARGES
1985
(1975 dollars)
High
Mountain
West North Central
Moderately High
East North Central
East South Central
West South Central
Moderate
South Atlantic
Middle Atlantic
Low
New England
Pacific
Source: Exhibits 2
Consumer Charges
Including Impacts
mills/kwh
40.3
39.3
36.0
28.0
31.2
39.4
39.8
39.7
30.5
and 5, Appendices V
Increase from Baseline
mills/kwh
4.0
3.6
2.8
2.6
2.6
1.9 *
1.6
0.7
0.3
A-I.
_s_
11.1
10.1
8.3
10.2
9.0
5.2
4.1
1.8
1.3
IMPACTS PROJECTED REGION BY REGION
The financial impacts which are projected to result
from compliance with pollution control regulations are described
below for each region. The impacts on capital expenditures,
external financing and operating and maintenance expenses
are highlighted. These financial indicators will be related
to two factors: the physical growth and the capacity mix by
fuel type in each region. The regions which will experience
the largest impact will be those which add substantial coal
and nuclear capacity.
Air regulations affect fewer unils, primarily those
burning coal, than the water regulations; however, the control
strategies required to meet the air regulations are far more
-------
V-24
costly than those required to meet the water regulations.
There is a direct correlation between the coal capacity
in each region by 1985 and the absolute costs incurred in
the same period to comply with federal regulations.
The two pollution control strategies which are pro-
jected to be used most heavily for achieving compliance with
4
the regulations are scrubbers and cooling towers. The
installation of scrubbers is the major expense related to
control of sulfur dioxide; cooling towers will be used at
coal and nuclear plants for compliance with the water regulations
(thermal and entrainment control). Plants installing cooling
towers would have used once-through cooling without the
regulations.
4
Given current available technology.
-------
V-25
New England (Region I)
IMPACTS OF AIR AND WATER REGULATIONS TO 1985
(billion 1975 dollars)
Capital Expenditures Since 1974
Baseline
Impact
% Change from Baseline
External Financing Since 1974
Baseline
Impact
% Change from Baseline
Operating and Maintenance Expense
Baseline
Impact
% Change from Baseline
Set of CHIP
*lees than .05
Source: Exhibits V-A-2 and V-A-5
1985
$9.3
+ 0.3
3.6%
$6.7
+ 0.4
5.5%
$2.7
1.1%
New England will experience a small impact in meeting
pollution control regulations. In the 1975-1985 period, this
region will incur about $350 million in capital expenditures,
all of which will be met by external financing. Operating
and maintenance expenses will be less than $50 million in
1985. No coal additions are expected; most of the growth
will.consist of 6.6 million kilowatts of added nuclear
capacity. By 1985, nuclear units will comprise 40 percent
of the 28.8 million kilowatts of total capacity.
Of the total impact, very little is the result of
compliance with air regulations. About $3 million or one per-
cent of the total is in this category. Ninety-nine percent
-------
V-26
of the costs for both nuclear and fossil compliance are
associated with thermal, chemical and entrainment guidelines.
Capital expenditures for compliance with federal
water regulations account for $346 million ($325 million for
cooling towers). In addition, the stringent State Water
Quality Standards (SWQS) are responsible for an increase of
26 percent of the requirements for fossil cooling towers. SWQSs
account for $86 million more in total capital expenditures.
For operating and maintenance expenses, federal compliance
results in $33 million ($32 million caused by cooling tower
operation and maintenance); the state standards are responsible
for another $9 million.
Middle Atlantic (Region II)
IMPACTS OF AIR AND WATER REGULATIONS TO 1985
(billion 1975 dollars)
Capital Expenditures Since 1974
Baseline
Impact
% Change from Baseline
External Financing Since 1974
Baseline
Impact
% Change from Baseline
Operating and Maintenance Expense
Baseline
Impact
% Change from Baseline
of CHIP
Source: Exhibits V-B-2 and V-B-5
1985
$24.2
2.5
10.2%
$15.0
2.1
14.0%
$ 8.6
+ 0.3
3.4%
-------
V-27
Electricity consumption in the Middle Atlantic
region is expected to grow at a much slower rate than the
national average over the next ten years. The majority of
its capacity additions will be nuclear units which will be
affected by the water guidelines. Coal units equal to 25.8
million kilowatts in 1985 will be brought into compliance
primarily by the use of precipitators and scrubbers.
In total, Middle Atlantic will incur about $2.5
billion in capital costs for pollution control strategies, an
impact of 10 percent on baseline projections. The capital
expenditure requirements for the 1975-1985 decade include
$1.4 billion for compliance with the water regulations
by fossil and nuclear units. Scrubbers account for another
$500 million of the total.
Despite the 10 percent impact on capital expenditures,
the reliance on a combination of precipitators and scrubbers
and the use of some Western low sulfur coal and blending,
is expected to keep additional operating and maintenance ex^
penses to $300 million dollars, or an impact of about 3
percent.
State Water Quality Standards will require approximately
$400 million more in capital expenditures during this period
and account for almost $40 million per year in operating and
maintenance expenses.
-------
V-28
East North Central (Region III)
IMPACTS OF AIR AND WATER REGULATIONS TO 1985
(billion 1975 dollars)
Capital Expenditures Since 1974
Baseline
Impact
. % Change from Baseline
External Financing Since 1974
Baseline
Impact
% Change from Baseline
Operating and Maintenance Expense
Baseline
Impact
% Change from Baseline
Sat of CHIP
Source: Exhibits V-C-2 and V-C-5
1985
$35.3
+ 5.0
14.3%
$23.4
+ 4.4
18.8%
$10.0
+ 0.7
6.7%
In 1974, East North Central was the region with both
the largest total capacity and largest coal capacity. As a re-
sult of a moderate growth rate during the next eleven years,
this region will have a capacity of 125.9 million kilowatts in
1985 which will place it behind the South Atlantic region in
size by the end of the decade. In that period, East North
Central will continue to add coal-fired units and in 1985 will
have 89 million kilowatts—the most coal-fired units in any
region. With this high level of coal capacity, East North
Central can expect an extremely high capital expenditure re-
quirement for pollution control equipment. Only 10 million
kilowatts (11 percent of the coal-fired units) were estimated
-------
V-29
to be in compliance with air regulations in 1974; coal units
of 79.5 million kilowatts will require pollution control
equipment. The air regulation strategies account for 98
percent of all pollution control costs.
This region has a minimal requirement for compliance
with the effluent guidelines. Only 2.3 million kilowatts are
expected to require cooling towers and all the fossil and
nuclear capacity are expected to be exempt from the entrainment
and chemical guidelines.
Despite the minimal water regulation requirements
and associated costs, East North Central will incur higher
capital and operating costs in absolute dollars than any other
region. Scrubbers are expected to be used as the control
strategy for 34 million kilowatts, and this alone will require
a capital cost of over $3 billion. The total capital expenditures
during 1975-1985 will be about $5 billion, a 14 percent in-
crease over the baseline projections. Almost all of these
monies must be financed externally, causing an increase of
about 19 percent in external financing.
Pollution control strategies will require an additional
$675 million for operating and maintenance expenses in 1985.
Although the impact is the largest of any region in absolute
dollars, it adds less than 7 percent to the baseline projection
for this region because of its high level of baseline expenditures,
-------
V-30
West North Central (Region IV)
IMPACTS OF AIR AND WATER REGULATIONS TO 1985
(billion 1975 dollars)
Capital Expenditures Since 1974
Baseline
Impact
% Change from Baseline
External Financing Since 1974
Baseline
Impact
% Change from Baseline
Operating and Maintenance Expense
Baseline
Impact
% Change from Baseline
of carp
Source: Exhibits V-D-2 and V-D-5
1985
$15.6
+ 2.8
17.6%
$10.3
+ 2.3
22.4%
$ 3.3
+ 0.3
8.2%
West North Central will experience a high impact
in meeting pollution control regulations. In terms of in-
stalled capacity it was the third smallest region in the
States in 1974 and its growth in the next decade will follow
the national average.
West North Central will be highly reliant on fossil-
fired steam generation throughout the decade. In 1974, coal
and gas units accounted for 70 percent of the capacity. Con-
versions of gas units to coal and the addition of new coal
units will increase the coal capacity to 36 million kilowatts
by 1985 or 67 percent of the total capacity. The air regulations
-------
V-31
will affect almost all of the coal-fired units. The water
regulations will affect 21 million kilowatts of the coal
units and 1.6 million kilowatts of the nuclear units.
West North Central will incur a total of $2.8 billion
in capital expenditures for new and retrofit pollution control
equipment, 82 percent of which will be financed externally.
Additional operating expenses will amount to about $270 .^1;! >
million in 1985. Scrubbers and cooling towers will account'
for $1.8 billion in capital equipment and $140 million in
operating and maintenance expense.
In absolute dollars, this level of total costs is
the average for all regions. As stated above, West North
Central is one of the smallest regions and is expecting only
a moderate growth. In light of this, the baseline projection
for capital expenditures is low and the percentage impact of
compliance with pollution control regulations is the highest
of all regions. Capital expenditures will be almost 18 per-
cent higher and external financing will be 22 percent higher
than the baseline.
With gas conversions to coal, West North Central
will incur higher baseline operating and maintenance costs
in 1985 than in 1974. Therefore, the additional pollution
control operating costs are related to an already higher
baseline and result in a more moderate percentage impact
than is manifested in capital costs. The $270 million in-
curred for pollution control operating and maintenance ex-
penses will be an 8.2 percent increase in 1985.
-------
V-32
South Atlantic (Region V)
IMPACTS OF AIR AND WATER REGULATIONS TO 1985
(billion 1975 dollars)
Capital Expenditures Since 1974
Baseline
Impact
% Change from Baseline
External Financing Since 1974
Baseline
Impact
% Change from Baseline
Operating and Maintenance Expense
Baseline
Impact
% Change from Baseline
of CHIP
Source: Exhibits V-E-2 and V-E-5
1985
$51.2
+ 4.5
8.7%
$39.1
+ 4.3
11.0%
$11.2
+ 0.7
5.9%
South Atlantic.was the second largest region in 1974
with 83 million kilowatts of installed capacity. The period
1975-1985 will exhibit a 70 percent growth, well above the
national average. Thus , in 1985, South Atlantic is projected to
have the largest amount of installed capacity—141 million
kilowatts or about 10 percent higher than East North Central.
•'?•• Historically, this region has relied heavily on
coal and oil for its generation. The Arab oil embargo and
the high cost of oil have resulted in conversions to coal of
many oil-fired units. The capacity additions in the de.cade 1975-
1985 will be predominantly coal and nuclear units, 24.3 million
-------
V-33
kilowatts and 27.9 million kilowatts respectively. The coal
share will continue to be about 50 percent of the capacity
in 1985 and the nuclear units will account for another 24
percent in that year.
The air regulations are expected to affect 48.2
million kilowatts of coal-fired units. The thermal and en-
trainment guidelines are estimated to require cooling towers
on 26.2 million kilowatts of coal-fired units and 26.9 mil-
lion kilowatts of nuclear units. All of the coal capacity,
67.5 million kilowatts, and about one-half of the nuclear
capacity, 16.4 million kilowatts, is expected to be impacted
by the chemical effluent guidelines.
The large amount of coal capacity in South Atlantic
and the large percentage of units required to meet both air and
water regulations will result in a high level of capital and
operating costs for new and retrofit pollution control equipment.
The region will incur almost $4.5 billion in capital expenditures;
$4.3 billion will be financed externally. An additional $650
million will be required for operating and maintenance expenses
in 1985. Scrubbers and cooling towers alone will account for
$3.4 billion of capital costs (76 percent of the total) and $440
million in operating costs (67 percent of the total).
In light of the high growth expected during this
period, the baseline capital and operating costs are the highest
of all regions. Therefore, the impact of pollution control in
the South Atlantic region, while high in absolute terms, appears
more moderate in relative terms. The $4.5 billion of capital
expenditures will result in an 8.7 percent increase and the
$650 million in operating expenses will cause only a 6 percent
increase over the baseline projections.
-------
V-34
East South Central (Region VI)
IMPACTS OF AIR AND WATER REGULATIONS TO 1985
, (billion 1975 dollars)
Capital Expenditures'1 Since 1974
Baseline
Impact
% Change from Baseline
External Financing Since 1974
Baseline
Impact
% Change from Baseline
Operating and Maintenance Expense
Baseline
Impact
% Change from Baseline
'Set of CHIP
Source: Exhibits V-F-2 and V-F-5
1985
$21.5
+ 3.4
15.6%
$13.2
+ 2.6
19.7%
$ 3.1
+ 0.3
8.7%
East South Central is unique with respect to the
predominance of publicly-owned utilities. The high proportion
of publicly-owned systems is due primarily to the presence of
the Tennessee Valley Authority. The region is also heavily
reliant upon coal-fired capacity; 71 percent of its total
capacity in 1974 was coal. The share of coal capacity and the
uniquely large public share of system ownership are two important
factors in the types of impact which are expected in the region.
During the period 1975-1985 the private sector will
continue to add coal units; TVA will add the nuclear capacity.
In 1985, the capacity mix will include 36.8 million kilowatts
-------
V-35
of coal-fired units (57 percent) and 13.9 million kilo-
watts of nuclear units (22 percent). The federal regulations
on air and water pollution will, therefore, affect most of the
capacity in East South Central.
Almost all the 36.8 million kilowatts of coal
plants is expected to be affected by the air regulations.
Scrubbers are projected on 13.8 million kilowatts while a
combination of precipitators, low and medium sulfur coal, and
blending is expected on 22 million kilowatts. In addition, all
fossil units are expected to be affected by the chemical ef-
fluent guidelines. Cooling towers are projected for 16.8
million kilowatts of fossil capacity in order to meet the federal
thermal effluent guidelines and for an additional 7.3 million
kilowatts in order to meet the more stringent State Water
Quality Standards. All nuclear plants are expected to require
cooling towers when the units are put in-service, while 95
percent are projected to be impacted by the chemical guidelines.
As a result, the capital expenditures required for
new and retrofit pollution control equipment in this region
are above the average level. East South Central will incur
$3.4 billion in capital costs, which is an increase of 15.6
percent on the baseline. More than three-fourths of these ex-
penditures are for scrubbers and cooling towers. East South
Central will need to meet 75 percent of its capital costs with
external financing. This is a smaller percentage than in any
other region and yet the increase over the baseline level of
external financing is almost 20 percent.
t
The use of the full spectrum of control alternatives will
keep the operating and maintenance expenses at $270 million, or
8.7 percent over the baseline level in 1985. Compliance with
the air regulations will account for over $200 million while the
water will account for another $65 million.
-------
V-36
West South Central (Region VII)
IMPACTS OF AIR AND WATER REGULATIONS TO 1985
(billion 1975 dollars)
Capital Expenditures Since 1974
Baseline
Impact
% Change from Baseline
External Financing Since 1974
Baseline
Impact
% Change from Baseline
Operating and Maintenance Expense
Baseline
Impact
% Change from Baseline
Net of CHIP
Source: Exhibits V-G-2 and V-G-5
1985
$40.1
+ 3.4
8.5%
$37.8
+ 3.4
9.0%
$ 5.6
+ 0.6
10.6%
West South Central is expected to almost double in
capacity during 1975 to 1985, from 64 to 114 million kilowatts.
Its coal capacity will increase from 7 to 36 percent of total
capacity as a result of new units and gas conversions.
Only 1.2 million kilowatts of coal-fired units were
in compliance with air regulations in 1974. All other units and
the new units are expected to require some change in order to
comply with the air regulations. These coal units are also
expected to be affected by the water regulations. By 1985
the West South Central region will also add 13 million kilo-
watts of nuclear capacity. All these units are expected to
be exempt from thermal and 316(b) guidelines and only 10 percent
-------
V-37
are expeqted to be affected by the chemical guidelines. The
costs of pollution control in the West South Central region,
therefore, are in direct correlation with the level of coal
capacity. The region can expect a moderately high percentage
impact in meeting the federal air and water regulations. While
this region will add the largest amount of coal capacity of
any region, it is expected to use mainly Western low sulfur
coal to comply with the air regulations. The capital cost of
this strategy is considerably lower than that of using scrubbers
and will help to moderate the level of costs for pollution
control.
West South Central is projected to incur a total of
$3.4 billion in capital expenditures for the period 1975-1985,
or an impact of 8.5 percent. The major share of these costs
will be associated with Western low sulfur coal. This strategy
is expected to be used for 28.8 million kilowatts, or 69 per-
cent of the coal capacity, and will require $2.2 billion in
capital costs (65 percent of the total impact). Scrubbers
are projected to account for most of the additional costs.
Only 4 percent of the impact is a result of the water regulations
Additional operating and maintenance expenses for
pollution control in 1985 will be almost $COO million and
$443 million of this total is associated with Western low
sulfur coal (74 percent) and $125 million is for scrubbers.
The additional operating costs will affect the baseline by
10.6 percent.
-------
V-38
Mountain Region (Region VIII)
IMPACTS OF AIR AND WATER REGULATIONS TO 1985
. (billion 1975 dollars)
Capital Expenditures Since 1974
Baseline
Impact
% Change from Baseline
External Financing Since 1974
Baseline
Impact
% Change from Baseline
Operating and Maintenance Expense
Baseline
Impact
% Change from Baseline
Net of CHIP
Source: Exhibits V-H-2 and V-H-5
1985
$16.7
+ 2.5
15.2%
$12.4
+ 2.0
16.1%
$ 2.0
+ • 0.2
10.8%
The Mountain region will experinece a high percentage
impact in meeting pollution control regulations. Although the
region will almost double in capacity in 1985, from 24 to
47 million kilowatts, it will still remain the second smallest
in total capacity. Most of the new capacity, about 72 percent,
will be coal-fired units which are expected to require scrubbers.
The impact of compliance will be significant because of
the relatively low level of baseline capital expenditures anti-
cipated before considering pollution control expenses. The
projected pollution control expenditures of $2.5 billion in
capital expenditures during 1975-1985 and $222 million in
-------
V-39
operating and maintenance expenses in 1985 represent increases
of 15.2 and 10.8 percent above baseline levels, respectively.
Air regulations are expected to account for 97 percent of
these expenditures. Scrubbers alone are projected to cost
$2 billion in capital expenditure and $173 billion in 1985
operating costs. The region is expected to meet 80 percent
of its capital needs with external financing.
Pacific (Region IX)
IMPACTS OF AIR AND WATER REGULATIONS TO 1985
(billion 1975 dollars)
Capital Expenditures Since 1974
Baseline
Impact
% Change from Baseline
External Financing Since 1974
Baseline
Impact
% Change from Baseline
Operating and Maintenance Expense
Baseline
Impact
% Change from Baseline
llet of Cf/IP
Source: Exhibits V-I-2 and V-I-5
1985
$22.5
0.6
2.4%
$15.5
0.5
3.2%
$ 5.4
0.1
1.1%
-------
V-40
In 1974, hydroelectric power represented about 50
percent of the 58 million kilowatts of installed capacity in
the Pacific regibn. Gas and oil accounted for another
40 percent. By 1985, however, the shares by fuel type will
have changed in spite of continued additions of hydroelectric
power. Gas units will have been converted to oil, and 10 million
kilowatts of nuclear capacity and 5 million kilowatts of coal
will have been added. Consequently, the region will be af-
fected to some degree by the air and water regulations, although
the impact will be the smallest of all the regions.
The low level of coal capacity is projected to require
capital expenditures of less than $300 million for scrubbers and
Western low sulfur coal, $255 million for cooling towers and
less than $1 million to meet the chemical guidelines. Only
1.6 million kilowatts, or 13 percent, of the nuclear capacity,
is expected to require cooling towers, and the total nuclear
capacity is expected to be exempt from the entrainment, 316(b),
and chemical guidelines.
Total projected capital expenditures of $550 million
for pollution control would result in an increase above the base-
line of only 2.4 percent. The pollution control strategies would
add $58 million in 1985 operating and maintenance expenses, or
1 percent of the baseline amount.
SUMMARY OF CAPITAL EXPENDITURES AND
OPERATING & MAINTENANCE EXPENSES
In summation, the impacts discussed in the regional
subsections above are assembled in one table as an overview of
all the,regions. The table emphasizes the variability of the
impacts as they are expected to be experienced across regions.
-------
V-41
IMPACTS OF CURRENT LEGISLATION
AIH AND WATER REGULATIONS
1975-1985
(billions of 1975 dollars)
CUMULATIVE OPERATING &
CAPITAL EXPENDITURES* MAINTENANCE EXPENSES
1975-1985
Change**
Baseline $ %
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
National Percent
Change
'Net of change in (VIP
"Change from baaeline
"*Laaa than .OS
9.3
24.2
35.3
15.6
51.2
21.5
40.1
16.7
22.5
projections,
0.3
2.5
5.0
2.8
4.5 '
3.4
3.4
2.5
0.6
10.5%
See Appendix A-I,
3.7
10.2
14.3
17.6
8.7
15.6
8.5
15.2
2.4
Edtibit S.
3aseline
2.7
8.6
10.0
3.3
11.2
3.1
5.6
2.0
5.4
1985
Change**
$
**»
0.3
0.7
0.3
0.7
0.3
0.6
0.2
0.1
5.0%
%
1.1
3.4
6.7
8.2
5.9
.8.7
10.6
10.8
1.1
-------
Exhibit V-l
ESTIMATED INSTALLED GENERATING CAPACITY
1972 BASELINE YEAR
(kilowatts 1n thousands- name plate)
Generator
Drive Type
Conventional Hydro
Capacity
PORC*
Pulped Storage
Capacity
PORC*
Nuclear Steam
Capacity
•PORC*
Peaking Units
Capacity
PCRC*
Coal
Capacity
PORC*
Oil '
Capacity '
PCRC*
Gas
Capacity
PORC*
New
England
1,449
9.0
31
0.3
3,469
20.5
1,379
8.6
561
3.4
9,355
. 57.4
111
0.8
16,355
Middle
Atlantic
4,166
7.0
1,801
3.0
2,140
5.0
9,255
15.6
20,582
35.2
18,345
31,2
1,742
3.0
58,039
• - East
North
Central
' 840
1.1
-
5,486
8.0
4,994
6.6
56,790
77.1
2,425
3.1
2,987
4.1
73,472
West
North
Central
2,681
9.6
408
1.5
569
2.0
3,322
11.9
12,869
46.1
545
2.0
7,513
26.9
27,907
South
Atlantic
4,956
7.3
549
0.8
2,376
3.5
5,976
8.8
33,517
49.6
16,061
23.3
4,137
6.2
67,572
East
South
Central
5,259
14.8
-
-
1,347
3.8
25,670
72,2
492
1.4
2,779
7.8
35,547
West
South
Central
2,009
4.0
271
0.5
-
1,240
2.5
1,207
2.4
i« j- /i
,10£
2.3
44,045
38.3
49,934
Mountain
6,294
31.5
307
1.5
-
712
3.6
5,897
29.5
530
2.7
6,230
31.2
19,970
Pacific
24,191
48,9
1,275
2.6
1,310
2.5
626
1.4
-
6,604
13.4
15,402
31.2
49,408
Alaska
&
Hawaii
79
5.6
-
-
173
' 12.4
172**
12.3
575**
41.0
403**
28.7
1,402
Generator
Type
Totals
51,924
4,642
15,300
29,024
157,265
55,094
85,357
399,606
*PORC - Percentage of Regional Capacity
^Alaalvi & Bauaii Fossil Capacity' Estimated at IS percent coalt SO percent oil,.and 35 percent natural gas. .
jourcs: ZEI S tet1s t1 calIcarbook, 1972 ™nd 197J; Fede""1 Power Ccnp1ss1on, Sta^$^cj_fpj^j^|^tel^C^^J^lJi^^ 19720
and ttydro^ie^fcr-ic/Mj^^ --d N?4-"" " °-'«r')'
-------
Exhibit Y-2
REGIONAL HISTORICAL FOSSIL TRENDS*
PERCENT OF GENERATION
(for selected years)
Year
1950
1353
1966
1S69
1972
1973
1974*1
United States
Coil Oil Gas
66 8 25
65 7 28
55 8 26
59 12 29
54 19 27
57 20 23
57 20 23
New England
Coal Oil Gas
53 37 5
63 33 .4
61 36 3
25 74 1
6-93 1
5 94 1
10 87 3
Kiii'e
A*la-.t1e
Ceal Oil Gas
73 14 8
75 15 10
77 16 7
60 32 8
52 44' 4
55 41 3
54 43 3
East
North Central
Coal Oil Gas
96-4
96-4
97 - 3
94-6
91 4 5
93 4 3
90 6 4
West
North Central
Coal Oil Gas
47 1 52
49 1 50
51 1 48
54 1 45
62 2 36
65 2 . 33
66 3 31
South.
Atlantic
Coal Oil Gas
77 8 15
79 10 11
80 12 8
73 15 12
62 29 .9
63 30 7
63 30 7
East
South Central
Coal Oil Gas
92 - 8
92-8
92-8
89 - 11
89 2 9
93 2 5
93 3 5
West
South Central
Coal Oil Gas
- 100
- 100
- 100
- 100
1 2 97
3 6 91
3 6 91
Mountain
Coal Oil Gas
26 8 66
40 4 56
49 4 47
51 3 46
58 4 33
64 7 29
67 8 25
Pacific
Coal Oil Gas
- 32 68
- 19 81
- 19 81
- 17 83
- 30 70
6 46 48
6 54 40
'No information available for Alaska and Scuaii
"EEI Statistical Yearbook 1974
Source: National Coal Association, Steam Electric Plant Factors. 1960-1974
-------
Exhibit V-3
ULTIMATE CUSTOJUOK K'.VII USAGE AND GKOWT11 RATES
19GO - 197-1
1960
1961
1352
1953
190-1 .
1905
19G6
19G7
1938
19G9
1970
1971
1972
1973
197-1
13CO-19G1
1961-1962
12-32-1963
19G3-12G4
1954-1955
I9G5-1203
I9CS-1SG7
I&07-19GS
12G3-1S59
1969-1970
1970-1271
1971-1972
1972-1973
1973- ^ 07-1
United
States
11.605
11,986
12,655
13,213
13,330
1-1, 54 3
15,528
16,2-10
17,216
18,429
19,195
19,746
20.718
21,708
21,232
3.3
5.6
4.4
5.0
4.8
6.8
4.6
6.2
6.9
4.2
2.9
4.9
4.8
(2.2)
New-
England
7,326
7,770
8,212
8,501
8,913
9,491
10,127
10,740
11,513
12,275
12,926
13,571
14,351
15,051
14 , 582
6.1
5.7
3.5
4.8
6.5
6. 7
6.1
7.2
6.6
5.3
5.0
5.8
4.9
(3.1)
Middle
Atlantic
9,426
9,843
10,325
10,794
11,405
12,081
12,821
13,307
14,131
15,126
15,795
16,223
16,913
17,810
17,228
4.4
4.9
4.5
5.7
5.9
6.1
3.8
6.2
7.0
4.4
2.7
4.2
5.5
(0.6)
East
North
Central
12,370
12,606
13,319
13,886
14,435
14,987
15,763
16,434
17,467
18,443
18,921
19.5G2
20,712
22,086
21,550
1.9
5.7
4.3
3.9
3.8
5.2
4.3
6.3
5.6
2.6
3.4
5.9
6.6
(2.4)
West
North
Central
South
Atlantic
East
South
Central
| ItVih Usase/Customer |
8,381
8,619
9,394
9,767
10,273
10,791
11,464
12,278
13,096
14,078
14,863
15.258
15 ,920
16 , 845
16,678
10,770
11,303
12,121
12,631
13,380
14,241
15,433
16,263
17,580
18,845
20,027
20,703
2.1 ,488
22 , 729
21,942
23,
13,
23,
24,
25,
25,
26,
26,
27,
28,
29,
29,
:n. .
625
537
943
789
425
762
605
791
749
815
589
859
413
32,987
34,
Usage/Customer Change
2."
9.0
4.0
5.2
5.0
6.2
7.1
6.7
7.5
5.6
2.7
4.3
5.8
(1.0)
(percent )
4.9
7.2
4 .2
6.0
6.4
8.4
5.4
8.1
7.2
6.3
3.4
3.8
5.8
(3.5)
0.
1.
3.
2.
1.
3.
0.
3.
3.
2.
0.
5.
5.
(2.
168
4
7
5
6
3
5
5
6
8
7
9
2
6
5)
West
South
Central
10,348
10,639
11,376
12,843
13,704
14.747
16,056
17,261
18,644
20,901
22,205
22,916
24.700
25,804
25,913
2.8
11.6
8.1
6.7
7.6
8.9
7.5
8.2
11.9
6.2
3.2
8.0
4.2
0.4
Mountain
13,598
14,608
15,205
15,483
16,254
16,671
17,953
18,346
19,179
20,738
21,133
21,201
21,737
22,039
22,397
7.9
3.7
1.8
5.0
2.6
7.7
2.4
4.3
8.1
1.9
0.3
2.5
1.4
1.6
Pacific
13,428
13,939
14,327
14,846
15.CS7
16,3^9
17.7G8
18,627
19,428 .
20,533
21 ,030
21.501
22,170
22,219
21,470
3.8
2.8
3.6
5.7
4.1
8.8
4.8
4.3
5.7
2.4
2.2
3.1
0.2
(3.4)
Alaska &
Hawaii
9,766
10,463
11,079
11,577
12.022
12.526
13.261
13,929
14,549
15,555
16,239
17,479
18,246
19 . 165
19 , 396
7.1
5.9
4.5
3.8
4.2
5.9
5.0
•4.5
6.9
4.4
7.6
4.4
5.0
1.2
Source: EEI
I
>&.
01
-------
Exhibit V-4
REGIONAL PROJECTION
THOUSANDS OF CUSTOMERS AND GROWTH RATES
(for selected years)
-
1972
Customers
FOP*
PCGR**
1975
Customers
POP*
PCGR**
1980
Customers
POP*
PCGR**
1335
Customers
POP*
PCGR**
1990
Customers
POP*
PCGR**
United
States
76,146
36.7
2.3
81 , 505
37.6
2.5
92,237
39.5
2.6
104,711
41.7
. 2.4
118,017
43.9
2.4
New
England
4,444
36.5
2.0
4.691
37.3
2.0
5,185
38.3
2.1
5,751
39.3
2.0
6,325
40.4
2.0
-Middle
Atlantic
12,999
34.3
1.3
13,519
34.7
1.5
14,596
35.4
1.6
15,832
36.0
1.5
17,073
36.7
1.5
East
North
Central
14,691
35.6
2.0
15,559
36.3
2.2
17,320
37.7
2.2
19,349
39.1
2.1
21,447
40.5
2.1
West
North
Central
6,324
38.1
1.7
6,658
39.2
2.0
7,349
41.1
2.2
8,163
43.1
2.1
9,024
45.2
2.1
South
Atlantic
11,765
• 37.2
3.3
12,945
39.2
3.4
15,294
42.7
3.4
18,062
46.6
3.2
21,138
50.8
3.2
East
South
Central
4,883
37.6
2.6
5,266
39.8
2.8
6,050
43.8
2.9
6,982
48.2
2.8
8,024
53.0
2.8
West
South
Central
7,346
37.0
2.5
7,898
38.2
2.7
9,001
40.4
2.8
10,273
42.7
2.5
11,631
45.2
2.5
Mountain
3,303
38.5
3.7
3,681
40.7
3.8
4,433
44.7
3.8
5,339
49.1
3.6
6,360
54.0
3.6
Pacific
10.072
37.9
2.7
10,933
38.7
2.9
12,585
40.0
2.8
14,460
41.4
2.6
16,413
42.8
2.6
Alaska &
Hawaii
319
28.8
3.6
355
30.5
3.6
424
33.6
3.4
500
37.1
3.1
582
40.8
3.1
I
^
Oi
'Percentage of Population
"^Period Compounded Groath Rate
Source: Census Bureau (Department of Commerce), EEI, TBS
-------
Exhibit V-5
ELECTRIC CUSTOMERS AS A PERCENTAGE OF NATIONAL POPULATION
I960 - 1973
(percent)
1960
1961
1962
1963
1964
1965
I960
19G7
1968
1969
1970
1971
1972
1973
United
States
32.71
32.86
33.01
33.35
33.57
33.88
34.22 .
34.53
34.97
35.23
35.67
35.09
36.73
37.17
New
England
34.43
34.57
34.45
34.35
34.31
34.39
34.71
34.91
35.36
35.66
36.08
36.27
36.56
36.89
Middle
Atlantic
32.81
32.79
32.90
33.03
33.15
33.28
33.53
33.75
33.87
34.10
34.29
34.27
34.34
34.52
East
North
Central
. 32.76
32.90
33.09
33.31
33.45
33.62
33.79
33.95
34.38
34.81
35.08
35.30
35.62
35.99
West
North
Central
34.17 r
34.58
34.85
35.18
35.45
35.93
36.25
36.52
36.93
36.88
37.27
37.81
38.16
38.71
Atlantic
30.74
30.94
31.19
31.61
31.65
32.46
33.08
33.69
34.30
34.86
35.60
36.45
37.25
38.45
East
South
Central
30. G9
30.93
31.40
32.12
32.24
32.08
33.30
34.00
34.69
35.26
36.09
36.92
37.67
39.25
West
South
Central
32.58
32.83
32.83
33.56
33.91
34.48
34.79
35.29
35.86
35.45
35.92
36.56
37.03
37.72
Mountain
31.48
31.80
31.98
32.73
32.95
33.39
33.69
34.06
34.61
34.85
35.75
37.03
38.51
40.13
Pacific
35.04
35.07
35.12
35.41
35.76
36.07
30.35
36.41
36.86
37.03
37.41
37. 58
37.96
38.30
Alaska &
Hawaii
23.40
23.40
23.47
24.01
24.59
25.08
25.62
25.95
26,60
26.87
27.57
28.18
28.83
30.10
Sources: EEI, Census Bureau (Department-of Commerce)
-------
Exhibit V-6
REGIONAL HISTORICAL AND PROJECTED POPULATION
1960-1990
(thousands)
Year
1350
1965
1370
1972
1975 .
1380
13S5
1330
United
States
173,974
193,459
203,180
208.411
215,553
232,967
251,272
268,834
New
England
10,531
11.329
11.847
12,154
12,630
13,600
14,687
15,735
Middle
Atlantic
34,270
36,122
37.153
37,852
38.928
41,233
43.869
46,409
East
North
Central
36,291
38,406
40,253
41.236
42,757
"45,906
49,474
52,891
West
North
Central
15,424
15,819
16,319
16,572
16,961
17,856
18,914
19,940
South
Atlantic
26,091
28,743
. 30,671
31,584
33,007
35,769
38,752
41,604
East
South
Central
12,073
' 12,627
12,805
12,903
13.206
13,794
14,477
15,130
West
South
Central
17,010
18,209
19,322
19,836
20,634
22,237
24,008
25,704
Mountain
6,910
7,740
8,234
8,576
9,034
9,903
10,855
11,768
Pacific
29,497
23,489
25.45-1
26,530
28,231
31.409
34 ,.837
38,278
Alaska
& Hawaii
871
975
1.072
1,108
1.165
1,260
1,349
1,425 •
Source: Census Bureau (Department ot Conserce)
-------
Exhibit V-7
REGIONAL GENERATION NOT SOLD* TO ULTIMATE CUSTOMER
1969 - 1974
(percent)
Year
1963
. 1970
1971
1972
1973
1974
United
States
9.4
9.2
9.1
9.7
7.9
8.8
New
England
8.9
9.3
7.6
6.3
5.3
3.4
Middle
Atlantic
3.2
5.3
6.2
6.2
4.2
2.6
East
North
Central
8.8
7.9
7.1
5.4
3.8
3.4
West
North
Central
6.8
8.3
7.9
9.2
6.3
9.4
• South
Atlantic
13.4
11.3
8.0
15.4
15.5
17.0
East
South
Central
7.9
6.6
6.0
8.4
5.9
3.7.
West
South
Central
12.1
12^1
13.1
12.7
9.9
11.6
Mountain
7.8
13.0
17.3
20.9
19.7
22.7
Pacific
12.1
10.6
9.1
7.1
3.9
7.5 ;
Alaska
& Hawaii
7.1
7.9
7.8
8.8
3.8
4.7
^Percent line losses calculated from total Electric Utility Industry generation and total sales to ultimate customers
(Includes "Energy Used by Producer", "Company Use and Free Service", and "Lost and Unaccounted for"
&
co
Source: EEI
-------
Exhibit V-8
REGIONAL BASELINE SUMMARY TABLE
REGIONAL COMPARISON: CAPACITY MIX BY PRIME MOVER
1975
(millions of kilowatts)
Prime
Mover
Coal
Oil
Gas
Nuclear
Hydro
Pumped
Peaker
Other
Total
National
196.2
72.1
89.5
40.7
57.6
8.5
44.8
509.7
New
England
0.5
12.3
0.1
4.9
1.4
0.9
1.7
21.9
Middle
Atlantic
21.3
21.7
1.7
8.0
4.4
1.8
11.9
70.8
East
North
Central
68.9
3.4
3.0
9.2
0.8
1.4
5.8
92.4
West
North
Central
16.2
0.5
7.7
2.0
2.7
0.4
5.2
34.7
South
Atlantic
43.6
18.3
4.0
8.3
5.7
1.1
9.7
90. R
East
South
Central
28.8
0.5
2.7
2.4
5.4
0.2
2.6
42.6
West
South
Central
5.6
5.9
48.5
1.5
2.0
0.3
3.1
66.9
Mountain
9.6
0.7
6.1
0.3
7.8
0.3
1.7
26.6
Pacific
1.5
8.1
15.2
4.1
27.3
2.2
3.0
61.3
Alaska
&
Hawaii
0.2
0.7
0.5
, 0
0.1
0
0.2
1.7
I
Ol
o
Source: PTm (Electric Dtilities)
-------
Exhibit V-9
REGIONAL BASELINE SUMMARY TABLE
REGIONAL COMPARISON: GENERATION MIX BY PRIME MOVER
1975
(billions of kilowatt hours)
Prime
Mover
Coal
Oil
Gas
Nuclear
Hydro
Pumped
Peaker
Other
Total
National
856.9
275.3
263.3
192.3
250.0
34.1
36.6
1908.2
New
England
2.3
42.6
0.3
21.6
5.2
3.2
1.3
76.6
Middle
Atlantic
95.0
80.0
4.2
37.4
16.8
6.8
9.5
249.6
East
North
Central
285.9
11.4
6.6
39.8
3.0
5.0
4.4
356.0
West
North
Central
68.1
1.9
17.7
9.0
9.7
1.4
3.9
111.5
South
Atlantic
191.6 .
66.5
9.8
38.4
21.6
3.7
7.7
339.2
East
South
Central
129.1
1.8
6.7
11.4
21.0
0.8
2.1
172.8
West
South
Central
32.4
28.2
154.3
9.2
10.0
1.3
3.3
238.7
Mountain
43.0
2.4
15.1
1.6
29.9
1.2
1.4
94.5
Pacific
8.2
37.1
47.0
24.0
132.3
10.7
2.9
262.2
Alaska
&
Hawaii
1.3
3.4
1.6
0
0
0
0
7.1
I
en
Source: PTm (Electric Utilities)
-------
Exhibit V-10
REGIONAL BASELINE SUMMARY TABLE
REGIONAL COMPARISON: CAPACITY MIX BY PRIME MOVER
1980
(millions of kilowatts)
Prime
Mover
Coal
Oil
Gas
Nuclear
Hydro
Pumped
Peaker
Other
Total
National
287.1
85.8
48.1
79.7
66.4
11.8
52.0
631.0
New
England
0.6
12.5
0
6.7
1.4
0.9
2.1
24.2
Middle
Atlantic
24.8
22.8
0.3
13.0
5.3
1.8
11.8
79.9
East
North
Central
80.4
5.8
0.5
14.8
0.9
1.4
6.4
110.3
West
North
Central
30.0
2.2
2.0
2.0
2.7
0.4
7.0
46.2
South
Atlantic
55.1
17.0
2.1
17.9
5.8
1.6
10.1
109.6
East
South
Central
36.0
1.5
0.8
10.9
6.6
1.7
2.5
60.0
West
South
Central
21.3
10.0
41.5
6.2
2.0
0.5
4.7
86.2
'Mountain
20.5
1.0
4.8
0.3
10 . 5
0.5
1.7
39.3
Pacific
4.0
18.2
4.3
8.0
31.0
3.0
5.1
73.6
Alaska
&
Hawaii
0.2
0.7
0.4
0
0.1
0
0.2
1.6
I
Ol
to
Source: PTm (Electric Utilities)
-------
Exhibit V-ll
REGIONAL BASELINE.SUMMARY TABLE
REGIONAL COMPARISON: GENERATION MIX BY PRIME MOVER
1980
(billions of kilowatt hours)
Prime
Mover
Coal
Oil
Gas
Nuclear
Hydro
Pumped
Peaker
Other
Total
National
1303.2
319.6
142.4
404.1
301.8
49.4
45.2
2565.6
New
England
3.2
50.9
0.1
36.5
6.7
4.0
1.9
403 . 3
Middle
Atlantic
122.1
86.6
0.8
66.5
23.5
7.5
10.3
317.4
East
North
Central
353.9
19.1
1.2
67.0
3.5
5.3
5.1
455.0
West
North
Central
114.3
4.6
4.1
8.4
9.6
1.4
5.0
-v
147.3
South
Atlantic
280.8
67.1
5.7
95.6
26.5
7.0
9.3
492.0
East
South
Central
133.0
3.4
1.6
41.5
21.4
5.1
1.6
207.6
West
South
Central
132.0
40.8
134.6
38.6
11.1
2.4
5.1
364.6
Mountain
76.2
2.8
9.5
1.3
34.8
1.6
1.1
127.3
Pacific
23.9
70.3
13.7
48.8
163.7
15.2
5.4
341.1
Alaska
&
Hawaii
1.9
4.7
2.1
0
0.8
0
0.3
9.9
i
01
CO
Source: PTm (Electric Utilities)
-------
Exhibit V-12
REGIONAL BASELINE SUMMARY TABLE
REGIONAL COMPARISON: CAPACITY MIX BY PRIME MOVER
1985
(millions of kilowatts)
Prime
Mover
Coal
Oil
Gas
Nuclear
Hydro
Pumped
Peaker
Other
Total
National
343.2
80.9
41.0
132.0
73.5
16.3
64.1
751.0
New
England
0.6
11.7
0
10.7
1.4
1.7
2.7
28.8
Middle
Atlantic
25.8
21.3
0.2
22.2
6.1
1.8
13.0
90.3
East
North
Central
89.0
5.4
0.3
20.9
0.9
2.5
6.9
125.9
West
North
Central
36.0
2.1
1.3
3.3
2.7
0.4
8.3
54.1
South
Atlantic
67.5
15.6
1.8
34.0
6.4
2.5
13.2
141.0
East
South
Central
36.8
1.5
0.6
13.9
6.9
2.1
2.5
64.3
West
South
Central
41.5
9.6
37.6
14.7
2.0
0.8
8.0
114.2
Mountain
26.1
0.9
4.3
0.5
12.4
0.6
2.0
46.8
Pacific
5.8
17.7
3.2
12.0
34.4
4.0
6.7
83.7
Alaska
&
Hawai i
0.3
0.6
0.4
*
0.2
0
0.4
1.9
I
u>
Source: PTm (Electric Utilities)
-------
Exhibit V-13
REGIONAL BASELINE SUMMARY TABLE
REGIONAL COMPARISON: GENERATION MIX BY PRIME MOVER
1985
(billions of kilowatt hours)
Prime
Mover
Coal
Oil
Gas
Nuclear
Hydro
Pumped
Peaker
Total
National
1685.6
293.7
122.4
726.7
359.1
73.4
60.6
3321.4
New
England
3.4
47.7
0.1
63.8
7.4
8.5
2.8
133.6
Middle
Atlantic
136.4
79.5
0.5
122.6
29.0
8.1
12.4
388.5
East
North
Central
422.1
17.4
0.7
101.5
3.8
10.0
5.9
561.4
West
North
Central
147.2
4.7
2.9
14.6
10.1
1.5
6.3
187.3
South
Atlantic
369.3
60.0
5.1
194.2
31.6
11.4
13.1
684.6
East
South
Central
146.5
3.4
1.2
56.7
24.1
7.0
1.8
240.7
West
South
Central
256.0
36.3
119.2
91.9
11.0
3.7
8.7
526.7
Mountain
103.2
2.5
8.9
2.0
43.8
1.8
1.4
163.5
Pacific
37.6
68.6
10.4
79.4
196.5
21.6
7.7
421.8
Alaska
&
Hawaii
3.4
5.0
2.2
0.1
1.7
0
0.6
13.2
I
Ul
01
Source: PTm (Electric Utilities)
-------
V-56
Exhibit V-14
REGIONAL COAL CAPACITY BY IN-SERVICE YEAR
FOR COMPLIANCE WITH CLEAN AIR ACT
In 1985
(millions of kilowatts)
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
National Total
In-Service Year
Pre-1974
0.5
20.8
60.4
16.9
37.2
29.5
1.2
8.9
1.3
176.7
1974-1976
-
1.5
10.0
2.2
6.9
1.7
1.9
5.5
-
29.7
After 1976
-
4.5
22.1
17.3
14.5
7.6
38.0
15.8
3.1
122.9
Total
0.5
26.8
92.5
36.4
58.6
38.8
41.1
30.2
4.4
329 . 3
Source: Sobotka & Co., Inc., unpublished data provided to EPA
November 17, 1975
-------
Exhibit V-15
REGIONAL BASELINE PROJECTIONS
SUMMARY OF CUMULATIVE ADDITIONS
(ADJUSTED FPC ANNOUNCEMENTS)
1975-1980
(millions of kilowatts)
Prime
Mover
Coal
Oil
Gas
Nuclear
Hydro
Pumped
Peaker
Other*
Total
National
79.0
17.6
4.4
48.0
11.4
3.5
13.6
0
177.50
New
England
0
2.2
0
2.6
0
0
0.5
0
5.3
Middle
Atlantic
2.3
4.1
0
6.8
1.0
0
0.9
0
15.1
East
North
Central
16.5
3.9
0
6.6
0.1
0
1.1
0
28.2
West
North
Central
12.3
0.2
0
0
0
0
2.6
0
15.1
South
Atlantic
9.1
5.5
0
11.9
0.8
0.8
1.7
0
29.8
East
South
Central
7.5 .
0
0
9.5
1.2
1.5
1.2
0
20.9
West
South
Central
17.3
0.6
4.3
4.7
0
0.2
2.3
!
0
29.4
Mountain
11.8.
0.3
0
0.3
3.9
0.2
0.1
0
16.6
Pacific
2.6
1.0
0
6.0
4.3
0.9
2.8
0
17.6
Alaska
&
Hawaii
CO
§
1—4
EH
Q
9
Q
a
§
w
M
O
CO
°
-
i
Ol
*"Other" is included in Peaker category
Source: PTm (Electric Utilities)
-------
Exhibit V-16
REGIONAL BASELINE PROJECTIONS
SUMMARY OF CUMULATIVE ADDITIONS
1981-1985
(millions of kilowatts)
Prime
Mover
Coal
Oil
Gas
Nuclear
Hydro
Pumped
Peaker
Other*
Total
National
70.2
0
0
52.3
7.4
4.5
15.0
149.4
New
England
0
0
0
4.0
0
1.0
0.9
5.9
Middle
Atlantic
2.0
0
0
9.2
0.8
0
2.0
14.0
East
North
Central
12.8
0
0
6.1
0
1.0
1.0
20.9
West
North
Central
7.5
0
0
1.4
0
0
1.7
10.6
South
Atlantic
15.2
0
0
16.0
0.5
1.0
3.6 '
36.3
East
South
Central
2.7
0
0
3.1
0.5
0.5
0
6.3
West
South
Central
21.7
0
0
8.6
0
0.3
3.6
34.2
Mountain
6.6
0
0
0
2.0
0
0.5
9.1
Pacific
2.1
0
0
4.1
3.6
0.9
2.0
12.7
Alaska
&
Hawaii
0.1
0
0
0
0.1
0
0.2
0.4
I
01
CO
"Other" ia -included in Peaker category
Source: PTu (Electric Utilities)
-------
Exhibit V-17
REGIONAL BASELINE PROJECTIONS
SUMMARY OF ASSUMPTIONS
1975
Region
National
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
Alaska & Hawaii
% of Capacity
Public
21.2
3.1
6.1
5.9
30,9
7.8
60.6
17.6
29.5
49.7
n.a.
Private
78.8
96.9
93.9
94.1
69.1
92.2
39.4
82.4
70.5
50.3
n.a.
o
Fuel Prir.e Index
Coal
1.00
1.59
1.20
0.98
0.69
1.30
0.82
0.31
0.44
0.63
n.a.
Oil
1.00
1.02
1.09
0.99
0.79
0.95
1.00
0.99
0.91
1.02
n.a.
Gas
1.00
2.67
2.14
1.52
0.83
1.20
1.07
0.87
1.02
1.20
n. a.
Non-Fuel
O&M Index3
1.00
1.55
1.51
1.07
1.12
0.83
0.84
0.56
0.82
1.02
n.a.
Capacity
Factor4
<%)
42.7
39.6
39.9
43.2
39.2
42.2
45.6
41.5
40.7
49.3
48.1
I
Ul
to
n.a. = not available
Sources: 1) EEI Data, 1973, adjusted for announced capacity additions.
2) Index relative to national average; EEI Data, 1974, adjusted
to limits of +20 percent of national average by 1985.
3) Index relative to national average; TBS survey of 47 electric
utilities for EPA Rate Study.
4) PTm (Electric Utilities); based on announced and projected
capacity additions.
-------
Exhibit V-18
REGIONAL BASELINE PROJECTIONS
SUMMARY OF ASSUMPTIONS
1980
Region
National
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
Alaska & Hawaii
% of Capacity
Public
21.2
2.9
6.4
5.7
32.5
7.8
61.8
17.8
30.2
49.9
n.a.
Private
78.8
97.1
93.6
94.3
67.5
92.2
38.2
82.2
69.8
50.1
n.a.
2
Fuel Price Index
Coal
1.00
1.40
1.20
0.98
0.74
1.25
0.82
0.53
0.60
0.70
n.a.
Oil
1.00
1.02
1.09
0.99
0.84
0.95
1.00
0.99
0.91
1.02
n.a.
Gas
1.00
2.00
1.70
1.38
0.83
1.20
1.07
0.87
1.02
1.20
n.a.
Non-Fuel
O&M Index3
1.00
1.55
1.51
1.07
1.12
0.83
0.84
0.56
0.82
1.02
n.a.
Capacity
Factor4
(%)
46.4
48.4
45.1
46.6
39.5
50.9
39.3
48.3
36.8
53.0
70.5
Ct
o
n.a. = not available
Sources: 1) EEI Data, 1973, adjusted for announced capacity additions.
2) Index relative to national average; EEI Data, 1974, adjusted
to limits of +20 percent of national average by 1985.
3) Index relative to national average; TBS survey of 47 electric
utilities for EPA Rate Study.
4) PTm (Electric Utilities); based on announced and projected
capacity additions.
-------
Exhibit V-19
REGIONAL BASELINE PROJECTIONS
SUMMARY OF ASSUMPTIONS
1985
Region
National
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
Alaska & Hawaii
% of Capacity
Public
21.2
2,8
6.6
5.7
33.1
7.8
62.0
17.8
30.5
50.2
n. a.
Private
78.8
97.2
93.4
94.3
66.9
92.2
38.0
82.2
69.5
49.8
n. a.
o
Fuel Price Index
Coal
1.00
1.20
1.20
0.98
0.80
1.20
0.82
0.80
0.80
0.80
n.a.
Oil
1.00
1.02
1.09
0.99
0.90
0.95
1.00
0.99
0.91
1.02
n.a.
Gas
1.00
1.20
1.20
1.20
0.83
1.20
1.07
0.87
1.02
1.20
n.a.
Non-Fuel
O&M Index3
1.00
1.55
1.51
1.07
1.12
0.83
0.84
0.56
0.82
1.02
n.a.
Capacity
Factor4
(%)
50.5
52.4
48.9
50.6
42.9
55.1
42.5
52.5
39.9
57.4
78.7
n.a. = not available
Sources: 1) EEI Data, 1973, adjusted for announced capacity additions.
2) Index relative to national average; EEI Data, 1974, adjusted
to limits of jf20 percent of national average by 1985.
3) Index relative to national average; TBS survey of 47 electric
utilities for EPA Rate Study.
4) PTm (Electric Utilities); based on announced and projected
capacity additions.
-------
V-63
APPENDIX V-A
NEW ENGLAND (REGION I)
Exhibit V-A-1
Exhibit V-A-2
Exhibit V-A-3
Exhibit V-A-4
Exhibit V-A-5
Capacity Report
Financial Baseline Projections
Coal Capacity: Coverage for
Compliance with Clean Air Act
Nuclear and Fossil Capacity:
Coverage for Compliance with
Water Guidelines
Impacts of Air & Water Pollution
Regulations
Preceding page blank
-------
NEU ENGLAND - BASELINE UITH OIL AND GAS CONVERSIONS
TEMPLE PARKER AND SLOANE.INC.
PTM ELECTRIC UTILITY MOPEL
CAPACITY REPORT
1974
1975
1976
1977
1978
1979
1980
1981
1982
1903
1984
1985
1986
1987
1983
1989
1990
KUH
GEN
74.6
76.6
82.1
87.0
92.2
97.6
103.3
108.8
114.6
120.6
127.0
133.6
140.7
148.0
155.7
163.8
172.3
NET KUH
SALES
69.3
70.9
76.0
80.5
85.3
90.4
95.9
101.0
106.4
112.1
118.1
124.3
130.9
137.8
145.1
152.7
160.6
12/31 TOTAL
CAPACITY ADDNS
19,5 1.5
21.9 .2..S
21.9 .1
21.8 .1
22.2 .4
23.2
24.2
25.2
26.0
27.1
27.9
28.8
30.4
31.9
33.6
.0
.2
.2
.1
,2
.2
.2
.6
.7
.9
35.3 2.0
37.1 2.0
TOTAL
RETIRED
.1
.1
.1
.1
.1
.1
.1
.2
.2
.2
.2
.2
.2
.2
.2
.2
.2
I
Oi
TOTAL
FOSSIL
COAL
CAPACITY REPORT
OIL GAS
NUCLEAR HYDRO
PUMPED
STORAGE
IC/GT
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1789
1990
11.5
13.0
12.9
12.8
13.0
13.0
13.1
13.0
12.8
12.7
12.5
12.3
12.2
12.0
11.8
11.6
11.4
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
10.8
12.3
12.2
12.2
12.4
12.3
12.5
12.3
12.2
12.0
11.9
11.7
11.5
11.4
11.2
11 .0
10.9
.1
.1
.1
.1
.1
0
0
0
0
0
0
0
0
0
0
0
0
4.1
4.9
4.9
4.9
4.9
5.8
6.7
7.6
8.3
9.1
9.9
10,7
11.9
13.1
14.4
15.8
17.2
1.4
1.4
1.4
1.4
1.4
1.4
1.4
1 .4
1.4
1.4
1.4
1.4
1.4
1.4
1.4
1.4
1.4
.9
.9
.9
.9
.9
.9
.9
1.0
1.2
1.4
1.5
1.7
2.0
2.3
2.6
2.9
3.2
1.6
1.7
1.8
1.8
2.0
2.1
2.1
2.2
2.3
2.5
2.6
2.7
2.9
3.1
3.4
3.6
3.9
Source: PTm (Electric Utilities)
-------
Exhibit V-A-2
NEW ENGLAND - BASELINE WITH OIL AND GAS CONVERSIONS
FINANCIAL BASELINE PROJECTIONS
(BILLIONS OF 1975 DOLLARS)
1975 1980 1985
CAPITAL EXPENDITURES
(NET OF CWIP CHANGE)
TOTAL SINCE 1974 1.43 4,13 9.30
CONSTRUCTION WORK IN PROGRESS
END OF YEAR .39 1.64 2.68
EXTERNAL FINANCING
TOTAL SINCE 1974 .66 2.77 6.74
OPERATING REVENUES
TOTAL FOR YEAR 3.1 A 3.88 4.85
TOTAL SINCE 1974 3.16 21.00 43.32
OPERATING AND MAINTENANCE EXPENSE
TOTAL FOR YEAR 1.95 2.38 2.69
TOTAL SINCE 1974 1.95 12.97 25.77
CONSUMER CHARGES
(MILLS PER KWH)
AVERAGE FOR YEAR 44.53 40.52 38.99
COVERAGE RATIO
(EDIT TO INTEREST 3.13 3.59 3.39
Source: PTm (Electric Utilities)
-------
V-66
Exhibit V-A-3
COAL CAPACITY
COVERAGE FOR COMPLIANCE WITH CLEAN AIR ACT
New England
In 1985
(millions of kilowatts)
Scrubbers
S02
TSP '
Joint
Medium Sulfur Coal
Western Low Sulfur Coal
Blending
S02
Joint
Precipitators
Subtotal
In Compliance
Conversion to Oil
Total
In-Service Year
Pre-197.4
-
-
-
-
-
-
-
0.17
0.17
0.33
-
0.50
1974-1976
-
-
. -
-
-
—
•~
—
—
-
-
-
After 1976
-
'
-
-
-
—
.—
-
—
-
-
-
Total
-
-
-
•
-
- .
-
0, 17
0.17
0.33
-
0.50
Source: Sobotka & Co., Inc., unpublished data provided to EPA
November 17, 1975.
-------
V-67
Exhibit V-A-4
NUCLEAR AND FOSSIL CAPACITY
COVERAGE FOR COMPLIANCE WITH WATER GUIDELINES
New England
In 1985'
(millions of kilowatts)
Thermal
Before 316(a)
After 316(a)
Entrainment
Chemical
1977 Guidelines
1983 Guidelines
State Water Quality Standards
Nuclear Capacity
Pre-1974
1.2
0
0
0.3
0.3
0
New
6.9
1.1
5.6
0
0
0
Fossil Capacity
Pre-1974
4.6
0.5
0.1
2.3
2.3
2.3
New
2.2
1.2
0.7
0.4
0.4
0
Source: EPA regional offices, 1975
-------
V-63
Exhibit V-A-5
IMPACTS OF AIR AND WATER POLLUTION REGULATIONS
ON
THE ELECTRIC UTILITY INDUSTRY
New England
1975-1985
-
Capacity Conversions
011 to Coal
Gas to Coal
Gas to 011
Air Regulations
Scrubbers
S02
TSP
Joint
Medium Sulfur Coal
Western Low- Sulfur Coal
Blending
S02
Joint
Preci pita tors
Effluent Guidelines
Fossil
Thermal
316 B
1977 Chemical
1983 Chemical
Nuclear
Thermal
316 B
Chemical
State Water Quality Standards
Fossil Plants
Nuclear Plants
Total1
Total Coverage
1975-1985
| megawatts |
89
-
75
-
-
-
-
-
.
-
170
1727
867
2639
2698
1160
5651
279
2289
Cumulative Capital
Expenditures For
Pollution Control
1975-1985
Operating and
Maintenance Expense
For Pollution Control
1985
| billions of 1975 dollars 1
$ .003
-
.001
-
-
-
-
-
-
-
.003
.046
.030
.006
.002
.030
.147
*
.086
-
$ .349
$(.003)
-
.006
-
.
-
-
-
-
*
.005
.003
.001
*
.002
.011
*
.009
-
$ .033
*less than .0005
^Totals include impact of energy penalty but exclude impact of conversions.
Source: PTm (Electric Utilities)
-------
V-69
APPENDIX V-B
MIDDLE ATLANTIC (REGION II)
Exhibit Y-B-1 Capacity Report
Exhibit V-B-2 Financial Baseline Projections
Exhibit V-B-3 Coal Capacity: Coverage for
Compliance with Clean Air Act
Exhibit V-B-4 Nuclear and Fossil Capacity:
Coverage for Compliance with
Water Guidelines
Exhibit V-B-5 Impacts of Air & Water Pollution
Regulations
-------
MIDDLE ATLANTIC - BASELINE WITH OIL AND GAS CONVERSIONS
TEMPLE BARKER AND SLDANE.INC.
PT« ELECTRIC UTILITY MOUEL
CAPACITY REPORT
1974
1975
1976
1977
1978
1979
1980
19B1
1982
1983
1984
1985
1986
1987
1988
1989
1990
KUH
GEN
245.6
249.6
264.5
276.8
289.8
303.0
317.4
330. 5
344.2
353. 4
373.2
388.5
404.5
421.2
43R.5
456 . 4
475.0
NET KUH
SALES
233.5
236.1
250.2
262.1
274.8
287.7
301.8
314.6
327.8
341.6
355.8
370.6
384.1
402.2
418.9
436.2
454.2
12/31
CAPACITY
67.7
70.8
73.6
74.9
76.4
76.9
79.9
82.3
84.3
86.3
88.4
90.3
93.9
97.9
101.8
105.8
110.4
TOTAL
ADDNS
4.8
3.5
3.4
1.8
2.0
.9
3.5
3.0
2.7
2.7
2.8
2.8
4.4
4.6
4.7
4.8
5.1
TOTAL
RETIRED
.3
.4
.4
.4
.4
.4
.4
.6
.7
.7
.7
.71
.7
.7
.7
.7
.7
I
~J
c
COAL
CAPACITY REPORT
OIL GAS
NUCLEAR HYDRO
PUMPED
STORAGE
IC/GT
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1903
1989
1990
43.5
44.7
45.6
46.9
47.0
46.7
48.0
47.9
47.7
47.6
47.4
47.2
47.3
47.4
47. J7.
47.6
47.8
21.3
21.3
21.3
22.0 -
22.2
22.4
24.8
25.1
25.2
25.4
25.5
25.8
26.1
26.5
27. 1
27. 3
28.1
20.5
21.7
22 .9
23.8
24.0
23.7
22.8
22.5
22.3
22.0
21.7
21.3
21.0
20.7
20.3
20.0
19.7
1.7
1.7
1.4
1.1
.8
.6
.3
.3
.3
.2
^ ~*
f •»
.1
.1
.1
.1
0
6.3
8.0
9.9
9.9
11.3
12.2
13.0
15.0
16.8
18.6
20.4
22.2
25.1
2fl.l
31.3
34.5
37.9
4.4
4.4
4.4
4.4
4.4
4.4
5.3
5.6
5.7
5.8
6.0
6.1
6.3
6.6
6.8
7.0
7.4
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
11.7
11.9
11.9
11.9
11.9
11.8
11.8
12.0
12.3
12.5
12.8
13.0
13.4
14.0
14.4
14.9
15.5
Source: PTm (Electric Utilities)
-------
Exhibit V-B-2
MIDDLE ATLANTIC - BASELINE WITH OIL AND GAS CONVERSIONS
FINANCIAL BASELINE PROJECTIONS
(BILLIONS OF 1975 HOLLARS)
1975 1980 1985
CAPITAL EXPENDITURES
(NET OF CUIP CHANGE)
TOTAL SINCE 1974 2.37 11.32 24.16
CONSTRUCTION WORK IN PROGRESS
END OF YEAR 2.81 4.24 7.16
EXTERNAL FINANCING
TOTAL SINCE 1974 .03 5.12 14.95
OPERATING REVENUES
TOTAL FOR YEAR 9.67 11.69 14.16
TOTAL SINCE 1974 9.67 64.45 130.20
OPERATING AND MAINTENANCE EXPENSE
TOTAL FOR YEAR 6.05 7.45 8.63
TOTAL SINCE 1974 6.05 40.55 81.25
CONSUMER CHARGES
(MILLS PER KUH)
AVERAGE FOR YEAR 40.96 38.72 38.20
COVERAGE RATIO
(EBIT TO INTEREST 2.88 2.78 2.77
Source: PTm (Electric Utilities)
-------
V-72
Exhibit V-B-3
COAL CAPACITY
COVERAGE FOR COMPLIANCE WITH CLEAN AIR ACT
Middle Atlantic
In 1985
(millions of kilowatts)
Scrubbers
S02
TSP •
Joint
Medium Sulfur Coal
Western Low Sulfur Coal
Blending
S02
Joint
Precipitators
Subtotal
In Compliance
Conversion to Oil
Total
In-Service Year
Pre-1974
0.7
-
3.9
-
-
1.0
2.1
10.7
18.4
1.7
0.7
20.8
1974-1976
'
-
1.5
-
-
-
-
-
1.5
'
-
1.5
After 1976
-
-
2.0
-
2.5
-
-
-
4.5
-
-
4.5
Total
0.7
-
7.4
•
2.5
1.0
2.1
10.7
24.4
1.7
0.7
26.8
Source: Sobotka & Co., Inc., unpublished data provided to EPA
November 17, 1975.
-------
V-73
Exhibit V-B-4
NUCLEAR AND FOSSIL CAPACITY
COVERAGE FOR COMPLIANCE WITH WATER GUIDELINES
Middle Atlantic
In 1985
(millions of kilowatts)
Thermal
Before 316 (a)
After 316(a)
Entrainment
Chemical
1977 Guidelines
1983 Guidelines
State Water Quality Standards
Nuclear Capacity
Pre-1974
6.0
2.1
2.3
6.3
6.3
0.1
New
18.1
0
0.9
11.3
11.3
1.5
i
Fossil Capacity
Pre-1974
9.9
1.8
4.0
41.2
41.2
8.4
New
9.6
0
0.6
4.2
1
j.
7.4 j
0.2 1
Source: EPA regional offices, 1975
-------
V-74
Exhibit V-B-5
IMPACTS OF AIR AND WATER POLLUTION REGULATIONS
ON
THE ELECTRIC UTILITY INDUSTRY
Middle Atlantic
1975-1985
Capacity Conversions
Oil to Coal
Gas to Coal
Gas to Oil
Air Regulations
Scrubbers
S02
TSP
Joint
Medium Sulfur Coal
Western Low- Sulfur Coal
Blending
S02
Joint
Preci pita tors
Effluent Guidelines
Fossil
Thermal
316 B
1977 Chemical
1983 Chemical
Nuclear
Thermal
316 B
Chemical
State Water Quality Standards
Fossil Plants
Nuclear Plants
Total1
Total Coverage
1975-1985
megawatts |
1975
225
1050
700
-
7449
-
2490
1000
2100
10700
1783
5003
45404
48607
2130
3245
17574
8588
1636
Cumulative Capital
Expenditures For
Pollution Control
1975-1985
Operating and
Maintenance Expense
For Pollution Control
1985
| billions of 1975 dollars 1
$ .061
.018
.012
.056
-
,794
-
.191
.005
.014
.197
.085
.226
.122
.053
.134
.182
.016
.334
.055
$2.465
$(.076)
.018
.089
.008
.
.108
-
.033
.004
.008
.020
.007
.020
.024
.003
.001
.006
.004
.034
.003
$.284
Totals include impact of energy penalty but exclude impact of conversions.
Source: PTm (Electric Utilities)
-------
V-75
APPENDIX V-C
EAST NORTH CENTRAL (REGION III)
Exhibit V-C-1 Capacity Report
Exhibit V-C-2 Financial Baseline Projections
Exhibit V-C-3 Coal Capacity: Coverage for
Compliance with Clean Air Act
Exhibit V-C-4 Nuclear and Fossil Capacity:
Coverage for Compliance with
Water Guidelines
Exhibit V-C-5 Impacts of Air & Water Pollution
Regulations
-------
Exhibit, V-C-1
EAST NORTH CENTRAL - BASELINE WITH OIL AND GAS CONVERSIONS
TEMPLE PARKER AND SLOANErlNC.
PTM ELECTRIC UTILITY MOHEL
CAPACITY REPORT
1974
197S
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
TOTAL
FOSSIL
69.7
75.2
77.2
80.1
83.0
84.9
8A.8
88.6
90.1
91.6
93.1
94.7
97.7
100 . 8
104.0
107.4
110.9
KUH
GEN
348.5
356.0
378.1
395.8
414.5
433.7
455.0
474.6
495.0
516.3
538.4
561.4
585.3
610.2
636.0
662.8
690.6
COAL
64.2
68.9
70.8
73.3
75.9
77.7
30.4
82.4
84.0
85.7
87.3
89.0
92.0
95.3
98.7
102.2
105.9
NET KUH
SALES
324.4
328.6
348.8
366.1
384.5
403.4
423.9
442.6
462.1
482.3
503.3
525.1
547.8
571 .4
595.8
621.2
647.6
CAPACITY
OIL
2.5
3.4
4.0
5.0
5.7
6.2
5.8
5.7
5.6
5.6
5.5
5.4
5.3
7>.3
5.2
5. 1
5.0
12/31
CAPACITY
86.0
92.4
95.3
98.4
103.4
106.6
110.3
113.9
116.8
119.8
122.8
125.9
131.3
136.9
142.7
148.7
155.0
REPORT
GAS
3.0
3.0
2.4
1.9
1.4
1.0
.5
.5
.4
.4
.3
.3
.2
1
.1
. 1
0
TOTAL
ADDNS
6.3
6.9
3.5
3.7
5.7
3.8
4.4
4.5
4.1
4.1
4.1
4.1
6.4
6.6
6". 9
7.2
7.4
NUCLEAR
8.3
9.2
10.1
10.1
11.8
12.9
14.8
16.1
17.3
18.5
19.7
20.9
22.7
24.6
26.6
in -7
*.U • /
30.9
TOTAL
RETIRED
.3
.4
.7
.7
.6
.6
.6
1.0
.0
.1
.1
.1
.1
.1
.1
.1
.1
HYDRO
.S
.8
.8
.9
.9
.9
.9
.9
.9
.9
.9
.9
.9
.9
.9
.9
.9
PUMPED
STORAGE
1.4
1.4
1.4
1.4
1.4
1.4
1.4
1.7
1.9
2.1
2.3
2.5
2.9
3.2
3.6
3.9
4.3
IC/OT
5.8
5.8
5.8
5.9
6.3
6.5
6.4
6.6
6.6
6.7
6.8
6.9
7.1
7.4
7.6
7.8
8.0
I
*3
O5
Source: PTm (Electric Utilities)
-------
Exhibit V-C-2
EAST NORTH CENTRAL - BASELINE WITH OIL AND GAS CONVERSIONS
FINANCIAL BASELINE PROJECTIONS
(BILLIONS OF 1975 HOLLARS)
1975 1980 1985
CAPITAL EXPENDITURES
(NET OF CUIP CHANGE)
TOTAL SINCE 1974 ' 3.74 18.48 35.35
CONSTRUCTION WORK IN PROGRESS
END OF YEAR 3.83 5.26 8.79
EXTERNAL FINANCING
TOTAL SINCE 1974 2.70 11.42 23.40 ,
-4
OPERATING REVENUES -4
TOTAL FOR YEAR 10.01 13.60 17.47
TOTAL SINCE 1974 10.01 71.00 150.49
OPERATING AND MAINTENANCE EXPENSE
TOTAL FOR YEAR 5.34 7.75 10.03
TOTAL SINCE 1974 5.34 39.82 85.21
CONSUMER CHARGES
(MILLS PER KWH)
AVERAGE FOR YEAR 30.46 32.09 33.27
COVERAGE RATIO
-------
V-78
Exhibit V-C-3
COAL CAPACITY
COVERAGE FOR COMPLIANCE WITH CLEAN AIR ACT
East North Central
In 1985
(millions of kilowatts)
Scrubbers
S02
TSP •
Joint
Medium Sulfur Coal
Western Low Sulfur Coal
Blending
S02
Jpint
Precipitators
Subtotal
In Compliance
Conversion to Oil
Total
In-Service Year
Pre-1974
10.0
3.2
8.1
9.5
1.4
-
12.8
2.4
47.4
12.1
0.9
60.4
1974-1976
-
-
4.1
4.5
0.5
-
-
0.9
10.0
-
-
10.0
After 1976
-
-
8.7
-
13.4
-
-
-
22.1
-
-
22.1
Total
10.0
3.2
20.9
14.0
15.3
-
12.8
3.3
79.5
12.1
0.9
92.5
Source: Sobotka & Co., Inc., unpublished data provided to EPA
November 17, 1975.
-------
V-79
Exhibit V-C-4
NUCLEAR AND FOSSIL CAPACITY
COVERAGE FOR COMPLIANCE WITH WATER GUIDELINES
East North Central
In 1985
(millions of kilowatts)
Thermal
Before 316 (a)
After 316(a)
Entrainment
Chemical
1977 Guidelines
1983 Guidelines
State Water Quality Standards
Nuclear Capacity
Pre-1974
0
0
0
0
0
0
New
0
0
0
0
0
0
Fossil Capacity t
Pre-1974
2.4
2.4
0
0
0
0
New
0.3 1
0.3
0
0
0
0
s
Source: EPA regional offices, 1975
-------
V-80
Exhibit V-C-5
IMPACTS OF AIR AND WATER POLLUTION REGULATIONS
ON
THE ELECTRIC UTILITY INDUSTRY
East North Central
1975-1985
Capacity Conversions
Oil to Coal
Gas to Coal
Gas to Oil
Air Regulations
Scrubbers
S02
TSP
Joint
Medium Sulfur Coal
Western Low- Sulfur Coal
Blending
S02
Joint
Preci pita tors
Effluent Guidelines
Fossil
Thermal
316 B
1977 Chemical
1983 Chemical .
Nuclear
Thermal
316 B
Chemical
State Water Quality Standards
Fossil Plants
Nuclear Plants
Total1
Total Coverage
1975-1985
| megawatts |
1050
1500
675
10000
3200
20912
14007
15298
-
12800
3285
2347
-
-
-
-
-
Cumulative Capital
Expenditures For
Pollution Control
1975-1985
Operating and
Maintenance Expense
For Pollution Control
1985
| billions of 1975 dollars |
$.033
.121
.008
.975
.065
2.228
.365
1.184
-
.088
.044
.093
-
•
-
-
-
-
-
$5.041
$(.033)
.087
.043
.103
..006
.242
.100
.171
-
.043
.004
.007
-
-
-
-
-
-
-
$.676
Totals include impact of energy penalty but exclude impact of conversions.
Source: PTm (Electric Utilities)
-------
V-81
APPENDIX V-D
WEST NORTH CENTRAL (REGION IV)
Exhibit V-D-1 Capacity Report
Exhibit V-D-2 Financial Baseline Projections
Exhibit V-D-3 Coal Capacity: Coverage for
Compliance with Clean Air Act
Exhibit V-D-4 Nuclear and Fossil Capacity:
Coverage for Compliance with
Water Guidelines
Exhibit V-D-5 Impacts of Air & Water Pollution
Regulations
-------
UEST NORTH CENTRAL - BASELINE WITH OIL AND GAS CONVERSIONS
TEMPLE BARKER AND SLOANEtlNC.
PTM ELECTRIC UTILITY HOHEL
CAPACITY REPORT
1774
1975
1976
1977
1970
1979
1980
1981
1982
1903
1984
1985
1986
1987
1988
1989
1990
KUH
GEN
109.3
111.5
119.1
125.5
132.4
139.5
147.3
154. A
162.2
170.2
178.5
1B7.3
196.5
206.2
216.3
226.8
237.8
NET KUH
SALES
101.0
102.8
109.6
115.7
122.1
128.7
136. 0
142.8
149.9
157.3
165.1
173.2
101.8
190.9
200.3
210.1
220.4
12/31
CAPACITY
32.9
34.7
35.6
38.3
41.1
43.7
46.2
47.9
49.3
51.0
52.6
54.1
56.8
59.5
62.4
65.6
68.8
TOTAL
ADPNS
2.5
2.0
1.3
3.2
3.0
2.8
2.8
2.3
1.9
2.1
2.1
2.2
3.2
3.4
3.5
3.6
3.8
TOTAL
RETIRED
.1
.1
.3
.4
,2
.2
.2
.4
.5
.5
.5
.5
.5
.6
.6
.6
.6
I
oo
to
COAL
CAPACITY REPORT
OIL GAS
NUCLEAR HYDRO
PUMPED
STORAGE
IC/OT
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
19B7
1938
1989
1990
23.1
24.4
25.2
27.4
29.5
31.6
34.1
35.2
36.2
37.3
38.3
39.4
41.2
43.1
45.1
47.2
49.4
14.8
16.2
17.8
21.0
23.9
26.7
30.0
31.3
32.4
33.6
34.8
36.0
37.9
40.0
42.2
44.4
46.7
«5
.5
.8
1.3
1.5
1.8
2.2
2.1
2.1
2.1
2.1
2.1
2.1
2.1
2.0
2.0
2.0
7.8
7.7
6.5
5.3
4.1
3.0
2.0
1.8
1.7
1 .6
1.4
1.3
1.2
1.0
.9
.8
.6
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.3
2.5
2.8
3.1
3.3
3.7
4.1
4.5
5.0
5.5
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4.7
5.2
S.3
5.8
6.S
7.0
7.0
7.3
7.5
7.8
8.1
8.3
8.8
9.2
9.7
10.3
10.8
Source: PTm (Electric Utilities)
-------
Exhibit V-D-2
WEST NORTH CENTRAL - BASELINE WITH OIL AND GAS CONVERSIONS-
FINANCIAL BASELINE PROJECTIONS
(EULHONS OF 1975 DOLLARS)
1975 1980 1985
CAPITAL EXPENDITURES
(NET OF CUIP CHANGE)
TOTAL SINCE 1974 1.02 8.47 15.64 ' <
CONSTRUCTION UORK IN PROGRESS 00
END OF YEAR 1.43 2.09 3.61 W
EXTERNAL FINANCING
TOTAL SINCE 1974 -.06 5.00 10.28
OPERATING REVENUES
TOTAL FOR YEAR 3.24 4.67 6.19
TOTAL SINCE 1974 3.24 23.56 51.41
OPERATING AND MAINTENANCE EXPENSE
TOTAL FOR YEAR 1.46 2.32 3.28
TOTAL SINCE 1974 1.46 11.42 25.83
CONSUMER CHARGES
(MILLS PER KUH)
AVERAGE FOR YEAR 31.57 34.31 35.72
COVERAGE RATIO
(EBIT TO INTEREST 3.73 3.03 2.90
Source: PTm (Electric Utilities)
-------
V-84
Exhibit V-D-3
COAL CAPACITY
COVERAGE FOR COMPLIANCE WITH CLEAN AIR ACT
West North Central
In 1985
(millions of kilowatts)
Scrubbers
S02
TSP '
Joint
Medium Sulfur Coal
Western Low Sulfur Coal
Blending
S02
Joint
Precipitators
Subtotal
In Compliance
Conversion to Oil
Total
In-Service Year
Pre-1974
3.2
0.9
-
-
-
4.8
-
5.5
14.4
2.5
-
16.9
1974-1976
-
-
1.3
0.9
-
• ' -
-
.- -
2.2
-
-
2.2
After 1976
-
-
7.1
-
10.2
-
-
-
17.3
-
-
17.3
Total
3.2
0.9
8.4
0.9
10.2
4.8
-
5.5
33.9
2.5
-
36.4
Source: Sobotka & Co., Inc., unpublished data provided to EPA
November 17, 1975.
-------
V-85
Exhibit V-D-4
NUCLEAR AND FOSSIL CAPACITY
COVERAGE FOR COMPLIANCE WITH WATER GUIDELINES
West North Central
In 1985
(millions of kilowatts)
Thermal
Before 316(a)
After 316(a)
Entrainment
Chemical
1977 Guidelines
1983 Guidelines
State Water Quality Standards
Nuclear Capacity
Pre-1974
0.3
0.3
*
0.1
0.1
0
New
1.4
1.4 .
*
0.1
0.1
0
I
Fossil Capacity
i
Pre-1974
17.7
7.3
0.4
4.5
4.5
0
New
12.9
4.4
3.0
0.6
1.5
0 |
Source: EPA regional offices, 1975
* less than 0.05
-------
V-86
Exhibit V-D-5
IMPACTS OF AIR AND WATER POLLUTION REGULATIONS
ON
THE ELECTRIC UTILITY INDUSTRY
West North Central
1975-1985
'
Capacity Conversions
Oil to Coal
Gas to Coal
Gas to Oil
Air Regulations
Scrubbers
S02
TSP
Joint
Medium Sulfur Coal
Western Low- Sulfur Coal
Blending
S02
Joint
Preci pita tors
Effluent Guidelines
Fossil
Thermal
316 B
1977 Chemical
1983 Chemical
Nuclear
Thermal
316 B
Chemical
State Water Quality Standards
Fossil Plants
Nuclear Plants
Total1
Total Coverage
1975-1985
| megawatts J
675
3075
2100
3200
900
8360
884
10188
4800
-
5500
11769
3359
5090
6022
1650
69
194
Cumulative Capital
Expenditures For
Pollution Control
1975-1985
Operating and
Maintenance Expense
For Pollution Control
1985
I billions of 1975 dollars |
$ .021
.249
.024
.275
.016
.846
.032
.781
.026
-
.101
.482
.115
.013
.007
.059
.004
-
$2.754
$ (.024)
.133
.117
.028
.001
.078
.004
.104
.013
-
.007
.023
.007
.002
*
.001
*
-
-
$.269
*less than .0005
Totals include impact of energy penalty but exclude impact of conversions.
Source: PTm (Electric Utilities!
-------
V-87
APPENDIX V-E
SOUTH ATLANTIC (REGION V)
Exhibit V-E-1
Exhibit V-rE-2
Exhibit V-E-3
Exhibit V-E-4
Exhibit V-E-5
Capacity Report
Financial Baseline Projections
Coal Capacity: Coverage for
Compliance with Clean Air Act
Nuclear and Fossil Capacity:
Coverage for Complaince with
Water Guidelines
Impacts of Air & Water Pollution
Regulations
-------
Exhibit V-E-1
SOUTH ATLANTIC - BASELINE WITH OIL AND OAS CONVERSIONS
TEMPLE BARKER AND SLOANE»INC.
PTM ELECTRIC UTILITY MODEL
CAPACITY REPORT
1974
1975
1976
1977
1978
1979
1980
1981
1982
1933
1984
19B5
1986
1987
1988
1989
1990
KWH
6EN
374.5
339.2
369.2
396.6
426.1
457.4
492.0
525.7
561.7
600.1
641.0
684.6
731.0
780.3
832.9
888.9
948.4
NET KUH
SALES
283.1
294.2
320.1
344.4
370.7
398.7
429.4
459.2
491.0
524.9
561.0
599.5
640.4
684.0
730.4
779.8
832.3
12/31
CAPACITY
83.3
90.8
96.0
99.8
102.1
105.6
109.6
115.9
121.7
128.0
134.1
141.0
150.4
160.5
171.4
182.9
195.1
TOTAL TOTAL
ADDNS RETIRED
8.1 .4
7.9 .5
5.9 .6
4.5 .6
2.8 .6
4.1 .6
4.6 .6
7.1 .9
6.9
7.2
7.4
7.7
10.7
11.3
12.0
12.7
13.4
.O
.0
.0
.0
.0
.1
.1
.2
.3
I
00
00
COAL
CAPACITY REPORT
OIL GAS
NUCLEAR HYDRO
PUMPED
STORAGE
IC/GT
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
62.6
66.0
68.6
70.5
70.8
72.4
74.2
76.3
78.4
80.5
82.6
84.9
88.4
92.2
96.2
100.4
105.0
41.3
43.6
45.1
46.6
43.1
50.2
55.1
57.6
60.0
62.4
64.9
67.5
71.4
75.5
79.8
84.5
89.5
17.1 '
18.3 t
19.9 :
20.7 :
19.9 :
i9.e ;
17.0 :
16.7 ;
16.5
16.2
15.9
15.6
15;4
15.1
14.8
14.4
14.1
1.1
1.0
J.6
5.2
J.8
2.4
S.I
Z.O
.9
.9
.8
.8
.7
.6
.6
.5
.4
6.0
8.3
10.8
12.5
14.1
15.8
17.9
21.1
24.1
27.3
30.6
34.0
38.7
43.6
48.9
54.5
60.5
5.0
5.7
5.7
5.7
5.7
5.7
S.8
5.9
6.0
6.1 :
6.2 :
6.4 :
6.5 j
6.7 ;
7.0 i
7.2 I
7.4 ,
.7 9.0
.1 9.7
.1 9.8
• 3 9.8
.5 .10.0
.6 10.1
.6 10.1
•8 10.8
.9 11.3
;.l 12.0
!.2 12.5
!.5 13.2
>,7 14.1
!.9 15.1
1.2 16.1
(.5 17.3
.8 18.4
Source: PTm (Electric Utilities)
-------
Exhibit V-E-2
SOUTH ATLANTIC - BASELINE UITH OIL AND GAS CONVERSIONS
FINANCIAL BASELINE PROJECTIONS
(BILLIONS OF 1975 DOLLARS)
1975 1980 1985
CAPITAL EXPENDITURES
(NET OF CUIP CHANGE)
TOTAL SINCE 1974 5.18 21.43 51.24
CONSTRUCTION WORK IN PROGRESS
END OF YEAR 5.07 9.26 15.66
EXTERNAL FINANCING
TOTAL SINCE 1974 -.52 12.51 . 39.09
OPERATING REVENUES
TOTAL FOR YEAR 11.37 15.76 22.43
TOTAL SINCE 1974 11.37 81.89 179.59
OPERATING AND MAINTENANCE EXPENSE
TOTAL FOR YEAR 5.75 8.42 11,19
TOTAL SINCE 1974 5.75 42.60 92.49
CONSUMER CHARGES
(MILLS PER KWH)
AVERAGE FOR YEAR 38.64 36.71 37.42
COVERAGE RATIO
(EBIT TO INTEREST 3.22 2.89 2.73
Source: PTm (Electric Utilities)
-------
V-90
Exhibit V-E-3
COAL CAPACITY
COVERAGE FOR COMPLIANCE WITH CLEAN AIR ACT
South Atlantic
In 1985
(millions of kilowatts)
Scrubbers
S02
TSP '
Joint
Medium Sulfur Coal
i
1
Western Low Sulfur Coal
Blending
S02
Joint
Precipitators
Subtotal
In Compliance
Conversion to Oil
Total
In-Service Year
Pre-1974
3.2
1.4
2.1
7.0
-
3.1
4.4
5.6
26.8
10.4
-
37.2
1974-1976
-
-
0.5
4.1
-
-
-
2.3
6.9
-
-
6.9
After 1976
-
-
13.6
-
0.9
-
-
-
14.5
-
-
14.5
Total
3.2
1.4
16.2
11.1
0.9
3.1
4.4
7.9
48.2
10.4
-
58.6
Source: Sobotka & Co., Inc., unpublished data provided to EPA
November 17, 1975.
-------
V-91
Exhibit V-E-4
NUCLEAR AND FOSSIL CAPACITY
COVERAGE FOR COMPLIANCE WITH WATER GUIDELINES
South Atlantic
In 1985
(millions of kilowatts)
Thermal
Before 316(a)
After 316(a)
Entrainment
Chemical
1977 Guidelines
1983 Guidelines
State Water Quality Standards
Nuclear Capacity
Pre-1974
5.2
2.2
0
5.6
5.6
0.8
New
27.9
24.7
0.4
10.8
10.8
0
Fossil Capacity
Pre-1974
'
16.7
3.1
0.2
62.6
62.6
5.4
New
25.0
23.1
0
|
10.1
17.5 i
1.3
1
Source: EPA regional offices, 1975
-------
V-92
Exhibit V-E-5
IMPACTS OF AIR AND WATER POLLUTION REGULATIONS
ON
THE ELECTRIC UTILITY INDUSTRY
South Atlantic
1975-1985
Capacity Conversions
Oil to Coal
Gas to Coal
Gas to Oil
A1r Regulations
Scrubbers
S02
TSP
Joint
Medium Sulfur Coal
Western Low- Sulfur Coal
Blending
S02
Joint
Precipitators
Effluent Guidelines
Fossil
Thermal
316 B
1977 Chemical
1983 Chemical
Nuclear
Thermal
316 B
Chemical
State Water Quality Standards
Fossil Plants
Nuclear Plants
Total1
Total Coverage
1975-1985
megawatts |
5830
600
1050
3200
1400
16174
11153
927
3100
4400
7900
26182
184
72700
80094
26906
419
16419
6713
786
Cumulative Capital
Expenditures For
.Pollution Control
1975-1985
Operating and
Maintenance Expense ',
For Pollution Control
1985
| billions of 1975 dollars 1
$ .181
.049
.012
.301
.028
1.710
.299
.076
.019
.030
.103
.513
.007
.158
.075
.843
.013
.012
.248
.041
$4.477
$ '(.143)
.049
.079
.039
.003
.214
.090
.013
.012
.017
.010
.096
.001
.042
.006
.088
*
.004
.022
.001
$.657
*less than .0005
Totals include impact of energy penalty but exclude 1mpact;af. conversions.
Source: PTm (Electric Utilities)
-------
V-93
APPENDIX V-F
EAST SOUTH CENTRAL (REGION VI)
Exhibit V-F-1 Capacity Report
Exhibit V-F-2 Financial Baseline Projections
Exhibit V-F-3 Coal Capacity: Coverage for
Compliance with Clean Air Act
Exhibit V-F-4 Nuclear and Fossil Capacity:
Coverage for Compliance with
Water Guidelines
Exhibit V-F-5 Impacts of Air & Water Pollution
Regulations
-------
EAST SOUTH CENTRAL - BASELINE WITH OIL AND GAS CONVERSIONS
TEMPLE BARKER AND SLOANE.INC.
PTH ELECTRIC UTILITY HOBEL
CAPACITY REPORT
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
KUH
GEN
171.8
172.8
181.1
187.3
193.8
200.4
207.6
213.8
220.3
226.9
233.7
240.7
248.0
255.5
263.2
271.1
279.2
NET KUH
SALES
159.4
159.3
167.0
173,0
179.5
185.9
192.9
198.9
205.1
211.4
217.8
224,5
231.4
238.6
245.9
253.4
261.0
12/31
CAPACITY
40.7
42.6
46.5
50.0
52.8
56.2
60.0
61.1
61.9
62.7
63.5
64.3
66.2
68.3
70.3
72.5
74.4
TOTAL
AOONS
2.5
2.3
4.0
3.9
3.0
3.7
.0
.6
.3
.3
.3
.3
2.4
2.5
2.5
2.6
2.7
TOTAL
RETIRED
.2
.2
.3
.3
.2
.2
.2
.4
.4
I
CO
COAL
CAPACITY REPORT
OIL CAS
NUCLEAR HYDRO
PUMPED
STORAGE
IC/GT
1974
1975
1976
1977
"1978
1979
1980
1981
1932
1983
1984
1985
1986
1987
1988
1939
1990
32.2
32.0
32.6
33.4
34.8
37.2
38.3
38.6
38.7
38.7
38.8
38.9
39.5
40.1
40.7
41.4
42.0
28.9
28.8
29.5
30.6
32.1
34.7 I
36.0
36.3
36.4
36.6
36.7
36.8
37.4
38.2
38.8
39.6 1
40.2 I
.5
.5
.7
.9
.1
.3
.5
.5
.5
.5
.5
.5
.5
.5
.5
.5
L.5
2.7
2.7
2.4
1.9
1.5
1.2
.8
.7
.7
.7
.7
.6
.5
.5
.4
.4
.4
1.4
2.4
4.3
7.1
8.1
9.0
10.9
11.7
12.2
12.8
13.4
13.9
15.0
16.1
17.3
18.4
19.6
5.5
5.4
5.4
5.4
5.7
5.8
6.6
6.6
6.6
6.8
6.8 :
6.9 :
7.0 :
7.1 '
7.2 :
7.4 '
7.4 Z
.2 1.4
.2 2.6
.6 2.6
.6 2.5
.7 2.5
.7 2.5
.7 2.5
.7 2.5
1.9 2.5
1.9 2.5
!.0 2.5
J.I 2.5
!.2 2.5
!.4 2.6
?.5 2.6
J.7 2.6
!.8 2.6
Source: PTm (Electric Utilities)
-------
Exhibit V-F-2
EAST SOUTH CENTRAL - BASELINE WITH OIL AND GAS CONVERSIONS
FINANCIAL BASELINE PROJECTIONS
(BILLIONS OF 1975 DOLLARS)
1975 1980 1985
CAPITAL EXPENDITURES
(NET OF CUIP CHANGE)
TOTAL SINCE 1974 1.50 15.18 21.50
CONSTRUCTION WORK IN PROGRESS
END OF YEAR 4.22 2.02 3.69
EXTERNAL FINANCING
TOTAL SINCE 1974 1.65 8.96 13.17 ' <;
I
OPERATING REVENUES
-------
V-96
Exhibit V-F-3
COAL CAPACITY
COVERAGE FOR COMPLIANCE WITH CLEAN AIR ACT
East South Central
In 1985
(millions of kilowatts)
Scrubbers
S02
TSP •
Joint
Medium Sulfur Coal
Western Low Sulfur Coal
Blending
S02
Joint
Precipltators
Subtotal
In Compliance
Conversion to Oil
Total
In-Service Year
Pre-1974
3.0
0.3
4.0
5.3
-
9.0
-
5.1
26.7
2;8
-
29.5
1974-1976
-
-
0.3
0.5
-
-
-
0.9
1.7
-
-
1.7
After 1976
-
-
6.2
- •
1.4
-
-
-
7.6
-
-
7.6
Total
3.0
0.3
10.5
5.8
1.4
9.0
^
6.0
36.0
2.8
-
38.8
Source: Sobotka & Co., Inc., unpublished data provided to EPA
November 17, 1975.
-------
V-97
Exhibit V-F-4
NUCLEAR AND FOSSIL CAPACITY
COVERAGE FOR COMPLIANCE WITH WATER GUIDELINES
East South Central
In 1985
(millions of kilowatts)
Thermal
Before 316(a)
After 316(a)
Entrainment
Chemical
1977 Guidelines
1983 Guidelines
State Water Quality Standards
Nuclear Capacity
Pre-1974
1.4
1.4
0
0
0
0
New
12.9
12.9
0
13.2
13.2
0
Fossil Capacity
Pre-1974
7.0
6.6
0
32.2
32.2
5.9
New
10.2
10.2
0
3.5
10.0
1.4
Source: EPA regional offices, 1975
-------
V-98
Exhibit V-F-5
IMPACTS OF AIR AND WATER POLLUTION REGULATIONS
ON
THE ELECTRIC UTILITY INDUSTRY
East South Central
1975-1985
Capacity Conversions
Oil to Coal
Gas to Coal
Gas to Oil
Air Regulations
Scrubbers
S02
TSP
Joint
Medium Sulfur Coal
Western Low- Sulfur Coal
Blending
S02
Joint
Preci pita tors
Effluent Guidelines
Fossil
Thermal
316 B
1977 Chemical
1983 Chemical
Nucl ear
Thermal
316 B
Chemical
State Water Quality Standards
Fossil Plants
Nuclear Plants
Total1
Total Coverage
1975-1985
| megawatts |
.
650
1050
3000
300
10518
5830
1384
9000
-
5985
16792
-
35700
42351
13900
-
13181
7297
Cumulative Capital
Expenditures For
Pollution Control
1975-1985
Operating and
Maintenance Expense
For Pollution Control
1985
I billions of 1975 dollars |
$ -
.053
.012
.273
.006
1.103
.134
.105
.050
-
.094
.590
-
.088
.054
,580
.010
.280
-
$ 3. 352
$ -
.027
.063
.024
*
.096
.039
.014
.024
-
.006 :
.018
-
.016
.003
.010
-
.002
.014
-
$ .267
*less than .0005
1 Hotals include impact of energy penalty but exclude Impact of conversions.
Source: PTm (Electric Utilities)
-------
V-99
APPENDIX V-G
WEST SOUTH CENTRAL (REGION VII)
Exhibit V-G-1 Capacity Report
Exhibit V-G-2 Financial Baseline Projections
Exhibit V-G-3 Coal Capacity: Coverage for
Compliance with Clean Air Act
Exhibit V-G-4 Nuclear and Fossil Capacity:
Coverage for Compliance with
Water Guidelines
Exhibit V-G-5 Impacts of Air & Water Pollution
Regulations
-------
UEST SOUTH CENTRAL - BASELINE WITH OIL AND GAS CONVERSIONS
TEMPLE BARKER AND SLOANE.INC.
PTM ELECTRIC UTILITY HOI'EL
CAPACITY REPORT
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
KUH
GEN
231.2
238.7
260.3
282.8
308.2
33S.3
364.6
372.9
423.1
455.3
489.8
526.7
566.3
608.6
653.9
702.3
754.2
NET KUH
SALES
206.2
215.4
235; 7
255.0
276.1
298.6
323.5
348.0
374.4
402.7
433.0
465.5
500.4
537.8
577.9
620.8
666.8
12/31
CAPACITY
62.:
66.9
67.4
70.0
74.1
79.6
86.2
91.5
96.7
102.3
108.1
114.2
122.5
131.7
141.4
151.6
162.6
TOTAL
ADDNS
6.3
5.2
2.0
4.2
4.7
6.1
7.2
6.4
6.4
6.8
7.1
7.5
9.9
10.5
11.3
12.0
12.9
TOTAL
RETIRED
.3
.3
1.5
1.6
.5
.5
.6
1.0
1.1
1.1
1.3
1.3
1.4
1.5
1.6
1.6
1.7
O
O
COAL
CAPACITY REPORT
OIL GAS
NUCLEAR HYDRO
PUMPED
STORAGE
IC/GT
f!974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1996
1987
1938
1989
1990
55.7
60.0
60.1
62.0
65.0
70.4
72.8
75.9
78.9
82.0
85.3
88.7
93.6
99.0
104.7
110.8
117.3
4.4
5.6
6.3
9.2
12.6
18.5
21.3
25.3
29.1
33.1
37.2
41.5
47.3
53.6
60.3
67.3
74.9
5.3
5.9
6.7
7.5
8.3
9.2
10.0
9.9
9.8
9.8
9.6
9.6
9.5
9.4
9.4
9.3
9.2
45.9
48.5
47.1
45.3
44.0
42.8
41.5
40.8
40.0
39.2
38.5
37.6
36.8
35.9
35.1
34.1
33.2
1.5
1.5
1.5
1.5
2.3
2.3
6.2
7.8
9.4
11.1
12.9
14.7
17.2
19.8
22.*
25.6
28.8
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
.3
.3
.3
.3
.3
.3
.5
.5
.5
.6
.6
.8
.8
.9
1.0
1.0
1.1
2.6
3.1
3.5
4.2
4.5
4.6
4.7
5.3
5.9
6.6
7.3
8.0
8.9
10.0
11.1
12.2
13.4
Source: PTm (Electric Utilities)
-------
Exhibit V-G-2
WEST SOUTH CENTRAL - BASELINE WITH OIL AND GAS CONVERSIONS
FINANCIAL BASELINE PROJECTIONS
(BILLIONS OF 1975 DOLLARS)
1975 1980 1985
CAPITAL EXPENDITURES
(NET OF CUIP CHANGE)
TOTAL SINCE 1974 2,28 16.58 40.15
CONSTRUCTION WORK IN PROGRESS
END OF YEAR 2.38 6.80 12.09
EXTERNAL FINANCING
TOTAL SINCE 1974 1.76 16.38 37.81
<
OPERATING REVENUES '
TOTAL FOR YEAR 4.73 8.70 13.33 o
TOTAL SINCE 1974 4.73 38.83 93.06 h1
OPERATING AND MAINTENANCE EXPENSE
TOTAL FOR YEAR 2.46 4.49 5.63
TOTAL SINCE 1974 2.46 20.89 43.34
CONSUMER CHARGES
(MILLS PER KWH)
AVERAGE FOR YEAR 21.96 26.89 28.63
COVERAGE RATIO
(EBIT TO INTEREST 3.50 2.76 2.74
Source: PTm (Electric Utilities)
-------
V-102
Exhibit V-G-3
COAL CAPACITY
COVERAGE FOR COMPLIANCE WITH CLEAN AIR ACT
West South Central
In 1985
(millions of kilowatts)
Scrubbers
S02
TSP •
Joint
Medium Sulfur Coal
Western Low Sulfur Coal
Blending
S02
Joint
Precipitators
Subtotal
In Compliance
Conversion to Oil
Total
In-Service Year
Pre-1974
-
-
-
-
-
-
-
-
-
1.2
-
1.2
1974-1976
.
-
0.6
1.3
-
-
-
-
1.9
-
-
1.9
After 1976
-
-
9.2
-
28.8
-
-
-
38.0
-
-
38.0
Total
-
-
9.8
1.3
28.8
-
-
-
39.9
1.2
-
41,1
Source: Sobotka & Co., Inc., unpublished data provided to EPA
November 17, 1975.
-------
V-103
Exhibit V-G-4
NUCLEAR AND FOSSIL CAPACITY
COVERAGE FOR COMPLIANCE WITH WATER GUIDELINES
West South Central
In 1985
(millions of kilowatts)
Thermal
Before 316(a)
After 316(a)
Entrainment
Chemical
1977 Guidelines
1983 Guidelines
State Water Quality Standards
Nuclear Capacity
Pre-1974
0
0
0
0
0
0
New
12.6
0
0
1.5
1.5
0
Fossil Capacity
Pre-1974
17.9
0
0
I
17.9
17.9
0
New
36.6
1.6
0
7.2
23.8
0
Source: EPA regional offices, 1975
-------
V-104
Exhibit V-G-5
IMPACTS OF AIR AND WATER POLLUTION REGULATIONS
ON
THE ELECTRIC UTILITY INDUSTRY
West South Central
1975-1985
Capacity Conversions
011 to Coal
Gas to Coal
Gas to 011
A1r Regulations
Scrubbers
S02
TSP
Joint
Medium Sulfur Coal
Western Low- Sulfur Coal
Blending
S02
Joint
Preclpltators
Effluent Guidelines
Fossil
Thermal
. 316 B
1977 Chemical
1983 Chemical
Nuclear
Thermal
316 B
Chemical
State Water Quality Standards
Fossil Plants
Nuclear Plants
Total1
Total Coverage
1975-1985
| megawatts |
.
4250
-
-
9789
1325
28838
-
-
-
1663
-
25170
41755
-
-
1511
Cumulative Capital
Expenditures For
Pollution Control
1975-1985
Operating and
Maintenance Expense
For Pollution Control
1985
| billions of 1975 dollars |
$ -
-
.048
-
-
.998
.049
2.233
-
-
-
.030
-
.053
.058
-
-
.001
-
$3.422
$ -
_
.338
-
.
.125
.008
.443
-
-
-
.003
-
.012
.006
-
-
*
-
$.597
*less than .0005
Totals Include Impact of energy penalty but exclude Impact of conversions.
Source: PTm (Electric Utilities)
-------
V-105
APPENDIX V-H
MOUNTAIN (REGION VIII)
Exhibit V-H-1
Exhibit V-H-2
Exhibit V-H-3
Exhibit V-H-4
Exhibit V-H-5
Capacity Report
Financial Baseline Projections
Coal Capacity: Coverage for
Compliance with Clean Air Act
Nuclear and Fossil Capacity:
Coverage for Compliance with
Water Guidelines
Impacts of Air & Water Pollution
Regulations
-------
MOUNTAIN - BASELINE WITH OIL AND GAS CONVERSIONS
TEMPLE BARKER AND SLOANEtlNC.
PTI» ELECTRIC UTILITY MODEL
CAPACITY REPORT
1774
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
KUH
GEN
72.4
94.5
101.2
107.1
113.5
120.0
127.3
133.8
140.8
148. 0
155.6
163.5
171.8
180.4
189.4
198.8
208.6
NET KUH
SALES
78.1
79.8
85.5
90.5
95.8
101.4
107.4
113.0
118.9
125.1
131.5
138.3
145.3
152.7
160.3
168.4
176.8
12/31
CAPACITY
.23.9
26.6
29.2
30.1
33.7
37.2
39.3
41.1
42.3
43.9
45.4
46.8
49.1
51.5
54.2
56.8
59.6
TOTAL
ADDNS
1.9
2.8
3.0
1.2
3.8
3.7
2.3
.9
.8
.8
.8
.8
2.7
2.9
2.9
3.1
3.2
TOTAL
RETIRED
.1
.1
.3
.3
.1
.2
.2
.3
.3
.3
.3
.3
.4
.4
.4
• .4
.4
t-1
O
O5
1974
r!975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
TOTAL
FOSSIL
15.2
16.4
18.5
18.9
21.1
24.3
26.3
27.4
28.3
29.3
30.3
31.3
32.9
34.6
36.4
38.2
40.1
COAL
8.4
9.6
11.8
12.5
1S.O
18.4
20.5
21.7
22.7
23.9
24.9
26.1
27.8
29.5
31.4
33.4
35.4
CAPACITY REPORT
OIL GAS
.6
.7
.9
.9
.9
1.0
1.0
1.0
1.0
1.0
1.0
.9
.9
.9
.9
.9
.9
6.1
6.1
5.8
5.4
5.2
5.0
4.8
4.7
.6
.5
.5
.3
.2
.1
4.0
3.9
3.8
NUCLEAR HYDRO
0
.3
.3
.3
.3
.3
.3
.4
.4
.4
.5
.5
.5
.6
.6
.7
.8
6.7
7.8
8.4
8.8
10.2
10.5
10.5
10.9
11.2
11.7
12.1
12.4
13.0
13.5
14.2
14.8
15.5
PUMPED
STORAGE
IC/OT
.3
.3
.3
.4
.4
.4
.5
.6
.6
.6
.6
.6
.6
.6
.6
.7
.7
1.7
1.8
1.7
1.7
1.7
1.7
1.7
1.8
1.8
1.9
1.9
2.0
2.1
2.2
2.4
2.4
2.5
Source: PTm (Electric Utilities)
-------
Exhibit V-H-2
MOUNTAIN - BASELINE WITH OIL AND GAS CONVERSIONS
FINANCIAL BASELINE PROJECTIONS
(BILLIONS OF 1975 DOLLARS)
1975 1980 1985
CAPITAL EXPENDITURES
(NET OF CWIP CHANGE)
TOTAL SINCE 1974 1.68 10.23 16.73
CONSTRUCTION WORK IN PROGRESS
END OF YEAR 2.41 2.05 3.54
EXTERNAL FINANCING
TOTAL SINCE 1974 1.86 7.39 12.37
OPERATING REVENUES
TOTAL FOR YEAR 2.55 3.91 5.02
TOTAL SINCE 1974 2.55 19.02 41.55
OPERATING AND MAINTENANCE EXPENSE
TOTAL FOR YEAR .86 1.40 2.04
TOTAL SINCE 1974 .86 6.68 15.28
CONSUMER CHARGES
(MILLS PER KUH)
AVERAGE FOR YEAR 31.95 36.41 36.29
COVERAGE RATIO
(EBIT TO INTEREST 2.88 2.90 2.84
Source: PTm (Electric Utilities)
-------
V-108
Exhibit V-H-3
COAL CAPACITY
COVERAGE FOR COMPLIANCE WITH CLEAN AIR ACT
Mountain
In 1985
(millions of kilowatts)
Scrubbers
S02
TSP '
Joint
Medium Sulfur Coal
Western Low Sulfur Coal
Blending
S02
Joint
Precipitators
Subtotal
In Compliance
Conversion to Oil
Total
In-Service Year
Pre-1974
1.7
0.5
3.0
-
-
-
-
2.3
7.5
1.4
-
8.9
1974-1976
-
-
3.2
'-
1.7
-
-
0.5
5.5
-
-
5.5
After 1976
-
-
12.0
-
3.8
-
-
-
15.8
-
-
15.8
Total
1.7
0.5
18.2
-
5.5
-
.
2.8
28.8
1.4
-
30,2
Source: Sobotka & Co., Inc., unpublished data provided to EPA
November 17, 1975.
-------
V-109
Exhibit V-H-4
NUCLEAR AND FOSSIL CAPACITY
COVERAGE FOR COMPLIANCE WITH WATER GUIDELINES
Mountain
In 1985
(millions of kilowatts)
Thermal
Before 316 (a)
After 316(a)
Entrainment
Chemical
1977 Guidelines
1983 Guidelines
State Water Quality Standards
Nuclear Capacity
Pre-1974
0
0
0
0
0
0
New
0
0
0
0
0
0
Fossil Capacity
Pre-1974
3.6
0.9
0
3.5
3.5
0.2
New
0
0
0
0
0
0.3
Source: EPA regional offices, 1975
-------
V-110
Exhibit V-H-5
IMPACTS OF AIR AND WATER POLLUTION REGULATIONS
ON
THE ELECTRIC UTILITY INDUSTRY
Mountain
1975-1985
Capacity Conversions
Oil to Coal
Gas to Coal
Gas to Oil
Air Regulations
Scrubbers
SO?
TSP
Joint
Medium Sulfur Coal
Western Low- Sulfur Coal
Blending
S02
Joint
PrecipUators
Effluent Guidelines
Fossil
Thermal
316 B
1977 Chemical
1983 Chemical
Nuclear
Thermal
316 B
Chemical
State Water Quality Standards
Fossil Plants
Nuclear Plants
Total1
Total Coverage
1975-1985
| megawatts |
750
75
1700
500
18191
-
5507
- .
-
2831
866
.'- .
3526
3526
-
-
550
Cumulative Capital
Expenditures For
Pollution Control
1975-1985
Operating and
Maintenance Expense
For Pollution Control
1985 '
| billions of 1975 dollars 1
$ -
.061
.001
.146
.010
1.863
-
.432
-
-
.042 .
.035
-
.008
.003
-
-
-
.017
-
$2.555
$ -
.029
.004
.014
.001
.158
-
.042
.
.
.003
.001
.
.002
*
_
.
-
.001
-
$.222
*less than .0005
Totals Include Impact of energy penalty but exclude impact of conversions.
Source: PTm (Electric Utilities)
-------
V-lll
APPENDIX V-I
PACIFIC (REGION IX)
Exhibit V-I-1 Capacity Report
Exhibit V-I-2 Financial Baseline Projections
Exhibit V-I-3 Coal Capacity: Coverage for
Compliance with Clean Air Act
Exhibit V-I-4 Nuclear and Fossil Capacity:
Coverage for Compliance with
Water Guidelines
Exhibit V-I-5 Impacts of Air & Water Pollution
Regulations
-------
PACIFIC - BASELINE WITH OIL AND GAS CONVERSIONS
TEMPLE BARKER AND SLOANErlNC.
PT« ELECTRIC UTILITY HOI'EL
CAPACITY REPORT
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
KUH
GEN
259.9
262.2
278.5
293.0
308.5
324.1
341.1
356.1
371.6
387.8
404.5
421.8
439.4
457.7
476.6
496.2
516.5
COAL
NET KU>
SALES
239.2
242.8
2S8.0
271.0
284.8
299.0
314.5
378.3
342.6
357.5
372.9
389.0
405.3
422. 3
439.9
453.1
477.0
CAPACITY
OIL
^ 12/31
CAPACITY
58.0
61.3
63.7
67.5
70.7
71.7
73.6
75.7
77.8
79.8
81.8
83.7
87.3
90.8
94.5
98.6
102.6
REPORT
GAS
TOTAL
ADDNS
4.3
3.2
3.2
4.3
3.3
1.2
2.3
2.8
2.5
2.5
2.5
2.5
.0
.1
.2
.4
.8
NUCLEAR
TOTAL
RETIRED
.1
.2
.5
.5
.2
.2
.2
.4
.4
.4
.4
.4
.4
.4
.5
.5
.5
HYDRO
<
I
PUMPED
STORAGE
IC/GT
1974
1975
1976
1977
1978
1979
1980
1781
1982
1983
1984
1985
1986
1987
19B8
1989
1990
24.6
24.7
24.7
25.1
25.4
25.7
26.5
26.6
26.6
26.6
26.6
26.6
26.8
27.1
27.3
27.6
27.8
1.5
1.5
1.9
2.5
2.7
3.3
4.0
4.4
4.7
5.0
5.4
5.8
6.4
7.0
7.7
8.3
9.0
7.7
8.1
9.8
12.1
14.1
16.1
18.2
18.1
18.1
17.9
17.8
17.7
17.6
17.5
17.4
17.3
17.1
15.4
15.2
13.0
10.5
8.5
6.4
4.3
4.1
3.9
3.6
3.4
3.2
2.8
2.6
2.3
2.1
1 .7
2.0
4.1
5.1
6.1
7.0
7.0
8.0
8.8
9.6
10.4
11.2
12.0
13.3
14.6
16.0
17.5
19.0
26.8
27.3
27.9
29.7
30.7
31.0
31.0
31.6
32.3
33.1
33.7
34.4
35.6
36.7
37.9
39.2
40.5
2.2
2.2
2.4
2.4
2.8
2.9
3.0
3.2
3.4
3.6
3.8
4.0
4.3
4.6
4.9
5.3
5.7
2.4
3.0
3.6
4.2
4.8
5.1
5.1
5.5
5.9
6.1
6.5
6.7
7.3
7.8
8.4
9.0
9.6
Source: PTm (Electric Utilities)
-------
Exhibit V-I-2
PACIFIC - BASELINE WITH OIL AND GAS CONVERSIONS
FINANCIAL BASELINE PROJECTIONS
(BILLIONS OF 1975 DOLLARS)
1975 1980 1985
CAPITAL EXPENDITURES
(NET OF CUIP CHANGE)
TOTAL SINCE 1974 2.29 12.22 22.48
CONSTRUCTION UORK IN PROGRESS
END OF YEAR 3.48 3.36 5.79
EXTERNAL FINANCING ' |
TOTAL SINCE 1974 1.92 7.58 15.48 ^
OPERATING REVENUES . W
TOTAL FOR YEAR 4.81 6.64 7.87
TOTAL SINCE 1974 4.81 34.49 71.27
OPERATING AND MAINTENANCE EXPENSE
TOTAL FOR YEAR 3.23 4.65 5.39
TOTAL SINCE 1974 3.23 23.50 48.90
CONSUMER CHARGES
-------
V-114
Exhibit V-I-3
COAL CAPACITY
COVERAGE FOR COMPLIANCE WITH CLEAN AIR ACT
Pacific
In 1985
(millions of kilowatts)
Scrubbers
so2
TSP '
Joint
Medium Sulfur Coal
Western Low Sulfur Coal
Blending
S02
Joint
Precipitators
Subtotal
In Compliance
Conversion to Oil
Total
In-Service Year
Pre-1974
-
-
-
-
-
-
-
-
-
1.3
-
1.3
1974-1976
-
-
-
-
-
-
-
-
-
-
-
-
After 1976
-
-
1.8
-
1.3
-
-
-
3.1
'
-
3.1
Total
-
-
1.8
-
1.3
-
-
-
3.1
1.3
-
4.4
Source: Sobotka & Co., Inc., unpublished data provided to EPA
November 17, 1975.
-------
V-115
Exhibit V-I-4
NUCLEAR AND FOSSIL CAPACITY
COVERAGE FOR COMPLIANCE WITH WATER GUIDELINES
Pacific
In 1985
(millions of kilowatts)
Thermal
Before 316(a)
After 316(a)
Entrainment
Chemical
1977 Guidelines
1983 Guidelines
State Water Quality Standards
Nuclear Capacity
Pre-1974
0.7
0.7
0
0
0
0
New
3.0
0.9
0
0
0
0
Fossil Capacity
Pre-1974
7.7
4.0
0
0.1
0.1
0
New
1
0
0
0
0
0 j
0 I
Source: EPA regional offices, 1975
-------
V-116
Exhibit V-I-5
IMPACTS OF AIR AND WATER POLLUTION REGULATIONS
ON
THE ELECTRIC UTILITY INDUSTRY
Pacific
1975-1985
Capacity Conversions
Oil to Coal
Gas to Coal
Gas to Oil
Air Regulations
Scrubbers
S02
TSP
Joint
Medium Sulfur Coal
Western Low- Sulfur Coal
Blending
S02
Joint
Precipltators
Effluent Guidelines
Fossil
Thermal
316 B
1977 Chemical
1983 Chemical
Nuclear
Thermal
316 B
Chemical
State Water Quality Standards
Fossil Plants
Nuclear Plants
Total1
Total Coverage
1975-1985
| .megawatts J
-
-
9750
-
-
1823
-
1314
-
.
-
4010
-
74
74
1571
-
.
Cumulative Capital
Expenditures For
Pollution Control
1975-198*
Operating and
Maintenance Expense
For Pollution Control
1985
| billions of 1975 dollars |
$ -
-
.110
- . .
-
.192
-
.103
-
-
-
.182
-
*
*
.073
-
-
-
$ .550
$ -
-
.925
.
-
.026
-
.021
-
-
-
.009
-
*
*
.001
-
-
-
$ .058
*less than .0005
Totals Include impact of energy penalty but exclude Impact of conversions.
Source: PTm (Electric Utilities)
-------
ECONOMIC AND FINANCIAL IMPACTS OF
FEDERAL AIR AND WATER POLLUTION CONTROLS
ON THE ELECTRIC UTILITY INDUSTRY
VOLUME VI
SECONDARY IMPACTS
MAY 1976
-------
VOLUME VI
TABLE OF CONTENTS
List of Exhibits (Vl-iii)
Chapter
1 INTRODUCTION AND OVERALL CONCLUSION VI-1
Introduction VI-1
Overall Conclusion VI-1
2 IMPACTS ON THE MAJOR USERS OF
ELECTRICITY VI-4
Methodology VI-5
Major Assumptions VI-8
Possible Refinement VI-10
3 IMPACTS UPON THE U.S. SULFUR INDUSTRY
AND ADDITIONAL SECONDARY IMPACTS VI-12
Sulfur Industry VI-12
Other Areas VI-26
-------
VOLUME VI
LIST OF EXHIBITS
Exhibits
VI-1 Calculations of PCE Impact on Ten Electricity-
Intensive Industries
VI-2 Listing of Wholesale Price Indices Used
VI-3 Total Sulfur Production by Producers, 1964-1973
VI-4 Projections of Recovered Sulfuric Acid
From Scrubbers, 1980 and 1985
(Vl-iii)
-------
CHAPTER 1
INTRODUCTION AND OVERALL CONCLUSION
INTRODUCTION
The purpose of this volume on Secondary Impacts is
twofold: first, to assess the effect of higher rates on
heavy users of electricity caused by utility expenditures for
pollution control equipment, and second, to identify and
analyze other areas likely to be affected as utilities com-
ply with pollution control regulations. This analysis
assumes that the increased costs of electricity will be
passed on by major industrial users in the form of higher
prices for their products and will not be absorbed in the
form of reduced profit margins. The other areas of second-
ary impact focus largely on the effect on the sulfur indus-
try of by-product sulfuric acid from regenerable scrubbers,
but also include four other areas of less importance.
OVERALL CONCLUSION
The overall conclusion of this analysis is that
secondary economic impacts of pollution control equipment in
the electric utility industry will be very small—on major
users of electricity and on other areas such as the sulfur
industry.
Major Users
Secondary economic impacts on major users of
electricity will be small by any measure. In the primary
aluminum industry—the most electricity-intensive industry
and the one where the effect will be greatest—higher costs
-------
VI-2
for electricity brought about by utility expenditures for
pollution control equipment will cause an increase in prod-
uct price of 1.1 percent by 1985 (assuming an otherwise
unchanged industry return on investment). The increase
will exceed 0.5 percent in only four of the ten most
electricity-intensive industries. The average for all
industries will be less than 0.1 percent. In addition,
these figures are based on conservative assumptions which
may overstate the effects. In any event, when experienced
over a ten-year period, even the 1.1 percent increase project-
ed for primary aluminum prices appears quite modest in com-
parison with the 30 percent price increase that occurred
between 1971 and 1974 (and the even larger increase since
1974).
Other Areas
The sulfur industry is the area most likely to be
affected as utilities install pollution control equipment.
However, the production of by-product sulfuric acid from
regenerable scrubbers is likely to be only about 2.5 percent
of industry production by 1985. An addition of that size—
in an industry expected to grow at a 4 to 5 percent annual
rate over the next decade—is unlikely to have major conse-
quences for product prices or existing sulfur producers.
In a similar fashion, as electric utilities install pollution
control equipment, the economic impact on other areas will
be small. Those industries producing pollution control equip-
ment will of course be stimulated by the expenditure of $25
billion (1975 dollars) between 1975 and 1985. Purchases of
limestone will be increased but are not expected to seriously
affect limestone markets. Employment impacts will be mixed:
jobs will increase for the construction and installation of
-------
VI-3
pollution control equipment—40,000 to 50,000 construction
jobs annually. In contrast, the price increases due to pol-
lution control equipment for the electric utility industry
and other industries may cause demand in these industries to
be lower than the demand projected without pollution control
expenditures. Therefore, total employment in these industries
may be lower than otherwise projected. However, given the
small price increase due to pollution control equipment, the
net employment impact related to those impacts is likely to
be slight both within the electric utility industry and others
which will experience price increases.
Although there will be increased costs for -elec-
tricity passed on to commercial and industrial customers,
those increases will not cause significant changes in the
economic structure of any individual industry. In fact,
the impacts are sufficiently small even in the most elec-
tricity intensive industry than one can conclude that the
overall effects of the pollution control expenditures will
be diffused broadly throughout the entire economy.
In the two chapters that follow, the overall
conclusion is discussed in more detail, together with an
explanation of methodology, a description of assumptions,
and relevant background.
-------
VI-4
CHAPTER 2
IMPACTS ON THE MAJOR USERS OF ELECTRICITY
The economic impact of the installation of pollu-
tion control equipment by electric utilities upon electricity-
intensive industries will be small. By 1985 only four of
the ten most electricity-intensive industries will experi-
ence product price increases greater than 0.5 percent
attributable to pollution control-induced increases in
electricity costs. These are as follows:
Price Increase Due to
Category Pollution Control Expenditures
Primary Aluminum 1.1%
Industrial Gases 0.9
Electrometallurgical Products 0.8
Alkalies and Chlorine 0.7
Thus, even in the most electricity-intensive of all
industries—primary aluminum—the increase resulting from
pollution control expenditures is only slightly more than 1 per-
cent. For all manufacturing industries taken together, the
impact of pollution control expenditures is less than 0.1 per-
cent. The results of the analysis of the ten heaviest users
of electricity are shown in Exhibit VI-1.
These increases are particularly small in light of
the recent price increases experienced in nearly all indus-
trial categories. In the ten categories examined, these
price increases range from 30 percent to 146 percent over
the three-year period from 1971 to 1974. The 30 percent
increase in primary aluminum prices over this time period
dwarfs the 1.1 percent increase attributable to pollution
control expenditures by 1985.
-------
VI-5
Finally, the conclusions reached with respect to
impacts on product prices of heavy electricity users are
likely to be conservative. The analysis assumes that
product prices in these industries will fully pass on elec-
tricity cost increases and that each industry will experi-
ence these increases at national average levels. In both
cases, these assumptions contribute to the largest probable
product cost impacts.
Most industries, particularly those which use
large amounts of electricity or other forms of energy, are
moving as rapidly as possible to less energy-intensive in-
dustrial processes. One forecaster projects that aluminum
will use 25 percent less electricity per ton produced in 1985
2
than in 1974. A similar forecast : for industrial gases-esti-
mates 13 percent reduction by 1930. This suggests that the
future ratio of kilowatt-hours to units of output will fall.
Since the analysis holds this factor constant, future cost
increases may be less than those suggested above.
METHODOLOGY
The year 1971 is the most recent year for which
industry-specific data are available at the level of detail
needed for the secondary impact analysis. These data were
extended to 1974 to assure consistency with the analysis
carried out elsewhere in this report. These 1974 data pro-
vide a basis for estimating the 1985 impacts of utility
expenditures for pollution control. The analysis shows the
effects on industry prices that would have been experienced
in 1974 if revenue increases necessitated by pollution con-
trol expenditures at that time were at the level anticipated
Industry Week, November 18, 1974, p.14.
2
Conference Board, Energy Consumption in Manufacturing 1974, pp. 207, 209.
-------
VI-6
for the year 1985. This methodology does not extrapolate
product price and energy consumption data from 1974 to 1985
since such an effort is subject to large errors.
The specific methodology consists of four major
steps, each described below.
Selecting the Industries
The first step of the methodology was to identify
and select the ten most electricity-intensive industries.
Four-digit SIC codes were used to be sufficiently precise in
industry definition: the use of broader categories would
not have isolated electricity-intensive industries without
including related categories which are not electricity-
intensive. A total of 86 industries purchased more than
one billion kilowatt-hours in 1971, and of this group ten
industry categories were selected in which the cost of
electricity constituted more than 3 percent of the value of
that category's 1971 shipments, and in which more than six
kilowatt-hours were consumed per dollar of value added in that
industry category. This selection process resulted in the
ten electricity-intensive industrial categories listed in
Exhibit VI-1.
Extending Data to 1974
The second major step in the analytical methodology
was to extend the available 1971 data to 1974, thereby making
it consistent with the baseline year used throughout this
report. This step first involved calculating for each in-
dustrial category the electricity costs as a percent of
-------
VI-7
shipments for the year 1971 (the most recent year for which
data were available). These percentages are shown as Column
1 in Exhibit VI-1. Then the percent change in the wholesale
price index from 1971 to 1974 was obtained for each industry
category, and the percent change in industrial electricity
costs for the equivalent period was calculated. These per-
cent changes are shown in Columns 5 and 6 in Exhibit VI-1.
Finally, the percent changes were used to extend the 1971
electricity cost as a percent of shipments to a 1974 level,
this figure being shown as Column 7 in the exhibit.
Including Pollution Control Expenditures
Volume III of this report concludes that electric
utilities will require an increase in electric revenues of
6.7 percent by 1985 to cover the costs of adding pollution
control equipment. This step of the methodology calculated
electricity costs as a percent of shipments for the individual
industries as if the utilities were already receiving the
6.7 percent increase in revenues in 1974 that will ultimately
be required to recover the costs of installing pollution
control equipment. These figures are derived simply by
increasing 1974 electricity costs as a percent of shipments
by 6.7 percent and are shown as Column 8 in Exhibit VI-1.
Calculating Pollution Control Expenditure Impacts
This final step in the methodology calculated the
differential between Column 7, 1974 electricity costs as a
percent of shipments for each of the industry categories
without pollution control expenditures, and Column 8, the same
item with pollution control rate increases added. The
impact is thus expressed for each industry as the increase
in price as a percent of shipments necessary to recover the
-------
VI-8
increased costs of electricity due to the pollution control
equipment added by the utilities. This impact is shown
as Column 9 in Exhibit VI-1.
MAJOR ASSUMPTIONS
Implicit in the methodology and thus in the results
of the analysis are four major assumptions. The assumptions
are reasonable and were based on the data that were available.
A conservative posture toward assumptions was taken where
possible. The assumptions are described in some detail below.
Wholesale Price Indexes
For each of the ten industry categories, a wholesale
price index was derived. In cases where the actual four-
digit SIC code wholesale price index was available, this
figure was used. In other cases the wholesale price index
for a larger group of commodities had to be used. Exhibit
VI-2 identifies the source and actual figures used for each
of the ten industries.
Increases in Electricity Prices
The 1971-1974 increase in the price of electricity
to all ten categories was assumed to be 56 percent. This is
an all-industry figure based on data from the Department of
Commerce and EEI Statistical Yearbooks for 1971 and 1974.
Every industry in the country—including those ten electric-
ity-intensive industries used in the analysis--obviously did
not experience an identical increase in the cost of electric-
ity during that particular period. Data for individual in-
dustries are simply not available, and the factors influencing
-------
VI-9
actual increases in electricity costs varied considerably
from industry to industry. For example, many industries
purchasing large amounts of electricity enjoy a cost per
kilowatt-hour much below national averages. Many aluminum
producers have been purchasing electricity from hydroelectric
sources and their historical costs have been low. In the
future, however, these producers may have to purchase addi-
tional electricity from fossil-fired plants at much higher
average costs. In a similar fashion, large industrial
customers often have long-term contracts with electric
utilities, and these contracts may alter the rate increases
bo.th recently experienced and expected in the future. Also,
many large industrial users of electricity supply a substan-
tial percentage of their own needs for electricity, and
these costs may vary widely and increase at much different
rates than do the costs of commercial electricity. Finally,
substantial regional differences exist in the cost of
commercial electricity, and this assumption ignores those
differences. In sum, some of these factors will cause the
costs of electricity to specific industry categories to
increase more rapidly than national averages; others will
cause the costs to increase less rapidly. Thus the
assumption is that electricity costs increased 56 percent
for all industries between 1971 and 1974.
Industrial Rate Increases
The third major assumption in the methodology is
that industrial customers will experience the same rate
increases as all other customers. Because industrial
customers generally pay larger demand charges as a percent
of total electric costs than do other categories of cus-
tomers and because demand charges may increase more rapidly
-------
VI-10
than other components of electricity rates due to high mar-
ginal costs per kilowatt, industrial customers may experience
higher percentage increases in total electricity costs than
do other customer categories. Data to analyze more specifi-
cally the impact of these factors are not available, and so
the above-mentioned assumption was made. In a similar fashion,
no attempt was made to distinguish regional differences in
rate increases proportioned to industrial customers.
Cost Pass-Throughs
The last major assumption in the methodology is
that increases in electricity costs will be passed through
to product prices with neither additional nor reduced pro-
fits. Thus the return on investment of the various industry
categories is assumed to remain unaffected by increases in
the cost of electricity.
POSSIBLE REFINEMENT
It obviously would be possible to refine the
analysis of secondary impacts on those industries which are
heavy users of electricity. Assumptions could be narrowed,
and figures made more specific. Several approaches to re-
fining the secondary impact analysis are outlined below.
More sophisticated analysis would be possible
if actual 1974 data on a regional basis were
available, particularly data on electricity
cost differentials.
The impact in terms of changed sales levels
in each industry category could be made more
accurate if estimates of price elasticity for
these products were available.
-------
VI-11
Those industries identified by this method-
ology as subject to the largest pollution
control equipment impact—primary aluminum,
industrial gases, and electrometallurgical
products—could be analyzed in more detail
by considering such factors as regional lo-
cation, special contracts for electricity,
and actual pollution control equipment cost
impacts likely to be experienced by the
utilities in that region of the country.
Given the relatively small secondary economic impact on
even the industry which is the most intensive user of elec-
tricity, additional detail and analysis will not change the
overall conclusion that the impact on electricity-intensive
industries will be small.
-------
VI-12
CHAPTER 3
IMPACTS UPON THE U,S, SULFUR INDUSTRY AND
ADDITIONAL SECONDARY IMPACTS
This chapter details the secondary impacts of
electric utility pollution control equipment on areas other
than those industrial customers for whom electricity costs
are substantial. The first part deals with the impacts on
the sulfur industry; the second part deals with the impacts
on the early retirement of generating capacity, industries
producing pollution control equipment, limestone consumption,
and on overall employment.
SULFUR INDUSTRY
The economic impact of by-product sulfuric acid
from regenerative scrubbers on the national markets for
sulfur and sulfuric acid is likely to be minimal. Under
the current provisions of the Clean Air Act, by-product
sulfuric acid from scrubbers will comprise only 2.6 percent
of total acid production by 1980, a figure that will de-
crease to 2.5 percent by 1985. Given the expectations
for growth in the markets for sulfur and sulfuric acid—
a 4 percent annual rate over the next ten years—and given
expected retirements in U.S. acid capacity in the next
decade, this additional production should be absorbed with
little economic distortion.
Because of the recent problems in the U.S sulfur
industry caused by the entry of by-product sulfur recovered
from Western Canadian sour gas, great concern has been
expressed over the impact on this industry of by-product
sulfuric acid from regenerative scrubbers. For that reason,
-------
VI-13
much attention has been paid to this subject, and it is
presented in detail in the sections which follow.
Industry Perspective
. '_.''- Three points are critical to an understanding of
the sulfur and sulfuric acid industries:
• 90 percent of the demand for sulfur is
in the form of sulfuric acid—a form
readily produced from elemental sulfur .
• Most of the basic supply is in the form
of elemental sulfur and is transported
in this form .
• For the most part, the sulfur producers
and the acid manufacturers are different
companies .
The two industries are closely interlaced in a supply-
demand relationship in which their price structures and
their consumption are proportionately related, as described
below.
Supply
Historically, domestic production of sulfur in the
United States has been derived from three sources: Frasch
sulfur, recovered sulfur, and by-product sulfuric acid.
Total sulfur production in 1973 was 10.9 million long tons,
an increase of almost 160.0 percent during the previous
decade. Sulfuric acid production was roughly three times
that of sulfur since acid content is 30.7 percent elemental
sulfur. A perspective of historical production is presented
in Exhibit VI-3.
-------
VI-14
Frasch producers have historically dominated
U.S. sulfur production; however, this dominance is slowly
eroding with the steadily increasing production of re-
covered sulfur. In 1964 Frasch production accounted for
85.1 percent of U.S. production; by 1973 the share had
declined to 69.6 percent. All of the 1973 amount was
produced by 12 Frasch mines located in Louisiana and
Texas. Five companies owned these mines: the Atlantic
Richfield Company, Duval Corporation, Jefferson Lake
Sulfur Company, Texasgulf, Inc., and the Freeport Minerals
Company.
By 1973 recovery of sulfur by petroleum companies
and by sour natural gas operations yielded 2..4 million
long tons of sulfur—about equally split between them—or
22.1 percent of total U.S. production. Recovery sulfur
production was largely dispersed between 132 facilities in
28 states, with the ten largest plants accounting for 37
percent of total output. Plant capacity in Texas, Califor-
nia, Florida, Louisiana, and Mississippi accounted for 51
percent of the production. The owners were: Exxon Company
U.S.A., Getty Oil Company, Shell Oil Company, Standard Oil of
California, and Standard Oil of Indiana. Production of
refinery and sour gas recovery sulfur is expected to
continue to increase because of two factors: increased
U.S. dependence upon high sulfur, Middle East oil, and
the increased development of dry sour natural gas associ-
ated with petroleum in the Jurassic Formations beneath
Alabama, Mississippi, and Florida.
The final source of sulfur, by-product sulfuric
acid, in 1973 amounted to 5 percent of domestic sulfur in
-------
VI-15
all forms. It was produced at 18 plants in 12 states as
a by-product of copper, lead, and zinc roasters and smelters.
The five largest plants accounted for 57 percent of the
production. The five largest producers are American Smelting
and Refining Company, The Bunker Hill Company, Kennecott
Copper Corporation, Phelps Dodge Corporation, and St. Joe
Minerals Corporation. Together they accounted for 79 percent
of the total by-product sulfuric acid production.
Acid Capacity
Sulfur capacity exists in the form of either
mines, recovery devices, or smelters. Sulfuric acid capacity,
on the other hand, consists of separate facilities in which
production is either captive or externally marketed. In
1972, 23.4 million of the 39.0 million, or 60.0 percent of
the total U.S. short ton sulfuric acid capacity, was for
captive use; the remaining 40.0 percent was marketed through
outside agents on the open market. Six states (California,
Florida, Illinois, Louisiana, New Jersey, and Texas) con-
tributed 58.0 percent of U.S. production capacity. Almost
70 percent of this six-state capacity, or 40.0 percent of
total daily capacity, was located on the Gulf Coast.
The age of existing acid capacity may increase in
importance as the production of by-product sulfuric acid
from scrubbers increases. According to a study performed
by ESSO Research & Engineering Company in 1965, 40 percent
of United States acid capacity was considered new (built
1952 and after), 40 percent was considered aging (built
Easo Research & Engineering Company, Long-Range Sulfur Supply & Demand
Model, 1971.
-------
Vl-16
during World War II) and 20 percent was considered vintage
(pre-World War II). Retirements of capacity, because of
either significant age or the inability to meet air emission
standards, may occur. The void in capacity left by these
retirements, as well as an annual capacity addition rate of
from 4 to 6 percent, will provide a major outlet for by-
product acid.
Demand
While 90 percent of U.S sulfur production is
used to manufacture sulfuric acid, 54 percent of the manu-
factured acid is used to produce fertilizers. In fact,
fertilizer production in 1970 consumed almost 15 million
short tons of sulfuric acid as is shown in the following
table:
USES FOR SULFURIC ACID
1970 Short Tons
End Use
Fertilizers
Petroleum Alkylation
Iron &.Steel Production
Chemicals
Aluminum
HF
Tl°2
Alcohol
Other
Total
Volume
14,990
2,400
800
Source: Tennessee Valley Authority, Market-
ing H2S04 From SOo Abatement
Sources, PB-231 671, December 1973
-------
VI-17
The approximate distribution of sulfuric acid consumption
was as follows:
• Southern States (except Florida) 39%
• Florida 30%
9 North Central 11%
• Western 12%
• North Eastern 8%
Traditionally, sulfuric acid has been the least
expensive acid available and demand trends for both sulfur
and sulfuric acid have tended generally to be inelastic.
Consequently, reductions in acid price do not necessarily
result in its increased marketability.
Annual demand growth for sulfur and sulfuric acid
in the past has closely paralleled fertilizer consumption,
which is expected to increase at an annual rate of from 4
2
to 6 percent. A substantial increase in demand for these
products would require the development of new markets. Such
an increase is not likely because three potential new uses
(as an agent in road building, rigid forms, and precast
products) would consume only an additional 1 million short
3
tons of sulfur per year —not large compared to the current
market size of over 28 million short tons.
TV A, Marketing # SO from S0_ Abatement Sources, PB-231 671, December
1973. 2 4
3EPA Sulfur Markets for Ohio Utilities, EOA 450/3-74-026, March 1974.
-------
VI-18
Sulfur exports remained relatively stable from
1969 to 1973, averaging about 3.7 million long tons annually.
Total imports, exports, and United States consumption are
outlined in the following table. Imports of recovered sulfur
from western Canadian sour gas fields and Frasch sulfur
from Mexican mines constitute the bulk of U.S. imports.
Mexican sources are imported primarily through Texas and
Florida, while Canadian recovered sulfur is marketed on the
West Coast and in the Midwest. The recent decline in imports
is the result of anti-dumping duties imposed by the U.S.
government on sulfur from Canada and Mexico, and a recent
increase in domestic production.
HISTORICAL IMPORTS, EXPORTS, &
U.S. CONSUMPTION FOR ELEMENTAL SULFUR
1964-1973
(thousand long tons)
Year
1973
1972
1971
1970
1969
1968
1967
1966
1965
1964
Source:
U.S.
Consump .
10,234
9,854
9,173
9,227
9,169
9,007
9,301
9,145
7,997
7,260
Imports
1,222
1,188
1,429
1,667
1,795
1,712
1,639
1,674
1,646
1,582
U.S. Department of
Exports
1,777
1,852
1,536
1,443
1,551
1,602
2,193
2,373
2,635
1,928
Commerce,
Net
Exports
555
664
107
(224)
(244)
(110)
554
699
989
346
Bureau of
Year End
Stocks
3,927
3,796
4,120
3,829
3,338
2,790
1,954
2,704
3,425
4,226
Mines
-------
VI-19
Prices
Prices for sulfur and sulfuric acid differ
widely among various locations. These differences in
price are due to several factors:
• Transportation Costs: Costs vary widely
depending upon the source of the sulfur,
the location of the market, the form of
the sulfur (S or HgSCK) and the means
of transportation (rail, barge, etc.).
• Supply: Prices have tended to drop with
the introduction of new supplies. New
producers of recovered sulfur have marketed
without regard to price (since their costs
are far below the price) and have caused
over-saturation of local markets.
• Manufacturing Costs: Due to the wide
range of difficulty in extracting sulfur
by the Frasch process, manufacturers are
subject to production costs varying
from $4 to $5/ton in rich sulfur deposits
to $20 or more in areas where extraction
requires many times more hot water in-
jection per ton of sulfur produced.
Price fluctuations of sulfur greatly impact the producers
of Frasch sulfur. This is because many Frasch producers have
high production costs and, unlike secondary producers, have
no co-product income available to meet rising transporta-
tion and manufacturing costs.
-------
VI-20
A historic perspective of sulfur and sulfuric
acid prices is presented in the following table.
1973
1972
1971
1970
1969
1968
1967
1966
1965
1964
PRICES FOR SULFUR & SULFURIC ACID
1964-1973
Approximate
Delivery Price
Gulf Ports
$/Long Ton*
n.a.
n.a.
23.0
25.5
39.5
46.0
28.3
30.8
30.5
28.5
Price
F.O.B.
$/Long
Ton_
18.6
17.4
17.5
23.7
26.6
40.3
32.8
26.1
22.7
20.0
List Price
Cost of .307*** 100%
LT of Sulfur Sulfuric Acid
Gulf Port Price $/Short Ton*
n.a.
n.a.
7.1
7.8
12.1
14.1
11.7
9.4
9.4
8.8
n.a.
n.a.
30.8
30.8
34.7
34.6
30.5
26.9
25.3
23.8
n.a. *° not available
*E0so Reeeo.rdh S Engineering Company, Long Range Sulfur Supply
8 Demand Model* November 1971
**Bureau of Mines historical statistics
***,30? LT of Sulfur is required to produce 1 ST of 100% sulfuria acid.
In the early 1970s, when recovered and by-product
sulfur production reduced sulfur prices from the record levels
experienced in the late 1960s, high-cost Frasch producers were
forced to sell at a loss. Increased sales in 1974 and 19754
again have boosted some sulfur prices though whole industry
price data are not available after 1973. Nonetheless, the
price levels in the sulfur industry are unstable and changes
Oil Week, January 20 3 19753 p. 36
-------
VI-21
in either supply or demand can have sizeable effects on price
levels and thereby on the profitability of high-cost producers.
Impact Methodology
The analytical methodology developed to estimate the
impact of by-product sulfuric acid from regenerative scrubbers
on the U.S. markets for sulfur and sulfuric acid was based upon
determining the amount of sulfuric acid produced by such pollu-
tion control equipment, then comparing that production with
both the size and growth expectations in the total market.
This methodology is described in the six steps which are
listed below.
Scrubbed Capacity. The first step in determining
the amount of by-product sulfuric acid that will be produced
by regenerative scrubbers is to estimate the amount of genera-
tion capacity that will be scrubbed in 1980 and 1985. Under
the current provisions of the Clean Air Act, EPA estimates
that 29.1 million kw of new generation capacity will be
scrubbed in 1980, and 63.5 million kw of new capacity by 1985.
The estimate for retrofitting existing generation capacity
remains at 54.4 million kw in both of these years. Therefore,
it is estimated that 83.5 million kw of generation capacity
will be scrubbed in 1980 and 117.9 million kw will be scrubbed
by 1985, and these figures were used in this analysis.
Regenerable Scrubber Share. The second step in the
analytical methodology is to estimate the portion of scrubbed
generation capacity that will be fitted with regenerable
scrubbers. The regenerable percentage will be affected by
'three factors: siting considerations, disposal costs, and
capital and operating economics. Under present conditions,
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VI-22
the high costs of these three variables, together with the
still uncertain state of present scrubber technology, make
the sludge disposal associated with non-regenerable scrubbers
a more economically attractive alternative to utilities.
Consequently, PEDCo Environmental Specialists estimate that
only 15 percent of scrubbed capacity will be regenerable by
1980, this figure declining to 12 percent by 1985. This
decrease in regenerable capacity's percentage of capacity
from 1980 to 1985 results from the fact that hew capacity
installed during that period can be sited in a way that will
permit the less expensive sludge disposal to be a far more
attractive alternative.
Sulfur Content of Fuel. The third step involves
making estimates of the sulfur content of the fuel burned by
utilities. This is a key determinant of the final impact since
the amount of sulfuric acid recovered from the regenerable
scrubbers is proportional to the sulfur content of the fuel
burned. PEDCo Environmental Specialists evaluated this
factor and their findings indicate that a trend will develop
to use lower sulfur fuels in regenerable systems. They sug-
gest that the use of higher sulfur content fuels will re-
quire greater capital and operating investments to scrub stack
gases, thereby increasing the likelihood that utilities will
resort to sludge disposal if siting factors permit. With
this fact in mind, a less sulfur-intensive fuel—one containing
2.1 percent sulfur—has been used in this analysis.
Asset Recovery. The fourth step in the methodology
involves determining the amount of by-product sulfuric acid
generated per kwh of capacity fitted with regenerable scrubbers.
c
In a study prepared for EPA , PEDCo Environmental Specialists
PEDCo Environmental Spea-LalistSj Flue Gas Desulfuvization Process
Cost Assessment. May B3 1975
-------
VI-23
examined both regenerable and sludge disposal recovery systems
and determined the amount of by-product acid recovered per kw
for regenerable systems. They estimated that, with 2.1 percent
sulfur fuel, 18.80 tons of sulfuric acid per million kw will
be produced by scrubbers in retrofitted units for each hour of
operation. For new generating units, the estimate is 18.17
tons. These data were used in the analysis as the basis for
by-product acid recovered per scrubbed kwh.
Capacity Factors. The recovery of by-product
sulfuric acid obviously will depend upon the number of hours
that the capacity with regenerable scrubbers is operated.
This analysis used a capacity factor, derived from PEDCo
Environmental Specialists and TBS data, of 60 percent for
new capacity and 50 percent for older capacity. These figures i
reflect the typical pattern of a 60 percent capacity factor for
the first 10 years of plant operation, declining by 1 percent
annually thereafter.
Market Growth for Acid. The final step in the
methodology involves estimating the expected growth in the
market for sulfuric acid. An annual growth rate of 4 percent
was used .in the analysis. This figure is on the low side of
the range of industry forecasts, thereby making the calculated
impacts of pollution control equipment on the markets for
sulfur and sulfuric acid larger than would be experienced
in a more rapidly growing market. Sulfuric acid production
in 1973 was 31.6 million short tons; with an annual growth
rate of 4 percent, acid production will be 41.6 million
short tons in 1980 and 50.6 million short tons in 1985.
-------
VI-24
Findings and Conclusions
Carrying the analytical methodology through to
completion results in two key findings:
• By-product sulfuric acid from electric utility
scrubbers will make up 2.6 percent of total
acid production by 1980.
• Scrubber by-product acid will decrease to
2.5 percent of total acid production by 1985.
These key findings and the major data from which they are
derived are presented in Exhibit VI-4.
i
In addition to the relatively small nature of the
figures for by-product sulfuric acid, retirements of existing
sulfuric acid capacity could alleviate the absorption of this
incremental acid production even further. About 60 percent of
U.S. sulfuric acid capacity is more than 30 years old and is
thus^,major uncertainties now facing the sulfur industry, each
of whichj could create a much larger dislocation than that from
utility-gerilsrated sulfuric acid. For instance, new uses for
sulfur and sulfuric acid are likely but unknown, ancfc the
fertilizer market is likely to be vigorous but its growth rate
could fluctuate violently. In a similar fashion, the governr
ment will determine import-export policy, and this final deter-
mination will have a decided effect on the markets for sulfur
and sulfuric acid. An additional major factor affecting the
-------
VI-25
outcome is the ultimate sulfur content of fuels used by
utilities with regenerable scrubbers. Since sulfur content
directly determines the quantity of acid by-product, an average
content which varies from our estimate of 2.1 percent will
alter the estimated impacts proportionately. Also the location
and form in which sulfur will be recovered from these scrubber
systems will help determine the final price economics and thus
the impact of by-product sulfuric acid. A final unknown is
the development of additional sources of sulfur or sulfuric
acid, particularly scrubbers in other sectors of the economy
such as the pulp and paper industry.
It is clear that by 1985, the 2.5 percent impact of
by-product sulfuric acid generated by scrubbers in utilities
will be one of the smaller items affecting the sulfur and
sulfuric acid industries. The potential impacts of these
other major uncertainties are substantially larger than those
likely to result from the addition of utility scrubber by-
product sulfuric acid to the existing market. Thus, given
the quantity of by-product acid expected, the likely growth
rate in the markets for sulfur and sulfuric acid, and these
other major uncertainties, the additional production of by-
product sulfuric acid from utility scrubbers should b.e
absorbed with very little economic distortion.
i
Possible Refinement
Further detailed analysis obviously should result
Vif'-v
in a flri&re precise forecast of the sulfur and sulfuric! acid
markets in 1985. Such an analysis would need to include the
following items:
-------
VI-26
• A detailed forecast of demand for sulfur and
related products by each major user industry
based on a forecast for each of those
industries
• A study of the existing and likely future
producers—including all scrubber by-product
sources—together with their respective cost
economics
• The projected resolution of the major
uncertainties discussed above
• Projections of the prices likely to result
from the supply and demand conditions.
This analysis is beyond the scope of the present undertaking
and requires data not currently available. The outcome of
such an analysis would not be likely to affect the estimated
impact in a major way. The increase of some 2.5 percent in
sulfuric acid caused by EPA regulations on utilities is suffi-
ciently small to have a negligible impact on the sulfur and
sulfuric acid markets in 1980 or 1985.
OTHER AREAS
There are four other areas of secondary economic
impact which merit consideration. Each is discussed briefly
below.
Early Retirement of Generating Capacity
If the electric utilities find it economically
infeasible to retrofit old generating plants with pollution
control equipment, the pollution control requirements could
cause some shutdowns of capacity and early retirements. These
early retirements could cause employment dislocations or even
-------
VI-27
reductions as old plants are shut down and their generating
capacity replaced by new units requiring fewer employees per unit
of output. In the absence of quantitative estimates of early
retirements caused by pollution control equipment together
with the employment levels of these older units, an accurate
estimate .of this impact is impossible. Available data and
opinion, however, suggest that these early retirements will be
small, or in those cases where early retirements do take place,
the retired units will be replaced with new capacity equipped
with pollution control equipment. Current best estimates
indicate that this new capacity will maintain comparable
employment levels per unit of capacity. Hence, the impact
of early retirements of electric generating capacity should
be small and thus have little economic effect.
Pollution Control Equipment Industries
A significant positive secondary impact will result
from the need to design, build, and install pollution control
equipment for the electric utility industry. As Volume III
has shown, $25 billion (1975 dollars)—or $30.7 billion in
current dollars—will be spent to produce and install this
equipment over the next decade. Such demand may be met by
expanding existing production capability, shifting other manu-
facturing facilities to the production of pollution control
equipment, or actually adding new capacity to produce this
equipment. Although a quantitative analysis of the production
capability of U.S. industry to meet this demand is beyond the
scope of the present study, expenditures averaging over $2
billion annually will have a stimulating economic impact.
In addition, these levels of expenditures will not decrease
as the retrofit program ends in the early 1980s, but will
continue indefinitely at comparable levels as the utility
-------
VI-28
industry continues to add to its capacity. The employment
impact is analyzed separately below.
Limestone Consumption
The consumption of limestone by pollution control
equipment is an additional area of secondary impact. Esti-
mates of relatively small limestone consumption by pollution
control equipment in 1985, together with limestone's wide
availability and its current large and easily expanded pro-
duction capability, indicate that demand will not seriously
affect limestone markets one way or another. Several studies
by PEDCo Environmental Specialists of limestone availability
and price economics of specific plant sites have indicated,
however, that the situation experiences considerable regional
differences. Therefore, it is possible that national figures
could obscure regional impacts and difficulties.
Overall Employment
The secondary impact of pollution control expen-
ditures on employment will be mixed. There will be increases
in the industries which produce and install pollution control
equipment. However, there will probably be offsetting de-
creases in the electric utility industry and other industries
in which price levels will rise as a result of these pollution
control costs.
The present experience in the electric utility in-
dustry is that approximately 20 to 25 building trades jobs
are supported by each $1 million of expenditures for new
plant and equipment. Assuming that that ratio will also
apply to the construction and installation of pollution con-
trol equipment, a rough calculation would suggest that the
-------
VI-29
average annual expenditures of approximately $2.0 billion
(1975 dollars) in the 1975-1985 period would support 40,000
to 50,000 jobs in the building trades.
On the opposite side of the coin, there will prob-
ably be employment declines as a result of demand elasticities
in the industries discussed above. However slight the price
increases may be in those industries, they and the industries
which buy their products will undoubtedly experience some
reductions in demand, and therefore will cut back their work
forces, as a result of the increased prices of electricity.
While the magnitude of this effect cannot be readily quantified,
the employment declines can be expected to be diffused among
many industries because, as the analysis above concluded, no
single industry should experience more than a 1.1 percent
price increase. A rigorous analysis of employment impacts
would require very detailed data on industry price elasticities,
a complete input-output methodology, and heroic assumptions.
The overall employment impact will be small in any
case when viewed in the context of the national economy with
a total civilian U.S. labor force of approximately 90 million
persons.
-------
Exhibit VI-1
CALCULATION OF PCE* IMPACT ON TEN ELECTRICITY-INTENSIVE INDUSTRIES
!
SIC
Code
2611
2621
2631
2812
2813
2819
3241
3313
3334
3339
-
Industry
Pulp Mills
Paper Mills
Paperboard Mills
Alkalies & Chlorine
Industrial Gases
Industrial Inorganic
Chemicals, n.e.c.
Cement, Hydraulic
Elect rometallurgical
Products
Primary Aluminum
Primary Nonferrous
Metals, n.e.c.
All Industries
1971
Electricity
Cost as %of
Shipments
1
3.8
4.0
4.1
9.6
12.4
6.7
5.4
10.2
13.9
kwh per
$ Value
Added
2
13.1
1-1.3
10.4
30.6
21.5
17.2
9.3
39.3
74.8
1
3.7
0.9
21.8
1.9
Total kwh
(millions)
Purchased
and Net
Generated
3
4,815
29,471
17,125
11,044
10,291
40,430
9,122
9,582
53,688
3,790
597,441
Mills
per kwh
Purchased
4
6.6
8.0
8.5
5.9
8.0
7.2
9.3
5.9
4.3
4.9
9.9
1971-1974
% Change In:
Wholesale
Price
Index
5
94.5
30.2
48.6
48.7
48.7
48.7
29.9
32.2
30.2
Costs of
Electricity
to
Industrial
Customers
6
56
56
56
56
56
56
56
56
56
146.5 56
17.9
56
1974 Electricity Cost
as % of Shipments
Without
PCE
7
3.1
4.8
4.3
10.1
13.0
7.0
6.5
12.1
16.7
2.3
1.20
With PCE
at 1985
Levels
8
3.3
5.1
4.6
10.8
13.9
7.3
6.9
12.9
17.8
2.5
1.28
PCE Impact:
% Increase
In Price
(Value of
Shipments)
Due to PCE
9
0.2
0.3
0.3
0.7
0.9
0.5
0.4
0.8
1.1
0.2
0.08
I
GJ
Pollution Control Expenditures
Source: U.S. Department of Commerce, 1971 Annual Survey of Manufactures, 1972 Census of Manufactures:
Fuels and Electric Energy Consumer (Supplement). Survey of Current Business; Edison Electric Institute,
Statistical Yearbooks (1971 and 1974); and TBS calculations
-------
Exhibit VI-2
LISTING OF WHOLESALE PRICE INDICES USED
SIC Code
2611
2621
2631
2812
2813
2819
3241
3313
3334
3339
Name
Pulp Mills
Paper Mills
Paperboard Mills
Alkalies & Chlorine
Industrial Gases
Industrial Inorganic
Chemicals, n.e.c.
Cement, Hydraulic
Elect rometallurgical
Products
Primary Aluminum
Primary Nonferrous
Metals, n.e.c.
All
Industries
Wholesale Price
Index Used
Wood Pulp
BLS Category 09-11
Paper
BLS Category 09-13
Paperboard
BLS category 09-14
Industrial Chemicals
BLS Category 06-1
Industrial Chemicals
BLS Category 06-1
Industrial Chemicals
BLS Category 06-1
Cement, Hydraulic
SIC 3241
Miscellaneous Metal
Products
BLS Category 10-8
Primary Aluminum
SIC 3334
Primary Nonferrous
metals, n.e.c.
SIC 3339
Private Business -
nonfarm
1971 Level
112.0
114.1
102.4
102.0
102.0
102.0
124.6
119.0
115.9
112.8
134.9
1974 Level
217.8
148.6
152.2
151.7
151.7
151.7
161.9
157.3
150.9
278.0
159.1
1971-1974*
Percentage
Increase
94.5%
30 . 2%
48.6%
48.7%
48.7%
48.7%
29.9%
32.2%
30.2%.
146 . 5%
17.9%
*Colwm 5, Exhibit VI-1
Source: Monthly Labor Review. U.S. Department of Labor, Bureau of Labor Statistics
Survey of Current Business. U.S. Department of Commerce, Bureau of Economic Analysis
i
CO
to
-------
Exhibit VI-3
TOTAL SULFUR PRODUCTION BY PRODUCERS
1964 - 1973
(million short tons)
BY-PRODUCT
RECOVERED SUAFURIC ACID*
WORLD SULFUR U.S. SULFUR FRASCH ELEMENTAL PRODUCED AT CU, PERCENT
YEAR PRODUCTION PRODUCTION SULFUR SULFUR ZN & PB PLANTS FRASCH
1973 31.6
1972 28.2
1971 24.8
1970 22.2
1969 20.8
1968 19.5
1967 17.9
1966 16.4
1965 15.3
1964 31.9
NA = Not Available
10.9
10.2
9.6
9.6
9.5
9.7
9.1
9.2
8.2
7.1
7.6
7.3
7.0
7.1
7.1
7.5
7.0
7.0
NA
6.0
2.4
2.0
1.6
1.5
.1.4
jl.4
•1.3
1.2
NA
1.0
*Sulfuric acid ia 30.7 percent elemental sulfur. The elemental
To determine short ton production by by-product sulfuric acid,
Source : Department
of Commerce;
Bureau of Mines,
TVA,
' .600
.546
.518
.537
NA
NA
NA
NA
NA
NA
69.6
71.3
73.3
74.1
74,9
76.6
76.8
76.5
NA
85.1
NEW
SULFURIC
ACID
PRODUCTION
NA
31.0
29.4
NA
27.4
27.4
27.7
27.4
23.8
22.0
sulfur content is illustrated in this chart.
multiply above amount by 3.26.
ESSO Research
& Engineering
Company
I
to
CO
-------
Exhibit VI -4
PROJECTIONS OF RECOVERED
SULFURIC ACID FROM SCRUBBERS
1980 and 1985
Type
Capacity
Fitted
Total
Existing
Retrofit
New
1980
Total
Scrubbed
Capacity
(million kw)
83.5
54.4
29.1
Sulfuric
Acid
(thousand
short tons)
1089 . 2
671.9
417.3
% of
Projected
Total Acid
Production
2.62
1.62
1.00
1985
Total
Scrubbed
Capacity
(million kw)
117.9
54.4
63.5
Sulfuric
Acid
(thousand
short tons)
1278.3
671.9
606.4
% of
Projected
Total Acid
Production
2.53
1.33
1.20
I
u
Source: PEDCo Environmental Specialists; TBS
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|