United :
Environi
Agency
Office of Energy. Minerals, and
Industry
Washington DC 20460
EPA-600/7-78-155b
August 1978
Research and Development
Review of New Source
Performance Standards
for Coal-Fired
Utility Boilers
Volume II
Economic and
Financial Impacts
Interagency
Energy/Environment
R&D Program
Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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REVIEW OF NEW SOURCE PERFORMANCE
STANDARDS FOR COAL-FIRED
UTILITY BOILERS
VOLUME II - ECONOMIC AND
FINANCIAL IMPACTS
March 1978
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DISCLAIMER
This report has been reviewed by the Office of Research 'and Development,
U.S. Environmental Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the views and policies
of the U.S. Environmental Protection Agency, nor does mention of trade names
or commercial products constitute endorsement or recommendation for use.
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ABSTRACT
This two volume report summarizes a study of the projected effects of several
different revisions to the current New Source Performance Standard (NSPS) for
sulfur dioxide (SO-) emissions from coal-fired utility power boilers. The revision
is assumed to apply to all coal-fired units of 25 megawatts or greater generating
capacity beginning operation after 1982. The revised standards which are
considered are: (I) mandatory 90 percent S02 removal with an upper limit on
emissions of 1.2 Ib S02 per million Btu; (2) mandatory 80 percent SC^ removal
with the same upper limit; (3) no mandatory percentage removal with an upper
limit of 0.5 Ib SCL per million Btu. In addition, effects of revising the NSPS for
particulate emissions from the current value of O.I Ib per million BtO down to
0.03 Ib are quantified. Projections of the structure of the electric utility
industry both with and without the NSPS revisions are.given out to the year 2000.
Volume I discusses air emissions, solid wastes, water consumption, and energy
requirements. Volume II discusses economic and financial effects, including
projections of pollution control costs and changes in electricity prices.
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PREFACE
This report is one of several volumes being submitted by Teknekron to the U.S.
Environmental Protection Agency under contract 68-01-3970, "Review of New
Source Performance Standards for Sulfur Dioxide Emissions from Coal-Fired
Steam Generators." This volume discusses the economic and financial implica-
tions of alternative New Source Performance Standards as they will apply to the
U.S. electric utility industry. Volume I, which is being submitted concurrently,
presents the emissions and non-air quality environmental implications.of these
SO2 control alternatives. A third volume discussing the air quality implications
of the emissions control alternatives is anticipated, as is a final volume
containing a series of "issue papers" summarizing results which bear on specific
policy issues relating to EPS's proposal to revise the current standard.
-i-
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CONTENTS
PREFACE [[[ i
CONTENTS [[[ II
LIST OF FIGURES ................................................ v
LIST OF TABLES ................................................. vj
I.OSUMMARY AND CONCLUSIONS ................................ l-l
I . I Principal Economic Impacts ............................... 1-4
1 .2 Principal Financial Impacts ............................... 1-7
2.0 OVERVIEW OF THE ELECTRIC UTILITY INDUSTRY .............. 2-1
2. 1 Industry Structure ..... . .................................. 2-1
2.1.1 Privately Owned Utilities ........................ 2-3
2.1.2 Nonfederal Government Units .................... 2-5
2.1.3 REA Cooperatives .............................. 2-5
2.1.4 Federally Owned Utilities ........................ 2-6
2.2 Operating Costs .......................................... 2-7
2.3 Electricity Prices ........................................ 2-11
2.4 Plant Size, Mix and Efficiency .............. . ............. 2-15
2.5 Regulatory Setting ....................................... 2-18
2.5.1 Regulatory Interaction with Utilities .............. 2-21
2.6 Financial Consideration ................................... 2-23
3.0 ECONOMIC AND FINANCIAL IMPACT ASSESSMENT OF
ALTERNATIVE NEW SOURCE PERFORMANCE STUANDARDS .... 3-1
3. 1 Teknekron's Electric Utility Financial Modules .............. 3-4
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3.2.1 Economic Impacts on the Utility Industry ......... 3-9
3.2.1.1 Total Revenue Requirements ........... 3-11
3.2.1.2 Costs 3-14
3.2.1.3 Net Profits 3-17
3.2.1.4 Investments 3-17
3.2.1.5 Retail Prices 3-19
3.2.2 Regional Prices and Per Capita Costs 3-19
3.2.3 Regional Pollution Control Cost and Investment.... 3-25
3.2.3.1 Regional Pollution Control Costs 3-29
3.3 Financial Impacts 3-33
3.3.1 Return on Equity ... 3-35
3.3.2 Interest Coverage , 3-38
3.3.3 Quality of Earnings 3-40
3.3.4 Summary of Industry Impacts 3-43
3.3.5 External Financing Impacts 3-45
3.3.6 Impact on National Capital Markets 3-47
4.0 COAL VERSUS NUCLEAR: Economics and Decision-Making As
Affected by Revised New Source Performance Standards for
Coal-Fired Boilers 4-1
4.1 Busbar Power Costs 4-2
4.2 Review of Economic Evaluations 4-3
4.3.1 Capacity Factors 4.4
4.2.2 Fuel Costs 4-7
4.2.3 Capital Costs 4-8
4.2.4 NSPS Revisions and Regional Effects 4-9
4.3 Factors Difficult to Quantify 4-10
4.3.1 Reasons to Invest in Nuclear and Reasons to Avoid
Coal 4-10
4.3.2 Reasons to Invest in Coal and Avoid Nuclear 4-12
4.4 Summary, Emphasizing Regional Considerations .%... 4-16
-in-
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APPENDIX A: CAPITAL FORMATION PROSPECTS A-1
A. The Role of Capitol Markets A-l
Capital Markets A-l
Electric Utility Participation in the Capital Markets A-3
B. Factors Affecting Electric Utility Industry Capital-Raising
Prospects A-13
Macroeconomlc Factors A-31
Mlcroeconomic Factors A-32
Regulatory Policies A-38
Management Policies A-42
Pollution Control Revenue Bonds A-54
APPENDIX B: GENERATING UNIT COSTS OF SO, AND
PART1CULATE CONTROLS t...... B-l
-iv-
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LIST OF FIGURES
PAGE
1.1 Teknekron Utility Simulation Model 1-3
2.1 Fuel Price and Cost for the Electric Utility Industry,
1940-1975 2-12
2.2 National Average Heat Rates for Fossil Fueled Steam
Electric Plants, 1950-1975 2-19
3.1 Teknekron Utility Simulation Model 3-2
B-l Cost of Particulate Control Using Electrostatic
Precipitators for New Coal-Fired Utility Boilers B-4
B-2 Cost of SO2 Control for New Coal-Fired Utility
Boilers Using a Limestone FGD System B-5
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USTOFTABLES
PAGE
I. I Alternative New Source Performance Standards Considered 1-2
2.1 Total Electric Utility Industry Sales and Revenues, 1965-1975, 2-2
2.2 Comparative Size Characteristics, Privately and Publicly Owned
Electric Utilities, 1975..... 2-4
2.3 Structures of Total Costs of Privately Owned Electric
Utilities, 1975 2-8
2.4 Structure of Total Costs of Publicly Owned Utilities, 1975 ... 2-9
2.5 Price Indices for Components of Electric Utility Plant
Construction, 1965-1975 2-10
2.6 Electric Utility Industry New Construction Expenditures,
1965-1975 . 2-10
2.7 Electric Utility Industry Fuel Consumption and Prices,
1965-1975 ...., 2-13
2.8 Electricity Price Index, 1965-1975 2-13
2*9 Percent Increase in Average Electricity Bills by Census Region
and Customer Class, 1965-1975 .. 2-14
2.10 Net Generation of Electricity, (I06 KWH) Class A and B
Utilities, 1965-1975 , 2-16
2.11 Privately Owned Electric Utilities Fossil Fueled Steam Plant
Capacity, 1965-1975 2-17
2.12 Backlog of Electric Utility Rate Cases 2-22
2.13 Distribution of Returns on Equity for Class A and B Utilities,
1970 and 1975 2-25
2.14 External Financing of Electric Utility Industry, 1965-1975 .... 2-26
2.15 Balance Sheet Relationships for Privately Owned Electric
Utilities, 1965-1975 2-27
3.1 Input Values Passed to the Financial Module by Other USM
Modules 3-5
3.2 Regions Used for Analysis of Alternative NSPS Revisions ..... 3-8
3.3 Alternative New Source Performance Standard Revisions
Considered 3.jo
-VI-
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3.4 Comparison of Selected National Economic Impacts on the
Electric Utility Industry 3-12
3.5 Comparison of Selected National Economic Impacts on the
Electric Utility Industry of Alternative NSPS Revisions 3-13
3.6 Regional Price Impacts on the Electric Utility Industry of
Alternative NSPS Revisions, 1995......... 3-20
3.7 Per Capita Cost of Alternative NSPS Revisions, 1995 ........ 3-23
3.8 Per Capita Cost of Alternative NSPS Revisions, 1995 3-24
3.9 Pollution Control Costs by Region for Alternative NSPS
Revisions, 1995 3-27
3.10 Pollution Control Costs by Region for Alternative NSPS
Revisions, 1985-1995 3-28
3.11 Direct Pollution Control Investment by Region for Alternative
NSPS Revisions, 1986-1995 3-30
3.12 Direct Pollution Control Investment by Region for Alternative
NSPS Revisions, 1986-1995 3-31
3.13 Return on Equity...... , 3-37
3.14 Interest Coverage 3-39
3.15 Quality of Earnings 3-41
3.16 Long-Term External Financing 3-46
4.1 Comparison of Nuclear and Coal Busbar Power Costs on
a Regional Basis 4-5
-yn-
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1.0 SUMMARY AND CONCLUSIONS
The Environmental Protection Agency asked Teknekron to assess the economic
and financial impacts of alternative New Source Performance Standard (NSPS)
revisions on the electric utility industry. This assessment has been accomplished
both from a regional as well as national perspective for a number of candidate
NSPS revisions, presented in Table I.I. For this analysis Teknekron has employed
its Utility Simulation Model (USM), which generates an integrated, internally
consistent analysis of the economic and financial impacts of alternative environ-
mental regulations on the operations of the nation's investor and publicly owned
electric utilities. Figure I.I illustrates the interaction of the economic and
financial analysis undertaken in the Financial module of the USM with the utility
planning, dispatching, and environmental analysis.
The remainder of this volume is organized in the following manner. Chapter 2
describes the structure, composition, and recent performance of the electric
utility industry over the last decade. Chapter 3 contains the economic and
financial impact analysis and results of alternative NSPS revisions. Attention
has been paid not only to the economic and financial impacts on the industry, but
to the potential impacts on the industry's customers and the public. Using the
Financial module of the USM, Teknekron has examined the regional price,
pollution control cost, and investment effects of these alternative NSPS
revisions. Financial effects on utilities1 return on investment, interest coverage
ratio, and earnings quality are analyzed in addition to the potential impact of the
NSPS revisions on the nation's capital markets. Chapter 4 presents an
assessment of the coal-nuclear trade-off in the context of changed environ-
mental regulations. Appendix A contains a discussion of issues surrounding the
t
capital formation prospects of electric utilities. Appendix B provides some
detail as to the costs of sulfur dioxide and particulate controls.
(M
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Table I.I
Alternative New Source Performance Standard Revisions Considered
Electricity Demand
Growth
BASELINE BASELINE
M 1.2(0)0.1 M 1.2(90)0.1 M 1.2(80)0.03 M 1.2(90)0.03 M 0.5(0)0.03 H 1.2(0)0.1 H 1.2(90)0.1 H 1.2(80)0.03 H 1.2(90)0.03
Moderate* Moderate* Moderate* Moderate* Moderate* High* High* High* "High*
r\>
Ceiling for SO, 0
Emissions"2 '*
1.2
1.2
0.5
1.2
1.2
(.2
1.2
Percent Removal _
Requirements for SO,
Porticulate Standard** 0.1
90%
O.I
80%
0.03
90%
0.03
0.03
O.I
90%
O.I
80%
0.03
90%
0.03
5.8% per year to 1985; 3.4% thereafter.
** lnlb/!06Btu
5.8% per year to 1985; 5.5% thereafter.
NOTE: Standards other than the baseline cases are assigned to apply only to coal-fired generating units beginning
commercial operation in I983 or later. See Volume 1 for a more detailed discusstion of the scenarios analyzed.
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Figure I.
TEKNEKRON UTILITY SIMULATION MODEL
DEMAND
PLANNING
DISPATCH
FINANCIAL
RESIDUALS
REGIONAL AIR
QUALITY ANALYSIS
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I. I PRINCIPAL ECONOMIC IMPACTS
The largest increases in national economic factors facing
the electric utility industry due to alternative NSPS
revisions over the 1986-1995 period (when the majority of
economic and financial impacts will occur) are forecast
for pollution control costs and investment. Nationally,
total costs facing the utility industry under the NSPS
revisions increase at most 5 percent over the 1986-1995
forecast period. Net profits for the industry may decrease
as much as 2.8 percent under the high growth cases.
Pollution control investment may increase to 10 percent
of total industry investment over the 1986-1995 period
under high growth. Comparing the forecasts of the 80 and
90 percent SO- removal standards over the 1986-1995
period indicates that there is little variation in pollution
control expenses (costs and investment) or in retail price
of electricity.
Changes in both national retail prices and per capita costs
(total revenue/population) due to alternative NSPS revi-
sions are forecast not to be large over the 1986-1995
period; the average yearly increase in real prices is
forecast to be approximately 0.5 percent at most, under
high growth, less than 0.2 percent under moderate growth.
National per capita costs are forecast to increase at most
by 0.4 percent per year over the 10-year period.
There are significant regional variations in the economic
impacts. Retail prices of electricity, in real terms, are
forecast to increase over 10 percent in the West South
Central region, which includes the Gulf coast area where
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relatively large amounts of coal-fired capacity subject to
the NSPS revisions are planned to be constructed to
replace gas-fired capacity. Other regions where retail
price increases may be significant under high growth
include North Mountain, West North Central, East North
Centr&l and South Atlantic. *
Regional per capita costs vary greatly over the 1986-1995
forecast period. As before, the West South Central region
incurs the largest increases, over 10 percent under the
high growth case. The impact of NSPS revisions on per
capita costs for the other regions is not so significant.
The forecasted differences between the 80 percent and 90
percent SO- removal cases are not large for national per
capita costs. The New England, West South Central and
South Mountain regions incur the largest differential
impact between the 80 percent and 90 percent cases.
Both pollution control costs and direct pollution control
investment are forecast to increase significantly over the
1986-1995 period as a result of the NSPS revisions
considered. As expected, direct pollution control invest-
ment expenditures increase more than costs. The largest
increases occur under the high growth, 90 percent S0~
removal cases; national direct pollution control invest-
ment expenditures increase between 174 and 195 percent
(to between $48 and $52 billion in 1975 dollars) and
pollution control (operation and maintenance) costs
increase between 37 and 41 percent (to between $51 and
$57 billion in 1975 dollars). Direct pollution control
See Table 3.2 for regional definitions.
1-5
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investment increases from between 2 and 3 percent for
the baseline cases to at most 7 to 10 percent of total
industry investment under the 90 percent SOj removal
cases. While pollution control expenses are higher under
the 90 percent cases than the 80 percent cases, on
average for the nation over the 1986-1995 period, they are
less than 8 percent different.
In addition to direct pollution control investment expen-
ditures that the electric utility industry is forecast to
make under the NSPS revisions, somewhat higher plant
investment expense will be incurred because of the FQD
system-related capacity penalties.* Based on information
supplied to Teknekron on these penalties, we estimate
that between $2 and $5 billion may be required for
additional plant investment over the 1986-1995 period.
These results represent less than one percent of fore-
casted total industry investment over the period.
Again, the West South Central region incurs the largest
increases in pollution control costs and direct pollution
control investment, which are forecast to increase a
maximum of 85 and 300 percent respectively over the
1986-1995 period. Under the high growth cases, six of ten
regions' direct investment costs increase over 100 per-
cent. Because of Its relatively small dependence on coal-
fired capacity, New England bears the lowest, increase in
costs and investment.
These capacity penalties are assumed to be between 5 and 6 percent.
1-6
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1.2 PRINCIPAL FINANCIAL IMPACTS
Important financial parameters that were examined include the utilities' return
on equity, their interest coverage ratios, and the quality of their earnings. These
factors were analyzed both nationally and regionally.
Alternative NSPS revisions for both the moderate and high
growth cases are forecast as having relatively little
financial impact. Nationally, the utilities' return on
equity decreases between 3.3 and 6.5 percent; the interest
coverage ratio decreases 1.3 percent under high growth,
remains constant under moderate growth. The quality of
earnings, measuring the extent of the utilities' earnings
that are composed of noncash AFDC, decreases relatively
little, 2.6 percent, under moderote growth and 6.8 percent
under high growth for alternative NSPS revisions.
Most affected from a financial perspective is the West
South Central region, principally because relatively large
amounts of coal-fired capacity subject to the NSPS
revisions are forecast to be constructed to replace much
> of the present gas-fired capacity. Other regions' financial
impacts due to NSPS revisions are much smaller.
The utilties' return on equity on a regional basis is
generally stable under NSPS revisions. The West South
Central and North Mountain are the most affected
regions.
Regional interest coverage ratios generally are not signi-
ficantly affected by the NSPS revisions. The most
affected regions are West South Central, East North
Central, and South Mountain.
1-7
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Quality of earnings for the utility industry is affected
relatively more by different electricity growth rates and
overall construction programs than by the NSPS revisions.
The most adversely affected regions are East South
Central and West South Central.
The impact on long-term external financing of the NSPS
revisions among the nation's investor-owned utilities is
felt most on common stock financng. Neither long-term
debt or preferred stock issues are greatly affected; the
greatest increase is in long-term debt under high growth,
representing 2.1 percent increase over the 1976-1995
period. Common stock issues increase 7 percent and 8.6
percent under the moderate and high growth 90 percent
SO- removal cases, respectively.
The impact of NSPS revisions on the nation's macro-
economic activities and capital markets is relatively
small. Additional direct investment by the utility industry
due to NSPS revisions in 1990 Is forecast to be at most
$6.2 billion in 1975 dollars, representing 0.25 percent of
real GNP and 1.6 percent of gross private domestic
investment.
1-8
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2A OVERVIEW OF THE ELECTRIC UTILITY INDUSTRY
Over the recent post the electric utility industry, already one of the largest in
the nation, has grown in importance within the energy sector. In 1950, 17
percent of the nation's primary energy supplies was used to produce electricity.
By 1975, this figure had Increased to 28 percent. Between 1970 and 1975,
electric utility construction work in progress increased over 80 percent in real
terms, to over $26 billion. Of this amount, almost $2.2 billion was for
environmental-related construction.
Electric utilities are highly capital intensive: in 1975 the amount of investment
(gross electric utility plant) per employee was $334,480, a 37 percent increase
since 1970. In addition, $3.60 of net capital investment was required to produce
$1 of revenue. In 1975, the total electric utility industry had $163 billion
invested in 'plants, making it among the largest in the nation. As will be
discussed below, this capital intensity and size both contribute to the utilities'
significant impact on the nation's capital market.
Not only is the electric utility industry large, but it is one of the fastest growing
in the nation. As Table 2.1 illustrates, both total kilowatt-hour (kwh) sales and
total revenues have increased greatly over the past decade. Between 1965 and
1975, total kwh sales increased by 68.6 percent, whereas the real gross national
product increased by 27.8 percent.
2.1 INDUSTRY STRUCTURE
Although all electric utilities produce the same product, they can differ
significantly by type of ownership, customer mix, cost structure and operation.
Since the first electric generating plant began commercial operation in 1892, the
2-1
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Table 2.1
Total Electric Utility Industry Soles and Revenues. 1965-1975
Year
1965
1970
1975
Total Energy Sales
to Ultimate Customers
(!09Kwh)
953.4
1,391.4 (46.0)*
1,607.4 (13.4)
Total Revenue
from Ultimate Customers
(10*$)
15,022*
23,434 (55.9)
73,447 (68.1)
Source: Federal Power Commission
*
Figures in parentheses indicate percent increase from previous period.
Adjusted by electricity Price Index. In 1967 dollars.
2-2
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Industry has undergone continuous development. The industry now is comprised
of over 3,000 operating utilities that are either privately owned, nonfederal
government, REA cooperatives, or federal projects.
2.1.1 Privately Owned Utilities
The privately owned electric utilities dominate the entire utility industry despite
their few numbers. While representing less than 15 percent of the nation's utility
systems, they account for the largest share of industry sales revenues, generated
output and customers, as illustrated in Table 2.2.
The growth of the private sector, like that of the whole industry,,has been im-
pressive; since 1965 the privately owned electric utilities' total power generation
has increased by 68.2 percent. Among the privately owned systems there is great
disparity in system size. A large number of private firms are small companies
serving nonurban, non-industrial markets. Like the small publicly owned utilities,
these firms are usually distribution-only systems, purchasing their power require-
ments from the larger utilities.
Within the privately owned sector the large utilities account for a dispropor-
tionate share of generated output, assets, and revenues. These large systems
have grown in size both through internal expansion and through acquisitions of
other electric utilities. In 1970 the fifty largest privately owned electric; utility
systems, representing less than 2 percent of the nation's operating electric
systems, generated 64 percent of the industry's net kwh output. The 213 Class A
& B utilities,* representing approximately one-half of the privately owned
operating utilities, accounted for nearly 100 percent of the privately owned
electric utilities' assets and revenues.
The Federal Power Commission defines Class A utilities as those with
annual electric operating revenues of more than $2.5 million. Class B
utilities are those with annual electric operating revenues between $1
million and $2.5 million. Those utilities having annual electric operating
revenues below $1 million are defined either as Class C or Class D, de-
pending on their size.
2-3
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Table 2.2
Comparative Size Characteristics, Privately and Publicly
Owned Electric Utilities, 1975
Private* Public*
Total Sales (I06 Kwh) . 1,353,089 '(84)**, 254,353
Total Net Generation (IO6 Kwh) 1,486,676 !(86) 245,778
Total Generative Capacity (Mw) 393,953(81) 91,696
Total Electric Operating Revenue (106$) 39,639 (90) 4,341
Total Customers (millions) 63.5 (89) 7.9
Source; Federal Power Commission
Privately owned Class A & B Utilities.
includes municipal wholesalers, municipal retailers, federal projects, and
state power authorities.
** r-
Figures in parentheses indicate percent of total electric utility industry,
private plus public utility figures.
2-4
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These relatively few systems thus exert a pervasive influence on the entire
industry's economic and financial performance. Much of the analysis of the
utilities1 performance in the following chapters will focus on these privately
owned utilities.
2.1.2 Nonfederal Government Units
The largest number of electric utility systems, the nonfederal government sys-
tems, include city and town municipal utilities, county and state systems, and
special utility districts. In 1975 these systems generated about 9 percent of the
industry's production and 11 percent of industry sales. Between 1965 and 1975
nonfederal government systems increased their generation by 75.5 percent. In
1923 there were 3,084 such systems, but by 1975 the number had declined from
this peak to approximately 2,000 with about two-thirds of them purchasing all of
their power requirements from either privately owned or federal systems. The
municipal systems are the most numerous of the nonfederal systems and vary
greatly in size. Some serve only a few hundred customers, while others like the
Los Angeles Department of Water and Power, the nation's largest municipal
electric utility, serve over a million.
2*1.3 REA Cooperatives
The Rural Electrification Administration (REA), founded in 1936, has promoted
the increased use of electric energy in rural America through the creation of
rural electric service cooperatives. Federal financing of such cooperatives was
necessary due to the apparent reluctance of private industry to provide electric
service in rural areas. This reluctance was likely caused in large part by the
relatively high distribution costs per customer, making rural electrification less
i
profitable than urban service areas. The REA systems serve an average load
density of about four customers per mile of line, which is about one-tenth the
load density in urban areas.
2-5
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When the cooperatives were first organized in the 1930s, they were almost
exclusively distribution systems. As time passed and their loads grew, generation
and transmission cooperatives were developed to supply the cooperatives' power
requirements. The REA cooperatives now purchase about 75 percent of their
wholesale power requirements? in 1940, 92 percent was purchased. Their largest
single power source is the government sector, including federal systems, which
supplied 45 percent of the cooperatives' requirements.
In 1975 the cooperatives accounted for almost 2 percent of the nation's
generated kwh. These utilities have grown the fastest of any systems; between
1965 and 1975 the cooperatives increased their power generation by over 200
percent.
2.1.4 Federally Owned Utilities
The federal systems account for the second largest segment of industry capacity
and generated energy. In 1975 they accounted for over II percent of the
industry's net generation. Over the last decade, their generation increased 46
percent.
The five largest federal systems include the Bonneville Power Administration,
the Southwestern Power Administration, the Southeastern Power Administration,
the Department of the Interior's Bureau of Reclamation, and the nation's largest
system, the Tennessee Valley Authority (TVA). Unlike the four other federal
systems, TVA operates fossil-fuel and nuclear generating capacity in addition to
hydroelectric facilities. These five systems sell most of their electric power to
other publicly owned systems (municipals and cooperatives) In their operating
regions, to a small number of large industrial purchasers, and to government
agencies such as the Energy Research and Development Administration for
nuclear diffusion and processing operations.
2-6
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OPERATING COSTS
The utilities' operations can include generation, transmission, and distribution of
electricity. The costs associated with these and other activities are presented In
Table 2.3 (Privately Owned Utilities) and Table 2.4 (Publicly Owned Utilities).
The differences in cost structures between the privately and publicly owned
utilities are notable, indicating these firms' varying operating environments.
With the exception of the municipal wholesalers, the publicly owned firm's power
production costs are relatively higher than those of the privates. In the case of
the municipal retailers, 56 percent of operating revenue is accounted for by
power production costs, reflecting the higher costs of purchased power. In
addition, the distribution costs are relatively higher for municipal retailers than
privately owned utilities, illustrating their more distribution-oriented operations.
Also of interest is the "Other Costs" category, which includes depreciation and
amortization allowances and taxes. This cost category for publicly owned
utilities represents about one-half the relative size of those for privately owned
utilities. This is due in large part to the relatively smaller amount of plant
owned by the publicly owned utilities and different tax provisions.
Labor, capital, and fuel costs are the major operating costs faced by the electric
utilities and have been increasing steadily. Between 1970 and 1975 total salaries
and wages for reporting Class A & B privately owned utilities increased 50
percent to $4.06 billion; total employment grew over the same period 4.8 percent
to 403,407 in 1 975. This increase in salaries and wages is put in perspective when
it is realized that the privately owned electric utilities' generated output
increased only 25 percent between 1970 and 1975.
The utilities' construction cost is a very important factor In an industry that Is so
capital intensive. The costs of constructing electric power plants have risen
dramatically over the past decade and are shown in Table 2.5. The Handy-
2-7
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Td>le 2.3
Structure of Total Costs of Privotely Owned Electric Utilities. 1975
Type of Cost
(I03 $)
Power Production
Fuel
Purchased power
Other power production
Maintenance
Sub-Total
Transmission
Distribution
Customer accounting & sales
Administrative and general
Total Operation & Maintenance
Other Costs (depreciation, amortization,
taxes, other)
Total Operating Costs
Utility Operating Income
Total Utility Operating Revenue
14,545,313
3,238,934
1,314,383
1 ,403,897
20,502,527
502,186
1,753,593
2,221,102
1,100,347
26,079,755
9,995,463
36,075,218
8,522,889
44,598, 107
(33)*
( 7)
( 3)
( 3)
(46)
( 1)
( 4)
( 2)
( 2)
(58)
(22)
(81)
(19)
(100)
Source: FPC, Statistics of Privately Owned Electric Utilities in the United
- - - - -
Figures in parentheses indicate percent of Total Utility Operating Revenue.
2-8
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Table 2.4
Structure of Total Costs of Publicly Owned Utilities, 1975
1 ,...:- -. - - - ;
Type of Cost
Power Production
Transmission
Distribution
Customer Accounts & Sales
Administrative & General
Total Operation & Maintenance
Other Cost (depreciation, amorti-
tization, taxes, other)
Total Operating Costs
Utility Operating Income
Total Utility Operating Revenue
Source: FPC, Statistics of Publicly
Municipal
Wholesalers*
216,192
(41)**
16,004
(03)
5,279
(01)
2,875
(Of)
27,207
(05)
267,557
(51)
49,815
(10)
317,372
(61)
204,995
(39)
522,367
(100)
Owned Electric
(I03 $)
Municipal
Retailers*
2,222,341
(56)
38,390
foi)
246,219
(06)
111,113
(03)
205,307
(05)
2,822,770
(71)
498,257
(12)
3,321,027
(83)
676,163
(17)
3,997,190
(100)
Utilities in
Federal
Projects
1,041,335
(56)
92,831
<05)
1,395
(00)
4,713
(00)
57,960
(03)
1,198,234
(64)
105,037
(ID
1,403,271
(75)
472,424
(25)
1,875,695
(100)
the United
**
States, 1975.
Municipal wholesalers are those publicly owned utilities whose revenues
from sales for resale are 51 percent or more of total utility operating
revenues.
Municipal retailers are those publicly owned utilities whose revenues from
sales for resale are 50 percent or less of total utility operating revenues.
Figures in parentheses indicate percent of Total Utility Operating Revenue.
2-9
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Table Z5
Price Indices for Components of Electric Utility
Plant Construction. 1965-1975
Handy Whitman Public Utility Construction Index
1965 1970 1971 1972 1973 1974 1975
Building*
Electric Light and
87
89
121
119
133
128
144
135
158
144
190
171
211
200
Power**
Source; Statistical Abstract of the United States, 1976.
Note: Based on data covering public utility construction costs for 95 items in
6 geographic regions. Covers skilled and common labor; does not
reflect tax payments nor employee benefit costs. (1967= 100)
**
Includes cost of components for power plant building construction.
Includes cost of material and equipment for steam-electric plant generation
(boilers, turbine-generators, coal and ash handling equipment, condensers
and tubing, and cranes); includes separate listing for operations employees.
Table 2.6
Electric Utility Industry New Construction Expenditures, 1965-1975
1965 1970 1975
Total National New Construction
Expenditures (106$)
Electric Light and Power Industry
New Construction Expenditures (10 $)
73,747 94,855 132,043
2,589 5,808 9,020
(3.7)* (6.1) (6.8)
Source; Statistical Abstract of the United States, 1976
* Figures in parentheses indicate percent of national total.
2-10
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Whitman Public Utility Construction Cost indices, which measure the change In
costs of constructing electric power plant buildings and of steam-electric
generation equipment, have increased by 142 percent and 125 percent, respec-
tively, over the 1965-1975 period. The utilities' new construction expenditures
between 1965 and 1975 increased almost 250 percent, as shown in Table 2.6, and
account for nearly 7 percent of the nation's new construction.
Fuel cost is the largest single operating cost faced by an electric utility, and
represents between 70 percent and 80 percent of total power production costs
(see Table 2.3). Table 2.7 illustrates the very large recent Increases in fuel cost
faced by the utilities. Between 1965 and 1975 the wholesale fuel price index
increased over 100 percent. Figure 2.1 illustrates the relationships between fuel
prices, fuel cost per kwh generated and fuel used per kwh generated.
As shown in Figure 2.1, as the price of fuel has increased, the utilities have en-
deavored to reduce their relative usage of fuel (indicated by fuel use per kwh)
through utilization of higher pressure and temperature steam generating
equipment. In order to reduce fuel usage the utilities have employed more
capital-intensive generating technologies (e.g., nuclear). Together, the increased
fuel costs and rising consumption raised fuel expenditures of privately owned
electric utilities for $3.73 billion in 1970 to $14.55 billion In 1975, almost a 400
percent increase.
Z3 ELECTRICITY PRICES
Each of these cost increases has been manifested most directly in the increased
price of electricity. As is shown in Table 2.8, the electricity price index
increased 69 percent between 1965 and 1975. This compares with the 71 percent
increase over the same period for the consumer price index. Table 2.9 illustrates
the regional breakdown for price increase between 1965 and 1975 in the
residential, commercial and industrial customer classes.
2-11
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FIGURE 2.1
FUEL PRICE AND COST FOR THE
ELECTRIC UTILITY INDUSTRY,
1940-1975
INDEX
650
COST OF FUEL PER kWh
1940
1945
1950
1955
I960
1965
1970 1975
NOTE: DATA BASED ON ALL FUEL USED IN ELECTRIC GENERATION
AND EXPRESSED IN UNITS OF EQUIVALENT COAL.
INDEX: 1937-1941 = 100
SOURCES: 1937-1958, FEDERAL POWER COMMISSION
1959-1975, FEDERAL POWER COMMISSION AND "
EDISON ELECTRIC INSTITUTE
2-12
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Table 2.7
Electric Utility Industry Fuel Consumption and Prices,
1965-1975
^^^^^^^^^^II^HHHIHIHIHH^II^^H|^HHHII|HjRHBE^^^^IHHBraH|Hj^^^^^^^
1965 1970 1971 1972 1973 1974 1975
Millions of short
tons of coal equi-
valent fuel
Wholesale Fuel
Price Index
(1967=100)
369 592 618 673 729 740 769
93.5 122.6 138.5 148.7 164.5 219.4 271.5
Source; Statistical Abstract of the United States, 1976.
Table 2.8
Electricity Price Index, 1965-1975
1965 1970 1971 1972 1973 1974 1975
Electricity Price Index 99.1 106.2 113.2 118.9 124.9 147.5 167.0
Consumer Price Index 94.5 116.3 121.3 125.3 133.1 147.5 J6I.2
Source; Statistical Abstract of the United States, 1976. (1967=100)
2-13
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Table 2.9
Percent Increase in Average Electricity Bills By Census
Region and Customer Class, I&5-I975
Region
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
Noncontiguous
U.S. Average
Residential
88.2%
14.5
52.9
41.9
78.7
78.0
30.1
39.0
78.3
63.2
72.3
Commercial
56.1%
38.9
36.2
33.6
58.7
40.0
21.5
41.3
65.5
51.8
63.8
^^^^^^^MPBI^^^^HHBMBMMBBI
Industrial
95.7%
55.1
57.1
47.8
06.6
89.1
42.9
58.2
90.9
70.0
89.6
Source; FPC. Typical Electrical Bills. 1975.
, 2-14
-------
Overall, the New England region has faced the largest increases in average
electricity bills. Both residential and industrial bills increased the most
nationally between 1965 and 1975 in New England. The next most adversely
affected region is the Pacific region, which had the highest increase in
commercial bills, and significant increases in residential and industrial bills.
These increases in labor, capital, and fuel costs have motivated the utilities to
employ generation techniques that realize scale economics by substituting
capital in place of labor and fuel, and raise thermal efficiencies to lower fuel
costs.
2.4 PLANT SIZE, MIX AND EFFICIENCY
Electric utilities have met the continued increase in demand for electric power
in large part by building larger generating units. By 1975, the largest unit size
rose to 1,300 Mw, a 30 percent increase for the largest unit in service in 1965.
These unit size increases were accomplished in order to realize the production
economies of scale. The utilities have maintained that using larger generating
units has allowed them to realize lower unit generating costs, thereby holding the
price of electricity from rising even more rapidly.
Between 1970 and 1975 the utilities almost doubled the number of large (over
1,000 Mw) plants. Finally, by 1975 over three-quarters of the utilities' plants
were larger than 100 Mw. By contrast, in I960 only one-half of the utilities'
plants were this size. In their move toward building larger generating units the
utilities have also been building more nuclear and fossil-fueled base load units.
Table 2.10 illustrates the industry's growing reliance on nuclear capacity.
Between 1970 and 1975 the nuclear plants' generation increased almost 700
percent and supplied more than 10 percent of the nation's electricity. Fossil-
fueled plants, however, remain the generating foundation for the utility industry,
supplying over 80 percent of the generated kwh.
Over the past decade the utility industry has been predicting growing reliance on
nuclear base load generation. Earlier predictions of much larger nuclear
generating capacity, however, have not been realized, due in part to potential
2-15 !
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Table 2.10
Net Generation of Electricity. (I06KWH) Class A & B Utilities.
1965
1970
1975
Fossil-fueled
Nuclear
Hydro:
-conventional
-pumped
storage
Internal Combustion
TOTAL
735,601
(91. I)*
3,725
(0.5)
67,042
(8.3)
707
(O.I)
807,075
1,077,450
(90.7)
19,113
(1.6)
71,436
(6.0)
3,423
(0.3)
16,067
(1.4)
1,187,489
1,226,337
(82.1)
152,021
(10.2)
83,428
(5.6)
7,780
(0.5)
23,398
(1.6)
1,492,964
Source: FPC, Statistics of Privately Owned Electric Utilities in the United
States, years indicated.
4.
Figures in parentheses represent percent of column total; exclude station
use.
2-16
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Table 2.11
Privately Owned Electric Utilities Fossil-Fueled
Steam Plant Capacity, 1965-1975
Year
1965
1970
1975
Total
No. of
Plants
653
661
631
Over
lOOMw
Capcity
398(61)*
442(67)
477(76)
Over
500 Mw
Capacity
89(14)
155(23)
222(35)
Over
1000 Mw
Capacity
17(3)
47(7)
90(14)
Total
Mw
Capacity
159,141
220,536
366,504
Source; FPC, Statistics of Privately Owned Electric Utilities in the United
States, years indicated.
Figures in parentheses indicate percent of total plants.
2-17
-------
pollution and siting considerations. The President's National Energy Act sub-
mitted to Congress on April 29, 1977, if enacted, could significantly affect the
utilities' choice of base load capacity since the availability and price of oil and
natural gas would be affected. In addition, Part F of the President's National
Energy Act proposes amendments to the Coal Conversion Program that have the
goal of converting oil- and gas-fired steam plants.
In the generation of electric power, one facet of economic efficiency is produc-
tive efficiency. From an engineering viewpoint this productive efficiency can be
measured by the heat rate and thermal efficiency of the plant. The more
efficient the plant, the lower is the heat rate measured by units of generated
heat (Btu) per net unit of output (kwh).
Thermal efficiency measures how effectively available inputs, including labor,
plant, fuel(s), and cooling facilities, are employed to produce electric power.
The higher the thermal efficiency, the more effectively these inputs are being
used. Changes in utilities' productive efficiency are measured by examining heat
rates for fossil-fueled steam-electric plants in the total electric power industry.
Figure 2.2 presents the trends in national average heat rates and thermal
efficiency over the period 1950-1975. Average heat rates dropped almost 30
percent and thermal efficiency increased over 30 percent, a major technical
accomplishment when facing diminishing returns.
REGULATORY SETTING
Electric utilities have been considered "natural monopolies" and, as such, are
subject to public regulation. This regulation takes place at three jurisdictional
levels federal, state, and local and fails into three principal areas issuance
of securities, rates, and accounting practices.
At the federal level, the Securities and Exchange Commission (SEC) regulates
the issuance of securities by nonexempt electric utility holding company affili-
2-18
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FIGURE 2.2
NATIONAL AVERAGE HEAT RATES
FOR FOSSIL-FUELED STEAM ELECTRIC PLANTS
1950-1974
(KTBtu/NetkWh)
Heat Rate*
1950
34%
Thermal Efficiency
32
Source: Federal Power Commission
* Includes Internal Combustion Plants Prior to 1968.
2-19
-------
ates, of which there were 70 in 1974. The SEC has authority also with respect to
financial disclosure requirements. The Federal Energy Regulatory Commission
(FERC, formerly the FPC) regulates the wholesale rates of all companies oper-
ating in interstate commerce. The FERC also regulates the issuance of
securities for utilities in states where no such regulatory authority exists.
Finally, the FERC prescribes accounting practices, requires detailed reporting on
utility operations, and has the authority to approve development of hydroelectric
projects on navigable rivers. A number of other federal agencies such as the
Environmental Protection Agency, the Department of Energy and the Nuclear
Regulatory Commission have regulatory authority which may significantly
affect the financial condition of the electric utility industry, but the impact of
these authorities on the industry's finance is generally considered to be indirect.
Most electric utility regulation takes place at the state level. Comprehensive
state regulation of electric utilities began in 1907, when the New York Public
Service Commission was created and the Wisconsin Railroad Commission was
given regulatory authority over electric and other utilities. By the 1920s,
electric utilities were regulated by more than two-thirds of the states. With the
implementation of statewide regulatory authority over electric utilities by
Minnesota and South Dakota in 1975 and Texas in 1976, 49 of the 50 states now
exercise such authority.*
The areas in which state commissions generally have regulatory authority include
Determining the appropriate rate of return on the utility's
equity investments.
Determining which cost elements should be included in the
rate base or in operating costs, and thus are to be paid by
consumers, and which elements should be excluded, and
thus are to be paid by the investors.
*
Nebraska, which has no privately owned electric utilities, is served by
public power districts and cooperatives.
2-20
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Approving a rate structure which distributes costs with
respect to classes of customer or types of service.
Approving the issuance of securities.
Prescribing accounting, auditing, and reporting standards.
. Approving reorganizations, mergers, and consolidations.
Certifying and licensing plant expansion
Ensuring safety and service reliability.
In addition to these powers, state commissions have a responsibility to ensure
that their current decisions do not endanger the financial viability of regulated
utilities to the extent that the utilities are unable to accommodate the needs of
customers in the future.
Regulatory Interaction with Utilities
Over the past five years, as the industry's capital and operating costs have risen
significantly (see Table 2.5), utilities have spent an increasingly large amount of
time before regulatory commissions in an attempt to recover costs through rate
increases. The result has been an increase in the time necessary for the public
utility commissions to decide on the utilities' rate increase requests. This
increased time for regulatory case review has been referred to as "regulatory
lag". Table 2.12 illustrates the dollar amounts of rate increases granted annually
over the period 1970-1975 , which grew from about $500 million in 1970 to more
than $3 billion in 1975. However, far more significant to the financial condition
of the industry was the fact that dollar amounts awaiting rate inclusion approval
due to regulatory lag grew from about $700 million at the end of 1970 to more
than $4 billion at the end of 1975.
The major impact of the regulatory lag on the industry's financial situation was
that by the time the final order was issued to allow the applicant to increase
rates, inflation had so eaten into the sum originally requested this sum being
2-21
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Table 2.12
Backlog of Electric Utility Rate Cases
End of
Year
1970
1971
1972
1973
1974
1975
Total Dollar Value
of Increases Granted
During the Year
(Million current $)
534
825
870
1,084
2,202
3,095
Number
of Rate
Cases Pending
at End of Year
59
99
99
137
183
185
Total Dollar Value of
Requested Increases
Pending at End of Year
(Million current $)
679
1,157
1,123
\,6S6
4,015
4,073
Source; Edison Electric Institute.
2-22
-------
calculated based on costs prevailing at the time of application that the rate
increases finally granted were insufficient to cover inflated costs. This impact
sometimes was mitigated by a commission's granting an interim rate increase
while deliberations proceeded on the application itself. However, for over three-
quarters of the cases decided during the period 1971-1973, no interim increases
were granted.
Another way to mitigate the financial effects of regulatory lag and inflation is to
permit so-called "forward-looking test years" to be used to calculate the amount
of costs needed to be recovered through rate increases. This method of
calculation permits applicants to anticipate cost trends, but has not been widely
used in regulatory hearings.
The utilities' financial condition over the past decade is described in more detail
in the next section, with particular attention to the utilities' future capital
requirements and their attendant costs.
\
2L6 FINANCIAL CONSIDERATIONS
There are several important factors that have contributed to the electric utility
industry's financial condition. This section will examine briefly these factors and
then examine the relationship between these factors to the industry's financial
condition. Chapter 3 presents a more detailed discussion of financial issues
related to changes in environmental regulations facing the industry.
Because a sizable number of requests for rate relief were not acted upon
immediately in recent years, as described above, it has become evident that the
costs the industry incurred would have to be carried, at least for a time, by some
other means. Since fixed charges, such as interest payable on debt, could not be
reduced, the major source of funds has been cash flow from operations.
2-23,
-------
Clearly, the regulatory delays that had worked to the industry's and its investors'
advantage in the early 1960s were working in the 1970s to their disadvantage.
Whereas, in the early 1960s the industry's members were generally able to earn
more than the rate of return allowed by regulatory commissions, in the early
1970s they were generally earning less. Table 2.13 illustrates that in 1970, 53
percent of privately owned utilities had higher than an 11 percent return on
common equity, whereas in 1975 only 48 percent of the utilities realized that
return.
One direct impact of a declining rate of return in the face of a greater need for
funds was that the industry was forced to become much more dependent on
capital markets, i.e., on external financing. When funds from internal sources
earnings, depreciation and tax deferrals constitute relatively little to the
firm's total investment needs, the utilities have had to acquire external funds in
the capital market. Table 2.14 shows the significant extent to which the industry
has been required to finance itself externally. External financing was required in
particular in 1974 when sufficient internal funds were not available.
Table 2.15 shows that both long term debt and preferred stock holdings have
increased, as a percent of the utilities capitalization between 1965 and 1975;
long-term debt increased from 51.5 percent to 53.3 percent in 1975 (representing
$70.8 billion); preferred stock increased from 9.5 percent ot 12.4 percent in 1975
(representing $16.8 billion issued. The average debt cost increased from 3.80
percent to 6.83 percent between 1965 and 1975, a very significant change-over a
period when utilities were financing a larger amount of-their capital needs
through debt, as indicated by the increased long-term debt as a percentage of net
utility plant. Also indicative of the utilities' changing external financing
patterns is that common stock holdings decreased as a percentage of capitali-
zation from 27.5 percent in 1965 to 24.0 percent in 1975.
This discussion has highlighted the economic and financial trends that the
electric utility industry has faced over the past ten years. Appendix A discusses
2-24
-------
Table 2.13
Distribution of Returns on Equity for Class A & B Utilities, 1970 and 1975
(Percent of Utilities Earning Indicated Return)
Return on Equity 1970 1975*
Less than 5.00%
5.00 - 7.99
8.00 -10.99
11.00 -13.99
14.00 -16.99
17.00 and above
2.4%
17.9
27.1
32.3
16.4
3.9
5.7%
14.8
31.0
37.1
9.5
1.9
Source; Federal Power Commission, Statistics of Privately Owned Electric
Utilities in the United States
Includes equity earnings on subsidiary companies.
2-25
-------
Table 2.14
External Financing of Electric Utility Industry. 1965-1975
Percent of Investment Percent of Investment
Year Financed Externally Year Financed Externally
1965 45% 1971 79%
1966 59% 1972 68%
1967 58% 1973 70%
1968 76% 1974 92%
1969 68% 1975 82%
1970 80%
Sources; from Edison Electric institute, Statistical Yearbook of the Electric
Utility Industry.
2-26
-------
ro
Table 2.15
Balance Sheet Relationships for Privately Owned Electric Utilities. 1965-1975
t
^11 . .!!!, , . !! | | III .. II ^^
1975 1974 1973
Percent of Capitalization:
Long-term debt
Preferred Stock
Common Stock and
other paid in capital
Retained earnings
Long-term debt as percent
net utility plant
Accumulated provision for
depreciation as percent
of total utility plant
AFDC as percent of
net income
Average debt cost
53.3% 53.
12.4 12.
24.0 23.
11.3 II.
51.5 51.
20.3 20.
26.5 28.
6.83 6.
kM^M^M.^.MBMI.»i« I^^B_>
Source: Federal Power Commission,
0% 52.3%
2 12.1
5 23.8
3 11.8
4 50.2
2 20.4
9 24.8
32 5.80
Statistics of
^MHMMMiM^BBMII^HmMHi^HM^^I«H^^HBBaBa>*V
1972 1971 1970
53.1% 54
11.8 10
23.5 23
11.6 II
51.3 52
20.7 21
24.2 21
5.51 5
Privately
.2% 54.8%
.7 9.8
.3 23.2
.8 12.2
.2 52.5
.3 21.9
.1 17.3
.27 5.01
^^^^^H
1969
54.6%
9.4
23.4
12.6
51.9
22.4
12.6
4.52
^^(MM
1968
53.8%
9.6
24.1
12.5
51.6
22.7
9.2
4.17
Owned Electric Utilities in
1967 1966 1965
53.0% 52.3% 51.5%
9.6 9.5 9.5
25.2 26.1 27.5
12.2 12.1 11.5
51.4 50.6 49.7
22.9 23.0 22.7
6.4 4.6 5.6
3.94 3.81 3.80
the United
States
-------
in more detail the capital market environment which the electric utilities will
face over the next ten to fifteen years as they find it necessary to finance their
investment requirements. The remaining chapters will provide more detailed
analysis of the economic and financial impacts on the industry and its customers
as a result of alternative New Source Performance Standard revisions.
2-28
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3.0 ECONOMIC AND FINANCIAL IMPACT ASSESSMENT
OF ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
In this chapter the economic and financial effects of the alternative New Source
Performance Standard (NSPS) shown in Table I.I will be assessed. The principal
analytical means of examining these impacts is Teknekron's Financial module of
its Utility Simulation Model (USM), which is described below. The Financial
module works in conjunction with the other modules of the USM, as shown in
Figure 3.1, so that the economic and financial impact results are fully consistent
with the technical and environmental assessments discussed in Volumes I and III
of this report.
In this chapter, "economic11 impacts focus on changes in retail prices and electric
utility expenses induced by revisions in NSPS at the national and regional levels.
"Financial" impacts include those that may affect the relative financial position
of the electric utilities. Also examined will be the relative impact of alternative
NSPS revisions on the utility industry's external capital needs and, thus, on the
nation's capital market. As with many types of forecasts, it is more important to
consider the relative effects of these revisions rather than their absolute levels.
Several qualifications need to be made before commencing this examination.
First, this analysis will not attempt to identify and compare the largely non-
quantifiable private and social benefits that may be realized from revision of the
NSPS. Such potential benefits may include improvements in human health, labor
productivity, agricultural sector output, and visibility, along with a general
improvement in social welfare.
Second, as is true for any forecast of future events, uncertainty surrounds our ,
projection of the relative economic and financial impacts. We believe, however,
that the Financial module, operating in conjunction with the rest of the Utility
Simulation Model, has generated as useful, comprehensive information about the
3-1
-------
Figure 3J
TEKNEKRON UTILITY SIMULATION MODEL
u>
DEMAND
PLANNING
FINANCIAL
DISPATCH
RESIDUALS
REGIONAL AIR
QUALITY ANALYSIS
-------
potential impacts of NSPS revisions as can be obtained. The principal assump-
tions of the Financial module are discussed below in Section 3.1.1. The USM is
discussed in the Appendix to Volume I.
Uncertainty also surrounds those estimates for a different reason. In the future
some State Implementation Plans (SIPs) may require local standards more strin-
gent than the Federal New Source Standards. Under such conditions, the
economic and financial impacts ascribed to the federal standards may more
properly be assigned to the state regulations. Although we have anticipated that
certain current SIPs are, or are expected to be, more stringent than the current
NSPS, we have assumed that the revised NSPS will apply uniformly to all coal-
fired units operating in 1983 and thereafter.
Third, as will be discussed in the text, there are several regulatory agencies
besides the state and federal environmental agencies that influence utility
operations and performance. State Public Utility Commissions, and in the case
of publicly owned utilities, utility district or local regulators, exert predominant
authority over the utility's financial position. As its name implies, the rate-of-
return regulation practiced by the State PUCs and the Federal Energy Regu-
latory Commission* over the electric utilities establishes an "allowed" rate of
return for the utility. This return and the utility's performance then directly
influence the firm's ability to raise capital. Federal environmental regulations
are but one of several that the utilities face in their interactions with the
nation's financial markets. As will be shown, pollution control investments made
by the utility industry as a result of state and federal environmental regulations
are growing, but still represent a small fraction of the industry's capital
requirements over the next two decades. The utilities' ability to raise this
capital is affected above all by state PUC policies and practices. Teknekron's
Financial module makes reasoned assumptions, similar to other such financial
models, about the responsiveness of the State PUCs to the utilities' financial
needs. These assumptions are described below in Section 3.1.1.
Formerly the Federal Power Commission.
3-3
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3.1 TEKNEKROWS ELECTRIC UTILITY FINANCIAL MODULE
The Teknekron electric utility financial module, which has been developed over
the past three years, provides economic and financial information to complement
the wealth of technical and environmental data produced by other modules of the
Utility Simulation Model. Table 3.1 presents the inputs that are passed to the
financial module from other modules. The Financial module uses this
information as well as internal computations for interest, depreciation, taxes,
financing and rate-setting to produce annual simulated financial statements.
These financial statements include an income statement, balance sheet, source
and use of funds statement and other financial statistics for both investor owned
and publicly owned electric utilities.
As is shown in Figure 3.1, the Financial module acts as an interface of the
demand and supply models by means of a computational module which calculates
prices at which revenues are in balance with costs. It constitutes a type of
computer simulation of regulatory control. But, strictly speaking, a computer
simulation of the regulatory process is impossible. Computer simulation implies
that prices are determinable from cost information, or similar data, by definite
mathematical formulas. This is often not the case. Rather, the regulatory
commissions (or similar public regulatory authorities) are deliberative bodies.
They consider a wide range of facts and hear opposing views expressed in the
form of a formal hearing. In making their judgments they may be called upon to
resolve problems when accepted principles are in conflict.
3.1.1 Financial Module Assumption*
This conceptual model, like other similar regulatory models,* involves a number
of assumptions and approximations. It entails a uniformity of approach to
regulation which does not, of course, exist among the many public bodies
For example, see P. L. Joskow and M. L. Baughman, "The Future of the
U.S. Nuclear Energy Industry," Bell Journal of Economics. Spring 1976,
pp. 3-32.
-------
Table 3.1
Input Values Passed to the Financial Module by Other USM Modules
DEMAND INFORMATION from DEMAND
Sales to ultimate consumers
Sales for resale
OPERATING DATA from DISPATCH
Fuel Expense
Operation Expense
Maintenance Expense
PLANNING DATA from PLAN
Cash outlays for plant construction
for each year of simulation
Details of plants coming online
(All information broken down by asset categories)
3-5
-------
involved. The institutional complexities surrounding the regulatory process set
limits on the analysis which can be made using the regulatory model.
The conceptual model of regulatory control assumes fundamentally that
regulation acts to set prices so that revenue collected will equal actual costs of
providing service. These costs are to be understood to include an appropriate
return to investor/owners of the utilities. Prices so set are adjusted among
different groups of customers in accordance with criteria of fairness to both
consumers and investors; efficiency of resource management; insuring adequacy
and reliability of future supply; and similar desirable attributes of an ideal
pricing-regulatory system. The following are several of the principal
assumptions incorporated into the operation of the Financial module.
Constancy of current parameter values and accounting and tax practices. The
Financial module is required to make implicit assumptions regarding the external
financial environment of the electric utility industry over the simulation period.
A key assumption in this regard is that conditions will either remain as they are
today or closely follow the historical pattern that has developed over the past 20
years. The model uses a predetermined external financing mix throughout the
simulation period; the inflation rate, specified by the EPA, remains a constant
5.5 percent; the target return to investors on common equity is 13 percent. It is
implicitly assumed that accounting practices and income-tax determination
regulations will remain the same as they are now. The model has been updated
for all current changes in tax laws and accounting procedures.
Cost of capital is constant of all financing levels. Just as the financing mix
ratios are predetermined, the cost of capital is set at an exogenuously
determined level for each type of security. This cost then remains constant
throughout the model and all new issues of debt and equity will pay the specified
return. It should be noted that in the case of common stock, because of well-
known forecasting difficulties, no attempt is made to predict the market price of
3-6
-------
the stock or earnings per share. Thus dividends are based on a specified per-
centage return for each dollar of common stock outstanding and are not deter-
mined on a per share basis.
Rote-setting Environment* The Financial module assumes a responsive rate-
setting environment. Revenues in any given year are a result of an average
electricity price determined in the previous year. This average price is based
upon what revenue requirements would have been in effect in that year in order
for the utility to recover all its costs and an allowed return to common
stockholders. Because annual electricity demand growth rates are exogenously
specified, there is an implicit assumption that price sensitivity and customers'
substitution of energy forms due to relative energy prices are not significant
factors. Although it is possible that during the simulation a return greater or
less than the allowed return will actually result, due to fluctuations in the real
cost of electricity and variations in financing levels, over the simulation period
the realized rate of return will not vary dramatically from the allowed return
specified.
Neutral effect of non-electric operations. A number of items on an electric
utility's balance sheet and income statement are outside the scope of electric
operations but nonetheless must be accounted for. These items include net
income from non-electric operations, non-operating income, non-income taxes,
other assets and other credits. The initial amounts of these items are
determined from FPC forms, for 1975. During each year of the simulation they
are assumed to increase at the inflation rate.
3,1.2 Reqionolization
Throughout this assessment, when warranted, we will be examining important
economic and financial impacts on a regional as well as national basis. The
regions we have examined are basically those defined by the Bureau of Census,
with one exception. In order to gain more insight into the economic and financial
3-7
-------
Table 3.2
Regions Used for Analysis of Alternative NSPS Revisions
co
New England
Connecticut
Rhode Island
Massachusetts
New Hampshire
Vermont
Maine
Mid-Atlantic
New York
Pennsylvania
New Jersey
South Atlantic
Delaware
Maryland/D.C.
Virginia
West Virginia
North Carolina
South Carolina
Georgia
Florida
East
North Central
Wisconsin
Michigan
Illinois
Indiana
Ohio
East
South Central
Kentucky
Tennessee
Mississippi
Alabama
West
North Central
North Dakota
South Dakota
Nebraska
Kansas
Iowa
Missouri
Minnesota
West
South Central
Texas
Oklahoma
Arkansas
Louisiana
North Mountain
Idaho
Montana
Wyoming
South Mountain
Nevada
Utah
Colorado
Arizona
New Mexico
Pacific
Washington
Oregon
California
-------
effects on the utility industry in the western United States, we have subdivided
the Census' Mountain region into two regions, North Mountain and South
Mountain. The regions are defined in Table 3.2.
3.2 ECONOMIC IMPACTS
The economic impacts associated with changing pollution control regulations for
electric utility coal-fired boiler operations can be examined from several
perspectives. First, we will analyze the economic effects on the utility industry;
including changes in its total revenue requirements; total costs and important
components, such as fuel, operation and maintenance and pollution control
equipment O&M; net profit and capital investment needs, both for plant and
pollution control equipment. These effects will then be compared across the
selected NSPS revisions. See Table 3.3 for a description of the alternative NSPS
revisions considered.
Second, we will then compare the impact on retail prices under several of the
scenarios defining alternative NSPS revisions. These prices will be examined
both nationally and regionally, to capture important regional detail. After this
we will analyze the per capita cost of the revisions. This measure is important
when one assumes that cost increases facing industrial and other utility
customers ultimately can be passed forward to the residential consumer.
Third, we will examine the national and regional pollution control costs and
investment expenses associated with alternative NSPS revisions. As will be
shown, it is important to show regional data as there can be significant variations
among regions, illustrating differences in the characteristics of their electricity
supply systems, economic factors and fuel availability and cost.
3.2.1 Economic Impacts on the Utility Industry
Revisions to the NSPS may have several, inter-related effects on important
economic parameters facing the electric utility industry over the 1976-1995 time
3-9
-------
Table 3.3
Alternative New Source Performance Standard Revisions Considered
BASELINE BASELINE
M 1.2(0)0.1 M 1.2(90)0.1 M 1.2(80)04)3 M 1.2(90)0.03 M 0-5(0)0.03 H 1.2(0)0.1 M 1.2(90)0.1 H 1.2(80)0.03 H 1.2(90)0.03
Moderate* Moderate* Moderate* Moderate* Moderate* High* High* High* High4
L
o
Requirement, lor S02 «* »* ° 0 90% 80% 90%
Portfcuhrte Standard** O.I O.I 0.03 0.03 0.03 O.I O.I 0.03 0.03
* 5.8% per year to 1985; 3.*% thereafter.
* 5.8% per year to I985j 5.5% thereafter.
NOTEj Standards other than the baseline cases ore assigned to apply only to coal-fired generating units beginning
commercial operation tn 1983 or later. See Volume I for a more detailed dlscusstion of the scenarios analyzed.
-------
period. We have focused on the ten-year period 1986-1995 since we assume that
plants subject to the revised NSPS will not be coming on-line until 1983. See
Volume I for a more detailed discussion.
Tables 3.4 and 3.5 present the forecasted national changes in the following
economic factors for the moderate and high demand growth rates, respectively:*
Total Revenue Requirements;
Total Cost;
Fuel Cost;
Operation and Maintenance Cost;
' Pollution Control Cost;
Net Profit;
Total Investment Excluding Pollution Control
Pollution Control Investment; and
Retail Price.
These represent the principal economic factors, facing the electric utility
industry that may be affected by a revision of the NSPS.
3.2.1.1 Total Revenue Requirements
As is shown in Table 3.4, total revenue requirements under moderate growth vary
little as a result of the NSPS revisions considered. The largest increase over the
current standard (baseline, M 1.2(0)0.1) occurs with the 90 percent removal with
!2.9ng/J (0.03 Ib/106 Btu) particulate limit. Under this case total revenue
requirements, which include a target return on equity (or the rate base in the
case of the publicly owned utilities), increase $24 billion over the 1986-1995 time
period, representing about a 2 percent increase over baseline. All of the other
Throughout this assessment all forecasted dollar values are presented in
1975 dollars.
O I I
-------
Table 3.4
Comparison of Selected National Economic Impacts on the
Electric Utility Industry of Alternative NSPS Revisions*
1986- 1995
Total Revenue
Total Cost
Fuel
Operation &
Maintenance
Pollution Control*
, Net Profit
Baseline
M 1.2(0)0.1
$1,149.5
1,023.9
369.8
167.4
36.4
125.6
M 1.2(90)0.1
+22.1**
+26.7
-0.3
+0.5
+7.2
-4.6
M 1.2(80)0.03
+20.9**
+25.8
-0.3
+0.5
+6.9
-4.9
M 1.2(90)0.03
+24.0**
+29.0
0
+0.6
+7.9
-5.0
M 0.5(0)0.03
+20.5**
+25.5
-0.9
+0.5
+7.0
-5.0
Total Investment
Excluding Pollution
Control
Pollution Control
Investment+
325.3
8.0
+4.2
+ 13.0
+3.1
+ 13.3
4.2
+ 14.6
+3.4
+ 13.3
Retail Price
(l975£/kWh)
J985.1995 1985.1995 J985 \99S 1985 1995 1985 1995
2.81 2.93 +0.04 +0.05 +0.03 +0.05 +0.04 +0.05 +0.03 +0.05
Unless noted otherwise, figures in billions of 1975 dollars.
Change from baseline.
Includes expenses for SO,, NO , particulate and water pollution controls. The latter
are not varied across scenarios?
3-12
-------
Table 3-5
Comparison of Selected National Economic Impacts on the
Electi
'
Total Revenue
Total Cost
Fuel
Operation &
Maintenance
Pollution
Control*
Net Prof it
Total Investment
Excluding Pollution
Control
Pollution Control
Investment '*
Retail Price
(!975
-------
revenue changes for other revisions, including moving to a 2l5ng/J
(0.5lb/l06Btu) S02 c
revenue requirements.
(0.5 Ib/10 Btu) S0~ ceiling result in less than 2 percent increases in total
Under the high growth cases, total revenue requirements increase more. Again,
the largest increase occurs under the 90 percent, !2.9ng/J (0.03 Ib/IO Btu)
case; where revenues increase over $47 billion, representing a 3.6 percent
increase. Each of the other revisions results in increases of about 3 percent.
Thus, the NSPS revisions considered are not forecast to increase total revenue
requirements significantly between 1986 and 1995.
3.2.1.2 Costs
Total Costs include the following items;
Fuel,
Operation and Maintenance,
Pollution Controls,
Income Taxes,
Other Taxes,
Interest Expense,
Depreciation and
Other Utility Costs.
We have selected fuel, operation and maintenance (O&M) and pollution control
costs as the most important operating costs of the above cost categories and
have focused our attention on them. Under the baseline case in both moderate
and high growth, these three cost categories are forecast to comprise over 55
percent of total costs between 1986 and 1995. The largest is fuel cost, represen-
ting 36 percent of total costs; the smallest of these categories is pollution con-
trol costs, representing somewhat over 3 percent of total costs.
3-14
-------
As will be shown, some cost categories increase substantially under the NSPS
revisions. Under moderate growth, as shown in Table 3.4, total costs increase
the most, $29 billion, under the 90 percent S02 removal case and a particulate
limit of !2.9ng/J (0.03 Ib/106 Btu). This would be expected because this
represents the most stringent NSPS revision we have considered. Putting this in
perspective, however, this change represents less than a 3 percent increase in
total costs. The high growth cases, presented in Table 3.5, show that the dollar
increase in total costs rise considerably, due mostly to the relatively higher costs
of building, operating and maintaining an electric utility system capable of
meeting this increased load.
The largest increase in total costs for the high growth cases (Table 3.5) is found
for the 90 percent 12.9 ng/J (0.03 Ib/IO Btu) case; a $60.7 billion increase. This
represents a 5.1 percent increase in total costs. Each of the other cases shows
between a 4 and 5 percent increase in total costs, over the ten-year period.
Under the moderate growth cases fuel costs remain essentially constant as
illustrated in Table 3.4. Each of the incremental changes are well within the
margin of uncertainty for the fuel price data used and represent less than one-
quarter of one percent change. Similarly, the O&M costs do not change
significantly across the alternative NSPS revisions*
The fuel costs increase slightly under the high growth cases. The largest change,
$5.1 billion, shown in Table 3.5 represents a 1.2 percent increase over the ten-
year period examined and should not be considered a significant change.
Operation and Maintenance costs also do not increase significantly; the largest
change, $1 billion, is but a 0.5 percent increase.
Pollution control costs, which represent not only operation and maintenance
expenses for SO, control equipment, but for NO , particulate and related control
* X
equipment, increase significantly under the NSPS revisions.* The largest
As mentioned previously, pollution control costs include the costs of
meeting water pollution regulations. However, since these regulations are
held constant, their effect is removed when we examine the incremental
costs of more stringent NSPS. Appendix B describes how SO- and
particulate costs can vary for a typical generating unit based on fuel type
and its physical characteristics.
3-15
-------
increase shown in Table 3.4 occurs under the 90 percent S02» 12.9 ng/J
(0.03 Ib/IO6 Btu) particulate case, $7.9 billion over the ten-year period, and
represents just under a 22 percent increase. The other cost increases range
between 19 and 20 percent for other NSPS revisions.
Imposition of the 90 percent SO2 removal requirement, as compared to 80
percent does not appear to markedly increase pollution control costs. If these
additional costs, $1 billion ($7.9 - $6.9), are spread evenly over the period
examined, they represent less than 0.5 percent annual increase in total costs. A
similar result is that tightening of the particulate standard does not appear to
result in a significant cost increase, less than 0.2 percent annual change over the
ten-year period.* Although pollution control costs increase significantly, as a
percent of total costs, they increase from 3.6 percent to 4.2 percent. When put
in the perspective of total costs the increase appears more tempered.
Under the high growth cases, shown in Table 3.5, pollution control costs increase
more, as expected. The largest growth occurs under the 90 percent 12.9 ng/J
(0.03 Ib/IO Btu) case, when over the ten-year period these costs increase $16.3
billion. This represents over a 40 percent increase in these costs. Other cost
increases range between 27 and 37 percent.
As was found in the moderate growth cases, the imposition of the 90 percent SO~
removal standard, as compared to the 80 percent standard, is forecast to have a
marginal effect on pollution control costs. If spread evenly ovear the ten-year
period, the stricter standard would increase annual total costs by less than 0.5
percent. In addition, annual total costs do not increase significantly, less than
0.4 percent, where the particulate standard is tightened to 12.9. ng/J
(0.03 Ib/IO6 Btu).
This conclusion may be different if precipitators, rather than fabric filters
had been used for Western coal; See Volume 1.
3-16
-------
In Section 3.3.2.3, we will discuss the regional effects of these pollution control
cost increases.
3*2.1.3 Net Profits
The imposition of alternative NSPS revisions is forecast uniformly to decrease
the electric utility industry's net profits,* defined as total revenues minus total
costs. The decreases as a percentage of baseline are greatest under the
moderate growth cases as shown in Table 3-4. Net profits decrease over 20
percent under scenario M1.2(90)0.03, in part due to the one year regulatory lag
assumed in the model in covering increased costs. Because of relatively lower
revenue growth under the high growth cases, net profit reductions are much less
and do not exceed 3 percent over the ten year period. Generally, the more
stringent the NSPS revision, the greater net profits drop, as would be expected.
More detailed analysis of the financial effects of NSPS revisions, including return
on equity and quality of earnings, is presented in Section 3.3.
3*2.1.4 Investment
The NSPS revisions are projected to influence both total investment excluding
pollution control, representing principally plant investment, and pollution control
investment. As presented in Tables 3.4 and 3.5, total investment excluding
pollution control increases with the NSPS revisions.
In addition to the direct pollution control investment expenditures that the
utility industry is forecast to make the industry also will face somewhat higher
plant investment expense due to the capacity penalties incurred with operation
of FGD systems. These penalties have been estimated to be between five and six
Net profits is used for both privately and publicy owned utilities although,
technically, publicly owned utilities' account would be called a "surplus."
3-17
-------
percent for installed generating capacity.* From this information and from the
simulation model's national forecast of the percent of capacity using FGD
systems in 1995, we estimate that approximately $2.7 billion (in 1975 dollars)
may be required for additional plant investment due to capacity penalties under
the moderate growth case (M1.2(90)0.03); under the high growth case
(HI.2(90)0.03), as much as $4.8 billion may be necessary. These additional,
indirect pollution control investment expenditures are accounted for, although.
not explicitly, in the incremental changes in Total Investment Excluding
Pollution Control category shown in Tables 3.4 and 3.5. The incremental
investment, however, is a small percentage increase over the baseline. The
largest increase under moderate growth, $3 billion, represents 0.6 percent.
Under high growth the largest increase over the ten-year period is $4.2 billion,
representing 1.3 percent increase over the baseline.
Pollution control investment increases significantly, as expected. It should be
remembered, however, that such investment represents a relatively smal I part of
the industry's forecasted capital investment needs over the 1986-1995 period.
Under the moderate growth baseline, pollution control investment represents 2.4
percent of total investment. For the high growth baseline, it represents 3.4
percent ot total investment.
The increases in pollution control investment for the moderate growth cases
range from $13 to $14.6 billion over the 1986-1995 period, representing between
a 62 and 83 percent increase over baseline. The largest increase for each growth
rate is found under the Ml.2(90)0.03 scenario, as expected. As is described in
more detail in Volume I, the amount of national coal capacity subject to FGD in
1995 increases from 16 and 13 percent to 51 and 68 percent for the moderate and
high growth cases, respectively. Pollution control investment, as a percent of
total investment, increases to 6.9 and 10 percent under the moderate and high
"Particulate and Sulfur Dioxide Emission Control Costs for Large Coal-
Fired Boilers," PEDCo Environmental, Inc. under EPA Contract
68-02-2535.
3-18
-------
growth rates, respectively. Since the regional distribution of this additional
pollution control investment can have important implications, the regional
effects are examined in Section 3.2.3, below.
3.2.1.5 Retail Prices
National average retail prices for each of the NSPS revisions considered are
found not to have significant variation in 1985. By 1995, only the high growth
cases shown significant variation. The largest change occurs with the 90 percent
S02 removal !2.ng/J (0.03 Ib /I06 Btu) particulate limit, a 16 mill/kWh Increase,
representing a 5.2 percent increase over the baseline. These retail prices
represent a weighted average of retail prices for privately and publicly owned
utilities. Section 3.2.2 contains more detailed analysis of the regional price
effects under alternative NSPS revisions.
3.2.2 Regional Prices and Per Capita Costs
Table 3.6 presents a detailed compilation of regional impacts on the utility
industry's retail electricity prices in 1985 and 1995. The 90 percent S02 removal
with the tightened particulate standard scenarios were chosen for moderate and
high growth since these resulted in the largest change in national average retail
prices (see Tables 3.4 and 3.5). In order to facilitate some comparison we have
included the M0.5(0)0.03 scenario as well.
The regional variations can be large. The New England region is forecast to
continue to have the highest retail prices under both moderate and high growth
cases, over 40 percent greater than the national average in 1995. The East South
Central region, which contains much of the Tennessee Valley Authority service
territory, historically one of the least expensive areas for electricity, is forecast
to change, on average, less than 50 percent of the national average by 1995.
Under both moderate and high growth scenarios, the largest Increase in retail
prices in 1995 occurs in the West South Central region. Consumers there bear
3-19
-------
Table 3.6
to
of Alternative NSPS Revisions, 1 976- 1 996
Baseline
M 1.2(0)0.1
REGION
1985
1995
M 1.2(90)0.03
1985
1995
M 0.5(0)0.03
1985
1995
Baseline
H 1.2(0)0.1
1985
1995
H 1.2(90)00)3
1985
1995
NATION
New England
Mid-Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
North Mountain
South Mountain
Pacific
2.81*
3.90
3.76
2.86
2.99
1.43
2.77
2.15
2.30
2.67
2.76
2.93*
4.23
3.58
3.03
3.11
1.32
2.73
2.92
2.02
2.67
2.75
1.4**
0.3
1.3
1.7
-0.7
1.4
0
3.3
0.4
5.6
0.7
1.7**
1.7
2.0
1.7
0.3
2.3
1.8
11.0
3.5
3.7
0.7
I.I*"
0.0
1.3
1.7
-0.7
0.7
0.0
3.3
0.4
4.9
0.4
1.7**
1.
2.
1.
-0.
2.
2.
4.
1.
0.
7
0
7
3
3
2
1
5
4
0.4
2.85*
3.96
3.81
2.90
3.01
1.45
2.81
2.17
2.29
2.76
2.78
3.10*
4.31
3.83
3.27
3.32
1.42
2.95
2.91
2.30
2.91
2.90
1.8**
0.3
0
2.1
2.0
2.7
1.8
3.7
0.8
4.0
I.I
5.2**
0.2
2.1
4.6
4.8
2.8
5.4
12.0
7.4
1.7
1.0
Average prices to retail customers expressed in £/kwh, in 1975 dollars. Represents a weighted
average of privately and publicly owned utilities.
Percentage change from Baseline.
-------
the largest price increase because of the projected phase-out of oil- and gas-
fired capacity and replacement by coal capacity additons subject to the revised
standards (see Volume I, Table 2.5). Other regions that reflect relatively higher
price increases are the two Mountain regions, where the revisions would cause a
shift from new source compliance through the use of low sulfur coals to the use
of FGD systems.
Changes in the percentage increases between 1985 and 1995 illustrate the distri-
bution of economic effects over time and system expansion schedules. Price
changes in 1985 do not reflect major impacts of the NSPS revisions since the
revisions only affect capacity on-line after 1983. What effects are present
reflect in large part the price-related additional investment expenditure impacts
for generating equipment construction underway. The West South Central
region's prices increase significantly more in 1995; whereas, other regions such as
Pacific, East South Central and South Atlantic reflect a more balanced increase
in prices over the period. Several regions such as South Mountain show less price
increase in 1995 than in 1985 and illustrate that by the last year of the forecast
much of the price-related effects have been accounted for. The 1985 price
change for East North Central under moderate growth appears negative.
However, the change should be interpreted as not significantly different from
zero, since it is within the forecast's margin of uncertainty. Overall, the price
changes resulting from NSPS revisions do not appear to be large by 1995, with
the exception of the Gulf Coast region as previously noted.
Under moderate growth the 2l5ng/J (0.5 Ib/IO6 Btu) SO2 ceiling case, the
M0.5(0)0.03 scenario, is notable in that there is relatively little difference in
1995 retail prices between it and the 90 percent SO2 removal scenario. Under
this scenario, however, the West South Central and North Mountain regions' price
increases in 1995 are less than half than those under the 90 percent SO2 cases.
Another useful measure of economic impact on the consumer is the relative
change in per capita costs, here defined as total revenue requirements divided by
population in 1995, are presented in Tables 3.7 and 3.8 for the moderate and high
3-21
-------
growth coses respectively. The growth of real per capital cost between 1976 and
1995 is not dramatic. In 1976, the model estimates that national real per capita
cost is $268; by 1995 it increases to over $500 and over $600 for the moderate
and high growth baseline cases respectively. There are several reasons for this
increase. The yearly demand growth rates we have assumed require the utility
industry to build new capacity to meet these projected loads with ever more
expensive generating capacity, transmission lines and distribution systems. The
compound effect of cost escalation and demand growth rates that exceeds the
population growth rate' increase (about one percent per year) increases the totaL
costs of operating, maintaining and financing the nation's utility systems. As
costs increase, revenue requirements correspondingly increase. Retail prices
have been shown not to increase greatly (see Table 3.6), so that increased
revenue requirements are satisfied principally by the constant growth in kWh
sales.
The important information presented in Tables 3.7 and 3.8 is the incremental
change in per capita costs between scenarios rather than the absolute level of
these costs. As is shown, none of the moderate growth cases shows a large
increase in per capita costs. The largest national increase occurs under the most
stringent scenario, Ml.2(90)0.03; but this represents less than a 2 percent change
in per capita costs over the baseline. Under the high growth cases the increase is
larger, $27 in 1995, representing almost a four percent increase in per capita
costs.
It is important to note the regional variations in per capita costs. The biggest
increases in per capita costs occurs in the Gulf Coast region, West South Central,
where the largest percentage of new FGD capacity is built. The largest increase
for this region under moderate growth, $35, represents a 6 percent change in per
capita cost. The next largest change occurs in the North Mountain region, where
per capita costs increase 5.1 percent. Each of the other changes represents less
than a 3 percent increase.
3-22
-------
Table 3.7
Per Capita Cost of Alternative NSPS Revisions, 1995*
Region
Nation'
New England
Mid-Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
North Mountain
South Mountain
Pacific
Baseline
M 1.2(0)0.1
$530
476
069
576
577
365
475
662
426
462
541
M 1.2(90)0.1
+$8+
+ 8
+~3
+ 5
+ 3
+ 7
+ 6
+31
+41
+14
+-7
M l.2<80).03
+$S+
+ 1
+ 5
+ 6
+ 5
+ 7
+ 6
+29
+38
+11
+ 8
M l.2(90).03
+$9+
+ 8
+ 7
+ 7
+ 3
+ 7
+ 6
+35
+42
+14
+ 7
M 0.5(0).03
> 7+
+ 8
+ 6
+ 7
+ 3
+10
+ 3
+25
+25
+ 1
+ 7
Defined as total revenues divided by population in 1995. All figures in 1975 dollars.
Change from Baseline.
3-23
-------
Table 3.8
Per Capita Cost of Alternative NSPS Revisions. 1995*
REGION
Baseline
H 1.2(0)0.1
H 1.2(80)0.03
H 1.2(90)0.03
NATION
New England
Mid-Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
North Mountain
South Mountain
Pacific
$685
632
609
766
747
491
629
801
606
617
677
$+24+
0
+ 7
+36
+27
+ 13
+26
+80
+45
+ 1
+ 5
$+27*
0
+ 12
+40
+33
+ 14
+30
+87
+48
+ 5
+ 6
Defined as total revenues divided by population in 1995. All figures in
1975 dollars.
Change from Baseline.
3-24
-------
Under the high growth coses, the some regions again incur the largest increases,
both above 7 percent as shown in Table 3.8. Also, the Mid-Atlantic, East North
Central and West North Central regions are .forecast to have relatively larger
increases in per capita costs, both between 4 and 5 percent. Each of the other
changes is under 4 percent.
To summarize, changes in both average retail prices and per capita costs under
the various control scenarios are not forecast to be large at the national level.
National price increases at most increase 5 percent in 1995. In that year,
national per capita costs increase at most 4 percent, under the high growth case,
and at most 2 percent under the moderate growth case.
Regional impacts display significant vqriation, with the West South Central
region incurring the largest price and per capita cost increases; over 10 percent
increase for both measures under high growth. Other more affected regions
include North Mountain and the West North Central regions, where coal capacity
additions using FGD systems are significant. Other regions analyzed are not
forecast to be severely affected in terms of price or per capita cost as a result
of alternative NSPS revisions.
On average, forecasted differences between the 80 percent and 90 percent
removal cases do not appear significant for either retail prices or per capita
costs.
3.2.3 Regional Pollution Control Cost and Investment
One of the most important impacts on the electric utility industry of Imple-
menting more stringent NSPS will be changes in direct pollution control
expenses, including both operation and maintenance costs and investment
expenditures. We have previously discussed a third important cost, indirect
pollution control-related expense, the cost of additional generating capacity
needed due to capacity penalties incurred by using FGD systems (see Section
3-25
-------
3.2.1.4). In this section we will examine the regional distribution of these direct
costs and investment over the 1986-1995 period.
3.23.1 Regional Pollution Control Costs
We will concentrate our discussion on the regional impacts of the NSPS revisions
on pollution control costs over the period 1986-1995. It should be remembered
that when used, the term pollution control costs includes expenses for
NO and particulate pollution control equipment operation and maintenance.*
x
Tables 3.9 and 3.10 display the regional pollution control costs associated with
alternative scenarios under moderate and high growth cases respectively. As is
shown in the tables, the South Atlantic, Mid-Atlantic, East North Central and
West South Central regions account for the largest percentage of pollution
control costs in the baseline cases, representing 68 percent of the national total.
As expected, the largest increases in pollution control costs occurs in the West
South Central region; for moderate growth, an 80 percent increase, for high
growth, an 85 percent increase. Other large percentage increases occur in the
Mid-Atlantic, North Mountain and Pacific regions. Increases for New England
are less than $0.1 billion because of the nuclear and oil-fired generation in that
region (see Volume I, Table 2.5). Finally, note that in all regions pollution
control costs under the 80 percent SO0 removal requirement and the 215 ng/J
/j £
(0.5 Ib/IO Btu) SOj emission limit scenarios are nearly identical.**
*
The costs of meeting chemical and thermal emission limitations promul-
gated by EPA in 1974 are included. However, these limits do not change
among the scenarios.
,w w,
Although we have not run this last scenario under the high growth
assumption, we do not anticipate that the results would contradict this
conclusion.
3-26
-------
Td>le 3.9
Pollution Control Costs by Region
For Alternative NSPS Revisions*
1986- 1995
Region
Nation
New England
Mid-Atlantic
South Atlantic
East North Central
East South Central
West Norlh Central
West South Central
North Mountain
South Mountain
Pacific
Baseline
M 1.2(0)0.1
$36.4'
°-9 +
5.0
(13.7)
7.0
(19.2)
8.5
(23.3)
4.0
(11.0)
2.2
(6.0)
4.1
(11.2)
0.3
(0.8)
2.5
(6.8)
1.9
(5.2)
M 1.2(80)0.03 M 1.2(90)0.03 M 0.5(0)0.03
+$6.9** +$7.9** +$6.8**
000
+0.3 +0.5 +0.5
:+1.9 -t-2.1 +2.0
+0.3 +0.3 +0.3
+0.1 +0.2 +0.1
+0.4 +0.« +0.3
+3.0 +3.3 +2.9
+0.1 +0.1 +0.1
+0.3 +0.5 +0.2
+0.5 +0.5 +0.5
In billions of 1975 dollars, icnludes expenses for SO,, NOx> porticuldte and related pollution
control equipment operation and maintenance costsf
Change from Baseline.
* Figures in parentheses indicate percent of national totalj does not add to 100 due to
rounding.
3-27
-------
Table 3.10
Pollution Control Costs by Region
For Alternative NSP5 Revisions *
Region
Nation
New England
Mid-Atlaa
South Atlantic
East North Central
East South Central
West North Central
West South Central
North Mountain
South Mountain
Pacific
1986-
Baseline
H 1.2(0)0.1
$40.0
I.I +
4.3
(10.8)
8.0
(20.0)
10.3
(25.8)
3.8
(9.5)
2.5
(6.3)
4.6
(11.5)
0.3
(O.I)
2.7
(6.7)
2.4
(6.0)
1995
HIJX80XX03
+$13.4**
0
+2.6
+2.6
+2.2
+0.2
+0.8
+3.3
+0.2
+0.4
+ 1.2
H 1.2(90)0.03
+$16.3**
+0.1
+3.0
+3.1
+2.6
+0.5
+0.8
+3.9
+0.4
+0.5
+ 1.4
In billions of 1975 dollars; includes expenses for SO2, NOx> participate and related pollu-
tion control equipment operation and maintenance costs.
Change from Baseline.
+ Figures in parentheses indicate percent of national total; does not add to 100 due to rounding.
3-28
-------
3,2,3,2 Regional Pollution Control Investment
We have discussed the national results on direct pollution control investment in
Section 3.2.1.4 above; now we will examine the regional impacts on direct
pollution control investment incurred under alternative NSPS revisions.
Tables 3.11 and 3.12 present regional pollution control investment expenditures
over the 1986-1995 time period.
As was in the case of pollution control costs, several regions dominate the
industry's direct pollution control investment. The Mid-Atlantic, South Atlantic,
East North Central and West South Central in both the moderate and high growth
baseline cases account for over 65 percent of the national total throughout the
period. In the moderate growth baseline case, the West South Central region
incurs the largest percentage of direct pollution control investment. In the high
growth baseline, the East North Central region, which contains the northern Ohio
River Valley area, incurs the largest percentage of this investment expense,
illustrating regional variances in demand growth and generating capacity
additions.
Again, the largest increases occur under the 90 percent SO- removal, 12.9 ng/J
g *
(0.03 Ib/10 Btu) case, although national and regional differences between the
90 percent and 80 percent S0« removal requirements, as presented in Table 3.11,
do not appear significant for the 1986-1995 period. Regionally, the West South
Central area incurs the largest increase, representing a 400 percent increase. As
has been stated before, this Gulf Coast region is the most severely affected due
to the utilities' movement away from gas-fired boilers to coal-fired capacity that
will be subject to the revised standards.'The South Atlantic, North Mountain and
South Mountain regions also show substantial increases in their direct pollution
control expenses. As before, we see that the M0.5(0)0.03 scenario shows nearly
the same direct pollution control investment as the 80 percent S02 removal
standard.
3-29
-------
Table 3.11
Region
Alternative NSPS Revisions*
1986- 1995
Baseline
M 1.2(0)0.1 M l.2(80).03 M l.2(90).03
M 0.5(0).03
Nation
New England
Mid-Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
North Mountain
South Mountain
Pacific
$8.0- +$13.3** +$14.6**
0.5. 0 0
(6.3)
1.5 +0.8 +1.1
(18.8)
1.4 +2.2 +2.5
(17.5)
I.I +0.4 +0.4
(13.8)
0.5 +0.7 +0.8
(6.3)
0.5 +1.4 +1.5
(6.3)
1.6 +6.1 +6.5
(20.0)
O.I +0.2 +0.3
(1.3)
0.4 +0.8 +0.9
(5.0)
0.4 +0.4 +0.5
(5.0)
+$13.3**
0
+ 1.1
+2.5
+0.4
+0.8
+ 1.3
+6.0
+0.2
+0.7
+0.4
In billions of 1975 dollars; includes expenses for SO2, NOX, TSP and related pollution control.
Change from Baseline.
Figures in parentheses indicate percent of national total; does not add to 100 due to
, rounding.
3-30
-------
Table 3.12
Direct Pollution Control Investment by Region
Region
Nation
New England
Mid-Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
North Mountain
South Mountain
Pacific
For Alternative NSPS
1986- 1995
Baseline
H 1.2(0)0.1
$17.6
0.9 +
1.6
(9.1)
2.8
(15.9)
6.1
(34.7)
0.7
(4.0)
I.I
(6.3)
2.7
(15.3)
0.2
(I.I)
0.5
(2.8)
1.0
(5.7)
Revisions*
H l.2(80).03
+$30. 1**
+0.1
+3.5
+4.9
+5.3
+ 1.9
+3.1
+7.3
+0.4
+ 1.6
+2.0
H 1.2(901.03
+$34.4**
+0.2
+4.0
+5.5
+6.1
+2.2
+3.4
+8.3
+0.5
+ 1.8
+2.2
All figures in billions of 1975 dollars; includes expenses for SO2, NOx, TSP and related pollution
control equipment investment.
Change from Baseline.
Figures in parentheses indicate percent of national totaU
3-31
-------
Under the high growth cases presented in Table 3.12, the largest increase occurs
in the West South Central region, as occurred in the moderate growth cases. The
increase in direct pollution control investment for the Gulf Coast area is 300
percent under the 90 percent SO2 removal case. Other regions where investment
expenditures at least double include South Atlantic, East South Central, West
North Central, North Mountain, South Mountain and Pacific. Because relatively
little of its generating capacity is coal-fired, New England again stands out as
being relatively unaffected.
As expected, we project large increases in the utility industry's direct pollution
control investment, although it must be remembered that this increase
represents a relatively small portion of the industry's forecasted total investment
needs.
To summarize, both pollution control costs and direct pollution control invest-
ment increase significantly over the 1986-1995 period. As would be expected,
investment expenditures increase more than costs. The largest increases occur
under the 90 percent SO2 removal 12.9 ng/J (0.03 Ib/IO Btu) particulate limit
cases, although we do not forecast large differences between the 80 and 90
percent S02 removal cases. The West South Central region is the most heavily
affected, as its pollution control costs are forecast to increase at most 85
percent; this region's direct pollution control investment costs may increase as
much as 300 percent. Under the high growth cases, six of the ten regions' direct
investment costs at least double. Becase of its minimal dependence on coal-fired
capacity, New England bears the smallest increase in these costs and investment.
3-32
-------
13 FINANCIAL IMPACTS
In appraising the relative effects of alternative NSPS revisions, economic
impacts, as have been discussed, can be shown as the result of a direct cause-
and-effect relationship. That is, if an NSPS revision suggests that additional
expenditures need to be made, then utilities will bear the added costs and
consumers, higher prices. Financial impacts are more difficult to relate to the
added capital expenditures implied by candidate new source performance
standards. This is true for a variety of possible reasons. There is, in fact, no
direct relationship between utilities' needs to incur additional costs and any
measure of their financial well-being. A number of factors can intervene. The
most important of these factors is regulatory treatment of the added
expenditures and the stock market's interpretation of the financial impact of the
added cost burden. Investors, in making these interpretations, will take into
account such matters as regulatory recognition of possible financial impacts,
consumer responses to higher prices, possible flexibility in the overall capital
spending plans of utilities, perceptions as to the phase of the business cycle in
which capital spending may take place, the perspectives and activities of other
market participants, and the management philosophies and overall financial
health of the affected utilities. It is impossible to take all such factors into
account. However, by making certain behavioral assumptions in the Utility
Simulation Model, it is possible to demonstrate the relative effect of alternative
NSPS revisions on several generally accepted measures indicative of financial
well-being.
The financial health of the electric utility industry may be represented by such
measures as its return on equity, its interest coverage ratio, and the quality of
its earnings. The return on equity, as used in this report, refers to a realized
book return on equity investment. It encompasses both cash and noncash
earnings. The interest coverage ratio refers to the relationship between earnings
and interest payable on debt. The ratio is calculated by adding earnings to
interest payments, and dividing this sum by interest payments. This ratio is
significant because bond indenture agreements are generally written so as to
3-33
-------
prohibit additional debt financing in the event the interest coverage ratio falls
below a certain level, usually 1.75:1 or 2:1. The final measure, quality of
earnings, shows the extent to which a current year's earnings are made up of
noncash credits to income. These credits are placed in an account termed the
Account for Funds used During Construction (AFDC). Clearly, the higher the
proportion of noncash earnings to total earnings (cash and noncash), the greater
will be utilities' difficulties in having both dividends to distribute and earnings to
reinvest in the enterprise.
These measures are often considered indicative of the relative access which
utilities may have to capital markets. If these measures, considered jointly, are
in a poor state over an extended period of time, they may suggest that the
utilities either do not have access to traditional sources of external funds or, if
they do, that these funds could be acquired only if the utilities were willing to
pay a relatively high price for their use.
Before proceeding to show the extent to which the selected measures of financial
health are affected under alternative NSPS revisions, it will prove useful to
highlight a few aspects of the way in which the Financial module of the Utility
Simulation Model produces financial results and, thus, the context in which these
results should be interpreted. (The Financial module has been described more
fully above in Section 3.1.1.)
The essential characteristic of the Financial module is that it is, like other albeit
less elaborately developed models of its type, an accounting structure. As such,
economic and financial decisions are treated in a pre-specified manner at pre-
specified times. Accordingly, these decisions are not constrained by extraor-
dinary events such as unexpectedly high inflation or interest rates. Moreover, it
should be noted that implicit in the operation of this model is a relatively high
degree of "regulatory responsiveness." That is, it is assumed that at the end of
each accounting year expected revenue requirements (for the following year) are
readjusted. In effect, a rate hearing is held and a decision is made at the end of
each year. This may be considered an optimistic assumption with respect to the
3-34
-------
possible deterioration of utilities' financial positions over multi-year periods.
However, it might be inappropriate to assume that state utility commissions
would be less responsive than this and still be able to maintain that the utilities
can operate efficiently.
Return on Equity
For purposes of assessing the relative impacts of alternative NSPS revisions, it
was assumed that all investor-owned electric utilities would be allowed to earn a
13 percent return on equity by their respective state commissions. As the
figures in Table 3.1 1 under national results ("Nation", column I) for the baseline
scenarios with moderate and high electricity growth rates (M 1.2(0)0.1 and
H 1.2(0)0.1, respectively) indicate, the USM projects that investor-owned electric
utilities as a whole will earn less than the allowed rate of return. This result is
due to a combination of factors. The principal element involves the fact that,
over an eleven year simulation period, 1985-1995, in an "average year"* the costs
incurred by the nation's investor-owned electric utilities are greater than the
revenues they are permitted (in the year) by regulatory commissions. These
costs may be greater than revenues because a net increase over the previous
year's interest, O&M, and fuel costs was experienced. Since we have assumed
that regulatory commissions will reassess revenue requirements but once a year,
if the utilities are unable to effect a net reduction in costs in an average year,
they will be unable to earn more than the allowed 13 percent return on equity.
Finally, it should be noted that it is not necessarily a severe problem for utilities
to earn less than that which is allowed by regulators. One of the nation's
strongest investor-owned utilities, Pacific Gas and Electric Company, has been
unable to earn its allowed rate of return in any one of the last five years.
Despite this failure, Pacific Gas and Electric continues to be one of the most
*
financially robust utilities in the nation.
The USM produces annual costs, revenues, returns on equity, etc. which
vary from year to year. For purposes of interpretation, these annual values
were averaged over an eleven year simulation period.
3-35
-------
The results of the simulation under alternative NSPS revisions show the following
results for the nation's investor-owned electric utilities.
EFFECT
SCENARIO ON RETURN
ON EQUITY
M 1.2(80)0.03 - 3.3%
M 1.2(90)0.03 - 4.2%
H 1.2(90)0.03 - 6.5%
The investor-owned electric utilities in some regions are more adversely affected
than they are in others. For example, in New England, NSPS revisions for coal-
fired units have an insignificant effect on the return on equity. Effects are more
readily apparent in the Mid-Atlantic, South Atlantic, East North Central, South
Mountain, and Pacific regions. The greatest impacts on returns on equity due to
tightened standards are projected for the East South Central, West North
Central, West South Central, and North Mountain regions. Impacts are greater in
these regions for both moderate and high growth rate cases.
Two important additional observations should be noted regarding Table 3.13.
First, it should be noted that there is a significant difference in the effect a 90
percent removal requirement will have under the moderate and high electricity
demand growth rate assumptions in certain regions. The Mid-Atlantic, East
North Central, West North Central, West South Central, and South Mountain
regions are more adversely affected under the high growth case than they are
under the moderate growth case.
3-36
-------
CO
Table 3.13
RETURN ON EQUITY
for Investor-Owned Electric Utilities on a Regional Basis under Alternative Scenarios, 1985-1995
>yREGION
CASE^V
Baseline
M 1.2(0)0.1
M 1.2(80)0.03
M 1.2(90)0.03
Baseline
H 1.2(0)0.1
H 1.2(90)0.03
Eost Eost West West *.
triQiQrtct r\TioriTic /\TionTic f^^tf. tmt t^^ntmt tf"*An4mf f^An+rsii lYiooTiTQif* ivioiinToin
12.4% 13.9% 13.1% 10.7% 12.9% 10.9% 14.5% 10.2% 16.5% 13.2% 14.5%
12.0% 13.9 12.7 10.4 12.8 9.8 13.7 9.0 14.0 12.7 14.3
11.9% 13.9 12.6 10.3 12.8 9.7 13.7 8.9 13.9 12.7 14.3
11.5% 15.4 12.1 10.1 11.6 10.2 13.1 9.5 14.9 12.5 13.2
10.8% 15.5 11.4 9.7 10.8 9.5 11.8 7.9 13.5 11.3 12.9
-------
Second, the results of the simulation show only a marginal effect on return on
equity in going from an 80 to a 90 percent S02 removal requirement. The small
effect that shows up in five of the ten regions is well within the margin of
uncertainty.*
3.3.2 Interest Coverage
Interest Coverage ratios for investor-owned electric utilities under the various
control scenarios are shown in Table 3.14. As indicated in this table, baseline
conditions (current NSPS for SO- and particulates under moderate and high
electricity growth rates) essentially foretell the extent to which utilities in
particular regions may have difficulty attracting needed debt financing. In this
regard, the New England, South Atlantic, East South Central, and West South
Central regions could have debt financing problems under the assumptions used in
the simulation model.
The interest coverage ratios in three of these regions South Atlantic, East
South Central, and West South Central can be shown to be measurably affected
by alternative NSPS revisions. Adverse effects are found in some other regions,
but, with the exception of the South Mountain region, these effects may not be
significant. It should also be noted that in some cases anomalies appear in these
results. That is, coverage ratios going up by one one-hundredths when these
might be expected to go down - but these results are well within the margin of
uncertainty.
The results for the nation's investor-owned utilities are summarized as follows:
An extensive sensitivity analysis would be required to quantify the band of
uncertainty surrounding all the key data for this analysis.
3-38
-------
Table 3.14
INTEREST COVERAGE
CO
CO
vo
\REGION
CASES.
Baseline
M 1.2(0)0.1
M 1.2(80)0.03
M 1.2(90)0.03
Baseline
H 1.2(0)0.1
H 1.2(90)0.03
New Mid- South East East Wesf West North South
England Atlanhc Atlonfc Cenfra| Ccntn]| Centnj| Centra| Moontam Mountom
3.14% 2.52% 3.50% 2.82% 3.44% 2.78% 3.61% 2.63% 4.38% 3.42% 3.70%
3.14% 2.52 3.47 2.81 3.43 2.73 3.62 2.62 4.36 3.38 3.68
3.14% 2.54 3.47 2.76 3.42 2.73 3.62 2.62 4.36 3.31 3.68
3.01% 3.23 3.24 2.67 3.27 2.66 3.30 2.55 3.71 3.14 3.37
2.97% 3.22 3.21 2.68 3.19 2.66 3.25 2.49 3.68 3.10 3.31
-------
EFFECT ON
SCENARIO INTEREST COVERAGE
RATIO
M 1.2(80)0.03 No Change
M 1.2(90)0.03 No Change
H 1.2(90)0.03 - 1.3%
33.3 Quality of Earnings
It is generally assumed that astute investors will bid down share prices if AFDC
is expected to represent a large proportion of earnings over a long period of
time. This would be true, in part, because a high proportion of (noncash AFDC)
earnings would be unavailable for immediate reinvestment in the utility. This
would imply that utilities would need to go to the capital markets for additional
funds if sizeable capital or any other expenditures were required. It would imply,
moreover, that if a significant downturn in revenues were experienced, dividends
or possible dividend increases could be endangered.
Table 3.15 shows that under the assumptions of the Utility Simulation Model,
AFDC in every region of the nation assumes a much larger position in earnings
statements than it has traditionally. This situation can be the result of a number
of factors, most important of which are relatively high construction financing
obligations tied up in the AFDC account and relatively low generation of cash
earnings. That the construction financing account (AFDC) should be relatively
high by historical standards can be understood by the fact that additions to
generating capacity will be more costly and capital-intensive than ever before.
Also, since the cost of capital assumed for the forecast period is reflective of a
current weighted average cost and not an historical cost, the AFDC rate will be
higher than it has ever been.
3-40
-------
Tdble3.l5
QUALITY OF EARNINGS
Percentage of Earnings That is Noncash AFDC
for Investor-Owned Electric Utilities on a Regional Basis under Alternative Scenarios, 1985-1995
\REGION
CASES.
Baseline
M 1.2(0)0.1
M 1.2(80)0.03
M 1.2(90)0.03
Baseline
H 1.2(0)0.1
H 1.2(90)0.03
NATION New Mid- South Jr"5.! £^t $**$ jj^ North South pacjfc
England Atlantic Atlantic r* * i r* * t /- * i <~ « i Mountain Mountain
Central i-entrai central central
38% 46% 32% 43% 36% 46% 31% 53% 22% 37% 28%
39% 46 31 44 38 50 30 57 23 36 28
40% 44 31 45 38 50 30 57 24 37 28
44% 60 38 51 43 52 37 55 30 42 34
47% 60 39 53 45 57 40 62 33 45 35
-------
It is certainly debatable whether or not the quality of the nation's electric
utilities' earnings could erode as much as that represented in the baseline
scenarios. Part of this erosion is due to regulatory lag, which the Financial
module includes. However, the utilities' response to earnings quality erosion
would likely be to request more rate increases (to increase cash earnings) and
higher returns on equity (both to increase cash earnings and to attract needed
capital, which may be more difficult to do due to investors' discounting as a
result of earnings quality troubles). The model does not increase the frequency
of rate relief, nor does it increase the allowed rate of return on equity.*
With these considerations in mind, it should be noted that the purpose of this
assessment is to show the effect, if any, on this measure of financial health,
eqrnings quality, which may be attributable to alternative NSPS revisions. For
the nation's investor-owned electric utilties, the results of the simulation model
show the following marginal impacts on earnings quality.
EFFECT
QUALITY
M 1.2(80)0.03 - 2.6%
M 1.2(90)0.03 - 5.3%
H 1.2(90)0.03 - 6.8%
*
Teknekron performed an analysis of the sensitivity of earnings quality to
increased allowable return on equity, and found that there is a greater than
one-to-one correspondence between percentage increases in target return
on equity and improvements in earnings quality.
3-42
-------
As for relative impacts on earnings quality over the ten regions considered in this
assessment, the regions most affected are the West South Central and East South
Central areas. Measurable effects are also shown in the North Mountain, South
Mountain, and West North Central regions.
The greatest impacts on earnings quality are experienced in two of the regions
with most basic financial difficulties as implied by results for the baseline
scenarios. To reiterate, these regions are West South Central and East South
Central. The South Atlantic region, which also has a relatively high proportion
of AFDC in its baseline scenarios, is not as significantly affected. New England
also has an earnings quality problem in its baseline scenarios; however, since in
this region the problem may be related to nuclear capacity expansion, the
alternative NSPS revisions have a negligible effect. In the results for New
England, there is an anomaly which is within the margin for error.
It is important to note, at this point, the relationship between earnings quality
and realized return on equity. Earnings quality is essentially a measure used to
distinguish between cash and noncash earnings. Return on equity calculaitons do
not make this distinction. The return on equity computation is based on a book
return (i.e., not a cash-flow return), as is consistent with accepted accounting
practice. Since the cash/noncash distinction is not made for return on equity, a
particular region may have a poor quality of earnings ratio without its return on
equity suffering to the same extent. If the return on equity were calculated on a
cash-flow basis, then there would be a direct relationship between it and earnings
quality.
3.3.4 Summary of Industry Impacts
Under the assumptions used in the operation of the Utility Simulation Model, the
following impacts on the financial well-being of the nation's investor-owned
electric utility industry may be viewed as attributable to alternative NSPS
revisions:
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M
M
H
Scenario
1.2(80)0.03
1.2(90)0.03
1.2(90)0.03
Return on
Equity
- 3.3%
- 4.2%
- 6.5%
Interest
Coverage Ratio
No Change
No Change
- 1.3%
Earnings
Quality
- 2.6%
- 5.3%
- 6.8%
The regions most significantly affected from a financial perspective are the West
South Central and East South Central areas. The impacts in other regions are
less significant. That the impacts should be greatest in West South Central
region could reasonably be expected since a large amount of coal-fired capacity
subject to a revised standard is anticipated to be built in this area. A sizeable
amount of new capacity both nuclear and coal, though especially the latter
will be built in these regions prior to the units subject to a revised standard
coming on line. This suggests that, particularly in these regions, though certainly
in other regions as well, utilities may have difficulty attracting investors on what
are now considered reasonable terms (e.g., a 13 percent allowed return on equity)
to the rather bleak prospects described under the baseline scenarios.
Accordingly, there are at least two interpretations that might give such
measures of financial health. First, these measures may be indicative of the
extent to which state regulations in certain regions will be under pressure to
facilitate electric utility financing (e.g., by raising the allowed return on equity,
by increasing the frequency of rate relief, by permitting construction-work-in-
progress in rate base, or by other means). Second, these measures may indicate
that electric utility spending plans are too ambitious.
Irrespective of the interpretation which may be attached to figures in the base-
line scenarios, the relative effects of alternative NSPS revisions, both for the
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moderate and high growth futures, are projected to have relatively little national
financial impact.
3.3^5 External Financing Impact
Since a large proportion of the additional costs and investment expenditures
required by the electric utility industry due to revisions in pollution control
regulations will be financed externally, it is useful to examine the impact on
long-term external financing of the alternative NSPS revisions for the nation's
investor-owned electric utilities. Results of the simulation for alternative NSPS
revisions on long-term financing are presented in Table 3.16.
For each of the cases considered, additional total external financing accounts for
approximately 60 percent of the investor-owned utilities' NSPS revision-related
investment requirements over the 1976-1995 period. The largest percentage
occurs under the high growth most stringent scenario (H 1.2(90)0.03), where
external financing represents 63 percent of total investment.
As shown, the utilities' long-term external financing increases significantly
between the moderate and high growth baseline cases. As would be expected,
the majority of this financing is made with long-term debt issues. Neither long-
term debt nor preferred stock financing is forecast to be affected greatly by the
alternative NSPS revisions under moderate growth. In addition, the 90 percent
SO- removal case is not forecast to affect significantly the utilities' external
financing requirements as compared to the 80 percent SO- removal case. The
differences between the two cases are less than 0.3 percent for each type of
financing. The NSPS revisions are forecast to influence common stock financing
more heavily than either debt or preferred stock, although debt remains the
major source of capital for the utilities. Common stock financing is forecast to
increase 7 percent under both the 80 and 90 percent S02 removal cases. Total
incremental external financing over the twenty-year period is forecast to be
$10.4 and $11.1 billion (in 1975 dollars) for the 80 percent and 90 percent
removal cases, respectively.
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Table 3.16
Long-Term External Financing
Baseline External Financing
Long-Term Common Preferred
Debt Stock Stock
Incremental Long-Term External
Financing Attributable to
Alternative NSPS Revisions
Long-Term
Debt
Common Preferred
Stock Stock
CO
J>
ON
Baseline
M 1.2(0)0.1
M 1.2(80)0.03
M 1.2(90)0.03
$255.2* $ 87.0
80.8
+$3.4
+3.8
+$6.0
+6.1
+$1.0
+ 1.2
Baseline
H 1.2(0)0.1
H 1.2(90)0.03
363.7
158.3
III.3
+7.7
+ 13.6
+2.3
All dollar figures in billions of 1975 dollars.
-------
Under high growth, the 90 percent S02 removal case is forecast to require more
than 2 percent more debt and preferred stock, and more than 8 percent common
stock financing, which together represent, on average, less than 0.2 percent
increase in total external financing per year over the 20-year period. This
incremental external financing is forecast to be $23.6 billion (in 1975 dollars)
through 1995.
3.3.6 Impact on National Capital Markets
The Utility Simulation Model allows for an integrated technical, environmental,
and economic/financial assessment of the alternative NSPS revisions on the
utility industry, as has been described above. However, the model is essentially a
micro-economic impact model and is not formally "linked" to a macro-economic
forecasting model. Because it is useful to examine the potential macro-
economic impacts of alternative NSPS revisions for electric utility industry
boilers, we have attempted to calculate these impacts by utilizing the Data
Resources, Inc. (DRI) long-term macro-economic forecasting model in conjunc-
tion with our results.
This effort could be undertaken because the data that are required to perform a
mcaro-economic analysis include forecasts for Gross National Product (GNP) and
its components. Comparable types of forecasts are required for the operation of
the Utility Simulation Model. However, producing forecast consistency is a
difficult problem because of differing assumptions about the movement of key
economic parameters such as the inflation rate, the growth in electricity demand
and financial parameters such as bond rates, returns on equity, and external
financing requirements.
Before we present the results of this co-ordinated assessment, there are several
qualifications that must be made about the results. First, the DRI forecasts stop
in 1990, when the financial impacts of the NSPS revisions have not yet matured.
Thus, the full potential financial impact of the revisions on the nation's capital
markets is not discussed. Second, the problem of forecast consistency between
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the two models cannot be fully resolved. Significant differences remain in
parameter values, data sources, and model structure. For example, we have used
the TRENDLONG 0977 forecast, which is the most consistent forecast with that
of the USM based on inflation rates and other parameters. However, under the
DRI forecast, an inflation rate of 5.7 percent between 1976 and 1983 drops to 4.5
percent in the late I980*s. This is contrasted to the constant 5.5 percent per
year rate used in Teknekron's forecast.
Nevertheless, we believe the results presented below are illustrative and indicate
the general magnitude of the macro-economic impact of imposing the NSPS
revisions we have considered, although care must be taken in placing confidence
in the actual forecast values.
We have selected the high growth, 90 percent SO- removal scenario
(H 1.2(90)0.03) for analysis because it contains the largest potential macro-
economic impact since the utility industry's total investment increases the most
under this case (see Table 3.5). All other alternative NSPS revisions will likely
result in less macro-economic impact.
Comparing the high growth baseline with the M 1.2(90)0.03 case, we forecast
that in 1990 an additional $6.2 billion dollars of plant and pollution control
investment will be needed. This figure is converted to 1972 dollars, which the
DRI model uses, giving $5.25 billion. In 1990 the DRI model forecasts that GNP
will be $2,109.4 billion and gross private domestic investment, $321.5 billion.
Thus we estimate in 1990 that the NSPS revision-induced investment for the
electric utility industry will account for 0.25 percent of GNP and 1.6 percent of
gross private domestic investment. From this we conclude that the NSPS
revisions we considered are likely to have, at most, a small impact on the
nation's capital markets, e.g., on the level of interest rates in that year.
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4.0 COAL VERSUS NUCLEAR: Economics end Decision-Making
As Affected by Revised New Source Performance Standards
For Coal-Fired Boilers
It has been asserted by a critic of nuclear power, Charles Komanoff,* that the
golden age of nuclear economics said to have lasted from 1968 to 1975 is
over. President Carter himself has declared, in addressing a delegation at the
International Fuel Cycle Evaluation Conference, that "the need for atomic power
for peaceful uses has perhaps been greatly exaggerated", suggesting that all
nations carefully assess the alternatives to nuclear power, "if for no other reason
than economics"** (emphasis added).
Alternatives to nuclear power for new baseload electrical generation also have
economic problems. At present, the principal alternative to nuclear is believed
to be coal-fired.plants. While the potential coal resources of the U.S. are
extensive, costly restrictions on the extraction, combustion, and disposal of
waste products make use of these resources an expensive proposition. It is
sometimes alleged that, in the final analysis, electrification based on coal will be
as expensive or more expensive than that based on nuclear power. Following this
view, revisions to current New Source Performance Standards for coal-fired
boilers might be sufficiently costly to tip the economic scales to a clear
advantage for the nuclear alternative.
What are the economics of nuclear and coal power? Is decision-making with
respect to nuclear vis-a-vis coal for new baseload electrical generating capacity
likely to be significantly affected by added cost burdens placed on coal-fired
plants as a result of revised NSPS? If so, in what regions of the nation can this
effect be anticipated to be most pronounced? If not, what factors may operate
to mitigate or otherwise make insignificant this effect? What are the principal
quantifiable and non-quantifiable factors likely to be weighed in choices, on a
regional basis, between nuclear and coal?
See Komanoff reference, Table 4.1.
The Energy Daily, 5(204); I, October 20, 1977.
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The purpose of this chapter is to address these issues in such a way as to provide
a broad assessment of the effect of a single set of possible EPA regulatory
initiatives - that of revising the NSPS for coal-fired boilers. As such, the
analysis does not dwell on any one of the sizeable number of sub-issues which
arise in considering the relative prospects for coal and nuclear power. Rather,
by presenting a brief review of a representative sample of economic evaluations
of these two power technologies and by enumerating the key factors on which the
relative attractiveness of each of these technologies now rests, it is hoped this
assessment will prove useful in the formulation of public policy.
4.1 BUSBAR POWER COSTS
The relative economics of alternative fuel-type/plant-types is conventionally
expressed in terms of busbar power costs. This means, in effect, that each
fuel/plant candidate is assessed in terms of the cost which is likely to be incurred
to feed its product, electricity, from the power plant to connecting transmission
I ines.
All anticipated capital charges, fuel, operating and maintenance expenses are
taken into account in this economic evaluation. Numerous detailed calculations
must be made to arrive at a busbar power cost. Crucial decisions must be made
as to the assumptions which should go into the model for evaluation. Generally,
every item input is based on someone's forecast, i.e., assumption, as to a "most
likely" value for that item. The end-product of such an economic evaluation is a
level ized cost - that is, a yearly cost spread over some period of time, which is
often but not always equal to the anticipated Irfe of the plant. This cost is
expressed in terms of mills-per-kilowatt-hour. In theory, the plant which is
calculated to deliver electricity to the transmission lines at least cost, e.g., over
the life of the plant, would be chosen to be built. In practice, this will not
always be so.
i
Decision-makers do not necessarily rely on "most likely" estimates for values
which are critical to the evaluation. Some would rather base their decisions on
"worst-case" values for these variables. If a particular fuel/plant type were to
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maintain its economic attractiveness under "worst-case" assumptions, then it
may stand a better chance of being chosen.
Another possible reason for not choosing the alternative which is calculated to
have the lowest busbar power cost has to do with the limitations which exist as
to what can be quantified as input data to busbar power cost calculations or
for other purposes. In theory, probabilities can be assigned to any future
occurrence. For example, one might wish to learn the probability of a nuclear
moratorium or shutdown aimed at then-operating plants in a particular state.
Even if the probability of such an occurrence could be determined, i.e.,
quantified, this information would not be reflected in anticipated unit power
costs. Moreover, it is unlikely that any decision-maker would lend much
credence to the precise odds produced as a result of such an exercise.
Despite these and other limitations to be discussed concerning the usefulness of
busbar power cost estimates for ultimate decision-making purposes, these
estimates provide a point of reference. In the following section, a review is
made of three recent estimates of the unit costs for producing electricity from
new baseloaded nuclear and coal-fired plants. In some respects, these estimates
parallel one another; in others, they diverge. Basically, in some cases analysts
would agree as to the future behavior of key variables affecting costs and, in
other cases, they would disagree.
4.2 REVIEW OF ECONOMIC EVALUATIONS
Over the last three years, numerous evaluations have been conducted concerning
the relative economics of coal and nuclear power. These studies have been
performed by or for reactor and boiler manufacturers, electric utility trade
associations, environmental organizations, and state and federal agencies. Each
of these studies was conducted for a different purpose. Accordingly, the
emphasis of each and the extent to which detailed calculations were performed
varies enormously. Few were published with sufficient documentation to make
possible meaningful comparison with other studies.
4-3
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Major assumptions as to basic investment costs, escalation rates for various cost
elements, and fixed charge rates differed among the studies. Further, costs were
levelized over different periods of time. In sum, since these and other problems
inhibited attempts to reconcile cost estimates, the generalizations which are
drawn from this review should be viewed in the light in which they are intended:
to establish a point of reference.
As might be expected, there are basically two schools of thought on the coal
versus nuclear economics.question: a coal school and a nuclear school. This
difference in views is clearly manifest in Table 4.1. In the Komanoff view coal is
the least-cost alternative in every region. The Electric Power Research Institute
(EPRI) presents a completely contrary point of view. The National Economic
Research Associates, Inc. (NERA) view is that nuclear is cheapest in most
regions. (It should be noted that the results shown for NERA estimates represent
but one set of figures offered by the firm in the GESMO hearings. Other sets of
figures show the economic advantage of nuclear to be greater.)
4.2.1 Capacity Factors
These estimates (and others) vary for some basic reasons. Komanoff, who has
made some contributions to the understanding of the recent reliability of nuclear
units and of both nuclear and coal units of larger magnitude, begins with the
premise that only larger (over 1000 Mw) nuclear units will be available in the
future and that these units will function at significantly lower capacity factors
thaii do smaller units built in the U.S. in the past. Consequently, he compares
the relative economics of three 600 Mw coal units (he alleges units of this size
are more reliable) operating at a levelized capacity factor of 70 percent to two
I ISO Mw nuclear reactors operating at a 55 percent capacity factor.
Capacity factor assumptions are crucial inputs to economic evaluations such as
these. That Komanoff should assume different capacity factors for coal and
nuclear plants and that EPRI and NERA should assume equal capacity factors for
these two types of plants makes it very difficult to compare the results of these
economic evaluations.
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Table 4. 1
Comparison of Nuclear and Coal Busbar Power Costs on Regional Basis
(Mills/kWh)
New Mid- South .Eas* J^t
England Atlantic Atlantic /^ , <~ , i
v_enTroi i*cnTrai
NUCLEAR 55.7 55.7 52.0 54.0 52.0
COAL 55.4 55.4 46.5 45.5 42.0
NUCLEAR 37.7-45.5 37.7-45.5 ,34.0-41.2 36.4-44.034.0-41.2
COAL 43.4-52.8 43.4-52.8 39.9-48.6 42.3-51.439.9-48.6
NUCLEAR 50.0 50.0 45.8 48.9 45.8
MFRA - - -
COAL 54.7 52.7 49.3 49.6 46.5
West
North
Central
54.0
42.8
35.4-42.8
38.4-46.7
48.9
46.4
W«*f North Sooth PACIFIC
Central Mountain Mountain NW Calif.
52.0 54.0 54.0 54.0 55.7
42.0 36.0 36.0 36.0 44.6
34.7-42.0 36.2-46.4 36.2-46.4 36.2-46.4
37.5-44.6 40.6-51.8 40.6-51.8 40.6-51.8
45.9 47.6 47.6 50.2 50.2
47.5 39.7 46.2 51.0 46.3
Komanoff, Chas., Testimony of - on the Costs of Nuclear Power before the House Subcommittee on Environment, Energy, and
Natural Resources, September 21, 1977. Komanoff compared costs of generating electricity from 3 - 600 MW coal units
to 2 - 1,150 MW nuclear units. He assumed these two configurations would achieve the same overall system reliability.
Assumed capacity factors: 55% for nuclear; 70% for coal.
EPRI PS-455-SR, Coal and Nuclear Generating Costs, April 1977. Assumed capacity factors: 66% for both types of plant.
NERA, Testimony of Dr. Lewis J. Perl, on behalf of the GESMO Utility group. Concerning Nuclear and Coal Electric
Generating Capacity Expansion, 1975-2000; March 4, 1977. NERA produced estimates of busbar power costs for two
scenarios under different capacity factor assumptions. The estimates shown are for the "high-cost" nuclear scenario, the
figures for which parallel those made in the latest estimates for plants coming on line in 1986. Assumed capacity
factors: 60% for both types of plant.
-------
Komanoff bases his capacity factor assumptions, in part, on rough extrapolations
of the recent experience of nuclear units of larger capacity. In effect, he sees
no reason to believe that nuclear reactors of this size will operate very much
better in the future than they do now. Utilities view this matter quite
differently, as do reactor manufacturers. They believe that the performance of
larger size reactors will improve with age. (It should be noted that reactor
manufacturers have taken issue with some of Komanoff's findings and, obviously,
with his conclusions.) They argue that a few problem plants, e.g., the Browns
Ferry units //I and #2, bias the overall performance of nuclear power. It is also
argued that the units of some manufacturers perform better than others.
Finally, and very importantly, it is argued that regulatory initiatives on the part
of the Nuclear Regulatory Commission (NRC), and others have had a great deal
to do with the less than anticipated nuclear capacity factors. It is suggested that
availability factors (a measure purported to adjust for the adverse effect on
capacity factors of regulatory initiatives to raise the probability that existing
nuclear reactors can be operated safely) would be a more equitable measure of
reactor performance. Also, it is argued that as the nuclear industry matures, as
reactor designs are standardized, and as regulatory procedures are routinized,
the capacity factors of nuclear power plants will rise.
It is clear that all of this takes some faith. The burden of proof rests with the
nuclear industry. It is also evident that, despite all the problems of the industry,
electricity now produced from nuclear reactors is competitive with that
produced from coal-fired facilities. This can probably be explained in part by the
fact that when nuclear units are available for use there is a large incentive to
use them as much as possible perhaps in the process relegating coal-fired units
to a subordinate dispatch position.
On the matter of capacity factors, another point should be noted. In another
evaluation of the relative economics of coal versus nuclear, a study group*
Nuclear Power; Issues and Choices; Report of the Nuclear Energy Policy
Study Group, Ford/Mitre, 1977.
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assumes that a coal-fired plant burning Northern or Central Appalachian coal and
requiring a scrubber would have a capacity factor five to ten percent less than it
would were no scrubber required.*
4.2.2 Fuel Costs
Another important factor contributing to the current economy of nuclear power
is the relatively inexpensive fuel now being used in these units. Future fuel
prices probably will be much higher. How much higher cannot be determined,
because virtually no new uranium supply contracts now negotiated involve fixed-
prices (with customary cost escalation clauses). Instead, all new contracts
entered are of the "market-price" variety, wherein the selling price is deter-
mined just prior to delivery, based on then-prevailing market prices.
Since these contractual arrangements are consummated as much as a decade
before deliveries begin, this presents a rather risky situation for a utility. It is
especially risky since fuel costs, based on information from fixed-price contracts
when they were available, are expected to represent 40 to 50 percent of total
fuel cycle costs** for plants coming on line in 1986. Fuel cycle costs are now
about 25 percent of total busbar power costs for nuclear units.
The combination of f.o.b. mine coal prices and transportation charges is
generally assumed to account for about 40 to 50 percent of the future busbar
power costs of coal units. As such, the assumptions which are made as to the
future prices of coals with different characteristics, in different regions, and
with different means and costs of transport are crucial inputs to busbar power
cost calculations.
It should be noted that possible changes in the availabilities of coal units
due to the installation of FGD systems have not been incorporated in the
Utility Simulation Model. *
** Fuel costs for a light-water reactor include the prices charged for mining
and milling. Fuel cycle costs, assuming no recycle, include the prices
chargecLfor mining, milling, conversion (U30ft to UFA enrichment (UF* to
3% UZl"), fabrication (enriched UF, to UO3,°peNeti2e, sinter to U02, fead
and fabricate into fuel elements), shipping spent fuel, waste management
(interim and long-term), and fuel inventory charge.
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It was not possible to determine with any degree of certainty whether the busbar
power cost differentials noted in Table 4.1 could be attributable to differences in
assumptions as to the future prices of coal and transport. The NERA study was
reasonably detailed insofar as it identified sources of coal, accordingly to Bureau
of Mines' regions, and assumed cost escalation factors were stated
unambiguously. A least-cost optimization model was said to have been used to
determine coal flows. The EPRI and Komanoff studies lacked equivalent
documentation. Other studies or models of coal flows, ones with which NERA's
results might conceivably be contrasted, were not considered for this analysis.
4.2.3 Capital Costs
The economic factor most often mentioned as the major nuclear parameter is its
capital cost. Building a kilowatt of nuclear capacity is estimated to cost from 15
to 30 percent more than building a kilowatt of coal-fired capacity. In the three
studies compared in Table 4.1, it was estimated by Komanoff that a kilowatt of
nuclear capacity would cost 26 percent more, by NERA, 24 percent more, and
EPRI, 17 percent more. These are national averages; there is very little regional
variation in these relationships.
In considering capital cost estimates, it is important to note not only the rela-
tionships between nuclear and coal investment figures but also the magnitude of
these estimates. In this regard, Komanoff's national average for nuclear,
$l,200/kw (1985 dollars, 1150 Mw), is 14 percent higher than the NERA estimate;
(same size unit); his coal investment figure, $950 (600 Mw), is 11 percent higher
than NERA's (800 Mw). EPRI figures could not be compared in this manner.
A higher absolute level of investment implies, other things being equal, that
there will be greater amounts of interest charges that will appear in busbar
power costs. This assumes, for pne thing, that the same fixed charge rates are
used. Komanoff and NERA did not use the same rates.
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To summarize, differences in the estimated busbar power cost advantages to
nuclear and coal, as displayed in Table 4.1, may be attributable to: differences
in assumed capacity factors; differences in assumptions as to future delivered
coal prices; and differences in capital cost and fixed charge rate assumptions.
Estimates for particular aspects of the nuclear fuel cycle could not be shown to
vary. Nor could it be demonstrated that significant variation exists in projected
O & M costs for either coal or nuclear.
4.2.4 NSPS Revisions and Regional Effects
Based on preliminary and rough calculations of the incremental costs associated
with NSPS revisions, it can be stated that the busbar power costs of coal may
increase by 6.5 mills per kilowatt-hour, ± 20 percent, in 1985 dollars. With
reference to Table 4.1, this effect may be seen to tip the economic scales in
favor of nuclear in three of the four areas which NERA now estimates a slight
advantage for coal. Coal would maintain its advantage, in the NERA analysis,
\
only in the North Mountain region. In the Komanof f analysis, coal would lose its
advantage in the Northeast, Mid-Atlantic, and South Atlantic regions.
While these may appear significant effects in terms of a strictly quantifiable
measure, their true effect on decision-making concerning coal and nuclear may
in fact be quite insignificant. Estimates such as those discussed in Section 4.2
may well not be the basis for actual decision-making. In the following section,
other not strictly quantifiable factors are suggested as possible reasons for
choosing to build a nuclear and not a coal plant, or vice-versa.
4.3 FACTORS DIFFICULT TO QUANTIFY
In this section, factors that are difficult to quantify are viewed from two per-
spectives. First of all, from the perspective of a decision-maker who may be
attempting to find out a number of good reasons to invest in nuclear. The list
4-9
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the decision-maker draws up will include, assuming there is but one other choice,
coal, the principal reasons to avoid coal. The other perspective is one drawn in
terms of reasons to go with coal, if for no other reason than to avoid nuclear.
4.3.1 Reasons to Invest in Nuclear
And Reasons to Avoid Coal
PUBLIC SUPPORT
It is not enough to simply calculate busbar power costs, do some sensitivity runs,
and then decide that nuclear power is competitive and, therefore, there can be
no argument about it. What a decision-maker needs is backers, people who will
help to make his choice an economic one.. In this regard, because an enormous
amount of taxpayers' money has already gone into the development of peaceful
uses for atomic power, there is a natural desire on the part of taxpayers and
public servants to see the nuclear promise realized at some time. Accordingly, it
may be safe to assume that the public would not permit nuclear power be made
uneconomic by, for example, lifting the tort liability protections provided under
the Price-Anderson Act, by pricing enrichment services or waste disposal
services at unsubsidized rates, or by eliminating certain special tax advantages.
EXPERIENCE
Firms such as Commonwealth Edison and an ever-increasing number of others are
learning, by experience, about the economics of nuclear power. Significantly,
Commonwealth Edison is pushing ahead with the siting and licensing of more
reactors and captive uranium mine development.
DIVERSITY
Even a utility such as Commonwealth Edison which is heavily committed to
nuclear, recognizes the strength in a diversity of plant/fuel types. As a result, it
is also planning to build more coal-fired units. Utilities now principally coal-
fired may be wishing, as the effects of the coal strike are beginning to hurt sales
and profitability, that they had a reactor or two.
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The threat of coal strikes is not the only reason to avoid too heavy a reliance on
coal. There may be apprehension that sulfur and participate controls will not
function properly on some coal plants, and that these plants may be required to
shut down until such controls are effective. The reliability and ultimately the
economics of these plants could, as a result, be much worse than now foreseen.
Other factors could make coal appear uneconomic. For one thing, FGD sludge
disposal costs may be higher than now anticipated. Severance taxes, greater
costs for surface mine reclamation, for mine health and safety, or for miners'
pension funds could make coal power lose its attractiveness.
SITING COAL PLANTS
Air quality standards make the siting of a coal-fired plant a major problem. To
site a plant in or anywhere upwind of a Non-Attainment area could well involve
having to invest in . tradeoffs. These could prove uneconomic given the
alternative of nuclear power.
In the near term, coal plants may be sited in Class II and other areas. But in so
doing, the allowable degradation increments may be used up. Again, nuclear may
be the only reasonable alternative in the long-term.
THE ENVIRONMENTAL EFFECTS OF EXPANDED COAL USE ARE UNKNOWN
One of the most compelling reasons to avoid coal is that new controls for nitric
oxides, heavy trace metals, and toxic and carcinogenic compounds may be re-
quired. The combined cost of such emissions controls is now not available.
NUCLEAR IS YOUNG, FURTHER ASSISTANCE WOULD MAKE ITS
PROSPECTS BRIGHT
Like all relatively new technologies, nuclear power has been struggling to get on
its feet. It may need further help. In this regard, an elimination of the Con-
struction-Work-in-Progress account (i.e., include construction expenditures in the
rate base) would help to reduce the economic/financial bias against a capital-
intensive technology. In addition, while plutonium recycle is contrary to current
national policy, were this policy changed the economics of nuclear power would
be enhanced marginally.
-------
4»3.2 Reasons to Invest In Coal ond Avoid Nuclear
INDIGENOUS RESOURCE
In 1976, greater than 80 percent of uranium procurements for future delivery
were negotiated with firms whose mines are in four western states New Mexi-
co, Wyoming, Colorado, and Utah. About 14 percent of procurements is to come
from foreign sources.* Nuclear electrification may end up sending a sizeable
proportion of electricity rate payers' money to these four states and,
increasingly, to other nations.
By contrast, coal-powered electrification can keep fuel costs circulating in local
economies. Twenty-one states have substantial coal reserves. Several others
have mineable through less significant reserves. NSPS revisions could make all
U.S. coal available for use that is, if these revisions imply an effective FGD
mandate. Not all reserves can be developed economically, but the potential is
there to have many states share in the spillover benefits of electrification.
In this regard, there may be further political/economic pressure to have reliance
on indigenous coal resources become a reality. This pressure may affect utilities
which have planned to build nuclear plants.
COMPETITIVE CHARACTERISTICS OF COAL MARKET
The market for coal may be seen as having more competitive characteristics
than does the market for uranium. 'NSPS revisions may further increase the
competitiveness of this market. It may also be said that the market for coal-
fired boilers has more competitive characteristics than does the market for
Reference to study conducted by J. Patterson and G.1 Combs, DOE, Division
of Uranium Resources and Enrichment, Supply Evaluation Branch, in The
Energy Daily, 5(210); 4, October 31,1977.
4-12
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' nuclear reactors. Together these factors may help to keep the busbar power
cost of coal-fired units very competitive - with nuclear or other types of elec-
trical generation.
FLEXIBILITY OF COAL-FIRED UNITS
If for some reason coal cannot be burned in the quantities now foreseen, units
designed for coal can in many cases with some, albeit expensive, modification be
converted to burn other fuels. Nuclear units have no such flexibility.
LESS EXPOSURE TO INFLATION
Since coal-fired units are less capital-intensive than nuclear reactors and if coal-
fired units continue to maintain their several-year advantage in terms of
licensing and construction, these units will be less exposed to the possibility of
labor and material cost overruns due to periods of high inflation during con-
struction. Moreover, for the same reason and with the same supposition in mind,
coal-fired units will have lower interest costs during construction.
THE NUCLEAR FUEL CYCLE IS FRAUGHT WITH PROBLEMS
At present, the alternatives for acquiring uranium to fuel a reactor appear to
include: (a) making a sizeable investment in a captive uranium mine with no
control over the rest of the fuel cycle (such investment in a captive coal mine
might be more cost-effective); or (b) entering into a fixed-price contract with a
supplier or middleman who has no bargaining strength with the risk that the
contract may be abrogated (as did Westinghouse) for reasons of "commercial
impracticability;" or, (c) entering into a "market-price" contract wherein there is
virtually no control over the price ultimately paid for the uranium. None of
these options appear particularly appealing.
Just 12 months ago, enrichment costs were considered relatively stable at
$60/Separative Work Unit (SWU).* Now, the GAO has called for higher, "fair
value", prices for enrichment services. $88/SWU is set as a new interim price.
A separative work unit is a measure of work required to separate uranium
isotopes in the enrichment process.
4-13
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This increase in price will mean a yearly increase in nuclear power cost from
about $4.7 million to about $6.9 million. Over a 30-year period, this is an added
cost of approximately $66 million. The future is uncertain - both in terms of
enrichment prices and in terms of national enrichment capacity.
Just 12 months ago, waste management was being estimated in busbar power
calculations at $!6/kg. Now the federal government has proposed a $IOO/kg
price for this service, and the service is simply an interim solution. The proposed
price increase would raise the yearly waste management costs to a utility from
about $400,000 to $2,500,000. Over a 30-year period, this means an increase
from $12 million to $75 million. There may be technological solutions to
ultimate waste disposal, but there may not be an institutional/political solution
for some time to come. In the meantime, other states or the federal government
may follow the lead of California and Sweden in stopping nuclear power until an
acceptable waste disposal solution is found.
DECOMMISSIONING
One of the frequently overlooked and potentially expensive aspects of the nu-
clear power alternative has to do with what it may cost to decommission a
reactor. The ultimate cost will depend on numerous factors, including the size of
the reactor, the period of time over which it was used, how many kilowatt-hours
it produced over its lifetime, and the manner in which it is considered safest to
segregate the reactor vessel and the concrete shield from society. Since a
reactor may remain hazardous for one-and-a-half million years, great care will
go into this decision.
Perhaps the easiest thing to do with a reactor is simply to bury, or entomb, it.
But this may not be an acceptable solution in all cases. Surveillance of some kind
may be required for centuries. Another possible solution is to dismantle the
reactor, but radioactive dust may be dispersed in the process. To date, of the
eight experimental reactors which have been decommissioned (the largest,
4-14
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61 Mw), only one has been dismantled. This reactor, Elk River (22 Mw), cost
$6 million to build (completed in 1962) and $6.9 million to dismantle (dismantled
in 1970).*
CONSEQUENCES OF ONE MAJOR ACCIDENT
The consequences of a major nuclear accident either here or anywhere else in
the world can be expected to be felt dramatically throughout the industry.
Just as the property and human damages which might result from a major acci-
dent are, for all practical purposes incalculable, so, too, are the enconomic and
financial impacts on utilities that have nuclear power plants. A major act of
sabotage could have the same effect. The fact that the Emergency Core Cooling
System has yet to be demonstrated to operate in a fullscale test adds to this
uncertainty.
PROSPECTS FOR HAVING SUBSIDIES ELIMINATED
There is also an economic risk that one day the substantial subsidies now offered
to assist nuclear power will be lost, in part or as a whole. By far the greatest
subsidy is the protection offered under the Price-Anderson Act. The provisions
of the Act, which were recently extended until 1986 (at which time they would
need to be renewed), limit the tort liability of utilities to $125 million. The
federal government promises to cover any additional damages up to $435 million.
After that, nothing though presumably emergency aid in the form of low-cost
loans, etc., might be provided. Beyond $560 million, the utility is subsidized by
the populace at large including of course, any firm which would choose to
locate in the neighborhood of a nuclear power plant.
There are additional taxpayer subsidies offered to nuclear power: a heavy em-
phasis on nuclear in federal R&D budgets; accelerated depreciation both for
plant (16 years, versus 22.5 for coal) and fuel core (4 years); and fuel cycle
subsidies.
"The Cost of Turning It Off," M. Resnikoff et al., Environment, 18(10); 26,
December 1976.
4-15
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Without special treatment for nuclear power it is doubtful that, in the near-term,
it could remain competitive with coal. It cannot be assumed that this special
treatment will last. Coal producing states may one day clamor for making
nuclear meet the market test.
*A SUMMARY, EMPHASIZING REGIONAL CONSIDERATIONS
This discussion of the relative economic advantage, on a regional basis, of coal
and nuclear power, as effected by NSPS revisions for coal-fired boilers, had two
parts. First, we discussed the key factors affecting differences in busbar power
cost estimates for coal and nuclear, on a regional basis, as performed in the
three existing evaluations of this type. Second, a description was made of some
of the crucial difficult-to-quantify factors which may well convince decision-
makers to choose one technology over another irrespective of values produced as
a result of busbar power cost calculations.
It was determined from the review of three studies of regional busbar power
costs for coal and nuclear that differences in results were due principally to
variation in assumed capacity factors, though also to variation in assumed coal
prices and assumed relative and absolute differences in capital costs for nuclear
and coal. Based on a rough calculation of the incremental costs due to NSPS
revisions, it was determined that in a few regions notably the Mid-Atlantic and
South Atlantic regions the economic scales might tip slightly in favor of the
nuclear alternative should the coal alternative be subject to a more stringent
new source standard.
However, care should be taken not to read an inordinate amount into these
results. This is necessary both because the incremental costs were calculated as
approximations and particularly because the studies to which these costs were
applied were not well documented. In sum, the purpose of the first part of the
analysis was primarily to provide a quantitative frame of reference. In so doing,
4-16
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it became clear that nuclear and coal power are quite competitive in most
regions. Finally, it should be noted that site-specific data were not analyzed. In
reality, of course, true economic evaluations are made solely on the basis of such
data.
In the second part of the analysis, factors which are not readily amenable to
quantification were described as very important to the coal versus nuclear
decision-making process. Many decisions to build one type of unit over another
may be strongly influenced by such things as public support for or disfavor with
subsidies to the nuclear industry, by a need to diversify a firm's generating
capacity, by siting restrictions, by political/economic pressure to utilize indig-
enous coal resources, by a major nuclear accident, by the perceived competi-
tiveness of coal and uranium markets, by perceptions as to ultimate costs of
waste disposal, enrichment, and decommissioning and by several other factors.
As for the combined effect of all these factors, it is our judgment that the ten
regions will in general be affected by NSPS revisions for coal-fired boilers in
the ways and for the reasons described below.
New England
Mid-Atlantic
South-
Atlantic
East North
Central
East South
Central
Relatively insensitive to revised NSPS; nuclear
is perceived to have advantage; experience
with nuclear; diversification possible, but
other fuels competitive.
Relatively insensitive to revised NSPS in New
York and New Jersey; more so in Pennsylvania;
some diversification possible; residual fuel
available due to refinery capacity.
Relatively insensitive to revised NSPS; mixed
coal and nuclear.
Relatively insensitive to revised NSPS; some
utilities strongly nuclear may diversify; polit-
ical pressure to use indigenous resources;
siting restrictions may in some cases neces-
sitate nuclear.
Relatively insensitive to revised NSPS; mixed
nuclear and coal; some possible siting restric-
tions.
4-17
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West North Relatively insensitive to revised NSPS; politi-
Central cal pressure to use indigenous resources; some
diversification to nuclear.
West South Relatively insensitive to revised NSPS; siting
Central restrictions possible; some diversification;
residual fuels available due to refinery capa-
city.
North Relatively insensitive to revised N.. S; heavy
Mountain commitment to coal.
South Relatively insensitive to revised NSPS; heavy
Mountain commitment to coal; possible siting restric-
tions.
Pacific In Northwest, relatively insensitive to revised
NSPS; some nuclear, much hydro.
In California, both coal and nuclear stymied;.
"coal-by-wire" from mountain states; hydro
and residual fuel oil.
4-18
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APPENDIX A
CAPITAL FORMATION PROSPECTS
-------
APPENDIX A: CAPITAL FORMATION PROSPECTS
A. THE ROLE OF CAPITAL MARKETS
INTRODUCTION
No industry is more capital-intensive than the electric utility industry. To
illustrate, the ratios of net investment to annual revenues in the steel, chemical,
and automobile manufacturing industries are such that it takes about twelve, ten,
and seven months, respectively, to generate sales revenues equal to net
(depreciated) assets. By comparison, it takes about four years' worth of
electricity sales revenues to match the industry's net tangible investment. The
electric utility industry's current level of capital-intensiveness suggests that,
under the best of circumstances, in order to fund new projects, it will require a
good deal more capital funds than it it likely to raise from internal sources
(depreciation allowances, retained earnings, and tax deferrals). This causes the
industry to seek funds in the capital markets.
The industry's requirement for external funds from 1978 to 1995 could be very
large on the order of $200-300 billion (1977 dollars), depending on the amount
of total capital need, earnings, dividend policies, and many other factors. It
cannot be assumed that the industry will be able to acquire funds sufficient to do
all it would like or may be asked to do. Numerous factors, many of which are
discussed in this section, will affect the outcome.
The purpose of this Section is to describe the capital market environment in
which the electric utility industry will find it necessary to fund a portion of one
of its major spending programs that of NSPS-related investmentthrough
1990. To describe this environment first a brief sketch is presented of the
capital markets in which funds for ail purposes are acquired. The important
aspects affecting electric utilities' participation in raising external capital over
the last 10 to 15 years are described next.
A-1
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In the second Section, the discussion becomes prospective in nature. Factors are
discussed which will affect the industry's need and ability to raise capital. Since
macroeconomic factors will affect the availability and cost of external capital,
some of these key economic variables are described first. The notion of "capital
shortage" will be discussed briefly.
The investment and financing policies of firms seeking external capital will be
important determinants of relative access to the capital markets; hence, an
overview will be presented of some of the important firm-level policy decisions.
First, consideration will be given to the uncertainty which pervades the industry's
capital budgeting environment.
The policies of both state regulatory authorities and utility management may
have a strong influence on the industry's capital-raising prospects; hence, some
of the key policy options available to regulators and management will be dis-
cussed briefly.
Further, since utility investment for air pollution abatement purposes will be
made in the context of the industry's possible investment requirements for other
purposes, as well as the requirements of all other public and private entities and
parties, a discussion will be presented of the types of projects which may
compete for investment funds.
Finally, since the electric utility industry would appear to hope that a major
proportion of pollution abatement spending could be funded through issuance of
tax-exempt debt, particular attention is given to the feasibility of this approach
to investment funding and to the impact that widespread use by investor-owned
utilities of pollution control revenue bonds could have on the market for tax-
exempt securities.
A-2
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CAPITAL MARKETS <
Capital markets are the network of institutions and mechanisms through which
intermediate-term funds (loans of up to ten years maturity) and long-term funds
(longer-term loans and corporate stocks) are pooled and made available to
businesses, governments and individuals. Capital markets include both primary
markets, in which an issuer's securities are first sold to the public, and secondary
markets in which outstanding securities are transferred. Examples of capital
markets include the markets for government, corporate, and municipal bonds,
corporate stocks, and mortgages.
A distinction is made between capital markets and money markets. The latter
are regarded as including financial assets that are short-term (obligations of a
year or less to maturity) and possess low risk and a high degree of liquidity.
Examples of money markets include the markets for short-term government
securities, bankers' acceptances, and commercial paper.
Although focus of this section is on the capital markets, the capital and money
markets should be considered interdependent. Suppliers and users of funds may
use both markets depending on investment policies and on the relative rates
available in the different markets. Funds flow back and forth between markets
as, for example, when a bank lends the proceeds of a maturing mortgage to a
business firm for a short period of time.
Some institutions serve both markets. Commercial banks, for example, make
both intermediate and short-term loans. Moreover, yields, in the long- and short-
term markets are interrelated. A rise in short-term interest rates reflecting a
condition of credit stringency is likely to be accompanied or followed by a rise in
long-term rates.
To complete this introductory overview of capital markets, it is useful to dis-
tinguish the markets according to the instruments involved; that is, the instru-
ments that represent funds supplied to and obtained from the capital markets are
A-3
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either debt instruments, such as corporate bonds, or equity instruments, such as
corporate stocks. This distinction will prove convenient when we consider the
electric utilities' participation in the capital markets.
Long-term Corporate Debt Financing
Historically, corporate bonds have been issued for a variety of reasons. The most
important of these is to reduce the cost of financing and to increase the rate of
return on equity capital by applying the principle of leverage. The after-tax cost
of long-term debt can be lower than that of equity capital because of its
preferred risk position and the tax deductibility of interest payments. Bond
financing also avoids possible dilution of control.
On the other hand, debt financing has definite disadvantages. The contractual
payments and restrictions on working capital and retained earnings contained in
the indenture agreements inhibit corporate flexibility and diminish the appeal of
debt financing. Also, because fixed changes are involved, the debt financing can
have an adverse impact on earnings during an economic downturn.
Corporate debt, either secured or unsecured, can be offered either publicly or
privately. Public issues are distributed through investment banking houses, which
form syndicates of investment banks and underwrite the bond issues for resale to
institutions and individual investors. The investment banker provides the issuers
with advice on the terms, timing, and prices of bond financing and with
continuing counsel after the issue is floated. Correspondingly, the members of
the underwriting syndicate serve as broker-dealers and provide investors with
information on the financial condition of the issuers, the form and terms of the
financing, and general investment advice.
Investment banking syndicates acquire new corporate bond issues by either
negotiated or competitive bidding. Direct negotiation between issuer and under-
writer (acting alone or as a manager of a syndicate) ends in a purchase contract
whereby the banker acquires the issue at a net price and yield determined by
A-4
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bargaining. Such underwriting is largely confined to offerings of industrial firms
and financial institutions. Competitive bidding, in which the issuer invites sealed
bids, is ordinarily required by federal or state statute in the case of public utility
and railroad issues. The cost of flotation of fully underwritten public issues
consists of the bannker's gross spread or commission and the expenses involved in
preparation and negotiation, as required by the Securities Act of 1933. The
banker's commission varies with size and quality of the issues and the methods of
distribution, and ranges from 0.5 to 0.8 percent.
The price that a borrower pays for the use of borrowed funds is the interest rate.
When the borrower issues a particular debt instrument, he agrees to meet a
schedule of interest payments over the life of the instrument at a stated rate of
interest (sometimes called the "coupon" rate). Normally, the stated rate is based
upon current market interest rates for similar debt issues and is chosen so that
the market value of the issue will be very close, if not identical, to the face
value of the instrument. For example, if a firm is planning to sell some new
thirty year bonds and similar ones are currently selling to yield 8fe, then we
would expect that a stated interest rate of 8fe would result in the market paying
approximately $1000 for each $1000 face value bond.
Over time, market interest rates fluctuate substantially. Since the stated
interest rates on outstanding debt instruments do not change, fluctuations in the
market rates cause the prices at which the instruments trade in the secondary
markets to adjust accordingly. If the market rate for a given bond is higher than
the stated rate, the bond will sell at a discount; if it is lower, the bond will sell
at a premium. The rate of return that an investor will earn if he purchases the
bond at the market price and holds it to maturity is called the yield.
There is no single market interest rate. Instead, there is a range of rates,
observable at any time, that encompasses such factors as the supply of funds
available, the expected rate of inflation and the risk of default by the borrower.
Issues of the U.S. government are normally considered free of default risk and
thus their yields are used as a proxy for the market's riskless rate of interest.
A-5
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This rate captures the market's time value of money, i.e., the rate at which the
market is willing to forego consumption today for future consumption, and the
anticipated rate of inflation, which adjusts for the loss of purchasing power of
the dollars received in the future over the dollars invested now.
For issuers other than the U.S. government there is the possibility of default.
Hence, the market interest rate for these issuers is equal to the riskless rate for
an instrument of the same maturity (since the effect of inflation varies with
maturity) plus a risk premium, which increases as the possibility of default
increases. The way that the market determines the possibility of default and
hence the size of a risk premium is not fully understood. However, one
important ingredient of the market's decision process is the ratings assigned the
bond by the two ratings agencies, Standard and Poor's and Moody's Investor
Service. These agencies evaluate the quality of bonds and state their opinion in
letter grade form. A brief discussion of the factors considered impoortant by
these bond raters is presentedlater in this section.
While the magnitudes of the interest rate differentials between the various
rating categories fluctuate over time, they are typically small relative to the
fluctuations of the entire interest rate structure. And it is this latter pattern of
movements which is considered to be one of the most significant aspects of
interest rates their role as an index of the availability of funds. In theory, a
firm, no matter how risky, should always be able to borrows funds at some price.
But in practice there are many legal and institutional constraints and conventions
that place limits on how high interest rates may go. As a result, a period of high
interest rates usually reflects tight money, even though the high rates may be
primarily attributable to high levels of anticipated inflation. For small firms and
for high risk large firms, periods of rising interest rates may indicate increasing
difficulty in obtaining new debt financing.
A-6
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Corporate Stock Financing
Corporate stocks in the form of transferrable certificates represent the equity
interest in the company. There are two types of corporate stocks, preferred and
common. Stocks having a preferred status rank ahead of common stock as the
claim on assets and in the receipt of dividends. The common stock represents
the residual equity in the corporation and participates in net assets in liquidation
and in dividends after all claims of creditors and of any preferred stockholders
have been met.
New corporate stocks are sold to investors both directly by the issuer and in-
directly through investment bankers and dealers. The chief means of direct sale
of common stocks is through the issuance of rights to existing stockholders
entitling them to buy new shares (including covertible bonds and preferreds) in
proportion to existing holdings. Sale of securities to employees in connection
with savings, stock purchase, and stock options incentives is also considered
direct. Some stock issues are directly placed with institutional buyers; these are
chiefly higher grade preferred stocks of public utility companies.
The majority of new common stock issues of public utilities is underwritten by
syndicates of investment banks, who negotiate the transaction directly with the
issuer and purchase the entire offering at a price net of discounts and com-
missions. They then sell the new shares to the public at the offering price which
usually is very close to the most recent price at which the issuers shares were
traded in its secondary market (such as the New York Stock Exchange). Thus,
the value which an issuer receives when selling new shares of stock is dictated by
the current market price of its outstanding shares. The balance sheet or book
value of the firm's shares plays no role in determining the price at which new
shares are to be offered (unless it is the first public offering of the firm).
A-7
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Composition of Sources off Funds
It is instructive to note that as business spending has been rising over the period
1960-1974, two significant changes in the composition of funds sources has
occurred. First, internal sources of funds have declined relative to total need for
funds. Second, the use of common and preferred stocks has declined relative to
the use of debt instruments. These trends can be observed in Table I.
These trends signify that U.S. firms chose to grow in the Sixties and early
Seventies by applying debt leverage. Of course, while the use of debt leverage
has its benefits, it too has its costs. It tends to destabilize earnings since firms
with fixed debt funding become more sensitive to cyclical swings in the economy.
As equity investors perceive this change, they tend to require higher prospective
returns to compensate them for added risk-taking. As firms become more
leveraged, incremental debt generally carries higher interest rates. As the cost
of financing grows, so grow the costs of production. With some lag, selling prices
rise, too. Inflation may result, and this would further boost returns sought by
investors.
Apparently, what has happened of late is that firms have continued to invest
without earning their costs of capital. Investors again bid up the required return;
consequently, share prices fell. Since some individual investors left the market
entirely, seeking greater opportunities in real estate and other investments, the
P
new equities market narrowed. Consequently, the significance of institutional
trading increased.
Institutional Sources of Long-term Capital
It has been estimated that individuals hold about 70 percent of outstanding equity
securities, 20 percent of corporate bonds outstanding, 30 percent of municipal
debt, and about 25 percent of outstanding federal debt (these figures include
holdings of individuals as beneficiaries of trusts managed by trust departments of
banks). Despite their large holding of equities (mostly common stocks) indi-
A-8
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Table I
Sources of Funds
Domestic Non-Financial Business Corporations
1960-1975
(billions of dollars)
Total Financing Need
Funds Internally Generated
(as percentage of Total)
Adjusted Retained Profits
(as percentage of Internal)
Capital Consumption
Allowances (Depreciation)
(as percentage of Internal)
External Funds Raised
(as percentage of Total)
Bank Loans and Other
Short-Term Debt
(as percentage of External)
Long-Term Funds
(as percentage of External)
Equity
(as percentage of Long Term)
Long-Term Debt
(as percentage of Long Term)
Mortgage Bonds
(As percentage of Long Term Debt)
Debentures
(as percentage of Long Term Debt)
I960
$44.1
34.4
78
10.1
29
24.2
71
9.7
22
2.1
22
7.5
78
1.5
20
6.0
80
2.5
42
3.5
58
1961
$49.2
35.6
72
10.1
28
25.4
72
13.7
28
2.8
20
10.8
80
2.2
20
8.6
80
4.0
47
4.6
53
Source: Flow of Funds Statistics, Board of Governors of
1962 1963
$55.2 $57.6
41.8 43.9
76 76
12.7 13.1
30 30
29.2 30.8
70 70
13.4 13.7
24 24
3.9 5.5
29 40
9.5 8.2
71 60
0.4 (0.6)
4 (7)
9.1 8.8
96 107
4.5 4.9
49 56
4.6 3.9
51 44
1964 1965
$67.2 $79.2
50.5 56.6
75 71
17.7 21.2
35 37
32.8 35.2
65 63
15.0 22.6
25 29
6.1 13.4
41 59
8.9 9.2
59 41
1.3 (O.I)
15 (1)
7.6 9.3
85 101
3.6 3.9
47 42
4.0 5.4
53 58
1966
$86.7
61.2
71
23.0
38
38.2
62
25.6
29
10. 1
39
15.5
61
I.I
7
14.4
93
4.2
29
10.2
71
1967
$86.5
61.5
71
20.0
33
41.5
67
24.9
29
3.5
14
21.4
86
2.2
10
19.2
90
4.5
23
14.7
77
1968
$96.1
61.7
64
16.6
27
45.1
73
34.4
36
16.1
47
18.4
53
(0.2)
(1)
18.6
101
5.7
31
12.9
69
1969
$96.3
60.7
63
10.9
18
49.8
82
35.6
37
15.5
44
20.0
56
3.4
17
16.6
83
4.6
28
12.0
72
1970
$95.3
59.4
62
5.8
10
53.6
90
35.8
38
5.2
15
30.4
85
5.7
19
24.7
81
5.2
21
19.5
79
1971
$ 1 16.8
68.0
58
10.3
15
57.7
85
48.8
42
7.0
14
41.5
86
11.4
27
30.1
73
11.3
38
18.8
62
1972
$ 133.9
78.7
59
15.7
20
63.0
80
55.2
41
15.9
29
39.2
71
10.9
28
28.3
72
15.6
55
12.2
45
1973
$ 154.1
84.6
55
17.1
20
67.5
80
69.5
45
34.9
50
34.5
50
7.4
21
27.1
79
16.1
59
9.2
41
1974
$ 163.1
81.5
53
9.0
II
72.5
89
81.5
47
45.3
56
36.3
44
4.1
II
32.2
89
10.9
34
2|,3
66
1975
$ 137.3
90.3
66
11.3
13
79.0
87
47.0
34
(12.8)
(27)
59.8
127
10.0
17
49.8
83
23.6
47
26.2
53
the Federal Reserve System
Note: Parentheses indicate net negative flows.
-------
viduals directly engage in trading only about 30 percent of equities, commercial
banks trade about 40 percent (including trading for noninsured pension fund and
for trust fund accounts), and other institutional investors principally mutual
funds, life insurance, and property and casualty insurance companies - trade the
remainder.
Since institutional investors engage in about 70 percent of equity trading -versus
about 30 percent in I960 the character of their trading habits has become of
concern. It has been alleged that the institutions show active interest in no more
than about 200 to 300 stocks and that they, in fact, limit trading mostly to the
so-called Favorite Fifty. Not many electric utilities are among these stocks .
(Institutional investors, as evidenced by their current holdings, show great
interest in Texas Utilities, three Florida utilities, and PSC of Indiana; some
interest in some firms located in Illinois, California, Ohio, Wisconsin, and
Montana; virtually no interest in forms located in New York, Pennsylvania, and
Massachusetts; and particularly low regard for the common equity of firms such
as Con Ed, Boston Ed, Detroit Ed, Iowa PS, and Portland G&E).
The lack of institutional interest in most electric utilities and indeed in about
90 percent of all stocks publicly traded tends to make these stocks illiquid, and
{(liquidity tends to negatively affect share prices. Further, since the value of
shares traded in the secondary market has great influence on the price of new
issues, a lack of institutional activity in a particular stock can add a cost and
serve as a constraint to the issuance of new utility equity.
Stocks that institutions do actively trade may also be made more risky by their
trading (hence, the required return is bid up; if by no other means, by bidding the
share price down). This may well be true due to the so-called "air-pocket effect"
if one firm sells a large block of shares, other institutions may follow suit.
This tends to create significant swings in stock prices. Individual investors who
are not privy to the same information that institutional investors are and those
individuals who do not watch closely their investments may be adversely affected
by institutional transactions.
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In summary, there may be significant benefits to institutional activity in the
stock market, but without restrictions on institutional trading, new electric
utility stock issues may not enjoy a marketplace characterized by breadth, depth,
and resiliency. Ultimately, this affects the financial options available to
investor-owned electric utilities.
The market for debt securities is largely institutional in nature. Therefore, the
policies of and restrictions placed upon financial institutions are important in
determining where funds go and at what interest rates. There are essentially
four markets for debt securities: the mortgage market, the federal market, the
municipal market, and the corporate bond market. The interest here centers on
the municipal and corporate bond markets, but it should be noted that the
mortgage and federal government securities market can, at times, offer very
serious competition for funds. Under normal circumstances, most institutional
investors hold some proportion of their portfolios in debt securities of all types.
The Municipal Market
The major participants in the municipal market are as follows: commercial
banks, with about 45 percent of outstanding securities; individual investors,
including those entrusting their accounts to banks, with about 30 percent; and
property and casualty insurance companies, with about 20 percent. The
remaining 5 percent is shared by life insurance companies, state and local
retirement funds, mutual savings banks, and business corporations. Lately the
largest growth in municipal participation has been evidenced by the household
(individual) sector.
The municipal bond's distinguishing feature is its tax-exempt status. The market
for municipals is thus principally composed of those seeking this status for their
own tax purposes; that is, investors with high marginal tax rates. The market's
major attraction is also a cause for concern for those seeking funds, because
when the earnings of its three large participants dip, they lose interest in the
market. In fact, though they hold about 95 percent of outstanding municipals,
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municipals represent only about 6 percent of the total combined financial assets
of commercial banks, property and casualty insurance companies and individuals.
Hence, a one percent shift in their combined assets away from municipals could
have major repercussions in the municipal market. Later in this section, the
municipal market will be reconsidered in light of the expanding use of pollution
control revenue bonds, which now account for about 10 percent of all newly
issued tax-exempts.
The Corporate Bond Market
The major participants in the corporate bond market are life insurance com-
panies and private and government pension funds. Other participants include
mutual savings banks, property and casualty insurance companies, mutual funds,
commercial banks, and foreign investors.
Since most 'corporate bonds are purchased by institutional investors, their
secondary market is rather thin. The institutions that buy these bonds are
generally satisfied to hold them to maturity. However, in the event of a liquidity
problem faced by a particular holder of corporate bonds, these bonds can
generally be sold rather quickly - as evidenced by the narrow bid-and-ask
spreads these bonds now enjoy. (Bid-and-ask spreads are stated as a percentage
of a bond's face value, and refer to the difference between what a potential
buyer is willing to pay and what a potential seller is willing to sell a bond for.)
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ELECTRIC UTILITY PARTICIPATION IN THE CAPITAL MARKETS
Trends and events occuring over the last decade have significantly affected the
setting in which the industry operates, the industry's financial condition, and the
manner and extent to which the industry participates in the capital markets. Of
course, the extraordinary events of 1974-1975 had a particularly adverse effect
on the industry. But trends beginning earlier, that is, in the late Sixties, had the
effect of making the industry very vulnerable to the Oil Embargo, high inflation,
pronounced regulatory lag, and other occurrences which shook the industry and
its investors in 1974-75.
Key Factors Affecting Financial Position
Demand
Over the past ten years, the industry's annual growth rate in peak demand has
exceeded the annual growth rate in average system demand on six occasions,
sometimes by as much as 2 or 3 percentage points. Over the last decade, in only
one year, 1967, did the growth in peak demand fall significantly below the
average demand growth rate. The variability in the peak growth rate was
substantial over the 1966-1975 period. The peak growth rate, more than any
other factor at present, signals the likely need for expansion of plant capacity.
With such great year-to-year variability in the peak, the accuracy of predicting
future capacity needs tends to be low. Still, the rate of peak growth, whether
considered over the 1966-1973 period (8 percent) or over the'1966-1975 period
(6.7 percent), seemed to indicate the need for large capital expenditures to
accommodate anticipated future demand.
The financial implications of the foregoing discussion are: (I) great uncertainty
had crept into the industry's capital budgeting process; (2) peak demand growth
(at least for the years 1966-1973) suggested that a substantially increased
amount of capital would be required to construct additional capacity
irrespective of added-expenditures implied by environmental guidelines; and (3)
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since peak demand was rising a good deal faster than yearly average demand,
operating efficiency would suffer.
Load Factor
Capacity utilization, as measured by load factor, did suffer. Over the last
fifteen years, load factor has fallen from about 65 percent to its current level of
61 percent.
When peak demand rises faster than average system demand, the load factor
deteriorates, and a greater portion of the industry's plant is idle or underutilized.
Since three-quarters or more of the industry's costs are either actual fixed costs
or essentially fixed, declining load factor signifies other things being equal
an increase in cost per unit sales.
Increasing Costs of Production
Fixed overhead did not remain stable during this period. Indeed, it rose drama-
tically. Historically, the electric utility industry had been faced with the fact
that the incremental cost of electrical production that is, the cost of pro-
ducing an additional kilowatt-hour was less than the average cost of each
kilowatt-hour then being produced. This meant that the more the industry built,
the cheaper would be the rates everyone paid. In the late 1960s, however, the
factors that made the industry increasingly cost efficient ended.
One reason for the demise of the economies associated with the building of
larger conventional plants was that the industry was unable to continue lowering
its heat rate, the number of BTUs from fuel required to generate each kilowatt-
hour of electricity. At the same time, the major components of construction
costs equipment, materials, labor, and money were increasing rapidly. The
increase in the cost of constructing new facilities is a major factor contributing
to the change in the industry's financial setting.
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Cost of Copital Funds
Over the last decade, the cost of capital funds has risen steeply. This rise may
be attributed chiefly to a greater use of debt financing and to the high rate of
inflation and to inflationary expectations over the decade. As shown in Table 2,
the yields on high-quality utility debt and equities essentially doubled over the
period 1966-1976.
Costs of Environmental Controls
During the past decade, environmental protection has become an important
aspect of electric utility planning and operations. Three major federal environ-
mental laws were enacted, and had significant impact on the industry. First, the
National Environmental Policy Act, enacted in 1969, affected utility plant siting
and land uses. Second, the Federal Water PoHution Control Act, and subsequent
amendments, affected the industry's practices with respect to the discharge of
effluents and waste water in both existing and planned facilities. Third, the
Clean Air Act of 1970, and the subsequent amendments to it, affected the
industry's practices with respect to the discharge of air pollutants, in particular
sulfur dioxide, nitrogen oxide, and total suspended particulates. In addition to
federal regulations, state and local agencies proposed environmental regulations.
The net effect of all these new laws and relationships was to increase both
capital and operating costs.
Fuel Costs
Fuel costs began to be a problem to the industry in the late 1960s. The closing of
the Suez Canal in 1967 affected oil tanker rates. Coal prices began to rise, due
in part to coal industry investments in health and safety improvements and in
part to the fact that the electric industry, in general, was neither vertically
integrated back to the mine nor made extensive use of the long-term contract.
Natural gas prices, too, began to rise as the Federal Power Commission began to
lift the ceiling on these prices.
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Table 2
Average Yields on Top-Grade Utility Bonds and
High Quality Utility Stocks, 1966-1976
BONDS PREFERRED STOCK Divi- COMMON STO^CK
End of Month Overall Avg. High Quality dend High Quality
of March Yield Yield Yield Earnings/Price Ratio
1976
1975
1974
1973
1972
1971
1970
1969
1968
1967
1966
9.36%
9.74
8.53
7.67
7.81
8.03
8.37
7.37
6.39
5.37
5.23
8.96%
9.31
8.06
7.39
6.99
6.91
7.26
6.39
6.04
5.15
4.69
9.00%
10.34
8.35
6.42
5.96
5.55
5.62
4.75
4.85
3.89
3.79
13.51%
15.63
11.63
9.34
8.55
7.51
7.71
6.54
7.01
5.83
5.44
Source: Moody's Investors Service
The overall average refers to the average of 40 utility bonds, 10 in each of
Moody's four top-grade ratings, Aaa, Aa, A, Baa.
This is the highest quality preferred rated by Moody's.
{+
This is the highest quality common rated by Moody's.
Note; In the past few years, the ratings given the issues of electric utilities
generally been lower than those given other utilities, so the percentages
above may understate that cost of money to the electric utilities.
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Of course, the largest fuel price increases occurred during the oil embargo, a
time at which the industry was more heavily dependent on petroleum than ever
before. This dependence resulted from the fact that many utilities had just
completed the conversion to oil-burning of coal-fired plants in an effort to meet
sulfur dioxide emission standards. In 1974, when the price of oil increased
137 percent and the price of coal increased 58 percent, the industry was
dependent on petroleum for 16.9 percent of its fuel for electrical generation and
on coal for 45.5 percent.
Regulatory Setting
As the industry's costs rose, it found it necessary to spend an increasingly large
amount of time preparing materials for and testifying before regulatory com-
missions in an attempt to recover costs through rate increases. As the first wave
of rate-increase applications appeared, regulatory commissions, had difficulty
processing the large number of applications. More applications were forth-
coming, however, and as the effects of the first round of rate increases were
beginning to be felt and, in many cases, resisted by consumers the com-
missions were compelled to take ever greater pains to scrutinize the arguments
for rate increases. This scrutiny required a great deal of time.
The major impact of regulatory lag on the industry's financial situation involved
the fact that by the time the final order was issued to allow the applicant to
boost his rates, inflation had so eaten into the sum originally requested this
this sum being calculated based on costs prevailing at the time of application
that the rate increases finally granted were insufficient to cover inflated costs.
This impact was sometimes mitigated by a commission's granting of an interim
rate increase while deliberations proceeded on the application itself. However,
for over three-quarters of the cases decided during the period 1971-1973, no
interim increases were granted.
Another way to soften the financial blow delivered by a combination of regu-
latory lag and inflation is to permit so-called "forward looking test years" to be
used to calculate the amount of costs needed to be recovered through rate
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increases. This method of calculation permits applicants to predict cost trends.
Perhaps fearing that applicants might erroneously inflate costs, throughout the
late 1960s and early 1970s, the regulatory authorities typically did not permit
such a practice.
In the early 1970s, one of the few concessions the industry was generally able to
win from regulatory commissions was the authority to pass certain "uncon-
trollable costs on to the consumer without having to go through formal rate
proceedings. By mid-1974, 43 states and the District of Columbia permitted fuel
cost adjustment/pass-through clauses. On the nationwide basis, 75 percent of
investor-owned utilities were permitted some form of fuel adjustment clause,
though in some cases, the adjustments were restricted to industrial and com-
mercial customers. A few regulatory commissions permitted utilities to pass
through taxes and the cost of power purchased from other utilities, but as a
general rule, such adjustments were not permitted.
Pass-through clauses undoubtedly helped utilities to recover costs more quickly.
Still, when fuel costs were soaring, for example, during the winter of 1973-1974,
even the normal lag between billing and collection added to the strain on a
utility's working capital.
While the pass-through clauses gave the industry's financial condition a moderate
boost, the need for rate increases to recover costs generally unrelated to fuel
outlays was growing rapidly. The dollar amounts of rate increases granted
annually over the period 1970-1975 grew from about $500 million in 1970 to more
than $3 billion in 1975. However, far more significant to the financial condition
of the industry was the fact that dollar amounts requested for rate increase
approval grew from about $700 million at the end of 1970 to more than $4 billion
at the end of 1975.
Since a sizable number of requests for rate relief were not acted upon imme-
diately, it became evident that the costs the industry had incurred would have to
be carried, at least for a time, by some other means. Fixed charges, such as
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interest payable on debt, could not be reduced, lest foreclosure proceedings be
commenced. The major source of funds would have to be cash flow from
operations.
Clearly what had happened was that the regulatory delays that had worked to the
industry's and its investors' advantage in the ealy 1960s were now working to
their great disadvantage. Whereas, in the early 1960s the industry's members
were generally able to earn more than the rate of return allowed by regulatory
commissions, in the early 1970s, they were generally earning less.
It is misleading to attribute all of the decline in the earnings rate of the electric
utility industry to regulatory lag. Regulatory lag does not explain why the
amounts requested and the amounts still pending at the end of the year were
progressively so much higher year to year. Allusion has been made to some of
the factors that contributed to this situation load-factor deterioration, higher
construction costs, environmental costs, and higher fuel costs. Other
contributing factors, including a higher level of construction activity, greater
external financing, a higher level of debt financing, and the use of certain
accounting practices will be discussed in ensuing paragraphs. The combination of
these factors has had extremely adverse impacts on earnings.
External Financing
As the industry found it could not prevent a lower rate of return (on shares and
rate base ), a number of factors came into play. The first impact of a declining
rate of return in the face of a greater need for funds was that the industry was
forced to become more dependent on capital markets, i.e., on external financing.
A review of Table I shows this quite clearly - as earnings contributed as
decreasing share to capital expenditures, external financing assumed an
increasing share. As external financing of the electric utility industry increased,
it came to represent an ever-growing proportion of all long term capital funds
available for U.S. industry. Table 3 shows that electric utility industry financing
of late has taken an extremely prominent position in the new issues market.
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Table 3
Electric Utility Industry Incremental Long-Term Financing as Percent of Total
For all U.S. Industries, 1965-1976 ~~~~
Year Long-Term Debt Preferred Stock Common Stock
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
10%
15%
12%
18%
20%
20%
17%
15%
23%
27%
18%
16%
29%
44%
51%
72%
56%
83%
50%
75%
55%
77%
46%
57%
7%
8%
9%
8%
10%
19%
22%
24%
33%
51%
51%
46%
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The declining rate of return also meant utility stocks were less attractive. While
a portion of that which is returned to stockholders, the dividends, remained
attractive, and in many cases become more attractive as dividend payouts were
moderately increased, the other portion of the return, the capital appreciation,
was falling rapidly. In the face of the overall decline in return to stockholders,
investors were requiring a higher rate of return. The reasons for this fact were
that general inflation made higher nominal (i.e., not inflation-adjusted) returns a
necessity, and higher bond yields were pushing the required yield on common
equity, the riskier the instrument, still higher. Since the industry was unable to
fulfill the expectations of common shareholders, the price/earnings ratio, a
measure used in the valuation of common stocks, had to fall. Table 4 shows the
decline in the price/earnings ratio, the multiplier the market applies to current
earnings in order to arrive at a market value, over the period 1965-1976.
The third impact of the reduced rate of return was that the industry's ability to
carry heavy interest burdens was being reduced. Over the period 1965-1974, the
industry's annual amounts of debt issued increased more than sixfold. Over the
same period, bond yields doubled. The combination of these factors caused
interest charges to grow from less than $1 billion in 1965 to $4.6 billion in 1974.
Over the same period, the amount of income available to service this debt grew
by only 83 percent. As a result of these trends, the annual interest coverage
ratio, the ratio of net income (before payment of taxes and interest) to interest
fell precipitously.
Interest coverage ratios are heavily relied upon by financial rating agencies in
evaluating the quality of a utility's bonds. As these coverage ratios have
declined in the last five years in particular, the ratings of the bonds of many
utilities have been downgraded by the rating agencies. When a utility's bonds are
downgraded, these bonds trade at a discount, i.e. the cost of new debt to the
utility rises. Another, and perhaps more important, effect of declining and
relatively low coverage ratios emerges from the fact that the indentures of
existing issues of utility bonds have provisions which will not permit a utility to
issue additional bonds when the coverage ratio falls below a certain level,
generally 1.75 to 2.0 times.
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Table 4
Price/Earnings Ratios of the Electric Utility Industry.
1965-1976
Year P/E Ratio Year P/E Ratio Year P/E Ratio
1965
1966
1967
1968
19.8
16.3
15.3
14.8
1969
1970
1971
1972
13.7
11.5
11.8
10.4
1973
1974
1975
1976
9.4
6.3
6.4
7.4
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With both the common stock and debt securities routes to financing fraught with
problems, the industry came to rely on preferred stock far more than it had when
the industry's finances were on better ground. Preferred stock was once
regarded as the most expensive form of financing in terms of cash payout
because dividends are not tax deductible to the issuing firm. However, new
issues of preferred stock offer tax advantages to investing corporations (85
percent deductibility for dividends received) and this fact allows the issues to be
sold at yields within a percentage point of those of common stocks.
Since preferred yields are relatively high and the amount of preferred stock
issued between 1965 and 1974 rose by a factor of 10, and further, the income
available for preferred dividends increased a mere 26 percent over these years,
the industry's preferred dividend coverage ratio fell rapidly.
Preferred stocks are also rated by the rating agencies. Declining and low
coverage ratios for these stocks lead to lower ratings, and low ratings mean
higher yields will be required in the future. Moreover, as preferred stocks may
also have indenture agreements which prohibit new issues when coverage ratios
fall below a certain level (generally a level somewhat higher than that applicable
to debt) the ability of utilities to issue more preferred stock without first raising
the rate of earnings has been limited. ,
Internal Sources of Funds
Given the increased expense and difficulty involved in raising funds externally, it
remains to be reviewed why the industry was generating a declining proportion of
its investment funds internally.
The key factor in this decline involves the fact that the amount of funds a given
utility can generate is relatively fixed in proportion to, its existing plant. Both
the rate of return allowed and the depreciation funds allowed are generally fixed
in proportion to the investments in plant that the utility has made. It has been
estimated that the amount of funds the ordinary utility can generate internally is
approximately 4 to 5 percent of its net plant. By contrast, the industry's capital
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expenditures relative to initial assets rose from 7.5 percent to 13.5 percent over
the period 1965-1973. Thus, even if the industry had earned all that it was
allowed to earn under regulatory limitations, the proportion of its investment
funds generated internally would still have declined substantially.
Another reason for the decline in importance of internally generated funds
involved the use of the flow-through accounting by regulatory commissions
having jurisdiction over 40 percent of the industry's assets. This method of
accounting caused firms to report higher earnings, due to the use of accelerated
depreciation for determining their tax payments, than they would have reported
had they been allowed to use an alternative accounting method, normalization,
wherein tax differences are normalized by showing a deferred tax credit. When
earnings appear high, it is, of course, more difficult for utilities to convince
regulators that higher rates of return are necessary. The effect of the flow-
through accounting practice was to maintain, if not increase, the utilities'
dependence on external financing.
Though earnings for the industry grew at an average annual rate of about 11
percent over the last decade, the quality of these earnings deteriorated badly
over the period. One measure of the quality of earnings is obtained by relating
reported net income to cash income. That which does not contribute to cash
income is created by accounting entries and, thus, is in a very real sense "paper
profit", i.e., a reporting of future cash income in the current year. In 1965,; 9
percent of the industry's earnings were noncash credits. By 1974, noncash credits
to income were fully one-half of net income. When so little of that which the
industry reports as earnings is actual cash which can be distributed (for example,
as dividends), rating agencies and investors tend to view the industry as a higher
risk enterprise.
The major factor contributing to the deterioration in the quality of the
industry's earnings is an accounting practice used by the great majority of
commissions which regulate the industry. The practice entails prohibiting
utilities from including the carrying charges of construction work in progress
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(CWIP) in the base amount- upon which rates are calculated. Instead of
permitting utilities to pass on the carrying cost of CWIP to current rate-payers,
regulators required utilities to credit an allowance for the use of funds during
construction (AFDC) to income for each year in which the facility is still being
built. The offsetting debit entry is to CWIP. The AFDC account includes bo'.h
interest paid on construction debt and an allowance for the return on the equity
portion of funds invested in the plant under construction. Only when the facility
comes on-line, i.e., starts producing electricity, are rates permitted to be raised
to cover the amortization of accumulated interest and equity return, as well as
the actual plant costs.
It has been estimated that AFDC charges amount to 20 to 25 percent of the costs
of plant. Since plant costs have risen a great deal in the last decade, these
charges, which are in effect a reporting of future earnings in the current year,
have become a major item in that which is reported as income. Over the period
1966-1974, the AFDC proportion of earnings rose from 5 percent to 31 percent.
By 1974, AFDC had risen to such an extent that aggregate reported earnings less
AFDC and dividends was negative.
Since cash earnings had become negative, the only positive sources of internal
funds in 1974 were deferred income taxes, 19 percent, and amortization and
depreciation, 81 percent. The former source of funds has grown far more signi-
ficant of late. It may be considered, either as a noninterest bearing federal loan,
one that, in effect, never has to be paid back so long as utilities' investment in
depreciable assets does not decline, or as a contribution to capital by the federal
taxpayers.
Another problem related to earnings reported over the last decade stems from
the percentage of plant which is allowed to be depreciated annually for rate-
making purposes. For tax purposes, the industry's assets are given relatively
short depreciable lives - for example, four years for the nuclear fuel core, 16
years for nuclear plants, 22.5 years for nonnuclear plants which allows for
accelerated depreciation. However, for rate-making purposes, the asset lives of
the industry's plant are more in line with their useful lives, 30 to 40 years.
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The problem with these relatively long depreciable lives for rate-making
purposes is that no more than about three percent of plant can be expensed
annually to meet the cost of plant replacement. When the cost of new plant is
far greater than it was for existing plant, such a low percentage added to the
accumulated depreciation account each year proves inadequate to cover the cost
of new plant. Again, if internal funds are insufficient, dependence on external
funds is increased.
Market Participation by Public and Cooperative Utilities
Thus far, the consideration of financial condition and problems faced by the
electric utility industry in recent years has focused, for the most part, on the
investor-owned sector of the industry. All but 21 percent of the installed
capacity and 28 percent of total customers served fall in the investor-owned
sector, and these shares have remained relatively unchanged for the last decade.
The fact that these shares have not changed appreciably suggests that publicly-
and cooperatively-owned segments of the industry have faced many, if not most,
of the problems experienced of late by the investor-owned segment.
Indeed, the publicly and cooperatively-owned utilities, too, were affected by the
vagaries of demand, the deterioration of load factor, the lack of improvement in
heat rate, the increasing costs of construction and environmental protection, and
the increasing cost of fuel and money. The only problems they escaped were
ones having to do with state regulatory commissions and distressed stock holders.
The publicly-owned and cooperatively-owned electric utilities can be subdivided
into municipals, federal projects, and cooperatives according to the responsible
governmental unit or agency. A discussion follows for each type of utility as to
its participation in the capital market to meet its capital requirements.
Municipal Electric Utilities
The municipal utilities' percentage of electrical energy generation has remained
relatively constant since 1962. In 1976 the municipals produced about 9 percent
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of the net electrical output, evenly divided between utilities owned by munici-
palities and utilities owned by state projects and power districts.
Municipal utilities participate in the capital markets by issuing bonds which enjoy
interest exemption from federal income taxation. These bonds may be either
revenue bonds, which are secured by the revenues of the issuing utility, or
general obligation bonds, which are guaranteed by the general taxing power of
the issuing governmental unit. Generally, municipal utilities find it more
expedient to issue revenue bonds. The reasons for issuing revenue bonds include:
Additional general obligation debt cannot be issued be-
cause of statutory limitations.
Legal restrictions exist on the employment of tax
revenues.
When general credit of a municipality is not highly re-
garded, revenue bonds may command a more favorable
market than general credit bonds and can be sold at lower
interest rates.
« A governing body of a municipality may be able to issue
revenue bonds by securing a simple voting majority and
not, as in the case with general obligation bonds, a two-
thirds majority.
In the issuance of long-term debt, the municipal utility must first obtain authori-
zation by the governmental unit. The bonds may then be advertised, specifying
the terms of the issue as to denominations, coupon rates, and maturities. The
sale of the bonds takes place either on competitive bidding or a negotiated basis.
Competitive bidding does deprive the issuer of the initial advice and services of
an investment banker. Revenue bonds are frequently sold on a negotiated basis.
The more specialized nature of the bonds make the aid of an investment banker
important.
Bidding for these bonds is on a yield basis. The underwriters or syndicates bidding
for an issue determine the yields for the various maturities within the issue and
add a spread to cover risk and distribution expense to arrive at a cost of
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purchase. The successful bidder may then resell all or part of the issue with the
difference between cost and resale price ranging from I to 1.5 percent. This
gross spread depends on the type, size, quality, marketability, and maturity of
the issue. The purchasers of such issues are institutions or individuals who have
the most to gain by holding tax exempt bonds.
The yields on municpal bonds are determined by factors which include:
The general level of interest rates determined by the
supply of, and demand for, funds in the capital market.
The value to investors of the tax-exempt privilege.
The particular factors affecting supply and demand for
municipal bonds.
In addition, the yields on individual issues are a function of quality, size, and
marketability. Quality tends to correlate with size, with the larger issues ob-
taining the more favorable yields.
Municipal bond yields have doubled since 1965. Yields on long-term municipal
bonds have remained about 70 percent of the yield of corporate bonds with the
same maturity. It can further be stated that the spread between Aaa rated bonds
and Baa rated has more than doubled. The spread was 40 basis points in 1965; in
1975 the spread has increased to 131 basis points. Unlike investor-owned utilities
with Baa ratings, municipal utilities Baa-rated bonds were-able to obtain long-
term debt financing in 1975. A possible explanation for this is that the
municipals obtain a significant proportion of their capital in a local segmented
market where knowledge of the municipal may be more important than a bond
rating by a national rating service.
Capital expenditures by municipal utilities have averaged about 10 percent of
investor-owned utilities' spending over the last decade. Internally generated
funds have contributed somewhat more to capital expenditures for these utilities
than they have for investof-owned utilities. Partial explanations for this fact are
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that these utilities do not distribute dividends, and taxes as a percent of revenues
are less than they are for investor-owned utilities (on average about 4 percent
versus 15 percent). It has also been suggested these utilities do better with
respect to internal funds generation since their rate requests do not have to be
approved by state public service commissions. Because they have generated
more funds internally, municipals have had to raise less long-term debt.
Federal Agencies
Federal agencies for example, the Tennessee Valley Authority, which produces
half the federal output and Columbia River Power System, which generated an
additional 30 percent of the total generated 12 percent of the U.S. electrical
output in 1975. All of this output is marketed through federal agencies such
/
as the Bonneville Power Authority and the TVA itself to nonfederal utilities
who, in turn, sell it to ultimate consumers. Statutory preference in the sale of
this electricity is given to public bodies and cooperatively-owned systems.
Though investor-owned utilities may contract for federal power, such contracts
may be cancelled on five years' notice if the power is needed by a preferred
customer.
Federal power tends to cost a great deal less than that which is generated by
investor-owned utilities. This fact reflects the lower interest costs required on
federal debt, the fact that no taxes need be paid by federal agencies, and the
fact that federal power is, as it turns out, generated at a higher load factor.
TVA, one of the more visible members of the electric utility industry, is a
permanent, independent corporate agency of the Federal Government. The
responsibility of this agency is to supply electric power as a wholesaler to the
Tennessee Valley area. The capital investment required for the building of dams,
steam plants and transmission facilities has been raised by Congressional
appropriation, retained earnings, and the issuance of long-term debt. In I960,
TVA began issuing long-term debt; such financing has become the primary means
for financing its capital expenditures.
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Cooperatives
Cooperatively-owned utilities produced about 2 percent of the total electrical
output in 1975, but they accounted for 8 percent of the total kilowatt-hour
sales.
Co-ops are a creation of the Rural Electrification Program initiated in 1935 and
the legislation of 1936 which established the Rural Electrification Administration
(REA) to lend money to the co-ops. The original purpose for the co-op program
was to see that rural areas would have electrical service that was dependable and
not overly expensive. Originally, loans to co-ops were made so that distribution
systems could be established. These systems would purchase wholesale power
from both government-owned and investor-owned generating facilities. As some
of these distribution co-ops grew in size, they realized economies in generating
and transmitting electricity on their own. In 1975, co-ops had installed capacity
of about 7,600 MW.
Since their creation, co-ops have been permitted to borrow funds from the
federal government at attractive interest rates 2 percent in most cases,
though 5 percent in some. In 1971, the REA adopted a policy requiring certain
REA electric borrowers to obtain part of their loan funds from non-government
sources. This policy has caused coops to issue long-term tax-exempt debt.
Cooperatives now issue several million dollars in tax-exempt debt each year.
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B. FACTORS AFFECTING ELECTRIC UTILITY
INDUSTRY CAPITAL-RAISING PROSPECTS
Having reviewed the nature of the capital markets and the electric utility
industry's recent participation in those markets, the discussion turns to the
factors which are likely to affect the ability of the industry to attract capital
sufficient for purposes of complying with NSPS as well as for other possible
purposes.
This section begins with a brief discussion of some of the important
macroeconomic factors contained in a compilation of economic forecasts through
the year 1985. This discusion is not intended to be an analytical critique of the
projections or of the key.assumptions which drive the projections. Instead, the
purpose is simple to indicate the importance of macroeconomic variables as they
may affect electric utility capital spending.
In the second portion of this section, the nature of the discussion changes some-
what. With reference to the compilation of forecasts, the discussion explores the
nature of the "capital shortage" that a number of economic forecasters allege
will exist in the future.
In the third portion of this section, the discussion turns to some of the macro-
economic factors which will affect electric utility capital spending. The un-
certainty-filled environment in which the industry must make investment deci-
sions is described in brief. Next, the important constraints to large-scale capital
investment by the industry are discussed, and some policy options available to
state regulatory commissions and utility management to overcome these
constraints are discussed. Finally, some remarks are made concerning the in-
vestor-owned electric utilities' use of pollution control revenue bonds.
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MACROECONOMIC FACTORS
The condition of the national economy is often considered a crucial factor in
determining the need for electric utility capital spending and the ability of the
industry to meet its financial requirements. In Table 5, a compilation of U.S.
financial parameters prepared by FEA is reproduced. Perhaps the most
important figures to consider are the estimates of real annual GNP growth for
the years 1975 to 1985. These estimates range from 3.6 to 5.0 percent. The real
GNP rate is important since electric utility capital requirements are to a large
extent related to electricity demand (especially to peak demand, and to a lesser
extent to average demand), and electricity demand is, in turn, believed to be
related to real GNP growth. If real GNP growth turns out to be lower than
forecast, estimates of utilities' capital requirements and external financing needs
are likely to be overstated.
The corporate bond rate is another important financial parameter. Table 5 shows
estimates of the Aaa bond rate. It should be noted that there are practically no
utilities currently in a financial position strong enough to earn Moody's Aaa
rating for their bonds. Most utilities in reasonably good financial condition are
selling Aa bonds, while those utilities in fair condition are selling bonds rated A.
Utilities whose bonds were rated Baa in 1974-75 were unable to secure new debt
funds. Should utilities be unable to improve their financial condition in the
future, they may well pay significantly more than the corporate Aaa bond rate
for their external funds (provided they are not prevented by indenture
agreements or usury laws from seeking the funds).
The amounts of gross private domestic investment and total savings in the
national economy are also important influences on the financial markets. Table
5 shows investment and savings broken down into separate components and
calculated as percentages of GNP. As gross investment (including foreign in-
vestment) must always equal gross savings (including depreciation), the invest-
ment and savings totals in Table 5 should be identical. Four of the five studies
estimated total investment and total savings as about 15 percent of GNP which
is consistent with percentages achieved in the 1950s and in pre-recession 1973.
For dramatic purposes, the NYSE totals do not match.
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TobleS
National Finance Parameters. 1975-1985
Real GNP Growth
Rate^
High grade (Aaa)
corporate bond rate
As % of GNP
Gross private domes-
tic investment
Non-residential
Inventory
Residential
Total Savings
Business
Personal
Government
Federal
State &
Local
Other
DRI
4.5%
8.6
15.3%
10.6
0.7
4.0
15.3
11.0
5.4
-0.8
-1.0
0.3
-0.2
NYSEa
3.6%
-
16.4%
9.4
3.1
4.0
15.0
10.6
4.0
0.3
-0.2
0.5
0
BDCb
4.3%
7.5
15.6%
10.9
0.7
4.0
15.6
10.6
4.6
0.2
0.3
-0.3
O.I
Labor
5.0%
-
15.4%
11.2
0.9
3.3
15.4
11.2
4.7
-0.4
-0.7
0.4
-O.I
Chase0
3.6%
9.9
14.5%
10.6
0.7
3.1
14.5
10.2
6.2
-2.0
-2.1
O.I
O.I
a!974- 1985. b!973- 1980. CI975- 1984.
dOther forecasts of GNP growth include Electrical World, 3.5%
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The relative proportion of GNP constituted by total savings is an important
indication of the amount of money potentially available in the capital markets.
One of the major influences on the amount of savings in the economy is the rate
of inflation. When the rate of inflation is as high or higher than the rate of
interest, money saved actually loses value; thus, there is a greater incentive to
spend than to save. Accordingly, the Chase study, which forecasted the lowest
amount of total savings, 14.5 percent of GNP, also forecasted the highest rate of
inflation, 6.2 percent. BDC, which estimated total savings at 15.6 percent pf
GNP, estimated the rate of inflation to be only 4.7 percent.
The lower the total real savings in the economy, the less money will be made
available for business investment; hence, the higher the yield which must be paid
to obtain that which is available. Ultimately, businesses may find interest rates
are so high thaf a reasonable rate of return on investment cannot be generated.
Therefore, one would expect that the demand for capital would be reduced;
reduced demand for capital tends to result in reduced interest rates. A reduced
level of inflation tends to provide incentive to save, increasing savings available
for business investment or to other borrowers such as government.
Government saving is a particularly important component of total savings in that
government savings are often negative; that is, it spends more than it collects in
taxes. When there is a government deficit, the government must obtain money
from external sources. Deficit spending may tend to drive up interest rates. A
government deficit could tend, therefore, to make external financing for the
utilities more costly. Chase forecasted the largest government deficit, 2
percent of GNP. DRI and the Department of Labor forecasted smaller deficits,
0.8 and 0.4 percent of GNP, respectively. BDC and NYSE estimated a
government surplus of 0.2 to 0.3 percent of GNP over the next five to ten years.
Capital Shortage?
Given certain macroeconomic parameters, is there reason to expect that the U.S.
will experience a "capital shortage," one that could affect the spending plans of
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the electric utility industry? In answering this question, it proves convenient
first to segregate the relevant issues into what are, in fact, two integral parts
a macroeconomic view of capital availability and a microeconomic view of the
utility industry and its member firms that are anticipated to require the capital.
The macroeconomic view takes into account such factors as the aggregate
amounts of prospective saving and investment, the essential manner in which
prices (including interest rates) are determined, the financial conditions of the
firms requiring capital, the prospective rates of economic growth and inflation,
the extent to which productive capacity is now utilized, and the role of
government policies (fiscal, monetary, and tax), programs, and laws, e.g., with
respect to environmental protection. The macroeconomic view focuses on the
ability of specific firms to generate investment funds internally and to compete
for external financing.
In the last three years, a number of studies have been undertaken to assess the
likely characteristics of the U.S. financial markets over the next decade. Among
the studies are those summarized in Table 5. Essentially what most of the
studies did was to add up a likely supply of aggregate national savings and
compare that total to the capital investment plans of the nation's business
corporations. Some studies found the aggregate investment figure to exceed the
likely aggregate amount of savings (generally assumed to be about 4 trillion
dollars over the next ten years) and thereupon declared that a "capital shortage"
would exist in the U.S.
The arguments advanced to justify a concern for a "shortage" include the fol-
lowing:
Inflation has and will likely continue to keep internal generation of funds low
relative to the need for investment funds. First, internal funds are generated
chiefly through depreciation allowances and through retained earnings. In the
absence of technological change and the presence of a relatively high rate of
inflation, depreciation allowances may be considered inadequate to maintain a
firm's stock of capital. During inflationary times, earnings are taxed at rates
which do not reflect the reduced buying power of such earnings. When corpora-
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tions are unable to generate funds internally, they must seek their financing
needs in the capital markets. But if all corporations seek external financing at
the same time, the argument is made, there may not be enough capita] to go
around.
Second, the argument is made that internally generated funds constitute prac-
tically all of gross corporate savings, and gross corporate saving (including depre-
ciation) generally accounts for about three-quarters of gross saving in the U.S.
each year. So, it is argued, the pool of savings may be insufficient to meet the
demands placed upon it.
Another argument made to support the notion of "capital shortage" is as follows:
Federal fiscal policy may foster enormous budget deficits. Deficit spending may,
it is argued, cause interest rates to rise (in fact, this alleged linkage is by no
means proven), and this may cuase the inflation rate to rise, and this, in turn,
may inhibit internal funds generation and force corporations into the capital
markets. It is also argued that mandated air and water pollution control may
require capital spending of tens of billions of dollars over the next decade.
Occupational health and safety legislation will also require what industry
spokesmen have called "non-productive" capital spending. Further, it is argued
that the nonprice rationing of credit to certain essential industries, e.g., electric
utilities, would appear unlikely given the relationship between government and
the banking industry in the U.S.
On the other hand, it can be stated that as a practical matter, ex post, savings
always equals investment. Firms which cannot compete for capital are always
"crowded out." Further, it can be said that the studies which purported to show
the existence of a capital shortage took the investment plans of corporations
without associating these plans to prices, interest rates, and/or the abilities of
the firms to earn their costs of capital. Spending plans tend to be grandiose in
the absence of financial constraints.
While a shortage of capital may not take place in the economy as a whole, it may
surely take place at the level of the individual firm. Thousands of firms
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experience capital shortages from time to time - they cannot compete, either
because they cannot lure investors or because legal restrictions prevent their
would-be participation in capital markets. Are a particular state's electric
utilities likely to be spurned by investors or otherwise prevented from raising
capital for NSPS compliance or other purposes? It would be helpful in answering
this question to be able to foretell federal and state tax policy, incentives for
individuals to save rather than consume, the realistic spending plans of other
firms, the expansion in the productive facilities of equipment and plant suppliers,
and many other facts. These factors are very difficult to predict with any
accuracy. Hence, this discussion of capital raising prospects is confined to
general and suppositional areas. The discussion here turns to microeconomics
F
and involves such factors and issues as the significance for capital formation of
accounting practices peculiar to public utilities, certain utility management
initiatives which might be taken to improve the industry's financial condition,
and other possible policies and constraints.
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MICROECONOMIC FACTORS
It was shown in the first section that the financial condition of the electric
utility industry is significantly affected by a combination of factors, including
low capacity utilization, a high rate of inflation, high interest costs, and regu-
latory lag. These and other factors affect the industry's ability to attract
capital. If the industry is to be in a position to fund necessary expansion of
plant, mandated NSPS, and other projects, it must, above all, generate an ade-
quate level of earnings, improve the state of its balance sheet, and reevaluate
some of its conventional management policies. It will need to do so in an
environment characterized by great uncertainty, with the prospects good for
more uncertainty in the future rather than less. To describe the environment in
which the industry must operate, it is useful to begin with one of its most basic
types of decisions: capital budgeting.
Capital Budgeting in the Electric Utility Industry
In an industry of inherently great capital intensiveness, the most crucial manage-
ment decisions have to do with capital budgeting. In attempting to determine
the amount and type of facilities to build to meet the demands of customers and
comply with state and federal environmental protection standards, a great many
factors need to be taken into consideration. For example, it is necessary to have
a reasonable amount of knowledge about the amount, type, cost lead time, and
profitability of capital expenditures. At present, much uncertainty clouds the
investment environment. The uncertainty is manifest in areas which include:
Demand
The uncertainty of electricity demand is a major problem affecting the industry's
mix, timing, cost, lead time, and profitability of capital expenditures.
This uncertainty is affected by uncertainties as to the degrees of voluntary,
mandatory, and price-induced conservation likely among consuming sectors. It is
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affected, as well, by the interaction of a dozen or so demographic and economic
variables whose future course is by no means clear. It is affected, also, both by
the substitution of electricity for the direct use of certain fuels whose costs may
be high or availabilities scarce and by the substitution of alternative means of
power generation for example, solar for the electrical output.
Regulatory Response
Many believe the remedies or solutions to any financial problems the industry
may have should come first and foremost from the industry's regulators
through timely and effective rate relief, allowance for higher rates of return on
investment, change in accounting practices, and perhaps changes in the way
electricity is priced. The regulators federal, state, and local, evidence no
common pattern of response to the industry's financial condition.
Construction and Equipment Costs
Economic choices need to be made periodically as to the amount, type, and
timing of new plants if for no other reason than to retire old, economically or
technologically, inefficient plants. These choices must now be made in a setting
characterized, among other things, by more lengthy plant gestation periods
which could well get longer and potentially rapid shifts in the economic and
financial advantage of one type of plant construction and equipment over
another. For example, it is by no means clear, even on pure cost grounds, to say
nothing of the imponderables introduced by legal interventions, whether nuclear
or NSPS-complying coal-fired units will be preferred for baseload capacity.
Fuel Supply and Cost
To determine the type of capacity to build to meet an estimated demand for
electricity, it is crucially important to have some notion as to the likelihood of
the availabilities and costs of fuels to burn over the life of the appropriate
generating plants. Since these plants may take 5 to 10 years to site, license, and
build, the fuel supply and cost calculation takes as a starting point 5 to 10 years
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from now and continues for perhaps another thirty to forty years from the
starting point.
Even in the least volatile of times such long-range forecasts are hazardous.
Today, even 3 to 4 year fuel supply and cost forecasts may miss the target by a
wide margin.
To begin to forecast coal supply and cost one needs, for example, some idea as to
how much is in the ground and whether it can be mined at a reasonable cost.
Further, it is necessary to know which coals can be mined and where. To begin
to forecast the cost of nuclear fuels, one needs, for example, some notion as to
the future costs of enrichment and the future availability of disposal facilities.
Though fuel cost forecasts must be made for planning purposes, they should be
treated with extreme caution.
One means to the control of fuel supply and cost involves the industry's purchase
or lease of coal and/or uranium mines. Yet, there is a great deal of uncertainty
as to whether the industry could afford such investments in supply and as to
whether its regulators would permit such investments in all instances.
Environmental Constraints
The future course of environmental legislation and standards present large uncer-
tainties to the electric utility industry. Controlling the discharge of effluents to
the air and water may cost a good deal more than now anticipated. Standards
may preclude the use of certain fuels and processes now in use.
Controls on the use of land for mining, generating, transmitting, or distributing
energy may be more stringent than now foreseen. Environmental concern for the
safety of nuclear operations could prevent large scale, if any, use of this source
of electrical generation.
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Federal Policies
There are numerous things that the federal government can do, wittingly or
unwittingly, to help or hinder the electric utility industry. To the extent that the
federal government through expenditure, tax, and monetary policy can control
inflation, it helps the electric industry. To the extent that federal deficit
spending is maintained or is increased, it may hinder the industry, in at least the
price the industry must pay for new debt issues or for the refunding of old issues.
In the short term, the federal government could probably also help the industry
though perhaps not its rate-payers or taxpayers by guaranteeing industry debt
issues. Whether such a measure is a long-term help is more problematic.
There are other federal policies or actions which might be pursued in an attempt
to aid the industry. They might include incentives to engage in load management
programs, policies with respect to the accounting practices which the Federal
Power Commission may permit to be used (e.g., with respect to CWIP and
AFDC), and an increase in the investment tax credit rate.
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REGULATORY POLICIES
State public utility commissions have considerable influence over the capital-
raising prospects of the nation's investor-owned electric utilities. Potential
investors view the fact that electric utilities are regulated monopolies as both an
asset and a liability. It is an asset because utilities have a legal right to the
opportunity of earning a fair return on their investments and because a monopoly
may be less subject to the operating risks faced by competitive firms. On the
other hand, the regulated nature of the industry is perceived as a liability
because, in some instances, regulators have had a role to play in the instability
which utilities' earnings have exhibited of late.
In May, 1976, a brokerage and research firm rated the "regulatory environment"
in 46 states and the District of Columbia. (It noted Utah's Public Service
Commission the most "favorable"; West Virginia's, the least.) It based its ratings
on factors which include: allowed return on equity; rate request processing time,
in months; test year for rate calculation, historical, forward-looking, or both;
rates go into effect under bond; limit on time permitted until rate decision
rendered; fuel adjustment clause; normalization of accelerated depreciation and
investment tax credits; and CWIP in rate base. In effect, regulatory climate
refers to alleged adverse treatment of investors either through insufficient rate
of return, insufficient rate relief, or delay in granting that relief.
It is unknown the degree to which investors attach importance to these subjec-
tive ratings or to the factors upon which the ratings are based. If investors
believe the factors very significant, they may either bid up the returns required
in particular states or from particular utilities. One thing that can be observed,
however, is that there are electric utilities in states which have so-called
unfavorable environments which are doing quite well, and there are utilities
operating in so-called favorable regulatory settings which are not doing very
well. Perhaps the only real evidence that "regulatory environment" is being
taken into account explicitly can be found in the area of bond ratings. This fact
and its implications is discussed in the next portion of this section.
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There are three particularly interesting regulatory policies which, if altered,
have a major effect on utility finances and thus capital-raising prospects. They
are: CW1P/AFDC treatment, the automatic fuel adjustment clause, and the cost
of capital adjustment clause. Until recently, there were four such policies to
consider, but last year, Congress would appear to have removed one from
immediate need for consideration. This one involved the question as to whether
utilities should be permitted to normalize tax credits and accelerated depre-
ciaiton or whether Public Service Commissions could force them to flow-through
the benefits of these tax subsidies to current rate-payers. In effect, normali-
zation was decreed. (California's PUC has vowed to take the issue to the
Supreme Court.) A discussion follows of the three remaining policies for
consideration.
Construction Work in Progress (CWIP)
CWIP is a temporary utility plant account which collects all funds, including the
cost of construction funds, which are tied up in the construction of new facilities
that have not yet come on line. When the facilities are completed, their costs
are transferred to a permanent plant account a rate base account.
Currently, 35 states, the District of Columbia, and the FPC exclude the CWIP
account from the rate base. The major arguments in support of this policy are:
(I) the costs of future generating plants should be borne by future rather than
current ratepayers, or, to state it differently, utilities should be able to charge
consumers only for assets that are "used and useful"; and (2) utility management
should have an incentive to see that projects are completed and completed
expeditiously. The major arguments for CWIP inclusion in rate base are: (I) cash
flow would be increased at a time whenJt is most needed; and (2) both the
quantity and cost of capital would be reduced; hence, the ultimate cost of the
electricity would be reduced.
Inclusion of the CWIP account in the rate base, given that the allowed rate of
return were kept constant, would, of course, immediately increase electricity
rates and revenues. Ceteris paribus, taxes would also increase, since net income
would be higher. Construction projects would be much less risky, however, since
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including CWIP in the rate base reduces the risk of building a plant which, if not
deemed necessary by a regulatory commission, might not be included in the rate
base upon completion. With the risk reduced, external financing could be
cheaper. Inthe long term, this could result in lower electricity rates.
The "Construction Work in Progress" account includes the interest and equity
costs of construction funds. These costs are capitalized in the account
"Allowance for Funds Used During Construction" (AFDC) which is credited to
income over the construction period. AFDC is noncash, non-taxable income and,
like CWIP, is currently not allowed by many regulatory commissions to be
collected in rates until the plant is transferred to the rate base. Were CWIP to
be included in the rate base, there would no longer be a need for AFDC since the
utility would be realizing revenues that cover the interest costs on CWIP.
The following example shows the relationship between capital expenditures, the
AFDC account (an income statement account), and the CWIP account (a balance
sheet account). In the example, the following assumptions are made: (a) capital
expenditures are made the first day of the year; (b) the AFDC rate is 8 percent;
(c) the plant takes three years to build; and (d) after three years of construction
expenditures, including those for use of construction funds, the plant comes on
line.
Year
Capital
Expenditure
AFDC
CWIP at end
of year
1
2
3
$100
200
100
$8
24
32
$108
332
464
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The important points to note from the example are (I) the CWIP account
accumulates all capital expenditures and AFDC associated with the construction
of the plant. When the plant comes on line, the amount of CWIP associated with
the plant is added to the rate base and begins to be amortized for rate-making
purposes. (2) For tax purposes, only that portion of the CWIP account which
represents capital expenditures, $400 (i.e., excluding AFDC) may be depreciated;
(3) for tax purposes, only the debt component of AFDG is an allowable expense
and this deduction must be taken in the period in which the interest was paid. (4)
AFDC is not compounded.
Fuel Adjustment Clauses (FACs)
During the Embargo and shortly thereafter, electric utilities argued strenuously
for the right to use automatic fuel adjustment clauses to pass on to customers
the rising cost of fuel without having to go through formal rate proceedings to do
so. The argument was that fuel costs were not in any way controllable by
utilities and it made no sense to require utilities to formally justify expenses
over which they had no control. Further, fuel costs were seriously depleting cash
positions. All but five states agreed with utilities and allowed FACs to be used.
It may have appeared that the FAC issue was resolved, and that in the future,
utilities could count on charging customers on a timely basis increases infuel
costs.
But the issue is far from resolved, as evidenced by a recent speech given by
President Carter in which he stated that: "It is hard to believe that every time
energy costs go up, that utility companies automatically raise your rates, and the
regulatory agencies don't have a thing in the world to say about it. That ought to
be changed."
The President no doubt had in mind a July 1977 report by the Senate Govern-
mental Affairs Committee, which criticized Public Service Commissions for
permitting utilities to pass through in FACs both direct fuel and non-fuel
expenses. Non-fuel expenses in FACs include those involving line losses,
efficiency factors, taxes and fees, fuel handling costs, fuel-related salaries and
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labor, allowance for uncollectable expenses, lag correction factors, wheeling
charges, hydro and geothermal power. The authors of the report suggest that
FACs have been abused and that FACs should be abolished.
The issue is not clear cut either way. There may be good arguments for relieving
utilities and Public Service Commissions from the drudgery of having to
scrutinize, in lengthy proceedings, many costs which utilities cannot control.
This assumes these costs are indeed uncontrollable. If they are uncontrollable,
regulators might more profitably focus on controllable costs and devise a
performance/incentive structure for dealing with these costs agreed to be under
management control. That is, allowed rate of return might be tied to
management performance as it is supposed to be in the rest of the corporate
sector.
As for the immediate financial consequences of a possible abolition of FACs, if
the electric utility industry is an increasing cost industry, the normal regulatory
lag associated with the review of expenses which were previously passed on in
FACs will adversely affect the industry and its capital-raising prospects.
Capital Adjustment Clause (CAC)
In April 1975, the New Mexico Public Service Commission instituted a novel
rate-making mechanism which, if adopted by other PSCs, could have very impor-
tant implications for the ability of the electric utility industry to attract funds
from the capital markets. For the Public Service Company of New Mexico, the
PSC established an automatic capital adjustment clause which permits the utility
to adjust rates on a quarterly basis such that it realizes the rate of return on
equity allowed by the Commission. The Commission set a range of 13.5 percent
to 14.5 percent for the return on equity.
In effect, the CAC guarantees that at the end of each 3-month period - i.e., not
prospectively - the equity return will be no less than 13.5 percent. By the same
token, every quarter the equity return is adjusted down to a ceiling level of 14.5
percent, if during the preceeding three months, it has exceeded that level.
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Clearly, this is a different sort of equity. This raises some interesting public
policy questions. Some of these questions will be explored momentarily. But
first, it is useful to consider the PSC's motivation for establishing the CAC and
what CAC's effect has been to date.
New Mexico PSC's basic motivation for instituting the CAC was that it saw a
need for the utility to attract capital at the least possible cost in order to build
new generating capacity. Specifically, it saw a need to build coal and nuclear
plants. It recognized that construction costs had mushroomed in recent years,
and it believed that while fuel adjustment clauses recover some costs on a timely
basis, the normal regulatory lag involved in scrutinizing other costs had a
sufficiently adverse effect on earnings' stability that funds to be used for
construction were becoming more difficult and expensive to attract.
It has been determined that the CAC has had a positive influence on Public
Service Company's cost of capital. Limited evidence suggests a decrease in its
cost of debt, and more robust evidence suggests an increase in its P/E ratio
roughly equivalent to a one to two percent decrease in its cost of equity.
From a public policy viewpoint, the principal problem with the CAC is that it
may tend to reduce a good deal of the risk which equity investors can be
expected to be willing to assume for a 13.5 to 14.5 percent return. If this be the
case, then the risk is shifted to consumers.
Another question is whether issuing this form of equity is less expensive than
issuing debt in the same amount. This is a difficult question since there may be
serious constraints on the firm's ability to do so even with the earnings
stabilizing influence of a CAC. Further, it can be argued that at some point a
firm needs an infusion of equity capital to maintain its target debt/equity ratio.
Undoubtably these questions and others involving the New Mexico PSOs CAC
will be debated at many other PSC's in the near future. Streamlining the
regulatory process by essentially eliminating the need for adversary proceedings
may be a course of action implying greater efficiency, but the risk/reward
A-47
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element tends to be altered by such initiative. Probably the ultimate question
with the CAC is the same as it is with the normalization/flow-through,
CWIP/AFDC, and FAC issues; that is: Is there a high probability that consumers
will receive a net benefit from a change in policy?
A-48
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MANAGEMENT POLICIES
The policies noted thus far would require regulatory initiative for change. There
are other policies which may affect capital-raising prospects which utility
management would need to take it upon themselves to establish. These policies
and their possible effects on financial position are described below.
Debt Ratio
Financial decisions concerning capital structure and dividend policy may have a
significant impact on an electric utility. It has been suggested that utilities
increase their debt ratio; that is, their degree of financial leverage. A change of
this nature in the capital structure could have a noticeable financial impact,
particularly/because most U.S. electric utilities are already highly levered (the
average debt-equity ratio is approximately 1:1). A higher debt ratio could lead
to a lower revenue requirement, since the after-tax cost of debt is less than it is
for equity. However, equity holders would require a higher rate of return to
compensate them for their additional risk, and there may be no net reduction in
the weighted average cost of capital. But, if the proportion of debt in the
capital structure were to increase, since interest charges are tax deductible,
taxes would decrease if rates did not change. If rates were to rise, however, net
income might benefit greatly, due to the increased degree of financial leverage.
This same leverage would hurt the utility considerably in the case of a decline in
revenues. External financing might become increasingly difficult with a higher
debt ratio, and this might curtail some capital spending.
Dividend Payout
Another change which financial management could implement would be to
decrease dividend payout. This, in turn, would increase the proportion of
earnings which the utility could retain and reinvest in its projects. One theory
holds that investors are indifferent to the amount of dividends they receive,
assuming the retained earnings are reinvested profitably. Therefore, decreasing
dividend payout should result in less need for external financing and perhaps in
A-49
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greater incentive for the utility to undertake capital expenditures. Rates would
be unchanged, as would taxes, since dividends are not a tax-deductible expense.
However, another theory holds that investors do value more highly stocks which
pay higher dividends - current income. Adherents to this latter theory would
argue that if the dividend payout were reduced, the utility would lose equity
holders, thereby having to raise rates somewhat to increase the return on equity
to attract new equity holders.
New Types of Capital Expenditures
As has been noted, a great deal of uncertainty now pervades the environment in
which the industry must plan its capital expenditures. For example, it does not
know precisely what types of new generating facilities to build base load,
intermediate, or peaking what would be most economical and most reliable for
baseload coal or nuclear and whether or not an attempt should be made to
acquire leases or producing companies to secure fuel supplies of a certain type
for new generating plants.
The industry must also consider the possibility that, for example, State Imple-
mentation Plans for emissions to air may be tightened to require either that fuels
with different characteristics be used, that coal cleaning plants be financed and
constructed to reduce the polluting characteristics of the fuel, or that stack gas
desulfurization investments be made.
There is an enormous number of possible investments for which the electric
utility industry may feel a need or may be required to make between now and
1995. The following is a partial list of possible capital investments which might
be made prior to 1995.
New generating plants of an appropriate mix.
Physical or chemical coal-cleaning facilities associated
with the use of existing plants.
Scrubbers for all new plants and for some proportion of
existing plants. Investment in sludge disposal facilities.
A-50
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Facilities constructed for compliance with the water
pollution control act.
Purchase or lease of coal and uranium mines. Acquisition
of operating companies. Investment in mining equipment,
additional railroad spurs, conveyor belts, slurry pipelines,
etc.
Investment in railroad rolling stock.
Investment in gasification and liquefaction projects.
Investment in solar energy either for electricity-
making purposes or for installation in consumer homes.
Investment in making consumer loans for insulation retro-
fit.
Investment in transmission and distribution facilities,
including those that are more energy-efficient or environ-
mentally-benign but which carry higher first-costs
(presumably lower life-cycle costs, or some form of
subsidy would be requested).
Undergrounding'of existing distribution facilities.
Investment in load management hardware at the utility
end and very likely at the consumer end as well.
For combination utilities, investment in gas supply
projects, as well as insulation retrofit and conventional
transmission and distribution investment.
It is not clear what all these possible investments would cost. It is clear that
some investments should make others unncecessary. However, it is also evident
that not all these investments can be made prior to 1995. Still, there are advo-
cates for each type of investment, and there will be competition among
advocates to effect the course of electric utility capital spending.
The existence of this competition for the spending capacity of the industry
suggests three things. First, it suggests capital expenditures for purposes related
to NSPS revisions could squeeze out possible expenditures for other purposes.
Second, it suggests that state regulatory commissioners will be under pressure to
A-51
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expand the industry's spending capacity by permitting higher allowed returns and
other favorable treatment. Third, it suggests that, if state regulators permit
increased spending capacity and if the rates of GNP and savings do not increase
as fast as the rate at which industry spending capacity does, the industry may
command a greater share of available capital than it would otherwise.
Constraints to Greater Investment
It has been suggested that the level of earnings the industry can generate proves
to be the greatest determinant of the success which will be had in attracting
investment capital. Earnings affects share prices which, in turn, affect the
ability to raise equity funds. Earnings also affects interest coverage ratios
which, in turn, affect bond ratings. Bond ratings have proven in recent years
crucial constraints on the ability to issue debt securities. In 1974-1975, no utility
with bonds rateJ Qiu or below was able to issue debt.
Bond ratings are purported to measure the probability that a firm will meet its
debt obligations in a timely fashion. A lower rating implies a lower probability
of prompt payment; hence, a higher degree of risk. Riskier bonds must carry
greater risk premiums to compensate investors for bearing the risk of default.
In the last decade, bond ratings have become extremely significant in affecting
the capital-raising prospects of firms whose financial positions are not as robust
as those of the nation's strongest and most stable firms. Electric utilities, which
a decade ago were considered both strong and stable, are now frequently counted
among the firms whose ability to gain relatively good ratings for their bonds is
somewhat problematic. Indeed, in recent years, numerous utility bonds have
been downgraded. The industry appears to consider 1976 a fairly good year in
this respect, since only eight bonds were downgraded that year, whereas 15
received such treatment in 1975.
What privileges accrue to the firm with relatively high ratings for its bonds?
First, it can attempt to market the bonds in the widest possible market for
securities. Institutional investors - including commercial banks, insurance
A-52
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companies, and pension funds are generally prohibited from purchasing any
bonds below Baa. Second, the firm is more likely to get the proceeds it needs
with lower transaction costs. These costs include investment bankers' fees and
commissions, and such costs tend to rise the more difficult it is to place the bond
with an eligible and willing buyer. Third, the firm is likely to acquire the debt
funds at a lower effective interest rate.
The magnitude of the effective interest rate presents special problems to firms
operating in about a dozen states. The problem is a statutory one, the states'
usury laws. These laws prohibit lenders of certain types read: investors
from requiring more than a certain percentage effective annual interest on any
loan. The statutory percentage rates vary from state to state, but the majority
are in the range of 9 to 12 percent per annum.
An exhaustive legal analysis of the extent to which usury laws would present a
serious constraint to utility capital formation has not been performed to date.
However, it is clear that in certain states investors are not exempt from these
usury provisions. As matters now stand, under the current usury laws of some
states, a utility with a relatively low bond rating must either sell bonds of a
shorter term and lower interest rate or sell bonds (the maturity of which may
match the life of the asset) with an interest rate which exceeds the usury level
and trust that there will be lenders willing to risk the possibility of legal com-
plications.
One of the interesting aspects of bond rating practices is that the raters now
look beyond such matters as a firm's asset protection, financial and .management
resources, and earnings stability, to subjective measures of the regula-
tory/political climate of the state in which the utility operates. Firms operating
in "favorable" regulatory climates that determination being made based on
allowed returns, present accounting practices, and other factors noted earlier
may be given the benefit of the doubt where there is some question as to
appropriate rating. Clearly, the firm that has limited financial1 and management
resources, exhibits wide swings in profitability (due perhaps, in part, to a highly
leveraged position), and which operates in an unfavorable regulatory environment
may have serious problems attracting outside capital.
A-53
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POLLUTION CONTROL REVENUE BONDS
It is estimated that the United States business sector invested about $7.5 billion
in 1977 for pollution control purposes. The investor-owned electric utility indus-
try accounted for about $2.3 billion, or 30 percent, of the estimated total. Sixty-
five percent of the investor-owned utilities share went to air pollution
abatement, thirty percent to water pollution control, and five percent to waste
disposal. Eleven percent of all new utility capital expenditures was devoted to
pollution control.
About half of all new capital raised by the business sector for pollution control
spending is being acquired by use of tax-exempt pollution control revenue bonds
(PCRB's). 'These tax-exempt issues now represent about ten percent of all new
debt issued by state and local governments. It is thouught that over the next ten
to fifteen years PCRB's issued by public authorities for the benefit of private
firms could assume a much larger share of the tax-exempt market. In so doing,
the expanded use of PCRB's may present a number of problems the ulimate
effect of which could be either a loss of advantage for their use by private firms
or an abolition of that use.
The use of public credit to finance private projects began forty years ago with
the industrial revenue bond (IRB's) program; however, IRB's were not widely used
until the economic boom in the Sixties at which time states and municipalities
bid against one another to attract industry. In 1968, an enormous amount of IRB
debt was issued, so much that municipal bond rates rose by twenty-five basis
points. Urged by municipal organizations and the Treasury Department, which
argued that a massive amount of income tax revenue would be lost, Congress
redefined eligibility requirements for use of IRB's, and their use fell to about $40
mi 11 ion in 1969.
Congress, believing private investment in pollution control facilitates a use of
IRB's that was genuinely in the public interest, continued to legitimize the use of
pollution control revenue bonds. Subsequent passage of the water and air
-------
pollution control acts essentially mandating certain private expenditures implied
an expanded use of PCB's. In effect, it was determined that the cost of cleaning
up the environment should be a responsibility shared between industry and tax-
payers.
It is a concern for the nature and possible magnitude of the shared-burden which
prompts a growing interest in tax-exempt pollution control financing. One
concern is that federal and, in many cases, state and municipal tax revenues may
be adversely affected by the expanded use of PCRB's. One estimate is that
PCRB's will cost the federal government more than $1 billion a year in foregone
tax revenue by 1980. Another $450 million will be incurred by state and local
governments the loss representing higher interest costs caused by overloading
the tax-exempt bond market with private industry debt and representing lost tax
revenue as well. It is argued that the major proportion of the tax loss to
government is due to the tax sheltering PCRB's would provide those investors in
the highest tax brackets, those for whom the tax-exempt feature has the
greatest attraction.
Precisely how much more state and local governments would have to pay in
interest costs due to the alleged flooding of the tax-exempt market by PCRB's is
very difficult to estimate. This would depend among other things upon the phase
of the economic cycle, the cash positions of the principal market participants,
the relative size of the municipal issue, and the magnitude of tax-exempt debt
used by the business sector and particularly by the electric utility industry.
Energy policies, environmental protection standards (form and stringency), and
Internal Revenue Service rulings will have a great deal to do with the magnitude
of PCRB's which the electric utility industry may wish to use. An energy policy
which encourages utilities and other industries to use dirtier, though perhaps
more plentiful, fuels implies greater use of PCRB's. Further, an energy policy
which encourages load flattening implies greater need for and use of coal and
nuclear baseload units. Both types of plants may be considered "dirty".
A-55
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The immediate problems with coal are fairly evident, thoijgh further research
may find all sorts of new environmental problems related to its use. Further
tightening of standards for known pollutants may be required, and standards for
other emissions the effects of which are not now well understood, may be
necessary.
The use of nuclear power plants involves serious pollution problems as well -
due to radiation. The very design of nuclear power plants may be seen as an
attempt to minimize hazards from radiation. It has been estimated that from
twenty-two to thirty percent of the investment in nuclear power plants could be
considered for purposes of pollution control (radiation and other pollution). If the
IRS confirms this estimate, a very large proportion of the investment could be
financed with tax-exempt securities. Since it is estimated that investment could
be made in as many as 187 nuclear plants by the year 1990, this could mean as
much as $6.5 billion worth of nuclear power PCRB's coming to the tax-exempt
market each year from now until 1990. This would represent about twenty
percent of the entire new issues market, for nuclear power alone!
Clearly, the above scenario bodes ill for state and local governments seeking
funds. It should be noted that seventeen states have interest rate ceilings on
their tax-exempt general obligation bonds, and these limits are nearly met al-
ready. It should also be noted that it has been suggested that states and local
governments issue taxable bonds to widen their access to the capital markets. It
would seem ironic if states and local governments in the future gained a large
proportion of their external funds in the taxable market while private firms
dominated the tax-exempt market.
Political reality suggests this cannot happen. Indeed it suggests that if state and
local governments make sufficient noise about the potential effects of expanded
use of PCRB's, the PCRB as a financial tool for private industry may be
endangered.
A-56
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On balance, it could well be that private industry will share the disenchantment
that some state and local governments have expressed for the thin, volatile tax-
exempt market. Yield spreads between good-quality corporate bonds and PCRB's
have narrowed considerably in recent years. In future years, PCRB yields could
conceivably rise above some corporate rates. All this suggests that the once
clear financing advantage of PCRB's may only continue to exist under certain
circumstances. Congress may perceive "the problem", for last year it enacted
another method of sharing the pollution control investment burden with tax-
payers by permitting such investments to qualify for both accelerated depre-
ciation and tax credits.
A-57
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APPENDIX B
GENERATING UNIT COSTS OF SO2 AND PARTICULATE CONTROLS
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APPENDIX B
GENERATING UNIT COSTS OF SO2 AND PARTICULATE CONTROLS
The generating unit cost of SO2 control to meet the revised new source
performance standards as a function of the coal sulfur content for a typical new
500 MW plant is illustrated in Table B-l. Cost for the current and the revised
SO2 standards is illustrated in Figure B-l. These costs are for a limestone wet
slurry flue gas desulfurization system having a 90 percent removal efficiency. If
less than 90 percent removal of S02 is required to meet the standard, it is
assumed that only part of the flue gas will be scrubbed".
The costs are based on a plant capacity factor of 0.65 and a capital recovery
factor of 0.15. The energy required to operate the FGD system is included as the
cost of the replacement capacity (and its associated pollution control devices)
needed to provide the energy. Interest during construction is not included for
this simplified cost comparison, although it is in the Utility Simulation Model.
Also, differences in fuel and boiler costs for the various fuel types are not
considered here. This comparison illustrates that based on SO^ control costs
alone the revised new source perfomance standards provide low sulfur coal with
less of a cost advantage than the current new source performance standard.
Table B-2 illustrates the cost of particulate control as a function of the coal
sulfur content for a typical new 500 MW plant meeting an emission limit of
22 ng/J. The costs of meeting the current particulate limit of 43 ng/J and a
22 ng/J limit are illustrated in Figure B-2. The proposed 13 ng/J limit is not
illustrated here. Hot-side ESP costs are shown for a fuel that is a subbituminous
coal or lignite with a sulfur content less than one percent. For all other fuels,
cold-side ESP costs are illustrated. In the Teknekron Utility Simulation Model,
the levelized least-cost particulate control device (ESP or fabric filter) is
selected. In the model, in all cases, fabric filters were selected for use on the
low sulfur Western coals.
B-l
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NJ
Table B-1
Typical Limestone Slurry FGD Costs (1975) for a New 500 Mw Plant Burning
Various Coals
Coal
Type
(Heating
Value
(J/g)
Sulfur
Content
(ng/J)
to Meet a
Capital
Cost
($I06)
90% Removal SO, Standard
Fixed
Operating
Cost
($I06)
Variable Operating
Cost
@CF= 1.0
($I06)
Capacity
Penalty
@ CF = 1.0
(MW)
Bituminous
Bituminous
Subbituminous
Lignite
30,700
25,600
19,800
16,300
455
1,410
350
490
43.25
55.71
42.94
46.08
0.41
0.41
0.41
0.41
7.11
12.89
6.44
7.13
26.9
27.0
28.6
30.7
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Table B-2
Typical Electrostatic Precipitation Costs (1975) for a New 500 Mw Plant Burning Various Coals to
Meet a Particulate Standard of 22 ng/J
Coal
Type
CD ....
CO
Bituminous
Bituminous
Subbituminous
Lignite
Heating
Value
(J/g)
30,700
25,600
19,800
16,300
Sulfur
Content
(ng/J)
460
1,410
350
490
Ash
Content
(ng/J)
1,680
4,030
4,650
4,180
Capital
Cost
($I06)
16.49
1 1 .67
30.74
31.91
Fixed
Operating
Cost
($I06)
1.23
0.89
2.42
2.51
Variable
Operating
Cost
@ CF = 1.0
($I06)
0.05
0.117
0.136
0.122
Capacity
Penalty
@CF= 1.0
(MW)
3.2
2.4
6.0
6.3
-------
3
to
O
U
O
U
LLJ
_
y
i
cc
<
0.
2-
200
i
400
500 MW, 1975 Costs
Midwest Location
0.65 Capacity Factor
Current NSPS Limit = 43 ng/J
Revised NSPS Limit = 22 ng/J
1
NSPS
O
0
A
KEY |
REVISED NSPS
O Bituminous-
Unc leaned
O Subbituminous
A Lignite
600
800
1000 1200 1400 1600
COAL SULFUR CONTENT (ng/J)
Figure B-1 COST OF PARTICULATE CONTROL
USING ELECTROSTATIC PRECIPITATORS FOR
NEW COAL-FIRED UTILITY BOILERS
B-4
-------
1 -
500 MW, 1975 COSTS, MIDWEST LOCATION
0.65 CAPACITY FACTOR
CURRENT NSPS LIMIT = Sttng/J
REVISED NSPS LIMIT = 90% REMOVAL
O Bituminous Cooi
a Subbituminous Coal
A Lignite
600 800 1000 1200
COAL SULFUR CONTENT (ng/J)
Figure B-2 COST OF SO, CONTROL FOR NEW COAL-FIRED
2 UTILITY BOILERS
USING A LIMESTONE FGD SYSTEM
1400 1600
B-5
-------
The basis for the particulate control costs are the same as for the FGD costs,
and operating energy costs are calculated as discussed previously. The cost
comparison illustrates that the type of coal used is as important as the emission
limit in determining particulate control cost.
B-6
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4. TITLE AND SUBTITLE
TLCIIWICAL REKWT DATA
(!'k'o:;c read limlniftions on the jcrmr before coinptrtiiir)
. REPORT NO.
Review of New Source Performance Standards for Coal-
Fired Utility Boilers, Volume II: Economic and
Financial Impacts
7. AUTHOR(S)
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Energy and Environmental Engineering Division
Teknekron, Inc.
2118 Milvia Street
Berkely, California 94704
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Office of Energy, Minerals, and Industry
Office'of Research and Development
Washinaton, 1J.C. 20460
3. Kt-CIPIkNTS ACCb'SSIur+NO.
5. REPORT DATE
_March 1518 .
6. PERFORMING ORGANIZATION COOE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
INK 624
11. CONTRACT/GRANT NO.
68-01-1921
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY COOE
EPA-ORD
15. SUPPLEMENTARY NOTES
This project is part of the EPA-pianned and coordinated Federal Interagency
Energy/Environment R&D Program.
16. ABSTRACT
This two volume report summarizes a study,, of the projected effects of several
different revisions to the current New Source Performance Standard (NSPS) for sulfur
dioxide (SC^) emissions from coal-fired utility power boilers. The revision is as-
sumed to apply to all coal-fired units of 25 megawatts or greater generating capacity
beginning, operation after 1982. The revised standards which are considered are: (1)
mandatory 90 percent S02 removal with an upper limit on emissions of 1.2 Ib SO- per
million Btu; (2) mandatory 80 percent S02 removal with the same upper limit; (3) no
mandatory percentage removal with an upper limit of 0.5 Ib S02 per million Btu. In
addition, effects of revising the NSPS for partic'ulate emissions from the current
value of 0.1 Ib per million Btu down to 0.03 Ib are quantified. Projections of the
structure of the electric utility industry both with and without the NSPS revisions
are given out to the year 2000. Volume 1 discusses air emissions, solid wastes,
water consumption, and energy requirements. Volume 11 discusses economic and
financial effects, including projections of pollution control costs and changes in
electricity prices.
17.
(Circle One or More)
KCY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
li.lDCNTIF-IERS/OPCN ENDED TLRMS
c. COSATI I'icld/Groiip
Earth Atmosphere
Combustion
Energy Conversion
Energy Cycle: Energy
Conversion
Fuel: Coal
97G
13. OISTHIBUI ION STATEMENT
Release to public
19. SECURITY CLASS (Tliis Report)
unclassified
21. NO. Or PAGLS
170
22. P'FUCC ~
unclassified
EPA Form 2220-1 (9-73)
*U.S. GOYB
«TW6 OFFICE: 1978260-880/98
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