Umtrt Suras
Environmanai Protection
Agency
Ottic* of
Policy Analytu
Novimtxr 1982
WMhtngton. DC 20460
230-11-33-001
An Economic Analysis
of the Final Effluent
Limitations, New Source
Performance Standards and
Pretreatment Standards for the
Steam Electric Power Industry
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ECONOMIC ANALYSIS 0? THE
PHIAL EFFLUENT LIMITATION GUIDELINES,
NEW SOURCE PERFORMANCE STANDARDS,
AND PRETREATMENT STANDARDS FOR THE
STEAM-ELECTRIC POWERPLANT POINT SOURCE CATEGORY
Prepared far:
OFFICE OF POLICY ANALYSIS
ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, O.C.
Prepared by:
TEMPLE, BARKER & SLOANS, INC.
33 HAYDEN AVENUE
LEXINGTON, MASSACHUSETTS 02173
November 6, 198 2
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PREFACE
This report has been submitted to the United States
Environmental Protection Agency (EPA) in partial fulfillment
of Contract No. 68-01-5845 by Temple, Barker & Sloans, Inc.
(TBS), 33 Bayden Avenue, Lexington, Massachusetts 02173.
Because of the need to meet the November 7, 1982, court dead-
line, TBS prepared this report on a compressed time schedule
and may make minor corrections to this report at a later date.
However, the substance o£ the analysis contained in this
report (i.e., calculations, assumptions, findings, and conclu-
sions) will not be changed.
TBS appreciates the contributions to this effort which
have been made by Jeffrey Wasserman, Gregory Tinfow, and
Jeannie Austin of EPA's Office of Planning Analysis who have
served as the Agency's project monitors. TBS also acknowl-
edges the work done by EPA's Effluent Guidelines Division and
its technical contractor, the Radian Corporation, in providing
engineering and technical input data for the report.
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COSTENTS
PREFACE i
I. INTRODUCTION I-1
II. DESCRIPTION OP THE. ELECTRIC
UTILITY INDUSTRY II-l
III. NATIONAL ECONOMIC EFFECTS III-l
IV. PLANT-LEVEL AND UTILITY-LEVEL
EFFECTS IV-1
V. COST-EFFECTIVENESS OF THE REGULATIONS V-l
Appendix A: THE ENERGY DATABASE A-l
Appendix B: PTm(ELECTRIC UTILITIES) B-l
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I. INTRODUCTION
This report, prepared by Temple, Barker fc Sloane, Inc.
(TBS), presents the economic analysis of final effluent limi-
tation guidelines, new source performance standards, and pre-
treatment standards being promulgated by the Environmental
Protection Agency (EPA) for the steam-electric powerplant
point source category (hereafter called the "final regula-
tions"). The report describes the costs of the final regula-
tions, assesses the effects of these costs on the electric
utility industry, and examines the cost-effectiveness of the
regulations. It is based on technical findings and cost data
developed by EPA and EPA's technical contractors and on econ-
omic and financial projections developed by TBS. Technical
data used in this report are summarized in the Development
Document for the steam-electric utility industry point source
category.1 The economic and financial assumptions on which
this report is based are described in Chapter II.
The final regulations consist of four separate regula-
tions, each applying to a different class of powerplants.
• Best available technology economically achiev-
able (BAT) regulations for existing powerplants
discharging directly into receiving waters
• New source performance standards (NSPS) for new
direct-discharging plants
• Pretreatment standards for existing sources
(PSES) for existing powerplants discharging to
publicly owned treatment works (POTVis)
• Pretreatment standards for new sources (PSNS)
for new powerplants discharging to POTWs
^United States Environmental Protection Agency, Effluent
Guidelines Division, Office of Water and Waste Management,
Development Document for Proposed Effluent Limitation Guide-
lines, New Source Performance Standards, and Pretreatment
Standards for the Steam-Electric Powerplant Power Source
Category, September 1980, EPA Document Number 440/1-8Q/Q29.6.
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1-2
Eleven major steam-electric industry waste streams are
potentially affected by these regulations:
•
Once-through cooling water
•
Recirculating cooling water
•
Fly ash transport water
•
Bottom ash transport water
•
Low-volume wastes
•
Chemical metal-cleaning, wastes
•
Coal pile runoff
•
Thermal discharges
•
Nonchemical metal-cleaning wastes
•
Flue gas desulfurization wastewater
•
Runoff from materials storage and
areas other than coal piles
construction
The regulatory standards that will apply to these waste
streams after promulgation of the regulations are summarized
in Exhibit 1-1.
While there are four types of regulations and 11 waste
streams involved, only the BAT and NSPS regulations for once-
through cooling water discharges by fossil and nuclear plants
of 25 MW or greater will impose additional costs on the in-
dustry. For plants with less than 25 MW, BAT equals best
practicable control technology (3PT) for chlorine discharges.
The regulations also set standards for toxic pollutant dis-
charges in recirculating cooling water and in fly ash trans-
port water that are more stringent than the standards current-
ly in place. On the basis of a technical analysis, however,
EPA has concluded that these standards will not result in
additional costs for the electric utility industry. The prom-
ulgated standards for four further waste streams—bottom ash
transport water, low-volume wastes, chemical metal-cleaning
wastes, and coal pile runoff—do not impose additional re-
quirements beyond those imposed by the regulations currently
in place. Finally, EPA has reserved four waste streams —
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1-3
thermal discharges, nonchemical metal-cleaning wastes, flue
gas desulfurization wastewater, and materials-handling runoff —
for future consideration.
Electric utilities will not incur additional costs under
pretreatment standards for new or existing sources.* The
chlorine discharge regulations that will require expenditures
at plants with once-through cooling systems do not apply to
plants that discharge to POTWs. The final pretreatment stand-
ards also set limits that are more stringent than those cur-
rently in force for toxic pollutants in recirculating cooling
water discharged to POTWs. These standards* however, are not
expected to result in additional costs for the industry.
Thus, only new and existing steam-electric powerplants
that have once-through cooling systems, discharge directly
into receiving waters, and have capacities of 25 MW or great-
er potentially incur increased costs as a result of the regu-
lations. These powerplants represent approximately 58 percent
of the current capacity of the steam-electric section of the
electric utility industry and 45 percent of the industry's
total capacity. In addition, it was assumed that approxi-
mately 40 percent of new fossil-fired steam capacity and
64 percent of new nuclear capacity may incur increased costs
as a result of the regulations, as they are estimated to have
once-through cooling water discharges.
The final regulations are expected to result in minimal
increases in costs at the national, plant, and utility levels.
At the national level the final regulations will result in
annual costs of $11 million to $12 million per year and in
capital costs through 1995 of $25 million <1982 dollars).
Seventy-seven percent of the increased capital costs and
86 percent of the total increased annual costs through 1995
will be incurred by existing powerplants. These costs for new
and existing plants represent increases of less than 0.01 per-
cent over the industry's baseline. At the plant and utility
levels cost increases for plants larger than 25 MW range from
0.003 to 0.25 mills per kWh. Cost increases incurred by very
small plants with capacities of less than 25 MW could have
ranged from 0.25 mills per kWh to 4.3 mills per kWh. Those
plants, however, have been exempted from the BAT chlorine
limitations imposed today; and BAT and NSPS have been set
equal to BPT for these facilities. Excluding very small
plants, over 90 percent of the electricity generated by util-
ities operating steam-electric powerplants will incur cost
increases of less than 0.05 mills per kWh. This increase
compares to the industry's baseline average consumer charges
of 47 mills per JcWh and 61 mills per JcWh.
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1-4
REVIZW OF THE HISTORY AND SCOPE
OF EFFLUENT LIMITATION GUIDELINES2
EPA first promulgated BPT, BAT, NSPS, and PSNS regula-
tions for 3team-electric powarplants on October 8, 1974. The
1974 regulations covered two basic types of pollution from
powerplants: thermal/ i.e., heat, discharges and chemical
discharges, e.g., chlorine, phosphorous, polychlorinated
biphenyls (PCBs) and suspended solids. Chemical limitations
were specified in the 1974 regulations for the following waste
streams: once-through cooling water, cooling tower blowdown,
bottom ash transport water, fly ash transport water, boiler
blowdown, metal-cleaning wastes, low-volume wastes, and
materials storage and construction runoff (including coal-pile
runoff).
On July 16, 1976, the U.S. Court of Appeals for the
Fourth Circuit remanded the following provisions of the 197 4
regulations: the thermal limitations, the NSPS for fly ash
transport water, the rainfall runoff limitations for materials
storage and construction, site runoff, and the BPT variance
clause. All other provisions of the October 1974 regulations
were upheld.
On June 7, 197 6, a Settlement Agreement was entered be-
tween EPA, the National Resources Defense Council, Inc., and
several other parties which committed EPA to a schedule for
developing effluent limitations for 21 major industries in-
cluding the steam electric utility industry. In partial re-
sponse to the Settlement Agreement, on March 23, 1977, EPA
promulgated PSES which specified effluent limitations for
PCBs, oil and grease, and copper present in metal-cleaning
wastes.
Finally, revised BAT, USPS, PSES, PSNS, and new BCT (best
conventional pollution control technology) were proposed on
October 14, 1980. At that time, EPA also proposed to change
the subcategorization scheme and format of the existing regu-
lations including the applicable BPT effluent limitations.
^The material in this section was drafted by EPA and edited by
TBS.
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1-5
REPORT ORGANIZATION
The economic analysis in this report focuses on thoae
requirements oC the regulations that impose incremental coats
on the industry. Chapter II provides an overall physical and
financial description of the industry. This description forms
the basis for the analysis of the incremental costs of the
regulations in subsequent chapters. Chapter III summarizes
the national economic effects of the regulations and compares
the cost of the final regulations to the cost of the regula-
tions proposed in October 1980. In Chapter IV the costs of
the regulations are evaluated at the plant and utility levels,
identifying increases in consumer charges that are expected
from the final regulations. Finally, Chapter V examines the •
cost-effectiveness of the final regulations promulgated in
November 1982, and compares the cost-effectiveness of these
regulations to that of the regulations proposed in October
1980.
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trfilblt 1-1
nrcmir iiiiurr waste STRrAtc
AND HNAI RrGIILATUAY STANDARDS
Waste Stream'
Tlnal Regulatory Standard
Oice-Lhrough cooling watar^
BAT and NSPSi Daily aaxlaua discharge of total realdual chlorine based on concentration of 0.2 ag/1 at
final dlecharge point| each Individual unit ia not allowed to discharge aore then 2 hours per day unieaa
the discharger denonatrataa to the peralt writer that a discharge for a longer period 1a necessary for
aacrolnvertnbrate control. BAT end NSPS equal BPI for plenta with capacltlee of leea than 25 IK,
Recirculating cooling water'
(cooling tower blowdomi)
BPI, BAT, and NSPS retain existing Units on free avallrfila chlorine based m 0.2 m)/\ average and
0.S ng/l daily nxlwii with aultlunlt chlorlnatlon prohibited. Ths new BAT, NSPS, and pretreataent
atsndarda also prohibit diachargea of 1Z4 priority pollutants in detectri>le aaounta but aalntaln 1974
llalta for chroalua and ilnci the phosphorous Halt Is deleted.^
Fly ash transport water
No BAT or PSCS Halts with the exception of prohibition of PCB dischargee. BAI Halt a fur conventional
pollutanta withdrawn (will be covered by BCI). NSPS and PSNSi larn dlecharge of all pollutante.
Bottoa ash transport watsr
No BAT, PSES, P5NS except for prohibition of PCB dlechargeai NSPS equal to BPI, withdraws 1974
recycle regulreaent.
Low-voIuob wastea
BAT Halts for conventions! pollutants wlthdrawni otherwise rataln existing etandarde while Including
boiler blowdown as a low-voluae waste.
Chaalcal natal-cleaning was tea
Maintain existing BAI, NSPS, PSES, PSNS reflations, except that BAT for conventional pollutanta
withdrawn, final pretreataent atandarde include llalte es aaalaua concentrations of 0.1 ag/1 for
total copper.
Coal pile runoff
Maintain exletlng atandarde but BAT withdrawn for conventional pollutanta.
Thermal discharges
Reserved.
Nonchealcel aetal-cleaning
wastes
Reeerved| were included with aetal-cleaning waates In proposed re^iletlona.
flue gas deeulfurlzetlon water
Heaerved.
Rrnoff froa aaterlels storage
other than coal piles and
construction areaa
Reserved.
'RmI conventional technology (BCI) Is reserved Tor all waste streams| for PSES In all mate streaaa CPA la wltlidrawing the 1977 llalta on oil
and grease discharges. BAT Halts on conventional pollutente are withdrawn sIncs they will be povarad by BCI.
*Thls Halt la leas stringent than the proposed Halt which set a zero discharge except For dischargers tliat could deaonstrata need Tor
chlorinei in no case allowing a TRC discharge or aore than 0.14 ng/l per Z hours par plant per day. Chlorine end zinc discharges Mara
prohibited In the proposal.
'ihe regulations proposed In October 1980 Included nore stringent llalte ui chlorine and a zero discharge standard for chroalua and zinc.
Source: EPA.
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II. DESCRIPTION OP THE ELECTRIC
UTILITY INDUSTRY
The economic and financial effects of the final regula-
tions on the electric utility industry are placed in context
in this report by comparing the expected costs and expend-
itures resulting from the regulations to the costs and expend-
itures the industry will incur independent of the regulations.
These "baseline" costs and expenditures include all costs and
expenditures expected to be incurred by the industry, includ-
ing the costs associated with other existing EPA regulations.^
This chapter presents future estimates of baseline costs and
expenditures, and is organized into three sections: the
current physical profile of the industry, industry growth and
financial assumptions made in developing economic and finan-
cial projections, and the projected economic and financial
baseline of the industry through 1995 as used in.this
analysis.
PHYSICAL DESCRIPTION OF THE
INDUSTRY
By any measure the electric utility industry is large.
The entire industry comprises about 7S0 privately and publicly
owned utilities that operate over 2,600 powerplants. Thirty-
seven percent—956 powerplants—have steam boilers. Of these,
825 have a unit capacity of 25 MW or greater; approximately
131 plants have a capacity of less than 25 MW. Altogether,
these steam powerplants have a generating capacity of
434,915 MW, and in 1979 they generated 2.11 trillion kwh of
electricity.
In the process of generating eletricity the industry
utilizes ever 60 trillion gallons of water per year exclusive
of that used to operate hydroelectric plants. This water is
used for generating steam, for cooling, and for transporting
ash and other wastes. With this level of water consumption
^-The assumptions used in this analysis are consistent with the
assumptions used in another major study by TBS for EPA:
Temple, Barker & Sloane, Inc., Environmental Regulations and
the Electric Utility Industry: An Integrated Overview,
November 1982; that study is referred to here as the MBO.
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II-2
the electric utility industry uses more water than any other
single industrial group in the Onited States. In fact, the
only other economic activity that exceeds the generation of
electricity in terms of water use is agriculture.
As explained in Chapter I, the final regulations will
result in higher compliance costs for only steam-electric
plants 25 MW or greater in size with once-through cooling
systems that discharge directly to receiving waters. There-
fore, the powerplant physical characteristics that will deter-
mine whether or not a powerplant will be affected by the final
regulations are plant type, plant size, and cooling type. The
characteristics of existing powerplants were examined in order
to determine the number and size distribution of powerplants
that could be affected by the final regulations. In addition
to focusing on plant type, size, and cooling type, TBS exam-
ined plant capacity factors. These capacity factors are con-
sistent with those used in generating the technical compliance
cost data. Two data sources were used to conduct this exam-
ination. The first source, the Energy Database, is a compre-
hensive listing of the key characteristics of all powerplants
larger than 25 MM. The Energy Database is described in detail
in Appendix A. The second data source was DOE's Generating
Unit Reference File (GURF) database. This source was used for
data on powerplants smaller than 25 MW and on nuclear power-
plants.
Plant Type
As used in this report, plant type refers to whether or
not the plant is a steam plant. Steam plants use steam to
drive a turbine which in turn rotates an electric power gener-
ator. Steam is generated by the burning of fossil fuels or,
in a nuclear plant, by a nuclear fission reaction. Nonsteam
plants use water, a jet-like engine, or an internal combustion
engine to rotate the generator. with the exception of the
water used to drive the turbine in a hydroelectric plant,
nonsteam- plants use far less water than do steam plants.
As shown in Table II-l, steam powerplants account for
approximately 78 percent of the industry's capacity. Steam
plants are also more intensively utilized than nonsteam
plants, which, with the exception of hydroelectric plants, are
designed to provide power during periods of. peak demand. In
1980 the steam sector contributed 85 percent of the elec-
tricity generated by the electric utility industry.
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II-3
The steam sector of the industry is made up of both
fossil and nuclear plants (Table II-2). Approximately 52 per-
cent of the steam capacity burtas coal as a primary fuel and
uses only small quantities of oil or gas as a starter fuel.
This capacity accounts for approximately 55 percent of total
steam generation. Oil and gas units together make up 37 per-
cent of steam capacity and 33 percent of steam generation.
Units that primarily burn oil contribute approximately twice
as ouch capacity as do gas units, but oil units are somewhat
less intensively utilized.2 Finally, nuclear plants account
for approximately 11 percent of steam capacity and 12 percent
of generation.
T*le II-l
CAPACITY AM) GENERATION OF
STEAM ANO NONSTEAH SECTORS
OF T* ELECTRIC UTILITY INDUSTRY
(year-end 1979)
Capacity Percent of Generation
(MN) Capacity (aillione of kWh)
Percent of
Generation
StflM sector 434,915 7B 2,110,918
Not steaa sector 121,650 22 774,350
85
15
Total
556,565 100 2,485,268
100
Source:
00E, Statistic# of Privately Q»ned Utilities in the United
States—1979: DOE. Statistics of Publicly Owned Utilities
In the United States—1979: OQE. Gas Turbine Electric Plant
Construction and Annual Production Exnensea—1978: DOE.
Updsta—Nuclear Power Proars* Information and Data.
July/
Auquat 1980; DOE. Hydroelectric Plant Construction Coat and
Annual Production Exoenase—1978i TBS/EPA Energy Database.
As one would expect, the increases in oil and gas prices
relative to coal have caused a shift in powerplant fuel types
in recent years. As shown in Table 11-3, the megawatts of new
oil- and gas-fired capacity as a percentage of total new capa-
city declined significantly after 1972. Construction of both
oil and gas units has been for all practical purposes discon-
tinued because of increasing costs and supply uncertainties
for these fuels. Relatively few nuclear units were built
before 1972, and in recent years a combination of factors has
resulted in a decrease in the construction of nuclear units.
^Approximately one-third of the units that are listed as burn-
ing oil or gas in fact burn both fuels, with neither fuel
accounting for more than 95 percent o£ fuel consumption.
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II-4
Tab la 11-2
DISTKIBUTIW OF S TEAM-ELECTRIC CAPACITY
Ut> GENERATOR BY FUEL TYPE
(ya«r-end 1979)
Percent
Cvaeity
Percent of
Generation
of
Fuel Type
(HW)
Caoaeitv
(¦11 lione of *»»)
Generation
Coal
227,019
52
1,153,438
55
011
104,463
24
434,212
2D
Gas
54,33
13
271,276
13
Nuclear
48,104
11
251,992
12
Total
434,915
100
2,110,918
100
Sourest DOE, Statiatics of Privately (hmed Utilities—1979; DOE.
StaUatica of Publicly Owned Utllltlaa—1979; TBS/EPA
Energy Databaaa.
Table II-3
DISTRIBUTION OF STEAN-ELECTHIC
CAPACITY BY WIT ACE
Hoga«etta
(yaar-«id 1979)
In-service
Year
Coal
gil
Gaa
Pre-1972
136,839
28,374
35,745
1972-1976
58,497
18,699
11,522
1977-1979
31,683
10,045
3,744
Total
2Z7.Q19
57,118
51,011
Gaa G«e/011 Nuclear Total
43,905
7,398
MO
51,6*3
7,742
31,192
9,180
48,104
252,605
127,298
55,012
434,915
Nata: Tha DOE atatiatica, which do not coitain a profile of capacity by age
category, and tha TBS/EPA Energy Databaaa do not coincide fully.
Results obtained concerning tha aga profila af stsa* capacity fro* the
Energy Databaaa were adjusted to apply to tha DOE atatiatica.
Sourco: DOE, Statistics of Privately Owned Utilities—1979; DOE, Statistics
of Publicly Owned Utilities—1979; GlHFi TBS/EPA Energy Databaaa.
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II-5
Plant Size and Capacity Factor
Steam-electric unit capacities range from less than 10 MW
for older units to well over 1,000 MW for recent coal or nu-
clear baseload units. The average size of units has increased
over time. Por example, as shown in Table II-4 the average
size of fossil-fired units that came into service before 1972
is just under 130 MW, compared with 474 MW for units built in
1972-1977. This average size has declined somewhat to 397 MW
for fossil units built after 1977. Coal units are generally
larger than other fossil-fired units. Nuclear units are
typically twice as large as fossil units of the same period.
Trtila 11-4
AVERAGE NAtfPLATE CAPACITY
B* UNIT ACE AND RJ EL-TYPE
Unit Fual Typa
Total
Unit Aoa
Coal
Oil
£aa
QsaZJUl,
foaail
Nuclaar
Pra-1972
127
94
112
ioa
129
480
1972-1976
533
401
349
381
474
870
Post-1976
455
470
321
93
397
a 54
Malghtad
Avaraga
Nmplata
Capacity
218
154
140
121
174
767
Sourest TBS/EPA En«rgy Databaaa and GURf.
There are some interesting correlations between plant
size and capacity factor. As shown in Pigure II-l, average
capacity factor increases with plant size. Plants under
300 MW account for 45 percent of all plants, 11 percent of
total generating capacity, and 9 percent of total generation,
with an average capacity factor of 44 percent. Plants from
300 MW to 750 MW account for 30 percent of all plants, 27 per-
cent of capacity, and 26 percent of generation, with an aver-
age capacity factor of 52 percent. Plants over 750 MH make up
25 percent of all plants, 62 percent of capacity, and 65 per-
cent of total generation, with an average capacity factor of
54 percent.
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II-6
Flgis* 11—1
CUMULATIVE DISTRIBUTION OF NUMBER OF PLANTS, CAPACITY,
AND GENERATION BY PLANT CAPACITY
100%
90%
80% -
70% -¦
60%
30% -
390 JO? WW
1.783.833 million kWh
20% -
10% -
0
500
1,000
1J500
2300
Plam Capacity (MWI
10«ta ZS plant! in dw Envvy Sratw arv not rapraaamad in tha n^ira, linw rhilM plana did net
raport urat-waaiHo capacity wd ganaraUon 6rta.
Sourm: Ena>w Dttabaaa.
Very small powerplants (less than 25 MW) have much lower
average capacity factors. As can be seen in Figure II-2, over
half of these plants have capacity factors of less than
20 percent.3 The 131 plants smaller than 25 MW have an aver-
age size of 15 MM and a total capacity of only 2,000 MM
(0.5 percent of total generating capacity). The reason for
the low capacity factors among these very small plants is age.
They are on average much older than the larger plants and
therefore less efficient and reliable. Figure II-3 presents
an age distribution of the very small powerplants. As the
^Generation data on very small powerplants are not always
available. Operating data on about 25 percent of these
plants were used as a sample to determine the distribution of
capacity factors among these plants.
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II-7
Flflur* 11-2
Ptreant of
Sampla
40% -i
30%
20%
10% -
DISTRIBUTION OF CAPACITY FACTORS FOR SAMPLE
OF VERY SMALL UTILITY PLANTS
V.'.v>.v,,,,.,.snv/AsV
;
•5
* V*v
»^ <¦ :•:<»;•:¦
>
~n0m$
fc.
<10
11-20
31-40
aV- - ¦*;
>40
Scan: TBS
B9Wi WWBn IMoQtin-MIU. 1880)
21-30
Capadty Factor (%)
Wortd- Plrtnorv qf tfoffft Vfflftiw 1WC-1981.
25% -%
Figure 11—3
DISTRIBUTION OF SMALL PLANT CAPACITY
BY IN-SERVICE DATE
PtfCBfTt Of
Capacity
20% -
15%
10%
5% -
< y>V
o'
Bator* 1948- 1981- 1966- 1961- 1966- 1971- 197*
1945 1950 19ffi I960 1965 1970 1975 1980.
In-Sarviea Yaar
Sourw: DOE OURF; DOE. Irwmorv at Powr Plprt, in th» Umt— Stwar, 7MO Anmrnt IJuim 19811.
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II-8
figure shows, more than half of all of the plants were built
before 1955, and many before 1945.
Cooling Type
The type of cooling system used by a powerplant is an
important determinant of the magnitude of the plant's effluent
discharge. Plants with once-through cooling systems continu-
ally discharge all water used for cooling. Plants with
closed-cycle cooling systems discharge only a very small por-
tion of their cooling water, and recycle the remainder. Only
plants with once-through cooling systems will be affected by
the final regulations.
Examination of the Energy Database and GURF indicates
that 58 percent of existing steam-electric powerplants use
once-through cooling systems. Future powerplants were assumed
to use the same mix of once-through and closed cycle cooling
systems found on powerplants built between 1977 and 1979, the
last three years for which there are reliable data. Forty
percent of future fossil capacity and 61 percent of future
nuclear capacity was assumed to be equipped with once-through
cooling systems.*
Technical analysis by EPA indicated that 71 percent of
the powerplants with once-through cooling systems chlorinate
and will therefore have to taJce some action to comply with the
final regulations. Approximately two-thirds of this capacity
is expected to comply using chlorine minimization, while the
other third is expected to use dechlorination.
INDUSTRY GROWTH AND
FINANCIAL ASSUMPTIONS
To determine the future size and spending level of the
electric utility industry, TBS made assumptions regarding
growth in energy demand, capacity additions, and generation
levels, cost factors, and accounting policies. The assump-
tions are described below. These assumptions are consistent
with the assumptions made in previous reports to EPA cited in
Chapter I.
4This is a more conservative assumption than that used in the
analysis prepared for the Utility Water Act Group: National
Economic Research Associates, Inc., Economic and Financial
Impacts of EPA's October 14, 1980, Proposed Regulations,
January 18, 1981.
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II-9
Electricity Demand
Since 1973, there has been an abrupt shift in demand
growth patterns. As indicated in Table II-5r in the 1960s and
early 1970s demand grew consistently at a high rate. This
growth rate shifted to a lower and more volatile growth
pattern in the period since the 1973-1974 Arab oil embargo.
The shift in the pattern of growth has been brought about
by dramatic changes in the underlying structure of demand.
Disruptions in the historical relationships among electricity,
other energy, and all other prices—and consequent changes in
consumer behavior and in the availability of conservation and
load management equipment—maJce it increasingly difficult to
forecast accurately future levels of demand. As shown in
Table II-6, there has been a significant reduction in the
growth of average consumption per customer over the 1960-1979
time period. This reduction represents the effect of signifi-
cant conservation efforts which include reductions in thermo-
stat settings, more energy-efficient homes, offices, and fac-
tories, and more energy-efficient appliances.
Since 1974, many industry observers have consistently
overestimated future demand, and the forecast used in this
study could also represent a high-side projection. However,
the projection of growth of 3.0 percent per year to 1990 cor-
responds closely to many other industry projections. Other
widely circulated forecasts range from 2.8 to 4.3 percent per
year (Table II-7). If actual demand is lower than projected,
the total baseline and pollution control costs identified in
this study will be conservatively high. These estimates would
of course prove to be too low if growth outstrips the MBO
report projections.
Capacity and Generation Profiles
The capacity and generation projections used in this
study are based on the requirements implicit in the electric-
ity demand estimates. This section presents forecast changes
in capacity by fuel type and in generation required to satisfy
demand.
As shown in Figure II-4 and described in detail in Exhib-
it II-l, the contribution of coal and nuclear plants to total
capacity is expected to increase dramatically in the future.
Coal's contribution to total capacity is expected to increase
from 41 percent of the total in 1980 (54 percent of steam
capacity) to 61 percent by the year 2010. Oil and gas
-------
11-10
Table II—5
HISTORICAL
IN PEAK
AND FORECAST ANNUAL GROWTH
DEMAtt AND ENERGY SALES
Total Electric Utility Industry
1960-2003
Year
Annual
Growth in Peak Daavid
In Kilowatta
(osrcant)
Annual
Growth In
Kilowatt-Hour
Salaa
(percent)
1961-1963
Growth Rata
7.0
4.7
1965-1966
1966-1967
1967-1968
1964-1969
1969-1970
1970-1971
1971-1972
1972-1975
9.2
5.0
11.5
8.3
6.6
6.4
9.3
7.8
6.9
9.0
6.5
8.6
8.7
6.4
5.4
7.6
1966-1973
Growth Rata
8.1
7.1
1975-1974
1974-1975
1975-1976
1976-1977
1977-1978
1978-1979
1.6
2.2
4.0
6.9
3.0
0.9
-0.6
1.5
6.3
5.1
3.5
2.9
1973-1979
Growth Rata
3.4
3.1
1979-1990*
Growth Rata
3.0
3.0
1990-1995
Growth Rata
3.0
3.0
1995-2005
Growth Rata
3.0
3.0
*Baaad on 1979
aalaa of 2,071!
peek deasid or 409,000 wm
.3 billion kilowatt-hours
jewatta aid
•
Sourcei forecast* provided by CPA.; Ediaon Electric
Institute. Statistical Yearbook of the
EJleetric Utility Industry. 1979
•
-------
11-11
Tabla II-6
wren or cusTtjicfts avejusz kilo matt-hour
USAGE PER CUSTOMS
Total Elactrlc Utility Industry
1960-1979
Yaar
Total Cuatisara
ktth ami CuatoaMr
1960-1963
Growth Rat*
+Z.2S
*4,78
1966
66,910,01]
15.67B
1967
68,168,000
16,384
196B
0,716,000
17,445
1969
70,929,000
18,563
1970
72,485,000
19.3BO
1966-1970
Growth Rat*
+2. OS
*5.43
1971
74,265,000
19,956
1973
76.150,000
20,964
1973
78,461,000
21,955
1974
80,102,000
21.448
1975
81,845,000
a,417
1971-1975
Growth Rata
+1.85
1976
63,613,000
22,361
1977
as. 90,000
23,052
1978
57,668,000
23,315
1979
99,514,000
23,454
1976-1979
Growth Data
-Z.3S
*i.6k
Sou re#: EE1,
Statistical Yearbook
of tha Elactric
Utility Induatry. 1979.
capacity ia projected to decline over the same period from 29
to 6 percent of total capacity aa existing units are retired
and replaced with coal and nuclear units, and as some existing
oil units are converted to coal. Nuclear power is assumed to
contribute significantly to new generation capacity, moving
from 9 percent of total capacity in 1979 to 15 percent in
2010. Many of the additions to nuclear capacity are expected
to occur in the post-1990 period, reflecting the assumption
-------
11-12
Tabl* II-7
CDHPARISW Of FORECAST ANNUAL
GROWTH IN ELECTRICITY OEMAM)
1979-1990
(parcant)
1979-1990 Average *nual
Sourco Grtwrth in Electricity Demand
EPA1 3.0
Data Reaourcea, Inc. 2.8
Energy Information A4iinistratian 3.2
Elactrlc Poner Research Institute 3.5
Ediaoi Elactrlc Institute 3.2-4.3
Electrical Xorld 4.2
^-Projection used In thii study.
Source: EPA; Data Raaourcea, Inc., &2£SX_SS^ilS.< Nintar 19B0|
DOE. 1979 Annual Report to Cororeaa. Vol lob III (prelimi-
nary); EPRI Planning Oirector, reported in Electrical
Weak. April 20, 1981; EEI, Ecorwic Growth in the
Future. Hay 1980; Electrical World. September 15, 1980.
that many of the current regulatory and financial barriers to
new nuclear plant construction will be overcome. Hydro and
pumped storage capacity additions are also expected to occur;
however, their contribution to total capacity is expected to
decline over the period from 13 percent in 1980 to 9 percent
in 2010. This decrease reflects the depletion of readily
available- sites for the construction of such facilities.
Industry reserve margins shown in Table XI-8 are expected
to decline from their current very high levels. The reserve
margin is a measure of the relationship between total capacity
and peaJc demand. Typically, utilities attempt to maintain re-
serve margins of roughly 20 percent to ensure system reliabil-
ity in the face of demand uncertainty and generator "downtime"
for maintenance or forced outages. The current excess reserve
margin situation is due to the recent falloff in demand and
the rise in oil prices. Because of ten-year (or more) con-
struction lead times, many units were and are being completed
because completion is economically preferable to stopping con-
struction already underway. Also, the rise in oil and gas
-------
Figure 11—4
DISTRIBUTION OF GENERATING CAPACITY BY FUEL TYPE
ieHa-2010
100%
sox
80% —
70%
60%
60%
IC/GT
Nuclear
i*i±ZLi'^vV. ^:,--y. y.; ¦ / s / / /////////////
Wm&i:
;»>&¦&£?
isfcii
:«:<•:«
wmWw^M
mm
iVA
S!>»»
40%
30%
20%
10%
2006
2010
&OU"* r^fj?Q?»'«5»'Wlk. In >h« U S 1»7» DOE/EIA Suiljlkjol
-------
11-14
prices-has resulted in many units that are technically opera-
tional and are therefore included in the industry's capacity
figures but are economically obsolete. These units are still
included in available capacity but are not fully utilized or
are held in reserve. Therefore, reserve margins are expected
to decline as oil and gas units are retired and as demand
catches up with existing capacity.
Tab la II-4
SELECTED DEMAND, ENERGY, ANO CAPACITY STATISTICS
Total Electric Utility Industry, 1960-1999
C^aclty at
1960-1979
Tiaa of SiHar
Nvicaincidant
Output
Raaarva
C^aclty
Load
Paak Load
Subit Pa*
{kMh in
Margin
Factor
F actor
(WW)
Load (HW)
¦illione)
(oarcsnt)
(oercant)
(pareant)
1964
240,700
203,350
1,152,900
18.4
54.7
64.7
1967
257,950
213,450
1,221,500
20.8
54.1
65.3
I960
278,950
238,000
1,327,200
17.2
54.2
63.5
1969
300,300
257,630
1,446,000
16.6
55.0
64.1
1970
326,900
274,650
1,536,400
19.0
53.7
63.9
1971
353,250
292,100
1,617,100
20.9
52.3
68.2
1972
381,700
319,150
1,752,200
19.6
52.3
62.5
1973
415,500
343,900
1,868,800
20.8
51.3
62.0
1974
444,400
349,250
1,871,700
27.2
48.1
61.2
1975
479,300
356,800
1,919,500.
34.3
45.7
61.4
1976
498 , 730
370,900
2,039,500
34.5
46.7
62.6
1977
516,000
396,350
2,132 , 300
30.2
47.2
61.4
1978
545,700
406, t»0
2,218,700
J3.7
46.4
62.1
1579
560,200
411,550
2,266,500
36.1
46.2
62.9
1985
604,600
488,400
2,716,500
23.8
51.3
63.5
1990
675,400
566,200
3,149 , 200
19.3
53.2
63.5
1995
769,100
656,300
3,650,700
17.2
54.2
63.5
1999
965,300
738,700
4,108,900
17.1
54.2
63.5
Soureaj EEI, Statiatical Ysarfaoofc of thm Electric Utility Industry. 1979;
PTs(Electric utilitiaa).
For many of the same reasons cited above, capacity fac-
tors are expected to reverse their downward/ trend and eventu-
ally reach levels approximating those that existed before the
1973-1974 oil embargo. The data in Table II-9 clearly indi-
cate the increasing reliance on coal and nuclear for the bulk
of the country's generation needs. The relatively low 197 9
-------
11-15
nuclear'utilization factor reflects in part the effects on the
operations of numerous plants across the country of the
nuclear plant mishap at Three Mile Island. Oil and gas capac-
ity utilization is expected to decline dramatically because of
continually rising fuel costs.
Tab la II-9
PROJECTED CAPACITY UTILIZATION
FACTOIS BY FUEL TYPE
1979-2005
(parcont)
Internal
Piaipad
Cfhuatlon/
Coal
011
Nuclaar
H^dgo
Storaae
Gas Turblna
1979
54.0
47.0
57.0
59.8
52.0
52.0
6.9
1985
61.6
42.3
42.3
70.8
48.2
48.2
6.6
1990
61.5
41.4
41.4
71.2
48.0
48.0
7.5
1995
61.5
36.7
36.7
71.3
47.8
47.8
7.6
2000
60.9
28.6
28.6
71.4
«6.3
46.3
5.0
2005
59.9
24.0
24.0
71.6
45.6
45.6
5.0
SourcB: EPA; IXK, Gaa Turbina Elactrlc Plant Construction Cost and
Annual Production Expanse*—1978: DOE, Updata—Huclaar Po»ar
Proqra* Information yia Data. July/Auguat 198Qj 00E,
Hydroelectric Plant Construction Coat «nd Annual Production
Expanaaa—1978: TIE/EPA Energy Databaaa.
Cost Factors
This section outlines the estimates of new plant capital
costs, fuel costs, and nonfuel operation and maintenance c.osts
used in this analysis. These costs, combined with the pro-
jected growth in the industry described above, provide the
information necessary to estimate changes in the industry's
financial profile over time.
Unit construction costs for the electric utility industry
have increased significantly in the.past decade and are pro-
jected' to continue to escalate more rapidly than the general
rate of inflation. The causes of recent and projected con-
struction cost increases include inflation in the cost of
labor and materials, increases in the complexity of generating
units, licensing delays, slippage in construction schedules,
and the cost and difficulty of financing. The unit costs
-------
11-16
assumed in this study ar« listed in Table 11-10 by plant type,
both including and excluding AFDC and pollution control costs.
These costs reflect an in-service date of 1979 expressed in
1982 dollars and are based primarily on data published by the
Electric Power Research Institute.
Trials il-io
fCX PUNT CONSTRUCTION COSTS1
BY FUEL TYPE
(1982 dollars par kilowatt)
Capital Coat Caoital Cast
Including AFDC' and Excluding AFDC and
Fual Typa Pollution Control Capital Coat Pollution Control Capital Coat-
Cosl3
1,283
903
Oil3
041
693
Gas3
533
479
Nuclear-'
1, J75
1,124
Hydro4
1,996
1,739
Punned storage3
947
906
Internal combustion/
gss turbine
290
ZB1
Transmission and distribution^
427
383
Nuclear fuel6
38
30
losl conversion^
277
96
^Costs are reported for a 1979 in-servic* year axprasaed In 1992 dollars.
2Assunss the AFDC rata of 8 percent for data derived fro® CPRI; otherwise the AFDC
reta is baaad on the weighted coat of capital.
'ePRI, Technical Asssss—nt Guide. July 1979. (Costs «ers inflatsd fro* 1978 to 1979
dollars using the Handy Whitman Index J
4C. D. Mar lor, Saall Scale Hydro Power; Economic and Financial Analysis. BSLES-ASCE
Hydra Lecture Seriaa for 1990.
^00£, Statistics of Privately Owned Utilities in the United Statas—1979.
6 [XX, Updats—Ngclssr Power Proqraa Information and Data. July/August 1980.
7TBS aatiiaats baaed on review of utility coal conversion plans for units Identified
by DOE as csndidataa for required reconversions and an information provided by EPA.
Sourest EPR1, Technical Assessment Guide. July 1979.
The cost of new coal capacity has been estimated bv vari-
ous sources at $1,025 to $1,385 per JcW in 1982 dollars,' a
^Electrical World, September 15, 1979, reports the costs of
coal capacity in 1979 dollars at $766 par kw and nuclear at
[Footnote continued on next page]
-------
11-17
range that captures the $1,283 per IcW estimate used in this
study. The cost of nuclear capacity has been estimated by
other sources at between $1, 385 and $1,449 per IcW, a narrow
range slightly above the cost of $1,375 per lew used in this
analysis.
Fuel costs represent the largest component of total oper-
ation and maintenance costs. Figure II-5 depicts the rapid
rise of fuel costs over the period 1960-1980. The impact of
the 1973-1974 Arab oil embargo is clearly evident. However,
the data also reflect the ongoing efforts of electric utili-
ties to shift from oil to lower-priced fuels, primarily coal.
Current expectations are that the rate of increase in
energy prices will slow (or even decline in real terms) in the
short run. However, over the entire forecast period energy
prices are expected to continue to escalate. Figure II-6
shows price projections for the major fossil fuels. As is
evident from the figure, the price advantage of coal over
other fuels is expected to grow over time. Because of limita-
tions on the use of natural gas, the existence of price con-
trols, and the current surplus situation, it is expected that
the price of natural gas will follow that of high-sulfur
residual oil throughout the forecast period.
Given fossil fuel prices, total operation and maintenance
costs can be derived as the product of fuel prices, heat
rates, and generation requirements plus nonfuel operation and
maintenance costs. It was assumed that the average heat rates
(not including energy penalty effects) for existing units
would approximate actual 1979 levels and that capacity addi-
tions would be more efficient. The average heat rates in
terms of Btu required per kwh of production are presented in
Table 11-11. Finally, future nonfuel operation and mainte-
nance costs were assumed to be the same in real dollars per
kWh as they were in 1979 (Table 11-12).
[Footnote continued from previous page]
$1,035 per JcW in 1979 dollars, which translate in 1982 dol-
lars to $1,025 and $1,385, respectively. ICF, Inc., Alterna-
tive Strategies for Reducing Utility SO? and NO„ Emissions,
June 1981, reports capital costs (in 1979 dollars) of coal at
approximately $800 per JcW, which excludes the cost of a
scrubber, estimated at $165 per kW, and of nuclear at $1,083
per kW and which translates to $1,272 per kW for coal plants
and $1,449 per )cW for nuclear plants in 1982 dollars. Coats,
however, may reflect different in-service date, pollution
control, inflation rate, and AFDC rate assumptions.
-------
11-18
Figure 11—6
AVERAGE INDUSTRY FUEL COST PER NET KILOWATT-HOUR
TOTAL ELECTRIC UTILITY INDUSTRY
1960—1980
1980-
1961
1982
1963
< ^
1964
j, * *
1966
1966
1967
1968
1969
-27
1970
J1
1971
1972
1973
1974
1975
1.12
V
1976
1977
1978
133
V <
1979
1980
Z.03
s. f-
1 2 2 A S A .7 A 9 1.0 1.1 1.2 1J 1.4 13 1A 1J 1J 1J 2.0 2.1
CENTS PER KILOWATT-HOUR
MianMB nm cimm trvawu* Jinyff uhmmb tw*
-------
11-19
Figure 11—6
PROJECTED FUEL PRICES
1979-2005
•40 -
DOLLARS
PER
MILLION Btu on
(CURRENT
DOLLARS)
$10
DISTILLATE OIL
RESIDUAL OIL
J t NATURAL OAS
COAL
1990 199S 2000 2005 2010
MOT*: PriM lui^i imp Mhr prwafcam _
Sauna: DOE/11A Cam, h Qu^Hv f fuih for 8kBP* LWlHv DOMIA Cl * Qmthr of Em* tor
H«ctrf UtHlty PUms-1980: ratf yvanh iwtm mn lammx br EPA. and phi vara MftaM » nomuMl
dollw u—* TBS imijiwt ONP Mtacar.
-------
11-20
Table 11-il
AVERAGE >CAT RATES1
(Btu per kilowatt -tour)
Unit Tvoe
Exiating
l>ilt a
Capacity
Additiona
Convwntiorml ataaa-aiactric
urvita
Coal-Fired
Oil -fired
Gae-flred
10,000
10,077
10,593
9,700
9,600
9,200
Internal ctsbustion/gaa turbine
14,200
12,500
Iflaported heat ratM do not reflect energy penaltiee
resulting fro® pollution control equipment.
Source: T8S/EPA Energy Database* EPA.
Financial and Accounting
Assumptions
This section briefly describes the assumptions and input
data concerning financial policies and costs employed in de-
veloping industry projections using the Policy Testing model
PTm(Electric Utilities). PTm (described in Appendix B) was
used to project industry costs and financial requirements with
and without the final regulations. The paragraphs that follow
first describe the input data used to arrive at the baseline
projection and then present selected financial assumptions
used in PTm.
While providing essentially the same electric service,
the public segment of the industry, which is owned by federal,
state, or local governments, and the private segment of the
industry, which is owned by stockholders, need to be treated
separately because they differ significantly in their finan-
cial characteristics. The private segment of the industry
accounts for 90 percent of total assets while the public seg-
ment hold the remaining 10 percent. In terms of generating
capacity, generation, direct costs of new capacity additions,
and operation and maintenance costs, the publicly owned sys-
tems account for approximately 22 percent of the U.S. total,
-------
11-21
Table 11-12
1979 OPERATION AM) MAINTENANCE
EXPENSES BY FIEL TWt
WUEL AW FUEL UPENSC5
(¦ilia par kilowatt-hour In 1979 dollars )*
Ncnfuel Expeneee
With
Without-
Pollution
Pollution
Fuel Expeneee*
Fuel Type
Control
Control
Coal
2.57
1.90
11.25
Oil
2.37
2.17
22.07
Gm
2.57
2.3U
lfl.54
Nuclear
6.77'
4.01
Hydro
2.05
2.05
N/A
Pueped storage
2.05
2.05
N/A
Internal combustion/
fee turbine
9.25
9.25
57.OB
Transmission, distribu-
tion & other expeneee
5.03
5.03
N/A
N/A r Mat applicable.
^Figurea an ba Inflated to 19B2 dollars uaing tha GNP inflator
projactiona in Tabla 11-14.
2Ooe» not includa coata associated with a sulfur preaiua or
¦nergy penalty. Thaaa coata ara added In the analysis of
pollution central coats.
'includee tha coat of nucleer decOMieaioning.
Sourest DOE, Stat^8t4£a_of_2rivjtg^_0gj^-Jfti^ltija_iin^ha->lJU^Bd
Stataa—1979; OQE, Coat and Quality of FueH for Qactrlc
utility Plants—1979; TBS.
while investor-owned systems account for the remaining 78 per-
cent. Because the privately owned systems have higher financ-
ing costs and tend to have a low percentage of relatively
inexpensive hydroelectric generation, they account for 88 per-
cent of total industry revenues. TBS used these percentage
distributions to extrapolate a total industry beginning
balance 3heet and income statement from available data for the
privately owned portion of the industry. Changes to tha pub-
licly owned segment attributable to environmental regulations
are modeled in the same manner as for the privately owned
-------
11-22
segment but take into account the differences in fuel type
between public and private sectors.6
A major input to the baseline financial projection is a
set of 1979 balance sheet items. Table 11-13 indicates the
data used, including the value of pollution control equipment
other than that required by the promulgated regulations.
The projections used in this study presume a continuation
of different rates of inflation for the various cost compo-
nents. Those rates are provided in Table 11-14 and are de-
rived primarily from information provided by Data Resources,
Inc. Note that the projected rates of inflation applied to
utility plant capital costs continue to be above the projected
rate of growth in GNP. Pollution control capital costs are
assumed to rise more slowly than the general inflation rata.
If the rate of increase in pollution control capital costs is
closer to or above the rate of growth in GNP, the relative
effect of pollution control equipment cost will be increased.
PTm also uses a number of financial indicators, ratios,
and percentages in making projections. Table 11-15 provides
data on 1979 actual returns and projected returns on various
forms of capital. With regard to the cost of equity, it was
assumed that regulators will in the future allow average con-
sumer charges per kWh that yield returns consistent with in-
vestors' required rates of return. Although these returns
generally have not been realized in the past decade, recent
indications are that regulatory agencies are beginning to
adjust allowed returns upward in response to the industry's
manifest financial difficulties. The input data reflect this
assumption. If returns do not increase relative to underlying
rates of inflation, the industry is likely to be unwilling or
unable to meet its projected external financing needs. Under
such conditions, both pollution control-related and other
expenditures for plant in-service will be reduced.
In projecting external financing, the PTm relies on in-
puts specifying proportions of common equity, preferred stock,
and long-term debt. As the data in Table 11-15 indicate, the
proportions set for 1995—40, 10, and 50 percent, respective-
ly—are very similar to the proportions actually experienced
by the industry during recent periods.
^Because nonsteam plants are more prevalent among publicly
owned systems, these systems will be less affected by the
promulgated regulations than the privately owned systems.
-------
11-23
T abls
11-13
U.S. PRIVATELY OWED ELECTRIC UTILITIESi
ELECTRIC PLANT LOfC-TEW ASSETS AND LIABILITIES
WITH mD WITHOUT POLLUTim CMTROL EOUIPtOT1
as or rcaxflQ 3i, 1979
(Billions of 1979 dollar*)2
Lona-Tani AjMta Aiggoints
With Pollution Without Pollution
Control Eouioeent Control Eouioasnt
Gross plant in-aarvlca
- Accuaulatsd daprociatlon
182,514 177,966
47,608 46,98
Nat plant ln-aarvtea
* Nuclaar fual (nat)
* Construction mrk in prograaa
134,906 129,668
3,713 3,715
53,991 48,044
Nat Elactric Plant
192,612 181,427
Lana-Taw Liability Accounts
Long-tarn dsbt
Prefarrad atodc
Ownara' aquity
90,499 88,365
22,284 21,758
67,741 66,144
Total Capitalization
180,524 176,267
Dafarrad itama
DaTarrad ITC
13,170 12,859
6,318 6,169
Total Long-Ten Li^ilitiaa
200,012 193,295
*Ineliriaa pollution control aquip—nt inatallad a af Dscsabsr 31, 1979.
^figure* cai ta inflated to 1982 do 11 an uaing (MP inflater projsctions in
Tab la 11-14.
Sourest DOE. Statiatiea of Privately Qwnad Utilitiaa in tha Llnitad Stataa—
19791 TB5/EPA Enargy Oatabass.
Internal casta generation in an industry as capital-inten-
sive as the electric utility industry depends importantly upon
the accounting procedures employed. As previously mentioned,
this analysis assumes'that the electric utility industry is
segmented into public- and investor-owned firms. The latter
group o£ utilities is further divided into those that are
required to use flow-through accounting procedures and those
that normalize their tax expenses. These alternative regula-
tory accounting practices significantly affect reported
expenses and revenue requirements, but they typically do not
affect actual taxes paid.
-------
11-24
Tabla 11-14
PflQJECTED IfTUlTIW RATES
1579-2007
Amual Utility Conatructlon Coat Inflation Rata*
Annual OF Pollution Control
Yaw
Inflation Rata^
Utility Plant
Eaulowant
Nuclear Fuel
1979
8.5*
9.7*
6.5*
IB.5
1980
9.0*
9.B*
6.5*
19.1
1961
8.7
11.1
7.3
IP.9
1982
8.2
9.7
7.2
19.7
1983
8.5
ID. 9
7.7
19.3
1984
9.1
12.5
7.9
19.2
1985
10.0
13.5
9.1
19.4
1986
9.5
11.8
9.0
12.9
1987
8.9
9.7
8.7
12.2
1988
8.1
8.8
7.7
U.6
1989
8.1
10.9
7.3
12.0
1990
8.5
11.9
7.5
12.3
1991
8.4
10.7
7.6
9.S
1992
8.0
8.6
7.2
8.9
1993
.7.4
B.4
6.5
8.4
1994
7.9
10.4
6.5
8.8
1995
9.0
10.2
6.7
9.8
1996
7.9
8.9
6.8
10.2
1997
7.3
7.8
6.a
9.7
1998
7.6
9.4
6.3
9.9
1999
7.6
9.4
6.2
9.9
2000
7.4
8.3
6.3
9.7
Z0Q1
6.9
7.1
6. a
7.7
2002
7.2
a.6
5.8
7.9
2003
7.3
8.5
5.0
7.8
2004
7.0
7.4
5.9
7.7
2005
6.4
5.8
5.7
7.8
2006
6.5
5.a
5.8
7.8
2007
6.6
5.8
5.8
7.8
lllaad Tor nonfual and pollution control operation and Mlntananca axpanaaa.
"Actual.
Sourcs: Data Raaourcea, Inc., U.S. Long Tera Review. Tall 1981; Handy
Whitwan Inda» of Public Utility Conatructlon Co at8 projected
by TBS ualng data provldad by Data Roaoureea, Inc.; ODE.
Preliminary 1985. 1990. 199? Energy Forecast for Annual Report
to Congraea. 19801 HE, Argdjjai£^f_JJs£J_Ni£laar_P2J«er_Plarrt
Production Coata for 1979.
-------
11-25
T*l» II
>13
FINANCIAL AS51M»TI(MS
(percent)
*
1979
1983
1W0
1995
Intarewt rati, long-tar* debt
7.6
12.6
11.3
10.3
Return an equity
11.2
15.6
14.3
13.3
Dividend payout ratio
75.0
75.0
75.0
75.0
Dividend rata, preferred stock
9.0
12.6
11.3
10.3
Caoltal Mix
Pit) lie aector
financing frea in tarn •! aourcaa
40.0
40.0
40.0
40.0
Private sector
Cjwun. equity
37.5
40.0
40.0
40.0
Preferred stock.
12.4
10.0
10.0
10.0
Long-tar* debt
50.1
50.0
50.0
50.0
Tax Rataa
Federal incoae tax
46.0
46.0
46.0
46.0
Stata incaaa tax
4.6
4.6
4.6
4.6
Other taxes on operating
revenues
7.6
7.6
7.6
7.6
Investment tax credit
10.0
10.0
10.0
10.0
Plant eliQibla for inveataant
tax credit
66.6
66.6
66.6
66.6
Source: DOE. Statistics of Privately Owned Utilities in
the
LtMtad States—197?; TBS.
The tax expense used by regulators in setting rates for
consumers is not necessarily the same as the taxe9 paid by a
utility. Utilities have the option, as do most companies, of
using either accelerated depreciation or straight-line depre-
ciation in determining their tax liability. Over the life of
an asset, the same taxes are paid regardless of which method
is used. Host firms use accelerated depreciation, however,
because it postpones tax payments. When a utility uses accel-
erated depreciation to determine its tax expense, and its con-
sumers are charged for a tax expense based on straight-line
depreciation, the tax benefits of accelerated depreciation are
said to be "normalized." Under these circumstances, the
-------
11-26
direct beneficiaries in the short run are the utility stock-
holders. If, on the other hand, rates for consumers are based
on the tax expense actually incurred by the utility, the tax
benefits of accelerated depreciation are said to be "flowed
through" to current consumers.
The financial ratios and rates shown in Table 11-15
assume a continuation of the industry's current regulatory
accounting practices. In particular, it is assumed that 30
percent of the investor-owned utilities will continue to util-
ize flow-through accounting, while 70 percent will use normal-
ized accounting. Based on observed rates of return these
rates are projected to be 0.5 percent lower for the normalized
sector of the industry than for the flow-through sector. For
regulatory and financial accounting purposesr TBS assumes
straight-line depreciation over the life of the plant. For
tax purposes, depreciation figures are based on the asset
depreciation range and the double-declining balance deprecia-
tion provisions within the tax code. An exception to the
above is nuclear fuel, which is depreciated on a four-year,
straightline basis for both tax and regulatory purposes. In
addition, a 10 percent investment tax credit is permitted on
66 percent of capitalized expenditures. The financial assump-
tions do not reflect recent changes in the tax code that allow
for more rapid depreciation of most classes of equipment.
The final area to be reviewed in this section is the
timing of construction expenditures for a given capital proj-
ect. The timing of construction expenditures is a key deter-
minant in the calculation of construction work in progress
(CWIP) and allowance for funds used during construction
(AFDC). The percent of the total construction budget spent
for each of the six years prior to completing the project is
shown in Table 11-16.
-------
11-27
r*i» ii-ls
PATTERN Of CASH FLOWS FOR CAPITAL PROJECTS:
ANNJAL EXPENDITURES OF RjfCS (EXaUDIfC AFDC)1
FTJR YEARS PRIOR
TO AM)
inclining me
IN-SERVICE YEAR
(percent per
year)
%
. T
In-Service
Capital Protects
T-6
T-5
T-A
T-3
T-2
r-i
Year
Foaail ateaa plants
4.0
1.1
7.2
28.3
41.9
15.0
2.0
Nuclear plants
13.0
20.0
25.0
15.0
15.0
9.0
1.0
Nuclear fuel
-
-
-
-
25.0
25.0
50.0
Hydra plants
9.9
13.5
17.9
18.9
Z3.9
11.6
4.3
Piujied storage plants
9.9
13.5
17.9
13.9
23.9
11.6
4.3
Internal caabuatlcn/gM tucbLn*
plants
-
-
5.0
5.0
a.7
59.0
22.3
Tranaaisaivt and dlatributlon
-
-
-
-
-
50.0
50.0
Pollution control coital equipwt
-
-
-
10.0
30.0
40.0
20.0
lPTai liaits tha potential conetrviction periods to sevan years. However, slight adjustments
wre aade to produce the appropriate Mounts of CWIP AFDC over th« tern of the project
Mher* lead tioea an expected to exceed seven yeen.
Source: IBS letlMtee based in the examination of representative utility coopany expenditures.
BASELINE PINANCIAL PROFILE
The baseline financial projections incorporate the numer-
ous assumptions described earlier and represent a most likely
scenario of the future of the electric utility industry.
These baseline projections include existing environmental
regulations but exclude the final regulations.
To capture the major financial implications of alterna-
tive sets of assumptions, TBS developed statistics for the
following financial parameters: changes in plant in-service,
external financing/ operating revenues, operation and mainte-
nance expenses, and average consumer charges. Table 11-17 and
the discussion below summarize these financial projections.
Changes in Plant In-Service are defined as total, cash
outlays for plant construction during a given year (both for
a plant that goes into service by year-end and for a plant
that remains in the cash amount in CWIP) plus AFDC, minus the
year-to-year change in the cash account in CWIP. To the
-------
11-28
extant that the equipment required by these regulations has a
construction lead time of less than one year, there is no AFDC
or CWIP and this definition corresponds closely to what many
studies refer to as "capitalized expenditures": it reflects
the increase in plant in-service that takes place in a given
year as a result o£ past capital expenditures. The baseline
projections through 1999 indicate that changes in plant in-
service will total $1,127.4 billion in constant 1982 dollars.
Table 11-17
SIM4MY OF BASELINE FINANCIAL PROJECTIONS
(billions of 1982 dollira)
Lhenoee in Plant In-Sarvicn1 1980 1985 1990 1995 1999
Total Tor yeer 31.21 44.ID 55.03 93.68 94.59
Total since 1980 31.21 217 . 37 454.80 772.IB 1,127.40
Operating Revanuee
Total for year 99 . 57 120.87 147.6* 175.66 209 . 87
Total since 1980 99.57 652.27 1,334.97 2,153.94 2,946.43
Operation and Maintenance Expenses^
Total for year 71.9 2 79 . 79 92 . 73 108.» 121.92
Total since 1980 71.92 452.56 888.06 1,396.02 1,862.17
Conataer Charoee (nillaAWh)
Average for year 46.69 48.90 51.52 52.88 56.13
^Exeludee chanqee in CHIP.
^Excludea nuclear fuel.
Source: PTa( Electric Utilities).
Operating Revenues represent the total amount of money
paid by utility customers for electricity in a given period.
To put it another way, operating revenues are the amount re-
quired by the utilities to cover fuel, other operating, and
capital-related costs. This represents perhaps the best
single statistic for measuring the total effects of pollution
control regulations. The baseline projections for total util-
ity operating revenues are $2,946.4 billion in the 1980-1999
period.
-------
Erfiibit II-l
U.S. ELECTRIC UTILITY CAPACITY,1 ADOITIONS, RECONVERSIONS,
AND RCTIROCNTS BY FUEL TYPE
1980-2010
(aagavatta)
Coal
Oil
Gaa
Nuclear
Hydro
PU4*«J
Storage
IC/GT
Total
Capacity 1980
Additions
Reconversions
Ratirsaents
227,019
77,315
6,478
(2,427)
105,463
(6,851)
(2,787)
54,329
(1,446)
48,104
15,696
59,080
6,305
14,770
1,576
47,800
11,928
556 , 565
72,820
(373)
(6,660)
Capacity 198$
Additions
Reconversions
Retirements
268,383
41,429
12,482
(876)
95,825
(14,248)
(2,119)
52,883
(1,092)
63,800
27,884
65,385
2,330
14,346
583
59 , 728
3,982
622,352
76,108
(1,766)
(4,087)
Capacity 1990
Additions
Retirement!
321,420
61,015
(1,326)
79,458
(1,492)
51,791
(768)
91,684
23 , 371
67,715
8,658
16,929
2,164
63,610
692,607
95,208
(3,586)
Capacity 199$
Additions
Aatiraaents
381,109
114,729
(11.393)
77,966
(8,282)
51,023
(4,267)
115,055
22 , 688
76,373
6,801
19,093
1,700
63,610
4,607
784,229
150,525
(23,942)
Capacity 2000
Additions
Rstireaenta
434,445
357,020
(74,807)
69,684
(30,4.72)
46,756
(15,698)
137 , 743
50,294
93,174
6,278
20,793
1,570
68,217
39 , 452
910,812
454 , 617
( 120,977)
Capacity 2010
766,658
39,212
31,058
188,037
39,452
22 , 363
107,669
1,244,449
^apacitias irt far beginning of year.
Sourcei Thau data ar« consistent with those provided by EPA Tor use in the HJO; OOC, Statistics of
Privately Owned Utllitiea in the United States—1979: OOE, Statiatiea of Publicly Owned
Utilities in tfta United States—1979.
-------
III. NATIONAL ECONOMIC EFFECTS
This chapter describes the economic effects of ,the final
regulations on the entire electric utility industry. The
analysis in this chapter is based on technical cost data con-
tained in the Development Document and supporting documents
and on the industry operating and financial assumptions de-
scribed in Chapter II. The results of the national-level
analysis are presented below, followed by a discussion of the
major differences in the economic effects of the proposed
October 1980 regulations and the final regulations and a
description of the methodology and assumptions used in the
analysis.
RESULTS OF THE ANALYSIS
The final regulations should have a minimal effect on the
electric utility industry and on consumers of electricity. As
explained in Chapter I, the final regulations will impose
additional costs only on existing and new steam-electric
powerplants that have once-through cooling systems and dis-
charge directly into receiving waters. As a result, only
53 percent of the existing capacity of the steam-electric
sector of the industry, 40 percent of new fosBil-fired steam
capacity, and 64 percent of new nuclear capacity could poten-
tially incur increased costs as a result of the regulations.
Table III-l summarizes the results of the analysis.
The increase due to the regulation in operating revenue
requirements, which is the single most comprehensive measure
of the cost of the regulations, is about $11 million per year
over the forecast period. This increase represents a minimal
increase in the industry's baseline annual revenue require-
ments of $120 billion to $175 billion nationwide. Increases
in consumer charges, which represent the increased costs to
customers, required to support higher revenue, requirements,
amount to 0.003 to 0.005 mills per kWh. (One mill equals
0.1 cents.) Changes in plant in-service through 199 5, which
reflect capital expenditures, amount to less than $25 million,
compared with baseline projections for the industry of $772
billion.
-------
III-2
Ttfila III-l
NATIONAL COSTS 0F FINAL REGULATIONS PROMULGATED BY CPA
(¦llllons of 1982 dollars)
Chance* In Plant
In-Service
1960-1985
1900-1995
Operating and Maintenance
Expanee
(total Tor yaar)
1905
1995
Oparatlnq Revenue
Requirement!
(total Tor yaar)
1985
1995
(ounilatlva sines 19B0)
1985
1995
Caneuaer Char pea
Average far year
(aUla/kWh)
1985
1995
Baaellne
$ 217,363
. ttz.ibi
S 79,790
108,287
$ 120,875
175,667
652,266
2,153,938
40.90
52.88
Incraaantal Percent
Coat Due to Ineraaae
Final Over
Heoulatlona (iaeej^ne
f 20.51
24.85
8.09
9.76
I 11.50
10.86
25.97
134.82
Q.005
0.003
.009
.003
.010
.009
.010
.006
.004
.006
.aio
.006
Source: PTa(Elect«c UtiliU.ee).
The effect of the regulation can be attributed primarily
to BAT standards affecting plants existing as of the beginning
of 1985..1 As shown in Table III-2, changes in plant in-
service due to the regulation for these plants through 1995
will amount to $19.2 million, compared with $5.65 million for
plants coming into service after 1984. Similarly, over the
^Existing plants must comply with the BAT regulations by
July 1, 1984. For the purpose of this analysis, however, we
have taJcen 1985 as the starting point, because it is the
first full calendar year that compliance is required.
-------
III-3
Tab la III-2
NATIONAL COSTS OF FINAL REGULATIONS PROMULGATED BY CPA
FOft EXISTING AW (CW PUNTS
(dollar* In
Millions of 1982
dollars)
Total
Existing
Plants
No*
Plants
22S&SBS-iiL£l«& -
In-Service
1900-1985
1980-1999
$ 20.51
24.85
$ 19.20
19.20
$ 1.31
5.65
Operation and
taintenanc* txssnse
(total for year)
1985
1995
$ 8.09
9.76
S 7.66
7.56
$ 0.43
2.20
Qoeratina Revenue
Reauirsaents
(total for yaar)
1985
1995
(ouMulatlva sine* 1980)
1985
1995
$ 11.50
10.86
25.97
134.82
$ 10.92
8.22
24.73
116.55
$ 0.58
Z.64
1.24
18.27
Conauaar Diaroee
Average for year
(aillsAHh)
1985
1995
0.005
0.003
.004
.002
.001
.001
Soireei PTa(Electric Utilities).
period from 1985 to 1995, the total increases in revenue re-
quirements incurred by plants that were in service before 1985
will be $116.55 million, as compared to $18.27 million for
plants that will come into service after 1985.
While the costs of the final regulations are relatively
small, when spread across the entire electric utility industry,
individual utilities and their ratepayers could incur signifi-
cantly higher costs than those cited above. The range of
costs which could be incurred at individual utilities as a
result of the regulations is the subject of Chapter IV.
-------
III-4
MAJOR CHANGES FROM THE PROPOSED REGULATIONS
The potential effects of the final regulations on the
electric utility industry are less than the potential effects
of the regulations proposed in October 1980. The proposed
regulations contained more stringent requirements (or both
once-through and recirculating (closed-cycle) cooling
systems.
The regulations proposed in October 1980 would have im-
posed more stringent requirements for total residual chlorine
(TRC) control by plants using once-through cooling systems.^
Fewer plants would have been able to comply with these re-
quirements using chlorine minimization, a less costly strat-
egy. Technical analysis by EPA indicated that only 10 percent
of' "the once through capacity would have been able to use
chlorine minimization, compared with 4 5 percent under the
final regulations. Also, plants that use chlorine minimiza-
tion and plants that use dechlorination would have been lim-
ited to chlorine discharges of two hours per plant per day.
For existing plants this requirement would have necessitated
replacing a plant's existing sequential chlorination system,
required by currant regulations, with a system capable of
chlorinating all systems at a plant simultaneously.
As shown in Table III-3, the annual revenue requirements
associated with the once-through cooling water standards in
the proposed regulations would have amounted to $24 million to
$27 million, and changes in plant in-service would have been
over $60 million through 1995. Thus the proposed regulations
would have been approximately three times as costly as the
final regulations.
The regulations proposed in October 1980 also would have
limited TRC discharges by plants using recirculating cooling
systems to 0.14 mg/1 and prohibited the discharge of cooling
tower maintenance chemicals containing the 126 priority pollu-
tants. Analysis of the proposed regulations for recirculating
cooling water performed in 1980 indicated that the revenue re-
quirements associated with these standards would have been
^These standards would have set a zero discharge standard for
TRC unless a need for chlorination could be demonstrated.
For plants that demonstrated a need for chlorine, the pro-
posed regulations would have limited TRC discharges to
0.14 mg/1 for two hours per plant per day rather than
0.20 mg/1 for two hours per unit per day.
-------
IIX-5
T*le III-3
NATIONAL COSTS (F REGULATIONS
PROPOSED BY EPA IN OCTOBER 1980
FOR arCC-TtffiOUGH COOLING HATCH
(doliara in «lLLians of
1982 dollara)
Total
Cxiatinq
Planta
New .
Planta
ChanoM in PI wit
In-Sarviea
1980-1985 $ 52.87
1980-1995 41.08
$ 50.41
50.41
$ 2.48
10.67
Operation end
Mtintanence Expanse
(total for roar)
1985 S 17.56
1995 20.98
t 16.64
16.44
t 0.92
4.54
Ooaratino Revenue
Reauireaenta
(total far year)
1985 S 24.57
1995 23.69
(ouajlativa ainca 1980)
1905 58.68
1995 " 501,30
23.59
18.35
56.17
264.40
1.18
5.34
2.51
56.90
Conauaar Charoea
Averse for yaar
(¦Llla/kMh)
1985 0.011
1995 0.007
0.010
0.006
0.001
0.006
Sourcai PTa(Elactric UtiLitin).
$30 million to $40 million per year and cumulative capital
expenditures through 1995 would have amounted to $70 million
(1980 dollars). These costs were almost entirely associated
with the TRC control requirements, although some minor costs
were associated with restrictions on zinc and chromium dis-
charges that have since been removed by EPA. Since EPA has
decided to eliminate both requirements and to revert instead
to the existing standards for chlorine, zinc, and chromium,
the costs associated with meeting these requirements will not
be imposed on the industry.
-------
III-6
methodology and assomptions
The approach used in the national-level analysis con-
sisted of three steps. First, a baseline operating and finan-
cial projection of the electric utility industry was produced.
This baseline projection of costs and capital requirements
described in Chapter II included the effects of all applicable
environmental regulations except for the incremental controls
which would be imposed by the final regulations. It was as-
sumed that all utilities were in compliance with BPT stand-
ards. Second, the incremental effects of the final regula-
tions were included in the operating financial projections of
the industry. Third, the baseline projections were compared
to the projections containing the effects of the final regula-
tions .
The operating financial projections were made using the
?olicy Testing model (PTm), a financial and accounting model
of the electric utility industry. PTm develops detailed year-
by-year financial forecasts for the industry in both constant
and current dollars, as described in Chapter II and Appen-
dix B. The level of detail within PTm permits a comprehensive
financial analysis that includes accounting, tax regulatory,
and financial considerations. The approach, however, does not
provide the capability to address supply or demand changes
that are due to changes in costs. The minimal cost increases
associated with the final regulations, however, will have no
effect on demand.
In calculating the costs of the regulations, several as-
sumptions were made regarding the total capacity of power-
plants that would incur additional costs as a result of the
final regulations. Based on an analysis of the Energy Data-
base for fossil-steam plants and of DOE's GURF database for
nuclear plants, it was determined that 58 percent of existing
steam-electric capacity uses once-through cooling systems and
would potentially incur costs as a result of the regulations.
Projections for future plants were based on cooling systems
used by plants built from 1977 through 1979. An analysis of
these recently built plants was used to estimate that 40 per-
cent of new fossil-steam capacity and 61 percent of new
nuclear capacity would use once-through cooling systems.
Technical cost and coverage assumptions were provided by
EPA and its technical contractors. Tables III-4 through III-7
present the key technical cost and coverage data used in this
-------
III-7
analysis. These data are excerpted from a September 1981
report by Radian Corporation to EPA.3
Two further important assumptions were made for this
analysis. First, the analysis assumed that new powerplants
could meet the NSPS fly ash transport water zero discharge re-
quirement with no increase in costs. Based on the engineering
cost analyses in the Development Document and other supporting
documents, EPA concluded that the costs of dry fly ash trans-
port and disposal systems were comparable to wet ash transport
and disposal (the only other technology -for ash removal).
Second, the analysis assumed that substitute cooling tower
maintenance chemicals, which would not contain detectable
amounts of the 124 priority pollutants when discharged, were
available at no additional charge.
^Radian Corporation, Costs of Chlorine Discharge Control
Options for Once-Through Cooling Systems at Steam Electric
Power Plants, Document Number 81-210-002-01-07, September 22,
1981.
-------
Ill- 0
Table III-4.
CAPITAL APO OPERATION A NO MAINTENANCE COST ESTIMATES
FOR QNCE -THROUGH COOLING MATER CHLORI* CONTROL
(Final Regulation*)
TDC LIMITj 2 Hours/Day/Unit
CWPLlANffi Oiacharge Point
CONCENTRATION! 0.20 mq/1
Exiatlng end New Plants
Capital QAM
Plant Slza Coat Coat
(tea— tta) (dollar*) (dollara/yaar)
100 Ml
Chlarlna Mln. 39,500 7,700
Dechlorination $6,700 16,100
SOD MW
Chlorine Mln. 40,100 5,100
Dechlorinetion 82,700 79,600
l.OOO MX
Chlorine Mm. 40 , 800 2,900
Dechlorination 90,800 55,700
Sources Radian Corporation, Coata of Chlorine
Discharge Control Qptlona for Once-Through
Cooling Syate«e at Steee Electric Power
Plants. Oocuaent Nueber 91-210-002-01-07
(Sapteaber 1981), Table 12.
-------
III-9
Table III-5
CAPITAL ANO OPERATIW AND NlINTDUNCE COST ESTIMATES
FOR ONCE-THROUGH COOLING WTCR CHLORDC CONTROLS
(Proposed Regulations)
TI* LlMni
CtmiANtt:
COCCNTRATIONi
2 HoMTa/Dey/Biacherga Paint
Discharge Paint
0.1A eg/1
Plant 51m
(mmmwrnttn) •
100 KW
Ne« Plants
Capital
Oat
0«M
Cat
(dollara/year)
Chlorine Nln.
Dechlorination
39,500
91,500
7,700
17,700
500 MM
Chlorine Min.
Dechlorination
40,100
111,300
5,100
39,800
1.000 MX
Chlorine Min. AO,300
Dechlorination 126,900
2,900
55,000
Source: Radian Corporation, Coata of Chlorine
Dlacheroe Control Qptlona for Once-Throuai
Cooling Syetewa at Steaa Electric Power
Planta . Doauaent Ntaber 81-210-002-01-07
(Septeaber 1981), Table 5.
-------
111-10
Table III-4
COVERAGE ESTIMATES
(final Regulations)
TItC LIHIT: 2 Houra/Day/Discharqe Unit
COmiANCCt Discharge Paint
CONCENTRATION: 0.20 eg/1
ExiaLing and New Plants
Percentage of Total
Hagamtt Capacity of
Plants Uairtg Once-
Through Cooling Syatan
That Will Choose Thia
Technoloov Technology
Chlorine oinioization 45
Dechlorination 26
Chlorine not uaad 29
Mote: These eatiMtes are based on an analysis
of data froa 23 plants uaing once-through
cooling systsaa that have conducted
chlorine ainiaization studies. Approxi-
mately 29 percent (by capacity) of planta
using ones-through cooling ays tans do not
use chlorine and thus incur no coopliancs
coats.
Sourcei Radian Corporation, Costa of Qilorine
Diacharqe Control Ctationa for Once-
Th rough Coo lino Svata» at Staa» Qectric
Power Planta. Document *fcjaber 31-210-002-
01-07 (Septeller 1991), Teble 13.
-------
I11-11
Table III-7
COVERAGE ESTIMATES
(PrapOMd flagulationa)
TI(C LIMIT i 2 Houn/Oay/Oiacharga Point
COWLIANCEt Oiecherge Point
CONCENTRATION! 0.14 ag/1
Eclating and Htm Plant!
Technology
atgggmmmmmmmmMmlm-
Chiorina lainiaizBtian
Dechlorination
Chlorine not used
Percentage of Total
Megawatt Capacity of
Plant! Uaing Once-
Through Cooling Syetaaa
That Hill Otooaa TMa
Technology
10.
61
29
Notai Thaae aatiaatea are baaed on an analyeia
of data fro" 25 plants uaing ance-through
coaling ayateaa that Have conducted
chlorine ainiaization stud lea. Approxi-
mately 29 percent (by capacity) of plants
uaing once-through cooling ayataaa do not
use dUorine and tlxia Inair no compliance
coats.
Sources Radian Corporation, Coata of Chiorina
Discharge Control Qptlona Tor Once-
Throuoh Cooling Syeteaa at Staaa Electric
Power PI ante. Document Nutter 81-210-002-
01-07 (Septeaber 1901), Tabla 6.
-------
17. PLANT-LEVEL AND UTILITY-LEVEL EFFECTS
This chapter describes the analysis of the economic ef-
fects of the final regulations at the plant and utility
levels. Since only direct discharging staam-electric plants
with once-through cooling systems and capacities of 25 MW or
greater incur costs as a result of complying with the final
regulations, this analysis focuses on these types of plants.
The effects of the regulations at the plant level depend on
the characteristics of the plant and on the cost of the com-
pliance strategy selected. These effects are diluted at the
utility level to the extent that a given utility operates
plants that do not bear additional costs. Costs borne by
utility customers reflect the costs incurred at the utility
level as environmental compliance costs are assumed to be
fully passed through to customers. The sections that follow
first present the results of the analysis at the plant and
utility levels and then describe the methodology and assump-
tions used in the analysis.
RESULTS OF THE ANALYSIS
The plant- and utility-level costs of the final regula-
tion are expected to be minimal except for small plants. For
plants larger than 25 MW the plant-level cost of compliance
with the final regulations for once-through cooling water will
range from 0.003 mills per kWh to 0.25 mills per JcWh. At the
utility level, the cost of compliance will be an even smaller
portion of all total expenses, because many utilities will
incur costs at only some of their powerplants.
Costs incurred by plants with capacities of less than
25 MW would have been significantly higher as a result of high
fixed costs and low capacity factors. These costs would have
ranged from 0.26 mills per kWh to 4.32 mills per kWh. These
costs compare to a baseline cost of generating electricity of
30 to 72 mills per kWh. However, EPA has established BAT
equal to BPT for chlorine for those plants. Thus the final
regulations impose no additional costs on those facilities.
The remainder of this section discusses the results of
the analysis. It addresses first the costs incurred by plants
with capacities of 25 MW and greater. Then it examines the
extent to which plant-level cost increases for these plants
will translate into higher consumer charges at the utility
-------
IV-2
level. Finally, because the utility-level analysis excludes
plants with less than 25 MW of capacity this section examines
the costs incurred by these very small plants.
Plant-Level Costs *
As shown in Table IV-1, the incremental plant-level costs
of chlorine minimization are approximately one half as great
as the costs of dechlorination for 100 MW and S00 MW plants.
The difference between chlorine minimization, and dechlorina-
tion is greater for 1,000 MW plants because capital and opera-
tion and maintenance costs of chlorine minimization are essen-
tially fixed while both capital and operation and maintenance
costs vary with plant capacity for dechlorination. The costs
of both technologies are higher at small plants because large
plants benefit from economies of scale and because small
plants generally have lower capacity factors.
Table IV-1
P LA WT-LEVEL COSTS OF FINAL CHORllC CONTROL
REGULATIONS FOR ONCE-THROUGH COOL I*: PLANTS
(1982 «illa pat kWh)
Compliance Heaaure
Plant Chlorine
Capacity* (MW) Minimization Dechlorination
25 a 0.43
100 0.06 Q.12
500 0.01 0.02
1,000 0.003 0.02
500 HW and 1,000 MW plants are aaauaed to heve
60 percent capacity factora; 100 WW planta
have 40 percent capacity Factora; and 25 MM
planta hava 25 percent capacity factors. Thsae
aaauaed capacity Factora are greater than the
capacity Factora experienced taring the recent
paet. Howevar, they are consistent with the
capacity Factora ahicti the induatry la pro-
jected to experience in 1985.
"Engineering coats far 25 MW planta ualrq
chlorine ainiaijation Mere not developed.
Source: Rsdian Corporation; TBS calculations¦
-------
IV-3
The coats incurred under the final regulations do not
differ significantly by fuel type or between new and existing
plants. The technical analysis performed for EPA assumes that
compliance costs depend on plant cooling water flows which are
independent of fuel types. With respect to new and existing
plants, the same standards apply under BAT and NSPS. EPA's
technical analysis also indicates that installation of fixed
equipment does not involve retrofit premiums associated with
working around equipment that is already in place. Cost
differentials are associated with the shorter capital amorti-
zation periods for existing plants but these differences are
insufficient to affect the results of the analysis appre-
ciably. Therefore, the costs for new and existing facilities
are not expected to differ.
Compliance costs under the final regulations range from
0.003 to 0.43 mills per kWh. These cost increases range from
just over 1 percent to less than 0.01 percent of the baseline
costs of generating electricity at the model plants used in
this analysis. Baseline costs are shown in Table IV-2. A
25 MW plant incurs a cost of 1 percent of its baseline costs.
By contrast the 500 MW and. 1,000 MW model plants (representa-
tive of plants that account for 90 percent of the industry's
capacity and over 90 percent of its generation) incur costs
that range from 0.1 percent of baseline costs to less than
0.01 percent of baseline costs.
Tabla IV-Z
1985 8ASELIFC PLANT-LEVEL COSTS
or generating electricity
(1982 mills per WHh)
In-aervica Y«ar and Fuel Typ*
Pre-19 72 1972-1976 1977-1979 1987
Plant ¦¦¦-¦¦ .. —
Capacity1 (HW) Coal 011 Coal Oil Coal Oil Coal
25
100
SOD
1,000
39 52 n/a n/a n/a n/a n/a
36 49 N/A N/A N/A N/A N/A
30 43 31 43 . 38 31 72
30 43 31 43 38 51 72
N/A x Not applicable.
300 MM and 1,000 MM plants aca asautod to havo 60 pareant
capacity factor*; 100 Mtf pianta ha** 40 parcant capacity
factors; and 23 N* plant* hava 29 parcaot capaelt y factor*.
Sources TBS calculation.
-------
rv-4
Because small plants could have the greatest increase in
cost of generation, and there is a wide distribution of capa-
city factors among these plants, the costs of the final regu-
lations for these plants were examined in detail. Table IV-3
shows how the increased costs of the final regulations vary
with plant size and capacity factor. The increased costs
range from 0.26 mills per kWh to 4.32 mills par kWta. Since
small plants frequently operate at low capacity factors, com-
pliance costs exceeding 1 mill per kW would not be unusual.
Compliance costs of this magnitude would be expected to in-
crease the total costs Of electricty by 2 to 3 percent at a
small powerplant. The potential increase could be as high as
10 percent for small plants operating at low capacity factors.
TBblB IV-3
SHALL PLANT DECrt-ORINATION COSTS
AS
A FUNCTION 0F PLANT CAPACITY FACTOR
(1992 allls par IcWh)
Plant
Caoacity
Plant Caoacity Factor (S)
Cm)
10 25 40
25
1.8 0.43 0.26
10
2.16 0.86 0.54
5
4.32 1.73 1.0a
Source:
Radian Corporation; TBS calculationa.
The regulations proposed in October 1980 would have re-
sulted in higher plant-level costs for all affected plants of
all sizes. As shown in Table IV-4r the proposed regulations
would have imposed costs ranging from 0.003 to 0.17 mills per
kWh on plants with capacities greater than 100 MW. Chlorine
minimization costs are the same for new plants under the pro-
posed and the final regulations because the same technology is
utilized. For existing plants chlorine minimization is
slightly more costly under the proposed regulations because
plants might have been required to replace their sequential
chlorination systems required by current regulations with a
system capable of chlorinating a plant's entire once-through
cooling water Clow simultaneously. Dechlorination costs are
higher at the plant level under the proposed regulations be-
cause simultaneous chlorination and dechlorination facilities
may have been necessary to meet the limit.
-------
rv-5
Tabla IV-A
PLANT-LEVEL CDSTS tr CH.0RI* CONTROL. REGULATION
FOR ONCE-THROUGH COOL IMC PLANTS PROPOSED OCTOK# 1W0 4
C1982 mils par kWh)
Co^llaftca foaaura
Chlorina Mini ai ration
Dechlorination
Plsnt
Caoacitv (MK)
Ham Plants
Existing
PJanlfS N
Plants
0.14
Existing
Plants
0.17
100
0.06
0.10
no
4 unit
10 init
0.01
0.01
a. 01
0.02
0.03
0.03
0.03
0.04
1,000
0.003
a. oi
0.02
0.02
Sourest Radian Corp.; TBS calculation.
Utility-Level Costs
The effect of the final regulations on the price the
customer pays at the utility level generally should be less
than the increased cost per kWh at the plant level. The price
a customer pays includes costs other than power production
costs. In addition, a utility may have some plants incurring
no compliance costs, which would allow the utility to spread
its compliance costs at one plant over its total generation.
To determine the extent to which plant-level costs will
be diluted at the utility level, TBS examined utility-level
costs for 229 utilities that represent over 96 percent of the
fossil-steam electric generation capacity in the United
States. Unlike the national analysis, this analysis made the
worst-case assumptions that all plants with once-through cool-
ing systems chlorinate and that all plants that chlorinate
will comply with the regulations by dechloriftating rather than
by using less costly chlorine minimization. Since this anal-
ysis applies only to existing plants it reflects only BAT
costs. As shown in Tables IV-1 and IV-2, larger plants should
experience the smallest increases in costs per kWh as a result
of the final regulations.
-------
IV-6
The utility-level analysis showed that for 80 percent of
the utilities (accounting for 98 percent of generation) the
increased costs of electricity due to the final regulations
would be less than 0.05 mills per kwh (Figure IV-1). The
increased cost of electricity would be less than 0.03 mills
per kWh at 70 percent of the utilities. About 18 -percent of
the utilities would experience no increased costs at all.
Figure IV-1
CUMULATIVE PERCENT OF UTILITIES ANO GENERATIONS
BY COST OP COMPLIANCE
100%
90% -
80%
70%
Cumulni««
Pvccnt
50%
40%
30% -
20%
10%
0.01 0.02 0.03 0.04 0.0S 0.06 0.07 0.08 0.09 0.10
0
0.20 0.30 0.40 0.50
Dachtorlrwtkxi Coco (milli/ldiowatt-taur)
Sourer. Enwvr Or** Radian Corporation; TBS adcultwna.
The utility-level costs cited above exclude two catego-
ries of plants—very small plants and nuclear plants—both of
which are not represented in the Energy Database. The effects
of including nuclear plants in the analysis would be to reduce
the costs reflected in the utility-level analysis because
nuclear plants generally have large capacities and operate at
high capacity factors. Small plants, on the other hand/ could
incur¦disproportionately high costs.
-------
IV-7
Eighty-nine of 131 small plants identified in the GUAF
database are owned and operated by small utilities, universi-
ties, and federal facilities that only operate small power-
plants. However, many of these small-plant owners buy signi-
ficant portions of their electricity from utilities -which
operate large plants. The effect of the final regulations on
the electricity costs of these small-powerplant owners depends
on the extent to which they rely on their small powerplants.
The small-plant owners which obtain a significant portion of
their electricity from their small, powerplants could incur
overall increased electricity costs as high as the plant-level
increases shown in Table 1V-3. It should also be noted that
whether they purchase a significant portion of their power or
not, many small utilities could encounter difficulties raising
the capital required for dechlorination and may not have the
technical expertise to operate a chlorine minimization pro-
gram. In addition, as noted in Chapter II, the median in-
service year far capacity in these small plants is before
1955. It is likely that some utilities operating these plants
would close them rather than make the capital expenditures
required to meet these regulations.
METHODOLOGY AND ASSPMPTIONS
This section describes the methodology and assumptions
used in the analysis of plant- and utility-level effects. The
methodology used in selecting model plants is discussed first,
followed by a discussion of the methodology used to determine
plant-level and utility-level costs.
Selection of Model Plants
Two major criteria—size and age—were used in the selec-
tion of model plants for the plant-level analysis because
these are. the key factors that can influence plant-level com-
pliance costs. In addition, a number of other criteria such
as fuel type, cooling system type, and number of units were
also taken into account in the analysis. As is discussed
below, TBS selected these criteria to encompass both those
plants that would be most affected by the proposed regulations
and those plants that account for most of the industry's gen-
erating capacity.
-------
IV-8
Plant Size
Since large plants benefit from economies of scale that
are not available to smaller plants, TBS examined the effects
of the regulations on existing plants in four different capac-
ity categories. These capacities—25, 100, 500, and 1,000 MW
—represent a range of plant capacities in the industry. The
25 MW and 100 MM plants were used to identify economic effects
on plants with capacities of less than 300 MW which account
for nearly 45 percent of the total number of steam-electric
powerplants but only 11 percent of the industry capacity and
less than 9 percent of its generation. Further analysis of
two additional categories of very small plants—5 MW and
10 MW--was also performed to determine whether these plants
face disproportionately high costs and should* be exempted from
the regulations. The 500 MW and 1,000 MW plants represent
plants with capacities greater than 300 MW, which account for
nearly 90 percent of the industry's capacity and more than
90 percent of its steam-electric generation. New plants were
examined only in the 500 MW and 1,000 MW categories because it
is not expected that new small plants will be built except for
experimental purposes.
Plant capacity factors were established for each size
category of plants. The capacity factor established for
500 MW and 1,000 MW plants was 60 percent, which represents
the 1985 projected capacity factor for coal-fired plants.
The capacity factor of 38 percent selected for the 100 MW
model plant is representative of the capacity factor for
fossil-steam plants smaller than 300 MW reported in the Energy
Database. Reliable data concerning very small plants with
capacities of 25 MW or less were not available in the Energy
Database. The analysis of other sources of data indicated
that capacity factors for these very small plants range from
10 to 40 percent, with a median of 16 percent. For this
reason the effects of the regulations on very small plants
with capacity factors ranging from 10 percent to 40 percent
were examined.
Plant Age
Plant age was also examined as a determinant of plant-
level costs. The two major age-related distinctions are
between new and existing plants and, among existing plants,
between plants with different remaining depreciable lives.
Whether a plant is an existing plant or a new plant has rela-
tively little effect on the costs that it incurs. Under the
final regulations the equipment required for compliance is
-------
IV-9
sufficiently separate from other plant operations that compli-
ance costs for existing plants are not expected to be higher
than for new plants.
The remaining depreciable life of a plant affects the
period over which the capital costs of pollution control
equipment can be amortized. The older the plant is when the
final regulations go into effect, the shorter the amortization
period for pollution control equipment installed. A shorter
amortization period at a given interest rate results in a
higher annual capital cost of compliance.
Remaining depreciable lives were determined assuming a
3 5-year depreciable life and three age categories of existing
plants—pre-1972, 1972-1976, and 1977-1979—as well as new
plants.1 For the three age categories of existing plants, the
plant year in-service used in determining baseline and compli-
ance costs was the average of units in the Energy Database
falling into that age category. These years are 1962, 1974,
and 1977, respectively for the three categories of existing
plants. The new plants were assumed to come into service in
1905.
Other Characteristics
Two other plant characteristics—cooling system and fuel
type—wera also considered in the selection of model plants.
The final regulations only impose incremental costs on plants
using once-through cooling water. For this reason only plants
with once-through cooling systems were considered in the
analysis. Compliance costs do not vary by fuel type; however,
for purposes of comparison with the cost of compliance TBS
developed baseline costs for both coal and oil plants.
Plants Selected for Analysis
As summarized in Table IV-5, ten model plants were se-
lected for analysis on the basis of plant capacities and ages.
Because the great majority of plants coming into service since
1972 have had capacities greater than 100 MW, costs were, not
developed for 25 MW and 100 MW plants coming into service
after 1972.
^¦The 35-year depreciable plant life used in this analysis is
shorter than is sometimes assumed. To the extent that plants
have actual lives that exceed their depreciable lives, this
analysis overstates their compliance costs.
-------
IV-10
Table IV-5
%
HD0CL PLANT CHARACTERISTICS
BY PUNT IN-ZRVIIZ YEAA
Plant
Cecity (HW)
Plant Capacity factor (percent)
Pre-1972 1972-1976 1977-1979 1987
23
100
$00
1,000
10-40 N/A N/A N/A
40 N/A N/A N/A
60 60 60 60
60 60 60 60
N/A > Not applicable. (The gnat aajorlty of plants
cosing Into aervice ainca 1972 nave hid capacities
greater than 100 MM.)
Determination of
Plant-Level Costa
Using the model plant physical and operating characteris-
tics described above, the cost of generating electricity at
each model plant was computed. These costs can be compared to
compliance costs to determine the relative increase in the
cost of generating electricity that would result from compli-
ance with the regulations.
Since the majority of existing plants are expected to
comply with the proposed regulations in 199 5, TBS projected
costs to 1985 in real terms. Capital-related charges were
annualized on a pretax basis using the capital recovery method
and assuming a weighted average embedded cost of capital of
15.5 percent for plants coming into service before 1980 and a
cost of new capital of 22 percent for plants coming into serv-
ice in 1985—the first full year when all plants will be
-------
IV-11
required to comply with the regulations,2 These charges were
then added to annual fuel, operation and maintenance, trans-
mission, distribution, administration expenses, and taxes
other than income taxes to obtain a total annual cost of gen-
erating electricity. The total annual cost obtained, in this
manner was divided by total plant annual electric power gen-
eration based on the plant's capacity factor to develop a
plant-level cost on a per kilowatt-hour basis. Baseline costs
are shown in Table IV-2.
A number of assumptions concerning compliance costs,
capital costs, and plant characteristics were necessary to
perform the analysis. Compliance costs were developed by
Radian Corporation for 100 MW, 500 MW, and 1000 MW plants. In
addition TBS obtained approximate costs for a 10 and 25 MW
plants through telephone conversations with Radian Corpora-
tion. To obtain capital and operation and maintenance costs
for intermediate plant capacities TBS developed exponential
regression equations from Radian cost data with correlation
factors of 1.00 and 0.99 respectively for capital and opera-
tions and maintenance costs.
Economic and financial assumptions were based on condi-
tions projected for 1985, because 1985 will be the first full
year of compliance for both new and existing plants. Costs,
however, are stated in 1982 dollars. To obtain a worst-case
scenario, the projected weighted average cost of capital for
utilities using flow-through accounting of 22 percent was used
in the analysis of compliance costs.
?The existing plant embedded cost of capital is based on ac-
tual 1979 pretax capital rates of 8 percent for long-term
debt, 24 percent for common equity (i.e., 11.55 percent
yield) and 17.4 percent for preferred stock (i.e., 8.35 per-
cent yield). This rate assumes capitalization rates of
50 percent long term debt, 38 percent common equity, and
12 percent preferred stock. The new plant capital cost of
22 percent is based on projected 1985 capital costs used in
the national analysis for plants using flow-through account-
ing. These costs are: 13 percent for long-term debt, 33 per-
cent for common equity (15.95 percent yield), and 27 percent
for preferred stock (13 percent yield). Assumed 1985 cap-
italization rates are 50 percent long-term debt, 40 percent
common equity, and 10 percent preferred stock.
-------
rv-12
Determination of Utility-Level Costs
The analysis of utility-level compliance costs was based
on data in the Energy Database concerning plant capacities,
generation, and cooling types and on the same technical cost
data and assumptions as used in the plant-level analysis.
The analysis includes 229 utilities operating fossil-fired
plants. These utilities represent approximately 96 percent of
the total fossil-fired steam capacity in the United States,
but they do not include approximately 90 utilities that oper-
ate only very small fossil-steam plants. The 229 utilities in
the analysis also do not include plants that do not operate
fossil-steam plants. Annual plant-level cost data were aggre-
gated to the utility level and divided by total utility gener-
ation to obtain an average utility cost of compliance in mills
per kWh. Since compliance costs are only associated with
once-through cooling water, costs per kWh were diluted to the
extent that a utility has plants that utilize recirculating
cooling water. Data concerning utility-level costs of gener-
ating electricity were obtained for 164 utilities, from Stan-
dard and Poor's Compustat Services, Inc.
It was not possible to determine on a case-by-case basis
which plants would be required to take action to comply with
the regulation and which plants would use chlorine minimiza-
tion or dechlorination. Therefore, to obtain a worst case
analysis it was assumed that all plants using once-through
coding would utilize dechlorination. In fact, 29 percent of
the capacity is expected not to incur additional costs as a
result of the regulations, and a further 45 percent of the
capacity is expected to comply using less costly chlorine
minimization.
Data on plant cooling types, capacity, and generation
used in the analysis are based on Form 67 submittals by utili-
ties to DOE. These submittals are summarized in the Energy
Database (see Appendix B). Data in the Energy Database re-
flect conditions in 1979 and not' necessarily conditions in
1985, the first full year when utilities are expected to com-
ply with the regulations. In particular, because of sharp
increases in the cost of oil and overcapacity at midwestern
coal-fired plants, eastern oil-fired plants operated in 1979
at low capacity factors and purchased power from midwestern
utilities. To the extent that capacity factors will be higher
in 1985 for eastern oil-fired plants their compliance costs
are overstated.
-------
IV-13
Results of the analysis are also overstated to the extent
that individual utilities rely on nocfossil steam capacity,
which is not represented in the Energy Database.5 To evaluate
the effect of this overestimate of costs TBS examined the
46 utilities that incur costs greater than 0.05 miTls per. kWh
in the DOE Inventory of Powerplants. which is based on DOE's
GCRP database. Seven of these 46 utilities have more than 50
percent nonfossil steam capacity (either nuclear or non-
steam) , and six of these seven utilities are among the 20
utilities that incur costs greater than 0.1 mills per kWh.
Depending on the capacity factors of the non-fossil steam
capacity, compliance costs for these utilities that rely on
non-fossil steam capacity will be lower them those estimated
in this analysis. In any event the cost increase of 0.05
mills per kWh is approximately 0.01 percent of the baseline
cost of generating electricity.
-------
V. COST-EFFECTIVENESS OF THE REGULATIONS
This chapter examines the cost-effectiveness of the final
regulations. Because the final regulations will oAly causa
increased costs in direct discharging powerplants which use
chlorine to treat once-through cooling water, the analysis in
this chapter focuses only on the cost per pound of chlorine
removal. The analysis is aimed at determining the cost-effec-
tiveness of chlorine removal procedures, and does not address
the benefits of reduced chlorine discharges. The sections
that follow describe the results of the cost-effectiveness
analysis and the methodology and data used in the analysis.
RESULTS OF THE ANALYSIS
The final regulations should result in the removal of
189 million pounds of chlorine from once-through cooling water
discharges during the period from 1984 to 1995 (Table V-l).
The total cost incurred by the electric utility industry in
removing the chlorine should be $135 million (in 1982
dollars). The average cost of chlorine removal under the
final regulations should be about $0.71 per pound.
Tabla V-l
final regulation
cost-effectiveness
FOR CH.QRIFC CONTROL
(1982 dollar*)
Ravanue
Raquir wonts
through 1999 .
CuauUtlva
Total
Pounds of
TRC flaaoved
through 1999
Total Ateraga Incraaantal
Pounik of Cost Coat
TRC Raaovad Par PotffxJ Par Pood
in 1905 of TRC of TRC
("IP6)
Rwaovad Haaovad
Final Ragulationa $179
169
13.5
tO.71
$0.71
Sourcoi Tables V-2 to V-4| TBS calculatlona
-------
V-2
METHODOLOGY
The cost-effectiveness analysis consisted of four steps.
First, the total costs of complying with the final regulations
were determined. These costs are the sum of the irrereased
annual revenue requirements through 1995, a reasonable time
horizon over which to examine the effects of the regulations.
They were developed in the national-level analysis using PTm.
Second, the expected reductions in chlorine discharged
was determined. TBS examined reductions in chlorine dis-
charges on the basis of expected performance rather than regu-
latory standards. Plants complying by means of dechlorination
were assumed to reduce chlorine discharges to 0.14 mg/1, the
level described in the Development Document as achievable with
dechlorination. Chlorine minimization is assumed to meet the
regulatory standard because utilities using chlorine minimiza-
tion are expected to control chlorine discharges to a level
consistent with the regulations.
The amount of chlorine discharged depends on the number
of hours per day that a plant is allowed to discharge chlor-
ine. The final regulations permit chlorine discharges of
0.20 mg/1 for two hours per unit per day measured at the point
of discharge. Because the final regulations permit dilution,
each unit at a plant with four equal units can discharge
0.80 mg/1 sequentially if this discharge is diluted by the
cooling water from the remaining three units.
Third, the quantities of chlorine discharged for a
100 MW, a 500 MW, and a 1,000 MW plant were calculated, using
average cooling water flows developed by Radian Corporation.^-
Flow rates used in this analysis were 81.7 million gallons per
day ( mgd J for a 100 MW plant, 210 mgd for a 500 MW plant, and
317 mgd for a 1,000 MW plant. Table V-2 illustrates average
chlorine removals per MW for the three model plant sizes.
These model plant chlorine removals were then weighted by the
percent of steam-electric generation contributed by each cate-
gory of plants as reflected in the Energy Database. The
weighting factors used and the range in plant capacity that
each plant represents are shown in Table V-3.
^Radian Corporation, Cost of Chlorine Discharge Control
Options, September 22, 1981.
-------
Tab la V-Z
«D£L
final regulation
PLANT CH.0RI* REMOVALS
(pounds par yaar par
jaxatt)
Plant
Caoacitv (MN)
Dechlorination
Minimization
100
168
96
500
70
90
1,000
53
68
Source: Radian Corporation* TBS
calculation.
Trf>la Y-3
Ksa
PLANT CHLORINE RDCVAL
weighting tactors
Plant
Caoacity (MW)
Range aT
Plant Caeacitias
Raoraaantad (HW)
Weighting
Factor
100
0-300
0.061
500
301.750
0.234
1,000
>750
Q.703
Sourca: Enargy Databaaa; TBS calculations.
Finally, weighted average chlorine removals were multi-
plied by the total number of MW ox capacity affected by the
regulations each year from 1984 through 1995. This calcula-
tion yielded the total quantity of chlorine that is expected
to be removed through 1995. Since performance-baaed removals
using chlorine minimization and dechlorination differ under
the final regulations, the affected capacity was separated
into that using each technology. Total chlorine removals
obtained in this manner are illustrated in Table V-4.
-------
V-4
Tabls V-4
OOUVATHW or TOTAL. CHLORINE
REMOVALS THROUGH
1$95
%
Weightad
Average
Total Rwoval
AfTectsd
Reaoval per
Throu^ 1995
MH.Yaara
~W par Year
(Billion#
IsCflftoloaY
(thou»«ida)
(oouuls)
of sounds)
Chlorine ¦lnlaizatlai
993
ao
79
Dechlorination
1,718
64
UO
Total
189
Sourcei Pta(Electric
Utilities); TBS calculations.
-------
Appendix A
THE ENERGY DATABASE
The Energy Database is a computerized information system
developed by Temple, Barker & Sloane for the P.S. Environ-
mental Protection Agency. The information contained within
the data files was obtained from Form 67s submitted to the
Energy Information Administration of the U.S. Department of
Energy (EIA, DOE) by electric utility companies.
Because the information was obtained from Form 67s,
certain limitations exist with the data. First, the forms
used contained information for 1979; therefore, any anomalies
occurring in that year will be reflected in the data; Second,
only steam-electric generating plants with a capacity of 25
megawatts or greater are required to file the FERC form.
Therefore, smaller-sized plants are not represented in the
databases.
To validate the information contained in the Form 67s,
comparisons were made between the forms and several other
sources. These sources included:
• Generating Unit Reference File (GURF), DOE
• Steam Electric Plant Factors, 1979, National
Coal Association
• Utility FGD Survey, PEDCo
• Survey of Utility Power Plant Emissions and
Fuel Data, ICF, Inc., for EPA
• Cost and Quality of Fuels for Electric Utility
Plants, 1980, DOE
Every reasonable attempt has been made to ensure that
numbers in the databases fall within ranges already estab-
lished in other publications.
The Energy Database consists of two sets of computer
files. The first set of data contains three computer files
describing current generating facilities and their operations.
Each of these three files describes a particular set of activ-
ities for powerplants in the Energy Database. These three
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A-2
files are named after the type of information they contain:
"plant file," "boiler file," and "stack file."
• The plant file describes characteristics of the
powerplants in general. These include the
plant's fuel consumption; fuel characteristics,
including Btu content, sulfur content, and ash
content; characteristics of ash production and
handling; and cooling water characteristics.
Costs associated with these characteristics are
also included.
• -The boiler file presents characteristics of
individual units within each plant. These
include unit fuel consumption, stack gas clean'
ing equipment for each unit, cooling facilities
on each unit, and costs and in-service dates
for the types of equipment described.
• Th* stack file describes the stacks used by the
individual units, including their height and
costs.
The second set of files contains information describing
planned plant expansions and equipment changes for the period
1980 to 1984 and fuel use for 1984 and 1989. This set con-
sists of two computer files, one describing future plant level
operations and the other describing future unit level opera-
tions. These two files are called the "future plant file" and
the "future boiler file."
• The future plant file projects for 1979, 1984,
and 1989 both fuel consumption, including char-
acteristics of the fuel, and plant-level emis-
sions for air, water, and solid wastes.
• The future boiler file forecasts the units and
pollution control equipment to be associated
with these units. This file includes the same
type of information included in the boiler file
but for future periods.
Each of the files described above can be examined inde-
pendently, and comparisons can be drawn between the plants,
the boilers, or the stacks within each file. The files can
also be related, however, producing complete profiles of
plants within a utility of boilers and stacks within the
plants, and of future plans for the plants.
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Appendix B
PTffl(ELECTRIC OTILITIES)
RESEARCH METHODOLOGY
This appendix on research methodology consists of a non-
technical overview of the logical structure of the computer
model, PTm(Electric Utilities), used to derive the projections
discussed and analyzed in the text of this report. In broad -
terms, PTm has three main logical components, which may con-
veniently be labeled the external, physical, and financial
modules. As shown in Exhibit B-l, it is assumed that general
economic conditions and other factors outside the model deter-
mine the demand for electricity. Expectations regarding fu-
ture generation expansion plans, and the equipment, power
drain, and generating efficiency implications of pollution
control requirements, combine to determine the industry's
physical plant, equipment, fuel, and labor requirements.
These physical requirements and the relevant factor costs,
which are also influenced by economic considerations external
to PTm, combine to determine the consequences of building and
operating the capacity.
The capital asset and operating cash requirements implied
by the capacity expansion plan are met in part by revenues
collected from the users of electrical energy and in part by
external financing. The amount of cash provided by operations
at any moment is influenced by regulatory policy (in effect
via the allowed revenue per kilowatt-hour), by tax policy (via
the effective rate of taxation after consideration of depreci-
ation tax shields, investment tax credits, etc.), and by the
cost of capital raised in prior periods. Any shortfall be-
tween cash needs and the cash provided by operations is met by
recourse to the capital markets.
Exhibit B-l omits a number of interactions and feedbacks,
two of which are notable. First, if external financing is to
be available, regulatory policy must be such as to allow reve-
nues per kilowatt-hour sufficient to yield returns to capital
that are adequate in light of prevailing capital market condi-
tions, tax policy, and pollution control requirements, all of
which may have an impact on the cost of electrical power and
hence on demand. As a second illustration, because the finan-
cial characteristics of the electric utility industry and of
individual utilities may be considered in the drafting and
administration of pollution control legislation, pollution
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B-2
control policy in part determines and in part is determined by
the industry's financial profile.
EXTERNAL MODULE
The model's external module has as its- primary function
the inputting of assumptions, such as those concerning future
growth in generating capacity, operating costs, future pollu-
tion control requirements, etc. The implications of these
policy, economic, and technical assumptions are then deter-
mined in the physical and financial modules of PTtn. PTm is
programmed so as to be able to test a wide variety of policy
alternatives through changes in input data.
PHYSICAL PLANT AND EQUIPMENT MODULE
The primary relationships determining the industry's
physical plant and equipment requirements are 3hown. in
Exhibit B-2. The industry's gross generating capacity in
service at any moment is typically determined by the level of
demand, the industry's policy with respect to capacity re-
serves, and the effect of pollution control equipment and in-
plant power requirements. However, for consistency with an-
other recent study for EPA, PTm was modified to accept pro-
jections of future capacity additions and retirements as di-
rect inputs. With the inclusion of the pollution control
equipment required for generating capacity currently in serv-
ice, the additions to in-service plant and related equipment
are fully specified in physical terms.
Given the long time lags involved in constructing new
generating capacity, the industry's plant and equipment con-
struction at any moment typically includes significant amounts
of work in progress. As is shown in Exhibit B-2, future ca-
pacity additions and future pollution control requirements—
together with the lags in construction—determine plant con-
struction in progress. It should be noted that because the
time span between ordering and placing generating capacity in
service is radically different for hydro facilities, peaking
units, fossil-fueled baseload plants, and nuclear units, PTm
computes construction work in progress for plants by fuel type
on different time schedules. Thus average construction lags
are themselves a function of the assumed future mix of these
various types of generating plant3.
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3-3
FINANCIAL MODULE
For expositional purposes it is convenient to divide
Pita's financial modules into three segments, dealing with:
%
• Oses of funds,
• Sources of funds, and
• Revenues and related variables.
Uses of Funds
The industry's uses of funds depicted in Exhibit B-3 are
determined primarily by the physical plant and equipment re-
quired to meet current and future demand and by the cost per
unit of this equipment. A second use is the allowance for
funds tied up in plant and equipment in the process of con-
struction. For simplicity, PTm assumes that the industry's
net working capital remains constant, so that changes in work-
ing capital appear neither as a use nor as a source of funds.
Given the minuscule size of such working capital changes in
comparison with the industry's major sources and uses of
funds, such a simplifying assumption is unlikely to introduce
appreciable error in the absence of fundamental structural
changes in the industry's current assets and payables accounts
or in its usage of short-term debt.
Exhibit B-3 3hows that once the total physical amounts of
plant and equipment required to meet current and future demand
and the proportions of those amounts accounted for by each
type of new capacity are determined, the crucial input assump-
tions required to convert these physical quantities into fi-
nancial terms are the cost per unit of each type of asset and
the schedule of payments required by contractors while such
plant and equipment are under construction.
Sources of Funds
In the case of the private sector of the electric utility
industry, sources of funds consist of two major elements:
• Funds provided by operations, and
• External financing.
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B-4
Funds provided by operations are in torn the sum of three
internal sources:
• Depreciation,
*
• Tax deferrals, and
• Retained earnings.
For the public sector, it is simply assumed that a per-
centage of total funds used is met from internal sources. As
is shown in Exhibit B-4A, any shortfall between total uses and
internal sources is net through external financing.
Exhibit B-4B shows these same relationships in a format
that is slightly different and that shows how the private
sector's total required external financing, capital structure,
and dividend policies combine to determine:
• Cash issues of preferred stock,
• Gross cash offerings of debt, and
• Cash issues of common stock.
Revenues and Related Variables
The third segment of the financial module determines
total industry revenues, expenses, profits, and related sta-
tistics such as price per kilowatt-hour and interest coverage
ratios. The output variables of this revenues segment serve
in many instances as inputs to other segments. For example,
the depreciation expense figure computed in the revenue seg-
ment is an input to the sources of funds segment. Conversely,
certain of the input variables to the revenue segment are
based on the output from the sources and uses segment of the
financial module (e.g., plant and equipment expenditures pro-
vide the base for computing depreciation expense). The struc-
ture of the revenue segment and the interactions between this
segment and other parts of the total model are depicted in
Exhibit B-5.
As shown at the top of Exhibit B-5, profits available for
common stockholders are assumed to be determined completely by
the amounts of the industry's common equity capital and by a
-------
B-5
rate of return on equity set by regulatory policy.^- As a
consequence of this assumption, revenues and prices per kilo-
watt-hour of electricity are determined by required profits,
other capital charges, and operating expenses.
Earnings before interest and taxes (EBIT) are simply the
sum of earnings before interest taxes (EBT) and interest
expense and are computed by the same general process used for
preferred dividends. The resultant EBIT figure constitutes
one of the five main determinants of revenues.
The second determinant of revenues, depreciation and
amortization of plant and equipment, is a variable related to
the amount of plant and equipment in service. Presuming that
taxes other than on income consist primarily of property
taxes, a third determinant of revenue, other taxes, is also
related to the amount of plant and equipment in service.
Generation expansion plans and the power drains and oper-
ating efficiency losses associated with pollution control
equipment combine to determine the level of operating and
maintenance expenses. This latter expense figure is the
fourth determinant of revenues.
Generation expansion plans and pollution control, require-
ments also determine the timing of future in-service plant and
equipment requirements and hence determine the amount of con-
struction currently in progress. The amount of construction
in progress in turn determines the allowance for funds used
during construction, which is another non-cash item, but which
also affects — in this case diminishes—the level of revenues
required to achieve a given level of profit as determined by
regulatory accounting procedures. This allowance on construc-
tion funds variable is the fifth and last major determinant of
revenues.
Net profit is simply the sum of profits available for
common stock and preferred dividends. The amounts of pre-
ferred dividends are determined by the amounts of preferred
equity capital and the average dividend rate on the industry's
^-It should be noted that "policy" is a term intended to com-
prise the effect of both the target rates of return set by
individual regulatory bodies and the administrative lags
involved in adjusting prices per kilowatt-hour so as to
achieve such target returns.
-------
B-6
outstanding preferred stock. The dividend yield on new pre-
ferred stock issues—and hence the average yield—is in turn
determined over time by the reaction of the capital market to
the industry's offerings.
«
Earnings before income taxes are then set at a level such
that EBT minus taxes will be equal to the required net profit
figure. The tax expense (or equivalently, the effective tax
rate) is itself a function of the EBT figure, which is com-
puted in accordance with regulatory accounting procedures, and
several other factors. The calculations are somewhat compli-
cated first because various special features of the tax code
(e.g., provisions allowing investment tax credits and acceler-
ated depreciation) and of regulatory accounting (e.g., the
creation of allowances for funds used during construction as
non-cash credits to income) must be taken into account. As a
consequence of these differing provisions, taxable EBT and
regulatory EBT may—and typically do—differ. Second, as
mentioned earlier, there exist two substantially different
regulatory methods for determining the tax expense figure to
be associated with EBT. Normalizing accounting gives rise to
deferred taxes, which are non-cash charges against income but
which nonetheless constitute an accounting expense to be
covered by revenues if accounting profits to stockholders are
to reach prescribed levels.
A CONCLUDING COMMENT
As has been outlined above, the operating, financial,
tax, regulatory, and accounting relationships and constraints
relevant to making economic and financial projections for the
industry are individually rather simple. However, the number
of these relationships and constraints is so great as to dic-
tate the use of a computer model such as PTm. Moreover, be-
cause of interactions among the various industry relationships
and constraints, attempts to reduce the number of factors
through sho-rtcut approximations are hazardous. Furthermore,
such shortcuts, even if based on careful econometric analyses
of historical data, tend to preclude an examination of the
implications of structural and policy changes.
PTm was designed not only to compute rapidly the implica-
tions of any given set of assumptions about the future, but
also to facilitate the examination of structural and policy
changes. Thus, the model is able conveniently to accept input
-------
B-7
assumptions for over 100 variables/ such as the current level
of and future changes in: the industry's peak demand; the
amount and mix of capacity additions; unit costs of generating
plants, transmission and distribution capacity, thermal and
chemical pollution equipmentf etc. PTm then generates projec-
tions for a variety of physical and financial variables, in-
cluding: generation figures for each of the major fuel seg-
ments of the industry; energy losses resulting from pollution
control equipment; income statements; balance sheets; funds
flows; reconciliations of regulatory and Internal Revenue
Service income tax expense figures; and summary statistics
such as interest coverage figures.
-------
Exhibit B—1
INTERACTIONS BETWEEN THE ENVIRONMENT AND THE PHYSICAL AND
FINANCIAL CHARACTERISTICS OF THE ELECTRIC UTILITY INDUSTRY
PtmHid
For Etaslik Pooir
•ml Capacity
E ipoulm Plant
Plant. Equipntanl,
and Opwaliuc
Cat* NMdi
I
VARIABLES TAKEN
~
GIVEN IV fTm
VARIABLES DETERMINED WITHIN PTm.
Sou ica: PTm lEtaclfic UlUllln).
Ealarnal Financing
PiarM, EqulpmMt,
and EUcliical
Powx Production
R«qulrHMnll
-------
Exhibit B-2
DETERMINANTS OF PLANT AND EQUIPEMENT IN SERVICE AND IN CONSTRUCTION
FOR THE ELECTRIC UTILITY INDUSTRY
Fuluil Oiraind
and Capacity
E Mpjuiion PUit
Curiml RiI^wmrU
linjiacl «• Ful«'* Pollution
Equipment on G#niiillO|
Plant EllkbMtr
Impact ol Curraol
PolNilion Equipment
m Gin«iilng riant
Ellldancy
Curiam Dimwd
and Capacity
Cuiiifll Ruifmiaii
PolliilkM Control
Etfulpmaot
Futura Grots
CapMiiy
CoihIiucum for
FulurtRiqukfrninli
Addition* lo Planl
and Cqulpowm In
&arvic« and In
CoiMliuclKin
Currant Raquirad
Grow Capacity
Comiruciion |of
Ciurml Rtquirwnmli
VARIABLES TAKEN A3 GIVEN BY PT«n
| 1 VARIABLES OETERMINEO WITHIN flm
Source HTn> |Elaclik Ulilllknl
-------
Exhibit B—3
DETERMINANTS OF USES OF FUNDS FOR THE ELECTRIC UTILITY INDUSTRY
CoM p«r Unit of
riwl aod
CAPITALIZED EXPENDITURES
rtoiil md EquifHnMI
Cantiiucalon lot
FiiUua RaqdltMunu
C ) VARIABLES TAKEN
I I VARIABLES DETERMINED WITHIN PTm
QIVEN IV rim
Coil pti Unit of
PUnl md
Cl|ui|NMNl
PtMl ind Equipnianl
CewMuclliw lor Currant
. RaquirAHMnii
T»Ul Um of Fundi
EipmdiiiNti lor ln-S«tvlc«
PlMl Mid EqHifiiMiii
Allowmca lor Fundi lifad
lor ConaUuclton ko
PfOgftU
l»pindiiwi lor lnaanl«|
haul Ml tquipmtnl
to CewliMlion
Souict: PIpi lEltclik Liiltliln).
-------
Exhibit B—4
DETERMINANTS AND COMPOSITION OF TOTAL SOURCES OF FUNDS FOR THE
ELECTRIC UTILITY INDUSTRY
TOTAL SOURCES OF INCOME
TOTAL SOURCES OP INCOME
Capftaf Sliurturi
Policy
CmJi IiunoI
D«bl RtlltMtonii
0 VAHIABLES TAKEN A3 OIVEN 8V PTm
1 1 VARIABLES DETERMINED WITHIN PTni
Paollt A«JliMl
lot Common
Slot*
Fundi Provld«4
by 0|Mriila(i«
Source: PTin lEIocirlc UiIIIiIm).
-------
Exhibit B-6
DETERMINANTS OF REVENUES. EXPENSES. AND PROFITS FOR THE ELECTRIC
UTILITY INDUSTRY
Capful Uukll
Condition*
Ptalirrtd Sloch
Cepital MiraM
Condition*
0«bi
Policy
Com
ol Pialanail
Siodi
Preferred Dividend!
Embedded Coal
ul Debt
Inlarni
Operating &
V——~
Maaatanance
(ipaiiut
Qapiictalion &
AmofiiuiHifl ol
PUnl and Equipnanl
RbquUIOVV
Pntky
Current
Demand md
Caoeclty
Reiurn oo
Equity
Eamitigi bitaia
InlNnl A 1 aiaa
Rtvmuo
Prolil Availalila
For Common
Com
mm Equily
Stock
I
Nil
Piotll
\
Earnings Laloie
Into.
M Tihh
Income Finn
AHowwica on
Funds Utod
Dufkifl
Construction
Tun olhw
ihtn Incoma
PImm& Equipment
b S«r«k«
Plant & Equipnieait
In Service
TuetPty^li
Deleaied
Policy
Future
Demend end
Capecily
Plant b
Equipment
In Coauliuctk)
k Policy J
Source Pint (Eloclik Ulilllunl
(^) VARIAULES TAKEN Afl QIVEN MY PTm
| | variables determined within pt«h
------- |