Power plant cumulative environment impact report

[From the U.S. Government Printing Office, www.gpo.gov]

PPSP-CEIR-3

POWER PLANT
@CUMULATIVE ENVIRONMENTAL
IMPACT REPORT

February 1982

Ti AND POWER PLANT SITING PROGRAM
164
M3 'OF NATURAL RESOURCES 0 DEPARTMENT OF HEALTH AND MENTAL
1982 1 DEPARTMENT OF ECONOMIC AND COMMUNITY DEVELOPMENT 0 DE
-STATEPL ANNING N DEPARTMENT OF TRANSPORTATION N DEPART-
4 ICULTURE 8 COMPTROLLER OF THE TREASURY E PUBLIC SERVICE

JAMES 8 COULTER LOUIS N PHIPPS, JR.
SECR*ETARY STATE OF MARYLAND DEPUTY'SECRETARY

DEPARTMENT OF NATURAL RESOURCES
TAWES STATE OFFICE BUILDING
ANNAPOLIS 21401

March 19, 1982

The Honorable Harry Hughes
Executive Department
Office of the Governor
State House
Annapolis, MD 21404

Dear Governor Hughes:

The 1981 Cumulative Environmental Impact Report prepared pursuant to the
Maryland Power Plant Siting Act is forwarded. The Report is an analysis of
the cumulative impact of electric power plants on Maryland's environment.

Eighty-seven percent of Maryland's electricity is currently generated,
using coal and nuclear fuels and it is likely that coal will displace even
more oil by the end of the decade. Increased coal use with its concommitant
potential for air, groundwater and surface water impacts from combustion,
transport and disposal will require thorough investigation in determining
appropriate conditions on the construction and operation of coal-fired power
plants.

Monitoring results show that nuclear plants (Calvert Cliffs, Peach
Bottom and Three Mile Island) are not exceeding regulatory constraints.
Establishment of a functioning system by the federal government for handling
spent nuclear fuel and high level radioactive waste is critical for the
continued operation of nuclear power plants in the United States beyond the
early 1990's. The federal government should be encouraged to determine
methods and locations for these wastes as soon as possible.

The information contained in this report demonstrates the importance of
the State's capability to collect and analyze technical data to insure that
Maryland continues to have an adequate supply of electricity without
degrading its natural resources or the human environment.

Sincerely yours,

James B. Cd@lter

JBC/kss
Enclosure
/Jam

PPSP-CEIR-3

POWER PLANT

CUMULATIVE ENVIRONMENTAL

IMPACT REPORT

U S DEPARTMENT OF COMMERCE NOAA
COASTAL SERVICES CENTER
2234 SOUTH H0BSON AVENUE
CHARLESTON, SC 29405-2413

FEBRUARY 1982

Property Of CSC Library

Maryland Department of Natural Resources

Comments and requests for additional copies should be
addressed to Editor, Cumulative Environmental Impact Report, Power
Plant Siting Program, Maryland Department of Natural Resources,
Tawes State Office Building, Annapolis, Maryland 21401

FOREWORD

The Cumulative Environmental Impact Report is issued every two years as
required by the Maryland Power Plant Siting Act. It is a compilation of all
studies relating to the cumulative impact of power plants on Maryland's
environment. Chapters were prepared under contract with principal
responsibility for content and completion vested in a member of the Power
Plant Siting Program Staff. Principal authors and their PPSP staff counter
parts are herewith acknowledged for their contribution to this effort:

Chapter I - Matt Kahal, Exeter Associates, Inc.; Howard Mueller, PPSP

Chapter II - Matt Kahal, Exeter Associates, Inc.; Howard Mueller, PPSP

Chapter III - Sally Campbell, MMC; Randy Roig, PPSP

Chapter IV - William Richkus, MMC; Randy Roig, PPSP

Chapter V - Rich McLean, PPSP

Chapter VI - Howard Mueller, PPSP

Chapter VII - Ed Portner, APL; Pete Dunbar, PPSP

Chapter VIII - Ed Portner, APL; Pete Dunbar, PPSP

Chapter IX - Randy Roig, PPSP

Chapter X - Tom Magette, PPSP

Chapter XI - Paul Miller, PPSP

I gratefully acknowledge Dr. Jorgen Jensen for his contributions in
putting this publication together; Karen Spencer and Daphne Heaphy for their
'Y
pat ient,2.Z5@@E@tin@,f' 'P'@ afid2 cheW-611-t- ping of numerous drafts; the many others
without whose contributions this publication could never have been completed.
Thank you.

Paul E. Miller
Editor, CEIR-III

SUMMARY

Chapter I - Power Demands in the State of Maryland

For decades prior to the early 1970's energy consumption grew steadily
in the United States while energy prices remained stable. The most important
factor sustaining this pattern was the availability of inexpensive oil,
imported mainly from the Middle East. 'These trends were brought to an abrupt
end in 1973 by the Arab oil embargo and subsequent events. Skyrocketing
prices and limited availability brought about sharp declines in energy usage.
Thus by 1980 the energy consumption was only marginally higher than in 1973.

The transient effects of the 1973 embargo have largely died out, and new
trends in the pattern of energy production and consumption have emerged. The
long range annual growth rate for total energy consumption has fallen from
4.1 percent for the 1960-1973 period to an expected 1.6 percent for the
1980-1995 period.

Prior to 1973 the national annual growth rate for electric energy was
about 7.3 percent. It is projected that the demand will grow by 3.2 percent
per year through 1995, while the demand for the other energy forms will
stagnate. Increased demand for electric energy coupled with increased coal
utilization by the industry is largely responsible for the proportional
increase in coal usage over other primary fuels.

This Chapter presents a detailed discussion of the electric utility
industry in Maryland. Projections of the future demand for electricity,
utilizing econometric models, are presented. The total of the peak demands of
the utilities serving Maryland is forecast to increase at an annual rate of
2.5% through 1990.

The potential for reduction of the growth rate of electricity demand
through implementation of conservation measures and load management is dis-
cussed. Load management can be accomplished through use of devices such as
radio controlled water heaters or through a ratemaking policy reflecting the
time-varying marginal cost of producing electricity.

Chapter II - Power Supply in the State of Maryland

The increasing demand for energy prior to the early 1970's was met
primarily by increasing natural gas and petroleum production and by higher
imports of petroleum. As a consequence of the 1973 oil embargo the nation's
supply of primary energy has shifted toward greater reliance on coal and
nuclear energy, In 1973 oil and gas accounted for about 78 percent of the
primary energy supply while coal and nuclear energy combined provided 19
percent of the supply. By 1985 it is expected that these percentages will be
62 and 33 respectively.

The pattern of electric power supply in the United States reflects the
conditions of the primary energy market (slower demand growth and higher fuel
prices) as well as changes in the regulatory environment. The Fuel Use Act
of 1978 prohibits use of oil or natural gas as a primary fuel for new
generating units and for existing units which can be converted from oil to

coal. These various factors are expected to cause the nation's electric
utilities to increase the use of coal and nuclear fuel from about 48 percent
in 1973 to about 74 percent and about 81 percent in 1985 and 1990
respectively.

Generation capacity of utilities serving Maryland is 33 percent oil and
gas fired and 66 percent from coal and nuclear. Since oil and gas fired
plants are operated less often than coal and nuclear power plants, the
electricity actually produced by oil and gas fired plants amounted to only
12% of the total, compared to 87% produced by coal and nuclear power plants.
By 1990, installed capacity is expected to be 25 percent oil and gas fired
and 70 percent fired by coal and nuclear.

The generation profile and capacity expansion plan for each of the
utilities serving Maryland are presented in this Chapter. These plans
provide for adequate capacity reserve margins throughout the period of the
current Ten-Year Plan.

Chapter III - Air Impact

Power plants contribute about 30 percent of the particulates, about 63
percent of the sulfur oxides, and about 28 percent of the nitrogen oxides
emitted by all sources in Maryland. Only negligible amounts of carbon
monoxide and hydrocarbons are contributed by the power plants.

For the three major pollutants emitted by power plants, air quality
shows a trend toward improvement for particulates and sulfur oxides, while
the level of nitrogen oxides has been relatively constant during recent W
years. All areas of the State are in compliance with the National Ambient
Air Quality Standards for sulfur and nitrogen oxides. A state implementation
plan has been prepared to bring the Baltimore Metropolitan nonattainment
region into compliance with the primary federal standards by 1982 and the
secondary (and more stringent) standards by 1986.

The theoretical and experimental work on mathematical models for predic-
ting air quality impacts is discussed in this Chapter.

Federal regulatory measures have impacted Maryland in two ways. The
first relates to the "emission offsets" policy of the Clean Air-Act. The
State is presently exploring the establishment of an offset "market" for the
Baltimore area. The second area of impact relates to coal conversion. Eight
units of the Baltimore Gas and Electric Company are under "prohibition
orders" which, should they become final, will prohibit burning of oil or
natural gas at these units. Since six of the units are located in or near
nonattainment areas for particulates the environmental consequences of these
conversions must be carefully examined.

Chapter IV - Aquatic Impact

Power plants can cause aquatic impact in several ways: 1) by entraining
fish eggs, larvae or other organisms into the cooling system where they will
be exposed to thermal, mechanical and thermal stresses; 2) by impinging fish
and crabs on intake screens; and 3) by discharging heat and chemicals into
receiving waters.

Since aquatic communities generally are characteristic of the salinity
zones they inhabit, the cumulative impact of power plant operations has been
assessed by salinity/habitat zones.

Because of the high reproductive rates of the plankton and good tidal
mixing at the existing plants in mesohaline regions of the Bay (Chalk Point,
Morgantown, Calvert Cliffs and Wagner), significant depletion of plankton
populations has not occurred. Ichthyoplankton is entrained by these plants,
but spawning occurs throughout the Bay for the species of fish present here,
so local depletions are insufficient to decrease Bay populations. Impingement
totals are small compared to mortality due to other causes. In addition,
efforts to reduce these totals are now underway at all major plants. Habitat
modification effects, usually more subtle in nature, have minor, localized
impacts as described in this chapter. Coupled together, the power plant
monitoring studies show a low cumulative impact on the mesohaline
environment.

The major area of concern within the tidal fresh/oligohaline region is
the impact of cooling water withdrawals upon the nursery and spawning areas
of striped bass and other anadromous species. Possum Point and Vienna have
the highest potential for impact. The estimated maximum total annual striped
bass loss would be about 1.0 percent of the adult population in the Maryland
portion of the Bay.

Data collected recently at Baltimore Harbor plants show that there are
abundant and diverse biota present in their vicinity. Measured impacts due
to entrainment, impingement, and habitat modification are uniformly small or
not present and restricted to the vicinity of the discharge. No evidence of
cumulative impact on the Bay ecosystem has been found. Temporally cumulative
impacts observed have been restricted to the immediate vicinity of discharge
and in some cases have been beneficial rather than deleterious.

Recent data from riverine plants have revealed impacts localized to the
discharge area. No cumulative river-wide effects are evident on the Potomac
River. The role of the Conowingo hydroelectric facility in the decline of
fisheries in the Susquehanna River remains a significant concern. Studies
currently underway address this issue.

Chapter V - Radiological Impact

The nuclear power plants affecting Maryland are Calvert Cliffs, on the
Chesapeake Bay (the only nuclear plant operating in Maryland), Peach Bottom,
and Three Mile Island, both on the Susquehanna River in Pennsylvania. Data
used in the assessment of the radiological impact of these plants come from
several monitoring programs described in this Chapter. Because the amount of
radioactivity released under stringent regulatory control is very small,
determination of power plant impact is complicated by the problem of
separating power plant effects from the background due to radioactivity from
natural sources or weapons-test fallout. For instance, fall-out from
weapons testing by the Chinese in 1978 introduced a dominant factor into the
monitoring measurements.

Releases of gaseous and liquid effluents from the plants, and the atmos-
pheric and aquatic distribution of radionuclides, as determined from the
monitoring programs, are presented. For the Calvert Cliffs plant it was
found that Sr-89 is the only radionuclide detectable in the atmosphere that
can be attributed to plant releases. The impact of the very low concentra-
tions of this element is deemed insignificant. Several power plant related
bioaccumulable radionuclides (Co-58, Co-60, Zn-65, and Ag-110m) are routinely
detected at low levels in Bay biota, with the exception of edible finfish.
The maximum detected concentrations would result in radiation doses to man
which are orders of magnitude below doses resulting from the natural radio-
active sources in the Bay environment. Consumption of seafood containing the
highest radionuclide concentrations measured would result in a plant-related
increment of less than 0.2 percent of the dose due to the natural background.

At Peach Bottom, 1-131 attributable to the plant has been detected in
the air and in milk on several occasions. 1-131 from the Chinese weapons
test and apparently from Three Mile Island has also been detected at the same
locations. Radiation doses from all these low 1-131 levels are, however,
well within the federal guidelines for power plant operations.

Liquid effluents containing power plant radionuclides have produced
detectable concentrations (of Zn-65, Cs-134, and Cs-137) in sediments and
biota of the Conowingo Pond, the lower Susquehanna River, and the upper Bay.
Consumption of Conowingo Pond water and contaminated finfish exclusively at
the highest radionuclide concentrations would represent about 1 percent of
the natural background radiation dose.

The accident at Three Mile Island resulted in detectable, low level con-
centrations of Xe-133 and 1-131 in air samples in Maryland. 1-131 was not
detected in cow's milk in Maryland nor were radionuclides attributed to that
power plant detected in the Susquehanna River in Maryland. The plant is
currently prohibited from discharging any accident-related water.

This chapter also discusses the radiological on-site and off-site plan-
ning required by Federal regulations.

Spent fuel is currently stored at the nuclear power plants because spent
fuel reprocessing was prohibited from 1977 to 1981 in this country. Although
this prohibition is now lifted it is not expected that reprocessing or off-
site storage of spent fuel will be possible until middle or late 1980's.
Storage of spent fuel is not considered to present a significant environ-
mental threat. Assuming present licensed capacity, and retaining the
capacity to discharge one full core, the projected date of the last refueling
that can be discharged to the spent fuel pool at Calvert Cliffs is April
1990. Under the same conditions, Peach Bottom has ability to store fuel
on-site until 1986 for Unit 2, and 1987 for Unit 3.

Chapter VI - Socioeconomic Impact

The construction and operation of a power plant may have significant
economic and social impact upon the community where it is located. The
effects include changes in population and land use patterns, traffic conges-
tion, changes in income, employment, and business activity, as well as

changes in local government tax revenues and spending. The magnitude of
these changes depends on the size, location, and composition of the affected
communities.

Early studies of the impacts caused by the Calvert Cliffs plant con-
struction showed the needs for a means of predicting impacts on the pre-
dominantly rural communities which are the proposed sites for future power
plants in Maryland. A computerized model was developed and subsequently used
to estimate the social and economic effects of the expansion of the Vienna
power plant. The plant is located on the border between Dorchester and
Wicomico counties. These counties and their urban centers, Cambridge and
Salisbury, will be affected.

The conclusions of this study are that: 1) the local economy can well
absorb the effects of increased employment during construction; 2) the demand
for additional housing can easily be met; 3) additional public services can
be provided within the existing frame work; 4) traffic congestion will be
minimal; 5) during the construction period neither Vienna nor Cambridge will
experience significant fiscal effects while Wicomico and Dorchester counties
will have a net increase in revenues, Salisbury is expected to suffer a small
construction period deficit; 6) during the operating period Dorchester County
will have a substantial net surplus whereas the effect on Wicomico County and
the cities will be negligible.

Expansion of the Vienna plant will lead to the strengthening of Eastern
Shore rail traffic because of the need for coal transport.

Chapter VII - Noise Impact

Noise associated with power plants can come from the primary generating
facility, from cooling towers, from coal handling equipment, or from
vehicular traffic associated with the plant operation.

A procedure for evaluating the impact of noise on people has been
developed by the U.S. Environmental Protection Agency. The State of Maryland
has established regulations restricting the noise levels.

The results of a noise evaluations at six proposed and existing Maryland
power facilities are described in this Chapter.

Chapter VIII - Solid Waste Management

Power plant operation generate large quantities of solid waste, mainly
flyash and scrubber sludge, and to a lesser extent bottom ash and boiler
slag. Waste product utilization is desirable and usually possible. Bottom
ash and some flyash is currently being sold for reuse. The remaining
quantities are placed in managed land fills. This chapter discusses the
potential problems of managing solid waste disposal.

There are no utility flue gas desulfurization systems operating in
Maryland and hence no sludge disposal impact. Flyash and bottom ash disposal
methods vary among the utilities. BG&E markets some of its flyash. All
utilities operate land fills at various places.

Vii

Previously utilized disposal sites are currently being studied by the
Power Plant Siting Program to determine if they are affecting the environ-
ment and if remedial measures are necessary.

Chapter IX - Groundwater

Four Maryland power plants use groundwater for their operation. The
reduction of water available to other users and the lowering of the water
level or "potentio-metric surface" surrounding the point of withdrawal is
evaluated.

Withdrawal at the Calvert Cliffs and Vienna plants have no adverse
effect on the aquifers involved. At the Morgantown plant the water level in
the lower of the two aquifers used has dropped substantially but no other
user is affected. At the Chalk Point plant the withdrawal from the Magothy
Aquifer could have significant impact on other users in the area. PEPCO has
indicated that future withdrawals will come mainly from new wells in the
deeper Patapsco aquifer which is not tapped by other users in the areas, and
which contains an adequate amount of water.

Chapter X - Transmission Lines

Construction of transmission lines has several impacts common to all
major construction projects such as sediment run-off, disturbance of wild
life habitats, and deforestation. In addition, electrical effects such as OF
radio and television interference, audible noise, ozone production, and spark
discharges can be present near transmission lines. Finally the presence of a
transmission line may cause aesthetic impacts, possibly affecting property
values.

The electric effects are only present at high voltage lines (500 KV and
above) and even then only in the immediate vicinity of the line, usually
within the power line right-of-way. The other effects can be minimized
through judicious routing of the transmission corridor, avoiding as much as
possible unique or environmentally sensitive areas.

This Chapter discusses the various factors that are important in the
routing of transmission line corridors.

It is concluded that no health effects associated with transmission
lines have been found. Electric effects can generally be avoided. Aesthetic
impact and impact on land value have been studied and no conclusive results
emerge.

viii

Chapter XI - Coolinp, Towers

Salt drift from the natural draft cooling tower at Chalk Point deposits
less than 8 kg/ha-month off site. This rate is below the rate at which
foliar damage was evident in commercial crops (20 kg/ha-month). Predicted
off-site deposition rates for the tower proposed at DP&L's Vienna expansion
are less than 25 kg/ha-month and reduction in crop yield is estimated to be a
few percent at the power plant site boundary and smaller off-site.

RECOMMENDATIONS

1. It is recommended that administrative or legislative methods be found
to further consolidate and streamline the current regulatory or
procedures for power plants. When the Power Plant Siting Act was
enacted in 1971, all state permits impinging on site suitability were
incorporated under the Public Service Commission certificate so that
there was a single regulatory proceeding for power plants in the
State. Since 1971 new environmental requirements at the federal level
have resulted in additional permits for water quality and solid waste
disposal. Decisions on these permits are only partially incorporated
in the PSC process.

2. Present requirements in law for a 10-year plan from each electric
utility should be extended to 15-years. Present trends indicate that
8-10 years are required to locate, license, and construct a fossil-
fueled plant and 10-15 years are required for a nuclear plant.

3. The continued disposal of low level radioactive waste and the
establishment of national capability for high level radioactive waste
disposal are critical to the continued operation of the Calvert Cliffs
Nuclear Power Plant. Negotiations should be concluded which will
allow Maryland to enter an interstate agreement for continued disposal
of low level radioactive waste. After January 1, 1986, States which
have concluded such regional agreements will be allowed by federal law
to exclude waste from outside their region. In addition, the federal
government should be encouraged to determine methods and locations for
storage of high level wastes as soon as possible.

4. The present State policy of considering both the need and the proposed
route for a given transmission line simultaneously has resulted in
failure to consider these facilities until they are imminently needed.
A preferable approach would be to identify and approve corridors
needed for long term growth, with permission for construction granted
at a later time, when short term need can be demonstrated. This would
allow the selection of corridors which would be more acceptable from
both environmental and developmental points of view. Incorporation of
these corridors into county plans, on a basis similar to that used for
identification of transportation corridors, would provide for orderly
planning, and prevent land use conflicts.

kh,

CONVERSION TABLE

I inch = 2.54 cm 1 acre = 4,047 m 2

1 foot = 0.305 m I lb 0.454 kg

1 st. mile = 1,6 09 m 1 Btu 252 calories

1 cu ft 28.3 liter = 28.3 x 10-3 m3
1 gallon 0.134 cu ft = 3.785 x 10-3 m3
1 cfs = 449 gpm = 28.3 x 10-3 m3/sec
106 gpm = 2.233 x 10 3 cfs = 63 m 3/sec
I acre foot = 4.36 x 10 6 cu ft = 123 x 10 3 m3

Concentration:.

1 ppb by weight in water I g/m
1 ppm by volume in air = 0.0224 X oncentration in jag/m 3
gram mol. weigh
t (C
Gram molecular weight:

02 = 30; 03 = 45; S02 = 62; No 29; N02 = 44;

The following values depend on many factors and vary a great deal.

Approximate values:

Heat value for coal = 12,500 Btu/lb

oil = 148,000 Btu/gallon

gas = 1,000 Btu/cu ft

One barrel of oil = 42 gallons

A coal burning plant operating at full capacity burns about 10 tons of
coal pes day per MW of capacity and requires about 900 g8m 2 cfs
0.057 m /sec of once through cooling water (heated by 10 F) per MW.

PF
TABLE OF CONTENTS

Page No.

FOREWORD . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

RECOMMENDATIONS . . . . . . . . . . . . . . . . . . . . . . . . . x

CONVERSION TABLE . . . . . . . . . . . . . . . . . . . . . . . . . xi

I. POWER DEMANDS IN THE STATE OF MARYLAND . . . . . . . . . .

A. Historical and Projected National
Trends in Energy Usage . . . . . . . . . . . . . . . .
B. Energy Usage in Maryland . . . . . . . . . . . . . . . 1-7
C. The Electric Utility Industry in Maryland . . . . . . .
D. Service Areas of the Major Maryland
Electric Utilities . . . . . . . . . . . . . . . . . . 1-17

Baltimore Gas & Electric Company . . . . . . . . . . . 1-17
Potomac Electric Power Company . . . . . . . . . . . . 1-19
Delmarva Power & Light Company . . . . . . . . . . . . 1-22
The Allegheny Power System . . . . . . . . . . . . . . 1-25
Summary of Economic and Electricity Usage Trends . . . 1-28

E. The Outlook for Growth in Power Demands . . . . . . . . 1-30
F. The Management of Demand . . . . . . . . . . . . . . . 1-37

Weatherization . . . . . . . . . . . . . . . . . . . . 1-38
Load Management . . . . . . . . . . . . . . . . . . . . 1-40

G. Historical and Projected Company Load Data . . . . . . 1-43

References . . . . . . . . . . . . . . . . . . . . . . . . 1-56

Ii. POWER SUPPLY IN THE STATE OF MARYLAND . . . . . . . . . . .

A. Nationwide Energy Production Trends . . . . . . . . . .
B. Generation Profiles of Maryland Utilities . . . . . . .

Baltimore Gas and Electric Company . . . . . . . . . .
Delmarva Power & Light Company . . . . . . . . . . . . 11-19
The Allegheny Power System . . . . . . . . . . . . . . 11-21
The Potomac Electric Company . . . . . . . . . . . . . 11-22

C. Generation Planning . . . . . . . . . . . . . . . . . . 11-23 1h,

Economic Principles of Generation Expansion Planning 11-24
Coal Conversion . . . . . . . . . . . . . . . . . . . . 11-28

xii

D. Alternatives to Conventional Generation . . . . . . . . 11-30

Municipal Solid Wastes . . . . . . . . . . . . . . . . 11-30
Solar. * * * * . . . . . . . . . . . . . . . . 11-31
Small Scale Hyd;o;l;c@ricity . . . . . . . . . . . . . 11-32
Wind Energy . . . . . . . . . . . . . . . . . . . . . . 11-32
Cogeneration . . . . . . . . . . . . . . . . . . . . . 11-33

E. A List of Electric Utility Industry Definitions . . . . 11-34

References . . . . . . . . . . . . . . . . . . . . . . . . . 11-36

III. AIR IMPACT . . . . . . . . . . . . . . . . . . . . . . . . . III-1

A. Sources of Major Pollutants . . . . . . . . . . . . . . III-1

B. Emission Trends of Major Pollutants . . . . . . . . . . 111-7

Total Suspended Particulates . . . . . . . . . . . . . 111-7
Sulfur Dioxide . . . . . . . . . . . . . . . . . . . 111-7
Nitrogen Oxides - . . . . . . . . 111-7
Hydrocarbons and C;rbon Monoxide . : '. *. *. *.''.**. '. 111-7

C. Standards . . . . . . . . . . . . . . . . . . . . . . . 111-14

Ambient Air Quality Standards . . . . . . . . . . . . . 111-14
Emission Limitations for Existing
Fuel-Burning Installations . . . . . . . . . . . . . . 111-14
New Source Review . . . . . . . . . . . . . . . . . . . 111-14

D. Health and Welfare Effects of Pollutants . . . . . . . . 111-20

Total Suspended Particulates and Lead . . . . . . . . . 111-20
Fluoride . . . . . . . . . . . . . . . . . . . . . . . . 111-21
Carbon Monoxide . . . . . . . . . . . . . . . . . . . . 111-21
Sulfur Dioxide . . . . . . . . . . . . . . . . . . . . . 111-21
Sulfates . . . . . . . u@ .. . . . . . . . . . . . . . . . 111-22
Potochemical Air Poll ion:
Hydrocarbons, Ozone, Nitrogen Oxides, PAN . . . . . . . 111-22
Other Pollutants . . . . . . . . . . . . . . . . . . . . 111-24

E. Status and Trends of Maryland Air Quality . . . . . . . 111-24

Total Suspended Particulates . . . . . . . . . . . . . . 111-26
Sulfur Dioxide . . . . . . . . . . . . . . . . . . . . . 111-26
Nitrogen Oxides . . . . . . * ' * * ' * * ' 111-27
Photochemical Oxidants and Hyd;oca;bon; *. . . . . . . . 111-27

F. Pollution Control . . . . . . . . . . . . . . . . . . . 111-27
G. Mathematical Modeling . . . . . . . . . . . . . . . . . 111-34
H. Regulating Effects . . . . . . . . . . . . . . . . . . . 111-37

Stack Height and Intermittent Control . . . . . . . . . 111-37
Nonattainment Areas . . . . . . . . . . . . . . . . . . 111-38

xiii

Prevention of Significant Deterioration . . . . . . . . 111-39
Coal Conversion . . . . . . . . . . . . . . . . . . . . 111-42

References . . . . . . . . . . . . . . . . . . . . . . . . . 111-43

IV. AQUATIC IMPACT . . . . . . . . . . . . . . . . . . . . . . . IV-1

A. Sources and Nature of Impact . . . . . . . . . . . . . . IV-1
B. Aquatic Habitats . . . . . . . . . . . . . . . . . . . . IV-7
C. Regulatory Considerations . . . . . . . . . . . . . . . IV-10
D. Aquatic Impact Assessment . . . . . . . . . . . . . . . IV-10

Mesohaline . . . . . . . . . . . . . . . . . . . . . . . IV-10
Entrainment . . . . . . . . . . . . . . . . . . . . IV-11
Impingement . . . . . . . . . . . . . . . . . . . . IV-13
Discharge Effects and Habitat Modification . . . . . IV-16

Tidal Fresh-Oligohaline . . . . . . . . . . . . . . . . IV-18
Entrainment . . . . . . . . . . . . . . . . . . . . IV-18
Impingement . . . . . . . . . . . . . . . . . . . . IV-20
Discharge Effects and Habitat Modification . . . . . IV-22

Riverine . . . . . . . . . . . . . . . . . . . . . . . . IV-23
Entrainment . . . . . . . . . . . . . . . . . . . . IV-23
Impingement . . . . . . . . . . . . . . . . . . . . IV-24
Discharge Effects and Habitat Modification . . . . . IV-24

Conowingo Dam - Hydroelectric Facility . . . . . . . . . IV-25

References . . . . . . . . . . . . . . . . . . . . . . . . . IV-27

V. RADIOLOGICAL IMPACT . . . . . . . . . . . . . . . . . . . . V-1

A. Calvert Cliffs Nuclear Power Plant . . . . . . . . . . V-3

Releases to the Environment . . . . . . . . . . . . . . V-4
Environmental Monitoring Programs . . . . . . . . . . . V-4
Atmospheric and Terrestrial
Radionuclide Distributions . . . . . . . . . . . . . . V-4
Aquatic Radionuclide Distributions . . . . . . . . . . V-11
Radiation Dose to Man . . . . . . . . . . . . . . . . . V-15
Summary . . . . . . . . . . . . . . . . . . . . . . . . V-15

B. Peach Bottom Atomic Power Station . . . . . . . . . . . V-15

Releases to the Environment . . . . . . . . . . . . . . V-18
Environmental Monitoring Programs . . . . . . . . . . . V-18
Atmospheric and Terrestrial
Radionuclides Distributions . . . . . . . . . . . . . . V-21
Aquatic Radionuclide Distributions . . . . . . . . . . V-27
Radiation Dose to Man . . . . . . . . . . . . . . . . . V-29
Summary . . . . . . . . . . . . . . . . . . . . . . . . V-30

xiv

C. Three Mile Island . . . . . . . . . . . . . . . . . . V-32

Accident . . . . . . . . . . . . . . . . . . . . . . . V-32
Releases to the Environment . . . . . . . . . . . . . . V-33
Atmospheric and Terrestrial
Radionuclide Distributions . . . . . . . . . . . . . . V-33
Aquatic Radionuclide Distributions . . . . . . . . . . v-36
Summary . . . . . . . . . . . . . . . . . . . . . . . . V-36

D. Radiological Emergency Planning . . . . . . . . . . . . V-37
E. Spent Fuel Accumulation . . . . . . . . . . . . . . . . V-38
F. Radioactive Materials Transportation . . . . . . . . . V-39

References . . . . . . . . . . . . . . . . . . . . . . . . v-41

Vi. SOCIO-ECOROMIC IMPACT . . . . . . . . . . . . . . . . . . . VI-1

A. Employment, Population, Housing and Fiscal Effects . . VI-2

Vienna Study . . . . . . . . . . . . . . . . . . . . . VI-3
Other Studies . . . . . . . . . . . . . . . . . . . . VI-8

B. Coal Transportation Effects . . . . . . . . . . . . . . VI-10
C. Traffic Congestion Effects . . . . . . . . . . . . . . VI-11
D. Cumulative Local Tax Revenues from
Maryland Electric Utilities . . . . . . . . . . . . . . VI-12

References . . . . . . . . . . . . . . . . . . . . . . . . VI-14

VII. NOISE IMPACT . . . . . . . . . . . . . . . . . . . . . . . VII-1

A. Noise Sources . . . . . . . . . . . . . . . . . . . VII-3
B. Noise Propagation . . . . . . . . . . . . . . . . . : . VII-5
C. Effects of Noise on People . . . . . . . . . . . . . . VII-5
D. State Noise Regulations . . . . . . . . . . . . . . . . VII-8
E. Site Evaluations . . . . . . . . . . . . . . . . . . . VII-8

References . . . . . . . . . . . . . . . . . . . . . . . . VII-11

VIII. GROUND WATER IMPACT . . . . . . . . . . . . . . . . . . . . VIII-1

References . . . . . . . . . . . . . . . . . . . . . . . . VIII-11

IX. SOLID WASTE MANAGEMENT . . . . . . . . . . . . . . . . . . IX-1

A. Chemical and Engineering Properties
of Flyash and Scrubber Sludge . . . . . . . . . . . . . IX-2
B. Disposal Techniques . . . . . . . . . . . . . . . . . . IX-5
C. Environmental Impacts . . . . . . . . . . . . . . . . . IX-10
D. Regulatory Status . . . . . . . . . . . . . . . . . . . IX-10
E. Vienna Example . . . . . . . . . . . . . . . . . . . . IX-12
F. Waste Disposal in Maryland . . . . . . . . . . . . . . IX-14
G. Long term Considerations . . . . . . . . . . . . . . . IX-16

References . . . . . . . . . . . . . . . . . . . . . . . . IX-17

X. TRANSMISSION LINES . . . . . . . . . . . . . . . . . . . . X-1

A. Environmental Impacts . . . . . . . . . . . . . . . . . X-1
B. Electrical Effects . . . . . . . . . . . . . . . . . . X-5
C. Health Effects . . . . . . . . . . . . . . . . . . . . X-7

References . . . . . . . . . . . . . . . . . . . . . . . . X-8

XI. COOLING TOWERS . . . . . . . . . . . . . . . . . . . . . . XI-1

A. Chalk Point . . . . . . . . . . . . . . . . . . . . . XI-1
B. Vienna . . . . . . . . . . . . . . . . . . . . . . . . XI-2

References . . . . . . . . . . . . . . . . . . . . . . . . XI-3

APPENDIX A . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

APPENDIX B . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2

THE 1982 TEN YEAR PLAN OF MARYLAND ELECTRIC UTILITIES

xvi

CHAPTER I

POWER DEMANDS IN THE STATE OF MARYLAND

The operation and planning of electric utilities are determined by their
customers' power demands. The last few years have witnessed important changes
in patterns of demand which will have important implications for the construc-
tion of additional power plants. The most important of these changes is the
sharp reduction in both actual and forecasted long-range load growth rates which
has lead in recent years to cancellations, size reductions and scheduling delays
for new generating units. In many cases it has also left utilities with
substantial excess generating capacity -- a burden which is ultimately borne by
ratepayers.

This chapter discusses the power demands facing utilities in the State of
Maryland. The supply of electric power is covered in Chapter II. To place the
subject of power demands in perspective, long term U.S. and Maryland energy
usage trends are discussed. The structural interelationships among Maryland
utilities are presented along with the basic characteristics of the service
territories of the major systems. The future outlook for power demands on these
systems is considered. A brief look at the Power Plant Siting Program (PPSP)
load forecasting activities is included, although a more detailed discussion of
the PPSP load forecasting methodology is deferred to Appendix A of this Report.
Finally, this chapter provides a survey of the various methods and techniques
which can be used to "manage" the growth of power demands. Although these
methods are not being extensively employed in Maryland at the present time, they
have the potential to significantly reduce the expensive oil-fired generation
and the need to build additional capacity.

A. Historical and Projected National Trends in Ener_qy Usage

Prices and supplies of competing sources of energy are determined by
regional, national and even international markets. National policy decisions
influence the operation of those markets, and as a consequence they shape energy
options available in Maryland. It is helpful, therefore, to consider the
national energy framework within which Maryland energy markets operate.

During the decades prior to the early 1970's energy production and usage
grew steadily while energy prices remained stable and even declined somewhat.
Energy demand was stimulated by rising living standards; increased automobile
dependence arising from suburbanization; the tendency in industry to replace
labor with energy-using capital equipment; the growth of energy intensive
industries such as chemicals, paper and aluminum; and the increasing adoption of
air conditioning. Stable prices in the face of rapid demand growth were made
possible by several factors, including productivity advances and new fuel
resource discoveries. Most important, however, were the rapidly growing imports
of inexpensive oil, mainly from the Middle East.

These trends were brought to an abrupt end in 1973 by the Arab oil embargo
and subsequent events. The embargo meant an immediate elimination of the key
ingredient to stable energy prices -- cheap, abundant imported oil. Oil and gas
(and even coal) prices skyrocketed, and availability, in some instances, became

a problem. These developments, coupled with the severe 1974-1975 recession,
brought about sharp declines in energy usage. Although economic growth resumed
in 1976, energy prices had risen to such an extent that energy users were still
in the process of adjusting to the earlier price shocks. Thus, by 1977 U.S.
primary energy consumption was approximately at the same level as in 1973.

Another round of energy price shocks (and oil scarcity) occurred in 1979
accompanying the Iranian Revolution. These further price increases along with
increasing national and state government efforts to encourage conservation led
to a further dampening of demand.

The general energy trends of the late 1970's -- rising real prices,
sluggish consumption growth and greater reliance upon coal -- are expected to
continue in the future. According to the U.S. Department of Energy, Energy
Information Administration (EIA), energy prices will increase faster than the
rate of inflation, while overall U.S. (primary) energy consumption will only
increase by 1.6 percent per year. Also, by 1995 coal is expected to drama-
tically increase its share of primary energy to 40.0 percent from 20.6 percent
in 1980. These projections along with historical trends since 1960 are shown in
Table 1-1. The prices indicated in this table (expressed in 1972 dollars) are
those received by U. S. producers. In 1980, the price per million Btu's (MBtu)
was roughly $1.26 for coal, $4.88 for oil and $1.39 for natural gas.

Energy consumption by major end-use sector and fuel type is shown in Table
1-21- As these figures indicate, only the industrial sector is expected to
increase its energy usage significantly. Electricity demand is projected to
grow noticeably in all sectors, while oil consumption is projected to decline
among all customer groups, even in transportation which is almost entirely
powered by oil.

Both tables reveal some important trends in energy consumption. From
1960-1973, energy usage grew steadily while real prices declined. These trends
were interrupted in the mid-19701s; total energy usage in 1980 only marginally
exceeded that in 1973. Overall energy demand is projected by EIA to grow in the
future but only modestly, and energy prices are expected to increase sign-
ficantly.

It is also important to recognize the shifts in fuel mix which have taken
place and will continue to occur in the future. Up until the mid 19701s, oil
and gas had been gradually and steadily displacing coal usage, particularly for
transporation and building heating applications. Oil also began to replace coal
in existing utility boilers as the result of State and Federal air pollution
legislation and regulations, principally the Clean Air Act Amendments of 1970.
Also, a large percentage of the new generating units brought on-line during this
period was oil-fired. Trends in utility generation mix will be discussed in
more detail in Chapter II.

-------------------------
IThe major difference between Table I-1 and 1-2 is the "energy conversion" loss.
Table 1-1 is primary energy while Table 1-2 is end-use energy and is therefore
net of conversions. This is most important in the electric utility industry
where fuels are burned to generate electricity, and about two-thirds of the ori-
ginal energy is lost in the conversion process. Thus, the 1995 total energy
usage in Table 1-2 is 65.7 quads compared to 93.5 quads of primary energy.
Nearly a third of primary energy is lost in the conversion process and most of
that is in the electric utility sector. This furthur emphasizes the prominent
role of that industry in the energy sector.

1-2

a M

Table 1-1

U.S. Energy Consumption and Price by Primary Energy Type 1960-1995

Coal Petroleum Natural Gas Nuclear Hydroelectric Total
Lear Quads Price Quads Price Quads Price Quads Quads Quads

1960 10.1 $0.40 20.0 $0.83 12.7 0.21 0.1 1.6 44.5

1965 11.9 0.34 23.2 0.76 16.1 0.21 0.1 2.0 53.3

1970 12.7 0.35 29.5 0.68 22.0 0.19 0.2 2.6 67.1

1973 13.3 0.38 34.9 0.71 22.5 0.21 3.0 74.6

1974 12.9 0.60 33.5 1.43 21.7 0.27 1.2 3.3 72.6

1975 12.8 0.62 32.7 1.50 19.9 0.35 1.8 3.2 70.6

1976 13.7 0.62 35.1 1.50 20.3 0.43 2.0 3.0 74.4

1977 14.1 0.64 37.0 1.56 19.6 0.55 2.7 2.4 75.8

1978 13.9 0.70 38.0 1.51 20.0 0.59 3.0 3.2 78.1

1979 15.1 0.71 37.1 1.98 20.7 0.71 2.8 3.2 78.9

1980 15.7 0.74 34.3 2.87 20.4 0.82 2.7 3.1 76.2

1985 20.6 0.90 30.3 4.13 18.1 1.96 5.6 3.2 77.8

1990 27.6 0.94 30.7 4.58 17.4 2.06 8.0 3.2 86.9

1995 35.0 1.00 29.1 5.58 17.0 2.51 9.1 3.3 93.5

Table 1-1 (Continued)

Annual Rates of Growth M

Coal Petroleum Natural Gas Nuclear Hydroelectric Total
Quads Price Quads Price Quads Price Quads Quads Quads

1960-
1973 2.1% -0.5% 4.4% -1.1% 4.5% 0.0% 5.0% 4.1%

1973-
1980 2.4 10.1 -0.3 22.0 -1.4 22.4 17.0 0.5 0.3

1980-
1985 5.6 4.4 -2.5 7.5 -2.4 19.0 15.7 0.6 0.4

1980-
1995 5.5 2.0 -1.1 4.5 -1.2 7.7 8.4 0.4 1.4

Notes : (a) Quad = Quadrillion Btu's = 1015 Btu.
M Prices are deflated to 1972 dollars by the GNP Deflator. Prices are
expressed in dollar per million Btu.
(c) Coal prices are bituminous delivered prices to electric utilities.
Petroleum prices are refiner aquisition prices, and projections are
world oil prices. Gas prices are domestic well head prices.
(d) All projections are the EIA "mid" case projections.

Source: (1), (2)

Table 1-2

Energy Consumption by End-Use and Fuel Type
(Quadrillion Btu's)
Residential(b) 1965 1973 1978 1985(a) 1995(a)

Oil 3.1 3.8 3.4 2.6 1.9
Gas 4.2 5.2 5.2 5.0 5.1
Electricity 1.0 2.0 2.4 2.8 3.5
Total** 8.6 11.2 11.1 10.6 10.6

Commercial (b)

Oil 2.0 2.4 2.3 1.4 1.0
Gas 1.4 2.4 2.4 2.3 2.8
Electricity 0.8 1.5 1.7 2.0 2.7
Total (c) 5.4 7.7 7.7 7.1 8.1

Transportation

Total 12.8 18.9 20.9 18.3 18.7

Industrial

Oil 3.7 5.2 6.5 3.5 4.0
Gas 7.3 10.4 8.5 8.6 9.3
Coal 5.4 4.4 3.4 4.7 7.3
Electricity 1.5 2.3 2.7 3.4 5.1
Total (c) 19.1 24.0 23.2 22.5 28.3

(a) Forecasts are EIA mid-price case.

(b) Master metered apartments are here listed as residential.

Source: (2)

1-5

40 Coal Consumption

35
11 PrJce

. . .........
30

oil Consumptiod
$4 25 -

20 - Gas Price

$2
Gas Consumption

$1 a Coal Price

0
1960 1965 1970 1975 1980 1985 1990 1995
.................

Figure I-1. U.S. primary energy consumption and prices in 1972 dollars.
Prices quoted in text are in 1980 dollars.

I I or r, liq

With the dramatic increases in gas and oil prices relative to coal, and the
perception of gas and oil as insecure, industry and utilities began switching
toward coal. At the same time the household and transportation sectors have
been increasing their efforts to conserve on oil and gas usage. With natural
gas in short supply in the early and mid 19701s, federal and state authorities
implemented curtailment plans. Many industrial users were curtailed, and in
many areas of the country (including Maryland) restrictions on new residential
and commercial hook-ups were imposed. As a result, the natural gas share of
total energy usage fell sharply within the space of just a few years.

During the decade of the 19701s, coal's decline was arrested and even
moderately reversed. Over the next 15 years EIA expects an enormous relative
and absolute increase in coal usage as both industrial and utility boilers shift
away from oil and gas. Since most coal (over 70 percent) is consumed by the
electric utility industry, and since coal is already the most important fuel in
that industry, electricity demand growth will help to drive this process.

EIA projects that electricity demand will grow by roughly three percent per
year while the end-use demand for other energy forms will stagnate. Industrial
usage of coal will increase, but that will be more than offset by reductions in
oil and gas, mainly in the nonindustrial sectors. Electricity will therefore
become more and more heavily relied upon to serve this nation's future energy
needs. The increasing relative importance of electricity is also largely
responsible for the growth of coal's share of total primary energy.

Historical and projected electrical energy demand are shown in Table 1-3.
Electricity sales, particularly to residential and commercial customers, grew
rapidly prior to 1973. Since 1973 sales growth has been moderate. EIA projects
that a change in growth patterns will occur over the next 15 years. Whereas in
the past there has been a fairly clear tendency for the residential and commer-
cial demands to grow more rapidly than industrial, in the future the industrial
sector is expected to grow more rapidly. The projected industrial growth rate
of 4.2 percent annually is nearly double the combined residential/commercial
rate of 2.3 percent.

B. Energy Usage in Maryland

Comparisons of historical energy usage patterns between the U.S. and
Maryland through 1977 are presented in Tables 1-4 and 1-5. These tables present
energy consumption at the end-use level by major customer groups and major
fuels. It does not include energy consumed in the process of producing electri-
city. In addition to percentage breakdowns for the various fuel-types and end-
use groups, Table 1-5 shows consumption growth rates for 1960-1973, 1973-1977
and 1960-1977.

Although similar in many respects, there are some noticeable differences
between Maryland and the U.S. in patterns of energy usage. In Maryland, the
residential, commercial and transportation sectors are relatively more prominent
energy users, whereas the industrial sector is substantially less energy inten-
sive than nationwide. Natural gas is relatively less important in Maryland
(15.9 percent of total energy consumption compared to 26.7 percent nationwide in
1977), but petroleum is noticeably more important. Nearly 60 percent of all
energy consumed in Maryland at the end-use level is petroleum compared to

1-7

Table 1-3 PF

Sales of Electricty by Customer Class in the U.S
(Billions of kWh)

Year Residential Commercial Industrial Other Total

1960 202 131 325 32 689

1970 466 307 571 48 1,392

1973 579 388 686 59 1,713

1974 578 385 685 58 1,706

1975 585 402 675 68 1,730

1976 603 424 740 70 1,836

1977 641 445 772 70 1,929

1978 671 460 801 73 2,005

1979 683 473 842 73 2,071

1980 717 488 815 74 2,094

1985 784 524 1,002 -- 2,418

1990 881 612 1,231 2,831

1995 989 713 1,504 -- 3,332

Annual Rates of Growth

1960-
1973 8.4% 8.7% 5.9% 4.8% 7.3%

1973-
1980 3.1 3.3 2.5 3.3 2.9

1980-
1995 2.2 2.6 4.2 --- 3.2

Source: (1), (2)

1-8

Table 1-4

U.S. and Maryland Energy Consumption, 1960-1977
(Trillion Btu's) (a)

1960 1973 1977
Residential(b) -us MD us MD us MD

Petroleum 2,638 52.7 3,195 57.9 2,990 56.4
Gas 3,202 47.4 5,036 75.4 4,983 67.3
Electricity 670 9.3 1,890 32.4 2,226 36.7
Total (c) 7,183 117.1 10,303 166.4 10,283 160.7

Commercial (b)

Petroleum 2,497 61.9 3,739 90.6 3,515 72.4
Gas 1/053 8.3 2,680 30.8 2,577 28.9
Electricity 468 4.0 1,561 25.0 1,832 26.1
Total (c) 4,398 78.8 8,083 147.0 7,973 127.6

industrial

Petroleum 2,319 59.2 3,184 73.8 3,694 49.8
Coal 4,685 140.0 4,270 160.7 3,823 84.6
Gas 4,481 17.2 10,567 62.7 8,740 39.1
Electric 1,176 16.5 2,345 37.6 2,583 44.1
Total (c) 15,386 257.2 24,679 365.0 23,216 243.3

Transport

Total (c) 9,639 163.6 18,311 302.7 19,515 318.3

Totals

Petroleum 17,093 337.4 28,429 525.0 29,714 496.9
Gas 8,736 72.9 18,283 168.9 16,300 135.3
Electricity 2,331 29.8 5,811 95.0 6,656 106.9
Coal 5,738 152.3 4,555 162.3 3,957 85.2

Grand Total(c) 36,606 616.7 61,376 981.1 60,987 849.9

(a) Excludes energy used to produce electricity.

(b) Master metered apartments are here listed as commercial.

Source: (3)

1-9

Table 1-5

U.S. and Maryland Energy Consumption, 1960-1977

Fuel Type and End-Use Annual Consumption Growth Rates
Sector Shares (1977) 1960-1973 1973-1977 1960-1977
U.S MD. U.S. MD. U.S. MD. U.S. MD.

Residential

Petroleum 29.1% 35.1% 1.5% 0.7% -1.6% -0.7% 0.8% 0.4%
Gas 48.5 41.9 3.5 3.6 -0.3 -2.8 2.6 2.1
Electricity 21.7 22.8 8.3 10.1 4.2 3.2 7.3 8.4

Commercial

Petroleum 44.1 56.7 3.2 3.0 -1.5 -5.5 2.0 0.9
Gas 32.3 22.7 7.5 10.6 -1.0 -1.6 5.4 7.6
Electricity 23.0 20.5 9.7 15.1 4.1 1.1 8.4 11.7

Industrial

Petroleum 15.9 20.5 2.5 1.7 3.8 -9.4 2.8 -1.0
Gas 37.7 16.1 6.8 10.5 -4.5 -11.1 4.0 5.0
Electricity 11.1 18.1 5.5 6.5 2.5 4.1 4.7 6.0
Coal 16.5 34.8 -0.7 1.1 -2.7 -14.8 -1.2 -2.9

Fuel Shares

Petroleum 48.7 58.5 4.o 3.5 1.1 -1.4 3.3 2.3
Gas 26.7 15.9 5.9 6.7 -2.8 -5.4 3.7 3.7
Electricity 10.9 12.6 7.3 9.3 3.5 3.o 6.4 7.8
Coal 6.5 10.0 -1.8 0.5 -3.5 -14.9 -2.2 -3.4

End-Use Shares

Residential 16.9 18.9 2.8 2.7 -0.1 -0.9 2.1 1.9
Commercial 13.1 15.0 4.8 4.9 -0.3 -3.5 3.6 2.9
Industrial 38.1 28.6 3.7 2.7 -1.5 -9.6 2.5 -0.3
Transportation 32.0 37.5 5.1 4.9 1.6 1.3 4.2 4.0

Source: Table 1-4

I I i I r I

approximately 50 percent for the entire U.S. Maryland's relatively heavy oil
dependence is characteristic of most of the Northeast part of the country.

Energy usage grew rapidly in Maryland (as in the rest of the nation) bet-
ween 1960 and 1973 for all major fuels (except coal at end-use). The decline in
coal consumption (excluding its use in generating electricity) was more than
offset by large increases in the consumption of gas, oil and electricity.
Electricity demand more than tripled in Maryland during this period. Since 1973
energy demand has fallen sharply, more sharply than for the nation as a whole.
An important exception to this trend is electricity usage which grew by 3 per-
cent per year. However, even this growth is very modest compared to the
pre-1973 annual growth rate of over 9 percent. This post-1973 conservation has
occurred, both in Maryland and the rest of the nation, in all major end-use
classes except transportation. The exceptionally sharp reduction in energy con-
sumption by Maryland industry has been due to both conservation efforts and a
longer term tendency for economic activity in the heavy industry (i.e., energy
intensive) sectors in the State to decline.

C. The Electric Utility Industry in Maryland

Households and business in the State of Maryland receive electric power from
four large and several small utilities operating in the State. Generally
speaking, these utilities fall into three main categories:

(a) Investor owned utilities -- Typically, these are large, integrated
electric systems engaged in the production, transmission and sale of
electricity. Such systems often operate in more than one regulatory
jurisdiction and may sell power on a firm basis to smaller power
distributors.1 Most Maryland customers are served by one of four such
systems.

(b) Municipal utilities -- Several medium-size and small towns in the State
own and operate their own utility systems. In most instances Maryland
municipals have operated as distribution systems only, purchasing bulk
power from the investor-owned utilities.

(c) Rural Electric Cooperatives -- Coops are similar in many respects to
municipal utilities in that they are not set up as profit making ven-
tures. Just as municipals are "owned" by the voters, coops are operated
by the ratepayers with financial assistance from the Federal
goverrunent's Rural Electrification Administration. Coops serve predomi-
nantly rural areas, although they often also serve the towns within
their geographic service areas. Two major rural electric cooperatives
operate in Maryland.2

-----------------------------------
1 Two investor owned utilities in Maryland, the Susquehanna Power Company (a
subsidiary of Philadelphia Electric) and Pennsylvania Electric Company have
hydroelectric facilities in Maryland at Conowingo Dam and Deep Creek Lake,
respectively. Neither utility sells power on a retail basis in Maryland.
Conowingo Power Company (also a Philadelphia Electric subsidiary) serves most of
Cecil County but has Ino generating capacity of its own.
2 In addition, A&N and Somerset Rural Electric Cooperatives serve a verV small
number of customers on Smith Island and in Garrett County, respectively.

With the resurgence of interest in cogeneration (discussed in Chapter II) and
small power production, many large power users (and perhaps even some
households) may satisfy some or all of their requirements by producing their own
power. Currently, the Sparrows Point Bethlehem Steel plant produces much of the
electricity it consumes.

Four major investor-owned utilities serve,the majority of the customers in
the State and produce nearly all of the electricity consumed. These utilities
are:

� Baltimore Gas & Electric Company (BG& E). -- BG&E serves nearly 750,000
customers in the Baltimore metropolitan area. In 1980 BG&E's annual peak
was 3,969 megawatts compared to installed generating capacity of 4,995 at
the time of the peak. Unlike the other large utilities in the State,
BG&E has no service territory outside of Maryland nor does it provide
power to any municipals or cooperatives.

� Delmarva Power & Light Company (DP&L DP&L, directly or indirectly,
provides almost all of the power consumed on the Delmarva Peninsula (and
thus the Eastern Shore of Maryland) with the exceptions of Cecil County,
the City of Dover and the Town of Easton., DP&L serves nearly three-
quarters of the Peninsula electric customers at retail, and it provides
bulk power as a wholesaler to the numerous municipals and coops which
directly serve the rest. In 1980 DP&L experienced a systemwide peak
demand of 1,581 megawatts and a Maryland portion peak of 410 megawatts.1
At the time of the peak the Company owned 2,062 megawatts of generating
capacity systemwide with only 252 megawatts located in Maryland. Thus,
the bulk of the customers, load and service territory is located in
Delaware.

Potomac Electric Power Company_(Pepco). -- Pepco serves approximately
500,000 customers at retail in the District of Columbia and its Maryland
suburbs. In addition, it indirectly serves most of St. Mary's, Calvert
and Charles Counties through its wholesale sales,to the Southern Maryland
Electric Cooperative (SMECO). It also serves a small number of customers
in the Northern Virginia suburbs. Maryland sales comprise slightly more
than half the entire Pepco system. In 1980 Pepco experienced a peak
demand of 4,142 megawatts compared to an installed generating capacity of
4,999 megawatts.

Potomac Edison Company (PE). -- PE provides power to Western Maryland
along with contiguous areas in Virginia and West Virginia. PE is one of
the three utility subsidiaries of the Allegheny Power System (APS). The
other two, Monongahela and West Penn Power, serve the northern half of
West Virginia and southwestern Pennsylvania, respectively. APS
experienced a peak of 5,564 megawatts for the winter of 1980/1981 (both
APS and PE are winter peaking) while having 7,671 megawatts of generating
capacity. The Maryland portion of PE comprises approximately a fifth of
the APS load, but only 117 megawatts of generating capacity are located
in the State. In addition to serving retail customers in the western
counties, PE sells power on a wholesale basis to three Maryland
municipals.

---------------------------
1 These peak demand figures include the loads of all municipals and cooperatives
with the exception of Easton, Maryland and Dover, Delaware.

1-12

Table 1-6 presents the municipals and cooperatives operating in Maryland
along with some basic descriptive data. In terms of sales, most of the munici-
pals are quite small, and only Easton has been generating any significant amount
of power.1 It is also interesting to note that, in contrast to many investor-
owned utilities, the majority of sales by municipals and cooperatives are made
to residential customers. The residential sales figure of 1,020 million MWh
represents 57 percent of total retail electricity sales of these companies. It
should be noted that although Easton Utilities is not a wholesale customer, it
is fully integrated with DP&L and engages in economy sales (and purchases) on an
interchange basis. It is the only municipal or cooperative in the State which
is not a wholesale customer of another utility.

Figure 1-2 is a map of the State of Maryland identifying the areas of the
State served by each utility. The DP&L service area is difficult to identify
on the map since the Maryland Eastern Shore is also served by Choptank and the
several municipals. The municipals are identified by numbered dots (except for
Centreville). In the central portion of the Eastern Shore, most of the rural
portions are served by Choptank while DP&L serves the towns.

Three of the four major utilities in Maryland are part of larger multistate,
and in one case, multicompany systems. These four systems not only provide
retail service to most of the State, they also provide nearly all of the bulk
power to the municipal and cooperative power distributors. These systems do not
function as totally isolated entities, however. There are many ways in which a
utility can interact with other systems even if those other systems operate in
other regulatory jurisdictions. Such arrangements may include integrated power
pooling, joint ownership of generation or transmission facilities, sales of firm
power, opportunistic economy sales and diversity power swapping arrangements.
Maryland utilities routinely engage in bulk power transactions primarily through
the Pennsylvania-New Jersey@Maryland Interconnection (PJM). With the exception
of Potomac Edison (and the municipals it serves), all Maryland electric utili-
ties are fully integrated with the PJM power pool. As a subsidiary, Potomac
Edison participates fully in the APS power pooling arrangements. In addition,
PJM and APS themselves conduct transactions with other utilities and power
pools. For example, APS and The Virginia Electric Power Company (Vepco) engage
in a diversity exchange whereby Vepco (a summer peaking utility) sends power to
APS in the winter, and APS (a winter peaking utility) returns those kilowatt
hours during the summer months.

To illustrate the importance of the off-system transactions, Table 1-7 shows
the quantity energy purchased and sold to other systems along with total power
supplied to meet native load (i.e., retail and wholesale obligations). For pur-
poses of comparison, power purchased is expressed as a percentage of total power
supply, and power sold (off-system) is expressed as a percentage of system
generation. As the figures indicate, Potomac Edison is a large net purchaser
of power, but the three Maryland PJM utilities are net sellers to the pool.

I Choptank, through its parent organization, The Old Dominion Electric
Cooperative, intends to share in 50 megawatts from the Vienna 9 coal-fired unit
which has a planned in-service date of 1990.

1-13

Table 1-6

Maryland Municipal and Rural Electric Cooperatives (1980)

Peak Generating
Sales Wh) Power Generation Demand Capacity
Residential Nonresidential Total Source (MWh) (W (MK)
Municipals

Berlin 7,369 15,971 23,340 DP&L 6,203 6.4 @3.5

Centreville* 22,093 16,408 38,501 DP&L 0 8.8 0.0

Easton 34,659 72,054 106,713 Self & 93,400 23.6 47.8
DP&L

Hagerstown 81,412 123,164 204,576 PE 0 48.9 20.0

St. Michaels* 20,395 13,084 33,479 DP&L 0 10.8 0

Thurmont 5,611 25,001 30,612 PE 0 6.8 0

Williamsoort 6,053 5,775 11,828 PE 0 3.1 0

Cooperatives

SMECO 616,788 415,947 1,032,735 Pepco 0 269.1 0

Choptank 225,406 70,905 296,311 DP&L 0 69.8 0

Total 1,019,786 758,309 1,778,095 99,603 447.3 71.3

Centreville and St. Michaels are no longer independent municipal systems.
They are now served at retail by DP&L.

Source: (4)

.000m M M M M M M M M

Pennsylvania

SOMERSET RURAL POTOMAC ED I SON BG &E CONOWINGO POWER CO.
ELECTR I C COOP

600
3 CARROLL
IIARfORD Delaware

BALTIMORE
E,

HHOWARD
Virginia EN CENTREVILLE
RY KA=11 ANINES
D
A@VA
ELM
OF MD.
PEPCO TALBOT &
9 MUNICIPAL ELECTRIC COMPANIES CHOPTANK
1) Williamsport PRINCE 4 CAROLINE ELECTRIC
Ln 2) Hagerstown GEORGES COOP
31 Thurmont
4) Easton CHARLES CALVERT, St. Michaels
5) Berlin DORCHESTER - - --- ---- I
WICOMICO
ST MARYS

WORCHESIER
SOUTHERN MARYLAND SOMERSET"
ELECTRIC COOP
I
>

ACCOMACK-NORTHAMPTON COOP
(SMITH ISLAND)
------ COUNTY BOUNDARY LINES *GENERALLY.. DELMARVA P&L - CITIES & TOWNS
ELECTRIC SERVICE BOUNDARY LINES lApprox.) CHOPTANK - SUBURBS & RURAL

Figure 1-2. Service territories of Miaryland electric utilities

Table 1-7

Interchange Purchases and Sales, 1980
(Millions kWh)

Total
Net Power
Purchases(a) Sales (b) Purchases Supply
Quantity Quantity

Pepco, 4,832 27.4% 5,265 29.1% -433 17,647

BG&E 1,665 9.0 3,013 15.1 -1,347 18,573

DP&L 696 8.7 1,059 12.6 -363 8,029

P.E. 2,681 25.5 1,590 16.9 1,091 10J1499

Total 9,874 18.0 10,927 19.6 -1,052 54,748

(a) Purchases as a percentage of total power supply.

(b) Off-system sales as a percentage of system generation.

Source: (5)

1-16

Of these three, BG&E is by far the largest net seller, both on an absolute
and relative basis. For all four major Maryland utilities, power pool purchases
and sales are a large percentage of system capability. Thus, off-system tran-
sactions constitutes a very important aspect of the operations of all major
Maryland utilities.

The structure of the electric utility industry in Maryland is summarized in
Figure 1-3. The heavy, vertical lines (without arrows) indicate a corporate
relationship; for example, Potomac Edison is a subsidiary of APS.
Unidirectional arrows indicate power flows, generally sales for resale; while
the bidirectional arrows indicate interchange sales.

D. Service Areas of, the Major Maryland Electric Utilities

As discussed in the previous section, nearly all of Maryland is served,
either directly or indirectly, by four major, integrated utilities -- BG&E,
epco, DP&L and PE. With the exception of BG&E, each of these utilities
possesses a very substantial amount of service territory outside of the State.
P

In this section we shall examine the service areas of each utility, both the
past development patterns and the future outlook. In particular, we shall exa-
mine the factors influencing the demand for electricity in each service area.

Baltimore Gas & Electric Company

BG&E serves a population of approximately 2.4 million people in a 2,300
square mile area. This area includes Baltimore City and eight surrounding coun-
ties. In addition to the City, the area contains most or all of Baltimore, Anne
Arundel, Harford, Carroll and Howard Counties and very small portions of
Calvert, Montgomery and Prince Georges Counties. Thus, the service area roughly
corresponds to the Census Bureau's definition of the Baltimore Standard
Metropolitan Statistical Area.

The economy of this region is diverse. Baltimore City and County contain
considerable heavy and light manufacturing activity, and with one of the East
Coast's largest international ports Baltimore is also a major commercial center.

The Baltimore area economy has been substantially dependent on its heavy
manufacturing base but will probably be less so in the future. Manufacturing
activity is not expected to grow rapidly; and the impetus for growth is instead
expected come from the commercial sector. In 1970 manufacturing accounted for
22 percent of Baltimore region employment, but this percentage has fallen signi-
ficantly over the past decade. The Maryland Department of State Planning pro-
jects that by 1990 manufacturing will comprise only 14 percent of total
employment, while the service sector and government will experience large gains.

Electricity demand has reflected the changing economic conditions facing
businesses and households. Prior to the mid-1970's electricity consumption grew
rapidly in response to rapid growth in the economy and favorable electricity
rates. Since then, economic growth has slowed considerably while electricity
prices increased dramatically. As shown below, electricity demand growth slowed
noticeably for each major customer class and for peak demand. The most dramatic
change has been a decline in peak demand growth from 9.1 percent per year to 2.5
percent. The system load factor decreased from 1966 to 1973 and has remained
fairly constant since then.

1-17

Other Power Pools Other Power Pools
and Systems and Systems

POWER

POOLS
APS PJM
4

----------------------------------- @L -- ------------------------------------------ I--------------------------------------

Getty Refinery
MULTI STATE ol
(or Non MD) otomac Edison Philadelphia Pennelec - PEPCO
I MD, Electric - PA
H PA MD,VA,DC City of Dover
Fj _WVA,VA Delmarva F.-
co
DEL,MD,VA Non MD Munies
Non MD Munies and Coops
and Coops
------------------- ------------------------ ---------- ------------- ---------------------------
onowi@;T] Pennele BG&E Delmarva f
MARYLAND Potomac Susquehanna
Edison PEPCO
..... ... ....
I-Thurmont Fw iIliamsport
Choptank
EH-9 erstown F

Figure 1- 3
Schematic diagram of the electric utility industry in Maryland
@ 11
tom
FtMD,;A

Table 1-8

Growth in Energy and Peak Demand on the BG&E System
(thousands of MWh)

Annual Growth Rates
1966 1973 1980 1966-1973 1973-1980

Residential 2,347 4,618 6,005 10.2% 3.8%

Commercial 1,771 2,582 2,933 5.5 1.8

Industrial 4,365 6,845 7,962 6.6 2.2

Total 8,653 14,341 17,228 7.5 2.7

Peak Demand 1,817 3,334 3,969 9.1 2.5
(MW)

Load Factor 58.9% 52.7% 53.0%

Important economic and demographic shifts have taken place within the
Baltimore region. The economies of Baltimore City and County, the two largest
entities in the area served by BG&E, have been stagnant relative to the rest of
the area. Over the past decade and a half the City has experienced a signifi-
cant net loss of both employment and population. At the same time the newer,
rapidly suburbanizing areas, particularly Anne Arundel and Howard Counties, are
growing rapidly. To some extent these geographic trends mirror the sector
trends. Heavy manufacturing, primarily located in Baltimore City and County,
has been gradually declining in comparison to commercial activity and light
manufacturing (and government).

These trends are expected to continue though not to the same extent as in
the past. For example, the latest Maryland Department of State Planning projec-
tions expect that Baltimore City's population will continue to decline though at
a slower rate than in the past (6). Howard and Anne Arundel Counties are
expected to continue to grow considerably more rapidly than the rest of the
State but also at a slower rate than in the past. These trends toward a
declining heavy manufacturing sector and increased suburbanization make it unli-
kely that BG&E1s rat her low load factor will improve significantly over time.

Potomac Electric Power Company

Pepco serves a population of roughly two million persons in a 643 square
mile area. This service area includes the entire District of Columbia, most of
the Maryland suburban counties of Prince Georges and Montgomery, and a small
section of Arlington County, Virginia. In addition, Pepco supplies all of the
bulk power requirements of the Southern Maryland Electric Cooperative which
serves all of Charles and St. Mary's Counties and most of Calvert County.

1-19

The three principal regions which directly or indirectly comprise Pepco's
service area have widely divergent characteristics. The District is a highly
urbanized environment of government and commercial office buildings and large
apartment complexes. The suburban Maryland region is a more affluent largely
residential area, but with a large retail trade sector. The Southern Maryland
region, which is served only indirectly by Pepco, is largely rural and small
town though with some suburban development.

The distinguishing aspect of the Pepco area economy is the virtual absence
of any significant manufacturing activity. In fact, Pepco is the only large
utility in the nation without a large industrial load. That fact, along with
the predominance of air conditioning in the Washington area, accounts for the
relatively low system load factor which Pepco has experienced over the years.1
The main "industry" in the area served by Pepco is the Federal government.
Thus, the lack of a manufacturing base coupled with the Federal presence tends
to insulate Pepco sales from the effects of the business cycle. Whereas the
nationwide unemployment rate in 1980 was 7.1 percent, the Washington area
averaged only 4.2 percent.

Table 1-9 indicates the employment patterns within the Washington
Metropolitan Area for selected years. These figures should be viewed cautiously
since the geographic coverage of these data includes certain areas outside of
the Pepco service area (e.g., Northern Virginia), and it excludes Southern
Maryland. It nevertheless serves as a useful guide.

Over the past decade and a half major employment gains have taken place, but
the sectoral shares have been remarkably stable. The only noticeable change has
been a tendency in recent years for the service/finance sector to displace
government employment. That tendency is, however, not dramatic and has little
effect on energy demand. Manufacturing, which occupies roughly twenty percent
of employment nationwide, accounts for less than four percent of Washington area
jobs. Moreover, even this small amount tends to be in such activities as
printing which use little energy. The combination of government and
services/finance dominate employment in the Washington area comprising nearly 70
percent of the total.

-----------------------
1 In 1980 the Pepco system annual load factor was only 48.6 percent.

1-20

Table 1-9

Employment by Sector Washington, D.C. Area
(Thousands)

1980* 1973*

Sector Number Percent Number Percent

Manufacturing 56.0 3.6% 45.2 3.6%

Construction 75.4 4.8 77.9 6.2

Transportation/ 67.5 4.3 61.6 4.9
Utilities

Trade 296.2 18.9 247.1 19.7

Services/Finance 512.2 32.7 348.9 27.7

Government 560.5 35.8 477.1 37.9

Total 1,567.8 100.0 1,257.8 100.0

* Figures are for April of indicated year.

Source: (7).

Table 1-10 demonstrates the extent to which power demand growth rates on
the Pepco system have fallen since 1973. Prior to that year, sales were growing
by more than eight percent per year, and have since slowed to slightly over two
percent per year. Peak demand growth has fallen even more dramatically,
revealing a slight tendency for Pepco's very low annual load factor to improve
over time. The pattern of growth in the residential and general service class
is similar. Sales to SMECO continue to grow fairly rapidly as the Southern
Maryland region continues to undergo a gradual suburbanization process,

1-21

Table I-10

Growth in Energy and Peak Demand on the Pepco System
(Thousands of MWh)

Annual Growth Rates
1966 -1973 1980 1966-1973 1973-1980

Residential 1,978 3,529 4,026 8.6% 1.9%

Nonresidential 5,661 9,704 11,425 8.0 2.4

Sales to SMECO 330 755 1,106 12.6 5.6

Total 7F969 13,988 16,557 8.4 2.4

Peak Demand (MW) 2,123 3,680 4,142 8.2 1.7

There are several identifiable factors accounting for the decline in demand
growth. Although some economic development in the Washington area has occurred
in recent years, it has done so at slower rate than in the past. Population
growth, in particular, has slowed considerably. Moreover, much of the
Washington area development which has occurred in recent years has been outside
of the Pepco service area -- i.e., in Northern Virginia and the extremeties of
Prince Georges and Montgomery Counties. The District's population, which is
entirely served by Pepco, has been declining in absolute terms. Also, it has
been hypothesized that Pepco residential and commercial customers have already or
achieved a very high level of air conditioning saturation (which represents a
large percentage of the Company's load), and the growth opportunities from
further saturation may be modest. Finally, it is likely that the combined
effects of higher prices and conservation programs also have substantially
contributed to this demand growth rate reduction.

Delmarva Power & Light Company

DP&L serves directly or indirectly the Delmarva Peninsula -- a geographic
region which includes the entire State of Delaware, the Maryland Eastern Shore
and two Virginia counties. This region contains about 5,700 square miles and a
population of 860,000. Electric service is also furnished to households and
businesses on the Peninsula by one other, very much smaller, privately owned
utility (Lincoln & Ellendale); by eleven municipal electric utility systems;l
and by three rural electric cooperatives. DP&L itself serves directly almost 80
percent of the retail electric load on the Peninsula; and it generates more than
90 percent of the bulk power consumed. DP&L has a larger role in generation
than in retail sales, because it provides indirect service to much of the load
served by the other distribution utilities. Dover, Delaware and Easton,
Maryland are the only other systems generating significant quantities of power,
and they buy (and sell) power on an interchange basis with DP&L. Thus, all uti-
lities operating on the Peninsula are fully integrated with DP&L.

-----------------
I Until recently the Maryland towns of St. Michaels and Centreville operated
their own municipal electric systems. Currently, those two towns are now served
at retail by DP&L.

1-22

Sorne energy is also generated by industrial companies for their own use.
Dupont's Seaford nylon plant generates most of the power it consumes and purcha-
ses back-up power from DP&L. A small amount of energy from the Getty Oil
Company's joint steam-electricity facility is produced in excess of refinery
requirements and is sold to DP&L.

Except for a major manufacturing and urban center in and around Wilmington,
the Delmarva Peninsula is a largely rural region. An important food processing
industry has developed in recent years as a natural complement to the region's
agricultural activity. In addition, there are several popular ocean and Bay
resorts, the largest being Ocean City, Maryland. Maryland comprises only about
a quarter of DP&L's total load, and virtually all of the heavy manufacturing on
the Peninsula is in Delaware. The Virginia service territory is very small and
accounts for less than five percent of total Peninsula power demands.

The economy of the Peninsula, as well as the differences among the three
states there, can best be understood by examining employment patterns as shown
below for the year 1977. U.S. breakdowns are included on this table as a
benchmark.

Table I-11

Employment shares by Major Sector
on the Delmarva Peninsula, 1977

Total
Delaware Maryland Virginia Peninsula U.S.

Agriculture 2.3% 10.6% 12.0% 4.9% 3.6%

Manufacturing 26.2 21.5 26.8 25.1 21.7

Trade 19.4 21.4 13.4 19.6 20.4

Government 18.7 15.9 19.7 18.0 16.7

Other 33.4 30.6 28.1 32.4 37.6

Source: Bureau of Economic Analysis unpublished data.

This table suggests that the structure of the Delmarva economy is similar to
the rest of the nation. However, these sector definitions are extremely
broad and tend to hide important differences among the various portions of the
Peninsula. For example the most important manufacturing industry in the
aryland service area is food processing, an activity which does not use large
quantities of energy. By contrast, chemicals, an extremely energy intensive
M

industry, dominates manufacturing in Delaware. Thus, within these employment
categories are major differences in economic activity which are themselves
expressed in electricity demand. This is shown below in Table 1-12.

1-23

Table 1-12

Customer Class Shares of Electricity Demand
On the Delmarva Peninsula, 1977

Total
Delaware Maryland Virginia Peninsula U.S.

Total Sales (thousands of megawatt-hours)

5,293 1,794 271 7,358 1,929,000

Percentage Distribution by Economic Sector

Residential 30.3% 50.0% 47.1% 36.0% 33.2%

Commercial 29.5 32.8 41.5 30.8 23.1

Industrial 39.6 15.9 10.7 32.4 40.0

Other 0.6 1.3 0.7 0.8 3.7

The obvious? dramatic differences are in the industrial energy sales cate-
gory. Delaware is typical of the U.S. (39.6 vs. 40.0), whereas in Maryland and
Virginia the industrial sector accounts for merely ten to fifteen percent of
total electricity usage. On the other hand, Maryland and Virginia have very
large residential sectors.

Table 1-13

Growth in Energy and Peak Demand on the Delmarva Peninsula
(Thousands of MWh)

Average Annual Growth Rates
1966 1973 1980* 1966-1973 1973-1980

Residential 1,063 2,136 2,682 10.5% 3.3%

Commercial 1,025 1,969 2,387 9.8 2.8

Industrial 1,510 2,513 2,430 7.6 -0.5

Total 3,752 6,958 8,109 9.2 2.2

Peak Demand 752 1,540 1,698 10.8 1.4
(MW)

Estimates. 1980 peak demand is weather adjusted.

1-24

Clearly, a precipitous decline in energy sales and peak demand growth rates
has taken place since 1973. This tendency can be explained by the various for-
ces which have operated nationwide -- sluggish economic growth, responses to
higher energy prices and so forth. But a prominent part of the explanation lies
in the stagnant industrial power demands. (Note that 1980 industrial sales were
actually below those in 1973.) The long-run outlook for heavy manufacturing
industry in Delaware is one of virtually no growth. Because of the importance
of this sector, overall system demand growth will be restrained.

The Allegheny Power System

APS is a holding company whose principal operating subsidiaries are The
Potomac Edison Company (PE), The Monongahela Power Company (MP) and The West
Penn Power Company. These three companies serve a sprawling, largely rural ser-
vice territory which extends over five states, approximately 86 counties and
29,000 squares miles. Approximately 2.6 million people live in this geographic
region. The rural nature of the system is attested to by the fact that the
largest city in the APS service territory, Parkersburg, West Virginia, has a.
population of about 44,000.

Potomac Edison operates in western Maryland, the eastern West Virginia
panhandle, and the northwestern portion of Virginia. Monongahela Power serves
the northern half of West Virginia and a small area in eastern Ohio along the
hio River. West Penn serves the southwest and central areas of Pennsylvania.
The,relative sizes of the three companies and the various regulatory jurisdic-
0

tions are shown in Table 1-14 below.

Table 1-14

1977 Energy Sales
(Thousands of MWh)

1965-1977
Annual
CM2any Sales %of APS Growth Rate

Potomac Edison 7,815.1 27.7% 10.7%
Maryland 5,628.8 19.9 11.9
Virginia 1,096.4 3.9 9.1
W. Virginia 1,089.9 3.9 6.9

Monongahela Power 7,198.0 25.5 6.0
W. Virginia 6,704.7 23.7 5.9
Ohio 493.3 1.7 7.4

West Penn 13,234.1 46.9 4.6

APS 28,247.3 100.0 6.3

1-25

On the basis of energy sales, West Penn is the single largest portion of
the system; PE and MP are approximately equal in size. The Ohio and Virginia
service areas of APS are quite small compared to those in Maryland, Pennsylvania
and West Virginia. From the above table it is apparent that power demands in
the various areas have been growing at different rates. Between 1965 and 1977,
PE (Maryland) grew by nearly 12 percent per year compared to less than five per-
cent for West Penn. The rather extraordinary growth in Maryland is partly
explained by the establishment of the Eastalco Aluminum Company plant in 1970
near Frederick. As of 1977 that single customer represented nearly a third of
the Maryland load and approximately a fifth of the total Potomac Edison load.

It should also be noted that APS serves several municipals and cooperatives
in its service territory on a wholesale basis. In 1977 the APS companies sold
737 thousand MWh to 13 resale customers, the largest being Hagerstown, Maryland.
However, those sales represented only about 2.6 percent of the System's energy
sales.

APS serves a vast rural region containing small towns and a few small
cities. Despite the absence of large cities in the service area, agriculture is
relatively unimportant (less than six percent of total employment) compared to
heavy manufacturing. APS serves a rather large industrial load due to the pre-
dominance of electricity intensive industries in the area such as steel, alumi-
num, chemicals, glass and coal mining. The employment shares shown below
demonstrate that the structure of APS service area economy is not atypical of
the rest of the nation.

Table 1-15

Employment Shares by Major Sector, 1977

Potomac Monongahela West
Edison Power Penn APS us

Agriculture 7.2% 6.1% 4.8% 5.9% 3.6%

Mining 0.7 6.3 4.1 3.9 0.9

Manufacturing 23.9 15.6 24.4 21.8 21.7

Trade 19.2 21.8 16.8 18.6 20.4

Government 15.2 16.3 16.2 16.0 16.7

Other 33.7 33.9 33.7 33.8 36.7

Source: Bureau of Economic Analysis unpublished county level
employment data.

1-26

These figures demonstrate that agriculture and coal mining are far more
important activities in the APS service area than nationwide; but employment
shares in the other major sectors compare rather closely with those of the U.S.
Even though the manufacturing share is virtually identical to the U.S. average,
manufacturing activity in this region has been disproportionately concentrated
in the energy intensive industries. As of 1977 nearly 75 percent of the
industrial electricity sales revenues came from a few, very energy intensive
industries -- coal mining; stone, clay and glass; primary metals; paper and che-
micals. Nationwide, these industries account for about 50 percent of industrial
electricity sales revenues.

The pattern of electricity sales reflect the nature of the APS service
territory economy. A breakdown of electricity sales by major customer class for
APS and the U.S. shown below for 1177 reveal dramatic differences.

APS U.S.

Residential 28.7% 33.2%

Commercial 15.1 23.1

Industrial 53.3 40.0

Other 2.9 3.7

The combination of a concentration of heavy industry and the lack of any major
commercial centers is largely responsible for the pattern of APS sales shown
above. Also, the relatively mild summer climate and lower than average per
capita incomes tend to hold down residential usage relative to the rest of the
U. S.

Although the customer class distribution of electricity sales is quite dif-
ferent from the rest of the nation, historical sales growth experience for APS
has been quite typical. Prior to 1973 sales and peak demand were growing
rapidly. A slight decline in demand occurred during the 1974-1975 period, and
demand since then has been growing sluggishly. The slowdown in demand
experienced by APS has been for substantially the same reasons as for the rest
of the electric utility industry. In addition, however, demand has reflected
the poor performance of the steel industryt in recent years, upon which the ser-
vice area economy is highly dependent. As the figures in Table 1-16
demonstrate, the post-1973 decline in demand has been sharpest for industrial
customers.

It is also interesting to note that peak demand has grown more rapidly than
energy sales since 1973. The figure listed for 1973 is the peak demand for the
winter of 1973-1974 - in the midst of the Arab oil embargo. The 1973 energy
sales figure is for the calendar year and therefore largely pre-embargo. This
tends to exaggerate post-1973 peak demand growth somewhat. Further, it has been
the nonindustrial sales which are the fastest growing part of the system. Since
these customers tend to have lower load factors (and higher coincidence factors)
than the system average, this has also caused peak to grow more rapidly than
energy,. Despite the deterioration which has occurred over the past few years,

1-27

APS still maintains a relatively high system load factor, especially compared to
the other Maryland utilities.

PF
Table 1-16

Growth of Energy and Peak Demand for the
Allegheny Power System
(Thousands of MWh)

Average Annual Growth Rates
1966 1973 1980 1966-1973 1973-1980

Residential 3,711 6,614 8,633 8.6% 3.9%

Commercial 1,865 3,621 4,631 9.9 3.6

Industrial 8,822 13,760 15,808 6.6 2.0

Total 14,712 24,672 29,958 7.7 2.8

Peak Demand 2,661 4,230 5,564 6.2 4.0
(MW)

Load Factor 68.7% 71.7% 6"6. 8 %

Summary of Economic and Electricity Usage Trends

The historical power demand experience facing the four major utility systems
is summarized in Table 1-17. Detailed data tables for both historical and pro-
jected demands are presented in tables at the end of this chapter.

Table 1-17 reveals important similarities in the patterns of demand growth
for the four systems. From 1966 to 1973 energy sales and peak demand grew at
annual average rates of 8.0 percent and 8.4 percent, respectively, for the four
major systems combined. Demand fell in 1974 and 1975 and resumed its growth
thereafter though at a slower pace than in earlier years. Between 1973 and 1980
demand growth averaged only 2.6 percent per year.

1-28

MMMMMMMMMM mom MMM M MM

Table 1-17

Historic Energy Sales And Peak Demand Of
The Major Utility Systems
(MW and Thousands MWh)

BG&E PEPCO DP&L APS TOTAL
-Sales P@ak Sales* Peak Sales Peak Sales Peak Sales Peak

1966 8,653 1,817 7,639 2,123 3,638 661 14,712 2,661 34,642 7,262
1970 11,971 2,496 11,183 2,908 5,440 1,045 20,119 3,785 48,713 10,234
1973 14,341 3,334 13,645 3,680 6,756 1,489 24,672 4,230 59,414 12,733

1974 13,990 3,190 12,526 3,502 6,592 1,429 24,944 4,272 58,052 12,393
1975 13,857 3,256 13,064 3,623 6,393 1,443 23,962 4,650 57,276 12,972
1976 14,758 3,234 13,444 3,500 6,660 -1,301 26,704 5,031 61,566 13,066

1977 15,462 3,588 14,020 3,857 6,906 1,499 28,247 5,174 64,635 14,118
1978 16,170 3,553 14,469 3,714 7,248 1,476 28,733 5,335 66,620 14,078
1979 16,823 3,621 14,651 3,804 7,492 1,501 30,377 5,272 69,343 14,198
1980 17,228 3,969 15,451 4,142 7,460 1,581 29,958 5,564 70,097 15,256

Annual Rates Of Growth

1966-1973 7.48% 9.06% 8.64% 8.18% 9.25% 12.30% 7.67% 6.85% 8.01% 8.35%

1973-1980 2.65 2.52 1.79 1.70 1.43 0.86 2.79 3.99 2.39 2.62

1966-1980 5.04 5.74 5.16 4.89 5.26 6.43 5.20 5.41 5.16 5.45

*Excludes sales to SMECO.

E. The Outlook for Growth in Power Demands

It is expected that future power demand growth will more closely resemble
the post-embargo growth rates than those occurring in the decade before 1974.
There are several reasons for this expectation. First, a continuation of the
economic slowdown of the 1970's, in comparison to the more rapid economic expan-
sion of the 1960's, is projected for the future. As Table 1-18 indicates, popu-
lation and employment growth rate projections for the 1980's are similar to or
even below those experienced in the 1970's.1 The Bureau of Economic Analysis
(BEA) is projecting that real per capita income in Maryland will increase by
only 2.3 percent annually over the next two decades (8). Finally, the tendency
during the 1970's for manufacturing (particularly heavy, energy intensive
manufacturing) to decline in absolute terms is expected to continue in the ser-
vice territories of the major utilities.

Perhaps the most obvious and important reason for the decline in demand
growth was the massive increases in energy prices during the mid and late
1970's. The historical price behavior and future outlook are shown in Table
1-19. Even if future real price increases do not occur, the massive price
increases which have already taken place will suppress future demand. This is
because many years are required before consumers can fully adjust to price PF
changes. Thus, during the 1980's consumers will still be adjusting their energy
usage to the price shocks of the 1970's. It is also reasonable to expect that
future real increases in electric rates for these systems will occur, and con- PF
tinued customer adiustment will follow.

Finally, attitudes and public policy concerning energy usage (and power
usage) have changed. Toward the end of the 1970's several important legislative
initiatives were enacted designed to require, fund or encourage conservation.
Although less potent than the slow economic growth and rising energy prices,
these numerous new conservation programs will help to slow the growth of power
demands.

The Power Plant Siting Program (PPSP), in cooperation with the Department of
the State Planning (DSP), has maintained a program of conducting independent
long-range load forecasts. Such studies have been undertaken for each of the
four major utilities ( 9 ), ( 10 ); ( 11 ), ( 12 ). The DP&L and APS studies
were completed relatively recently; however the Pepco and BG&E studies were
completed in 1974 and 1977 and were partially updated in 1978 and 1981, respec-
tively. It is anticipated that both studies will be updated and substantially
revised in 1982.

The PPSP/DSP load forecasts were developed through the application of eco-
nometric models (see Appendix A). This methodology involves two principal sta-
ges. In the first stage, statistical models of the demand for electricity are
estimated from historical data. These econometric models describe the rela-
tionship between the demand for electric energy and the various factors (i.e.,
the explanatory variables) that govern it, such as population, employment, cli-
mate, income and electricity rates. In the second stage, projected or assumed

---------------------------
1 The employment projections shown were prepared in 1978 and are therefore
somewhat dated. The most recent BEA figures (November 1980) project employment
in the State of Maryland to increase by only 1.2 percent annually.

1-30

Table 1-18

Population and Employment Trends, 1970-1990
(Thousands)

Population
Annual Rate of Growth
Service Area 1970 1980 1990 1970-1980 .1980-1990

Pepco 2,062 2,090 2,196
(Md. only) 1,300 1,411 1,525 0.82% 0.81%

BG&E 2,071 2,174 2,296 0.49 0.55

Delmarva 800 879 959 0.94 0.87
(Md. only) 205 236 257 1.42 0.86

APS 2,495 2,636 2,797 0.55 0.59
(Md. only) 294 334 366 1.28 0.92

Maryland 3,924 4,216 4,510 0.72 0.67

Employment* (nonagricultural)

Pepco 1,058.6 1,168.7 1,434.4 1.42% 1.59%
(Md. only) 411.6 514.7 728.4 3.24 2.71

BG&E 885.8 949.1 1,191.1 0.99 1.76

Delmarva 344.2 381.4 486.8 1.48 1.89
(Md. only) 92.8 105.9 127.8 1.90 1.46

APS 832.0 936.5 1040.0 1.70 0.81
(Md. only) 112.7 127.6 139.4 1.79 0.68

Maryland 1,519.0 1,709.0 2,216.1 1.70 2.02

Employment figures in the 1980 column are 1977.

Source: (8), (9), (10), (11), (12)

1-31

Table 1-19,

Monthly Residential Electric Bills*

Annual Rate of Growth
Service Area 1972 1980 1990 1972-1980 1980-1990

Pepco $10.35 $29.62 -- 14.1% --
(CPI Adjusted) 10.35 15.92 18.28 5.5 1.4%

BG&E 15.30 28.11 -- 7.9 --
(CPI Adjusted) 15.30 15.11 18.41 -0.2 2.0

DP&L 13.19 36.11 -- 13.4 --
(CPI Adjusted) 13.19 19.40 20.80 4.9 0.7

Potomac Edison 10.62 27.12 -- 12.4 --
(CPI Adjusted) 10.62 14.57 15.24 4.0 0.5

Maryland 13.82 28.57 -- 9.5 --
(CPI Adjusted) 13.82 15.35 1.3

*Bills are based upon 500 kwh per month on January 1 of designated
year. Bills are for Maryland portions of service area only.

Source: (13)

1-32

future values of the explanatory variables are inserted into the estimated
model, and the forecast is then calculated for each year. Peak demand is fore-
casted in a similar manner except that total energy usage is used as an impor-
tant explanatory factor in the peak demand equation. Thus, energy forecasts
must first be developed in order to calculate the peak demand forecast.

In all of the PPSP/DSP forecast studies prepared to date, electricity sales
models have been estimated separately for the residential and non-residential
classes of customers. Moreover, models were separately estimated for the resi-
dential class, nonresidential class and system peak demand for the summer and
winter seasons, since behavioral relationships and some of the underlying deter-
minants differ between the two seasons. In all cases the models were estimated
using ordinary least squares regression -- in some cases using quarterly or
monthly time series data and in other cases using pooled time series/cross sec-
tion data.

The resulting forecasts are heavily influenced by the projections of and
assumptions on future values of the explanatory variables. To the extent
possible, these values were obtained from official, published sources. Where
official sources did not exist, future values were developed judgmentally (see
Appendix A).

Table 1-20 provides the energy and annual peak demand forecasts prepared by
PPSP for the four major electric utility systems. Historical growth rates of
power demands are included in this table for purposes of comparison. Forecasts
for the Maryland portions of APS and DP&L are shown along with the aggregate
totals both with and without the non-Maryland demands. The figures for the
Maryland jurisdiction portions are not very meaningful to utility system plan-
ners since each of these utilities plans its generation investments strictly on
a system-wide basis without regard to jurisdictional patterns of demand.

There is significant variation among the forecasts for the four systems.
Pepco's peak demand is projected (updated forecast) to grow by less than one
percent annually compared to 3.3 percent for BG&E.1 APS and DP&L, the two most
recent studies prepared by PPSP, are between these two extremes. With the
exception of the BG&E forecast of energy sales (which was completed in 1977),
the forecasted growth rates are roughly comparable to those occurring between
1973 and 1980. This is not a surprising result. Future economic and population
expansion in the service areas of the Maryland utilities is not expected to be
any more rapid than in the 1970's. However, even though future energy prices
are expected to rise in real terms, a 1970's type price explosion is assumed
not to reoccur. Thus, growth rates slightly in excess of those occurring during
the 1973-1980 period are plausible.

The PPSP/DSP forecasts in Table 1-20 are each based upon a carefully for-
mulated set of assumptions regarding the future behavior of the variables
appearing in the demand equations. Those sets of assumptions are referred to as
the Most Likely Case (MLC). In each case the MLC scenario is based upon offi-
cial projections from federal and state agencies along with PPSP's best judgment

-------- ----------
1 The BG&E peak demand forecast in Table 1-20 is a revision of an original study
prepared by PPSP. However, the energy projections shown in that table have not
yet been revised. That accounts for the large discrepancy in the peak demand
and energy sales growth rates.

1-33

Table 1-20

Projected Energy Sales and Peak Demand
For Major Maryland Utilities(a)
(Thousands MWh and MW)

Annual Rates of Growth
1982 1985 1990 1973-1980 1982-1990
Sales Peak Sales P;Ta-k Sales Peak' Sales Peak Sales Peak

Pepco 15,828 4,284 16,824 4,393 18,599 4,554 2.22% 1.70% 2.04% 0.74%

BG&E 19,586 4,028 23,049 4,447 30,021 5,232 2.65 2.52 5.48 3.32

DP&L(b) 8,099 1,687 8,996 1,919 10,250 2,246 2.21 0.86 2.65 3.23
(MD Portion) 1,515 454 1,697 503 1,995 592 5.29 3.99 3.50 3.37

APS 31,394 5,726 33,997 6,294 38,251 7,236 2.79 3.99 2.50 2.96
(MD Portion) 6,014 1,063 6,488 1,181 7,384 1,405 5.59 5.01 2.60 3.55

MD Total(c) 42,943 9,829 48,058 10,524 57,999 11,783 2.96 2.44 3.83 2.29

Total 74,907 15,725 82,866 17,053 97,121 19,268 2.57 2.84 3.30 2.57

(a) PPSP/DSP forecasts.

(b) Includes entire Delmarva Peninsula.

Source: Tables 1-24 through 1-35.

concerning those variables for which official projections are not available.
Also, every effort is made to assure that the various assumptions in each case
are logically consistent with one another.

Some of the sources of these projections have been referred to earlier.
BEA has been relied upon for projections of real per capita income, and outside
of Maryland, for employment projections. Population and household formation
projections (utilized to determine residential customers) have been obtained
from the U.S. Census Bureau. Within Maryland, the Department of State Planning
projections of employment and population have been utilized. Finally, electric
energy price projections have been determined on a largely judgmental basis, but
taking into consideration national EIA fuel price projections along with the
specific circumstances of the utility system under study.

The usage of the projections figures available from these sources intro-
duces a large element of uncertainty into the load forecasts.1 It is important
that this uncertainty be recognized and explicitly incorporated into the
planning process. In order to gauge the magnitude of forecast uncertainty,
various alternative scenarios are constructed, including a "conservation case"
scenario. Upper and lower bound load growth rates are obtained by determining
the extreme, plausible modification to the MLC assumptions and recalculating the
forecasts. For example, the DP&L MLC peak demand growth rate forecast is 3.2
percent per year, surrounded by upper bound of 4.3 percent and a lower bound of
1.8 percent. Clearly, the range of uncertainty is quite large.

Table 1-21 provides a comparison between the PPSP and Company prepared peak
demand forecasts through 1990, with some minor exceptions, the independent peak
demand forecasts prepared by PPSP are quite similar to those prepared by the
Companies. For all four major systems combined the difference is roughly 400
megawatts or less than one year's load growth. This discrepancy is well within
any reasonable range of uncertainty.

IUncertainty over forecast assumptions is only one problem of many involved.
For example, the models themselves may be in error to some degree. However,
assumption error is probably the most serious problem in forecasting and the
greatest source of uncertainty.

1-35

Table 1-21

Comparisons Of PPSP/DSP And Company Prepared Peak Demand Forecasts
NW)

Annual Rates of GrowthM
1982 1985 1990 1973-1980 1982-1990
PPSP Company PPSP Company PPSP CM2any DifferenceM PPSP Company
Pepco, 4,284 3,956 4,393 4,105 4,544 4,355 4.2% 1.70% 0.74% 1.21%

BG&E 4,028 4,130 4,447 4,530 5,232 5,130 1.9 2.52 3.32 2.75

DP&L(a) 1,547 1,627 1,694 1,767 1,951 1,918 1.7 0.86 2.94 2.08
(MD Portion) 454 407 503 480 570 517 9.3 3.99 2.89 3.04

APS 5,726 5,689 6,294 6,202 7,236 7,182 0.8 3.99 2.97 2.96
(MD Portion) 1,063 1,050 1,181 1,195 1,405 1,460 -4.3 5.01 3.61 4.33

9,829 9,543 10,524 10,310 11,751 11,462 2.4 2.44 2.26 2.32
MD Total(b)

Total 15,585 15,402 16,828 16,604 18,963 18,585 2.0 2.84 2.48 2.38

(a) Figures exclude Dover and Easton load not served by DP&L and
the Getty Oil Refinery load. The 1990 figures are lowered by 50
megawatts to reflect capacity purchase by The Old Dominion
Electric Coop. (The Maryland portion load projections for 1990 are
lowered by 22 megawatts for the acquisition of capacity by Old
Dominion Electric Cooperative.)

(b) Includes non-Maryland portions of Pepco. Excludes Conowingo Power
Company.

Source: Table T-20, (14)v (15), (16), (17).

pri I I I I I

F. The Management of Demand

System planning has traditionally involved determining the optimal sche-
duling and mix of plant types (i.e. base load, cycling or peaker) and fuel types
which will minimize the total costs of producing power, while at the same time
providing reliable service. This is a complicated process and relies heavily
Upon the outlook for the growth of power demand. With the rapid increases in
recent years in the cost of boiler fuel, generation facilities and financing, it
is becoming increasingly obvious that the least-cost approach in planning will
involve programs and measures to reduce energy demand (or at least the growth in
energy demand) and flatten load curves.1

Many utility systems recognize and are pursuing the demand-side alter-
natives. The Duke Power Company has been pursuing an ambitious demand manage-
ment program explicity in its generation plans. It has identified more than 25
such programs including new home insulation standards, direct load control and
time-of-day ratest- which could result in amazingly large benefits. The
Company's Annual Report to Stockholders states:

Over the next 14 years, Duke Power has the opportunity to
avoid an investment of more that $10 billion.
The Company's comprehensive Load Management Program is
designed to do just that by reducing the incremental growth
of peak demand 5,635,000 kilowatts by 1994 - nearly the
equivalent of 5 generating units the size of McGuire 1. (18)

There are two basic approaches to managing power demands -- conservation
and load management.2 Conservation simply refers to the reduction in use of
electricity that can be achieved by better weatherization, improved appliance
efficiencies or by choosing a less energy intensive lifestyle. Load management
is only concerned with when electricity is consumed and not total usage. Load
management can achieve greater system efficiencies by shifting usage from times

1-There-are-other-factors which also argue for seeking alternatives to
construction of central station generating facilities -- environmental dif-
ficulties and financial distress. Environmental impacts of electric power
generation (and industrial activity generally) has led to environmental legisla-
tion. This legislation has tended to increase power plant licensing time and
has to some extent increased the length of the construction period. Both
effects have contributed to lengthening the lead times necessary to bring new
power plants on-line. Environmental litigation has also led to unanticipated
delays in bringing facilities on-line (as in the case of APS's proposed Davis
pumped storage hydro project) or even to out-right cancellations. High interest
rates may make it difficult for utilities to carry large, expensive construction
projects for long time periods.
2From the utilities point of view, production of power by the customer such as
solar or wind energy also lessens demands, if that power replaces purchased
power. However, since these technologies produce electricity they are discussed
in Chapter II.

1-37

when additional energy is expensive to produce (or when demand is pressing
against capacity) to times when additional energy is cheap (or when there is
excess capacity). Approaches which would facilitate such load shifting include
thermal storage technologies, appliance cycling controls, time-of-use pricing
and interruptible rates.

There is mounting evidence that in many instances conservation is extremely
cost-effective. However, there are numerous institutional barriers that tend to
prevent economically justified conservation measures from being undertaken by
consumers. These would include difficulty in obtaining information concerning
costs and benefits of conservation; the setting of utility rates at historic
costs rather than marginal costs (i.e. the costs of producing and providing
additional power); rapid ownership turnover of homes; and the unwillingness of
financial institutions to provide conservation loans at reasonable rates. These r
problems can be mitigated to some extent by utility and governmental programs.1

Weatherization

Improved weatherization of residential structures may be one of the most
cost-effective methods of reducing expensive energy usage for homes which heat
and/or cool with electricity. The following data from BG&E shown in Table 1-22
illustrate this point.

Potential weatherization benefits were confirmed in a recent study of
electricity usage in New York State. That study estimates that implementing
weatherization measures, as compared to typical current practice, would reduce
electricity used for space cooling by about 5 percent (20).

-------------------------------
1 For a description of the many State and Federal programs operating in
Maryland see: Energy in Maryland, Maryland Energy Administration, January 1981,
pp.18-49.

1-38

Table 1-22

Annual Electric Bill Savings for a "Typical Home" Served
By BG&E

Electric Resistance Heat Electric
Heat Pumps A/C

Caulking & Weather-
stripping $33-$50 $25-$35 $3-$5

Wall Insulation $65-$100 $36-$56 $10-$16

Floor Insulation $66-$101 $36-$56 so

Duct Insulation NA $29-$44 NA

Storm/Thermal
Windows $59-$91 $33-$50 $4-$6

Storm/Thermal
Doors $33-$51 $18-$28 $1-$2

Ceiling Insulation $429-$600 $239-$367 $102-$157

Clock Thermostat $42-$65 NA $9-$14

Source: (19)

The California Energy Commission has estimated that a fairly modest investment
in weatherization could save electric heat customers in California 1,800 to
3,000 kWh annually. The same study reports that The Pacific Power & Light
Company (PP&L) estimates that a somewhat larger weatherization investment in a
typical, electrically heated home in its Oregon service territory could save
5,000 kWh per year (21).

PP&L and Pacific Gas & Electric Company (PG&E) have implemented agressive
programs to subsidize such investments. Under both programs, the utility, with
the customer's consent, arranges and pays for the weatherization of a customer's
home. There is no cost to the customer until the home is sold, at which point
the original owner must repay the principal, The utility, however, absorbs all
interest costs. PP&L and PG&E believe that these weatherization subsidies will
have the effect of ultimately benefiting all customers since it will lead to
large, long run reductions in system costs -- far larger than the amount of the
subsidies.

The cost-effectiveness and practicality of such a program depend on a
number of specific factors, such as the potential for further weatherization in
the service area and the structure of costs of the utility in question. PPSP is
conducting a study, jointly funded with the Office of People's Counsel, to
determine the possible costs and energy savings impacts such a program might
have on the BG&E system. If the results appear promising, the study will be
extended to the other utilities in the State.

1-39

Even more cost-effective than retrofitting is the weatherization of new
homes. In recognizing this fact, several utilities and state governments have
proposed rate incentives, hook-up restrictions and information programs to
encourage builders and prospective new home owners to build and purchase energy
efficient homes. In Maryland, recent legislation has been enacted to ensure
that new buildings will meet a minimum set of energy efficiency standards
(HB 7 4 8) .

Load Management

The demand for electricity on a given system varies significantly by season
of the year, by day of the week, and by time-of-day. The major utilities in the
State, with the exception of APS, have historically exhibited rather low annual
load factors. Unless some deliberate efforts are made to change this situation,
the low load factors are likely to persist and may even deteriorate further.

The setting of electric rates can play a useful and effective role in both
reducing the large, time related variations in load and in encouraging conser-
vation of electric power. This idea has been promoted by utility ratemaking
experts and became embodied in Federal energy policy with the 1978 passage of
the Public Utilities Regulatory Policies Act (PURPA).

This Act deals with numerous aspects of public utility regulation. It
requires state commissions to hold evidentiary hearings and to determine the
appropriateness of six principal ratemaking standards. These are:

Cost of service standard -- Rates charged to each class of customers
should reflect the costs of serving each class to the maximum extent
practicable. Such determinations should include "marginal costs".

Declining block rate standard -- Unless cost justified, the energy com-
ponent of an electric rate shall not decrease as kilowatt hour consump-
tion increases.

Time-of-day rate standard -- To the extent practicable, rates should
reflect time related variations in costf unless such rates are deter-
mined not to be cost-effective.

Seasonal rate standard -- Electric rates should reflect seasonal dif-
ferences in cost.

Interruptible rate standard -- Commercial and industrial customers
shall be offered interruptible rates which reflect the costs of pro-
viding service on an interruptible basis to those customers.

Load management techniques standards -- Utilities shall provide load
management techniques found to be cost-effective, practical, and use-
ful to reduce capacity requirements and/or fuel costs.

These rate design standards were established in order to promote the stated
purposes of PURPA -- conservation, efficiency and equity. By and large, these
goals can be achieved by providing the consumers of electricity with price
signals that better reflect the costs of providing additional electric service
to them.

1-40

Time-of-use (Tou) rates (based upon time-varying marginal costs) can help
reduce the growth rate of peak demand, improve system annual load factors and
generally flatten load curves. These results naturally occur as customers
shift power usage from the peak to the off-peak period. If achieved, the
existing generation system can function more efficiently, and capacity additions
may be deferred. The fuel cost reduction occurs as the reduction in peak usage
(i n response to higher peak prices) permits the utility to reduce operation of
its more energy inefficient generating units. In that manner TOU rates help to
serve the purposes of PURPA.

TOU rate implementation requires a large front-end investment in expensive
metering equipment needed to measure energy usage by time period. Consequently,
PURPA requires that such rates pass a cost-effectiveness test. TOU rates will
only lower system costs if the resulting increase in system efficiency outweigh
the additional metering and administrative costs. This question was investi-
gated by PPSP for the BG&E system (22). Benefits were measured as changes in
"consumer surplus" when moving from current rates to those reflecting marginal
costs by time period. TOU pricing was found to be cost-effective for the
average size customer in each class though cost-ineffective for smaller residen-
tial customers. It was estimated that the present value of the gains over the
lifetime of the metering equipment is roughly $85 million. Since this study
relies upon data several years old, and since fuel prices have risen far more
rapidly than metering costs, this may represent a substantial understatement of
the benefits.

Currently, none of the four utility systems provides time-of-use pricing to
its Maryland customers. The PURPA compliance hearings have been held or are
currently underway for each utility, but the Public Service Commission has ruled
on the ratemaking standards only for BG&E. In the other state jurisdictions in
which the Maryland utilities operate time-of-use rates have also been con-
sidered, and they have been adopted to a limited extent. The District of
Columbia has implemented the rates for the Pepcols approximately 250 largest
High Tension customers. The State of Delaware has also moved forward to imple-
ment such rates for many of the large industrial concerns. For many years now
West Penn Power and Monongahela Power have sold power on a time-of-use basis to
some of their industrial customers. However, there appears to be a very large
potential to expand time-of-use pricing, on a cost-effective basis, for both the
Maryland and non-Maryland portions of the service areas.

Direct load control devices are intended to serve the same purpose as time-
of-use rates, but they are generally controlled by the utility rather than the
individual customer. There are two basic approaches to direct load control --
heat (or cooling) storage and appliance cycling. With the former, electricity
heats water or some other thermal storage medium during the off-peak period.
Through the use of a communication device of some sort, the utility shuts off
the customer's electric space and/or water heater during the peak period. The
other approach, appliance cycling, involves interrupting the service of major
appliances -- air conditioners, electric space or water heaters -- for only a
few minutes at a time during the periods of maximum demand on a system. whereas
thermal storage systems can save capacity and energy costs, appliance cycling
saves little energy cost and is primarily designed to save capacity costs.

Like time-of-use pricing, load control devices can improve system effi-
ciency but require a major investment in facilities to communicate with and
control customer appliances. A recent Tennessee Valley Authority (TVA) staff

1-41

study estimated the costs and benefits of several different proposed load mana-
gement methods. These results are summarized below on a present value basis
through the year 2000.

Table 1-23

TVA System Savings From Load Management
(Millions $)

System MW
Method Costs Benefits Reduction

Water Heat
Cycling $71-$96 $130 458

Water Heat
Storage 11-47 267 627

Space Heat
Storage 35-127 335 578

Space Heat
Cycling 48-55 129 311

Source: (23)

'Several observations concerning direct load control need to be be made.
First, interrupting service may involve a certain amount of customer incon-
venience. Second, it also appears that heat storage economics is more favorable
than cooling storage, thus making it more advantageous for winter peaking
systems (such as TVA) but less so for summer peaking systems. Third, since
appliance cycling does not save a great deal of energy, it is probably only
worthwhile on systems that are capacity constrained. Many systems, such as
Pepco, will have excess capacity for many years to come. On excess capacity
systems, there appears to be little that direct load control can accomplish that
cannot be accomplished by TOU pricing. The latter method allows customers to
respond to price signals that follow the time pattern of costs, and is therefore
a preferable method of managing system loads. However, there may be an impor-
tant role for both approaches to load management.

None of the major Maryland utilities currently have direct load control
programs of any significance in any jurisdiction. Each of the four utilities
plans to examine or has examined the feasibility and impacts from such programs
Pepco, for example, is currently attempting to intitiate a load management
experiment in Maryland. However, a preliminary analysis suggests to the Company
that implementation is not cost-effective at this time (24). DP&L is currently
conducting a two-year experiment of load management techniques and innovative
rate structures with 1,000 of its Delaware residential customers. The purpose
of the study is to determine customer attitudes and responses to these programs.

Outside of their Maryland service area two utilities, DP&L and APS, have a
modest program of curtailable rates (i.e., rates that permit service
interruptions) for their large industrial customers. DP&L currently sells

1-42

power to three customers on interruptible rates, whose potential interruptible
loads represent roughly five percent of the Company's system peak demand. APS
has roughly 50 megawatts of interruptible load which is less than I percent of
total system peak demand.

G. Historical and Projected Company Load Data

The last section of this chapter presents detailed statistical data on
historical and projected power demands for the four major electric utilities
serving Mayland. The historical tables provide annual residential and nonresi-
dential sales, summer and winter peak demand, generating capacity and the
reserve margin. Reserve margin is defined as generating capacity minus annual
peak demand divided by annual peak demand.

The tables of projected demands provide the same information through 1990.
The projections of energy sales and peak demand were prepared by PPSP, and the
capacity figures are based upon Companies' latest generation plans. The table
also provides the Companies' load forecasts (and thus reserve margin forecasts)
for purposes of comparison.

For Delmarva Power & Light Company and the Allegheny Power System, the
historical and projected data are provided for both the total system and for the
aryland portions of those systems. The reserve margins have no meaning for the
Maryland portions and are therefore not provided.
M

1-43

Table 1-24

Historic Energy Sales, Peak Demand
And Generating Capacity For The Allegheny Power System

Energy Sales (Thousands MWh) Peak Load (MW) Capacity Reserve Margin(%)
Residential NonResidential Total Sumner Winter (MW)

1966 3,711 11,001 14,712 2,425 2,661 2,536 -4.7%

1970 5,319 14,800 20,119 3,206 3,785 4,254 12.4
1971 5,694 15,585 21,279 3,274 3,769 4,731 25.5
1972 6,137 16,678 22,815 3,622 4,039 5,208 28.9
1973 6,614 18,058 24,672 4,040 4,230 5,742 35.7
1974 6,809 18,135 24,944 3,916 4,272 6,388 49.5
1975 7,229 16,733 23,962 3,959 4,650 6,428 38.2

1976 7,524 19,181 26,704 4,284 5,031 6,428 27.8
4b.
1977 8,096 20,152 28,247 4,539 5,174 6,428 24.2
1978 8,351 20,382 28,733 4,632 5,335 6,417 20.3
1979 8,466 21,911 30,377 4,676 5,272 6,997 32.7
1980 8,633 21,274 29,958 4,903 5,564 7,568 36.0

Annual Average Rates of Growth

1966-1970 9.42% 7.70% 8.14% 7.23% 9.21% 13.81%

1970-1975 6.33 2.48 3.56 4.31 4.20 8.61

1975-1980 3.61 4.92 4.57 4.37 3.65 3.32

1966-1980 6.22 4.82 5.21 5.16 5.41 7.56

Peak demand figures are for winter beginning in designated year.

Table 1-25

Projected Energy Sales, Peak Demand And
Generating Capacity For The Allegheny Power System

Reserve Company Projections
Energy Sales (Thousands MWh)* Peak Load (MW)* Capacity marginM Winter
Residential NonResidential Total Summer Winter (MW) Peak (MW) R.M.(%)

1981 8,793 21,718 30,511 5,552 7,587 36.7% 5,445 39.3%
1982 9,194 22,200 31,394 5,726 7,600 32.7 5,689 33.6
1983 9,602 22,657 32,259 5,910 7,600 28.6 5,798 31.1
1984 10,022 23,106 33,128 6,093 7,600 24.7 6,024 26.2
1985 10,447 23,550 33,997 6,294 8,020 27.4 6,202 29.3

1986 10,853 23,975 34,828 6,443 8,446 31.0 6,448 30.9
1987 11,260 24,401 35,661 6,626 8,440 27.4 6,628 27.3
1988 11,676 24,836 36,512 6,810 8,440 23.9 6,806 24.0
1989 12,099 25,271 37,370 7,000 9,070 29.6 6,933 30.8
1990 12,526 25,725 38,251 7,236 8,995 24.3 7,182 25.2
Ln

Annual_.Lveja2e Rates of Growth

1980-1985 3.88% 2.05% 2.56% 2.50% 1.17% 2.19%

1985-1990 3.70 1.78 2.39 2.83 2.32 2.98

1980-1990 3.79 1.92 2.47 2.66 1.74 2.59

Projections prepared by PPSP.
Peak demand figures are for winter beginning in designated year.

Table 1-26

Historic Energy Sales, Peak Demand And
Generating Capacity For The Potomac Edison Company (Maryland Portion)

Energy Sales (Thousands MWh) Peak Load (MW) Capacity* Reserve Margin(%)
Residential NonResidential Total Summer Winter (MW)

1966 489 932 1,421 336 227

1970 731 2,104 2,835 550 143
1971 788 2,775 3,563 601 142
1972 851 2,908 3,759 656 142
1973 930 3,080 4,010 682 139
1974 985 3,004 3,990 693 139
1975 1,065 2,889 3,954 802 139

1976 1,142 4,164 5,306 916 139
1977 11235 4,394 5,629 1,018 139
1978 1,267 4,231 5,498 981 129
1979 1,276 4,554 5,830 961 129
1980 1,289 4,580 5,869 960 117

Annual Average Rates of Growth

1966-1970 10.58% 22.58% 17.24% 13.11% -10.9%

1910-1975 7.82 6.55 6.88 7.84 -0.6

1975-1980 3.89 9.65 8.22 3.66 -3.4

1966-1980 7.14 12.04 10.66 7.79 -4.6

Peak demand figures are for winter beginning in designated year.

Does not include the Potomac Edison Company share of jointly-owned stations located
in Pennsylvania and West Virginia, or the wholly-owned stations in Virginia.

i I I I I i I! N 7

Table 1-27

Projected Energy Sales, Peak Demand And
Generating Capacity For The Potomac Edison Company (Maryland Portion)

Reserve 22mpanZ Projections
Energy Sales (Thousands MWh)* Peak Load (MW)* Capacity Margin(%) Winter
Residential NonResidential Total Summer Winter (MW) Peak (MW) _R.M. (%)

1981 1,355 4,517 5,872 1,021 117 1,015
1982 1,452 4,562 6,014 1,063 117 1,050
1983 1,555 4,610 6,165 1,098 117 1,085
1984 1,665 4,658 6,323 1,141 117 1,140
1985 1,781 4,707 6,488 1,181 117 1,195

1986 1,897 4,757 6,654 1,225 117 1,255
1987 2,018 4,807 6,825 1,269 117 1,295
1988 2,146 4,858 7,004 1,309 117 1,350
1989 2,280 4,910 7,190 1,355 117 1,405
1990 2,421 4,963 7,384 1,405 117 1,460

Annual Average Rates of Growth

1980-1985 6.69% 0.55% 2.03% 4.23% 0.0% 4.48%

1985-1990 6.33 1.06 2.62 3.53 0.0 4.09

1980-1990 6.51 0.81 2.33 3.88 0.0 4.28

*Projections prepared by PPSP.

Peak demand figures are for the winter beginning in designated year.

Capacity data does not include the Potomac Edison Company share of jointly-owned stations
located in Pennsylvania and West Virginia or the wholly-owned stations in Virginia.

Table 1-28

Historic Energy Sales, Peak Demand And
Generating Capacity For The Baltimore Gas And Electric Company

Energy Sales (Thousands MWh) Peak Load (MW) Capacity Reserve Margin(%)
Residential NonResidential Total Summer Winter (MW)

1966 2,347 6,306 8,653 1,817 1,422 1,866 2.7%

1970 3,665 8,306 11,971 2,496 1,954 2,791 11.8
1971 3,864 8,620 12,485 2,605 2,053 3,303 26.8
1972 4,102 8,889 12,991 2,960 2,059 3,748 26.6
1973 4,618 9,723 14,341 3,334 2,302 3,541 6.2
1974 4,469 9,251 13,990 3,190 2,177 3,410 6.9
1975 4,664 9,194 13,857 3,256 2,301 4,046 24.3

1976 4,888 9,870 14,758 3,234 2,418 4,241 31.1
1977 5,231 10,230 15,462 3,588 2,640 4,995 39.2
00 1978 5,435 10,735 16,170 3,553 2,850 4,995 40.6
1979 5,497 11,327 16,823 3,621 2,900 4,995 37.9
1980 6,005 11,223 17,228 3,969 3,046 5,010 26.2

Annual Average Rates of Growth

1966-1970 11.79% 7.14% 8.46% 8.26% 8.28% 10.59%

1970-1975 4.94 2.05 2.97 5.46 3.32 7.71

1975-1980 5.18 4.07 4.45 4.04 5.77 4.37

1966-1980 6.94 4.20 5.04 5.74 5.59 7.31

1 1 i I I I I '1 7 1 1 1 1

Table 1-29

Projected Energy Sales, Peak Demand And
Generating Capacity For The Baltimore Gas And-Electric Company

Reserve Company Projections
Energy Sales (Thousands MWh)* Peak Load (MW)* Capacity Margin(%) Summer
Residential NonResidential Total Summer Winter (MW) Peak R.M.(%)

1981 5,824 12,719 18,543 3,897 5,025 29.0% 3,970 26.6%
1982 6,122 13,464 19,586 4,028 5,025 24.8 4,130 21.7
1983 6,446 14,234 20,681 4,162 5,025 20.7 4,260 18.0
1984 6,797 15,036 21,833 4,303 5,594 30.0 4,390 27.4
1985 7,175 15,874 23,049 4,447 5,634 26.7 4,530 24.4

1986 7,577 16,713 24,290 4,591 5,759 25.4 4,640 24.1
1987 8,008 17,596 25,604 4,741 5,701 20.3 4,740 20.3
1988 8,469 18,525 26,994 4,897 6,321 29.1 4,870 29.8
1989 8,961 19,503 28,464 5,031 6,321 25.6 5,000 26.4
1990 9,486 20,535 30,021 5,232 6,321 20.8 5,130 23.2

Annual Average Rates of Growth

1980-1985 3.62% 7.18% 6.00% 2.30% 2.38% 2.68%

1985-1990 5.74 5.28 5.43 3.30 2.33 2.52

1980-1990 4.68 6.23 5.71 2.80 2.35 2.60

* Projections prepared by PPSP.

Table 1-30

Historic Energy Sales, Peak Demand And
Generating Capacity For The Delmarva Power And Light Company (Total System)

Energy Sales (Thousands MWh) Peak Load (W Capacity Reserve margin(%)
Residential NonResidential Total Summer Winter (MW)

1966 839 2,799 3,638 661 639 799 12.5%

1970 1,280 4,610 5,440 1,014 943 1,151 13.5
1971 1,381 4,367 5,748 1,090 1,002 1,184 8.6
1972 1,464 4,777 6,241 1,262 1,150 1,364 8.1
1973 1,630 5,126 6,756 1,434 1,076 1,552 8.2
1974 1,597 4,995 6,592 1,375 1,140 1,624 18.2
1975 1,672 4,721 6,393 1,397 1,155 1,905 36.4

1976 1,788 4,872 6,660 1,301 1,278 1,917 47.4
1977 1,925 4,981 6,906 1,450 1,352 1,998 37.8
C) 1978 1,980 5,268 7,248 1,428 1,339 1,993 39.6
1979 1,968 5,524 7,492 1,452 1,322 1,993 37.3
1980 2,047 5,413 7,460 1,529 1,444 2,008 31.3

Annual Average Rates of Growth

1966-1970 11.14% 10.41% 10.58% 9.32% 10.22% 7.57%

1970-1975 5.49 3.28 6.62 4.14 10.60

1975-1980 4.13 2.77 3.14 1.82 4.57 1.06

1966-1980 6.58 4.82 5.26 5.63 6.00 6.80

Data represent the entire DP&L System and exclude energy sales to Easton and
includes portions of Dover and Easton peak demand provided by DP&L generation.
Data exclude caloacity from and loads served by Delaware City 1 and 2 (dedicated
to Getty Refinery).

Table 1-31

Projected Energy Sales, Peak Demand And
Generating Capacity For The Delmarva Power And Light Company (Total System)

Reserve Company P ojections
Energy Sales (Thousands MWh)* Peak Load (MW)* Capacity Margin(%) Summer
Residential NonResidential Total Summer Winter (MW) Peak(MW) R.M.(%)

1981 2,022 5,028 7,059 1,506 1,406 2,219 47.3% 1,531 44.9%
1982 2,100 5,107 7,226 1,547 1,453 2,234 44.4 1,627 37.3
1983 2,183 5,212 7,423 1,594 1,504 2,167 40.0 1,667 30.0
1984 2,270 5,333 7,641 1,641 1,557 2,167 32.1 1,711 26.7
1985 2,363 5,464 7,874 1,694 1,594 2,217 30.9 1,767 25.5

1986 2,437 5,584 8,075 1,749 1,640 2,217 26.8 1,808 22.6
1987 2,515 5,711 8,286 1,808 1,688 2,177 20.4 1,818 19.8
1988 2,597 5,841 8,505 1,869 1,757 2,177 16.5 1,870 16.4
1989 2,682 5,978 8,734 1,934 1,808 2,177 12.6 1,919 13.4
U,
H 1990 2,770 6,118 8,970 1,951 1,819 2,502 28.2 1,918 30.5

Annual Average Rates of Growth

1980-1985 2.91% 0.19% 1.09% 2.07% 1.37% 2.00% 2.94%

1985-1990 3.23 2.29 2.64 2.87 2.68 2.45 1.65

1980-1990 3.07 1.23 1.86 2.47 2.02 2.22 2.29

Projections prepared by PPSP.
Peak demand figures are for the winter beginning in designated year.
Energy sales figures exclude sales to Easton and Dover. Peak figures include the portion
of Easton and Dover load provided by DP&L generation. Peak load and capacity figures exclude
the Getty Refinery loads and the Delaware City I and 2 capacity, respectively. The 1990 peak
loads are reduced by 50 megawatts to reflect the sale ot capacity from the Vienna 9 plant to
the Old Dominion Electric Cooperative.

Table 1-32

Historic Energy Sales, Peak Demand And
Generating Capacity For The Delmarva Power And Light Company (Maryland Portion)

Energy Sales (Thousands MWh) Peak Load (MW) Capacity Reserve Margin
Residential NonResidential Total Summer Winter Vqw)

1966 199 299 498 141 116 105

1970 322 451 773 210 206 132
1971 355 480 835 227 227 282
1972 389 511 900 278 233 282
1973 441 564 1,005 327 290 252
1974 458 569 1,027 319 275 252
1975 483 593 1,076 342 294 252

1976 543 648 1,190 315 347 252
1977 624 733 1,357 384 400 252
1978 654 776 1,430 377 400 252
1979 650 778 1,428 402 388 252
1980 669 773 1,442 430 - 252

Annual Average Rates of Growth

1966-1970 12.78% 10.80% 11.62% 10.47% 15.44% 4.68%

1970-1975 8.45 5.62 6.85 10.25 7.37 13.81

1975-1980 6.73 5.44 6.03 4.69 - 0.0

1966-1980 9.05 7.02 7.89 8.29 6.45

Peak demand figures are for winter beginning in designated year.
Energy sales figures exclude sales for resale and sales to Eas ton. Peak
demand figures include the portion of Easton peak served by DP&L generation.

MW M M'M IM M'M M M'M'M'M'M M I= M'=

Table 1-33

Projected Energy Sales, Peak Demand And
Generating Capacity For The Delmarva Power And Light Company (Maryland Portion)

Reserve Company Projections
Energy Sales (Thousands MWh)* Peak Load (MW)* Capacity Margin(%) Summer
Residential NonResidential Total Summer Winter (MW) Peak(MW) R.M.(%).

1981 661 800 1,461 443 252 391
1982 688 826 1,515 454 177 452
1983 717 854 1,573 468 177 457
1984 749 882 1,633 485 177 467
1985 782 913 1,697 503 177 480

1986 804 945 1,751 518 177 490
1987 829 978 1,809 535 177 503
1988 854 1,013 1,868 553 177 516
1989 880 1,048 1,930 572 177 528
Ln
1990 908 1,086 1,995 570 502 517

Annual Average Rates of Growth

1980-1985 3.18% 3.38% 3.31% 3.18% -6.82% 2.22%

1985-1990 3.03 3.53 3.29 2.53 23.18 1.50

1980-1990 3.10 3.46 3.30 2.86 7.13 1.86

Projections prepared by PPSP.
Peak demand figures are for the winter beginning in designated year.
Energy sales figures exclude sales for resale and sales to Easton. Peak demand
figures include the portion of Easton peak served by DP&L generation. The 1990
peak load projection is reduced by 22 megawatts to account for acquisition of
capacity by the old Dominion Electric Cooperative.

Table 1-34

Historic Energy Sales, Peak Demand And
Generating Capacity For The Potomac Electric Power Company (Total System)

Energy Sales (Thousands MWh) Peak Load (MW) Capacity Reserve Margin
Residential NonResidential Total Summer Winter (Mw)

1966 1,978 5,661 7,639 2,123 1,249 2,363 11.3%

1970 2,932 8,251 11,183 2,908 1,813 3,708 27.5
1971 3,038 8,696 11,734 3,045 1,919 4,529 39.9
1972 3,122 9,069 12,190 3,479 1,990 4,454 28.0
1973 3,529 9,704 13,233 3,680 2,159 4,721 28.3
1974 3,304 8,885 12,189 3,502 2,012 4,933 40.9
1975 3,399 9,322 12,722 3,623 2,145 5,190 43.3

1976 3,485 4,603 13,088 3,500 2,334 5,010 43.1
1977 3,617 10,030 13,647 3,857 2,508 5,013 30.0
1978 3,761 10,473 14,234 3,714 2,682 5,003 34.7
1979 3,907 10,821 14,729 3,804 2,691 4,990 31.2
1980 4,026 11,425 15,451 4,142 -- 4,999 20.7

Annual Average Rates of Growth

1966-1970 10.34% 9.88% 10.01% 8.18% 9.78% 11.92%

1970-1975 3.00 2.47 2.61 4.49 3.42 6.96

1975-1980 3.44 4.16 3.96 2.71 - -0.74

1966-1980 5.21 5.14 5.16 4.89 5.50

Peak demand figures are for the winter beginning in designated year.
Data exclude energy retail sales in Virginia and sales to SMECO, but
include Virginia and SMECO loads at the time of system peak.

PF PF PF 'I N ' I N N I ,

Table 1-35

Projected Energy Sales, Peak Demand And
Generating Capacity For The Potomac Electric Power Company (Total System)

Reserve Company Projections
Energy Sales (Thousands MWh)* Peak Load (MW)* Capacity Margin(%) Summer
Residential NonResidential Total Summer Winter (MW) Peak (MW) R.M.(%)

1981 4,232 11,276 15,508 4,242 4,999 17.9% 4,152 20.4%
1982 4,404 11,424 15,828 4,284 4,996 16.6 3,956 26.3
1983 4,590 11,572 16,162 4,322 5,322 23.1 4,000 33.1
1984 4,790 11,704 16,494 4,358 5,322 22.1 4,058 31.2
1985 5,000 11,824 16,824 4,393 5,322 21.2 4,105 29.7

1986 5,235 11,853 17,088 4,420 5,322 20.4 4,153 28.2
1987 5,484 11,962 17,446 4,453 5,322 19.5 4,208 26.5
1988 5,746 12,072 17,818 4,486 5,322 18.6 4,259 25.0
Ln
1989 6,020 12,184 18,204 4,520 5,322 17.7 4,302 23.7
1990 6,308 12,297 18,599 4,554 5,148 13.0 4,355 18.2

Annual Avera2e Rateq of Growth

1980-1985 4.43% 0.70% 1.72% 1.18% 1.26% -0.18%

1985-1990 4.76 0.79 2.03 0.72 -0.65 1.19

1980-1990 4.60 0.74 1.87 0.95 0.29 0.50

Projections prepared by PPSP.
Energy sales exclude retail sales in Virginia and sales to SMECO, but include
Virginia and SMECO loads at the time of the system peak.

REFERENCES - CHAPTER I

(1) Energy Information Administration. 1980 Annual Report to Congress,
Volume Two: Data. U.S. Department of Energy, DOE/EIA-0173(80)/2,
March 1981.

(2) Energy Information Administration. 1980 Annual Report to Congress,
Volume Three: Forecasts. U.S. Department of Energy,
DOE/EIA-0173(80)/3, March 1981.

(3) Energy Information Administration. Federal Energy Data System (FEDS)
Statistical Summary Update. U.S. Department of Energy,
DOE/EIA-0192. July 1979.

(4) Annual Reports to the Maryland Public Service Commission of the
municipal and cooperative electric utilities in Maryland for
calendar 1980.

(5) Annual Reports to the Maryland Public Service Commission for BG&E,
Pepco, DP&L and PE for calendar 1980.

(6) Maryland Department of State Planning. Population and Employment
1975-1990, May 1978 Revisions.

(7) Bureau of Labor Statistics. Employment and Earnings. U.S. Department
of Labor. July 1973 and July 1980 issues.

(8) Bureau of Economic Analysis. Survey of Current Business. Volume 60,
Number 11. U.S. Department of Commerce. November 1980.

(9) Wilson, John W. Douglas Point Site. Maryland Power Plant Siting
Program. PPSE 4-2, Volume 3. July 1975.

(10) J.W. Wilson & Associates, Inc. Projected Electric Power Demands for
the Baltimore Gas & Electric Company. Maryland Power Plant Siting
Program, PPES-1. 1979.

(11) J.W. Wilson & Associates, Inc. Projected Electric Power Demands for the
Allegheny Power System. Maryland Power Plant Siting Program,
PPES-2. January 1980.

(12) J.W. Wilson & Associates, Inc. An Econometric Forecast of Electric
Energy and Peak Demand on the Delmarva Peninsula. Maryland Power
Plant Siting Program, PPES-3. March 1980.

(13) Energy Information Administration. Typical Electric Bills. U.S.
Department of Energy, DOE/EIA-0040(80). December 1980.

(14) Poindexter, C. H. (BG&E). Letter to Thomas J. Hatem (Md. PSC).
October 29, 1981.

(15) Robb, Paul W. Letter to Howard A. Mueller (PPSP). November 11, 1981.

1-56

(16) Schuck, Gary A. Letter to Howard A. Mueller (PPSP). December 7, 1981.

(17) McCarthy, Homer T. Letter to Howard A. Mueller (PPSP).
December 21, 1981.

(18) The Duke Power Company. Annual Report. 1980.

(19) Baltimore Gas & Electric Company. Residential Conservation Program.
1981.

(20) Raskin, Paul, et. al. The Conservation Alternative for New York State.
Energy Sy7s-tem@s-Research Group, Inc. January 1981.

(21) California Energy Commission. Energy Service Corporations:
Opportunities for California Utilities. November 1980.

(22) Data Resources, Inc. The Impact of Marginal Cost Electricity Pricing in
the State of Maryland. Maryland Power Plant Siting Program,
PPRP-33. February 1979.

(23) Office of Power. TVA Report on the Rate Making Standards. Tennessee
Valley Authority. December 1979.

(24) Rebuttal Testimony of William F. Schmidt. Maryland Case 7441.
May 1981.

1-57

CHAPTER 11

POWER SUPPLY IN THE STATE OF MARYLAND

This chapter describes trends and issues relating to the supply of
electric power by Maryland utilities. To place this subject in proper
perspective, national and Maryland overall energy production trends are first
examined. Next, the generation profiles and capacity expansion plans of each
of the four major Maryland utility systems are presented in detail. The third
section of this chapter concerns generating capacity expansion planning. An
overview of the basic principles, methods and problems of generating planning
is provided. The fourth section contains a discussion of some of the more
important unconventional generation sources such as cogeneration, wind energy
and small-scale hydroelectricity. This chapter concludes with a list of defi-
nitions of terms commonly used in the electric utility industry.

A. Nationwide Energy Production Trends

Primary energy supply in the U.S. grew steadily during the 1950's, 1960's
and early 1971's. The increasing demand for energy was met principally by
increases in natural gas and oil production and by higher levels of imports.
As a consequence of the Arab oil embargo of 1973 and the subsequent increases
in petroleum prices, the supply of primary energy shifted towards greater
reliance on coal and nuclear energy. This shift represents an adjustment to
the significantly higher price of petroleum, both absolutely and relative to
other fuels, at the end of the 1970's compared to the pre-embargo years.

As shown in Table II-1, domestic production and net imports of oil and
natural gas accounted for approximately 78 percent of total primary energy
supply in 1973, while coal and nuclear energy combined represented 19 percent
of supply. Hydro, solar and geothermal accounted for the remaining 3 percent.
The most recent Department of Energy forecasts for 1985 indicate that the por-
tion of total primary energy supply from coal hnd nuclear energy will rise to
33 percent, while domestic and net imports of oil and natural gas will decline
to 62 percent.1 This represents a substantial shift to coal and nuclear (1).

while higher prices for oil and natural gas have induced producers to
increase exploration and to employ enhanced recovery techniques, physical
returns to drilling are declining. Figure II-1 indicates a sharp increase in
drilling activity throughout the forecast period, though less pronounced than
the increase which occurred in the 1970's. The number of feet drilled is
expected to approximately triple between 1971, a year of relatively low
drilling activity, and 1995. In spite of the expected increase in drilling
activity, the projected barrel-per-day of output over that period shows very
little change (see Figure 11-2).

----------- --- ----- -- -
-1 Percentages are based on the Btu content of the primary energy sources.

II-1

HISTORY PROJECTION

400

300

Lu 200
Lu
u-

z
0

100

1960 1965 1970 1975 1980 1985 1990 1995

Fig. II-1. U.S. oil and Gas Well Drilling, 1960-1995.

I PF PF IR 1 14 1 N I I I I

HISTORY PROJECTIONS
24

-4,

Uj
IL
cl) @--@Total Supply
Lu 12
M Imports
Ova

alft ftft a,,
*Aft MW "Wo goo ral Gas Plant Liquids
z
0 8
.j "t'stts North Alaska
still
I 1811,11'r'r 0 er-48 States Offshore
4

Lower-48 States Onshore

1960 1965 1970 1975 1980 1985 1990 1995

Fig. 11-2. U.S. Petroleum Liquids Supply by Source, 1960-1995.

The pattern of electric power supply in the U.S. reflects both the con-
ditions in primary energy markets (including the slower growth in demand for
electricity) and changes in the regulatory environment. The Power Plant and
Industrial Fuel Use Act of 1978 (Public Law 95-620) prohibits the use of oil
or natural gas as a primary fuel for new electric generating units and for
existing units which can be converted from oil to coal.1 The Act also
restricts use of natural gas in existing power plants. Unless a utility sub-
mits a plan for reducing its consumption of natural gas by 1990 to 20 percent
of the natural gas consumed in 1976, it is prohibited from using any natural
gas after January 1990. Additionally, the proportion of natural gas consumed
by an electric utility in any year prior to 1990 cannot exceed the average
proportion consumed in the period from 1974 through 1976.

while exemptions from the Fuel Use Act guidelines may be granted for
reasons of excessive cost of converting from oil to coal, fuel availability,
or environmental considerations, the combined effects of the Fuel Use Act and
higher oil and natural gas prices are clear: the future fuel mix of electric
utilities will emphasize coal and nuclear more heavily than has been true in
the.past. The combined percentage of coal and nuclear fuel used by electric
utilities is expected to rise from 48.2 percent in 1973 to 74.2 percent in
1985 and to 80.6 percent in 1990 according to EIA data (see Table 11-2).
National projections of electric utility generating capacity reveal a similar
trend of increasing reliance on coal and nuclear and diminishing reliance on
oil and natural gas (see Table 11-3).

Projections for the composition of supply of electric power by Maryland
utilities broadly follow the national trends though certain differences are
apparent. As shown in Table 11-5, 57 percent of the current generating capa-
city is coal-fired and 31 percent oil-fired. Current plans of the Maryland
utilities will result in 61.6 percent of capacity being coal-fired by 1990,
while oil-fired capacity falls to 23.7 percent.

While Maryland plans reflect national trends towards coal-fired capacity
and away from oil-fired capacity, Maryland is currently more oil dependent
than the nation as a whole and is expected to remain so through the end of
this decade. Although Maryland's generation mix differs somewhat from the
nationwide average, it is fairly typical of the Northeast region of the
country. This region has neither the convenient access to coal nor the great
hydroelectric resources found in other regions of the country. In addition,
many units originally designed to burn coal were converted to oil for environ-
mental reasons during the 19601s. For all of these reasons, the Northeast
(including Maryland) became more oil dependent than the rest of the nation.

In addition to inducing a shift to coal, higher oil and gas prices will
encourage the expansion of hydroelectric and nuclear capacity. At the
national level, hydroelectric generating capacity is forecasted to increase
approximately 35 percent between 1978 and 1990.2 Hydroelectric capacity owned
by Maryland utilities is expected to increase by over 600 percent during the
1980's and will account for 5.5 percent of 1990 generating capacity compared
with 1.1 percent in 1980.

--------------------------
1 The Act also provides exemptions for peaking units, such as combustion
turbines.

2 Based upon EIA middle oil price scenario.

11-4

Table II-1

U.S. Primary Energy Supply 1965-1995(a)
Domestic Supply And Net Imports
(Quadrillion Btuls)

Natural
Year Oil Gas Coal Nuclear Other(b) Total

1965 23.4 16.2 12.0 0.1 2.1 53.7

1973 35.1 23.2 13.0 0.9 2.9 75.0

1978 37.8 20.4 14.1 3.0 3.0 78.4

1985 30.5 18.6 20.6 5.6 3.4 78.7

1990 30.8 17.0 27.6 8.0 3.6 87.0

tn 1995 29.0 16.4 35.0 9.1 4.2 93.7

(a) Forecasts based on ETA middle price scenario.

(b) Other includes hydroelectric, solar, and geothermal.

Source: (1).

Table 11-2

Electricity Fuel Consumption, 1965-1995
(Quadrillion Btuls)

Fuel 1965 1973 1978 1985 1990 1995

Quads % Quads % Quads % Quads % Quads % Quads %

Fossil Fuels:
Oil 0.8 7.2% 3.6 18.1% 3.8 16.3% 1.6 5.7% 2.1 6.4% 0.8 2.1%
Natural Gas 2.4 21.6 3.7 18.6 3.3 14.2 2.2 7.8 0.6 1.8 0 0
Coal 5.8 52.3 8.7 43.7 10.3 44.2 15.3 54.3 18.3 56.1 23.4 62.4
Subtotal 9.0 81.1 16.1 80.9 17.4 74.7 19.1 67.7 21.0 64.4 24.2 64.5

Nuclear (a) 0.9 4.5 3.0 12.9 5.6 19.9 8.0 24.5 9.1 24.3

Hydroelectric 2.0 18.0 2.8 14.1 2.9 12.5 3.2 11.4 3.2 9.8 3.3 8.8
New Technologies(b) (a) (a) 0.1 0.4 0.3 1.1 0.4 1.2 0.8 2.1

Total Consumption 11.1 19.9 23.3 28.2 32.6 37.5

Total Generation 3.6 6.4 7.5 9.0 10.6 12.5

(a) Less than 0.05 quadrillion Btu.

(b) New technologies' historical data consist of geothermal and wood waste technologies. The projections
include the following renewable resources: geothermal, wind, solar thermal, solar photovoltaics,
biomass, and ocean thermal.

Source: (1).

M IM

Table 11-3

Electric Utility Generation Capacity And Reserve Margins 1965-1995
(Millions Of Kilowatts)

1965 1973 1978 1985c 1990C 1995C

Fossil Steam
Oil NA NA NA 77.0 92.0 82.0
Natural Gas NA NA NA 69.0 48.0 56.0
Coal NA NA NA 289.0 341.0 472.0
Subtotal 187.0 321.0 400.0 435.0 481.0 610.0
Nuclear 1.0 21.0 54.0 88.0 125.0 141.0
Hydroelectric 44.0 62.0 71.0 87.0 96.0 109.0
Combined Cycle a a a 8.0 8.0 8.0
Combustion Turbine 5.0 38.0 55.0 64.0 73.0 80.0
b
New Technologies a a 1.0 4.0 7.0 18.0

J
Total Capacity 236.0 442.0 579.0 686.0 790.0 966.0

Peak Demand 186.0 344.0 408.0 483.0 568.0 670.0

Reserve Margin 26.7% 28.5% 41.8% 41.9% 39.2% 44.2%
(percent)

a Less than 0.5 million kilowatts.
b New technologies include the following renewable resources:
geothermal, wind, solar thermal, solar photovoltaics, biomass,
and ocean thermal. New coal conversion processes are reported
with coal.
c Projections based on EIA middle price scenario.

Source: (1).

Table 11-4

Production Of Electricity By The Electric Utility Industry
By Type Of Energy Source 1960-1980
(Billion Kilowatt Hours)

Energy 1960 1965 1970 1975 1980*
Source 10!'KWH Percent lVKWH Percent IVKWH Percent lVKWH Percent 109
- - - Percent

Coal 403 53.5% 571 54.1% 704 46.0% 853 44.5% 1161 50.8%

Petroleum 46 6.1 65 6.2 184 12.0 289 15.1 246 10.8

Natural Gas 158 21.0 222 21.0 373 24.3 300 15.6 346 15.1

Nuclear
Power 1 0.1 4 0.4 22 1.4 173 9.0 251 11.0

Hydro Power 146 19.4 194 18.4 248 16.2 300 15.6 276 12.1
CD
Other - - - - 0.1 0.1 3 0.2 0.6 0.3

Total 753 1055 1532 1918 2286

Estimate

Source: (2).

M M M 1111 i i

Table 11-5

Electric Utility Generation
Capacity--Maryland Utility Systems
1980 AND 1990*
(Megawatts)

1980 1990
MW/Percent MW/Percent

Oil 5,966 31.3% 5,799 23.7%

Coal 10,763 56.5 15,042 61.6

Natural Gas 246 1.3 246 1.0

Hydroelectric 211 1.1 1,339 5.5

Nuclear 1860 9.8 2,026 8.3

TOTAL 19,046 24,432

Based on Summer 1980 capacity; projections based on
planned additions and retirements.

Source: (3).

11-9

most of the increase in hydroelectric capacity is represented by the
Allegheny Power System's decision to purchase a large part of the Bath County
pumped storage project. Increased ownership in the Safe Harbor Facility by
BG&E and several small scale hydro projects will also add to the total.
Although this represents a significant increase in total hydroelectric capa-
city, this 5.5 percentage is well below the 12.2 percent national figure pro-
jected for 1990.

Similarly, nuclear-powered units are projected to account for approxima-
tely 8 percent of the Maryland utilities' generating capacity in 1990, while
nuclear plants nationwide are forecasted to represent 16 percent of capacity.
The absence of additional nuclear capacity from the generation expansion plans
of Maryland utilities is due in large part to the slowdown in both recent and
projected growth in the demand for electricity, proximity to coal supplies,
and the need for relatively small size generating units, as well as economic
conditions which have reduced the relative desirability of nuclear power. In
order for a nuclear-powered generating plant to be economically attractive, it
needs to be large enough to capture the benefits of scale economies.
Typically, nuclear units which have gone into service in recent years have
name-plate capacity ratings of approximately 900 megawatts or more. (Calvert
Cliffs in Maryland includes two 810 MW units.) Because electric power demand
growth for Maryland utilities is expected to be relatively slow over the next
ten to fifteen years, a utility bringing on-line a 900-1100 megawatt unit must
either carry substantial excess capacity for several years (if the plant is
put into operation as soon as any of its capacity is required) or it must
purchase power to meet its load (if the utility waits until demand is suf-
ficient to absorb the additional capacity).1

In addition to this "lumpiness" problem, several other factors have dam-
pened interest in nuclear power. First, the lead time required in bringing
on-line a nuclear facility is in excess of ten years, with wide variability,
making generation planning difficult. In addition to the planning dif-
ficulties, the potential economic advantage to the utilities of using nuclear
power rather than coal as a fuel is substantially lessened by the ability of
Maryland utilities to pass through to the consumer any increase in fuel prices
on a monthly basis. Finally, both operating problems and regulatory delay
have served to lessen the economic attractiveness of nuclear units.

The rate of growth of capacity for Maryland utilities over the next ten
years is projected to be comparable to that of the nation as a whole. By
1990, capacity is expected to increase by 27 percent nationally and by 28 per-
cent in Maryland. Since 1973, however, the proportionate increase in
generating capacity by Maryland utilities has been significantly lower than
that for the nation: only 28 percent compared to 39 percent nationally. The
main reasons for this difference are the relatively slow economic growth since
1973 in the service areas of Maryland utilities and the excess capacity which
existed in the early part of this period and which was largely due to the dra-
matic decrease in the rate of growth in the demand for electricity since 1973
(see Chapter I).

--------------------------
1 Utilities have sometimes attempted to deal with this problem by either
jointly owning the plant with other utilities or by short-term capacity sales,
i.e., selling off some of the capacity of the plant during its early years of
operation.

II-10

B. Generation Profiles Of Maryland Utilities

As described in Chapter I, almost all of the bulk power consumed in
Maryland is provided by four major, privately-owned, integrated utilities:
Potomac Electric Power Company, Baltimore Gas and Electric, Potomac Edison and
Del .. arva Power and Light. This section.examines the present and future
generating profiles of each of these four major utilities. The discussion
describes the capacity expansion plans over the next ten years and evaluates
the ability of each utility to meet its future loads by comparing forecasted
loads with planned capacity additions. Trends in generating capacity mix are
also discussed.

The discussion in this section is supplemented by data tables which sum-
marize the capacity expansion plans and generating capacity profiles of the
four major electric utilities. Table 11-6 provides forecasted demands, capa-
city and reserve margins for each utility. Table 11-7 presents a schedule of
capacity changes on a unit by unit basis through the end of this century. The
capacity profile (i.e., megawatts by fuel type) of each utility is shown for
1979 and for selected future years in Table 11-8. Those figures are also pre-
sented in percentages in Table 11-9. Finally, Table II-10 presents each
Company's megawatt hour generation by fuel type for calendar 1980.

Baltimore Gas and Electric Company (BG&E)

BG&E, serving Baltimore City and all or portions of eight surrounding
counties, had a total generating capacity of 5,010 megawatts in 1980 compared
with a peak demand of 3,969 megawatts, leaving BG&E with a reserve margin of
approximately 26 percent.1 PPSP forecasts peak demand growth of 2.8 percent
per year through 1990, and current plans call for an annual increase in
generating capacity of 2.3 percent. On the basis of this forecast and expan-
sion plan, BG&E will have adequate reserves through the end of this decade.
Reserve margins exceed 25 percent in most years and never fall below 20 per-
cent. (see Table 11-6).

During the 19801s, BG&E plans to add two 620 mW coal-burning units at the
Brandon Shores site, purchase power from a 40 megawatt municipal solid waste
generating plant, and a 125 megawatt expansion of its Safe Harbor hydro capa-
city. The solid waste plant is scheduled to begin service in 1985, the
Brandon Shores units are scheduled for 1984 and 1988, and the Safe Harbor
addition is scheduled for Fall 1985. Five oil-fired units at the Westport
Station which total 177 megawatts are scheduled for retirement during the
1984-1992 period. For the 1990's, BG&E plans to add 1400 megawatts of
"baseload" capacity and 443 megawatts of pumped storage. one of the baseload
plants will be an 800 megawatt coal-fired plant to begin service in 1992 at
the Perryman site. The Company plans to retain 400 megawatts of the plant.

----------------------------
1 The industry usually accepts reserve margins of 15 to 25 percent as adequate
for reliability purposes. Planned reserve margins differ for each utility.

II-11

Table 11-6

Forecasted Peak Demand, Generating Capacity
and Reserve Margins, 1980_1990(a)
(megawatts)
BG&E DP&L Pepco APS (b)
Demand Capacity R.M. Demand Capacity R.M. Demand Capacity R.M. Demand Capacity R.M.

1980 3,969 5,010 26.2% 1,529 2,008 31.3% 4,142 4,999 20.7% 5,564 7,568 36.0%
1981 3,897 5,025 29.0 1,506 2,219 47.3 4,242 4,999 17.9 5,552 7,587 36.7
1982 4,028 5,025 24.8 1,547 2,324 50.2 4,284 4,996 16.6 5,726 7,600 32.7
1983 4,162 5,025 20.7 1,594 2,167 36.0 4,322 5,322 23.1 5,910 7,600 28.6
1984 4,303 5,594 30.0 1,641 2,167 32.1 4,358 5,322 22.1 6,093 7,600 24.7
1985 4,447 5,634 26.7 1,694 2,217 30.9 4,393 5,322 21.2 6,264 8,020 27.4

1986 4,591 5,759 25.4 1,749 2,217 26.8 4,420 5,322 20.4 6,443 8,440 31.0
1987 4,741 5,701 20.3 1,808 2,177 20.4 4,453 5,322 19.5 6,626 8,440 27.4
1988 4,897 6,321 29.1 1,869 2,177 16.5 4,486 5,322 18.6 6,810 8,440 23.9
1989 5,091 6,321 24.2 1,934 2,177 12.6 4,520 5,322 17.7 7,000 9,070 29.6
1990 5,232 6,321 20.8 1,951 2,502 28.2 4,554 5,148 13.0 7,236 8,995 24.3

(a) Capacity figures are from the Company's latest generation plan. Peak demand figures are PPSP forecasts.

(b) Figures refer to peaks and installed capacity for winter beginning in designated year.

Source: Chapter 1, Tables 1-24 through 1-35.

Table II - 7

summary Of Capacity Chan es of
Maryland Utilitiesia)
(Megawatts)

Additions Reductions

1981 +19 Miscellaneous Rerates - 12 Kent (DP&L)
(APS) - 4 Edge Moor 2, 3 & 4 (DP&L)
- 2 Delaware City 3 (DP&L)
-269 Benning 13 & Buzzard
1-6 Retirement (Pepco)

------------------------------------------

1982 +83 Salem 2 (DP&L)
+22 Indian River Uprate (DP&L) - 10 Mitchell 3 Derate (APS)
+600 Chalk Point 4 (Pepco) - 8 Chalk Point I & 2 Derate (Pepco)
+23 Pleasants 2 Uprate (APS)

------------------------------------------

1983 No additions - 70 Edge Moor 1 Retirement (DP&L)
- 15 Edge Moor 4 (DP&L)
- 70 Edge Moor 2 Retirement (DPW
- 2 Edge Moor 3 (DP&L)
- 8 Chalk Point I & 2 Derate

--- --------------------------------------

1984 +620 Brandon Shores 1 (BG&E) - 51 Westport 1, 13, 14 (BG&E)

------------------------------------------

1985 +50 Indian River 4 (DP&L) No reductions
+420 Bath Project (APS)
+40 Solid Waste (BG&E)

------- ----------------------------------

1986 +125 Safe Harbor (BG&E) - 40 Delaware City 3
+420 Bath Project (APS)

------------------------------------------

1987 No additions - 58 Westport 4 (BG&E)

------------------------------------------

1988 +620 Brandon Shores)2 (BG&E) No reductions

------------------------------------------

11-13

Table II - 7 (Continued)

Summary of Capacity Plans Of
Maryland Utilities
(Megawatts)

Additions Reductions

1989 +630 Lower Armstrong 1 (APS)

------------------------------------------

1990 +500 Vienna 9 (DP&L)(a) - 42 Edge Moor 10, Madison St (DP&L)
+ 42 CT's (DP&L) - 75 Retirements (APS)
-174 Potomac River 1, 2 (Pepco)

------------------------------------------

1991 +630 Lower Armstrong 2 (APS) - 75 Retirements (APS)

------------------------------------------

1992 +800 Perryman (BG&E)(c) - 68 Westport 4 (BG&E)
+630 Lower Armstrong 3 (APS) - 51 Delaware City 10, Indian
+ 51 CT's (DP&L) River 10, Vienna 10 (DP&L)
- 75 Retirements

------------------------------------------

1993 +300 Coal Plant (Pepco) No reductions

------------------------------------------

1994 +148 Pumped Storage (BG&E) No reductions

------------------------------------------

1995 +295 Pumped Storage (BG&E) No reductions
+400 Coal Unit (DP&L)

------------------------------------------

1996 No additions -80 Edge Moor 3(DP&L)

------------------------------------------

1997 +400 Base Load (BG&E) No reductions

------------------------------------------

11-14

Table 11-7 (Continued)

Summary of Capacity Plans of
Maryland Utilities
(Megawatts)

Additions Reductions

1998 No additions -89 Indian River 1 (DP&L)
+400 Coal Unit (DP&L)

------------------------------------------

1999 +225 Pumped Storage (Pepco) No reductions
+600 Base Load (BG&E)

------------------------------------------

2000 No additions No reductions

(a) APS plans only available through 1992.
(b) DP&L's share of Vienna 9 is 325 MW. The other shares are
125 MW to Atlantic City Electric and 50 MW to the old Dominion
Electric Cooperative.

Source: (4), (5), (6), (7).

11-15

Table 11-8
Generating Capacity Of Maryland Utility Systems
By Fuel-Type 1979-1991
(Megawatts)

Other(b)
LeRqq DP&L(a) APS BG&E Md. Total(c)

1979
Oil/Gas 1,986 1,285 486 2,371 31 6,159
Coal 3,013 793 6,449 852 - 11,107
Nuclear - 237 - 1,635 - 1,872
Hydro - - 62 152 950 1,164
Total 4,999 2,315 6,997 5,010 981 20,302

1981
511/Gas 1,986 1,189 446 2,371 31 6,023
Coal 3,013 815 7,079 852 - 11,759
Nuclear - 320 - 1,650 - 1,970
Hydro - - 62 152 950 1,164
Total 4,999 2,324 7,587 5,025 981 20,916

1986
Oil/Gas 2,317 760 446 1,936 31 5,490
Coal 3,005 1,097 7,092 1,856 - 13,050
Nuclear - 320 - 1,650 - 1,970
Hydro - - 902 277 950 2,129
Total 5,322 2,177 8,440 5,719 981 22,639

1991
Oil/Gas 2,317 760 296 1,878 31 5,282
Coal 2,831 1,422 8,352 2,476 - 15,081
Nuclear - 320 - 1,650 - 1,970
Hydro - - 902 277 950 2,129
Total 5,148 2,502 9,550 6,281 981 24,462

(a) DP&L figures are for 1980, 1982, 1987 and 1992 rather than
indicated years.

(b) Includes oil-burning units at Hagerstown, Md. and hydro units
at Deep Creek Lake and Conowingo.

(c) Table excludes generating capacity of Easton, Maryland; Dover,
Delaware; and a 40 megawatt municipal solid waste unit supplying
the BG&E system.

Source: (4), (5), (6), (7).

11-16

Table 11-9

Generating Capacity Of Maryland Utility Systems
By Fuel-type 1979-1991
(percent)

Pepco DP&L APS BG&E Total

1979
Oil/Gas 39.7% 55.5% 7.0% 47.3% 30.3%
Coal 60.3 34.3 92.2 17.0 54.7
Nuclear - 10.2 - 32.6 9.2
Hydro - - 0.9 3.0 5.7

1981
Oil/Gas 39.7 51.2 5.9 47.2 28.8
Coal 60.3 35.1 93.3 17.0 56.2
Nuclear - 13*1 - 32,1 9*1
Hydro - - 0.8 3.0 5.6

1986
Oil/Gas 43.5 34.9 5.3 33.9 24.3
Coal 56.5 50.4 84.0 32.5 57.6
Nuclear - 14.7 - 28.9 8.7
Hydro - - 10.7 4.8 9.4

1991
Oil/Gas 45.0 30.4 3.1 29.9 21.6
Coal 55.0 56.8 87.5 39.4 61.7
Nuclear - 12.8 - 26.3 8.1
Hydro - 9.5 4.4 8.7

Source: Table 11-8.

11-17

Table II-10

1980 Generation Profile of The Maryland Utilities F

Generation (Thousands MWh)

Pepco BG&E DP&L* APS Total

Oil/Gas 1,983 3,361 4,051 103 9,498

Coal 16,095 5,167 2,971 34,645 58,878

Hydro - 436 - 193 629

Nuclear - 10,947 1,286 - 12,233

Total 18,078 19,911 8,308 34,941 81,238

Percent

Oil/Gas 11.0% 16.9% 48.8% 0.3% 11.7%

Coal 89.0 26.0 35.8 99.2 72.5

Hydro - 2.2 - 0.5 0.8

Nuclear 55.0 15.4 - 15.1

Generation from Delaware City 1, 2 and Atlantic City Electric's
share of Indian River 4 have been subtracted from the totals.

Source: (4), (5), (6), (7).

Currently, BG&Els capacity profile is dominated by nuclear and oil. Coal
comprises only 17 percent of the total compared to 33 percent for nuclear and
47 percent for gas and oil. Over the next ten years oil capacity will
decline, nuclear will not change, and coal capacity will increase substan-
tially. However, as shown in Table 11-8 and 11-9, oil and gas will still pro-
vide more than a third of BG&E'S capacity in 1991.

In evaluating the power supply prof ile of an electric utilitv system, it
is important to recognize generation by fuel type as well as capacity by fuel
type. This is because not all generating units on a utility system run for
the same amount of time. With some minor exceptions, all four utilities
operate on an economy basis, meaning that the units which are most inexpensive
to operate are run as much as possible, and the units which are more expensive
to operate are run only when required to serve loads.1 BG&E provides an
excellent example of economy operation. The Calvert Cliffs nuclear units
account for less than a third of BG&E1s capacity, but they accounted for more
than half of the Company's power generation in 1980. Oil and gas represented
about 47 percent of BG&E's capacity in 1980, but less than 20 percent of the
Company's power generation. Thus, BG&E is not nearly as oil dependent as the
capacity figures might suggest.

Delmarva Power and Light Company (DP&L)

DP&L provides either directly or indirectly more than 90 percent of the
electric power consumed on the Delmarva Peninsula.2 For purposes of planning
and operation, DP&L functions as a completely integrated system. The descrip-
tion which follows, therefore, examines the DP&L service area in its entirety
rather than artificially isolating the Maryland portion, which accounts for
only approximately one-fourth of DP&L's systemwide sales.

All of the municipal and rural electric cooperative utilities on the
Delmarva Peninsula are integrated with DP&L. However, the data presented in
Tables 11-6 through II-10 exclude the Dover, Delaware and Easton, Maryland
municipal systems (the only other systems on the Peninsula generating signifi-
cant amounts of power) since DP&L does not routinely report Group figures to
the Maryland Public Service Commission. Those tables also exclude the Getty
refinery load and the generating units dedicated to those loads.

The DP&L Group, which includes the Dover and Easton systems, had a total
generating capacity of 2,111 megawatts in 1111, DP&L plans to increase calpa-
city by 8.7 percent by 1991. During the 19801s, DP&L will replace much of its
oil-fired capacity with coal and a small amount of nuclear. The principal
additions to capacity in the 1980's are two coal-fired plants -- Indian River
4, which began operation in late 1980, is a 400 megawatt power plant3, and the

---------------------------
1 Utilities sometimes run their high cost plants to take advantage of oppor-
tunities to sell power to a power pool. The pool settlements procedure more
than reimburses them for the cost of doing so.
2 The Peninsula consists of the Maryland Eastern Shore counties, the State of
Delaware, and the two Virginia counties on the Eastern Shore.
3 Atlantic City Electric Company will lease 50 megawatts from the Indian River
plant until 1985.

11-19

and the proposed Vienna 9, scheduled to come on-line in 1990, has a planned
capacity of 500 megawatts-1 DP&L will receive 83 megawatts of capacity in
1981 from the Salem 2 nuclear plant. Edge Moor 3 and 4 (combined capacity 249
megawatts) will be converted from oil-fired to coal-fired in 1982 and 1983.
Edge Moor 1 and 2, oil-fired units with a combined generating capacity of 140
megawatts, will be retired during the 19801s.

Between 1980 and 1990, peak demand is forecasted to grow at an average
annual compount rate of 2.5 percent, compared with a 2.2 percent rate of
growth for capacity. While DP&L's peak demand is expected to grow more
rapidly than capacity, DP&L is expected to face high reserve margins during
the early portion of the 1980's. Reserve margins are expected to exceed 25
percent through the mid-1980's but will drop below 20 percent during the late
1980's until Vienna 9 comes on-line in 1990.2
OF
DP&L has designed its generation plan to move very rapidly away from its
very heavy oil dependence. In 1980, more than half of the DP&L Group capacity
was oil-fired, with coal accounting for only about one-third. By 1990, oil
capacity will fall to 30 percent, and coal capacity will rise to 57 percent.
Thus, a dramatic reversal will take place within a decade if the Company's
plan is implemented.

The Company is currently seeking a license from the Maryland Public
Service Commission for a 500 megawatt plant to be located at its existing
Vienna, Maryland site (Maryland PSC Case No. 7222). Although DP&L now intends
to begin operation in 1990, the Company originally intended to bring Vienna 9
on-line in 1987. That date would have been in advance of when the capacity
would have been needed for reliability purposes according to the PPSP load
forecast. However, a PPSP study demonstrated that oil savings from the opera-
tion of the plant make the 1987 on-line date economically attractive (9).
This result is due to the large disparity between the per Btu price of oil and
coal.

Like BG&E, the DP&L Group is operated on an economy dispatch basis
generating units are dispatched in merit order on the basis of their relative
operating costs. Although nearly 65 percent of the Company's capacity in 1980
was oil, only 51 percent of its power was generated from burning oil in
1980.3 The tendency to minimize the usage of oil by instead operating the
cheaper to operate coal and nuclear facilities is illustrated in the detailed
generation data provided in PPSP's annual report on the long run generation
plans of Maryland utilities (10). As the data in that report show, the coal
burning facilities have dramatically higher capacity factors4 than do the oil
burning plants.

---------------------------
1 DP&L will maintain ownership of 325 megawatts, 50 megawatts will be owned by
three rural co-ops that are presently wholesale customers of DP&L, and 125
megawatts will be owned by Atlantic City Electric.

2 DP&L considers 16 percent an adequate reserve margin.
3 The capacity percentage figure excludes Indian River 4 which did not begin
service until October 1980.

4 A capacity_factor is defined as total electric energy generated by a plant
during some time interval as a percentage of the total amount of energy the
unit is capable of generating. For purposes of comparison, 1980 capacity
factors have been adjusted for planned and forced outages of each unit.

11-20

The Allegheny Power System (APB)

APS is a predominantly coal-fired Utility. This is not surprising given
the fact that its service territory is one of this nation's most important
coal mining regions. Given the fact that transportation represents a very
large percentage of the total cost of coal for most utilities, APB' proximity
to that fuel has made coal-fired generation particularly attractive.
Currently, more than 90 percent of the system's capacity is coal-fired. In
addition, APB has about 450 megawatts of oil generation and a small amount of
hydro capacity.

APB plans to add nearly 2,100 megawatts of generating capacity between
now and 1991 from two large projects. APB has announced its intention to par-
ticipate in a joint venture with Virginia Electric Power Company (VEPCO) to
construct a hydroelectric pumped storage facility in Bath County, Virginia.
When completed, this project will be the world's largest pumped storage
facility.1 APB intends to purchase (and/or lease), subject to regulatory
approval, either 40 or 50 percent of the total 2,100 megawatts of the plant.
APB' current generation plan indicates 420 megawatts in 1985 and an additional
420 megawatts in 1986, but it may ultimately add as much as 1,050 megawatts.

The other major facility which APS lists in its generation plan is the
Lower Armstrong Station, which will consist of three 630 megawatt coal-fired
units. The three units are scheduled to begin service in 1989, 1991, and
1992. Some initial design work and a draft environmental impact statement
have been completed. However, APB suspended work in 1978 on the project,
indicating that its financial condition and expectations concerning future
rate treatment prevent it from undertaking the project (11). In order that
the first Lower Armstrong unit meet its planned in-service date of 1989, work
must resume within the next year. Thus, if the suspension continues much
longer, the Company will be forced to alter its generation plan.

The APB decision to participate in the Bath Project was prompted by its
inability to proceed with Davis, a proposed 1,000 megawatt pumped hydro plant
which had been licensed several years ago by the Federal Energy Regulatory
Commission (FERC). The FERC license has been challenged in Federal Courts.
After receiving the FERC license, APB was refused a dredge and fill permit for
Davis by the Army Corps of Engineers. The permit dispute is currently under
litigation, but APB has eliminated Davis from.its current ten year plan.
However, should it succeed in obtaining needed approval, APB would consider
constructing Davis in the 1990's after completion of Lower Armstrong.

APB has also included in its plans some unspecified retirements over the
1990 to 1992 periods which amount to 225 megawatts of capacity.

1 Pumped storage hydro involves pumping water from a lower reservoir to a
higher reservoir during the off-peak period and allowing that water to flow
back into the lower reservoir and generate power during the peak period. The
facility creates no additional electricity because the energy required for
pumping exceeds the energy generated. However, it is able to shift energy
from the off-peak to the peak period, and thereby make energy available when
most needed.

11-21

APS' current capacity plan, when compared to the PPSP load forecast,
indicates a pattern similar to that of DP&L (see Table 11-6). Reserve margins
are rather high in the early part of the 1980's and gradually decline
thereafter.1 After the early 1980's reserves will range between approxima-
tely 25-30 percent. Because of its relatively high system load factor, APS
believes that its optimal reserve margin should be approximately 23 to 27 per-
cent. Thus, APS' generation plan appears to be adequate and only requires
carrying excess reserves in the early part of the 19801s.

That evaluation assumes that APS' current generation plan is built as
scheduled. The Lower Armstrong units cannot be built as scheduled unless
progress is resumed in the very near future. On the basis of existing fore-
casts, significant further delays would lead to an unreliable system by the
early 19901s.

The Potomac Electric Power Company (Pepco)

Pepco currently has 4,999 megawatts of generating capacity, approximately
40 percent of which burns oil and the remainder burns coal. It currently
lacks, and has no plans to add, hydroelectric or nuclear capacity. Pepco
capacity expansion plans are rather modest, largely because the Company's
system load is growing so slowly: Pepco is predicting annual load growth of
approximately one percent. The nearly completed Chalk Point 4 oil-fired plant
is expected to begin service in 1982. The Company is currently planning for
an unspecified 300 megawatt coal unit in 1993 and is considering an
underground pumped storage facility for the late 19901s. Mixed in with these
capacity additions are several retirements of some of the Company's older,
oil-fired capacity.

Despite the planned retirements, Pepcols percentage of oil capacity will
increase over time. Pepco, is the only Maryland utility expected to experience
such an increase. This situation will occur for two reasons. First, the
Chalk Point 4 unit, which will add 600 megawatts of oil capacity in 1982, was
planned and designed before the industry began to switch away from oil capa-
city so decidedly. Second, the next capacity addition is not scheduled to
occur until 1993, and that addition is only half the size of Chalk Point 4.
Thus, Pepco's generation plan after 1982 provides little opportunity to
replace oil.

Like the other Maryland utilities, Pepco dispatches its generating units
on an economy, cost-minimizing basis. The Company, therefore, attempts to
maximize the operation of its coal plants and to minimize the operation of its
oil plants. Consequently, although oil represents about 40 percent of the
Company's capacity, it accounted for only 11 percent of total power production
in 1980.

-------------------
1 The reserve margins for the first half of the 1980's are actually greater
than shown in Table 11-6 (which includes only installed capacity) because APS
maintains a diversity exchange arrangement with Vepco. Under this arrangement
APS supplies 300 megawatts to Vepco in the summer in exchange for the same
amount of power in the winter. This arrangement will run until 1985.

11-22

Pepco's level of reserves is barely adequate at the present time.
However, with the imminent addition of Chalk Point 4, Pepco's reserves should
be adequate until the early 1990's if the present forecasts are correct. To
some extent the Company can modify the level of reserves by altering planned
retirement dates of its older capacity. However, current forecasts call for
load growth of roughly one percent per year. if loads were actually to grow
at the rate of just under three percent forecast by APS and the DP&L systems,
Pepco would experience deficient reserves several years in advance of its next
planned capacity addition. For that reason, the Pepco load growth warrants
careful scrutiny.

C. Generation Planning

A generation expansion plan is the means by which a utility proposes to
serve its expected future loads. A franchise monopoly held by a regulated
utility carries with it an obligation to provide adequate and reliable service
to all its "firm" customers, and capacity must be planned accordingly. At the
same time, it is desirable that the utility provide reliable service at mini-
mum long run cost. As a result, reliability and long-run cost minimization
are the twin goals of system generation planning.

With these goals in mind, the generation planner must address the
following fundamental questions:

0 When should new capacity additions be scheduled to begin service?

0 How large should those capacity additions be?

0 What kind of generating capacity (i.e., technology and fuel type)
should be added?

0 How can and should power demands be managed to avoid expensive energy
and/or capacity additions?

The question relating to the timing of new capacity is determined by the pro-
jected growth in loads on the system in conjunction with judgments concerning
the appropriate reserve margin for the utility. Load forecasting and the sub-
ject of demand-side approaches to generation planning are discussed in detail
in Chapter I. This section focuses on the economic principles normally
employed in the selection of the least cost generating technology. The
discussion also gives recognition to the various dynamic factors which may
complicate the planning process and often limit the options available to the
planner. This section concludes with a discussion of the conversion of oil-
fired plants to coal.

11-23

Economic Principles of Generation Expansion Planning

Given forecasted loads and specified reliability standards (e.g.,
expressed as reserve margins), the planner determines when the system must add
its next plant.1 Having made the scheduling determination the planner
must then select the least cost technology for the next unit. Conventional
power plant technologies fall into three major categories -- baseload, cycling
and eaking -- and five major fuel types -- nuclear, coal, hydro, oil and
gas.3

The way in which a mix of these various plant types operate to serve a uti-
lity system's power demands can best be explained by reference to a typical
daily load curve. That curve shows system demands at different times of the
day. Load falls in the early morning hours and sharDly rises throughout the
day reaching a maximum in the late afternoon. Loads gradually subside during
the evening. There is a certain minimum or "base" level of load which is
exceeded at virtually every hour. This will be served by baseload units,
which are large, very efficient generating units which run almost con-
tinuously. Because these units require long periods of time to be brought up
to full throttle from a cold start, they can only run in a continuous mode.
Typically, baseload units are coal or nuclear-fired and about 400 megawatts or
larger.

Above the base or minimum load on the daily load curve, demand may change
rapidly from hour to hour. There is a need for power plants on the system
which can adjust their energy output to follow these changes in load. Cycling
units have the capability of altering their output on short notice in response
to expected load changes. The cost of this flexibility is some loss in energy
efficiency as compared to the baseload units. Cycling units are usually steam
plants, coal or oil-burning, and are somewhat smaller than baseload units.
Hydro plants with reservoir storage can also be operated as cycling plants.

Finally, the very top of the load curve is served by peaking plants.
Peaking plants are extremely expensive to operate, but are only run for short
periods of time when power demands are near the maximum. Also, peaking plants
are completely flexible and are capable of coming up to full load on very
short notice (i.e., in minutes). oil and gas burning combustion turbines are
the most common type of peaking plant used in the industry. However, there

----------------------
1 Because of the high cost of oil relative to other fuels, it is becoming
increasingly common for utilities to schedule capacity additions in advance of
load growth to displace oil-fired generation. Doing so reduces long-run
system costs if the added fuel savings from accelerating the schedule more
than offset the additional capital costs of carrying the "excess" capacity. A
PPSP study concluded that this is likely to be the case for DP&L's proposed
Vienna 9 plant (9).
2 The Fuel Use Act prohibits the use of gas or oil in new utility plants.
However, it is possible to obtain exemptions for plants that will be operated
as peaking units.

11-24

is also growing interest in pumped storage hydro both to serve peak loads and
to function as cycling capacity.

Baseload, cycling and peaking plants have different operating charac-
teristics, construction costs and lead time requirements. At one extreme,
baseload plants are very expensive to construct and install on a per kW basis
compared to smaller peaking plants. Offsetting that, baseload plants are
capable of burning relatively inexpensive fuels (e.g., coal and uranium) and
do so with relatively high efficiency. Thus, on a per kilowatt hour basis
they are the most inexpensive plants to operate. At the other extreme peaking
units are relatively inexpensive to construct per kW but are expensive to
operate, largely because they typically burn oil or gas.

Thus, aside from operating characteristics, the choice of plant type is a
matter of trading off capital and operating costs. For example, a typical
baseload coal plant might cost $1,000 per kilowatt to construct and have an
operating cost (i.e., fuel cost) of 1.5 cents per kilowatt hour. By com-
parison, a combustion turbine unit might cost roughly $200 per kilowatt to
construct and 7 cents per kilowatt hour to operate. The selection of the type
of capacity will ultimately depend upon the number of hours the plant must
run. If the plant is expected to run a large number of hours, a baseload
plant is clearly more economic. If the capacity is only required for a small
number of hours, it is more economic to conserve capital costs and expend
higher fuel costs.

The following diagram illustrates this trade-off on an annual basis for
one kilowatt of capacity. A 10 percent annual carrying cost is assumed,
translating the capital costs into $100 per kW per year for baseload and $20
per kW for a peaking unit.

11-25

Annual
Total
Cost
$

500

400
peakirxg unit

300

200

baseload unit
100

1 2 3 4 5 6

Hours operated per year
(Thousands)

The two lines indicate the total annual cost of carrying and operating both
types of capacity at varying levels of usage. This diagram indicates that
total costs are equal at roughly 1,500 hours of usage; for fewer hours of
usage the peaking unit is less expensive, and for more hours of operation the
baseload unit is less expensive. This simplified example, however, will
overstate the attractiveness of the peaking unit if it is expected that oil
will increase in price over time more rapidly than coal.

in order to select an optimal plant size and fuel type, it is necessary
to compare generating costs in a manner which reasonably reflects the full
range and complexity of relevant economic and engineering factors. The
variable costs of bulk power supply over an appropriate time horizon (usually
about 20 years) are often calculated by the use of a production costing simu-
lation model. These models attempt to simulate the operation of a given power

11-26

system by dispatching the utility's power plants to meet its forecasted loads.
It is assumed (unless otherwise adjusted for) that plants will be dispatched
on a merit basis so as to serve load in the most inexpensive way possible.
The modeling takes into account numerous factors, including fuel costs over
time, non-fuel operating and maintenance expenses, load growth, changes in
load shape, unit maintenance requirements and forced outages.

After determining the variable costs of different generation capacity
plans from the simulation model (and discounting those costs to the present),
the fixed costs of the various generation plans must be considered. The fixed
costs may be calculated as the additional revenue requirements over the time
horizon of the alternative capacity addition plans (discounted to present
value).' The sum of the variable and fixed cost revenue requirements is the
total cost of a given plan. The plan providing the lowest total cost,
assuming it satisfies the reliability criteria, is considered optimal.

The above discussion describes the straight-forward calculations used to
determine the selection of the least-cost generation technology alternative.
It is also important to recognize that the planner faces a multitude of
complications and constraints. A partial list includes the followi ng:

0 Uncertainty -- The single most important planning decision relates
to capacity addition timing. Unfortunately, the load forecasts which
are relied upon tend to be highly uncertain. similarly, the calcula-
tion of the cost-minimizing technology is based upon uncertain
assumptions regarding future fuel prices, capital costs and so forth.

0 Lead Time -- It now requires 10-12 years or longer to site, license
and construct a new baseload power plant. Long lead times have the
effect of reducing planning flexibility by limiting the feasible
generation alternatives. For example, a firm may need new capacity
sooner than it is capable of getting a new baseload unit on-line.

0 Financial Capability -- Electric utilities do not have unlimited
financial resources. The generation plan must therefore be con-
sistent with the ability of the utility to raise the required
investment capital. It is possible that financial limitations might
force a utility to select a capacity expansion plan which does not
minimize long-run costs.

Regulatory Constraint -- Generation planning options are sometimes
limited by regulatory constraints on power plant construction and
operation. The inability of APS to obtain approval to construct the
Davis pumped storage project is an example of such constraint. The
restrictions in the Fuel Use Act represent a further restriction on
the fuel type a power plant may be designed to burn.

Generation planning is clearly not a simple, straightforward exercise. It
requires reconciling the economically most attractive plan with a long list of
real world risks and problems which are beyond the direct control of the
planner.

---------------------------
1 As in our simplified example, capital costs of alternative plants may be
calculated by applying an appropriate annual carrying cost rate to the
construction costs.

11-27

Coal Conversion

The price of oil in recent years has increased significantly and far more
quickly than the price of coal. Prior to the 1973-74 Arab oil embargo, oil
was viewed as an inexpensive, readily available and convenient fuel.
Additionally, oil is a relatively clean fuel and does not require large
investments in pollution abatement equipment. Consequently, the generation
plans drawn up in the late 19501s, 19601s, and early,.1970's relied heavily
upon oil-fired power plants. It has been become evident since the embargo,
however, that coal is generally more economical to use as a primary fuel in
baseload generating units. Unfortunately, the replacement of oil-fired capa-
city with coal-fired capacity is complicated by the fact that the useful life
of a generating unit is about 30 years. The long service life, coupled with
the large initial capital investment associated with bringing on a new plant,
tends to discourage replacement of oil-fired capacity far in advance of the
originally envisaged retirement date.

A utility may, however, have the option of converting an oil-fired unit.
Conversion of a generating unit specifically designed to burn oil into a coal-
fired unit involves major alterations to the unit. However, many facilities
were originally designed to burn coal and were later converted to oil. It is
economically practical to reconvert many of these "coal-capable" units.
Coal conversion is cost-effective only if the capital costs of conversion can
be recovered over *the remaining useful life of the generating unit by the
savings (appropriately discounted) obtained by using coal as a primary fuel
rather than the higher priced oil. This condition will be met if (1) the
price of a unit of coal does not quickly increase to approach the price of an
energy-equivalent amount of oil; and (2) if the useful life of the generating
unit is sufficiently lo 'ng. Clearly, if the cost of obtaining energy from coal
is roughly equal to the cost of energy from oil, there is no compelling econo-
mic reason to convert to coal. Similarly, if the power plant under con-
sideration can supply only a few remaining years of useful service, there will
to be too few kilowatt hours generated in which to recoup the initial capital
costs associated with the conversion.

The Energy Supply and Environmental Coordination Act of 1974 underscored
the Federal Government's interest in shifting reliance from oil to coal and
stipulated that coal-capable power plants must burn coal. In 1978, stricter
standards were enacted and financial incentives were created to induce utili-
ties to alter their fuel mix in favor of coal. The Power Plant and Industrial
Fuel Use Act (1978) precludes the construction of large (baseload) oil and
natural gas boilers by public utilities and industryl, though certain exemp-
tions may be granted by the U.S. Department of Energy if warranted by
envirorunental or economic considerations, or site-specific limitations, such
as insufficient space to achieve a coal-handling ability. The construction of
oil-fired peaking units, however, may be permitted.

The Energy Tax Act (1978) provides financial incentives for coal conver-
sion through a ten percent tax credit and accelerated depreciation. Not only
are such tax credits unavailable for natural gas and oil-fired units, but they
must be depreciated using the straight line method.

---------------------------------
1 Boilers with a fuel heat input rate equal to or greater than 100 million
Btu's per hour are considered large.

11-28

There are a number of technical and regulatory impediments to coal conver-
sion. First, air quality regulations require desulfurization equipment to be
installed if other than low sulfur coal is to be used.1 The expense of
desulfurization equipment may, in certain cases, be eliminated only by using
more expensive low sulfur coal (see Chapter III). In non-attainment areas
(where air quality standards are not met), pollution offsets may be required;
that is, arrangements need to be made to reduce the emissions of the pollutant
in question within the non-attainment area through reductions in emissions
from other sources (see Chapter III).

Second, operation of a coal-fired unit requires more space than operation
of an oil-fired unit of comparable capacity. Many stations lack the large
area which is needed for coal storage. Also, waste material resulting from
the burning of coal (e.g., fly ash), must be disposed (see Chapter VIII).

Third, when coal plants were originally converted to oil, many were
replaced with boilers capable of burning only oil. Unless extensive alter-
nations are undertaken, these units can only burn coal in the form of a
coal/oil mixture -- a technology which is still in experimental stages. If
the mix is more than 50 percent coal, it is considered by the U.S.
Environmental Protection Agency (EPA) to be solid fuel, and federally mandated
pollution control equipment for coal-burning stations must be installed. This
creates a powerful disincentive to employ that fuel mix.

While the factors enumerated above serve to inhibit coal conversion,
regulatory and economic considerations have made conversion an attractive
option for several power plants owned by Maryland utilities. DP&L plans to
convert the Edge Moor 3 and 4 facilities in 1982 and 1983 (249 megawatts), and
BG&E is converting both its C.P. Crane facility (384 megawatts) and its two
Brandon Shores plants (620 megawatts each) which are now under construction.
No other utilities operating in the State currently have any coal conversion
plans.

Coal conversion (to burn high sulfur coal) has been estimated at approxi-
mately $500 per kilowatt (1981 dollars). For example, at Delmarva's Edge Moor
3 and 4, the cost of conversion is estimated to be $74.6 million ($297/kW).
DP&L plans to use expensive, low sulphur coal at the Edge Moor plants. The
Company estimates that if it installs desulphurization equipment instead of
using low sulphur coal at those plants, capital costs of coal conversion would
be $175 to $200 per kW higher (12). Coal conversion often results in a slight
reduction in generating capacity. In the case of Edge Moor 3 and 4,
generating capacity is expected to decline by 5 megawatts for both units com-
bined (2.0 percent), which is a cost that should be considered part of the
coal conversion costs.

-1 --------------------------
Western Maryland coal has a relatively high sulfur content.

11-29

0
M

D. Alternatives to Conventional Generation

Since 1973, the cost of generating electricity by conventional means has
increased substantially. It has also become evident that much of our primary
energy is supplied by unstable and unreliable sources. As a consequence of
higher costs and an increased awareness of the need for a greater degree of
energy independence, increased emphasis has been placed on the development and
use of unconventional methods of electric generation to augment conventional
sources. Both at the federal and state levels, financial incentives have been
provided to induce residential, commercial, and industrial users to employ
alternate sources of electricity.

Some of the more promising alternative generation sources are cogenera-
tion, wind, solar, municipal solid waste, and small scale hydroelectric.
Because of their current limitations, either due to technological con-
siderations or their region-specific nature, this section does not examine
such technologies as photovoltaics, ocean thermal energy conversion (OTEC),
geothermal, or tidal power.

Legislation enacted 1981 by the Maryland General Assembly (Ch. 497)
established the Maryland Energy Financing Administration (MEFA). MEFA was
created to alleviate the problems of high initial cost and insufficient con-
ventional financing of conservation and renewable resource equipment and
installation in the industrial and commercial sectors. MEFA will be a self-
supporting unit within the Department of Economic and Community Development,
and is authorized to issue rev6nue bonds to finance low-interest loans for
conservation, solar energy alcohol fuel production, geothermal, hydropower,
cogeneration, synthetic fuel from coal, municipal solid waste, wood and wind
projects (14) .

In examining alternatives to conventional generation, special emphasis is
given to their applicability in the State of Maryland and to the current
Maryland experience and plans.

Municipal Solid Wastes

As an alternative to costly conventional fuels such as oil and coal,
municipal solid wastes, which would otherwise be disposed of in landfills, are
soon to be employed at several sites in Maryland. In addition to potential
savings in fuel costs, generation using municipal solid wastes provides two
other benefits. First, valuable landfill sites will be exhausted less
quickly, thereby reducing the need for additional sites. Second, this tech-
nology provides a vehicle for the recycling of reusable wastes, such as glass
and metals. The sorting of recyclable material is generally performed in con-
junction with the sorting of usable energy-producing refuse.

The Northeast Maryland Waste Disposal Authority is currently in the final
stages of replacing a large incineration unit in Baltimore with a waste-to-
energy facility capable of burning 2,000 tons of solid waste per day.
Electricity from the 40 megawatt unit will be sold to BG&E. Consideration is
also being given to the future operation of two other units, one in Baltimore
and the second in Harford County. The Harford County unit, which is to burn
750 tons of solid waste per day, would sell steam to Aberdeen Proving Grounds
and a small amount of electricity to BG&E. The Baltimore unit will produce
steam to be used in the drying of sewage sludge (13).

11-30

The Maryland Environmental Service Resource Recovery Facility at
Baltimore produces refuse derived fuel (RDF), which has a higher Btu content
than unprocessed waste. RDF, which can be used for combustion or as a sewage
COMposting agent, was tested by BG&E at the Crane plant as a fuel supplement
for high sulfur coal and was found to perform well (14).

The Federal government provides financial incentives for the use of muni-
cipal solid wastes in energy-producing activities through the Windfall Profit
Tax Act (1980) and the Energy Security Act (1980). A ten percent tax credit
is allowed for equipment designed to burn biomass fuel or used for converting
biomass into synthetic solid fuel. Also, tax exempt Industrial Development
Bonds may be used to finance facilities to produce electricity from solid
wastes if the facility is owned and operated by a state or the Federal govern-
ment. Subsidized loans, loan guarantees, and tax-exempt grants may also be
obtained from the Federal government.

Solar

Solar energy systems are of two basic types: passive and active.
Passive solar systems refer simply to devices used to permit sunshine to enter
a structure or to exclude sunshine. Such devices include shutters, large win-
dow areas, southern exposures, window shadest etc. Active solar systems are
based on the collection, storage, and use of solar energy. Typically, water
(or air) is heated via solar collectors and circulated throughout the heating
system of the building or used to heat domestic hot water.

Because sunshine is not available at night or during periods of inclement
weather, active solar systems are generally equipped with thermal storage
capability. While it is possible to construct an active solar system with
sufficient storage to supply all the hot water or space heating requirements
of a building, the cost is generally prohibitive and a back-up system is
usually relied upon.

The primary application of active solar heating systems is for residen-
tial use. Nationally, in 1979, approximately 80 percent of solar collectors
were delivered to residential end users and 60 percent of all collectors were
used to heat swimming pools (14). Industrial and commercial application has
not been widespread.

The costs and productivity of solar units vary widely and depend upon the
geographic area, the type of solar system used, and the housing structure to
which the system is affixed. A recent study conducted by Resources for the
Future show that low-end estimates of solar costs make it competitive with
electric resistance heat (15).

Purchase and installation costs for an active solar water heating system
vary substantially. According to a recent survey, the average cost of
purchase and installation in Maryland in 1979 was approximately $3,200, and
repair and maintenance expenses for the solar facilities have been negligible.
This study also estimates the pay back time of a solar water heating system to
be approximately 6.5 years (16).

A number of different federal, state and local financial incentives make
the installation of a solar system more attractive to the homeowner. The 1980
Windfall Profit Tax Act stipulates a 40 percent tax credit for investment in

11-31

solar systems up to a maximum of $4,000 per household. The 1978 National
Energy Conservation Act allows FHA to increase its limit on low interest loans
by 20 percent. Additionally, the Energy Security Act (1980) allows for the
establishment of a Solar Bank to administer loans for solar systems through
HUD.

Maryland State solar legislation specifies that solar units cannot be
used as a basis for increasing property assessments and allows local munici-
palities to grant tax credits for solar equipment. Harford and Anne Arundel
Counties have established such property tax credits which appear to have sti-
mulated considerable solar activity.

Small Scale Hydroelectricity

With the realization that the most economical of the large scale
hydroelectric potential in the United States has already been fully exploited,
interest in small scale hydro power has been increasing. Both large and small
scale hydro (capacity less than 30 megawatts)l have been important components
of the electric power industry since its inception.

There is considerable potential for expansion of small scale hydro in the
State of Maryland. The Maryland Energy Administration estimates that the
total underdeveloped hydroelectric potential in the State is 560 million kWh
per year with an energy equivalence of 6.2 million Btu per year (14).

The construction of a small scale hydroelectric facility requires a
license from the Federal Energy Regulatory Commission (FERC). Normally, the
first step in this process is to obtain a preliminary permit which FERC routi-
nely grants to the applicant for an 18-month to two-year period. This tem-
porary permit allows the applicant the time to perform the necessary
feasibility and environmental studies and during that time maintain exclusive
rights to the site. Upon completion of the studies the permit holder may
apply for the construction and operating license to be reviewed by FERC.
Currently, five preliminary permits have been either applied for or obtained
for small scale hydro facilities in Maryland.

Certain environmental and institutional impediments inhibit wide reliance
on small scale hydro. Rights of access to the river, stream bed and stream
banks need to be secured and permits for dam construction need to be acquired.
Additionally, restrictions along certain reaches prohibit dam construction and
initial capital costs are increased as a result of the required construction
of fish ladders.

Federal initiatives aimed at using small scale hydro are contained in the
Public Utilities Regulatory Policies Act of 1978, the Windfall Profit Tax Act
of 1980, and the Energy Security Act of 1980. Incentives include tax credits,
loans and loan guarantees, and grants for the development and construction of
demonstration projects.

Wind Energy

The average wind speed in most areas of the State of Maryland ranges from
8 to 10 miles per hour, making wind an uneconomical energy source in most

---------------------------
1 U.S. Department of Energy definition from the Public Utilities Regulatory
Policies Act of 1978.

11-32

parts of the State. An average wind speed of 12 miles per hour is generally
required to make wind-powered energy an attractive alternative to conventional
energy sources (14).

The Federal government has established financial incentives to foster
increased investment in wind energy. A 40 percent tax credit is provided
through 1985 for investment in wind energy equipment by the Windfall Profit
Tax Act (1980).

Cogeneration

Cogeneration is a familiar though, to some extent, underexploited power
source. Widespread use of cogeneration has been taking place in the
industrialized European nations for many years, and it has enjoyed some
limited success in this country. Because of its efficiencies, proponents
believe that the potential exists to radically expand its usage.

The term cogeneration has been used by engineers to describe a process
whereby electricity and process heat in some form (e.g., process steam) are
simultaneously produced. It may arise from a situation where the primary pur-
pose of consuming energy is to produce electricity, and waste heat is pro-
duced. The firm may then find a productive use for that waste heat.
Alternatively, an industrial or commercial firm may use energy primarily to
obtain process steam, and in doing so it finds it can also produce electricity
relatively inexpensively. As a result of jointly producing both types of
energy (e.g., steam and electricity), total energy requirements may be reduced
by as much as 30 percent.1 Although there is potential for exploiting coge-
neration from commercial and residential heating systems, it is believed that
the bulk of the cogeneration will come from industrial applications.

It is widely believed that cogeneration, particularly coal-fired steam,
is capable of producing relatively inexpensive energy.2 The cost tends to be
competitive with both the short-run marginal costs of existing electric
systems and the long-run marginal (and average) cost of a new baseload coal
facility. Unfortunately, the contribution of cogenerators to system reliabi-
lity is an unsettled issue and clouds a complete evaluation. On the basis of
favorable cogeneration economics and the rather large industrial demand for
process steam in the service areas of Maryland utilities, an opportunity
exists to increase sharply the amount of electricity produced by cogeneration.

Maryland utilities have had some limited experience with industrial coge-
neration in their service areas. The Getty Oil Company operates a large coge-
neration project with DP&L near Wilmington, Delaware. The Delaware City 1 and
2 units simultaneously produce process steam and electric power for the refi-
nery. Any excess power is sold back to DP&L. The Celanese Corporation in

----------- ------------------------
1 Energy in America's Future, Resources for the Future, p. 160. The RFF
study reports four additional benefits: (1) capital savings in generation
equipment; (2) transmission and distribution savings; (3) reduced cooling
water requirements; and (4) reduced siting and licensing lead times.
2 Argonne National Laboratory estimates that the average total cost of
cogenerated power may be as low as 2.5@/kWh (in 1980 dollars) assuming a rela-
tively large, efficient cogeneration facility. This is well below both the
long-run and short-run marginal costs of power on most utilities (17).

11-33

Cumberland, Maryland has in the past operated a 10 megawatt facility with
Potomac Edison, but that unit has been retired since 1978. The Westvaco
Corporation in Luke, Maryland currently operates a large facility and sells a
small amount of power to Potomac Edison. On the basis of Company surveysp
there appears to be a significant potential to expand cogeneration and small
power production in the Allegheny Power System service area.

E. A List of Electric Utility Industry Definitions

The final section of this chapter provides definitions of some of the
terms commonly used by electric utility generation planners. Most of these
terms are used extensively throughout this Report, and particularly in
Chapters I and II.

� Cycling Plants are units designed to operate at relatively high effi-
ciency, but which can be adjusted to meet changing loads and can
operate well under relatively frequent on-off cycles.

� Peaking Plants are units designed to operate only for short periods of
peak demand, usually for only a brief part of the day during a few
months of the year.

� Demand is the amount of electric power required by customers at any
given instant in time, usually stated in megawatts (MW) or kilowatts
(M. One kW is the amount of power needed to light ten 100 watt light
bulbs, and a megawatt is 1,000 kilowatts.

� Peak Demand is a maximum demand experienced during some time interval,
such as a day or year. Peak demand in the tables in this chapter is the
average power used over the 60 minute period of heaviest demand during
a given year.

� Load Factor is the ratio of the average load (MW) to the peak load
during the time period being measured. An annual system load factor,
SLFa, is defined as:

SLFa SEa
SPLA x 8760

where: SLFa = annual system load factor
SEa = annual system energy output (MWh) (energy sales plus
losses)
SPLa = annual system peak load (MW), and
8760 is the number of hours in a year (8784 in a leap year)

� Capacity Factor is the ratio of the average load (MW) on a plant or
entire system to the capacity rating (maximum rated output, MW) of the
plant or system for the time period being measured.

11-34

� Reserve Margin is the difference between system maximum capacity (MW)
and system peak load, divided by the system peak load, for any given
moment in time. The most commonly used reserve margin is defined at
the time of the system peak demand:

RMp SCP - SDp
SDp

where: RMp = system reserve margin
SCp = system maximum capacity at time of peak
SDp = system peak demand

� Base Load Plants are generating units designed to be run at high effi-
ciency on a continuous basis over long periods of time.

11-35

REFERENCES - CHAPTER II

(1) Energy Information Administration. 1980 Annual Report to Congress,
Volume Three: Forecasts. U.S. Department of Energy,
DOE/EIA-0173(80)/3. March 1981.

(2) Energy Information Administration. 1980 Annual Report to Congress,
*Volume Two: Data. U.S. Department of Energy, DOE/EIA-173(80)/2.
March 1981.

(3) Maryland Power Plant Siting Program. Ten Year Forecast of Energy, Peak
Demand and Generating Capacity for Maryland Electric Utilities.
Maryland Department of Natural Resources (in conjunction with the
Maryland Department of State Planning). November 1980.

(4) Humphreys, Thomas J. (BG&E). Letter to Howard A. Mueller (PPSP).
January 8, 1982.

(5) Schmuck, Gary A. (DP&L). Letter to Howard A. Mueller (PPSP).
December 7, 1981.

(6) Robb, Paul W. (Pepco). Letter to Howard A. Mueller (PPSP).
September 11, 1981.

(7) McCarthy, Homer T. (APS). Letter to Howard A. Mueller (PPSP).
December 21, 1981.

(8) Energy Information Administration. Statistics of the Privately owned
Utilities in the United States - 1979. U.S. Department of Energy,
DOE/EIA-0044 (79). October 1979.

(9) Miller, Ralph E. Electric Generation Capacity Planning for the Delmarva
Power & Light Company: Analysis of the Proposed Vienna Unit No. 9.
Maryland Power Plant Siting Program, PPES-4, Revision 1. April
1981.

(10) Maryland Power Plant Siting Program. Long-Range Plan Report for
Maryland Electric Utilities - 1981. Maryland Department of Natural
Resources. (Forthcoming).

(11) Weeks, L. H. Direct Testimony of L. H. Weeks. On behalf of the Potomac
Edison Company, Maryland PSC Case No. 7259. November 1980.

(12) Colla, Joseph (DP&L). Personal communication. September 1981.

(13) Gagliardi, Michael (Northeast Maryland Waste Disposal Authority).
Personal communication. September 1981.

(14) Maryland Energy Administration. Energy in Maryland. Maryland
Department of Natural Resources. January 1981 and December 1981.

11-36

(15) Schurr, Sam (et. al.). Energy in America's Future: The Choices Before
US. Resources for the Future. Johns Hopkins University Press.
Baltimore. 1979.

(16) Sawyer, Stephen. Solar Water Heating in Maryland: A Study of Current
Customers. Department of Geography, University of Maryland.
(Prepared for the Maryland Energy Office). May 1981.

(17) Center for Regulatory Analysis. Technology Alternative to Conventional
Electric Supply: A Utility Perspective. Argonne National
Laboratory. April 1981.

11-37

CHAPTER III

AIR IMPACT

The majority of gaseous airborne pollutants result from man-made combus-
tion and abrasive processes, including commercial and residential heating,
generation of electricity by fossil fuels, mobile sources (e.g., cars, boats,
and other vehicles), various industrial processes, and refuse incineration.
Industrial combustion processes are major sources of sulfur dioxide and
nitrogen oxides. Automobile exhaust is rich in nitrogen oxides, hydro-
carbons, and carbon monoxide.

Some particulates emissions are due to industrial processes. However, in
many cases, the greatest mass of particulate emissions is due to blowing dust
from activities such as handlihg of materials (e.g., coal and gravel), con-
struction, and transportation (e.g., particulates dislodged along roadways by
vehicles and emissions from uncovered trucks and rail cars). Erosion of
exposed earth and sand by the wind is also a major source of blowing dust.
In some cases, natural particulate emissions such as wind-blown dust and
pollen can exceed man-made emissions by an order of magnitude (1).

A. Sources of Maior Pollutants

Figures III-1 through 111-5 present data on emissions of five major pol-
lutants by source category for 1975 through 1978 in the State of Maryland.
Table III-I is the total statewide emissions inventory. During 1975 and 1976,
Maryland power plants contributed 63 percent of the sulfur oxides ! 30 percent
of the particulates, and 28 percent of the nitrogen oxides (see Figure 111-6
for plant locations). Since power plants use relatively efficient combustion
processes, they contribute less than 1 percent of total hydrocarbon and
carbon monoxide emissions.

Emissions from power plants vary depending on the composition of the
fuel, operating conditions, and control equipment (precipitators and scrub-
bers). During combustion, sulfur in coal and oil is almost completely con-
verted to S02 and emitted through the stack. The preponderance of NOX emit-
ted is due to reactions between 02 and N2 in the air at elevated tempera-
tures. These NOX emission rates are sensitive to fuel type, burner design,
flame temperature, and the amount of excess air entering the furnace. Par-
ticulates emitted include noncombustible fuel residues (silicates, metal
salts, sodium chloride) and incompletely burned organic materials. Coal
combustion also releases large amounts of soil minerals embedded in the coal.
Relatively small amounts of fluoride, mercury, beryllium, and various radio-
active materials may also be released when coal is burned.

domestic and space heating
power plants
mobile sources
industrial processes
refuse disposal
(includes open burning
in 1975 and 1976 only)
30,000-

Un
:z
0

V)
L/I
20,000-

M
10,000-77 < <
< <

<
1975 Oz 1976 1977 1978
*vXX

Figure III-1. Statewide particulate emissions, 1975-1978 (data from Ref. 2).

M M 111 1111111 r 14 14 1 N N N N i

MM M M M'=

domestic and space heating
power plants
300,000- mobile sources
industrial processes
C: refuse disposal
2

V)
;-I
0

V)
V)
200,000-

LU
X
Uj

X
C) LU LU
__j

100,000-
V) < <

0
77- 7-7
<
<
Fz \
1975 1976 1977 1978

Figure 111-2. Statewide sulfur oxide emissions, 1975-1978 (data from Ref. 2).
XN

ED = domestic and space heating
M = power plants
300,000- = mobile sources
= industrial processes
= refuse disposal
V)
;z
0

Ln
Ln
200,000-
z
0
CO

C-)
LU

CO
< <
100,000-
< < X
0 0

1975 1976 1977 1978

Figure 111-3. Statewide hydrocarbon emissions, 1975-1 978 (data from Ref. 2).

Ell 11 11 11111 loll 11 11 1 11 11 1

N
domestic and space heating
power plants
200,000- mobile sources
industrial processes
0 refuse disposal

V)
0

LLJ
LLJ
im

X
100,000-
0 LLJ LLj
LLJ CO Ca
LI C-D < <
0

:::c
7/ 0 0
FLI
1975 1976 1977 1978

Figure 111-4. Statewide nitrogen oxide emissions, 1975-1978 (data from Ref. 2).
I\V\

1,808,000 1,446,300 E2] = domestic and space heating
power plants
mobile sources
industrial processes
refuse disposal
z
0 100,000-
i/-;

LU
I=

X
0
z
H LU
50,000-
z
0 < <

< <

<
ee
1975 1976 1977 1978

Figure 111-5. Statewide carbon monoxide emissions, 1975-1978 (data from Ref. 2).

M oil INN 1 1111 1 1 i

B. Emission Trends of Major Pollutants

Total Suspended Particulates (TSP)

National emissions of particulates showed considerable reduction from
1970 to 1978 (Fig. 111-7). A continuation of this trend is predicted by a
comprehensive simulation model developed by the U.S. Environmental Protection
Agency (EPA) -- the Strategic Environmental Assessment System (SEAS) (4).
This model incorporates recent modifications and data files developed by the
Energy Research and Development Administration (ERDA), now a part of the
Department of Energy. The model assumes the use of coal will approximately
double by 1990. Figure 111-8 shows the total predicted emissions of TSP for
the U.S. in 1985 and 1990, relative to 1975 emissions. Estimates of total
particulate emissions in Maryland (excluding mobile sources) for recent years
fluctuate with time (see Table III-1) and show no clear trend.

Sulfur Dioxide (SO,)

National emissions of S02 showed a general increase until 1970, but have
decreased slightly since then. (see Fig. 111-9). EPA projections made in
1978 predicted that increased use of coal would cause a reversal of this
downward trend, with SO2 emissions increasing about 10 percent over 1975
emissions by 1985 (see Fig. 111-8).

Total sulfur oxide emissions in Maryland for 1975 - 1978 (Table III-1)
(excluding mobile sources) have fluctuated with time, showing no clear trend.

Nitrogen Oxides (NQ,%l

U.S. emissions of NOX from power plants and motor vehicles have shown an
increasing trend, but since 1976 the emissions from motor vehicles have
stabilized because the increase in miles travelled has been offset by
decreased emissions due to automotive pollution control techniques (5) and
increased mileage per gallon.

Figure 111-8 shows the total predicted emissions for nitrogen oxides for
the U.S. for 1985 and 1990 to be about the 1975 level. In Maryland, NOX
emissions showed large variations from one year to the next due to changes in
the emission inventories for power plants.

Hydrocarbons and Carbon Monoxide

Automobiles are the major sources of both hydrocarbons and carbon
monoxide. Advanced automotive emission controls have significantly reduced
emissions from new cars. As old cars are phased out, national HC and CO
emissions will be reduced, as shown in Fig. 111-8. Additional reductions may
result if increased gasoline prices reduce a significant reduction in vehicle
miles travelled. Emissions of hydrocarbons and carbon monoxide for Maryland
in recent years are shown in Table III-1.

111-7

Power Plants (>90MW) Within or Adjacent to Maryland

(Capacity in MW)

Gas Fuel of
Plant Mama Utility Steam. Turbine Steam Unit

1. Benning; Road(a) PEPCO 597 Oil
2. Brandon Shores(b) BG&E 1,250 Coal
3. Buzzard Point(c) PEPCO 222 252 Oil
4. Calvert Cliffs BG&E 1 620 Nuclear
5. Chalk Point(d) PEPCO 1:105(e) 48 Coal/oil
6. C.P. Crane BG&E 384 14 Oil(f)
7. Dickerson (9) PEPCO 545 13 Coal
8. Gould Street BG&E 103 Oil
9. Morgantown PEPCO 1,163 248 Coal
10. Notch Cliff BG&E 128
11. Perryman BG&E 204
12. Potomac River(h) PEPCO 480 Coal
13. Riverside BG&E 321 172 Oil
14. R.P. Smith Pot.Ed. 129 Coal
15. Vienna(i) DELMARVA 241 17 Oil
16. Wagner BG&E 988 14 oil/coal
17. Westport(J) BG&E 209 118 Oil

Plants Owned by Out-of-State Utilities (A

18. Conowingo (Philadelphia)
19. Mount Storm (VEPCO)
20. Possum Point (VEPCO)

Proposed Future Power Plant Sites (0

21. Bainbridge(k)
22. Canal (Philadelphia)
23. Della Brooke Farm (So. Md. Elec. Coop.)
24. Douglas Point (PEPCO)
25. Elms (k)
26. Point of Rocks (Pot. Ed.)
27. Seneca Point (Philadelphia)
28. Summit (DELMARVA)

(a) Unit 13 (47 MW) is scheduled to be retired in 1982.
(b) Unit 1 is scheduled to begin operation in mid-1984,
Unit 2 in early 1988.
(c) Units 1-6 (222 HW) are scheduled to be retired in 1982.
(d) Scheduled to add Unit 4 (600 HW, oil) in 1982.
(a) Capacity will increase to 1,335 MW at end of 1982
following the addition of more stringent emission
controls.
(f) Commenced legal process for conversion to coal.
(g) Proposed addition of Unit 4 (300 MW, coal) in 1993.
(h) Units 1-2 (174 MW) are scheduled to be retired in 1984.
(i) Units 5-7 (74 MW) were scheduled to be retired in 1980;
also scheduled is the addition of Unit 9 (500 MW, coal
with DELMARVA retaining ownership of 325 MW) in 1987.
(J) Units 1, 13, 14 (19, 16, 16 MW) are scheduled to be retired
in 1982; while Unit 3 (58 MW) is scheduled to be retired in
1987.
(k) Power Plant Siting Program required site.

Figure 111-6. Power plants in the Maryland region.

111-8

m m m m m m M'M'M

14 10 19 2127
11

6
26

A 19

123*1
10

24 23 4
0

Figure 111-6. Continued.

CD
30-
V)
LU

20 -

LU
2, 10-
LU
CD CL
Ln

0 0-
1970 1971 1972 1973 1974 1975 1976 1977 1978

Figure 111-7. Estimates of total suspended particulate emissions for the United States
(data from Ref. 6).

NATIONAL EMISSIONS OF AIR POLLUTANTS
PROJECTED FOR
2.0 1985 AN D 1990 RELAT I VE TO 1975 EM I S S I ON S

1975 LEVEL
1.0 ---- -=

U"% 00 C>
00 00 0% C@ C,
-4
0.0
PART sox HC NOx CO

Figure 111-8. National emissions of major air pollutants projected by EPA for
198S and 1980 relative to 1975 emissions (data from Ref. 4).
T
ro a,
C2*1 011
-4 r--f

Table III-1. Statewide Total Emissions Inventory for the Five Major Source Categories for
1975-1978(a)

Total Emissions (tons/year)(b)

1975 1976 1977 1978

Particulates
Including mobile sources 85,000(c) 73 Soo __(d)
Excluding mobile sources 66,400 5S:400 1.6,100 67,200

Sulfur Oxides

Including mobile sources 409,800 318,700
Excluding mobile sources 393,300 274,100 390,200 308,300

Hydrocarbons
Including mobile sources 311,600 (e) 263,300
Excluding mobile sources 76,200 56,100 S2,700 74,300

Nitrogen Oxides

Including mobile sources 359,000 288,200
Excluding mobile sources 169,700 138,900 273,700 177,700

Carbon Monoxide

Including mobile sources 1,910,200 1,577,000
Excluding mobile sources 107,400 130,700 99,300 100,400

(a) Data from Ref. 2. Emission data are obtained from estimates of indicators such as fuel consump-
tionI production rates, control efficiencies, and vehicle miles traveled. Average emission
factors, which relate these indicators to emission rates for specific source categories, are
used to derive total emissions (3).
(b) Does not include miscellaneous source categories.
(c) These are "man-made" particulate emissions. Particulate "emissions" due to natural causes
(e.g., wind-blown dust and pollen) vary widely with place and time and can exceed man-made
emissions by an order of magnitude.
(d) Data for mobile sources not available.
(e) In addition, about 150,000 tons per year is released from asphalt roads in the State. This
quantity can be redu@ed to 20,000 to 25,000 tons per year by current use of a different type
of road tar. Emission from an asphalt-surfaced -road decreases significantly over a period
of 1 to 2 years.

I I I i I i I i I I i I

L
30
C:

20
X
0

U-
1 10-
ZD
V)

0
1970 1971 1972 1973 1974 1975 1976 1977 1978

Figure 111-9. Estimates of sulfur oxide emissions for the United States (data from
Ref. 6).

C. Standards

Ambient air quality is measured and defined as ground-level concentra-
tions of pollutants. Federal and State agencies are,attempting to attain and
maintain good air quality by: 1) regulating pollutant groundlevel concentra-
tions through ambient air quality standards, 2) controlling emissions from
new and existing sources through source-emission standards, and 3) restric-
ting sulfur content of fuels. Emissions from new sources are controlled
through an extensive new source review process.

Ambient Air Quality Standards

Ambient air quality standards have been established by the EPA for
ground-level concentrations of certain pollutants and have been adopted by
State of Maryland. The National Ambient Air Quality Standards (NAAQS) are
listed in Table 111-2. The national primary standards are designed to pro-
tect human health, whereas the secondary standards are concerned with the
protection of human welfare (i.e., the material and aesthetic effects of
pollution).

Emission Limitations for Existing Fuel-Burning Installations

Sulfur content of fossil fuels is controlled to reduce the ground-level
concentration (GLC) of S02. Limitations are less strict in Maryland rural
air quality areas (Areas I, II, V, and VI -- see Fig. III-10) than in urban
areas (III and IV). Ni@trogen oxide emissions are limited for all installa-
tions in areas III and IV and for installations that commenced operations
after 12 May 1972, in other areas of the State. Visible emissions other than
steam are restricted throughout Maryland. The total mass of particulate emis-
sions is also regulated. Dust collectors are required for installations
burning residual oil in areas III and IV. (See Table 111-3).

New Source Review

New propoged utility steam-generating units with a heat input greater
than 250 x 10 Btu/hr, or major modifications at installations of this size
that increase controlled emissions of any pollutant by more than 100 tons per
year, are subject to New Source Review. This review must demonstrate that
all source emissions from these installations meet applicable New Source
Performance Standards (NSPS). These standards were originally established by
EPA in December 1971 under authority of the Clean Air Act of 1970 for certain
new sources beginning operation after 17 August 1971 (7, 8). To satisfy the
requirements of the Clean Air Act Amendments of 1977, EPA has adopted revised
standards of performance for electric utility steam generating units for
which construction commenced after 18 September 1978 (9). Table 111-4 gives
the two sets of NSPS for utility boilers.

In addition, the operator must demonstrate that the new unit it will not
produce or exacerbate any violations of NAAQS, and that the increased emis-
sions of S02 and TSP due to the unit will not produce increased ground-level
concentrations in excess of allowable Prevention of Significant Deterioration

111-14

Table 111-2. National Ambient Air Quality Standards and Prevention of Significant Deterioration
Increments (a)

National PSD increments
Pkimary Secondary (pg/m3) by class
Pollutant lig/m3 ppm lig/m3 ppm

Sulfur oxides
Annual arithm 80 0.03 2 20 40
24 h 365 0.14 S 91 182
25 512 700
3-hr max= 1,300 0.5
I-hr maximum(c)
Suspended particulate matter 0(d) 5 19 37
Annual geamet* 75 6
24-hr maximLin1g)", 260 150 10 37 7S
Carbon monoxid Tb) mg/m 3 10 9 10 9
8-hr maximm(b): mg/.3 40 35
1-hr maximum 40 35(e)
Hydrocarbons (nonmethang)
3-hr (6-9M maximum( 160 0.24 160 0.24

Nitrogen dioxide
Annual arithmetic mean(f) 100 0.05 100 0.05

Ozone
1-hr maximum(g) 235 0.12 235 0.12

Lead
Quarterly average 1.5

(a) NAAQS figures from Ref. 10 and 11, PSD increments from Ref. 12.
(b) Not to be exceeded more than once per year.
(c) Not to be exceeded more than once per month.
(d) A guide to be used in assessing implementation plans to achieve the 24-hour standard.
(e) The EPA is proposing to lower the primary I-hour standard to 25 ppm.
(f) A short-term (e.g., 1-hour average) standard for N02 is under consideration by the EPA.
(g) The ozone standard was changed from 160 jjg/m3 and 0.08 ppm in January 1979.

.4
In
jj
T gill.;
P -4 ..

MR
BE ........ ....
........ .
I V
AREA I (Western Maryland);
Allegany, Garrett and Washington Counties
AREA II (Central Maryland): Frederick
County
AREA I I I(Baltimore Metropolitan Area):
Arme Arundel, Baltimore, Carroll,, Harford,
and
Howard counties and Baltimore City
AREA IV: (Washington Metropolitan Area):
Montgomery and Prince George's counties
AREA V (Southern Maryland): Calvert,
Charles, and St. Mary's counties
AREA VI (Eastern Shore): Caroline, Cecil,
Dorchester, Kent, Queen Annels, Somerset,
Talbot, Wicomico, and Worchester counties.

Figure III-10. The six air quality control areas in Maryland. From Ref. 13.

111-16

M M M M M M M M M M M M M M W M

Table 111-3. Restrictions in Fuel Sulfur Content and Emissions of Criteria Pollutants from Fuel
Burning Equipment for Rural and Urban Areas of Maryland.

Rural Limitation Urban Limitation
Parameter
(Regions I, II, V, VI) (Regions III, IV)

Visible emissions 20% opacity except 40% opacity None allowed except 40% opacity
other than water not more than 6 min/hour during not more than 6 min/hour during
startup and soot blowing startup and soot blowing

TSP emissions: (a) (b
Residual oil 0.1 lb/106 Btu 041 gr/dscf, )dust collectors
required
Solid fuel Same as oil 0.03 gr/scfd, Wdust collectors
required
Sulfur limitation: (d) 6 (e) 6 (e)
Solid fuel 3.5 lb/10 Btu 1.0% (1.7 lb/10 Btu

Residual fuel oil 2.0% 1.0%

Distillate fuel oil 0.3% 0.3%

(a) For new installations with more than 250 x 106 Btu/hour heat input. Higher emissions arg allowed for
installations existing before 17 Jan 1972 and for smaller installations (up to 0.6 lb/10 Btu).
(b) 0.02 gr/dscf for equipment constructed prior to 1 July 1975; 0.03 gr/ascf for equipment with a heat
input less than So x 106 Btu/hour.
(c) O.OS gr/dscf for installaions with a heat input less than 250 x 106 Btu/hour.
(d) Or equivalent if flue gas desulfurization is used.
(e) 6
Not regulated if total fuel-burning equipment on premises has a heat input less than 100 x 10 Btu/hour.

Table 111-4. Original (1971) and Revised (1978) New Source Standards of Performance for Steam
Generators Fired by Fossil Fuels

Original Standard Revised Standard
Pollutant Applicable to boilers constructed Applicable to boilers constructed
17 Aug 1971 to 18 Sept 1978 after 18 Sept 1978

Particulate matter 0.10 lb per million Btu heat input, maximum 0.030 lb per million Btu heat input,
2-hr average maximum 2-hr average

20 percent opacity; except that 27 percent Same
opacity is permissible for not more than
6 min in any hour

99% of uncontrolled emissions when
solid fuel is combusted or 70% when
combusting liquid fuel
------ ------- ---- -- --- ------- --- ---- ------ -------
Sulfur dioxide -------- 0.80-lb-per-million-Btu-heat-input,- maximum ------ Sameu -- --------------------------
2-hr average when liquid fossil fuel is burned
1.2 lb per million Btu heat input, maximum Same(b)
2-hr average when solid fuel is burned

90 percent reduction of uncontrolled
emiss ion (- )

------------------------------------------------------------------------------------------------------------
00 Nitrogen oxides 0.2 lb per million Btu heat input, maximum Same(b)
2-hr average, expressed as N02, when gaseous
fossil fuel is burned
0.30 lb per million Btu heat input, maximum Same(b)
2-hr average, expressed as N02, when liquid
fossil fuel is burned

0.70 lb per million Btu heat input, maximum 0.60 lb per million Btu heat input,
2-hr average, expressed as N02, when solid maximum 2-hr average, expressed as
fossil fuel (except lignite) is burned N02, from combustion of bituminous
coal.

0.50 lb per million Btu heat input,
maximum 2-hr average, expressed as
N02, from combustion of subbituminous
coal, shale oil, or any solid liquid
or gaseous fuel derived from coa

(a) Revised from 1978 CEIR (14)
(b) 30-day rolling average.
(c) 30-day rolling average. For sources emitting less than 0.60 lb per million Btu, the percent
reduction required is 70%. No reduction is required when the facility uses liquid or gaseous
fuel and emits less than 0.2 lb per million Btu.

Table 111-5. Emissions of TSP and Trace Contaminants Subject to PSD
Analysis for a Hypothetical Coal-Fired Power Plant Consuming
100 ton/hr of Coal

Uncontrolled Emissions Controlled Emissions
Uncontrolled Assumed pSD(b)
Contipnt_ in Endssion Control
Coal(a) Rate Efficiency de minimus
(plxn) (lb/hr) M (g/s) (ton/y-r) (ton/yr)
TSP 224 lb/ton(-C) 223,400 99.7 8.0 350 10
Pb 35 t 44 7.0 99.0 0.0085 0.3 0.6
Hg 0.20 t 0.20 0.04 5.0 0.0050 0.17 0.10
Be 1.6 t 0.8 0.31 90.0 0.004 0.13 0.004
F 61 � 21 12.0 90.0 0.15 5.4 3.0
As 14 � 18 2.8 90.0 0.035 1.3 N/A(d)

(a@ Measured standard deviations for 101 coals. Data from Ref. 15.
Cb) New sources and modifications which are 'tojor" under the PSD and non-
attainment regulations of S August 1980 require an air quality analysis
for all pollutants emitted in amounts greater than PSD de minimus values.
(c) Flyash production; assumes 14% ash content.
(d) Not established.

Iii-19

(PSD) increments (see Table 111-2). An ambient air quality analysis must be
carried out for all other pollutants emitted at rates greater than specified
de minumus values. Several of these will be relevant for coal-fired power
plants (see Table 111-5). Utilities desiring to build plants in or near
nonattainment areas must also demonstrate that their emission control equip-
ment meets Lowest Achievable Emission Rate (LAER) requirements. If units are
added in or near areas where ambient air quality standards are violated,
other sour ces in the area must, in most cases, make offsetting emission
reductions.

D. Health and Welfare Effects of Pollutants

The Clean Air Act of 1970 directs the Administrator of the EPA to compile
a list of hazardous air pollutants and issue criteria documents describing
the environmental effects of eacb. Ambient air quality standards are to be
set for these material, using the best scientific evidence cited in the
criteria documents. A safety factor is to be incorporated to protect the
most sensitive elements of the population and to account for uncertainties in
the data. The criteria documents and the resulting standards are to be
reviewed and revised every 5 years.

To date, criteria documents have been issued and ambient air quality
standards established for six pollutants: sulfur oxides, nitrogen oxides,
total suspended particulates, photochemical oxidants (ozone), carbon monox-
ide, and lead. A hydrocarbon standard was issued as a guide for attaining
ozone standards. The health effects on which the primary standards are
based, and some of the welfare effects, are summarized below.

Total-Suspended Particulates and Lead

Total suspended particulate material has been associated with a variety
of adverse health effects in humans. These include decreased respiratory
function,' asthma, silicosis, asbestosis, and perhaps lung cancer. They are
due both to the particulate nature of the suspended material and to its chem-
ical composition. In addition, suspended particulate material impairs
visibility and causes soiling.

The TSP ambient air quality standards established by the EPA in 1971
placed limits on the total mass of suspended material in the environment.
However, more recent information suggests that the health effects are caused
primarily by the smaller particles in the aerosol (16). The TSP standard is
thus currently being revised to limit the mass of particles in the smaller
size fractions as well as the total mass.

Emissions of specific components such as mercury, beryllium, and asbestos
are regulated under national emission standards for hazardous pollutants. An
ambient air quality standard for lead was promulgated in 1978 and standards
may be forthcoming for other components of TSP as well.

111-20

Fluoride

Significant ambient concentrations of fluoride can alter bone metabolism
in humans and animals. Exposures to moderate concentrations may cause bone
deformation and kidney damage in humans. Prolonged exposure to low levels
caused mottling of tooth enamel. Dairy cows are especially sensitive to the
effects of fluoride because of their rapid rate of calcium metabolism. Even
trace amounts in forage caused disabling bone and hoof disorders in dairy
herds (17). Certain plants, including fruit trees and ornamentals, are
injured by exposure to levels of atmospheric fluoride which are readily
tolerated by animals.

The State of Maryland (18) has established ambient air quality standards
for fluoride that limit the concentration in the ambient air to that which
results in fluoride concentrations of 20 ppm in unwashed vegetable crops, 35
ppm in field crops, and 50 ppm in fruit tree leaves. (For applicable concen-
trations in other crops see COMAR, 1978, 10.18.04-01). In areas where vege-
tative sampling is not feasible, ambient air sampling may be required. The
applicable standard is then 1.2,ug/m3 of Fluor (as gaseous fluoride) (24-hour
average) and 0.4.ug/m3 of Fluor (72-hour average). If lime paper 5 are used
to monitor fluoride, the allowable catch is 2 jug Fluor, per 100 cm of paper.

Carbon Monoxide

Carbon monoxide interfers with the transport of oxygen from the lungs to
body tissues. Symptons of carbon monoxide poisoning include headaches,
impaired vision, and loss of coordination. These effects are accentuated at
high altitudes (5,000 ft). Persons having heart or respiratory diseases are
at increased risk. The severity of symptoms is related to both the concen-
tration of carbon monoxide in the ambient air and the duration of the ex-
posure.
In a healthy person engaged in normal activities, exposures to 20.Ug/m 3
of carbon monoxide (twice the primary standard) for 8 hours produce ns ad-
verse effects. Eight-hour exposures to levels between 34 and 40JUg/m (or
3.4 to 4 times the primiry standard) may result in headaches, while levels
between 40 and 100jug/m (or 4 to 10 times the primary standard) may impair
visual perception, manual dexterity, or coordination (19). During strenuous
activity, carbon monoxide is taken up more rapidly. The EPA recently (18
August 1980) proposed revising the 1-hour standard downward (to 25 ppm) to
more adequately protect persons engaged in strenuous activity (51).

Sulfur Dioxide

Sulfur dioxide is a mild respiratory irritant which may produce bronchial
asthma in susceptible persons (20). Continued and repeated exposure has been
linked to the development of emphysema, bronchitis, and other chronic lung
problems. However, some of the respiratory effects previously thought to
result from S02 exposure appear to be due, instead, to sulfuric acid mist
(see below). There is also some evidence of synergism between the effects of
S02 and TSP, but this mechanism is not yet understood. High levels of sulfur
dioxide produce leaf damage in susceptible plants; destruction of vegetative
cover has occurred near some major S02 sources.

111-21

Mandated review of the S02 ambient standards is in progress. A draft
criteria document has been circulated summarizing the results of recent
studies on S02 toxicity. New ambient standards have not yet been proposed,
however.

Under conditions of high humidity, or in the presence of ozone or
suspended particulate material contaning vanadium or other transition metals
sulfur dioxide is rapidly oxidized to form sulfuric acid mists and sulfate
aerosols (see below). These are strong respiratory irritants. Monkeys
exposed to moderate concentrations develop distinctive changes in lung tissue
similar to those seen in obstructive lung diseases in humans (21). Sulfuric
acid mists also cause damage to limestone and plants.

Sulfates

Sulfates are formed from sulfur oxides and sulfuric acid mist in the
presence of other reactants such as fine particulates, nitrogen dioxide,
hydrocarbons, ammonia, catalytic metals, and photochemical reaction products.
Sulfate aerosols are transported long distances and may produce significant
deteroration of visibility in rural areas. The presence of sulfuric acid and
sulfates in the atmosphere is one major cause of the increased acidity of
rain and snow found particularly in the northeastern part of the United
States. Sulfates account for about 60 percent of the total non-carbonate
acidity in precipitation while nitrates account for about 30 percent; the
remaining 10 percent is caused by chlorides, ammonia, and other acids (22).

The use of tall stacks decreases local S02-sulfate pollution levels
because of dispersion, but the pollutants will be carried far from their
sources. This long-range transport, along with the complex precursor
relationships between sulfur dioxide and sulfates, explains why a general
decrease in S02 levels is not necessarily reflected in a similar trend for
sulfates, as illustrated in Fig. III-11.

Although there is mounting evidence of health hazards associated with
inhalation of sulfates, no standards for ground-level concentrations have
been established. Regulation of atmospheric sulfates has been under con-
sideration by EPA, but advances in monitoring and analytical techniques, as
well as improved assessment of health hazards, are required before standards
can be set (23).

Photochemical Air Pollution: Hydrocarbons, Ozone, Nitrogen Oxides, PAN

Nitrogen oxides and hydrocarbons react in sunlight to form a variety of
oxidation products including-ozone, peroxyacetyl nitrate (PAN), aldehydes,
and particulate material (haze). The resulting mixture causes eye and lung
irritation and increased susceptibility to infections. Exposures to oxidant
levels commonly found in urban areas during stagnation conditions may lead to
decrease'd lung function and asthematic attacks in susceptible individuals.

111-22

MMM M MMM M,M,M

LU E40

LU
__j
so 2

30 -

V)
LU
LJ_
0
20 -

Ln
< LLJ
LL, L)
0 SULFATE

1976 1977 1978 1979

Figure III-11. Composite quarterly means of sulfate and S02 ground-level concentrations for
all stations using the flame photometric method. Graph is for readers' infor-
mation only -- many stations have less than 75% of the prescribed number of
readings. (Graph based on data from Ref. 2).

The ozone component of smog produces rapid degradation of rubber and
nylon and increases the rate of S02 oxidation in power plant plumes to form
sulfuric acid mist. Both PAN and ozone damage commercial crops at concen-
trations below the current ambient air standard.

Many, if not most, areas of the eastern United States have ozone (oxi-
dant) concentrations greater than the original standard of 80 ppb (oxidant).
The sources of these exceedances have not been determined, but are believed
to be natural or regional in many cases. The standard has recently been
revised to allow 1-hour average concentrations up to 120 ppb (ozone). This
change has greatly reduced the number and extent of rural nonattainment
areas.

The ususal concentrations of hydrocarbons in ambient air have no adverse
effects on health. However, prolonged exposure to levels of nitrogen oxides
somewhat above the existing standard may lead to chronic obstructive lung
disease.

Other Pollutants

A number of other compounds found in trace amounts in ambient air are
known to have various adverse health effects. Emissions of some of these
(e.g., beryllium, mercury, and asbestos) have been limited under the National
Emissions Standards for Hazardous Pollutants (24). However, until more is
known about the complex precursor relationship between emitted pollutants and
the pollutants which ultimately cause health hazards, the EPA feels a sound IF
and meaningful general strategy is to control ground-level concentrations
only for the six major "criteria" pollutants: particulate matter, sulfur
dioxide, nitrogen oxides, carbon monoxide, hydrocarbons, and lead.

E. Status and Trends of Maryland Air Quality

All areas of Maryland are currently in compliance with the National
Ambient Air Quality Standards, with the folowing exceptions: the Baltimore
Metropolitan area is nonattainment for total suspended particulates, as shown
in Fig. 111-12. A previous TSP nonattainment area, Election District 8 in
Luke, Maryland, is now unclassified. Portions of the cities of Hagerstown,
Cumberland, and Baltimore and areas of high traffic density near Washington,
D.C., are designated nonattainment for carbon monoxide. A proposal to change
these GO areas to unclassifiable is presently under consideration. The
Baltimore Metropolitan area (Air Quality Control Region III), shown in Fig.
III-10, is nonattainment for ozone, as is Washington County and the Maryland
portion of the metropolitan Washington, D.C., area. Previous ozone nonattain- hL
ment areas in Garrett and Alleghany counties are now unclassified or have
ambient levels below national standard (25, 26).

Trends in ambient air quality can be determined from analyses of ground-
level concentrations measured at air quality monitoring stations. The
national air quality trends are based on data from EPA's National Aerometric
Data Bank (NADB). These data are gathered primarily through the monitoring
activities of state and local air pollution control agencies (27).

111-24

M M'M M M M M 0 M M'" M M
L T I M 0 R
C 0 U N T Y

TOWSON
0 5km

IlAk.@IMORE

.....................

ELLICOTT
CITY
H OWAR D

COUNTY V

A N N E
A Primary
Figure 111-12. Primary and secondary TSP nonattainment zones Nonattainm
in the Baltimore area (data from Ref. 24). secon(lary
Nonattainm

Maryland data are reported by the Air Quality Program of the Department
of Health and Mental Hygiene, which has stations throughout the State, mainly
in the urban areas (2). Because stations are not distributed uniformly, the
ground-level concentrations reported may not be representative of the overall
status of air quality; but the trends, or changes, at these stations do indi-
cate the statewide trends. Also, since many stations have been moved and the
measurement methods have changed over the years, it is sometimes difficult to
select stations with sufficient continuous data records to establish long-
term trends. Therefore, in some cases, annual data may not be directly com-
parable.

Total Suspended Particulates

There has been a downward trend in TSP ground-level concentrations in
Maryland over the past 10 years. Among 21 stations from which data were
continuously available for the period, the number of sites showing a viola-
tion of the primary annual standard (75 jug/m3) decreased from 3 in 1971 to 1
in 19791 The composite average for these stations was 78 iug/m in 1971 and
49 Aig1m in 1979 (see Fig. 111-13). The me In annual average vaAue for all
stations in Maryland decreased from 75 jag/m in 1971 to 50 jag/m in 1979 (see
Fig. 111-14).

A State Implementation Plan (SIP) has been prepared to bring the Baltimore
Metropolitan nonattainment region into attainment with the primary NAAQS
during 1982 and with the secondary standard by 1986. The SIP addresses the
major causes of high values, which seem to be fugitive emissions from roads
and industrial installations. The impact of the existing oil-fired power
plants in this region appears minimal.

However, there are several power plants in attainment areas that are not
in compliance with emission limitations. For example, Chalk Point Units I
and 2 will be subject to a delayed compliance order (under a recently sub-
mitted SIP revision) calling for final compliance by January 1, 1983 (28).'
Recent testimony indicates that the fugitive emission inventories used in
preparing the SIP may have been greatly underestimated. SIP revisions are in
preparation calling for additional emission reductions based on a corrected
inventory. The need for stricter emission controls and a longer compliance
period than originally proposed has become an issue in the pending coal con-
versions at Crane and Brandon Shores (29, 30).

Sulfur Dioxide (SOn)

The entire State of Maryland is in compliance with the NAAQS for sulfur
dioxide (25). Measurements of ambient sulfur dioxide levels made by the
Maryland Department of Health and Mental Hygiene show a consistent downward
trend in average S02 ground-level concentrations since 1974 (see Fig.
111-15).

---------------
lWagner Unit 3 also was not in compliance as of January 1, 1982, but manage-
ment has been granted 90 days to achieve compliance (28). Note that, Wagner
and Chalk Point do not produce ambient TSP concentrations in excess of NAAQS
at nearby air quality monitors.

111-26

Figure 111-16 shows the seasonal trend in S02 ground-level concentration
(measured by the flame photometric method). Higher levels in the heating
months (first and fourth quarters) indicate that much of the S02 comes from
local sources, primarily space heating using sulfur-containing fossil fuel.
The S02 emissions from power plants may be expected to run counter to this
seasonal variation since electrical demand and power plant generation rates
in Maryland are traditionally highest in the summer months.

Nitrogen Oxides (NO.,J-

The entire State of maryland is in compliance with NAAQS for nitrogen
oxides (25). Figure 111-17 shows that the annual average ground-level con-
centration of N02 has remained relatively constant in Maryland from 1974 to
1979 (2).

Photochemical Oxidants and Hydrocarbons

All of Maryland is in attainment for ozone, except for sections of
Baltimore City, Washington County, and the Washington, DC area. Previous
nonattainment areas in Garrett and Allegany counties are now unclassified or
have ambient levels lower than national standards (25, 26).

F. Pollution Control

Ambient air quality can be improved by reducing emissions of pollutants
from power plants (via emission control, conservation, cleaner fuel, or
alternative power sources such as solar or nuclear) or by enhancing disper-
sion. The need for emission control can be assessed by comparing uncontrolled
emission factors to allowable emissions under new Source Performance Stan-
dards. Table 111-6 relates NSPS to the emissions resulting from burning
coal, oil, or gas without any emission control. The N02 standard set by NSPS
can be met by controlling the combustion process in the power plant boiler.

Table 111-6 shows that natural gas is the only fuel with particulate
emissions low enough to meet NSPS without additional particulate emission
controls. Plants burning coal with an ash content of 15 percent would need
precipitators with an efficiency of about 99.7 percent. Although modern
precipitator technology now permits efficiencies exceeding 99 percent (31),
actual performance is often critically dependent on fly ash composition,
sulfur content, and equipment maintenance, and must be carefully monitored.

Particulate emissions also result from coal delivery, storage, conveying,
and sizing for optimum combustion, and from transfer of fly ash and bottom
ash from control devices and boilers. Such emissions are termed "fugitive"
(i.e., they do not emanate from a stack or vent).

Power plants located in the Baltimore and Washington, D.C., metropolitan
areas are required to apply reasonable available control measures to abate
fugitive emissions. Such measures might include unloading coal cars in an
enclosure equipped with water sprays, enclosing conveyors, and equipping

111-27

100.

80-

E
Uj M
--I

Z
= v) 60- 20-
0 F- V)

0
Uj V)
CD Z
< 3
Uj
1--- 40 Exceeding 60/ig/m
> < U_ 10 -
<

Z 3
z Exceeding 75@Lg/m
<
20 0 L
71 72 73 74 75 76 77 78 79
YEAR

0 __j
1971 1972 1973 1974 1975 1976 1971' 1978 1979

YEAR

Figure 111-13. Composite means of annual average TSP ground-level concentration at 21 stations
throughout Maryland which have a continuous record since 1971. Violations of
primary and secondary TSP NAAQS for the same 21 stations. Based on Ref. 2.

or OF r PF PF PF PF 14 14 N 11 1 14 N

LLJ E
LLJ 200-
_j

V)
0
U_ 150-
C
Uj V)
C.D Z!
<
Q::
W 1--- 100-
> <
<

tIj
LD <
CIO
0
<

AVERAGE

YEAR 1971 1972 1973 1974 1975 1976 1977 1978 1979

Figure 111-14. Composite mean of the annual average TSP ground-level concentration for all
Maryland stations with adequate data (at least 75% of the prescribed number
of readings). The bars indicate the range of values. Based on Ref. 2.

cyi-
E
C71 77
-L 60-
C"i
0 N

L.L.
Un 50-
;z
0 AVERAGE

40 -

3o -
LU

CD 20

Ui
C-1)
< 10 -

LU
>
<
__j
<
,71
0 YEAR 1973 1974 1975 1976 1977 1978 1979

Figure 111-15. Composite mean of annual S02 ground-level concentrations average for those
Maryland stations with data for the entire year. For informational purposes
only; many stations have less than 75% of the prescribed number of readings.
t
T

Measurements are by the flame photometric method. Range of values is
indicated by the bars. Based on Ref. 2.

PF OF OF PF PF PF OF OF 14

M M M MIMI MMI M M a

50-

40
Ln

U_
0
Uj V) 30-
CD Of
:z0

LU
H f>< 20-
1 <

< LU
10-

0
< U
0
1 2 3 4 '2 '3 41 2 3 4 1 2 3 -4 1 2 2 3 41 1 2 3 4
1973 1974 1975 1976 1977 1978 1979

Figure 111-16. Seasonal trend in S02 ground-level concentrations, average for all Maryland
stations (flame photometric method). For informational purposes only;
many stations have less than 75% of the prescribed number of readings.
Based on Ref. 2.

cyi_
E
VU

80-
AVERAGE
U_

70 -

60 -

LU
U
2: 50
0
U
__j
LU 40 -

LU
__j
30 -

0
M
20 -

_Wh_

<
YEAR 1974 1975 1976 1977 1978 1979

Figure 111-17. Composite mean of annual average N02 ground-level concentrations (measured
by 24-hr gas bubbler) for all Maryland stations with adequate data (at
T T

least 7S% of the readings). Range of values is indicated by bar. Based
on Ref. 2.

ME 101 1101 111111 IMI I 1111 14 14 1

M M M M M M M M 0 W'M MM M M M M a

Table 111-6. Comparison of New Source Performance Standards (NSPS) and Emission Factors for
Combustion in Utility Boilers

POLLUTMT PARTICULAT17 MATTT-.R SULFUR DIOXIDE NITROGEN DIOXIDE
FOSSIL FUEL SrAqDARD EMISSI()N(a) sTANwD EMISSION(a) ST@ EMISS,6ga)
AND FURNACE TYPE (lb/10- Btu) FACTOR (lb/106 Bt!AFACMR (11b, u
0 Z10 Bt ) FACTQR
Old New Old New( New

Pulverized Coal 0.10 0.03 1.2 1.2 0.70 0.60(c)
(0.50)
General 0.67A 0.75
Wet bottom 0.54A 1.58S 1.25
Dry bottom 0.71A 0.75
Cyclone 0.08A 1 2.29
Fuel Oil 0.10 0.03 0.80 0.80 1 0*30 0*30
Ta-jigentially fired 0.055 1.08s 0.34
other 1 0.72
Natural Cias 0.10 0.03 1 No 0,10 0*20 0*20
H Tangentially fired 0.014 std. 0.0005S 0.27
H Other 0.64

Note: The old standards did not apply to lignite.
(a) A is ash content of coal in percent by weight. S is sulfur content in percent by weight.
Emission factors have been converted from weight and volume units to Btu's using the following
conversion, which approximates conditions prevailing in Wryland:
Coal: 12,000 Btu/lb = 24 x 10 6 Bju/ton
Oil 145,000 Btu/jal = 145 x IV Btu/thousan&kals
Gas 1,100 Btu/ft = 1,100 x 106 Btu/million ft3

Emission factors are only approximate guidelines and may be conservative (high). The emission
factor of 1.58S for sulfur dioxide nssumes that 95 percent (by weight) of the sulfur in the coal
is released as sulfur dioxide (3).
(b) The new NSPS also require a 90 percent reduction (presumably by scrubbing) of the uncontrolled
SO emissions from solid, liquid, and gaseous fuels. An 85% reduction is required when solvent
refined coal is used. For sources emitting less than 0.6 lb S02 per million Btu, the percent
reduction required is 70%. No reduction is required when the facility uses liquid or gaseous
fuel and emits less than 0.2 lb S02 per million Btu.
(c) The new NOx coal standard of 0.60 applies to bituminous coal,and O.SO applies to subbituminous
coal, shale oil, or any solid, liquid, or gaseous fuel derived from coal.

transfer points with water sprays; equipping screens and crushers with water
sprays, at the inlet and outlet, periodically applying a crusting agent to
inactive storage piles; handling fly ash in enclosed systems; and storing fly
ash in fabric-filtered bins prior to disposal.

Under the provisions of Prevention of Significant Deterioration (PSD)
regulations, new power plants are required to apply Best Available Control
Technology for stack and fugitive emissions. For these plants, the
previously discussed control measures would be the minimum required, no
matter where the plant is located in Maryland.

The old (1971) NSPS could be met through use of clean (or cleaned) fuels.
For example, control of..S02 emissions was not needed for gas. Oil could meet
the old and new emission standards, provided that the sulfur content was
about 0.8 percent or lower. Attainment of this sulfur level presents no
technical problem, although there may be a related economic penalty (see
Table 111-7). S02 emission control for coal-burning power plants could
potentially be achieved by:

� Use of coal of inherently low sulfur content (less than 0.8 percent)

� Conversion of coal to cleaner fuels

� Use of advanced combustion systems (fluidized-bed combustion).

Extensive research programs funded by private and public interests are
underway in these areas. The requirement of the new (1978) NSPS that almost
all power plant effluents must be scrubbed to reduce S02 may remove much of
the economic incentive for development of these technologies, although some
credit will be given for precleaning fuel. The advanced technologies will
probably be commerically available for power plant operations in the late
80's (32). Many of these technologies are not complicated for small-scale
uses but are difficult to transfer to the large scale of a power plant. See
the 1978 CEIR (14) for a review of these programs.

G. Mathematical Modeling

Mathematical modeling is becoming increasingly important for predicting
air quality impacts caused by present and future sources. Section 320 of the
1977 Amendments to the Clean Air Act (33) recognizes modeling as a necessary
tool, especially for predicting the extent of increment consumption by pro-
posed sources and modifications subject to PSD.

The most widely favored dispersion models are based on the concept of the
Gaussian plume. These models assume that the pollutants are dispersed by the
wind such that the average concentrations across the plume (i.e., perpendicu-
lar to the mean wind direction) are distributed as the bell-shaped normal (or
Gaussian) curve. Both vertical and horizontal dispersion are assumed to have
this form although their widths generally are different. The plume center-
line will rise to a height determined by the buoyancy of the effluent gasses.

The Gaussian formulation is attractive because it is simple -- the basic
equations can be evaluated with a hand calculator. It is also applicable to
a wide variety of physical conditions. The ground-level concentration (GLC)

111-34

Table 111-7. Fuel Costs for Maryland Utilities (1980 Prices, in Dollars).

Utility Steam Coal

Percentage Costs Differential
Sulfur Cost per Cost per Per ton Per
ton 106 Btu 106 Btu

0.5 - 1.0 44.31 1.73 Base

1.5 - 2.0 37.22 1.57 7.09 0.16

2.0 - 3.0 37.98 1.55 6.33 0.18

> 3.0 19.66 0.90 24.65 0.83

Residual Oil

Percentage Costs Differential
Sulfur Cost per Cogt per Per Per
Barrel 10 Btu Barrel 106 Btu

0.5 - 1.0 27.32 4.38 Base

1.0 - 2.0 2S.18 4.03 2.14 0.35

2.0 - 3.0 22.54 3.62 4.78 0.76

Data based on Reference 52.

!1-1-3 5

for a variety of pollutants may be projected for a number of wind conditions
and atmospheric stabilities and averaged over sets of meteorological condi-
tions. Various additional computations can and have been built into
specific models to simulate the effects of momentum-dominated plume rise,
chemical reactions and ground deposition (which are especially important in
Jong-range plume transport), building interference, impact of terrain fea-
tures, etc. Because the selection of such options may drastically change the
projected GLCs, the EPA has recently issued guidelines designed to improve
the uniformity of model applications. Some of the models that have recently
been accepted as "guideline" models are CRSTER (a single point-source model
for use in rolling terrain), RAM (a multiple-point and-area source model used
in urban areas), and ISC (an industrial source complex model containing pro-
visions for modeling multiple-point, -volume, and -area sources).

Because the results from these models determine regulatory requirements
for many projects, it is important that these projections be accurate.
Underestimates of GLCs may lead to inadequate protection of public health and
welfare, while overestimates of GLCs will result in installation of unneces-
sarily expensive emission control equipment. Because of the assumptions of
Gaussian distribution, the empirical nature of the coefficients used, and the
vagaries of real atmospheres, these models frequently project GLCs that dis-
agree with measured values by more than a factor of two (34).

Research is therefore continuing at a variety of public and private in-
stallations to improve these models and develop additional types that may
provide more reliable projections than the conventional Gaussian formulation. W
These new models emphasize better characterization of the ambient flow
fields, both mean and turbulent, into which pollutants are emitted, although
the models often still rely on a Gaussian distribution within the plume.
Also, in recent years, the question of fugitive dusts has become a major air
quality consideration. No model have been validated (proved acceptable) for
estimating impacts of fugitive dusts at nearby downwind receptors. Hence,
considerable work is being done to develop models that can be used to esti-
mate emissions and dispersion of fugitive dusts fr om material storage piles
under a variety of wind conditions.

Current models are also deficient in accurately describing plume tran-
sport and dispersion in complex terrain. In recent studies, the flow field
about the terrain has been modeled with simple potential flow methods for
neutral stability (35) or similarly simple approaches (35, 36) for stable
conditions and certain types of terrain. The flow fields are used to locate
the plume centerline within the flow while the pollutant distribution about
the centerline is still assumed to be Gaussian. Summaries of ongoing large-
scale field programs pertaining to complex terrain problems can be found in
References (37) and (38).

Work is also continuing on modeling the effects of enhanced turbulence in
building wakes on plume diffusion within such wakes. Although the Gaussian
formulation is used, the height of the plume centerline is sometimes
decreased, and the dispersion parameters are increased by an amount depending
on building size, geometry, and downwind distance. These modifications
depend strongly on the results of wind-tunnel simulations., and field con-
firmation is still needed. A recent review of these approaches is given in
Reference (39).

111-36

An example of improved modeling of flow fields where the Gaussian formu-
lation is not retained, is the calculation of pollutant dispersion during
convectively unstable conditions within a region of limited vertical extent
(the mixing depth). It is under these meteorological conditions that tall
stacks in flat terrain usually produce their highest ground-level concentra-
tions. Recent laboratory experiments (40) and numerical simulations (41) of
pollutant dispersion in convective conditions show that the vertical distri-
bution of pollutants is not Gaussian. This deviation is attributed to the
characteristics of the thermal velocity field -- updrafts and downdrafts --
which distribute the p1lutants. The findings from these detailed research
studies (40. 41) have led to simpler models for stack plume dispersion during
convective conditions (42, 43).

H. Regulatory Effects

The Clean Air Act Amendments of 1977 are of major importance in the regu-
lation of air quality in two crticial areas: 1) they specify acceptable
approaches in controlling atmospheric emissions from industry; and 2) they
give specific legislative direction to "prevention of significant deteriora-
tion", one of the most controversial concepts of air pollution control.

Some of the most signinificant provisions related to power plant siting
and operations are discussed below. The Clean Air Act is scheduled for con-
gressional review during 1982. Some of the provisions described here may be
changed at that time.

Stack Height and Intermittent Control

In response to the Clean Air Act Amendments of 1977, which called for
reductions in pollutants, some electric utilities sought simply to decrease
the GLC of the pollutant in the air shed rather than reduce the actual
amounts limited. Three methods were proposed: 1) the use of very tall
stacks, 2) switching of fuel, and 3) switching of load between plants. The
EPA argued against the acceptability of these methods because they did not
diminish emissions. Although better air quality, as defined by GLC, was
stained by spreading the pollutants, the improvement was an artifact.

The new Act essentially eliminated the use of these dispersion methods by
denying credit for pollution abatement attributed to them. This approach was
recently upheld in the case of Dow vs EPA in the U.S. Court of Appeals for
the 6th Circuit. In particular, credit is denied for stack height exceeding
11good engineering practices", which is "the height necessary to insure that
emissions from the stack do not result in excessive concentrations of any air
pollutant in the immediate vicinity of the source as a result of atmospheric
downwash eddies and wakes which may be created by the source itself, nearby
structures or nearby terrain obstacles" (33). Proposed EPA regulations per-
taining to tall stacks (44) set the height for good engineering practice
(GEP) as the height of the structure plus 1.5 times the lesser of the height
or width of the structure. "Nearby" (Section 123) is taken to be a distance
up to five times the height or width of the structure, but not more than 0.5
miles (0.8 km) away unless a greater height is necessary to avoid the exces-
sive concentrations referred to above. Typically, the GEP stack height of a
power plant is 500 to 600 feet.

111-37

Nonattainment Areas

When air quality in a region does not meet National Ambient Air Quality
Standards, the area becomes "nonattainment", and no further increase in total
pollutant emissions from major sources in the area is allowed. To permit new.
industries to locate in such regions, the EPA has promulgated a policy of
"emission offsets" (38). The policy states that a new power plant to be
located in such a region must not only meet an emission limitation specified
as the Lowest Achievable Emission Rate (LAER) for that source, but must also
provide for sufficient reduction of emissions from its own or other sources
in the area to offset the new emissions. The objective is to achieve "reason-
able progress toward attainment of the applicable NAAQS." Any power plant
outside the nonattainment region producing a "significant" degradation in the
air quality of the nonattaniment region is also subject to an offset require-
ment.

Although the intent of this policy is to satisfy the competing needs of
growth and maintenance of air quality, it engenders several significant con- PF
sequences. First, it appears to give industries now emitting major amounts
of pollutants the power to sell "pollution rights". That is, they could sell
the right to clean up their output levels to the highest bidder. As a
result, one company can be economically responsible for the operation and
maintenance of another company's pollution controls. In fact, the new
source, rather than the sources already located in the area, would be forced
to bear the economic burden of controls both for its own plant and the offset
plants. Thus, unless there are compelling economic considerations for
locating in a particular region, plant owners will tend to choose sites where
they will not be subject to an offset.

The State of Maryland is presently encouraging the development of an
$'offsets market" for the Baltimore nonattainment area. The first agreement
of this nature was recently established between Maryland Slag, Bethlehem
Steel, and Atlantic Cement Company. Under the agreement, Maryland Slag will
sell emission offsets to Atlantic Cement so that Atlantic can process slag
from Bethlehem Steel. Bethlehem will reduce emissions from open storage
piles to provide additional required offsets. The air quality analysis that
provided the basis for the trade-off was facilitated by the close proximity
of the three companies.

Maryland presently has nonattainment areas for three pollutants: particu-
lates (Baltimore area), carbon monoxide (Baltimore and Western Maryland), and
photochemical oxidants (Baltimore, Washington D.C., and scattered areas else-
where).

The Baltimore TSP nonattainment area is the one which affects power
plants most. Recent analyses indicate that up to 70 percent of the total
blowing dust there is due to fugitive emissions. The recently submitted
Maryland SIP revisions (45) propose paving roads and covering storage piles
in the nonattainment region to reduce blowing dust. In addition, power
plants converting to coal contributing more than 5 jag/m3 (24-hour) or I Jag/m3
(annual) in this region will be a subject to stringent fugitive emission

111-38

controls and may be required to obtain emission offsets. These requirements
will particularly affect the design of coal-handling facilities at plants
undergoing coal conversion.

To estimate the implications of this policy for siting new power plants
near such areas, a typical 1,000-MW coal-fired station was modeled. It was
assumed that emissions were at the levels permitted by the New Source Per-
formance Standards (Table 111-5). The results indicated that, to avoid an
offset, such a plant could be located no nearer than 10 to 15 miles from the
border of a nonattainment area, depending upon the local meteorology.

Thus, the siting of future fossil-fueld power plants in Maryland will be
influenced to a large extent by the existing TSP nonattainment areas.

Prevention.of significant Deterioration (PSD)

The most significant change within the Clean Air Act relates to PSD (46,
47). The law establishes upper limits on allowable air quality changes for
S02 and particulates. It designates three classes of areas (1, 11, and III)
with differing restrictions on increases in pollution levels.

The Class I area designation is reserved for regions where it is desir-
able to maintain the present air quality. Automatically classified within
this category are international parks, national wilderness and memorial parks
over 5,000 acres, and national parks over 6,000 acres. Other areas may be
added to this list by the State, in some cases at the suggestion of the
Federal Land Manager. Maryland has no Class I areas at this time, although
there are several such areas in nearbly Virginia and West Virginia (see Fig.
111-18).

Class II areas are assigned allowable increments that permit moderate
industrial growth. All areas of the country not originally classified as
Class I start out in this category.

Class III areas are less restricted and may allow fuller industrial de-
velopment. A Class II area may be redesignated Class III only after a
process involving the Governor, the legislature, and "general purpose units
of local governments." The actual procedure is not determined at this time.

The allowed increase (increments) for each area and the comparable stan-
dards are shown in Table 111-2. The total increments used by all emitters
must stay within the specified limits.

According to the Clean Air Act Amendments of 1977, Sec. 163 (a):

"In the case of sulfur oxides and particulates, each appli-
cable implementation plan shall contain measures assuring that
maximum allowable increases over baseline concentrations of, and
maximum allowable concentrations, such pollutants shall not be
exceeded. In the case of any maximum allowable increase (except an
allowable increase specified under 165 (d) (2) (C) Uv) for a pol-
lutant based on concentrations permitted under national ambient air

111-39

f Pa.

B: Uto.

Clarksburg 9

Va. Wash.

Charleston
J*
A
slau ton

4'.

IIf Richmond

lynchburg
Roanoke

Miles

Figure 111-18. Mandatory Class I areas around Maryland. There are no mandator@
areas in Pennsylvania.
1) Shenandoah National Park
2) Dolly Sods
3) Otter Creek
Circle A shows the Class I exclusion area for a hypothetical 10
plant located at X burning 1% sulfur coal with an 80%-efficient
circle B shows the exclusion area for the same plant burning 2%

11111 ION 1111111 1111 1 1 @ I , "ll I IN 14

quality standards for any period other than an annual period, such
regulations shall permit such maximum allowable increase to be
exceeded during one such period per year."

This section clearly indicates that the total GLC (from all sources)
should be considered in a before-and-after analysis. Certainly, if no changes
have been made in the sources before and after, no PSD increment should be
consumed. Therefore, to conduct such an analysis, the same meterological
data must be used for both "before" and "after".

The annual average PSD increment can be calculated for each receptor
-point by calculating the annual averages due to only the changes (plus and
minus) in emissions at the sources. This simple procedure can be used for
calculating the annual PSD increment consumption because source contributions
to the annual average GLCs are additive. The maximum annual PSD increment
consumed is then the greatest of the calculated increments for the set of
receptors. This maximum is usually less than the sum of the maxima (at the
respective maximum locations) for individual source alternations.

The 24-hr. PSD increment consumption is more difficult to model. The PSD
increment consumed at each receptor is obtained by calculating the highest
(or second-highest) 24-hr. GLC due to all sources after the change and sub-
tracting from these values the highest (or second-highest) modeled "baseline"
24-hr. GLC at that receptor. The maximum 24-hr. PSD increment consumed is
then the greatest of the calculated increments for any receptors in the set.
Because GLCs depend strongly on wind speed and direction, the 24-hr. PSD
increments consumed at any receptor can be less than the total PSD increments
consumed due to a number of changes at the various individual sources, even
when measured at the same receptor.

To aid the U.S. in becoming less dependent on foreign oil, EPA has al-
lowed a temporary suspension of PSD provisions for power plants that may be
ordered to revert to coal under provisions of the Energy Supply and Environ-
mental Coordination Act of 1974. These reversions are exempt from the re-
quirements of NSPS and not subject to PSD review. However, where allowable
PSD increments are exceeded due to coal burning the State will be required
after 5 years to obtain emission reductions at other installations sufficient
to restore the increment to the allowable limit.

Since pollutants may travel across political boundaries, the question
arises of what disposition to make in cases where long-range transport of
pollutants from a large coal-fired plant in, for example, Ohio or West
Virginia consumes part of the available PSD increment for neighboring states.
By federal regulation, the maximum allowable consumption by an out-of-state
utility is 50 percent of the remaining increment. However, this amount may
not be acceptable to the affected state. It is not clear at this time what
recourse a state so affected would have, especially if the additonal pollu-
tants do not cause a violation of standards. The present amendments (Section
126) call only for "written notice to all nearby states. . . at least sixty
days prior to the date on which commencement of construction is to be per-
mitted."

PSD analysis requirements also include an estimation of S02 and TSP
transport into distant Class I areas, and the results are relevant for siting

111-41

decisions. This analysis is difficult since 1) the Gaussian plume model is
not accurate at distances beyond 20-30 miles, 2) the meteorological data
necessary for realistic calculations (vertical profiles of wind every 20-30
miles) are not available, and 3) the interaction of pollutant plumes from
various sources is not well understood. Typical "exclusion distances" for a
1000-MW power plant operating at normal fuel consumption (2% S coal and 90%
flue gas desulfurization) would be 30-70 km.

Coal Conversion

At one time, virtually all of the power plants in Maryland were coal-
fired. Because of stringent pollution control requirements and lower cost,
many of these plants were converted to oil in the late 1960's or early 70's.
However, reconversion to coal is now being considered in response to the
current oil supply and price situation.

At the present time, eight units -- Crane I and 2, Brandon Shores I and
2, Wagner 1 and 2, and Riverside 4 and 5 -- are under "prohibition orders"
issued under the Energy Supply and Conservation Act (ESCA) and the Fuel Use
Act (FUA). Should these orders be made final, these facilities will be
prohibitied from burning oil or gas. The environmental consequences of these
conversions need to be carefully examined: six of the eight units are
located in, or nearby, an area that does not presently meet standards for
particulates. Fueling with coal also will generally increase S02 ground-
level concentrations and consume PSD increments.

Baltimore Gas and Electric Company has voluntarily applied to the
Maryland Public Service Commission for conversion of the Brandon Shores and
Crane plants to coal. (PSC cases #6516 and #7443, respectively). Final
briefs have been filed for Crane and Brandon Shores (48, 49, 50). General
agreement has been reached on the equipment and fuel necessary to control
particulate and sulfur oxide emissions to permissible levels.

Of the two remaining plants, only conversion at Wagner appears economi-
cally sound. Riverside is relatively old (29-30 years), has a low capacity
factor, and is subject to severe space and environmental limitations. Wagner
Units 1 and 2, on the other hand, are younger (21-24 years), have a higher
capacity factor, and already have coal facilities in use for Unit 3. Rough
estimates of cost savings due to fuel conversion indicate a payback period of
1-2 years. Thus, it is likely that Wagner Units I and 2 will be ordered to
@burn coal.

III@42

REFERENCES - CHAPTER III

1. Cooper, J.A., and J.G. Watson. Portland Aerosol Characterization Study
(PACS): Application of Chemicalk Mass Balance Methods to the Identi-
fication of Major Aerosol Sources in the Portland Airshed, Oregon
Graduate Center. 1979

2. Maryland Air Quality Data Reports (Annual: 1971-1979). State of Mary-
land, Department of Health and Mental Hygiene, Environmental Health
Administration, Baltimore, Maryland.

3. Compilation of Air Pollutant Emission Factors (with supplements 1-7),
U.S. Environmental Protection Agency, Office of Air and Waste
Management Office of Air Quality Planning and Standards, AP-42.
1977

4. Environmental Outlook, 1977 National, Regional, and Sectoral Trends and
Forecasts 1975, 1985, 1990, U.S. Environmental Protection Agency,
EPA-600/9-78-011. 1978

5. National Air Quality and Emissions Trend Report 1976. U.S. Environmental
Protection Agency, EPA-450/1-77-002. 1977

6. National Air Pollutant Emission Estimates, 1970 - 1978, U.S. Environ-
mental Protection Agency, Office of Air Quality Planning and Stan-
dards, Research Triangle Park, NC, EPA-450/4-80-002. 1980

7. New Source Performance Standards, U.S. Environmental Protection Agency.
Federal Register, Vol. 43, No. 182, Tuesday, September 19, 1978,
Part V, pp. 42154 - 42189.

8. New Source Performance Standards, U.S. Environmental Protection Agency,
Federal Register, Vol. 43, No. 182, Tuesday, September 19, 1978,
Part v, pp. 42154-42189.

9. U.S. Environmental Protection Agency, Federal Register, 44 FR 33612,
June 11, 1979.

10. U.S. Environmental Protection Agency, 40 CFR 50: 41 FR 11253. March
1976; or Environmental Reporter, April 16, 1976.

11. U.S. Environmental Protection Agency, Federal Register, 43 FR 46258,
October 5, 1978.

12. Section 110.10 of State Implementation Plan. Maine Department of
Environmental Protection, January 24, 1979.

13. Environmental Reporter, The Bureau of National Affairs, Inc., Washing-
ton, D.C., January 10, 1975, p. 53.

14. Power Plant Cumulative Environmental Impact Report, Maryland Power Plant
Siting Program, Annapolis, MD, PPSP-CEIR-2. 1978

111-43

15. Ruch, R.F., J. H. Gluskoter, and N.F. Shimp. Occurrence and Distribu-
tion of Potentially Volatile Trace Elements in Coal, III. State
Geological Survey, EPA 650/2-74-054, p. 96. 1974

16. Miller, F.J., D.E. Gardner, J.A. Graham, R.E. Lee, Jr., W.E. Wilson, and
J.D. Bachmann. Size Considerations for Establishing a Standard for
Inhalable Particles, Journal of the Air Pollution Control Associa-
tion, Vol. 29, No. 6, p. 610. 1979

17. Fluorides, National Academy of Sciences, Committee on Biologic Effects
of Atmospheric Pollutants, National Res. Council, Wash., DC, ISNB
0-309-01922. 1971

18. Code of Maryland Regulations.

19. Ferris, B.G., Jr. Health Effects of Exposure to Low Levels of Regulated
Air Pollutants: A Critical Review, Journal of the Air Pollution Con-
trol Association, Vol. 28, No. 5, pp. 482-497. 1978

20. Alarie, Y., C.E. Ulrich, W.M. Busey, A.A. Krumm, and H.N. MacFarland.
Long-Term Continuous Exposure to Sulfur Dioxide in Cynomolgus
Monkeys, Archives of Environmental Health, Vol. 24, pp. 115-128.
1972

21. Alarie, Y., W.M. Busey, A.A. Krumm, and C.E. Ulrich. Long-Term Con-
tinuous Exposure to Sulfuric Acid Mist in Cynomolgus Monkeys and
Guinea Pigs.Archives of Environmental Health, Vol. 27, pp. 16-24.
1973

22. Clausen, R. Acid Rain, an International Concern, Journal of the Air Pol-
lution Control Association, Vol. 30, No. 10, pp. 1090 - 1091. 1980

23. Katz, M. Advances in the Analysis of Air Contaminants: A Criical Review,
Journal of the Air Pollution Control Association, Vol. 30, No. 5, P.
541. 1980

24. Code of Federal Regulations 40 CFR 60

25. Attainment Status Designations, U.S. Environmental Protection Agency,
Federal Register. 40 CFR Pt. 81, Vol. 43, p. 9000. 1978

26. Bowles, A. Personal conounicatin from Alvin Bowles, Bureau of Air
Quality and Noise Control, November 24, 1979.

27. Trends in the Quality of the Nation's Air, U.S. Environmental Protection
Agency. 1977

28. Schumacher, R. Personal communication from Ralph Schumacher, Bureau of
Air Quality and Noise Control, November 24, 1980

29. Brower, R.P. The Air Quality Impact of the Coal-Fired Crane Power Plant,
prepared by Martin Marietta Environmental Center for the Maryland
Power Plant Siting Program, Annapolis, MD, PPSP-CPC-80-7. 1980

111-44

30. Brower, R.P. The Air Quality Imapct of the Coal-Fired Brandon Shores
Power Plant, Vol.1: Text, prepared by Martin Marietta Environmental
Center for the Maryland Power Plant Siting Program, Annapolis, MD,
PPSP-BS-80-2. 1980

31. White, E.J. Electrostatic Precipitation of Fly Ash, APCA Reprint Series,
Air Pollution Control Association, Pittsburgh, PA, July 1977; see
also: Jones, A.B., Air Pollution Control for Industrial Coal Fixed
Boilers, in Power Generation: Air Pollution Monitoring and Control,
K.E. Noll and W.T. Davis, Ann Arbor Science, Ann Arbor, MI.

32. Ponder, W.H., and R.D. Stern. S02 Control Methods, The Oil and Gas
Journal. December 13, 1976, pp. 60-68

33. The Clean Air Amendments of 1977, U.S. Environmental Protection Agency.
P.L. 95-99, August 7, 1977, with Technical Amendments to the Clean
Air Act, P.L. 95-190, November 16, 1977

34. Weil, J.C. Evaluation of the Gaussian Plume Model at Maryland Power
Plants, prepared by Martin Marietta Corporation, Baltimore, MD, for
Maryland Power Plant Siting Program, PPSP-MP-16. 1977

35. Hunt, J.C.R., J.S. Puttock, and W.H. Snyder. Turbulent Diffusion from a
Point Source in Stratified and Neutral Flows around a Three-
Dimensional Hill, Part I, Diffusion Equation Analysis, Atmospheric
Environment, Vol. 13, pp. 1227-1239. 1979

36. Weil, J.C. Buoyant Plume Rise over a Two-Dimensional Hill, Proceedings
NATO/CCMS 10th International Technical Meeting on Air Pollution
Modeling and Its Application, Rome, Italy, 23-26 October. 1979

37. Holzworth, G.C. The EPA Program for Dispersion Model Development for
Soures in Complex Terrain, Proceedingg Second Joint Conference on
Applications of Air Pollution Meteorology. New Orleans, LA, 24-27
March 1980, Amer. Meteor Soc., Boston, MA, pp. 92-107. 1980

38. Dickerson, M.H. and P.H. Gudiksen. The Department of Energy's Atmos-
pheric Studies in Complex Terrain (ASCOT) Program, Proceedingg.
Second Joint Conference on Applications of Air Pllution Meteorology,
New Orleans, LA, 24-27 March 1980, Amer. Meteor. Soc., Boston, MA,
pp. 469-473.

39. Hosker, R.P. Dispersion in he Vicinity of Building Wakes, ProceedingE.
Second Joint Conference on Applications of Air Pollution Meteor-
ology, New Orleans, LA, 24-27 March 1980, Amer. Meteor. Soc, Boston,
MA, pp. 92-107. 1980

40. Willis, G.E. and J.W. Deardorff. A Laboratory Study of Dispersion for an
Elevated Source within a Modeled Convective Planetary Boundary
Layer, Atmospheric Environment, Vol. 12, pp. 1305-1312/ 1978

41. Lamb, R.F. A Numerical Simulation of Dispersion from an Elevated Point
Source in the Convecive Planetary Boundary Layer, Atmospheric
Environment, Vol. 12, 1980, pp. 1297-1304.

111-45

42. Weil, J.C. A Simplified Numerical Model of Dispersion from Elevated
Sources in the Convective Boundary Layer, to be presented at Amer.
Meteor Soc. Fifth Symposium on Turbulence, Diffusion, and Air Pollu-
tion, Atlanta, GA,March 9-13, 1981.

43. Venkatram, A. Dispersion from an Elevated Source in a Convective
Boundary Layer, Atmospheric Environment, Vol. 14, pp. 1-10.

44. Proposed Regulatory Revision, 1977 Clean Air Act Amendments for Stack
Heights, U.S. Environmental Protection Agency, Federal Register,
Friday, January 12, 1979, p. 2608.

45. Revision to the Plan for Implementation of the National Ambient Air
Quality Standards for Total Suspended Particulate Matter, Photo-
chemical Oxidants and Carbon Monoxide for the Metropolitan Baltimore
Intrastate Air Quality Control Region, Maryland State Department of
Health and Mental Hygiene, Office of Environmental Programs, October
31. 1980

46. Stern, A.C. Prevention of Significant Deterioration: A Critical Review,
Journal of the Air Pollution Control Association, Vol. 27, No. 5, pp.
440-453. 1977

47. Easton, E. B., and F.J. O'Connell. The Clean Air Act Amendments of
1977, Journal of the Air Pollution Control Association, Vol. 27, No
10, pp. 943-47. 1977

48. Roig, R. A. Prefiled Supplemental Direct Testimony on Behalf of The
State of Maryland before the Public Service Commission of the State
of Maryland, Case Number 6516 (Brandon Shores Power Plant), November
17, 1980

49. Ellis, H.,M. Direct Testimony on Behalf of Baltimore Gas and Electric
Company before the Public Service Commission of the State of
Maryland, Case Number 6516 (Brandon Shores Power Plant), October 15,
1980.

50. Ferreri, G.P. Prefiled Direct Testimony on Behalf of the State of
Maryland before the Public Service Commission of the State of
Maryland, Case Number 6516 (Brandon Shores Power Plant), November
17. 1980

51. U.S. Environmental Protection Agency, Federal Register, Vol. 45, No.
161, August 18, 1980, p. 55066.

52. Energy Data Report, U.S. Department of Energy. Cost and Quality of
Fuels for Electric Utility Plants 1980 Annual. DOE/EIA-0191(80),
Dist. Cat. UC-97. June, 1981.

111-46

CHAPTER IV

AQUATIC IMPACT

For each kilowatt hour of electricity generated, a steam power plant
burning fossil fuel must dispose of about 4,400 Btu of heat via its conden-
ser, and a nuclear power plant must dispose of about 6,600 Btu. Most Mary-
land power plants use once-through cooling systems to transport this waste
.heat from the plant. In these systems, water is drawn into the plant, heated
10 to 170F in the condenser, and discharged into a receiving b3dy of water.
Approximately one million gallons of water per minute (or 63 m Is) is re-
quired for each 1,000 MW of generating capacity. Closed-cycle cooling can be
used to reduce water withdrawal. Use of this technology will allow con-
sideration of such options as more power generation per site, or sites in
more sensitive areas.

The Chesapeake Bay and its tributaries serve as the major source of
cooling water in Maryland. At the same time, this ecological system supports
complex aquatic food webs that produce renewable resources of fish and shell-
fish. A major concern of the Power Plant Siting Program is to ensure that
power plants provide electricity at a reasonable cost, while not interfering
with the maintenance of sustained yields of these resources and the stability
of the system, which depends on all components of the food web. Thus, the
impact of power plants on the aquatic ecosystem as a whole must be evaluated,
and measures to mitigate this impact should be examined for their potential
benefits and costs.

A. Sources and Nature of Impact

As water is drawn through a power plant and returned to its source,
aquatic organisms interact with cooling system structures, intake and dis-
charge velocity fields, the heated effluent, antifoulants, and other alte
ations of the environment caused by plant operations, as explained below.
The locations and nature of the interactions and ensuing stresses which are
encountered by aquatic organisms are briefly described below: (See also
Figure IV-1)

Entrapment

Two of the largest Maryland power plants (Calvert Cliffs and Morgantown)
have intake embayments partially shut off from the main bay or river by
a curtain wall, i.e., a wall reaching from above the surface of the
water to some depth below the surface. The function of the curtain wall
is to permit the plant to draw its cooling water from the deeper por-
tions of the water column, where temperatures tend,to be lower than at
the surface during summer months. During the summer, large numbers of
fish congregate in the intake embayments and may be entrapped there.
During the summer months, dissolved oxygen (DO) concentrations in the
water often drop to levels below that needed to sustain adult and

lRadiological-effects are discussed in Chapter V.

IV-1

juvenile fish. The drop is pronounced in the deeper water entering the
embayment under the curtain wall. Fish kills may result. The killed
(or weakened) fish may then impinge in large numbers on the protective
intake screens. In the following discussions entrapment will not be
treated as a separate effect.

"Impingement

The circulating pumps for the cooling water are protected by intake
screens (usually 3/8-inch mesh). Organisms too large to pass through
these screens may be impinged, i.e., pinned against them by the pressure
of the passing water, a prospect that is markedly increased when the
organisms (fish or crabs) are weakened by stresses such as low DO con-
ditions. The screens are rotated periodically and the impinged matter
is washed off. At several plants the organisms are flushed back into
the cooling stream discharge. Some species survive this treatment, but
others suffer a high rate of mortality.

'Entrainment

Organisms small enough to go through the intake screens pass through the
entire cooling system, where they are stressed by mechanical forces due
to physical contact with pumps and pipes, and pressure and shear forces
generated by complex flow patterns and turbulence.

While passing through the condenser, the entrained biota will be sub-
jected to a sudden temperature rise. The biological response to this
heating depends on the magnitude of the temperature rise, the length of
exposure to the elevated temperature, and the initial ambient temper-
ature. In Maryland plants, the temperature rise varies from 10' to 320F
and the exposure time from a few minutes to almost two hours (including
retention time in effluent canals). Thus, " thermal stress dose," i.e.,
a product of temperature and time, is quite variable.

Entrained biota experience additional stress at plants where biocide
(usually chlorine) is added to the cooling water to prevent clogging of
the cooling system by biomass build-up.

*Discharge Effects

The alteration of local habitat produced by the discharge of cooling
water can manifest itself in several ways. Aquatic organisms can be
"entrained" into the discharge plume, where they will be exposed to
higher-than-ambient temperatures and biocide residuals. Other toxic
substances released with the cooling water (e.g., copper) may affect the
stationary benthic communities near the plume. Finally, a fast-moving
discharge flow may alter the characteristics of bottom sediment in its
way and may also directly influence the behavior of some organisms in
the discharge zone.

Plants using cooling towers rather than once through cooling systems
exert similar stresses on organisms interacting with them. However, the
degree of stress,in most cases, differs markedly between the two types of

IV-2

M M M M M M a M M M M M M

A. C

ITrasl
Curtain Wall I I Intake Condenser
",*@ Intake Rack Screens Puml) Tubes RECEIVING WATER
INTAKE WATER Emba ment 0 Discharqe
-Y Condull
C===3 Plume %I

C===

DISCHARGE (Plume)
ENTRAPMENT IMP INGEMENT1 ENTRAINMENT

Figure iv-1. Path of water flow through a power plant Using once-through cooling and 1ccations of plant-
organism interactions.

A. Fish may be entrapped in the intake embayment, and may suffer prolonged exposure to
water of low dissolved oxygen content drawn from below the curtain wall.

B. Organisms may be trapped on intake screens; the screens are rotated to wash fish
and crabs from the screens back into the receivina water.
Fn I c,

C. Small organisms in the water column (plankton) pass through the cooling system; they
experience a temperature rise and also shear and pressure forces during their transit
through the cooling system.
D. Organisms in the receiving water may encounter temperature rises in the plume (plume
entrainment3 and may be affected by the discharge.

cooling system. The volume of water withdrawn for use in cooling towers is
small and intake velocities are low; the result is that entrapment and im-
pingement tend to occur at low rates. The numbers of organisms entrained are
low, but mortality is essentially 100 percent because residence time of
water in cooling towers is very high. Cooling towers discharge a portion of
their cooling water on a regular basis; this water is known as blowdown.
Blowdown often contains high levels of metals such as copper (eroded from the
cooling system pipes) and biocides, used to prevent fouling of the system.
In saline waters, blowdown may also have a high salinity, due to evapora-
tion. Discharge effects due to blowdown release will be similar to that from
a once-through cooling system, but because of the small water volumes in-
volved, the area experiencing discharge effects would be very small. For
cooling towers the consumptive use of water can often be a concern, requiring
augmentation reservoirs to make up for evaporative losses during low-flow
conditions in the source-waters.

The organisms interacting with the power plant can be grouped as
follows:

� Phytoplankton

� Zooplankton

� Benthos

� Ichthyoplankton

� Juvenile and adult fish and crabs.

Individual groups may be more susceptible to damage by one type of power
plant interaction than by another (Table IV-0. Entrapment most often
stresses juvenile fish. Impingement stresses adult and juvenile fish and
crabs. Entrainment stresses planktonic organisms (which serve as food for
many resource species), as well as the planktonic larval stages of many re-
source and forage species. All aquatic biota may experience discharge ef-
fects, but benthic species, because of their predominantly immobile life
style, would be most stressed.

Mortalities resulting from plant/organism interactions can cause a de-
cline in a population if they are not offset by biological compensation
mechanisms such as increases in growth rate, fecundity, recruitment and/or
early survival. In the case of phytoplankton or zooplankton, losses due to
entrainment are generally recouped quickly as a result of inherent rapid
reproduction rates (generation times of hours to days). Other organisms have
much longer generation times. Most fish spawn only once a year and may not
reproduce until several years of age. For species utilizing a very localized
spawning or nursery area adjacent to a power plant, high entrainment losses
can occur unless cooling towers with carefully controlled blowdown are used
to reduce the amount of organisms entrained. The potential for such losses
having an impact is much less for ubiquitous species which spawn in or in-
habit wide areas of the Bay.

IV-4

Table IV-1- Major Types of Aquatic Effects of Power Plant Operations.

Sources of Primary Susceptible Type of Stress
Effects Organisms LOW DO (a) Mechanical lbermal Chemical Habitat
Alteration

Entrapment Adult and juvenile x
fish

Impingement Juvenile fish, crabs x
Entrainment Ichthyoplanttyn (b)
zooplankton c d) x x x
Phytoplankton

Discharge Adult and j'uvenjle
fish, benthos(e), x x x
shellfish

(a) Low dissolved oxygen concentrations oxygen deficiency
(b)Eggs and larvae of fish
(c)Weak swimming animals present in the water
(d)Minute plants present in the water
(e)Organisms living in or on the bottom.

ORGANISMS NOT ENTRAINED BUT DEPENDENT ON SUSCEPTIBLE ORGANISMS

STRIPED BASS

IMMATURE AND MATURE ADULTS
YOUNG-OF-THE-YEAR
(20 DAYS - 1 YEAR)

STRIPED BASS

EGGS AND LARVAE

STRIPED BASS PREY

ANCHOVIES -.0 PREY SPECIES
AND (NO CROAKER OR
YOUNG OF CRUITACIA MENHADEN EGGS)
ALEWIFES
MENHADEN ZOOPLANKTON
WHITE PERCH 4@@
CROAKER SHRIMP CP
SPOT BLUE CRABS MACROPLANKTON
MUD CRABS (WATER FLEAS, COPEPODS
MYSIDS. ETC

frk 19
SHRIMP AND MUD CRAB PHYTOPLANKTON
LARVAE AND YOUNG @A

ORGANISMS SUSCEPTIBLE TO ENTRAINMENT

Fig. IV-2- Areas of potential power plant entraiment impact on striped bass and associated
food items.

I III I I I I I I 1 1 ' 1 1

Plant operations can indirectly cause a decline of a population by de-
creasing the abundance of its food supply. (See Figure IV-2) The dominant
groups in the Bay which are important as forage are phytoplankton, zooplank-
ton, benthic organisms, and small fish species (e.g., bay anchovy and men-
haden). Although fish populations are more likely to be affected by the
entrainment of their ichthyoplankton, they could also be affected by a change
in the density of their food. These indirect effects may propagate through
several trophic levels, although they are unlikely to be measurable beyond
one link along the food chain.

Plant operations also affect particular species through modification of
the physical/chemical environment. Biocide residuals may accumulate in areas
around the plant, and temperatures are elevated by varying amounts in the
discharge vicinity. Discharge jets may also scour the bottom sediments,
creating locally uninhabitable zones for benthic organisms. If such habitat
modifications make an area unsuitable for use by some species, a subsequent
decline in their abundance can occur locally.

B. Aquatic Habitats

The central concept underlying the cumulative aquatic assessment pre-
sented here is that the Chesapeake Bay and its tributary estuarine waters are
composed of distinct habitat types. These habitat types are defined by water
salinity, which is the environmental variable most important in controlling
distributions of organisms in estuaries. Each of these habitats can be iden-
tified with unique functions in producing or supporting important resource
elements, although their biotic components overlap, and their extent varies
seasonally. Cumulative impact will be assessed in terms of significant ef-
fects on the biota over the entire extent of each characteristic habitat type
within Maryland, with the emphasis on whether the long-term integrity of each
estuarine habitat and its characteristic functions are maintained. In order
to accomplish this assessment the salinity zones must be defined and the
distribution of the power plants among the zones determined.

The salinity zones designating the habitat types can be defined by the
Venice system of classification (1) as:

Habitat Salinity Ranges

Euhaline (Marine) 30.0 ppt - 35.0 parts per thousand (ppt)
Polyhaline 18.0 ppt - 30.0 ppt
Mesohaline 5.0 ppt - 18.0 ppt
Oligohaline 0.5 ppt - 5.0 ppt
Tidal fresh 0 ppt - 0.5 ppt
Riverine 0 ppt

The major ecological functions of each habitat are:

Polyhaline and Marine

These high salinity waters are primary sites of the blue crab spawning
and development; they also support hard clams. Several fish species,
(e.g., spot, croaker, and Atlantic menhaden) whose young and adults

IV-7

seasonally feed in upper estuarine zones, spawn and develop in these
regions. These zones generally do not exist in the Maryland portion
of the Chesapeake Bay.

�Mesohaline

These medium salinity regions are the primary areas of production for
those shellfish (clams, oysters) whose early life stages are plank-
tonic. Mesohaline waters also support the adult crab populations and
produce most of the estuarine forage fish biomass. Therefore these
waters serve as feeding areas for large predator fish (e.g., bluefish,
striped bass).

�Oligohaline

These brackish water environments support resident estuarine fish pop-
ulations and serve as their spawning and nursery grounds. Although
these fish populations serve primarily as forage organisms for larger
fish, they may also be exploited by man. The areas also are feeding
grounds for migratory marine and estuarine species such as menhaden
and white perch. Some spawning of anadromous fish also occurs here.

�Tidal Fresh

These segments of estuaries are within tidal influence but without a
significant salt intrusion. They provide spawning and nursery areas
for anadromous fish species and also support their larvae and juve-
niles during the spring and summer months. In addition, resident fish
species, some adapted to both this and riverine environments, spend
their entire life cycles in this zone. The striped bass is a particu-
larly important example of a species using this environment as a
spawning and nursery area.

� Riverine

These freshwater habitats beyond the head of the estuary have resident
fish populations and supporting bottom (benthic) communities adapted
to constant freshwater conditions.

The locations of these zones change seasonally as a result of changes in
the amount of freshwater inflow (2). Table IV-2 indicates the zones in which
Maryland power plants are located and designates their zone according to
season. The majority of plants in Maryland are situated in oligohaline-meso-
haline regions. Data collected since publication of the last Cumulative
Environmental Impact Report (CEIR) (3) show that four plants previously con-
sidered to be in tidal fresh-oligohaline areas (Wagner, Westport, Gould
Street, Riverside) are actually on oligohaline-mesohaline waters. The
largest of the power plants in the state (Calvert Cliffs, Chalk Point, and
Morgantown) are 'sited in mesohaline regions (at least in the fall) and new
plants (e.g., Elms) will also be in the mesohaline habitat. There are no
power plants in the polyhaline and marine habitats along the Atlantic shore-
line in Maryland.

IV-8

Table IV-2. Power Plant Location by Salinity Regime.

Spring Fall
Net
Power Plant Capacity RiveTine Tidal- Oligo- Meso- Riverine Tidal- Oligo- Meso-
fresh haline Haline fresh haline haline

Brandon Shores 1,250 x x

Calvert Cliffs 1,620 x x

Chalk Point 1,265 x x

Conowingo (hydro) 512 x

C.P. Crane 384 x x

Dickerson 54S x x

Gould Street 103 x x

Morgantown 1,163 x x

Possum Point 478 x x

R.P. Smith 129 x x

Riverside 321 x x

Vienna 241 x x

Wagner 988 x x

Westport 177 x x

Total Capacity
by Zone 1,186 2,112 4,2S8 1,620 1,186 0 2,353 5,637

C. Regulatory Considerations

The intake, use, and discharge of waters for power plant use are reg-
ulated through the issuance of surface water appropriation permits and
Natural Pollutant Discharge Elimination Systems (NPDES) discharge permits.
These permits reflect Federal and State constraints on the amount of water
used, the type of intake employed, and the chemical and physical character-
istics of the effluent.

The evaluation of existing once-through cooling systems to determine if
cooling towers are required to protect the "balanced, indigenous population"
is done in conjunction with the NPDES permit process and the Code of Maryland
Regulations (COMAR) 08.05.04.13. Under the State regulations, an initial
evaluation of impact is made based on the size of the thermal plume with
respect to mixing zone criteria and the importance of the area as a spawning
and nursery area. If the plant fails to pass these screening criteria, a
more detailed evaluation is required. Impingement (and intake technology
used to minimize it) is also treated under the State regulation. Yearly
impingement total are estimated (as discussed later in this chapter) and
various methods of mitigation are evaluated to determine which techniques are
cost-effective. The status of the various Maryland plants which fall under
this regulation is listed in Appendix B.

The Dickerson Power Plant wastewater treatment system was under a
compliance order during 1978-79. Testing of the new system was completed in
August, 1979 with the plant passing a compliance test in February, 1980.

D. Aquatic Impact Assessment

Many additional monitoring studies have been completed since the pub-
lication of the last CEIR (3) including several carried out at sites where
data had previously not been available. All additional data available through
November 1980 has been incorporated into the following assessment of power
plant impacts on each of the salinity zones in Maryland.

Mesohaline

This medium salinity zone accounts for the greatest percentage of
aquatic habitat in the Maryland portion of the Chesapeake Bay. It serves as
the primary area of shellfish and forage fish production and as nursery and
feeding ground for most commerically and recreationally valuable fish species
and blue crabs. Three of the plants located in this zone (Calvert Cliffs,
Chalk Point, and Morgantown [summer-fall]) are the largest and newest in the
State. All three of these plants have been or are being intensively studied.
The findings of the Calvert Cliffs monitoring studies covering the preplant
period as well as the first five years of operation (1975-1980) have been
reported in References 4 through 14., The results of these studies are sum-
marized in Reference 15. The Morgantown monitoring findings are summarized
in References 16 and 17. The results of the Chalk Point Studies in the 1960's
are summarized in Reference 18. This plant is currently being intensively
studied.

IV__I 0

Four additional plants (Gould Street, Riverside, H. A. Wagner, and West-
port) are located on the Patapsco River and its tributaries in the Baltimore
area. Salinities at these plants tend to be in the oligohaline range in the
spring and low mesohaline during the remainder of the year. In the past, en-
vironmental degradation which was not related to these plants had elminated
the area as an important anadromous spawning ground (19). However, as will
be discussed below, numerous species of aquatic biota are currently using the
area. Except for Wagner, these plants are all older than 20 years, are used
for peaking and cycling service, and have seen decreased service since Cal-
vert Cliffs came on-line. Because of the close proximity of these four
plants, they will be discussed as a group in the material presented below.

'0 Entrainment

In-plant losses of about 30-70 percent of entrained zooplankton have
been observed at Calvert Cliffs, but the percentage loss was very var-
iable and often species-specific. Losses of entrained phytoplankton
biomass and productivity (on the order of 30% for each) have also been
observed, primarily in late summer and fall. No significant nearfield
depletion of zoo- or phytoplankton has been observed. Regional reduc-
tion in zooplankton density and phytoplankton assimilation was noted
in 1975, but the widespread nature of the changes suggests the plant
was not the causative agent. Similar reductions were not observedin
the nearfield in later years. A review of these studies is contained
in Reference 15.

High zooplankton mortalities (50 %) have been measured as a result of
entrainment at Morgantown only under the most severe thermal and
chlorine stress conditions. Phytoplankton productivity was also
reduced during those periods (16) . However, no changes in zooplank-
ton and phytoplankton populations in the river were detected (16). It
was estimated that 2 percent of the plankton transported past the
plant would be destroyed by entrainment (16, 17). No adverse impact
would result from losses of this magnitude to the rapidly reproducing
plankton populations.

Large mortality of entrained organisms was reported at Chalk Point in
studies done in the 1960's, with both thermal and biocide stresses
appearing to be important causes (20). Near-field depletions of jelly-
fish were also noted, but no changes in river populations of copepods
were found (18). More recent phytoplankton studies (21) also suggest
a reduction in photosynthetic activity and chlorophyll concentrations
between intake and discharge that is more marked during periods of
chlorination. Similarly, recent zooplankton studies indicate entrain-
ment losses of 21 and 52 percent without and with chlorination,
respectively, during summer, but no apparent losses during winter
sampling (22) (no chlorination is used in winter). Some plant effects
on near-field phytoplankton biomass and productivity have also been
observed in recent studies (24), with enhancement occurring in winter
and depresssion in summer. However, these effects were inconsistent
(21, 25). A lower density of zooplankton in the plant vicinity was
observed during one study (22), but not during others (22, 26).

IV-11

No zooplankton or phytoplankton entrainment studies have been done at
Baltimore harbor plants. For phyto- and zooplankton entrainment we
conclude that the findings at Morgantown and Calvert Cliffs are
similar. Entrainment losses of phytoplankton and zooplankton do occur,
but high reproduction rates of the affected populations compensate for
the plant effects. Based on these findings, cumulative effects would
not be expected.

At Chalk Point, the receiving water body has relatively low flushing
rates, and near-field effects are detected. However, the effects are
not consistently present. Further evaluations are currently underway
to assess impacts at the plant. The assessment is complicated by the
existence of other stresses on this ecosystem, such as sewage treat-
ment plant discharge and non-point source pollution.

Eggs and larvae of bay anchovy, naked goby, and hogchoker (all forage
species) are found in the Calvert Cliffs vicinity and are entrained.
Densities near the plant have not differed significantly from those
observed beyond the area of plant influence, and, in some cases, den-
sities near the plant were highest (15). No conclusive evidence of
ichthyoplankton depletion in the plant vicinity exists (15).

The same species of larvae are found at Morgantown, as at Calvert
Cliffs. Nearfield ichthyoplankton depletions were not detectable at
Morgantown (16).

Data from recent ichthyoplankton studies at Chalk Point (27, 28) have
not yet been analysed to determine if depletions occur in the vicinity
of the plant. Anchovy, naked goby, silversides, and hogchoker are the
dominant ichthyoplankton species in the plant area. The data thus far
suggest that striped bass and white perch larvae in the Patuxent are
concentrated upstream and away from the plant, but that some larvae
could be entrained under certain conditions of river flow (29).

Ichthyoplankton entrainment studies carried out at the Baltimore
harbor plants in 1979 and 1980 indicate that entrainment rates at
Gould Street are low, while those at Riverside and Wagner are higher
and similar to each other (30, 31, 32). major species spawning in
the Harbor include bay anchovy, Atlantic silverside, tidewater silver-
side, naked goby, rough silverside, and hogchoker (30, 31, 33, 34).
Entrainment at Gould street is dominated by naked goby (77%), juvenile
eels (5%), and bay anchovy larvae (5%) (31). At Riverside,bay anchovy
larvae dominated (43%), together with naked goby (24%), and tidewater
silversides (11%) (32). Species entrained at Wagner included gobies
(30%) bay anchovy (29%) and menhaden (19%) (30). These results con-
firm that the Baltimore area plants are not located in spawning areas
of important exploited fish species.

In general it is found that the entrained ichthyoplankton at all the
mesohaline plants belong to small forage species, mainly bay anchovy,
silversides, naked goby, and hogchoker. These species spawn throughout
the Maryland portion of the Chesapeake Bay and are ubiquitously dis-
tributed there. Thus localize'd losses at the plants under discussion
are insufficient to cause decrease in Bay-wide stocks. When the negli-
gible near-field effects observed to data are also considered, no

IV-12

cumulative Bay-wide impacts of ichthyoplankton entrainment at all the
power plants are likely.

Chalk Point has an additional entrainment effect due to the lack of
screens in front of the augmentation pumps used during the summer
months. Without these screens, fish and crabs that would normally be
impinged may be entrained into the pumps. Studies to quantify the mag-
nitude of these losses have been complicated by difficulties in
deploying sampling gear near the pumps. The studies have suggested
that fish and crabs do pass through the pumps, however, an estimate of
the number entrained could not be made (35).

Impingement

Fish and crab impingement data from Calvert Cliffs, Morgantown, and
Chalk Point, collected during the period 1976 through 1979, are pre-
sented in Table IV-3 along with data taken from the last CEIR (3)
covering the period 1975 to 1977. Although the values presented repre-
sent an estimated total annual impingement, the years are not the same
for each plant. However, they do permit an assessment of the
consistency of impingement over a period of about 5 years. In some
respects, data from the two time periods are very similar: the same
six species account for 93 and 78 percent of the total fish impinged
in the two time periods, respectively; the number of blue crabs im-
pinged is nearly the same for the two time periods. The data differ
in two respects: the total number of fish impinged decreased substan-
tially from the earlier to the more recent time period, and numbers of
impinged individuals of several species included in the "other" cate-
ory (e.g., winter flounder, gizzard shad, and blueback herring)
increased substantially.

Impingement data from Baltimore harbor plants are presented in Table
IV-4. The same two species dominate impingement here: menhaden and
spot. However, other species differences are evident; no substantial
numbers of hogchoker are taken at Baltimore plants, while gizzard shad
do not appear insignificant numbers at the other three plants. These
differences may reflect the fact that the Baltimore plants are located
on mesohaline waters of lower salinity than at the other three plants.

Table IV-5 presents the results of impingement mortality studies done
at Calvert Cliffs in 1979 (14). These data suggest that nearly all
crabs and hogchokers, and substantial percentages of other major
species, are not directly killed by impingement. Similar mortality
data are not available for other meoshaline plants, where screens are
operated differently from those at Calvert Cliffs. However, the
Calvert Cliffs data do suggest that impingement totals at all mesoha-
line plants do not necessarily represent numbers of fish lost to the
ecosystem.

The implications of impingement losses to the Chesapeake Bay ecosystem
and its fisheries were discussed in detail in the last CEIR (3).
Because the nature of impingement at these mesohaline power plants has
remained similar to that reported and discussed in the last CEIR, the
significance of impingement as presented there remains the same: the

IV-13

Table IV-3. Estimated Annual Total Impingement by Species at Three Power Plants in
Mesobaline Waters (Calvert Cliffs, Chalk Point, Morgantown).

1976 (a) 1976 1979 (b)

PeTcent Percent
Species Number of Total Number of Total
Atlantic Menhaden(c) 10766p671 39 8969557 32
Spot (G) 1,8210367 40 4249632 is
Hogchoker 27S,427 6 3509518 13
Bay Anchovy 135,9543 3 3169629 11
Atlantic Croaker(c) 1113-901 3 44t2S2 2
White Perch 106,110 2 140P705 5
Others 3189632 7 608t743 22

TOTAL FISH 4PS3596Sl 100 2)7829036 100

Crabs IP8200977 200360427

(a) Data reproduced from the 1978 CEIR and are primarily from 1976.
(b) Excludes data used under (a); Calvert Cliffs data from 1979, all months (14);
Chalk Point data from 1978, no data from January, February, and October (23,3S);
Morgantown data from May 1976 to May 1977 (17).
(C) Predominantly juveniles.

NMI ON 111111 1 1 1

M 'M 'M 'M "M ''M m 'M 'm 'M "M 'M "M M 'm "M

Table IV-4. Estimated Annual IHpingement at Baltimore-Area Power Plants (1978-1979);
Number of Individuals.

Species Gould St. (a) Riverside (b) Wagner(c) Total Percent

Spot 745 176 554@151 555,072 54

Atlantic Menhaden 2,982 34,267 244,666 281,915 27

Atlantic Croaker 9,402 21,05S 49,439 79,896 8

Gizzard Shad 3,786 6,758 20,966 31,510 3
Ln Atlantic Silverside 223 414 21,230 21,867 2

White Perch 287 516 12,723 13,526 1

Other 686 2,S16 40,752 43,954 5
-100
Blue Crab 6,348 9,241 430,045

(a) Data from Ref. 31
(b) Data from Ref. 32
(c) Data from Ref. 30

species comprising most of the impingement total are ubiquitous and
abundant in the mesohaline zone; juveniles of all species dominate in
the impingement totals; and no changes in fish density or community
composition in the vicinity of these plants have been observed. Thus,
impingement losses appear to be too small to alter significantly the
size of Bay populations of affected species.

Table IV-5
Percent Survival and Percent Loss of Equilibrium (LOE)
of Major Fish Species Impinged at Calvert Cliffs in 1979

Percent Percent
Species Survival LOE

Atlantic Menhaden 49.27 1.41
Spot 87.34 0.14
Hogchoker >99.00 0.0
Bay Anchovy 66.82 2.66
Atlantic Croaker 3.81 1.04
White Perch 73.08 11.54
Blue Crab >99.00 0.0

Data from Reference 14.

Discharge Effects and Habitat Modification

The maximum radial extent of the 20C excess temperature isotherm at
Calvert Cliffs, with Units 1 and 2 both operating, waq 2.3 km, and the
areas enclosed by the isotherm did not exceed 50 x 104 M2 on 14 of the
17 occasions when surveys were made' (20). Some depletion of zoo-
plankton was noted near the plant, but it appeared to be attributable
to in-plant entrainment rather than to thermal plume effects (15). No
near-field effects on phytoplankton were observed during 2-unit ope-
ration (15). Although discharge effects on benthos as a result of
bottom scouring have continued to be observed, in many instances the
induced changes have resulted in increases in population biomass (15).
Some benthic species near the plant have increased in abundance, pos-
sibly due to organic enrichment of the sediments caused by mortality
of entrained plankton. Occasionally, higher copper content was
observed in oysters in the immediate vicinity of the discharge during
2-unit operations, but densities of oysters here are relatively low
and the area is not regularly fished (15). No plant effects on the
feeding behavior of fish in the discharge area have been observed. No
plant effects on distribution, abundance, or condition of fish in the
discharge vicinity have been discerned (15).
At Morgantown the thermal plume as [email protected] the 20C isotherm was
generally about 0.1 x 1 4 to 0.6 x 10 M2 in size, and occasionally
was as great as 32 x 10@ M2. Morgantown findings are consistent with

1 lxlo4 m2 2.5 acres.

IV-1 6

Calvert Cliffs results. No significant influence of the thermal dis-
charge has been found (17).

Of the three largest mesohaline power plants, Chalk Point has the
greatest potential for causing discharge effects, because the Patuxent
estuary on which it is sited is shallow and has relatively low flows.
The 24-hour average radial extent of the 20C excess temperature iso-
therm was 1.98 km, but lower excess temperatures could be detected
over a broad portion of the estuary (36, 37, 38, 39). The area of
bottom covered by the 10C excess temperature isotherm extends as far
as 6 km upstream and downstream of the plant (40). Studies conducted
in the 1960's revealed some plant discharge effects. Both erosion of
copper from condenser tubes and uptake by oysters of copper discharged
from the plant was found. The conditions that caused the release of
copper were later corrected by changing the condenser material (41).
Large concentrations of fish have appeared in fall and winter in the
discharge canal and now supports an intensive sport fishery there.
Large kills of fish and crabs in the discharge canal, attributed to
accidental excessive discharge of chlorine were reported in the 1960's
(18, 42). Similar kills have not been reported in recent years.

The recent studies on phytoplankton and zooplankton (already discussed
in the Entrainment section), revealed some inconsistently ocurring
near-field plant effects on these trophic groups. The effects are
probably attributable more to entrainment losses than to habitat mod-
ifications caused by plant discharges.

In a 1979 study (40), the geographic distribution of species of ben-
thic organisms showed no deleterious plant effects. Rather, densities
of organisms in the plant vicinity often were 4 to 10 times higher
than at upstream and downstream reference stations, possibly due to
organic enrichment resulting from settling of planktonic organisms
killed by entrainiment. Fish studies have shown that distributions and
feeding behavior of some species are influenced by plant operations
(43). The significance of these non-lethal effects on fish stocks has
not yet been determined, but they are likely to be inconsequential.

Baltimore harbor plants are situated on relatively small water bodies
and exert substantial effects on the thermal regimes of these water
bodies. The maximum radial extent of the 20C isotherm averages 0.2 km
at Gould Street (31), 0.3 km at Riverside4(33) and 2.1 km %t yagner
(30). Average areas enclosed are 26 x 10 m and 110 x 10 m for
Riverside and Wagner, respectively (30, 31). Plumes at all three
plants are strongly influenced by wind, and wind events often deter-
mine the length of time during which elevated temperatures will exist
in a given location. Five to ten percent of the surface of Baltimore
harbor appears to be affected by the thermal plumes of these three
plants.

Near-field studies at Baltimore harbor plants are currently being con-
ducted under funding from PPSP and BG&E. No data from those studies
are yet available.

IV-17

When the results of studies at all mesohaline plants are considered, a
picture emerges that indicates a low probability of cumulative impact on the
mesohaline environment. Although plankton entrainment losses have been
measured from time to time at several of the power plants, there is no con-
sistent occurence of measurable plankton depletion in the waters around the
plant. This lack of consistent effects is probably due to the high repro-
duction rate of the plankton, and suggests that there is no cumulative in-
fluence due to plankton entrainment. Since no important commercial or recre-
ational species spawn in this habitat, entrainment losses of ichthyoplankton
have little economic significance. Localized effects on benthic organisms,
including shellfish, are sometimes evident. These effects have no signi-
ficance beyond the immediate discharge areas. A comparison of recent studies
with the studies described in the previous CEIR published 2 years ago show no
first-time or increased effects on any trophic level.

Current studies at Chalk Point and the Baltimore harbor plants will
permit a more definitive assessment of impact at those sites.

Tidal Fresh - Oligohaline

These habitat zones have significant value as the major spawning area of
anadromous fish, which as a group have accounted, on the average, for about
65% of the total monetary value of commercially harvested finfish from 1972
to 1976 in Maryland. Since anadromous spawning occurs in the spring, the
plants of most concern are those in the tidal fresh-oligohaline zone at that
time, particularly those sited near striped bass spawning areas. However,
the zone also serves as a nursery area for many important fish species year
around.

Seven plants use oligohaline waters for cooling purposes in the spring
(Table IV-2). At six of these seven plants, salinity is in the mesohaline
range during most of the remainder of the year. Impacts associated with
those plants (Chalk Point, Morgantown and the Baltimore area plants) was
discussed in the preceeding mesohaline section. Of these plants only Mor-
gantown is situated near waters of sufficiently low salinity to be of in-
terest as far as striped bass impact is concerned.

The remaining plants to be discussed here are Possum Point, Vienna and
Crane. Possum Point, on the Potomac, and Vienna, on the Nanticoke, are both
in the vicinity of major striped bass spawning areas. Crane, though located
on tidal fresh-oligohaline waters, does not impact on a striped bass spawning
area.

0 Entrainment

A detailed, in-plant phytoplankton entrainment study at Crane is cur-
rently being conducted under BG&E funding. Samples taken at intake
and discharge locations during nearfield studies (33, 44, 45, 46)
showed no discernable loss of either zooplankton or phytoplankton, and

IV-18

suggest an enhancement of phytoplankton productivity. Entrained zoo-
plankton from Seneca Creek may be enhancing zooplankton populations in
the discharge area (47). Entrainment of zooplankton and phytoplankton
of the Vienna plant will be 0.20 - 0.25 percent of the organisms
moving past the plants when Unit 9 comes on line (see below) (53).
Such losses will have negligible effects.

Results of studies conducted in 1979 indicate that relatively low num-
bers of ichthyoplankton species and individuals are entrained at the
Crane Station. Entrainment was highest in summer, when bay anchovy
and naked goby were the dominant species. Other commonly entrained
species were white perch and tidewater 3silversides (48). Highest
densities entrained were 6 larvae/100m of cooling water.

Possum Point is sited on the striped bass spawning grounds in the
Potomac estuary. Recent work indicates that.the plant entrains a
maximum of about 2 percent of the striped bass larvae produced
annually in the Potomac. Morgantown is located 20 km downstream of
the center of the striped bass spawning area in the Potomac. Few eggs
or larvae (less than 0.01% of Potomac production) are entrained (49,
50, 51). Consequently, the operation of this plant has no significant
impact on the striped bass population. Vienna is in the midst of the
spawning area in the Nanticoke. With the retirement of unit 5, 6 and
7 (68 MW total) using once-through cooling (withdrawal 3.6 m sec)
only unit 8 (162 MW) using a cooling tower (withdrawal 0.12 m /sec
from the discharge of units 5, 6, and 7) remains. Delmarva Power and
Light has proposed a 500- 9 expansion (Unit 9, 1988 completion date)
which will withdraw 0.42 m /sec for cooling and plant purposes. The
proposed intake of this unit includes a fine mesh, wedge wire screen
which is designed to minimize entrainment of fish eggs and larvae
(52). The estimated amounts oof striped bass eggs and larvae entrained
by the previously existing units have been about 8 percent (of the
Nanticoke Stock) annually from 1977 to 1979. When Unit 9 begins
operation ichthyoplankton entrainment is predicted to average 2
percent (52).

The potential impact of entrainment by a power plant on the overall
striped bass stock can be estimated by examining the contribution of
the impacted area to total spawning in the Maryland part of the
Chesapeake Bay and its tributaries. This contribution can be esti-
mated from the commercial catch records for the months (March and
April) just prior to spawning. This catch is assumed to be propor-
tional to the presence of spawning adults and hence to the spawn.
These data are summarized in Table IV-6 which shows, for example, the
Potomac River spawning constitutes about one fourth of the total
striped bass spawning in Maryland. Therefore, under our assumption, a
1 percent loss of striped bass larave in the Potomac would translate
to a 0.25 percent loss of the Maryland fisheries, and the 2 percent
loss at Possum Point translates into a 0.5 percent loss to the
Maryland fisheries. The consequences of the 2 percent loss of
ichthyoplankton at Vienna is compounded over generations (because of
local effects) and could increase the estimated local loss of adults

IV-19

to 4 percent (52) since Table IV-6 shows that the Nanticoke-Wicomico
region accounts for 12 percent of the commercial catch on the average
this loss of adults is equivalent to a loss of almost'0.5 percent of
the Maryland Bay Stock. The total potential loss to the Maryland
striped bass population from the operation of these power plants will
thus be I percent. The reported commercial catch in Maryland averaged
4.6 million lbs. annually from 1960 to 1975 (52), and the average
annual sports catch is estimated to roughly equal the commercial catch
(54). Consequently the 1 percent loss of striped bass ichtyoplankton
through entrainment is equivalent to an annual loss of about 92,000
lbs. of striped bass based on the 1960 to 1975 average. In recent
years the Maryland striped bass catch has declined substantially
compared to the 1960-1975 average. Therefore, the calculated loss of
striped bass in pounds will be correspondingly less.

For the tidal fresh-oligohaline plants the conclusion is that cumula-
tive impacts due to zooplankton and phytoplankton entrainment at olig-
ohaline plants have not been detected. Impact is unlikely because of
the high reproduction rates of these groups of organisms. Cumulative
impact of all plants in Maryland on striped bass due to entrainment of
eggs and larvae would be about 1.0 percent of annual landings.
0 Impingement

Impingement at Chalk Point, Morgantown, and the Baltimore area plants,
where waters are oligohaline for only a few months in the spring, was IF
discussed in the previous section on mesohaline plants. Impingement of
juvenile and adult fish at Vienna is negligible (53).

Impingement data from Crane have only recently become available. The
Crane data from 1978-1979 presented in Table IV-7 can be contrasted to
that for mesohaline plants present in Tables IV-3 and 4. Atlantic men-
haden and spot are dominant at both sets of mesohaline plants, while
white perch replace spot as a dominant species at Crane. It is inter-
esting to note that the majority of white perch recorded as impinged
at mesohaline plants (Table IV-3) was taken at Morgantown in the
spring, when waters at that site were actually oligohaline (16).
Thus, white perch are demonstrated to be primarily an oligohaline kh,
species. Other species differences are evident between impingement at
the two groups of mesohaline plants: gizzard shad and silversides are
major components of impingement at the Baltimore plants whereas they
are not prominent at the other mesohaline plants. This result may
reflect the fact that the Baltimore plants are located on lower
salinity mesohaline water. The,data discussed here s .uggest that con-
sequences of impingement at oligohaline plants are similar to those of
impingement at mesohaline plants: the major species impinged are
ubiquitous and abundant throughout Maryland tidal waters; impingement
losses appear too small to have a detectable effect on stock sizes of
affected species. For example, white perch are impinged in substantial
numbers and have important commercial and recreational value. This
species is, however, abundant throughout Maryland (2),@, and annual
impingement losses are very small relative to the total commercial and
recreational harvest. Thus, stocks are not likely to be affected.

IV-20

M mm M M = M W'm = = = M = M M

Table IV-6. Commercial Catch of Striped Bass in March and April by Region in the
Maryland Portion of the Chesapeake Bay, by Percent.

1972 8.67 30.76 4.61 S.76 10.02 2.37 2.22 IS.87 19.67
1971 10.13 27.24 2.39 S.66 10.S8 0.8s 4.07 13.1S 25.87
1970 9.37 34.86 5.18 4.90 10.84 0.99 2.65 8.81 22.14
1969 17.17 33.66 1.63 4.18 9.24 0.86 3.27 8.27 21.67
1968 12.04 24.20 1.76 3.69 6.40 1.2S 2.09 11.61 36.74
1967 9.54 29.58 1.36 3.31 7.00 0.82 2.18 11.4S 34.7S
1966 6.03 22.91 2.73 2.84 10.37 1.65 1.07 19.34 33.03
F

Averages 10.73 29.SO 2.80 4.30 9.10 1.25 2.49 12.28 27.46

1 1 1 1 1 1

From Ref . 3

Table IV-7
Estimated Annual Impingement at Crane Located in
Tidal-Fresh Oligohaline Waters (1978-1979)

Species Number Percent

Atlantic Menhaden 246 353 50
White Perch 148:941 30
Spot 19,118 4
Gizzard Shad 14*255 3
Atlantic Silverside 1,022 <1
Atlantic Croaker 78 <1
Other 67,124 13

Data from Reference 48.

Discharge Effects and Habitat Modification

Thermal plumes at Vienna were sufficiently small that discharge ef-
fects can be considered negligible (55). Studies at Crane in 1979 and
1980 have documented the extent of influence of the plant's thermal
discharge (56). The 24-hr. averge radial extent of the 20C excess
tempera ure isotherm at that plant is 1.8 km, and an average area of
90 x 10@ M2 of river bottom is enclosed by that isotherm. Because of
the relatively small dimension of the water body into which the dis-
charge enters, (Saltpeter and Dundee Creeks), much of the creek system
is thermally influenced. Thus, potential for thermal discharge ef-
fects is higher than in the case of the mesohaline plants.

At Crane, studies demonstrated that under extreme summer temperature
conditions, the temperature in the immediate discharge area exceeded
lethal limits for some zooplankton and inhibited photosynthesis by
phytoplankton (44). Decreases in phytoplankton productivity and
alternations in zooplankton community structure in late summer were
observed in the discharge area (44, 46). However, during other
periods phytoplankton productivity in the thermally affected area was
enhanced and no effects on zooplankton abundances were evident (33,
45, 46). No major deleterious effects on submerged aquatic vegetation
in the discharge area were noted (57, 58, 59). Vegatation growth
appeared to be enhanced during some periods.

Benthic studies suggest that the brackish-water clam may be protected
during cold winter periods by the thermal discharge, resulting in
population enhancement (60, 61, 62). A summertime decrease of about
30 percent in density of an amphipod Lel)tocheirus in the discharge
area was observed in 1979 (44). Several species in the discharge area
also showed greater population build-ups in Spring 1980, suggesting
accelerated growth or development (62).

Finfish studies in summer showed that white perch and, to some extent,
spot were attracted to the plume (63).In Spring white perch avoided
the plume region, whereas pumpkinseed were attracted to it. In a

IV@22

follow-up extended summer study (64) white perch did not show
preference for the discharge region. The same study also found that
low numbers of spot occurred in shallow creeks as well as in the dis-
charge areaj suggesting a generalized creek effect.

One effect which might be construed as cumulative, though not neces-
sarily as deleterious, is a change in the zooplankton and benthic
communities in the Crane discharge area. As the plant takes higher
salinity water from the intake area and discharges it into lower sa-
linity receiving waters, it also transports an oligohaline fauna into
a location which, without the plant, would probably harbor a fresh-
water fauna (47, 62). This higher salinity water also provides a
habitat more suited to oligohaline benthic and planktonic species
during certain times of the year.

Riverine

The only Maryland steam electric stations located on riverine waters are
R.P. Smith and Dickerson, both on the Potomac River. Each uses, at times, a
substantial portion of average river flow for cooling purposes. The plants
are relatively old, of low to medium generating capacity, and located in
areas inhabited by typical warm water "riverine" biological communities (65).
Conowingo Dam on the Susquehanna River is the only large hydroelectric gen-
erating station in Maryland. Significant stocks of fish, both comerically
and recreationally important, inhabit the Susquehanna River below the dam.

Entrainment

Limited entrainment data at the R.P. Smith plant are available from
studies conducted in 1978 (66). Organisms primarily entrained were
sucker and carp larvae, midges, and gammarid amphipods. Rumbers en-
trained during the 3-month study period were very low, but the studies
were not done during periods when high ichthyoplankton abundances were
expected.

Entrainment at Dickerson during a 12-month study was an estimated 48
million fish eggs and larvae and one million juveniles which repre-
sents approximately 10 percent of the organisms drifting past the
plant (67). Species entrained were primarily carp, spottail shiner,
and spotfin shiner. Since most of these entrained species are nest
builders or have demersal eggs, drifting eggs susceptible to entrain-
ment represent only a small percentage of the total spawn. Maximum
local population loss of 4.1 and 2.3 percent are predicted for spot-
tail shiner and redbreast sunfish, respectively (68). Thus, localized
entrainment effects will not alter river populations of these forage
and rough species.

Very few eggs and larvae of sport fish were entrained at either plant;
thus, direct entrainment effects on sport fish populations would be
negligible. The species entrained are ubiquitous in the Potomac and
spawn over the entire freshwater reach of the river in Maryland.

IV-23

Impingement

Very few fish (a total of about 300) were impinged at R. P. Smith
during studies in 1978 (66). Golden redhorse and shiners dominated,
and 72 percent of the annual total was taken in June. Impingement at
this level is negligible in terms of effects on fish populations. P,
Other 1978 studies showed an estimated annual total of about 256,000
fish impinged at Dickerson (67). Primary species were spottail
shiner, channel catfish, sunfish (several species), spotfin shiner,
and smallmouth bass. Impingement was highest in winter and spring.
The shiners are important forage species; the rest are important
sportfish. With no data available from periods prior to plant opera-
tion, an assessment of whether the plant has had a deleterious impact
on these fish stocks is difficult to make. Detection of effects on
populations near the plant is made more difficult by the fact that
fish are seasonally attracted and repelled by the plant's thermal
plume (67).

Discharge Effects and Habitat Modification

Data from thermal plume surveys at both Dickerson and R. P. Smith have
become available since publication of the 1978 CEIR (3). At
Dickerson, the 20C excess temperature isotherm extended downstream
more than 20 km and entended across the river approximately two thirds
of its width during summer, low-flow conditions (67). The thermally
influenced area is largest during summer and fall.

Discharge effects on insects were noted in the immediate plant vicin-
ity in studies conducted in 1977. Decreases in abundance, numbers of
species, and growth rates were found (67). Effects on fish were dif-
ficult to assess because of the seasonal change in response of many
species to the thermal plume; avoidance during summer and fall, and
attraction in winter and spring. Although literature data suggest
that thermal conditions in summer are often deleterious for growth and
reproduction of several species, no clear evidence of cumulative,
adverse impact of river-wide stocks of any species is apparent in the
data collected. Discharge effects apparently are localized (about 2.5
km in extent), and the area of greatest impact is not particularly
critical for any of the fish species present. ---

The size of the thermal plume at R. P. Smith depends on river flow and
meteorological conditions and is highly variable (66). The maximum
downstream extent of the 20C excess temperature isotherm is about 7 km
and the same isotherm seldom extends further than 30 m across the
river about one third of the width from the Maryland shore. Discharge
effects on periphyton and benthic organisms (primarily insects) have
been observed to be inconsistant and tend to be small (69, 70, 71).
The riverine habitat is very heterogeneous in the vicinity of the
plant, and communities at different unaffected stations often differ
from each other. This situation complicates the evaluation of dis-
charge effecs. However, the data do not suggest the existence of a
well-defined area of depleted or modified biota in the discharge
vicinity. This, in turn, suggests the absence of significant cumula-
tive impact on periphyton and benthos. Fish distribution is

IV-24

influenced by the thermal plume. Golden redhorse, the dominant
species in the area, is concentrated in the plume in winter. Summer
avoidance was not evident for any species when plant discharge tem-
perature was low (70). During one summer period with high plant
discharge temperature resulting in near-field temperatures of 400C, no
live finfish were taken in the discharge plume. If localized distri-
bution effects are discounted, fish data show no major differences
between the fish community inhabiting the general region of the river
near the plant and communities inhabiting unaffected areas upstream
and across-stream. Those data suggest the absence of significant cumu-
lative impact on fish.

Conowinao Dam - Hvdroelectric Facility

The manner in which this hydroelectric facility can impact an aquatic
ecosystem is entirely different from that in which nuclear or fossil fuel
plants create effects. Although entrainment of organisms through the turbines
of the facility may occur, the more important modes of effect relate to the
facility's modification of flow regimes, water oxygen content, and habitat
area.

The Conowingo Dam is operated as a peaking power generating unit, with
fullest operation scheduled for weekday afternoons. Generation is reduced or
stopped at night, and frequently also on weekends, to allow the reservoir
level to rise. The generating station has seven 36-MW turbines and four
56-MW turbines. The addition of the four larger turbines in 1967 increased
the maximum water use from 45,000 efs to 85,000 cfs. By comparison, median
monthly-average flows of the Susquehanna River range from 7,000 cfs (August)
to 65,000 cfs (March).

Several water flow, water quality, and fisheries problems in the
Susquehanna are thought to be related to Conowingo's operating patterns.
Fluctuations in water levels below the dam caused by the mode of operation of
the turbines periodically expose large aras of river bottom to the air.
Benthic biomass may be reduced in these dewatered areas thus decreasing food
availability for some resident fish species. Additionally, demersal fish eggs
may become stranded and exposed to air as the water level falls after a flow
reduction.

Water temperature, and, to some extent, dissolved oxygen (DO) concentra-
tions in the river below the dam seem to reflect conditions near the bottom
of Conowingo Pond. Although classical thermal stratification has never been
observed in the pond, DO concentrations decrease with depth from saturation
values at the surface to less than 2 ppm near the bottom (23 m below sur-
face). Intake structures for the turbines draw water from 20 m below the
surface, thus releasing this low DO water into the river.

Oxygen problems also have occurred in the river below the dam during
periods when no water is being released. Biota in isolated pools consume
available oxygen and can create low DO conditions. The danger of fish kills
or other biological impacts are most severe in summer when river flow is near
its annual minimum and prolonged shutdowns are required to refill the reser-
voir. At the same time, water temperature is high (approaching 3000,
resulting in a reduction in its DO capacity. These problems are exacerbated

IV-25

during periods when large numbers of fish are present below the dam, such as
during anadromous spawning runs. The high fish densities accelerate the rate
of oxygen depletion. Such events led to the repeated occurrence of resident
and anadromous fish kills below Conowingo Dam in the 1960's.

These problems and the recent dramatic declines in upper Chesapeake Bay
landings of American shad and other anadromous species (72), prompted the
Maryland Department of Natural Resources to initiate studies through the
Power Plant Siting Program to obtain data needed to assess these problems and
develop solutions. The information will also be submitted during the Con-
owingo relicensing proceedings under the Federal Energy Regulatory Commission
(FERC).

Some preliminary findings of these studies are:

* At high discharge volumes, the DO concentration of the river below the
dam depends on that of the bottom layer of the reservoir (which is
discharged through the dam turbines). At low flows, downstream DO
distribution is patchy and is heavily influenced by local metabolic
processes, including the unpredictable aggregations of fish which
might cause localized anoxic conditions.

' In 1980, the population size of shad in the Upper Bay is below 10,000
adults, blueback herring is below 200,000 adults, and alewife and
hickory shad populations are too small to estimate.

- Benthic invertebrate populations are extremely sparse on substrates
which periodically dewater as a result of the present discharge pat-
tern.

* In the Upper Bay, analyses of historical fisheries data have iden-
tified a weak relationship of shad landings to the general operating
pattern of the dam (73).

Because of the absence of detailed historical biological data in the
Susquehanna below Conowingo, a complete quantitative evaluation of the cumu-
lative effects of Conowingo operations on the Susquehanna River ecosystem is
not presently possible. Results of the on-going studies will provide data to
further address this question.

IV-26

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IV-27

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IV-28

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IV-29

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IV-30

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the Maryland Power Plant Siting Program. 1974

50. Potomac Estuary Fisheries Study, Ichthyoplankton and Juvenile Investi-
gations. Prepared by Chesapeake Biological Laboratory, University of
Maryland for the Maryland Power Plant Siting Program. 1975

51. Potomac Estuary Fisheries Study, Ichthyoplankton and Juvenile Investi-
gations. Prepared by Chesapeake Biological Laboratory, University of
Maryland for the Maryland Power Plant Siting Program. 1976

52. Portner, E.M., and L.C. Kohlenstein. Prediction of Entrainment Impinge-
ment Impact for Striped Bass Eggs and Larvae by the Proposed Vienna
Unit No. 9. Applied Physics Laboratory, the Johns Hopkins University.
PPSE 8-1. 1979

53. Otto, R.G., M. VanDeusen, and L.S. Kaufman. Prediction of Biological
Impacts Associated with Expansion of Vienna Steam Electric Station.
Chesapeake Bay Institute, the Johns Hopkins University. PPSE 8-11.
1980

54. Kohlenstein, L.C. Aspects of the Population Dynamics of Striped Bass
saxatilis) Spawned in Maryland Tributaries of the Chesapeake Bay.
Applied Physics Laboratory, the Johns Hopkins University. PPSE T-14.
1979

55. Carter, H.H., and R.J. Regier. The Distribution of Excess Temperature
from the Vienna Generation Station on th Nanticoke River. Technical
Report 90, Chesapeake Bay Institute, the Johns Hopkins University.
1975

56. Binkerd, R.C., H.G. Johnston, and J.K. Comeau. Physical Impact Evalua-
tion of the Discharge of Heated Water from the C.P. Crane Generating
Station. Prepared by Aquatec, Inc., South Burlington, VT, for
Maryland Department of Natural Resources, Power Plant Siting Program.
1978

IV-31

57. Nichols, Barry L., Richard R. Anderson, and William C. Banta. Evaluation
of the Effect of the Thermal Discharge on the Submerged Aquatic Vege-
tation and Associated Fauna in the Vicinity of the C.P. Crane Genera-
ting Station. Interim Report. Prepared by Science Applications,
Inc., McLean, VA, for Maryland Department of Natural Resources, Power
Plant Siting Program. 1979

58. Nichols, Barry L., Richard R. Anderson, and William C. Banta, Eddy J.
Forman, and Scott H. Boutwell. Evaluation of the Effect of the
Thermal Discharge on the Submerged Aquatic Vegetation and Associated
Fauna in the Vicinity of the C.P. Crane Generating Station. Final
Report. Prepared by Science Applications, Inc., McLean, VA, for
Maryland Department of Natural Resources, Power Plant Siting Program.
1979

59. Nichols, Barry L., Richard R. Anderson. Evaluation of the Effect of the
Thermal Discharge on the Submerged Aquatic Vegetation Growth. Pre-
pared by NTSC Technical Services, Falls Church, VA, for Maryland
Department of.Natural Resources, Power Plant Siting Program. 1980

60. Jordan, Robert A., Charles E. Sutton, and Patricia A. Goodwin. A Survy
of the Late Summer Benthos Community in the Vicinity of the C.P.Crane
Generaring Station. Prepared by Virginia Institute of Marine
Science. Gloucester Point, VA, for Maryland Department of Natural
Resources, Power Plant Siting Program. 1980

61. Jordan, R.A., P.A. Goodwing, and C.E. Sutton. C.P. Crane Power Station
Benthos Study Interim Report. Part I: Benthic Macroinvetebrate
Population Distributions in Relation to the Power Plant Thermal Dis-
charge: April, June and September 1979. Part II: Trace Metals in
Sediment and in Tissues of the Brackish Water Clam, Rangia cuneata,
September 1979. Prepared by Virginia Institute of Marine Science,
Gloucester Point, VA, for Maryland Department of Natural Resources,
Power Plant Siting Program. 1980

62. Jordan, R.A., C.E. Sutton, and P.A. Goodwin. Benthic Macroinvertebrate
Population Distributions in Relation to the C.P. Crane Power Plant
Thermal Discharge. Final Report. Prepared by Virginia Institute of
Marine Science, Gloucester Point, VA, for Maryland Department of
Natural Resources, Power Plant Siting Program. 1980

63. Evaluation of C.P. Crane Generating Station Thermal Discharge Effects on
the Finfish Community. Final Report. Prepared by Texas Instruments,
Inc., Dallas, TX for Maryland Power Plant Siting Program. 1980

64. Evaluation of C.P. Crane Generating Station Thermal Discharge Effects on
the Finfish Community. Summer 1980. Prepared by Texas Instruments,
Inc., Dallas, TX for Maryland Power Plant Siting Program. 1981

65. Power Plant Site Evaluation: Aquatic Biology. Final Report: Dickerson
Site. Prepared by Ecological Analysts, Inc., Baltimore, MD, for
Maryland Department of Natural Resources. 1974

IV-32

66. R. Paul Smith Power Station Thermal Discharge and Impingement/Entrainment
Studies, Volumes I and Il. Prepared by Energy Impact Associates,
Inc., Pittsburg, PA, for Potomac Edison Power Company. 1980

67. A 316 Demonstration in Support of the Application for Alternate Effluent
Limitations for the Potomac Electric Power Company, Dickerson Steam
Electric Station. 3 Volumes. Prepared by the Academy of Natural
Sciences of Philadelphia.

68. Summers, J.K. and F. Jacobs. Estimation of the Potential Impact on
Spawning and Nursery Areas near the Dickerson Steam Electric Station.
Martin Marietta Corporation, PPSP-D-81-1. 1981

69. Evaluation of R. Paul Smith Power Station Thermal Discharge Effects on
Fish and Benthic Communities. Prepared by Texas Instruments, Inc.,
Dallas, TX for Maryland Department of Natural Resources. Final Report
Contract No. P40-80-2. 1980

70. Evaluation of R. Paul Smith Power Station Thermal Discharge Effects on
Fish and Benthic Communities. Spring 1980. Prepared by Texas
Instruments, Inc., Dallas, TX for Maryland Department of Natural
Resources. 1980

71. Evaluation of R. Paul Smith Power Station Thermal Discharge Effects on
Fish and Benthic Communities. Prepared by Texas Instruments, Inc.,
Dallas, TX for Maryland Department of Natural Resources. 1981

72. Dwyer, R.L., G.F. Johnson, and T.T. Polgar. Historical Relationships
Between Anadromous Fish Landings in the Upper Chesapeake Bay and
Stock-dependent and Environmental Factors. Prepared by Martin
Marietta Environmental Center for Maryland Power Plant Siting Pro-
gram. 1980

IV-33

CHAPTER V

RADIOLOGICAL IMPACT

Nuclear power plants in the United States are licensed and regulated by
the U.S. Nuclear Regulatory Commission. Conditions imposed in the operating
licenses for each plant permit the routine discharge of low levels of radio-
activity to the environment. These releases must be within the guidelines of
the federal regulations contained in 10 CFR 50 Appendix 1, and are restricted
by limits on the radiation doses received offsite by a hypothetical maximum
exposed individual (Table V-1). Annual total body doses cannot exceed 3 mrem
per reactor for the aqueous pathway and 5 mrem.per reactor for the atmos-
pheric pathway. Aqueous pathway doses are received through ingestion of
radioactivity in water and seafood, and exposure to contaminated water and
sediments. Atmospheric pathway doses result from inhalation of gaseous and
particulate radioactivity and ingestion of radionuclides deposited on, or
assimilated by, terrestrial vegetation and animals.

The operator of each nuclear plant is required to conduct environmental
monitoring to assure that dose criteria are met. In addition to these pro-
grams, state and federal agencies conduct monitoring activities to assure
compliance. These radiological monitoring programs are designed to determine
actual radionuclide concentrations in environmental media in order to provide
estimates of the ultimate dose to man.

Environmental Studies and surveillance activities which define the im-
pact of releases to the atmosphere are:

*Estimation of radionuclides discharged - Samples are collected from
in-plant decay tanks and main vent filters to determine radionuclide
concentrations in gases prior to release.

'Analysis of air samples - Air is sampled continuously and sample com-
posites are analyzed weekly to detect radioiodine and radionuclides in
air particulates.

-Analysis of precipitation - Precipitation is sampled continuously to
detect radionuclides which wash out with airborne particulates.

*Analysis of soil and vegetation - These analyses indicate terrestrial
radionuclide concentrations derived from deposition of atmospherically
released radionuclides.

-Analysis of milk - This analysis indicates 1-131 concentrations in
dairy products as a result of animal ingestion of atmospheric iodine
deposited on pasture grass.

*External radiation measurements Thermoluminescence dosimeters (TLD)
are used to provide an assessment of ambient dose levels and exposure
rate variation.

V-1

Table V-1

10 CFR 50 Appendix I
Limiting conditions for operation of light-water-cooled
nuclear power reactors to keep radioactivity in effluents
to unrestricted areas as low as is reasonably achievable.

Appendix I(a5 Point of Dose
Type of Dose Design Objectives Evaluation

Liquid Effluents
Dose to whole body 3 mrem/yr per unit Location of th @ighest
from all pathways dose offsitetb

Dose to any organ 10 mrem/yr per unit Same as above
Gaseous Effluents(c)
Gamma dose in air 10 mrad/yr per unit Location of thq ighest
dose offsiteld@

Beta dose in air 20 mrad/yr per unit Same as above
Dose to whole body 5 mrem/yr per unit Location of th @b @ighest
of an individual dose offsitel

Dose to skin of an 15 mrem/yr per unit Same as above
individual
Radioiodines and Particulates(e) Released to the Atmosphere
Dose to any organ 15 mrem/yr per unit Location of thTf @ighest
from all pathways dose offsite

(a) Evaluated for a maximum exposed individual.
(b) Evaluated at a location that is anticipated to be occupied during
plant lifetime, or with respect to such potential land and water
usage and food pathways as could actually exist during the term of
plant operation.
(c) Calculated only for noble gases.
(d) Evaluated at a location that could be occupied during the term of
plant operations.
(e) Doses due to carbon-14 and tritium intake from terrestrial food
chains are included in this category.
(f) Evaluated at a location where an exposure pathway and dose receptor
actually exist at the time of licensing. However, if the applicant
determines design objectives with respect to radioactive iodine on
the basis of existing conditions and if potential changes in land and
water usage and food pathways could result in exposures in excess of
the guideline values given above, the applicant should provide reson-
able assurance that a monitoring and surveillance program will be
performed to determine: (1) the quantities of radioactive iodine
actually released to the atmosphere and deposited relative to those
estimated in the determination of design objectives; (2) whether
changes in land and water usage and food pathways which would result
in individual exposures greater than originally estimated have occur-
red; and (3) the content of radioactive iodine in foods involved in
the changes, if they occur.

V-2

Those studies which define the impact of liquid effluent releases are:

'Estimation of radionuclides discharged - Samples from in-plant monitor
tanks and steam generator blowdown are analyzed to determine radio-
nuclide concentrations in liquid inventory prior to release.

'Analysis of Bay water - Samples of Chesapeake Bay water are analyzed to
determine actual radionuclide concentrations.

*Analysis of Bay fishery - Samples of various species of finfish and
shellfish are collected and analyzed to measure radionuclide concen-
tations and predict dose to consumers.

*Analysis of other environmental biota - Samples of submerged aquatic
vegetation and lower trophic-level fauna are analyzed to determine
radionuclide concentrations within the food chain.

*Analysis of sediments - Samples are analyzed to determine temporal and
spatial distributions of sediment radionuclide concentrations.

The Maryland Power Plant Siting Program (PPSP) is responsible for
assessing the radiological impact of nuclear power plants affecting Maryland.
Those currently considered are Calvert Cliffs on the Chesapeake Bay in Mary-
land, and Peach Bottom and Three Mile Island on the Susquehanna River in
Pennsylvania. Determining power plant radiological impact is complicated by
the fact that the plant increment must be discerned from environmental con-
centrations of natural and weapons-test fallout radioactivity which already
exist, or, in the case of weapons-test fallout, may be introduced during the
monitoring period. Attributing a radiological effect to a specific plant may
also be difficult under conditions where impacts may overlap. Such an in-
stance occurred as a result of the Three Mile Island accident.

This chapter presents the PPSP's evaluation of the environmental impact
on Maryland of radioactivity released by Calvert Cliffs, Peach Bottom and
Three Mile Island during 1978-1980. This assessment is based on monitoring
programs conducted by the individual utilities, the Maryland Department of
Health and Mental Hygiene (DHMH), and the PPSP. Described herein are the
monitoring programs conducted by the various agencies, the effluents released
by each plant, and the actual distribution of radioactivity in the environ-
ment. Doses to man via the atmospheric and aqueous pathways are calculated.
Comparisons with natural background doses, predictions made in Final Envi-
ronmental Impact Statements, and operating license requirements are made
where appropriate. A brief discussion of the quantity of electricity pro-
duced, and thevastes generated by each plant is also included.

A. Calvert Cliffs Nuclear Power Plant

The Calvert Cliffs Nuclear Power Plant (CCNPP), owned and operated by
the Baltimore Gas and Electric Company (BG&E), is the only nuclear power
plant located in Maryland. Each of its two units is a pressurized water
reactor. Present ratings are 890 MWe gross each for Units I and 2 in winter,
and 860 MWe gross in summer, when discharge water temperature restrictions
may limit maximum load.

V-3

Unit I of the CCNPP, placed in commercial service on May 8, 1975, had as
of the end of 1980 produced 29,594,233 MWh gross of electrical energy. Unit
2, placed in commercial service April 1, 1977, had as of the end of 1980,
produced 22,728,967 MWh gross. Since the inception of commercial operation,
Units 1 and 2 had as of the end of 1980, achieved cumulative unit capacity
factors of 67.3% and 77.9%, respectively.

Releases to the Environment

Radionuclides discharged to the atmosphere and Chesapeake Bay by the
Calvert Cliffs Nuclear Power Plant during 1978-1980 as reported by BG&E are
given in Tables V-2 and V-3. Noble gases, which are not of significant en-
vironmental concern, comprise virtually 100% of the atmospheric releases.
Other than Sr-89, no radionuclides released to the atmosphere were detectable
in the environment during this period. Of the aquatic releases, Co-58,
Co-60, Zn-65, and Ag-110m. are the only bioaccumulable radionuclides routinely
detected in the Bay environment. Cr-51 and Fe-59, both with relatively short
half-lives (28 days and and 45 days respectively), were detected on two occa-
sions.

Environmental Monitoring Programs

The Baltimore Gas and Electric Company (BG&E), the Maryland Department
of Health and Mental Hygiene @DHMH), and the Maryland Power Plant Siting
Program (PPSP) each conduct routine radiological monitoring programs designed
to define the environmental impact of the releases described above. The BG&E
program satisfies the environmental surveillance requirements imposed in its
NRC operating license. The DHMH performs assurance monitoring to provide an
independent confirmation of the utility program. The Power Plant Siting
Program conducts a monitoring program and performs detailed investigations to
describe the actual level of impact within ecosystem components. PPSP
studies define the locational and trophic-level distribution of power plant
radionuclides in the Calvert Cliffs area of the Chesapeake Bay. The programs
conducted by the three agencies, described by sample type, collection
frequency, and type of analysis, are presented in Tables V-4, V-5, V-6a, and
V-6b.

Atmospheric and Terrestrial Radionuclide Distributions

Releases of radioactivity to the atmosphere during 1978-1980 did not
contribute measurably to offsite radiation exposure as determined by TLD
(7-11). Man-made radionuclides were, however, detected in the atmospheric
and terrestrial environment on a few occasions during the period.

Iodine-131 was detected in the atmosphere at low levels during the week
of March 20, 1978 by the utility and the State, both in the vicinity of the
plant and at farfield locations. Because of its short half life, the pre-
sence of 1-131 in the environment is indicative of a recent event, although
not necessarily a power plant discharge, since it is also produced in the
detonation of thermonuclear devices. In this case, its presence was attri-
buted to the atmospheric weapons test conducted on March 10, 1978 by the
Peoples Republic of China. Other gamma-emitting radionuclides associated

V-4

Table V-2

Total Gaseous Effluents (in Curies) Released by the
Calvert Cliffs Nuclear Power Plant as Reported by BG&E (1-6)

Radionuclide 1978 1979 1980

Tritium 1.63 5.13 27.9
Noble Gases 26800. 10200. 2960.
Halogens 0.200 0.419 0.107
Other 0.064 1.75 0.045
Total Curies 26801.894 10207.299 2988.052

Na-24 0.00000239
Ar-41 0.914 0.127 0.374
Cr-51 0.00000155 0.00000512
mn-54 0.00000395 0.0000232 0.00000183
Mn-56 0.00000906 0.00000327 0.0000205
Co-58 0.00605 0.00247 0.0185
Co-60 0.000318 0.000631
Br-82 0.0000730 0.000108 0.0000470
Kr-85 31.6 0.961
Kr-85m 62.8 35.5 7.23
Kr-87 0.00193 0.00280
Kr-88 0.0471 1.24 0.218
Rb-88 0.0566 1.57 0.0130
Sr-85 0.00919
Sr-89 0.0000599 0.0442 0.0000352
Sr-90 0.00000359 0.0859 0.0000391
Sr-91 0.0000252 0.0000426 0.00000657
Nb-95 0.00000182 0.00000450
Mo-99 0.0000805 0.00000135 0.00000110
Ru-103 0.000000700 0.000417 0.0000000951
Ru-106 0.00000408 0.00000723
Sb-124 0.00000266
Sb-125 0.00000155
Te-132 0.0000239
1-131 0.118 0.300 0.0555
1-132 0.00346 0.00765 0.00170
1-133 0.0749 0.107 0.0213
1-134 0.00270 0.00000197 0.0000238
1-135 0.00105 0.00388 0.0284
Xe-131m 12.1 1.30 6.88
Xe-133 26300. 9820. 2860.
Xe-133m 33.2 3.73 3.51
Xe-135 322. 338. 86.9
Cs-134 0.000280 0.0000226
Cs-137 0.000593 0.000306
Cs-138 0.0000934 0.00164 0.0133
Ba-139 0.00000380 0.00000505 0.00000854
Ba-140 0.0000494 0.0329 0.0000679
La-140 0.00000762 0.0000500 0.0000570
Ce-141 0.000171 0.00000700
Np-239 0.000000457

V-5

Table V-3

Total Liquid Effluents (in Curies) Released by the Calvert Cliffs
Nuclear Power Plant as Reported by BG&E (1-6)
Radionuclide 1978 1979 1980 or

Tritium 456. 514. 491.
Dissolved (a)
Noble Gases 7.91 15.6 15.8
Other 5.98 7.77 4.79
Total Curies 469.89 537.37 511.59

Na-24 0.00511
Ar-41 0.000170
Cr-51 0.770 0.638 0.737
Mn-54 0.130 0.112 0.0867
Mn-56 0.0000236 0.000659 0.00124
Fe-59 0.0593 0.0300 0.00737
Co-57 0.00271 0.00645 0.000817
Co-58 1.97 3.81 2.00
Co-60 0.462 0.325 0.441
Zn-65 0.0000651 0.0240
Kr-85m 0.000885 0.0000748 0.000179
Kr-87 0.000565
Sr-85 0.000600 0.000724
Sr-89 0.0244 0.00109 0.0141
Sr-90 0.00387 0.000989 0.0230
Sr-91 0.000613
Nb-95 0.158 0.0163 0.0384
Zr-95 0.162 0.147 0.212
Zr-97 0.000845 0.00112 0.000584
Mo-99 0.111 0.0122 0.00873
Ru-103 0.0376 0.0252 0.0248
Ru-106 0.00369 0.0126 0.000733
Cd-109 0.000102
Ag-110m 0.0440 0.0953 0.0301
Sn-113 0.00181 0.243
Sb-124 0.0135 0.0329 0.0167
Sb-125 0.187 0.268 0.205
Te-129 0.000172
Te-132 0.00219
1-131 0.498 0.648 0.158
1-132 0.00906 0.0118 0.00162
1-133 0.384 0.391 0.0695
1-135 0.00753 0.0345 0.00703
Cs-134 0.308 0.394 0.106
Cs-136 0.0174 0.00318
Cs-137 0.465 0.568 0.183
Xe-131m 0.00644
Xe-133 7.20 15.1 15.5
Xe-133m 0.204 0.0952 0.106
Xe-135 0.498 0.420 0.210
Xe-135m 0.00423 0.00322
Xe-138 0.000109
Ba-140 0.0452 0.0185 0.00605
La-140 0.0677 0.133 0.0313
Ce-141 0.00751 0.00563 0.00269
Ce-144 0.00181
Np-239 0.0214
Unidentified 0.0271 0.104

----------------
(a) Noble Gas Totals are the summations of the listed noble gas isotope
activities.
V@6

Table V-4

Radiological Monitoring Conducted by the
Baltimore Gas & Electric Company in the Vicinity of the
Calvert Cliffs Nuclear Power Plant

NUMBER OF
SAMPLE COLLECTION SAMPLING
MEDIA FREQUENCY LOCATIONS ANALYSES

Aquatic

Finfish Quarterly I
Flesh Gamma
Bone Sr-89/90

Shellfish
Crabs (Flesh) Quarterly 3 Gamma
Oysters (Flesh) Quarterly 2 Gamma

Sediment Quarterly 4 Gamma, Sr-89/90

Bay Water Monthly 2 H-3, Gamma,
Sr-89/90

Atmospheric

Air
Iodine Weekly 4 1-131
Particulates Weekly 7 Gamma, Gross Beta, Sr-89/90

Precipitation Continuous 1 Gamma, H-3, Gross Beta,
Sr-89/90

Terrestrial
Vegetation At Harvest 3 Gamma, Sr-89'/90(a)
Soil At Harvest 3 Gamma, Sr-89/90
Groundwater Quarterly 4 H-3, Gamma
External
radiation Monthly 14(b) TLD

(a) Analysis of cured or dried sample
(b) Includes Baltimore, Md. as a control station

V-7

Table V-5

Radiological Monitoring Conducted by the
Maryland Department of Health and Mental Hygiene
in the Vicinity of the Calvert Cliffs Nuclear Power Plant

NUMBER OF
SAMPLE COLLECTION SAMPLING
MEDIA FREQUENCY LOCATIONS ANALYSES

Aquatic

Shellfish
Oysters Quarterly 1 Gamma
Sediment Quarterly 1 Gamma
Bay Water Quarterly 3 Gamma, H-3

Atmospheric

Air
iodine Weekly 4(a) 1-131
particulates Weekly 4 Gamma, Gross Beta,

Terrestrial
Vegetation At Harvest 1 Gamma(b)
Groundwater Quarterly 15 Gamma, Gross Beta, H-3
External
radiation Monthly 12 TLD

(a) In addition to these, a Baltimore location serves as a control
(b) Analysis of cured or dried sample

V-8

Table V-6a

Radiological Monitoring of Aquatic Impact Conducted by the
Maryland Power Plant Siting Program in the Vicinity of
the Calvert Cliffs Nuclear Power Plant

NUMBER OF
SAMPLE COLLECTION SAMPLING .(a)
MEDIA FREQUENCY LOCATIONS ANALYSES

Shellfish
Oysters
Natural bar Quarterly 2 Gamma, Sr-89/90
Discharge
tray Quarterly, 1 Gamma, Sr-89/90
Semi annually,
triquarterly,
annually

Crab Spring,fall 2
Shell Gamma, Sr-89/90
Flesh Gamma, Sr-89/90

Clams (Flesh) Nonroutine 2 Gamma

Finfish
Forage species Spring,Fall 2
Whole Gamma, Sr-89/90
Edible species Spring,Fall 2
Flesh Gamma, Sr-89/90
Bone Sr-89/90

Waterfowl Winter 2
Flesh Gamma, Sr-89/90
Bone Sr-89/90

Grass shrimp Spring,Fall 2 Gamma, Sr-89/90

Algae Springjall 2 Gamma, Sr-89/90

Miscellaneous Springjall
biota (zooplantt3n Gamma, Sr-89/90
benthos, etc.)

Sediments Quarterly, 14 Gamma, Sr-89/90
Annually 24 Gamma, Sr-89/90

(a) Routine Sr-89/90 analysis initiated in 1980.
(b) Routine quarterly epifauna program initiated in 1981.

V-9

Table V-6b

Radiological Monitoring of Terrestrial Impact Conducted by
the Maryland Power Plant Siting Program in the Vicinity of
the Calvert Cliffs Nuclear Power Plant

NUMBER OF
SAMPLE COLLECTION SAMPLING a)
MEDIA FREQUENCY LOCATIONS ANALYSES(

Vegetation At harvest 2 Gamma, Sr-89/90(b)
crops

Lichens, leafy (c) (c)
vegetables, lawn
grass, pasture
grass, etc. Gamma, Sr-89/90

Soils (c) 2 Gamma, Sr-89/90
<12 Sr-89/90
External 11(d)
radiation Monthly TLD

(a) Routine Sr-89/90 analysis initiated 1980.
(b) Analysis of freshly harvested sample
(c) Non-routine collection to determine specific radiological impact as
required.
(d) This program is integrated with DHMH, however, these 11 are in addi-
tion to those listed in Table V-5.

V-10

with this weapons test were also detected in air particulates at this time
(11). In April 1379, DHMH detected a trace atmospheric concentration of
1-131 (10+7 fCi/m ) in the Calvert Cliffs area. This is probably not due to
releases by the plant, but is more likely from a remote source (Peach Bottom,
TMI) since 1-131 was also detected in the atmosphere (11), and in milk (12)
in the Peach Bottom vicinity during this period.

As is the case with 1-131, Sr-89 and Sr-90 are produced in weapons test
explosions as well as power plant operation, and therefore can be introduced
into the environment by both weapons test fallout and routine power plant
releases. The longer lived Sr-90 has been historically present throughout
Maryland, and was not detected in the Calvert Cliffs vicinity at levels sig-
nificantly higher than those of farfield locations. Sr-89 attributed to
power plant operation, however, was detected in air particulates at Calvert
Cliffs during the third quarter of 1979 (9). Sr-89 was also detected in soil
samples from both Calvert Cliffs and farfield locations in March 1978 (8),
and was attributed to the March 1978 Chinese weapons test. The environmental
impact of Sr-89 at the very low concentrations detected is inconsequential.
Precipitation samples contained no plant-related gamma radionuclides or
Sr-89/90, and tritium values were consistent with fallout-associated levels.

No plant-related radionuclides were detected in crop vegetation in 1978.
In 1979 a sunflower sample analyzed by BG&E indicated the presence of a low
concentration of Sr-89 which may have been the result of plant operation.
Sr-90 detected by BG&E in tobacco in concentrations up to 1.8 nCi/kg (wet)
may also be plant related. This value is somewhat in question because it
varies significantly (on the high side) from the other data. BG&E personnel
attribute this to improper laboratory technique (13), and data from other
monitoring programs support questioning the validity of this number. Soil
and tobacco collected in the fall of 1980, however, show no discernible Sr-90
increase in the vicinity of Calvert Cliffs (7). More detailed radio-
strontium investigation is underway; PPSP and BG&E are analyzing fresh
(uncured) tobacco and soils from both the plant vicinity and farfield loca-
tions in an attempt to detect any possible plant-associated increment.

In summary, of those radionuclides released to the atmosphere during
1978-1980 by the Calvert Cliffs Nuclear Power Plant, only Sr-89 and a trace
of 1-131 were detected in the atmospheric and terrestrial environment.
Detection of fallout from the 1978 Chinese weapons test confirmed the
ability of the monitoring programs to discern other small, man-made incre-
ments of radioactivity in the airborne pathway. These concentrations provide
context for evaluating the minor plant-associated increment, which is re-
garded as insignificant.

Aquatic Radionuclide Distributions

An annual average of approximately 500 Ci of tritium was released via
the liquid pathway during the 1978-1980 period. This represents approxi-
mately 96 percent of the activity released to the aqueous environment. Moni-
toring of Chesapeake Bay water by BG&E and the State occasionally reveals
tritium concentrations above the background levels -1500 pCi/l (11). These
higher concentrations, attributed to routine releases by the plant, are
localized in the discharge vicinity. Because of dilution and dispersion,

V-11

tritium concentrations in Bay water outside the immediate discharge area are
at background levels. Because tritium is not a bioaccumulated radionuclide,
the resulting radiation doses to aquatic biota are insignificant, and no
adverse environmental impact is associated with these levels.

Radionuclides with potentially significant environmental impact are
those which may, through chemical and biological processes, be retained and
accumulated in the Chesapeake Bay ecosystem. Cycling and trophic level as-
similation of these radionuclides will provide an additional radiation dose
to Bay organisms, and could ultimately contribute some radiation dose to man.

A variety of such bioaccumulable radionuclides have been introduced into
the Bay as a result of atmospheric weapons testing. Since 1978, three
Chinese atmospheric detonations have produced detectable concentrations of
fallout in Bay samples. The relatively short-lived Ce-141, Ce-144, Ru-103,
Ru-106, Zr-95 and Nb-95 are episodically detected in sediments and finfish
following these events and during the annual Spring washout of weapons-test
debris. The long-lived fallout product Cs-137 is ubiquitously distributed in
the environment and is consistently detected in sediments and biota of the
Chesapeake Bay. Calvert Cliffs also discharges small quantities of these
radionuclides. However, concentrations detected in environmental samples
collected near the plant are within the statistical distribution of concen-
trations present in the same media at locations beyond the plant's influence.
The plant-related contributions are indistinguishable and therefore not
quantifiable. These very low levels of fallout radionuclide concentrations
are insignificant contributors to the dose received by Bay biota and human
consumers.

Other radionuclides which are not fallout constituents, but are
routinely released by Calvert Cliffs, have been detected in Bay samples
(7-10, 14). Nearfield biota and sediments periodically contain low levels of
Co-58, Co-60, Zn-65, and Ag-110m. Because of the physically and biologically
dynamic character of the Chesapeake Bay Estuary, and variations in radio-
activity released by the plant, radionuclide concentrations within individual
sample media vary greatly. Table V-7 presents maximum concentrations of
plant-associated radionuclides detected in the PPSP monitoring program.

Naturally ocurring radionuclides of the t.horium and uranium decay pro-
ducts and potassium-40, as well as weapon test fallout radionuclides, are
present in sediments in the Calvert Cliffs area and throughout the Bay. Ra-
dionuclides detected in sediments which are attributed to Calvert Cliffs are
Co-58, Co-60, and Ag-110m. Ag-110m was detected at extremely low levels in
nearfield sampling locations through November 1979, but not later (7, 15).
Co-58 and Co-60 have been detected consistently in area sediments during the
reporting period (1978-1980). Prior to 1978, Co-58 was not detected in sed-
iments and Co-60 was present at a barely detectable concentration at one
sampling location. The Co-60 detected at that time may not be related to
Calvert Cliffs since it was found in sediments prior to plant operation (15).
Concentrations of Co-58 and Co-60 in sediments fluctuate over time, but a
constant localized increase of radiocobalt in area sediments is not apparent.
However, the increased incidence of Co-58 at the transect extremes (7) in-
dicates an expansion of the impact area.

v-12

Table V-7

Maximum Concentrations of Radionuclides Attributed to
Calvert Cliffs Operation in Various Environmental Media for the
Period 1978-1980 as Determined by PPSP Monitoring Program Counting
Uncertainty @ 95% Confidence Level

MEDIA Radionuclide Concentration (pCi/kg, wet) (a)
Co-58 Co-60 Zn-65 Ag-110m

Seaduck
Flesh 11+9 -
Gut 472+38 50+24

Edible Finfish - - -
Forage Finfish(b) 186+4 15+2 - 3+2

Oysters 73+4 6+2 31+6 350+20

Clams (Mva arenaria) 3+3 2+2 - 65+6

Crab
Meat - - - 22+6
Shell - - - 119+32

Grass Shrimp 25+11
Zooplankton 28+6 5+5 - -
Algae 141+14 3+8 - -

Sediment
Sand 287+11 33+6 - 9+5
Clay 450+14 179+16 - 13+7

(a) Concentrations for crab shell and sediments are in pCi/kg, dry. Con-
centrations for zooplankton are in pCi/l.

(b) This collection of menhaden also contained 82+15 pCi/kg Cr-51 and
8+3 pCi/kg of Fe-59.

V-1 3

The mobile and transitory nature of finfish results in a short term
exposure to Calvert Cliffs discharges. This reduces the extent to which
these species can assimilate discharged radioactivity through direct uptake
or food chain transport. Resident benthic and epibenthic biota such as clams
and oysters which are present (and therefore exposed) year-round are impacted
to a greater extent and serve as indicators of upper concentration limits.
Macro-algae and fouling organisms which are present or metabolically active
on a seasonal basis reflect shorter term radioecological impact.

Edible finfish (primarily bluefish) collected in the Calvert Cliffs
vicinity have contained fallout-attributed Cs-137 but no detectable power
plant-related radionuclides (7-10). Samples of certain forage finfish
(anchovies and silversides) have likewise contained no detectable power plant
radioactivity. Radionuclides attributed to the plant have, however, been
detected on occasion in the filter-feeding menhaden, a primary prey species
for important predator finfish, e.g., bluefish and weakfish (7). The
presence of the short-lived Cr-51 (half-life 28 days) and Fe-59 (half-life 45
days) in these samples indicates that the population was in the nearfield
during a discharge, and collection and analysis took place soon after
exposure to and uptake of, the released radioactivity.

Radionuclides attributed to Calvert Cliffs have been detected in shell-
fish: periodically in blue crabs (7) and consisently in oysters (8-10, 14).
As previously mentioned, oysters resident in the Calvert Cliffs vicinity are
exposed to radioactivity to a greater extent than transient biota such as
finfish and crabs, and may provide a higher potential dose to man through
seafood consumption. PPSP monitors oysters from a natural bed 3/4 mile north
of the discharge, and conducts a submerged tray study in which groups of
oysters are exposed directly to Calvert Cliffs discharges for selected time
periods. The assimilation and depuration of radionuclides in oysters is
affected not only by the availability of radionuclides, but also a multitude
of chemical and biological conditions. The tray study provides a more
thorough understanding of the controlling parameters than is possible through
quarterly monitoring of the natural bed. Significantly, this study indicated
that uptake was totally inhibited during the winter season (14). The most
noteworthy radionuclide present in oysters during the previous period was
Ag-110m (16). Concentrations of Ag-110m in continuously exposed oysters
peaked in the fall of 1977 at approximately 600 pCi/kg (wet) (17) and have
been decreasing throughout the 1978-1980 period to approximately 60 pCi/kg
(wet) (8-10, 14). As of this publication date, concentrations were -20
pCi/kg (wet) (7, 11). Evidence of the sensitivity of using oysters as bio-
logical indicators of potential radioecological impact is provided by the
fact that very low levels of Zn-65 are sporadically detected in these organ-
isms (11, 14) while the quantities of this radionuclide remain so low as to
be undetectable by BG&E in their analysis of releases.

Sea ducks (Old Squaw) collected in the discharge vicinity have contained
Co-58 associated with plant releases (7). These birds overwinter on the Bay
and feed extensively on small clams found in the Calvert Cliffs area. While
these low levels have no significant radiological impact, they serve to
demonstrate upper trophic level assimilation of power plant radioactivity.

v-14

Radiation Dose to Man
The estimate of the dose commitment 1 to an individual consuming seafood
harvested in the vicinity of Calvert Cliffs has been calculated using the
maximum radionuclide concentrations detected in shellfish taken from this
area (Table V-7). Calculated dose commitments to adults, teenagers and
children are given in Table V-8. Table V-9 contains a comparison of doses
predicted in the Final Environmental Impact Statement for CCNPP and those
doses calculated using the maximum concentrations from Table V-8.

Summary

Of the radioactivity detected via monitoring of the atmospheric pathway
during 1978-1980, only Sr-89 detected at low levels in air particulate and
vegetation samples was attributed to plant operation. A trace of atmospheric
1-131 may be plant related, or due to releases from a remote source. At
these levels, environmental impact is negligible.

Radioactivity dicharged via the aqueous pathway has been detected in the
Chesapeake Bay ecosystem. Sediments have contained low levels of Co-58,
Co-60, and Ag-110m. Ag-110m has not been detected in sediments since 1979.
Co-58, which had not been detected prior to 1978, is consistently found in
area sediments. The range of concentration varies over time, and while no
significant build-up is apparent in the nearfield, sediment dispersion
appears to be expanding the impact area.

Radionuclides attributed to aqueous releases by Calvert Cliffs have been
detected at low levels in all sampled Bay biota with the exception of edible
predator finfish. The maximum detected concentrations would result in ra-
diation doses to the various organisms which are still orders of magnitude
lower than doses resulting from naturally radioactive sources present in the
Bay environment such as thorium and uranium decay products and potassium--40.
Due to their year-round residence, oysters in the Calvert Cliffs vicinity
represent the greatest potential human radiation dose through seafood con-
sumption. Employing the maximum detected concentration in seafood, the es-
timated dose to the maximum exposed individual through consumption would be
0.11 mrem to an adult's G.I. tract. The plant operates well within 10 CFR 50
Appendix I design criteria which limit a maximum exposed individual to 3 mrem
annually per reactor for the aqueous pathway.

B. Peach Bottom Atomic Power Station

The Peach Bottom Atomic Power Station (PBAPS), owned and operated by the
Philadelphia Electric Company (PECO), is located approximately three miles
north of the Pennsylvania-Maryland border on the Susquehanna River. Although
it is outside Maryland, it has the potential for impact in Maryland because

--------------
The dose commitment from the ingestion of a given quantity of some radio-
nuclide is the total dose that will be received by the individual before the
radioactive material is removed from the body by excretion and/or radioactive
decay. These estimates employ Regulatory Guide 1.109 dose conversions (24).

V-15

Table V-8

Ma:FlTum Dose Commitment in mrem to an Individual Consuming
ShellfiW J Exclusively from the Vicinity of the Calvert Cliffs Nuclear
Power Plant (Utilizing Radionuclide Concentrations Given in Table V-7)

Age Group Adult Teen Child

Quantity (b) Oysters 29 dozen 22 dozen 10 dozen
Consumed Clams 29 dozen 22 dozen 10 dozen
Crabs 15 dozen 11 dozen 5 dozen

Total Co-58 .000610 .000621 .000684
Body Co-60 .000142 .000144 .000159
Dose Zn-65 .001079 .001099 .001196
Ag-110m. ..000154 .000157 .000173
TOTAL 00198 .00202 .00221

Bone Co-58 (c) (c) (c)
Dose Co-60 (c) (c) (c)
Zn-65 .000750 .000679 .000722
Ag-110m ..000280 .000273 .000321
TOTAL .00103 .00095 .00104

Liver Co-58 .000272 .000270 .000223
Dose Co-60 .000064 .000064 .000054
Zn-65 .002387 .002356 .001924
Ag-110m, ..000259 .000258 .000217
TOTAL .00298 .00295 .00242

Kidney Co-58 (c) (c) (c)
Dose Co-60 (c) (c) (c)
Zn-65 .001597 .001508 .001212
Ag-110m -.000509 .000492 .000403
TOTAL .00211 .00200 .00162

GI-LLI Co-58 .005511 .003717 .001303
Dose Co-60 .001206 .000834 .000299
Zn-65 .001504 .000998 .000338
Ag-110m ..105700 .072485 .025764
TOTAL .11392 .07803 .02770

(a) No power-plant radioactivity h as been detected in edible finfish.
(b) The numbers of each type of shellfish consumed corresponds to 5kg/yr,
3.8kg/yr, and 1.7kg/yr for an adult, teen, and child, respectively.
These are recommended values (Reg. Guide 1.109) used in lieu of site
specific data to determine the dose commitment to the maximum exposed
individual.
(c) Dose/concentration conversion factors not available.

V-1 6

M'M

Table V-9
Comparison of Predicted(a) and Calculated (b) Dose Commitments in mrem
to a Maximum Exposed Individual from Consuming Seafood Exclusively from
the Vicinity of the Calvert Cliffs Nuclear Power Plant

Total G.I.-LLI
Seafood Body Tract Thyroid Bone
Consumed Predicted Calculated Predicted Calculated Predicted Calculated Predicted Calculated

Finfish 0.037 (c) 0.078 (c) 0.087 (c) 0.021 (c)

(e)
-Ij Crustacea, 0.20 0.000017 1.62 0.011960 0.22 (d) 0.022 0.000032

Molluscs 0.043 0.003571 0.42 0.205058 0.22 (d) 0.037 0.001854 (e)

(a) Predicted doses taken from the Final Environmental Impact Statement for Calvert Cliffs
(18).

(b) Calculated doses are derived assuming an annual consumption of 18 kg of finfish, and 9 kg
of crustacea or molluscs; radionuclide concentrations utilized are those found in Table
v-7.

(d) Thyroid dose conversion factors not available.

(e) These values include no dose commitment for Co-58 or Co-60 as conversion factor were
unavailable for these isotopes.

of its location on the Susquehanna River. Each of the two units remaining in
operation (Unit 1, a 40 MWe High Temperature Gas Cooled Reactor, was decom-
missioned in January 1975) is a boiling water reactor with a maximum depen-
dable capacity of 1098 MWe.

Unit 2 of the PBAPS, placed in commercial service in July 1974, had
produced 42,405,440 MWh gross of electrical energy as of the end of 1980.
Unit 3, placed in commercial service in December 1974, had produced
39,745,940 MWh gross. Since the inception of commercial operation, Units 2
and 3 have achieved cumulative unit capacity factors of 62.3% and 62.7%,
respectively.

Releases to the Environment

Radionuclides discharged to the atmosphere and the Conowingo Pond
(Susquehanna River) from the Peach Bottom Atomic Power Station as reported by
PECO during 1978-1980 are given in Tables V-10 and V-11. Noble gasses,
chiefly the Xenon isotopes, comprise nearly 100 percent of the radioactivity
released to the atmosphere. These radioisotopes have very little environ-
mental impact due to their inert nature. Iodine-131, which is an isotope of
environmental significance, is routinely released in small quantities. Actual
releases to the atmosphere for the three year period are considerably lower
than estimated in the Final Environmental Impact Statement for Peach Bottom
(18).

Of the liquid releases, tritium and dissolved noble gases accounted for
about 70 percent and 10 percent, respectively, of the total activity released
during the three year period. Environmentally significant radionuclides
(other than tritium and noble gases) accounted for about 20 percent of the
total activity released over the three year period, with 1-131, Co-60, Zn-65,
Cs-134 and Cs-137 being of primary importance. Due to the short half-lives
of the Iodines, they are only sporadically detected in the aquatic environ-
ment and do not accumulate in environmental media. Co-60, Zn-65, Cs-134, and
Cs-137 are consistently detected in Conowingo Pond sediments. Zn-65, Cs-134
and Cs-137 are routinely detected in biota of the Conowingo Pond, Susquehanna
River, and Susquehanna Flats.

Environmental Monitoring Programs

PECO, the Maryland DHMH, and PPSP all conduct extensive monitoring
programs to assess the impact of PBAPS. To define the atmospheric pathway
impact, PECO contractors analyze samples of air, precipitation, terrestrial
vegetation, soils, and milk. Monitoring of ambient radiation levels provides
an assessment of the external dose delivered by noble gasses through the
atmospheric pathway. The DHMH maintains air particulate and air iodine
samplers in the Peach Bottom vicinity for assessing atmospheric impact, and
conducts jointly with PPSP an ambient radiation monitoring program.

The utility's aquatic environmental monitoring program is designed to
quantify radionuclide concentrations in water, sediment and finfish. Sampling
is restricted to the Conowingo Pond except for a spring collection of shad
from the Conowingo Dam tailrace; Maryland impact beyond the Conowingo Dam is

V-18

Table V-10

Total Gaseous Releases (Curies) from the Peach Bottom Atomic
Power Station as Reported by PECO (19-24)

Radionuclide 1978 1979 1980

Tritium 20.0 27.3 12.9
Noble Gases 49700. 122500. 12900.
Halogens 1.44 1.36 1.14
Other 0.038 0.122 0.096
Total Curies 49721.478 122528.782 12914.136

Na-24 0.000437 0.00249
Cr-51 0.000288 0.000674
Co-58 0.0000825
Co-60 0.00469 0.000940 0.00870
Zn-65 0.00310 0.000853 0.0151
Kr-85 1.91
Kr-85m 66.6 433. 16.6
Kr-87 112. 3.72
Kr-88 84.9 6.13
Rb-88 0.0103 0.00356
Rb-89 0.000379 0.0000746
Y-91M 0.000917 0.00247 0.00318
Sr-89 0.00241 0.00209 0.00210
Sr-90 0.000106 0.0000927 0.0000659
Sr-91 0.00220 0.000326 0.00145
Sr-92 0.0000426
Mo-99 0.0000747
Tc-99m 0.00121
Ag-110m 0.000156
1-131 0.0839 0.258 0.0294
1-133 0.645 0.631 0.569
1-135 0.711 0.475 0.543
Cs-134 0.000570 0.00165 0.00177
Cs-137 0.000942 0.00152 0.00450
Cs-138 0.0211 0.0962 0.0535
Xe-131m 136.
Xe-133 45440. 106000. 11000.
Xe-133m 4197. 194. 115.
Xe-135 15400. 1600.
Xe-135m 86.9 76.5
Xe-138 23.1 107.
Ba-140 0.0000855 0.000334 0.00129
La-140 0.00104 0.000188 0.000925
Np-239 0.0000687

V-19

Table V-11
Total Liquid Releases (Curies) from the Peach Bottom
Atomic Power Station as Reported by PECO (19-24)

Radionuclide 1978 1979 1980

Tritium 32.4 42.7 37.3
Dissolved Noble
Gases 7.10 6.53 1.35
Other 9.78 21.10 3.65
Total Curies 49.28 73.33 42.30

Na-24 4.45 9.27 0.578
P-32 0.0719 0.0170
Cr-51 0.00445 0.0649 0.0965
Fe-55 0.203 0.0220
Mn-54 0.0879 0.00735 0.00879
Mn-56 0.000627
Co-58 0.0273 0.0240 0.0234
Co-60 0.155 0.162 0.156
Ni-63 0.0319 0.00511
Zn-65 0.424 0.460 0.306
Kr-85m 0.0528 0.000403
Kr-87 0.0298
Kr-88 0.0851
Y-91M 0.0230 0.0139
Sr-89 0.0189 0.0202 0.00757
Sr-90 0.000944 0.000813 0.000380
Sr-91 0.00763 0.00711
Sr-92 0.000127 0.00142 0.000734
Nb-95 0.000471 0.000570
Zr-95 0.000416
MO-99 0.000416 0.000160
Te-99m 0.00262 0.101 0.0218
Ru-103 0.000177
Cd-109 0.0858 0.00171
Ag-110m 0.000114
Sb-122 0.194
Sb-124 0.000536 0.0000315
Te-132 0.0505 0.0151 0.0238
1-131 0.227 0.964 0.0639
1-132 0.00746 0.00322 0.000784
1-133 0.300 0.446 0.0721
1-134 0.136 0.000721
1-135 0.118 0.0236
Xe-131m 0.103 0.0185
Xe-133 1.17 0.313
Xe-133m 0.000718 0.00222
Xe-135 3.08 0.521
Xe-135m 0.103 0.0185
Xe-133 1.17 0.313
Xe-133m 0.000718 0.00222
Xe-135 3.08 0.521
Xe-135m 0.0705 0.0546
Cs-134 2.86 3.92 0.568
Cs-137 0.810 3.26 0.691
Ba-140 0.000963 0.00740
La-140 0.0237 0.0107
Np-239 0.115 0.0286 0.0116

V-20

not addressed. PPSP conducts an extensive monitoring program to assess the
actual distribution of PBAPS radionuclides, focussing on the aquatic
environment because this pathway has the greatest potential for a significant
impact in Maryland. Samples are collected from Conowingo Pond, the Susque-
hanna River and the Upper Chesapeake Bay to determine radionuclide concentra-
tions in sediments, aquatic vegetation, forage and commercially significant
finfish, shellfish, waterfowl and aquatic mammals (Figure V-0. The programs
conducted by the three agencies, described by sample type, collection fre-
quency and type of analysis, are presented in Tables V-12, V-13, V-14, and
V-15.

Atmospheric and Terrestrial Radionuclide Distributions

Except for 1-131, relatively small quantities of environmentally signi-
ficant radioactivity are released via the atmospheric pathway, a fact which
is supported by the general lack of detectable PBAPS radionuclides in atmos-
pheric and terrestrial samples. TLD measurements indicate that the ambient
radiation level is no higher in the PBAPS vicinity than at farfield locations
(12, 25, 26). The frequent detection of natural and weapons test fallout
radioactivity in air particulate, precipitation, soil and milk samples demon-
strates the efficacy of the surveillance network. Cosmically-activated Be-7,
the ubiquitous and routinely detected Cs-137, and the episodically present
Zr-95 and Nb-95 are natural and weapons test fallout products whose concen-
trations peak with seasonal precipitation and atmospheric washout (11, 12,
25-29).

In March 1978, an atmospheric weapons test by the Peoples Republic of
China produced detectable fallout, which included 1-131, in the Peach Bottom
vicinity (11, 25) as well as at farfield locations (11). Some, or all of the
1-131 detected at this time in milk and air particulates (by PECO contrac-
tors), and in atmospheric and particulate samples (by DRMH) can be attributed
to this event, since fresh fission radionuclides (I-132/Te-132, Ba/La-140)
were also in evidence (11). PBAPS did release 1-131 in April (the fifth
highest monthly 1-131 release over the 3 year subject period, 20.5 mCi) and
may also have been an unquantifiable contributor to the detected concentra-
tions. PECO contractors again detected 1-131 in milk later in the year
(October and November), an event which is attributed solely to releases by
PBAPS (25). The maximum detected spring concentration in milk was 9.1+0.9
pCi/l, and in the fall, 0.84+0.08 pCi/l.

In 1979, 1-131 was detected in milk in the Peach Bottom vicinity
throughout the month of April to a maximum concentration of 0.53+0.06 pCi/1
(26). The Maryland DHMH (11) also detected 1-131 in air samples from 3 Htrford
County in the second and third weeks of April (Maximum of 30+10 fCi/m ) . The
TMI accident in late March and subsequent atmospheric releases has been re-
garded as the source of this 1-131 because similiar levels were present in
milk from near and distant farms suggesting a regional effect from a distant
source (26). However it should be noted that the second highest total
monthly release of 1-131 from PBAPS for the three-year subject period also

---------------
1DHMH also detected a trace (10+7 fCi/m3 ) of 1-131 in the atmosphere in the
Calvert Cliffs area during the second week of April which may be due to TMI,
PBAPS, Calvert Cliffs or a combination.

V-21

OF
HR- I
N HR-2 HOLTWOOD RESERVOIR
4!2@ R-3

HOLTWOOD DAM

CP-1
CONOWINGO RESERVOIR

PEACH BOTTOM P-2
PA. ATOMIC POWER STATION 0
-------------------
MD. CP-3

CP-4 CONOWINGO DAM

BIOTA SAMPLE
SEDIMENT SAMPLE
SF-1
SF-2
SCALE SF- I
mISF-3
0 6 miles F-4
ESF-8
0 10kM NSF-9
NSF-10

SF-ii

SF-120 SASSAF AS VER
BALTIMORE CITY1

M
IN 4R@

INC
co
LU

Fig. V-1. PPSP Susquehanna River/Upper Bay Sampling Locations

V-22

Table V-12

Radiological Monitoring Conducted by
Philadelphia Electric Contractor.Interex Corporation
in the Vicinity of the Peach Bottom Atomic Power Station

NUMBER OF
SAMPLE COLLECTION SAMPLING
MEDIA FREQUENCY LOCATIONS ANALYSES

Air particulate Continuous samples 17 Gamma (monthly);,
composited weekly/monthly Gross Beta (weekly)

Precipitation Continuously 3 Gross Beta;
Sr-89/90, Cs-137

Milk Quarterly 11 Gross Beta;
Sr-89/90;Cs-134/137,
1-131, K-40

Vegetation Spring, summer, fall 7 Gross Beta;
Sr-89/90;
Cs-134/137,K-40

Soil Semiannually 6 Gross Beta;
Sr-89/90;Cs-134/137,
K-40

Small mammal Semiannually 1 Gross Beta;
thyroid 1-131; Sr-89/90
muscle
bone

Well water Quarterly 4 Gross Alpha; Gross
Beta; Cs-137;
Sr-89/90

Surface water Monthly 8 Gross Alpha; Gross
Beta

Discharge water Monthly 2 Gross Alpha; Gross
Beta

Sediments Semiannually 6 Gamma; Gross Alpha;
Gross Beta;Cs-134/137

Finfish Quarterly 5 Gamma; Gross Beta;
Sr-89/90; K-40

V-23

Table V-13

Radiological Monitoring Conducted by Philadelphia Electric
Contractor Radiation Manaptement Corporation in the Vicinity
of the Peach Bottom Atomic Power Station

NUMBER OF
SAMPLE COLLECTION SAMPLING
MEDIA FREQUENCY LOCATIONS ANALYSES

Air
Particulate Continuous samples 2 Gross Beta (weekly),
composited weekly Gamma (monthly)
Iodine(a) Continuous samples 7 1-131
composited weekly

Precipitation Continuous samples 2 Gamma, Gross Beta
composited monthly
Milk Weekly while cows on 11 I-1@1, Sr-89 (b)
pasture, otherwise H-3kc), Gam
monthly; quarterly 8;3

Soil Semiannually 3 Gamma, Sr-89/90

Ambient radiation Monthly, quarterly 47 TLD

Well water Quarterly 4 Gross Beta, H-3

Surface water Monthly 9 Gamma, Gross Betf,,,
H-3, Gross alphakei

Discharge water Monthly 2 Gamma, Gross Beta
H-3

(a) Initiated in March, 1980
(b) One farm
(c) Four farms
(d) One farm
(e) Four stations

V-24

Table V-14

Radiological Monitoring Conducted by the Maryland Department
of Health and Mental Hygiene in the Vicinity of the
Peach Bottom Atomic Power Station

NUMBER OF
SAMPLE COLLECTION SAMPLING
MEDIA FREQUENCY LOCATIONS ANALYSES

Air (b)
particulates Continuous samples 2 Gamma, Grosq @eta,
composited weekly Gross Alphakaj
iodine Continuous samples 2(b) Gamma
composited weekly

Ambient radiation Monthly 12 TLD

Surface water Weekly 1 Gamma, Gross Beta,
H-3

(a) PPSP initiated Sr-89/90 analysis on these samples in 1981.
(b) An additional, Baltimore location serves as control.

V-25

Table V-15

Radiological Monitoring Conducted by the Maryland Power Plant Siting
Program in the Vicinity of the Peach Bottom Atomic Power Station

NUMBER OF
SAMPLE COLLECTION SAMPLING
MEDIA FREQUENCY LOCATIONS ANALYSES

Mammals Annual 2
(muskrat, otter,
raccoon)
Flesh Gamma, Sr-89/90
Bone Sr-89/90

Waterfowl (a) 2
Flesh Gamma, Sr-89/90
Bone Sr-89/90

Finfish
Forage species Spring, Fall 4
Whole Gamma, Sr-89/90
Edible species Spring, fall 4
Flesh Gamma, Sr-89/90
Bone Sr-89/90

Shellfish
Crabs (Flesh) (a) 1 Gamma, Sr-89/90
Clams (Flesh) (a) 1 Gamma, Sr-89/90
Oysters (Flesh) (a) 1 Gamma, Sr-89/90
Mussels (Flesh) Spring, fall 1 Gamma, Sr-89/90

Submerged Spring, fall 3 Gamma, Sr-89/90
Aquatic
Vegetation

Sediments Spring, fall 35 Gamma, Sr-89/90

(a) Non-routine collection to determine specific radiological impact as
required.

V-26

occurred in March 1979 (42.3 mci). It is possible that some fraction or all
of the 1-131 detected at this time was due to PBAPS releases. The third
highest monthly release of 1-131 for the subject period (39.3 mCi) occured in
June and its presence in milk detected by RMC in June (max 0.65+0.04 pCi/1)
and July and August (max 0.06+0.03 pCi/1) is attributed to releases by PBAPS
during this period. In September and October, 1-131 detected in milk to a
maximum of 0.5+0.1 pCi/l was attributed solely to PBAPS (26).

During 1980, 1-131 was detected in milk in October, November and Decem-
ber by RMC (12) to a maximum concentration of 0.33 pCi/l. PBAPS released
very little 1-131 during this period; however, fallout from the Chinese wea-
pons test on October 15 was reported by numerous agencies to have contributed
1-131 throughout the mid-atlantic region. Maryland DHMH also detected 1-131
in atmospheric samples at this time. The 1-131 in milk in the PBAPS vicinity
is attributed to this fallout event.

Other than 1-131, radionuclides attributed to PBAPS atmospheric re-
leases were detected only once during the 1978-1980 period at an onsite air
monitoring station. Low levels of Co-60, Zn-65, Cs-134 and Cs-137 were de-
tected at this location in air particulates in July 1980 (12).

Aquatic Radionuclide Distributions

As indicated in Table V-16, relatively low levels of radionuclides at-
tributed to PBAPS have been detected in sediments, finfish, freshwater mus-
sels, aquatic vegetation, waterfowl, and in one otter (30). While these low
concentrations do not represent a human health concern, the diverse distri-
bution of PBAPS radionuclides within the ecosystem is nonetheless confirmed.

Radionuclide concentrations in finfish are highest in the plant vicinity
in the Conowingo Pond and in the Susquehanna River below the Conowingo Dam.
Finfish collected from the Susquehanna Flats have occasionally contained
PBAPS attributed radioactivity (Cs-134). The highest concentration of PBAPS
radioactivity detected in submerged aquatic vegetation (SAV) occurred on the
Susquehanna Flats (the closest sampling location for SAV); however, Cs-134
was found associated with an SAV (milfoil) sample from an area below the
Sassafras River, some thirty miles from the PBAPS (30). Because of cesium's
high affinity for organic material, it was likely bound to suspended particu-
late material attached to the sample, rather than actually incorporated in
the SAV itself.

Freshwater mussels from the Flats have been found to contain Zn-65 and
Cs-134 attributed to PBAPS discharges, while crabs and oysters from the Swan
Point area (the northernmost distribution limit for oysters in commercial
abundance) have contained no detectable PBAPS radioactivity. Fish-eating
waterfowl (mergansers) from the Susquehanna below the Dam have contained
PBAPS radioactivity; muskrats and raccoons collected from the Susquehanna
River below the Dam have contained no radioactivity attributed to PBAPS;
however, a river otter taken in the Sassafras River area in 1980 did contain
a trace of Cs-134 attributed to aquatic releases by PBAPS (30). As these
animals are known to travel considerable distances, it is not unlikely that
radionuclide uptake took place during residence closer to PBAPS, e.g., on the
Susquehanna Flats or in the Susquehanna River.

V-27

Table V-16

Maximum Concentrations of Radionuclides Attributed to Peach
Bottom Atomic Power Station in Various Aquatic Media for the
Period 1978-1980 as Determined Through PPSP Monitoring
Program (30). Counting Uncertainty @ 95% Confidence Level

PF
Media Radionuclide Concentration (pCi/kg, wet)(a)
CO-60 Zn-65 Cs-134 Cs-137(b)
OF

Mammals
Otter
Flesh - - 2+3 22+5 PF
Gut - 20+11 - 14+6
Raccoon
Flesh - - - 23+8 PF
Gut - - - 135+16
Muskrat
Flesh - - - 21+7
Gut - - - -

Waterfowl
Merganser
Flesh 20+9 35+9
Gut - - 13+16 60+24

Finfish
Edible Species - 60+20 230+26 316+26
Forage Species - 197+23 173+14 203+16

Invertebrates
Crab
Meat - - - -
Shell - - - 8+14

Oyster (Meat) - - - -
Rangia cuneata - - - -
Elliptio complanata - 17+6 24+3 27+4

Submerged Aquatic
Vegetation - 9+4 134+5 155+5

Sediment 70+2 132+20 796+62 967+18

(a) Concentrations for crab shell and sediments are in pCi/kg, dry.

(b) Primarily attributable to weapons testing fallout; however the detection
of Cs-134 indicates that power plant produced Cs-137 is present as well.

V-28

Zn-65 has been detected in Conowingo Pond sediments, but not in samples
from below the Conowingo Dam. Cs-134 and a generally unquantifiable concen-
tration of Cs-137 have been detected in sediments from Conowingo Pond and the
Upper Pesapeake Bay, distributed as far out as the mouth of the Sassafras
River. Maximum concentrations occur in the Pond and the mouth of the
Susquehanna River (30).

Most of the radioactivity released to the Susquehanna River by the PBAPS
is dispersed and diluted to an extent that it is undetectable in the environ-
ment. Some radionuclides, however, are incorporated within the Susquehanna
River/Upper Chesapeake Bay ecosystem, and trophic-level transport is ap-
parent. Periodic fluctuations in environmental radionuclide concentrations
occuras functions of a multitude of parameters such as discharge rate,
stream flow, organic loading, and organism metabolism. The range of radio-
nuclide concentrations in the various environmental media reflect the total
system, and assuming that the radioactive discharges from the plant do not
vary significantly from year to year, maximum concentrations detected
probably represent upper environmental concentration limits. In other words,
there is no indication that a localized "buildup" of radioactivity is occur-
ring over time.

Radiation Dose to Man

The principal contributor to dose via the airborne-to-food chain pathway
is 1-131 ingestion though milk consumption. Doses projected in the Final
Environmental Impact Statement (FEIS) published by the Nuclear Regulatory
Commission are unrealistically high as they assume far greater 1-131 releases
and subsequent concentrations in milk (0.2 bCi/1) than actually occur. (The
maximum concentration de 9ected during the subject period was due to fallou
and was 5 pCi/l or 5xlO_ pCi/l; the maximum attributed to PBAPS was 8xlO_
,uCi/l.) Utilizing this maximum concentration detected during November 1978,
and attributable to PBAPS, the maximum hypothetical dose from milk consump-
tion would be 0.11 mrem. to an infant's thyroid (25). Consumption of milk
containing the maximum concentrations of 1-131 ocurring during the 1979
period would have produced a dose to an infant thyroid estimated to be 0.11
mrem (26). The 1980 Chinese weapons test would have produced a maximum
annual dose to an infant thyroid of 0.05 mrem through 1-131 ingestion by milk
consumption. These dose estimates are based on Regulatory Guide 1.109 con-
sumption factors and dose conversions (31).

The annual adult total body dose associated with the consumption of
drinking water is calculated for an individual consuming 2 liters of Cono-
wingo Pond water daily, based upon the release radionuclides given in Table
V-11. H-3, Cs-134, and Cs-137 would produce a dose of 0.14 mrem for an
annual Susquehanna River low flow of 2500 cfs and 0.01 mrem under average

--------------
As noted in the previous table, Cs-137 is introduced into the environment not
only by power plants, but also by fallout from nuclear weapons testing. Cs-
134, however, is introduced into the environment exclusively as a result of
power plant operation, and its presence infers that at least some percentage
of the Cs-137 was contributed by the power plant. Because the two isotopes
behave identically in the environment, the power plant Cs-137 increment may
be estimated from the ratio of Cs-137 to Cs-134 in the plant discharge.

V-29

flow (36,000 cfs). Although these estimates exceed the doses projected by
the FEIS for Peach Bottom of .03 mrem. for low flow and .003 mrem for an
average flow these levels are considered insignificant. It should be noted
that the 0.14 mrem. estimate is almost totally due to those cesium isotopes,
which would in actuality be organically bound and settle out (hence the
radiocesium concentrations in sediments) or be removed in drinking water
treatment plants prior to ingestion. Doses calculated utilizing release data
are therefore considered to be unrealistic overestimates. The other radio-
nuclides listed in Table V-11 are insignificant contributors to dose.

The annual whole body dose commitment to an adult consuming the PBAPS
radioactivity in finfish from the plant vicinity was predicted in Peach
Bottoms FEIS to be 0.37 mrem (assuming 21 kg of finfish are consumed annu-
ally). The consumption of this quantity of finfish containing the maximum
concentration detected by the PPSP study would result in a whole body dose
commitment to an adult of 1.07 mrem/yr. Table V-17 summarizes dose commit-
ments to an individual consuming finfish containing these maximum radio-
nuclide concentrations. These values illustrate maximum ingestion doses and
do not reflect actual conditions. Even these overestimates, however, indicate
a trivial dose increment by comparison with that attributed to ingestion of
natural radioactivity (-21 mrem/yr). More realistic estimates of ingestion
dose commitments are provided by utilizing the mean of radionuclide concen-
trations detected in edible finfish by the PPSP study. These doses are in
the range of 0.05 mrem/yr to 0.08 mrem/yr for consumption of fish from the
Conowingo Pond and 0.29 mrem/yr to 0.40 mrem/yr for consumption of fish from
the Conowingo Dam tailracel.

Summary

During the 1978-1980 period, atmospheric releases of radioactivity from
the Peach Bottom facility produced detectable radionuclide concentration at
low levels in an air particulate sample from an onsite location on only one
occasion. 1-131 was detected in cows' milk and air samples from the PBAPS
vicinity on numerous occasions throughout the 1978-1980 period. The source of
this radionuclide might be attributed to Chinese weapons tests during the
spring of 1978, and the fall of 1980. Releases from TMI in the first week of
April 1979 may have been a source of 1-131 detected in the PBAPS vicinity
about this time. 1-131 detected in milk in the fall and winter of 1978, and
June, August, September and October 1979 is attributed exclusively to atmos-
pheric releases by PBAPS. PBAPS could also have been a source of 1-131 de-
tected during the weapons test fallout and TMI event episodes as well. Ra-
diation doses associated with these low 1-131 levels are nonetheless well
within 10 CFR 50 Appendix I guidelines.

Liquid effluents containing PBAPS radionuclides have produced detectable
concentrations of Zn-65, Cs-134 and Cs-137 in sediments and biota of the
Conowingo Pond, the lower Susquehanna River, and the Upper Chesapeake Bay.
Maximum concentrations in finfish occur in the Conowingo Pond and just below

---------------
IThe mean depends upon the manner in which samples without detectable radio-
nuclide concentrations are treated in the calculation. The range estimated
herein was developed by assuming that undetectable concentrations lie between
zero and the mean of concentration actually detected.

V-30

Table V-17
Maximum Dose Commitment(a) in mrem for an Individual
Consuming Seafood Affected by PBAPS Effluents Exclusively
(Assume Finfish Radionuclide Concentrations Given in Table V-16).
Calculations Based Upon Conversion Factors of USMRC Reg. Guide 1.109

Age Group Adult Teen Child

Consumption:

Finfish 21 kg/yr 16 kg/yr 6.9 kg/yr

Total Body Dose:

Zn-65 .008770 .008957 .009398
Cs-134 .584430 .336352 .128547
Cs-137 -.473810 .262406 .100716
TOTAL 1.067 0.608 0.239

Bone Dose:
Zn-65 .006098 .005526 .005673
Cs-134 .300426 .308016 .371358
Cs-137 -.528889 .566272 .712860
TOTAL 0.835 0.880 1.090

Liver Dose:
Zn-65 .01940 .019200 .01511
Cs-134 .71484 .724960 .609408
Cs-137 .72332 .753344 .682340
TOTAL 1.458 1.498 1.307

Kidaey Dose:

Zn-65 .012978 .012288 .009522
Cs-134 .231357 .230368 .188853
Cs-137 .245532 .256339 .222360
TOTAL 0.490 0.499 0.421

GI Tract Dose:
Zn-65 .012222 .008131 .002650
Cs-134 .001251 .009016 .003285
Cs-137 .014002 .010710 .004273
TOTAL 0.027 0.028 0.010

(a) The dose commitment from ingestion of a given quantity of a radio-
nuclide is the total dose that will be received by the individual
before the radioactive material is removed from the body by excretion
and/or radioactive decay.

V-31

the Conowingo Dam. Maximum sediment concentrations occur in the Conowingo
Pond and at the Susquehanna River mouth. The maximum dose resulting from the
ingestion of finfish containing the highest recorded concentrations is es-
timated to be 1.5 mrem/yr to a teenager's liver.

The dose increment resulting from operation of PBAPS is within the 10 CFR
50 Appendix I design criteria, which limits a maximum exposed individual to 3
mrem per year per reactor for the liquid pathway. An assessment of these
exposure levels is given some context by a comparison with dose from natural
radiation background. In the Peach Bottom vicinity a dose to the total body
and internal organs averages about 100 mrem per year. The Peach Bottom
plant-related increment obtained by consuming Conowingo Pond water exclu-
sively (2 liters/day) and Peach Bottom contaminated finfish exclusively (21
kg/yr) at the highest radionuclide concentrations would represent about 1
percent of the natural background radiation dose.

C. Three Mile Island

The Three Mile Island Nuclear Station (TMINS), owned by Metropolitan 01
Edison Co, Pennsylvania Electric Co and Jersey Central Power and Light Co is
operated by the GPU Nuclear Corporation. The plant is situated on an island
in the Susquehanna River approximately 8 miles Southeast of Harrisburg,
Pennsylvania. This location is about 30 air miles and approximately 42 river PF
miles from the Maryland border. Each of its two units is a pressurized water
reactor with a maximum dependable capacity of 840 MWe. Neither of these units
has been in operation since the March 28, 1979 accident at Unit 2.

Unit 1 of the TMINS, placed in commercial service on September 2, 1974,
has produced 25,484,330 MWh of gross electrical energy. Unit 2, placed in
commercial service on December 30, 1978 and in operation for only 95 full
power days prior to the accident, has produced 2,125,528 MWh of gross elec-
trical energy.

Accident

The loss of coolant accident which occurred on March 28, 1979 (described
in detail in several references, cf. ref. 32) produced a large volume of
radioactive water. The containment building was flooded with approximately
750,000 gallons of highly radioactive water, and surface areas within the
building were also contaminated. The Auxilliary and Fuel Handling Building
was flooded by approximately 600,000 gallons of radioactive water. This
water was not nearly as radioactive as that in the containment building since
it never came in direct contact with the damaged fuel, and has since been
cleaned by the EPICOR II decontamination system.

During the accident, some radi oactive effluent was discharged to the
Susquehanna River in order to prevent overflowing the Auxilliary and Fuel
Handling Building sump. This discharge was via a usually "clean" pathway,
and because of the potential for impact in Maryland, was a primary concern.
Although the utility and the State of Pennsylvania had monitoring programs in
place, PPSP and DHMH initiated monitoring to assess potential effects and
environmental consequences in Maryland of these releases to the Susquehanna
River.

V-32

Since the termination of these accidental liquid discharges PPSP has
conducted an extensive program of radioecological monitoring and assessment
in the Susquehanna River and Upper Chesapeake Bay in conjunction with its
radiological monitoring program for Peach Bottom. The TMI event affirmed the
need for continuing radiological sampling to provide baseline radioecological
data for assessment of the potential And real impact of the TMINS on the
Maryland environment.

Releases to the Environment

Radionuclides discharged to the atmosphere and Susquehanna River by the
Three Mile Island Nuclear Station during 1978 and 1979 as reported by Metro-
politan Edison are given in Tables V-18 and V-19. As a result of the March
28, 1979 accident, normal plant operation was terminated in 1979. Uncon-
trolled atmospheric discharges associated with the event are apparent through
a comparison of the quantity of radioactivity released during the two years.
The principal radionuclides released were isotopes of the noble gas Xenon,
1-131 and 1-133. Both Xe-133 and 1-131 were detected in the environment by
utility monitoring programs in place at the time of the accident. In the
clean-up process, approximately 43,000 Curies of the noble gas Krypton-85
were vented from the Unit 2 containment building from June 28, 1980 through
July 10, 1980.

During the accident, water containing higher than normal levels of ra-
dioactivity was discharged into the Susquehnna River (35, 37). The dis-
solved noble gas Xe-133 was detected in spot samples of river water as far
downstream as Columbia, Pennsylvania (approximately 17 miles downstream)
during the accident's early stages (38); however, TMI-attributed radio-
nuclides were not detected in the Susquehanna River in Maryland. Water
samples collected every two hours by DHMH at the Holtwood and Conowingo Dams
(see Figure V-1) revealed only natural radioactivity. Numerous agencies in
addition to Metropolitan Edison began monitoring the Susquehanna in the TMI
discharge vicinity to check for accidental releases during clean up opera-
tions (39).

AtmoSDheric and Terrestrial Radionuclide Distributions

This section contains a discussion of the TMI radioactive discharges
only as they affect Maryland. The results and interpretation of all moni-
toring activities conducted by various agencies following the TMI-accident
are available elsewhere (11, 38, 40).

Atmospheric releases of radioactivity (principally Xenon isotopes and
1-131) during and immediately following the accident were detected in the
environment in Pennsylvania as well as in Maryland. During the period March
30 through April 1, the DHMH detected 1-131 and Xe-133 in the atmosphere at
fixed sampling locations in Harford County near the Pennsylvania bo5der. The
maximum recorded atmospheric concentration of 1-131 was 90+30 fCi/m . Iodine-
131 was again detected in this region from April 11 through April 18 with a
maximum concentration of 30+10 fCi/m3 (11). These incidents have been attri-
buted to TMI, (26) although, as previousely mentioned, the Peach Bottom plant
may have been a contributing source. 1-131 detected subsequently in Harford

V-33

Table V-18

Total Gaseous Releases from the Three Mile Nuclear Station
as Reported by Met. Ed. (33-36)

Radionuclide 1978 1979

Tritium 234 189.
Noble Gases 15700. 9940000.
Halogens 0.027 16.6
Other 0.111 0.002
Total Curies 15934.138 9940205.602

K-40 0.00172
Ar-41 97.0 18.5
Co-58 0.0322 0.000871
Co-60 0.0000133 0.000123
Kr-85 0.439 0.113
Kr-85m 1.03 0.0893
Kr-88 0.000610
Sr-85 0.000000430
Sr-89 0.000000265 0.000109
Sr-90 0.00000143 0.0000329
Nb-95 0.00000555 0.0000179
Ru-103 0.0000547 0.0000545 IF
Ru-106 0.0000985
1-131 0.0272 14.2
1-133 2.39
Cs-134 0.00897 0.00000996
Cs-136 0.000000246
Cs-137 0.0677 0.000377
Cs-138 0.0000166
Xe-131m 11.4 2.52
Xe-133 15400. 8210000.
Xe-133m 49.8 11900.
Xe-135 183. 1580000.
Xe-135m 141000.
Ba/La-140 0.00000545 0.000200

V-34

Table V-19

Total Liquid Releases from the Three Mile Island Nuclear
Station as Reported by Met. Ed. (33-36)
Radionuclide 1978 1979 (a)

Tritium 194 104
Dissolved (b)
Noble Gases 0.358 0.054
Other 1.00 0.681
Total Curies 195.358 104.735

Na-24 0.0533
Ar-41 0.00356
Cr-51 0.00497 0.00889
Mn-54 0.0362 0.0123
Mn-56 0.00300
Fe-59 0.00398 0.00152
Co-57 0.00000860
Co-58 0.481 0.0786
Co-60 0.0204 0.0142
Zn-65 0.000394
Ga-72 0.000721
Kr-85 0.000988
Kr-88 0.000188
Rb-88 0.000117
Sr-89 0.00134 0.0775
Sr-90 0.00045 0.00475
Nb/Zr-95 0.0109 0.00358
Zr-97 0.000303 0.0000888
Mo-99 0.000502 0.0000471
Ru-103 0.000292 0.000284
Ag-110 0.00199
Ag-110m 0.0123 0.000198
Sb-122 0.000326 0.000159
Sb-124 0.000130
1-131 0.0235 0.369
1-133 0.0470
1-134 0.00963
1-135 0.000608
Xe-133 0.349 0.0534
Xe-133m 0.000809
Xe-135 0.00337 0.000398
Cs-134 0.144 0.0115
Cs-136 0.000459 0.00158
Cs-137 0.191 0.0238
Ba/La-140 0.000690 0.0235
Ce-141 0.0000539 0.0000315
Ce-144 0.00102
W-187 0.00251 0.000343

--------------
(a) Listed activities are for the first half of 1979.
(b) Noble Gas totals are the summations of the listed noble gas isotope
activities.

V-35

County is attributed to Peach Bottom and weapons test fallout events (11).
The deposition of atmospheric concentrations of 1-131 produced low but de-
tectable concentrations of this isotope in cows' milk in some Pennsylvania
localities (25, 27) but not in Maryland (11).

During the TMI clean-up period, several agencies were involved in
monitoring the impact of Kr-85 vented from the containment building. During
this period the PPSP maintained a network of Beta-sensitive dosimeters along
the Pennsylvania-Maryland border and in the TMI vicinity. No dose increment
attributable to the venting was discernible in Maryland (41).

Aquatic Radionuclide Distributions

To evaluate the impact of TMI discharges in Maryland, the PPSP collected
and analyzed a series of sediment and biota samples collected during the
spring and summer of 1979, from the Susquehanna River between TMI and the
mouth of the River, as well as from the Upper Chesapeake Bay. With the excep-
tion of Cs-137 attributable to fallout, no man-made radioactivity was de-
tected in finfish or sediments collected upstream of the Peach Bottom in-
fluence. Sediment, finfish and other biota collected from below Peach Bottom
(in the Conowingo Pond, Lower Susquehanna River and Upper Chesapeake Bay)
contain man-made radionuclides attributed to1both fallout and routine
releases of radionuclides from Peach Bottom.

Summary

Xe-133 and 1-131 released to the atmosphere by TMI during the accident
were detected at low levels in early April 1979 in air samples (11). 1-131
was not detected in cows' milk in Maryland. Radionuclides attributed to TMI
have not been detected in the Susquehanna River in Maryland. Continued DHMH
surveillance and the extensive monitoring PPSP is conducting to characterize
the radioecology of the lower Susquehanna River and Upper Chesapeake Bay will
provide the necessary data base for evaluating the effect of any future
releases from TMI. The plant is currently prohibited from discharging any
accident-related water. The NRC's Final programatic Environmental Impact
Statement QPEIS) on decontamination (40) addresses potential effects of
discharging decontaminated water.

The major issue associated with the discharge option is not an environ-
mental or radiological concern, but rather the public's perception of the
effects of such a discharge. This perception could result in consumer
avoidance of Bay seafood products, severely damaging commercial and recrea-
tional fisheries.

---------------
1It is recognized that some fraction of TMI-related radioactivity, particu-
larly Cs-134 and Cs-137, would ultimately be deposited in the Upper Bay.
However, the absence of any detectable concentrations in samples taken
from the Holtwood Reservoir (upstream and beyond PBAPS influence)
indicates that TMI has made no significant contribution to man-made
radioactivity detected in Maryland.

V-36

The State of Maryland opposes any such discharge pending the completion,
evaluation and public review of studies designed to assess the potential
social and economic consequences of the discharge option. The Maryland
position and PPSP assessment of the potential environmental effects of a
processed water discharge are detailed in Appendix A to the FPEIS

D. Radiological Emergency Planning

While the greatest environmental impact associated with the operation of
most power plants occurs during normal day-to-day operation, nuclear power
plants are distinguished by their potential for severe environmental impact
in the event of an accident. While there have been no accidents causing such
an impact in Maryland (or at any nuclear power plant), there has been a
heightened interest in the preparation of Radiological Emergency Plans to
cope with any such accident. This was, of course, motivated by the accident
at Three Mile Island.

Required by Federal regulations are both off-site and on-site Radio-
logical Emergency Plans. Preparation of the off-site portion is the respon-
sibility of the State, while the on-site portion is the responsibility of the
utility company. Preparation of the State of Maryland Radiological Emergency
Plan was underway prior to the accident at Three Mile Island, while BG&E had
in effect a plan as required by its license.

The development of the State's plan was redirected, and vast revision
necessary in the Company's plan as a result of the new Federal Regulations
promulgated as a response to TMI. The Nuclear Regulatory Commission has
published its Final Rule on Emergency Planning (42), and, in conjunction with
the Federal Emergency Management Agency, has published plan development
criteria for state, local and utility planners (43). Both on-site and
off-site portions of the plan have been designed to comply with these reg-
ulations, and were successfully tested in the presence of Federal observers
on November 17, 1981. This was a complete test of both the onsite and offsite
portion of the Radiological Emergency Plan (REP) for the Calvert Cliffs
Nuclear Power Plant, thereby involving the Baltimore Gas and Electric Com-
pany.

An important basis for planning is the concept of Emergency Planning
Zones (EPZ), defined as "areas for which planning is needed to assure that
prompt and effective actions can be taken to protect the public in the event
of an accident" (43). There are two types of EPZs: the plume exposure path-
way (that area within a 10 mile radius of the plant) and the ingestion ex-
posure pathway (that area within a 50 mile radius of the plant).

Maryland must prepare an REP for each nuclear power plant having any
part of its plume exposure pathway within the State. Thus an REP must be
prepared for the Peach Bottom Atomic Power Station (Delta, Pennsylvania) as
well as Calvert Cliffs. The overall REP for the State (44) and that appendix
applying to Calvert Cliffs (45) have been completed; while the appendix for
Peach Bottom is still under preparation. BG&E has completed development and
testing of the on-site plan for Calvert Cliffs (46) while PECO is nearing
completion of the on-site plan for Peach Bottom.

V-37

E. Spent Fuel Accumulation

From the spring of 1977 until October 1981 the commercial reprocessing
of spent fuel was prohibited in this country.1 Because of this, spent fuel
generated at nuclear power plants across the country is stored on site in
spent fuel storage pools. It will be necessary to continue this policy until
one of three events occurs:

1) Reprocessing of spent fuel is undertaken, either by the Federal
government or within the private sector; r
2) Permanent or long-term retrievable storage of spent fuel is made
available by the Federal government; or
3) Away from reactor storage becomes available.

It is unrealistic to expect any of the options to exist before the mid-
dle to late 1980s at the earliest.

These spent fuel pools were never expected to serve their present func-
tion of storing spent fuel for indefinite periods of time. On-site spent
fuel pools were designed to hold spent fuel for cool-down for approximately
one year pending shipment to a reprocessing facility. Fortunately, the
storage of fuel for these unanticipated periods poses no significant environ-
mental threat because fuel elements are at far lower temperatures in the
spent fuel pool than they were in the reactor.

The most significant problem associated with on-site spent fuel storage
is that the finite capacity of spent fuel pools limits how long utilities can
store spent fuel on-site and continue to operate their plants. The current
capacities of and amounts of fuel stored in the spent fuel pools at Calvert
Cliffs and Peach Bottom are given in Table V-20. Assuming present licensed
capacity, and retaining the capacity to discharge one full core, the project-
ed date of the last refueling that can be discharged to the spent fuel pool
at Calvert Cliffs is April 1990. Under the same conditions, Peach Bottom
has ability to store fuel on-site until 1986 for Unit 2, and 1987 for Unit 3.

Table V-20
Capacity (in Fuel Assemblies) of Spent Fuel Pools at Calvert
Cliffs Nuclear Power Plant and Peach Bottom Atomic Power
Station, and Amount of Spent Fuel Presently Stored

Calvert Cliffs Peach Bottom
Both Units Unit 2 Unit 3

Licensed Capacity 1760 2608 2608

Installed Capacity 1358 2608 2608

S ent Fuel in Storage 584 896 712

---------------
IThis policy has been reversed by order of President Reagan and com-
merical reprocessing is now permitted. No group, however, has ex-
pressed an interest to undertake reprocessing, given the uncertainty
of Federal policy remaining constant through succeeding Administra-
tions.

V-38

BG&E is planning an addition to its spent fuel pool which will require
relicensing. PECO has the ability to install additional racks, thereby
increasing the volume of its spent fuel pool. This change would require
relicensing.

F. Radioactive Materials Transportation

Radioactive waste shipments for nuclear power plants in and around Mary-
land are presented in Tables V-21 and V-22. Since January 1978 there have
been 109 and 922 shipments offsite of radioactive waste from Calvert Cliffs
and Peach Bottom, respectively. All of those non-spent fuel shipments from
Calvert Cliffs and Peach Bottom have been to Barnwell, South Carolina.
Three Mile Island also shipped waste to Barnwell prior to the March 28, 1979
accident, but has been prohibited from doing so since then. Shipments of
radioactive waste from Three Mile Island now go to Hanford, Washington.

V-39

Table V-21

Solid Waste Shipped Offsite for Disposal from the
Calvert Cliffs Nuclear Power Plant.

-11978 31979 3 1980
Type of Waste M-1 Ci m Ci M Ci

Spent resin, filter sludge, 80.9 1055 41.1 294.5 47.3 504 F-
evaporator bottoms, etc.

Dry compressor waste, 155.3 59.3 306 53.4 134.3 1.1
contaminated equipment, etc.

Irradiated components, 367 2.18 84.9 623 69.2 14,268
control rods, etc.

P-

Table V-22

Solid Waste Shipped Offsite for Disposal from the
Peach Bottom Atomic Power Station

3 1978 1979 1980
m Ci m3 Ci m3 Ci

6.91 x 10 4 4970 8.47 x 104 8030 9.27 x 10 4 6686

V-4 0

REFERENCES-CRAPTER V

1. Baltimore Gas and Electric Co., Semi-annual Effluent Release Report for
Calvert Cliffs Jan 1978 May 1978. 1978.

2. Semi-annual Effluent Release Report for
Calvert Cliffs June 1978 Dec 1978. 1979.

3. Semi-annual Effluent Release Report for
Calvert Cliffs Jan 1979 May 1979. 1979.

4. Semi-annual Effluent Release Report for
Calvert Cliffs June 1979 Dec 1979. 1980

5. Semi-annual Effluent Release Report for
Calvert Cliffs Jan 1980 May 1980. 1980.

6. Semi-annual Effluent Release Report for
Calvert Cliffs June 1980 Dec 1980. 1981.

7. McLean, R.I., T.E. Magette and S.G. Zobel, "Environmental Radiological
Monitoring in the Vicinity of the Calvert Cliffs Nuclear Power
Plant". PPSP-R-4. (In Press).

8. Baltimore Gas and Electric Co., Radiological Environmental Monitoring
Program Annual Report for the Calvert Cliffs Nuclear Power Plant
Jan I - Dec 31, 1978. 1979.

9. , Radiological Environmental Monitoring
Program Annual Report for the Calvert Cliffs Nuclear Power Plant
Jan I - Dec 31, 1979. 1980.

10. , Radiological Environmental Monitoring
Program Annual Report for the Calvert Cliffs Nuclear Power Plant
Jan I - Dec 31, 1980. 1981.

11. Maryland Department of Health and Mental Hygiene, "Quarterly Environ-
mental Radiological Monitoring Reports" Division of Radiation Con-
trol. 1979-1981.

12. Radiation Management Corp, Peach Bottom Atomic Power Station, Radio-
logical Regional Environmental Monitoring Porgram Jan 1-Dec 31,
1980. 1981.

13. Rafi, A., Balt. Gas & Elec. Co. Personal Communication with R.I. McLean,
PPSP. 1981

14. McLean, R.I., "Radionuclide Concentrations in Chesapeake Bay Oysters
Maintained in the Discharge of the Calvert Cliffs (Maryland)
Nuclear Power Plant. Paper presented at the 26th Annual Conference
an Bioassay, Anal. and Environ. Chem. Oct 14-15, 1980, Ottawa,
Canada. 1980.

V-41

15. McLean, R.I. and S.M. Long, "Gamma-Ray Emitting Radionuclide Concentra-
tions in Selected Environmental Media from the Vicinity of the
Calvert Cliffs Nuclear Power Plant (August 1975-May 1978), Maryland
Power Plant Siting Program, PPSP-R-3. 1978.

16. Maryland Power Plant Siting Program, Power Plant Cumulative Environ-
mental Impact Report, PPSP-CEIR-2. Nov, 1978. 1978.

17. McLean, R.I. and S.M. Long, "Ambient Radiation Levels in the Vicinity of
the Calvert Cliffs Nuclear Power Plant as Determined by Thermo-
luminesence Dosimetry", Maryland Power Plant Siting Program, PPSP-
R-2. 1978

18. United States Atomic Energy Commission, 1973a "Final Environmental
Impact Statement for Calvert Cliffs Units 1 and 2".

19. Philadelphia Electric Co., "Semi-annual Effluent Release Reports for the
Peach Bottom Atomic Power Station, Units 2 and 3 Jan 1, 1978-May
31, 1978". 1978.

20. . "Semi-annual Effluent Release Reports for the
Peach Bottom Atomic Power Station, Units 2 and 3 June 1, 1978-Dec
31, 1978". 1979.

21. "Semi-annual Effluent Release Reports for the
Peach Bottom Atomic Power Station, Units 2 and 3 Jan 1, 1979-May
31, 1979". 1979.

22. "Semi-annual Effluent Release Reports for the
Peach Bottom Atomic Power Station, Units 2 and 3 June 1, 1979-Dec
31, 1979". 1980.

23. - "Semi-annual Effluent Release Reports for the
Peach Bottom Atomic Power Station, Units 2 and 3 Jan 1, 1980-May
31, 1980". 1980.

24. , "Semi-annual Effluent Release Reports for the
Peach Bottom Atomic Power Station, Units 2 and 3 June 1, 1980-Dec
31, 1980". 1981.

25. Radiation Management Corp, Peach Bottom Atomic Power Station, Radio-
logical Regional Environmental Monitoring Program Jan 1-Dec 31,
1978. 1979.

26. Peach Bottom Atomic Power Station, Radio-
logical Regional Environmental Monitoring Porgram Jan I-Dec 31,
1979. 1980.

27. Interex Corp., Peach Bottom Atomic Power Station Regional Environs
Radiation Monitoring Program Jan 1 - Dec 31, 1978. 1979.

28. Interex Corp., Peach Bottom Atomic Power Station Regional Environs
Radiation Monitoring Program Jan 1 - Dec 31, 1979. 1980.

V-42

29. Interex. Corp., Peach Bottom Atomic Power Station Regional Environs
Radiation Monitoring Program Jan 1 - Dec 31, 1980. 1981.

30. McLean, R.I., T.E. Magette and S.G. Zobel, "Environmental Radiological
Monitoring in the Vicinity of the Peach Bottom Atomic Power
Station." PPSP-R-5. (In Press).

31. United States Nuclear Regulatory Commission, Regulatory Guide 1.109
"Calculation of Annual Doses to Man from Routine Releases of
Reactor Effluents for the Purpose of Evaluating Compliance with 10
CFR part 50, Appendix 1." 1977.

32. Rogovin, Mitchell, Director, Three Mile Island, A Report to the Commis.-
sioners and to the Public, Nuclear Regulatory Commission Special
Inquiry Group, 1980.

33. Metropolitan Edison Company, Semi-annual Effluent Release Report for
Three Mile Island Jan. 1978-June 1978. 1978.

34. . Semi annual Effluent Release Report for
Three Mile island July 1978 - Dec. 1978. 1979.

35. , Semi annual Effluent Release Report for
Three Mile Island Jan. 1979 - June 1979. 1979.

36. . Semi annual Effluent Release Report for
Three Mile Island July, 1979 - Dec, 1979. 1980.

37. McLean, R.I. and T.E. Magette, "TMI II Source Term for Accident".
Memorandum to S.M. Long, PPSP, Dec 10, 1979. 1979.

38. McLean, R.I., "Gamma-Emitting Radionuclide Activities of Susquehanna
River and Upper Chesapeake Bay Samples". Memorandum to Dr. S.
Long, PPSP, Dec 10, 1979. 1979.

39. McLean, R.I., "Radiological Monitoring of TMI Effluents and Susquehanna
River Conducted by Other Agencies". Memorandum to S.M. Long, PPSP,
Aug 23, 1979. 1979.

40. United States Nuclear Regulatory Commission, Final Programmatic Environ-
mental Impact Statement Related to Decontamination and Disposal-of
Radioactive Wastes Resulting From March 29, 1979, Accident Three
Mile Island Nuclear Station, Unit 2. NUREG-0863 Vols. I and 2,
March 1981. 1981.

41. McLean, R.I., "Results of Our TLD Monitoring of the Kr-85 Venting from
Three Mile Island " Memorandum to S.M. Long, PPSP, Sept 26, 1980.
1980.

42. United States Nuclear Regulatory Commission, "Environmental Planning;
Final Regulations, 45 FR 55402, Aug 19, 1980. 1980.

V-43

43. United States Nuclear Regulatory Commission and Federal Emergency
Management Agency, Criteria for Preparation and Evaluation of
Radiological Emergency Response Plans and Preparedness in Support
of Nuclear Power Plants, NUREG-0654, Rev. 1, Nov 1980.

44. Maryland Emergency Management and Civil Defense Agency, State of
Maryland Radiological Emergency Plan - Fixed Nuclear Facilities,
Annex Q, Maryland Disaster Assistance Plan, June 1981.

45. Maryland Emergency Management and Civil Defense Agency, State of
Maryland Radiological Emergency Plan - Calvert Cliffs Nuclear
Power Plant, Appendix I to Annex Q, Maryland Disaster Assistance
Plan, June 1981.

46. Baltimore Gas & Electric Co., Calvert Cliffs Nuclear Power Plant Units 1
& 2, Emergency Response Plan, Revision 1, August 1, 1981.

V-44

CHAPTER VI

SOCIO-ECONOMIC IMPACT

The construction and operation of an electric generating station may
have significant economic and social impact upon the community where it is
located. Among the many possible effects usually considered are changes in:

. population, housing and school enrollment
. land use patterns
. transportation and congestion
. income, employment, and business activity
. local government spending and tax revenues

For convenience, these effects are usually divided into changes
affecting the social and economic functions of the private sector and changes
affecting tax revenues and the demand for services in the public sector.

The socio-economic effects of power plant construction stem from the
rapid increase in population resulting from a sudden increase in the local
work force during plant construction. The influx of workers who relocate
within the area, as well as commuters, can potentially create demands that
exceed the capacity of the public and private services, facilities, markets,
and institutions -- the local social and economic infrastructure -- which
serve a given community, county, or region. The magnitude of these social
and economic effects depends on several factors, particularly the size of
the construction project, the size and diversity of the economic base of the
local economy, and the infrastructure of the local community. Jurisdictions
with a large and well developed economic base are generally more able to
meet the service, employment, and economic requirements of major construction
projects more readily than jurisdictions lacking this asset.

The most recent major power plant construction project in a rural
Maryland community was Calvert Cliffs (completed in 1975). Some preliminary
data about the socio-economic effects of this project has been released (1,2)
and the results from a more comprehensive study will be available in 1982.
These studies showed the need for a means of predicting impacts on the pre-
dominantly rural communities which are the proposed sites for future power
plants in Maryland. Consequently the Maryland Power Plant Siting Program
(PPSP) supported the development of a socio-economic impact assessment model
(3). This model, which was subsequently computerized (4), was first applied
as part of the Eastern Shore Power Plant Siting Study which evaluated four
sites potentially suitable for fossil and nuclear power plant development on
the Eastern Shore ot Maryland (5). An estimate of the socio-economic impacts
that would result if these sites were developed for power plant use were
described in the 1978 Cumulative Environmental Impact Report.

Most recently, this model has been used to estimate the social and
economic effects of the expansion of the existing Vienna generating station
by Delmarva Power and Light Company (DP&L). DP&L has applied for a Certifi-
cate ot Public Convenience and Necessity to construct a 500 MW coal-fired

VI-1

generating unit, Vienna Unit 9. Because the application included the option
of constructing capacity of up to 600 MW, social and economic impact studies
of the Vienna expansion were based on a 600 MW plant design.

The Vienna analysis provides the most recent data illustrating the
potential effects of power plant development within Maryland. The results of
this analysis are presented here as an illustration of typical socio-economic
effects. This analysis is particularly significant since the Vienna location
is typical of the rural Maryland setting where future power plant development
is most likely to occur.

A. Employment, Population, Housing and Fiscal Effects

The magnitude of socio-economic effect is determined by a variety of
very specific factors, including:

* the size of the plant under construction and its design,
both of which influence labor force size

* the location ot the plant site with respect to the nearest
major cities, which influences the proportion of the work
force that commutes rather than becomes immigrant PF
- the size and economic base of the local communities, which
influence the extent to which local municipal and county
governments experience increased revenues due to increased
local business activity.

The driving force for socio-economic effects is the large labor force
necessary for the construction of a modern power plant. It has been esti-
mated that at the peak of construction activity, some 3,200 workers would be
involved in the construction of a two-unit, 2,400-MW nuclear power plant (5).
At the peak, the work force for a single unit, 600 MW station has been esti-
mated to be approximately 1,000 workers (6).

While construction goes on, these workers purchase goods and services
from the local retail economy, increasing local business retail activity.
This, in turn, leads to increased wholesale business activity. The result is
an increase in local income and employment. It is the sum of these employ-
ment.gains (direct construction labor plus the additional employment induced
by the increase in local business activity) that is the principle driving
force for the local effects which occur during the construction phase.

The scale of the effects that these employment changes have on local
social and economic conditions depends primarily on two factors: the ability
of the local region or county to provide workers from its own population, and
the ability of the local community to absorb the new workers who decide to
move in during the construction period. These factors are a function of the
existing population base and the size and economic integration of the local
economy.

VI-2

Most of the rural counties of the State are located within a relatively
short distance (measured in driving time) from the more populous counties and
larger metropolitan areas. As a result, even in these rural counties, many
of the more severe social and economic effects that may result from large
construction projects are mitigated by the relative proximity to large labor
force concentrations and urban centers,

Vienna Study

The analysis of the proposed Vienna Unit 9 provides an indication of the
scale of the impacts which are likely to result from the construction of what
is by current standards a smaller size generating station in a rural, non-
suburban Maryland county. In order to understand the impacts of development
on a rural economy in Maryland, it is necessary to understand the economic
structure of the local community. Because the town of Vienna is located on
the border between Dorchester and Wicomico Counties, it is likely that the
presence of two urban centers, Cambridge and Salisbury, will serve to buffer
adverse impacts because of their relatively well-developed economic base and
infrastructure. At the same time, the presence of these cities is likely to
improve the ability of the area's economy to obtain maximum benefit from
power plant development.

Vienna is almost exactly equidistant from Cambridge (1980 population:
11,703) and Salisbury (1980 population: 16,429) both of which are 16 miles
from the town. The town of Hurlock, approximately 10 miles to the north, is
the closest moderately sized community (1980 population: 1,690). The Vienna
Unit 9 site is immediately north of the existing Delmarva Power and Light
Company (DP&L) plant on the north side of the community of Vienna.

Land use and development trends in the vicinity of the Vienna site are
typical of many portions of rural Maryland. There have been almost no new
homes built within the town of Vienna and its immediate environs during the
1970's. Commercial and industrial development has also been minimal during
this period. The market for residential development in the area is quite
limited, and the lack of vacant land within the town, problems of failing
septic systems, and the reluctance of surrounding property owners (primarily
farmers) to develop their property have all contributed to the lack of
development (7).

Most of the adverse socio-economic effects of power plant development
result from the influx of a large construction work force. These effects are
usually largest when the number of workers who move into the local area
during the construction period represents a significant proportion of the
local population. In the case of the Vienna plant, most workers would be
hired from outside of the immediate Dorchester - Wicomico County area because
the local labor force does not contain a large enough pool of workers with
the appropriate heavy construction skills.

DP&L has provided estimates of the number of workers required to con-
struct and operate the Vienna plant as shown in Table VI-1. The construction
of a 600 MW unit at Vienna is estimated to require a maximum of 1,005 workers
at the peak of the five year construction period. Of those workers, most are
expected to be hired from outside the local economy, only 12.5 percent of the
peak work force would come from the Dorchester - Wicomico labor force. Some

VI-3

of these "outside hires" are expected to relocate to the general vicinity of
the construction site. Approximately 30 percent of the workers who do
relocate are projected to move into Dorchester County.

TABLE VI-I
Workers Required to Construct And Operate Proposed
Vienna Power Plant
1983-1988

,Outside Local Total
Year. Hires Hires Hires

Construction Period

1983 57 29 86
1984 468 121 589
1985 879 126 1005
1986 737 98 835
1987 348 96 444

Operating Period

19881 30 70 100

'First full year following start of plant operations. The number of
workers required to operate Vienna 9 is expected to remain constant at the
1988 level during the life of the plant.
Data from Reference 8.

The total number of jobs likely to be generated in the local economy by
the Vienna power plant is shown in Table VI-2. Approximately 300 county
residents are expected to be employed by DP&L and local employers on or off
the construction site during the peak construction year. This effect on
employment is likely to be well within the ability of the local economy to
absorb. This estimate represents only 2 percent of the employed Dorchester
County work force and 20 percent of the total unemployed labor pool in 1977.
Although some of these jobs would be filled by workers shifting from their
existing occupations to higher paying jobs at the construction site or in the
local area, the number of these workers is likely to be too small to
adversely affect the labor supply of existing firms.

The workers who gain employment on or off the construction site as a
result of the Vienna power plant construction and who relocate into
Dorchester County are not expected to have a significant impact on county
population, housing demand, or schools. County population at the time of
peak construction activity is expected to increase by approximately 150
people, with an increase in school population of approximately 30 students.
The total population increase translates to an increase in housing demand of
less than 50 units at peak. This additional demand for housing represents
only 14 percent of the 350 housing vacancies that are currently projected as
the number of units available for rent or sale in 1985 in the absence of

VI-4

TABLE VI-2

Jobs Generated by Vienna Power Plant in Dorchester County
Direct and Secondary

1983-1988

County At Construction Site Secondar
Year Residents Immigrantsi Subtotal Jobs Total

Construction Period

1983 13 2 15 24 39
1984 55 21 76 136 212
1985 57 55 112 247 359
1986 44 37 81 112 193
1987 43 13 56 21 77

Operating Period
19883 32 9 41 3 44

lNumber of workers hired from outside the local area who reside in
Dorchester County as of the given year. Excludes employees who stay in
motels during the week and commute to their homes on weekends.
2Filled by county residents.
3First full year following start of plant operations. The number of
jobs generated by the power plant is expected to decline to 41 by 1990 and
then stabilize for the remainder of the operating period.

Data from Reference 6.

VI-5

power plant construction. Sufficient rental units of all types are projected
to be available to meet this demand. The additional demand of 50 units in a
county of the size of Dorchester is not expected to have a significant effect
on the local housing market other than to reduce the average monthly housing
vacancy rate. These effects are summarized in Table VI-3.

The increase in the number of workers during the construction phase will
result in an increase in the demand for public services. This increase stems
in part from the variety of services, such as police and fire, required by
,the total increase in work force, including commuters. Most of this increase
comes from those workers who move into the county and make use of schools,
fire and police protection, water and sewage treatment, social services and
general public administrative functions.

In response to this increased demand for services, local governments
have several options available. Public officials may choose to maintain
services at the existing per capita level, which would require increasing the
local government budget in proportion to the population increase. Alterna-
tively, recognizing the short-term nature of the increase, public officials
may permit the per capita level of services to decline by not expanding them
in proportion to the population change. At the limit, services may not be
expanded at all. Because the population increases and increased service
requirements that do occur are likely to be relatively small and of short-
term duration, local officials have frequently found it unnecessary to
greatly expand services and budgets.

Balanced against this demand for services is an increase in revenues.
Before the plant comes on line, increased housing prices, new construction of
houses, increased local income and business activity will all increase tax
revenues. After the plant begins to operate, the county receives revenues
from property and capital taxes of the plant.

Table VI-4 summarizes the fiscal effects on several jurisdictions during
plant construction and operation. The estimates are based on the assumption
that average per capita services are maintained by increased provision of
services and represent additional local tax revenues and public expenditures
which result from power plant development.

It is seen that throughout the construction period, neither the local
municipality of Vienna nor the City of Cambridge (the county seat) are likely
to experience significant fiscal effects, and that throughout the period
additional tax revenues from construction-related economic activity will more
than offset any additional expenditures. Throughout the construction period,
Dorchester county government is expected to experience an increase in reve-
nues which exceeds projected increases in expenditures.

Table VI-4 also shows the expected total revenues and total expenditures
during the operating period. The net fiscal effect on Vienna and Cambridge
during the plant's operating years is expected to be neutral. However, in
the case of Dorchester County, the fiscal impact of the operation of Vienna 9
is likely to be substantial, approximately $4.8 million annually in 1978
dollars. That revenue represents approximately 400 percent of the County's
Fiscal Year 1981 budget, and is an understatement of the fiscal effect due to
the use of 1978 dollar estimates for revenues. These revenues stem largely
from the property taxes paid by the utility.

VI-6

TABLE VI-3

Total Housing Demand Population and School Children
from Proposed Vienna Power Plant Estimated by Year

1983-1988

Additional School Children
Immigrating Housing Cumulative Grade High
Year Workers Demand Population School School College Total

Ronstruction Period

1983 2 2 5 1 0 0 1
1984 21 19 58 7 3 1 11
1985 55 48 151 19 8 2 29
1986 37 33 103 13 5 1 20
1987 13 11 35 4 2 0 7

Operating Period
19881 9 8 25 3 1 0 5

lFirst full year following start of plant operations. Total housing
demand, population and school children during 1989 and the remainder of the
operating period are expected to remain constant at 1988 levels.

Data from Reference 6.

VI-7

In Wicomico County only the city of Salisbury is expected to experience
a construction period deficit. That deficit is likely to be very small, and
is subsequently offset by small operating surpluses.

Table VI-4
Net Fiscal Impacts for
Plant at Vienna

Total During Yearly Total
Jurisdiction Construction During Operation

Dorchester Co. $ 261,600 $4,840,700
Cambridge 15,000 1,700
Vienna 700 500

Wicomico Co. 114,000 27,000
Salisbury (-6,300) 3,500

State of Maryland 3,320,500 461,500

Data from Reference 6.

Eastern Shore Study

Local fiscal effects of power plant construction are strongly affected
by local tax rates. As a result, these effects vary from locality to
locality. The variability in these effects can best be illustrated from data
prepared for an evaluation of four alternative power plant locations on
Maryland's Eastern Shore. These results are summarized in Table VI-5 which
show the fiscal effects of the construction of a plant with a peak work force
of 3,200 workers.

The variations that exists between counties are the result of dif-
ferences in the various tax rates and in the extent to which workers move
into the county and provide increased tax revenues through increased property
values and taxes, increased sales taxes, and business taxes. Dorchester and
Wicomico Counties, which experience the largest absolute increase in popula-
tion, and which also have more extensively developed infrastructures,
experience a balanced flow of revenues and expenditures. The other counties
and all of the cities (which experience much of the population impacts but
less of the revenue benefits because of plant location) experience deficits
throughout the construction phase.

As seen in Table VI-5, the county deficits are signficiant, but are
manageable in size. In the case of three of the four cities, however, the
deficits are of very substantial proportions. Those municipal deficits would
require either outside assistance, local tax inreases, or potentially signi-
ficant reductions in the per capita level of services provided. At both the
county and municipal levels, service reductions or tax increases may aggra-
vate the congestion, housing and other difficulties experienced during con-
struction.

VI-8

Table VI-5

Projected Fiscal Impacts of
2400 MW Power Plant Development,
Various Jurisdictions, Peak Conn5uction Year
and Operating Period a
(1977 Dollars)(b)

Peak Construction Year Deficit as Operating
Total Total Surplus % of (c) Period
Jurisdiction Revenues Expenditures (Deficit) Revenues Revenues

Kent County $735,600 $912,700 $077,100) 4.0% $36,000,000

Chestertown 50,100 84,700 (34,600) 13.8%

Queen Annes 565,200 650,100 (84,900) 1.9% 271000,000

Centreville 24,500 46,400 (21,900) 21.3%

Dorchester 1,010,000 982,900 27,100 40,000,000

Cambridge 189,800 329,000 (139,200) 13.3%

Wicomico 1,116,800 1,088,800 28,000 28,000,000

Salisbury 113,700 195,800 (82,100) 2.9%

(a) This study was done for a two unit 2400 MW nuclear plant. No nuclear
plant is under consideration for the Eastern Shore. The socio-economic
impacts do not depend on the type of plant, therefore the study is
representative of any plant requiring the stated labor force.

(b) Rounded to nearest $100.

Data from Reference 5.

VI-9

B. Coal Transportation Effects

DP&L's 600 MW Vienna Unit 9 would use 1.5 million tons of coal a year at
an annual capacity factor of 68 percent. On A weekly basis, coal consumption
would range between 28,800 and 42,300 tons at 68 and 100 percent capacity
factors, respectively. For coal shipped by rail, DP&L expects to rely
largely on 100 car unit trains with a capacity of 100 tons of coal per car.
On this basis there would be between 2.9 and 4.2 unit trains per week
traveling each way to maintain the coal supplies. There would be at least
15,000 coal cars a year traveling over the Delmarva rail system each way. By
comparison, approximately 1,000 carloads are expected on the Dorchester seg-
ment of the Cambridge to Seaford line in Fiscal Year 1980.

There are two positive effects on the Eastern Shore economy resulting
from a decision to transport coal to Vienna by rail: an improvement in rail
service due to the upgrading of track conditions in order to serve the heavy
loads of coal trains, and long-term assurance that rail operations would be
profitable along the applicable branch rail lines. The possibility that rail
service might be abandoned would therefore be reduced.

More efficient rail service and reduced travel time between the Eastern
Shore and potential markets for local industries could allow rail users to
compete in more distant markets and/or improve local profit margins. In
addition firms considering the Eastern Shore as a possible location would
find the area more attractive with improved rail service. Although the
quality of rail service is only one of the many factors a firm would consider
in making a locational choice, industries dependent on shipping bulk goods
long distances would weigh this factor highly.

If the Vienna site is approved for the power plant and coal is trans-
ported by rail, the incentive to maintain rail service on the entire
Cambridge to Seaford line would be even stronger than it has been. This
could prevent rail abandonment of the Cambridge segment of the line, and
could have a significant effect on the Dorchester and Caroline County
economies.

In a period of failing local rail gervice through many areas of
Maryland, the impact of improved rail service to present and potential future
users can be an important economic benefit from the development of a coal-
fired power plant.

There is also a potentially adverse impact of coal shipment by rail:
the inconvenience which results from traffic crossings and local noise. Both
effects are determined by site-specific conditions.

At Vienna, trains would cross a number of highways at grade at
relatively slow speed, causing periodic delays for cars., trucks and other
highway users. The amount of delay is dependent on the train speeds, which
in turn are controlled by the quality of the track and roadbed. Specific
plans for upgrading the Cambridge to Seaford line have not yet been formu-
lated. It appears reasonable to assume, however, that the line would be
upgraded to Class II standards, allowing a speed of 25 mph. On that basis,

VI-10

the 100 car unit trains, which would be approximately 5,000 feet long, would
take between 2 and 3 minutes to cross an intersection. Warning devices and
driver hesitation would increase the delays somewhat, perhaps up to 4
minutes. It is possible that the trains would travel more slowly, particu-
larly through towns such as Hurlock. If the trains travel at only 5 mph,
they would take between 11 and 12 minutes to cross an intersection. Adding
delay time may increase this period to about 13 minutes.

C. Traffic Congestion Effects

Increased numbers of resident and commuting workers to a power plant
site during the construction period frequently produce traffic congestion.
The impact on traffic conditions is a function of the increase in the number
of commuters and the available carrying capacity of the relevant local trans-
poration routes. Because the severity of traffic congestion is likely to be
dictated by local conditions it is not possible to reach a general conclusion
about the extent to which traffic congestion during plant construction can be
mitigated. With adequate advance planning, severe congestion problems that
result from existing bottlenecks can be eliminated by altering highway im-
provement schedules. Congestion resulting from construction period over-
crowding of otherwise adequate roads and bridges may be reduced by adjusting
work schedules and traffic flow patterns. The extent to which mitigation
measures will succeed in reducing traffic congestion depends on the ability
to make the appropriate long-range planning decisions.

Vienna Study

Traffic impacts for the Vienna site were examined in detail for the 1985
peak construction year (6). This analysis revealed that the highway level of
service on the two lane segment of U.S. Route 50 in the Vienna area will be
unacceptable in 1985 even without the incremental effect of commuting con-
struction workers. The incremental impact of commuting construction workers
would increase traffic congestion on this highway segment, particularly for
the highway west of the interchange at Route 331. However, plans by the State
Highway Administration (SHA) to construct a northern bypass around Vienna to
reduce traffic flow through the town will reduce or eliminate this problem.

Traffic impacts at the U. S. Route 50-Route 331 intersection at Vienna
were also examined for 1985. This analysis revealed that the incremental
traffic resulting from the commuting construction workers would result in an
unacceptable level of highway service through this intersection during the
summer months. As part of its review of the Vienna plant, SHA proposed high-
way improvements at the intersection to minimize backups and the potential
for intersection related accidents. These improvements are estimated to cost
$120,000 in 1980 dollars and would normally be paid for by the utility, and
would greatly reduce the projected congestion problems.

Other Studies

The study of four Eastern Shore counties estimated (3) that the increase
in the number of commuters coming into the counties ranged from 103 percent
(2,524) to 664 percent (3,101). The county receiving the largest increase

VI-11

(relative and absolute) in the number of commuters was the least likely to
experience significant traffic congestion because of the capacity of the
major roads leading to the area. For each of the other three counties, signi-
ficant traffic congestion was projected to occur at particular points. Those
congestion points were all located at two-lane bridges crossing rivers in the
area. In each case, the congestion point had been previously identified by
the Maryland Department of Transportation in its long-range plan.

In the case of Calvert Cliffs, a traffic increase of an estimated 1,200
vehicles was experienced during the morning shift. That increase represented
150 percent of the hourly capacity per lane of the major two-lane road used
to reach the plant, resulting in significant rush hour congestion (1).

D. Cumulative Local Tax Revenues from Maryland Electric Utilities

Once a power plant comes on line, the local county government receives a
significant increase in tax revenue from the utility. The revenues received
by local governments once a plant begins to operate provide new flexibility
in the options availabe to the locality, including capital improvements,
improvement of the local housing stock, expansion of social service activi-
ties, and reductions in tax rates. Table VI-5 provided estimates of tax
receipts projected for four Eastern Shore counties during the construction PF
and operation of a new power plant. The variation in the tax receipts during
the operating period is largely the result of differences in tax rates among
the counties. However, in all cases the increase in tax receipts after the
plant comes on line is substantial.

Due to very high capital cost of modern base-load units, tax receipts
from these facilities tend to be substantial. Tax revenues received from a
power plant can dwarf other revenues and expenses in the budget of a rural
county. It is not uncommon in such cases for the county to reduce tax rates
significantly, which has the effect of reducing power plant tax revenues as
well. The rate reductions have occurred in Calvert County as a result of the
tax revenues received form the Calvert Cliffs nuclear plant (2).

Table VI-6 gives the revenues received by all Maryland counties from
electric ut lities and also indicates the size of the revenue increase rela-
tive to the county budgets. These tax payments vary substantially, and
depend largely on the size, age, and fuel type of the facilities owned by
utilities in each county, as well as on local tax rates. The presence of
power plants in Anne Arundel, Baltimore, Calvert, Montgomery, and Prince
George's Counties and in Baltimore City are evident in the tax receipts of
these counties. The impact of a large facility on the budget of a largely
rural county is most evident in Calvert County. However, even the presence of
an older plant in a rural county has some impact, as may be seen in the cases
of Charles and Dorchester Counties.

VI-12

M N'M

Table VI-6

Electric Utility Tax Payments to Maryland Counties
Fiscal Year 1980-81

% of County
Budgeted Total % of County
-County BG&E -DP&L APS/PE PEPCO Total tax receip s Operating Budget

Allegany 976 262,597 263,573 1.50 1.18
Anne Arundel 5,110,573 18 5,110,591 3.44 1.75
Baltimore City 18,905,402 2,041 18,907,443 5.83 1.61
Baltimore County 10,291,334 55 10,291,389 3.31 2.52
Calvert 11,089,717 4 11,089,721 49.43 50.62
Caroline 1,120 231,080 232,200 4.89 3.83
Carro @al) 678,730 82,916 761,646 2.47 (a) 1.91
Cecil 46,854 7,331 54,185 .34 .25
Charles 475 3,838,019 3,838,494 15.40 12.10
Dorchester 1,707 585,197 586,904 7.64 5.44
Frederick 68,814 1,163,251 30,127 1,262,192 3.14 2.80
H Garrett 151 344,583 344,734 3.43 3.07
(a)
Harford 1,773,674 3 1,773,677 3.72 2.61
Howard 1,515,004 10,286 1,525,290 2.50 1.72
Kent 1,013 163,180 23 164,216 3.34 2.45
Montgomery 102,795 351,223 10,055,283 10,509,301 2.77 1.59
Prince George's 891,161 57 12,301,680 13,192,898 5.35 2.79
Queen Anne's 1,674 196,176 197,850 2.61 2.20
St. Mary's 553 168,704 169,257 1.18 .81
Somerset 744 121,934 122,678 3.49 2.29
Talbot 3,982 59,649 63,541 .89 .55
Washington 2,973 685,356 688,329 2.21 1.90
Wicomico 1,752 377,696 379,448 2.33 1.40
Worcester 968 246,613 247,581 2.01 1.49
TOTAL 50,492,056 1,988,856 12,902,413126,393,813@81,777,138

(a) Also receives taxes from Conowingo Power Co., (not included).

Data from Reference 9.

REFERENCES - CHAPTER VI

Department of Natural Resources. Review of Socio-Economic Impacts of
the Calvert Cliffs Nuclear Power Plant on Calvert County, Maryland
and Comparison with Kent County, Maryland. Maryland Power Plant
Siting Program. 1975.

Flynn, James. Socioeconomic Impacts of Nuclear Generating Stations,
Calvert Cliffs Case Study. Nuclear Regulatory Commission.
(Draft). 1980.

3. Rogers and Golden. Economic, Fiscal and Social Assessment Handbook,
Volume 3, Maryland Major Facilities Study. Department of Natural
Resources, Maryland Coastal Zone Management Program. 1977.

4. Harms, Peter L. Regional Impact of Facility Location on the Economy -
Users Guide, Maryland Economic, Fiscal and Social Impact Assessment
Model. Department of Natural Resources, Coastal Resources Divi-
sion. (DRAFT) 1980.

5. Rogers and Golden. Eastern Shore Power Plant Siting Program. 1977.
Department of Natural Resources, Maryland Power Plant Siting
Program, PPSA-4. 1977.

6. Blinder, Calvin L. Prediction of Socio-Economic Impacts by the Proposed
Unit No. 9 at Vienna and Alternative Sites. Department of Natural
Resources, Maryland Power Plant Siting Program, PPSE 8-7. 1981.

7. Blinder, Calvin L. Land Use and Development Trends in Dorchester and
Wicomico Counties. Department of Natural Resources, Maryland Power
Plant Siting Program, PPSE 8-12. 1981.

8. Delmarva Power and Light Company. Amended Application for Certificate
of Public Convenience and Necessity, Vienna Power Station Unit 9.
1979.

9. Data for this Table were provided by the following sources:

Bannon, Thomas P. (Potomac Electric Power Company). 1981. Letter
to Howard A. Mueller (PPSP). August 28, 1981.

Bryson, Robert (Conowingo Power Company). 1981. Personal Communi-
cation.

Hinkle, M. F. (Baltimore Gas and Electric Company). Letter to Howard
A. Mueller (PPSP). September 10, 1981.

McDowell, D. R. (Delmarva Power). Letter to Howard A. Mueller (PPSP).
August 31, 1981.

Powell, Mehrl L. (Potomac Edison Company). Letter to Howard A. Mueller
(PPSP). August 11, 1981.

VI-14

CHAPTER VII

NOISE IMPACT

An evaluation of the impact of a power plant includes an evaluation of
noise (1). This evaluation will typically consist of the following steps:

Identification of the noise sources of the facility and a description
of the nature of the emissions,
Analysis of noise propagation to off-site areas,
Evaluation of already existing noise (ambient noise) in off-site
areas,
Evaluation of the effects of the intruding noise on people,
Consideration of constraints and mitigation if necessary.

Noise can be described either by spectrum components or overall energy
levels. The more complete description is by spectrum components in which
sound energy is quantified at different frequencies. This is an important
method of characterizing sound since the human ear has a sensitivity which
varies markedly with frequency. Propagation characteristics are also
frequency dependent. Typically, a spectrum description will use nine
separate octave bands, centered at intervils between 31 and 8000 Hz. The
sound energy is reported in decibels W).

The individual octave bands are weighted according to the frequency
sensitivity of the human ear. An overall sound level, described as the
"A-weighted sound pressure level", reported in units of dBA can be obtained.
Table VII-1 lists several common sources of noise in terms of their overall
dBA levels.

Since many noise sources fluctuate over time, statistical descriptions
of the A-weighted sound can be defined. The following descriptors are
frequently used:
Leq (equivalent sound level), is the A-weighted sound pressure level
averaged over a 24-hour period,

Ldn (day/night sound level), is the dBA sound level averaged over a
24-hour period, but where the noise levels between the hours from 10
PM to 7 AM are treated as if they were 10 dB greater than the actual
level,

---------------
lAn octave is a doubling of frequency. An octave band analyzer will add up
all the energy that exists in a particular band of frequencies that is one
octave wide.
2A decibel description of sound energy needs to state a unit of reference.
For acoustics, as applied to noise and human hearing, the reference (zero dB)
is approjimately the quietest sound a person with good hearing can hear
(20 jiN/m ). The decibel is a logarithmic unit, an increase of 3 dB corre-
sponds to a doubling of the energy level.

VII-1

TABLE VII-1.
Typical A-Weighted Sound Levels Measured with a Sound-Level Meter

DECIBELS

140

50 HP Siren (100')
130

Jet Takeoff (2009
120

Riveting machine 110

100
Textile Weaving Plant
Subway Train (20')
90 Boiler Room
Pneumatic Drill (501) 80 Inside Sport Car (50 MPH)

Freight Train 0009
Vacuum Cleaner (101) 70
Speech (19
Near Freeway (Auto Traffic)
60 Large Store

Large Transformer (200') Private Business Office
50

Average Residence
40 Nightime Residential areas

Soft whisper (59
30

Threshold Of Hearing 0

Note: These values are taken from the literature. Sou.nd-level measurements
give only part of the information usually necessary to handle noise problems,
and are often supplemented by analysis of the noise spectra.

VII-2

L10, L50, 1,90 are dBA sound levels that are exceeded for 10, 50, and 90
percent of the time, respectively.

A. Noise Sources

Major power plant noise sources can usually be categorized as follows:

' The primary generating facility, consisting of turbines, generators,
and associated equipment,
. Cooling towers (natural or mechanical draft),
* Coal handling machinery, consisting of bulldozers, conveyors, and
crushers,
. Large vehicles (trucks and trains).

The first category, the primary generating facility, contains a multi-
tude of individual noise sources, such as fans, furnaces, turbines, gene-
rators, outdoor paging systems, etc.

Cooling towers can also be a significant source of noise from a power
plant. Natural draft cooling tower noise is produced by the sound of falling
water, a mechanical draft tower generate additional fan noise. Fan noise
generally dominates the noise spectrum for frequencies below 2000 Hz, while
water noise dominate above. Table VII-2 lists octave band and dBA levels for
noise measured at various points surrounding several plants. Five plants
are listed ranging from a small diesel plant (48 MW) to a large nuclear plant
(1645 W. The lowest noise emissions was from the nuclear facility. The
small diesel plant produced noise levels comparable to the largest coal-fired
plant. The noise from such a small plant, when propagated to neighboring
areas, can actually be more significant than that from a larger facility,
because of the relatively small land area often allocated to a small
facility.

In addition to the broad band noise sources discussed above, discrete
tones must also be considered. A discrete tone results from concentration of
sound energy into a narrow band of frequencies. For a given amount of
energy, a discrete tone is more noticeable than broadband noise. Because a
relatively small addition of energy in the form of a discrete tone can in-
crease the annoyance value of a noise, noise regulations often require a 5 dB
lower noise level if prominent discrete tones are contained in the intruding
noise.

Noise emissions from most power plants do contain discrete tones,
usually related to the rotation rates of large generating machinery. However,
with one exception, past studies did not find discrete tones strong enough to
increase the annoyance potential of the noise emissions.

VII-3

Table V11-2
Octave-Band Noise Under Full Load at 1000 Feet from Plant Edge. (a) Plants Under Full Load

Band Coal-Fired Coal-Fired Coal-Fired Nuclear Diesel
Center PLANT I PLANT II PLANT III PLANT IV - (1,645 MWe) PLANT V- (48MWe)
(11z) (550 Me), (550 Me) (1,500 Mel Front Sides Back Front Sides Back

31 64.1 60.1 70.9 55.7 52.7 59.7 68.0 67.0 73.0
62 62.1 58.1 69.9 54.7 53.7 59.7 59.0 65.0 68.0
4i 125 57.1 57.2 68.0 52.8 50.8 59.8 56.9 63.9 67.0
H 250 53.2 49.2 59.1 47.8 45.8 50.8 54.9 56.9 59.9
H 500 52.4 48.5 56.3 42.0 39.0 47.0 50.6 52.7 54.7
1K 46.8 43.0 53.7 39.5 33.5 41.5 45.1 55.1 56.1
2K 38.9 35.5 52.3 32.8 29.8 39.8 40.6 51.6 48.6
4K 24.8 27.3 52.0 22.2 17.2 30.2 32.9 43.9 41.9
8K 2.1 17.7 40.0 12.5 -1.5 18.3 18.4 26.4 25.4

dBA 52.7 49.3 60.7 45.2 42.1 49.7 52.4 58.9 59.7

(a) Values in dB, with reference to 20,01m 2

I I I I I I PF

B. Noise Propagation

Calculations are required to determine the noise levels that will be
propagated from a noise source to off-site areas. In this process, it is
necessary to consider the following points:

� geometric spreading (the dilution of sound energy as it propagates
away from a source);

�atmospheric absorption (the loss of sound energy as it is converted
into heat in the air);

�absorption by vegetation (usually trees);

.obstruction by barriers (terrain or buildings which block the line-of-
sight path between the source and listener).

The overall noiseIis the sum of the noise energy propagated from each source
to a given point.

These calculations must be performed for numerous points surrounding the
plant. The results can be summarized in terms of dBA contours, i.e., the
line which connects points which have equal dBA levels. Figures VII-1 and
VII-2 show examples of dBA contours for two typical facilities. Figure VII-1
refers to a coal burning facility consisting of an existing 550 MW plant and
two proposed 850 MW units. Figure VII-2 applies to a diesel generating
facility consisting of eight units, each of 6 MW capacity. The effect of
shielding by trees is included. As mentioned earlier, the small diesel
facility propagates considerably more noise beyond the plant site boundaries
than the large coal-fired facility.

C. Effects of Noise on PeORle

Several indices may be examined to determine how people will be affected
by intruding noise. One such method correlates noise levels to various
social/physiological functions; i.e.,

* actions taken by citizens, such as formal complaints or lawsuits,
* people's responses on social survey questionaires,
interference with understanding of speech,
interference with sleep.

Figure VII-3 shows an example of an evaluation procedure documented by
the U.S. Environmental Protection Agency (EPA) in which the intruding noise
is correlated with observed community actions. Table VII-3 shows a number of
correction factors in the EPA method which account for conditions that could
make a given problem more or less sensitive compared with a base-case. In

---------------
lIt is not correct to add dBA levels arithmetically when computing the com-
bined noise from several sources. For example, two sources each at 50 dBA
would have a combined level of 53 dBA.

VII-5

..........
-X....d`: X ......
............ ... ................ .............
................. ......
........ ... ........... ..
. .........
..... .............
.. .. .... .. .........
..................... ........ ... ....
.......... .......
............ X XX X
X . . -:-X

X X ww-;

...........
..........

............ .
.-:50 ...
....... .......
....... ... ...

............ ....
55 dBA
..... ............... .

........ ..........
........ .......
"D. Cooling
Coal
New Plant:':
1W I
.... ........
*--@Cooling Tower
.... ..... ...... .........
.... .... .................
......... .....
-X-X
............
. ..... ...
.. ...... Coal-,
Handling Large
.................
-:-X
0 ..X.Existing Plant - Truck
X
X..
............
0
Ian
. ......... .....
B ou nda ry
x
..... ... ..... ....

... .... . ...... ...

............ ..
........... ......
............ .. ....
....................... .. xx.@ ....
......:::.:.:.:.Contours do not apply 0 1 2 3 4 5
Towpath - See Text
ce(, .......
U@ :.00.0,feet)
Fig. VI I-1 Noise Contours Calculated for Coal Burning Plant PF

Airport

Industrial Park
Plant Boundary`\

les) Tree Screen

Residential Area

0 100 0 2000
Distance in feet

Fig. VII-2 Noise Contours Calculated for Diesel Plant

VII-6

Table VII-3
Corrections to be Added to the Measured Day-Night Sound Level (Ldn)
0f Intruding Noise to Obtain Normalized (Ldn)
(As recommended by Enviromental Protection Agency) Amount of
Correction
to be Added
Type of to Measured
Correction Description Ldn in dB

Seasonal Summer (or year-round operation) 0
Correction Winter only (or windows always closed) -5

Correction Quiet suburban or rural community (remote from large +10
for Outdoor cities and from industrial activity and trucking)
Noise Level
Measured in Normal suburban community (not located near industrial +5
Absence of activity)
Intruding
Noise Urban residential community (not immediately adjacent to 0
heavily traveled roads and industrial areas)

Noisy urban residential community (near relatively busy -5
roads or industrial areas)

Very noisy urban residential community -10

Correction No prior experience with the intruding noise +5
for Previous
Exposure and Community has had some previous exposure to intruding 0
Community noise but little effort is being made to control the
Attitudes noise. This correction may also be applied in a situ-
ation where the community has not been exposed to the
noise previously, but the people are aware that bona-
fide efforts are being made to control the noise.

Community has had considerable previous exposure to the -5
intruding noise and the noise maker's relations with
the community are good

Community aware that operation causing noise is very -10
necessary and it will not continue indefinitely. This
correction can be applied for an operation of limited
duration and under emergency circumstances.

Pure Tone No pure tone or impulsive character 0
or Impulse Pure tone or impulsive character present +5

VII-7

Figure VII-3, the assumptions are that the plant noise is continuous, the
surrounding community is of a quiet suburban or rural type with some prior
exposure to the intruding noise, windows of residences are assumed to be
partially open, and the noise does not contain prominent discrete tones.

D. State Noise Regulations

The State of Maryland has noise regulations which restrict the noise
levels that a person may cause or permit. As shown in Table V11-4, the State
noise constraints are categorized by zoning district and time of day. Daytime
hours are 7 AM to 10 PM, and nighttime hours 10 PM to 7 AM. Allowable dis-
crete tones are 5 dBA lower than the levels listed in the table.

Construction noise' is exempt from the regulations'of Table VII-4, Also
exempt are railroad noises associated with train passbys, as well as audi-
tory warning devices. State noise regulations concerning construction noise
are as follows:

A person may not cause or permit levels emanating from construction
or demolition site activities which exceeds:

a) 90 dBA during daytime hours

b) the levels specified in Table VII-4 during night-time hours.

E. -Site Evaluations

Noise evaluations completed on six power facilities are briefly
described here.

Brandon Shores

A coal-fired plant of 1240 MW capacity is planned to be added adjacent
to an existing facility known as Wagner. The Public Service Commission (PSC)
imposed a constraint of 45 dBA in areas zoned for residential use in order to
protect against annoyance. Subsequerily, the utility filed for a revised
restriction to 50 dBA at night, and 60 dBA during the day. Additionally, the
utility has requested that the noise criteria should apply to the emissions
from the new facility only, rather than the total noise from the combined
facility. These issues remain unresolved at this time.

Dickerson

An 850 MW coal-fired plant is planned to be added to an existing 550 MW
facility. Since the site was situated in a rural/suburban community, noise
was an important consideration. ' Potential disturbances along a U. S. Park
Service hiking path was questioned by intervenors. In order to protect
against annoyance, the PSC imposed a 45 dBA noise limit, as well as
individual octave band constraints. The utility petitioned to have a relaxa-
tion of the octave-band constraints. It was subsequently recommended that

VII-8

Community reaction
vigorous action

Several threats of legal
action or strong appeals ore!
to local officials to
stop noise

single threat of legal action
or Widespread complaints

sporadic complaints

No reaction although noise 0000
is generally noticeable 0 1

30 40 50 60 70 80

Intruding Noise Level (dBA)

Fig. VII-3. An example of community reactions to plant noise levels.
Graph applies to a quiet suburban or rural community, with
some prior exposure to the intruding noise. Windows of
residences are assumed to be parially open, and intruding
noise is continuously present.

Table V11-4

State Noise Regulation

Maximum Allowable Noise Levels by Zoning Category (dBA)

Industrial Commercial Residential

Day 75 67 60

Night 75 62 50

VII-9

the octave band constraints could be relaxed in certain respects without
serious additional annoyance.

Douglas Point Site

A nuclear facility of 2356 MW capacity was planned in a quiet rural area
along the lower Potomac River. The evaluation revealed that noise would not
be a significant source of annoyance. The application has, however, been
withdrawn.

Kaston

A 48 MW diesel facility is planned adjacent to the community. Due to
the small land area and relatively large noise emissions, the PPSP study
judged that noise might create annoyance in residential areas if current
construction practices were followed. The PSC has ordered the utility to
submit a constuction plan that included provisions for noise abatement.

Sollers Point

A gas turbine facility was planned to be added to a facility which al-
ready contained several other gas-turbine peaking units. Due to the design
and placement of the proposed addition it was judged to be a potential source
of annoyance if conventional design practices were followed. The utility
agreed to accept design constraints which would allow the unit to be operated
without causing annoyance. The utility has since decided not to implement
this expansion.

Vienna

A 500 MW coal-fired unit is planned by Delmarva Power and Light for the
Eastern Shore of Maryland. The site location favored by the utility would
place this unit at a facility already containing several smaller units. A
re-routing of a major highway around the plant was also being planned by the
State Highway Administration. With the new route, ambient noise levels in the
town of Vienna would drop significantly, and plant noise could cause annoy-
ance if proposed design practices were followed. In addition, for certain
conditions of operation, it was concluded that State noise regulations would
be exceeded by a few dBA. At the present time, PSC hearings have not been
concluded.

VII-10

REFERENCES - CHAPTER VII

1. The following Power Plant Siting Program reports document noise evalua-
tions carried out under the PPSE Program and more fully discuss the
issues presented in this chapter.

2. J.P. Reilly, "Cooling Tower Noise Impact", Chapter III of Addendum to
"Power Plant Site Evaluation - Brandon Shores Site", PPSE 1-2,
January 1973.

3. J.P. Reilly, "Potential Impact on Community Noise Levels", Chapter 6 of
"Addendum to Power Plant Site Evaluation, Dickerson Site", The Johns
Hopkins University Applied Physics Laboratory, Report Number 3-1,
January 1974.

4. J.P. Reilly, "Noise Impact", Chapter 9 of "Power Plant Site Evaluation
Report - Douglas Point", The Johns Hopkins University Applied Physics
Laboratory, Report Number PPSE 4-1, Vol 2, May 1974.

5. J.P. Reilly, "Noise Impact", Chapter 4 of "Power Plant Site Evaluation
Final Report - Easton Utilities Commission Plant No. 2", The Johns
Hopkins University Applied Physics Laboratory, Report Number PPSE
5-2. March 1975.

6. J.P. Reilly, "Power Plant Noise Models for Community Impact Studies",
Proc. of the Technical Program, NOISEXPO 75, Atlanta, GA, April 30-
May 2, 1975.

7. M. Cwiklewski, "Models for the Prediction of Traffic Noise". The Johns
Hopkins University Applied Physics Laboratory, Report CPE-76-067,
June 7, 1976.

8. M. Cwiklewski, "Present and Projected Neighborhood Ambient Noise Levels
in the Sollers Point Area", Johns Hopkins University Applied Physics
Laboratory, Report Number CPE-76-100, August 18, 1976.

9. M. Cwiklewski, "Noise Impact of the Four Gas Turbine Electrical
Generating UnitsProposed for BG&E Sollers Point Facility", The Johns
Hopkins University Applied Physics Laboratory Report CPE-76-077, June
24, 1976.

10. M. Cwiklewski, "Prediction of Noise Impacts by the Proposed Vienna Unit
No. 9", The Johns Hopkins University Applid Physics Laboratory Report
PPSE 8-2,February 1980.

VII-11

CHAPTER VIII

GROUNDWATER IMPACT

In addition to condenser cooling water, power plants also need freshwater
for boiler make-up, pump cooling, sanitary water supply, and pollution con-
trol equipment. A diagram showing typical uses is shown in Figure VIII-1.
These uses can be considerable - up to 1.6 million gallons of water daily for
2,000 MW of fossil-fuel capacity and 500,000 gallons daily for a 2,000 MW
nuclear plant. Much of this water demand comes from the requirement for
extremely clean (demineralized) water in modern high pressure super-critical
boilers, thus leading to the requirement of multiple filtration and backwash
systems and limited reuse (1). This water can be drawn from four sources,
depending on location of the plant.

*Non-tidal river - Usually, the water is withdrawn from the
r3.ver and purified for use. Examples of plants using this type
of withdrawal are Dickerson and R.P. Smith.

'Industrial water supply - Large cities like Baltimore and Washington
provide water of industrial quality to power plants and other large
users.

*Groundwater/Desalination - For plants located near brackish surface
water, but remote from municipal supplies, there are two alternatives:
to desalinate the surface water or to use groundwater. For four of
the Maryland plants (Morgantown, Chalk Point, Calvert Cliffs, and
Vienna), the choice has been to use groundwater. The potential impact
of these wells on adjacent users is discussed below.

The potential impact of the use of groundwater lies both in a reduction
of the quantity of water available, and in a decrease in the hydraulic head
or 11potentiometric surface" in the area surrounding the point of withdrawl.
This surface represents the level to which the water would rise if a well
were drilled into the aquifer in question. As the well is pumped, a "cone of
depression" centered around the well is created in this surface. If pumpage
lowers the surface below the intake level of the pump of a neighboring well
in the same aquifer, then that well becomes "dry". In such a case, the pump
would have to be lowered to a depth that would remain below future lowerings
of the potentiometric surface.

The Calvert Cliffs plant has 3 wells averaging 620 feet in depth that
withdraw water from the Aquia aquifer. The average monthly usage (Figure
VIII-2) is far below the allowed average and maximum appropriations of
600,000 gpd and 865,00 gpd, respectively. Water levels showed an initial
decline of about 10 feet, but observations taken since that time show no
further lowering. PPSP, through the U.S. Geological Survey, is instrumenting
a permanent observation well at this site.

The Morgantown plant has 5 wells, averaging 1,100 feet in depth, that
withdraw water from the Patuxent aquifer. The average withdrawal (Figure
VIII-3) is eight hundred thousand gallons daily. Water levels of the

VIII-1

Condensate Boiler Soot-
Polishing Blowing
Condenser System
Dernineralizer Hot Well Main
System -Auxiliary Boiler Steam
Feed System System

Miscellaneous
(demineralized)

Wells Pretreatment
System

- Domestic

Well Water - Seal Water
Services
Closed Cooling
Water

L Miscellaneous
(well water)

Figure VIII-1. Typical freshwater uses for a fossil-fueled power plant.

VIII-2

Aquio Water Level(feet)

-15

Aquio Observation Well -20-

-25-
G e e

-30-
G
-35-
D

I-
(D

X
Permitted Yearly Average
.6

.4 Aquia Purnpage

01
J M M J S N
J M M J S N J M M J S N J M M JS N J M M J S N JM M J
1975 1976 1977 1978 1979 1980

Fig. VIII-2. Pumpage and water levels of the Aquia Aquifer at the Calvert
Cliffs Nuclear Plant. The circled readings represent point
measurements rather than monthly averages.

1.8
zi
CD
1.4

CP
0 1.2
0
cn
-n 1.0 Patuxent Purnpoge

.01
J M M J S N J M M J S N J M M J S N J M M J S N J M M J S N J M M J
1975 1976 1977 1978 1979 1980

Fig. VIII-3. Pumpage from the Patuxent aquifer at the Morgantown Power Plant.

v I I I I 1 14 1 1

Patuxent aquifer have declined 90 - 100 feet since plant operation began in
1971, as measured by an observation well near the plant (2). Water levels of
the upper aquifers have declined at rates basically unchanged since before
PEPCO began pumping, indicating that the plant is not directly linked to the
decline (2). At the request of the Power Plant Siting Program, the U.S. Geo-
logical Survey has installed a continuous water-level recorder on an observa-
tion well screened in the Patuxent aquifer at this site.

Vienna presently draws from 5 wells, four are screened in an unconfined
aquifer (Pleistocene) (35 - 54 feet) and one draws from the Nanticoke
aquifer (310 feet) (3). The average withdrawal rate for both aquifers is
shown in Figure VIII-4. With the retirement of Units 5-7, useage is expected
to decline until start-up of Unit 9 in 1988. The expected yearly average
withdrawal from Unit 9 is 0.39 mgd (4). Because of the high yield of this
aquifer, no water supply problems are anticipated for the area (5).

The Chalk Point plant draws from two aquifers, the Patapsco (1,066 feet)
and the Magothy (630 feet). The average withdrawals, shown in Figure VIII-5,
indicate that the plant exceeded the maximum monthly average of I mgd for the
Magothy aquifer twice since 1979. The water level (shown in Figure VIII-5)
in the Magothy has consistently decreased since operations began in 1963,
reaching a level of -55 feet during 1979-80. The plant does not pump from
the upper aquifer (Aquia) used for domestic wells in the area. There are no
other users of the Magothy in the immediate vicinity of the plant (< 8
miles). Plant influence can be put in perspective by looking at the effect
of these withdrawals on the potentiometric surface in the area. Figures
VIII-6 and VIII-7, surveys (USGS) of the Magothy surface taken during early
September 1979, and August 1980, shows a "cone of depression" near the plant.
Similar cones exist near Waldorf (as shown on map), Annapolis, and Severna
Park.

Comparison of the September, 1977 map in the 1978 CEIR (6) to the August,
1980 map indicates that changes have taken place. This comparison is accom-
plished in Figure VIII-8, a difference map of the two potentiometric
surfaces. In the Northern section of the aquifer, levels have risen or
remained fairly constant. However, the Chalk Point/Waldorf areas show large
declines reflecting increased pumping rates and drawdown. These declines are
large enough that users who can not adjust their pumps with water level
("telescopic wells") may be affected. The demand for water in the La Plata/
Waldorf and Chalk Point areas is expected to increase within the next few
Years (7). In particular, the power plant has an additional unit scheduled
for completion in 1982. To meet this demand, PEPCO has indicated that they
will drill at least one more deep well into the Patapsco Aquifer (8). Since
an adequate supply of water is available from this level, the power plant
operation should not affect the areas water supply. Also, a PPSP-sponsored
study of water use at this site may indicate cost-effective methods of
reduced consumption (9).

VIII-5

120
CL
1013,
0
100 Pleistocene Purnpoge

ro 0

40
Nanticoke Purnpage
20

0
J M M J S N J M M J S N J M M J S' N' i J S N J M M J S N J M M J
1975 1976 1977 1978 1979 1980

Fig. viii-4. Pumpage from the Pleistocene and Nanticoke aquifers at the
Vienna Power Plant.

M IME ISO OF I pr IR 14 N

10 -5
Aquia Observation Well
-5 -10

-0 -15

Magothy Aquia Water Level -5 --20
Observation 4--
(Eagle Harbor) 0
Well 4) -25

Magothy Water Level --30
(Eagle Harbor)
1.2
Magothy Purnpage
1.0
4Permitted Yearly Average
U) .8 . . .. .............. . ....... .. ...
D

I..
(D
C3

.4 Patapsco Purnpag
0%-
CD

0
J MM J S N J M MJ S N J MM J S N J MMJ S N J M M J S N J MMJ
77

19T5 1976 1977 1978 1979 1980

Fig. VIII-5. Pumpage from the Magothy and Patapsco aquifers at Chalk Point.
Also included are water levels at test wells in Eagle Harbor,
approximately 2 miles north of the plant.

77000, 76030'
I , -k-,- 7
EXPLANATM SAL MPRE
WTCRW AIRIER OF IN ANOW AWFIER

AT[ 801110DAIRY OF 7W MWTWT AQUIFER

-10 - POTEIrrIMMIC COW= - Show altitude of
patentiametric surface. Dashed WHire
lustally located. Interval 10 feet.
tours within area covered by wall
............
SY0601 net shaust. Obtain is son low]. ..........
(National geodetic vertical datun Of 1929) -.5
............ .....

WELL WA6*r is 81titON Of the P0t4ftti0-
Metric surfs at wall used for control.
co
Datum son 141. .. ........
6
...... .....
0 Observation wall or supply wall yielding less . ... .....
than 10,000 gallon per day.
Supply wall Syshol indicates average yield
40
3
106.000 - I.M.000
in .",1,'o"thAp`r1.1Y,'.0.
39-
00

V
2 ANNAPOLIS
-01
N 51

ILI
39

4
0 ANNE

UPP
1 ARUNDEL'
RO : i i
0
PRINC'E

CO)
GEORIGES@, P e
09

3 0 09, 40

Pt
0

WALDORF
CHALK

110

-9 '0 PRINC
0 OMDE

N.
30' N@4
380

j
CHARLES
'T
!AL4ER,
A.

1>
0 A
0
P 0
ST MARXS

4 0 4 12 16MILES
. . i I j , OI.EnNARTMWN
4 0 4 a 12 16 20KILOMETERS Q@
_j

BASE FROM WYLAND GEOWGICAL SURVU 19 1. 1;250.000

Fig. VIII-6. Map showing the potentiometric surface of the Magothy aquifer
in southern Maryland. September, 1979.

VIII-8

77*00' 7(6f'30

OUTCROP AREA OF THE MAGOTHY AQUIFER

APPROX MATE BOUNDARY OF THE MAGOTHY AQUIFER
EXPLANATION ALTIMOR:E

POTENTIOMETRIC CONTOUR - Shows altitude of
potentiometric surface. Dashed where
approxim tel locate -le'va1 10 '.et.
a y d* I
Con tou rs witin a rea covered by well
symbol not shown. Datu
is sea level.
ti
(National geodetic ver Cal datum of 1929)

WELL - Number is altitude the P tentic-
fo
metric surface at well 'usfed rocontrol.
Datum is sea level.
016
Observation well or supply well yielding less
t
han 10 000 gallons perday.

Supply well - Symbol indicates average yield
in g Ilons per day. -4
la -70 0
0,000 - 99,999 A 3 _9
100,000 - 11000,000 V --6q
0 8
39' More than 1,000,000 55 5
00'
-::x
-22
12 %
4 AN APOLIS
'3@9 .20 1
25 *2

22
V, _@WASHINGTXJN '?27 9
%

9
60 / / 1
- --* 48 16 ANNE
V- NO 0-1
'UPPEFee ARUNDEL 10
0
.2@@RO
10
PRINCE
ol
10 7 @ II
-- - a4)-*2-1 -Mt
)j 18 A0 )I
R G E S@i
-G
0

70 2
0 05 0
.18
-22 '1
-160
V
-2
-4 0@-
Ch.lk
-10 Point
0@1
/-2-8-

-12

39'
30'
CHARLES
4 "I I- I CALV ERT
V Z>

A C
P 0
ST. MARYS 'o-

IT,
<

4 0 4 16MILES
8 1,EONARDMWN
+ 1'2 16 2@KILOMETERS
4 0

@.E M11 [email protected] GEOLOGICAL SERVEY 196_ [email protected]

Fig. VIII-7. Map showing the potentionmetric surface of the Magothy aquifer
in southern Maryland. August, 1980.
51@2 B
I'% ,-
1

VIII-9

77'00' 7e 30
EXPLANATION BALTIMPR
OUTCROP AREA OF THE MAGOTHY AQUIFER

APPROXIMATE BOUNDARY OF THE MAGOTHY AQUIFER
Lin:,of equal difference bet.ee the potenti ometric
n
'faces of September 1977 and September 1979.
D.Shed,where appro imately located. Decline in
ic Ly
potent omer suPface indicated by negative
value and rtisefindicated by positive value.
Intervalis 5 eat.
WELL- Number is the value.in feet,of the difference
between th%potentiotnetric surfaces Of September 1977
a d Septern er 1979r. if
than
6 Observation well or a supply well yielding less
10,000 gallons per day.
V
Supply well- Symbol indicates average yield in
gallons per day. X 0 1@2
ti
**1
0 10 000 99,999 +3 +4 3 0
106,000 1,000,000 -2* 0
4) , . "114
More than 1,000.000 CP * -4 1 ,
39, W.
TI
00'

ANNAPOLIS
+3 4 t4
4D + -2

WASHINGIXiN +1 't,
P
+1

+1 ANNE
4

UPPER 4
ARUNDEL
ARLSORO
0
PRINCE @0
+5
0,0 0 0
0
62 GEORGES@'
-4
0
0
-2
0 1 r "1 -2 -5
LDORF
0 WALDORF 3
ALK
pOiNT
.0
'j 0A
-12 PRINCE
FREDERIrIk
-6

3e
_N@
30,
CHARLES
CALVERT

A C
P 0 0
ST. MAR
YS

4 4 8 12 16MILES ,
1 GLEYINARMTOWN
4 0 il 12 16 20K I L 0 M E T E R S 5'

I bASE FROM

Fig. VIII-8. Map showing the difference in the potentiometric surface of the
Magothy aquifer from September, 1977 to August, 1980.
P,

v,_

VIII-10

REFERENCES - CHAPTER VIII

1. Trident Engineering Associates, Inc. 1979. Assessment of Groundwater
Useage at Chalk Point Power Plant, Task I Report. PPSP-CP-79-5

2. Mack, F. K. 1980. Unpublished data collected by the U.S. Geological
Survey.

3. Geraghty and Miller, Inc. 1980. Hydrogeologic Description of the Pro-
posed Delmarva Power and LIght Company Plant Site at Vienna,
Maryland. PPSE 8-6.

4. Delmarva Power and Light Company. 1980. Amended Application for Cer-
tificate of Public Convenience and Necessity, Section 2.14.2.6b(2).

5. Portner, E. M. 1980. Impacts of the Proposed Vienna Unit No. 9 - An
Overview of Vienna and Alternate Sites. Applied Physics Laboratory.
PPSE 8-8.

6. PPSP. 1978. Power Plant Cumulative Environmental Impact Report, PPSP-
CEIR-2

7. Mack, F. K. and Mandle, R. J. 1978. Digital Simulation and Prediction
of Water Levels in the Magothy Aquifer in Southern Maryland. Report
of Investigations #28, Maryland Geological Survey.

8. Guiland, L. S. 1980. Letter from L. S. Guiland (PEPCO) to C. Wheeler
(WRA).

9. Trident Engineering Associates, Inc. 1978. Statement of Work, Contract
P30-79-02 (PPSP).

VIII-11

CHAPTER IX

SOLID WASTE MANAGEMENT

Burning of coal produces combustion gases that contain solid flyash
and gaseous sulfur oxides. When these products are cleaned from the stack
gas by the use of precipitators and scrubbers, large volumes of flyash and
sludge are generated. Lesser quantities of bottom ash and boiler slag are
also produced. Broadly speaking, such wastes must either be used, stored
temporarily, or permanently disposed of. Engineering costs and environmental
hazards may be associated with any of these approaches.

Where possible, waste product utilization is desirable. Bottom ash
is frequently used as a road base, as a drainage blanket, and as an aggregate
in concrete. Federal law requires the use of flyash in cement in federal
projects, where feasible, and Maryland law requires that flyash be stored in
a manner permitting its subsequent recovery and use (1). The principal
potential uses of flyash take advantage of its hardening properties in the
mixing of concrete; in structural fill; and in admixture with other wastes to
simplify their disposal and minimize leachate generation. Calcium sulfate
scrubber sludge, or "abatement gypsum", from non-recoverable processes can
sometimes be used as a soil conditioner, in wallboard manufacture, or as a
set-retarding agent in concrete. Elemental sulfur or sulfuric acid is ob-
tained from recoverable sulfur removal processes.

At present some flyash is being sold for re-use and the remainder is
being placed in managed landfills. Previously, ash was placed wet in unlined
disposal ponds or deposited on marshland. Such disposal is no longer likely
to meet land use and environmental regulations in most areas of Maryland. No
scrubber sludge will be generated in Maryland until a scrubber begins opera-
tion in 1988 at the Vienna plant of Delmarva Power and Light (DPL).

Quantities of waste requiring disposal will probably increase in re-
sponse to increased coal use and more stringent air and water pollution con-
trols motivated by environmental and health concerns.

Potential adverse impacts associated with landfill disposal include
withdrawal of land from productive use, destruction of visual attractiveness,
and particulate emission during handling and placement. These effects are not
discussed further in this chapter because they are relatively obvious or
reasonably amenable to control. The most important problem is potential su-
rface and groundwater contamination by runnoff and leachate, with a conse-
quent degradation of drinking water aquifers and impacts on aquatic and ter-
restrial organisms.

Problems associated with waste disposal are site-specific because
waste properties, dispersal mechanisms, and resources at risk can vary sub-
stantially. Variation in waste properties can occur because of differences in
mineral content of the coal, options in process design and control, and in
waste disposal practices and facility design. Dispersal of the waste is
governed by topography, climate and geology. The geologic strata underlying
the relatively flat terrain of the Coastal Plan generally constitute a water
table aquifer and one or more underlying artesian aquifers, which are often

IX-1.

of lesser quality. Waste leachate could enter and contaminate one or more of
these aquifers and possibly enter surface streams. On hilly terrain,
leachate will tend to seek and follow the underlying natural drainage channel
to emerge and enter a nearby stream or pass into the fracture system in the
underlying rock. The impact of such waste dispersal would depend on the
extent to which the affected aquifers and streams are important for drinking
water and ecological purposes.

Waste disposal is governed by both State and Federal regulation. Reg-
ulations in each case are complex, inter-related, and in flux; they are en-
forced through a state permitting process based on the Environmental Protec-
tion Agency (EPA) criteria. Utility waste from coal combustion is regarded
as a high volume, low hazard waste and is specifically excluded at the state
and federal level from designation as a hazardous waste. In most instances
such waste can be contained to whatever extent is necessary through
engineering measures discussed in Section B. The tradeoffs between reuse,
facility siting, and containment of wastes are complicated by rapidly
changing regulations, disposal technology and reuse economics.

A. Chemical and Engineering Properties of Flyash and Scrubber Sludge

The need to provide environmentally sound disposal for the principal
wastes, flyash and scrubber sludge, is governed by their chemical properties.
The manner of providing safe disposal is governed by iheir engineering pro-
perties.

As a hydrocarbon, coal consists principally of hydrogen, carbon,
oxygen, nitrogen and sulfur, which will air form gaseous compounds during
combustion. The sulfur content of coal commonly used by utilities ranges up
to 6 percent. An additional 3 to 30 percent of the coal consists of com-
pounds that fuse and form ash. These are mostly complex aluminosilicates,
iron, calcium, sodium and a large number of trace elements.

The liquid resulting from the contact of water with waste is called a
leachate. Table IX-1 lists the concentrations of trace elements in ash lea-
chate and compares them with several standards which are likely to be appli-
cable in the vicinity of a disposal site. It is not usually possible to
predict the quality of leachate from any particular ash without testing.
Laboratory extraction procedures have been developed by EPA (2) and the
American Society for Testing Materials (ASTM), and the ability of these tests
to predict leachate quality is currently under scrutiny (3).

The principal non-recoverable scrubber sludge component is a mixture
of calcium sulfite hemihydrate and calcium sulfate dihydrate ("abatement
gypsum"). The calcium sulfite hemihydrate can be converted to the gypsum form
by an excess of oxygen in the scrubber or through forced oxidation after it
leaves the scrubber. Calcium sulfite is thixotropic (water holding) in
nature. If it is left in the unoxidized form, a common option for its dis-
posal is ponding, with an attendant threat to ground water from leachate
discharge. It can also be disposed of by blending with flyash alone or by
stabilization in a chemical fixation process with flyash and lime. Stabili-
zation is facilitated by oxidizing the sludge to calcium sulfate. Table IX-2

IX-2

Table IX-1 (a)
Representative Trace Elements Concentrations in Coal Ash Leachate

EPA EPA
Primary (b) Secondary (c)
Range Mean Standard Standard
Species M/1 miz/1 mp,/l mp,/l

Antimony .002 to .04 .02 ---

Arsenic .0001 to .42 .03 .05

Barium .1 to .5 .31 1.0 ---

Beryllium .0004 to .01 .002

Boron .17 to 3.2 1.2 ---

Cadmium .0001 to .005 .002 .01 ---

Chromium .0006 to .07 .035 .05 ---

Cobalt .0003 to .01 .005 --- ---

Copper .004 to .08 .03 --- 1

Fluorine .2 to 20 5 1.4 to 2.4 ---

Iron .01 to 4.6 .59 .3

Lead .006 to .25 .02 .05 ---

Manganese *001 to .90 .27 --- .05

Mercury .0004 to .08 .007 .002 ---

Molybdenum .002 to .056 .02 --- ---

Nickel .001 to .12 .04

Selenium .001 to .12 .02 .01 ---

Silver .0003 to .01 .004 .05 ---

Uranium .002 to .1 .006 --- ---

Vandium .005 to .23 .14

Zinc .01 to .4 .07 --- ---

(a) Thirty different coal ash leachates and pond liquors were reviewed.
(b) EPA's National Interim Primary Drinking Water Standards (NIPDWS).
(c) EPA's National Secondary Drinking Water Regulations (NSDWR).

Data from Reference (4).

IX-3

Table IX-2
Representative Trace Elements Concentrations in Scrubber Sludge Liquor(a)

EPA EPA
(d) Primary (b) Secondar Tc)
Range Mean Standard Standard
Species mit/l mg/l Mg/l mg/l

Antimony .09 to 2.9 .2 --- ---

Arsenic .004 to .3 .009 .05
Barium (e) (e)

Beryllium .0006 to .14 .013 --- ---
Boron .9 to 46 (e) --- ---

Cadmium .002 to .044 .032 .01 ---

Chromium .005 to .4 .08 .05
Cobalt .1 to .7 (e) --- ---

Copper .002 to .6 .20 1

Fluorine .7 to 3.0 1.5 1.4 to 2.4 ---
Iron .02 to 8.1 (e) --- .3

Lead .001 to .4 .016 .05 ---

Manganese .007 to 2.5 .74 --- .05

Mercury .0004 to .07 .01 .002 ---
Molybdenum .07 to 6.3 (e) --- ---

Nickel .005 to 1.5 .09 --- ---

Selenium .001 to 2.2 .14 .01
Silver .005 to .6 (e) .05
Uranium (e) --
Vandium .001 to .67 (e)

Zinc .03 to 2.0 0.18 5

(a) Thirteen different sludge liquors were reviewed.
(b) EPA's National Interim Primary Drinking Water Standard (NIPDWS).
(c) EPA's National Secondary Drinking Water Regulations (NDWR).
(d) Underscored values are equal to or greater than most stringent reference
standard.
(e) Sufficient data were not available for the meaningful calculation of a
significant mean.
Data from Reference (4). IX-4

identifies the range of concentrations of trace elements in scrubber sludge
liquors (slurry water) from one set of tests and compares these concentra-
tions to EPA drinking water standards.

A common disposal technique for plants that produce both flyash and
scrubber sludge is to mix or blend the wastes together and (usually) to "fix"
the mix by the addition of lime (5). After a brief setting period the
mixture is put at the disposal site and compacted. The fixation reaction is
a pozzolonic reaction consisting of the formation of calcium silicate links
between the flyash and lime particles. This is the same type of process
responsible for the setting of portland cement. The formation of this
mixture takes up some of the remaining water in the sludge. In addition,
some gypsum may react with the lime and flyash to form a mineral called
etrringite. The rate at which leachate can be generated depends on whether
the materials are blended or fixed, but leachate concentrations, as illus-
trated in Table IX-3, are estimated to be the same for either process. It
should be noted that for any scrubber waste the use of saline water as make-
up to the scrubber could significantly increase the chlorides and total dis-
solved solids concentrations.

When wastes are to be stored in a landfill, the physical properties
of concern include compactibility, shear strength, and permeability.
Obviously the greater the compactibility, the more waste can be placed on a
single piece of land; the same is true for shear strength, which governs the
permissible steepness of the sideslopes of the waste pile. In general all of
the wastes discussed here, except untreated unoxidized sludge, can be placed
in unconfined piles.

Permeability determines the rate at which leachate may be generated
by infiltrating water. Table IX-4 gives illustrative permeabilities for
various wastes. Fixed scrubber sludge is generally less permeable than other
wastes, but the rigidity of the material is such that differential settlement
may eventually cause cracks which would increase the bulk permeability.

A topic of current interest is the extent of trace amounts of radio-
activity in coal wastes. Table IX-5 provides an indication of radioactivity
present in coal, flyash, bottom ash, and scrubber ash from two power plants.
There are indications that radio-nuclides become enriched in the ash (rela-
tive to the coal) and tend to concentrate on the finer particles. Draft
criteria would label a waste as radioactive should the radium-226 concentra-
tion exceed 5 picocuries per gram,or the total single source emission exceed
10 microcuries (6).

B. Disposal Techniques

Power plants produce large volumes of solid waste. The specific
quantities depend on many factors, such as the type of furnace, composition
of the coal, and type of flyash precipitator. Scrubber sludge may not be
produced at all if a utility has the option to burn low sulfur coal; the
decision depends upon a number of regulatory and economic considerations. If
a scrubber is used, the quantities of scrubber sludge will usually be greater
than the quantity of flyash.

IX-5

Table IX-3

Representative Permeate Concentrations for Blended or Fixed
Scrubber Sludge (All concentrations mg/1)

Total Dissolved Solids 8800
Sulfate 1350
Chlorinde 2970
Arsenic 0.094
Cadmium 0.21
Selenium 0.12
Barium 1.0
Chromium 0.001
Lead 0.005
Mercury 0.0005
Silver <0.001
Iron 0.86
Manganese 2.39
Zinc 5.4
pH 7.5

Data from Reference (7).

Table IX-4

Representative Permeabilities of Utility Solid Wastes

Material Permeability - cm/sec
Flyash 10-4 to 10-5
Fixed scrubber sludge 10-5 to 10-7
Blended flyash and scrubber sludge 10-4 to 10-5

IX-6

Table IX-5
Contents of the Various Radionuclides in Coal, Bottom Ash and Fly Ash(a)

PPM Pci/p,
U Th K 40K 228 Th 228 Pa 210 Pb 226 Ra 238U 235U
Plant A (b)

Coal 0.71 1.6 806 0.73 0.17 0.17 0.26 0.21 0.24 0.012

ESP fly ash 5.6 15 9400 8.1 1.7 1.7 1.4 2.3 1.9 0.093

Bottom ash 4.6 14 7900 6.8 1.5 1.5 0.58 1.9 1.5 0.072
Plant B(c)

Coal 2.6 5.0 1660 1.4 0.56 0.55 0.68 0.64 0.85 0.037

ESP fly ash 11 22 7400 6.3 2.4 2.4 2.2 2.9 3.5 0.14

Bottom ash 8.4 19 7200 6.2 2.2 2.1 0.84 2.5 2.8 0.11

Scrubber ash 11 22 7200 6.2 2.5 2.5 2.8 3.0 3.6 0.14
Plant B(c)

Post-ESP
(stack)

Fly ash
(mmd)kal

17 jam 16 25 8200 7.0 2.8 2.7 4.3 3.3 5.4 0.17

6 )im 20 31 8600 7.3 3.3 3.5 10 4.6 6.8 0.28

3.8 )im 30 36 8600 7.4 3.3 4.0 14 5.3 10 0.39

2.5 jum 36 38 8100 7.0 3.3 4.2 17 5.9 12 0.50

(a) 10-20% propagated 1 (r error from the mean.
(b) Samples from Plant A; input coal contains 11.3% H201 9.2% ash, and 0.52%
sulfur.
(c) Samples from Plant B; input coal contains 6.8% H20, 23.2% ash, and 0.46%
W mmd = mass median diameter determined by centrifugal sedimentation.

Data from Reference 6.

IX-7

Table IX-6 shows typical waste quantities for a 500 MWe plant. An
acre-foot is a volume one foot high over one acre. As an illustration,
thirty years of waste would cover a 150 acre disposal area to a height of OF
almost 50 feet.

Table IX-6
Typical Waste Quantities for a 500 MWe Plant Using 2.5% Sulfur Coal PF
(Volume in Acre-Feet)

Waste Annual Volume per MWe Annual Total Volume 30-Year Volume PF

Flyash 0.14 72

Bottom Ash 0.03 14

Oxidized Scrubber
Sluge 0.35 174
Total: Flyas@ aN 0.49 246 7380
and Sludge' '

(a) Since bottom ash is often sold for commercial use it is not included in
total waste requiring land-fill disposal.

Where wastes are not to be re-used, disposal or long-term storage is
neces sary at either the plant or an off-site location. Land-filling is the
most widely available option for disposal. (The past use of unlined disposal
ponds was only a specialized form of landfilling; such ponds in contact with
ground water or subject to leaching are no longer likely to meet environ-
mental regulations.) Blending of ash and sludge allows the pozzolanic pro-
perties of ash to improve the engineering properies of scrubber sludge and
adding lime or "fixing" tends to further harden the resulting product. The
special technique of employing fixed scrubber sludge in the construction of
artificial reefs is an option still under study and even if viable would only
be available to power plants in suitable locations. Ocean disposal is pos-
sible, but regulatory attitudes, the cost of transportation, and the perma-
nent loss of a potential resource suggest that off-shore disposal is unlikely
to become commonplace. Thus, for Maryland, landfilling will probably be the
principal method of utility waste disposal in the immediate future.

Transportation is an important consideration in disposal planning.
Scrubber sludge in the form of calcium sulfite is a semi-liquid and can only
be transported by slurry pipeline or an especially suited vehicle unless it
is first dewatered or stabilized. Sludge in the form of calcium sulfate can
be transported as a solid, and ash may be transported either as a solid or a
slurry. Solids can be moved by truck or railcar. Slurry transport implies
either ponding at the disposal site or that dewatering facilities must be
provided. The decanted supernatant can be re-used or must meet discharge
standards. Dewatered slurried wastes will still be high in moisture content
unless dried, leading to excessive land requirements, unstable waste piles,
and leachate release as the pile settles. On the other hand, dry waste dis-
posal may produce fugitive emissions. Increased truck traffic and random

IX-8

spillage are possible added concerns whenever vehicle transport is used. In
general there is a trend away from wet disposal systems because of difficul-
ties in meeting environmental regulations.

Rarely is the installation of a properly designed and operated land-
fill seen as an improvement over existing land uses. Beyond concern for the
loss of the site from productive use during active disposal, responsibility
for long term use and maintenance also concerns communities in the site
vicinity. Future use and maintenance of the site must be part of preliminary
planning since suitability for future use can only be guaranteed through
proper initial design followed by adequate quality control throughout the
operating period.

Structural stability of the waste depends on both the properties of
the material and on proper site design and operating procedures. Calcium
sulfite remains thixotropic and must be retained in a pond or behind dikes
unless dewatered or stabilized. Calcium sulfate is a solid and will stand in
a pile, but is subject to erosion and leaching. Flyash is relatively stable
and can be piled alone. Additional stability is achieved when flyash is
blended with scrubber sludge or fixed with scrubber sludge and lime. In any
case proper drainage and dike design must be provided, and allowances made
for ground settlement beneath the weight of the pile.

Several options exist for the prevention or reduction of leachate
entry into ground water. The formation of leachate may be prevented by cap-
ping the landfill with a waterproof material such as compacted clay or syn-
thetic rubber covered by vegetated soil. Sufficient experience is not avail-
able on cover durability, but inspection and repair of a cover is feasible
since it is accessible. Entry of rain during construction may also require
control, but under some circumstances, such as rapid construction with rela-
tively dry waste, the amount of rain water may be small enough to preclude
significant leachate generation. If a cap is not used and leachate must be
collected, a barrier made of the capping materials mentioned above can be
placed between the waste and the ground water with a collection system
located in the layer between the two. This system may consist of granular
material alone or with a pipe grid collection system added. Both the barrier
and the collection systems are susceptible to damage due to settlement, and
inspection and repair are nearly impossible. Under some circumstances, fixa-
tion of the waste may provide adequate control of leachate generation. Such
measures may be unnecessary where leachates will be dispersed.

Where surface water will traverse the open face of the landfill (for
example in rainstorms), collection and treatment of contaminated runoff
should be carefully considered. Grading to prevent water running onto the
waste is good engineering practice.

Just as potential environmental impacts of utility waste disposal
vary from site to site, disposal costs also vary, and for many of the same
reasons -variability of source coal, variability of plant processes, and
variability of the engineering effort needed to protect the resources at
risk. The total cost of a waste disposal facility includes the sum of the
initial capital costs (purchase of land and equipment, design and licensing,
construction),and the total of all operating and maintenance costs throughout
the lifetime of the facility. Costs of closure and perpetual maintenance,
such as leachate collection and treatment, must also be included. Since

IX-9

disposal facilities have varying lifetimes, total costs among facilities are
best compared on a present value basis or on a present value basis or on a
cost per unit quantity of waste per unit of electricity generated.

Although it is desirable to present some indication of waste disposal
costs, the many factors to be considered in any single situation make a
general approach impractical. An illustration is provided here and the
reader is referred to estimating techniques published by the Electric Power PF
Research Institute in 1979 for further information (7).

For a 500 MWe plant operating at a 70 percent capacity factor, PF
trucking 299 tons per day of dry ash over one mile of public roads to a land-
fill without special containment features, the annual cost for flyash dis-
posal is estimated to be, in 1979 dollars, 0.78 million dollars. This is
equivalent to $7.15 per dry ton, or 0.255 mills per kilowatt-hour, or $1562
per year per installed megawatt. Wide variability in actual situations may
be expected.

For the same plant, burning coal with 12 percent ash and 2.5 percent
sulfur, and disposing jointly of 299 tons of ash blended with 399 tons of
oxidized scrubber sludge daily in a landfill without special containment
features, the total annual cost for disposal of both wastes is 5.15 million
dollars, equivalent to $20.22 per dry ton of combined ash and scrubber
sludge, or 1.68 mills per kilowatt-hour, or $10,308 per year per installed OF
megawatt. The incremental cost of scrubber sludge disposal is thus $8746 per
year per installed megawatt. As noted above wide variability around this
estimate may be expected.

C. Environmental Impacts

The most important potential environmental impacts of discharges from
utility waste disposal areas are due to elevated concentrations of total dis-
solved solids, salts and trace elements. Uncontrolled discharges could cause
ground water in the vicinity of the site to exceed some of the primary and
secondary standards given in Section A. This situation would usually be
monitored by wells adjacent to the site. The extent to which discharges are
a problem will depend on current and planned future uses of the affected
aquifer. In some circumstances such discharges may be unimportant because the
aquifer is unsuitable for drinking water purposes in its natural state.

The biological impacts of discharges to surface water are currently
under study. A detailed discussion is contained in Chapter 7 of Reference
(8). In general there are no indications that even low concentrations of
trace elements such as arsenic, selenium and cadmium can cause developmental
deformities in fish larvae. Potential releases from disposal areas need to
be evaluated on a case-by-case basis to determine the likely extent of
impact6

D. Regulatory Status

The regulatory situation regarding the disposal of utility wastes is
complex because both the federal and state governments are in the process of
implementing broad regulations covering the disposal of many types of waste.

IX-1 0

There are still many uncertainties regarding both the philosophy and the
technical details of the proposed regulations. At present utility wastes are
specifically excluded from classification as "hazardous" and are therefore
11solid wastes". The federal requirements for disposal as proposed by the En-
vironmental Protection Agency are less severe for solid waste than for
hazardous waste, but are still stringent. A disposal facility must not cause
primary and secondary drinking standards shown in Table IX-7 to be exceeded
in the ground water beyond the edge of the waste pile or at an alternative
boundary set by the State.

Table IX-7
Drinking Water Standards

XLiaam_q@@

Contaminant Level (mgLIJ

Arsenic .05
Barium 1.
Cadmium .01
Chromium .05
Fluoride 1.4 - 2.4
Lead .05
Mercury .002
Nitrate (as N) 10.
Selenium .01
Silver .05

Secondary Standards

Contaminant Level

Chloride 250. mg/l
Color 15. color units
Copper 1. mg/l
Foaming Agents .5 mg/l
Iron .3 mg/l
Manganese .05 mg/l
Odor 3 threshold odor No.
PH 6.5 - 8.5
Sulfate 250. mg/l
TDS 500. mg/l
Zinc 5. mg/l

Code of Maryland Regulations require a permit from the Department of
Health and Mental Hygiene (DHMH) for discharges to the ground water regard-
less of the material, but the constraints vary depending on the nature of the

IX-11

material. In general the State can regulate facility design, discharge con-
centrations and receiving water quality. For the disposal area recently pro-
posed at Vienna, Maryland (see next Section) the preliminary state regulatory
criteria include meeting primary and secondary drinking water standards at
all depths at the edge of the waste pile and preventing direct contact of the
waste with the water table. Discharges to surface waters from a waste dis-
posal facility are also regulated by the State through the NPDES permitting
process. The general criterion is that waters must be free from substances
in concentrations which are harmful to human, animal, plant or aquatic life.
The only applicable specific criterion is pH outside of a designated mixing
zone, but other criteria are likely to be proposed on a case-by-case basis.

In addition to the regulation of discharges from utility waste dis-
posal facilities by DH14H and EPA, it is possible that the Maryland Public
Service Commission could impose conditions on the siting and operation of
such facilities to insure that waste disposal is handled safely and econo-
mically.

Compliance with regulations would usually be determined by monitoring
the quality of discharge and receiving waters. For ground water such moni-
toring is complicated because discharges are not readily observable and the
concentrations of some constituents in the ground water may exceed standards
due to natural conditions or agricultural practices. Baseline monitoring is
usually necessary to determine such conditions. A more detailed discussion
of the regulatory situation is contained in Chapter 2 of Reference 8.

E. Vienna Example PF

A study by the Power Plant Siting Program has recently been completed
of Delmarva Power's plans for disposal of solid waste for the proposed 500
MWe Unit 9 at Vienna (8). Flyash and scrubber sludge would be blended
together to form a damp, soil-like material and disposed of in a landfill at
the rate of approximately two-thirds acre-foot per day. After 30 years the
waste pile would cover 165 acres to a maximum height of approximately 50
feet. The waste would be placed over a layer of fill to maintain a five foot
separation of the waste from the ground water. An impermeable cover would be
installed over the waste after emplacement to eliminate contact with rain
water. A layer of soil would be placed over the cover and planted with Ken-
tucky 31 fescue.

An artist's sketch of the general features of the waste pile after 30
years of operation is shown in Figure IX-1. The grading would route rainfall
runoff from completed area of the landfill to natural drainage. The emplace-
ment procedure for the waste would be to work in ten successive 16.5 acre
tracts. Runoff from the active area would be collected in a lined sedimenta-
tion basin and recycled into the scrubber system. Analysis indicates that
infiltration of rain water during emplacement of the waste would be insuf-
ficient to cause the pile to saturate, so no leachate would result. The
proposed design is predicted to result in a negligible amount of leachate
reaching the ground water or surface waters.

The above design was developed after laboratory and field studies and
discussions between the Power Plant Siting Program and the utility. Because
of site features such as a high watertable, localized soft foundation soil

IX-1 2

a a a a a MM am

I17A,

Fig. IX-1 Artist's concept of solid waste disposal area.

and the proximity of important natural resources, usual disposal approaches
such as waste fixation or use of an underdrain could not be employed. The
facility design was therefore tailored to the characteristics of the waste
and the site. The most important aspect of facility design was the study of
factors affecting the ability of the cover to prevent infiltration by rain
water, such as liner performance, sideslope stability, settlement, and water
budget. Another important facet of the evaluation was analyses of dispersion
and attentuation of discharges in the ground water and surface water and the
resulting biological consequences.

The results of the design study are contained in references 8, 9, and
10. The design concept was found adequate to meet regulations and to prevent
contamination of the drinking water aquifer or damage to natural resources in
the adjacent surface water bodies.

F. Waste Disposal in Maryland

At present, there are no utility flue gas desulfurization systems
operating in Maryland; all of the utility waste being generated is flyash and
bottom.ash. Currently there are five coal burning plants: Baltimore Gas and
Electric Company (BG&E) and Potomac Edison Company (PECO) each has one, and
Potomac Electric Power Company (PEPCO) has three. Delmarva Power (DPL) is
planning a major new coal-burning facility at Vienna which will include a
scrubber. Also, BG&E is planning to burn coal at its new Brandon Shores
plant and eventually to convert most of its oil burning plants to coal.
Scrubbers will not be used at the Brandon Shores plant because it is exempted
from the most recent New Source Performance Standards. The need for scrub-
bers at the converted BG&E plants and at the future plants of PEPCO and PECO
is presently unknown.

Information currently available about the present ash disposal situ-
ation is presented below.

Baltimore Gas and Electric Company

The Wagner 3 station presently generates 61 acre-ft of flyash and
15 acre-ft of bottom ash annually. When the conversion of the
Charles P. Crane station is completed in 1983, 46 acre-ft/yr of
flyash and 46 acre-ft/yr of bottom ash will be produced, and in
1988, when Brandon Shores Unit No. 2 becomes operational an addi-
tional 191 acre-ft (in the same proportion of flyash to bottom ash)
will be generated annually. BG&E reports a continuing effort to
matket its flyash. In 1979, 10 percent of the Wagner ash was sold,
and this amount was doubled in 1980. In 1981, ash from Wagner will
be used in the parking lot and road system at the Calvert Cliffs
nuclear plant. Earlier, flyash from the Riverside plant was used
in the construction of Liberty Dam for the Baltimore City water
supply system. It is further anticipated that from 25% to 50% of
the ash from Brandon Shores will be marketed.

Material not marketed in the past was sent to the Boehm-Joy land-
fill near Crownsville in Anne Arundel County. Since that landfill
was closed in November 1980, ash has been sent to a landfill in a
sand and gravel quarry near Joppa in Harford County. Unsold

IX-1 4

material from Brandon Shores is planned to be used as structural
fill material near the plant assuming all necessary permits can be
obtained.

' Delmarva Power and Light Company

The Vienna plant on the Nanticoke River where it is crossed by U.S.
50 operated coal-fired units from 1928 until 1972. Coal refuse was
deposited in a diked marshland of approximately 90 acres across the
Nanticoke River. For the planned addition to the Vienna plant,
blended coal ash and scrubber sludge will be placed in an engi-
neered landfill on-site. The landfill design, worked out through
negotiations with the Power Plant Siting Program, will keep the
waste isolated from groundwater and ambient precipitation and is
expected to create no environmental hazard. Environmental review
by the Public Service Commission and the Office of Environmental
Programs is still required, however.

* Potomac Edison Company

(Subsidiary of the Allegheny Power System). The R. Paul Smith Plant
at Williamsport on the Potomac River in Washington County generates
40 acre-ft per year of flyash and 10 acre-ft per year of bottom
ash. These wastes are slurried across the Potomac River to set-
tling ponds, now filled, on the plant site in Maryland.

. Potomac Electric Power Company

This company operates coal-fired plants at Chalk Point on the
Patuxent River in Prince George's County, at Dickerson on the
Potomac River in Montgomery County and at Morgantown, also on the
Potomac River in Charles County.

The Chalk Point plant has disposal sites both at the plant and at an
engineered site nearby in Brandywine. Annual ash production includes 11
acre-ft of bottom ash and 138 acre-ft of flyash. When new precipitators
become operational in 1980, these amounts will be increased by 10 percent.
Between 1964 and 1971, the ash was disposed of on-site. Since 1971 it has
been landfilled at Brandywine.

At Dickerson, annual ash production is 48 acre-ft of bottom ash and
119 acre-ft of flyash. From 1960 to 1967, this material was disposed of in
on-site ponds. From 1967 to 1979 the ash was shipped to Pennsylvania, and
since 1979 it has again been disposed of on-site.

At Morgantown, annual ash production is 130 acre-ft of bottom ash and
191 acre-ft of flyash. This material has been stored at the Faulkner site on
a managed basis since 19742 with unmanaged use of the site extending back to
1971. Earlier disposl sites are unknown but assumed to be on-site.

For the existing disposal sites of each utility it is not possible
without further study to determine whether any contaminants exist that are
producing leachate in harmful concentrations and whether remedial measures
will be necessary. Existing sites are currently under study by the Power
Plant Siting Program.

IX-15

G. Long Term Considerations

Waste disposal areas will require perpetual care. Although the
wastes are not legally hazardous, they can cause contamination of drinking
water and environmental impacts unless properly controlled. In contrast to
some other types of waste, the contaminant level of utility waste in ground
water will not decrease to zero over time unless there is a substantial
depletion of dissolved materials by release to the environment. It is there-
fore important to have disposal approaches that minimize routine maintenance
and are relatively immune to extremes in natural conditions such as storms.
From this point of view facilities that require the collection and treatment
of leachate or the active maintenance of drainage systems are undesirable.
But even facilities which require no direct routine care are subject to
eventual failures from causes such as erosion and deterioration of materials.
Therefore institutional arrangements to insure maintenance, prevent distur-
bance of the facility, monitor for releases and provide for possible reuse of
stored materials are important.

Institutional arrangements include such topics as the mechanism of
ownership, management responsibility, liability, regulatory responsibility,
insurance, and the posting of bonds. The State of Maryland is currently in
the process of drafting a comprehensive solid waste management plan which
should address these considerations.

IX-16

REFERENCES - CHAPTER IX

1. Natural Resources Article., Section 7-464

2. Code of Federal Regulatins. 40CFR261

3. Electric Power Research Institute. "Extraction Procedure and Utility
Industry Solid Waste", EPRI EA-1667. 1981

4. Holland W.F. and B.F. Jones. Potential for Groundwater Contamination by
Trace Elements in Ponded Ash and Scrubber Sludge. Presented at the
ASCE Spring Convention and Exhibit, April 1978. Pittsburgh, PA.
Preprint 3289.

5. Environmental Protection Agency. "Decision Series. Sulfur Emission:
Control Technology and Waste Management", EPA 600/9-79-019. 1979

6. Fred C. Hart Associates, Inc. "The Impact of RCRA (PL 94-580) on Utility
Solid Wastes", FP-878, Technical Planning Study 78-779, prepared for
Electric Power Research Institute. 1978

7. Electric Power Research Institute. "Coal Ash Disposal Manual", EPRI
FP-1257. 1979

8. Portner, Edward M., John J. Lentz, William D. Stanbro, Gary A. Yoshioka,
Dennis T. Burton and Lenwood W. Hall, Jr. "Prediction of Impacts
from the Solid Waste Disposal Area for the Proposed Vienna Unit No.
9", JHU PPSE 8-5, for the Maryland Power Plant Siting Program. 1981

9. Frind, Emil 0 and Carl D. Palmer. "Parametric Study of Potential
Contaminant Transport at the Proposed Delmarva Power and Light
Company Plant Site, Vienna, Maryland", JHU PPSE 8-15, for the
Maryland Power Plant Siting Program. 1980

10. Geraghty & Miller, Inc. "Hydrogeologic Description of the Proposed
Delmarva Power and Light Company Plant Site at Vienna, Maryland", JHU
PPSE 8-6 for the Maryland Power Plant Siting Program. 1980

IX-17

CHAPTER X

TRANSMISSION LINES

Environmental impacts of a transmission line may arise from the construc-
tion or presence of the line, from the maintenance of the right-of-way, or
from electromagnetic effects associated with the operation of the line.
Construction and maintenance may lead to effects on vegetation, wildlife, and
fish populations. The presence of a transmission line can potentially impact
land uses and values, and also be a visual intrusion. Electromagnetic fields
generated in the vicinity of high voltage transmission lines can cause:

Audible noise

Radio and television interference

Ozone production

Spark discharges to persons touching large, ungrounded metallic
objects located in or near the transmission line right-of-way

Electrical fields under transmission lines may create health effects although
the existence of such effects have not been confirmed.

Transmission lines are necessary to transmit electrical power from gen-
erating stations to the electrical distribution grid, and compose that part
of the distribution system operating at 69 kilovolts (kV) and higher. Lines
energized at less than 69kV are distribution lines, and form the network that
actually brings electricity to the customer.' Prior to constructing a trans-
mission line of voltage greater than 69kV, a utility must obtain a Certifi-
cate of Public Convenience and Necessity from the Maryland Public Service
Commission. The utility must demonstrate, in a public hearing, the need for
the transmission line, and the acceptability of the route being proposed.
These issues, especially that of route acceptability, are independently eval-
uated by various State agencies, including the Power Plant Siting Program. A
map of transmission lines of 230 kV and higher in Maryland is shown in Figure

A. Environmental Impacts

The construction of a transmission line will inevitably cause some envi-
ronmental impact, but there are several ways by which such impact can be
minimized. The first and most obvious way is judicious routing. Identifying
a transmission corridor which avoids those areas considered to be unique or
environmentally very sensitive obviates the need for special mitigating
actions. Performing route selection studies, such as that done in conjunc-
tion with the Potomac Edison Company's application to construct the Mont-
gomery - Damascus - Mt. Airy transmission line (1) is useful for identifying

---------------
While 69KV is a transmission voltage by definition, it can be utilized for
either transmission or distribution.

X-1

LEGEII@D*
lpfkopoSED
EX IST 1 NG . ...... 500 KV
amw - --- 2.50 KV
poWEft PLANT
SWITC14ING STATION Liues i.
vig-

available options and tradeoffs necessary for choosing the most acceptable
route. Several techniques are available for performing such studies, and the
most appropriate is best selected on a site specific basis (2).

One of the most obvious environmental impacts associated with construc-
tion of a transmission line is the deforestation which occurs when a right-
of-way (ROW) is being cleared. While the location of the ROW will dictate
the extent to which land must be cleared, it is difficult to conceive of a
route not requiring the removal of some trees. Since deforestation is a
problem of increasing magnitude in eastern states such as Maryland, the area
of woodlands to be removed becomes a crucial factor in comparing right-of-way
alternatives.

Reducing forested areas, while an adverse impact in itself, can lead to
secondary effects such as alteration and/or elimination of wildlife habitat,
and increased erosion. Wildlife habitat may be altered by ROW clearing, but
a habitat is rarely totally eliminated. Species diversity can actually
increase when forested areas are interrupted by a corridor populated by shrub
and bush species. Exactly how such a habitat change will affect local popu-
lations depends upon many factors.

Clearing of a ROW may also affect fish populations. Such effects are of
two types: introduction of excess sediments to waterways because of soil
erosion, and warming of waters as a result of the elimination of shade trees.
Increasing the temperature of a stream can render it unsuitable for existing
fish populations. This is most important in the case of natural trout
streams. Introducing sediments to waterways can have an adverse impact on
the spawning of resident and migratory fish. Sediment blanketing of eggs has
been documented as a cause of increased mortality during spawning (3). This
is a severe problem in areas composed of highly erodible soils. Mitigative
measures, however, are both simple and effective. Seeding and mulching imme-
diately following soil exposure, and restricting construction to the summer
growing season should limit sediment damage (4).

once a transmission line is in place, wildlife can be impacted by the
presence of the line and ROW maintenance. A transmission line can, for
example, effect birds in flight. Collision related deaths are known to
occur, and may be significant on species with dangerously low populations,
where any added source of mortality is nontrivial (5). Several site
pecific factors influencing the frequency of waterfowl collisions have been
identified: number of birds present, visibility, species composition, be-
s

havior, disturbance, and familiarity with the area (6). There are many
uncertainties associated with this problem, but one should weigh the desira-
bility of avoiding those environmentally sensitive areas which can be
identified.

Some impact to wildlife will occur as a result of ROW maintenance, which
is necessary to prevent vegetation from either compromising transmission line
safety, or restricting ROW access. Several techniques, including winter
burning, moving, hand clearing, and selective basal or aerial spraying of
chemical herbicides, are commonly used for maintenance. Use of chemical
herbicides holds the potential for environmental problems, but recent
development of fairly innocuous herbicides, and care in using them can elim-
inate any undesireable impact. The use of selective basal spraying is
generally preferred to broadcast spraying. The Power Plant Siting Program

X-3

recommends that certificates granted for the construction of transmission
lines restrict the use of chemical herbicides to selective basal application.

The aesthetic impact associated with the presence of a transmission line
has become a very contentious point in several Public Service Commission
hearings. Such impacts are inherently subjective and vary greatly, but in-
variably invoke very emotional responses from some of the affected indi-
viduals. While it has been shown that some people do not wish to see trans-
mission lines, the assumption that transmission lines are intrusive and that
no-one wants to see them is unproven (7). Unfortunately, regardless of the
route selected, there is usually some aesthetic impact.

Although this impact is very subjective in nature, many technical factors
affect its severity. The appearance of a transmission line is a function of
such engineering factors as voltage, line configuration, number of circuits,
and number of conductors per phase, and such external factors as the vege-
tation and topography which characterize the ROW. In addition, the structures
used for transmission lines range from a single wooden pole to latice steel
towers of heights exceeding 150 feet. All of these factors also result in
great variation in the width of the ROW. Because of this, the extent to which
a transmission line visually impacts an area varies greatly.

Because of the potential for aesthetic impact, and the expense of ob-
taining rights-of-way, transmission lines are generally located away from
urban centers. This generally results in a reduction in the number of people
whose surroundings are negatively affected. Unfortunately such routes can
result in a more significant deterioration of what was formerly a very scenic
area. Areas where viewers would be especially sensitive to the presence of a
transmission line, e.g., National or State forests and parks, scenic rivers,
and sites of historic or cultural significance, can generally be avoided
during the route selection process.

Attempting to avoid creating a visual impact can itself actually result
in environmental impact. For example, scenic impacts are often reduced by
locating transmission lines in low lying areas. Unfortunately streams also
tend to be located in low lying areas. Routing around such areas can result
in placing a transmission line on land considered to be highly desireable for
various human activities, such as agriculture and development. This causes
an inevitable conflict over land use.

Whenever a transmission line passes through or in close proximity to
residential areas or land proposed for residential development, it is typi-
cally claimed that a transmission line adjacent to a lot will drastically
reduce the value of the property, possibly even rendering it unsellable.
Several studies have been undertaken to determine if there actually is a
direct relationship between proximity to transmission line and property
value. There are numerous studies supporting both the contention that the
presence of a transmission line adjacent to a residential lot will cause a
reduction in property value (8), and that no such reduction will result (9).
A study done in Maryland for PPSP found a slight reduction in one community
and no effect in another (10). While these effects can occur, although they
are usually small, there is great variance from case to case.

X-4

Another consideration is the effect on agricultural operations. Although
the impact is generally minimal, a transmission line spanning agricultural
lands can result in a loss of productivity. Such losses result from land
lost around structures and guy wires, adverse effects on soil profile and
drainage from construction, structure interference with harvesting patterns,
and weed propagation around structures (11). In addition, aerial operations
for crop control in the vicinity of a transmission line will be restricted.

Obviously, there are some unavoidable impacts associated with the routing
of any transmission line, and not all can be mitigated by judicious routing.
Selecting a route requires tradeoffs between the various potential impacts.
Any areas where the impact would be unacceptably severe can generally be
avoided in the route selection process.

B. Electrical Effects

The operation of a transmission line has certain electrical effects on
its surroundings. These effects usually are negligible at voltages below
230 kV, and can be divided into two categories: corona effects and field
effects.

Corona discharge occurs at the conductor surface because local field
strengths at some points on the conductor become great enough to ionize air,
Such concentrations of field strength are enhanced by surface irregularities,
e.g., dirt, scratches and water droplets. Corona discharges result in such
electrical effects as audible noise, radio and television interference, and
ozone production (12). Each of these effects becomes more severe in wet
weather, a result of the increase in water droplets on conductors.

Audible noise occurs as a buzzing sound under very high voltage lines, such
as those 500 kV and greater. Noise levels will tend to reach a maximum during
periods of fog or mist, and are lower during dry weather. During
heavy rain the loudness of the rain itself exceeds noise generated by the
transmission line. While the posibility of annoyance to nearby residents
cannot be discounted, it is nonetheless highly unlikely to occur.

The electromagnetic energy in corona discharges can cause interference
with radio or television reception. This effect is generally significant
only during wet weather, and is principally associated with voltages of 500
kV and greater (although it can occur on lower voltage lines, especially if
they are older). Radio interference can be experienced by residents located
near a transmission line as a reduction in quality of AM reception, but
rarely during fair weather. Television interference near 500 kV lines has
been shown to be a problem only when the following conditions exist: 1) tele-
vision set located less than 300 feet from ROW; 2) indoor antenna only; 3)
tuned to low frequency stations (channels 2 through 6); and 4) in use during
rain (13).

The other result of corona discharge is the production of ozone from
normal oxygen, The production efficiency varies greatly, and is dependent
upon line voltage, electric field strength, conductor geometry, conductor
surface condition, and meteorological conditions. Attempts to detect ozone,
a highly reactive gas, produced by corona discharge have generally failed.
Under worst case conditions, concentrations averaging less than 1 ppb above

x-5

peak background fluctuations have been found (14). Ozone produced by trans-
mission lines is not expected to have any significant effect on ambient air
quality.

Field effects can result from either electric fields or magnetic fields
which are created around the conductors. Electric fields are basically a
function of line voltage, while magnetic fields are basically a function of
conductor current. These fields can cause transfer of electrical energy
through induction to conducting objects within the fields.

Both electric and magnetic fields contribute to induction on conducting
objects, although the mechanisms vary. Induction from magnetic fields is
important on long conductors with a connection to ground (such as fences),
while electric fields tend to effect conducting objects which are well
insulated from the ground (such as motor vehicles).

People touching objects on which voltages have been induced may experi-
ence noticeable effects as a result of induced currents or spark discharges.
The magnitude of these effects ranges from the threshold of perception, to
actual discomfort or startle reaction. Under worst case conditions, induced
currents can theoretically reach levels (the "let-go" threshold) at which
hand and arm muscles involuntarily contract, preventing one from releasing
one's grip. These levels are, however, usually far higher than those induced
by transmission lines on objects such as long fences.

More likely to be a problem, but still typically one of discomfort or
annoyance rather than an actual safety hazard, is the spark discharge experi-
enced from touching a conducting object on which a voltage has been induced.
The associated sensation is not unlike that experienced when touching a
metallic object after walking across a carpeted room in winter. A hazard-
ous situation might arise if someone climbing a ladder on a house near a
transmission line touches a gutter on which voltage has been induced, the
individual may be startled and fall down. Several conditions must be met
before this accident could be expected to occur; one example meeting the
proper conditions would be a house 40 feet long with a raingutter 15 feet
high, and located 120 feet from the center of a 500 kV ROW. While only pre-
liminary work has been completed, a detailed study is now being undertaken to
define exactly how people react to short duration, high voltage shocks (15).

A spark discharge could possibly ignite gasoline vapors given the proper
conditions. This highly unlikely event requires conditions such as refueling
of a large gasoline powered vehicle under a transmission line where the elec-
tric field strength is 5 kV/m or greater. The vehicle would have to be well
insulated; e.g., standing on asphalt or crushed stone, the individual re-
fueling the vehicle would have to be well grounded, e.g., standing on damp
earth, the gasoline vapors and air would have to be mixed in proportions
necessary for combustion, and the neck of a metal gas can would have to come
close enough to the vehicle to cause a spark discharge. The Public Service
Commission did consider a recommendation that conductor heights above Sur-
faced roadways be raised to a minimum of 50 feet because of the possibility
of fuel ignition, but ruled that the likelihood of such an event did not
merit altering the existing 42 foot minimum height standard.

X-6

C. HEALTH EFFECTS

Transmission lines rated at 345 kV and above have been in existence for
about 30 years. No health hazards to the general public exposed to the
electric and magnetic fields produced by these transmission lines have been
documented. Effects from long-term exposure to these fields could
nonetheless exist. .

Concern about this intensified in the early 1970s when reports of ad-
verse health effects on workers in 500 kV and 700 kV switchyards were
received from the Soviet Union. Various individuals have suggested that these
studies prove that field strengths associated with transmission lines pose a
health hazard. However, similar studies with workers in the United States,
Canada and other countries have failed to reproduce the Soviet results, and
more recently, some Soviet experts have expressed doubts about the earlier
work from their country.

Of the many projects to look for effects of power frequency fields on
laboratory animals, some found associated health effects and others did not.
It is important to resolve questions as to whether the fields from high-
voltage transmission lines can have long-term effects on humans or animals.
To this end the utility industry, various governmental bodies, and others
have initiated broad and extensive research programs. It is hoped that
these programs will resolve most of the existing issues, and in the near
future permit an improved assessment of any risks resulting from long-term
exposure to transmission line fields.

Although no direct health effects associated with electric and magnetic
fields have been identified, some states have chosen to set limits on the
strength of fields permitted under transmission lines based upon considera-
tion of shock effects. Both Oregon and Minnesota have maximum permissible
field strengths with a right-of-way, 9 kV/m and 8 kV/m, respectively, while
New York has effectively limited field strengths to 1.6 kV/m at the right-
of-way edge (16). Oregon has actually limited field strengths by law; the
other restrictions have come in required construction permits. Current ac-
ceptable National Electrical Safety Code clearances would probably keep the
maximum induced field to less than 10 kV/m. Typical values for maximum field
strengths under powerlines in Maryland are 7 to 7.5 kV/m. No limits have
been imposed in Maryland.

X-7

REFERENCES CHAPTER X

1. Route Selection Study, Montgomery Damascus - Mt. Airy 230 kV Transmis-
sion Line, Commonwealth Associates, Inc., Jackson, Michigan, June
1980.

2. Arlen D. White, "Overview of Corridor Selection and Routing Methodo-
logies," Environmental Concerns in Rights of Way Mangement, Proceed-
ings of Second Symposium Held October 16-18, 1979, R. E. Tillman,
ed., March 1981, pp. 8-1 - 8-8.

3. Morgan, Rasin, Noe. 1973. Effects of Suspended Sediments on the
Development of Eggs and Larvae of Striped Bass and White Perch.
Nat. Res. Inst. Univ. Md. NRI ref. no. 73-110. Appendix XI..

4. Wi P. Jensen (MTA). July 2, 1980. Memorandum to T. E. Magette (PPSP).

5. Daniel E. Willard, "The Impact of Transmission Lines on Birds (and Vice
Versa)," Impacts of Transmission Lines on Birds in Flight, Proceed-
ings of a Workshop., Michael L. Avery, ed., September 1978, pp. 3-7.

6. W. L. Anderson, 1978. Waterfowl collisions with power lines at a coal-
fired power plant. Wildl. Soc. Bull. 6(2): 77-83.

7. Thomas W. Smith, Transmission Lines: Environmental and Public Policy
Considerations - An Introduction and Annotated Bibliography, Insti-
tute for Environmental Studies, University of Wisconsin-Madison,
June 1977.

8. W. R. Kellough, "Impact Analysis of Electrical Transmission Lines,"
Right of Way, October 1980, pp. 50-55@

9. Louis E. Clark, Jr. and F. H. Freadway, Jr., Impact of Electric Power
Transmission Line Easements on Real Estate Values, American Insti-
tute of Real Estate Appraisers of the National Association of Real
Estate Boards, Chicago, Illinois, 1972.

10. Calvin Blinder, "The Effect of Transmission Lines on Residential
Property Values," Environmental Concern in Rights of Way Manage-
ment, Proceedings of Second Symposium Held October 16-18, 1979, R.
E. Tillman, ed. March 1981, pp. 14-1 - 14-14.

11. "Impact of Transmission Lines on Agriculture," from Location Hydro,
Interdisciplinary Research, Centre for Resources Development,
University of Guelph, 1974.

12. J. Patrick Reilly and Robert Carberry, The Electrical Environment of
High Voltage AC Transmission Lines, Institute of Electrical and
Electronic Engineers, DRAFT, July 1981.

13. J. Patrick Reilly, Electric and Magnetic Field Effects from 500 kV
Transmission Lines., Applied Physics Laboratory, The Johns Hopkins
University, PPSE-6-2A, January 1979.

X-8

14. J. Patrick Reilly, Electrical Influence on the Environment from EHV
Power Transmission, Applied Physics Laboratory, The Johns Hopkins
University, PPSE-T-7, April 1977.

15. Human Reactions to Transient Electric Currents, A Research Proposal from
the Johns Hopkins Uiversity Applied Physics Laboratory to the
Maryland Department of Natural Resources and the Canadian Electrical
Association, May 1981.

16. J.P. Reilly OHU). July 14, 1981. Memorandum to L.C. Kohlenstein
(JHU).

X-9

CRAPTER XI

COOLING TOWERS

Two general types of condenser cooling systems are currently in use at
Maryland power plants. Open or once-through systems predominate. Cooling
towers are alternatives which may be required by Maryland law. Cooling
towers require less water to operate (as much as a 50 fold reduction), so
their aquatic impacts are considerably reduced as discussed in Chapter IV.
They could, however, have adverse terrestrial impacts that require site
specific evaluations.

Cooling towers can use natural draft or fan-induced, "mechanical" dratt.
Both types remove heat by evaporation. In the process an aerosol is created
which may drift beyond the exit point of the tower. This drift may contain
concentrated dissolved solids as well as the chemicals used in biofouling
control. Concentrated saline aerosols resulting from cooling tower operation
in brackish water regions of the Bay could have an adverse impact on native
vegetation, crops, and soils. Fogging and icing may occur under certain
meteorlogical conditions and must be considered when highways or buildings
are within the plume impact region. Noise impact, created by cascading water
(natural and mechanical types) and fans (mechanical type) on neighboring
communities, must be evaluated. Visual impacts of cooling towers and plumes
must be considered within the context of existing visual elements at the
site.

Chalk Point plant has two natural draft towers. The proposed expansion
of Vienna will also use a natural draft tower. Present and predicted impacts
at each site are discussed below.

A. Chalk Point

Chalk Point Unit 3 is equipped with a natural draft cooling tower. It
has operated in a brackish water region of the Patuxent since 1975. This
unit also emits brackish water steam from a stack scrubber. Drift emissions
from the stack is approximately equal to the emission from the tower.
Detailed studies have been made of the extent of this salt drift and its
effect on crops, soils and native vegetation in the vicinity of the plant.
These studies show that maximum deposition occur within 1 km of the source.
This distance is within the plant boundary and the measured deposition rate
of 8 kg/ha-month is below the rate at which commercial crops (soybeans, corn
and tobacco) exhibit foliar damage (20 kg/ha-month). There appears to be no
buildup of Na + or increases in electrical conductivity of the soil due to
dustfall accumulation (1). Experimental studies using five species of native
woody trees showed an increase of Na+ and Cl- with increased exposure to
saline aerosol. In all species, except dogwood, the accumulation levels of
Cl- at the end of a growing season were less than the levels causing foliar
damage (0.4-1.8% on a dry weight basis). Normal autumn color in dogwood,
however, obscured observations (2) of any foliar damage due to Cl-.

XI-1

Unit 4 at Chalk Point is also equipped to operate with a similar cooling
tower, but it has not operated to date. The predicted off-site deposition
from cooling towers and stack drift from both units is estimated (3) to be
less than 5 kg/ha-month.

B. Vienna

A natural draft cooling tower has been proposed for DP&L's 500 megawatt
coal fired expansion at Vienna. The issues of salt deposition, plume vis-
ibility, fogging/icing, and visual intrusion were considered by PPSP for
natural and mechanical draft cooling towers.

The Chalk Point Cooling Tower Drift Simulation Model was used to predict
salt drift both on and off site at Vienna for the optimal type of cooling
tower (natual draft). Maximum off-site deposition rate occurred in the
autumn and was less than 25 kg/ha-month. Wo significant accumulation is
predicted to result from this amount. Reduction in crop yield of corn and
soybeans is estimated to be on the order of a few percent. Weathering and r'
corrosion of materials at the boundary will be similar to that found at sites
I km inland from the ocean coast (4).

The impact of visual intrusion of the cooling tower and related plume is
difficult in quantify. The tower itself will be 122 meters high, and on most
days the plum *e will exceed 100 meters in length. The visual impact of the
tower and plume, however, must be considered as an incremental visual impact
in addition to the 171 m stack, turbine (30.5 m) and boiler buildings (76.2
m) of the proposed facility. Because of vacation traffic along Route 50, the
number of people exposed to the view could be as high as 14,000 per year.
Fogging and icing on the Route 50 bridge is expected to be minimal because of
the plume elevation.

On the basis of these studies, the PPSP has recommended to the Maryland
Public Service Commission that a natural draft cooling tower be used at the
proposed Vienna expansion (5).

XI-2

REFERENCES - CHAPTER XI

1. Charles L. Mulchi. Cooling Tower Effects on Crops and Soils. Chalk Point
Cooling Tower Project: Post-Operational Report No. 6. PPSP-CPCTP-36.
1981

2. R.A. Galloway and B.A. Francis. Native Vegetation Study. Chalk Point
Cooling Tower Project. PPSP-CPCTP-32. 1981

3. E.A. Davis. Environmental Assessment of Chalk Point Cooling Tower Drift
and Vapor Emissions. PPSP-CPCTP-28. 1981

4. Edward M. Portner. Impacts of the Proposed Vienna Unit No. 9-An Overview
of Vienna and Alternative Sites. PPSE 8-8. 1981

5. State of Maryland Recommendations. Exhibit No. 42 to Case 7222 of the
Maryland PSC.

XI-3

APPENDIX A

THE PPSP/DSP LOAD FORECASTING PROGRAM

Since 1974 the Power Plant Siting Program, in conjunction with the
Maryland Department of State Planning (DSP), has conducted an active load
forecasting program. During this time period long-range forecast studies of
each of the four major utility systems which operate in the State have been
prepared (1), (2), (3), (4). These studies provide comprehensive and
detailed projections of future electric energy use for each of the four
systems. In each case, the forecasts were prepared for the entire multi-state
system rather than just the Maryland portion because each of these utilities
is planned on a systemwide basis. In addition to developing the annual peak
demand forecasts, energy sales were forecast by major customer class, regula-
tory jurisdiction and season. The PPSP/DSP forecasts were obtained from a set
of econometric equations which relate key explanatory variables to the demand
for electricity. It is the purpose of this Appendix to describe the methodo-
logy and the forecasts it has produced.

PPSP has produced long-range forecast studies for Pepco (1975), BG&E
(1979), APS (1980) and DP&L (1980). Revisions have been prepared for Pepco,
BG&E and APS. The two most recent studies were the DP&L forecast completed in
March 1980, and the APS forecast, completed in January 1980. Since those two
studies were completed within a few months of one another, the methodologies
employed are substantially similar. -This Appendix uses the DP&L models to
illustrate that methodology since it is the most recent of the four studies.

The BG&E and Pepco studies were prepared several years earlier, and thus
are methodologically somewhat different from the DP&L and APS studies. The
Pepco study was completed in 1974 using a data base which ran through 1972.
The BG&E study was substantially completed in late 1977, although the report
resulting from the study was published by PPSP in 1979. The terminal year of
the BG&E data base was 1974.

PPSP has performed forecast updates of the Pepco and BG&E systems in 1978
and 1981, but those revisions are limited in scope. They involved alterations
to the forecasting assumptions along with the use of a more recent base year.
The updates provide revised energy and peak demand forecasts for Pepco
(through 1991) and only peak demand forecasts for BG&E (through 1995).

Because the original studies were prepared so long ago and used little or
no data from the post-Arab Oil Embargo period, completely new forecast studies
of the two utiities are needed. The new studies will use the more complete
data which are now available and will also use any methodological improvements
which have taken place in the last few years. PPSP is currently in the pro-
cess of performing a new Pepco load forecast. Completion is scheduled for
September 1982. A revision of the BG&E forecast will also be prepared, sche-
duled for completion in March 1982. This revision will rely upon the models
from the original study but will employ a more recent base year and updated
assumptions.

A-1

A. Overview

The process of econometric forecasting consists of two principal stages.
In the first stage, statistical models of the demand for electricity are esti-
mated from historical data. These econometric models describe the rela-
tionship between the demand for electricity and various causative economic
factors that govern it, such as population, income, employment, wage rates and
energy prices. In the second stage, projections of future values for these
causative factors are inserted into the econometric models in order to deter-
mine the likely future demand for electricity.

In order to construct a structural econometric model, it is first
necessary to determine the important causative factors affecting the demand
for electric power. After specifying a model which incorporates these fac-
tors, historical data on the dependent and independent variables are collected
and processed. The precise quantitative relationships between the dependent
variable, i.e., energy consumption, and the factors that govern it are esti-
mated by the use of ordinary least squares regression. In the recent
Delmarva study, such models were developed for summer and winter residential
usage (per customer), summer and winter commercial usage (per nonmanufacturing
employee) and industrial usage (per manufacturing employee). The study also
included a statistical analysis of other, less important elements of electri-
city demand, as well as energy losses, and summer and winter system peak
demands.

The econometric equations are derived from the behavioral relationships
governing the demand for electricity, as they existed during the period from
which the historical data were drawn, generally the mid-1960's to the mid- or
late 1970's. The demand forecasts are then calculated by inserting into the
estimated equations the expected future values of the driving (causative)
variables. Most of these values have been developed from official state or
federal projections, including those of the Department of State Planning. The
remaining values were determined judgmentally. After the energy forecasts are
calculated, these values are inserted into the equation which relates peak
demand to energy usage, relative sector size and weather. In that manner pro-
jected peak demand is determined. Using values of the driving variables
determined in this manner, the Most Likely Case forecast is produced.

it is critically important, however, that system planners and regulators
realize that any forecast is uncertain, regardless of how skillfully the
models are developed. In order to obtain alternative upper and lower bound
growth paths, substantial but plausible alterations to the Most Likely Case
assumptions are made and the forecasts recalculated. The difference between
the upper and lower bounds represIents the plausible long-run range of uncer-
tainty. in addition to these alternative forecast scenarios, the PPSP/DSP
studies include estimates of demand reductions (both total energy sales and
peak demand) due to conservation programs and time-of-use electricity pricing.

A-2

B. The Econometric Models

The econometric models used to forecast energy usage have been formulated
on the basis of a priori, theoretical judgment concerning the various economic
and other factors which directly affect energy usage. Since the models in all
cases are estimated from historical time-series data, the results reflect the
behavioral relationships that prevailed during that historical period. It is
assumed that these historical relationships will prevail in the future.

The development of the PPSP/DSP models has been guided by technical con-
siderations normally encountered in the econometric analysis of electricity
demand. These considerations relate to both the limitations of economic
modeling, and to the statistical properties of ordinary least squares
regression, the estimation method used to quantify the models.

0 Specification -- Ideally, an econometric model should be fully spe-
cified. This means that all factors which significantly influence
demand should be included in the model. Failure to do so will result
in coefficients which may be biased, since the remaining variables
will be forced to "explain" what the missing variables should
explain. However, it is not practical to construct a model which
includes the entire universe of possible considerations. Therefore,
judgment is required to keep the models as simple as possible without
excluding the truly important factors.

0 Dynamic behavior -- The rubric of specification includes the
"functional form" of the equation as well as the selection of
variables included in the model. Since time-series data are being
analyzed, there is an opportunity (as well as a necessity) of deter-
mining how rapidly households and businesses alter their power
demands in response to changes in the causative variables. Since
electricity is consumed only through stocks of electricity-using
equipment, and since customers will only alter these stocks gra-
dually, the electricity demand responses to changes in the causal
variables will likewise be gradual. A model which fails to take
this dynamic behavior into account is badly misspecified and will
likely produce erroneous results.

0 Multicollinearity -- A problem common to time-series regression ana-
lysis occurs when two or more independent variables are highly corre-
lated with one another. It is very important that this situation be
avoided since it may render the coefficient estimates of one or more
of the correlated variables involved erroneous. If the problem is
sufficiently serious, one or more of the correlated variables may
have to be eliminated from the equation.

0 Electricity price definition -- A key assumption in regression analy-
sis is that causation runs solely from the independent to the depen-
dent variable. If causation runs the other way or both ways then
biased results are likely. Because electricity has historically been
sold from declining block tariffs, this problem is familiar to ana-
lysts of electricity demand. With the declining block rates, a ran-
dom factor, such as unusually hot weather, causes an increase in

A-3

consumption and thus a decline in the average price paid per kilowatt
hour for electricity. Thus, in this example, the increase in usage
caused the reduction in price, not the other way around. This
problem can be overcome by avoiding an average revenue definition of
price.

0 Aggregation -- The estimated equation should be derived from data
which are not so aggregated as to camouflage important causal rela-
tionships. That is, the very act of aggregating can eliminate the
variations in the dependent and independent variables needed for
efficient econometric estimation. In the PPSP/DSP models this has
been avoided by disaggregating by season, customer class and regula-
tory jurisdiction. How far disaggregation should go depends upon
data quality (and availability) as well as theoretical or econometric
considerations.

The PPSP/DSP econometric models were specifically designed to avoid these
potential pitfalls to the extent possible. The way in which this was
accomplished is described below, with special reference to the Delmarva study.

Residential Models

The important determinants of residential usage of electricity can be
easily identified and would include:

electricity prices
� alternative energy prices
� personal income
� population
� weather
� housing stocks
� household appliance stock ownership
� appliance vintages and energy efficiencies
� natural gas available
� household size
� inflation

However, it would be rather unwieldy to include all these items in a
regression model, and moreover a reliable historical data series on many of
these items is not available. Further, some of the variables (e.g., income
and appliance stocks) are interdependent in a complicated manner and thus not
truly independent of one another.

These problems can be largely avoided by the inclusion of a "lagged
dependent variable" -- i.e., the value of the dependent variable the previous
year. The lagged dependent variable serves as a proxy for appliance and
housing stocks, lifestyle and other factors which are capable of changing very
gradually. This specification also serves to introduce a dynamic adjustment
process into the model in a convenient manner.

The residential equations in the Delmarva study were estimated from
pooled time-series cross-section data. That data series consists of indivi-
dual observations for each month 1966-1977 for each of the three states which

A-4

comprise the Delmarva Peninsula. Separate equations were developed for the
summer and winter seasons. Explanatory variables in the models include the
number of customers, real (i.e. inflation adjusted) income, real electricity
prices, weather, an air conditioning or space heating saturation measure, and
a dummy variable for each region.1 Logarithmic transformations were per-
formed on the dependent variable (monthly sales per customer), real income and
the price of electricity. The estimated summer and winter equations along
with certain test statistics are presented in Table A-1.

The specification of the weather variable, the lagged dependent variable
and the electricity price measure warrant additional explanation. The lagged
dependent variable is defined as the value of the dependent variable for that
region exactly twelve months prior. The weather variable is specified in
first difference form. In order to obtain an "effective" weather measure, the
heating degree day values were multiplied by one plus the electric space heat
saturation percentage, while the cooling degree day values were multiplied by
one plus the air-conditioning saturation.

Finally, the price measures were specified so as to avoid the two-way
causation problem described earlier. This requires avoiding the use of an
average revenue measure, Therefore, the summer model uses a -marginal price-
constructed by subtracting a 500 Kwh monthly bill from a 1000 Kwh monthly
bill, and the winter model simply uses a 500 Kwh monthly bill.2

Both short and long-run elasticities can be calculated. The elasticities
obtained, as shown below, are consistent with although somewhat below the
results obtained in other studies. Both the price and income elasticities are
slightly lower in the winter.

Summer Season

Price Income

Short-run: -0.09 0.21

Long-run: -0.40 0.95

Winter Season

Price Income

Short-run: -0.05 0.09

Long-run: -0.33 0.62

-------------------------
1 A dummy variable operates in a binary fashion, taking on a value of 1 when
operative and zero otherwise. This approach essentially allows for a separate
intercept or constant term for each geographic region.

2
The monthly bills were constructed from DP&L tariffs in each jurisdiction
and fuel adjustment charges.

A-5

Table A-1

Delmarva Residential Energy Forecasting Models

Summer

In (RMWH/CUST) - -0.99 - 0.0004 CDD + 0.78 LDEP
(-2.4) (19.3)

-0.09 In PRICE + 0.21 In INCOME + 0.04 DVA
(-2.7) (2.0) (0.7)

+ 0.04 DSD + 0.03 DMD
(1.2) (1.0)

R2 = .92 Durbin-Watson = 1.94

Winter

In (RMWH/CUST) 0.66 + 0.86 LDEP - 0.05 In PRICE
(-1.2) (32.7) (-1.2)

* 0.09 In INCOME! + 0.0002 HDD + 0.06 DMD
(1.3) (9.0) (2.4)

* 0.05 DVA + 0.05 DSD
(1.3) (2.0)

R2 = .94 Durbin-Watson = 1.56

Variable Definitions

RMWH = Monthly Sales in Mwh
CUST = Number of residential customers
LDEP = Lagged dependent variable
PRICE Electricity price measure in real terms
INCOME Personal income in real terms
HDD = Heating degree day measure
CDD = Cooling degree day measure
DMD = Maryland region dummy variable
DVA = Virginia region dummy variable
DSD = Southern Delaware region dummy variable

Numbers in parentheses are t-statistics.

A-6

Commercial/Industrial Models

In contrast to the residential sector, the commercial and industrial
classes are extremely heterogeneous. Although this heterogeneity warrants a
highly disaggregated approach, lengthy time-series on energy usage are usually
available only for broadly defined "commercial" and "industrial" customers.
The Delmarva study developed separate equations from time-series data for com-
mercial, industrial and other (mainly resale) customers for each of the three
states on the Peninsula. Separate summer and winter equations were estimated
for the commercial sector, but since seasonality is relatively unimportant in
the industrial sector, only annual models were developed. Because of the
relative month to month stability in industrial sales, those equations were
estimated from quarterly rather than monthly observations.

The character and pattern of nonresidential electricity usage differs
markedly from the residential, but the underlying determinants are analogous.
Instead of household appliance stocks, power usage by firms tends to be
governed by technology and the stock of capital goods which embodies that
technology. Thus, it is convenient to specify a model with a lagged dependent
variable to serve as both a surrogate for technology and to impart a dynamic
response to changes in the values of the causative variables.

Nonresidential model specification is consistent with the standard eco-
nomic theory of production, The demand for electricity is determined by the
level of economic activity (represented by an appropriate measure of
employment), and the technology utilized is ultimately determined by relative
prices paid for the various production inputs. Thus, in addition to
employment and a lagged dependent variable, key explanatory variables would
include electricity price and the wage rate.1

Several short-run or transitory factors were also included in some of the
equations. All commercial equations included a weather variable since commer-
cial electric loads are weather sensitive. Two other variables were employed
to account for short-run changes in labor productivity (and thus energy usage)
which would normally be masked by an employment variable. A capacity utiliza-
tion variable was used for that purpose in the industrial sector, reflecting
the fact that employment tends to lag behind output over the course of the
business cycle. In the commercial sector, an employment change variable was
used since marginal or part-time workers are generally disproportionately
discharged during a business downturn and hired during an upturn. Consistent
with the model in the previous section, these short-run variables are spe-
cified in first differ ence form.

The estimated commercial/industrial models are shown in Table A-2 along
with some key test statistics and variable definitions. Because of the marked
difference in the nonresidential sector from state to state2 the use of
pooled data was avoided. All models were estimated from time-series data
covering the period 1966-1977.

-----------------------
1 Rapid increases in the wage rate encourage the use of more capital intensive
production methods which, in turn, tend to be more energy intensive.
2 For example, the industrial sector in Maryland is largely light industry,
particularly food processing. By contrast, Delaware is dominated by heavy
industry such as chemicals, metals and automobiles.

A-7

Table A-2

Delmarva Study
Coitaiercial/Industrial Model

(1) Delaware Commercial Summer Model

In (MWH/CEMP) -0.06 + 0.0004 CDD + 0.77 LDEP
(-0.27) (19.6)

0.11 In WAGE 0.06 In PRICE
(0.97) (-1.21)

R2 = .88 Durbin-Watson = 1.84

(2) Delaware Commercial Winter Model

In (NWH-CEMP) = 0.80 LDEP + 0.07 In WAGE
(20.5) (1.13)

0.00004 HDD - 0.06 In PRICE
(2.27) (-2.43)

R2 = .88 Durbin-Watson = 1.40

(3) Maryland Commercial Winter Model

In (MWH/CEMP) 0.89 LDEP - 1.04 CH + 0.02 D 1969
(30.55) (-5.18) (0.63)

+ 0.0002 HDD 0.03 In PRICE + 0.05 In WAGE
(4.55) (-0.83) (0.46)

R2 = .95 Durbin-Watson = 1.55

(4) Maryland Commercial Summer Model

In (MWH/CEMP) = 0.89 LDEP - 0.03 PRICE
(27.56) (-0.85)

+ 0.06 In WAGE + 0.0002 CDD - 0.74 CH
(0.63) (2.84) (-3.94)

R2 = .94 Durbin-Watson = 2.19

A-8

Table A-2 (Continued)

(5) Delaware industrial Model

In (MWH/MEMP) = 1.97 + 0.49 LDEP - 0.27 In PRICE
(3.47) (6.07) (-3.33)

+ 0.56 In WAGE + 0.0009 CUL
(1.81) (0.25)

R2 = .77 Durbin-Watson = 0.80

(6) Maryland industrial Model

In (MWH/MEMP) = 0.83 LDEP - 0.05 In PRICE
(18.06) (-1.03)

0.40 In WAGE + 0.06 D 1975
(1.57) (2.24)

R2 = .94 Durbin-Watson = 1.70

(7) Virginia Commercial/industrial model

In (MWH/TEMP) = 0.22 + 0.88 LDEP - 0.08 In PRICE
(0.40) (8.40) (-1.23)

0.15 In WAGE + 0.0004 CDD + 0.00004 HDD
(0.36) (4.51) (1.01)

R2 = .87 Durbin-Watson = 2.08

Variable Definitions

MWH = Monthly or quarterly megawatt hour sales
CEMP, MEMP, TEMP = Commercial, manufacturing and total
employment
LDEP = Lagged dependent variable
PRICE = Electricity price defined as either
marginal price or typical bill (inflation
adjusted)
WAGE = Manufacturing hourly wage rate (inflation
adjusted)
CDD = Cooling degree day measure
HDD = Heating degree day measure
CUL = Capacity utilization measure
CH = Change in employment measure
D 1969, D 1975 = Dummy variables for 1969 and 1975

Numbers in parentheses are t-statistics.

A-9

The resultant econometric equations are noticeably different in the com-
mercial and industrial sectors. The price and wage elasticities which are
shown below as systemwide averages highlight the basic differences.

Price Wage Rate
Short-run Long-run Short-run Long-run

Summer Commercial -0.05 -0.24 0.10 0.50

Winter Commercial -0.05 -0.29 0.06 0.37

Industrial -0.23 -0.58 0.52 1.41

The industrial elasticities appear to be roughly in line with results obtained
in other studies. The commercial elasticities are much lower, but since
little econometric research has been performed in this sector it is difficult
to compare these results with any sort of prevailing consensus.

Other Elements of Energy Demand

In addition to energy usage by commercial and industrial customers, there
are some other elements of system energy use that must be forecasted. In the
Delmarva study it was not possible to obtain customer class retail sales data
from some of the municipal systems operating in Delaware. Consequently, the
DP&L sales for resale to those systems and any generation by those systems
were combined into one aggregated time series. W
61
Since most of this energy is used by residential customers, it was
modeled by constructing a regression model which relates this energy to
Delaware residential sales and a series of monthly dummy variables. The dum- b6,
mies explain the extent to which this energy usage differs from DP&L residen-
tial usage with respect to seasonality and/or weather-relatedness.

The final element of energy considered in these studies is system energy
losses, which on any utility system is an accounting residual measuring the
difference between system output and system sales. The approach taken was
first to construct a loss factor (defined as losses as a percentage of sales)
and then to relate that loss factor to the industrial sector's share of total
sales (ISHR) and the log of time. These relationships were estimated using
annual time-series data with ordinary least squares regression. The results
are shown below.

Losses/Sales = 0.12 - 0.12 ISHR - 0.0008 ln TIME
(5.66) (-2.38) (-0.31)

R2 = .56 Durbin-Watson = 1.94

Increases in the industrial sector's share should lower the loss factor
because industrial customers receive power at high voltages. Loss factors
tend to be inversely related to the voltage level. Time is intended to serve

A-10

as a proxy for technological change; over time loss factors should improve.
The logarithmic transformation is intended to suggest "diminishing returns" to
technological change and also to insure that any forecast of an improved loss
factor is modest.1

Peak Demand Models

The PPSP studies have forecast peak demand at the system level only. No
attempt has been made to do so at the class or jurisdiction level because
accurate data series on such loads are not available. Moreover, system
planning is governed by system peaks rather than class or jurisdictional
peaks.

Peak demand in the long-run tends to be driven by virtually the same fac-
tors that determine energy usage -- economic activity, population, energy pri-
ces, weather and so forth. 'Rather than-directly relate those factors to
system peak demand, it is far easier to utilize a total energy output
variable, which accounts for all of those factors implicitly. Thus, the basic
approach involved constructing regression models, for the summer and winter
seasons, which relate monthly peak demand to total system energy output (i.e.
sales plus losses), the industrial sector's share of total system energy out-
put and a peak day weather variable. For a given level of total energy out-
put, an increase in the industrial sector's share should tend to lower peak
demand since the industrial sector tends to exhibit flatter loads.

The estimation of such a model appears to be rather simple and straight-
forward, but it is in fact complicated by swings in monthly weather. Month to
month changes in weather can rather drastically affect the magnitude of the
total energy output variable. However, the weather sensitivity of peak demand
is properly measured by a peak day weather variable, not a monthly weather
variable. To complicate matters further, monthly weather and peak day weather
(using a monthly series) are likely to be highly correlated causing a multi-
collinearity problem between the energy (which is strongly influenced by
monthly weather) and peak day weather variables in the equation. The result
is that the energy variable is likely to "overexplain" peak demand, and the
weather variable would "underexplain" peak demand.

The solution to this problem is to first remove the weather component of
the monthly energy usage variable. To do this a set of equations were econo-
metrically estimated which related total monthly energy output to a trend
measure and to monthly weather. Using the resultant coefficients and monthly
weather values, the weather sensitive component was removed.

Thus, the peak demand estimating equations, which are shown in Table A-3,
relate monthly peak demand to non-weather sensitive energy, the industrial
sector's share of non-weather sensitive energy and peak day weather. These
models were estimated from monthly time series covering the period 1966-1977.
After examining residuals from initial regression results, it was found that
the models produced some small but systematic error for August and January.
To correct the problem, dummy variables were inserted for those months.

---------------------------
1 Without such transformation the model might forecast unrealistic loss factor
improvements a number of years into the future.

A-11

Table A-3

Delmarva Peak Demand Models

Summer

In (MW) = -9.94 + 1.04 In MWH - 0.30 In ISHR
(-13.08) (30.89) (-4.54)

+ 1.03 In WEATHER - 0.03 AUGUST
(7.84) (-2.21)

R2 .98 Durbin-Watson = 1.62

Winter

In (MW) -4.37 + 0.95 In MWH - 0.005 WEATHER
(-7.45) (30.59) (-8.46)

- 0.25 In ISHR - 0.04 JANUARY
(-3.83) (-2.67)

R2 = .97 Durbin-Watson = 2.36

Variable Definitions

MW Monthly system peak demand
MWH Monthly system nonweather sensitive
outputs
ISHR Industrial sector's share of nonweather
sensitive monthly system energy output
WEATHER =Peak day weather variable.
AUGUST, JANUARY =Dummy variables for those months.

Numbers in parentheses are t-statistics.

A-12

Backcast Checks

As judged by the R21s, the Delmarva energy and peak demand regression
equations were able to explain power demands rather accurately. This was
further examined by the calculation of "backcasts." Backcasts are obtained by
inserting actual values of each of the independent variables into the esti-
mated model and then calculating the values of the dependent variable. The
simulated or backcasted sales (or peak demand) figure can be obtained for each
historical month or year and compared to actual experience in order to judge
the accuracy of the model -- at least for that period.

A summary of backcast and actual comparisons is shown in Table A-4 for
the Delmarva study. These errors are averaged over selected time periods on
both a simple averaging basis and an absolute averaging basis. The purpose of
the absolute average is to demonstrate the degree of accuracy in explaining
the historical data. The percent error figures were converted to absolute
values before taking the average so that the positive and negative values do
not cancel each other out. These results indicate average errors of about one
to two percent and almost no perceptible difference by time periods. The
simple average measures permit positive and negative errors to cancel. This
measure can be used to determine if models systematically underestimate demand
during certain periods (e.g., 1967-1973) and overestimate demand during others
(e.g., 1974-1977). All of the simple average figures in Table A-4 are
extremely small (because of offsetting errors within time periods), and there
appears to be no systematic tendency for differences in results by time
period. Thus, Table A-4 indicates that the models appear to explain the early
years of the data base as well as they do the later years.

A-13

Table A-4

Delmarva Peninsula

Average Differences Between Backcast and

Actual Power Demands (Percentages)

Residential Commercial Industrial Summer Peak
Absolute Simple Absolute Simple Absolute Simole Absolute Simple
Time Period Average(a) Average (b) Average(a) Average(b) Averaqe(a) Average (b) Averaqe(a) Average (b)

1967 - 1977 1.35% 0.22% 1.29% -0.01% 2.56% -0.03% 1.96% -1.10%

1967 - 1973 0.93 0.57 0.54 -0.11 3.25 -0.32 2.46 -2.38
> 1974 - 1977 2.09 -0.40 2.60 0.17 1.35 0.46 1.56 1.14

1975 - 1977 1.61 0.64 1.85 1.85 1.42 1.00 1.04 0.48

(a) The absolute value of the percent backcast error for each year of the specified time period is first
obtained, and the average of those figures for that time period is then computed.

(b) The percent backcast error for each year of the specified time period is first obtained, and the
average of those figures for that time period is then computed. This differs from the "absolute
average" in that positive and negative percent errors are permitted to cancel each other in
in the averaging process.

Source: (4)

C. Forecast Assumption

In order to forecast demands using the models described in Section B, it
is first necessary to formulate assumptions concerning future values of all
right-hand-side variables in the models. For some variables, e.g., weather,
dummy variables, capacity utilization, and so forth, future values are rather
obvious and do not change over the forecast period.' Most other variables can
only be predicted with great difficulty and uncertainty. Since the variables
in question tend to be causally interrelated, it is important to develop
assumptions concerning these variables that are logically consistent with one
another. A set of internally consistent assumptions is referred to as a
"scenario." A Most Likely Case scenario is normally developed first based
upon the best available information and judgment, and then alternative sce-
narios are constructed in order to bracket the range of uncertainty which
surrounds the Most Likely Case growth path.

Most Likely Case (MLC)

The major forecasting assumptions can be divided into four main
ategories:

� The size of the service area economy -- This would include such
variables as employment (total and by sector), population, and number
of households.

� The productivity of the service area economy -- The hourly wage rate
and personal income largely reflect the productivity of the region.

� Energy prices -- This includes electricity price, and where fuel
switching is relevant, price escalations for natural gas and/or oil.

� Other factors -- Assumptions must be made concerning weather, space
heating and air-conditioning saturations, and capacity utilization.
The treatment of dummy variables is self-explanatory.

The Delmarva study serves to illustrate the PPSP/DSP method of developing
the Most Likely Case set of assumptions. For most variables, assumed growth
rates were applied to the base year (i.e., 1977) values to obtain values of
those variables for all future years of the forecast period. All dollar deno-
minated variables (e.g., income, wage rate, energy prices) were escalated in
inflation adjusted terms. In most cases, the economic and demographic assump-
tions could be obtained from official state or federal sources * In some
instances official projections were only used to provide general guidance and
additional analysis and judgment were applied. Finally, the methods used
varied from state to state, depending upon the quality and quantity of projec-
tions data available from state governments.

Populati'on and employment projections for Maryland counties were provided
by DSP (5), and the growth rates implicit in these projections were applied
in a straight-forward manner without any adjustment. The county level projec-
tions were simply aggregated to correspond to the Maryland portion of the ser-
vice territory. The population growth rate was combined with the U.S. Census

A-15

Bureau's nationwide household formation rate projection to obtain a projection
of the growth rate of households in the Maryland service area. The number of
households is expected to grow more rapidly than population because of the
tendency toward smaller size families.

The population and employment projections are also useful in obtaining
projections on the service area's productivity variables -- i.e., wage rates
and per capita income. Earnings per worker and the ratio of employment to
population are the two main determinants of per capita income. That is, not
only does per capita income depend upon earnings per worker, but it is also
determined by the percentage of the population which is employed. Ignoring
for the moment non labor income, the growth rate in per capita income is the
sum of the growth rates of earnings per worker and the growth in the percen-
tage of the population employed.

Over the very long term, real wage rates are governed by labor produc-
tivity advances, because real wages are the mechanism by which the economic
benefit of increased productivity is reflected in labor incomes. However,
neither regional wage rates nor productivity projections are available from
any official source. Thus, it was assumed that the Maryland service area wage
rates will grow by two percent annually based upon the U.S. Department of
Labor's long-term outlook for the national economy. Finally, the income pro-
jection was obtained by adding to this two percent figure the growth in the
employment/population percentage.

Undoubtedly, the most difficult variable to forecast is the price of
electricity. To some extent, the U.S. Energy Information Administration's
mid-term projections for electricity prices and the prices of fuels used to
generate electricity -- coal and oil -- were relied upon for guidance. 3V
However, these figures are national and must be applied to any individual uti-
lity with caution. Thus, in formulating final assumptions on electricity
price various factors were judgmentally considered, including expected growth
in rate base resulting from scheduled capacity additions, changes in fuel mix,
and past trends.

The final category of assumptions were dealt with very simply. All
weather variables were assumed to equal their long-term average in all fore-
cast years. The same assumption was made concerning capacity utilization.
Assumptions concerning changes in space heat and air conditioning saturation
were developed by specifying exponential "decay" rates for households not
possessing those appliances. That is, households lacking those appliances are
assumed to diminish by some fixed percentage each year until some theoretical
maximum saturation level is achieved. These are relatively minor assumptions
since the saturation variables only serve in the models to weight the weather
values.

Alternative Scenarios

Alternatives to the Most Likely Case were developed to deal with the
problem of assumption uncertainty and to produce a plausible range of results.
In developing each scenario care was taken to ensure that the changes in

A-16

assumptions were logically consistent with one another. Along with the sce-
narios, sensitivity tests were performed in which only one assumption change
was made per forecast model run in order to determine the importance of each
assumption.

The major alternative scenarios to the Most Likely Case include the
following:

� High Electricity Prices -- Assume that the real price of electricity
escalation rate is double the MLC for all customer classes and juris-
dictions.

0 Low Economic Growth -- Decrease all of the MLC projected growth rates
of employment and in the number of residential customers by 0.5 per-
cent annually, and decrease the real wage and per capita income MLC
growth rates by 0.8 percent annually.

� High Electricity Prices and Low Economic Growth -- This scenario
incorporates the changes to the MLC from the above two scenarios.

� High Economic Growth -- Increase MLC projected growth rates for
employment and households by 0.5 percent per year and increase wage
rates and per capita income by 0.8 percent per year.

� Energy Policy Scenario -- Includes anticipated effects of the
National Energy Act conservation programs and the systemwide imple-
mentation of marginal cost, time-of-use rates. This scenario is
discussed further in the next section.

In the Delmarva study, as in all the PPSP/DSP forecast studies, the
results vary considerable from one scenario to another; the spread between the
upper and lower bound results is quite large. Table A-5 presents the peak
demand forecasts and annual average growth rates for each scenario in the
Delmarva study. The high electricity price/low economic growth scenario ser-
ves as the lower bound, while the rapid economic growth scenario is the upper
bound. The 1995 difference between the upper and lower bounds is about 1,100
megawatts, and both scenarios differ from the Most Likely Case in that year by
about 500 megawatts.

Energy Policy Impacts

In October 1978 Congress passed five pieces of legislation known collec-
tively as the National Energy Act. This legislation increased federal
involvement in and regulation of the energy sector and mandated several major
conservation programs. Some of the programs, such as the appliance efficiency
standards, serve to regulate the way in which energy is used. Many others
involve very substantial grants or tax incentives to encourage conservation
and renewable resources. The Public Utilities Regulatory Policies Act
requires state commissions to consider the appropriateness of marginal cost,
time-of-use pricing of electricity.

None of the programs were considered in the Most Likely Case because the
econometric models could not be directly structured to accommodate these
programs. Thus, methods were employed to determine program impacts outside
the framework of the Delmarva models.

A-17

Table A-5

Peak Demand Forecasts For The Most Likely Case And Alternative Scenarios

-- Delmarva Study (Megawatts)

Low High
most High Economic High Price/ Economic Energy
Likely Price Growth Low Growth Growth Policy

1980 1,645 1,639 1,608 1,602 1,682 1,645

1985 1,979 1,872 1,788 1,745 2,060 1,871

1990 2,246 2,163 1,983 1,912 2,545 2,150

1995 2,632 2,504 2,198 2,096 3,156 2,504

Annual Rates of Growth

1980-
1995 3.19% 2.87% 2.11% 1.81% 4.29% 2.85%

Source: (4)

M Ot Im M 01 IM 11

Because of the great uncertainty associated with both the future of these
programs and their impacts, none of these results are included in the Most
Likely Case forecasts. They are listed instead as a separate scenario.

Using the Oak Ridge National Laboratory integrated economic/engineering
model of energy usage, the Energy Information Administration has made qstima-
tes of national electric energy savings from National Energy Act conservation
programs. The Oak Ridge model is able to determine energy usage reductions
net of what would have been induced by rising electric rates. virtually all
of the conservation programs included in their analysis relate to the residen-
tial and commercial sectors. By 1990, Oak Ridge estimates nonindustrial
electric energy usage reductions of roughly seven percent as compared to their
base case. For Delmarva, this translates into a 180 megawatt reduction in
peak demand assuming that conservation programs are neutral with respect to
time of use of electricity.

The Delmarva study also includes an analysis of the potential peak demand
reductions from marginal cost, time-of-use pricing. It was assumed that these
rates will have no effect on total energy consumption but only the time pat-
tern of consumption. The impact on peak demand growth was determined by
applying the price elasticities from the econometric models to differentials
in peak/off-peak costs which were obtained from a recent marginal cost study
of the Delmarva system. To obtain conservative impact estimates, it was
assumed that the demand at the time of the system peak is less price elastic
(i.e., price responsive) than overall energy use. using this approach, it was
estimated that systemwide implementation of time-of-use pricing might save as
much as 130 megawatts of peak demand by 1995.

Monthly Adjustments to Energy Models

Since energy sales serve as an input to the forecast of peak demand, it
is necessary that each of the various energy models be capable of producing a
long-range forecast for each month of the year. The major concern in pro-
ducing monthly forecasts is to ensure that the forecasted monthly pattern or
allocation of annual sales is realistic. For the most part, the only right
hand variable which is capable of generating monthly differences in energy
usage is the weather. Other factors may also systematically influence the
monthly energy sales pattern, but these factors were excluded from the models
either because they could not be quantified, could not be identified, or would
have introduced an unacceptable degree of multicollinearity.

A technique was utilized in the Delmarva study which assures that the
monthly historical sales accurately reflects the historical pattern. For each
of the energy forecasting models, residuals were computed from the econometric
equations and regressed against a series of monthly (or quarterly in the
industrial sector) dummy variables. The estimated coefficients on the dummies
represent the average statistical error (after permitting positives and nega-
tives to cancel) in the application of each of the models to the various
months. The residual coefficients (or means) and dummy variables were then
incorporated into the final forecasting models to obtain the monthly fore-
casts.

A-19

The results from this procedure indicate that for most equations and most or
months there is no significant tendency to over or underestimate energy usage.
In a few instances the average error is as much as two to three percent; but
in most cases it was less than one percent.

The analysis of residuals assures that the monthly pattern of usage per
employee or per customer will be satisfactorily adjusted. However, to ensure
that total energy sales reflect the proper monthly pattern, the patterns of
employment and residential customers must be maintained. To this end, the
projections on customers and employment were adjusted to fit the average
monthly pattern in those variables which prevailed over the period 1972-1977.

D. Forecast Results For The Other Companies

As a means of presenting the PPSP/DSP approach to load forecasting, this
Appendix has used the Delmarva study as an example. This section provides a
summary of the forecast results for the other three major utilities -- APS,
Pepco and BG&E. Since updates have been performed for all three utilities,
both the original and the latest PPSP forecasts are provided for comparison.
Although the original studies all included several alternative scenarios, the
udpates only provide a Most Likely Case forecast.

Table A-6 provides the results for the Most Likely Case and five alter-
native scenarios from the original forecast study for APS. Along with the
various economic scenarios, the last column of the table incorporates the
potential impact upon peak demand from time-of-use pricing. This table indi-
cates that the upper and lower bounds have forecasted annual rates of growth
which differ from the Most Likely Case by approximately a percentage point.

Table A-7 presents forecasted peak demand growth rates for BG&E, Pepco
and APS from the original studies and updates for purposes of comparison. As
this table indicates, the update results are substantially below the original
forecasts in every case. There are two basic causes of the forecast reduc-
tion. First, late 1970's load growth was far less than anticipated, by both
the Companies and PPSP. Second, the outlook for economic growth in the ser-
vice areas of these utilities has become less optimistic. Although downward
revisions to the orginal forecasts are clearly warranted, the new forecast
studies which will be prepared by PPSP in the near future should provide more
reliable results.

A-20

mum W W W W'W W W'= n W W M W

Table A-6

Peak Demand Forecasts For The Most Likely Case and Alternative Scenarios

-- The Allegheny Power System (Megawatts)

Most Rapid Growth/ Rapid Slow Slow Growth/ Time of Use
Likely Low Price Growth Growth High Price Pricing

1980 5,648 5,902 5,775 5,521 5,340 5,648

1985 6,867 7,432 7,141 6,548 6,050 6,579

1990 8,156 9,386 8,732 7,565 7,015 7,592

1995 9,601 11,441 10,612 8,757 8,117 8,820

Annual Rates of Growth

1980-1995 3.60% 4.51% 4.14% 3.12% 2.83% 3.02%

Source: (3)

Table A-7

Original And Revised Peak Demand Forecasts For
APS, PEPCO And'BG&E
(Megawatts)

APS Pepco BG&E
U'riginal Revi'sion Original Revisi 671r'ginal Revisi

1980 5,648 5,272 4,452 4,142 3,510 3,770

1985 6,687 6,093 5,621 4,393 4,418 4,447

1990 8,156 7,000 -- 4,554 5,543 5,232

1995 9,601 7,984 -- -- 5,965

Annual Rates of Growth

1980 -
1995* 3.60% 2.81% 4.77% 0.95% 4.68% 3.11%
1

Growth rates, based upon 1995 or last year of the forecast period.

Source: (3), (6), (1), (7), (8)

REFERENCES - APPENDIX A

(1) Wilson, John W., Douglas Point Site. Maryland Power Plant Siting
Program, PPSE 4-2, Volume 3. July 1975.

(2) J.W. Wilson & Associates, Inc., Projected Electric Power Demands for the
Baltimore Gas & Electric Company, Maryland Power Plant Siting
Program, PPES-1. 1979.

(3) J.W. Wilson & Associates, Inc. Projected Electric Power Demands for the
Allegheny Power System. Maryland Power Plant Siting Program, PPES-2.
January 1980.

(4) J.W. Wilson & Associates, Inc., An Econometric Forecast of Electric
Energy and Peak Demand on the Delmarva Peninsula. Maryland Power
Plant Siting Program, PPES-3. March 1980.

(5) Maryland Department of State Planning, Population and Emplovment,
1975-1990. May 1978 Revisions.

6) Kahal, Matthew I., Additional Direct Testimony of Matthew I. Kahal on
behalf of the Maryland Power Plant Siting Program. November 12, 1981.

(7) Maryland Power Plant Siting Program, Ten Year Forecast of Energy and Peak
Demand for Maryland Electric Utilities1 1981-1990. Maryland Department
of Natural Resources (in conjunction with the Maryland Department of
State Planning). November 1980.

(8) Kahal, Matthew I. (Exeter Associates, Inc.). Memorandum to Howard A.
Mueller (PPSP). July 15, 1981.

A-23

5
I
I
I
I
I APPENDIX B
I

STATUS OF POWER PLANTS UNDER THERMAL
I DISCHARGE REGULATIONS
I
I
I
I
I
I
I
I
I
I B-1
I

APPENDIX B

STATUS OF POWER PLANTS UNDER THERMAL DISCHARGE REGULATIONS

Mixing Zone Spawning and Nursery
Plant Criteria Area of Consequence Status

Calvert Cliffs Passes PFSP recommends passage Approved 12/81

Chalk Point Fails Under review Draft impact report submitted by BG&E;
undergoing review

Crane Fails Under review Draft impact report submitted by BG&E;
undergoing review

PPSP recommends passage
Dickerson Fails (under some PPSP recommendation of acceptable
flow conditions) impact submitted 4/81; final hearing
scheduled 2/82

Gould Street Passes Passes PPSP recommendation submitted 10/81
to DHMH, awaiting EPA/OEP review

Morgantown Passes PPSP recommends passage Approved 8/81

R.P. Smith Fails (under some PPSP recommends passage PPSP recommendation submitted 5/81
flow conditions) to DHMH; awaiting hearing schedule

Wagner Fails Under review Awaiting action for further studies

M, M M N

THE 1982 TEN YEAR PLAN

MARYLAND ELECTRIC UTILITIES

PROPOSED AND PLANNED NEW POWER PLANTS

1982 THROUGH 1991

Prepared For:

POWER PLANT SITING PROGRAM
DEPARTMENT OF NATURAL RESOURCES

BY:

ENG MG DIVISION
PUBLIC SERVICE COMMISSION OF MARYLAND
AMERICAN BUILDING
231 E. BALTD40RE STREET
BALTIMOREq MARYLAND 21202

NOVEMBER, 1981

TABLE OF CONTENTS

PAGE NO.

I. INTRODUCTION 3

II. UTILITIES IDENTIFIED 4

111. 1982 TEN-YEAR SITING PLANS9 BY COMPANY 5
1. Baltimore Gas and Electric Company 5
2. Conowingo Power Company 7
3. Delmarva Power and Light Company 7
4. Easton Utilities Commission 9
5. The Potomac Edison Company 9
6. Potomac Electric Power Company 10
7. Southern Maryland Electric Cooperative, Inc. 10

IV. PROJECTED GROWTH IN PEAK DEMAND IN MARYLAND 11

V. ASSOCIATED TRANSMISSION LINES 13

VI. POWER PLANT SITING PROGRAM PROJECTIONS OF UTILITY PEAK DEMAND 14

VII. Fu R INQUIRY 15
or
ATTACHMENT NOS. 1 - Section 54B(b), Article 78 of the Annotated 16
Code of Maryland
2 - Retail Electric Companies Operating in Maryland 17
3 - Projected Peak Load, Capacity and Reserve 18
Estimates, Baltimore Gas and Electric Company
4 - Projected Peak Load, Capacity and Reserve 19
Estimates, Potomac Electric Power Company
5 - Projected Peak Load, Capacity and Reserve 20
Estimates, The Potomac Edison Company
6 - Projected Peak Load, Capacity and Reserve 21
Estimates, Delmarva Power and Light Company
7 - Projected Peak Load, Southern Maryland Electric 22
Cooperative, Inc.
8 - Projected Peak Loads, Conowingo, Power Company, 23
Easton Utilities Commission and Thurmont
Municipal Light Company
9 - Comparison of Projected Average Annual Compound 24
Growth Rates in Peak Demand For Electricity
10 - Projected Annual Growth Rates in Peak Demand 25
By Utilities and In State, 1982-1991 Period
11 - Power Plant Siting Program Projections of 26
utility Peak Demand, 1982-1992 Period

-2-

I. INTRODUCTION

This Report constitutes the 1982 Ten-Year Plan of the Public

Service Commission of Maryland (referred herein as the Commission)

regarding those planned and proposed sites, including associated

transmission routes, of new electric power plants within the State

of Maryland. This report is prepared in compliance with Section 54B(b)
of Article 78 of the Annotated Code of Maryland. (See Attachment No. 1)

The plans herein are based upon the long-range plans submitted annually

by the individual electric utilities, with supporting analyses and

information by the Engineering Division of the Commission.

Although the primary thrust of this Report is on new generating

plants planned for Just the State of Maryland, it should be recognized

that three of the four major electric utilities operating in the State

are multi-jurisdictional. Planning by these utilities is on a system-

wide basis to provide generation capacity to meet the needs of their

entire service area.

For this reason, this Report also provides data on projected

system demands and new generation planned outside Maryland. Unit

retirements are not listed although they are available in the individual

utility plans.

II. UTILITIES IDENTIFIEM
or

The 14 retail electric companies presently operating in

Maryland and subject to the jurisdiction of the Commission are listed

in Attachment Wo. 2. according to type of ownership: investor-owned,
mmicipally-owned, and customer-owned (i.e., cooperatives).

In addition, 2 non-retail electric companies own generation

property in Maryland. They are:

1. Pennsylvania Electric Company owns a hydro-electric

plant on the Youghiogheny River, Garrett County

(Deep Creek Lake Reservoir) and an associated

transmission line into Pennsylvania.

2. Susquehanna Power Company, a wholly-owned subsidiary

of Philadelphia Electric Company, owns the Conowingo

hydro-electric plant on the Susquehanna River, Harford

and Cecil Counties, and an associated transmission

line. Operation of this plant is by the Susquehanna

Electric Company under a long-term lease with

Susquehanna Power Company.

Of these 14 companies, only the 7 utilities listed below have

future power plant siting interests in Maryland:

Baltimore Gas and Electric Company
Conowingo Power Company
Delmiarva Power and Light Company
Easton Utilities Commission
The Potomac Edison Company
Potomac Electric Power Company
Southern Maryland Electric Cooperative, Inc.

Of these 7 companies, 2 companies, Conowingo Power Company and Southern

Maryland Electric Cooperative, own no generation plant at the present

time. Some of the other Maryland utilities may have partial interests

in generating plants outside the State.

-4-

111. 1982 TEN-YEAR SITING PLANS, BY COMPANY

General These Plans reported herein reflect continued uncertainties

by the electric utility industry in the demand for electricity, and in

the amount and type of generation capacity required to reliably meet

that demand. During the past 7 years, a number of events have occurred

which have had and are having a significant influence on peak demand,,

such aa the economic recession of 1974-75, the continued high rate of

inflation, the escalating costs of all forms of energy, increased

awareness for the need for energy conservation, and spiraling costs

of new generation plant. Clouding the nuclear option has been the

recent accident at Three Mile Island.

The estimates of peak demand contained herein have been

provided by the individual utilities. It is anticipated that a review

of the methodologies used will be undertaken at a later date.

A discussion of the individual company plans is provided below.

1. Baltimore Gas and Electric Company

In 1973,' the Company was granted approval by the Commission

to begin construction of two 620-MW coal-fueled steam units at Brandon

Shores, near Hawkins Point, Anne Arandel County. Unit One is scheduled

to begin operational service in May, 1984. The second unit will become

operational in January, 1988. These same operational dates were reported

in last year's Plans.

Additional generation capacity is being planned as an extension

to the Safe Harbor Water Power Corporation hydro-electric plant in

Pennsylvania. This plant has a present capacity of 228-MW. It is located

on the Susquehanna River, Lancaster County, Pennsylvania, approximately 20

miles upstream from the Pennsylvania-Maryland border.

-5-

The Safe Harbor Water Power Corporation is wholly owned by the

Baltimore Gas and Electric Company and the Pennsylvania Power and Light

Company. The entitlement to the present plant's capacity and energy is.*
Baltimore Gas and Electric Company 152-MW (66.67%)
Pennsylvania Power and Light Company 76-MW (33.3 )
TOTAL 08-MW(100.00%)

The expansion already approved by the Federal Energy Regulatory
Commission will consist of 4 additional turbine units, each of 37.5-Mwt PF

for a total added capacity of 150-NW. Of this, Baltimore Gas and Electric

Company will receive lOO-MW.
Approval of a fifth turbine unit (37.5-mw) by the Federal Energy

Regulatory Commission is being awaited, pending completion of minitmim

flow studies of the Susquehanna River.

This approved expansion, as well as the fifth new unit, will

have an in-service date of Fall, 1985. Construction is scheduled to start

in the Fall of 1982. Baltimore Gas and Electric Company will not require

any reinforcements of the existing transmission line from this plant.

Projects which will go on-line in the years following the

1982-1991 decade require planning, site work, regulatory approval and

licensing within this ten-year period. The Company is considering new

generation subsequent to 1991 to include the construction of a large

fossil-fteled unit at its Perryman site in Harford County, Maryland.

It would become operational in the early to mid-19901s. The technology

choice, including the kind of fuel and unit size,, are currently under

study. There may be joint ownership with a neighboring utility.

Also being studied for the mid to late 1990's is a hydro

pumped storage plant. Studies by the Company have shown this technology

to be an attractive way to generate power during times of peak demand.

The Company is looking for another utility for joint participation. There

is no indication as to its location.

-6-

2. Conowingo Power Company

The Conowingo Power Company is a wholly-owned subsidiary

of The Philadelphia Electric Company. Conowingo Power Company is operated

as an integral part of the Philadelphia Electric system, and so enjoys

the benefits of being part of the larger system and of the PJM Inter-

connection, of which Philadelphia Electric is a member.

Almost all of the Philadelphia Electric system generation

plant is located in Pennsylvania. The Conowingo hydro-electric plant on

the Susquehanna River in Maryland has 474-MW installed capacity. It

represents about 7% of the Philadelphia Electric's total installed capacity.

Philadelphia Electric Company owns two sites in Maryland

for future power plant development. The 680 acre Canal site is located

on the Chesapeake and Delaware Canal approximately one mile west of the

town of Chesapeake City, Cecil County, Maryland.

The other site, known as Seneca Point, contains approximately

560 acres which Philadelphia Electric Company owns for future power plant

development. it is located on the west bank of the Northeast River,

approximately one mile southwest of Charlestown, Cecil County, Maryland.

There are no plans for Philadelphia Electric Company to

start construction on either of the above sites within the next ten years.

3. Delmarva Power and Light Company

In April, 1978, Delmarva filed an Application with the

Commission for the construction of a new 400-MW coal-fired steam generation

unit as an extension to its existing generation plant at Vienna, Dorchester

County, Maryland. By a letter to the Commission in July, 1979, Delmarva

modified its original Application to increase the size of the unit to

500-600-MW nominal. Its exact size will depend on ultimate ownership

and each owner's degree of participation.

-7-

Delmarva anticipates shared ownership of this unit,

known as Vienna #9, as follows:
Delmary '2'-MW 15%
Atlantic City Electric Co. 125-MW 2-,,,.
Old Dominion Electric Co. 50-MW 1
Total 350-MW I

Delmarva will be responsible for the licensingg construction and operation

of this unit. It is expected to be operational in 1990. Actual construction

start is presently planned for 1986.

No new transmission lines associated with this new unit

will be required. However, several existing bulk power lines will be

upgraded to 230-KV operation.

The Commission's Hearing Examiners Division issued a

Proposed Order granting a Certificate of Public Convenience and Necessity

to Delmarva for the construction of this unit on October 30, 1981.

Additional details concerning this unit will be found in Commission

Case No. 7222 which dockets this proceeding.

Two sites on the eastern shore, identified and evaluated

by the Maryland Power Plant Siting Program in a recent study* appear

suitable for use by Delmarva as possible sites. The Church Creek site,

in Dorchester County, is just east of Church Creek and approximately

5 miles southwest of Cambridge along Maryland Route 16. The Deep Branch

site is in southwestern Wicomico County about 3 miles west of the

Nanticoke River at the Bivalve communi ty, and north of the Wicomico

River at its junction with Wicomico Creek.

Eastern Shore Power Plant Siting Study,
Vol. 2, Maryland Major Facilities Studies,
October, 1977 PPSA-4

-8-
W
65%
206
1
1

4. Easton Utilities Commission

In 1975, the Public Service Commission granted Easton

Utilities Commission a Certificate of Public Convenience and Necessity

for the construction of a new generating plant, to be known as Plant

#2. This plant is located on a Town-owned 7 acre site within the city

limits of Easton. The first two units of this Plant, having a total

capacity of 12.5-MW, are in commercial operation.

Additional generation of 12.5-MW is planned for Plant

#2 with commercial start-up in 1990. Prime mover of all units will

be diesel engines, fueled by either No. 2 fuel oil or natural gas.

5. The Potomac Edison Company

The Potomac Edison Company is one of three operating

subsidiaries of the Allegheny Power System. Potomac Edison together

with its sister utilities Monongahela Power Company and West Penn Power

Company are operated as one integrated facility. Most of the generation

facilities of the Allegheny Power System are in Pennsylvania and West

Virginia.

The Potomac Edison Company owns one site in Maryland for possible

future power generation. This site, containing 829 acres, is approximately

2 miles downstream from the town of Point of Rocks, Prederick County,

Maryland on the north side of the Potomac River. This site is one of

several sites which are being evaluated for a coal-fired station with

an in-service date in the mid-199019.

Several other potential power generating sites in Maryland

have been identified in an Allegheny Power System Siting study. A list

of favorable candidate areas has been given to the Power Plant Siting

Program which is currently performing a Western Maryland Power Plant

Siting study. The site selected would be coal-fired with an initial

-9-

in-service date in the mid-199019.

In October, 1980, the Virginia Electric and Power Company

signed an $800 million preliminary agreement to share its 20100-MW

pumped storage hydro-electric facility in Bath County, Virginia with the

Allegheny Power System. Expected APS participation in this facility may

be as much as 50% through either outright purchase or lease. Scheduled

for completion in 1985, this facility is the largest pumped hydro, plant

ever built in the United States. The Potomac Edison Company's entitlement

would be 280-MW. This matter is currently in proceedings before the

Commission and before the Pennsylvania Public Utilities Commission.

6. Potomae Electric Power Company

Potomac Electric Power Company expects its 600-MW Chalk

Point Unit #4 to begin commercial service in 1982, the same date

identified in last year's Plan.

Plans by the Company show a possible 300-MW coal-fired

unit for construction at its Dickerson site. In-service date has been

tentatively identified as 1993. Preliminary engineering site studies,

etc. were begun in 1981 with start-up as early as 1990, if needed.

The Company's Ten-Year Plan lists a possible 2,,OOO-MW

pumped-storage hydro-electric plant at an undetermined site in Maryland.

The plant would likely be a joint venture with one or more other utilities.

The in-service date is not specified.

7. Southern Maryland Electric Cooperative, Inc.

The Cooperative owns a 300 acre site on the Patuxent River,

St. Mary's County. This site, known as the De La Brooke Farm, is considered

for possible future generation. However, no plans have been made for such

use.

_10-

IV. PROJECTED GROWTH IN PEAK DEMAND IN MARYLAND

The peak demand for electricity in Maryland as projected by

the major utilities is listed on a yearly basis for the next decade on

Attachments No. 3 through No. 6. Also shown on these Attachments are

peak demands, system-wise, for the three multi-jurisdictional utilities.

Total installed capacity reflecting both the additions of new or up-

graded plant and retirements of older units is also indicated.

Data on the smaller utilities, Southern Maryland Electric

Cooperative, Conowingo Power Company, Easton Utilities Commission and

Thurmont Municipal are shown on Attachments NO. 7 and No. 8.

A summ ry of the average annual growth rates in peak demand

by utility is provided by Attachment No. 9. Corresponding data for the

1980 and 1981 Ten-Year Plans are also shown. Attachment No. 10 is a

bar chart of the peak demand growth rates.

Several observations concerning the data of Attachment No. 9

are noteworthy:

1. Baltimore Gas and Electric Company, the largest utility

in Maryland, has revised downward the growth in peak

demand to 2.7%. Last year it projected a 3.0% growth

per year.

2. At the low end of the range of growth rates is Potomac

Electric Power Company. This utility is now estimating

an average growth of 1% per year in Maryland, somewhat

more (1. 2%) system-wise.

3. The Potomac Edison Company, the only major winter-peaking

utility in the state, is estimating that its Maryland

customers will be requiring a 2.6@vo increase in peak demand,

-il-

off sharply from its figure of 4.3% in its last year's Pr
Ten-Year Plan.

4. Delmarva Power and Light Company, also, for Maryland, has

revised its projected demand significantly downward,,

from 3-W per year in the 1981 Plan to 2.296 this year.

5. For the entire State, the peak demand estimate has

dropped from 2.8% per year last year to this year's

figure of 2.3%. As a matter of interest,, a growth

rate of 2.3% per year corresponds to a doubling in demand

in 30 years, that is by the year 2011.

-12-

V. ASSOCIATED TRANSMISSION LINES

The transmission lines associated with the construction of

new generating stations will generally operate at 115-KV and higher

voltages. They will require rights-of-way widths of 150 to 300 feet.

An "associated transmission line", with respect to Section 54B of

Article 78, refers to the means of transporting electric power from

a power plant to one or more points on an existing transmission system.

Such lines are often called "generation leads". There are also

"transmission lines". with respect to Section 54A of Article 78, which

are not "generation leads" but rather they provide substation-to-sub-

station bulk power transmission for increased capacity or reliability

purposes. In any of these instances, the long-range need and probable

capacity of a future transmission line can be determined from extensive

system studies. However, the actual route and often the actual terminal

location(s) of a line can be established only after subsequent years of

planning and surveys.

Lines planned for possible construction at later dates and

in particular the "associated transmission lines" for new power plants

cannot be defined as to specific siting. However, general planning

information regarding terminal points,, voltage levels and dates to

the extent possible is contained in the individual plans submitted by

the major companies.

-13-

VI. POWER PLANT SITING PROGRAM PROJECTIONS
OF UTILITY PEAK DEM M

The Power Plant Siting Program of the Department of Natural

Resources has prepared its own forecasts of annual peak demand for

the four major utilities in Maryland out through 1992.

These projections, forwarded to the Public Service Commission

in a letter dated November 20, 1981, are listed in Attachment No. 11.

Additional details concerning the methodologies and assumptions used

as a basis for these data may be obtained from Dr. Howard Mueller of

the Power Plant Siting Program.

-14-

VII. FURTHER INQUIRY

In the event further inquiry is indicated, such as by

other state agencies, the request should be directed to the Commission

by writing to Mrs. Gloria Jimenez, Executive Director. Specific

information requests of an engineering nature and comments on this

Plan should be directed to Mr. John W. Dorsey, Chief Engineer, or to

its author, Mr. Richard M. Hollis, Senior Engineer.

ATTACHM9NT NO. 1

SECTION 54B(b), ARTICIE 78 OF THE
ANNOTATED CODE OF MARYLAND

54B. Consolidated public hearingg long-range plans and
establishing an environmental surcharge on
generated electric energy; notice to landowners
over whose property company intends to run
line, etc.; purchase of power plant site by State.

(b) In cooperation with the Secretary of Natural Resources
as set forth in 03-304 of the Natural Resources Article of the
Code, the Commission shall be responsible for assembling and
evaluating annually the long-range plans of Maryland's public
electric utilities regarding generating needs and means for
meeting those needs. The chairman of the Public Service
Commission shall, on an annual basis, forward to the Secretary
of Natural Resources a ten-year (10) plan listing possible
and proposed sites, including associated transmission routes,
for the construction of electric power plants within the State
of Maryland. Sites which are identified as unsuitable by the
Secretary of Natural Resources in accordance with the requirements
of 83-304 of the Natural Resources Article of the Code shall be
deleted from the plan, provided, however, nothing in this sub-
section shall prevent the inclusion of such site in subsequent
ten-year (10) plans. The first ten-year (10) plan shall be
submitted on or about January 1, 1972.11

ATTACHMENT NO. 2

RETAIL ELECTRIC COMPANIES OPERATING IN MARYLAND

NAME ADDRESS TELEPHONE NO.

Investor-Owned

Baltimore Gas and Electric Gas and Electric Building 234-5000
Company Baltimore, MD 21203

Conowingo Power Company 211 North Street 398-1400
Elkton, MD 21921

Delmarva Power and Light P. 0. Box 1739 749-6111
Company Salisbury, MD 21801

Potomac Edison Company, The Downsville Pike 731-3400
Hagerstown, MD 21740

Potomac Electric Power Company 1900 Pennsylvania Ave., N.W. (202)872-2449
Washington, D. C. 20006

Municipally-Owned

Berlin, Mayor and Council of P. 0. Box 235 641-2770
Berlin, MD 21811

Easton Utilities Commission, 11 S. Harrison Street 822-61io
The Easton, MD 21601

Hagerstown Municipal Electric Hagerstown, MD 21740 731-26oo
Light Plant

Thurmont Municipal Light Co. P. 0. Box 385 271-7313
Thurmont, MD 21788

Williamsport, Mayor and Williamsport, MD 21795 223-7711
Council of

Customer-Owned

A and N Electric Cooperative Parksley, Virginia 23421 (804)665-5116

Choptank Electric Cooperative, P. 0. Box 430 479-0380
Inc. Denton, MD 21629

Somerset Rural Electric P. 0. Box 270 (814)445-4106
Coop., Inc. Industrial Park
Somerset, Pennsylvania 15501

Southern Maryland Electric Hughesville, MD 20637 274-3111
Coop., Inc.

-17-

ATTACHMENT NO. 3

PROJECTED PEAK LOAD, CAPACITY, AND RESERVE ESTIMATES

BALTIMORE GAS AND ELECTRIC CC14PANY

PROJECTED CONTRACT TOTAL INSTALLED INSTALLED RESERVE
YEAR LOAD NO CAPACITY, (MW) MARGIN (PERCENT)

1982 4130 5025 21.7
1983 4260 5025 18.0
1984 4390 5634 28.3
1985 4530 5634 24.4
1986 4640 570 24.1
1987 4740 5701 20.3
1988 4870 6321 29.8
1989 5000 6321 26.4
1990 5130 6321 23.2
1991 5260 6321 20.2

Average Annual Compound Growth, Percent,, 2.7 in Peak Load

Contract load represents the total demand on the Company including only that
part to Bethlehem Steel which cannot be supplied by the Bethlehem generating
capacity itself. The Company also reports a Group Load which represents the
total electrical requirements of the Company and of Bethlehem Steel.

ATTACHMENT NO. 4

PROJECTED PEAK LOAD, CAPACITY, AND RESERVE ESTIMATES

POTOMAC ELECTRIC POWER COMPANY

SYSTEM MARYLAND COMPONENT
PROJECTED PEAK LOAD TOTAL INSTALLED INSTALLED RESERVE PROJECTED PEAK DEMAND
YEAR (14W) CAPACITY (MW) MARGIN (PERCENT) NW)

1981 3912 4999 27.8 2152
1982 3956 4996 26.3 2167
1983 4000 5322 33.0 2182
1984 4058 5322 31.1 2214
1985 4105 5322 29.6 2235
1986 4153 5322 28.1 2254
1987 4208 5322 26.5 228o
1988 4259 5322 25.0 2309
1989 4302 5322 23.7 2326
19go 4355 5148 18.2 2344
1991 Not Available (N.A.) N.A. N.A. N.A.
Average Annual Compound
Growth,, Percent 1.2 1.0
(1981-1990 Period)

These data include Southern Maryland Electric Cooperative projected peak demand.

** PEPCO estimates for 1991 were not available at the time this report was prepared.
It is anticipated that approved figures through 1991 will be made available in early 1982,
and distribution of revised figures made at that time to recipients of the Commission's
1982 Plan.

-19-

ATTACHMENT No. 5

PROJECTED PEAK LOAD, CAPACITY AND RESERVE ESTIMATES

THE POTOMAC EDISON COMPANY

SYSTE14 MARYLAND COMPONENT
INSTALLED INSTALLED RESERVE
YEAR P EAK LOAD CAPACITY MARGIN P M LOAD
WINTER OF NO NO (Percent) (mw)---

1982/83 1585 1882 18.7 1024
1983/84 1630 1882 15.5 1046
1984/85 1694 1882 11.1 1081
1985/86 1741 1999 14.8 1116
1986/87 1822 2117 16.2 1147
1987/88 1881 2117 12.5 1174
1988/89 1932 2117 9.6 1199
1989/90 1968 2281 15.9 1226
1990/91 2050 2242 9.4 126o
1991/92 2113 2405 13.8 1295

Average Annual 3.2 2.6
Compound Growth, Percent in Peak Loads

-20-

ATTACHMENT No. 6

PROJECTED PEAK LOAD, CAPACITY AND RESERVE ESTIMATES

DELMARVA POWER AND LIGHT COMPANY

SYSTEM MARYLAND COMPONENT
PROJECTED TOTAL INSTALI PROJECTED
PEAK LOAD INSTALLED CAPACITY RESERVE MARTO PEAK DEMAND
YEAR NO (W (PERCENT) (W

1982 1,627 2,324 42.8 452
1983 1,667 2,167 30.0 457
1984 1,711 2,167 26.6 467
1985 1,767 2,217 25.5 480
1986 1,808 2t217 22.6 490
1987 1,818 2,177 19.7 503
1988 19870 29,177 16.4 516
1989 11919 29177 13.4 528
1990 1,918* 2,460 28.3 517**
1991 1.964@ 2,56o 29.7 528 **

Average Annual 2-4 2.2
Compound Growth (Percent), 1982-1989 Period in Peak Loads

These figures reflect a 50-MW reduction in peak REA Cooperative load due to the
proposed assumption of responsibility as a result of participation in Vienna #9
by Old Dominion.
These figures reflect a 22-MW reduction in the peak load of the Maryland Component
due to participation by Old Dominion in Vienna #9, (*) above.

-21-

ATTACHMENT NO. 7

PROJECTED PEAK LOAD

SOUTHEM MARYLAND ELECTRIC COOPERATIVE. INC.

YEAR PEAK LOAD

1982 282
1983 300
1984 316
1985 333
1986 348
1987 366 Ar
1988 383
1.989 398
1990 414
1991 428

Average Annual Compound Growth, Percent 4.7

-22-

ATTACHMENT NO. 8

PROJECTED PEAK LOADS

CONOWINGO POWER COMPA19Y
EASTON UTILITIES CMUSSION
THURKONT MUNICIPAL LIGHT COMPANY

PEAK LOAD (MW)
YEAR CONOWINGO EASTON THURKONT

1982 95 26.3 7.5
1983 97 27.1 7.9
1984 100 28.0 8-3
1985 102 28.9 8.7
1986 105 29.8 9.1
1987 107 30.7 9.5
1988 110 31.7 9.9
1989 113 32.7 10.3
1990 116 33.7 10.7
1991 119 34.8 11.1

Average Annual Compound Growth, Percent
2.5 3.2 4.5

-23-

ATTACHMENT NO. 9

COMPARISON OF PROJECTED AVERAGE ANNUAL
COMPOUND GROWTH RATES IN PM DEMAND FOR ELECTRICITY
(PERCENT PM YEAR)

1980 PLO 1981 PLAN 1982 PLO
(1980-1989) (1981-19901 (1982-19911

Baltimore Metro
Baltimore Gas and Electric Company 3.5 3.0 2.7

Washington Metro
Potomac Electric Power Company
(Maryland Only) N/A 1.2 1.0
(System) 1.9 1.2 1.2

Western Maryland
Potomac Edison Company
(Maryland Only) 4.4 4.3 2.6**
(System) N/A 4.8 3.2

Southern Maryland
Southern Maryland Electric Coop., Inc. 4.0 4.8 4.7

Eastern Shore
Conowingo Power Company 4.0 3.0 2.5
Delmarva Power and Light Company
(Maryland Only) 4.1 3.8 2.2*
(System) R /A 2.4 2.4
Easton Utilities Commission 5.4 5.5 3.2

Entire State 3.0 2.8 2.3

*Average Over 1982-1989 Time Period
**Average Over 1981-1990 Time Period

-24-

nirn @V^
L IN
]PROMTED A", @@AL GROWTH RATES 'IN
D94A NDL BY VTII ITIES AND IIN STATE
1W2
=W1 PERIOD

Dolted lines pre sent Projectioms In TAst Year a Reip ort

T :77.
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It
I i i

J I _1 1 1 1 i i

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th

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ATTACHMENT NO. 11

POWER PLANT SITING PROGRAM PROJECTIONS
OF
UTILITY na Dmmzs 1982-1992 PMOD
(14W)

POTOMAC EDISON DELMARVA P. & L. PEPCO BG & E
YM TOTAL SYSTEM M. ONLY TOTAL SYSTEM MD. ONLY TOTAL SYSTEM

1982 19544 988 1,619 454 4,284 49028
1983 1,600 1,024 1,671 468 4,322 4,162
1984 1,657 1,061 1,728 485 4,358 4,303
1985 1,717 1,099 1,790 503 4,393 4,447
1986 19775 19136 19844 518 49420 49591
1987 19834 19174 19902 535 49453 49741
1988 1,895 1,213 19963 553 49486 4,897
1989 1,958 1,253 29,027 572 4,520 5091
1990 2,023 1,295 2,094 592 49554 59232
1991 2,088 19337 2,16o 612 4,580 59372
1992 Not Not 2,229 634 4,623 5,513
Available Available

Average Annual 3.4 3.4 3.2 3.4 o.8 3.2
Compound Growth Rate (Percent)

*Potomac Edison is a winter peaking utility. The peak indicated for, say 1982, is that
projected for the winter of 1981/1982.

Data include portions of the Dover, Delaware and Easton, Maryland loads served by
Delmarva at Lle time of the annual peak.

-26-

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