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PPSP-CEIR-2 POWER PLANT CUMULATIVE ENVIRONMENTAL IMPACT REPORT r'@ 7 "ll INFORMATION C;:.i NOVEMBER 1978 M-ARYLAIND POWER PLANT SITING PROGRAM ENT OF NATURAL RESOURCES EDEPARTMENT OF HEALTH AN D TD HYVME EDEPARTMENT OF ECONOMIC AND COMMUNITY DEVELOP- 195 MPOATMENT OF STATE PLANNING 0 COMPTROLLER OF THE TREASURY ;E*VXIE COMMISSION E4 M38 1978 A, 4 JAMES B. COULTER LOUIS N PHIPPS JR. SECRETARY STATE OF MARYLAND DEPUTY'SECRET'ARY DEPARTMENT OF NATURAL RESOURCES TAWES STATE OFFICE BUILDING ANNAPOLIS 21401 269-3041 January 18, 1979 The Honorable Harry Hughes Executive Department Office of the Governor State House Annapolis, Maryland 21404 Dear Governor Hughes: The second Cumulative Environmental Impact Report prepared pursuant to the Maryland Power Plant Siting Act is forwarded. The Report colligates the results of the studies of the Power Plant Siting Program with respect to the cumulative impact of power plants on Maryland's environment. Major findings presented in the Report are as follows: Existing and proposed power plants will provide adequate electricity to Maryland over the next ten years. The entire state is in compliance with the air quality standards for two of the three pollutants emitted in significant quantities by power plants, sulfur oxides and nitrogen oxides. For the third pollutant, particulates, air quality in the general areas of Baltimore City and the Potomac River Valley near Bloomington is in violation of Federal ambient air quality standards. Studies to date have revealed no significant cumulative aquatic impacts due to power plant operation. Radio- active discharges from the Calvert Cliffs plant have remained less than 10% of the permitted limitations on emissions. Experience indicates the importance of the continued collection and analysis of environmental data, both for comprehensive site-specific field investigations of individual power plants and for cumulative assessments of all power plants operating in the State. Several specific recommendations relating to environmental policy are listed in the Report. In some respects the Federal government is more of a hindrance than a help to the State in its effort to achieve the purpose of the Power Plant Siting Act. Actions of the various federal agencies and officials are unpredictable which leads to an undependable basis for long range Federal- State coordination. Page Two The Hon. Harry Hughes January 18, 1979 For instance, a continual stream of new federal laws creates additional requirements that cause plans to be outmoded as fast as they can be developed. Policy direction governing the use of fuels is in a continual state of flux and often a policy such as that to encourage the production of coal for utilization in power plants is immediately neutralized by another set of changes such as those contained in the Clean Air Act Amendments of 1977. Another example is the vacillation of the Federal government with respect to various schemes for resolution of the nuclear waste disposal issue. The current unpredictable and undependable behavior of the Federal government points up the importance of a strong state capability to protect the environment while providing for an adequate supply of electric energy as provided for in the Power Plant Siting Act. Sincerely yours, James B. Coulter Secretary JBC:PM:pc Enclosure PPSP-CEIR-2 POWER PLANT CUMULATIVE ENVIRONMENTAL IMPACT REPORT U.S. DEPARTMENT OF COMMERCE NOAA CAOSTAL SERVICES CENTER NOVEMBER 1978 2234 SOUTH HOBSON AVENUE CHARLESTON , SC 29405-2413 Maryland Department of Natural Resources PropertY Of CSC Library 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 job of compiling and editing the Cumulative Impact Report could not have been accomplished without the help and cooperation and many people and organizations. Editorial content of the individual chapters was aided by members of the PPSP staff. I thank Dr. Steven Long for his contributions to Chapters IV and VI and Mr. Howard Mueller for his contributions to Chapters I and V. Special thanks go to Mr. Jorgen Jensen, Ms. Nadine Johansen and Ms. Lois Craig of Martin Marietta Corporation for their perseverance in review- ing and typing the many drafts of this document. I would also like to acknowledge the cooperation and aid of the follow- ing individuals and organizations: C. Cater Allegheny Power System, Inc., Greenburg, Pa. R. Kissnek 11 it J. Nicol if it E. Bauereis Baltimore Gas and Electric Company, Baltimore, Md. J. Reynolds if if J. Stout if if P. Crinigan it if A. Kampa if it R. Douglas if if R. Ash T1 it D. Kent It TV J. Tiemann to W. Thompson if M. Hinkle it M. Toskes it C. Franklin it C. Boyd it W. Bonta Bureau of Air Quality Control, Baltimore, Md. G. Ferreri 11 it N. Kelly Chesapeake Bay Foundation, Annapolis, Md. J. Cawood Chesapeake Environmental Protection Asso., Annapolis, Md. R. Bryson Conowingo Power Company, Elkton, Md. P. Scheuerman Delmarva Power and Light Co., Salisbury, Md. J. Pflieger L. Kohlenstein Johns Hopkins University, Applied Physics Laboratory J. Lentz to it I E. Portner J. Reilly J. Wilson John W. Wilson & Associates, Inc., Consultant to State Planning, Washington, D.C. M. Haire Marti n Marietta Environmental Center, Baltimore, Md. T. Polgar it it W. Richkus it W. Furth if J. Weil if D. Sturtevant Maryland Association of Counties M. Bundy Maryland Coastal Zone Administration, Annapolis, Md. P. Massicot Maryland Power Plant Siting Program, Annapolis, Md. P. Miller it It L. Zeni it it I A. Miller Maryland Dept. of State Planning, Annapolis, Md. L. Ramsey Maryland Water Resources Administration, Annapolis, Md. N. Allard Potomac Electric Power Company, Washington, D.C. D. Bailey it 11 it W. Foy L. Guiland it E. Mitchell if A. Rioux it P. Robb It D. Oliver it M. Gould it L. Gallump it G. Baines it R. Hollis Public Service Commission, Baltimore, Md. S. Stainman Regional Planning Council, Baltimore, Md. Randy A. Roig Editor iv SUMMARY Chapter I - Energy During the five years prior to 1973, Maryland electric energy peak demand grew by an annual average rate of 8.3%, and consumption grew by 8.6%. During the 1973-1975 period, those rates dropped to 0.0% and --0.3%, respectively. In the 1975-1977 period, growth in both peak demand and consumption resumed, to 5.0% and 7.4%/year. Forecasts prepared by the Power Plant Siting Program and the Maryland utilities project growth in peak demand over the next ten years to average 4.0'/./year for the utility systems serving Maryland (3.4%/year for the portion of their service territories within Maryland). The total time required for the construction of large-scale electric generating plants ranges up to 8-10 years for coal plants and up to 15 years for nuclear plants. Utilities plan for new capacity requirements ten or more years in advance. Maryland utility systems plan to add 3,024 megawatts of generating capacity by 1987 within Maryland. An additional 4,245 megawatts of capacity within Maryland is tentatively projected for the period 1987 to 1997. The projected increase in load factors will result in the addition of relatively more baseload capacity by these systems. Comparison of capacity from existing and proposed plants with demand projections for the utility systems serving Maryland indicate that adequate electric power will be available over the next ten years. Based on Power Plant Siting Program demand projections and completion of planned generation additions, utility capacity plans will result in reserve margins above 25% for most of the period, with reserve margins reaching 30% by 1980, and dropping to the 25-27% range for the remainder of the period. As a result of reported financial and licensing difficulties, the Allegheny Power System (which includes Potomac Edison) may be unable to construct two generating stations planned to come online in the years 1983-1987. Based on the utility's demand projections, this contingency could cause available capacity over those years to fall as low as 10.9% below peak demand. Chapter II - Air Impact Of the five major pollutants emitted by all sources in Maryland, power plants contribute negligible amounts of carbon monoxide and hydrocarbons, about 30% of the NO X1 32% of the particulates and 69% of the sulfur oxides. For the three main power plant pollutants (NO particulates and SO X09 the air quality is as follows: For particulates, & general areas of Baltimore City and the Potomac River valley near Bloomington are in violation of Federal Ambient Air Quality Standards. All areas are in compliance with standards for sulfur and nitrogen oxides. However, for photochemical oxidents (for which NOx is a precursor), the areas near Baltimore and Washington have been declared non-attainment areas. v Various methods of sulfur oxide emission control have been analyzed for availability and cost. Comparative costs indicate no major difference (for a new plant) between the use of flue gas desulfurization, starting with high sulfur coal, physical coal cleaning and the use of low-sulfur coal. The use of scrubbers can also generate substantial amounts of waste, (for example, 200 to ns/hour for a 1000 MW plant burning 3.5% sulfur coal using a lime scrubber). The Gaussian plume model, in view of its central role in the prediction of air quality, has been tested using measurements at Maryland power plants. The model has been found to be generally accurate to a factor of two, given flat terrain, low to moderate distance extrapolations, and moderate winds. The limitations on model accuracy in conditions other than these are discussed. The implications of the Clean Air Act Amendments of 1977 upon the siting of power plants arediscussed. Because of provisions related to the Prevention of Significant Deterioration (PSD) and non-attainment areas, the size and potential locations of new coal-fired power plants may be limited. In particular, the designation of a Class I area in or near Maryland could severely limit the potential for siting a 1000 MW coal-fired plant by creating a 40-80 mile Itexclusion" zone surrounding the area. Because of the large area of influence of coal-fired plants, the implications of PSD-related growth limitations will lead to competition for use of the available increments within the State. Similarly, the interstate nature of air pollutant transport may lead to competition and dispute between states. Chpater III - Aquatic Impact Power plants can cause aquatic impact in several ways: (1) by entraining fish eggs, larvae or prey organisms into a cooling system where they are subjected to thermal, mechanical and chemical stresses; (2) by impinging adult and juvenile fish and crabs on intake screens; and (3) by discharging heat and chemicals into receiving waters. Cumulative impact has been examined by salinity/habitat zone. Dividing the aquatic habitat into three general areas, we can draw the following conclusions: Mesohaline (5-19 ppt) Because of the high reproduction rates of the plankton and good tidal mixing at existing plants, depletion of plankton populations has not occurred. 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 sources. In addition, efforts to reduce these totals are now underway at all three existing plants, Calvert Clirts, Morgantown, and Chalk Point. 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. vi Tidal Fresh/Oligohaline (0-5 ppt) The major area of concern within this 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. New facilities planned for this region (Douglas Point, Summit and Vienna) would increase withdrawals. The overall impact upon striped bass due to entrainment drops from an estimated 6.6 percent entrainment (upper bound) of the eggs and larvae spawned in the Maryland portion of the Bay at present to an estimated 3.4 percent (upper bound) after 1987. The addition of Douglas Point and Summit is more than off-set by the retirements of the once- through cooling units at Vienna. No impingement data is available at any of the present plants; however, degraded water quality at the Baltimore and Washington plants appears to have severely restricted fish populations in these waters. Similarly, habitat modification effects or depletion of plankton would be difficult to detect. Ongoing studies should help to quantify these effects at the existing Maryland plants. The proposed plants are expected to have no major impacts in the areas of impingement or habitat modification due to the small amount of water withdrawn. Riverine No impact is expected from entrainment and impingement. Studies of possible habitat modification due to the discharge of heated effluent are now underway at both of the existing plants in this region. These studies are expected to be completed during 1979. Chapter IV - Radiological Effects The Calvert Cliffs Nuclear Power Plant, owned by Baltimore Gas and Electric Company, is the only operating nuclear power plant in Maryland. No other nuclear generating stations are scheduled to begin operations within the next ten years. Spent reactor fuel is accumulating at Calvert Cliffs because the Federal government has halted commercial reprocessing, and has not yet developed its own plans for taking over the job of disposal. By the end of 1978, there will be a total of 216 spent fuel assemblies stored at the plant. BG&E has received permission from the Nuclear Regulatory Commission to expand the capacity of their spent fuel storage pool to 1056 assemblies. This will provide sufficient storage to continue plant operations through 1984, by which time it is hoped that the Federal government can begin accepting spent fuel from commercial reactors. Discharges of radioactivity from the power plant have been small fractions of the quantities and concentrations allowed, never reaching 10% of any of the various limitations imposed by the Operating License. Environmental monitor ing in the vicinity of the plant has shown the radiation dose to the public from plant operation to be quite small. Calculations from the reported release rates yield 0.2 mrem whole body dose and 0.6 mrem skin dose for the calendar quarter of maximum release. Vii Radioactivity discharges to the Chesapeake Bay have resulted in detectable concentrations of Ag-110m, Co-58 , and Co-60 in sediments and shellfish. The area yielding samples with detectable concentrations of plant effluents extends for roughly six miles up and down the western shore, with maximum values found at the plant discharge area. The radiation dose to an individual eating 29 dozen oysters and 15 dozen crabs (5 kg of each) taken from the plant discharge area would be about 4/1000 mrem whole body dose and 0.2 mrem gastrointestinal tract dose (about 0.007% and 0.5% of the applicable guidelines, respectively.) Comparison of these power plant-induced doses with the fluctuations in natural radiation dose already experienced by the public indicates that the power plant effects are insignificant. For instance, detected variations in the natural radioactivity of the soils from place to place in Calvert County can create differences in annual radiation dose of 30 mrem, and different construction materials have been shown to cause changes of 14 mrem/year in the interior dose rates of buildings. These natural variations are tens of times greater than the maximum doses resulting from Calvert Cliffs Power Plant. Although operations to date provide an insufficient basis to predict radiological impact of the Calvert Cliffs Plant over its operational lifetime, available data indicate that the plant should continue to operate with insig- nificant radiological impact, well within all applicable guidelines. Chapter V - Socio-Economic Impacts The construction of an electric generating station may have socio-economic effects upon the community in which it is located. Among the possible effects during construction are changes in population leading to strains in housing, schools, employment, transportation, and increased demands on local government services. The scale of the effects vary accoTding to the population base of the county in which the plant is located and the distance of the site from major metropolitan areas. Increased demands for county and municipal public services also varies during the construction period. In some instances the increased cost of public services can result in large budget deficits at both the county and municipal level as construction period revenue increases fail to keep pace with service costs. In the study case of potential Eastern Shore power plant sites, annual municipal budget deficits were estimated to range from 3% to 21% for nuclear plant construction. The same study projected the largest county deficit at 4%, with other counties experiencing revenues and expenditures which were essentially in balance. After a new plant starts operation, the tax revenues to county governments are on the order of several million dollars per year or greater depending on plant size and local tax rates, and the service costs are small. Chapter VI - Other Impacts Cooling towers can be an environmentally-acceptable alternative to once- through cooling. Basically, a cooling tower exchanges consumptive water use and possible terrestrial effects for effects in the aquatic environment. There also is a loss in energy production. Because the balance of these effects is site-specific, each plant location should be examined to determine the appropriate cooling system. viii Studies at Chalk Point indicate that salt deposition from the natural draft cooling tower would not exceed 8 kg/ha/month (7 lb/acre/month) at the maximum point. Experiments to determine the sensitivity of corn, soybeans, or tobacco indicated that no significant effects occurred at deposition rates below 20 kg/ ha/month (18 lb/acre/month). The routing of transmission lines deals with effects that may have aesthetic, ecological, health and physical implications. The aesthetic effects generally include trade-offs between visibility and enviromnental protection. Ecological effects can be both positive and negative and must be evaluated on a case-by-case basis. The electrical effects are now well understood and are potentially significant only for locations within, or extremely close to the right of way. The health effects remain an area of controversy, mainly due to differing medical results from U.S. and Soviet studies. Although the withdrawal of groundwater is relatively high at power plants compared to most other industrial sources, due to the relatively sparse usage of the deep aquifers they have tapped and the large area occupied by the power plant sites, there has been no significant impact upon present wells near these plants. However, if a major increase in withdrawals from the Magothy aquifer were to occur in the neighborhood of Chalk Point, there could be significant impact upon users of the Magothy aquifer in that area. ix RECOMMENDATIONS 1. It is recommended that the present requirement in law for a 10-year plan from each electric utility be extended to 15 years. Present trends indicate that 8-10 years are requ'ired to locate, license, and construct a fossil- fueled plant and 10-15 years are required for a nuclear plant. 2. Although studies to date indicate that there have been no significant cumu- lative impacts on the aquatic environment due to power plants, studies of long duration are needed to validate that initial conclugion. Cumulative impact assessment by salinity habitat zone should continue for.th,e purpose of finding any cumulative impact thresholds that might impose limits on the siting,*design or operation of future power plants. 3. Issues arising under the Federal Clean Air Act Amendments will seriously impact the State's ability to carry out orderly planning for the siting and construction of new fossil-fueled.power plants. These issues include the allocation of "Prevention of Significant Deterioration" (PSD) increments among all emitting facilities, the requirement for emissions offsets for new sources locating in or near non-attainment areas; and the interstate nature of air pollutant transport and resulting regulatory issues. Since all ,emitting facilitie's are affected, not just power plants, the resolution of these issues must be achieved on a comprehensive basis. As initial steps the following actions are'recommended: a. A policy board should be convened to devise alternative strategies for allocating PSD increments among new sources. This board would be composed of representatives of the Depart- ments of Economic and Community Development, Health and Mental Hygiene, State Planning, and Natural Resources. b. An of f set bank exchange center should be established that would facilitate the purchase of emissions offsets for. new sources wishing to locate near non-attainment areas or near areas where the PSD increment has been fully utilized. c. The State should pursue the creation of a multistate planning council, for example, through the National Governor's Association,.whose purpose will be to: (i) provide a clearing house for information on all sources likely to contribute significantly to pollution levels across State boundaries as well as regulatory actions related to those sources. xi (ii) provide a forum for the resolution of disputes between states on consumption of PSD increments by interstate transport of pollutants. 4. Current State law prohibits storage of spent fuel in Maryland for longer than two years. As amended during the 1978 General Assembly Session, this effectively prohibits storage of spent fuel at Calvert Cliffs beyond January, 1980. In view of the lack of facilities to accept.this spent fuel anywhere in the nation, legislation to resolve this dilemma must be considered. Since the findings of Chapter 4 indicate no environmental impact from the additional storage, it is recommended that legislation to*allow continued storage at Calvert Cliffs be enacted during the 1979 session pending action of the Federal government to provide permanent storage. 5. Although available data indicate that the Calvert Cliffs plant should be able to continue to operate with insignificant radiological impact, operations to date provide an insufficient basis to predict radiological impact of the plant over its operational lifetime. Thefefor6 the State should continue its program of data collection to provide for continuing cumulative impact assessment. xii TABLE OF CONTENTS Page No. FOREWORD ---------------------------------------------------- iii SUMMARY -------------------------------------------------- v RECOMMENDATIONS -------------------------------------------- xi I. ENERGY AND ELECTRIC POWER ---------------------------- 1- 1 A. Electric Utilities in Maryland ------------------- 1- 1 B. National Energy Trends -------------------------- 1- 8 C. Maryland: Energy ------------------------------ 1-23 D. Maryland Utilities: Past Trends and Future Projections ------------------------------------- 1-23 E. Maryland Utilities: Capacity Trends and Plans --- 1-37 References ------------------------------------------- 1-72 AIR IMPACT ------------------------------------------ 11- 1 A. Sources and Nature of Emissions ------------------ 11- 1 B. Health Effects ----------------------------------- 11- 4 C. Standards ---------------------------------------- 11- 4 D. Status and Trends in the Maryland Airshed -------- 11- 5 Total Suspended Particulates (TSP) --------------- 11- 8 Sulfur Dioxide (SO 2) --------------------------- 11-14 Nitrogen Oxides (NO ) --------------------------- 11-21 Other Pollutants -------------------------------- 11-21 E. Pollution Control ------------------------------- 11-26 Use of Low Sulfur Coal ------------------------- 11-28 Cleaning of Coal --------------------------------- 11-32 Conversion of Coal Gasification ------------------ 11-34 xiii Page No. Conversion by Coal Liquefication --------------- 11-34 Fluidized Bed Combustion -------------------------- 11-34 Flue Gas Desulfurization (FGD) ------------------- 11-34 F. Mathematical Modeling ----------------------------- 11-40 G. Regulatory Effects ------------------------------- 11-44 Stack Height and Intermittent Control ------------- 11-44 Non-Attainment Areas ----------------------------- 11-44 Prevention of Significant Deterioration (PSD) ----- 11-46 References ----------------------------------------- 11-60 III. AQUATIC IMPACT -------------------------------------- 111- 1 A. Aquatic Habitat --------------------------------- 111- 4 B. Assessment and Mitigation of Impact --------------- 111- 8 C. Aquatic Impact ----------------------------------- III-11 Mesohaline ---------- - - - ---- - ------------ - ---- 111-14 Tidal Freshwater/Oligohaline---n -------------------- 111-23 Riverine --- - - -------- - ------------------------- 111-28 D. Regulatory Considerations ------------------------- 111-29 E. Conclusions and Summary of Impact ----------------- 111-30 References ------------------------------------------ 111-33 IV. RADIOLOGICAL EFFECTS -------------------------------- IV- 1 A. Status of Nuclear Power in Maryland --------------- IV- 1 B. Operations at Calvert Cliffs Nuclear Power IV- 2 Plant - - - - ------------ - ------- ---------------- Electrical Power Production --------------------- IV- 2 Radioactive Effluent Releases --------------------- IV- 3 Solid Radioactive Waste -------------------------- IV-11 xiv Page No. Spend Fuel Accumulations -------------------------- IV-11 C. Radiological Effects Around the Calvert Cliffs Plant Site -- - --- - -- - ---- - --------------------- IV-13 D. Conclusions --- - -- - - - - ------------------------ IV-19 References ------------------------------------------- IV-25 V. SOCIO-ECONOMIC IMPACT --------------------------------- V- 1 A. Employment --------------------------------------- V- I B. Population --------------------------------------- v- 6 C. Housing ---------------------------------------- v- 8 D. Transportation ----------------------------------- V-10 E. Business Activity --------------------------------- V-10 F. Fiscal Effects ----------------------------------- V-12 G. Simmary -------- - - - ----------------------------- V-16 References -------------------------------------------- V-19 Vi. OTHER IMPACTS ---------------------------------------- VI- 1 A. Transmission Lines -------------------------------- Vi- 1 Conclusions ------------------------------------- VI-12 B. Groundwater ------------------------------------- VI-13 Conclusions -------------------------------------- VI-21 C. Cooling Towers ----------------------------------- VI-21 Chalk Point Cooling Tower Project ----------------- VI-23 Conclusions -------------------------------------- VI-26 References -- - - - -- - -- - -- - -- - --------------------- VI-27 APPENDIX A ------------------------------------------------- A-1 APPENDIX B ------------------------------------------------- B-1 xv LIST OF ILLUSTRATIONS Figure Page No. 1- 1 Service territories of Maryland electric utilities ---- 1- 4 1- 2 Imports and exports of power by BG&E and PEPCO, 1976-1977 --------------------------------------------- 1- 5 1- 3 U.S. total energy consumption by primary source, 1960-1977 --------------------------------------------- 1- 9 1- 4 Proportion of total U.S. energy supplied by coal vs. oil and natural gas, 1960-1977 ------------------------ I-11 1- 5 U.S. electrical power generation fuel mix, 1960-1977-- 1-14 1- 6 Projections of peak demand by U.S. utilities, 1974- 1977 ------------------------------------------------- 1-22 1- 7 Energy flows, 1974 ------------------------------------ 1-25 1- 8 Hypothetical daily load curve ------------------------- 1-27 1- 9 Maryland and U.S. electric energy sales, 1962-1977, Maryland and U.S. electric energy peak demand, 1962- 1977, respectively ------------------------------------ 1-29 I-10 Projections of peak demand by Maryland electric utilities, 1973-1978 ---------------------------------- 1-33 I-11 Peak demand forecast for Maryland, 1977-1987 ---------- 1-36 1-12 Location of electric power plants in the Maryland region ----------------------------------------------- 1-38 1-13 Peak demand and capacity forecast for electric utility systems serving Maryland, 1977-1987 ------------------- 1-46 II_ 1 Power plants in the Maryland region ------------------- 11- 3 11- 2 (A) Composite average annual mean total suspended particulate concentration, U.S. (B) Composite average peak daily total suspended particulates, U.S. (C) Total suspended particulate emission estimate for U.S ------------------------------------------- 11-9 xvii Figure Page No. 11- 3 Violations of total suspended particulates for Maryland ----------------------------------------------- II-10 11- 4 Composite mean of the annual averages of total sus- pended particulates for Maryland ----------------------- II-11 11- 5 Estimates of total suspended particulates ground- level concentrations for Maryland 1973, 1980, 1985 ----- 11-13 11- 6 Composite average of annual mean S02 concentration, U.S ---------------------------------------------------- 11-15 11- 7 Long-term trends in U.S. S02 emissions ----------------- 11-16 11- 8 Composite mean of annual arithmetic averages Of S02 for Maryland stations ---------------------------------- 11-17 II_ 9 Seasonal trend in S02 ground-level concentrations, Baltimore City and County ------------------------------ 11-18 II-10 Estimates Of S02 ground-level concentrations for Mary- land 1973, 1980, 1985 --------------------------------- 11-19 II-11 Composite mean of annual averages of N02 concentration for Maryland since 1971 -------------------------------- 11-22 11-12 Trends in national power plant and retail coal consump- tion and in BSO and BAP annual averages ---------------- 11-23 11-13 Composite quarterly means of sulfate ground-level concentration in Maryland ----------------------------- 11-25 11-14 Washability of some West Virginia coal ----------------- 11-33 11-15 Representation of the Gaussian plume equation ---------- 11-42 11-16 Mandatory and suggested Class I areas in and around Maryland ---------------------------------------------- 11-48 11-17 Maximum annual average ground-level concentration for S02 AT = 30* C ---------------------------------------- 11-51 11-18 Maximum annual average ground-level concentration for S02 AT = 90*C ----------------------------------------- 11-52 11-19 Maximum 24-hour average ground-level concentration for S02 -- Meteorological Condition 1 ------------------ 11-53 11-20 Maximum 24-hour average ground-level concentration for S02 -- Meteorological Condition 2 ------------------ 11-54 11-21 Annual wind rose for three airports -------------------- 11-56 xviii Figure Page No. 11-22 Distance to ground-level concentrations of 5 vg/m S02, 1% sulfur coal, 80% efficiency scrubber ----------- 11-57 11-23 Distance to ground-level concentration of 5 pg/m3, 2% sulfur coal, 80% efficiency scrubber ---------------- 11-58 11-24 Siting restriction for a 1000 MW coal-fired plant with a 500 ft stack ------------------------------------ 11-59 111- 1 Path of cooling water flow through a power plant and location of plant-organism interactions ---------------- 111- 2 111- 2 Areas of potential power plant entrainment impact on striped bass and associated food items ----------------- 111- 6 111- 3 Spring and autumn salinity distributions in the Chesa- peak Bay ----------------------------------------------- 111- 9 111- 4 (A) Estuarine circulation patterns (B) Tidal excursion ------------------------------------ 111-13 IV- 1 Locations of radionuclide discharges into Chesapeake Bay ---------------------------------------------------- IV-17 IV- 2 (A) Gamma spectrum of oysters from Calvert Cliffs nuclear power plant discharge area (B) Gamma spectrum of oysters from Kenwood Beach Area ---------------------------------------------- IV-20 V_ 1 Total employment profiles for electric power plant construction ------------------------------------------ V- 3 Vi- 1 Power plants and transmission lines in the Maryland region ------------------------------------------------- VI- 2 VI- 2 Typical 500 kV transmission line-, ---------------------- VI- 6 VI- 3 Electric field profile of 500 kV horizontal configura- tion with three sub-conductors ------------------------ VI- 7 VI- 4 Worst case electrostatically induced spark discharge for people touching various objects -------------------- Vi- 9 VI- 5 Worst case electrostatically induced currents for people touching various objects ------------------------ VI-10 xix Figure Page No. VI- 6 Gasoline ignition potential from AC spark discharges --- VI-11 VI_ 7 General cross-section through unconsolidated coastal plain sediments in Southeastern Maryland --------------- VI-14 VI- 8 Pumpage and water levels of the Aquia aquifer at the Calvert Cliffs Nuclear Plant --------------------------- VI-15 Vi- 9 Pumpage from the Quaternary and Cheswold aquifers at Vienna Power Plant ------------------------------------- VI-17 VI-10 Pumpage from the Patuxent aquifer at the Morgantown power plant -------------------------------------------- VI-18 VI-11 Pumpage from the Magothy and Patapsco aquifers at Chalk Point ----------------------------------------- - VI-19 VI-12 Map showing the potentiometric surface of the Magothy aquifer in Southern Maryland, September 1977 ----------- VI-20 xx LIST OF TABLES Tables Page No. 1- 1 Imports and exports to and from Maryland by utility, 1967-1977 ------------------------------------------------ 1- 7 1- 2 U.S. energy consumption by primary energy type, 1960-1977 ------------------------------------------------ I-10 1- 3 Electric generation by fuel type, U.S., 1960-1977 -------- 1-12 1- 4 Change in electric generation fuel mix, by region, 1960-1985 ------------------------------------------------ 1-15 1- 5 Projected U.S. coal consumption -------------------------- 1-17 1- 6 National and regional generation expansion plans, 1977-1987 ---------------------------------------------- 1-18 1- 7 U.S. nuclear power capacity expansion -------------------- 1-20 1- 8 Comparison of annual growth rates in U.S. electricity consumption ---------------------------------------------- 1-21 1- 9 Energy flows, 1974 -------------------------------------- 1-24 I-10 Electric energy sales in Maryland, 1962-1977 ------------- 1-30 I-11 Electrical bills in Maryland, 1971-1977 ----------- 7------ 1-32 1-12 Projected energy sales and peak demand in Maryland, 1977-1987 --------------------------------------------- 1-35 1-13 Maryland electricity generation by source, 1960-1977 ----- 1-40 1-14 Generating capacity by fuel type, 1966-1997 -------------- 1-42 1-15 Peak demand and generating capacity in Maryland for Maryland utilities, 1978-1987 ---------------------------- 1-44 1-16 System peak demand and generating capacity of Maryland utilities, 1978-1987 ----------------------------------- 1-45 1-17 Effects of capacity changes on the APS system ------------ 1-48 1-18 Projected and actual energy demand, capability and growth rates for Maryland utilities, 1966-1987 ------------------ 1-50 1-19 Generating capability and fuel type by generating unit for Maryland utilities ----------------------------------- 1-63 1-20 Proposed new power plants and expansion of existing plants in Maryland --------------------------------------- 1-69 xxi Tables Page No. II_ 1 Statewide total emissions inventory, 1974 and 1975 ------- 11- 2 11- 2 Federal ambient air quality standards -------------------- 11- 6 11- 3 New source performance standards calculated -------------- 11- 7 11- 4 Calculated contribution to S02 ground-level concentration from BG&E power plants ----------------------------------- 11-20 11- 5 Comparison of new source performance standards and emission factors ----------------------------------------- 11-27 II- 6a Estimated in-place coal reserves, U.S -------------------- 11-29 II- 6b Estimated in-place coal reserves for Eastern states with major reserves -------------------------------------- 11-30 11- 7 Energy costs in the Washington, D.C. area --------------- 11-31 11- 8 Status Of S02 scrubber system applications as of July 1978 ------------------------------------------------ 11-37 S02 scrubber system selection in terms of MW capacity ---- 11-37 II-10 Cost Of S02 control technologies for baseload plants ----- 11-38 II-11 Prevention of significant deterioration of air quality --- 11-47 111- 1 Major types of aquatic effects of power plant opera- tions -------------------------------------------------- 111- 5 111- 2 Power plant location by salinity regime ------------------ III-10 111- 3 Water flows at Maryland power plants --------------------- 111-15 111- 4 Relationship between plant withdrawal volumes and tidal volumes; plant withdrawal rate and tidal and river flow rates --------------------------------------------------- 111-16 111- 5 Estimated total impingement by species at mesohaline power plants ------------------------------------------- 111-18 111- 6 Maryland commercial landings ----------------------------- 111-20 111- 7 Commercial catch of striped bass in March and April by region in the Maryland portion of the Chesapeake Bay ----- 111-27 111- 8 Estimated upper limit impact on striped bass ichthyo- plankton power plant entrainment ------------------------- 111-31 xxii Tables Page No. IV- la Liquid radioactive effluents cumulative to December 41, 1977 ---------------------------------------------------- IV- 4 IV- lb Airborne releases cumulative to December 31, 1977 -------- IV- 6 IV- 2 Regulatory limitations on radioactivity in Calvert Cliffs effluents ----------------------------------------------- IV- 8 IV- 3 Solid wastes shipped off-site during 1977 ---------------- IV-12 IV- 4 Maximum concentrations of radionuclides attributed to . . plant operation in various environmental media ----------- IV-18 IV- 5 Dose commitment due to Calvert Cliffs Nuclear Power Plant effluents --------------------------------------- IV-21 IV- 6 Dose-risk conversion factors ---------- ----------- ------- IV-22 IV- 7 Comparison of Calvert Cliffs radiological impact esti- mates with NRC guideline dose-value ---------------------- IV-24 V- 1 Employment effects Four Eastern Shore Counties -------- v- 5 V- 2 Population effects Four Eastern Shore Counties -------- v- 7 v- 3 Housing effects -- Four Eastern Shore Counties ----------- V_ 9 v- 4 Effects on local business -- Four Eastern Shore Counties- V-11 Counties ------------------------------------------- ------- V-11 V- 5 County and municipal fiscal effects -- Four Eastern Shore Counties ------------------------------------------ V-14 V- 6 Projected deficits due to plant construction -- Four Eastern Shore Counties ----------------------------------- V-15 V- 7 County-revenues, operating period -- Four Eastern Shore County --------------------------------------------------- V-17 V_ 8 Total taxes paid to Maryland Counties by Maryland Utilities, Fiscal year 7/l/77-6/30/78 -------------------- V-18 vi- 1 Pole miles of transmission lines and circuit miles of underground cables in Maryland --------------------------- VI- 3 VI- 2 Comparison of cooling tower alternative for the proposed Douglas Point power plant -------------------------------- VI-24 xxiii Tables Page No. Appendix A Attachments: See p. A-2 Appendix B B-I Electric energy sales in Maryland and the U.S -------------- B- 3 B-2 National and Mary land projected electric energy copsump@- tion and peak demand --- - ---- ---- - --------------- B_ 4 B-3 Typical monthly electric bills 1972, 1974, 1977 ---------- B- 6 B-4 Projected average annual compound growth rates on popula- tion, employment, and real per capita income ------------- B- 9 B@5 Energy sales, peak demand, and growth rates for Maryland utilities 1966-1987 ----------------------------------- B-10 xxiv CHAPTER I ENERGY AND ELECTRIC POWER Since the publication of the first Cumulative Environmental Impact Report in 1115, a number of major changes have occurred which will affect the generat- ing requirements and plans of Maryland's electric utilities. The recession and steep rise in fuel prices which occurred after the oil embargo caused a decline in the use of electric power in 1974. The use of electric power leveled off as Maryland's ecomony recovered and fuel price moderated. Growth in the use of electricity has resumed, but at a lower rate than before. In considera- tion of the earlier decline in usage and the current lower average annual rates of growth, Maryland utilities have delayed or postponed the addition of some generating units, and have rearranged the construction schedule of others. This chapter reviews the status of electric utilities in Maryland. The purpose of the chapter is to provide an analysis of future electric generating requirements. Because the demand for electric power in Maryland and the types of generating capacity selected by Maryland utilities are strongly influenced by national economic and energy trends and policies, the chapter begins with a description of the organization of the electric utilities in Maryland. Next national energy trends and projections are discussed, followed by the current projections of electric power demand for the Maryland electric utilities, and analyzes their plans for new generating capacity over the next twenty years. This analysis includes a discussion of likely trends in both plant types and siting. The chapter concludes with a discussion of the adequacy of the future supply of electricity in Maryland. A second function of this chapter is to make available a compendium of information on historic and projected electric power use and generation in Maryland. The analysis of electric power supply in Maryland is based on traditional central generating station systems. Energy conservation and decentralized alternative energy systems are not discussed explicitly, but are to some extent implicit in the Power Plant Siting Programs independent demand forecasts. Maryland's energy conservation and alternative energy programs are managed by another unit of the Maryland Energy and Coastal Zone Administration of which the Power Plant Siting Program is a part. A. Electric Utilities in Maryland Most of Maryland's electrical customers receive power generated by one of five major electric utilities. All except Conowingo have power plants in Maryland.* These utilities are: Two utilities, 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 has customers in Maryland. I-1 * Baltimore Gas and Electric Company, serves 714,633 residential customers, with 1977 peak load of 3,588 MW and total megawatt hour sales of 15,462,000 MW. e Conowingo Power Company, a non-generating subsidiary of the Philadelphia Electric Company, serves 20,982 residential customers, with 1977 peak load of 85 MW and total megawatt hour sales of 419,926 MWh. e Delmarva of Maryland, a subsidiary of Delmarva Power and Light Company, serves Delaware and portions of Maryland and Virginia. Delmarva of Maryland serves 68,816 residential customers with a 1977 peak load of 400 MW and total megawatt hour sales of 1,726,551 MWh. Delmarva also provides generation for municipals and cooperatives located in its service territory. e Potomac Electric Power Company, serves portions of Maryland, Virginia and the District of Columbia. PEPCO serves 249,384 Maryland residential customers with a 1977 system peak load of 3,857 MW and total megawatt hour sales of 8,342,247 MWh in Maryland, including wholesale sales to the Southern Maryland Electric Cooperative. 9 Potomac Edison serves customers in Western Maryland, eastern West Virginia, and northern Virginia. A subsidiary of the Allegheny Power System, Potomac Edison had a 1977 Maryland peak load of 1,018 MW and total sales of 5,604,079 MWh, and serves 107,682 residential customers in Maryland. The Potomac Edison 1977 system peak was 1,486 MW, with system sales of 8,349,010 MWh. In addition to the major utilities, Maryland is served by a number of municipally-owned utilities ("municipals"), most of which purchase power from the generating companies at wholesale rates and distribute that electricity within their service areas, and by rural electric cooperatives ("cooperatives") which are owned by their customers and most of which also purchase their power from the generating companies. The municipals and cooperatives operating in Maryland are: Municipals Cooperatives BLNrlin Accomack - Northampton Centreville Electric Cooperative Easton Hagerstown Choptank Electric St. Michaels Cooperative Thurmont Williamsport Somerset Rural Electric Cooperative Southern Maryland Electric Cooperative 1-2 Of the municipals, only Easton has generating capability. Easton currently has 32.6 MTJ capacity, and is included in this chapter as part of the Delmarva Group, consisting of the Delmarva Power and Light Company system, Dover) Delaware (a municipal system), and Easton. The service territories of the Maryland utilities are shown in Figure I-1. In addition to generating their own power, utilities may arrange for pur- chases of power from plants owned by other utilities to which they are connected by a transmission system. Such purchase may be made on a "firm power" basis as a substitute for a utility's own capacity, or may be made either on an emer- gency basis (such as the temporary failure of one of its own units or a level of demand larger than anticipated) or on an "economy" basis. Economy sales and purchases are exchanges between utilities which permit the uti 1i ty to select the least expensive electricity available at a given moment either from its own generating units or from units owned by another company. Utilities can function as a power "pool," in which all of the plants of the member compan- ies are treated as belonging to a single entity -- the "pool" -and power is sent out to a given utility from the most efficient unit (i.e., the unit with the lowest cost of generation) available at that moment, regardless of owner- ship or location.* Four of the five Maryland electric companies belong to the PJM Inter- connection, a power pool made up of 11 utilities in Maryland, Pennsylvania New Jersey and Delaware.** (Potomac Edison, the fifth major utility is a subsidiary of the Allegheny Power System, which operates its three subsidiary companies as a fully integrated system in a manner analogous to a power pool.) These utilities interchange electricity between each other on an economy basis. As a result, the extent to which each utility generates its own electricity is largely a function of the availability of less expensive generation else--- where in the system at a given moment in time. This, in turn, depends on the efficiency of the plants owned by each utility and on the pattern of demand experienced by each company at a given moment. Figure 1-2 illustrates sales and purchases to other utilities for BG&E and PEPCO (1). for the calendar years 1976 and 1977. The Figure shows the change in the relative amounts of purchases and sales of power from other utilities (mostly within the PJM power pool) which occurs over an annual demand cycle, particularly the shift towards purchases of power during the summer months during which these two utilities experience their highest level of demand. The figure also shows the shift towards deliveries of power to the pool as a large amount of capacity becomes available from new units with lower capital costs, as when the second BG&E Calvert Cliffs nuclear unit came on-line Transmission costs are incorporated into the send-out decisions. The PJM members are: Atlantic City Electric Company, Baltimore Gas and Electric Company, Delmarva Power & Light Company, Jersey Central Power & Light Company, Metropolitan Edison Company, Pennsylvania Electric Company, Pennsylvania Power & Light Company, Philadelphia Electric Company (of which Conowingo is a subsidiary), Potomac Electric Power Company, Public Service Electric and Gas Company, UGI Corporation 1-3 Pennsylvania SOMERSET RURAL POTOMAC ED I SON BG &E CONOWINGO POWER CO. ELECTR I C COOP N m 3-- 3 CARROLL .............. X! X Delaware HARfORD . . . . . . BALTIMORE XX E, 0. K HOWARD Virginia QUEEN CENTREVILLE RY j--ANNE AMES 'Py ARUNDEL D 'L ARVA E WMD. PEPCO & TALBOT MUN I C I PAL ELECTR I C COMPAN I ES CHOPTANK ELECTR I C 1) Williamsport PRI14CE 4 CAROLINE 2) Hagerstown GEORGES COOP 3) Thurmont 4) Easton CHARLES CALVERT. St. Michaels 5) Berlin DORCHESTER i. WICOMICO ST MARYS WORCIESIER SOUTHERN MARYLAND SOMERSET ELECTRIC COOP. ACCOMACK-NORTHAMPTON COOP ISMITH ISLAND) COUNTY BOUNDARY LINES *GENERALLY. DELMARVA P&L - CITIES &TOWNS ELECTRIC SERVICE BOUNDARY LINES (Approx.) CHOPTANK - SUBURBS & RURAL Figure I-1. Service territories of Maryland electric utilities m m IN Will m m m m m m m G00- 13G& E 500 - 400- 300- NET (IMPOR78 C200 - OR EXPORTS) S'C 100 - EXPORTS IMPORTS '001 too i P M A U J J A 8 0 N 019 F M A M J J A 3 0 N 0 197.6 G00-- - PEPCO GOO--- 400.- NET (IMPORTS OR EXPORTS 300 02oo-. -EXPORTS .. I; PmT 100. Ur 200- 1976 F M' AL J J A S 0 Figure 1-2. hports and exports of electric power by BG&E and PEPCO, 1976-1977 in April of 1977, or during winter months during which these utilities exper- ience lower levels of energy use by their own customers. Historically, Maryland has been a net importer of electric power. In recent years, imports have ranged from a low of 1.2% of total electric power use in 1977 to a high of 13.9% in 1975. BG&E, Potomac Edison, Delmarva of Maryland, and Conowingo have historically been net importers of power, while PEPCO, Pennsylvania Electric (owner of hydroelectric capacity at Deep Creek Lake), and Susquehana Electric (owner of hydroelectric capacity at Conowingo Dam) have been net exporters. Table I-1 gives the net imports and exports of power for Maryland by utility from 1967 to 1977 (2). In addition to whatever pool arrangements they may make, U.S. utilities were required by the Federal Power Commission* to form regional Electric Reliability Councils. Formed as a consequence of the 1965 Northeastern power blackout, the purpose of the councils was to develop a level of utility inter- connection and system reliability adequate to reduce the likelihood of large- scale power blackouts. These reliability councils serve as planning bodies to coordinate utility generation and transmission planning They do not serve the economy send-out function of power pools. However, the councils do monitor the availability of plants in their own and neighboring territories, they make that information available to member utilities hourly, and they coordinate emergency interchanges. BG&E, Delmarva, Conowingo (through its parent company, Philadelphia Electric Co.), and PEPCO are members of the Mid-Atlantic Area Council (MAAC), which covers all or parts of Maryland, the District of Columbia, Pennsylvania, New Jersey, Delaware, and the Eastern Shore portion of Virginia. Potomac Edison is a member of the East Central Area Reliability Coordination Agreement (ECAR), which covers the western portion of Maryland, Pennsylvania, and Virginia, all of West Virginia, Ohio, and Indiana, and most of Michigan and Kentucky. Utility interconnections, either in power pools or in the reliability system grid, raise the question of whether or not a utility generation con- struction program is required for the utility's own customers or for sales to another utility located elsewhere. The regional reliability council agreements are intended to foster a high level of total system reliability by requiring that each member utility have a level of capacity adequate to serve its own needs, and by providing a level of interconnection of utilities that is capable of transfering power from other utilities into a particular service area in emergencies.** The PJM Power Pool agreement, which is designed to provide its members access to the least expensive electricity at any point in time, has a similar clause requiring that its members own enough generating capacity to maintain a given level of reliability, and includes a surcharge for continuing purchases necessitated by factors such as inadequate generation capacity. Now the Federal Energy Regulatory Commission (FERC) of the U.S. Department of Energy. This ability to obtain power from other companies actually reduces the amount of capacity a utility must own in order to achieve a given level of reliability. 1-6 M M M M M Table I-1. Imports and exports of electricity to and from Maryland by utility, 1967-1977, millions of MWh(a) Delmarva Pennsylvania Potomac pEpoo(d) Sus anna Total F geh Baltimore Conowingo Ed ectric State of Md. Year Gas & Elec. Power & Light(b) Electric ison (c) 1967 -1,251,673 -184,240 -407,715 27,988 -974,259 3,725,179 1,811,472 2,746,762 1968 -463,019 -205,142 -484,876 22,850 -1,137,49S 2,536,890 1,S06,69S 1,776,916 1969 -984,212 -2SO,341 -Sn'sw 16,42S -1,372,891 1,058,753 1,265,288 - 783,SSS 1970 -1,146,112 -259,983 -680,646 29,655 -2,407126S 1,515,313 1,790,275 -1,158,749 1971 -1,881,874 -281,841 -751,188 34,652 -3,180,728 2,254,070 1,663,910 -2,142,985 1972 -3,145,610 -300,186 -503,684 39,733 -3,422,097 4,885,510 2,163,320 -283,000 1973 -4,286,781 -319,786 -340*,331 32,860 -3,802,468 4,161,602 2,038,271 -2,SI6,621 1974 -3,617,297 -326,SS3 -472,106 31,420 --3,683,085 5,677,575 1,848,381 -591,778 1975 -S,711,684 -332,967 -1,095,230 3S,868 -3,630,108 5,047,380 2,185,789 -3,605,478 -4 1976 -3,479,120 -374,773 -885,IS2 23,059 -4,964,629 6,175,803 1,971,017 -1,608,762 1977 850,077 -391,677 -1,414,885 20,862 -5,236,SSS 3,893,618 1,899,644 -370,679 - I I I (a) Data indicates net exports; negative figure indicates imports. (b) Includes only DP&L of Maryland and Easton. (c) Includes imports and exports from Maryland portion of service territory only. (d) Includes PEPOO sales to PEPOO service territory in Virginia and the District of Columbia as exports. In reviewing certificate applications for Maryland's utilities, it has been the policy of the Maryland Public Service Commission to evaluate the need to expand capacity to meet projected future demand on the basis of the antici- pated requirements of the utility's own service territory. The interconnections and power pools to which Maryland utilities belong can assist in improving utility performance and reliability. Ultimately, however, generation plans are developed by an individual utility on the basis of the requirements of its own service territory, and are judged by regulatory authorities on the same basis. The next section of this chapter evaluates national and regional trends in total energy and electricity. In that framework, the final sections describe electrical generation trends and plans for each of the Maryland utilities at the service territory level. B. National Energy Trends Prices and supplies of competing sources of energy are determined within the framework of national and regional markets. Policy decisions made at a national or even an international level influence those markets, and as a con- sequence they shape energy options available in Maryland. It is helpful, therefore, to begin the discussion of Maryland's energy situation by describing the national energy framework within which Maryland functions. The major primary sources of energy in the United States are petroleum, natural gas, coal, hydroelectric power and nuclear power. Figure 1-3 shows the changes that have taken place in the consumption of these primary sources of energy since 1960. Table 1-2 presents similar data in tabular form, with energy sources shown as a percentage of U.S. energy use for each year (3). Two major trends in the table and figure are worth noting. First, total domestic energy use has grown almost without interruption, increasing by 70% over the past 17 years. However, during the recession which followed the dramatic oil price increases after the oil embargo of 1973, total U.S. energy consumption fell for the first time since the recession of 1958-1959. But as the data in Table 1-2 show, growth in energy use resumed in 1976, coin- ciding with the end of the 1974-75 recession. The second point to note in Table 1-2 is the two major changes that have taken place in the composition of the U.S. energy mix. The first major change is the longterm replacement of coal by oil and, until recently, by gas. The energy share coming from coal has been taken up by the growth in the use of gas, especially for home heating purposes, and by the growth in the use of oil, especially for home heating, and for industrial and electric utility fuel use. Figure 1-4 shows clearly the extent to which coal has been replaced by oil and natural gas over the past 75 years (4). The data in Table 1-2 and Table 1-3 suggest that in the post-embargo years since 1973 the role of coal nationally may be reversing again, particularly for electric power generation purposes (3). 1-8 M MM M M M MM M MW so NUCL HYDROEL 11 70 - TOTAL CONSUMPTION 60 50- NATURAL GAS 40 tn- 10 PETROLEUM z 30-- 0 20 CY 10 COAL 0 1960 1965 1970 1975 197T Figure 1-3. U.S. total energy consumption by primary source, 1960-1977 Table 1-2. U.S. energy consumption by primary energy type, 1960-1977 Total Energy coal Petroleum Natural Gas Nuclear Hydroelectric Year Constmption * I Change Quads I of Quads % Quads Quads I Quads % Quads Annual Total 1960 44.5 3.3 10.1 22.7 20.0 44.9 12.7 28.5 < 0.1 < 1.0 1.6 3.6 1961 45.3 1.7 19.9 21.9 20.5 45.3 13.2 29.1 < 0.1 < 1.0 1.6 3.5 1962 47.4 4.6 10.2 21.5 21.3 44.9 14.1 29.7 < 0.1 < 1.0 1.8 3.8 1963 49.3 4.0 10.7 21.7 22.0 44.6 14.8 30.0 < 0.1 < 1.0 1.7 3.4 1964 51.2 3.9 11.3 22.0 22.4 43.8 15.6 303 < 0.1 < 1.0 1.9 3.7 1965 53.3 4.1 11.9 22.3 23.2 43.5 16.1 30.2 < 0.1 < 1.0 2.0 3.8 1966 56.4 5.8 12.5 22.2 24.4 43.3 17.4 30.9 0.1 < 1.0 2.0 3.S 1967 S8.2 3.3 12.3 21.1 2S.3 43.5 18.3 31.4 0.1 < 1.0 2.3 4.0 1968 61.7 6.0 12.7 20.6 27.1 43.9 19.6 31.8 0.1 < 1.0 2.3 3.7 1969 64.9 5.2 12.7 19.6 28.4 43.8 21.0 R.4 0.1 < 1.0 2.6 4.0 1970 67.1 3.3 12.7 18.9 29.5 44.0 22.0 32.8 0.2 < 1.0 2.6 3.9 0.6 2.8 4.1 1971 68.3 1.8 12.0 17.6 30.6 44.8 22.5 32.9 0.4 1972 71.6 4.8 12.4 17.3 33.0 46.1 22.7 31.7 0.6 o.8 2.9 4.1 1973 74.6 4.1 13.3 17.8 34.9 46.8 22.S 30.2 0.9 1.2 3.0 4.0 1974 72.6 (2.6) 12.9 17.3 33.S 44.9 21.7 29.1 1.2 1.6 3.3 4.4 197S 70.6 (2.8) 12.8 18.1 32.7 46.3 19.9 28.2 1.8 2.5 3.2 4.5 1976 74.4 5.3 13.7 18.4 3S.1 47.2 20.3 27.3 2.0 2.7 3.0 4.0 1977 75.8 2.0 14.1 18.6 37.0 48.8 19.6 25.9 2.7 3.6 2.4 3.2 *Quads - quadrillion UM's 10 is BTU Is 100- 90- 0 PETROLEUM F- CL so - COAL NAT@@*'O. GAS 0 76 z 60 - 50 - 40 - 30 - w a.. 20 - 10 - 0 1900 1920 w 1960 INO Figure 1-4. Proportion of total U.S. energy supplied by coal vs oil and natural gas, 1960-1977 Table 1-3. Electricity generation by fuel type - U.S. (millions of kilowatt hours and percentages of total generation) Coal Petroleum Natural Gas Nuclear Hydroelectric Other Year Total Net Production 106 kWh % 106 kWh % 106 kWh % 106 1,-Iqh % 106 kWh % 106 kjqh % 106 kWh 1960 7533,350 4030067 53.5 46,105 6.1 157,970 21.0 S18 0.1 145,516 19.3 174 0.0 1961 792,039 421,871 53.3 470120 5.9 169,286 21.4 .1,692 0.2 151,850 19.2 220 0.0 1962 8S2,314 450,249 52.8 46,983 5.5 1840301 21.6 2)270 0.3 168,283 19.8 228 0.0 1963 916,793 493,927 53.9 52,001. 5.7 201,602 22.0 3,212 0.3 1650755 18.1 296 0.0 1964 983,990 526,230 53.5 56,954 5.8 220,038 22.4 34343 0.3 177,073 18.0 352 0.0 1965 119055,252 570,926 54.1 64,801 6.1 221,S59 21.0 3,657 0.4 193,851 18.4 458 0.0 1966 1$144,350 613,475 53.6 78,926 6.9 251,151 21.9 50520 0,.S 194,756 17.0 522 0.1 1967 1,214,365 630,483 51.9 89,271 7.4 264,806 21.8 7,65S 0.6 221,518 18.2 632 0.1 1968 13*329,443 684,904 51.S 104,276 7.9@ 304,433 22.9 12,S28 0.9 222,491 16.7 811 0.1 1969 11,442.%183 /06,001 48.9 137,847 9.6 333,279 23.1 13,928 1.0 250,193 17.3 935 0.1 1970 10492,971 675,199 45.2 179,376 12.0 366,619 24.5 21,806 1.5 2490090 16.7 881 0.1 1971 1,612,593 714,680 44.3 218,622 13.5 374,027 23.2 38,105 2.4 266,300 16.S 859 0.1 1972 1,749,629 7720857 44.1 272,550 15.6 375,735 :71.5 54)091 3.1 272,613 15.6 1,783 0.1 1973 lt860,440 848,987 45.7 312,940 16.8 340,804 18.3 830334 4.5 272,081 14.6 2,294 0.1 1974 11867,103 829,973 44.5 299,363 16.0 320,055 17.1 113,976 6.1 301,032 16.1 2,704 0.2 1975 1,917,638 852,968 44.5 2880908 15.1 299,772 15.6 172,506 9.0 300,047 15.6 3,437 0.2 1976 2,036,487 943,879 46.3 319,518 15.7 294,419 14.5 191,108 9.4 283,680 13.9 3,883 0.2 1977 2,124,078 985,450 46.4 357,889 16.8 305,357 14.4 250,883 11.8 220,435 10.4 4,063 0.2 M M M M M IM M, M M, M M M M M M M M The second change is the more recent decline in the proportion of the energy share contributed by natural gas since 1971, when gas contributed 32.9% of the U.S energy supply. By 1976, the share had dropped to 27.3%, a decline in market share of 5.6 percentage points in only 5 years. That relative decline occurred as total U.S marketed production declined from its 1972 record produc- tion of 22.1 trillion cubic feet of gas to 19.9 trillion cubic feet in 1976 -- a 10% production decline in 4 years. The decline in gas usage has occurred as gas users, especially industrial customers subject to winter curtailments, have switched to other fuels and as new customers, such as residential custo- mers who would have been gas users, have been forced by moratoria on new gas connections to find alternative sources of energy. In both cases customers have largely turned either to the use of oil or to the use of electricity. Figure 1-5 and Table 1-3 show the changes which have occurred nationally since 1960 in the fuel mix used in generating electricity (3). The most obvious change that has occured has been the relative increase in the role of oil, compared to the relative decline in generation by all other fuels except nuclear. This is especially true of coal, which had provided over half (51.5%) of U.S. electric energy as recently as 1968, but which provided only 44.1% by 1972, only four years later. The portion of total electricity generation which had been based on coal shifted to other fuels, principally oil: during the same period, the oil portion of this fuel mix almost doubled from 7.9% of total generation to 15.6%. The absolute amount of oil-fired generation more than doubled, growing from 104,276 million kWH in 1968 to 272,550 million kWH in 1972. The rapid decline in the relative use of coal was the result of state and Federal air pollution legislation and regulation, principally the Clean Air Act Amendments of 1970. Utilities switched boilers from coal to oil, particularly in urban areas with poor air quality. A large percentage of the new units which were brought on line were also oil-fired. This trend was particularly marked in the heavily urbanized Northeast. Table 1-4 shows the fuel mix distribution for each region of the U.S. (5). The data in the table show fuel mixes for 1960 and 1974, and the Federal Energy Administration's (now part of the U.S. Department of Energy) projection for the 1985 fuel mix, prepared in 1976. As Table 1-4 demonstrates, the fuel mix used to generate electricity varies greatly by region. Changes in state and federal energy and environmental policies, as well as in relative energy prices, can significantly affect trends in the fuel mix used by the utilities in the regions in different ways. Air pollution requirements in the urbanized and industrialized Northeast, as well as trends in operating costs, resulted in the dramatic decline in the relative share of coal in New England, which dropped from 50.3% of generation in 1960 to only 7.4% in 1974, and the more modest decline in the Middle Atlantic region, including Maryland, where the coal share dropped from 69.3% in 1960 to 42.7% in 1974. In response to the 1973 oil embargo, the post-embargo oil price increases and national energy legislation, these trends have begun to change. Table 1-3 showed what appears to be the start of an increase in the market share of coal at the national level. Recent legislation, including the Energy Supply and Environmental Coordination Act of 1974 and the Power Plant and Industrial Fuel Use Act of 1978, a portion of the Carter Administration's National Energy 1-13 2JO0. 2POO IPOO 11800-- 11700 - TOTAL GENERATION HYDROELECTRIC 11600 - OTH Ig500 11400 1;5 00 11260 19100 NUCLEAR NATURAL GAS 1POO - 900-- PETROLEUM 0 Boo 700 COAL GOO, 500 400 300 200 100-- 0 1960 1965 1970 1975 1977 Pigure 1-5. U.S. electric power generation fuel mix, 1960-1977 Table 1-4. Change in electric generation fuel mix, by region, 1960-1985 Percentage of Total Generation for Region Region 1960 1974 1985 Coal Oil/Gas Nuclear Hydro Other Coal Oil/Gas Nuclear Ilydro Other Coal Oil/Gas Nuclear Hydro Other New England 50.3 31.7 0.1 17.9 - 7.4 61.3 24.4 6.9 - 26.8 28.4 41.0 3.9 - Middle Atlantic 69.3 18.S 0.2 12.0 - 42.7 36.2 8.5 12.6 - 47.9 13.6 29.9 7.3 1.2 Fast North Central 93.5 3.8 0.2 2.S - 82.0 8.7 8.3 1.0 - 66.4 5.8 26.3 0.6 1.0 West North Central 40.3 46.9 - 12.6 0.2 54.4 27.2 7.7 10.7 - 70.1 4.9 17.2 7.7 - South Atlantic 66.3 20.2 - 13.5 - 54.9 32.5 7.4 5.2 - 52.6 10.3 32.0 7.3 1.2 Fast South Central 74.S 5.5 - 20.0 - 76.5 5.4 3.6 14.5 - 50.8 4.5 37.3 7.4 - West South Central - 95.7 - 4.3 - 3.0 92.6 0.2 4.2 - 20.6 55.3 22.8 1.4 - Mountain 11.8 36.6 - 51.6 - 46.3 23.2 - 30.5 - 48.7 16.9 14.9 is.2 3.7 Pacific - 42.0 - 58.0 - 1.7 27.8 2.8 66.7 1.0 4.7 19.9 10.2 62.2 2.5 Nation 53.5 27.1 - 19.3 - 44.5 33.2 6.0 16.1 0.1 4S.4 16.1 26.1 11.5 1.0 Plan, is intended to reinforce this trend. This legislation permits the Department of Energy to require utilities and other large users to convert boilers from oil to coal, and to require that new boilers be fueled by coal. The Congressional Budget Office (CBO), in its review of President Carter's proposed energy legislation, projected that U.S. domestic use of coal would increase from 681 million tons in 1976 to 1,066 million tons in 1985 under current national policy and price estimates, and to 1,229 million tons in 1985 under the President's proposals (6). Table 1-5 summarizes these projections, which are based on estimates of the growth in the demand for electricity. According to the CBO estimates, the National Energy Plan is not likely to produce major changes in 1985 coal use by electric utilities. The data in Table 1-4 also include projections of the future fuel mix used by the electric utilities in each region of the country. The projections were prepared in 1976 by the Federal Energy Administration, and are based on a complex set of assumptions concerning future fuel availability and prices, and the economic and physical ability of utilities to respond to the changing fuel conditions. Nationally, those projections indicate a large relative shift away from oil-fired generation towards nuclear, with a relatively constant coal share. For the Mid-Atlantic region (which includes Maryland), where the use of imported oil is extensive, the relative shift away from oil is antici- pated to be substantial, with significant increases in the shares of coal and nuclear generation. Table 1-6 presents the additions to total generating plant projected by more recent forecast (7). The forecast is the National Electric Reliability Council's (NERC) summary of the generation expansion plans of the U.S. electric utilities for the next 10 years, summarized by electric utility region. The two NERC regions which include Maryland are MAAC and ECAR. The projections shown in Tables 1-4 and 1-6 contain important policy implications. It is now national policy to encourage and require the use of coal and nuclear power to replace oil. The NERC compilation of utility expan- sion plans shows a shift away from oil and gas generation in favor of nuclear and coal generation. At both the national and regional levels, however, the shifts projected by the utilities in NERC (Table 1-6) are not as pronounced as had been anticipated by the FEA (Table 1-4). The major reason for the much smaller shift away from oil and gas projected by the NERC utilities is the smaller amount of planned new nuclear and coal generating capacity. This results in a significantly higher share of generating capacity being born by oil and gas than assumed by FEA. This difference is even greater in the NERC regions which include Maryland than they are in the country at large. The differences between the fuel mix projected by the FEA and the fuel mix reflected in current construction plans reported by NERC can be explained to a great extent by the difficulty of altering basic plant designs for plants actually under construction or in advanced planning. However, for plants in the early planning stages, utility generating planners can respond fully to new economic and regulatory policy considerations. As will be discussed in more detail for Maryland later in this chapter, capacity additions during the 1988-1997 time period are expected to fully reflect these changes, and show very pronounced changes in the generation fuel mix. 1-16 Table 1-5. Projected U.S. coal consumption Consuming Sector 1976 Projected Use, 1985 Current Policy Nat'l Energy Plan Residential/Commercial 6 2 2 Industrial 156 206 360 Electric Utility 459 768 777 Export 60 90 90 TOTAL 681 1,066 1,229 1-17 Table 1-6. National and regional generation expansion plans, 1977-1987 NERC Region* Coal Oil Gas Nuclear Hydro Punped Storage 1977 1987 1977 1987 1977 1987 1977 1987 1977 1987 1977 1987 ECAR 81.8 74.S 9.6 7.5 1.1 0.7 3.3 13,7 0,7 0.5 3,3 2.8 ERCOT 11.3 35.8 0.2 03 87,8 S2,9 0.0 10,7 0.6 0.4 0..0 0.0 M@w 34.2 31.8 46.3 36.4 0.S 0.4 14,0 27.0 2.1 2.0 2.9 2.2 MAIN 67.1 5S.9 12.4 14.9 0.6 0.2 16.2 27,2 1,2 018 2.3 0.9 MARCA S2.1 65,7 15,6 1110 1.4 0.7 17.1 14,3 13,8 8.3 0.0 0.0 NPCC 7.4 10.5 61.6 50.9 <0.1 <0.1 ls'o 28.8 10.6 S.6 S.2 4.3 SERC SO.4 43.6 26.2 17.9 0.2 0.1 13.0 28,8 9,5 6,3 0.7 3.3 SPP 11.9 40.6 12.8 7.9 67.9 35,6 1.9 12.5 4.9 2.7 0.7 0.6 WSCC 18.2 23,3 32.8 23,8 2.9 2,7 2.8 15,9 41.3 30.4 1.3 2.6 NATION 39.2 42,7 25.5 18.3 13.1 7.8 8.4 20,0 11.7 8,4 1.9 2.3 NERC regions are generally defined as follows: 00 ECAR - Western Maryland, Pennsylvania, and Virginia, Ohio, West Virginia, Kentucky, Indiana, Michigan MAAC - Maryland, Pennsylvania, New Jersey, Delaware ERCOT Central and Southern Texas MAIN - Missouri, Illinois, Wisconsin, Northern Michigan MARCA North and South Dakota, Uinnesota, Iowa, Nebraska; Manitoba NPCC - New York, New England; Ontario, New Brunswick SERC - Eastern Virginia, Tennessee, North and South Carolina, Mississippi, Alabama, Georgia, Florida SPP - Kansas, Oklahoma, Northern Texas, Arkansas, touisianna, Western Mississippi WSCC - Montana, Wyoming, Colorado, New Mexico, and all states further West; British Columbia The likelihood of attaining the projected shifts in production patterns shown in Table 1-4 and even Table 1-5 is open to some question. Utilities have postponed or cancelled many of the nuclear units assumed in the projections in Tables 1-4 and 1-6. The data show a drop-off in the number of new nuclear plants coming on line (Table 1-7), and the number of new units ordered has shown a similar decline (3). Part of. the dro P-off in new plants and new orders can be explained by the falloff in electric power demand during the 1974-1975 recession and to the sub- sequent rate of growth in the demand for electric power. In response to levels of demand for electricity which were lower than anticipated, many utilities slowed construction schedules or postponed the startup of new construction. In addition however, part of the drop-off in the rate of addition of new nuclear units stems from uncertainty on the part of utilities about such national policy issues as nuclear waste disposal (see Chapter IV). If the trend in Table 1-7 continues, it is likely that the national share of generation coming from nuclear power in 1985 and 1990 will be lower than anticipated, and the share from coal and oil correspondingly higher. (The 1978 ten-year capacity and demand forecast prepared by Electrical World (8), a major trade journal, reaches a similar conclusion, and projects an even lower nuclear power share of 18% in 1987.) It is also likely that the national share of generation coming from coal- fired generating units will be lower than anticipated. Some of the coal-fired capacity assumed in Table 1-4, and even in Table 1-6, has been postponed or cancelled in response to levels of demand and rates of demand growth that are lower than had been anticipated. Projections of trends in future fuel mixes are based on projections of future growth in electric power demand, as well as of energy policy, fuel supply, and price trends. National projections of electric energy demand have been made by a number of forecasters representing government, private corpora- tions, and independent consultants. While the estimated growth rates differ, the projections uniformly show a significant reduction in the growth rate, from the more than 7% annually that prevailed in the years from 1945 through 1973. Table 1-8 show the results of a number of these forecasts, most of which were prepared in 1976 and 1977. Projections of future demand at the national level have continued to de- cline as more experience with higher energy prices has accumulated. Regional electric reliability councils include ten-year forecasts in their annual sub- missions to the Federal Power Commission. Figure 1-6 shows the declines in each successive forecast since the 1973 embargo (9). These forecasts are derived from projections made by each of the nation's utilities, and they vary signifi- cantly in the forecasting methodology used. The changes in forecasts shown in Figure 1-6 indicate the degree of uncer- tainty which has affected recent utility planning, making national forecasting more difficult. From these utility capacity and demand forecasts, however, it is quite clear that the demand for electric power at the national level is expected to grow, although at a slower rate than in the past, and that the generating equipment used to meet this demand is likely to rely less on oil and more on coal and nuclear power than in the past. The reduction in the 1-19 Table 1-7. U.S. nuclear power capacity expansion Year Units Added Capacity Added, MW 1965 1 16 1966 1 907 1967 - 1 - 35 1968 0 987 1969 3 1,310 1970 3 1,048 1971 5 3,322 1972 5 4,556 1973 9 8,121 1974 9 9,649 1975 10 8,878 1976 3 2,561 1977 8 5,884 1-20 Table 1-8. Comparison of annual growth rates in U.S. electricity constmption (%/)rr)* Forecast Demand Starr SR-37 EEI NIP DRI FEA IEA EPP MPPS NERC- 77 FPC 1975-1980 High 7.9 6.7 8.4 6.1 6.2 6.3 6.3 5.4 6.8 4.1 Medium 6.9 5.5 7.4 6.1 S.S 6.6 5.4 3.3 6.7 LOW 6.9 4.7 6.1 5.5 4.S 6.1 5.2 4.4 3.0 3.2 1980-1985 High 6.8 6.7 7.2 6.6 6.2 5.6 6.3 S.3 6.8 4.1 Medium 6.0 5.5 S.3 5.4 5.S 5.6 S.4 3.3 6.2 LAW S.S 4.7 3.2 4.3 43 5.6 5.2 4.4 3.0 3.2 1985-1990 High 6.1 6.7 5.6 S.S 4.9 6.4 4.3 5.0 4.1 Medium S.3 S.S S.0 4.6 4.7 5.7 2.4 S.S low 43 4.7 2.8 3.S 4.9 S.3 2.9 1.7 3.2 1990-199S High S.8, 6.7 5.6 5.5 6.4 4.3 S.0 4.1 Medium 4.8 5.5 S.0 4.6 5.7 2.4 5.5 LOW 4.3 4.7 2.8 3.5 5.3 2.9 1.7 3.2 1995-2000 High S.7 6.7 S.6 4.3 5.0 4.1 Medium 4.6 5.5 5.0 2.4 LOW 4.1 4.7 2.8 2.9 1.7 3.2 Demand 77 Larry J. Williams, et al., Demand 77, EPRI Annual Energy Forecasts and Consumption Model, EA-621-SR (Palo Alto, Calif.: Electric Power Research Institute, 1978). Starr Chauncey Starr, "Electricity Needs to the Year 2000," presented to the Subcommittee on Energy Research, Development, and Demonstration; [buse of Representatives Cammittee on Science and Technology; Washington, D.C., 1976. SR-37 Larry J. Williams, A Preliminary Forecast of Emergy Consumption Through 1985, SR-37 (Palo Alto, Calif.: Electric Power Research Institute, 1976). EEI Edison Electric Institute, Economic Growth in the Future (New York: McGraw-Hill, 1976). NFP Mitre Corporation, Need for Power (NFP) Study, Interim Report, prepared for U.S. Energy Research and Development Administration, Washington, D.C., 1977. DRI Data Resources, Inc., Energy Review, Summer 1977 (Lexington, Mass.: Data Resources, Inc. 1977). FEA Federal Energy Administration, National Energy Outlook (Vashington, D.C.: U.S. Government Printing Office, February 1976). IEA Institute for Energy Analysis, Economic and Environmental Impacts of a Nuclear Moratorium, 1985-2010 (Oak Ridge Associated Universities, September 1976). EPP Energy Policy Project of the-Ford Foundation, A Tim to Choose (Cambridge, Mass.: Ballinger, 1974). MOPPS Energy Research and Development Administration, Market Oriented Program Planning Study, Review Draft (Washington, D.C., 1977). NERC-FPC Projections of the National Electric Reliability Council and the Federal Power Commission, as reported in NFP (see above). *Growth rates are repeated from one five-year period to another where they have only been reported for longer periods. 900 Boo AVERAGE ANNUAL' GROWTH RATE 700 1974 PROJECTION 7.4 % 1975 PROJECTION 6.6% 600 1976 PROJECTION 6.2% 1977 PROJECTION 5.9% 00@ z 500 w 400 300- 1977 1978 1979 1980 1981 1982 1985 Figure 1-6. '1974-1977 projections of peak demand by U.S. electric utilities reliance on oil in favor of coal and nuclear power will be less than had been anticipated by government planners at the Federal level. C. Maryland: Energy The demand for and supply of energy in Maryland are driven by the same factors that affect national energy use and supply patterns. Those factors work through the set of conditions that uniquely define the State of Maryland and the Maryland economy. Factors such as the cost of transportation for alter- native fuels, the composition of state industry, the age and construction of homes, and the relative level of personal income all influence the way in which Maryland consumers and industries use energy and types of fuels selected to meet those energy needs. The resulting pattern of energy demand and supply, while strongly influenced by national trends, is unique to Maryland and must be evaluated at the state level. Table 1-9 and Figure 1-7 present energy flow data for the U.S. and Maryland for 1974, the most recent year for which comparable data are avail- able (10). As can be seen from the table, there are major differences in gross energy supply and conversion between Maryland and the nation at large. The principle and most striking difference is the proportionately large share of total energy coming from oil in Maryland. The important role of oil is seen both in gross energy input for all uses and in the mix of fuels used by Mary- land utilities. In both cases, Maryland oil usage is considerably higher than that of the nation as a whole: the proportion of gross oil usage is 36% higher in Maryland than in the nation, and the proportion of oil used in electric generation is almost 240% higher. The importance of oil usage in Maryland is based on the ready availability of formerly inexpensive foreign oil, the dis- tance of population centers from large coal fields and the resulting relatively high transportion costs, and the air pollution problems that exist in Maryland's extensive urban and suburban areas. D. Maryland Utilities: Past Trends and Future Projections Public utilities are required by the terms of their franchise to meet customers' demand for electric power. The instantaneous demand for electric power varies by time of day, the day of the week, and by season. In addition, the demand for power exhibits a long-term trend of growth, interspersed with infrequent declines. In order to fulfill the service requirement, utilities must formulate generating expansion plans well in advance. Recent estimates indicate that it may take 8 to 10 years to bring a major coal-fired power plant on line, and up to 13 years to bring a nuclear plant on line. As a result, utilities must plan for changes in capacity over a period significantly in excess of 10 years* The Regional Electric Reliability Councils require that member utilities submit 10 and 20 year generating plans and forecasts, and the Maryland Public Service Commission requires the annual submissions of a Ten- Year Plan (see Appendix A). There are several important concepts necessary to an understanding and evaluation of the long-range generation expansion plans of Maryland's electric utilities: 1-23 Table 1-9. Energy Flows, 1974. Entries in percent of gross energy input: U.S., 72.67 x 1015 BTU; Maryland, 1.23 x 1015 BTU U. S. CROSS INPUTS ELECT111r, CONVMSION TO END tTSERS To Electric Electric To Household TO To Source Input Generation Output Source Input & Commercial Industry Transportation Nu0par 1.7 1.7 Electric 8.8 5.1 3.7 0z Hydro 4.5 4.5 coal 17.7 11.7 Coal 6.1 0.4 5.7 Gas 29.9 4.8 8.8 Gag 25.1 W. 4 13.8 .9 Petro- Petro- leurn 46.1 4.8 leum 40.9 8.4 8.1 24.4 TOTAL 100.0 27.5 8.8 81.0 Z4.4 31.3 25.4 Unaccounted for (petroleum) - 0.4 In industry sector 0.15 and 4.87 percentage points of coal and petroleum, respectively, go into non-fuel use (chemical feed stock) Electric conversion efficiency - 8.82/27.52 x 100 = 32.1 percent Electric energy is 10.9 percent of end user supply Totals may not check because of independent rounding Maryland GROSS INPUM MUCTRIC CONVERSION TO END US M. Source Input To Electric Electric Source Input To flomehold TO TO Ceneration output I Commercial Industry Transportation Nuclear 0 0 Electric 9.9 6.1 3.8 0.06 1 lyd ro 1.2 1.2 Goal 19.1 9.1 9.9 Coal 10.0 0.1 9.8 0 fins 16.8 1.1 Gas IS.7 10.4 4.1 0.20 Petroleum 62.9 16.3 Petroleum 46.S 16.0 5.1 26.40 IDTAL 100.0 27.6 9.9 82.0 32.7 22.8 26.6 Waccounted for and miscellaneous 0.3 Electric conversion efficiency 9.92/27.64 35.9 Electric energy is 12.1 percent of end user supply Totals may not check because of independent rounding W M M U. S. Hydro Nuclear Electric Wa coal Conversion Household . . . . .. . . . . .. .. ..... Commercial . ......... S4 Wg-m> N' Industry Maryland Electric @Waste conversion Household g & Commercial I ndu .1 . . . . . .. . . . . . . Transportation Figure 1-7. Energy flows, 1974 percent distribution 1-25 � Demand is the amount of electric power required by customers at any given instant in time, usually stated in megawatts (MW) or Kilowatts (W). One kW is the amount of power needed to light ten 100 watt light bulbs, and a megawatt is 1,000 kilowatts. � Energy is the amount of electric power consumed over a period of time, usually stated in kilowatt-hours (Wh). One kWh is the amount of electricity required to light ten 100 watt light bulbs for one hour, and a megawatt hour (MWh) is 1,000 kilowatt-hours. � Peak Demand is the maximum demand experienced during some time inter- val, such as a day or year. Peak demand in the following tables is the average power used over the 60 minute period of heaviest demand during a given year. Electric power demand varies significantly over a day, week or year, as shown in the one-day "load curve" in Figure 1-8. Peak demand for that load curve is approximately 8,500 MW. � 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)* 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. � Reserve Margin is the difference between system maximum capacity (MW) and maximum system load, divided by the maximum system load, for any given moment in time. The most commonly used reserve margin is de- fined at the time of the system peak demand: RMp = SCp - SDp SDp where: RMp = system peak 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, and are used over the period indicated by "A" in Figure 1-8. Load factor computation is based on system energy output defined to include system losses. 1-26 9000 0000 C PEAKING GENERATION 7000 ------ -- ------ . . ......... . . ........................... . ......... . ...... 6000 .. . .... . ........ . ... . .. .......... . . . . ..... . . ...... . ...... . . B CYCLING GENERATION.H.01. ...................I......... ..... ... .................................. ......................... .. . ............. ................... . .... ... .................... % % ........... ........ .......... ...... %.......... . ....... ... ...................... .......................... 4000 ......................... . %..... . X.: X.- .................................... .............. ........ ................. .......... ...................................... %.% .............................. ... .......... .......... .......................... z .. ................ ............. e... ... .......... %. ......... ... ....... . .... .... . . . 3000 ............... ............... ................. %% . . ............... ....... . . .......... .............................................. w ..... ............... ........... ............. . .. ........... X. A BASELOAD .............. .. :::-*:*:*: ..................... ...... ................... ................. : ................ ....... .. ........ GENERATION ...... ............................ Z600 .... ... ............... ............ ............... ................... . ................ .......... ............. .......... ....... Y x % .................. % ....... ..... . .................... . . ......% ..................................... ............... ......... . .... .... ... ........... X .............. X. 1000 ..... .......... ............. .. ......... .... % ......... ............ . ..... ........................ NX * X .......... ...:..... ......... . ... . . .. ....... .................. ............. . ............. % . ............. .............. .............. ...... .. % 0 .......... ......... 2400 0200 0400 0600 0600 1000 1200 14W 1600 1800 2000 2M 2400 TIME Figure 1-8. Hypothetical daily load curve kTION e--- ks 1-27 � 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. They are generally used in the periods indicated by "B" in Figure 1-8. � 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. Efficiency is less important than on-off cycling ability and low capital cost because of the extensive portion of the year during which these plants are idle. They are operated during period "C" in Figure 1-8. The demand for electricity exhibited a remarkably steady growth from the period after World War II through the early 1970's, except for brief periods of slower growth or slight declines during economic recessions. During the period from 1963 to 1973, for example, the annual growth in electric energy used was 7.5% nationally, and 9.7% in Maryland. Figure 1-9 shows the sudden change in this pattern of growth which followed the 1973 oil embargo and the subsequent explosive rise in energy prices (8,11).* The rapid energy price increase and the sharp recession which accompanied them produced a 0.1% decline in electric energy use nationally in 1974, and only a relatively slight 1.9% increase in 1975. In Maryland, where imported oil made up a greater share of both the total energy and the electricity utility fuel mix than in the nation generally, the change in the growth in electric energy use was even more drama- tic: electric energy use declined by 2.8% in 1974, and grew by only 1.0% in 1975. Not until 1976 did electric power use in Maryland exceed what it had been in 1973. By 1976 growth in electric power use had clearly resumed. Peak demand shows a similar pattern. Table I-10 shows the pattern of growth in electric power use in Maryland for 1963 through 1977. In the most recent period, covering the years 1976 and 1977, growth in electric power use appeared to indicate a significantly slower rate of growth than in the period prior to 1973, dropping from a 9.7% annual growth rate to 7.4%. In 1977, energy sales nationally grew by 4.3% (see Table 1-3), and peak demand grew by 7.1%, very close to the long-term average. In Maryland, energy growth was 5.9%, and noncoincident peak demand grew by 11.9%.** What is an apparent resumption of prior growth experience must be evaluated carefully, however. The 1977 growth occurred in a year in which both the national and Maryland economies were rapidly recovering from one of the longest and deepest recessions in recent history, and in which most of the contiguous United States experienced record and prolonged July beat. In the period before 1973, these conditions probably would have resulted in national peak demand growth of approximately 10%. The 1977 experience would appear to lend support From 1973 to 1975, the price of imported oil, adjusted for general inflation, rose by 184%, total oil prices (including both domestic and imported oil) by 111%, and coal prices by 88% (12). See also Table 1-18, at the end of this chapter. 1-28 U. S. 2000- -40 CD 4A C 1500- 30 Ma @ry I a nd z 4A 1000- 20 z cc 500 -10 62 64 66, 68. 70 72- 74 76 Maryland G C r= CD 400- -8 U. S. 300 6 V% U6 - CA 200 - -4 tA iE z loo- -2 62 64 66 68 70 72. 74 76 - Figure 1-9. Maryland and U.S. electric energy sale, 1962-1977, Maryland and U.S. electric energy peak demand, 1962-1977, respectively y1and 1-29 Table I-10. Electric energy sales in Maryland, 1962-1977* Maryland llions of kWh) Year Residential Non-Residential Total 1962 3,145 6,879 10,024 1963 3,425 7,491 10,916 1964 3V789 8,307 12,096 1965 4P229 9,081 13,310 1966 4,792 lOp220 15,012 1967 5,196 11,209 16,405 1968 5P990 12,268 18,.258 1969 6,700 13p497 20,197 1970 7,483 15,004 22,487 1971 7,919 16,311 24,23-0 1972 8,406 17pOO5 25,411 1973 9,330 18,270 27,600 1974 9p2OO 17,910 277110 1975 9,598 17,859 27,457 1976 10,064 19,837 29,901 1977 10,718 20,935 31,653 Data from Appendix B 1-30 to forecasts, such as those in Table 1-8, which project a significant reduction in the growth rate in electric power use nationally. Part of the explanation for the changes in electric energy use that have occurred since 1973 can be found in the changes in energy prices that have occurred since that year -- which also served as a major cause of the accompanying recession. The dramatic fuel price increases of 1973-1974 re- sulted in significant increases in the price of electricity, as shown in Table I-11 for Maryland (13). The more recent years from 1975 to 1977 experienced far more moderate price increases in electricity (also shown in Table I-11), and have been accompanied by a resumption of growth in electric power usage. As the data in Table I-10 and Figure 1-9 show, recent experience indicates a resumption of growth in electric power use in Maryland. In order to meet that growing demand for electricity, utilities and government agencies must project future levels of demand and develop an appropriate generation expan- sion plan. The Maryland Power Plant Siting Act requires that each utility file annually with the Maryland Public Service Commission a Ten-Year Plan showing a forecast of peak load for each of the next ten years, plans for changes in generating capacity and transmission lines, and possible and proposed power plant sites (14). The Public Service Commission compiles these filings into an annual Ten-Year Plan of Maryland Electric Utilities. The 1978 Ten- Year Plan, as amended is included in this report as Appendix A. Figure I-10 shows the growth projections of each of the successive Plans as well as updates of those projections presented in cases currently before the Maryland PSC (15). These projections, which are compiled directly from the forecasts prepared by the individual utilities, have experienced a pattern of successive reductions in projected growth rates similar to the forecasts reported nationally by the Regional Reliability Councils to the Federal Energy Regulatory Commission (see Figure 1-6). Projected average annual growth rates in peak demand for the State have declined with each successive report, from the 9.4% rate reported in the 1973 Plan to the 4.5% rate reported in the 1978 'Plan, The most recent projections, taken from cases currently before the Maryland PSC show a growth rate of 4.0%. Neither the filings by the Maryland utilities nor the Commission's Ten- Year Plan contain any description of the forecasting methods used, supporting documentation, forecasts disaggregated by customer class, or a forecast of energy consumption. However, some of these issues have been explored by the ommission in a case intended to evaluate the adequacy of the utilities' long- range plans (16). Testimony presented by the Maryland utilities in that case C indicates that each utility takes a different approach to forecasting. While some of the Maryland utilities use a simple extrapolation of historical trends modified in some way by the judgement of the utility forecaster, others have begun to use a more sophisticated statistical or "econometric" approach. Over the past two decades, a number of sophisticated techniques have been developed to forecast the future demand for electric power. These approaches utilize statistical or mathematical models to determine the effects of relevant factors on electric energy usage based on historical data. Factors 1-31 Table I-11. Electrical bills in Maryland, 1971-1977, in current dollars Year Residential(a) Commercial(b) Industrial@c) Bill % Change Bill % Change Bill % Change 1970 11.63 -- -- -- 1971 12.33 6.0 52.07 -- 1,259 -- 1972 13.83 12.2 59.05 13.4 1,425 13.2 1973 14.83 7.2 62.75 6.2 1,543 8.2 1974 16.08 8.4 66.42 5.8 1,684 9.1 1975 21.97 36.6 85.44 28.6 2,386 41.7 1976 22.08 0.5 88.29 3.3 2,346 - 1.7 1977 22.78 3.2 92.15 4.4 2,454 4.6 ------------------------------------------------------------------------------ 1971-1973 20.3 20.5 22.6 1973-1975 41.1 36.2 54.6 1975-1977 3.7 7.8 2.8 (a) State aver age bill for 500 kWh per month on January 1 (b) State average bill for 1,500 kWh per month at 12 kW on January 1 @c) State average bill for 60,000 kWh per month at 300 KW on January 1 1-32 191poo- 1973 PLAN (9.4!/,) ispw- 1974 PLAN (760/6) 17POO- t6IOOO, 1975 PLAN (5-90/6) 1976 PLAN (@30/0) 11@000 1977 PLAN (6-10/6) 14POO- 1976 PLAN (4-4,0/*) UPDATED ISPOO FORECASTS C4.00/6) 123000 z CI IIPOO- IOjOOO 91000- 8000 1973, 1974 1975 1976 1977 IR78 1979 1980 1981 1982 1983 1984 1985 1986 1987 Figure 1-10. 1973-1978 projections of peak demand by Maryland electric utilities incorporated in these models usually include the price of electricity and alter- native fuels, personal income, industrial production, weather, and population. The models have the advantage of explicitly and quantitatively identifying the relationships between the appropriate factors and the demand for electricity (17). In conjunction with the Department of State Planning, the Power Plant Siting Program has prepared forecasts for two Maryland utilities (BG&E and PEPCO) as part of a program designed to prepare independent forecasts for all of the major generating utilities. Forecasts for the Allegheny Power System and the Delmarva Power and Light Company will be completed in 1979. The econometric forecasts prepared for PEPCO and BG&E are included in the full state forecast prepared by the Department of State Planning and included in this Report as Appendix B. Table 1-12 presents the energy and peak demand forecast from the Depart- ment of State Planning for the years through 1987. As shown in the last line in Table 1-12, total electric consumption in Maryland is expected to grow by 5.07% annually over the next ten years. Peak demand for the State is expected to grow by 3.33%. While this growth rate represents an increase from the 2.57% anticipated for the 1977-1980 period and from the negligible growth experienced during the 1975-1977 period (see Table 1-18 at the end of this Chapter and Table B-5g of Appendix B), it represents a significant reduction from the 9.3% annual growth rate experienced from 1966 to 1972. Table 1-12 also includes a column showing an estimated load factor for the State as a whole. A state-wide load factor is not appropriate for planning purposes, since capacity decisions are made separately by each utility. The State load factor is included here only as a general indication of likely over-all trends in capacity usage. As can be seen from the Table, growth in energy consumption is expected to exceed the growth in peak demand over the 1977-1987 forecast period. The implication of this relatively slower peak load growth, and the accompanying improvement in the load factor estimate from .38 to .45 over the same period, is that on a statewide basis, power plant capacity of the Maryland utilities will be more fully utilized than it is now. Should system demand forecasts indicate that this trend will continue, then the State may require future expansion of relatively more efficient base-load capacity.* This conclu- sion will be more fully explored below. Figure I-11 shows the demand forecast for each of the Maryland utilities reported in the Department of State Planning report in Appendix B. The figure shows the noncoincident peak demand for each utility, and accumulates them for a state total. System reliability considerations require that each utility possess generating capacity in excess of its projected peak load at any given moment in time, as a margin of safety in the event that system load is greater than forecast, or in the event of an unanticipated unit outage. The reserve margin Capacity planning decisions are made on the basis of an analysis of alter- native generating plan options on electric utility revenue requirements. 1-34 Table 1-12. Projected energy sales and peak demand in Maryland, 1977-1987 (a) Year Energy Peak Demand (MV) State Load Factor(b) Residential Non-Residential Total 1977 (actual) 10,717,522 20,934,984 31,652,506 9,438 0.38 1980 11,989,620 24,857,772 36P847,392 10,186 0.41 198S 15,625,985 31,541,607 47,167,592 12@179 0.44 1987 17$392.9838 34,494,714 51,887,552 13,098 0.45 Average Annual Growth Rates 1977-1980 3.81 5.89 S.20 2.57 1980-1985 5.44 4.88 5.06 3.64 1985-1987 5.50 4.58 4.88 3.70 1977-1987 4.96 5.12 5.07 3.33 (a) Data from Appendix B (b) The load factor estimates produced here are conputed on the basis of energy sales, rather than on the basis of system energy net of losses (1het energy for load") properly used to conpute the load factor of an electric utility. 15- -26 -18 24 -16 MARYLAND PEAK +.15% -22 -14 20 U1% MARYLAND -18 10 - 12S -16- -10 14 PEPCO U- z U- 8 CL 5 POTOMAC ED I -8 6 -4 S EASTON & CONOW INGO BG &E 2 -2 1975 1980 1 V85 Figure I-11. Peak demand forecast for State of Maryland, 1977-1987 M M M M required by reliability council or power pool agreements varies for each utility, and is a function of the operating record of the utility's generat- ing plant and the extent of its interconnections with other utilities, as well as a function of the level of demand. For planning purposes, the desired level of reserve capacity is usuallv considered to be from 15% to 20% above peak demand. A 15% reserve margin has been applied to the State peak demand in Figure I-11, and the total capacity required to meet Maryland's peak demand and reserve requirements shown in the top line of Figure I-11. For comparison, the right- hand scale of the Figure shows the number of units the size of Calvert Cliffs (845 MIJ nuclear) or Morgantown (575 MW coal) that are equivalent to this level of generating capacity. By 1987, Maryland's peak demand is forecast to be the equivalent of 15.5 Calvert Cliffs units or 23.2 Morgantown units. With a 15% reserve margin, the total generating requirement is the equivalent of 17.8 Calvert Cliffs units (an increase over present capacity of 3.3 units) and 26.2 Morgantown units (an increase of 5.8 units). Table 1-18 at the end of this Chapter contains a set of tables which present past data and future projections by both the Power Plant Siting Program and the utilities themselves for each Maryland generating utility* The tables include residential, non-residential, and total energy consumption, and peak demand for each vear from 1966 to 1987, as well as annual, 5-year, and 10-year growth rates for each. Table 1-19 also includes data on generating capacity, load factor, and reserve margin. Table I-1 provides data on imports and exports of power by Maryland utilities for each year from 1966 to 1977. F. Marvland Utilities: Capacity Trends and Plans The total generating capacity of power plants located in Maryland is 8,633.5 MTJ, an increase of 913.5 MW over that reported in the 1975 CEIR. In addition, 594 M14 of capacity is owned by BG&E as part ownership of two Pennsylvania plants, Keystone and Conemaugh, owned principally by Philadelphia Electric. A further 1,969 M14 of capacity located in the District of Columbia and Pennsvlvania is owned by PEPCO, including part ownership of the Conemaugh plant. The locations of the operating plants and proposed sites for future plants are shown in Figure 1-12. The table which accompanies Figure 1-12 gives the capacity and, fuel type, for each plant. Where more than one fuel type is used for a single plant, the larger component is listed first (i.e., oil/coal indicates that a mixture of oil and coal is used, but oil represents the larger amount of fuel). Table 1-19 at the end of this chapter provides the capacity ratings of each of the existing and planned units of the plants owned by Mary- land utilities, including the plants located outside of the State. Table 1-19 also indicates the fuel type for each unit. The data shown in Table 1-19 at the end of this Chapter indicate that the newer generating units constructed in Maryland have tended to be larger than their predecessors, and they are most often designed as base-load units. The rates of growth in demand over the past ten years, and the improvement in load 1-37 23 21 22 12 21 13 0 ---"4 28 Existing Plants for Maryland (9) No IQ A (Capacity in MW) Plant Name Utility Steam Gas Fue 0 Turbine Steam it m 1 Benning Road PEPCO 679 Oil 2: Brandon Shores BG&9 1,220 Oil 3 B zzard Point PEPCO 222 252 Oil 4.Cu 3 C:!vert.Cliffs BG&E 1,620 Nuclear 5. lk P int PEPCO 1,262 48 Coal/Oil It% 6.C,p, Crane BG&E 384 14 Oil 7 Crisfield DELMARVA 10* 8: Dickerson PEkO 547 13 Coal 9 Easton EASTON 33* 10: Gould Street BGSE 103 Oil 11. Morgantown PEPCO 1,112 248 Coal/Oil 12. No tch Cliff BGSE 128 2i 13' Perryman BG&E 204 14. Philadelphia Road BG&E 64 H 15. Potomac River PEPCO 458 coal 24 1 16. Riverside PEPCO 321 172 Oil U., 17. R.P. Smith POT.ED. 129 Coal 00 18. Vienna DELMARVA 224 17 Oil 19. Wagner BG&E 988 14 Oil/Coal 20. Westport BG&E 177 lie Oil 25 Diesel units %% Plants for Out-of-State Utilities(A) Sites Discussed for Future Plants_.QDj 21. Bainbridge 22. Chesapeake City 23. Conowingo 24. Douglas Point 25. Elms 26. Mount Storm (VEPCO) 27. Possum Point (VEPCO) 28. Summi t Figure 1-12. Location of electric power plants in the Maryland region the proportion of generation coming from these units with lower operating cost. Technological improvements in generating systems have resulted in lower operating costs for larger units operated over a longer period of the duty ycle. As a result, base load units tend to be larger than other units, and they generate electricity at substantial cost savings. c Given the cost characteristics of base load plants, there are two condi- tions in which it is generally desirable to add base load capacity rather than cycling or peaking units. If base demand ("A" of Figure 1-8) is growing rapidly enough, the most appropriate plant expansion can be a base load unit even if demand in the non-base load periods ("B" and "C" of Figure 1-8) is growing more rapidly and the system load factor is declining. The precise point which determines the relative desirability of base-load versus cycling capacity is determined by factors which include the relative and absolute rates of demand growth during the three time periods (i.e., the change in the shape of the load curve), the operating costs of new units, and the operating costs of existing base load units if they were switched to cycling capacity. Base-load capacity is also desirable when the system load factor is improving and base-period growth is occurring more rapidly, filling in the demand "valleys." Under those circumstances, the choice is most likely to be base-load. Depending on the cost reduction that results from improved techno- logy, and assuming no differences in environmental and other impacts, it is quite possible that a system whose load factor is improving rapidly enough may be justified in adding base-load capacity even in the absence of peak load growth. Total system energy growth in the period from 1966 to 1972 occured at an annual rate of 9.2% in Maryland, and was accompanied by a slightly higher peak load growth rate of 9.3%. The load factor improvements being forecast for the future indicate that baseload capacity additions may be appropriate in the future, although these additions are likely to be made at a slower pace than occurred in the last ten years. The growth in consumption for the utilities operating in Maryland was accompanied by major changes in the fuel mix used in generation. Table 1-13 shows the changes in generation for the four major Maryland systems from 1960 to 1977 (18).* During that period, Maryland utilities experienced a major change in the annual growth in net electric generation, which dropped from an annual rate of 11.4% for the 1960-1968 period to the 6.7% decline experienced in 1974-1975. At the same time, changing technology, fuel prices, transporta- tion costs, and pollution control requirements led to major changes in fuel mix. The four systems included in Tables 1-13 to 1-15 are the Allegheny Power System, Baltimore Gas and Electric Company, Delmarva Power and Light Company, and Potomac Electric Power Company. Because generating capacity is planned on a system-wide basis by these utilities, rather than for the Maryland portion of their service areas alone, the data in these tables includes the entire systems except at noted. 1-39 Table 1-13. Maryland electricity generation by source, 1960-1977 (millions of kWh and percent of total) Year Total Coal Petr leum. Natural Gas Nuclear f*droelectric 106 kWh 106 kWh % 106 kWh % 106.kWh % 106 kjqh % 106 kWh % 1960 9,316 7*792 83.6 84 0.9 7 0.1 13,433 15.4 1961 9,808 82490 86.6 94 1.0 5 0.1 1)219 12.4 1962 11,013 9)692 88.0 98 0.9 6 0.1 1P217 11.1 1963 12,552 11,404 90.9 114 0.9 8 0.1 1,026 8.2 1964 13,991 12P681 90.6 123 0.9 5 0.1 1)182 8.4 196S 17,361 1SP993 92.1 134 0.8 5 0.1 1.*229 7.1 1966 18,944 17*397 91.8 131 0.7 19 0.1 IP397 7.4 1967 21,020 18)782 89.4 173 0.8 38 0.2 2,027 9.6 1968 22,054 19@614 88.9 707 3.2 45 0.2 11688 7.7 1969 21,514 17,466 81.2 2$156 lo.o 452 2.1 1P440 6.7 41 0 1970 23,594 14.*942 63.3 5.9844 24.8 745 3.2 2PO63 8.7 1971 24$179 133,351 55.2 8,229 34.0 639 2.6 12960 8.1 1972 27,349 11,688 42.7 12,901 47.2 478 1.7 2,282 8.3 1973 27,603 10$188 36.9 14,664 53.1 587 2.1 2P164 7.8 1974 28,821 10,001 34.7 15,989 55.4 862 3.0 1,969 6.8 1975 26)877 9,481 35.3 10,656 39.6 43 0.2 40386 16.3 2 v 311 8.6 1976 31,235 12P885 41.3 9P820 31.4 21 0.1 6,426 20.6 22088 6.7 1977 33,612 11,122 33.1 9,562 28.5 29 0.1 101881 32.4 2)018 6.0 During the 1960-1965 period, 85-90% of Maryland electricity was pro- duced from coal. As late as 1968 that proportion was still 89%. But by 1972, only four year later, the proportion of electricity generated from coal had been cut in half, dropping to 43% -- a reduction much larger than that experienced for utilities nationally. Coal was replaced by oil, which increased during this period from 3% to 47% as a proportion of total generation -- increasing by a factor of 15. This trend continued in Maryland through 1974. By 1975, the introduction of the first nuclear unit as Calvert Cliffs and increased prices for both foreign and domestic oil reversed the increasing share of generation coming from oil. From 1974 to 1977, that share dropped from 55% to 29%, while nuclear power increased from 0% to 32% and the propor- tion of generation using coal remained essentially constant. Table T-14 shows the historic and projected capacity of the utility systems serving Maryland for the 1966-1997 time period. Over the historic portion of this period, from 1966 to 1977, capacity trends followed a pattern similar to the generation pattern shown in Table 1-13. In comparing the two tables, however, the different pattern of use for the major plant types is evident. While in 1977 oil units represented 33.6% of total capacity for Maryland utilities, they provided only 28.5% of total generation. Conversely, nuclear power plants represented only 9.6% of total capacity, but accounted for 32.4% of generation. Because of operating cost characteristics, many of the existing oil units are operated on a cycling or peaking basis, while the nuclear units and most of the coal units are operated as base-load plants. The existing nuclear units tend to have the lowest operating costs of the plants owned by these systems* Future additions to generating capacity for the four Maryland systems are shown in the upper portion of Table 1-14 (19). It should be noted that plans for the 1987-1997 period do not include plant location, and are regarded by the utilities as tentative and subject to change. The plans for the 1977-1987 time period, which includes plants under construction or in advanced planning, maintain the current capacity mix rela- tively unchanged. Plans for the 1987-1997 time frame, which permit a response to recent changes in fuel prices, technology and national energy and environ- mental policies, show a marked reduction in relative and absolute oil capacitY5 and a shift towards nuclear and pumped storage. As noted in the table, a review of nuclear policy by one of the Maryland utilities may lead to an in- crease in the proportion of coal capacity. The lower half of Table 1-14 presents similar capacity data, but does not include capacity additions in Maryland for either the APS or DP&L systems during the 1987-1997 period. Due to the multi-state nature of these systems and the tentative non-site-specific nature of the plans for this period, it is not possible to indicate likely additions to Maryland generating capacity for those systems at this time. Capacity additions by BG&E and PEPCO are assumed to be located in or adjacent to Maryland or the District of Columbia. Therefore, the additions to capacity indicated in the lower half of Table 1-14 represent additions that are likely to occur within or adjacent to Mary- land or the District of Columbia. Current plans call for a 1987 capacity mix within Maryland that is little changed from the present. The small shifts that occur in the mix result 1-41 Table 1-14. Generating capacity by fuel type, 1966-1997, in MW Avg. Ann. CD31 Petroleum Natural Nuclear flydro. PLanped Unknotm Yea r Total Growth Gas - Storage MW I M I I MW MV t ?49 1 MV I MV KV Total for W- ryland Utilities (a) 1966 8,072 8.3 7,147 88.S 177 2.2 40 O.S -- -- 708 8.8 1977 19,307 3.3 10,130 52.5 6,484 33.6 128 0.7 1,8S7 9.6 744 3.7 1987 26,665 14,847 S5.7 7,917 30.0 128 O-S 1,940 7.3 833 3.1 1,000 3.8 -- H 1997 40,640 4.3 19,902 49.0 7,562 18.6 128 0.3 7,025 (b) 17.3 833 2.0 3,290 8.1 1,900 4.7 Total for Existing and Planned Generating Units in Maryland (c) 1966 4,724 8.1 4,068 86.1 -- -- lo 0.2 -- -- 646 13.7 -- -- -- -- 1977 11,076 2.2 3,923 35.4 4,7S9 43.0 128 0.2 1,620 14.6 046 5.8 1987 13,739 2.7 5,098 37.1 6,122 44.6 128 0.9 1,620 11.8 771 5.6 1997 17,984 6,698 37.2 5,567 31.0 128 0.7 2,920 16.2 771 4.3 1,300 7.2 600 3.3 (a) Generating capacity reported is the capacity for the full APS, DG&E, DP&L, and PFPOD systems, Easton, Wei) Creek Lake, and Conowingo. (b) Ilie Allegheny Power System is currently reviewing projected nuclear capacity for the 1987-1997 time period. A reduction in this capacity is likely to result in an increase in coal capacity for the system. (c) Generating capacity reported inlcudes all existing and planned units in Nbryland through 1987. Chily addi- tions by BG&H and PEPOO are included in 1987-1997 additions to capacity. M M M M M M M M M M M M M M from the fact that no new nuclear capacity is planned for the state during this time period and from retirement of older coal and oil units. By 1997, however, Maryland utilities anticipate that retirements of older oil units and the addition of new coal and nuclear capacity and the construction of energy storage systems (either pumped hydro or air) will alter the capacity mix. Oil capacity is expected to decline in absolute amount during that time period. Finally, the capacity projections indicated in Table 1-14 indicate that while the capacity growth rate during the second half of the forecast period is likely to be higher than during the first half, it will remain below the 8.3% annual growth experienced from 1966 to 1977. Capacity growth during the 1977 to 1987 period will remain lower than demand growth as utilities use the excess capacity that currently exists. Over the next twenty years, the projections in Table 1-14 indicate that the four systems plan to add capacity that is equivalent to 25.2 Calvert Cliffs nuclear units, or 37.1 Morgantown coal units. The capacity additions within Mary- land indicated in the lower half of Table 1-14 are the equivalent of 8.2 Calvert Cliffs units, or 12*0 Morgantown units. Table 1-15 presents the load forecasts and planned capacity in Mary- land for each Maryland utility and for the State as a whole. Capacity plans are those listed in the 1978 Ten-Year Plan (Appendix A of this report), modified by subsequent submissions to the Maryland PSC. Peak demand fore- casts are taken from the report by the Department of State Planning (Appendix B of this report) and Table 1-18 at the end of this chapter. The capacity and demand data presented in the table are presented in a form that Is consistent with the data shown in the Public Service Commis- sion's Ten-Year Plan. Capacity and demand forecasts presented in that form do not provide a complete indication of the capacity available to serve Maryland demand. In the case of Potomac Edison, for example, 1978 peak demand in Mary- land is projected to be 1018 MW, but 129 MW of capacity is available in Maryland. However, the entire APS system of which Potomac Edison is a part has 6679 MW of capacity available to serve a system peak of 5510 MW, which is 343 MW (or 5.4%) more than is necessary to meet peak demand plus a 15% reserve margin. In planning for future additions to generating capacity, the planning area considered by utilities is the entire service territory of the systemo Electricity produced in one part of the system is sent out over the utility's transmission and distribution lines to all points in the system. In evaluating the adequacy of the long-range plans of the utilities serving Maryland, it is necessary to evaluate the load and capacity forecasts and plans for the system as a whole. Table 1-16 presents projections of total system demand, total system capacity, and reserve margins for the years 1978 to 1987 for each of the utilities serving Marylando Figure 1-13 shows both total system peak demand plus a 15% reserve requirement and total system capacity from Table 1-16. This data is taken from Table 1-18. The data in Table 1-16 and 'Figure 1-13 indicate that the current capacity plans of Maryland utilities will give the state an adequate supply of electric power over the next ten years. Based on the demand projections in the Table, 1-43 Table 1-15. Peak demand and generating capacity in Maryland,(a) for Maryland utilities, 1978-1987(b) PE/M[) (c) BGGE (d) PEPM-M OONOIVINGD Peak D Ca D C D -C D C D 1978 1,071 129 3,234 5,162 390 296 4,011 5.003 86 -0- 8,801 10,120 10,590 1979 1,135 129 3,357 5,162 412 296 4,123 4,990 90 -0- 9.117 10,485 10,577 1980 1,212 129 3,510 5,162 436 296 4,191 4,990 94 -0- 9,443 10.8sq 10,S77 1981 1,283 129 3,676 5,162 462 296 4,242 4,990 98 -0- 9,761 11,225 10,577 1982 1,360 129 3,849 5,721 493 308 4,284 5,231 103 -0- 10,089 11,602 11,389 1983 1,443 129 4,029 5,721 523 308 4,322 5,231 107 -0- 10.424 11,988 11,389 1984 1,S37 129 4,219 6,331 SS4 308 4,358 5,231 112 -0- 10,780 12,397 11,999 198S 1,632 129 4,418 6,456 S89 308 4,393 5.631 117 -0-- 11,149 12,821 12,524 1986 1,739 129 4,620 6,456 621 333 4,420 5,631 122 -0- 11,522 13,250 12,S49 1987 1,854 129 4,833 6,798 652 697 4,453 5,631 128 -0- 11,920 13,708 13,255 Average Annual Growth Rate 6.31 4.61 S.6j 1.21 4.5 t 3.49 IL-adings: Peak Demand - D Capacity C (a) rer Potomac Edison and Delmarva Power and Light, only the peak demand and capacity in Maryland is included. (b) Data from Appendix B (c) Utility forecast (d) PPSP/DSP forecast (e) 1987 capacity differs from value in Table 1-14 mainly because Easton, Deep Creek Lake and Conowingo are not included here. Table 1-16. System peak demand and generating capacity of Maryland utilities@a) 1978-1987 -APS-(Bj- BG-&r (cT-- DP&LAW- - PEPCO [c) INGCO (b) - MAL STATE U_ -W- JIL@- 2T D U V- L V L K V - L K 1978 5,460 6,429 17.7 3,234 5,162 59.6 1,710 2,227 30.2 4,011 5,003 24.7 86 -0- 14,501 16,676 18,821 29. 1 1979 S,750 7,OS5 22.7 3,357 5,162 S3.8 1,800 2,310 28.3 4,123 4,990 21.0 90 -0- 15,120 17,388 19,517 29.1 1980 6,100 7,681 2S.9 3,510 S,162 47.1 1,890 2,710 43.4 4,191 4,990 19.1 94 -0- 15,785 18,153 20,543 30.1 1981 6,395 7,681 20.1 3,676 5,162 40.4 1,890 2,709 36.8 4,242 4,990 17.6 98 -0- 16.301 18,746 20,542 26.0 1982 6,765 7,681 13.5 3,849 S,721 48.6 2,070 2,722 313 4,284 S.231 22.1 103 -0- 17,071 ;9,632 21,3SS 25.1 .1983 7,OOS 8,311 18.6 4,OZ9 5,721 42.0 2,170 2,72Z 25.4 4,322 5,231 21.0 107 -0- 17,633 20,278 21,98S 24.7 1984 7,480 8,941 193 4,219 6,331 50.1 2,270 2,722 19.9 4,358 S,231 20.0 112 -0- 18,439 21,205 23,225 26.0 198S 7,870 9,571, 21.6 4,418 6,4S6 46.1 2,370 2,821 19.0 4,393 S,631 28.2 117 -0- 19,168 22,043 24,479 27.7 1986 8,290 10,071 Z1.5 4,620 6,456 39.7 2,470 2,846 IS.2 4,420 S,631 27.4 122 -0- 19.922 22,910 2S,004 25.5 1987 8,620 10,S71 22.6 4,833 6,798 40.7 2,S90 3,141 21.3 4,453 5,631 26.5 128 -0- 20,624 23,718 26,141 26.8 Average Annual Growth Rate S.2% 1 4.61 1 4.79 1 1-21 4.S1 4.01 Headings: Peak Demand - D Capacity - C Reserve Margin R (a) Includes the complete service territories of the Allegheny Power System (including Potomac Edison) and Delmarva Power and Light. Data from Table 1-18. (b) Utility forecast (c) PPSP/DSP forecast 3a - 25- CAPACI 20- CONOWING LAND + 15 ... ...... ..... ..... ki ..... ................ ........ . . RYLAND 15 J. ........ DP L BG & 0 io ............ _HWH . . . ....... - ------------ - - - ----- -------- IS INC 78 '79 '80 a 82 @3 a4 85 So -'87 Figure 1-13. Peak demand and capacity forecast for electTic utility systems serving Maryland., 1977-1987 1-46 the reserve margin for all Maryland utilities taken together will range from 25% to 30% during those years. As was indicated earlier, desired reserve capacity ranges from 15% to 20%, depending on such factors as plant size and reliability and the extent of interconnection. The state-wide average annual growth rate projected for peak demand from Table 1-16 was 4.0%. An average annual growth rate of 5% over the period would result in a reserve margin of approximately 16% by 1987, indicating that even under conditions of growth in peak demand that are more rapid than anticipated, the state is likely to have adequate supplies of electricity over this time period. Based on all available forecasts, it is expected that each of the indivi- dual utilities serving Maryland will have adequate generating capacity and reserves over the next ten years, as measured by a minimum reserve level of 15%* However, Table 1-16 also shows that there is some variation in the ade- quacy of the electric power supply of the individual utilities. Based on the APS forecast, the APS system is expected to fall below the 20% reserve level for a four-year period in the early 1980's. In one year, 1982, reserve capacity is expected to fall below 15%, the lowest level antici- pated for any Maryland utility. Based on the PPSP forecast, the BG&E system is projected to have 40% to 50% reserve capacity through most of the period, well in excess of the 20% reserve level. (Table 1-18 includes the most recent forecast prepared by BG&E, which indicates reserve levels falling in the 20% to 30% range during the 1978-1987 forecast period.) Based on the DP&L forecast, the DP&L system is expected to maintain reserves above 20% level until the mid-1980's, and above 15% throughout the entire period. The PEPCO system is anticipated to experience reserve levels which drop below 20% in 1980 and 1981, based on the PPSP forecast for that system. The forecast prepared by PEPCO projects levels falling below 20 from 1981 to 1984. Both forecasts indicate that reserves are likely to remain above 15% throughout the entire forecast period. The adequacy of the APS system reserves depends on capacity additions planned for each of the years 1983 through 1987. APS has announced the in- definite suspension for financial reasons of the three Lower Armstrong units planned for 1983, 1984, and 1985, and the Corps of Engineers has denied a permit necessary for the construction of the Davis pumped storage units planned for 1986 and 1987. This denial is currently under litigation. In addition, a Federal Power Commission permit for Davis is under litigation in the Federal courts. Table 1-17 shows that the level of reserves for the APS without any of these units would drop below 15% in 1983, and below 0% in 1985 (20). The construction of Davis alone would not prevent reserves from dropping below 0% in this period. Without large purchases of capacity from other systems or other alternative plans, it is likely that the APS system will be unable to meet its anticipated load. Comparison of the data in Tables 1-16 and 1-17 shows that without the Davis and Lower Armstrong units, state-wide reserves drop below 15% by 1987, indicating that the capacity planned by other Maryland utilities may be barely adequate to meet APS requirements, assuming no other changes in the forecasts for this period. Reliance on the continuous use of 1-47 Table 1-17. Effects of capacity changes on the APS system Year Peak. Demand Planned Capacity Capacity Without -Cap-acity-W-itWu-t- L40wer Armstrong Reserve Margin Lower Armstrong Reserve Margin or Davis 1983 7,005 8,311 7,681 9.7 70681 9.7 1984 7,480 8,941 7,681 2.9 7,681 2.9 1985 7,970 9,571 7,681 (-2.4) 7,681 2.4) 1986 8,290 10,071 8,181 (-1.3) 7,681 7.3) 1987 8,620 10,571 8,681 0.7) 7,681 (-10.9) 4- OD MM M,M M M M w, M M, M M MIM M large imports of power may result in reduced system reliability for all the systems involved, however. The ability of the APS system to meet projected electric power demand in the Potomac Edison service territory is currently the subject of investigation by the Maryland Public Service Commission. The 1978 Ten Year Plan (Appendix A) lists the additions to generating capacity planned within Maryland for the next ten years. Plant additions by Maryland utility systems which are located outside of Maryland are not all included in the Ten Year Plan, but are included in Table 1-18. The new units planned within Maryland have been included in the map in Figure 1-12, above. As can be seen from the plant statistics in Tables 1-19 (21) and 1-20 (22) and the map of Figure 1-12, older plants in Maryland, as elsewhere, were located near load centers in urbanized areas. Examples can be seen in BG&E's Gould Street and Westport plants and PEPCO's Benning Road and Buzzard Point units. As was discussed in the 1975 CEIR, the introduction of high voltage transmis- sion lines (of 230 kv or greater) has reduced the cost of siting power plants further from metropolitan areas by reducing line losses and right-of-way requirements. Suitable sites for large power plants of the scale most commonly used for baseload units are difficult to find in urban areas. The high popula- tion densities of urban areas violate Nuclear Regulatory Commission population criteria for location of nuclear plants (23), and also result in a concentra- tion of transporation and industrial activities which cause high air pollution levels (see Chapter II). Further, the pollution control devices required by the Clean Air Act Amendments (see Chapter II) require large landfill areas for coal-burning plants. For a 1,200 MW coal unit, approximately 1,100 acres are required for waste disposal over the operating life of the plant. Tracts of this size are rarely available in urban areas, necessitating off-site disposal for such wastes. All of these trends and constraints favor the siting of large base load and cycling power plants in non-urban areas. The 1975 CEIR depicted the shift away from urban siting. Of the plants and sites included in the current Ten Year Plan, only Brandon Shores is within 20 miles of a metropolitan area. The sites currently listed in the Ten Year Plan follow the trend of siting outside of metropolitan areas, The 1978 Ten Year Plan lists new units planned at seven sites in Maryland, as well as six'sites at which no units are currently planned. These Maryland sites are described briefly, by utility, in Table 1-20. 1-49 I I I Table 1-18. Projected and actual energy demand, capability and growth rates for Maryland utilities. 1966 through 1987 1 1 1 1 I I I I I I I I I I I 1-50 1 Table I-18a. Allegheny Power System (total system) (a) Year and Energy Sales M) (C.) Peak Load all) (c) Capaci Reserve Load n Gruwt Non- t (1) Factor RateN) Residential Residential Total Swmer Winter (Cly Margi 1966 3,711,236 11,000,930 14,712,166 2,42S 2,661 2,343 12.0 68.9 1 7.13 S 10 1967 4,027,051 11,279,560 15,306,611 2,453 2,863 2,646 1*1 61*7 1 8.51 2.S3 4.04 1.15 7.59 5 10 1968 4,409,112 12,2S3,33S 16,662,447 2,749 3,017 3,222 6.8 68.8 1 9.49 8.63 8.86 12.07 S.38 S 10 1969 4,84S,Sll 13,3S7,748 18,203,259 2,941 3,343 3,809 14.0 67.7 1 9.90 9.01 9.25 6.98 10.81 S 10 1970 5,318,888 14,800,349 20,119,237 3,206 3,78S 4,293 17.6 68.0 1 9.77 10.80 10.S3 9.01 13.22 S 10 1971 5,694,162 15,S84,S94 21,278,756 3,327 3,769 4,819 27.3 69.3 1 7.08 S.30 5.76 3.77 0.42 S 8.94 7.21 7.66 6.53 7.21 10 1972 6,136,732 16,678,103 22,814,83S 3,622 4,039 S,503 37.2 69.9 1 7.77 7.02 7.22 8.87 7.16 5 8.79 8.14 8.30 8.11 7.12 10 1973 6,614,299 18,057,714 24,672,013 4,040 4,230 5,965 41.0 71.6 1 7.78 8.27 8.14 ll.S4 4.73 S 8.45 8.06 8.17 8.00 6.99 10 1974 6,808,969 18,134,728 24,943,697 3,916 4,272 6,663 S7.6 73.6 1 2.94 0.43 1.10 -3.07 0.99 5 7.04 6.31 6.50 S.89 5.03 10 1975 7,228,634 16,732,95S 23,961,589 3,959 4,650 6,429 40.1 64.8 1 6:16 - 7.73 - 3.94 1.10 9.85 S 6.33 2.48 3.S6 4.31 4.20 10 1 6.47 1976 7,S23,Sl8 19,180,93S 26,704,4S3 4,284 S,0131 6,429 28.8 66.1 1 4.08 14.63 11.45 8.21 8.19 S 5.73 4.24 4.65 5.19 S.95 10 7.32 S.72 6.14 S.86 6.S8 1977 8,09S,776 20,lSI,533 28,247,309 4,539 S,174 6,429 24.3 68.7 1 7.61 S.06 S.78 5.9s 2.84 S S.67 3.86 4.36 4.62 S.08 10 7.23 5.97 6.32 6.35 6.10 1978 8,S21,000 20,340,236 28,861,236 4,720 5,460 6,429 17.7 66.6 1 S.2S 0.94 2.17 3.99 S.S3 5 5.20 2.41 3.19 3.16 5.24 10 6.81 5.20 5.65 5.5s 6.11 1979 9,007,000 21,73S,SOO 30,742,50 0 4,870 S,750 7,OSS 22.7 66.7 1 5.70 6.86 6.52 3.18 S.31 S 5.7S 3.69 4.27 4.46 6.12 10 6.40 4.99 S.38 5.17 S.S7 1-51 Table I-18a. Allegheny Power System (Continued) Year and Energy Sales 00h) Peak Load W (c) Reserve Non- Capacity Margin Load Growth Residential Total Summer Winter (c) Factor Rates W Residential 1980 9,529,000 22,807,200 32,336,20C 5,170 6,100 7,681 25.9 653 1 5.80 4.93 5.18 6.16 6.09 S S.68 6.39 6.18 5.43 538 10 6.00 4.42 4.86 4.89 4.89 1981 10,086,000 23,716,000 33,802,000 5,390 6,39S 7,681 20.1 65.3 1 5.8S 3.98 433 4.26 4.84 S 6.04 4,34 4.83 4.70 4.91 10 5.88 4.29 4.74 4.94 S.43 1982 10,634,000 2S,048,Soo 3S,682,500 5,62S 6,765 7,681 13.S 6S.8 1 5.43 S.62 S.S6 4.36 5.79 S S.61 4.45 4.78 4.38 5.Sl 10 SAS 4.15 437 430 S.29 1983 11,234,000 26,027,200 37,261,200 S,875 7,OOS ,,,,,(a. 18.6 65.6 1 5.64 3.91 4.42 4.44 3.SS S S.68 LOS S.24 4.48 S.11 10 S.44 3.72 4.21 3.82 S.17 1984 11,833,000 27,202,800 39,03S,800 6,20S 7,480 8,,41-(a' 19.'s 64.6 1 S.33 4.S2 4.76 S.62 6.78 5 S.61 4.59 4.89 4.96 5.40 10 S.68 4.14 4.S8 4.71 S.76 198S 12,48S,000 28,SO1,400 40,986,400 6,560 7,870 9,S71 (a: 21.6 64.6 1 S.Sl 4.77 S.00 S.72 S.21 S S.S5 4.S6 4.86 4.88 5.23 10 5.62 5.47 S.Sl S.18 5.40 1986 13,143,000 29,732,000 42,87S,000 6,850 8,290 10,071(c' 21.S 64.2 1 S.27 4.32 4.61 4.42 5.34 5 S.44 4.63 4.87 4.91 S.33 10 S.74 4.48 4.8S 4.81 S.12 1987 13,849,000 30,900,600 44,749,60C 7,130 8,620 10'S71(c) 22.6 64.0 1 S.37 3.93 4.37 4.09 3.98 5 5.43 4.29 4.63 4.86 4.97 10 S.S2 4.37 4.71 4.62 S.24 (a) Data represents the entire APS system, including Potomac Edison, West Penn Power Go. , Monongahela Power Co. (b) I yr growth, percent S yr avg. growth, percent 10 yr avg. growth, percent (c) Forecast prepared by APS 1-52 Table I-18b. Potomac Edison Conpany (Nfaryland Portion)* Year and Energy Sales Oft) (C). Peak Load (MN) (c) Reserve Load Growth Non- Margin Rates (b) Residential Residential Total Summer Winter I@Vcy (1) (d) FACtoT (d) 1966 488,702 931,649 1,420,351 336 129 1 S 10 1967 539,6S8 1,014,SSS 1,SS4,213 362 129 1 10.43 8.90 9.42 7.74 S 10 1968 599,608 1,114,9SZ 1,714,560 390 129 1 11.11 9.90 10.32 7.73 S 10 1969 664,953 1,221,389 1,886,342 420 129 1 10.90 9.55 10.02 7.69 S 10 1970 730,S79 1,894,813 2,62S,392 S50 129 1 9.87 S5.14 39.18 30.9S 5 10 1971 787,501 2,504,470 3,301,971 601 129 1 7.79 32.18 25.77 9.27 S 10.01 21.87 18.38 12.33 10 1972 850,904 2,624,932 3,47S,836 656 129 1 8 *Os 4.81 S.27 9.1s S 9.S3 20.94 17.47 12.63 10 1973 929,917 2,784,849 3,714,766 682 129 1 9.29 6.09 6.87 3.96 5 1 9.17 20.09 16.72 11.83 10 1974 985,282 2,72S,246 3,710,528 693 129 1 5.95 - 2.14 - 0.12 1.61 S 8.18 17.41 14.49 10.0 10 1975 1,065,026 2,629,187 3,694,213 802 129 1 8.,09 - 3.52 . 0.44 15.73 S 7.83 6.77 7.07 7.84 10 1976 1,142,266 3,911,928 S,054,194 916 129 1 7.2S 48.79 36.81 14.21 5 7.72 11.90 8.89 8.79 10 8.86 15.43 13.S3 10.5s 1977 1,234p939 4,118,S14 5,353,453 1,018 129 1 8.11 5.28 S.92 2.13 5 7.73 9.43 9.02 9.19 10 8.63 IS.04 13.17 10.89 1978 S,632,368 1,071 129 1 5.21 S.21 5 8.68 9.45 10 12.63 10.63 1979 5,969,184 1,135 129 1 S.98 S.98 S 9.98 10.37 10 12.21 10.45 1-53 Table I-18b. Potomac Edison Company (NIaryland Portion) (Continued) Year mid Energy Sales (Wh)(c). Peak Load (MW) (c) Reserve Growth Residential Non- - - Marg load Rates(b) Residential Total Summer Winter (@;CAT (J)i(nd) Factor(d) 1980 61373,894 1,212 129 1 6.78 6.78 5 II.S3 8.61 10 9.28 8.22 1981 6,747,404 1,283 129 1 5.86 S.86 5 5.9s 6.97 10 7.41 7.88 1982 7,152,248 1,360 129 1 6.00 6.00 5 S.96 5.96 10 7.48 7.S6 1983 7,S88,S36 1,443 129 1 6.10 6.10 S 6.14 6.14 10 7.40 7.78 1984 8,082,549 1,537 129 1 6.Sl 6.Sl 5 6.25 6.2S 10 8.10 8.29 1985 8,S82,051 1,632 129 1 6.18 6.18 5 6.13 6.13 10 8.79 7.36 1986 9,145,033 1,739 129 1 6.Sfi 6.S6 S 6.27 6.27 10 6.11 6.62 1987 9,749,S20 1,8S4 129 1 6.61 6.61 5 6.39 6.39 10 6.18 6.18 (a) Data represents only the Maryland portion of the Potomac Edison Service territory (b) 1 yr growth, percent S yr avg. growth, percent 10 yr avg. growth, percent (c) Forecast prepared by Allegheny Power System (d) Not calculated separately for Maryland portion of system, 1-54 Table I-18c. Baltimore Gas and Electric Company Year and Energy Sales oft) (b.) Peak Load M (b) Reserve W&E Forecast(c) Growth sidential Non- capaci Margin 1,oad &Mwr Reserve Rates (a) Re Residential Total Suffoer Winter V (1) Factor Peak Margin 1966 2#347,000 6,306,000 8,653,000 1,817 1,422 1,866 2.7 S8.9 1 5 10 1967 2,548,461 6,797,355 9,34S,816 1,9Z7 1,558 2,095 8.7 S9.8 1 8.58 7.79 8.01 6.05 9.56 5 10 1968 2,933,422 7,238,078 10,171,500 2,179 1,683 1 1,898 12.9 S7.7 1 Is.11 6.48 8.83 13.08 8.02 5 10 1969 3,285,000 7,880,000 11,165,000 2,306 1,792 2,046 - 11.3 59.7 1 11.99 8.87 9.77 S.83 6.48 5 10 1970 3,664,S64 8,306,165 11,970,729 2,496 1,954 2,290 - 8.3 S9.0 I ILSS S.41 7.22 8.24 9.04 S 10 1971 3,864,160 8,620,399 12,484,S59 2,605 2,053 2,290 - 12.1 S8.7 I I SAS 3.78 4.29 4.37 S.07 S 10.49 6.2S 7.61 7.47 7.62 10 1972 4,102,000 8,889,000 12,991,000 2,960 2,006 2,917 - Ls S3.9 1 6.16 3.12 4.06 13.63 2.29 S 9.99 S.Sl 6.81 8.96 5.18 10 1973 4,617,840 9,722,929 14,340,819 3,334 2,302 3,491 4.7 52.7 1 12.S8 9.38 10.39 12.64 14.76 S 9.50 6.08 7.11 8.88 6.46 10 1974 4,469,140 9,S20,84S 13,989,98S 3,190 2,177 3,294 3.2 S3.9 1 3.22) 2.08) ZAS) 4.32 S.43 S 6.3S 3.86 4.61 6.71 3.97 197S 4,664,000 9,194,000 13,8S8,000 3,256 2,301 4,402 3S.2 52.4 10 1 4.36 3.43 - 0.94 2.07 5.10 5 4.94 2.OS 2.97 S.46 3.32 10 1976 4,887,793 9,870,413 14,758,206 3,234 2,418 4,408 36.3 S6.2 1 4.80 7.36 6.SO 0.68 S.08 S 4,11 1,11 3*40 4.42 3-33 10 7.61 4.58 5.48 S.93 SAS 1977 S,231,000 10,231,000 15,462,000 3,S88 2,640 S,162 43.9 S2.7 T 1 7.02 3.6S 4.77 10.9s 9.18 5 4.98 2.8S 3.S4 3.92- SAS 0 7.46 4.17 5.16 6.41 S.42 1978 -S,070,266 10,912,SO7 1S,982,773 3,234 2,770 5,162 S9.6 3,740 38.0 1 (- 3.07) 6.66 3.37 9.87) 4.92 4.24 S 1.89 2.34 2.19 0.61) 3.77 2.32 10 S.62 4.19 4.62 4.03 5.11 S.5s 1979 S,292,6S4 11,282,637 16,S75,291 3,357 2,900 5,162 53.8 3,930 31.3 1 4.39 3.39 3.71 3.80 4.69 5.08 S 3.44 3AS 3.4s 1.03 S.90 4*26 10 4.89 3.65 4.03 3.83 4.93 S.48 1-55 Table I-18c. Baltimore Gas and Electric Company (Continued) Year and fhergy Sales "&) (b). Peak Load W(b) Reserve Load BGGE Forecast(c) Growth Non- C) Margin Summer Reserve Rates (a) Residential Residential Total Summer Winter Z' (1) Factor Peak Margin 1980 S,SS3,091 11,993,630 17,546,721 3,510 3,046 5,162 47.1 4,110 25.6 1 4.92 6.30 S.86 4.56 5.03 4.58 S 3.55 S.46 4.83 1.93 5.77 4..77 10 4.24 3.74 3.90 3.47 CS4 S.11 1981 5,823,603 12,719,192 18,542,79S 3,676 3,190 5,162 40.4 4,310 19.8 1 4.87 6.05 5.68 4.73 4.73 4.87 5 3.57 S.20 4.67 2.60 S.70 5.91 10 4.19 3.97 4.04 3.50 4.Sl 5.16 1982 6,121,884 13,464,105 19,585,989 3,849 3,342 5,721 48.6 4,S20 26.6 1 S.12 S.86 S.63 4.71 4.76 4.87 5 3.20 SAS 4.84 1.41 4.83 4.73 10 4.09 4.24 4.19 2.66 S.24 4.32 1983 6,446,13S 14,234,493 20,680,628 4,029 3,505 5,721 42.0 4,730 21.0 1 S.30 5.72 S.S9 4.68 4.88 4AS S 4.92 5.46 5.29 4.49 4.82 4.81 10 3.39 3.89 3.73 1.91 4.29 3.56 1984 6,796,829 15,036,050 21,832,879 4,219 3,67S 6,331 SO.1 4,940 28.2 1 S.44 5.63 5.57 4.72 4.8S 4.44 5 S.13 S.91 5.66 4.68 4.8S 4.68 10 4.28 4.68 4.S5 2.84 S.38 4.47 198S 7,174,723 13,874,4S8 23,049,181 4,418 3,855 6,4S6 46.1 S'160 2S.1 1 5.56 5.58 S.57 4.72 4.90 4AS S S.26 S.77 5.61 4.71 4.82 4.66 10 4.40 5.16 S.22 3.10 S.30 4.71 1986 7,S76,536 16,713,496 24,290,026 4,620 4,042 6,4S6 39.7 5,390 19.8 1 S.60 5.29 5.38 CS7 4.85 4.46 S SAO 5.61 S.55 4.68 4.8S 4.S7 10 4.48 S.41 5.11 3.63 S.27 S.24 1987 8,007,837 17,S96,30S 25,604,142 4,833 4p239 6,798 40.7 5,630 20.7 1 S.69 5.28 S.41 4.61 4.87 4.45 S S.52 S.50 S.SO 4.66 4.87 4.49 10 4.3S 5.57 S.17 3.02 4.85 4.61 (a) 1 yr growth, percent - 5 yr avg. growth, percent 10 )rr avg. growthq percent (b) Forecast prepared by PPSP (c) Fore cas t prepared by BG&E 1-56 Table I-18d. Delmarva Power and Light Company (total system)(a) Year and Energy Sales OMh) (c) Peak IOad (M)(c) Capacity Reserve Load Growth ReSiLdential Non- (d) Total Sumter Winter (c) Margin Factor Rates(b) I IResidential I 1 (1) 1966 838,548 2,636,66S 3,475,213 710 617 799 62.8 1 5 10 1967 910,S47 2,855,780 3,766,327 748 680 836 11.8 64.7 1 8.S9 8.31 8.38 5.28 10.18 S 10 1968 1,037,222 3,409,021 4,446,243 898 751 864 - 3.8 63.1 1 13.91 19.37 18.0s 20.12 10.54 5 10 1969 1,108,94S 3,743,009 4,851,954 955 SS9 8S3 - 10.6 65.0 1 6.91 9.80 9.12 6.30 14.33 5 10 1970 1,280,420 3,897,S14 5,177,934 1,045 947 1,045 0.0 63.7 1 IS.46 4.13 6.72 9.47 10.33 5 10 1971 1,380,763 4,093,144 5,473,907 1,135 986 1,210 6.6 62.0 1 7.8A S.02 S.72 8.61 4.08 S 10.49 9.19 9.51 9.83 9.84 10 1972 1,463,821 4,457,292 5,921,113 1,259 1,043 1,237 1.7 61.0 1 6.02 8.90 8.17 10.94 5.76 S 9.96 9.31 9.47 10.99 8AS 10 1973 1,629,640 4,771,818 6,401,4S8 1,508 1,201 1,406 6.8 SS.1 1 11.33 7.06 8.11 19.76 15.14 S 9.46 6.96 7.S6 10.92 9.84 10 1974 1,S97,471 4,641,3S4 6,238,82S 1,447 1,144 1,801 24.5 S5.8 1 - 1.97 - 2.73 - 2.54 4.03 4.73 S 7.S7 4.40 S.16 8.68 S.91 10 1975 1,672, 180 4,34S,147 6,017,327 1,463 1,187 1,gsg 33.8 S3.8 1 5.48 - 6.38 - 3.5S 1.11 3.73 5 2.71 2.20 3.05 6.96 4.61 10 1976 1,787,663 4,473,186 6,260,849 1,434 1,276 1,971 37.4 S7.3 1 6.91 2.95 COS 1198 7.51 5 S.30 1.79 2.72 4.79 4.11 10 7.86 S.43 6.06 7.28 7.54 1977 1,924,723 4,612,039 6,S36,761 1,609 1,402 2,OS2 27.5 S2.8 1 7.67 3.10 4.41 12.21 9.88 5 5.63 0.68 2.00 S.03- 6.09 10 7.77 4.91 S.69 7.97 7.51 1978 1,949,612 4,843,88S 6,793,497 1,710 NIA 2,227 30.2. N/A 1 1.29 S.03 3.93 6.26 5 3.65 0.30 1.20 2.SS 10 6.Sl 3.S8 4.33 6.65 1979 2,099,950 5,181,002 7,280,952 1,800 NIA 2,310 28.3 N/A 7.71 6.96 7 18 5.26 S S.62 7.22 3:14 4.46 10 6.59 3.30 4.14 6.S5 1-57 Table I-18d. Delmarva Power and Light Company (total system) (Continued) Year and Energy Sales 00h) (c) Peak load (W)(c) Reserve - Growth Non- (d) Capaci Margin Load Rates(b) Residential Residential Total Summer er (city M Factor 1980 2,249,924 S,393,335 7,643,2S9 1,890 N/A 2,710 43.4 N/A 1 7.14 4.10 4.98 5.00 5 6.12 4.42 4.90 5.25 10 5.80 3.97 6.11 1981 2,380,702 5,876,192 8,384,075 1,980 N/A 2,709 36.8 N/A 1 11.47 8AS 9.69 4.76 5 S.90 S.61 6.01 6.66 10 S.60 3.30 4.36 5.72 1982 2,507,883 S,925,941 8,433,824 2,070 N/A 2,722 31,S N/A 1 5.34 0.85 0.59 4.SS 5 5.44 S.14 5.23 S.16 10 S.S3 2.89 3.60 5.10 1983 2,637,6SO 6,192,999 8,830,649 2,170 N/A 2,722 2S.4 N/A I S.17 4.51 4.71 4.83 S 6.23 S.04 S.39 4.88 10 4.93 2.64 3.27 3.71 1984 2,77S,979 6,430,890 9,206,869 2,270 N/A 2,722 19.9 N/A 1 S.24 3.84 4.26 4.61 S S.74 4.42 4.81 4.7S- 10 5.68 3.31 3.97 4.61 198S 2,906,426 6,70S,276 9,611,752 2,370 NIA 2,821 19.0 N/A 1 4.70 0.84 4.40 4.41 S 5.2S 4AS 3.98 4.63 10 S.68 4.43 4.79 4.94 1986 3,046,86S 7,03S,3SO 10,082,215 2,470 N/A 2,846 1S.2 N/A 1 4.83 4.92 4.89 4.22 5 S.06 3.67 3.76 4.52 10 S.48 4.63 4.88 S39 1987 3,194,811 7,405.92S 10,600,736 2,S90 N/A 3,141 21.3 NIA 1 4.86 S.27 S.14 4.86 5 4.96 4.56 4.6 4.S8 10 S.20 4.85 4.9s 4.87 (a) Excludes energy sales to Dover and Easton; includes only the portion of Dover and Easton peak demand provided by DP&L (b) 1 yr growth, pe-ent S yr avg. growth, percent 10 yr avg .growth, percent (c) Forecast prepared by DPU (d) Excludes sales for resale in Maryland 1-58 Table I-18e. Delmarva Power and Light Company of Maryland(a@ Year and Energy Sales (W%) (c.) Peak Load M (c) Reserve Non- Capacity MaTg,.Ln Residential Total Summer Winter (c) (d) Rt.,@b) Residential I F=r(d) 1966 198,797 299,477 498,274 141 116 105 1 S 10 1967 220,454 327,383 547,837 149 139 105 1 10.89 9.32 9.9s 5.67 19.83 S 10 1968 ZS3,058 367,772 620,830 177 iss 132 1 14.79 12.34 13.32 18.79 11.51 5 10 1969 288,757 410,236 698,493 197 164 132 1 14.11 11.5s 1239 11.30 S.81 S 10 1970 321,86S 4Sl,2S7 773,122 210 206 132 1 14.47 10.00 10.61 6.60 25.61 S 10 1971 3S4,861 480,329 83S,190 227 227 282 1 10.25 6.44 8.03 8.10 10.19 5 12.29 9.91 10.88 9.99 14.37 10 1972 389,4S3 S10,769 900,222 278 233 282 1 9.7S 6.34 7.79 22.47 2.64 5 12.OS 9.30 10.44 13.28 10.88 10 1973 441,381 S63,605 1,004,986 '327 290 252 1 13.33 10.34 11.64 17.63 24.46 5 11.77 8.91 10.11 13.06 13.3s 10 1974 457,947 S69,227 1,027,174 319 27S 2S2 1 3.7S 1.00 2.21 - 2AS - S.17 5 9.66 6.77 8.01 10.12 10.89 10 1975 483,370 593,163 1,076,533 342 294 2S2 1 S.SS 4.21 4.81 7.21 6.91 S 8.47 S.62 6.8S 10.2S 7.37 10 1976 542,SO9 647,974 1,190,483 315 .347 252 1 12.23 9.24 1O.S8 - 7.89 18.03 5 6.8S 6.17 7.3S 6.77 8.86 10 1O.S6 8.02 9.10 8.37 ll.S8 1977 623,778 733,443 1,3S7,221 384 400 2S2 1 14.98 13.19 14.01 21.90 1S.27 S 9.88 7.SO B.S6 6.67 11.41 10 10.96 8.40 9.50 9.93 11.1s 1978 6SS,911 787,717 1,443,630 390 N/A 252 1 SAS 7.40 6.37 LS6 S 8.24 6.92 7.Sl 3.59 10 9.99 7.91 8.80 8.22 1979 704,979 863,973 1,568,9SS 412 N/A 252 1 7.48 9.68 8.68 S.64 S 9.01 8.70 8.84 5.2S 10 9.34 7.73 8.43 7.66 1-59 Table I-18e. Delmarva Power and Light Conpany of Maryland (Continued) Year and Energy Sales M)(c) Peak load ("q (c) capacity Reserve Load Growth Residential Non- Total Swmr winter (c) Ma(r$ n(d) Factor(d) Rates(b) Residentiall 1980 749,888 921,6S4 1,671,545 436 NIA ZS2 1 6.37 6.67 6.54 S.83 S 9.18 9.21 9.20 4.98 10 8.83 7.40 8.02 7.S8 1981 800,740 978,46S 1,779,211 462 N/A 2S2 1 6.78 6.16 6.44 5.96 5 8.10 8.59 8.37 7.96 10 8.48 7.37 7.86 7.36 1982 8S3,336 1,045,2Sl 1,898,S89 493 N/A ZS2 1 6.S7 6.83 6.71 6.71 S 6.47 7.34 6.94 S.12 10 8.16 7.42 7.7S S.90 1983 905,688 1,114,185 2,019,876 523 N/A 2S2 1 6.13 6.S9 6.39 6.09 5 6.67 7.18 6.9S 6.04 10 7.4S 7.OS 7.23 4.81 1984 960,747 1,168,717 2,129,46S S54 NIA 252 1 6.08 4.89 S.43 S.93 S 6.39 6.23 6.30 6.10- 10 7.69 7.46 7.56 S.67 1985 1,014,699 1,241,103 2,ZSS,80S S89 NIA 252 1 5.62 6.19 5.93 6.32 S 6.24 6.13 6.18 6.20 10 7.70 7.66 7.68 S.S9 1986 1,072,143 1,323,171 2,395,316 621 N/A 252 1 5.66 6.61 6.18 S.43 5 6.01 6.22 6.13 6.09 10 7.OS 7.40 7.24 7.02 1987 1,129,042 1,40S,7S1 2,534,794 652 N/A 618 1 5.31 6.24 5.82 4.99 5 5.76 6.11 SAS 5.75 10 6.11 6.72 6.45 5.44 (a) Data represents the Maryland portion of the DP&L system; data excludes sales to East0n; data includes only the portion O:f the Easton peak provided by DP&L (b) 1 yr grmdh,- percent 5 yr avg. growth, percent 10 yr avg. growth, percent (c) Forecast prepared by DP&L, Easton not inlcuded in plant capacity. (d) Not calculated separately for Maryland Portion of system. 1-60 (a) Table I-18f. Potomac Electric Power Company (total system) Year and Energy Sales Dft)(c). Peak Load (W) (c) Reserve PEPCO Forecast(d) Grmdh cqmcity Margin Load mmr Reserve Rates (b) Residential Residential Total Summer winter (%fg)-(d) (1) Factor Peak Margin 1966 1,978,031 5,660,581 7,638,612 2,123 1,249 2,363 11.3 N/A 10 1967 29084,SI7 6,194,069 8,278,S86 2,283 1,385 2,395 4.9 N/A I S.38 9.42 8.38 7.54 10.89 5 10 1968 2,401,544 6,915,402 9,316,946 2,627 I,S20 2,973 13.2 N/A 1 15.21 11.65 12.S4 1S.07 9.7S S 10 1969 2,648,6SB 7,60S,966 10,2S4,624 2,7S9 1,622 2,973 7.8 N/A 1 10.29 9.98 10.06 5.02 6.71 5 10 1970 2,931,982 8,2S1,123 11,183,105 2,908 1,813 '3,708 27.5 NIA 1 10.70 8.48 9.0s S.40 11.78 S 10 1971 3,037,526 8,696,OS8 11,733,584 3,04S 1,919 4,2S9 39.9 NIA 1 3.60 5.39 4.92 4.71 SAS 5 8.96 8.97 8.96 7.48 8.97 10 1972 3,121,794 9,068,SO4 12,190,298 3,479 1,990 4,454 28.0 NIA 1 2.77 4.28 3.89 14.2S 3.70 5 8.41 7.92 8.05 8.79 7.52 10 1973 3,S29,039 9,704,09S 13,233,134 3,680 2,lS9 4,721 28.3 N/A 1 13.05 7.01 8.55 5.78 8.49 S 2.48 7.01 7.27 6.97 7.27. 10 1974 3,304,222 8,884,72S 12,188,947 3,SO2 2,012 4,933 40.9 NIA I - 6.37 - 8.44 - 7.89 - 4.84 - 6.81 S 4.52 3.16 3.52 4.88 4.40 10 197S 3,399,4S2 9,322,077 12,721,S29 3,623 2,145 S,190 43.3 N/A 1 2.88 4.92 4.37 3.46 6.61 S 3.00 2.47 2.61 4.49 3.42 10 1976 3,484,01 4,603,245 13,087,776 3,SOO 2,334 S9010 43.1 N/A 1 2.SO 3.02 2.88 - 3.39 8.81 S 2.78 2.00 2.21 2.82 3.99 10 6.38 S.43 S.53 S.13 6AS 1977 3,617,267 10,029,S46 13,646,813 3,8S7 2,508 S,013 30.0 N/A 1 3.81 4.44 4.27 10.20 7.46 5 2.99 2.03 2.28 2.82 4.74 10 S.67 4.94 S.13 S.38 6.12 1978 3,761,400 10,472,600 14,2349000 4,011 S,003 24.7 NIA 3,922 27.6 1 3.98 4.42 4.30 3.99 1.69 5 1.28 1.54 1.47 1.74 1.28 10 4.S9 4.24 4.33 4.32 4.09 1979 1 3,907,300 10,821,300 14,728,600 4,123 1 4,990 21.0 N/A 4,007 24.S 1 3.88 3.33 3.47 2.79 2.17 S 3.41 4.02 3.86 3.32 14.77 10 3.96 3.S9 3.69 4.10 3.80 1-61 Table I-18f. Potomac Electric Power Company (total system) (Continued) Year and Energy Sales Oft) (C.) Peak Load (W)(c) Capaci Reserve Load PEpco Forecast(d) Growth Non- ty "in Summet Reserve Rates(b) Residential lResidential Tot summer Winter O.Sf) (d) (1) Factor Peak Margin 1980 4,058,700 11,076,400 15,135,100 4,191 4,990 19.1 N/A 4,098 21.8 1 3.87 2.36 2.76 1.6S 2.27 5 3.61 3.Sl 3.54 2.96 13.82 10 3.31 2.99 3.07 3.72 3.40 1981 4,231,600 11,276,200 IS,S07,800 4,242 4,990 17.6 N/A 4,220 18.2 1 4.26 1.80 2.46 1.22 2.97 5 3.96 3.26 3AS 3.92 12.58 10 3.37 2.63 2.83 3.37 3.32 1982 4,404,100 11,423,700 1S,827,800 4,284 S,231 22.1 N/A 4,350 20.3 1 4.08 1.31 2.06 0.99 3.08 S 4.01 2.64 3.01 2.12 2.43 10 3.50 2.34 2.6S 2.10 2.26 1983 4,S90,300 11,571,800 16,162,100 4,322 S,231 21.0 N/A 4,484 16.7 1 4.Z3 1.30 2.11 0.89 3.08 S 4.06 2.02 2.57 1.50 2.71 10 2.66 1.76 2.02 1.62 2.00 1984 4,790,300 11,703,800 16,494,100 4,3S8 5,231 20.0 N/A 4,563 14.6 1 4.36 1.14 2.05 0.83 1.76 S 4.16 1.58 2.29 1.11 2.63 10 3.78 2.79 3.07 2.29 2.68 198S 4,999,700 11,824,000 16,823,700 4,393 S,631 28.2 N/A 4,638 21.4 1 4.37 1.03 2.00 0.80 1.64 S 4.26 1.31 2.14 0.9s 2.51 10 3.93 2.41 2.83 IAS Z.SO 1986 5,234,900 11,80,400 L7,088,300 4,420 S,631 27.4 NIA 4,712 19.S 1 4.70 2.49 LS7 0.61 1.60 S 4.35 1.00 1.96 0.83 2.23 10 4AS 2.13 2.70 2.36 3.02 1987 S,484,400 11,961,700 17,446,100 4,453 S,631 26.5 N/A 4,787 17.6 1 4.77 0.91 2.09 0.7S LS9 S 4.49 0.93 1.97 0.78 1.93 10 4.25 1.78 2.49 1AS 2.18 (a) Data includes the entire PEPOD system; data excludes energy sales to SMECO; data includes SMEOD peak (b) 1 yr growth, percent S yr avg. growth. percent 10 yr avg. growth, percent (c) Forecast prepared by PPSP (d) Forecast prepared by PEPOD 1-62 Table 1-19. Generating capability and fuel type by generating unit for Maryland utilities For all utilities: 1. GT units are gas turbines; IC units are diesels; all other units are steam. 2. Changes in net capability include additions, retirements and deratings. 3. Station total is given as capability at peak season (Tables A and B, Winter; Tables C and D, Sumer) 4. For stations with joint ounership capability listed in the tables is the utility's share of total station capability. The total capability of jointly owned units is as follows: Summer Winter Conemaugh 1 850 850 2 850 850 IC 1 11 11 Dickerson 4 800 800 Keystone 1 840 850 2 840 850 IC 3-6 11 11 Peach Bottom 2 l"051 1,055 3 1,035 1,035 Safe Harbor 228 228 Existing Expansion 188 188 Salem 1 1,090 1,090 2 1,115 1,115 Gr 3 38 48 1-63 'Table I-19a. Allegheny power system (the Potomac Edison Company, West Penn Power Company, Monongahela Power Company) unit Ye Nlet Capability (W) Fuel Type station I Ifitr Total Existing System Albright 1 1952 73 76 Coal 2 1952 73 76 coal 3 1952 137 140 Coal 292 Armstrong 1 19S8 173 180 Coal 2 1959 176 180 Coal 360 Celanese 1 1937 7 10 Cogen.(Nat.Gas: 10 Ft. Martin 1 1967 276 276 Coal 2 1968 S55 555 Coal 831 Fatfield's Ferry 1 1969 Soo S55 Coal 2 1970 Soo 555 Coal 3 1971 Soo 550 Coal 1,660 Harrison 1 1972 640 640 Coal 2 1973 640 640 Coal 3 1974 640 640 coal 1,920 Hydro Stations (8) 7 10 Hydro 10 Lake Lynn 1-4 1926 S2 52 Hydro 52 Milesburg 1 1950 22 23 Oil .2 19SO 22 23 Oil 46 Mitchell 1 1948 85 89 Oil 2 1949 84 89 Oil 3 1963 282 291 Coal 469 Riverton 1 1949 38 39 Oil 39 Rivesville S 1943 46 48 Coal 6 19sl 91 94 Coal 142 R.P. Smith 3 1947 38 39 Coal 4 19S8 99 90 Coal 129 Springdale 7 194S 8S 86 Oil 8 1954 134 137 Oil 223 Willow Island 1 1949 57 58 coal 2 1960 181 188 Coal 246 Additions and 1978-1987 Celanese 1 1978 (7) (10) Cogen. (Nat. Gas Pleasants 1 1979 626 626 Coal 2 1980 626 626 Coal 1,2S2 Lower Armstrong 1 1983 630 630 Coal 2 1984 630 630 Coal 3 198S 630 630 Coal 1,890 Davis 1 1986 2SO 2SO Hydro 2 1986 250 2SO Hvdro 3 1987 250 2SO Hydro 4 1987 250 2SO Hydro 1,000 Long Range Additions, 3,4SS Fossil 1988-1997 3,785 Nuclear 990 Hydro Total Existing System 6.203 6,429 Total Net Additions to 1987 4,135 4,132 Total Planned System to 1987 10,338 lo,S61 Total Long Range Additions, 1988-1997 8,230 1-64 Table I-19b. Baltinore Gas and Electric Conpany Capability year Net Station unit Sumer Winter Fuel Type Total E)dstinz System Calvert Cliffs 1 1975 810 820 Nuclear 2 1977 810 820 Nuclear 1,620 Conemaugh(a) 1 1970 90 90 coal 2 1971 90 90 coal IC A-D 1970 1 1 Oil 181 C.P. Crane 1 1961 192 193 Oil 2 1963 192 193 Oil Gr 1 1967 14 17 Oil 398 Gould St. 3 103 104 Oil 103 Keystone (20.991)(a) 1 176 .179 Coal 2 177 178 coal IC 3-6 2 2 Oil 3SS Notch Cliff Gr 1-4 64 68 Gas Gr S-8 64 68 Gas 128 Perr/man Gr 1-4 204 240 Oil 204 Philadelphia Rd. Gr 1-4 64 68 Oil 64 Riverside 1 58 S9 Oil 2 S9 60 Oil 3 61 62 Oil 4 78 79 Oil 5 6S 66 Oil Gr 6 128 132 Oil Gr 7 22 2S Oil Gr 8 22 2S Oil 493 H.A. Wagner 1 137 139 Oil 2 134 135 Oil 3 319 321 Coal 4 398 400 Oil Gr 1 14 17 Oil 1,002 Westport 1 19 19 Oil 13 16 16 Oil 14 16 16 Oil 3 S8 S9 Oil 4 68 69 Oil GT S 118 132 Oil 295 Safe Harbor 1931 152 1S2 Hydro 152 rmtitlevent Bethlehem Steel -- 167 169 Oil 167 Entitlement Additions and (Removals), 1978-1987 Brandon shores 1 1982 610 620 Oil 2 1984 610 620 Oil Westport 1 1982 (10) (19) Oil 13 1982 (16) (16) Oil 14 1982 (16) (16) oil Safe Harbor 198S 12S 12S R/dro' Entitlement Dickerson(a) 4 1987 400 400 Coal Westport 3 1987 (S8) (59) Oil Long Range Additions, 400 Oil 1988-1997 1,600 Coal 1,300 Nuclear 800 Hydro OSS) Oil Total Existing System 5,162 S,232 Total Net Additions to 1987 1,636 1,65S Total Planned System to 1987 6,798 6,887 Total Long Range Additions, 3,14S 1988-1997 (a) Stations with joint okinership 1-65 Table I-19c. Delmarva Power and Light Company Net Capability W station unit Year SMmer I Winter Fuel Type Total Existing System Bayview IC 1 1964 2 2 Oil 1C 2 1964 2 Oil IC 3 1964 2 oil IC 4 1964 2 2 Oil 1C s 1964 2 2 Oil IC 6 1964 2 2 Oil 12 Cape Charles IC 1 1947 0.8 0.8 Oil IC 2 1936 0.8 0.8 Oil 1.6 Christiana Gr 11 1973 20 26 Oil Gr 14 1973 20 26 Oil 40 Conemaugh(a) 1 32 32 Coal 2 31 31 Coal IC A-D 0.4 0.4 Oil 63.4 Crisfield IC 1 1968 2.S 2.s Oil IC 2 1968 2.S Z.s Oil IC 3 1968 Z.s 2.S Oil IC 4 1968 Z.s Z.5 Oil 10 Delaware City 1 19S6 27 27 Oil 2 19S6 27 27 Oil 3 1961 6S.S 66.S Oil Gr 10 1968 17 21 Oil 136.S Easton IC 3 1936 0.5 0.5 Oil IC 4 1941 0.6 0.6 Oil 1C s 1947 0.8 0.8 Oil IC 6 19so 1.2 1.2 Oil IC 7 19S4 2.4 2.4 Oil IC 8 1957 2.S 2.S Oil IC 9 1961 2.2 2.2 Oil IC 10 1966 3.s 3.S Oil 11 1968 3.6 3.6 Oil 12 1970 4.1 4.1 Oil 13 1973 S.6 5.6 Oil 14 1973 5.6 5.6 Oil 32.6 Edge Moor 1 i9sl 70 70 Oil 2 i9si 70 70 Oil 3 19S4 82 82 Oil 4 1966 167 167 Oil s 1973 412 412 Oil Gr 10 1963 is is Oil 816 Indian River 1 1957 89 90 Coal 2 19S9 89 90 coal 3 1970 162 165 coal Gr 10 1967 17 19 Oil 3S7 Kent Gr 1 1964 12 is Oil 12 Keystone (a) 1 1967 31 31 Coal 2 1968 31 32 Coal IC 3-6 1968 0.4 0.4 Oil 62.4 Mdison Street Gr 1 1962 11 14 Oil 1C 2 1948 0.5 0.5 Oil ll.S W-Kee Run (Dom) 1 1961 is is Oil 2 1961 is is Oil peach Bcyttom(a) 3 197S i0s los Oil 135 2 1967 79 79 Nuclear 3 1974 78 78 Nuclear lS7 Sale, (a) 1 1977 80 81 Nuclear Gr 3 1971 3 4 83 1-66 Table I-19c. Delmarva Power and Light Company (continued) unit Year Net Capability W Station S1MW Winter Fuel Type Total Tasley IC 1 1929 0.3 0.3 Oil IC 2 1937 0.5 0.5 Oil IC 3 1929 0.5 0.5 Oil Gr 10 1972 26 33 .1 27.3 Viemia S 1948 17 17 il 6 1949 17 17 il 7 l9sl 40 40 il 8 1971 iso iss ii Gr 10 1969 17 19 il IC A 1965 0.5 O.S il 241.5 Ifest GT 1 1964 16 20 Oil 16 Additions and (Removals), 1978-1987 Easton 21-22 1978 12.S 12.S Oil Easton 3 1978 (0.5) (0.5) Oil Slem(') 2 1979 83.0 83.0 *clear Indian River 4 1980 400.0 400.0 :oal Easton 4 1981 (0.6) (0.6) )il Easton 23-24 1982 12.S 12.S 3il Easton 7 1984 (0-S) (0.5) Dil Unidentified 1985 100.0 100.0 3il Easton 2S-28 1986 2S.0 25.0 )il Edge Moor 1 1987 (70.0) C70.0) 3il Viffm S-6 1987 (34.0) (34.0) Dil Easton S 1987 0.8) 0.8) 3il Easton 8 1987 0.5) O.S) 3il Viema 9 1987 400.0 400.0 .10al Long Range Additions, 200 ;Ossil 1988-1997 1,300 Inidentified. Total Existing System 2,214.8 Z,266.8 Total Net Additions to 1987 926.1 926.1 Total Platmed. System to 1987 3,140.9 3,192.9 Total Lon Range Additions , 1988-199,71, 1,500 -1,500 (a) Stations with joint ownership 1-67 Table I-19d. Potomac Electric Power Company Lklit Year Net Capability W Fuel Type station r Winter Total Existing System Benning Road 10 1927 28 28 Oil 11 (b) 1929 (23) (23) Oil 12 1931 28 28 Oil 13 1947 47 47 Oil 14 19S2 26 26 Oil is 1968 275 27S Oil 16 1972 275 275 Oil 679 Buzzard Point l(c) 1933 (23) (28) Oil 2 1938 30 30 Oil 3 1940 48 so Oil 4 1942 48 so Oil 5 1943 48 so Oil 6 194S 48 so Oil Gr East 1968 124 160 Oil Gr West 1968 123 160 Oil 474 Chalk Point 1 1964 330 330 coal 2 1965 330 330 Coal 3 197S 602 602 Oil Gr 1 1957 18 18 Oil Gr 2 1974 so 35 Oil 1,310 Conemaugh(a) 1 1970 83 83 Coal 2 1971 82 82 coal IC A-D 1970 1 1 Oil 166 Dickerson 1 19S9 182 182 coal 2 1960 183 183 Coal 3 1962 182 182 Coal Gr 1 1967 13 13 Oil 560 NIorgantown 1 1970 SS6 S56 Coal 2 1971 SS6 SS6 Coal GT 1 1970 16 20 Oil Gr 2 1971 16 20 Oil Gr 3 1972 S4 65 Oil GT 4 1972 S4 65 Oil Gr S 1972 S4 6S Oil Gr 6 1972 S4 65 Oil 1,360 Potomac River 1 1949 86 87 Coal 2 1950 66 67 coal 3 19S4 102 102 Coal 4 19S6 102 102 Coal 5 1957 102 102 Coal 458 Additions and (Renewals), 1978-1987 Potomac River 3 1978 (1.3) (1.3) coal 4 1978 (1.3) (1.3) Coal S 1978 (1.4) (1.4) Coal 1-2 1979 (3.0) (3.0) coal Dickerson 1-2 1979 (10) (10) coal Chalk Point 1-2 1982 (8) C8) Coal 4 1982 600 600 Gil Bemning 10-14 1982 (129) (129) Oil Buzzard 1-6 1982 (222) (222) Oil Dickerson (a) 4 1985 400 400 Coal Long Range Additions, 600 Unknown 1988-1997 Soo Hydro/PS Total Existing System 5,007 S,142 Total xet Additions to 1987 624 616 Total Planned System to 1987 S,631 S,7S8 Total Long Range Additions 1988-1997 1,100 (a) Stations with joint ownership (b) Benning No. 11 turbo-generator can only function as a replacement for No. 10 and No. 12 turbo-generators but cmmt operate concurrently with them (c) Buzzard No. 1 is '@wthballed" and may be reactivated at a later date. The effective capability is currently considered to be 0. I-68@ 1111 Jim M M M M M W Table 1-20. Proposed new power plants and expansions of existing plants in Maryland SITE COUNTY NrAREST TOWN SITE SIZE PLANT TYPE PLANT SIZE COMPLET ALLEGiANY POWER SYSIIN SPOTOMAC EDISON) 1. Point of Rocks Frederick Point of Rocks 829 acres No plans. No plans. No pl (Originally planned ipinally planned for nuclear) Orr nuclear) ------------------------- -------------- ----------------------------------------------------- ------------------------------ BALTIMORE GAS & ELEC. 00. 1. Brandon Shores Anne Arundel Riviera Beach 350 acres Oil, with coal as Two 600 MN units 1981, alternate fuel 2. Dickerson Montgomery Dickerson 1000 acres Coal 800 MW of new 1985 (existing station) capacity 3. Soller's Point Baltimore Dundalk 1000 acres Gas turbine 100 Nil total new 1986 (existing station) capacity 4. Undetermined--north- 800-1000 eastern Maryland undetermined Undetermined acres Coal 800 W 1987 region ------------------------- -------------- ----------------------------------------------------- ------------------------------ CONOWINGO POWER 00. 1. Canal Cecil Chesapeake City 680 acres No plans. (Listed No plans No pl. as alternative nuc- lear site) 2. Seneca Point Cecil Charlestown 500 acres No plans. (Listed No plans No pl as an alternative nuclear site). ------------------------- -------------- ------------------------------------------------------ ------------------------------ Table 1-20. Proposed new power plants and expansions of existing plants in Maryland (Continued) SITE COUNTY NEAPYM TOWN SITE SIZE PLANT TYPE PLWr SIZE COMPLETION DATE NOTES DELWVA POWER LIGIT CO. 1. Vienna Dorchester Vienna 955 acres Coal 400 W 1987 (existing station) ------------------------- -------------- -------------------------------- -------------------- --------------------------------------- --------------------- EASTON UTILITIES COMM. 1. Easton Plant 2 (existing station) Talbot Easton 7 acres No. 2 Oil 37.5 MW 1982, 1986 ---------------------------------------- -------------------------------- -------------------- ------------------------------------------------------------- P01MC ELECTRIC POWER CO 1. Chalk Ibint (existing station) Charles Benedict 1160 acres Oil 600 W 1982 4 2. Dickerson 4 Jointly owned with (existing station) Montgomery Dickerson 1004 acres Coal 800 W 1985 BG&E. PFM is managing partner. PFPW share is 400 MW. 3. undetermined Undetermined Undetermined 1000 acres Pumped Storage 1000 MW Undetermined 4. Douglas Point Charles Nanjempy 1400 acres Nuclear 2200 MW Undetermined ------------------------- -------------- -------------------------------------------- ------- --------------------------------------- --------------------- MW W W, W W, M, W M W M W W W M M M M M IN M W Table 1-20. Proposed new power plants and expansions of existing plants in Maryland (Continued) SITE COUNTY NEAJW= TOM SITE SIZE PLMr TYPIE PW SIZE COMPLETION N DATE PTES SOLMiERN MARYLAND HLEURIC COOPEWIVE 1. Della Brooke Farm St. Mary I s Oraville 300 acres No plans No plans No plans ------------------------- -------------- ------------------------------------------ 7------ ------ --------- ------- -------- MARYLAND POWER PLANr SITING PROGRUFS= 1. Elms St. Wry"s St. Mary's City 1000 acres No plans No plans No plans Site is designated for PEPCO. No plans have been announced for its use, 2. Bainbridge Cecil Port Deposit 937 acres No plans No plans No plans Site is in process @4 of acquisition from U.S. General Services Administration. Site has been designated for the BG&E system. No plans have been announced for its use. Philadelphia Electric Co. (Cono- wingo) has indicated interest in sole or joint use of site. ------------------------- ----------------------------------------------- ---- -------------- ------ ----------- ---------------- --------------------- REFERENCES -- CHAPTER I 1. Perso nal Communication, Mr. G. Baines, PEPCO, and Mr. W. Thompson, BG&E. 2. FPC Form 1 Reports of each utility for the years 1967-1977. 3. "1977 Annual Report to Congress, Volume III, Statistics and Trends of Energy Supply, Demand and Prices," Energy Information Administration, U.S. Department of Energy, Washington, D.C., May 1978. 4. The National Energy Plan, Executive Office of the President. Office of Energy Policy and Planning, Washington, D.C. April 1977. 5. "National Energy Outlook," Federal Energy Administration, Washington, D.C., February 1976. 6. "President Carter's Energy Proposals: A Perspective," Staff Working Paper, Congressional Budget Office, U.S. Congress, Washington, D.C., June 1977. 7. "8th Annual Review of Overall Reliability and Adequacy of the North American.Bulk Power Systems," National Electric Reliability Council, Princeton, N.J., August 1978. 8. "29th Annual Electrical Industry Forecast," Electrical World, September 15, 1978. 9. "Electric Power Supply and Demand, 1977-1986 as Projected by the Regional Electric Reliability Council in their April 1, 1977 Responses to FPC Order 383-4 Docket R-362," Federal Power Commission, Washington, D.C., .May-1977. 10. Minerals Yearbook 1975. Vol. 1. Bureau of Mines, U.S. Department of the Interior, Washington, D.C. 1977. 11. "2,8th Annual Electrical Industry Forecast," Electrical World, September 15, 1977. 12. Energy in Focus, Federal EnergyAdministration. Washington, b.C. May 1977. 13. "Typical Electric Bills," 1971-1977, Federal Power Commission, Washington, D.C. 14. Article 3-304(l), Natural Resources Article, Annotated Code of Maryland. 15. Case No. 6807 and Case No. 7259, Maryland Public Service Commission. 16. Case No. 6807, Maryland Public Service Commission. .1-72 17. "Projected Electric Power Demands for the Baltimore Gas and Electric Co.," Maryland Department of State Planning for the Maryland Power Plant Siting Program, Maryland PPSP, forthcoming. 18. FPC Form 1 Reports of each utility for the years 1960-1977. 19. FPC Form 1 Reports of each utility for 1966; "Coordinated Regional Bulk Power Supply Programs," ECAR Information Report to Economic Regulatory Administration, U.S. Department of Energy, ECAR, Canton, Ohio, April 1, 1978; "MAAC Systems Plans," Mid-Atlantic Area Council, April 1, 1978. 20. Testimony of Carl Cater, Allegheny Power System, Maryland Public Service Commission, Case No. 7259, August 30, 1978. 21. Appendix A; Appendix B; Letter from Mr. M. Kahal, J.W. Wilson and Asso- ciates to Mr. H. Mueller, reporting updated PEPCO forecast, November 17) 1978; testimony of various utilities in Maryland Public Service Commission Cases 6807 and 7259; "Coordinated Regional Bulk Power Supply Programs," Op. Cit.; "MAAC Systems Plant," Op. Cit. 22. "Coordinated Regional Bulk Power Supply Program," ECAR Information Report to Economic Regulatory Administration, U.S. Department of Energy, ECAR, Canton, Ohio, April 1, 1978; "MAAr Systems Plans," Mid-Atlantic Council, April 1, 1978; "Inventory of Power Plants in the United States," Office of Utility Project Operations, U.S. Department of Energy, Washington, D.C., December 1977. 23. "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," NUREG-751087, Office of Nuclear Reactor Regula- tion, U.S. Nuclear Regulatory Commission, Washington, D.C., September 1975. 1-73 CHAPTER II AIR IMPACT The quality of the air around us is measured in terms of the ground-level concentration of certain pollutants. Changes in this air quality is the result of several factors such as emission of pollutants, the atmospheric transport and dispersion of the pollutants, and chemical and mechanical processes acting on the pollutants. The impact of the pollutants on man and materials depends on frequency, duration, and level of exposure, and on the chemical reactivity of the pollutants, as well as the susceptibility of the receptors to damage. To protect man, primary air quality standards have been established while sec- ondary standards protect against damage to materials. The interplay of these various factors is discussed in this Chapter. In sections A to D, we will discuss the nature of power plant emissions, the health effects of the pollutants, standards protecting human health, and, finally, the present levels of pollution. Section E will focus upon emission control of SO 21' the major power plant pollutant. Mathematical modeling of pollutant plume dispersion, often a central factor in licensing procedures, is discussed in Section F. Finally, the provisions and implications of the Clean Air Act Amendments of 1977 are reviewed in Section G. A. Sources and Nature of Emissions Airborne wastes from power plant combustion include sulfur oxides (SO X), possibly mixed with sulfates and sulfuric acid mist, nitrogen oxides (NOX), particulates, and, to a lesser degree, hydrocarbons, carbon monoxide , flourides, carbon dioxide, and traces of organic and metallic compounds. The rate of release depends on the type of fuel, power level, the type of boiler firing, and the efficiency of pollution control devices such as precipitators and scrubbers. During combustion, sulfur in coal and oil is almost completely converted to S02 and emitted through the stack, unless it is absorbed in a scrubber. The preponderance of NOx emitted is due to reactions between 02 and N2 in the air at elevated temperatures. Thus, NO x emission rates are sensitive to flame temperature and amount of excess air entering the furnace. Particulates, mainly non-combustible fuel residues (silicates, metal salts, sodium chloride) and incompletely burned organic materials, are often removed from the flue gas by precipitators. Table II-1 shows Maryland area power plant (Figure II-1) emissions for 1974 and 1975 and the total state emission inventory (1) by source category as obtained from measurements and theoretical calculations. It can be seen that, of the five major pollutants emitted by all sources in Maryland, power plants contribute negligible amounts of carbon monoxide and hydrocarbons, about 30 percent of the NOXI 32 percent of the particulate, and 69 percent of the sul- fur oxides. Power plant contributions to ground-level concentrations of these pollutants are, however, much smaller than these emission data indicate (see Section D). Table II-1. Statewide total emissions inventory, 1974 and 1975 Ile t' Power Plants Mobile Sources Process Refuse Total (a) 1974 '65 Y97F-f97@ 1974 1975 l9r4____F975 1974-----T975 1974-197 Particulate (b) Tons/yr 12,200 9,900 47,SOO 27,300 17,600 18,600 22,000 27,700 4,300 1,500 103,SOO BS5,400 I of total 11.8 11.6 45.8 32.0 17.0 21.7 21.2 32.4 4.2 1.7 SLIfur Oxides Tons/yr 62,200 60,000 248,800 283,SOO 18,100 26,600 45,500 39,300 800 400 37S,SOO 409,900 i of Total 16.6 14.6 66.3 69.2 4.8 6.5 12.1 9.6 0.2 0.1 Hydrocarbons (c) Tons/yr 3,200 3,700 2,100 2,800 198,100 259,900 77,400 44,900 1,100 300 281,900 336,100 % of Total 1.1 1.1 0.8 0.8 70,3 77.3 27.S 13.4 0.4 0.1 Nitrogen oxides Tons/yr 47,400 46,800 102,900 104,900 154,200 189,400 39,600 17,500 1,000 400 342,900 359,100 of Total 13.7 13.0 29.8 29.2 44.7 52.7 11-S 4.9 0.3 0.1 Carbon Monoxide Tons/yr 9,900 8,700 3,900 4,300 1,374,500 1,808,000 112,200 85,200 3,800 4,000 1,S04,300 1,915,400 of Total 0.6 0.5 0.3 0.2 91.4 94.4 7.S 4.5 0.2 0.2 (a) Includes a miscellaneous category. (b) 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. (c) In addition, about 1SO.000 tons per year is released from asphalt roads in the State. This quantity can be reduced to 20,000 to 25,000 tons per year by current use of a different type of road tar. Bnission from an asphalt surfaced road decreases significantly over a period of one to two years. W M ilmn MM M M MM MM M mmmm M M 23 21 14, 13 21 Existing Plants for Maryland A (Capacity in MW) Plant Name Utility Steam Gas Fuel of 19 Turbine Steam Unit I Benning Road PEPCO 679 Oil 2- Brandon Shores BG&9 1,220 Oil 3. Buzzard Point PEPCO 222 252 Oil 4. Calvert Cliff s BC&E 1,620 Nuclear 3 5. Chalk Point PEPCO 1,262 48 Coal/Oil 6. C.P. Crane BG&E 384 14 Oil 7. Crisfield DELMARVA 10* 8. Dickerson PEPCO 547 13 Coal 9. Eas ton EASTON 33* 10. Gould Street BG&E 103 Oil 11. Morgantown PEPCO 1,112 248 Coal/Oil 43 12. No tch Cliff BG&E 128 13* Perryman BG&E 204 14. Philadelphia Road BG&E 64 H 15. Po tomac River PEPCO 458 Coal 24 r H 16. Riverside PEPCO 321 172 Oil 101 4-41 1 17. R.P. Smith POT.ED. 129 Coal u.) 18. Vienna DELMARVA 224 17 Oil 19. Wagner BG&E 988 14 Oil/Coal 20. Westport BG&E 177 Ila Oil 25 Diesel units Plants for Out-of-State Utilities(A Sites Discussed for Future Plants 21. Bainbridge 22. Chesapeake City 23. Conowingo 24. Douglas Point 25. Elms 26. Mount Storm (VEPCO) 27. Possum Point (VEPCO) 28. Summit Figure II-1. Power plants in the @Iaryland -region B. Health Effects Numerous investigations have sought to document the health effecus of exposure to air pollutants for concentrations normally encountered at ground level (2). Scientific consensus on the interpretation of dose-response data has led to enactment of Federal and State Ambient Air Quality Standards, which include sufficient safety margins (as a hedge against uncertainty in the data) to protect even the most sensitive segments of the population (3). Emission stan- dards and fuel use regulations have also been promulgated as a means of obtain- ing compliance with Ambient Air Quality Standards by regulating pollution at its source. There is an increasing realization that few of the pollutants for which standards have been established act directly or alone in producing medical effects. Toxicological studies indicate that the chemical transformation pro- ducts of S021 mainly sulfates, are more likely than S02 alone to be responsible for many of the adverse health effects associated with ambient sulfur oxides. In the absence of other pollutants, such as ozone and particulates, S02 is a mild respiratory irritant; but there is evidence that certain sulfate compounds (especially sulfuric acid aerosols) are more severe irritants (4). For instance, epidemiological studies in several U.S. cities have associ- ated high daily or annual sulfate levels with increased frequency of asthma attacks, intensification of symptoms in cardio-pulmonary patients, decreased ventilatory function in school children, and symptoms of acute and chronic respiratory disease in children and adults. Taken together, findings of the toxicological and epidemiological studies suggest that sulfate compounds may be the agents responsible for the observed excess mortality associated with high S02 levels (5). Similarly, many hydrocarbons have been found not to be medically harmful, but they take part in a chain of photochemical reactions with NOX and other atmospheric constituents to form oxidants, such as ozone (03), which are major irritants (6). Thus, in many cases, the emitted pollutants are only precursors to the substances which actually constitute the health hazard. Since these relation- ships between precursors and their end products are complex and often poorly known -- even the origin of some of the precursors (e.g., hydrocarbons) is not well understood -- the Environmental Protection Agency (EPA) has found it pre- mature to establish standards for "ultimate pollutants" such as sulfates. Until more is known about the reaction processes, it is considered sound and meaningful strategy to control the five major "criteria" pollutants: partic- ulate matter, sulfur dioxide (S02), nitrogen oxides (NOx), carbon monoxide, and hydrocarbons. C. Standards Ambient air quality is measured and defined as ground-level concentration of pollutants. Federal and State agencies are attempting to attain and maintain good air quality by regulation of: (a) pollutant ground-level concentrations, 11-4 through ambient air quality standards, (b) source emissions, through source emission standards, and (c) the quality of fuels burned, through sulfur con- tent standards. Ambient Air Quality Standards have been established by the Federal En- vironmental Protection Agency for ground-level concentrations of certain pollutants.* The National Ambient Air Quality Standards (NAAQS) (7) are listed in Table 11-2. The National Primary standards are designed to protect human health (i.e., medical effects of pollution), whereas the secondary standards are concerned with the protection of human welfare (i.e., the material and aesthetic effects of pollution). Emission Standards were established by EPA in December, 1971 under autho- rity of the Clean Air Act of 1970 for new sources, i.e., sources beginning operation after 1977 (8). To satisfy the requirements of the Clean Air Act Amendments of 1977, EPA has proposed new standards of performance for stationary sources (8). These standards would apply to utility steam generating units for which construction is commensed after September 18, 1978. Table 11-3 compares these New Source Performance Standards (NSPS). Fuel Standards have been imposed by the State in the form of limits on the sulfur content in coal and oil that can be used in specific power plants and in oil for home consumption (9). In addition to the standards, a comprehensive body of guidelines and regulations have been developed at national and state level to control and maintain air quality. Several of these regulations will be discussed in sub- sequent sections. D. Status and Trends in the Maryland Airshed In general, all areas of the State are currently in compliance with the National Ambient Air Quality Standards, except for the hydrocarbon and photo- chemical oxidant standards which are violated throughout the State, and sus- pended particulate and carbon monoxide standards which are violated in part of the Baltimore area and part of the Potomac Valley (10) in Allegany County. Trends in ambient air quality can be determined from analyses of ground- level concentration data from air quality monitoring stations. The national air quality trends presented below are based on data from the U.S. Environ- mental Protection Agency's National Aerometric Data Bank (NADB). These data are gathered primarily from State and local air pollution control agencies through their monitoring activities (11). Maryland data are reported by the State's Bureau of Air Quality and Noise Control (BAQNC) which has stations throughout the State mainly in the urban areas (12). Because of the non-uniform distribution of stations, the ground- level concentrations reported may not be representative of the overall status Maryland Ambient Air Quality Standards were repealed by HB 1146 in the 1978 legislative session. The National Ambient Air Quality Standards therefore apply to the State. 11-5 Table I I - 2. Federal ambient air quality standards Primary National Secondary Ug/m 3 ppm Ug/m3 ppm Sulfur Oxides Annual Arithmetic Mean 80 0.03 24-hr Maximum(a) 365 0.14 3-hr Maximum(a) 1,300 0.5 1-hr Maximum(b) Suspended Particulate Matter Annual Geometric Mean 75 60 24-hr Maximum(a) 260 150 Carbon Mon@xld ta) 3 8-hr Maximum ,mg/m 10 9 10 9 1-hr Maximum(a), mg/m3 40 35 40 35 Hydrocarbons (non-Teth (carbon) (carbon) 11) 160 0.24 3-hr (6-9AM) Maximunfa 160 0.24 Nitrogen Dioxide 100 0.05 100 0.05 Annual Arithmetic Mean Photochemical Qxjdants (ozone) (ozone 1-hr Maximumtc) 240 0.12 240 0.1@ (a)Not to be exceeded more than once per year (b)Not to be exceeded more than once per month (c)The ozone standard was changed from 160 -og/m3 and 0.08 ppm in January 1979 (regulations to be published in Federal RegiSter week of February 5, 1979) 11-6 M M M M M M M M M M M M M M M M M Table 11-3. Existing new source standards of performance for fossil fuel fired steam generators (1971) and proposed standards (1978) Pollutant Old Standard Proposed Standard Particulate matter 0.10 lb per million BTU heat input, maximum 0.030 lb/per million BTU heat input, maximum 2-hr average. 2-hr average. 20 percent opacity (6-min average); except Same that 40 percent opacity is permissible for not more than 2 min in any hour. ----------------------------------------------------------------------------------------------------------------- (n'l Sulfur dioxide 0.80 lb per million BTU heat input, maximum Same-'-' 2-hr average when liquid fossil fuel is burned. 1. 2 lbs per million BTTJ heat input, maximum Same(a) 2-hr average when solid fuel is burned. 8S perce t reduction of uncontrolled emission.5) ------------------------------------------------------------------------------------------------------------------ Nitrogen oxides 0.2 lb per million BTU heat input, maximum Same 2-hr average, expressed as N02, when gaseous fossil fuel is burned. 0.30 lb per million BTU heat input, maximum Same 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, maximum 2-hr average, expressed as N02, when solid 2-hr average, expressed as N02, from combus- fossil fuel (except lignite) is burned. tion of bituminous coal. 0.50 lb per million BTU heat input, maximum 2-hr average, expressed as NO from combus- tion of subbituminous coal., Ile oil, or any solid liquid or gaseous fuel derived from coal. (a)Except for 3 days per month; compliance to be determined on a 24-hr daily basis. (b)Except for 3 days per month; when only 75 percent reduction is required. For sources emitting less than 0.20 lb/ million BTU, the percent reduction requirement would not apply. of air quality, but the trends, or changes, at these stations do indicate the state-wide trends. However, since many stations have been moved over the years and the measurement methods have changed, it is sometimes difficult to find stations with sufficient continuity to establish long-term trends. Emission data are obtained from estimates of indicators such as fuel consumption, 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 (13). In the following sections, national and State trends in air quality are discussed for the three main power plant pollutants. Total Suspended Particulates (TSP) The national trend for TSP ground-level concentrations shows considerable improvement from 1960 to 1975 at 95 urban stations throughout the nation (14). The urbaI composite average Sf the annual geometric mean decreased from about 110 lig/m in 1960 t 72 ug/m in 1975, just below the primary national standard of 75 ug/m In a much broader sample of 2350 stations throughout U.S.A. (11) the recent trend, from 1970 to 1976 is shown in Figure II-2A. Peak daily concentrations are shown in Figure II-2B for the same stations. Corresponding emission trends are shown in Figure II-2C. Additional particulate emission control is not expected to produce much improvement in air quality, since many areas have a high background concentration of natural origin (e.g., windblown dust and pollen). There has also been a downward trend in TSP concentrations in Maryland over the last 10 to 15 years (12). Because of changes in locations and dele- tion and additions of stations, the trends may not be immediately evident from an inspection of the annual air quality data reports. Figure 11-3 shows the number of stations violating state standards for annual arithmetic mean of TSP out of a group of 35 measuring stations which have been in-operation at the same location for the six years, and where each station has had at least one violation in one of the six years. Improvement is indicated by decreasing violations. Figure 11-3 shows the trends for these stations from 1971 to 1976, and the trend for all Maryland stations is shown in Figure 11-4. A closer inspection of the air quality data from the Bureau of Air Qual- ity and Noise Control reveals that there are two general non-attainment areas: along the Potomac Valley from the Bloomington/Luke area to Cumberland, and in the southeastern part of Baltimore City. The importance of these non-attainment areas to the siting of future power plants will be discussed in Section G. The problem in maintaining a satisfactory air quality in the greater Baltimore area has been investigated (15) through the use of an Air Quality Display Model (AQDM) (16). This model calculates ground-level concentration of pollutants using a Gaussian plume model with appropriate atmospheric sta- bility and wind conditions established from 5 years of meteorlogical records. Discrete (e.g., industrial and commercial) and distributed (e.g., home heating) emission sources are used as inputs to the model. Vehicular emissions are also 11-8 MILLIONS OF TiONS TOTAL SUSPENDED PARTICULATE CONCE 0-3 0 m n n qk,.n c:) %-n C=) 0 0 0 CD @-n %.n c=) CD C) C) c:) C) C) C:) C) C) 20 0 0 (A U) tA rt H FJ- " r@ r+ P5 CD w (D r+ r@ FJ- FJ- P) co (@D rt Qq r+ GQ 0 (D 0 0 r+ U4 1-h w H- Ln U-1 2 C:)Io c) @-A (::@0 R -< F-1 m C+ c/) (D 12LA 03 H W C+ 0 FJ- r+ @j r+ 0 QQ P rt F-A (D (A (A F-1- (f) rt C+ (D (D (A r+ (D (D -4 CLA c-- r+ FJ. (D (D F 100 /-Lg/m3 80 60 -r-exceeding 65kLulm CcD 30- 3 exceed i ng 75/-Lg /M Ca - 40 -1--0 20- 10- E 20 0- 71 72 73 74 75 76 year 1971 1972 1973 1974 1975 1976 YEAR Figure 11-3. The bar graph (insert) shows the number of violations of the State standards for total suspended particulates (TSP) for a set of 35 stations throughout Maryland. These stations have a continuous record since 1971 and exceeded one or the other of the "more adverse range" or "serious level" State standards at least once during this period. The graph on the top shows the composite means of the annual average of TSP for these stations. (The State Standards have since been replaced by Federal primary and secondary standards of 75 iig/m@ and 60 Pg/m3, respectively.) II-10 200 150 E 100 Ln 50 AVERAGE YEA R 1971 1972 1973 1974 1975 1976 1977. Figure 11-4. Coffposite mean of the annual averages of total suspended partic- ulates (TSP) for all Maryland stations with a continuous record for the six years shown. The bars indicate the range of values for the stations. T T T T T accounted for using known traffic density and emission rates per miles travelled. A set of baseline emission conditions have thus been established for 1973, and forward projections to 1985 have been made using expected rates of change in economic activities (including new power plants such as Brandon Shores) and population shifts, from Department of State Planning data. The AQDM can only calculate ground-level concentrations under prevailing average conditions in a gross sense, and it does not account for localized effects (caused by conditions such as local wind patterns, detailed topography or any shielding effect) at any particular spot where measurements may be taken at a monitoring station. Although all known major emission sources are in the model, unknown small sources may be located near a monitoring station and affect its readings, although their impact on overall air quality may be negligible. Therefore, one must not expect a point by point agreement between calculated and measured value in any one area, particularly in an urban area. However, general overall distributions and trends should agree between the model and field measurements. Figure 11-5 shows the expected distribution of annual average TSP for the Baltimore area in 1973, 1980, and 1985, based on model runs (15). Used as trend indicators, the model runs show that the air quality of the region will change little over the next 10 years, and that the existing pattern of viola- tions of the annual average will continue unless control efforts are intensi- fied. Other calculations for the 24-hour average indicate that this standard also will be violated regularly throughout a sizeable part of Baltimore City and the suburbs surrounding the industrial area (Essex, Sollers Point, Lansdowne, and Glen Burnie) unless corrective measures are taken (15). An additional problem with the TSP levels (not considered in the model runs) has resulted from the federal coal conversion program. At the present time, Morgantown, Dickerson, and Chalk Point Units 1 and 2, are burning 100% coal (as coal deliveries and emission constraints allow), as opposed to a coal /oil mixture. In the Baltimore area, Wagner Units 1 and 2, Riverside and Crane, are now burning oil and are under active consideration for coal conversion. The Department of Energy (DOE) is studying the impacts of these conversions and is expected to announce the results of its study by the end of 1979. To meet State emission control limitations at these three plants would require substantial investment in precipitators. Recent estimates range from 18 to 30 million dollars per unit (17). Even with this equipment, the addi- tional impact of coal burning on the Baltimore Airshed may be sufficient to warrant a negative decision for conversion of one or more of these plants. The DOE study will include an evaluation of this impact. Two power plants, Chalk Point and Dickerson, are presently not in compli- ance with particulate emission limitations. The precipitators on the older units at these plants need to be upgraded to modern standards. Plans have been submitted that will achieve final compliance by July 1, 1979 in accordance with the Clean Air Act Amendments. The new Chalk Point #3 unit was recently damaged by fire. Final repairs and upgrading started in January 1978. No final compliance deadline has been set. 11-12 Carroll County Harford County Baltimore County 40-65 R/ 3 0-40 /m ....................... Howard County 65-75 /.Lg/ M3 ..... ..... .... Anne Arundel Cou nty -1973 ---- 1980 ........ 1985 Figure 11-5. Estimates of total suspended particulates ground-level con- centrations by the Maryland Bureau of Air Quality and Noise Control 11-13 Sulfur Dioxide (SO 2) From 1964 to 1975 there was a decrease of about 60 percent in the composite annual SO 2 arithmetic means from 32 stations throughout the U.S. (14). Most of the improvement (a 50 percent decrease in the composite mean) occurred between 1964 and 1971 and was much greater for the "dirty" areas than for the "clean" areas. In the indultrial northeast, the "dirtiest" reSion, the annual mean fel' I from almost 90 pg/m in 1964 to a little above 40 lig/m in 1971. Recent trends (1970-1976) are shown in Figure 11-6 for a much broader sam- ple of 722 stations throughout the U.S.A. (11). Plots of national emissions (Figure 11-7) show that, during the period when S02 ground-level concentrations decreased by 50 percent (1964 to 1971), the total SO emissions increased by more than 20 percent (27 to 33 million tons per yeari. This apparent incon- sistency can largely be explained by the following considerations. First, most air quality monitoring stations are located in urban areas whereas large power plants, the most important source of the increase in emission (Figure 11-7), are increasingly being located in rural areas. They contribute little to urban pollution levels because of distance, their tall stacks, and high buoyancy flux; all of which increase the S02 dispersion. Secondly, the SO 2 emissions in and around the cities have decreased markedly as clean fuels, such as low sulfur oil and gas, have replaced coal and high sulfur oil for space heating in resi- dential and commercial establishments. The effect of this fuel replacement is small. on national emissions but large on local air quality. Maryland SO@ data generally follow the national trends up to 1970 (12). Z ground-level concentrations, Since 1972, there has been some improvement in S02 which have been in compliance with the air quality standards. Figure 11-8 shows the trend at several stations across the State since 1973. Figure 11-9 shows a seasonal trend in the S02 concentration (measured by the flame photometric method). Higher levels in the heating months (first and fourth quarters) further indicates that a large contribution to the S02 level comes from local sources, primarily space heating units (most Maryland power systems have higher summer than winter loads, see Chapter I). Predictions by the AQDM for 1973, 1980, and 1985 (see Figure II-10) indicate that the SO 2 air quality will change little through these years, and that no violations of current So 2 standards are expected (15). As with TSP, the heavi- est So 2 Pollution will be in the industrialized southeastern part of the city and the adjoining suburbs. A special study was made using the AQDM to compare the contribution from BG&E power plants to the S02 level in this critical industrialized area of Baltimore to that from a group of 23 industrial sources (17). Table 11-4 shows the calculations of the BG&E plants contributions to the SO 2 ground-level con- centration. The detailed data (not shown here) reveal that, as a group, these power plants are either the second or third largest contributor at each of the receptor points shown. However, their total contribution to the ground-level concentration (about 17 percent) is far below their contribution to SO emission (55 percent). In contrast, the 23 other industrial sources contributei 70 per- cent or more of the ground-level so2 concentration (at most of the receptor points) from only 31 percent of the total emissions. It appears that distributed sources, e.g., from home heating units, are not adequately accounted for in the 11-14 60 50 - 40 - E 30 - 20 - 10 - 01 YEAR 1972 1973 1974 1975 1976 Figure 11-6. Composite average of annual mean S02 concentrations at 722 U.S. sampling sites. 11-15 40 30 New Series V) .-Z Tota I C) o 20 CD New Series 10 Electric Utilities 0 1940 1945 1950 1955 1960 1965 1970 1975 YEA R Figure 11-7. Long-term trends in U.S. S02 emissions. New Series starting in 1970 are based on improved New Se@nes estimating techniques. 60 50i- AVERAGE 40 - Cn E 30 - -L 20 - 10 - YEAR 1973 1974 1975 1976 1977 Figure 11-8. Corposite mean of annual arithmetic averages Of S02 for those stations in Maryland with complete data f6i entire year. Measurements are by the flame photometric method, which was introduced in 1972, and has full-year coverage since 1973. Ranges of values indicated by the bars. F T 11-17 50 40 E ZL 30 20 00 10 0 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1973 1974 1975 1976 1977 Figure 11-9. Seasonal trend in S02 ground-level concentration. Average for all Baltimore City and County stations (Flame Photometric Method). M,M M M MW M M M M M M M Ca rrol ICounty Baltimore County Harford County 3 0-29/.Lglm 3 20-40p.g/ m Howard County 0-50pg),m3 3 50-60/Lg/m Anne Arundel 1973 Cou nty 1980 .......... 1985 Figure II-10. Estimates Of S02 ground-level concentrations by the Maryland Bureau of Air Quality and Noise Control 11-19 Table 11-4. Calculate contribution to S02 ground-level concentrations from BG&E power plants compared to contributions from 23 other industrial sources at various receptor points in greater Baltimore. Percentage Percentage Contribution Contribution a) from other named b) Receptor Point from BG&E Plants( Pollution Source@ 1973 Conditions Sun and Chesapeake is 73 Fort IvItHenry 18 70 Patapsco Sewage Treatment Plant 12 79 Reed Street 21 75 Essex 18 69 Sollers Point 12 79 Riviera Beach 27 64 Fort Howard 14 79 Sparrows Point High School 17 76 Sandy Plains 18 70 Cleaners Hangers 13 70 Fire Department #22 is 70 (a) The plants are: Crane, Riverside, Westport, Gould and Wagner. Calculations are rounded to nearest percentage point. These plants emitted 71,300 tons S02 in 1973. (b) A total of 23 individual sources, which emitted 40,800 tons S02 in 1973. 11-20 calculations, since the total contributions shown in Table 11-4 from the named sources adds up to about 90 percent of the GLC. Nitrogen Oxides (NO X) Nitrogen oxides are formed in the power plant combustion process primarily bv interaction of atmospheric nitrogen and oxygen at high temperature. There has been a national trend toward increasing ground-level concentrations of both nitric oxide (NO) and nitrogen dioxide (N02). Historical data for these pollu- tants is extremely limited. The Federal Continuous Air Monitoring Program (CAMP) shows increases of 13, 6, and 9 percent in NO, NO 2, and total NO + NO 2 ground- level concentrations, resoectively, for the period 1964 to 1971 at the five urban CAMP sites (14). The NOx emissions from both power plants and motor vehicles have shown an increasing trenri, but since 1976 the emissions from motor vehicles have stabi- lized because the increase in miles travelled has been offset be decreased emissions due to automotive pollution control devices (18). Figure II-11 shows the trends in Maryland for the annual average ground- level concentration of '402 (12). It is difficult to separate power plant con- tributions from those of other sources. Other Pollutants Particulate Constituents. There are national and state standards for sus- pended particulate matter and state standards for settleable particulate matter. Because particulates are known to cause disease and discomfort, several constit- uents of particulates are being monitored, although there are no specific stan- dards for their concentration level. One group of such constituents is the benzene soluable organic (BSO) portion (about 3 to 5 percent) of total suspended particulate matter in the ambient air. Polycyclic aromatic hydrocarbons, many of which are present in the BSO fraction, have been linked to cancer in animals, and one of them, Benzo-a-pyrene (BaP), is believed to be potentially carcinogenic in humans (19,20). Power plants have relativelv low hydrocarbon emissions because of their efficient combustion process, and the main sources of BSO are probably burning coal for space heating. A decrease of 50 percent of this activity from 1960 to 1970 (see Figure 11-12) was probably the major reason for the declining trend in BSO and BaP (20). Controls on automotive combustion may be another factor. Since power plant coal consumption doubled from 1960-70 (Figure 11-12) while the BSO level decreased, it is evident that power plants must have a minor effect on urban BSO levels. A definite seasonality in the BSO ground-level concentra- tions is also evident. Sulfates. The sulfur emitted into the atmosphere is ultimately removed primarily by precipitation and dry deposition on the ground. Most of the S02 is converted to sulfate, either before or during this removal process. Global mass balance estimtaes yield atmospheric residence time for sulfur compounds in the range of 1 to 8 days, suggesting that long-range transport of sulfate is 11-21 110 100 90 - 80 - AVERAGE 70 - 60.- < 50 < 40 LU U- W- 30 Ln 20 J. JL 10 YEAR 1971 1972 1973 1974 1975 1976 1977 Figure II-11. Composite mean of annual arithmetic 'iverages of.N02 concentrations (measured by 24-hr gas bubbler) for Maryland since 1971-. Ranges of values are indicated by the bars. T 11-22 35 14 COAL CONS UMED I N RETA I L DEL I VER I ES (LEFT SCALE) 30 - 12 25 - COAL CONSUMED IN 10 ELECTRIC UTILITIES E E BS Multiply left scale by 10 (R I GHT SCALE) CD 20 8 BSO uj LU U C-) 15 6 V) Coal ;z 0 C) Ln Co U M = 10 4 0 5 Ba P (R I GHT S CALE) 2 0' 1970 0 1960 1961 1962 1963 1964 1965 196'6 1967 1968 1969 TIME, year Figure 11-12. Trends in national power plant and retail coal consumption, and in BSO and BAP annual averages. Utility coal consumption 0 P (Rl@ annual cumulative growth rate is approximately 7.2 percent from 1961 to 1971. 11-23 possible (21). A major concern is the possibility of long-range transport from the industrialized midwest into Maryland. The various meithanisms for sulfate formation are poorly understood. The oxidation of S02 and its ultimate transformation into sulfates involve several reactive agents, such as fine particulates, ammonia, catalytic metals, and photochemical reactants. Sulfate formation rates are usually enhanced by high humidity and temperature. Rates of S02 oxidation in the ambient air are thought to range between 0.035 and 11.7 percent per minute (22). It has been observed that S02 oxidation rates in power plant plumes for distances of up to 30 miles are 1 to 2 percent per hour for coal-fired plants and 10 to 20 percent per hour for oil-fired plants (23). This difference is explained as follows. In oil-fired plants, more metallic catalysts (e.g., vanadium) are present and accelerate the oxidation. Additionally, in the coal- produced plumes, So oxidation is originally inhibited by high concentrations of NO (nitric oxidei, which will be preferentially oxidized to N02 by background oxidants. However, as the plume progresses downwind, several other factors enter into the oxidation process: NO is depleted as more ambient oxidants are encountered, N02 participates in a photochemical process leading to oxidation of S02. and ammonia (possibly of rural origin) in the ambient air acts to con- trol one of the more Important conversion mechanisms. Thus, the extent of S02 oxidation can depend more on concentrations of other precursors than on the concentration of S02 itself. Therefore, a reduction in ambient S02 level may not always produce a corresponding decrease in sulfate production, if these precursors are limited (24).. Nationwide, there has been a general decrease in urban S02 levels of more than 50% between 1960 and 1970, but there is no consistent trend for urban sulfates (14). A combination of long-range transport and the complex precursor relationship may account for this. The decreased S02 emissions in the cities reduce the local sulfate component, whereas the increased rural emissions5 mostly from power plants, may have caused an influx of transported sulfates off-setting the decrease in the locally formed sulfates. Figure 11-13 shown a comparison of Maryland quarterly averages of S02 and sulfates from 1976, when the sulfate measurements began (12). Although there is mounting evidence of health hazards, no sulfate ground- level concentration standards have been established. EPA's current position is that not enough is known about sulfate formation and its health effects to war- rant immediate establishment of standards (25). While standards are being form- ulated, control of sulfates will be attempted through maintenance of control of the precursor pollutants: S02 and particulates. Enforcement of state imple- mentation plans for control of S02 and particulates, and increasing application of new source performance standards to power plants are thus relied on to reduce the rate of increase in the ambient sulfate levels. Photochemical Oxidants and Hydrocarbons. Photochemical oxidants5 mainly ozone (03), are pollutants of increasing concern. The mechanism of ozone formation in the atmosphere is not completely understood. There is complex rela- tionship between precursor pollutants, particularly non-methane hydrocarbons (NMHC) and NO possibly transported over considerable distances, and the crea- tion of 0 9' 3 (2 ). In this respect, the situation is analogous to the S02-sulfate 11-24 45 40 15 S02\ 35 _E 30 cn, Ln 25 10 CD S ulfates V) 20 15 V 10 5 Quarters 1 2 3 4 1 2 3 1976 1977 Figure 11-13. composite quarterly means of -sulfate ground-level concentration since first quarter of 1976 when measurements began in Maryland. I Also shown is the composite means of SO 2 for all stations using the flame photometric method. relationship. Ambient air quality standards exist for both photochemical oxi- dants (measured as ozone) and hydrocarbons. The hydrocarbon standards are not based on any direct adverse effect of hydrocarbons, but rather on an empirical relationship, based on measurements, between hydrocarbon concentrations in the morning (the 3 hour period from 6 am to 9 am EST is the determining period in the Maryland Standards) and oxidant concentration occurring later during the same day. The hydrocarbon standard is designed primarily to achieve the standard for photochemical oxidants. In view of the lack of an exact quantitative rela- tionship between the two constituents, and because hydrocarbons are difficult to identify and measure, the levels specified for hydrocarbons should be con- sidered as guidelines only.* The standards are therefore not enforced. Both the oxidant and the hydrocarbon standards are consistently violated throughout the U.S., and Maryland is no exception. EPA is presently in the process of formulating a policy for control of photochemical oxidants. One of the major concerns is ozone formation in rural areas, caused by heavy influx of hydro- carbons transported from large population centers. Since a 1000 MW power plant typically emits 250 tons of non-methane hydrocarbons per year, any regulation of hydrocarbon could have a significant impact on power plant siting (see also Section G).** E. Pollution Control Ambient air quality can be improved by reducing emissions of pollutants from power plants (via emission control, conservation, cleaner fuel, or switch- ing to alternatives such as-solar or nuclear) or by enhancing dispersion. At present, emission controls are necessary for fossil-fueled power plants. The need for emission control can be assessed by comparing emission factors to allowable emissions under the new source performance standards (NSPS). Table 11-5 relates the new source performance standards to the emissions resulting from burning coal, oil, or gas without any emission control. Although it appears from the table that the new source performance standards for N02 cannot be met without additional emission control for any of the three fuels, it is possible to control combustion in a modern power plant boiler so that the N02 standard can be met. Table 11-5 shows that natural gas is the only fuel for which particulate emission control is not needed in order to comply with NSPS. For coal with an ash content of 15 percent, precipitators with an efficiency of about 99.7 percent would be necessary for plants using this fuel. Modern precipitator technology has progressed to the point where efficiencies exceeding 99 percent can be obtained (29), however, these efficiencies are often critically depen- dent on fly ash 6omposition and sulfur content and must be carefully monitored. There is considerable dispute on the ability of hydrocarbon control alone to reduce photochemical oxidant levels (27). Based on EPA emission factors (13). These factors are now under revision and may be reduced significantly (28). 11-26 Tablell-S. Comparison of new source performance standards (NSPS) for emissions (in pounds per million BTU) and emission factors (in the same units) for combustion in utility boilers POLLUTANT PARTICULATE MATTER SULFUR DIOXIDE NITROGEN DIOXIDE FOSSIL FUEL STANDARD EMISSION STANDARD EMISSION STANDARD EMISSION AND FURNACE TYPE FACTOR FACTOR FACTOR Old New Old New* Old New Coal 0.10 0.03 1.2 1.2 0.70 0.60 Pulverized: (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 0.30 0.30 Tangentially fired 0.05S 1.08S 0.34 Other 0.72 Natural Gas 0.10 0.03 No 0.80 0.20 0.20 Tangentially fired 0.014 std. 0.00055 0.27 Other 0.64 Note: The old standards did not apply to lignite. The new NOx coal standard of 0.60 applies to bituminous coal, and 0.50 applies to subbituminous coal, shald oil, or any solid, liquid, or gaseous fuel derived from coal. There is no S02 NSPS for natural gas. A is ash content of coal in percent by weight. S is sulfur content in percent by weight. Emission factors have been converted from the weight and volume units to BTU's using the follow- ing conversion, which approximates Maryland conditions: Coal: 12.9000 BTIJ/lb = 24 x 106 BTU/ton Oil : 145,000 BTU/gal = 14S x 106 BTU/thousand gals Gas : lJ00 BTU/cu ft = 1,100 x 106 BTU/million cu ft Emission factors are only approximate guidelines and may be on the conservative (high) side. The emission factor of 1.58S for sulfur dioxide assumes that 95 percent (by weight) of the sulfur in the coal is released as sulfur dioxide. The new NSPS also requires a reduction (presumably by scrubbing) by 8S percent of the uncontrolled S02 emissions from solid, liquid, and gaseous fuel. The old (1971) NSPS could be met through use of clean (or cleaned) fuels. For example control of S02 emission was not needed for gas. Oil could meet the emission standards, provided that the sulfur content was about 0.8 percent or lower. Attainment on this level presents no technical problem, although there may be a related economic penalty (see Table 11-7). S02 emission control for coal-burning power plants could potentially be met y: � use of coal of inherently low sulfur content (< 0.8 percent) � cleaning of coal � conversion of coal to cleaner fuels � advanced combustion systems (fluidized bed combustion) Extensive research programs funded by private and public interests, are underway in these areas as discussed below. The requirement of the new (1978) NSPS that all power plant effluents must be scrubbed for S02 reduction may remove much of the economic incentive for development of these technologies, although credit for pre-cleaning of the fuel will be given in the form of an easing of the S02 percent reduction requirements. The technologies discussed below will probably be commercially available for power plant operations in the 80's (30). Many of these technologies are not complicated for some small scale uses but are difficult to transfer to the scale of power plant fuel consumption and large volume of effluents.* Use of Low Sulfur Coal Table II-6a shows the estimated measured and indicated reserves of coal by sulfur content (18,31). Although reserves of Eastern and Western coal are roughly equal, it is seen that the preponderance (86 percent) of the "clean" coal (S < 1 percent) is in the West. In the East (Table II-6b) the preponderance of this clean coal is in West Virginia (53 percent) compared to Maryland's share (0-6 percent). Coal demand by U.S. utilities by 1980 is projected to be about 620 million tons (32), of which about one half will have a sulfur content low enough to comply with the NSPS of 1.2 lb SO 2 emission per million BTU. This compares to a 1974 consumption of 390 million tons, again with one half conforming to the current new source emission regulations. Availability of low sulfur coal, and the desirability of using it for burning in power plants, depend on several economic and energy-policy considerations. The price differential between low- sulfur and high-sulfur coal in the Washington area in 1975 is shown in Table 11-7 (32). A change in demand and point of origin of the coal can shift these costs considerably. The capital cost of converting a plant from high-sulfur to low- sulfur coal also varies considerably. One recent estimate is $20 per kW, which A high efficiency 500 MW unit burns about 190 tons of coal pgr hour, 1.3 x 106 tons per year at 80% utilization, and will exhaust 1.16 x 10 cubic feet of air per minute (at 20% excess air), assuming 38 percent efficiency (9,000 BTU/kWh) and 12,,000 BTU/lb. 11-28 TableII-6a. Estimated in-place coal reserves in millions short tons Sulfur Content in S < 1 1 < S < 3 3 < S Unknown TOTAL % S by 11@eijzht Eastern States Deep Mine Reserves 21,200 48,461. 65,992 25,811 161,464 Strip Mine Reserves 5, 302 6,822 15,434 4y93)6 32,494 TOTAL 26,502 55,283 81,426 30,747 193,958 Percent of Reaional Total 13.7 28.5 42.0 15.8 Percent of U.S. Total 6.2 12.9 19.0 7.2 Western States Deep Mine Reserves 99,457 10,757 7,727 13,2216 131,157 Strip Mine Reserves 67,866 26,774 3,516 5,106 103,262 TOTAL 167,323 37,531 11,243 18,322 234,419 Percent of Regional Total 71.4 16.0 4.8 7.8 Percent of U.S. Total 39.0 8.8 2.6 4.3 11-29 Table II- 6b. Estimated in-place coal reserves in millions short tons for eastern states with major reserves. Sulfur Content % S <1 1<S<3 3<S Unknown To tal Maryland Deep Mine 106 624 171 0 902* Strip Mine 29 67 16 35 146 Pa., Ky., Va., W. Va. Deep Mine 18P787 32,319 17,571 123086 78,186 Strip Mine 41988 3,466 2,608 31265 14,336 Other Eastern States Deep Mine 2,327 15,518 48P250 13,726 82,428 Strip Mine 285 3,289 12,810 1,637 18,029 TOTAL Deep 21,220 48,461 65,992 25,812 161,516 Strip 5,302 6,822 15,434 4,937 32,511 The Maryland Geological Survey estimates 855 million tons recoverable in Maryland of which an estimated 100 million tons could be recovered By' sur- face mining techniques. Maryland production in 1975 was about 2.5 million tons. Peak production (1907) was about 5.5 million tons. Conventional under- ground mining allows recovery of 50-60 percent of coal in place. 11-30 Table 11-7. Energy costs in the Washington, D.C. area (1975 prices) Residual Oil Percentage Sulfur Cost per Barrel Differential .5 - 1.0 $ 13.10 --- 1.0 - 2.0 $ 12.25 $ .85 2.0 - 2.8 $ 11.25 $ 1.85 > 2.8 $ 10.25 $ 2.85 Utility Steam Coal Percentage Sulfur Cost per Ton Differential .5 - 1.0 $ 42.00 --- 1.0 - 2.5 $ 35.00 $ 7.00 > 2.5 $ 30.00 $ 12.00 11-31 includes coal handling, combustion system modifications and the necessary changes in the particle emission control system (30).* Another factor of importance is that much of the low sulfur coal found in the west has an appreciably lower heat value than the Eastern coal. Heat values as low as 7,500 BTU/lb commonly occur, compared to 12,000 BTU/lb (independent of sulfur content) for Eastern coal. Thus, the advantage of low emission from western low-sulfur doal is offset by the fact that more coal must be burned to get the same electric output. Transportation charges may also make use of Western coal unattractive. It is, therefore, not evident that use of low sulfur coal would be cost-competitive with other pollution reduction methods (see also Table II-10). Cleaning of Coal Sulfur is either r@hemically bound to hydrocarbon constituents of the coal (organic) or occurs in minerals (pyrite) associated with the coal (inorganic). Some of the sulfur can be removed from the coal, either by mechanical or chem- ical cleaning. In the mechanical cleaning process (33), the coal is crushed and the in- organic impurities are removed by screening and washing, based on the differ- ence in specific gravity between coal (about 1.3) and the pyrite (about 5.0). The organic sulfur cannot be removed by this process. In Appalachian coal, pyritic sulfur can be as much as 40-80 percent of the total sulfur. Up to 80 percent of the pyrite can be removed by physical clean- ing, leaving about 50 percent of the total sulfur (see Figure 11-14). Since this coal often has a sulfur content of 2.5 to 3 percent, it can therefore not be reduced below the level required to meet the NSPS without additional emission control. Because coal with inherently low sulfur content contains most of its sulfur in organic form, physical cleaning does not work (see last three cases in Figure 11-14). Concurrent benefits from the cleaning operation are increases in heat value** (from 12,000 BTU/lb to 13,400 BTU/lb), and removal of approxi- mately one half of the ash content. Washing of coal is done routinely, although percentages of coal cleaned has decreased from about 65 percent (332 million tons) in 1965 to 49 percent (289 million tons) in 1973 (32). Cost of mechanical cleaning (ranging from $2.50 to 4.00 per ton) has increased by a factor of four to five since 1968, mainly because of new government regulations of air and water pollution (32). Capital cost for a coal cleaning facility, including cost of environmental controls, may typically be the equivalent of an additional $12/kW in power plant capital cost. Additional costs may be incurred to upgrade power plant electrostatic precipitators. Operating cost is in the range of $0.10 to $0.20 per million BTU (corresponding to 1-2 mills per kW hr) (30). Changes in fuel characteristics often necessitate changes in the emission control systems. Some coal is also removed in the cleaning processes so that there is a loss in the basic resource although the energy content per unit coal as burned has increased. 11-32 FJ 11@ Sulfur Conte (D Raw Was 4.0 - @4 0 INN 0 0 Ash Conteni (D 2: 5.9 Raw Was (D H. Ln F@ F@ t C-t CrD C= Ln 3.0 11 't Fo@, cz rt CA H 0 --_O N n @@ 0-) ::@i: C-) 0 FI, 5, (ID C:) rt n rt rt ':: x ';'- m 2.0 F-i CD QQ F- 61 n rt 0 N P r+ rt n 0 R 0 rri :j P3 m (D r+ F- C-) @-h GO M n 0 CD 0 H r+ 1.0 0 n 0 C-- (A 0 r+ W N Pittsburgh Middle Upper Powellton Chilton Kittanning Freeport Chemical cleaning of coal consists of grinding the coal into fine par- ticles, which are treated with a reagent under controlled conditions of pressure and temperature. Both inorganic and organically bound sulfur can be removed by this process. The removal efficiency depends on a number of physical and chemical properties of the process and the coal. The technology is not commercially available, but is being pursued as an EPA development program (34). Chemical coal cleaning will probably be expensive and not available until the 1980's (see Table II-10). Conversion by Coal Gasification There are several ways of producing gas from coal (34,35). Generally, the coal is crushed and screened before being subjected to high temperatures (1,000 to 3,000 'F) and pressures (atmospheric to 1,000 psi). The end product of the various processes usually fall into one of the following categories: low BTU gas, beat values 100-200 BTU/cu ft medium BTU gas, heat values 300-500 BTU/cu ft o high BTU pipe line quality, synthetic natural gas (SNG), heat value around 1000 BTU/cu ft. Coal gasification technology for power plants probably can not be devel- oped until the middle 80's,.although numerous small systems are in operation around the world. The economics of coal gasification have been studied exten- sively (30,35). Although great uncertainty exists in the projections, it now seems that these systems will not be cost-effective in comparison to other available fuel and control options (see Table II-10). Conversion bv Coal Liquefication Liquid fuels can be prepared from coal by several different processes. For power plant applications, several processes that hydrogenate coal to a liquid have shown promise (34,35). Commercial application of coal liquefication for power plant use is pos- sible by the mid 1980's. Cost estimates are uncertain, but it appears that costs will be high, and the technique will probably not be competitive with the other techniques shown in Table II-10. Fluidized Bed Combustion In a fluidized bed combustion system, a grid or distribution plate at the bottom of the boiler supports a mixed bed of granular limestone or dolomite and pulverized coal (36,37,38). High velocity combustion air (2-5 fps) is blown up through the bed suspending or fluidizing it. Because of the thorough mixing and large contact area of fuel and air throughout the bed, an evenly distributed, complete combustion can be supported at a lower temperature than in a conven- tional boiler. The heat generated in the bed can be removed by heat exchanger directly in the bed as well as in the heated gas flow. 11-34 Most of the S02 produced by the combustion is removed by reaction with the limestone or the dolomite in the bed. The limestone or dolomite en be regen- erated for repeated use in the boiler. The advantages of the fluidized bed system over conventional boilers include: e high heat release rates and transfer rates in the bed which allow lower temperatures to be used (e.g., 1550-1750* F) than in a conventional boiler (e.g., 2700* F) resulting in lower NOX emissions allow boiler size to be reduced by as much as 50% resulting in lower construction rLost e removal of S02 directly at the combustion source. Sulfur removal efficiencies of 90-95 percent have been measured on exper- imental units using a limestone or dolomite sorbent. Nitrogen oxides are gen- erally emitted at levels of 0.3-0.6 lb/million BTU, well below the NSPS of 0.7 lb/million BTU. Particulate emissions can be high for fluidized bed systems, and are very sensitive to bed operating conditions. Fluidized beds can be operated at atmospheric pressure or pressurized. In a pressurized system, a gas turbine cycle can be combined with the steam turbine cycle, with possible operating efficiencies in the 40% range. The feasibility of this system depends on adequate removal of particulates up- stream from the gas turbine. Atmospheric pressure fluidized bed coal combustion systems for large power plants will probably be operational in the mid 1980's and may well prove to be less expensive than current combustion technology (Table II-10). Flue Gas Desulfurization (FGD) Engineering development of flue gas desulfurization systems (scrubbers) will probably receive a major impetus from the NSPS requirement for S02 reduc- tion of the uncontrolled emissions. FGD systems use a sorbent, usually lime (CaO) or limestone (CaC03) to absorb or react with the SO 2 (39,40,41,42). The sorbent can be discarded after the use or regenerated for repeated use. The most common FGD systems are non-regenerable. The resulting sludge (consisting of a mixture of fly ash, calcium sulfite, calcium sulfate, and water) must be disposed of either in settling ponds or (if treated with a fixative) in a land- fill tract. This disposal can be a significant environmental problem. A typical 1000 MW plant, burning 3.5 percent sulfur coal with 12 percent ash content (as fired) with a lime scrubber removing 90 percent of the SO 2 will generate about 200 tons of settleable slurry and ash per hour, 60 percent of whidh is 6aldium solids. The settled material (slurry and ash) has a spe- cific gravity of 1.31 @with 60 percent water content), so that the volume created is about 140 m /hr. For a lifetime of pla t3operation, assumed to be 127,500 hrs, this amounts to a volume of 1.77 x 10 m . or a settling pond 40 feet deep with an area of about 360 acres. Implicit assumptions in this calculation are: 75 percent of ash content becomes fly ash, 99.5 percent of particulates are removed in the precipitator, heat rate 9000 BTU/kWh, heat value of coal 12,000 BTU/lb, giving coal consumption of 375 tons/hr. For a 11-35 limestone system, the Zalcium solids are 15 to 20 percent more than for the lime system (43). The most important regenerable systems are the magnesium oxide (MagOx) and the Wellman-Lord sodium sulfite process. In a regenerable system, the sulfur is removed from the sludge (or liquid in certain processes) and con- verted to a marketable product such as sulfuric acid or elemental sulfur. The sorbent medium is reused. The 1000 MW plant described above will gener- ate about 775 tons of 98 percent sulfuric acid per day using the Magnesium Oxide process. In the sodium sulfite processes about 275 tons of sulfur is generated per day, and about 90 tons of sodium sulfate. About 5500 tons of particulate slurry (15 percent undissolved solids) representing the ash, will also have to be disposed of per day. The catalytic oxidation process will generate about 950 tons of 80 percent sulfuric acid (about 800 tons of dry ash will have to be disposed of per day) (43). There has been a great deal of controversy over whether S02 scrubbers are reliable, and whether or not they constitute "available technology" as opposed to "experimental technology." According to the National Academy of Engineer- ing, FGD can be considered "available technology" if it can operate continu- ously for one year with no more than 10 percent down time. Most of the early problems with FGD systems are being solved to provide acceptable reliability and efficiency at the high temperatures and large flow volumes of large steam electric plants. However, while the terms of the NAE's definition are increas- ingly being met the controversy continues. The status of FGD systems is shown in Table 11-8 (44). There are 139 systems in operation, under construction, or planned as of July 1978, representing close to 60,000 MW of generating capacity (total fossil-fueled generating capa- city of all private and public utilities was about 532,000 MW in 1978) of which 250,000 MW, or 47 percent is 6oal-fired. Scrubber systems are installed on about 6 percent of present coal-fired capacity. The S02 removal efficiency is generally in the 80-90 percent range, and reliability of the more recent install- ations approximates 90 percent (44). Table 11-9 shows the various processes selected as of 1978, and a projec- tion to 1986. It can be seen that the preferred system is, and will continue to be, limestone. Non-regenerable lime and limestone systems constituted 96 percent of FGD systems installed in new plants and 83 percent of FGD systems retrofitted into old plants (44). About 80 percent of present installations are on new power plants (the remainder are retrofits), and by 1986 the percentage of new installations will increase to 84 percent. Present projections (44) indicate that by the end of 1986, 16 percent of the coal-fired capacity will be controlled by FGD. This situation could be changed if the 85 percent scrubbing requirement is retained in the New Source Performance Standards. The cost of S02 control technologies have been studied extensively (43, 45,46). Costs to be considered are not only capital costs and operational costs in the conventional sense, but also costs associated with the environ- mental impacts each one of the methods will create. As discussed above, for non-regenerable scrubbers, there will be waste disposal problems; for regen- erable scrubbers, some waste disposal may be necessary; for coal processing, there may be problems of water availability and pollution. Disposal of solid waste, such as fly-ash and sludge will be covered by regulations to be 11-36 Table 11-8. Status Of S02 scrubber system applications as of July, 1978 Number of Status Units IV Capacity Operational 40 14P440 Under Construction 42 16,834 Planned: Contract Awarded 21 10,708 Letter of Intent 3 1,960 Requesting/Evaluating Bid 4 2,255 Considering only FGD systems 29 13,232 TOTAL 139 59,429 Table 11-9. S02 scrubber system selection in terms of MW capacity Total MK of Installations Process 1978 1986 Lime 6,070 15,581 Limestone 7,426 269766 Lime/Limestone 20 680 Magox f2O 846 Wellman-Lord 429 1,8SS Others 375 2,546 Not Selected --- 11,155 TOTAL 14,440 59,429 11-37 Table II-10. Cost of SO 2 control technologies for baseload plants in 197S dollars Basic Control Annualized Costs millsA-Wh Plant Technology Capital Cost Capital Cost Coal Control Total $/kW $/kW Technology Power Conventional Boiler Coal Fired: High Sulfur Coal (>2.51 S) (TVA) 500 - 700 0 10.8 0 .34.4 Medium Sulfur Coal (1-2.St S) (IVA) 510 - 710 0 12.6 0 36.5 Low Sulfur Coal (<1.21 S) (TVA) 520 - 720 0 IS.2 0 .39.3 Low Sulfur Coal (EPRI) 37S - 455 0 12.5 I(ERDA) 294 - 404 0 13.0-IS.0 Physical Coal Cleaning (TVA) 12.0 10.8 1.S 35.9 Chemical Coal Cleaning (TVA) 75.0 10.8 4.5 38.9 Flue Gas Desulfurization: (TVA) 48.9 10.8 3.3 37.7 Lime/Limestone (EPRI) 110-170 10.0 6.0-7.5 I(ERDA) 72.0 11.0-13;0 2.6-3.6 Magnesium Oxide (TVA) 57.4 10.8 2.6 36.0 Sodium Sulfite (IVA) 67.8 10.8 4.0 38.4 Unspecified Regenerable (EPRI) 185-280 10.0 7.0-9.S New Fuels: 00 500 - 655 (IVA) - 10.8 6.8-7.6 41.3 Coal Gasification w/Steam Turbine 760 - 1000 10.0 0 I(EPRI) 245 - 300 205-700 Coal Gasification (EPRI) 190 - 260 175-600* 8.0 0 w/Combined Cycle I(SM) 395 - 555 - 8.S 0 (TVA) WA - - - NIA Coal Liquefaction I(EPRI) 375 - 500 - 10.0 Fluidized Bed Boiler (TVA) 632 - 10.8 32.9 Atmospheric (EPRI) 450 - 6SS - 10.0 t(EPDA) 389 - 409 - 11.0-13.0 (TVA) 723 - 10.8 38.4 L Pressurized (ERDA) 332 - 462 11 - 11 11.0-13.0 *Covers a range of low and medium BTU processes. TVA assumes 0.80 capacity factor; EPRI 0.65; ERDA variable over life of plant, average about 0.60. Footnote to Table II-10 (a) Data labeled TVA has been adapted from (33) and e Capital cost based on gross capacity, annual adjusted to a high sulfur coal cost of $30/ton expenditures on net. and low sulfur coal cost of $42/ton. Heat values 0 Particulate control costs deducted, but regener- assumed to be 12,500 BTU/lb and 9,025 BTU/kWh. ation and by-product recovery facility costs in- The TVA data for flue gas desulfurization sys- cluded. Replacement power costs not included. tems (scrubbers) are derived in (43). A base loaded plant of 500 MW capacity is assumed, with e Capital cost of modification or installation an operating life of 30 years over a declining of equipment not part of the FGD system in- operating profile (total of 127,500 hours). A cluded if required for operation of the system. 3 year construction schedule ending in mid-1975 * Indirect charges adjusted to provide for engineer- is assumed at a mid-Western location. For the ing, field expenses, legal services, insurance, midpoint of construction the Chemical Engineer- interest during construction, allowance for ing Cost Index is 160.2, inflation factor from start-up, taxes, and contingencies. 1975 to 1977 is about 1.2 (20 percent). Solid waste disposal costs assume conditions existing * Annual cost adjusted to 65% capacity factor. in 1975. Coal is assumed to have 12% ash con- a 30-year life for new systems, 20-year life for tent, oil is 18,500 BTU/lb with ash content of retrofits. 0.1%. Additional cost assumptions, including recovered cost for by-product sales, are found 9 Sludge disposal costs adjusted to include S02 in (43). waste disposal (not fly-ash) over the anticipated lifetime of the system. Only the TVA costs have been carried forward to total annualized costs in mills/kWh. EPRI Some of the results of this analysis are: and ERDA costs (48) are also 1975 costs. EPRI assumes capacity factor of 0.65 and coal cost Average Adjusted Costs of $1/million BTU. ERDA has a variable capacity Capital, $/kW Annual, mills/kWh factor over the plant lifetime (average about 0.6) and coal cost varying between $0.68 and All systems 95.8 5.53 $0.92 per million BTU. New systems 87.6 5.13 Retrofit systems 103.4 5.92 PEDCo Environmental, Inc. has recently (44) Lime 94.1 7.03 collected cost data for existing scrubber Limestone 87.0 4.55 systems,and adjusted cost reported by utili- ties to a common July 1, 1977 basis incor- (b) Covers a range of low and medium BTU processes. porating the following: promulgated by EPA under authority of the Resource Conservation and Recovery Act of 1976 (RCRA). There are indications that EPA may designate fly-ash and scrubber sludge as hazardous wastes. If so, disposal cost could reach $25 to $30 per ton of fly ash or sludge (47). Cost recovery through sale of useful by-products from some of the processes also present an estimating uncertainty. Equipment maintenance problems present another area of uncertainty. Although many scrubber systems are in full scale operation there is little solid cost experience to build on because so many of the installations involve retrofitting, with all its site specific conditions, or developmental installations, often with shared financing, which makes it difficult to assess true costs of installation and operation. Table II-10 gives an overview of the effect of S02 control techniques on the cost of electric power. The values are developed from a number of sources (33,46,48) and provide a rough indication of relative costs. The absolute cost figures have considerable uncertainty attached to them and also depend on factors which are highly variable, such as fuel costs and transportation costs. The current situation regarding S02 abatement can be summarized as follows: Choice of an S02 control strategy is complicated by the interaction of opera- tional and economid fa,6tors, the availability of low sulfur fuel, the uncertain- ties associated with the new NSPS requirements for S02 scrubbing and the variabi- lity of emission regulations throughout the U.S. However, several conclusions can be drawn from the current knowledge of S02 emission control technology. Using currently available technology, all coal-fired electric power plants in Maryland Could operate in compliance with present State emission standards by 1985. Between now and 1985, only about half of the projected national coal demand can be supplied with low sulfur coal. Therefore, S02 emission standards can only be achieved through a combination of low sulfur coal use, coal-cleaning, and FGD technology. The utilities in Maryland will reflect this mix in their plant design and operations. In new installations there is no major economic penalty associated with FGD (as opposed to retrofits which are much more expensive). Cost of FGD starting with high sulfur coal is comparable to, or slightly below, the price of electricity using low sulfur coal, despite the large differential in capi- tal costs. F. Mathematical Modeling Mathematical modeling is becoming increasingly important for air quality predictions and maintenance studies. Section 320 of the 1977 amendments to the Clean Air Act (49) recognizes modeling as a necessary tool, especially as it relates to the problems of prevention of significant deterioration (PSD) of air quality. The Gaussian plume equation is currently the most widely used model (50). It is based on the idea that, over a short time, a plume of pollutants will tend to move with the wind in sudh a manner that the average density has a normal (i.e., Gaussian) distribution about the mean wind direction both in the 11-40 lateral direction and in altitude. It is further assumed that the pollutant is conservative, i.e., that there is no loss of pollutant due to chemical reac- tions or ground deposition, and that the plume will be perfectly reflected from the ground. Attractive features of the Gaussian plume model are its simplicity, and the fact that the required input parameters are readily measurable. More complex models for pollution dispersion, based on flow field analyses and solution of standard turbulent diffusion equations, have been developed (51). However, they require input data that are not readily available, and they do not, in general, give consistently better results than the simple Gaussian model. In the Gaussian model the ground-level concentration (CLC) is directly pro- portional to the emission rate, which again is directly proportional to the sulfur level in the fuel and to the fraction of S02 not removed by the scrubber. Therefore, the data presented can easily be scaled to other values of sulfur content and scrubber efficiency through use of the factor F = so_ scrubber efficiency in percent) 100 where S is the sulfur content of the fuel. The general shape of the ground-level concentration along the plume centerline as a function of the downwind distance x is shown in Figure 11-15. We can see that c, the GLC, is zero near the source, rises to a maximum, cmaxl at a distance xmaxl and then slowly decreases to zero as x increases (for large values of x the applicability of the model is in question, as will be discussed later). In general, cmax is inversely proportional to the emissioa rate Q which in turn is proportional to the power level and the F factor dis- cussed above. As a general approximation, c ax is inversely proportional to the square of the effective stack height (hel * The dependency on wind speed, v, is more complex since he also depends on wind speed. The effective stack height is also a function of the difference, AT, between stack gas temperature and the ambient temperature, in such a way that he decreases with decreasing AT. Therefore, a decrease in AT generally will result in an increase in c ax' Thus, it is conceivable that a flue gas scrubber, while removing S02 Ti.e., reducing the emitted quantity of pollutants) may lower the flue gas exit tem- perature (and therefore the effective stack height) to the point where the GLC actually increases. This is a paradoxical situation, where removal of pollutants decreases the ambient air quality. These basic parametric relation- ships are important to the subsequent discussion of air modeling results as they apply to future siting decisions. In view of its central position in air quality assessments, the limita- tions of the Gaussian pollutant dispersion model must also be understood. There is a limit to the distance over which the model can be applied with any degree of confidence even for flat terrain. Two basic factors must be considered: 0 The calculations are usually based on meteorlogieal conditions at a point at or near the emission source. It is unlikely that these con- ditions persist over an infinite range downwind of the source. Both wind direction and the state of the atmosphere with respect to 11-41 1.00- ckm 1 .70- .50- X1XM 1 .30- E .20- LA- 0 2 .10- 07 .05- .02- .0i .01 .5 1.0 5 10 50 100 DISTANCE IN MILES Figure 11-15. Representation of the Gaussian plume equation. (Y, b Cmax = Trva a(y'/ P-M=2 when a = 1 + bl 1 2 (h2/a2 )a 2 The a's and b's are coefficients determining the dispersion parameters Ily a1x bl GZ a2x b2 The graph has been normalized to present ratio of actual ground- level concentration c to the maximum c , as a function of actual distance x to the distance x at whic the maximum concentration will occur. The numerical va.Tu@s apply to Brookhaven C stability class. Note logarithmic scales. 11-42 turbulence and other parameters affecting mixing will change. The functional form assumed for the dispersion parameters (or's) can also not be expected to hold indefinitely for larger values of x. The assumption of a conservative pollutant does not hold ad infinitum because of dry ground deposition, wash-out, and chemical processes. This problem is currently under investigation and some of the conversion processes were discussed earlier in connection with the sulfate problem (p. 11-24). Other problems with the Gaussian plume dispersion model appear under certain meteorological conditions. These conditions include low wind speed, where the concept of a continuous plume is not valid and stable atmospheric conditions, where the "standard" dispersion coefficients to an elevated plume rising from a tall stack are not necessarily applicable. There is also a problem in applying the Gaussian model in rough (non-flat) terrain where topographical features strongly affect the air flow. A number of Gaussian rough terrain models are in common use (51). Most of them are rather primitive, in the sense that they take the Gaussian plume and modify the effec- tive height of the emitting source by some fraction of the height of the terrain at the point of plume impingement. This type of model generally does not agree with measured GLC, [e.g., Power Plant Siting Program studies at Luke, Maryland (52)]. The general Gaussian model has been tested extensively in the Maryland Power Plant Siting Program for three different power plants and for various algorithms for determining stability classes, dispersion parameters and plume rise. For flat terrain the best model was found to agree with measured con- centrations to within a multiplicative factor of 2 in about 70 percent of the 126 cases that were tested (53). The thrust of current development in the Siting Program is toward mathe- matical models that consider actual flow patterns. Flow patterns, air pressure distributions and velocity profiles are studied in wind tunnels simulating the existing meteorological and topographic conditions. It is expected that this ongoing work will lead to a better understanding and formulation of the underlying physical principles of dispersion. In practice, the influence of local features (i.e., local emissions, and local topography and meteorology) can create great differences between actual point measurements and model pre- dictions. Plume measurements have generally been confined to ground level. It is possible to make airborne measurements, but these are expensive and beset with practical problems such as helicopter rotor downwash interference and instru- ment time response problems from fixed wing aircraft. Improved measurement methods are expected to aid materially in future model development. The Power Plant Siting Program, in cooperation with NASA, has been using Lidar (a laser- type remote sensing instrument) for plume measurements (54). The Lidar is useful in studying details of plume rise (near the stack), vertical plume struc- ture, and three dimensional development along the plume. The demonstrated capability of Lidar to track particulates is currently being extended to chem- ical pollutants such as S02 and photochemical oxidants. 11-43 G. Regulatory Effects The Clean Air Act Amendments of 1977 are of major importance in that they give specific legislative direction to "prevention of significant deterioration, one of the most controversial concepts of air pollution control. The amendments also give focus to other control approaches which have devel- oped over the years since the previous amendment to the Clean Air Act was passed in 1970. Some of the most significant areas of importance to power plant siting and operation are discussed below. Stack Height and Intermittent Control One of the air pollutant control techniques proposed (and in some cases implemented) by electric utilities was the use of tall stacks, switching of fuel, and switching of load between plants in such a manner that the air shed impact, in the form of pollutant GLC was minimized. EPA argued against the acceptability of this method on the ground that tall stacks and switching of load to other plants in a utility system did not diminish emissions, although a better air quality, as defined by GLC was attained by spreading the pollutants. The new act essentially eliminates the use of these dispersion techniques by denying credit for pollution abatement by these techniques. In particular, credit is denied for stack height exceeding "good engineering practice," 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." (Section 123 of the Act) EPA has recently proposed a set of regulations per- taining to tall stacks (55). The height for good engineering practice is inter- preted as the height of the structure plus 1.5 times the lesser height or width of the structure. "Nearby" is taken to be a distance up to 5 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 excessive concentrations referred to above. The height of the source, i.e., the structure of a power plant, is typi- cally such that stack height is limited to the 500 to 600 feet range. It is not clear at this time whether cooling towers (which range up to 450 feet tall) are to be included as source structures. If they are (and there are often good engineering reasons for including them), then the law provides no practical limitation upon stack heights. If they are not, then the stack height limita- tion may be important to meeting the prevention of significant deterioration cri- teria as will be discussed below. Non-Attainment Areas When an area exceeds Federal ambient air quality standards, it becomes a non-attainment area, and no further growth in pollutant emissions from major 11-44 sources is allowed.* To permit new industries to locate in such regions, the EPA (under the Clean Air Act) has promulgated a policy of "emission offsets" (49). A new power plant, if it wishes to locate 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 other sources (its own or others) in the area to offset its new emissions, so that "reasonable progress toward attainment of the applicable NAAQS" is made.** Any power plant, outside the non-attainment region, producing a "significant" decrease in the air quality of the non-attainment region, is also subject to an offset requirement. Although the idea behind this policy is to satisfy the competing needs of growth and maintenance of air quality, it entails several significant con- 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 whomever they chose (or refuse to do so) for more than the price of the control equipment. In fact, it is possible for a company to be economically responsible for the operation and maintenance of another company's pollution controls. Another consequence is that the economic burden of controls, both for its own plant and the offset plants, would be borne by any new source (as opposed to the sources already located in the area). Thus, unless there are compelling economic considera- tions for locating in a particular region, power plants will tend to locate far enough away from non-attainment areas so that they will not be subject to an offset. In Maryland there are presently four pollutants for which non-attainment areas exist: particulates and carbon monoxide (Baltimore and Western Maryland), hydrocarbons, and photochemical oxidants (Baltimore, Washington, and scattered areas elsewhere). Because of the differing sources and nature of these pollu- tants, different offset policies have been developed. Any source increasing the 5oncentration of particulates An a non-attain- ment area by more than 1.0 Pg/m (annual average) or 5.0 Ig/m (24 hour average) is subject to an offset (49). To estimate the implications of this policy for power plants, a typical 1000 MW coal-fired generating station emitting at the new source performance standards (Table 11-3) was modeled for "worst-case" conditions. The results indicated that, to avoid an offset, such a plant would have to locate 10-15 miles from the border of a non-attain- ment area, depending upon the local meteorology. Photochemical oxidants, because of the regional nature of their emissions and their slow reaction/deposition rates, have been approached from a larger geographic scale. According to a draft EPA policy (56) any major source Although the present discussion will center on power plants, the conclusions will be valid for all large emission sources with similar characteristics. The applicant must also certify that all the existing major sources he owns or operates in the same state are in compliance with the applicable emission limitations or are meeting the target dates of a compliance schedule. 11-45 (greater than 50 tons/year) locating within an 85 mile circle of Baltimore or Washington would require an offset. When similar circles around Pittsburgh and Philadelphia are considered, most of the State (all except the tip of Garrett and Worcester Counties) is subject to an offset. In this case, the offset is not the for primary pollutant (03) but is for a percursor, non-methane hydrocarbons (NMHC). A typica 1000 MW generating station produces about 250 tons/year of NMHC.* The major difficulty in this offset policy is finding controllable stationary sources that can produce an offset. Table 11-3, the State-wide total emissions inventory, shows that 77 percent of the NMHC emissions (in 1975) come from mobile sources (automobiles and trucks). When road resurfacing is added, the transportation sector produces 85-90 percent of the total emissions. Clearly, any strategy to control hydrocarbons should include this sector. These policies are now being used to evaluate the proposed expansion at Sollers Point (100-600 NW of gas turbines). The proposed site is a non-attain- ment area for particulates, hydrocarbons, and photochemical oxidants. The preliminary site investigation (57) indicates that the plant will have to meet the offset requirements listed above. An output of six hundred megawatts, previously proposed by BG&E, has been ruled unsuitable by the Department of Natural Resources. A detailed site evaluation study now in preparation by Applied Physics Laboratory of Johns Hopkins University will more clearly define available options and requirements. In the 1978 Ten-Year Plan, BG&E listed a proposed installation of only 100 MW (58). Thus, the existing non-attainment areas in Maryland will influence the siting of future fossil-fueled power plants either by requiring use of an offset or by requiring the plants to locate outside the affected region. Prevention of Significant Deterioration (PSD) The most significant change within the Clean Air Act relates to PSD (59,60). The law establishes upper limits on allowable air quality changes for S02 and particulates. It designates three classes of areas with differing restrictions on increases in pollution levels. The allowed increases (increments) for each area and the comparable standards are shown in Table II-11. The total increments caused by all users must stay within the specified limits. 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 5000 acres in size, and national parks over 6000 acres in size. 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 nearby Virginia and West Virginia. Figure 11-16 shows the mandatory and discretionary areas in and near Maryland that 'have been mentioned by Federal agencies for possible Class I designation. Emission factor under revision by EPA (28). Fort McHenry has been proposed as a Class I area by the National Park Service. 11-46 Table II-11. Prevention of significant deterioration of air quality. Maximum allowable increase in ground-level concentration of particulate matter and sulfur dioxide under the provi- sions of the Clean Air Act Amendments of 1977* Area Designation Maximum Allowable Increases pg/m3 Class I Class II Class III Pollutant: Particulate Matter Annual Geometric Mean 5 19 37 24-hr Maximum 10 37 75 Sulfur Dioxide Annual Arithmetic Mean 2 20 40 24-hr Maximum 5 91 182 3-hr Maximum 25 512 700 The allowable concentrations must in no case exceed the concentrations permitted under the national primary and secondary ambient air quality standards. 11-47 Pa. Ma. Ballo. Clarksburg 0 J""I 10 5 Va. Wash. \b K Charleston 'Del. 'A 3 Md. A 1- 01 Staunto Q@p es Richmond %jr Lynchburg 00 Roanoke 1 10 11 1 Miles Va. Figure 11-16. Mandatory (M) and suggested (S) Class I areas in and around Maryland. Ihere are no mandatory areas in Pennsylvania. 1) Ft. McHenry (S) 5) Eastern Neck Nat'l Wildlife 8) Catoctin Mountain Pk (S) 2) Washington's Birthplace (S) Refuge (S) 9) Shenandoah Nat'l Pk (M) 3) Blackwater Nat'l Wildlife Refuge (S) 6) Assateague Nat'l Seashore (S) 10) Dolly Sods (M) 4) Martin Nat'l Wildlife Refuge (S) 7) Chincoteague Wildlife Refuge (S) 11) Otter Creek (M) Circle A shows the Class I exclusion area for a 1000 MIV power plant located at X burning 1% sulfur coal with an 80% scrubber, and circle B shows the exclusion area for the same plant burning 2% coal (see discussion on p. II-SS). Class II areas have increments allowing 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 devel- opment. A Class 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. When the allowable increment for an area has been used, an offset policy will probably come into effect. EPA is presently formulating this policy (61). Thus, it may be important to keep this ultimate possibility in mind while evaluating specific plant designs. For example, any coal-fired facility which now burns high-sulfur coal or oil may, during its lifetime, be expected to eventually burn low-sulfur coal or oil (perhaps cleaned to that level). So, it may be advantageous to ensure that the equipment is compatible, or easily convertible, to that type of fuel. Although the PSD presently applies only to S02 and particulates, EPA must establish regulations by August 1979 regarding PSD for hydrocarbons, carbon monoxide, photochemical oxidants, and nitrogen oxides. If national ambient air standards are established for other pollutants at some future date, corresponding PSD regulations must be promulgated within two years of that date. For power plants which are required to switch to coal as a result of an order under the provision of the Energy Supply and Environmental Coordination Act of 1974, the added concentration due to increased emission will not be applied against the allowable increment for a period of five years. The same consideration applies to plants converting from natural gas as the result of a natural gas curtailment plan implemented under the Federal Power Act. With the PSD restrictions the question of long-range, interstate trans- port of pollutants becomes important because a large coal-fired plant, located in Maryland, could use up part of the available increment for up to four states. It is not clear at this time what recourse a state affected by the siting of a source in a neighboring state (and not causing a violation of standard) would have. The present amendments (Section 126) call only for "written notice to all nearby states.9oat least sixty days prior to the date on which commencement of construction is to be permitted." To investigate the potential impact of the Clean Air Act Amendments upon power plants within the State, several representative cases have been modeled, using the Gaussian plume model for typical power plants in the following range of variables: � plant capacity: 100 - 1500 MW * stack height: 100 - 700 feet � exit temperature difference: 30*C and 90*C The lower exit temperature difference is typical for a power plant where the flue gas is not reheated after passing through the S02 scrubber, while the 11-49 higher AT corresponds to a moderate reheat. (It is not yet known whether EPA will allow reheat to be considered in calculations). The 1000 MW power plant used in the modeling has a stack diameter of 35 feet, an exit velocity of 41 feet per second, burns two percent sulfur coal, and utilizes a ninety-nine percent efficient particulate precipitator and an eighty percent efficient SO 2 scrubber for emission control. With these parameters, the numbers quoted for sulfur dioxide concentrations can be converted to particulate levels by divid- ing the quoted concentration by 5. The S02 ground-level concentrations scale directly as power level, sulfur content of the coal, and percent of S02 emitted from the scrubber. The calculations are for flat terrain, and thus would not apply in the rough terrain of western Maryland (in rough terrain, the specific locations of mountains, valleys, and stacks must be considered in each indi- vidual case). The annual average ground-level concentration depends primarily on meteor- ological conditions, as defined by the annual windrose (considering stability class and wind persistency); by the difference AT, between the flue gas exit temperature and the ambient temperature; by the physical stack height; and by the power plant emission rate (which depends on power level, in addition to the sulfur content and scrubber efficiency as discussed above). Using the windrose at the Baltimore-Washington International Airport (BWIA) as a representative case for Maryland, the annual average ground-level concentrations were calculated for several plant configurations. These results are summarized in Figures 11-17 and 11-18, which show the maximum annual average of S02 as a function of power generated and stack height. In all cases for moderate stack heights (500 feet), the increase in concentration is less than twenty-five percent of the Class II increment. Two meteorological situations have been considered in order to establish the worst situation to compare to the 24-hour average increment. 1) Neutral atmospheric stability with high wind (8m/sec) and persistent wind direction. 2) Unstable atmospheric conditions with light wind, typically for 8 hours followed by persistent wind direction and stable conditions for 16 hours. These conditions occur rarely in Maryland (only a few times a year), but, depending upon location, may occur frequently enough to be the determining factor in a plant siting decision. Results of calculations for these meteoro- logical conditions, shown in Figures 11-19 and 11-20 for a plant employing reheat, indicate that a 1000 MW plant with a 500 foot stack would be allowed in a Class II area, although a significant percentage of the allowable increase (up to fifty percent) in Class II regions would be used. Thus, depending upon the local frequency of these meteorological conditions, the siting of a power plant might lead to future sources requiring an offset. For conditions other than the two named above, 24-hour average concentrations would typically lie below 30 pg/m 3 for a 1000 MW plant with a 500 foot stack. Calculations for the three-hour average indicate it is not a restraining factor for PSD in a Class II area. The final area of concern, long range transport of S02 into Class I areas, is a difficult area to analyze. The Gaussian plume model is not accurate at 11-50 S02 GLC /Ig/M3 20 Allowable Class 11 Increment 16 12 Stack Height 100 ft 8 200 ft 500 ft 700 ft 4 Allowable Class I Increment -J 0 500 1000 1500 0 UT PUT POWER LEVEL (MW) Figure 11-17. maximun annual average ground-level concentration for S02 AT 300 C S 02 GLC 3 /_Lg1M 20 Allowable Class I I Increment 16 12 8 Allowable Class I Increment Stack Height 4 100 ft 200 ft 500 ft 700 ft I _j 0 500 1000 1500 OUTPUT POWER LEVEL (MW) Figure 11-18. Maximum annual average ground-level concentration for S02 AT 900 C MM MMMM M 0 OWN M 0 M MM MMM S02 GLC /.LgIM3 100 Stack Height 100 ft A i _Iow-a5I_6-CT_as Ts f TI Fn Er- e-m J_t 80 200 ft 60 500 ft 40 - .---1"700 ft 20 - Allowable Class I Increment- 0 500 1000 OUTPUT POWER LEVEL (MW) Figure 11-19. Maximum 24-hour average ground-level concentration for SO 2 Meteorological Condition 1 AT = 90'C S02 GLC pg/m3 10.0 Allowabl.e Class I I Increment 80 Stack Height 100 ft 60 - 700 ft 40 - 2-0 - Allowable Class I I ncrement 0 500 1000 0 UT PUT POWER LEVEL (MW) Figure 11-20. Maxim= 24-hour average ground-level concentration for S02 meteorological Condition 2 AT = 90*C distances beyond 20-30 miles (as explained in Section F), the meteorological data necessary for realistic calculations (high level and profiles every 20-30 miles) are not available, and the interaction of pollutant plumes from various sources is not well understood. One indication of this difficulty is the large difference in the annual windrose from National Airport, Dulles Airport, BWI, and Patuxent Naval Air Station (as shown in Figure 11-21). Despite the fact that all four airports are located within a 50 mile radius, the windroses are different. A plume emitted at National might change direction by the time it reached Southern Maryland or Baltimore, and vice-versa. Still, by looking at various limiting cases, we can gain insight into the effect of a Class I area upon power plant siting. The two meteorological conditions mentioned above give upper limits to the "zone of influence" (the maximum distance) from which a power plant would be excluded. A more common condition, medium winds (5 m/sec) for 10 hours followed by stable conditions, gives the minimum exclu- sion distance. The exact exclusion area (to be determined by site specific meteorological studies) would be somewhere between the two. The results of these calculations are shown in Figures 11-22 and 11-23. Although the Gaussian plume model is not adequate to deal with transport over these large distances, we obtain the following indications (see Figure 11-24). A 1000 MW power plant using a 500 foot stack and burning two percent sulfur coal with an eighty percent scrubber could not be located closer than 90 (and possibly not closer than 200) miles to a Class I area. If the same plant burned one percent sulfur coal, the plant could not be located closer than 40 (and possibly not closer than 75) miles to a Class I area. Thus,, the designation of a Class I region in, or nearby, Maryland could: � limit a substantial portion of the State to allow only the siting of small fossil-fueled plants, � make the operation of new plants more expensive by requiring the use of low-sulfur in addition to scrubbing, and � encourage the use of nuclear power because of the two points made above. In summary, the effects of the PSD provisions of the Clean Air Act will be to: 9 limit the increase in pollutant levels, 9 require power plants to locate moderate distances away from each other and from other major emission sources, and e establish power plant exclusion zones around Class I air quality regions. 11-55 FRIENDSHIP, 1972 Patuxent, 1972 6.6 7.1 6.3 7.9 10% 7.2 8.4 6.7!6 '6 8.1 6 8 6.0 8.2 7.0j - 6.5! 7.9 5.8 - 7.6 7.0, 6.6 7.7 7.1i: 7.11 &8 10.6 10.5 6.5 9.1 6.4 7.6 DULLES, 1972 6.3 7.8 7.5 6.4. 10% 5.7 6.7 Wind Speed In Knots 5.2 5.9 5.9- 7.8 6.5 5.7 10.4 6.2 8.7 6.5 Figure 11-21. Aimual wind roses for three airports. Length of arrow shows frequency of occurrence (in percent of time - Note 10 percent circle) of wind blowing towards the indicated direction. Number at tip of arrow shows annual mean wind speed (in knots) in that direction. M M IN M M w M 160 MILES 120 Stack Height_ 80- 700 ft Meteorological Condition 2 100 ft 100 ft 40 700 ft Meteorological Condition I 0 0 500 1000 OUTPUT POWER LEVEL (MW) Figure 11-22. Distance to ground-level concentrations of 5 Pg m3 S02 (Class I area increment) 1% 'sulfur coal, 80% efficiency scrubber AT = 90* C Stack Height 700 ft' 200- -100 ft MILES Meteorological Condition 2 160- 120- - Ay 100 ft co 80 700 ft 4,4 Y 40- Meteorological Condition I 0 0 500 1000 OUTPUT POWER LEVEL (MW) .Figure 11-23. Distance to growid-level concentration of 5 jig/m3 S02 (Class I area increment) 2% sulfur coal? 80% efficiency scrubber AT = 90'C 2 percent coal, 80 percent scrubber 0 20 40 60 80 100 120 140 160 180 200 210 Distance in miles to Class I area 1 percent coal, 80 percent scrubber U1 @.O Excluded Site-specific study needed L/_7 Allowed under present guidelines Figure 11-24. Siting Restriction for a 1000 MW coal-fired plant with a 500 ft stack relative to a Class I area. REFERENCES -- CHAPTER II 1. 1975 Emission Inventory Report. Bureau of Air Quality and Noise Control Technical Memorandum. State of Maryland BAQNC-TM 76-09. 2. Power Plant Cumulative Environmental Impact Report. Maryland Power Plant Siting Program. PPSP-CEIR-1, September 1975. 3. Assessment of the Current Scientific Bases for Achieving Clean Air in the United States. John H. Knelson, April 18, 1975. Human Studies Laboratory. U.S. Environmental Protection Agency. See Also: Review of Human Health Criteria for Ambient Air Quality Standards in Maryland. John S. Neuberger and Edward P. Radford. August 1974. Department of Environmental Medicine. Johns Hopkins University, School of Hygiene and Public Health. Health Consequences from Elevated Levels of Sulfur Emissions. Report to the Honorable Marvin Mandel, Governor of Maryland. May 1975. Maryland State Department of Health and Mental Hygiene. 4. Air Quality and Stationary Source Emission Control Commission on Natural Resources, Natural Academy of Sciences, Washington, D.C. March 1, 1975. 5. Position Paper on regulation of atmospheric sulfates. U.S. Environ- mental Protection Agency 450/2-75-007. September 19075. 6. A Critical Review of Regulations for the Control of Hydrocarbon Emissions from Stationary Sources. Milton Feldstein. Journal of Air Pollution and Control Association, Vol. 24, No. 5. May 1974, pp. 469-478. 7. See 40 CFR 50; 41 FR11253 March 17, 1976; or Environmental Reporter April 16, 1976; 121:0101. 8. See 40 CFR 60.40 for 1971 Standards, and Federal Register Vol. 43, No. 182, Tuesday, September 19, 1978, Part V, pp. 42154-42189 for 1978 Standards. 9. Rules and Regulations Governing the Control of Air Pollution in the State of Maryland. 10.03.35 (Also 10.03.36 - .41 for Areas I-VI.) Maryland State Department of Health and Mental Hygiene. 10. Federal Register Vol. 43 No. 43. March 3, 1978, pp. 9000. 11. National Air Quality and Emissions Trend Report 1976. U.S. Environ- mental Protection Agency. EPA-450/1-77-002. December 1977. 11-60 12. Maryland Air Quality Data Reports (Annual: 1971-1977). State of Maryland, Department of Health and Mental Hygiene. Environmental Health Administration, 201 West Preston Street, Baltimore, Maryland, 21201. 13. Compilation of Air Pollutant Emission Factors (with supplements 1-7). U.S. Environmental Protection Agency AP-42. 14. The National Air Monitoring Program: Air Quality and Emissions Trends. Annual Report, Volume 1. EPA 45/1 73-001-a. See Also: Nationwide Air Pollutant Emission Trends, 1940-1970. EPA AP-115. Monitoring and Air Quality Trends Report, 1973. EPA 450/1 74-007, October 1974. National Air Quality and Emissions Trends Report. 1975. EPA 450/1 76-002, November 1976. 15. Air Quality Maintenance Analysis for the Baltimore, Maryland Intrastate Air Quality Control Region for Total Suspended Particulate Matter and Sulfur Dioxide. March 1976. Bureau of Air Quality and Noise Control Technical Memorandum. BAQNC-TM 76-06. 16. Air Quality Display Model U.S. Department of Health, Education and Welfare Public Health Service, Consumer Protection and Environmental Health Service, Washington, D.C. November 1969. 17. Feasibility Study of a Fuel Switching Strategy for Maryland Power Plants. Vols. I and II. Prepared by Trident Engineering Association, Inc. December 1976. Maryland Power Plant Siting Program. 18. Trends in the Quality of the Nations Air. March 1977. EPA. 19. Preferred Standards Path Report for Polycyclic Organic Matter. October 1974. EPA. 20. Special Report: Trends in Concentrations of Benzene-Soluble Suspended Particulate Fraction and Benzo(a) Pyrene. 1960-1972. EPA 450/2-74-022. November 1974. 21. Junge, C.E. Journal of Geophysical Research, Vol. 65, p. 229. 1960. 22. S02 in the Atmosphere: A Wealth of Monitoring Data, But Few Reaction Rate Studies. Urone P. and Schroeder, W.H. Environmental Science and Technology, Vol. 3, No. 5. May 1969. 23. Conversion Rates of S02 to Submicron Sulfate in the Plume of a Coal- Fired Power Plant in the Western United States. Wayne 0. Ursenbach et al. Presented at 70th Annual Meeting of the Air Pollution Control Association. Toronto, Ontario, Canada. June 20-24, 1977. 11-61 24. Seasonality and Regional Trends in Atmospheric Sulfates. Neil H. Frank and Norman C. Possiel, Jr. Presented Before the Division of Environmental Chemistry, American Chemical Society, San Francisco, California, August 30 - September 3, 1976. 25. Report to Congress on Control of Sulfur Oxides. February 1975. EPA 450/1-75-001. 26. Determining the Geographical Area for Supplementing Oxidant Control Strategies. U.S. Environmental Protection Agency. January 1977. 27. Baltimore Oxidant Study 1977, Gary M. Klauber, Power Plant Monitoring Program, August 1978. 28. BAQNC/personal communication. 29. Electrostatic Precipitation of Fly Ash, Harry J. White APCA Reprint Series, July 1977. Air Pollution Control Association, Pittsburgh, PA 15213. See Also: Air Pollution Control for Industrial Cost Fired Boilers, by Allen H. Jones in Power Generation: Air Pollution Monitoring and Control K.E. Noll and W.T. Davis. Ann Arbor Science (1976). Electrostatic Precipitation: Predicted vs Actual Efficiencies, by Kenneth Stamper and K.E. Noll. 30. S02 Control Methods, Ponder, W.H. et al. The Oil and Gas Journal. December 13, 1976, pp. 58-68. 31. -Coal Reserves in Maryland - Potential for Future Development. Weaver, K.N. et al. Department of Natural Resources, Maryland Geological Survey, Information Circular 22, 1976. 32.. Survey of Alternative Air Pollution Control and Fuel Strategies for the PEPCO System 1975-2000. J. Pfeffer Project Leader. MITRE Techni- cal Report MTR-6934. April 1975. MITRE Corp. McLean, VA 22101. 33. Coal Cleaning with Scrubbing for Sulfur Control. U.S. Environmental Protection Agency, August 1977. EPA 600/9-77-017. 34. Industrial Research Laboratory - RTP Annual Report 1976. Office of Energy, Minerals, and Industry; Office of Research and Development. U.S. Environmental Protection Agency. Research Triangle Park, N.C. 27711. See Also: Publication List, May 1978, Electric Power Research Institute (EPRI). Research Reports Center P.O. Box 10090, Palo Alto, California 94303. Gives an extension list of EPRI reports available on these technologies. 11-62 35. Coal Processing Technology, CEP Chemical Engineering Progress, Vol. 73, No. 6, June 1977. 36. The U.S. Environmental Protection Agency's Fluidized-Bed Combustion Program. FY 1976. EPA 600/7-77-012. February 1977. 37. The U.S. Environmental Protection Agency Program for Environmental Characterization of Fluidized-Bed Combustion Systems. D.B. Henschel. Presented at the Symposium on Health/Environmental Effects and Control Technology Aspects of Energy Research and Development. Sponsored by EPA, Washington, D.C. February 9-11, 1976. 38. Environmntal Assessment of the Fluidized-Bed Combustion of Coal -- Methodology and Initial Results. K.S. Murthy et al. Paper No. 77-26-6. The 70th Annual Meeting of the Air Pollution Control Association, Toronto, Ontario, Canada, June 20-24, 1977. 39. A History of FGD Systems Since 1850 (a condensation of history from the status of flue gas desulfurization applications in the United States, Vol. 27 No. 10, pp. 948-961. October 1977. 40. The Status of S02 control systems. H.S. Rosenberg et al. Chemical Engineering Progress. Vol. 71, No. 5. May 1975. pp. 66-71. 41. The Status of Flue Gas Desulfurization Applications in the United States. A Technical Assessment. Federal Power Commission. July 1977. 42. Proceedings: Symposium on Flue Gas Desulfurization. New Orleans, March 1976. Vols. I and II. EPA 600/2-76-136b, May 1976, EPA Research Triangle Park, NC 27711. 43. Detailed Cost Estimates for Advanced Effluent Desulfurization Processes. G.C. McGlamery et al. EPA 600/2-75-006. January 1975. 44. EPA Utility FGD Survey. June-July 1978. EPA 600/7-78-051d. November 1978. 45. Simplified Procedures for Estimating Flue Gas Desulfurization System Costs. Thomas C. Powder Jr., et al. PEDCO Environmental Specialists, Inc. EPA 600/2-76-150, June 1976. 46. Advances in S02 Stack Gas Scrubbing. F.T. Princiolla. CEP (Chemical Engineering Progress), February 1978. 47. Electrical World. Vol. 190, No. 8. October 15, 1978, p. 4. 48. Comparing New Technologies for the Electric Utilities ERDA 76-141 (Revision A). December 1976. See Also: Clean Cost: What Does It Cost at the Bus Bar. EPRI Journal 76-141. December 9, 1976. 11-63 49. The Clean Air Amendements of 1977. P.L. 95-95, August 7, 1977 with Technical Amendments to the Clean Air Act, P.L. 95-190, November 16, 1977. 50. Atmospheric Diffusion. Pasquill, F.A. John Wiley and Sons. New York, N.Y. 1974. 51. Lectures on Air Pollution and Environmental Impact Analyses. Duane A. Haugen, Coordinator. American Meteorological Society. September 1975. See Also: Interim Guidelines on Air Quality Models. EPA Guideline Series, OAQPS No. 1.2-080. October 1977. Report to the U.S. EPA on the Specialists' Conference on the EPA Modeling Guideline. Organized by Argonne National Laboratory. Chicago, Illinois. February 22-24, 1977. 52. Testing of Rough Terrain Dispersion Models at the Westvaco Corporation's Pulp Mill in Luke, Maryland. Jeffrey C. Weil. January 1978. PPSP-MP-20. Baltimore, Maryland. 53. Evalu ation of the Gaussian Plume Model at Maryland Power Plant. Jeffrey C. Weil. March 1977. PPSP-MP-16. Baltimore, Maryland. 54. Stack Plume Characterization and Model Assessment with Lidar DAta. Jeffrey C. Weil, NATO/CCMS, 9th International Technical Meeting on Air Pollution Modeling and Its Applications. Toronto, Canada. Augusta 28-31, 1978. 55. Proposed Regulatory Revision, 1977 Clean Air Act Amendments for Stack Heights. Federal Register, Friday, January 12, 1979. p. 2608. 56. There may be a major change in EPA's Approach to Photochemical Oxidant' Standards. See: Environment Reporter, Vol. 9, No. 7, June 16, 1978. p. 235 and also Science, Vol. 202, No. 4371, December 1, 1978. p. 949. 57. -Preliminary Site Investigations. Soller's Point Site. 600 MW Gas Turbine Facility. Maryland Power Plant Siting Program. Letter to PSC, July 28, 1976. 58. 1978 Ten-Year Plan of Maryland Electric Utilities, Possible and Proposed Plants, 1978 through 1987 Public Service Commission of Maryland. 59. Prevention of Significant Deterioration. A Critical Review. Arthur C. Stern. Journal of the Air Pollution and Control Association. Vol. 27, No. 5, May 1977, pp. 440-453. 60. The Clean Air Act Amendments of 1977. Eric B. Easton and Francis J. O'Donnell. Journal of the Air Pollution and Control Association. Vol. 27, No. 10. October 1977. pp. 943-47. 11-64 61. The latest EPA Regulations for PSD became effective June 19, 1978 (43 FR 26380). See: Environment Reporter, Vol. 9. No. 8, June 23, 1978, p. 335. The publication of the emission offset policy has been delayed, probably, until January 1979. See: Environmental Reporter, Vol. 9. No. 28, NovemberlO, 1978, p. 1277 and p. 1295. 11-65 CHAPTER III AQUATIC IMPACT For each kilowatt hour of electricity generated, a steam power plant burn- ing fossil fuel must dispose of about 4,400 BTU of heat via its condenser, and a nuclear power plant must dispose of about 6,600 BTU. Most Maryland 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 17*F in the condenser, and discharged into a receivil ig body of water. Approximately 1 million gallons of water per minute (or 63 m /sec) is required for each 1000 MW of generating capacity. Even when closed cycle cooling can be used to reduce water withdrawal (as discussed in Chapter VI), there may still be a significant amount of water withdrawn. The Chesapeake 'lay and its tributaries serve as the major source of cooling water in Maryand. At the same time, they also support complex aquatic food chains that produce renewable resources of fish and shellfish. A major concern of the Power Plant Siting Program is that power plants, while providing electri- city at a reasonable cost, do not interfere with the maintenance of sustained yields of resource species, which are dependent on all food chain components. 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. As water is drawn through the power plant and returned to its source, aquatic organisms interact with cooling system structures, with intake and discharge velocity fields, with the heated effluent, and with other alterations of the environment caused by plant operations as explained below.* The loca- tions and nature of these interactions are shown schematically in Figure III-1. The following types of interactions and stresses are encountered by aquatic organisms: o 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 portions of the water column, where temperatures tend to be lower than at the surface during summer months. Large numbers of fish congregate in intake embayments during the summer where they may be entrapped. During the summer months, dissolved oxygen (DO) concentrations in the water often drop to levels below that needed to sustain adult and juvenile fish. The drop is pronounced in the deeper water entering the embayment under the curtain wall. Fish kills may result, and the killed (or weakened) fish may then impinge in large numbers on the protective intake screens. Radiological effects are discussed in Chapter IV. III-1 A. B C D Curtain Wall ITrash. I nta ke `11@ Intake! Rack Condenser Screens RECEIVING WATER INTAKE WATER' Embaymenti PUMP tubes Discharge C------ Conduit' e------- -)0- 31- Plume 4- U0 DISCHARGE (Plume) ENTRAPMENT IMP I NGEMENTJ ENTRA I NMENT: EFFECTS Figure III-1. Path of cooling water flow through apower plant and locations 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 receiving water. C.- Small organigms in the water column (plankton) pass through the cooling system; they experience a temperature rise and also shear and pressure forces during their cooling system transit. D. Organisms in the receiving water may encounter plume temperature rises (and may be affected by the velocity of the discharge). 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 it 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 condi- tion. The screens are rotated periodically and the impinged matter is washed off and usually flushed back into the cooling stream discharge. Some species survive this treatment, but others suffer a high rate of mortality. o 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 tempera- ture. Temperature rise varies from 10'F to 17'F in Maryland plants, and exposure time from a few minutes to almost two hours (including retention time in effluent canals). Thus, thermal stress "dose," i.e., product of temperature and time is quite variable. Additional stress is experienced by entrained biota at plants where biocide (usually chlorine) is added to the cooling water to prevent clogging of the cooling system by built-up biomass. o Discharge Effects The alteration of local habitat produced by the discharge of cooling water can manifest itself in several ways. Aquatic organisms can be 1. entrained" into the discharge plume, where they will be exposed to higher-than-ambient temperature and biocide residuals. Other toxic substances released with the cooling water (e.g., copper) may affect the stationary benthic communities near the plume. Finally, fast-moving discharge flows cause alterations in the characteristics of bottom sedi- ment in the discharge zone, and also directly influence the behavior of some organisms. The trophic levels and life stages of organisms interacting with the power plant can be grouped as follows: o phytoplankton zooplankton benthos 111-3 � 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 III-1). Entrapment can stress juvenile fish. Entrainment stresses planktonic organisms, which serve as food for many resource species, as well as the planktonic larval stages of many resource and forage species. All aquatic biota may experience discharge effects 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 mecha- nisms such as increases in growth rate, fecundity and/or early survival. In the case of phytoplankton or zooplankton, losses due to entrainment are generally recouped quickly as a result of rapid reproduction (generation times of hours to days). Other organisms have much longer generation times. 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 con- trolled blowdown are used to reduce the exposure. The potential for such losses is much less for ubiquitous species which spawn in or inhabit wide areas of the Bay. Plant operations can indirectly cause decline of a population by decreas- ing the abundance of its food supply. The dominant groups in the Bay which are important as forage are phytoplankton, zooplankton, benthic organisms, and small fish species (e.g., Bay anchovy and menhaden). Although fish popu- lations are more likely to be affected by the entrainment of their ichthyo- plankton, they could also be affected by a change in the density of their food (see Figure 111-2). 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 modificatons make an area unsuitable for use by some species, a subsequent decline in their abundance can occur locally. A. Aquatic Habitat The central concept underlying the cumulative aquatic assessment presented here is that Chesapeake Bay and 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 distribu- tions of organisms in estuaries. Each of these habitats can be identified with unique functions in producing or supporting important resource elements, although their biotic compositions gradually change into one another, and their extent varies seasonally. Cumulative impact will be assessed in terms of 111-4 Table III-1. Major types of aquatic effects of power plant operations Type of Stress Sources of Primary Susceptible (a) Habitat Effects Organisms Low DO Mechanical Thermal Chemical Alteration Entrapment Fish x Impingement Juvenile fish, crabs x Entrainment Ichthyoplankton (b) Zooplankton(c) x x x Phytoplankton(d) Discharge Adult and juvenile x x x Effects fish, benthos(e) shellfish (a) Low dissolved oxygen concentrations oxygen deficiency (b) Eggs and larvae of fish (c) Minute 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 PREY SPECIES 01 AND (NO CROAKER OR YOUNG OF CRUSTACEA MENHADEN EGGS) ALEWIFES MENHADEN ZOOPLANKTON WHITE PERCH (P CROAKER SHRIMP kv SPOT BLUE CRABS MACROPLANKTON MUD CRABS (WATER FLEAS, COPEPODS MYSIDS'ETC 4st SHRIMP AND MUD CRAB A PHYTOPLANKTON LARVAE AND YOUNG ORGANISMS SUSCEPTIBLE TO ENTRAINMENT Figure 111-2. Areas of potential power plant entraiment impact on striped bass and associated food items. significant effects on the biota over the entire extent of each characteristic habitat type within Maryland, with the emphasis on whether the long-term integ- rity of each estuarine habitat and its characteristic functions are maintained. 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 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 parts per thousand (ppt) The following major ecological functions of each habitat may be listed: * Polyhaline and Marine These high salinity waters are primary sites of blue crab spawning and development, and also support hard clams. Several fish species, (e.g., spot, croaker, and menhaden) whose young and adults 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. 9 Mesohaline These medium salinity regions are the primary areas of shellfish pro- duction (clams, oysters) whose early life stages are planktonic. Mesohaline waters also support the adult crab populations. They pro- duce most of the estuarine forage fish biomass, and therefore, serve as feeding areas for large predator fish (e.g., bluefish, striped bass). * Oligohaline These brackish water environments support resident estuarine fish populations, and serve as spawning and nursery grounds for them. These fish populations serve primarily as forage organisms for larger fish, but may also be exploited by man (e.g., white perch). The areas are also feeding grounds for migratory marine and estuarine species such as menhaden and white perch. Some spawning of anadromous fish also occurs here. * Tidal Fresh Segments of estuaries within tidal influence but without a significant salt intrusion provide spawning and nursery areas for anadromous fish species, also supporting their larvae and Juveniles during 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 particularly important example of a species using this environment as a spawning and nursery area. 111-7 9 Riverine These freshwater habitats beyond the head of the estuary have resi- dent fish populations and supporting bottom (benthic) communities adapted to constant freshwater conditions. The location of these zones change seasonally as a result of changes in the amount of freshwater inflow (see Figure 111-3). Table 111-2 indicates the zones in which power plants in Maryland are located, and shows locations according to season. The majority of plants in Maryland are situated in tidal fresholigohaline regions. However, the largest 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 shoreline in Maryland. B. Assessment and Mitigation of Impact Environmental impact assessments are carried out by the Maryland Power Plant Siting Program. These assessments consist of predictions of the effects of the power plant construction and operation, evaluations of the impact of these effects upon the aquatic resources of the State and determination of measures to minimize adverse impacts.* At several existing plants there are monitoring programs for detecting and quantifying these effects and for measur- ing and analyzing their impact. For new plants, after regional surveys have quantified the existing popu- lations, the local impact of each effect is predicted and related to regional impact on populations of affected organisms. The aquatic impacts are, as much as possible, described in terms of percent reduction of local and re- gional populations, the possible indirect effects on other organisms, and the impact on man's use of the resources. Where appropriate, a sensitivity analy- sis is performed to reveal the consequences of uncertainties in knowledge or assumptions. Feasible alterations in plant design which might reduce impacts are evaluated with respect to benefits and costs. Those alterations which are found to have sufficient benefits are recommended to the appropriate regula- tory agency (e.g., the Public Service Commission or the Nuclear Regulatory Commission) for incorporation into the decision process for a construction permit. For example, in the course-of the detailed site evaluation of Douglas Point, a plant design alternative was identified which would reduce the water withdrawn from the Potomac River by a factor of three. Entrainment of fish eggs and larvae would thus be reduced by the same factor. This proposed de- sign alternative was accepted by the utility. Sometimes detailed predic- tions of the most probable impact are not possible, and a conservative analysis must be used (e.g., assuming 100% mortality of impinged fish where no specific mortality studies have been done). The monitoring phase consists of detection and quantification of power plant effects, and evaluation of the significance of these effects in altering resource An effect is a measurable change. An impact is an effect that is judged to be significant. 111-8 salinity spring autumn Surface Soli ity Surface So linity in parts per thousand (%a) in parts per thousan 0/60) @3 7 3 4 10 5 1211 C 7 D 13 14 9 7 4 910 110 5 7 11 12 17 Is 16 10 is 6 IS 13,4 Is '0 w 11 12 14 17 Is Is 116 17 13 17 06 0- 5 IS 6@ 2 5-10 1:1 20 $ 10- 15 3 122 IS 29 15-20 4 3 10 23 10 28 116 27 20-25 Is 26 A SCALE IN MILES 25-30 12 13 a 3 10 '"S .It P., 1000 0 ..t., Figure 111-3. Spring and autum salinity distributions in the Chesapeake Bay. From: The Chesapeake Bay in Maryland. Editor Alice Jane Lippson. The Johns Hopkins University Press. Baltimore. Copy- right 1973 by the Johns Hopkins University Press (by permission). M_9 Table 111-2. Power plant location by salinity regime SPRING FALL Power Plant Riverine Tidal- Oligo- Meso- Riverine Tidal- Oligo- Meso- fresh haline haline fresh haline haline, Benning Rd. x x Brandon Shores x x Buzzard Pt. x x Calvert Cliffs x x Chalk Pt. x x C.P. Crane x x Dickerson x x Douglas Pt. x x Gould St. x x Riverside x x Wagner x x Westport x x Morgantown x x Possum Pt. x x Potomac River x x R.P.'Smith x x Sumnit * Vienna x x Conowingo (Hydro) x x Theproposed Sumdt plant is on the C&D canal. Salinity varies irregularly from tidal fresh to mesohaline. The monthly average at the plant site is generally below 5 ppt (37). M M Im M M M W M M W, M M M M M M M M yield and ecosystem stability. To learn how losses of organisms due to entrain- ment, impingement, and plume effects indirectly alter population sizes in the receiving body, populations must be monitored over a considerable span of distance and time. Plant-induced changes (if any) must be separated from natural and other man-induced changes that occur seasonally, annually, or irregularly. To determine the direct damage caused by entrainment, the number and condition of organisms are measured as they enter and leave the plant with the cooling water. Impingement damage for each species is determined from samples taken from screens. These measurements show which species are directly affected in-plant, and to what extent they are affected. Plume effects are determined by measuring changes in abundance or distribution of organisms in the area exposed to temperature increases and other discharge related environmental alterations. The results of ongoing studies at existing plants are applied to mitigate impact. Where these studies identify plant-related effects, alternative operating schemes and changes in plant design are evaluated as to their benefits and costs. Examples of this are changes in the intake structure at Calvert Cliffs (discussed under the mesohaline section of this chapter) and the ongoing evaluation of augmentation pumping at Chalk Point and Morgantown (2.3). Monitoring results will be applied to the design of future plants. For example, it is extremely unlikely that any new plant would be built with a long discharge canal or low velocity discharge because of the deleterious effects that have been associated with such systems (2,3,4). The procedures used to assess the ecological significance of plant-induced population changes will vary according to the group of biota considered. For plankton, the concern may be about the result of a localized depletion in terms of yields of higher trophic levels. In the case of fish, the magnitude of plant- related kills might be compared to commercial or recreational harvests. Once the effect has been quantified, the determination of the acceptibility or un- acceptibility requires a value judgement, and thus there is a degree of sub- jectivity associated with the specific determination. C. Aquatic Impact Because aquatic impact is a consequence of withdrawal and discharge of cooling water, the magnitude of cooling water flows in relation to the size and flow rates of the water bodies on which plants are sited provides an index of potential impact. These flows contribute to the mixing and trans- port of the cooling water effluent, and they determine the size of the zone of physical and potential biological alterations. The dilutions of heated water and toxic materials, and the mixing of biota-depleted volumes of cooling water into ambient waters, influence the ability of the habitat to accept the power plant effects without significant ecosystem alterations. In riverine waters, flow is unidirectional and varies with the amount of rain water run-off. The ability of such a flow regime to meet cooling flow requirements of a power plant, while maintaining environmental integrity, is indicated to some extent by the relative amounts of river flow (usually mean annual low flow) and plant cooling flow. III-11 Estuarine flows are complex and vary from the upper to the lower reaches. Tidal oscillations of the water are superimposed on the unidirectional river flow, and usually exceed it in magnitude. Thus, although water masses may oscil- late several times past a given location, net river flow continually brings new water from upstream and flushes "resident" water downstream. Because of tidal influence, discharges from estuarine power plants have residence times near a particular location which are greater than at riverine plants. However, because of the large volume tidal flows, effluents are more readily dispersed and diluted than in rivers. As salinity increases down-estuary, the non-tidal circulation patterns in the estuary become more complex (see Figure 111-4). As the fresh river water flows downstream, it entrains denser (i.e., heavier) salt water from below. A gravitational convection pattern (enhanced by tidal mixing) develops in the lower estuary (extending to some degree to the tidal fresh region). Downstream mass transport in the upper layer will now exceed the river input. To maintain continuity of mass, saline bottom water from downstream must replace the water convected vertically upwards creating an upstream net flow in the lower layers. Thus, opposing non-tidal flows develop, flowing down- stream on the top and upstream on the bottom. These flows are superimposed on the tidal flow and may exceed the river input both in the upstream and downstream direction. The difference between these opposing flows is, how- ever always equal to the river input at any point along the estuary. In a general way, we can view these large non-tidal flows as providing high rates of flushing of power plants effluents, while the tidal flows generate disper- sion and dilution.* In this context, there are several characteristics of each power plant and its adjacent water body which are important in assessing the potential impact of the plant. As a result of tidal flows which reverse direction over a single cycle, water originally outside the plant will make an upstream or downstream excursion from that point over the period of that cycle. These double tidal excursion distances define a localized reference volume and area, (see Figure 111-4), to which the amount of water used by the plant and the dimensions of the discharge plume may be compared. Ratios of non-tidal river flow to plant flow given an index of the rate of advection (flushing of discharge) away from the site. Ratios of root-mean-square tidal flow to plant flow can be considered as indicators of dispersive potential at a site. The tidal surface area can be compared to the area of the thermal plume (which represents an area over which a direct physical effect is measurable). The volume of water present within a double tidal excursion distance of the plant can be compared to the volume of water which has passed through the plant over various significant periods of time. Such comparisons have greatest relevance when considering potential plant effects on phytoplankton and zoo- plankton. These organisms exhibit rapid reproduction (5) (phytoplankton cells typically double in numer in a single day; zooplankton have generation times on the order of seven days). If it were assumed that all entrained organisms The extent of the immediate area physically and biologically altered also depends on the width, depth, and velocity gradients of the river. In addi- tion, specific intake and discharge designs will influence the size and shape of the areas affected by intake and discharge flows. 111-12 A. Salinity 0 0 0100 Tidal Fresh 0.5 5.10 181.0 301.0 To Ocea n Riverine I R 1.5R 2. OR 2.5R 17777777 Upper Layer I nput Net Transport 0.5R 0. 5R :0. 5R Lower Layer 0. 5R 1. OR 1. 5R Net Transport Limit of Two-layered Estuarine Circulation B. 4@ Slack before ebb Tidal Average Tidal Excursion Average Tidal Excursion Slack before Excursion S u rface A rea Volume' f lood Distance Figure 111-4. (A) Estuarine circulation patterns (B) Tidal excursion 111-13 were killed, and that the remaining organisms in the tidal excursion volume continued to be homogeneously distributed (i.e., instantaneously mixed), then the ratio of plant withdrawal volume, during the doubling time, to the tidal excursion volume would represent the percentage reduction in population growth rate attributable to entrainment losses. For populations that are limited in growth due to other factors (such as nutrients), the effect of lowering growth rate by 10-20 percent will probably only affect the time required to reach the limiting level, not the overall standing stock. Table 111-3 and 111-4 show these various flows and volumes for plants in Maryland and on Maryland-related water bodies. These areal and volumetric relationships indicate a potential impact of power plants based on scaling alone. Based upon these ratios alone, one would, for example, expect the C.P. Crane, Benning Road, Chalk Point, Buzzard Point, Vienna, and, as a group, the Baltimore BG&E plants, to have a greater potential for aquatic impact. Detailed studies are required, however, to confirm or deny the existence of any in-plant effect. Having discussed the possible impacts of plants from a physical compari- son of the water body size to the plant water needs, we shall now turn to the results of evaluation and monitoring studies for each site within the various salinity regimes. 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 of most commercially and recreationally valuable fish species and blue crabs. The three plants located in this zone (Calvert Cliffs, Chalk Point, and Morgan- town [summer-fall]) are the largest and newest in the State. All three of these plants have been and are being intensively studied. Preliminary findings of Calvert Cliffs monitoring studies covering the first two years of operation of Unit 1, have been reported (6,7). Morgantown monitoring findings have also been summarized (2,3). Chalk Point was the subject of study in the 1960's (4), and is currently being extensively studied. Entrainment Inplant losses of about 30-70 percent of entrained zooplankton have been observed at Calvert Cliffs. Loss of entrained phytoplankton have also been observed, primarily in late summer and fall (6,7). In both cases, no nearfield depletion has been observed. Regional reduction in zooplankton density and phytoplankton assimilation was noted in 1975, but the widespread nature of the changes suggest the plant was not the causative agent (6,7). High zooplankton mortalities (50 percent) have been measured as a result of entrainment at Morgantown only under the most severe ther- mal and chlorine stress conditions. Phytoplankton productivity was also reduced during those periods (2). However, no changes in zooplankton and phytoplankton populations in the river were detected (2). It was estimated that 2 percent of the plankton transported 111-14 M M Table 111-3. Water flows at Maryland power plants. Mean River Root Mean Square MW Plant Discharge Tidal Flow Double Tidal Average Tidal Mean of Two Tidal Nameplate Withdrawal W/sec) (103m3/sec) Excursion Distance Excursions Volume Tidal Excursions Rating (m3/sec) (Nautical Mi.) (xio6m3) Surface Area Spring Fall Spring Fall (xlo6m2) Benning Road (a) 749 6.1 6.2 2.4 0.003 0.003 2.1 1.5 1.70 Brandon Shores (b) 1220 0.9 NIA NIA N/A NIA NIA N/A NIA Buzzard Point 235 3.5 6.2 2.4 0.37 0.37 3.0 9.0 2.10 Calvert Cliffs 1828 156.4 2300.0 400.0 61.40., 56.70 11.8 2263.5 250.00 Chalk Point(c) 1387 23.4 20.0 8.0 2.03 1.89 13.1 113.5 45.40 C.P. Crane (d) 400 21.0 0.5 0.5 0.56 0.44 5.0 3.00 Dickerson(e) S88 14.7 3S8.0 144.0 - - - - Douglas Point (f) 2200 1.4 4SLO 181.0 9.42 8.99 8.1 318.2 79.70 Gould St. (g) 174 67.0 H H Riverside 334 13.8 1 9.0 3.0 1.80 1.80 486.6 68.00 H Wagner 1043 41.6 Ln Westport 194 10.0 Morgantown 1252 61.1 487.0 197.0 12.40 11.40 11.8 636.0 102.70 Yossum Point 478 14.8 475.0 19S.0 4.44 4.13 6.6 199.3 37.70 Potomac River 514 9.7 470.0 190.0 1.38 1.20 10.5 50.4 19.75 R.P. Smith(e) 110 3.5 200.0 .30.0 - - - - Stwimit(f) 900 0.7 96.3(h) S3.8(h) 1.27 1.18 20.4 61.6 6.00 Vienna(i) 230 3.7 4.3 1.4 1.74 1.62 19.7 S4.0 1530 (a) 250 @11 with cooling towers (e) River plant (b) Withdraws cooling water from Wagner discharge canal, (f) Proposed plants, with cooling towers uses cooling tower (g) Total for the four plants (c) Units I and 2 have once-through cooling, Unit 3 has cooling tower (withdrawal not including augmentation pumps) (h) Based on net non-tidal transport through C & D Canal (d) Withdraws from Seneca Creek, discharges into Saltpeter Creek (i) Units 5, 6, 7 have once-through cooling systems Table 111-4. Relationships between plant withdrawal volumes and tidal volumes; plant withdrawal rate and tidal and river flow rates. VP 1 VP7 QP QP VT QT QR Spring Fall Spring Fall Benning Road (a) 35.1 246.0 203 *.33 203.33 98 254 Brandon Shores (b) N/A N/A N/A N/A N/A N/A Buzzard Pt. 3.4 23.5 0.95 0.95 56 146 Calvert Cliffs 0.6 4.2 0.25 0.28 7 39 Chalk Pt. (c) 1.8 12.5 1.15 1.24 117 293 C.P. Crane (d) 36.3 254.0 3.75 4.77 4200 4200 Dickerson (e) N/A N/4 N/A N/A 4 10 Douglas Pt. (f) < 0.1 0.3 0.01 0.02 < I I Could St. (g) Riverside Wagner 1.3 9.0 4.00 4.00 801 2403 Westport Morgantown 0.8 5.8 0.49 0.54 13 31 Possum Pt. M 43 0.33 0.36 2 5 Potomac River 1.7 11.6 0.70 0.81 3 8 R.P. Smith(e) N/A N/A N/A NIA 2 12 SUMIt M 0.1 0.7 0.06 0.06 j(h) I(h) Vienna(l) M 4.1 1 0.21 0.23 1 86 264 Key: vPl plant withdrawal voltene - I day QP = plant withdrawal rate VT tidal volume QT - tidal flow ry) VP7 plant withdrawal volume - 7 days QR - flow of river (or net flow up estua NOTE: For footnotes, see Table 111-3 M" M M, M M M M M past the plant would be destroyed by entrainment (2,3). No adverse impact would result from losses of this magnitude to the rapidly reproducing plankton populations. Large kills (up to 100 percent) of entrained organisms have been ob- served at Chalk Point* with thermal and biocide stresses appearing to both be important as causes. Near-plant depletions of jellyfish were noted, but no changes in river populations of copepods were found (4). The findings at all three plants are consistent. Entrainment losses of phytoplankton and zooplankton do occur but high reproduction rates of the affected populations compensate for plant effects. Cumulative effects would not be expected. Studies to verify this are now under- way. 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 magnitude of these losses are now in progress (9). 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 (6). Thus, nearfield losses caused by entrainment were not detected. The same species of larvae are found at Chalk Point and Morgantown. Nearfield ichthyo- plankton depletions were also not detectable at Morgantown (2). Localized losses of ichthyoplankton of these species, which spawn virtually throughout the Maryland portion of the Bay, are insufficient to decrease Bay populations. e Impingement Fish and crab impingement data from Calvert Cliffs, Morgantown and Chalk Point are summarized in Table 111-5. Menhaden and spot dominate the fish impingement at these plants, except for Calvert Cliffs impinge- ment in 1975 which shows greater variability in species composition. The six species listed in the table are all abundant, ubiquitous species that occur throughout mesohaline regions of the Bay and its tributaries. These species also dominate net catches made during surveys conducted at these sites (3,6), confirming the non-selective nature of cropping by power plants. The plants appear to be impinging fish at a rate propor- tional to their abundance in the plant vicinity. There is insufficient knowledge of population size and dynamics of all of the listed species to predict the exact consequence of plant-induced losses, but no changes in fish density or community composition in the vicinity of these plants have been observed. This implies that impingement losses are too small to significantly alter the size of Bay populations. One way of putting impingement losses in perspective is to compare them to other population PEPCO has indicated that more recent, unpublished studies may lower entrainment mortality estimates (8). 111-17 Table 111-5. Estimated total impingement by species at mesohaline power plants (number of individuals). Data have been obtained by summing monthly totals estimated from samplings during that month. Sampling schedules (frequency and duration) vary from plant to plant and from time to time. (See references for details.) 1975 1976 Species MDrgantown(a) Calvert CI1ffs(bJ1 Calvert Cliffs(bl Chalk Point(c) Morgantown(d) Total (e) Menhaden.(f 414,376 (571) 189,873 (111) 4S4,209 (20t) 552,782 (591) 7S9,680 ( 55%) 1,766,671 ( 39t) Spot(f) 200,972 (271) 261,964 (151) 1,280,094. (581) 254,404 (27%) 286,869 ( 211) 1,821,367 ( 401) 11ugchoker 2,S10 ( 0.3%) 99,154 ( 61) 188,367 ( 8S) 50,893 ( SI) 36,167 ( 31) 275,427 ( 6t) Bay Anchovy 30,969 ( 4%) 672,709 (381) 77,271 ( 31) 10,421 ( It) 47,8SI ( 3%) 135,543 3%) Croaker(f) 3,069 ( 0.0) 338,531 (19%) 106,799 ( 5%) 5,102 ( 0.5%) -- 111,901 3%) White Perch 60,648 ( 81) 3,921 ( 0.21 4,7S2 ( 0.21) 4,365 ( 0.5%) 96,993 ( 7%) 106,110 21) Others 19,S76 ( 31) 199,050 (10.8t] 111,881 ( SU S9,030 ( 71) 147,721 ( 11t) 318,632 71) 00 TOTAL FISH 732,081 (100%) 1,765,202 (1001) 2,223,373 (100t) 936,997 (100t) 1,37S,281 (1001) 4,535,651 (1001) Crabs -- 294,975 434,004 IlpIO69269 280,704 1,820,977 (a) March and June-December (6) (d) may 15, 1976. - May 28, 1977 (6) (b) January - December (7) (0) For periods indicated (Does not Include large episodic fish kills see text) (f) Predominantly juveniles (c) June - December losses (i.e., due to predation, fishing, natural die-offs, etc.). Such data are available for the major impinged species discussed below. Detailed studies are now in progress to improve our knowledge of these species. Menhaden is one of the major commercial finfish species in the Bay, usually accounting for over 40 percent of total landed weight (Table 111-6). Populations are mobile, and they are distributed throughout mesohaline and oligohaline regions of the Bay. In some cases, the impingement data in Table 111-5 do not span'an entire year, but do cover the summer-fall period when menhaden are most abundant. Impinge- ment mortality for menhaden is considered to be 100 percent. As an approximation of a single year's impingement weight total of menhaden for the 3 mesohaline plants, the 1976 number totals were multiplied by the average weight of menhaden impinged at Calvert Cliffs (20 g .043 lbs) to give total impinged weight estimates of 76,000 pounds. This is about 1.25 percent of the 1976 Maryland landings of 6 million lbs (Table 111-6). Although the mean weight of commercially harvested menhaden is not known, they are larger (older) than the juveniles being impinged. The number of juvenile menhaden impinged is, there- fore, much more than 1 percent of the number of adult menhaden commer- cially caught. However, since these juveniles would have suffered considerable natural mortality (typically 90 percent) before reaching harvestable size, the plant related losses would probably cause a much smaller decline in subsequent years. Menhaden experience large natural die-offs throughout the Bay during summer months. Many of these kills are unreported or unquantified. Reported kills of menhaden in 1974 and 1975 totaled 100 million and 1.9 million individuals, respectively (10). The 1976 impingement total for the 3 plants is estimated to be 1.8 million individuals. Menhaden are also a favorite prey of the two major predatory fish in the Bay: bluefish, and striped bass. Daily rations for these species are about 3-5 percent of their body weight/day (11). Total stock of bluefish and striped bass in the Bay is unknown, but the amount harvested, which may represent only a small per- centage of the stock, can be used to give some insight into the amounts of forage fish consumed by predators. From May to Octo- ber in 1976, sportfishermen landed 535,800 lbs of striped bass and 2,915,179 lbs of bluefish in the upper Bay (12). If these totals are combined with commercial landings over the entire Bay during the same period, total weight of both species landed was 5,2469000 lbs. Assuming 4 percent of body weight consumed each day for a 5 month period, total forage which would have been uti- lized by these landed fish is 32,525,000 lbs, much of which would have been menhaden. The estimated impinged total of 76,000 lbs is about 0.23 percent of that total. All of the above comparisons demonstrate that menhaden impingement kills represent a small perturbation on the Bay. Spot and croaker juveniles are abundant in mesohaline areas. Their impingement mortality is considered to be near 100 percent (13). 111-19 Table 111-6. Maryland camercial landings 1972 1973 1974 197S 1976 Pounds Dollars Pounds Dollars Pounds Dollars Pounds Dollars Pounds Dollars Fish Ue-wives(a) 1,6S4,641 $ @3,098 2,33lt424 4S,254 1,387,676 $ 31,801 696,477 $ 16,075 121,990 $ 5,320 Bluefish 59,075 S.802 275.330 23,097 372,738 28,357 271,914 ZS,671 489,399 28,589 Catfish and Bullheads 386.340 39,567 29S,083 31,125 302,628 37,908 260,OSO 30,485 230,023 28,409 Eels 229,764 33,164 180,466 44,118 144,527 42,984 204,667 69,725 165,725 58,004 menhaden 6,212,OOZ 124,614 9,686,956 221,059 4,932,962 128,631 6,228,700 166,003 6,105,600 192,607 Seal 'T at 313,429 34.125 539,520 74,61S 372,832 47,7S4 892,718 79,414 428,786 46,283 Sha ka 954,145 117,299 S97,914 105,573 221,444 46,000 182,352 44,606 110,639 42,028 spot 68,171 10,974 27,322 5,244 10,018 1,383 89,900 8,314 15,737 2,838 Striped has (a) 3,18S,929 917,S48 4,677,617 1,451,800 3,382,852 880,329 2.763,509 1.083,710 1,813,910 990,863 White perc;?a 1,108.033 204,784 762,719 162,697 497,7SS 93,402 S68,900 112,049 407,700 107,046 Yellow perch 101,46S 13,549 3S,S23 7,150 35,409 5,070 29,818 5,323 22,744 4,973 Other finfish and Unclassified 897,610 185,717 1,179,483 246,222 1,602,9S2 277,375 2,78S,SSI 510,279 3,714,130 SOS,787 TOTAL FISU 15,170,603 $1,720,241 20,589,357 $2,417,954 13,263,793 $1,620,994 14,974,556 $2,152,095 13,626,383 $2,312,747 Anadromous fish above - and % of total fish $1,272,729 (74%) $1,765,324 (731) $1,051,532 (65%) $1,2S6,440 (58%) $1,14S.257 (SO%) Shellfish Hu-e--c-r-As (hard, soft, peeler) 2S,050,531 $3,114,209 20,723,286 $3,484,OS7 24,9i3,677 $4,631,815 2S.917,890 $5,149,76S 20,88S,60O $5,649,968 Soft clams 1,949,S20 1.014.782 668,688 SS7,240 1,766,136 I.S01,210 1.246,128 1,174,340 1,742,604 2,767,698 Oysters 19,02,800 11,963,272 19,055,700 12,561,489 17,263,970 11,S88,664 16,402,300 13,126,666 15,827,708 16,4Z8,117 0 Turtles (snapper) 18,023 3,S97 24,353 S.189 36,540 10,226 83.144 26,644 48,08S 14,136 Terrapin (Diamondback) 3,S45 1,523 1,4S8 709 1,733 1,016 S,OS8 3,319 1,201 791' ABOVE SHELLFISH(b) 46,074,41 $16,097,383 40,473,485 $16,608,684 44,042,056 $17,732,931 43,654,S20 $19,472,737 38,505,198 $24,860 710 (R" TOTAL 61,245,022 $17_181@7624 61 062 842 $19,026,038 57 058 849 $19,353 925 58,629 076 $21,624,832 52,131,581 027,173,457 (a) Anadromous species (b) Exclusive of the following species limited primarily to Atlantic Ocean waters: lobsters, hard and surf clams, conch, and squid. Source: "Haryland Landings," Current Fisheries Statistics, U.S. Department of Commerce, National Oceanic and Atmospheric Administration, National Marine Fisheries Service, December 1973-76. The estimated annual impingement in 1976 at Morgantown, Chalk Point, and Calvert Cliffs was about 1,800,000 spot and 112,000 croaker with mean weights of 0.0112 and 0.018 lbs, respectively. Trawl surveys at Morgantown and Calvert Cliffs show that both spot and croaker juveniles are very abundant in these areas. We estimate, from catches at Calvert Cliffs, that the total number of spot impinged in June 1976 (346,800, the highest monthly total for the year) was equivalent to the number of spot occupying about 100 acres of Bay bottom at that time, repre- senting approximately 0.01 percent of the suitable habitat in the Bay (14). Another indication of the density that occasionally occurs is that 23,000 juvenile spot were taken in a single tow in the fall of 1976 during the scientific sampling program. To determine the impact of this impingement, we can compare to sports and commercial catches. In making such a comparison, it must be kept in mind that the juveniles impinged in the lower mesohaline habitats (e.g., Calvert Cliffs) would have spend their adult life in a region extending from the higher mesohaline environ- ment at the Maryland-Virginia border to the marine environment of the ocean. Thus, any effect of juvenile kills at Calvert Cliffs would manifest itself in depletions in the lower Bay and the ocean. Because of relatively high natural mortality in developing from juveniles to adults, the effect of juvenile impingement mortalities would be greatly attenuated as it propagates through the age struc- ture of the species. It must also be kept in mind, that both spot and croaker are very lightly exploited resources in Maryland, with modest sports and commercial catches. The available data (12) indicates that the sport harvest in the upper Bay during May through October 1976 was about 52,800 spot and 10,950 croaker of an average weight of 0.3 to 0.1 lb, respec- tively (clearly a different age class from the impinged fish). These low numbers are reasonable, considering the preference of the adult fish for higher salinity waters. Commercial landings in the Bay for 1976 were 5,723 lbs in Maryland and 1,203,766 lbs in Virginia for spot, and 1,089 lbs in Maryland and 2,871,420 lbs in Virginia for croaker (Table 111-6). (Total Maryland commercial landings in 1975, mainly from the ocean, were 89,900 lbs and 639,000 lbs for spot and croaker, respectively.) Converted to number of individuals, the Bay commercial catch of 4 million spot and 3.2 million croaker can be compared to an estimated adult stock loss 0.22 million spot and 0.012 million croaker due to impingement (assuming 10 percent of juveniles survive to adulthood). The conclusion is that the juvenile impingement losses of spot and croaker, lightly exploited species, are insignificant, based on the great abundance of these juveniles in the mesohaline habitat. --,Hogchoker, a very hardy species, suffer less than 1 percent mor- tality as a result of being impinged. Thus, no plant influence on hogchoker populations can be expected. 111-21 -- Anchovy, the remaining major impinged fish species, is distributed throughout the Bay. Acousti surveys have revealed densities on 15 of water (6). At a density of 13-14 the order if 7-25 fish per m fish per m , the total impinged in one year at the three plants would occupy only about 10,000 M3 (a volume approximately 100 by 100 feet wide and 30 feet deep), 1/4 of 1 percent of the total mesoha- line volume of the Bay. Impingement mortality is 100 percent (13). Crabs are impinged at all 3 plants. In 1976, Morgantown impinged about 281,000 crabs. From June to December 1976, Chalk Point impinged approximately 1 million crabs,* which was 3 times the commercial catch in the Patuxent and equal to the estimated sport harvest. In 1976, Calvert Cliffs impinged approximately 440,000 crabs. Mortality studies have demonstrated that crabs suffer less than 1 percent mortality from impingement (13). Thus, unless the crabs should suffer delayed mortality as a result of the impinge- ment episode (and there is no evidence of this), no impact would result from the mechanical effects of impingement. Post-impinge- ment mortalities could occur where crabs are washed into a dis- charge canal (such as at Chalk Point or Morgantown) where they are exposed to chlorinated and heated effluent. This possibility is currently being assessed at Chalk Point. The impingement rate at the Calvert Cliffs plant has changed consider- ably since the first summer of operation. During July/August 1975, several large impingement episodes of 500,000 fish or larger crushed intake screens and forced shut-down of the power plant (7). It was theorized that entrapment (explained previously), coupled with low DO caused by certain wind conditions weakened the fish, causing them to impinge in large numbers. To combat this problem, BG&E now removes four panels from the curtain wall during the summer months, allowing surface water (presumably higher in oxygen) to enter and allowing an escape route for the fish. Since this adjustment, only one large episode has occurred: during routine impingement studies at the plant on June 13, 1978, approximately 72,000 fish were collected during one hour (15). 9 Discharge Effects and Habitat Modification The thermal plume produced by Calvert Cliffs Unit 1 averaged 10 acres within the 2*C excess temperature isotherm (6). The maximum extent of this isotherm along the Bay was 2/5 mile from the point of discharge (approximately 1/10 the width of the Bay at that point). In studies of fish, plankton and benthos, no changes in community composition or abund- ance could be found which were attributable to this thermal influence. Benthic communities were altered only in about a 60-acre bottom area from which loose sediments have been swept by the high velocity dis- charge. No deleterious effects on oyster growth or mortality nor uptake of copper by oysters were observed (6). Based on extrapolation of impingement data taken during 465 half-hourly sampling periods from June through December. The utility (PEPCO) feels that a saturation effect may limit the number of crabs impinged during actual opera- tion. 111-22 The thermal plume produced by Calvert Cliffs Unit 1 and 2 combined averaged 30-40 acres within the 20C excess temperature isotherm and occasionally exceeded 60 acres in size (16). Studies to quantify any discharge effects are presently in progress. Morgantown findings are consistent with Calvert Cliffs results. The thermal plume as defined by the 2'C isotherm, was generally about 3-4 acres in size, but occasionally as great as 80 acres. No significant influence of this thermal discharge has been found (3). Temperature elevations caused by Chalk Point operations have been detected over 1 mile from the plant (17). Because the estuary is shallow and has low flows (Table 111-4), thermal influence would be experienced over greater areas than at Calvert Cliffs or Morgan- town. Despite this fact, the monitoring studies conducted in the 1960's revealed few plant effects. Erosion of copper from condenser tubes was noted, and uptake of copper discharged from the plant by oysters was found. This situation was apparently corrected later (18) Large concentrations of fish in the discharge canal have appeared in fall and winter, and the area now supports an intensive sport fishery. Large kills of fish and crabs in the discharge channel were reported.in the 1960's, attributed to accidental excessive discharge of chlorine (4,19). Similar kills have not been reported in recent years, and no detectable effects on zooplankton or ichthy- oplankton were found. Additional monitoring is currently proceeding at this plant. When results of studies at the three plants are compared, a consistent picture emerges indicating low probability of cumulative impact on the meso- haline environment. Plankton entrainment losses have been measured inside several of the power plants. These losses, however, do not show up as any measurable plankton depletion in the waters around the plant. This lack of measurable effects is probably due to the high reproduction rate of the plankton, and indicates that there is no impact due to plankton entrainment. No important commercial or recreational species spawn in this habitat, and entrainment losses of ichthyoplankton are thus of little significance. Loca- lized effects on benthic organisms, including shellfish, are sometimes evident. These effects have no significance beyond the immediate discharge areas. Tidal Freshwater/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 total monetary value of commercially harvested finfish from 1972 to 1976 in Maryland (Table 111-6). Anadromous spawning occurs in spring so the plants of most concern are those in the tidal fresh zone at that time (Table 111-2). The nine plants so located can be divided into three geographical regions. The Baltimore Plants (C.P. Crane, Gould St., Riverside, H.A. Wagner, and Westport) are located on the Patapsco River and its tributaries and on Seneca Creek. In the past, environmental degradation which is not related to 111-23 these plants has eliminated the area as an important anadramous spawning ground (20), and the area also does not serve as a major nursery area for juveniles of most important fish species. White perch is the most common fish. With the exception of Wagner and Crane, these plants are all older than 20 years, are used for peaking service, and have seen decreased service since Calvert Cliffs came on line. The Washington Area Plants (Benning Road, Buzzard Point, and Potomac) are located in the upper Potomac Estuary where chronic oxygen deficiencies have been reported (21). This decline in water quality has been reflected in a reduction in diversity and abundance of fish (22). However, if the other pollution sources should be cleaned up, and these areas became productive again, power plants should not be allowed to adversely affect the environment. Thus, assessment of the potential impact of these plants is appropriate despite the present absence of major aquatic resources nearby. The Possum Point plant is located in a segment of the Potomac River where striped bass spawn, and Douglas Point located across the river is a proposed site for a new power plant. The proposed plant, the effect of which has been extensively studied, would utilize cooling towers so that cooling water with- drawals would be small (estimated 50 cfs) (23). Another plant, Summit, has been proposed in New Castle County in Delaware on the Chesapeake and Delaware Canal, approximately two-thirds of the way towards the eastern end of the canal. This plant, as originally proposed, would use 2 cooling towers and have a total withdrawal rate of 42.5 cfs. The oligohaline zone serves as a nursery area for many estuarine fish during much of the year. Some striped bass spawning occurs in portions of this zone in the spring. The three plants using oligohaline waters for cooling in the spring are Chalk Point on the Patuxent, Morgantown on the Potomac and Vienna on the Nanticoke. The salinity Chalk Point is often on the borderline between oligohaline and mesohaline in the spring and the Morgantown site drops to within the oligohaline range on the average only during spring of each year (2). Thus, impact at Chalk Point and Morgantown were discussed under mesohaline plants, with only Morgantown ichthyoplankton entrainment and impingement mentioned here. Eight of the ten freshwater tidal plants become oligohaline during the summer-fall period (Table 111-2). 9 Entrainment Plankton entrainment data are not available for any of the present tidal freshwater plants. Studies elsewhere (see Mesohaline discussion above) indicate that entrainment losses of phytoplankton and zooplank- ton generally do not result in detectable nearfield depletions and thus would be unlikely to contribute to cumulative impact. However, at most of the present tidal fresh plants, cooling water withdrawal is large relative to freshwater and tidal flow (Table 111-4), and localized effects on plankton may occur. Entrainment losses of ichthyoplankton could cause declines in fish populations utilizing discreet spawning areas. The Baltimore and Washington areas currently do not serve as important spawning ground for any anadromous species. The abundant 111-24 species of these areas, such as white perch, are ubiquitous in the Bay (14). Losses of eggs and larvae at those plants are unlikely to cause Bay-wide declines in such ubiquitous stocks. Possum Point, how- ever, 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 bass larvae produced annually in the Potomac The exact significance of such a loss to adult fish is not currently known, but it can certainly not exceed 2 percent of the actual catch of fish spawned in the Potomac (23). If a plant using cooling towers were constructed at Douglas Point (across the Potomac from Possum Point) it would be unlikely to alter local zooplankton and phytoplankton populations through entrainment because of the small volume of water utilized. It has been estimated that such a plant would entrain between 0.6 and 1.2 percent of the striped bass larvae produced there in any one year. Such a loss could cause no more than similar percentage decline in eventual production of adults (23). The strength of the year class is usually well estab- lished by the time the striped bass spawn become juveniles (3-5 months old) and is largely dependent on environmental conditions during that period (24). The Summit plant is located in an area of some striped bass spawning, although most of the spawning takes place towards the western end of the canal. It is estimated that between 1 and 2 pecent of the entrainable striped bass ichthyoplantkon that originate in the canal will be entrained by the Summit power plant (25). Possible plant design alternatives to reduce the entrainment are still being pursued. Morgantown is located 20 km downstream of the center of the striped bass spawning area in the Potomac. Few eggs or larvae (< .01 percent) are entrained (26) and consequently, no significant impact on the striped bass population occurs because of the operation of this plant. Vienna is in the midst of the spawning area in the Nanticoke. The plant has two distinct sections: 3units 5. 6$ 7 (68 MW) using once- through cooling (withdrawal 3.6 @ /sec) and unit 8 (162 MW) using a cooling tower (withdrawal 0.12 m /sec from discharge of units 5, 6, 7). The once-through units, now scheduled for retirement in 1987, will operate below 25% capacity factor (annual average) after 1980 (27). In addition, Delmarva has propoied a 400 MW expansion (1987 completion date) that will withdraw 0.36 m /sec for cooling and plant purposes. The present plant does entrain striped bass eggs and larvae (28). but the exact magnitude and consequences of the losses are not known. To estimate the loss, we may use two simple techniques (29) involving tidal volumes and known distributions of eggs ind early larval stages. These results, for a withdrawal rate of 0.36 m /sec (about 10% capacity factor for units 5, 6, 7), give an entrainment estimate of 3-8% of the spawn in the river.* Spring capacity factors for the last 5 years have ranged between 23% (1977) to 79% (1974). The assumptions implicit in this simple calculation are probably not valid for losses greater than Implicit in this calculation are the following assumptions: 100% mortality, no recirculation, uniform entrainability for 90 days. 111-25 30%*. Nevertheless, they do show that entrainment losses at this site constitute a significant percentage of the Nanticoke spawn. Studies now underway to evaluate the impact of the new unit at Vienna will be used to establish the impact of the present units. A possible outcome of this study will be a capacity factor limitation at this site during the spawning and nursery season for striped bass. The potential impact on the overall striped bass stock can be estimated by examining the contribution of each impacted area to total spawning in the Maryland part of the Chesapeake Bay and its tributaries. These contributions can be estimated from the commercial catch records for the months (March and April) just prior to spawning. This catch is assumed to be proportional to the presence of spawning adults and hence to the spawn. This data is summarized in Table 111-7 which shows, for example, that Potomac River spawning constitutes about one fourth of total striped bass spawning in Maryland. Therefore, under our assumption, a 1 percent loss of striped bass larvae in the Potomac would translate to a 0.25 percent loss of the Maryland fisheries. The total potential loss can be assess from the size of the fishery affected. Table 111-6 shows the annual commercial striped bass catch in Maryland (the average annual sports catch is roughly equal to the commercial catch (12)). Following the reasoning above, each 1 percent loss of the striped bass larvae in the Potomac is equivalent to a loss of about 8000 lbs of striped bass. This calculation neglects the relative decline in the Potomac catch for 1964 to 1972 (Table 111-7) as well as the absolute decline in Maryland catch (Table 111-6). In addition, the Bay stock is the principal contri- butor to a large fishery in the mid-Atlantic states and New England. Impingement No impingement data are available for the the tidal-fresh plants. Since all except Possum Point are sited on waters of degraded water quality supporting limited fish populations, any impingement losses from these plants have little probability of influencing Bay resource yields. Because of the low velocity and volume of cooling water to be utilized at the proposed Douglas Point plant, magnitude of impingement there would be expected to be low and impact inconsequential (23). It is interesting to note that the majority of white perch collected (3) in Morgantown impingement samples in 1975 (Table 111-5) were taken during the single spring sampling period (March). At that time sali- nities are close to oligohaline. This species is more typically oligo- haline than mesohaline. Thus, the data substantiates the validity of examining cumulative plant impact according to habitats defined by salinity regimes. As discussed earlier, white perch populations occur in virtually all tributary estuaries of the Bay, including areas of poor water quality. Morgantown impingement kills are not expected to modify Potomac River or Bay white perch populations. No impingement data is available from Vienna. Which would occur at a capacity factor of 37-100%. 111-26 Table 111-7. Comercial catch of striped bass in March and April by region in the Maryland portion of the Chesapeake Bay, by percent 91 z 1972 8.67 30.76 4.61 S.76 10.02 2.37 2.22 15.87 19.67 1971 10.13 27.24 2.39 S.66 10.S8 0.85 4.07 MIS 25.87 1970 9.37 34.86 5.18 4.90 16.84 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 1.25 2.09 11.61 36.74 1967 9.54 29.58 1.36 3.31 7.00 0.82 2.18 11.45 34.75 1966 6.03 22.91 2.73 2.84 10.37 1.65 1.07 19.34 33.03 Averages 10.73 29.SO 2.80 4.30 9.10 1.25 2.49 12.28 27.46 Discharge and Habitat Modification The general degradation of water quality in the vicinity of the Balti- more and Washington plants (21) makes identification of plant dis- charge effects difficult. If water quality were to improve, thermal and biocide discharges of these plants would have the same potential for aquatic impact as plants in unpolluted areas. Thus, they require studies to determine appropriate measures to mitigate any adverse im- pact. (Studies at the Baltimore plants are now underway.) Possum Point cooling water enters the Potomac shortly after discharge. At the proposed Douglas Point plant, the discharge would consist of cooling tower blowdown, which could contain biocides and metals such as copper corroded from the plant cooling system, unless, as recommended, titanium tubing is used in the condenser and the blowdown is dechlorinated (30). Because of the low volume of discharge, any effects of these discharges would be restricted to the immediate area of the discharge point. Studies of the Vienna discharge during spring (31) revealed a small plume con- fined near the west bank. Over most of the region, larger temperature gradients resulted from differential solar heating than from the heated water discharge. Riverine The only Maryland steam electric stations located on rivers are R.P. Smith and Dickerson, both on the Potomac. Each utilizes, at times, a substantial portion of average river flow for cooling purposes (Table 111-4). The plants are relatively old, of low to medium generating capacity, and located in areas inhabited by typical warm water "riverine" biological communities (32). � Entrainment Riverine communities are not plankton-based. Entrainment losses of the sparse populations of plankton present have little influence on local ecosystems. No spawning of anadromous fish occurs near these plants. Most resident fish are nestbuilders having non-planktonic larvae. Significant ichthyoplankton entrainment would thus not occur. The juveniles tend to be shore oriented, not moving with the main flow of water (33). � Impingement Data are now being gathered to provide the basis for an analysis of impingement effects. � Discharge and Habitat Modification Temperature elevations in the discharge area are usually the only type of interaction of importance in assessing impact on riverine aquatic communities. Data delineating the size of the thermal plumes has been collected, but the results are not yet available. Studies to assess the significance of these elevations and to quantify their areal extent are underway at both plants. 111-28 The Conowingo Dam on the Susquehanna River is the only large hydroelectric generating station in Maryland. Large kills of anadromous clupeid fish (ale- wives, blueback, American and hickory shad) occurred at the base of the dam in the 1960's, and were accompanied by declines in the size of the annual runs of these species (34). These springtime kills of spawning fish occurred when the turbines were shut off at night, and no water passed the dam site. The cause of the morta- lity was traced to a depletion of dissolved oxygen by fish massed at the foot of the dam during spawning runs (34). No kills have occurred in recent years since an agreement between the utility and the Maryland DeDartment of Natural Resources went into effect, guaranteeing a continuous minimum flow of 5,000 cfs through the dam during the spawning season. Runs of anadromous fish in the Susquehanna below the dam have continued to decline. However, since kills have not occurred in the dam, the decline cannot be directly attributed to these kills (34,35). D. Regulatory Considerations The question of which type of cooling system should be required for existing power plants in order to ensure acceptable aquatic effects has been the subject of several State and Federal Regulations. Under the Federal Water Pollution Control Act of 1972 (FWPCA), a goal of zero heat discharge was set by Congress. The original proposed EPA regulations under this Act (March 1974) included a requirement for all "base load" steam electric stations to install closed cycle cooling (see Chapter IV) by 1978/79. Exceptions were to be granted under section 316(a) if a utility could demonstrate that closed-cycle cooling was not needed to "assure the protection and propagation of a balanced indigenous population of shellfish, fish, and wildlife in and on the body of water..." The promulgated regulations have changed the deadline to 1981 for units constructed after 1970. However, the entire issue of federal regulation has been clouded by a 1976 court decision remanding several sections of the EPA regulations that affect Maryland power plants (36). In addition, the*lack of final format for regulations, guidance manuals, and procedures has hindered initiation of studies. On the State level, the Water Resources Administration (WRA) has been delegated authority under the FWPCA to administer the National Pollutant Discharge Elimina- tion System (NPDES). Under this system, once the State has established water quality standards that are at least as strict as Federal regulations, the State may, with EPA oversight, regulate all discharges within the State. Water Re- sources Regulation 08.05.04.13 places requirements on all steam electric stations over 25 MW expected to have in 1980 an annual capacity factor over 25 percent or a summer capacity factor over 40 percent. All discharges that do not satisfy a preliminary screening test based on the ratio of the size of the thermal plume to the cooling water body and the importance of spawning in the region must either: 1) install closed cycle cooling; 2) demonstrate that the standards are unnecessarily stringent and existing conditions preserve natural water quality; or 3) demonstrate that other limitations less costly than closed cyle cooling will preserve natural water quality. The first case (Morgantown) is presently scheduled for the spring of 1979. 111-29 All steam electric stations must, under section 316(b) of the FWPCA, demonstrate best practicable technology (to minimize impact) in their in- take structure design. However, the EPA regulations for this section have also been remanded (36). Maryland Water Resources Regulation 08.05.04.13 requires evaluation of best practicable intake structure design by setting up a cost- benefit analysis approach for modifications. Here the potential conflict between Federal and State regulation is minimal. E. Conclusions and Summary of Impact Dividing the aquatic habitat into three general areas, we can draw the following conclusions: � Mesohaline Because of the high reproduction rates of the plankton and good tidal mixing at the existing plants, depletion of plankton popula- tions has not occurred. 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 sources. In addition, efforts to reduce these totals are now underway at all three existing plants. Habitat modification effects, usually more subtle in nature, have minor, loca- lized impacts as described in this chapter. Coupled together, the power plant monitoring studies show a low cumulative impact on the mesohaline environment. � Tidal Fresh/Oligohaline The major area of concern within this 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. New facilities planned for this region (Douglas Point, Summit, and Vienna) would increase withdrawals. Using Table 111-7 as a guide for the relative importance of striped bass spawning areas, the present and future entrainment levels are summarized in Table 111-8. As can be seen, the overall impact upon striped bass due to entrainment drops from an estimated 6.60 percent entrainment (upper bound) of the eggs and larvae spawning in Maryland portion of the Bay to an estimated 3.14 percent (upper bound). The addition of Douglas Point and Summit is more than off-set by the re- tirements of the once-through cooling units at Vienna. No impingement data is available at any of the present plants; however, degraded water quality at the Baltimore and Washington plants appears to have severely restricted fish populations in these waters. Similarly, habitat modifi- cation effects or depletion of plankton would be difficult to detect. Ongoing studies should help to quantify these effects at the Maryland plants. The proposed plants are expected to have no major impacts in the areas of impingement or habitat modification due to the small amount of water withdrawn. 111-30 Table 111-8. Estimated upper limit impact on striped bass ichthyoplankton power plant entrainment Power Plant River % of Md. Present to 1980 1980 to 1987 After 1987(a) Spawn in of River % of Total of River % of Total % of River % of Total River Population Md. Spawn Population Md. Spawn Population Md. Spawn Entrained Entrained Entrained Entrained Entrained Entrained Possum Pt. Potomac 28 2 0.60 2 0.60 2 0.60 Morgantown Potomac 28 0.01 <O. 01 0.01 <0.01 0.01 <0.01 Vienna Nanticoke 12 SO(b) 6.00 2S(c) 3.00 2.8(d) 0.34 8.0(e) 0.96 Douglas Pt. Potomac 28 1.20 0.34 n Summit C&D Canal 30 3 0.90 TOTAL of Md. spawn entrained 6.60 3.60 3.14 at all plants (a) Assuming Douglas Point, Summit, and Vienna unit 9 come on line (b) Assuming SO percent capacity factor on once-through cooling units (c) Assuming 25 percent capacity factor on once-through cooling units (d) Assming once-through units retired, Vienna 8 still on line (e) Vienna unit 9 Riverine No impact is expected from entrainment and impingement. Studies of possible habitat modification due to the discharge of heated effluent are now underway at both of the two existing plants in this region. These studies are expected to be completed during 1978. 111-32 REFERENCES -- CHAPTER III 1. Ecology of Estuarine Benthic Invertebrates: a perspective, pp. 77-85. M.R. Carriker. In Estuaries, Ed. by G.H. Lauff, AAAS, Washington, D.C. 1967. 2. Impact of the Morgantown Steam Electric Station on the Potomac River Estuary: An Interpretive Summary of 1972-1974 Investigations. L.H. Bongers, et al. Martin Marietta Laboratories, MT-75-6, June 1975. 3. Academy of Natural Sciences of Philadelphia, 1977. Morgantown Station and the Potomac Estuary: a 316 Environmental Demonstration. Prepared for Potomac Electric Power Company. 4. Patuxent Thermal Studies - Summary and Recommendations NRI Special Report No. 1. J.H. Mihursky, Chesapeake Biological Laboratory, University of Maryland, 20 pp. 1969 1* Plankton and Productivity in the Oceans. J.E. Raymont. Pergammon Press, New York, 660 pp. 1967 6. Martin Marietta Corporation, 1977. Summary of Current Findings: Calvert Cliffs Nuclear Power Plant Aquatic Monitoring Program. Submitted to Maryland Power Plant Siting Program. 7. Chesapeake Bay, Maryland, Routine Chemical, Physical, and Bacteriological Studies, I, for the Baltimore Gas & Electric Company, 1968. Academy of Natural Sciences of Philadelphia. October 1969. Chesapeake Bay, Maryland, Routine Chemical, Physical, and Bacteriological Studies, II, for the Baltimore Gas & Electric Company, 1969. Academy of Natural Sciences of Philadelphia. November 1970. A Chemical, Bacteriological, and Physical Study on the Chesapeake Bay in the Vicinity of Calvert Cliffs, Maryland for the Baltimore Gas & Electric Company, Februaryt 1970 - December 1970. Academy of Natural Sciences of Philadelphia. April 1972. . January 1971 - December 1971. December 1972. . January 1972 - December 1972. September 1973. . January 1973 - December 1973. December 1974. Baltimore Gas & Electric Company. Semi-Annual Environmental Monitoring Report, Calvert Cliffs Nuclear Power Plant. Prepared by BG&E and the Academy of Natural Sciences of Philadelphia. March 1975. March 1976. March 1977. Non-Radiological Environmental Monitoring Report, Calvert Cliffs Nuclear Power Plant, January - December 1977. Prepared by BG&E and the Academy of Natural Sciences of Philadelphia. March 1978. 111-33 8. Letter to Dr. R. Roig from Mr. W. Foy, PEPCO, September 22, 1978. 9. Scientific Studies at the Chalk Point Steam Electric Station, Academy of Natural Sciences of Philadelphia submitted by PEPCO to WRA as study plan under COMAR 08.05.04.13. 10. Maryland State Fisheries Administration, 1974-1975. Summary of Fish Kills. Department of Natural Resources, Annapolis, Maryland. 11. Menhaden, Sport Fish and Fishermen. C. Oviatt. University of Rhode Island, Marine Technical Report 60, 24 pp. 1977 12. 1976 Maryland Chesapeake Bay Sport Fishing Survey. H.J. Speir, D.R. Weinrich, and R.S. Early. Fisheries Administration, Maryland Department of Natural Resources, June 1977. 13. Impingement Studies II. Qualitative and quantitative survival estimates of impinged fish and crabs. D.T. Burton. In Semiannual Environmental Monitoring Report, Calvert Cliffs Nuclear Power Plant, BG&E, March 1976. 14. The Chesapeake Bay in Maryland -- An Atlas of Natural Resources. A.J. Lippson (ed). The Johns Hopkins University Press, Baltimore, Maryland, 1973. 15. Letter from Mr. J.W. Stout (BG&E) to Mr. Ray Schwartz (WRA) June 23, 1978. 16. Thermal plume studies in the vicinity of Calvert Cliffs Nuclear Power Plant. Scott Zeger. Academy of Natural Sciences of Philadelphia. No. 78-13. November 1977. 17. Personal Communication, S. Zeger, Academy of Natural Sciences of Philadelphia. 18. Greening and copper accumulation in the American oyster, Cassostrea Virginica, in the vicinity of a steam electric generating station. W.H. Roosenburg. Ches. Sci. 10:241-252, 1969.* 19. Electric Power Plant in the Coastal Zone -- Environmental Issues, American Littoral Society. J.C. Clark and W. Brownwell. Special Publ. 7, Highland, New Jersey, October 1973. 20. Johns Hopkins University, Applied Physics Laboratory, Addendum to the Brandon Shores Site Evaluation, January 1973. 21. Water Quality Conditions in the Chesapeake Bay System. T.H. Pheiffer, D.R. Donnely, and D.A. Possehl. Technical Report 55, EPA, August 1972. 22. Fishes of the Upper Anacostia River System of Maryland. A. Giraldi, and A. Dietemann. Atlantic Naturalist, 29(2):61. 1974. 111-34 See also: O'Dell, C.J., H.J. King, III, and J.P. Gabor. Survey of Anadromous Fish Spawning Areas. Federal Air Report, U.S. Department of Commission, NOAA, Fisheries Administration, Maryland Department of National Resources, Annapolis, Maryland 1973. 23. Power Plant Site Evaluation, Final Report, Douglas Point Site, Vol. 1. The Johns Hopkins University, PPSE 4-2, February 1976. 24. Impact of Potomac River Power Plants on Early Life Stages of Striped Bass - Preliminary results. T.P. Polgar. Record of the Maryland Power Plant Siting Program, Vol. 4 (3), 1975. 25. Estimates of the entrainment rates of spawn of striped bass (Morone saxatilis) in the proposed power plants at Summit and Chesapeake City. K.L. Warsh. APL/JHU PPSE-T-8, 1978. 26. Potomac Estuary Fisheries Study, Ichthyoplankton and Juvenile Investi- gations. 1974, 1975, 1976. 27. Miller, I.J. Delmarva Power and Light, personal communication. 28. Effects of Steam Electric Station operations on organisms pumped through the cooling water system. I. Macroplankton Studies, Vienna SES - 1973. Final Report-J.H. Mihursky, et al. University of Maryland, N.R.I. Ref. No. 74-75, CEES, March 1974. 29. Portner, E. APL, personal communication. 30. Joint letter of recommendation of 10/26-1976 to Mr. Thomas Hatem, Chairman, Public Service Commission from Maryland State Departments of Economic and Community Development, Transportation, Natural Resources, Public Health and Mental Hygiene, Agriculture, and State Planning. 31. The distribution of excess temperature from the Vienna Generation Station on the Nanticoke River. H.H. Carter, and R.J. Regier. Technical Report 90, Chesapeake Bay Institute, the Johns Hopkins University. 32. Johns Hopkins University, Applied Physics Laboratory, Addendum to the Power Plant Site Evaluation Report: Dickerson Site, January 1974. 33. Handbook of Freshwater Fishery Biology. Vol. 1 & 2. K.D. Carlander. Iowa State University Press, Ames, 750 pp. 1969 34. Assessment of the Effects of Hydroelectric Water Discharged from the Cono- wingo Dam on Spawning Fish in the Lower Susquehanna River. J.W. Foerster. Maryland Power Plant Siting Program. January 1976. 35. Historical Analyses of the Commercial Shad Fisheries. S.P. Reagen, and J.W. Foerster. Goucher College Pub. 12, Environmental Studies Program, 1975. 111-35 36. Appalachain Power vs Train. D.C. Court of Appeals, Fourth Circuit. 9 ERC 1033 (Environment Reporter - Cases). 37. Hydrographic and Ecological Effects of Enlargement of the Chesapeake and Delaware Canal. Final Report. Appendix XIV. D.W. Pritchard, and C.B. Gardner. Chesapeake Bay Institute. The Johns Hopkins University. Ref. 74-1. February 1974 (also published as CBI Tech. Rept. No. 85). 111-36 CHAPTER IV RADIOLOGICAL EFFECTS The first Cumulative Environmental Impact Report has presented a discussion of general siting, safety and health issues pertinent to nuclear power plants. It also presented projections of radiological impacts in Maryland, based upon the utility companies' projections for additional nuclear plants, as delineated in their 1975 Ten Year Plans. Since lq75, extensive changes have occurred in the utility companies' scheduling for new generation. In addition, the Calvert Cliffs Nuclear Power Plant has commenced operation, providing an opportunity to compare actual impact measurements with preoperational predictions. This Chapter summarizes the current planning for additional nuclear power in Maryland and focuses on the operations to date at Calvert Cliffs. The quantities of electrical energy produced, effluents released and wastes created are discussed. Results of radiological environmental monitoring activities are presented and radiation doses from plant operation are estimated. Comparisons are made, where appropriate, to regulatory limits and to predictions made prior to reactor start-up. Emphasis is placed on continued compliance with NRC guidelines for keeping radiation doses to the public "as low as reasonably achievable". Finally, radiation doses from plant operations to date are compared to variations in natural dose levels measured in Maryland, and the health risks from low level dose increments are tabulated. A. Status of Nuclear Power in Maryland The Calvert Cliffs Nuclear Power Plant, owned by the Baltimore Gas and Electric Company, is the only operating nuclear power plant in Maryland. Each of its two units has a Pressurized Water Reactor licensed at 2700 MW (thermal), with design net electrical power output of 845 MWe. Present ratings are 820 MWe for Unit 1 and 855 MWe for Unit 2 in the winter but 810 MWe for both units in the summer, when maximum discharge temperature restrictions may limit plant power (1). The Peach Bottom Atomic Generating Station, owned by Philadelphia Electric Company, is situated in Pennsylvania on the Susquehanna River, approximately 3 miles north of the Maryland border. Peach Bottom Unit 1, a 40 MWe High Tempera- ture Gas Cooled Reactor, was decommissioned in January 1975. It was originally placed in service on May 25, 1967 as a demonstration plant. During its operating lifetime, it generated more than 1 billion kilowatt hours of electrical energy (2). Peach Bottom Units.2 and 3 are both 1065 MWe Boiling Water Reactor systems. Unit 2 began commercial operation in July of 1974, and was followed by Unit 3 in December of the same year (3). According to their 1978 Ten-Year Plans filed with the Maryland Public Service Commission, none of the State's utilities now plan new nuclear units for at least the next ten years (4). The Douglas Point Nuclear Generating Station planned by IV-1 the Potomac Electric Power Company has been deferred indefinitely. PEPCO intends to retain the site and to pursue a regulatory determination of the site's suitability. The Baltimore Gas and Electric Company has deleted from its current ten- year plan the nuclear units scheduled for the Perryman site. On December 1, 1977, the staff of the Nuclear Regulatory Commission issued a report recommending that BG&E's application for an early site review and construction permit be denied on the basis that at least one other site available to the Company was superior overall to the Perryman site, particularly with respect to the safety- related issues of surrounding population density and nearby military activities (5). The Philadelphia Electric Company does not plan for any new nuclear capa- city near Maryland before the 1992-1994 time frame. The prime location is their Fulton site, in Pennsylvania directly across the Susquehanna River from Peach Bottom. Three alternative sites include two properties already owned by the Company at Chesapeake City on the C&D Canal, and Seneca Point on the Northeast River, plus the Bainbridge site, currently sought by the Power Plant Siting Program for its site land-bank. All three of these alternatives are located in Maryland. Delmarva Power and Light Company currently holds a Limited Work Authori- zation to begin construction of a nuclear plant at Summit Bridge, Delaware, on the C&D Canal three miles east of the Maryland border. Current plans do not specify the type of reactor to be used and indicate an on-line date beyond their current ten-year planning period. The Potomac Edison Company is selling its Black Oak site, but retaining its Point of Rocks site, both on the Potomac River. The Point of Rocks site was originally obtained for a nuclear plant with an ultimate capacity of 2500 Mwe. However, the Company currently has no plans to use the site. B. Operations at Calvert Cliffs Nuclear Power Plant Electrical Power Production Calvert Cliffs Unit I achieved initial criticality on October 7, 1974. Following start-up test procedures, it was placed in commercial service on May 8, 1975. Unit 2 achieved initial criticality on November 30, 1976, and was declared commercial on April 1, 1977. As of January 1, 1978, Unit 1 had produced a total of 14,778,865,000 kilowatt hours of electrical energy, and Unit 2 had produced 4,541,354,000 kilowatt hours (6). This corresponds to an average capacity factor of 75.2% for Unit 1 and 81.4% for Unit 2. The environ- mental impact calculations made by the Baltimore Gas & Electric Company and by the Atomic Energy Commission for the Calvert Cliffs Plant assumed an 80% capa- city factor, and attempted to estimate an annual discharge value that would be representative of the average over the plant's 30 year lifetime (7). In the comparisons of reported vs predicted discharges which follow, the "predicted" values given are based upon 3.42 reactor years of operation at 80% capacity factor. The reader should bear in mind that the plant produced virtually the same amount of the power assumed by the predictions for an equivalent period of time after start-up, but neither reactor has yet built-up its internal inventory IV-2 of the longer-lived radioactive materials to the levels that will be representa- tive of the average values over the lifetime of the plant. Radioactive Effluent Releases Tables IV-la and IV-lb present listings of the total reported releases from the Calvert Cliffs plant through December 31, 1977, for liquid and atmospheric pathways, respectively (8,9,10,11,12,13,14). Reported releases are derived from measured total releases or from sampling of continuous or semi-continuous low-level discharges. Also included in the tables for comparison are the release values predicted by the Atomic Energy Commission in its Final Environmental Statement before plant start-up, and the values predicted by the Baltimore Gas & Electric Company in 1976 for its "Appendix I Evaluation Report"* (15). The tabulated quantities of radionuclides released to the environment are small fractions of the releases that are allowable under the portion of the plant's operating license which limits concentrations and quantities of radio- active materials in plant effluents.** The various limitations on plant efflu- ents are summarized in Table IV-2, along with the maximum fraction of the limits actually reached in plant operations through December of 1977. In addition to the limitations on the quantities and concentrations of radionuclides in effluents, the plant is also required to keep the radiation doses to the public 1. as low as reasonably achievable". Guideline dose values delineating what the NRC considers reasonably achievable will be discussed later in the impact section of this Chapter. It has been customary for estimates of probable plant radioactivity effluents to be made prior to plant start-up, and to predict maximum dose rates which the power plant could deliver to members of the public, assuming that the plant released effluents at the predicted rate, rather than the maximum allowable rate. Two such sets of effluent predictions have been included in Tables IV-la and IV-lb. It is useful to assess the accuracy of these predictions as well as trends in the actual release rates in order to assess the level of confidence for prediction of the plant's future performance in keeping doses "as low as reasonably achievable". In general, the total quantity of radioactive material released to the water has been about one third the level predicted before startup. Total atmospheric releases, which are predominantly Xe-133, have exceeded predic- tions because the release rate of this radionuclide was underpredicted by more Appendix I to 10CFR50 established "Numerical Guides for Design Objectives and Limiting Conditions for Operation to Meet the Criterion 'As Low As Is Reasonably Achievable' for Radioactive Material in Light-Water-Cooled Power Plant Effluents". All licensed nuclear power plant owners were required to file a report with the NRC by June of 1976, demonstrating that their reactor design complied with the provisions of the Appendix I. Effluent concentrations and quantities are limited by Section 2.3 of Appendix B, Environmental Technical Specifications to the Calvert Cliffs Nuclear Power Plant Facility Operating License issued by the U.S. Nuclear Regulatory Commission. IV-3 Table IV-la. Liquid radioactive effluents cumulative to December 31, 1977 Radionuclides Total Releases AEC Prediction BG&E Prediction R@ported by BG&E (1973 Est.x 3.42) (1976 Est-x 3.42) Tritium 1110. Curies 3420. Curies 1160. Curies(a) Dissolved Noble Gases 38.9 - - other 6.14 17.1 Z.120 TOTAL llS5.04 Curies 3437.1 Curies 1162.12 Curies Na-24 0.03S6 - - Ar-41 0.000OZ39 Cr-Si 0.320 0.137 0.0000342 Mn-S4 0.104 0.205 - M-56 O.OOOS32 - - Fe-SS - 0.787 0.0000342 Fe-S9 0.371 0.171 - Co-S7 0.003Zl - - Co-S8 1.93 7.18 0.0140 Co-60 0.263 0.20S 0.0298 Kr-85m 0.000117 - Kr-87 0.000626 Kr-88 0.0000726 - - Rb-86 0.000445 0.00171 Sr-8S 0.000729 - - Sr-89 0.118 0.00410 Sr-90 0.0123 0.000137 Sr-91 0.00127 - Y-90 0.000185 - Y-91 - 0.8SS 0.0000342 Zr/Nb-9S 0.406 0.00137 Zr-97 0.00391 M-99 0.0156 0.342 0.00157 TC-99M - - 0.00168 Ru-103 0.0789 0.000479 - I;U-106 0.000639 0.000133 - Rh-103m - 0.000479 - Rh-105 - 0.0000787 - Ag-110m 0.102 Cd-109 0.00437 Sn-113 0.00264 Sn-12S - 0.0000044S Sb-124 0.00518 Sb-125 0.0103 Sb-127 - 0.00002S7 - Te-12Sm - 0.000410 - Te-127 - 0.0032S - Te-127m - 0.0032S - Te-129 0.00422 0.342 - IV-4 Table IV-1a. Liquid radioactive effluents cumulative to December 31, 1977 (Continued) Radionuclides Total Releases AEC Prediction BG&E Prediction Reported by BG&E (1973 Est.x 3.42) (1976 Est.x 3.42) Te-129m 0.342 Te-131 0.000889 Te-131m - 0.00479 - Te-132 0.000300 0.161 0.000308 1-130 - - 0.0000684 1-131 0.872 0.923 0.0332 1-132 0.00805 0.00103 1-133 0.281 - 0.019S 1-134 0.00201 - - 1-135 0.0268 - 0.00277 Xe-133 38.0 - - Xe-133m 0.242 - Xe-13S 0.523 - - Cs-L34 0.286 3.76 0.718 Cs-136 0.00781 1.27 0.229 Cs-137 0.848 0.20S 0.581 CS-138 0.006S8 - Ba-133 0.000172 - Ba-137m, - 0.239 0.44S Ba/La-140 0.233 0.00821 Ce-139 0.00206 - Ce-141 - 0.000718 - Ce-143 - 0.000106 - Ce-144 - 0.000410 - Pr-143 - 0.00OS81 - Nd-147 - 0.000233 - PW-147 - 0.0000"S - Pm-149 - 0.00171 - W-187 0.000762 - - Au-198 0.000163 U-235 0.000161 Np-239 0.038S Unidentified > 0.029S 0.000171 M .4 0.136 (a)BG&E also used the 1976 vintage NRC model which wotad have predicted a release of 1,810 curies of tritium in the 3.42 reactor-years of operation. MThis item contains "all other" releases predicted by the BG&E model. A IV-5 Table IV-1b. Airborne releases cumulative to December 31, 1977 Radionuclides Total Releases AEC Prediction BG&E Prediction(a) Reported by BG&E (1973 Est.x 3.42) C1976 Est.x 3.42) Total Noble Gases 39400..Curies 12300. Curies 28700. Curies Total Halogens .3il OASS 0.79 Particulate Gross 0 0.619 - Particulate >0.00000181 - Gross a <0.00000345 - Tritium 159. - 1160.Cb) Na-24 0.000992 - Ar-41 9.20 - Cr-Sl 0.00674 - - Mn-54 0.0494 - 0.000787 Mh-56 0.000330 Fe-59 - 0.0002S7 Co-S7 0.0000249 Co-S8 0.00634 - 0.00257 Co-60 0.0103 0.00116 Ni-6S 0.00000317 Cu-64 0.0125 Br-82 0.00107 - - Kr-85 7.94 2570.0 6500. Kr-8Sm 38.0 - 13.7 Kr-87 11.9 20.5 3.4Z Kr-88 21.4 68.4 27.4 Rb-88 1.47 - - Sr-89 0.000370 - 0.000OS47 Sr-90 0.0000147 - 0.0000103 Sr-91 0.00116 - - Zr/Nb-9S 0.00774 - - M-99 0.000271 - - EU-103 0.0013S - - Cd-109 0.00000"0 - Sn-113 0.000107 - Sn-133 0.00000436 Te-129 0.0000000805 Te-132 0.0000389 - 1-131 0.313 OASS 0.342 1-132 0.068S - 1-133 0.247 0.410 1-134 0.0231 1-135 0.189 - Xe-131m 23.1 109. 236. Xe-133 37600. 9400. 21900. Xe-133m 176. - 147. Xe-135 1SOO. 123. 68.4 Xe-138 1.28 20.S 0.00 IV-6 Table IV-1b. Airborne releases cumulative to December 31, 1977 (Continued) Radionuclides Total Releases AEC Prediction BG&E Prediction Reported by BG&E (1973 Est. x 3.42) (1976 Est. x 3.42) Cs-134 - - 0.000787 Cs-137 0.00108 - - Cs-138 0.9S16 - - Ba-133 0.00105 - - Ba/La-140 O.OOS64 - - Ce-139 0.000498 Au-198 0.00000634 NP-239 0.000292 (a)This model neglects any noble gases contributing less than 3.42 curies to this table and any iodines contributing less than 0.000342 curies to this table. (b) BG&E also used the 1976 vintage NRC model which would have predicted a release of 1,850 curies of tritium in the 3.42 reactor years of operation. IV-7 Table IV-2. Regulatory lindtations on radioactivity in Calvert Cliffs effluents 7ype of Effluent Limited Value or Equation Maximum Fraction of Limit Actually Reached Total quantity of radionuclides, 10 ci/unit/calendar quarter 0.07 excluding tritium and dissolved noble gases, in aqueous effluents Aqueous concentration for all Limits specified in 10 CFR.20, Appendix 0.000111 (tritium) radionuclides, including tritium B for concentrations in waters in un- 0.00393 (dissolved and dissolved noble gases restricted areas noble gases) 0.0244 (others) Average quarterly rate of release (Quantity of nuclide "ill) in atmospheric effluents of < 0.6 0.0763 all radionuclides except 1-131 i (3.85 k 105) (MDCi) and particulates with half-lives Where M@Pi values are defined in > 8 days Appendix B, Table II, Column 1 of 10 CFRZO H .4 Average annual rate of release (Quantity of nuclide "ill) 0.0732 010 in atmospheric effluents of 1 5 < U. Uzi all radionuclides except 1-131 i (3.85 x 10 ) (MDCi) - and particulates with half-lives Where MCDi values are defined in > 8 days Appendix B, Table II, Column 1 of 10 CFR20 Quarterly average release rate of 0.16 tj Ci/sec (1-131 equivalent) 0.0538 1-131 and particulates with half- lives > 8 days Annual average release rate of 0.08 tj Ci/sec (1-131 equivalent) 0.0719 1-131 and particulates with half- lives > 8 days than a factor of three** In order to understand the significance of differences between the predicted and reported release values, it is necessary to make comparisons for individual radionuclides or groups of radionuclides in the context of the various pathways by which they deliver radiation doses to the public. Atmospheric releases are predominantly radioactive isotopes of the inert or "noble" gases krypton and xenon. These gases do not accumulate in biota or soil, but will give a radiation dose as they blow past an individual. Xenon-133 makes up 95% of the reported airborne releases, and is averaging approximately four times the AEC's predicted release rate. Although relatively large batch releases of Xe-133 during the first half of 1977 resulted in quarterly totals two of three times greater than the average for the remainder of the operating period, it is still clear that the average release rate for the plant will exceed the AEC's predicted value by a factor of three to four. The more recent calcu- lations by BG&E assumed a Xe-133 release rate of 6,000 Ci/yr/unit which has been exceeded by 50% to 70% in operations reported to date. Since Xe-133 has only a 5.27 day half-life, production and discharge of this isotope has already reached equilibrium in the reactors, and an increase is not to be expected with increas- ing cumulative generation. Since Xe-133 is a gas produced within the fuel road during fission of uranium, it can be expected that the release rate for this isotope will vary somewhat among fuel batches, depending upon the number of imperfections in the fuel cladding. Changes in the leakage rate from the primary coolant loop could also result in future changes in atmospheric release rates for Xe-133. Except for Xe-135, reported releases of other noble gases have been near or below their predicted values. Kr-89 is the only noble gas radionuclide with a half-life long enough (10.2 years) to allow for continued build-up in the reactor over a period of years. However, reported releases of Kr-85 have been only a few thousandths of the predicted values, and it appears that the turnover of fuel, water and air in the reactors and containments will prevent future increases of the magnitude necessary to approach predicted levels. Atmospheric releases of radioactive halogens (i.e., iodines and bromines) may be bioaccumulated in the human thyroid gland through several pathways, including inhalation and absorption through the lungs, ingestion of leafy veget- ables with radiohalide deposition, and ingestion of milk containing radiohalogens bioaccumulated by cows. Because 1-131 has an 8 day half-life and constitutes the majority of radiohalogen releases, it is responsible for the majority of radio- halogen delivered doses. Releases of radioactive 1-131 were approximately one-third of the value originally predicted by the AEC, but closely approximated the values predicted later by BG&E. Releases of the other detected isotopes of iodine were not predicted, except for BG&E's prediction for 1-133. Because of their low release rates and very short half-lives, these isotopes are often neglected in impact predictions. Again, because radioactive halogen isotopes all have short half- lives (except for 1-129, which has not been predicted or detected), the reactors already should have attained their equilibrium releases rates for this group of radionuclides. As will be discussed later, this release rate is still well below allowable limits, and has not resulted in environmental dose rates of any significance. IV-9 Tritium is released from the power plant in the form of water or water vapor (HTO instead of H20) and can potentially deliver a radiation dose to the public only by inhalation, absorption through the lungs and subsequent inclusion in body fluids. Atmospheric release of tritium was not predicted by the AEC in their pre-operational calculations. However, more recent NRC dose assessment models predict atmospheric tritium release rates nearly twelve times greater than reported by BG&E for operations to date. BG&E's own recent predictions indicate a release rate more than seven times greater than they have actually reported. Since tritium has a 12.3 year half-life, reported releases might be expected to increase somewhat in the future as concentrations increase in internal plant water systems. Since internal water residence time is more important than either radioactive decay or atmospheric release rate in limiting concentrations, this increase will be less than if the equilibrium concentrations were principally controlled by radiological half-life. Quarterly release data does show a general increase in release rate with time until the last two quarters of 1977, when the rate dropped by two orders of magnitude. BG&E personnel indicate that this de- crease in reported releases occurred because of a change in the method of estimat- ing the activity discharged during purges of air in the containment buildings, rather than because of an actual change in the plant's internal concentrations or operating procedures (16). Such variability in discharge estimating procedures is one reason for the large variability in the model predictions, which are based upon earlier observations at other operating reactors. Original AEC predictions did not include estimates of the isotopic compo- sition for radioactive particulates to be released to the atmosphere. The more recent BG&E predictions do include predictions for 8 isotopes. Actual measure- ments indicate 29 different radionuclides being released in particulate form, including 6 of the 9 predicted by BG&E. Radioactive particulate releases may potentially enter the human body by deposition in lungs or on leafy vegetables, but these pathways are usually insignificant because of the small quantities of radioactive particulates actually released. Reported release rates approximate BG&E's predictions only for Sr-90 and Cs-137, the other predictions being low by factors ranging from 2.6 to 63. Of the particulate activity actually released, qO% was Rb-88, an isotope not included in the predictions. The presence of this isotope is to be expected, however, since it is produced by the radioactive decay of Kr-88 as well as directly by fission of uranium. Excluding Rb-88, the total of the other particulates released exceed the total BG&E predictions by a factor of 23. Still, the total quantity of particulate releases is quite small, amounting to less than 2 millicuries, exclusive of the Rb-88. Aqueous releases can roughly be divided into three categories: 1) dissolved noble gases, which do not participate in biological processes, 2) tritium, which does not bioaccumulate, but which does enter biological systems in the same manner as stable hydrogen, and 3) the other elements which chemically interact in both biological and inorganic processes of the environment. The quantity of radioactive noble gases dissolved in the aqueous releases was not estimated by the AEC in their original predictions for Calvert Cliffs. Since they are chemically inert and the water shields aquatic biota from radiation emitted only a short distance away, dissolved noble gases have insignificant effect in the aquatic ecosystem. Most of the dissolved gas discharge is Xe-133, but the quantity discharged to the water is only about 0.001 of the quantity of Xe-133 discharged directly to the atmosphere. IV-10 Aqueous releases to Chesapeake Bay have contained one-third of the AEC's predicted quantities of tritium. The more recent predictions by BG&E indicate that this will be the equilibrium release rate, while the newer NRC model (see footnote to Table la) indicates that the release rate will increase with time by nearly a factor of 2. The quarterly total release data are somewhat difficult to extrapolate because Unit 2 has just recently begun operation. However, it does appear that RG&E's predictions are most consistent with the data to present. If so, it indicates that tritium concentrations reach equilibrium between production and discharge within several months of commercial reactor operation, and that both the aqueous and gaseous releases of tritium will remain stable near their present values. The total of other radionuclides contained in the aqueous discharges has been about one-third the pre-start-up prediction, but is about three time greater than BG&E predicted in its Appendix I Evaluation Report, which considered rela- tively few isotopes. The radionuclides which have been reported in plant releases and are most likely to be of significance in the Chesapeake Bay ecosystem are Cr-51, Mn-54, Co-58, Co-60, Zr/Nb-95, Ru-103, Ag-110m, 1-131, Cg-134, and 1-131. Of these, only the two cesium isotopes were predicted in the proper range by the BG&E Appendix I Evaluation Report, while the others were either greatly under-pre- dicted or not included in these predictions at all. The earlier predictions by the AEC more reasonably approximate the reported releases for all these isotopes except Zr/Nb-95, Ru-103 and Ag-110m. Because the ecological portions of the impact prediction models were grossly pessimistic, however, actual measurements of these radionuclides in biota are used later in this Chapter to assess the significance of this under-prediction of releases insofar as it affects actual radiation doses to the public. Solid Radioactive Waste Low level radioactive waste shipments from the Calvert Cliffs plant during calendar year 1977 are given in Table IV-3, tabulated by the type of waste and the estimated radionuclide content. There were 19 separate shipments of radioactive wastes by truck from the Calvert Cliffs Nuclear Power plant to Barnwell, S.C. during 1977. Prior to 1977, BG&E was not required to tabulate such shipments and report them to the NRC. Spent Fuel Accumulation As of January 1, 1978, Unit 1 had refueled only once and Unit 2 not at all, giving an on-site inventory of 72 spent fuel assemblies in the storage pool@ During 1978, both Units 1 and 2 will refuel, bringing the total of spent fuel stored on site to 216 assemblies (17). To date, no spent fuel has been shipped off-site. In the spring of 1977, President Carter initiated a major change in federal policy by prohibiting the commercial reprocessing or disposal of spent nuclear reactor fuel. Although he announced plans for the federal government to begin acquiring spent fuel from utility companies for federal disposal, the time-table now specified by the Department of Energy does not anticipate that federal acquisition could begin before 1982. Permanent federal disposal sites are not expected to be available before 1988, and perhaps as late as 1993 (18). IV-11 Table IV-3. Solid wastes shipped off-site during 1977 Quantity of Wastes Type of Waste Voltune Radioactivity a. spent resin, filter sludge 3 evaporator bottoms, etc. 28.8 m 33.9 -curies b. dry compressible wastes, 3 contaminated equipment, etc. 232.0 m 0.807 curies c. irradiated components, 48.7 m3 63.6 curies control rods, etc. Composition by Radionuclides. Nuclide Total Activity Mn-54 1.75 curies Co-57 0.102 curies Co-58 9.94 curies Co-60 68.3 curies Zr-95 0.0142 curies Nb-95 0.0279 curies 1-131 1.74 curies Cs-134 4.65 curies Cs-137 10.9 curies Ba-140 0.2V curies La-140 0.385 curies IV-12 When the Calvert Cliffs plant was designed and constructed, it was assumed that spent fuel assemblies would be stored on-site for cool-down for approximately one year, followed by shipment off-site to a commercial spent fuel reprocessing plant. The spent fuel storage pool was therefore designed to hold 410 fuel assemblies, so that it could accommodate one annual discharge (72 assemblies) from each reactor plus one complete core (217 assemblies), in case it ever became necessary to empty one reactor. Under the new federal policy, the Calvert Cliffs Nuclear Power Plant would completely fill its spent fuel storage pool in 1980. Unless BG&E makes arrange- ments to store additional spent fuel on-site, this would force a shutdown of the plant. In response to this situation, BG&E has redesigned the racks which contain the spent fuel in the storage pool (19-23). The new densely-packed racks can accommodate 528 spent fuel assemblies on each of the two sides of the storage pool. On January 4, 1978, the NRC issued amendments to the Facility Operating Licenses for both units at Calvert Cliffs, allowing the new rack design to be placed in both halves of the spent fuel pool. BG&E has since changed the racks in the Unit 2 side, thus providing sufficient storage for continued operation until January of 1982. A similar substitution of racks on the Unit 1 side can be used to extend operations through September 1984, without shipping spent fuel off-site. As of January 1982, 720 assemblies are expected to be in storage. This number could increase to 1000 by 1984 if there is no shipment to a federal facility before that date. Spent fuel elements are kept at much lower temperatures in the spent fuel pool than they experienced in the reactor core. Experience has shown that even fuel rods which leaked fission products while in the reactor will cease leaking when cooled-down and transferred to the spent fuel pool. In addition, Zircoloy cladding has been demonstrated to withstand storage for many years in demineral- ized water. Consequently, the storage of additional spent fuel elements is not expected to cause any significant increase in the discharge of radioactivity in effluents from the reactor site. Safety issues investigated for spent fuel pool rack modifications include the possibility of accidently initiating a fission chain-reaction in the spent fuel pool and the consequences of accidently releasing a puff of radioactive noble gases by damaging fuel rods while they are stored in the pool (e.g., by dropping a heavy object on them). The additional risks involved in utilizing the densely-packed racks at Calvert Cliffs were found to be insignificant in investigations by BG&E (24) and the NRC (25). C. Radiological Effects Around the Calvert Cliffs Plant Site Extensive radiological sampling is conducted around the Calvert Cliffs site by both BG&E and the State. In addition, other radiological sampling activities of the State Government elsewhere in Maryland provide context for interpreting the results around Calvert Cliffs. Sampling methods used to detect atmospheric discharges from the plant in the surrounding environment include: IV-13 � Measurement of monthly external radiation dose by thermoluminescence dosimetry (TLD) techniques at multiple sites, to detect radiation doses given by noble gases. � Collection of iodine and atmospheric particulates by air pump/filter devices at several locations, with gross 0&, gross @, radiostrontium and y spectrum analyses of the samples, to detect radionuclides which may give a dose through inhalation. � Collection of precipitation, local vegetation and soils for y spectrum analysis to detect deposition of particulate effluents on crops and soils. � Collection of milk from nearest dairy for radiostrontium and y spectrum analysis to detect bioaccumulation in cows milk of radionuclides inhaled by cattle or ingested by grazing. Data reports addressing methodologies and results of these analyses have been published by the various investigators (26-37). Only the overall conclusions will be addressed here. Detection of power plant effects is complicated by two factors. First, the natural radiation in the environment is not constant. Variations in rainfall and sunspot activity, and disturbances of soils by human activities such as bulldozing and fertilizing all produce variations in the level of natural background radiation. The second complicating factor is fallout from nuclear weapons testing, which continues to deposit some of the same types of radioactive material that are re- leased by the power plant. To date, no measured doses and only one concentration of a radionuclide detected around Calvert Cliffs can reasonably be attributed to airborne releases from the power plant. Two measurements of atmospheric concentrations of radioiodine by BG&E on-site for the weeks of March 30 to April 6 and April 20 to 27, 1976 are most likely due to plant effluents (29), as radioiodine was not detected at any other location or in precipitation, in milk, or on grass. Inhalation at these measured concentrations, which averaged 0.02 and 0.01 pCi/m3 for their respective periods, could potentially result in dose rates of 0.0074 and 0.0037 mrem/week, respectively, to an infant's thyroid gland.* NRC regulations set the limit for such doses to 30 mrem/year (0-6 mrem/week average) off-site. Radioactive iodine was again detected in the atmosphere during each of the fallout periods from the Chinese nuclear weapons tests on September 26, 1976, November 17, 1976 and September 17, 1977. Only during fallout from the 1977 test did calculations based on the plant's release rate and meteorological measurements indicate that the plant could have contributed detectable quantities to any of the radioiodine concentrations measured. Plant contributions to measurements could have been as high as 10% of the measured value at an on-site location during the week of September 27 through October 4, 1977 (31). when fallout iodine was detectable at all stations. Two on-site stations also showed detectable concentrations the following week. BG&E's calculations indicate that the plant The thyroid gland of an infant will receive a greater radiation dose than the thyroid gland of an older individual who breaths air with the same concentration of radioactive iodine. Consequently, the infant thyroid gland dose calculation is the controlling parameter for compliance with standards for maximum dose to any organ of an individual in the general public. IV-14 may have contributed to these values (31). The equivalent maximum individual thyroid dose due to inhalation of these concentrations was only 0.005 mrem/week. No measurements of radioiodine in milk are attributed to Calvert Cliffs effluents. Measurable concentrations of radionuclides in atmospheric particulates, precipitation, vegetation and milk have all been attributed to fallout, rather than to the power plant. These conclusions are based upon comparisons of near- field and farfield data during the periods of fallout. Measurements of external radiation doses by TLD techniques have resulted in several instances when the BG&E operational phase data exceeded the range expected from their preoperational measurements of ambient doses. Calculations of dose based on the plants release records and meteorological data were used to aid in interpreting these differences. Typically, variations in quarterly doses during the operational phase, which are above the range expected in ambient dose, are on the order of I mrem, while calculated plant contributions are on the order of 0.001 mrem or less for the same periods (29,30,31). Since the BG&E control station In Baltimore has also exceeded its expected value by a significant margin, these occurrences have been attributed to the random fluctuations and systematic varia- tions incumbent on any TLD system used to monitor for small increases above natural dose rates. As previously discussed, release rates of Xe-133 and Xe-135 have been signif- icantly higher than predicted. Calculation of the maximum site boundary dose due to these isotopes for the first quarter of 1977, when the greatest release was reported, produces an estimate of 0.23 mrem total body dose increment and 0.62 mrem skin dose increment (36). These estimates are based on the annual average dis- persion factor to a point on the site boundary 1190 m SE of the plant. Calculations using actual meteorological data for that quarter may vary, but the accuracy is sufficient to conclude that the maximum external dose increment due to the plant's operations should be of the same order or smaller than the fluctuations in the TLD monitoring systems used for this work. These calculated dose rates, even if they continued for the entire year, are only about 5% and 6% respectively, of the NRC guidelines applicable to the plant. For additional perspective, it should be noted that the State's TLD data at Calvert Cliffs and elsewhere have shown over the past two years that the external dose rate near the power plant, including whatever increment is being contributed by the plant, is among the lowest in Maryland (36): about 55 mrem/ year compared to a value of 95 mrem/year tabulated by EPA as the Maryland aver- age (41). Moving from the Calvert Cliffs area to the Baltimore area can be expected to increase the annual dose rate by an average of 24 mrem/year. Moving from a wooden frame house to a stone house may add 14 mrem/year. Even the variation of soil composition among sites within the Calvert Cliffs area has been shown to account for differences of 30 mrem/year. Consequently, the dose incre- ments from the Calvert Cliffs airborne releases are not considered significant in the context of normal human activities. Sampling activities used to address the radiological impact of Calvert Cliffs in the aquatic ecosystem of Chesapeake Bay include sampling water, sediment, and aquatic biota, both edible and forage species. IV-15 Discharges of radionuclides to the Bay were predicted to occur only through the cooling water discharge conduit (see Figure IV-1). However, sampling of storm water runoff and the sand below the storm water outfall pipe 002 have revealed that minor amounts of radioactivity are also being discharged by this path (37). At least two discrete incidents (38,39) reported by BG&E to the Maryland Water Resources Administration have been responsible for discharges of radioactive material from this outfall. Continued discharge of barely detectable radioactivity may be due either to continued flushing of contamination caused by these two incidents, or by some other source. Isotopes associated with this discharge include Co-60, Co-58, Mn-54, Cs-134, and Cs-137. Sampling of shorezone fishes, oysters and sediments in close proximity to this outfall has indicated that the radioactivity discharged from the storm drain has probably not made any detectable contribution to radionuclide concentrations in the Bay. This is due in part to the (assumed) small quantity of radionuclides discharged, but also, in large degree, it is due to the rapid dispersion of effluents once they cross the beach and enter Chesapeake Bay. This finding, that some radioactivity may be discharged into stormdrains, should be carefully considered when evaluating other nuclear power plant designs which may be proposed for sites where storm water runoff enters creeks or other natural water bodies with poor natural flushing. Radionuclides discharged through the cooling water conduit at Calvert Cliffs have been detected in sediments, oysters and crabs (31,32,33,35,37). Although fallout contributions have also been detected, especially in shore zone fishes, the plant's contribution can be ascertained by the near-field/far-field distribu- tion or, in the case of Co-58 and Ag-110m, the additional fact that these isotopes were not detected in recent atmospheric fallout samples. Table IV-4 presents a list of the maximum concentrations of radionuclides which have been detected in various media and attributed to the power plant's discharges. Of the items listed, it can be seen that Ag-110m has accumulated in the greatest concentrations. This finding was somewhat surprising because discharges of Ag-110m had not been included in the plant's predicted releases nor reported in the plant's effluents prior to the time that the geographic correlation of Ag-110m concentrations in oysters with distance from the plant's cooling water discharge location lead to the conclusion that this radionuclide was coming from the plant. However, Ag-110m had previously been detected in effluents from other nuclear plants, and NRC models current in the summer of 1977 were predicting Ag-110m. discharges. The discrepancy between field data and release reports was resolved when it was discovered that an error in BG&Els computerized effluent analysis routine caused AG-110m to be mis- identified as Zr-97. Zr-97 (probably actually Ag-110m) was first reported released by the plant in the first quarter of 1976. Ag-110m was first detected in oysters near Calvert Cliffs in the fourth quarter of 1976. By the summer of 1977, the concentration of Ag-110m. in oysters near the plant had reached its maximum value to date. While the nearfield concentrations in oysters remained essentially unchanged, Ag-110m reached detectable levels in sediments near the plant and also in oysters near Kenwood Beach, some 6 miles away, by the winter of 1977-78. At this point, it is not yet possible to predict equilibrium concentrations and distri- butions for the life of the power plant. Ag-110m has a 253 day radiological half- life. Biological turnover in biota and physical movements of water and sediment can be expected to produce a shorter effective half-life for media near the plant's discharge. This may be the case insofar as the Ag-110m concentration in oysters there has remained relatively stable for three quarters, whereas the concentrations could be expected to continue to rise for a period of a few years if radioactive IV-16 0 UTFA LL 001 COOLING WATER 0 UTFALL 002 DISCHARGE POINT STORM WATER DISCHARGE -001 110> 100, .001 I NTA KE REACTORS CURTAIN WALL TURBINE BUILDING Approx. 500 ft Figure IV-1. Locations of radionuclide discharges into.Chesapeake Bay IV-17 Table IV-4- t4aximum concentrations of radionuclides attributed to plant operation* in various environ- mental media Radionuclide Concentration Wdia Ag-110m Co-S8 Co-60 Units Estuarine Biota Oysters 620 � 20 6 S 3 1 pCi/Kg � 1.96a (wet) Crab Meat 14 � ' -8 pCi/Kg � 1.96a (wet) Shell 72 � 7 is 5 pCi/Kg � 1.96a (dry) Fishes Estuarine Sediments Sand (5 � 7) 17 � 5 18 � 6 pCi/Kg � 1.96a (dry) Clay 31 � 10 60 � 7 53 � 10 pCi/Kg � 1.96a (dry) IL co Beach Sand Discharge 002 Area 12 � 4 53 � 4 pCi/Kg � 1.96a (dry) Other Areas pCi/Kg � 1.96a (dry) The radionuclides Zr-9S. Nb-9S, Ra-102, Ru-106 have also been detected in these media. Although documented as constituents of plant releases they are also fallout products. Levels in the plant area are not significantly different from control area concentrations, thus any plant contribution to the existing fallout-contributed level is unassessable. Such possible contributions have been neglected here as insignificant contributers to total impact. Eli decay were the only operable removal mechanism. However, variations in the plant's discharge rate and seasonal fluctuations make such treatments of the data very speculative at this time. A program has been started in which uncontaminated oyster stock is placed directly in the Calvert Cliffs effluent for various periods of time to provide a properly controlled experiment for the evaluation of these various effects. Figure IV-2a and IV-2b demonstrate that Ag-110m has become the predominant radioisotope in oysters near the power plant discharge. However, the dose received by an individual eating these oysters is quite small. An adult would receive a dose of 0.000009 mrem to the whole body and 0.006 mrem to the gastrointestinal tract by eating one dozen "select" (large) oysters with a Ag-110m concentration of 500 pCi/Kg.* When computing doses to the "maximum exposed individual", the NRC's Regula- tory Guide 1.109 (40) recommends an assumption, in lieu of more specific data, that an adult will eat 5 kg of seafood other than fish, each year. Five kilograms of oysters corresponds to about 24 dozen "select" or 29 dozen "standard" oysters. Five kilograms of crab meat corresponds to about 15 dozen medium crabs. Rather than arbitrarily divide the assumed 5 kg intake between crabs and oysters, Table IV-5 gives the doses that individuals of various ages would receive if they ate 5 kg of oysters and 5 kg of crab meat that contained the radionuclide concentra- tions given in Table IV-4 as the maximum contributions yet detected from the power plant. None of these doses is considered significant in comparison with the fluc- tuations created in an individual's natural dose rate by routine human activities, as was discussed in the section on impacts of the airborne effluents. For purposes of absolute risk evaluation, it has been customary to assume that any incremental radiation dose, no matter how small, increases the risk of certain biological disorders, including cancers, thyroid nodules and genetic defects Ln progeny. Table IV-6 gives the assumed incremental risk of each effect due to I mrem of dose to the appropriate organ (41). In this context, an individual who lived for a year at the site boundary where the maximum dose rate occurs and who ate 5 kg of oysters and 5 kg of crabs from the plant discharge area would expose himself to an additional risk of about one in three million that the nuclear power plant's effluents would induce a biological disorder in him, and an additional risk of about one in five hundred million that it would cause a serious genetic effect in his progeny. Such additional risk levels are miniscule compared to the normal risk levels (43) associated with the same effects in the U.S. population today. D. Conclusions Although the Calvert Cliffs Nuclear Power Plant is reporting releases to the atmosphere which are several times greater than originally predicted, and although the reported aqueous releases of the more important radionuclides are greater than BG&E predicted when demonstrating compliance with NRC's design bases dose values, it is still concluded that operations of the plant to date have resulted The value of 500 pCi/kg is used for illustration because it is a reasonable approximation of the concentrations in oysters in the plant vicinity, where values ranged from 620 pCi/kg directly in the discharge plume, to 420 pCi/kg at Camp Canoy. IV-19 ................ ............ .............. ............. .............. ..................... .................. U,K X-RAYS Ag-110. PEAKS Pb-212(Th) K-40 W!" ANNIHILAMON RADIATION Ag-110M ............. ............. (239 KOV) (511 KOV) (657 K*V) (884K*V) (1461 KeV) Figure IV-2. (A) Gamma spectron of oysters from Calvert Cliffs Nuclear Power Plant discharge area showing effluent radionuclide bioaccumulation m U.K X-RAYS K-40 Pb-212 (TIO ANNIHILATION RADIATION .... .......... .. (239KGV) (511 KOV) (1461 KeV) Figure IV-2. (B) Gama spectrLun of oysters from Kenwood Beach area showing only natural radioactivity IV-20 Table IV- 5. Dose commitment (a) due to Calvert Cliffs Nuclear Power Plant effluents for an individual who takes all his seafood from the plant vicinity (assumes radionuclide concentrations given in Table IV-4). Age Group Adult Teen Child Consumption: Oysters 5.0 Xg/yr 3.8 Kg/yr 1.7 Kq/yr (29 dozen) (22 dozen) (10 dozen) Crabs 5.0 Kg/yr 3.8 Kg/yr 1.7 Xg/yr (15 dozen) (11 dozen) (S do--an) Total Body Dose: CO-S8 0.0000543 mrem/yr 0.0000553 mrem/yr 0.0000609 narem/yr Co-60 0.0000708 0.0000722 0.0000796 Ag-110= 0.000279 0.000284 0.000314 Total 0.00040 0.00041 0.00045 Bone Dose. Co-58 (b) (b) (b) Co-60 (b) (b) (b) Ag-110m 0.000507 0.000494 .0.000581 Total 0.00051 0.00049 0.00058 Liver Dose: CO-58 0.0000242 0.0000240 0.0000119 Co-60 0.0000321 0.0000320 0.0000270 Ag-110m 0.000469 0.000467 0.000392 Total 0.00053 0.00052 0.00043 Kidney Dose: CO-58 (b) (b) (b) Co-60 (b) (b) (b) Ag-110m 0.000922 0.000891 0.000731 Total 0.00092 0.00089 0.00073 GI Tract Dose: Co-58 0.000491 0.000331 0.000116 Co-60 0.000603 0.000417 O.OOQ149 Ag-IlOm 0.191 0.131 0.0467 Total 0.19 0.13 0.047 (a) The dose commitment from ingestion of a given quantity of a radionuclide is the total dose that will be rece--Ved by the individual before the radioactive mate--_,al. is lost from the body by excretion and/or radioactive decay. (b) Dose/concentration conversion factors not available. IV-21 Table IV-6. Dose-risk conversion factors Incremental probability of a particular health effect caused by radiation dose: 9 1 chance in 5,000,000 per mrem total body does for fatal cancer. e 1 chance in 5,000,000 per mrem. total body does for non-fatal cancer. e 1 chance in 250, 000, 000 (a) per mrem gonadal dose for serious genetic effect in progeny 9 1 chance in 17,000,000 per mrem thyroid dose for thyroid cancer(b) e 1 chance in 4,000,000 per mrem thyroid dose for benign thyroid nodule(c) * 1 chance in 25,000,000 per mrem lung dose for fatal lung cancer (a) Gonadal dose risk is established on the basis of a continuous annual exposure rate for a 50 year generation time. The value given here is based upon 1/50 of the estimated value for the continuous 50 year expo- sure. That value is 200 effects/yr for 106 person-rem annual exposure in the U.S. population with a 50 year generation time. (b) Usually not fatal. (c) The absolute risk level for benign thyroid nodule incidence was not given in reference 41, but is computed here as the risk of thyroid cancer given by reference 41 times the ratio of benign-to-cancerous radiogenically-induced thyroid growths given in Reference 42. IV-22 In dosee to maximally exposed individuals which are well within the guidelines established by the NRC. These guidelines are given in Table IV-7, along with estimates of the fraction of the guidelines values which the plant has actually contributed. Predictions regarding future release rates and environmental concentrations of radionuclides produced by Calvert Cliffs are difficult to make with accuracy, given the present state of predictive models and the short period of actual plant operations available for model tuning. However, in view of the very small fractions of the "as low as reasonably achievable" dose guideline values now resulting from plant operations, and with the absence of any visible trends of increasing radio- nuclide release rates, it appears that the Calvert Cliffs Nuclear Power Plant should continue to operate well within applicable standards. IV-23 Table IV-7. Comparison of Calvert Cliffs radiological impact estimates with NRC guideline dose value Type of Dose Appendix (A) Fraction Given by Point of Dose Design Objectives Caivert Cliffs Evaluation (2 Units) Liouid Effluents Dose to whole '.ody 3 mrem/yr per unit (0.007%) Location of the highest from. all pathways dose offsite.(b) Dose to any orMn 10 mrem/yr per unit (0.461) same as above. from all pat ays Gaseous Effluents(r-) Gamma dose in air 10 mrad/yr per unit (2.5%) Location of the highest dose offaite.(d) Beta dose in air 20 mrad/yr per unit (3.4%) Same as above. Dose to whole body 5 mrem/yr per unit (<50 Location of the highest of an individual dose offsite.(b) Dose to skin of an 15 mrem/yr per unit (0.8%) Same as above. individual Radioiodines and Particulateb(e)Released to the Atmosphere Dose to any organ 15 mrem/yr per unit Location of the highest from all pathways dose offsite.(f) (a) Evaluated for a maximum exposed individual. (b) Evaluated at a location that is anticipated to be occupied during plant lifetime or evaluated 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 tho term of plant operation. (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 babis of existing conditions ?knd if potential changes in land and water usage and food pathways could result in exposures in excess of the guide- line values given above,,the applicant should provide reasonable assurance that a monitoring and surveillance program will be performed to determine 1 (1) tbe quantities of radioactive iodine actually released to the atmosphere and - . deposited relative to those estimated in the determination of design objectivesl (2) whsther changes in land and water usage and food pathways which would result in intlividual exposures greater than origina ly estimated have occurred.; and (3) the content of radioactive iodine in foods involved in the changes, if they occur. REFERENCES -- CHAPTER IV 1. Personal communication from Mr. Lee Russel to Dr. Steven Long, June 1978. 2. Nuclear Industry, October 1974, Vol. 21, No. 10, p. 25-26. 3. Nuclear Newsq Mid-February 1978, Vol. 21, No. 3, p. 57. 4. "1978 Ten-Year Plan of Maryland Electric Utilities, Possible and Proposed Power Plants, 1978 through 1987", Public Service Commission of Maryland, Baltimore, Maryland. 5. "Evaluation of Alternative Sites - Perryman, Early Site Review", U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor Regulation, November 1977. 6. "December 1977 Operation Status Report for Calvert Cliffs No. I Unit, (Docket 50-317) and Calvert Cliffs No. 2 Unit, (Docket 50-318)", Baltimore Gas & Electric Company, Baltimore, Maryland, January 9, 1978. 7. "Final Environmental Statement related to the operation of Calvert Cliffs Nuclear Power Plant Units 1 and 2", Dockets Nos. 50-317 and 50-318, U.S. Atomic Energy Commission, Directorate of Licensing, April 1973. 8. "Baltimore Gas & Electric Company Calvert Cliffs Unit I Semi-Annual Report No. 1, Oct. 7, 1974 - Dec. 31, 1974", Baltimore Gas & Electric Company, Baltimore, Maryland, February 27, 1975. 9. "Baltimore Gas & Electric Company Calvert Cliffs Unit 1 Semi-Annual Report No. 2. Jan. 1. 1975 - June 30, 1975", Baltimore Gas & Electric Company, Baltimore, Maryland. 10. "Calvert Cliffs Nuclear Power Plant Docket No. 50-317 Semi-Annual Effluent Release Report", Baltimore Gas & Electric Company, Baltimore, Maryland, February 9, 1976. 11. "Calvert Cliffs Nuclear Power Plant Docket No. 50-317 Semi-Annual Effluent Release Report", Baltimore Gas & Electric Company, Baltimore, Maryland, August 9, 1976. 12. "Calvert Cliffs Nuclear Power Plant Docket Nos. 50-317 and 50-318 Semi- Annual Effluent Release Report", Baltimore Gas & Electric Company, Baltimore, Maryland, February 23, 1977. 13. "Calvert Cliffs Nuclear Power Plant Docket Nos. 50-317 and 50-318 Semi- Annual Effluent Release Report". Baltimore Gas & Electric Company, Baltimore, Maryland, August 29, 1977. 14. "Calvert Cliffs Nuclear Power Plant Docket Nos. 50-317 and 50-318 Semi- Annual Effluent Release Report", Baltimore Gas,& Electric Company, Baltimore, Maryland, February 24, 1978. IV-25 15. "Appendix I Evaluation Report Calvert Cliffs Nuclear Power Plant", TERA Corportion, Berkeley, California, October 1, 1976. 16. Personal communication from Mr. Peter Crinigan to Dr. Steven Long. 17. "March 1978 Operation Status Report for Calvert Cliffs No. 1 Unit, (Docket 50-317) and Calvert Cliffs No. 2 Unit, (Docket 50-318)", Baltimore Gas & Electric Company, Baltimore, Maryland, April 10, 1978. 18. "The Department of Energy's Spent Fuel Storage Program", M. J. Lawrence, U.S. Department of Energy, speech presented to American Nuclear Society National Conference, San Diego, California, June 19, 1978. 19. Letter from A.E. Lundvall, Jr., Vice President - Supply, Baltimore Gas & Electric Company, to E.G. Case, Acting Director, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, regarding Spent Fuel Pool Modifications, Request for Amendment to Operating License, August 5, 1977. 20. "Baltimore Gas & Electric Company Docket No. 50-317 Calvert Cliffs Unit No. I Amendment to Facility Operating License, Amendment No. 27, License No. DPR-53 and "Baltimore Gas & Electric Company Docket No. 50-318 Calvert Cliffs Unit No. 2 Amendment to Facility Operating License, Amendment No. 12, License No. DPR-69", U.S. Nuclear Regulatory Commission, January 4, 1978. 21. "Environmental Impact Appraisal By the Office of Nuclear Reactor Regulation Relating to Modification of the Spent Fuel Pool, Baltimore Gas & Electric Company Calvert Cliffs Nuclear Power Plant Unit Nos. 1 and 2", U.S. Nuclear Regulatory Commission, January 4, 1978. 22. "Behavior of Spent Nuclear Fuel in Water Pool Storage", A.B. Johnson, Jr., Battelle Pacific Northwest Laboratories, Richland, Washington, BNWL-2256 (UC-70), September 1977. 23. "Corrosion of Materials in Spent Fuel Storage Pools", J.R. Weeks, Brookhaven National Laboratory, Upton, New York, BNL-NUREG-23021, July 1977. 24. "Baltimore Gas & Electric Company Licensing Report, Calvert Cliffs Nuclear Power Plant Unit 2 Spent Fuel Storage Rack Modification", J.D. Gilevest, Nuclear Services Corporation, NSC-BGE-0101-ROO1, Rev. 1, July 25, 1977. 25. "Safety Evaluation by the Office of Nuclear Reactor Regulation Supporting Amendment Nos. 27 and 12 to License Nos. DPR-53 and DPR-69 Relating to Modification of the Spent Fuel Pool, Baltimore Gas & Electric Company Calvert Cliffs Nuclear Power Plant Unit Nos. 1 and 2", U.S. Nuclear Regulatory Commission, January 4, 1978. 26. "Semi-Annual Environmental Monitoring Report Calvert Cliffs Nuclear Power Plant", Baltimore Gas & Electric Company, Baltimore, Maryland, March 1975. 27. "Radiological Environmental Monitoring Program Semi-Annual Report for the Calvert Cliffs Nuclear Power Plant, January 1 - June 30, 1975", Baltimore Gas & Electric Company, Baltimore, Maryland, and Radiation Management Corporation$ Philadelphia, PA, RMC-TR-75-11, September 1975. IV-26 28. "Semi-Annual Environmental Monitoring Report Calvert Cliffs Nuclear Power Plant", Baltimore Gas & Electric Company, Baltimore, Maryland, March 1976. 29. "Semi-Annual Environmental Monitoring Report Calvert Cliffs Nuclear Power Plant", Baltimore Gas & Electric Company, Baltimore, Maryland, September 1976. 30. "Radiological Environmental Monitoring Program, Semi-Annual Report for the Calvert Cliffs Nuclear Power Plant, July 1 - December 31, 1978", Baltimore Gas & Electric Company, Baltimore, Maryland, and Radiation Management Corporation, Philadelphia, PA, RMC-TP-77-07, March 1977. 31. "Radiological Environmental Monitoring Program Annual Report for the Calvert Cliffs Nuclear Power Plant Units 1 and 2, January 1 - December 31, 1977", Baltimore Gas & Electric Company, Baltimore, Maryland, March 1978. 32. "Calvert Cliffs Nuclear Power Plant Units 1 and 2 License Nos. DPR-53 and DPR-69 Non-routine Radiological Environmental Operating Report", Baltimore Gas & Electric Company, Baltimore, Maryland, September 29, 1977. 33. "Calvert Cliffs Nuclear Power Plant Units I and 2 License Nos. DPR-53 and DPR-69 Non-routine Radiological Environmental Operating Report", Baltimore Gas & Electric Company, Baltimore, Maryland, January 24, 1978 and errata to same, January 27, 1978. 34. "State of Maryland Environmental Radioactivity Monitoring Program" Quarterly Reports, Fourth Quarter 1975 through Second Quarter, 1977, Division of Radiation Control, Maryland Department of Health and Mental Hygiene, Baltimore, Maryland. 35. Unpublished radioactivity monitoring program data, Division of Radiation Control, Maryland Department of Health and Mental Hygiene, Baltimore, Maryland. 36. "Ambient Radiation Levels in the Vicinity of the Calvert Cliffs Nuclear Power Plant as Determined by Thermoluminescence Dosimetry, April 1976 Through March 1978", R.I. McLean and S.M. Long, Maryland Power Plant Siting Program, Annapolis, Maryland, PPSP-R-2, June 1978. 37. "Gamma-Ray Emitting Radionuclide Concentrations in Selected Environmental Media from the Vicinity of the Calvert Cliffs Nuclear Power Plant (August 1975 - May 1978)", R.I. McLean and S.M. Long, Maryland Power Plant Siting Program, Annapolis, Maryland, PPSP-R-3, May 1978. 38, Letter from Mr. R.M. Douglas to Mr. Ray Schwartz, reporting unscheduled discharge at outfall 002 in accordance with Maryland State Discharge Permit 74-DP-0187A (NPDES MD. 0002399) for the Calvert Cliffs Nuclear Power Plant, December 21, 1977. 39. Letter from Mr. R.M. Douglas to Mr. Ray Schwartz, reporting unscheduled discharge at outfall 002 in accordance with Maryland State Discharge Permit 74-DP-0187A (NPDES MD. 0002399) for the Calvert Cliffs Nuclear Power Plant March 31, 1978. IV-27 40. "Regulatory Guide 1.109 Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents from the Purpose of Evaluating Compliance with 10 CFR50, Appendix I, Revision I", Office of Standards Development, U.S. Nuclear Regulatory Commission, Washington, D.C., October 1977. 41. "Radiological Quality of the Environment in the United States, 1977", Office of Radiation Programs, U.S. Environmental Protection Agency, Washington, D.C. EPA 50/1-77-009, September 1977. 42. "Radiation-Associated Thyroid Carcinoma", edited by L.J. Degroo t, Grune & Stratton Inc., New York, 1977. 43. Power Plant Cumulative Environmental Impact Report. Maryland Power Plant Siting Program PPSP-CEIR-1, September 1975. IV-28 CHAPTER V 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: e population, housing and school enrollment 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 or 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. Both workers who relocate within the area and commuters can potentially exceed the capacity of the public and private services, facilities, markets, and institutions -- the local social and economic infra- structure -- which serve a given community, county, or region. The scale of socio-economic effects from construction depends on the nature of the region where construction occurs, as well as on the relative proportions of commuters, residents and relocating workers employed on the project. There is a paucity of actual monitoring data or before and after comparison studies for the socio-economic effects of power plant development. In Mary- land, the Power Plant Siting Program has studied the effects of construction of the Calvert Cliffs nuclear power station (1).* More recently, the program has developed a model for estimating the socio-economic effects of power plant development (2), and has used the model to estimate these effects for four Eastern Shore counties (3). A. Employment The driving force for socio-economic effects is the large labor force necessary for the construction of a modern power plant. It has been estimated that at the peak of construction activity, some 3,200 workers would be in- volved in the construction of a two-unit, 2,400-MW nuclear power plant, and 800 for a two-unit, 1,200-MW coal-fired plant (3). While construction The Calvert Cliffs study is strictly an ex post study. It does not provide baseline data, and does not attempt to separate out the effects caused by other simultaneous local or national developments. V-1 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, which leads to further increases in local business activity, employ- ment and income. It is the sum of these employment gains -- direct construction labor plus the additional employment induced by the increase in local business activitv -- which is the principle driving force for the local effects brought on by power plant construction. Figure V-1 shows the number of workers involved in the construction of a 2,400 W nuclear or 1,200 MW coal-fired power plant over the life of the con- struction project, assuming a nine year construction schedule*. The employ- ment profiles include both workers directly involved in construction and workers employed by firms which supply materials and services to the construction pro- ject. The profiles in Figure V-1 show two important characteristics. First, employment is not uniform over the construction period. As a result, the effects tend to be at their greatest during the middle years of construction, and generally diminish by the time the power plant enters service. Second, for these examples peak construction employment for a fossil-fueled plant is much lower than for a nuclear plant -- only 25% for the plant sizes shown here. In addition, employment for a fossil fuel plant is relatively uniform for a period of several years, and does not show the sharp employment peak characte- ristic of the nuclear case. As a result, the socio-economic effects which result from fossil fuel construction tend to be much less than those from nuclear plant construction, and are more uniform over time. The scale of the effects that these employment changes have on local social and economic conditions depends primarily on the ability of the local region or county to provide workers from its own population, and on the ability to absorb the new workers who decide to move in during the construction period. Both the ability to provide workers and to absorb a rapidly increased population are a function of the existing population base and the size and integration of the local economy. A large, urbanized county would experience little nega- tive socio-economic impact from a large construction project because the labor force available from its large population reduces significantly the number of workers who must be hired from outside of the county, and its large population and substantial wholesale and retail business sector are able to absorb the new workers who do move into the county and meet the demand for goods and services which they create. By contrast, the small work force, population, and economy typical of many of Maryland's smaller rural counties are less able to absorb the changes that accompany a large construction project. This construction schedule was selected even though it is likely to repre- sent a more rapid construction timetable than a utility of the size assumed in the Eastern Shore study (3) is likely to consider. The purpose of the rapid construction assumption was to provide estimates which would be unlikely to under-state the amount of stress which the affected communities would exper- ience. v-2 5000- NUCLEAR 4000- Z 3000 - W jai 2000- FOSSIL FUEL 1000- 100 00 000 too 00 0000 goo ft* 00 YEAR YEAR Yt@R YEAR YEAR YEAR YEAR YEAR 'YEAR 1 2 3 4 5 6 7 8 9 Figure V-1. Total employment profiles for electric power plant construction 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 socio-economic effects which may result from large construc- tion projects are mitigated by their relative proximity to larger labor force concentrations and urban centers. The disruption found in some Western coal and energy development areas where virtually the entire work force was forced to migrate to the construction site is not likely to occur in Maryland. While such large-scale changes are not likely to occur, some migration effects are possible for some of the rural counties. In a rural or semi-rural area, much of the skilled labor force required for power plant construction comes from outside the local economy, although some local workers have appropriate skills and are able to obtain construc- tion jobs on the plant. Most of the local. workers who obtain construction jobs are semi-skilled and unskilled workers (3). Since construction jobs for all classes of workers traditionally have high wage levels, these jobs provide an opportunity for local workers to significantly increase their income. In Calvert County, farm laborers were able to triple their earnings by working on the construction of the Calvert Cliffs plant, where the lowest construction wage was $6.50 per hour (1). As a consequence of these higher wages, some local firms and farms found it difficult to find workers or found workers available only at higher wages than were traditionally paid. In the extreme, some firms dependent on low-wage labor were reportedly forced out of business (1). The total effect of power plant construction on the local labor market results from both the demand for workers at the plant site, and the increase in the number of new jobs created by the increased demand for goods and services. Table V-1 shows the predicted size of this impact for the case of the construction of a nuclear plant in four Eastern Shore counties (3). Line 5 shows the estimated increase in the number of additional local workers hired from the current population in the peak year, which is shown as the percentage of current resident employment in Line 6. Line 7 shows the total number of additional workers residing in the county (current residents plus workers who move to the county as a result of the new job opportunities), shown as a percentage of current resident employment in Line 8. The effects caused by construction period employment changes are more complex than the numbers shown in Table V-1 would appear to indicate. As can be seen from the data in the table, there is a great deal of variation in the employment effects that can be expected from the construction of a power plant in different counties within the same relatively small region. The size of the total change in county employment is influenced by the amount of induced employment which occurs within the county itself. The closer the plant site is to a major metropolitan area, the larger will be the number of these induced Jobs which will occur in other counties, as can be seen in the differences in in-migration between Kent and Dorchester Counties. The reduction in the local share of these induced jobs is largely due to the reduction in the proportion of workers who find it desirable to eliminate commuting time by moving into the project county, and to the convenience with which both contractors and workers can purchase goods and services outside the project area. V-4 M M M M Table V-1. Employment effects -- Four Eastern Shore Counties Kent Queen Annes: Dorchester Wicomico County County County County Baseline County Employment, Total 6,845 7J.085 13,960 23)395 Increase in County Employment, Total., Peak Year 4,90S 4,770 4,895 5,616 Increase in County Employment, Total, Peak Year, % 71.7% 67.3% 3S.1% 24.0% Baseline County Employment, Current Residents 6V368 79378 12,160 223,647 Increase in County Employment, Current Residents., Peak Year li'lls 999 1.110S 1P882 Increase in County Employment, Current Residents, % 17.5% 13.5% 9.1% 8.3% Increase in County Etm)loyment. Current Residents and In-niigrants, Peak Year 1,937 1,671 2,188 3,092 Increase in County Employment, Current Residents and In-migrants, Peak Year 30.4% 22.6% 18.0% 24.0% Similarly, the data in Table V-1 reflect the fact that the further the project is from a metropolitan area, the larger the number of workers who elect to move into the project area, and the larger the proportion of local workers likely to be hired for the project. While the number of workers moving into the area is the major source of population effects, it is the number of local workers hired for the project that results in local employment effects. In the three counties closest to metropolitan areas, the number of local workers hired as a direct or indirect result of construction is lowest. However, the base work force in two of these counties (Kent and Queen Annes) is small enough that this change represents a significant shift in the local labor market, and is likely to have significant effects. By contrast, the largest numerical change in the local labor force in Table V-1 occurs in the largest of the four counties, Wicomico, where the relatively large and growing labor force is likely to be able to provide the additional workers over the five year period leading up to the peak with little noticeable change in local labor market conditions. B. Population Table V-2 shows the predicted increase in county and nearby municipal populations at the peak construction year for each of the four Eastern Shore counties (3). The largest population increases occur in the counties which are furthest from the population centers of Baltimore, Washington, and Wilmington. The effect of this population change is determined less by the absolute size of the increase than by the size of that increase relative to the existing local population. Localities with larger population bases tend to possess more developed infrastructures. An influx of new residents into these larger communities is less likely to affect existing social patterns because the size of the population change is relatively small and therefore more readily absorbable, and because the more developed infrastructure is less likely to be subject to increased crowding and inconvenience that can lead to increased social stress. The effect of the population changes predicted in the Eastern Shore study (see Table V-2) was estimated to be greater in Kent and Queen Annes Counties, whose major communities (Chestertown and Centreville, respectively) are relatively small. By contrast, the larger population base of Wicomico County would experience only slight effects over the same five-year period. The estimates of the effects of the population changes shown in Table V-2 demonstrate the complex relationship between in-migration, base popula- tion, distance from metropolitan areas, and socioeconomic effects. The counties closest to major metropolitan areas (Kent and Queen Annes Counties) were estimated to receive the smallest amount of in-migration, due to the relative east of commuting. But as a result of the small population base of those counties and their major communities, the effects of the projected population changes is likely to be largest. By contrast, the counties with the largest amount of in-migration (with as much as 80 percent more in- migration) were also the counties with the largest population base, and were projected to experience the smallest adverse effects from the construction- period population changes. v-6 mmm Table V-2. Population effects -- Four Eastern Shore Counties Kent Queen Annes. Dorchester Wicomico County County County County Increase in County Population 2,034 1,743 2,740 3.9132 Increase in County Population, % 13% 10% 9% 5% Chestertown Centreville Cambridge Salisbury Increase in Municipal Population 637 279 1,477 780 Increase in Municipal Population, % 18% 15% 13% 5% Source: Reference (3) C. Housing One potential impact of the population increase that is likely to accom- pany power plant development in rural counties is the effect on the housing market. The influx of new residents into these counties results in a rapid increase in the demand for both conventional and temporary housing. In many of the more rural counties in the state, the housing industry has experienced a protracted period of slow growth. Without adequate planning, the housing indus- try may find itself unprepared to respond to such a rapid increase in the demand for new units. As a result, most of the housing units purchased or rented in these counties are likely to be existing units or temporary units. Given the relatively high wage scale, power plant workers moving into a county are typically willing and able to pay higher prices than other residents for all available homes and rental units. In the case of Calvert Cliffs, rental prices increased to two and three times their former levels (1).* Farmers and landlords experienced windfall income during a period in which a tight market permitted the rental of even marginal properties. The higher rents also resulted in the displacement of former low andmoderate income families unable to increase their housing expenditures. Instances were reported of public employees, espe- cially teachers, having been forced to seek housing outside the County (1). The predicted effects on housing markets of construction of a power plant on the Eastern Shore (3) varied considerably according to the size and nature of the county in which a plant might be located (Table V-3). However, given the present low population growth rates of the region, the housing markets in all four counties are likely to be strained during peak years of construction for a plant of the size considered. Significant shortages of both permanent and temporary housing units are likely during the two peak years of the nuclear plant construction activity; in one county (which is already experiencing a tight housing market) the shortage was estimated to last for a four year interval. A shortage of temporary housing units during the construction period may be fairly easily mitigated through adequate planning, once the scale of the housing deficit is known. Mitigating the shortage of permanent units is more difficult and will require greater planning on the part of the appro- priate unit of local government, the utility, and contractor. It has been suggested that the increased demand for housing and higher housing prices of the construction period provide an opportunity, with adequate planning, to upgrade the existing housing stock, particularly substantial units (4). Some counties may require both technical and financial assistance in order to properly plan and carry out an effective mitigation or upgrading program. As noted earlier, the Calvert Cliffs study does not permit separation of Calvert Cliffs impacts from the effects of other simultaneous developments. V-8 Table V-3. Housing effects -- Four Eastern Shore Counties Year Kent County Queen Annes County Dorchester County Wicomico County Conventional Mobile flame Conventional Mobile flame Conventional Mobile flame Conventional Mobile flame I no deficit no deficit no deficit no deficit no deficit no deficit no deficit no deficit 2 no deficit no deficit no deficit no deficit no deficit no deficit no deficit no deficit 3 no deficit no deficit no deficit no deficit - 16 - 2 no deficit no deficit 4 - 72 - 70 no deficit - 63 -168 - 69 no deficit -111 S -166 -144 - 79 -143 -276 -198 - 67 -349 6 -177 -130 - 88 -131 -299 -215 -149 -301 7 - 62 - 55 no deficit - 66 -153 - 93 - 16 -124 10 8 no deficit no deficit no deficit no deficit no deficit - 4 no deficit no deficit 9 no deficit no deficit no deficit no deficit no deficit no deficit no deficit no deficit D. Transportation The increase number of resident and commuting workers during the construc- tion frequently produce significant traffic congestion difficulties (1). The impact on traffic congestion is a function of the increase in the number of commuters and the available carrying capacity of the relevant transportation routes, dictated by local conditions. 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% of the hourly capacity per lane of the major two- lane road used to reach the plant, resulting in significant rush hour congestion . The study of four Eastern Shore counties estimated that the increase in the number of commuters coming into the county ranged from a low of 103% (2,524) to 664% (3,101). The county receiving the largest increase (relative and absolute) in the number of commuters was the least likely to experience signi- ficant traffic congestion because of the capacity of the major roads leading to the area (3). For each of the other three counties, significant traffic congestion was anticipated at particular points. Those congestion points all occurred 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. 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 improvement schedules . Congestion resulting from construction period overcrowding of otherwise adequate roads and bridges may be reduced by adjusting work schedules and traffic flow patterns. The extent to which appropriate mitigation measures will succeed in reducing traffic congestion depends on the ability to make long-range planning decisions for road improvements and congestion scheduling. E. Business Activity As indicated above, power plant construction may bring a large infusion of new money into a community. Power plant construction spending on payrolls and the purchase of materials represents a major source of potential income for local residents and businesses, particularly in more rural counties. Since the majority of construction material and many of the workers come from outside the local area, large amounts of this spending may leave the area un- affected. However, the amount of local spending that does occur may still con- stitute a major increase in personal income and in local business activity. Table V-4 presents predicted estimates of the change in county business activity from the Eastern Shore study (3). The data from the table indicate that in all cases the impact of power plant construction activity on smaller counties can be substantial, in spite of the relatively small proportion of total spending that occurs within the local county. In counties containing larger communities with larger, more diversified economies (which also results in the attraction of more resident workers), a greater proportion of total-spend- ing can be retained within the local economy, although that increase represents V-10 Table V-4. Effects on local business -- Four Eastern Shore Comties Kent Queen Annes Dorchester Wicomico COUnty County County County Increases Service Receipts, 3,630,000 2,787,000 2,732,000 7,S42,000 Peak Year Increased Service Receipt, 89% 1081 47% 351 Peak Year, I Increase Increased Wholesale and Retail 35,538,000 29,993,000 35,574,000 50,336,000 Sales, Peak Year Increased Wholesale and Retail 611 sit M 141 Sales, Peak Year, t Increase a smaller proportionate increase in the county's business volume. (See, for example, Column 4 of Table V-4). Those county-to-county variations also point to another difference: the smaller counties without large communities typically have a local business structure whose firms are small in size, established, and are frequently not able to respond quickly to a large, rapid change in the size and nature of their market. As a result, these firms are unable to capture as large a share of the new business potential as they might otherwise. Such firms are more likely to be adversely affected by competition by new firms entering the area to capture a share of the plant-induced business activity. Adequate planning by the existing local business community can increase the amount of business volume and income obtained by the local economy during the construction period. F. Fiscal Effects The increase in the number of workers during the construction phase will result in an increase in the demand for public services provided by local and county governments. This increase stems in part from the variety of public services -- such as police and fire service -- 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, local government has several options available. Public officials may choose to maintain public services at the existing per capita level, which would require increasing the local govern- ment budget in proportion to the population increase. Alternatively, recog- nizing the short-term nature of the increase, public officials may permit the per capita level of services to decline by not expanding services in pro- portion to the population change. At the limit, services may not be expanded at all. With the exception of plant sites in the sparsely populated western states, local governments have generally not experienced massive increases in public budgets or major overcrowding of services due to power plant construction. This experience has usually been explained by the fact that power plant construction, particularly in Eastern states like Maryland, has generally taken place in counties located close enough to metropolitan areas to have relatively well developed infrastructures. As a result of the proximity to metropolitan areas, the proportion of workers moving into a project area is also relatively small (see Tables V-1 and V-2). Because the population increases and increased service requirements that do occur are likely to be relatively small and of short-term in duration (see Figure V-1), local officials have frequently found it unneces- sary to greatly expand services and budgets (1,4). The experience in Calvert County during the construction of the Calvert Cliffs plant is similar to that of other Eastern states. County officials elected to avoid major increases in the county budget during the construction V-12 period (1). Some sections of county government did experience increased service requirements. For example, housing shortages, some portion of which stemmed from the Calvert Cliffs construction, resulted in increased use of housing services. Administrative services such as zoning and building permit issuance also increased. School officials estimated an increase of 250 in school enroll- ment as a result of the work force, an increase of about 3.8 percent. However, the county was able to meet these and other service requirements without a signi- ficant budget increase. 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 tax income from the property and capital taxes of the plant. The crucial question for local government is the extent to which these revenues will match the increased government service costs. In the absence of accurate revenue projections, local government officials may be reluctant to expand services and risk deficits. Pointing to increases in the demand for services which occurs during the construction phase but which diminish at the end of construction and to the increased tax revenues that accrue significantly to the county only after the plant begins operating, local planners have commented on the mismatch in the timing of their expenditure and revenue changes. The size of the potential mismatch can be seen in estimates calculated for Maryland's Eastern Shore (3). Table V-5 shows the annual deficits each of the four counties would experience under the assumption that they increased their service expenditures in proportion to their anticipated population increases (3). Table V-6 show the maximum de- ficit of each jurisdiction as a percentage of total local revenues in the appro- priate year (3). The data in Table V-5 illustrates the variation that exists between coun- ties. These variations are the result of differences 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 property taxes and increased sales taxes and business taxes. Dorchester and Wicomico Counties, which exper- ience the largest absolute increase in population, 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 -- all experience deficits throughout the construction phase. As seen in Table V-5 and V-6, the county deficits are significant, 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 will require either outside assistance, local tax increases, or potentially signifi- cant reductions in the level of services provided. At both the county and muni- cipal levels, service reductions or tax increases may aggravate the congestion, housing and other difficulties experienced during construction. Once a power plant comes on line, local county governments receive a sig- nificant increase in tax revenues from the utility. Without a mechanism to permit borrowing against these revenues, the county and municipal governments V-13 Table V-5. County and municipal fiscal effects -- Four Eastern Shore Counties Year Revenues Costs S/(D)* Revenues Costs E S/ (D) Revenues Costs SAD) Revenues Costs T- S/(D) Kent Queen Annes Dorchester Wicomico 34,331 33,049 1,282 26,345 34,416 1,929 41,132 34,34S 6,787 42,167 35,222 6,945 2 68,542 71,444 (2,902) S2,874 SS,565 (2,691) 86,115 73,672 12,443 91,713 78,6SS 13,058 3 2S8,143 288,154 (30,011) 195,603 207,276 (11,673) 349,S51 324,287 25,264 385,926 351,SO7 34,419 4 476,233 527,611 (51,378) 352,6S2 383,193 (30,S41) 689,182 6S2,584 36,598 757,969 712,187 45,782 5 736,444 882,625 (146,181) S63,774 631,2S5 (67 481) 1,002,180 950,469 51,711 1,082,893 1,047,824 35,069 6 735,606 912,716 (177,110) 565,196 650,074 (84:878 1,010,024 982,903 27,121 1,116,751 1,088,766 27,985 7 544,177 569,794 (2S,617) 430,329 392,573 37,7S6 789,082 730,474 58,608 811,321 679,018 132,303 8 332,679 183,011 149,668 281,66S 130,5SS IS1,110 551,530 197,790 353,740 484,427 216,203 268,224 9 11 247,222 49,334 197,888 223,063 37,477 185,S86. 4S9,706 SO,219 409,487 345,399 S5,059 291,340 Chestertown Centreville Cambridge Salisbury 1 1,856 2,965 (1,009) 897 1,694 (797) 5,971 10,960 (4,989) 3,873 6,256 (2,383) 2 3,947 6,273 (2.326) 1,906 3,433 (1,527) 13,228 24,08S (10,8S7) 8,376 13,469 (5,093) 3 15,425 26,092 (10,667) 7,536 14,765 (7,229) 58,456 106,487 (48,031) 37,555 61,629 (24,074) t@ 4 30,127 47,601 (17,474) 14,132 27,319 (13,187) 123,612 215,198 (91,586) 76,253 126,027 (49,774) 5 49,869 81,638 (31,769) 24,454 44,908 (20,454) 188,902 316,667 (127,765) 111,665 187,301 (7S,636) 6 SO,073 84,702 (34,629) 24,482 46,355 (21,873) 189,801 329,017 (139,216) 113,651 195,786 (82,135) 7 37,376 53,195 (IS,819) 19,582 27,05S (7,473) 165,403 207,049 (41,646) 89,899 123,164 (33,265) 8 23,177 17,210 S,967 14,S63 9,4SS S,108 138,682 66,634 72,048 63,942 39,386 24,556 9 17,761 4,680 13,0 12, is 2,765 9,850 128,684 16,698 111,986 53,663 10,079 43,584 S/(D) - Surplus/(Deficit) Table V-6. Projected deficits due to plant construction Four Eastern Shore Counties County or Maximum Deficit % of Maximum Deficit as % of Municipality Current Property Tax Total Revenues Revenues Kent 6.6% 4.0% Queen Anne's 2.8% 1.9% Dorchester Surplus Surplus Wicomico Surplus Surplus Chestertown 23.7% 13.8% Centerville 41.4% 21.3% Cambridge 18.3% 13.3% Salisbury 3.7 2.9% V-15 cannot reduce the fiscal strains which some jurisdictions may experience during construction. The revenues received by local governments once a plant begins to operate do provide new flexibility in the options available to the locality, including capital improvements, housing upgrading, expanded social or service activities, and reductions in tax rates. For example, Table V-7 gives the tax receipts estimated for the four Eastern Shore counties (3). The variation in these tax receipts is largely the result of variations in tax rates among the counties. Due to the very high capital cost of modern base-load units, tax receipts from these facilities tend to be substantial. As indicated by the comparison between tax revenues and current county budgets shown in Table V-7, the tax re- venues 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. Table V-8 gives the revenues received by all Maryland counties from electric utilities (5). Table V-8 also indicates the size of the revenue increase relative to the existing county budgets. These tax payments vary substantially, and depend largely on the nature and age 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 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. G. Summary In summary, power plant construction in Maryland is not likely to in- duce the kind of boomtown effects experienced by western energy development. Depending on the size, location, and infrastructure of the county in which power plant development does occur, however, significant effects may be experienced in the area of housing, traffic congestion, and local population changes. In all jurisdictions, gains in personal income and business sales are likely. Local government budgets and service requirements may increase, but the size of the increase and any potential budget imbalances will vary substantially be- tween counties. In some instances, particularly at the municipal level, the magnitude of the potential imbalance could lead to a deterioration of services or to the necessity of raising new revenues to cover potential deficits. v-16 Table V-7. County revenues, operating period Four Eastern Shore Counties County Revenues As % of Current Budget Kent 36,000,000 650% Queen Annes 27,000,000 390% Dorchester 40,000,000 450% wicomico 28,000,000 140% Ad V-17 Table V-8. Total taxes paid to Maryland Counties by Maryland utilities, fiscal year 7/1/77 - 6/30/78 County Utility Total Taxes Utility Tax Payments Paid to County as % of County Budget Allegheny 266,121 1.2 Anne Arundel 4,488,153 2.0 Baltimore City 17,983,231 1.7 Baltimore County 9,152,877 2.8 Calvert 11,552,445 48.1* Caroline 151,105 2.7 Carroll 654,042 2.3 Cecil 643,978 3.8 Charles 3,765,579 15.1 Dorchester 780,364 8.7 Frederick 1,315,699 3.6 Garrett 260,305 3.3 Harford 2,696,904 4.8 Howard 1,303,675 2.2 Kent 168,017 3.1 Montgomery 14,165,565 2.7 Prince Georges 14,327,239 3.5 Queen Annes 120,946 1.7 St. Marys 30,485 0.2 Somerset 133,826 3.3 Talbot 81,058 0.9 Washington 770,835 2.7 Wicomico, 384,651 1.9 Worchester 254,459 1.8 If adjusted for one-time capital expenditure out of current expenses budget this figure would increase to 72.2% V-18 REFERENCES -- CHAPTER V 1. "Review of Socio-Economic Impacts of the Calvert Cliffs Nuclear Power Plant on Calvert County, Maryland and Comprison with Kent County, Mary- land," Maryland Power Plant Siting Program, January 1975. 2. "Economic, Fiscal and Social Assessment Handbook," Volume 3, Maryland Major Facilities Study, Maryland Coastal Zone Management Program, Depart- ment of Natural Resources, December 1977. 3. "Eastern Shore Power Plant Siting Study," PPSA-4, Maryland Power Plant Siting Program, October 1977. 4. "NACo Case Studies on Energy Impacts, No. 4, Nuclear Power Plant Develop- ment Boom or Boon? County Experiences," National Association of Counties Washington, D.C. July 1976; "Socioeconomic Impacts: Nuclear Power Station Siting," NUREG-0150, U.S. Nuclear Regulatory Commission, Washington, D.C., June 1977. 5. Data provided by J. Nicol, APS; M. Hinkle, BG&E; R. Bryson,Conowingo; J. Pflieger, DP&L; M. Gould, PEPCO; D. Sturtevant, Maryland Association of Counties. V-19 CHAPTER VI OTHER IMPACTS A. Transmission Lines Electrical power is carried from generating stations to the users of electricity by a system of power lines, transformers and switching stations. The higher voltage lines, called "transmission lines," connect generating stations to each other and to major transformer substations located near load centers. Figure VI-1 depicts the transmission system in Maryland. All power lines above 69,000 volts in the State are designated as transmission lines, and the highest voltage currently used or planned for use in the State is 500,000 volts (Table VI-1). Power lines carrying 69,000 volts or less are desig- nated as "distribution lines." They form a grid system throughout each service area, connecting each consumer of electricity to the transmission lines and hence to the generators. Several types of impacts may be associated with power lines. Ecological impacts, both positive and negative, may result from the clearing created to permit the passage of power lines through natural areas. Aesthetic impacts may occur when direct view of the lines or their clearings interfere with the other elements of the natural visual scene. Physical effects caused by the electrical fields near higher voltage transmission lines include spark discharges and currents to which a person may be subjected if he touches an ungrounded metallic object. Audible noises are also generated by these electrical fields, such as 11 sizzling" sounds produced bv 500,000 and some 230,000 volt lines, and discrete tones ("60 cycle hum") produced by transformers and some higher voltage lines. Radio and television interference may be caused by the corona discharges on high voltage lines and by loose connections which cause sparking in lower voltage equipment. Health effects from the oscillating electrical field under high voltage lines have recently been alleged, and are presently the subject of much national debate and study. The magnitude of each of these effects depends upon the voltage carried by the power line, the design of the line's conductors and towers, and the location and situation of the line. The visual surroundings, the extent, type and proximity of nearby human activities, the strength of commercial radio and television signals in the area, and the nature of the local ecosystem are all factors which will determine the extent and severity of adverse effects. In general, the potential for adverse effects increases as the voltage of the power line is increased. Higher voltage lines create greater electric fields, stronger radio frequency emissions, and require larger, more visible towers and wider clearings for rights-of-way. Balanced against these effects is a reduction in the number of transmission lines needed to carry the given amount of power. Ecological impacts of power lines can largely be mitigated by proper routing to avoid unusually sensitive or unique areas, by careful sedimentation VI-1 17 21 1@2 13 10 6 0 12 19 2 Existing Plants for Maryland Plant Name Utility 3 1. Benning Road PEPCO A 9 2. Brandon Shores BG&E 3. Buzzard Point PEPCO 4. Calvert Cliffs BG&E 5. Chalk Point PEPCO 6. C.P. Crane BG&E 23 7. Crisfield DELMARVA 8. Dickerson PEPCO 9. Easton EASTON 4 10. Gould Street BG&E 11. Morgantown PEPCO N, 12. Notch Cliff BG&E 13. Perryman BG&E 14. Philadelphia Road BG&E 15. Potomac River PEPCO Existing Proposed 16. Riverside PEPCO 17. R.P. Smith POT.ED. 18. Vienna DELMARVA 500 kV 19. Wagner BG&E 20. Westport BG&E 230 kV Plants for Out-of-State Utilities 0 Power Plants 21. Conowingo CONOWINGO 22. Mount Storm VEPCO 23. Possum Point VEPCO V ;Switching Station Figure VI-I. Power plants and transmission lines in the Maryland region = M = M, M M M a' M-M M M Table VI-1. Pole miles of transmission lines and circuit miles of tmderground cables in Maryland Existing or under construction as of December 31, 1977, per annual reports to the Maryland Public Service Commission Line Voltages Existing Utility Corridors 500 W 230 w 138 W US kv 69 W (Acres) BG&E Pole Miles 195.7 214.6(') IS.3 333.4 - 9,698 Und. Cable - S8.9 - PEPCO Pole Miles 52.4 341.S - - (c) - 5,997 Und. Cable - 16.3 48.2 11.7 - Conowingo Pole Miles 24.1 1. 7 (c) 2.4 (d) - - 92S Und. Cable - - Susquehanna Pole Miles - 13. 9 (c) 930 Und. Cable - - Delmarva Pole Miles - 61.0 125.7 311.6(0) 7,209 Und. Cable - - - Pot. Edison Pole Miles 90.4 72.8 260.S 17.7 6,760 Und. Cable - - Southern W. Pole Miles 264.6 3,379 Und. Cable - - - 0.3 TUTALS Pole Miles 362.6 70S,S 403.9 333.4 593.9 34,898 Und. Cable - 16.3 48.2 70.6 0.3 lop, (a) Plus 6.4 circuit miles of sub marine cable (b) Plus 26.4 miles on Structures of another line. (c) 200 W (d) Plus 2.1 miles on structures of another line, all voltage 132 W (e) Plus 0.6 miles of submarine cable VI-3 and erosion control practices during construction, and by selective clearing and maintenance. Right-of-way maintenance for enhanced wildlife productivity is possible for some species which require grasses, dense brush or edge habitats. Where power lines traverse areas that are otherwise solidly forested, power line corridors may actually increase the diversity of species. Other species, however, particularly those requiring mature trees or forests, can only have their available habitat decreased by power line rights-of-way. Where power line corridors open otherwise secluded areas to human traffic, particularly noisv traffic such as motor bikes, all-terrain vehicles and snowmobiles, habitat may become unacceptable to timid species and erosion may be caused by vehicular traffic. These impacts must be evaluated on a case-by-case basis. Aesthetic impacts are subjective but no less significant. Selective clearing and vegetative screening can mitigate visual intrusion in natural areas, but it is usually not possible to hide power lines completely from human view. A trade-off arises between routing a line through a more secluded area, where less people see it but the aesthetic impact per person is high, and routing it along a more populated urbanized corridor which is already visually impacted but where more people will see it. The effects such views create on property values have not yet been quantified for the various types of residential settings and power line configurations in Maryland. Residen- tial situations vary from low cost row housing to estates situated near focal points of natural scenic beauty. Transmission lines range from single wooden poles carrying three wires, to bridgework tower structures over 150 feet tall , carrying bundles of wires. Again, impacts must be considered case by case. Radio interference, audible noise, and ozone production are all caused by corona discharges which occur when the local electric field strength at the surface of the transmission line wires exceeds the breakdown potential of the air. These effects are particularly noticeable in wet weather when water droplets on the conductors increase corona discharge. Audible noise consists of a "sizzling" sound in wet weather and a barely audible crackling noise in dry weather. For example, during wet weather, one 500 kV double circuit line reached a level of 43 dbA* near the transmission, line ROW, and 30 dbA (corresponding to the background noise in a very quiet rural area at night) at a distance of 200 ft from the ROW (1). The 43 dbA level is considerably below the Maryland State Limit of 50 dbA (night), al- though the possibility of annoyance cannot be absolutely ruled out. Under wet weather conditions, ambient noise levels are exceeded at high frequencies (above 500 Hz) at locations close to the line. Fortunately, the higher fre- quencies characteristic of transmission line noise are more rapidly attenuated with distance (1). Radio interference (RI) is a collective term for the various types of electromagnetic interference. RI from power lines is caused by corona dis- charge, an effect that is particularly important in wet weather. In such dR or decibel is a relative measure, here equal to the logarithm of the ratio of a measured energy to some reference energy. dBA is the total energy over a frequency band simila to that perceivId by the human ear, referenced to a pressure of 2 x 10_@ p bars = 20 -PNm VI-4 conditions, it may be bothersome for AM reception for residents located close to the line (1). During fair weather, residents nearby the ROW experience minimal interference. For example, investigations (2) involving the proposed Rrighton-High Ridge 500-kV line indicate that at least 18 AM radio stations would maintain an acceptable signal-to-noise ratio (21 dB). During light rain and heavy fog, residents extremely close to the ROW (less than 100 ft) for this line may notice a degradation in signal quality, but between 5 and 10 radio stations would still be available at an acceptable quality level. During heavy rain (a condition which often brings electrical interference of its own), interference effects extend to greater distances, but between 2 and 7 radio stations would still be available at distances of 100 feet from the ROW (2). Studies indicate that TV interference would not be bothersome, except possibly for sets located close to the ROW (< 300 feet) using indoor antennas (rabbitears) tuned to a weak, low wavelength station (channels 2-6) during a heavy rainstorm. In most cases, installation of a directional, outdoor antenna would eliminate this problem (1,2). For FM broadcasts and higher wavelength TV reception (channels 7-13 and UHF), no significant interference is expected outside the ROW. Corona processes from EHV power transmission lines also produce ozone by a method analogous to that occurring during lightning discharges. Sev- eral laboratory programs and modelling efforts have investigated the corona production and dispersion processes (1). The efficiency of the production rate varies widely with line voltage, electric field strength, conductor geometry and condition, and meteorological conditions around the transmission lines. On very humid days (but without precipitation), with clean conductors, and with conductor configurations designed to minimize the electric field strength, corona loss and ozone production will be reduced. During heavy rain, with nicked or contaminated conductor surfaces, corona loss and ozone production will be increased. Laboratory measurements have determined that ozone is generally produced at a rate of 0.5 to 5 grams per kW-hr of corona energy loss, depending on conditions (1). Field studies (as reviewed in Ref. 1) have either failed to detect ozone contributions due to transmission lines or have, under worst case conditions, averaged less than 1 ppb above peak background fluctuations. Based upon these results, it is reasonable to conclude that ozone production from transmission lines is not expected to have any significant effect on the local or regional environment. Electric and magnetic fields are generated around an operating power line. Magnetic fields are present any time current flows in the line, but the magnitude of these fields is small and their effects negligible when compared to the effects of electric fields, which can induce charges on metallic surfaces such as vehicles, gutters on adjacent structures, fences, and masts of sailboats. People touching these objects may draw a steady current through their body or may be subjected to spark discharges upon approaching these objects. The magnitude of the electric field varies with location, conductor height, and the configuration of the line. For example, for the line configuration shown in Figure VI-2, the maximum field intensity varies from about 7.0 kV/m at the minimum clearance point to below 3 kV/m at conductor heights above 65 feet (Figure VI-3). For all heights, the field at the edge of the ROW would be below 2.5 kV/m. VI-5 9 7 @-26'-j 0.572" Dia. -F rN Ground Conductor 263.5' B 35F 5' Three 1.502" Dia. Conductors, 75' to 110' 18" Spacing a) Lattice Structure ri -\@.40' Ground Clearence 75 0' b) Example Span Profile Figure VI-2. Typical 500 kV transmission line 3 , V-,, 3 5 VI-6 Edge of R. 0. W. 10.0 1 8.0 h 38' 42.5' 6.0 47.5' Measurement height = 1 m h minimum conductor height 4.0 h = 55' h 65' _E 2.0 - > 1.0 C 0.8 0'.6 .2 0.4 65' 55' cc 47.5' 42.5' 0.2 38' 0.1 0.08 0.06 300 0 50 100 150 200 250 Distance from center of R.O.W. (feet) Figure VI-3. Electric field profile for 500 kV horizontal configuration with three sub-conductors VI-7 The magnitude of these effects has been calculated for several repre- sentative "worst case" situations assuming a typical 500 kV power line configuration (1). Effects depend on the distance to the transmission line and the size and orientation of the object causing the effect on the human. In field tests, actual observed effects have varied from 10 to 100 percent of the calculated "worst case" results, reflecting the fact that many un- known and uncontrollable factors (such as insulation or leakage resistance under different conditions of soil, vegetation, and moisture content, and capacitance of irregular objects) are of central significance. Effects to quantify these factors (allowing a more realistic risk assessment) are now in progress (3). Figures VI-4 and VI-5 give the maximum "worst case" induced currents and spark discharge currents for various objects exposed to the fields surrounding the line depicted in Figure VI-2. Also shown in the fig- ures are the range of human responses. The "let-go" current is the level at which a person is unable to release his grip on a conductor. This level, obviously, is considered to be potentially dangerous. Another possible hazard is that a spark discharge may cause ignition during fueling of a vehicle under a transmission line near midspan. Figure VI-6 shows ignition potential for some typical vehicles when located in the maximum "worst case" electric field at the point of minimum height (40 ft) for the line shown in Figure VI-2 (note that a tractor-trailer normally will use diesel fuel not subject to ignition under these conditions). Actual tests have shown that the chances of such ignition are extremely remote, but it is nevertheless good practice not to refuel under a transmission line. The Power Plant Siting Program has recommended, as a result of these calculations, that the minimum height of new 500 kV lines over roads be raised to about 50 feet (depending upon configuration) so that refueling a vehicle the size of a school bus will not entail any risk of fuel ignition. Questions have been raised concerning the health effects of chronic exposure to oscillating electric fields at magnitudes found within (or possibly adjacent to) transmission line rights-of-way. Soviet literature contains reports of medical evaluations of personnel working in 400 kV to 765 kV switchyards. A majority of those studied developed pathological reactions attributed to their exposure to the electric fields. As a re- sult, Soviet work regulations limit the time a worker may be exposed to fields equal to or in excess of 5 kV/m. Maximum field intensities from some 500 kV lines currently in use in Maryland may reach peak intensities within the right-of-way of 6.7 kV/m at a height of I meter above the ground, and 7.5 kV/m at a height of 3 meters above the ground. These peak intensities occur at the lowest point of conductor sag. The Soviet work rules would limit a person's exposure to such fields to 3 hours per day. In contrast to the Russian reports, a major U.S. study of the medical effects of 10 linemen (4), working with 138 kV and 345 kV equipment over a 9-year period, concluded that the health of these men had not been affec- ted by their exposure to the high-voltage lines. The question of the health effects of exposure to 60 Hz electric fields is under study by many researchers (5). Both the Energy Research and Development Administration and Electric Power Research Institute are sponsoring major research Programs to determine the long-term chronic health effects of exposure to electric fields. At the present time, safe limits for exposure to electric fields from transmission lines have not been established in the VI-8 100- - Minimum conductor height 400 Three sub-conductor 500 kV design Increasingly objectionable 10 sensation /Rain gut'ter, h = 20' E Rain gutter, h = 10' Objectional sensation threshold Tractor trailor - Cm & 500' fence - Schoolbus - Perception 100' fence 1\ tip of 0.1 finger Station wagon- 1A L_ 0 Grounded Perception back of 0.01. conductor finger Edge of R.O.W. 0.001 F 0 100 200 300 Distance from center of R.O.W. (feet) Figure'VI-4. Worst case electrostatically induced spark discharge for people touching various objects ,d 3r @ N@t VI-9 10.0 Let go 50% wo.men 8.0 1 1 Let go 0.5% men 6.0- Minimum condtor height 40' - - Let go 0.5% women 4.0 Three sub-conductor 500 kV design - - Let go 0.5% children Startle (50% women pinched contact) Startle 50% women 2.0 (arm contact) E (A 1.0 Grip perception r= 50% men 0.8 Tractor trailor +0 500' fence' 0.6 Grip perception Schoolbus 50% women 0.4 1 - - Touch perception '0 Rain gutter, h 20' 50% men CD Station @ain gutter, h 10' _ Touch perception 0.2 50% women wagon 0 1 U% 0 0.08 0.06 - Grounded 0..04 - conductor 0.02- Edge of R.O.W. 100' fence 0.01 L 0 100 200 300 Distance from center of R.O.W. (feet) Figure VI-5. Worst case electrostatically induced currents for people touching various objects Tractor 'ra or 00 c L5 fen e a Swt a to @oon School. bus R a i.nutterl g u R a @@intte .d 3r 10@ VI-10 10 8 'ossible Fuel Ignition Region 6 Jr Tractor Trailor 4 W SchoolBus 0 Per > son With Gas Can 2 - Station Wagon CD CL 0 1 0.5 t J 100 200 400 600 1000 2000 4000 10000 Object to Ground Capacitance, (pF) Figure VI-6. Gasoline ignition potential from AC spark discharges. (Test results obtained on a warm, dry day.) Points apply to worst case open circuit voltage under proposed 500 kV line. Minimum conductor height = 40 feet VI-11 U.S. Several factors should be appreciated in evaluations of available literature on transmission line health effects: � Neither Soviet nor U.S. reports on health of linemen and switchyard workers present adequate test data or discuss control procedures. � Linemen and switchyard workers may be exposed to higher fields (up to 25 kV/m) then would be experienced by other people under the transmission lines. � Generally, levels of the electric field from transmission lines along the ROW are below levels at the lowest point of conductor sag. � Exposure to the highest field intensity occurs only when a person is almost directly under one of the conductors. Within the ROW, the average intensity is lower. � Beyond the edge of the ROW, intensities drop rapidly below peak levels. Tt is in this reduced intensity region that residents would be likely to receive extended exposure. Table VI-I summarizes the status of transmission lines in Maryland. Since the last CEIR, several changes have occurred. First, BG&E has upgraded their low-level (115-138 kV) transmission system substantially. PEPCO has started work on a 500 kV distribution loop around Washington, D.C. Finally, Delmarva has completed 61 miles of their 230 kV distribution loop for power distribution on the Delmarva peninsula. These trends in upgrading voltage and distribution nets are expected to continue. Conclusions The routing of transmission lines deals with effects that may have aesthetic, ecological, health, and physical implications. The aesthetic effects generally involve trade-offs between rural and urban routes. Ecological effects can be both positive and negative and must be evaluated on a case-by-case basis. The electrical effects are now well understood and are potentially significant only for locations within or extremely close to the ROW. The health effects remain an area of controversy, mainly due to differing medical results from U.S. and Soviet studies in this field. While the dangers to personal safety are relatively remote for anyone who is only occasionally in the proximity of transmission lines, the Maryland Power Plant Siting Program has taken steps to reduce that risk even further, so that the possible hazards from transmission lines, except under highly unusual conditions, are virtually negligible. VI-12 B. Groundwater In addition to the need for cooling described in the aquatic chapter, power plants also require freshwater for boiler make-up, pump cooling, sanitary water supply, and pollution control equipment. These uses can be considerable - up to 1.6 million gallons daily for 2000 MW of fossil-fueled capacity and 500,000 gallons daily for a 2000 MW nuclear plant. This water can be drawn from four sources, deDending upon the plant location. 9 Non-tidal river - Usually, the water is withdrawn from the river and purified for use. Examples of plants using this type of withdrawal are Dickerson and R.P. Smith. 9 Industrial water supply - Large cities like Baltimore and Washington provide water of industrial quality to power plants and other large users. 9 Groundwater/Desalination - For plants located near brackish surface water, but remote from municipal supplies, there are two alterna- tives: 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. A generalized cross section of the coastal plain sediments, shown in Figure VI-7, indicates the water-yielding formations ("aquifers") available for groundwater withdrawals in Southeastern Maryland. The potential impact of the use of groundwater lies not so much in a reduction of the quantity of water available, but in a decrease in the hydraulic head or "potentiometric surface" in the area surrounding the point of withdrawal. 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 (6). The average monthly usage (Figure VI-8) is far below the allowed average and maximum appropriations of 600,000 gpd and 865,000 gpd, respectively (6). Water levels in an observation well located about a quarter mile from the plant have declined approximately 10 feet due to pumpage (Figure VI-8) (7). No significant lowering would be expec- ted outside the plant property due to this pumping (8). Several other users in the area (e.g., U.S. Naval Research Laboratory, Patuxent Naval Air Center, Randle Cliffs) use similar or larger amounts of groundwater from the aqui- fer (6). The Vienna plant draws from 5 wells, four of which are screened in an unconfined aquifer (Quaternary) (35-54 feet) and the other of which draws VI-13 R0 OF WAX, '0 400 400 110 y v 200 '00 SEA ..... SEA LEVEL LEVEL ATIMI 5, 200 200 400 400 ....... .. ... .. . ... 600 600 .......... T__ 800 Soo ........... ........................... 1000 am 1000 ............ MIRAM 1200 1200 X 1400 1400 1600 1600 1800 2000 2P 00 2400 1 A Figure VI-7. General cross-section through unconsolidated coastal plain sediments in Southeastern Maryland m m m m m m m m -10 AQUIA AQUIFER WATER LEVEL .15 9L -20 W E W 'NVOO" ROKEN ik 25 W W 1.0- @j 30 PERMITTED YEARLY AVERAGE W -40 IX Ln AQLHA PUMPAGE W z W =3 A- 0 Ix 0 1 1 1 1 1 1 1-74 '14, a CA "S -PA 19T5 19T?- G Figure VI-8. Pumpage and water levels of the Aquia. aquifer at the Calvert Cliffs Nuclear Plant from the Cheswold aquifer (310 feet) (6.9). The average withdrawal rate for both aquifers is shown in Figure VI-9. Average withdrawal decreases during winter periods because the Nanticoke River is used as a supplemental fresh water supply (9). Because the Quaternary aquifer is likely recharged on an annual basis directly from precipitation and possibly seasonally from the Nanticoke River (5). the pumpage is expected to have no long-term effect. However, nearby domestic wells could be impacted on a seasonal basis (i.e. during periods of little recharge and heavy pumpage) (10). The town of Vienna supplies most of the local domestic water from the Cheswold aquifer (45pOOO gpd). Overall groundwater usage at this plant will increase by about 220pOOO gpd in the 1980's if a proposed 400 MW expansion is constructed (11). This increase will be partially offset by retirement of the existing once- through units. The detailed investigations needed to characterize the ground- water resources in this area are now in progress (12). The Morgantown plant has 5 wells, averaging 1100 feet in depth, that withdraw water from the Patuxent aquifer (6). The average withdrawal .,(Figure VI-10) is eight hundred thousand gallons daily (6). Water levels of the Patuxent aquifer have declined 80-90 feet (13), as measured by an observation well near the plant. 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 (13). At the request of the Power Plant Siting Program, the U.S. Geological Survey is installing a continuous water-level recorder on an observation well screened in the Patuxent aquifer at this site. The Chalk Point plant draws from two aquifers, the Patapsco (1066 feet) ,and the Magothy (630 feet). The average withdrawals, shown in Figure VI-11, indicate that the plant exceeded the permitted yearly average withdrawal for the Magothy aquifer in 1976* (14). Drawdown in the Magothy aquifer due to pumping from the plant (also shown in Figure VI-11) has been consistent since operations began in 1963, reaching a maximum of 55 feet in August/ ,September 1976 (15). 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. Figure VI-12, a survey (USGS) of the Magothy surface taken during early September, 1977 shows a "cone of depression" near the plant. Similar cones exist near Waldorf (as shown on map), Annapolis, and Severna Park. At present, the impact of these cones upon nearby users appears to be minimal. Howeverp should Waldorf expand its withdrawal rate significantly or another major user locate in the general area, the combined cones may affect users who cannot adjust their well pumps with water level (so-called "telescopic wells") (16). Detailed studies (as required under Title 8 of the Natural Resources Articles and proposed revisions to Water Resources Regulation .08.05.02) would have to be carried out before such expansion would be allowed. The USGS (17) has prepared a model of the Magothy aquifer that can be used to clarify the possible interactive effects of increased usage near the Waldorf-Chalk Point area. There is an unresolved questionp whether the maximum monthly average pumpage permit limitation of 2 mgd must be divided between the two aquifers (18,19). VI-16 m m m m 140' QUATERNARY PUMPAGE CHESWOLD PUMPAGE 120 06 0 100 W 60. 60. a: ul 40- 0@ D 20 0 W 0 v 1K Is T) 1976- -1977-- Figure VI-9. Pumpage from the Quaternary and Cheswold aquifers at Vienna Power Plant PATUXENT PUMPAGE PERMITrED YEARLY AVERAGE L2 0 1.0 am@ owm p ami NMI I am@ Iowa I I asomwsM@m W .8 00 Id U) .6 A D .2 0 0 70 01 ta .0 'A S;*A0ra r, %i A .1975 -1976 -1977- m Figure VI-10. Pumpage from the Patuxent aquifer at the Morgantown Power Plant mmmmmm m mm-m MM M M MM 0 ..2 AQUIA WATER LEVEL --4 (EAGLE HARBOR) -6 MAGOTHY WATER LEVEL (EAGLE HARBOR) .10.W 12 14- -14 W ilu > 12. -j W 10. -isW 3;: .20 6 22 !g 4 4 t5 2 -Z6 0 ? --30 P-0 - is 14 MAGOTHY PUMPAGE PATAPSCO PUMPAGE ta I LZ PERMITTED YEARLY AVERAGE W ()AAGOTHY) (FATAPSCO) 1.0. METER BROKEN z 0 .4 .2- 0 lk 'I % 19765 '977- - Figure VI-11. 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 VI-19 PREPARED IN COOPERATION WITH UNITED STATES MARYLAND GEOLOGICAL SURVEY DEPARTMENT OF THE INTERIOR AND GEOLOGICAL SURVEY MARYLAND ENERGY AND COASTAL ZONE ADMINISTRATION OPEN FILE MAP 78-999 77000, 76*30' EXPLANATION BALTIMPRE OUTCROP AREA Or THE XWZM AQUIM ED APPROXIMATE BOUNDARY OF TU KAGOTHY AQUIFER of potentionatric surf- .10 PaTExTIOPMTRIC CONTOUIt- Shows altitude ... ;d.D,,ho her approximately lo in.. w 10 f: t. Contours within area covered by wall symbol not shown. Datum in f-'4 mean sea level. -Number is altitude of the potentio- W= metric surface at wall used for control. Datum is man sea level. 016 Observation wall yielding less than 10.000 gallons par day. Supplj well- symbol indicates average d in gallons par day. 100.000 -.6 10 000 1 0 000 - 1,000,000 a .3 0 Nor; then 1.000,000 @4 00 8 NAPOLIS 23 23 64t A. 0 WASKING71*- 0 ro 4s ^3 J 915ANNE UPPiR ARUNDEL M .PA CS 0 R PRINCE 6 r .4) CO) 19 )JO /0 G E 0 RIG E SS 9 .16 12 4D 12 WALDORF -53 P-x I CHALK P01"T -15 e. f. 0 a -3 'S 46 o 380 to 301- -7 :RLES 6, CHA @: i A V E IF1 T@\ A 0 C 01 i P MAR: ST YS i n . -1 )!. J _rz -41" 4 9 @2 IaMILES 4 0 1 ARWTOWN *L"W 4 6 4' 8 1@ IS 20KILOMETERS _BAS1 ?ROR_PA1r-VM GWUXIM 0 0", Figure VI-12. Map showing the potentiometric surface of the Magothy aquifer in Southern Maryland, September 1977, by Frederick K. Mack, Judith C. Wheeler, and Stephen E. Curtin, 1978 VI-20 Conclusions Although the use of groundwater is relatively large at power plants mpared to most other industrial sources, due to the relatively sparse usage of the deep aquifers they have tapped, there has been no significant co impact upon present wells near these plants. However, if a major increase in withdrawals from the Magothy aquifer were to occur in the neighborhood of Chalk Point, there could be significant impact upon users of the Magothy aquifer in that area. C. Cooling Towers Once-through cooling systems use large amounts of water, typically about 2 cfs per MW for a fossil fuel plant, and almost 3 cfs per MW for a nuclear plant, in both cases for a 10' F temperature rise across the condenser. Although this water does not immediately disappear from the natural water system (eventual consumptive loss for a once-through system is about 10-70% of that for a cooling tower), it mav never-the-less be necessary to reduce the intake flow under three conditions: e If a large water intake causes potentially excessive entrainment losses, (e.g., Douglas Point site on the Potomac); e If the natural river flow is not sufficient to guarantee adequate cooling flow at all times, (e.g., Dickerson units 4 & 5 on the Potomac River); * If the cooling water volume is such a large portion of the available natural flow that the heating of the river may be unacceptable, (e.g., as might be the case of a large plant on a small body of water). The alternative to once-through cooling is a closed loop cooling system, such as cooling towers, spray ponds, and cooling ponds. In Maryland, due to factors such as amount and cost of available land, the preferred alternative is the cooling tower. There are many design options which tailor performance to site-sDecific needs. Towers can be of two basic types: dry or wet. In a dry tower, the condenser cooling water rejects its heat to the air in a totally enclosed system similar to the cooling system in an automobile. A dry cooling tower requires very large heat exchange surfaces, and is typically not economi- cally feasible for large power plants. A dry system does, however, have the advantage of being the only system where there is no evaporative loss of water. In a wet cooling tower the hot water is brought into contact with the air, and a large proportion of the cooling is accomplished by evaporation, a potentially troublesome situation where consumptive water use is a major consideration (as on the fresh water portion of the Potomac River). The water can be sprayed into the passing air, or more commonly, the air is passed through porous surfaces around or through the area where the water also passes. The air can be moved either by fans (mechanical draft towers) or by natural circulation (natural draft towers). While the use of cooling towers may be beneficial as far as aquatic impacts are concerned, it can introduce adverse impact in the terrestrial environment* Possible impacts may result from: VI-21 � formation of ground-level fog � ground-level icing � salt deposition (if the cooling water is saline) � noise � visual effects of the plume and the cooling tower, aesthetically offensive to some people. For the above effects that are caused by the condensation of the saturated air in a wet cooling tower exhaust, these impacts can be alleviated (if they are found to be significant) by use of a wet/dry combination tower where the exiting air is kept below saturation. Various cooling towers have been investigated in detail by the Power Plant Siting Program, particularly in connection with the proposed Dickerson and Douglas Point Plants, to see what tradeoffs can be made with respect to the more important of the impacts listed above (20,21). An extensive measurement program has been carried out at the Chalk Point plant to study the effect on vegetation of salt drift from a brackish water cooling tower, as will be discussed subse- quently. Six different cooling tower designs were considered in the Douglas Point study. They were: (a) a natural draft tower; (b) a fan-assisted natural draft tower; (c) a full wet mechanical draft tower; (d) two wet/dry mechanical draft designs with varying degrees of wet-to-dry cooling ratios; and finally, (e) a round mechanical draft tower. The characteristics of each type of tower can be briefly described as follows: � The natural draft tower is a big chimney, usually a hyperboloid (for mechanical reasons) where an updraft is created by the air being heated The air flow through the tower is entirely determined by ambient air temperature, relative humidity, and by the temperature of the cooling water. The air flow is highest at low ambient temperature, and decreases by almost 50 percent as the ambient temperature rises from the freezing point to the 90's. � The fan-assisted natural draft tower uses fans around the base of the tower to stabilize the air flow through the tower so that it becomes almost independent of external conditions. Such a tower also has a slightly higher rate of evaporation at low temperatures, but approaches that of the natural draft tower at high temperatures. Its main advantage is its smaller size. � The mechanical draft tower has its air flow completely controlled by fans and can be much smaller than natural draft towers, at the expense of additional power consumption. � The wet/dry towers reduce evaporation, particularly in the winter (when the river flow may be low, and the decrease in water uptake may be important). VI-22 The round mechanical draft tower is a special design where the fans are arranged in a centered configuration giving rise to enhanced updraft, thereby alleviating some of the environmental impacts of the low mechani- cal draft towers by dispersing the moist airborne plume more effectively. Common to all evaporative cooling systems is the fact that the evaporated pure water leaves behind increasingly saline water. This concentrated water must be diluted or discharged (blow-down) from time to time (or continuously). This concentrated discharge may also carry residual biocides (such as chlorine) if not treated to neutralize them. In addition, all cooling towers extract an energy penalty of 0.5 - 5.0% during temperature extremes due to increased condenser back-pressure. New types of turbines allow the maximum penalty to be shifted to either cold or warm weather, depending on the peak electrical demand of the utility and the inlet temperature of the cooling water. The results of the Douglas Point study (20) are summarized in Table VI-2. The conclusions are that there is little ground fog induced for any of the tower designs considered; and that the natural draft tower is, as expected, the least susceptible to this effect. The wet/dry design offers little advantage over the all wet mechanical tower. The persistence of visible elevated plumes is highest for the natural draft tower, but long plumes (> 2 km) are not common. The salt drift deposition is appreciably smaller for the natural draft tower than for any other design, about a factor of 5 less than for the mechanical draft tower. Icing is not a significant factor for any of the configurations. Noise is the least from the natural draft tower, which also requires the least power for its operation. Natural draft towers may be aesthetically objection- able because of their great height. On balance, the natural draft tower appears to have the least impact on the physical and biological environment. Chalk Point Cooling Tower Project The cooling tower at the Chalk Point power plant (PEPCO) is the world's first large natural draft hyperbolic cooling tower to use brackish water. It began operation in 1975. Because the water in the cooling tower is brack- ish with the salinity ranging from 4 to 15 parts per thousand, the potential for damage to the terrestrial biota, accelerated corrosion, and the contamina- tion of water bodies has been investigated. The Chalk Point Cooling Tower Project (CPCTP) of the State of Maryland Power Plant Siting Program has received the full cooperation of PEPCO and has been jointly supported by the U.S. Environ- mental Protection Agency, the U.S. Energy Research and Development Administra- tion, the Electric Power Research Institute and the State of Maryland. This program, the first long-term, full-scale endeavor of its kind, has received world-wide attention. CPCTP analyses and field programs (22) are being conducted to determine the extent of visible plumes, and the mechanisms of drift emissions and transport, as well as the impact of salt deposition on local vegetation and crops. Of particular interest is the effect on tobacco grown in the field surrounding Chalk Point, since it is known that chlorides can significantly effect burning qualities. A preliminary analysis of this data has been made, indicating that the cooling tower is not likely to produce off-site crop VI-23 Table VI-2. Comparison of cooling tower altematives for the proposed Douglas Point power plant. The power plant consists of 2 generating units, each unit generating 1,100 Nil with a condenser heat load of 16 x 109 BTU/hr (20). Environmental Natural-Draft Fan-Assisted Mechanical-Draft Tower Factors Tower Natural-Draft Round Tower Tower Full-Net Wet-Dry Design I Wet-Dry Design 2 Size Height: 120-150 a Height; 61 m Each cell: Each cell: Each cell: Height: 21 m Top Diameter: SS m Top Diameter: 49 m height, 21 m height, 21 m height, 21 m Diameter: 7S m Bottom Diameter: Bottom Diameter; length, 12 m length, 12 m length, 12 m IIS m 76 m width, 20 m width, 20 m width, 20 m --------------------------------------- ------------------------------------------------------------------------------------------------------------ Number of towers One per generating Two pe generating -35 cells gener- -43 cellspor gener- -S3 cells per gener- Two per generating unit unit (a) ating unitTaI5 ating unit ka) ating unit unit ------------------ -------------------- ------------------------------------------------------------------------------------------------------------ Ground-level fog <4 at any particular <10 at any particular <2S at any particu- Q2 at any particu- <21 at any particular <S at any particular induced off-site, off-site location off-site location lar off-site lar off-site off-site location off-site location hours per year location location ------------------ ------ -------------- ---------------------------------------------------------------- ------------------------------------------- Elevated visible SOO m (301) SOO m (2SI) SOO m (601) SOO m (2SI) 500 m (81) SOO m (401) plume lengths: I,SOO m (2S%) 1,500 m (20%) I'SOO m (101) 1,500 m (0%) I'SOO m (01) 1,500 m (20&) (annual average, percent of time exceeding indicat- ed distance) ------------------ ------------------------------------------- ----------------------------------------- --------------------- --------------------- Salt drift deposi- <42 at any particu-- <91 at any particular <226 at any parti- < Poll-wet <Design 1 <201 at any particular tion, pounds per lar off-site loca- Dff-site location, cular off-site off-site location, acre per year tion, extreme extreme conditions; location, ext extreme conditions; conditions; <3S typical conditions conditions; <78 typical conditions <16 typical <88 typical condi- conditions tions, very high on-site M M M M M' M M W Table VI-2. Comparison of cooling tower alternatives (Continued) Environmental Natural-Draft Fan-Assisted Mechanical-Draft Tat-ter Factors Tower Natural-Draft Round Tower Tower Full-Wet Wet-Dry Design I Wet-Dry Design 2 Near-term salt Off-site: none ff-site: limited Off-site: reduced Off-site: reduced Off-site: reduced Similar to fan- drift effects (b) On-site: some corro- 3ffect on crops crop yields crop yields crop yields assisted natural-draft sion and vegetation )n-site: modest corro- On-Site: severe On-site: severe On-site: severe towers damage during periods;ion and damage to corrosion and damage corrosion and damage corrosion and damage of extreme river 6regetation to vegetation to vegetation to vegetation salinity -------------------------------------------------------------------------------------------------------- --------------------- ---------------------- Icing None expected None expected Occasionally near Less than full-wet Less than Design I None expected tower ---------------- b ---------------------- i---------------------- -------------------- -------------------- --------------------- ---------------------- Noise from total 32.2 dB(A) at SOOO Less than round 36.3 dB(A) at 5000 Slightly more than Slightly more than Less than full-wet plant complex ft; this is 1.9dB(A) mechanical-draft ft; this is S.9dB with full-wet tower with Design 1 tower increase over ambient (A) increase over noise level ambient noise level -------------------------------------------------------------- ----------------------------------------- --------------------- ---------------------- Auxiliary power ne ra 8. 2 Pj5. 3 =6.S fts.0 Ps8.2 required for fans, M11 per generating unit -------------------------------------------------------------- ----------------------------------------- --------------------- ---------------------- Visual, aesthetic 1 2 4 S 6 3 impact; ranking, 1 - most impact 6 - least impact (a) Depends upon tower manufacturer and particular design. (b) Long-term effects cannot be predicted. damage. Peak depositions from the cooling tower fall within 1 km of the plant and effects beyond 1 mile will be small. At the point of maximum ground deposition, approximately 0.5 km (0.3 mi) from the cooling tower, the maximum monthly deposition is approximately 8 kg/ha (7 lb/acre). To date no evidence of salt damage has been observed to corn, soybeans, or tobacco grown on experi- mental field plots surrounding the site. In addition, experiments to determine the sensitivity of corn, soybeans, or tobacco to aerosol salt deposition indicate that no significant effects occur in the growing season at drift deposition rates up to 20 kg/ha/mo (18 lb/acre/mo). This far exceeds the drift deposition rates from the cooling tower at all off-site locations. During the experimental program, it was discovered that the "wet" par- ticulate scrubber associated with one of the generating units was also a major source of drift, which suggests that in all future siting on brackish water, it is important to consider the salt emissions from scrubbers when evaluating the environmental impact. Future work in the program is directed towards improving the confidence in the predicted values of salt drift and evaluating the long-term effects of salt deposition. Conclusions The use of cooling towers is an environmentally acceptable alternative to "once-through" cooling systems. Basically, a cooling tower exchanges consumptive water use and possible terrestrial effects for effects in the aquatic environment. Because the balance of these effects is site-specific, each plant location should be examined to determine the appropriate cooling system. VI-26 REFERENCES -- CHAPTER VI 1. Electrical influence on the environment for EHV power transmission. J. Patrick Reilly. Johns Hopkins University/Applied Physics Laboratory Technical Note T-7. April 1977. 2. Electrical influence on the environment from 500 kV transmission lines Brighton to High Ridge Corridor. J. Patrick Reilly. Johns Hopkins University/Applied Physics Laboratory PPSP 7-1. June 1977. 3. Proposed Scope of Work for F.Y. 1979 Detailed Site Evaluation Program, Johns Hopkins University, APL/CBI, June 1978. 4. "Medical evaluation of men working in AC electric fields." W.B. Kowen- hoven, et al. IEEE Trans., PAS-86 (4), April 1967. pp. 506-511. "Medical follow-up study of high voltage lineman working in AC electric fields," M.L. Singewald et al., IEEE Trans. PAS-92 (4), July/August 1973 pp. 1307-1309. 5. "Biological and Psychological Effects due to Extra High Voltage Installa- tion" G.E. Atoian IEEE Trans. PAS-97(l) January/February 1978. p. 8. "Environmental considerations concerning the biological effects of power frequency (50 or 60 Hz) electrical fields." J.E. Bridges, IEEE Trans., PAS-97(l) January/February 1978. p. 19. 6. Groundwater Appropriation Permits, Maryland Water Resources Administra- tion, Annapolis, Maryland. 7. Observation Well Water Levels, U.S. Geological Survey, Annapolis, Maryland. 8. "Groundwater Supply Investigation for the Calvert Cliffs Nuclear Power Plant for Baltimore Gas and Electric Company," Bechtel Corporation, January 1969. 9. "Comments on MPPS Cumulative Environmental Impact - Groundwater," letter from Mr. J.I. Owens (Delmarva) to Dr. Paul Massicot (PPSP), July 12, 1978. 10. "Comments on Groundwater Section, CEIR," John Vukovitch, Groundwater Permits Section, Maryland Water Resources Administration. 11. Application for Certificate of Public Convenience and Necessity for Vienna Power Station Unit #9, Delmarva Power and Light, April 26, 1978. 12. Proposed Scope of Work for F.Y. 1979 Detailed Site Evaluation Program, Johns Hopkins University, APL/CBI, June 1978. 13. Groundwater Appropriation Application Review for Morgantown Generating Station, Maryland Water Resources Administration, November 1977. 14. Letter from Mr. Charles Wheeler (WRA) to Mr. L. Stephen Guiland (PEPCO), June 29, 1978. VI-27 15. "Preliminary Analysis of Geohydrologic Data from Test Wells Drilled Near Chalk Point, Prince Georges County, Maryland," U.S. Geological Survey, F.K. Mack, Open file Report 76-322, 1976. 16. Personal Communication; Frederick K. Mack, U.S. Geological Survey, and John Vukovich, Water Resources Administration. 17. Digital Simulation and Prediction of Water Levels in the Magothy Aquifer in Southern Maryland, Frederick K. Mack and Richard J. Mandle, Maryland Geological Survey Report of Investigations, November 28, 1978. 18. "Comments on Groundwater Section, CEIR," letter from Ms. Ann Rioux (PEPCO) to Dr. R. Roig (PPSP), July 31, 1978. 19. Personal Communication; Charles Wheeler, Groundwater Permits Section, Maryland Water Resources Administration. 20. Power Plant Site Evaluation Final Report. Douglas Point Site. Maryland Power Plant Siting Program. Johns Hopkins University Applied Physics Laboratory/Chesapeake Bay Institute. JHU PPSE 4-2, Vol. 1 Part I (Chapter 4) 'February 1976; Part 2 (Chapter 4) January 1976. 21. Power Plant Site Evaluation. Interim Report. Dickerson Site. Maryland Power Plant Siting Program. Johns Hopkins University. Applied Physics Laboratory/Chesapeake Bay Institute. JHU PPSE 3-1 (Chapter 4) April 30, 1973. 22. See Below: PPSP-CPCTP-12. "Environmental Systems Corporation's Comprehensive Project, Final Report for the Period October 1, 1975 - June 30, 1976, Vol. 1: Phase IV, Comprehensive Field Program Description, Vol. 2: Environmental Systems Corporation's Summer Seasonal Test Data by Environmental Systems Corporation, (April 1977). PPSP-CPCTP-14. "Field Research on Native Vegetation" Chalk Point Cooling Tower Project Final Report FY '76 by Water Resources Research Center, Univ- ersity of Maryland (June 1976). PPSP-CPCTP-15. "Cooling Tower Plume Survey" (Vol. 1: Technical Summary; Vol. 2: Tabulated Data; Vol. 3: Air Quality Data Plots and Vol. 4: Droplet Size Data Plots by Meteorology Research, Inc., (November 1976). PPSP-CPCTP-16. (Volume 1) "Salt Loading, Modeling and Aircraft Hazard Studies" by the Johns Hopkins University, Applied Physics Laboratory (August 1977). (Volume 2) "Cooling Tower Drift Dye Trcer Experiment" June 16 and 17, 1977 by the Johns Hopkins University, Applied Physics Laboratory, (Aug. 1977). VI-28 (Volume 3) "Cooling Tower Drift Dye Tracer Experiment, Surface Weather and Ambient Atmospheric Profile Data," June 16 and 17, 1977 (Aug. 1977). PPSP-CPCTP-17. "Effects on Simulated Saline Cooling Tower Drift on Woody Species" by the University of Maryland, Water Resources Research Center, (July 1977). PPSP-CPCTP-18. "Field Research on Native Vegetation" by the University of Maryland, Water Resources Research Center, (June 1977). PPSP-CPCTP-20. (Volume 2) "Cooling Tower Drift Dry tracer Experiment" by the Environmental Systems Corporation, (December 1977). PPSP-CPCTP-22. "A Symposium on Environmental Effects of Cooling Tower Emissions" May 2-4, 1978, Co-Chairman, Richared S. Nietubicz, Power Plant Siting Program and R. Lamar Green, University of Maryland, Water Resources Research Center (Supplement included). VI-29 APPENDIX A 1978 TEN-YEAR PLAN OF MARYLAND ELECTRIC UTILITIES, POSSIBLE AND PROPOSED POWER PLANTS., 1978 through 1987 Public Service Gommission of Maryland 301 W. Preston Street Baltimore., Maryland 21201 7:3 A-1 TABLE OF CONTENTS PAGE NO. I. Introduction 3 Ho Utilities Identified 3 IIIo 1978 Ten-Year Siting Plans by Company 4 IV. Projected Growth In Peak Load and Generating-Capacity 11 V. Comparison of 197 7 and 1978 BG&E and PEPCO Ten-Year Plans 13 V`I. Power Plant 0onstruction Schedules 14 VIIo Associated Transmission Lines 15 VIII. Additional Data Inquiry 15 Attachment Noo 1 Retail Electric Companies Operating In Maryland 17 Noo 2 Projected Ten-Year Growth in Peak Electric Demand 18 and Installed Generating Capacity in Maryland Noo 2A Projected Ten-Year Growth in Peak Electric Demand 21 and Installed Generating Capacity in Marylandp The Potomac Edison Company Noo 3 Comparison of Projected Annual Growth Rates in 22 Peak Demand and Installed Generating Capacity as Presented in the 1976, 1977 and 1978 Ten Year Plans Noo 4 Projected Annual Growth Rate in Peak Demands 23 1978-1987 Period (Graph) No. 5 Ten-Year Projections of Peak Electric Demands 24 Installed Capacity and Reserve Margin, 1977 and 1978 Ten-Year Plans of Baltimore Gas & Electric Company and Potomac Electric Power Company Noo 6 Estimated Reserve Margin (Instal-led) 27 BG&E and PEPCO., Percent (Graph) No. 7 Time Schedules for Implementing New Electric 28 Generating 'Plants in Maryland.. 1978-1987 Period A-2 I. INTRODUCTION This report constitutes the 1978 Ten-Year Plan of the Public Service Commission of Maryland (referred to herein as the Jommission or the PSC) regarding the possible and proposed sites, including associated transmission routes, for the construction of electric power plants within the State of Maryland. The report is in accordance with Section 54B (b) of Article 78 of the Annotated Code of Maryland* The plans herein are based upon the individual long-range plans submitted by the Maryland electric utilities,, with supporting analyses and information by the Engineering Division of the Commission. II. UTILITIES IDENTIFIED The 16 retail electric companies presently operating in Maryland and subject to the jurisdiction of the Commission are listed in Attachment No. 11 according to type of ownership: investor-owneds municipally-owned., and customer-owned (i.e., cooperatives). In additiono there are two non-retail electric companies owning generation property in Maryland. They are: 19 Pennsylvania Electric Company owns a bydro-electric plant on the Youghiogheny River, Garrett County (Deep Creek Lake Reservoir) and an associated transmission line. 2e 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* A-3 Of these 18 companies, only the 7 utilities listed below have future power plant siting interests in Maryland: Baltimore Gas and Electric Company Conowingo, Power Company Delmarva Power and Light Company of Maryland Easton Utilities Commission The Potomac Edison Company Potomac Electric Power Company Southern Maryland Electric Cooperative,, Inc. Of these 7 companies, two., namely2 Conowingo Power Company and Southern Maryland Electric Cooperative, own no generation capacity at the present time, 111. 1978 TEN-YEAR SITING PLANS, BY COMPANY General These Plans reflect continued planning by the electric utilities-for the deferral and stretch-out of new generation and associated transmission plant construction in the next decade* These current plans are indicative of the uncertainties in formulating long-range.electric demand forecasts. A listing of the utility planned and possible new power plant sites is given in Attachment No- 7 (at end of report), arranged by utility and further indicating: name of site/plant, type of fuel, capacity., initial construction and in-service dates. A discussion and further explanation of the sites is given below: 1. Baltimore Gas and Electric Company The second unit of the Calvert Cliffs nuclear plant became operational April 1. 1977. Total rated capacity of both units is 1730 W A-4 In 1973 the Company was granted approval to begin construction of two 610-MW fossil-fueled steam units at Brandon Shores, Anne Arundel County. These two units are to become operational in 1981 and 1983, respectively. These dates represent a one-year stretch-out from last year's Plan. New generating plant of 100-W capacity is planned for Sollers Point, Baltimore 'County. Total acreage involved is 1000 acres. Actual size of the individual units, the kind of fuel and the year construction is to start are presently undetermined although completion is expected by 1986. This represents a two-year delay in completion date from the previous year's Plane The Company had previously considered building a 200-W plant at this site. Additional generation is now being planned at the Safe Harbor Water Power Corporation bydro-electric plant. This plant is on the Susquehanna River, Lancaster Countyp Pennsylvania,, approximately 20 miles upstream from the Maryland-Pennsylvania border. The proposed expansion is being planned in conjunction with the application for the renewal in 1980 of the plant's operating license by the Federal Power Commission., filed April., 1977. If the license is not renewed., these expansion plans will be cancelled. The expansion would include 5 units having a total capacity of 187.5 W. Capacity entitlement of 125-MW would be allocated to the Baltimore Gas and Electric Company in the proportion of its ownership: 2/3 Baltimore Gas and Electric Company and 1/3 Pennsylvania Power and Light Company. No transmission line reinforcements will be required insofar as the Baltimore Gas and Electric Company is concerned. A-5 The Company is considering the possibility of a 800-NW coal-fired plant to be located on an undetermined site in the northeastern section of Maryland. Approximately 800-1000 acres will be required* Cooling water, services and other special requirements are presently under review, Last year's Company Plan listed a Northwest Substation in Baltimore County as the site of a peaking generating station. Plans for this station have been deleted. Plans for additional generation at the Perryman station, Harford County, have also been deleted. 2. Conowingo Power Company The Philadelphia Electric Company and its wholly-owned subsidiary,9 Conowingo Power Company.. operate their facilities as though these facilities were that of a single company. Conowingo customers thus obtain the benefits of being a part of the larger Philadelphia Electric system and of the PJM Interconnection., of which Philadelphia Electric is a member. At the present time, almost all of the Philadelphia Electric system generation plant is in Pennsylvania. The Conowingo bydro- electric plant represents about 6% of the Philadelphia Electric's installed capacity. An additional 938-MW of capacity is being added to the Philadelphia Electric system through the partial (42%) entitlement of the 220-W nuclear generating plant at SalemO New Jersey. The first unit of this plant went on-line in June,, 1977. The second unit is scheduled for service in 1979. A-6 The Conowingo hydro-electric plant is a peaking generation station with an annual capacity factor of about 40%. Because of this, Conowingo is unable to supply just the Maryland load but instead must be operated in conjunction with base load generation plant of the Philadelphia Electric system. A major new generating station in the Philadelphia Electric system is scheduled to become operational sometime within 1992-1994, with construction beginning approximately 1985. Prime location of this station is in Fulton Township, Iancaster County,, Pennsylvania. The three alternate locations for this station are in Maryland* They are the following sites: Canal site Bainbridge site Seneca Point site Conowingo Power Company presently owns 680 acres at the Canal site. This is located approximately 1 mile west of Chesapeake City., Maryland on the Chesapeake and Delaware Canal. The Canal site was listed in the application to the Nuclear Regulatory Commission for the Fulton Nuclear Generating Station, as an alternate site. Bainbridge, formerly the location of the Naval Training Center just east of Port Deposit3 Maryland, has approximately 1260 acres available for power plant construction* The State of Maryland is currently negotiating with the General Services Administration of the Federal Government for acquisition of this site, to be included with the Elms site in St. Mary's County, in the State Power Plant Site Bank. The Philadelphia Electric Company is interested in either joint or wholly-owned development of generation plant at this site. A-7 The Seneca Point site is approximately 500 acres of which 394 are currently owned for future development. It is located on the west bank of the Northeast River2 approximately 1 mile southwest of M Charlestown, Cecil County., Maryland. At any of these three sites., development would probably be two base load nuclear-fueled units for possible service in the 19901s. Unit capacity would be in the 1100-1500-MW range. Alternately., the development could be equivalent fossil-fueled capacity. Final determination of the type of plant would depend on detailed studies including plant and fuel costs,, environmental considerations and licensing aspects* 3. Delmarva Power and Light ComparW of Maryland The Company has no proposed generating station sites either through ownership or under option. Studies are continuing on potential plant sites in the lower eight Maryland counties on the eastern shore* No information is available on specific sites at this time. 4. Easton Utilities Commission. In 19752 the Public Service Commission granted Easton Utilities Commission a Certificate of Public Convenience and Necessity for the construction of a new generating plant, known as Plant No* 2. Located on a Town-owned 7-acre site within the city limits of Eastons this plant is presently under construction, with completion of the first two units, having a total capacity of 12.5-MW, now scheduled for 1978. This was to be completed in 1977, according to the Easton Utilities Commission's 1977 Plan. A-8 Additional capacity will be incorporated at Plant No. 2 in 1982 and 1986. Prime mover of all units will be diesel enginesV fueled by No. 2 fuel oil. 5. The Potomac Edison Company The Company owns one site in Maryland for possible use as a power generation site. This site, known as Point of Rocks, is in Frederick County., 214 miles down the Potomac River from the community of Point of Rocks. This sitej containing 829 acres, was purchased for a nuclear generating facility having an ultimate capacity of about 2500-mw. There are no active plans at the present time to proceed with construction at this site, After extensive internal study and discussions with the state power plant siting program., the Company has withdrawn the Black Oaks site in Allegany County from consideration as a location of a future generation plant. The Black Oak site has three serious deficiencies for power generation: air quality, flooding and water makeup. The problem of meeting applicable governmental air quality standards appears to be insoluble. The Company has no plans for expansion of its R. Paul Smith plant at Williamsport or its Celanese power plant2 the only existing plants it operates in Maryland. 6. The Potomac Electric Power Company On June 9, 1977 the Company announced the indefinite deferral of its plans to construct a nuclear generating station at Douglas Point A-9 in Charles County. However,, the site will be retained for eventual construction of a generation plant when the needs so warrant. NRC (Nuclear Regulatory Commission) site suitability determination will be pursued* Specific contracts and arrangements associated with the two planned units will be abandoned., sold,, terminated or otherwise dealt with., as determined by economic analysis and estimates of future technical applicability. Potomac Electric Power Company now expects the 600-W Unit No. 4 at Chalk Point to begin commercial service in 1982. It is now under construction. This represents a 2 year delay from the 1980 date given in the Company plans last year* This unit will burn residual fuel oil in accordance with the Carter Administration policy of allowing existing plants to burn oil where coal-firing capability does not exist* In June, 1977.. PEPCO and Baltimore Gas and Electric Company executed an Agreement in Principle on the Dickerson #4 coal-fired unit. This agreement calls for tenancy in common with equal shares of ownership. Capacity and KWH output will be shared equally with the Baltimore Gas and Electric Company. PEPCO is designated as the managing party.. to serve as agent for construction and operation of this Unit. Construction of the 800-MW Dickerson Unit No. 4 is to begin in 1978 with commercial service expected in 1985. This represents a 3-year stretch-out in the operational date. According to PEPCOI requirements still exist for a 1000-MW pumped-storage hydro-electric plant to be located on a 1000 acre undetermined site in Maryland. The year this site is needed to become operational is not specified. A-10 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 Della Brooke Farm., is considered for possible future generation. However, no plans have been made for such use* IV. PROJECTED GROWTH IN PEAK LOAD AND GENERATING CAPACITY The growth in peak load and in installed generation capacity within Maryland, as projected by each utility (except The Potomac Edison Company) over the next decade,, 1978-1987, is listed in Attachment 2. The listing of the utilities is by regional areas in the State. '"his arrangement allows demand and generating capacity by region to be readily compared. The numbers within parenthesis are changes from the projections made last year. A third potline at the Eastalco plant in Frederick County is under consideration. Depending upon approval of appropriate environmental permits, this line is estimated to become operation during the winter of 1979/1980. At this time, this load will increase the peak demand by 35-MW and by 130-MW for each year thereafter. Formal notice of this additional load, however., has not been received by The Potomac Edison Company. Attachment #2A lists the projections in the Maryland peak load, both with and without this third ptoline, for The Potomac Edison ..ompany over the next ten-year period, 1978-1987* The Company's generating capacity in this period will remain at 139-MW. A-11 The Potomac Electric Power Company data in Attachment No. 2 are for the entire Company system. PEPCO's service area includes the entire District of Columbia, the Pentagon and Rosslyn complexes in Virginia, as well as the Metropolitan Washington area lying in Maryland. PFPCIO owns generation plants in the District, Virginia and Marylands and shares with other utilities mine-mouth generating plants in Pennsylvania. Data on the Baltimore Gas and Electric Company generation include a proportionate share of the Keystone and Conemaugh Mine-Mouth plants in Pennsylvania. The generating facilities of the Hagerstown Municipal Plant have a total nameplate rating of 20-W capacity. These facilities are maintained on a stand-by basis and are used for peaking purposes only when The Potomac Edison Company is unable to supply the demand. Present interconnection capability with The Potomac Edison Company is 65-W- Also listed on Attachment No. 2 are estimates of the average annual growth rate of both the peak load and generating capacity for each utility and for the state as a whole. These rates are computed as compound rates over the ten-year period, 1978-1987o The corresponding doubling times are also listed. The individual peak loads do not sum to the listed state totals in Attachment No. 2. Peak demand data for Hagerstown and Southern Maryland are excluded from the state figures since these data for these utilities are included in The Potomac Edison Company and Potomac Electric Power Company figures., respectively. A-12 Attachment No* 3 is a summary of the projected annual growth rates in peak demand and installed generating as predicted by the utilities in their 1976, 1977 and 1978 (current) Ten-Year Plans. State-wide data are also shown. Several observations concerning these estimates should be noted: 1. This year the community of Easton projects the highest growth in peak demand (8.4% per year) in the state. 2, In the estimate made last year Southern Maryland Coop. expected an annual growth in demand of 10-5%. This has now been scaled down to a more modest 6.1%, still significantly higher than the state as a whole 3. Lowest growth in peak demand in the state is again projected for the PEPCO service area (3.1%), down from the 4.0% estimate in the 1977 Plane 4. Baltimore,, the other major metropolitan area, is expecting a growth of 5o2%., down slightly from the 1977 estimate of 5o4%. 5. The Potomad Edison Company2 which serves virtually all of western Marylando estimates its growth in peak demand at 5.7% without the additional pot-line in the Eastalco plant, virtually unchanged from the 1977 figure* With this pot-line, the estimate is 7.2%. The load created by this additional pot-line is almost 11% of the peak load expected during the winter of 1980-1981, when it may become on-lineo 6o For the state as a whole, peak demand is expected to increase at 4.5% per year average* This is down from the 5ol% estimate last year. Attachment No. 4 is a bar graph of these expected annual growth rates for these 5 principal regions and for the.state. V. COMPARISON OF 1978 and 1977 BG&E AND PEPCO TEN-YEAR PLANS A-13 Shown on Attachment No. 5 are the ten-year projections of the peak demand, installed generating capacity and reserve margin for the Baltimore Gas and Electric Company and Potomac Electric Power Company as given in their 1977 and 1978 Plans, Differences between these estimates are also listed for comparison purposes* The reserve margin is usually defined by the relation: Reserve Margin - Installed Generating Cal2acity_- Peak Load x 100 Peak Load This definition is used in this Plan. Current Potomac Electric Power Company reserve margin estimates for the next ten years varies from a minimum of about 17.4% in 1981 to a peak of 29.0% next year. The average margin aver this decade is 22.1%., down somewhat from the 24.8% average in last year's estimate* For the Baltimore Gas and Electric Company the estimated reserve margin peaks at 28.4% next year with a low of about 14*5% for the years 1980, 1982, 1984 and 1986. The current estimate of the margin over the next decade is 15.7% which is also less than the estimate for this same period in last year's plan (22.9%). Attachment No. 6 graphs the estimated reserve margins for these two utilities. VI. PaIER PLANT CONSTRUCTION SCHEDULES Attachment No. 7 has been prepared to assist in visualizing the planning schedules for new electric generation facilities in Marylande Dashed lines and dashed blocks show indefinite construction and/or in- service dates of proposed new generation. A-14 VII. ASSOCIATED TRANSMISSION LINES The transmission lines associated with the construction of new generating stations will generally operate at 115KV 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 782 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 lines1l, with respect to Section 54A of Article 78j which are not "generation leads" but rather they provide substation-to- substation bulk power transmission for increased capacity or reliability D In any of these instances., the long-range need and probable ,urposes. 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* Howeverj 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* VIII. FURTHER INQUIRY Tn the event further inquiry is indicated, such as by other state agencies, the recuest may be directed to the Commission by writing A-15 to Mr. Frank J. Wasowicz., Executive Secretary. Specific information requests of an engineering nature and comments on this Plan may be directed to Mr. John W. Dorsey, Ghief Engineer. A-16 ATTACHMENT NO. 1 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 1-398-1400 Elkton, MD 21921 Delmarva Power and Light P. 0. Box 1739 1-749-6111, Company of Maryland Salisbury., MD 21801 Potomac Edison Company,, The Downsville Pike 1-731-3400 Hagerstown, MD 21740 Potomac Electric Power Company 1900 Pennsylvania Avenue.., N. W. 1-202-872-2449 Municipally Owned Washington, D. C. 20006 Berlin., Mayor and Council of P. 0. Box 235 1-641-2770 Berlin, MD 21811 Centreville, The Town of Centreville, MD 21617 1-758-0830 Easton Utilities Commission., 11 S. Harrison Street 1-822-6110 The Easton, MD 21601 Hagerstown Municipal Electric Hagerstown, MD 21740 1-731-2600 Light Plant St. Michaels Utilities Commission St. Michaels, MD 21663 1-745-94oo Thurmont Municipal Light Company P. 0. Box 385 Thurmont, MD 21788 Williamsport., Mayor & Council of Williamsport., MD 21795 1-223-7711 Customer Owned A and N Electric Cooperative Parksley,, Virginia 23421 1-804-665-5116 Choptank Electric Coop., Inc. P. 0. Box 430 1-479-0380 Denton, MD 21629 Somerset Rural Electric Coop., P. 0. Box 270 Inc. 125 E. Fairview Street 1-814-445-4106 Somerset,, PA 15501 Southern Maryland Electric Hughesville.9 MD 20637 1-274-3111 n .Oop*, Inc* A-17 Sheet 1 of 3 ATTACHMENT NO. 2 PROJECTED TEN-YEAR GROWTH IN PEAK ELECTRIC DEMAND AND IN INSTALLED GENERATING CAPACITY IN MARYLAND 1978-1987 TIME PERIOD IN MEGKdATTS 1978 1979 1980 1981 REGION PEAK LOAD GEN. CAP. PEAK LOAD GEN. CAP. PEAK LOAD GEN. CAP. PEAK LOAD GEN. CAP. Balto e MeIE-0 A, 402A-3-10P 5162(-120) 4280(-110) 5162(-120) 4510(-120) 5162(-730) 4750(-130) 5772(-120) Washington Metro PEPCO(q 3885(-266) 5013(+3) 4017(-346) 5013(+3) 4142(-409) 5013(-597) 4269(-488) 5013(-597) (Entire System) Western Maryland Hagerstown V 51 20 54 20 58 20 61 20 Potomac Edison (9) 139 (9) 139 139 (1) 139 >1 Southern @@land 00 ' 259(+2) 279(+7) South. HD Elea. 242(+10) 0 0 0 293(-25) 0 Coop*, Inca Eastern Shore A & N(U 1 1 1 1 1 1 2 1 Berlin U N/A 4 N/A 4 N/A 4 N/A 4 Conowingo 0 90 0 0 98 0 G 86 94 Delmarva 390(-19) 258(o) 410(-38) 258(0) 435(-56) 258(0) 460(-70) 258(0) Easton 26.3(-0.3) 44.60) 28-50-3) 44.6(o) 30.9(0.2) 44.6(o) 33.4(-0-3) 44-0(0) State TotalS8 W10 P/L8 941.6(-396) 10642(-117) 9899(-1s94)1lO642(-l17) 10348(-586) 10642(-1327) 10806(-689) r250(-718) W PA 9416(-396$ 9899(-1494) 10383(-551) 10936(-55s NOTES: G Generation in Pennsylvania included Includes all customers including Sai-es For Resale Q Baltimore Group Load Data from 1976 Plan Numbers in parentheses indicates changes from 1977-Plan 7 Non-coincident peak load totals Load data are shown on Attachment No. 2A Eastalco 3rd pot line Sheet 2 of 3 ATTACHMENT NO. 2., continued 1982 1983 1984 1985 PEAK LOAD GEN. CAP. PEAK LOAD GEN. CAP. FEAK LOAD GEN. CAP. PEAK LOAD GEN. CAP. UTILITY B G & E 5000(-130) 5721(-730) 5260(-140) 6331(-120) 5530(-140) 6331(-320) 5800(-1)40) 6731(-220) PEPCO 4453(-536) 5613(-797) 4594(-551) 5613(-797) 4749(-552) 5613(-797) 4866(-590) 6013(-1575) Hagerstown 6 20 64 20 7@6 20 20 Potomac Edison a 139 139 139 139 South. MD Eled . 310(-40) 0 3 -59) 0 343(-87) 0 3 -log) 0 Coop*, Ince A & N 2 1 2 1 2 1 2 1 Berlin N/A 4 N/A 4 N/A 4 X/A 4 Conowingo 103 0 107 0 112 0 U7 0 Delmarva 4go(-82) 258(o) 515(-102) 1 258(0) 545(-121) 258(0) 575(-144) 258(o) Easton 36.2(-0.2,) 56.5(0) 39.3(-0.1) 56.5(0) 42.6(o) 56.0(0) 46.1(0) 56.0(0) State Totals W/o P/L 1134o(-747) 11674(-1665) 11817(-793) 12283(-lo56) 12363(-813) 12283(-1256) 12869(-874) 13083(-1934) w PA 11470(-617) 11947(-663) 12493(-683) 12999(-744) Sheet 3 of 3 ATTACHMENT NO. 22 concluded AVERAGE OVERALL GROWTH DOUBLING TIME 1986 1987 YEARS UTILITY PEAK LOAD GEN. CAP. PEAK LOAD GEN. CAP. PEAK LOAD GEN. CAP. PEAK LOAD GEN. CAP. B G & E 6080(-150) 6956(-1195) 6370 7698 5.2 4-5 13.6 15.6 PEPCO 4983(-703) 6013(-1575) 5103 6013 3.1 2.0 22.9 34.3 Hagerstown N/A NIA N/A N/A Potomac Edison a 139 (9) 139 Q 0 South. MD Elec 390(-125) 0 413 0 6.1 - 11.7 Coops, Inc* A & N 2 1 2 1 8.0 0 9.0 Berlin N/A 4 NIA 4 N/A 0 - Conowingo 122 0 128 0 4.5 - 15.7 Delmarwa 605(-171) 258(0) 635 258 5.6 0 12.8 Easton 50.0002: 81.0(0) 54.2 80.4 8.4 6.8 8.6 lo.6 State Totals W/o P/L 13332(-1091:12676(-3546) 13888 14054 4.4 3.1 16,1 22.4 W PA 13462(-961) :L4ol8 4.5 15.7 M IF I I I mo ATTACHMENT NO. 2A PROJECTED TEN-YEAR GROWTH IN PEAK ELECTRIC DEMAND AND IN INSTALLED GENERATING CAPACITY IN MARYLAND 1978-1987 PERIOD MEGAWATTS THE POTOMAC EDISON COMPANY Winter 977/78 Winter 1978/79 4 Winter 1 79/80 Winter 1980/81 PEAK LOAD CAP* PEAK LOAD GEN. CAP. PEAK LOAD GEN. CAP.- = LOAD I GEN. CAP. Without 3rd Potline, Eastalco, 1008(0) 139 1072(0) 139 1136(o) 139 1194(0) 139 Frederick Co, With 3rd Potline, Eastalco, 1008(0) 139 1072(0) 139 1171(+35) 139 1324(+130) 139 rederick Co. Winter 19 1/82 Winter 1982/83 Winter 1983/84 Winter 1984/85 1256(o) 139 1300(0) 139 1382(0) 139 1463(0) 139 1386(+130) 139 1430(+130) 139 1512(+130) 139 1593(+130) 139 Winter 1985/86 Winter 1986/87 Average Overall Growth Doubling Time Years 1554(0) 139 1663 139 5.7 0 12.5 1684(+130) 139 1793 139 7.2 0 10.0 Notes: Includes all customers in Maryland, including 3 Sales for Resale customers., Hagerstown., Thurmont and Williamsport Numbers in parenthesis indicate changes from 1977 Ten-Year Plan figures t-I La P) 9 . C+ C+ tAl U 0 co W w H 0 CD 0 (D 1@ A) m 0 C+ C+l 3 C+. L P) 4 Q FJ 0 (D g- q m t 0 I m 0 CD 0 34 co :3 C+ ct 0 Od m 0 t=f (D CD I (D C+ C+* 0 (D C+ :rg r. C+ 4 cr P) 0 0 C+ in-w -y ;L 0 C+ 0 0 C+- cD F-J \0 F6 --j p Fj H o' \0 VI (ON --j m \0 -11 F-i 0 . F --4-3 C+ w --4 OD 0 -4 OD \0 01% tLi 0) C+ 104 \0 0 CD P) OD t-J -4 Ia.H 0 0 Vlt N) VIL ON -N Fi P) CD m 0 1 pu C+ Ia. ;r- @P, o 6 C-1 cl) La W 11-1 P3 Eg @-i n P) C+- (A \0 C+.M --4 @, r. M 'I 03 CD t0d t@ tZI ca 0ct, FJ 0m \0 Z 0 .. 1-i 0 W 4 H -3 co 00 4,-7- \IJI zr- VI CD \0 A t-4 CD t @- -4 @ @ I P, 14 ;a @7- zm @pl zo CD @i 110 0 OD Fl- C', zoo 00 0 0 lic 0 tzj F-i (n 110 CC) v T f, @j T 0 CD \0 X=l 0\\A px m z 4 OD C) i CD @11 000 00 0 VI -ATT, 4F(jAftj - - --- ------ -INA 1 7 4-L, -4-L _L_ 7, -T 17 T-1 ++ + 1-T L4' :44 _ ! i T- 4, -J- -1 i - -- L L, i -1 -T -t f -141 i 4- i 4 1 -i -1 T i- i -,IT -t- 4 A- -4, 4 - -! J- FIL A --L j jj- In J- F 17-1 14- - L+ I- JI L J- A 4- k7 f 7T7 lit i Sheet 1 of 3 ATTACHMENT NO. 5 TEN-YEAR PROJECTIONS OF PEAK ELECTRIC DEMAND, INSTALLED CAPACITYP AND RESERVE MARGIN, 1977 and 1978 TEN-YEAR PLANS OF BALTIMORE GAS AND ELECTRIC COMPANY AND POTOMAC ELECTRIC POWER COMPANY 1978 1979 1980 1981 Peak Gen. Res. Peak Gen, Rese Peak Gen. Res. Peak Gen. Res. Load Cap, Margin Load cap* Margin Load Cape Margin Load Cap. Margin MW Mw % MW w % )w MW % Mw MW % Baltimore "das & Electric 1978 Plan 4020 5162 28.4 4280 5162 2o.6 4510 5162 14.5 4750 5772 21-5 1977 Plan 4130 5282 27.9 4390 5282 20.3 4630 5892 27.3 4880 5892 20-7 Difference -110 -120 0.5 -110 -120 0.3 -120 -730 -12.8 -130 -120 0.8 Potomac Electric(l) Power Comparpr 1978 Plan 3885 5013 29.0 4017 5013 24.8 4142 5013 21.0 4269 5013 17.4 1977 Plan 4151 5010 20.7 4363 5010 14.8 4551 5610 2303 4757 5610 17.9 Difference -266 3 8.3 -346 3 1010 -4og -597 -2,3 -488 -591 -0.5 t (1) En ire System I ills NO INS Ohl MM M M M 0 Sheet 2 of ATTACHMENT NO. 5, continued 1982 1983 1984 Peak Gen. Res. Peak Gen. Res. Peak Gen. Res. Load Cap. Margin Load Cap. Load Cap. Margin MW w % w w w w % Baltimore Gas & Electric Ln 1978 Plan 5000 5721 14.4 526o 6331 20.4 5530 6331 14.5 1977 Plan 5130 6451 25.7 5400 6451 19-5 5670 6651 17.3 Difference -130 -730 -U-3 -140 -120 0.9 -140 -320 -2.8 Potomac Electric Power Company 1978 Plan 4453, 5613 26.o 4594 5613 22.2 4749 5613 18.2 1977 Plan 4989 6410 28.5 5145 6410 24.6 5301 6410 20.9 Difference -536 -797 -2.5 -551 -797 -2.4 -552 -797 -2,7 Sheet 3 of 3 ATTACHMENT NO._5,, concluded 1985 1986 1987 Peak Gen. Res, Peak Gen. Res. Peak Gen Res. Load Cap. Margin Load Cap. Margin Load Cap: Margin w MW % MW w % Baltimore Gas & Electric 6370 7698 20.8 1978 Plan 5800 6731 16.1 6080 6956 14.4 1977 Plan 5940 6951 17.0 6230 8151 30.8 - - - Difference -1-40 -220 -0.9 -150 -1195 -16.4 Potomac Electric Power Comparw 1978 Plan 4866 6013 23.6 4983 6013 20.7 5103 6013 17.8 1977 Plan 5456 7588 39-1- 5691 7588 33.3 - - - Difference -590 -1575 -15-5 -708 -1575 -12.6 M M M M M M ATTAcm4w NO. 6 ESTDILI*D RMEM IN (nWALUW) 20 1. 0 3.__ .00, Nb .32_ ----- - ------ J 1 1.578 1979 :L5 80 1@81 1983 1 1584 [email protected] 1506 1987 4- - NA___ Favo Sheet 1 of 2 ATTACHMENT NO. 7 TIME SCHEDULE FOR IMPLEMENTING W., ELECTRIC GETERATING PLANTS IN MARYLAND, 1978 - 1987 Period 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 Baltimore Gas & Electric Brandon Shores (F) 61o unit #1 ---*A 610 Unit #2 06 Sollers Point 100 Peaking Units 2 Safe Harbor (H) S Northeastern Maryland (F) - - - - - - - - - - - - - - - - - - - goo - - - - - - - - - - - - - - - - - - - - - - - - - - 00 Conowingo Power Company 1100-15001 indefinite construction and in-service dates Canal (N or F) -d7a es - - - - - - - - - - - - - - - - - - - 11070-1560; 1ndeha_te_c;n_stiu;t1o; Zna 1n7-sZr7A;e t7 Bainbridge (N or F) -110-0-15607 1n9e?i;iie_c;n_st;u;t1o; ind 1n_-s;rv_i;e_d7at;s - - - - - - - - - - - - - - - - - - - Seneca Point N or F) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Easton Utilities Commission Plant No. 2 (0 - D) 12 First 2 units 44 12,5 -A Third unit Potomac Edison Company no plans for development in this site Point of Rocks - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Potomac Electric Power Co. indefinite construction and in-sez-vice dates Douglas Point (N) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Dickerson Addition (F) 800 unit #4 Chalk Point Addition (F) 630 Unit #4 91!1 indefinite construction and in-service dates Station J (P/S H) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Southern Maryland Coop. possible generation site De La Brook Farm - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Sheet 2 of 2 ATTACHMENT NO. 7s concluded KEY 0 Date of Initial Construction (N) - Nuclear-rueled In-Service Dates (F) - Fossil-Fueled (0 - D) - Oil-Fired Diesel (P/S H) - Pumped Storage Hydroelectric cn, (?) - T!ype of Fuel Undecided Numbers on horizontal lines denote planned capacity in megawatts. APPENDIX B ELECTRICITY CONSUMPTION IN MARYLAND THE NEXT TEN YEARS Prepared by The Electrical Energy Forecasting Unit, Division of Planning Research Programs, Maryland Department of State Planning B-1 INTRODUCTION Over the years, the demand for electricity in the State of Maryland has remained generally consistent with national trends, and this consistency is anticipated for the future. In the decade preceding the 1973 oil embargo, rising incomes, gererally steady electricity prices, industrial expansion, and a growing population caused rapid growth in Maryland's consumption of electric energy. As Table B-1 indicates, the State experienced a growth rate even higher than that of the nation as a whole. Between 1962 and 1973 national consumption rose 8.5% in the residential sector and 6.9% in the nonresidential sector, while the State of Maryland recorded growth rates of 10.39% and 9.29% respec- tively in these two sectors. This steady and rapid exponential growth was ended in 1974 by sharp energy price increases and the deep recession which followed. Both national and State electrical energy consumption figures exhibit virtually no growth between 1973 and 1975. The impact of these events upon'energy usage was greater in Maryland than for the rest of the nation. Since 1975, State and national consumption has again resumed growth, largely due to the expansion of the economy and the modera- tion of the rates of increase in electricity prices. Despite the resumption in the growth of demand, however, it is not generally expanding at rates approach- ing the pre-1973 era, and as Table B-2 clearly indicates, forecasters at both the national and State level expect the rate of future expansion to be far below that of the 1960's. In fact, expansion over the next ten years is expected to proceed at rates slightly lower than those over the last two years, since the 1975-1977 growth rate reflects the extraordinarily depressed base figure recorded for 1975. Electric energy is normally measured in kilowatt hours. One kilowatt hour (kWh) is the amount of electricity required to power a 100 watt light bulb for ten hours. This is the unit in which electricity is normally sold to consumers. It is also common for utilities to express total sales in megawatt- hour units (MWh), where one megawatt-hour equals 1,000 kilowatt hours. Although an annual kilowatt-hour forecast indicates a community's future energy needs, a planner is also interested in "demand" -- the amount of power being drawn from a system by electricity consumers at any given instant in time. Peak demand refers to the maximum level of demand on a utility system within a specified time period (for example, a year). It is commonly measured in kilowatts (W) or megawatts (MW). Peak demand is an important concept because it indicates the total electricity generating capacity required to service the needs of electric power customers. The following pages briefly examine the basic factors which govern energy consumption, and which determine the methods and accuracy of forecasting energy demand in the State. B-2 Table B-1. Electric energy sales in Maryland and the US U. S. Maryland Year (Billions of kWh) Mllions of kWh) Residential Non-Residential Residential Non-Residential 1962 226.4 549.7 3,145 6,879 1963 241.7 589.9 3,425 7P491 1964 262.0 628.3 33,789 8,307 1965 281.0 672.4 4,229 9,081 1966 306.6 732.4 4,792 10,220 1967 331.5 775.5 5,196 11,209 1968 367.7 834.6 5,990 12,268 1969 407.9 899.3 6,700 13,497 1970 447.8 943.6 7,483 15,004 1971 479.1 987.4 7,919 16,311 1972 511.4 1,066.3 8,406 17,005 1973 554.2 1,149.0 9,330 18,270 1974 555.0 1,145.8 9,200 17,910 1975 586.1 1,146.9 9@598 17,859 1976 613.1 1,236.6 10,064 19,837* 1977 652.3 1,298.5 10.4718 20,935 Average Annual Compound Growth Rates 1962-73 8.5% 6.9% 10.39 9.29 1973-75 2.8% - .1% 1.43 -1.13 1975-77 5.8% 6.2% 5.67 8.27* Service to the Eastalco aluninum plant was initiated in 1976. Sources: CEIR 1975 Table 2.1; Electric World (3/15/78 and 3/15/73); Annual Reports of the Electric Utilities in Maryland, Edison Electric Institute, Statistical Yearbook of the Electric Utility Industry 1976 B-3 Table B-2. National and Maryland projected electric energy consumption and peak demand (consumption in billions of kilowatt hours and peak demands in millions of kilowatts) National State Year Residential Non-Residential Total Peak Residential Non-Residential Total Peak Demand Demand 1977* 6S6.5 [email protected] 1,949.2 398.2 10.718 20.935 31.653 9.438 1980 764.3 1)473.1 2P237.4 474.9 11.990 24.858 36.847 10.186 1985 958.8 1.%873.7 2.%832.5 621.3 1S.626 31.S42 47.168 12.179 1987 1,039.0 2,066.4 3$105.4 688.3 16.393 34.495 50.888' 13.098 Average Annual Compound Growth Rates 1977-80 S.20 4AS 4.70 6.OS 3.81 5.89 5.20 2.57 1980-8S .4.64 4.93 4.83 S.S2 5.44 4.88 5.06 3.64 1985-87 4.10 5.02 4.71 5.25 2.42 4.58 3..87 3.70 1977-87 4.70 4.80 4.77 5.63 4.34 5.12 4.86 3.33 *National peak demand for 1977 is estimated, and all other 1977 figures are actual Sources: For Maryland, the PEPCO and BG&E portions are Maryland Department of State Planning forecasts, and the remainder are company projections I oil M M DETERMINING ELECTRICITY USAGE During the pre-embargo years, utility planners and forecasters for Maryland and the nation could expect energy sales to increase at a predictable, steady rate. This is no longer the case, and forecasting has become far more difficult and complex than in the past. At the same time, accurate demand projections have never been more important. Failure to anticipate and plan for increased demand may result in disruptions of service to customers, in undue cost increases if there is a shortage of total generation capacity, or In inefficient mix of generating plants. On the other hand, overestimating future demand risks imposing an unnecessary burden on the community for support- ing the additional cost of idle generating capacity that has been constructed too far ahead of demand. In this context, it is necessary to focus sharply on the underlying determinants of both past and future consumption. As mentioned previously, it is no longer reasonable to believe that elec- tric energy consumption will continue to grow as rapidly or steadily as in the pre-embargo past. The nation's experience from 1973 to 1975 serves as convinc- ing evidence that consumption patterns are highly sensitive to such factors as electricity price and income. As Table B-3 illustrates, a considerable rise in electricity price has occurred in Maryland since 1973. Moreover, the bulk of this price increase took place between 1972 and 1975, with only moderate in- creases in price in the following two years. Correspondingly, we observe stagnant demand over the 1973-1975 period and moderate recovery thereafter. This pattern, of course, cannot be attributed solely to price changes; it is also a function of the general behavior of the U.S. economy. Residential consumption of electricity is based largely upon housing characteristics (e.g., percentage of apartment units), and the extent of the use of electric appliances, which, in turn, is likely to be dependent upon household income, the price of electricity, and, for certain appliances, the price of alternative fuels (e.g., consumers decide on the basis of relative fuel prices between gas and electric heating). Recently, the availability of natural gas, as well as its price, has become a significant influence. For a given stock of electrical appliances, electricity prices and weather conditions will determine the extent to which the stock is utilized, and changes in these factors will determine the short run changes in the residen- tial use of electricity. For example, an increase in electricity price will Induce consumers to run airconditioners less frequently. Finally, it may be assumed that a "conservation ethic," distinct from high energy prices, may also influence residential consumption. Energy consumption in the nonresidential sector is obviously closely related to the total output of the economy, and consequently does not exhibit rapid growth during slowdowns in overall economic activity. In addition, the nonresidential sector is extremely heterogenous, consisting of such diverse subsectors as government, farming, manufacturing, trade, and services, some of which are greater energry users than others. Thus, as shares of output shift among these subsectors, electricity consumption growth is correspondingly B-5 Table B-3. Typical monthly electric bills 1972, 1974, 1977 (current year dollars) Company 1972 1975 1977 % Change % Change 1972-1975 1975-1977 BG&E Residential 1S.30 23.39 24.07 42% 3% Commercial 61.20 87.12 93.53 35% 7% Industrial 1,449 2.1387 23,375 49% 1% PEPCO Residential 10.35 18.65 19.77 57% 6% Commercial 47.85 76.65 84.97 46% 10% Industrial 1,297 2,381 2.1868 S9% 19% Delmarva Residential 13.19 22.93 23.17 54% 1% Potomac Edison Residential 10.62 18.35 17.57 53% - 4% State of Maryland Residential 13.83 21.97 22.78 45% 4% Commercial S9.05 85.44 92AS 37% 8% Industrial 1,42S 2P386 2)454 50% 3% Source: Typical Electric Bills, Federal Power Commission, 1972, 197S, and 1977 Definitions: Bills are based on prevailing rates on the first day of that year. Residential, 500 kWh per month; Commercial, 1,SOO kWh and 12 kW per month; Industrial, 60,000 Wh and 300 kW per month L B-6 affected. A decline in the relative size of the primary metals industry, for example, would probably serve to restrain energy demand growth despite overall growth of the national economy. In addition, a corporation is not necessarily committed to a fixed electricity-to-output ratio, and can alter it by adopting different and possibly improved technologies. The decision to switch techniques (and thus energy usage) is influenced by the price of electricity relative to the price of competing inputs -- the prices of labor, capital, and substitute fuels. For example, if the price of electricity rises relative to the cost of capital, firms might respond by improving building insulation. This would tend to save on electricity usage while using more capital. Although such factors as relative prices and income affect electricity usage, a long period of adjustment is normally required before the full effect, or even most of the impact, is fully manifested. If gas prices rise relative to electricity, households will not simply abandon gas appliances. Consumers do not immediately translate higher incomes into larger houses. Businesses cannot instantly install electricity-conserving equipment in response to current price increases for electricity. These responses do come, but they are spread out over time, and in some cases extremly long periods of time are required. It is interesting to note In Tables B-3 and B-5 that electricity price increases in the 1975-1977 period have been quite modest (in fact, less than the overall rate of inflation) and income gains considerable, yet consumption growth is considerably slower than the pre-embargo period. This result stems in part from the fact that customers were adjusting to the massive price increases of an earlier period. Moreover, even during the next several years, consumers and businesses will be in the process of completing their adjustments to price changes of the early 1970's. FORECASTING FUTURE USAGE THE NEXT TEN YEARS The Electrical Energy Forecasting Unit of the Maryland Department of State Planning, is preparing forecasts for the major utility systems operating in the State of Maryland. To date, forecasts on Potomac Electric Power Company and Baltimore Gas and Electric Company have been completed. These forecasts use statistical models to estimate the various impacts of the aforementioned factors (e.g., electricity price, income, etc.) on electricity usage patterns. Future values of these factors, based both on judgment and official government project- ions are then inserted into the statistical model to produce projections of future electricity consumption. This method is commonly referred to as a structural econometric approach, and possesses the advantage of explicitly and quantitatively expressing the impacts of important determinants on electric energy consumption. Since the Department of State Planning has not yet made projections on the other Maryland utility systems -- Delmarva Power and Light Company of Maryland, Potomac Edison Company, Easton Utilities Commission, and Conowingo Power Company the forecasts prepared by the companies themselves are presented in Table B-5 In some cases, minor adjustments to company figures were required in order to B-7 achieve consistency in the presentation. These companies used various techni- ques to make their forecasts. Potomac Edison and Easton Utilities relied heavily on time trending, assuming that future growth will proceed at the same rate as past assuming that future growth will proceed at the same rate as past growth. Delmarva employs a methodology that is similar in some respects with that used and advocated by the Maryland Department of State Planning. Statis- tical models were used to determine the impact on electricity consumption of various factors including population, employment, manufacturing and non-manufac- turing earnings, weather conditions, disposable income, use of air conditioners, and electricity prices. To project peak demand, the data were weather-adjusted to historically normal conditions, and the historical relationship was ascer- tained between peak demand, income, and air-conditioner ownership. These estimated relationships were then used as the basis for the company's forecasts. The following tables present past and forecasted electric energy sales and the annual peak demand for the five major bulk suppliers of electricity in the State. Energy sales are measured in megawatt hours (each megawatt hour equals 1,000 kilowatt-hours), and the peak demand figures are in megawatts. The final table compiles the State-wide totals from the five suppliers. In addition, many Maryland households and businesses purchase their electricity from municipally owned systems and electric power cooperatives. However, these municipal systems and cooperatives purchase power wholesale from one of three major suppliers -- Delmarva, Potomac Edison, or PEPCO, and then sell the power to their own retail customers. Thus, the figures presented for these three companies include the bulk sales to municipal systems and cooperatives, which, in turn, were divided into residential and nonresidential segments accord- ing to the same proportion as was found to exist (or projected to exist) in the retail sales of the bulk supplier. It was explained earlier that a utility's annual peak demand is the maximum amount of demand for power during the year. Although this definition applies for each of the five systems, it is not true for the State as a whole, since the individual systems annual peaks used to tabulate the State total do not occur simultaneously. For example, PEPCO's peak normally occurs in July or August while Potomac Edison's occurs in December or January. In other words, the State peak demand figure should not be interpreted as the maximum amount of demand for power in Maryland at any one time during the year. It is merely the sum of the annual peak demands of the five systems operating in the State. However, the statewide figures are still useful for making year-to-year comparisons. Also, peak demand is measured as the maximum system power sent out at any hour during the year. This system peak cannot be broken down geographically with precision, and most utilities do not even attempt to do so. Thus, the peak demand figures for PEPCO and Potomac Edison, multistate companies, are systemwide and therefore extend beyond Maryland's boundaries. Thus, the Maryland total also includes the D.C., Virginia, and Pennsylvania portions of the PEPCO and Potomac Edison load. The forecasts presented in Table B-5 are based upon certain expectations concerning the underlying determinants of electricty consumption. The econo- metric forecasts reflect these expectations explicitly, and other methods embody other implicitly formulated assumptions. Table B-4 presents the projec- tions on population, employment, and real per capita income prepared by authori- tative sources. All three variables are projected to increase, but at rates somewhat less than the rapid expansion experienced during the pre-embargo B-8 Table B-4. Projected average annual compound growth rates on population, employment, and real per capita income Region 1975-80 1980-1985 1985-1990 A. Population Baltimore Area 1.19 1.22 1.28 Easton Shore .83 1.18 1.15 Southern Maryland 1.08 2.14 1.54 Washington Suburban 1.48 1.47 1.75 Western Maryland .40 .61 .73 State of Maryland 1.19 1.26 1.39 B. Employment Baltimore Area 1.68 1.60 1.39 Eastern Shore 2.02 1.30 1.38 Southern Maryland .82 1.46 1.67 Washington Suburban 3.39 2.72 2.30 Western Maryland 1.68 1.13 1.08 State of Maryland 2.16 1.88 1.65 C. Real Per Capita Income State of Maryland 3.25 2.60 2.60 Sources: Maryland Projection Series Population and Employment 1975-1990, Maryland Department of State Planning, 1977; 1972 OBERS Projec- tions of Regional Economic Activity in the U.S., U.S. r Resources Council,, 1972 B-9 Table B-5a. Baltimore Gas and Electric* Year Energy (Alh) Peak Residential Non-Residential Total Demand 1966 25,347.9000 6,306,000 8,653,000 1,817 1969 3,28S,000 7JI880,000 11,165,000 219306 1972 4,102,000 8)889)000 12,991,000 23,960 197S 4,664,000 9,194,000 13.%858.4000 3,256 1977 S.9231.4000 10,231,000 15,462,000 31588 1980 5,553,000 12.10035,000 17.%556,000 3,SlO 198S 7.9175,000 15,886,000 23,061,000 4,418 1987 8.9009,000 17,611,000 25,620,000 42833 Average-Annual Compound Growth Rates 1966-72 9.75% 5.89% 7.01% 8.47% 1972-75 4.37% 1.13% 2.18% 3.23% 1975-77 5.90% 5.49% 5.63% 4.97% 1977-80 1.99% 5.47% 4.32% .73% 1980-85 5.26% 5.77% 5.61% 4.71% 1977-87 4.35% 5.58% 5.18% 3.02% *Forecasts are Maryland Department of State Planning figures B-10 Table B-5b. Conowingo Power Company* Year Energy (MVh) Peak Residential Non-Residential Total Demand 1966 77,1148 1403,967 218,115 42 1969 107,195 1753,886 283,081 56 1972 148,949 177,225 326,174 67 1975 193,741 185,488 379,229 78 1977 201.%467 218,459 419,926 85 1980 242,000 240,686 482,686 94 1985 328,300 290.9236 618,536 117 1987 366,200 313,956 680,156 128 Average Annual Compound Growth Rates 1966-72 11.59% 3.89% 6.94% 8.09% 1972-75 9.16% 1.53% 5.15% 5.20% 1975-77 1.97% 8.52% 5.23% 4.39% 1977-80 6.30% 3.28% 4.75% 3.41% 1980-85 6.29% 3.81% 5.08% 4.47% 1977-87 6.16% 3.69% 4.94% 4.18% Forecasts are company figures B-11 Table B-5c. Easton utilities* Year Energy Peak Residential Non-Residential Total Demand 1966 10,074 29,586 39,660 10 1969 15J1456 39,999 5S,455 13.5 1972 22,554 493*129 71,683 17.1 1975 26,925 59,080 86,OOS 20.4 1977 3110370 66)333 972703 22.3 1980 42,189 89,211 131,400 30.9 1985 613%878 130,842 1922720 46.1 1987 72.9847 1542037 226,884 54.2 Average Annual Compound Growth Rates 1966-72 14.38% 8.82% 10.37% 9.35% 1972-75 6.08% 6.34% 6.26% 6.06% 1975-*77 7.94% 5.96% 6.58% 4.55% 1977-80 10.38% 10.38% 10.33% 11.49% 1980-85 7.96% 7.96% 7.96% 8.33% 1977-87 8.79% 8.79% 8.79% 9.29% Forecasts are Easton Utility Commission figures. Easton does not provide a residential/non-residential breakdown for its projected energy sales. These figures were obtained by multiplying the projected total by the 1977 actual proportions. B-12 Table B-5d. Delmarva of Maryland* Year Energy (N51h) Peak Residential Non-Residential Total Demand W 1966 263,935 397,602 661,537 141 1969 384,606 546,410 931,016 197 1972 527,652 692,019 13,219,671 278 1975 651,955 800,041 1,451,996 342 1977 793,521 933,030 19726,551 400 1980 951,828 1,169.1854 2,121,682 43S 1985 1,291,274 1,579,392 2,870,666 575 1987 1,436,701 1,788.181S 3,225,516 635 Average Annual Compomd Growth Rates 1966-72 12.24% 9.68% 10.73% 11.98% 1972-7S 7.31% 4.9S% 5.98% 7.15% 1975-77 10.32% 7.99% 9.05% 8.15% 1977-80 6.25% 7.83% 7.11% 2.84% 19,180-85 6.29% 6.19% 6.23% 5.74% 1977-87 6.12% 6.73% 6.45% 4.73% Forecasts are company figures B-13 Table B-Se. Potomac Edison, Maryland Portion* Year Energy (Hlh) Peak Residential Non-Residential Total Demand (MW) 1966 495,2S9 944,149 1,439,408 512 1969 681,153 1,2S1,144 1,932,297 673 1972 902,604 2,784,419 3,687,023 1,099 197S 1,131,080 2,792,257 3,923,337 1,359 1977* 1,291,892 43-312,187 5,604,079 1,486 1980 1 10640,703 S,562,721 73,203,424 1,925 1985 2,411,833 7.9231,537 9,643,370 2,630 1987 2.q749,490 8,027,006 1O.p776,496 2,995 Average Annual Compound Growth Rates, 1966-72 10.S2% 19.7S% 16.97% 13.S8% 1972-7S 7.81% .09% 2.09% 7.33% 1975-77** 6.87% 24.27% 19.52% 4.57% 1977-80 8.29% 8.86% 8.73% 9.01% 1980-8S 8.01% S.39% 6.01% 6.44% 1977-87 7.8S% 6.41% 6.76% 7.26% Forecasts are company figures. The company forecasts on a systemwide (multistate) basis only. To obtain the Maryland megawatt hour projec- tions the systemwide forecasted growth rates are applied to actual 1977 Maryland consumption. In 1976 Potomac Edison initiated service to the Eastalco aluminum plant. B-14 Table B-5f. Potomac Electric Power Company (Maryland Portion) Year Energy (Mvli)* Peak Residential Non-Residential Total Demand 1966 1,488,701 2)1371,608 3,860,309 2,123 1969 2,111,689 33,577,122 5@68819811 2.1759 1972 2,589p262 4,491,480 7,O8Op742 314479 1975 2,929,826 4P827J,844 7,757,670 3,623 1977 3,168,272 519173p975 8p342p247 33*857 1980 3,599,900 5,792,300 9,352,200 4,191 1985 4,357p7OO 6p423p6OO 10)781,300 4,393 1987 4.1758.4600 6.4599,900 11,358p5OO 4,453 Average Annual Compound Growth Rates 1966-72 9.66% 11.23% 10.64% 8.S8% 1972-75 4.21% 2.44% 3.09% 1.36% 1975-77 3.99% 3.52% 3.70% 3.18% 1977-80 3.96% 3.83% 3.88% 2.80% 1980-85 4.13% 2.09% 3.90% .95% 1977-87 4.15% 2.46% 3.13% 1.45% Includes sales to a1ECO. For future years projected sales to SMECO are broken down as residential and non-residential according to 1972 actual SMECO proportions. B-15 Table B-5g. The State of Maryland Year Energy (Mqh) Peak* Residential Non-Residential Total Demand W) 1 1966 416823,117 10,189,912 143,872,029 4,645 1969 6,585,099 13.1470,561 201055,660 6,005 1972 8,293,021 17,083y272 25,376,293 7,900 1975 9y597,527 1711858,710 27,456,237 8,678 1977 10,717,522 20y934,984 31,652,506 9,438 1980 11,989y620 24p857.9772 36,847p392 10,186 1985 l5y625,985 31,541y607 47pl675,592 12.9179 1987 173,392.%838 34,494,714 51,887,SS2 131098 Average Annual Compound Growth Rates 1966-72 10.00% 8.99% 9.31% 9.25% 1972-75 4.99% 1.43% 2.66% 3.18% 1975-77 S.67% 8.27% 7.37% 4.29% 1977-80 3.81% S.89% 5.20% 2.57% 1980-85 5.44% 4.88% 5.06% 3.64% 1977-87 4.96% 5.12% 5.07% 3.33% Peak demand digures include West Virginia, Virginia, D.C., and Pennsyl- vania loads in the PEPCO and Potomac Edison service territories. B-16 decade. Inasmuch as there are no official projections on the future course of electricity price in the State of Maryland, it is assumed that future prices will probably rise at least modestly above the rate of inflation.* These factors, along with the delayed adjustments to 1972-1975 price increases, should serve to restrain demand below the pre-embargo growth rates. Several factors are working the other way to increase future consumption. Although the population growth rate is expected to be lower in the future than in the past, the expected increase in the household formation rate will mean that the number of electricity customers is expected to grow considerably faster than population. Furthermore, natural gas, a major substitute for elec- tricity, is expected to rise in price even faster than electricity, encouraging a corresponding fuel substitution. In addition, the supply restrictions on new gas hook-ups mandated in the early 1970's in Marland, are expected to continue over portions of the next ten years. These observations apply to future growth of both energy consumption and peak demand. Peak demand is also expected to grow at a slower rate than in the pre-embargo past. As Table B-5 illustrates for most utilities and the State, it is expected to rise at a slightly lower rate than annual energy consumption. In the past, an important factor in the growth of peak demand has been the increasing utilization of air-conditioning in the residential and commercial sectors. However, in many areas of the State, particularly the wealthier suburban counties, the market for air-conditioners is reaching saturation. Thus, the impact of airconditioning on peak demand growth will be somewhat weaker than in the past. Additionally, for most Maryland utilities,** peak demand occurs during the summer months. Over the forecast period, electric space heating is expected to be installed in a large percentage of new homes -- far larger than in the past -- a trend based at least in part upon the price and availability problem associated with natural gas. This, of course, boosts the growth rate of electricity consumption, but will have little effect on peak demand in the summer peaking utility systems. Considering the current lead times required for constructing new additions to generating capacity, electricity consumption and peak demand must be projected at least ten to fifteen years into the future. However, the state-of-the-art limits the forecaster's ability to produce reliable long-range projections. Since future demand depends on what happens to those factors that affect usage (i.e., energy prices, income, population, employment, etc.) predictions on future electricity usage can be no more reliable than the long-range projections of those factors. An accurate forecast of electric power usage in Marylad in 1987 requires precise information regarding the Maryland economy and energy prices over the next ten years, Moreover, some of these determinants of electricity demand are subject to policy changes at both the national and state levels. Examples of public policies which will affect these factors include federal initiative to deregulate See the discussion in Chapter 5 on electricity price in the forthcoming Projected Electric Power Demands for the Baltimore Gas and Electric Company, Maryland Department of State Planning, 1978. Potomac Edison is the only large winter peaking utility in the State. B-17 interstate natural gas transactions, and the introduction of new building codes to alter insulation standards. Additionally, there is currently great interest in the reform of electric utility rates. Proposed changes would alter rate structures so as to price electricity according to season or time of day. The purpose of this proposed reform is to reduce the growth of peak demand. The difficulty of anticipating these kinds of policy actions introduces substantial uncertainty into the forecasts, even when the importance of such policies is fully appreciated. It is within this environment of considerable uncertainty that demand forcasts must be formulated. It is no longer reasonable to assume that future demand growth will procede at the same rate as in the past. The Maryland Depart- ment of State Planning has produced forecasts of electric energy consumption and peak demand for two utility systems -- PEPCO and BG&E -- which specifically account for the impacts of the various major causal factors. Future efforts along similar methodological lines will result in the Department of State Plan- ning's production of forecasts for Maryland's other two large electric utilities -- Delmarva Power and Light and Potomac Edison. Updates will also be periodi- cally performed in order to incorporate the best and latest information avail- able into the forecasts. Eventually, then, electricity usage in virtually the entire State of Maryland will be forecasted using structural econometric models. B-18 REFERENCES -- APPENDIX B 1. Annual reports of the Maryland electric utilities - 1966, 1969, 1972, 1975, 1977. 2. Appendix to System Long Range Electric Load and Energy Forecast, Delmarva Power and Light, 1978. 3. Statistical Year Book of the Electric Utility Industry, Edison Electric Institute, 1976. 4. Electrical World, September 15, 1977 and March 15, 1978. 5. Typical Electric Bills, Federal Power Commission, 1972, 1975, 1977. 6. "Electric Power Consumption in Maryland and the U.S.," Maryland Department of State Planning, 1976 (draft report). 7. Maryland Projection Series - Population and Employment 1975-1999, Maryland Department of State Planning, 1977. 8. Projected Electric Power Demands for the Baltimore Gas and Electric Company, Maryland Department of State Planning, 1978 (forthcoming). 9. Projected Electric Power Demands for the Potomac Electric Power Company, Maryland Department of State Planning, 1975. 10. Cumulative Environmental Impact Report, Maryland Power Plant Siting Program, 1975. 11. "Ten-Year Plans of Maryland Electric Utilities, Possible and Proposed Power Plants, 1978 through 1987," the Public Service Commission of Maryland, 1978. 12* 1972 OBERS Projections of Regional Economic Activity in the U.S., U.S. Water Resources Council, 1974. B-19 t I a I a i a I I I A 1, ,Wk i i I i i ---- 3 6668 00002 1081 46 1,1,