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

            Impacts of Coastal Energy Development
                                      on New Jersey-fs Shorefront
                Recreational Resources and Economy

                                  The New Jersey Department of Environmental Protection

                                                                       Study Report
                                                            Appendix Volume 2

                                                          Appendix B: Facility Descriptions

                                                                 Rogers, Golden & Halpern
                                                                 Philadelphia, Pennsylvania
    04

                                           APPENDICES VOLUMES

               Volume 1.     Appendix A. User's Guide

               Volume 2.     Appendix B. Facility Descriptions

               Volume 3.     Appendix C. Facility Impact Assessment Matrices

                             Appendix D. Environmental Change Schedules for Coastal
                                          Energy Facilities

                             Appendix E. New Jersey Shoref ront Tourism Regions

                             Appendix F. Questionnaiee Used for Group Estimation

                             Appendix G. Tourism Response Coefficients

                             Appendix H. New Jersey Shore Municipalities' Attitudes
                                          Towards Development and Preservation

                             Appendix 1. Municipal Data File

               Volume 4.     Appendix J. Case Studies

                  Zr- Z-

                                                    Note to Readers

                      Changes in the descriptors of five of the six tourism regions used in the stu    dy
                Impacts of Coastal Energy Development on New Jersey's Shorefront Recreational
                Resources occurred after final editing of this appendix volume and are not included in it.

                      Consequently, the reader is asked to substitute the descriptors found in this volume
                (listed below, left) for those found in the summary report (listed below, right).

                         Former Version                                           Final Version

                Densely Settled Commuter Suburb                        Non-Seasonal Suburban

                Northern Shorefront Year-Round and                     North Shore Non-Seasonal/Rural
                 Rural Community

                Northern Shoref ront Seasonal                          North Shore Seasonal
                 Communities

                Southern Shore Year-Round and Rural                    South Shore Non-Seasonal/Rural
                 Community

                Southern Shoref ront Seasonal                          South Shore Seasonal
                 Communities

                      The tourism region Resort Gambling remains unchanged.

                                 APPENDIX B. ENERGY FACILITY DESCRIPTIONS

                     The magnitude, composition, and timing of the environmental., social, and economic
               impacts of developing energy facilities in coastal areas are dependent upon the
               characteristics of the energy facility under consideration.     A comprehensive policy
               planning tool such as the Coastal Tourism Model depends on an understanding and a
               specification of the functions, purposes, inputs, and impacts of each of the 15 energy
               facilities being considered within the model. A primary component of the model is
               therefore the set of 15 energy facility descriptions which contain information that
               permit model users to begin to proceed along each of the three impact paths.           In
               addition, the descriptions contain information which provide model users with a base of
               knowledge about the various facilities.

                     The 15 energy facilities are presented as follows:

                     0    Support Base
                     0    Oil and Natural Gas Pipelines
                     0    Oil Pumping and Gas Compressor Station
                     0    Gas Separation and Dehydration Plant
                     0    Gas Treatment Plant
                     0    Natural Gas Liquids (NGL) Fractionation Plant
                     0    Peak Shaving Facility
                     0    Tank Farm

                     0    Nuclear Power Plant

                     0    Coal-Fired Power Plant
                     0    Cogeneration Facility
                     0    Resource and Energy Recovery Facility
                     0    Electric Transmission Line
                     0    Coal-Handling Terminal
                     0    Offshore Oil Port

                     The  accompanying energy facility descriptions contain the following components:

                     0    Facility Descri ption: Presents the purpose and functions of each facility, along-
                          with identification of its major components and design configurations.

                                                         B-1

                      0    Facility Size/Land Requirements: Notes the range in design capacities or
                           throughputs based on existing technology. Land requirements as a function of
                           size are also given.

                      0    Site Parameters: Lists the features of the physical and man-made environ-
                           ments which each facility requires for cost-effective development at a given

                           site.

                      0    Capital Costs: Capital costs as a function of size are presented in fourth
                           quarter, 1982 dollars.

                      0    Employment Profile: Describes on an annual basis the manual and non-manual
                           components of both the construction and operating labor forces over an
                           eleven-year period for the size of the facility most likely to be developed
                           within the study area.

                      0    Environmental Impacts: Describes the significant environmental impacts by
                           category that would accompany facility construction andoperation.

                      The descriptions utilize some of the information contained within the Coastal
                Energy Facility Development Potential Study. The descriptions of facility processes and
                design alternatives are more detailed in the Development Potential Study and interested
                readers are referred to that document. In addition, the Development Potential Study
                also contains much more useful data on how the site parameters influence the economics
                of facility development at a particular site.

                      Each facility description is accompanied by a Facility Impact Assessment Matrix
                and an Environmental Change Schedule. Each facility's matrix presents the type and
                time of occurrence of the on-site activities during the construction and operation phases.
                Listed for each activity are the direct impacts associated with these activities. The
                Environmental Change Schedule lists the probability of occurrences of environmental
                changes that will produce corresponding changes in the tourist visitation patterns. These
                two components of the model are the primary mechanism for translating facility-related
                environmental impacts into losses of tourism. The Environmental Change Schedules for

                                                           B-2

                each facility are contained in Appendix D.            The assumptions and information
                incorporated into producing both of these items, along with an explanation of the how to
                interpret the data presented on them, is contained in Impact Path 3, Tourist Response to
                Environmental Impacts.

                      Each of the 15 energy facility types noted previousl      y differs in terms of it's
                probability of ever being located within the study area. This probability for each facility
                is based on a number of factors, including:

                      0    the need for the facility as a function of changes in the market conditions for
                           the type of energy produced, processed, or handled by it;

                      0    the environmental impacts and associated costs of obtaining the required
                           permits associated with the facility's construction and operation;

                      0    uncertainty o the future regulatory and rate-making climates which affect the
                           probable capital cost and accompanyin  g profitability of a facility;

                      0    the availability of suitable sites within the study area;

                      0    diminishing probability that the Baltimore and   Hudson Canyons will prove to
                           have sufficient reserves of oil and natural       gas to warrant commercial
                           development; and

                      0    the public's perception of the environmental and public health risks associated
                           with a facility's construction and operation.

                      Changing market conditions can be the primary determinant in the probability of
                developing a particular energy facility. Changes in market condition can include the
                development of competing facilities in other locations so that likelihood for developing
                such facilities in New Jersey declines. Coal-handling terminals are a prime example, as
                the large number of projects proposed in other states has diminished the probability of
                developing a' facility in New Jersey. Other changes in market conditions can include
                changes in the relative price of an energy product, such as oil, with the result that the
                demand for that product declines.

                                                           B-3

                      The difficulty in obtaining the necessary environmental permits can also affect the
                probability of developing a particular facility. Owners of the Louisiana Offshore Oil
                Port have noted that the difficulty faced in obtaining the necessary environmental
                licenses and approvals for their facility make it highly unlikely that a similar facility can
                be profitably developed elsewhere in the country. In addition, this facility's long-term
                profitability has declined due to increases in the price of oil, which have resulted in a
                decrease in demand in the amount of oil imported into this country.

                      The regulatory uncertainty surrounding the construction of nuclear power plants,
                along with the long lead times required to construct such capital-intensive facilities, has
                diminished the probability of constructing these facilities in the near future.

                      There is a definite lack of suitable sites for some of the energy facilities within the
                study area. Thus, the likelihood of their development within the study area is quite low.
                Facilities include tank farms, an offshore oil      port (assuming one could be profitably
                developed) and a coal-handling terminal. The northern section of the study area in
                Monmouth County is the only part which would have sufficient proximity to navigation
                channels of proper depth. to warrant the expenditure of funds for'dredging of sufficient
                depth to allow coal colliers or tankers access to a coal-handling terminal or a tank farm.
                From Point Pleasant south, the presence of the heavily developed barrier islands makes
                the siting of a tank farm or a coal-handling terminal highly unlikely.

                      Recent cessation of offshore exploration and drilling activity by major oil
                companies in the Baltimore and Hudson Canyons diminished the probability that
                commercial development of these areas will ever take place. As a result, the likelihood
                of developing accompanying ancillary facilities such as support bases, oil or natural gas
                pipelines, or the three natural gas processing facilities has likewise declined.

                      As a result of the consideration of these factors, this study estimates the
                probability of developing each of the 15 energy facility types within the study area over
                the next 10 to 20 years.       Model users should be aware that these probabilities are
                speculative and aer based on the conditions prevailing in early 1983. Future changes,
                such as regulatory reform or. continuing declines in the price of oil, could significantly

                                                             B-4

                affect these probabilities       The probabilities within each group are presented in
                descending order.

                      0     HIGH PROBABILITY (50% or better chance of occurrence)
                                  Resource and Energy Recovery Facility
                                  Coal-Fired Power Plant
                                  Electric. Transmission Lines
                                  Cogeneration

                      0     MODERATE PROBABILITY (less than 50%, but more than 20%)
                                  Support Base
                                  Oil and Natural Gas Pipelines
                                  Oil Pumping and Gas Compressor Stations
                                  Gas Separation and Dehydration Plant
                                  Coal-Handling Terminal
                                  Peak Shaving Facility

                      0     LOW PROBABILITY (20% or less)

                                  Nuclear Power Plant

                                  Gas Treatment Plant

                                  NGL Fractionation Plant

                                  Tank Farm

                                  Offshore Oil Port

                      Each of the fifteen energy facilities also differs in terms of its dependency on
                proximity to water. Water dependency is defined as the necessity of utilizing water as a
                process input (i.e., cooling water for power plants), or the requirement to locate in, or
                immediately adjacent to, a shorefront site. This dependency translates to the probability
                of a specific facility type being sited in a shorefront location should it ever be developed
                within the study area.     The need to utilize water as a process input implies that
                proximity to water is partially a cost-optimization factor. Generally, the closer an
                energy facility location is to the water supply source, the lower the cost is of obtaining
                the water. However, the need for water as a process      input does not automatically imply
                a coastal location. Coal-fired and nuclear power plants can be sited at inland locations
                within the study area if sufficient cooling water supplies are present.

                                                            B-5

                      Some energy facilities require a coastal location as a precondition for feasible
                operation.   Such facilities are usually involved in the transfer of a bulk energy
                commodity from one transportation mode to another. The obvious examples include
                support bases, tank farms, and coal-handling terminals. If any of these facilities are
                ever developed within the study area, they will certainly be sited in coastal locations.

                      Presented below are estimates of each facility type's probability of being located
                in a shorefront location within the study area. These assessments are specific to the
                study area being considered in this report. For obvious reasons, an offshore oil port's
                probability is not considered.

                Probability of One:        Requires an oceanfront, riverfront or bayfront location
                                           adjacent to navigable waters as a precondition for feasible
                                           operation:
                                           o Support Base

                                           o Tank Farm
                                           o Coal-Handling Terminal

                High Probability:          Location in, or as close as possible to, an oceanfront site
                                           maximizes the economic efficiency and technical feasibility of
                                           an energy facility:
                                           �  Gas Separation and Dehydration Plant

                                           o  Gas Treatment   Plant
                                           �  Natural Gas Liquids Fractionation Plant
                                           �  Oil and Natural Gas Pipelines

                      The above four facilities' probabilities assume the presence of OCS oil and gas
                development.

                Moderate Probability:      Proximity to an adequate supply is required; however, the need
                                           for waterfront location does not translate into a need for an

                                           oceanfront location:

                                           o Nuclear Power Plant

                                           o Coal-Fired Power Plant

                                                           B-6

                Low or Zero
                 Probability:             Proximity to a shorefront location or to a water supply source
                                          has minor or no influcence on a facility's location:
                                          o  Oil Pumping and Gas Compressor Station
                                          o  Peak Shaving Facility
                                          o  Cogeneration Facility
                                          o  Resource and Energy Recovery Facility
                                          o  Electric Transmission Line

                                                         B-7

                                                    SUPPORT BASES

                Facility Description

                      Support bases link onshore and offshore activities during all phases of Outer
                Continental Shelf (OCS) oil and gas exploration, development, and production. Materials
                are assembled and stored at these bases for delivery to offshore drilling rigs and
                production platforms. There are three types of support bases:

                      �    bases supporting exploration,
                      0    bases supporting development and production, and
                      �    bases supporting platform and pipeline installation.

                      Bases Supporting Exploration. Temporary support bases are set up during explora-
                tory drilling operations to transfer materials and workers between shore and the offshore
                drilling rigs. Supply and crew boats and helicopters operate from these bases usually on
                a 24-hour, 7-day-week basis, shuttling food, water, fuel, drilling mud, cement, drill pipe,
                casing, and equipment to t  -he rigs and bringing back refuse that cannot be disposed of at
                .sea. Weather conditions and the distance from the offshore drilling locations determine
                whether helicopters or crew boats are used as the predominant mode of crew transfers.

                      Bases Supporting Development and Production. Support bases set up during the
                development or production phases of OCS activities serve basically the sa   me function as
                temporary support bases--i.e., transferring materials and workers between shore and the
                offshore facilities on a 24-hour, 7-day-week basis--but on a larger scale. Permanent
                support bases may be set up by the oil companies involved or by service companies. The
                land is either purchased or leased on a long-term basis. In some cases a decision is made
                to simply expand the existing temporary support base. The company operating the base
                may opt to either bring in other companies such as cement companies, caterers, and
                other specialist suppliers as tenants, or act as an agent for ordering and distributing
                supplies.

                      Bases Supporting Platform and Pipeline Installation. Very similar to the support
                bases set up during the exploratory phase are the bases set up to support installation of
                platforms and pipelines for OCS development. Unless a large volume of work over an

                                                            B-8

                extended period of time is anticipated, these bases are set up on a short-term basis.
                Their main requirements are waterfront warehouse space, and service and maintenance
                facilities for vessels and barges. Road and/or rail access is essential for transporting

                material into the base.

                Facility Size/Land Requirements

                      Bases supporting exploration have up to 20 berths for supply ships, and they require
                f ive acres (ac) per drilling rig being serviced.    Pages 3-33 of the Energy Facility
                Development Potential Study give the vessel requirements during the various offshore
                phases. Approximately five acres per platform being serviced is the required land area
                for a supply base supporting development and production or platform and pipe instal-
                lation. A site with an area of five acres is generally adequate for the installation of a
                pipeline or up to four platforms. For both platform and pipeline operations a minimum
                of 200 feet of wharf is required. An additional 200 feet is preferable for each "spread"
                (about three ships) supporting the platform or pipeline installation operation.

                Site Parameters

                      Siting of support bases involves consideration of several key factors. Properly
                sited facilities should be areas with the following characteristics:

                      0   adequate flood protection
                      0   fresh water delivery capabilities
                      �   high load bearing capacity soils
                      �   relatively flat topography
                      0   access to railroads and highways
                      �   access to an all-weather harbor with an adequate wharf or pier
                      �   reasonable proximity to offshore activity
                      �   access to and availability of ancillary services

                                                          B-9

                Capital Costs

                     The total capital cost for a supply base can be estimated using the following
                equation. Remember that the number of berths required varies with the phase (i.e.,
                exploration, development and production, etc.).
                     Capital Cost   $1,500,000 (NB)

                          Where:

                              NB    number of berths at the support base.

                Sources:
                John F. McMullen, 1981; Rogers, Golden & Halpern, 1979.

                Employment Profiles

                     The level of construction employment at a support base is low, as the primary
                activity consists of site preparation (i.e., grading and clearing, construction of
                docks/wharves and buildings) as opposed to construction of a highly complex processing
                or production facility.

                Construction Profiles:

                                             temporary service base               permanent service base
                manual                                  18                                  34

                Non-manual                               7                                  13

                Total                                   25                                  47

                     Bases supporting exploration and pipeline/platform installation are considered
                temporary bases. Bases supporting development and production are permanent service
                bases. Construction is expected to take six months to one year.

                Operating Equipment:

                     The level of operating employment at a support base varies according to the type
                of offshore activity being supported. Permanent bases have larger employment levels
                due to the amounts of materials and services required by the offshore facilities.

                                                         B-10

                                 helicopter   exploration     development      prod.      pipe./plat.
                                    base          base            base          base      instal. base

                Manual                15           70              93            56            75

                Non-manual             5             5               7            4            10

                Total                 20            75             100           60            85

                Source:
                Roy F. Weston, Inc., July 1978. Methodology for Assessing Onshore Impacts for Outer
                Continental Shelf Oil and Gas Development.

                Environmental Impacts

                Air Waste Disposal

                      During construction, heavy machinery will emit hydrocarbons, carbon monoxide and
                nitrogen oxides during use. Yearly vehicle emission inspection by The New Jersey
                Department of Motor Vehicles should keep emissions within allowable limits.

                      Sources of air emissions during the operation of a support base are:

                      0    evaporation f rom f uel tanks f or the storage of f uel,
                      0    combustion from machinery and vehicles, and
                      p    accidental spills, breaks, etc.

                      The  magnitude of air emissions depends on the volume of delivery, storage, and
                transfer of fuel, supplies, and waste associated with offshore oil and gas operations.

                      Support bases involved in the storage and transfer of dry, pumped cement and mud
                are major sources of dust emissions. Large dust clouds can form as a result of accidental
                spillage or hose blowouts.

                      Recreation and tourism impacts, as a result of support base air waste disposal, are
                anticipated to be minimal. Dust clouds, because of their high visibility, cause the most
                serious potential impact.

                                                          B-1 I

                 Water Use/Water Discharge

                      Support bases commonly have three sources of wastewater, namely sewage, bilge
                 water, and ballast water. Sewage wastes generated by a support base are discharged into
                 municipal sewage treatment systems. The dischar      ge of sewage wastes f rom support or
                 crew boats is controlled by Coast Guard-approved sanitary waste devices. Any system
                 that cannot meet the regulated standards would have to utilize holding tanks for sewage.

                      Bilge and ballast water are generated by work boats utilizing the support base.
                 Bilge water could contain petroleum and heavy metals that would be toxic to marine
                 organisms if discharged into coastal waters.        Ballast water could contain similar
                 contaminants and fecal bacteria that would have a: high biological oxygen demand. As a
                 result, the Coast Guard actively enforces regulations that require bilge and waste water
                 discharges to be made to onshore receptacles or to be released greater than 50 miles to

                 the coast.

                      Impacts to recreation and tourism will be minimal with proper adherence to
                 regulations. Impacts to biota and the aesthetic quality of an area could result because of
                 improper waste water disposal and in turn adversely impact tourism and recreation.

                 Solid Waste

                      During OCS drilling operations, drilling muds and drill cuttings are used to aid the
                 process. Drilling muds are chemical mixtures which are circulated through a well bore
                 during drilling, while drill cuttings are those rock particles displaced during the drilling
                 of a well. The primary functions of drilling muds are to cool and lubricate one drill bit
                 and drill pipe; transport drill cuttings to the surface; and provide hydrostatic pressure to
                 prevent blowouts., (U.S. Dept. of the Interior, 1981)

                      The discharge of drilling muds and cuttings is regulated by NJPDES pe              rmit
                 requirements. Although the discharge at sea of oil-based muds is prohibited, substantial
                 quantities of conventionally-used muds can be discharged at sea. The large quantities of
                 oil-based wastes must be returned to the shore through the service base.

                                                            B-12

                      Because drilling wastes often contain hazardous materials, such as oils, acids         or
                heavy metals, they must be disposed of in secure landfills where there is no danger of
                groundwater contamination, surface water runoff, or evaporation (NERBC, 1978).

                      Solid waste generated by the support base operation can be incinerated, disposed of
                by landfilling, or disposed of with sewage. Little adverse environmental impact is
                anticipated if these materials are disposed of in accordance with existing regulations.
                (NERBC, 1978).

                      Impacts to tourism and recreation are anticipated to be minimal with normal
                operation. However, as with any hazardous waste, the potential exists for groundwater
                contamination and the subsequent diminished usability of an area.

                Noise

                      Because a support base is in operation 24 hours a day, noise is generated
                continually. Sources of noise from a support base include pneumatic power tools, air
                compressors, pumps, compressed air machinery for painting and c        leaning, and industrial

                trucks and cranes.

                      Impacts to tourism and recreation are dependent upon the size of the support base,
                proximity to recreation area and the existence of a buffer zone. In general, a noticeable
                increase in the ambient noise level will detract from the quality of a recreation area,
                and may affect use of the area.

                Aesthetic Impact

                      The aesthetic impact of a support base, in any of the three phases, will depend
                primarily upon the area in which the base is located. In an industrial port, a support base
                would have minimal impact. In an undeveloped port a 24-hour lighted storage facility
                with heavy machinery in continual operation and trucks, trains and boats constantly
                arriving and leaving, would have a much greater aesthetic impact.

                      Impacts to tourism and recreation would be dependent upon the size of the support
                base, the amount of activity generated, and the existence of a buffer zone. Because of

                                                            B-13

                the essentially non'residential character of the study area, the aesthetic impact of a
                support base is anticipated to be noticeable.

                                                      References

                Baldwin, Mark. Offshore Center Inc., Alice, Texas. Personal communication, June 1982.

                John J. McMullen Associates, Inc., February 1981. An Offshore Supply Base in the City
                of Perth Amboy: Final Report, New York.

                New England River Basin Commission and the Resource and Land Investigations Program
                of the U.S. Department of the Interior, 1976. Onshore Facilities Related to Offshore Oil
                and Gas Development: Factbook,    Boston.

                Rogers, Golden & Halpern, 1981. New Jersey Energy Facility Development Potential
                Study. Prepared for the New Jersey Department of Environmental Protection, Division
                of Coastal Resources, Philadelphia.

                Rutgers State University, Center for Coastal and Environmental Studies, September
                1977. Onshore Support Bases for OCS Oil and Gas Development: Implications for New
                Jersey.

                United States Department of the Interior, 1981. Draft Environmental Impact Statement:
                OCS Sale No. 59. Prepared by the Bureau of Land Management.

                                                         B-14

                                                        PIPELINES

                Facility Description

                      The pipelines considered in this study include oil and natural gas pipelines on land,
                and offshore to the 3-mile (mi) limit.

                      Oil pipelines are generally built by the companies producing oil, either on an
                individual or cooperative basis. Natural gas is usually sold on the platform to a gas
                transmission company, which builds the pipeline to transport the gas from the platform
                to its transmission line.

                      Offshore Pipelines. A pipeline system servicing offshore activity, whether for oil
                or gas, may consist of a pressure source (if well pressure is not sufficient), gathering
                lines, a main pipeline, intermediate pressure booster stations, a landfall, and an onshore
                destination. When several companies are operating in the same general area, they are
                required by Federal regulations to build a common carrier pipeline that transports their
                combined products. Careful metering of the throughput at both ends ensures that each
                company receives its share.

                      Usually the marine pipeline is routed to the nearest point     of land because of the
                expense of building marine pipelines (approximately 1.5 times the cost of building
                onshore pipelines). However, other factors such as earthquake fault' zones, bathymetry
                and underwater obstructions (i. e., pipelines or cables), excessive depths, bottom currents,
                shifting sand dunes, environmental sensitivity, marine activity in the area, and proximity
                to existing or potential onshore facility sites may necessitate a longer route.

                      Pipeline Landfall. The landfall is the section between the last points where lay-
                barges and conventional onland pipelaying equipment can operate. The selection of a
                landfall site involves minimizing the length of the more costly             marine section,
                considering the onland pipeline route, and accommodating the siting of associated
                onshore facilities.

                                                           B-15

                      If incoming oil is to be transshipped by tanker, the landfall must be located near a
                site suitable for a tanker terminal and tank farm. If the oil is to continue by onland pipe
                to a refinery, a pumping station may be the only facility associated with the landfall.

                      The landfall for a gas pipeline is usually located near an existing or potential gas
                separation/dehydration plant or gas treatment plant. These facilities are owned by the
                producer, who retains the rights to the liquefiable hydrocarbons contained in the gas
                stream and recovered in the separation process.

                      Beach-upland areas (referred to as the headlands in New Jersey) often include a
                bluff or steppe upgrade, composed of rock or compacted sediment, adjacent to a narrow,
                sometimes nonexistent beach. Construction in these areas tends to be very difficult and
                expensive due to high erosion rates, corresponding steep offshore slope, and lack of
                sufficient sediment for burial. Techniques such as sheet-piled cofferdams and explosives
                would be utilized in conjunction with techniques employed with a landfall in a barrier
                island beach-dune system.

                      Onshore Pipeline. An onland pipeline system consists of a     'main pipeline, valves,
                and pressure booster stations. It may also include branch pipelines, loops, multiple main
                lines, and/or meter stations.

                      Onshore pipelines (oil or gas) may be very inconspicuous after completion,
                particularly where it does not pass through a wooded area. A pipeline right of way
                (ROW), either purchased in fee or as an easement, is required for construction of oil and
                gas pipelines. Revegetation can be hastened by separation of topsoil and subsoil during
                excavation.    It is general practice and the expressed use policy for pipelines and
                associated facilities-as stated in the New Jersey State Coastal Management Program to
                locate pipeline ROW corridors in or parallel to existing ROWs of highways, power
                transmission lines, railroads, other pipelines, or similar facilities.

                      Factors influencing pipeline route selection include topography, geology and soils,
                type and number of crossings (water bodies, roads, and railroads), and land use.

                      When the pipeline crosses bodies of water, roads, or railroads, special pipelaying
                techniques must be used. These involve additional construction costs. Stream crossings

                                                           B-16

                 may utilize one or more of the following methods: bottom pull, floating bridge,     f loating
                 barge, and directionally controlled horizontal drilling. Road and railroad crossings may
                 also be accomplished by several methods, including open cutting of roadway (unpaved or
                 lightly traveled), and boring under roadways (heavily traveled roads or railroads).

                 Facility Size/Land Requirements

                      The diameter of transmission pipelines, whether for oil or gas, ranges from 6 to 48
                 inches. Throughput capacities range from .5 to 10,000 million cubic feet/day (MMcfd)
                 for gas (at 1,100 pounds per square inch maximum) and 5 to 2,000 thousand barrels/day
                 (Mbpd) for oil (at 1,440 pounds per square inch maximum). Onland ROWs vary from 50 to
                 100 feet in width.

                      Onshore oil pipelines and gas pipelines require 6 to 12 acres per mile. The acreage
                 requirement varies with the  pipeline's capacity and corresponding diameter.

                 Site Parameters

                      Because of their high cost, the shortest route is often the most important criterion
                 for locating pipelines. Marine pipeline routes should avoid anchorage areas, existing
                 underwater objects, active faults, rock out-crops, mud slide areas, and areas which are
                 environmentally sensitive. The shore approach should be gently sloping with sufficient
                 depth of- sand or shingle to give not less than ten f eet of cover over the pipel,ine at the
                 low water mark and seven feet of cover at a depth of 50 feet. Areas subject to seabed
                 shifting or strong tidal flows should be avoided.       Erosion caused by shifting could
                 undermine pipeline support, placing additional stress on the pipeline and possibly causing
                 it to f ail.

                      Criteria for a landfall site include a flat approach or a reasonably gentle transition
                 from marine to land environment. Proximity to acreage for a pre-existing compressor
                 and pumping station or tank farm may also be included in the site parameter.

                      On-land pipelines also attempt to find the shortest route. . However, pipelines
                 should be routed around environmentally sensitive and densely populated areas. The lack
                 of availability of land, and its.high cost in developed areas weigh against pipeline ROWs

                                                           B-17

                in these areas   Pipeline routes should minimize the number of special crossings (i.e'.,
                roads, rivers) and areas of high relief as construction costs are higher in these areas.

                Capital Costs

                      The cost of constructing an offshore oil or gas pipeline is approximated as follows:
                      Capital Cost = 277,000 (1.0356D)L

                The cost of constructing an onshore pipeline is approximately-

                      Capital Cost   77,000 (1.0705D)L
                           Where:

                                 D   the pipeline diameter in inches
                                 L   length of the pipeline route in miles.

                The total cost for a 36" onshore pipeline extending 100 miles would be:

                      Capital Cost = (77,000 $/inch of diameter/mile)(1-0356 36inches)(,,, miles)
                                        $27,127,153

                Employment Profile

                      Employment figures for construction of onshore and offshore pipelines to some
                degree vary with the length of the pipeline. Construction crews will also vary depending
                on pipeline diameter, topography, and bathymetry. As longer pipelines are constructed,
                instead of having one construction crew work for a longer period, companies often use
                several crews to construct different segments of the line simultaneously.

                      In order to present a complete picture, sets of data are listed' below for both
                onshore and offshore pipelines. The 5-mile offshore pipeline would take six months to
                install, while the 100-mile offshore pipeline would take one year. The two onshore
                pipelines would take one year to construct.

                                                         B-18

                 Offshore Construction Employment:
                                                   .5-Mile Pipeline                         100-Mile Pipeline

                 Manual                                   246                                       303

                 Non-manual                                 26                                        25

                 Total                                    272                                       328

                 Onshore Construction Employment:

                                                  150-Mile Pipeline                        1,500-Mile Pipeline

                 Manual                                   160                                      1,090

                 Non-manual                                 22                                      120

                 Total                                    182                                      1,210

                       Construction crews for pipelines usually include the following types of workers;
                 welders, oilers, mechanics, electricians, pipefitters, plumbers, laborers. The 1,500-mile
                 pipeline consists of three groups of workers and equipment (known as "spreads") working
                 simultaneously, averaging 400 workers per spread.

                       Operational employment for pipelines consists of maintenance crews that make
                 regularly scheduled, periodic inspections of the pipeline to check for leaks or damage. In
                 addition, work crews regularly maintain the ROW by clearing vegetation, etc.

                 Sources:
                 BLM/Alaska OCS Office, 1979; Northern Tier Pipeline Company; Roy F. Weston Inc.,
                 1979; Santa Fe International Corp., 1979.

                 Environmental Impact

                 Spill/Accidental Discharge

                       Spills of petroleum onto land or into fresh or salt water resulting from breaks in
                 pipelines are the potentially greatest impacts from operational pipelines.         Causes of

                                                             B-19

               pipeline breakage can include any of the following: external corrosion, damage from
               equipment (anchors, fishing nets), defective pipeline seams, internal corrosion, and
               improper operation by personnel. Although quality control measures and technological
               advances have increased in recent years, the potential for an oil spill still remains.

                     Clean-up efforts involve the following techniques:

                     0    burning the oil floating on the water's surface,
                     0    utilizing sinking agents,
                     0    utilizing dispersants, and
                     0    skimming and absorbing the oil.

               Of the clean-up efforts available, only the last option--skimming and absorbing the
               oil--is widely used. The remaining options all have possible additional polluting effects.

                     The operation of marine pipelines may also involve chronic low level leaks. The
               petroleum leaks dissolve into the surrounding water and terrain during normal operation.

                     Biological resources-are adversely affected by an oil spill 'because of the petro-
               leum's toxicity and/or coating properties. The extent of the impact is the subject of a
               great deal of research. If an oil spill reaches a recreational boating, swimming and/or
               fishing area, the aesthetic impact is obvious.      Impacts to tourism and recreation
               activities can be expected, but the degree of impact is influenced by media coverage,
               cle an-up efforts, and the volume of the spill.

               Solid Waste

                     Normally, operating pipelines do not generate solid waste. However, solid waste is
               associated with pipelines in the event of an oil spill. Absorbants are commonly used to
               "soak up" the oil, and any non-recoverable oil and oily waste must be disposed of in a
               hazardous waste landfill.

                                                        B-20

                Aesthetic Impact

                      Depending upon site restoration practices at the time of construction, pipelines
                may not be noticeable. However, where the vegetation is not as easily restored the
                impact could be more severe. Aesthetic impacts can be particularly noticeable where
                pipeline ROWs pass through forested areas, resulting in highly visible linear gashes
                standing in contrast to the surrounding natural scenery. Impacts related to pipelines may
                be less important than aesthetic impacts associated.with other onshore energy facilities.

                Ecological Impacts Due to Construction

                      The Department of the Interior requires the burial of pipelines in water less than
                200 feet deep. The trenching method used to bury the pipeline removes sediments under
                the pipeline through the use of high pressure jets. As a result, increased turbidity may
                affect benthic organisms. In shallow waters, contour restoration is more rapid than in
                deeper waters. In bedrock areas, the necessary blasting may kill marine animals in the
                blasting area.

                      At the landfall site, construction impacts may be greater because of the critical
                areas at the marine--land   interface. Special construction procedures are necessary to
                protect dunes, barrier islands, marshes and estuaries.

                      Onshore pipeline construction activities disrupt soil, vegetation, and animal habi-
                tats. The impact depends on the characteristics of the site. Where pipelines cross rivers
                and streams the impact potential is greater than for flat, upland sites.          Long-term
                modifications in water quality, water table levels, and vegetation could result if water-
                holding properties of soil layers in wetlands were not restored to pre-construction
                conditions. Tourist-related impacts would be largely confined to the construction phase.

                                                       References

                'Federal Energy Regulatory Commission, 1980. Cost of Pipeli     ne and Compressor Station
                Construction Under Non-Budget Pipeline Certificate Authorization for the Years 1976
                through 1979, Washington, D.C.

                                                           B-21

                New England River Basin Commission and the Resource and Land Investigations Program
                of the U.S. Department of the Interior, 1976. Onshore Facilities Related to Offshore Oil
                and Gas Development: Factbook, Boston.

                New Jersey Department of Environmental Protection, Division of Coastal Resources,
                1981. New Jersey Energy Facility Development Potential Study, Trenton.

                New Jersey Department of Environmental Protection, Division of Coastal Resources,
                September 1980. New Jersey Outer Continental Shelf Natural Gas Pipeline Siting Study
                Phase 1: Corridor Identification, Trenton.

                Roy F. Weston, Inc., 1979.     Methodology for Assessing Onshore Impacts for Outer
                Continental Shelf Oil and Gas Development, Vol. 2: Methodology.

                Rutgers State University, Center for Coastal and Environmental Studies, 1980. OCS
                Natural Gas Pipelines:   An Analysis of Routing Issues.     Prepared for the Office of
                Planning and Policy Analysis, New Jersey Department of Energy, Newark.

                United States Department of the Interior, Bureau of Land Management, 1980. Draft
                Environmental Impact Statement: Eastern Gulf of Alaska, Sale No. 55, Washington, DC.

                United States Department of the Interior, Bureau of Land Management, 1980. Final
                Environmental Statement: Crude Oil Transportation Systems, Vol. I of 4, Washington,
                DC.

                                                         B-22

                                   OIL PUMPING AND GAS COMPRESSOR STATIONS

                Facility Description

                      These facilities are required to transport the oil or natural gas through the
                pipeline, and to maintain desired operating pressure in the pipeline.        A typical gas
                compressor station consists of one or more compressors, depending upon the volume of
                gas in the pipeline, and the temperature and pressure to which the incoming gas must be
                compressed. Station size in terms of horsepower (HP) requirements generally increases
                with higher throughput capacity, higher operating pressures, and/or greater transmission
                distances between stations. Pumping stations for crude oil pipelines usually consist of
                one of more pumps linked together in series that send the crude oil from one station (or
                other departure point such as a tank farm) to the next pumping station or other
                destination (e.g., a refinery). The number of pumps required, and the HP of each one is
                dependent upon a number of factors, including the daily throughput capacity in thousands
                of barrels per day, the type of crude (i.e., different- crudes have varying specific
                gravities), topography, and the maximum operating pressure of the pipeline.

                Facility Size/Land Requirements
                      Oil pumping and gas compressor stations may have* ten or more compressors or
                pumps with total station energy requirements approaching 40,000 HP.              Throughput
                capacities for oil pumping stations can range as high as 2 million barrels/day (MMbpd)
                and for gas compressor stations as high as 2,000 MMcfd.          Gas compressor stations
                generally have total energy requirements between 2,000 and 10,000 HP, while oil
                pumping stations have total station energy requirements of between 5,000 and 15,000
                HP.

                      An oil pumping station may require as much as 40 ac of land and includes storage
                tanks, an office, and the pumping station itself. Onshore gas compressor stations, fueled
                by natural gas or refinery gas, require from 10 to 25 ac of land located along the pipeline
                corridor. Land requirements would increase only minimally as a function of throughput
                capacity. This is because additional pumps or compressors require little additional land

                area.

                                                           B-23

                Site Parameters

                      Oil pumping or gas compressor station locations are usually dictated by the
                operating conditions (i.e., temperature and pressure of the pipeline, as well as physical
                and chemical characteristics of the substance being transported). Locations for pumping
                or compressor stations should be flat, with well drained soils, and not be subject to
                flooding (coastal or riverine) or coastal erosion. Sites should be large enough to have
                adequate land for a buffer zone, and should be located in rural or undeveloped areas. Oil
                pumping stations often need to be located near existing electric transmission lines in
                order to obtain energy to drive the pumps. In cases such as the Trans-Alaska Pipeline,
                small on-site refineries called topping plants are used to produce a kerosene-like fuel
                from crude oil extracted from the pipeline which is then used to drive the compressors.
                They do not, therefore, require proximity to electric transmission lines.

                Capital Costs

                Oil Pipeline Pumping Station - Onshore:

                      Capital Cost = (470$/hp)(HP)

                           Where:
                                 HP = the total pumping station horsepower

                The equation assumes the use of centrifugal pumps.

                Source:
                United States Department of the Interior, Bureau of Land Management, 1979.

                Natural Gas Compres or Stations - Onshore:

                      Capital Cost = $113,000 + (415$/hp)(HP)
                      The equation assumes the use of centrifugal compressors.

                                                          B-24

                Source:
                Federal Energy Regulatory Commission, 1980, Oil & Gas Journal, Annual "Pipeline
                Economics" issuesfrom 1978-82.

                Employment Profile

                      The labor force required to construct and operate both oil pumping and gas
                compressor stations are presented as follows:

                Construction:

                Oil Pumping Station (500 Mbpd)              Gas Compressor Station (2,000 MMcfd)

                          Manual            27              Manual           48

                          Non-manual         7              Non-manual       6

                          Total              34             Total            54

                Oil pumping and gas compressor stations generally take from four to six months to construct.

                Operation:

                Oil Pumping Station (500 Mbpd)              Gas Compressor Station (2,000 MMcfd)

                          Manual             6              Manual           14

                          Non-manual         1              Non-manual       2

                          Total              7              Total            16

                The number of operating personnel at an oil pumping station increases gradually up to
                1,000 Mbpd and then levels off at ten operating employees, one non-manual and nine

                manual workers.

                The number of operating personnel at a gas compressor rises slowly from lower
                production rates but levels off at 2,000 MMcfd.       Smaller pumping and compressor

                                                          B-25

                 stations are almost totally automated, and require only periodic visits by operating
                 personnel.

                 Sources:
                 Roy F. Weston, Inc., 1978.; U.S. Department of the Interior, Bureau of Land Manage-
                 ment, 1979.

                 Environmental Impact

                 Air Waste Disposal

                       During the operational phase, air emissions will be generated from compressors and
                 pumping stations.    The pumps and compressors are fueled by either natural gas or
                 refinery gas (i.e., fuel produced by small on-site refinery-like facilities which obtain fuel
                 from crude oil extracted from the pipeline). The major emissions are sulfur oxides and
                 hydrocarbons. Nitrogen oxides are also emitted from gas compressors and are a direct
                 function of the load on thecompressor engine.

                       The overall impact of removal pumping and compressor station operations on
                 ambient air quality appears to be minimal. This is because the amount of emissions
                 generated by pumping or compressor stations would not be significant enough to result in
                 decreases in local ambient air quality conditions. Impacts on recreation and tourism are
                 anticipated to be minimal.

                 Spill/Accidental Discharge

                       For a complete discussion of oil spills related to pipeline and pum ping/com pressor
                 station operation, refer to the Spill/Accidental Discharge Section in the Pipeline facility
                 write-up.

                 Noise

                       Compressors generate the most noise during operation, approximately 92 to 100
                 "All weighted decibels dB(A) at the source. The pumps and compressors run day and

                                                            B-26

                 night so their presence could significantly increase nighttime ambient sound levels in
                 adjacent areas.    Silencers built into the compressors can lower the noise level
                 Approximately once a year, venting of high pressure gas in a pipeline and at the
                 compressor station occurs, lasting approximately 45 minutes on the pipeline and five
                 minutes at the station. Uncontrolled noise levels peak at 140 dB(A), but silencers can
                 lower the level to almost half.

                      With proper controls, sound levels can be controlled and buffered, resulting in little
                 or no impact on tourism and recreation. Use of improper controls can, however, reduce
                 the quality of an area and may impact the number of participants using
                 recreation/tourist areas.

                                                        References

                 Federal Energy Regulatory Commission, 1980. Cost of Pipeline and Compressor Station
                 Under Non-Budget Pipeline Certificate Authorization for the Years 1976 through 1979,
                 Washington, D.C.

                 Federal Energy Regulatory Commission, Oil and Gas Journal, Annual "Pipeline
                 Economics" issues from 1978-82.

                 Roy F. Weston, Inc., 1978.      Methodology for Assessing Onshore Impacts for Outer
                 Continental Shelf Oil and Gas Development, Vol. 2.

                 Sieck, Ronald and Becnel, C.L., January 1980. Oil & Gas Journal, Vol. 78, No. 2,
                 "Adjustable Speed Motors Offer Alternative for Pipeline Pumps." Tulsa, Oklahoma:
                 Petroleum Publishing Co.

                 United States Department of the Interior, Bureau of Land Management, January 1979.
                 Final Environmental Statement: Crude Oil Transportation Systems. Prepared for the
                 Northern Tier Pipeline Company, Northwest Energy Company, Kitimat Pipeline Ltd., and
                 Trans Mountain Oil Pipeline Corporation.

                                                            B-27

                                    GAS SEPARATION AND DEHYDRATION PLANT

                Facility Description

                      Gas separation and dehydration involves separating the      gas, oil, and f ree water
                components of the well stream into separate components, and      dehydrating the liberated
                gas to remove water vapor. Free natural gas is obtained from      the well stream by either
                a two-phase process which separates gas from the rest of the well stream or by a three-
                phase process which results in separate gas, oil, and free water components. Heavy
                liquid hydrocarbons are settled out in one or a series of separation vessels, each at
                successively lower pressures.      (These recovered liquids are subsequently processed
                "downstream.")

                      The liberated gas passes through a valve at the phase interface and on to the
                dehydration process. Dehydration, by removing water vapor that remains in the gas
                stream after separation, prevents the build-up of solid hydrates along the pipeline and
                minimizes corrosion by acid gases often present in the gas stream. The most common
                dehydration process involves the use of absorbers containing triethylene glycol, which
                removes the water vapor from the gas as it passes through the dehydrator.

                      Onshore separation/dehydration facilities are generally located as close as possible
                to the pipeline landfall either as a separate facility, or together with a marine terminal,
                an NGL fractionation plant, or a gas treatment plant. A location at the pipeline landfall
                is desired so as to minimize the higher costs incurred in transporting the unprocessed
                gas, as well as to enable pipeline-ready gas to be available for sale as soon as possible.
                Gas separation/dehydration plants are generally owned and operated by gas pipeline
                companies or purchasers of the gas (i.e., utilities).

                Facility Size/Land Requirements

                      There are no standard sizes or process configurations for a gas Separation/dehydra-
                tion plant as each one is individually designed around a particular gas stream's chemical
                composition and flow.     Gas separation/dehydration plants have throughput capacities
                ranging in size from 20 MMcfd to 2,000 MMcfd. The smaller gas se par ation /dehydration
                facilities are portable plants mounted on skids, while the larger plants (above 100

                                                           B-28

                MMcfd) are permanent structures. Most permanent gas separati on/dehyd ration plants
                have throughput capacities of between 200 and 500 MMcfd.

                      The amount of land required for a gas separation/dehydration plant is related, but
                not directly proportional, to the plant's throughput capacity. Two-thirds of the total
                land area is required for the facility with one-third for buffering. The following equation
                can be used to estimate the land area required for a separation /dehydration plant:

                      LAND = .03(CAP) + 20

                            Where:
                                  CAP = throughput capacity in MMcfd
                                  LAND = total land area in acres

                Site Parameters

                      Coastal sites are preferred which are immediately adjacent to pipeline landfalls
                and easily accessible by highways and/or a railroad siding. Locations should not be in
                areas subject to periodic coastal flooding or erosion. Potential sites should be level,
                contain well-drained soils, and be of sufficient size to provide adequate buffering.

                Capital Costs

                      The following equation may be used to estimate the capital cost of a gas separation
                and dehydration plant:

                      Capital Cost =-$15,500,000 + (33,000$/MMcfd)(V)

                            Where:
                                 V = Daily throughput in MMcfd.

                      As a comparison, a 200 MMcfd gas separatio     n and dehydration facility that also
                includes gas treatment, gas processing (i.e., removal of natural gas liquids), and
                fractionation is estimated to cost between $50 - $80 million (Dr. V. Mohr, Lotepro, Inc.,
                1982).

                                                           B-29

                 Employment Profile

                       The construction duration and construction labor force requirements of a gas 200
                 MMcfd separation and dehydration plant are presented below.

                                            Year 1                Year 2'(6 months)

                       Manual                 130                         300

                       Non-manual              15                          35

                       Total                  145                         335

                       The peak labor force for the above facility is estimated to be approximately 500
                 workers. As a comparison, the 200 MMcfd gas separation and dehydration plant, that
                 also includes gas processing, treatment, and fractionation components, would have a
                 peak labor force of approximately 1,500 workers on-site for a short period of time (3-4
                 months) (V. Mohr, Lotepro, Inc., 1982).

                       The operating labor force for a 200 MMcfd       gas separation and dehydration plant is
                 estimated at 15-18 persons (New Jersey Department of Energy, 1981).

                 Environmental Impacts

                       Air Waste Disposal. There will be some occasional flaring of small amounts of
                 natural gas at a sep ara tio n/deh yd ration plant, along with releases into the atmosphere of
                 water vapor from the glycol reboilers. However, no major air pollutants will be emitted
                 from the facility, and the intermittent releases noted above would not be significant
                 enough to have any perceivable effect on local air quality such that tourist activity

                 would decline.

                       Liquid Waste. The major source of liquid waste would be the glycol compounds
                 used in the dehydration unit that serve as liquid dessicants (a dessicant is a solid or liquid
                 having an affinity for water; in the above case gas is bubbled upward through a glycol
                 solution, which removes the water vapor from the gas). If properly disposed, glycol
                 compounds should not pose any significant health or environmental risk.

                                                              B-30

                       Water Use/Water Discharge. Gas separation/dehydration plants do not consume
                 water for processing or cooling.        However, the process of separation results in the
                 removal of water from the gas stream, which has a high salt content. This water is often
                 stored on-site in tanks before removal to an off-site disposal location. In other cases,
                 the salt wastewater is disposed of through deep well injection. The disposal of the
                 wastewater should not result in any significant impact on recreational activities if it is
                 disposed of in a proper manner.

                       Spill/Accidental Discharge. A number of liquids that are either used or produced as
                 a result of the separation/dehydration of gas could cause environmental damage if
                 released because of an accidental spill or discharge.          These include the natural gas
                 liquids and salt water generated by the separation process, and the glycols used in the
                 dehydration process.      The accidental release of these liquids from oceanfront gas
                 separation/ dehydration plants could have adverse impacts on the surrounding area's
                 environment, thus potentially reducing its attractiveness as a recreational location. The
                 magnitude and duration of any adverse impacts would be a function of the facility's
                 throughput capacity.

                 Noise

                       Apart from the heavy equipment needed during the construction of a gas
                 separation/ dehy dra ti on plant, the major impact on ambient sound levels would be from
                 the operation of compressors. They would only be required in instances where the
                 pressure from offshore wells is not enough to drive the gas to the nearest interstate gas
                 pipeline.   Use of a compressor with proper on-site soundproofing would not increase
                 ambient sound levels at 300 meters by more than five decibels (NJDOE, 1981). When
                 required, compressors would operate continuously, having a substantial effect on
                 ambient, nighttime sound levels. This could have adverse, localized effects on tourism in
                 areas whose attractiveness depends in part on their perception as tranquil locations
                 offering an opportunity for rest and relaxation.

                 Aesthetics

                       The most visible structures of a gas separation/dehydration plant would be
                 approximately 40-50 feet high. Thus, any adverse aesthetic impacts would be confined

                                                              B-31

                to a small area. However, the facility's continuous operation and accompanying evening
                lighting, along with the intermittent flaring of gas, could constitute a more adverse,
                localized aesthetic effect than the presence of the structures. In some instances a
                communication tower, ranging up to 500 feet in length, could be required. A structure
                this size would be clearly visible for quite a distance in the flat, coastal locations that
                comprise the study area. The other adverse tourism-related aesthetic impact would be
                where the facility's presence is visually incompatible with an adjacent scenic, natural, or
                coastal location.

                                                       Ref erences

                Federal Energy Regulatory Commission, Office of Pipeline and Producer Regulation,
                July 1980. Final Environmental Impact Statement: Prudhoe Bay Project, Washington,
                D.C.

                Ikoku, Chi U, 1980. Natural Gas Engineering: A Systems Approach, Tulsa, Oklahoma.

                Larrea, James, Proser Processes and Systems, Inc., Houston. Personal communication,

                1981.

                Mohr, Dr. Volker, Lotepro, Inc., New York. Personal communication, 1982.

                New England River Basin Commission and the Resource and Land Investigations Program
                of the U.S. Department of the Interior, 1976. Onshore Facilities Related to Offshore Oil
                and Gas Development: Factbook, Boston.

                New Jersey Department of Energy, March 1981. New Jersey OCS Handbook, Newark.

                Roy F. Weston, Inc., 1978.       Methodology for Assessing Onshore Impacts for Outer
                Continental Shelf Oil and Gas Development, Vol. 2.

                Transcontinental Gas Pipeline Corp., Houston. Personal communication, 198 1.

                                                           B-32

                                                 GAS TREATMENT PLANT

                 Facility Description

                       Natural gas often contains acid gases, primarily hydrogen sulfide (H    25) and carbon
                 dioxide (CO 2). Natural gas streams with high concentrations of either H2S or C02          are
                 referred to as "sour" gas, and the process of removing acid gases is known as
                 "sweetening". A gas treatment plant is the facility used for removing acid gases from
                 the natural gas stream.

                       Hydrogen sulfide must be removed from the gas stream because it is a toxic,
                 poisonous gas, and because, in the presence of water vapor, it is extremely corrosive. Its
                 presence in the gas stream decreases the useful life of pipe, valves, and   pressure vessels;
                 and increases operating and maintenance (0 & M) costs for the pipeline. In addition, it is
                 very expensive to provide specially coated pipe and handling facilities capable of
                 resisting the corrosive effects of the gas when it is being sent over long distances.
                 Removal of carbon dioxide is desired because it is also corrosive when water is present in
                 the gas stream, and because carbon dioxide is conducive to the f      ormation of hydrates,
                 whose formation can lessen flow rates and impair the functioning of the pipeline.

                 As with a gas separation and dehydration plant, a gas treatment plant is designed
                 specifically for the chemical composition of the gas stream it will be treating. Some of
                 the major processes used in a gas treatment plant include iron-sponge sweetening,
                 absorption with an amine solution, and a molecular sieve.

                 facility Size/Land Requirements

                       Gas treatment plants can range in size from 2 to 2,000 MMcfd in terms of
                 throughput capacity. Typical facility sizes range between 200 and 500 MMcfd.

                       Approximately 50-75 acres per 1,000 MMcfd of daily throughput capacity is
                 requir ed, with approximately one-third of the total site required for buffering.

                       A sulfur recovery plant often accompanies the const"ruction of a gas treatment
                 plant in instances where the natural gas stream has a high concentration of hydrogen

                                                            B-33

                 sulfide. The sulfur recovery plant converts the H     2S into elemental sulfur   which can
                 then be sold for other industrial process uses. The most common sulfur recovery process
                 is the Claus process, in which H2 S is first oxidized to remove most of the sulfur, with the
                 rest being removed in catalytic converters. Preliminary indications are that natural gas
                 found off New Jersey would not likely require the use of a sulfur recovery plant, as it is
                 fairly "sweet" gas.

                 Site Parameters

                      On-shore gas treatment plants should be located as close as possible to the pipeline
                 landfall. This minimizes the extra costs that result from the corrosive effects of sour
                 gas, and the extra energy costs incurred in pumping the sour gas constituents.

                      A gas treatment plant is often co-located with a gas separation/dehydration plant
                 at a shorefront location. A site should be level, with well-drained soils, and not situated
                 in areas subject to coastal flooding or areas with seasonably high water levels. Finally,
                 sites should be accessible by highways and railroads.

                 Capital Costs

                      The capital cost of a gas treatment plant varies widely based on the volume and
                 chemical composition of the gas stream. In addition, there are economies of scale that
                 are gained when a gas treatment plant is constructed at the same location as any of the
                 other natural gas facilities.   Smaller units, treating less than 50 MMcfd, are often
                 mounted on skids for temporary installation, while larger treatment facilities are
                 permanent structures.

                      The capital cost of a gas treatment plant may be estimated using the following
                 equation:

                      Capital Cost = (12,700,000$/MMcfd) (1.0034    V

                            Where:

                                  V = throughput capacity in MMcfd

                                                            B-34

                 This equation applies to units with capacities of 30 MMcfd or greater

                 Sources:
                 Ford, Bacon & Davis, Dallas, Texas, 1982; Pacific Offshore Pipeline Co., 1982; Proser
                 Co., Houston, 1982; Superior Oil Company, 1982.

                 Employment Profile

                       The construction labor force requirements for a 60 MMcfd and a 200 MMcfd plant

                 are listed as follows:

                                            Year 1                         Year 2 (6 months)
                                    60 MMcfd 200 MMcfd                  60 MMcfd 200 MMcfd

                       Manual           150          250                    225          350

                       Non-manual         12           15                    20           30

                       Total            162          265                    245          380

                       The operating    labor force for a gas treatment    plant increases only marginally for
                 plant sizes above 50 MMcfd due to the use of automated control systems. Operating
                 labor force for a gas treatment plant would be approximately 20 - 25 persons.

                 Sources:

                 Pacific Offhore Pipeline Co., 1982; Superior Oil Co., 1982.

                 Environmental Impacts

                 Air Waste Disposal

                       Cons tructi on-relat ed pollutant emissions would depend on the type and amount of
                 heavy equipment utilized, however, as noted previously, New Jersey's vehicle emission
                 standards should minimize the impacts of construction activities on ambient air quality.

                       During operation, gas treatment plants produce hydrogen sulfide, which if produced
                 in amounts too small to economically justify sulfur recovery, may be flare-vented or
                 incinerated if permitted by local air quality regulations. The pollutants released to the

                                                              B-35

                atmosphere include sulfur dioxide (SO   2), nitrogen oxides (NOX)   and smaller amounts of
                hydrocarbons. In cases where a sulfur recovery plant accompanies a gas treatment plant,
                significant amounts of sulfur dioxide are produced.

                      If gas treatment plants, without accompanying sulfur recovery plants are con
                structed in New Jersey (as seems likely given the relatively "sweet" gas off New Jersey),
                the impact of air emissions on ambient air quality should be minimal. As a comparison,
                the 2,300 MMcfd gas treatment plant (without sulfur recovery) proposed for Prudhoe
                Bay, a class II area in terms of air quality, was projected not to result in any significant
                deterioration of ambient air quality (FERC, 1980). The corresponding effects on tourism
                should likewise be minimal.

                Water Use/Water Discharge

                      Wastewater is produced as' part of the gas treatment process, however, in most
                sweetening processes, little of this is process water. The wastewater discharges can, for
                the most part, be accommodated by the local municipal sewer system, though some pre-
                treatment may be required for cooling water and process water. The environmental
                impacts and the accompanying effects on tourism should be negligible.

                Spill/Accidental Discharge

                      A malfunction at a gas treatment     plant could result in spillage where sweetening
                processes use liquid chemicals (i.e., amines) or liquid solvents as absorbents.           The
                magnitude and direction of the environmental effects accompanying any spills would
                vary widely according to site-specific conditions and the size of the plant.

                Noise

                      The operation   of a gas treatment plant results in noise being produced by the
                continuous operation  of compressors, boilers, scrubbers, and flarestacks. The location of
                a gas treatment plant in a commercially developed coastal location (with an ambient
                sound level (LEQ) in the vicinity of 50-55 decibels), could result in a significant increase
                in ambient sound levels in the vicinity of the plant. However, as with a separation/dehy-
                dration plant, if the site is properly buffered and proper sound attenuation measures are

                                                           B-36

                adopted, sound levels would likely not increase by more than five decibels above ambient
                levels at 300 meters (NJDOE, 1981).

                      The presence of a gas treatment plant in an area prized for its rural ambience and
                solitude (i.e., with an LEQ of between 40 and 50 decibels) could adversely impact tourism
                activities in the immediate area.       However, this impact would be very localized,
                extending no more than a quarter of a mile from the site.

                Aesthetics

                      Gas treatment plants' primary adverse aesthetic impacts would come from the
                flaring of natural gas and the presence of lights from 24-hour operation.            A gas
                treatment facility's structures would be relatively low (under 50 feet), and would
                therefore not be visible over a substantial area. As with other facilities, the siting of a
                gas treatment plant in a scenic natural or coastal location would be incompatible with
                the existing aesthetic environment. The incompatibility of the structure itself vis-a-vis
                the surrounding environment, as well as the flaring and lighting effects, could decrease a
                location's attractiveness as an area for tourism activities.

                Odor

                      Odors are produced by the incomplete combustion and occasional venting and
                flaring of hydrogen sulfide. The unpleasant odor associated with this gas could certainly
                have a significant adverse effe ct on tourism activities occurring in thesurrounding area.
                The magnitude of the effect would depend on the frequency of the releases and
                prevailing atmospheric conditions around the site.

                                                       Ref erences;

                Federal E nergy Regulatory Commission, Office of Pipeline and Producer Regulation,
                July 1980. Final Environmental Impact Statement: Prudhoe Bay Project, Washington,

                D.C.

                Ford, Bacon & Davis, Dallas, Texas. Written communication, November 1982.

                                                           B-37

                Ikoku, Chi U1 1980'. Natural Gas Engineering- A Systems Approach*. Tulsa, Oklahoma:
                Pen Well Publishing Co.

                Larrea, James, Proser Processes and Systems,    Inc., Houston. Personal communication,
                1981.

                Mohr, Dr. Volker, Lotepro, Inc., New York. Personal communication, 1982.

                New England River Basin Commission and the Resource and Land Investigations Program
                of the U.S. Department of the Interior, 1976. Onshore Facilities Related to Offshore Oil
                and Gas Development: Factbook, Boston.

                New Jersey Department of Energy, March 1981. New Jersey OCS Handbook, Newark.

                Perry Gas Processors, Inc., April 1977. Fundamentals of Gas Treating Manual for Design
                of Gas Treaters, Odessa, Texas.

                Roy F. Weston, Inc, 197.8.     Methodology for Assessing Onshore Impacts for Outer
                Continental Shelf Oil and Gas Development, Vol. 2.

                University of Oklahoma, Sc   ien ce and Public Policy Program, 1980. Energy From the
                West: Energy Resource Development Systems Report, Vol. 5: Oil and Gas.

                Yates, Mel, Pacific Offshore Pipeline Company. Personal communication, October 1982.

                                                         B-38

                                NATURAL GAS LIQUIDS (NGL) FRACTIONATION PLANT

                 Facility Description

                       In addition to oil, water, and "sour" (i.e., hydrogen sulfide and carbon dioxide)
                 components, liquefiable hydrocarbons such as ethane, butane, and propane may also be
                 present in a natural gas stream. If the gas stream is rich in these natural gas liquids, it
                 may be economically attractive to separate the bulk liquids content into these individual
                 components. A gas processing plant is first used for removing liquefiable hydrocarbons
                 from the gas stream.      A natural gas liquids fractionation plant then separates the
                 liquefiable hydrocarbons into their constituent components. Both the gas processing
                 plant and the fractionation plant are located "downstream" from a gas treatment plant.

                       NGL relies on the different vaporization temperatures of the products.                The
                 process is performed in a series of fractionating towers. The lighter, more volatile
                 products are vaporized first, condensed, and collected, while the remaining liquid is fed
                 to the next tower, where the process is repeated for the heavier products. The major
                 constituents usually separated out by a fractionation facility include ethane, propane,
                 butane, and pentane. The individual fractionating towers are named for the product they
                 remove, and are thus called a dethanizer, a depropanizer, a debutanizer, etc. The
                 specific design of a fractionation plant depends on throughput capacity, the relative
                 abundance of desired products in the bulk liquid, and the desired recovery rate of those
                 products.

                       An NGL fractionation plant would be located at a gas separation/dehydration plant,
                 or at a gas-processing plant only if the volume of NGL recovered from a single facility
                 were  large enough to economically justify the operation of a fractionation plant. In most
                 other cases, a fractionation plant would be centrally located so as to receive the NGL
                 produced by a number of gas separation/dehydration or gas processing plants. In New
                 Jersey it is likely that NGL would be collected at individual locations and shipped by
                 tanker truck to a centrally located fractionation plant.

                                                             B-39

                Facility Size/Land Requirements

                      Fractionation plants may be     designed for any volume.       Typical throughput
                capacities of these facilities range from 5 to 50 Mbpd of natural gas liquids.

                      As with the other natural gas-related facilities, the land required for an NGL
                fractionation plant is related, but not directly proportional, to the plant's throughput
                capacity. The following equation can be used to estimate land requirements:

                      LAND= .03(CAP) +30

                          Where:

                               LAND    plant area in acres
                               CAP    plant daily processing capacity in thousands of barrels (Mbpd)

                Site Parameters

                      Fractionation plants, have the same general siting requirements as gas separa-
                tion/dehydration and gas treatment'plants. The one exception is that they do not have to
                be located close to pipeline landfalls or close to the interstate gas pipelines.

                Capital Costs

                      The capital costs of a 10,000 barrel/d,ay gas liquids fractionation plant are

                estimated as follows:

                      Capital Cost = (400$/barrel per day)(BPD) + $4,000,000

                          Where:
                               BPD = barrels of condensate processed per day

                This assumes the fractionation of the condensate into propane, butane, and pentane.

                Sources:

                Ford, Bacon & Davis, 1982; Pervin and Gurtz, 1981.

                                                         B-40

                 Employment Profile

                       The employment required to construct and operate a natural gas liquids-frac-
                 tionation plant is small in comparison with most of the other n atur al-gas-r elated energy
                 facilities. This is due to the small size of the facility.

                       The construction labor force consists of:

                                                        Year 1 (6 months)

                           Manual                                98
                           Non-manual                         -6
                           Total                                104

                       The operating labor force will be small for two reasons.        First, fractionation
                 facilities will generally be located at gas processing plants, and the labor force required
                 to operate these facilities would also have the responsibility of overseeing the frac-
                 tionation facility. Second, state-of-the-art fractionation facilities employ highly auto-
                 mated control systems and would require a minimal amount of operating labor. It is
                 estimated that no more than five persons (all manual) would be required to operate a gas
                 liquids fractionation plant.

                 Environmental Impacts

                 Air Waste Disposal

                       As with other energy facilities, there will be emissions from vehicles and heavy
                 equipment utilized on-site during the construction of an NGL fractionation plant. Given
                 the relatively short construction period for this facility, and the existing vehicle
                 emission control program in New Jersey, the impacts during the construction phase
                 should be minimal. During operation an NGL fractionation plant will release small
                 amounts of hydrocarbons from valves and fittings during the     fractionation process. In
                 addition, combustion-related emissions from the operation of boilers and compressors
                 will also occur. The environmental impacts accompanying these emissions would be
                 minimal, and would not be expected to have discernible effects on tourism.

                                                           B-41

                 Water Use/Water    Discharge

                       The major consumptive use of water in an NGL fractionation plant is for cooling
                 and condesning each constituent as it leaves each fractionator.          This water usually
                 contains chemicals which prevent scaling and fouling in the condenser and cooling
                 system, and this water would likely have to be pre-treated on-site before being sent to a
                 local municipal wastewater treatment system. Process requirements would be of a
                 lesser degree than cooling water requirements, but would also require pre-treatment
                 before being released to the local wastewater treatment system. The volume of water
                 required by an NGL fractionation plant would not be large enough to have any significant
                 effect on local water supplies (i.e., as compared to the cooling water requirements of an
                 electric generating plant).     Similarly, the environmental effects accompanying the
                 wastewater generated by this    facility should be minimal if all applicable environmental
                 standards are adhered to. The related impacts on tourism should also be minimal.

                 Spill/Accidental Disch arge

                       A malfunction at an NGL fractionation plant would result in the release of the
                 separated components (i.e.   butane, propane etc.) being stored on-s'ite. The magnitude of
                 the environmental effects accompanying any such release would be dependent upon the
                 site-specific conditions and on the volume of the release.

                 Noise

                       As with the other natural-gas-related facilities, an NGL fractionation plant
                 involves the use of compressors and boilers. Similarly, the continuous operation of such
                 a facility in a rural -site would result in a signif icant increase in nighttime ambient sound
                 levels. The magnitude of the increase in ambient sound levels would be similar to those
                 noted previously for a gas treatment plant and a gas separation/dehydration facility. In
                 conclusion, the noise effect will be localized and, depending on site-specific conditions,
                 could have an adverse    impact on the suitability of the adjacent areas as a location for
                 tourism-related activities.

                                                             B-42

                Aesthetics

                      The aesthetic impacts of an NGL fractionation facility would be very similar, but
                somewhat larger than those noted elsewhere for a gas treatment plant. The most visible
                component of a fractionation plant would be the individual fractionators which can range
                as high as 150 feet. They would be clearly visible over a significant area due to the flat
                topography of the study area. The presence of clearly visible fractionators, in coastal
                locations desired for their aesthetic qualities, would constitute an adverse visual

                intrusion.

                                                       References

                Ford, Bacon and Davis, Dallas, Texas. Written communication, November 1982.

                Ikoku, Chi U, 1980. Natural Gas Engineering: A Systems Approach. Tulsa, Oklahoma:
                Pen Well Publishing Co.

                New Jersey Department of Energy, March 1980. New Jersey OCS Handbook, Newark.

                Pervin and Gurtz, Houston, Texas. Personal communication, 1981.

                                                           B-43

                                              PEAK SHAVING FACILITIES

                Facility Description

                      Peak shaving facilities constitute reserve storage facilities which can supply
                natural gas to utilities and other consumers during peak demand periods. The obvious
                advantage of storing natural gas in a liquefied form is that 600 cubic feet of natural gas
                can be condensed and cooled to occupy one cubic foot in its liquid form. One barrel of
                LNG is equivalent to approximately 3,450 cubic feet of natural gas.

                      There are three fundamental steps in the peak shaving process.          Natural gas
                entering the plant is first liquefied by compression and cooling to -2600 F. The liquefied
                natural gas is then stored in specially insulated storage vessels. Finally, the gas is re-
                vaporized and reinserted into a natural gas transmission and distribution system for
                distribution to consumers.

                      A number of storage options exist, but the most commonly used is the conventional
                above-ground, double-insulated metal tank. These tanks genera      lly have a steel outer
                wall and an'inner wall of aluminum, 9% nickel steel, or austenitic stainless steel. The
                material of the inner wall must retain its ductility at cryogenic temperatures. In order
                .to contain the contents of the tank in the event of a spill, each tank is surrounded by a
                diked impounding area with a capacity of at least 100% of the tank capacity. It is
                generally bottom-lined with moist sand and 2.5 inches of shotcrete to help withstand the
                thermal shock of a spill.

                Facility Size/Land Requirements

                      Peak shaving plants may contain two or more storage vessels with each having a
                capacity of up to 900,000 barrels of LNG (equivalent to 3,100 MMcfd of natural gas).
                They can vaporize up to 116,000 barrels of LNG per day, delivering 400 MMcfd to meet
                peak demand. The daily delivery capacity (i.e., rate at which gas can be vaporized and
                delivered to a pipeline) is generally about one-fifth of a peak shaving plant's total
                storage capacity.

                                                          B-44

                      As with other natural gas-related facilities, land   requirements for peak shaving
                plants are indirectly associated with total plant capacity.

                      The following equation can be used to estimate total land requirements:

                      Land Area = 94 + .03 + _SCP

                           Where:

                               Land area = site size in acres
                               SCP = storage capacity in thousands of barrels of LNG

                The facilities would occupy about half the total site while the remainder would be used
                as a buffer area for safety reasons.

                Site Parameters

                Peak shaving plants  should be located in areas where the soil has good bearing capacity,
                because of the considerable weight of the liquefied natural gas. Sites should be flat, and
                situated out of flood plains, areas subject to coastal flooding, and seismically active
                areas. They should be directly adjacent to an existing gas transmission line. Finally,
                peak shaving plants should not be located in areas where concentrations of population are
                adjacent to the site due to the flammability of LNG.

                Capital Costs

                      Capital Cost   (13,440,000$/thousands of barrels) (1.0017 SCP

                           Where:
                               SCP    storage capacity in thousands of barrels.

                      The foundation costs are included in the baseline capital cost equation.         This
                equation assumes the use of a concrete mat foundation over selected backfill.

                                                           B-45

                 Sources:
                 Chicago Bridge and Iron Co., 1982; Ikoku, Natural Gas Engineering, 1980; Public Service
                 Electric and Gas, 198 1.

                 Employment Profile

                       The construction labor forces for two sizes of peak shaving plants are presented
                 below.

                                            290,000 Barrel               580,000 Barrel
                                           Storage Capacity            Storage Capacity

                                         Year I        Year 2        Year I         Year 2
                                                   (9 months only)

                       Manual              45            58             75              98

                       Non-manual            5             7              8             12

                       Total               50            65             83             110

                       The operating labor force for a peak  shaving plant does not'vary by size, as these
                 facilities are highly automated and use computerized control systems. The operating
                 labor force for facilities in the size range noted above would consist of 17 persons over a
                 24-hour shift, 3 non-manual and 14 manual.

                 Sources:
                 Bimonte, Joe, July 1982; Transcontinental Gas Pipeline Company, Carlstadt, New Jersey;
                 Wilson, Peter, September 1982, Chicago Bridge and Iron.

                 Environmental Impact

                 Air Waste Disposal

                       During the construction of a peak shaving facility, clearing grading and earthwork
                 activities can generate dust. Dust can be controlled by spraying water on - the disturbed
                 areas. With proper dust suppression methods implemented, impacts to air quality and to
                 tourism and recreation are anticipated to be minimal.

                                                           B-46

                       operation of a peak shaving plant will include an occasional vaporization of the gas
                 supply . As a result, nitrogen oxides are emitted in significant amounts. However,
                 because vaporization units are operated approximately 20 days a year, the annual
                 emissions of nitrogen oxides are a relatively insignificant amount. The impacts to air
                 quality and to tourism and recreation are anticipated to be negligible.

                 Noise

                       During various phases of facility construction, noise levels will rise and may
                 produce an impact on ambient noise levels. Because of the limited duration of noise and
                 occurrence primarily (if not solely) during daylight hours, construction noise levels are
                 not considered to be a significant impact.

                       Sources of noise generated during operation are the turbin e/com pressor set, heat
                 exchangers, and primarily the vaporizer units. Because of the amount of noise generated
                 (113 dB(A) at a reference distance of 3 feet), acoustical treatment is most often a
                 component of the facility's plans. One option includes housing the equipment in an
                 acoustically treated building.

                       Because of the relatively non-industrial, suburban characteristics of the study area,
                 the increase in ambient noise levels could be a significant impact. An increase in
                 ambient noise levels could be interpreted as a decrease in the quality of an area and
                 could, in turn, affect the number of tourism and recreation participants.

                 Aesthetic Impact

                       Large storage tanks may approach 150 feet, thus the aesthetic impacts would be
                 similar to those noted previously for other natural gas-related facilities. In addition, in
                 an effort to maintain safety standards near the facility, trees, bushes and other
                 landscaping are not permitted as a measure to reduce the amount of combustible
                 material near the facility. As a result, the facility's appearance becomes even more

                 blatant.

                                                           B-47

                 Accident

                      LNG is a liquefied flammable gas which is readily vaporized when exposed to
                 external heat sources. The vaporized LNG is not flammable when unconfined (Federal
                 Power Commission, 1976), but is flammable in enclosed areas. A potentially flammable
                 vapor cloud could form if a storage tank were ruptured and LNG escaped into the
                 atmosphere. The probability of an accidental release of LNG due to a storage tank
                 rupture is quite low; conversely, the probability of a release of other flammable liquids,
                 used in either the liquefaction or vaporization processes, is much higher.

                      The process of liquefying pipeline gas to liquid natural gas will probably entail the
                 use of a mixed refrigerant. The refrigerant consists of hydrocarbons, most likely a
                 mixture of ethane, propane, butane, nitrogen and methane.         All of the components
                 except for nitrogen are flammable. A processing accident could leak the refrigerant and
                 result in the potential for a fire or explosion. Methanol, also flammable, may be used
                 during the pretreatment of gas to remove water and carbon dioxide. The potential for
                 fire and/or explosion also exists with the storage and processing of methanol.

                      Hazard detection, prevention, and mitigation constitute        major efforts in the
                 construction and operation of a peak shaving facility. Because of   the incorporation of a
                 protective buffer zone around the    facility, and siting in low density population areas,
                 danger to the nearby public is reduced.

                                                        Ref erences

                 Federal Energy Regulatory Commission, February 1980.           In the Matter of Energy,
                 Terminal Services Corporation, Docket No. CP74-122, Washington, D.C.

                 Federal Power Commission, December 1976. Draft Environmental Impact Statement:
                 West Deptford LNG Project, Tenneco LNG Inc, Docket No. CP76-16, Washington, D.C.

                 Ikoku, Chi U, 1980. Natural Gas Engineering: A Systems Approach. Tulsa, Oklahoma:
                 Pen Well Publishing Co.

                                                           B-48

                Transcontinental Gas Pipeline Corporation,' Carlstaadt, New Jersey. Personal communi-
                cation, August 1982

                Transcontinental Gas Pipeline Corporation, 1979. "Let's Talk About Storage of Natural
                Gas." Houston, Texas.

                Wilson, Peter, Chicago Bridge and Iron Company, Philadelphia. Personal communication,
                1982.

                                                        B-49

                                                     TANK FARMS

                Facility Description

                      Petroleum tank farms are used for the storage of crude oil and refined petroleum
                products. Tank farms store oil arriving from outer continental shelf drilling operations
                via pipelines, and oil arriving by tanker- from overseas producers. When they are located
                at marine terminals, tank farms store oil offloaded from tankers, or oil sent via overland
                pipelines awaiting loading onto tankers. Tank farms are also essential components of the
                oil refining process, storing incoming crude oil prior to its being pumped through an
                overland pipe to a refinery. Tank farms are also used for storing refined petroleum
                products prior to their distribution by pipeline, rail, ship, barge, or truck.

                      Oil storage tank farms may be located at a number of different facilities,
                depending upon the oil processing and transportation schemes being used. If crude oil is
                being piped to shore, tank farms may be located near the pipeline landfall, associated
                with either pumping stations or marine terminals. From either of these facilities the oil
                is transshipped to refineries in other regions.

                Facility Size/Land Requirements

                      The individual storage tanks can be built to store up to one'million barrels each,
                but storage between 150,000 and 300,000 barrels per tank is more typical. Oil tank
                farms are also sized on the basis of their throughput capacities. This is the number of
                barrels per day the facility is capable of pumping from offloading tankers, and it is
                determined by the capacity of the pipeline supplying the tank farm.             Throughput
                capacities range as high as 1,000,000 barrels/day, with- 250,000-500,000 barrels/day being
                the most common. As a general rule, throughput capacities are generally about one-
                eightieth of a tank farm's total storage capacity.

                      The acreage of the tank farm depends on     the total storage capacity required and
                the rate at which incoming oil enters the facility. Tank farms may contain up to 20
                storage tanks with total storage capacities approaching five million barrels. The amount
                of land required for a tank farm depends on its total storage capacity. Approximately 13
                to 20 acres are required per one million barrels of oil stored.

                                                           B-50

                 Site Parameters

                       Sites for the tank farm should be flat, not subject to coastal flooding, and have
                 soils capable of bearing the heavy loads associated with storage tanks. If the tank farms
                 are to be used by tankers, the site must also be adequate in terms of wind and wave
                 conditions, and bathymetry.      Waterfront locations must be sheltered from adverse
                 weather and wave conditions and the mooring areas must have sufficient depth to
                 accommodate the draft of the largest anticipated tanker expected to utilize the facility.

                 Capital Costs

                       As with the land requirements, the costs of a tank farm are'dependent upon the
                 total storage capacity of the facility. Capital costs can be estimated using the following
                 equation:

                       Capital.Cost = (18,020,000$/10 6barrels)(V) - $5,600,000

                           Where:
                                 V = total storage capacity in 10 (millions) of barrels

                 The design assumptions include a reinforced concrete ring foundation on top of     a graded
                 and compacted surface with a sand-grav    el and asphalt subbase. The tanks are assumed
                 to have fixed-roofs. It should be noted that the above costs are for the oil storage
                 facilities only, and do not include the required unloading/ loading facilities. In addition,
                 these costs assume that the storage tanks would be designed, fabricated, and erected at
                 a remote site and delivered to the site by rail, barge, or truck transportation.

                 Sources:
                 U.S. Dept. of Interior, Bureau of Land Management, 1979; Oil & Gas Journal, Annual
                 "Pipeline Economics" issues from 1978-80.

                                                            B-51

                Construction Personnel

                      The number of annual manual and ann-ual non-manual employees required to
                construct a tank farm with a total storage capacity of 4 million barrels is presented as

                f ollows:

                                       Manual                                 175

                                       Non-manual                              25

                                       Total                                  200

                The construction period would last approximately 24 months.  Due to economies of scale,
                additional construction labor force requirements are minimal for facilities with storage
                capacities greater than 4 million barrels. However, the length of the construction phase
                would increase.

                      Following is the number of manual and non-manual employees required to operate a
                tank farm with a storage capacity of four million barrels:

                                       Manual                                  27

                                       Non-manual                                3

                                       Total                                   30

                The number of employees required to operate tank farms with larger storage capacities
                would not change due to the highly automated and computerized control systems used in

                new tank farms.

                Sources:
                Northern Tier Pipeline Co., Northwest Energy Co., Kitimat Pipeline Ltd., and Trans
                Mountain Oil Pipeline Corp., Environmental Statement Crude Oil Transportation
                Systems, Volume 1, 1979; Roy F. Weston Inc., July 1978.

                                                          B-52

                 Environmental Impact

                 Air Waste Disposal

                       During the construction of tank farms, combustion emissions from heavy machinery
                 operating on-site include nitrogen oxide and carbon monoxide. Dust is also generated by
                 heavy machinery moving topsoil.

                       Hydrocarbons are the primary emissions from tank farms. Controlling hydrocarbon
                 emissions is important because of their reaction with nitrogen oxides in the presence of
                 sunlight to produce ozone and smog. Sources of hydrocarbon emissions include:

                       0    evaporation from storage tanks,
                       0    evaporation during the transfer of crude oil and fuel, and
                       0    accidental spills and small leaks.

                 The magnitude of the hydrocarbon air emissions on the ambient air quality is influenced
                 by several of the following factors:

                       0    number of storage tanks
                       0    number of marine vessels (transfer points)

                       0    ambient air conditions
                       0    tank design and tank paint color (colors that increase the reflectivity of light
                            from takes can increase the formation of smog in adjacent areas)

                       Impacts to tourism and recreation are not anticipated from construction machinery
                 emissions because of New Jersey's Motor Vehicle yearly emission testing to meet
                 specif ic standards.   Impacts to tourism and recreational activities as a result of
                 hydrocarbon emissions will be minimal if emissions are kept to a minimum.                   If
                 hydrocarbon emissions increase substantially, however, the resultant smog will lessen the
                 quality of the recreation area. Developing ozone is not only harmful to the atmosphere
                 bu@ causes coughing, eye irritation, headache, and damages vegetation. As a result,
                 increased hydrocarbon emissions could make an area undesirable and unsafe, reducing
                 recreation activities.

                                                            B-53

                Solid Waste

                      Sediment sludges must be removed from the bottom of storage tanks to maintain
                maximum holding capacity. The sludges are considered hazardous and contain iron rust,
                iron sulfides, sand, and oil. Disposal in a secured landfill is required.

                      The impact of tank farm solid waste will be minimal unless the dump site is not
                properly secured and the sediment sludges are allowed to contaminate the groundwater.

                Spill/Accidental Discharge

                      Because of the large volume of oil stored and transferred at tank farms, oil spills
                may occur at any time. A spill would have a significant impact on biological resources in
                the vicinity because of the coating and toxic properties of the oil. A spill might also
                result in an aesthetic impact if the slick coated recreational beaches or boating areas.

                      A major oil spill could severely impact tourism and recreation. Fishing, boating,
                and swimming could conceivably be curtailed as a result of a spill. Clean-up efforts,
                water current patterns, and site locations all influence the degree of impact of an oil
                spill on recreation and tourism.

                Noise

                      If the construction of a dock or bulkhead is required, pile drivers will be used.
                Although they are used only temporarily, they do generate a considerable amount of
                noise, and ambient sound levels can be expected to increase. During operation, ambient
                sound levels will rise because of pumps moving oil to and from tanks, pipelines, and

                tankers.

                      Increases in ambient sound levels   would be noticeable in shorefront recreational
                areas, and particularly in sparsely-populated rural shorefront areas valued for peace and
                quiet, thereby possibly affecting recreation and tourism. Higher ambient sound levels
                would decrease tourists perceptions of a site's suitability as a location for relaxing and
                escaping the pressures of everyday life.      Buffer zones and proximity of the site to
                recreation areas will determine the extent of the impacts.

                                                           B-54

                Aesthetic Impact

                      The presence of numerous large tanks, possible round-the-clock operations, and
                continual lighting would create adverse visual impacts in shorefront recreational areas.
                In the event of a major oil spill, patches of oil washing up on sandy beaches would have a
                devastating effect on the visual attractiveness of such areas. In addition, floating oil
                slicks would adversely affect the visual appearance of water, and result in oil lines on
                boats and waterfront structures. The presence of oil tanks and the possibilty of adverse
                aesthetic effects can be mitigated by several factors, including the following:

                      0    buf f er zone

                      0    landscaping
                      0    oil spill clean-up measures
                      0    location away from recreation areas

                The aesthetic impact of tank farms on recreational and tourism activities can range
                from a marginal effect to a complete reduction in the area's recreational usage (as in the
                case of a major spill). -Certainly, oil slicks covering sandy beaches will result in
                swimmers going to other, unaffected beaches. Similarly, recreational boating would
                decline, and other potential visitors seeking an attractive shorefront location for rest
                and relaxation would change their patterns of visitation.

                Other-Fire Hazard

                      Tank farms store large volumes of oil and other petrochemicals and, as a result,
                fires and explosions are ever-present hazards. Even a small fire may produce enough
                heat to cause explosions of nearby stored oil.

                      A buffer zone would increase protection for nearby tourists and participants in
                recreational areas, but would also increase industrial land usage, thereby possibly
                decreasing recreational areas. An explosion would obviously seriously affect recreation
                and tourism in the vicinity of the tank farm.

                                                          B-55

                 Other-''Dredging

                       If oil is expected to be loaded or unloaded from tankers, construction activities will
                 also include dredging and jetty construction. Dredging will alter the biological resources
                 in the vicinity of the dredged site, due to increases in turbidity, siltation, and the
                 disruption of benthic organisms.     If the dredging is extensive, it may change water
                 currents significantly enough to alter the coastline.

                       Construction and dredging impacts are anticipated to be temporary, and have
                 minimal effect on tourism and recreation. However, a more significant impact will be
                 the use of the coastline for an industrial purpose rather than a recreational purpose.

                                                        Ref erences

                 New England River Basin Commission and the Resource and Land Investigations Program
                 of the U.S. Department of the Interior, November 1976. Onshore Facilities Related to
                 Offshore Oil and Gas Development: Factbook Boston.

                 New Jersey Department of Environmental Protection, Division of Coastal Resources,
                 198 1. New Jersey Energy Facility Development Potential Study, Trenton.

                 Roy F. Weston, Inc., July 1978. Methodology for Assessing Onshore Impacts for Outer
                 Continental Shelf Oil and Gas Development.

                 United States Department of the Interior, Bureau of Land Management, January, 1979.
                 Final Environmental Statement: Crude Oil Transportation Systems. Prepared for the
                 Northern Tier Pipeline Company, Northwest Energy Company, Kitimat Pipeline Ltd., and
                 Trans Mountain Oil Pipeline Corporation.

                                                            B-56

                                                 NUCLEAR POWER PLANTS

                  Facility Description

                        Nuclear power plants generate electricity by capturing the heat from the control-
                  led fission of uranium-235 (U-235), transferring the heat to water, and using the resulting
                  steam to drive turbines that are linked to generators. In the United States, light water
                  reactors are used. Light water refers to the use of ordinary water to cool the reactor
                  core. Heavy water reactors use heavy water, water whose hydrogen atom has an extra
                  neutron, to cool the reactor core.

                        There are two types of light water reactors--pressurized water reactors (PWRs),
                  and boiling water reactors (BWRs).

                        A PWR is based on a two-step heat transfer process. Water that circulates around
                  the reactor vessel, contained in a closed high-pressure system called the primary water
                  system, is pumped to a heat exchanger, where its heat is transferred to the secondary
                  water system, producing the stream that drives the generator's          turbines.   The spent
                  stream is condensed to water by a third water system, often a once-through pass of
                  water from a river, lake, or other source that is consumed by evaporative cooling.

                        In BWRs, the water that circulates around the reactor core and carries away the
                  heat from U-235 is allowed to vaporize to steam, which directly drives the turbogenera-
                  tor. Since this water is highly radioactive due to its close association with the fuel
                  module, greater design and operating precautions are necessary against possible leakage
                  of radioactive material. However, a higher thermal efficiency is achieved in this one-
                  step coolant cycle design than in the PWR's two-step cycle.

                  Facility Size/Lan'd Requirements

                        Currently operating nuclear power plants have net electric-generating capacities
                  of between 200 megawatts and 1,200 megawatts per unit. Most plants have generating
                  capacities of between 800 and 1,200 megawatts.             In many instances two or more
                  generating units are co-located.

                                                              B-57

                      Minimum site acreages for nuclear power plants are determined by the Nuclear
                Regulatory Commission's (NRCIs) criteria for determining the exclusion area. The radius
                of the exclusion area around the plant is determined by the dosage a person would
                receive in the event of an accidental release of radiation, which in turn is related to
                plant size.

                      Exclusion areas are typically .4 mile (NRC, 1979, NUREG 0625). Thus, assuming a
                half-mile radius around a plant for the exclusion area, and assuming a square site, yields
                a minimum site size of 650 acres per generating unit.

                Site Parameters

                      Proper siting of a nuclear power plant involves consideration of several factors
                including:

                      0    proper topography with adequate flood protection and soils with good load
                           bearing capacity;
                      0    a seismically inactive region;
                      0    proximity to electric transmission lines and access to highways;
                      0    access to and availability of large amounts of water;
                      0    suitable distance from airport-restricted zones and man-made hazards, and
                      0    areas of low population density.

                      The Nuclear Regulatory Commission has very specific regulations concerning
                population densities permitted within 30 miles of a potential plant site.

                Capital Costs

                      For a plant beginning commercial operation in 1982, the following equation can be
                used to estimate capital costs:

                      Capital Cost        $31,840 (MWe-' 4921) KWe

                           Where:
                               MWe        net electrical generating capacity in megawatts

                                                          B-58

                                K We = net electrical generating capacity in kilowatts

                      The capital cost of a 1,000 MWe nuclear power plant beginning commercial
                 operation in late 1982 would be:

                      Capital Cost     = (31,840 $ 103 watts)(1000-*4921 x 106 w atts)(1,000,000 x 103
                                            watts)
                                       = (31,840 $ 103 watts)( 29.94 x 106 watts)(1,000,000 X 10 3 watts)

                                       = $1,063,460,524

                      These costs are  expressed in as-spent dollars. "As spent" dollars are defined as the
                 amount of a revenue   or expenditure expressed in the current or nominal dollar amount
                 prevailing at the time. the revenue or expenditure was incurred. Thus, the total "as
                 spent" cost of a nuclear power plant beginning commercial operation in 1990 would
                 consist of the sum of the current dollars costs incurred each year throughout the
                 construction period (i.e., 1985 current dollar outlays plus 1986 current dollar outlays,
                 etc.). As an example, assume $1,000 is spent for concrete in 1985, and $1,050 for the
                 same amount of concrete -in 1986 (i.e., inflation is 5%/yr.). The total "as spent" cost of
                 concrete during the two-year period would be $2,050.

                      The equation assumes a location 10 feet above the 100-year flood plain and a

                 concrete mat foundation on bedrock.

                 Sources:
                 Budwani, R., Power Engineering, May 1980; Oak Ridge National Laboratory and United
                 Engineers and Constructors, 1980; United Engineers and Constructors, 1977.

                 Employment Profile:

                      The labor force required to construct a nuclear power plant is given in table 1.

                      The manual laborers consist primarily of skilled trades personnel (i.e., boiler-
                 makers, pipefitters, electricians, carpenters, etc.).    Non-manual laborers consist of

                                                           B-59

                clerical and support personnel (about 20%) and foremen, construction managers and
                engineers (about 80%).

                      The operating labor force requirements for the two plant configurations noted in
                table I are indicated as follows:.

                                               One 1,000 Mwe Unit       Two 1,000 Mwe Units

                      Manual                            40                        70

                      Non-manual                       160                      285

                      Total                            200                      355

                      Manual workers consist of equipment operators and laborers (i.e., maintenance personnel),
                while non-manual workers consist of skilled plant operators, engineers, managers, supervisors,
                and support personnel.

                Sources:
                EPRI, 1982; Oak Ridge National Laboratory, 1980; Pennsylvania. Power & Light, 1978.

                                                        B-60

                                                                         Construction and Operating Labor Force
                                                                          Requirements of Nuclear Power Plants

                                   One 1,000 Mwe Unit

                               Year                1       2        3       4         5         6        7        a        9       10

                             Manual                52      418     680      1177     1440      2010      1465     628      209     91
                             Non-manual            13      91       183      243      277       344       328     247      133     47

                               Total               65      509     863      1420     1717      2354      1783     875      342    138

                                   Two 1050 Mwe Units    (constructed concurrently)

                               Year                  1       2        3        4         5        6         7        8        9       10

                             Manual                100     800      1300     2750      2750     3840      .2800     1200     400      175
                             Non-manual             25     175       350      465       530       659      638       472     256       90

                               Total               125     975      1650     3215      3280     4499      3438      1672     656      265

                Enviro nmental Impact

                Air Waste Disposal

                       Construction machinery required for a nuclear power plant can be anticipated to
                emit carbon monoxides, nitrogen oxides, sulphur dioxide, and hyrocarbons. Required
                vehicle emission testing by the State of New Jersey should keep pollutants at a
                minimum, with minimal tourist impact.

                       The use of saline water in the mechanical draft cooling towers will most likely
                result in salt deposition near the facility. Vegetation in the vicinity of the power plant
                could be adversely affected because of the salt deposition. Impacts to tourism and
                recreation from air waste disposal are anticipated to be minimal.

                Water Use/Water Discharge

                       Heat from the fission of nuclear fuel in the reactor is used to produce steam at
                high temperature and pressure, which in turn drives a turbine connected to a generator.
                The "spent" steam is condensed by passing it through condensers with large amounts of
                water. The heat is transferred to the cooling water.

                       Substantial amounts of water are required by the condensers to cool the steam. As
                a result, organisms small enough to pass through the intake screens and be drawn into the
                system will be killed. Mortality is due to mechanical, thermal, or chemical shock.
                Intake screens may impinge fish not large or strong enough to swim safely away.
                Mortality is anticipated to be 100% for those fish impinged on screens.

                       Blowdown, the effluent from cooling towers, is discharged continuously, most often
                at a higher temperature than when originally withdrawn and containing added chemicals.
                Changes in water temperature may af f ect. reproduction, growth, and survival of larval
                forms, juveniles, and adults. The warmer water has a lower dissolved oxygen content.
                Possibility exists for fish and/or plankton kills. Alteration of the aquatic community in
                the immediate vicinity of the discharge site is anticipated.

                                                          B-62

                      Because of state and federal controls on point discharges of liquid wastes, impacts
                 to tourism and recreation should be minimal with proper operations and controls.
                 However, in the event of a large volume of heated waste water being discharged, the
                 water quality and biotic quality will decrease. This may be interpreted as a decrease in
                 the quality of a -recreation area and may result in a decline in the number of
                 participants.

                 Aesthetic Impacts

                      The most visible components of a nuclear power plant would be natural draft
                 cooling towers (where they are required) and the reactor containment building. Natural
                 draft cooling towers can be as high as 500 feet and would be clearly visible over a sizable
                 viewshed, perhaps as far as 3.5 miles given the flat terrain of the study area. Reactor
                 containment buildings may approach 200 feet in height, and would also be highly visible
                 structures. There would be no way to screen either of these structures through the use
                 of vegetation or intervening structures. Thus, the presence of one or more natural draft
                 cooling towers, or a reactor containment building in scenic coastal locations would
                 adversely affect the aesthetic quality of such areas by introd      ucing a highly visible
                 structure clearly incompatible with the existing visual setting.

                 Radiological Impacts

                      The. major potential impact associated with a nuclear power plant is the release of
                 radiological liquid and gaseous effluents. Plant design includes shielding of the reactor,
                 hold-up tanks, filters, and demineralizers. Potential releases of radionuclides also exists
                 in the transportation of the nuclear fuel.

                      Small doses of radiation from the cooling towers and cooling water discharges that
                 are within state and federal limits should pose no threat to wildlife, vegetation, or man.
                 Direct radiation from the machinery within the plant is not expected to be significant at
                 the plant boundary.

                      A significant  effect of building a nuclear power plant is the public's perception of
                 the probability of  a malfunction that would release radiation into the surrounding
                 environment.    Since Three Mile Island, the public's awareness of the potential or

                                                           B-63

                unplanned radioactive release from a facility has certainly been heightened*. It is likely
                that the public's perception of the probability of an unplanned release of radiation is
                higher than the actual probability of occurrence. Clearly, this heightened perception by
                the public could act to also significantly decrease their perception of the recreational
                suitability of an area located in the vicinity of a nuclear power plant.

                                                       Ref erences

                Braid, Robert, April 1981. "Better Work Force Projections Needed for Nuclear         Power
                Plant Construction", Power Engineering.

                Budwani, Ramesh N., August 1982.. "Power Plant Scheduling, Construction and     Costs: 10
                Year Analysis", Power Engineering.

                ------ May 1980. "Power Plant Capital Cost Analysis", Power Engineering.

                Consumers Power Company, 1981. Midland Nuclear Power Plant Report,                 Jackson,
                Michigan.

                Electric Power Research Institute, February 1982. Socioeconomic Impacts of Power
                Plants. EPRI EA 2228, Palo Alto, California.

                Friedlander, Gordon, October 1981. "Coal or Nuclear? Economics Govern", Electrical

                World.

                Oak Ridge National Laboratories and United Engineers      and Constructors, 1980. Power
                Plant Capital Investment Cost Estimates: Current Trends and Sensitivity to Economic
                Parameters. Prepared for the U.S. Department of Energy, Washington, D.C.

                Susquehanna Steam Electric Station: An Update, Allentown, Pennsylvania.

                United Engineers and Constructors, Inc., 1977. Commercial Electric Power Cost Studies,
                Vols. 1-8. Prepared for the U.S. Nuclear Regulatory Commission, NUREG-0247.

                                                          B-64

               United States Department of Energy,  Office of Environmental Assessments, 1979.
               Technology Characterizations: Environmental Information Handbook, DOE/EV-0072,
               Washington, D.C.

                                                    B-65

                                             COAL--FIRED POWER PLANT

                Facility Description

                      The electricity is produced as steam expands over the length of the turbine,
                causing it to spin, in turn driving the generator which produces electricity.           The
                combustion of coal requires extensive on-site materials handling capability (i.e., convey-
                ors, stacker/reclaimers, and storage space), and requires the installation of extensive
                pollution control equipment (i.e., scrubbers and precipitators) to remove the particulates
                and other pollutants produced during combustion.       Coal-fired power plants use large
                amounts of water to remove the excess heat produced by the combustion of coal (i.e.,
                electric generating plants convert only about one-third of the total heat produced into
                electricity; the remaining two-thirds is removed by the cooling water).

                      Coal-fired power plants burn coal in order to produce steam, which is sent through
                a turbine generator, producing electricity. The major components of a coal-fired power
                plant include:

                Facility Size/Land Requirements

                      Coal-fired power plants generally range from 100 to 1,000 gross megawatts
                electrical energy in output capacity per unit. Up to four generating units have been built
                at a given location. In terms of land use, a large plant (800 megawatts) may require over
                1,000 acres of land, mostly for fuel storage and waste disposal.        To determine the
                approximate acreage, output capacity of the plant in megawatts is to be inserted into
                the following equation:

                      AC = 200 + .5(NEGC)

                           Where:
                               AC = plant site in acres
                               NEGC = plant net electrical generating capacity in megawatts

                                                          B-66

                Site Parameters

                      The site for a coal-fired power plant should be relatively flat, with a good load-
                bearing capacity soil and a low ground water contamination potential. Cooling water
                must be available near the site. The site must also be near rail or barge transportation,
                or both, for fuel delivery. A coal slurry pipeline is another possible fuel delivery option.
                The plant should also be sited within a reasonable distance of an existing electric

                transmission line.

                Capital Costs

                      The total capital cost of a coal-fired power plan   t beginning commercial operation
                in 1982 can be estimated using the following equation:

                      Capital Cost= (NEGC `     3538)(NEGCK)

                           Where:
                                NEGC = net electrical generating capacity in megawatts (10    6watts)
                                NEGCK = n   et electrical generating capacity in kilowatts (103watts)

                      The equation yields the following result for a 500 megawatt coal-fired power plant
                beginning commercial operation in late 1982.

                      Capital Cost = ($8451 103 watts)(500 `3538 x 106watts)(500,000 x 103 watts)
                                    = ($8451 103 wattsX. 11094 x 10-6 watts)(500,000 x 103   watts)
                                    = $468,607,950

                      The total "as spent" cost of a power plant with a 1990 start-up date would consist
                of the sum of the current dollar costs incurred for each year throughout the construction
                period (i.e., 1985 current dollar outlays plus 1986 current outlays, etc).         "Current,"
                dollars are defined as the amount of a revenue or expenditure expressed in the nominal
                dollar amount prevailing at the time the revenue or expenditure was incurred.               A

                S
                 pecified amount of concrete may cost $100,000 in 1985 and the amount may cost
                $110,000 in 1986. The total "as spent" cost for concrete during 1985 and 1986 would be
                $210,000.

                                                            B-67

                      Capital Cost = $15,072 (NEGC -,3538  ) NEGCK

                Sources:
                Oak Ridge National Laboratory and United Engineers and Constructors, Inc., 1980, Power
                Plant Capital Investment Costs Estimates: Current Trends and Sensitivity to Economic
                Parameters; Budwani, Ramesh, May 1980, "Power Plant Capital Costs Analysis", Power
                Engineering

                Employment Profile

                      Table I shows the annual average manpower requirements for a 500 megawatt
                coal-fired power plant and a 1,000 megawatt facility consisting of twin 500 megawatt
                units during construction. The figures represent full time, annual workers.

                      Manual workers include laborers, equipment operators, and skilled trades (i.e.,
                boilermakers, pipefitters, electricians, etc.). Non-manual workers include administrative
                and managerial workers, secretaries, and engineers.

                Sources:
                Bechtel Power Corporation, 1982; Budwani, 1982; Burns and Roe, 1978; Electric Power
                Research Institute,* 1982.

                      The following table shows the operational work force for both of the power plant
                configurations noted previously.

                                                       One 500 Megawatt Unit       Two 500 Megawatt Units

                                  Non-manual                       12                          17

                                   Manual                         90                          123

                                  Total                           102                         140

                Sources:
                Burns and Roe, 1978;. Delmarva Power & Light, 1982.

                                                          B-68

                 Environmental Impacts

                 Air Waste Disposal

                      During construction of a coal-fired power plant, combustion emissions from heavy
                 machinery operating on the site include nitrogen oxide and carbon monoxide. Dust is
                 also generated by heavy machinery moving topsoil. Yearly vehicle emission testing by
                 the State of New Jersey will keep emissions to a minimum.

                      Emissions from an operating coal-fired power plant will include sulphur oxides,
                 formed as a result of the combustion of the sulfur in coal, and particulates, consisting of
                 silicates, metal salts, and sodium chloride. Also emitted in lesser amounts from coal-
                 fired power plants are nitrogen oxides, hydrocarbons, carbon monoxide, and metallic
                 compounds.

                      Air quality impacts are influenced by composition of coal M ash and % sulphur by
                 weight), efficiency of the emission control equipment, and local climatic conditions. The
                 perceived impacts of air waste disposal on tourism and recreation will be negligible with
                 proper environmental controls and compliance with ambient air quality standards.

                 Water Use/Water Discharge

                      During construction, sites cleared of vegetation result in exposed topsoil, which
                 decreases the infiltration capacity of the soil. In turn, erosion will increase, producing
                 increased turbidity and siltation in receiving waters.

                      Operation of a coal-fired power plant involves the use of cooling and process
                 water. The quantity of water used daily creates two problems. Quantity demand may
                 exceed supply during seasonal, low flow periods; and the quantity of water affects
                 biological resources near and around intake pipes and screens, and discharge pipes and

                 structures.

                      Cooling water discharges can have a thermal impact on receiving waters by raising
                 their temperature and lowering the dissolved oxygen levels.        If corrosion-prevention

                                                           B-69

                 chemicals have been added to the cooling water, the chemicals may affect surface water
                 quality when they are discharged with the cooling water     . Surface water may also be
                 adversely affected by the acidic quality of coal-pile runoff. The results of increases in
                 water temperature and declines in water quality include adverse impacts on aquatic
                 ecosystems (i.e., declines in species diversity and productivity of habitats), and decreases
                 in the potability of water.

                       The impact to drinking water sources and/or aquatic resources as a result of water
                 use and discharge could also impact tourism and recreational activities in the vicinity of
                 the plant.   A reduction in the number or type of fish species, or a decline in the
                 productivity of habitats near the site would adversely affect recreational fishing and
                 perhaps boating. Algal growth sometimes associated with a thermal discharge may also
                 cause an aesthetic impact and reduce the use of an area for swimming or recreation
                 boating.

                 Solid Waste

                       Operation of a coal-fired power plant results in the production of a considerable
                 amount of solid waste, primarily fly     and bottom ash, and scrubber sludge.        On-site
                 disposal of these wastes is increasingly becoming the preferred alternative. Large piles
                 of ash and sludge, commonly thirty to forty feet high, would constitute a visual intrusion
                 that is out of character with natural settings of recreational areas. Similarly, the large
                 amounts of land required for disposal would diminish the amount of available land
                 available for recreational uses.

                 Noise

                       Ambient sound levels in a non-industrial area can be expected to increase with the
                 construction of a coal-fired power plant.     Heavy machinery involved in construction
                 would be the source of increased sound levels.

                       During operation, ambient sound levels will increase as a result of the operation of
                 coal trains, coal unloading and transfer equipment, and mechanical draft cooling towers.

                                                            B-70

                      Because of the non-industrial character of shoref ront recreational areas,         an
                increase in ambient sound levels would be a significant impact. Although higher sound
                levels may not directly decrease the usability of some areas, the subjective perception of
                a locale's recreational suitability may diminish because it is perceived to be "noisier."
                The attractiveness of other areas prized for their natural, rural settings as places of
                relaxation would definitely decline due to an increase in ambient sound levels.

                Aesthetic Impact

                      Although landscaped buffer zones can conceal parts of an energy facility, a coal-
                fired power plant has three tall and noticeable structures--a stack, a cooling tower, and
                a coal pile. In the relatively flat, recreational study area these three structures would
                be visible from a considerable distance. They would be visual intrusions into formerly
                natural viewsheds.

                      If the visual and aesthetic impact detracted significantly from the existing
                aesthetic quality of an area, recreation and tourism activities could diminish as a result
                of perceptions by users that the suitability or "attractiveness" an area had declined.

                                                       Ref erences

                Budwani, Ramesh N., August 1982. "Power Plant Scheduling Construction and Costs: 10
                Year Analysis," Power Engineering.

                ------ May 1980. "Power Plant Capital Cost Analysis," Power Engineering.

                Burns and Roe, Inc., January 1980. Considerations in Electric Power Plant Siting Coal
                Fired Power Plants 50 to 2400 Megawatts. Prepared for the Power Plant Siting Program,
                Minnesota Environmental Quality Control Board, Oradell, New Jersey.

                Delmarva Power & Light Company, Wilmington, Delaware.             Written communication,
                June 1982.

                Electric Power Research Institute, February 1982. Socioeconomic Impacts of Power
                Plants, EPRI EA-2228, Palo Alto, California.

                                                           B-71

                Friedlander, Gordon, October 1981. "Coal or Nuclear? Economics Govern," Electrical
                World.

                Nobile, P.A., and Kettler, D.J., March 1981. "Selecting An Optimum-Size Coal-fired
                Unit," Electrical World.

                Oak Ridge National Laboratories, and United Engineers and Constructors, Inc., 1980.
                Power Plant Capital Investment Cost Estimates:      Current Trends and Sensitivity to
                Economic Parameters. Prepared for the U.S. Department of Energy, Washington, D.C.

                United Engineers and Constructors, Inc., 1977. Commercial Electric Power Cost Studies,
                Vols. 1-8. Prepared for the U.S. Nuclear Regulatory Commission, NUREG-0247.

                United States Department of Energy, Office of Environmental Assessments, 1979.
                Technology Characterizations: Environmental Information Handbook, Washington, D.C.,
                DOE/EV-0072.

                                                        B-72

                                                      COGENERATION

                 Facility Description

                       Cogeneration is broadly defined as a system in which mechanical or electrical
                 energy, and thermal energy are simultaneously produced at one location. The advantage
                 of cogeneration is to utilize what was formerly wasted energy (i.e., hot exhaust gases or
                 hot cooling water) to produce another form of energy. For example, hot exhaust gases
                 can be used.to heat steam that in turn is passed through a turbine generator to produce
                 electricity, or hot cooling water can be used for space heating.          Given amounts of
                 electricity and thermal energy can be produced for lower fuel inputs than would be
                 required if the same amount of energy were produced in two separate facilities.

                       Cogeneration configurations in which electricity is first produced, and then the
                 steam or hot cooling water is used for process @ or space heating, are known as topping
                 cycles.   Conversely, a configuration in which thermal energy is first produced (i.e.,
                 exhaust gases from an industrial boiler), then used to produce steam that is sent through
                 a turbine generator, is known as a bottoming cycle. Due to the v      ariety of cogeneration
                 configuration, there is no typical application or type of facility. The development of a
                 specific cogeneration application depends upon the energy needs of the primary producer
                 and the needs of the consumer of the cogenerated energy, particularly if the consumer is
                 different than the primary producer. The range of cogeneration applications include the
                 following examples:

                       0    A utility sending hot cooling water from an electric generating plant to a
                            district heating system

                       0    An industrial plant using hot exhaust gases from a smelter to produce steam,
                            then electricity

                       0    A municipal resource and energy recovery facility in which steam is passed
                            through a turbine generator, producing electricity that is sold to the local
                            utility prior to the steam being used in a district heating system

                                                             B-73

                 Facility Size/Land Requirements

                        The size of different cogeneration configurations, in terms of their cogenerated
                 energy outputs, varies widely. The range of the electrical outputs varies from as low as
                 .5-10 megawatts for steam bottoming cycles, up to 5-100 megawatts for steam topping
                 cycles (Detroit Edison, 1980). The thermal output of cogeneration systems ranges from
                 less than 100,000 lbs/hr. of steam to approximately 800,000 lbs./hr. In addition, thermal
                 energy outputs can range from steam at temperatures of up to 1,OOOOF and pressures of
                 up to 900 pounds per square inch (psi), down to hot water at temperatures of up to 250OF
                 and pressures of up to 200 psi (Detroit Edison, 1980).

                        Land requirements may range from virtually nothing for a steam bottoming
                 configuration at an existing industrial boiler to site acreages associated with electric-
                 generating facilities and resource and energy recovery facilities which incorporate
                 cogeneration into their designs. Site acreages for these two facilities are given in their
                 f acility descriptions.

                 Site Parameters

                        Sites for cogeneration facilities should have similar parameters as sites for
                 elect ric-generating facilities, and resource and energy recovery facilities.         Thus, the
                 sites should be flat, with good load-bearing soil, low groundwater contamination
                 potential, and low seasonal water table levels. Sites should be located near surface
                 water bodies in order to obtain cooling water, as well as being located near railroads or
                 large unloading sites for fuel delivery.

                        In addition, cogeneration facilities have to be located near the consumers of the
                 cogenerated energy. Steam is capable of being sent up to five miles through insulated
                 pipes, while hot water can be sent up to 70 miles (Detroit Edison, 1980).                Finally,
                 resource and energy recovery facilities cogenerating electricity must be located near the
                 centers of solid waste generation so as to minimize transportation costs.

                                                              B-74

                 Capital Costs

                      Installed capital costs for various cogeneration cycle configurations range from
                 $550-$830/kW of electrical output for bottoming cycles to $685-830/kW for topping
                 cycles (Power Engineering, 1978). As an example, the installed capital cost of new
                 steam topping cogeneration equipment at the American Cyanamid plant in Bound Brook,
                 New Jersey is estimated at approximately $780/kW of generating capacity (Argonne
                 National Laboratory, 1980).    The capital costs for electric-generating facilities and
                 resource and energy recovery facilities that incorporate cogeneration into their designs
                 would be slightly higher than the capital costs given for these two facilities in their
                 respective descriptions.

                      The most likely application of cogeneration within the study area is a resource and
                 energy recovery facility that burns municipal solid waste (MSW) in a mass burning unit.
                 This facility produces steam for use in an adjacent district heating system; the steam is
                 first sent through a turbine to cogenerate electricity prior to being extracted from the
                 turbine and sent on to the district heating system. A facility processing 1,800 tons per
                 day of MSW that would produce 370,000 lbs./hr. of steam and generate 30 megawatts of
                 electricity is estimated to have a capital cost of $119,130,'000, while a facility
                 processing 3,000 tons per day that would produce 610,000 lbs./hr. of steam and generate
                 5 megawatts of electricity would cost $176,330,000 (Gilbert Commonwealth, 1981).

                 Sources:
                 Argonne National Laboratory, March 1980; Det       rolt Edison, September 1980; Power
                 Engineering, March 1978.

                 Employment Profile

                      The labor force required for constructing cogeneration facilities differs widely due
                 to variations in designs and variations in the composition      of energy outputs from
                 cogeneration configuration. Electric-generating plants and resource and energy recovery
                 facilities incorporating cogeneration into their designs would have construction labor
                 requirements similar to those presented for the two facilities in their respective
                 descriptions.

                                                           B-75

                      Following are construction employment figures for a resource and energy recovery
                facility that consumes 2,000 tons/day of MSW in cogenerating electricity (from steam)
                that is eventually sent on to a district heating system.

                                        Year I                 Year 2              Year 3

                Manual                     84                    350                 190
                Non-manual                 16                     50                 -30
                Total                     100                    400                 220

                      This facility would have a peak employment figure of between  500 and 750 workers
                occurring during the second year.

                      The operating labor force for the above facility would consist of approximately 65
                manual and 15 non-manual employees spread over two shifts per day, six days a week.

                Source:
                Mitre Corporation, March 1981, Draft Report: Environmental Impact Statement for a

                I
                Resource Recovery Facility in Detroit.

                Environmental Impact

                Air Waste Disposal

                      During construction, emissions will be generated by the mechanized equipment and
                vehicles used on-site. These emissions would consist of nitrogen oxide, carbon monoxide,
                and sulphur dioxide.   As with other facilities, New Jersey's yearly vehicle emission
                testing should keep these emissions at a minimum so that the impacts on recreational
                and tourist activities would be negligible.

                      During operation, the air type and quantity of air emissions will be largely
                determined by the type of fuel used in producing the primary form of energy. Resou    rce
                and energy recovery facilities that burn municipal solid waste in waterwall incinerators
                would produce hydrocarbons, hydrochloric and hydroflouric acid, and particulate emis-
                sions.  Conversely, industrial facilities burning coal in boilers where the hot exhaust

                                                         B-76

                gases are used in a steam bottoming application would produce the emissions normally
                associated with the combustion of coal.

                      The impact of air waste disposal from cogeneration applications will vary accord-
                ing to the type and size of the energy facility in which the cogeneration occurs. Coal-
                fired power plants that cogenerate steam for district heating applications would have air
                waste disposal impacts virtually identical to those for coal-fired power plants that do not
                cogenerate. Similarly, in industrial applications where the heat from exhaust gases is
                used to produce steam in a bottoming cycle, there would be no change in the level of air
                pollutant emissions. In summation, the impact of air waste disposal from cogeneration
                facilities will correspond with those already described in other sections for the facility
                that produces the primary form of energy.

                Water Use/Water Discharge

                      Site preparation operations resulting in the clearance of vegetation and the top
                layer of soil increase the potential for erosion and resulting sedimentation in nearby
                surface waters.      However, if soil erosion and control laws are followed during
                construction, the temporary impacts on surface water bodies should be minimal.

                      Substantial quantities of water are required for cogeneration facilities where
                steam is either used in the production of electricity, or circulated through a district
                heating system.    However, in some instances, the cogeneration of steam for use in
                district heating systems may actually lessen overall water requirements for a facility by
                eliminating the need for a condenser or a cooling tower to remove the rejected heat.
                The volumes of water required will also be largely determined by the type of facility and
                the type and quantity of primary energy being produced.

                      The impacts of water use or water discharge from cogeneration facilities on
                tourism and recreation, as with air emission impacts, will largely parallel those already
                described elsewhere for the energy facility producing the primary energy output.

                                                           B-77

                Solid Waste

                      Cogeneration facilities will produce process or combustion residues from the
                production of the primary energy output. Thus, a resource and energy recovery facility
                where MSW is burned, and steam is used to cogenerate electricity, would produce process
                and ash residuals from the combustion of the MSW. The application of cogeneration
                equipment to an existing primary energy production facility would not generally result in
                the production of additional amounts of solid waste beyond that already being produced.
                For example, using steam bottoming cycles to generate electricity in industrial boilers
                producing hot exhaust gases, the initiation of cogeneration would not result in the
                additional generation of any solid wastes.

                      As with the other environmental effects already noted, solid waste production and
                disposal impacts on tourism and recreational activities associated with a cogeneration
                facility will be similar to those described elsewhere for the energy facility type
                producing the primary energy output. Thus, landfilling would be required for the process
                and combustion residuals produced by a resource and energy recovery facility cogenerat-
                ing' electricity. The result would be the potential to adversely affect groundwater
                quality through the seepage of leachate from the landfill. The retrofitting of existing
                industrial boilers to cogenerate energy would result in negligible impacts on tourism, as
                these facilities are not located in or adjacent to desirable coastal recreation areas.

                Noise

                      The construction of a cogeneration facility would generate significant noise levels
                from the mechanized equipment use on-site. Sources of sound generatiorl include heavy
                equipment such as bulldozers, pile drivers, and scrapers. The increase in ambient sound
                levels from this equipment would be a short term impact, confined to the construction
                period.

                      During operation, the size of any increase in ambient sound levels would be a
                function of the size and type of the energy facility being used to produce the primary
                energy output. These two factors determine the type of noise-generating equipment that
                would be present on-site. For example, coal-fired power plants sending steam to a

                                                          B-78

                 central heating system would include the full complement of equipment such as coal
                 crushers, conveyors and rail car unloaders needed to handle the coal on-site.              In
                 addition, resource an'd energy recovery "facilities that cogenerate energy would result in
                 increases in ambient sound levels in adjacent areas due to the movement of trucks to and

                 from the site.

                      Without proper mitigating measures, the presence of a cogeneration facility in a
                 recreational area would likely result in an increase in the ambient sound level and a
                 corresponding decrease in the perceived recreational quality of an area.

                 Aesthetic Impact

                      Some cogeneration applications would include large structures that would be
                 clearly visible in the coastal areas comprising the study area. Resource and energy
                 recovery facilities would contain a stack up to 300 feet and a main building housing the
                 incinerator and the turbine generator up to 150 feet. Similarly, a coal-fired power plant
                 with cogeneration would contain the highly visible structures already noted previously in
                 the description for that fa cility. In most instances, the siting of a cogeneration facility
                 in a recreation area prized for its scenic view would constitute a visual intrusion into the
                 landscape that would decrease tourists' perceptions of the recreational suitability of the

                 area.

                 Odor

                       Resource and energy recovery facilities would be the cogeneration application with
                 the most significant odor impacts. The storage of MSW prior to combustion can release
                 unpleasant odors to -the surrounding arreas if the waste is not properly stored in a closed,
                 sealed enclosure. The presence of such a facility adjacent to a recreational area would
                 certainly result in a decrease in tourists' perceptions of the suitability of the area if
                 odors periodically escaped from the facility.

                                                            B-79

                                                      Ref erences

                Argonne National Laboratory, Energy and Environmental Systems Division, Industrial
                Cogeneration Case Study #2: American Cyanamid Chemical Company. Prepared for the
                United States Department of Energy, ANL/CNSV-TM-37, Bound Brook, New Jersey.

                        Case Study #3, April 1980.      Industrial Cogeneration Case Study #3:      Mead
                C--or-p*oration Paper Mill. Prepared for the United States Department of Energy,
                ANL/CNSV-TM-37, Kingsport, Tennessee.

                Bauer, F.W. and Melick, G.F., 1981. The Reference Plant Concept of Cogeneration.
                Available from Stone and Webster Engineering Corporation, Cherry Hill, New Jersey.

                Detroit Edison, September 1980. The Future Potential of Cogeneration in the Detroit
                Edison Service Area, Detroit.

                Mitre Corporation, March 1981.       Environmental  Impact Statement for A Resource
                Recovery Facility in the City of Detroit. Prepared for Combustion Engineering, Inc.

                Power Engineering, March 1978. Cogeneration.

                Public Service Electric &- Gas, January 1977. Cogeneration Evaluation, Newark, N.J.

                Stone and Webster, Inc., 1981. Central Heating System Study. Prepared for the Detroit
                Edison Company, Cherry Hill, New Jersey.

                                                         B-80

                                     RESOURCE AND ENERGY RECOVERY FACILITY

                 Facility Description

                       A resource and energy recovery facility is any facility that processes and combusts
                 solid waste and utilizes the thermal energy from combustion for the production of other
                 energy, namely steam and electricity. The technologies used include pyrolysis and the
                 combustion of refuse-derived fuel (RDF) or municipal solid waste WSW).

                       Pyrolysis is the thermal decomposition of materials in the abse     'nce or near-absence
                 of oxygen. The products of pyrolysis are a gas, a liquid, and a char, all of which can be
                 used for energy production.      Pyrolysis is as yet an unproven technology, although it
                 offers promise for the future.

                       Incineration with heat recovery can be accomplished either by waterwall incinera-
                 tion or by modular incineration, both of'which have been used successfully for solid
                 waste disposal. Both processes have the advantage of producing useful energy and using
                 proven technology. The steam generated by these facilities can be used as industrial
                 process steam for heating or for driving electric generators. The facilities may also
                 incorporate the cogeneration of energy, where steam used for district heating or process
                 purposes is first sent through a turbine generator to produce electricity. Two types of
                 fuel are used for incineration, municipal solid waste (MSW) and refuse-derived fuel
                 (R DF).

                       RDF is produced by processing municipal solid waste (through shredding, magnetic
                 separation, air classification, or other separation techniques) to remove noncombustible
                 materials. The shredded product may be combusted or further processed to form pellets
                 or briquettes.

                       If a suitable market for the energy produced by a resource and energy recovery
                 facility is not located within economical distance, the RDF produced may be used at
                 other locations to produce steam in a dedicated boiler. The metal and glass by-products
                 can be sold as an additional source of revenue.         A number of operational problems
                 associated with mass burning of solid waste can be eliminated by separating out the
                 metal and glass by-products and other non-com bustibles prior to combustion.

                                                             B-81

                Facility Size/Land Requirements

                      Resource and energy recovery facilities have processing and incineration capacities
                of between 500 and 3,500 tons per day. Most currently operating or proposed facilities
                range between 1,000 and 2,000 tons per day. Resource and energy recovery facilities
                may produce up to 40 megawatts of electricity or one million lbs/hr. of steam. However,
                energy production amounts of 10-15 megawatts or 600,000 pounds per hour of steam are

                more common.

                      Resource and energy recovery facilities require 7 to 25 acres of land per facility.
                The size of the site depends on the capacity and design of the facility and on whether or
                not the fuel preparation and firing operations are in one location.

                Site Parameters

                      Following are considerations for the establishment of site parameters for a
                resource and energy recovery facility:

                      0   flood protection-
                      0   relatively flat land
                      0   proximity to highway, railroad and/or barge transportation
                      0   access to electric transmission lines

                In addition, resource recovery facilities have locational requirements that affect siting
                and, in the long run, affect operating and transportation costs. Locational requirements
                include the following considerations:

                      0   proximity to sources of waste generation which reflect transportation costs
                          for hauling municipal solid waste,
                      0   waste composition which influences the amount and type of recoverable
                          material, energy content, types of pollutants, and amount of ash,
                      0   proximity to markets for recoverable materials (iron, steel, glass, and alumi-
                          num), and
                      0   proximity to a sewage treatment plant for those resource recovery facilities
                          (RRFs) designed to burn sewage sludge.

                                                          13-82

                 Capital Costs

                      Capital Cost = 50,400 (TL)  + 28,500,000

                            Where:
                                  TL = daily combustion capacity in tons.

                      This is for a resource and energy recovery facility that processes MSW to produce
                 RDF, which is then burned in a waterwall incinerator. The steam produced is sent
                 through a turbine generator to cogenerate electricity prior to being sent off-site for
                 heating or process uses. This cost includes a mechanical draf t cooling tower and the
                 necessary air pollution control equipment.

                 Sources:
                 Electric Light & Power Magazine, July 1981, Ocean County Solid Waste Management
                 Plan; Union County Solid Waste Management Plan.

                 Employment Profile

                      Profiles are for a facility designed to handle 2,000 tons per day of municipal solid

                 waste with a waterwall incinerator.

                 Construction:                                  Year I         Year 2         Year 3

                           Manual                                   84           350            190

                           Non-manual                               16            50             30

                           Total                                   100           400            220

                 Peak employment occurs during the second year and averages between 500 and     750.

                 Operation:

                          Manual                                    63

                          Non-manual                                11

                          Total                                     74

                          Plant is staffed for two shifts per day, five days a week.

                                                           B-83

                Source:
                Mitre Corporation, March 19811 Draft: Env     ironmental Impact Statement for a Resource
                Recovery Facility in the City of Detroit.

                Environmental Impact

                Air Waste Disposal

                      During construction of a resource recovery facility, combustion emissions from
                heavy machinery at the site will include nitrogen oxide, carbon monoxide and sulphur
                dioxide. New Jersey's yearly vehicle emission testing should keep the pollutants at a
                minimum.

                      During operation, emissions will be generated by the facility itself and by the
                trucks or barges transporting the solid was   te. Hydrocarbons, hydrochloric and hydro-
                flouric acid, and particulates will be emitted during the operation of the facility.
                Emission levels will depend upon the process used to burn MSW or RFD and upon the type
                of air pollution control equipment used. Air emissions associated with the transfer of
                solid waste will include nitrogen oxide, carbon monoxide, and sulphur dioxide. Siting
                parameters and capital costs encourage a central location for hauling trucks to minimize
                travel time and costs, thereby minimizing vehicle-related air pollution effects.            In
                addition to a central location, New Jersey's emission testing program will aid in limiting
                exhaust emissions.

                      The impact of air waste disposal from a resource and energy recovery facility on
                tourism and recreation is expected to be minimal. Strict New Jersey laws concerning air
                pollution will keep air quality degradation to a minimum.

                Water Use/Water Discharge

                      During construction, the site is cleared of vegetation and, as a result, the exposed
                topsoil alters the water retention property of the soil. Erosion and siltation will increase
                and produce greater turbidity and possible plant growth in nearby surface waters.

                                                            B-84

                      Large quantities of water are requi  .red for the operation of a resource and energy
                 recovery facility, resulting in the generation of significant amounts of wastewater.
                 Major water requirements include cooling tower makeup (where applicable), steam or hot
                 water production, and boiler makeup. Major sources of wastewater are boiler blowdown,
                 cooling tower blowdown, and ash-handling equipment. Wastewater would probably be
                 pretreated before discharge to a municipal sewer system.

                      Impacts of water discharges from an RRF on tourism and recreation are antici-
                 pated to be minimal. The amount of water used by a resource recovery facility is not
                 likely to low'er water supplies.

                 Solid Waste

                      Process residue (i.e., waste not included as either RDF or separated out because of
                 its commercial value) and ash residue comprise the majority of solid waste from a
                 resource recovery facility. The non-com bustibles and ash must be disposed of in a secure
                 landfill, usually located near the facility.

                      The solid waste generated by an RRF will have minimal i        mpact on tourism and
                 recreation.  However, solid waste disposal by landfilling does have the potential to
                 adversely affect groundwater by leaching, and could impact the number of recreation
                 participants drawn to an area.

                 Noise

                      During construction of a resource recovery facility, pile drivers and heavy
                 machinery may generate considerable noise and increase ambient sound levels.           This
                 effect would be especially noticeable in a non-industrial area.

                      Noise from an o   perating facility will be generated by the acceleration of trucks
                 (delivering MSW) and by several pieces of machinery including:

                      0     shredders,

                      0     conveyors,
                      0     magnetic separators,

                                                           B-85

                       0   turbine generators, and
                       0   crushers.

                       Impacts to tourists and recreation participants would be lessened with the
                 incorporation of buffer zones and effective landscaping. However, without these efforts,
                 the perceived quality of an area'could decrease and would be expected to adversely
                 affect the number of participants.

                 Aesthetic Impact

                       Resource and energy recovery facilities have several large structures that would be
                 easily visible from locations within the relatively flat coastal plain, which constitutes
                 the study area.     The building housing the main combustion equipment and turbine
                 generator may be as high as 150 feet, while the stack for some larger facilities may be
                 300 f eet high.  Thus, the siting of a large (3,000 ton per day) resource and energy
                 recovery facility in a coastal setting prized for its scenic view would constitute a visual

                 intrusion that detracts from the natural ambience and recreational nature of such
                 locations. The introduction of a visual element clearly out of character with its setting
                 could decrease tourists' perceptions of the suitability of an area as a location for the
                 enjoyment of recreational facilities.

                 Odor

                       Accumulated municipal solid waste may create an odor problem prior to burning.
                 This is generally controlled by storing MSW in closed, covered areas with negative draft
                 ventilation (drawing air into the structure) to prevent odor from escaping. In addition,
                 continuous burning at resource recovery facilities ensures that MSW is not stored for any
                 length of time and that combustion is complete.

                       With proper operation, odors from resource recovery facilities will have minimal
                 impacts on recreation and tourism in the vicinity.      Any malfunction in odor control
                 operations would lower the quality and aesthetics of the area, and could conceivably
                 detract from the tourism industry.

                                                           B-86

                 Other-Traf fic

                      If the primary method of transporting municipal solid waste is by truck, traffic
                 near the resource recovery area could become congested during peak commuting periods.
                 Siting parameters influence the degree of traffic congestion in and around the site. In
                 most cases, highways and major travel routes will not be affected. Traffic problems will
                 be more evident closer to the facility site. Main routes used by tourists heading to the
                 shore at peak periods (i.e., Friday afternoons) could be temporarily congested due to
                 conflicts with trucks hauling waste to the site.

                                                      References

                 Albrecht, Oscar, August 1981. "What Happened to the Gold in Garbage," American City
                 and County Magazine.

                 American Iron and Steel Institute, 1981. Summary Report of Solid Waste Processing
                 Facilities, Washington, D.C.

                 Congress of the United States, Office of Technology Assessment, 1979. Materials and
                 Energy from Municipal Solid Waste, Washington, D.C.

                 Cunningham, J.A.; Hazzard, N.D.; and Smith, M.L., February 1981.          Economic and
                 Reliable Disposal of Solid Waste by Combustion Engineering. Combustion Engineering,
                 Inc.: Windsor, Connecticut.

                 Electric Power & Light , July 1981. "Success Elusive in Garbage Power," Vol. 59, No. 5,
                 Barrington, Illinois.

                 Electric Power Research Institute, May 1982. Technology Assessment: Municipal Solid
                 Waste as a Utility Fuel, EPRI CS-2409, Palo Alto, California. Prepared by Ebasco
                 Services, New York, New York.

                 M. Disko Associates, June 1979.     Ocean County Solid Waste Disposal and Resource
                 Recovery Management Study; Proposed -Solid Waste Disposal Plan.       Prepared for the
                 Ocean County Board of Chosen Freeholders, Toms-River, New Jersey.

                                                          B-87

                      Union County District Solid Waste Management Plan. Prepared for the Union
               County Board of Chosen Freeholders, Toms River, New Jersey.

               Mitre Corporation, March 1981.   Environmental Impact State ment for a Resource
               Recovery Facility in the City of Detroit. Prepared for Combustion Engineering, Inc.,
               Windsor, Connecticut.

               Stone and Webster, Inc., 1981. Central Heating System Study. Prepared for the Detroit
               Edison Company, Cherry Hill, New Jersey.

                                                    B-88

                                            ELECTRIC TRANSMISSION LINES

                 Facility Description

                       High-voltage electric transmission lines (69 kV and greater) must be installed for
                 bulk transfers of electric power from the power-generating source to the existing
                 electrical transmission system. Transformers at the generating site step up the voltage
                 of the plant-generated electricity to the main transmission voltage.

                       Economic, technical, and environmental factors determine the size and type of
                 transmission line selected. The line voltage and circuitry needed, length of transmission
                 line, costs, land use, aesthetics, and compatibility with the existing system are factors

                 that affect this decision.

                       The structural design of electric transmission lines varies greatly. Design variables
                 include structural type and materials, insulation configuration, and number of circuits.
                 Transmission towers may be single-pole wood, single-pole steel, single-pole concrete,
                 wood-pole H-frame, concrete H-frame, or lattice steel. Insulators are configured in
                 horizontal vees, vertical vees, or single string suspension. Single' or double circuits can
                 be used. The rationale for using two full-capacity circuits is partly based on having a
                 backup; if there should be a power outage on one circuit, the line could continue to
                 transmit electricity at full output on the other.

                 Facility Size/Land Requirem  ents

                       Transmission capacities for electrical lines range from 69 to 765 kV. ROW widths
                 vary from 90 to 280 feet, accordingly. Generally for most tower types, between five and
                 seven towers per mile are required.

                       Approximately 9 to 42 acres are required per mile of electric transmission line.
                 Land requirements vary with the capacity of the line and the capacity affects ROW
                 width requirements.

                                                           B-89

                 Site Parameters

                       Electric transmission lines are generally routed so as to minimize the disturbance
                 to environmentally sensitive areas, minimize adverse aesthetic impacts (i.e. clear cuts
                 through forests), and minimize cost (i.e., shortest route, lowest ROW clearance and
                 installation costs). In some cases, avoidance (if sensitive areas must be balanced with
                 costs where such avoidance would require unusually long corridors. Transmission line
                 corridors passing through regions of high relief, areas having a substantial number of
                 special crossings (i.e., over major highways, rivers, etc.), or heavily wooded or densely
                 populated areas, would result in higher capital costs. Suitable locations for individual
                 towers consist of level areas with soils of sufficient bearing capacity to accommodate
                 the towers, and locations that would be easily accessible for bringing construction
                 materials and power equipment to the site.

                 Capital Costs

                       Capital Costs for transmission lines installed above the ground are represented as
                 f ollows:

                                 169 kV                              CC = $162,000 D
                                 230 kV                              CC =  $285,600 D
                                 345 kV s.c.                         CC =  $540,000 D
                                 345 kV d.c.                         CC =  $1,080,000 D
                                 500 kV s.c.                         CC =  $756,000 D
                                 500 kV d.c.                         CC = $1,566,000 D

                       Capital Costs for transmission lines greater than 230 KV installed below ground are
                       calculated as follows:

                             Capital Cost = $1,836,000 D

                                   Where:

                                         D = distance in miles
                                         s.c.  single circuit
                                         d.c.   double circuit

                                                             B-90

                 These costs assume level topography and minimal special construction costs such as river
                 crossings. In addition, average soil conditions are assumed, which imply concrete mat
                 supports without piles. The cost for underground transmission lines assumes rural/subur-
                 ban conditions with no pavement-breaking and subsequent recovering. All costs may
                 vary depending on topography, type of ground cover, land use, etc.

                 Sources:
                 Burns and Roe, 1980; Electrical World, March 1981; Public Service Electric & Gas, 1981;
                 Rogers and Golden, 1979.

                 Employment ProfUe

                      Construction of an electric transmission line is usually performed in sections along
                 the proposed route, rather than all at once over the entire length of the line.
                 Construction involves two phases--surveying and clearing and tower and line construc-
                 tion.

                      Individual work crews required during surveying and site clearing range from two to
                 ten workers, with up to ten workers needed in heavily forested areas. A total of up to 40
                 workers, dispersed among four, five, or more work crews, are generally working on
                 separate locations clearing the ROW along segments of up to 40 miles in length. During
                 construction, up to 60 workers would be dispersed among several work crews over a
                 similarly-sized segment of the transmission line.

                      Preconstruction crews are expected to move at the rate of ten miles per month.
                 Crews constructing a 138 kV transmission line with single wood towers are anticipated to
                 work at the rate of -10 miles per month. Construction of a 345 kV transmission line with
                 steel towers will take more time, with crews expected to work at a pace of five miles
                 per month. (USDOE, March 1978). Generally, construction work crews can construct
                 between five and ten miles of transmission line per month.

                      Apart from occasional inspection of lines and maintenance of the right-of -way, no
                 operating personnel are required.

                                                           B-91

                 Environmental Impact

                 Aesthetic Impact

                       The towers carrying transmission lines vary in size and type.         The structures
                 include single wooden poles carrying three wires, and steel lattice structures of up to 150
                 feet in height carrying up to six conductor cables. The structures may obstruct views for
                 private homeowners in residential areas and may seriously affect the visual quality of
                 natural settings on public lands. The imposition of cleared ROWs in heavily forested
                 areas can constitute a particularly severe aesthetic impact.       Selective clearing and
                 vegetative screening can mitigate visual impacts to natural areas, but it is not possible
                 to hide transmission towers entirely.

                       Impacts on recreation and tourism depend on existing visual quality of the area,
                 topography, and extent of mitigating efforts.

                 Other-Electrical Effect

                       Audible noise, communications interference, and ozone production are all caused
                 by "corona" discharges from transmission lines.      A corona is an electrical discharge
                 produced  when the electric field intensity at a conductor surface exceeds the electric
                 breakdown potential of the surrounding air.      The released electrons collide with air
                 molecules to cause the disturbances (Roig, 1979).

                       Noise due to corona discharges consists of a sizzling sound in wet weather and a
                 barely audible sound in dry weather.      Radio interference from corona discharges is
                 evident especially in rainy weather for AM reception near the power line. Interference
                 is usually negligible for FM radio and T.V. reception. Corona discharges from high-
                 voltage power transmission lines produce ozone, similar to the production of ozone
                 during lightening discharges. Because of very small amounts of ozone emitted, it is
                 reasonable to conclude that emission of ozone from transmission lines would not
                 seriously affect air quality.

                       Because electrical effects are so slight, they are not expected to affect tourism
                 and recreation participants.

                                                           B-92

                                                     References

                Atlantic Electric, May 1980. Coal-Fired Power Plant Site Selection Study. Prepared by
                Dames and Moore, Cranford, New Jersey.

                Burns and Roe, Inc., January 1980. Considerations in Electric Power Plant Siting: Coal-
                Fired Power Plants from 50 to 2400 Megawatts. Prepared for the Power Plant Siting
                Program, Minnesota Environmental Quality Board, Oradell, New Jersey.

                Electric World, March 1981.

                New Jersey Department of Environmental Protection, September 1981. New Jersey
                Energy Facility Development Potential Study. Prepared by Rogers, Golden & Halpern,
                Philadelphia, Pennsylvania.

                ------ 1979.  Coastal Development Potential Study. Prepared by Rogers, Golden
                Halpern, Philadelphia, Pennsylvania.

                Public Service Electric & Gas, Newark, New Jersey. Written communication, 198 1.

                Roig, Dr. Randy, 1979. Record of the Maryland Power Plant Siting Act, "The Effects of
                Transmission Lines," Power Plant Siting Program, Maryland Department of Natural
                Resources.

                U.S. Department of Energy, March 1978. Environmental Impact Statement: Dickey-
                Lincoln School Lakes Transmission Project, Bangor, Maine.

                                                         B-93

                                              COAL-HANDLING TERMINAL

                 Facility Description

                       Coal-handling facilities are involved in the transshipment of coal between water
                 and land modes of transportation. They operate as centers for the export of U.S. coal,
                 and, to a lesser degree, as distribution points for regional utilities and industries. These
                 facilities contain materials handling equipment to move the coal from one transport
                 mode to another, and often have on-site storage capacity.

                       Coal-handling operations differ in size and on-site facilities, depending on the
                 specific materials-handling system and site of the facility. There are three fundamental
                 approaches to loading coal onto an outgoing collier:

                       0   reclamation of coal entirely from stock,
                       0   loading directly from railcars and/or barges, and
                       0   loading directly from railcars and/or barges as well as reclamation from stock.

                 Facility Size/Land Requirements

                       Coal-handling terminals measure capacity or throughput in torls handled per year.
                 In determining land requirements, six acres are required for every million tons per year.
                 Most recently announced plans involve facilities in the range of 10-15 million tons per
                 year, although two million tons per year is a feasible lower limit.

                 Site Parameters

                       Siting parameters for a coal-handling terminal include consideration of the
                 following factors:

                       0   flood protection,
                       0   proper topography (relatively flat land with good weight-bearing, capacity
                           soils),
                       0   access to railroads,
                       0   access to an all-weather'harbor and adequate wharf or pier,

                                                            B-94

                       0   suitable amounts of land, and
                       0   groundwater contamination protection

                 The volumes associated with specific siting parameters (harbor and.acreage) will depend
                 on throughput capacity and draft requirements of ships.

                 Capital Costs

                       The equation to determine the approximate cost of constructing a coal-handling
                 terminal is listed as follows:.

                       Capital Cost = ($12,000,000)T

                           Where:
                               T = the throughput capacity of the terminal in 10 6 tons per year.

                       This equation assumes foundation costs are included.        The foundation design
                 consists of a. concrete mat foundation on selected backfill for the onshore loading/un-
                 loading equipment. It alsd includes dredging, and wharf or pier costs. In some locations,
                 expenditures for a large volume of dredging, or high capital costs for a long trestle
                 linking an offshore loading/unloading facility to the mainland, could significantly
                 increase capital costs.

                 Source:
                 Alabama State Docks, 1981; Alla-Ohio Coal Co., 1981; Dravo Corp 1981; Port Authority
                 of New York and New Jersey, 1981; Soros Associates, 1981.

                 Employment Profile

                       Following are employment profiles for a coal terminal in Virginia, with a 12 million
                 ton per year capacity:

                                                           B-95

                 Construction:                               Year I            Year 2

                            Manual                             365              365
                            Non-manual                         -37                37
                            Total                              402              402

                 Manual workers include carpenters, electricians, iron workers, laborers, operating
                 engineers, pipe filters, welders, and pile drivers. Non-manual workers include secretarial
                 and administrative persons, engineers, and project managers. Construction is assumed to
                 be over a 24-month period with the numbers reflecting peak employment at the
                 beginning of the second year.

                 Operation

                            Manual                             92

                            Non-manual                           4

                            Total                              96

                 Manual labor will include coal handlers, coal samplers, electricians, quality c         ontrol
                 inspectors, and maintenance people.

                 Sources:

                 A.T. Massey Coal Co.,.Inc.,. 1982; Soros Associates, 1981.

                 Environmental Impacts

                 Air Waste Disposal

                       During construction of a coal-handling terminal, combustion emissions from heavy
                 machinery at the site will include nitrogen oxide, carbon monoxide, and sulphur dioxide.
                 New Jersey's yearly vehicle emission testing should keep the pollutants at a minimum.

                       Operation of a coal-handling terminal involves the transportation of millions of
                 tons of coal. Fugitive coal dust is a major source of air quality degradation. Sources of

                                                              B-96

                 coal dust include coal handling and coal storage      Coal dust deposited on surrounding

                 areas can:

                      0    inhibit photosynthesis in plants,
                      0    harm wildlife that consumes food covered by coal dust,
                      0    alter soil permeability characteristics,
                      0    alter the visual quality of the surrounding region, and/or
                      0    cause respiratory disease.

                 Means of  alleviating sources of coal dust include enclosed systems, dust collection, and
                 water or chemical sprays.

                      Spontaneous heating and combustion within coal storage      areas can create serious
                 environmental and safety problems at transshipment facilities. Spontaneous heating is
                 primarily an oxidation phenomenon involving coal, pyrite, and impure coal substances.
                 Factors affecting spontaneous heating include composition of coal, amount of volatiles in
                 coal, and the method of stockpiling and transportation. Air circulation is the key in
                 preventing spontaneous heating and combustion.

                      Because the study area has a non-industrial character, air quality degradation in
                 the form of coal dust will be a noticeable impact. Coal dust will affect the quality of
                 recreation and tourist areas and may affect the number of participants. The degree of
                 tourism and recreational impact will depend on the type of coal dust air quality controls.

                 Water Use/Water Discharge

                      During construction, the coal terminal site is cleared of egetation, and, as a
                 result, the exposed topsoil alters the water retention property of vthe soil. Erosion and
                 siltation will increase and produce greater turbidity and sedimentation in nearby surface

                 waters.

                      A suitable wharf or pier accessible via a channel of proper depth is required.
                 Dredging will be required to provide sufficient water depth at dockside as well as

                                                           B-97

                 sufficient channel depth. Dredging will alter the biological resources in the vicinity of
                 the dredged site'. If the dredging is extensive, it may change water current patterns
                 significantly enough to alter the coastline.

                       During operation of a coal-handling terminal, water runoff contaminated by coal
                 and other chemical products can degrade surface and groundwater resources. Pollutants
                 enter the waterways as water, reacts with coal pits, dust fallout, and coal spillage.
                 Contaminated runoff contains acids, metals, trace substances, and suspended and
                 dissolved solids. The degree of surface and groundwater impact from coal pile runoff is
                 influenced by the following factors:

                       0   volume of the stored coal

                       0   amount of precipitation

                       0   climate
                       0   terrain and hydrology surrounding the coal pile

                       Without proper controls, surface and gr   oundwater can be degraded by coal pile
                 runoff, thereby damaging biological resources in the area and lowering the area's
                 aesthetic quality.   As a result of poorer water quality, tourists and recreational
                 participants may choose other more usable, aesthetically-pleasing areas for activities
                 such as swimming and fishing.

                 Noise

                       Construction activity for a coal-handling terminal includes grading,    hauling, and
                 erection of structures. As a result, ambient sound levels can be expected to increase
                 temporarily. . During the operation of a coal terminal, the movement of trains and barges
                 to and from the site and the use of coal-handling equipment will increase ambient sound
                 levels. If sound levels rise significantly enough, wildlife in the vicinity of the site may
                 disappear. The aesthetic quality of an area may also decrease with an increased ambient
                 sound level.   In an effort to reduce sound levels, control options include enclosing,
                 insulating, shielding, or buffering the site or equipment.

                       Impacts to tourism and recreation, as a result of the noise generated by coal
                 terminal operation, will be dependent upon the ambient sound levels and the sound

                                                           B-98

                 control equipment. Because the study area has a relatively non-industrial character, an
                 increase in ambient sound levels will be a noticeable impact on the area thereby possibly
                 degrading the aesthetic quality of an area.

                 Aesthetic Impact

                      The major visual quality impact caused by coal-handling terminals results from the
                 obstruction of the horizon. Shiploaders, stacker/reclaimers, the control tower, and the
                 coal stockpile are the tallest structures having the potential to intrude upon the
                 viewsheds of coastal locations. Due to the level topography of the study area, the
                 stockpile and some of the taller equipment could be visible from adjacent areas.

                      The impact of facility development on visual quality depends on design, type of
                 equipment, and land use.     Without the proper siting and design considerations, the
                 aesthetic impact of a coal-handling t  erminal near a recreation area could lower the
                 quality of an area, thereby reducing the number of participants.

                                                       Ref erences

                 Allumena, Bill, Dravo Corporation, Pittsburgh, Pennsylvania. Personal communication,
                 May 198 1.

                 Bary, James, President, . Massay Coal Company, Newport News, Virginia.           Personal
                 communication, June 1982.

                 Browning, Buddy, Alabama State Docks, Mobile, Alabama, Personal communication,
                 March 198 1.

                 Dravo Corporation, 1980.     U.S. Coal Ports Market Study 1980 to 2000.         Marketing
                 Department, Engineering Works Division, Pittsburgh, Pennsylvania.

                 New Jersey Department of Environmental Protection, Division of Coastal Resources,
                 198 1. New Jersey Energy Facility Development Potential Study.

                                                          B-99

                Port Authority of New York and New Jersey, New York, New York.                 Written
                communication, 1981*.

                Rogers, Golden & Halpern, 1982. Environmental Assessment of Coal Transshipment
                Facilities, Camden County Environmental Agency, Camden, New Jersey.

                Soros, Paul, 1981. "Coal Shiploaders for the Mississippi." WWS/World Ports Magazine,
                October/November 198 1.

                United States Environmental Protection Agency, December 1980. The Environmental
                Impact of Coal Transfer and Terminal Operations. EPA 600/57-8--169. Prepared by
                Delon Hampton Associates, Silver Spring, Maryland.

                Von Dobeneck, Klaus, Soros Associates, New York, New York. Personal communication,
                May 198 1.

                                                       F3-1 00

                                                    OFFSHORE OIL PORTS

                  Description

                        Offshore oil ports are deepwater ports for unloading crude oil shipments from
                  supertankers (tankers over 175,000 dead weight tons (dwt)) and very large crude carriers
                  (VLCCs). The crude oil is then sent to shore via a pipeline for transportation to other
                  facilities (i.e., tank farm, refinery).

                        The tankers anchor at unloading buoys called single-point moorings (SPMs).           There
                  are several types of SPMs that can be used in transferring crude oil from tankers to
                  pipelines.   All include as components an anchored floating buoy, floating hoses for
                  conn ecting the tanker manifold to the buoy, and undersea hoses connecting the buoy to
                  submarine pipelines. The tanker is attached to        the buoy with bow anchor lines and is
                  free to weathervane around the buoy. The oil is transferred through the pipeline to an
                  offshore platform that gathers oil from multiple single-point mooring stations. From
                  here the oil is pumped onshore.

                  Facility Size/Land Requirements

                        The recently completed Louisiana Offshore Oil Port (LOOP) has three single point
                  mooring buoys, a 4811 pipeline from the offshore pumping station to shore, and an initial
                  unloading capacity of 1.4 million barrels/day. Other proposed offshore oil ports would
                  have similar capacities.

                        The amount of onshore land required for offshore oil ports depends on the type of
                  support services provided (i.e., pipeline landfall, tank farm, or complete marine
                  terminal). Refer to other energy facility descriptions and their land requirements.

                  Site Parameters

                        Factors determining the siting of an offshore oil port include: offshore location for
                  mooring system and pipeline with acceptable wind and wave conditions; bathymetry and
                  marine geology; proximity to onshore storage tanks and oil terminals; and proximity to
                  man-made hazards (i.e. shipping lanes).

                                                              B-101

                 Capital Costs

                       There is no equation for the capital costs of offshore oil ports due to the limited
                 sampling size. The cost of the recently completed Louisiana Offshore Oil Port was
                 approximately $700 million. The Port Authority of New York and New Jersey estimates
                 the cost of a facility transferring 1.4 to 1.5 million barrels per day at approximately $1.2
                 billion Ct15%) in 1981 dollars. The capital cost varies widely depending upon the quantity
                 of oil transported and the type of onshore storage -facilities required.

                       The total capital cost for a proposed offshore unloading system with a 500,000
                 barrel per day capacity consisting of two singlepoint mooring buoys, each connected to
                 an onshore tank farm by a 2.5 mile, 4811 submarine pipeline is estimated at approximately
                 $62,800,000. This cost includes the undersea pipeline, but does not include any onshore
                 support facilities (United States Department of the Interior, Bureau of Land Manage-
                 ment, 1979).

                 Employment Profile

                       The employment figures reflect the construction of the Seadock Offshore Oil Port,
                 twenty-six miles off the Texas coast.        Seadock consists of two 52-inch crude oil
                 pipelines, an offshore pumping platform, four single point moorings, and an offloading
                 capacity of 2.5 million barrels/day.

                 Construction:

                                                Year I      Year 2      Year 3
                          Manual (89%)              89         196        178
                          Non-manual (1 M           11          24         22

                            Total                  100         220        200

                 Manual workers consist of laborers, equipment operators, and skilled trades workers (i.e.,
                 boilermakers, pipefitters, and electricians). Non-manual workers consist of secretarial,
                 managerial, and administrative employees, as well as engineers.

                                                            B-102

                 Operation:

                          Manual (77%)             54
                          Non-manual (23%)        -16
                          Total                    70

                      The construction employment     figures for the 500,000 barrel per day facility noted
                 previously are as follows:

                 Constructionr                  Year I     Year 2
                                                         (8 months)

                          Manual                  135         135

                          Non-manual               15          15

                          Total.                  150         150

                 Sources:

                 Roy F. Weston, 1978;       U.S. Dept. of the Interior, 1979; and U.S. Department of
                 Transportation, U.S. Coast Guard, 1976.

                 Environmental Impacts

                      Offshore oil ports themselves have few environmental impacts (except for a large
                 oil spill). However, associated with offshore oil ports are onshore facilities, including:
                 support bases, tank farms, pipeline landfalls, and marine terminals.        The facilities
                 supporting the offshore oil port will have more significant environmental effects that
                 may affect recreation and tourism.      These facilities are discussed in accompanying
                 sections and can be reviewed for environmental and associated tourism-related impacts.

                 Air Waste Disposal

                      Hydrocarbon emissions can be expected in very small quantities from offshore oil
                 ports during the transfer of oil.    Impacts on recreation and tourism as a result of
                 hydrocarbon emissions will be negligible.

                                                           B-103

                 Spill/Accidental Discharge

                       Because of the large amounts of oil being transferred and transported from tankers
                 and through pipelines, the risk of an oil spill is present during operation. Spills can range
                 in size from small operating, accidental spills, to larger more significant spills. Although
                 oil spill clean-up equipment has become more advanced, potential impacts from spilled
                 oil remain. Spilled oil has a detrimental effect on biological resources because of its
                 toxic and coating properties.

                       The most significant impact of an oil spill to tourism would be the soiling of
                 beaches and recreation areas.        If the spill moved onto the coast, the aesthetic
                 degradation would be obvious. In addition, swimming, fishing, and boating activities
                 would be hampered. The impact on recreation and tourism would reflect a significant
                 drop in the number of those industries' participants.

                                                         Ref erences

                 Civil Engineering, June 1982. The LOOP Project: Taking the Port to the Ship.

                 Loop Inc., Harvey, Louisiana. Written communication, 1981.

                 Oil and Gas Journal, June 28, 1982.         "Declining Imports Cloud Outlook for U.S.
                 Deepwater Port Projects."

                 Roy F. Weston, Inc., July 1978. Methodology for Assessing Onshore Impacts of Outer
                 Continental Shelf Oil and Gas Development.

                 Travato, Terry, LOOP Inc. Harvey, Louisiana. Personal communication, 1981.

                 U.S. Department of the Interior, Bureau of Land Management, 1979. Final Environ-
                 mental Impact Statement: Crude Oil Transportation Systems, Washington, D.C.

                 U.S. Department of Transportation, U.S. Coast Guard, 1976. Final Environmental Impact
                 Statement for the Seadock Deepwater Port License Application, Washington, D.C.

                                                            B-104

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