L Final Report January 14, 1977 Energy Facility Siting In The Great Lakes Coastal Zone Analysis And Policy Options Great Lakes Basin Commission for The Office Of Coastal Zone Management National Oceanic And Atmospheric Administration U. S. DEPARTMENT OF COMMERCE Digitized by the Internet Archive in 2012 with funding from LYRASIS Members and Sloan Foundation http://www.archive.org/details/energyfacilitysiOOunit Final Report January 14, 1977 Energy Facility Siting In The Great Lakes Coastal Zone: Analysis And Policy Options Prepared for The Office of Coastal Zone Management National Oceanic and Atmospheric Administration U.S. DEPARTMENT OF COMMERCE (Under Contract No. 6-35350) And The Standing Committee on Coastal Zone Management, Great Lakes Basin Commission By The Staff of The Great Lakes Basin Commission: Charles A. Job, Project Manager, Reed M. Bohne, Robert H. Clemens, Thomas Gross, John R. Hall, John A. Johansen, William E. Skimin, David M. Staples, (With the assistance of: Gerald Kotas, Jonathan Mayer, and Timothy Monteith) J- *tf* TOf CGas to stack Stack. gas L> *a- Scrubber CaCO, 4 ■S»» "?, Settler Pump__^/ tank" METHOD I. SCRUBBER ADDITION OF LIMESTONE CaS0 3 + CaS0 4 to waste Stack gas CaCO_— > o Calciner r— >Gas to stack Ca(0H) 2 «S- Scrubber «3- Pump tank CaO Settler ->J CaS0 3 + CaS0 4 to waste METHOD 2. SCRUBBER ADDITION OF LIME r-^Gas to stack CaO +gas CaCO— H Boiler H- Scrubber Pump tank _T > Settler CaS0 3 + CaS0 4 to waste METHOD 3. BOILER INJECTION [Source-222] 142 reactive as lime, which makes it necessary to use more limestone, install a larger scrubber, recirculate more slurry, grind the limestone finer, or otherwise offset the lower reactivity. • Introduction of lime into the scrubber. Scrubbing efficiency can be improved by first calcining the limestone to lime (CaO) and introducing the lime into the scrubber. However, the cost is increased greatly over that for limestone slurry scrubbing, since a lime kiln installation is expensive to build and operate. Use of lime also increases the problem of deposit formation in the scrubber (scaling). • Introduction of limestone into the boiler. The cost of calcina- tion can be reduced in power plants by injecting the limestone into a boiler furnace. The gas then carries the lime into the scrubber. Problems include possibility of boiler fouling, dan- ger of over-burning and inactivating the lime, and increased scaling in the scrubber when the lime enters with the gas [222; pp. 12-13]. Table 9 summarizes the status (as of January 1976) "of the present and projected development (by megawatt capacity) of flue gas desulfurization (FGD) systems in the U.S. By the end of 1976, approximately 10,000 MWe of FGD is expected to be installed. The efficiencies for removal of SO range from approximately 40-90 percent and particulate removal efficiencies generally are above 99 percent for those units designed for particulate removal. Most sys- tems are being designed to operate at 80-90 percent efficiency [336]. TABLE 9 STATUS, NUMBER AND CAPACITY OF FLUE GAS DESULFURIZATION SYSTEMS No. of Status units MW Operational 21 3,796 Under construction 20 7,026 Planned Contract awarded 10 3,761 Letter of intent 10 3,911 Requesting/evaluating bids 7 3,837 Considering only FGD systems 40 19,797 Total 108 42,128 [336] 143 The major resource requirement related to power plant siting that will change if these techniques are used is the amount of land required. As dis- cussed earlier, the amount of land needed for throwaway system waste disposal can be up to 200 acres beyond the normal plant requirements. In addition, facilities will be needed for scrubber material (limestone) delivery and storage at the site. If deliveries are made by water, this may increase the desirabil- ity of coastal locations. Presumably, the same considerations as those related to fuel delivery would be important. b. Nuclear Power Plants (1) Description Nuclear power plants on-line at this time or planned for construction in the next ten years are almost uniformly light water-reactors (LWR) . Figure 7 shows diagrams of the two common LWR types presently in use. In the boiling water reactor (BWR) water is converted to high temperature/high pressure steam (5A5°F. /I ,000 psi) by the core and is used directly to drive the turbine. The pressurized water reactor (PWR) , on the other hand, has two heated water sys- tems. Heat is picked up from the core by the primary system (600°F. /2 ,250 psi) and is transferred to the secondary system via a heat exchanger (the steam generator) . Steam carried in the secondary system is then used to drive the turbine/generator system. For purposes of comparison, a 1000-MWe nuclear power plant has been selected as the unit of analysis. It has been assumed that this plant operates at an efficiency of 32 percent with an average annual plant capacity of 65 percent. Average operating life is assumed to be 30-35 years. Use of a 1000-MWe plant size does not take into account the potential for multiple-unit facilities with combined nameplate capacities of 3000 MWe and above. Because this clustering of 2-4 units on one site seems to be the pre- sent trend, it is important to recognize this practice and examine its effect on the resources required. Efforts will be made, therefore, to indicate how resource requirements change as capacity is raised above 1000 MWe. Nameplate capacity is the power production at 100 percent output; actual out- put is nameplate capacity multiplied by load factor, generally about 65 percent of this (as assumed above) . 144 FIGURE SEPARATORS d DRYERS REACTOR PRESSURE VESSEL FUEL . <; li! CONTROL RODS & DRIVES GENERAL ELECTRIC X> REACTOR FEED PUMP FEED WATER HEATER CONDENSER GENERATOR ( ' COOLING WATER PUMP -'O- COOLING WATER CONDENSATE PUMP FUEL Slijhdy anrichad uranium oxida dad with zirconium alloy MODERATOR Boilino w*t»r COOLANT Boiling v»»t»r PRESSUR2 OF PRIMARY SYSTEM 1.000 pj OUTLET TEMPERATURE 550° F Boiling Water Reactor Power Plant CONTROL RODS & DRIVES PRESSURIZER GENERATOR NDENSER &&§3 \-S COOLING ; : <^ WATE R CONDENSATE PUMP BABCOCK & WILCOX COMBUSTION ENGINEERING WESTINGHOUSE FUEL Slightly onrichtd uranium oxids clad with zirconium tlloy MODERATOR Watar COOLANT Watet PRESSURE OF PRIMARY SYSTEM 2,250 poundi per »qu»rs inch REACTOR. OUTLET TEMPERATURE £05° F Pressurized Water Reactor Power Plant [Source - 203] 145 (2) Site Requirements (a) Land requirements An analysis of 75 existing and proposed nuclear power plant sites shows a size range from 84 acres to 30,000 acres, with an average of 2,730 acres [data in 208]. Further analysis of the same data indicates that the average station size (including power house, reactor, and related buildings, cooling structures, but not including ponds or canals and onsite switching and transmission equip- ment) is 135 acres, or roughly 5 percent of the total site area. Excluding those facilities using cooling ponds or canals for cooling the average total site and station sizes are 1,335 acres and 123 acres, respectively. This indicates that, even without cooling systems requiring a large land commitment (i.e., ponds and canals), nuclear sites are much larger than strict generating requirements dictate. A large part of this additional land requirement is for the provision of an exclusion zone, within which the operating utility has "authority to deter- mine all activities including exclusion or removal of personnel and property from the area" [442; p. 20]. This requirement will be dealt with more fully in the next section. Because the conversion efficiency of a nuclear power plant is 32 per- cent, as compared to 38 percent for fossil fuel plants, the total heat rejec- tion per kilowatt hour is substantially higher. In addition, while 10 percent of the thermal waste produced by a fossil plant is lost up the stock, essen- tially all goes into the cooling water system from a nuclear plant. Thus, 9 total heat rejected by the nuclear facility considered here would be 4.71 x 10 9 Btu/hr, as compared to 3.26 x 10 Btu/hr for a similar size fossil fuel plant. This higher heat rejection rate results in an increase in cooling sys- tem requirements, both in terms of flow across the condenser [discussed in Water requirements, Section IV. A. 3. b (2) (a) ] and land required for the system compo- nents. Table 10 lists the land required for cooling systems of both nuclear and fossil fuel plants. As can be seen from these figures, a nuclear plant re- quires 50 percent more land for its cooling system than does a similar capacity fossil fuel plant. There are several additional considerations which determine the size of the site required. For example, additional land may be needed to provide adequate noise buffering, especially in the case of mechanical draft 146 cooling towers. Another important consideration is the necessity to limit the potential impact of water vapor plumes from the cooling system. Although this aspect of plant siting is not specifically subject to federal or state regula- tion, it must be considered by the utilities in their site selection procedure and envrionmental report preparation. There are other considerations that are not included above. For exam- ple, multiple use areas for controlled public access to shoreline areas and cooling ponds, farming and grazing, and use of other inactive areas on the site, In moving from a single 1000-MWe plant to a multiple unit facility of 2000-4000 MWe, several factors related to total land required will increase. First, it is important to note that the exclusion zone requirement is not based on total plant capacity and will not change for a given site as that capacity is increased. Land requirements that may change include those for cooling, noise abatement, plume dispersion, and the plant itself. The degree of this change is not known and probably is site-specific. Based on the material given above, it is difficult to postulate a "typical" site size for nuclear facilities. Given the figures for the various components that determine site size, a range from 320-3,500 acres would seem reasonable. Multiple unit sites could range up to 10,000 acres if cooling ponds we~e used. (b) Location with respect to population As mentioned in the previous section, there have been regulations pro- mulgated by the AEC, now administered by the NRC, regarding the location of nuclear power plants with respect to population. In general, "long standing policy of the Atomic Energy Commission [now Nuclear Regulatory Commission] has encouraged siting nuclear power plants away from densely populated areas..." [207]. Title 10 CFR Part 100 (Statement of Consideration, Reactor Site Cri- teria, published in the Federal Register, April 12, 1962] specifies a three- tiered system of population-related locational criteria that must be met in Off-site effects of water vapor plumes are also considered by utilities in selecting fossil fuel plant sites, although environmental reports are not required. An exception to this is New York State, which regards cooling tower drift as a settleable particulate, subject to numerical regulatory criteria. Assumes a minimum exclusion area radius of 0.4 miles [570] and a plant size of 100 acres. The only explicit variable is cooling system size. 147 Siting a nuclear facility. The three criteria, illustrated in Figure 8, are: • An exclusion area, which is that area surrounding the reactor in which the reactor licensee must have the authority to determine all activities including exclusion or removal or personnel and property from the area. Activities unrelated to operation of the reactor may be permitted in an exclusion area under appropriate limitations, but the licensee must be in a position to clear the area promptly in the event of an emergency. For example, the area may be traversed by a highway, railroad, or waterway, pro- vided these are not so close to the facility as to interfere with normal operations of the facility and provided appropriate and effective arrangements are made to control traffic on the highway, railroad, or waterway in case of emergency. • A low population zone , immediately surrounding the exclusion area in which the total number of residents and the population density are small enough to provide a reasonable probability that appro- priate protective measures could be taken in their behalf in the event of a serious accident. AEC's regulations do not specify a permissible population density or total population within this zone because the situation varies from case to case. whether a specific number of people can, for example, be evacuated from a specific area, or instructed to take shelter, on a timely basis will depend on many factors such as location, number and size of highways, scope and extent of advance planning, and distribution of residents within the area. • A population center distance , which is the distance from the reactor to the nearest boundary of a densely populated center containing more than about 25,000 residents. [442; p. 20] (c) Water requirements Because of the significantly higher heat rejection rate, the cooling water requirements for a nuclear power plant are substantially higher than those of a fossil fuel plant of similar capacity. Table 11 compares the flow required across the condenser for the fossil fuel and nuclear plants considered here for different temperature rises. As can be seen, flow requirements are two-thirds higher for nuclear plants for a given temperature rise. Estimated water consumption rates for cooling system alternatives have been compiled from various sources and are shown in Table 12. Because of the wide range of values and a lack of uniformity in assumptions among sources, it is difficult to estimate an average consumptive rate for any given cooling alternative. A range of 0^30 cfs would not seem unreasonable. There are, of course, other water requirements for a nuclear facility 148 TABLE 10 COOLING SYSTEM LAND REQUIREMENTS Nuclear Fossil Fuel 1 Once-Through 1 1 Natural Draft Cooling Towers 15 10 Mechanical Draft Cooling Towers 68 45 Spray Canals 150 100 Cooling Ponds 3000 2000 FIGURE 8 [Source - 203] DEFINITION OF EXCLUSION AREA LOW POPULATION ZONE AND NEAREST POPULATION CENTER ^NEAREST POPULATION / ( CENTER, POPULATION / \ GREATER THAN / \ 25,000 DISTANCE C MUST BE GREATER THAN 4/3 DISTANCE Z IN LOW POPULATION ZONE o) PERSONS SUBJECT TO PROTECTIVE MEASURES b) MAXIMUM BODY DOSE 25 REM, AND MAXIMUM DOSE TO THYROID 300 REM FROM EXPOSURE DURING TIME OF PASSAGE OF RADIOACTIVE CLOUD RESULTING FROM ACCIDENTAL RELEASE IN EXCLUSION AREA o)HIGHWAYS, RAILWAYS, WATERWAYS SUBJECT TO CLOSURE b) PERSONS SUBJECT TO EVACUATION c) PERSON MUST NOT RECEIVE MORE THAN 25 REM TOTAL BODY DOSE CR MORE THAN 300 REM TO THYROID FROM TWO HOURS' EXPOSURE. m \ \exclu \ LOW POPl EACT SION JLAT OR / 1 IVREA/ / ON ZONE / [Source 451] 149 TABLE 11 REQUIRED COOLING WATER FLOW RATES Change in Temperature (°F) 30 20 10 gpm cfs gpm cfs ; gpm cf s Fossil Fuel 269,400 600 404,100; 900; 808,20011800 Nuclear 449,000 I 1000 673,500 1500 I 1 ,347 ,000 3000 ■k Figures from Figure 2 beyond cooling. An example of a water flow system through a nuclear facility, proposed Enrico Fermi Units (1075 MWe) , is given in Figure 9 and Table 12 [from 551]. As can be seen, these other flows are not significant when compared to cooling needs. Total withdrawals are 22,545 gpm (50.2 cfs) on an annual average basis, with a total consumptive loss of 11,610 gpm (25.9 cfs). In summary, nuclear power facilities require significantly more water than do similar sized fossil fuel plants, due primarily to differences in ther- mal efficiency. A lower bound of 13,4 70 to 17, 960 gpm (30-40 cfs) withdrawal rate with a consumptive rate of about 11,225 gpm (25 cfs) is not unreasonable for an efficient closed-cycle system. A withdrawal rate of one million gpm (2,230 cfs) for a once-through system with some consumptive loss provides an upper bound (assuming a 15 °F temperature rise across the condenser). The above discussion is based on a single unit 1000-MWe reactor. For each additional unit added, the water requirements given above should be in- creased by a similar amount. This does not take into account possible water use economies of scale that may be available, although it does provide a reasonable rule of thumb. (d) Transportation access Good transportation access to a nuclear facility site is required for movement of fuel and wastes, and delivery of large components during the con- struction phase. Unlike the case of a coal-fired plant, large volumes of fuel are not required on a continuous basis; figures from the Fermi 2 unit are shown in Table 13. In addition, nuclear waste materials (primarily spent fuel) must be it The same is true, of course, for fossil-fuel plants, although it was not discussed at that point. 150 TABLE 12 NUCLEAR POWER PLANT CONSUMPTIVE WATER USE gpm cf s 4520 1 10. 1 1 Once-Through 3590 2 5840 3 8 2 13 3 o 4 o 4 7240 1 16. I 1 Natural Draft Tower 8530 3 19 3 12030 4 26. 8 4 7240 1 16. I 1 12570 2 2 28 Mechanical Draft Tower 8530 3 19 3 12030 4 26. 8 4 Spray Canal 11670 2 26 2 5440 1 12. I 1 Cooling Pond 6290 2 9880 3 14 2 3 22 17740 4 39. 5 4 [78] [207] [51], assumes 1200 MWe [222] 151 1 2 < _i a. WER TORT O LU UJ cl a: 3 fx O _l O u5 u (X 2 LU 152 e CO 1 a, Oi »i () rd T1 ^ u +J ^> CD pi > ,c H < w U, o o o w a w H hJ Cn PQ «! O H H g 0, *— * Oi rtf ^ CD C rH Cr> rrj «J •H 3 H P r: o rd c > M < »< Q) D, O M (U • en o > i? Pj | ^ w rH g >^ Eh rH •H iH 3 X ^ fci rd p en £ C H o Eh (1) s: 2 ^3 < J a, V) •5 . o O rH tn > g r< *-) 3 1 •gj U> -H rH (0 c: X! Cm U ■H +J CD s: c O > sC s CO 2 O J Cm o o O o O o 00 ro O m o CD in rH o en 01 in ro o 00 00 H o rH O o O o O o in o o o 01 rH O o 01 r*- o 00 CM CD o .* -h rd u-i g T) -p (1) -H S-l T) •H nrj 3 rfl CD C C£ -H o o O O o o O ■^ o o + -P m u o Ci, rd > CD 01 c ■H rH o O O u CD 10 C 0) T3 C (J w (D o p 0i c •H rH o o u a o u M-l (0 10 o g o u 03 01 rH VI CD C 2 o o •H P p rd Cn M C -H Oi -H rd O > O W O P C rrj rH & p c CD e p rrj CD .— U O ■P "-' u CD P O P CD rd 5: p rd rH a. O ■P o Oj CO 3 £: o g — O 01 Vj U M-l (D oi o oi p O rH tjl c P -H U-l rH H O ^ o Q O g O o- 01 U-l U 0) c s o o •H -P P rd tn H C O -H D| rH rd O > O W U o o C3 o en o ■* «« O o rH c^ 01 o o o o o o V >* (N o rH C5 cr» o o o Q O 01 C •H P rrj rH U ■H O B o o > U-l 0) en u 0) o p c 0) p 0) rrj -U rd O G Cn O CD Oi c rd JC V X 0) c u r— co en c CD 01 -H M o - <4-l >i P •H u rd ft rd U +J c rd rH a r d CD H> u CD a. >1 -p -H o rd id o Jj c rd p rd TJ > CD O P rH rd y-i rH O CD rH P rd TJ CJ oi ^3 3 153 removed from the plant site for reprocessing or disposal; figures on expected waste shipments from Fermi 2 are also included in Table 14. However, while the annual tonnage of materials moved may be relatively small, the potential (and realized) problems can be quite significant, especially with regard to waste transport : Shipment of spent fuel from the reactor to nuclear fuel repro- cessing plants is the most complicated and expensive shipment in the nuclear fuel cycle. The large amount of shielding needed for a shipping cask designed to carry a single pressurized water reactor (PWR) fuel element brings the cask's empty weight to about 50,000 pounds. The tractor, trailer, and clask will have a gross vehicle weight in excess of the 73,000 pound highway limit which most states impose. Thus, special over- weight permits will be required in many cases for shipment of spent fuel by truck. On the other hand, rail transported shipping casks are envisioned which will carry seven elements per cask and will have a loaded weight close to 200,000 pounds. However, not all reactor sites have rail facilities immediately available at the fuel storage area and some reactor sites equipped with rail facilities cannot obtain rail service because local railroads have refused to transport fuel [203; p. 127]. Because of the potential for long-term catastrophic impacts if an accident should occur during transit, it is important that safe routes be guaranteed over the life of the plant. Careful consideration of the long-term implications of an accident (such as a container leak) should be made before a transit plan is approved for a specific facility, especially if all or part of the route in- volves waterborne movement [625]. The second aspect of nuclear facility siting concerned with transporta- tion access is related to the delivery of construction material and major plant components : The site should preferably be convenient to either bodies of water or rail or road corridors of sufficient width and load-carrying capacity to enable the delivery of construction materials and equipment amd major reactor and turbine components without unac- ceptable disruption of the surrounding environment [207; p. 107]. Many of the plant components are very large and massive, so that "water access is espcially desirable for deliver of large shop-fabricated and assem- bled reactor vessels, although field assembly is becoming more common" [442: p. 8]. For example, For a PWR the reactor pressure vessel itself may be a steel con- tainer 17 feet in diameter and 42 feet long with 9-inch thick walls and a weight of 450 tons... The turbine-generator train may 154 TABLE 14 EXPECTED FUEL AND WASTE SHIPMENTS FOR FERMI 2 FRESH FUEL As semblies Trucklo ads Enrichment Total Wt. Year Load P er Year Per Ye ar (Wt% U) U (KG) 1977 1 (1st Core) 764 24 1.90 142,000 1980 2 (1st reload) 276 9 2.61 51,300 1981 3 208 7 2.61 38,700 1982 4 176 6 2.61 32,700 1983 5 180 6 2.61 33,500 1984 < a) 6 188 6 2.61 34,900 (a) and annually thereafter SPENT FUEL Shipment Total Truckloads Total Wt. Ave . Burnup Year Number Assemblies Per Year U (KG) (MWD/MTU) 1980 1 276 138 50,400 12,000 1981 2 208 104 37,700 18,200 1982 3 176 88 31,800 22,000 1983 4 180 90 32,400 23,500 1984 ( a ) 5 188 94 33,700 26,700 (a) and annually thereafter 155 be as much as 18 feet in xliameter by 200 feet long and weigh 3,900 tons. This component, too, must be shipped to the site in major segments weighing up to 500 tons [207; pp. 107-108]. (e) Seismology and geology Specific regulations have been published regarding seismic and geological protection and assessment of risk for nuclear power facilities ("Design Bases for Protection Against Natural Phenomena," U.S.A.E.C. 10CFR, 50, Appendix A, and "Seismic and Geological Siting Criteria for Nuclear Plants, "U.S.A.E.C, 10 CRF 100, Appendix A). Natural disasters such as earthquakes, volcanic activities, landslides, floodings, and tsunamis are potentially so catastrophic that their possible occurrence at any site could be considered as sufficient cause to exclude the site from further consideration" [207; p. 14]. However, sites subject to flooding, but properly protected , can and have been used. Site characteristics related to soil stability and topography must also be considered. In general, however, slope instability will not "pose any direct hazard to a nuclear power plant that has been well engineered to the environment" [207; p. 15]. Also, Areas of actual or potential surface or subsurface subsidence, uplift, or collapse that can result in such phenomena as ground- water withdrawal or recharge, mineral extraction, cavernous or karst terrain, and regional warping should be avoided [207; p. 17]. Finally, the potential for site inundation by seiches should be considered care- fully before siting of a nuclear facility. (f) Hydrology and meteorology Among the factors important in determining "the magnitude of the radio- active dose received by individuals and the population within 50 miles are... meteorology, and hydrology of the site and its surrounding environs" [203; p. 125] Criteria related to the hydrological and meteorological conditions of a potential nuclear power plant site have been published [see, for example, 207] and in some instances codified into the federal regulatory structure. The most significant meteorological concerns are related to the potential problem of plume formation from a closed-cycle cooling device. As a 156 general rule, the plume from a natural draft tower will rarely extend to the ground, but rather will merge with existing clouds or evaporate before reaching ground level. On the other hand, plumes from mechanical cooling towers, ponds, and spray canals are more likely to cause ground-level fog [207]. Specific consideration should be given to the site dispersion clima- tology during the site selection and evaluation process: A site should provide atmospheric dispersion of radioactive effluents and wate heat sufficient to protect the surrounding environment [207; p. 21]. Specific annual average atmospheric dilution factors have been suggested by the AEC [207; p. 2]]. It is also recommended that specific consideration be given to the cumulative effect of "wind trajectories passing over several scat- tered heat sources" [207; p. 22] on localities near the proposed site. More specific recommendations are made with regard to shoreline sites: If cooling tower plumes or other atmospheric emissions could deleteriously affect the residential, recreational, or other human resources, then shoreline sites which have low over- water diffusion rates and high over-land turbulent mixing should be avoided. This especially applies to shorelines where there are cold currents [207; p. 25]. Two important factors have been identified in evaluating a shoreline site: the change in atmospheric stability that occurs at the land-air interface, and the change in wind trajectory that occurs when air moves from the smooth surface of the water to the irregular land surface. The major concerns related to plume dispersion are potential increases in fog and ice formation in the area surrounding the plant site. Plumes are formed when the effluent from the water-saturated cooling device fails to mix effectively with the drier ambient air. The degree of plume formation and stability is determined primarily by air mixing (mechanical and convective) , temperature, humidity, and ambient air pressure. At sites where the prevailing atmospheric conditions are less favorable for the dissipation of visible water droplet plumes, visibility hazards to transportation and navigation may result. In particular, environmental hazards may occur where water droplet plumes from cooling towers or ponds result in fog formation over corridors of land, sea, or air transportation. Additional hazards caused by icing may result in areas under the influence of cooling towers if ambient air or surface temperatures below freezing are prevalent [207; p. 31]. 157 As mentioned before, fewer fogging and icing problems can be expected from natu- ral draft towers than from other closed-cycle devices. In the Great Lakes Region, there are several important hydrological as- pects of a potential site than must be considered. There must be assurance of a long-term uninterrupted water supply in amounts sufficient to meet the plant's needs. Careful consideration must be given to future development in the plant locality which could change the quantity of water available either for in-plant use or as a receiving body for thermal and chemical effluents. For streams in the Great Lakes Basin supply in g principal consumptive requirements, "the con- sumptive withdrawal should not exceed 50 percent of the lowest monthly mean flow of record unless reservoir capacity is included" [207; p. 40]. In addition, water withdrawals must be related to regional withdrawal agreements, where appli- cable. With respect to ground-water resources, the AEC has stated: Protection of groundwater [sic] supplies is needed for the qualification of a site as suitable for a nuclear power plant. If groundwater is used by the plant, the sustained yield of the groundwater system should not be exceeded, i.e., ground- water mining would require special evaluation. The location and use of groundwater at the potential site must be considered in the selection process if any discharge of water to the groundwater system, planned or inadvertent, may occur [207; p. 43]. Statutory requirements related to water quality are defined in sections 401 and 402 of P.L. 92-500. All water effluents discharged from a nuclear power plant must conform to the limitations established under P.L. 92-500. Thus, "designs associated with site options should in all cases minimize the discharge of any materials which contribute to lowering of water quality" [207; p. 51]. There are several other important requirements in site selection decisions: "Potential sites on waterbodies subject to heavy icing and blockage need special consideration in order to assure continuity of water supply. Because ice can impact upon structures, causing plugging or structural failures, this factor should also be considered in the selection of a site [207; p. 54]. The site must accomodate a power plant design such that the mixing of all heated or otherwise thermally modified discharges to receiving waters can be carried out within the formal mixing zones established by applicable Federal or State regulations [207; p. 57]. Waterbodies which are stratified at any time of the year need 158 special consideration of their vertical mixing characteristics if they are to be used for cooling water" [207; p. 59]. (3) Environmental and Other Considerations There are a number of further considerations that must be included in a site selection and evaluation process. A general consideration is the total impact of construction and operation on the terrestrial and aquatic ecosystems in the vicinity of the site. While there are several important specific aspects to this problem (see discussion below) the overall degree of disruption and change engendered by the plant must be explicitly discussed. The importance of these impacts will, of course, depend on the importance (as measured by scarcity, system function, etc.) of the ecosystems disrupted and the degree of the impact. Related to this is the question of the long-term effect of low-level radioactive emissions on the plant and animal (including human) populations in the plant vicinity. All nuclear power facilities produce some radioactive effluents, both gaseous and liquid, that are released into the environment. The major concern is that these emissions will be taken up by plants and animals and will become concentrated through the food chain (see Figure 10). The generic issue of long-term low-level emission affects are unresolved and are presently under study. FIGURE 10 PATHWAYS OF RADIATION THROUGH THE ENVIRONMENT Critical Pathway for 1-131 Nuclear Reactor Pasturage Discharge of Radionuclides In Gaseous Effluents Discharge of Radionuclides In Liquid Effluents Ground Water Ground Water Supply Animals Farm Products Fish & Shellfish Processing Recreational Exposure Edible Waterfowl Drinking Water Dairy Products Human Population [Source - 451] 159 While this report has not dealt with the nuclear fuel cycle and the problems of waste handling and storage, these factors are important in the general decision to authorize or encourage the development of nuclear power plants. Resolution of problems in these areas is paramount if a major commitment to nuclear energy is to be made. Consideration of these problems must be a part of the decision to permit the continued shift to a higher nuclear share in the electric power fuel mix. One problem that has not been dealt with extensively to date concerns the eventual decommissioning of nuclear power plants. With a life expectancy of 30-35 years, utilities and the public at large will have to face this problem in the near future and consideration should be given to it now. One report [551] stated that a mothballed period of up to 50 years would be required before "all areas of the plant site will be available for unrestricted access" [551; p. 59-62], This means that at least a portion of the site would be committed to the facility for 80 years or more, a long period in terms of land use change and socioeconomic development. Another consideration is whether there is a need for continuous cooling of the reactor throughout the period prior to final decommissioning. If there is, then consideration should be given to providing sufficient cooling water to meet this requirement. If a closed-cycle system is used then potential problems with maintenance of the system through this period of inactivity should be dealt with. As with the other facility types dealt with in this study, perhaps the most important determinant of siting and site requirements is public opinion. However, in the case of nuclear power plants, the public acceptance factor is even more significant as there are basic questions being asked about the desir- ability of using it at all, as evidenced by the many recent State nuclear power referenda. (4) Emerging Technologies There are two principal technological alternatives to the light water reactors presently in use: the high temperature gas-cooled reactor (HTGR) , and the liquid metal fast breeder reactor (LMFBR) . Only the HTGR is considered to be feasible (i.e., potentially applicable as a major producer in the commercial electrical energy market) during the period covered by this study. While the 160 LMFBR may see some commercial use by the end of the study period, there are too many technological and political problems with it to make widespread use feasible, The HTGR was available commercially for a period although it has seen only limited use. Research and development on the process is continuing. Figure 11 shows a cross-sectional view of the major components of a typical HTGR generating system. As opposed to the LWR system, the HTGR uses helium as a coolant and heat transfer medium. Because helium can be heated to higher temperatures and pressures than water, HTGR can achieve efficiencies of 40 percent. The fuel, a mixture of uranium 2 35 and thorium 232, is formed into microspheres and embedded in a matrix of graphite blocks. While large quantities of thorium are not available today (primarily due to a lack of demand) , economi- cally recoverable reserves are thought to be available in sufficient quantities to supply a 100,000-MWe capacity for 400 years [222] HTGR proponents claim significant safety advantages over available LWR systems [222]. First, loss of the helium coolant does not represent as severe a problem as does the loss of the coolant water in a LWR, because the graphite core can absorb substantial amounts of heat. Second, the use of a prestressed concrete reactor vessel (PCRV) adds to the overall safety of the reactor by eliminating the worry of a primary pipe rupture. Third, the use of small, coated fuel pellets instead of large fuel rods reduces the amount of radio- active material released to the coolant should a fuel pellet rupture. Finally, the graphite core reduces the chance of a major core meltdown. Use of a direct-cycle system in which the helium is expanded through the turbine could raise HTGR efficiencies to 50 percent. c . Fuel Transshipme nt and _ Sto rag e Facilities Ports and terminals are being considered as energy facilities insofar as they relate to the transshipment and/or storage of fuels and materials associated with power plants, conversion facilities, and refineries. Because this category is represented by a wide variety of facilities, it serves no use- ful purpose to attempt to establish a generalized definition of any one facility. However, these facilities may be classified according to the type of fuels or materials which they handle, e.g., coal, oil, or nuclear fuels and wastes. Fur- thermore, the six general siting considerations established at the outset of this report may be expanded as they apply to ports and terminals. These facili- ties include harbors, associated storage areas, and combination rail-harbor 161 p fn CM 01 3 o t/3 162 transshipment facilities. (1) Facility Types (a) Coal Development or expansion of coal handling and storage facilities depends directly on projected increases of coal utilization within the Great Lakes Basin and changes in mode of transportation. Furthermore, increased use of low sulfur western coal has necessitated a change in coal traffic flow on the Great Lakes and corresponding development of new storage and handling facilities. The gen- eral considerations associated with the development or expansion of these facili- ties are demonstrated in such specific cases as the coal transshipment facility at the Duluth-Superior harbor and the unloading facility at Marquette, Michigan. In the case of the Duluth-Superior facility, a detailed report [391] was published outlining the site selection process and the impacts associated with the final propsed site. Paramount in the location analysis was the need for multimodal transshipment capabilities (e.g., ship and rail); rail lines capable of supporting unit train transport; and potential for adequate docking facili- ties for large lake freighters. Furthermore, relative proximity to coal source and load center was a major consideration. After selection of the location at Superior, Wisconsin, attention was shifted to defining the impacts of the proposed facility and designing controls to reduce or preclude any negative impacts. The impacts most directly associated with the construction and operation of such a coal transshipment facility are the effects of coal dust on ambient air and water quality. During the process of moving coal from unit train, to storage pile, to conveyor belt, to ship, large amounts of coal dust may be generated and controls must be implemented to reduce the amount of dust which escapes into the air or water. Some controls include wetting down the coal with special suppressants, and the use of restricting bag chutes on the conveyor systems. Other impacts are those generally associated with construction and operation of a major facility. These include dredging, dredge spoil, and land alteration impacts on surrounding air and water quality. Also, magnitudes of community disruption, noise, and aesthetic impacts are considered in the assess- ment of the Superior facility development. The coal unloading facility at Marquette, Michigan [299] is designed to 163 supply coal directly to the Presque Isle generating station at Marquette. Its development was related directly to projected increases in coal requirements by the power plant and a desire to modernize the existing facility. This moderniza- tion included the elimination of a short haul rail line and overall decrease in personnel requirements due to automation. According to the environmental impact statement: Consideration of siting the proposed unloading facility must acknowledge the presence of existing facilities in the vicinity of the site. The immediate environs surrounding the Presque Isle site are presently committed to industrial use. Since the site west of Lake Shore Boulevard has already been dedicated to power generation, the unloading facility can be considered a reasonable adjunct to this enterprise [299]. From the above two examples and others, it is possible to summarize the general resource requirements and the major impacts which are specific to this type of facility. Of primary concern is the availability of land adjacent to existing rail and harbor facilities. Acreage requirements for coal storage and related han- dling equipment vary greatly depending on the configuration of the coal pile and the length of reserve time required. Based on figures from specifications in project reports [391, 203, 299, 526] and communications with coal dock personnel, an approximate figure of 35,000-40,000 tons per acre is reasonable for a coal storage land-requirement, assuming a 40-50-foot pile height. This figure can vary greatly depending on the customer-pile relationships and the type of mech- anical stacking equipment employed. Major impacts of coal handling facilities as evidenced in the previous discussions include disruption of communities during construction, increase in noise levels as a result of heavy equipment use, health and cleaning problems associated with coal dust as a result of coal handling, water quality problems associated with runoff from coal piles, and removal of land from multiple use for storage. (b) Oil Oil storage facilities are utilized at almost all the major ports on the Great Lakes [535]. This includes both crude oil and refined products storage and related transshipment facilities. Future development of storage and han- dling capacity is expected to take place primarily in the form of expansion at 164 existing facilities. This, of course, is highly dependent on decisions regarding potential future development of major pipelines capable of bringing crude oil into the Great Lakes Basin from sources in the West. Considerations of particular importance to the siting of new facilities or expansion of existing facilities which store or handle oil are primarily in the areas of systems requirements and environmental concerns. Presently, most storage facilities contain refined petroleum products and are situated at Great Lakes ports to facilitate ship loading, which in turn insures a wide variety of distribution points without the restrictions of a permanent pipeline. Crude oil on the other hand is routed by pipeline directly to the regining facility. (In 1974, crude oil represented only .2 percent of the petroleum products ship- ped on the Lakes [536]). A discussion of the crude oil-refinery relationship is contained in the following section. Storage and handling facilities are located with regard to existing and potential product distribution systems. Consequently, most oil storage tank farms are located at Great Lakes ports, particularly those ports which have re- fining capacity and, thus, short distance product transport capacity. From a systems planning standpoint, the location of storage facilities at ports and utilization of the extensive shipping network provides for the widest distribu- tion of refined products. A review of some of the important environmental considerations associated with the development or expansion of an oil storage and handling facility is pro- vided by the Lakehead Pipe Line Company for their proposed Refined Products Terminal in Superior, Wisconsin [158]. As might be expected, the primary concern regarding the facility is safe- guarding against potential spills in storage and handling. This would include tank construction, pipeline integrity, and any special precautions required for the loading manifold (pipeline-ship hookup) . Clay dikes surrounding the oil storage tanks are proposed in order to insure control of potential spills in the case of tank leaks. The negative effects of oil on water quality and aqua- tic ecology are well documented; consequently drainage controls and leak security are important considerations. Other considerations for oil storage facilities are those associated with hydrocarbon emissions from storage tanks. Ambient air quality may in some cases prohibit further expansion of oil storage capacity, if this expansion is projected to raise hydrocarbon levels above acceptable standards. Emissions during vessel loading are a particular problem. 165 (c) Nuclear fuel The scope of this study did not allow a complete investigation of the nuclear fuel cycle, nor of the controversial issue of nuclear waste disposal. However, because of the extent of planned nuclear power development in the Great Lakes states, it is necessary to comment at least on handling and storage of the fuels required by these plants and the waste generated from them. Because of the comparatively small volume of fuel required by nuclear power plants, transshipment and storage facilities such as those associated with coal and oil are not a necessary component in the fuel delivery system of nuclear plants. Arrangements for delivery of nuclear fuel involve truck transport from the fuel processing plant directly to the power plant site [379]. Transport and/or storage of wastes remain uncertain at this writing but are anticipated to involve either truck or rail transfer from the generating plant directly to a disposal site or fuel reprocessing center. Consequently, without dismissing the safety and disposal problems associated with nuclear fuels, the role of nuclear fuel transshipment facilities is small or non-existent. (2) General Considerations (a) Systems requirements Expansion of harbor or harbor-rail facilities necessarily depends on com- parable expansion or development in power production or changing emphasis in transporation modes. In addition to new facilities, existing developments, such as harbors, docks, and rails, provide areas for continued expansion. Other sys- tems considerations are the relative distances and related transportation costs between proposed storage or handling facilities and ultimate usage locations. (b) Safety The considerations within this category apply primarily to the environ- mental aspects associated with the storage and handling of fuels. These would include the affects of spills or leaks of radioactive fuels or wastes, the affect of coal dust and other particulate matter associated with coal storage and handling, and the problems with hydrocarbon emissions from oil storage tanks. (c) Engineering Development or expansion of storage and/or handling facilities entail many engineering considerations similar to those discussed for other energy 166 facilities. Most important of these are the feasibility of the land-water inter- face and the design of harbor breakwaters and docks. Likewise, consideration must be given to foundation stability and soil properties. Finally, pollution abatement and control is an important consideration when associated with the preceding and following sections. (d) Environmental Determining site locations for development or expansion of fuel storage and handling systems relies heavily on the potential environmental impacts of the facility: possible water pollution from runoff, spills, and ship activity; air pollution from emissions, hydrocarbon leaks, and coal dust; increase in ambient noise levels due to unloading operations and related industrial activity; aesthetic considerations such as visual impacts of coal piles, tanks, stacks, dust, and railways; decreases in nearby residential land values due to industrial development; and disruption of terrestiral and aquatic ecology. (e) Institutional Regulating and permitting procedures by state and federal agencies must be met in some phases of siting of storage and handling facilties. These would include filing of environmental impact reports with the proper administrative body, application for construction permits with agencies such as the Corps of Engineers or state departments of natural resources, and meeting various state and federal air and water quality standards. In addition, specific safety regulations regarding the storage and/or handling of radioactive wastes would be a special consideration for the placement of these particular facilities. (f) Economics Costs of the above considerations are a major determinant of the loca- tion and mode of storage and handling facility to be constructed. The costs of land acquisition, construction, and operation will vary depending on the type of facility planned and the kind of fuel to be considered. Likewise, pollution control and abatement costs are dependent on the materials and the areas in which they are handled but are major considerations in the planning phase. 167 d. Refine ries^ (1) Description Present petroleum refining facilities in the Great Lakes Basin range from small, less than 10 mbd (1 mbd = 1,000 barrels per day), to plants with capacities greater than 350 mbd. At the present time, there are no new refin- eries under construction in the Basin although several existing facilities are being expanded. The largest expansion identified at this time is one of 27.5 MBD. The only new "grassroots" refinery being considered in the Basin would be a 200 MBD facility at Oswego, New York, although no decision has been made as yet as to whether or not it will be constructed. Further discussion of present and future refinery activity in the Great Lakes Basin can be found in Section IV. B., "Energy Consumption and Movement in the Great Lakes Region." Refineries are by nature very complex systems with many components. As such, it is difficult to characterize a "typical" configuration, size and pro- duct mix. Generally, complexity and associated resource requirements increase with product mix diversity. As will be discussed below, refineries specializing in one or more of the four "standard" products (gasoline, jet fuel, diesel fuel, and fuel oil) are relatively simple and require less area than a diversified refinery producing a wide range of products and petro-chemical feedstocks [292]. Contact with several of the refineries in the Basin has indicated that they pro- duce a broad spectrum of produces with little evidence or regional specialization. Figure 12 shows some of the major components and feedstock flow patterns used in modern refineries. The configuration of these components and flow rates will vary from refinery to refinery, depending on crude oil supply source and product mix. For a more complete discussion of these components, including their potential environmental impacts, the reader is referred to 370. In addi- tion, reference 135 provides concise descriptions of several refinery configurations. (2) Site Requirements General siting considerations for refineries can be broken into two groups: economic criteria and environmental criteria [292]. While both will be For the purpose of this discussion, no distinction has been made between bar- rels per calendar day (annual capacity divided by 365) and barrels per stream day (annual capacity divided by the days the refinery is actually in operation). Generally, calendar day capacity is about 95 percent of stream day capacity. 168 s:: O) o CO _J v. CD o i .f"i JZ o "3 v. a. XJ o > n 2 ~L w a> XJ T (Jo00t7-002) uny ^. a> M Q> 1 V_ cr o ^ v_ «4-- o "J". V) CD M XJ -, 01 X a: XJ S3 S C CO W o uunnpisey o o o in CO (JoOS8-OS9) I JO SD9 o a> O 169 discussed at greater length below, some general observations can be made at this time. The two most important economic criteria are availability of crude oil and access to product markets. The most important environmental criteria con- sidered in the Great Lakes Basin region relate to air and water quality regula- tions. Also important are problems related to visual intrusion (aesthetics) and socio-economic impacts to the local area. (a) Land requirements Estimates of land required for refineries of varying sizes and complexi- ties are shown below in Table 15. Because major Great Lakes refineries would generally fall into the "diversified" class, the acreage estimates given for that class are the most important for this study. TABLE 15 REFINERY LAND REQUIREMENTS (ACRES) COMPLEXITY CAPACITY (MBD) SIMPLE 1 MAJOR PRODUCT 2 DIVERSIFIED 3 j 700 6 100 i 800 6 1860-2105 4 1000 6 200 1400 6 I600 6 3720-4210 4 1800 1400 8 2000 6 250 1750 6 1 2000 6 4650-5265 A 1000 5 2500 6 Gasoline and fuel oil [292] Gasoline, fuel oil, jet fuel, and diesel fuel [292] Wide range of distillates Reference 222 - Room for expansion buffers. Accurate within a factor of 2. Reference 505 (New Eng. Vol.11) Reference 292 - Includes doubling, 60 day storage Reference 370 - Includes doubling, buffers Reference 285 - 15 days storage 170 In a report on refinery siting considerations [370], estimates for land required for 200 mbd account for 1.27-3.73 percent of the total facility cost (estimates based on 1973 dollar costs). As a result . . . refineries have an incentive to buy as much land as possible for use as a green belt and for storage. The green belt is important for aesthetic reasons and so that emissions measured at the fenceline meet standards [370; p. 13]. If it is assumed that future refineries would allow sufficient space to double production capacity as well as provide a green belt to isolate the plant from surrounding land uses, "average" site sizes might be: 100 mbd 1,500 acres 200 mbd 2,200 acres 250 mbd 2,700 acres (b) Location with respect to population When selecting a site for a refinery, there are two countervailing forces considered. One is the necessity of being located close to the finished product market or distribution system to reduce transportation costs. The second is to meet environmental criteria related to reduced air quality impacts, aesthetic and noise impacts, etc. As indicated above, companies are balancing these two criteria by locating on large sites in which it is possible to isolate the plant from the surrounding population. How these two forces balance in a given plant location decision depends on the specifics of the situation and cannot be generalized. (c) Water requirements Water use by a refinery can be partitioned into process water used in producing the distillates (usually an insignificant fraction of total consump- tion) and cooling water. The amount of cooling water required will depend on the component configuration and the extent to which air cooling is used. Typi- cal values are given in Table 16. Reductions in water consumption for cooling are possible using a higher level of air cooling. However, it would increase capital costs and the land required as well as the level of noise produced [505]. Even without a total shift to air cooling, however, refinery dependence on easy water access has been decreasing. This conclusion is best summarized as follows: 171 TABLE 16 REFINERY COOLING WATER REQUIREMENTS WATER REQUIRED CAPACITY (MBD) MGD CFS 100 4/3 1 2 5-10 6.2/4.6 7.3-15.5 200 8/6 1 12.4/9.3 250 10/7. 5 1 4.5-5.4 3 15.5/11.6 7.0-8.4 Estimated 1985/2000 make-up requirements [285] [292], 40-50% air cooling [506], 40% of total flow consumed Historically, siting was dependent upon water supply and waste- water disposal considerations, but this dependence is weakening as water makeup and discharge both decrease with increasing water recycling practices [370; p. 63]. (d) Transportation access As indicated above, the two most important economic criteria considered in refinery siting are crude oil supply and product distribution. In terms of crude oil supply to the plant, there are two principal modes available in the Great Lakes Basin: tankers and pipeline. The extension of the nationwide crude oil pipeline system into the Great Lakes Region has made it unlikely that future refineries will be dependent on tanker-supplied crude oil. This conclusion was reached in a study of the Great Lakes transportation system [147], which stated that, "consideration of oil and gas in relation to the Grat Lakes shipping does not involve to any significant degree either crude or products as cargoes to, from, or within the Lakes." Support for this conclusion came by contacting several of the refineries in the Great Lakes Basin; most crude was received by 172 pipelines from either the southern U.S. or Canada. The product distribution question is somewhat more complicated. Because product transport is more expensive than crude oil movement, this may lead to a situation in which refineries are located close to their potential product mar- kets, with crude oil supplied by pipeline or tanker. In this way, crude oil source is less determinative of site location than is product market location [370]. This view of the site selection process can be summarized as follows: Petroleum refining is rapidly becoming "market oriented" rather than "raw material" oriented. This trend stems from the general concession that transportation of crude to the refinery is less costly than transportation of products to the market .... There- fore, it is very likely that new refineries will be located in the vicinity of the large metropolitan markets such as the East Coast, along the Great Lakes , the West Coast, and the Gulf Coast [370; pp. 53-54] (emphasis added). Under this view, one would expect to see major new refining capacity, either as new plants or large-scale expansions of existing facilities, come into being in the Great Lakes region in the near to mid-term future. There are, however, certain constraints that modify this market-oriented site selection model. Some of these constraints were discussed previously: land and water availability in the quantities required. Others, related to long-term protection from natural disasters, are discussed briefly in subsequent sections. Constraints related to potential environmental and public-acceptance problems will also be discussed in the section, "Environmental and Other Considerations." Of particular importance to this study is that most of the large re- fineries in the Basin are connected to a regional/national product pipeline system (see Figure 13). For this reason, refineries do not have to be located in the vicinity of their potential product market. Instead, the national re- finery system can respond to regional demands and ship products to the points where they are needed. The existence of this demand-responsive system obviates the need for locating refineries in each product market area. Indications at this time are that major new refining capacity will be located outside of the Basin (most likely on the Gulf Coast) and the products moved through this sys- tem to the Great Lakes market. Thus, refineries are not expected to be a major concern in the future energy facility siting in the Great Lakes region. (e) Seismology and geology Requirements for refineries are much the same as those for coal-fired 173 m is i— i -j w Ph H g P o i— i txi < C H H < Pfil O 174 generating plants — i.e., they be located in areas with suitable foundation condi- tions outside of areas with active faults or other types of geologic hazards. (f) Hydrology and meteorology As is the case with the coal-fired power generating facilities, refiner- ies should be located outside of areas prone to flooding and where plant opera- tion will not adversely affect surface and ground-water quality. (3) Environmental and Other Considerations There are several further criteria to be considered in the siting of new fuel processing facilities. The most important relative to the Great Lakes Basin are those concerned with environmental quality. In particular, air pollution emission standards may prove to be the most restrictive in terms of limiting new plant construction (and possible expansion of existing plants). While most air quality problems can be solved, reducing hydrocarbon emissions to the levels specified in the national standards presents major technological difficulties. This problem has been highlighted in several reports dealing with refinery siting [506, 285, and 370], indicating "the need for careful attention to hydrocarbon emissions in refinery siting decisions" [506; pp. 11-50]. How- ever, care must be taken to assess refinery effluent impacts with respect to existing water quality conditions in the receiving stream. Also, low-flow conditions of the receiving waters must be considered in a refinery siting decision. Finally, the state water quality control agencies should be contacted since states have the right to impose water quality standards more stringent than those established at the federal level. The final site selection consideration discussed here, public acceptance, is perhaps the most important of all. It has become increasingly obvious in the past couple of years that public sentiment can be the final determinant of where new refining capacity will ultimately be located. An excellent example of this is the case of the Olympic refinery (400 mbd) proposal for Durham, New Hampshire that was rejected by local residents in 1974 [505]. Thus, it is important that public opinions and attitudes be assessed early in the site selection process. In addition, the issues causing greatest concern, air and water quality degrada- tion, aesthetics, conflicting land use, etc, must be addressed directly at the See discussion of EPA for details of air pollution control program., Chapter III 175 outset. (Some of these impacts are discussed in a subsequent section.) (4) Summary The process of selecting a site for a major new refinery is complex, superceding simple regional boundaries. Because the U.S. refinery system is tied together via an extensive crude oil supply and product shipment pipeline system, the decision of where to locate a new facility is made at the national level, in conjunction with various regional considerations related to crude oil supply and environmental quality limitations. 4. ENVIRONMENTAL AND ECONOMIC IMPACT ANALYSIS a. Introduction This section presents both a discussion of the environmental and economic impacts of the energy facility types considered in this report and a framework within which these impacts can be organized. Because of the specific nature of the data required, this framework cannot be used to perform a regionwide general facility analysis. Rather, it has been included to provide the coastal zone management programs with a concise framework within which they can evaluate pro- posed energy facilities. In addition, it provides a useful summary of the major facility activities as well as the potentially affected environments. Finally, it has been used as a guideline in development the accompanying text material. (1) Framework Approach For each facility type, there is a general discussion on potential im- pacts to both the natural and cultural environments. Following this, there is an activity impact matrix specific to each facility type. On this matrix, activities associated with a given facility are listed on the left-hand side and are cross-referenced with potentially affected environments. There is a separate matrix for each of the major facility types: • Fossil-Fuel (Coal Power Plants • Nuclear Power Plants • Coal Transshipment and Storage Facilities • Oil Transshipment and Storage Facilities • Refineries 176 The degree of impact would be indicated by a numerical entry at the intersection of the appropriate activity and environment. An impact scale of -3 (major nega- tive impact) to +3 (major benefit) is suggested. There would also be a special entry for those potential impacts that are inherently immeasurable. It is important to emphasize again that this system will not and cannot be used in a regionwide analysis. It is, instead, intended to be used by the states in evaluating specific facility proposals. (2) Facility Activities The energy facilities considered in this study have been characterized in terms of activities associated with them. For the purposes of this report, an activity is defined as follows: Activity — The major actions associated with the construction and opera- tion of major energy facilities. These activities have been further subdivided into one or more impact vectors, which are defined as follows: • Impact vectors — Those aspects of an activity which may result in a significant change in the existing environment. In some cases, they repre- sent actions, such as ground clearing and reshaping, equipment use, channeliza- tion, and shoreline modification, etc. Others are the result of an activity, such as influx of temporary work force, wastewater discharge, thermal effluents, etc. It is important to note that they are not potential impacts themselves but rather are elements of facility operation or construction that may cause impacts on certain aspects of the natural and cultural environment. The following material presents definitions of all activities and impact vectors used in the five facility-type matrices. (a) All facilities Construction — That activity associated with the actual development of the energy facility. It is common to all facility types and is found on each matrix. • Ground clearing and reshaping — Those operations involving a physical disruption of the ground surface,, including stripping of vegetation, grading, excavation, road building, and site restoration. • Equipment use — Those impacts directly attributable to the use of construction equipment, such as noise, dust, air pollution, etc. 177 • Channe l ization, shoreline modification , and other water- related activities — All construction activities associated with the water, in- cluding channelization of harbors for moving heavy equipment and material to the site, construction of breakwalls, jetties, and other shore protection de- vices, construction of docks and terminals for fuel and product transshipment, and the construction of water intake and outlet structures. • Material moveme nt^ to^ si^te — Those impacts related to the move- ment of construction materials to the facility site, e.g., disruption of local traffic patterns, deterioration of roads, dust, and noise. • Inf l ux of temporary work force — The impacts of moving a large (1,000-3, 000-person) work force into a local community during the construction of a major facility. These impacts may be expressed in terms of increased demand for housing, increased local business activity, increased local inflation, increased demand for public services, etc. • Public service requirements — The impact that construction of a major new energy facility would have on levels of public services required in the local area (independent of those above), including public safety (fire, police, and medical protection), water supply and wastewater treatment facili- ties, government services, etc. • Land committed to facility — The impact of the lost opportun- ities for potential uses of the land committed to the development of major energy facilities (several hundred to several thousand acres) . • Other — Facility or site specific construction activities, specified on a case-by-case basis. (b) Nuclear power plant operation Reactor Operation — Those impacts associated with the production of power from a nuclear reactor facility. This does not include those impacts generated by the cooling system, by fuel and waste handling, or by the transmission of the electric power. • Rad emissions — Those impacts generated by the emission of radionuclides to the air and water. While a portion of these radionuclide emis- sions are associated with the cooling system, they have been included here to provide for the more general case of overall plant operation. • Wastewater discharge — Those wastewater effluents not associ- ated with the cooling system nor containing radionuclide emissions (e.g., 178 stormwater runoff, sanitary sewage, and other non-process water uses). • Human service requirements — The long-term employment and public service requirements of operating a nuclear power plant facility. This includes plant operating personnel, public safety requirements (possibly includ- ing disaster training for police, fire, and medical personnel), increased gov- ernment services, etc. • Accidents — The potential for major disaster occurrences (e.g., core meltdowns and radioactive gas emissions) . Because of the potentially cata- strophic nature of such an event, its impacts are immeasurable. This category has been included primarily to emphasize that such events should be considered when judging a proposed nuclear facility. Fuel and Waste Handling — Both an activity and an impact vector. For the purposes of this study, consideration of fuel and waste handling problems has been limited to those aspects directly related to the energy facility site; it is beyond the scope of the present project to consider problems related to waste reprocessing and ultimate disposal. While such problems are not explicitly dis- cussed in this report, they must be considered as part of an overall site approv- al process. Coolin g — Those impact vectors directly related to the operation of the facility cooling system. • Thermal effluent — Those environmental impacts related to the release of heated water from the cooling system into the environment. • Chemical additions — The impact of the various chemicals, such as chlorine, added to the cooling waters to prevent fouling, scale formation, etc, • Blowdown water — That fraction of the cooling water removed to prevent the build-up of an undesirable levels of dissolved solids in the cooling water system. It does not include water removed from the boiler-turbine system. • Makeup water requirement — The impacts resulting from cooling system consumptive water use. • Fog/drift — The impacts of the production of a visible water vapor plume (fog) and the deposition of dissolved solid material on the ground surface (drift). • Entrapment/ impingement — The physical impact or damage that the cooling water intake has on aquatic organisms (primarily plankton and fish). • Visual intrusion — Those impacts associated with the physical presence of a major structure as they relate to the surrounding environment. 179 Transmission — Those impacts related to the transmission of electrical energy via EHV and UHV transmission lines. Also included are those impacts of maintaining these large bulk transmission systems. • Visual intrusion — (See previous definition. ) • Disruption of human activitie s — Those impacts related to a limitation on the use of land or the movement of people across it. Examples are the fractionation of property by rights-of-way, and the limitation of the use of lands within a right-of-way. • Natural system disruption — Those impacts affecting the ecology of an area. They may be reflected in changes in the species diversity of the plant and/or animal communities in and around the area of interest. • Electric field effects — Potential impacts of high energy electric fields, especially those associated with UHV (765 KV and larger) trans- mission lines. Examples of these potential impacts include, radio noise (RN) , television interference (TVI) , audible noise (AN), induced voltages, and pro- duction of ozone near the lines. (c) Fossil fuel (coal-fired) power plant operation Fuel Transshipment and Storage — The receiving, movement over short dis- tances, and storage of coal at fossil fuel power plants. • Noise — The impacts of noise generated for a given activity. • Particulates — The impacts of fine solid materials given off to the atmosphere during fuel processing and storage or combustion. • Leachates and runoff — The impact of material leaching and washing off of stored coal and surface wash from plant site in general. • Visual instrusion — (See previous definition.) • Human activity disruption — (See previous definition.) • Equipment use — Impacts associated with the use of fuel-hand- ling equipment. Plant Operation — That activity directly related to the operation of a fossil fuel power plant to produce electricity. • Wastewater discharge — (See previous definition.) • Particulates — (See previous definition.) • S0 X emissions — The impacts of sulfur emissions from plant operation and fuel processing. 180 • NO x emissions — The impacts of nitrogen oxide emissions from fuel processing or combustion. • Human service requirements — (See previous definition.) • Accidents — (See previous definition.) Cooling — (See previous activity and impact vector definitions.) Waste Handling and Storage — An activity associated with the disposal and storage of waste from fuel combustion or processing. This may include fly-ash and spent sulfur dioxide control materials (limestone, dolomite, etc.). Impact vectors included under this activity have been satisfactorily defined previously. • Leachates and runoff — • Particulates — • Visual intrusion — (See previous definitions.) • Human activity disruption — • Natural system disruption — Transmission — (See previous activity and impact vector definitions.) (d) Fuel transshipment and storage facilities General — Activities common to both coal and oil transshipment facilities. • Harbor maintenance — The impact of additional harbor mainten- ance required to service fuel transshipment and storage facilities, including such operations as dredging, dredge spoils disposal, breakwater construction, etc, • Waterborne material movement — The impacts of additional harbor traffic related to the development of a fuel transshipment and storage facility. It only deals with impacts in the harbor area, not on the lakes in general. • Overland material movement — Impacts of material movement in the vicinity of the facility. It does not include impacts of the movement of material from the point of extraction to the facility. Coal Facilities — Those impact vectors specific to coal transshipment and storage facilities. All impact vectors included under this activity have been defined previously. • Human service requirements — • Particulates — • Leachates and runoff — • Visual intrusion — • Human activity disruption — • Equipment use — (See previous definitions.) 181 Oil Facilities — Those impact vectors specific to oil transshipment and storage facilities. • Hydrocarbon emissions — Those impacts associated with the dis- persion of hydrocarbon vapors into the atmosphere. • Leaks and spills — Those impacts that occur through the re- lease of small amounts of oil into the environment. • Visual intrusion — (See previous definition.) • Human activity disruption — (See previous definition.) • Accidents — (See previous definition.) (e) Refineries Crude Oil Receiving and Storage — Those impact vectors related to the movement of crude oil from its arrival point (e.g., pipeline, tanker terminal, or rail terminal) to the refinery complex and its storage onsite. All impact vectors included in this activity have been defined previously. • Hydrocarbon emissions — • Leaks and spills — • Visual intrusion — (See previous definitions.) • Human activity disruption — • Accidents — Plant Operation — Those impact vectors related to fuel processing at a refinery. (The following have been previously defined.) • S0 X emissions — • N0 X emissions — • Particulates — • Hydrocarbon emissions — • Other emissions — Impacts associated with the emission of other refinery residuals to the atmosphere, including aldehydes, carbon monoxide and ammonia. • Leaks and spills — (See previous definition.) • Solid wastes — Impacts stemming from handling and disposal of refinery waste materials, such as sludges and biological solids. • Cooling water consumption — (See Makeup Water Requirement.) • Process Water Consumption — Water consumed in processing crude oil and feedstocks independent of the cooling system requirements. 182 • Wastewater effluents — (See previous definition.) • Visual intrusion — (See previous definition.) • Accidents — (See previous definition.) Product Storage and Shipping — The activity with the impact vectors re- lated to the storage of refinery products and their transfer into a shipment system (truck, train, pipe, or ship). All associated impact vectors have been defined previously. • Hydrocarbon emissions — • Leaks and spills — • Visual intrusion — (See previous definitions.) • Human activity disruption — • Accidents — (3) Impacted Environments The environments potentially impacted by the activities associated with the construction and operation of energy facilities may be conveniently divided into two major categories: natural and cultural. The natural environment in this analysis refers to the existing physical, chemical, and biological charac- teristics of a site or area which may be altered by a proposed activity. The cultural environment may be distinguished from the natural by emphasizing the attributes, uses, and alterations of the environment associated with human development. These may be divided into the social, economic, and physical aspects of the human environment. (a) Natural (i) Physical and chemical characteristics Dividing the environment into its three major components, terrestrial, hydrological , and atmospheric, it is possible to describe the existing conditions and suggest how those conditions may be affected by a proposed activity. Under terrestrial are included the existing soil characteristics defined in terms of quantity and composition and landforms which define the natural topography. The hydrological category includes both the quantity and quality aspects of the surface and ground-water systems. It is necessary to define the existing characteristics of water supply and water quality in order to determine the potential impact of a proposed activity, such as the development of a cooling 183 system and the associated additional demand for water. Changes in water quality that result from this activity are potentially important impacts and should be accounted for in an impact analysis. Examples of such physical and chemical quality changes would include alterations in temperature due to thermal dis- charges from cooling systems and increases in chloride content as a result of chemical treatment. The atmospheric category includes the local meteorology of a proposed site and the ambient air quality associated with the area. Because of the importance of the meteorology to local circulation patterns and affected land uses (e.g., agricultural), any potential impacts from energy facility activities should be outlined prior to implementation. Likewise, any alterations in air quality, beneficial or detrimental, which may result from a proposed activity should be noted in an environmental impact assessment. An example of this would be the increase in hydrocarbon levels associated with the emplacement of a new oil refinery. (ii) Biological conditions The natural biological conditions can be divided into the terrestrial and aquatic ecology of a given area. The terrestrial ecology can be categorized in terms of the vegetation and the wildlife which characterize an area or site for a proposed energy facil- ity. Because of the complex interrelationships within these categories, it is important to outline any potential alterations or disruptions in the vegetation and wildlife communities as a result of activities associated with the construc- tion and operation phases of a proposed facility. Likewise, impacts on aquatic life, such as disruption of benthic com- munities due to dredging, entrainment, and impingement of nektonic communities by water intake systems, and alteration of planktonic life due to thermal changes, are all potentially significant and should be addressed in an overall assessment. (b) Cultural The cultural environment refers to the attributes, uses, and alterations of the natural environment associated with human development. These can be cate- gorized into social, economic, and physical headings. 184 (i) Social Included in the social division of the cultural environment are the un- quantifiable aspects associated with aesthetics and human interest and the poten- tially sensitive areas of public health. Aesthetics and human interest refer to the prevalent values assigned to natural features such as scenic views and vistas, wilderness qualities, land- scape design, unique physical features (e.g., sand dunes), parks and reserves, rare and unique species and ecosystems, and historical or archeological sites. It is possible that activities associated with the development of energy facili- ties may create, enhance, alter, reduce, or destroy those features to which value or interest is attached in a particular area and this impact should be noted. Factors related to public health which may be affected by a specified activity include ambient noise levels, quality and quantity of drinking water, air quality, and safety. In this case, safety refers to the degree to which public well-being may be affected in the event of a major accident such as radiation leaks, fires, or terrorist attack on the facility. (ii) Economic Included in the economic section are those areas of the cultural environ- ment related to the framework within which the human community functions: employ- ment, housing, infrastructure, land value, and local economy. Impacts on employment can be divided into short-term effects related to the construction of a facility and any long-term effects due to increases or decreases in the maintenance and operation staff. Other possible impacts on employment are the indirect or multiplier effects associated with the increased demand on related goods and services, and the decrease in employment associated with new automated technologies. Housing supply and demand in an area are directly affected by the influx or workers associated with a construction project on the short term and permanent staff on the long term. In order to meet housing requirements, this impact must be assessed during the planning stages. Infrastructure refers to the existing transportation network, waste dis- posal systems, utilities, and public services that are required for support of a population in a given area. Changes in these requirements as a result of the development of an energy facility should be planned for and are thus included in 185 the impact assessment. Safety services in this section refer to police, medi- cal, and fire services. Land values may change as a result of energy facility development and related activities. These land values are divided into residential, agricul- tural, commercial, and industrial categories and are considered with regard to their proximity to the proposed facility. In other words, it is possible that residential land values adjacent to a proposed refinery would decrease for its present use, whereas, the value of residential land somewhat removed from the facility would increase due to added demand from added employees. Finally, the local economy of an area may be affected by a proposed energy facility in terms of changes in governmental budgetary or fiscal effects, and positive or negative impacts on local business activity. (iii) Physical Physical aspects of the cultural environment include the existing and potential land and water uses assigned by humans to the natural environment. Also included are the recreational values of the natural environment. Land and water uses have been divided into wilderness and open space, wetlands, forests, grazing, agriculture, residential, commercial, industrial, and designated lands (i.e., state and federal lands). Impacts of energy facility development differ greatly depending on the existing land use of the area under consideration. This is exemplified in the decision of whether to develop on agricultural land, precluding further agricultural use of that land, or to develop on land already used by industry. The impacts on land use and potential alterations in land use are extremely important in an overall assessment of en- vironmental impact. Recreational value assigned to a natural area increases or decreases as a result of an energy facility development. Such a change in value should be recognized at the outset. Recreational categories include hunting, fishing, boating, swimming, and camping. (4) Application The material that follows provides a general survey of the types of natural and cultural impacts that may accompany the construction and operation of a major new energy facility. Because it deals with general energy facility types rather than with specifically proposed projects, it cannot reach the level 186 of detail necessary in actual project evaluation. It will, however, focus atten- tion on certain aspects of each facility type that should be addressed in such an evaluation. The matrices accompanying each discussion are intended to be used as guides in developing a facility siting evaluation process. As such, they can be used in several ways. The activities and environments listed on the matrices could be used as guidelines in developing the elements of such a process. In addition, the matrices themselves could be used as a part of the evaluation pro- cess. This could be done in one, or both, of two ways. They could be used by the state site review agency or agencies in evaluating specific energy facility siting proposals. Alternatively, they could be used by utilities and companies in developing reports on the environmental and economic impacts of their pro- posed projects. Ideally, the state agencies and the companies would use the same framework to facilitate a more comprehensive and free-flowing procedure. Before the analysis of major facility operation impacts, there is a general discussion of construction activity impacts common to all. b. Energy Facility Construction Because most construction activities are common to all of the facilities considered here, discussion of their impacts has been grouped into this one sec- tion. Where differences do exist, e.g., in period of construction, size of labor force employed, and overall project scale, they will be highlighted and discussed separately. In general, power generating facilities of both types require the longer time (7-10 years) and a larger labor force (peak of more than 2,000 persons) for construction than transshipment facilities, which require the less than 2 years and 100-200 persons. The discussion will first address impacts to the natural environment and then examine cultural impacts. (1) Natural Environment Construction activities represent a major disruption of the local environ- ment that can result in significant changes in the surrounding air and water quality. While details as to what those impacts would be and how extensively they would change the existing environment will vary from site to site, a certain amount of generalization is possible. In a report published by the EPA [599], three classes of construction-related pollutants were identified: sediment, chemical, and biological. Of these, very little is known in a quantitative way 187 concerning chemical and biological pollutants. The principal biological pol- lutants are associated with poor sanitary conditions at the site as well as soil organisms released through the physical disturbance of the earth. The major chemical pollutants associated with construction activities are petroleum pro- ducts (the largest group), pesticides, fertilizers, synthetic organic materials, heavy metals, additives used to maintain desirable soil characteristics (includ- ing lime, fly ash, asphalt, phosphoric acid, salt, and calcium chloride), and construction chemicals (glues, solvents, sealants, etc.) Several studies have looked at the effect of construction activities on erosion rates and sediment loads. One study in the Washington D.C. area found that, while lands under natural conditions contributed sediment at a rate of 2 less than 70 metric tons/km /yr, land under development contributed 354 to 2 42,350 metric tons/km /yr [cited in 599]. Other studies have demonstrated simi- lar results: a study in northern Virginia showed that construction activities representing only 6 percent (72.5 ha) of the surface area of a watershed con- tributed 94 percent of the 33,500 metric tons of sediment transported from the basin during a 3-4 year period of record [cited in 599]. In a report prepared for the Atomic Industrial Forum [173], four phases in the facility construction process were identified: • Preconstruction — Those activities which closely follow site selection, including site inventory, environmental monitoring, and implementation of tem- porary impact controls. • Site Work — Site clearing and construction of temporary buildings, access routes (roads, railroad spurs, and channels and docks) and associated facilities. • Permanent Facilities — Activities associated with construction of facility components. • Project Closeout — Removal of temporary buildings and final landscaping. The principal pollutants and potential impacts associated with each are listed in Table 17 [from 203] . The distribution and magnitude of these impacts varies with the type of facility being constructed. For example, impacts on the aquatic ecosystem* par- ticularly the benthos, might be greater in the development of a new fuel trans- shipment facility for which major harbor and channel modification may be neces- sary. In similar fashion, water quality impacts stemming from erosion of 188 TABLE 17 POTENTIAL ENVIRONMENTAL IMPACTS RESULTING FROM CONSTRUCTION PRACTICES ruction Practi (1) Vehicular traffic <2) Test pits b. Envir.-.Ttal monit- oring c. Te-cpora:y controls ll) Srorcrwater (?) Erosion t sedi- ment (3) Vegetative (») Dust -/ roiui>H Sediment spoil, nutrients solid waste ential Env •ital Iroacts Short-term and nominal Du:;t , sediment, and tree injur/ Tree root Injury, sediment Negligible if properly done Shcr' :-term and nominal Vege: :atiop, water quality Vegei •ation, water quality Pert ilizcrs in evcesr. Hegl: Lgible if properly done a. Clearing and dem litior, (1) Clearing (2) De-nolition Temporary facilities (1) Shops t storage sheds (2) Access roads 6 parking lots (3) Utility trenches t backfills (>») Sanitary facili- ties (5) Fences (6) Laydown areas (7) Concrete batch plant (3) Temporary and permanent pest control (ter- mites, weeds, insects) ant , noise, solid Gases, odors, f unes , particulates, dust, deirir.g chemicals, noise petroleum prodacts, waste water, solid wastes, aerosols, pesticides Sediment , dust Short-term Decrease in the area of protective tree, shrub, and ground covers, stripping of topsoil; increased soil erosion, sedieen- tation, and stomvater runoff; increased str-an water terrpera- tures; modif icat ion of stream banks and channels, water quality Increased dust, noise, solid wastes Long-term Increased surf are areas inpervious to water infiltration, increased water runoff, petroleum products Increased surface areas impervious to wat^r infiltration, increased water runoff, generation of dust on unpaved irtas Increased visual irr.pacts, soil erosion, and sedimentation for short periods Increased visual impacts, solid wastes Barriers to animal migration Visual impacts, increased runoff Increased visual impacts; disposal of wastewater, Increased dust and noise Non-degradable or slowly degradahle pesticides are accumulated by plants and animals, then passed up the food chair, to can. Degradahle pesticides having short biological half-lives are preferred for use l. Earthwork . (1) Excavation (2) Grading (3) Trenching (*) Soil treatme d. Site drainage (1) Foundation drainage (2) lewatering (3) Veil points (u) Stream chann relocation t. Lacdjcapinr (] ) Temporary seeding (2) renasen: seeding and sodd int- rust , noise, sediment, debris, wood waste.-., solid wastes, pesti cides, particulates, bituminous products, soil conditioner chemi cals Nutrients, pesticides Long-term Stripping, soil stockpiling, and site grading; increased eros- ion, sedimentation, and runoff, soil compaction; increased in soil levels of potentially hazardous materials; side effects on living plants and animals, and the incorporation of deecrrrposi- tion products into food chains, water quality Long-term Decrease in thp volume of underground water for short and long time periods, increased stream flow volumes and velocities, downstream damages, water quality Decreased soil erosion and overland flow of stormvater , stabilization of exposed cut and fill slopes, increased water infiltration and underground storage of vater, minimize visua impacts heavy traffic areas (1) larking lots (2) Switchyard (3) Railroad spur line Buildings U) Warehouses (2) Sanitary waste treatment (3) Coolirj towers Related facilities (1) Feactor intake I discharge channel (?) Water supply I treatment (3) Stcrmvater drain- age (u) Wastewater treat- ment (5) rams I impound - rents (6) Breakwaters, jetties, etc. (7) Fu-.-l handling equipment (?) O'.l storage ticks, controls, 4 piping (9) Conveying systems (cranes, ho : sts , chutes) Sediment, dust, particulates Sediment, trace elements, noise, caustic chemical wastes, sediment spoil, flocculants, particulates, fumes, solid wastes Long- term Stormwater runoff, petroleum products Visual impacts, sediment, runoff Stormwater runoff Long-term Impervious surfaces, stormwater runoff, solid wastes, spillag Odors, discharges, bacteria, viruses Visual impacts Long-term Shoreline changes, bottom tonography changes, fish nigration, benthic fauna changes Waste discharges, water quality Sediment, water quality Sediment, water quality, trace elements Dredging, shoreline erosion Circulation patterns in the waterway Spillages, fire, and visual impacts Visual impacts Visual impacts (10) Waste handling ec.uipr.-ent (inci erators, wood chipperu, trcsh compactors) Security fencing (1) Access road (2) Fencing Sediments, wood wastes atid visual Long-term Increased runoff Harriers to animal movements FTo-jec F.cmoval of temporary offices 6 shops (1) Dentition (2) Relocation Site restoration C) Finish grading (?) Topsoiling (3) Fertilising CO Sediment een;roia Preliminary start-up (1) Clearing (?) Flushing Noise, dust, solid wistc- Sediment, dust Nuetien:--., petroleum products Short-tcvm Noise, solid waste, dust Stoi-rrrwatcr , runoff, traffic blockages, SDil compact ion Short-term Sediment, duct soil co-paction Frosion, sediment Nutrient runoff, water quality Vegetat ion Short -tern Water quality, oils, phosphate and ot^er nutrients 203] 189 excavated and cleared soil might be greatest for a nuclear facility construction site because of the longer construction periods involved. The impacts associated with a given construction activity must be evaluated in light of the specific conditions of the site under consideration and the actions proposed by the developer. A list of factors having a bearing on these impacts include: • Resistiince of the surface and subsurface soils to erosion by gravity, water, and wind • Chemical and physical properties of the soils and parent materials • Topography and size of the jobsite • Distribution and frequency of rainfall • Care used in trapping sediment and collecting liquid wastes • Area and time duration of exposure of cleared and excavated portions of the jobsite • Number of people and machines linked with each jobsite at successive stages of the construction effort [173; p. 4]. (2) Cultural Environment The impacts of construction on the cultural environment in the vicinity of a proposed energy facility can be severe as evidenced in the Alaskan Pipe- line experience. While it is unlikely that impacts of such magnitude would be experienced in the Great Lakes Region, certain elements of development-induced cultural system change must be considered. Tables 18 through 21 present employment profiles for each of the facility types considered. The different facility types show considerable variation in terms of construction time, peak construction employment, and operating employ- ment requirements. Because of its small construction manpower requirements, it is not likely that the development of a new fuel transshipment facility would cause any significant cultural system impacts. On the other hand, the large work forces and relatively long construction periods with high levels of employ- ment for power plants and refineries create the potential for some local social impact. The magnitude of this impact depends on existing socioeconomic condi- tions and must be evaluted on a case-by-case basis. Cultural impacts during the construction and pre-operational stages of major facilties development arise from three major sources: influx of a large construction work force, the movement of construction materials through the 190 TABLE 18 WORK FORCE PROFILE: NUCLEAR POWER PLANTS' PRO POSED P W E R PLANT INFORM A T I N HYPOTHETICAL Belefonte (2430HWe) McGuire (2360MWe) River Bend (1870MWe) Susquehanna (2100MWe) AVERAGE (2200HWe) Year Construction Operation Construction Operation Construction Operation Construction Operation Construction Operation 1 850 850 100 300 418 2 1500 1537 350 1800 1232 3 2150 1810 1200 2300 1980 4 2240 30 1634 2100 2500 2200 5 1660 155 950 30 2000 2400 1914 6 630 170 200 170 1650 1500 1254 35 7 170 200 1000 30 800 396 105 8 170 200 300 70 250 20 140 9 170 200 100 100 60 140 10+ 170 200 100 77 140 [390] TABLE 19 WORK FORCE PROFILE: FOSSIL FUEL (COAL) POWER PLAN T S PROPOSE D POWER PLAN T INFORMATION BECHTEL ESTIMATES (800MWe) Colstrlp 3 & 4 1 (700MWe) Tombigbee 2 & 3 1 (420MWe) 2 Pleasant Prairie 1 & 2 (l234MWe) Year Construction Operation Construction Operation Construction Operation Construction Operation 1 270 180 48 40 2 1418 972 155 420 3 1418 972 566 864 4 270 173 180 112 1131 814 5 693 450 578 360 109 6 693 450 845 109 7 693 450 81 120 109 8+ 693 450 120 109 [390] [573] [541] Unit 1 completed in year 5, Unit 2 in year 7. probable error less than 25%. 191 TABLE 20 WORK FORCE PROFILE: REFINERIES 250 MBD 1 200 MBD 3 Low Fuel Oil High Fuel Oil Low Fuel Oil Year Construction ■ 2 Operation Construction 2 Operation Construction Operation 1 2180 1800 521 2 2180 1800 2536 3 2180 1800 3272 4 435 410 1257 5+ 435 410 551 [506] [505] [541], probable error generally less than 25%, TABLE 21 WORK FORCE PROFILE: FUEL TRANSSHIPMENT FACILITIES C f) A L OIL • 1 Super ror , Wi so ons in 2 Marquette, Michigan . 3 Superior, Wisconsin (8 million tons/yr) (12 million tons/yr) (6.2 million barrels/yr) [ Construction Period I (months) i 20 12 12 1 Construction Employment 100 - 150 - 200 ! 1 Operating Employment 50 2 4 8-12 [391] [299] [158] Based on operator time requirements 192 local area, and the presence of the facility itself. Of these, the potential for the greatest cultural system damage is associated with the first, while the greatest potential benefits stem from the third. Of course, the magnitudes of the costs and benefits associated with each will vary from case to case. (a) Influx of work force For a construction project of the magnitude considered here, there will be 1,000-3,000 workers employed at the site for periods of up to five years. It is doubtful that a mix of the skilled tradesmen in the quantities required could be found locally unless the site were near a major metropolitan area. In other cases, a large fraction of the work force would have to come in from outside of the local area and either commute (daily or for the week days, leaving on week- ends) or move into the local area for the duration of the project. Construction workers generally are willing to commute long distances to job sites, with 50-100 miles each way not uncommon [451]. Figure 14 shows those areas within 75 miles of major metropolitan areas (SMSAs with 1970 populations of 500,000 per- sons or more) in the Basin where daily commuting may be possible for a large portion of the work force. While it may not present a complete picture of "local work force availability," Figure 14 does at least indicate that the south- ern, more heavily developed portion of the Basin may generally be less suscepti- ble to the types of impacts associated with heavy in-migrations of construction workers. The reader is cautioned about drawing conclusions from Figure 14 and the brief dicussion of it that go beyond the material presented. In reality, the problem of a commuting versus transient resident work force is much more complex, depending on many factors, some site-dependent, others supralocal. One factor that must be considered is the attractiveness of the site community in terms of inducing workers to move from their present locations to the local area. For example, if the workers were being drawn primarily from large metropolitan areas of great cultural diversity (shopping, entertainment, recreation, schools, etc.) that a rural job site could not offer, then it might be that those that could commute would do so. If however, the site were in an area similar to those For the purpose of this discussion, the physical presence of the facility it- self, regardless of its operational status, will be considered under construction impacts. Impacts and residuals stemming directly from the operation of the plant are discussed in later sections. 193 FIGURE 14 GENERALIZED POTENTIAL COMMUTING ZONE 194 in which the potential work force lived at present, there may be more in-migra- tion to the local community. Another factor is that the contractor and subcontractors may bring a portion of the labor force in with them, especially for the managerial and highly skilled engineering positions [451]. Thus, if non-local construction firms were used, it is likely that at least a portion of the work force would be brought in form outside of the area. Labor union practices are also important in determining the geographic origin of the construction work force [451]. How jobs are distributed to mem- bers of the various craft locals will influence the mix of commuting versus resident workers: It was found to be a general rule that the location of the union had much to do with the housing and commuting patterns of the work force. For instance. . .more people commuted to the job site from Leominster and Fitchburg [Massachusetts], a dis- tance of roughly one hour by good road, than might have been expected. The cause of the heavy commuting was the fact that most of the carpenters working on the site were from the Fitchburg-Leominster area [and] nearly all the field employees commuting from that area were., and are, carpenters [451; p. 175]. Another factor that should be considered is the condition of the local (i.e., commuting) construction labor market. If unemployment among the skilled trades is high, then more local commuting might be expected. If, on the other hand, the available labor force is fully employed, then immigration from other regions may provide a large percentage of the needed workers. There are three patterns of work force entry to the local area: daily commuting, Monday-Friday commuting (where the worker stays in the area during the week and travels to a permanent home over the weekend) , and relocation to the local area for the duration of the project. In general, the first case, a daily commuting force, "generates minimal fiscal, social, or political impacts on a host community" [hypothesis advanced in 600]. In a study of the cultural system impacts of two nuclear facility construction projects (Pilgrim I in Plymouth, Massachusetts and Millstone I in Waterford, Connecticut) in which daily commuting was common, the following conclusions were drawn: Social, political, and economic impacts upon the towns of Waterford and Plymouth during construction of their respec- tive nuclear plants have been minimal. The only impact of any magnitude identified retrospectively is construction worker traffic. 195 Most construction workers in the case of Pilgrim I and Millstone I and II commut«ed to the site from their existing place of residence within the metropolitan areas rather than relocate closer to the site or within the host community. As a result, little impact on commercial activity was noted in either community during construction. In both Plymouth and Waterford, little interaction took place between construction worker crews and local towns- people. What interaction did take place was primarily in local grocery stores and taverns. Speeding by construction workers appeared to be a problem in Waterford and Plymouth. In Waterford, a police officer had to be stationed at the entrance to the construction site each night in order to control speeding onto secondary town roads [600; pp. 9-10]. In the case of Monday-Friday commuting by the project workers, the poten- tial impacts may be somewhat more important, depending on local socio-economic conditions. During the week, the workers would require housing, food, and recre- ation in the local area. However, they would probably not spend a large portion of their wages locally, preferring instead to send most of it to their families for living expenses elsewhere. This means that service industry requirements would be minimal. Also, because the workers do not relocate their families into the local area, impacts on the schools and other family-related systems would be insignificant. This is not to say, however, that Monday-Friday commuters may not cause significant local impacts. The need for housing, especially of a "boarding house" type, for the workers during the week may cause changes in the local housing mix and price structure. Conversions of large single dwellings into multiple units may increase availability to offset this demand. Existing rental housing may be diverted away from those who would normally rent it as well. Rents may rise as the demand increases, especially as local landlords see an opportunity to increase profits at the expense of the construction workers (whose median income may be considerably higher than the local norm) . Because of this, low-income residents of the area may be forced into lower quality housing than they could afford prior to the project. Finally, the housing mix established as a response to the project will exist after construction has ceased, which may leave the local communities with an overabundance of poor A secondary impact may be an increase in building code violations and the need for an expanded inspection and enforcement program. 196 quality rental units [451]. Also, rents may fall once the work force leaves the area, causing significant local income effects. There will also be impacts felt in other sectors of the local economy. Food sales may increase, both at markets and restaurants and cafes. Tavern and bar sales may also increase [451]. As in the case of housing, market demand- response expansion and inflation may occur in these areas during the construction period followed by a sharp decline once the project ends. It is not likely that there would be significant increases in the durable goods market. There are, of course, many factors operating to mitigate these potential problems. For one, the magnitude of these problems will depend on the local economic and social structure. It would be reasonable to assume that, in general, a large metropolitan area would be better able to absorb the work force without significant change than would a rural town or small city. Care must be taken not to over generalize, however, and to examine the economy of the proposed site localities in detail to determine how important these effects might be. For example, the impacts, particularly with respect to housing, may be considerably less in areas oriented to a seasonal tourist economy, where excess capacity may ■k be available for rent. Also, areas with stagnant or declining populations may have an excess supply of housing available and, thus, be more able to absorb the influx of workers. In addition, the construction workers may not locate in one area but rather, spread out into surrounding localties. This avoids a concentration of the impacts of this phase (subject to the qualifications discussed with respect to local fiscal effects below) . In some cases, a substantial portion of the work force may relocate into the locality of the project. The impacts of such an immigration can be signifi- cant, subject to the caveats discussed above. Demand for housing in this case will be shifted away from the "boarding house" market, into family dwellings. This may cause a decrease in availability of rental units and a limited increase in new home starts. An important source of housing for construction worker families is the mobile home sector [451]. Because rapid development of mobile home parks can bring problems with public service support and conflict with existing residents (especially in areas of limited experience with this form of * Owners may also prefer to rent to construction workers on a year-round basis, rather than depend on temporary tourist occupancy. 197 housing), the expansion of these facilities should be carefully planned and inte- grated into the local system. An overview of the local response to the demand for new housing has been summarized as follows: Recent population trends and the age structure of the local population are important: in an area which is stagnant or declining in population, and which has relatively few younger people, rooms or larger parts of existing houses may be in great supply and obviate the need for other sources. An area which is growing rapidly and has many young families is more likely to meet some demand with permanent housing, because such housing is likely to be saleable or rentable after con- struction ceases. The availability of sites for mobile home parks, the import- ance of tourism (and, thus, the abundance of motels and inns) , and the attitudes of owners toward conversion and renting space to strangers are all relevant factors. The general amenities and quality of public services will also influence choices of workers, especially those bringing families. Thus, the sources of supply of housing which are easily expanded in particularly favored communities will weigh heavily in determining the mix for the whole region [451; p. 179]. In addition to demand for new housing and associated services, there will also be a general increase in local business activity. As in the case of the weekend commuting, food and food service sales will increase, although to a greater extent in this instance. There will also be increases in other sectors, including both durables and nondurables as family-oriented demand rises. As a net result, more of the consturction payroll will be spent locally, generating secondary income benefits. The size of this income multiplier effect, as it is called, is determined primarily by two important factors, the marginal propensity to spend locally (c) , and the fraction of sales that becomes local income (h) . The general formula is: multiplier = 1 l-(c)(h) The larger the value of the multiplier, the greater the secondary income benefits, The marginal propensity to spend locally is simply the fraction of total income spent on locally provided goods and services. As such, it depends on the * This concise explanation of a potentially complex concept is taken from reference 451. 198 mix of goods available locally, relative prices between local and imported goods, the availability of imports, and the type of goods and services desired. Finally, movement of families into a locality for the term of the pro- ject could have impacts on other services, such as schools, sewers, health care, police, churches, etc. The school system especially could be adversely affected, as enrollment increases, but only for a short period (2-7 years) . Because the crowding is only temporary, new additions may not be warranted. This does, of course, depend on the enrollment in the system relative to capacity before the project begins. (b) Movement of material through the local area In addition to a movement of workers to the site of a new energy facility there is also a large-scale movement of material : All plants require substantial amounts of materials to be moved to the plant site. The most important of these are the concrete required for buildings and dams; steel for concrete reinforcing and for structural frameworks; and large pieces of equipment, such as turbines, parts of boilers, pipes, etc. These materials can be moved to the construction site by any one of three ways, by truck, by rail, or by barge, depending upon how accessible the site is to each of the modes and where the materials are being shipped from. In general, the greater the dependence on highway transportation, the greater the impact on the surrounding communities [451; p. 130].* The major transportation-related problems are local system congestion (both by worker traffic and material delivery to the site) , increased risk of accidents, and deterioration of the roadbed, curbs, and bridges. There may also be local improvements to the transportation system brought about by the project. For example, relocation and improvement of existing road- ways could provide improved access for the local residents after the construction period has ended. Related to the movement of construction materials through the local area is the local purchase of materials to be used at the site. If the area is highly industrialized and produces structural steel, piping, equipment, or other materials, then a significant share may be bought locally. However, if the area is rural with little heavy industry, then the locally purchased material will See discussion of Transportation Access Requirements in description of nuclear power plants. 199 most likely be limited to sand and gravel. (c) Impacts of the facility's presence The presence of a major new energy facility, even prior to its operation, can produce significant changes in the local socioeconomic system. One of the most obvious of these impacts is the addition to the local tax base. A new facility valued at several hundred million to more than one billion dollars will pay several million dollars per year in property taxes upon completion. Assum- ing that total tax revenue to the local jurisdictions remains constant, this would mean a tax reduction for all other property owners. The size of this re- duction depends, of course, on the tax value of the plant relative to the total local tax base. Figure 15 illustrates the range of effects that a new plant might have on the tax rate as its share of the tax base changes. FIGURE 15 EFFECT OF A MAJOR NEW FACILITY ON THE LOCAL TAX BASE if 100% eo - o 40 2 Z0 150 200 % Plant tax value as proportion of original tax base [Source - 451] It will also produce property tax revenue throughout the period of construction in proportion "to the total amount expended by the utility on investment to date" [451; p. 194]. 200 In a case study of two towns within which nuclear generating plants pro- vided 50-60 percent of the local tax base, workers from Oak Ridge National Labo- ratory found the following: The major impact of the nuclear plant in both Plymouth and Waterford is the large increase in tax base provided by the operating reactor. One option chosen by both communities has been to lower (or stabi- lize) the existing tax rates while currently using the additional revenues to significantly increase public services and facilities. Both communities have taken some steps to professionalize adminis- tration of services through hiring new staff and creating some new positions in local government. In both communities, new depart- ments of public works have been established and town planners have been hired to control future land use development. In Plymouth, a town manager has been hired to oversee local affairs [600; p. 10]. In addition, to direct tax benefits from the new facility, there will be some secondary tax revenue gains. For example, new housing for construction and operating employees will expand the facility tax base. Also, market value of commercial property may increase in expectation of higher profits [451]. Finally, there may be added benefits in cases where local communities can levy sales and income taxes, especially during the construction period. These benefits do not accrue without offsetting costs, however. The Oak Ridge study cited above also has identified a number of problems created by the new facilities: External relationships of the two communities have been altered by the presence of the nuclear power plant, principally because of the augmented tax base. The presence of the nuclear power plant may create new tensions or exacerbate existing tensions. Efforts have been initiated in both states to redistribute the utility tax payments so that a larger proportion will go to other jurisdictions and/or the state. Neighboring towns have, in varying degrees, become resentful or antagonistic over the favored status and resources of the host community. The transportation of nuclear waste through neighbor- ing towns in both Plymouth and Waterford has caused some concern and has resulted in challenge of the legality of the transfer of that waste. The sudden population growth occurring in Plymouth since 1968 (the beginning of the nuclear plant construction) was intensi- fied by construction and operation of Pilgrim I, but growth would have occurred soon because of regional growth patterns 201 and proximity to Boston. Growth was one consequence of the low- ered tax rate in Plymouth [600; pp. 11-12]. While these conclusions are based on the study of a specific situation, they do highlight a problem that may be true in the general case. That is, while tax revenue (especially property tax revenues) generated by the facility accrues primarily to the host jursidiction, the costs may be shared with several surrounding communities. There are other problems related to local fiscal effects as well. For example, the actual assessment and taxing procedure may be very complex, causing problems for local officials. There are sometimes problems with deciding what portion of the facility is taxable, how to tax transmission line easements, how the presence of the plant or construction activities affect neighboring property values, etc. [451]. Resolution of problems such as these may be beyond the capability of local administrators. Another problem is that plannning and implementation of programs to miti- gate adverse impacts, especially during the construction phase, must be done before the project begins. Tax revenue to finance these programs, however, is not available until after construction has begun (see Table 22). This lag effect can produce dislocations in the local fiscal picture. TABLE 22 TAX PAYMENTS DURING CONSTRUCTION OF THE JIM BRIDGER POWER PLANT Tax Year Property Taxes ($) 1972 $ 37,000 1973 490,000 1974 1,285,000 1975 3,000,000 1976 4,000,000 1977+ 5,000,000 [Source - 451] 202 Another source of monetary benefits is the interst paid on the bonds to construct the facility. However, it is likely that these monies will be spread out among a large group outside of the local area and, hence, will not add direct- ly to local income. In addition to monetary costs and benefits, the presence of a large energy facility will have other impacts of both a local and regional scale. In many cases, at least a portion of the land used for such a facility will be unavailable for other uses for at least 30-40 years. The long-term commitment of a site of the size considered here (range of 300 to approximately 3,000 acres) will affect development patterns on a local and, perhaps, a regional scale. In addition, potential uses displaced by the facility must be considered, especially in terms of alternative sites available to them. This analysis should also in- clude possible uses of water resources that may be preempted in the long term. Related to this is the problem of potential land use conflicts that may arise, both in terms of existing development patterns and future changes. A large facility does not exist in a vacuum and must be related to the socio- economic matrix within which it is located. Included in this is the problem of aesthetic disruption and visual intrusions which may be considered to be a measure of harmony between human artifacts and the existing environment. Natural draft cooling towers, tall stacks, and large distillation and cracking towers can significantly degrade the quality of surrounding environment. (d) Summary The evaluation of facility impacts during the construction and pre- operational stages is a complex and confusing task. The discussion presented above covered only part of the picture, giving major highlights without filling in the many gaps and details needed to do a complete analysis. Table 23 presents a list of potential construction phase problems. Used in conjunction with the facility activity impact matrices, it should present at least a starting point in evaluating the cultural impacts engendered in the construction of a new facility. c. Operating Impacts The major impacts caused by the operation and maintenance of a large energy facility are related to the production, storage, and release of residuals to the water, air, and land. In contrast to the construction phase impacts 203 I %'?: c c r. *-« o — a L ■ o - - o. c o 4-1 e j" O c liJ _ •' O 'J 2 ? " J =lo - si; 2: ha c 0J "O O a. c a- *j (o o i_ */i o c •- o a, < o — .2: U. ar. 4) t/l >. 41 _* > 4) Q. C -13 *-< ^ 4> "O ■- a» ^ 1/1 E c c tj cr -sr c r< u — c *o 0.0 i/> ;j :d a. o r r- ,n n-r u-\ \D r^ 00 C\ o — 3: — _ a m 4) > > V O O 204 which are primarily related to the cultural environment, those produced by plant operations tend to be more closely tied to the natural environment. This is not to say, however, that they do not affect the cultural system, but rather that their impacts are generally channeled through the natural system. For example, changes in air quality caused by plant emissions could lead to public health problems and reductions in land values close to the plant site. In many cases, the linkages between these natural system changes and resultant changes in the cultural system are poorly understood. This is espe- cially true where those changes require long periods of time to accumulate and become measurable. As a result, a discussion of the environmental impacts caused by facility operation must deal primarily with identifying the residuals produced rather than the effects of those residuals on the natural and cultural environments . (1) Fossil Fuel (Coal-Fired) Power Plants Table 24 presents a general summary of the types of impacts associated with the major activities in the power generation fuel cycle, while Figure 16 diagrams the major impacts specifically related to the operation of a coal-fired power plant. The discussion below is organized by major activity types as de- fined previously and shown in Figure 16. For a discussion of the impacts related to fuel transshipment and storage, the reader is referred to the section on Coal Transshipment and Storage Facilities. (a) Plant operation Table 25 presents estimates of the air-borne effluents produced by a 1,000-MWe plant both with and without emission controls. While this type of information may not indicate the effect of these emissions on the environment, it does at least provide guidelines as to the scale of the problem. The impacts and interactions of these air-borne residuals on the environ- ment are generally not understood at this time. Of the major pollutants listed in Table 25, the one most easily controlled at present is particulate matter. Current control technology allows collection efficiencies greater than 99 percent [546, 222, 451, and others]. For this reason, the most visible effects of * The entire fuel cycle has been included here to provide the reader with a broad perspective of the impact picture. Only those activities directly related to this report are discussed further. 205 XJ r0 cn 4J 4J JJ 4J V u c •D c ■u •H c o --H o ■H •A CJ • h (0 CJ XI o rH jQ a a fO £> It) •H r^ 'J 3 (T3 ■H O ra fu ro ft ra •« c^ J-J 5 •H ft jc 01 O H J3 -ji c x: en p j~~ '/i g ft rn X 2 01 •H ^J 73 H -a H »3 •H 3 O o •H < n-t 0) X ia 4-1 c M-4 c in C >~i 3 U a, ^H Oj iH C rH ro rrj CJ n in rH 3 H 1 u-i O I ■P rC 4J 4.J » C « C 07 CO ■si ra rH jj a, jj C^ en 01 3 rH rd rH S ro 5 rd CJ rjv o cr» T) •H c TJ •H c H tn ■H •H 'n -h rH > J-J rH >1 4J rC ■H rC -H u> ft ■JJ CO ft 03 G c c T5 r: o T3 C ■H C •H C c •H a 0) ra cn O T3 01 B) 31 •H tn O ■H 11 H H» cu r-i -U 5 y S a 4J e ro rH (13 .0 CU CD H 'V 3 en 3 to cu 3 m U i o 3 'H CJ 3 H 5 ■H •H o 4J a) aJ a Jj 4-1 CD U 01 !-( cn ra r4 tn ,-3 rrj ra ra a (0 ra D-, Cn CU CT> J3 CX cn >i (3 1) 5 CJ T C U-l rfl O a 1 u j-J 4J rC c cn •H y. tJ a C 4-1 iM ia O <-i g c >, •H u ■H 5-i 4J 4J CJ ra •H X 31 4J •H 5-i T3 •'\ 3 V CJ 14H "3 u CU CJ CJ o cn ■H Q -X- c H 3 in O en ■H H 4J e CJ CU -J 01 ; -H 03 4-1 QJ rd cn ■u c rH ro -H .C V4 OJ en -P c TJ rd O c ? •H 3 J-l a. O ro U3 a GJ 6 -r4 +J rn JJ ■n Cn O J-> C 11 C a ,rH u O ft S-( O •H en CJ rH U-( ra 01 Jl X C CJ 03 U-l OJ rC ■H O O ro H ai rC +J T3 4J CJ O < C CU o ij •H CJ XJ >H O u ra 5-1 ►J a tl X Cj W C o c +J •H w 4J •H O ■3 tn ft 5J 5^ tn ra 0) c ft > 3 OJ c U u o c^ 04 CJ ■* V3 a Ou ra en M -H ^ Q ■X- * 206 FIGURE 16 DIAGRAMATIC SUMMARY OF COAL-FIRED POWER PLANT ENVIRONMENTAL IMPACTS | Ati/|>«.lkul.l.» I ^jj Q 4 irul/ic.lua ociu[>*flon I (w.m/chluilm | |w«i.i/h.IT| I Lftllll/tUlUca OCCupAllClt I ^3 J3 liufccoui tlg.ulUcnl ni.nb.ii o< dlltcl lujnun d..U.« bam acciilaii [Source - 501] 207 CN W rJ pq < H in ^ In-rJ CO in o r- l-> CT> C* in rH CO r 1 O (N vD m i£> 0^ 2 Xm rH rH rH rH CO o o rH rH C to cd en £ LTl'J O CO CM CN o kO CM o t$ -p • • • • • • P -H rH cn CTi m t> ro -P Xro CM rH rH CM rH CN -H O O S rH ' >1 he ^-H P -H U CO m in in in CO P ' H m ro m m m ro ir ih _ ' U-, W 01 rH O in ■P g -P m en m U -p in C CD c g C -H > CO > -H rd CD ft m in C rH C -H e > o rd -p rd P rcJ -P £ rH id c O-rltP OH fjl O-rltT >i CD o u > c use U 5 G -H u -P -P u 2 •H -H •H rH CD CO c u & CUfl £ P ,£} rd ? P CD r Q P CD ,Q P CD ,Q u CD rH p +J -H P. CD rH p CD i o •H rd rd cq in rd po en CD 03 in rC U S O u W W £ P4 U o cd o o m 4J , rH J^ rH OJ T1 4J a 4J a cr) o CQ rH CJ B > O 0) Sh XI MH CD 03 4J 4-) rd rd X X ti d O o T1 X! cu OJ CO CO rd cd PQ rt 208 particulate emissions, thick, dark smoke, and deposition of dirt on surrounding property, can be eliminated. While the overall removal efficiency may be high, the ability to control the fine particulates (FRA«m.nii.it ..oral. mmm IJHin ABtl UATFR USF. RFCRKAT.ON "t{'r"J » ',' r" i ■ 11'AI.ITY g s 1 § 8 1 § _3 3 I Is 1 S 3 3 3 g 3 1 1 i 1 z ti i 5 "«'»"«»■ ACRT.ai.H.RAI. CflllKXIIA.. .mwimui. gij K 32 i j S a | 3 | i 8 B 5 S a | K g i | ■A | ■i i ■i l s s 1 1 3 g i i 1 I OODND CLEARING AHD RESHAPING - - EQUIPMENT USE CHANNELIZATION, SHORELINE MODIFICATION. AND OTHER WATER-RELATED ACTIVITIES MATERIAL MOVEMENT TO SITE B INFLUX OF TEMPORARY WORK FOICE | PUBLIC SERVICE REQUIREMENTS LAND COMMITTED TO FACILITY OTHER I £ 5 B | | | BOISE gg i PARTICULATES LEACHATES AHD RUNOFF VISUAL INTRUSION HUMAN ACTIVITY DISRUPTION EQUIPMENT CSE 1 i HASTBWATER DISCHARGE PARTICULATES SO, BOx HUMAN SERVICE RECVTHEKEHTS ACCIDENTS 8 THERMAL EFFLUEHT CHEMICAL ADDITIONS BLOUDOVN WATER MAKE-UP WATER REQUIREMENTS FOG/ 1CDJG /DRLTT ENTRAPMENT / IMP LTK EMENT VISUAL INTRUSION || LEACNATES AND RUNOFF PARTICULATES VISUAL INTRUSION HUMAN ACTIVITY DISRUPTION NATURAL SYSTEM DISRUPTION 5 i VISUAL INTRUSION HUMAN ACTTVITY DISRUPTION NATURAL SYSTEM DISRUPTION ELECTRIC FIELD EFFECTS I FIGURE 17 FOSSIL FUEL (COAL) PCWER PLANTS 219 Because EHV transmission lines use air as an insulator, there is a con- stant discharge to the atmosphere, termed "corona discharge." The magnitude of this discharge depends primarily on the size and spacing of the conductors and ambient weather conditions, especially humidity. Proper design can reduce the problems caused by corona discharge, but cannot eliminate them. There are four potential problems related to the effects of corona dis- charge: audible noise (AN), television and radio interference (TVI and RI, res- pectively), ozone production, and electrostatic induction. Generally, these problems are worse during wet or humid weather. Right- of-way selection and line design should be carried out in such a way as to mini- mize these effects. Figure 17 summarizes the impact vectors and environments potentially affected by the construction and operation of a fossil-fuel power plant. (2) Nuclear Power Plants The types of impacts and general environments affected by the operation of a nuclear power plant are shown in Figure 18. This discussion will concen- trate on impacts related to reactor operation, specifically sources of radio- nuclide release to the environment. It will also touch briefly on human service requirements, and accidents. Impacts related to cooling system operation and electricity transmission have been covered adequately in the previous section and will not be repeated here. The principal sources of radioactive materials are the fission products which are produced in the fuel elements as a by- product of normal operation. The quantity formed is small in terms of mass, amounting to a few kilograms per day in a large power plant. Under normal operation, more than 99 percent of fission products remain in the reactor core where they were formed. Small quantities which leak from the fuel elements, however, are ultimately released from the plant radioactive waste processing system to the environment. In addition to the fission products, other sources of radioactivity are leakage of radioactive materials from control rods, activation of impurities in the reactor coolant, activation of corrosion products from structural materials, and tramp uranium which adheres to the outside of the fuel rods during the manufac- turing process [203; p. 23]. There are four types of radioactive waste materials (radwastes) that must be dealt with: gaseous, liquid, ventilation exhaust air, and solids. All four are produced by both reactor types now in use: the boiling water reactor 220 FIGURE 18 DIAGRAMATIC SUMMARY OF NUCLEAR POWER PLANT ENVIRONMENTAL IMPACTS fctacUlc Pqwii An/i.J.um.U.J.i, at y Fuel fuL'iCotloli I AU/p. icuUlai - niu J© LiQhl Watur Reactor V,'«lo,/I,i:,jo, W«i«i/Ju..ii.«J •oliJs - radioacllv I L «nd/tb l«co occupation j I An/i>jic».cl'i!i.itigu J I All/pMttcula 3 Spuol fuul Sluruja ^ Wilu/Ji»aJv«J lohdi - ndi.i.cU. fl7^ "N I L«Ml/auilM* ottupalUm] [•.V.l.«/..l.l...ln« »"cl|! W.l../du.t,l»ad «..i..l71 (•■../■I...U..J Jq1!Ji|| UnJViuilaco h u >»w< J plqu.Uc fl,ol./d.<.cl l.au.na] rw.l.i/di.iolvad »ul.J» | fc=3 iD"- k ot i»^*J cMattUo^tU. acutU [Source - 501] 221 and pressurized water reactor. However, the mix of these wastes varies with reactor type, BWR 1 s producing more gaseous radwaste (radgas) and PWR's producing higher levels of liquid radwaste. (a) Boiling water reactor wastes The principal source of radgas in both reactor types is the degassing of the primary coolant. Much of this gas is a result of air inleakage at the condenser. In a BWR, additional gaseous wastes are generated by fission and activation products and radiolytic decomposition products (hydrogen and oxygen) . Also, radgas emissions may arise from leakages around the turbine gland seals, especially in older plants (new plants having eliminated this waste source) . Most of these gaseous wastes are removed at the turbine condenser through an air ejector. These effluents contain nitrogen-13 (an activation product) , noble gas isotopes, krypton and xenon (fission products), halogens (mostly iodine), and tritium. In addition, there are some radioactive particulates and solid decay products associated with the gaseous wastes. Treatment consists primarily of delay (30-60 minutes) to allow the short- lived isotopes to decay and filtration through high efficiency particulate (HEPA) filters prior to venting through the station's stack [203 and 546]. Alterna- tively, cryogenic distillation may be used to liquify and remove the noble gas fission products [546]. A charcoal absorber system can also be used to provide up to 10 hours of delay to reduce the amount of xenon and krypton, the two principal radioactive species. Figure 19 shows a simplified radgas control sys- tem schematic while Table 27 summarizes the principal isotope emissions based on varying delay times. There are four major types of liquid radwastes from a nuclear power facility of either type: high purity wastes, which are radioactive but low in normal chemical impurities (e.g., primary coolant leaks and equipment drains); low purity wastes with varying levels of radioactivity, such as floor drains; chemical wastes; and detergent wastes with low levels of radioactivity [203 and 546]. "These waste streams are segregated according to origin so that liquids of near coolant quality may be treated and reused..." [546; p. 167]. Following treatment, the liquid waste discharges are then bled into the cooling water discharge flow at such a rate to meet government emission standards. Figure 20 and Table 27 show a typical BWR liquid radwaste treatment system and effluent activity levels, respectively. 222 m a to u - - c en :< o Otf) 'X en ae bi w 5 UJ 1 ° ** O (£ < o x w oc o x a u < 223 TABLE 2 7 ANNUAL LIQUID EFFLUENT* ACTIVITY FOR A 1000 MWe REACTOR (Curies/year) Principle Isotopes BWR PWR Rb-88 0.39 Sr-89 0.64 -- Y-90 0.14 — Y-91 0.31 -- 1-131 1.71 0.47 Te-132 -- 0.96 1-133 0.20 0.11 Cs-134 0.36 0.41 Cs-136 — 0.20 Cs-137 0.27 0.28 Cs-138 — 0.27 Ba-140 0.93 -- Ba-137m -- 0.26 La-140 0.71 -- Fe-55 0.26 -- Co-58 0.60 0.33 Mn-56 __ 0.84 Other li. quid activity 1.0 0.78 Total (excluding tritium) 7.1 5.3 Tritium 20.0 350 [Source - 203] Solid radwastes are similar for both BWR 1 s and PWR's, consisting of three general types: wet, such as spent resins and evaporator concentrates; dry compressible, such as rags, clothing, and plastic; and dry noncompressible , such as equipment [546]. The wet wastes are solidified and kept on-site for a period to permit the decay of short-lived radionuclides. Ultimate disposal for all forms is burial at an approved site. It is estimated that total solid waste activity from a 1000-MWe reactor amounts to 2,500-5,000 curies per year [203]. See Table 21 for definition. 224 FIGURE 20 BWR LIQUID WASTE SYSTEM FROM EQUIPMENT DRAINS FROM PLANT FLOOR DRAINS COLLECTOR FOR HIGH PURITY V^STE FILTER DEMIN- ERALIZER © 5 FROM LAB DRAINS AND DECON- TAMINANTS FLOOR DRAIN WASTE COLLECTOR FILTER & 777T7777777 DEMIN- v ERALIZER . CHEMICAL WASTE COLLECTOR- NEUTRALIZER FROM LAUNDRY. DRAINS LAUNDRY (DETERGENT) DRAIN TANKS (2) FILTER ¥ CONDENSATE STORAGE RECYCLE WASTE SAMPLE TANK 77777777777. / SAMPLE "*£ TANKS ; (2) ' /////////// s 7TTTJTTT7T. EVAPO- y RATOR t t LujlUJIjjl k TTTTJTTT-rr} CONDENSATE TANK ///// /// / S SAMPLING POINT ($\ SOLID WASTE TO PACKAGING Lj ADDED FOR MAX RECYCLE R RADIOACTIVITY MONITOR f DISCHARGE CANAL [Source - 203] 225 (b) Pressurized water reactor wastes The major source of PWR radgas is in the primary coolant system, although "radioactive gases will exhaust from the main condenser air ejector when steam generator leakage from primary to secondary system occurs" [546; p. 190]. During operation of PWR, radioactive materials released to the atmosphere in gaseous effluents are similar to those released from a BWR and include low concentrations of the fission product noble gases (krypton and xenon), halogens (mostly iodines), and tritium contained in water vapor and particulate material [203; p. 26]. However, the activity levels of these emissions is typically much lower for a PWR, due to the considerably larger delay prior to release (45-60 days) ; see Table 28. A schematic of a PWR radgas control system is shown in Figure 21. As Table 28 indicates, liquid radwastes are similar for both PWR and BWR plants with the exception of tritium. This greater than tenfold difference in tritium emissions arises primarily from the use of boron soluble poison in the PWR coolant for supplementary control. Boron undergoes a neutron capture reaction to generate tritium which has a relatively long half-life (12.3 years). Since tritiated water is chemically identifical with ordinary water, separation is very difficult and to date impractical. The lower tritium releases in later model PWR f s have been largely achieved by water management schemes which store more of the tritium in the plant water inventory [203; p. 34], As discussed above, PWR solid radwastes are similar to those from a BWR facility. (c) Environmental impacts of emissions Figure 22 shows the major pathways of radiation through the environment and ultimately to the human population. Under normal operating conditions, all nuclear plants (and, as discussed earlier, most fossil fuel plants) emit traces of radioactive substances to the environment in both liquid and gaseous form. Concern with the effects of these emissions, especially over the long term, is one of the major points of controversy in the nuclear power debate. The brief discussion below cannot answer any of these questions (nor can any other docu- ment) but it will highlight some of the issues. JU Radioactive solids (except for fine particulates that may pass through the HEPA filters) are not considered to be an emission for the purposes of this report, although their handling and disposal (storage) do present significant problems. 226 TABLE 28 ESTIMATED ANNUAL RADGAS EFFLUENTS FROM A 1000-MWe REACTOR Release Rate, curies? ye arjL/ Nuclide Half-: Life 30 2/ min. delay— 1 day delay 8 ./ 60 day delay!!/ 83111^^, 1.86 hr. 90,000 13 85 Kr 10.76 yr. 250 250 250 85m Kr 4.4 hr. 160,000 3,900 - 87 Kr 1.3 hr. 480,000 1.5 88 Kr 2.8 hr. 510,000 1,500 89 Kr 3.2 min. activity 1 11,000 ,250,000 250 Total Kr 5,650 (■ approx. ) 15 3/ day delay— 131m Xe 11.9 day 375 150 10 133 Xe 5.27 day 160,000 22,000 50 133m Xe 2.3 day 6,000 50 135 Xe 9.2 hr. 540,000 135m Xe 15.6 min. 260,000 l 37 Xe 3.8 min. 28,000 138 Xe 14 min. 780,000 _p_ Total Xe activity 1 ,800,000 22,200 60 ( approx. ) 1/ Assumes operation with 0.2% clad defects. 2/ Typical holdup time in BWR's built to date. 3/ Typical holdup times for BWR's using charcoal beds. 4/ Typical holdup times in PWR's are between 45 and 60 days and accordingly would be between the 1 and 60 day values. A curie is a measure of radioactivity, specifically "a quantity of any radioactive nuclide in which 3.7 x 10-LO disintegrations occur per second." (Webster's New Collegiate Dictionary) [Source - 203; 227 W H U3 ^ CO H h-1 O a W o oi u t> C) CO H it: < J— z < h- *: < 1- t- 00 ?3 < o Id >- < o UJ o >- < o UJ Q oo bJO m » umaenm Mini. r,™,,„ UIOI Aim UATrR u.r rnxKEATim S 3 "Em' »;r IIIIAI.ITY g a 1 a i 1 a 3 a i 3 a 1 II a B ! B S g i 3 s 1 BrsmrartAi. AnftTrtil.TlWAL amoiciAi umimw. 1 8K n n ^ i p 3 a i3 3 3 1 r % 1 g R !j ?j 1 3 i ^ £ 15 E a 9 1 3 i 1 3 1 3 jj 1 GROUHD CLEANING AMD RESHAPIBG - - - EQUIPHEHT USE - ~ CHAHHELIZATIOH, SBDRELINI MODIFICATION, AMD OTHD WATER-RELATED ACTIVITIES MATERIAL MOVEMENT TO SITS INFLUX OP TEMPORARY UOSX FORCE PUBLIC SERVICE REQU DtEMEWTS LAHD COrtilTTED TO FACILITY OTHER - aE HARBOR MALWTEHAHCE UATERBORNE MATERIAL MOVEMENT iZ OVERLAND MATERIAL MOVEMENT - 5, HTTMAN SERVICE REQUIREMENTS S* PARTICULATES w £ LEACHATES AKD RUSOFF VISUAL INTRUSION * HUMAN ACTIVITY DISRUPTION ^ULPMENT USE , i i ■' COAL TRANSSHIPMENT FACILITIES Figure 24 235 change of land use due to the rural nature of the area. In these cases, the impact of committing undeveloped open lands to a single use (coal storage) is significant especially in the coastal zone where land utilization and public access are important questions. Finally, community disruption in the form of traffic flow alterations and tie-ups is a potentially significant impact of a coal transshipment facility. In the case of the coal facility at Superior Harbor, Wisconsin [391] , major consideration was given to the effects of unit train operation in and about the facility and how it would be reflected in traffic disruption. These effects include increased necessity for traffic rerouting, construction of bridges and bypasses, and expansion of existing roads or railways. A graphic summary of activities and environments assembled in the form of a matrix, which may be used for a more specified case analysis, is provided in Figure 24. (4) Oil Transshipment and Storage Operation and maintenance impacts associated with oil transshipment and storage facilities include the effects on the natural environment of oil spills and hydrocarbon emissions and effects on the cultural environment in terms of aesthetics and safety. (a) Natural The most significant and specific impacts of an oil transshipment and storage facility on the natural environment are those associated with hydrocarbon emissions and potential leaks and spills of oil. Hydrocarbon emissions escaping during both storage and loading processes adversely affect air quality by re- ducing visibility in contributing to a photochemical smog effect [158] and by adding significantly to the ambient odors. Also, as discussed in the facilities description section, refined products transshipment is most common on the Great Lakes and it is these petroleum products whose aromatic hydrocarbons are most toxic [292]. Effects of oil leaks and spills on the natural environment range from adverse impacts on water quality to health effects on wildlife. Figure 25 shows the manner in which an oil spill may be taken in the aquatic environment. In the case of transshipment facilities on the Great Lakes, these spills will most likely occur at or near the water's edge. Depending on the viscosity of the spilled oil, impacts on the land range from few for high viscosity products o > N 2 _J < 2 £L H O OS s _J « a H 1 01 !<5 H — IT) O CM t 3 C D ^~ O H ~ < fe l^ UJ 01 L'J X c co O < H °^ 237 to significant for low viscosity products (such as gasoline) , which are more difficult to recover [158]. Impacts on water quality are intensified by the high solubility of refined prducts and the subsequent toxic impacts on aquatic ecology. In the cases where oil products are emulsified in the water column, threats to drinking water derived from wells may result. Impacts on biota include toxicity of volatile hydrocarbons and smothering by the heavier fractions of refined products. Effects of oil spills are felt most severely in nearshore areas, and shoreline communities are thought to suffer pronounced detrimental effects [158]. Benthic organisms, aquatic vegetation, and sea and shorebirds are all significantly affected by the range of petroleum distillates that may be spilled from a storage facility. The effects are numer- ous and underscore the necessity for strict safeguards against leaks and spills. In addition to the potential for leaks and hydrocarbon emissions, there are harbor maintenance impacts similar to those described in the proceeding coal transshipment section. These dredging impacts are significant in the case of oil transshipment facilities because the sediments in the berthing areas are likely to have higher amounts of petroleum distillates due to leaks. When these materials are dredged up, the hydrocarbons may be released into the water, or the dredge spoil may have a higher toxicity and present special problems for disposal. Finally, hydrocarbons and other chemicals may be discharged from ballast tanks of ships during the loading of refined products. Their effects further degrade water quality in the harbor areas. (b) Cultural Cultural impacts of oil transshipment facilities lie primarily in the aesthetic intrusion and safety categories. Because of the organoleptic impacts of hydrocarbon emissions and oil leaks and spills, public attitude is the area most severely affected by these facilties. Odors from these emissions are generally disagreeable and their indirect effects may be seen in changes of land value in the vicinity of the facility. In the case of spills or leaks, drinking water quality may be negatively affected in an extreme case if ground or surface water infiltration by low viscosity distillates. The probability of major accidents is low, but the magnitude is extremely high. In the event of a major spill, human service requirements for oil spill contingency plans must be met. These include personnel trained in oil containment 238 and clean-up techniques, and the various paraphenalia, such as booms and skimmers used in the clean-up process. Likewise, the potential for major fires exists and local fire fighting services must be prepared for special procedures for petro- leum fires. Economic benefits from these facilities are reflected primarily in tax revenues to the local area. Personnel requirements for maintenance and operation are low or negligible and therefore, do not significantly affect employment or housing. (5) Refineries The problems associated with crude oil and product transshipment were described in the preceding section. This discussion will focus only on those activities related directly to crude oil refining: air and water emissions, solid wastes, visual intrusion, and human service requirements. Because expan- sion of the present Great Lakes refinery capacity is unlikely and "standard" refinery characterization so difficult, this discussion will be as brief as possible, touching only on major issues. (a) Air quality impacts The principal air emissions produced during refinery operation are SO , NO particulates, and hydrocarbons. In addition, a wide range of organic and inorganic materials are produced in various quantities: olefins, aldehydes, ammonia, hydrogen sulfide, carbon monoxide and others. Table 30 shows estimated emission rates for a variety of refinery sizes and product mixes. The technology is presently available to meet national air emission standards for all major pollutants with the exception of hydrocarbons [506, 370, and 222]. Measuring the impact of these hydrocarbon emissions is difficult, however: Current federal standards are based on total hydrocarbon emissions. One of the major problems in measuring hydrocarbon impacts is the difficulty in discriminating among "reactive" hydrocarbons and inert forms. Reactivity is critical to the formation of photochemical oxidants, which constitute the major hydrocarbon-related air quality problem. At present, there is no adequate basis for distinguishing between reactive and nonreactive hydrocarbons; the subject is being studied by the federal government [506; pp. 11-80]. T C CROUND CLEARING AND T.ES1 EQUIPMENT USE CHANNELIZATION. SHORELIt MODIFICATION, AW) OTHJ WATER-RELATED ACTIVIT] MATERIAL MOVEMENT TO SI1 INFLUX OF TEMPORARY WORJ PUBLIC SERVICE REQUIRE!! LAND COMMITTED TO FACIL1 OTHER IS ►-. 'J la si § 2 a i HARBOR MAINTENANCE WATERBOWIE MATERIAL MOV[ OVERLAND MATERIAL MOVEMI HUMAN SERVICE REQUIREMO HYDROCARBON EMISSIONS LEAKS AND SPILLS VISUAL INTRUSION HUMAN ACTIVITY. D1SRUPTIC ACCIDENTS 238 and clean-up techniques, and the various paraphenalia, such as booms and skimmers used in the clean-up process. Likewise, the potential for major fires exists and local fire fighting services must be prepared for special procedures for petro- leum fires. Economic benefits from these facilities are reflected primarily in tax revenues to the local area. Personnel requirements for maintenance and operation are low or negligible and therefore, do not significantly affect employment or housing. (5) Refineries The problems associated with crude oil and product transshipment were described in the preceding section. This discussion will focus only on those activities related directly to crude oil refining: air and water emissions, solid wastes, visual intrusion, and human service requirements. Because expan- sion of the present Great Lakes refinery capacity is unlikely and "standard" refinery characterization so difficult, this discussion will be as brief as possible, touching only on major issues. (a) Air quality impacts The principal air emissions produced during refinery operation are SO , NO particulates, and hydrocarbons. In addition, a wide range of organic and inorganic materials are produced in various quantities: olefins, aldehydes, ammonia, hydrogen sulfide, carbon monoxide and others. Table 30 shows estimated emission rates for a variety of refinery sizes and product mixes. The technology is presently available to meet national air emission standards for all major pollutants with the exception of hydrocarbons [506, 370, and 222]. Measuring the impact of these hydrocarbon emissions is difficult, however: Current federal standards are based on total hydrocarbon emissions. One of the major problems in measuring hydrocarbon impacts is the difficulty in discriminating among "reactive" hydrocarbons and inert forms. Reactivity is critical to the formation of photochemical oxidants, which constitute the major hydrocarbon-related air quality problem. At present, there is no adequate basis for distinguishing between reactive and nonreactive hydrocarbons; the subject is being studied by the federal government [506; pp. 11-80]. 238a H A T U It A L CULTURAL ftlYtilCAJ. ! GtMlCAL GlATtACTFRISTICS DlCtiaCAL COiHITlCTO Social Economic Physical TBM1TRIAI immnimiui. Aiwwiraic nwinsTRiAL ixSS SaTIS *™ si™ nmrmmrt „„„ 5 ,Nr. •Msnia PR ' RF'iTHI Ul» AND WATER USE ■n UFA riw _|_ wrf ua'i'i'u" 8 i|i'Ai.n» s a fTi 1 1 3 5 3 8 9 1 a 3 *" i i s K 3 li § ! i i K e ■•I % 6j T,A,. MamsMnui c..»tp.R,:.A,. urn,..".™..,. f 3E \ as | i § a b a 1 3 i a a jj § I n i i g s P £ | fc (J i g 1 i i i u :j 1 j CROUND CLEARING M r.ESllAPIKC - EQUIPMENT USE MODIFICATION, AND OTHER WATER-RELATED ACTIVITIES MATERIAL MOVEMENT TO SITE i INFLUX OF TEMPORARY WORK FORCE rUBLIC SERVICE »mUI»BtB!TS land cohkiitd) to facility OTKt, IS \\ J 1 2 o 5 UATEPMRjrt MATERIAL MOVEMENT OVERLAND MATERIAL HOVEMENT ULIVUI SERVICE RETIREMENTS HYDROCARBON EMISSIONS LEAKS AND SPILLS visual nmuKios HUMAN ACTIVITY DISRUPTION ACCIDENTS 1 OIL TRANSSHIPMENT FACILITIES Figure 26 239 TABLE 30 ESTIMATED REFINERY AIR EMISSIONS (1000 lbs/day) S0 2 CO NO x HC Particulates 250 MBD, Low Fuel Oil 97.8 5.6 42.1 90.1 20.8 250 MBD, High Fuel Oil 84.0 5.7 35.1 91.9 17.2 100 MBD, uncontrolled 274. 3 3 698.2 26.1 265.1 10.4 100 MBD, 4 controlled 24. 3 0.2 22.5 27.0 3.1 180 MBD 5 102.6 4.7 63.2 62.4 23.1 i ; [506] [222], without emission controls S0 X [222], with emission controls [370] (b) Aquatic impacts Water-related impacts of refinery operations arise from two sources: withdrawal and consumption, and effluents added to the receiving waters. As was indicated in the refinery description discussion, the dependence on water supply and wastewater disposal has decreased as water recycling within the facilities has increased. Water requirements (Table 16) are relative small, generally less than 10 mgd (15 cfs). Estimates of withdrawals and consumption for a 250-mbd facility are: low fuel oil high fuel oil Withdrawal Consumption 13.2 mgd 5.4 10.5 mgd 4.5 [Source - 506] Waterborne effluents discharged by a refinery include both organic and inorganic materials. Table 31 presents estimates of pollutant concentrations in the water return flow from typical refinery configurations. 240 TABLE 31 ESTIMATED WATERBORNE EFFLUENT CONCENTRATIONS (ppm) BODs COD SS Oil Phenols Ammcnia Total 250 MBD Low Fuel Oil, Present Controlsl 43.22 291.72 27.60 12.96 0.28 42.05 250 MBD Low Fuel Oil, Advanced controls-*- 13.68 74.43 13.68 2.64 0.06 16.71 250 MBD High Fuel Oil, Present Controls 1 - 30.49 206.48 19.69 9.12 0.19 29.44 250 MBD High Fuel Oil, Advanced Controls- 1 - 9.75 52.82 9.75 1.92 0.04 11.76 180 MBD 2 15 80 10 2 0.1 2 2 [506] [370], best available controls The impact of these effluents depends on the water quality and volume (flow) of the receiving waters. For large rivers and lakes, very few problems are anticipated using existing technology [370 and 506]. An analysis of the effects of a new refinery on a large river in New England concluded: The effluents from "new source" [existing control technology] 250-mbd refineries appear to pose very few water quality problems in a large river, when considered independent of actual receiving water quality above the point of discharge. (If the receiving stream immediately above the refinery dis- charge already contains high concentrations of contaminants, even minor incremental loading may contribute to poor water quality.) The 250-mbd "new source" refineries would probably remove biochemical oxygen demand (BOD), suspended solids (TSS), and chemical oxygen demand (COD) , in greater amounts than they would contribute to most large New England rivers, thereby improving certain aspects of water quality. The concentrations of phenolics in the receiving waters would approach or slightly exceed Massachusetts standards [0.001 ppm], but would be well within the EPA recommended criteria [0.1 ppm]. Ammonia concen- trations would exceed the EPA criteria [0.02 ppm], but not those of Massachusetts [0.5 ppm]. ...In summary, the 250-mbd refinery modules with "new source" wastewater treatment technology would appear to pose several minor but no major water quality problems in a large clean river [506; pp. 11-50]. GROUND CLEAJUNG A>1) RES1 EQUIPMENT USE CHANNELIZATION, SHCREUJ MODIFICATION, AI3. OTH1 WATER-RELATED ACTIVIT MATERIAL MOV EH EST W SI' IHVLUX OF TEHrCRAP.'f WORI FUfLIC SERVICE REOirREn LAND COMMITTED TO FACIL | HYTJROCAH3QN £ LEAES AJfD SPI visual iimtos HUMAN ACT TV IT SO EMISSIONS NO EMISSIONS PAKTLCULATEJ HYDROCARBON E OTHER EHISSIC LEAKS AND SPI SOLID WASTE COOLING WAT EI PROCESS WATET WASTEWATER H VISUAL [NTRU! HYDROCARBON I LEA/.S W1D SP VISUAL INTR'J! HUMAN ACTIVE' 240 TABLE 31 ESTIMATED WATERBORNE EFFLUENT CONCENTRATIONS (ppm) BODs COD SS Oil Phenols Ammonia Total 250 MBD Low Fuel Oil, Present Controlsl 43.22 291.72 27.60 12.96 0.28 42.05 250 MBD Low Fuel Oil, Advanced controls-'- 13.68 74.43 13.68 2.64 0.06 16.71 250 MBD High Fuel Oil, Present Controls-*- 30.49 206.48 19.69 9.12 0.19 29.44 250 MBD High Fuel Oil, Advanced Controls^ 9.75 52.82 9.75 1.92 0.04 11.76 i 180 MBD 2 15 80 10 2 0.1 2 2 [506] [370], best available controls The impact of these effluents depends on the water quality and volume (flow) of the receiving waters. For large rivers and lakes, very few problems are anticipated using existing technology [370 and 506]. An analysis of the effects of a new refinery on a large river in New England concluded: The effluents from "new source" [existing control technology] 250-mbd refineries appear to pose very few water quality problems in a large river, when considered independent of actual receiving water quality above the point of discharge. (If the receiving stream immediately above the refinery dis- charge already contains high concentrations of contaminants, even minor incremental loading may contribute to poor water quality.) The 250-mbd "new source" refineries would probably remove biochemical oxygen demand (BOD), suspended solids (TSS), and chemical oxygen demand (COD), in greater amounts than they would contribute to most large New England rivers, thereby improving certain aspects of water quality. The concentrations of phenolics in the receiving waters would approach or slightly exceed Massachusetts standards [0.001 ppm], but would be well within the EPA recommended criteria [0.1 ppm]. Ammonia concen- trations would exceed the EPA criteria [0.02 ppm], but not those of Massachusetts [0.5 ppm]. ...In summary, the 250-mbd refinery modules with "new source" wastewater treatment technology would appear to pose several minor but no major water quality problems in a large clean river [506; pp. 11-50]. 240a H A T U 1! A 1. CULTURAL riracM. s D miCAl. rn-wo nis irr. Hihia'.icw. ruiiiirmn Social Fcoiiohic Physic AL FNF, STRIA, y„ro„«:,™. M"..Nr„M„, "min^"^ 1 Kw, S^i'm ™ $";" ™,,„„p„r .™™ hihiasir,,,:,, nr. rESini" torn rmmn ij\:id Ann VATrR u RPC « RATION s R .J T,T*'- r UATEj" • lUAUlY g a H § s | 1 3 3 3 h 3 '" -3 5 5 1 C 1 ! § 1 i s J \ D t.ai. ATM..W.T..WL «,„.,;»*, al INF.USTIUAI. af. 1 I 3 a 1 P. J g § 1 1 1 I £ '. '[': i i ■A k 3 jjj ti u 9 g 9 1 9 S 3 I 5 1 CROUHD CLEARING A>T> RESHAPIHC — - E0UTPHE1IT USE CHANNELIZATION, SHi RELLNE MODIFICATION, AlC OTHER VATER-REUTE2 ACTIVITIES - MATERIAL MOV EH EST TO SITE influx or temporary vork torce FURIC SERVICE REOU'REHOUS LAUD COMMITTED TO FACILITY OTIiER Ihtorocmlboh emissions i I'it LEAFS AND SPILLS VISUAL INTP.USION HUM,\M ACTIVITY DISRUPTION ACC1D7JI1S % I SO, MISSIONS 80 x EMISSIONS particulate: vnPP.OC.MIMN EMISSIONS OTHER EMISSIONS LEAKS AMD SPILLS SOLID UASTE COOLING WATER CONSUMPTION rPCCLSS WATER CONSUMPTION 'VASTP/JATER EFFLUENTS (ISOAl INTRUSION ACCIDENTS P HYDROCARBON EMISSIONS - LLA7.S AIIO SPILLS - VISUAL INTRUSION — HUMAN ACTIVITY DISRUPTION ACCIDENTS REFINERIES Figure 27 241 (c) Cultural impacts Of all facilities examined in this study, refineries require the largest operational work force. As shown in Table 20, the estimated employment during the operational phase varies from 410-550 persons for a 200-250-mbd facility. Furthermore, because average refinery wages are higher-than-average for the economy as a whole [506; pp. 1-29], the indirect employment and income gains to the local and regional economy could be significant. Also, the tendency for associated petrochemical plants to locate near large refineries could bring in significant numbers of new jobs and income. An important consideration is the land committed to the facility on a long-term basis, especially concerning the uses displaced by it. As the dis- cussion of refinery land requirements indicates, a facility of the size con- sidered here would require from 1,500-2,700 acres, a substantial committment of land on a local and even regional scale. Other concerns of a site-specific nature are related to aesthetics, noise, and public safety hazards. The accompanying activity impact matrix for refineries (Figure 27) can be used to evaluate potential impacts of a proposed refinery. 242 5. FACILITY COST ANALYSIS a. Introduction The economics of site location depend on the variations of costs and prices over space and time that arise through differences in resource and pro- duct availability and distribution. Some of the basic economic factors that are considered when examining and comparing energy facility locations are the avail- ability and cost of capital, infrastructure, labor, transportation, facilities, and the natural resources necessary for production and waste disposal, such as air, water, and land. The following factors are related to the determination of power plant location in the coastal zone: • The cost of transporting fuel from its origin to the energy facility and of onsite fuel storage. • The cost of a cooling system (including transporting water from source to plant) . • The cost of product storage and distribution to consumers and the relationship of distribution to the distance of consumers from the facility. • The opportunity cost of using land on the coast for energy facilities rather than alternative uses. • The cost of environmental controls, including air and water quality controls and transportation and storage of solid wastes. Energy facility siting requires tradeoffs among these factors. Table 32 is an example of such tradeoffs developed by the Rand Corporation for power plants located in California. Caution should be exercised in using these fig- ures because of their regional specificity. However, this chart does show some of the tradeoffs that can be important in siting power plants. These tradeoffs are of the type that must be made in comparing coastal and inland sites. b. Fossil-Fuel (Coal) Power Plants (1) Fuel Transportation and Storage The three major coal -producing areas which serve the Great Lakes Region are: the Eastern Province, the Interior Province, and the Northern Great Plains Province (Montana, Wyoming, North Dakota, and South Dakota) . These areas are shown in Figure 28 [222]. 243 Table 32 MISCELLANEOUS COST COMPARISONS INLAND COOLING VS. ONCE-THROUGH WITH SET-BACK • Wet cooling towers « 2 mi of set-back • Dry cooling towers « 6 mi of set-back WATER CONVEYANCING VS. TRANSMISSION • 1 mi of water conveyancing « 1 mi of transmission lines WATER COST VS. WATER CONVEYANCING COST . Water. cost at $100/acre-f t « 18 mi of water conveyancing DRY COOLING TOWERS VS. TRANSMISSION • Nuclear: dry cooling tower « 240 mi of transmission lines • Fossil-fuel: dry cooling tower « 170 mi of transmission lines WET COOLING TOWERS VS. TRANSMISSION • Nuclear: wet cooling tower «* 70 mi of transmission lines Fossil-fuel: wet cooling tower 3 » 60 mi of transmission lines No water or water conveyancing costs m- r 1 1 1 rl o A [149] There is a great deal of variation in the heat content of coal, depend- ing upon its origin. Western coal contains 7,800 to 8,800 Btu per pound, with an average of 8,300 Btu per pound, although some coal has up to 13,000 Btu per pound [316]; Illinois and Indiana coal ranges from 10,500 to 13,000 [213] Btu per pound, with an average of 12,000 Btu per pound; and Appalachian coal varies from 10,000 to 13,000 Btu per pound, with an average of about 12,000 Btu per pound. The Great Lakes Basin has four major coal transportation routes. Coal is transported by unit train from the Appalachian area to Lake Erie ports and shipped from there to other United States and Canadian Great Lakes ports (51% of the coal shipped out of Lake Erie ports went to Canada in 1975). The second 244 u o o 4J r- (d sf -P l [f] H 'd , , o 'v? jj T^ •H G^ rj -H *— •; I ,-, ^ '--J ^, i—l < _ pq O •H •• -P 3 u JQ u •r-i \i U o 4J go 0) -H Q 1 oo CM 0) u •D M 245 route is from Illinois and Indiana coal fields by unit train to the Chicago area and the lower part of Wisconsin along Lake Michigan. The third and most recent- ly developed route is from the west by unit train to the Lake Superior ports of Duluth and Superior. Currently, coal from the Superior coal dock facility is shipped to ports on the St. Clair River at the southern end of Lake Huron. Wes- tern coal may soon be shipped as far as Buffalo. The fourth route, also devel- oped recently, is by unit train from the west to Minnesota, Wisconsin, Illinois, and Ohio. The costs of transportation are important considerations in the future location of the coal-fired power plants in the Great Lakes Basin. Coal deli- vered by unit train is less dependent upon coastal siting than coal delivered by ship or barge. Locations east of Chicago probably would not receive western coal by unit train because the cost of receiving that coal would increase sub- stantially, due to problems and costs of transferring the coal to lines of other railroad companies. Important economic parameters that affect the cost of shipments are vol- ume, distance, capacity, speed, return trip cargo, and mode. Delivery of coal can be less expensive per mile if there is a return cargo, if it is delivered by unit rather than conventional train, if there are higher volumes, and if the cargo travels longer distances (although short routes with high volumes can be less expensive in some cases than longer routes) . It should be noted that these factors will change with the location of the receiving site. A comparison of slurry pipeline and unit train costs per mile (shown in Table 33) illustrates that their costs are closely competitive. Shipping coal on the lakes is less expensive per mile than other modes, but shipping dis- tances are generally greater on water than on land. (a) Western coal A comparison between railroad unit train delivery and a combined unit train-ship delivery of coal presented in Table 34 shows that it is economically feasible to deliver coal by unit train-ship from the western coal regions to Detroit. Although not indicated by Table 34, it is also economically competitive to deliver coal to Buffalo by this method. (Power companies serving the western New York area are considering this possibility.) The estimated cost of trans- porting coal to Buffalo by unit train-ship combination is $11.19 per ton; to Cleveland, $10.36 per ton. 246 TABLE 33 COSTS OF COAL TRANSPORTATION (1972 ESTIMATES) Costs 1 Type (dollars per 10 12 Btu ' s transported) Distance Assum (miles) ad Cost per Tor.-' (cents par ton- 'ilc mile) Fixed Operating Total Unit Train 5, 100 79,800 84,900 300 0.7 Con ven Li ona 1 T rain 9, 240 145,000 154,000 300 1.3 River Barge 4,850 35,600 40,400 300 0.3 Slurry Pipeline 48, 500 20,800 69, 300 273 0.6 Ship** . j 1 Source: ( Hittman, 1974, Vol. I, Tables 1 and 2 and associated footnotes.) * Personal communication, Argonne National Laboratory. [218 ** 1976 Dollar Figures. Slurry pipeline is another mode of transportation that can be used to deliver large quantities of coal. The estimates by Hittman Associates (218) show unit train and slurry pipeline are economically competitive with each other under certain conditions. Slurry pipeline is much more specialized and requires high initial capital outlay. It is considered a serious alternative only when: • No other transport exists. • Volumes between origins and destinations are large and steady. • Pipeline transport offers a more direct route (especially over rugged terrain) . • The solid coal is reduced to a slurry of fine particles during part of its normal processing. • Water for transport is readily and cheaply available. If one assumes new rail branch-line construction rather than transport by existing lines, costs per ton-mile for pipelines are competitive under the following conditions for solids: Tons per year (in thousands) Competitive with Railroads Over: 500 1,000 2,000 5,000 10,000 All distances Distances over 70 miles Distances over 150 miles Distances over 250 miles About the same over 300 miles [312] 247 Table 34 Transportation Costs (April 1974 Dollars) Per Ton of Delivered Coal Midwestern Point (D=Distance in Miles) 19/4 1978 1982 Powder River Basin Chicago (D=I172) Detroit (1=1444) Milwaukee (D=1257) Indianapolis (D=1266) Cincinnati (D-1304) Cleveland (D=1512) $ 8.08 (9.20) 9.96 (9.78) 8.66 8.74 9.14 (9.67) 10.43 $ 9.10 (10.36) 11.21 (11.01) 9.77 9.84 10.14 (10. 10.77 $10.24 (11.76) 12.63 (12.39) 11.00 11.07 11.37 (12.25) 13.21 H a n n a Basin Chicago (D=1128) Detroit ( D -1400) Milwaukee (D=1213) Indianapolis (D=1273) Cincinnati (D=1361) Cleveland (D=1468) Chicago (D~1477) Detroit (D=1749) Milwaukee (D=1562) Indianapolis (D=1585) Cincinnati (D-1612) Cleveland (D-1817) Railroad distance measured from the Handy Railroad Atlas of the U.S. (Rand McNally) 2 Nuttbers in parenthesis correspond to rail water routes *Argonne National Laboratory has indicated that these figures have increased three to four dollars a ton. 7.78 9.66 8.37 8.78 9.40 (10.24) 10.13 ( g i n t a 10.20 12.07 10.78 10.94 11.30 (11.58) 12.54 8.76 10.87 9.42 9.90 10.58 10.92 11.47 13.59 12.13 12.32 12.53 (13.03) 14.11 9.87 12 . 24 10.60 11.14 11.89 (12.99) 12.84 12.91 15.30 13.66 13.85 14.09 (.14.67) 15.89 248 It is difficult to obtain land for construction of slurry pipelines without the power of eminent domain. Most states do not have laws granting land condemnation power for slurry pipelines. Capital construction costs are 70% [312] of the total costs of slurry pipeline operation and construction. Slurry pipelines transport a single substance (coal) from a single point. There is a tremendous risk in building such a specialized line due to changes in the fuel transportation patterns, coal gasification costs, or costs of desul- furization. One slurry pipeline in Ohio has not shipped coal since 1958. The purpose of this pipeline was to reduce coal shipping cost by offering competi- tion to railroads. However, the railroads proved to be a more adaptable trans- portation mode and were more economically desirable. In the Great Lakes Basin the most likely destination for a slurry pipe- line from the western United States, from an economic standpoint, would prob- ably be the Chicago area. Such a facility would probably not be dependent on coastal locations, unless the coal slurry were transshipped to water carriers. The uncertainty of origin and type of fuels that will be used in the U.S. in the future and competition from railroad and barge lines will likely restrict any possible development of slurry pipelines to the Midwest. The location of power plants at western coal mines and transmission of electricity to the Midwest is an exceedingly expensive option, due to the high cost of building transmission lines compared to using existing railroads for coal shipment [307]. In summary, the most likely mode of transportation from the western coal region in the next 5 years is unit train, or a combination of unit train and ship. Power plants west of Lake Michigan are not as coastal dependent with res- pect to deliveries of coal from the western United States as are plants that must receive western or Appalachian coal transported by a combined unit train- lake carrier movement. (b) Eastern coal Obviously, since Appalachian and Illinois basin coal is transported shorter distances (50 to £00 miles) than western coal (900 to 1,400 miles) to reach the Great Lakes Region [550], eastern coal transportation costs are lower. Coal from these regions is transported by unit train to power plants in the Great Lakes Region. 249 The typical costs for transporting coal from the Appalachian field to the Great Lakes range from 2.50 to 4.00 dollars per ton in 1973 dollars. These costs depend upon the origin and destination of coal. The cost of transporting & southern Illinois coal to the city of Chicago is approximately $2.00 per ton, •k'k and to the State of Wisconsin is approximately $4.50 per ton in 1976 dollars. The costs vary by contract, type of delivery, distance, and other regional con- siderations. (c) Short distance hauling Power facilities located at inland sites near but not on the coast may receive fuels from water ports. In this situation, the additional cost of transporting the fuel is reflected in the cost of locating the facility inland as opposed to on the coast. The total cost of the coal may be less if it is transported to the plant entirely by railroad. In this case, the incremental cost of locating the facility inland (as opposed to on the coast) may be less than it would be if the coal were transported by water and then from the port to an inland location. There are a number of ways to transport coal over short distances, truck, conveyor, slurry pipeline, train, and barge being the most common. Trucks, although commonly used at mines, have limitations in the coastal zone. Economic considerations require use of large trucks which are generally undesirable or illegal for street use. Off-street use of large mine trucks requires an access road with approximately 53 feet of right-of-way or 6.4 acres per mile from the harbor to the power facility [400]. Conveyor belts can transport coal and wastes along a fixed route on an access strip. Conveyors require approximately 30 feet of right-of-way or 3.64 acres of land per mile [400] . Pneumatic slurry pipeline is a new technology for transporting coal. The pipeline would require a right-of-way of approximately 62.5 feet, but could be buried [400], For new technologies such as this, costs are subject to change more rapidly than in existing and proven technologies. Unit train transportation of coal for short distrances is expensive be- cause of high loading and unloading costs in addition to other slowdowns and Personal Communication, Commonwealth Edison ■k-k Personal Communication, Wisconsin Electric Power Company 250 delays incurred by using a long train over a short distance. According to one industry source, it would be virtually impossible from an economic standpoint to move a unit train 15 miles or less. Rail transportation lends itself to longer hauls. Barge transportation of coal from ports and terminals inland is limited to special areas with water access and inland dock facilities. Table 35 presents a cost comparison among methods used for short dis- tance transportation of coal. Although the estimates are not all for the same base year, the costs listed are indicative of the relative differences between modes. The cost estimates indicate the following order of transport modes by cost per ton-mile for a 5-mile distance, from lowest cost to highest: slurry (water) pipeline, truck, unit train, and conveyor belt. The (updated) 1974 cost estimates for unit train and conveyor belt transport of coal suggest that the two modes are about equal in cost over the 5-mile distance. Table 35 SHORT HAUL COAL TRANSPORTATION COSTS TONNAGE COST PER TON-MILE MODE YEAR MILES PER DAY (Cents) Trucking 1972 (estimates) 5-10 A. 5 (A) (July '74) updated 5 4.7 (B) Conveyor Belts 1972 (estimates) 5 7.6 (A) (July '74) updated 5 5.4 (B) Unit Train (July '74) updated 5 5.4 (B) Slurry Pipeline May 1975 4.5 (above 2000 tons) l-2c (estimates) (C) (Pneunatic) Slurry Pipeline (July '74) updated 5 1.2 excluding grinding equip . (B) (A) [222] (B) [211] (C) [218] ^Personal communication, Chessie System, 251 However, additional considerations change the relative ranking of the alternatives. Unit trains would probably not be used to transport coal from a coal unloading dock to an inland electrical generating or storage facility lo- cated 15 miles or less from the dock because of loading costs and delays. Ad- ditionally, large trucks presently used to transport coal at mine sites would probably not be used for the short haul of coal from docking facilities to in- land sites over public roads and highways due to the weight of the trucks and environmental concerns such as noise and coal dust. Thus, conveyor belts and slurry pipelines are the primary modes that would be used to transport coal from shoreline coal unloading docks to inland sites over distances of 15 miles or less [211, 218, 222]. Additional costs must be considered for slurry pipe- lines for grinding the coal for slurry pipeline use and dewatering the coal slurry (if pneumatic lines are not used) after movement to destination. There- fore, conveyor belt transport is the mode most likely to be used for the short haul transportation of coal from a shoreline dock to an inland facility. (2) Cooling Systems (a) Cooling system types A major determinant in the location of coal power plants is the cost of providing a sink for waste heat. Water is the primary natural resource used as a heat sink, although air can also be used in some cases. Costs vary for pro- viding water and cooling systems to coastal and inland locations. There are five basic types of cooling systems used for fossil-fueled and nuclear steam-electric plants: 1) once-through cooling, 2) wet cooling towers (mechanical and natural draft), 3) cooling ponds, 4) spray channels, and 5) dry towers. A nuclear power plant requires 50 percent more coo] ing water than a coal plant of the same capacity, due to the difference in heat rejection rates to the cooling water and stack losses. This difference for coal power plants is 67% of that for muclear power plants. As a result, coal-fired plant cooling systems cost less than systems used on nuclear plants of the same generating capacity [211, 149], As a rule of thumb, the cost of the cooling system for nuclear pow- er plants is assumed to be 50 percent more than that of a coal-fired plant. For this study's generalized facilities it is 45 percent. There are two major costs to consider in analyzing cooling systems: 1) capital costs (costs of building the system) and 2) operation and maintenance costs. Once- through cooling systems are used as a standard or base against 252 which to compare other cooling systems. Table 36 shows that there is a loss in plant efficiency and plant capacity and an increase in auxiliary power consump- tion when other systems are used. These losses and increased power consumption are reflected in higher operation and maintenance costs. TABLE 36 COOLING SYSTEM EFFICIENCIES FOR 800 MW COAL-FIRED PLANTS Once Wet Dry Thru Mechanic al Natural (Mech) Base 1% 1% 9% Base 1% 1% 10% Lost Capacity (Due to Higher Back Press) Loss in Efficiency (Increased Heat Rate) Auxiliary Power 1 Base 0.5% 0.25% 1.25% (Consumption) 2 Land Requirements'" - 3-5 2-3 5-7 (Acres) Source: [149] Based on various reports, and manufacturer's information 2 These land requirements are for comparative purposes only, not to calculate total station land needs. The capital costs in Table 37 were compiled for various cooling systems from an Atomic Energy Commission report on power plant costs [308]. Historical- ly, once- through cooling has been the least expensive cooling method. Table 37 ESTIMATED COSTS OF TWO-UNIT [1300 MW(e) EACH] COAL FIRED PLANT WITH ALTERNATIVE COOLING SYSTEMS Without Abatement With S02 In On creased ce-throv Costs Above igh Cooling Costs Capital Costs 945 1150 Base Base Dollars per kilowatt 363 442 Base Base Wet Natural Draft Cooling Towers Capital costs 983 1194 38+ 44+ Dollars per kilowatt 378 459 15+ 17 + Mechanical Draft Cooling Towers Capital costs 958 1164 13+ 14+ Dollars per kilowatt 368 448 5+ 6+ Source: [308; Capital costs in millions of dollars (mid-1974 dollars) Capital costs in dollars per kilowatt of plant capacity 253 The cost figures in Table 38 compare alternative cooling systems for nuclear power plants [51]. The figures are updated to 1975 dollars from 1973 dollars in the manner explained below the table and are based on a lower heat rejection rate for coal-fired plants than for nuclear plants. The entry en- titled "Evaluated Present Worth of Cooling System, Millions of Dollars" presents the capital costs for the various systems and the entry entitled "Increase in Generation Cost, Mills per Kilowatt-Hour" gives the operation and maintenance costs. From a capital cost standpoint, once-through cooling is the least expen- sive plant cooling system. At present, however, closed-cycle cooling is re- quired unless a utility company can prove, on the basis of meeting certain cri- teria presecribed by the U.S. Environmental Protection Agency (see Section III.B.l.d.), that its once-through cooling system will not cause serious envi- ronmental damage, and thereby receive a variance from this requirement. The data for closed-cycle cooling systems show that wet natural draft towers, wet mechanical draft towers, and spray canals are all economically competitive cool- ing systems, and the ultimate choice is dependent on site conditions. Environ- mental impact statements for nuclear and coal-fired plants show a wide variation in the costs of cooling systems. The reports [51, 181, 203, 235, 279, 308, 312, 149] do, however, indicate that wet mechanical draft towers are currently the least costly closed-cycle cooling system. Wet natural draft cooling towers are closely competitive to wet mechanical draft, but are restricted in use due to geological and atmospheric considerations. Recent experience with spray canals shows that operation and maintenance costs have been much higher than reported in the Nuclear Regulatory Commission's Nuclear Energy Center Site Survey [48-54]. (b) Cooling water supply A power plant located inland but near the coast could have water trans- ported to it by pipeline from the Great Lakes. Supplying water for a 1,000 MWe power plant with a once-through cooling system would require a pipe ten to twenty feet in diameter. An evaporative cooling system would only require a one to three-foot pipe. The exact diameter of the pipe needed depends upon many fac- tors, such as the velocity of the water, the hydraulic resistance of the pipe, and the volume of water required to ensure proper heat exchange. The operation and maintenance costs of supplying water by pipeline de- pend on pumping costs, which are a function of the height the water is pumped, 254 Pi o 5X4 >■< H H r-J H pa < H Ph H < 23 CJ P H CJ co w 2 )M a I— 1 co H -H ^ r-4 -H CO g o p CO < 25 G CO 0i 3 H CO O 1 fa O O fa LO G O CM rH 4-1 ■. i— 1 a ■H CT\ CXI o> o 4J i—l • H r^ • en O U CT> oo Sf LP) • O^ r*. LO « 4 > c -tr ra tr O 1 4~> o o -.— .,- 4 J ■4— *f— "^■C sc 4-> 4-> Out~ r:I rj f J #— 4 > »» s- y. 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OJ — H X •H G •- cd QJ rH 4-J X 5-4 LM — ^ 0) ^> s0 c = 4J o L) L!-J 5-4 M CO • •H SB ■ — i CGi o cd G G 5 c, p. iH pd 5-1 o Cd H X CO G — P H o P P o »4 o/: G GJ H G — i "3 cd •H X E CO CO 5-i ccj G LH G G o cd > — — X* 4-1 5-i a - CJ 5-1 G CO Ph CO iH «d _r cd 4- >^ p p i—l H CC C/l T3 o o «H 4-1 iH G G •H •H e 5-i E O •H OO 4J 4-J 4-1 cd TD X p rd cd G m Jp M P •H 3 5-i G rH G M-l G •H H , — i 0) 5-i > O cO P i- — > G X) O CO O > CD O CO > p ^ 5-i CJ w O G "~-" O CO cd O X* 4-J CO oo co G cd „ a) CJ r~- 1^. r^ CO G — 1 rP CO ON o a> G 4-1 G iH H CM H 1 — 1 ^^ X CO CJ uo CO X) G H 5-i H i— i 255 the distance from the water source, the type of power plant, and the type of cooling system. Table 39 shows how operation costs vary by distance from water source and height that the water is raised. The cost of operation increases drastically with the distance and height that the water must be pumped. In general, power plants with once-through cooling will be used when the elevation of the site does not significantly increase operating costs. The operating costs for conveying water for closed-cycle cooling will not generally affect the selec- tion of a site. In the Wisconsin Electric Power Company Environmental Report on the Pleasant Prairie Power Plant [552], three of the potential sites located along Lake Michigan would not have used once-through cooling systems due to the height to which the water would have had to have been pumped and the distance from the plant to the end of the pipe in the water. Table 39 OPERATION COSTS FOR WATER CONVEYANCE BY PIPELINE, BY DISTANCE, AND BY TYPE OF FACILITY FOR A 1000 MWe PLANT (Mills/kWh) COAL NUCLEAR (HEIGHT WATER IS CONVEYED) 3 FT. 50 FT. 100 FT. 3 FT. 50 FT. 100 FT. DISTANCE FROM WATER SUPPLY 1,000 Feet 1 Mile 5 Miles 1,000 Feet 1 Mile 5 Miles CLOSED CYCLE COOLING .0024 .0168 .0315 .0031 .0219 .0419 .0089 .0230 .0380 .0112 .0300 .0500 .0409 .0550 .0700 ONCE-THROUGH .0512 COOLING .0700 .0900 .0776 .4536 .8536 .0993 .5693 1.069 .3070 .6830 1.083 .3960 .8660 1.366 1.439 1.815 2.215 1.360 2.180 2.830 NOTE: 1972 dollars are projected to 1985 dollars at 3% for operation costs. The differential between nuclear and coal operation cost for water conveyance are due to the higher BTU/Kwh for nuclear power plants. Figures are from formulas derived by a Rand Corporation Report Electrical Generating Cost Model For Comparison of California Power Plant Siting Alternatives, Rand Corporation, 1973, p. 24. Capital costs for pipelines vary directly with the diameter of the pipe, length of pipe, type of cooling system, and cost of land. Both evaporative 256 cooling and once-through cooling systems require intake and outfall pipes Table 40 shows the cost of pipelines for different cooling systems. TABLE 40 WATER PIPELINE COSTS COOLING SYSTEM NUMBER OF 1000 MW CAPITAL COSTS POWER PLANT UNITS PER MILE YEAR OF DOLLAR Evaporative Cooling System 2 units (1234 MW) 4 units (4800 MW) $158,400 1985 from 19722/ at 5% inflation 1,020, 000^ 1974 1973 ±' 1,071,428 4/ 223,214- i/ 1973 20,000,000 10,000, oooA/ 1976 u 9,963,360 1985 estimated from 19721/ Once-Through cooling System — Communication, Detroit Edison 2/ — Communication, Commonwealth Edison 3/ — 1985 dollars estimated at inflation rate of 5% per year. [311] 4/ — The proportion of cost for a 1000 MW unit of the 4800 MW - 4 unit costs. Cost for 1 pipeline would be much higher than the figures indicate, but it is assumed that if power plants were located inland from the coast, then more than one plant would be built to take advantage of these economies of scale. 5/ The average cost per mile derived from cost data for a five-mile pipeline [573, 574] 6/ The proportion of cost for a pipeline serving a 1000 MW unit of a 2000 MW-2 unit plant. The cost for one pipeline would be much higher than this figure indicates, but it is assumed that if the power plant were located inland, then more than one unit would be constructed to take advantage of economies of scale. In general, once-through cooling would not be used for a facility loca- ted two or more miles inland. For example, cooling system costs for a 1200 MWe coal-fired power plant with a once-through cooling system located two miles in- land are shown in Table 41 to be approximately the same as those of a plant with a closed-cycle cooling system, because of the rapidly increasing operation and maintenance costs of the former system. Costs for specific sites vary de- pending upon site characteristics. 257 Table 41 COST OF PROVIDING WATER TO A COAL-FIRED POWER PLANT WITH 1200 MW CAPACITY SITED TWO MILES INLAND ONCE-THROUGH COOLING Pipeline Costs A. Capital $20,000,000 (a) B. Operation 0.5279 Mills Kwh (b)(d) CLOSED CYCLE COOLING (MECHANICAL DRAFT) Pipeline Costs $500,000 - A. Capital $2,000, 000( e ) B. Operation 0.0153 Mills Kwh (b) (d) The cost of the Mechanical Draft System which is more than the Once-through Cooling System. C. Capital $30,700,000 D. Operation and Maintenance 0.397 Mills Kwh^^ U) 1976 dollars 1975 dollars - adjusted at 3% per year from 1985 dollars to 1973 dollars, and increased at 9.3% per year to 1975. (C) 1975 dollars W) p ■ Pumping costs assume 3 ft. per mile which maximizes the use of once- through cooling. (e) 1974 dollars If a variance to current Environmental Protection requirements is not obtained or if once- through cooling cannot be used, the principal cost of lo- cating a power plant that uses Great Lakes water one mile inland from the shore- line would then be the cost of conveying water for an evaporative cooling system. or about $250,000 to $1,000,000 per mile. "This is not to say that such vari- ances cannot be obtained at a reasonable expenditure of time and resources by the utility. Section 316 [a] (of the Federal Water Pollution Control Act Amend- ments of 1972) exemptions to the closed cycle cooling requirements have been granted to Great Lakes stations."' If a given site would qualify for a 316 [a] exemption, the differential Communication, Commonwealth Edison 258 cost of locating inland would be the cost of conveying water for a once-through cooling system up to a distance- of two miles. This cost is approximately $10,000,000 per mile and 0.307 to 0.396 mills per kwh, assuming a 3 foot change in elevation. When a closed-cycle cooling system has to be used, the differen- tial cost is that of using a closed-cycle system versus a once-through cooling system. This cost is $30 to $45 million for the differential in capital costs of the systems, 0.397 to 0.517 mills per kwh for the differential in operation and maintenance costs of the two systems, and $250,000 to $1,000,000 per mile for the water pipeline costs. In any event, economics have a strong bearing on the type and design of cooling systems. (3) Electrical Transmission System The electricity produced by power plants is consumed at load centers which are primarily in the urbanized areas of the Basin. The cost of transmit- ting the electricity to the load centers from the power plant is primarily de- pendent upon the cost of the transmission facilities. These costs encompass transmission lines, their associated terminals, substations, and step-down transformers at major load centers. In recent years the location of power plants in relation to regional and instrastate transmission lines has been co- ordinated to minimize costs and increase electrical reliability. Power gen- erated in urban-metropolitan coastal areas is generally consumed within the coastal zone. There is no simple relationship between a transmission facility's cost and distance of power plants from the load centers. In specific cases, the cost may be increased or decreased by locating a power facility inland rather than on the coast. It is important to consider the location of existing load centers and transmission lines when examining an inland location for a power plant. If the transmission lines have been placed inland for environmental, social, or economic reasons, it may be less expensive to locate the power plant inland. If no such lines exist, it probably would be more economical to locate on the coast. There are more potential inland sites near load centers (urban areas) . The cost of transmission facilities varies widely. Estimating unit cost is made difficult by 1) regional differences in line construction cost due both to labor rates and the type of Communication, Detroit Edison 259 terrain; 2) differences in design at the same voltage rate; and 3) rapidly escalating costs [236]. Two lines of the same voltage level and length may have substantial differences in cost because one may have to follow an irregular right-of-way, requiring in- stallation of costly angle structures and dead end towers, in contrast to lower cost tangent towers which can be used on straight rights-of-way. As is indicated in Table 42 the "capacity of a transmission line at any voltage is a function of the length of the line and its location in the bulk power network." Figure 29 graphically presents the variations in power capacity with voltage and line length. Transmission lines, like other structures, have increased in cost at disproportionately higher inflation rates than the average price indexes. Over- head 765 kV lines are projected in various studies to cost in 1975 dollars be- tween $200,000 and $500,000 per mile, excluding land costs". It was estimated in the Nuclear Energy Center Site Survey (1975) that it would cost about $400,000 per mile on the average for the west and east central regions of the United States and $500,000 per mile for the eastern regions of the United States for a 765 kV line [51]. In summary, there is no apparent relationship between transmission line cost and proximity to load centers. Specific site characteristics will deter- mine the cost of locating inland versus locating on the coast, and no trends have been found at this time. (4) Land The value of land is a function of the availability of land offering a similar mix of resources, and not necessarily a function of the amount of land needed for energy facilities. The coastal zone has unique characteristics and features, whose value has often been assumed to be greater than that of an equal sized inland property. The value of these unique characteristics and features result from various demands on the coastal zone, many of which are in competition with one another, such as recreation, tourism, water supply, and multimodal transportation (ship and train). The value placed on this land due to its cultural, psychological, and aesthetic resources is greater than the value that these physical uses would indicate. For example, a house located on a lot on the coast near West Olive, Michigan costs $60,000 [549]. The cost Communication, East Central Area Reliability Agreement 260 TABLh 42 Costs and Power Carrying Capabilities of Overhead Transmission Circuits Costs are estimated as of January, 1974* Voltage: Nominal 345kV 500kV 7 65kV Maximum 3 6 2kV 550kV 800kV Capacity: 50 Mile 1000MW 2400MW 5500MW 250 Mile 6 25MW 150 OMW 3300MW Land: Route Width 150 ft. 175 ft. 200 ft Acres/Mile 18 21 25 Line Cost: Million $/Mile East 0.081 0.151 0.236 West 0.059 0.113 0.206 Central 0.051 0.059 0.102 Terminal Cost: Million $/Line (excluding transformers) 50 mile 3.175 4.900 8.700 250 mile 4.415 6.475 13.500 Incremental Terminal Cost (Park less dispersed) Million $/Line 50 mile 250 mile Transformer $/MW Generator Step Up Step Down (Auto) Power Losses: Percent of yearly energy delivered per 100 miles 1.0% 1.0% 1.0 - 1.575 5.525 10.325 1900 2600 1900 2600 1900 2600 * CAUTION: As of April 1975 these costs, which were derived from industry reported values in the early 1970' s, appear to be h or 1/3 of their present values . 149] 261 FIGURE 29 TRANSMISSION LINE CAPACITIES t < 0- < o < < 5000 4000 3000 ^.-500 TYPICAL LOADINGS 2000 000 300 MILES 262 of the lot was $30,000 of which $j>,000 was simple land value (similar to inland land costs) and $25,000 was aesthetic value [549]. The implications of these figures are that coastal property is more valuable than non-coastal property primarily because of its unique aesthetic resources. The benefits from this land realized by the public for aesthetic, recreational, or psychological rea- sons versus the benefits gained by public and private uses for ports and ter- minals, power plant siting, and cooling water are important resource management considerations. In summary, although difficult to estimate, the value of coastal land is generally assumed to be greater than non-coastal land. (5) Environmental Controls (a) Air The major air pollutants from the coal-fired power plants are SO (sul- fur dioxide), NO (nitrogen dioxides), and suspended particulates. The National Ambient Air Quality Standards and New Stationary Source Performance Standards place restrictions on the emission of these air pollutants. The major tech- nological problem for coal-fired power plants has been meeting the SO stand- ards and auxiliary to this, particulate emission standards. Two primary ways to meet the sulfur dioxide emission standards in the near future are flue gas desulfurization and use of low sulfur coal. In the future, f luidized-bed boilers and coal gasification may be important. Flue gas desulfurization technology is now in operation on several demonstration coal- fired power plants; however, the technology has not proven to be reliable in all cases. There are several types of flue gas desulfurization systems: wet limestone, dry limestone, magnesium oxide, catalytic oxidation, double alkali, and citrate systems, among others. Environmental Protection Agency information in Table 43 shows the lat- est estimates of cost for different flue gas sulfur control technologies, ar- ranged by size of power plant. The Table shows that the cost is between 2.7 and 4.2 mills per kilowatt-hour for limestone flue gas desulfurization, cur- rently the least expensive of the technologies [336]. The other major method of controlling sulfur emissions is through the use of low sulfur coal. There are two sources of low sulfur coal: the western states and the Kentucky-West Virginia region. Most of of the West Virginia and 263 fn en •H co td pq *J CO o u 00 On 01 n .) V-i U-l rt ■H CD H o >o w 'O o cm co ci ^o n ic co -J w ia - -i to NC0rHinr^o:cOH intA^^t^Ts] nn O r-- N M CN o) d o\ nmmMn-jvDco HHHVO H-JO\ io -J n n -o vo m oj -o - in i-» •— i i — (— | rf IT) r- 1 i% t^ co m -^-^rmcinrocMCM r*i \o ^ in i — m •— * en co co m m tn o ■- 1 o oOvdcooon— < r~- — i •^ W> •H T» r. 4J ■H ■H in i-l .-( T» Cfl •H ■rl •H O r-< X o y U-l to (f, j-i c iNi CJ 3 o lO ■h co n en )-j d • co in CO CO CO ft< ft< .>? c • o m o ■rl O l-J CM en ■n in c e< c -h cu - o m o > «-i to O O X -A O CJ CJ iJ3sc;>5>3CJ-ri o H C O a> c £ o. CJ Vj cm?: £ g e~ (5 ^ o ■H CO O o O o O u o c J c > o l. - 1 J-? CM CM i-O m in 5 u U o o cm ,-" cm en -h o o o co o co >: p o n o a. in c o C) a X o ~< x: > c K a m 264 Kentucky low sulfur coal is used for metallurgic processes although some has been used in the Midwest by power plants. The cost of western low sulfur coal, the major source of low sulfur coal for the Midwest utility market, is projected to increase at 3% per year between 1975 and 1980. After 1980, the price is expected to remain relatively constant. The cost of transporting coal has been a major component of this increased cost. This cost has roughly increased three to four dollars a ton more than the figures reported in the coal transportation section (Section IV.B.2.a). The cost of flue gas desulfurization, on the other hand, has re- cently stabilized and is not expected to increase as rapidly as in the past. The price of western coal depends upon several parameters; the cost of transportation, profit margins on low sulfur coal, whether air pollution stan- dards are enforced on time and without variances, the capability of mining and transportation facilities to expand, and others. An Argonne National Laboratory study on the differential in cost be- tween low sulfur coal and flue gas desulfurization found it to be less than one mill per kwh, with low sulfur coal being slightly cheaper. Due to this small variation in the cost differential between the two major sulfur controls, the method which will be used depends upon site characteristics affecting the trans- portation, origin, and destination of coal, duration of contracts, and company policy. There is an interrelationship between the cost of SO removal and par- ticulate removal. For example, the use of certain low sulfur coal will in- crease the emissions of particulates, and the cost of particulate removal. Another method for reducing sulfur emissions is physical and chemical coal desulfurization. When used with medium sulfur content coal, the resulting fuel can meet existing standards. The availability of medium sulfur coal re- stricts the use of this method (14% of the United States reserves) [219]. (b) Waste disposal Coal-fired power plants produce large quantities of solid waste; out of a ton of coal delivered to the plant, 10 to 30 percent is residual waste, main- ly in the form of fly ash. Coal with an ash content of 15 percent would pro- duce approximately 40 tons of waste per hour or approximately 250,000 tons a Communication, Argonne National Laboratory 265 year for a 1000 MWe power plant. A large land area (100-133 acres) filled to a depth of 25 feet is necessary for disposal of the waste over a 35-year useful life for a 1000 MWe plant [221]. In recent years, fly ash has been sold as filling material on local markets for asphalt and structural fills or embank- ments. In the United States in 1974, 16.3% of the fly ash was sold at prices ranging from two dollars a ton to as much as six dollars a ton, depending on the market supply and demand and the region. In the future, scarce metals such as magnesium, chromium, titanium, and vanadium may be extracted from the ash. A power plant located near the coast may transport the waste to an in- land location for disposal. The mode of transporting the waste inland varies, but tenerally pipelines or trucks are used. "The tariffs currently approved by the Michigan Public Service Commission for transporting fly ash are 69c/ton *** for up to five miles and $1.32/ ton for distances up to 5-20 miles." The transportation cost is only one of the costs associated with transporting the waste to an offsite location. The other is the incremental cost (the extra cost above onsite disposal costs) for extra onsite or offsite preparation, dis- posal, and storage of waste. "Annualized costs for waste disposal, a difficult problem, ranged from $1.00 to $7.00 a ton, and $3.00 a ton is used" [432]. Information from Detroit Edison shows the total cost of transporting fly ash wastes and disposing of them offsite to be as follows: A. Dry storage in silos and trucking to offsite disposal area. Assume sufficient silo capacity for three-day storage. Levelized Annual Cost: $3.96 per ton, 5 miles to disposal site $5.02 per ton, 20 miles to disposal site B. Flyash from hoppers mixed with water and pumped to small on- site reservoir. Dewatered sludge removed and trucked to off- disposal area every two years. $2.64 per ton, 5 miles to disposal site $3.71 per ton, 20 miles to disposal site C. Flyash from hoppers mixed with water and pumped directly to permanent disposal site. * Figures were reduced from a 3000 MWe plant, which would require 300-400 acres ** Electric World , May 1, 1976; Volume 185, Number 9. *** Communication, Detroit Edison. 266 Levelized Annual Cost: $2.53 per ton, 5 miles to disposal site $3.32 per ton, 20 miles to disposal site It should be noted that these costs are actually costs per ton of fly ash produced. The increased tonnage of ash-water mix- tures or any additional costs due to lime/sulfur slurries have not been estimated. The differential cost per ton of disposing the fly ash offsite as opposed to onsite is the cost per ton of offsite disposal (as in the chart above) minus the onsite disposal cost per ton. The major costs contributing to this differ- ence are those for transportation, onsite equipment, cost of disposal site, and site preparation. The cost of onsite disposal of fly ash varies from site to site and depends upon land costs, selling price and alternative uses for fly ash, and transportation and storage costs. If limestone scrubbers are used for the removal of SO , residual waste volumes will be expanded by one to two times the present amount each year [231]. Special problems will be encountered in disposing of the sludge from limestone scrubbers. Sulfur removed from the gas can be sold at up to $15.00 per ton [432]. "The EPA has estimated that sludge for a 1000 MWe coal-fired power plant [assuming three percent sulfur, 12 percent fly ash, 6,400 hours/year operation] will require 269 acres for solid waste disposal or 377 acres necessary includ- ing fly ash" [432]. "As a rough guide, EPA believes that if the cost of sludge disposal exceeds $4.00 to $6.00 a ton [wet basis], a regenerable process which covers a useful byproduct will be more economical than a nonregenerable pro- cess" [432]. In many instances, the preliminary data which EPA compiled on disposal waste indicated that offsite disposal is cheaper than onsite disposal [432]. In reality, the costs associated with offsite disposal depends upon specific site factors and regional conditions. In summary, waste disposal with limestone scrubbing could be a major problem in terms of land required. There is no obvious pattern related to the extra cost associated with offsite disposal as opposed to onsite disposal. c. Nuclear Power Plants (1) Fuel Transportation and Storage While the cost of transporting fuel can have a major effect on the lo- cation of a coal-fired power plant, this same factor has but a minor effect on Communication, Detroit Edison. 267 the location of a nuclear power plant L50]. The cost of transporting nuclear fuel is approximately $4.00 to $5.00 per kilogram of uranuim, or only one to two percent of the total cost of fuel. Table 44 shows that the transportation requirements for nuclear power plants are low over the entire nuclear fuel cycle. The implications of risk and impact on coastal waters from the trans- portation of nuclear materials is out of the scope of this report; however, the implications are extremely important and deserve further examination. TABLE 44 ANNUAL SHIPMENTS OF RADIOACTIVE MATERIALS TO AND FROM AN OFFSHORE NUCLEAR POWER STATION (One 1100-MWe Pressurized Water Reactor) Operation Approximate number of shipments per year Barge Land Fresh (unirradiated) fuel 3 1. Fuel fabrication plant to 6 trucks* shore transfer point 2. Shore transfer point to 1 to 2 barges c offshore power plant Spent (irradiated) fuel 3 1. Offshore power plant to 2 to 5 barges c shore transfer point 2. Shore transfer point to 60 trucks or 10 rail cars fuel reprocessing facility Solid radioactive wastes 1. Offshore power plant to 2 to 5 barges c shore transfer point 2. Shore transfer point to 46 trucks or 11 rail cars licensed radioactive waste disposal facility a The shipment of ompty casks for fresh and spent fuel will require essentially the same number of shipments as the number of loaded casks indicated in the table. However, the radioactivity hazard will be negli- gible. Initial loading of reactor requires about 18 truckloads of unirradiated fuel. Shipment of unirradiated fuel by rail is usually ruled out because of length of transit time. c Number depends on capacity of barge. [ J) 6 2 J (2) Cooling Systems A major determinant in the location of nuclear power plants is the cost of providing a cooling medium. Water is the primary natural resource used as a cooling medium, although air can also be used. There are different costs in- volved in providing cooling water to coastal and inland locations. As was the case with coal-fired plants, both capital (costs of building and of the components of the system) and operation and maintenance costs must be considered. The use of more sophisticated cooling systems results in greater losses in efficiency and capacity, and increased auxiliary power con- sumption than the use of once-through cooling. Table 45 shows that the ef- ficiencies for nuclear power plants vary with the cooling method. Table 46 268 TABLE 45 COOLING MODE EFFECTS ON NUCLEAR PLANT EFFICIENCY Typical Nuclear Cooling Mode Plant Efficiency Evaporative Natural Draft Tower 32.7 Evaporative Mechanical Draft Tower 32.6 Cooling Pond 32.8 Once Through (River) 32.9 Dry Tower - Mechanical Draft 28.1 Dry Tower - Natural Draft 28.6 Source: [149] Table 46 COOLING MODE EFFECTS.. ON FQ S S. I L /NUCLEAR PLANT OPERATION F OSSIL/ HTGR - 800 MW BWR/PWR - 100 MW Once Wet Dry Once Wet Dry D ir il M echanical Natural (Moch) ±L ir iL Mecha nical Na tura l (Mech) Lost Capacity (Due to Higher Back Ba.se 1% 1% 9% Base 1% 1% 15%-PWR Press) 17%-BWR Loss in Efficiency (Increased Heat Rate) Base 1% 1% 10% Base 1% 1% 15%-PWR . 17%-BWR Auxiliary Power Consumption Base 0.5% 0.25% 1.25% Base 0.3% 0.4% 2% (2) Land Requt remcnt (Acres) - 3-5 2-3 5-7 - 5-7 3-5 7-10 Based on various reports, studies, and manufacturer's information (2) These land requirements are for comparative purposes only, not to calculate total station land needs. 149 shows losses in efficiency and capacity and the increase in auxiliary power con- sumption due to various cooling systems. These losses are reflected in higher operation and maintenance costs. The capital costs in Table 47 were compiled for various cooling systems from an Atomic Energy Commission report [308]. Historically, as shown in the table, once-through cooling has been the least expensive cooling method. The cost figures given in Table 48 show comparisons among alternative 269 TABLE 47 ESTIMATED COSTS OF TWO-UNIT [1300MWe EACH] LWR PLANT WITH ALTERNATIVE COOLING SYSTEMS (Cooling Systems Cost in Brackets for One-Unit [1300 MWe] LWR Power Plant with Alternative Cooling Systems) Once-Ihrough Cooling Capital costs a 1410 Dollars per kilowatt 542 Wet Natural Draft Cooling Towers Capital costs Dollars per kilowatt Wet Mechanical Draft Cooling Towers Capital costs 1406 Dollars per kilowatt 541 Increased Capital Costs Above Once-Through Cooling BASE BASE 1434 24+ [722] 551 11+ [556] -4 -1 Capital costs millions of dollars mid-1974 dollars for a plant finished in 1981 Capital costs in dollars per kilowatt of plant capacity [308] cooling systems for nuclear power plants [51]. The figures in the table are updated to 1975 dollars from 1973 dollars in the manner explained at the bottom of the table. The line indicating "Evaluated Present Worth of Cooling Systems, Millions of Dollars" shows the capital costs and "Increase in Generation Costs, Mills per Kilowatt-hour" is the operation and maintenance costs, Once-through cooling is the least expensive system but currently is not used on new plants unless a variance is granted under Section 316(a) of the Federal Water Pollution Control Act Amendments of 1972. As the data shows, wet natural draft towers, wet mechanical draft towers and spray canals are all competitive alternative cooling systems depending upon the site location. Further discussion of this subject is presented under Sec- tion IV. A. 5. b. (2) of this report. (3) Electrical Transmission Systems No discernable differences between electrical transmission lines for nuclear power plants versus coal power plants could be detected. 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H Q c H a 02 z c 1 >1 a: 1 >, -H W ^-v W Cm a> X re < 0/ re z rJ S u o i- K u o u < Cm c CO (L 6. B re Cu d. c txi O HH < o z s: to u O O z X to CJ tc ^J 3E O o D2 >— ■ to o z rJ rH r: -H -a c o u h c ai jd u jj c c x >- c c c c K 03 CC 03 O 0> 01 01 I- :- - u oc 5c 5b 5c •H T-l -H -H lz_ ti. u. iu ►H KH r-l > 276 Footnotes for Table 50. 1 The figures for land requirements include the requirements for different cooling systems except for cooling ponds. The land requirements for cooling ponds and spray canals for coal-fired power plants were adapted from nuclear power plant requirements at the lower Btu/kWh heat rejection rate (77% of a nuclear power plant) for coal-fired power plants. The other cooling sys- tems, it is assumed, would not use appreciably more land for fossil-fuels than for nuclear. 2 These figures represent different plant capital costs in millions of dol- lars for a two unit [1300 MWe each] power plant. These costs are from a different source than the cooling system costs and are in mid-1974 present value dollars. These figures do not include fuel costs, operation and maintenance costs, or sulfur dioxide controls [308]. 3 The capital costs are presented in 1976 present value dollars for conveying water one mile inland for a 1000 MWe plant. See section on Water Supply (Section IV. A.b. (2) (b) ) , for detailed limitations on use of figures. The capital costs for water supply do not consider the type of facilities which could be used on the coast versus inland and should be used with caution. 4 The operation and maintenance costs are in mills per kilowatt hour in 1985 dollars projected from 1972 dollars for a 1000 MWe plant, assuming a height increase of 3 feet for one mile inland distance. 5 The capital cost figures are represented in 1975 present value dollars for a 1200 MWe plant. The coal-fired power plant figures are adapted from the nuclear figures by using the lower heat rejection, 77% of a nuclear power plant, for a coal-fired power plant. 6 The operation and maintenance costs are in 1975 dollars in mills per kWh. See section on Cooling Systems [Section IV. A.b. (2) ] , for limitations on use of figures. 7 The figures in the short haul transportation of fuel for coal assume a 1000 MWe plant using 2,800,000 tons of coal per year: the amount of western coal a power plant would use in a year. The short haul transportation figures assume moving coal one mile using conveyor belts at 5.4c per ton mile. Coal would not be moved just one mile at this cost due to high handling costs. 8 The long haul transportation figures assume moving 2,800,000 tons of coal a distance ranging from 250 miles to 1400 miles, assuming approximately seven miles per ton per mile. 9 The cost figures for transporting nuclear fuel for a 1000 MWe nuclear plant assumes the cost of 46,800 KgU of fuel per year is between $4.50 to $5.54 per KgU or an approximately average of $5.00 per KgU in 1976 dollars. 10 The land acreage needed for storage at a coal power plant assumes 90-day supply of coal and 30-40,000 tons/acre. 277 11 The cost figures are for a 1000 MWe plant assuming a quarter of the cost of a 765 kV line with a 4000 MWe line capacity in 1976 dollars. 12 The cost for sulfur dioxide controls, the principal air pollution control, are figured from costs that range between 2.7 to 4.2 mills per kWh. 13 The costs for fly ash disposal, the principal solid environmental control, are figured from a volume of 250,000 tons a year fly ash wastes for a 1000 MWe plant at one to seven dollars a ton disposal costs. The costs and volume will increase one to two times if limestone desulfurization pro- cesses are used. 14 The figures for land requirements for fuel transshipment and storage are for the principal use of these facilities — coal. The land requirements are only the area necessary for storing 1,400,000 tons of coal. 15 This cost figure for short haul transportation of coal is based upon 5.4 cents per ton per mile, and 5. 6 million tons of coal transported per year. Coal would not be moved just one mile at this cost due to high handling costs. 16 Depends on capacity. Figures given are from refinery description section.. 17 Based on minimum and maximum figures found in literature and size varies from 100 to 250 MBD. 18 Based on figures from [370] cited in [312]. 19 Noise and light control. 20 @ $1.052/bbl [312] — encompasses estimates in [506]. (continued from page 273) haul transportation section indicates that the cost of transporting coal fuels versus nuclear is many times more expensive on a per unit basis. The cost of transporting coal can have a significant effect on the location of a coal-fired power plant. Refinery site location costs, though no figures are listed, are significantly affected by existing pipeline location. New refineries will locate near existing or proposed crude oil pipelines. The storage section indicates the approximate number of acres the facilities re- quire for oil storage. The "Product Distribution" column indicates the cost to power plants and refineries for distributing their product, electricity and oil, to cus- tomers. The cost of product distribution from power plants is an important site location factor, but not necessarily a coastal dependent factor. The cost of product distribution from refineries is not an important factor in 278 determining site location. The "Environmental Controls" column reflects the cost to facilities for air, water, solids, noise, and light controls. The important environmental control in relation to site location is air. The air quality can affect both the location of refineries and coal power plants due to the ambient air quality. Refinery location can also be affected by light and noise intrusion, especially in relation to residential communities. In summary, this section has highlighted those factors which affect site location and coastal dependency. These important general factors affect- ing site location are often mitigated by specific site location factors. The specific site location factors, as is shown in the Pleasant Prairie Case Study, in Section IV. 6, and the discussion of coastal dependency can be more important in determining site location in respect to the coast than general site location factors. 279 6. DISCUSSION OF COASTAL DEPENDENCE AND CASE STUDY At the outset of this discussion on the environmental and economic factors affecting the siting of energy facilities the following definition of "coastal dependence" was adopted: The determination of energy facility location with respect to the lakeshore is expressed through the following general considerations : system requirements, safety, engineering, environmental, institutional, and economic. The breadth of this definition indicates that the analysis must go beyond simple evaluation of factors related to coastal locations, to a more general examination of facility location. Retaining the lakeshore as a reference point, however, puts the analysis into a coastal-versus-inland framework. This defini- tion thus provides sufficient latitude to identify the trade-offs between coastal and inland site locations. This analysis will provide a discussion of the general and specific factors related to both coastal and inland sites, highlighted by examples from a specific facility proposal. In selecting the facility to be used as an example, the following criteria were important: (1) it should be one of the facility types considered in this study, (2) it should be representative of the approximate size of facilities considered in this study, and (3) coastal and inland location alternatives should have been considered. The facility selected, the Pleasant Prairie Power Plant (Wisconsin Electric Power Company) near Kenosha, Wisconsin, provides the perfect example for this type of analysis. It is a coal-fired plant with an electric output of 1,160 MWe. Furthermore, sites both on Lake Michigan and inland were considered during the site selection process. A brief description of the facility is given below. The material used to highlight the discussion of coastal dependent and nondependent factors was abstracted from the Environmental Report, Pleasant Prairie Power Plant, Units 1 and 2 [552 and 553]. a. Pleasant Prairie Description In February, 1975, the Wisconsin Electric Power Company submitted an environmental report describing its proposed Pleasant Prairie Power Plant Units 1 and 2, to be built near the town of Pleasant Prairie, approximately four miles southwest of Kenosha, Wisconsin. In the report, information was provided on the proposed plant and site and its environment, the expected environmental impact of the project was assessed, and a comparative assessment was made of six alterna- tive sites. The facility is presently under construction. 280 The plant will consist of two identical generating units, each of which includes a coal-fired boiler, steam turbine and generator, and associated equip- ment. The two steam generators will use low sulfur pulverized coal at a rate of approximately 380 tons per hour per unit on a normal full load basis. The expected net capacity of the plant will be 1,160 MWe, although actual output will vary with ambient temperature and relative humidity. The total capital invest- ment in the plant and facilities will be $432,672,000, with annual operating expenses estimated to be $42,830,000. As of 1975, the Wisconsin Electric Power Company had not selected a coal supplier for the plant. However, it is determined that coal will be received at the Pleasant Prairie site by unit train from Wyoming coal fields, approximately 1,150 miles away. The main cooling water system will consist of two mechanical draft cooling towers rejecting approximately 6.8 x 10 Btu/hr to the atmosphere. The system will circulate a total of 400,000 gpm across the condensers for both units. Makeup water for this sytem will be received via pipe from Lake Michigan (approximately 4.5 miles east of the site) at a nominal rate of approximately 8,660 gpm. Particulate material will be controlled through the use of electrostatic precipitators designed for overall collection efficiencies of at least 99.3 percent. The collected fly ash will be moved pneumatically to silos for temporary storage before movement to an onsite disposal area. Because the plant will use low sulfur western coal it is not expected that sulfur dioxide emissions will be a major problem. In addition, nitrogen oxides and carbon monoxides are also expected to meet emission standards. To aid in the dispersion of these effluents a stack at least 450 feet high will be used. The Pleasant Prairie site incorporates an area of approximately 425 acres, of which the principal plant facility will require 210 acres. Figure 30 depicts the arrangement of the plant and the locations of the related facilities. Figure 31 shows the proposed intake and discharge pipe corridor leading to Lake Michigan from the site. The six alternative sites considered for this plant include: (a) the Haven site located at former Camp Haven Military Reservation in the northeastern portion of Sheboygan County; (b) the Port Washington site located southwest of the company's existing Port Washington Power Plant in Ozaukee County on Lake Michigan; (c) the Milwaukee Harbor site situated just north of the mouth of the 281 Milwaukee River on existing lake fill; (d) the Lakeside site located between South Lake Drive and Lake Michigan in the City of St. Francis (an existing power plant owned by the company is located just south of this site) ; (e) the Oak Creek site located in the southeastern part of Milwaukee County just north of the company's existing Oak Creek Power Plant on Lake Michigan; and (f) the Kenosha site located just south of the City of Kenosha municipal boundary. Figure 32 shows all of these sites, including the selected Pleasant Prairie site. In a comparison of the alternative sites, factors considered included the following: (1) proximity and suitability of both rail and road facilities during construction and operation of the plant; (2) potential for congestion of service roads; (3) surrounding land use; (4) proximity to population concentrations, and; (5) other factors discussed in the environmental report. In addition, sites were evaluated on a combined economic, engineering and environmental basis. Critical factors for evaluation and comparison included site characteristics, cooling method, and fuel supply provisions. b. Discussion of Coastal Dependence Because this study deals with the problem of site selction on a nonsite- specific basis, it is impossible to identify those factors favoring a coastal site over an inland site or vice versa. Instead, at the level of this analysis there is a continuum of coastal dependence or nondependence, running from those factors that can be generalized for all sites as being coastal-related to those factors which may, on a site-specific case-by-case basis, involve important coastal versus inland site trade-offs. The most obvious factor tying major energy facilities, especially electrical generating facilities, to the coast is the need for large volumes of water to dissipate the great amounts of waste heat. In the past when once- through cooling was used almost exclusively, a coastal location could result in tremendous cost savings: figures developed for this report indicate that the capital cost alone for a once- through cooling system could be up to $10 million per mile to move water to an inland site for a 1000 MWe plant. In addition, the operating and maintenance cost would be enormous. One estimate of this is 0.307 mills/kWh/ mi (assuming a difference in elevation of 3 feet between water intake in the plant). With the increased use of closed-cycle cooling systems, however, this dependency on the coast has been lessened considerably. The capital costs for supplying water to a plant with a closed-cycle system range from only $250,000 to $1 million per mile. Operating and maintenance cost are estimated to be 283 w O H K ui O 2 a £ O — — K 8 I rss ! HI w 9 284 MANITOWOC HAVEN SITE ST WASHINGTON PORT WASHINGTON SITE DANE CO GENERAL WILLIAM MITCHELL FIELD j RACINE CO.1 ROCK CO. WALWORTH CO. BTURTEVANT 4.1 CHICAGO, MIWAUKEE, ST. PAUL AND [_ [PACIFIC RR. COMPANY BELOIT ILWAUKEE MILWAUKEE HARBOR SITE LAKESIDE SITE OAK CREEK SITE ENOSHA KENOSHA SITE PLEASANT PRAIRIE SITE 2 < O X u ILLINOIS CHICAGO AND NORTH WESTERN TRANSPORTATION COMPANY WAUKEGAN ALTERNATIVE SOTi LOCATION FIGURE 32 :TK^ gAiwa uaii ^ra)fflM^iK Hra«ffittiaB6M«M^ PLEASANT PRA8RI2 POW'ER PIAMY Wisconsin Electric [SOURCE - 552] irnn m i ii um i — — — f* M ■— — M I ---»n- J 285 0.0153 mills/kWh/mi . This reduction in cooling water supply costs for inland sites allows the utilities and companies much more freedom in their site selection procedure. This is not to say, of course, that an inland site with a closed-cycle system will maintain its water supply more economically than a coastal site with once-through cooling; in most cases the latter would be much less expensive in the long run. What it does mean, however, is that the companies will be able to take advantage of other possible benefits of inland locations. In the Pleasant Prairie example the following site alternative combina- tions were considered: • Both once-through and mechanical draft cooling towers were considered for the Kenosha, Oak Creek, and Haven sites. • Once-through cooling exclusively was considered for the Port Washington, Lakeside, and Milwaukee Harbor sites. • Mechanical draft cooling exclusively was considered for the Pleasant Prairie site. While an acceptable arrangement could be developed for each of the sites using the systems mentioned above, there were substantial construction and operating cost differences between the systems and among the sites. For example, minimum construction cost would be incurred at the Haven, Oak Creek and Kenosha sites, utilizing mechanical draft cooling towers. All schemes utilizing a once-through system would be considerably more expensive ($2.5 to $7.8 million, depending primarily on the length of the cooling water intake and blowdown discharge lines required) . The Pleasant Prairie site would incur additional construction costs of $5.5 million for the five-mile cooling water makeup pipeline from Lake Michigan to the site. While construction costs for the mechanical draft towers are significantly lower than for the once-through cooling arrangements the annual operating costs of approximately $850,000 per year would be considerably higher. Although long run costs for cooling water supply to the Pleasant Prairie site would be higher than for the other locations, use of a closed-cycle system allowed the Wisconsin Electric Power Company to take advantage of other signifi- cant Pleasant Prairie site benefits. Specifically, the Pleasant Prairie site would incur minimum costs in tying into the existing transmission system, for which the other sites would incur considerable costs. In addition, Pleasant Prairie was the only site at which adequate rail transportation access was already available. The Pleasant Prairie site had additional benefits not found at the other locations (some of these are discussed below) . 286 Another factor important in many, if not all, facility location decisions is the location of properties owned in part or wholly by the companies. For example, in most environmental reports regarding proposed facilities reviewed during the course of this study, it was found that alternative sites were generally owned by the utilities. In similar fashion, fuel transshipment facilities and refinery expansions are generally constructed adjacent to existing facilities. This is primarily a reflection of the long range planning engaged in by the major energy suppliers. However, it can result in a definite bias toward coastal locations purchased by the companies in the past when once-through cooling was used almost without exception. This observation is borne out by the following citation from the Pleasant Prairie Environmental Report: With the exception of Pleasant Prairie, all of the candidate sites were located on Lake Michigan. . .All sites are owned by the Applicant with the exception of the Milwaukee Harbor site and small parcels at some of the other sites [552; p. 6. 3-1]. A factor of considerable importance, especially in the siting of fossil- fuel power plants, is the location of fuel delivery routes and transshipment points. As was indicated in the discussion of transportation access in the fossil-fuel facility description [Section IV.A.5 .b. (1) ] , it is desirable to have a location offering fuel delivery options; a coastal site served by both lake carrier and railroads would meet that requirement. There are many locations in the Great Lakes Region where delivery by lake vessel or barge is far more economical than by unit train. For a 1000 MWe coal-fired plant using 2.8 million tons of coal per year it would cost approximately $150,000 per mile per year to transport coal inland, in addition to the handling and land costs for port and terminal storage. Cost savings for fuel supply (in addition to water supply) in such a case would tend to favor a coastal location. While fuel delivery via lake carrier or barge may not be an important consideration in the case of nuclear facilities, delivery of major facility components might very well be. As was discussed in the transportation access section in the nuclear plant description [Section IV.A.c.(l)], ease in delivery of large reactor and turbine components may favor locations with water access. In the Pleasant Prairie example, the opposite situation was found. Coal receipt was to be exclusively by unit train from the western United States, and the Pleasant Prairie location offered the least expensive alternative with respect to fuel supply. This cost savings was able to partially offset the increased cost of cooling water supply, illustrating the advantages of coastal nondependency 287 Two important factors were identified in the discussion of the hydro- logical and meteorological site requirements for nuclear plants related to shoreline sites: (1) the change in atmospheric stability that occurs at the land- air interface, and (2) the change in wind trajectory experienced when air moves from the smooth surface of the water to the irregular land surface. These concerns highlight the fact that local coastal meteorology may be an important factor in determining whether or not a facility should be located on or near the lakeshore. This consideration was further addressed with respect to coastal meteorology as it affects the dispersion of emissions from fossil fuel plants. The influence of the lakes on meteorological patterns plays an important role in determining nitrogen oxide and hydrocarbon impacts on the air quality onshore. For example, Milwaukee has experienced high oxidant air pollution reading at times when emission activity was low. One theory is that the daytime nitrogen oxide and hydrocarbon emissions are blown out over Lake Michigan by a land breeze, photochemically reacted to form oxidants, and blown back to the shore with the evening lake breeze. There are only sketchy experimental data to verify this hypothesis. Nevertheless, the lakes do play a significant role in determining the transport of pollutants [546; p. 80]. The Pleasant Prairie report provides a perfect example of these types of concerns. With respect to air quality, the Haven site was the most desirable, being located in an area which had no other major sources of pollution. In this regard, the Pleasant Prairie site ranked second and was located further away from local and metropolitan emissions than the other sites available. Concerning meteorology and climatology, all the sites are located in a region characterized by favorable large scale dispersion patterns. The Pleasant Prairie site, however, appeared to be the most acceptable in this respect because it was further inland, with frequency and intensity of lake effects being less than at the other sites. Therefore, "the potential for fumigation of stack emission and for ground level fogging and icing due to the cooling tower emissions during onshore winds will be less than for the lake shore sites" [552; p. 6. 3-6]. A second concern related to local shoreline meteorology is the potential effect of the facility on the local climate. For example, in some areas (e.g., Erie County, Pennsylvania, and southwestern Michigan) the presence of the lakes creates a climate uniquely suited to specialized agricultural crops , such as fruits, by extending and stabilizing local growing seasons. The presence of a major energy facility, especially one fitted with a closed-cycle cooling system, could possibly change these conditions. The potential for such changes would have to be evaluated. The aesthetic impact of a coas tally located energy facility can be great. While this may not be true for all locations (e.g., highly industrialized areas such as Gary, Indiana, and Lackawana, New York) there most certainly are many areas along the Great Lakes shoreline which would be severely disrupted by the presence of such a facility. While there may also be aesthetically unique areas inland from the coast, it is more likely that such areas would be of limited extent along the coast. This would indicate a desirability to locate facilities away from these unique shoreline areas when possible. There are a series of coastal-related factors that may tend to favor inland locations to allow savings in construction costs. Examples of these are areas subject to flooding during periods of high lake levels, coastal reaches subject to high rates of erosion requiring expensive (and sometimes ineffective) erosion control structures, areas requiring significant bluff restructuring, sites requiring significant fill, and sites requiring special foundations. As the shoreline segment maps in Figure 33 indicate, the Great Lakes coast is highly variable and these factors must be evaluated on a site-by-site basis. It is sufficient to say, however, that there are many areas in the Great Lakes Basin where inland locations may be preferable to near-shore locations to avoid such problems. Several of these considerations were brought out in the selection of the Pleasant Prairie site. The comparisons of site preparation costs included: special structures required, earth work, demolition, and associated costs. The only major difference among the sites was in the amount of earth work required. The Haven, Milwaukee Harbor, and Pleasant Prairie sites required a minimum amount of earth work and thus showed the minimum cost. Two Oak Creek alterna- tives and the Kenosha site would have required major grading and use of borrow material with associated costs of approximately $400,000. The Port Washington, Lakeside, and a third Oak Creek alternative required landfill and extensive restructuring of bluffs. Costs associated with these activities were estimated at approximately $5 to $6 million above the minimum site preparation costs. In addition, the Haven, Oak Creek, Kenosha, and Pleasant Prairie sites could utilize mat foundations. The Port Washington, Milwaukee Harbor, Lakeside, and a variation of the Oak Creek site would use landfill and thus would require pile foundations at an additional cost of approximately $4.4 million. Thus, the lower construc- tion costs associated with the inland site tended to favor the selection of Pleasant Prairie. 289 FIGURE 33 EXAMPLES OF GREAT LAKES SHORELINE TYPES , _ s LAKE ERIE Artificial Fill Area Erodible High Uluff. 30 ft- or higher Non-Erodible High Bluff. 30 ft. or higher . Erodible Low Bluff, less than 30 ft. high . Non-Erodible Low B'uff. less 'nan 30 ft. nigh High Sand Dune. 30 ft. or higher Low Sand Dure, less than 30 ft. high Erodible Low Plain Non-Erodible Low Plan Wetlands Combinations Shown As: Lakeward/Landward . Upper Bluff Material Lower Bluff Mater Beach Material Sand and gravel Ledge rock . Problem Identification Areas subiect to erosion generally protected . Critical erosion areas not protected Non-critical erosion areas not protected Shoreline subiect to lake flooding Shoreline not subiect to erosion or flooding _ Bluff seepage problems ._& [SOURCE - 607] 290 Just as there are a wide variety of shoreline characteristics that influence construction costs, there are also many landforms and habitats which make portions of the coast unique. Examples include the rocky cliffs along portions of the Lake Superior shoreline, the sand dunes along eastern Lake Michigan, and the areas of coastal wetlands. In many cases these features may be quite rare and limited in their extent. For example, there are only 57 miles of coastal wetlands in the entire Great Lakes Region, amounting to only 1.5 percent of the total shoreline mileage [436], In some cases the protection of these rare and unique landforms and habitats may require the inland siting of energy facilities. This may become especially true when the state coastal zone manage- ment programs begin to designate areas of particular concern. Not only should potential conflicts with the land in its natural state be avoided, but also conflicts with various land uses. The Great Lakes shoreline is and will continue to be put to many uses by people from both within and outside of the region. Some of these uses, such as lake fishing, swimming, and boating, require the use of the lake. Others, while not absolutely requiring a lakeshore location can be greatly enhanced by one, such as second home development, picnicking, hiking, nature study, etc. Displacement of these uses by committing large tracts of land to energy facilities for long periods of time can result in long-term social costs and lost resources. The need to look at these alternative land use conflicts has been alluded to at several points in the discussion of energy facility impacts. The desirability of avoiding such conflicts may indicate a preference for inland locations for large energy facilities. Because the amount of shoreline is immutably fixed, it is important that uses of it should be assigned priorities, with those not requiring a coastal location sited inland when possible . c. Summary This discussion of the coastal dependence or nondependence of energy facilities in the Great Lakes Region has necessarily been conducted at a very general level. Because of this it has identified only one generally applicable example of a trade-off that must be made between coastal and non-coastal loca- tions: the supply of water for the main cooling system. There are however, a large number of other considerations that should be evaluated on a site-by-site basis to determine the importance of a shoreline location for a proposed power plant: utility land ownership, mode of fuel delivery^ local meteorology and 291 dispersion patterns, aesthetics, potential construction problems, unique land- forms and habitats, and potential land use conflicts. The use of the Pleasant Prairie example has served to illustrate that none of these factors can be considered in a vacuum. A similar evaluation of another plant in a different area of the Basin could show a strong coastal dependence. The trade-offs and relative economies associated with each must be evaluated so an overall picture of the coastal dependency of a given facility can be developed. 7. CONCLUSIONS AND IMPLICATIONS FOR POLICY OPTIONS The preceding descriptions and discussions of energy facilities and their associated siting requirements and environmental and economic impacts have been provided to determine the degree to which these facilities are dependent on coastal resources, and to highlight those siting factors which appear to be most coastal dependent. The discussion of coastal dependence which directly precedes this section attempts to outline those technical considerations and environmental impacts which most heavily depend on or affect coastal resources. These coastal dependent factors are further clarified by relating them to a case study reporting the actual coastal and non-coastal factors considered in the siting of a fossil- fuel power plant. Briefly, the following factors and considerations have been highlighted in the foregoing discussion as the most coastal dependent in relation to the siting of energy facilities in the Great Lakes Basin: o The Great Lakes coastal zone provides resources and opportunities for many uses. Inevitably, the development of some of these uses must necessarily exclude or displace others. • Unique landforms and habitats presently exist in Great Lakes coastal areas . • Aesthetic considerations such as scenic coastal vistas are unique to the Great Lakes coastal zone. • Special construction constraints such as bluff reshaping and shore protection are associated only with the lakeshore. • Coastal meteorology and related dispersive capability are special siting considerations on a site-specific basis. • Many utilities presently own land along the coast for future develop- ment of energy facilities. 292 • The Great Lakes represent a large and easily accessible source of water for cooling purposes. • Access to waterborne transport of fuels and materials is necessarily related to the Great Lakes ports and terminals. The following general conclusions can be cited with respect to the coastal dependence of power plants: • Facilities using once-through cooling must be located on or near the shoreline because of the substantial costs of transporting cooling water inland via pipeline. • Facilities using closed-cycle cooling are less dependent on locations on or near the shoreline than are facilities using once-through cooling, assuming all other factors to be approximately equal for sites being compared. Site conditions will determine the type of closed-cycle cooling system used. However, the further inland a facility is located, the greater are the. construction (capital) costs for water provision and blowdown pipelines. • For power plants using closed-cycle cooling, the cost of locating on the shoreline versus the cost of locating inland are essentially trade-offs among the construction and operation costs of such necessities as transmission lines, water supply and cooling facilities, facilities for delivery and handling of fuels and other supplies, and disposal of waste material. • Nuclear facilities require very large and massive components, which in most cases are delivered via water transportation. However, rail or road corridors of adequate width and load-carrying capacity can be utilized for delivery of these components. If these rail or road corridors are not available to potential sites, the location of nuclear facilities may be more dependent on shoreline or near-shoreline locations. However, field assembly is becoming more common, thus possibly negating some of this shoreline dependence. Other nuclear facility coastal dependence considerations are the same as in the preceding item. The coastal dependence of fuel transshipment and storage facilities and refineries can be summarized as follows: • Fuel (coal and oil) transshipment and storage facilities that receive or ship their commodities by water must locate near the shoreline, although storage areas do not have to be located on the shoreline. Storage area location is highly dependent on industrial needs, future transportation requirements, and onsite and offsite use of stored fuel. 293 • Refineries are not coastal dependent, but do need access to water for processing and cooling. Dependence on easily accessible water is decreasing due to increasing water recycling practices . Air cooling is also reducing refinery dependence on easy water access. Refinery location decisions are increasingly becoming market oriented, with decisions being made on a national basis, due to the existence of the national product distribution pipeline. Finally, coal gasification and liquefaction facilities are not likely to be located in the Great Lakes Basin, with the possible exception of low-Btu gasi- fication facilities, which can be located at or near the site of use. Large coal gasification and liquefaction facilities will be located near mine mouth locations due to the high cost of transporting coal compared to substitute natural gas. The implications of this report on technical considerations for the development of policy options relating to energy facility siting in the coastal zone are many and varied. In a general sense, however, it is possible to say that no one factor absolutely ties a given energy facility to a coastal site. Furthermore, it is evident from the discussion of technical considerations and the case study that there are a number of technical options which may be generated for future siting considerations. These options are predicated on the conclusion that energy facilities are not coastal dependent per se , and that it is possible that they be sited inland from the coast while maintaining certain degrees of access to coastal resources. The technical policy options and implications developed in Section VI. C are based on this tenet of nondependency . At this point, a concluding statement on facility siting should be made. The entire preceding section dealt with technical considerations affecting siting of energy facilities. It should be noted that there are other possible (or even probable) considerations of a nontechnical nature which may affect the final site selection process. More specifically, these considerations relate to politico- economic decisions based on expediency and profit motivation. To ignore the existence of these nontechnical considerations in the site selection process would be naive; to assess their magnitude in relation to coastal siting would be impossible. 294 B. ENERGY CONSUMPTION AND MOVEMENT IN THE GREAT LAKES REGION 1. INTRODUCTION Rational planning for the future necessitates a sound knowledge of the present. The following information was collected for the purpose of providing that knowledge. This section presents collected data on the present energy situation pertinent to the Great Lakes coastal zone. An attempt was made to concentrate on those aspects of supply, transpor- tation and utilization of energy that relate to electric power generation and the coastal zone. Electric generating facilities and fuel transshipment points are discussed both in the context of present capacities and locations and of planned and scheduled facilities. A major portion of this section attempts to address the question of the future relationship between energy facilities and the coastal zone. This discussion focuses on the relationship between electric generating facilities and potential fuel mixes. Further, the problems associated with determining future demand levels for electric energy are discussed in the context of how various demand growth rates may affect siting of electric generating facilities. Finally, a number of potential fuel mixes and growth rates were postulated in the attempt to determine possible future resource requirements and pressures on the coastal zone. 2. ENERGY DEMAND a. Fuels for Power Production The Great Lakes Region is one of the most highly industrialized and energy consumptive regions in the world. Its development is in large measure facilitated by the ease of commodity transportation on the lakes and the wealth of fuel resources within the eight states bordering the Great Lakes. Energy production in the Great Lakes states reflects the unique resource capabilities of the region. An average of over ninety percent of the fossil-fuel electrical generating facilities are coal fired in seven of the eight Great Lakes states. This section will therefore focus on the origin, transportation and end use of coal, although other fuels will be discussed also. The discussion will assume a regional and state perspective with special emphasis on activity in the coastal zone. 295 (1) Origin of Fuels The Great Lakes Basin states are net importers of energy. Each state consumes more energy from coal, oil and natural gas than it can produce. Even the major coal- and oil-producing states of Pennsylvania and Illinois consume over twice as much fuel as they produce [618]. Thus, the Great Lakes Region must depend heavily on fuels from elsewhere. (a) Coal The United States has an abundant supply of coal. The estimated reserve base for the country is 434 billion short tons. This is an estimate of the identified resources deemed suitable for mining by 1974 methods [19]. At the present consumption rate of approximately 600 million tons per year this resource could last six or seven centuries. There are three primary coal supply regions: the Appalachian, Illinois and Western basins. The preponderance of coal consumed in the Great Lakes states is produced in the Appalachian and Illinois coal fields. These two major fields supply most of the region's needs for coal for power production. Pennsylvania and Ohio supply almost 40% of the coal used by electric utilities in the Great Lakes states. Illinois, Kentucky and Indiana follow in order behind these states. Combined, the five states provided 76% of the total coal supplied to the Great Lakes utilities in 1975 [547]. FIVE LARGEST COAL PRODUCING STATES FOR ELECTRIC UTILITY USE IN THE GREAT LAKES STATES State Pennsylvania Ohio Illinois Kentucky Indiana TOTAL 1975 (1000 Tons) 38,093 37,533 31,201 22,933 20,172 149,932 1975 Percent of Great Lakes States Total 19.5 19.2 16.0 11.8 10.3 76.8 SOURCE [547] 296 Recently, air quality standards have forced utilities to purchase a lower sulfur coal than commonly found in the eastern fields. The purchase of a considerably lower sulfur coal from the Western basin, primarily Montana and Wyoming, has increased considerably in the region. Between 1974 and 1975 there was a 58.3% increase in western coal destined for states in the East Northcentral Region (Wisconsin, Illinois, Indiana, Ohio and Michigan). Ninety-five percent of the western coal shipped to the Great Lakes states was produced in Montana or Wyoming. Most of this fuel was surface mined and of sub-bituminous grade [547]. Table 51 presents the major state sources of coal to electric utilities in the Great Lakes states. TABLE 51 ORIGIN A N D DE STINATION O F COAL DELIVERIES TO ELECTRIC UTILITIES IN 1975 (Deliveries in 1000 tons) O R I G 1 N ■ AST i a n MIDWEST U E S T E 1 N DESTINATION KENTUCKY OHIO W. VA. PA. ILL. IND. MONT. WYO. COLO UTAH Percent Totsl Coal Froa All States Illinois 1.18*. 1 9.1 0.3 - 21,218.1 379.3 9,310.5 1,866.3 10.3 20.0 33,999.3 Indiana 5,045.5 0.9 75.0 " 3,134.6 18,896.4 819.0 2,841.4 1.6 130.3 30,944.7 _ 30,968.1 * Michigan 5.778.7 8,362.1 5,116.6 691.0 274.5 82.2 1,056.0 - " - 21,361.3 . 21,361.8 "* Minnesota 98. J 0.4 3.0 - 1,717.3 - 6,205.1 2.2 3.0 60.9 8,797.4 "" New York 524.0 - 839.7 4.591.6 - - - " 5.0 " 5.970.8 *" Ohio 7.151.9 29,113.6 6,540.6 2,168.2 29.6 - 93/. 7 1.9 362.4 ",30S-» . m 46.860.3 ™* Pennsylvania 1,080.4 20.3 4,216.2 30,070.3 - - - " - " 35.448.9 "* Wisconsin 2,072.6 26.6 4.6 572.4 4.856.9 784.6 2,161.2 1 ,052.8 20.2 " 11,552.5 TOTAL 22,933.5 37,533.2 16,796.0 38,093.5 11,201.4 20,172.1 19,551.8 6,700.4 316.5 573.6 194,659.1 . 194,959.1 SOURCE: [547] NOTE: Does not include anthracite and imported coal. The coal resources in this country have been extensively surveyed. The magnitude of remaining deposits provides a stable base for fossil fuel-fired electricity generation. The quantity of this fuel is not at issue. Concern centers rather on environmental and health risks involved in coal utilization. These factors will to a large extent determine the coal type recovered for future use. 297 (b) Oil and natural gas All the Great Lakes states except New York have a fossil-fuel mix percentage for electrical generation lower in oil and natural gas than the rest of the country. These seven states used about 5% oil and 3% gas for power. The national figures in 1975 were 18.9% oil and 19.8% gas for the generation of electricity [547]. Further analysis of these statistics is contained in the discussion of fuel mixes. Most of the sources for oLl and natural gas are distant from the Great Lakes Region. A network of pipelines carries oil and gas into the region from the south? central, and Gulf states:" Canada also supplies oil to the region from fields in Alberta. With Canadian demand increasing, this source will soon be terminated to the Great Lakes states. The Great Lakes states are relatively minor producers of oil and natural gas, contributing about 3% of the U.S. oil production and 2% of the national gas production [24]. The region must therefore import substantial quantities of oil and gas. An examination of production and consumption figures in the eight states for oil and natural gas reveals that the states supply about 4% of their annual consumption [618] . Figures 34 and 35 show the major sources of natural gas and oil for the Great Lakes Basin states. FIGURE 34 SOURCES OF NATURAL GAS SUPPLY TO THE GREAT LAKES BASIN STATES GLGT - GREAT LAKES TRANSMISSION CO. M*PL - MICHIGAN WISCONSIN PIPELINE CO. NGPL - NATURAL GAS PIPELINE CO OF AMERICA NNG - NORTHERN NATURAL GAS CO. PEPL - PANHANOLE EASTERN PIPELINE CO. TET - TEXAS EASTERN TRANSMISSION CO. TGPL - TENNESSEE GAS PIPELINE CO 298 FIGURE 35 SOURCES OF CRUDE OIL SUPPLY TO THE GREAT LAKES BASIN »0C - AMOCO OIL CO WLC - ARCO PIPELINE CO I.FLC - LAKEHEAO PIPELINE CO., INC «»H - MARATHON PIPELINE CO. MVPC - MID-VALLEY PIPELINE CO NTC - NATIONAL TRANSIT CO SPLC - SHELL PIPELINE CO TCSP - TEXACO-CITIES SERVICE PIPELINE CO [Source 618] Future long-term supplies of Alaskan oil to the Great Lakes region are presently under consideration. Three major long-term options have emerged for transport of the oil. • Trans-Provincial Pipeline — Alaskan crude transported by tanker from Valdez, Alaska, would be delivered to a new deepwater port at Kitimat, British Columbia. The oil then would be transferred to a 30-inch pipeline and would move 830 miles to Edmonton, Alberta. In Edmonton the oil would move into existing pipelines. The Trans-Provincial Pipeline would utilize the Interpro- vincial/Lakehead Pipeline system presently serving the Great Lakes Region. The proposal is projected for an initial total capacity of 300,000 barrels per day with an eventual capacity of 650,000 barrels per day [490]. • Northern Tier Pipeline — This proposed line would cross the northern tier of states from a deepwater facility in Port Angeles, Washington, to Clear- brook, Minnesota. This 40- to 42-inch line would stretch 1500 miles and connect with Minnesota and Lakehead pipelines in Clearbrook, Minnesota. Initial opera- tional capacity is projected as 600,000 barrels per day with an eventual capacity of 800,000 to 1,200,000 barrels per day [490]. 299 • Williams Pipeline Company — This expansion involves construction of a 500-mile pipeline from Oklahoma to Iowa. The proposed 24-inch line would receive oil from existing pipelines connected to a new deepwater facility in Texas. The Williams line could also connect to a proposed pipeline from Long Beach, Cali- fornia. The new system could provide an additional 350,000 barrels per day of crude oil from Oklahoma to Minneapolis, Minnesota [490]. The availability of oil in the future relies on the rate of new discover- ies and the economic incentives arranged to promote further exploration. Development of coal liquefaction technologies may also affect the supply of liquid fossil fuels. Additional sources of natural gas to the Great Lakes states may also arrive from Alaska. Proven natural gas reserves in the North Slope are estimated at 22.5 trillion cubic feet. The proposed Artie Gas system would transport gas through 5,551 miles of buried pipeline overland from northern Alaska through northern and western Canada to three ultimate destinations within the 48 contiguous United States. One of these destinations would be Delmont, Pennsylvania where an estimated 1.5 billion cfd could be delivered. The other major alternative, the El Paso Alaska system, would move gas south from the Prudhoe Bay area by pipeline to a port on the southern Alaskan coast. There the gas would be converted to liquified natural gas (LNG) and shipped via cryogenic tanker along the northern Pacific coast to a delivery point on the California coast. The LNG would then be regasified and would be distributed through the gas pipeline network. The El Paso Alaska system would provide gas to the Great Lakes Region by rerouting northward the gas previously required on the west coast [257 ] . (2) Great Lakes States Production and Reserves Oil, natural gas and coal are produced in the states bordering the Great Lakes. Peat, a potential fuel found in the Great Lakes Region, is not presently used as a fuel for power production. The four southernmost Great Lakes states, Illinois, Indiana, Ohio and Pennsylvania, yield most of the gas.,, and oil and virtually all the coal produced in the Great Lakes states. A summary of fuel production and reserve capacity by state follows. • Illinois — Illinois has a recoverable reserve of coal greater than the combined reserve of the remaining seven Great Lakes states [19]. Deposits under- lie 65% of the state and are found in 86 of its 102 counties [5]. Illinois holds 300 15.1% of the country's total coal reserves, or 65 billion tons. This plentiful resource, which has a high heating value ranging from 10,500 to 13,000 Btu's per pound, accounts for 16.6% of the nation's potential energy reserve from coal [4]. Illinois coal production, although on the decline, contributed 9.6% of the total U.S coal production in 1974 [327], The state mined 58,215,000 short tons that year compared to an average 64,197,000 tons/year between 1966 and 1970 [585]. The decline in coal production is in many ways symptomatic of the quality of Illinois coal. Much of this coal has a 3 to 5% range in sulfur content, which exceeds the standards set by the Environmental Protection Agency [4]. The Federal Power Commission in 1973 estimated that more than 85% of the coal now being burned by Illinois electric utilities would be prohibited when sulfur emission standards are enforced [3]. This valuable resource therefore grows increasingly impractical for power generation and depends on the development of efficient technology for sulfur removal. Illinois also has substantial reserves of oil and natural gas . Illinois oil production was 26,080,000 bbl of crude in 1975 [319], which was the highest for the eight Great Lakes states. The state had an estimated reserve in 1974 of 162.3 million barrels, which among the Great Lakes states was second only to Michigan [24] . Natural gas production was 2,840 million cubic feet in 1973, with reserves in total gas of 380,525 million cubic feet [586]. Illinois is developing the use of underground caverns for storing liquified petroleum gases. The Illinois Great Lakes Basin counties of Will and Dupage presently store 46,000 bbl of LP gas and 250,000 bbl of propane and butane [3]. Peat, which is not sold as a fuel for power production, is the only fuel mined in the coastal zone [317]. • Indiana — The mineral industry survey for Indiana in 1975 reports that Mineral fuels accounted for about 58% of the estimated value of Indiana's mineral production in 1975, 15% higher than in 19 74. Coal, which alone accounted for nearly half of the total value of all mineral output, increased an estimated 5% in quantity and 19% in value. Output of both petroleum and natural gas declined sharply in 1975, continuing a downward trend which has occurred annually since 1965 [320], In 1975, Indiana produced 24.8 million short tons of bituminous and lignite coal [320]. The state had a demonstrated coal reserve in 1974 of 10.6 billion tons. Sixty-four percent of this reserve has a sulfur content greater than three percent, which makes it environmentally unfavorable. No coal is mined in the Indiana coastal counties. 301 Crude petroleum production in Indiana in 1975 was 4.6 million barrels, a decrease of 287,000 bbl from 1974 production [403]. Reserves of Indiana crude oil were 29.6 million barrels in 1974 [24]. A small amount of the oil produced in 1974 came from the coastal county of LaPorte, which produced 3,389 barrels [321]. Production of natural gas in Indiana has declined also. Production fell from 176 million cubic feet in 1974 to 126 mmcf in 1975 [320] . Though reserves of natural gas are estimated at 5,308 mmcf, 50% of this reserve is in nonproducinj reservoirs [24] . • Michigan — Michigan produced no coal in 1974 [327]. Coal fields are found beneath 20% of the state, but the resource is thinly distributed, yielding an identified coal reserve base of only 119 million tons [19]. Michigan's petroleum production in 1975 increased 6.3 million barrels from the previous year, yielding a total of 24,413,000 bbl [319]. Petroleum was produced in the coastal counties of Allegan, Antrim, Arenac, Bay, Grand Traverse, Huron, Macomb, Mason, Monroe, Muskegon, Oceana, Ottawa, Presque Isle, St. Clair, Tuscola, VanBuren, and Wayne. These counties produced 1,757,000 barrels in 1975, which accounted for about 14% of the total state petroleum production [317]. Michigan's oil reserve of 164.1 million barrels is the largest of the eight Great Lakes states. Natural gas production in Michigan in 1975 was 102 billion cubic feet which was an increase of 32 billion cubic feet over 1974 [75]. Natural gas was produced in the coastal counties of Allegan, Grand Traverse, Macomb, Ottawa, and St. Clair (also natural gas liquids) in 1972 [319]. Michigan exceeded the remaining Great Lakes states in production and reserves of natural gas in 1974. Total reserves were estimated at 1,041 billion cubic feet [24]. Michigan produced 1.1 million barrels of natural gas liquids in 1973. Of this total 65% was liquified petroleum (LP) gas and 35% was natural gasoline. Proved reserves of this resource totaled 25 million barrels in 1973, which was an increase of 6 million barrels over the previous year's estimate [586]. Overall, Michigan is able to produce approximately 10% of its needs for oil and gas, so must still import the majority of its energy [75] . • Minnesota — Minnesota claims 50% of the nation's known supply of peat. Peat, the only potential mineral fuel Minnesota produces, was used primarily for potting purposes [317]. 302 • New York — New York's mineral fuel production is restricted to natural gas and petroleum. Negligible coal resources are estimated to cover 10 square miles of New York's total area of 49,576 square miles [19]. In 1975 New York produced 890,000 barrels of crude petroleum, which was a decrease of 6,000 barrels from 1974 [319]. The state showed crude oil reserves of 6,667 mbbl in 1974 [24]. Chautauqua County was the sole New York Great Lakes coastal county to produce oil. In 1973 this county had 43% (41 wells) of New York's proved oil field wells [586]. Natural gas production in New York was 4.5 million cubic feet in 1973. This represented a 23% increase over production in the previous year [586]. The estimate of natural gas reserves in New York was 87.1 billion cubic feet. The coastal counties of Cayuga, Chautauqua, Erie and Monroe produced natural gas. Erie and Chautauqua Counties had 87% (21 wells) of New York's proved natural gas field wells in 1973 [586]. • Ohio — Ohio coal production in 1974 was 45.4 million short tons, which accounted for 7.5% of the national coal production [327]. In terms of value, bituminous coal is the state's principal mineral commodity, contributing $338.8 million to the economy in 1973 [586]. There was a demonstrated coal reserve in Ohio of 21 billion tons [191 . Of this reserve 60% has sulfur content greater than 3.0% [327]. Most of the future production of coal in Ohio will depend on recovery from underground mines. An estimated 80% of the recoverable coal reserve in Ohio is located in beds suited to underground mining [19]. No coal is extracted in Ohio's coastal counties. Ohio ranked third among the Great Lakes states in oil production. The state produced 11,704,000 barrels of crude petroleum in 1975 which was an increase of 2.6 million barrels over production in 1974 [319]. All coastal counties in Ohio are considered either oil or gas producing counties. In 1975 twenty-five new producing wells were drilled in Ashtabula County. Eight of the wells produced natural gas, two produced oil, and fifteen produced both oil and natural gas. Of the five new wells drilled in Lorain County in 1975, four were dry and one produced gas [325], Total oil reserves within the state amounted to 87.3 million barrels. Total natural gas production in 1974 was 94.3 billion cubic feet [10] with gas reserves totaling 1,238.6 billion cubic feet [24]. • Pennsylvania — Pennsylvania is the largest coal producing state in the Great Lakes Region. In 1974, the state produced 80.5 million short tons of 303 coal, which was 13.3% of the total U.S. production [327], Coal deposits cover 15,000 square miles or approximately one- third of the state. The demonstrated coal reserve base in Pennsylvania is 31.0 billion tons. Approximately 95% of this reserve is recoverable by underground mining methods. Seventy-eight percent of the total underground and surface bituminous coal reserve has a sulfur content less than 3%. Twenty-four percent or 7.3 million tons of the coal has less than 1% sulfur. Anthracite, a high quality coal, is found primarily in Pennsylvania. This high Btu coal has an average sulfur content of 0.75%, which is favorable for compliance with air quality standards [586], Anthracite reserves are smaller and more difficult to recover than bituminous coal. In 1973 anthracite production was 6.8 million short tons or 8.2% of the total coal production in the state. Being higher quality coal, anthracite contributed over 10% of the total value from coal in Pennsylvania that year [586]. Erie County, Pennsylvania's only Great Lakes coastal county, has no reserves of coal. Crude petroleum production in 1975 was 3,910,000 barrels, an increase of 432,000 barrels over 1974 production figures [319]. Proved reserves were estimated at 35.5 million barrels [24]. Erie County had five crude oil wells in 1974, which produced an insignificant 257 barrels [14]. Natural gas production was 82.7 billion cubic feet in 1974, which was a 5% increase over the previous year. Gas reserves were estimated at 878.5 billion cubic feet [24]. Erie County produced 64 mmcf of natural gas in 1974 [14]. • Wisconsin — As of 1976, Wisconsin has no known or projected production or reserves of oil, natural gas or coal. Although producers of coal, oil and natural gas, the Great Lakes states are net importers of energy. The role each state will assume in production of these fuels is contingent upon a multiplicity of factors relating to recovery technologies, costs, availability, demand and fuel quality. Reserves of the mineral fuels available in the Great Lakes states are located primarily in Michigan, Illinois, Pennsylvania and Ohio. Michigan and Ohio hold 70% of the natural gas reserves. This reserve is insignificant relative to gas consumption in the region. The 2,279.8 billion cubic feet of natural gas reserves in Michigan and Ohio would supply about one-tenth of the yearly demand of the Great Lakes states, which in 1972 consumed approximately 22,614 billion cubic feet of gas [618]. The situation is similar for oil. Michigan and Indiana have 67% of the reserves, or 326.5 million barrels of oil. Consumption in 1972 was 1,752 million barrels of oil, which was five times the total reserves of the two states [618]. 304 Therefore, production of oil and natural gas in the Great Lakes states can meet only a minor portion of the demands. Coal, which is the major fuel for the generation of electricity in the basin, remains in extensive reserve in Pennsylvania, Ohio, Indiana and Illinois. Pennsylvania and Illinois hold more than 75% of the demonstrated coal reserve among these four states. The Pennsylvania-Illinois reserve of 96.6 billion tons contributes substantially to the demands in the Great Lakes Region. The future recovery of coal from the Great Lakes states hinges increasingly on the question of sulfur content. Great Lakes coal will retain its traditional share of the market only if the cost of removing sulfur is competitive with the cost of delivering low sulfur western coal to the region. Great Lakes states coal production also faces higher mining costs as 85% of the demonstrated reserve would be recovered from underground mines. The Great Lakes states produce no fuels for nuclear power generation. The states of Wyoming, New Mexico, Texas, and Utah are the principle U.S. producers of uranium, listed in order of quantity produced [586]. Hydroelectric power, which contributes substantially to the generation of electricity, is assumed to remain fairly constant because of the environmental cost of creating reservoirs and because the major sites in proximity to load centers have been developed. (3) Present Fuel Mix The Great Lakes states consume approximately 46% of the Btu's produced by coal for fossil-fuels plants in the country. The eight states also consume 27% and 4%, respectively, of the national supplies of oil and natural gas used for power production [547]. Table 52 describes the relative percentages of coal, oil and natural gas used for steam-electric plants in 1975. This table shows that 82.8 percent of the total Btu's produced by fossil-fuel facilities in the eight states were generated by coal. The fuel mix for New York is a reversal of the mix for the other seven states. In 1975, New York used oil for 77% of its electric generation needs. This percentage does not properly reflect the fuel mix in the New York Great Lakes coastal zone. Coal-fired power plants account for about 70% of the power produced by fossil- fueled plants in the upstate coastal counties of New York [289]. The state figures on fuel mix are generally more representative of the dependence on oil in and around the New York City area. 305 TABLE 52 PRIMARY ENERGY PURCHASE DATA FOR STEAM-ELECTRIC PLANTS DURING THE TWELVE MONTHS OF 1975 PERCENT OF AVERAGE PRICE, STATE TOTAL BTU (BILLIONS) TOTAL BTU q. PER 10 BTU COAL OIL GAS TOTAL COAL OIL GAS COAL OIL GAS ILLINOIS 688,793.7 44,970.2 29,438.0 763,201.9 90.3 5.9 3.9 75.4 153.5 113.1 INDIANA 657,428.4 8,867.3 10,053.2 676,349.0 97.2 1.3 1.5 59.2 214.1 81.7 MICHIGAN 505,464.0 95,488.7 32,820.4 633,773.2 79.8 15.1 5.2 92.3 209.1 127.7 MINNESOTA 157,825.9 4,872.4 15,173.7 177,872.0 88.7 2.7 8.5 62.3 196.0 63.9 NEW YORK 143,624.5 526,724.0 13,146.1 683,494.6 21.0 77.1 1.9 117.7 194.3 .87.4 OHIO 1 ,027,147.5 8,304.9 3,630.5 1,039,082.8 98.9 0.8 0.3 95.2 224.1 122.6 PENNSYLVANIA 864,484.7 79,199.4 11.7 943,695.7 91.6 8.4 0.0 95.5 210.9 146.7 WISCONSIN 245,320.5 2,856.6 13,751.5 261, '928. 5 93.7 1.1 5.3 86.4 189.9 81.5 GREAT LAKES STATES TOTAL 4 ,290,089.3 771,283.4 118,025.0 5,179,397.6 82.8- 14.9 2.3 85.3 196.0 101.9 [Source: "Annual Summary of Cost and Quality of Steam-Electric Plant fuels 1975" Federal Power Commission] The fossil-fuel mix figures for the seven remaining Great Lakes states reliably portray the general situation in the coastal counties. This is especially true in Michigan in which 38 of the 45 fossil-fuel plants are located in the coastal counties. Many of the plants in the Illinois-Indiana coastal zone are designated as coal/gas-fired. The gas used is a relatively small amount however, generally supplying fuel for peaking units or as start-up fuel for the large coal-fired boilers. The percentage of gas used in the coastal counties of this area does not greatly differ from the states' fuel mix consumption figure. An examination of kilowatts produced in the coastal counties of Illinois and Indiana show that approximately 4% of the fossil-fuel electrical generating capacity is provided by natural gas. Therefore a substantially accurate extrapo- lation concerning fuel mix in the coastal counties can be derived from review of the statewide mix. The present fuel mix of the Great Lakes states depends on enormous quantities of coal. Ohio, Pennsylvania, Illinois and Indiana are the four largest coal consuming states for electric generation in the nation [547] . Oil and natural gas are minor sources of fuel in the region. In absolute terms though, the Great Lakes Region provides a substantial market for the national consumption of oil and natural gas. 306 Problems with the availability and price of natural gas make this fuel increasing unreliable as a primary fuel for power generation. Demands for space heating and industrial applications further remove natural gas from consideration as a primary fuel for electric production. Petroleum, another versatile fuel, will most likely continue to decline in importance as a base load fuel for power production. The cost of petroleum is growing increasingly prohibitive, but petroleum still has certain environmental advantages over coal-fired plants and generally requires lower initial capital costs for plant construction. Being more limited in its applications than oil or gas, coal will continue to be the primary fuel for power generation. New technologies which utilize coal (i.e., fluidized bed, liquefaction and gasification, etc.) are aimed at reducing many of the detrimental effects of coal-fired generation. A developing trend suggests that electricity will take up much of the slack left by reduced use of oil and natural gas due to the end use versatility of electricity. However, the continuation of any such trend is very dependent on the progress made in acceptable means of utilizing coal for power production. This issue hinges on the problem of sulfur. Changes in the amount of coal used depend on the development of efficient desulfurization technologies either before or after combustion. Hydro-electric power currently comprises 5% of the region's generating capacity and is not expected to increase to any degree in the future. This type of generation is centered primarily in New York where it meets approximately 24% of the current state power needs [466]. The utilities have planned to increase nuclear capacity rapidly over the next twenty years to the point where it will comprise some 30-35% of the total generating capacity. The continuation of this trend is predicated upon the resolution of many serious problems currently plaguing the nuclear industry. These factors would include the availability of fuel, a reduced construction period, a greater public acceptance, and a solution to the problem of nuclear fuel waste disposal. Some seven or eight nuclear generating facilities in the Great Lakes Region have been hard hit by plant cancellations and deferrals. Those deferrals, combined with the rising costs and long lead times for construc- tion of nuclear facilities, indicate a continued heavy reliance on coal over the next ten years or so. 307 Nuclear facilities have grown rapidly and now contribute 12% of the power generated in the region. The future development of nuclear generating capabilities will depend on the industry's ability to surmount the problems mentioned above. The relative price and availability of the major fuels for electrical power generation will play a major role in determining their future use . TABLE 53 19 75 Fuel Mix by Fuel Type for Fower Generation (percent B.T.U. contributed by State) State Oil Gas Coal Hydro Nuclear Illinois 8% 4% 63% .1% 24% Indiana 3% 2% 93% 1% 0% Michigan 10% 6% 72% 1% 10% Minnesota 3% 12% 63% 2% 19% New York 39% 5% 15% 24% 17% Ohio 4% 2% 94% 0% 0% Penn. 14% 1% 74% 1% 9% Wisconsin 1% 9% 57% 1% 28% Regional Weighted Average 13% 4% 66% 5% 12% Source: FPC, NRC, FEA (4) Cost and Use By State and Region The cost of primary fuels has increased greatly since the early 1970 's. The. most significant price increases have affected users of nuclear fuels and residual oil for power generation. The relatively greater increase in the price of these two fuels compared to coal indicate coal's favorable cost position. However, the costs of transportation and insuring environmentally sound use of coal are expected to rise in the future. For many reasons the price of all primary fuels for power production are expected to rise in the future, with coal prices possibly rising least of all. The price in 1975 for the four primary fuels in the Great Lakes states was: 308 Coal 85C/10 6 Btu Nuclear 55c/10 6 Btu* Oil 196C/10 Btu *Based upon U3O8 at Gas 102C/10 6 Btu twenty dollars/pound. The costs of transportation and extraction will play an increasingly larger role in the future price of electricity. (5) Transport of Fuels for Power Production The movement and distribution patterns of fuels for power production in the Great Lakes Region evolve through complex interactions among the transporta- tion mode, commodity, and the commodity's origin. Fuel movement and routing are subject to constant change. Competition between fuel carriers insures a high degree of flexibility in the transportation pattern. It is through the existence of such a network that fuels used in the Great Lakes Region can originate from such diverse areas of the country as the Louisiana Gulf Coast or the North Slope of Alaska. Historically, coal, oil and natural gas have been transported by rail, waterway, truck or pipeline throughout the Great Lakes states. The railway system is comprised of more than 200,000 miles of track, with the greatest concentration existing in the eastern half of the country. Coal, as a high bulk commodity, is well suited to transport by rail. Railroads haul 78% of the coal and less than 3% of the oil and gas in the country [364]. Recent innovations, particularly the advent of unit trains, have substantially lowered the costs of hauling large volumes of coal. Approximately 20% of all coal mined in the United States presently moves by unit train [147], The unit train "consists of a dedicated set of haulage equipment loaded at one origin, unloaded at one destination each trip, and moving in both directions on a pre- determined schedule. The unit train combines three principle factors: design efficiency, equipment balance, and intensive use. To achieve the lowest possible transportation costs, all elements of the operation must be in balance; the loading, haulage, and unloading facilities must be designed and scheduled for intensive use but not to a degree that would bring intolerable maintenance costs; the haulage capacity must be in balance with supply, with the consumer's needs, and with amortization requirements" [310], 309 -3- m w I Pn H in | § — I 4-1 f -C ro J3 n O O 1-1 H ! X X j «J < • rH 5<« C ri 5-^ n vO CT> c CN -J" rH — 1 rH o CO rH ri CT\ m en >«; rH CM rH CO rH ^ CM u-1 c^ r^ CN u-i en ^? • -cr « u~l rH vO m A CM CO •H .H rH rH CO ^3- vO -3- 3 o CO rH r-l rH o-> o en o o vO CO rH -r-( li- a% vO CO S4 rH CO jr en • 5^ co • o en CM o CO »h rH in • MO cm m CN r-l "^ en C3> rH . en rC CTi O rH -j- CM en CJ ' r~ co fr-3 VO CO 5-« r! CO vO co rH rH o rH s * CN r- rH - m .H <- ^T rH cm m O i-l tO- iH r-l CM ■CO- CM CO CO l c i O rH CO ri CM o ■a cn vO m s-s c 1 in • i-« C7\ • -a- M j CM as • m vO o CO rH vO en r-l o r-l ON CN K rH rH «n en CM CTN rH • ! en C j c m -*C* en in P^ « o n co S cn p- i-i is: r- • rH o CM CO CM en H rH O CM f^- rH , o vO rH •CO- / rH ^ 1 o CO CO CM rH VO rH O >- CM 5 . r-l •> CO B-S O- rH o VO rH CM n in CM O rH 2: CO CM r- rH CM rH 6S >. ec >. c U c •T3 £ T- ^j a 1-1 rH CO CJ W 4. 4J CO jjen t C Oa! CO rH_| > U ■H u a -H r-l o rH C o r-l rO a. 4J CJ o o- 4J >.rH a ,0 01 •o u 0) to d. x p •a u ■^ i- VU M XJ o rH iJ o CJ r" 1 S i-i W vw CO w 'tr -j K c u O p Oj c O r-l>-f a; j-j 0) CD 4J OJ — 1 D. JD m X) c CJ m • X c O eo Ji r-. ci e co U 3 r-» to E CO CD P 0) j_j r-l | C\ > D rH CD H o > J rH CO o o c rH < z a 3m CO rH < Z CXBh CO O H HH iH 1 310 Unit trains in the Great Lakes Region have primarily hauled coal to the consumer directly from the mine. Unit train rates were developed through major long-term contracts for all rail coal movement from mine to consumer. Railroads have been unwilling to offer such rates to ports and terminals. Rail companies would naturally prefer to contract for coal movement to the final destination rather than short-hauling for transshipment to lake carrier. The Lake Carriers Association recently received a favorable ruling concerning the establishment of unit train rates to the Lake Erie ports. Additional litigation on this matter is expected. Unit train transportation is not excluded from all ports on the Great Lakes. Of notable exception is the transshipment facility in Superior, Wisconsin. Unit trains 100 cars in length are loaded in Montana and hauled 800 miles east to deliver 10,000 tons of western coal to the coal transshipment facility at Superior Operations of this sort represent a significant improvement in the historical transportation of coal by rail. Rail transport of coal, traditionally parochial in nature, is expanding to markets well beyond the regions of production. Efficient utilization of rail transportation on this scale relies on rapid turnaround time in loading and un- loading as well as stable and well constructed road beds capable of withstanding the stresses of 10,000-ton unit trains. The shipment of coal by rail accounts for 57% of the total coal movements for electric utilities in the Great Lakes states. The two largest coal consuming states in the country, Ohio and Pennsylvania, move 34% and 36% of their coal for electricity by rail [604]. The rail network, although extensive in these states, competes with the inland movement by barge and truck to utilities. However, it should be stressed that these competing modes of transportation occur largely outside the Great Lakes Basin. Some of the largest coal mines are located near the Monongahela and Ohio Rivers, which assume a large portion of the coal traffic by barge. Economical movement by truck is generally restricted to the regions of coal production located well inland of the coastal counties. There- fore, the rail system, unencumbered by the geographical and economic restraints affecting river or truck transportation, primarily serves the coal demands of the Pennsylvania and Ohio utilities located in the coastal counties along Lake Erie. Illinois and Indiana are also large producers of coal. The percentage of rail transport for electric utilities is considerably greater in these midwestern states than in Ohio and Pennsylvania. Indiana and Illinois move better than two- thirds of the coal used for electric power generation by rail. This traffic 311 supplies fuel for the enormous industrial and residential power demands in the Lake Michigan coastal counties of Illinois and Indiana. More than half of the coal moved by rail for electric utilities is produced within the states' borders. Recently the influx of low sulfur western coal has taken a larger share of the coal movement by rail. Thirty-eight percent of the rail movement to Illinois originated in Montana and approximately 15% of Indiana's coal for electric power generation was produced in Wyoming. As demands for low sulfur coal increase, rail traffic can be expected to realize an even greater share of the coal transporta- tion market in Indiana and Illinois. The four northernmost Great Lakes states of Minnesota, Wisconsin, Michigan and New York are north of the bituminous border that runs through Illinois, Indiana, Ohio and Pennsylvania. The northernmost states must import virtually all their fuel supply for electric power generation. The transportation sector, particularly the railroad industry, benefits from this situation. This is especially true in Minnesota and New York, whose geographic location have historically precluded extensive coal traffic on the Great Lakes. In 1975 over 80% of the coal used by utilities in Minnesota was transported by rail. All but 15% of this coal was mined in Montana. New York similarly received approximately 80% of the coal delivered to utilities by rail. This coal was mined primarily in eastern Pennsylvania and West Virginia. Although the percentages for rail traffic are high in these two states it should be noted that the total tonnage of coal consumed by utilities in New York and Minnesota are the lowest of the Great Lakes states. Combined, these states consume only about 8% of all coal use for electric power production in the Great Lakes states. Michigan and Wisconsin consume more than twice the coal used in New York and Minnesota. Here again rail transporta- tion is the dominant method of coal movement. These states, however, are well suited for coal transport by lake vessel. Consequently, rail shipments to Michigan and Wisconsin constitute a slightly smaller portion of the total coal movement than in Minnesota and New York. In 1975, Wisconsin received 66% of its coal for electric utilities by rail. Most of this coal originated in Illinois and Kentucky. Almost 30% of this fuel was mined in Montana or Wyoming and transported by rail. Eastbound rail movement from Montana and Wyoming can be expected to increase in the near future. Two planned power facilities in Wisconsin's Lake Michigan coastal counties, Edgewater and Prairie View, anticipate delivery of western coal by unit train. Although Michigan has more shoreline than the remaining seven Great Lakes states, rail movement comprised 312 71% of the total coal shipments in 1975. More than 80% of this rail movement originated in Ohio and West Virginia. The dominant position of rail over water transportation in Michigan can be partially attributed to the locations of the major load centers in the southern portion of the state. The growth of unit train movement directly to utilities in the Detroit area has affected the tradi- tional short haul by lake vessel from the coal loading ports on Lake Erie . Railroads, as previously mentioned, prefer to control the commodity's transportation from mine to consumer. They are not, however, interested in totally displacing the coal commerce of the lake carriers. Each major coal shipping port is serviced by a particular rail company which delivers coal to the facility. An extensive rail network supplies the lake ports with coal for transshipment to the waterways. Other rail companies not directly serving the ports may do so indirectly by delivery to a number of inland "turnover points" where coal is transferred to the rail company serving a port for final delivery. The Louisville and Nashville Railroad Company indirectly serves many of the Lake Erie coal ports in this manner. This symbiotic relationship with railroads is necessary for economical coal movement by lake carrier. Michigan and Wisconsin are the only Great Lakes states that receive appreciable tonnages of coal by lake vessel. In 1975, Michigan received 29% of the coal for electric power generation from Great Lakes vessels. Approximately 40% of the lake traffic to Michigan originated in West Virginia and Kentucky and was transshipped via the Lake Erie ports [604] . The coal destined for Wisconsin ports primarily originated in the midwestern coal fields of Illinois, Indiana and Kentucky and moved onto the lakes through the port at South Chicago. This movement of coal has diminished almost by half over the last ten years. Western coal, notably from Montana, is presently taking a larger share of the coal movement on the Great Lakes. Originating from a new transshipment facility in Superior, Wisconsin, western low sulfur coal traffic on the Great Lakes represents a reversal of the traditional patterns of movement by lake carriers. Historically, iron ore and coal have been complementary commodities for dry bulk transportation on the Great Lakes. Vessels hauling iron ore down- bound from Lake Superior to Lake Erie could reload with coal for the return upbound passage. The advent of western coal movement on the lakes complicates this traditional commodity exchange flow. The additional coal traffic from Lake 313 Superior has spurred construction of new bulk cargo vessels. The dimensions of new vessels on the Great Lakes are increasing with the capacity of the locks to accommodate them. The completion of the Poe Lock at Sault Ste. Marie in 19 70 increased the limitations on vessel dimensions to 1,000 feet length and 105 feet beam. This development permits construction of vessels with a carrying capacity over 56,000 tons or approximately twice as much as any prior lakers [251]. Although the number of commercial vessels on the Great Lakes has decreased by one-half since 1960, the increased capacity of vessels presently on the lakes has compensated for this decline so that there is a total decrease in carrying capacity of only 10% [290]. The extension of the shipping season on the Great Lakes may also have a minor impact on the waterborne movement of coal. Coal is generally stockpiled on site in quantities sufficient for the demand over the winter months. The beneficiaries of an extension in the shipping season would most likely be the smaller, older shoreline plants located primarily on the -western shores of Lakes Michigan and Huron. These utilities with smaller storage facilities must presently supplement winter stockpiles with deliveries by rail. With season extension the percentage increase in coal tonnage shipped on the Lakes would be less than 5% [243]. Lake vessels also transport crude petroleum and petroleum products. The development of an extensive pipeline network throughout the region has substan- tially reduced tanker transport of these liquid fuels. Petroleum, a minor fuel commodity for electric power generation in the coastal counties of the Great Lakes, can be expected to continue to decline in movement on the Lakes with additional pipeline construction in the region. The heavy fixed investment and economies of scale are cited as reasons for the favorable share of the market assumed by pipeline transportation [147]. The possible movement of oil onto the lakes by ocean-going tanker is restricted by the limitations of the St. Lawrence Seaway and the connecting channels of the lakes. On a much smaller scale there is barge movement of oil on the lakes for power production. Specifically, the oil-fired energy facilities in Oswego, New York, receive oil by barge. Originating from oil storage facilities in Montreal, barges supplied the Niagara-Mohawk Oswego facilities with approximately 4.5 million barrels in 1975. Coal is also transported by barge. The Common- wealth Edison Company uses barges to deliver four to five million tons of coal per year to electric facilities in and around Chicago. Low sulfur western coal 314 is transported by rail to a transshipment point on the Illinois River near Peoria. Barges move up river delivering 1,250 to 1,450 tons of coal per barge. The Commonwealth Edison Company has long been committed to this method of coal transportation and anticipates continued use of barges for fuel transport. Movement of crude oil by pipeline is routed from Duluth-Superior through Michigan to Sarnia, Ontario, and another line from the same origin runs parallel to the western shore of Lake Michigan around the southern end of the Lake and across Michigan to Sarnia. Additional supplies of crude are delivered from the Gulf region to the major refining facilities along the Illinois and Indiana region of Lake Michigan. Refined products from refineries throughout the Great Lakes states are transported via a major refined products pipeline network concentrated in the major industrial load centers throughout the Great Lakes Region. Pipelines can also carry a coal slurry. Finely pulverized coal can be mixed with water and pumped through a pipeline at about three and one-half miles per hour. At the destination point coal is removed from the water by a filter. A coal slurry pipeline once delivered coal to the Cleveland area. Completed in 1958, operations ceased in 1963 when railroads lowered their rates to compete with the line. Future development of coal slurry pipelines is presently constrained by the inability to acquire legal rights-of-way across private property, particularly railroad property. These pipelines also require consi- derable quantities of water for the slurry mix. Availability of water is a major limiting factor to the development of slurry lines. b. Electricity (1) Power Use of electricity is growing faster than use of any other form of energy in the United States. While the national average growth of energy consumption was 4.8% per year from 1961-1972, the growth in electrical energy consumption grew at an annual average rate of 7.3%, or doubled approximately in 10 years. [576]. A continuation of this rate would require approximately an eight-fold increase in the present generating capacity, transmission capability and fuel requirements by the year 2000. Improved efficiencies would slightly reduce the magnitude of this increase. Though the amount of fuel would necessarily increase proportionately, the mixture of fuel types used for power production has and will continue to change. 22% 18% 44.2% 46% .2% 1% 1.3% 4% 32.3% 31% 315 TABLE 55 U.S. DISTRIBUTION OF ENERGY CONSUMPTION BY FUEL AND BY SECTOR Fuel 1968 1973 Coal Petroleum Nuclear Hydro Natural Gas [576] Broken down further by sector use (1968) Office of the Secretary of Transportation report, relative importance of energy source: Sector Commercial Industrial Transport Residential For the period 1971-1975 annual growth in net electricity produced varied from a high of 8.6% during 1971-1972 to a low of 0.4% for the 1973-1974. The average for the 5-year period was 5.1%, with the growth rate during 1974-1975 being 2.6%. These are national electricity production figures which should not be confused with the increase in installed generating capacity, which (over the 5-year period) increased at an average annual rate of 8.2%. These statistics reflect fairly accurately the conditions of the eight Great Lakes states. Nationwide, the production of electricity accounted for over 25% of the primary energy consumed annually. The electric utility sector's demand for energy is growing faster than that of any other sector, at approximately 8% per year (pre-1973) . Since the Arab oil embargo of 1973, the utility sector's demand for energy has lessened in response decreased consumption of electricity, due to such factors as the increased cost of power and the depressed state of the economy, As will be seen further on in the study, assessing future demand for electricity is a most difficult task. The historical growth rate of approximately 7% is Coal % Gas % 26.8 Pet. 49.2 % Elec. 15.7 % Tota 8.3 100 26.2 43.3 20.9 9.6 100 .1 4.0 95.8 .1 100 50.1 34.8 15.1 100 316 no longer assumed to be the case in the post-1973 world of higher energy prices, capital shortages, conservation measures, and economic misfortunes. The economic growth of an area will often indicate a rapid rise in the demand for electricity. Similarly, the growth in population and its electric energy consumption habits will greatly influence the demand for electric power. TABLE 56 CONTRIBUTION OF EACH FUEL TO THE UTILITY SECTOR U.S. 10 6 kwh prod. Coal Oil Gas Nuc. Hydro . 1960 57.3% 9.5 26.1 - 7.1 1973 1,859,120 45.7% 16.8 18.3 4.5 14.6 1974 1,854,847 44.5% 16.1 17.2 6.0 16.1 1975 1,908,784 44.6% 15.1 15.7 8.7 15.7 Electric use growth rate (1973) Residential 8.2 Commercial 9.6 Industrial 5.8 Transportation Electricity demand by sector (1973) (% used) Residential 32% Commercial 22% Industrial 42% Other uses 4% 317 (2) Population Historically, population has been growing at a rate of 15% per decade, and for the last few years the U.S. population has been growing at an annual rate of just under 2% [U.S. 1975 statistical abstract]. In comparison, the power gener- ating capability in the U.S. since 1955 has been growing at an annual rate of approximately 7%. This indicates to some degree the increasing consumption of energy per capita in the U.S. Tables 57 and 58 indicate the growth in energy consumption that has taken place in the last few decades. TABLE 57 PER CAPITA POWER GENERATION Total Power Year Population (10 6 people) Kilowat t-hours per capita Installed Kw per capita Generated* (10 9 Kw-hr) 1955 164 3853 0.44 633 1960 180 4718 0.53 849 1965 194 5969 0.68 1157. 1970 205 8100 0.93 1660 1975 (est) 221 10450 1.19 2310 1980 (est) 2 31 14000 1.60 3300 [U.S. Statistical Abstract] TABLE 58 TOTAL AND PER CAPITA ENERGY CONSUMPTION 1920 1930 1940 1950 1955 1960 1965 1970 19 74 Total Per Capita 10 12 B.T.U.) (10 6 B.T.U.) 19,782 182 22,288 181 19,107 181 34,153 226 39,956 243 44,816 249 53,969 278 67,143 330 73,121 346 [U.S. Statistical Abstract, 1975] 318 The preceding tables illustrate the growth in energy consumption in the U.S. As population growth begins to level off in the future, demand for energy can be expected to continue increasing, although at a reduced rate. The projected population of the U.S. as of July, 1976, is 211,909,000. At the same time the populations of the states within the Great Lakes Region were : N.Y. 18,111,000 Penn. 11,835,000 Ind. 5,330,000 111. 11,131,000 Ohio 10,737,000 Minn. 3,917,000 Wise. 4,566,000 Mich. 9,098,000 74,725,000 The Great Lakes states contain 35.27% of the total U.S. population. Of the states in the Great Lakes Region, the coastal zones (figures by counties) comprise 26% or 19,415,897 of the total population of the eight Great Lakes states. Table 59 shows the population of the states' coastal zones as of July, 1975. TABLE 59 GREAT LAKES STATES POPULATION BY COASTAL ZONE Number of Counties Coastal Zone Population Total State Population Percent Population in Coastal Zone N.Y. 10 2,696,600 18,111,000 14.89 Penn. 1 273,780 11,835,000 2.31 Ind. 3 749,000 5,330,000 14.03 111. 2 5,765,700 11,131,200 51.8 Ohio 8 2,855,700 10,737,000 26.6 Minn 3 233,500 6.34 Wise. 15 1,928,400 4,566,000 42.23 Mich. 41 4,898,200 9,098,000 53,83 [U.S. Census Bureau] 319 Major changes in the populations of the eight Great Lakes states do not appear likely. What does appear to be happening within the states is the continued growth, in both numbers and density, of the various Standard Metropoli- tan Statistical Areas around the large cities. The growth of these areas has implications for the concentrating of the utility's load centers. This concen- tration of population and load centers around the large metropolitan areas will affect the siting of facilities and the flow of electric power in and out of the Great Lakes coastal zone. (3) Power Flows in the Great Lakes Coastal Counties The relationship of electical power flows moving in and out of the coastal counties is a major consideration in attempting to assess the importance of electric generating facilities in the future. Power flows in and out of the coastal counties are not constant with respect to both direction and amounts. Further, once electricity leaves the generating unit it is virtually impossible to determine its final destination. Electric power flows within the coastal counties of Lake Michigan are easily defined on a large scale. On the simplest level, power generated in rural coastal counties flows inland from the coast, whereas power generated in urban- metropolitan coastal areas is generally consumed within the coastal counties. Beyond these simple observations, electrical energy flows vary according to region and are a function of a particular power pool's varying requirements. The Michigan Electric Power Pool (a combination of Detroit Edison and Consumers Power Co.) regulates electrical flows throughout the state, constantly monitoring loads, costs of power generation, and related factors in the effort * to provide the lowest cost, most efficiently derived electric power. Given that power flows within the state are not the same on any two days, attempts to specify coastal counties' electrical energy flows are impractical. However, what can be determined is the direction of average flows for large cities near the coast. Generally, electric power flows into cities such as Detroit, Chicago, and Cleveland. The Chicago area has more than 5 million people living in its two * Communication, Michigan Electric Power Pool. 320 coastal counties and only four coastal power generating units. The Chicago metropolitan region is the load center for Commonwealth Edison, whose service area extends over most of northern Illinois. For the Chicago region there is a constant need to bring electricity into the coastal counties, predominantly from the south and west. With the difficulty of obtaining sufficient coastal properties within the Commonwealth Edison Service Area and transmission rights- of-way in the metropolitan area, additions to generating capacity which involve new coastal sites would seem unlikely, so there will be a continued reliance on noncoastal zone electric power supplies. The Detroit Edison Company, with a service area of 7,600 square miles, is an example of a utility with its primary load center and a high percentage of generating capacity located in the coastal zone. The generating facilities located within the Detroit metropolitan coastal counties produce power less efficiently than those located on the St. Clair River and Lake Erie, so that on light load days only 10% of Detroit's power is generated within the metropolitan area, the other 90% coming from the north and south. On heavy load days, only 75% of Detroit's power comes from these areas, because the output from the inefficient Detroit plants is increased. The St. Clair River, Detroit River, and Lake Erie generating facilities are largely located in the coastal zone, making intracoastal power flows predominant in the eastern Michigan area. With a service area of 1,700 square miles, Cleveland Electric Illuminat- ing Company has both a very concentrated load center and, by comparison to Detroit Edison and Consolidated Edison, a concentrated service area. The Cleveland municipal plant has the ability to generate 90% of the portion of the needs in its service areas. However, there are three generating facilities that produce with greater efficiency and at lower cost most of the metropolitan area's needs. Cleveland Electric Illuminating Company s generating facilities are closer to its load center than either Detroit Edison or Commonwealth Edison, with the major plants located close to Lake Erie. As with Detroit Edison, the power which Cleveland Electric Illuminating Company generates is consumed within the coastal zone. Communication, Commonwealth Edison. ** Communication, Detroit Edison. *** Communication, Cleveland Electric Illuminating Company. 321 The Milwaukee metropolitan area is the largest consumer served by the Wisconsin Electric Power Company. The area's industrial sector uses approxi- mately two-thirds of the power produced by the utility. This high percentage reflects the heavy industrialization of the Milwaukee area. The electric power is generated on the coast, with much of this within the Milwaukee metropolitan area. The remainder of the Milwaukee base load is generated in the coastal zone north of Milwaukee at the Point Beach plant (this assumes the Oak Creek plant to be in the Milwaukee metropolitan area) . The power flows for Milwaukee are intracoastal. More power is produced within the coastal zone of New York than is consumed locally. The inland location of many New York population centers, combined with the difficulty of siting power facilities in many parts of the state, suggests the reason for intensive energy facility siting in the coastal zone. Generally, power flows from west to east in New York State. Areas such as Oswego are rapidly becoming major energy exporting centers. The number of power plants and transmission facilities existing and being planned suggests the importance of the coastal zone in supplying inland areas with large blocks of power [449]. (For example, utilities such as Long Island Lighting Company and Orange and Rockland Utilities, Inc. are joining in construction of Oswego area power facilities.) The Niagara Falls-Buffalo area produces large amounts of power, but due to heavy industrialization, exports smaller quantities of electri- city to more eastern areas. The variations that have developed in electrical energy produced in the coastal zone and its end use are the result of the needs of the regional power pools, availability of facility sites and transmission line rights-of-way, and location of fuel and water resources. Communication, Wisconsin Electric Power Co. ** Communication, New York Power Pool. 322 3. EXISTING ENERGY SUPPLY FACILITIES a. Electrical Generation (1) Types by State and Region The types of generating facilities in the Great Lakes Region are currently reflected in the region's fuel mix, described in Section IV.B.2. a. (3) . The average capacities of the different types of facilities varies. Modern nuclear facilities average between 900-1000 MW each whereas most coal-fired units are around 600 to 800 MW. The majority of hydroelectric and gas facilities are quite small and are often used for peaking purposes. The locational requirements for the different generating types varies considerably according to fuel types. Hydroelectric facilities have the most obvious restrictions as to where they may site. These restrictions suggest a limited future role for hydroelectric power. The possible exception to this would be a further development of pumped storage facilities, but these also have very stringent locational restrictions. A primary siting consideration for fossil-fuel plants is the location of existing or planned fuel transportation. In the past few years environmental considerations have become a major factor in determining the location of a fossil-fuel generating plant. Air quality regulations are especially pertinent to coal-fired facilities. In addition to environmental and fuel considerations, fossil-fuel plants have and will continue to locate where water is available. The location of nuclear facilities has been dictated by two primary considerations: (1) availability of water, and (2) availability of enough land for the required zone of exclusion. Fuel transportation is not a major considera- tion in the location of nuclear facilities. There does not appear to have been a preference of one fuel type over another in locating in the coastal zone. Recent trends, however, suggest that a higher percentage of nuclear facilities have and will be located in the coastal counties. Future preference for locating in the coastal zone will be dictated by the following considerations: (1) water availability, (2) access to fuel transport routes, (3) environmental quality standards, and (4) land in sufficient quanti- ties for exclusion areas. The following shows a rough breakdown of the quantity of each state's generating capacity. 323 Table 60 POWER GENERATION BY STATE ILLINOIS Elec. produced 94,480 GWh Installed gen. cap. 25,942 MW [F.P.C. News June 4 - 12/31/75] Gen. cap. in C.Z. 3267.25 MW [322] % of total cap. in C.Z. 12.5% Future scheduled or planned gen. cap. 16,880 (planned through 1984) Planned expansion in C.Z. - None WISCONSIN Elec. produced 35,063 GWh Installed gen. cap. 8,881 NRC Gen. cap. in C.Z. 5574.3 MW % of total cap. in C.Z. 59.6% Future scheduled or planned gen. cap. 5333 MW Planned expansion in C.Z. 1,560 MW MICHIGAN Elec. produced 72,074 GWh Installed gen. cap. 18,926 MW Gen. cap. in C.Z. 17229 MW % of total cap. in C.Z. 73% Future scheduled or planned gen. cap. 10232 MW Planned expansion in C.Z. 9557 MW (include D.C. Cook unit 2) OHIO Elec. produced 105,665 GWh Installed gen. cap. 25,225 MW Gen. cap. in C.Z. 5514.4 MW % of total cap. in C.Z. 21% Future scheduled or planned cap. 10,077 MW Planned expansion in C.Z. 5,300 MW INDIANA Elec. produced 65,421 GWh Installed gen. cap. 13,315 MW Total cap. in C.Z. 2,918.956 MW % of total cap. in C.Z. 20.4% Future scheduled or planned gen. cap. 6,516 MW Planned expansion in C.Z. 685 MW (nuclear) (indef .) 324 MINNESOTA Elec. produced 28,289 GWh [F.P.C.] Installed gen. cap. 6,707 MW* Gen. cap in C.Z. 324.329 MW % gen. cap. in C.Z. 5% Future scheduled or planned gen. cap. 2,820 MW Planned expansion in C.Z. - None. PENNSYLVANIA Elec. produced 111,762 GWh Installed gen. cap. 28,770 MW Gen. cap. in C.Z. 118 MW [322] % of total cap. in C.Z. .4% Future scheduled or planned gen. cap. 13,120 MW Planned expansion in C.Z. 800 MW NEW YORK Elec. produced 109,521 GWh Installed gen. cap. 29,500 MW [F.P.C. Jan. 1, 1976] Gen. cap. in C.Z. 7,968 MW % of total cap. in C.Z. 27% Future scheduled or planned gen. cap. 15,829 MW [F.P.C. Jan. 1, 1976] Planned expansion in C.Z. (1100 Nuc) 3,950 MW (2) Electrical Transmission With the development of the electric reliability councils during the mid-1960' s the electrical transmission network within the Great Lakes Region has become increasingly reliable. A primary function of these councils is to promote the comprehensive planning of both generating facilities and transmission net- works. The reliability councils have helped to coordinate overall design of the transmission grid for the purpose of balancing power flows between load centers and the generating units, the sharing of power between utilities, and the overall efficient operation of the region's generating capacity. Further, inter-utility buying and selling of power has been encouraged by the development of a compre- hensive transmission network. One benefit of pooling power is the reduction in generating capacity needed by an individual utility to compensate for emergency generating outages or days of extra heavy load. 325 The development of power pools such as the Michigan Power Pool or CAPCO was predicated upon the ideas of sharing and coordinating resources and providing the least expensive power possible. The practices of the utilities and power pools have become very complex, such that at any given time it is nearly impos- sible to determine the destination of locally generated power. With the develop- ment of inter-utility electric reliability councils and power pools, the siting of new generating units is no longer heavily dependent upon proximity to large load centers. To assure transmission line stability and interregional power reliability, some new generating units may locate outside of the general proximity of large load centers. The development of a comprehensive and efficient transmission network has increased the flexibility in energy facility siting. The D.C. Cook nuclear facility, located in Michigan and owned by the Indiana and Michigan Power Company, is a good example of a generating unit able to locate hundreds of miles from the load areas it serves, due to the availability of an efficient long distance transmission network. Cooling water from Lake Michigan was the primary reason for the selection of the Michigan site, while the EHV (345 and 765 kV) transmis- sion network made it economically feasible to serve the widely dispersed demands of the American Electric Power grid. The bulk transmission system of the region is predominantly comprised of 345 kilovolt (kV) lines. The use of high voltage transmission lines allows large transfers of power at a very high efficiency. The overall efficiency of the electric transmission network is lowered each time the power is stepped down to a lower capacity line, so it is beneficial to transmit power along the higher voltage power lines over long distances. Future transmission network plans call for the development of 765 kV transmission lines which will allow the transfer of more power at a higher efficiency than that of the 345 kV lines. The 765 kV network presently operating in the Great Lakes Region is currently transmitting the power generated at the D.C. Cook facility to the southwestern Ohio region. The trend in transmission lines is towards larger, more efficient lines. A continued emphasis is being placed on reliability and coordination of the entire generating-transmission system. 326 b. Fuel Transshipment and Storage (1) Facility Type and Size Ports on the Great Lakes have shown a pattern of growth and development towards efficient and rapid handling of bulk commodities. Rapid growth in many phases of transportation, particularly those concerned with the handling of bulk commodities, forced the gradual disappearance of the old general cargo facility. Typically located close to the downtown metropolitan area, these ports became obsolete due to increasing demands for extensive land areas, access to major rail facilities, waterfront dockage capable of accommodating larger vessels, and closer proximity to outlying industrial complexes. Bulk cargo terminals are designed specifically to handle materials such as grain, ore, coal and oil efficiently and quickly. Fuels, coal and petroleum products account for a significant portion of the bulk commodity trade on the lakes. (a) Coal In 1974 the 35 million tons of coal shipped on the Great Lakes accounted for about 17% of the total foreign and domestic freight shipped on the lakes. This was the third largest single commodity handled that year. Coal is shipped from three primary regions on the Great Lakes: southern Lake Erie, south Chicago, and Superior, Wisconsin. Together these ports shipped over 95% of the total lake coal traffic in 1975 [290]. The Lake Erie coal ports of Toledo, Sandusky, Lorain, Conneaut, and Ashtabula transship coal originating in West Virginia, Pennsylvania and Ohio. The combined tonnage of coal shipped from these ports was over 33 million tons, or 85% of all coal shipments on the Great Lakes in 1975 [290]. This massive commodity shipment is partially counterbalanced by receipts of iron ore from mines in the upper Great Lakes for use in the iron and steel industries located along the Ohio River and its tributaries. The ports developed as the gateways for coal demanded by northern utilities and industries and iron ore demanded by foundries in Ohio and Pennsylvania. A brief survey of the ports follows. • Toledo — The port of Toledo typically handles more coal traffic than the remaining four major facilities on Lake Erie. Coal shipments in 1975 increased 11% from 1974 to 14.6 million tons [290]. This was a reversal of the previous four-year downward trend. Four of the six coal piers are served by the Chessie System while the Baltimore & Ohio and Penn Central service the remaining piers. 327 The port has no coal storage areas employing direct rail-to-ship transfer. The combined unloading speed for the six piers is 15,900 tons per hour. • Sandusky — This port is served by the Norfolk and Western Railroad. Its unloading equipment can handle 3,500 tons per hour. In 1975 Sandusky shipped 4.3 million tons of coal. This was a slight increase over coal shipments in 1974 but less than the tonnage figures for the 1972 and 1973 shipping seasons . Storage capacity is 910,000 tons. • Lorain — Lorain is the smallest of the Lake Erie coal ports. Served by the Chessie System, the port has lost more than half its coal traffic since 1973. In 1975, Lorain shipped 1,264,954 tons. The port uses very little of the approximately 80 acres available for storage. It can load coal at a speed of 2,700 tons per hour. • A shtabula — Comparable to Sandusky in coal traffic volume, Ashtabula coal shipping was up approximately 400,000 tons over 1974. Penn Central serves this port, which is capable of loading 8,000 tons per hour. Total coal storage capacity is presently 1.4 million tons. • Conneaut — Conneaut ranks second in coal tonnage shipped from Lake Erie ports. Between 1974 and 1975 this port increased tonnage shipped almost 20% to 8.3 million tons. Conneaut has direct rail connections with the Bessemer and Lake Erie Railroad. It can store 4 million tons and has a loading speed of 10,000 tons per hour. Four million tons, or 10% of the total coal shipments on the Great Lakes in 1975 were shipped out of the South Chicago port facility. This facility is the major coal shipment area on Lake Michigan. In 1975, 3,943,165 tons were shipped from this port. The facility is served by the Belt Railway Company of Chicago and is a transshipment point for coal mined in western Kentucky, Indiana and southern and central Illinois. Coal shipments from this facility have steadily declined to essentially half of what they were in 1967. The port can load two vessels simultaneously at a total of 5,000 tons per hour. A new port in Superior, Wisconsin, presently competes with the South Chicago and Lake Erie ports. Superior has become the third major coal shipping port due to the attractiveness of low sulfur western coal. The new Superior Transshipment Terminal presently receives coal from Burlington Northern Railroad unit trains. The unit trains consist of 100 cars each hauling 100 tons. Coal is loaded in Montana and travels 800 miles east to the Superior coal facility. This terminal has the capacity to transship 14 million tons annually. The 328 facility is designed for an eventual expansion to 20 million tons throughout. Coal is unloaded from the train, transported by inclined conveyor to a 1,200 foot long elevated truss which evenly stockpiles the coal beneath it. The storage area has capacity for 7 million tons. Coal is reclaimed by four rotary plow feeders beneath the stockpile which feed the coal to a 96-inch conveyor capable of moving 11,000 tons per hour. This conveyor feeds the shiploader, which is the largest in the world in terms of volume handled per unit time [605]. In 1976 Superior harbor will ship 2.2 million tons. By 1980 it is expected that through- put will increase to 8 million tons. Table 61 shows the tonnage of coal shipped and received at the major Great Lakes ports in 1974. The ports and terminals that receive and store coal are typically comprised of many private facilities designed to accommodate the fuel needs of a specific factory or power plant. For example, the 6.5 million tons received in Detroit in 1974 is the combined total for 23 separate coal facilities reported to exist at the Detroit Harbor. Twelve are situated along the Detroit River; nine are located on the Rouge River and two are on the Short Cut Canal. The combined storage capacity of these facilities is 5 million tons [584]. Table 61 shows that coal received in Chicago does not arrive via the Great Lakes. The waterborne movement of coal to Chicago is handled primarily by barge traffic up the inland waterway system connecting the Great Lakes with the Mississippi River Basin. There are 17 facilities that handle coal in the Port of Chicago. Eleven facilities report a total storage area of 68.7 acres. The remaining six facilities have a combined coal storage capacity of 2,360,000 tons [583]. The existence of the many private coal unloading and storage facilities within a port indicates that industry has found there are positive economic and environmental benefits to the direct control of coal deliveries. Off site un- loading and storage results in increased costs from additional handling to transport the coal to the site of consumption and added environmental impacts. For example, the Upper Peninsula Generating Company in Marquette had no storage facility at the plant site until recently. Coal was held for the company at the Marquette Dock Company, four miles away, and transported by rail to the power plant. The intermediate transportation of coal was costly and restrictive. The company anticipated expansion of generating capacity, so it constructed a new coal facility, located approximately 600 feet from the plant to receive coal directly from self-unloading vessels. The harbor has a storage capacity of 500,000 tons 329 Table 61 MAJOR COAL SHIPPING OR RECEIVING PORTS, 1974 (Thousands of Short Tons) Foreign Domestic Total Overseas Canadian Coastwis a Lakewise Internal U.S. Receiving Ports Port of Detroit 6,571 1 - 6,570 - Port of Chicago 5,024 - - 1 5,023 St. Clair River, Mich. 3,046 - - 3,046 ~ Muskegon, Mich. 1,919 - - 1,919 - Green Bay, Wis. 1,606 - - 1,606 - Marquette, Mich. 909 - - 909 - Duluth-Superior 892 - - 892 - Milwaukee , Wis . 890 20,857 1 890 15,833 - Total 5,023 Percent of Total 100% - - 76% 24% U.S. Shipping Ports 6,719 - 4,699 4,150 2 37 4,186 - 3,017 4,059 60 2,257 2,015 - - 821 12 13 34,682 72 12,934 100% 0.3 37.2 9,821 - 2,020 - 4,113 - 1,169 - 1,742 - 2,015 - 796 - 21,676 62.5% - Toledo, Ohio 12,732 - 2,911 Conneaut, Ohio Port of Chicago Ashtabula, Ohio Sandusky, Ohio Lorain, Ohio Duluth-Superior Total Percent of Total Sources: Waterborne Commerce of the United States, Part 3, Waterways & Harbors, Great Lakes, 1974. and is designed for eventual expansion to accommodate three new generating units in Marquette. This new development is but one of the numerous and highly site- specific coal unloading facilities that exist throughout the Great Lakes system. Greenwood's Guide to Great Lakes Shipping lists 90 such facilities. Storage capacity at these coal unloading docks ranges from 2.5 million to 5 thousand tons. Most of the facilities are owned by electric utilities or steel and cement industries. 330 A fairly recent design feature that has become commonplace among the coal receipt docks is coal delivery from self-unloading vessels. The development of the self-unloading vessel has eliminated the need for much of the expensive unloading equipment that previously dominated coal unloading sites. A self- unloading vessel has hoppers with a V-shaped bottom located in the hold of the ship, which allow the coal to be dumped onto a conveyor belt located in a tunnel at the bottom of the ship. Bucket elevators then life the coal out of the hold to another system of conveyors which swing out from either side of the ship and dump the coal directly onshore. These ships can carry 35,000 tons and unload at a rate of 3,600 tons per hour. Once in storage the coal is then fed mechanically or by bulldozer to a belt conveyor feeding the plant [566]. (b) Oil Oil is another major fuel commodity transported on the lakes. In 1975, shipments of petroleum products totaled 11,545,789 net tons, which is approxi- mately equal to 86,600,000 barrels. This represents a 9% decrease from 1974 and a 23% decrease from shipments in 1973 [290]. The development of pipeline facili- ties around the lakes has accelerated the decline in transport of petroleum products by lake carrier. The network of pipelines and the physical limitations of the Great Lakes-St . Lawrence Seaway System have substantially restricted movement of crude petroleum through the ports. In 1974, less than one percent of the petroleum moved on the lakes was crude petroleum. Refined products, particularly distillate and residual fuel oil and gasoline, are the major liquid fuels carried by lake tankers . Table 62 lists the major shipping and receiving ports for petroleum products. Commodities considered in developing this table were crude petroleum, crude tar, oil, gas products, gasoline, jet fuel, kerosene, distillate fuel oil, residual fuel oil, coke, petroleum coke and liquefied gases. The bulk of products refined in the U.S. destined to be transported by lake vessel originates from the Indiana Harbor area of Lake Michigan. In 1974 Indiana Harbor was the shipping terminal for 77.3% of the gasoline, 81.3% of the jet fuel, 70.4% of the kerosene, 70.6% of the distillate fuel and 40.0% of the residual fuel oil shipped on the Great Lakes [536]. This facility is served by one of the largest refineries on the Great Lakes, Amoco' s whiting refinery, which has a capacity to process 360,000 barrels of crude petroleum per day. There are eight major transshipment facilities located in Indiana Harbor. The 331 433 storage tanks in the harbor have a combined capacity of approximately 15 million barrels [607]. Movement of refined products on the lakes through this facility has remained fairly constant over the last 10 years. Crude petroleum, a minor commodity which was not handled in the harbor in 1974, is primarily refined in the area for shipment as a refined product. The other major petro- leum shipping ports in 1974 were Chicago (10%) and Toledo (12%) , which together with Indiana Harbor (61%) handled over 80% of the petroleum products shipped on the Great Lakes. Table 62 MAJOR PETROLEUM SHIPPING OR RECEIVING PORTS, 1974 (Thousands of Short Tons) Total For. e i g n D o i m e s t i c Overseas Canadian Coastwise Lakewise Internal U.S. Receiving Ports Port of Chicago 3,776 _ 7 _ 682 3,087 Oswego Harbor 721 - 710 - - 11 Indiana Harbor 550 - - - 442 108 Milwaukee Harbor 534 - 6 - 522 6 Port of Detroit 314 - 210 4 100 Total 5,895 - 933 4 1,746 3,212 Percent of Total 100 - 15.8 0.1 29.6 54.5 U.S. Shipping Ports Indiana Harbor 3,325 — — _ 3,325 - Port of Chicago 1,111 - - - 556 555 Toledo Harbor 649 - 7 - 642 - Port of Buffalo 244 - 12 - 227 5 Port of Detroit 201 5,530 _ 3 22 _ 198 4,948 - Total 560 Percent of Total 100 - 0.5 - 89.4 10.1 Source: Waterborne Commerce of the United States, Part 3, Waterways & Harbors, Great Lakes, 1974 332 The Port of Chicago is the major receiving port on the Great Lakes. Eighty percent of the petroleum traffic in this port occurs internally and reflects movement by barge in and around the facilities on the Chicago Sanitary and Ship Canal and Calumet River. In 1974 1.1 million tons of Canadian petroleum products were received by U.S. ports. Most of this was residual fuel oil (913,779 tons). Of that amount 78% was received at Oswego, New York, and 10% was handled in Detroit. (2) Capacity There is a. subtle but important distinction to be made between port capacity and port capability. The distinction reflects the difference between historic performance (capability) and estimated potential performance (capacity) . Capacity is in many respects an unrealistic term when applied to port activities. Though often used, the term is often misunderstood. Capacity implies an upper limit to the quantity of cargo throughput and storage. The nature of port operation tends to preclude such absolute characterization. Port capacity is not a simple function of the loading/unloading speed. The constraints of ship scheduling, rail movements, traffic interruptions and delays each contribute to a port's capacity to handle cargo. Additionally, the activity of a port can be deceptive. Ports are designed to accommodate the reasonable seasonal and inter- mittent peaks in demand. Therefore a certain amount of inactivity is programmed into the function of a port and doesn't necessarily indicate the capacity is in excess of need [251]. Consequently, capacity is a constantly fluctuating value dependent not only on the space and equipment at the port but also on the coordi- nation, availability, and transshipment limitations of the various shipping and receiving modes of transportation. The U.S. National Academy of Science [548] points out: It would be possible, of course, to design a port facility so that its capacity would be fully utilized at all times. Under this situation, variations in demand would have to be accommodated by delaying ships, forcing them to wait at anchorage until vessels that arrived previously had been serviced. Also, cargo awaiting ships would be delayed or would be routed through a competing port. Although this approach to port operations would maximize the cargo handled at a port for a given set of facilities, an economic analysis incorporating both vessel cost and port facility costs would show that such an extreme case of port operations would represent a highly uneconomic use of resources. Conversely, designing a port so that vessels are never forced to wait also represents an uneconomic use of resources. As for any service 333 operation, the least total cost is obtained by minimizing the sum of the costs of service facility construction and operation and the costs of ship and cargo delays. This results in a level of service at which vessels are infrequently forced to wait during peak periods. Determination of such an economic optimum point requires a complex and detailed analysis of each port. While queuing theory and other concepts can be employed for the study of individual facilities or elements in a port, the interconnections among these facilities and elements are so complex that a sophisticated time- oriented simulation procedure may be necessary to determine fully the effects of modifications in facilities or changes in operating costs of physical facilities requires simulations using as inputs varying numbers of berths, entrance channel configurations, storage capacities, and operating policies and procedures. Such analyses to determine the economic balance for a port are, of course, costly and time consuming, especially in the larger and more complex ports. The scope of this study precludes a detailed evaluation of the capacities of the Great Lakes ports insofar as those capacities are determined through the realization of a complex and largely site-specific analysis of the economic and physical parameters of the port. In recognition of the variables associated with port capacity, this study highlights the historic port transshipment capa- bility. The study briefly reviews the peak bulk throughput figures for the major fuel handling regions in the last ten years. A ten year time frame was chosen because it was felt that a decade would provide an adequate range of yearly cargo fluctuations with the least complications in equipment retirement and facility modification. This approach is felt to offer the most reasonable measure of the Great Lakes ports' existing potential for fuel transshipment. The approach is conservative but appears realistic in terms of near future coal and oil movement on the lakes . Coal shipments from the major coal ports of Lake Erie have declined 30% within the last decade. This decline is marked by an overall decrease of 13.9 million tons since 1966. In that year 47.2 million tons of coal were shipped from Lake Erie ports. The year 1966 will serve as the high volume benchmark for total shipments of coal from Lake Erie. Over seventy percent of this total in 1966 originated from the port of Toledo. This port has witnessed a decline of 19.1 million tons of coal shipments since 1966. Toledo has the present capability to more than double its coal throughput. Of the four remaining major coal ports on Lake Erie only Lorain is regarded as presently operating considerably below 334 previous levels of coal throughput. This port has had a nearly threefold decline in coal traffic since 1973. In that year Lorain shipped 3.6 million tons of coal, In 1975 shipments had decreased to approximately 1.3 million tons. This port, which primarily handles coal for electric power generation, plays an increasingly minor role in the total Lake Erie coal traffic, contributing about four percent to the combined coal shipments from Lake Erie in 1975 [290]. The ports of Sandusky, Ashtabula, and Conneaut are presently running either near or above peak levels of the last decade. Sandusky and Ashtabula both presently ship approximately four and one-half million tons of coal and are considered by their respective port officials to be operating comfortably within the port limitations and foresee no major expansions necessary. Conneaut is the only major Lake Erie port presently considering an extensive expansion of facilities and storage. In conclusion, Toledo could presently contribute an additional 20 million tons of coal traffic to the system. Revitalization of smaller facilities such as Lorain with additional growth in throughput from Sandusky, Ashtabula and Conneaut could add substantially to this figure. Thus, in general terms, the ports of Lake Erie are capable of nearly doubling present coal throughput. It should be reemphasized however that such expansion is contingent upon the complex optimi- zation of diverse activities such as coordinating rail-to-ship transfer and, most importantly, upon a return to the high demand for coal originating in the Appalachian fields. Shipments of coal from the South Chicago facility have demonstrated a decline similar in magnitude to the Toledo facility. In 1975 this facility handled less than half the coal it shipped in 1967. Resumption of coal trans- shipment to 1967 levels would result in an additional four million tons of Great Lakes coal traffic. Like Toledo, this area has historically transshipped coal of a relatively high sulfur content. The future revitalization of this port is highly contingent upon the quality of coal originating from this port to the lakes. The new coal shipping facility at Superior, Wisconsin has been in opera- tion only one year, so it is unreasonable to equate historic capability with the capacity limitations of the facility. This coal transshipment facility handles low sulfur western coal from Montana. Reported to be the largest bulk handling facility in terms of cargo handled per unit time, the Superior facility is designed for an eventual transshipment capacity of 20 million tons per year. 335 This facility, in addition to expanded shipments through South Chicago and Toledo, could essentially double the coal traffic tonnage moved on the Great Lakes in 1975. The capabilities of the system for coal movement on the lakes is presently not in excess of need. This assumption is based on a nonspecific demand for coal quality and may vary considerably according to fuel quality. An analysis of the factors affecting this demand is presented in the section on regional scenarios. The capacity of facilities shipping oil on the Great Lakes is of lesser concern in relation to a fuel supply for electric power generation in the region. The development of extensive oil movement by pipeline, combined with a negligible future development of refinery capacity in the area, indicates at best a very conservative rate of growth in shipping of petroleum products. Indiana Harbor, the primary location of petroleum movement on the Great Lakes, reports operation well within historic capabilities and anticipates no major expansions. (3) Demand The pressures placed on the capabilities of ports and terminals is a function of the demand for fuels to be transported by lake vessel. The demand for coal on the Great Lakes is largely generated by utilities, coke and gas companies, and retail dealers. Coal for utility consumption accounted for 51% of the coal traffic on the lakes in 1975. Coke and gas facilities acquired 34%, while 15% of the U.S. coal transshipped through U.S. and Canadian ports was received by retail dealers and other users. Of the Great Lakes states only Michigan, New York, Ohio and Wisconsin were reported to receive bituminous or lignite coal via the Great Lakes in 1975 [604]. Nearly 47% of the present market for U.S. coal transported on the Great Lakes is located in Canada [604]. A number of projections have been developed forecasting the future demand for Great Lakes coal traffic. These projections as analyzed in the Great Lakes Transportation System [147] predict either growth or stabilization to occur on the Great Lakes over the next 40 years. The U.S. Army Corps of Engineers in 1961 projected coal movements on the Great Lakes to increase steadily from 93.4 million tons in 1975 to 148.5 million tons in 2015. These projections were based on a study of the major consumers of coal: electric utilities, steel plants and cement plants. 336 The projections by the Bureau of Mines (1970) assumed a growth rate of Great Lakes coal traffic of 3.1% per year, commensurate with the national energy needs through 1980. Increased development of nuclear power was assumed to reduce this growth rate to 2.5% per year after 1980. This projection predicted that 73 million tons of coal would be shipped on the Great Lakes in 1995. The International Great Lakes Levels Board (IGLLB) extended the Bureau of Mines forecast beyond 1995, projecting stabilization of coal shipments at 74 million tons through the year 2020. This projection was balanced by their high ^nd low forecasts for Great Lakes coal shipping. The high forecast predicted an increase of 73 million tons between 1970 and 1995. Beyond 1995 shipping levels would stabilize at 134 million tons per year through 2020. The low projection assumed a 1.25 percent growth rate until 1995 then leveled off at 43 million tons through 2020. In either case the projections assumed the same ratio of coal production to shipping as postulated by the Bureau of Mines. A recent projection of coal shipments for the Great Lakes Region, published by A. T. Kearney Inc. in 1976 for the U.S. Army Corps of Engineers [243], seems the most likely of the trend projections (Table 63). The Kearney study took a conservative approach in forecasting potential western coal move- ment on the Great Lakes and St. Lawrence Seaway (GL/SLS) . Only the movements currently planned were included in the forecast potential. Additionally the study operated under the assumptions that: • Few, if any, existing facilities would be converted to western coal due to high conversion costs. • Only new facilities that have announced plans for use of western coal would be included in the forecast. • Stack gas scrubbers would be economically efficient and available by 1990. • Current emission standards will remain unchanged throughout the forecast period. • Variances to burn high sulfur coal will be extended until stack gas scrubbing technology becomes available. • Canada will adopt emission standards that will not preclude usage of U.S. eastern coals. • The development of nuclear power generation facilities will be delayed and retarded by environmental, safety and economic factors. 337 • Environmental concerns regarding strip mining will not restrict the growth of coal mine development in the West. The Kearney projection of a 2% average annual increase shows coal move- ment tripling by the year 2040. As the Kearney report points out, U.S. movements assume the largest share of the total growth at 2.1% per year, while Canada initiates domestic movements and shows movement of 12.6 million tons by 2040. This traffic is expected as a result of Canadian western coal movement to the Lake Ontario facilities of Ontario Hydro. TABLE 63 Potential GL/SLS Coal Movements (Mill ions of Tons) United Sta tes Canada United States Base Domestic Domestic to Canada Total 1972 44.1 17.8 61.9 1980 58.3 5.0 22.7 86.0 1990 77.7 6.4 26.8 110.9 2000 94.7 8.0 30.4 133.1 2010 114.9 10.1 34.3 159.3 2020 134.0 11.0 36.5 181.5 2030 156.7 11.7 38.7 207.1 2040 184.2 12.6 41.0 237.8 Source: A. T. Kearney, Inc. Table 64 and Figure 3b, adapted from Schenker [147] and with the addi- tion of the Kearney projection, illustrate the variations among the previously described demand projections of Great Lakes coal movement. The demand for U.S. shipments of liquid fuels on the Great Lakes was, in a projection by Schenker [147], determined to have difficulty competing with pipeline transportation. Pipelines, as a long-term capital investment, maintain a high rate of utilization once constructed. Therefore the continued development of the pipeline network throughout the region was assumed to have a substantial negative impact on the future demand for Great Lakes shipping of liquid fuels. Rail movement, though usually more costly than waterborne movement, is important to high volume consumers such as electric utilities, because of its reliability. 338 TABLE 64 PROJECTIONS OF U.S. GREAT LAKES SHIPMENTS OF COAL (Millions of Short Tons) 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 202^ Corps of Engineers (1) 83.5 93.4 106 (1961) bureau of Mines (2) 53.0 58.0 (1970) 7 114.6 124.9 130.3 135.0 139,6 143.2 143. 62.0 66.0 69.0 73.0 IGLLB -High (1973) (3) 61.0 83.0 62.0 134.0 134.0 74.0 74.0 43.0 81.0 104.5 43.0 43.0 105.1 -Medium (4) 5 3.0 -Low (5) 44.0 Kearney (1976) (*) NOTE: The Kearney projections are for domestic traffic only SOURCE: [147] 300 200 Short Tons (Millions) lOO FIGURE 36 PROJECTIONS OP U. S. GREAT LAKES COAL SHIPMENTS (MILLIONS OF SHORT TONS) 149.2 O 1970 1980 1990 2000 ... i 2010 Year 2020 339 The problems of storing large supplies of liquid fuels combined with the seasonal nature of lake traffic encourages use of pipelines and rail transporta- tion instead of waterborne movement. Schenker [147], in considering expansion of pipeline traffic and conservation efforts, suggests the projection giving slightly more weight to the immediate past is most accurate. TABLE 6b TREND PROJECTIONS OF GREAT LAKES AND ST. LAWRENCE SEAWAY SHIPMENTS OF CRUDE PETROLEUM AND SELECTED PETROLEUM PRODUCTS 1975-1985 (Millions of Short Tons) 1975 1980 1985 Great Lakes Unweighted trend: Weight of immediate past: Slightly Stronger: Strong : Very Strong 14.6 13.8 13.6 13.7 15.0 14.1 13.7 14.0 15.5 14.3 13.9 14.3 St. Lawrence Seaway Unweighted trend: Weight of immediate past Slightly Stronger: Strong: Very Strong 4.5 3.9 4.5 4.6 5.4 4.3 5.3 5.5 6.4 4.7 6.2 6.4 Source [147] 340 (4) Origins and Destinations of Fuels Handled An important adjunct to the increased demand for fuels, particularly coal, is the effect such demand will have on the pattern of waterborne traffic around the lakes. Competition between the various modes of transport, water, rail, pipeline, etc., insures a constant flux in the patterns of movement between origins and destinations. Historically, the bulk of coal movement on the Great Lakes has originated from the ports on Lake Erie. Located in proximity to the major Appalachian coal fields these ports developed as transit points for coal and iron ore movement in the region. Table 66 illustrates the destinations on a regional basis for coal moving through Toledo, Sandusky, Lorain, Ashtabula and Conneaut. TABLE 66 BITUMINOUS COAL SHIPMENTS TO UNITED STATES PORTS FROM LAKE ERIE To U.S. To Lake To To To Lake To Lower To Superior Sault Lake Huron Michigan Rivers Lake Erie Total Toledo 1,370,004 44,442 301,878 1,427,757 7,254,639 823,954 11,222,674 Sandusky 725,539 40,590 100,090 45,857 511,177 78,742 1,502,004 Lorain ... ... 161,507 ... 887,688 215,759 1,264,954 Ashtabula 234,241 ... 192,244 267,976 37,494 ... 731,955 Conneaut 616,644 18,965 109,965 613,214 155,557 ... 1,514,345 Total 1975 2,946,428 103,997 865,693 2,354,804 8,846,555 1,118,455 16,235,932 Percent 1975 8.88 .31 4.06 7.10 26.67 3.37 48.94 Total 1974 2,521,287 232,090 1,210,502 2,568,195 9,576,237 725,396 16,S33,707 Percent 1974 8.46 .78 4.06 8.62 32.14 2.43 56.4D Thru To Canada To Lake To To To Lower To Welland Superior Sault Ls ike Huron Rivers Lake Erie Canal Total Toledo 25,710 1,992,674 41,843 19,135 32,839 1,319,745 3,431,946 Sandusky ... ... ... ... 51,005 2,785,050 2,836,055 Lorain ... — ... ... ... ... ... Ashtabula 78,449 ... — 943,606 943,737 1,887,061 3,852,853 Conneaut ... ... ... 1,937,872 2,781,988 2,098,794 6,81S,654 Total 1975 104,159 1,992,674 41,843 2,900,613 3,809,569 8,090,650 16,939,508 Percent 1975 .31 6.01 .13 8.74 11.48 24.39 51.06 Total 1974 229,145 1,791,127 48,269 3,151,810 1,487,482 6,259,219 12,967,052 Percent 1974 .77 6.01 .16 10.58 4.99 21.00 43.51 SOURCE: Lake Carriers Association. Annual Report : Lake Carrier 's Association. 19 341 The table shows that over half of the coal shipped from these ports is destined for Canada. This trend is most pronounced at the ports of Conneaut and Ashtabula, which ship 82 and 84%, respectively, of their coal to Canadian markets. The cross-lake traffic in coal to Canada primarily supplies steel mills and the power facilities of Ontario Hydro. Traffic to utilities and the steel industry accounted for 95% of the U.S. coal movement on the Great Lakes to Canada [604]. The domestic movement of coal from the Lake Erie ports is dominated by the Port of Toledo. Seventy percent of the Great Lakes coal movement to United States ports originated from this port. Of this traffic over 60% was destined for the steel mills and utilities of southeastern Michigan. The future of this short haul movement from Toledo to the Detroit area is uncertain. Unit train movements from mine directly to the consumer and downbound traffic of western coal from Lake Superior are satisfying a greater percentage of the electrical fuel demands of this region. Movement of coal to Lake Superior from the port of Lake Erie remains a major traffic movement. Nearly 50% of the domestic shipments from Sandusky are destined for ports on Lake Superior. The electric power facilities at Marquette account for the majority of this traffic. While Sandusky supplies coal for Lake Superior ports, over 60% of all coal shipped on the Great Lakes from this port goes to Canada. Lorain, the only major coal handling port on Lake Erie not to export to Canada, shipped primarily to the electric power facilities of the Detroit Edison Company. Regulations on the sulfur content in coal and competition from rail traffic have been instrumental in the decline of Lorain as a major coal facility. The facility at South Chicago on Lake Michigan was the point of origin for approximately four million tons of coal shipped on the Great Lakes. Coal from this port was destined primarily for the Consumers Power units of western Michigan and the facilities of the Wisconsin Electric Power Company. Coal traffic from South Chicago has declined by about one-half over the last decade, largely because of sulfur regulations. The new transshipment facility at Superior, Wisconsin, was designed to benefit from the regulations on coal quality that have plagued many of the other transshipment facilities. Handling low sulfur coal from western states, Superior is the origin for low sulfur coal shipped to the electric power facilities of Detroit Edison. Presently serving only Detroit Edison, extensive expansion to other markets is anticipated. The Superior facility is designed for an eventual capacity of 20 million tons throughput. 342 Electric utilities provide the major demand for coal shipped on the lakes. In 1975 48% of the coal shipped on the Great Lakes was destined for use by utilities. Coke and gas plants consumed 28%, while retail dealers and others consumed the remaining 24% [604]. These destinations were located almost exclusively in either Michigan or Wisconsin. These states purchased 96% of all domestic coal transported by lake for utilities, and Michigan alone was the destination for 91% of the waterborne coal used by coke and gas plants. Petroleum shipments on the lakes originated primarily from the ports of Indiana and Chicago on Lake Michigan's southern shore. These ports accounted for more than 70% of the petroleum products shipped on the Great Lakes. The destination points for lakewise movements of these fuels are scattered throughout the region with virtually every major port receiving and storing liquid fuels. The widespread distribution of receiving terminals through- out the region reflects the flexibility shipping offers over pipelines in smaller scale delivery of this fuel. (5) Planned or Scheduled Facilities Port expansion or new port construction is often the direct consequence of the development of additional energy facilities. Such port development is particularly applicable to the construction of coastal dependent coal-fired electric generating facilities, which historically have relied on waterborne fuel delivery. U.S. Great Lakes coal traffic originates from three major districts: Lake Erie, South Chicago and Superior, Wisconsin. In 1975, the Lake Erie ports of Toledo, Ashtabula, Conneaut, Lorain and Sandusky shipped 33.2 million tons of coal, or 85% of the coal traffic on the lakes. Within the last ten years coal shipments from these ports have declined 28%, a decrease of 12.7 million tons since 1965. Consequently, most of the ports in this region operate at levels well below their previous capabilities. The only major Lake Erie coal harbor presently contemplating extensive expansion is Conneaut. Conneaut, presently storing four million tons and shipping approximately eight million tons, antici- pates a substantial increase in coal traffic. The proposed expansion will provide substantially more storage space and will include a conveyor belt system, travelling stacker, and bucket wheel reclaimer. Much of the expansion is projected for Canadian use, particularly by the Ontario Hydro utility facilities. Eighty percent of all coal shipments from 343 Conneaut are presently destined for Canada. The expansion may double storage capacity to 8 million and increase throughput to 13 million tons. Barring delays in permit approval and construction, expansion completion is set for the spring of 1978. The ports of Sandusky, Toledo, Ashtabula and Lorain anticipate no near term major expansions. Officials at these ports feel the facilities can accommodate the expected increases in coal traffic. The South Chicago harbor on Lake Michigan shipped eight million tons of coal in 1967. In 1975 this facility found market for about four million tons of coal. There are no plans to expand. Much of the coal moving through this port originates from the midwestern coal fields in Illinois. The high sulfur content of this coal has accelerated the decline in volume transshipped from this port. A minor quantity of western coal has moved through the Chicago port and could contribute to future redevelopment of capacity capabilities. The third major coal shipping region is located in Superior, Wisconsin. This single facility completed in 1976 will have an eventual capacity to trans- ship 20 million tons. Coal shipments have risen sharply in Lake Superior. In 1973, 130,592 tons of coal were shipped from Lake Superior ports. Completion of the facility in Superior, Wisconsin in 1976 will add 2.2 million tons to the total coal shipments from Lake Superior ports. The facility was developed in response to the demand from the Detroit Edison Company for low sulfur coal. This utility contracted for 180 million tons of low sulfur western coal from the Decker mine in Montana. This contract for western coal extends over a 26-year period and was projected for use by Edison's St. Clair and Belle River power plants. However, construction plans for the Belle River plant have been delayed due to financial difficulties, and Detroit Edison is in the process of analyzing alternatives for the consumption of coal originally designated for Belle River. A development similar to the Superior facility is being constructed at Thunder Bay, Ontario, on Lake Superior. Low sulfur coal originating from mines in Alberta, Saskatchewan and British Columbia will be delivered by Canadian National and Canadian Pacific unit trains. Scheduled to begin operation at the start of the 1977 shipping season, this facility is expected to initially ship 3 million tons of coal per year. These shipments are destined for Canadian markets in Ontario and eastern Canada and may compete with future coal shipments originating from the U.S. ports on southern Lake Erie [147]. 344 A major expansion in demand for coal receipts from Superior, Wisconsin, may occur near Buffalo. The Niagara-Mohawk Power Corporation is planning two 850 MW coal-fired plants near Dunkirk, New York, on Lake Erie for 1985 and 1987. Low sulfur western coal is anticipated for use as the fuel source. Operation of the two Lake Erie power plants will require approximately six million tons per year. Niagara-Mohawk was faced with two major options for transshipment of their western coal to the plants at Dunkirk. They could either have coal delivered to Buffalo and then transport it by unit train or barge approximately 50 miles to Dunkirk, or develop a separate transshipment facility at Dunkirk. Were coal delivered directly to Buffalo high costs would be incurred both in the develop- ment of a large coal facility at the port and in transportation rates by short haul unit train or barge to Dunkirk. Development of a new deepwater harbor at Dunkirk also appeared prohibitive in that the lake bottom in that area is essentially bedrock. The utility is presently developing plans for an offshore unloading facility at a site in Lake Erie approximately eight miles west of Dunkirk Harbor. This structure would consist of a number of concrete bresting and mooring dolphins, one of which is designed with an open shaft to accept coal from the self-unloading coal vessels. The coal will drop down the shaft to a conveyor tunnel approximately 23 feet in diameter running beneath the lake bottom. The tunnel would emerge onshore for reclamation and distribution by conveyor to the plant. The tunnel will also house a water pipeline to supply makeup water for the plant. Total cost for the unloading facility and tunnel conveyor is estimated at about $60 million. Such a facility represents a unique approach to traditional coal trans- shipment design. Projecting the development of future facilities of this kind at other Great Lakes sites is difficult as this facility may be the direct result of the geological characteristics that hamper economical dredging activity at Dunkirk. The Dunkirk plans represent a major addition in coal transshipment facilities for power production in the Great Lakes through 1985. Table 6 7 outlines the expected fuel origin, type, and method of movement for scheduled fossil-fuel power facilities greater than 300 MWe in the Great Lakes coastal counties through 1985. 345 TABLE 67 FUEL TYPE, ORIGIN AND TRANSPORTATION FOR FOSSIL-FUEL FACILITIES SCHEDULED THROUGH 1985 LIKELY FUEL GENERAL TRANSPORT PLANT NAME UTILITY LOCATION FUEL TYPE FUEL ORIGIN METHOD Edgewater Wisconsin Sheboygan, Coal Western Unit Train Power & WI fields Light Prairie View Wisconsin Kenosha, Coal Western Unit Train Power & WI fields Light Campbell 3 Consumers Holland, Coal Eastern Unit Train Power MI fields Karn 4 Consumers Bay City, Oil Sarnia, Train-Sarnia Power MI Canada and Lakehead pipeline Pipeline - Superior ,WI Belle River Detroit St. Clair, Coal Western Lake Vessel Edison MI fields Greenwood Detroit Port Huron, Oil Sarnia, Barge to Edison MI Ontario Pipeline Dunkirk Niagara- Dunkirk, Coal Western Lake Vessel Mohawk NY fields Oswego #6 Niagara- Oswego, Oil South Ocean Tanker Mohawk NY America to Barge The information in Table 6 7 was gathered from each utility and is presented as their current estimate for fuel supply. Certain entries are, of course, more definite than others. The Edgewater and Prairie View plants in Wisconsin each anticipate utilization of western coal. Their geographic loca- tions allow fairly direct access from eastbound unit trains. The Edgewater site could conceivably receive coal by lake carrier through Sheboygan, but the officials at Wisconsin Power and Light presently favor direct unit train transportation. The Consumers Power Company is investigating use of low sulfur eastern coal delivered by unit trains for their Campbell #3 unit on Lake Michigan This utility anticipates that the low sulfur eastern coal will have better heat value, be a more reliable supply, and have lower transportation costs than western coal. 346 Three of the eight new facilities listed in Table 67 are designed to burn oil for power production. Both the Karn and Greenwood units are to receive their oil fuel supply from Sarnia, Ontario. Each utility assumes a different approach to the transportation of this fuel. Detroit Edison's Greenwood facility plans to transship fuel oil by barge from Sarnia across the St. Clair River. Once across the river the oil would then be pumped into a pipeline that runs approximately 15 miles inland to the Greenwood plant. The Karn unit near Bay City also plans to receive oil from Sarnia. However, they intend to receive fuel delivered by train. Additional oil from the Lakehead pipeline will supplement the fuel deliveries from Sarnia. Karn units #3 and //4 combined will consume approximately 30,000 barrels per day. Seventy- five percent of the fuel supply to these units will be delivered by train while the balance will be supplied by pipeline. It is expected that fuel for the Oswego #6 unit will be delivered by the same barge system that presently serves the existing Oswego oil-fired units. No major expansions are planned for fuel transshipment. Presently oil from South America moves by tanker to refineries in the Caribbean. The refined product is shipped northward into the St. Lawrence Seaway for delivery to storage facilities in Montreal. Oil is transferred to barges in Montreal for delivery in Oswego. c. Refineries The total refinery capacity in the eight Great Lakes states is 3,513,380 ■k barrels of crude per day (calendar day figures are refiners averages for the number of barrels per day a refinery yields on the average) . Of this refining capacity 1,045,185 bbl/day or 30% is located in the coastal zone. All eight states have some refining capacity, with Minnesota, Pennsylvania and Illinois having no capacity located within their coastal zone . With respect to the relative numbers of barrels refined within each state the breakdown is shown in Table 68. Current refinery construction in the Great Lakes states is presently restricted to expansion of existing facilities. These expansions amount to only 95,440 bbl/day (includes coking operations) of which only 2,400 bbl (Sun Oil Co., Toledo, Ohio) are in the coastal zone area. from Oil and Gas Journal, April, 1976 347 TABLE 68 BARRELS OF CRUDE OIL REFINED IN EACH GREAT LAKES STATE Total Total bbl/day Capacity bbl/day Capacity Percent In (State) (Coastal Zone) Coastal Zone ISJew York 111,385 111,385 100% Pennsylvania 757,020 Indiana 561,160 486,000 87% Illinois 1,176,800 Michigan 147,200 65,000 44% Minnesota 216,800 Ohio 589,770 337,400 57% Wisconsin 45,400 45,400 1 nc\ a / X \J KJ /o Great Lakes Total 3,513,380 1,045,185 30% U.S. Total 15,074,845 bbl/cL? i y Greet Lakes total as :; of U.S. Total 23% Grer.-t Lakes Coastal Zone as % of U.S. 7% total Source: Oil and Gas Journal, April, 1976 Texaco 's Lockport, Illinois, plant has announced a planned expansion of 3 input capacity of 25 x 10 bbl/day with an uncertain operational start date. The Cirillo Brothers of Albany, New York have announced a new refinery of 20,000 bbl/day input capacity of uncertain operational date and product output. The largest new facility to be announced in the coastal zone is New England Petroleum's Oswego, New York, refinery of an expected 200,000 bbl/day input capacity. Again, no operational date or product output ahs been announced for this proposed plant. High costs of refinery construction combined with uncertainty about long-range government energy policy has led to the smallest increase in U.S. refinery capacity (1975 - 146,000 bbl/day) since 1965. Further, this increase was approximately 240,000 bbl/day less than had been forecast. Nationwide, the 348 expansion of existing facilities accounted for most of the U.S. increase in refinery capacity. Each refinery is a specially designed unit with the specifications and requirements of the facility being very dependent upon the type of crude and the products to be refined. Therefore, generalizations about refineries are often inaccurate outside the context of site, product and process specificity. Allow- ing for such, the following "rule -of- thumb" guidelines for refineries have been suggested. There are three main determinants of refinery siting: (1) proximity to major product market area, (2) relative proximity to sources of crude, and (3) availability and costs of various modes of transport. This last is a major reason for refineries' preference for coastal siting. Between 200 and 1,000 acres are needed for 100,000 bbl/day refinery complexes, with the lower limit representing a simple fuels refinery with a 40-day storage capacity and the upper limit a complex fuels-petrochemical refinery with a 120-day storage capacity. This large difference in land requirements (with land generally being 5-10% of total refinery cost) represents the large variations in the complexity of refineries as well as the different storage capacity requirements at specific refineries. Almost all refineries have minimum storage facilities sufficient for a 30-day supply of crude oil plus additional capacity for mixing and storage of refined products (i.e., heating oil in summer or gasoline if delivery of crude is erratic) . Refineries which are tanker- fed (necessarily coastal dependent) require more storage area due to the non- continuous nature of the tanker delivery system. This last factor tends to be of smaller concern to Great Lakes refineries as they are predominantly pipeline supplied. A 200,000 bbl/day refinery capacity is considered an optimal size. Such a size is needed to introduce the economies of scale necessary to offset high construction costs of new facilities so that they can be competitive with old plants. These sizes are also necessary to keep operating costs to a minimum. A few years ago, a rule-of -thumb cost for refineries ran approximately $1500/bbl/day capacity. Now a more realistic figure would be $3,500 to $4,000/ bbl/day capacity, with some plants going as high as $6,500 to 7 ,000/bbl/day capacity. Communication, National Petroleum Refiners' Association, 349 For the past few years, the national trend has been to build new refineries outside the continental U.S., particularly in the Caribbean, to take advantage of lower total taxes, less strict environmental controls, deepwater ports and competitive transport costs. However, this trend is being reversed (balanced expansion) somewhat by high tarrifs on imported refined products and low domestic crude prices, along with considerations for national defense policy. The probable increase of national refining capacity coupled with refineries' desire for close proximity to transport facilities and areas of demand may indicate a renewed interest in the Great Lakes coastal zone for siting refinery complexes . The two major obstacles to new refinery development are high construction costs and environmental considerations. Of the latter, by far the greatest concern to refineries is oxidant level requirements set by the Environmental Protection Agency. According to the refining industry, the low levels allowed by EPA virtually preclude new refinery construction in already developed areas, precisely where the refining industry wants to be. The major source of this problem is the emission of hydrocarbons (a 100,000 bbl/day refinery with 30-day capacity may emit as much as 10,000 lbs /day, even with advanced containment technologies), with most hydrocarbons released during storage and tank filling. Other pollutants associated with petroleum refining are particulates, sulfur oxides, aldehydes, ammonia, and hydrogen sulfide. Water use is being minimized (H20/bbl capacity) by using water recirculating cooling systems. New refinery construction is depending more on air cooling, resulting in a lessened dependency on large water resources. Further, better water treatment is being utilized, which further reduces water consumption (by increasing usable life span of water) and thus the coastal dependency of facilities. New refineries are most dependent on environmental and economic consider- ations, many of which are not easily controllable by the individual states. With the problems of capital formation and air/environmental quality requirements, the development of refineries in the Great Lakes Region would seem slim. A further factor which dictates against Great Lakes Region siting of refineries is the relatively lower cost of refining mideastern and most domestic crude oil in the Communication, National Petroleum Refiners' Association, 350 Gulf Coast states [370]. Refinery economics are such that in most instances, it is less expensive to pipe refined products to the Great Lakes Region, than it is to refine the crude locally. These three major factors would seem to dictate against any large expansion of refinery capacity. One factor which might influence further refinery development in the Great Lakes Region would be the piping of Alaskan crude through the region. The proposed Trans-Provincial or Northern Tier pipelines could potentially bring between 700,000 to 1,000,000 bbl of oil daily into Minnesota. Such a development might necessitate the building of two or three new refineries, but would not significantly influence the coastal zone. 4. PLANNED OR SCHEDULED FACILITIES FOR ELECTRICAL GENERATION a. Types and Location by State and Region Future electric power generation in the eight Great Lakes states will be very dependent upon coastal zone facilities. Of the eight Great Lakes states, Illinois, Minnesota and Pennsylvania currently have no confirmed plans through 1985 for new generating capacity within their coastal zones. A single 800 MW coal-fired plant has been discussed for the Pennsylvania coastal zone around 1990, with the utility's land holdings at the projected site being sufficient for an additional unit. The western portion of Erie County, Pennsylvania, is largely undeveloped, with a large percentage of the land held by Penn Electric, United States Steel, and the Boy Scouts. Hence, the potential for facility development in Pennsylvania still exists. Illinois also has a relatively small coastal zone, but one of the most highly developed in the Great Lakes states. The potential for future expan- sion is seen to be limited due to the difficulty of obtaining sufficient acreage for energy facility development [568]. The pressures on the coastal zone area for uses other than energy facility siting are such that no major facilities are currently being considered. Access to the coastal zone water resources and fuel transshipment facilities for inland generating sites will most probably comprise the major use of the Illinois coastal counties for electric generation purposes. The utilities within the State of Illinois have currently planned eight coal- fired facilities, five oil-fired and eight nuclear-powered generating units, totaling 11,370 MW by 1984. This schedule reflects Illinois' continuing develop- ment of a high nuclear generating capability. 351 The Minnesota utilities currently have no announced plans for generating facilities in their coastal counties. With respect to future development the Minnesota Energy Agency suggests that: "Water availability, population density and location to relative load centers would all seem to point toward increasing pressure on the coastal zone area especially if demand grows as rapidly as the utilities project." Statewide, Minnesota currently has five coal-fired generating facilities scheduled to come on line by 1984. No oil or nuclear facilities have been announced for the state. The curtailment of Canadian oil will probably further the development of coal-fired facilities. One event which may alter Minnesota's energy future is the transporting of Alaskan crude oil through the state via the proposed Northern Tier pipeline or the Trans-Provincial pipeline. Such a circumstance might alter the future fuel mix for electric power generation or reduce the substitution of electricity for other energy sources, thus reducing projected demand for electric power. Indiana currently has one scheduled facility in its coastal zone, the 645 MW Bailly nuclear facility. The coastal zone of Indiana is fairly industrial- ized, with 22 miles of the 45 mile coastal zone industrially developed and 17 miles devoted to public recreation lands [436]. Future development in this area may be restricted by air or water quality regulations. As with Illinois, Indiana may only be able to utilize the waters of the coastal zone for inland energy facility sites. The Indiana utilities have currently planned 10 coal-fired and 3 nuclear powered generating facilities, totaling 9,220 MW by 1984 (this includes the one coastal zone facility) . Wisconsin has seven coal-fired facilities scheduled, three of which will be in the coastal counties. With 140 miles of their 619 mile coastal zone currently agricultural or undeveloped, the potential for new generating facilities in the coastal zone is large [436]. The two Koshkonong nuclear 900 MW units scheduled for 1983 and 1984 have been deferred until 1986. Similarly, the Tyrone nuclear station has been deferred indefinitely. The coastal zone resources of Wisconsin, as in many states, will be in greater demand in the future due to limited availability of inland water in quantities sufficient for a modern generating station. The Pleasant Prairie plant is an example of a station that will site near existing transmission and fuel transportation systems but close enough to the coastal zone for economical utilization of lake water. For many * Communication from R. D. Visness, Minnesota Energy Agency 352 future facility sitings the access to coastal zone water resources will be of high importance. The availability of western coal combined with the deferment of nuclear facilities will emphasize the use of coal in the near future. The States of Michigan, New York and Ohio have the most ambitious plans for developing energy facilities in their coastal zone. This reflects their rela- tively longer coastal zones, the lack of adequate inland sites, proximity of the coastal zone to load centers, and the generally higher energy demand in these three states. All planned facilities in Michigan (with the exception of the Midland plants) are scheduled for the coastal zone (as defined by the first tier of counties and a use or impact of /on coastal zone resources) . Of these facilities four are coal-fired, two oil-fired and five nuclear-fired, totaling 10,550 MW by 1984. Nuclear generating capacity comprises almost 50% of planned capacity, with the oil and coal being respectively 16% and 33% of the scheduled generating capacity. This scheduled fuel mixture represents an increased emphasis on nuclear generating capability in Ohio and New York, similar to what has been found in Illinois. Within Michigan a number of nuclear facilities have been delayed or cancelled for such reasons as lack of capital, equipment delivery delays, inflation, questions over fuel availability and safety, etc. Nuclear generating facilities have been hardest hit by delays and cancellations. The problems currently faced by the Michigan utilities apply to all types of electric generating plants as well as to utilities in the other states. The current decline in electric energy demand coupled with high reserve margins and lack of utility capital have been the main reasons for the delay in Michigan's scheduled generating capacity additions. These problems notwithstanding, the coastal counties of Michigan have the most ambitious energy facility development plan of any Great Lakes state. The justification for siting in the Michigan coastal zone, ease of fuel transportation, proximity to load centers, relative availability of coastal land, sufficient quantities of water and the design of the power grid, will continue to be the reasons for power plant siting there. Currently, the utilities plan to continue construction of coal-fired plants for the mid-term, hoping that nuclear generating capacity can be added soon to prevent future electric power shortages. The Ohio utilities are also planning a large nuclear power generation development program. All plants scheduled for the Ohio coastal zone through 1985 are nuclear facilities. Currently, only one nuclear facility is being planned 353 outside of the coastal zone, with the remaining scheduled capacity for the state consisting of eight coal-fired plants totaling 3,815 MW. The pressure on the Ohio coastal zone for energy facility siting is expected to continue to grow. The demand on the coastal zone will be for both siting and water resource access. The Ohio utilities face many of the same problems as the other Great Lakes states' utilities with respect to construction delays, capital shortages and siting problems. The intensive development of nuclear power in the Ohio coastal zone indicates a shift in the fuel mix of the state from almost total coal-fired base load generation toward a more balanced nuclear-coal mix. The New York state fuel mix for electric generation deviates from the seven other Great Lakes states through its heavy reliance on oil- and gas-fired generation. The scheduled changes in capacity indicate a lessening dependence on oil and a relatively large increase in nuclear generating capacity. Statewide, seven nuclear, four coal- and three oil-fired plants have been scheduled through 1984, totaling approximately 12,000 MW [303], Of these facilities four have been located in Great Lakes coastal counties: two nuclear facilities, one coal-fired facility and one oil-fired facility. Of New York's 292-mile Great Lakes shore- line, approximately 134 miles of this is agricultural or undeveloped [436]. Due to the problems of siting and water availability within the state, the pressure for energy facility siting in the coastal zone will increase. As indicated earlier the power flows in New York are generally east and south, with areas such as Oswego becoming major exporters of electric power. The role of nuclear generating capacity can be clearly seen as expanding. The future role of coal is projected to increase slightly statewide, while the use of oil is projected to decline in relative terms. On a regional basis more nuclear generating facilities have been scheduled than either oil or coal facilities. However, the number of delays and cancellations announced during 1974-1975 reduce significantly the amount of nuclear capacity that will come on line during the next ten years. This gap in generating capabilities will more than likely be made up by fossil fuel-fired plants (predominantly coal), giving the utilities time to see how post-1973 growth patterns develop with respect to both demand and fuel type. During the mid-1980' s the utilities' on line capacity will increasingly reflect their effort to cope with foreseeable fuel, legal and environmental restraints. 354 TABLE 69 CHANGES IN NUCLEAR UNIT SCHEDULES DURING 1972-1975 (All changes listed involved change in the year of commercial operation.) During No. of units Plant yr No. to No. Year changed added indefinite cancelled 1972 54 72 3 1973 52 67 1974 104 201 16 9 1975 102 116 (-1) 12 Data taken for the most part from ERDA tabulations of industry information. Nearly as many units were changed in 1975 as in 1974, but the total impact was lower in some respects. It is noteworthy that 34 new unit orders were entered in 1974 while 9 were cancelled. In 1975, only 4 new orders were entered while 12 were cancelled. The 1974 changes (104) affected 56% of all nuclear units on order or under construction through 1974. The 1975 changes (102) affected 59% of the units remaining on order or under construction through 1975. Power Engineering/April, 1976. b. Estimated Capacity and Projected Demand The ability of an electric company to meet a future electric power demand level is dependent upon many factors, most of which are not controlled by the utility. Availability of electric power in the future depends on present planning and construction based upon future estimates of demand. This current planning and construction for future needs is very sensitive to long-range fore- casts, capital availability, assessments of fuel availability and a host of other factors which since 1973 have become difficult problems for the utilities. The first problem faced by the utilities is what will the future demand for electricity be? Historically, demand has grown 7% annually, but during 1974 the growth rate was near zero. Current best estimates assume 5.5% growth rate in demand, tapering off somewhat after 1985 [344]. Some utilities, however, feel that demand may once again return to historical rates. Whatever the future demand may be there is an inherent difficulty in planning and constructing for unknown future demand levels in the context of the present uncertain consumption patterns. In addition to uncertain demand levels, current low load factors and high reserve levels further confound the future energy demand picture. Over the last few years total electricity demand has grown less than peak demand, resulting in lower load factors [364]. A shift towards increased peak demand in the utilities' load schedule has required a large increase in peak load generating 355 capabilities and produced a large reserve capacity. This accentuation of the peaks in the load schedule necessitates the construction of capacity to meet small peak load periods (Figure 37). Figure 37 WEEKLY LOAD CURVE 100 90 80 70 60 50 40 30 20 10 INTERMEDIATE m- WwWfflvKwly SUNDAY MONDAY £*V.ViliV.V.VA'.Y. , .'.'.VA'AV/AV/ .*.*.'. *. • t T .* J . , J .*^'. , . *.'.>'.'.VW*, TUESDAY WEDNESDAY THURSDAY SATURDAY An increase of 10% in the load factor (e.g., from 50% to 66%) would result in a 10% reduction of total capacity, and about 40% less peaking capacity [344; p. 440]. To bring about increased load factors and reduced peaking capacity requirements, peak load pricing has been suggested. Peak load pricing will result in redistribution of costs to various end users, but its aggregate effects on electrical energy demand and in fact its very workability are less certain [344]. 356 The Federal Power Commission has suggested some reasons for the problems in utility planning: Rapid increases in energy prices, the downturn in economic activity, the sluggish growth of electricity demand following the Arab oil embargo, curtailments of natural gas service to industrial customers and embargoes on new gas hookups, and the talk of moving toward oil import independence in part through increased reliance upon nuclear and coal-fired electricity generation have created a good deal of uncertainty about the growth of future loads. Will the "pause" of 1974 be matched by a "spurt" at some later point in time? Will recent historical growth rates reemerge, but from a lower-than- anticipated base? Or will growth rates continue to be lower than in the past? Utilities are finding it necessary to adapt their methods of planning for system expansion to include the effects of consider- ably more uncertainty in load growth than heretofore [534] . Besides uncertain load growth factors the utilities are facing difficult problems in assessing the future availability of primary fuels for electric power generation. The utilities' low priority in the FPC's natural gas allocation program and the nation's desire to reduce the dependence on foreign oil suggest the limited future use of these two fuels for base load units [534] . However, the cost and difficulty of switching operating units using oil and gas to coal- fired units indicate that there will be a continuing demand for these fuels by the utility sector. Many utilities, having accepted the limited future of using oil and gas for base load generation, are confronted by a number of constraints which until resolved serve to increase the uncertainty of future power avail- ability. Assuming that coal and uranium are the only fuels readily available for large scale power generation, some of the restrictions faced by the utilities may be: a lack of a firm commitment by the government to the use of coal and/or uranium, delays in developing new coal mining capability, especially of western low-sulfur coal, doubts about the adequacy of coal transport facilities, contro- versies over clean air regulations, uncertainties surrounding the mining and milling of uranium, unresolved issues of the nuclear fuel cycle, and questions about the availability of technology for clean coal utilization [421] . Many of these problems can only be remedied by legislative or governmental administrative action, which again serves to compound the problems surrounding future power availability. The question of future fuel mix for power generation is dependent on many factors of which neither the utilities nor government have complete control. 357 A last major factor in determining the availability of future electric supplies is the financing of construction. The utilities, already one of the most capital-intensive industries in the U.S., are facing increased costs from both owning and operating their generating units, while at the same time suffer- ing from a reduced earning power. Inflation, tight money and eroding investor confidence have contributed to a general rise in the cost of capital financing [534]. Environmental standards and construction cost escalation have also boosted the cost of investing in new capacity. The Federal Power Commission has suggested some reasons for the utilities' reduced earnings: The delay by some utility managers in seeking adequate rate relief, compounded by the lag in some regulatory commission responses to such requests, lower than expected sales, and sharply rising costs of fuel and other inputs have been the principal sources of earnings deficiencies. They have seriously impaired the industry's ability to carry out construction programs and may have put pressure on some utilities to reduce these programs to levels dictated by their current ability to raise capital, rather than by their judge- ment concerning long-term growth expectations [534] . All the above factors are shown in an attempt to understand the magnitude and complexity of the problem of providing sufficient future supplies of electric power. Other issues such as system reliability and delays in expanding capacity also bear upon the problem of assessing the adequacy of future electric power supplies. The question of the adequacy of presently planned generating capacity with respect to some future demand level for electric power is one surrounded by many problems. Given the number of delays and cancellations in new generating capacity over the past two or three years, there is a possibility of a serious inadequacy of electric power if growth rates return to their historical levels [564] . The combined planned and scheduled generating capacity of the eight Great Lakes states is 74,067 MW through 1984. If load factors and reserve margins were held at 1973 levels this capacity might be expected to accommodate an annual growth rate of 6 percent. c. Implications of Emerging Technologies Over the next 15-20 years no major changes in the technology of large- scale power production are expected to be implemented on a commercial basis. This Temporary decreases in sales serve to reduce current revenues without necessarily reducing current capital requirements. 358 is to suggest that current technologies will continue largely unchanged for the next twenty years. Efficiencies of the generating process will continue to improve as will those of the transmission networks. The nuclear technologies are not expected to change as to type or process; but rather an improvement in the engineering and fuel cycle aspects of nuclear technology might be expected. An increasing reliance on emerging coal technologies may alter the existing patterns of coal use. These might include fluidized bed combustors, gasification or liquefaction, low Btu gasification for use in combined cycle systems, and the development of technologies cleaning up coal's adverse impacts. In short, major technological changes in electric power generation systems are not expected to play a large role in the next 15 to 20 years. The pressure on the Great Lakes coastal zone from energy facilities will continue to increase in the future. The increase in demand for energy, the restricted thermal capacity of many inland water supplies, the proximity to load centers, and access to transport routes all suggest that demand for the coastal zone water resource (either direct siting on the coastal zone or simply access to the resource) will increase in the future. Tables 70 and 71 compile the announced generating facilities in the Great Lakes Region through 1984. 359 TABLE 70 PLANNED OR SCHEDULED ADDITIONS IN GENERATING CAPACITY IN THE COASTAL ZONE, 1976 (Plants over 300 MWe) State and Date Source of Plant Name Fuel Type MWe County in Service Information Illinois None — 303 Indiana Bailly Nuclear 685 Porter Indefinite 303 Michigan Greenwood #1 Oil 815 St. Clair Indefinite 303 Karn 93 Oil 605 Bay May, 1977 303 Belle River 91 Coal 697 St. Clair Indefinite 303 Belle River #2 Coal 697 St. Clair Indefinite 303 Campbell 03 Coal 770 Ottawa May, 1980 303 Enrico Fermi 92 Nuclear 1,215 Monroe Indefinite 303 Greenwood 92 Nuclear 1,341 St. Clair Indefinite 303 Greenwood 93 Nuclear 1,341 St. Clair Indefinite 303 D.C. Cook #2 Nuclear 1,100 Berrien Indefinite 303 Minnesota None 303 New York Oswego 96 Oil 850 Oswego May, 1979 450 Lake Erie #1 Coal 850 Sheridan or Pomfret Nov., 1985 450 Lake Erie 92 Coal 850 Sheridan or Pomfret Nov. , 1987 450 Nine Mile Pt. #2 Nuclear 1,080 Oswego Nov. , 1982 450 Sterling Nuclear 1,150 Sterling May, 1984 450 Ohio Davis Besse #1 Nuclear 906 Ottawa April, 1977 325 Davis Besse #2 Nuclear 906 Ottawa April, 1983 325 Davis Besse 93 Nuclear 906 Ottawa April, 1985 325 Erie #1 Nuclear 1,200 Erie April, 1984 324 Erie 92 Nuclear 1,200 Erie April, 1986 324 Perry 91 Nuclear 1,205 Lake Dec, 1981 325 Perry 92 Nuclear 1,205 Lake June, 1983 325 Pennsylvania None — Wisconsin Pleasant Prairie #1 Coal 617 Kenosha April, 1980 303 Pleasant Prairie #2 Coal 617 Kenosha April, 1982 303 Lakeside Coal 310 Milwaukee April, 1982 303 360 53 O H H w w 9 O W IS H 0) O >H £> H H c U ,--v •H < S3 S X) 01 U St o •u rH 00 o cfl |N« o ON CO las rH •H W H n TS h-J H I OJ e < 5 UD 5 •H H w r^. (XI Ss o> CO QJ w >H ■u •H o (3 CO 4-1 •H ^ rH rH H PL, "1 — ' •H CJ CO 01 S3 IH O H <-l-) H O H Q . Q o — a c ■3 •J > HI 2 ^ 3 — O S3 C 4J — >-' « ir u 01 K W o (J Z 361 Chapter V REGIONAL SCENARIOS OF ENERGY DEVELOPMENT A. INTRODUCTION TO SCENARIO APPROACH The rates of growth in demand for electrical power and the fuel mix used to generate that power are the key variables in attempting to evaluate the electric energy future of the Great Lakes coastal zone. To facilitate the assess- ment of the future pressures put on the Great Lakes coastal zone by electricity generating facilities, four alternative fuel mix scenarios have been postulated. The basic approach is to make certain assumptions for each fuel mix future and then examine the possible impacts if they were to hold true. The scenarios will then be evaluated in the context of three electrical demand growth rates to provide an indication of the resources required for future energy facility development. This study shall define a scenario as a set of assumptions relating to a particular fuel mix and its ability to generate electric power in required quantities. A scenario should not be confused with a forecast. Each scenario is developed on assumptions which provide a basis for analysis of the possible future. It is not based on conclusions or predictions as to what the future will be. Furthermore, scenarios do not assess the feasibility of the political, economic, and social events which must take place for any particular scenario to occur. The number of potential fuel mixes for future electric power generation is essentially unlimited. The scenarios have been selected to be representative of the major potential fuel mix development routes. This method allows for a comparison of their associated impacts and suggests the range of future fuel mixes that can occur. The values assigned to each scenario represent a reason- able level of supply and utilization that might be associated with the different technologies of the scenarios. 362 The attempt has been made to evaluate those scenarios which, under vary- ing situations and circumstances, have a potential of occurring within the 20- year time span being considered. A comparison of multiple alternatives serves to illustrate many of the variables influencing the Great Lakes Region's energy future . A further objective of the scenario approach is to identify and evaluate possible problems and impacts of future developments, thereby aiding policy decisions for power facility siting. It should be noted that no one set of policy options is associated with a particular scenario. Although the relation- ship between energy production and the economy has not been thoroughly investi- gated in the context of this study, it is assumed to be uniform throughout the four scenarios. The basic energy demand for end use is constant for each scenario. The four scenarios are based on variations in the fuel mix used for electrical energy production. As differences in the relative capital costs and environmental considerations among types of generating facilities have been used elsewhere in this study, the fuel mix for power generation becomes the critical issue. (Another important issue is that of development of controlled technology for the environmentally sound use of these fuels.) The availability, price, and environmental and social impact of primary fuels for electric energy generation are major questions which point to the important role fuels will play in the future. The future fuel mix is dependent upon factors such as: federal and state regulations, commercialization of new technologies, availability of foreign fuel sources, and other facts which will be discussed as they relate to fuels for electricity production. 363 B. DESCRIPTION AND DETERMINANTS OF SCENARIOS 1. SCENARIO I - RECENT TRENDS The nature of the utility industry is such that plans for the next ten years have been fairly well established. Such planning is directed by the lead times necessary for developing and constructing new generating facilities. Development time for nuclear facilities is often 9-12 years and 5-7 years for large fossil fuel plants, from planning through operation. Given the planning requirements of utilities it would appear that the capacity mix used for power generation is "locked in" until 1983 or so. Thus, the recent trends scenario includes the 1976-1983 time period and the facilities scheduled to come on line as its base. The assumptions within this scenario suggest that present fuel mix trends will stay relatively unchanged over the next 20 years, except that future capacity will continue to grow some 35%. Future fuel requirements might be predicted by extrapolating the current consumption patterns at a given electrical demand growth rate . As mentioned previously, these scenarios have been developed to show what the relative pressures and resource demands on the Great Lakes coastal zone might be in the future. Essentially, recent trends is a continuation of presently utilized fuel mix site selection process and power generating technologies. The recent trends scenario assumes no major change in regulatory policy or in the social instituttions which may affect the use or supply of electric power. This base case scenario is one with which the other scenarios will be compared and shall be used as the departure point for developing the other cases. Recent trends is the only scenario which deals explicitly with oil- and gas-fired generation. As the percentage of power generated from oil and gas is expected to hold fairly constant until the early 1980' s and then decrease, the role of these fuels in power generation will only be discussed in the context of the recent trends scenario. Three major variations appear in currently used fuel mixes. The States of Ohio, Michigan, and Pennsylvania use the highest percentage of coal for power generation. Wisconsin, Minnesota, Indiana, and Illinois use somewhat less. New York State uses the least amount of coal of any Great Lakes Region state [192/421], A weighted average was used to determine the present regional fuel mix (of which a breakdown appears in Table 75). The current planned and scheduled facilities were then worked into the regional generating fuel mix. The result is 364 TABLE 72 SCENARIOS: MAJOR ASSUMPTIONS FOR BASE LOAD GENERATION FOR THE REGIONAL SCENARIOS ECONOMIC Fuel Costs Capital Availability O.N. P. growth DEMOGRAPHIC Population RESOURCES Coal Labor Water Oil & Natural gas RECENT TRENDS Oil and natural gas increasing faster than coal. Overall increase through 20-year period Tight for next 5 years then expanding, closely related to state of economy overall between 3 and 4% OBERS "E" assumptions Local resources stated in study, national resources ; 1975 BOM est. Available Available, but at higher costs due to env. considerations Available, but decreasing after mid-1980' s. Foreign supplies also available HIGH COAL Less expensive fuel costs than recent trends scenario, but increasing due to environ- mental consi- derations HIGH NUCLEAR High fuel costs due to incomplete fuel cycle and increasing scarcity, plus delay in breeder development Federal Assistance NEW TECHNOLOGIES Increasing for conventional fuels . SCENARIOS: MAJOR ASSUMPTIONS (Continued) 365 RECENT TRENDS HIGH COAL HIGH NUCLEAR NEW TECHNOLOGIES ENVIRONMENTAL i Air /Water Existing I new schedules Land Stricter stip- mine laws Increased siting control Little change from R.T. TECHNOLOGY Electric Minor increases in efficiency Major increases Production in the overall efficiency of energy production process Plant factor minor increases Environmental Improvement in pollution control Acceleration of R . T . development Same as R.T. technology Fuel Research Continue present trends Increase in research for new technologies INSTITUTIONAL Anti-trust/ No major change tax structure Nuclear Power No significant More anti- Policies which No major change change nuclear policy promote nuclear development Price regulation Gradual de- regulation of •^^ all fuels State/local No limitations to growth Policy 366 a projected 1995 fuel mix comprised of 50% coal-fired generation, 30-35% nuclear, and 15% oil, gas, and hydroelectric. 2. SCENARIO II - HIGH COAL ELECTRIC With the recent trends scenario extending until 1982-1983, a high coal fuel mix would not be evident before the mid-80' s. A possible exception to this supposes that a change in the fuel mix of currently planned facilities, combined with an increase in demand for electrical power, would favor the growth of fossil fuel plants to meet this demand, due to their considerably shorter construction period. The variations among current fuel mixes in the eight Great Lakes states, shown on Table 75, indicate that many states currently have what might be termed "high coal" fired generation. For these states the variations between their present fuel mix and the high coal scenario may not be substantial. There are certain conditions necessary for the development of a high coal scenario. A primary condition would be the further development of reliable technologies for the clean utilization of coal, including desulfurization and removal of particulates and N0 X . At the same time, actions such as a reduction in air quality standards (on a case-by-case basis remaining consistent with health and environmental standards), the development of more mining and transpor- tation activity and a political commitment sufficient to sustain the increased utilization of coal for power generation would be needed for coal to play a larger role in generation of electric power. Furthermore, strenuous use of coal would be facilitated by a higher relative cost for nuclear power or the imposi- tions of restrictions on nuclear facilities development. It is assumed here that the coal fuel mix will be approximately 15-20% higher between 1990 and 1995 than in the recent trends scenario. The fuel mix for the high coal scenario will break down as follows: 70% coal-fired, 15% nuclear and 15% oil, gas, and hydroelectric. An additional factor influencing the rate of coal use is the rate of conversion of oil-fired generating plants to the burning of coal. This would apply to both currently operating and planned facilities. The federal govern- ment will be the primary factor in determining the rate at which conversion will take place, assuming that some policy position will be forthcoming on oil to coal conversion of generating facilities. Currently, two plants in New York, the 367 Albany and Danskammer, have been ordered to convert to coal by the Federal Energy Administration. (The order for the Albany Station is not presently effective.) 3. SCENARIO III - HIGH NUCLEAR ELECTRIC The high nuclear scenario suggests a rapid development of nuclear generating capabilities exceeding that associated with recent trends. Nuclear generation of electrical power remains one of the few fuel mix options suffi- ciently developed to assume a major role as a regional power supplier. Nuclear power currently provides 10-12% of the Great Lakes Region's electrical energy demand. As is projected in the recent trends scenario, by 1995 it will comprise approximately 30-35% of the generating capacity. The nuclear scenario then further assumes that the Great Lakes Region's nuclear generating capacity will be approximately 45% of the 1995 total generating capacity. Nuclear development on such a scale would require major actions by both the utilities and the federal government. The acceleration of the siting process in conjunction with the alleviation of capital cost and formation problems of nuclear facilities would be necessary in order to achieve a high nuclear scenario Furthermore, problems in the entire nuclear fuel cycle, from scarcity of fuels and transportation security to radioactive waste, require serious consideration and improvement. In short, the questions being raised regarding the expansion of the nuclear power industry, combined with the long lead time for planning and construction, indicate that a firm commitment to continue building will be needed in the near future. The high nuclear scenario will reflect the continued decrease in the use of oil and natural gas as primary fuels for base load power generation. Coal- fired units will make up the remaining required generating capacity (45%) , with few large coal units scheduled past 1985. 4. SCENARIO IV - APPLIED EMERGING TECHNOLOGIES The fourth scenario assumes a more rapid development of new technologies for power generation than is presently anticipated. During the 20-year period under consideration, the rate of new technology implementation is dependent on Personal communication, Brookhaven National Laboratory. 368 the price of conventional fuels (including nuclear) , the emphasis on commerciali- zation of new technologies, and the size of electricity demand. Problems with the use of the two primary fuels for future power generation might limit the rate at which facilities fired by coal or nuclear fuel come on line. Such a slow- down would provide additional impetus for the development and commercialization of new power producing technologies. The environmental and social problems of coal use have been investigated, but there remain many unknown factors associated with coal utilization. The questions of siting, nuclear wastes and the availability of fuel are crucial to the further development of nuclear facilities. Thus, the degree to which the two primary fuels may be utilized in the future is an unanswered issue. One new technology would be the use of a low Btu coal-gasification process for production of fuel in a combined cycle generating unit, resulting in higher heat rate efficiencies and prevention of the more deleterious effects of coal utilization. Such a project is currently planned by Commonwealth Edison on a 100-200-MWe scale, with future development in some degree dependent on the facilities' operating record. A fuel mixture composed of garbage-coal or biomass (i.e., crops grown specifically for combustion on energy plantations or simply agricultural wastes) could be utilized in conventional generating facilities, thereby reducing resource pressure and the negative impacts of conventional fuel use. Although no firm commitment has been made by private industry or govern- ment, high Btu gasification or liquefaction could potentially make an impact on electrical generation systems by 1995 (by decreasing the demand due to end use substitution) . The use of fluidized bed systems for combusion of coal would reduce the negative effects of coal utilization as well as increase generation efficiencies. (This changes only the process and not the primary fuel, but as a new technology it is included in the fourth scenario.) Further new technologies might include: wind-actuated electric power generation; small-scale "total energy" systems for commercial or industrial use, which would greatly increase overall efficiency; bioconversion processes for natural gas production and use in electrical generating facilities; solar-assisted heating units which would decrease electrical demand thereby possibly altering the fuel mix; fuel cells for thermo-electric generation; and generally, combina- tions of technologies which produce electric power and reduce the pressure on the primary fuels. 369 The future of any of these technologies is uncertain. Given that these and other technologies have potential for development and implementation in the next 20 years, their possible impact should be noted. Under optimum conditions the generation attributable to such technologies would be 15 to 30% of the region's total by 1995. The remaining generating capability would come from standard sources with conventional coal boilers constituting approximately 40-50% and nuclear accounting for 20-35%. C. INTRODUCTION TO DEMAND PROJECTIONS While the fuel mix for electric power generation is fairly well set for the next several years, the demand for power is not. Of the two critical variables for future electric power production, the demand variable is the most difficult to estimate over the time horizons of this study. The demand rate for electric power, then, may be the only major surprise in the electric power equation for the Great Lakes Region. Historically, electricity demand has been the major factor in determining the rate of electrical power supply. With the advent of higher prices and shortages of primary fuels for generation, demand for power is no longer the only variable to consider. Factors such as fuel shortages, rapid increase in prices, fluctuating demand levels, and governmental regulation have increased the difficulty and complexity of projecting future demands for electric power [549] . But the long lead time necessary for power plant planning is the very reason why forecasts must be made. Electrical demand forecasts have been studied in order to give an idea of the possible future pressures on the Great Lakes coastal zone due to the need for siting increasing numbers of power generating facilities. A combination of different growth rates with fuel mixes may give an indication of the resource requirements necessary for various electrical power futures. These requirements may then be used to develop policies for future power plant planning. The electrical demand growth rate is that figure which represents the percentage increase over the previous time period (defined as one year) in electrical power consumed, as determined by the additional number of kilowatt hours consumed. Before 1973 this figure had grown at an average rate of approximately 7% per year, or doubling every 10 years. Since 1973 the demand for electrical energy has fluctuated greatly. It is currently 5.4% per year, but 370 the future level of this number is one of great contention [421]. The variations among electrical energy growth forecasts are tremendous, largely due to the absence of a standard methodology and a single set of reliable facts • Given the speculative nature of forecasting and its reliance on past trends, 100% accuracy should never be expected. Growth forecasts are generally derived from a model describing the process that is under study. These models vary greatly with respect to scope, specificity, assumptions, emphasis, etc. Development of a single, comprehensive model is not recommended [45]. The degree of sophisitication and variation among forecasting models is a significant factor in assessing the usefulness or accuracy of growth models. Regardless of their sophistication, econometric models always depend on statistical observa- tion and interpretation of the past [549] and hence are only valid as long as structural changes of relationships or independent variables do not occur during the models' time frame [549]. To suggest that prediction is the purpose for which models have been developed would be misleading. Rather their purpose is to identify, organize, and clarify the parameters and variables influencing electrical power demand, hopefully giving improved information as to how the future may develop. When analyzing electric energy forecasts there are a number of major points which should be kept in mind, including: the time span being studied, the need to understand key assumptions and how they are incorporated into the fore- cast, for whom and by whom the studies are prepared, the comprehensiveness of the model, and the degree of detail it covers. In addition, the capabilities of the forecasting model (particularly in adapting to policy and technology changes) and its economic aspects (i.e., inter-fuel and regional competition, determinants of supply and demand) [45] are important to understand. Actual projection analysis is based on certain key factors which are representative of the individual variables that have been selected as effectors of future demand for energy. The factors to be considered and their weighted importance in the analysis are very important, as the potential for altering the analysis and outcome is greatly influenced by the factors selected. As in the Dr. Miller B. Spangler, An Appraisal of Future Energy Developments Affecting the National and Regional Economic Outlook for Nuclear-Generated Electricity During the Next Forty Years . March 1976. 371 selection of the methodology and assumptions to be employed for an analysis, the key factors are selected on the basis of their judged relative importance by the group doing the analysis. The factors used in assessing future demand for electrical energy are different for long- and short-term projection analysis. These factors also vary among projections which analyze the same time period. "The short-run projections (2-3 years) must recognize the experienced factors such as the current recession period, level of unemployment, and the leading economic indicators as the key variables" [394]. "Long-run projections, on the other hand, hinge on factors such as trends in population growth, household formations, changes in stock of appliances, long-term business and economic outlook, availability of fuel substitutes and their prices, environmental regulations, and technological change' [394]. Somewhat differently, Oakridge National Laboratory considers population growth, per capita personal income, price of electricity, price of competing energy sources and price of electric appliances as the key factors in assessing future electricity demand. The key factors used in a projections analysis are as important in shaping the final output of energy demand modes as are the assumptions and methodologies employed. D. REVIEW OF PAST PROJECTIONS 1. OVERVIEWS OF AVAILABLE PROJECTIONS The projected growth rates analyzed for this study vary greatly with respect to region, fuel mix, approach and results. Projections relevant to the demand for future electrical power were gathered to assess the variations described above and how they might relate to the Great Lakes coastal zone. Given that no projection has been done specifically for the Great Lakes coastal zone, the growth rate for electrical power in this region can only be inferred. Table 73 lists the projections reviewed, along with a number of major factors which should be considered during a review of the projections. The degree of diversity between the projected growth rates can be explained by the various assumptions, methodologies and key factors used in the respective studies. As might be expected there is some degree of correlation between the party preparing the projections and their implications for future growth rates. Those groups having a direct relationship to electrical energy production (i.e., utilities, component producers, or independent firms hired by utilities) tend to develop higher rates of projected electrical energy demand 372 TABLE 73 1/ OVERVIEW OF ELECTRIC POWER PROJECTIONS-- FORECASTER DONE FOR REGION PERIOD FORECASTED AVERAGE COMPOUND RATE OF ANNUAL DEMAND GROWTH X COMMENTS Duane Chapman, E.C.A.R. 1974-1980 2.6% Agricultural economist, Cornell University New York Power Pool Utility planning purpose New York late 1970's-1990 4 .0% declining to 3.5% by 1990 Stanford Research institute Wisconsin Utilities Assoc. Wisconsin 1975-2000 4.5% Jim Griffin U.S. 1974-1981 4.8% Economist, University of Pennsylvania Michigan Public Service Comro. Detroit Edison Service Area Consumer Power Service Area 1979-1982 4-5.6% 4.6-5% Re-forecast of company's forecasts , same methodology, different assumptions Detroit Edison Planning use Detroit Edison Service Area 1974-1985 5.6% Consumers Power Planning use Consumers Power Service Area 1974-1985 5.0% Dept. of Interior (Bureau of Mines) U.S. 1975-2000 5.5% Revised Edition Edison Electric Institute U.S. 1975-1980 6.0% Utilities within states Ohio Power Siting Contaiscion Ohio 1974-1985 6.13% Cincinnati Gas & Electric Co. Ohio Power Siting Comm. Cincinnati G.& E. Co. Service Area 1976-1986 6.7% Service area of 3000 sq. mi. and 1,7 million people R.T. Cornell U.S. 1977-1990 8.0% Utility Securities Analyst for Institutional Investors, E.F. Button Co. Westinghouse U.S. 1975-1980 9.1% — Adapted frora Forecasting Electric Energy Demand in Michigan , by Waino H. Pihl and i-awrence M. Glazer, February, 1976. growth than groups not so involved. This is not to suggest that either group's projections are deliberately biased. Differences are due to the different natures of the groups, the emphasis placed on different variables, and human judgement. The differences in the projections, between what might be termed vested interest groups and independents, should further emphasize the need for projections from many sources in assessing the needs for future power requirements. The majority of the states within the Great Lakes Region have limited capability for making independent electrical energy demand forecasts. The Public Service Commissions (in some states Public Utility Commissions) within the eight 373 states rely heavily upon the utilities for their future demand forecasts. Due to limited staff, budget, resources, etc., these commissions' forecasting capabilities are often limited to analyzing the utilities' projections. More often the commissions' role has been to act on a request for a construction permit, deciding whether or not a new plant should be approved. Many of the state energy agencies' electrical demand forecasting capabilities are also very limited, such that in many states only the utilities have the capability of making long-range energy forecasts. Minnesota, as an example of a state having forecasting capabilities, has two forecasting groups: one concerned with reviewing the utilities' forecasts and a second producing independent energy forecasts working with the Minnesota Energy model. Wisconsin, in conjunction with the University of Wisconsin, utilizes the Wisconsin Energy model (WISE) in assessing the future state electrical demands. Overall the eight Great Lakes states have limited forecasting capabilities. Hence there tends to be a reliance solely on utility forecasts to assess the future needs for electrical energy. The Ohio Power Siting Commission and the New York State Board on Electric Generation Siting and the Environment are the only state agencies within the Great Lakes Basin that deal specifically with the issue of the siting of electri- cal generating facilities. The Ohio Power Siting Commission has the capability of making electrical demand forecasts independently of the utilities. This fore- casting ability allows for verification of and comparison with the projections prepared by the utilities. The commission also reviews the utilities' projections for compilation of the state's ten-year forecast for electric power [514]. The format and content of the forecasts are specified by the commission with a primary goal of the process being the need for the utilities to justify the rationale that underlies their decisions to strive for a given resource require- ment [514]. Towards this end the commission has stipulated that all assumptions and special information related to the forecasts be listed and explained. The Commission reports: While most of the utilities complied with the requirement (9-01 (D)(3)) to list the assumptions used in the preparation of * Personal communication, Office of Energy Emergency Assistance, Wisconsin. 374 the forecasts, some reporting utilities either failed to justify the inclusion of these assumptions or described the assumptions in such general terms as to be meaningless. Further, the impact of the assumptions on their basic forecast was not adequately addressed [514]. Other issues which the commission felt to be inadequately addressed in the utilities' forecasts included the impact of alternate rate structures on demand, the effect of changes in the relative price of electricity, and the optimal use of generation capacity. The role of the Ohio Power Siting Commission, as both reviewer of utility forecasts and forecaster, is to "review and comment and certify the need for new facilities" in Ohio [514]. 2. ANALYSIS OF SELECTED PROJECTIONS A detailed analysis of energy projection models has been performed by Argonne National Laboratory. This study gives useful insight into the workings and problems of energy modeling. The following comments were developed to better understand differences between projections, what they were designed to do, how they developed, as well as shortcomings of the energy modeling situation. Argonne 's purpose was to evaluate several existing energy models to determine their usefulness for ERDA' s Regional Studies program and identify areas where future work should be undertaken due to certain weaknesses found in the models. Three basic criteria were used in evaluating the models: (1) model capability, (2) economic aspects, and (3) model comprehensiveness. Projection models can be divided into "local impact," used for substate or state regions, which are particularly useful for end-use details, and "National synthesis," which analyzes energy availability and/or consumption on a larger scale [45]. These two basic groups differ markedly in their abilities and out- puts, such that in many instances combining the two provides a more comprehen- sive result. For instance, if a regional policy affects the national energy picture (such as high energy facility development in the Great Lakes coastal zone), this output could then be used as input for the larger national model. Conversely, a national model could provide a regional energy supply and demand analysis consistent with national policy as input for a local model [45]. The point being that rarely will a single model be sufficient to cover all relevant relationships, suggesting that more than one projection should be utilized in a decision-making process. 375 The Bat telle Columbus-EPA Energy Quality model, the Proejct Independence Evaluation System, and the Wisconsin Energy model are representative of sophisti- cated energy projection models that vary in methodology, scale, and type of out- put. "The Battelle-EPA Energy Quality model is a large linear program that determines a minimum national cost of the distribution of coal, natural gas, residual oil, distilate oil, and nuclear power in the contiguous United States under specified conditions of supply, price and demand." The model's output describes the fuel policy and use schedule for each region (PAD or AQCR) and a schedule of fuel shipped from a supply to a use region [45]. Due to its spatial detail and regionalized energy consumption and costs (including transport) it is considered of value when undertaking regional energy studies [45], "The Project Independence model (PIES) of the nation's energy system is ** probably the most comprehensive and all-inclusive energy model yet produced." This national model has the capability of analyzing regional energy situations on an interregional basis with the end product being an instrument against which policy and technology development for national and regional energy strategies may be measured and evaluated. The model provides for total energy demands to be linked to economic growth. With the detail in the level of supply and demand, interfuel competition can be assessed [45], The PIES model has been criticized for underestimating capital and environmental costs, the uncertainty in supply and price of fuels, and the lack of constraints on production [45]. With respect to the "local impact" type model the Wisconsin Energy model •>'fk-k (WISE model) has "stressed flexibility with maximum room for innovations" in developing their modular format. "The main subcomponents of the system are the socioeconomic, primary energy source, end-use demand, electricity production, and environmental impact models," [45] which provide excellent evaluation capa- bility on the state level. The model can evaluate local regulatory policies, provide for analysis of regional technology options, include engineering design parameters, and assess the social and economic impacts of energy systems [45]. Battelle Columbus Laboratories, A Proposal to Develop Energy Price and Availability Projections , p. A-2 , April, 1973. ■k-k Federal Energy Administration, Project Independence Report , Project Independence, p. 18, November, 1974. *** Foell, W.K. The Wisconsin Energy Model: A Tool for Regional Energy Policy Analysis , Energy Systems and Policy Research Report No. 101, p. 6, November, 1974. 376 The model further permits a description of future changes in policy and tech- nology to examine the resulting energy scenario. The WISE model "does not predict the future, nor constrain all future trends to be like the past" [45]. With modification the WISE model could be utilized by other states and as a data base input into inter- regional (national synthesis) energy projection models. The primary results of Argonne's analysis of these state energy projec- tion models is as follows: (1) all models were found deficient in that they failed to consider interregional competition and did not integrate energy supply and demand forecasts with economic growth, and (2) none of the models studied were able to adequately predict and analyze regional effects of national energy actions [45]. This analysis should help to emphasize that the variations among projection models, due to differing methodologies, assumptions, and purpose, are quite large. They also indicate that relying on a single model or source in developing policy or plans for future energy demand should be avoided. 3. SELECTED GROWTH RATES FOR PROJECTIONS For the purpose of evaluating future potential pressures on the Great Lakes coastal zone, a number of potential fuel mix scenarios have been postulated. The actual pressure on the coastal zone will be a function of the increase in the demand for electric power, the utilities' ability to construct sufficient capacity, and the type of fuel chosen for the new generating capacity. The choosing of an average or best-gues electrical demand growth rate would assume that accurate knowledge of the future energy picture is known. The use of high, medium, and low growth rates encompasses a number of possible energy futures. More importantly it gives a range to the potential impacts of new energy facili- ties from which it may be possible to determine the requirements for fulfilling the various scenarios. The integration of these growth rates with the four scenarios described earlier will give an indication of the resources that might be required by a certain fuel mix and electrical demand growth rate. These figures can then be used by interested parties in developing policies that relate to the fuels (need, transport, cost, etc.), siting, and regulation of future plants. To this end, three growth rates have been chosen representing a low (3% per annum), a medium (5.5%) and a high (8%). The low growth rate might be tied to high conservation rates; the medium rate will be close to the electrical demand growth rate since the 1973 Arab oil embargo; and the high growth rate 377 might be associated with an intensive electrification process due to substitution for other fuel types. E. IMPLICATIONS OF SCENARIOS The direct extrapolation of generating capacities does not take into consideration critical factors which will greatly influence the determination of quantities and types of current generating capacity. Thus, in conducting the resource impact analysis, a number of assumptions were made which have a direct bearing on the results of the analysis. The mix of new generating facilities is assumed to be the following: 75% base load, 20% intermediate load, and 5% peak load capability. Coal and nuclear facilities will compete for base load generation capability and for half of the intermediate load. Oil, gas, and hydroelectric facilities will be used primarily in intermediate and peak facilities. (Oil will continue to be used in decreasing amounts as the base load fuel source.) Load factors for the new facilities are assumed to be 65%. Prices of primary fuels for electric power generation were not considered in the analysis, but availability and price will play a major role in determining the types and numbers of facilities constructed. No assumptions were made as to the substitution of electricity for other energy end use purposes, but such a trend would be reflected in higher rates of demand for electricity. The analysis further assumes a standard 1000-MW unit size with the option to locate multiple units on a site. Further expansion of present utility sites and reconstruction on retired sites were assumed, thereby potentially lowering demand for total land requirements by 15-25%. Two nuclear units were assigned to each site with potential of up to 4 units per site before additional land would be required. Approximately one-half of the water required for a closed-cycle system is consumed. The assumption was made that facility retirements would not substan- tially affect the amount of new capacity to be installed. There are a number of critical points which greatly affect the demand for electricity which have been ignored in this analysis. Any one of these issues could greatly alter the demand for electricity and the capacity needed over the next twenty years. The analysis does not consider the effect of prices on the demand for electricity, a central issue in most projections. No account is taken 378 of the potential slackening in demand as population growth levels off or as some saturation level for electricity is approached. Straight extrapolations of present generating capacity do not consider increasing efficiencies over time in the generation, transmission or end use of electricity. The present situation of high reserve capacities and low load factors, which may delay need for additional capacity (increasing load factors will substantially reduce short- term need to increase capacity), is not addressed. Also not considered is the regional or power pool level of demand analysis which allows for a potential reduction in required generating capacity due to better management and the sharing of power through well-developed transmission networks. This partial list of "critical factors not accounted for" suggests the many weaknesses of the analysis. The point should be emphasized, however, that the analysis was conducted as a demonstration of the magnitude of the resources required, should certain capacity expansion schedules be followed, and not as a forecast of capacity expansion in the Great Lakes Region. Based on present (1975) generating capacity and electricity demand (by state), future generating capabilities and demand levels have been postulated, using the three growth rates (3%, 5.5%, 8%) at time increments of 10 and 20 years Using a simple compounded interest formula, the current electrical power capacity and demand levels were extrapolated at the three growth rates to give an indica- tion of future potential resource requirements needed for new energy facilities. While both capacity and demand projections were made for analysis purposes only, electric generating capacity will be used in the assessment of future resource requirements. Working through projected required capacity figures provides a graphic display of how fast new capacity would be required at various growth rates. Given certain assumptions, such as traditional load factors and utility opera- ting practices, a number of possible resource requirement schedules for the different growth rates can be postulated. The purpose of such an exercise is to give a rough indication of what future demands for electric power might mean in terms of land, water, and fuel resources required for the new capacity. When these resource requirements are combined with the four scenarios, some indica- tion of the number and types of facilities may be estimated. 379 F. PROJECTED GENERATING CAPACITY AND RESOURCE REQUIREMENTS On a regional level, using a standard 1000-MW generating unit, the additional projected capacity needed at a 3% growth rate through the year 1995 would be roughly 126,686 MW. Similarly, for the same time span, the amount of capacity needed at growth rates of 5.5% and 8% would be 300,677 MW and 575,642 MW respectively. These numbers were determined by taking each state's 1975 genera- ting capacity and extrapolating at the three growth rates over a twenty year period. Assuming no present facilities decommission, a rough estimate of the number of new 1000-MW generating units (multiple units may be located on one site) needed by 1995 would be 126 at a 3% growth rate, 300 at a 5.5% rate, and 575 at 8%. Due to the nature of the assumptions previously listed these figures contain a substantial margin of error. TABLE 74 NEW GENERATING CAPACITY REQUIREMENTS FOR 1995 (in MW) (1975) Base Proj ections (1995^ 1 State 3% 5.5% 8% Illinois 25,500 46,055 74,402 118,854 additional capacity 20,555 48,802 93,354 Indiana 13,315 24,048 38,850 62,060 additional capacity 10,733 25,535 49,745 Michigan 18,926 34,316 55,437 88,558 additional capacity 15,390 36,511 69,632 Minnesota 6,700 12, ion 19,548 31,228 additional capacity 5,400 12,848 24,528 New York 29,000 52,377 84,614 135,167 additional capacity 23,377 55,614 106,167 Ohio 25,780 46,561 74,943 120,159 additional capacity 20,881 49,163 94,379 Pennsylvania 28,770 51,961 83,943 134,095 additional capacity 23,191 55,173 105,325 Wisconsin 8,881 16,040 25,912 41,39 3 additional capacity 7,159 283,556 17,031 457,547 32,512 Region Total 156,872 732,512 total additional capacity 126,686 300,677 5 75,642 380 The land, water, and fuel resources required for these facilities could be determined by using figures available for existing facilities. The result represents an average or ideal facility requirement and is subject to debate. For coal-fired plants, fuel requirements are assumed to be 228 tons per hour, or approximately 2 million tons of coal per year. The Btu value of the coal averages 20 x 10 per ton. For low Btu western coal, the heat value could be 15-20% lower. Conversely for a higher Btu coal the heat content could be as much as 15-20% higher. Land requirements for a 1000-MW coal-fired facility are 400 acres per unit. This includes the land required for the plant with on-site ash and S0 X disposal, natural draft cooling towers, and storage for a six-month coal supply. Depending on the mix of these variables, total land requirements can vary as much as 100 acres. Water requirements vary substantially between closed-cycle cooling systems and open-cycle or once- through cooling, such that two sets of numbers will be postulated to represent each system. The water requirements for a natural draft cooling tower are 700,000 gallons per minute (gpm) (assuming a 12°-13°F tempera- ture rise across the condenser) for the open-cycle and 10,000 gpm for closed-cycle system. Resource requirements for nuclear units vary as greatly as those of a coal-fired station. The fuel requirement for nuclear units has been deleted from this analysis due to the unique problems posed by the handling, transport, and processing of nuclear fuels. Land requirements average 1,335 acres per unit (135 for the actual facilities, and the additional 1,200 acres as exclusion zone). Nuclear facilities, unlike coal facilities, are able to economize by siting multiple units on a single site, requiring no additional land for up to 4 units. Nuclear facilities require more water than do coal facilities, averaging an additional 15,000 gpm for a closed-cycle system, of which approximately 50% is consumptive use, and up to 1 million gpm for an open-cycle system, with some consumption (assuming a 15 °F temperature rise across the condenser) . These resource requirements are used in conjunction with the four scenarios to indicate potential pressures on the Great Lakes Region in the siting of new electric generating facilities. With the major exception of New York, the Great Lakes states rely primarily on coal for base load generation, with an average of 66%. The remaining capacity is made up of hydroelectric, 5% (expected to provide a decreasing percentage of electric power as suitable sites become scarce), oil and gas-fired, 17%, for base and peak supply, and nuclear, currently 12% and expected to comprise roughly 35% by 1990. The question of 381 oil-fired generating units is somewhat more crucial to New York State, as it presently accounts for about 40% of the state's power. TABLE 75 1975 FUEL MIX BY TYPE FOR POWER GENERATION (Btu percentage by state) State Oi 1_ Gas Coal Hydro Nuclear 4% 63% .1% 24% 2% 9 3% 1% 0% 6% 72% 1% 10% 12% 63% 2% 19% 5% 15% 24% 17% 2% 94% 0% 0% 1% 74% 1% 9% 9% 57% 1% 28% Illinois 8% Indiana 3% Michigan 10% Minnesota 3% New York 39% Ohio 4% Penn . 14% Wisconsin 1% Regional Weighted Average 13% 4% 66% 5% 12% The recent trends scenario suggests that nuclear generating capability will grow to approximately 35% of the total generation over the next 15 to 20 years. Based on 1975 figures, determined by weighted average of the eight Great Lakes states' fuel mix distribution, this works out to approximately 70,000 MW, or 70 nuclear units, and 40,000 MW, or 40 new coal units, at the 3% rate by 1995 This would bring the nuclear capacity up to 35% of the generating capability for the region with coal comprising 50%, and oil, gas, and hydroelectric making up the remaining 15%, accounting for roughly 18 new units. The method for arriving at these figures involved determining the current generating capabilities by fuel type for the states and weighing them, accounting for differences in each state's generating capacity, and coming up with an average regional fuel mix. These figures were then used to determine the approximate amount of capacity for each fuel type in the region, Then, with the additional capacity required by the three growth rates, the number of new units was determined by multiplying the expected capacity percentage for each fuel type by the total capacity in 1995 and subtracting the present capacity. 382 Land requirements for nuclear facilities in the recent trends scenario at a 3% growth rate are on the order of 46,725 acres for the region. This assumes that two units per site would require no additional land. Additional units per site would reduce land requirements further. The water require- ments for these 70 nuclear facilities, using a closed-cycle cooling system, c. axe. 1,512 x 10 gallons per day (gpd) , while for a once-through cooling system, o 1,008 x 10° gpd would be needed. Similarly for the coal-fired units, land requirements total 16,000 acres and fuel consumption would equal 80 x 10 tons per year. Once-through cooling water equals some 403 x 10° gpd, and a closed- cycle system would utilize some 5 76 x 10 gpd. As is evident, even at a low growth rate the number of new 1,000-MWe units required by 1995 is substantial and indicates the need for rational long-term planning. The amount of new capacity required at a 5.5% growth rate would be 141,000 MWe, or 141 nuclear units and 121,000 MWe, or 121 units, for coal- fired generation. Oil, gas, and hydroelectric might contribute up to an additional 35,000 MWe. Nuclear facilities would require 93,120 acres of land, 3,046 x 10 gpd Q of water for a closed-cycle system, and 2,030 x 10 gpd for a once-through cooling system. The coal-fired facilities would require 48,400 acres of land, o 242 million tons of coal per year, 1,220 x 10 gpd for a once-through cooling f. system, and 1,742 x 10 gpd for a closed-cycle cooling system. Table 76 ADDITIONAL FACILITIES REQUIRED BETWEEN 1975-1995 FOR SCENARIO I, RECENT TRENDS Growth Rates Type 3% 5.5% 8% Nuclear (units) 70 141 238 land requirements (acres) 46,725 94,120 158,865 water requirements (gpd) : o o q once-through 1,008 x 10* 2,030 x 10* 2,427 x 10 closed-cycle 1,512 x 10 6 3,046 x 10 5,141 x 10 Coal (units) 40 121 185 land requirements (acres) 16,000 48,400 74,000 fuel requirements (millions of tons/year) 80 242 370 water requirements (gpd) : „ o once- through 403 x 10 1,220 x 10* 1,865 x 10' closed-cycle 576 x 10 1,742 x 10 2,664 x 10 "* 383 At a growth rate of 8%, approximately 238,000 MW, or 238 nuclear units, would be required and 185,000 MW, or 185 units, for coal-fired generation. The nuclear units would need 158,865 acres of land, 5,141x10 gpd of water for a o closed-cycle cooling system, and 3,427 x 10 gpd for a once-through system. The coal units would require 74,000 acres of land, 370 million tons of coal, 6 o 2,664x 10 gpd of water for a closed-cycle cooling system, and 1,865x10 gpd for a once-through system. The second scenario postulates a fuel mix for the year 1975 comprised of 70% coal, 15% nuclear, and 15% oil and gas. At the 3% growth rate the number of new facilities required by this scenario will be approximately 96 coal units (1,000 MW each), 24 nuclear units, and about 20 oil or hydroelectric units. The resource requirements for these facilities are shown in Table 77. Table 77 ADDITIONAL FACILITIES REQUIRED BETWEEN 1975-1995 FOR SCENARIO II, HIGH COAL ELECTRIC Growth Rates Type 3% 5.5% 8% 24 16,020 50 33,380 92 61,410 346 x 10^ 518 x 10 1, 720 x 10^ ,080 x 10 1,325 x 10^ 1,987 x 10 96 38,400 217 86,800 410 164,000 192 434 820 968 x 10^ 1,382 x 10 2 3 ,187 x 10^ ,125 x 10 4,133 x 10^ 5,904 x 10 Nuclear (units) land requirements (acres water requirements (gpd): once-through closed-cycle Coal (units) land requirements (acres) fuel requirements (millions of tons/year) water requirements (gpd): once-through closed-cycle The third scenario assumes that nuclear generating capability will equal that of coal-fired generation. The fuel mix breakdown for this scenario is approximately: 45% nuclear, 45% coal, and 10% oil. The fourth scenario postulates a rapid development of new technologies, hence, a somewhat reduced dependence on more conventional generation technologies It suggests a fuel mix having the same proportions between fuel types as that of recent trends, but with a reduction of 20-25% in the number of new coal and nuclear facilities required. Given this similarity, the resource requirements for the new technologies scenario are assumed to be 70-80% of those postulated for the recent trends scenario. 384 Table 78 ADDITIONAL FACILITIES REQUIRED BETWEEN 1975-1995 FOR SCENARIO III, HIGH NUCLEAR Growth Rates Type 3% 5.5% 8% Nuclear (units) 104 177 311 land requirements (acres) 60,420 118,150 207,590 water requirements (gpd) : „ once-through closed-cycle Coal (units) land requirements (acres) fuel requirements (millions of tons/year) water requirements (gpd): once- through closed-cycle 1,498 x 10" 2,246 x 10 2,549 x 10, 3,823 x 10° 4. 6 ,478 x 10 ,718 x 10 12 4,800 91 36,400 227 90,800 24 182 454 121 x 10^ 173 x 10 917 x 10^ 1,310 x 10 2. 3 ,288 x 10 ,269 x 10 G. COASTAL ZONE RESOURCE IMPACT ANALYSIS 1. RELATION OF PROJECTED DEMAND TO POWER PLANTS The implications of these figures vary greatly from county to county in the Great Lakes coastal zone. The limitations of the analysis notwithstanding, the potential impact of energy facility siting can be estimated by assessing the current importance to the states of coastal county energy facilities and then assuming that this current proportion will hold constant in the future. For the States of Illinois, Pennsylvania, and possibly Indiana, the future of their coastal counties with respect to energy facilities will most probably be limited to demands for access to the water rather than the physical siting of facilities on or near the shoreline. This aspect of coastal zone utilization is further limited by the difficulty of siting new generating units in the already heavily developed Indiana and Illinois counties. Pennsylvania's coastal county, being somewhat less developed, has a slightly higher potential for access. It may turn out, however, that as an increasing number of facilities require water supplies no longer obtainable from inland sites, there will be increased pressure to transport coastal waters further inland. Minnesota currently has the lowest number of energy facilities in the coastal zone. The current percentage of coastal zone generating facilities of the state total is roughly 5%. Further, there are no plans at present to construct any facilities. If land presently categorized as agricultural or 385 undeveloped were considered potentially available for the siting of energy facilities, Minnesota would have 11 miles of coast land available for energy facilities. By taking the total new generating capacity required by the four scenarios and determining Minnesota's portion based on the percentage of current capacity, a rough idea of the number of new Minnesota facilities required could be derived. (This procedure will be followed for the remaining states.) Minnesota's share of the postulated new facilities would range from 6 plants at a 3% growth rate to 23 facilities at an 8% rate. Maintaining 5% of its total capacity in the coastal counties, only one or two new coastal facilities would be required. These facilities would take approximately 1000 - 2000 acres of land, with the water and fuel resources presenting little additional burden to the coastal zone. Assuming a pressure to site an increasing percentage of the state's total generating capacity in the coastal zone, the number of new facilities there may rise to five or six. Following the same procedure, the pressure on the coastal counties in Wisconsin is seen to be substantially greater than that in Minnesota. Currently 59% of Wisconsin's generating capacity is located in coastal counties. With 8,881 MWe, Wisconsin comprises 6% of the Great Lakes Region's total generating capacity. Based on these figures, the potential number of new facilities required in the Wisconsin coastal counties ranges from 8 at a 3% growth rate to 20 at 8%. The resources required for these new facilities will vary depending upon the scenario. Assuming equal development of both nuclear and coal facilities the requirements in the coastal counties might be the following: land requirements — from 5,870 acres for 8 facilities to 10,675 acres for twenty; water requirements — for a closed-cycle cooling system from 100,000 gpm to 250,000 gpm, and for an open-cycle cooling system between 6.8 x 10 gpm to 17 x 10 gpm. With one-half of the new facilities being coal-fired the fuel requirement would range from 8 million tons/year to 20 million tons/year. Ohio's current generating capacity is approximately 25,225 MWe of which 21% is located in coastal counties. Under the regional projections, Ohio's coastal counties would need to accommodate 4 new generating units at the 3% growth rate and 19 at the 8% level. Again, assuming equal numbers of both coal and nuclear facilities the resource requirements would be within the following range : land — from 2,135 acres for 4 units to 10,140 acres for 19 units; water — for closed- cycle systems between 50,000 gpm and 237,500 gpm, and for open-cycle systems, 386 requirements would fall between 3.4 x 10 gpm and 16.15 x 10 gpm. The fuel requirements for the coal-fired facilities vary between 4 million tons /year and 19 million tons/year. New York's generating capacity is currently 29,000 MWe of which 27% is in coastal counties. The number of new facilities in the coastal counties would range from 7 plants at a 3% growth rate to 29 at the 8% rate. With these numbers of potential new coastal zone facilities the additional pressure on the coastal zone would be significant. The resources required for these new facilities break down as follows: land — from 3,740 acres to 15,480 acres for 29 new units; water — from 87,500 gpm for 7 units closed-cycle cooling to 362,500 gpm for 29 units. For open-cycle cooling these numbers range from 5.95 x 10 gpm to 24.65 x 10 gpm. Coal requirements would fall between 7 million tons/year for the 3% growth pro- jection to 29 million tons/year for the high growth rate. The State of Michigan has the highest percentage (73%) of its generating capacity (18,926 MWe) located in coastal counties. Michigan's coastal counties' share of the projected new capacity would be 11 units at a 3% growth rate and 51 units at the 8% level. The requirements on Michigan's coastal counties break down as follows: land — between 5,870 acres and 27,220 acres; water — in a closed- cycle-cooling system between 137,500 gpm and 637,500 gpm, and for the open-cycle 5 6 6 system between 9.3 x 10 gpm and 43.35 x 10 gpm. The coal requirements, assuming an approximate 50% coal fuel mix for projected base load generation, would range between 11 million tons/year and 51 million tons/year. The number of postulated new facilities in the coastal counties associated with the 3% growth rate might be assumed to accurately represent the minimum over the next twenty years. This is supported by the following: (1) "best guess" estimates for growth in energy demand hover around 5.5%, hence a 3% growth rate might reduce the errors in many of the assumptions made in the analysis, (2) the thermal loading of inland waters will increase the pressure on the Great Lakes for cooling purposes (a good example of which might be the Ohio River system) , and (3) the proportion of generating capacity currently located in the coastal zone (or utilizing land and water resources) may rise in the future rather than remain constant. At this time, it should be apparent that the demand for electricity over the next twenty years will be a major factor controlling pressures on the Great Lakes coastal zone with respect to energy facility siting. 387 2. RELATION OF PROJECTED ELECTRICAL AND FUEL DEMANDS TO FUEL TRANSSHIPMENT AND STORAGE The future demands for electrical energy production interact with the expansion and development of fuel transshipment and storage facilities in a complex and diverse manner. The discussion of this topic will center primarily on the effects coal movements may have on the future of these facilities. Oil, presently contributing a smaller percentage of the region's fuel mix, is expected to have a minor impact on the future development of ports and terminals. It was felt that the facilities were adequately developed to handle liquid fuels and that competition from pipelines and rail movement would, in the future, further reduce the relative percentage of this fuel moved on the lakes. Additionally, the questionable role of oil in the future generation of base load ' power was taken into account. Coal, which is expected to contribute to the major fossil fuel demands for power generation in the region, will continue to depend heavily on movement through transshipment facilities. Assessing the adequacy of these facilities is complicated by a number of intrinsic and external variables. In previous sections of this report the capacity of ports and terminals was analyzed from a historical perspective. In examination of the prior ten-year period it was determined that the system could presently double the coal tonnage moved on the Great Lakes. This would involve additional shipments of approximately forty million tons. The assessment, how- ever, does not specify the quality or origin of the coal transported. Under this evaluation, higher sulfur eastern and midwestern coal would contribute heavily to the total shipments through the facilities on Lakes Erie and Michigan. The relative percentage of eastern versus low sulfur western coal moved on the Great Lakes is crucial in any assessment of future impacts of coal on ports and terminals. This eastern/western mix is largely dependent on the development of low-cost technologies of sulfur removal either before or after combustion. The competition between rail and lake vessel movement is also central to an examination of future demands on ports and terminals. In 1975, 4.4% of the coal used in the eight Great Lakes states for electric power generation was moved on the Great Lakes [604]. Fluctuations in this relative percentage will naturally affect the impact that coal shipments on the Great Lakes will have on transshipment facilities. 388 The previous section developed a number of scenarios based on the future fuel mix for electric power generation. An examination of the scenario projecting a high coal fuel mix is most relevant to the future coal movement on the Great Lakes. A general discussion of impacts on ports and terminals can be developed through examination of this scenario. Analysis of projected activities at particular ports on the lakes is not feasible and would be highly speculative, considering the vagaries of future competition from other modes of transport and the relative utilization of high or low sulfur coal. It is possible, however, to analyze the overall implications of such a high coal scenario on transshipment facilities. Taking the 8% growth rate developed in the high coal scenario for electric generation as an upper bound, the fuel requirements are projected as an additional 820 million tons of coal for the eight Great Lakes states. Assuming Lake traffic contributes 4.4% to the total movement of coal for electric power generation, waterborne coal movement would increase by 36 million tons. It must be stressed that this figure is the product of extended extrapolations and as such becomes increasingly removed from the eventual realities of coal transshipment. Based on a relative fuel mix at a given growth rate, assuming an average heat value of coal and a relative percentage of lake movement, the figure of an additional 36 million tons by 1995 for utility use on the lakes should be viewed with guarded skepticism. This tonnage figure will be used strictly as representa- tive of a substantial increase in coal traffic on the Great Lakes and may rise to higher levels if shipping takes a larger share of the total transport market of coal to electric utilities. The impact of this additional tonnage demand on transshipment facilities can be discussed on a regional level varying the coal origin (eastern versus western) as it relates to the geographically specific locations of transshipment. If one assumes that utilities, in an effort to comply with air quality regulations and in the absence of efficient sulfur removal techniques, purchase western low sulfur coal, then the pattern and movement of lake traffic of coal will shift substantially. A considerable increase in western coal utilization of the magnitude previously described would place enormous stress on the facilities presently in use. This is compounded by the fact that generally western coal has a lower heating value than coal from eastern mines, necessitating even greater volume throughout. Facilities at Superior, Wisconsin and perhaps Chicago would handle much of the additional load. However, with the cost advantages in shipping 389 over long distances one would expect that additional facilities would be required and expansion of present coal handling ports would occur. It is difficult to project the location of the additional facilities on a site-specific basis, but relative to cost reduction in delivered price one would assume a maximation of the direct waterborne portion of transportation, encouraging further developments on the western end of Lake Superior. The high coal scenario hinges primarily on the absence of efficient low- cost sulfur technologies. With such development the pressures on transshipment facilities may return to the ports of the lower Lakes and specifically to the facilities on Lake Erie. The long-established and highly developed ports of this region would require less overall new development and expansion than would be expected for increases in western coal use. The upbound movement from these ports would facilitate the continuation of the traditionally economically beneficial iron ore/coal interchange at the Lake Erie ports. Either extreme of strictly western versus eastern coal is unrealistic. In this discussion the pressures on the transshipment facilities are examined from a perspective of the relative emphasis of coal origins. Utilities commonly blend coal of varying sulfur contents to achieve a mix that will meet air quality standards. Future demands on the movement of coal through transshipment facili- ties are largely a function of what the future mix will be as related to the economies and technologies of coal-fired generation and emissions control. 391 Chapter VI POLICY OPTIONS RELATED TO THE SITING OF ENERGY FACILITIES IN THE GREAT LAKES COASTAL ZONE A. INTRODUCTION The principal objective of this study is the development of a full range of policy options for the siting of energy facilities in the Great Lakes coastal zone. Institutional arrangements and technical-environmental-economic approaches are emphasized in the options. The institutional options cover options for: (1) siting policy, (2) organizational arrangements, (3) functional responsibili- ties, (4) siting procedures, (5) siting criteria and standards, (6) financial mechanisms, and (7) intergovernmental relations. The technical options include options for: (1) the exclusion of all new facility development from the coastal zone management area including access to coastal waters and related fuel trans- shipment; (2) exclusion of all new facility development from the coastal zone management area, but allowing coastal water access, related fuel transportation and product transmission through the coastal zone; and (3) inclusion of new facility development in the coastal zone management area except in designated sensitive areas in which additional development would be precluded. These options are only suggestive. No recommendations are made that a state or program should adopt any of the options proposed. The situation in each state will dictate the kinds of options it might employ in planning for and managing the effects of energy facilities sited in or near the coastal zone. Some of the options would entail major reorganization of institutions or revi- sion of siting criteria, regulations and standards. Other options suggest use of existing institutional arrangements or augmenting present siting criteria and regulation. 392 Selection of certain options will preclude choosing other options. However, selection of combinations of options within and among the categories mentioned above are essentially unrestricted. This listing of options is comprehensive, but is not intended to be exhaustive. The agencies affected will probably identify additional options and develop the details of these options as they relate to their respective programs, The energy growth rates used in this study (in Chapter V) do not affect which options might be chosen, but they do serve to suggest: how much emphasis a particular state might place on developing an energy facility siting program; how comprehensive that program might be in terms of facilities and fuels; what the areal extent of the program jurisdiction should be; which levels of govern- ment should be involved with the program; what involvement the state coastal zone management program might have in such a program; and what authorities and sanctions should be vested in the program. 393 B. INSTITUTIONAL OPTIONS 1. INTRODUCTION Options discussed in this section were derived from the study of exist- ing state programs for the siting of energy facilities and of various proposals for improving such programs. Where an option can be identified with a particu- lar state program, the state is indicated by its two-letter postal service abbreviation in parentheses. In this manner, the interested reader is directed to the appropriate state program description or to the state itself for addi- tional information. The options discussed in this section range from general approaches to more specific procedures and criteria that may be employed in the regulation of energy facility siting. The seven categories are: Siting Policy, Organizational Structure and Arrangements, Functional Responsibilities, Siting Procedures, Siting Criteria and Standards, Financial Mechanisms, and Intergovernmental Relations. 2. SITING POLICY Energy facility siting is closely related to numerous traditional functions of state government. In establishing policies to regulate energy facility siting, a state may choose to specify the relationship of the siting program to one or more of these functions, thereby imposing a philosophy of operation on the siting process. Several of these relationships and their possible impacts are described below. The lack of any such relationship would imply that utilities and other energy producers/distributers have almost com- plete freedom in site selection. a. Traditional Utility Regulation This approach represents the status quo in most states that have not re- cently enacted energy facility siting legislation. Traditional utility regulation has received criticism for a variety of reasons, including: failure to consider all aspects of the siting issue; lack of early public participation; the multi- plicity of independent local and state agencies with responsibility over some phase of siting; and the delays that result from this process. However, these "problems" do not seem to be inherent features of traditional utility regula- tion. The process may be improved by means of interagency agreements or orders 394 of the Governor, while maintaining the basic system of responsibilities. Implications . Possible consequences of this arrangement include subordi- nation of environmental considerations and the inability to address the broader issues of energy policy and land use. Without a legislative mandate it may not be possible to assure that the criticisms listed in the above paragraph are dealt with adequately. Utility regulatory commissions are traditionally con- cerned primarily with economic matters affecting service charges and return on utility investment and the safety and engineering aspects of facilities. The resolution of conflicts over economic and environmental issues, which are com- mon in energy facility siting, may require expanding the regulatory commission to include members with appropriate backgrounds. b. Energy Policy The siting function may be handled in the broad context of state energy policy. The emphasis would be on regulation/allocation of fuels to assure adequate supplies of each type for essential or best purposes, and also to assure adequate supplies of electricity. The program may include methods of limiting electricity demand and conserving energy in all forms. Implications i Projections of (electrical) energy demand indicate an esca- lating demand for sites. The siting function would be simplified if the demand for sites could be reduced by means of an aggressive state energy conservation program. Thus, the option of foregoing sites is contingent upon reducing demand . Another aspect of energy policy, the interchangability of fuels to provide energy, is also closely related to siting questions. For example, the fuel type of a power plant has definite environmental implications that affect the suitability of a site, while the choice of fuel type must be made in light of state or national requirements for alternative uses and for environmental pro- tection. Extraneous factors that affect siting decisions might include the environmental degradation accompanying the strip mining of coal, the scarcity of natural gas and its requirement for other industrial and domestic purposes, the precarious situation entailed by dependence on foreign supplies of oil, and the problems associated with the reprocessing and disposal of nuclear wastes . Combining the responsibilities for siting regulation and energy policy in one agency would facilitate these decisions. Lack of a coherent national energy policy also affects local and regional facility siting regulation by not 395 providing adequate direction for future fuel use, and thus the types of plants that should be constructed. c. Land Use Policies This option would treat all major construction projects, including energy facilities, as significant impacts requiring state approval. The emphasis would be on patterns of land development and regional economic and environmental impacts. A corollary to this option would be to limit land use control juris- diction to the coastal zone. Such an approach would recognize the unique and valuable aspects of coastal lands and the heavy development pressures they are subject to. Whatever energy facility siting process applied to the remainder of the state would necessarily be closely coordinated with the coastal zone manage- ment function. Implications . For the state to assume land use control requires the retaking of authority that has traditionally been relegated to local units of government. This may not be a popular approach, and heavy restrictions on the size and type of facility or project or the geographic area that would be sub- jected to state control may be required. It may be appropriate to recognize the regional nature of many large facilities, including power plants and other energy facilities, and provide for state control of their siting. Restricting control to the coastal zone would recognize the critical importance of this region and would satisfy the requirements of Section 306(e)(1) of the Coastal Zone Management Act. Less direct state land use control in the coastal zone is also an option under the Act. d. Pollution Control/Environmental Protection This option would place emphasis on pollution standards and the relevant technology to assure protection of air, land and water resources. Siting con- trol would probably reside with the state's environmental protection agency. Critical or fragile areas would be heavily protected. Implications . Environmental protection is a primary concern in energy facility siting. Historically, utility regulation commissions have placed more emphasis on adequate provision of energy than on environmental issues associated with energy production. In many states the environmental protection agency already has major responsibilities for issuing permits and certifying the environmental compatibility of facilities. It would generally be only a small 396 step to enable such agencies to have overall authority for site certification. However, it may be difficult to obtain unbiased decisions from an agency with an historic emphasis in one direction. e. Scope of Facility Siting Regulation Two basin options exist for the types of energy facilities subject to state regulation, though the intervening ground is a continuum between the two. One one hand, regulation may apply to all energy facilities: power plants, transmission lines, pipelines (gas and oil), refineries, transfer and storage facilities, and coal gasification and liquefaction facilities, and perhaps large scale solar collectors, etc. On the other hand, regulation may be limited to facilities constructed by regulated monopoly utilities (i.e., gas and electric companies) . This approach might even limit itself to power plants and trans- mission lines, in light of their high public visibility and the need to balance the demand for electricity with the protection of the environment and economic issues. Implications . The scope of facility siting regulation may depend on the overall responsibility or emphasis of the primary siting agency. If the state has a program to deal with energy policy, it may be feasible to regulate a broad range of facilities, whereas maintenance of the traditional system of utility regulation with a slightly broader scope to address siting issues might dictate a limiting of the regulatory process to utility-owned facilities. f . State Power Authority A state may elect to compete with or supersede public utilities in the matter of construction of base load power plants. A state power authority could construct and operate power plants and sell power at cost to utilities for ulti- mate distribution to customers. The power authority would have primary respon- sibility for selecting facility sites that are compatible with all aspects of environmental and economic concerns. Implications . Recent economic developments affecting interest rates, construction costs and fuel costs have raised doubts concerning the ability of invest or- owned, privately managed utilities to meet the future demand for elec- tric power. Numerous power plant plans have been delayed or cancelled. Imple- mentation of the state power authority concept would be a response to percep- tions of the present or potential severity of this situation. The state 397 authority would be able to borrow money at lower rates through the issuance of tax-exempt bonds and would not be required to pay stock dividends. The critical question in establishment of a state energy authority is: Who may best serve the public in the production of electrical energy; the pri- vate sector or the public sector? The private sector may argue that they have traditionally served the public well, that the profit motive guarantees con- tinued high quality service, and that the current regulatory process is a major source of difficulty. An evaluation of the relative merits of each side of the question is beyond the scope of this report. Interested persons might obtain the Brickley Commission Report, Governor's Advisory Commission on Electric Power Alternatives, State of Michigan, August 1976. 3. ORGANIZATIONAL STRUCTURE AND ARRANGEMENT S Within any of the general policy mechanisms discussed in the previous section, a variety of agency structures are possible for the regulation of energy facility siting. A state may elect to forego establishment of formal siting procedures, in essence leaving siting regulation in the hands of local zoning authorities. However, compliance with the Coastal Zone Management Act requires, at the least, that states establish criteria and standards to guide local authorities in establishing zoning restrictions in the coastal zone, sub- ject to state review and enforcement of compliance. The organizational arrangements discussed below are intended to apply to an agency or formal program for the regulation of energy facility siting. Sub- sequent institutional options will not necessarily require the establishment of a siting agency. a. Multi-stop Process This option requires review and approval by each agency with an interest in the various aspects of energy facility siting and is the process that has evolved in many states (IL, IN, MI, PA). The public utilities commission, air and water pollution control agencies, local zoning boards and perhaps several other state and local agencies would all be involved in the siting process. Within this framework, it is possible to establish a coordination mechanism that provides for the timely siting of facilities and minimum duplication through a unified application procedure and concurrent hearings. Implications . This option takes advantage of existing expertise within 398 various state agencies and does not unnecessarily tie up a permanent staff for infrequent siting work. However, even with provisions for coordination, the process will lack the ability to resolve conflicts among competing interests in the siting process, since no single body has such authority. The lack of public participation at the decision-making levels may adversely affect the credibility and responsiveness of the agency. b. Consolidation of Authority Again using existing agencies, but shifting primary responsibility to one or two agencies (WI) , this option facilitates the siting process by stream- lining it and providing for consideration of conflicting interests by a single agency. (Even where two agencies share responsibility, each would consider several opposing issues.) Primary candidates for this arrangement would be the public utility commission and the environmental protection agency. Local authority would be preempted. Implications . A shift in responsibilities of this magnitude would prob- ably require legislative action. The public utility commission would be in- volved only with regard to regulated utilities, so that in a program encompas- sing an extensive range of energy facilities it would be more appropriate to place major responsibility for site approval in an environmental protection agency, perhaps acting through a siting council within the agency. Certifica- tion of facilities constructed by regulated utilities would still be under the purview of the public utility commission. c . Siting Agency Composed of Heads of State Agencies The principal siting agency would be composed of the heads (or their designees) of the state agencies whose missions relate to or are affected by the siting of energy facilities (MD, WA, OR). This could include representation of the department of natural resources (DNR) , the state environmental protection agency (if separate from the DNR), the public utility commission, the department of economic development or commerce, the department of public health, the depart- ment of transportation and possibly others. It would also be possible to in- clude a representative of the state coastal zone management program on this coun- cil. The council would meet several times during the site approval process and engage existing agency staffs for requisite research and information functions. The chairman of such a council could be the head of the state agency in which 399 the state CZM program is situated. If organizational arrangements would pre- clude this, then the chairmanship could be shifted to the head of the state agency which has responsibility fof the state CZM program when the proposed facility affects the coastal zone. Implications . This approach would insure direct involvement in the siting decision process of the concerns and interests represented by the prin- cipal state agencies and draw on the varied expertise of the agency heads. It would also permit efficient transfer of information between supporting staff and siting agency members by using the existing lines of intra- and inter-agency communications, or by minor modifications thereof. The administrators are familiar with the details of their respective policies, programs, and legal authorities and are well equipped to evaluate siting proposals in terms of these factors. Adequate consideration of coastal zone policies could be achieved if the CZM program were represented directly or if the DNR representatives were to represent coastal zone interests as part of overall DNR concerns. This option does not provide for direct public participation in siting decisions. It would be necessary to provide extensive opportunities for public access to information and for the expression of public opinion. Insurance of adequate consideration of a wide range of the problems and needs associated with energy facility siting would be dependent on the comprehensiveness of the agency programs and the structure of the overall energy facility siting program. d. Public Members A siting council may be composed entirely of public members or only partially so. Public members would most likely be appointed by the Governor, possibly with state senate approval. The backgrounds of members may be speci- fied in order to insure a wide range of expertise or experience in applicable fields. It may be desirable to restrict the past and future employment of council members by those regulated (potential applicants). Implications . Direct public involvement enhances credibility with public members either representing the broad public interest or with a balance of biases (backgrounds) specified by law. Specification of backgrounds helps assure a wide range of expertise. Employment restrictions further enhance credibility and may be applied to nonpublic council members as well. Including public members on a council of state agency heads (MN) would 400 enhance credibility while taking advantage of existing exertise in matters related to siting. e. Hearings Examiners Various proposals exist for establishing a siting council based on the legal system. The council members would have both legal and technical back- grounds and would act as hearings examiners. The various interests involved would all be represented and the case would be decided on the merits of the arguments. Implications . The court system is currently used as a last resort in the adjudication of siting issues. Relegating siting responsibility to hearings examiners may reflect an increasing difficulty in reaching decisions under an- other system and a desire to obviate court action. This may be an effective means for rational decision making on siting issues, relying on the professional integrity of the small (three to five member) board of hearings examiners. f . Independent Staff Within the structure of an energy facility siting council such as c, d., or e. above, there may be established an independent staff to collect and analyze data on energy demand and other matters, to conduct environmental stud- ies on proposed sites, and to provide whatever other information the council requests. Implications . The requirement for an independent staff may be predicated on the amount of work to be done (number of facilities to be sited) which may depend on the range of facilities addressed. There are probably sufficient num- bers of power plants projected for each of the Great Lakes states to warrant an independent staff. The staff would help determine the need for energy facili- ties and could establish itself as a source of expert information on all aspects of energy facility siting. g. Ad Hoc Member (s) This option entails ad hoc representation on the siting council by a citizen of the region being considered as a possible site. Appointment may be by the legislative body (municipal or county) with jurisdiction over the pro- posed site, and the representative may or may not be a member of such body. Service on the council would be for the duration of deliberations on that site. 401 Implications . This option promotes credibility by assuring that the views of the affected community are expressed and considered in the siting process. But if the application process requires consideration of alternative sites, there may be two or three (competing) representatives of the several candidate communities on the council. 4. FUNCTIONAL RESPONSIBILITIES Several functions are associated with the regulation of energy facility siting. Of the functions listed in this section, not all would necessarily be performed in each state. Those which are performed may come under the purview of any of several organizational entities, including federal, interstate, state, intrastate, and local governments; the private (corporate) sector; and the general public. Within each of these categories, consideration is limited to the agencies that have been established with authority to undertake such respon- sibilities. The discussion of each function will attempt" to identify those en- tities most likely to assume responsibility for that function and the possible consequences of such delegation of authority. a. Long Range Planning Utilities and other potential constructors of energy facilities engage in long range planning, but such plans are often proprietary, leading to a "plan- disclose-defend" paradigm of energy facility siting. Long range planning, in- cluding demand projections and evaluation of alternative prospective sites, is an essential part of the overall siting process. If a state finds a need to regulate energy facility siting, one of the first steps is to regulate the pre- paration and disclosure of long range plans so that a comprehensive view of expected future development may be obtained. The desirability of such a future may then be evaluated and siting decisions made in terms of their impacts on the future. (1) Long Range Energy Planning and Forecasting Performed by Private Sector Without State Intervention Under this option, determination of long range energy demands and forecasts and evaluation of potential sites would be the function of the power industry. Plan disclosure would not be required, and the corporate sector would operate under its own guidance. 402 Implications . This option recognizes the technical expertise and monetary and personnel resources available to the private sector to invest in long range energy planning. If a state chooses not to engage in its own inde- pendent planning and forecasting, this approach assumes that the factors con- sidered and the assumptions employed by the private sector adequately reflect the problems and needs of the general public. Preliminary evaluation and selection of prospective sites would be based primarily on economic criteria and on compliance with existing federal and state environmental protection laws. There would be no assurance that there would be adequate consideration of the full range of problems and needs expressed by the general public. Since public disclosure of plans and forecasts would not be required under this option, public accountability of energy facility siting decisions would be very limited. (2) Independent Long Range Planning and Forecasting Performed by the State Independent long range planning and forecasting conducted by the state could be concerned with projections and trends of future energy use, and with future site and facility requirements. Implications . There are some advantages associated with state indepen- dent energy site planning and forecasting. First of all, the state is able to maintain a better overview of the total energy picture in the state. Factors affecting the various sectors of energy development and consumption could be evaluated in a comprehensive, coordinated manner, and the relationships between these sectors could be determined. This would facilitate the development of a unified, integrated, statewide energy policy and would serve as a sound basis for future siting decisions. One fundamental implication of this option is the underlying assumption that sufficient legal authority exists to provide for com- pliance with these plans by the private sector. If this were not the case, there would be no means by which to tie future siting decisions into such plans and forecasts. The lack of such adequate authority would limit the value of independent plans and forecasts to merely identifying the differences between the long range goals and objectives of the private and public sectors. 403 (3) Long Range Energy Plans and Forecasts Prepared by Private Sector with State Designated Guidelines and Criteria This option provides for regulatory oversight of private long range plans and forecast preparation. Under this approach the state would stipulate the conditions for plan and forecast preparation. This would involve promulga- tion of rules and regulations outlining procedural requirements, public parti- cipation in the planning process, identification of planning and forecast method- ologies employed, substantive content of informational requirements, the number and types of alternatives that must be examined, and other factors. It is also possible to include within these guidelines the criteria by which to assess the probable environmental impacts of the prospective sites outlined in the long range plans and forecasts. Another approach would be to require the evaluation of these sites in terms of some set of state designated site suitability cri- teria. Implications . This option implies legislated authority for government involvement in long range planning conducted by the private sector. It also involves public disclosure of energy plans and forecasts. There are several advantages associated with this particular approach. Opening the planning pro- cess up to public scrutiny greatly increases the accountability of actions by the private sector. Establishment of standards and criteria by which to pre- pare such plans and forecasts provides a well defined and consistent basis on which the private sector can rely. This reduces confusion, improves the efficiency of government, and limits unnecessary cost incurred by the private sector. Administration of such a program could be achieved by a public utility commission, a state energy office, the principal energy facility siting office, the lead coastal zone management agency, or some combination of these organiza- tions. b. Environmental Impact Assessment An important concern in the siting of energy facilities is the impact of the facility on the surrounding environment. Options for delegating responsi- bility for impact assessment include: (1) require the applicant for a facility site to provide a report on environmental impacts to the state; (2) assign the responsibility to a state agency; or (3) require that the assessment be performed by an independent consultant. The independent consultant may in turn be respon- sible to either the applicant, a state agency, or perhaps, the local 404 government with jurisdiction over the proposed site (NY). Implications. The credibility of impact assessments would probably be enhanced if the responsibility were placed with a government agency. If the actual study were performed by the state, it might be easier to achieve a uni- form methodology for comparing sites. If the assessment were performed by the private sector, assessment criteria could be established by the state. c. Final Site Approval Land use control (zoning) has largely been delegated by the states to local units of government. Retaking of a segment of this power by a state would involve major decisions. At the state level, final responsibility for site approval may rest with a siting council (NY, OH, MD) or with the Governor (OR, WA) or with the legislature. Legislative approval may be reserved for special cases such as nuclear power plants (VT) . The status quo in many states would keep zoning as the province of local units of government. However, com- pliance with the Coastal Zone Management Act requires that the state exercise at least a modicum of control over local zoning in the coastal zone. The Act lists two options short of direct state land use control: 1) state establishment of criteria and standards for local implementation, or 2) state review of all development plans, projects, and zoning regulations for consistency with the state's coastal zone management program. The state may choose to extend control in either case to the entire state. Note that this would effectively address all projects and facilities; not just those related to energy. Implications . Giving authority for site approval to local governments does not provide for consideration of the regional or statewide interests in- volved in large energy facilities. Distinguishing the control over coastal zone siting from that which applies to the remainder of the state may hinder the rational selection of a site from among coastal and inland alternatives. A state siting agency, with provisions for prior approval by the coastal zone management agency of proposed sites in the coastal zone (CA) , would provide for both consideration of state/regional interests and special attention to the coastal zone . d. Monitoring All states are required by federal law to monitor the quality of air and water resources within their jurisdiction. A state may choose to expand this 405 monitoring program to include a broader range of environmental factors affected by energy facilities (MD) . This would involve sampling of natural parameters such as physical, chemical, and biological effects, and cultural parameters such as changes in land use patterns and social and economic conditions associ- ated with the construction, operation, and maintenance of a facility. Responsi- bility for environmental monitoring could be: 1) delegated to local government, 2) assigned to a private consultant, 3) assigned to the energy corporation, or 4) placed with the state environmental protection agency or department of natural resources. Implications . A comprehensive program for monitoring the environmental effects of energy facilities would provide valuable insight into those aspects of energy development that are typically of greatest concern. It may also indi- cate substantive areas in which criteria and standards for energy facility sit- ing and for protection of air or water quality in general appear to be either overly stringent, reasonably sufficient, or inadequate. e. Conservation In recognition of the scarcity of energy resources on an economic or geographic basis, or of the adverse environmental impacts resulting from their use, the state may choose to implement a program of energy conservation. The scope of such a program may range from a requirement that utilities (and others) describe conservation efforts as part of their plans, to a state agency with responsibility for specifying building codes, appliance and automobile effi- ciencies and other measures to reduce demand and thereby reduce the number of energy facilities required. Implications . Energy facilities in general represent huge commitments of resources, including land, and have significant adverse impacts on the environment. If an aggressive state program for energy conservation can slow the rate of growth in energy demand, the effect should be to slow the rate of construction of energy facilities, and, thus, slow the rate at which siting decisions must be made and reduce the number of sites occupied at any given time in the future. Conservation can provide the siting regulation process with the option of not siting a proposed facility. For further details related to this option, the reader should consult Chapter V, Regional Scenarios of Energy Development. The discussion there concerns a range of electrical energy growth. The energy industry, as part of our economic system, is probably 406 dependent on growth for its economic well-being. In the regulated utility sector, a slower growth rate may require adjustments in the rate scheme, but this could be handled by the traditional regulatory mechanism. In the private sector, the gradual slowing of the rate of energy consumption could result in the shifting of economic resources away from energy production. 5. SITING PROCEDURES The siting process may entail a variety of procedures, most of which are independent of the responsible regulatory agency. However, the procedures listed here generally assume a strong state role in the regulation of energy facility siting. Several options and their implications are discussed for each of four procedural categories: the application process, site selection, treat- ment of generic issues, and funding. a. Application Process The regulation of siting implies that the construction of facilities will follow an application process to decide the merits of a site. The formal application may be preceded by a notice of intent to file such an application. Actions taken on the notice of intent would include a preliminary evaluation of the site and notification of potentially interested parties. Public hearings may be held on the notice of intent. The application itself may describe the site and the facility to be con- structed thereon. Public hearings would most likely be held at this stage with time limits specified for the completion of the site approval process. The state may require that the application include not only a preferred site, but one or more alternative sites as well. Coastal states may specify that at least one alternative be outside the coastal zone. A separate application process may be established for sites in the coastal zone. Implications . Requiring a notice of intent allows time for a prelimi- nary site evaluation before an application fee may be required. Public hearings at intervals throughout the site approval process help assure that the results are responsive to public needs and desires. The specification of time limits for the process assures the applicant that there will be no delays while allow- ing ample time for consideration of all aspects of the issue. Where the constructor of an energy facility is free to select which sites to propose, the requirement for proposing alternative sites allows comparisons 407 of the relative advantages of each site. This is especially important with re- gard to coastal sites where both the magnitudes of the advantages and disadvan- tages may be greater than for an inland site. The requirement for prior approv- al by a coastal zone management agency for sites in their jurisdiction insures protection of the coastal zone but denies the opportunity to compare the rela- tive merits of coastal and inland sites. With regard to comparison of coastal and inland sites, the reader is directed to the case Study and discussion of coastal dependence that appears in Chapter IV. A. 6. b. Site Selection Several options exist for a state to assure selection of acceptable sites for energy facilities. The normal situation would leave the decision to the constructor of the facility through the application process. Advance con- sideration of siting problems by the state may lead to one of the following: establishment of criteria to be used by the constructor in the selection of sites (MN) ; designation of regions of the state that are suitable/unsuitable for various types of energy facilities (OR); establishment of inventory of specific sites (MN) ; or actual purchase of land by the state for eventual lease or sale as sites (MD) . Implications . The plan-disclose-def end paradigm of site selection is no longer satisfactory when a state chooses to regulate the siting of facilities. An applicant for site approval deserves to at least be aware of the criteria that the state will use in evaluating the suitability of proposed sites. Estab- lishment of such criteria facilitates generic treatment of siting cases (see section c. below) and serves to reduce ambiguity in the decision-making process. The designation of suitable and unsuitable regions for various energy facilities may be used in addition to siting criteria. Such designations result from the application of certain criteria, most likely those related to air and water quality, to all regions (such as airsheds and watersheds) of the state, taking into account the expected environmental impacts of each type of facility. This would also serve to provide applicants with needed information to reduce wasted efforts of studying and proposing unsuitable sites. Carrying the process one step further, the state could establish an inventory of suitable sites, taking over the site selection function altogether. Potential applicants could work with the state in establishing the inventory and in proposing sites to be included. This may require the prior establishment 408 of criteria to be used in the selection of sites and the whole process might be relatively time-consuming and expensive, but once the inventory is established, siting would be a relatively simple process. The purchase of potential sites by the state can serve to assure that suitable sites are available, even if proposed sites are rejected. A revolving fund could be established to purchase an initial inventory of sites. c. Treatment of Generic Issues In the siting of energy facilities there are a number of issues that recur in the siting process. Such issues include: "questions of proper demand policies, allocation of research efforts, the amount of new capacity needed, and proper safety, environmental and land use standards" [613] . Some aspects of these generic issues may be decided upon separate from (and prior to) the site approval process. Some generic issues related to site selection are discussed in the previous section b. Implications . Treating common issues beforehand simplifies the siting process by reducing the volume of material to be considered in individual cases. It can also serve as a means for providing applicants with information that enables them to forego making proposals that are unacceptable to the state. Furthermore, separate treatment of generic issues serves to reduce ambiguity in the site approval process. d. Funding As a function of state government, the regulation of siting may simply be funded through the normal budgetary process. However, energy facilities offer a great potential source of funds that may be applied either directly or indirectly to the siting process. Assessments may be considered in two broad categories: application fees and annual fees. The two are not mutually exclu- sive. The application fee is a one-time charge to be paid upon submission of an application for site approval. The amount may be fixed or may be a variable charge based on the size of the facility, measured either in terms of its estimated cost or its design capacity (megawatts, barrels per day, etc.). The fee may fund the general operations of the siting process or be earmarked for a specific purpose, such as environmental impact assessment. An annual fee may be assessed against all potential applicants for an 409 energy facility site, or at least against those with existing facilities. The fee may again be a fixed fee, or a variable one based on the output of the facility in the past year, measured either in terms of quantity of output or dollar sales. The state may choose to determine an adequate sum for funding the siting process and associated functions and assess those regulated on a proportional basis. Implications . Making site regulation financially independent relieves the burden on the state's general budget and obviates arguments against the establishment of such a function on financial grounds. The resultant higher energy rates may slightly reduce demand. 6. SITING CRITERIA AND STANDARDS a. State Designation of Site Suitability Criteria The state may wish to develop a set of criteria by which to evaluate various energy facility siting proposals. These criteria could be quite general or they could be specified in detail. General criteria usually involve rather broad statements that relate to protection of the environment, provision of ade- quate supplies of energy, protection of the general public health, safety, and welfare, conformance with existing land use and/or energy plans, and other factors (NY, OH). Specific site suitability criteria involve a detailed analysis of the physical capabilities of the resources affected, the specific resource requirements of the types of facilities under consideration, and the probable environmental impacts of those facilities. These criteria can be translated into geographic areas within the state which represent varying degrees of suitability for energy facilities. The state could thus maintain an inventory of suitable sites by which to evaluate future siting proposals (MD, MN) . Implications . Site suitability criteria designated by the state would insure consideration of factors in the evaluation of alternative sites that are of statewide concern. If the criteria were structured to incorporate factors representing the broad spectrum of environmental protection and natural resources management policies, the site review process could be stream- lined and the relationship between these various policies and the resultant trade-offs could be identified and evaluated. The success of this approach depends largely on either a unified statewide land use policy, or an integrated, comprehensive set of policies which together represent an overall statewide policy. 410 The use of general criteria provides for consideration of general concerns about the environment, future energy needs, and other factors. It permits considerable flexibility in the means by which the criteria are satis- fied. However, past experience indicates that other state and federal laws that have taken this approach have been subject to a wide variety of interpre- tations in the early stages of applying such criteria, and a great deal of uncertainty often exists as to what is required to satisfy these general cri- teria. Through the application of specific site suitability criteria, it is possible to incorporate specific elements of existing state land use and energy development policy into the energy facility siting process. Such elements include air and water quality standards, soil erosion and sedimentation con- trol criteria, solid waste disposal standards, radiological standards, and other factors. It is also possible to incorporate other state policies and program elements such as areas determined to be of critical stae environmental concern, areas in which economic development is encouraged, natural hazard areas, and so forth. Establishment of energy facility site suitability criteria would prob- ably be achieved through promulgation of rules and regulations by the lead state siting agency, such as a public utility commission, a department of natural resources, a siting council, or some other agency. b. Separate Site Suitability Criteria for Different Types of Energy Facilties Separate criteria could be developed for each type of energy facility, such as petroleum refineries, nuclear power plants, coal power plants, etc. It would also be possible to establish criteria for different size facilities. Under this approach, proposed energy facilities could be grouped in generic categories and evaluated under separate site suitability criteria. Another approach would be to conduct a statewide inventory of sites that would be suit- able for these generically different types. Technical analyses would be con- ducted for the various types of energy facilities of concern to the state and specific resource requirements could be determined. The physical capabilities of air, land, and water resources to support these generic types could also be ascertained. Implications. This option could streamline the energy facility siting 411 process considerably. Similar siting proposals could be evaluated more effi- ciently, since past experience would identify those factors that are likely to warrant special consideration and those that are routinely similar. In order to implement this option a considerable amount of research and planning would be required. This may involve extensive monitoring of existing energy facilities (MD). c. Detailed Siting Criteria for the Coastal Zone This option would involve the application of detailed criteria to pro- posed energy facility sitings in the coastal zone of a particular state. This option presumes that the state had not established siting criteria for non- coastal areas. These criteria could be based on a detailed resource inventory of the state's coastal zone and could indicate suitability of various land and water uses in the coastal zone through consideration of areas of particular con- cern, permissible uses, priority uses, etc. In addition, coastal zone siting criteria could include factors such as environmental opportunities or con- straints determined by applicable air and water standards and other factors related to physical capability. Implications . This option could foster the achievement of policies for energy facility siting in the coastal zone in states where regulation of energy facilities is limited. Because the institutional framework for coastal zone management has been developed to a higher degree than that for non-coastal areas in several states, it may be easier to approach the energy facility siting prob- lem by working within the existing CZM planning framework. However, separate and distinct treatment of energy facility siting in the coastal zone, as opposed to a broader statewide approach, may result in a lack of balance regarding both coastal and non-coastal needs and problems. This problem could be partially eliminated if suitability criteria for energy facility siting in the coastal zone were developed with full consideration of the remainder of state, regional, and local policies, standards, and criteria relating to land use and energy development. In order to implement this option, enforcement provisions would have to be established to insure adequate consideration of these coastal- specific criteria in the siting process. This could be achieved by placing authority within the lead CZM agency, by establishing a mandatory review and comment process, or by formal or informal interagency agreements. 412 d. Point of Application of Suitability Criteria (1) Application of Suitability Criteria to Long Range Plans and Forecasts This option involves the application of site suitability criteria to the prospective energy facility sites identified in long range plans and forecasts. Two states (MD, MN) have taken this approach in the regulation of electric gener- ating plants. This option would involve evaluation of the land holdings of the various energy companies or of sites under consideration for acquisition. It would facilitate the development of an inventory of suitable sites within the state. Determination that a site was unsuitable could serve as grounds for elimination of that site from further consideration. Implications . The application of suitability criteria at the long range planning stage would have many desirable implications. For example, demonstra- tion by the energy development companies that a proposed site is deemed accept- able by a set of reasonable yet comprehensive suitability criteria would increase the likelihood that the site would receive final approval. This would greatly reduce the uncertainties associated with energy development, and may well reduce the regulatory lag time that has plagued energy facility siting in the past. This would also permit adequate lead time for local and regional interests to express their views and to adequately plan for the provision of necessary public services and to manage the resultant environmental impacts. This option implies some state involvement in development of long range energy plans and forecasts. It also implies that the appropriate decision- making body has authority to establish policies and procedures requiring com- pliance by the private sector. Presumably, satisfaction of the suitability cri- teria would constitute acceptance of a proposed site, and failure to satisfy the criteria would imply either outright rejection of the site or acceptance only upon satisfaction of certain site development conditions. (2) Analysis of Site Suitability at Time of Application for Approval This option would provide for the evaluation of the suitability of a specific site at the time of application for site approval. The private sector would conduct its own preliminary assessment of alternative potential sites and would choose a preferred alternative. In states where there is no principal lead agency to administer the existing energy facility siting program, 413 the suitability analysis at the time of application could be handled by the state coastal zone agency, by the state environmental review board, or by the principal environmental protection or natural resources management agency. Ade- quate consideration of regional and local problems and needs could be arrived at through a variety of organizational structures, review procedures, public involve- ment mechanisms, and other means. Implications . Under this option, it would be the prerogative of the private sector to conduct preliminary site suitability analysis according to its own criteria. However, the state-designated site suitability criteria to be applied at the time of application for approval would significantly influence the preliminary site suitability criteria employed by the private sector, be- cause pursuit of sites unlikely to satisfy the state-designated suitability cri- teria may be a poor investment of time and money. If the state criteria were sufficiently comprehensive and sufficiently flexible to allow for variable con- ditions, these criteria could serve as an effective set of guidelines by which state utilities and other energy companies could evaluate the suitability of their prospective future sites. The application of these suitability criteria implies some sort of state regulatory authority over energy facility site loca- tions. Such authority would be necessary if this approach is to be effective. e. Designation, of Environmental Impact Assessment Criteria for Site Evaluation A state may wish to establish criteria for the assessment of the envi- ronmental effects of siting proposals. Following the lead of the National En- vironmental Policy Act of 1969 (NEPA) , numerous states have taken the initiative in this area and have developed their own statewide environmental impact review processes (IN, MI, MN, NY, WI) . Other states (NY, OH) have incorporated assess- ment criteria in their power plant siting regulatory programs. Criteria can either be very general or quite specific. General impact assessment criteria are broad statements which permit a great deal of flexibility in their inter- pretation. Specific criteria often take the form of various categories of in- formation required, and often list specific data that must be collected to supply this information. These criteria can also include information that is required under the various federal and state permit programs in effect in the state, such as those required under the Clean Water Act (NPDES permit) and the Clean Air Act (permits to construct and operate), and state programs for 414 soil erosion/sedimentation control, resource recovery, critical area or resource protection, and other applicable programs. In addition, assessment criteria could be developed to reflect f actors of particular concern to the coastal zone. Implications . There are several advantages to stipulating environment- al impact assessment criteria for proposed energy facilities. Carefully de- signed criteria can include nearly all of the information and data require- ments included in the various permit systems, and can thus serve as a mechanism by which to streamline the approval process. Also, criteria that are clearly stated and well understood can serve as a solid foundation for adequate con- sideration of those areas of greatest concern in coastal and inland locations. This would also reduce uncertainty in the private sector about the kinds of in- formation that would ultimately be required in the siting process. Once a par- ticular set of impact assessment criteria has been applied to various proposed site locations, a correlation would be established between various kinds of energy facilities and the probable environmental impacts. 7. FINANCIAL MECHANISMS It is generally agreed that financial problems are among the most severe of problems currently facing energy development. These problems have arisen from uncertainties about governmental policies and from difficulties in capital formation in the private sector. If implemented, many of the options outlined above could streamline the regulatory process and thereby reduce uncertainties and resultant financial risks. For a number of reasons, the states may wish to employ various financial mechanisms to facilitate the wise development of energy. In addition to directly encouraging or discouraging the siting of new facilities, financial techniques can be employed to promote energy conservation and thereby reduce the need for new facilities, insure an adequate mix of fuels, encourage the application of new technologies, and ameliorate the adverse ef- fects of facility sitings. Options associated with these mechanisms can be categorized under three headings: 1) methods of generating financial resources, 2) direct public investment in energy development, and 3) incentives for energy development by the private sector. a. Methods of Generating Financial Resources Several options are open with regard to obtaining revenues for the 415 administration of various aspects of energy facility programs. The following list of such methods is presented to stimulate additional thinking in this area and is not intended to be exhaustive. (1) Appropriations from General State Revenues (2) Issuance of Industrial Revenue Bonds (3) Consumption Tax on Fuels and/or Energy Forms (4) Tax on Goods that are Less Energy Efficient than other Goods of the Same Type Due to Design or Construction (5) Tax on Energy-intensive Goods (6) Charges for Operating Source of Pollution (7) Federal Assistance from a Potentially Wide Variety of Sources (8) Fees for Site Applications and Long Range Plans and Forecasts. Implications . Numerous scenarios can be developed which incorporate one or more of these options with other institutional options outlined in this report. The implications of employing one or more of these revenue sources will depend on the details involved. No attempt will be made to elaborate on these implications. b. Direct Public Investment (1) Direct Siting of Facilities and Production of Energy (Electric Power) by the State This option and its implications were discussed above under Section 2 , Siting Policy. In particular see Section 2.f., State Power Authority. (2) Joint State Provate Sector Corporations This option would entail the joint financial underwriting of new energy facilities by both the public and private sectors. This would probably be most feasible for the electric and gas industries. Public and private sector siting considerations and investment criteria would be combined to determine siting de- cisions. Implications . Under this option, state government would be required to work closely with one or more of the various sectors of the energy industry to jointly finance new facility sitings. It is not inconceivable that such an arrangement may require extensive negotiations involving two sectors of society that are often diametrically opposed. Details of other phases of the siting 416 process, including long range planning, site selection, and site certification, would have to be clearly defined so that a high degree of visibility could be achieved in this potentially controversial arrangement. This option has the potential for providing the best features of both public and private sector involvement in energy facility siting. The state may be more able to provide a stable source of financial resources for facility development [457]. It can also provide adequate insurance, through the demo- cratic process, that public financial resources will be invested in projects that reasonably satisfy objectives for economic development, equitable distri- bution of resources, and environmental quality. (3) State Financing of Energy Facility Development by the Private Energy Corporations This option would involve state financial assistance to the energy cor- porations. Options for raising the necessary capital were presented in the pre- vious section. The probable means of financing would be state loans or loan guarantees. Implications . This option would require legislative authority to invest public resources in quasi-public (electric and gas utilities) or private (fuel production) energy companies. It is likely that the state would require that certain conditions or criteria be met by the private sector, although these would not be as extensive as those encountered with a more direct state involve- ment. c. Incentives for Energy Development by the Private Sector Options under this heading imply a lower degree of economic risk in ventures undertaken and probably a slower market response to the stimuli. (1) Positive Financial Incentives for Siting (a) Tax incentives Tax incentives can be used in a number of ways to encourage energy fa- cility siting. Investment tax credits could be employed to stimulate the development of associated facilities. Accelerated depreciation allowances might also be used to achieve these ends. In addition, deferred taxation may be applied to minimize immediate siting costs. The state may also wish to pro- vide credits against state income tax for local property taxes paid by energy 417 facilities. Implications , Tax incentives must be justified as an appropriate solu- tion to a well-defined problem (private market imperfections in the energy in- dustry) . They have been employed at the federal levels (oil depletion allow- ance) and they tend to come under close public scrutiny. Tax incentives would have to be designed to avoid undesirable redistributions of income. Tax incentives are related to the facility rather than to the site. Since facility development, operation and maintenance costs are very large com- pared to site acquisition costs, incentives to limit the former may be quite effective in stimulating new energy facilities. (b) Financial incentives for site location This option builds on the concept of the previous option. It may be desirable to provide strong positive financial incentives to site energy facili- ties at predetermined locations or at sites that are otherwise deemed suitable. This could be achieved by providing the tax incentives of the previous option for predetermined sites or for sites that meet state-designated suitability criteria. Such incentives would not be available for other sites. A variation on this option would entail state acquisition of suitable sites with the sites subsequently being sold to energy corporations at either a token price or at a somewhat reduced price. The previous option could then be tied into the arrangement. Implications . The legality of this option would have to be determined. In order to be acceptable, the use of this option would probably have to be based on well-defined long range plans for energy development and economic growth. Steps would have to be taken to insure equitable distribution of the related costs and benefits. (2) Negative Financial Incentives for Siting Options under this heading would be characterized by fees, penalties, or other charges to discourage the siting of energy facilities in certain areas or to provide a source of revenue to ameliorate the adverse effects of locating a site in those areas. This option could be used to discourage siting in coastal areas that are deemed unsuitable for energy facilities. Negative financial in- centives could be graduated to reflect the relative desirability of siting in 418 various coastal or inland areas. Implications . The employment of negative financial incentives implies a reactive approach to siting regulation. This option, along with other options that provide financial incentives or disincentives, should be based on a ra- tional plan for energy development in the state. Since these options tend to create spillovers into other sectors of the local or regional economy, the probable implications would have to be fully assessed. 8. INTERGOVERNMENTAL RELATIONS a. State-Federal Relations The federal role in energy facility siting outlined in Section III.B. indicates that there are several aspects of siting that involve federal agencies. Section 307 of the Coastal Zone Management Act (CZMA) requires that federal actions be consistent with approved state CZM plans. The Act also requires that states consider the national interest in the development of CZM plans and pro- grams. Greater coordination between the states and the federal government in energy policy and in the siting of energy facilities will promote economically efficient, publicly acceptable and environmentally sound energy development. The options described below suggest alternative mechanisms by which the Great Lakes states might interact with the federal government to achieve these objec- tives and implement the portions of the Act requiring consistency. (1) Coordination and Consolidation of Siting Procedures A variety of options exist under this general heading. These options are associated with the phases of energy facility siting regulation that are typically encountered in state siting programs. The approaches taken by a par- ticular state would depend on the siting procedures currently employed or on those that may be selected by the state from the institutional options outlined above. (a) Long range planning To align the long range plans and forecasts for energy development of the federal and state governments, the states may attempt to incorporate federal agencies concerned with long range energy planning (e.g., ERDA, NRC, FEA, and the FPC) into the long range planning process employed by the state. This 419 could be achieved by requesting extensive review and comment by these agencies on state plans, by requesting that these agencies attend public hearings and ad- ministrative meetings held by the state on long range plans and forecasts, and by seeking clarification of federal policy in various substantive areas address- ed in the state energy planning process. Implications . This option implies that the state has some involvement in long range energy planning. It may facilitate the identification of those aspects of state and federal energy facility siting policy that are likely to generate controversy and thus require special attention. Resolution of these issues early in the process will streamline siting regulation by reducing delays. (b) Involve federal agencies in the state site certification process This option would provide for direct involvement of the appropriate fed- eral agencies in the site review and evaluation process. Representatives of these agencies would participate in the internal review process by acting as resident liaisons between their respective agencies and the state siting bu- reaucracy and CZM agency. For example, representatives of the U.S. Environ- mental Protection Agency could interpret applicable air and water quality stan- dards as they relate to the specific siting proposal under consideration in the state application process. The FPC could evaluate the proposal (for an electric generation facility) in terms of the degree to which it increases the reliabili- ty of electricity production and meets well-defined energy demands. Other fed- eral agencies could be incorporated in the process as warranted by the types of energy facilities and locations involved. At the same time, federal agencies could take this opportunity to obtain state approval for federal actions affecting the coastal zone as required under the consistency provisions of the CZMA. Permits issued by the Corps of Engi- neers for structures in navigable waters or by the EPA for pollutant discharges could be discussed and a determination made with regard to joint state and fed- eral approval. Implications . Increased participation of the federal government in the state energy facility site certification process would have to be handled very carefully to avoid charges of federal encroachment in state siting matters. The important point with regard to this option is that the states as well as the 420 federal government could benefit from increased communication and cooperation in the certification of energy facility sites. This option would provide for enun- ciation in the siting decision process of the specific aspects of federal policy, such as site evaluation or site suitability criteria, and air, land, and water pollution control standards, which must be complied with, or which reflect those interests and concerns of society that are represented by the federal govern- ment. Importantly, the Coastal Zone Management Act requires consideration of the national interest in the siting of facilities that are of greater than local significance. Also, by bringing the federal agencies into the certification process, and by encouraging public participation, the states could facilitate the resolution of policy conflicts with the federal government. (2) Consolidation of State and Federal Environmental Impact Assess- ment Processes Federal agency environmental assessments under NEPA, and state environ- mental assessments required under a statewide program or under the state's energy facility siting regulatory program would be consolidated under this option. This could involve combined assessment criteria, uniform time limits, coordinated review procedures, and joint public hearings. This option could be applied to environmental impact assessments of prospective sites outlined in long range plans or of sites for which application for final approval has been made. These combined assessments could be performed by the lead state siting agency, or by a consultant, or the individiual agencies could contribute their respective inputs to be compiled, possibly by the state. Implications . This option would eliminate much of the duplicated effort that currently exists in the regulation of energy facilities. A significant savings of public resources might result. This option may also reduce the over- all time required to evaluate proposed sites. Each interested party could re- view the resultant impact statement with its own particular interests in mind. Impact assessment guidelines should be developed to insure that all significant impacts are addressed in the analysis. b. Options for Interstate Relations Many of the problems and needs related to energy facility siting can be handled either on an intrastate basis or through establishment of appropriate 421 state-federal relations. However, several siting issues will probably not be adequately addressed by these institutional mechanisms. It is with regard to these issues that a sound case for an interstate regional approach to siting regulation can be made. (1) Establishment of Multi-State Regional Siting Council This option would entail the formation of an organization by two or more states to deal with siting-related problems and needs that are not confined to one state. This organization could take a variety of forms. Membership would depend on the functions and authority assigned. Contiguous Great Lake states may wish to employ such an organization comprised of CZM program administrators to coordinate energy facility siting in the coastal zone. The influence of a regional CZM siting council would depend not only on the authority of the council itself but on that of the CZM programs within the respective states. Another approach to an interstate regional siting council would be to include as members the heads of the lead state energy facility siting regulation agencies. This would involve CZM considera- tions as part of the broader set of statewide siting considerations. If the principal function of the regional siting council were to assess the impacts of proposed sitings, the council might be structured to include heads of natural resource departments and/or environmental protection agencies, or representatives from state-level environmental review boards of citizen advisory committees. It would also be possible to establish a skeletal framework for a re- gional siting council and activate it on an ad hoc basis as the need arose. Implications . There are several advantages associated with this option. An interstate organization would provide a mechanism for the resolution of energy facility siting-related conflicts between states. It would also provide a single forum for interacting with federal energy-related agencies, and would strengthen the position of the states vis a f vis the federal government. With regard to electric power generation, the private sector, through federal en- couragement, has already recognized the need for such cooperation by establish- ing regional reliability councils to coordinate interstate electric power flows. Implementation of this option would require some form of agreement be- tween the states, such as parallel state legislation, memoranda of agreement or other mechanisms to bring the states together. 422 (2) Establish an Interstate Regional Siting Approval Process This option would entail joint approval of certain kinds of energy- facilities by the states involved. This process could be limited to those pro- posed sitings that would have significant, direct impacts on the environments of two or more states, or that will substantially alter the future availability of energy in two or more states. For example, the siting of, say, a large nuclear or coal-fired electric generation plant in a state's coastal zone may have significant direct impacts on coastal or other areas of one or more nearby states, and it may materially influence future growth patterns in those states as well. Implications . This option would necessitate a formal mechanism for agreement between two or more states. This implies either approval by a formal interstate siting council or the separate approval by the agency or agencies that have regulatory authority for siting in the states involved. In addition, approval by the federal sector (depending on the location and type of facility) would also be required, as would approval by other levels of organization within a particular state. The effectiveness of this option would be maximized if the individual siting regulation programs of the states involved were well defined and well coordinated with other environmental and land use policies and programs in those states. Public acceptance of this option would be critical to its success. This option also implies that the states participating in regional site certifi- cation are capable of and willing to adopt specific policies regarding siting- related issues to guide their actions in joint siting decisions. This option may act as a catalyst in forcing the states to delineate these policies. (3) Institute an Interstate Regional Process for Predesignation of Suitable Sites This option is an extension of one described earlier. It would involve the aggregation of sites deemed suitable by each state into an overall set of suitable sites in the Great Lakes Basin or some sub-region thereof. It could involve the entire area or only the coastal zone of each state. Implications . Through this approach the states could strengthen their bargaining positions with other levels of organization in the overall siting process. Also, this option fosters an active rather than reactive approach to siting regulation by identifying suitable sites, thereby indicating areas where 423 energy development could generally be favorably received. Identification and predeslgnation of suitable energy facility sites implies the application of some criteria by which to judge site suitability. The relationships between the suitable sites of adjacent states would have to be determined to avoid conflicts and to reasonably meet each state's goals and objectives for energy development, economic growth, and environmental quality. This option implies that the appropriate organizations and legal author- ities exist in various states to pursue a multi-state regional approach to energy facility siting. To be most effective, this approach requires active state participation in the preparation of long range energy resource and facil- ity plans and demand forecasts. An ongoing, multi-state, long range energy planning process would increase the rationality of siting and would largely determine the site suitability criteria and the priorities for siting new facilities with a particular state. This option would be strengthened if the states chose to acquire certain interests in sites and to encourage develop- ment on those sites through a promotional campaign. 424 C. TECHNICAL OPTIONS 1. FRAMEWORK The technical options related to energy facility siting and development with regard to the coastal zone have been arranged to provide a full range of policy choices consistent with the Coastal Zone Management Act of 1972. The three major groups of options have been categorized as they relate to jurisdic- tional decisions. They are: • Exclusion of all new facility development from the coastal zone management area, including access to coastal waters and related fuel transshipment • Exclusion of all new facility development from the coastal zone manage- ment area, but allowing coastal water access, related fuel transportation, and product transmission through the coastal zone. • Inclusion of new facility development in the coastal zone management area, except in designated sensitive areas in which additional development would be precluded. The coastal zone management area is defined as that area the Great Lakes states will designate as the coastal zone subject to their management program. The definition of coastal zone used by Coastal Zone Management Act of 1972, P.L. 92-583, is as follows: Coastal zone means the coastal waters (including the lands therein and thereunder) and the adjacent shorelands (including the lands therein and thereunder) , strongly influenced by each other and in proximity to the shorelines of the several coastal states, and includes transitional and intertidal areas, salt marshes, wetlands, and beaches. The zone extends, in Great Lakes waters, to the inter- national boundary between the United States and Canada and, in other areas, seaward to the outer limits of the United States territorial sea. The zone extends inland from the shorelines only to the extent necessary to control shorelands, the uses of which have a direct and significant impact on the coastal waters. Excluded from the coastal zone are lands the use of which is by law subject solely to the discretion of or which is held in trust by the Federal Government, its officers or agents (Sec. 304(a)). [582] "Coastal waters" means (1) in the Great Lakes area, the waters within the territorial jurisdiction of the United States consisting of the Great Lakes, their connecting waters, harbors, roadsteads, and estuary- type areas such as bays, shallows, and marshes; and (2) in other areas, those waters, adjacent to the shorelines, which contain a measurable quantity or percentage of sea water, including but not limited to sounds, bays, lagoons, bayous, ponds, and estuaries (Sec. 304(b)) [582]. 425 Assumptions included in this discussion of technical policy options are: • All present and anticipated environmental quality standards and controls will be a minimum requirement. • Guidelines of the Coastal Zone Management Act as presently stated will be followed in the development of the state CZM programs. It is intended that the following policy options provide a wide range of considerations but at the same time avoid any preference or bias toward either the conservational or developmental viewpoint regarding the future of the coastal zone. 2. DESCRIPTION OF OPTIONS a. Exclusion of All New Facility Development from the Coastal Zone Management Area Including Access to Coastal Waters and Related Fuel Transshipment New facility development in the coastal zone as well as all conveyance of fuel or coastal waters through the management area are excluded by this option. The aim of this option is to substantially reduce the impacts characteristic of energy facilities located in the coastal zone. Exclusion of all new facility development is visualized as aesthetically and environmentally beneficial. This option presumes a conservative attitude towards the development of coastal resources and considers energy facilities to be incompatible with conservation- oriented planning objectives in the coastal zone. In the discussion of this option, the implications developed will focus on many of the technical, environmental, and economic impacts associated with a policy of facility exclusions. Although the policy of exclusion may be the least viable of the three general options presented, this option is included to present a full range of options for the siting of energy facilities. Complete exclusion of new facility development from the coastal zone may not, in fact, serve the intent of the Coastal Zone Management Act to include the siting of facilities of national or regional concern. The Coastal Zone Management Act specifies that adequate consideration be given to the siting of facilities that serve the requirements of the national interest. Such characterization of energy facility siting may preclude an arbitrary exclusion of development within or through the coastal management area. This option is therefore presented to illustrate the range of coastal implications 426 associated with inland siting and is not designed to portray a prescriptive policy concerning energy. Implications . The primary intent of this option concerns the preserva- tion of the environmental, aesthetic, and recreational uniqueness of the coastal resources of the Great Lakes. The exclusion of new facility development from the coastal zone would permit sizable tracts of shoreline which would otherwise be used for energy facilities to remain in existing uses or be used for purposes of ostensibly less detrimental environmental impact. One would assume that a reasonable adjunct to this stringent policy framework would be an exclusion of similar large scale facilities, e.g., steel plants, from the coastal zone. Depending on the viewpoint, implementation of a policy excluding major industrial uses from the management area would either greatly enhance the flexibility of coastal resource planning or impose rigid, restrictive, and inflexible management of the area. Certainly, land no longer required for energy facilities or their associated access rights-of-way for coastal waters or fuels would be available for a wide range of uses. Public access to the coast could directly benefit, increasing the recreational and aesthetic value of the coastal zone. The natural characteristics of shoreline and near-shore areas not heavily used for recreation would be preserved by this option. The development of smaller scale, less resource-intensive, commercial activities might serve to offset the economic liabilities in the management area. Small scale activities like light industry may benefit particularly in develop- ment at sites once used for energy production. Land around decommissioned fossil- fuel energy facilities could be redeveloped for other purposes. However, redevelopment of a portion of a retired nuclear facility directly adjacent to the reactor vessel would be generally infeasible due to radioactive contamination of the site. Complete exclusion of new energy facility development in the management area would reduce the continuation of such long-term environmental impacts in the coastal zone. This option would also largely eliminate the milieu of short-term and operating impacts associated with the development of additional energy facilities in the coastal zone. The movement of fuels would depend heavily on inland modes of transporta- tion. The exclusion of access through the coastal zone for transportation of fuels would have a direct and significant economic impact on the future of 427 commercial lake navigation. The land and inland waterway transportation modes, train, pipeline, truck or barge, would assume the balance of additional fuel movement. The resulting reduction of cost-efficient Great Lakes vessel transpor- tation and the increased use of inland modes would generally raise the delivered price of fuels. A technical spinoff of the decrease in lake transportation of fuels could be an increased utilization of coal scrubbers. The availability of low sulfur coal from the western states has been abetted by the low-cost transportation rates via dry bulk vessel on the Great Lakes. The denial of future western coal trans- shipment from lake vessel to new facilities would shift the movement of this coal to other carriers. The resultant transportation costs may encourage utilities to revert to eastern and Appalachian sources and install sulfur scrubbing systems. A sulfur scrubbing system would then increase the acreage required for solid waste disposal. It is estimated that the use of sulfur scrubbers necessitates a 100 to 200 percent increase in land available for solid waste disposal. The expense of this additional land acquisition may be partially offset by the generally lower costs and increased availability of larger tracts of land inland than are commonly prevalent in the coastal zone. Moreover, the competition for land use is regarded as less intense inland than on the coast. The benefits in lower land acquisition costs are largely counterbalanced with the economies of inland water utilization. The use of inland water resources would in most cases require installation of complex cooling systems (mechanical or natural draft, spray ponds, canals, etc.), which in comparison to once-through cooling demand a higher level of maintenance and operation investment. The exclusion of access to coastal waters for cooling purposes would place enormous pressure on the inland water resources. It is questionable whether these resources could fully accommodate the increase in water demand. In some instances, this would require use of currently expensive technologies (e.g., dry cooling towers) and may result in installation of uneconomically sized units and/or the use of other types of technology for generating electric power which may not presently be fully developed. The policy of facility and access exclusion might also, over time, shift the existing pattern of power flow. The prevalent coastal power load might gradually shift inland as facilities on the coast were decommissioned, although some older urban sites would be redeveloped with energy facilities which might even use clean fuels. Depending on site location this trend may involve extensive 428 construction of high voltage lines to transmit electricity back to the coastal load centers. Overall, the implications would entail a general reorientation of transmission systems. Many of the technical drawbacks that have surfaced within the facility exclusion option would probably encourage research in and development of alterna- tive energy sources less dependent on water. Closed-cycle cooling systems would be an obvious component in inland siting. Perhaps other systems fueled by renew- able sources (e.g., solar, wind) might evolve under the constraints of non-coastal siting. The attempt throughout development of this policy option has been to stress the major implications that a program of energy facility and coastal access exclusion would involve. The orientation of such an approach is the future preservation of the unique resources of the coastal zone. While the approach in totality may be extreme and possibly would not comply with the provisions of the Coastal Zone Management Act, certain aspects of this option may be adapted within the CZM programs. The presentation of this option of total exclusion represents an effort to consider the full range of policy choices for the CZM programs. b . Exclusion of All New Facility Development from the Coastal Zone Management Area, but Allowing Coastal Water Access, Related Fuel Transportation, and Product Transmission through the Coastal Zone This general option excludes the major negative environmental impacts associated with energy facilities in the coastal zone, while allowing access to the most coastal-dependent features such as cooling water and fuel delivery, and providing corridors for transmission of products such as electricity and oil back into the coastal zone. In the following discussions of each option and its implications, references will be made to various types of access corridors and rights-of-way . These would include utility corridors and rights-of-way for transmission lines, cooling water pipelines, and for fuel and product conveyance, including coal and oil transport by pipeline, conveyor, barge, or rail. It is assumed that any necessary acquisition of corridors or rights-of-use would be accomplished through a fee simple purchase or a granting of easement where feasible. It is felt that the above general option is viable under the guidelines of the Coastal Zone Management Act because the exclusion of facilities from the coastal zone is neither complete nor arbitrary in view of the limited coastal 429 resources under consideration. Furthermore, exclusion of these resources from facility development would allow flexibility of planning by state CZM programs for potential uses of higher priority. (1) Limit Expansion or Conveyance of Construction of Conveyance Systems to Existing Corridors and Rights-of-Way Implications . Where feasible, this option would limit expansion of conveyance and development of conveyance systems to those corridors presently owned and developed for such uses, such as railroads, transmission lines, and pipelines. The primary intent and implication of this option would be to limit further commitment of coastal land resources to development of new access routes, while at the same time concentrating those environmental impacts associated with access routes (such as the above ground aesthetic intrusions and effects on adjacent property values and uses) along presently developed corridors. Restriction of future development to existing corridors would have an effect on conveyance capacity as well. In those cases where present capacity of pipeline, rail, transmission line, or barge conveyance is not being fully utilized, expansion of conveyance could conceivably take place without construc- tion. In those cases where existing conveyances are at full capacity, it might be possible to construct higher capacity systems on the same corridors. Finally, in those areas where existing corridors could support no further expansion in capacity, a necessary limitation on transportation and transmission capabilities would result from this option. If this option were implemented, it is possible that inland siting of energy facilities would be limited to those areas closest to the existing conveyance corridors, depending, of course, on the relative transportation costs outside the coastal zone. Concentrated conveyance use along existing corridors could result in an overall decrease of operation and maintenance costs, especially in cases where existing capacity can be utilized without new construction. In the case of below-ground transmission lines and pipelines, concentration of such facilities may involve strict control of above-ground land uses to provide for adequate access and maintenance. This latter possibility may involve fewer aesthetic or economic effects. 430 (2) Avoid Areas of Particular Concern in Determination of Access Routes and Rights-of-Way Implications . Areas of particular concern would include those areas designated by the state CZM programs according to the guidelines of the CZM regulations. Examples are areas of unique habitats, high natural productivity, substantial recreational value, significant hazard, etc. The implication of such an option would be to encourage preservation of and restrict use of such areas by siting access routes and conveyance corridors elsewhere or in such a way as to avoid them. In cases where the state would designate so many areas of particular concern that access through the coastal zone would be difficult, a limitation on conveyance capacity would result. (3) Disperse New Access Routes and Corridors Implications . A dispersal of access routes and conveyance corridors would presumably result in a corresponding dispersal of the environmental and economic costs and benefits associated with the specific conveyance. For instance, aesthetic impacts such as noise generated by rail traffic might be lessened due to dispersal of tracks. Likewise, economic benefits and costs derived from construction and maintenance of dispersed conveyances would be spread out over a larger area. Increases in land requirements due to dispersal within the coastal zone would increase acquisition costs and at the same time remove land from other or previous uses. Additionally, inland facility siting would tend to be dispersed, corresponding to the water and fuel access dispersal. (4) Concentrate Access Routes and Corridors Implications . This option takes the opposite tack from the previous option, but the implications fall into the same categories. Also, this option differs from option (1) by permitting new access and corridors in addition to existing access and corridors. Concentration of access routes and corridors would result in a corresponding concentration of environmental/economic impacts in specified areas. This in turn would confine impacts to the specified areas, while not further affecting other areas. In addition, economic benefits and costs associated with construction of new access facilities would be concentrated. The less even distribution of new access facilities along the coastal zone would permit the use of other lands for other existing or future uses. In conjunction 431 with this concentration of access routes, a corresponding clustering of energy facilities inland might possibly result. Land requirements related to this option would be greater than in the case of restricting new development to existing corridors, but less than in the previous option of dispersal. Costs of land acquisition would also increase. Finally, it is possible that the implementation of this option would have the overall effect of limiting transmission and transportation capabilities in the event that cost feasibility could no longer be justified. (5) Specify Development Areas Implications . This option would allow the state CZM programs or other state agencies to designate those areas which could be developed for access routes and conveyance corridors, thus facilitating long-range coastal zone planning. This option would blend well with option (2), which suggests determination of areas of particular concern, thus identifying those corridors which could be developed for access or conveyance with least negative impact on the remaining coastal zone. Additionally, the review and permitting process might be completed more rapidly, as these specified areas would be more acceptable to the reviewing agency, and therefore reduce in advance possible disagreement over the selected site. This option would shift the responsibility of corridor site selection from the utilities to the planning agencies and potentially present problems to the utilities in terms of their long-range expansion plans. Given the go-ahead to develop along specified areas, the net result might be a concentration of facilities and their associated impacts. This should be foreseen and planned for in the initial specification of development areas. (6) Develop Buffer Control Areas Buffer control areas here refer to zones bordering either side of an access route or conveyance corridor that would reduce or contain the visual and/or auditory impacts of facilities such as railroads, transmission lines, conveyor belts, or above-ground pipelines. This buffering effect might be accomplished by raised, landscaped mounds or simply by retention of a natural green belt during development. Implications . The reduction of visual and auditory impacts accomplished by the buffer zones would be offset to a certain degree by the increased costs 432 to the developer (utility or railroad) of additional land requirement and land- scaping costs. This ratio of benefits and costs would be of a site-specific nature. Such a buffer zone might have a positive effect on adjacent land values and uses. This option would effectively limit some uses of the land alongside the corridor such as industrial development or perhaps agriculture, but at the same time might provide increased public recreational areas where safety would allow. (7) Develop Multiple-Use Corridors and Rights-of-Way In the development of new access routes or corridors, or in the expanded use of existing ones, provisions for multiple uses of the land could be stressed or required. This would be restricted to those uses that would benefit from long continuous stretches of access such as would be expected along rail lines, transmission corridors, or pipeline paths. Such uses might include recreation, such as hiking, or bicycle routes, or multiple facility uses such as combining transmission lines with pipeline paths or rail routes. Implications . The intent and implication of such an option would be to increase the number of uses in a previously single-use facility route or corridor. This in turn would reduce demand on other coastal lands. Total land costs would be reduced for multiple users of rights-of-way, though construction and main- tenance costs might increase in the case of recreation development along rights- of-way. In the case of multiple conveyance use of rights-of-way, a combination of conveyances could possibly significantly increase the visual or noise impacts to the point of offsetting those benefits gained from multiple use. Finally, increased safety hazards resulting from increased public use of conveyance corridors would require appropriate safeguards. (8) Establish Limit on Resource Utilization Within this report, figures have been developed for the various resource requirements of different energy facility types. This option would specify the amount of land or water that might be used by energy facilities and thus limit the development or use of access routes or corridors through the coastal zone as determined by utility/CZM joint planning. This would probably require some form of legislation, regulations, or standards to facilitate implementation. Implications . This option would encourage conservation of land resources in the coastal zone and promote land use that will be of higher priority as future 433 demand increases. By limiting the amount of land available for development of access routes and corridors, inland facility development would necessarily be controlled by capacity limitations of access routes or might be displaced to other coastal zone locations. Limitations on water resource utilization would be intended to preserve coastal water quality and quantity for future use and development, as well as for future development of the shoreline. A limit on water availability for cooling and other uses would result in reduction or displacement of water consumption and have impacts on water quality. It would likely encourage development of technolo- gies which use less water or return higher quality water to the environment. This, in turn, could increase the cost of using water. (9) Provide Financial Assistance to Affected Areas for Impact Assessment and Amelioration (a) Impact assessment Implications . The intent of this option is to direct monies collected from the utilities or facility owners, or provided by the state or federal govern- ment, to the areas affected by proposed facilities for impact assessment. This would ostensibly improve initial assessment and aid identification of potential impacts early in the facilities planning stage by aiding local planning efforts. Additionally, this option would increase public involvement in both the planning and decision-making process. In providing for local input to impact assessment, this might also result in an overall increase in time taken to reach decisions. Also, regardless of who provides the monies, planning costs will increase. Finally, the increase in money for local planning efforts would provide for added employment in the impact assessment field, e.g., consultants or planners. (b) Impact amelioration Implications . Provision of monies for amelioration of impacts associated with energy facilities access routes would increase costs but also increase local benefits as a result of potential upgrading of environment in the vicinity of the facility in question. It would also obviate negative impacts of access route development. 434 (10) Use Technologies Requiring Least Land Area for Access Rights- of-Way Implications . It is intended that this requirement would result in preservation of coastal land for future higher priority use and development. This option would encourage both the use of existing technologies and development of new technologies that would require less land. Development costs might increase but land costs would decrease. Examples of such technologies might be coal slurry pipelines replacing short haul rail routes, or narrower or underground transmis- sion line requirements . c. Inclusion of New Facility Development in the Coastal Zone Management Area, Except in Designated Sensitive Areas in Which Additional Development Would be Precluded This set of options is designed to address the present status of energy facility siting, which places no geographical or locational restrictions on siting in the coastal zone, except in designated sensitive areas. These options are intended to maintain the present policy of siting in the coastal zone management area but suggest possible limiting or restrictive policies which would enhance or preserve coastal resources for future use and development. All facilities previously described in this report are included for consideration, and the support materials regarding facility type descriptions and associated impacts serve as the basis for the option selections. The implications following each option are intended to look at the ramifications (intended or other- wise) of an option if implemented. Furthermore, it should be realized that these options are not presented for blanket approval and implementation. It is possible that they may be implemented individually or in combinations where feasible. It is equally possible that none of the options will be implemented as presented. It is felt that this group of options represents a framework of potential policies that could be most easily implemented by the state CZM programs, short of doing nothing at all. Under the Coastal Zone Management Act and its amendments, the state programs will have management responsibilities for those lands and uses of land having a direct, and significant impact on coastal waters. The following options suggest various forms of management of new energy facilities in the coastal zone. 435 (1) Limit Expansion or Reconstruction to Existing Industrial or Utility Areas This option would prohibit Commitment of coastal lands and other resources to future energy facility development by restricting new development or capacity expansions to those areas presently developed for such uses. Implications . This option would require new electric generating units to be built on sites which have already been developed for electrical generation, thus increasing productivity per unit of land without increasing land requirements, Presently, large tracts of land are developed for generating facilities with only a small percentage of this land being utilized for the generating plant (see facility descriptions on coal and nuclear facilities) , allowing for potential expansion. Those environmental/economic costs and benefits associated with facility development would be concentrated at existing sites as a result. However, many of the negative environmental impacts associated with site preparation would be avoided and associated costs would be less also. Some environmental impacts of operation and maintenance would be concentrated and thus further degrade the quality of the existing site. Economic benefits would be restricted to specific areas of previous facility development. In cases where existing energy facility sites could not technically support further expansion, generating or refining capacity would be displaced to other or non-coastal sites. (2) Avoid Areas of Particular Concern, Including Sensitive Areas Areas of particular concern would include those areas designated by the state CZM programs according to the guidelines of the CZM Regulations. Examples are areas of substantial recreational value, significant hazard, and great sensitivity, such as areas of unique habitats and high natural productivity, as well as others. Implications . This option would preserve applicable coastal resources for future development possibilities and provide for protected environmental preserves It would restrict facility siting in the coastal zone, intensify competition for remaining coastal areas between energy facilities and other uses, and could ultimately promote inland siting in those cases where remaining coastal lands are not sufficient or satisfactory for energy facility development. 436 (3) Encourage Development of Dispersed Siting Implications . Dispersed siting of new energy facilities or a deliberate spatial distribution of new developments would tend to disperse environmental impacts and at the same time increase systems reliability. This option also would have the effect of increasing construction and fuel transport costs as distance from load centers increased. To offset long distance transportation costs it is entirely possible that an increase in development of fuel transshipment facilities would result. Economic costs and benefits associated with facility construction and operation would be more evenly distributed but would increase or decrease depending on the site specifics. (4) Encourage Multiple Unit/Single Site Development This option would allow development of new areas of coastal land, but in a manner that would obtain the highest energy production per unit of land. Implications . It is felt that implementation of this option would have the effect of reducing land requirements, therefore preserving coastal lands for future use. It would reduce development costs per unit of energy and would reduce transport and transmission costs. As with the first option in this section, this option would tend to concentrate the environmental/economic costs and benefits in specific areas. (5) Specify Development Areas State CZM programs, in addition to designating areas of particular concern, would specify those areas, including energy resource areas, remaining in the coastal zone where facility development would be permitted. Implications . Ideally, this would provide the coastal zone planning agency with some control of the degree of concentration of facilities and their impacts. In addition, it would facilitate future coastal zone land use planning. Adoption of this option would remove some control of the site selection process from the utilities and shift the burden of planning to the state CZM or other planning agencies. Because of the intricate nature of suitable site selection for such facilities as nuclear and coal-fired power plants, an expansion or addition of necessary expertise within these agencies would be required. Hence, there would be an employment benefit, but this would be offset by the increase in costs of this added responsibility. 437 (6) Specify Facility Type and Size in the Coastal Zone Based on their associated impacts, only certain types of facilities determined by the CZM agencies would be allowed to site in the coastal zone. An example of this would be to allow the coastal siting of nuclear plants with cooling towers rather than coal-fired plants with once- through cooling. The intent here would be to specify a facility which does not commit large areas of land to coal and fly ash storage and does not have significant entrainment/ impingement impacts on the lakes. This is only an example and does not indicate a preference. Implications . This option, if implemented, would provide for control of the type and scale of impacts to be permitted in the coastal zone. Because of the extensive planning required to determine what impacts will and will not be acceptable, an increase in cost of planning programs is foreseen. Likewise, development costs and associated planning problems would increase for the facility owners. (7) No Restrictions on Facility Type and Size in the Coastal Zone This option, while assuming that present environmental standards will be maintained, provides for no further siting restrictions or controls with regard to the coastal zone. Implications . The intent of this option would be to promote the most rapid and inexpensive development of energy facilities per unit of production and capacity. This would allow the utilities to more readily "meet America's growing energy needs. " (8) Give Coastal Development Priorities to Energy Facilities This option would give first priority to energy facilities in the develop- ment of coastal lands. In other words, if a tract of land might be available for an auto plant development or a refinery, under this option the refinery would be given priority by the state CZM program. Implications . Implementation of this option would provide for lower cost energy production by facilitating utility access to fuel and water resources. This would also encourage lake transportation of fuels and promote expansion of harbor and transshipment facilities. In addition, this option would reduce coastal land and other resources which might be used for other development. Facility impacts on the coast would 438 increase, e.g., thermal loading from cooling water, aesthetic intrusions of transmission lines, and increase in construction employment. This option would increase coastal zone transmission capacity requirements in areas devoid of previous development. (9) Site Close to Existing Transshipment Facilities Implications . The intent of this option would be to decrease costs and negative environmental impacts associated with the transportation of fuels within the coastal zone. Land committed to these conveyance systems would be reduced as well. This option would limit siting alternatives, depending on the number or variety of transshipment facilities in existence. The merit of this option would depend also on the relative location of the transshipment facility to major transmission systems. In some cases, higher cost of transmission would offset fuel transportation cost savings. Expansion of existing transshipment facilities might necessarily follow, as generating plant fuel demands increased in a concentrated area. This cluster- ing of plants in the vicinity of transshipment facilities would concentrate those economic benefits and environmental costs as well, resulting in either a financial shot in the arm for the local community or an environmental eyesore, depending on the quality of planning. (10) Locate in Proximity to Existing Electric Power Grid The elect?ic power grid is the network of extra high voltage (ehv) trans- mission lines used for regional distribution of electricity. The intent of this option in contrast to the preceding one would be to site close to the transmission system to reduce construction and maintenance costs of new tie-in lines. Implications . This would reduce those environmental and economic impacts associated with the construction and maintenance of new transmission lines required to tie distant generating facilities into the power grid system. This would increase the cost of fuel transportation and water conveyance in those cases where the existing power grid was not near the coast. Siting alternatives would necessarily be limited as a result of this option, and in some cases capacity of existing systems might have to be increased to handle new generating demands . 439 (11) Assign Priorities for Facility Development to Those Facilities Employing By-Product Utilization By-product utilization includes use of waste heat from generating plants for industrial processes, mixture of fly ash with asphalt, utilization of thermal discharges for mariculture, and others. Implications . This would reduce the local negative environmental impacts associated with fuel utilization, such as air pollution, waste storage, and cooling discharges, and at the same time promote efficient use of resources. By prioritizing siting, an incentive for development of by-product utilization would be established. Operating costs would be reduced overall because of more efficient utilization of primary fuels. Development costs would necessarily increase in order to make these by- product usages technically and economically feasible. Symbiotic siting of generating facilities and industrial users of by-products would result in concen- tration of environmental/economic impacts in specific areas. (12) Develop Buffer Zones As specified in the second set of options, buffer zones are areas designed to reduce or contain aesthetic intrusions associated with energy facilities. Examples might be green belts surrounding refineries, preservation of natural areas around power plants, or vegetated berms around coal storage areas. Implications . Development of buffer zones would reduce visual, auditory and other impacts on the human senses which may be undesirable. Green belts have been shown to naturally filter out some types of air pollution. In some cases, increased recreational use may accompany development of buffer zone areas. However, uses such as industrial development would be restricted. Costs of developing these buffer zones would fall on the owners of the energy facility contained within and therefore raise the cost of the facility overall. (13) Maintain or Increase Public Access to the Shoreline in the Event that a Facility's Property has Shoreline Frontage Under this option the new facility owner would include plans for public access to shoreline areas if his property includes shoreline. Implications . Ideally, this option would provide for increased public access to scarce shoreline areas for uses such as recreation. This would in effect shift some of the burden of public access acquisition and development from state and local agencies to utilities and facility owners. Development costs 440 would increase for the utilities, but these might be passed along to the consumers. There might possibly be restrictions to this option in the case where safety regulations would not allow such activities (i.e., nuclear safety exclusion zones) . (14) Establish Restrictions on Cooling Type Implications . This option would provide stricter controls on those environmental impacts associated with condenser cooling methods. The environ- mental control and planning agencies, rather than the utilities, would select cooling systems and would decide which type would be most desirable in the coastal zone. This might result in a decision to ban flow-through cooling because of negative effects on aquatic life, or a ban on cooling ponds because they require large amounts of land area. Finally, the costs to utilities to implement these prescribed cooling types might be so restrictive as to encourage inland siting. (15) Adopt Air and Water Quality Standards Compatible with Coastal Siting This option would allow the state CZM programs to suggest stricter environmental standards for energy facility operation in the coastal zone. Implications . The thrust of this option would be to improve air and water quality, or at least prevent further degradation of coastal environments. This option would increase costs of environmental controls, and in cases where these costs would be prohibitive, discourage coastal siting. It is entirely possible that adoption of stricter environmental standards for the coastal zone would result in a favoring of those facility types which most easily meet the new standards. However, as noted in Section III.B.l.d. of this report, the states may not be able to adopt stricter (or more lenient) environmental stan- dards specified only for their coastal zones. (16) Provide Financial Assistance to Local Areas for Impact Assess- ment and Amelioration (a) Impact assessment Implications . Similar to option (9) (a) in the second grouping, this would provide monies to the area affected by a proposed facility to aid local planning agencies in initial identification of potential deleterious impacts. This would 441 increase public involvement in the planning process and decision making. This might also increase the time required for decision making. Increased employment in the planning and consulting field would result from these monies, but these planning costs would have to be met elsewhere. (b) Impact amelioration Implications . Monies allocated for this purpose would obviate negative impacts of energy facilities and may in the long run increase benefits to a local area due to overall increases in environmental or economic quality. (17) Permit Shoreline Site Location of Energy Facilities This option would permit the location of power plants and refineries next to or near the shoreline, as well as permit the use of coastal resources. Unless shorelines are presently zoned for other uses, this option is essentially the status quo. Implications . This option would result in shoreline use for energy facilities, thereby precluding its use for other major development or conserva- tion purposes. However, with proper planning, other uses could be accommodated in some areas of the energy facility site. The development of the land near shorelines and its use for energy facilities might possibly induce local shore- line damage. By competing with other possible uses of the shoreline, energy facilities development of the shoreline might increase its value and local land acquisition costs. The presence of an energy facility next to or near the shore- line may also affect adjacent land values and uses. By doing so, commercial- industrial development of the shoreline may be encouraged, possibly discouraging other uses of neighboring shorelines. Related to these considerations are the visual-aesthetic effects of large facilities on the shoreline. An advantage of shoreline or near shoreline location is that docking facilities might be developed for water transportation of fuels and other materials, if water transportation is less expensive. Shoreline location would also provide ready access to water for cooling or other plant processes. (18) Specify Shoreline Setback Distance for Energy Facilities Under this option, a setback distance for energy facilities would be required. The setback distance could vary depending on the location and local conditions and characteristics. The setback requirement could be established 442 by local ordinance or by legislative action. Such a requirement could affect fuel storage areas for docking facilities, but not the docking facilities them- selves. This option would not be intended to affect access to coastal resources for the facilities discussed in this report. Implications . By specifying a setback distance for energy facilities, the integrity and aesthetic qualities of the shoreline would be preserved. This option might increase multiple use of shoreline property if public access were permitted; i.e., the property could be used for access to coastal resources and for recreation. A required setback distance for energy facilities would increase capital and operation costs for a pipeline and pumping station, particularly if once-through cooling is used and/or the increase in elevation is large between the water source level and the plant. Additionally, if fuel or products are received by water transportation, transportation costs of these materials would be increased. For a discussion of these increased water provision and transpor- tation costs, the reader is referred to Sections IV.A.5 .b . (1) . (a) and (b) of this report. The use of a setback distance might also affect adjacent development along the shoreline as well as development behind the setback distance. For example, the setback line might preserve shoreline for natural or recreational uses on the property affected as well as encouraging such uses on adjacent areas. This situation may influence adjacent land values also. Behind the setback line, commercial-industrial as well as residential development might cluster, depending on provision of roads and utility services. The use of a setback distance might also encourage companies and govern- ments to purchase property for energy facilities that would not have property frontage on the shoreline, as long as resource access was available, such as through the purchase of an easement. With respect to the distance considered for setback, a 1000-foot setback for the plant and appurtenances might be similar to not having any setback require- ment at all. This would be particularly true in the case of aesthetic and shore- line use effects. A setback distance approximately 1/2 to 1 mile might be more beneficial from the aesthetic and shoreline use standpoints, but would involve some incrementing water provision costs and possibly transportation costs. However, as in the case of the Pleasant Prairie facility in Wisconsin, an inland location may be advantageous to tying in to the existing transmission system. 443 (19) Permit Only Those Facilities Absolutely Requiring Shoreline Location to be Located on or Near the Shoreline This option would necessitate some kind of legislative action at the local or state level. It would be similar to zoning areas for particular uses; in this case, zoning certain shoreline areas for particular energy facilities which absolutely require a shoreline location. Under this option, energy facili- ties would still have access to coastal resources. Implications . This study has not identified any energy facilities, except docking and transshipment facilities for water transportation, which absolutely require shoreline locations. This option would permit areas along the shoreline to remain in existing use or to be used for other purposes, rather than be used for energy facilities. Considerations for shoreline location should emphasize economic as well as environmental factors. Inland locations in some areas may result in significantly greater economic costs which may not be warranted, even when compared to the environmental effects. Thus, this approach would have to be used on a case-by-case basis, and yet applied stringently enough to have a recognizable effect on shoreline uses. This option might place considerable emphasis on a state-required environmental report on energy facili- ties, an approach already adopted by some Great Lakes states. Other implications such as effects on shoreline and inland development, tie-in to the transmission system, and water provision and transportation costs would be similar to technical option (18) above. D . SUMMARY The institutional and technical policy options provide a broad range of directions that the states and their coastal zone management programs might take. The options in the various categories serve to highlight the many possibilities for: (1) developing new institutions to address the current and complex problems related to energy facilities siting; (2) utilizing existing institutions with new or expanded arrangements among them and, in some cases, additional responsibili- ties; (3) developing financial approaches to assist the companies and governments involved in energy facility siting; and (4) developing technical, environmental and economic approaches to locating energy facilities with respect to the coastal zone management area and the shoreline. Particular emphasis was given to integrating these options with state coastal zone management programs. Selection 444 of some options within certain categories necessarily precludes choosing other options within or among the categories. For the most part though, the selection of combinations of options in various categories is unrestricted. Individual or collective decisions by the states and their CZM programs regarding well-defined policies for review and examination of guidelines for energy facility siting may assist the utility companies and other energy-related industries in their short and long range planning for facilities. 445 Chapter VII SUMMARY AND CONCLUSIONS This study covers several broad subjects related to energy facility siting in a manner that should be useful to the Great Lakes coastal zone manage- ment programs. Some general conclusions from this study can be made in each of the major areas of analysis. A. INSTITUTIONAL CONSIDERATIONS At present, four of the eight Great Lakes states (Minnesota, New York, Ohio, and Wisconsin) have instituted concerted and fairly well defined site selection processes for electric generating facilities. However, these states have not addressed to a significant degree the selection of sites for other types of energy facilities. The four remaining states have only limited involvement in the regulation of sites for all energy facilities, and have concentrated primarily on the certification of a proposed facility with respect to compliance with standards for air, water and land resource protection. In all Great Lakes states, policies to guide the siting of energy facilities in the coastal zone are in the early stages of development. The authorities of several federal agencies, notably the Nuclear Regula- tory Commission and the Environmental Protection Agency, will have a significant influence on energy facility siting. The policies, standards and guidelines of the EPA for the protection of air and water resources define a framework within which other agencies or interests of the public and private sector may operate. The greatest federal impact on future selection of sites for energy facilities will probably be through the Coastal Zone Management Act of 1972 and its 1976 Amendments. Several provisions of the Act deal with energy facility siting. 446 With respect to incorporating energy facility siting policies into a comprehen- sive program for coastal zone management, numerous institutional options are available to the states. The Coastal Zone Management Act allows the states considerable freedom in the development of plans and in the establishment of programs for the management of their coastal zones. The mere fact that such plans and programs are being developed, that they will be reviewed and approved at the state and federal level, and that subsequent actions must be consistent with such plans, will introduce a measure of comprehensiveness and coordination to energy facility siting as well as to the entire process of resource management for the coastal zone. The requirement for a planning process for energy facilities in the Great Lakes states coastal zone management programs provides the foundation for energy facility siting programs that address and emphasize the problems and opportunities of energy facility siting in the Great Lakes coastal zone. B. TECHNICAL CONSIDERATIONS 1. FACILITIES SITING AND COASTAL DEPENDENCE The major types of energy facilities included in this study — fossil-fuel and nuclear power plants, coal and oil transshipment facilities, and refineries — were described and their particular site and resource requirements discussed. In addition, a discussion of their major environmental and economic impacts were presented and a framework for analyzing these "activity impacts" suggested. Finally, an analysis of some of the major cost components was given. Based on this material, a description of the coastal dependent, or nondependent , aspects of facility siting was presented. The major conclusion drawn from this analysis is that, like so many other siting factors, the degree of coastal dependence exhibited by an energy facility is a function of the facility type, the geographic area within which it is to be located, and the availability of alternative sites. In addition, certain facility types — refineries, fuel transshipment facilities, and coal conversion facilities — are not expected to have a major impact in the Great Lakes coastal zone during the period considered in the study. It can generally be concluded that an electrical generating facility does not require a location on or near the coast. However, certain aspects of the facility, such as cooling system and water provision, mode of fuel supply, local geological and topographical conditions, meteorology, location of the existing 447 transmission system, may make a coastal site more or less favorable than an available inland location. An evaluation of this degree of coastal dependence should be carried out for each proposed facility so that it can be compared to other, less displaceable, uses of the Great Lakes coastal zone. The following general conclusions can be sited with respect to the coastal dependence of power plants: • Facilities using once-through cooling must be located on or near the shoreline because of substantial inland transportation (pipeline) costs of water provision. • Facilities using closed-cycle cooling are less dependent on locations on or near the shoreline than are facilities using once-through cooling, assuming all other factors to be approximately equal. Site conditions will determine the type of closed-cycle cooling system used. However, the further inland a facility is located, the greater are the construction (capital) costs for water provision and blowdown pipelines. • For facilities using closed-cycle cooling, the cost of locating on the shoreline versus the cost of locating inland are essentially trade-offs between construction and operation costs for transmission lines, water supply and cooling facilities, facilities for delivery and handling of fuels, and other supplies, and disposal of waste material. • Nuclear facilities require very large and massive components, which in most cases are delivered by water transportation. However, rail or road corri- dors of adequate width and load-carrying capacity can be utilized for delivery of these components. If these rail or road cooridors are not available to potential sites, the location of nuclear facilities may be more dependent on shoreline or near shoreline locations. In any event, field assembly is becoming more common, thus possibly negating some of this shoreline dependence. Otherwise, nuclear facility coastal dependence considerations would be those in the previous conclusion. The coastal dependence of fuel transshipment and storage facilities and refineries can be summarized as follows: • Fuel (coal and oil) transshipment and storage facilities receiving or shipping their commodities by water must locate near the shoreline, although storage areas do not have to be located on the shoreline. Storage area location is highly dependent on industrial needs, future transportation requirements, and onsite and off site use of stored fuel. 448 • Refineries are not coastal dependent, but do need water for processing and cooling. Coastal dependence for water supply and wastewater disposal consid- erations is decreasing due to increased water recycling. Air cooling is also decreasing refinery dependence on easy access to water. Refinery location decisions are increasingly becoming market oriented, with decisions being made on a national basis, due to the existence of the national product distribution pipeline. The degree of coastal dependence exhibited by a proposed energy facility of a type discussed in this report may vary from nonexistent or slight, to very strong or complete, depending on a range of site and facility characteristics. In light of the limited, and in some cases unique, coastal land available in the Great Lakes Basin, an evaluation of the best use of the coastal land should be included in a site selection or approval process. In this way, use of the Great Lakes coastal zone can be reserved for those uses least suited to inland locations. While this may include energy facilities in some cases, it will ensure that a more comprehensive view of coastal development is taken. 2. ENERGY CONSUMPTION AND MOVEMENT Intensive energy consumption in the Great Lakes Region is facilitated by the availability of an abundant fuel resource, proximity to major water resources, and the unique transportation system afforded by the Great Lakes. Extensive coal resources in the nearby Appalachian and midwestern regions supply the bulk of the fuel for generating electricity in the Great Lakes states. Oil, a very versatile fuel, has less application historically for the generation of base load power in the Great Lakes Basin. However, the broad and diverse end- use of oil make it crucial to the region's energy needs. The waters of the lakes are also a source of hydroelectric power for the region and a heat sink for the nuclear and fossil fuel power plants that line the coast. Transportation of fuels to these plants is facilitated by low-cost water- borne movement on the lakes. The patterns of fuel traffic through the region arise from a complex relation among costs, reliability, and legal regulations. The arrival of low sulfur western coal on the lakes has marked a change in the prevalent upbound traffic pattern of this commodity. Long-term investments in this movement assure continuation of a new pattern. Complementing and competing with lake movement of coal is the extended use of unit train coal transport. 449 Unit train movement typically runs directly from the mine to consumer. Litiga- tion by the lake carriers is presently seeking for Great Lakes ports the lower unit train rates already available for other destinations. Coal will continue to play a dominant role in the future fuel mix of the region. The preeminence of this fuel will depend largely on resolving many of the unanswered questions that presently plague the development of nuclear energy facilities. The use of coal also depends on adjustments of air quality stand- ards or improvements in combustion/air quality control technologies. New generating capacity is not planned or scheduled to be in service by 1984 in the coastal counties of Illinois, Minnesota or Pennsylvania. The combined planned and scheduled additional electrical energy generating capacity for the entire Great Lakes states area through the mid-1980s is 74,067 MWe , with 19,433 MWe to be located in the Great Lakes coastal counties . (A state-by-state analysis is presented in Chapter VI, Technical Considerations — Energy Consumption and Move- ment in the Great Lakes Region.) Of this 19,433 MWe of additional capacity by 1984, 28 percent will be coal-fired (Michigan, New York and Wisconsin), 12% will be oil-fired (Michigan and New York), and 60% will be nuclear (Michigan, New York, Ohio, and Indiana) . 3. REGIONAL SCENARIOS OF ENERGY DEVELOPMENT Regional scenarios of energy development (principally electrical energy generation) were prepared to develop a perspective on potential resource impacts of siting new energy facilities in the Great Lakes coastal zone. The scenarios are based on different fuel mix assumptions. The four scenarios with their respective fuel mix assumptions are: • Scenario I, Recent Trends — 50% coal, 35% nuclear, 15% oil, gas and hydroelectric • Scenario II, High Coal — 70% coal, 15% nuclear, 15% oil, gas, and hydro- electric • Scenario III, High Nuclear — 45% coal, 45% nuclear, 10% oil, gas, and hydroelectric • New Technologies — 40-50% coal, 20-35% nuclear, 15-20% new technologies (solar, wind, fluidized bed, etc.) In developing regional resource requirements for land, water, and fuel (coal) , these scenarios were applied to a range of electrical energy demand growth projections (3%/year, 5.5%/year, and 8%/year) , an assumed mix of generating 450 facilities (75% base load, 20% intermediate load, and 5% peak load), and an assumed capacity load factor (65%) . The resource requirements of the generalized facilities (coal-fired and nuclear power plants) were then applied to these assumptions to evolve the regional resource requirements of energy development. For the purposes of this study, a three percent growth rate per year in electrical energy consumption was assumed to be a lower bound in projecting future power plant development, given present uncertain circumstances. Actual growth in the future may be considerably higher or somewhat lower. These situ- ations are not disputed or argued. This 3% growth rate will then describe the minimum amount of resources required to meet future electrical energy consumption, as shown in Table 79. TABLE 79 ADDITIONAL RESOURCE REQUIREMENTS OF THE GREAT LAKES STATES, 1975-1995 SCENARIOS AT 3%/YEAR GROWTH RATE IN ELECTRICAL ENERGY CONSUMPTION Additional Requirements (1975-1995) Scenarios I II III Nuclear (units) 70 24 104 land (acres) 46,72f 16,020 69,420 water (gpd) once- through 1,008 x io 8 346 x io 8 1 ,498 x IO 8 closed-cycle 1,512 x io 6 518 x io 6 2 ,246 x IO 6 Coal (units) 40 96 12 land (acres) 16,000 38,400 4,800 fuel (millions < Df tons per year) 80 192 24 water (gpd) once -through 403 x io 8 968 x io 8 121 x IO 8 closed-cycle 576 x io 6 1,382 x io 6 173 x 10 6 Requirements under Scenario IV, New Technologies, is assumed to be about 80% of those in Scenario I, Recent Trends, due to a postulated reduced dependence on more conventional generation technologies. 451 Assuming an 8%/year growth rate, Scenario I, Recent Trends, projects an additional 238 nuclear units and 185 coal units needed, with land requirements Q of 233,000 acres, water withdrawals "of 5,292 x 10 gpd for once-through cooling or 7,805 x 10 gpd for closed-cycle cooling, and coal requirements of 370 million tons per year. Table 80 shows the general projected resource requirements (assuming a 50% coal/50% nuclear fuel mix for additional capacity between 1975 and 1995, which is an approximate average of the four scenarios) that were developed for the Great Lakes coastal counties on the basis of an analysis of the scenarios and each state's energy development. TABLE 80 ADDITIONAL RESOURCE REQUIREMENTS OF TIIE GREAT LAKES COASTAL COUNTIES, 1975-1995, A ASSUMING A 3% GROWTH RATE IN ELECTRICAL ENERGY CONSUMPTION Additional Requirements State Generating Units* Generating Capacity (MWe) Land (Acres) Water Withdrawals Once- 1 Through (gpm) Closed Cycle Coal (Millions of Tons per year) Illinois ii , •k-k Indiana — Michigan 11 11,000 5,870 9.35xl0 6 137,500 11.0 Minnesota 1-2 1-2,000 1-2,000 0.9-1.7xl0 6 12-25,000 2-4.0 New York 7 7,000 3,740 5.95xl0 6 87,500 7.0 Ohio 4 4,000 2,135 3.4xl0 6 50,000 4.0 Pennsylvania Wisconsin 8 8,000 4,270 6.8xl0 6 100,000 8.0 ** 'Coal and nuclear units, assuming a 50% coal/50% nuclear mix, as noted above. Does not include Bailly nuclear unit, Porter County, on site already containing two coal-fired units. 452 If an 8% growth rate is assumed, the figures in the table above would increase by factors ranging from 2.0 to 4.8, depending on the state . This indicates that considerable pressure might be placed on the coastal counties of Great Lakes Basin for electrical energy generation facilities. 4. OTHER CONSIDERATIONS A host of other factors not addressed in this report will affect energy facility siting. Some of these factors involve economic and political circum- stances. The economic development and stimulation provided by the siting of an energy facility may be attractive to relatively less developed areas located near load or market centers. In many cases, utilities and industries already have purchased land in outlying areas. Such development may be more acceptable in these localities, and indeed, campaigns for the facilities may be undertaken. Thus, political factors may influence the final location of these facilities. Such political-economic factors are difficult to examine "in an objective analysis of energy facility siting, and are beyond the scope of this study. State energy policies relating to consumption, rates, construction and building requirements, and other factors will affect the need for additional facilities and the types of fuels to be used. Public reaction to the location of individual facilities or types of facilities and energy use will have obvious effects on where facilities will be located as well as when they will be constructed and placed into operation. The absence of a federal energy policy is permitting public acceptance, environmental and market factors, and state policies to influence energy use and energy facility siting at the national level. The present national energy policy is thereby made up of these subsets of policies which affect each other but are developed separately. While these factors and subsets of energy policies must be incorporated into a federal policy because of their importance, there is no consistency or coherence among them. On one hand, this absence of a federal energy policy does not lock the country into energy developments that may not be advantageous in the long run. On the other hand, the lack of a federal policy results in a piecemeal approach to energy development, inconsistency in dealing with energy consumption and facility siting problems, and confusion for utility and energy related companies as to future planning and investments. 453 C. POLICY OPTIONS The institutional policy options described in Section VLB. indicate the range of options available to the states under the Coastal Zone Management Act, as well as other applicable federal and state legislation. An attempt was made, within the constraints of reasonableness, to make the list as thorough as possible. The options are structured to encourage the reader to develop new options through permutations and combinations of those presented. Note that while special attention is given to matters related to the coastal zone, the options also address the broad issues of energy facility siting on a statewide basis. It is important to relate CZM-specific policy options to the institutional framework of the state as a whole, and to provide consideration of statewide energy facility siting regulation where such programs do not exist. The technical options were developed within the limits of present or probable technical feasibility to provide as wide a range of choices as possible for future energy facility siting in the Great Lakes coastal zone. The technical options are not constrained by traditional and present institutional policies. This permits consideration of innovative siting options. Given the conclusions of the coastal dependence analysis, the state coastal zone management programs are encouraged to give strong consideration to the siting of energy facilities other than shoreline fuel transshipment facilities) inland from the shoreline, but with access to coastal resources. The technical options suggest how this might be accomplished. D. IMPLICATIONS FOR FURTHER RESEARCH During the course of this project, several topics were encountered for which there was a lack of available information or that were beyond this study's scope. Time constraints precluded any extensive investigation of these topics by the study staff so they are offered here as suggestions for additional research. All have a bearing on the siting of energy facilities in the coastal zone. 1. LAND VALUES Attempts to compare coastal and inland sites for energy facilities were 454 impaired by a lack of information on relative land values. Not only is there a lack of data comparing actual land costs, but the intangible land values associ- ated with aesthetic, recreational and psychological aspects of the coastline also require additional investigation. 2. NUCLEAR FUEL CYCLE Nuclear power plants require a variety of facilities for the enrichment of nuclear fuel and the processing and disposal of wastes. While none of these facilities are currently located in the coastal zone of the Great Lakes, some are nearby and others are proposed. The scope of the study did not permit adequate consideration of the coastal dependency of such facilities. The trans- portation of radioactive materials on the Great Lakes also requires additional investigation with regard to transshipment and storage facilities and the poten- tial hazard to the lakes from radioactivity. 3. MULTIPLE-USE SITING The use of land for one purpose may not preclude all other uses. The intensity of land use in some coastal areas suggests that it may be judicious for states to investigate the possibilities for multiple uses of lands, such as transportation corridors and the shoreline, associated with energy facilities. 4. SYMBIOTIC SITING The waste heat from a power plant and the heat from incinerating municipal trash both offer opportunities for symbiotic siting. Waste heat may be dissipated in a beneficial, industrial application, while trash may supple- ment other fuels in the production of electricity or perhaps serve as the sole fuel. Practical problems with implementation of such schemes require investi- gation. 5. CONSERVATION While research is underway into various methods of conserving electricity and other forms of energy, the potential for the mitigation of adverse impacts on the coastal zone could be investigated. 6. OTHER FACILITIES Coastal zone management plans and programs will deal with a wide variety 455 of facilities and land uses. The coastal dependency of these other facilities and uses could be investigated so tj^at a comparison could be made with the results of this report and the relative requirements for coastal access among all land uses could be established. 7. SMALLER SCALE FACILITIES Although electrical generating facilities were covered in detail in this report, a factor that may affect the construction of large generation facil- ities is the development of combined cycle generation. Research is being directed toward examining the use of combined cycle generation for facilities (less than 150 MWe) that would serve small communities or neighborhoods and large individual industrial plants. Future pricing policies for electricity use and for natural gas may encourage their application. The use of smaller scale fossil- fuel power plants (other than combined cycle) should also be evaluated and compared to possible use of combined cycle plants. The significance of the possible use of these facilities and their implications for future land, water, air, and fuel use should be examined. 8. DETAILED STATE POLICY ANALYSIS A highly detailed analysis should be made of the policies, programs, and legal authorities within each state that significantly influence energy facility siting in both coastal and inland areas. This greater level of detail is a logical spinoff from this study and is a necessary prerequisite for each state's development of comprehensive institutional framework to implement energy facility siting policies and/or programs. 9. RELATIONSHIP BETWEEN STATE AND FEDERAL POLICIES Further research into a number of substantive areas of energy policy in the Great Lakes Basin is needed. A detailed analysis should be made of the specific implications of the various aspects of federal energy facility siting policy for each of the eight Great Lakes states. 10. STATE AND FEDERAL POLICIES Policy research is necessary in state and federal policies affecting energy use. Suggestions should be made for the establishment of coherent frame- work within which the present energy use policies can be viewed and future 456 policies developed. Furthermore, the interaction among policy development, technology, and resource requirements needs considerable attention. At the state level, the effect of electric and fuel rates on the need for energy facilities should be investigated. At the federal level, a compre- hensive fuels use-environmental policy would provide guidance to the energy industry. 11. SHORELINE USE A detailed study of shoreline land use should be undertaken on a state- by-state as well as regional basis. Energy facilities compete with other uses of the shoreline. A better understanding of these uses and their relationship and dependence on shoreline locations could greatly assist coastal zone manage- ment planning. 12. ENVIRONMENTAL AND ECONOMIC EFFECTS Load centers for electricity and facilities to provide this power are clustered near the coastline of the Great Lakes. The environmental and economic effects of these facilities on the Great Lakes coastal zone in the context of resource and impact management should be investigated. 13. LOCAL PLANNING AND DECISION MAKING Planning and decisions made at the local (municipal, county, multi-coun- ty) level can have a significant impact on the availability and use of resources Planning for energy facilities is a case in point. Further research should be directed toward how local planning and decision-making affect resource manage- ment and what are the types of policies, institutions, and processes involved in this planning and decision-making. 14. THE GREAT LAKES BASIN AS A FUTURE EXPORTER OF ELECTRICITY The Great Lakes provide a water resource for cooling and process water in the energy industry as well as for other industries. The potential exists for this use of Great Lakes water to expand in the future. Energy facilities do not need to locate on the shoreline to use this resource, but can be located inland and still draw on it. If large energy facilities or clusters of facil- ities locate in or near the coastal zone of the Great Lakes and export energy from this area while utilizing its water resources, the social, economic, 457 political, and environmental implications of this circumstance should be examined in detail. 15. INTERNATIONAL IMPLICATIONS Great Lakes ports engage in international shipment of fuels for energy production. In addition, electricity is transmitted back and forth (primarily on a seasonal basis in the Great Lakes Region) across the international boundary Further study should be undertaken by the United States and Canada to determine the implications of this for plant requirements and the associated resource demands and impacts. 459 Appendix A STANDING COMMITTEE ON GREAT LAKES COASTAL ZONE MANAGEMENT MICHIGAN Mr. Merle Raber, Acting Chief Shorelands Management & Water Resources Planning Sec, Div. of Land Use Michigan Dept. of Natural Resources Stevens T. Mason Building Lansing, Michigan 48926 ILLINOIS Mr. Peter L. Wise (Committee Chairman) Coordinator for Coastal Zone Management Marina City Office Building 300 North State St., Room 1010 Chicago, Illinois 60610 Mr. Chris A. Shafer Assistant Director for CZM Department of Transportation Marina City Office Building 300 North State St. , Room 1010 Chicago, Illinois 60610 INDIANA Mr. William J. Andrews, Deputy Director for Water & Mineral Resources Indiana Dept. of Natural Resources 608 State Office Building Indianapolis, Indiana 46204 Mr. Theodore Pantazis State Planning Services Agency 143 West Market Street Harrison Building Indianapolis, Indiana 46204 MINNESOTA Mr. Gene Hollenstein Chief Hydrologist Division of Water, Soils & Minerals Minnesota Dept. of Natural Resources 345 Centennial Building St. Paul Minnesota 55155 Mr. Roger Williams Minnesota State Planning Agency 100 Capitol Square Building St. Paul, Minnesota 55101 Mr. Archie Chelseth Assistant Commissioner Minnesota Dept. of Natural Resources 300 Centennial Office Building St. Paul, Minnesota 55155 NEW YORK Mr. Henry Williams Director of State Planning Department of State 162 Washington Avenue Albany, New York 12231 Mr. Frederick W. Howell New York State Department of Environmental Conservation 50 Wolf Road Albany, New York 12233 OHIO Mr. Bruce E. McPherson Shoreland Management, Div. of Water Ohio Dept. of Natural Resources Building E., Fountain Square Columbus, Ohio 43224 460 PENNSYLVANIA Mr. George E. Fogg, Coordinator Coastal Zone Management Program Dept. of Environmental Resources Bureau of Resources Programming Third & Reily Streets Harrisburg, Pennsylvania 17120 WISCONSIN Mr. Theodore F. Lauf Coordinator-Special Projects Office of Planning & Analysis Wisconsin Dept. of Natural Resources Box 7921 Madison, Wisconsin 53707 Mr. Allen Miller Land Use Coordinator Dept. of Administration State Planning Office 1 West Wilson Street Madison, Wisconsin 53702 DEPT. OF TRANSPORTATION Mr. David C. Robb, Director Office of Comprehensive Planning St. Lawrence Seaway Development Corp. 800 Independence Avenue, S.W. Washington, D.C. 20591 Cmdr. Charles R. Corbett Chief of Environmental Affairs Ninth Coast uard District 1240 East 9th Street Cleveland, Ohio 44199 DEPT. OF COMMERCE Dr. Arthur P. Pinsak Great Lakes Environmental Research Lab Dept. of Commerce, NOAA 2300 Washtenaw Avenue Ann Arbor, Michigan 48104 Ms. Eileen Mulaney Office of Coastal Zone Management Dept. of Commerce, NOAA 3300 Whitehaven Street Page Building No. 1 Washington, D.C. 20235 DEPT. OF INTERIOR Ms. Madonna F. McGrath, Acting Special Assistant to the Secretary North Central Region U.S. Dept. of Interior 230 S. Dearborn Street Chicago, Illinois 60604 DEPT. OF ARMY Mr. Louis D'Alba Planning Branch North Central Division U.S. Army Corps of Engineers 536 South Clark Street Chicago, Illinois 60605 ENVIRONMENTAL PROTECTION AGENCY Mr. Ralph Nordstrom, CZM Coordinator Planning Branch Air and Water Programs Division Environmental Protection Agency 230 South Dearborn Street Chicago, Illinois 60604 DEPT. OF HOUSING & URBAN DEVELOPMENT Mr. Harry P. Blus Environmental Standards Officer Community Planning and Management U.S. Dept. of HUD Region V 300 South Wacker Drive Chicago, Illinois 60606 SECRETARIATS Mr. Leonard T. Crook Executive Director Great Lakes Basin Commission 3475 Plymouth Road P. 0. Box 999 Ann Arbor, Michigan 48106 Mr. Gerald F. Kotas Water Resources Planner Great Lakes Basin Commission 3475 Plymouth Road P. 0. Box 999 Ann Arbor, Michigan 48106 461 Appendix B CZM ENERGY PROJECT STEERING COMMITTEE Mr. John Armstrong State Planning Office 1 West Wilson Street Madison, Wisconsin 53702 Dr. William Mattox Ohio Dept. of Natural Resources Building D, Fountain Square Columbus, Ohio 43224 Mr. Delbert Johnson Water Resource Planner Bureau of Water Management Michigan Dept. of Natural Resources Stevens T. Mason Building Lansing, Michigan 48926 Mr. Thomas Fiddler Dept. of Environmental Resources P. 0. Box 1467 Harrisburg, Pennsylvania 17120 Mr. Dmitri Aperjis Office of Coastal Zone Management NOAA, Dept. of Commerce 3300 Whitehaven Street Page Building #1 Washington, D.C. 20235 Mr. David C. N. Robb , Director Office of Comprehensive Planning St. Lawrence Seaway Corporation 800 Inddpendence Avenue, S.W. Washington, D.C. 20591 Mr. Warren Hofstra North Central Region U.S. Dept. of the Interior 230 S. Dearborn Street, 32nd Floor Chicago, Illinois 60604 Mr. James H. Phillips Energy Coordinator, Region V U.S. Environmental Protection Agency 230 South Dearborn Street Mr. John Paul Tolson Office of Coastal Zone Management NOAA, Dept. of Commerce 3300 Whitehaven Street Page Building #1 Washington, D.C. 20235 462 Appendix C CZM ENERGY PROJECT TECHNICAL ADVISORS Mr. Fred Abel U.S. Energy Research and Development Administration Fossil Energy 20 Massachusetts Ave., N.W. Washington, D.C. 20545 Professor Richard Bishop Dept. of Agricultural Economics 340 Agricultural Hall 1450 Linden Drive Madison, Wisconsin 53706 Mr. Karl Bremer Lake Studies PCB Technical Support Branch U.S. Environmental Protection Agency 230 S. Dearborn Chicago, Illinois 60604 Mr. Walker Cisler 1071 Devonshire Grosse Point, Michigan 48236 Mr. Andrew (Pete) D' Zmura 19155 Roman Way Gaithersburg, Maryland 20760 Mr. Hugh Gardner Federal Energy Administration 175 W. Jackson Chicago, Illinois 60604 Mr. Tom Hemminger Commonwealth Edison Div. of Environmental Affairs Box 767 Chicago, Illinois 60690 Mr. Forrest G. Hiple Vice-President Electric Operations & Construction Northern Ind. Public Service Company 5265 Hohman Avenue Hammond, Indiana 46320 Mr. John Hoover Argonne National Laboratory 9700 S. Cass Avenue Argonne, Illinois 60439 Mr. Herb Jacobs Governor's Energy Council 905 Payne-Shoemaker Building Harrisburg, Pennsylvania 17120 Mr. Owen A. Lentz, Exec. Manager East Central Area Reliability Coordination Agreement P.O. Box 102 Canton, Ohio 44701 Dr. James L. Liverman U.S. Energy Research and Development Administration Mail Station E-201 Washington, D.C. 20545 Mr. Peter Meier Associated University, Inc. Brookhaven National Laboratory Upton, New York 11973 Mr. Walter J. Matthews 555 Wayside Drive Indianapolis, Indiana 46260 463 Mr. E.L. Michelson Administrative Manager, MAIN 1 N. 301 Swift Road P.O. Box 278 Lombard, Illinois 60148 Mr. William McGorum, Acting Secretary Ohio Power Siting Commission Seneca Tower 361 E. Broad Street Columbus, Ohio 43215 Mr. Charles Hill Federal Power Commission Federal Building, Room 3130 230 S. Dearborn Street Chicago, Illinois 60604 Mr. Robert S. Ryan, Director Ohio Energy Research and Development Agency 25th Floor, State Office Tower 30 E. Broad Street Columbus, Ohio 43215 Mr. Al Grandys Division of Energy Illinois Dept. of Bus. and Economic Dev. 222 S. College Street Springfield, Illinois 62706 Dr. Miller Spangler U.S. Nuclear Regulatory Comm. Washington, D.C. 20555 Mr. Richard L. Wawrzyniak Assistant Chief Division of Water Room 605, State Office Bldg. Indianapolis, Indiana 46204 Mr. Robert F. Welford, Reg. Coordinator U.S. Fish & Wildlife Service Federal Bldg., Ft. Snelling Twin Cities, Minnesota 55111 Mr. Jerry Williams, Engineer Environmental Impact Statement EIS Review Section U.S. Environmental Protection Agency 26th Floor, S&A Division 230 S. Dearborn Chicago, Illinois 60604 Mr. Richard Williamson Systems Analysis U.S. Energy Research and Development Administration 20 Mass Ave. , N.W. 7th Floor, APAE Washington, D.C. 20545 Mr. Alec Wisch Governor's Energy Council 905 Payne-Shoemaker Building Harrisburg, Pennsylvania 17; 20 Mr. Howard Zar, Oceanography Permits Branch U.S. Environmental Protection Agency 230 S. Dearborn Chicago, Illinois 60604 Mr. Ellison Burton U.S. Energy Research and Development Administration APAE - 7th Floor Washington, D.C. 20545 Mr. Robert H. Sims, Chairman Mid-Atlantic Area Coordination Group co/GPU Service Corp. 260 Cherry Hill Road Parsippany, New Jersey 07504 Mr. Julius Bleiweis Executive Director Northeast Power Coordinating Council 1250 Broadway New York, New York 10001 Mr. Thomas Jackson Michigan Energy Administration Dept. of Commerce Law Building Lansing, Michigan 48913 Mr. Jick Myers Office of Planning, Analysis, & Evaluation U.S. Energy Research and Development Administration Washington, D.C. 20545 464 Professor John Steinhart Associate Director, Marine Studies Center University of Wisconsin — Madison 1225 West Dayton Street Madison, Wisconsin 53715 Mr. Frank Davenport U.S. Water Resources Council Suite 800, Gelman Building 2120 "L" Street Washington, D.C. 20037 Mr. Derek M. Foulds Director, Ontario Region Inland Waters Directorate 135 St. Clair Ave., West 2nd Floor Toronto, Ontario M4V 1P5 Mr. Richard C. Clancy Vice President Niagara Mohawk Power Corporation 300 Erie Boulevard West Syracuse, New York 13202 Mr. George L. Houston Assistant Vice President New York State Electric & Gas Corporation 4500 Vestal Parkway East Binghamton, New York 13902 Mr. Gerald I. Stillman Acting Principal Environmental Engineer Power Authority of the State of New York 10 Columbus Circle New York, New York 10019 Mr. Roger W. Kober Acting Assistant Manager of Environmental Engineering Rochester Gas and Electric Corporation 89 East Avenue Rochester, New York 14649 Mr. Earl G. Ellerbrake Office of Oil and Gas Federal Energy Administration Room 3442, Federal Building 12th and Pennsylvania Ave. , N.W. Washington, D.C. 20461 Mr. John Foltz Ashland Oil Co., Inc. ATTN: Communications Department P.O. Box 391 Ashland, Kentucky 41101 Dr. John Armstrong Coastal Zone Laboratory University of Michigan Ann Arbor, Michigan 48109 Mr. Jim Beatty Sault St. Marie Power and Light Sault St. Marie, Michigan Mr. Rob Callen, Director Research Division Public Service Commission 7545 Mercantile Way Lansing, Michigan Mr. Joseph Cook, Manager Port Development Section Bureau of Transportation & Planning Michigan Dept. of State Highways & Transportation Highways Building Lansing, Michigan Dr. William Cooper Department of Zoology Michigan State University East Lansing, Michigan Mr. John Duane, Staff Engineer Gas Energy Planning Dept. Consumers Power Company 212 W. Michigan Avenue Jackson, Michigan 49201 Professor Marc Enns East Engineering Building University of Michigan Ann Arbor, Michigan 48109 Mr. Thomas Cotton Office of Technology Assessment U.S. Congress Washington, D.C. Dr. Fred Jones American Natural Gas Company 1 Woodward Avenue Detroit, Michigan 465 Dr. Elizabeth Peel Social Impact Assessment Oakridge National Laboratory P.O. Box X Oakridge, Tennessee 37830 Mr. Carl Rapport Federal Energy Administration Washington, D.C. Mr. Burkhard H. Schneider Detroit Edison Company 2000 Second Avenue Detroit, Michigan 48823 Mr. Richard T. Huber Fish and Wildlife Service U.S. Dept. of the Interior Federal Building, Fort Snelling Twin Cities, Minnesota 55111 While a broad group of technical advisors from both the public and private sectors participated in the study by reviewing and commenting on preliminary material and the draft report, this should not be taken as their endorsement of this final report. They served only as advisors, reactors, and providers of information. 466 Appendix D CZM ENERGY PROJECT CITIZEN ADVISORS Mr . David Comey Executive Director Citizens for a Better Environment Suite 2610, 59 E. Van Buren Chicago, Illinois 60605 Dr. John Neess Department of Zoology Birge Hall University of Wisconsin Madison, Wisconsin 53706 Mr. Myron Cherry One IBM Plaza, Suite 4501 Chicago, Illinois 60611 Mrs. Betty MacDonald Regional Resources Chairperson League of Women Voters 1155 Edgewood Avenue Madison, Wisconsin 53711 Dr. Paul Friesma Public Lands Project Northwestern University Evanston, Illinois 63301 Ms. Louise Young 755 Sheridan Winnetka, Illinois 60093 467 Appendix E CZM ENERGY PROJECT STAFF PROJECT MANAGEMENT Leonard Crook, Executive Director — Supervisor Charles Job — Project Manager Gerald Kotas — Coastal Zone Management Coordinator POLICY UNIT Thomas Gross — Policy Analyst John Hall — Resources Planner and Policy Analyst COASTAL DEPENDENCE UNIT Robert Clemens — Geologist John Johansen — Economist William Skimin — Resources Planner and Policy Analyst PROJECTIONS AND TRENDS UNIT Reed Bohne — Resources Planner David Staples — Resources Planner and Policy Analyst SECRETARY AND OFFICE MANAGEMENT Terri Ogle — Secretary and Office Manager Marie Murrell — Typist TECHNICAL ADVISORS Jonathan Mayer — Transportation Research Analyst Timothy Monteith — Civil Engineer 468 Appendix F SUMMARY OF AIR QUALITY EFFECTS OF S0 2 , PARTICULATES, AND N0 2 Effects of Sulfur Dioxide 1. Effects on Humans 3 1500 yg/m (0.52 ppm) of sulfur dioxide (24-hour average), and suspended particulate matter measured as a soiling index of 6 cohs or greater: increased mortality may occur (American data). 3 715 yg/m (0.25 ppm) of sulfur dioxide and higher (24-hour mean), accompanied by smoke at a concentration of 750 yg/m^: increased daily death rate may occur (British data) . 500 yg/nr 3 (0.19 ppm) of sulfur dioxide (24-hour mean), with low particulate levels: increased mortality rates may occur (Dutch data). 3 3 300 yg/m to 500 yg/m (0.11 ppm to 0.19 ppm) of sulfur dioxide (24-hour mean), with low particulate levels: increased hospital admis- sions of older persons for respiratory disease may occur; absenteeism from work, particularly with older persons, may also occur (Dutch data) . 3 715 yg/m (0.25 ppm) of sulfur dioxide (24-hour mean), accompanied by particulate matter: a sharp rise in illness rates for patients over age 54 with severe bronchitis may occur (American data) . 3 600 yg/m (about 0.21 ppm) of sulfur dioxide (24-hour mean), with smoke concentrations of about 300 yg/m^: patients with chronic lung disease may experience accentuation of symptoms (British data) . 3 3 105 yg/m to 265 yg/m (0.037 ppm to 0.092 ppm) of sulfur dioxide (annual mean), accompanied by smoke concentrations of about 185 yg/m-*: increased frequency of respiratory symptoms and lung disease may occur (Italian data) . 3 120 yg/m (0.046 ppm) of sulfur dioxide (annual mean), accompanied by smoke concentrations of about 100 yg/m^: increased frequency and severity of respiratory diseases in school children may occur (British data) . Material in this appendix is adapted from Environmental Protection Study , prepared by ICF, Incorporated, for the Michigan Public Service Commission. May, 1975. 469 3 • 115 yg/m (0.040 ppm) of sulfur dioxide (annual mean), accompanied by smoke concentrations of about 160 yg/m : increase in mortality from bronchitis and from lung cancer may occur (British data) . 2. Effects on Visibility 3 • 285 ug/m (0.10 ppm) of sulfur dioxide, with comparable concentration of particulate matter and relative humidity of 50 percent: visibility may be reduced to about five miles (American data) . 3. Effects on Materials 3 • 345 ug/m (0.12 ppm), accompanied by high particulate levels: the corrosion rate for steel panels may be increased by 50 percent (American data) . 4. Effects on Vegetation 3 • 85 ug/m (0.03 ppm) of sulfur dioxide (annual mean): chronic plant injury and excessive leaf drop may occur (Canadian data) . 3 • 860 ug/m (0.3 ppm) of sulfur dioxide for 8 hours: some species of trees and shrubs show injury (American data) . 3 3 • 145 yg/m to 715 ug/m (0.05 ppm to 0.25 ppm): sulfur dioxide may react synergistically with either ozone or nitrogen dioxide in short- term exposures (e.g., 4 hours) to produce moderate to severe injury to sensitive plants (American data) . Effects of Particulates 1. Effects on Humans 3 • 750 yg/m and higher for particulates on a 24-hour average, accompanied by sulfur dioxide concentrations of 715 yg/m^ and higher: excess deaths and a considerable increase in illness may occur (British data) . 3 3 • A decrease from 140 yg/m to 60 yg/m (annual mean) in particulate concentrations may be accompanied by a decrease in mean sputum volume in industrial workers (British data) . 3 • If concentrations above 300 yg/m for particulates persist on a 24-hour average and are accompanied by sulfur dioxide concentrations exceeding 630 yg/m over the same average period, chronic bronchitis patients will likely suffer acute worsening of symptoms (British data) . 3 • Over 200 yg/m for particulates on a 24-hour average, accompanied by concentrations of sulfur dioxide exceeding 250 yg/m^ over the same average period: increased absence of industrial workers due to illness may occur (British data) . 3 3 • 100 yg/m to 130 yg/m and above for particulates (annual mean) with sulfur dioxide concentrations (annual mean) greater than 120 yg/m^: children residing in such areas are likely to experience increased incidence of certain respiratory diseases. 470 3 Above 100 yg/m for particulates (annual geometric mean) with sulfation levels above 30 mg/cm -mo. : increased death rates for persons over 50 years of age are likely (American data) . 3 3 80 yg/m to lOOyg/m for particulates (annual geometric mean) with sulfation levels of about 30 mg/cm -mo.: increased death rates for persons over 50 years of age may occur (American data) . 2. Effects on Direct Sunlight 3 3 • 100 yg/m to 150 yg/m for particulates, where large smoke turbidity factors persist: in middle and high latitudes direct sunlight is reduced up to one-third in summer and two-thirds in winter (American data) . 3. Effects on Visibility 3 • 150 yg/m for particulates, where the predominant particle size ranges from 0.2 to 1.0 and relative humidity is less than 70 percent: visibility is reduced to as low as 5 miles (American data) . 4. Effects on Materials 3 3 • 60 yg/m ( annual geometric mean) , to 180 yg/m for particulates (annual geometric mean) , in the presence of sulfur dioxide and moisture corrosion of steel and zinc panels occurs at an accelerated rate (American data) . 5. Effects on Fublic Concern 3 • 70 yg/m for particulates (annual geometric mean) , in the presence of other pollutants: public awareness and/or concern for air pollution may become evident and increase proportionately up to and above con- centrations of 200 yg/m3 for particulates (American data) . Effects of Nitrous Oxide 1. Effects on Humans 3 • 225 yg/m (0.12 ppm) for nitrogen dioxide: an odor becomes detectable. 3 9,400 yg/m ( 5 ppm) for nitrogen dioxide for 10 minutes: has produced transient increase in airway resistance. 3 • 162,200 yg/m (90 ppm) for nitrogen dioxide for 30 minutes: has pro- duced pulmonary edema 18 hours later. • 118 to 156 yg/m 3 (0.063 to 0.083 ppm) for nitrogen dioxide (24-hour standard) with a mean suspended nitrate level of 2.6 yg/m or greater: increased acute bronchitis among infants and school children. 3 • 117 to 205 yg/m (0.062 to 0.109 ppm) for nitrogen dioxide (24-hour mean) with a mean suspended nitrate level of 3.8 yg/m^ or greater: increased acute respiratory disease in family group. 471 2. Effects on Materials 470 yg/m 3 (0. abscission and decreased yield among navel oranges 3 940 yg/m (0.5 ppm) for nitrogen dioxide for 3 abscission and chlorosis on citrus fruit trees 3 1,900 yg/m (1 ppm) for nitrogen leaf injury to sensitive plants. 3 • 470 yg/m (0.25 ppm) for nitrogen dioxide for 8 months caused leaf oi 3 940 yg/m (0.5 ppm) for nitrogen dioxide for 35 days resulted in leaf 3 1,900 yg/m (1 ppm) for nitrogen dioxide for one day can cause overt 472 Appendix G ELECTRIC GENERATING FACILITIES COUNTY LOCATION COMPANY PLANT' NAME MWe FUEL WATER SOURCE AVG CFS INTAKE PLANT HEAT RATE # OF UNITS STATE Ashtabula Clev. Elect, ilium. Co. Ashtabula 640 Coal/Oil Lake Erie 658 BTU/KWH 11,428 9 Ohio Lorain Clev. Elect. Ilium. Co Avon Lake 1,275 Coal/Oil Lake Erie 947 10,338 9 Ohio Lake C lev. Elect. ilium. Co. East Lake 1,275 Coal/Oil Lake Erie 1,270 9,512 5 Ohio Cuyahoga Clev. Elect. Ilium. Co. Lake Shore 514 Coal /Oil Lake Erie 456 11,552 5 Ohio Lake Commonwealth Edison Co. State Line 972 Coal /Gas Lake Michigan 1,259 10,573 4 Indiana Cook Commonwealth Edison Co. Fisk 547 Coal/Gas Chicago Canal 401 11,302 3 Illinois Cook Commonwealth Edison Co. Calumet 107 Gas Calumet River 67 13,224 1 Illinois Cook Commonwealth lidtson Co. Crawford 702 Coal /Gas Chicago Canal 593 10,292 3 Illinois Cook Commonwealth Edison Co. Ridgeland 690 1 Oil/Gas Chicago Canal 742 11,177 4 Illinois Lake Commonwealth Edison Co. Waukegan 933 Coal/Oil Lake Michigan 962 10,195 7 Illinois Lake Commonwealth Edison Co. Zion 1,098 Nuclear Lake Michigan 1,618 13,269 1 Illinois Muskegon Consumers Power Co. Cobb 510 Coal/Oil Lake Muskegon 619 10,590 5 Michigan Charlevoix Consumers Power Co. Big Rock Point 75 Nuclear Lake Michigan 114 11,421 1 Michigan Bay Consumers Power Co. Karn 550 Coal/Oil Saginaw River 454 9,136 2 Michigan Ottawa Consumers Power Co. Campbell 650 Coal /Oil Pigeon Lake 504 9,097 2 Michigan Van Buren Wayne Consumers Power Co. Palisades 7 20 Nuclear Lake Michigan 900 10,981 1 Michigan Detroit Pub. Lightng. Comm Misteroky 174 Coal Detroit River 243 BTU/KWH 10,909 6 Michigan Ashland Lk. Superior Dist .Pwr.Co. Bay Front 82 Coal/ Oil/Gas Lake Superior 46 13,213 6 Wisconsin Manitowoc Manitowoc Public Util. Manitowoc 69 Coal Lake Michigan 51 14,999 5 Wisconsin Marquette Marquette Br< of Lt & Powei Sheras 37 Coal/Gas Lake Superior 30 14,243 2 Michigan St. Louis Minn. Power 6, Light. Aurora 110 Coal/Oil Lake Colby 210 13,030 2 Minnesota St. Louis Minn. Power & Light. Hibbard 124 Coal/ Oil/Gas St. Louis River 364 14,576 4 Minnesota Oswego Niagara-Mo- hawk Pwr.Co. Oswego 376 Oil Lake Ontario 500 11,545 4 New York Erie Niag. -Mohawk Power Co. Huntley 828 Coal Niagara River 1,160 10,380 6 New York Chautauqua Niag. -Mohawk Power Co. Dunkirk 628-' Coal/Oil Lake Erie 890 10.0SP 4 New York Oswego Niag. -Mohawk Power Co. 9 Mile Point Nuc 500 Nuclear Lake Ontario 518 10,709 1 New York Porter No. Ind. Public Serv. Co. Bailly 615 Coal/Gas Lake Michigan 470 10,008 2 Indiana Bay Consumers Power Co. Weadock 614 Coal/Gas/ Oil Saginaw River 545 10,616 8 Michigan Monroe Consumers Power Co. Whiting 325 Coal/Oil Lake Erie 362 9,913 3 Michigan Wayne Detroit Edis Conners Creel 510 Coal/ Oil/Gas Detroit River 796 13,05(1 8 Michigan 473 COUNTY LOCATION COMPANY PLANT NAME MVte FUEL WATER SOURCE AVG CFS INTAKE PLANT HEAT RATE I OF UNITS STATE Wayne ii. null Edis Delray 375 Oil/Gas Detroit River 375 14,440 6 Michigan Monroe ik. 11 oil Ed Is Fermi 158 Oil Lake Erie 82 14,626 1 Michigan Huron Detroit Edis Harbor Beach 121 Coal/Oil Lake Huron 154 BTU/KWH 10,600 1 Michigan St. Clair Detroit Edis Marysville 200 Coal/Gas St. Clair River 461 12,300 7 Michigan Wayne Detroit Edis Pennsalt 37 Coal/Oil Detroit River 18 54,657 7 Michigan Wayne Detroit Edis River Rouge 933 Coal/ Oil/Gas Detroit River 1,041 9,450 3 Michigan St. Clair Detroit Edis St. Clair 1,905 Coal/ Oil/Gas St. Clair River 2,290 9,220 7 Michigan Wayne Detroit Edis Trenton Channel 876 Coal/ Oil/Gas Detroit River 1,400 10,450 5 Michigan Wayne Detroit Edis Wyandotte 54 Coal/ Oil/Gas Detroit River 152 11,800 8 Michigan Monroe Detroit Edis Monroe 2,462 Coal/Oil Raisin River 1,796 9,600 3 Michigan Lake No. Indiana Public Serv. Mitchell 529' Coal/Gas Lake Michigan 690 10,124 4 Indiana Laporte No. Indiana Public Serv. Michigan Cit> 215 Coal/Gas Lake Michigan 223 12,349 3 Indiana Charlevoix No. Mich. Elec .Coop . In< . Advance 37 Coal Lake Charlevoix 856 12,636 3 Michigan Lorain Ohio Edison Co. Edgewater 193 Coal Lake Erie 181 11,747 3 Ohio Erie Pennsylvania Elec. Co. Front Street 119 Coal Lake Erie 220 14,295 5 Penn. Monroe Rochester Ca: 6 Elec. Corp Rochester 03 196 Coal/ Oil /Gas Genessee River 147 18,849 9 New York Monroe Rochester Gas &. Elec. Corp. Rochester //7 253 Coal/Oil Lake Ontario 231 10,534 4 New York Wayne Rochester Ga; & Elec. Corp. Rochester#13 490 Nuclear Lake Ontario 842 10,803 1 New York Lucas Toledo Edisoi Co. Acme 321 Coal/ Oil/Gas Maumee River 309 BTU/KWH 12,994 5 Ohio Lucas Toledo Ecison Co. Bay Shore 638 Coal/Oil Maumee River 1,100 9,238 4 Ohio Marquette Upper Penin. Gen. Co. Presque Isle 175 Coal/Oil Lake Superior 184 11,283 4 Michigan Milwaukee Wisconsin Elec.& Pwr Ci Commerce 35 Oil/Gas Milwaukee River 72 16,021 1 Wisconsin Milwaukee Wis. Elect. & Power Co . Lakeside 310 Oil/Gas Lake Michigan 41 17,159 8 Wisconsin Milwaukee Wis. Elect. & Power Co. North Oak Creek 500 Coal/Oil Lake Michigan 686 10,301 4 Wisconsin Ozaukee Wis. Elect. & Power Co. Port Washington 400 Coal Lake Michigan 623 11,585 5 Wisconsin Milwaukee Wis. Elect. & Power Co. South Oak Creek 1,192 Coal/Oil Lake Michigan 1,457 9,685 4 Wisconsin Milwaukee Wis. Elect. & Power Co. VAlley 272^ Coal/Gas N. Menominee Canal 182 14,145 2 Wisconsin Manitowoc Wis. Elect. & Power Co. Point Beach 1,047 Nuclear Lake Michigan 1,287 10,934 2 Wisconsin Sheboygan Wis. Elect. & Power Co. Edgewater 437 Coal/Oil Lake Michigan 295 10,085 4 Wisconsin Brown Wis. Elect. & Power Co. Pulliam 393 Coal/Oily Gas Fox River 500 11,351 8 Wisconsin Berrien Ind. & Mich. Electric Co. Cook, D.C. 1,089 Nuclear Lake Michigan 1,537 10,771 1 Michigan 475 ACRONYMS AQCR - air quality control region ACRS - Advisory Committee on Reactor Safety ASLB - Atomic Safety and Licensing Board BWR - boiling water reactor cfs - cubic feet per second DER - Department of Environmental Resources DES - Draft Environmental Statement DNR - Department of Natural Resources EHV - extra high voltage EPA - Environmental Protection Agency EQC - Environmental Quality Council ESECA - Energy Supply and Environmental Coordination Act ERDA - Energy Research and Development Administration FEA - Federal Energy Administration FES - final environmental statement FPC - Federal Power Commission gpd - gallons per day gpm - gallons per minute kWh - kilowatt (1,000 watts) hour LMFBR - liquid metal fast breeder reactor LNG - liquefied natural gas MW = megawatt (1,000,000 watts) NO - nitrous oxides x NPDES - National Pollutant Discharge Elimination System NRC - Nuclear Regulatory Commission PCRV - prestressed concrete reactor vessel PSC - Public Service Commission or Power Siting Commission PUC - Public Utility Commission SIP - state implementation plan SNG- synthetic natural gas SO - sulphur oxides 477 GLOSSARY Base load unit - an electric generating facility which is normally operated to carry base load and which, consequently, operates essentially at a constant load. Base loading - the operation of a unit at or near its rated output to supply the base load of a system. Benthic organisms - organisms attached, resting, or living on or in the bottom sediments. Blowdown - release or cleaning out of water with high solids content, the solids having accumulated each time water evaporates. BWR - boiling water reactor - a nuclear reactor in which water, used as both coolant and moderator, is allowed to boil in the core. Btu - (British thermal unit) - the amount of energy necessary to raise the temperature of one pound of water by one degree Farenheit, from 39.2 to 40.2 degrees. Capacity - maximum rating of a generating unit most often in Kw or Mw. Capacity factor - the ration of the average load on a machine, or equipment, for the period of time considered, to the capacity rating of the maching or equipment. Cooling Systems - Once through systems - where cooling water is taken from a suitable source, passed through the condenser, and returned to the source body of water. Same as direct cooling. Closed cycle systems - (evaporative cooling) where cooling water is contained in a closed system and its heat dissipated to the air through heat exchangers. Includes dry and wet cooling towers, spray ponds, canals, mechanical draft, etc. Core meltdown - failure in control mechanism or cooling system of nuclear reactor which results in nuclear pile going super-critical with meltdown and rupture of the reactor vessel potentially occurring. Efficiency - (heat rate) - measure of how effectively a thermal generating station is operating, generally expressed in Btu per net kilowatt hour. It is computed by dividing the total Btu content of fuel burned for electric generation by the resulting net kilowatt hour generation. 478 Energy - the capacity for doing work, often measured in kilowatt hours. Energy facility - broad term which includes development, production, conversion, storage, processing, transfer or transportation of any energy resource. These would include refineries, fuel transshipment and storage facilities and electric generating units. EHV lines - transmission lines which have a rated capacity above and including 230 kilovolts. Generating facility - broad term encompassing all types of electric generating facilities. Intermediate load plant - a generating unit that is normally operated to provide power for loads between base load and peak load levels. kW - MW - GW - (kilowatt, megawatt, gigawatt) instantaneous measure of electric power equal to 1,000 watts, 1 million watts, and 1 billion watts, respectively kWh - Kilowatt hour - the basic unit of electric energy equal to one kilowatt of power supplied to or taken from an electric current steadily for one hour. Load center - a point at which the load of a given area is assumed to be concen- trated. Load factor - the ratio of the average load in kilowatts, supplied during a designated period, to the peak or maximum load in kilowatts occurring in that period. LWR - light water reactor - a nuclear reactor which uses water (H2O) to transfer heat from the fissioning of uranium to a steam turbine. Load schedule - same as load curve - a curve of demand versus time of occurrence in chronological sequence the magnitude of the load for each unit of time of the period covered. Makeup water - that quantity of water added to a closed cycle cooling system needed to replace water lost through evaporation or blowdown. Nektonic - swimming organisms able to navigate at will. Particulates - microscopic pieces of solids which emanate from a range of sources and are the most widespread of all substances usually considered air pollutants. Peak demand - same as peak load - the maximum load in a stated period of time. Peaking facility - same as peaking generation - same as peaking unit - a unit which is normally operated only to provide power during high demand periods. Plant factor - same as capacity factor. 479 Planktonic - floating organisms whose movements are more or less dependent on currents. Power - the time rate at which work is done or energy emitted or transferred, measured instantaneously in kilowatts. Power plant - same as generating facility Power pool - regional grouping of utilities to promote reliability, production and transmission of electricity. PWR - Pressurized water reactor - a nuclear reactor in which heat is transferred from the core to a heat exchanger by water kept under high pressure to achieve high temperature without boiling in the primary system. Steam is generated in the secondary system. Reliability councils - coordinate in varying degrees the planning, construction, and operation of transmission and generating facilities of groups of utilities. 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Energy Reporter , Feburary, 1976. 97. Federal Energy Administration. Energy Reporter . May, 1976. 98. Great Lakes Commission, Institute of Science and Technology. Great Lakes News Letter . Vol. XX, No. 3. January - Feburary 1976. 99. U.S. Energy Research and Development Administration. The Economics of_ America's Energy Future . 1975. 100. U.S. Department of Commerce. Commerce America . April 26, 1976. "U.S. Fishery Conservation Zone 200 Miles Offshore Preserves Vital Resource." Pg. 11. 101. 94th Congress, 2d Session, Synthetic Fuel Commercial DemonstrationFund Supplemental Appropriation . Communication from the President of the United States. House Document No. 94-425. March 25, 1976. 102. U.S. Energy Research and Development Administration. Creating Energy Choices for the Future . 103. Resources for the Future, Inc. Towards a Responsible Energy Policy . 1975. 104. Resources for the Future, Inc. Limiting the Demand for Energy: Possible? Probable? July, 1974. 105. American Enterprise Institute. The Future of the Electric Utilities . Reprint No. 31. April, 1975. 106. Department of the Interior, U.S. Fish and Wildlife Service. National Power Plant Team . March, 19 76. 107. White, David C. Energy Consumption and Electric Supply Influences . 1972. NEREM - Vol. 14. 108. Power Plants in the Great Lakes Basin . 109. Energy Research and Development Administration. Nuclear Energy, Questions About Nuclear Power . May 14, 1976. 110. U.S. Energy Research and Development Administration. Fusion . 1975. 111. Public Service Electric and Gas Company. Nuclear Energy, Questions and Answers . 1976. 112. Federal Energy Administration. Energy Reporter . Special Nuclear Issue, March, 1976. 113. Atomic Industrial Forum, Inc. National Environmental Studies Project . Vol. 4, No. 2. March/April 1976. 114. 93D Congress, 2d Session. Energy Supply Act of 1974 . Senate Report No. 93-1140. September 9, 1974. 115. 94th Congress, 1st Session. Energy Independence Authority Act of 1975 . Communication from the President of the United States. House Document No. 94-284. October 20, 1975. 116. Science. Transportation Energy Conservation Policies . Vol. 192, No. 4234. April 2, 1976. 117. Inman, Donald L. Preliminary Assessment of Potential Great Lakes Offshore Oil and Gas Operations . November, 1973. 118. Union Carbide Corporation. Synthetic Natural Gas(SNG) . December, 19 75. 119. Union Carbide Corporation. The U.S. Electric Power Supply . "A Vital Service to be Wisely Priced." September, 1975. 120. Union Carbide Corporation. The Crisis in Natural Gas . December, 19 75. 121. 92nd Congress, S. 3507. Public Law 92-583. Marine Resources and Engineering Development Act of 1966, Amendment . October 27, 1972. 122. 94th Congress, S. 622. Public Law 94-163. Energy Policy and Conservation Act . December 22, 1975. 489 123. 94th Congress, 1st Session. Conference Report - Energy Policy and Conservation Act . Report No. 94-516. December 8, 1975. 124. 94th Congress, 2d Session. fl.R. 13451 . A Bill to improve the Nation's energy resources, by establishing a national power grid system, for the purpose of assuring an adequate and reliable low-cost electric power supply consistent with the enhancement of environmental values. April 29, 1976. 125. 94th Congress, 2d Session. H.R. 13350 . A Bill to authorize appropria- tions to the Energy Research and Development Administration in accord- ance with section 261 of the Atomic Energy Act of 1954, as amended, section 305 of the Energy Reorganization Act of 1974, and section 16 of the Federal Nonnuclear Energy Research and Development Act of 1974, and for other purposes. April 27, 1976. 126. 94th Congress, 2d Session. H.R. 13172 . An Act making supplemental appropriations for the fiscal year anding June 30, 1976, and the period ending September 30, 1976, and for other purposes. April 26, 1976. 127. 94th Congress, 2d Session. H.R. 13350 . A Bill to authorize appropria- tions to the Energy Research and Development Administration in accordance with section 261 of the Atomic Energy Act of 1954, as amended, section 305 of the Energy Reorganization Act of 1974, and section 16 of the Federal Nonnuclear Energy Research and Development Act of 1974, and for other purposes. April 27, 1976. 128. 94th Congress, 2d Session. H.R. 13449 . A Bill to amend the Federal Energy Administration Act of 1974 to provide for authorizations of appropriations to the Federal Energy Administration, to extend the duration of authorities under such Act, and for other purposes. April 29, 1976. 129. 94th Congress, 2d Session. S. 3339 . A Bill to promote more effective management of certain related functions in a new Department of Energy and Natural Resources. April 28, 1976. 130. 94th Congress, 2d Session. H.R. 12207 . An Act to amend the Rural Electrification Act of 1936, as amended, to correct unintended inequities in the interest rate criteria for borrowers from the Rural Electrification Administration, and to make other technical amendments. May 4, 1976. 131. 94th Congress, 2d Session. S. 3105 . A Bill to authorize appropriations to the Energy Research and Development Administration in accordance with section 261 of the Atomic Energy Act of 1954, as amended, section 305 of the Energy Reorganization Act of 1974, and section 16 of the Federal Nonnuclear Energy Research and Development Act of 1974, and for other purposes. March 9, 1976. 132. 94th Congress, 2d Session. H.R. 13410 . A Bill to create within the Energy Research and Development Administration the position of Assistant Administrator for Solar and Geo thermal Energy and Conservation, and for other purposes. April 28, 1976. 490 133. 94th Congress, 2d Session. S. 3107 . A Bill to authorize appropriations to the Nuclear Regulatory Commission in accordance with section 261 of the Atomic Energy Act of 1954, as amended, and section 305 of the Energy Reorganization Act of 1974, as amended, and for other purposes. March 9, 1976. 134. 94th Congress, 2d Session. H.R. 12387 . A Bill to authorize appropria- tions to the Nuclear Regulatory Commission in accordance with section 261 of the Atomic Energy Act of 1954, as amended, and section 305 of the Energy Reorganization Act of 1974, as amended, and for other purposes. March 9, 1976. 135. 94th Congress, 2d Session. S.J. RES. 126 . Joint Resolution consenting to an extension and renewal of the interstate compact to conserve oil and gas. May 4, 1976. 136. 94th Congress, 2d Session. S. 3362 . A Billto provide authorization for a United States contribution to the International Atomic Energy Agency in support of its safeguards activities and for other purposes. May 3, 1976. 137. 94th Congress, 2d Session. H.R. 12168 . A Bill to_ amend the National Gas Pipeline Safety Act of 1968 to authorize appropriations for fiscal year 1977. February 26, 1976. 138. 94th Congress, 2d Session. H.R. 13220 . A Bill to amend the Natural Gas Act to authorize a natural gas pipeline from the North Slope of Alaska through Canada to the contiguous forty-eight States. April 13, 1976. 139. 94th Congress, 2d Session. S. 3310 . A Bill to conserve electric energy, to reform electric utility rate regulation, to strengthen State electric utility regulatory agencies, and for other purposes. April 13, 19 76. 140. 94th Congress, 2d Session. S. 3341 . A Bill to abolish the Federal Energy Administration. April 29, 1976. 141. 94th Congress, 2d Session. S. 2872 . Amendment intended to be proposed by Mr. Pell to S. 2872, a bill to amend the Federal Energy Administration Act of 1974 to extend the expiration date of such law until September 30, 1979, and for other purposes. April 29, 1976. 142. 94th Congress, 2d Session. S. 3311 . A Bill to amend the Federal Power Act, to provide coordinated longrange planning and facility siting in the electric utility industry, and for other purposes. April 13, 1976. 143. 94th Congress, 2d Session. H.R. 13350 . A Bill to authorize appropria- tions to the Energy Research and Development Administration in accord- ance with section 261 of the Atomic Energy Act of 1954, as amended, section 305 of the Energy Reorganization Act of 1974, and section 16 of the Federal Nonnuclear Energy Research and Development Act of 1974, and for other purposes. April 27, 1976. 491 144. U.S. 94th Congress, 1st Session, Senate. Energy Facility Siting in Costal Areas. (Committee Print for Senate Committee on Commerce). U.S.G.P.O. , 19 75 . 145. Shafer, Chris A. Power Plant Siting Issues and Policies for the Great Lakes Costal Zone . Prepared for the Great Lakes Basin Commission Standing Committee on Costal Zone Management. February 3, 1975. 146. U.S. Geological Survey. Resource and Land Investigations (RALI) Pro- gram: Methodologies for Environmental Analysis . Vol. Ill: "Power Plant Siting." I 19.2: R13. 147. Wisconsin University Sea Grant Program. The Great Lakes Transportation System. Technical Report #230. January, 1976. 148. U.S. National Science Foundation. Assessment of Energy Parks vs Dispersed Electric Power Generating Facilities , Final Report. Vol. II. May 30, 1975. Report Prepared for the Office of the Science Adviser Energy R&D Policy Office Under National Science Foundation Grant OEP74-22625 A01. 149. U.S. National Science Foundation. Assessment of Energy Parks vs Dispersed Electric Power Generating Facilities , Final Report. Vol. I. May 30, 1975. Report Prepared fore the Office of the Science Adviser Energy R&D Policy Office Under National Science Foundation Grant OEP74-22625 A01. 150. New York, Cornell University Center for Environmental Quality Management. Cornell Energy Project: National Energy Needs and Environmental Quality . "Recent State Initiatives on Power Plant Siting: A Report and Comment." February, 1972. Paper No. 72-3. 151. New York, Cornell University Center for Environmental Quality Management. Cornell Energy Project: National Energy Needs and Environmental Quality . "New Institutional Arrangements to Resolve Power Plant Siting Conflicts: A Polical Analysis." February, 1972. Paper No. 72-4. 152. New York, Cornell University Center for Environmental Quality Management. Cornell E nergy Project: National Energy Needs and Environmental Quality . "Public Utility Investment and Regulatory Practices." January, 1974. Paper No. 74-1. 153. New York, Cornell University Center for Environmental Quality Management. Cornell Energy Project: National Energy Needs and Environmental Quality . "NEPA: Some Legal Constraints as Set Forth by the Court in Calvert Cliffs." October, 1971. Paper No. 71-12. 154. New York, Cornell University Center for Environmental Quality Management. Cornell Energy Project: National Energy Needs and Environmental Quality . "Coal Gasification: A Review. November, 1971. Paper No. 71-15. 155. New York, Cornell Univeristy Center for Environmental Quality Management. Cornell Energy Project: National Energy Needs and Environmental Quality . "Nuclear Insurance: An Estimate of the Cost of the Nuclear Hazard." October, 1971. Paper No. 71-13. 492 156. New York, Cornell University Center for Environmental Quality Management. Cornell Energy Project: National Energy Needs and Environmental Quality . "Federal Funding for Research and Development of Fossil Versus Nuclear Fuels Used for Civilian Energy Production." October, 1971. Paper No. 71-14. 157. New York, Cornell University Center for Environmental Quality Management. Cornell Energy Project: National Energy Needs and Environmental Quality . "Radioactive Waste Management at Nuclear Fuel Reprocessing Plants." February, 1972. Paper No. 72-2. 158. U.S. Army Corps of Engineers. St. Paul District. Draft Environmental Impact Statement . "Refined Products Terminal Lakehead Pipe Line Company, Inc. Duluth - Superior Harbor." May, 1975. 159. Empire State Electric Energy Research Corporation. 1975 Report of Member Electric Corporations of the New York Power Pool and the Empire State Electric Energy Research Corporation Pursuant to Article VIII, Section 149-b of the Public Service Law . Vol. 1. April 1, 1975. 160. Empire State Electric Energy Research Corporation. 1975 Report of member Electric Corporations of the New York Power Pool and the Empire State Electric Energy Research Corporation Pursuant to Article VIII, Section 149-b of the Public Service Law . Vol. 2. April 1, 1975. 161. U.S. 94th Congress, 1st Session, Senate, Energy Facility Siting in Costal Areas . (Committee Print For The Use of the Committee on Commerce and National Ocean Study Policy Pursuant to S. Res. 222 National Ocean Study Policy). December, 1975. 162. State of Florida, Department of Environmental Regulation. Materials Outlining Florida's Power Plant Siting Program. As of July, 1976. 163. Michigan Congress. House Bill No. 5271 . A Bill to regulate the loca- tion of power facilities within this state; to create the state power facility siting council and to prescribe its powers and duties; to re- quire utilities to prepare certain plans; and to prescribe penalties. May 20, 1975. 164. Michigan Congress. House Bill No. 4478 . A Bill to provide for review by the Michigan public service commission of plans, forecasts, and planned expansion of electric and gas utilities; to provide for the re- gulation by the commission of the location, construction, and operation of certain electric generating plants, certain electric transmission lines, and gas processing plants including holding joint hearings and issuing joint orders with other states or the the United States; to provide for certificates of public convience and necessity and environ- mental compatibility; to provide for control of costs and operating efficiency of certain electric generating plants and gas processing plants; to premit the commission to enter into interstate compacts; and to prescribe penalties. March 4, 1975. 493 165. Michigan Congress. House Bill NO. 4846 . A Bill to regulate the con- struction and use of oil and gas pipeline facilities; to authorize the public service commission to,, establish and enforce safety standards concerning oil and gas pipelines, gas processing plants, and gas stor- age facilities; to provide for rates and tariffs; to provide for con- demnations; to provide penalties; and to reveal certain acts and parts of acts. April 8, 1975. 166. Great Lakes Basin Commission Staff and Great Lakes National Assessment Work Group. State-Regional Future Great Lakes Region: 1975 National Water Assessment (Draft) . March, 1976. 167. Cornell University, Center for Environmental Quality Management. Cornell Energy Project, National Energy Needs and Environmental Quality . Technology Assessment with Special Reference to Energy, Paper No. 70-1 . Written by C.L. Comar, Principal Investigator. October, 1970. 168. Cornell University, Center for Environmental Quality Management. 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Power Plant Siting in the United States , June, 1976. 210. East Central Area Reliability Coordination Agreement. Volume V: Conceptual Planning Projections . A Report by ECAR Bulk Power Members to the Federal Power Commission Pursuant to Docket R-362, Order 383-3. April, 197 6. 211. Illinois (State) Institute for Environmental Quality. Power Facility Siting in the State of Illinois . Part 1: Siting Regulation Alternatives. 1974. 212. East Central Area Reliability Coordination Agreement. ECAR Summary Report of Permit and Contact Requirements of ECAR Members . 7 2-EAP-48. 1972 213. Illinois (State) Institute for Environmental Quality. Potential Sites for Coal Conversion Facilities in Illinois . October 21, 1974. 214. East Central Area Reliability Coordination Agreement. Volume V: Load Projections and Resource Planning . A Report by ECAR Bulk Power Members to the Federal Power Commission Pursuant to Docket R-362, Order 383-3. April 1976. 215. East Central Area Reliability Coordination Agreement. Volume II: System Performance and Transmission Planning . A Report by ECAR Bulk Power Members to the Federal Power Commission Pursuant to Docket R-362, Order 383-3. April 1976. 216. East Central Area Reliability Coordination Agreement. Volume III: Area Controls, Communication, and Emergency Preparedness . A Report by ECAR Bulk Power Members to the Federal Power Commission Pursuant to Docket R-362, Order 383-3. April 1976. 217. East Central Area Reliability Coordination Agreement. Volume IV: Liaison Systems' Data . A Report by the ECAR Liaison Committee to the Federal Power Commission Pursuant to Docket R-362, Order 383-3. April 1976. 218. U.S. 94th Congress. 1st Session. Senate. Greater Coal Utilization . Joint Hearings before the Committees on Interior and Insular Affairs and Public Works. S. 1777. Part 1. June 10 and 11, 1975. 219. U.S. 94th Congress. 1st Session. Senate. Greater Coal Utilization . 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Pennsylvania Carnegie-Mellon University, School of Urban & Public Affairs. Power Plant Siting Policy Alternatives for Pennsylvania . May 4, 1976. 237. Council of State Governments. State Responses to the Energy Crisis March 1974. 238. Council of State Governments. State Energy Management; The California Energy Resources Conservation and Development Commission . May 1976. 239. Boeing Commercial Airplane Company. Intercity Passenger Transportation Data: Service and Economic Comparisons, Volume I . May, 1975. 240. Boeing Commercial Airplane Company. Intercity Passenger Transportation Data: Energy Comparisons, Volume 2 . May, 1975. 241. New York Dept. of Transportation. Introductory Materials to the Comprehensive Upstate New York Ports Study . April 8, 1975. 242. New York Dept. of Transportation. Preliminary Progress Report: New York State Dept. of Transportation Upstate Public Ports Study. Phase I Report . July, 1975. 243. U.S. Army Corps of Engineers, North Central Division. Great Lakes/ St . Lawrence Seaway Traffic Forecast Study . Summary Report. February, 1976. 244. Massachusetts, Berkshire County Regional Planning Commission. Evaluation of Power Facilities: A Reviewer's Handbook . April, 1974. 245. Texas (University of), Petroleum Extension Service. Introduction to the Oil Pipeline Industry . May, 1966. 246. Texas (University of), Petroleum Extension Service. Oil Pipeline Construc - tion and Maintenance, Volume II . April, 1973. 247. Oak Ridge National Laboratory. Ecology and Resource Economics: An Integration and Application of Theory to Environmental Dilemmas . April, 1971. 248. Federal Power Commission. Hydroelectric Power Resources of the United States — Developed and Undeveloped . January 1, 1972. 249. Department of Transportation. Energy Primer: Selected Transportation Topics . 1975. 250. Michigan University, Dept. of Naval Architecture and Marine Engineering. Optimum Capacity of Ships and Port Terminals . December, 1973. 251. 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Part IV, Decision Guidelines and Development Alternatives. November, 1975. 516 503. New England Regional Commission. Gas Industry Development in New England Analysis of Alternatives . Parts I, II, III. November, 1975. 504. New England Regional Commission. Petroleum Development in New England : Economic and Environmental Considerations . Volume One of Four Volumes: Executive Summary. November, 1975. 505. New England Regional Commission. Petroleum Development in New England : Economic and Environmental Considerations . Volume Two of Four Volumes: Modular Results. November, 1975. 506. New England Regional Commission. Petroleum Development in New England : Economic and Environmental Considerations . Volume Three of Four Volumes : Regional Factors. November, 1975. 507. New England Regional Commission. Petroleum Development in New England : Economic and Environmental Considerations . Volume Four of Four Volumes: Appendices. November, 1975. 508. New England Regional Commission. Decision Making for Energy Facilities in New England: Institutional and Legal Process . December, 1975. 509. Ohio Power Siting Commission. The Mead Corporation Chillicothe, Ohio Facility Ten Year Electric Demand Forecasts . 1976. 510. Ohio Power Siting Commission. Duquesne Light Company, 1976 . Ten Year Forecast Report Submitted to the Ohio Power Siting Commission. 511. Ohio Power Siting Commission. The Cincinnati Gas and Electric Company . Ten Year Forecast Report to the Ohio Power Siting Commission. 1976. 512. Ohio Power Siting Commission. Ohio Valley Electric Corporation: Ten Year Forecast Report to the Ohio Power Siting Commission . 1976. 513. Ohio Power Siting Commission. Columbus and Southern Ohio Electric Company: Ten Year Forecast Report to the Ohio Power Siting Commission . 1976. 514. Ohio Power Siting Commission. 1975 Key Ohio Electric Utility Statistics . 515. Ohio Power Siting Commission. The Cleveland Electric Illuminating Co . Ten Year Forecast Report to the Ohio Power Siting Commission . 1976. 516. Ohio Power Siting Commission. Monongahela Power Company Ten-Year Forecast Report to the Ohio Power Siting Commission . April 15, 1976. 517. Ohio Power Siting Commission. The Goodyear Tire and Rubber Company , Akron Facility: Ten Year Electric Demand Forecasts . 1976. 518. Ohio Power Siting Commission. PPG Industries: Ten Year Forecast Report to the Ohio Power Siting Commission . 519. Ohio Power Siting Commission. Union Carbide Corporation Power Station : Ten Year Forecast Report to the Ohio Power Siting Commission . April 15, 1976. 517 520. Institute for Contemporary Studies. No Time to Confuse . A Critique of the Final Report of the Energy Policy Project of the Ford Foundation: A Time to Choose America's Energy Future. 1975. 521. U.S. 94th Congress. 1st Session. Senate. Air Quality and Stationary Source Emission Control . A Report by the Commission on Natural Resources National Academy of Sciences, National Academy of Engineering, National Research Council. March, 1975. 522. Chesser, Al H. Economic Advantages of Transporting Coal by Rail vs . Coal Slurry Pipeline . June, 1976. 523. Environmental Protection Agency. Air Quality Implementation Plans : Prevention of Significant Air Quality Deterioration . Federal Register Volume 39, Number 235, Part III. December 5, 1974. 524. Environmental Protection Agency. Environmental News . November 27, 1974. 525. U.S. 91st Congress, H.R. 17255. The Clean Air Act Amendments of 1970 . December 31, 1970. 526. Commonwealth Associates, Inc., Landplan Systems Division. Environmental Report on the Belle River Power Generating Facilities, St. Clair County , Michigan . Prepared for the Detroit Edison Company. April 8, 1974. 527. Zeni, L.E. Electrical World , "Maryland Pioneers with State Siting Program", April 1, 1976. Volume 185, Number 7, p. 30-33. 528. Central Electricity Generating Board. Modern Power Station Practice . Second Revised and Enlarged Edition. Volume 1. 529. Decker, Gerald L. The Dow Chemical Company. Power Plant Design Considera- tions for Energy Conservation . 1975. 530. Wisconsin University, Institute for Environmental Studies. 1975 Survey of Energy Use in Wisconsin , May, 1976. 531. U.S. Federal Power Commission. Alaska Natural Gas Transportation Systems : Final Environmental Impact Statement . September, 1976. 532. Burlington Northern, Inc. Statement of Louis W. Menk, Chairman and Chief Executive Officer, Burlington Northern Inc . , Before the House Committee on Interior and Insular Affairs. H.R. 1863, 2220, 2553, and 2896. 533. Ohio Power Siting Commission. Ten Year Forecast of Electric Generation and Transmission Facilities, 1976-1986 . Submitted by Buckeye Power, Inc. April 15, 1976. » 534. U.S. Federal Power Commission. The Adequacy of Future Electric Power Supply; Problems and Policies . Technical Advisory Committee on the Impact of Inadequate Electric Power Supply. March, 1976. 518 535. Greenwood, John 0. Greenwood's Guide to Great Lakes Shipping . April, 1975. 536. U.S. Army Corps of Engineers. Waterborne Commerce of the United States . Calendar Year 1974. 537. New York Coastal Zone Management Program. Land and Water Uses . July, 1976. 538. U.S. 94th Congress, 1st Session, Senate. Air Quality and Stationary Source Emission Control . March, 1975. 539. U.S. Army Corps of Engineers, St. Paul District. Draft Environmental Impact Statement. Units 7, 8 & 9, Presque Isle Generating Station Upper Peninsula Generating Co . March, 1976. 540. U.S. Dept. of the Interior. Feasibility of Alternative Means of Cooling for Thermal Power Plants Near Lake Michigan . September, 1970. 541. Bechtel Corporation. Manpower, Materials, and Capital Costs for Energy- Related Facilities . Research Sponsored by Brookhaven National Laboratory Associated Universities, Inc. April, 1976. 542. Dukert, Joseph M. Nuclear Power and the Environment . 1976. 543. Committee for Economic Development. Nuclear Energy and National Security . A Statement by the Research and Policy Committee of the Committee for Economic Development. September, 1976. 544. National Academy of Engineering. Engineering for Resolution of the Energy- Environment Dilemma . 1972. 545. Battelle Columbus Lakes, Ohio. Environmental Considerations in Future Energy . April, 1973. 546. Argonne National Laboratory. Proceedings of the Second Federal Conference on the Great Lakes . March 25-27, 1975. 547. Federal Power Commission. Annual Summary of Cost and Quality of Steam- Electric Plant Fuels 1975 . May, 1976. 548. National Academy of Sciences. Port Development in the United States . Washington, D.C. 1976. 549. Coastal Zone Laboratory. Appendix A: Engineering-Economic Analysis of Shore Protection Systems: A Benefit/Cost Model . 550. U.S. Bureau of Mines. Long-Distance Coal Transport: Unit Trains or Slurry Pipelines . 1975. 551. Detroit Edison. Enrico Fermi Atomic Power Plant, Unit 2 . Applicant's Environmental Report Operating License Stage, Volume 2. 519 552. Wisconsin Electric Power Company. Environmental Report: Pleasant Prairie Power Plant, Units 1 and 2, Volume 1 . February, 1975. 553. Wisconsin Electric Power Company. Environmental Report: Pleasant Prairie Power Plant, Units 1 and 2, Volume 2 . February, 1975. 554. Wisconsin University. Institute for Environmental Studies. Energy Systems Forecasting, Planning and Pricing . Proceedings of a French- American Conference University of Wisconsin-Madison, 23 September - 3 October, 1974. 555. U.S. Energy Research & Development Administration. A National Plan for Energy Research, Development & Demonstration: Creating Energy Choices for the Future . Volume 1: The Plan. 556. New York. Cornell University. Center for Environmental Quality Mgmt. Cornell Energy Project. Summary of Present Status of High Voltage D.-C . Transmission . By Simpson Linke. December, 1974. 557. New York. Cornell University. Center for Environmental Quality Mgmt. Cornell Energy Project. On the Minimum Size of Natural-Draft Dry Cooling Towers for Large Power Plants . By Franklin K. Moore. August, 1972. 558. New York. Cornell University. Center for Environmental Quality Mgmt. Cornell Energy Project. A Pricing System for Pollution Control . By J.E. Hass. March, 1972. 559. New York. Cornell University. Center for for Environmental Quality Mgmt. Cornell Energy Project. A Critique of the New EPA Emission Standards for New Stationary Sources . By C.R. Aleta. October, 1971. 560. New York. Cornell University. Center for Environmental Quality Mgmt. Cornell Energy Project. Cost Comparison Between Natural Gas and Electricity . By Rob Hogue. June, 1971. 561. New York. Cornell University. Center for Environmental Quality Mgmt. Cornell Energy Project. Electric Utility Optimum Mix Model . By K.B. Cady and J. Hass. January, 1971. 562. U.S. Nuclear Regulatory Commission. Final Environmental Statement Related to Manufacture of Floating Nuclear Power Plants by Offshore Power Systems . Volume 1 . September 1976. 563. U.S. Nuclear Regulatory Commission. Final Environmental Statement Related to Manufacture of Floating Nuclear Power Plants by Offshore Power Systems , Volume 2 . September 1976. 564. U.S. Bureau of Reclamation. Construction Cost Trends . January 1976. 565- New York Dept. of Transportation. Upstate Public Ports Study, Volume I , Market Potential: Phase I . September 1976. 566. New York Dept. of Transportation. Upstate Public Ports Study, Volume II , Market Potential: Phase II . September 1976. 567. New York Dept. of Transportation. Upstate Public Ports Study, Volume III , Port Development Plans and Policies . September 1976. 520 568. Illinois Coastal Zone Management Program. Energy . 569. Argonne National Laboratory. Air Quality Policy Analysis of Electric Utilities: A Regional Perspective . March, 1975. 570. U.S. Nuclear Regulatory Commission. Regulatory Guide 4.7: General Site Suitability Criteria for Nuclear Power Stations . November 1975. 571. Argonne National Laboratory. A Study of Social Costs for Alternative Means of Electrical Power Generation for 1980 and 1990 . Prepared for Atomic Energy Commission. February 1973. 572. Comar, C.L. and Sagan, L.A. Health Aspects of Energy Production and Conversion . 573. Wisconsin Electric Power Company. Environmental Report: Pleasant Prairie Power Plant, Units 1 and 2 , Volume 1. February 1975. 574. Wisconsin Electric Power Company. Environmental Report: Pleasant Prairie Power Plant, Units 1 and 2 , Volume 2. February 1975. 575. Energy Research & Development Administration. Annual Report for 1975 : Laramie Energy Research Center . January, 1976. 576. Department of the Interior. Energy Perspectives 2 . June 1976. 577. Environmental Protection Agency. Fuel and Energy Production by Bioconver- sion of Waste Materials . State-Of-The-Art. August 1976. 578. U.S. 94th Congress, 2nd Session. Senate. ERDA Energy Conservation Programs March 5, 1976. 579. U.S. 94th Congress, 2nd Session. Senate. Federal Energy Reorganization : Issues and Options . Report to the Committee on Government Operations. September, 1976. 580. Department of the Interior. Leasing and Management of Energy Resources on the Outer Continental Shelf . 581. U.S. 94th Congress, 2d Session. Coastal Zone Management Act Amendments of 1976. Report of the Committee of Conference on S. 586 . June 24, 1976. 582. U.S. 92nd Congress, S. 3507. Public Law 92-583: Coastal Zone Management Act of 1972 . October 27, 1972. 583. U.S. Army Corps of Engineers. The Port of Chicago, Illinois . Port Series No. 46. Revised 1975. Washington, D.C. 584. U.S. Army Corps of Engineers. The Port of Detroit and Ports on the Saginaw River Michigan . Port Series No. 45, Revised 1972. Washington, D.C. 585. Department of Transportation. Energy Statistics: A Supplement to the Summary of National Transportation Statistics . August, 1974. 521 586. U.S. Bureau of Mines. Minerals Yearbook 1973 . Volume II, Area Reports: Domestic. Washington, D.C. 1976. 587. National Aeronautics and Space Administration. ECAS — Westinghouse Phase I Final Report . Volume I — Introduction and Summary and General Assumptions . 588. National Aeronautics and Space Administration. ECAS — Westinghouse Phase I Final Report . Volume II — Materials Considerations . 589. National Aeronautics and Space Administration. ECAS — Westinghouse Phase I Final Report . Volume III — Combustors, Furnaces and Low BTU Gasifiers . 590. National Aeronautics and Space Administration. ECAS — Westinghouse Phase I Final Report . Volume IV — Open Recuperated and Bottomed Gas Turbine Cycles . 591. National Aeronautics and Space Administration. ECAS — Westinghouse Phase I Final Report . Volume V — Combined Gas-Steam Turbine Cycles . 592. National Aeronautics and Space Administration. ECAS — Westinghouse Phase I Final Report . Volume VI — Closed-Cycle Gas Turbine Systems . 593. National Aeronautics and Space Administration. ECAS — Westinghouse Phase I Final Report . Volume VII — Metal Vapor Rankine Topping-Steam and Bottoming Cycles . 594. National Aeronautics and Space Administration. ECAS — Westinghouse Phase I Final Report . Volume VIII — Open-Cycle MHD . 595. National Aeronautics and Space Administration. ECAS — -Westinghouse Phase I Final Report . Volume IX — Closed-Cycle MHD . 596. National Aeronautics and Space Administration. ECAS — Westinghouse Phase I Final Report . Volume X — Liquid-Metal MHD Systems . 597. National Aeronautics and Space Administration. ECAS — Westinghouse Phase I Final Report . Volume XI — Advanced Steam Systems . 598. National Aeronautics and Space Administration. ECAS — Westinghouse Phase I Final Report . Volume XII — Fuel Cells . 599. U.S. DPA. Methods for Identifying and Evaluating the Nature and Extent of Nonpoint Sources of Pollutants . 1973. 600. Peelle, Elizabeth. Socioeconomic Effects of Operating Reactors on Two Host Communities: A Case Study of Pilgrim and Millstone. Presented at Conference on Land Use and Nuclear Facility Siting: Current Issues. Sponsored by Atomic Industrial Forum, Denver, Colorado. July 18-21, 1976. 601. Peelle, Elizabeth. Social Effects of Nuclear Power Plants . 1974. 602. Young, Loise B. Power Over People. 1973. 522 603. Department of the Interior. Water Quality Critera . Report of National Technical Advisory Committee. 604. Department of the Interior. Bituminous Coal and Lignite Distribution Calendar Year 1975 . April 12, 1976. 605. World Ports/American Seaport . "Superior's Mammoth Coal Terminal. September, 1975. 606. U.S. Army Corps of Engineers. Ports on Lake Michigan, Part 2 . 1974. 607. Great Lakes Basin Commission. Appendix 12: Shore Use and Erosion . 608. Consumers Power Company. Environmental Report, Volume 3: Quanicassee Plant, Units 1 & 2 . February, 1974. 609. Eichholz, Geoffrey. Environmental Aspects of Nuclear Power . 610. New York State University. Sea Grant Project. Visual Quality and the Coastal Zone: Conference Proceedings . 611. U.S. Department of the Interior. The Need for a National System of Transportation and Utility Corridors . July 1, 1975. 612. U.S. Department of the Interior. Environmental Criteria for Electric Transmission Systems . 1970. 613. Special Committee on Electric Power and the Environment. Electricity and the Environment: The Reform of Legal Institutions . A Report of the Association of the Bar of the City of New York. 614. U.S. Atomic Energy Commission. Final Environmental Statement . Related to Operation of Davis-Besse Nuclear Power Station, Unit 1. Proposed by Toledo Edison Company. October 1975. 615. Armstrong, John R. and Bensky, Lawrence. Energy: The Institutional Question . February, 1975. 616. U.S. 94th Congress. 2nd Session. Senate. Land Use and Energy: A Study of Interrelationships . January 1976. 617. Edsall, T.A. "Electric Power Generation and Its Influence on Great Lakes Fish". By Argonne National Laboratory: Proceedings of the Second Federal Conference on the Great Lakes . 618. Asbury, J.G. "Future Fossil Energy Requirements in the Great Lakes Basin State." Argonne National Laboratory: Proceedings of the Second Federal Conference on the Great Lakes. 523 619. Wisconsin Planning Office. Energy: The Institutional Question . Prepared by Lawrence Bensky and John R. Armstrong. February 1975. 620. Federal Power Commission. The Thermal Component of Atlantic Coast Estuarine Environments . 1974. 621. Federal Power Commission. Energy Technology III: Regional Energy Systems Planning . 1976. 622. A Statement of Concerns and Suggested Ecological Research, Report No. 1 of the Lake Michigan Cooling Water Studies Panel . Panel supported by the United States Environmental Protection Agency, Region V, and the Pollution Control Agencies of Illinois, Indiana, Michigan, and Wisconsin. 1975. 623. U.S. Department of Commerce. "Energy Impact Complicates Coastal Manage- ment Problem", Commerce America , pp. 4-6. October 11, 1976. 624. Environmental Protection Agency. "Steam Electric Power Generating Point Source Category: Effluent Guidelines and Standards". Federal Register . Title 40, Chapter 1, Subchapter N, Part 423. Volume 39, No. 196, Part III, Tuesday, October 8, 1974. 625. Energy Research and Development Administration. Role of Transportation in the Nuclear Fuel Cycle , report to the Michigan Environmental Review Board at its July, 1976, meeting, Lansing, Michigan. 626. Environmental Protection Agency. Federal Register ., Vol. 41, No. 81, "Effluent Guidelines", Title 40, Chapter 1, Part 401/402. Monday, April 26, 1976. 627. Environmental Protection Agency. "Thermal Discharges", Title 40, Chapter 1, Part 122. Federal Register , Voluem 39, No. 196, Part II. Tuesday, October 8, 1974. 628. U.S. Environmental Protection Agency. Development Document for Best Technology Available for the Location, Design, Construction, and Capacity of Cooling Water Intake Structures for Minimizing Adverse Environmental Impact . April, 1976. 629. Federal Register . "208 Planning Rules. Appendix C, 40 CFR Part 130 and 131: Policies and Procedures for Continuing Planning Process, Preparation of Water Quality Management Plans." Vol. 40, No 230. Friday, November 28, 1975. 630. Environmental Protection Agency. Coordination of Coastal Zone Management Plans and Air Quality Implementation Plans . August, 1976. 631. U.S. 94th Congress. 2nd Session. Senate. Legislative History of the Coastal Zone Management Act of 1972, as Amended in 1974 and 1976 with a Section-by-Section Index. December 1976. 524 632. U.S. Department of Commerce, National Oceanic and Atmospheric Administration, "Notice of Final Rulemaking, Coastal Zone Management Program Development Grants": Federal Register , Vol. 38, No. 229, November 29, 1973. 633. U.S. Department of Commerce, National Oceanic and Atmospheric Administration, "Notice of Final Rulemaking, Coastal Zone Management Program Administrative Grants": Federal Register , Vol. 40, No. 6, January 9, 1975. 634. U.S. Department of Commerce, National Oceanic and Atmospheric Administration, "Proposed Regulations, Federal Consistency with Approved Coastal Zone Management Programs": Federal Register , September 28, 1976. 635. U.S. Department of Commerce, National Oceanic and Atmospheric Administration, "Proposed Regulations for Financial Assistance to Coastal States, Coastal Energy Impact Program": Federal Register , October 22, 1976. 636. 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