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HomeMy WebLinkAboutElectric Power in Alaska - A Report for the House Finance Committee 1976 ENE Alaska Power Authority 045 LIBRARY COPY N r D Y ELECTRIC POWER IN ALASKA, 1976-1995 A Report for the House Finance Committee Second Session Ninth Legislature State of Alaska August 1976 R dD INSTITUTE OF SOCIAL AND ECONOMIC RESEARCH UNIVERSITY OF ALASKA Anchorage ¢ Fairbanks ¢ Juneau ELECTRIC POWER IN ALASKA, 1976-1995 A Report for the House Finance Committee Second Session, Ninth Legislature State of Alaska by THE INSTITUTE OF SOCIAL AND ECONOMIC RESEARCH UNIVERSITY OF ALASKA ANCHORAGE e FAIRBANKS e JUNEAU in cooperation with Kent Miller, Ketchikan Robert W. Retherford Associates, Anchorage Stefano-Mesplay and Associates, Inc., Anchorage and National Economic Research Associates, Inc., New York City August 1976 ENE oOUsS 5 ee PREFACE Meeting Alaska's electric demand, both current and long-term, has been the subject of much discussion and many studies. Proposed solutions have generally been directed toward the needs of indi- vidual localities or developing massive power projects to serve usually undefined future industrial potentials. The approach to large-scale projects and the few statewide studies previously undertaken has usually been based on power supply potentials rather than upon demand to serve Alaska's needs. In most instances, investigations and proposals have been the product of agencies and firms with vested interests in specific technological solutions. Recognizing the need to pursue sound development and expansion of power sources in order to provide adequate electric power services to Alaskans at reasonable rates, the 1975 Alaska State Legislature author- ized a comprehensive demand and supply study for the state. Specifically, the Legislature provided that the study: 1. Project the demand for electric power in each of Alaska's regions over the next 5- and 20-year periods, based upon popu- lation and income factors. 2. Carry out an inventory by regions of alternative sources of electric power, including but not limited to water, gas, coal, diesel, geothermal, solar, nuclear, and wind sources. 3. Perform an analysis by region of these alternative power sources, iii including economies of scale, distribution systems, environ- mental impacts, reliance on renewable vs. nonrenewable re- sources, and other factors. 4. Illustrate the kind of projects that would be most efficient generators of electric power. 5. Analyze alternative methods of financing future development and distribution of electric power in the state and its regions The Legislative Budget and Audit Committee contracted with the Institute of Social and Economic Research (ISER) of the University of Alaska to take responsibility for and perform the bulk of research under the electric power demand and alternative supply study. At legislative request, Arlon R. Tussing was designated study director, with principal responsibility for study design, execution, and for synthesizing study results. Other principal ISER staff participants in the study were Scott Goldsmith, Lloyd Pernela, and Mike Scott. Carrying out the study became a unique effort. The Legislature had stipulated that preference be given to Alaska-based consultants. The initial organizational effort quickly proved that the basic professional economic and engineering capability existed within Alaska without re- quiring recourse to out-of-state consultants for major segments of the work. In consultation with the Legislature, Dr. Tussing and Victor Fischer, until recently ISER director, assembled a highly competent and effective working team consisting of the Institute of Social and Economic Research of Fairbanks and Anchorage, Kent Miller of Ketchikan, Robert W. Retherford iv and Associates of Anchorage, Stefano-Mesplay and Associates of Anchorage, and Homan and McDowell Associates of Juneau. The only outside consultant used was Herman G. Roseman of National Economic Research Associates of New York, who provided special assistance in examining alternative means of financing future power development. In addition to these study participants, extensive information was provided by many state and federal agencies, public and private util- ities, and many others. They are literally too numerous to mention, but their contribution is nonetheless greatly appreciated. ISER particularly appreciates the support provided by the Legisla- ture. Representative Hugh Malone, Chairman of the House Finance Committee and principal author of House Concurrent Resolution No. 71 mandating the study, and Representative Ed Naughton, Chairman of the Legislative Budget Committee, took a personal interest in and provided strona support for the electric power study. Our very special thanks also go to Jim Rhode, prin- cipal staff assistant to Representative Malone, who not only carried out project oversight in behalf of the Legislature, but also provided policy guidance and substantive advice throughout the study. This final report on the Alaska electric power study reflects the internal review of a preliminary study draft by the study team, comments received on the draft from reviewers in utility industry and government agencies, and results of the March 1976 legislative hearing on the study. In addition to this report, the Legislature has been provided with the computer models and other information produced as part of this project. ISER has been advised that this study has already been of major service to the Legislature during the recent session. It is our hope that this final report will prove of value to others in helping to deal with Alaska's present and future requirements for electric power. August 1976 Edward Lee Gorsuch Director, ISER vi ALASKA ELECTRIC POWER STUDY TABLE OF CONTENTS I. ELECTRICITY GENERATION IN ALASKA--SUMMARY AND CONCLUSIONS Introduction 1-1 Anchorage and Southcentral 1-2 Fairbanks 1-16 Southeast 1-20 Rural Alaska 1-24 II. EXISTING SYSTEM Introduction Southcentral and Anchorage Regions Fairbanks Region Southeast Region Rural Alaska CTA ONUNH III. ELECTRICITY DEMAND PROJECTIONS Summary and Conclusions 3-1 Utility Demand Sef. A. Recent Growth Pattern 3-7 B. The Future Alaskan Economy 3-19 C. The Intensity of Electricity Consumption 3231 D. Future Demand Projections 3-68 Electricity Demand in Rural Areas 3-99 A. Past Trends 3-99 B. Future Demand 3-106 Industrial Demand 3-116 A. Past Trends 3-116 B. Projections of Requirements 3-118 Military Electricity Demand 3-123 Bibliography 3-127 IV. ELECTRICITY GENERATING TECHNOLOGY REVIEW Diesel Electric Generating Units 4-1 Combustion Turbine (Gas Turbine) Gen- erating Units 4-3 vii TABLE OF CONTENTS (Continued ) Steam Turbine Generating Units Hydroelectric Generating Units Other Generating Technologies ELECTRIC ENERGY RESOURCE INVENTORY Oil and Gas Resources Inventory Coal Inventory Oil Shale Inventory Geothermal Inventory Regional Hydroelectric Resources The Solar Energy Resource The Wind Power Resource Tidal Power in Alaska FINANCING ELECTRIC POWER SUPPLY IN ALASKA Preparatory Remarks Methods of Organizing and Financing Electric Power Supply in the U.S. A. Costs of Operations B. Costs of Financing Financing Alternatives for Power Supply in Alaska Subsidies for Electric Power ANALYSIS OF GENERATION ALTERNATIVES Economics of Generation Mode Capital and Operating Cost Forecasts The Investment Model Structure and Assumptions Regional Analysis of Generation Alternatives APPENDICES viii 4-10 4-23 I. ELECTRICITY GENERATION IN ALASKA - SUMMARY AND CONCLUSIONS Introduction This section summarizes the study's findings regarding future require- ments for electricity in Alaska; the modes of generation and transmission which will minimize the costs to consumers of meeting these requirements; and the alternatives available to Alaska's utilities for financing required new capital investment. The results in each of these areas rest on a large set of assumptions about the state's population growth, personal income, the costs of construction, labor, and various fuels, and the cost of money to each of several types of utility. The assumptions, interrelationships, and calculations, which typically were made with the help of a computer model, are presented in detail in the body of the report and its appendices. The organization of this summary is as follows: The first part is devoted to the problems of the Anchorage-Southcentral Alaska region, which has the largest population and expected demand growth, the most complex existing generation and transmission system, the widest range of possible development strategies, and the greatest problems in financing new con- struction commensurate with community needs. The general principles ap- plied in analyzing the technical and financial problems of the utilities are explained in the pages dealing with Anchorage and its surrounding areas. 1-1 Subsequent sections deal with the Fairbanks region, whose problems and opportunities resemble those of Anchorage, but on a smaller scale. Southeastern Alaska, which expects more moderate growth and is composed of a number of smaller and isolated load centers, is treated next. Finally, the technical and financial problems of the isolated bush com- munities of Northwest, Southwest and Interior Alaska are discussed. In dealing with each successive region, all those general principles covered for the previous, more populous regions have been assumed, and only those issues are explained which are being introduced for the first time. Anchorage 1. The most serious problems in providing for the growth of electricity usage are in Anchorage and the surrounding areas of South- central Alaska where most of the state's people live. This area's loads are expected to grow at a compounded rate of no less than about nine percent per year in the next decade; under certain plausible assumptions loads could grow at more than sixteen percent per year. (Table 1.1) Even the low estimate means that the utilities would have to double the amount of clectricity generated in about eight years; the higher figure would require a doubling of output every four and one half years! The absolute amounts of capacity that need to be added in Anchorage and Southcentral Alaska are even more staggering. The peak capacity of the area's utilities was 337 megawatts in 1974. The lowest of our projections requires an addition of more than 500 megawatts by 1985 and another thousand megawatts by 1995. The highest alternative requires 1350 megawatts of new capacity by 1985 -- a fivefold increase! The high assumption implies that a further three thousand megawatts must be added between 1985 and 1995. The rapid growth of the region's requirements for generating capacity is both "good news and bad news." Its advantages and difficulties are described below. Table 1-1 ELECTRICITY REQUIREMENTS IN ANCHORAGE AND SOUTHCENTRAL ALASKA Capacity Total Energy Growth Rate Year Required (MW) (Million KWH) (Annual Percent) low high low high low high 1974 261 261 1149 1149 1985 702 1394 3095 6523 9.4 701, 1995 1672 4162 7004 18141 9.0 14.0 2. The exceedingly rapid growth of electrical demand in Anchorage and surrounding areas is a great advantage in selecting the lowest cost combination of generating equipment. The most efficient potential sources of base load power for the region would be large (100 MW and up) steam plants or even larger hydro projects, such as are proposed for the Susitna River. Such plants, however, could achieve lower costs than gas turbines of smaller capacity (50-100 MW) only if operated at close to their full capacities. 1-3 The ability to use the larger thermal or hydro generating plants elliciently depends not only on the total demand but also on its: a) reserve capacity -- the amount of capacity the system can afford to lose because of the failure of its largest single unit and still meet the anticipated peak demand; and on its b) load growth -- the speed at which the growth of demand will fully utilize the capacity of a new plant. Load growth is especially critical in the case of large capital intensive thermal. or hydro plants because a facility that has to remain partly idle for years while demand catches up with its capacity can be far more expensive than a theoretically less efficient smaller plant. 3. The expected growth of electricity usage in the Anchorage- Southcentral Alaska region during the period covered by this study permits serious consideration for the first time of large-scale (100- 500 MW) steam or hydro generation facilities. The mix of generating equipment that is, in fact, optimum for the region, and the specific units which should be added in specific years depend upon a number of factors, including the terms on which the utilities can obtain capital and the future availability and prices of coal and natural gas. In principle, the lowest prices for large increments of base load power would be obtained from the Susitna hydro project. Unfortunately, 1-4 Table 1-2 Anchorage Base Load Units This table is designed to compare the first cost and cost to consumers during the initial year of operation of various types of generating units. Cost of Energy in Mills/kwo i for initial year of plant operatio: Equipment Capacity Fuel First Cost Fuel Price @ stated fuel prices MW $/kw ¢/mmbtu and interest rates Interim Financing for Initial of 6% and 8% @ 6% @ 8% Year of Plant . M H Operation 1985 gas turbine cle 50 gas $355 242-322-402 51.7 64.0. 76.4 aia $358 53.4 65.7 78.0 gas turbine tive cycle 50 gas $438 242-322-402 tee. 5050) 5822 in $443 43.8 52.0 60.3 ‘bi 200 coal $809 115-153-191 36.9 40.6 44.4 ee - $839 44 45.2 48.9 turbine 200 coal $809 115-153-191 33.2: -36.9:-—"40.6 — (30 yr financing) $839 $6.52, -4459°*-US6 i 200 as $680 242-322-402 45.1 §2.9 60.7 — $705 ; 48.9 56.7 64.5 . = =I 8 $7.6 bi 200 gas $680 242-322-402 42.0 49. eae (30 yr financing) $705 46.2 54.0 61.8 hydro 792 Watana $2,901 per installed (7%) --- 103.5 6%-20 yr-coverase (Corps of Engineers proposal) 70.0 6%-20 yr-no cover. (1987 dollars) 86.6 6%-30 yr-coverazge 68.4 6%-30 yr-no cover. 51.3 6%-50 yr-no cover. 119.7 8%-20 yr-coverace 80.5 8%-20 yr-no cover. 105.5 8%-30 yr-coveraze 69.0 8%-30 yr-no cover. 65.5 8%-50 yr-no cover. Assumptions: 20 year financing of fossil plants unless otherwise noted Coverage factor of 1.5 on fossil plants Cost escalation at 6 percent materials, 8 percent labor 55 percent load factor on fossil plants Combined cycle gas units are also technically feasible but have not been analyzed No credit for secondary energy for hydro Note: Large scale steam turbine units have yet to be built in Alaska. Asa result, there is no general agreement among engineers regarding the capital cost of such a project, and some would feel the first cost in this table to be somewhat low. Table 1-2 Continued i Cost of Energy in Mills/kwh % i for Initial Year of Plant Operation Equipment Capacity Fuel First Cost Fuel Price @ stated fuel orices MW $/kw ¢/mmbtu and interest rates a Interim Financing for Initial of 6% and 8% @ 6% @ 8% Year of Plant L M H Operation : 1990 gas turbine simple cycle 50 gas $486 323-431-539 70.1 86.6 103.2 $491 72.4 88.9 105.4 gas turbine regenerative cycle 50 gas $601 323-431-539 56.9: 67.9: 78.9 * $606 . 59.7 70.7 81.7 steam turbine 200 coal $1110 169-225-281 $2.0 eats 63.9 $1149 58.2 63.6 69.2 steam turbine 200 coal $1110 169-225-281 46.9. SOC 5758 (30 yr financing) $1149 $3.7... .59.2> 68-6 steam turbine 200 gas $932 323-421-539 61.4 Tio 82.3 : $965 66.6 77.0 87.5 steam turbine 200 gas $932 323-431-539 57.1, 6726. 7850 (30 yr financing) $965 62.8 73.3 83.7 hydro 1,568 Watana and $2,252 (7%) -—-- 719.1 6%-20 yr-coverage : : Devils Canyon 53.3 6%-20 yr-no cover. (Corps of Engineers proposal) 66.2 6%-30 yr-coveraze (1992 dollars) 44.8 6%-30 yr-no cover. » 39.8 6%-50 yr-no cover. 91.4 8%-20 yr-coverage 61.5 8%-20 yr-no cover. 80.6 8%-30 yr-coverage 64.3 8%-30 yr-no cover. 60.1 8%-50 yr-no cover. 1-5 (a) because of financing constraints described later, the Susitna project does not in fact seem to result in the lowest rates to consumers unless both of two conditions are met: a) new organizational forms, or federal ownership, relieve Alaska consumers of the need to service the construction loan prior to completion, and b) the price of coal or natural gas, whichever is the lower, is at least as high as the values assumed for this study. 4. Choosing the optimal future generating plant depends highly on future availability and price of natural gas, which is presently the cheapest source of energy to the utilities of the region. We have assumed in this study, however, that a national shortage of natural gas will continue, and that gas consumers elsewhere in the United States and industrial customers in Alaska (serving national or international markets) will be able to outbid the local utilities for new gas supplies unless the latter are willing to pay at least 75 percent of the world oil price in terms of heating value for that gas. There is, in addition, a serious possibility that federal legislation responding to the national shortage will prohibit the use of new natural gas supplies for utility boiler fuel or for all utility use. On the other hand, there is also a real possibility of major new gas finds in Lower Cook Inlet, the Gulf of Alaska, or onshore in South- central Alaska}? Such discoveries could keep the region a gas surplus § e 1-6 area for many years and hold prices substantially below the prices of alternate fuels. (North Slope natural gas, even if moved by a Trans-Alaska gas pipeline, would likely be more expensive in the Anchorage area than coal. ) Three major implications arise from the uncertainty about the natural gas outlook and the probability that gas will be more expensive than coal (or unavailable for utility use), together with the possibility it might be much cheaper: a) Steam plants designed to burn coal should be installed with gas burning capacity, in order to use gas if and when it is in fact cheaper than coal. b) If gas remains available for utility use at * price substantially below that of coal, the lowest cost electricity would be produced by adding gas turbines to the system, rather than by using either gas or coal-fired steam plants. This would be a happy circumstance, because it would virtually eliminate the financial constraint on the use of the lowest cost technology. c) For the foregoing reasons, utility planners should keep well informed of developments which would affect the future availability and price of natural gas, and be prepared to change their generating strategies and long-term construction plans in response to changed anticipations about long-term trends. 1-7 5. As we have shown above, rapid growth enhances the ability of a utility (or system of interconnected utilities) to generate power more cheaply by allowing it to add larger plants and operate them efficiently, without jeopardizing the system's reliability. Rapid growth, however, also limits a utility's ability to finance the most cost-efficient plants, and in some cases dictates adding generating facilities which, in the long run, will produce more expensive power, because the lowest cost scale of plant requires too much investment at the "front end." The financial constraint on new investment in a rapidly growing utility stems from the disparity between its future capacity needs and its current earnings, which have to be obtained from a much smaller system. The more rapidly demand is growing, the greater is the pro- portion of a utility's total investment which is "plant under con- struction," earning no revenue but nevertheless adding to the debt service burden that must be borne by present ratepayers. Lenders judge the credit-worthiness of a utility not so much by its projections of future revenue growth but by how much its current net operating revenues (or some other measure of cash flow, depending upon the type of utility) exceeds its obligation to pay interest and amortize its debt. If the "coverage" ratio required here is 2.0 (a typical figure for private utilities), the utility would be faced with a need to raise electric rates to its current customers by at least twice the amount of the interest accruing on a new construction debt. This necessity for rate increases is quite independent of, and is in addition to, any rate increases required by rising fuel prices or other operating costs. 1-8 Suppose, for example, that: a) A utility's demand is increasing at 10 percent per year (compounded), implying that capacity must be doubled every seven years. b) It takes an average of seven years to bring a new plant of the most efficient scale on line. c) New plants cost no more per kilowatt of capacity than old plants, and the interest rate on new debt is no higher than on old "embedded" debt. Under these assumptions, at any point in time the utility will have as much new plant under construction as it has on line, and will be obliged to pay interest on twice as much debt as it would if demand were constant rather than growing. (More than twice, actually, because some of the ori- ginal debt on the old plant would already have been amortized.) The utility's net earnings from current rates charged to its customers, therefore, would have to be doubled to meet the coverage requirements of the bond market. But (a) the growth of demand in the Anchorage-Southcentral Alaska. region is expected to exceed 10 percent per year; (b) new, technically more efficient, steam or hydro plants are more expensive per kilowatt of capacity than the existing gas turbines and would, moreover, be built at higher construction costs than in the past; and (c) interest rates on new debt will be considerably higher than on old embedded debt. (0n the other hand, the subscriber-owned and municipal utilities of the region are able to get by with coverage ratios of considerably less than 2.0.) As a result of this financial constraint, any growth strategy for the region's utilities is likely to dictate significantly higher electric rates in the near future, regardless of the course of fuel prices. 1-9 With conventional financing arrangements and under most plausible assumptions about growth rates and costs, moreover, the higher near-term electric rates required by the more capital intensive construction programs (the Susitna project or steam plants of greater than 100 MW capacity) might, under some conditions, more than offset the benefits to consumers from the lower, long-term costs that flow from their greater operating efficiency. Under certain circumstances, as we pointed out above, the optimum strategy for the region might continue to involve the addition of new gas turbines for base load power, despite their relatively high operating costs and despite the uncertainty over whether gas will continue to be available for electrical utility use. 6. The ability of a region to take advantage of the most efficient mix of generating equipment and to operate it most efficiently is enhanced by interconnection among the region's utilities. Interconnection creates a broader demand base and increases both the largest scale of generating plant that is consistent with system reliability, and the largest size of plant that can be added to the system without creating excessive idle capacity. Interconnection also allows reserve capacity to be a smaller proportion of total system capacity. Where there are substantial differences in daily or seasonal demand patterns among the region's utilities, it allows a smaller proportion of the system's total capacity to be designed to produce the more costly peak load power. The benefits of interconnection are limited to the distances in which generating cost savings (including savings on peaking and reserve capacity) exceed the fixed costs of additional transmission facilities plus line losses. Those utilities presently interconnected in the Anchorage-Southcentral 1-10 . e Alaska region (Anchorage Municipal Utility, the Chugach, Matanuska and Homer Electric Associations) just about define the foreseeable limits to cost savings from interconnection, unless construction of the Susitna project is undertaken. (A local interconnection, isolated from the system centered in Anchorage, is planned for the Valdez-Glennallen corridor. ) Addition of the Fairbanks area to the Anchorage-Southcentral Alaska region would, under certain assumptions, significantly improve the economics of the Susitna project, by adding about 20 percent to its total demand base. Without the Susitna project, however, the economics of linking Fairbanks and Anchorage in the near future are doubtful. 7. The benefits of interconnections do not necessarily require consolidation of the various utilities in the Anchorage-Southcentral Alaska region, or even formation of a single new entity or joint venture to build new generating and transmitting facilities serving the entire interconnected system. In the extreme case that growth and cost expectations for the region called for additions of a series of relatively small increments to the existing system (gas turbines or steam plants up to about 50 MW capacity), there would be few technical or financial advantages to consolidation. Innovative forms of ownership and/or financing which reduce the cost of capital can, however, help in taking advantage of the more capital-intensive technologies, i.e., large steam plants or hydro plants. Electric rates are most sensitive to the cost of money where generation is carried out by long-lived, capital-intensive projects. 1-l1 = In the case of a hydroelectric plant with an economic life of fifty years or more and negligible operating costs, the price of a kilowatt hour is almost directly proportional to the cost of money, all other things being equal. The price of electricity from a gas turbine, on the other hand, is far less sensitive to interest rates than to the price of fuel. Fossil fueled steam generation facilities fall between these two extremes. Interest on money now available to Alaska utilities ranges from two percent on some loans to cooperatives from the Rural Electrification Administration (REA) to ten percent or more on the bonds of private utilities. The interest rate used in calculating the cost of power on new federally owned installations is about 6.6 percent, and the typical rate on tax exempt securities of municipal or state-owned utilities is around seven percent at the time of writing (spring 1976). Cooperatives can expect to pay about nine percent on REA guaranteed loans (as dis- tinguished from direct REA loans). Interest as such is not the total cost of money to any of the utilities, however. The bond market requires private utilities to fi- nance a substantial proportion -- typically around 35 percent -- of their assets out of equity, which has a higher cost than debt. The coverage requirements for all types of utilities have a similar effect (though they are calculated differently for the different types). Only for federally owned facilities is the requirement for a specific proportion of equity, financing, or interest coverage inapplicable, so that only in this case is the cost of money in electric rates the interest cost alone. Even where the optimum scale of plant is considerably larger for the region than it is for any individual utility's own market, con- solidation is unnecessary, or the utility holding a large scale plant can sell surplus power to other facilities with which it is interconnected. 1-12 The total cost of money to different kinds of utilities is Tht buenced strony ty by their pespect ive Tatemenrt corntey but it tenebe: to be even more sensitive to the circumstances of the individual utility, its existing debt structure and its construction program. Except for the smallest cooperatives, which can rely heavily on two percent REA money, and federally owned projects, the difference in total capital costs among the different types of utility tends to be less than is suggested by the interest rates they pay. Without question, federal ownership of major generating and transmission facilities would result in the lowest effective cost of capital to the electricity consumers of the Anchorage-Southcentral Alaska region, because of the lack of any interest coverage requirement either after the facility begins operating or -- even more importantly--during the long period needed to build a hydropower facility before it goes on line. Determining the financing arrangement -- other than federal ownership -- which would result in the lowest cost for a particular plant construction program in the region requires a detailed analysis of the particular proposal, beyond the scope of the present, report. We suggest here, however, four alternative arrangements which could be expected to reduce the cost of money and thereby allow the region's electricity consumers to enjoy lower rates for power from any given system. Under most plausible assumptions, some financial innovations will be nesessary in order to consider seriously construction of the one project potentially offering, the lowant electric costs. 1-13 8. We propose for consideration four alternative schemes for construction and financing of major generation and transmission facilities for Anchorage and the surrounding areas. These suggestions are made with the understanding that, in the case of hydropower, they would all be inferior -- from the point of view of the region's consumers -- to federal ownership, and additionally, that under certain circumstances new arrangements may be neither necessary nor advantageous -- namely, if the optimum growth strategy for the region's utilities is simply to add more gas-fired combustion turbines to the existing system. a) The most elementary device for pooling resources of the region's utilities is the tenancy-in-common. In this instance, new genévating and transmission facilities are built and operated by the participating utilities as undivided interest joint ventures. The only advantage of this form of enterprise over each utility acting alone is that the group can pool its assets and borrowing capacity to build a bigger facility than any one of them alone might he able to do. There are no financial advantages as such, for each utility would raise its own share of the investment on the basis of its own access to the capital market. This arrangement, unlike others, however, would permit the participating cooperatives to use whatever low-interest REA money was available to them. b) A second possible arrangement is for the participating utilities to create a jointly owned entity with a separate corporate identity to build and operate new facilities. Such a power company probably would not have access either to REA loans or to the tax-free bond market. It would, however, be able to obtain a lower total cost of capital 1-14 because it could operate with a high debt-equity ratio (perhaps 80% debt) and a correspondingly low implicit coverage ratio. These ratios would be achieved by securing the company's debt with "take-or-pay" contracts to purchase power by its owner utilities. c) The third alternative is a power authority owned by the state (or perhaps by a regional authority created by the state but owned by the three boroughs). The power authority, like the jointly owned power company described above, could achieve low implicit coverage rates by a high debt-equity ratio, and debt would be secured by take-or-pay purchase contracts with the utilities. Being publicly owned, the power authority would be able to borrow in the tax-free municipal bond market. A state general obligation guarantee of the authority's bonds would reduce the state's overall borrowing capacity without necessarily making the bonds significantly more marketable or saving significantly on the interest rate. Wholesale electric rates, however, could be calculated so as to give the state a return on its equity in the power authority marginally higher than it could obtain by lending out its surplus cash, and yet give the authority a total effective capital cost lower than if the equity had to be provided by the utilities. d) The fourth arrangement is not necessarily inconsistent with the first three, namely, establishment of a state power financing agency to assist utilities in borrowing in those cases (and only in those cases) where the state could obtain capital at a lower 1-15 interest rate than individual utilities (or entities formed jointly by a group of utilities). The agency could either insure the debt of individual utilities, or borrow in the tax-free bond market and relend the funds to the utilities. Probably the most useful service of such a state agency would be in providing interim construction financing on capital intensive projects with long lead times. Unlike private lenders, the state agency would not require the utilities to show current earnings of some multiple coverage of the interest accruing on con- struction debt. Interest on work in progress would be capi- talized, and when the project was completed, the project would be conventionally refinanced in the bond market. In our opinion, the greatest leverage in easing the financial constraints to adding more efficient, but bigger and more capital intensive generating facilities to the system in the Anchorage-Southeast Alaska region, would result from (c) or a combination of (b) and (d). Fairbanks 9. The problems of providing electricity at reasonable costs in the Fairbanks region over the period of this study are expected to be of the same kind as we described for the Anchorage-Southcentral Alaska region. Fairbanks load growth rates may be somewhat less than those in Anchorage, but the problems of delivering low cost power there are aggravated by the lower absolute size of existing loads and of expected annual load growth, which limits the ability to add large-scale, efficient plants and to 1-16 operate them cfficiently, consistent with maintenance of adequate reserve capacity. Fairbanks is also handicapped by the present ‘ab- sence of local supplies of natural gas, and by uncertainty over whether natural gas will be available to local utilities at any time in the foreseeable future. Table 1-3 ELECTRICITY REQUIREMENTS IN THE FAIRBANKS REGION Capacity Total Energy Growth Rate Year Required (MW) (Million KWH) (Annual Percent) low high low high low high 1974 76 76 319 319 1985 144 297 602 1244 5.9 13.2 1995 260 677 1088 2843 6.0 ti. 10. As is the case in Anchorage and the surrounding areas, the lowest cost base load power for Fairbanks would in principle be provided by large, capital intensive installations: either the Susitna hydro project or large (66 MW and up) coal fired steam plants. The only foreseeable circumstance in which oil (either residual or distillate) would be competitive with coal as a fuel for base load power supply would be the total and catastrophic collapse of OPEC and world oil prices, but in that event Fairbanks' (and Alaska's) economic growth would at best be severely retarded, with profound other consequences for electrical demand growth in the region. The natural gas made available from either a Trans-Alaska or Alcan Highway gas pipeline, or methanol produced on the North Slope and moved in the Trans-Alaska oil pipeline, would likely 1-17 be much cheaper than oil, but probably would still be more costly for base load use than coal. Such fuels burned in combustion turbines, however, might well be the most economical source of primary energy for utility peaking purposes. 11. Unless the Susitna project is constructed to serve both the Fairbanks and Anchorage regions, coal-fired steam plants appear to be the most efficient additions to the Fairbanks region's generating capacity. The critical issue in this case is just what is the optimum size of plant and the rate at which new capacity is added. It is at this decision point where the financial constraints of interest coverage and the like, described earlier for Anchorage and Southcentral Alaska, come into play. In order to take advantage of the technically optimum scale of plant, either hydro or steam, the utilities of the Fairbanks region must be assisted by one or more of the financial innovations listed here: a) construction and ownership of the Susitna project by the federal government ; b) undivided joint venture generation and transmission facilities owned by the existing utilities; c) a Susitna Power Company, or a Tanana Basin Power Company, whose bonds would be secured by take-or-pay wholesale electricity purchase contracts with its owner utilities; ad) a State or regional power authority (which would be a creature of the state) which would build and operate generation and 1-18 TABLE 1-4 Fairbanks Base Load Units Cost of Energy in Current Mills/kwh : for Initial Year of Plant Operation Equipment Capacity Fuel First Cost Fuel Price @ stated fuel prices uw $/kw ¢/mabtu and interest rates - Interim Financing _ for Initial of 6% and 8% @ 6% 8% Year of Plant L M H Operation . i985 gas turbine ; simple cycle so gas $425 i 241-322-402 53.7 66.0 78.4 $430 $5.7 68.1 80.4 gas turbine : simple cycle 50 oil $425 483-644-805 90.4 115.1 1329.8 $430 97-5. 339.4 144-0 gas turbine regenerative cycle 50 gas . $526 241-322-402 49.2 52.5 60.7 $531 46.7 54.9 63.2 gas turbine regenerative cycle 50 oil $526 483-644-805 68.9 85.3 101.8 $531 7% 878 154.3 steam turbine 66 gas $835 241-322-402 7. 66-4 75-6 : “ ; $865 61.3 70.8 60.2 steam turbine 66 gas $835 241-322-402 S238... 162-350 71e0) (30 yr financing) $865 50.0 67.55 76.9 steam turbine 66 oil $835 322-430-537 66.2 78.8 91.4 $865 70.8 83.3 96.1 steam turbine 66 oil $835 322-430-537 65.3" 45.0 e676 (30 yr financing) $865 : 67-5 80.1 $2.7 bine 66 coal 40-99% 115-153-191 8732 -~$2.8-—.56.2 peeew ete $1030 $2.7. 157.2) 4161.9 steam turbine 66 coal $99% 115-153-191 2:6 47.4... 51-6 (30 yr financing) $1030 hydro 792 Watana $2,901 (7%) s=-.' 108.5; “6%-20 yr-covereze (Corps of Engineers proposal) 70.0 6%-20 yr-no c 86.6 6%-30 yr-coverace (1987 dollars) 58.4 6%-30 yr-no cover 51.3 6%-S0 yr-no cover. 119.7 8%-20 yr-coverage 80.5 8%-20 yr-no cover. 105.5 8%-30 yr-cove 69.0 8%-30 yr-no cove 65.5 8%-S0 yr-no caver. i Assumptions: 20 year financing of fossil plants unless otherwise noted ° Coverage factor of 1.5 on fossil plants Cost escalation at 6 percent materials, 8 percent labor 55 percent load factor on fossil plants Combined cycle gas units are also technically feasible but have not teen analyzed No credit for secondary energy for hydro Table 1-4 Continued Cost of Energy in Reena Mills/kwh ‘or Initial Year of Plant Operatio Equipment Capacity Fuel First Cost Fuel Price @ stated fuel palces Z Mi _S/kw ¢/mmbtu and interest rates Interim Financing for Initial of 6% and 8% @es @ 8% Year of Plant L M Operation 1990 gas turbine simple cycle so gas $583 0 323-431-539 72.4 88.9 105.4 . . $589 78.6 92.2 108.7 gas turbine ae simple cycle so oil $583 646-862-1077 122.4 155.4 188.4 $s89 125.2 158.2 191.2 gas turbine regenerative cycle 50 gas $721 323-431-539 60.3 71.3 82.3 $728 63.7, 74.7 85.7 gas turbine regenerative cycle 50 oil $721 646-862-1077 93.3 115.3 137.3 $728 96.7 118.7 140.7 steam turbine 66 gas $1144 323-431-539 77.2 89.9 102.5 . . $1185 83.6 96.2 108.9 stcam turbine 66 gas $1144 323-431-539 71.9 84.6 97.2 (30 yr financing) $1185 79.0 91.6 104.3 Sedeniturbine 66 oil = $1144 431-575-719 89.9 107.0 123.7 $1185 96.3 113.1 130.0 curdine 66 oil $2244 431-575-719 84.6 101.5 118.4 — (30 yr financing) $1185 91.7 108.5 125.4 ‘canine 66 coal $1362 169-225-281 66.6 73.2 79.8 ete $1411 74.1 80.7 87,3 ates turbine 66 coal $1362 169-225-281 60.3 66.9 73.5 (30 yr financing) $1411 68.7 75.3 81.9 hydro 1,568 Watana and $2,252 (7%) co 79.1 6%-20 yr-coverage = Devils Canyon 63.3 6%-20 yr-no cover. (Corps of Engineers proposal) 66.2 6%-30 yr-coverage (1992 dollars) 44.8 6%-30 yr-no cover. 39.3 6%-SO yr-no cove>. 91.4 8%-20 yr-coverage 61.5 8%-20 yr-no cove:. 80.6 8%-30 yr-coveraz? 54.3 8%-30 yr-no cover. 50. se s : 1-19 (a) | 1 8t-50 yr - cover. transmission facilities, and whose bonds would likewise be secured by take-or-pay wholesale purchase contracts with the utilities; and/or e) a state financing agency, which would provide interim construction financing for large construction projects, without imposing interest coverage requirements for those loans. It appears, under most plausible assumptions, that the alternatives which promise the lowest expected rates to consumers, are, in order of preference: (a), (e), and (c) plus (f). Southeast 12. Southeast Alaska is not a single regional power market as are the regions centered in Anchorage and Fairbanks. It is composed of a number of isolated load centers with populations ranging from a couple hundreds to that of Juneau (17,800 in 1975). Population and electrical demand in the region, and in its constituent communities, are expected to grow, but more moderately than in the Anchorage or Fairbanks regions. The expected growth in Southeast Alaska as a region is of limited use in judging the problems or opportunities in providing economical power to indi- vidual communities, but it does indicate average growth trends in the region. 1-20 Table 1-5 ELECTRICITY REQUIREMENTS IN SOUTHEAST ALASKA Capacity Total Energy Growth Rate Year Required (MW) (Million KWH) (Annual Percent) low high low high lo high 1974 48 48 215 205 1985 93 112 417 505 6.2 8.0 1995 141 184 634 827 Sas 6.6 13. Because of the distance between Southeast Alaska's individual load centers, their small size and the difficult mountainous, glacial and marine topography, there are no evident opportunities to reduce costs or improve reliability by means of interconnection. Except for Juneau, which already has substantial excess generating capacity in the Snettisham hydroelectric project, each of Southeast Alaska's communities has such small total demand that their only technological options are small-scale hydro or diesel generation, usually operating as isolated systems. Because there are no local natural gas or coal resources, distillate and residual fuel oils are the only available fossil fuels. 14. We have identified several sites close to Southeast Alaska communities where small-scale hydroelectric projects should result in lower electric rates in the long term than exclusive reliance upon diesel generated power. A list of the more promising of these are included in Table 1-6. 1-21 Table 1-6 SOUTHEASTERN UNDEVELOPED HYDROELECTRIC SITES os ae Prime batt ee g Capacity (KW) Energy Total Capital Cost Per® Area/Project Installed Prime (MWH) (000$) Prime KW Installed KW Southeast . : een Metlakatla = Purple Lake Rehabilitation 1,400 400 17,520 | 1,134 2,835 810 Hassler Lake 4,000 2,000 16,980 6,830 3,415 3,415 Total 5,400 2,400 34,500 ° ei Ketchikan : ; Upper Mahoney Lake 10,000 4,700 41,172 9,035 1,772 903 Swan Lake 15,000 7,700 67,500 32,980 4,283 2,199 Lake Grace 20,000 11,000 94 ,000 39,351 3,577 1,968 Total 45,000 23,800 202,672 Petersburg-Wrangell i 7 Anita 4,000 2,100 18,396 5,871 2,796 1,468 Anita and Kunk Lakes 8,000 3,830 33,550 9,128 pata dees Virginia Lake 6,000 3,000 26,280 7,070 2,357 1,178 Sunrise Lake 4,000 2,400 21,024 4,174 1,739 «1,083 Ruth Lake : 16,000 7,950 69,660 23,355 2,938 1,460 Crystal Lake Expansion 2,500 400 3,504 4,400 11,000 1,760 Cascade Creek I 15,000 5,100 44 781 22,955 4,501 1,530 Cascade Creek II 36,000 17,900 156,672 21,335 1,192 593 Scenery Lake 18,000 9,100 79,716 22,310 2,452 1,239 Total . 105,500 51,780 453,583 Juneau : 5 Snettisham Expansion I 27,000 11,758 103,000 22,000 1,871 815 Snettisham Expansion IL - 18,607 162,997 16,000 860 -- Total 27,000 30,365 265,997 38,000 1,251 Sitka Lake Irina 3,000 1,790 15,680 3,665 2,047 1,222 Green Lake 14,000 6,600 57,816 18,050 2,735 1,289 Lake Diana 10,000 4,585 40,165 9,705 2,117 970 Milk Lake 16,000 8,000 70,080 18,750 2,321. 1,172 Four Falls Lake 6,000 3,000 26,280 4,265 1,417 ad Carbon Lake 18,000 6,830 59,832 19,200 2,811 1,067 Takatz Lake 20,000 10,000 87,600 26,600 2,660 1,330 Total 87,000 40,805 357,453 Haines Unnamed Lake 9,000 4640 40,640 10,435 2,249. 1,159 Skagway Goat Lake 9,000 4,450 38,982 9,140 2,054 1,016 Total Region 287,900 158,240 1,393,827 ®All costs calculated assuming construction begins early 1976. 1-22 AS). Because of the moderate growth rates of demand, and the relatively small scale of necessary addition to capacity, there are no desirable new generation projects in Southeast Alaska which clearly could not be financed by the existing utilities by conventional means. Those pro- jects which apparently could not be financed conventionally -- including some which are under serious consideration by utilities in the region --were not the least cost alternatives in any of the cases examined here, generally because they were 1-22A too big relative to reasonably anticipated demands. As we pointed out earlier, the test of a prelate cost effectiveness is not the cost per kilowatt of in- stalled or peak capacity, but the cost per kilowatt hour actually delivered. The optimum investment strategy in this region will generally be to provide suffi- cient hydropower capacity to meet the community's base load demand and to continue meeting peaking and reserve requirements with diesel generators, which cost much less while they are standing idle than the same amount of idle hydropower capacity. Significant savings do not seem to be possible as a result of organi- zational innovations, although three options are nevertheless available: First, there may be individual utilities for which the total cost of money could be reduced by the intermediation of a state financing agency. Second, for some of those communities with promising hydropower sites, the burden on consumers might be significantly reduced if the state financing agency extended interim construction credit as described for other regions. Third, some Southeast municipalities might elect to pool their financial resources in order to undertake joint projects, as Petersburg and Wrangell have already done. The opportunities available to several individual local utilities, however, are very attractive. They have the ability to continue constructive development of their own systems without sacrificing local independence or planning priorities to a larger agency. 16. Juneau's "cheap" hydroelectric power from the federal Snettisham project does not result in significantly lower electric rates to consumers than "costly" diesel generation elsewhere in Southeast Alaska. The Men- denhall Valley-Glacier Highway area which is also supplied from Snettisham via a federally financed REA cooperative, has nearly the most éxpensive 1-23 power in the region. The main reasons are high distribution costs, and the necessity of maintaining standby diesel capacity because of the unreliability of the transmission lines from Snettisham. Reduction of costs in the Juneau area will require attention to these factors, which were beyond the scope of this “a Rural Alaska 17. “Rural Alaska" is composed of about two hundred villages, in every part of the State (but primarily in the Northwest, Southwest, and Interior regions), with populations ranging from a few families to Nome, Barrow and Kotzebue (Northwest), and Bethel and Dillingham (Southwest ) with populations between two and three thousand. Most of them are isolated from one another and from year-round surface transportatidn networks, depending for transport of fuel (among other things) on costly aviation and in most cases seasonal water carriage. Both loads and expected load growth in rural Alaska are moderate, and the total demand of all the rural communities together is not great in comparative terms. Some rural communities, with the characteristics described here, are included in the previous projections for Southcentral wa Southeast Alaska, and Table 1-7 shows projected electricity require- ments for a group of the largest communities in the Northwest and South- west regions. These estimates include Kotzebue, Nome, Unalakleet, Bethel, McGrath, Naknek, and Nushagak. 1-2h Table 1-7 ELECTRICITY REQUIREMENTS IN THE NORTHWEST AND SOUTHWEST REGIONS Capacity Total Energy Growth Rate Year Required (MW) (Million KWH) (Annual Percent) low high low high low high - 1974 8 8 31 31 1985 9 21 36 86 eo) Sav 1995 10 31 Ky a27 1.6 6.9 18. In all but a few cases (e.g. Barrow, which has a local natural gas supply), the only feasible source of electricity in the foreseeable future is the diesel internal combustion engine, fired by oil that costs from 50 cents to $1 per gallon. Most rural Alaskan villages also have low per capita electricity consumption, stemming from low per capita cash incomes, which makes the maintenance of any utility system precarious. At the time of this writing, forty-eight villages were supplied with electricity by the Alaska Village Electrical Cooperative (AVEC), which received an initial capital grant from the Office of Economic Opportunity and 2 percent from the REA. AVEC and some independent village utilities were formerly sustained in part by take-or-pay contracts with the Bureau of Indian Affairs and the state-operated schools, for substantially more power than these entities actually consumed. With the takeover of the rural schools by local govern- ment, these subsidies are being terminated. This development, together with the great increase in fuel oil prices over the last three years has placed AVEC and the village utilities in (worse than usual) difficulty. These trends have been partly offset by an inflow of income to the villages I-25 resulting from the Alaska Native Claims Settlement, and (in a few cases) payrolls from pipeline work, but there is a serious issue whether the state should further subsidize the provision of electric power to low income rural communities. It is not our province as economists or engineers to prescribe whom the state should subsidize or by how much. We have two salient recommenda- tions, however. Firstly, that the subsidy should not lead to the choice of equipment or operation strategies other than the lowest-cost ones calculated on the basis of true (unsubsidized) prices of equipment, money, and fuel; and secondly, that whoever is the beneficiary of a subsidy and whatever its magnitude, that it be for capital equipment and not for fuel; if operating costs must be subsidized, the subsidy should take the form of a lump sum payment and should not increase with the amount of fuel consumed or power sold. 1-26 FOOTNOTES 1 thomas R. Stahr, Manager, Anchorage Municipal Light and Power, comments © interconnection of major load centers: "Based on the projected power loads in the Anchorage-Fairbanks area, which incidentally appear reasonable and well thought out, it is inconceivable that a transmission interconnection will not be re- quired, even if the thermal alternative is selected. The high un- availability of steam units will necessitate this unless an unac- ceptably large amount of stand-by capacity is provided. The esti- mated costs of this system must be added into the thermal cost es- timates. The estimates for the Upper Susitna (Devil's Canyon and Watana) by necessity already includes this transmission system." (Letter to Tussing, May 10, 1976) Robert J. Cross, Acting Administrator, Alaska Power Administration, also comments on this issue: "The report suggests the railbelt interconnection is essentially dependent on the Susitna Project. We suggest that interconnection would be justifiable under several alternative power supply situa- tions." (Letter to Tussing, May 14, 1976) 2 Robert J. Cross, Acting Administrator, Alaska Power Authority, comments on this section: "In its treatment of Southeast Alaska, the report finds that there aren't any desireable new generation projects which clearly could not be financed by existing utilities by convential means. This finding is premised on very rough reconnaissance evaluations of a series of small hydro projects. In our judgement, these evaluations are premised on very optimistic pricing assumptions, and the findings appear to be at odds with the balance of experience in Alaska and elsewhere." (Letter to Tussing, May 14, 1976) 3 Robert J. Cross, Acting Administrator, Alaska Power Administration, comments: "Long term costs of maintaining stand-by diesel generators will be avery small part of Juneau's power bill. Present wholesale power cost from Snettisham is 15.6 mills per kilowatt-hour which is roughly one-half the present fuel costs for diesel generators in Southeast. Snettisham has adequate installed capacity and energy capability to allow for future growth. Its power costs are far cheaper than other alternatives now under consideration in Southeast. "No question that Snettisham power costs are much higher now than estimated when the project was authorized in 1962; no question that the transmission problems are both serious and costly. Also no question that Snettisham still looks like one of the cheapest long-term sources anywhere in the state." (Letter to Tussing, May 14, 1976) 1-27 II. EXISTING SYSTLM Introduction Existing systems of generation and distribution of electricity in Alaska include relatively large interconnected utilities serving urban populations and small isolated utilities serving remote towns and villages. However, most bush areas with scattered villages of less than 200 persons are not served by any electric utility. Every city in the state with a 1970 Census population of at least 1,000 persons has some utility service, and most places which had at least 200 persons in 1970 have electricity, provided by local or regional utilities or by the Alaska Village Electrical Cooperative (AVEC). An inventory of the largest systems in the state is included in Appendix A. The largest grouping of customers is in the service areas of Anchorage, the Kenai Peninsula and Matanuska and Susitna Valleys. This grouping includes Anchorage Municipal Light and Power, and three REA cooperatives, the Chugach Electric Association, Matanuska Electric Association, and Homer Electric Association. Because these utilities have been able to obtain low-priced natural gas and also because of scale of generation and load-center density, this area has the lowest electric rates in the state. The next largest service area is that of Fairbanks and the Tanana Valley which is currently served by two utilities, Fairbanks Municipal Utilities System and a cooperative, Golden Valley Electric Association. 2-1 Electric rates in this area are considerably higher than those in the Anchorage-Kenai-Matanuska-Susitna area. This results from use of coal-fired steam plants tor base loading, supplemented by of l-f ired internal combustion peaking units, both of which are more costly modes of generation than those available in the gas-rich Cook Inlet area. Other systems in the state are small and isolated, such as those in Southeast Alaska, Kodiak Island, Prince William Sound, the Lower Kuskokwim, and the Arctic. These utilities differ in many ways from one another and from the larger utilities. Southeast Alaska has several systems which depend partly on hydroelectric power, but not all of them enjoy low electric rates as a result. These include Juneau, Skagway, Petersburg, Ketchikan, Metlakatla, Sitka, and Pelican. Remaining generation in Southeast Alaska comes from diesel units of varying sizes. With the exception of natural-gas-fired combustion turbines in Barrow, all other electrical utilities in the state depend upon diesel generators of various sizes. The farther north and west the community, the further from tidewater, with a very few exceptions, the higher is the price of diesel oil. Southcentral and Anchorage Regions The Southcentral and Anchorage region comprise both the largest load center in the state and the area expecting the most rapicly growing demand. It contains, in addition, the most integrated and interconnected system, composed of two municipal utilities and three cooperatives, plus the APA's Eklutna hydroelectric facility. 2-2 The total utility generation capacity of the Anchorage and South- central Alaska regions is shown in Table 2.1 as 395 MW, excluding 16 MW of diese] capacity in villages served by the Homer Electric Association and used mainly for standby. The region also includes 125.5 MW of non-utility generating capacity: 14.0 MW of diesel capacity and 53.5 MW of steam turbine capacity on military installations, and 31.6 MW of diesel and 26.4 MW of gas turbine capacity owned by oil and gas. producers. Nearly 282 MW cf additional. capacity is presently plannea for Anchorage, and the Corps of Engineers has considered the Upper Susitna River as e site for a twoedam hydroelectric project designed ultimately to provide 1,568 MW installed capacity with 692 MW prime to the entire railbelt area, including the Kenai Peninsula, Anchorage, the Matanuska and Susitna Valieys, Fairbanks and the Tanana Valley, ond perhaps the Copper Valley. There are major interties in the Anchorage-Cook inlet area. These would be interconnected with the utilities in the Fairbanks area if the Susitna project were built. A line between Valdez and Glennallen is aisc under consideration. A key problem of the Anchorage and Southcentral regions is their rapid growth of demand in the face of increasing competition for the remaining uncommittea gas reserves in Cook Inlet. The scale of this market is large enough and its growth rapid enough that a major hydro project or coal fired steam plant of optimum.size could be added to the system, with the present gas-fired turbines being relegated to peaking service. Both hydro and coal resources are abundant in the region. TABLE 2-1 Summary of Available Utility Generating Facilities for Anchorage and the Southcentral Region Capacity Census Division (MW) Type Utility Location Kodiak Division: Diesel Kodiak Electric Authority Diesel Kodiak Electric Authority Diesel AVEC : ee Total nN nouwno OoNFrFN Nn Kenai-Cook Inlet Division, - : 45.0 Hydro Alaska Power Authority, Chugach : Matanuska-Susitna (| d Division, 16.0 Diesel LEP, Homer Electric Assoc., Seward Light & Power, Mata- nuska Electric Association Anchorage Div., 1269.5 Gas Turbine Seward Division: \14.5 Steam Turbin : Total 345.0 (1) Cordova-McCarthy Division: 8.15 Diesel Cordova Public Utility Total 8.15 Valdez-Chitina- 3 Whittier Div.: 0.1 Diesel Chistochina Telephone & Power 0.1 Diesel Chitina Power Company 7.6 Diesel Copper Valley Electric Assoc. 0.3 Diesel Paxson Lodge, Inc. 7.3 Diesel Copper Valley Electric Assoc. Total 15.4 : Regional Total 394.55 Port Lions Kodiak Old Harbor Eklutna, Cooper Lake Anchorage, Hor. -Kenai, Seldcov Seward, Taixe Cordova City Chistochina Chitina © Glennallen ” Paxson Valdez Note (1): A total of 16 MW diesel capacity is currently inactive in the Anchorage- Cook Inlet area. Source: Stephano/Mesplay Associates, Anchorage, Alaska and 1974 Alaska Power Survey. Major new discoveries of natural gas could change the present outlook significantly, provided national legislation does not restrict the use of gas as electric utility fuel. Fairbanks Region The Fairbanks area is the second largest load center in the state, and it is currently the fastest growing, although its long-term growth rate is expected to fali below that of Anchorage and Scuithcentral Alaska. According to Table 2.2, the region's current generating capacity is 178 MW, of which 165.3 MW is in the Fairbanks Census Division. Not all of this capacity is supplied by public utilities; the utilities, the military, and the University of Alaska are interconnected and borrow power from one another. The military has an additional 10.1 MW diesel, most of it at Fort Greely. A transmission line connects Fairbanks with a mine-mouth, coal-fired steam plant at Healy, 104 miles distant, and another connects with Fort Greely, 80 miles away. In addition to the rapid growth in Fairbanks, which makes it difficult for the utilities to keep up with demand, the price of distillate fuel oil (which is used for base load as well as peaking) is a serious problem. Construction of the Susitna hydroelectric project would add relatively lowecost hydropower to the generating mix of the area. The project would justify an Anchorage-Fairbanks intertie which would gain economies for both service areas. This intertie, however, although technically feasible, does not presently appear to be practical based upon thermal generation alone. 2-5 TABLE 2-2 Summary of Available Utility Generating Facilities Capacity Census Division (QW) Type Utility Location Fairbanks Division: 108.8 Steam Turbine Fairbanks Munic. Util. Sys.,Fairbanks, Healy, 49.3 Diesel Golden Valley Elec. Assoc., Ft. Wainwright, 7.2 Gas Turbine Ft. Wainwright, Eielson AFB. Eielson, AF3. Total 165.3 for the Fairbanks Region (Note: 113.0 MW Public, 52.3 MW Military. Inter-tied to Ft, Greely, Southeast Fairbanks Division: 1 eon ° 6 ~oO Total 13.0 Region Total 179,0 State Total 790.0 Upper Yukon: 0.7 Total 0.7 Yukon Koyukuk: 0.1 * * 0.1 0.1 Total 0.3 Region Total 1.0 S.E. Fairbanks Division.) Diesel Ft. Greely Ft. Greely Diesel Alaska Power & Telephone Tok Junction Diesel Northway Power & Light Northway Diesel Fort Yukon Utilities Fort Yukon Diesel AVEC Huslia Diesel AVEC : Kaltag Diesel AVEC 3 Minto Diesel AVEC Nulato Diesel Manley Hot Springs Electric Manley Hot Springs Note: * Size not reported. Source: Same as Table 2-1, Southeast Region Southeast Alaska is a region exceedingly rich in hydroelectric sites. Several communities now use hydropower and 82.3 MW out of a total of 192.45 MW nameplate capacity are in the form of hydropower. Table 2.3 shows that diesel is the only other mode of generation in the area. The largest facility in the area is the Alaska Power Administration's Snettisham project near Juneau, which is rated at 46.7 MW installed and 19.2 MW firm capacity. Juneau hes, in addition, 11.0 MW other hydro capacity and 13.2 MW of diesel capacity; and Ketchikan, 12.7 MW hydro and 14.3 MW diesel. In aadition to the utility systems, there are 2.4 MW of installed diesel capacity in defense installations, and 46.4 MW of industrial steam turbine and diesel capacity. For most ef the towns using some hydropower, millage rates are relatively low. The area has opportunities for further reducing its dependence on expensive diesel fuel by building on some potential hydro sites; however, there is little potential for transmission interties because of the great distances between loed centers and the abundance of small scale hydroelectric sites nearby. The Southeast region is expected to grow substantially, in population ever the time period encompassed hy this study, but not sufficiently to alter the optimum mix of generating facilities, namely, a combination of hydro and diesel. Rural Alaska Table 2.4 shows the generating capacity of the electric utilities in Northwestern, Southwestern, and Interior Alaska. Except for Barrow, which has a 1.5 MW gas turbine in its system, all plants are diesel. They are also very small -- the largest being that of Nome Light and Power with a capacity of 3.5 MW. The total utility generating capacity in the overall region, is only 24 MW. Ct Census Division ” .Skagway-Yakutat Division: Total Haines Division: Total TABLE 2-3 Summary of Available Utility Generating Facilities for Southeast Region Capacity o (MW) Type Utility Location 1.2 Diesel Yakutat Power Company Yakutat 0.4 Hydro Alaska Power and Telephone Skagway 1.3 Diesel Alaska Power and Telephone Skagway 1.1 Diesel City of Hoonah Hoonah 0.5 Hydro Pelican Utility Company Pelican 0.4 Diesel Pelican Utility Company Pelican 4.8 0.4 Diesel Tlingit-Haida Regional Elec. Auth. Klukwan 2.4 Diesel Haines Light and Power Haines 2.8 Cy Pe | Hydro Alaska Electric Power & Light, Juneau-Douglas Juneau Division: Total Angoon Division: - Total Sitka Division: Total Wrangell-Peters- burg Div.: Total Prince of Wales Division: Total Outer Ketchikan Division: Total Ketchikan Division: Total Regional Total Glacier Highway Electric Assoc., Alaska Power Authority. (Note: Includes the Snettisham project at 46.7 MW hydroelectric.) 13.2 Diesel AEL & P, GHEA, APA Juneau~Doug las 70,8 ; 0.6 Diesel AVEC Angoon * 0.6 6.0 Hydro Sitka Electric Department Sitka 3.1 Diesel Sitka Electric Department Sitka 9.1 : aoe Diesel Community of Kake Kake 2.0 Hydro Petersburg Municipal Light & Power Petersburg 3.7 Diesel Petersburg Municipal Light & Power Petersburg 7.7 Diesel Wrangell Lighting Department Wrangell 14,8 0.05 Diesel Tlingit-Haida Regional Elec. Auth. Kasaan 1.6 Diesel Tlingit-Haida Regional Elec. Auth. Klawock 0.2 Diesel Alaska Power and Telephone Hydaburg 0.6 - Diesel Alaska Power and Telephone Craig 2.45 3.0 Hydro Metlakatla Power and Light Metlakatla 3.0 Diesel Metlakatla Power and Light Met lakatla 6.0 ; 12.7 Hydro Ketchikan Public Utility Ketchikan 14,3 Diesel Ketchikan Public Utility Ketchikan 27.0 192.45 * Includes 1 400kw unit without governor. Source: Same as Table 2-1. 2-8 TABLE 2-4 Summary of Available Utility Generating Facilities for Rural Alaska Census Division Capacity Type Utility Location Barrow Division: 1.2 MW Diesel Barrow Utilities Corp., Inc. Barrow City 1.5 MW Gas Turbine Barrow Utilities Corp., Inc. Barrow City * Diesel North Slope Borough Utilities Point Lay Total 2.7 MW Kobuk Division: 0.2 MW Diesel AVEC : Kiana City 0.1 MW Diesel AVED Kivalina City 2.4 MW Diesel Kotzebue Electric Assoc. Kotzebue City 0.2 MW Diesel AVEC Noatak 0.2 MW Diesel AVEC Noorvik City 0.2 MW Diesel AVEC Pt. Hope City 0.2 MW Diesel AVEC Selawik City 0.1 MW Diesel AVEC | Shungnak City Total 3.6 MW Nome Division: 0.1 MW Diesel AVEC Elim 0.2 MW Diesel AVEC Gamble City 0.2 MW Diesel AVEC Koyuk 3.5 MW Diesel Nome Light and Power Nome City 0.3 MW Diesel AVEC St. Michael City 0.2 MW Diesel AVEC Savoonga City 0.1 MW Diesel AVEC Shaktolik City 0.1 MW Diesel AVEC Shishmaref City 0.3 MW Diesel AVEC Stebbins City Diesel Teller Light & Power Utility Teller City 0.8 MW Diesel Matanuska Electric Assoc. Unalakleet 0.1 MW Diesel AVEC Wales City Total 5.9 MW Northwest Region Total 12.2 MW * Size not reported. Source: Same as Table 2-1. (Continued on next page) 2-9 TABLE 2-4 Continued * Size not reported. Source: Same as Table 2-1. 2-10 Nameplate Capacity Census Division (MW) Type Utility Location _ ———— ale =s “Kuskokwim Div.: 0.2 Diesel AVEC Grayling 0.2 Diesel AVEC Anvik 0.2 Diesel AVEC Shageluk 0.2 Diesel AVEC Holy Cross 0.3 Diesel Aniak Power Company Aniak 0.2 Diesel AVEC Kalskag, Lower z Kalskag 0.8 Diesel Northern Commercial McGrath Total 2.1 . Wade Hampton 0.3 Diesel AVEC Emmonak Division: 0.2 Diesel AVEC Alaknuk 0.1 Diesel AVEC Scammon Bay 0.8 Diesel AVEC Mountain Village, Pikas Point, St. Mary’s, Pilot Station, Marshali 0.4 Diesel AVEC Hooper Bay 052 Diesel AVEC Chevak Total 2.0 Bethel Div.: 0.2 Diesel AVEC Mekoryuk 0.2 Diesel AVEC Tununak, Toksook Ber 0.3: Diesel AVEC Kasigluk, Nunapitehu: 1.6 - Diesel Bethel Electric Utility Bethel City (Note: Plant destroyed by fire in 1975, to be rebuilt in 1976.) 0.1 Diesel AVEC Eek 0.2 Diesel AVEC Quinnagak 0.2 Diesel AVEC Goodnews Bay Total 2.8 Bristol Bay 0.2 Diesel AVEC : Togiak * Diesel Nushagak Electric Corporation Aleknagik * Diesel AVEC New Stuyahok 1.9 7 Diesel Nushagak Electric Corporation Dillingham 0.2 Diesel Naknek Electric Assoc. Egegik Total 2.3 Bristol Bay Borough: 1.6 Diesel Naknek Electric Assoc. Naknek 5 Total 1.6 : Southwest .Region Total 10.8 According to the 1974 Alaska Power Survey, there was a total of 96.7 MW of generating capacity outside the utilities, all of it on federal govern- ment installations, except for 3.2 megawatts of capacity at Prudhoe Bay. There are no interties in these regions, and only Barrow has natural gas available as substitute fuel for diesel. Small additions to capacity are planned in Nome and Kotzebue in 1976 and 1977. The rural area of the state (the Northwest, Southeast, and Interior as defined in this study) do not anticipate rapid population growth. Their problems stem from very small load centers, low average per capita in- comes, high construction costs, and particularly the high price of diesel fuel. Fuel is normally shipped in during the ice-free season along the coast and on interior rivers, but supplementary supplies sometimes are shipped by air. This adds considerably to the price of fuel. Some of the communities in this region are in oil and gas exploration zones; wherever natural gas is discovered close to a village, it may be used as fuel for electric generation and directly for space heating and appliance use, as is already the case in Barrow. Other areas are also under- lain by coal, but the relatively high cost of power generated from extremely small coal-fired installations probably precludes its use as a utility fuel in the foreseeable future. Diesel is, therefore, expected to be the primary source of generation through 1995, with the possible exception of the vil- lages immediately around Bethel. Interties among utilities are unlikely be- cause of the small size of load centers and their wide dispersion. 2-11 III. ELECTRICITY DEMAND PROJECTIONS* Summary and Conclusions Under a wide variety of assumptions regarding both the pace of future economic development within the state and the intensity of electricity use, future electricity demand in Alaska is projected to increase at a rapid rate over the next 20 years. Limited economic development beyond projects currently under way, combined with very limited increases in the intensity of electricity use, result in annual growth rates of 8 percent between 1974 and 1995. This exceeds the historic long-run growth rate for the U. S. as a whole, which has 1 tt is lower than recent historic been fairly constant at 7 percent since 1880. growth rates for Southwest and Southcentral Alaska, including Anchorage and Fairbanks. Accelerated economic development, in the form of more rapid development of the petroleum resources in the state, combined with future growth in electri- city consumption consistent with past trends, would result in an average annual growth rate of 13 percent over the 20-year period 1975-1995. This is consis- tent with recent historic growth in the Anchorage and Fairbanks regions. In all cases, the growth in electricity demand slows over the projection period, which means that short-term growth rates will exceed these long-term estimates. Regional growth rates differ considerably. Table 3-1 compares historic growth rates in electricity consumption for regions of the state with short- and long-run projected growth rates based on accelerated? economic development *Demand in this chapter has an economic rather than engineering meaning. To the economist, demand for electricity is total kwh consumed. To the engineer, demand is the level of generation necessary to satisfy peak electricity requirements. PROJECTED ELECTRICITY DEMAND GROWTH RATES BY REGIONS Table 3-1 (Assuming Accelerated Economic Development) Historic Annual Projected Growth Rate Projected Growth Rate Growth Rate Short-Term Long-Term 1965-1974 1975-1980 1974-1995 High Low High Low Intensity Intensity Intensity Intensity of of of of Region Percent Use Use Use Use I. Anchorage 12.5 17.5 10.5 14.7 10.4 II. Southcentral 11.9 22.1 11.6 11.5 8.4 III. Fairbanks 14.1 12.8 6.1 11.0 6.7 IV. Interior a * . z : V. Southeast 6.5 8.7 7.2 6.6 6.2 VI. Northwest 7.9 8.1 3.1 44 22 VII. Southwest 11.5 11.0 2.0 8.6 2.1 —— * no data available 3-2 assumptions and both high and low intensity of electricity use. The follow- ing conclusions regarding regional differences in demand growth are evident from Table 3-L and the demand analysis in this chapter. Anchorage, Long-run growth of electricity demand will be the most vapid in Anchorage and will be fairly insensitive to the pace of economic development in the state. Long-term growth rates, assuming accelerated eco- nomic development, are projected at between 10 and 15 percent, which brackets the historic rate of 12.5 percent. Short-term growth occurs at approximately the same rates, indicating a relatively stable growth pattern under most pro- jection assumptions. Southcentral, Demand in the long-run is projected to grow in excess of the national historic average of 7 percent annually in the Southcentral region, but less than the historic rate of 12 percent. The assumptions re- garding average usage are more important than assumptions regarding economic development. Short-run growth here will be the most rapid in the state and is projected to occur at least at the 12-percent historic rate. Fairbanks, Electricity demand in Fairbanks is not projected to continue at the historic 1l4-percent rate under any of the assumptions employed in this analysis. Long-run growth is strong, however, and assuming accelerated de- velopment ranges from 7 to 11 percent. The regional aggregate projections given in Table 3-2 were done by a two-step procedure described in detail below. Scenarios of economic develop- ment patterns for the state were combined with different assumptions regard- ing the future level of electricity use per customer. Each projection is thus a combination of two sets of assumptions which were linked together using an econometric model of Alaska, the MAP model. In general, projection results are much more sensitive to the assumption of customer usage than those of economic development. The projection of future levels of usage per cus- tomer are extremely difficult because increasing electricity and energy prices are changing consumption habits in ways which are not completely understood. In 1975, electricity usage nationwide increased 2 percent compared to the historic rate of 7 percent. ° Identifying the elements of this shift in consumption, determining whether they are short-term or long- run changes in behavior, and relating the national trend to Alaska, are all difficult tasks. Projections were calculated only for electricity generated by the public utilities within the state. However, this chapter includes analyses of the electricity demands of small villages, private industry, and the military. Southeast, The range of projections in the coulbaast is the narrowest of all regions of the state because of its stable growth in the past and pro- jected stable economic growth in the future. The level of petroleum develop- ment in the state will not directly affect the growth of the Southeast economy. Indirectly, government activity will provide the stimulus. All Southeast pro- jections assume the capital will remain in Juneau. (This does not reflect any opinion that it should do so.) In the long-run, growth in electricity demand is projected to occur at approximately the historic rate of 5.5 percent. 3-4 Southwest. Data problems in this region also result in a broad range for the projected growth rate. The pace of economic development will have less effect on the growth rate than the future level of usage of electricity per customer. If the intensity of electricity usage continues to increase, 20-year annual growth rates could be in the range of 9 percent. This is somewhat below the historic rate of 11.5 percent. If intensity of use does not increase, long-run growth could be as low as 2 percent. Northwest- Demand projections are very imprecise because of uncertain- ty regarding both the level of economic activity generated by petroleum de- velopment and uncertainty regarding future electricity usage per customer. Part of the problem is lack of data resulting from incomplete reporting to government agencies. No information was available from Barrow. Assuming accelerated economic development, long-term growth in electricity demand falls in the lowest range lor the state. This range, from 2 to 5 percent growth annually, is half the historic rate of 8 percent. 3-5 Ore Table 3-2 ' SUMMARY OF THE RANGE OF ALASKA ELECTRICITY DEMAND PROJECTIONS, 1985 AND 1995 Peak Demand (MW) - Total Energy Sales (Thousand MWH) Average Annual Growth Rates 1974 1985 1995 1974 1985 1995 1975 1975. -1975 (actual) (actual) to to to Region 1980 1985 1995 “Vv. Anchorage lowest - 199 538 1300 867 2347 5679 9.9 9.4 9.4 highest 199 1104 3515 867 4822 15350 17.5 16.9 14.7 IV. Southcentral (except Anchorage) lowest 62 164 372 282 748 1325 10.1 G22 7.6 . highest | 62 290 611 282, 1701 ;..2791 21.9 17.7 11.5 Anchorage, Southcentral lowest 261 702 1672 1149 3095 7004 9.9 5 9.4 9.0 S highest 261 1394 4126 1149 6523 18141 18.7 Ltd 14.0 VII. Fairbanks lowest 76 144 260 319 . 602 1088 5.8 5.9 6.0 highest 76 297 677 319 1244 2843 1258" --1552- 710.0 Anchorage, Southcentral, lowest 337 846 1932 1468 3697 8092 9.1 8.8 8.5 and Fairbanks highest 337 1691 4803 1468 7787 20984 Le 166+ toy 5 III. Southeast lowest 48 93 «141 215 417 634 6.7 6.2 5.3 highest 48 1? 184 215 505 827 8.7 8.1 6.6 Rural I&II. Northwest plus Southwest lowest 8 9 10 81 36 yy 250 1.3: 1.6 highest 8 21 31 31 86° | 127 9.7 9.7 6.9 Alaska Statewide lowest 393 948 2083. 1715 4147 8765 8.6 8.4 f.2 highest 393 1824 5018 1715 8358 21938 26.5, 1605) 1295 Utility Demand* A. Recent Growth Pattern Annual growth rates in sales to final consumers are reported in Table 3-3 by region for those Alaskan electric utilities which file re- ports annually with the Federal Power Commission. (A map of the regions appears in the appendix.) The growth rates cover the period from 1965 through 1974, although some utilities, as noted, do not report sales for all years. Simple regression analysis was used to fit a curve of the following form for each utility: = . S, = 8, (1g) where S = sales o - 1965 = observation year - 1965 g = growth rate Examination of these historic growth rates indicates several facts. First, growth rates have generally greatly exceeded the national aver- age of 7 percent, although there is a large amount of variation in growth rates among utilities within each region and also across regions. Only in the Southeast has growth been under 7 percent annually, while in the rail- belt area, growth has been twice the national average. Second, the growth rates of individual utilities have been in some cases extremely high over the recent historic period. Golden Valley Electric 3-7 Table 3-3 HISTORIC GROWIH RATES OF SALES TO FINAL CONSUMERS ALASKA ELECTRIC UTILITIES 1974 Total Annual KWH Sales Map Regions and Electric Growth. to Final Census Divisions Utility Rate (%) Consumers Observations R? REGION V Anchorage Anchorage Anchorage Municipal 12,05 350,302 10 99 Light & Power “ Chugach Electric Assn, 14,31 516,830 10 99 Average 12.53 REGION IV Southcentral Alaska Cordova-McCarthy Cordova Public Utilities 9,36 9,577 5 98 Kenai-Cook Inlet Homer Electric Assn. 16,47 92,223 10 .90 (Homer ) Homer Electric Assn. 11.36 20,223 10 «74 (Kenai) i Homer Electric Assn. 34,47 217 3 .97 (@ort Graham) : Homer Electric Assn. 13.14 3,600 10 -98 (Seldovia) Kodiak Kodiak Electric Assn. 8.78 36,528 9 94 (Kodiak) Kodiak Electric Assn. 10.20 1,580 6 -90 (@ort Lions) Matanus ka- Matanuska Electric Assn. 12,43 92,073 10 <o5 Susitna (Palmer) Matanuska Electric Assn. 17.09 plant closed 8 92 (Talkeetna) Seward Seward Electric System 10.14 14,152 10 +98 Yaldez-Chitina- Copper Valley Electric 6.83 5,576 5 +98 Whittier ~ Assn. (Glennallen) Copper Valley Electric 12,81 8,464 6 91 Assn, (Valdez) Average 11,93 . REGION VI i Interior (No reporting utilities) Table 3-3 continued 1974 Total Annual KWH Sales Map Regions and Electric Growth to Final 2 Census Divisions Utility Rate (%) Consumers Observations R REGION VII Fairbanks Fairbanks Fairbanks Municipal 7.06 88,135 9 +92 Utilities ’ Golden Valley Electric 20,18 230,618 10 -98 Assn. University of Alaska 10,212 4 -55 Southeast Alaska Power §& Telephone 8.69 2,996 5 -88 Fairbanks Co. (Tok) Average 14,11 REGION III Southeast Alaska Haines Haines Light § Power Co. ~ Juneau Glacier Highway Electric 7.85 5,352 4 95 (Auke Bay) Alaska Electric Light § 7.03 71,482 10 «98 _ Power (Juneau) * Ketchikan City of Ketchikan Public 5.66 66,628 9 99 Utilities Outer Ketchikan Metlakatla Power § Light 5.31 16,435 10 +70 Prince of Wales Alaska Power § Tele- 14,60 1,054 5 .97 phone Co. (Craig) Alaska Power & Tele~ 23.27 466 5 +98 phone Co. (Hydaburg) Sitka City & Borough of Sitka 4.45 29,467 6 +94 Skagway-Yakutat Pelican Utility Co. 1.10 2 Alaska Power § Telephone 10.20 3,708 S -88 Co, (Skagway) Wrangell- Petersburg Municipal 9.25 15,970 5 .93 Petersburg Light § Power Wrangell Municipal 6,75 9,076 8 +98 Power Plant Average 6,54 Table 3-3 continued Source: FPC data for the period 1965-1974, 1973 total 3-10 1974 Total Annual KWH Sales Map Regions and Electric Growth to Final i : 2 Census Divisions Utility Rate (%) Consumers Observations R _ REGION I Northwest Alaska Kobuk Kotzebue Electric Assn, 8,90 4,859 5 94 Nome Nome Light § Power 8.57 8,921 8 .89 Matanuska Electric Assn. 6.39 1,398 8 -87 Qnalakleet) Average 7,86 REGION II Southwest Alaska Bethel Bethel Utilities Corp. 21.36 11,948 6 -96 Bristol Bay Nushagak Electric Coop. 9.80 3,565 4 96 @illingham) ® Bristol Bay Bor, Naknek Electric Assn. 8,17 4,864 4 oa Kuskokwin McGrath Light § Power 1.14 1,102 6 -07 Average 11.49 Association, the third largest in the state in terms of 1974 sales, experi- enced an annual growth rate of over 20 percent for the 10-year period. This is equivalent to a doubling of sales every 4 years. Three smaller utili- ties at Bethel, Hydaburg, and Port Graham had annual growth rates in excess of 20 percent. Third, the high R? figure for most utilities masks some substantial year- to-year variations in growth rates.” Chugach Electric Association for example, with an average growth rate over the period of 14.3 percent, has a growth in sales of 17.9 percent between 1969 and 1970 and only 6.6 percent between 1973 and 1974. The rapid growth rates observed have resulted from a combination of two factors - population increase and growth in per capita consumption. Table 3-4 divides the electricity consumption growth for the period into these two component parts for the six regions of the state for which data is available. 3-11 TABLE 3-4 Historic Growth Rates Related to Electricity Consumption (1965-1973) Annual Growth Annual Growth. Annual Growth Region Electricity Consumption Population Per Capita Electricity (percent) (percent) Consumption (percent) Anchorage 1255. 4.8 Ted, Southcentral 1158, 4.4 735 Fairbanks 14.1 2.9 eZ ‘ Southeast 6.5 ed) 4.8 Northwest 7.9 1.6 6:5 "Southwest i% 8 10.7 (Text continues below. ) The annual growth rate of population between 1965 and 1973 shows con- siderable variation from region to region with the railbelt area (Anchorage, Fairbanks, and Southcentral) showing the strongest growth. The Northwest and Southwest had rates closer to but higher than the national average, and only the Southwest had a population growth rate under 1 percent. Growth in elec- tricity consumption has not closely followed the growth in population. Total 3-le electricity consumption in the Southwest grew at the rate of 11.5 percent, and the population increased at the rate of 0.8 percent; while in the South- east, consumption grew only 6.4 percent annually and population increased 1.7 percent annually. These differences are calculated in Table 3-4 as the annual per capita growth rates in electricity consumption which vary from a low of 4.8 percent per annum in the Southeast to a high of 11.2 percent in the Fairbanks region. Variation in the growth of per capita consumption is the result of two factors. The number of electric hookups for every 1,000 persons has been increasing as the service areas of utilities have expanded, the average size of families has changed, and the composition of economic activity has changed. At the same time, average consumption per consumer has been increasing. The data in Table 3-4 do not allow one to distinguish between these two components of growth. Tables 3-5 and 3-6 show the extent to which average annual kilowatt hour electricity usage has increased from 1965 through 1974 at the same time that the number of customers has increased. (In the Northwest and Southwest, no meaningful distinction by type of customer is possible.) There are significant differences in both the level and growth rate of kwh consumption per customer across regions. This difference in addition to differences in rates of popu- lation growth and extension of service to ee a unserved customers, accounts for differences in rates of growth in electricity demand by regions. 3-13 PL-E Year 1965 66 67 68 69 70 71 72 73 74 Table 3-5 AVERAGE ANNUAL RESIDENTIAL ‘ELECTRICITY USE ANCHORAGE FAIRBANKS SOUTHEAST SOUTHCENTRAL Number of Average Number of = Average Nunber of Average - Number of Average Customers Annual KWH Customers Annual KWH Customers Annual KWH Customers ‘Annual KWH 22,110 6,614 8,183 4,804 9,050 6,067 “7,336 4,946 23,003 7110 8,170 5,712 9,291 6,309 6,677 5,726 23,931 7,246 8,574 6,055 9,354 6,472 7,792 5,453 27,437 6,977 9,344 6,569 9,314 6,865 8,698 5,719 30,079 7,112 10,023 7,672 9,570 7,121 9,278 6,187 33,159 7,641 10,756 8,418 9,877 - 7,459 10,800 6,401 35,056 8,555 11,184 9,515 10,419 7,593 11,467 7,287 38,817 8,817 11,487 10,529 10,995 7,719 11,899 7.715 39,915 9,273 11,825 11,233 11,677 7,472 12,617 8,175 43,453 9,106 13,261 11,597 11,940 7,623 14,507 8,029 a _» \ i a - Table 3-6 AVERAGE ANNUAL_COMMERCIAL- INDUSTRIAL ELECTRICITY USE PER CUSTOMER ANCHORAGE COMMERCIAL/INDUSTRIAL FAIRBANKS COMMERCIAL/INDUSTRIAL Number of Average Number Year Customers Annual MWH Custome 1965 3,035 46.997 1,318 66 3,105 51.790 1,467 67 3,195 56.794 1,452 68 3,488 56.865 1,469 69 3,793 58.475 1,579 70 4,093 63.260 1,717 71 4,245 70.804 1,772 72 4,652 75.654 1,800 73 4,815 84.714 1,883 74 5,132 85.395 2,073 SOUTHEAST COMMERCIAL SOUTHEAST INDUSTRIAL Number of Average Number of Average Year Customers Annual MWH Customers Annual MWH 1965 1,608 20.345 * * 66 1,662 21,227 * * 67 1,650 21.932 * * “68 1,657 22.749 * * 69 1,704 22.700 * * 70 1,761 25.117 57 457.912 71 1,783 26.515 54 522.870 72 1,857 27.607 89 322.101 73 1,943 29.440 52 549.442 74 1,359 28.852 13 1,401.385 * No customer figures available 3-15 of rs 25 23. 25. 33. 35. 62. 69. 69. 73. 71. 1817 910 363 665 269 087 268 773 167 449 Average Annual_MWH SOUTHCENTRAL SOMMERCTAL/ Number of Average Customers Annual MWH 1 575 35.594 1,399 41 924 1,559 40.880 1,703 49.342 1,687 58.518 2,447 49.412 23001 56.280 2,403 54.420 2,636 54.961 2,839 53.583 Table 3-7 shows that annual average electricity use per customer varies considerably within regions as well as across parts of the state. Herey average annual residential use is broken into the census divisions for 1974. The state- 4 wide average of 8,860 kwh is exceeded by the Anchorage and Fairbanks divisions, the two most populous in the state, and by Outer Ketchikan, which contains the Coast Guard station at Metlakatla. These are the three areas of the state which q contribute to Alaskan residential electricity use per customer being consistently 5 to 10 percent higher than the national avetakes” Ll This short review of recent utility electricity statistics for Alaska indicates that no region of the state is typical of the state as a whole in its i past pattern of growth. Growth in consumption is not adequately explained by a single parameter such as population or se per customer. Projections of future demand for electricity must consider a broad range of factors on a regional basis. 3-16 Table 3-7 1974 RESIDENTIAL ELECTRICITY CONSUMPTION (A) B) c . 1974 KWH SA) Map Region, ; 1974 Residential Residential Annual KWH Census Division Utility Locations _ Customers Sales by Utilities Sales/Customers REGION V Anchorage Anchorage Anchorage 43,456 395,854,136 9,109 REGION VI . Interior Upper Yukon Ft. Yukon 130 179,650 1,381 Yukon- Koyukuk Manley Hot Springs 9. 48,764 5,418 REGION VII Fairbanks Fairbanks Fairbanks 13,261 153,781,613 11,597 Southeast Fairbanks Dot Lake, Tok * 674,870 * REGION III Southeast Alaska Angoon wor --- o-- Haines . 596 5,346,132 8,970 Juneau Auke Bay, Juneau 5,266 35,392,244 6,721 - Ketchikan Ketchikan 3,569** 30,957 ,853** 8,674** Outer Ketchikan Metlakatla 326 6,881 ,403 21,109 Prince of Wales Craig, Hydaburg * 742,597 * ‘Sitka Sitka 1,666 11,656 ,608 6,997 Skagway- Yakutat Pelican, Skagway * 1,205,185 * Wrangel1- Petersburg Wrangell, Petersburg 1,532 9,482,975 6,190 Source: FPC reports and Alaska Public Utilities Commission Annual Reports * Consumption figures not complete ** 1973 figures Table 3-7 continued A B c ™) 1974 a SA) Map Region, 1974 Residential Residential Annual KWH Census Division Utility Locations Customers Sales by Utilities Sales/Customers REGION IV Southcentral Alaska Cordova- : McCarthy Cordova 534 3,159,042 5,916 Kenai-Cook Inlet Homer 2,023 14,494,954 7,165 Kodiak Kodiak 1,774 10,596,414 5,973 Matanuska- Susitna Palmer 1,087 5,940,733 5,465 Seward Seward 785 4,664,360" 5,942 Valdez- Chitina- Whittier Valdez 935 3,750,993 4,012 REGION I Northwest Alaska Barrow Barrow 377 915,896 2,429 Kobuk Kotzebue 369 1,553,676 4,210 Nome Nome, Unalakleet 748 6,454,067 8,628 REGION II Southwest Alaska Aleutian Islands --- --- --- Bethel Bethel 670 2,470,288 3,687 Bristol Bay Naknek 190 ‘980,821 5,162 Borough Bristol Bay Dillingham 301 1,200,571 3,989 Kuskokwim McGrath 54 97 ,283 1,802 Wade Hampton i --- wee on= . TOTAL 79,062 700,514,344 8,860 3-18 B. The Future Alaskan Economy 1. Introduction Projections of future electricity demand within Alaska were made using a two-step procedure. First, projections were made of the future level of economic activity within the state. Then for each projected level of eco- nomic activity, a range of projections on the intensity of electricity use was developed. Thus, a projection of the level of electricity demand is the combination of an economic projection and an electricity-use projection. This procedure results in both a large number of final projections and in a broad band of estimates of future demand even after assuming a level of economic activity. The reason for this is that the intensity of electricity use is not specified by the level of economic activity alone, especially in an economy which is growing as rapidly as that of Alaska. The availability and price of competing fuels may change significantly over the projection period in ways which are not predictable by growth of the Alaskan economy alone. For example, Prudhoe Bay natural gas will be marketed using some transportation system, and some economic growth within the state will result from this. If the El Paso trans- portation system proposal is approved, a decision which will probably be made in the U. S. Congress, gas may or may not be available in Fairbanks. The Federal Power Commission will possibly have jurisdiction over whether the gas line could be tapped to supply Fairbanks, and its decision may not be based upon economics. Thus, cin pean Tyee of natural gas in Fairbanks cannot be predicted by any economic model, 3-19 The large number of alternatives examined here allows the possible future projections to be divided into more scenarios than the usual set of three: (1) low growth, (2) medium growth, and (3) high growth. Each particular demand scenario could be used in conjunction with a different set of assumptions concerning the availability and cost of electricity supply to analyze least-cost generation alternatives in a supply and demand framework. This allows the relationship of electricity cost to price and thus demand to be considered. 2. Methodology for Economic Ptojections The economic projections are based upon an econometric model of the Alaskan sear (MAP model) developed at the University of Alaska's In- stitute of Social and Economic Research. The MAP economic model of Alaska provides estimates of the future level of output, employment, and wages and salaries by industry, and real disposable personal income and population. The model divides the state into seven geographic regions, and the variables are estimated for each region. All relationships between economic variables have been determined statis— tically using sidake data. These past relationships are for the most’ part assumed to be applicable to the future Alaskan economy and are thus used for purposes of projections. The industrial sectors fall into two categories, depending upon whether factors within the state or outside the state are the primary determinants of the level of activity. In the former category are the support industries, including trade, finance, services, transportation, communication, and public utilities. Output in these industries responds to local demands for goods and 3-20 services, which are generated by Alaskan disposable income. Thus, the level of economic activity within the state determines the level of output of these industries. The latter category includes the mining (and petroleum) industry, agriculture-forestry-fisheries, and manufacturing. The level of output in these sectors is largely a function of forces outside the economy of Alaska. The level of demand in national and international markets, the availability of resources, and policies of the federal government are the essential de- terminants of output in these industries. The construction industry is in a special category because factors both within Alaska and outside the state combine to determine its level. One component of construction activity provides for needs of consumers with- in the state. In addition, construction activity is related to activity in those industries which are independent of consumer demand within the state. The Trans-Alaska oil pipeline is one example of an activity which induces demand for the output of the construction industry. The government sector includes both a model of government revenues from taxation and expenditures out of revenue. The state, by establishing a reserve fund, has the option of not spending all revenues as they accrue. The level of Federal government output and the level of military activity are determined outside of the model. A demographic model is integrated into the economic model to project population change. Net migration, which is a function of the level of eco- nomic activity within the state, together with natural increases explain population dynamics. 3-21 For given values of the variables which generate the level of output in those industrial sectors determined outside the state economy (exogenous varia- bles), the model iteratively solves a set of equations projecting the level of economic activity within the state. The level of output is a function of personal income, so output of industry and income of individuals must be determined simultaneously. A consistent set of exogenous variables is known as a "scenario," since each such set is based upon a set of assumptions regarding government policies and economic activities outside the state, which create demands for Alaskan products. Incorporating each set of exogenous variables into the model results in a different projection of the growth and composition of economic activity in Alaska. Obviously, there are an infinite number of possible specific patterns by which forces outside the Alaskan economy could affect economic growth within the state. It is assumed that the most likely pattern of future development will center upon growth of the petroleum industry within the state, and for this reason, "petroleum scenarios" have been developed to derive the projections of this economic development. The level of output in other industries determined by exogenous forces will undoubtedly change and contribute to economic growth in the state. There are two reasons why the scenarios do not explicitly consider large increases in activity occurring in industries other than petroleum. First, petroleum develop- ment in Alaska is a certainty because reserves are present in large quantities at a 3-22 cost which makes them marketable not only today, but also in the foreseeable future. The outlook for other raw material industries is not as consistently favorable because of problems of accessibility, high labor costs, quality of the raw materials, and uncertain market demand. Developments will undoubtedly occur, but it is not possible to specifically predict the pattern of such development. Second, the impact of development in other natural resource in- dustries will be small for the state as a whole in comparison with the impact resulting from petroleum exploitation. The output in other natural resource industries is expected to grow, but not so much as to be considered the driving force behind the growth of the Alaskan economy. The pace of growth in these areas does not differ among the "petroleum scenarios." Growth in the fisheries industry is constrained by the availability of natural resources to one percent per annum in real value of output. The forest products industry is constrained by supply and Federal government policies with regard to allowable cuts. In spite of this, output between 1975 and 1990 is projected to nearly double, but the growth rate declines from 6 percent in the early part of the period to 2.5 percent towards the end. Nonpetroleum mining and agriculture are projected to increase only slightly in the future because of problems of climate, transportation, technology, and suit- able land. Specific developments may be of local importance but their impact on the total economy is likely to be minor. Three "petroleum scenarios" have been constructed corresponding to three possible levels of development of reserves within the state between 1975 and 1990. None of the three is a prediction of what actually will happen because actual development patterns are dependent upon state and Federal government policy, the 3-23 actual levels of reserves discovered in various reservoirs, costs of explora- tion and development, price of petroleum products, international politics, capital available to the petroleum industry, and other factors, none of which can be predicted with any certainty. Each scenario rather is a consistent and systematic construct of what might happen if petroleum development is cies ‘ 7 "limited," "accelerated," or "maximum." The basic components of each scenario are as follows: 1) Limited Petroleum Development Present developments are continued in Cook Inlet and Prudhoe Bay. Federal government activity is limited to leasing of Lower Cook Inlet and Federal areas in the Gulf of Alaska. The state and private interests (essentially the Native cor- porations) lease and develop in the areas adjacent to exist- ing producing fields and near existing pipeline facilities. The state leases in the Beaufort Sea and North Slope Upland Area and Native leasing occurs in the North Slope Uplands as well as in the Yukon-Kandik and Copper River areas. Under this scenario, total production of oil rises from 2 million barrels/day in 1980 to nearly 3.6 million barrels/day by 1990. A gas pipeline is constructed from Prudhoe Bay through Canada. An LNG facility is constructed to process Gulf of Alaska gas. 2) Accelerated Petroleum Development The accelerated development case, in addition to all the activity in the limited development scenario, includes activities related to the opening of Naval Petroleum Reserve #4 for development by the Federal government. As a result of this, a second pipeline is constructed from the North Slope to carry oil on a route closely parallel to the existing trans-Alaska pipeline. Federal ' government activity includes further leasing in Lower Cook Inlet as well as the Bering Sea, the Beaufort or Chukchi Sea, and Pet 4. The state leases adjacent areas including the Gulf of Alaska, Beaufort/Chukchi, and west of Pet 4. Native leasing occurs on the North Slope in the vicinity of Pet 4. Oil production in this case rises from 2 million barrels/day in 1980 to 7.3 million barrels/day in 1990. 3-24 3) Maximum Petroleum Development The maximum development case incorporates the most favorable assumptions regarding levels of economically recoverable re- serves, capital availability, and sufficient technology com- bined with the present Federal government energy development plans, to present the maximum possible amount of petroleum acitivity. This rate of development is compatible with Project Independence and the Federal OCS leasing schedule. All acti- vities in the accelerated case are included and, in addition, the leasing of tracts in Western Alaska will necessitate the construction of both an oil and a gas pipeline to transport these commodities to a port facility in Southcentral Alaska. Additional Federal leasing will occur in the Bering and Chukchi Seas. State leasing will occur in the Chukchi-Hope Basin and Ha Bristol Bay area. Native corporations will lease additional tracts west of Pet 4 and in the Selawik/Yukon - Koyokuk/Bethel area. Production of oil rises from 2 million barrels/day of oil in 1980 to nearly 10 million barrels/day in 1990. Growth of the economy will be realized in two ways from the exploitation of petroleum. First, as exploration, development, and production of the resources occur, new employment opportunities will be generated. These will increase disposable personal income which will create additional demands in other sectors of the economy. Second, the state will obtain revenues in the form of lease bonuses, production taxes, royalties, and property taxes which will be spent for government services and capital improvements. This spending will in turn con- tribute to increased disposable personal incomes for Alaskans which will generate additional demands in other sectors of the economy. This may occur long after the resource exploitation phase of development. The role of state spending thus plays an important role in the rate of ‘it it impossible growth of the Alaskan economy. As with "petroleum scenarios,' to predict the pattern of state government spending over a 15-year period. There- fore, for this exercise it is assumed that the structure of state and local taxa- tion remains basically unchanged in the future, and that the pattern of total 3-25 state and local government expenditures remains the same in terms of the pro- portion of the budget going into various categories. Nonpetroleum related revenues will be spent in the year they accrue. It is assumed that 25 per- cent of recurrent revenues in the form of royalties, production taxes, and property taxes will be saved after 1978 when Prudhoe Bay oil begins flowing. Of non-recurrent revenue, essentially the lease bonuses, 50 percent will be saved. The income from the reserve fund is spent as it accrues. Since state oil revenues are sensitive to the wellhead price of oil, this is assumed to be $5/barrel for all new reservoirs in the state. 3. Economic Scenarios Two petroleum scenarios were chosen as being more likely to reflect the actual pace of petroleum development in Alaska between the present and 1990. The "maximum petroleum development" scenario is based upon the accelerated outer continental shelf leasing schedule of the Bureau of Land Management, Department of the Interior, which calls for nine sales in Alaska before the end of 1978. This schedule appears unattainable in light of recent events. As — of February, 1976, no sales had been held. Russell Train, administrator of ' the Environmental Protection Agency, urged Interior Secretary Kleppe to post- pone indefinitely the scheduled sale in the Gulf of Alaska. If it is held this , 4 year, it will include reduced acreage. A sale off the coast of Southern Cali- fornia in December, 1975, resulted in a disappointing leasing of only 25 per- cent of the acreage offered. And in response to this, the acreage being of- a fered for bid in a sale off New England later in 1975 has been drastically 3-26 reduced, and the sale itself has been postponed at least two months. ® Thus, the "maximum development scenario" does not seem reasonable as a basis for projecting electricity demand. 9 The two remaining scenarios, as noted previously, cannot and do not purport to predict exogenous economic changes which may have significant lo- cal impacts but which would be swamped by the size of overall growth of the state. Thus, for example, no attempt has been made to analyze the effect on Southeastern communities of the relocation of the Coast Guard station from Metlakatla to Sitka. (Separate report by Homan - McDowell Associates addresses specific local developments in the Southeast.) In addition, the effect of the capital move and the construction of a trans-Alaska gas pipeline have not been built into the scenarios because both are uncertain at the present time. The scenarios present the broad outlines of economic growth of the state on a regional basis. A statewide summary of projection values for the two scenarios are presented as Table 3-8. Detailed projections of regional gross product, employment, real wages and salaries, and population are included in an appendix. The growth rates of key economic variables for the "limited" and "accelerated" scenarios are presented in Table 3-9. The basic difference between the limited and accelerated cases is that through the decade of the 1980's, a higher growth rate is sustained as a result of continuing new petroleum leasing in the accelerated case. In the limited case, leasing of fields ends in 1978 but the employment associated with exploitation of the fields peaks in the early 1980's. Government spending from oil revenues begins in 1978 and continues throughout the projection period. The accelerated 3-27 Table 3-8 SALIENT STATISTICS OF MAP PROJECTIONS Limited Development 1974 Population ( Employment ( State and Local Government 1980 Population ( Employment ( State and Local Government 1985 Population ( Employment ( State and Local Government 1990 Population ( Employment ( State and Local Government ) 350.659 thousand persons) 159.886 Wages and Salaries (real million $) 973.9 Petroleum Production (thousand b/d) 200 Expenditures (nominal miilion $) 793.2 ) 456.927 thousand persons) 219.712 Wages and Salaries (real million $) ae Petroleum Production (thousand b/d) 2,066 Expenditures (nominal million $) 1,973.3 ) 547.913 thousand persons) 265.412 d Salari real million $) 1,970.0 NGS in Praes a (thousand b/d) 3,033 Expenditures (nominal million $) 3,408.8 ) 641.344 thousand persons) 312.677 Wages and Salaries (real million $) Aan Petroleum Production (thousand p/q) > 5,026.1 Expenditures (nominal million $) 3-28 Accelerated Development 350.659 159.886 973.9 200 793.2 471.429 229.249 1,586.3 2,066 2,058.1 614.811 300.916 2,260.8 4,930 4,084.4 738.004 361.399 2,919.2 7,299 6,197.1 Table 3-9 GROWIH RATES OF ECONOMIC VARIABLES FOR LIMITED AND ACCELERATED PETROLEUM DEVELOPMENT SCENARIOS POPULATION 1974 - 1980 1980 - 1990 1974: - 1990 Region Limited Accelerated Limited Accelerated — Limited "Accelerated Vv. Anchorage 5.8 6.3 4.8. 63 §.2_ 6. 2 IV. Southcentral 6.0 7.3 2.9 3.6 4.0 * 5.0 VI,. Interior ene 2.9 - 0.1 0.1 0.2 4.3 VII. Fairbanks 2.4 2.6 2.1 3.1 2.2 2,9 III. Southeast 4.0 4.3 2.5 3.5 3.0 3.8 I. Northwest 1.7 2.9 1.2 1.9 1.4 2.3 II, Southwest 1 a2 1.1 2.0, 1.1 1.7 State 4.5 So 3.4 4.6 3.8 4.8 EMPLOYMENT 1974 - 1980. 1980 - 1990 1974 - 1990 Region Limited Accelerated Limited Accelerated Limited Accelerated Vv. Anchorage 6.3 6.9 4.9 6.0 5.4 6.4 IV. Southcentral 6.0 ToS 2.6 ora 3.9 4.6 VI. Interior 6.7 8.9 - 3.5 1s? 0.2 26 VII, Fairbanks | 3a 3.5° 2.4 3.3 2.7 34 I1I. Southeast 5.3 5.6 2.8 3.9 3.8 4.5 I, Northwest 4.9 8.7 2.8 4.1 3.6 5.8 II. . Southwest aol 3.6 2.5 4.2 21 4,0 State - 5.4 6.2 .6 4.7 4.3 5.2 REAL WAGES AND SALARIES 1974 - 1980 1980 - 1990 1974 - 1990 Region Limited - Accelerated Limited Accelerated Limited Accelerated V. Anchorage 8.4 9.0 6.4 7.6 7.2 8.1 IV. Southcentral 8.6 10.5 4.0 4.4 5.7 6.6 VI, Interior 6.3 8.5 - 3.3 - 0.8 0.2 2.6 VII. Fairbanks 5.4 5.9 4.6 Leda 4.9 57 III, Southeast 7.5 7.9 4.8 5.9 5.8 6.6 I, Northwest 6.9 13.0 4.9 6.0 5.6 8.6 II, Southwest _5.4 5.9 4.3 6.3 4.7 6.2 State oe: 8.5 5.2 6.3 6.1 Tel case adds an additional petroleum related employment impact beginning in 1978 and continuing through the 1980's. Government revenues and expenditures increase as a result of higher production of oil beginning in 1980. Both scenarios project high rates of growth for the state for the next fifteen years, tapering off somewhat between 1980 and 1990. In the limited development case, population grows at 3.8 percent yearly over the entire pe- riod, with 4.5 percent growth in the early years and 3.4 percent growth later. Accelerated development results in population growth approximately 25 percent more rapid at a 4.8 percent rate. The more rapid growth is concentrated in the period between 1980 and 1990 when accelerated population growth exceeds limited by 35 percent. The pattern for employment and real wages and salaries is essentially the same except that the differences between the limited and accelerated growth rates are not as pronounced. Growth will not be evenly divided among the regions of the state. Growth of employment and real wages and salaries follows the regional pattern of petroleum development. Population growth is more concentrated in the southern portion of the railbelt. Government expenditures will produce growth more evenly divided among the regions. * Future growth in demand for electricity will be a function of economic growth, but is conditioned by the prices and availabilities of alternative fuels. It is thus necessary to examine different intensities of electricity use as well as the pace of economic growth to derive reasonable projections of future electricity demand. 3-30 C. The Intensity of Electricity Consumption 1. Determinants of Intensity of Electricity Use As noted in a previous section, average annual electricity use per consumer shows considerable variation among utilities. In addition, there is considerable variation among utilities in the number of electric hookups for every 1,000 persons in the service area. The "saturation levels" for residential hookups, defined as the ratio of hookups to population in the region, were as indicated in Table 3-10 in 1974. TABLE 3-10 Residential Hookup Saturation Levels 1974 (Percent) Anchorage 31.1 Southcentral 32-7 Fairbanks 28.0 Southeast 24.9 These two components of variability have 3 main causes. a) Utility Service Area. First, there is variation among the regions of the state in the service areas of the utilities relative to the population of the region. Major utility service, according to Table 3-10, seems to be available to a smaller percentage of the population in Fairbanks and the Sdinxet than in either the Anchorage or Southcentral regions. On .the other hand, availability of electricity in the Southcentral region seems to exceed that of Anchorage, possibly because of the large number of second homes and vacation homes in that region. It is significant that the national residential hookup "saturation level" in 3-31 1972 was 28.3 percent, which indicates that the four most populous regions of the state seem to be well saturated with residential hookups. Some of the high rate of saturation is the result of Alaskan family and housing patterns, but this component cannot be separated out. No data is available to determine service areas for commercial and industrial customers or to compare them with national statistics. It seems reasonable to assume that they follow the same relationship to the national average as do residential service areas. Since the majority of the state is ahead of the rest of the nation in terms of "hookup saturation," any future increase would likely be the result of a trend toward smaller family size, more second homes, and factors affecting the ratio of commercial and industrial establishments to population rather than extension of service to new areas. b) Geography. Variation in geography primarily affects the level of electricity consumption per customer. It is important for two reasons. First, as one moves further north, the number of heating degree days generally increases, A heating degree day is a measure of space heating requirements. One heating degree day is recorded for every day for every degree Farenheit by which the temperature falls below 65°. Twenty-year heating degree day ence for selected Alaskan communities are given in Table 3-11. Heating requirements increase with heating degree days and concurrently, electricity demand for space heating. For example, the average annual kwh requirements for space heating in Fairbanks are on the order of 33 percent greater than those in Anchorage.” This rough estimate does not take account of either differences in the average size of electrically heated homes in the two communities or of differences in the 3-32 Table 3-11 HEATING DEGREE DAYS FOR ALASKAN COMMUNITIES 20 YEAR AVERAGES (1955-1974) Degree Days (Farenheit) Anchorage 10,960 Annette (S.E.) 7,054 Barrow 20,426 Barter Island (Int.) 20,197 Bethel 13,372 Bettles (Int.) 16,107 Cold Bay 9,885 Fairbanks 14,439 Gulkana 14,250 Homer 10,443 Juneau 9,184 King Salmon (S.W.) 11,701 Kodiak 8,890 Kotzebue (N.W.) 16,171 McGrath (S.W.) 14,667 Nome (N.W.) 14,512 St. Paul Island 11,205 Shemya (S.W.) 9,574 Summit (S.C.) 14,603 Talkeetna 12,024 Unalakleet (N.W.) 14,162 Yakutat (S.E.) 9,711 Source: U.S. Dept. of Commerce, National Oceanic and Atmospheric Administration, Environmental Data Service, "Local Clima- tological Data," various issues, Asheville, N.C., 1974. 3-33 average quality of insulation. Climate also affects electricity consumption because of differing requirements for electric appliances such as automobile engine heaters, humidifiers, etc. Latitude determines the number of. hours of daylight available during the year and thus affects the demand for electric lighting and electric ck lighting. This is particularly significant in small rural communities where a large percentage of consumption is for electric lights. c) Economic Effects. The consumption of electricity depends not only upon the level of aggregate activity in the economy as measured by output, popu- lation, employment, and disposable income. If not constrained by supply, it is also a function of the price of energy, the relative price of electricity compared to other types of energy, and the level of real income of consumers. The sensi- tivity of the level of consumption to these factors varies by consumer type. In the case of residential consumers, consumption may be expected to rise as real disposable income rises and as the real price of electricity falls. Considerable effort has been expended by economists in attempts to measure the magnitude of adjustmerit in demand to price and income changes. A recent economic journal article has summarized the results of the more well known atadtan,** Nearly all studies reviewed in that article found that in the long run (a period of many years), the price elasticity of electricity is greater than one. This is equivalent to the statement that in the long run, a one-percent rise in the price of electricity will cause demand to fall by more than one percent, Implicit is the assumption that other energy prices are held constant - a fair assumption for small electricity price changes, but not necessarily large changes. 3-34 The findings on the income elasticity of electricity are not as consistent. Estimates range from zero to two, indicating that a one-percent increase in income is predicted to increase electricity demand by from zero. to two percent. This variability is partially a function of the type of "model" Gullaged in estimating the demand equation. More recent studies have found that the response of electricity demand to an income change will depend upon the level of income. In particular, the price elasticity of electricity demand was found to be a positive function of the level of income. 12 Thus, the higher one's level of income, the smaller one's incremental electricity consumption as income rises further. Equivalently, lower income individuals will increase their electricity consump- tion more with a given dollar income increase than high income individuals. This finding is consistent with the theory that many electric appliances are considered to be "necessities" by most people. Residential electricity rates on file with the Alaska Public Utilities Commission as of October, 1975, were used to construct the typical bills and average prices per kwh presented as Table 3-12. Consumption of 500 kwh per month is equivalent to 6,000 kwh per year, which is somewhat less than an all- electric appliance household would consume during a year without electric heating. The typical bills are not in every instance the rates which consumers pay for two reasons. Some utilities have several residential consumer categories with dif- ferent rate schedules, and since the latter part of 1973, automatic fuel adjust- ment rate clauses have allowed utilities to pass through the increased costs of fuel to consumers in the form of temporary rate increases. 3-35 9E-€ Table 3-12 RESIDENTIAL ELECTRICITY TYPICAL MONTHLY BILLS October, 1975 Minimum 50 KWH Price 100 KWH Price 500 KWH Price Map Region, Utility Bill Bill per KWH Bill per KWH Bill per KWH Census Division Locations REGION V Anchorage 1 Anchorage Eagle River 9.00 9.00 18.0 9.00 9.0 31.25 6.3 ee 2.00 2.75 5.5 4.25 4.3 13.00 2.6 Chugac! 2.00 4.75 5.5 4.25 4.3 13.75 2.8 REGION IV Southcentral Alaska . ' Cordova-McCarthy Cordova 4.00 6.50 13.0 9.50 9.5 27.50 5.5 Kenai-Cook Homer 7.50 7.50 15.0 8.00 8.0 25.00 5.0 Inlet Kenai 5.00 5.00 10.0 7.50 7.5 23.50 4.7 Port Graham* : i Seldovia 7.50 7.50 15.0 11.50 11.5 33.50 6.7 Soldotna 7.50 7.50 15.0 8.00 8.0 25.00 5.0 Kodiak Kodiak 3.00 5.50 11.0 9.13 9.1 24.63 4.9 Port Lions 9.00 7.00 14.0 14.00 14.0 44.00 8.8 Matanuska- Susitna Palmer 9.00 9.00 18.0 9.00 | 9.0 31.25 6.3 Seward Seward 6.00 7.80 15.6 12.30 12.3 23.30 4.7 Valdez-Chitina- Chitina --- 7.50 15.0 15.00 15.0 75.00) 21/1.) 1630 Whittier Glennallen 7.50 8.00 16.0 13.50 18.5 45.50 9.1 Valdez 5.00 5.00 10.0 9.75 9.8 41.75 8.4 Paxson Lodge 5.00 8.00 16.0 13.50 18.5 53.50 10.7 ee * Information not available LE-€. TABLE 3-12 CONTINUED - Minimum 50 KWH Price 100 KWH Price 500 KWH Price Map Region, Utility Bill Bill per KWH Bill per KWH Bill per KWH Census Division Locations _ . REGION VII Fairbanks Fairbanks Municipal 1.80 4.00 8.0 7.50 7.5 22.50 4.5 Golden Valley 10.00 10.00 20.0 10.00 10.0 37.96 7.6 Southeast Delta Junction 10.00 10.00 20.0 10.00 10.0 30.38 6.1 Fairbanks Dot Lake --- 7.50 15.0 15.00 15.0 63.00 12.6 Northway 10.00 10.00 20.0 13.00 13.0 55.00 11.0 Tok 7.80: , 7.50 15.0 13.00 13.0 53.50 10.7 Alaska Village Electric Cooperative (AVEC) --- 10.00 20.0 18.75 18.8 72.75» 14.6 REGION VI Interior Upper Yukon Deadhorse --- 13.20 26.4 26.39 26.4 131.94 26.4 Fort Yukon 3.00 12.50 25.0 25.00 25.0 85.00 17.0 Yukon-Koyukuk Bettles oo- 12.00 24.0 24.00 24.0 120.00 24.0 Manley Hot Springs 10.00 12.50 25.0 25.00 25.0 125.00 25.0 Nenana 7.00 7.00 14.0 13.00 13.0 61.00 T2ce Tanana 7.80 7.80 15.6 13.00 13.0 61.00 1252 BE-€ Map Region, REGION III Southeast Alaska Haines Juneau Ketchikan Outer Ketchikan Prince of Wales Sitka Skagway- Yakutat Wrangel1- Petersburg Utility Locations Haines Auke Bay Juneau Ketchikan Metlakatla*: Craig Hydaburg Sitka Hoonah Pelican Skagway Yakutat Petersburg* Wrangell * Information not available “Minimum Bill 5.50 10.00 4.00 4.50 3.30 3.30 5.00° 2.50 3.50 5.00 5.50 TABLE 3-12 CONTINUED 50 KWH Bill 5.50 10.00 4.00 6.00 5.30 5.30 5.00 5.00 3.75 5.00 5.00 5.50 Price per KWH 11.0 20.0 8.0 12.0 10.6 10.6 10.0 10.0 7.5 10.0 10.0 11.0 100 KWH Bill -50 00 - -00 7.50 -80 -80 -00 -00 -00 -00 +35 Price per KWH 500 KWH Bill 23. 35. 20. 18. 37. S7 19 50. 26. -50 40. 31 24. 50 00 80 25 80 80 -00 00 00 00 75 6e-¢ TABLE 3-12 CONTINUED y Minimum 50 KWH Price 100 KWH Price 500 KWH Price Map Region, Utility > Bill Bill per KWH Bill per XWH Bill per KWH Census Division Locations ($) (S) (¢) ($) (¢) ($) (¢) REGION I Northwest Alaska Barrow Barrow 10:00 10.00 20.0 15.00 15.0 66.00 1352 Kobuk Kotzebue 10.00 - 10.00 20.0 17.50 ze 67.50 13.5 Nome Nome 5.00 5.00. 10.0 10.00 10.0 50.00 10.0 Teller 10.00 20.0 20.00 20.0 100.00 20.0 Unalakleet 10.00 12.00 24.0 18.00 18.0 54.00 10.8 REGION II Southwest Alaska Aleutian Islands Cold Bay " 10.00 10.00 20.0 ~ 10.00 10.0 41.00 8.2 Bethel : Bethel 5.00 6.00 12.0 11.00 11.0 44.75 9.0 Bristol Bay Dillingham 14.00 14.00 28.0 14.00 14.0 50.00 10.0 Egegik : 7.50 7.50 15.0 13.50 1335 44.50 8.9 Bristol Bay King Salmon 7.50 ° 7.50 15.0 13.50 13.5 44.50 8.9 Borough Naknek 7.50 7.50 2), 1520) 13.50 13.5 44.50 8.9 Kuskokwim Aniak 20.00 20.00 40.0 20.00 20.0 95.00 19.0 McGrath 5.00 6.75 13.5 12.50 1255 57,008) Wr ile4 Source: Electric utility rate files, Alaska Public Utilities Commission. These are the rates on file at the commission and do not include either interim rate increases or automatic fuel cost rate adjustments which increase actual prices paid. For utilities with more than one residential rate, the base rate without specific appliances was reported. The range of prices per kwh for 500 kwh bills is huge. The smallest average prices are in Anchorage where a kwh costs from 2.6¢ to 2.8¢. In the Southcentral, the range for the large utilities is between 4.7¢ and 6.7¢, except for Glennallen and Valdez which are 9.1¢ and 8.4¢, respectively. Fair- banks prices range between 4.5¢ and 7.6¢ with much higher prices in the smaller outlying communities. In the Southeast, the price ranges from 3.7¢ up to 6.3¢ for the larger utilities, while it is between 7¢ and 8¢ for the small utilities. Prices in the Northwest, Southwest, and Interior generally begin at the level of the highest prices in the other regions and continue upward. The Southwest prices are between 8.2¢ and 11.4¢, except for Aniak at 19.0¢. In the Northwest the range is from 10.0¢ to 20.0¢. In the Interior, the range is 12.2¢ to 26.4¢. The AVEC rate of 14.5¢ is the same in communities in all regions of the state. The range that utilities charge for 500 kwh/month of electricity thus varies between 2.6¢ and 26.4¢, a factor of ten. As expected, the price seems to be a function of size and location of the community. A monthly bill of 500 kwh could thus vary from a low of $13.00 to as much as $132.00. Electricity rates are not the same for all consumption levels but rather have declining rate blocks in all but the smallest communities in the state. This means that the price charged for additional increments of electricity declines as monthly purchases increase and it reflects the fact that the cost of providing additional electricity to a consumer declines with increasing pur- chases. This causes the average price of electricity to decline with increas- ing consumption. The average electricity price in Alaska exceeds the national average by a large margin. In 1972, the average residential charge in Alaska was 3.33¢/kwh 3-40 while the average for the United States was 2.29¢/kwh - 45 percent less. ‘The averape for all sales in Alaska was 3.20¢/kwh and 1.77¢/kwh for the United States as a whole, a difference of 80 percent. Twelve years earlier in 1960, the difference between Alaska and the United States average was much larger. The average United States residential kwh sold for 2.47¢ while in Alaska, it was 4.32¢ - a difference of 75 percent. For total sales, the difference was larger. Alaska's average of 4.11¢ put it 143 percent above the national average of 1.69¢. Throughout the 1960's, electricity prices declined both inside Alaska and throughout the contiguous United States, but prices fell much more rapidly in Alaska than elsewhere. Residential prices declined on average over 2 percent yearly between 1960 and 1972 in Alaska and less than 1 percent na- tionally. Total electricity prices in Alaska also declined 2 percent yearly while nationally, they increased by about 0.5 percent yearly. The absolute cost of the average annual residential bill in Alaska in- creased between 1960 and 1972, but the relative cost of the bill declined as compared to the national average. It was 93 percent more than the average bill nationally by 1972.79 Electricity prices throughout the United States have been increasing since 1969 due to increases in electricity generation costs. The index of average prices increased by approximately 42 percent between 1970 and 1974 at an increasing rate.++ In Alaska, the official electricity rates on file with the Alaska Pub- lic Utilities Commission have not increased very rapidly between 1970 and 3-41 1974. Since early 1974, utilities have availed themselves of automatic fuel cost rate adjustment clauses added into their utility tariffs. This clause allows a utility to automatically pass on to consumers, in the form of a surcharge on the electric bill, additions in the costs of fuels actually consumed in the generation of electricity. The amount of the surcharge may change monthly and is not in effect for all utilities. The surcharges in force as of October 1, 1975, are given in Table 3-13. They may rise or fall from month to month because of changes in the price of fuel consumed, cane efficiency, and portion of electricity generated by fossil fuel. For this reason the surcharges reported cannot be assumed to be permanent rate additions but they clearly show the upward pressure on electricity prices resulting from fuel price increases. Price increases resulting from increases in labor, capital, construction, and other costs of inputs are not reflected in fuel adjustment surcharges but rather in rate increases and filings for rate increases. The number of filings for rate increases has expanded in the last several years. Data is also available to compare the average kilowatt hour price of electricity to all-electric utility customers in Alaska's largest cities with cities nationally. As of January 1, 1974, the average charge in cents per kwh for 30,000 kwh per year was between 1.5 cents and 1.63 cents in Anchorage, and between 2.24 cents and 2.77 cents in Fairbanks. The national average charge for 30,000 kwh per year was 2.11 cents. Thus, Anchorage all- electric households were below and Fairbanks above the national average. Average consumption in Alaskan all-electric homes, however, was 34,956 which was 66 percent above the national average for all-electric homes of 21,096 kwh 25 3-42 Table 3-13 AUTOMATIC FUEL COST RATE ADJUSTMENT CLAUSE SURCHARGES AS OF OCTOBER 1, 1975 Utility Aniak Power Company Craig (AP&T) Egegik (Naknek Electric Association) Fort Yukon Utilities Golden Valley Electric Association Haines Light & Power Homer Electric Association Hydaburg (AP&T) Juneau (AELP) Kodiak Electric Association Kotzebue Electric Association Matanuska Electric Association Naknek Electric Association Northern Commercial Company Northern Power and Engineering Northway Power and Light Nushagak Electric Skagway (AP&T) Tok (AP&T) Yakutat Power Company Source: Alaska Public Utilities Commission 3-43 Surcharge in ¢/KWH 2.89 2.06 4.5 1.082 -5973 1.33 1.32 2.49 -48 1.34 -518 «74 5 -87 pony — ~ -76 1.63 1.502 35 1.96 1.604 High nominal electricity prices in Alaska exist along with high average consumption rates. This is partially the result of climate and geography, and partially the result of higher incomes which tend to offset higher Alaskan prices. However, within the state, the price of electricity is inversely correlated with the median income of the region. (The eccenlarion coefficient is -.70.) Higher electricity prices are in general associated with lower median incomes. Quality data iS not available to do a detailed econometric analysis which would isolate the individual effects of price, income, and geography on consumption of electricity in individual communities. However, a simple regression analysis can provide a general idea of trends. A cross-section of census divisions for 1970 was chosen for which utility residential electric sales per customer, price of electricity, heating degree days, and median personal income were known. The resulting equation is as follows: electric consumption . 4.25708 - .64591 electricity price per customer (.12907) + .19345 median income + .27343 heating degree (.11679) ‘ (.13521) days observations = 21 R2 = .774 Standard errors are given below each coefficient. 3-44 Consumption of electricity in Alaska is found to vary directly with the number of heating degree days and the median income of the census division and to vary inversely with the price of electricity. The price elasticity of electricity was calculated to be .9, indicating that a 10 percent increase in the price of electricity while holding other variables constant would, in the long run, reduce electricity consumption by 9 percent. The average income elasticity was found to be .41, indicating that a 10 percent increase in the median income while holding other variables constant would, in the long run, increase electricity consumption by 4.1 percent. Over the 20-year projection period, other factors such as the availability of new products, consumer tastes, living styles, etc., will not be constant and the equation thus has only limited projection value. However, based upon the regression equation it can be assumed that residential electricity consumption will increase at a slower rate than the rate of increase in median income if the prices of fuels do not change. In addition, if the price of electricity rises or falls relative to the prices of competing fuels, electricity consumption will decline or increase relatively. Finally, if the prices of all fuels rise, while the price of other budget items re- main unchanged, a loss of income will in effect have occurred, and consumption of electricity will decline. Data on commercial, industrial, and other electricity consumption categories is not available to do a regression analysis to determine the responsiveness of demand to changes in the price of electricity and other economic variables. National demand studies have also tended to concentrate on residential demand because of the availability of residential data and the heterogeneity of the commercial and industrial consumer classifications. 3-45 The Taylor survey article does report the results of several studies of the price elasticity of demand for commercial and industrial electricity. Of the five studies noted, the long run price elasticity of demand ranged from -1.25 to -1.94,16 This price elasticity of demand is in the same range of response as that found in the residential sector and indicates that in the long run, the commercial and industrial electricity demand response to a price increase would be quite significant. A recent study by the Energy Policy Project of The Ford Foundation investigated the possibilities for energy conservation in various sectors of the economy. The objective of the analysis was to determine what energy- saving technologies, presently available and economically feasible in the presence of increasing prices for energy, could be incorporated into energy consumption patterns as new capacity replaced old through retirement and normal growth. The analysis provides an additional basis for the assumption that increasing energy prices would reduce energy consumption in the commercial and industrial sectors because of conscious efforts to utilize energy more efficiently. The study concludes that in the commercial sector, most of the savings would be the result of more efficient space heating. The report estimates that more efficient use of energy in space heating can cut the growth in energy consumption in the commercial sector by nalr.17 It is impossible to predict possible savings for Alaska based upon a national study, but undoubtedly significant measures could be taken to increase the efficient use of energy under the stimulus of higher prices. Savings in electricity usage would contribute to this. 3-46 In the industrial sector, which includes energy processing, the possible savings through the introduction of energy-efficient technology is more dramatic. It is estimated that by 1985, 22 percent savings could be realized nationally in the manufacturing sector, while 36 percent savings could be realized in the energy processing sector. 28 In the manufacturing sector, more efficient use of energy would result from more efficient steam generation, heat recovery, industrial processing, and materials recycling. Energy consumption in the energy processing sector could be most effectively” reduced through more efficient generation of electricity. Again, it is impossible to extrapolate from this study to project future Alaskan commercial and industrial response to changes in the price of electricity and other types of energy. It seems clear, however, that the potential is present for a significant price response. 2s Methodology for Projecting Intensity of Electricity Use Projections of the intensity of electricity use combine a formula for determining the number of customers with a formula for determining the use per customer. These are later linked to the economic projections of population, income, and employment. Utilities report sales in several consumer categories and the projections have, as feasible, been divided into these separate categories. Farm consumption has been included with residential consumption in this analysis; commercial and industrial have usually been combined because of data inconsistencies; and street lighting consumption has been added to the "other" category which consists primarily of government electricity use. 3-47 The available data allowed demand projections to be divided into user categories in four regions including Southeast, Southcentral, Fairbanks, and Anchorage. 19 Total electricity consumption could be projected for the Northwest and the Southwest, but not its component parts. No utilities from the Interior region file reports on sales to the Federal Power Commission. a. residential demand Four sets of projections were prepared for residential electricity within each region. The large number permits examination of the growth implications of a wide range of possible consumer patterns of future con- sumption. Growth as usual projects future consumption of electricity consistent with past patterns identified by regression analysis, This pattern is based on low electricity prices, increasing appliance stocks per customer, and extension of service to new customers. Moderate electrification and low electrification erotent moderation in the growth of demand because of assumptions of a ceiling on "hookup saturation" and higher future electricity prices resulting in a slowdown of growth in use per customer. No growth projects no growth in use per customer based upon very high electricity prices in the future. Hopefully, this range effectively brackets the minimum and maximum possible cases. The assumptions underlying each case are described in detail below. (1) growth as usual - Two equations for each region were developed by regression analysis. The first explained the number of residential utility customers in the region based upon population and the level of wages and salaries in that region. 2° The second explained the average level of consump- tion per customer based upon real wages and salaries of that region. Data for the regression analysis covered the period 1965 to 1973. 3-48 The results of the regression analysis were generally statistically significant. When linked to the MAP economic model the resulting projec- tions indicate extremely rapid growth in electricity demand which is con- sistent with the pattern during the recent historic period. By analyzing the projected growth in electricity as the combination of growth in customers and growth in average consumption, the growth-as-usual projection appears unrealistic, particularly in those regions with the most rapid past growth rates. For example, average consumption in Fairbanks is projected to increase to 40,000 kwh annually by 1990. This is equivalent to an all-electric home for each additional household in Fairbanks with all presently existing households switching to electric heat. Growth in the number of customers also exceeds reasonable limits in some cases. In 1990, for example, 396 residential hookups are projected for every 1,000 population in Fairbanks. Both these results are consistent with historic growth trends but do not seem reasonable based upon present use levels and hookups as a percentage of population. Table 3-14 compares the number of residential customers in each census division in 1970 with the number of occupied housing units reported on the census. In 1970 the ratio of residential customers to occupied units was -85 for the whole state. This somewhat overstates the level of hookup saturation because of the presence of second homes in some census divisions, notably Matanuska-Susitna. Hookup saturation in the four more populous regions, particularly in the census divisions of those regions with large electric utilities, was quite high. In Anchorage it was 95 percent and in Fairbanks census division, 92 percent. In Southcentral Alaska, Kodiak, and Valdez-Chitina-Whittier aside, the saturation is virtually 100 percent; but 3-49 Map Regions and Census Divisions REGION V Anchorage Anchorage REGION IV Southcentral Alaska Cordova-McCarthy Kenai-Cook Inlet Kodiak Matanuska-Susitna Seward Valdez-Chitina-Whittier REGION VII Fairbanks Fairbanks Southeast Fairbanks Table 3-14 1970 RESIDENTIAL CONSUMER UTILITY SATURATION LEVELS* (a) (b) 1970 Occupied 1970 Residential Units and Rural Consumers 35,021 33,168 563 500 3,881 3,493** 2,535 1,635 1,797 3,974 534 705 1,017 561 11,630 10,756 982 91 Source: 1970 Census of Housing, FPC Form 12 reports. (c) (a-b) Potential, Consumers 1,853 63 388** 900 (-2,177) (-171) 456 874 891 Tq negative figure for potential customers indicates. that there were more hook-ups than occupied units on the day of the census. second homes in those census divisions. *AVEC utilities not included. Includes utilities reporting to the FPC. **Figures not complete. 3-50 This is due to a large number of TABLE 3-14 CONTINUED : . (c) . (a) (b) (a-b) Map Regions and 1970 Occupied 1970 Residential Potential Census Divisions Units and Rural Consumers Consumers REGION VI Interior Upper Yukon 365 --- 365 Yukon-Koyukuk 1,030 --- . 1,030 REGION III Southeast Alaska Angoon : 116 --- 116 Haines 362 ** we Jurieau 4,293 4,307 (-14) Ketchikan 2,820 3,067 (-247) ‘Outer Ketchikan 412 286 126 Prince of Wales 528 ~ 64** 464** “Sitka 1,873 1,378 495 * Skagway-Yakutat 526 272 254 “Wrangel1-Petersburg 1,395 1,303 92 REGION I Northwest Alaska Barrow 513 ** ak Kobuk : 955 346 609 Nome 1,238 79** 1,159** REGION II Southwest Alaska Aleutian Islands 1,192 Dae 1,192 Bethel 1,439 429 1,010 Bristol Bay Borough 213 --- 213 Bristol Bay 655 409 246 Kuskokwim 401 39 362 Wade Hampton 773 --- 773 TOTAL . 79,059 66,862 12,197 3-51 this figure may be misleading because of the presence of residences used only a portion of the year. In the Southeast, excluding Angoon, Haines (no data available), and Prince of Wales census divisions, 94 percent hookup saturation was observed in 1970. : From this analysis, as well as from the "hookup saturation" data of Table 3-10, it appears that the utilities in the more populous regions of the state are near the point of saturating their service areas with residential hookups and that the ratio of hookups to population will not be increasing at the same rate in the future as it has in the past. Table 3-14 also provides an informal estimate of the coverage of utilities statewide. The number of potential customers is a rough approximation because of the omission of several small utilities which do not report to the Federal Power Commission as well as the Alaska Village Electric Cooperatives, and the presence of second homes among the households counted. Table 3-15 and 3-16 detail by census division the number and percentages of households with major appliances according to the 1970 Census of Housing. "Modern" is defined to include an appliance fueled by either natural gas, electricity, fuel oil, or bottled gas. The census divisions with the large electric utilities in the four most populous regions are relatively well saturated with modern major appliances including space heaters, water heaters, and ranges. Saturations taper off for other common appliances which, in general, require less electrical energy to operate. Table 3-17 presents estimated annual kwh use of common household appliances. Water heaters, electric ranges, electric freezers, electric refrigerators, and electric clothes dryers are the largest users of electricity in the home aside from space heating. 3-52 €S-€ Source: 1570 Census of Housing Tints 4s nunber of households with this appliance. The household say have more than one unft. wa w= ' ww » NUMBER OF SELECTED HOUSEHOLD APPLIANCES BY CEN’ 10% 1970 Table 3-15 Number of - Number Number Occupied Number Number Number Number Number Number Number Electric Number Clothes Number Rumer CENSUS Housing = Modern Electric Modern Electric Modern Electric Clothes Clothes Dish- = kashing Number = Television Air DIVISION Units Space Heat Space Heat Water Heat Water Heat: Cooking Fuel Cooking Fuel Oryers Oryers washers Machines Freezers Sets Condizfoners! ANCHOPASE REGION Anchorage 35,021 33,222 2,255 33,476 12,122 34,818 22,586 20,784 18,971 «10,138 22,117 13,682 33,121 278 UTLCENTRAL REGION Corcsva-HeCarthy 563 563 0 509 65 563 292 277 193 6 272 387 8 ¥enai-Cook Inlet 3,931 3,525 140 3,343 1,261 3,780 a7 2,118 1,652 676 «= -2,382, 2,358 2 30 Kodiak 2,535 ° 2,437 21 2,261 556 2,535 1,385 1,692 1,569 326 1,934 1,305- 2,045 37 Matenuska-Susitna , 1,797 1,236 20 1,135 563 1,476 790 853 790 347 850 1,195 1,347 1s Senara 534 510 2 267 165 534 25) 283 197 140 402 381 434 29 Valesz-Chitina-whittier 1,017 802 0 575 205 952 182 356 78 56 310 407 366 0 INTERIOR REGION . . User Yukon 365 134 0 0 0 139 Qo o 0 0 44 99 51 0 Yoxen-Soyskuk 1,030 758 6 500 28 833 363 336 317 38 493 436 sis 7 FAIRSANSS REGION Fairbarks 11,630 8,647 803 8,311 3,915 11,497 9,033" 5,531 $5,413 2,523 6,590 4,677 10,625 184 Southeast Fairbanks "982 8 6 8i5 450 907 579 537 537 168 598 451 667 25 SOUTHEAST REGION . 0 0 0 0 ° 18 0 ° ne ae 4 ay A a 7 206 206 47 250 190 150 ° 4,293 4,250 2 4.215 1,181 4,192 _ 3417 2,465 2,467 1,050 2,549 1,651 3,505 18 wan 2,820 2,809 yoo 2,783 1,872 2,820 2,477 1912 1.812 sis gee 2.209 ei setehthan "e12 412 m 412 346 212 367 305 305 aa 38) a 386 9 of kales 523 509 0 a7 39 493 35 167 B . a Sitka 1,873 1,873 0 1,817 793 1,873 1,119 1,163 1,109 376 Vea) a9 aes 3 Sade Yolen "326 a hy ae 1 a 3 o3 83 as 895 751 $32 33 Srangel}-Petersdurg 1,395 1,346 47 1,206 ™m 1,348 NORTHREST REGION (Rural) 90 15 146 0 rrow 513 513 9 128 9 Age 1 MY 18 Pi 14g 283 43 0 ‘ 955 77 21 184 63 ns 184 3 ne cs 1,238 1,089 22 421 69 1,085 17 156 137 63 187 160 Fi SST REGION : Aleutian Islands 1,192 1,053 68 987 628 1,192 742 aes Le 73 oe rel oe oy Berne} 1,439 1,258 0 284 37 1,177 ues At ie 3 235 ons 0 é Bristol Bay 655 + 589 0 244 23 610 vat 1 bay Borough ‘213 213 0 184 62 213 31 180 a3 2 ue 1 i, aia 401 120 9 58 38 159 s re as 3 18 3 23 0 onpton 773 357 0 45 0 360 TOA ce. @ 79,059 70,375 3,794 66,127 25,669 76,089 46,564 41,492 38,174 «17,314 46,224 «32,685 62,401 800 hS-€ PERCENTAGES CF HOUSEHOLDS WITH SELECTED APPLIANCES - 1970 Table 3-16 Number of Percent Percent census cre percent Percene Percent Percent Percent Percent Percent Electric Percent Clothes Percent DIVISION ais 9 a lodern Electric _Sodern Electric Modern Electric Clothes Clothes Dish- Washing = Percent = Television : pace Heat Space Heat ater Heat ter Heat Cooking Fuel Cooking Fuel Oryers Oryers washers Nachines Freezers Sets a ANCHOSAGE REGION Anchorage 35,021 94.9 6.4 95.6 34.6 99.4 64.5 59.4 54.2 29.0 63.2 39.1 4.6 SOUTHCENTRAL REGION Corsova-MeCarthy 563 100.0 0.0 90.4 1.5 190.0 51.9 49.2 34.3 10.8 48.3 68.7 62.5 Yensi-Cock Inlet + 3,831 90.3 3.6 86.1 . | 93.0 97.4 23.6 54.6 42.8 17.4 61.6 60.8 70.5 Kosick 2,535 96.1 0.8 93.1 21.9 100.0 56.7 66.8 61.9 12.9 78.3 51.5 80.7 1,797 63.8 11 63.2 n.3 82.1 46.0 47.5 48.0 19.3 47.3 66.5 75.0 534 95.5 3.9 87.5 30.9 100.0 47.0 53.0 36.9 26.2 75.3 7e3 90.6 Valsez-Cnitina-whittfer 1,017 78.9 0.0 56.5 20.2 93.6 17.9 35.0 17.5 5.5 30.5 40.0 36.0 INTERIOR REGION Upper Yukon 265 36.7 0.0 0.0 0.0 38.1 0.0 0.0 0.0 0.0 12.1 27.1 14.0 Yukon -Koyukuk 1,030 73.6 5.9 48.5 28.0 81.8 35.2 32.6 30.8 S07 47.9 42.3 50.1 FAIRGANKS REGION Fairpanks 11,630 72.6 6.9 75.8 33.7 98.9 77.7 47.6 46.5 21.7 56.7 38.5 916 Southeast Fairbanks 982 73.1 6.2 €2.9 45.8 92.4 59.0 54.7 54.7 Ww 60.9 45.9 67.9 SOUTHEAST REGICN i i 0. 0.0 0.0 0.0 9.0 15.5 0.0 ia in ub 23 0 1 2.2 yee 48.9 56.9 $6.9 13:0 69.1 52.5 41.4 Juneau 4,293 39.0 0.6 98.2 27.5 97.7 79.6 57.4 57.0 24.2 59.4 38.5 81.6 40.6 78.3 Ketchikan 2,820 99.3 3.5 98.7 6.4 100.0 87.8 64.3 64.3 21.8 63.2 6 8.3 Outer Ketchikan 42 100.0 26.9 100.0 83.5 100.0 89.1 74.0 74.0 W.7 94.9 63.7 88. Prince of wales 528 95.8 0:0 79:0 74 93.4 6.6 3116 13.8 70 (68.8 43.4 (16.3 ; 2 : 59.7 62.1 59.2 20.1 na 48.6 23.0 Stsgeay-Vabutat We 3007 $8 oe 23 33 34.8 33.7 25.3 7.0 40.9 47.1 25.3 rgell-Perersburg «1,365 96.5 3.4 86.5 51.0 96.6 60.9 45.4 45.4 19.6 64.2 53.8 66.8 KORTHSEST REGION (Rural) 4 7.6 21.6 18.1 0.0 17.5 4.6 28.1 ° Konak 98 Sh 2 is:3 ee ae 17.6 19.3 (19.3 4:6 15.6 30.2 “5 Rone 1,233 85.5 1.8 34.0 5.6 87.6 9.5 12.6 nW1 5.1 15.1 12.9 4 SOUTHWEST REGION eae ig gs gga ea EO Bt 2-the| 3 7 § e 5 5 4 fe . fz . 25. . + istol Bay 655 89.9 0.0 37.3 aus 93.1 18.5 18.2 13.2 3.4 34.4 37.9 0.0 82.1 93.4 Bristol Bay Corough 213 100.0 0.0 72.3 29.1 100.0 38.0 84.5 48.4 17.8 56.8 2 Kushokwim 401 29.9 0.0 28.4 9.5 39.7 14.0 14,7 14.7 9.9 aA 2.4 1 Wade-hompton 773 46.2 0.0 5.8 0.0 45.6 6.2 8.9 8.9 : ‘ x ' TOTAL... 79,059 89.0 4.8 83.6 . J 32.5 96.2 58.9 52.5 48.3 21.9 58.5 4.3 78.9 Source: 1970 census of Housing Among the major appliances, electric appliances form only a portion. Electric space heating, for example, had the taxgext intention in the state in 1970 in Fairbanks with 6.9 percent of households. (Outer Ketchikan had 26.9 percent but this is a percentage of a small total and the resuit of housing constructed for the Coast Guard facility at Metlakata,) Electric water heating had the largest saturation in Ketchikan with 66.4 percent of the households (again only exceeded by Outer Ketchikan at 83.5 percent). Electric cooking appliances were chosen by 87.8 percent of households in Ketchikan. (In Outer Ketchikan, the saturation was 89.1 percent.) It appears from the figures from Tables 3-15 through 3-17 that future increases in electric appliance saturation in areas with major utilities will result from two factors. First, for major appliances future growth among existing customers can come from substitutions of electric appliances for gas, oil, and propane appliances. Present low saturations among house- holds with respect to freezers and clothes dryers could account for substantial future growth. Among new households, of course, there will be demand for all major appliances and the choice of type will depend on price and availability. Second, growth in the saturation levels for minor electric appliances among both present and future customers can contribute to average kwh usage increases. But because average kwh usage of these appliances is much less than the major appliances, the impact on average household use of such growth will not be as large. Thus, investigation of recent statistics on residential hookups and appliance stocks in households imply that the historical growth pattern, reflected in the regression analysis, may not hold in the future. There may be an underlying structural change in consumption patterns occurring which 3-55 ‘ Table 3-17 HOUSEHOLD APPLIANCE ELECTRICITY CONSUMPTION Major Appliances Dishwasher Range < oven) Range (self-cleaning) Freezer (15 cu. ft.) Freezer (Frostless, 15) Refrigerator - cu. Tt.) Refrigerator (Frostless, 12) Clothes dryer Water heater Water heater (quick-recovery) Air conditioner (room) Dehumidifier TV (black & white, tube) TV (black & white, solid st.) TV (color, tube) TV (color, solid st.) Other Common Appliances Broiler Coffee maker Deep fryer Frying pan Hot plate Oven (microwave) Roaster Toaster ’ Trash compactor Iron (hand) Wash machine (automatic) Wash machine (nonautomatic) Bed covering Heater (portable) Humidifier Hair dryer Heat lamp (infrared) Radio Clock Sewing machine Vacuum cleaner Toothbrush Source: Electric Energy Association 3-56 Average Wattage 1,201 12,200 12,200 341 440 241 321 4,856 2,475 4,474 860 257 160 55 300 200 1,436 894 1,448 1,196 1,257 1,450 1,333 1,146 400 1,008 512 286 177 1,322 77 381 250 71 75 630 Estimated Annual KWH Use 190 1,175 1,205 1,195 1,761 728 1,217 993 4,219 4,811 860 377 350 120 660 440 100 106 83 186 90 190 205 39 50 144 103 76 147 176 163 14 13 86 7 n 46 1/2 is not reflected in the regression analysis or in analysis of past trends in growth rates of consumption. That structural change may have two components. First, it may be the gradual satisfaction of demand for household hookups and modern appliances and second, it may be a reaction to a higher level of electricity and energy prices. For this reason, several other projections have been constructed. (2) moderate electrification - The moderate electrification projection combines the assumptions of increasing intensification of use per customer with a ceiling on the ratio of new hookups to population growth. All new homes will come equipped with all-electric appliances with the exception of electric space heating. New homes will come equipped with electric space heat in the same ratio as the ratio of electrically space-heated homes among all existing homes. 24 The estimate of annual kwh usage of electricity in electric appliances in the new homes is based upon actual historic use pat- terns in each region. Present households will not increase consumption in this projection. Thus intensive electricity consumption for new customers is combined with constant consumption levels for existing customers. The estimate of electric usage per new customer was done as follows: i) The percentage of existing homes with electric space heating was determined from census data and FPC statistics. ii) This percentage was multiplied by the average heating requirement in kwh for an electrically heated home in each region to obtain the average space heating component of demand by new customers. For Anchorage and Fairbanks, the numbers were obtained from FPC All-Electric Home data while 3-57 for the Southeast and Southcentral regions linear extrapolations were made from the Anchorage-Fairbanks usage using heating degree days in those regions. 414) The estimate of non-space heating electric appliance usage for each new customer was based upon an average kwh usage of all major electric appliances with a factor added for small appliances. The appliances assumed in the all-electric appliance home and their kwh requirements are shown as Table 3-18. TABLE 3-18 All-Electric Home Major Appliances and Electricity Usage Appliance Average kwh Annual Water heater 4,600 Range 1,200 Clothes dryer 1,000 Dishwasher 363 Clothes washer 100 Freezer 1,500 Television 400 Air conditioner 860 Refrigerator 1,000 11,023 Additional kwh for small appliances were added into each region on the basis of the ratio of 1970 kwh residential consumption not allocated to major appliances as determined by Table 3-18 and census data to total residential electricity consumption in the region. For example, based upon Census of Housing appliance data and average consumption of electricity data for those appliances, 84 percent of non-electric space heating electricity consumption in the Anchorage region was accounted frets the appliances listed in Table 3-18. Residential demand not accounted for was 16 percent. Total non-space 3-58 heating requirements per customer were thus calculated for Anchorage as (11,023)/(.84) or 13,122 kwh. The ratio of household electricity hookups to population is assumed to increase from its present level in each region approximately 3 percent and then to remain constant. These constants for each region are shown in Table 3-19, along with the parameters for electricity usage by each new residential customer in each region. Obviously, no set of circumstances would result in present households holding their consumption levels constant and future households purchasing only all-electric appliances in the manner assumed. However, these assumptions are balanced in the sense that present consumers would increase electric consumption if continued moderate electrification occurred, and new consumers would not immediately purchase all the appliances listed in Table 3-18. In sum, the moderate electrification case assumes an atmosphere conducive to increasing electricity use per customer but not an atmosphere in which there is no feasible alternative. This atmosphere could be the result of relative fuel prices conducive to increased use of electricity, limited availability of alternatives, government regulations favoring electricity, etc. 3-59 09-€ Table 3-19 MODERATE RESIDENTIAL ELECTRIFICATION PARAMETERS D Ratio of Major E . A B ; Appliance . F ; : Cc Electric Total Percent of Average . Requirements Electricity Ratio of Existing Home Major to Total 1970 Requirements Electric Region Homes with Heating Appliance Electric Non- of New Hookup Hookups Electric Electric Electric Space Heating (kwh) to Space Heat* Requirements Requirements Requirements {A-B+e) Population (%) (kwh) (kwh) (%) an) (%) ee Anchorage 7 25,000 11,023 : -84 14,872 35 Fairbanks 60 33,000 11,023 +84 32,922 . 32 Southcentral 2 25,000 11,023 ov 16,025 37 Southeast 3 16,000 11,023 87 13,150 27** *The large figure for Fairbanks is reflective of the trend in new housing between 1970 and 1974. For the other regions, the percentage is based on the 1970 Census only. **This saturation level is low because it does not include the communities of Haines, Skagway, or Yakutat. (3) low electrification - The low electrification projection is constructed in essentially the same manner as the moderate electrification case. The only difference between the projections is that low electrification assumes that new customers will acquire major electric appliances in the same ratio as major electric appliances are a portion of total major appliances for present customers. For this purpose space heaters, water heaters, and stoves are the major appliances. All other appliances are electric for new households and as before are purchased immediately. The ratio of consumers to population grows to the same level in this projection as in the moderate electrification case. Table 3-20 presents the parameters used in the low electrification projections. The low electrification case assumes an atmosphere conducive to only limited growth in average household electricity use. New households consume electric appliances for which there are no substitutes in greater numbers than existing households; but when there is a choice of fuels, electricity is chosen by new consumers in the same ratio as existing consumers. This atmosphere could be created by future electricity prices in the same range as alternative fuels, somewhat limited availability of electricity, or government regulations designed to moderate electricity consumption growth. (4) no-growth - The no-growth case is presented to provide a lower bound on possible future levels of residential electricity demand. New households will consume electricity at the same annual level as existing consumers in 1974. The ratio of new electric hookups to new population remains the same as the ratio of existing electric hookups to existing population. Parameters for this projection are shown in Table 3-21. 3-61 29-€ A ; B Percent of Average Region Existing Home Homes with Heating Electric Electric Space Heat* Requirements (%) (kwh) Anchorage 7 25,000 Southcentral 2 25,000 Fairbanks “12.5 33,000 Southeast 3 16,000 Table 3-20 LOW RESIDENTIAL ELECTRIFICATION PARAMETERS G Total Electricity for H Electric CG D E F Appliances Average : Minus electric Percent of Average Percent of Average Major Consumption Existing Water Existing Electric” Electric per New Homes with Heating Homes with Range Appliances Household Electric Electric Electric Electric Electricity,, fiaxs) +(can)e} Water Heat Requirements Range Requirements Consumption j(ExF)+G (%) (kwh) (%) (kwh) (kwh) (kwh) 35 4,600 65 1,200 74323 11,463 34 4,600 39 1,200 9,725 12,257 44 4,600 78 1,200 7,323 14,420 47 4,600 77 1,200 6,870 10,436 ' *The figure for Fairbanks is derived from the 1970 Census in this case. **Total electricity for appliances from Table II. 17, Column Es TABLE 3-21 No-Growth Residential Parameters Ratio of Average ; Electric Hookups 1974 Annual Region to Population Consumption (CRs (kwh) Anchorage 31.1 9,106 Southcentral 32.7 8,026 Fairbanks 28.0 11,597 Southeast 24.9 i 7,623 The no-growth case assumes a very restrictive atmosphere for electricity consumption in the future. This could result from high electricity prices relative to other fuels, dimited availability of electricity, very restrictive energy conservation measures, etc. In all probability, the consumption level of new consumers will exceed that of today's average consumer under all but the most restrictive conditions, so this case is truly a low bound on future consumption levels. b. commercial and industrial projections The commercial and industrial categories are quite heterogeneous since they exhibit both a wider variation in use per customer and a larger variety of uses of electricity than the residential category. Detailed modeling of commercial and industrial is not possible because of data limitations for individual users. Two projection methods are nonetheléss used to bracket the expected level of electricity intensity of use in the commercial and industrial sectors. The first is comparable in method to the growth-as-usual case in the residential 3-63 ( sector and is so named, while the latter is based upon growth assumptions adopted from national averages and is called the minimum growth case. (1) Growth as usual - The number of commercial and industrial cus- tomers and the average consumption per customer were each related to eco- nomic variables by regression analysis. Data by region for the are 1965 to 1973 was used. The number of customers was found to be a function of either employment or of wages and salaries in the region. Employment is a measure of the economic activity of the commercial and industrial sectors of the economy and electricity use is related to the level of this activity. Wages and salaries reflect the level of incomes within the region and form the basis for the level of demand for goods and services provided by the commercial and industrial sectors. In most of the regions, both employment, wages, and salaries are good predictors of the number of customers during the historical period. In addition, linear and log-linear forms of the equations did equally well. Results for the historical period were good. All equations are reported in Appendix C. Average consumption was also assumed to be a function of either the level of employment or of the level of wages and salaries for the same theoretical reasons. Regression results were satisfactory in the Southeast and Anchorage but very little statistical relationship was observed between average consumption and the level of wages and salaries or employment in either the Southcentral or the Fairbanks regions. It may be that in the Southcentral region, the growth in demand resulting from wage and salary increases has been largely satisfied by Anchorage commercial and industrial activity. In the case of Fairbanks, the boom associated with the pipeline has probably caused growth in wages and salaries and employment which is not closely related to levels of electricity demanded by commercial and 3-64 industrial customers. Nonetheless, it is expected that electricity demand will be related to the level of economic activity in the long run in these regions and so regressions projecting average consumption in the South- central and Fairbanks regions included these explanatory variables. Future projections of demand using the historic relationships result in very rapid continued growth in both the numbers of commercial and industrial customers and in average consumption per customer. Between 1960 and 1972, the number of commercial and industrial customers of the large utilities in the state increased at an annual average of 5.0 percent from 5,960 to 10,699. At the same time, average consumption was increasing at an annual 22 Continued growth at 6.4 percent rate from 21,477 kwh to 45,425 kwh. these levels even with low energy prices may not occur because some of the historic growth may have been Alaska "catching up" to the electricity use- economic activity ratios in other parts of the country. (2) Minimum electrification - A second projection method was developed to reflect the effect of an atmosphere less conducive to growth in commercial and industrial electricity. This atmosphere would likely be the result of higher electricity prices as well as a leveling off in growth of use because of saturation points being reached in both new customer hookups and use per customer. The growth in the number of customers using this projection method occurs at the same ratio between number of customers and population as was observed in 1974 in each region. Consumption per customer continues to grow in the future at the growth rate observed nationally for the period 1962 3-65 to 1972. This was 5.8 percent per annun. 23 This is definitely not the most restrictive set of assumptions possible for consumption, but it does signifi- cantly reduce growth in commercial and industrial demand, compared, to growth as usual. Other projections could be constructed to reflect different growth assumptions. Since the data is not available to substantiate any such exercise, it is assumed these two cases will bracket the actual range. ce Other - This final category of demand consists of the most diverse group of consumers, including public buildings, street lighting, and electricity use by utilities. It is a small heterogeneous category which generally grows with growth of the economy. Projections of the growth in other demand are based on regressions relating this category of demand to employment or population growth. The statistical relationships are high in all four regions, and the equations are presented in an appendix. Alternative projection methods were not done for this category because it is relatively small and its level is probably not as sensitive to price changes as the other demand categories. d. Total consumption in Northwest and Southwest regions Lack of data prohibited the division of consumption by category of consumer in the Northwest and Southwest regions, so total consumption was projected as a unit. Regression analysis was done to relate total demand to the level of economic activity in each region. The resulting equation for the Southwest showed a strong statistical relationship of consumption to both civilian population, wages and salaries. In the Northwest, only 3-66 population was statistically related to electricity consumption, and the relationship was not strong. These equations are reported in Appendix B. As with the other projections using historical relationships, growth in these regions is quite rapid in this growth-as-usual case. projection method using the present ratio’ of consumers to population and present average consumption was constructed to provide a no-growth alternative. The parameters in this projection are as follows: TABLE 3-22 No-Growth Parameters in Total Electricity Projections Customer Average Region Population Annual Ratio Consumption* (4) (kwh) Rural Northwest 9.8 11,766 Southwest 7.2 9,955 * This number is commercial and relatively large because it includes industrial consumption. The customer/population ratio in these regions is very low because the major utilities are serving only a small portion of the scattered population. No growth assumes that the service areas of the utilities will not grow rela- tive to the population in the region. 3-67 An alternative D. Future Demand Projections In this section, the economic growth assumptions for the state are combined with the intensity of electricity use assumptions to produce several estimates of future regional electricity demands. Several things must be kept in mind while analyzing these projections. First, none of the projections can be considered the most likely alternative. Typically, in years past both within Alaska and nationally, projections of electricity demand did very well by merely assuming a con- tinuation of past trends. This is not adequate for the Alaskan case for two reasons. The real price of electricity relative to other goods has in recent years reversed its historic downward trend and can be expected to continue rising relative to other prices for several years. Thus, consumption patterns based upon low prices may not continue in periods of high prices. In addition, the economy of Alaska is small but growing rapidly, thus making the task of projecting the economic growth of the state very difficult. Economic developments which could be absorbed in large states without appreciably affecting the rate of economic growth have much more impact on the Alaskan econoay because of its size. The narrow base of the economy, centered upon natural resources, makes this particularly difficult, because the diversification of larger states or regions partially protects them from either stagnation or very rapid growth. Growth in more diversified regions is smooth and continuous, but growth in Alaska has been and will continue to be discontinuous. Therefore, each projection is a possible outcome, but none is the most likely to occur. The projections provide a range of values to be guides to 3-68 planning the future but cannot be accurately ordered by probability of occurrence. Second, the projections are for growth of demand in the long run. The MAP econometric model of the state is a long-run model, not designed or equipped to detect every short-run change in every region of the state to particular circumstances. It is designed to present a consistent picture of the development of the state over a long period of time, based upon those forces assumed to be most important in shaping long-run growth. All major projects which might occur and significantly impact economic development have not been included because to be thorough, a projection would need to be performed both including and excluding each project. Sucha multiplicity of projections would result in a large amount of data of questionable value to this study. The economic projections presented here are felt to fairly represent the more reasonable bounds on future growth. Finally, not all utilities in each region are included because their data is either not available, or is not available in a compatible format. The most notable omissions are Barrow, Haines, and Skagway. Many smaller utilities do not report to the Federal Power Commission, and only sporadically report to the Alaska Public Utilities Commission. AVEC utilities are in a separate section of this report. All results are in terms of final consumption, not to be confused with estimates of generation which include sales to other utilities and system losses. Projections of capacity requirements are included based upon load factors analyzed in an appendix and regional system losses. 3-69 The four intensity-of-electricity-use assumptions for residential consumption can be combined with the two different cases for commercial and industrial consumption to form eight cases overall. Of these, four were chosen for inclusion here. Case 1 combines the growth-as-usual assumptions in both the residential and the commercial-industrial categories. Case 2 combines moderate electri- fication for residential electricity use with growth as usual commercial- industrial, Case 3 combines low electrification residential electricity use with minimum electrification commercial-industrial. Finally, Case 4 combines no growth residential electricity consumption with minimum electrification commercial-industrial. At Anchorage Anchorage is projected to have the highest levels of electricity growth in the state in the long run. The growth rates for the 1974-1995 period range from a low of 9.4 percent to a high of 14.7 percent, with higher growth rates in the early years, but growth in excess of 9 percent continuing through the second decade of the projections. These results are presented in Table 3-23. The rate of growth is not very sensitive to differences in economic growth except during the early 1980s when petroleum developments in the northern part of the state induce accelerated growth in Anchorage. By 1995, however, the resulting differences in demand in the limited and accelerated economic growth cases are huge, particularly in Case l. As in the Southcentral region, Case 1 results in unrealistic increases in both residential hookup saturations and average annual consumption. 3-70 Hookups rise to a 42 percent ratio to population and average consumption in- creases to 30,704 kwh in the accelerated economic growth case. This is shown in Table 3-24. Comparable figures for 1974 were 31.1 percent and 9,106 kwh. For the reasons previously mentioned, primarily rising relative energy prices and existing appliance electricity consumption, such use levels appear unrealistic. In 1973, tis uate all-electric home in Anchorage con- sumed 32,396 kwh. Residential growth as usual thus implies essentially an all-electric residential sector with electricity levels comparable to pre- sent all-electric homes by 1995. Any significant growth in the intensity of use of electricity will result in near term growth in the 12-16 percent annual range. As in the Southcentral region, the choice of projection depends upon the expected price of electricity relative to natural gas and fuel oil. In Anchorage, there is a real substi- tution possibility between fuels, and since population is rapidly expanding, demand projections will depend heavily upon both the electricity price and the price and availability of natural gas. Clearly, however, demand in Anchorage is going to continue at or near historic rates for most of the projection period. Sal 2l-€ Electricity Intensity Scenario Economic Scenario QYPE SSS 1974 (Actual) | 1980 1985 1990 1995 1974-80 1980-85 1985-90 1990-95 | \ i Table 3-23 PROJECTED NET SALES OF ELECTRIC UTILITIES TO FINAL CONSUMERS (Thousand MWH) Anchorage Case 1 Case 2 Case 3 Case 4 Moderate Residential Low Residential Growth As Electrification Electrification Minimum Usual Commercial/Industrial Commercial/Industrial Growth } \ Growth As Usual Minimum Electrification Limited Accelerated Limited Accelerated Limited Accelerated Limited Accelerated Growth Growth Growth Growth Growth Growth Growth Growth SS ee a Sess BESS ee 2 Se 867.132 867.132 867.132 867.132 867.132 867.132 867.132 867.132 i 2,124 2,286 ' 2,012 2,147 1,664 1,723 1,529 1,580 3,734 4,822 3,245 4,076 2,550 2,924 2,347 2,679 1 6,326 8,637 5,096 6,749 3,910 4,628 3,625 4,273 10,633 15,350 7,982 11,154 6,071 7,416 5,679 6,918 | AVERAGE ANNUAL GROWTH RATES (%) 16.1 17.5 151 16.3 115 14.1 9.9 10.5 12.0 16.1 10.0 iF 8.9 Tz 8.9 Th.? Tito 12.4 | 9.4 10.6 8.9 9.6 9.1 9.8 10.9 12.2 9.4 10.6 9.2 9.9 9.4 "| Ges _— €L-€ Table 3-23 Continued PROJECTED ELECTRICITY PEAK DEMAND (MW) Anchorage rn ee Case 1 Case 2 Case 3 Case 4 Moderate Residential Low Residential Electricity Growth As Electrification Electrification Minimum Intensity Usual Commercial/Industrial Commercial/Industrial Growth Scenario Growth As Usual Minimum Electrification Economic Limited Accelerated Limited Accelerated Limited Accelerated Limited Accelerated _ Scenario Growth Growth Growth Growth Growth Growth Growth Growth tee —— end 1974 198.6 198.6 | 198.6 198.6 198.6 198.6 198.6 198.6 1980 486.4 523.5 460.7 491.7 381.1 394.6 350.1 361.8 1985 855.1 1,104.2 743.1 933.4 584.0 669.6 537.5 613.5 1990 1,448.7 1,977.9 1,167.0 ~* 1,545.5 895.4 1,059.8 830.1 “978.5 1995 2,435.0 3,515.2 — 1,827.9 2,554.3 1,390.3 1,698.3 1,300.5 1,584.2 a fe ee Assumptions: oad factor = .55 ; system losses = 10.4% qL-€ Table 3-24 PROJECTED RESIDENTIAL CONSUMPTION PARAMETERS Anchorage a A ee Electricity Moderate Low Intensity Growth As Usual Electrification Electrification Scenario tt Ba Economic Limited Accelerated ; Limited Accelerated Limited Accelerated Scenario Growth Growth Growth Growth Growth Growth hookup kwh/ hookup kwh/ hookup kwh/ hookup kwh/ hookup kwh/ hookup kwh/ “saturation consumer | saturation consumer | saturation consumer | saturation consumer | saturation consumer | saturation consumer 1974 31.1% 9,106 31.1% 9,106 31.1% 9,106 31.1% 9,106 31.1% 9,106 31.1% 9,106 1980 35.8 12,614 36.1 12,931 35.0 11,317 35.0 11,425 35.0 10,010 35.0 10,054 1985 38.1 16,073 39.1 ~ 17,605 35.0 12,102 35.0 12,439 35.0 10,331 35.0 10,469 1990 39.9 20,505 40.9 23,090 35.0 12,695 35.0 13,023 35.0 10,573 35.0 10,707 1995 41.3 26,498 42.2 30,704 35.0 13,162 35.0 13,466 35.0 10,794 35.0 10,888 eee Note: consumption per customer and is, therefore, omitted. Hookup saturation is defined as residential customers/civilian population. fd The no growth case assumes no change over time in either hookup saturation or average KWH 2 Southcentral Very rapid growth is projected for the Southcentral region in the near future under all alternatives. Limited economic growth combined with no growth in intensity of electricity use results in 10 percent annual growth between 1974 and 1980. Accelerated economic growth combined with growth as usual in intensity of electricity use results in an annual growth rate of nearly 22 percent over the period to 1980. After 1980,growth slows consider- ably in all cases, because economic growth slows as development of Gulf of Alaska petroleum potential phases out. In the last years of the projection period, growth under the various scenarios is reduced to between 4.3 percent and 6.2 percent. These results are presented in Table 3-25. Growth rates for the entire projection period range from 7.6 percent in the limited economic growth Case 4 to 11.5 percent in the accelerated econo- mic growth Case l. Table 3-26 presents the implications of the various projections for residential electricity use. In the fastest-growing case, residential hookup saturation exceeds 42 percent in 1995. This seems very unlikely based upon the present 32.7 percent level, present family patterns, and national saturation statistics. Second homes would increase the percentage, but would reduce average use per consumer, which is projected to increase to 24,477 kwh by 1995. Again, compared to present use at 8,026 kwh and electric appliance annual requirements, the projected figure seems unlikely. | Thus, the Case 2 to Case 4 projections seem the more reasonable. The Sail gL-€ Table 3-25 PROJECTED NET SALES OF ELECTRIC UTILITIES* TO FINAL CONSUMERS (Thousand MWH) 5 , \ Case 1 Case 2 Case 3 Case 4 : Moderate Residential Low Residential Electricity Growth As Electrification Electrification Minimum Intensity Usual Commercial/Industrial Commercial/Industrial Growth Scenario | Growth As Usual Minimum Electrification Pe Re oes eee POUR aie ese cere RUA UUM esac Economic Limited Accelerated Limited Accelerated Limited Accelerated Limited Accelerated Scenario |, Growth Growth j Growth Growth Growth Growth Growth i ee ee =o sosor wees a 1974 (Actual) i 282.417 282.417 f 282.417 282.417 282.417 282.417 282.417 282.417 ; \ 1980 \ 762 933 717 849 563 612 503 544 1985 11,302 1,701 1,131 1,432 835 966 748 857 1990 ; 1,659 2,178 1,390 1,774 1,087 1,267 987 1,142 1995 (2,114 2,791 1,716 2,205 1,436 1,686 1,323 1,545 AVERAGE ANNUAL GROWTH RATES {%) 1974-80 h 18.0 21.9 16.8 20.0 12.2 13.6 10.1 11.4 1980-85 11.3 12.8 9.6 11.0 8.2 9.6 8.2 9.5 1985-90 | 5.0 5.1 4.2 4.4 5.4 5.6 5.7 5.9 1990-95 5.0 5.1 4.3 4.4 5.7 5.9 6.0 6.2 i *Includes Cordova, Glennallen, Homer, Kenai, Talkeetna, and Valdez. Kodiak, Palmer, Seldovia, Seward, LI=E Electricity Intensity Scenario eee an eet Economic Scenario 1974 1980 1985 1990 1995 Table 3-25 Conti nued PROJECTED ELECTRICITY PEAK DEMAND (MW) Case 1 Southcentral Case 2 Moderate Residential Case 3 Low Residential Assumptions : load factor = .56 system losses = 7.4% Case 4 Growth As Electrification Electrification Minimum Usual Commercial/Industrial Commercial/Industrial Growth Growth As Usual Minimum Electrification Limited Accelerated Limited Accelerated Limited Accelerated Limited Accelerated Growth Growth Growth Growth Growth Growth Growth Growth a a 61.8 61.8 61.8 61.8 61.8 61.8 61.8 61.8 166.9 204.3 157.0 185.9 23a) 134.0 110.2 119.1 285.1 372.5 247.7 313.6 182.9 211.6 163.8 187.7 363.3 477.0 304.4 388.5 238.1 277.5 216.2 250.1 463.0 611.2 375.8 482.9 314.5 369.2 | 289.7 338.4 | FPP [eee ee a QL-E Table 3-26 PROJECTED RESIDENTIAL CONSUMPTION PARAMETERS Southcentral Electricity Moderate Low : Intensity Growth As Usual Electrification Electrification Scenario . y Se ee Economic Limited Accelerated Limited Accelerated Limited ~ Accelerated Scenario Growth Growth Growth Growth Growth Growth 1974 1980 1985 1990 1995 t it kwh/ “saturation consumer hookup hookup kwh/ saturation consumer hookup kwh/ saturation consumer ——— _ hookup kwh/ saturation consumer hookup kwh/ saturation consumer ft hookup kwh/ saturation consumer 32.7% 8,026 37.4 12,896 40.0 16,771 40.8 18,961 42.1 21,448 32.7% 8,026 38.3 14,240 40.1 19,050 41.2 21,589 42.3 24,477 32.7% 8,026 37.0 11,076 37.0 11,999 37.0 12,304 37.0 12,585 32.7% 8,026 37.0 11,422 37.0 12,502 37.0 12,801 37.0 13,075 32.7% 8,026 37.0 9,639 37.0 10,127 37.0 10,289 37.0 10,438 Note: The no growth case assumes no change over time in either hookup saturation or average KWH consumption per customer and is, therefore, omitted. Hookup saturation is defined as residential customers/civilian population. 32.7% 8,026 37.0 9,822 37.0 10,394 37.0 10,552 37.0 10,696 Case 2 commercial/industrial demand is based upon growth-as-usual assumptions, while the other two cases are based upon more moderate rates of growth in use. By 1995 there is little difference in average commercial/industrial use between the two cases; but in the interim period, growth-as-usual assumptions result in much larger average customer use than minimum electrifi- cation commercial/industrial assumptions. Which projection is more likely depends largely upon the relative prices of Sueke in the near future when most of the rapid economic growth is projected to occur. Electricity will be in a strong competitive position in the region as a whole and, therefore, growth somewhere between Case 2 and Case 3 seems likely for Southcentral. 3. Fairbanks Future electricity demand in Fairbanks is relatively insensitive to the assumptions made regarding the idemimcie. growth of the state. Only during the early 1980s does economic growth spurt in this region as an adjunct to development of petroleum in Naval Petroleum Reserve #4 and adjacent areas. Fairbanks projections are presented in Table 3-27. The rate of growth tends to taper off during the projection period in all cases except 4 where it remains relatively constant and strong through 1995. In the near future, the projections indicate large variability in the annual growth rate depending upon intensity of electricity use. The differences in assumptions among the intensity of electricity use scenarios are more pronounced for the Fairbanks residential sector than in other regions. In particular, the moderate electrification case assumes that new residential consumers will choose electric space heating approximately 60 percent of the time while the low electrification figure is 12.5. The use of 60 percent was based upon data on recent consumption patterns in Fairbanks. Sa) 08-€ Table 3-27 PROJECTED NET SALES OF ELECTRIC UTILITIES TO FINAL CONSUMERS (Thousand MWH) Fairbanks Case 1 Case 2 Case 3 Case 4 f Moderate Residential Low Residential | Electricity Growth As Electrification Electrification Minimum Intensity tl Usual Commercial/Industrial Commercial/Industrial Growth Scenario f | Growth As Usual | Minimum Electrification — Economic Limited Accelerated Limited Accelerated Limited Accelerated Limited Accelerated Scenario Growth Growth | Growth Growth Growth Growth Growth Growth ————EEEEE SEE FLEETS SSS SS SS SSE SSS SSS SS = 1974 (Actual) j 318.751 318.751 318.751 318.751 318.751 318.751 318.751 318.751 1980 ; 631 658 598 616 485 495 446 455 q 1 1985 . | 1,032 1,244 833 950 650 727 602 669 1990 1 1,534 1,891 * 1,090 1,256 861 977 803 907 ! 1995 2,247 2,834 1,410 1,640 {| 1,157 1,334 1,088 1,250 AVERAGE ANNUAL GROWTH RATES (%) 1974-80 12.0 12.8 ald i1.6 72 7.9 5.8 6.1 1980-85 10.3 13.6 | 6.8- 9.1 6.0 8.0 6.2 8.0 H i 1985-90 8.3 8.7 5.5 5.7 5.8 6.1 5.9 6.3 1990-95 7.9 8.4 5.3 §.5 6.1 6.4 6.3 it | 6x6 e e @ @ e L8-€ | | Electricity Intensity Scenario Economic Scenario 1974 1980 1985 1990 1995 Limite Growth 76.2 150.8 246.6 366.6 537.0 Case 1 Growth As Usual d Accelerated Growth 76.2 157.3 297.3 451.9 wv » Table 3-27 Continued PROJECTED ELECTRICITY PEAK DEMAND (MW) Fairbanks Case 2 Case 3 Case 4 Moderate Residential Low Residential Electrification Electrification Minimum Commercial/Industrial Commercial/Industrial Growth Growth As Usual Minimum Electrification Limited Accelerated Limited Accelerated Limited Accelerated Growth Growth Growth Growth Growth Growth | nett EE 76.2 76.2 76.2 76.2 76.2 76.2 ' 142.9 147.2 115.9 118.3 106.6 108.7 199.1 227.1 155.4 173.8 143.9 159.9 260.5 300.2 205.8 233.5 191.9 216.8 337.0 392.0 276.5 318.8 260.0 298.8 677.3 Assumptions: load factor = .53 system losses = 11.0% In addition, the assumption that such a large percentage of the residential heating market would choose electricity is consistent with a conscious plan to help ameliorate the problem of icefog in the Fairbanks area. All-electric space heating, in conjunction with generation of electricity outside the Fairbanks area, might reduce the icefog problem, It is not clear how much improvement would result from this measure, because the primary contributors to the icefog buildup appear to be electric utility cooling water and the products of internal combustion in sutotutten. The moderate electrification case implies much higher demand projections than the low electrification and no-growth cases; but surprisingly, it is significantly below the growth-as-usual case. As indicated in Table 3-28, annual average residential consumption per household increases very rapidly in the growth-as-usual case, going from 11,597 kwh in 1974 to between 44,585 kwh and 52,006 kwh by 1995. In 1973, the average all-electric home in er consumed 40,081 kwh. Thus, the growth-as-usual residential electricity case implies that all of residential Fairbanks will have all- electric facilities at some time between 1990 and 1995. In addition, this case implies that hookup saturation increases from 28 percent in 1974 to 40 percent by 1995. For the reasons outlined under the Anchorage section, such a high hookup saturation seems unlikely. Cases 2 and 3 appear to be more reasonable projections and as in other regions, the choice between them is dependent upon the choice of competing fuels and their availability. In this region in particular, the importance of fuel price in determining the level of future projections is highlighted by the differences between Case 2 and Case 3. Recent historic growth of electricity use in Fairbanks has been in excess of 14 percent, the most rapid in the state. Long-run future growth in the region will be much lower. Twenty-year projections range between 6.0 percent and 11.0 percent, while the 10-year projections are somewhat more spread out between 5.9 percent and 13.2 percent. 3-82A €8-€ Table 3-28 PROJECTED RESIDENTIAL CONSUMPTION PARAMETERS Fairbanks Electricity Intensity Scenario Economic Scenario a Growth As Usual Limited Growth Accelerated Growth Moderate Electrification Limited Growth Accelerated Growth Low Electrification Limited Accelerated Growth Growth $$ hookup kwh/ hookup ° kwh/ hookup kwh/ hookup kwh/ hookup kwh/ hookup kwh/ “saturation consumer | saturation consumer | saturation consumer | saturation consumer | saturation consumer | saturation consumer =—— —. 1974 28.0% 11,597 28.0% 11,597 28.0% 11,597 . 28.0% 11,5977 28.0% 11,597 28.0% 11,597 1980 31.5 19,112 31.8 19,797 32.0 16,987 32.0 17,235 32.0 12,310 32.0 12,343 1985 34.3 26,816 34.9 30,735 $2.0 | .18,9§2 32.0 20,278 32.0 12,509 32.0 12,746 1990 36.9 34,801 3763 40,223 32.0 20,324 32.0 21,723 32.0 12,752 32.0 12,937 1995 39.6 44,585 40.0 52,006 32.0 21,561 32.0 23,002 32.0 12,916 32.0 13,107 Note: The no-growth case assumes no change over time in either hookup saturation or average KWH consumption per customer and is, therefore, omitted. Hookup saturation is defined as residential customers/civilian population. he Southeast The Southeast is the most stable of the regions, in that growth in electricity demand shows the least sensitivity to variations in growth of the economy and in intensity of electricity use. Projecting to 1995, the variation in the long-run growth rate is only between 5.3 percent and 6.6 percent. Projections for the Southeast are presented in Tables 3-29 and 3-30. In the other three regions where Cases 1-4 were examined, moving from Case 1 to Case 4 consistently reduced electricity demand. First, the assumption of minimum growth in the commercial/industrial category (with a constant ratio of consumers to population and following the national average growth rate in consumption per customer of 5.8 percent) resulted in higher growth than the growth-as-usual case although the opposite result occurred in all other regions. Second, the growth-as-usual assumptions for residential demand do not result in the highest level of residential demand until after 1990.234 ‘This anomaly underscores the fact that growth of demand in the Southeast has been relatively slow during the historical period, and assumptions which cause projections to be moderated in the Southcentral, Anchorage, and Fairbanks regions cause projections in the Southeast to increase more rapidly. The impact of accelerated economic growth on the Southeast is largely indirect and occurs through increased: government spending. The difference between the limited and accelerated cases is not large, however. At the same time, changing the assumptions regarding the intensity of electrification 3-84 does not have a very significant impact on the results. The largest variation in growth rates occurs in the 1974-1980 period where a low of 7.2 percent is calculated in Case 4 and a high of 8.7 percent in Case 2. The closely-ranged short-run estimates, centering about 7-8 percent and tapering off to 4-6 percent, are based upon the capital remaining in Juneau and the continued growth of the state government. A separate report for this study done by Homan and McDowell Associates analyzes the impact on electri- city demand in the Southeast of the capital move and other possible large impact projects. In general, however, electricity demand is the most stable and predictable in the Southeastern region of the state. 3-85 .98-€ Electricity Intensity Scenario Economic Scenario } —SEEeee SS 1974 (Actual) | 1980 1985 1990 1995 | 1974-80 1980-85 1985-90 1990-95 tt - = ‘ wv 7 Table 3-29 PROJECTED NET SALES OF ELECTRIC UTILITIES * TO FINAL CONSUMERS (Thousand MWH) Southeast Case 1 Case 2 Case 3 Case 4 Moderate Residential Low Residential Growth As Electrification Electrification Minimum Usual Commercial/Industrial Commercial/Industrial Growth Growth As Usual | Minimum Electrification ikidgeep ieee belts -stildtiliedaelaneinameieasigeneatia kaeomecceganeied Limited Accelerated Limited Accelerated Limited Accelerated Limited Accelerated Growth Growth Growth Growth Growth Growth | Growth Growth 215.088 215.088 |' 215.088 215.088 215.088 215.088 215.088 215.088 328 338 344 355 340 350 318 326 432 487 443 505 449 502 417 465 529 611 527 617 561 639 523 594 656 777 634 763 713 827 667 768 AVERAGE ANNUAL GROWTH RATES (%) 7.3 a. 8.1 8.7 7.9 8.4 6.7 cae 5a7, 7.6 Bia 7.8 §.7 7.8 5.6 Vell 4.1 4.6 3.6 4.4 4.6 5.2 4.6 Sia 4.4 4.9 3.7 4.6 4.9 5.5 ep aU *Includes Juneau, Ketchikan, Metlakatla, Petersburg, Sitka, and Wrangell. L8-€ Table 3-29 Continued PROJECTED ELECTRICITY PEAK DEMAND (MW) Southeast -eRRhae—eeeee—e—eee——n e esanwXn$~—OOO Case 1 Case 2 ‘Case 3 Case 4 Moderate Residential Low Residential Electricity Growth As Electrification Electrification Minimum Intensity Usual Commercial/Industrial Commercial/Industrial Growth Scenario Growth As Usual Minimum Electrification Economic Limited Accelerated Limited Accelerated Limited Accelerated Limited Accelerated Scenario Growth Growth ' Growth Growth Growth Growth Growth Growth 1974 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 1980 73.1 75.4 76.7 79.2 75.8 78.1 70.9 72.7 1985 96.3 108.6 98.8 112.6 100.1 111.9 93.0 103.7 1990 "118.0 136.3 117.6 137.6 125.1 142.5 116.6 132.5 1995 146.3 173.3 141.4 170.1 159.0 184.4 148.7 171.3 a pet Assumptions: load factor = .56 system losses = 9.2% 88-€ Southeast eee | aa Electricity Moderate Intensity Growth As Usual Electrification Scenario ' ee! Economic Limited Accelerated Limited Accelerated Scenario Growth Growth Growth Growth hookup kewh/ ! Table 3-30 PROJECTED RESIDENTIAL CONSUMPTION PARAMETERS hookup ~ kwh/ hookup kwh/ Saturation consumer _ hookup kwh/ saturation consumer $e Low Electrification Limited Growth J 8 hookup kwh/ saturation consumer Accelerated Growth hookup kwh/ saturation consumer ‘saturation consumer | saturation consumer 1974 1980 1985 1990 1995 Note: 24.9% 7,623 25.9 8,520 26.9 9,181 27.9 9,776 29.1 10,435 24.9% 7,623 25.9 8,555 26.7 - 9,226 27.7 «9,818 28.8 10,472 24.9% 7,623 27.0 9,137 27.0 9,690 27.0 10,008 27.0 10,296 consumption per customer and is, therefore, omitted. 24.9% 7,623 27.0 9,232 27.0 10,009 27.0 10,340 27.0 10,635 Hookup saturation is defined as residential customers/civilian population. 24.9% 7,623 27.0 8,394 27.0 8,675 27.0 8,837 27.0 8,983 Ss The no growth case assumes no change over time in either hookup saturation or average KWH 24.9% 7,623 27.0 8,422 27.0 8,808 27.0 8,972 27.0 9,118 Die Rural Northwest. Projections for the Northwest are very imprecise because of not only the lack of data, but also because future growth in demand may be quite different from past trends. This may be more the result of changes in income and local government structure than of relative increases in electricity prices. Table 3-31 gives projected sales to final customers under two sets of assumptions concerning electrification combined with the two economic growth scenarios. (This is because data limitations in the Northwest and Southwest do not allow identification of types of customers.) Accelerated economic growth has a significant impact on electricity use because this scenario includes development of Naval Petroleum Reserve #4 within the region which begins in 1980 and tapers off after 1985. Growth as usual in the intensity of electricity use results in significantly higher total electricity demand than the limited electrification and for the Northwest, this is probably a reasonable assumption. Barrow is not included in the projections and it has much smaller annual average residential kwh sales than the other communities in the region (Table 3-7). This imbalance may imply more rapid growth in Barrow in the future, thus increasing the growth rate for the region as a whole. The short-term growth rates which range from 5 percent to 8 percent and then taper off after the development phase of Pet #4 are thug tmprectse. Growth of economic activity and electricity use are both difficult to project in the Northwest. 3-89 06- ¢€ wv w = = vw v - - Table 3-31 PROJECTED NET SALES OF ELECTRIC UTILITIES* TO FINAL CONSUMERS (Thousand MWH) ; Northwest Case 1 ae Case 2 Case 3 | Case 4 Moderate Residential Low Residential Electricity Growth As Electrification Electrification Minimum Intensity Usual Commercial/Industrial Commercial/Industrial Growth » Scenario i Growth As Usual Minimum Electrification : 1 Ls iniaibiabecilaiannedmerayieernns Economic ~ Economic | Limited Accelerated |! Limited Accelerated Limited Accelerated Limited Accelerated Scenario j, Growth Growth | Growth Growth Growth Growth Growth ere) th ee nero a ae aie al cae : 1974 (Actual) j 15.178 15. 178 : { 15.178 15.178 1980 | 20 24 7 18 1985 24 34 \ q i 7 21 1990 i 27 36 H - 19 22 1995 0 37 : 20 . 23 | AVERAGE ANNUAL GROWTH RATES (%) 1974-80 ) 8.1 1.7 2.9 1980-85 3.7 Tee 0.7 3.4 1985-90 2.3 1.1 1.8 0.6 1990-95 2.2 0.3 1.0 ’ 0.6 t mr ee! *Includes utilities at Kotzebue, Nome, and Unalakleet. L6-€ Table 3-31 Continued PROJECTED ELECTRICITY PEAK DEMAND (MW) Northwest Pee oa ae ee eh oe La Te ee a mie mm te etn ee a a eae Case 1 Case 2 Case 3 Case. 4 Moderate Residential Low Residential Electricity Growth As Electrification Electrification Minimum Intensity Usual Commercial/Industrial Commercial/Industrial Growth Scenario i ° Growth As Usual Minimum Electrification Economic Limited Accelerated Limited Accelerated Limited Accelerated Limited Accelerated . Scenario Growth Growth Growth Growth Growth Growth Growth Growth Te ee hen eT ee ee eee 1974 3.6 3.6 3.6 3.6 1980 4.8 5.7 4.0 4.3 1985 $.7 8.1 4.0 5.0 1990 6.4 8.6 4.5 5.2 1995 a 8.8 4.8 §.§ Assumptions: load factor = .53 system losses = 10.5% a a Lee «= a a Southwest. In the Southwestern region of the state, projected electricity sales are very sensitive to the intensity of use but not to the overall growth of the economy of the state. Results of four projections are presented in Table 3-32. The industries which form the basis of the economy in the South- west are not projected to grow significantly in either the limited or ac- celerated economic growth cases. If the intensity of electricity use does not increase, growth rates are projected to be in the range of 1-3 percent throughout the projection period. If the intensity of use increases in the future as in the past, short-term growth rates will be much higher, between 7 and 12 percent annually. Historical growth rates have varied considerably within the region -- from 1 suey in McGrath to 21 percent in Bethel (Table 3-3, page 8). Annual average sales per residential customer show considerable variation among utilities, but the regional average for 1974 of 3,857 kwh was less than half of the state average of 8,860 kwh. The Case 1 projections may be more reasonable for the region, although the continued rapid growth in the Bethel utility, largest in the region, is not likely to occur at historic rates unless it undertakes a significant service area expansion. 3-92 €6-€ Electricity Intensity Scenario Economic Scenario == 1980 1985 1990 1995 1974-80 1980-85 1985-90 1990-95 i! i Table 3-32 PROJECTED NET SALES OF ELECTRIC UTILITIES* TO FINAL CONSUMERS (Thousand MWH) Southwest 2. Case 3 | Case 4 A Case 1 Moderate Residential Low Residential Growth As Electrification Electrification Minimum Usual Commercial/Industrial Commercial/Industrial Growth Growth As Usual Minimum Electrification ee nereenaeel eet Nee ee eee Limited Accelerated Limited Accelerated Limited Accelerated Limited Accelerated Growth Growth ; Growth Growth Growth | Growth | | Growth Growth 16.615 16.615 rat 16.615 16.615 28 30 18 18 40 52 19 21 51 69 20 23 63 90 22 25 AVERAGE ANNUAL GROWTH RATES (%) 9.3 10.0 1.3 1.4 { 7.0 11.8 1.4 2.8 5.0 6.1 1.2 1.8 | 4.5 5.4 1.2 = 18 | *Includes utilities at Bethel, McGrath, Naknek, Nushagak. 6-E Table 3-32 Continued PROJECTED ELECTRICITY PEAK DEMAND (MW) Southwest ee Case 1 Case 2 Case 3 Case 4 Moderate Residential Low Residential Electricity Growth As ; Electrification Electrification Minimum Intensity Usual Commercial/Industrial Commercial/Industrial Growth Scenario Growth As Usual Minimum Electrification Economic Limited Accelerated |' Limited Accelerated Limited Accelerated Limited Accelerated Scenario Growth Growth Growth Growth Growth Growth Growth Growth laadecipdenieaeasaibisaaas Msaaaladtaiint ndeabiaaiceaiaenmmpedeepeepenaeeetas aea2 1974 4.1 4.1 4.1 4.1 1980 120 we 4.5 4.5 1985 10.0 12.9 4.7 5.2 1990 12.7 lize 5.0 5.7 1995 15.7 22.4 5.5 6.2 - + ee Assumptions: load factor = .51 system losses = 11.6% 7. Statewide Summary Under a variety of assumptions regarding the growth of the economy and a variety of assumptions regarding the intensity of electricity use, electricity demand is projected to increase at a very rapid pace for the next 20 years. Table 3-33 summarizes statewide growth under four sets of conditions. The highest and lowest projections in each region under both limited and accelerated economic growth assumptions are combined to get statewide totals. Except for the Southeast region, highest growth cor- responds to the growth as usual scenario which projects past relationships between electricity demand and economic variables. Lowest growth cor- responds to no increase in intensity of use. In all cases, growth tapers off as the projection period proceeds; but in addition, the long-run growth rate exceeds the historical rate for the U.S. as a whole. In the short run, growth rates are much higher and in one case exceed 16 percent, which implies a doubling of demand in less than 5 years. The overall growth of the economy is not as important in determining growth as is the intensity of use. The cases presented probably bracket the likely range of intensity of use ranging from no increase to increases consistent with the past experience. None of the projections is a prediction, because the prices and availabilities of alternatives upon which the reasonableness of each projection depends cannot be accurately predicted. At attractive prices for electricity, the potential for future growth in demand is very rapid. At unattractive prices, the growth in demand will still be rapid. 3-95 Table 3-33 STATE ELECTRICITY DEMAND PROJECTIONS SUMMARY Thousand MWH Demanded Annual Growth Rates Calculated from 1974 (%) Accelerated Economic Limited Economic | Accelerated Economic Development Development Development highest lowest highest lowest highest lowest 1,715 1,715 - - - - 4,286 2,941 14.7 8.7 16.5 9.4 8,358 4,712 13.0 8.4 15.5 9.6 13,450 6,961 11.8 8.1 N37 9.2 21,929 10,524 - 11.2 8.1 12.9 9.0 i ity @ 50% Load Limited Economic Development Year highest lowest 1974 1,715 1,715 1980 3,909 2,830 1985 6,581 4,147 1990 10,158 5,975 . é 1995 15,799 8,765 MW Peak Capac 1974 392 392 1980 892 646 1985 1,503 947 1990 2,319 1,364 * 1995 3,607 2,001 | - 392 392 979 671 1,908 1,076 3,071 1,589 5,007 2,403 A regional comparison of projected growth clearly shows that the Anchorage area will increasingly dominate the state in quantity of electricity demanded, assuming the same intensity of electricity use throughout the state. It will increase from 51 percent of consumption in 1974 to between 65 and 70 percent of consumption in the accelerated economic growth case. This is shown in Table 3-34. All other regions decline in importance relative to Anchorage over time. The Northwest and Southwest are the least predictable and appear to grow most slowly. The Southeast is next, followed by the Southcentral region and Fairbanks. The limited economic development scenario would probably show a comparable future regional distribution of demand. The dominance of Anchorage in the statewide picture should not dis- tract one from the fact that other regions will continue to grow rapidly and under certain circumstances, exceed their historic growth rates. 3-97 g6-€ Table 3-34 COMPARATIVE REGIONAL GROWTH IN ELECTRICITY DEMAND ACCELERATED ECONOMIC DEVELOPMENT Thousand MWH Region V. Anchorage IV. Southcentral VII. Fairbanks II. Southeast I. Northwest II. Southwest State plectrietty highest lowest highest lowest highest lowest highest lowest highest lowest highest lowest highest lowest yw a : —- Year 1974 867.132 867.132 282.417 282.417 318.751 318.751 215.088 215.088 15.178 15.178 16.615 16.615 1,715 1,715 1980 2,286 1,580 933 544 658 455 355 326 24 18 30 18 4,286 2,941 1985 4,822 2,679 1,701 857 1,244 669 505 465 34 21 52 21 8,358 4,712 1990 8,637 4,273 2,178 1,142 1,891 907 639 594 36 22 69 23 13,450 6,961 1995 15,350 6,918 2,791 1,545 2,834 1,250 826 763 37 23 90 25 21,929 10,524 Percentage of State Total (%)* 1974 50.6 50.6 16.4 16.4 18.6 18.6 12.5 12.5 8 8 9 9 -- oo 1980 53.3 53.7 21.8 18.5 15.4 15.5 8.3 1 6 6 7 6 -- oo 1985 57.7 56.9 20.4 18.2 14.9 14.2 6.0 9.9 4 4 6 4 -- -- 1990 64.2 61.4 16.2 16.4 14.1 13.0 4.8 8.6 3 3 5 3 -- -- 1995 70.0 65.7 12.7 14.7 12.9 1.9 3.8 7.3 2 2 4 2 - -- Average Annual Growth Rates from 1974 17.5 10.5 22.1 11.6 12.8 6.1 8.7 7.2 8.1 3.1 11.0 2.0 16.5 9.4 16.9 10.8 17.7 10.6 13.2 7.0 8.1 7.3 7.7 3.1 N.3 2.5 16.5 9.6 15.5 10.5 13.6 9.1 11.8 6.7 7.0 6.6 5.6 CO 9.6 2.3 13.7 9.2 14.7 10.4 W.5 8.4 11.0 6.7 6.6 6.2 4.4 2.1 8.6 2.1 12.9 9.0 12.5 ng 14.1 6.5 7.9 11.5 “Tetals may not add up due to rounding Electricity Demand in Rural Areas A. Past Trends In rural communities within the state, electricity is supplied either by very small public utilities such as the Alaska Village Electric Coopera- tive (AVEC) or Alaska Power and Telephone Company, or by private generators which serve a single household or a few neighboring households. The largest single supplier to the rural areas is AVEC, which presently provides power to 48 communities with populations in the 100-600 range. The regional distribution of this service is shown in Table 3-35. The average population of AVEC supplied communities is approximately 300. Sales to final consumers in the AVEC system in 1974 are shown in Table 3-36. Sales data indicates that the largest individual consumer in each com- munity is the school. Schools, together with residential consumers, use 79 percent of the power generated by AVEC. A review of the system since its organization in 1968 indicates increas- ing use per customer, but generalizations based upon observed increases can- not be made because consumption is probably presently constrained by the available power supply. For example, residential use per customer increased at an annual rate of 16 percent between 1971 and 1974. On the other hand, school use has not increased. According to AVEC personnel, this is because the peak demand of the schools very rapidly reached the capacity of the system. Further school demand increases would require system expansion. 3-99 IV. VI. Il. II. REGION Southcentral Interior Southeast Northwest Southwest Table 3-35 VILLAGES INCLUDED IN AVEC SYSTEM (1974) CENSUS DIVISION Kodiak Yukon-Koyukuk Angoon Kobuk Nome Bethel Bristol Bay 3-100 COMMUNITY Old Harbor Huslia Kaltag Minto Nulato Angoon Kiana Kivalina Noatak Noorvik Point Hope Selawik Shungnak Elim Gambe11 Koyuk St. Michael Savoonga Shaktoolik Shishmaref Stebbins Wales Eek Goodnews Bay Mekoryuk Nunapitchuk Quinhagak Toksook Bay Tununak Emmonak Kasigluk New Stuyahok Togiak REGION Customer Type Residential Commercial Industrial (school) Street Lighting Other Source: FPC Form 12-D Table 3-35 Continued CENSUS DIVISION Kuskokwim Wade Hampton Wade Hampton (Cont. ) Table 3-36 AVEC SALES - 1974 COMMUNITY Grayling Holy Cross Lower Kalskag Shageluk Anvik Upper Kalskag Alakanuk Chevak Hooper Bay Marshall Mt. Village Pilot Station Pitkas Point St. Mary's Scammon Bay KWH Sales/Consumer Number Total KWH Sales 2,145 3,101,457 135 1,009,108 “47 4,357,040 75 63,480 250 965,630 Power System Statement 3-101 1,446 7,475 92,703 846 3,863 The level of average annual residential sales of electricity in AVEC communitites is very low compared to urban areas. The 1974 average for AVEC was 1446 kwh. This level of kwh of electricity is about the amount required to provide lighting and refrigeration in each household served. By comparison, the statewide average for utility customers was 8879 kwh. Several other utilities provide electricity to small communities. Most notable among these is Alaska Power and Telephone Company which serves Craig, Hydaburg, Skagway, and Tok. Others are the utilities at Unalakleet, McGrath, Port Graham, Hoonah, and Kake. Where extensive data is available, the sales of these utilities have been included in the previous section of the report. Recent data on residential electricity consumption per house- hold in these communities indicates that a large potential for increased residential consumption exists in the AVEC communities. This is indicated by Table 3-37. Differences among these communities and with the average AVEC community are the result of a variety of factors not easily isolated, but including in- come, employment opportunities, culture, and cost of power. AVEC estimates there are 125 communities presently within the state with a population of over 25 people without an adequate electrical power system. The total population in those communities may be approximately 15,000 people. An example of two such villages without utility electricity are Napakiak and Akiachak, villages recently surveyed in conjunction with a study of a re- gional electric power system for the lower Kuskokwim. 7“ A description of 3-102 Table 3-37 1974 RESIDENTIAL CONSUMPTION PER HOUSEHOLD ' SMALL ALASKAN COMMUNITIES « Community KWH/Household Craig 2,609* Hydaburg -- Unalakleet 2,132 : McGrath 1,796 : i Port Graham 3,857 Tok 3,065* Hoonah 4,536 Kake 4,200 AVEC 1,446 . - 4 * 1970 data Source: FPC Form 12 Power System Statements; except Hoonah and Kake from R.W. Beck and Associates, "Report on Establishment of Consolidated Operations, Projected Operating Results, and Recommended Form of Rates for Tlingit-Haida Regional Electrical Authority," Oct. 8, ‘ 1975, p. Il. 5. 3-103 the present electricity supply situation in these communities is presented not because it is necessarily representative of communities presently with- out electric utilities, but simply to provide an example of electricity use in small villages. In Napakiak, a community of 38 houses and 223 people, there are 23 small electric generators, averaging about 3 kw in size. Thirty-six of the 38 houses are supplied by these units for varying portions of the day and appliances on hand are indicated in Table 3-38. TABLE 3-38 Appliances on Hand - Napakiak Refrigerator 6 Water Pump 4 Clothes Washer 27 Space Heat 5 Freezer 18 Range BE Iron 16 Clothes Dryer i Television 34 Hot Plate 9 Radio 27: Power Tools 16 Miscellaneous Small Appliances 177 Source: Robert W. Retherford Associates, "A Regional Electric Power System for the Lower Kuskokwim Vicinity," July, 1975, page 16. 3-104 All houses with electricity have lights and at least one other appli- ance such as a television or radio. Present average electricity use per household is estimated at 2,001 kwh/year and with the addition of appli- ances which individuals indicated they planned to purchase in the future, consumption is estimated to increase to 3,610 kwh/year. In Akiachak, a community of 51 households and 320 persons, five gen- erators serve 38 of the residences for varying portions of the day. The average generator size is 3 kw, and appliances on hand are listed in Table 3-39. TABLE 3-39 Appliances on Hand - Akiachak Refrigerator 4 Range 1 Clothes Washer 20 Water Pump 0 Freezer 9 Clothes Dryer 1 Iron alal Dishwasher 0 Television 33 Hot Plate 5 Radio 24 Power Tools 7 Space Heat 8 Miscellaneous Small Appliances 49 Source: Robert W. Retherford Associates, "A Regional Electric Power System for the Lower Kuskokwim Vicinity," July, 1975, page 17. 3-105 Three of the residences with electric power have only Lights and as is the case in Napakiak, television sets are, after lights, the most popular appliance. This is due to the proximity of a public television station in Bethel which provides local programming in Native languages. Average kwh use per household is estimated to be 1,427 yearly. With planned appliance additions, this would rise to 2,369 kwh. The average kwh used in these villages is actually somewhat higher than the average for all the AVEC communities in the state. Since these communi- ties are not necessarily representative, no generalizations can be drawn from this on the average consumption of electricity in other communities without public utilities. In these communities, as with others without an electric utility, commercial buildings, schools, and public buildings have their own individual generating capabilities or share with others. B. Future Demand The estimation of future electricity demand in rural villages is highly speculative for several reasons. The basic problem lies with attempting to predict the future economic viability of the individual community. This will depend upon the cultural heritage of the village, the use made of opportuni- ties available under the Alaska Native Claims Settlement Act, the general economic development of the state and region, and not least by the availability of electricity to the community. In addition, each village is a small isolated unit for the purposes of determining the level of demand. A change in the habits of a few households or the local school can have a dramatic 3-106 effect on the total level or composition of electricity demand in a com- munity. Third, the level of demand in any small community will largely be determined by government decisions made outside the control of the community. AVEC personnel state that the future level of demand in AVEC served villages is mainly determined by the demand generated by the following government installations: 1) state schools 2) Bureau of Indian Affairs schools 3) state high schools 4) Public Health Service facilities 5) housing authorities 6) Federal Aviation Administration 7) satellite communications All of these factors imply the need to determine demand projections independently for each village. The small size of the individual communi- ties allows this to be done by surveying the expected future needs of in- dividual households and commercial and public facilities. This technique, of course, suffers when accurate estimates by individuals cannot be made, and when rising expectations alter consumption patterns. This has been a problem encountered by AVEC planning. Since an overall projection of electricity demand in small villages would have no meaning because it could not be related to individual communi- ties or supplies, this section will merely analyze the apparent demands in some villages which may not necessarily be representative of all rural communities. ‘Future electricity demand increases in communities presently served by AVEC are expected to result primarily from increased electricity use 3-107 per customer according to AVEC's own recent demand projections.-> The average annual growth rate in the number of customers between 1973 and 1983 based upon analysis of the 48 individual communities presently served is projected to be 2.7 percent, not including schools and other public build- ings which show an increase of 18 total units. On the other hand, total mwh electricity requirements increase at an annual rate of 10.6 percent, rising from 11,000 to 30,067 mwh between 1973 and 1983. The total consumption in the community divided by the number of households in the typical community is projected to rise from 5,128 kwh to approximately 14,000 kwh. This includes not only residential consumption but also commercial, school, and public building consumption. Actual use of electricity by residential consumers has increased at an annual rate of 16 percent on a per customer basis between 1971 and 1974. This figure is too high for a projection of future demand levels because it includes households newly supplied with power during a year who show an abnormal growth rate between the first two years. At a growth rate of. 16 percent, average household consumption in 1984 would be 6,380 kwy/year, which is well below the present statewide average of 8,879 kwh. It would be about 85 percent of the present average level of consumption of an Anchorage household without electric heat of 7,500 kwh. At present price levels, the average yearly bill to AVEC residential consumers in 1984 would be over $900 if that growth rate were realized. There can be no doubt, however, that growth rates will remain high for some time as residential customers gradu- ally become accustomed to the availability of electricity. 3-108 The projections of demand for electricity tn villages whieh do not presently have utility service has an added element of uncertainty in addition to the problems of AVEC supplied communities. Even though electri- city use exists in such villages, the introduction of an electric utility creates an essentially new product--more reliable service--which changes the composition of demand such that past behavior is not a reliable guide to future consumption. One must project electricity demand in those vil- lages on the basis of the AVEC experience with the introduction of electri- city to villages. Two studies of this nature have recently been completed and may provide examples of projecting individual village electricity requirements. A recent study of the residential electricity needs of six Southeast communities assumes average annual appliance usages as shown in Table 3-40. A level of appliance saturation is assumed for 1985 which implies 7,800 kwh average consumption in five of these communities (Hoonah, Kake, Kasaan, Klawock, and Klukwan). This would include lights, range, refrigerator, washer and dryer, freezer, television, and some hot water heaters. The sixth village, Angoon, would have slightly lower needs because of the pres- ence of propane ranges. Non-residential growth in demand was based upon historic consumption rates for individual consumers and estimates of the growth in the number of such consumers. 3-109 Table 3-40 SOUTHEASTERN ALASKA ELECTRIC APPLIANCE ELECTRICITY CONSUMPTION KWH/Year Lights 1,200 Range 1,200 Refrigerator 1,800 Dishwasher 360 Hot Water* 4,800 - 9,600 Washer and Dryer 1,440 Freezer 1,560 Television 600 - * The larger figure includes the use of hot water in a clothes washer. Source: R. W. Beck and Associates "Report on Establishment of Consolidated Operations, Projected Operating Results, and Recommended Form of Rates for Tlingit-Haida Regional Electric Authority," Oct. 8, 1975, p. 11. 3. 3-110 Projected growth rates in total consumption in the six communities ranged between 3.9 percent and 11.7 percent and averaged 5.8 percent for the 10 year period to 1985. The differences in growth rates among the com- munities is the result of differences in the growth in the number of a dential consumers (the average growth rate in the number of households is 3.6 percent) and differences in the number of new consumers in other cate- gories. The projections for individual communities are shown in Table 3-41. It appears that consumption in the smaller communities is primarily residential, but in larger villages commercial, public, and other demands play a significant role. Another recent study projecting electricity consumption in newly sup- plied communities includes ten villages in the Southwestern region. Estimates of annual kwh consumption of common appliances for the study are listed in Table 3-42. 3-111 Table 3-41 SOUTHEASTERN VILLAGE DEMAND PROJECTIONS 1976 Residential | Residential Other Other Total Village Consumers Consumption Consumers Consumption Consumption Thousand KWH Thousand KWH Thousand KIIH Angoon 113 373 28 711 1,084 Hoonah 262 1,316 41 990 2,306 Kake 173 845 27 2,385 3,230 Klawock 98 480 18 1,625 2,105 Kasaan VW 49 4 64 cs Klukwan * 59 291 6 47 338 716 9,176 1985 Angoon 131 888 30 971 1,859 Hoonah 370 2,670 51 2,008 4,678 Kake 245 1,780 35 2,793 4,573 Klawock 143 1,042 20 2,250 3,292 Kasaan 29 : 219 7 86 305 Klukwan 68 488 6 53 541 986 15,248 Source: R. W. Beck & Associates "Report on Establishment of Consolidated Operations, Projected Operating Results, and Recommended Form of Rates for Tlinget- Haida Regional Electric Authority," Oct. 8, 1975, Table S-1. 3-112 Table 3-42, SOUTHWESTERN ALASKA ELECTRIC APPLIANCE ELECTRICITY CONSUMPTION KWH/Year Lighting 300 - 600 Refrigerator 400 Washer 40 Freezer 1,200 Iron 100 Space Heating 240 - 360 Range 1,440 Water Pump 180 Dryer 1,200 Radio 100 Dishwasher 30 Television : 300 Source: Robert W. Retherford Associates, "A Regional Electric Power System for the Lower Kuskokwim Vicinity," July, 1975, p. A3. 3-113 Two communities among the ten, Napakiak and Akiachak, were surveyed as to what household appliances would be desired but are not now in the home. Based upon the estimated usage levels, the acquisition of the appliances reported to be desired would increase consumption 80 percent and 66 percent, respectively, in the two villages. Unforeseen demands are assumed in the study to increase that growth rate to 10 percent annually, based upon data from the AVEC villages in the area. Growth rates for other categories of consumers are assumed to be 7 percent for small commercial, 1 percent for Bureau of Indian Affairs' schools, and 15 percent for public buildings. The number of consumers is assumed to grow at the rate of 4 percent for residen- tial, 7 percent for commercial, and 4 percent for public buildings. The resulting projected demands for the 10 villages are shown in Table 3-43. TABLE 3-43 Electricity Use Projections for Ten Southwestern Communities Residential Other Total a Consumers Mwh Consumers Mwh Mwh 1975 414 725 60 1,714 2,439 1985 613 2,788 90 2,486 5,274 Source: Robert W. Retherford Associates, "A Regional Electric Power System for the Lower Kuskokwim Vicinity," July, 1975, p. 15. 3-114 This is equivalent to an average annual growth rate in demand over the period of 8 percent for the ten villages as a unit. These two studies support the contention that each rural siteasion is unique. Demand growth in the first study is projected at an average rate of 5.8 percent with wide variation by community. In the second study, 8 percent is chosen. Each may be correct for the particular villages ana- lyzed, although many of the numbers underlying the projections must neces- sarily be arbitrary. It is clear that there is a strong potential for growth in electricity consumption in these communities if it is available at a reasonable price. It is also clear that state and local government agencies have a large impact on the projected growth rates in consumption in different communities. Unfortunately it is not possible to predict future public demands for electricity in these small communities. 3-115 Industrial Demand A. Past Trend Many industrial users of electricity find it necessary or convenient to generate their own power. Overall statistics for the state are not available on total consumption in this category but there is some data available to put industrial demand into perspective with other electricity users. Electricity production by industry in Alaska is reported to the Pedéral Power Commission and is presented for recent years in Table 3-44. Produc- tion appears to be growing slowly over time. The statistics are misleading, however, in that only four establishments which produce electricity file reports. They are Alaska Lumber and Pulp Company, Ketchikan Pulp Company, Ketchikan Spruce Mills, and Shell Oil Company. TABLE 3-44 Industrial Electricity Production Year Thousand MWH 1965 231.857 1966 252.785 1967 255.507 1968 266.108 1969 270.125 1970 269.891 1971 276.695 1972 271.617 1973 277.617 1974 302.525* *Tentative figure Source: Federal Power Commission Electric Power Statistics, Table 2, Industrial Establishments, various issues. 3-116 A list compiled by the Alaska Power Administration, Table 3-45, provides a better picture of industry-produced electricity. TABLE 3-45 Industrial Electricity Capacity 1972 Gross Location Company Installed Capacity Generation i" 1,000 KW 1,000 MWH Sitka Alaska Lumber & Pulp 24.7 -- Ketchikan Ketchikan Spruce Mills 9 -- Ketchikan Pulp Mills 20.8 -- Cook Inlet offshore production platforms 42.3 -- drift river pipeline 10 4.4 Kenai Collier plant 957, 45.3 Kenai LNG 4 stand-by Tesoro Refinery 203 -- Trading bay production plant es 12.8 Prudhoe Bay British Petroleum 10 -- ARCO ene 9.1 TOTAL 107.6 MW Source: U. S. Department of Interior, Alaska Power Administration, 1974 Alaska Power Survey, Resources and Electric Power Generation, Appendix A. 3-117 Industrial production is concentrated in two industries and is the result of two situations. In some cases, as at Prudhoe Bay and in Cook Inlet, there is no electricity available from a utility and the company must pro- duce it. In others, such as the pulp mills, electricity is available, but it is not of a quality or at a price which makes it attractive for the plant to purchase. It is more economical to produce. In some instances, a plant will purchase its electricity from a utility but have its own standby backup, as in the case of the LNG facility at Kenai. In others, the plant will produce its own power but have some intertie with the electric utility for standby or marginal purchases and sales. The most obvious omission from Table 3-45 is the electricity generating capacity which has been installed in conjunction with the Trans-Alaska Oil Pipeline project. There are certainly others, but the total number of large producers is small. This being the case, it is impossible to carry out any kind of statistical analysis to attempt to pick up a historical relationship between production and general economic variables within the state. B. Projections of Requirements Aside from the problem of statistically projecting future industrial re- quirements due to the small number of significant producers and paucity of data, such an exercise would be of questionable value, particularly for this study. Small industrial users of electricity will continue to find, as in the past, that purchasing power is more economical than generating it except 3-118 in certain applications where there are special requirements or an efficient total utility system can be installed which provides space heating capability in conjunction with electricity generation. This type of small industrial use was projected as a component of utility needs. On the other hand, large industrial users will in some cases always prefer to produce their own power because of special needs or because it is more economical. Projecting electricity needs for this category of user has no value for this study. Finally, there is a class of large industrial users who would purchase utility electricity if it were available at a low price. This user category is presently not large within the state but could increase by a quantum step if, for example, an aluminum smelter were to locate in the state. It is necessary to distinguish two distinct groups within this industrial user category. First, there may be mineral resource industries which might be attracted to Alaska because of low electricity prices. Second, there may be industries which would locate in Alaska as the size of the market expands, or would locate in Alaska regardless of the price of electricity. Attempts have been made in the past, notably in connection with the Rampart Dam Proposal, to project electricity requirements which would be the result of mineral resource industry development in Alaska stemming from the availability of low-cost electric power. Such attempts are highly speculative because of the assumptions which must be made regarding future world wide market, conditions for both the products of the industries and electricity and other energy sources. These assumptions in turn heavily depend upon assumptions regarding political stability in foreign countries, 3-119 etc. A more basic criticism of such projections is that they proceed on the theory that mineral resource development will follow the development of low cost power. On the contrary, the development of mineral resources through discovery and exploitaticn phases generally precedes the establish- ment of other industries and infrastructure, including electric power. Projections of industrial use of electricity by large users has not been done. This is not to imply that large industrial users will not be locating in Alaska over the next 20 years either as a result of an attractive electricity price, as a result of the growth of the state market, or as a result of mineral development. However, the construction of scenarios to project specific developments cannot be done with any accuracy because of the uncertainties contingent upon any industrial development. A reasonable scenario would require a detailed analysis of each potential project and future markets for factors and outputs not only in Alaska, but also through- out the world. An analysis of electricity demands by large industrial users based upon casually constructed scenarios has no value because of these market uncer- tainties and if it were not interpreted with caution, such a projection could misrepresent growth in electricity needs within the state. On the other hand, it is useful to have an understanding of the direct electricity requirements of large industrial installations which have been suggested as most Likely to be built in Alaska in the future. Table 3-46 presents the electricity generation requirements of several installations which have been discussed from time to time for Alaska. They are not meant to be either representative or comprehensive. 3-120 Table 3.46 ELECTRICITY REQUIREMENTS OF SELECTED INDUSTRIAL INSTALLATIONS Location Southcentral Haines Tyonek Sitka Kenai Kenai Anchorage Juneau Plant Design Output aluminum smelter cement caustic soda chlorine jron ore mining iron ore mining ¢oal mining 150,000 ton-/year 2,000,000 bbl/year 77,000 tons/year 5,000,000 tons/year 5,000,000 tons/year Existing Facilities Alaska Lumber & Pulp Collier Plant Tesoro Refinery Chugach Electric Assn. Alaska Electric Light & Power 3-121 Generating Capacity Required (megawatts) 350 10 10 60 - 80 60 - 80 100 24.7 9.7 2.3 294 27 For purposes of comparison, the generation requirements of present industrial users and of representative communities are included. Any of these projects would require large amounts of power relative to what is presently produced and, thus, if any were installed, it would have a major direct effect on electricity generation requirements. 3-122 Military Electricity Demand Military electricity requirements are included only to provide a complete picture of electricity use in the state and also to provide a perspective to utility electricity demand levels and growth. Military facilities, although often intertied with utilities, form an essentially independent electric generating system. Consumption of electricity by the military has in recent years been fairly constant and is projected to remain so through the rest of this century. Table 3-47 presents a breakdown of generating capacity presently in place within the state. A large percentage of capacity is concentrated near Anchorage and Fairbanks with Shemya and Adak also having large instal- lations. Barring unforeseen changes in national defense requirements, the capacity levels indicated in Table 3-47 should be approximately sufficient to meet demand requirements in 1995. Military demand will thus continue to decline as a percentage of total electricity demand in the state. 3-123 Table 3-47 MILITARY ELECTRICITY USE Generating Capacity MW Southcentral Alaska U. S. Air Force - Elmendorf 32.5) U. S. Air Force - 17 sites ‘eo U. S. Army - Fort Richardson 25.2 = U. S. Navy - Kodiak 5.2 Subtotal 64.0 Interior Alaska U. S. Air Force - Clear 2 U. S. Air Force - Eielson 2 U. S. Air.Force - Fort Yukon U. S. Air Force - Galena U. S. Air Force - Barter Island U. S. Air Force - 29 sites U U U ~ . S. Army - Fort Greeley . . S. Army - Fort Wainwright . S. Navy and U.S. Air Force - Point Barrow ny PNONMNMNWONM AOwUInn—ouw Subtotal . 102.3 Southeastern Alaska U. S. Air Force -- 4 sites 2.2 i Southwestern Alaska U. S. Air Force - Shemya 231 U. S. Air Force - 19 sites 17.9 U. S. Navy and U. S. Army - Adak 19.7 Subtotal 49.7 TOTAL 218.2 Source: Air Force - private communication with Thomas Dwyer, Deputy Director of Operations and Maintenance, Alaskan Air Command. Others - U. S. Department of Interior, Alaska Power Administration, 1974 Alaska Power Survey, Resources and Electric Power Generation, Appendix A. Note: Regional breakdown does not conform to MAP model regions. 3-124 uo 10. air a2) FOOTNOTES Federal Power Commission, 1970 National Power Survey, (Washington, D.C., 1971), pp. I-33. See David T. Kresge, "Alaska's Growth to 1990," Alaska Review of Business and Economic Conditions 13:1 (Jan. 1976). A map of the regional boundaries is in the Appendix. Alaska Village Electric Cooperative (AVEC), although a public utility, is given separate treatment in a later section of the report. R° is a statistic which reflects the "goodness of fit" between all the data points and the corresponding values predicted by the equation. If R@ is +1, the fit is perfect. These high R® figures are the result of both a small number of observations and the fact that growth rate equations normally produce high R2 results. U. S. Department of Interior, Alaska Power Administration, Alaska Electric Power Statistics 1960-1973, (Juneau, December 1974) p- 42. A more detailed scenario description is in Morehouse, "Development of Alaska's Petroleum Resources," draft paper, Institute of Social, Economic and Government Research, 1975. "U.S. Slashes Size of Oil-Lease Sale Off New England," Wall Street Journal, Friday, Jan. 2, 1976, p.3. A sensitivity analysis of the projections to (1) wellhead oil price, (2) rate of state savings from recurrent oil revenues, and (3) con- struction of Trans-Alaska gas line resulted in very little movement outside the range of growth projected by the limited and accelerated growth cases in the long run. Federal Power Commission, "All Electric Homes in the United States," Washington, D. C., Jan. 1974. L. D. Taylor, "The Demand for Electricity: A Survey," Bell Journal of Economics, Vol. 6, #1 (Spring, 1975), p. 74-110. Ibid., p. 105. 3-125 13. Data tor these comparisons comes from U. S. Department of Interior, Alaska Power Administration, Alaska Electric Power Statistics, 1960-1973, Dec. 1974, p. 44. 14. Federal Power Commission, All Electric Homes in the U. S. Annual Bills, Jan. 1, 1974, Washington, D. C., 1974, p. 6. 15. Ibid. 16. L. D. Taylor, op. cit., p. 101. 17. Energy Policy Project of The Ford Foundation, A Time to Choose (Cam- bridge: Ballinger, 1974), p. 52. 18. Ibid., pp. 64-65. 19. See the appendix for a map of the regions. 20. Regression results are included in the appendix. 21. An appendix analyzes the fuel prices at which a consumer of residential space heating would prefer electric heat. In general, electric space heating is not competitive in Alaska from an economic viewpoint. 22. U. S. Department of the Interior, Alaska Power Administration, op. cit., pp. 43-44, 23. Calculated from Federal Power Commission statistics. 23a. Before that time, moderate electrification (old consumers continue at present use levels, household hookup ratio rises to 27 percent and holds constant, new consumers choose electric space heating in same proportion as old, and other appliances are all electric and pur- chased immediately) results in larger demands. 24. Robert W. Retherford Associates, "A Regional Electric Power System for the Lower Kuskokwim Vicinity," July 1975. 25. U. S. Department of Agriculture, Power Requirements Staff, Rural Electrification Administration, "Power Requirements Study (Revised) Alaska 27 Villages, Alaska Village Electric Cooperative," Washing- ONS De = Cog OCtes LIAY. 3-126 BIBLIOGRAPHY Alaska Public Utilities Commission. Annual Report, annual. Alaska Public Utilities Commission. Utility financial reports. Alaska Public Utilities Commission. Utility rate files. Alaska, State of. Department of Community and Regional Affairs, Division of Community Planning, "An Overview of Electric Power in Alaska, April 1975." Arthur D. Little, Inc. Alaska's Mineral Resources as a Base for Industrial Development. Report to State of Alaska, 1962. Arthur D. Little, Inc. Potential for Use of Alaska's Energy Resources. Report to State of Alaska, 1962. Bracken, E. 0. "Power Demand Estimators, Summary and Assumptions for the Alaska Situation," Alaska Department of Economic Development, April 1973. Energy Policy Project of Ford Foundation. A Time to Choose. Cambridge: Ballinger Co., 1974. Federal Power Commission. All Electric Homes in the United States. Wash- ington, D.C.: Government Printing Office, annual. Federal Power Commission. Electric Power Statistics. Washington, D.C.: Government Printing Office, various issues. Federal Power Commission. 1970 National Power Survey. Washington, D.C.: Government Printing Office, 1971. Federal Power Commission. Statistics of Privately Owned Electric Utilities in the United States. Washington, D.C.: Government Printing Office, annual. Federal Power Commission. Statistics of Publicly Owned Electric Utilities in the United States. Washington, D.C.: Government Printing Office, annual. Federal Power Commission. Form 12 annual reports of utilities, annual. Harrison, Gordon S. The Potential Market in Alaska for North Slope Natural Gas. ET Paso Alaska Company, March 1975. Henry J. Kaiser Company. Upper Susitna River Hydroelectric Development. Report to the State of Alaska, 1974. 3-127 Hoag, Rush. The Promise of Power. Potential Economic Development in Southeast Alaska. Alaska State Yukon-Taiya Commission and Depart- ment of Economic Development, State of Alaska, Juneau, Jan. 1972. Mooz, W. E., and Mow, C. C. "California's Electricity Quandary: Esti- mating Future Demand." Prepared for the Resources Agency of Cali- fornia with support from the National Science Foundation by Rand, September, 1972. R. W. Beck and Associates. "Report on Establishment of Consolidated Operation, Projected Operating Results, and Recommended Form of Rates for Tlingit-Haida Regional Electrical Authority." Oct. 1975. Spurr, Stephen, et al. Rampart Dam and the Economic Development of Alaska. School of Natural Resources, University of Michigan, Ann Arbor, 1966. Taylor, L. D. "The Demand for Electricity: a Survey," Bell Journal of Economics, Spring 1975, vol. 6 #1, pp. 74-110. U.S. Department of Agriculture. Rural Electrification Administration. Power Requirements Studies for Alaska Systems. 1975. U.S. Department of Commerce, Bureau of the Census. 1970 Census of Housing. Washington, D.C.: Government Printing Office, 1977. U.S. Department of Commerce, National Oceanic and Atmospheric Administra- tion, Environmental Data Service. "Local Climatological Data." Asheville, North Carolina, 1974, various issues. U.S. Department of Interior, Alaska Power Administration. Alaska Electric Power Statistics 1960-1973. Juneau, December 1974. U.S. Department of Interior, Alaska Natural Resources and the Rampart Project. Washington, D.C.: Government Printing Office, 1967. U.S. Department of Interior, Alaska Power Administration. 1974 Alaska Power Survey. Juneau, 1974. U.S. Department of Interior, Alaska Power Administration. Devil Canyon _ Project, Alaska. Juneau, 1974. U.S. Department of Interior, Alaska Power Administration. Devil Canyon Status Report. Juneau, 1974. U.S. Department of Interior, Alaska Power Administration. A Regional Elec- tric Power System for the Lower Kuskokwim, prepared by Robert W. Retherford Associates, Anchorage, July 1975. 3-128 Wasic USS. Department of Interior, Alaska Power Administration. Susitna Power Markets draft. Juneau, 1975. Senate, Committee on Public Works. The Market for Rampart Power, Yukon River, Alaska. Washington, D.C.: Government Printing Office, 1962. University of Alaska, Institute of Social, Economic, and Government Research. "Development of Alaska's Petroleum Resources," by Tom Morehouse, draft. Wall Street Journal. 3-129 Iy. ELECTRICITY GENERATING TECHNOLOGY REVIEW Diesel Electric Generating Units Diesel generating units are internal combustion diesel engines directly connected to an alternating generator. These units are built as an integral whole and mounted on skids for transport to their place of use. The fuel supply is usually in a tank farm located a short distance from the power house. Like any piece of operating machinery and more than many, a diesel unit must be continuously observed and maintained to stay operational and provide continuous reliable power. 1) Efficiency: 500 KW and larger power plants with good operation and mainte- nance procedures can approach efficiencies of 13 kwh/gallon, or 10,800 btu/kwh, which is competitive with larger steam plants. Remotely located 75 to 250 KW diesels may have efficiencies as low as 7 kwh/gallon or 20,000 btu/kwh. The average AVEC plant rate, for example, was 7.5 kwh/gallon in 1972. 2) Cost of Electricity Produced: The cost of fuel oil is the single most important factor in determining the cost of electricity generated by diesel units. As the price of diesel fuel increases, the cost of electricity goes up rapidly. 4-1 5) Timing for Installation: Diesel units are "on the shelf" items stocked by several manu- facturers, and the lead time between initial order and commencement of service may be as little as the time required to transport the unit to its point of use. Alaska Related Technical Problems: Lack of qualified operators, available spare parts, and inadequate transportation, are commonplace in Alaska. Special Capital Requirements: Initial capital investment may exceed $500 per person in small locations. These costs are prohibitive to remote consumers and outside financial help may be required for the initial installation. Environmental Considerations: Fuel tank installations require integrated spill protection, which may be difficult in remote locations. Reliability: Diesel units will carry their designed loads on a continuous basis, if properly installed and maintained. If the unit is utilized as a standby peaking unit, it is very reliable and the delay in putting it "on line" is usually measured in minutes. The higher reliability of low speed diesel units is advantageous for rural areas. Because of their lower first cost however most units now operating in Alaska are in the higher speed 1800 RPM range of operations. 4-2 Combustion Turbine ("Gas Turbine") Generating Units Gas turbines are installations in which either gas or oil is fired in a turbine which drives a generator. Simple cycle units release exhaust combus— tion gases directly into the atmosphere. Units using a aemenmmesteines eycle channel the hot exhaust gases through a heat exchanger, which transfers some . of the waste heat in the exhaust to the inlet combustion air, raising the overall efficiency of the unit above that of the simple cycle. Combined cycle units use gas turbines and a secondary steam turbine to increase the overall efficiency of the basic unit. Units of this type are usually considered for installations of 150 MW or more. 1) Efficiency: Simple cycle gas turbine efficiencies range from 12,000 to 16,000 btu/kwh, depending upon size, and regenerative cycle gas turbine efficiencies are between 9,500 and 13,500 btu/kwh. The efficiency of gas turbines is sensitive to inlet air temperature; that is, the lower the temperature, the higher a given unit's power output. Example: 3,000 KW simple cycle gas turbine 2,700 KW output available at 60°F 3,200 KW output available at -20°F The fuel efficiency of a turbine can approach that of the steam plant if a regenerative cycle, or heat recovery boilers and steam turbines, are added to the basic unit. 2) Cost of Electricity Produced: Gas turbines are designed to operate at full capacity. In general, the operation of a gas turbine at less than full capacity reduces 4-3 the fuel efficiency of the system. For example, a gas turbine with no load will still use approximately 30% of the fuel it would use at full load. Turbines may be fired with either natural gas or oil; in Alaska, however, the cost of oil is much higher in those areas where gas is available. Gas turbines have traditionally been utilized for peaking rather than base load because operating costs are high relative to fixed costs. In Alaska, where the cost of gas has been comparatively low, gas turbines have been used for base load generation. Rising gas prices in the future may reverse this trend. Timing of Installation: Manufacturers have been able to keep pace with the large demand for turbines in the past few years. The lead time, however, may vary from "on the shelf" for smaller simple cycle units, to as much as two years for the larger regenerative or combined cycle units. In the latter case, installation after arrival of the unit normally takes about one year before the plant goes on line. Even so, the larger units can be put on line far more quickly than steam or nuclear plants, and for this reason they are becoming more popular for base load in the Lower 48 in spite of high gas prices and impending shortages. Alaska-Related Technical Problems: The time required for maintenance tasks and acquisition of repair parts tends to take a little longer in Alaska, but other problems are similar to those encountered in the Lower 48. The cold Alaska winters, which result in higher gas turbine efficiencies, also cause 4-4 an air intake icing problem under certain temperature and humidity conditions. This problem restricts air flow to the turbine, reduces its output, and in extreme cases, causes the unit to shut down. Manufacturers have been working on this problem, and to date the most successful method of preventing icing has been to preheat the inlet air, either by supplemental heaters or by recirculating exhaust heat. 5) Special Capital Requirements: Normal power plant financial arrangements are used for gas turbine installations. 6) Environmental Considerations: Exhaust from gas fired turbines is exceptionally clean but may cause ice fog formation in the winter. Integration of the unit into a community rarely causes any environmental or aesthetic problems. 7) Reliability: Gas turbines installed in support of larger units in a standby and/or peaking capacity have a very high reliability and the lead time needed to replace them on line is extremely short. Steam Turbine Generating Units Conventional steam plants consist of a fuel fired boiler for generating steam which drives a steam turbo-generator. The changing costs of individual fuels has caused plant designers to use boilers 4-5 and fuel handling methods which are easy to adopt for either coal, oil, or gas. The conversion from one fuel to another does not change the over- all plant efficiency substantially, as the heat rate remains about the same. The cost of the fuel is the controlling factor and with the multifuel equip- ment, the cheapest fuel available is used to produce steam. Coal-handling equipment is not required for oil and gas fired boilers, and change-over from coal to oil and/or gas is not as complex or as costly as the change- over from gas or oil to coal. If done at the time of original construction, multifuel capability is relatively inexpensive to build in. Retrofitting existing gas-fired boilers to use coal, however, can be prohibitively ex- pensive -- in some instances approaching the cost of wholly new facilities. 1) Ufficiency: Steam turbine unit heat rates average 12,000 btu/kwh for the smaller units to 9,500 btu/kwh for the hundred MW and larger range. Using wasté heat from noncondensing units for space heating or for other purposes greatly increases the efficiency of the plant. Noncondensing steam turbine generators have an imputed heat rate as low as 4,500 btu/kwh, when credit is given for otherwise "waste" heat marketed separately. 2) Cost of Electricity Produced: The steam turbine generator, especially in its larger sizes (100-1000 MW), has proven to be the most efficient means developed to date to generate base load electric power from fossil fuel. Nuclear plants are believed by much of the utility industry to be competitive with fossil fuel plants in the 1000 MW range, depending upon fuel cost and other factors, though this judgment is becoming increasingly controversial. 4-6 3) Timing, of Installation: Gleam power plants for Large base loads are custom designed. The lead time needed for fabrication and delivery of the major pieces of equipment (boiler, turbines) tends to be 3 to 5 years. Small plants ranging to 10 MW can be installed within 3 years. The University of Alaska plant at 3 MW was designed and constructed in 2 years. Plants of 20 MW or more may require 3 to 5 years, and occasionally longer. For this reason, contractual commitments are usually made to turbine and boiler manufacturers before the start of construction in order to allow for delivery of equipment simultaneously with completion of foundations. Due to the fast escalation of construction costs, the lead time required for this type of plant is a critical design item. 4) Alaska Related Technical Problems: In Alaska, steam plants must be totally enclosed, and (in the areas where coal-fired steam plants are a plausible choice in the foreseeable future) must use relatively low-grade coal. Table 4-1 gives some notion of what the requirements imply; it excerpts data from Electrical World's "19th Steam Station Cost Survey" for those plants burning coal with heat content less than 10,000 BTU/1b. and located in areas where one would ex- pect most plants to be enclosed. Enclosed plants have a significantly higher unit investment cost, and, of course, plants burning low-grade coal would have a higher investment in fuel, ash and related environmental protective equipment. The actual heat rate of all the coal-burning plants listed averages 10,283 BTU/KWH, but when they are segregated by fuel heat content, one finds the heat rate of plants burning coal of less than 10,000 BTU/1b. averages 11,099 BIU/KWH as opposed to 9,876 BTU/KWH for the plants listed which burn a higher grade coal. The average plant factor (load 4-7 factor) for the plants burning the low-grade coal was 53 percent,so this is comparable to what would be expected here. The influence of coal quality on heat rate can also be seen from the Fed- eral Power Commission publication "Steam Electric Plant Construction Cost and Annual Production Expenses, Twenty-Fifth Annual Supplement-1972," which shows heat rates of 11,412 BTU/KWH and 11,093 BTU/KWH for Regions VI and VII respectively. Regions VI and VII cover the Northwest and north half of the mid-west where most coal has a lower heat content. High labor costs in construction and operator availability, coupled with the added freight required, also increase the costs of power plants for Alaska. These factors affect the steam generating plants dis- proportionately, because of the higher share of site construction labor to total capital costs. Other problems encountered would be similar to those in the Lower 48, with the major exceptions of parts availability and the remoteness of manufacturers' representatives. Special Capital Requirements: Because of higher capital-output ratios, and long economic lives, steam power plants require long term financing arrangements. Because of the recent upheayals in fuel markets, long range commitments of V8-t Table 4-1. Plant No. Location Coal BTU/1b Capacity MY No. of Units Completed Plant Factor Employees/MwW No. of Employees Plant Cost $/KW (exc. switch yard) Design Heat Rate BTU/KWH Actual Heat Rate BTU/KWH Oper. & Maintenance (exclusive of fuel 1974) Mills/KWH Summary of Coal-Fired Plants Burning Coal with Heat Content Under 10,000 BTU/1b. 711 Pacific 7,631 1,350 2 1972 36% elizeo 163 246 9,800 10,595 ] 79 728 Mountain 8,466 355 ] 1973 75.4% +2025 7] 300 10,288 1.04 719 W. No.Central 9,301 825 ] 1973 21.8% . 2420 199 239 10,290 14,200 4.67 Source: Electrical World, "19th Steam Station Cost Survey." 721 Mountain 7442 754 4 1959-1972 57% +2945 161 184 10,355 10,497 1.8 729 Mountain 9,590 250 ] 80% . 3950 130 124 9,660 10,161 2.08 717 E.No.Central 9,234 882 2 1965 & 1972 47.9% - 1645 145 165 10,855 220i oil and gas to utility companies operating a steam power plant are becoming more and more difficult to obtain. The development of new coal mines, on the other hand, depends upon long term purchase commitments, so that assured supplies of coal can be expected to be available on long term contracts. Environmental Considerations: Since 1971, stack emissions from coal fired plants have become a major concern in design. Systems to control dust, sulfur oxides, and nitrogen oxides have been designed and installed in Alaska. The University plant is an example that all Environmental Protection Agency regulations can be successfully met. Federal legislation now discourages the use of oil and gas, and additional restrictions may be expected in the future, leading to the use of coal as the major fuel for steam plants. The mining aspect of coal is of serious environmental impact and if a new mine is associated with the plant, it will require environmental safeguards. Reliability: Steam power plants provide the base load for the bulk of the power producing industry in the United States. They have a long history of use, and other plant types are usually compared to steam plants in order to gain a reliable perspective of the new plant's use. Steam plants are considered by many to be the most reliable fuel fired base load generating systems now in existence. Hydroelectric Generating Units The great advantage of hydro energy is that it creates electricity from falling water, a renewable resource that is recycled by the sun. Hydro- electric installations must obviously be located where the falling water can best be converted to the electric energy form. This requirement often places the pro- ject some distance from the load center that needs the electricity. This fact may be a hydroproject's most serious disadvantage. The balancing of these factors with the individual topographic and hydrographic nature of each project then establishes the characteristics that support or defeat it. In contrast with fossil-fueled generating facilities, hydroelectric installations are considered far more sensitive to the influence of local conditions Hydro-electric units compare with fossil- fueled units as follows: 1) Efficiency: Hydro-electric energy conversion efficiency is the ratio between the electric energy delivered out of the hydro-plant and the maximum theo- retical energy of falling water. This ratio is typically about 90 per- cent, compared to about 38 percent efficiency realized from converting fuel energy to electricity in the best fossil-fueled plants. 2) Cost of Electricity Produced: Capital costs of a hydro-electric installation are the most significant contributors to the cost of electricity produced. The cost of "fuel" (falling water) is usually taken to be zero.* Hence, the cost of money _and investment per kilowatt of plant are the major elements. 3) 4) 5) 6) Timing for Installation: Hydro-electric projects typically require long lead times for instal- lation. Geology and water supply data plus legal requirements require nearly as much time as the construction process. Alaska Related Technical Problems: 4 See the following special sections on "Alaska Experience--Hydro" and "Alaska Experience--Transmission". Special Capital Requirements: Investment in hydro-electric projects will generally be greater per kw of total capacity than fuel-fired installations; however, in specific locations lower operating costs (such as zero fuel cost) may more than offset these higher investment charges. A feasible hydro-project i will generally be able to meet its debt service by the reduction in fuel bills, except when the size is substantially larger than the thermal plants it replaces. This characteristic will result in little disturbance, and often an improvement in cash flow for the utility. Environmental Considerations: Each hydro-project has its own particular impact on the environment. Hydro produces clean energy and sometimes creates additional recreation values. a In some cases, the ability of a hydro reservoir to regulate run-off may enhance a stream-supported fishery by reducing erratic fluctuations of the natural conditions. Hydro-electric, however, can reduce land areas by q flooding reservoirs and may disturb the ecological balance of water-related life. Dams may block the runs of migrating fish, and power reservoirs are often inferior recreational resources, compared to the flowing streams they replace (at least in the eyes of some interested parties). In addi- tion, very large reservoirs can conceivably have significant climatic effects. 4-11 7) Reliability: The reliability of hydro-electric facilities is classed as the best in the business of generating electricity. Maintenance requirements are minimum and operating restraints are of utmost simplicity allowing for easy automation, remote control and unattended operation. 2 a—-V2 Alaska Experience - Hydro Alaska has accumulated substantial experience in hydroelectric applications around the State and there exists within its own utilities and professionals a considerable reservoir of knowledge and sensitivity to factors uniquely Alaskan. This "know how" has been accumulated through the years by careful attention to Alaskan conditions and occasionally learned the "hard way". The importance of this awareness to lessons of the past and its impact on costs of hydroelectric developments can be illustrated by the following com- parison of two hydroelectric projects in Southcentral Alaska: (Continued on Page }~-15) 4-13 Name of Plant , Location of Plant Year Originally Constructed Gross Head (feet) Installed Generating Capacity, Nameplate, KW Number of Units Est. Average Annual Firm Energy, Cost of Plant (Thousands of Dollars) Land & Land Rights. .. Structures & Improvements Reservoirs & Waterways Dams eayen sume =o fictis Es a) Equipment Costs ... . Roads & Bridges . .. . Total Cost. . S/kv——= oo Production Expenses (Thousands Operation Supervision & Engineering. ...-. Operating Expenses. .. Maintenance Supervision Engineering. . .. .- Maintenance Expense . . Total Production Expense . . .- Average Number of Employees (on-line) MWH EKLUTNA 30 mi NE of Anchorage COOPER LAKE Cooper Landing 100 mi. south of Anchorage Average Cost of Energy at Busbar (Mills/kwh) Using equal capital recovery factors of 9%. . . Sie eee 4$. .. 1955. 5 196d 800" econ 30,000 15,000 2 2 137,000 41,000 1,538 $ — 390 783 23,801 SoD = 5952 2,024 1,548 == 893 30,953 $ 7,771 L032 $ 518 aay $ 6 105 48 == I 35 4 140 $ 59 T3; 2 21.4 a8.5 23 LORS Oe 9.0 If these two projects are compared after adjusting the total costs to equivalent years (say, 1961) by using the “implicit price deflator for GNP" (see Survey of Current Business, September 1969 and subsequent issues) the costs would relate as follows: (1955 to 1961 = 1.151) EKLUTNA COOPER LAKE © (1000's) (1000's) Total Cost (Aaj ..toO—-'96)) =. -._-_ .=1905,,027 S157 7s. Total Production Expense ..... 140 59 Cost of Energy at Busbar (Mills/kwh) Capital Recovery @ 9% .... 24.4 1855 Capital Recovery @ 5%... . 14.0 10.9 Capital Recovery @ 4% .... rela 9.0 Comments The direct comparison of these two projects using figures alone cannot be completely fair to either project since hydroelectric installations invariably have differences that are the result of difficult human choices of alternatives. However, it seems clear also that there is a learning ex- perience taking place that is worthy of close attention. The following statements are intended to add perspective to the comparison of the two projects: 1) The Eklutna project was built within 30 miles of Anchorage and was located where there were existing good quality roads passing close to the powerhouse site and the 4-15 2) 3) tunnel intake site at Eklutna Lake. A railroad also existed within about 1 mile of the Powerhouse site. The Cooper Lake project was required to pay for con- struction of about 9.5 miles of road. The nearest railroad was about 15 miles from the project road system. The Eklutna project did not include construction of a dam, relying instead on an existing small dam and draw- down of the existing reservoir for regulation. The useable storage of 160,000 acre-feet is about 70% of the average annual runoff. The Cooper Lake project included the construction of a dam which provided a reservoir with a usable storage of 108,000 acre-feet which is about 150% of the average annual runoff. Eklutna has about 4.5 miles of tunnel that is concrete- lined throughout with an inside diameter of 9-feet. An additional 1/4 mile of 7 to 8 foot steel and concrete- lined penstock tunnel makes a total length of about 4.75 miles which represents about 6300 kw per mile of waterway. This tunnel survived the 1964 earthquake with minor damage except at the intake where the structure shifted and allowed large amounts of backfill and misc- ellaneous debris to be flushed into the tunnel and effectively reduce water flow so that output of the plant was severely restricted. About $500,000 was required for clean-up. Cooper Lake has about 1 mile of tunnel that is mostly un-lined with an inside diameter (horseshoe) of ll feet. An additional 1 mile of 7-foot diameter steel pipeline and penstock buried in an excavated trench makes a total length of about 2 miles which represents about 7500 kw per mile of waterway. The above recitation of numbers and descriptions of comparative data is believed to demonstrate that "hindsight" may have considerable potential value if it is used fairly and openly when considering new projects. The impact of various alternate schemes for development of Alaska hydro- electric projects needs the maximum relevant input of the \ total Alaskan experience. Alaska Experience - Transmission Hydroelectric projects almost always require that the electricity they generate be transported from the site to the loads they will serve - usually some distance away. Hence, the transmission line becomes an absolutely necessary adjunct to a typical hydroelectric project. Alaska has also accumulated substantial experience in the transmission of electric power, much of it requiring innovation to solve peculiarly Alaskan problems. A wealth of experience has been accumulated by the utilities and pro- fessionals of Alaska which include those men of the pioneer entities such as the Alaska-Juneau Mining Company (now Alaska Electric Light & Power Company), the Fairbanks Exploration Company (now U.S.S. R & M Co.), the CAA (now the FAA), the Corps of Engineers, and others who were faced with solving a myriad of technical problems, including the transportation of electricity over permafrost, under water, over water, over mountain passes, through heavy timberland, and under all extremes of weather. 4-18 A brief listing of accomplished projects and proven techniques would include: Ly) 2) 3) 4) 5) De-icing of lines while in service using circulating currents of reactive power interchange between plants. (A-J Sheep Creek-Annex Creek line in service since about 1916). Wood Pole transmission lines built across broad areas of permafrost to supply gold mining dredges and pumping facilities at Nome and Fairbanks (F.E. Co.) Wood pole communication and power lines constructed in permafrost, muskeg and other materials throughout Alaska in support of airport facilities (CAA). Wood pole, H-frame, transmission construction with high- strength aluminum crossarms to provide strength for high wind and ice loads in mountain passes at elevations to 3700 feet (Chugach Electric Association [CEA]). Guyed-Y aluminum transmission towers for 138 kw used across the broad Nenana plains with foundations on perma- frost and special anchors screwed into the frozen ground for support and guying. This design has survived the changing dimensions of seasonal and permanently frozen 4-19 6) 7) 8) ground. The Cold Regions Research and Engineering Lab (CRREL) of the Corps of Engineers participated with Golden Valley Electric Association (GVFA) in testing permafrost anchors. Guyed-xX hinged aluminum transmission tower for 138 kv and 230 kv service used across muskeg swamp, timberland and flood plains with river crossings up to 1800 feet in length on 125-foot towers (CEA). This design, using a balanced guying scheme has proven to be a successful survivor of extreme frost generated movements of earth and flood eroded footing deflections. Use of high-strength aluminum-jacketed steel cables for long over water crossings of the fjords on the south side of Kachemak Bay with spans up to 4,135 feet (across Sadie Cove) by the Homer Electric Association (HEA), and flat profile river crossings for minimizing aircraft hazards and still providing fishing boat clearances on the Naknek River a 2000-foot span (Naknek Electric Association [NEA]). A low profile crossing of the Susitna River near Talkeetna to reduce visual impact and aircraft hazard -- 1894 feet by the Matanuska Electric Association (MEA). High voltage (138 kv), solid dielectric, single con- ductor submarine cables 22,000 feet long plowed 12-feet 4-20 9) 10) a) 12) deep beneath the shipping lanes of the Knik Arm approach to the Anchorage Port (CEA), and 3-conductor, oil-filled paper, lead covered submarine cables of 138 kv voltage across the same general area of Knik Arm (CEA). A 3-conductor, 25 kv cable of about 20,000 foot length, laid from a single reel across Kachemak Bay to the Homer Spit by HEA. A 12.5 kv, 6000-foot submarine circuit across the rock ridged channel between Kodiak Island and Woody Island - where the cables were hand-placed by divers in some areas of ragged underwater terrain by Kodiak Electric Association (KEA). Ground lay, 3-conductor 15 kv armored cables in lengths of about one mile have been used in areas of severe icing and wind on mountain tops (KEA) (Corps of Engineers). Messenger-supported, 15 kv shielded cable suspended in trees through heavily timbered areas. ‘This minimizes clearing, reduces visual impact and provided a reliable electric line where trees are suitable for this use (KEA and HEA). There have, of course, been instances in which Alaska experience in transmission line design, construction, or operation has been less than satisfactory. The most notable of these is probably the line between Snet- tisham and Juneau, where the routing chosen (after a bitter contest between environmentalists and project engineers) has been exceedingly vulnerable to high winds, and has failed frequently. In addition to this actual Alaskan experience, there are sone interesting and promising concepts for clectric transmission being seriously studied by Alaska professionals for potential applications in areas of Alaska that have not yet found feasibility for interconnecting dispersed load centers in the Northwest, Southwest, and Southeast areas of Alaska. These schemes are described briefly as follows: a) A single-wire-ground-return (SWGR) electric circuit using the earth as a return conductor. This idea has been applied to thousands of miles of line around the world and is currently under study by the Alaska Power Administration in regard to possible use for transmitting energy with substantial savings to wide- spread villages along the Lower Kuskokwinm. b) A new submarine cable design utilizing a high strength electrical conductor to provide both strength and electrical conductivity is being reviewed for its potential in reducing circuit costs by eliminating the need for armor on the cable in deep water. This could provide some opportunities for inter- connection and/or water routes from selected hydro- projects which are separated from load centers by rugged, difficult terrain in Southeastern Alaska. 4-22 c) A ground-lay/underground transmission system 26 miles in length has been studied in-depth to determine the feasibility for connecting a 6000 kw hydro-electric project to a community on Kodiak Island. This study showed significant advantages over more conventional systems where heavy timber and unusually heavy ice and wind load conditions prevail. Other Generating Technologies There are numerous other available or potential generating technologies. Among these are nuclear plants, geothermal conversion units of several kinds, wind, direct solar energy, tidal power, and fuel cells. These technologies will. probably only have limited practical application in Alaska during the period under study in this analysis. The availability of geothermal sites, solar conversion possibilities, wind power and tidal power sites is discussed in the following chapter. Two variations on normal fossil fuel generation, coal gasifi- cation and solid waste generation, are treated in an appendix, as are the technologies for geothermal, nuclear, and fuel cell power. Separate appendices also discuss the economics of interties between load centers in Alaska and submarine cables, and compare the feasibility of transmission lines with oil, gas, and geothermal pipelines. FOOTNOTES The foregoing discussion of the effects of enclosure requirements and low-grade coal was furnished by Thomas R. Stahr, manager, Anchorage Municipal Utility System. Strictly speaking, the falling water is costless only if it has no al- ternative use, for example as fish habitat, which must be sacrificed in order to generate power. Thomas R. Stahr (Manager, Anchorage Municipal Light and Power) comments: "As noted [in the Electrical World "19th Steam Station Cost Survey"] the average unavailability for the 20 newest units 500 MW and over was 27.6%; the corresponding figure for the low grade coal burning plants was 28%. The unavailability figures refer to the percentage of the hours during the year the plant is unavailable for any power production. The correspond- ing figure for a hydro unit would be around 5% to 8%, but a hydro plant, which usually has several units, would be considerably more reliable than a single hydro unit. In fact, for a hydro plant to be totally unavailable is extremely rare. Therefore, when comparing hydro and thermal systems it is necessary to account : fort the greater reliability of hydro, especially so in the case of the Corps of Engineers designs for the Upper Susitna, because that system is conservatively designed. "To properly evaluate the reliability factor would require analysis of the likely generation mix which would be available at any given time, which,of course would be dependent upon the cumulative load growth and generation options previously selected. However, without going into that detail,certain salient facts can be observed. a If the large hydro plants were built, there would be more than ample back-up thermal capacity during the first decade or so of their life. This would be the generation used to supply the area load before the hydro went on line. Even if this were very high cost generation, such as oile-fired gas turbines, it would have an insignificant effect on overall energy costs due to the short time it would be used. Therefore, for the purpose of this study there need be no extra costs assigned to the hydro alter- native due to plant unavailability. ‘2. If the thermal option is selected, there would be no incentive to install any more capucity than necessary because the major cost items, fuel and labor, will escalate at essentially the same rate in any case. Therefore, it will be at least necessary to have back-up capacity to cover a forced outage on the largest unit. 4-2) FOOTNOTES (Cont. ) For the Anchorage area, considering the coal alternative this would be 200 MW. If we assumed all the load supplied from 200 MW units the extra capacity required in 1985 would be between 14% and 25% based on the high and low growth rates respectively. Obviously considering a realistic generation mix and possible intercon- nections with Fairbanks would alter the required margin some- what. Considering the national statistics for well interconnected thermal systems it is doubtful if a reserve capacity significantly less than 25% of total system load would guarantee adequate re- liability. Therefore, both firm capacity and availability consid- erations indicate the need for 25% excess capacity if the coal-fired thermal option is selected. This extra capacity is required ca peak so it is not included in the 55% load factor assumption. (Letter to Tussing, May 10, 1976) 4 Robert J. Cross (Acting Administrator, Alaska Power Authority) comments on this section: "Alaskan experience in hydro development since about 1950 includes Eklutna, Cooper Lake, Blue Lake near Sitka, Silvis Lake near Ketchikan, Purple Lake near Metlakatla, and Blind Slough project near Petersburg, Chatanika near Fairbanks, and Snettisham. The record includes several design failures and instances of costly rehab work which can be attributed to design problems. It points up the difficulty of providing adequate maintenance for small projects in small power systems. The record suggests serious needs for more careful attention to designs. "The comparison [between Eklutna and Cooper Lake] seems to us very mis- leading, particularly in the inference that the difference between the two results from a learning process. For example, tunnel lining is often justifiable because of energy savings over the life of a pro- ject. "I think it is fair to say the Eklutna designs are somewhat more con- servative than for Cooper Lake, and therefore more costly. Eklutna construction encountered one serious unforeseen problem--the tunneling crews ran into a very costly water control problem. I doubt very ser- iously that a solid case could be built to demonstrate that long-term economics of Eklutna are less favorable than Cooper Lake." (Letter to Tussing, May 14, 1976) V. ELECTRIC ENERGY RESOURCE INVENTORY This section is a review of energy resources available in Alaska for electricity generation. Oil and gas, oil shale, and coal locations are indicated, with estimates of the volumes of these resources in place, and the feasibility of their use for electricity generation. Potential hydroelectric and geothermal sites are also discussed, along with alter- native technologies, such as wind, tidal, and solar power. Engineering studies making up our greater portion of this review were prepared by Robert W. Retherford and Associates, and Stefano-Mesplay and Associates, Inc., of Anchorage. This regional treatment of Alaska's energy resources focuses on elec- tricity supply and demand issues which have been raised in different parts of the state. The conclusions reached are summarized later in this report. There are several ways in which the use of a given resource may be judged feasible or unfeasible. The opinions of technically qualified in- dividuals may differ as to the appropriate weights to give various possible criteria, as may the opinions of laymen. However, the objectives of this study reflect a concensus that resource development costs should be mini- mized and that the pace of development should be consistent with the needs of the community. Therefore, this study considers most resources which can now be identified, rejecting from immediate consideration those resources for which development technologies are immature, which would require un- economical long distance transmission of electricity, or which are clearly 5-1 ot an inappropriate scale for use by present and anticipated electrical load centers through 1995; some of these resources may be suitable for development after 1995. This study also considers the potential environ- mental impacts of development of a given resource; for example, the Rampart hydroelectric project was rejected partly because of unacceptable environ- mental damage. Legal constraints are important in some cases, and these were explicitly used to reject the use of resources located on restricted lands. Because the criteria used to limit resource alternatives are gen- erally accepted, and departure from these criteria would likely lead to exceptionally high development cost, this prescreening process is believed to have identified the set of resources which is most feasible for further study and planning. Inventory of Regional Energy Resources A. Oil and Gas Resources Inventory This inventory shows the location and estimated amounts of oil and gas in place, regardless of access, quality, ownership and present development status. The following are estimated or speculative order-of-magnitude volumes of hydrocarbons in place: Region 1. Anchorage 2. Southcentral 3. Northwest 4. Interior 5. Southwest 6. Southeast 7. Fairbanks Oil Gas (Million Bbl.) (trillion cf) 250 1.84 12,350 90.21 40,070 201.36 5,180 23.31 15,850 105.83 2,200 16.05 aioe euioues Source: Adapted from State of Alaska Department of Natural Resources, Division of Geological and Geophysical Survey, Alaska Open File Report 50. (See Appendix E for map. ) These volumes are subject to the previous feasibility criteria and are not all available for exploitation. Oil and Gas Development Offshore leasing has begun in the Interior Department's Offshore Con- tinental Shelf Program; an accelerated leasing schedule has been established with Cook Inlet and the Gulf of Alaska now in negotiation. This schedule first projects leasing in southern offshore areas, followed by a northerly rotation around the state's coastline, with Chukchi Sea areas offered for lease in late 1978. This program indicates a planned fast pace of develop- ment for offshore oil provinces, resulting from Presidential orders to lease 10 million acres of offshore oil lands by the end of 1975.2 A fur- ther major factor which could affect the total state petroleum resource outlook would be development of the National Petroleum Reserve (formerly Naval Petroleum Reserve No. 4) by the Federal Government. While a modest drilling program by the U.S. Navy (to be transferred to the Interior Department in 1977) is now underway, there is presently no legal authority for development or production of oil in the reserve. Alaska is currently regarded to have six offshore oil provinces and eight onshore provinces. As a result of present land use classifications, all but 6 percent of the acreage of these onshore oil provinces are at this time closed to development. Land use classifications are based on various existing and proposed land uses by Federal, State, Native and private concerns. Land availability is restricted subject to the estimated time requirement for settling dis- putes over land ownership and use. Using Alaskan Open File Report No. 50 as the best document to base predictions, the following facts concerning onshore oil provinces are apparent: 1. 4 percent immediately open for development 2. 19 percent open for development in one to five years 3. 35 percent open for development in five to ten years 4. 42 percent closed to private oil and gas development indefinitely The 4 percent open to oil and gas development immediately encom- passes the Cook Inlet Basin province and the developed field at Prudhoe Bay with all others being closed to development. Under these prediction guidelines, the regions immediately affected by the resource potential thus developed are the Northwest Region and the Southcentral Region of the state, as indicated below: Is the Resource a Reasonable Alternate for a Regional Oil and Gas Province Power Source? * Offshore 1. Beaufort Yes, if leased by 1980 2. Chukchi No 3. Hope No 4. Bering Sea No 5. Kodiak Island No Gulf of Alaska Yes, if leased by 1980 Onshore 1. North Slope Yes 2. Kotzebue No 3. Koyukuk No 4. Bethel No 5. Bristol Yes, if leased by 1980 6. Yukon Kandik No 7. Copper River No 8. Cook Inlet Yes 9. Tanana, etc. No * Appendix F contains the "Resource Alternate Selection Criteria" detailing the selection procedure. 5-5 B. Coal Inventory Volumes of coal estimated by region and their energy values are as follows: Approximate Electric Region Volume Heati Value Energy Potential (Million Tons) (BTU/LB. ) (Billion Kwh @ 11,000 BTU/Kwh) Anchorage and Southcentral 2,849.9 21,500 5,184 Fairbanks and Interior 104 134.0 16,000 151,465 Northwest 873,498.6 10,000 1,588,178 Source: Adapted from Alaska Department of Natural Resources, Division of Geological and Geophysical Survey, Alaska Open File Report 51. (See Appendix E for map.) Coal Development In 1913, Alaska coal reserves were estimated at about 22 billion tons; in 1946, this estimate was increased to about 96 billion tons; in 1967, it was increased to 130 billion tons. In 1975, total recoverable coal resources were estimated at 132.9 billion tons. Hypothetical (undiscovered coal) resources of 1.9 trillion tons, brings the latest estimate of Alaska's ultimate coal re- source to two trillion tons. Major coal beds are located in the Interior, Northwest, and Southcentral regions of the state. Other occurrences and small fields are scattered through- out the state. 5-6 The Alaska Division of Geological and Geophysical Survey shows that the above quantities of coal lie within 41,522 square miles of onshore land and 4,389 square miles underlying contiguous offshore areas along the western Arctic coast and in Cook Inlet. Coal deposits in Northwest Alaska contain an estimated 975 billion tons, but at the present time, they are classified as closed to development. Fields located in South- central Alaska are mostly on state patented lands, and are immediately open for development. Alaska coals are graded from lignite to fittenincues Heating value (BTU/1b.) varies with location from 6,000 to 14,000 BTU/1b. At this time, Alaska's total coal production comes from surface mining in the Nenana coal field by Usibelli Coal Mines Corporation. The Fairbanks-Tanana Valley area utilities consumed approximately 700,000 tons in 1973.9 Coal mines in the Wishbone Hill district of the lower Matanuska Valley were forced to close in 1968 when Anchorage area utilities converted to cheaper natural gas fuel. The Alaska Open File Report 51 shows the following land development classifications in known coal areas: 1. 47 percent closed to all mineral entry.4 2. 1 percent closed but could be opened by the Secretary of the Interior. 3. 3 percent highly restricted to mineral entry. 4. 18 percent open immediately. 5. +17 percent open within one to five years. 6. +17 percent open within five to ten years. 5-7 Under these guidelines, the regions which may be affected by coal resource potential for electricity generation are Southcentral, Anchorage and Fairbanks, as follows: Coal Field 1. Northern 2. Nenana 3. Jarvis Creek 4. Matanuska 5. Susitna 6. Kenai 7. Bering River 8. Herendeen Bay 9. Chignik 10. Unga Island 11. Broad Pass 12. Eagle) Is the Resource a Reasonable Alternate for a Regional Power Source? No Yes No Yes Yes Yes No No No No No No In particular, the major coal deposits located in the Susitna and Beluga fields are considered important long range resource alternatives for electric power generation in the Southcentral and Anchorage regions of the state. Appendix F contains the "Resource Alternate Selection Criteria" which describes the detailed selection procedure. Golden Valley Electric Association's cost for mine-mouth coal at its Healy plant has increased during the last three years as follows: Year Cost (per Million BTU) 1973 34 cents 1974 47 cents 1975 71 cents The most recent cost of 71 cents per million BTU or $12.50/ton was used as a base for escalation in estimating coal fired generation costs for this study. C. Oil Shale Inventory The following are estimated and speculative order-of-magnitude volumes of oil shale in place between 68 degrees and 69 degrees North Latitude, in Northwest and Northern Alaska. All volumes shown are within the National Petroleum Reserve (formerly Naval Petroleum Reserve No. }). Region Equivalent Oil (Million Bbl.) 1. Northwest 9,810 2. Northern 1,090 Sources: Federal State Land Use Planning Commission, Alaska Regional Pro- files; "Oil Shale Estimates for Naval Petroleum Reserve No. 4," prepared in the Conservation Division, U. S. Geological Survey. Oil Shale Development Oil shale is a fine-grained sedimentary rock that contains sufficient hydro- carbon to yield ten or more gallons of oil per ton, when properly processed, Most oil shales of commercial interest yield from 25 to 65 gallons of oil per ton. 5-9 In processing, oil shale is heated in a retort to about 900 degrees F.; some of its organic material then liquifies, and gases form when this liquid is heated to higher temperatures, These gases can be condensed to form oil, with a'‘hydrocarbon gas byproduct. From 25 to 75 percent of the organic matter in oil shale can be converted to oil and combustible gas by this means, The remaining carbon in the organic matter forms combustible char or coke. Although no satisfactory technique of in sito extraction of oil shale (processing directly within the rock formation) has yet been developed, some such technique is likely to have greater economic potential than the mining and resorting technique, because it avoids the necessity of moving large volumes of overburden, ore and spent rock. Oil shale deposits in northern Alaska were discovered in the nineteenth century although the oil shale appears to have been used for fuel by Eskimos in prehistoric times. The substance was called ‘‘wood’’ by the Natives and was hard, brittle, light-brown in color, very light weight, and burned readily, giving out quantities of gas. Tailleur (1964) reported oil yields of 146 and 144 gallons per ton from two rich samples of marine shale from northern Alaska; oil yields of about 25 to 50 gallons per ton were obtained from five other samples; and one sample yielded seven gallons per ton. Oil shale deposits are widespread in a belt of intensely and complexly deformed rocks north of the front of the western and central Brooks Range. These oil shale deposits lie in a belt along the southern edge of Naval Petroleum Reserve No. 4, through Northern and Northwest regions of Alaska. Alaska’s oil shale deposits are very remote from probable markets and suffer the same lack of serious large scale development interest as deposits in the other states. Promising oil shale deposits in the U.S, Rocky Mountains have not been 5-10 developed commercially, nor was any great interest shown in these deposits at a recent sale. In addition, techniques used in recovery of hydrocarbons from oil shale are now considered to be an immature technology when compared to oil and coal refining processes. It also appears at present that greater and better quality fuels may be developed from oil and coal at the same cost of exploration and production. Due to handicaps of high cost and immature technology, it is expected that other oil and gas resources must approach depletion before oil shale development becomes economically feasible. Therefore, it is believed that fuel obtained from oil shale will not be of practical value for electri- city generation within the time frame of this study. There is a remote possibility that a breakthrough in in sito extraction techniques might make economic some of the richest ores located near the trans-Alaska pipeline. For reference, however, an order-of-magnitude estimate of potential oil shale resources lying within the NPR-4 is as follows: Area Quadrangle Sq. Miles Acres Kiligwa River Howard Pass 1,019 652,160 Etivluk River Killik River 165 105,600 The average specific gravity of National Petroleum Reserve shale is the approximate equivalent of lignite or about 1,700 tons per acre-foot .° On this basis, the NPR oil shale resource can be roughly estimated as follows: 60 gal/ton x 1,700 ton/af = 100,300 gallons per acre-foot 100,000 gal/af + 42 gal/bbl = 2,400 barrels per acre-foot 2,400 bbl/af x 6 ft. thickness of shale = 14,400 barrels per acre 14,400 bbl/ac x 640 acres = 9,216,000 barrels per square mile 9,216,000 bbl/sm x 1,184 sm = 10,911,744,000 barrels total reserve 5-11 In summary, it is concluded that although it may be a substantial and someday valuable resource, NPR oil shale is not a reasonable al- ternate regional power source for the study period. Appendix E contains the "Resource Alternate Selection Criteria" which describes the selection procedure in detail. D. Geothermal Inventory The following geothermal areas are locations of thermal springs and/ or volcanos used as indicators for geothermal development: Geothermal Region Development Areas 1. Anchorage None 2. Southcentral 19 Locations 3. Northwest 7 Locations 4. Northern 13 Locations 5. Southwest 2 Locations 6. Southeast 11 Locations 7. Fairbanks 2 Locations Sources: Federal-State Land Use Planning Commission, Alaska Regional Pro- files; Robert R. Coats, Volcanic Activity in the Aleutian Arc, Geological Survey Bulletin 974-B (Govt. Printing Office, 1950); D. F. White and D. L. Williams, eds. Assessment of Geothermal Resources of the United States, 1975, Geological Survey Circular 726, 1975; "Distribution and Chemical Analyses of Thermal Springs in Alaska," Thomas P. Miller Open File Map, 1973. 5-12 Geothermal Development Geothermal energy is heat energy from the interior of the earth. There are four major types of geothermal systems: hot water, vapor domi- nated, geopressurized reservoirs, and hot dry rock systems. Geothermal generating plants require a greater amount of fluid than conventional power plants to generate the same amount of electricity. This is due to the fact that the lower steam and hot air temperature and pressures naturally associated with geothermal power plants reduce the thermodynamic efficiency of the plant. Appendix E shows there are currently 54 locations where the possibility of geothermal power could be developed. These locations have two indica- tors which show geothermal possibilities: 1) existence of a hot spring, and 2) existence of calderas. A state-wide overview shows basic volcanic indicators on a band from the Anchorage-Valdez areas through the Aleutian Chain. Another major hot spring band lies across central Alaska between 64 degrees and 66 degrees North Latitude. To date, the following geothermal systems have been identified in Alaska: 1. No vapor-dominated systems 2. 88 volcanic calderas 3. Hot water conversion systems A. Four each above 150 degrees C. B. Twenty-four each from 90 degrees C. to 150 degrees C. 5-13 It will be necessary to conduct extensive additional field surveys followed by drilling programs before these resources can be adequately evaluated. ‘This must be followed by an economic study which would com- ' pare the alternate methods of energy generation at a particular location. In general, due to relatively high construction costs in isolated areas of Alaska, it would appear that development of geothermal resources in outlying areas will be limited compared with other possible means of energy generation for the next few years. The cost of long range trans- mission would indicate that major emphasis should be initially concentrated in areas close enough to established electrical loads, resulting in a higher probability of developing economically competitive systems. This could provide a basis for developing geothermal expertise in Alaska with pos- sible future expansion into more remote areas. As indicated below, prime geothermal potentials for near term develop- ment are located in the Southcentral and Northwest Regions. Is the Resource a Reasonable Geothermal Locations Alternate for a Regional / (By Region) Power Source? 1. Anchorage ; No 2. Southcentral No, Possible Adak & Mt. Drum 3. Northwest Yes, Elim & Pilgrim Springs 4. Northern No 5. Southwest No 6. Southeast No 7. Fairbanks No Note: Appendix F contains the "Resource Alternate Selection Criteria" which shows the detailed analysis of the selection procedure. Source: Same as previous table. 5-14 E. Regional Hydroelectric Resources It is well known that Alaska has extensive hydroelectric resources. At least 400 potential hydroelectric sites have been identified, and many of these have been studied to some degree. Potential sites range in esti- mated prime capacity from a few kilowatts to the 3,900,000 kilowatts esti- mated for the Rampart site on the Yukon River. It is possible that a very substantial majority of Alaska's hydro- electric sites may not be considered suitable for development at any time in the future, for technical, economic, and environmental reasons. Within the period covered by this study, extending through 1995, development of only a small number of sites may be projected, using the following criteria: 1. Sites must be located within a technically and economically feasible transmission range of existing and projected load centers. This criterion was applied prior to the preparation of project cost estimates, using typical design criteria and an order-of- magnitude cost factor per unit of required transmission. As a result, projects were selected within relatively short radii of indicated load centers. Most of the smaller sites indicated by this means are within 20 miles of the target load center, al- though a few are as remote as 40 miles. The Susitna project, on the other hand, is located 135 miles from Anchorage and 190 miles from Fairbanks, which are feasible transmission ranges for a pro- ject of this relatively large size. 2. The capacity of sites designated for development must be con- sistent with electricity demand of target load centers. This criterion was applied pending the results of the study's economic analysis. In order that no reasonable site be excluded from that analysis, the largest individual sites designated would satisfy the total capacity requirements of their target load cen- ters through 1995. It is recognized, however, that unless pro- ject development cost is extremely low, the cost of electricity 5-15 produced by most self-supporting, hydro projects will not be competitive if their capacity cannot be fully utilized within n ‘= bo 10-year load growth period. 3. Sites designated may have no previously identified or other- wise obvious adverse environmental impacts which would weigh against their benefits to the community. This criterion does not imply that the environmental impact of any project were measured in economic terms, or balanced dollar for dollar against the economic value of electricity supply to the community. However, in some cases, such as Rampart, signi- ficant environmental impacts have been identified and in a number of other cases, it was evident that projects would conflict with established commercial fisheries, or wilderness area designations. These factors excluded possible sites in the Rudyerd Bay and Stikine River areas of Southeast Alaska, the Wood River Lakes and Kvichak River areas of Southwest Alaska, as well as others. It is evident that these selection criteria provide an ample number and capacity of potential hydroelectric projects for development through 1995. Further, they provide that the designated key projects are the most deserving of further study and planning as practical additions to regional power systems. The following list designates 36 key hydroelectric project sites with estimated prime capacity of one million kilowatts as summarized in Table 5.1. These key projects are described in greater detail in Appendix H and are evaluated in the economic section of this study. The results of the economic evaluation determine whether a parti- cular key project should be given priority in a given locality's power system planning. The number and size of key projects listed by area does not imply the amount of capacity which is recommended for development in that area, nor does it represent the area's total hydroelectric resources; key projects 5-16 are regarded as the first usable projects for each area covering the time frame of this study. For both the Juneau and Anchorage-Fairbanks areas, it was necessary to list only one key project which has previously been determined feasible and which is capable of staged development through 1995. For most other areas, it was necessary to list several available sites, any of which may subsequently be ruled unfeasible. The list of key projects excludes several which have been proposed prior to this study. The exclusion of Rampart on environmental grounds has already been noted; however, that project would not meet this study's transmission and capacity criteria even if it were environmentally ac- ceptable. Yukon-Taiya is also excluded by transmission and capacity criteria, and because its environmental impacts are considered potentially serious. Other major projects which have been excluded are discussed fur- ther in this section. In preparing the project descriptions and order-of-magnitude cost estimates included in Appendix H, the study's hydraulic engineers, Robert W. Retherford and Associates, first collected all prior reports and re- search data on each key site. In some cases, this data more or less con- clusively proved the technical and economic feasibility of a given develop- ment scheme; however, in other cases, only site reconnaissance data was available. The engineers reviewed existing development schemes where applicable, in some cases projecting revisions; in addition, they prepared indicative development schemes for projects which previously had received little study. Order of magnitude project costs were estimated using common 5-17 development standards and unit costs, with regional variations. It is believed that the results of this analysis are a realistic ranking of potential hydroelectric projects, offering a sound basis for preliminary choice between alternative sites, and also for comparing the economy of hydro resource development with alternative generation systems. As shown in Table 5.1, designated key projects range widely in scale and cost. In particular, it is evident that many relatively eco- nomical small projects may exist, and that economies of scale are not necessarily present in larger projects. The lack of economics of scale is partially attributable to transmission cost. Smaller projects, because of their more frequent occurrence, are often located within a shorter dis- tance of load centers. In addition, the cost of many smaller projects benefits from minimized site access, logistics, and civil construction requirements. These factors may produce severe diseconomies of scale under the torturous terrain conditions present in and near many Alaskan hydro sites. The absence of economies of scale has also been demonstrated in the two most recent hydroelectric projects constructed in Alaska. The Snet- tisham Project was constructed by the Corps of Engineers during the late 1960's and early 1970's and was completed at a prime capacity of 19,200 KW and total capital cost of $67,500,000 or $3,516 per prime KW. The Upper Lake Silvis project was constructed by Ketchikan Public Utilities in the late 1960's, with a prime capacity of 1500 KW. Original total construction cost for plant and transmission was $2,100,000; however, the project was 5-18 later substantially destroyed by a spillway failure, resulting in further net spending of $1,600,000 to recommission it in 1976. Total investment in this project is, therefore, $3,700,000 or $2,467 per prime KW. Capacity of the Upper Lake Silvis project is less than 8 percent that of Snettisham; 6 however, its cost per prime KW is 30 percent lower. The fact that economies of scale cannot be relied upon to yield cheaper power has an important bearing on the concept of how hydroelectric development should be financed in Alaska. If economies of scale were al- ways present, then a project which strained a local utility's financial resources to the maximum, or which required State or Federal assistance, could always yield greater benefits to the community than a small project which a local utility could perhaps afford. This is evidently not true. This study's hydroelectric resource inventory identifies a substantial number of relatively economical small projects. Therefore, pending fur- ther economic analysis it suggests that there may be substantial room for local self-help in developing usable and economical hydroelectric power. 5-19 Table 5.1 CAPACITY AND COST OF KEY HYDROELECTRIC PROJECTS : Prime Capacity (KW) Energy Total Region/Area/Project Installed Prime (MWH) (000$) Anchorage-Fairbanks Susitna Project ;: Watana 792,000 353,880 3,099,988 2,297,700 Devil’s Canyon 776,000 344,750 3,020,010 1,234,100 Total 1,568,000 698,630 6,119,998 3,531,800 Southcentral—Anchorage— Fairbanks—Cordova— Valdez—Glennallen Tebay Lakes 64,000 30,150 264,114 -- Power Creek 12,000 3,725 32,631 11,610 Sheep River Lakes 4,000 2,540 22,250 6,590 No Name Creek 5,000 2,550 22,338 3,970 Solomon Gulch 12,000 4,440 38,877 19,972 Total 97,000 43,405 380,210 Kenai Peninsula Nellie Juan Lake 40,000 21,000 184,000 45,555 Snow River 60,000 31,900 279,000 57,705 Bradley Lake 125,000 51,400 450,000 89,835 Total 225,000 104,300 913,000 Kodiak Terror Lake . 20,000 7,220 63,250 40,370 Southeast Metlakatla Purple Lake Rehabilitation 1,400 400 17,520 1,134 Hassler Lake 4,000 2,000 16,980 6,830 Total 5,400 2,400 34,500 Ketchikan : Upper Mahoney Lake 10,000 4,700 41,172 9,035 Swan Lake 15,000 7,700 67,500 32,980 Lake Grace 20,000 11,000 94,000 39,351 Total 45,000 23,800 202,672 Petersburg-Wrangell Anita 4,000 2,100 18,396 5,871 Anita and Kunk Lakes 8,000 3,830 33,550 9,128 Virginia Lake 6,000 3,000 26,280 7,070 Sunrise Lake ~ 4,000 2,400 21,024 4,174 Ruth Lake 16,000 7,950 69,660 23,355 Crystal Lake Expansion 2,500 400 3,504 4,400 Cascade Creek I 15,000 5,100 44,781 22,955 Cascade Creek II 36,000 17,900 156,672 21,335 Scenery Lake 18,000 9,100 79,716 22,310 Total 105,500 51,780 453,583 *® All costs calculated based on construction beginning early 1976. ‘5-20 3,117 Capital Cost Per® Prime KW 6,493 3,580 5,055 2,587 1,557 4,498 2,169 1,809 1,748 5,591 2,835 3,415, 1,922 4,283 3,577 2,796 2,383 2,357 1,739 2,938 12,000 4,501 1,192 2,452 Installed KW 2,901 1,590 2,252 967 1,648 794 1,664 1,139 962 719 2,018 810 1,708 903 2,199 1,968 1,468 1,144 1,178 1,043 1,460 1,760 1,530 593 1,239 Table 5.1 Cont. é Prime . Capacity (KW) Energy Total Capital Cost Per® Region/Area/Project Installed Prime (MWH) (000$) Prime KW Installed KW Southeast (continued) Juneau : i 5 : 815 Snettisham Expansion I 27,000 11,758 103,000 22,000 1,871 pains Snettisham Expansion IL - 18,607 162,997 16,000 860 Total 27,000 30,365 265,997 38,000 1,251 | Sitka Lake Irina 3,000 1,790 15,680 3,665 2,047 ee Green Lake 14,000 6,600 57,816 18,050 2,735 "370 Lake Diana 10,000 4,585 40,165 9,705 2,117 ars Milk Lake 16,000 8,000 70,080 18,750 2,321 ra Four Falls Lake 6,000 3,000 26,280 4,265 1,417 45087 Carbon Lake 18,000 6,830 59,832 19,200 2,811 res Takatz Lake 20,000 10,000 87,600 26,600 2,660 , Total 87,000 40, 805 357,453 Haines Unnamed Lake 9,000 4,640 40,640 | 10,435 2,249 : 1,159 Skagway Goat Lake 9,000 4,450 38,982 9,140 2,054 1,016 Total Region 287,900 157,840 : Northwest Unalakleet Anvik River 14,000 6,800 59,568 — 19,725 2,901 1,409 ’ Southwest : Dillingham : Lake Elva 2,500 1,240 10,820 6,690 5,395 2,676 Bethel Kisaralik River 36,000 18,200 159,222 74,485 4,093 2,069 Total 38,500 19,440 170,042 Total Region 1,910,000 853,555 7,477,142 STATEWIDE TOTAL 2,250,400 1,037,635 9,093,187 5-21 Regional Hydroelectric Development Southcentral, Anchorage, Fairbanks Regions. In this region, hydro- electric resources have been identified which would serve the Anchorage and Fairbanks areas as an interconnected system, with a possible further interconnection to the Kenai Peninsula. Additional resources have been identified which would permit development of self-sufficient systems on the Kenai Peninsula and in the Cordova-Valdez-Glennallen area, which with further growth should be capable of interconnection with Anchorage-Fair- banks. The Kodiak area has no foreseeable alternative to electrical iso- lation; a single key hydro project is identified there. Kodiak: Terror Lake is a technically feasible hydroelectric site which the Kodiak Electric Association, Inc., has examined in detail. The primary obstacle to this project is its high cost per unit of prime capacity. However, it does appear that this project is consistent with the future energy needs of Kodiak Island and that it could be developed to optimum scale. Kenai Peninsula: Projects identified in this area include Nellie Juan Lake and Snow River in the peninsula's northeast coastal mountains and Bradley Lake near the head of Kachemak Bay. Each of these is a sub- stantial site, and all are among Alaska's more economical small hydro sites. Although the Kenai Peninsula is now interconnected with the Anchorage area, it may be that this interconnection will become less economical in the 5-22 future, due to rapid load growth in the Anchorage area, and the diffi- culty of expanding transmission either via the present route or via a Turnagain Arm crossing. Cordova, Valdez, Glennallen: Five potential hydroelectric sites have been identified in this area. It is expected that these resources may offer a better alternative to interconnection with the Anchorage- Fairbanks regions in the near term due to the relatively long and difficult transmission route and the relatively small size of this area's load. These projects are summarized in Table 5.1 and detailed in Appendix H. Anchorage-Fairbanks: These two regions are the only parts of Alaska which have sufficient demand projected through 1995 to utilize the capacity of a relatively large hydroelectric project. During the past 15 years, extensive studies have been made of hydroelectric alternatives for this region. These studies have identified several sites on the Upper Susitna River as the resource best located and most compatible in scale with the An- chorage-Fairbanks Regions' demand. These sites, with one exception, can be developed with unusually small reservoir surface area, probably with minimal overall environmental impacts. A Susitna project was currently pro- posed to the U. S. Congress for funding in the Water Resources Omnibus Bill of 1976; however, it is considered improbable that it will receive major Federal funding in the coming fiscal year. Therefore, it is considered that at present, the proposed Federal Susitna project does not offer the Anchorage and Fairbanks regions a viable alternative to present gas and coal fired generation systems. The State of Alaska already has exercised 5-23 some influence over the priorities and technical concept of this pro- ject. In 1974, the state retained the Henry J. Kaiser Company to pre- pare a reassessment of the previous U. S. Bureau of Reclamation develop- ment scheme. This report addressed itself to minimizing the project's environmental impacts by reducing reservoir size, and to improving the project's overall economy by projecting use of a high rockfill main dam. The report concluded that the project could be undertaken by the state and that it would be financially self-supporting from sales of power to Anchorage-Fairbanks utilities. Since the completion of that study, the Corps of Engineers has adopted the concept of a high rockfill main dam, although in a different and more remote location than proposed by Kaiser. For this study, the general project description and cost estimates prepared by the Corps of Engineers are used for the Susitna project. This development scheme projects first stage construction of an 810 foot rock- fill or earthfill dam near Watana Creek, about 46 miles upstream from the Gold Creek station of the Alaska Railroad. The second stage consists of construction of a 635 foot concrete thin arch dam at Devil's Canyon, 15 miles upstream from Gold Creek. Power would be transmitted to Anchorage via a 345 kv double circuit line, and to Fairbanks via a 230 kv single cir- cuit line. Project capacity and cost of plant and transmission are as follows: Watana Devils Canyon Total Prime Capacity, MW 354 345 699 Installed Capacity, MW 796 776 1568 Prime Energy, GWH 3080 3020 6100 Capital Cost $1,088,000,000 $432,000,000 $1,520,000,000 5-2h The Corps of Engineers estimates that four years would be required for preconstruction planning, with 6 years required to complete and com- mission Watana. Devil's Canyon would require an additional 5 years to construct, part of which could be concurrent with Watana construction. For comparison, a brief review of the Kaiser development concept pre- pared for the State of Alaska is as follows: This concept is based on first stage construction of an 800-foot, concrete-faced rockfill dam about 20 miles upstream from Gold Creek. This would be followed by second stage construction of a 185-foot rockfill dam near Portage Creek, 12 miles upstream from Gold Creek. The final stage would be construction of a 600-foot rockfill dam below Vee Canyon, about 65 miles above Gold Creek. Power would be transmitted to Anchorage via a 230 kv double-circuit line, and to Fairbanks via a 230 kv single circuit line. Project capacity and cost are as follows: a oer: EIT Total Prime Capacity, KW 385 90 210 685 Installed Capacity, KW 700 163 4u5 1308 Prime Energy, GWH 3372 785 1840 5997 Capital Cost $638,000,000 $98,000,000 -- -- The Kaiser plan appears to be optimized to least cost of power rather than to maximal regulation, as is the Corps plan; this results in slightly lower capacity, although a larger percentage of available head and water are developed, and substantially lower cost per prime KW. Kaiser's design and cost figures are not complete for stages II and III. Kaiser estimates a seven-year licensing design and construction schedule for Stage I. 5-25 The Kaiser plan is an interesting supplement to the Corps proposal for Susitna, first because it outlines a project comparable in size but substantially less costly, second because it proposes a shorter completion schedule, and third because it indicates the project could be self-support- ing from revenues, thereby enabling state sponsorship without major gen- eral fund expenditures. If state sponsorship is decided upon for the Susitna project, it is evident that at least two recent and contrasting T development options will be available. Key Potential Hydroelectric Projects Southcentral, Anchorage, Fairbanks Regions 1. Total Sites Reviewed - © «© + «© «© «© « « 10 2. Capacity Range of Sites: Installed. . «© © «© © «© «© «© « « « 41568 mw Prime . «© «© «© «© «© «© © © «© « + « 265-788 mw 3. Total Capacity of Sites: Installed - «© © «© © «© © «© 2 « + 1910 mw Prime . .© © © © © © © © «© «© @ 943 mw 4, Range of Estimated Investments in 1976 dollars: Installed »- »+ + «© «© «© «© «© «© «© -¢ 709-2018 /kw Prime . 2. - © © © © © © © # « 1557-5591 /kw 5. Average Estimated Investment in 1976 dollars: Installed. + © «© «© © «© «© «© « + 963.9/kw Prime . e ° e . e . ° . ° ° 1952.2/kw 5-27 Southeast Region. ‘The Southeast region is rich in hydroelectric re- sources commensurate in scale with local electricity needs. Virtually every community in this region has a technically feasible hydroelectric site in its immediate vicinity. Land use and environmental impacts are minimal for most of these sites because, in general, they are small-area, high- elevation, natural reservoirs with high to extreme annual rainfall and runoff. Hydroelectric sites of this general description are both techni- cally and environmentally very desirable. The following table is a summary of the general characteristics of hydroelectric sites in the Southeast Region. In preparing data for key Southeast hydro projects, only those projects capable of serving major electrical load centers were analyzed in detail. Therefore, these key projects are capable of meeting the electricity requirements of the Metlakatla, Ketchikan, Petersburg-Wrangell, Sitka, Juneau, and Skagway-Haines areas, but not smaller potential load centers such as Hyder, Craig-Klawock, and Hoonah. A number of secondary hydro sites, some very small, have also been identified. Due to budget constraints, these were not analyzed in detail, but their existence demon- strates a potential for small scale hydro development to serve most per- manent communities in Southeast Alaska, regardless of population. Second- ary sites are shown in Appendix E. The list of key Southeast hydro projects includes the Federal Snet- tisham project, near Juneau, with present capacity of 19,200 KW prime and 46,700 KW installed. This project is currently planned for a two-stage 5-28 Key Potential Hydroelectric Projects Southeast Region ik Number of Sites Reviewed - - «© «© «© «© «© «© « 22 2. Capacity Range of Undeveloped Sites: Installed . «© «© «© «© «© «© «© «© «© « 1,400 - 41,000 KW Prime a 400 - 30,400 KW 3. Total Capacity of Sites: instal. — $$ =— $$ =—__ = == = 289,900 KW Prime. . . . » © «© +6 «© «© © « » 158,200 KW 4, Range of Estimated Capital Costs in 1976 dollars: Prime Capacity - - + «+ «+ « « « . $1,251/4,501/KW De Average Estimated Investment, in 1976 dollars: Installed . . «© © © «© © © «© «© $1,105/KW Prime . + © © © © © ¢«€ © © © «@ $2,024/KW 5-29 Mederally funded expansion first to capacity of 31,200 KW prime and 73,700 KW installed, and finally to 57,200 prime with no further increase in installed. Two other existing small hydro projects at Metlakatla and Petersburg are also currently planned for expansion and are included on the list of key sites. The potential for minor expansion of an existing Ketchikan hydro plant has been suggested locally but is not evaluated herein. As shown in Table 5.1, the prime capacity of all the Southeast pro- jects selected for further analysis totals 158,240 KW; exceeding 200 per- cent of the region's projected demand growth through 1995; therefore, it is believed that these projects provide an ample basis for selecting alternatives for system development. Northwest Region. Several potential hydroelectric sites exist in Northwestern Alaska; however, there are an unusual number of technical and economic obstacles to hydroelectric development in this region, as follows: 1. Potential sites are relatively large in size compared with local electricity requirements. 2. Sites are sufficiently far from load centers that trans- mission would make up a large percentage of project cost. 3. The topography of most sites restricts available head and would require relatively large-volume dams to realize a minimum energy potential. 4, The hydrology of the region, with its prolonged winter 5-30 drought, requires unusually large storage for year-around operation. 5. The requirement for large storage and the moderate relief of the most sites demand extensive land inundation by reservoirs, with corresponding substantial environmental impacts. 6. Permafrost is often present in damsite areas, requiring extensive excavation to reach competent foundation materials. 7. The severity and length of winter in the region would re- quire special measures both for protection of structures from ice damage, and also to protect downstream areas from winter flooding by winter tailwater discharges. Flooding could be caused by ice damming of tailrace channels or watercourses downstream of the damsite, where winter runoff would be very substantially increased by year-around regulated discharges. 8. Construction of hydroelectric projects in the Northwest would be subject to an extremely short construc- tion and supply season, and very high costs of transporta- tion and labor, imposing serious cost handicaps on these projects. For these reasons, it is concluded that hydroelectric resources may not be practical alternatives for expanding the electric power supply of most Northwest Region load centers during the study period. The most promising site identified in this region is on the Anvik River 32 miles from Unalakleet. It is possible that it could be developed to serve Unalakleet and some neighboring villages. This key project is described further in Appendix H. =31 Southwest Region. This area has two key hydroelectric potentials, although additional technically feasible sites exist, and have been listed in previous hydroelectric surveys by the Corps of Engineers and other agencies. However, the Kisaralik River near Bethel, and Lake Elva near Dillingham, are among the few sites with at least marginal economic merit and of a scale consistent with existing and projected loads within their feasible transmission range. Because this region has many of the disadvantages to hydro develop- ment noted for the Northwest Region, it is probable that alternative modes of generation probably must continue to provide most electric energy in the future. Lake Elva is a small hydroelectric site which could generate energy for the Dillingham-Aleknagik service area served by Nushagak Electric Association, Inc. This site has not been analyzed in detail; however, no conflict with the area's important fisheries resource is evident at this time. Development of the Kisaralik River would include transmission to Bethel and river villages within approximately 20 miles of Bethel. The Alaska Power Administration has investigated an area-wide transmission concept. Conventional three-phase transmission appears economically un- feasible for this area; therefore, a single wire ground return design has been proposed. Characteristics of the Lake Elva and Kisaralik River projects are summarized in Table 5.1. Cost data are reported in detail in Appendix H. 5-32 Other Major Hydroelectric Potentials Chakachamna: Prime Capacity: 183 mw Installed Capacity: 366 mw Prime Energy: 1.6 billion kwh/yr This project is located at Chakachamna Lake about 80 miles west of Anchorage; it has potential for serving Anchorage area utilities. How- ever, prior studies by Federal agencies indicate that the very long power { tunnel may make it economically marginal or unattractive for development. Crooked Creek: Prime Capacity: 1,070 mw Installed Capacity: 2,140 mw Prime Energy: 9.4 billion kwh/yr This project is located in the shallow basin of the middle Kuskokwim River; according to the Federal development concept, it would impound an exceptionally large reservoir, inundating much of the middle and upper Kus- kokwim valley. Its environmental impacts on fisheries, wildlife, and the economic cost of inundated land would be excessive and unacceptable. It is possible that a very low dam on this site or another Kuskokwim River site would impound a reservoir within acceptable limits, and that in ad- dition to power, such a dam could produce important flood control benefits for lower Kuskokwim communities. It is probable, however , that such a 5-33 project could not be justified primarily for power and that it could be very costly due to its need for fisheries mitigation and navigation features. Woodchopper: Prime Capacity: 1,620 mw Installed Capacity: 2,160 mw Prime Energy: 14.2 billion kwh/yr This project would impound a large reservoir on the Upper Yukon River. The reservoir would extend into Canada, requiring an international treaty to enable it. Environmental and fisheries damage could be extensive and navigation features could be required. A significant transmission penalty would be imposed on project cost due to its remoteness from load centers. Yukon-Taiya: Prime Capacity: 2,400 mw Installed Capacity: 3,200 mw Prime Energy: 21.0 billion kwh/yr This project envisions diversion of a major volume of water from the Canadian Upper Yukon lakes to tidewater near Skagway. Such a project pro- bably could only be accomplished as a U. S. - Canadian joint venture. This project's environmental impacts are frequently understated. It would re- quire a dam either just above Whitehorse or near the Teslin confluence, 5-34 either of which would flood a major portion of the Upper Yukon Valley. It would subject the Upper Yukon Lakes first to higher crest levels and second to seasonal drawdown. It would require relocation of existing highways, communities, and other infrastructure. Its diversion of water from the Yukon basin to tidewater would alter the saline water regime of Lynn Canal, possibly with icing and adverse fisheries impacts. It would change the stream flow characteristics of the Yukon River over much of its length and would alter with the impacts of its fresh-water and organic silt discharge into the Bering Sea. Compared to a simple reservoir pro- ject, such as Rampart, its impacts would be very complex, and possibly unpredictable. The large size of this project, and its remoteness from load centers would make it difficult and costly to market its power. Al- though energy intensive industries have been proposed as possible customers, it must be recognized that a very large aluminum smelter, with primary metal capacity of 225,000 tons per year, would consume about 500 mw prime. Four such smelters would be required to utilize about 85 percent of Yukon- Taiya's generation, the remaining 15 percent would be sufficient to serve a community of 500,000 population. Four such aluminum plants must produce and sell 900,000 tons of primary aluminum per year, a very substantial percentage of Pacific Basin demand. These plants would employ about 3,600 persons subject to cyclical layoffs; these would require development of community facilities and services for over 15,000 people; they would generate heavy marine traffic; they would generate significant fluoride, hydrocarbon and thermal pollutants. These factors illustrate that it would be extremely 5-35 tenuous to project an adequate industrial demand base for Yukon-Taiya, and just as difficult to justify such industrial development as being beneficial to Alaska or northern Canada.? Wood Canyon: Prime Capacity 2,500 mw Installed Capacity: 3,600 mw Prime Energy: 21.9 billion kwh/yr This project could damage the fisheries resource of the middle and upper Copper River. This possibility of damage is recognized by Federal agencies, which have set aside the project for the foreseeable future. It must be noted, however, that if Alaska is to grow in population, it will eventually require projects of this scale, either hydro, coal-fired, or nuclear. Wood Canyon and other Copper River projects are reasonably well located with respect to Anchorage and Fairbanks load centers. They are also among Alaska's most economical hydro sites and, in general, their reservoir sizes are moderate. It is probable that further consideration must be given to these projects beyond 1995, and that this will involve the critical balancing of possible damage to fisheries and other environmental impacts against the community's need for power and the desirability of alternative power sources. Rampart: Prime Capacity: 3,900 mw Installed Capacity: 5,000 mw Prime Energy: 34.2 billion kwh/yr 5-36 The unacceptable environmental effects of this middle Yukon River project have been well publicized. Rampart is not considered a realistic potential for development at any future time. It is listed here for scale comparison only. F. The Solar Energy Resource The term solar energy identifies the direct conversion of incident solar radiation to heat or electricity; its potential in Alaska is very poor. The reason, of course, is low incident radiation in winter, when energy needs are greatest, requiring costly energy storage. This, at the present time, reduces or eliminates any economic advantage of using this annie Compounding the limitation of longer twilight and winter darkness is the low angle of incidence of sunlight at all times of the year in high latitudes. The daily solar zenith angle near Anchorage ranges from +55° to +52.5° and near Barrow from -4.5° (below horizon) to +42.5°. This low zenith angle of the sun causes a higher percentage of all incoming solar radiation to be reflected; what is absorbed is distributed over a larger area due to the earth's curvature. It is likely that direct solar energy conversion feasibility, world wide, will be limited to low lati- tudes and tropic regions where solar zenith angles, year around daylight- to-darkness ratios, and cloud cover conditions are more nearly optimal. 5-37 G. The Windpower Resource The hypothetical windpower potential of Alaska, which theoretically could be extracted by wind machines, has been estimated by one researcher ae at 3,400 MW. Considered in these terms, wind appears to be a "free" energy source of great magnitude, merely requiring the erection of simple windmills to harness it to electric generating machinery. A common be- lief is that if a circa 1920 rural farm wind generator could serve a single family, then "windmill farms" of larger machines can serve a city. However, this does not take into account problems of voltage control, energy storage, or windpower technologies' ability to produce the volumes of energy required by any load center. The current technology of wind powered electrical generators has been built upon a long history of windmills dating from ancient times and including European installations of hundreds of years ago, on to the construction of a demonstration 1250 KW wind generator in the United States during the early 19hos. 22 Following the structural failure of this latter unit in 1945, large scale electric wind machinery development was ar- rested in the United States until the 1975 ERDA/NASA development and con- struction of a 100 KW unit now undergoing tests near Sandusky, Ohio. Be- tween 1945 and 1975, other efforts world-wide produced electric wind ma- chines in the 100-300 KW range. The current leader in the United States electric wind machinery re- search is ERDA, utilizing the facilities and staff of NASA and the Lewis 5-38 Research Center in Ohio. The growth of the ERDA wind energy develop- ment fund is spectacular, reflecting the nation's energy consciousness, as seen in the following tabulation: ERDA Wind Energy Development Funding EN | 73 $ 200,000 FY 74 1,500,000 FY 75 7,000,000 FY 76 (requested) 12,000,000 ERDA findings to date indicate that the optimum technical and economic size of windpowered electrical generators may lie between 150 and 300 KW. ERDA/NASA's demonstration 100 KW unit, now being tested is probably not economically competitive with alternative generation sys- tems in most areas because it requires an investment in excess of $5000/KW. The feasibility of such equipment is based on the possibility of system interconnection with utility grids without the need for large scale energy storage. ERDA/NASA have identified interconnection, electric system stability, and wind "farm" spatial distribution as key problem areas in the ongoing development of large scale wind generator systems. Demon- strations systems are planned no sooner than 1980. 5-39 The installed cost of both large and small scale electric wind machinery make them only marginally feasible to unfeasible at this time. Very small scale tower mounted units, range from about $1,500/KW to $4,000/KW depending on manufacturer, auxiliaries, desired voltage con- vertors, and other accessories. If long-term energy storage is required, as it usually is in small scale units, the costs can be substantially increased. Wind energy capture on a large scale requires large intercept areas. This means large propellors which require large supporting towers. The end result is a high capital cost. Because the wind does not blow continuously, either energy storage or the interconnection of wind generators to an alternative electric sys- tem is required. For large scale wind machines, even short term energy storage systems are cost prohibitive. For small scale wind generators, storage capacity for long wind-lull periods is cost prohibitive, and some- times technically impractical. Interconnection of either large or small scale wind systems to electric power grids supplied primarily from an alternative source such as hydroelectric, or fossil-fueled is technically realizable and may be economically feasible. The ERDA/NASA developmental work and experimenta- tion by utilities may lead to practical solutions of the interconnection, interface and stability problems identified in present technology. The largest conceptual ERDA/NASA wind generator is in the 150-200 KW range.+3 This is equivalent to the average size diesel electric generator 5-40 used by many very small Alaskan utilities. However, the largest electric utility turbine units in the state are over 200 times the scale of the largest wind generators proposed by ERDA/NASA. It is possible that economies of scale in the higher capacity ranges may never be attained by wind generation. Coastal regions in Alaska typically have high average winds. Many of the areas and communities which might practically benefit from optimally scaled wind generation systems are also located on or near the coast. This is especially true of Western Alaska, the Alaska Peninsula, and the Aleu- tian Islands. Mean wind speeds for 37 stations in Alaska are shown in Table 5.2. However, mean speeds are only one consideration in determining wind genera- tors practicability; the entire wind regime, velocity by percent of total time for each locality determines the extractable wind energy. Some small scale wind generators have minimum threshold wind velocities below which the quantity or quality of electric energy is degraded or unacceptable. Time percentage wind distributions for selected stations are shown in Table 5.3. Wind energy development in Alaska, at optimum scale for appropriate locations, will likely require public subsidy support to move past the demonstration project level. One approach might be a concerted effort by State agencies and Federal research and development authorities, such as ERDA/NASA, in an Alaska demonstration project. In this manner, the maximum technical and financial resources could be focused on discover- ing whether large scale practical wind generation is possible in certain remote areas. 5-41 TABLE 5.2 NEAR-SURFACE YEARLY MEAN WIND SPEEDS AT VARIOUS ALASKAN LOCATIONS Yearly Mean Speed & Data Anemometer General Area Station (knots ) Period Height (feet) Aleutian Shemya 16.2 1950-72 184-20 Islands Amchitka 18.3 1943-50 2 Adak 13.1 (sh) 1942-65 75-15 Atka 10.9 (sh) 1942-45 ? Nikolski © 14.0 1959-69 30-13 Ft. Glenn © 13.6 1942-48 ? Driftwood Bay 4 8.3 (sh) 1959-69 ? Dutch Harbo: 9.6 (sh) 1946-54 33 Cape Sarichef 13.7 1952-56 i St. Paul © 16.0 1962-71 42 Alaska Cold Bay 14.9 1956-72 88-21 Peninsula Port Moller 8.9 (sh) 1959-59 30-20 Port Heiden 12.8 1942-67 29 Ugashik Under measurement King Salmon 9.6 1956-72 38-20 Source: Tables reprinted from January 31, 1975 report by Dr. Tunis Wentink, Jr., Geophysical Institute, U. of A., (NSF GI 43098). a. (sh): pronounced topographic shielding effects may be involved b. Last value is usually the most recent height. Large horizontal shifts also may have occurred. c. Umnak Island d. Unalaska Island e. Pribilof Island 5-42 General Area Southeast and Gulf of Alaska Kuskokwim and Yukon Rivers and Deltas Norton and Kotzebue Sounds, Seward Peninsula Northwestern and Northern Coasts Fairbanks (interior) f. Interior location g. St. Lawrence Island h. Barter Island TABLE 5.2 (continued) Yearly Mean Speed a Station Annette Island 9.5 Juneau Yakutat Cordova Middleton Isl. Kodiak Cape Newenham Cape Romanzof Bethel McGrath f Koyuk Moses Point Nome Northeast Cape® Tin City Kotzebue Cape Thompson Pt. Hope Cape Lisburne Barrow Kaktovik » Fairbanks 7.4 7.0 44 11.9 8.9 9.8 11.7 11.2 4.3 9.5 10.6 9.5 11.0 14.9 11.1 17.4 10.7 10.5 10.6 11.2 4.3 5-43 (mots ) (sh) (sh) (sh) Data Period 1942-70 1948-70 1941-70 1946-70 1945-63 1946-69 1953-70 1953-70 1958-72 1949-73 1944-45 1945-67 1955-73 1952-69 1953-70 1945-70 1960-61 1945-48 1953-70 1945-68 1945-70 Anemometer Height (feet) 53-20 b 32-37 59-20 36-20 30-20 60-16 30-13 15-11 63-20 26 75-21 30-13 31 13 39-31 27-20 sos TIME PERCENTAGE OF SELECTED WIND VELOCITY RANGES IN ALASKAZ Location Adak NS Amchitka AFB Cape Lisburne AFS Cape Sarichef AFS Cold Bay? Driftwood Bay AFS Dutch Harbor NS Kotzebue? Nikolski AFS St. Paul Island? Shemya AFB Tin City AFS Annual Mean, Knots 13.1 18.3 10.5 13.7 15.1 14.9 8.3 9.6 11.1 13.9 16.0 15.7 16.2 14.9 TABLE 5.3 % of Time below 7 knots 22.9 9.2 35.0 24.0 12.0 41.2 39.8 23.3 24.5 6.9 13.0 % of Time at 7-21 knots 60.9 60.1 55.4 57.5 64.0 56.9. 53.3 61.5 57.0 68.9 59.0 % of Time above 21 knots 16.2 30.7 9.6 18.5 24.0 1.9 6.9 9.2 18.5 24.2 28.0 Data discrepancies -need resolution? 16.0 63.0 21.0 Source: Tables reprinted from January 31, 1975 report by Dr. Tunis Wentink, Jr., Geophysical Institute, U. of A., (NSF GI 43098). 1fhese should not be compared closely since there are wide ranges in anemometer height and topographic shielding involved. 2Commercial Airport 3Discrepancies often exist in comparison of tabulations, like Census data, ETAC data, and long term averages given in Annual Summaries of LCDs. discrepancy source may be due to the appreciable differences in the re- porting period. Another is significant shifting of the anemometers vertically and horizontally during the report period. 5-44 One H. Tidal Power in Alaska There are many coastal areas in Alaska where the combination of a large tidal range and topographic features produce impressive tide races. Primarily these are located in the Southeast Region, Prince Wil- liam Sound, Cook Inlet, Kodiak Island, and the Alaska Peninsula. The scale of these tide races ranges from the massive currents and bores of Turnagain Arm, near Anchorage, to smaller but impressive fiord and passage type "salt-chucks" in the Southeast and Prince William Sound areas. Most tide races are not located close enough to communities to warrant in- terest as potential electric energy sources. One exception is Kootznahoo Sound on the west side of Admiralty Island, near the village of Angoon. There are certainly other sites but their hydroelectric potential must be weighted both against the capabilities of available and proven equip= ment, and the availability of alternative modes of generation. The load requirement in the Angoon area is well within this technical feasibility range. Tidal electric equipment currently in service around the world can be generally referred to as low-head, axial-flow hydroelectric generators. Applications of this type of machinery are equally suited to salt water tide-race or run-of-the-river inland installations. Table 5.4 lists some pertinent data from actual recorded installations around the world. Unit sizes in this listing range from 50 to 21,000 KW while water flows range from as little as 130 cfs to as high as several thousand cfs. 5-45 TABLE 5.4 PERTINENT DATA ON EXISTING AXIAL FLOW INSTALLATIONS * Name of Plant Year and Location Installed Castet (France) 1951 Mercues " 1952 La Maignan- nerie b s 1952 L' Ame a 1953 Argentat n, 1953 Cambeyrac * 1953 Verdun ee 1955 Rethel i 1955 Beaumont- Monteux a 1955 Capdenac % 1956 Mercues a 1956 St. Malo i 1956 North of Scotland Hydro 1962 La Rance (France) © Pierre Benite (France) © - Partial listing. Head Ft. 23.0 11.5 5.9 6.2 54.1 35.1 10.2 10.5 41.0 19.7 12.8 19.7 22.5 18.8 11-41 Nominal Runner Number Output Speed Discharge Diameter of H.P. R.P.M. c.f.s. in. Units 1,100 250 440 65 2 325 187 350 65 at 69 224 130 44 zr 200 165 340 63 bi 19,250 150 1,760 150 2 7,000 150 1,930 122 2 327 187 310 65 2 345 187 310 65 2 12,000 150 3,140 120 1 1,020 260 530 ae 3 432 254 350 55 2 12,200 88 8,000 228 z 705 386 300 49 4 12,600 93.75 8,500 210 24 28,000 - - 240 4 . Special layout with siphon arrangement; this is the only one of its type to be built. ‘Under construction. 5-46 14 The three basic design types of axial-flow machinery are pit, tubular, and bulb. for purposes of low-head tidal peneration, the bulb type is usually the most emphasized. In this type, a water-tight steel bulb encloses the generator which is direct connected to a Kaplan- type runner turbine blade assembly. The entire submerged assembly some- what resembles a bulbous miniature submarine with an oversized screw pro- peller. Marine cables or water tight passages are required to bring the electric power to the surface switching and control area. Bulb turbines are not simply anchored in flowing water, thereafter producing continuous electric power. Substantial concrete structures are required for water ways, structural strength, and flow control. Exten- sive power-house structure is unnecessary, however, due to the submer- sible generator housing. Tidal bulb turbine installations, of course, require machines and water works designed for operation with two-direction flow, as opposed to inland run-of-river installations. One of the significant limitations of bulb turbines is their inability to provide stable voltage and frequency when operating in isolation from utility grids or machinery which can provide system stability. The inertia of the moving water is very large in comparison to the small "fly-wheel" effect of axial-flow machines. This means that bulb turbines are limited to contributing roles in a power system rather than replacement roles. As in the case of all hydroelectric installations, installed costs are site-specific and can vary over a wide range as a result of unit scale, waterworks arrangement, and transmission cost. 5-47 The French firm of NEYRPIC has been a leader in axial-flow turbine design, production, and installations for many years. The primary pio- neer United States firm has been the Allis Chalmers Manufacturing Company. Germany, Switzerland, and Japan also manufacture axial-flow hydro machin- ery. The Federal Power Commission has been studying and reviewing low- head axial-flow turbine installations since the 1960's and is a source of additional information and data. 5-48 FOOTNOTES However, ISEGR's Man in the Arctic Program petroleum development scenarios upon which the demand section of this report is partly based anticipate a somewhat slower rate of leasing than the current schedule. According to those scenarios, the earliest sale occurs in 1976, the latest in 1982. Department of Natural Resources, State of Alaska, Open File Report #51. U. S. Department of Interior, Alaska Power Administration, 1974 Alaska Power Survey, Resources and Electric Power Generation, p. 68. Forty-four percent is included in NPR-4. "Oil Shale Estimates for Naval Petroleum Reserve No. 4". Prepared in the Conservation Division, U.S.G.S. (mimeo - date unknown, but after 1966). An acre-foot is the equivalent volume of one acre of land, one foot deep. Robert J. Cross (acting Administrator, Alaska Power Administration) comments: "The authors have determined relatively attractive costs for some very small hydro projects. Many of these same projects have been ex- amined in previous studies with opposite findings. A close look at design requirements, operation and maintenance assumptions, and costing assumptions might result in substantially different conclusions on the small hydros and a different assessment of the realities of scale economies. "It is of course a tremendously difficult job to get completely compar- able cost information for the various projects, particularly for those on which there is very little basic data. Very often, preliminary rough estimates of Alaskan hydro projects have substantially underestimated the difficulties and costs of the projects. Several examples come to mind such as a series of reports in the mid-1960's on several hydro projects near Petersburg in which preliminary estimates were one-third to one-half the costs found in follow up reconnaissance studies. "A similar difference was experienced between Kaiser's first estimate for the Susitna Project and their reconnaissance report to the State of Alaska. Cordova has had similar experience with several reports on the Power Creek potential. In these cases, low preliminary cost estimates have had significant impact on public policy and public costs." (Letter to Tussing, May 14, 1976) 5-49 FOOTNOTES (cont. ) 7. Robert J. Cross (Acting Administrator, Alaska Power Administration), comments: "We question validity of the cost comparison between the Kaiser and Corps plans for the Susitna Project. Studies by both the Corps of Engineers and Bureau of Reclamation indicate that, if similar de- sign criteria and cost assumptions are applied, the Kaiser plan does not produce cheaper power. We believe this is another case of two different sets of experts with two different sets of answers. If Kaiser is right, the Corps is too conservative; if the Corps is right, Kaiser has underestimated the difficulty and cost of doing the job." (Letter to Tussing, March 14, 1976) H.W. Holliday (Chief, Engineering Division, Corps of Engineers) comments: "We have noted a difference in your comparison of the Kaiser Plan for Susitna River development to that of ours. In our analysis of the Upper Susitna River, we evaluated the Kaiser report and found that in many areas direct comparisons could not be made. For instance, while Kaiser estimates that the prime energy capability of Susitna I is 3372 gwh, in fact this energy is only available, as stated in their report, 97 percent of the time. By reevaluating the Susitna I under the same criteria used in our study (100% reliability based on the historical stream flow record), the firm energy capability drops in approximately 2600. Our reconnaissance of the Susitna I site revealed that most of the required borrow material would have to come from several miles away which would result in a much more expensive project than indicated by their estimate when evaluated using the same criteria in estimating our alternatives. Furthermore, because of the seismic activity of the entire Susitna basin, our design incorporates a considerably wider and less steeply sloped dam section than that proposed by Kaiser. In general we find the Kaiser report to be a very comprehensive and well written document; however, those areas of the report subject to contention are as follows: Kaiser Est. Corps Est. "Susitna I Prime Energy (GWH) 3.372 2,600 Susitna I Prime Energy (MW) 385 297 Susitna I Storage Capacity (1,000 AC ft.) 5,760 4,733 Susitna I Const. Cost ($1,000) 469,300 1,036, 0002 Transmission Line Cost ($1,000) 87,2003 230,0004 Susitna II Const. Cost ($1,000) 98,000 380,000 - Construction Costs Reflect Jan. 1975 levels 2 Corps Structure 5 Single Tower Transmission Line 4 Double Towers for Reliability " (Letter to Tussing, May 20, 1976) 5-50 8. De 10. 11. 127 FOOTNOTES (Cont. ) Capacity and energy data for Alaska hydro potentials from U.S. Department of Interior, Alaska Power Administration, Resources and Electric Power Generation, 1974 Alaska Power Survey (reprint table from APA, 1968). p. 1-12. Robert J. Cross (Acting Administrator, Alaska Power Authority) comments: We Dr. "The report is very negative on the Yukon-Taiya Project. The Yukon-Taiya diversion would involve a fairly small part of the total Yukon basin and the area is already regulated by natural lakes. Downstream impacts would certainly need study, but there does not seem to be a basis for expecting serious adverse downstream impacts. Similarly, based on pre- liminary appraisal of impacts of the fresh water diversion on Upper Lynn Canal, there is good reason to believe adverse impacts wouldn't be catastrophic. "A further aspect of Yukon-Taiya is its fairly close proximity to the B.C. Hydro HV transmission system. Existing studies indicate good op- portunity for using any surplus power from that project until such time as loads within the region would use the project output." (Letter to Tussing, May 14, 1976) do not intend to rule out all use of solar energy in Alaska. Under some circumstances, solar heat collectors on residences and commercial buildings might become a feasible means of reducing fall and spring heating fuel costs, even at Alaskan latitudes. But this use is not, of course, a method of generating electrical power. Tunis Wentink, Jr., Ph.D., Geophysical Institute, University of Alaska. The Grandpa's Knob Installation in Rutland, Vermont. . ERDA/NASA has recently contracted for a demonstration 1.5 MW generator. . Pit units involve a waterproof generator housing generally located beneath the reservoir. Tubulor units involve a generator placed at reservoir level, with the water from the reservoir directed to the turbine through tubes. See F.P.C. Staff Report on Bulb Turbines. 1962. p= REFERENCES Tubular Turbine Installation Water Power Magazine (English) - April 1960 Bulb Turbines Give Cheap Power from Low Heads Engineering Magazine (English) - November 3, 1960 Experimental Tidal Station at St. Malo Revue Generale de L'Electricité - May 1960 Report on Possibility of Using Bulb-Type Turbines SCGREAH Machine Experimental Station - March 1958 France Builds First Tidal Power Plant Electric Light and Power - June-July 1962 Development of Small Streams Contacts No. 30 of Electricité de France - June 1961 Turbine Regulation by Downstream Gate Paper delivered by C. T. Advani Symposium de Nice, France - September 1960 Brochure of Ets NEYRPIC on Utilization of Bulb Units at Belleville Site on Ohio River - October 1961 Research and Progress in Hydraulic Turbine Design La Houille Blanche Magazine (French) - March-April 1961 The Hydraulic Turbine in Evolution Institute of Mechanical Engineers, England James Clayton Lecture by P. Danel - December 1958 The Use of Axial-Flow Turbines for Low Head Development Chaleur et Industrie Magazine (French) - December 1961 Franch Water Power The Engineer Magazine (English) - August 1961 5-52 REFERENCES (continued) French Bulb Sets for Tidal and Low Head Power The Engineer Magazine (English) - January 1961 Research Developments and Results Concerning Bulb Units Engineering Institute of Canada Transactions - 1961 French Low Head Power Development The Engineer Magazine (English) - March 1962 Water Power Engineering By Rolt Hammond Axial Units Provide Cheap Power from Low Heads by Pierre Misson of Ets NEYRPIC Ability of Hydroelectric Sets, (Kaplan vs Bulb) to Regulate a Separate Network Report on Pierre Benite Project by C. Moulin of NEYRPIC - November 1960 Editorial - Off the Shelf Water Power Magazine (English) - March 1962 9-53 VI. FINANCING ELECTRIC POWER SUPPLY IN ALASKA Preparatory Remarks The purpose of this chapter is to present data relevant to a legislative decision on the future organization and financing of electric power supply in the State of Alaska. It has not been the aim of this study to provide a single answer-indeed, there may be no single correct answer-but, rather, to furnish information and analyses that legislators may use in making decisions. On the other hand, we have avoided encyclopedic compilations of data, because masses of unanalyzed data are as much a handicap as an aid to informed decision-making. This chapter embraces two main topics-first, the financial implications of alternative forms of electric utility organization, and second, the impacts on operating efficiency of these forms of organization. The financial questions are discussed at much greater length than the operational questions; this recognizes immediate priorities, rather than the long-term relative importance of the two topics. This chapter is divided into two main parts. In the first part there is a description and analysis of the existing forms of organization of electric power supply in the U.S. In this first part of the study there is a discussion of the costs of capital and of operations of the various types of utilities. In the second part of the chapter there is a discussion of possible ways in which future power supply in the State of Alaska might be reorganized. This part of the chapter is meant to convey suggestions rather than recommendations. We have tried to in- dicate the criteria by which various alternatives may be analyzed, rather than to indicate which of the alternatives is most desirable; the latter is ultimately a legislative decision. Also contained in this second part is a discussion of various forms in which the state might provide subsidies to low-income consumers burdened by exceptionally high power costs. Here too, the discussion has sought 6-1 to develop economic criteria for the form which a subsidy should take, ue than to recommend specific subsidies. There are several general assumptions that should be noted at this point. First,it has been assumed throughout this study that current general economic conditions, including inflation and high money costs,will continue in the future. Second, this study has been written from the standpoint of a non-lawyer, so decisions in some of these areas will require legal analysis. Methods of Organizing and Financing Electric Power Supply in the United States Electric power in the United States is produced and transmitted by inves- tor-owned or private utilities, rural cooperative utilities or coops, state and t municipally owned utilities, agencies of the Federal government, and by various combinations of these in joint ventures. In the present section, we will de- scribe and analyze these various organizational forms of electric power supply. We will first discuss the operational aspects of the various organizational forms and then-discuss the financial aspects of them. A. Costs of Operations The cost of building and operating an electric utility is largely a function of the characteristics of the territory served. Local characteristics affect fuel costs, wage costs, construction costs, and the character and size of the loads to be served; the latter, including load factor and load density, pro- foundly affect the planning process and the unit costs of distribution, and economies of scale may also affect all unit costs. The powerful influence which local characteristics exert on costs makes it unusually difficult to compare the efficiency of different utilities. Consequently, there have been few studies comparing the operating efficiencies of the various 6-2 forms of utility organization, and those studies are not of proven reliability. However, because there is relatively little direct competition among utilities, and because equipment is supplied by a small number of companies, managerial and technical information is more uniformly available in the electric power industry than in many other industries, and there is probably more uniformity of managerial and technical performance than in other industries. It is not possible in the present state of knowledge to reach any firm conclusions about the relative efficiency of private, cooperative, or publicly owned electric utilities, From a purely theoretical standpoint, one could point to disadvantages of both private and public ownership. Publicly owned enter- prises theoretically suffer from the absence of the profit incentive, as well as profits as a yardstick of performance. Privately owned utilities, because of regulation and the absence of strong competition, are alleged to have an attenuated profit incentive to efficiency, and are also alleged to have an incentive to overinvest in plant. But none of these allegations, whatever their theoretical merit, has been conclusively shown to be a factor leading to inefficient operations in the electric utility industry, either here or abroad. It should also be noted that one of the chief shortcomings of publicly owned enterprises,namely, their reliance on legislative appropriations for capital funds,is generally not applicable to publicly owned utilities in the U.S., whose great majority rely on the capital markets for their funds, rather than on legislative appropriations. There remains to be considered the influence of scale of operation on the unit costs of electric utilities. Also to be explored are the effects of scale on the required degree of managerial and technical competence. We will first examine these factors in relation to distribution systems, and then in relation to gen- erating systems. 6-3 1. Distribution Systems Generally speaking, the engineering and operation of distribution systems does not provide as great a challenge as the engineering of generation and trans- mission systems. As the scale of the distribution system increases-—whether this is in terms of area, number of customers in a given territory, or Case per cus- tomer—there are increasing challenges to the managerial and technical capabilities of the enterprises. This is mainly because the increase in scale affords oppor- tunities to the management to cut costs and to improve reliability of service. To take a simple example, as the number of customers grows, there is an increas- ing likelihood that computerization of billing procedures will cut billing costs. As the number of customers grows, systems analysis may increasingly reveal ways of constructing the distribution network so as to increase reliability of service and/or to reduce investment costs or line losses.Thus, while it may remain possible to operate the large distribution utility with the same managerial and technical skills as were employed in the smaller company, and possibly with no increase in unit costs, the greater size poses opportunities for a higher level of competence to achieve something significant. The greater size deamands—but does not necessarily require—a higher level of competence. 2. Generating and Transmission Systems The construction and operation of generation and transmission systems generally requires a higher level of technical expertise than does the distribution system, The small utility will be faced with a relatively nar- row range of options, and the generation and transmission equipment used will be relatively simple in character. But there exist very great technical economics of scale in generation and transmission, not only as regards the unit costs of individual pieces of équipment, but as regards the structure of the entire system. There is also a much wider range of options of different kinds and sizes of equipment, and 6-4 complex tradeoffs between fuel costs, generating capital costs, and transmission capital and operating costs. With great enough scale, the generation and transmission systems demand very advanced skills for their design, construction and operation. Large generating plants may also pose special financial problems, The prin- cipal problem created by a large plant arises out of the long lead-time between the beginning of construction and the initial delivery of power. The long lead time, which for a nuclear plant can be as long as 10 years, means that the utility must raise capital for major construction expenditures many years before the plant produces any revenues to cover capital carrying costs. These large gener- 1 Thus, financing such a plant ating plants may cost as much as $1 billion. during a long preproduction period would present a major strain on the finances of even the largest utility. On the other hand, studies conducted by the author indicate that investors prefer to buy the securities of larger utilities—which means a lower capital cost for them-whether because the larger utilities are more diversified and stable or simply because more is known about them, In addition, a very large plant may raise quest ions about reliability of the entire system, since the rule of thumb followed by the utility industry is that generating reserve must be adequate to cover an outage by the largest single plant. And if there are reliability problems with a single large plant, there is a corresponding increase in the financial risks of the utility. Finally, when a large generating plant goes into operation it may, temporarily at least, create a situation of excess capacity for the utility; i.e., of excessive unit costs for capacity actually required bythe system in the short run. Despite these shortcomings and problems of large plants, the utility industry seems generally agreed that the economies of scale of large plants greatly outweigh any diseconomies. 6-5 Although growth in scale of operations requires, for most efficient opera- tion, a higher level of managerial and technical competence in all aspects of the enterprise, larger scale also makes that competence more readily available. The most talented and energetic people, whether in sales, finance, a ae ing, are attracted to challenges. Top flight engineers will usually prefer to be with a utility which is doing a lot of construction and where the work is ‘ ‘state of the art.’? Such challenges are much likely to be afforded by a large utility than by a small one. So long as most Americans continue to prefer an exciting job to a quiet life, the large utility will have an edge in attracting the most competent technical and managerial personnel, In addition, the larger enterprise provides much greater scope for speciali- zation of managerial and technical skills. A distribution utility which serves a single community of, say, 1,000 customers will not be able to develop the same degree of specialized expertise as a utility distributing power to 50 such communities. Although it is true that the larger enterprise may have a stronger tendency to get bogged down in bureaucratic procedures, it will enjoy the vast advantage of being able to call upon experienced and highly trained specialists to perform virtually every managerial and technical function. That this dis- advantage of small scale is more than theoretical may be seen from the fact that both the Rural Electrification Administration (REA) and the Tennessee Valley Authority (TVA) are extensively engaged in providing managerial and technical counsel to the many small utilities they serve. Thus, there appear to be significant economies of scale that can be achieved in all branches of the enterprise’s activities. 6-6 B. Costs of Financing Before embarking on a description or analysis of the various organizational means of financing electric utilities, it may be helpful to set forth some general considerations. The first point to be noted is that the cost of capital to an enterprise is not simply the interest rate which must be paid on debt. With rare exceptions, borrowers must have equity capital and must have earnings on net revenues significantly in excess of expected intunese payments. The reason is simply that the existence of equity capital and equity earnings_provides a mea- sure of security to lenders, The existence of a flow of earnings over and above interest requirements reduces the probability that the borrower will default. The existence of equity capital assures the lender that if there is default, the value of the property will exceed the amount he is owed, thereby increasing the likelihood that he will be able to recover the principal amount of the loan. The only exceptions to this general rule appear to be cases where the loan is fully guaranteed as to principal and interest by some highly credible third party. For example, the Federal Government guarantees mortgage loans on U.S. built and operated merchant ships. Even so, the guarantor will require that the borrower invest equity capital of at least 10 percent of the value of the ship. It should be borne in mind that the main source of loan capital in our so- ciety is from fiduciary financial institutions which are lending other people’s money. These include insurance companies, pension funds, banks, etc. These insti- tutions all have firm commitments to pay specified amounts of money either on demand or at specified future dates. They therefore must largely restrict their investments to highly secure instruments; in many cases there are government regu- lations to prevent them from pursuing riskier investment policies. 6-7 The requirement that indebtedness be backed by equity investment and equity earnings imposes additional costs on the enterprise and its customers. For one thing, there is the cost of raising the equity capital. Whatever the eiaies of that capital, the fact remains that if it were not tied up in the enterprise, it could have been invested elsewhere and have provided income to its owner. This remains true whether the equity capital is contributed by the taxpayer, the ratepayer, or the general investing public. Since the ‘‘cost’®’® of equity capital is typically higher than the cost of debt capital, it will typically be advantageous to have as much debt and as little equity as possible. There are, however, limits to this. For as the pro- portion of debt rises, the riskiness of both the debt and the equity increase. After a certain point, further increases in debt may so increase the costs of both the debt and equity that the overall cost of capital may rise. It is ex- tremely difficult to determine what this optimal point is for any enterprise, and financial managers therefore must fly-by-seat-of-their-pants in this regard—a fact which should be understood when evaluating the capital struc- ture of any given utility. The capital structure may also be institutionally constrained by interest coverage or other requirements. Lenders may sometimes directly restrict the proportion of debt to total capital or may restrict the portion of earnings paid out as dividends. Also, by requiring that earnings exceed interest by a given margin, they may effectively force the borrower to invest enough equity to gen- erate the earnings margin and to hold down his indebtedness so as to keep his interest coverage in bounds. 6-8 The interest coverage requirement also means that the ratepayers of the utility must pay enough to meet more than current expenses and interest costs} they must pay enough to enable the utility to have net income after interest. This is true of both publicly and privately owned utilities. Thus, the oes capital to the ratepayer is more than the interest payment. One must therefore consider the coverage requirement of any utility as an important element of the rates that must be charged to ratepayers. The matter is further complicated by the fact that a low coverage reece typically entail a relatively high interest cost, so that utilities will typically try to have coverage at least moderately above the absolute minimum, It should also be borne in mind that the coverage require- ment becomes increasingly burdensome as interest rates rise. 1. Private Utilities Privately owned electric utilities account for over three-fourths of the power sold in the U.S. These utilities typically operate in monopoly franchise territories, although service territories are not always precisely defined. They are now subject to regulation by state commission in all states, although the character of the regulation varies widely. They are subject to Federal Power Commission regulation of power sales to wholesale customers—i.e., customers who resell the power to ultimate consumers—such as minicipal utilities and coops. Most private utilities operate solely within a single state. Utilities with substantial operations in several different states are often organized as holding companies in which the subsidiaries provide service in individual states while the parent provides overall management; the subsidiary companies typically issue preferred stock and bonds on their own account while the parent raises common equity capital for all the subsidiaries. 6-9 Privately owned utilities are heavily dependent on capital markets to supply needed capital funds; unlike many industries, the utilities typically cannot in- ternally generate enough retained earnings to finance the expansion of plant. Since this characterizes all branches of the electric utility industry, it may be worthwhile to explain why it is the case. Basically, the need for external financing arises out of the very heavily capital-intensive nature of the electric utility industry. Utilities typically require $3 to $4 of plant investment to produce $1 of annual revenues, in con- trast to manufacturers who, on average, require only $1 of plant per dollar of annual revenue, Suppose now that a utility’s demand is expanding 6 percent per year and that it must increase its capacity 6 percent per year. The unit cost of new plant is, because of inflation, roughly twice the unit cost of old plant. Thus, the utility will have to raise capital in an amount equal to 12 percent of existing plant. Since existing plant is about 3.5 times current revenue, the new capital required by the utility is 42 percent of its currentrevenues. To attempt to raise all of this capital without recourse to external financing would place a heavy burden indeed on the utility’s customers. The fact is that internally generated capital funds of the utility come to about 5 percent of plant or 15-20 percent of revenues.2 Thus, internally gener- ated funds can only account for roughly 40 percent of capital requirements. The rest must be raised in the capital markets. 6-10 Because the utility industry has such heavy reliance on the capital markets, we must examine what the capital markets require to be willing to provide the necessary funds. Speaking in the most general terms, there are two requirements. First, the utility must offer investors rates of return which are competitive with what investors can earn in alternative investment opportunities. Second, in order to keep the required returns from being too high, the utility must provide the in- vestor with a reasonable degree of security that the required return will actually be earned and that the investor is not bearing a heavy risk. The cheapest source of capital for the utility is debt. But it is a well known principle of finance, that the larger the portion of capital raised through borrowing, the greater the risk to the borrower and also the greater the risk to the equity investor. As a consequence, utilities have sought the optimum capi- tal structure which would enable them to raise much of their capital through low-cost debt without unduly increasing the risks to investors, since not only the cost of the capital but its availability at all will be unfavorably affected if indebtedness is too great. The capital of private utilities is typically raised in the following pro- portions: long-term debt accounts for 55 percent, preferred stock accounts for 10 percent, and common equity accounts for 35 percent. Short-term debt is usually 6-11 minor in amount, averaging about 5 percent of total capital and rarely going above 10 percent, Capital structures of individual companies rarely vary much from this average. Regulatory agencies today typically allow private utilities to earn 8.5 to 9.0 percent, after taxes, on their investment, This is determined as : weighted average of (1) the costs of all outstanding bonds and preferred stocks, which averages about 6.2 percent; and (2) a current cost of common equity, on which most regulatory agencies appear to be allowing rates of return in the neighbor- hood of 13 to 14 percent. Thus, the weighted average return for this typical company is 8.58 to 8.93 percent: Long-term debt -55 @ 6.2% = 3.41% Preferred stock: -10@ 6.2% = 62% Common Equity: 035) 13"14% = 4,55-4.90% 1.00 8.58-8.93% This does not represent, however, the current cost of raising capital in the marketplace. At present the average private utility must offer about a 10 percent interest rate on new bonds and preferred stocks, Thus, the current cost of raising capital is over 11 percent: Long-term debt: — 255 @ 10% = 5.50% Preferred stock: 2-10 @ 10% = 1.00% Common stock: 035 @ 13-14% = 4,55-4.90% “1.00 11,05-11.40% This element of the capital carrying charge is before taxes. In recent years, however, there has been a sharp decline in the amount of Federal in- come taxes actually paid by electric utilities, as a result of their very 6-12 massive construction programs which generate large tax deductions in form of investment tax credits and accelerated depreciation. Actual Federal income tax payments of private utilities in recent years amount to less than 1.0 percent of total capital, and with the new investment tax credit will not amount to more than 0.5 percent of total. Thus, the pretax cost of capital is roughly 0.5 per- centage points more than the after-tax cost of 11.1 to 11.4 percent. On the other hand, state and local taxes paid by private utilities are five or six times as great, adding 2.5 to 3.0 percentage points to the capital carrying charges of these utilities. In order to be able to raise capital in the required amounts, the utility must be able to have a rate of earnings on that capital at least equal to the cost of the capital—that is, the utility must earn enough to pay investors the returns they require if they are to induce investors to advance more capital. In addition, the utility must meet certain interest coverage requirements if it is to be able to raise additional debt capital. Interest coverage is broadly defined as operating income, before payment of interest and income taxes, divided by total annual interest charges. Thus, the coverage ratio measures the degree to which interest charges are covered by current income. If the coverage ratio is high, the bondholder can feel relatively assured of the utility’s ability to meet interest payments; if it is low, then the bondholder must be concerned that a decline in income, or further borrowing, may force the utility to default on interest payments. Thus, interest coverage has become a principal test of the credit worthiness of a utility. The test is applied in two ways. First, every outstanding utility 6-13 I bond has a contractual provision that the utility shall not issue additional bonds if the interest on those bonds, added to existing interest obligations, would reduce the interest coverage below 2.0 times.4 Second, whenever a new bond is issued, the utility is required by the SEC to inform investors of the level of coverage. These coverage ratios are heavily relied on by rating agencies and investors as indications of risk, Utilities with low coverate ratios find that the market will require higher interest rates and, often, will accept only limited amounts of new bond issues. For example, in today’s markets, a utility with coverage in the neighborhood of 2.0 times will typically have a poor bond rating of Baa and will have to pay interest of 11 percent or more, whereas a utility with coverage of 4.0 times will have an AA rating and will have to pay interest of only 9 percent. The average utility today has a coverage ratio of approximately aoe But coverage ratios for individual companies range from less than 2.0 to well over 4.0. This is reduced very substantially from the average of almost 4.0 which the utility industry enjoyed in the late 1960s. This decline in cover- ages is a sign of the increasing difficulty which private utilities are having in raising capital to meet their expansion needs, It is beyond the scope of this report to analyze why this has occurred and how it might be remedied.® Suffice it here to note that the decline in coverage, coupled with a sharp rise in the cost of both debt and equity money? and an inflationary erosion of utility earnings, gave rise to severe financial difficulties during 1974 as utilities attempted to raise unprecedented amounts of new capital. The result was a massive reduction in utility construction budgets: over 200,000 megawatts of planned generating capacity has been postponed or cancelled- enough to give power to 20 cities the size of New York. 6-14 2. Municipal Utilities® There are 2,000 municipally owned utilities in the United States, and they account for 8.6 percent of power generation and 10.8 percent of power sales (in kilowatt-hours) in the nation.? They range very widely in size, from the Los Angeles Department of Water and Power, which serves 1.1 million customers to tiny companies which serve only a few customers. The smaller municipal utilities typically buy power from large wholesale suppliers serving their territories; in Tennessee the municipal utility will buy power from TVA, in Massachusetts from New England Power Company. Power purchased from privately owned utilities are at rates determined hy the Federal Power Commission. The larger municipal utilities typically generate much if not all of the power they sell. In most states, municipal utilities are not subject to any rate regulation. There are a number of states, including Alaska, however, where power sales outside of the city limits are subject to regulation, and there are over half a dozen states where all sales of the municipal utility are regulated. Rate regulation of municipal utilities seems to be relatively perfunctory in most cases, perhaps because there is no clear perceived conflict of interest 6-15 between ratepayers and owners, or perhaps because too active regulation would be deemed to infringe on the taxing powers of the municipality, since surplus revenues of the utility may provide a source of funds to the muni- cipal government. For reasons to be noted below, the mere existence of regulatory powers can make it difficult if not impossible for the utility to raise capital, which may account for the fact that bond sales by muni- cipal utilities subject to rate regulation are virtually unheard of. In recent years, there has been increasing interest of municipal dis- tribution utilities in participating in power generation. In some cases, small utilities have banded together to enter into joint ventures in generating plants with coops and/or private utilities. In other cases, municipal utilities have demanded to be allowed participation in the ownership of new plants being planned by one or a group of private utilities, a demand which has generated a certain amount of litigation as to their right to such entry. On the other hand, small municipal utilities which generated some or all of their own power from small inefficient plants still seek, in some cases, to be acquired by large private utilities which can furnish them with cheaper power. Thus, small municipal utilities are less and less content to remain passive whole- sale customers of power suppliers, and increasingly seek ways to capture a greater share of the scale economies of large-volume production. The typical municipal utility derives capital from one of three sources: 10 capital contributions by the municipal government,'~ retained earned surplus, and sales of tax-exempt debt securities to the investing public. Although capital structures vary very widely among municipal utilities, the average such utility has 40 percent equity and 60 percent long-term debt in its capital 6-16 structure, a ratio quite similar to that of the private utility. The debt of the municipal utility is secured by the plant and revenues of the utility; we know of no instance in which such debt is also an obligation of the muni- cipality or is guaranteed by a state or municipal government. Tax-exempt securities are chiefly sold to banks, casualty insurance 11 i , ' ; ‘ companies, and high-income individuals. Other types of financial institutions hold relatively small amounts of tax-exempt securities. The market for tax-exempt securities is somewhat limited in scope, therefore, and may explain why the interest rates on tax-exempt debt securities tend to be considerably higher than what one would expect given the yields on taxable bonds and the income tax rates. For example, in late 1975, newly issued tax-exempt bonds had yields in the neighborhood of 7 percent, U. S. Treasury bonds had yields a bit over 8 percent, and utility bonds had yields in the range of 9 - 10 percent. Given tax rates in the range of 50 - 70 percent for large corporate and private investors, one would have expected tax-exempt bonds to yield about 5 percent. Yet an investor in the 50 percent tax bracket could actually ex- pect to earn the pretax equivalent of 14 percent on a good quality long-term bond of a municipal utility. Although the financial advantages of tax-exempt bonds are not as great as one would have expected before the fact, such bonds still offer an interest cost 1 percentage point less than U. S. Treasury bonds and 2-3 percentage points less than bonds of private utilities. Municipal utilities typically issue revenue bonds with maturities rang- ing from 1 to 35 years. A single issue will typically be composed of bonds with varying maturity dates, since issuers generally attempt to achieve equat annual payments of interest-plus-principal, similar in effect to the payment schedules of home mortgages. !2: 6-17 Municipal utility bonds generally offer several types of security to bond- holders, which appear necessary to make the bonds marketable at a reasonable cost. The muntct{pal utility contractually agrees to certain financial practices similar in ultimate intent, if not always in form, to the coverage requirement of private utilitfes. We will discuss three of these. In this discussion we will talk about 4 the typical municipal utility, but it should be borne in mind that there is _ considerable variation among these utilities as regards all of these characteristics. a. The municipal utility covenants that each year its rates will be adequate { to meet operating expenses and to provide a margin, called net revenue for debt service, which is typically 1.25 times as great as a required for interest plus . principal repayment. A private utility cannot make such a covenant because L its rates are subject to regulation. Unlike the private utility, the muni- cipal utility agrees to maintain adequate coverage at all times. Note also that this coverage calculation is pretty strictly in cash terms: Net revenue for debt service is operating revenue less cash operating costs, before de- preciation, and the debt service which must be covered includes scheduled principal repayment as well as interest .23 b. The municipal utility usually contracts to a certain handling of its funds. In the typical. case, it will agree, first, to accumulate, over a period _ of five years, a sum equal to the largest future annual debt service for { principal and interest. In practice, the utility may simply increase the amount it borrows, with the "excess" being set aside to meet this requirement -- with " funds being invested in relatively liquid assets, for example, i the "excess short-term U.S. Treasury bills. Second, out of the remaining net revenues, the municipal utility will pay out no more than half to the general funds of the municipality. 6-18 ce. The municipality agrees not to sell additional parily bonds (that, is, bonds not subordinated to the securities in question) unless its net, revenues during each of the preceding two years is 1.5 times! 4 as great as the largest single future annual debt service (of interest and principal), in- cluding in the latter the annual interest and repayment amounts from the proposed new bonds. This provision explains how municipal utilities decide on the maturity dates of new bond issues: The maturities are timed so as to equalize all the future annual debt service requirements and thereby have the maximum single year's requirement as low as possible. These characteristics of municipal utility bonds have quite intricate implications for the minimum revenue requirement and equity investment of a municipal utility. One thing is clear, however. The notion that a municipal utility can finance with close to 100 percent debt, and that its revenues after expenses need only suffice to pay interest costs, i.e., that it needs no equity return or the equivalent, is incorrect. There is good reason to believe that the actual capital structures of municipal utilities are not very different from what would be the prudent maximum amount of leverage for a private utility. We turn now to a determination of the cost of capital for a municipal utility. There are two ways of determining this cost. The first way is to measure the cost of debt and to impute a cost to the equity capital, and then to derive a weighted average of these two costs. 6-19 The first way of measuring the cost of capital for the municipal utility is to answer the question: What are the revenue requirements’ of a municipal utility which wishes to maintain its credit? As we have seen, the bonds of municipal utilities require that net revenues of the utility significantly exceed its payments of interest and principal. Let us consider the situation of a newly formed municipal utility with 100 percent debt financing and a 7 percent interest cost. If the bonds had a maximum maturity of 35 years, the annual debt service requirement for principal and interest would be $7.70 for each $100 of bonds outstanding. If the coverage requirement were 1.5 times the debt service, this would mean that its net revenues would have to be about 11.5 percent of total capital. This in turn would imply, after subtracting depreciation, that the required return on total capital would be about 8.5 percent .15 This is the return that would be required merely to meet the minimum coverage necessary to be able to issue new bonds. It should also be noted that this required return, or "cost of capital," is what it takes to raise new capital; many utilities sold bonds in the past at interest rates much below the present level and their present revenue requirements are correspondingly lower. 6-20 A second way of measuring the cost of capital to a municipal utility is to take a weighted average of the current cost of debt and the imputed current "cost of equity" capital. The cost of long-term debt currently averages about 7 percent for municipal utilities. The "cost of equity" should be equal to the return which the supplier of the equity--whether taxpayer or ratepayer-- could obtain if his funds were placed in alternative investment opportunities of comparable risk.1® Since it is believed that the cost of equity for privately owned utilities is about 14 percent, we will ascribe a 12-13 percent cost of equity for the municipal utility. Thus, the weighted overall current cost of capital17 for a typical municipal utility with a 60 percent debt ratio is about 9 percent: Long-term debt: 0.60 @ 7.0% = 4.20% Equity: 0.40 @ 12-13% = 4.8-5.2% 1.00 9.0-9.4% Thus, we conclude that the current cost of raising new capital for a municipal utility is about 9 percent. By stretching things, this figure might be reduced to 8 percent. The earnings of municipal utilities are not subject to Federal (or state) income taxes, although as we have seen, the Federal tax burden on privately owned utilities has been considerably reduced in recent years. Municipal utilities do, however, pay the equivalent of local taxes. In 1973, municipal utilities paid local tax equivalents equal to 1.0 percent of net plant.18 This may be compared with the 2.5 percent paid by private utilities.19 6-21 Such comparisons of local taxes paid can be misleading, for two reasons. First, the territories served by municipal and by private utilities probably dif- fer in character, and consequently the municipal utility might, even if privately owned, not pay local taxes comparable to those of other private utilities serving different territories. Second, many municipal utilities pay a substantial fraction of their earnings into the coffers of the local government. If we view these earn- ings as the return on equity capital which ratepayers have ‘‘invested’’ in the enterprise, then it is a species of double-counting to assert that the utility is paying these funds as taxes and that they are also returns to investors. The market for tax-exempt securities has been profoundly affected in recent years by two untoward developments, First, there has been a very great increase in the amount of borrowed by state and local governments. Given the relatively limited scope of the sources of funds for tax-exempt borrowers, this has put considerable upward pressure on tax-exempt interest rates. Second, the grave financial diffi- culties encountered by New York City, to a lesser but still important degree by New York State, and by some other municipalities appear to have affected the interest costs of all tax-exempt borrowings. The financial integrity of such borrowers has been called into question: The ability of state and local gov- ernments, and their agencies, to raise capital in the money markets will doubt- less be profoundly influenced by the character of the ultimate resolution of the financial problems of the City and State of New York--and by whether similar problems emerge in the finances of other state and city governments. 6-22 3. Rural Electric Cooperatives The financing of rural electric cooperatives, hereinafter referred to as **coops’?’, has changed radically in recent years. Originally the program was de- signed to provide very low cost REA financing for the construction of rural transmission and distribution systems, It was expected that oe would buy wholesale power from other utilities, whether privately or publicly owned. Thus, by 1960, REA loans for generating plants accounted for less than 12 percent of the cumulative total of all REA loans ever made. But by 1974, generation ac- counted for 23 percent of cumulative loans; between 1960 and 1974, generation accounted for 36 percent of all new REA loans. In 1973, new legislation was enacted by Congress which greatly changed the basis of coop financing. Although this legislation is claimed to increase the total amount of capital available to coops, it also greatly increases the cost of that capital. REA loans at 2 percent interest are now only available to coops serving very sparsely populated areas or having relatively weak finances. The standard REA loan now bears an interest rate of 5 percent as compared with the 2 percent rate previously charged. Moreover, such loans are now limited as to total amount and purpose, A revolving fund has been established. Coop payments to REA of in- terest and principal on earlier loans are deposited in the fund and are the princi- pal source of new loans made by the fund. In addition, the REA can (in essence) borrow from the Federal Financing Bank, using ‘‘insured’’® coop loans as security. In addition to borrowing directly from REA, the coops are now encouraged, and in some measure required, to raise some of their capital from other sources. The 1973 statute provides that the REA can guarantee loans made to coops by 6-23 other lenders. Theoretically, the coop is to negotiate a loan with any willing lender, and the REA will guarantee the loan as to principal and interest. In practice, such loans are mostly made from the Federal Financing Bank, at interest rates based on the current rate paid by the U.S. Treasury. In November 1975, the rate on such guaranteed loans was above 8 percent. Finally, coops can borrow from the National Rural Utilities Cooperative Financing Corporation (CFC). This is a not-for-profit cooperative association which raises money from the general public which is then lent to coops. Since it has recently been selling bonds with a coupon over 9 percent, the rate it charges coop borrowers must come close to 10 percent. In 1974, new REA loans amounted to $730 million. Only $89 million of these loans were at the 2 percent rate; the rest were at the 5 percent rate. The volume of guaranteed loans in 1974 was $1,075 million; their average interest cost was probably in the neighborhood of 8 percent. Finally, there were nonguaranteed loans 20 to coops in the amount of $532 million; these loans were probably at interest 21 rates in excess of 9 percent. Thus, coop borrowers in 1974 were, on average, paying about 7 percent on new borrowings. At year-end 1974, coops had $6,230 million in outstanding long-term debt, and $2,407 million in equity. Thus, 72.1 percent of their capitalization was provided by long-term debt, and 27.9 percent by equity. The debt ratio has been rising during the 1970's; it was only 71.8 percent in 1970. However, coop operat- ing margins, which were 2.5 times annual interest during 1970-1973, dropped to 2.0 times in 1974, principally because of a 25 percent increase in interest pay- ments in that single year. Given the large amounts of money that coops have been borrowing, and the historically high interest rates they have been paying, it seems clear that their interest coverage will be falling quite rapidly. This 6-24 suggests that it may not be possible to sustain the current capital struc- ture for very long, and that substantial injections of equity capital will soon be necessary. As a general matter, a high debt ratio is much easier to achieve for an enterprise borrowing 2 percent money than for one borrow- ing 7 percent money. As a general rule, coops are expected by REA to have interest coverage of.at least 1.5 times. Those with lower coverage are considered to be in suf- ficiently weak condition to be eligible for 2 percent loans from REA. Also, CFC requires interest coverage of at least 1.5 times for distribution borrowers and 1.0 times for power supply borrowers. There are two ways of looking at the current cost of capital to a coop. One way is to consider the before-interest return requirement needed to main- tain adequate interest coverage. The other is to weigh the cost of debt with the true economic cost of the equity contributed by members. If we consider a coop with a 75 percent debt ratio and with a 7 percent cost of new debt, then in order to maintain interest coverage of 1.5 times, the return on total capital must be about 8 percent. 2? Such an overall return would imply earnings of 10.5 percent on the equity capital. If we assume that the "cost" of equity capital? is 12 - 14 percent, then the overall cost of capital would be about 8.5 percent. It is worth noting that in this connection, averages can be a bit decep- tive. A coop which is engaged only in distribution can expect a somewhat lower cost of capital than one which is also generating power. The bulk of 6-25 debt capital for distribution facilities may still be obtainable at an in- terest cost of only 5 percent, while borrowing for generation may be ex- pected to cost between 8 and 9 percent. The distribution coop will, there- fore, need earnings on total capital in the range of 5-7 percent, while the generating coop may need earnings of as much as 9 percent on total capital. It is well to bear in mind that Federal policies toward rural coops may still be in a state of flux. For example, in early 1975, the REA an- nounced a proposed new policy according to which REA 5 percent loans would no longer be made for any but the smallest generating facilities. Coops seeking to build larger generating plants would have to borrow under the guaranteed loan program, at rates substantially above 5 percent. Although this proposed new policy guideline was withdrawn by REA later in the year, the fact that it was proposed at all suggests that present policies are being reconsidered. 4, Federal Power In 1974 Federal agencies produced about 12 percent of the nation's total power output. The Federal government has been a producer of electric power chiefly in circumstances where multi-purpose facilities are called for. The Congress may then appropriate funds for the construction of hydroelectric power facilities where there is a showing that substantial public benefits can be derived as a result of flood control, irrigation, recreational faci- lities, etc., provided in association with the hydroelectric power. Power from such projects is typically sold to "preference customers''*+ -- public bodies and coops -- at relatively low rates. 6-26 Although TVA is the best-known example of Federal power, the operation of TVA differs in very important respects from other Federal power projects. Originally TVA was created to provide power from multi-purpose hydroelectric dams in the Ten- nessee Valley. The capital of TVA was entirely derived from Congressional appro~ priations, But over the past two decades, two important changes occurred. One of these changes was that taxpayers ceased to provide capital funds to TVA, and TVA oad snubled to borrow money directly from the public, in addition to raising capital through retained earned surplus, Second, TVA was permitted to build fossil fuel and nuclear generating plants. As economic hydroelectric sites diminished, TVA was “thereby able to continue expanding its operations, much in the manner of any public utility. Aside from TVA, the more usual form in which Federal power is produced and marketed is as follows. Subject to a specific appropriation by Congress, the Corps of Engineers or the Bureau of Reclamation will construct a specific multi-purpose hydroelectric facility. This facility will then be operated, and the power marketed, by an agency of the U.S. Department of Interior, such as the Bonneville Power Administration, the Alaska Power Administration, the Bureau of Reclamation, atexe* However, the Federal Columbia saints Transmission Act of 1974 enabled Bonneville Power to sell revenue bonds to the U.S. Treasury, thereby reducing its dependence on Congressional appropriations. Power is marketed by these Federal agencies at rates approved by the Federal Power Commission, 26 Rates are theoretically designed to cover operating costs, provide for depreciation of the plants, and to enable the power authority to pay interest and repay principal to the U.S. Treasury on the Federal funds invested 6-27 in the project. Depreciation and principal repayment are charged to electric cus- tomers in amounts large enough to cover that portion of the total project costs allocated to the power supply function. Since the hydroelectric dams jointly serve two or more functions, there is a somewhat arbitrary allocation of costs between power supply and other functions <’ The interest rate to be paid to the U.S. Treasury is stipulated by specific Congressional statutes for individual pro- jects; interest rates have been as low as 3 percent for generating facilities and 5 percent on transmission facilities, however, new federal projects are subject to higher rates. It is obvious that power marketed under these terms embodies very substantial Federal subsidies to consumers, since the interest rate on U.S. Treasury bonds sold to the public is several times as great as the interest rate charged by the Trea- sury to these power projects. Moreover, in some cases the rates of the power agency may not be high enough even to cover these extremely low ae Because of these and other direct and indirect subsidies, as well as the intrinsically low cost of producing power from high-grade hydro resources, the rates charged for power by these Federal agencies are extremely low. For example, the Southwestern Power Administration sold bulk power in 1974 at an average rate of about 0.7 cents per kilowatt-hour, and Bonneville sold power at an average rate of 0.24 cents per kilowatt-hour; by contrast, bulk power rates or privately owned utilities averaged about 1.5 to 2.0 cents per kilowatt-hour, several times the rates for Federal power. 5. Combination Financing In the past decade or two, there appears to have been an accelerating trend towards joint ventures in the field of power generation. Utilities have found that considerable economies of scale are to be found in extremely large power plants. A single large plant may provide enough power to meet the growth needs of an in- dividual utility for several years. This means that when such a plant goes into 6-28 operation, the utility will have excess capacity for several years. It also means that the cost of building it will be very large relative to the exist- ing capital investment of the utility. Given the increasing financial dif- ficulties of most utilities, as well as a desire to share risks and to avoid excessive unused capacity, there has been an increasing amount of joint venturing in the construction of these large power plants. The joint venturing which has occurred has taken a variety of forms. Often these involve cooperation among private utilities, state or municipal utilities, and coops. A few examples will be discussed, but it should be understood that much more various schemes may yet be implemented. a. In the 1950's and 1960's, there were several atomic power plants built in New England by new corporations specially created for each plant. Shares of these corporations were held by privately owned utilities who gave guarantees to purchase power from it in proportion to their respective ownership shares, and to share costs in the same proportion. By virtue of these guarantees, the new corporations were able to borrow very heavily to construct their plants. Two new corporations were Yankee Atomic Power Company and Vermont Yankee. b. Tenancies in common. A more popular form of joint venture is the tenancy-in-common. In this form, the participating corporations, which may in- clude coops and municipal utilities, as well as private utilities, enter as partners in the construction of a large new power plant. Ordinarily only a single plant is involved, and one of the partners is made responsible for opera- tion of the plant. In most cases, municipal utilities and coops are junior partners to the private utilities. For example, a group of Massachusetts municipal utilities has bought a 3 percent share in the Millstone No. 3 nu- clear plant; a group of Florida municipals and coops bought a 10 percent share 6-29 in Florida Power Cor.’s Crystal River No. 3 nuclear plant; a group of seven muni- cipal utilities in Kentucky and Indiana has an option to buy a 7 percent share of Public Service Company of Indiana’s Marble Hill nuclear plant. But in other cases, municipal utilities and coops are independently embarked on massive generating construction programs. ce. In New York, the seven privately owned utilities have formed a new cor- poration—Empire State Power Resources, Inc., which, pianubaee™ will construct and operate all new power facilities in the State. It is contemplated that ESPRI will ultimately invest $16 billion in generating facilities over the next two decades, the bulk of this capital to be ‘raised by ESPRI itself. Because the otvun sponsors will jointly and severally guarantee to buy all the power that ESPRI produces at rates fully compensatory to ESPRI, it is believed that ESPRI will be able to use an 80 percent debt ratio, with the sponsors contributing equity funds for the remaining capital. Thus, substantial savings in capital costs are contem- plated, as well as large cost savings derived from centralized planning and con- struction, It is clear that where the joint venture takes the form of a partnership among participating utilities, there are no financial etrhictenhe derived by any of the partners. That is, each partner is responsible for raising his share of the capital by the ordinary means, and at the ordinary costs, involved in his business. But where a new corporate entity is formed, with power independently to raise capital from the public, the possibility arises of reducing the cost of capital for the new plants. This possibility arises because the partners in this new venture can, by firm guarantees to buy power from it, give investors a rela- tively high degree of confidence in its credit-worthiness, 6-30 Financing Alternatives for Power Supply in Alaska In the present section we will discuss various alternatives to the present organization and financing of power supply in the State of Alaska. This discus- sion of specific alternatives will be prefaced by some general remarks about the factual and conceptual assumptions of the discussion. It is not the purpose of this report to make specific recommendations on the reorganization of power supply in Alaska. Rather, the more modest task of pre- senting and discussing alternatives has been undertaken, The legislative decision maker must weigh this discussion in light of his own evaluation of certain im- portant general considerations. First, to what extent is it desirable or necessary to provide State assistance to electric consumers? Second, to what extent should the State involve financial and managerial resources in this area, as opposed to other areas of activity? In addition to these general considerations, the de- cision maker must also give detailed consideration to the pros and cons of each of the suggested alternative approaches, with perhaps different emphases than are placed in this report. The organization and financing of electric utilities is to a considerable extent a function of the character of their operations. Our judgments here flow from certain characteristics of power supply systems in Alaska, which are treated in greater detail in other parts of this report. Firstly, although utility service in Alaska has hitherto been provided by small, electrically isolated systems, there now exists the prospect that it may be economic to create a large, integrated power supply system for the Anchorage, Southcentral, and Fairbanks regions, possibly based on the proposed Susitna hydroelectric power development. 6-31 Secondly, there are in any event, likely to remain many areas and communities which will, for economic reasons, continue to be served by small local utilities. Thirdly, it is expected that electric power consumption in the more populous areas of Alaska will grow by more than 10 percent per year over at least the next decade or two. Given the very high costs of electrical equipment and con- struction, this rapid growth rate in demand for power implies a level of capital expenditures which will be quite large relative to investments made in the past. Fifthly, in some communities the costs of providing power will be extremely high, whatever means is used to generate it and whatever the financial arrangement. These characteristics imply the following general conclusions. The major cost advantages which can be gained through centralized reorganization of power supply in Alaska will principally accrue in the Anchorage, Southcentral, and Fairbanks regions where there is the prospect of a large-scale integrated power supply system. The gains to electrically isolated power companies should be relatively minor, unless there is cross-subsidization, i.e., unless charges are designed so that Anchorage ratepayers pay part of the higher cost for generating power in the remote villages. . Also, the creation of large power supply systems, such as that contemplated for the Cook Inlet-Railbelt region, can give rise to very considerable problems of organization and financing. The State Government can therefore play a critical role in achieving the prospective cost savings by either providing financing support or by acting as an organizational catalyst. One of the conceptual presumptions of the present report is that when considering any financial reorganization of the utility industry that it may be desirable to retain certain aspects of existing arrangements. Many utilities borrowed money in the past at much lower interest rates than prevail today. 6-32 i, i Any reorganization scheme which would, for legal reasons, require the repayment of that debt, and its replacement with new issues, would impose substantial costs on ratepayers. If we assume, e.g., that utilities in Alaska have outstand- ing debt of $200 million, at an average interest cost that is 3 percentage points less than the current cost of debt, then if the outstanding debt must be replaced by new debt, consumers will have to bear an additional $6 million per year of interest costs before any allowance for coverage requirements, This extra interest burden will have the further effect of limiting the amount of new debt that can be sold thus requiring extra equity capital to be provided. The importance of the foregoing should not be exaggerated, however. If total capital investment of Alaska utilities grows by 10 to 15 percent per year, then in 10 years from 60 to 75 percent of the capital, and the debt, outstanding will have been raised after 1975, anyway. Thus, the relative impact of having lost the advantages of older, lower cost debt will rapidly diminish over time and in a decade or two will become quite minor, In the short run, however, the effect would be sizeable. We turn now to a specific discussion of possible new forms of organizing power supply in Alaska. In presenting these alternatives, we have looked first at the most comprehensive involvement by the State Government, then examining progressively lesser degrees of involvement. 1. Alaska State Power Authority One alternative, of which there could be several variant forms, would be for the State Government to take over all power supply in the State of Alaska. The following are variant versions of this: a. The State takes over all existing generation and transmission 6-33 as well as distribution and is responsible for all future construction. b. The State takes over all existing power generation, but leaves dis- tribution to existing enterprises. c. The State takes responsibility for construction and operation of all new generation, but leaves old generation, as well as distribution, in the hands of existing utilities. All three variants have serious problems attached to them. The most serious in the view of the sachet, is that of centralizing what is, in fact, a highly decentralized maui: The result would unavoidably be to reduce management’s responsiveness to local needs in the design and operation of local systems, and to eliminate the local sense of responsibility and participation. In many cases, there is probably relatively little that a central authority could add in the way of technical expertise-which in any event could be made available in an advisory ca- pacity—or through coordination. In variant (a) there would also be the loss of the advantages of the relatively low embedded debt costs, which would be especially great in the case of REA coops. The same applies, in lesser degree, to variant (b). Variant (c) deserves more serious consideration. Aside from the management problems mentioned above, there are some important financial considerations which should be taken into account. We assume that the State assumes a monopoly over construction of power generation facilities, and that it emerges as a whole~ sale supplier of power to utilities in Alaska. We assume that capital funds to finance this construction are principally derived from revenue bonds issued by the State Power Authority. In order to sell such bonds, there must be both some reasonable property as security, and a firm prospect of revenues sufficient to meet debt service requirements. The former is no problem, But the latter requires some 6-34 obligation by the wholesale customers, i.e., the local utilities, that they will indeed buy the Authority's power in sufficient quantity. There have been numer- cus power supply contracts in which the purchasers agree to buy fixed amounts of baseload power from the producer, or otherwise fully compensate the producer for the capital costs of his plant. But in most such cases, the purchaser is one of the owners of the plant, or finds it financially advantageous to buy power under conditions which almost make the buyer a lessee of the plant. With the many such supply contracts which would have to be put into operation in Alaska, and with the essentially involuntary obligations placed on the wholesale customers, there could be numerous circumstances in which the customers suffered severe financial disadvantages. Perhaps, however, the many local difficulties could be overcome by a system in which the State would only construct new generation in a locality at the request of the local utility - a request couched in terms of an offer to buy given quantities of baseload power in specified years. There are important financial advantages and disadvantages of these schemes which merit discussion. First, by and Tange, it is the case that tax-exempt se- curities bear the lowest interest costs. A State Power Authority would probably have to pay less interest than a private utility, slightly less than a municipal utility, 9? less than a coop building a large generating plant, but more than a small coop, which could probably borrow most needed capital for only 5 percent. Since coops in Alaska account for over half of the power sold in the State, and they continue to be able to borrow at REA's ss alipeadie rate, or less, the overall financing costs of a statewide power authority might well be higher than what must be paid by the utilities as they now stand. Such a power authority would also be able to provide a centralized and specialized management. But the centralization of planning would be more of a hindrance than a help to small electrically isolated systems. And the advantages of specialized management might well be achieved under alternative schemes to be discussed below without completely sacrificing local control. 6-35 2. Central Alaska Power Authority A second approach would be for the State to build, own, and operate a major generation and transmission system in the Anchorage, Southcentral and Fairbanks regions. Presumably, the State would interconnect with all local utilities for which that would be economically feasible. The Authority would then market power to these utilities. It would be financially advantageous to the Authority to sell most if not all of this power under contracts which assured the Authority that its costs would be fully recovered at all times. Whether that could be done might depend upon whether the new generating facilities would be providing baseload power and whether its rates would be lower than the fuel costs of the existing plants of the present utilities. 9" With an efficient interconnected system serving the region, it would probably be desirable to have central dispatching of power. At any moment in time, power would be produced from that group of plants, irrespective of ownership, which could most economically produce and deliver the power consumed at that time. If such a central power pool existed, it would be necessary to provide for the power compensation of the parties involved, along the lines of the many power ais now operating all around the U. S. The problems of setting up appropriate payment mechanisms are far from insoluble. They have in fact been resolved in various ways in more or less similar circumstances elsewhere in the country. The precise manner of annette them in the present case would depend upon the pertinent factual circumstances, and on how the various affected parties would conceive their interests. These problems have been mentioned here so that the reader may be aware that precise solutions have to be worked out, and also because the form of the State's financial involvement could be affected. The latter point should be discussed to indicate the State's interest. Ideally, the financing and administration of such a power project would he easiest and least costly for the State if all of the utility customers of the project were 6-36 ‘committed to purchase fixed amounts of baseload power from the project. This would be true regardless of the ownership of the project. Also, the charges by the project to the customers should be automatically passed through te nupbaneells Finally, there should be some institutionalized assurance that the utility cus- tomers are in reasonable financial condition. If these conditions are met, then the project could be financed at the lowest cost, for these conditions amount to a guarantee of the project’s debt by its customers, Of course, a similar degree of assurance might be provided by a State guarantee of the project’s debt, but it is not clear that dendave would necessarily regard the State as a better risk than the utilities, Such a guarantee might, in addition, ultimately affect the State’s ability to finance other types of outlays. The construction-and-operating cost savings that might be achieved by this project are dealt with elsewhere in report. It should be mentioned, however, that if there is the prospect that one major construction project in the Cook Inlet-Rail- belt area might be followed by others, there could be important savings through the creation of a continuing staff of experts to plan, build, and operate such projects. It seems reasonable to expect that a state power agency of the kind dis- cussed above, and with the revenue assurances described, might be able to obtain a lower interest rate than either privately owned or municipal utilities in tasks? ta fact, it might be able to sell bonds at an interest rate of not much above 6 percent. This is still higher than an REA loan. But a State power authority may also be able to maintain a very high debt ratio with very low coverage re- quirements, and hence achieve the lowest overall cost of capital. 6-37 3. Central Alaska Power Company A third possible alternative would be for some or all of the utilities in the area to form a new entity to build and operate the new project with varying degrees of financial participation or assistance by the State, a. One variant might be for the State to build, own, and operate the pro- ject, but to accept capital contributions from utilities willing and able to make them, Companies making capital contributions would be charged reduced rates, in proportion to their capital contribution. Each utility could then calculate whether it could raise capital more cheaply than the State, and would be a capi- tal contributor, or not, in accordance with what that calculation revealed to be the lowest cost for it. In this way, the total financing cost of the project would be minimized. b. A second variant might be to forma new corporation which was not an agency of State government, and in which some or all of the utilities would be stockholders, This new corporation could then borrow on its own account. There are probably legal and tax difficulties associated with such a scheme which would, for example, mean that this corporation could now borrow at tax-exempt rates. c. A third variant might be to form what would amount to a partnership, or tenancy-in-common, which would build and operate the project. The partici- pants would be entitled to buy power at cost in proportion to their capital contributions. The new venture’s cost of capital would simply be that of the individual contributions. There are several ways in which (c) could be assisted by the State, 6-38 i) A State Power Financing Agency could borrow money in the market 36 and advance these funds, at cost, to individual utilities to invest in this project. This would make each utility's own capital contribution a function of its ability to raise capital at lower rates than what it would have to pay the State. ii) The State could become a part owner of the project, selling its share of the power to utilities unwilling or unable to become full partners in the project. Thus, all utilities in the area could share in the cheaper power to be provided by the project, while the financially weaker utilities or those with relatively high costs of capital, would not have to put up their full share of the required capital. It seems likely that the State could finance this investment by the issuance of revenue bonds backed by firm power sales contracts. iii) The State could build the project and lease it to participating utilities. The State's financing might then be possible through revenue bonds. This would have the advantage of relieving the State of the prob- lems of managing this enterprise. It would, however, involve the State in a long-term financial commitment. Moreover, such a lease might not be considered good security by lenders, especially if they questioned the credit-worthiness of the lessees. iv) It might well be that the most critical financial assistance which the State could provide the utilities would be in financing the project during its term of construction. Given the long period of construction, it may un- duly strain the finances of a utility to have to raise and invest large amounts of capital years before that capital can produce any revenues for 6-39 the utility. A State agency could ease this problem by financing the construction of the project and then selling, rather than leasing, it to the participants. This would mean that the State would not be engaged in a long-term financial involvement in the power supply business, and that the project would be self-liquidating in a relatively short span of years. 4. State Power Financing Agency (SPFA A State agency could be created to assist any utility (not just one in the Cook Inlet-Railbelt area) with its financing problems. This agency would lend money, as required, to utilities in the State unable to raise capital as cheaply as the agency. 2” Such assistance would be especially helpful to municipal utilities and to coops required to obtain non-REA loans. These loans should be reasonably secure; legislation could be devised which would give the Public Utilities Commission the authority to require any defaulting utility to raise its rates enough to enable it to repay the loan. But even this might not help in circumstances where the utility faced with declining local demand for power would be unable to raise revenues by rate increases. Consideration might also be given to the establishment of a revolving capital fund, perhaps financed by a power receipts tax, which would lend money to small utilities. A different function for a state power finance agency might also be devised. There might also be created an agency to insure and/or to guar- antee the borrowings of any utility in the state. This would keep to a minimum the actual financial involvement of the state, while still pro- viding considerable financial aid to many utilities but not to coops, whoSe borrowings are already insured or guaranteed by REA. 6-40 5. Technical Assistance As was indicated earlier, it may be undesirable to centralize the management of all the utilitics in the State. Yet there are certainly economies to be achieved if technical and managerial assistance can be offered on a regular basis to the smaller utilities in the State. Whether this function is, or can be, adequately performed by private dbnduletag firms should be investigated; the very small utilities may not be able to afford private consultants. Thus, a State agency for this purpose might provide many of the ieee without the disadvantages of centralized management. This agency could put out publications, or provide training seminars, to keep utility managers fully informed on modern techniques. It could also review capital spending programs of the utilities from both a technical and economic standpoint, perhaps with a statutory requirement that no utility could make expenditures above a certain amount without the agency’s approval, It is clear that the scope of activities of such an agency could vary widely; it also seems clear that the agency could develop expertise that would be very helpful to many utilities in the State. 6-41 SUBSIDIES FOR ELECTRIC POWER The decision on whether, and to what extent, electric power consumers should be subsidized ultimately involves value judgments at which the eco- nomist can offer no expert advice. What the economist can do, however, is to suggest how to avoid subsidies which have particularly uneconomic effects. For the purposes of this discussion, electric consumers receive a sub- sidy if they receive power for a rate less than the additional (marginal) cost required to supply that power. In a system operating at considerably less than full capacity, this additional cost may be little more than the price of the additional fuel required to serve the consumers in question. If the additional demand requires capital expansion, however, any rate which does not also recover an appropriate portion of the capital cost (de- preciation and interest) for the new facilities involves some subsidy. The issue of subsidized rates usually arises in connection with the rate structure of individual utilities and the relative burden on different classes of ratepayers. It is often said that the typical declining block rate system subsidizes large consumers at the expense of smaller consumers, and several state utility commissions are considering requiring a modifica- tion, or even the "inversion" of this system, both to subsidize smaller (and presumably lower income) consumers, and to discourage the growth of demand. So-called lifeline rates would provide each residential customer with a hookup and a first block of power at a lower average rate than the rate charged for subsequent blocks. Whether or not a particular declining block rate structure or life- line rate actually involves a subsidy to any class of consumers depends 6-42 upon the details of the rate and of the cost configuration of the utility in question. The issue of alternative rate designs for self-supporting utilities is an important one for the state to examine from the standpoints of both equity and energy conservation, but it is outside the scope of this report. The subsidy issue with which we are concerned here arises where there is no rate structure which would provide a particular utility with suf- ficient revenue to be financially viable, because of high costs and a low income population. The citizens of Alaska might deem it unacceptable that any community go without electricity for this reason, and determine to make up the shortfall in some fashion out of the stake treasury. Where power rates in Alaska are unusually high, the main causes are in- variably one or more of the following factors: 1) low population density leading to high distribution costs; 2) low usage per customer and consequent low load factors (resulting from low per capita incomes) with the same re- sult; 3) remote location leading to very high fuel and plant costs, and 4) small loads leading to inefficient generating plants. Bearing this in mind, we must ask in what regard a rate subsidy can have uneconomic effects. If we assume that it is socially desirable that power be made available to everyone, even if the cost of doing so exceeds the willingness or ability of some customers to pay for the full cost, then once the customer is hooked up, the economic question becomes one of how much power the customer should consume. 6-43 Suppose, for example, that a utility received an operating subsidy that allowed it to charge its customers less for power than the price of fuel necessary to generate that power. It might then be advantageous for people to heat their homes with electricity, despite the fact that direct oil heat would have used only one-half or one-third of the fuel consumed in generating electricity. So long as the rate to the customer is at least as great as the cost of generating additional power, so that the customer is paying the full cost of whatever increments in power he consumes, the rate does not give rise to uneconomic consumption. Moreover, as he increases his consumption, the unit cost of distribution will decline, and if the rate he pays is greater than the incremental cost of generation, then with increased consumption, he will be making an increasing contribution toward covering part of the fixed costs of the generating plant and distributing facilities. From the economic standpoint, therefore, the effect of subsidizing the facilities necessary to serve all of a community's population is quite dif- ferent from subsidizing the cost of generating the power he consumes, be- cause the latter would encourage wasteful excess consumption. We would pro- pose as a general rule for subsidies, therefore, that whatever form they take, they not be used to reduce rates below the variable costs of gener- ating power. There are presently two programs operating in Alaska which in effect subsidize the capital outlays of village utilities. The first is the low interest credit available from REA. The 2 percent loans with which the Alaska Village Electric Cooperatives (AVEC) has financed its facilities re- duce the fixed costs of the village utilities by about two-thirds, compared with conventional credit arrangements. 6-44 The second form of subsidy is the "take-or-pay" contracts which the Bureau of Indian Affairs and State Operated Schools executed with AVEC or village utilities for blocks of power substantially exceeding the amounts the schools actually consumed. These contracts provided a fixed payment that was not directly offset by increased fuel consumption, and thereby contributed toward the fixed capital cost of the system. As local govern- ments take over the bush schools, however, these contract obligations are not being assumed by the schools' new operators, to the serious distress of AVEC. In addition to subsidized credit, or direct state assistance in the purchase of capital equipment, there are various ways of reducing the aver- age cost of power to a utility's customers without violating the rule that the incremental rate charged for power should be at least as high as the variable cost of generation. The simplest and probably most efficient way is to give direct subsi- dies to the utility companies. Suppose that the variable costs of genera- tion nowhere exceeded 10 cents per kilowatt hour. Any utility company whose costs exceeded 12 cents per kilowatt-hour, for example, would be required to reduce all rates to that average level, with the State paying it for any consequent revenue shortfall. (The PUC could readily fix the amount of shortfall.) Note that this might result in sole. individual customer paying more than 12 cents. But the utility could be required to reduce its highest rates, which would direct the subsidy toward the neediest customers. 6-45 A direct subsidy payment to consumers would, on the contrary, be difficult and expensive to administer. If it gave each utility customer a lump sum unrelated to his electricity consumption, such a subsidy would really be no different from a general welfare payment; it would not, on the other hand, encourage inefficiency in energy consumption. A payment per kilowatt hour consumed would encourage greater consumption and subsequently a greater outlay for subsidies, of course. If it reduced the net price of electricity below its variable cost, such a subsidy would result in inefficient fuel use as well. And any scheme in which the state directly reimbursed individual customers for any payments exceeding a specified rate per kilowatt hour would tend to reward customers of utilities which had relative wide differences in the rates paid by different customers, and might even encourage such discrimination. 6-46 FOOTNOTES Large plants generally tend to be very fuel efficient, reflecting a tradeoff between capital costs and fuel costs. The utility typically earns about 12 percent on its common equity capital, which is one-third of its total capital. Two-thirds of these earnings are paid out as dividends. Thus, retained earnings are equal to 1.3 percent (1/3 x 12% x 1/3) of net plant. In addition, depreciation equals 3.0 percent of net plant. Thus, total internally generated funds will usually be a bit less than 5 percent of plant or 15-20 percent of revenues. It may be worth pointing out here that a major portion of utility capital is provided by insurance companies and pension funds whose need to avoid excessive risk is quite obvious. For some utilities, the minimum coverage is as low as 1.75 times or as high as 2.5 times, but 2.0 times is the standard in the over- whelming majority of cases. It should also be noted that the pre- cise way in which the coverage ratio is computed varies somewhat among utilities. The average utility today is earning about 11] percent on common equity. Thus, its return after taxes is about 7.88 percent: Debt: -55 @ 6.2% = 3.41% Preferred: -10 @ 6.2% = .62% Common Equity: _.35 @ 11.0% = 3.85% 1.00 7.88% Since Federal income taxes equal about 1 percent of capital, the pre- tax earnings rate is 8.88 percent. The interest portion of this is 3.41 percent. Thus, the coverage ratio is 2.6 times (7.88 = 3.41 = 2.6). See "Prepared Statement of Irwin M. Stelzer and Herman G. Roseman be- fore the United States Senate Committee on Interior and INsular Af- fairs," August 7, 1974; and H. Roseman, “Utility Financing Problems and National Energy Policy," Public Utilities Fortnightly, September 12, 1974. The rise in the cost of equity money has taken the form of a sharp de- cline in utility stock market prices over the past several years. 6-47 10. ITs 2s 13. 14. 15S 16. We 18. We are indebted to Mr. T. Swick and his associates at White, Weld & Co. for invaluable suggestions relative to this section and to Section III, below. Naturally, any errors which remain are solely our responsibility. Derived from data in Federal Power Commission, Statistics of Public] Owned Electric Utilities in the United States, 1973 and Edison Electric Institute, Statistical Year Book of the Electric Utility Industry for 1974. We believe that such capital contributions were usually made at the inception of the municipal utility. In recent years, there have emerged a number of mutual funds special- izing in tax-exempt securities. This is in contrast to private utilities whose bonds involve no principal repayment until final maturity, usually 30 years after issuance. By contrast, the private utility can count some or all of non-operating income in its earnings for purposes of calculating coverage. It is necessary to repeat that this figure varies significantly among utilities, with 1.5 times being the most common figure, but also the highest figure. The larger and more creditworthy municipal utilities often have somewhat more lenient coverage requirements. Note that if 10 percent of the utility's capital were tied up in construction work-in-progress, this would mean that the utility would have to have a return of almost 10 percent on the actual plant in service. The important point to be recognized here is that there is no free source of equity capital to the utility, although the utility need not pay cash dividends to suppliers of equity capital (except per- haps in the form of reduced rates). Any capital raised from rate- payers (or taxpayers) costs them something, and that cost must be considered as a matter of public policy. By way of analogy, the homeowner deludes himself if he thinks the cost of the capital in- vested in his home is only the interest he pays on his mortgage, and if he ignores the cost of the equity capital he has tied up in his house. This is the cost of raising new capital. Derived from data in Federal Power Commission, Statistics of Publicly Owned Electric Utilities in the United States, 1973. 6-48 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. Derived from data in Edison Electric Institute, Statistical Year Book of the Electric Utility Industry for 1974. In the year ended May 31, 1975, CFC made loans of $256 million. The bulk of CFC loans made during 1974 were at 7 percent interest, but in 1975 CFC has been charging 9.25 percent on the bulk of its loans. For every $100 of capital there is $75 of debt with an annual interest payment of $5.25 (.07 x $75 = $5.25). Coverage of 1.5 times means earnings of $7.88 (1.5 x $5.25) on capital of $100, or a rate of return of almost 8 percent. The opportunity cost of equity is the rate of return a coop member could expect to earn if he invested his money in another enterprise of comparable risk. Sales to private industry and to private utilities are not infrequent, and in some cases a generating plant is simply leased to a private utility. On occasion, the facility will be turned over to a non-Federal agency. For example, the Salt River Project, a political subdivision of the State of Arizona, operates certain hydro plants (originally built by the Bureau of Reclamation) under contract with the U. S. Govern- ment, as well as builds and operates plants of its own (which now provide the bulk of its power). TVA's rates are not subject to any regulation by outside bodies. In the case of Bonneville Power, about 80 percent of the project costs are allocated to power supply. For example, the Southwestern Power Administration (SPA) stated in its 1974 Annual Report: "For the first time in 31 years of operation, SPA is meeting its responsibility under that portion ... of the Flood Control Act of 1944 which requires SPA 'to recover the cost of producing and transmitting such electric energy including the amortization of the capital investment allocated to power over a reasonable period of years.'" Attached as an appendix to this report is a copy of an article in the. September-October 1975 issue of Public Power (the journal of the American Public Power Association) fully documenting the degree to which public power agencies were engaged in various sorts of joint ventures. The companies are seeking regulatory approval for this project. 6-49 31. 32. 33. 34. 35. 36. 37. Obviously, the cost savings from economies of scale are great enough to have encouraged a considerable number of these joint ventures to be formed. It is possible, however, that investors might be more receptive to a diversified package of securities from a number of smaller com- panies than to the large package from this single borrower. Although most coops in the U. S. have in recent years had heavy re- liance on higher-cost non-REA loans -- which were twice as great as REA loans. in 1975 -- this has not. been true in Alaska. Coops in Alaska borrowed $54 million from REA in 1974-75, but had only $5.2 million in non-REA loans in those years. That is, would the existing utilities always find it in their financial interest to buy whatever State power was available, or would they tend to produce from their own plants leaving some State plants idle? If there might be a significant tendency for the latter to occur, then-it might prove necessary to require the individual uti- Tities as a°condition for interconnection to pay for certain minimum quantities of State power. This would, in part, depend on whether the investment community had any real preference for diversity of borrowers. ‘It is not clear that. these could be "revenue bonds", and general ob- ligation. bonds might be required. It is not clear that this agency could be financed by revenue bonds, but> general obligation bonds might be required. 6-50 we —- VII. ANALYSIS OF GENERATION ALTERNATIVES Economics of Generation Mode The choice of mode and amount of electric generating facility in any particular situation depends upon the costs of equipment and fuel and upon the particular configuration of electricity demands to be satisfied. This section presents a simplified analysis for the non- engineer and noneconomist of the basic analytical principles for design- ing an electrical generating system. A. Demand Configuration Analysis of the system begins with the nature of the electricity demand to be satisfied. Three basic components of electricity usage must be identified because they will effect the choice of system. 1) The total number of kilowatt hours (kwh) of electricity consumed in.a year is the amount of electricity reaching customers, and determines the amount of fuel that needs to be burned or the amount of water allowed through the turbines of a hydroelectric facility. 2) Peak kilowatt electricity consumption in a year is the amount demanded during that hour of the year when usage of electricity is at a maximum. This amount, measured in kilowatts or megawatts, determines the level of electric generating capacity which must be available at the peak time of the year. In Alaska, this generally occurs during the winter months. To insure that the required capacity will be available, 7-1 backup units must be available to the utility in the event of the failure of an operating unit. This reserve is described in Section C. 3) The variation of electricity use during the day, the week, and the seasons of the year determines over what percentage of time various amounts of electricity will be demanded. A schedule of electricity demand levels for the entire year can be translated into a load duration curve. The load duration curve allows one to calculate the number of hours during the year that a certain amount of electricity is demanded. In addition, it includes a representation of total kwh sold and peak kw demanded. A hypothetical load duration curve is shown in Figure 7-1. Figure 7-1 HYPOTHETICAL LOAD DURATION CURVE 2s Peak Load. Demand in Ti oe ae oe Tatermeduate Megawatts ; Load ! | Base Load AMM Hours During Year 8760 7-2 The number of hours of the year, 8760, is on the horizontal axis and demand measured in megawatts on the vertical axis. The level of demand for each hour of the year is represented in descending order. Thus point a, at 25 megawatts, is the peak for the year. Point b indi- cates that demand is at least 15 megawatts for 1000 hours during the year. (This might consist of 100 10-hour periods during as many different days.) Total energy sales is represented by the area under the load duration curve. Load factor is a term often used to describe the relationship between peak demand and average demand. It is calculated as the ratio of average kilowatts demanded during a period of time divided by the peak kilowatts demanded during that same period. Knowledge of the load factor gives an indication of the shape of the load duration curve, but not its exact shape. It is obvious from the load duration curve that a certain level of demand occurs year-round. This demand level is usually referred to as the base load. For a small portion of the year, demand is very much above the average. This increment of demand at the top of the load duration curve is known as the peak load. Between these two extremes is the intermediate load, which is the range within which demand will vary for most of the hours of the year. The load duration curve will be different for every demand center (market). The height and shape of the load duration curve will be one factor in deciding what combination of generating plants is most economical for a given location. This is because different types of plant are generally best suited for one type of load. For example, a nuclear plant or large coal fired steam plant is best suited for base load because of both a low 7-3 variable cost, mainly fuel, in relation to total cost and high costs of starting the plant up to produce electricity. A gas turbine, for exactly the opposite reasons, that is, because of a relatively low fixed cost and high fuel cost, is well suited for peak load generation. B. Generation Plant Characteristics Affecting Cost This section contains a basic discussion of the most important factors that affect the economic choice of generation plant. 1) Size of Plant: In general, there often are significant economies of scale in electricity generation. The cost of a kilowatt of electricity from a large plant will be less than from a small plant because the cost of construction per kilowatt of power declines as the size of plant increases. This will be most significant for plants which are the most capital intensive, that is, where initial construction cost is a larger percentage of total cost. However, this generalization does not apply uniformly to hydro plants, where transmission and site development costs are greater percentages of total investment than operating equipment. Figure 7-2 presents a set of curves which show the initial capital cost of different kinds of fossil generating plants of various capacities. Costs are approximate estimates as of 1975 for the Anchorage area. All types of plant exhibit economies of scale in the range examined. Geothermal plants show the least reduction in cost as size of plant increases. Like hydro, their costs are site specific. Diesel generators and gas turbines decline somewhat more in unit cost as capacity increases. Large steam turbines exhibit still more decline in unit capital cost as plant size increases. The larger the plant, the smaller the unit cost. 7-4 2) Initial Cost: Figure 7-2 indicates also that the per kilowatt initial cost differs significantly with the type of plant. Gas turbines have the lowest initial cost for most sizes of plant examined. They are followed by small diesels and then the large steam turbines. The initial cost for hydroelectric projects and geothermal units is determined by the specific site but normally exceeds that of steam turbines of comparable size. Nuclear plants also have very high initial costs. The larger the initial cost of a generating facility, the more important is the cost of capital in determining the total cost of electricity generated. For a hydroelectric project where most of the cost is initial construction cost, increasing the cost of capital from 4 percent to 8 percent would nearly double the unit cost of electricity. 3) Ratio of Fixed Cost to Total Cost: For a given size range of generating units, a plant with higher unit fixed costs generally will have lower unit variable costs. A large steam or nuclear plant has a high ratio of fixed to total cost. As noted above, such a plant is best suited for base load operation. This is because most revenues from the sale of en will go into fixed costs, which must be recovered regardless of whether the plant is generating electricity or not. If the plant is operating at a 90 percent plant factor, operating as a base load for most hours of the year, the fixed cost will be spread over a large number of kilowatt hours. If the plant is operating at 50 percent plant factor, however, the unit cost of the electricity will be nearly doubled as output is decreased by almost half. There are few variable costs which can be eliminated as production of electricity declines. 7-5 Figure 7-2 HYPOTHETICAL CAPITAL COSTS PER KILOWATT FOR VARIOUS TYPES OF ELECTRIC GENERATING PLANTS =a Se me Fa Pet eed oe es ee 4 547290 3 456789 7-6 4 5 67390 3 (1,000, 000) 700, 000) ( (10,000) (4,000) Size of Generating Unit in Kilowatts On the other hand, gas turbine plants have low unit fixed costs and, in general, high variable costs. In most instances, discussed below, such units are most suitable for peak load or low load factor generation. In addition to their ability to be turned on and off rapidly, these: machines do not cost much when they are not in operation because most costs are for fuel and labor which occur when the units are operating, but not otherwise. If gas turbines are operated as base load, on the other hand, they tend to be more expensive than traditional base load units unless very inexpensive fuel is available. (This has, incidentally, been the case in the Anchorage-Southcentral Alaska region since the early 1960s, but is not likely to continue long.) In contrast to the case in which fixed costs are a large percentage of total cost and the price of capital funding is very important, when variable costs are a large percentage of total costs, unit costs are very sensitive to the price of fuels. This is indicated in Figure 7-3 for several types of fossil fuel plants. Construction costs are estimates for Anchorage in 1975 and fuel costs vary as indicated. The curves are hypothetical and meant to be illustrative only. 4) Conversion Efficiency: Efficiency in the use of fuel varies with the type of generating equipment and with the fuel itself. Some fuel pro- duces more water when burned than other fuels. This steam is lost out the stack of the plant and reduces conversion efficiency.) This efficiency of conversion is measured by the heat rate in fossil fuel plants. Heat rate is defined as the number of btu's (British thermal units) required to pro- duce a’ kilowatt of electricity, because all fossil fuels can be measured in terms of thermally equivalent btu's. A perfectly efficient unit would convert all the btu's in a fuel to kilowatts of electricity at the rate of 3415 btu/kwh. This is technically impossible because of heat loss "out the stack" of the unit and into the 7-7 Figure 7-3 °, UNIT ELECTRICITY COST UNDER VARIOUS FOSSIL FUEL PRICES Ge AND GENERATING UNIT TYPES AND SIZES a 70 a t 7 —— + 4+ coal Fired Power Plant esas = 4 fe Diesel Generator ammaccmm dl + - ea +—| Gas Turbine (Simple Cycle) [ | Steam Turbine (Gas Pired) — Be 4 _— Fae | Steam Turbine (Oil Fired) oe ee i 1 t e ie . nt 1 While TH coal Saga laale Nall —- M4 : at = ‘Ie “t aes zi ‘ TTT | | : ai 373¢ mmbtu " 50 ay et ++ 14 i | "© Pp t + + ~t tree b oF) 5996 mmbtu N eo ae I B N x SS = N im ¥ heehee Ss 2 NIN. = 2 H [ =4 Gas 707% mmbta | Electricity Cost: N Ss fo a aw S24 meet Coo} 1/4 mmbtu 1 Gas 53.5%mmotu is 35¢ mmbtu 4 1 th 574 3 4 567890 2) eee Clare 2) 8 ¥ S678In ZT I oer @ (7,000) (10, coc) (100, 000) (1,000, 000) Size of Generating Unit in Kilowatts - $ - i = = a cooling medium of the generating equipment. The best actual heat rates in Alaska are in the range of 10-11,000 btu/kwh, which is an efficiency of less than 33 percent in the use of fuel. The most efficient large fossil units in the Lower 48 rarely achieve a heat rate of 9,000 which is the approximate present technologically feasible limit. Obviously, the higher the heat rate, the lower the efficiency of conversion of fossil fuel into electric energy. Heat rate varies with the type of fuel, the type of generating unit, the characteristics of the particular plant examined, and the operating schedule of the plant. A gas fired open-cycle turbine plant generally has a lower heat rate, or higher thermal efficiency than an oil fired open-cycle turbine. A regenerative cycle gas fired turbine plant has a lower heat rate than an open-cycle gas fired turbine because the regenera- tive cycle allows the conversion of some waste heat into additional usable electricity. This is because the exhaust heat is not directly vented to the atmosphere in a regenerative cycle unit, but rather is used to pre- heat the intake air. The increased efficiency of combination plants is only available at the cost of considerable additional investment per ad- ditional kw produced. The size of a unit and its location also affect the efficiency of conversion. For example, gas turbine efficiency increases as the ambient air temperature declines. Finally, average efficiency will be higher for a plant which operates constantly relative to a plant which is turned on and off frequently. 7-9 Greater efficiency in the conversion of fossil fuel by one type of plant may be counterbalanced by fuel prices which do not reflect equal unit cost per available btu's. In mid-1975 the average prices for fossil fuels per million btu paid by electric utilities throughout the United States were as follows: Source: Table 7-1 FOSSIL FUEL PRICES TO UTILITIES - MID 1975 Fuel ¢/million btu coal 80.6 residual fuel oil 204.8 gas 66.4 Federal Energy Administration, Monthly Energy Review, August, LST 56 Thus, lower efficiencies in the conversion of gas to electricity can be balanced by a lower price per million btu's for that gas in some cases. 7-10 For Alaska, 1975 prices for new fossil fuel supplies have been estimated by Robert Retherford Associates to be as follows: ALASKA FUEL COST ESTIMATES FOR UTILITIES - 1975 Table 7-2 Fuel Location coal Fairbanks oil Tidewater gas Anchorage Source: Robert W. Retherford Associates, Anchorage, Alaska. ¢/million btu 90¢ 221¢ 60¢ Combining these cost estimates with some operating heat rates observed in Alaskan thermal plants yields a price for various fuels as burned for electricity. These relative fuel costs are as follows: RELATIVE FUEL COSTS AS BURNED FOR ELECTRIC GENERATION Plant Steam Turbine - Coal Fired Gas Turbine - Open Cycle Gas Turbine - Regenerative Cycle Gas Turbine - Oil Fired Diesel - Oil Fired Table 7-3 A Heat Rate btu/kwh 10,000 16,000 14,000 17,000 11,000 7-11 B Unit Price ¢/million btu 90 60 60 221 221 (AxB)/100,000 Unit Price isi 9.0 9.6 8.4 37.6 24.3 Efficiency in hydroelectric plants, in the sense of converting the energy of falling water to electrical energy, is about 90 percent. 5) Construction Design and Timing: Generally, the larger the plant, the longer the planning and construction period. More importantly, it is also a function of the type of plant. Gas turbines can be ordered, delivered, and installed in one year. Thus if a situation arises in which the system load growth far exceeds expectations and additional generating capacity is required on short notice, simple cycle gas turbines can be quickly added to the system even though they may not necessarily be the most economical long range investment. This has been the chief reason for the choice of gas turbines by several Alaskan utilities. A large coal fired steam plant may require 5 years construction time. The more site specific the structure, as in hydroelectric dams, or the more recent the technology, as in nuclear plants, the longer the construction time. The more time spent in construction, the higher the cost of interim financing of the project. For a large hydro or nuclear facility, this item alone can exceed 100-200 million dollars. In addition, large site specific projects involving newer technologies are more eae to cost overruns than small, quickly constructed plants. The overruns may be the result of labor union pressures, design problems, cost of materials inflation, delays in licensing, or other problems. Recent estimates of the costs of nuclear plants which have attempted to include adjustments to take into account all these factors have consistently underestimated actual costs. 6) Usable Energy: Fossil plants supply energy by simply burning enough fuel to supply the demand that exists at the time. Lesser demands require less fuel -- greater demands more. Fossil fuels can be readily stored to accomodate these variations in the electrical loads. Hydro- electric projects store "fuel" as water in a reservoir for use as required. Wind generation of electricity can occur only when the wind is blow- ing, which might not correspond to the time when electricity is demanded. The wind energy available may be lost unless it can either be stored in a battery, as pumped water storage, or in a heat sink, or integrated into a power supply system which includes units which can be turned off and on to compensate for the variable electric power from the wind generator. Some hydroelectric projects may have limited energy storage capabilities, depending upon the characteristics of the project. Such limitations usually mean that construction costs are also less; hence average energy costs will be less if the output of the project can be readily accommodated by the electric system it supplies. When it is available in conjunction with fossil fueled generation, its use should be timed to optimize the mix of fossil/hydroelectric power generation. In most cases, this results in maximizing the use of hydro when alternative generation modes are most costly. Thus, storage of hydro power is in a sense equivalent to an elec- tric battery which stores electric energy when it is cheap or opportune to produce and releases it when alternative electric generation is expen- sive. Pumped storage hydro provides the ability to use excess energy from any source, store it for a short period, and then return it to the electric system during following peak demand periods. 7-13 If banttteles for storing or using the excess energy from unregulated sources (commonly called secondary energy) are limited, it may be lost and the cost of the electricity actually consumed is increased. Other considerations affect the choice of type of generating facility in any particular situation, such as the growth rate of demand and the availability of funding for specific purposes. Expectations regarding fu- ture inflation rates will affect the choice between plants with high fixed or high variable costs. All these factors are important in Alaska as elsewhere. The conclusion of this discussion is that all must be considered in a thoughtful analysis of choice of plant. One cannot concentrate only on conversion efficiency, or fuel price, or initial fixed cost. Rather, it is the combination of all factors discussed which determines which plant is least costly for a parti- cular situation. 7-13 (a) C. Capacity Requirements: The capacity of a generating system cannot be described by a single Measure. Consideration must be given to spinning reserve, single contin- gency outages, and firm capacity in planning capacity additions, and the effect they have on the reliability, generation costs, operation and stability of the system. Spinning reserve may be defined as the capacity of a power system to pick up or serve additional load without interruption to consumers. A single contingency outage is, as the name implies, failure of a single unit of equipment or interconnecting lines resulting in the partial loss of ability to provide power to consumers. Firm capacity in Alaska is generally figured as the total generating capacity of a system, minus the largest single contingency outage. Perhaps these two concepts may be il- lustrated by referring to a hypothetical power system using four 100-mega- watt generators facing a peak load of 300 megawatts. Assume all four generators are operating at the time of the system peak load, and the load is divided equally among them. Under these conditions, each generator would have 75 MW load and 25 MW excess capacity, and for the system, the spinning reserve would be 100 MW. If only three generators were operating at the time of the peak, each generator would have 100 MW load and no excess capacity, and the system spinning reserve would be zero. 7-14 The largest single contingency outage would he the loss of any one unit, or 100 MW of capacity, or, with all four units operating each with a 75 MW load, the largest single contingency would be 75 MW (one unit). In this simple example, the spinning reserve of the three units remaining in service would be 75 MW, adequate to serve the peak load. The firm capacity of the system would be 400 MW less the largest single contingency, the loss of one unit, 100 MW, or 300 MW. Thus, the system would have an adequate firm capacity for the peak load of 300 MW. The hypothetical system presented here was used to illustrate a few of the constraints on electric utility system generation planning. Actual utility systems are much more complex. Capital and Operating Cost Forecasts The prices at which capital equipment and construction materials, site labor, and alternate fuels are expected to be available in Alaska are critical factors in the choice of additional generating facilities. The relative merits of different system designs are particularly sensitive to fuel costs, and the future prices of individual fuels are subject to exceptional uncertainties. 7-15 An attempt to estimate future costs of inputs to electrical generation depends first of all upon the long-term rate of inflation in the United States as a whole. Higher rates of general inflation imply correspondingly higher escalation rates in Alaska for equipment, materials and wages, higher long-term interest rates, and higher fuel prices. Our forecasts of all costs could have been expressed in terms of constant dollar prices, and "real" interest rates -- essentially, the nominal interest rate minus the expected rate of long-term inflation. Reduction of all prices and interest rates to real values, however, introduces serious complications in calculating even real electric rates and in assessing financial viability. In this study, therefore, analyses have generally been set out in nominal, or current, dollars. The most comprehensive national measure of inflation is the implicit deflator for the Gross National Product, or GNP Deflator, which increased at less than 2 percent per year in the early 1960's, but rose at a rate of about 9 percent in 1974-75. Inflation rates in the late 1970's and the 1980's could conceivably be as low as in the earlier sixties, or even higher than those of the last three years, depending on a number of factors that are impossible to forecast confidently, including the political influences on national economic policy. The base case projections for this study assume that the average annual rate of inflation will be 6 percent over the whole period under consideration. This figure is close to those of many mid-term (3 to 5 year) economic forecasts, but it is essentially an arbitrary choice. 7-16 The Alaska prices of equipment and construction materials produced elsewhere were assumed in the base case to increase at the same rate as the GNP Deflator, i.e., 6 percent. In recent years these prices have tended to increase considerably more rapidly than the prices of most other goods and services, but there are grounds to consider this differential as a cyclical phenomenon, reflecting temporary supply bottlenecks, in steelmaking capacity and specialized engineering talent, for example, which are not likely to dominate long-term price movements. Similar reasoning was used with respect to the cost of labor, where we assumed 8 percent as an annual escalation factor. In general, real i wage rates, including supplements, can be expected to increase at about the average rate of growth of labor productivity in the economy as a whole. During the last decade, increases in construction wage rates have considerably exceeded the average for all industries. But there are no grounds for expecting such a trend to be permanent. Our choice of 8 percent assumes that real wages (including supplementary benefits) will increase at an average annual rate of 2 percent, reflecting a similar average growth of productivity in the U.S. economy. Two percent per year is somewhat lower than long-term historical rates of growth in real wages or per capita personal income (3-4 percent), but we have assumed that a growing emphasis on environmental quality, job satisfaction and safety will result in some retardation of productivity growth in the United States for the rest of this century, compared with earlier periods. 7-17 In the foregoing estimates, we have assumed that in the long run, prices and wages in Alaska increase at the same average rate as prices in the other states. That is, Alaska prices and wages are expected to exceed national averages by about the same ratios as now. The historical trend has actually been for a gradual narrowing of differentials (about three-quarters of a percent per year between Anchorage and the U.S. average over the period 1950-1973), but since 1974, Alaska prices have increased more rapidly than those Outside, as a result of the oil pipeline boom. The prices of fuels in Alaska will likewise reflect national or world trends, provided that Alaska markets for those fuels are linked to national or world markets by exports and/or imports. The most crucial influence on all such fuel prices will be the price of Persian Gulf oil landed in Lower 48 ports. Because almost every use of energy, such as spaceheating, transportation, electric generation, etc., can be served directly or indirectly by oil, and because U.S. domestic supplies of primary energy will be insufficient to serve U.S. demand, the price of imported oil will tend to determine the prices of most other fuels which are not subject to U.S. price controls. The world crude oil price itself is not determined by the conventional interaction of cost and demand, but by decisions of the Organization of Petroleum Exporting Countries (OPEC). The present Persian Gulf price of crude oil is as much as one hundred times its actual cost in terms of labor, materials and capital, so that forecasting the OPEC price ten years from now, or even one year from now, may be only wild speculation. For the purposes of this study, however, we have assumed that on the one hand, the OPEC cartel will not break up, but on the other, the world oil price has about reached a maximum, in real terms. It is likely that further price increases would reduce world oil consumption sufficiently so that certain key members of OPEC would face seriously reduced revenues, and that the temptation of some producers to "cheat" on the OPEC price would be irresistable. Accordingly, we have assumed in our base case that the world price of crude oil increases only enough to keep pace with inflation, i.e., at 6 percent per year. Crude oil prices in the United States are now controlled at less than the world market price, but the formula in present law allows the average domestic price to advance at 10 percent per year -- faster if the President recommends, and Congress does not veto, a higher price. This price control authority expires in 1979, so we have assumed that average U.S. crude oil prices rise in a straight line fashion to meet the world price in 1980, and thereafter to increase at the same rate as the world price, namely 6 percent. Crude oil produced in Alaska will, if not subject to price controls, tend to be priced in Alaska at the price of OPEC crude oil landed in Lower 48 U.S. ports, less transportation costs from the Alaska point in question, such as Prudhoe Bay, Valdez, or Cook Inlet, to Lower 48 ports. An assumption that transportation costs will increase at the same rate as general inflation is not unreasonable; its implication is that Alaska crude oil prices would also increase at 6 percent per year. Where conl is not used, residual fuel oi] is the dominant fuel fee cletirta utility use on the East. Coast of the U.S., and in Burope and Japan as well. It is not used or. sold in Alaska at present but it would become available here if there were a market for it. Because crude oil in the United States is refined primarily for gasoline, residual produced from U.S. refineries has been regarded as an inferior byproduct and, before the upheavals of 1973-74, had to be sold at prices lower than crude oil. For this reason little domestic residual oil was produced, and the East Coast U.S. market was served mainly by residuals from formerly cheap Caribbean crudes. The lack of U.S. residual producing capacity and the present price control system in the United States have resulted in a situation in which low sulfur residual now sells for a considerably higher price than crude oil -- for almost as high a price as distillate fuel oil. We regard this situation as temporary, however, and assume that the residual price at tidewater in Alaska will remain at its present nominal level until world crude oil prices catch up with it. Thereafter, we have assumed, the Alaska price of residual will be equal to the price of Persian Gulf crude oil landed in Lower 48 U.S. markets. It will, therefore, increase at 6 percent per year. It is not likely to make any substantial difference to the Alaska Solio of petroleum fuels whether these fuels are imported from outside the state or refined in Alaska from Alaska crude oil. This is because Alaska refiners can be expected to price their product -- as they do now -- just low enough to meet outside competition and no lower. If several refineries were huilt in the state, competition among them might result 7-.20 in somewhat lower prices than the prevailing norm: West Coast price plus transportation and higher Alaska distribution costs. But the inability of the intrastate market to support even one worldscale or lowest-cost refinery, much less several, makes this development unlikely over the period of our projections. Prices of distillate fuel oils such as diesel and stove oils at Anchorage have been assumed to continue their present relationship with average U.S. crude oil prices, i.e., about 50 percent higher. The price of natural gas will differ between locations in Alaska and elsewhere, and among locations in Alaska by far greater proportions than oil prices, because of the much greater cost of transporting the same amount of energy in the form of natural gas. Nevertheless, because natural gas is potentially interchangeable with petroleum products in a number of applications, including spaceheating and other household uses, electric utility and industrial boiler fuel, and petrochemical feedstocks, its price trends can be expected to reflect trends in the price of oil, if only slowly and indirectly. There has been a large excess of natural gas available in the Cook Inlet area relative to Alaska demand, including industrial demand, for production of urea and LNG, and no facilities have existed to transport this gas to Lower 48 markets. As a result, gas prices in Alaska have been only a small fraction of the price of oil in terms of their respective heating value. In the Cook Inlet area, low-priced gas has totally or partly displaced both coal and fuel oil for household and utility use. We can now expect rapid increases in the Alaska prices of gas in new contracts, however. With the emergence since 1970 of a national shortage of natural pas, there is a growing interest in transporting Alaska natural gas, or natural gas products, to Lower 48 markets. The development of a fixed transportation system for North Slope gas or for LNG produced in Alaska will strengthen the influence of Lower 48 prices upon Alaska natural gas prices. In principle, the Alaska price of natural gas in new contracts will then tend to approximate the expected Lower 48, or possibly Japanese, price of the same amount of energy in the form of Persian Gulf oil, less the cost of processing and transporting the gas from Alaska to the Outside markets. Actual gas prices will reflect a large number of additional influences which cannot be anticipated with any confidence, however, including federal and state regulatory policy. We have made a simple assumption for the Cook Inlet-Railbelt price of natural gas in new contracts, that it will start from the 1975 Anchorage city gate price and rise at a rate of 25 percent annually until it reaches 75 percent of the world oil price, in btu equivalents. One additional consideration should be noted with respect to natural gas. A national policy appears to be emerging to discourage or prohibit the use of natural gas as electric utility fuel or industrial boiler fuel. This policy flows from the general proposition that utility use of gas is an "inferior" use in a period of gas shortage, because utilities burn gas "only" for its energy content and unlike household and certain industrial consumers are indifferent to its form. In other words, it is argued, utilities can easily use other fuels while many gas customers cannot. While the foregoing argument is not entirely appropriate to Alaska, which so far constitutes a separate market from the Lower 48, it is conceivable that federal legislation might prohibit any new natural gas sales for electric utility use, or for baseload power generation. Or, alternatively, the FPC might use its authority over interstate pipelines to prohibit the movement of any gas for utility use by an interstate pipeline, even if that movement were totally intrastate, i.e., within Alaska. There is not likely to be a strong influence soon upon Alaska coal prices from the national or world prices of other fuels. The price of coal from new mines opened to serve Alaska utility demand will probably closely reflect actual mining costs, in which labor is the largest single element. It seems reasonable to assume that over the long period, technical progress in mining resulting in cost reductions will just about offset the effect of stricter environmental and safety standards on costs. For this reason, our base coal cost assumption uses an average of the present Healy and Fairbanks prices, escalating at 8 percent per year for all possible sites in the Railbelt-Cook Inlet region. Table 7-4 shows the assumed nominal prices in cents per btu for the various fuels in Southcentral Alaska. In the case of each fuel considered here, location differentials in prices have been used where they were deemed appropriate in cost analyses. 7-23 h7-L Table 7-4 SELECTED FUEL PRICE ASSUMPTIONS, BASE CASE (cents per million btu) Crude Oil, Persian Crude Oil, Average Residual Distillate Fuel Year Gulf, landed in U.S. U.S. Tidewater Price Fuel Oil Oil Natural Gas Coal 1975 240 190 N.A. 285 54 71 1976 254 218 300 327 67 7 1977 270 247 300 370 84 83 1978 286 274 300 411 104 89 1979 303 303 303 4S 131 97 1980 321 321 321 482 163 104 1981 340 340 340 510 204 113 1982 361 361 361 541 255 122 1983 385 385 385 573 289 131 1984 405 405 405 608 304 142 1985 430 430 430 644 322 153 1986 456 456° 456 683 342 166 1987 483 483 483 724 362 179 1988 §12 512 512 ¢ 767 384 193 1989 543 543 543 813 “ 407 209 1990 . STS 575 $75 862 431 225 1991 610 610 610 914 457 243 1992 646 646 646 969 485 253 1993 685 685 685 1027 514 284 1994 726 726 726 1089 S44 30€ 1995 770 770 770 1154 577 331 The reader should be aware of the heavy influence of subjective judgment in price forecasts such as the foregoing. Very different numbers can in many cases be obtained from alternate but equally reasonable premises. This point is illustrated by a comparison of the fuel. cost assumptions of two different study teams contributing to this report. Table 7-5 compares selected fuel cost forecasts from the foregoing table (ISEGR) with those used by Robert W. Retherford Associates (RWRA). Table 7-5 COMPARISON OF FUEL COST FORECASTS, ISEGR AND RWRA (cents per million btu) 1980 1985 1990 1995 Residual Fuel Oil - Railbelt - ISEGR 321 430 575 770 Distillate Fuel Oil - Railbelt - ISEGR 482 644 862 1154 Oil - Anchorage - RWRA 310 435 610 855 Natural Gas - Railbelt - ISEGR 163 322 431 577 Natural Gas - Anchorage - RWRA 84 118 166 232 Coal - Railbelt - ISEGR 104 153 225 331 Coal - Healy - RWRA 74 104 146 205 Coal - Railbelt - RWRA 126 Tid, 248 348 The Investment Model Structure and Assumptions An investment model has been constructed to permit analysis of alternative investment strategies for electric generation. The model has been built in two stages with results from only the first stage reported here. Stage one of the model determines the cost of power generation for a specific technology, location, and cost of input configuration. Stage two of the model incorporates the actual demand requirements of a specific 7-25 load center into an analysis which determines the mix and timing of new generating facilities and furthermore determines the least cost combination of plant operations to meet any load during the year. The engineering firms of Robert N. Retherford Associates and Stefano-Mesplay and Associates, Inc., both of Anchorage, collected the basic data necessary to build the model which generates the costs of alternative plants. Cost information was collected for nine different fossil fuel generating technologies and those hydroelectric sites chosen for detailed study after a review of a large number of possible alternatives. The basic data were collected using the same format for all alternatives. Fossil technology data are in Appendix G and the hydro analysis data are in Appendix H. The model takes the basic data and generates the initial investment re- quirement in terms of dollars per kilowatt installed capacity for each plant and the average cost per kilowatt hour of electricity produced by the plant in terms of mills/kwh. Assumptions regarding the size of plant, operating plant factor, financing arrangements, coverage requirements, costs of materials and labor, costs of fuels, plant location, and year construction of plant begins can all be varied for fossil fueled plants. The assumptions used to analyse the cost of any hydro project can likewise be varied with the exceptions of size of plant and location, both of which are obviously fixed for any particular hydroelectric proposal. The purposes of the model are three. 1) Different projects designed to provide a specific amount and type of energy (base load or peak) can be quickly compared with regard to 7- 26 both initial cost of installation and lifetime average electricity cost. This is because the assumptions underlying all projects with regard to costs, financing, etc., are consistent and variable at the discretion of the researcher. Thus, for example, the model permits one readily to compare the lifetime electricity costs of different generating facilities installed in one location in one year for any year between 1975 and 1995; it allows one to compare the cost of electricity produced by the same or different technologies in different locations in the state at any time, or it allows one to compare the cost of installation of new generation facilities at different points in time. 2) Because of specification and standardization of all assumptions underlying the costs and computerization of the most critical assumptions, one can easily vary the assumptions to see how the costs of electricity change as the assumptions change. This provides an indication of the sensitivity of any result to the underlying assumptions. For example, if a gas turbine is chosen as the least cost generation alternative on the basis of low cost gas and is still the least cost alternative if the assumed price of gas is allowed to double, then the choice is not sensitive to the price of gas. In addition, the model shows how much the price of electricity increases as the price of gas increases. 3) The model provides a complete set of all the alternatives which a utility could possibly chose to satisfy an increment in load. Thus it provides all the necessary supply data necessary to balance supply and demand over a 20-year planning horizon for a specific utility. This is a problem well suited for computer analysis because of the large number of alternatives which must be examined in all but the most elementary cases T- 27 in order to identify that set of new generating plants, and the timing of their installation, which minimizes the cost of electricity, subject to whatever financial constraints apply to the utility. In addition to the assumptions regarding future costs of labor, materials, and fuels discussed earlier in this chapter, and the basic cost of construction assumptions provided by the engineers and presented in detail in the appendices, the model requires that specific assumptions be made regarding the costs of financing during project construction and over the life of the project, and regarding the other project costs which affect the price of electricity. The range of long term capital costs has been allowed to vary between 6% and 8%. These rates are within the range experienced by Alaska utilities and the state of Alaska. The term of the bonding of new generation facilities is a function of the type of project. Small fossil plants are normally financed over a 20 year period. Larger fossil units may obtain a longer term. Hydro- electric plants generally have a longer useful life and can be financed over a longer period. Federal financing is considered only in the case of the Susitna hydro project where a 50-year term is assumed. If 100-year, rather than 50-year, financing were obtained at 6%,the annual cost would be reduced by only 5%. In addition to the cost of capital which each project must pay, the debt payments themselves must be covered. In order to guarantee to the investors that required interest and principal repayments can be made on schedule, revenues net of operating costs must exceed debt service. For the purposes of this study, 1.5 is assumed to be the coverage requirement each utility must meet. This means that electricity sales revenues minus operating expenses must exceed annual debt service by 50 percent. Construction loan costs must be included in total costs of project construction. The interest rate required on construction bonds is generally slightly below that of long term financing of the same project because of its shorter term and thus the reduced risk. The difference, however, is not large and is ignored in this analysis. Since only the interest costs incurred after construction funds are expended are a net cost to the project, an adjustment is made for the timing of construction cost payouts. The payout of construction accounts occurs somewhat later during the construction process for hydroelectric projects than for fossil fuel plants. The coverage requirement is not figured on construction debt in this analysis although, as pointed out in the previous chapter, under most financing arrangements it is necessary and adds to the cost of electric power before it becomes available for consumption. Utilities are generally required to pay taxes or to make payments "in lieu of" taxes. Actual tax rates will vary from community to community. An average tax rate of 2.1 percent of gross receipts is used here for all utilities and is counted as an operating expense. Insurance must be carried on electric generating facilities. A rule of thumb is used here that the insurance rate for fossil fuel plants is -3 percent of plant. Hydroelectric projects can obtain lower rates and, thus, .1 percent of plant is used for all hydroelectric projects. 7-29 All other costs of construction and operation are site specific. Yor hydroelectric sites each plant has to be costed-out at its actual location. Fossil fuel plants have all been costed-out on an Anchorage scale. This Anchorage base cost is adjusted for different costs of construction in the other census divisions of the state. 7-30 Regional Analysis of Generation Alternatives A. Southcentral Alaska Southcentral Alaska, including Anchorage, the Kenai Peninsula, the Matanuska-Susitna Valley, Kodiak, and the Cordova-Valdez-Glennallen area, is projected to have the most rapid growth in electricity demand in the state over the next twenty years. The most conservative projections put that growth at approximately 9 percent annually, while more optimistic pro- jections result in much higher annual growth rates. Anchorage itself will show the most rapid sustained growth, although in the short run, other Southcentral communities may grow at much faster rates. This sustained growth in the demand for electricity puts South- central Alaska in a position to examine several electricity generation alternatives. If the Fairbanks load is added to the other areas of South- central Alaska, which could possibly be intertied if a suitable low cost generation source were found (essentially the whole railbelt area but not Kodiak or the Cordova-Valdez-Glennallen area), a peak demand of 825 MW is projected for 1985 using the most conservative growth assumptions. Several hydroelectric projects were examined to determine their fea- sibility to serve this load. As indicated in Chapter V, the Devils Canyon project proposed by the Corps of Engineers for the Upper Susitna River was identified as the most feasible hydroelectric project to satisfy the ex- pected load growth over the projection period for the Railbelt. 7-31 The economic feasibility of the Devil's Canyon hydroelectric pro- ject depends upon its ability to deliver power to the load centers of Anchorage and Fairbanks at a cost which is competitive with alternative sources available to these two areas. This cost depends upon relative con- struction costs, the method of financing the project--both construction financing and long-term financing, and the prices of alternative fuels. The U. S. Corps of Engineers have most recently estimated construction costs of the project at $1.52 billion, which with Federal financing would result in a cost range of 15-20 mills/kwh in 1976 dollars. If the project were undertaken using conventional financing such as bonding at 7 percent for 25 years with coverage at 1.5 times the capital recovery factor included, the average cost of energy would be approximately 38 mills/kwh. If coverage were not required on the debt, the mill rate in 1976 costs would be reduced to approximately 25 mills/kwh. Anchorage and the surrounding area have the possibility of using large fossil units for base load generation additions. Natural gas is, of course, presently supplying a large percentage of the load and its use could be ex- panded if supplies become available at existing or somewhat higher prices. Liquid fuels (crude oil, residual fuel oil, distillate fuel oil, and condensate) are available from Alaska sources or from Outside, but they will probably con- tinue to be more costly than natural gas because of the more intimate link be- tween their Alaska and West Coast markets. Coal has been used in the past and could again become a major fuel for electric generation. Extensive deposits of sub-bituminous liquate coal with a btu content ranging from 7,160 to 8,890 btu per pound are located in the Beluga- Yentna area. The mine-mouth coal price there has been estimated in 1975 dollars at 7-32 71¢ mmbtu by the energy resource portion of the study. The Matanuska Valley also contains bituminous and semi-anthracite to anthracite coal with a heating value ranging from 10,390 to 14,130 btu per pound. Even if either area's mine mouth costs were as low as 35¢ to 50¢ per mmbtu, which is conceivable, power costs per kwh would be reduced by less than one-half cent. A mine-mouth plant in either of these locations would have the benefits of a lower cost site than a plant situated in Anchorage and better access to cooling water. There may, however, be significant environmental costs associated with the emissions from the plant or from the associated coal mining operations. For this reason a large steam plant in either of these locations would connect to Anchorage with 230 kv transmission lines. No geothermal resource of a size and quality necessary for large scale application as a power source is presently known within a reasonable dis- tance of the major load centers of the region. Nuclear power, likewise, does not appear to be economically feasible in Alaska during the period of this analysis because of the large size of efficient units, huge initial costs, large proportions of site labor (which is disproportionately expensive in Alaska) in total costs, long lead time for construction, and the availability of lower cost alternatives. Coal, natural gas, and hydro projects will be the economically feasible units for future expansion of generation facilities in the Anchorage load center. If load growth is rapid, even a large hydro facility such as the Corps of Engineers' Susitna project will not alone provide all the neces- sary power increments. Hydro projects and large fossil units might both be required. 7-33 Several alternatives for Anchorage are compared for 1980-1985-1990 in the following tables 7-5, 7-6, and 7-7. Such comparisons may be mis- leading for several reasons. All fossil plants assume 20 year bonding although the steam turbine units are designed to last much longer. The coal price must be interpreted as delivered to Anchorage either as coal or with the transmission of the electricity factor built in. The hydro units are also assumed to have 20 year honding if built by the State or a utility consortium to show that such a constraint would cause them to be uneconomical in spite of the fact that the useful life of the hydro facility in general exceeds that of large fossil plants. Load factors are set for new base load facilities even though FPC research has shown that the lifetime load factors for base load plants is closer to 55 percent. Finally, hydro is calculated on the basis of prime capacity, which somewhat underestimates the available energy which it can deliver. The first fuel cost for each unit is the base cost from the discussion of fuel prices while the second is a 25 percent increase to provide an indication of the sensitivity of the price of electricity to fuel costs. 7-34 Table 7-6 1980 Anchorage Base Load Units (1980 $) Cost of Energy in 1980 é = mills/kwh for Initial year of Plant Operation Equipment Capacity ~ Fuel First Cost Fuel Price @ stated fuel prices MW $/kw ¢/mmbtu and interest rates Interim Financing for Initial of 6% and 8% 6 = @ 8% year of | L M H - plant operation diesel 3 oil $520 362-482-602 63.9 77.1 90.3 $525 66.3 79.6 92.8 gas turbine simple cycie 50 gas $259 122-163-204 26.7 32.9 39.2 $261 27.9 34.2 40.4 gas turbine regenerative cycle 50 gas : $320 122-163-204 24.7 28.9 33.1 ‘ $323 26.2 30.4 34.6 steam turbine 200 coal $591 78-104-130 26.3 28.8 31.3 $612 29.5 32.1 34.6 steam turbine 200 coal $591 78-104-130 23.5 26.1 28.2 (30 yr financing) $612 212 9a $252 steam turbine 200 gas $496 122-163-204 27.6 31.6 35.5 k $514 SO. 94.3. 38.3 steam turbine 200 gas $591 122-163-204 25.3 29.3 33.2 (30 yr financing) $612 28.4%. .32.3 396.3 steam turbine 200 oil $496 241-321-401 39.1 46.9 54.7 $514 41.9 49.7 57.4 steam turbine 200 oil $496 241-321-401 36.8 44.6 52.4 (30 yr financing) $514 "39.9 47.7 55.4 Assumptions: 20 year financing of fossil plants unless otherwise noted Coverage factor of 1.5 on fossil plants Cost escalation at 6 percent materials, 8 percent labor 55 percent load factor on fossil plants Combined cycle gas units are also technically feasible but have not been analyzed. No credit for secondary energy for hydro Note: Large scale steam turbine units have yet to be built in Alaska. As a result, there is no #eneral agreement among engineers regarding the capital cost of such a project, and some would feel the first cost in this table to be somewhat low. 7-35 Table 7-7 1985 Anchorage Base Load Alternatives (1985 $) Cost of Energy in 1985 mills/kwh for - ; Initial Year of Plant Operation Equipment Capacity Fuel First Cost Fuel Price @ stated fuel prices MW $/kw ¢/mmbtu and interest rates Interim Financing for Initial of 6% and 8% @ 6s @ 8% year of - L Mu H - plant operation a diesel 3 oil $712 483-644-805 86.7 104.5 122.2 $719 90.3 107.9 125.6 gas turbine simple cycle 50 gas $355 242-322-402 51.7. 64.0 76.4 $358 53.4 65.7 78.0 gas turbine regenerative cycle 50 gas $438 242-322-402 41.8 50.0 58.2 $443 43.8 52.0 60.3 steam turbine 200 coal $809 115-153-191 36.9 40.6 44u Ly $839 41.4 645.2 48.9 steam turbine 200 coal $809 115-153-191 33.2 36.9 40.6 (30 yr financing) $839 38.2 41.9 45.6 steam turbine 200 gas $680 242-322-402 45.4% 52.9 60.7 : $705 48.9 56.7 64.5 steam turbine 200 : gas $680 242-322-402 42.0 49.8 57.6 (30 yr financing) $705 46.2 54.0 61.8 steam turbine 200 oil $680 322-430-537 53.0 63.4 73.8 $705 S67 - 67.52" 7926 steam turbine 200 oil $680 322-430-537 49.8 °° 6002, 70.7 (30 yr financing) $705 54.0 64.4 74.9 hydro 792 Watana $2,901 (7%) --- 103.5 6%-20 yr-coverage (Corps of Engineers proposal) 70.0 6%-20 yr-no cover. (1987 dollars) 86.6 6%-30 yr-coverage 58.4 6%-30 yr-no cover. 51.3 6%-50 yr-no cover. 119.7. 8%-20 yr-coverage 80.5 8%-20 yr-no cover. 105.5 §%-30 yr-coverapy 69.0 8%-30 yr-no cover. 65.5 9¢-50 yr-no cover. Assumptions: See Table 7-6 7-36 Table 7-8 1990 Anchorage Base Load Alternatives (1990 $) Cost of Energy in1990 . : mills/kwh for : Initial Year of Plant Operation Equipment Capacity — Fuel First Cost Fuel Price @ stated fuel prices : MW $/kw ¢/mmbtu and interest rates Interim Financing for Initial of 6% and 8% 6&8 Year of L M H @ - Plant Operation diesel 3 oil $975 646-862-1077 118.9 142.5 166.0 $985 123.6 147.2 170.7 gas turbine simple cycle 50 gas $486 323-431-539 70.1 86.6 103.2 $491 72.4 88.9 105.4 gas turbine regenerative cycle 50 gas $601 323-431-539 56.9 -~67.9- 76.9 7. $606 59.7 70.7 81.7 steam turbine 200 coal $1110 169-225-281 52.0 57.5 63.0 $1149 58.2 63.6 69.1 steam turbine 200 coal $1110 169-225-281 46.9—-52.4-—_57.8 (30 yr financing) $1149 53.7 59.2 64.6 steam turbine 200 gas $932 323-431-539 61.4 71.9 82.3 3 $965 66.6 77.0 87.5 steam turbine 200 gas $932 323-431-539 57.1 67.6 78.0 (30 yr financing) $965 62.8 73.3 83.7 steam turbine 200 oil $932 431-575-719 71.9 85.8 99.8 $965 77.1 91.0 105.0 steam turbine 200 oil $932 431-575-719 67.6 81.5 95.5 (30 yr financing) $965 73.3 87.3 101.2 hydro 1,568 Watana and $2,252 (7%) -— 79.1 6%-20 yr-coverage Devils Canyon 53.3 6%-20 yr-no cover. (Corps of Engineers proposal) 66.2 6%-30 yr-coverage (1992 dollars) 44.8 6%-30 yr-no cover. 39.3 64-50 yr-no cover. 91.4 8%-20 yr-coverage 61.5 8%-20 yr-no cover. 80.6 8%-30 yr-coverage 54.3 8%-30 yr-no cover. 50.1 94-50 yr-no cover. Assumptions: See Table 7-6 7-37 Alternatives for utilities in the Southcentral region outside the Anchorage and Fairbanks transmission and distribution systems are more limited. Small loads and limited immediate prospects for the development of low cost fossil energy resources near loads essentially eliminate all generation alternatives except hydroelectric power and small fossil units supplied with fuels imported into the region. Tables 7-9,7-10, and 7-11 illustrate the initial cost and the average mill rate during the initial year of operations for several base load alternatives installed in outlying Southcentral communities. Construction cost factors in the Southcentral range from 1.0 to 1.8 depending upon location. All these figures assume an average value of 1.4 times the Anchorage construction cost. Fuel prices are all based at Anchorage,Coal-fired plants would tend to be located near the resource, however, and specific locations could have either higher or lower fuel prices, depending upon future development of resources within the region. For small communities without accessibility to natural gas, diesel units appear most economical because of a relatively low initial cost. In somewhat larger communities, gas, if available, would again be the most economic alter- native. Gas turbines have the further advantage of being able to burn diesel oil if natural gas is not available. Coal could be a competitive fuel if it were deliverable locally at a price close to that assumed for the Anchorage area. As noted in the resource inventory chapter, the hydroelectric projects in the outlying Southcentral areas presently either appear too costly to compete with alternative fossil fuel generation or are not well suited for the local loads. There are some hydro projects in the Southcentral 7-38 Table 7-9 1980 Southcentral Base Load Units (1980 $) Cost of Energy in 1980 mills/kwh for Initial Year of Plant Operation Equipment Capacity Fuel First Cost Fuel Price @ stated fuel prices MW $/kw ¢/mmbtu and interest rates Interim Financing for Initial of 6% and 8% 6% @ 8% Year of L M H Plant Operation ; diesel 3 diesel $728 361-482-602 69.7 82.9 96.1 $735 73.1 86.3 99.6 gas turbine simple cycle 3 gas $770 122-163-204 SUT 56.9 Go.2 $778 54.4 60.6 66.8 gas turbine 3 simple cycle 10 gas $551 122-163-204 44.2 50.4 56.7 $556 46.8 53.0 59.3 gas turbine regenerative cycle 10 gas $670 122-163-204 44.3. 45.5 49.6 $676 44S 48.7 52.8 steam turbine 3 coal $1552 78-104-130 63.0 66.2 69.4 $1552 69.8 73.0 76.2 steam turbine 3 gas $1304 . 122-163-204 62.6 66.4 71.4 $1304 68.4 72.2 77.2 steam turbine 3 residual oil -- $1304 241-321-401 76.0 85.7 95.5 $1304 81.7 91.5 101.4 ; steam turbine 3 distillate oil i $1304 361-482-602 90.7 105.4 120.2 - $1304 96.5 111.2 126.0 Assumptions: 20 year financing Coverage factor of 1.5 Cost escalation at 6 percent materials, 8 percent labor $5 percent load factor 7-39 Table 7-10 1985 Southcentral Base Load Units (1985 $) Cost of Energy in 1285 f mills/kwh for F Initial Year of Plant Operation Equipment Capacity - Fuel First Cost Fuel Price @ stated fuel prices MW $/kw ¢/mmbtu and interest rates. Interim Financing for Initial of 6% and 8% @ 6% @ 8% Year of L M H Plant Operation : diesel 3 diesel $997 483-644-805 95.0 112.6 130.3 $1006 99.7 117.3 135.0 gas turbine simple cycle 3 gas $1056 241-322-402 81.8 94.2 106.5 $1066 86.8 99.4 111.5 gas turbine simple cycle 10 gas $754 241-322-402 72.8 85.2 97.5 ; $762 Ts 26007" L0Led gas turbine = regenerative cycle 10 gas $918 241-322-402 65.1 73.3 81.6 = $927 69.5 Tat: 85.9 steam turbine 3 coal $2126 115-153-191 85.3 92.8 97.5 $2126 94.6 102.1 106.8 steam turbine 3 gas $1786 241-322-402 94.0 103.9 113.8 : $1786 © 101.9 111.8 121.7 steam turbine 3 residual oil . $1786 322-430-537 104.0 117.1 130.3 ots $1786 111.9 125.0 138.2 steam turbine 3 distillate oil $1786 483-644-805 123.6 143.4 163.0 $1786 439-5 (1.1512) 249420 Assumptions: See Table 7-9. 7-40 Table 7-11 1990 Southcentral Base Load Units (1990 $) Cost of Energy in 1990 ; ” mills/kwh for Initial Year of Plant Operation Fuel Equipment Capacity - First Cost Fuel Price @ stated fuel prices MW $/kw ¢/mmbtu and interest rates Interim Financing for Initial of 6% and 8% 6% 8% Year of L M H a a Plant Operation : diesel 3 dicsel $1365 646-862-1077 129.9 153.5 177.1 $1379 136.4 160.0 183.6 gas turbine simple cycle 3 gas $1446 323-431-539 112.4 128.9 145.4 $1461 119.2 135.7 152.3 gas turbine simple cycle 10 gas $1034 323-431-539 100.1 116.6 133.1 : $1044 105.0—121.5_138.0 gas turbine a regenerative cycle 10 gas $1257 323-431-539 89.9 100.9 111.9 $1270 95.9 106.9 117.9 steam turbine 3 coal $2913 169-225-281 123.6 130.5 137.4 $2913 136.4 143.4 150.3 steam turbine 3 gas $2447 323-431-539 129.3 142.5 155.7 $2447 140.2 153.4 166.6 steam turbine 3 residual oil $2447 431-575-719 142.5 160.2 177.7 - $2447 153.4 171.0 188.5 steam turbine 3 distillate oil ; $2447 646=862-1077 168.9 195.3 221.7 $2447 179.7 206.1 232.5 As umpt ions: See Table 7-9. 7-41 region which could possibly be economically linked to the Anchorage load center or the surrounding communities served by the Anchorage utilities. 7-42 B. Fairbanks Without the Susitna project, the economic feasibility of an intertie between Fairbanks and the rest of the railbelt does not appear likely in the time frame of this study. Neither has the resource inventory identified any hydroelectric sites consistent with the Fairbanks area load growth re- quirements. Thus, all the alternatives for Fairbanks without Susitna are fossil fuel generating plants. A variety of base load units are compared for Fairbanks assuming in- stallation in 1980, 1985, and 1990 in Tables 7-12, 7-13, and 7-14. In all likelihood, not all fossil fuels will be available in Fairbanks during the next 20 years and for those that will be available, price is very uncertain. Prices used here are the same as those of Anchorage with the exception of natural gas, which begins at the Anchorage base of 53.5¢/mmbtu and includes a 23¢ transportation cost to Fairbanks. The figure, taken from the Federal Power Commission: Alaska Natural Gas Transportation System Draft Environ- mental Impact Statement, is certainly open to ola The choice of the most economical fossil fuel for Fairbanks partially depends upon plant location restrictions due to the ice fog problem. The exact etiology of ice fog has not yet been identified. The elements which appear to be necessary for severe ice fog to form, as in the Fairbanks basin, are as follows: 1) cold stable air 2) warm water source. Table 7-15 summarizes man-made sources of water into the atmosphere in Fairbanks. 3) particles in the air around which ice crystals can form. 7-43 aavae sae 1980 Fairbanks Base Load Units (1980 $) Cost of Energy in 1980 i = mills/kwh for Initial Year of Plant Operation Equipment Capacity - Fuel First Cost Fuel Price @ stated fuel prices MW $/kw ¢/mmbtu and interest rates Interim Financing for Initial of 6% and 8% @6s @ 8% Year of L M H Plant Construction 3 gas turbine simple cycle | 50 gas $311 122-163-204 30.7 36.9 43.2 $314 32.2 38.4 44.6 gas turbine c simple cycle 50 oil $311 361-482-602 67.3 85.8 104.3 $314 68.8 87.3 105.7 gas turbine regenerative cycle 50 gas $384 122-163-204 26.5 30.7 34.9 $388 28.3 32.5 36.7 gas turbine regenerative cycle 50 oil $384 361-482-602 $1.0 63.3 75.6 $388 52.8 65.1 77.4 steam turbine 66 gas $610 122-163-204 34.8 39.6 44.4 : : a : : $631 38.2 43.0 47.8 steam turbine 66 gas $610 122-163-204 32.0 36.8 41.5 (30 yr financing) $631 35.7 40.5 45.3 steam turbine 66 oil $610 241-321-401 48.7 58.1 67.6 $631 §2.1 61.5 70.9 steam turbine 66 oil $610 241-321-401 45.9 55.3 64.7 (30 yr financing) $631 49.6 59.1 68.5 steam turbine 66 coal $726 78-104-130 33.5 36.5 39.6 $752 37.5 40.6 43.6 steam turbine 66 coal $726 78-104-130 30.1 33.2 36.2 (30 yr financing) $752 34.6 37.7 40.7 Assumptions: 20 year financing of fossil plants unless otherwise noted Coverage factor of 1.5 on fossil plants Cost escalation at 6 percent materials, 8 percent labor 55 percent load factor on fossil plants No credit for secondary energy for hydro 7-44 Table 7-13 1985 Fairbanks Base Load Units (1985 $) Cost of Fnergy in 1985 mills/kwh for Initial Year of Plant Operation Equipment * Capacity Fuel First Cost Fuel Price @ stated fuel prices MW S/kw ¢/inmbtu and interest rates Interim Financing tor Initial of 6% and 8% 6 \eahar L Ce Opestion 4 H gas turbine simple cycle 50 gas $425 241-322-402 53.7 66.0 78.4 $430 55.7 68.1 80.4 gas turbine simple cycle 50 oil $425 483-644-805 90.4 115.1 139.8 $430 92.5 117.1 141.8 gas turbine regenerative cycle 50 gas $526 241-322-402 49.2 52.5 60.7 $531 46.7 54.9 63.2 gas turbine . regenerative cycle 50 oil $526 483-644-805 68.9 85.3 101.8 e $531 71.4 87.8 104.3 ' steam turbine 66 gas $835 241-322-402 56.7 66.1 75.6 ; : $865 61.3 70.8 80.2 steam turbine 66 gas $835 241-322-402 52s0--~-6203-—--74.7 (30 yr financing) $865 58.0 67.4 76.9 steam turbine 66 oil $835 322-430-537 66.2 78.8 91.4 $865 70.8 83.3 96.1 steam turbine 66 oil $835 322-430-537 62.3 75.0 87.6 (30 yr financing) $865 67.5 80.1 92.7 tubbine 66 coal $994 115-153-191 47-52----Siv8--—- 56.2 “— $1030 52.7 57.2 61.7 carbine 66 coal $994 115-153-191 42.6 47.1 51.6 overs (30 yr financing) $1030 48.7 $3.2 87.7 hydro 792 Watana $2,901 (7%) --- 103.5 ete yr-coverage (Corps of Engineers proposal) 70.0 6%-20 yr-no cover. (1987 dollars) i 86.6 6%-30 yr-coverage 58.4 6%-30 yr-no cover. 51.3 6%-50 yr-no cover. 119.7 8%-20 yr-coverage 80.5 8%-20 yr-no cover. 105.6 8%-30 yr-covernge 69.0 8%-30 yr-no cove . 65.5 @%-50 yr-no cover. diesel 3 diesel $853 483-644-805 90.9 108.6 126.3 $863 94.9 112.6 130.3 Assumptions: See Table 7-12 7-45 Table 7-14 1990 Fairbanks Base Load Units (1990 $) Cost of Eneryy in 13°7 fe - mills /kwh for Initial Year of Plant Operation Equipment - Capacity Fuel First Cost Fuel Price @ stated fuel prices MW . $/kw ¢/mmbtu and interest rates Interim Financing for Initial of 6% and 8% @et @ at Year of | L 4 4 Plant Operation _ ————————E———————— ee gas turbine simple cycle 50 gas $583 323-431-539 72.4% 88.9 105.4 $589 78.6 92.2 108.7 gas turbine . simple cycle 50 oil $583 646-862-1077 222.4 #155.4 188.4 $589 125.2 158.2 191.2 gas turbine regenerative cycle 50 gas $721 323-431-539 60.3 71.3 82.3 $728 63.7 74.7 85.7 gas turbine . regenerative cycle SO oil $721 646-862-1077 $3.3 118.3 137.3 = $728 96.7 118.7 140.7 A steam turbine 66 gas $1144 323-431-539 77.2, 89.9 102.5 : 2 : . soto $1185 83.6 96.2 108.9 steam turbine 66 gas $1144 323-431-539 71.9 84.6 97.2 (30 yr financing) $1185 79.0 91.6 104.3 eurbine 66 ofl $2144 431-575-719 89.9 107.0 123.7 oe $1ies 9.3 113.1 130.0 66 oil | $1144 431-575-719 84.6 101.5 116.4 istese) curb ine (30 yr financing) $1285 91.7 108.5 125.4 66 coal $1362 169-225-281 66.6 73.2 79.8 Ch ae $1432 7.1 80.7 87.3 cabine 66 coal $1362 169+225-281 60.3 66.9 73.5 ae (30 yr financing) $1412 68.7 75.3 61.9 hydro 1,568 Watana and $2,252 (7%) _ 19.1 6%-20 yr-coverage Devils Canyon $3.3 6%-20 yr-no cover. = (Corps of Engineers proposal) 662 6%-30 yr-coverage (1992 dollars) 448 64-30 yr-no cover. 39.3 6%-50 yr-no cover. 914 64-20 yr-coverage 61.5 .8%-20 yr-no cover. 80.6 84-30 yr-coverage 84.3 8%-30 yr-no cover. ‘ 80.1 8%-50 yr-no cover. Assumptions: See Table 7-12 . 7-46 : Table 7-15 Summary of Man-Made Water Sources for the Fairbanks Atmosphere Source Amount Percent (millions of grams of water/day) Combustion products Gasoline 124 3 Fuel oil 202 5 Coal, domestic 207 § Subtotal S33 Coal, power plants 760 ‘ 19 Subtotal 1,293 Cooling water from power plants 2,600 64 Miscellaneous (leaks from steam 170 4 lines, houses, university mine shaft, sewage, people and animals breathing, etc.) Total 4,063 100 Source: Benson, page 23. 7-47 Benson feels that removal of the sources of water vapor in the atmosphere would reduce the ice fog problem most significantly. Since cooling water from electric power plants is the largest single source of water vapor in the Fairbanks atmosphere, relocation of the plants would presumably reduce the ice fog problem significantly. Ohtake? found that most nuclei of ice crystals are combustion by- products, although not all crystals have nuclei. He condlues that the most important element in the formation of ice fog is the difference in temperature between water released into the atmosphere and the ambient air temperature rather than the available supply of steam. The presence of particles in the air accelerates the process of freezing of the water droplets and allows the process to operate at higher temperatures. Benson held that power plant stack exhausts did not contribute to ice fog formation, because the water vapor thus released escaped the local inversion. Ohtake, however, believed that steam plant exhaust returned to the local inversion and thus did contribute to ice fog formation. Thus, the potential contributors to ice fog formations have been identified, but not well enough to pinpoint how funds could best be ex- pended to reduce the problem. The main culprits - internal combustion en- gines and electric generating plants - are obvious enough. Internal combustion omission could be reduced with wide availability of automobile heater plug-ins to eliminate idling and cold starts; this, of course, would increase electricity consumption. If water vapor is 7-48 identified as more important, elimination of cooling water discharges or higher steam plant exhaust stacks could be helpful. However, it is con- ceivable that removal of thermal modes of generation from the immediate area of Fairbanks may be necessary to minimize ice fog formation. This factor certainly should be considered in selecting and locating future generating plants for service to the Fairbanks area. C. Southeastern Alaska Because of small loads and isolation, the only economically viable al- ternatives available to Southeastern Alaska are hydroelectric projects and diesel internal combustion generation. The larger communities are fortunate in that all are situated close to technically feasible hydroelectric sites. The choice for most communities is among several potential sites and addi- tional diesel capacity. Table 7-16 summarizes the approximate prime energy charge of these hydro sites in 1975 dollars and illustrates that many of them are very economical when compared to new diesel generation which could not be installed under 50 mills/kwh. The choice of the proper hydroelectric site to develop in each instance depends upon the cost of development and the load to be served. No pattern of scale economies has been observed among the Southeast hydro sites, so care should be taken in choosing a project which meets the anticipated load but does not result in excess capacity. 7-49 Table 7-16 SOUTHEASTERN HYDROHLECTRIC SITES (1974 Peak Load in’ MW and Generation in Thousand mwh in Parentheses) Capacity Prime Initial Cost Prime Energy Prime Installed Energy $/kw Charge Site kw kw MWH . Prime Installed mills/kwh Metlakatla (5.400) (18.731) : - Purple Lake Rehabilitation 400 41,400 17,520 2,835 819 a Hassler Lake 4,000 2,000 16,980 3,415 1,708 4446 Ketchikan (13.400) (68.171) Upper Mahoney Lake 4,700 10,000 41,172 1,922 903 23.37 Swan Lake 7,700 15,000 67,500 4,283 2,199 49.38 Lake Grace 11,000 20,000 94,000 - 3,577 1,968 41.95 Petersburg-Wrangell (5.65) (29) Anita Lake 2,100 4,000 18,396 2,796 1,468 31.67 Anita and Kunk Lakes 3,830 8,000 33,550 2,383 1,101 27.21 Virginia Lake 3,000 6,000 26,280 2,357 1,178 29.67 Sunrise Lake 2,400 4,000 21,024 1,739 1,043 19.95 Ruth Lake 7,950. 16,000 69,660 2,938 1,460 34.86 Crystal Lake Expansion 400 2,500 3,504 11,000 1,760. --- Cascade Creek I 5,100 15,000 44,784 4,501 1,530 53.45 Cascade Creek II 17,900 36,000 156 ,672 45192) 593 28.87 Scenery Lake 9,100 18,000 79,716 2,452. 1,239 _ 29.47 Sitka (6.700) (30.922) Lake Irina 1,790 3,000 15,680 2,047 1,222 23.49 Green Lake 6,600 14,000 57,816 2,735 1,289 31.45 Lake Diana 4,585 “10,000 40,165 22137 970 24.40 a Milk Lake . 8,000 16,000 70,080 2.324) 1,172 26.72 Four Falls Lake 3,000 6,000 26,280 1,447 741 16.18 Carbon Lake 6,830 .18,000 59,832 2,811 1,067 32.40 Takatz Lake 1,000 20,000 87,600 2,660 1,330 30.08 Haines . Unnamed Lake "4,640 9,000 40,640 2,249 1,159 25.80 Skagway (1) (4.198) ci Goat Lake 4,450 9,000 38,982 2,054 1,016 22.99 Juneau (16.870) (78.189) Snettisham Fxpansion I 11,758 27,000 103,000 1,871 815 --- Snettisham Expansion II 18,607 eee 162,997 860 --- _— 7-50 D. Rural Alaska Small rural Alaskan communities will, in general, remain dependent upon diesel generation of electricity in the foreseeable future. Some isolated instances of local energy resources, such as Elim with hot springs, and Wainwright and Atkasook with coal, may possibly be used as alternatives to diesel, especially if combined heating and electricity generating sys- tems can be developed. There is a possibility that an intertie system could provide power to the small villages surrounding Bethel. It appears technically feasible. Providing diesel power to small rural communities will continue to be a very high cost operation because of the problems of transportation. logistics, maintenance, and fuel costs. If diesel fuel is 50¢/gallon burned, and the heat rate of the unit is 14,000, the fuel cost in the electricity alone is approximately 5¢/kwh. The installation of a new 300 kw diesel system for a small village es- timated at approximately 400 people would, with regular financing and 40¢ fuel, result in electricity at approximately 29¢/kwh given the high reserve requirements (100%) and low load factor (25%) of small isolated rural com- munities. Reducing the fuel cost to zero would lower the price to approxi- mately 23¢/kwh. The high cost of maintenance and the servicing of debt ac- count for nearly all the remainder. Individual larger rural Alaskan communities have some alternatives. Barrow has the natural gas from Navy Pet 4 to use in gas-fired internal 7-51 combustion or turbine units. The efficient heat rate of the natural gas fired internal combustion unit makes it economically attractive. The hydroelectric project survey identifies several possible sites in North- west and Southwest Alaska for development, including Anvik River, Lake Elva, and Kisaralik River. For the most part, however, the larger communities will also be dependent upon diesel-fired internal combustion. Costs of diesel generation in larger rural communities are much less than the small villages because of higher load factors, lower reserve re- quirements, and lower cost fuel supplies. 7-52 1. FOOTNOTES A more likely source of natural gas for Fairbanks is the North Slope, with gas delivered through a pipeline built primarily for interstate gas trans- portation. The wellhead price necessary to support development of the field to a capacity of 2 BCF per day would be between 50 and 90 cents per MCF, and transportation to Fairbanks is likely to cost about 50 cents per MCF in a 2 BCF/d capacity 42-inch pipeline. Carl S. Benson. Ice Fog: Low Temperature Air Pollution, Research Report 121, Cold Regions Research and Engineering Laboratory, Hanover, New Hampshire, June 1970. Takeshi Ohtako. Studies on Ice Fog, prepared for National Center for Air Pollution Control, Public Health Service, HEW, Univer- sity of Alaska UAG R-211, June 1970. 1-53 TABLE OF CONTENTS APPENDIX Regional Maps of Existing Systems and Loads Demand Projection Background Material MAP Economic Model Projection Values Regression Analysis Results - Growth as Usual Case Summary of Alaska Power Administration Load Growth Study Load Factors for Alaska Utilities Approximate Comparative Fuel Costs for Residential Space Heating aPwnh— eee e le Possible Future Generating Technologies and Modifications for Alaska Geothermal Nuclear Fuel Cells Coal Gasification Solid Waste Energy aPWn— oe 8 ee Transmission Technologies Transmission Lines and Economics of Interties Regional Potentials for Interties Submarine Cables Oil and Gas Pipelines vs. Electrical Transmission Geothermal Pipelines vs. Electrical Transmission aPwWwNn— ee « Regional Maps of Alaska Resources td ond Summary of Ratings Used to Select Fuel Resources as Feasible Fossil Fuel Generation Systems Descriptions and Costs Introduction Cost Summary Sheet and Fuel Price Sensitivity Alaska Construction and Operating Cost Factors Case #1 Diesel Oil Fired Diesel Generator Case #2 Gas Turbine Simple Cycle Case #3 Gas Turbine Regenerative Cycle Case #4 Coal Fired Power Plant Case #5 Gas Fired Steam Turbine Case #6 Oi] Fired Steam Turbine Case #7 Geothermal Steam Turbine Case #8 Geothermal Binary Hot Water Power Plant S$HCOWOONDOPWNH— oie ejetee. ae? Br ene Hydroelectric Site Descriptions and Cost Estimates Introduction Northwest Hydroelectric Sites Southwest Hydroelectric Sites Southeast Hydroelectric Sites Southcentral Hydroelectric Sites arPwn— Pile ¢ihe ye Financing Electric Power Background Material Major Electric Utility System Inventory Introduction Northwest Systems Southwest Systems Southeast Systems Southcentral Systems Anchorage Systems Fairbanks Systems NOOPWNH— e le 0 .e ee 6 APPENDIX A REGIONAL MAPS OF EXISTING SYSTEMS AND LOADS - 1. Map of ISEGR Man in the Arctic Program Regions Northwest - 2. Northwest Region Existing System Southwest . 3. Southwest Region Load Centers and 1974 Consumption - 4. Southwest Region Existing System Southeast - 5. Southeast Region Load Centers and 1974 Consumption . 6. Southeast Region Existing System Southcentral - Anchorage . 7. Southcentral - Anchorage Region Load Centers and 1974 Consumption . 8. Southcentral - Anchorage Region Existing System Interior (No Maps) Fairbanks . 9. Fairbanks Region Load Centers and 1974 Consumption -10. Fairbanks Region Existing System ) [eee ie See oe. Hm Oe eae eee Te, 6 At 8 9 Or | MAP Model Regions A \A I. Northwest i II. Southwest | III. Southeast IV. Southcentral Vv. Anchorage ! VI. Interior i VII. Fairbanks 8 | LEGEND | te © Places of 25,000 to 50,000 inhabitants outside SMSA's | | c ic p Qe D | | BRISTOL BAY | eee eeeeeeee cern AG fi ce ‘ ‘BRISTOL BAY BOROUGH ¢ elk , E ! 9 | ° | — te ! d lis ALEUTIAN ISLANDS (PART) a Bis: o | F | 1 “~~ eer : S80L|q P2}99]S puke SUOISIAIG SNSLIBD OAMBELL PETES meer HL DAN OONDe WAINWRIGHT (VARIOUS) 0.3 MING EEE no osnwi BARRO W__DIVISION IVALINA SEVEES Os nwo) + RAB: nwo NAR SR co * SELAW iN IAVECIO.Z MW (Or NOME San, AOE MOUNTAIN: hy a wie Si i 8 f Ae) rw) Snes Na Tewioy HATE 2 mw cor iso Erm con san OA ST LAWPENCE ISLAND A NORTHWEST REGION EXISTING SYSTEM DATA wounTam mLAee MOOPER BAY TKAS POINT: 4 tt cartes wares arom ; Wot starion 6 eS ; 5 SOUTHWEST REGION II 1974 ELECTRICITY ConsuMPTION FOR REPORTING UTILITIES > w ae a | -- PIGURE NO ae rS v3 sit tas et in wa J ROOPER BAY \AvECIO 2 wwe cme vas 1AvEC)O 2 MMO scavu_n gar son vECioruW OF =" a rox s200 > vec FM 18) a fos ta ANOUK wouNTAMm viLLaCe PITKAS POINT 97. maRy's ies starien MARSHALL weooewnn se” i oF we (AVECIO SMW (0) TS vans ra Gy a ma Pf iaetcipauw(0) EARS SAGE. UK (avec 2M pbs 7 Hoey ones favecio’ MWiO} (avECiO 2 ew i a avarure wes TKeEANS.S bw (0) 1973 (DOING 13 ww (0) r9TE) wr acme ey s SOUTHWEST REGION I! ELECTRICAL SYSTEMS INVENTORY Sa ras 9 a —_ | FIGURE NO SOUTHEAST REGION III (914 ELECTMCITY CONSUMPTION FOR REPORTING UTILITIES ee eo svavure wcce =~ FIGURE NO. Bie Reese TRanguit3ion Lint $2 WOT wo aoe RE SH Bhv-sitt “ Ct . ana hee Biase cL AE ni Has a Nk SOUTHEAST REGION I! ‘ ELECTRICAL SYSTEMS INVENTORY ae, ee Te) te Soest SeMAED vost we evaTuTe mee SP eT TSHAM CXPAKBON TO 73) ew POTENTIAL (ASCE. ESTIMATED aa ce cede: remem ome shine ree _ FIGURE NO nnenee TALK “WO DATA 194 PARTIAL DATA 1973 1423 Mn 1872 “-AMGHORAGE (awe 01330, 302 tewn 1ECA) 216,830 MH (EKLUTMA PROJECT) 728 Mew STATUTE wices REGIONAL LOCATION ISOUTHCENTRAL REGION IV ANCHORAGE REGION V 1974 ELECTRICITY CONSUMPTION FOR REPORTING UTILITIES SOVTHCENTRAL oe TAB nw cor MATANUSKA- SUSITNA DIVISION @rcTPian oO enc acs NEA SERVICE TALKEETNA , AREA (APPROX) GLENMALLEN t eee ee We of tls ctr ck | sare naswwrnal cic avooh VALDEZ- CHITINA - WHITTIER wuvow (eA rasta ‘ DIVISION nero enn coher maine CORDOVA- M°CARTHY ALEXANDE Ete DIVISION CANADA ee frvonei KENAI- 00K IN DIVISION {erurets nwo enue SrA 7 ' pau: f Zi *} socootma ee ~8 rr <> 4 Save ae = GABE_VAMATAGA oe Lae | a v CLAM outcy® y q inne Bae Uv | ye ms ong, ei A eee s rn gat Do scouanendy ctiegoned AQ) 4 : EXISTING SYSTEM DATA { THEAYO.2 wb _ : : NTR GION 3 ‘ Vv ES ALASAA POWER STUDS rn aos A ATS, 2 7 IGMI (APPROX) ae FAIRBANKS REGION (974 ELECTRICITY CONSUMPTION FOR REPORTING UTILITIES lS ——————E _— avaTure wee Ae A in Wei Bee es 2 ee rE tr 6°v ————_—, avaTuTE wues FAIRBANKS REGION VII ELECTRICAL SYSTEMS INVENTORY FIRRE NO ni APPENDIX B DEMAND PROJECTION BACKGROUND MATERIAL MAP Economic Model Projection Values Regression Analysis Results - Growth as Usual Case Summary of Alaska Power Administration Load Growth Study Load Factors for Alaska Utilities Approximate Comparative Fuel Costs for Residential Space Heating L5 Boks MAP MODEL ECONOMIC PROJECTION VALUES Limited Development POPULATICN THOUSANDS OF PERSONS RGN 1 RGN 2. RGN 3 RGN 4 RGN 5 RGN 6 RGN 7 STATE 74 13.499 27.503 48.615» 45.283 153.118 8.562 54.920 359.659 75 13.748 27.647 51.466 53.601 163.995 9.967 57.800 378.137 76 14.051 23.042 53.556 56.240 173.753 9.831 59.161 395.934 77 14.220 28.524 54.610 53.252 176.760 9.067 57.867 397.315 78 14.362 28.80! 55.765 54.3812 187.411 9.385 58.735 49.272 79 14.589 29.078 57.582 57.252 158.372 9.387 59.912 426.571 BO 14.919____.29..362 61.555 644245 2146927 ss G. 764____ 624154 456.927 31 15.254 29.879 642112 68.273 225.612 9.79% 64.218 4776145 82 15.593 30.192 66.534 71.557 236.992 9.008 65.962 495.747 83 15.621 30.379 67.842 76.551 247.200 8.736 66.938 513.667 84 15.618 30.710 69.595 79.078 259.264 8.670 62.388 531.523 85 16.935 31.125 71.297 78.793 271.972 8.759 69.957 547.913 86 15.234 21.599 72.870 732301 (284.599 &.767 712415 56%.678 387 16.393 31.833 74.182 80.670 257.139 8.795 72.683 581.693 88 16.549 32.140 75.546 81.495 311.223 &. 802 73.992 599.767 39 16.695 32.471 76.511 23.251 325.995 6.821 75.352 615.503 99 16.857 32.778 78.427 854146 342.414 8.875 11 76.847. 661.344. 1 tele EMPLOY MENT 74 us 76 Lele 78 Te 80 B81 82 R3 84 385 86 87 ge 8g 99 RGN 1 4.085 4.471 4.723 4.682 4.766 5.003 52446 52693 5.999 6-159 6.344 66495 6.639 6.755 6.879 7-020 7.185 eM RGN 2 19.654 11.123 11.567 11.626 11.829 12.219 12.830 Use 2a 0 130109) 14.936 14.392 14.714 15.036 15.534 15.649 15.997 16.376 MAP MODEL ECONOMIC PROJECTION VALUES Limited Development THOUSANDS OF WAGE EARNERS RGN 3 24.627 27.006 28.2624 28.482 29.2138 30.709 33-521 35.040 36.848 37.891 39.056 39.999 40-506 41.659 42.477 43.360 44.354 RGN 4 17.929 21.492 222490 20.554 21.502 222487 252427 262347 28.191 30.396 31.173 30+ 865 30.933 Ble soe 31.579 32-189 32.883 RGN 5 12.475 719.244 84.200 €5.874 89.515 95.351 104.854 169.713 115.506 121.570 127.680 133.607 139.613 145. 664 152.575 160.037 168.476 RGN 6 5. 344 8.687 6.279 6.236 6-830 6. 862 7.872 7-800 6125 56634 52476 5.546 5 0488 52477 52439 52438 Diep Lo RGN 7 24.772 27.542 23.294 26.932 27.336 28.9099 29.760 30.781 31.2933 32.625 33.449 34.187 34.904 35.531 26.297 36.968 37.349 STATE 159.886 119.625 188.177 184.796 190.916 290.720 219.712 Jere 2332696 248.313 2572569 265 412 273.520 281.771 290.2799 301.0190 382.0627 e°L'd ES REAL WES 2GN 1 74% 24.9 Uf) 27.7 76 29.8 77 39.2 78 31.4 79 aoa 0 80 37.1 81 39.5 82 426% 83 44 04 84 46.7 85 48.35 36 50.9 37 32.9 388 55.9 89 Sie 90 59.9 - WS/ePT RGN 2 56.5 60.9 6464 66.0 08.4 T2el 77 04 R1.5 8529 29.7 93.7 97.6 101.4 105.2 19%.2 113.4 118.0 MAP MODEL ECONOMIC PROJECTION VALUES I MILLIONS OF DOLLARS RGN 3 150.5 168.8 182.9 185.9 194.0 208.7 232.6 247.9 265.7 278.4 292.5 305.3 318.1 329.5 342.6 356.1 Sile3 Limited Development RGN 4 102.5 139.3 138.1 128.1 134.1 142.5 168.1 189.6 192.2 21267 221.0 22C.3 222.9 229.0 233.7 241.5 249.8 RGN 5 441.1 493.5 535.0 556.1 590.2 640.0 716.1 761.6 817.7 871.1 $29.4 $87.2 1046.8 1107.9 1176.7 1251.0 1334.6 PGN 6 48.1 82.5 78.1 54.4 59.3 5504 69.4 69-2 1.8 aie. 46.9 4722 47.0 47.9 4726 48.2 49.5 RGN 7 159.2 174.9 183.2 LS) 1é1.2 199/20 20642 218.0 231.2 241.1 252.6 263.6 274.7 265.4 296.7 399.1 323.1 STATE 973.9 1138.6 121125 1195.8 1258.5 1346.6 1506.9 1598.3 1687.0 1784.8 1881.9 1970.9 2061.9 2157.8 2261.7 237606 25062 e lg Ml oe o MAP MODEL ECONOMIC PROJECTION VALUES Accelerated Development eee POPULS TION . THOUSANDS OF PERSONS SGN |: PGN 2 RGN 3 RGN 4 26N 5 GN 6 QOGN 7 STATE 74 13.499 27-563 48.615 45.293 153.118 8.562 54.920 350.659 ie 13.748 27.647 51.466 53.691 163.909 ¢,967 57.899 278.137 76 14.051 78.942 933956 56224) Lied 3 eiBe 59.161 305 2934 tal 14.387 27.483 56.738 55.476 186.201 9.935 59.981 409 6402 78 14.357 76.710 562059 58.859 Se Gil 17 ©2352 53-946 416.363 t9. 14.632 29.049 58.654 ®le233 292.2266 Orzo 60.115 4256196 80 2162055 29.559 62.410 69.092 221.408 10.172 63.932 41712429 81 L&el 38) 1 30.278 652145 78.349 236.962 11.291 64.297 5195 «569 82 20.409 312096 69.286 88.924 257.439 12.958 70.572 549.083 83 20.601 Pe Geo (26957 94.871 278.020 nate 73.391 583.243 84 LE SOS 32.415 T60424 P1155 294.069 0.166 Ge D5 596.253 85 Ll.881 Bo ei2eo 78.392 89.892 297.794 10.025 76.592 514.511 86 1£.610 SDs 80.392 69.975 323.307 $.951 72.212 634.2538 87 18.867 24.2602 82.150 91.668 349.177 10.031 19.959 657.445 88 Ovary, 350267 84.073 pr e2ll 359.740 TORS 61.827 583.424 89 VG eze9 35.6619 86.967 95.613 3792564 10.233 22718 719.163 a0 Vere La: a5 .O 1) 88.027 88.147 409.593 1¢.305 25.607 732.904 wes AS MAP MODEL ECONOMIC PROJECTION VALUES Accelerated Development EMPLOY MENT SON 1 74 4.085 5 4.47) 76 4.723 tH 5.0c9 78 4.635 79 Dela + 89 6-743 S31, 9.326 82 13.99% 83 Ves 58 84 10.514 85 9.845 86 ©2252 87 9647C 8&8 e811 39 9.9% 90 10.031 eM PGMN 2 IN. 654 plea 11.567 12.995 11.€06 12.336 Uae, 13.746 14.8¢ 152439 16.28&9 16.871 17.526 18.274 19.960 19.552 19.338 THOUSANDS RGN 3 2%.627 27.006 - 28.624 20.439 29.547 Siltersin 244226 Sema 38.613 41.2278 43.509 44.248 45-0288 462223 47.293 48.695 49.998 ae o RGN 4 Le 2! 212492 22.499 222119 232213 24.169 27.378 30.44% 34.597 37.3589 35.614 324.679 346444 34.995 35.2%4 36.172 37.0961 WAGE FARNERS SGN S 7206475 79.244 84.290 99.473 912439 972903 198.429 115.221 1246.22% 126.987 144.5599 149.853 1560764 194 65149 174.912 182.3844 194.348 RGN 6 52344 & 587 8.279 6 0498 6.868 6.682 @.¢°35 11.632 14.241 13.274 2.455 T2845 7.273 7.542 7.804% 7.838 72958 OGN 7 24.772 272542 28.294 24-2133 27.660 28.403 30.392 32.079 3%.710 36.422 372144 37.586 38.252 39.962 492037 41.996 42.1746 STATE 159.8286 LT Deo25 188.177 194.575 195 .5E7., 205.981 2292245 245 2.830 275.9463 264.975 296.114 399.916 303 6797 329.947 33370482 347.198 361.359 L'a S¢ REAL WES - wS/PPI ©GN 1 *GN 2 74 24.9 56.5 75 ie 69.¢ 76 29 26 64 4 77 32.2 6°23 78 viet 68.9 79 3422 T7229 80 51.P 797 81 82-7 45.3 82 T2558 G2.8 83 129.2 190.4 84 94.5 18.5 85 37.10 Ll GieC 86 80.2 121.5 87 83.8 129.3 88 98.9 T37 of 89 90.7 143.4 99 93.9 147.5 s ’ ( o » MAP MODEL ECONOMIC PROJECTION VALUES Accelerated Development MILLIONS OF DOLLARS RGN 3 RGN 4 RGN 5 RGN 6 Glu 7 STATE 150.5 192.5 441.1 48,1 150.2 973.9 168.8 139.3 493.5 82.5 174.6 1132.6 182.9 138.1 525.0 78.1 183.2 T2165 198.8 135.3 586.6 55.3 183.7 1260.1 196.8 142.8 632.2 59.5 183.6 1253.6 21323 158.3 657.4 Sileere, 1$2.2 1365.5 25 1s5 126.2 740.9 78.8 211.3 1586.3 252. 216.6 890.3 107.6 ero TAT Seb ZUGiea 247.4% 299.4 129.7 25560) 2020.3 302.9 272.9 982.9 T2164 27325 218s 2 326.8 25566 1952.5 75.3 233.8 2197.8 338.6 251.0 1197.3 69.4 292.8 2260.8 353ien Zoey. L175} 63.7 293 69 2349.4 367.3 258.2 1251.0 67.0 316.7 2473.3 383.6 2455.2 1241.0 79.2 SIEGE) 2617.5 491.5 274.8 1435.4 eTalreta) B47 <1 2754.9 415.9 22562 L537.2 Led 363.5 2916.2 9°L°a B.2.1 B.2. REGRESSION ANALYSIS RESULTS - GROWTH AS USUAL PROJECTIONS I. Northwest - Total! Total consumption = - 31.424 + 3.556 Cvutaton Il. Southwest - Total civilian - Total consumption = - 81.569 er es * §:792 population R2= .984 III, Southeast Residential number of _ real wages, civilian R2 = .975 customers 2-218 *iaeot} and salaries (ase) population average a real wages a consumption — 3.791 Sie and salaries R 753 Commercial number of ~ real wages R? = .96846 customers 1236.5 tyacess) and salaries average a real wages R2 = .97728 consumption -0109 (19382) and salaries Industrial Total consumption = 1.987 ian R? = .970 - 456 Other Total consumption = - 17.224 ea Re = .973 5.770 1 ee Pe ee ; , rae Regression statistics not reported since this equation is the sum of three equations for individual utilities. Note: Numbers in parenthesis are t values. All variables are regional. Bogue IV. Southcentral Residential number of _ _ civilian 4 965 "eal wages customers ——_ jean population (acaie) and salaries R2 = .996 average - real wages consumption \e68 (42an) and salaries Re = .g22 Commercial/Industrial number of _ real wages customers aA I6St {ocRe) and salaries R2 = .9697 average = real wages consumption -010 (agen and salaries R2 = .60268 Other Total consumption = - 17.538 + 2.253 employment R2 = .686 (3.180) Vv. Anchorage Residential number of _ _ civilian 2. customers = ee population : secs real wages 2 average = 3.62 + .013 : R* = .931 consumption (9.742)and salaries Commercial/Industrial number of - _ 1220.55 + 93.791 employment R2 = .98061 customers (18.815) average == = .027 + .002 employment R2 = .95417 consumption (12.071) V.__ Anchorage (cont. ) Other Total consumption = - 46.033 + 1.194 employment (11.966) VII. Fairbanks Residential number of - _ real wages civilian customers 3.410 * res) and salaries (zza0) population average - real wages consumption a0 reer and salaries Commercial/Industrial number of (log) = 3.166 + .878 real wages (log) customers (9.304) 2nd salaries average = real wages consumption 7.008 jams) and salaries Other Total consumption = -.16.487.+ .745 Civilian (1.928) population B.2.3 -953 -969 -916 odo - 26534 -770 B.3.1 B.3. ALASKA POWER ADMINISTRATION LOAD GROWTH STUDY The most recent comprehensive study of future Alaska electric power requirements has been the Alaska Power Administration Load Growth Study done as a part of the 1974 Alaska Power Survey. Projections were made through the year 2000 for electricity requirements of utilities, national defense, and industrial systems. The study developed three scenarios based upon a likely growth rate bracketed by somewhat higher and somewhat lower growth rates. The results of those projections are shown on Table 1. The assump- tions underlying the growth pattern of each type of load appear to be as follows: ; 1) Utility. Load estimates of individual utilities in 1980 were compiled and used as the likely demand figures for that year. Higher and lower growth rates were assumed to be 20 percent more or less than the likely mid-range figure. Growth rates in the subsequent decades were assumed to reflect the development of appliance saturation, in- creased efficiency in consumption, and conservation of energy in all uses. The growth rates were assumed as follows:! Assumed Annual Growth Rates 1972-80 80-1990 90-2000 higher 14.8% 9% 8% likely mid range 12.3% 7% 6% lower range 9.8% 6% 4% lus. Departinent of Interior, Alaska Power Administration, Alaska Power Survey, Economic Analysis and Load Projections, 1974, p. 71. Bosne 2) Military. The Alaskan Command provided the APA with an estimate of 1.7 percent annual growth rate in requirements. This growth does not vary among the three scenarios. 3) Industry. Industrial requirements not supplied by the utilities “were projected on the basis of a recent study by the Alaska Department of Economic Development. Basic elements underlying the three scenarios were as follows: i) high probability of major new petroleum, natural gas, coal, and other new mineral production and processing; ii) significant further developments in timber processing; iii) good possibilities that Alaska energy and other re- sources will attract energy intensive industries. Timber, minerals, and petroleum are the three industries for which growth in electricity needs are projected. In all scenarios, mineral industry growth predominates with low sulfur coal mines, a nuclear fuel enrich- ment plant, extractive metal mines, metal processing plants, and dredging operations suggested as likely projects. The source is one which is likely to take a comparatively (and perhaps unrealistically) bullish view of industrial development prospects in Alaska. Many possible alternative assump- tions could be made since the future development of industrial requirements is very difficult to project. The growth rates of annual energy consumption which come out of the APA study can be calculated as follows for the interval, 1972 to 1990: B.3.3 HIGHER RATE LIKELY MID-RANGE LOWER RATE TYPE OF LOAD SCENARIO SCENARIO __|_ SCENARIO oo Aral ete Utility 10.0% 8.1% 6.6% National Defense Nee 137%. 1.7% Industry 16.6% 12.4% 8.4% Total 11.6% 8.7% 6.3% Type of Loac tility National Defense Industry Total Utility National Defense Industry Total Utility National Defense Industry Total Source: Table I. Actual Requirements 1972 Annual Energy Peak Demand 1000 KW_ Million KWH 355 1,620 110 594 104 455 569 "2,669 Tota) Statewide Power Requirements, -1972-2000 Estimated Future Requirements 1980 1990 2000 Peak Annual Peak Annual Peak Annual Demand Energy Demand Energy Demand Energy 1000 KW_ Million KWH 1000 KW Million KWH 1000 KW_ Million KWH Higher Rate of Growth _— 1,050 4,600 2,490 10,900 5,360 23,500 160 720 190 850 220 960 © 620 4,340 4,290 30,060 4,800 33,630 1,830 9,660 6,970 41,810 10,380 58,090 Likely Mid Range Growth Rate’ - : 940 4,100 1,850 8,100 3,320 14,500 160 720 190 850 220 960 330 2,320 620 4,340 1,720 12,050 1,430 7,130 2,660 13,290 5,260 27,510 Lower Rate of Growth 830 3,600 1,480! 6,500 2,190 9,600 160 720 190 850 220 960 210 1,470 330 2,310 620 4,340 1,200 5,790 2,000 9,660 3,030 14,900 U.S. Department of Interior, Alaska Power Administration, Alaska Power Survey, Economic Analysis and Load Projections, 1974, p. 42. 1 | Bae B.4. LOAD FACTORS OF ALASKA UTILITIES Load factor is defined as: net energy for load peak demand x 8760 It is a percentage measure of the electricity produced by a system over the period of a year in relation to the maximum generated by the system in one hour times the number of hours in the year. A load factor of 1 means that the same amount of electricity was generated each hour of the year. Since demand normally fluctuates, reaching a peak in the winter months and during certain times each day and each week, there is unused capacity during periods of low demand and load factors in Alaskan utilities are generally in the .50-.60 range. Load factors change over time as the composition of demand changes. An increase in residential space heating normally would reduce the load factor by increasing the winter peak. Conversely, certain industries are able to buy power off peak when the utility has unused capacity and, thus, increase the load factor. A higher load factor, other things being equal, corresponds to a lower unit cost of electricity because the generating capacity of the utility is being used more intensively. The trend in load factor of the largest Alaskan utilities has been cal- culated using regression analysis on the following equation: Fe = Fo (1+g)* where F = load factor t = year of observation - 1965 Fo load factor in 1965 g = growth rate over time of load factor Results of this analysis are presented in the accompanying table. CALCULATED TRENDS IN LOAD FACTORS Load Factor 10 Year et (1965) (1974) Load Factor “Rate” SOUTHEAST Juneau (AELP) -497 sol 536 -67 Ketchikan 544 -618 - 582 -70 Petersburg -594 -611 -591 -68 ‘Sitka 579 547 565 - .17 SOUTHCENTRAL Palmer (MEA) - 544 - 546 2008 - .50 Homer - 540 -626 -590 -69 Kodiak (KEA) -539* 632 - 550 -04 ANCHORAGE Anchorage Municipal 15652 -605 -578 83 Chugach Electric -50 543 -527 .70 FAIRBANKS Fairbanks Municipal .529 -644 - 582 1.9 Golden Valley - 560 - 443 - 505 - 1.00 * 1966 figure Statistic mo FS WwW ao a no © t -07 B.4.2 R 52 .74 44 .01 seo -19 -01 -53 -78 ~59 -44 B.4.3 Year to year fluctuations in load factor are normal and expected as a result of weather and other factors. These equations estimate the signi- ficance of a trend over time to a higher or lower load factor resulting from a change in the composition of demand. From the low Re figures, it is apparent that there are substantial year to year fluctuations.* The t statistic is an indicator of the significance of the growth as a function of time. A t statistic greater than 2 is roughly "significant at the 5 percent level." Several utilities have load factors which have been trend- ing "significantly" on this basis. Load factors have been increasing in Juneau, Ketchikan, and Petersburg in the Southeast. Changes in Sitka and the Southcentral region have not been significant. In Anchorage, load factors have been increasing at about .7 percent yearly. In Fairbanks, Fairbanks Municipal has been increasing its load factor by 1.9 percent yearly while Golden Valley has had a de- clining load factor over the period. The trends identified by these regressions may not continue into the future because they are obviously not a function of time but rather of the composition of demand. The differences in load factor between utilities should be noted also. These differences among utilities are also the re- sult of differences in the composition of demand. For the smaller utilities, 10 year averages for load factor have been calculated. The resulting averages are as follows: * This is partially the result of using calendar year data. B.4.4 AVERAGE LOAD FACTORS - SMALL UTILITIES Annual Average Northwest Load Factor Kotzebue -551 Nome -528 Unalakleet (MEA) -491 Southwest Bethel - 482 McGrath - 626 Dillingham (NEA) -526 Naknek - 562 Southeast Metlakatla .465 Wrangell] - 587 Skagway (AP&T) 451 Hydaburg 392 Craig «32d Juneau (GHA) -435 Southcentral Kenai (HEA) 521 Seldovia (HEA) .376 Seward - 558 Cordova -479 Glennallen (CVEA) -613 Valdez (CVEA) -649 With the load factor known, one can move from the demand for electricity in terms of KWH to net generation capacity requirements. Because of year to year fluctuations and changes in the composition of demand, load factor can vary and change the relationship between electricity demand and generation requirements. This must be kept in mind when calculating net generation requirements. B.5.1 B.5. APPROXIMATE COMPARATIVE FUEL COSTS FOR RESIDENTIAL SPACE HEATING A comparison of the cost of residential space heating using different fuels depends basically upon the available heating potential of the fuel, measured in btu's, and the efficiency of the system in converting the avail- able heat energy to usable energy, measured as a percentage. This compari- son does not take into consideration the lower initial cost of electric space heating. The available heat energy of different fuels is fairly constant, but conversion efficiency to heat for each fuel varies considerably with the individual installation, particularly in the case of the fossil fuels. A recent study found that the national average conversion efficiency of natural 1 On the other hand, the upper bound gas space heating units was 60 percent. on the efficiency of a new unit has been estimated at 85 percent. For this reason, a table which compares the cost of an equivalent amount of space heating provided by different fuels can only be a rough guide. ‘conservation Foundation, "Hidden Waste - Potentials for Energy Conservation," David B. Large editor, (Washington, 1973), p. 24. 2claude Summers, "The Conversion of Energy," in Energy and Power, (San Fran- cisco: Scientific American, 1971), pp. 95-109. B.5.2 The available btu's in common Alaskan fuels are as follows: unit measure btu/unit electricity kilowatt hour (KWH) 3,413 #2 fuel oil gallon 138,500 natural gas thousand cubic feet (mcf) 1,005,000 The following percentages are assumed for conversion efficiency of the above fuels:° conversion efficiency to space heating electricity 100% #2 fuel oil 65% natural gas 75% Given these assumptions, equivalent per unit prices for one million btu of space heating are as shown in the accompanying table. This table is for residential space heating customers only. Because the production of electricity involves the conversion of mechanical energy or fossil fuel energy to electrical energy, the conversion efficiency of the process creating the electricity must be considered when making compari- sons for other purposes. For example, a natural gas fired turbine producing electricity which is then used for space heating is less energy-efficient than using the natural gas directly in a furnace. The cost of using natural gas for space heating, as measured by btu's, will generally be higher if it is first converted to electricity and then to heat rather than if it is converted to heat, directly.* » SErom L. 0. Bracken, "Power Demand Estimators, Summary and Assumptions for the Alaska Situation," Alaska Department of Economic Development, 1973. * Despite the greater cnergy-effieieney of the direct use of fossil fuels for heal ing, it is not always more cost efficient than its use as electricity when the cost. of transmission or transportation is taken into account. While it is generally cheaper to move large volumes of energy by pipeline in the form of natural gas than by wire in the form of electricity, for example, the re- lationship is reversed for the costs used by a single dwelling at some dis- tance from the trunk line or distribution center. cost per million btu $2. -40 ao on on oO i 7 93 -86 .59 33 -06 79 72 -65 -58 Unit Fuel Price for Equivalent Space Heating Output electricity ¢/kwh 1.5 2.25 2.5 2.75 ao om #2 fuel oil $/gallon $ +26 -40 +53 -59 -66 73 79 1.05 1.32 1.58 natural gas $/mcf $2. 3. 41 ono ano ua FSF i 20 31 95 51 . 06 -61 81 02 see Bs5.3 APPENDIX C POSSIBLE FUTURE GENERATING TECHNOLOGIES AND MODIFICATIONS FOR ALASKA C. 1. Geothermal C. 2. Nuclear C. 3. Fuel Cells C. 4. Coal Gasification C. 5. Solid Waste Energy Colt C.1. GEOTHERMAL TECHNOLOGIES Current trends in technology indicate two basic plant types which could be used to exploit geothermal resources: 1. Small systems of less than 5,000 KW using surface hot water without well drilling. 2. Larger systems of 10,000 KW and larger using the higher tempera- tures obtainable at well depth. Load must be large enough to support the higher cost of well drilling. The possible power production from each well is dependent upon the fluid temperature and flow rate. As the fluid temperature goes down, the flow rate must go up to produce a given quantity of power. There are currently three basic geothermal conversion systems. They are: 1) flashed steam, 2) Binary cycle, and 3) total flow. 1. Flashed Steam The wellhead fluid is fed into a flash separator. The vapor frac- tion thus produced is then used to drive a standard axial-flow steam turbine for electric power generation. This system uses standard equipment, and plants are operational in New Zealand, Japan and Mexico. 2. Binary Cycle This system uses a lower temperature fluid to heat a secondary fluid in a heat exchanger. The secondary fluid is expanded through a fixed-temperature, low-pressure turbine for electric power production. C.1 3. Total Flow The total flow method uses wellhead fluid expanded directly across the turbine for power generation. The flashed steam system is a proved technology, but the Binary cycle and total flow technologies are untested and will require pilot project demonstration in order to prove their feasibility. Alaskan subsurface con- ditions have been estimated to be in the lower range of temperature and flow rates, which are best utilized by the Binary and total flow technologies. Wells must be drilled, and the flow and temperature rates measured, before the likelihood of power production can be determined using these methods. Geothermal energy utilization in Alaska has the advantage that the fluid could be used for space heating after power generation. This might par- tially offset the higher cost of well drilling in the state. Research to develop alternative energy sources other than fossil fuels will greatly enhance the prospects for geothermal power production. © oe C.2.1 C.2. NUCLEAR ENERGY IN ALASKA Due to the large size of economic nuclear fission plants (1000 MW and higher), the potential for nuclear electric generation in Alaska is limited through the rest of this century. The installed cost of present 1000 MW and larger nuclear fission plants in the continental United States has been estimated in recent years at $300 - $600/KW although some plants have had much higher initial capital costs. Alaska costs for installations iden- tical to those constructed or under construction in the continental United States could easily be over $1,000/KW in 1976 dollars. This installed cost does not include environmental costs and litigation costs, which may be considerable. Because of limited Alaskan interest in nuclear electric energy in the forseeable future, this report will not review reactor details and relative merits. It is worth noting that sources of fuel for fission reactors may be running out by the time Alaska might seriously consider the nuclear al- ternative. Electricity from nuclear energy will then depend on the success- ful development of the controversial breeder reactor or on the realization of fusion type reactors operating from heavy hydrogen. A Canadian design "CANDU" type reactor has introduced some new factors into the nuclear picture which could possibly create Alaskan interest prior to the next century. These reactors employ a different fuel bundle design, have heavy water cooling, and utilize unenriched and, therefore, cheaper C.2.2 uranium fuel. These innovations allow both smaller scale plants in the range of 500 MW and lower installed costs. This type of plant is still new and further scale reductions could at some time in the future bring the size of nuclear plants into the range of Alaskan needs. Sources: "The Economics of Nuclear Power", M.I.T. Technology Review, February 1975. "Natural-Uranium Heavy-Water Reactors", Scientific American, October 1975. C.3.1 C.3. MEGAWATT SCALE FUEL CELLS The promise of fuel cells suitable for application at electric utility demand and energy scales has been repeated by research and development firms for over a decade. The technological leader in fuel cell development has historically been the Pratt & Whitney Aircraft Corporation. This company developed the multi-million dollar Apollo fuel cells which were hydrogen- oxygen fueled. Its efforts to develop small fossil fuel cells in the range of 12.5 KW have been underwritten by gas and electric utilities for $50 million. A new research and development consortium composed of Pratt & Whitney, the Edison Institute, some of the large Northeast utilities, Southern Cali- fornia Edison, and possibly the federal Energy Research & Development Ad- ministration (ERDA) has been formed which would initially invest more than $40 million toward the specific goal of a demonstration 26 MW fossil fueled unit. This would be the first utility scale fuel cell ever developed. Pro- jections of a 1978 demonstration unit with production units to follow by 1980 have been made by the consortium. All fuel cells are best described as "continuously fueled batteries". Energy conversion is direct electro-chemical in nature, just as in a con- ventional battery, but instead of being "charged" periodically, the cell is fueled continuously. The primary fuel cell technology to date has centered around the physics of hydrogen-oxygen conversion. Pure hydrogen-oxygen sys- tem fuel cells such as those used on hydrogen-oxygen rocket propelled lunar 1 modules have severe economic limitations as utility scale units. However, a Hypothetically, a large hydro or nuclear power plant could manufacture hydrogen during off-peak load periods for storage and later fuel-cell use. C.3.2 all fossil fuels are basically hydrocarbon compounds. By reforming these fuels into their basic hydrogen and carbon elements, and using oxygen from the air, it is possible to operate a fuel-cell from natural gas, petroleum, coal, gas, or shale oil. The reforming process is built into the fuel cell. Assuming the successful development of commercial fossil fuel cells in the 26 MW scale range at competitive installed costs, there is potential for applications in Alaska for several reasons. First, Alaska is a prime market for units in the 26 MW scale range which fit small community power requirements. Second, the fuel cell units are highly portable because of their compact size. Third, their size, clean emissions, low noise level, and lack of moving parts allow them to be sited practically anywhere. Fourth, the siting flexibility would reduce distribu- tion costs. Finally, the siting flexibility would allow installations to take advantage of otherwise waste heat. By installing the fuel cell within a building, the heat which is a byproduct of the chemical process in the fuel cell could be completely utilized for space heating. This could increase the overall efficiency of the unit to 70 percent. (System efficiency would be somewhat lower because of the energy required to convert hydrocarbons to hy- drogen and carbon dioxide. ) Compared with a gas turbine, the efficiency of a fossil fuel cell would be higher, possibly lowering the heat rate to as little as 9,000 btu/kwh. This would be an approximate 25 percent gain over the best combined cycle turbine in use today and a 47 percent gain over open cycle turbines of which there are several in Alaska today. At a natural gas price of 60¢/mmbtu, this would translate into a fuel cost savings of 48 mills/kwh. The fuel cell also has the unique capability to maintain a high ef- ficiency at low loads, which is of particular advantage to small communities with low-load factors. s C.323. If feasible, the proposed 26 MW scale fossil fuel cell seems ideally suited to Alaskan electric requirements in many instances for many years. Unfortunately, in 1976, it is only a proposal. Availability of fossil fuel cells as a production alternative prior to 1985 seems very improbable. There are many technical problems to be solved before production of a large fuel cell with proved economic feasibility and reliability can be planned upon. C.4.1 C.4. COAL GASIFICATION Conversion of coal into Substitute Pipeline Gas (SPG) is a proved technology which is presently in use in 16 plants located around the world. However, the present cost of synthetic gas is four to five times that of natural gas. In the future, the prices of natural gas will certainly increase, and it is conceivable, if unlikely, that SPG may become competitive for base-load usage, such as electricity generation in some cases. A decent estimate of the typical conversion efficiency of coal to SPG is 65.2 percent. The conversion of gas to electricity occurs at approximately 30 per- cent efficiency. Thus, the conversion of coal to electricity through inter- mediate step of gasification results in a conversion efficiency rate of approximately 17 percent. This is approximately half as efficient as using the coal directly to generate electricity. To compensate for this reduc- tion in conversion efficiency and the extra cost of gasification, the cost of gas transportation must be much lower than that of either coal or electricity. A typical coal gasification plant of 250 MMcf/d capacity and average efficiency of 60 percent will require an annual bituminous coal feedstock of 6 million tons. Capital requirements for such a plant have been esti- mated to be $260 to $305 million for an underground eastern site and $175 to $230 million for a surface mined western site. The capital cost of an Alaskan plant would be much higher. * The practice of the gas transmission companies of "rolling in" the prices of costly gas from unconventional sources with those of low-priced natural gas from conventional sources, allows them to market quantities of unconventional supplements, including synthetics, at a lower price than its cost to them. For this reason, some gas transmission companies and distributors may desire to manufacture synthetic gas from coal at (say) $3 to $5 per MCF in order to continue serving electric utilities who are unwilling to pay more than $1 to $2 per MCF (the price of alternate fuels). Rolled-in pricing results in gross misallocation of resources, but it is well established in utility practice and regulatory principles. C.4.2 The vast coal deposits in Alaska are ideally suited for conversion plants, but within the same regions are large quantities of oi] and gas which will be exploited before mining of coal for gasification will be economically feasible. Hence, the prospect of coal gasification con- tributing to Alaskan electricity generation in this century is very un- likely and will not be considered an energy resource alternate for this study. An alternative system for use of coal is in combined-cycle, low-btu gasification plants. Here, the coal is converted to gas of less than pipe- line quality and burned on the site in a combustion turbine which drives a generator. Waste heat from both the gasification phase and the turbine are used to generate steam, which in turn drives a steam turbine. With the com- bined cycle, theoretical efficiencies as high as 50 percent can be achieved. Because of the considerably higher capital costs of this sytem in compari- son to coal-fired plants, however, the principal interest in the combined cycle plant is as a means of controlling sulphur and other emissions from the combustion process. Sources: J.L. Hatten, "Pipeline Quality Gas From Coal", Mechanical Engineering, July 1975. U.S. Senate, Committee on Interior and Insular Affairs, Advanced Power Cycles, Washington, D.C., 1972. C7 5s C.5. SOLID WASTE ENERGY The nationwide problem of solid waste disposal is also present in Alaska, and municipal planners are investigating more efficient methods of disposal than the present sanitary landfill. Currently, each person produces approximately 5 pounds of solid waste per day, and this is projected to increase to approximately 7 pounds per day by the year 2000. Each pound of refuse contains approximately 5,000 btu of heat energy. This heat content presents a supplemental source of energy that could be utilized while at the same time, reducing the volume of solid waste that is required to be disposed of in a landfill. An idea of the volume of energy associated with solid waste may be obtained by calculating the electrical energy contained in the approximately 155,000 tons of refuse disposed of in Anchorage in 1975. The heat content of the refuse would be approximately 1,550,000 million btu, or at a conver- sion rate of 12,000 btu per kilowatt hour, approximately 130,000 kwh of electrical energy. This would contribute approximately 10 percent of the energy consumption for 1975, provided that 100 percent of the area refuse were processed. Facilities have been constructed in several locations in the Lower 48 which utilize conditioned solid waste as supplemental fuel for fossil fueled power plants. The expertise and equipment necessary for the conditioning and burning of municipal refuse is available; however, due to the unique conditions that exist for each application, specific recommendations are not presented in this study. APPENDIX D TRANSMISSION TECHNOLOGIES Transmission Lines and Economics of Interties Regional Potentials for Interties Submarine Cables Oil and Gas Pipelines vs. Electrical Transmission Geothermal Pipelines vs. Electrical Transmission D.1 D.1. TRANSMISSION LINES AND ECONOMICS OF INTERTIES Transmission voltages are generally regarded as those above 34.5 kv, with 33-35 kv considered as subtransmission and below 33 kv as distribu- tion voltages. The primary distinctions are: Transmission (above 35 kv) Used for transporting large energy blocks long distances Sub-Transmission (33-35 kv) Used for transporting large energy blocks short distances or smaller energy blocks inter- mediate distances. Distribution (below 33 kv) Used for transporting small energy blocks short distances and includes electric supply voltage directly connected to consumer transformers at or near the point of electric power purchase. The common line voltages (phase-phase) presently existing in Alaska are: Distribution Sub-Transmission Transmission 2.40 kv 33 —okv 69 kv 4.16 kv 34.5 kv 115 kv 12.47 kv 138 kv 13.80 kv 24.94 kv Table 1. summarizes the existing transmission lines as of December, 1975. The largest system presently in operation is 138 kv, but the 230 kv transmission threshold is being approached. Within the time frame of this +1 D.t2 Table 1. Transmission Lines Over 33 KV KV Mileage Fairbanks 138 104 69 57 34.5 42 Anchorage-Cook Inlet 138 48 Overhead 138 4 Submarine 115 213 69 153 34.5,33 127 13.8/69 4 Southeast 138 41 Overhead 138 3 Submarine 34.5/33 30 ALASKA 138 193 Overhead 9,600 MW-Mi. 138 12 Submarine 115 213 7,700 MW-Mi 69,13.8/69 214 2,700 MW-Mi 34.5,33 199 600 MW-Mi 20,600 MW-Mi. Sources: U. S. Department of Interior, Alaska Power Administration, Alaska Power Survey, System Coordination and Interconnection, 1974, p. 17. Robert W. Retherford Associates, Anchorage. D1-3 study, transmission lines up to 345 kv or even 500 kv may be considered for the Southcentral part of the state. Larger systems, although more costly, can transmit energy a longer distance with a given line loss for a given loading level. In addition, the higher the load on a given line, the greater the percentage line loss. Transmission line costs in Alaska have shown large variation and have in recent years been escalating as a result of labor cost increases and right of way procurement and clearing cost increases. Environmental im- pact statement preparations and related public review have added substan- tial initial costs to already capital intensive transmission line construc- tion. The capability of the line to transmit electricity increases approxi- mately with the square of the line is voltage rating while construction costs increase linearly with voltage. Thus, unit transmission costs are lower for high voltage transmission systems than low voltage systems, as- suming the line is fully utilized. Table 2. presents hypothetical transmission line costs generated by the Alaska Power Administration as well as actual costs for two recently installed transmission systems near Anchorage and Juneau. The juxtaposition of the costs of the two recent installations under- scores the fact that generalizations concerning installation costs of trans- mission systems in Alaska are difficult to make. The estimated 1976 cost of the 26 mile line from Point McKenzie to Teeland is $90,000/mile. The actual cost turned out to be about $75,000 per mile. The high cost of the Snettisham- Juneau line of 41 miles was the result of initial construction problems and relocation of the line. For these reasons, D.1.4 Table 2. Hypothetical and Actual Transmission Line Costs in Alaska No. of Per-Mile Cost KV Circuits With Clearing 33 SC (Single) $ 50,000 DC (Double) 75,000 69 SC 55,000 DC 90,000 115 Sc 70,000 DC 115,000 138 Sc 95,000 oc 125,000 138* Sc 75,000* (1975) Pt. McKenzie to Teeland Substation 138* Sc 250,000* (1975-76) Rehab. of Snettisham 161 Sc 100,000 Dc 155,000 230 SC 105,000 oc 180,000 345 SC 155,000 DC 280 ,000 500 sc 255,000 Sources: U. S. Department of Interior, Alaska Power Administration, Alaska Power Survey, System Coordination and Interconnection, 1974, p. 50. Robert W. Retherford Associates, Anchorage. * Actual costs Dee5 the high cost per mile for that transmission line should not be taken as representative of Alaskan 138 kv transmission line construction costs, but rather should indicate that costly problems can arise in particular situations. All transmission voltage level lines in Alaska presently are single circuit. Double circuit transmission on a single structure has not been adopted by utilities because of the additional construction costs for the same capacity. The provision of double circuit capability by means of separate and independent structures usually offer a better combination of economic load-carrying capacity and circuit reliability than single structures, and Alaskan utilities have adopted this method. However, where environmental and right-of-way problems exist, double circuit lines are being considered. i = D.2.1 D.2. REGIONAL POTENTIALS FOR TRANSMISSION INTERTIES I. Northwest Region The load is small, dispersed, and expected growth is moderate. No potentials for interties envisioned using conventional transmission systems. II. Southwest Region As in the Northwest, conventional transmissions systems are not eco- nomically feasible. However, communities in the vicinity of Bethel may have intertie potential using low-cost, unconventional transmission sys- tems. The Alaska Power Administration has reviewed the feasibility of a low-cost Single-Wire-Ground-Return (SWGR) line for the Bethel area with preliminary findings favorable. Economically feasible hydroelectric de- velopment at a scale appropriate for regional loads would enhance the Single-Wire-Ground-Return line feasibility. III. Southeast Region The U. S. Corps of Engineers, assisted by the Alaska Power Administra- tion (APA), is completing a Southeast Regional Hydroelectric Power Study which will examine the potential for intertie of the communities of Peters- burg, Wrangell, Ketchikan and Metlakatla. This potential was briefly re- viewed by APA in the 1974 Alaska Power Survey and is shown in Map 1 taken from the APA study. A key element in this potential intertie would be the D.2.2 submarine circuit portions. Although small in relation to overall tie- circuit length, their use would become questionable from both a relia- bility and economic viewpoint if proposed in excess of a 5 mile length at any single crossing. Particularly to be viewed with caution would be a crossing of the Stikine River flats or any similar area subject to periodic channel relocation and scouring. In addition, the transmission intertie installed cost per mile may be higher than those experienced in the Southcentral Region due to special Southeast Alaska terrain, clearing and environmental factors already identified in the construction of the Snet- tisham-Juneau line in this region. In 1976 dollars, this might reasonably range from $95,000 to $125,000/mile. A second Snettisham-Juneau line is not economically justified until load growth warrants further development of the Snettisham hydroelectric project. At Sitka, a 115-138 kv line under 30 miles is feasible to intertie the community with the proposed Takatz and Green Lake hydroelectric pro- jects, and its construction will depend upon economic feasibility of these projects. This proposal is shown as Map 2. IV. Southcentral Region and Railbelt Area The Copper Valley Electric Association plans in 1976-77 to intertie the communities of Valdez and Glennaltlen via a 138 kv line. The proposed Solomon Gulch hydroelectric project would supply this circuit. An addition- al tie circuit to Cordova might also be feasible. This might enhance the economic feasibility of the Solomon Gulch hydro project (although it is De2.3 attractive without Cordova intertie) and could be so routed as to provide access to other hydroelectric potential developments in this three-com- munity subregion. The possibility of a railbelt tie between Anchorage and Fairbanks has been examined several times within the last decade. It is technically feasible and thus dependent upon economics. The Corps proposal for the Devils Canyon Project includes a double-circuit 230 kv 184 mile line north to Fairbanks and a double-circuit 345 kv 136 mile line south to Anchorage from the proposed Gold Creek terminal. Without this major hydroelectric development, single or parallel 230 kv or 345 kv lines interconnecting An- chorage-Fairbanks are feasible. An intertie of these large power systems would enhance the possibility of development of lowest cost generation for Anchorage and Fairbanks using either hydroelectric or lowest cost fossil fuel. Thus, the decision to intertie would be one of economics. The iso- lated, smaller railbelt communities would benefit from a related sub-trans- mission/distribution system. Completing the loop of transmission and intertie around the Fairbanks- Delta-Paxson-Glennallen-Anchorage route is not likely until development of more load growth in the eastern communities makes such a project economically feasible, perhaps in the latter 1980's. However, the possibility of a sub- transmission intertie between Golden Valley Electric Association and Copper Valley Electric Association near Paxson may be feasible within the next few years. See Map 3 for these possible interties. D.2.4 The potential for a Kodiak - Port Lions intertie is poor, unless the Terror Lake hydroelectric project is developed, in which case the intertie would be achieved incidental to the transmission from Terror Lake to Kodiak. V. Anchorage Region The intertie between Anchorage and Palmer using a 138 kv line is presently under construction. This line will ultimately be part of the Beluga-Anchorage alternate route augmenting the Beluga-Anchorage subma- rine cable system under Knik Arm. Load growth in the Kenai Peninsula will soon require either new gen- eration or more transmission from Anchorage. The development of the Bradley Lake hydroelectric project to maximum scale could reverse the traditional Kenai role as an energy recipient and result in some load-flow toward An- chorage using new 230 kv lines. Alternatively, in the more immediate fu- ture, well-head gas-turbine generation expansion in the Kenai Peninsula could displace electricity presently imported from the Beluga field well- head plant. If this occurs, only transmission line development commensurate with local Kenai growth would be required into the 1980's. VI. Interior Region The communities in this region are extremely small with modest electric loads. Transmission service between communities, of which the largest is Fort Yukon, is not economically feasible with conventionally constructed systems. D.2.5 The new 138 kv transmission system serving the North Slope and northern pipeline region is the only transmission facility in this re- gion. It is privately owned by Alyeska Pipeline Company and operated by British Petroleum Company and does not wholesale or retail public power. VII. Fairbanks Region The construction of major radial transmission lines from Fairbanks to outlying communities is unlikely into the 1980's. One possible excep- tion is a highway route intertie between Glennallen and Fairbanks in the Paxson vicinity. Fairbanks' electrical system capital will be focused on meeting its own local load-growth and the development of lower cost genera- tion. In this respect, the Fairbanks region will seek transmission inter- ties which supply energy into its system rather than expanding radial transmission out of its system to new loads. "09 ‘d ‘p/6L ‘UOLzDaUUODAazZUT pue UOLZeULpAoOD WezSAS ‘faAUuNS AaMOd BYSELY SUOLZEUSLULUPY 4AMOd eYSeLY ‘4OLUaqUT JO JUAaUQUedag *s “fy aounos PETERSBURG 5 fi SUBSTATION 22 Cretenburg ETCnIRAN LOCATION ™. GOAT CREEK POWERPLANT B& SWITCHYARD "ATRaNGELL) eae SUBSTATION ETOLIN 'SLAND ZAREMBO ISLAND CLARENCE ™~ SCALE IN MILES a oe $e a ‘SUBSTATION : e : s wT) “’ oS fo NS 5 a TYEE CREEK os POWERPLANT Soy SwitcHYARDS \_————/ ISB RV am, SWAN LAKE POWERPLANT. SWITCHYARD Sthaunt Geay wa ON METUARATLA ‘APA = JUNE 1974 UNITED STATES DEPARTMENT OF THE INTERIOR ALASKA POWER ADMINISTRATION POWER POTENTIALS FOR THE PETERSBURG— WRANGELL- KETCHIKAN AREA GENERAL PLAN “L dWW WS0d0Ud JILYFLNI NOIDSY LSWAHLNOS 9°2°d *Kaaans [}aUUODAByUT pue UOL}eULPA00) WaySXAS "29 “d ‘p/6| ‘uo 4ABMOd BASELY SUOLZRUZSLULWPY UBMOg BYSeLY ‘UOLUaQUT Jo JUAaUuedag “Ss ‘fn aounos as ZETRKATZ CR. He GREEN LAKE —a LOCATION MAP. ye Voce LAKE c GREEN LAKE ~~ POWERPLANT AND SWITCHYARD \ TAKATZ CREEK POWERPLANT AND SWITCHYARD amen 9 TAKATZ UNITED STATES DEPARTMENT OF THE INTERIOR ALASKA POWER ADMINISTRATION TAKATZ CREEK AND GREEN LAKE PROJECTS GENERAL PLAN SCALE IN MILES SS aaa 4 A.PA~ JUNE 1374 “2 dwW STWSOd0Ud NOISSIWSNVYL WALIS £°2°0 D.2.8 MAP 3. SOUTHCENTRAL REGION INTERTIE POSSIBILITIES VICINITY MAP ” , ; 2 2h Sy, WOOD Bal CANYON! U.S. DEPARTMENT OF THE INTERIOR ALASKA POWER ADMIKISTRATION KEY HYDROELECTRIC AND TRAUSUISSION ALTERMATIVES FOR THE RAILSELT > fe : ef ? ny AP I CRADLET | ey LAKE § whe ag 54 ne MGS Sl ee ene Et aeebinry eatin meer ST Source: U. S. Department of Interior, Alaska Power Administration, Alaska Power Survey, System Coordination and Interconnection, 1974, p. 65. D.3.1 D.3. SUBMARINE CABLES Developments in submarine cable technology in recent years offer new potentials to Alaskan electric utilities near tidewater. Several modern design submarine cables have been installed and these are listed in the accompanying Table 1. The cables are of two types, solid dielectric and oil filled. The former has the advantage of lighter weight and a very small bending radius. This allows installations with less specialized and smaller scale marine equipment which reduces the cost of installation. A reeled, solid, one- piece dielectric cable up to 100 tons in weight and 4.0 miles in length has been recently successfully laid in 360 feet of water across Kachemak Bay using tug and barge equipment of a size available in Alaska. Oil filled cables, such as those laid across Knik Arm, are extremely heavy and have large minimum bending radii. They require specially designed cable laying vessels and equipment not available within Alaska. This results in higher installation costs which require that larger loads be served so that the unit cost of energy transmission is not prohibitively high. Modern solid dielectric cables up to 138 kv of both single and multiple conductor design are compiling an excellent performance record with regard to cable integrity. However, submarine cables in Alaska have not been com- pletely successful. It appears that the primary hazard to submarine cables is maritime traffic and specifically, the operations of anchoring, dredging, and bottom fishing. The Anchorage circuits have developed repeated faults Region. Southeast South-Central Anchorage Southwest Community Juneau Seldovia Anchorage Anchorage Anchorage Kodiak SUBMARINE CABLE Installation in Alaska Installation Date (Owner Utility) [APA (servicing AEL&P from Snett. Hydro) ] January 8, 1976 (HEA Serving Seldovia) 1970 (CEA from Beluga) August, 1975 (CEA from Beluga) 1967 (CEA from Beluga) 1969 & 1972 (KEA serving Woody Is.) (1) These circuits damaged winter of 1974/75. Operating Voltage 138 kV 24.9 kV (3/c, solid) 138 kV (3/c, oil filled) 138 kV (3/c, oil filled) 138 kV (1/c, solid) 12.5 kV Circuit Miles 3.1 4.0 8.0 8.0 4.0 1,5 (2) Two each, 3/c replacement circuits, installed 1975 for 150MW total capacity. (3) CEA derates these circuits (1976) to 55MW for normal operating purposes. Design Installed Loading 75MW 1OMW 75MW(1) 75MW (2) 90MW (3) SMW $/Mile $520 k/mile $120 k/mile $700 k/mile $813 k/mile $450 k/mile $ 55 k/mile o°e°a D.3.3 over their combined seven year history but all apparently from external causes of various kinds. The Kodiak-Woody Island 15 kv circuit was par- tially damaged by a tug and barge operation two years after being energized. Tenuous service was maintained on the balance of the circuit for over a year before replacement cables could be obtained and laid. The Kachemak Bay 25 kv cable has only been energized for a few months but is operating satisfactorily. Multiple circuit redundancy over separated physical routes provides for increased reliability of service but only at a much higher cost. The alternative is to plan the submarine circuit characteristics for repair capability and have emergency service alternative electric sources available to the system loads in the event of an outage of the cable. Almost all submarine cables installed in Alaska employ one or both of these plans to increase service reliability. The economic feasibility of submarine cables in any particular situation is a function of circuit voltage, load, length of circuit, service relia- bility requirements, estimated circuit hazard, and water depth. Table 2 shows the general range of costs in 1976 dollars for submarine cables of various voltages and designs. Table 2 Submarine Cable 1976 Costs a Voltage 3/C, Oil filled 138 kv 1/C, solid 138 kv 3/C, solid 35 kv 3/C, solid 25 kv 1/C, solid 25 kv 1/C;, solid 15 kv * Costs are for cables in place only. No onshore facilities or terminals included. Installed Cost* $1000/Circuit Mile $ 870 $ 700 $ 200 $ 145 $ 115 $ 70 D.3.4 D.4.1 D.4. OIL AND GAS PIPELINES VS. TRANSMISSION LINES If the cost of transporting a given quantum of energy a given distance by pipeline is compared to using electric transmission lines, it is seen that pipelines are generally cheaper. 0i1 pipelines in turn have an economic ad- vantage over gas pipelines because the lower fuel density of gas requires a larger capital investment per heat unit transported. Gas lines also have more complex handling problems and hazard protections. Figure 1 shows the transportation cost in cents per million btu of transporting energy in different forms using different systems. It shows that even if one reduces electric transmission costs by a factor of three to compare with fossil fuels at 33 percent efficiency (average fossil energy to electrical energy conversion rate), gas and oil pipelines are cheaper than electric transmission. These comparisons are of course dependent upon the amounts of energy carried, particularly where they involve pipelines, for which economics of scale are considerable. D.4.2 Figure 1 TRANSPORTATION COSTS OF ENERGY BY DIFFERENT MODES Transportaticn costs, 20 cents/million B.t.u. — per 100 miles — ge w= Electricity. 700 Kv. a.c. ae rerpnenn te ee . _” Electricity. 50 Kv. d.c. Factor of three by which to lowerelectric transmission cost for comparison with fossil fuets at 33 per cent .y efficiency. Coal, conventional rail _ Liquified natural gas, rail Coal, unit train Gas, pipeline Coal, pipeline (Pr) Coal, integral train (Pr) Oil, pipeline Liquified natural gas, snip Liquified natural gas, barge | ae on | = ~—- Gil, tanker, 25,020 tons dw. | o- 200 -400 600 800 1000 | 28 5 pie | Ege ese poate ey ee cera | : Miles | pcagh the chart above proposes to show comparative costs of jaensporeng fuel and energy in different forms and by different means, it is in fact so simplifie as to be only vaguely correct. For the actual transportation cost depends critically on the efficiency of the particular facility being considered as well as on the par- ticular place and time when it is being used; for these reasons—and because parallel data are difficult or impossible to acquire—a critical issue in developing our energy strategies is only vaguely suggested by this presentation. Source: Technology Review, Energy Technology to the Year 2000, A Special Symposium, MIT, Cambridge, Mass., 1971. DT5ea D.5. GEOTHERMAL PIPELINES VS. TRANSMISSION LINES Geothermal energy can be transmitted either by electric transmission lines or by a hot water pipeline. The relative efficiencies of the two systems depend upon the final use to which the energy is put. If properly constructed, over a distance of 50 miles or less, the energy loss of a geo- thermal pipeline is about equal to that of an electric transmission system. With this in mind, the controlling factors in the comparison would be ini- tial capital cost and final end use of the delivered product. For example, the comparison below shows the cost of a pipeline to be five times that of the transmission line. At first inspection, the electrical transmission system would appear to be the best application. Cost Comparison Estimates (25 MW capacity, 50 miles) Transmission Line Pipeline $5,000,000 ($100,000/mi. ) $22,440,000 ($85/ft. ) $ 500,000 (2 sub-stations @ 250k) $ 500,000 (2 pump stations) $5,500,000 $ 250,000 (surge control) $ 250,000 (pumps, valves, etc.) $23,440,000 However, assume that 20 percent of the energy delivered is utilized for electricity generation and 80 percent is used for heating. With a geo- thermal pipeline, 80 percent of the hot water thus delivered could be used D.5e2 directly for space heating without further conversion and little or no additional operating cost. The electrical transmission system has a lower conversion efficiency because a large percentage of the electric energy must be reconverted back to heat energy. If the cost of producing the electricity and converting it back into heat, plus the cost of electricity transmission, aeamais the cost of the geothermal line, plus the cost of producing only 20 percent of the transmitted energy as electricity at the destination point, the geothermal pipeline would be preferred. It is plausible that the high capital cost of the pipeline could com- pete favorably, based on life cycle costs, with the high operating cost of the all-electric system, depending upon the utilization of the heating energy and alternate heat resource costs. In addition, it appears that as the trans- mission distance is reduced, other things being equal, the thermal pipeline becomes more viable. . - APPENDIX E MAPS OF ALASKA RESOURCES E. 1. Map of the State, Showing Regions and Census Divisions E. 2. Oil Province Locations, with Estimated Reserves, State E.-3. Goals Geothermal, and 0i1 Shale Province Locations with Estimated Reserves, State E. 4. Major Hydroelectric Potentials Northwest Region E. 5. Barrow Division Fossil Fuel and Geothermal Resources E. 6. Kobuk Division Fossil Fuel and Gevtharmal Resources E. 7. Nome Division Fossil Fuel and Geothermal Resources Southwest Region E. 8. Key Potential Hydroelectric Projects Southeast Region E. 9. Key Potential Hydroelectric Projects E. 10.. Secondary Potential Hydroelectric Projects Southcentral Region - Anchorage Region —E. 11. Anchorage Region Fossil Fuel and Geothermal Resources Kenai-Cook Tnlet Division Fossil Fuel and Geothermal Resources and Existing Electrical Interties E. 12. Seward Division Fossil Fuel and Geothermal Resources E. 13. Matanuska-Susitna Division Fossil Fuel and Geothermal Resources E. 14. Valdez-Chitina-Whittier Division Fossil Fuel and Geo- therial Resources E. 15. Cordova-McCarthy Division Fossil Fuel and Geothermal Resources E. 16. Southcentral Region - Anchorage Region Key Potential Hyavestéctric Projects E. 17. Anchorage Region Fossil Fuel and Geothermal Resources OIL PROVINCE LOCA ONS “% SONS. AVOUNTS FER OF MAGNITUDE REGON 1 ANCHOR: 8) Coe SET BASS on ooes. “ors fom 26 Ov ozs 2. SOUTHCENTRAL Z* Coppre DYES BAS 100% 22 COOK Wie BUS. uy 90% 23 BRSTOL SASS ca 24 MO Ax SLAND PROVINCE om 29 BLE OF ALASHA PONCE rR “TAL FO2 OLS ON 3. NORT#W P2ov Ace o% 1 ORev NCE 33 SPE eas Be WOE CANCE, Bbaorriase Bas 2e VIAN KOVeK os 2! 37 BE2\G SEA 2D09~ 4. NOR 41 BEA 42 wore 23 YUKON AND K BAS 4 DDE AANA BUS s AS OR HOY EUN GEIS NE 2 08 6eGoN 28 MIDDLE TANANA BASIN 50% 13 DBO" 20 sao: of 10% — — ee 7% 1s 280 308-07 BERING “SEA VNU MA BASS 3% gana YS SYURON KOVUMUK HECSYACUNE = 23% OBR masa! VINCE NX “TAL FOR BEG ON 1505 931+ 08 SOUTHEAST 8) GUE DE ALASKA B2DV\CE x 270 aan “OTA. 508 RESON 229 a of I. FA RBANKS 7 wDDLe AMARA Marauusies SUSIT NA conpova MCARTNY ALASKA POWER STUDY ‘STFA RS INC =! aes NOE 3S. VES SON £28 OS VED PAS NS OFS S VOSS VISES TD Wane. MAM oe TON BETHEL 5 ere ee ST = uppee vurow NORTHWEST REGION A ofa -d “ or =O aA a cen 868. 9 2 ‘ a Wom 3987 * @ 22 VAAL Sas CO4. FELD 2.3 23 we Con ED Bez eareow, 2a 92205 9752 co ED we co ELD S Be COR FELD 100% 2? 2.34 SAT CO. FED 100%. < xosue 7 N 2 rad = . PARAA KS HIGON rasue 7 MR CED won eet ean sans o ‘ 4, FN Se GErERVAL coma eros Wa» — i yh Lui a) Za q ) 2 errs sovrweast ae BROUNCE C/T ONS FAIR @ANKS wh ce FAIRBANKS RECOV * B25 oe a om aa 4 Nomeray 285 08 10% on con ces ES suS-NA OAL FELD! 7. . BATANUSHA ih okt, ySiT Na MITA Kusmonwins ERNE from con ED | 4 ay = HOR LGE aay sRisTou \ . NTS ~| mts “SUSITNA PROJECT" US CORP of ENGINEERS 1978 PROPOSAL. ps © wer cc cee omeroe win rome, sree £O rau © cerrmenrar ro mawemes mesounce. . © mrermaronse senceweer mons, rene 9 s ronaauc “Sesser HIGH TRAKSWISSION COST PENALTY TO REACH APPROPRIATE REGION EXTREME ENVIBONMENTAL DETRIVENTS, PROJECT SCALE MOT APPROPRIATE REG.OMALLY, CONFLICT RAMPART PROPOSAL EXCLUDED FROM POTENTIALS FOR REASONS COMMENTED, SHOWN FOR PURPOSES. OF PROJECTS SCALE COMPARISON OMY MAJOR HYORCELECTRIC POTENTIALS 183-2400 MW RANGE” MO_2VES S-OWN 422 ESTIVATED (SPECULATED) ANOGDN"S OF SPACE WDROCLRSONS. AVOURTS ND CATE OF9E2 OF VGN TUDE ONLY. OFS-CPE CuuKCul SEA OL FELD Woue¥8 6122020200 BABPELS OW “33. cx0,000, 000,000 CF GAS on K034< DVSON RE BROW DVSON SS WTHN OR"4 S.OPE OL PROVE, eanrow NORTHERN O'L SHALE FIELD YOUVE: ©.9),784,000 ares: 5 YOUVE | 2,710,000 000 S427E.3 OL aN 13 seo.c00,00n700 CE GAS OFFS-O7FE BE4 7087 SEZ O'L FIELD > OSHORE SOF S_OFE OL FELD ye WOLIYE: 15.500,000,009 S497E.5 04 (4 1,002,000,000,009 © GS vf Pree DVIS ON {\ WN Avy es = batt Sa sorry sips asiy— = Lon KEE) QD WOE PROVACE ON us yp - Yo 7 ervece % \ moans KE | \ J iS 41 SN osuawe | 2, 1a4ON - KOVEKUK —— wi = _ re ; WOBUK DVISON Se. DY SION ° ~. SSo._f., | es a TESUE AAS — / _ aoe sores = sacl F, DEEANG @ BucKLAND & KOBUK DVISON £ — 9 h «=» \ K03_< DV SON ALASKA POWER STUDY |F STE < NOVE DIVISON STEFANO @ wate von ELM WADE HAVPTION DIVISION YUKON = KOV KK DVIS ON ww Ov 2 NZ cree or seman mae Seb meine oa te re ov manre A [7 2 LOT STATION £ / SOUTHWEST REGION i! KEY POTENTIAL PROJECTS HYDROELECTRIC g sect evarute mes FIGURE NO. 8°4 Goat Lane asew anaMeD LAKE seuw -HOOWAN presen TAKATE LAKE wouw CARBON LAKE couw FOUR FALLS LAKE sO Mw Mie Lame touw xr = CRYSTAL LAKE (exisTinG 1.8 ew EXPANSION 0.4 MH) WS PENS? < be = aN SS <a Q@yr feereanarca punt pant ee ceee sae sm SOUTHEAST REGION III KEY POTENTIAL PROVECTS HYOROELECTRIC —-~- FIGURE NO. are ae canveow ome Un. ac, CR. stn TURMER Ue. ashing, ey ut, ome Lemon 1 ees grees oeanosuey exerting) CRATER UK amr owe LK, Emprcorr af. SEAR Lx, CmLKAT TEASE Ux. SMETTiSMAM CEKSTIN® —— SWEETHEART CR, Ered DELTA 1 me reo bs OR Se Bove SOUTHEAST REGION Ii! SECONDARY POTENTIAL PROVECTS HYDROELECTR'C UNCLUDES EX/STING PROVECTS = = =; he WITH EXPANS\ON POTEMTIAL) avaTUTE wes eg ce ake ie b. sovsiadibtinieniinneinsn cohen mms | ee eum eee Olea "UINE BAY RE WN RYER FIELD | BELUGA RYER FIELD Ni COOK INLET FIELD KENA! FIELD FALLS CREEK FIELD -] NCRTH FORK FELD SPANSON 2 VE? FELD BEAVE? CPFE« FELD SERNG ELD G43? Pe LAE POWER T24NSWIS3.ON UNE cy Dy SON BoLsoar RKELAS SUTTON OL ¢ GAS FIELDS 4.8) © AED0UET SoA. _— @wor.eeaaxs sax, 20 (Qwest FoRELAND _ @ wesrraur VER 2 (SN MIDDLE GROUND SOK — ©) TRADING Bey 10 (7) Gente PONT is @Nicora: creex es (9) AwEAT Kaas aS WO) MOQsAWKIE, — (i) e-ues aver — @ v.cooK LET a (3) WN RIVER fe (A) 2.9m wie as (15) SWANSON RIVER a (&) aeavee CREEK — (1) wesm oR« _ (it) SveRLNG = (9) mene ae (@) Fas Cresw _ 2) NOwTH FORK DVISION TOL 115 COAL a me Brae Fee OS HF ro - He <86+0° 2 48 «0° or feo? _ os os 48 +0" _ 28 S50" 708 a CF ans Feom ars KENAI-COOK INL T_DIVISION ALASKA POWER STUNY Presa ANCHORAGE ANCHORAGE DIVISION KENAI-COOK INLET DIVISION VALDEZ -CHITINA- WHITTIER SEWARD DIVISION DIVISION DIVISION LOCATION } | SEWARD DIVISION ALASKA POWER STUDY STEFANO BAS Coen Gt éLl°3 KUSKOKWIM DIvIS!ON KENAI-COOK INLET DIVISION / YUKON -KOYUKUK DIVISION DIVISION wittow @ i has ANCHORAGE DIVISION MATANUSKA-SUSITNA SOUTHEAST FAIRBANKS DIVISION VALDEZ CHITINA WHITTIER DIVISION Q'IVISION LOCATION sr KENAI-COOK INLET DIVISION. ANCHORAGE ANCHORAGE DIVISION MATANUSKA- ak 7 EF emarson MANTASTA @LAaKe on DIVISION Wf ~~ ~gonsrgenn oS tees, cuempauey A tz as shevniibdas coPren Shing VALDEZ ” = =: CHITINA WHITTIER DIVISION ¢ curriwa Pe vacoez y p E ro eae ° AR TATATILIC a COR DOVA-McCARTHY DIVISION SOUTHEAST FAIRBANKS DIVISION i, DIVISION LOCATION | oH mrss Beau} | VADDEZ-CHITINA- WAN TIER DIVISION | m ALASKA POWER STUDY |=@ QUVISION LOCATION SOUTHEAST FAIRBANKS DIVISION VAL DE Z:CHITINA: WHITTIER OIVISION CORDOVA-McCARTHY DIVISION D Georwenmn CANADA YARATAGA 1 Ces = reso | ow TORDOVA-MeCARTHY UiWISION 5 ALASKA POWER STUDY 9 . ei tesealiee 75 es ol i nah swow nivel TRUt NORTH 4 ‘ GAY us cones OF CWOUMCERD Mas sivicace Peasmurtr OF BRADLEY alsé Cae To 108 ae beveLonmenT st + manent, sy EF £ v U { 3 2 Me Sart ; e - : ° YESS a svaruTe wnes REGCNAL LOCATION ree SOUTHCENTRAL REGION IV ANCHORAGE REGION V KEY POTENTIAL PROVECTS HYDROELECTRIC Otes MATANUSKA-SUSITNA - DIVISION OP SARE cecen @cMuarax @rAoLe mivER ANCHORAGE ANCHORAGE DIVISION KENAI~COOK INLET DIVISION SEWARD DIVISION VALDEZ CHITINA WHITTIER DIVISION DIVISION LOCATION [ANCHORAGE DIVISION ALASKA POWER STUDY ;% rar APPENDIX F SUMMARY OF RATINGS USED TO SELECT FUEL RESOURCES AS FEASIBLE summarized from STEFANO/MESPLAY ASSOCIATES bol Appendix F SUMMARY OF RATINGS USED TO SELECT FUEL RESOURCES AS FEASIBLE Thirty-three potential fuel resource sites within Alaska were analyzed for their feasibility as inputs into electricity generation before the year 2000. The results of that analysis are summarized in the following tables. The study analyzed 14 oil] and gas provinces, 12 coal sites, one oil shale site, and 6 geothermal sites. Information is limited on many sites and their commercial potential. For this reason and because of the fact that events between the present and the year 2000 are not predictable, the conclusion regarding the feasibility of each potential site is of necessity subjective. ell OIL AND GAS F.1.2 COOK GULF OF KODIAK BRISTOL BERING —CIIUKCHE F_RESCAVE INLET ALASKA ISLAND BASIN SEA ___& NOPE __ BEAUFORT _ 1. LOCATION MAP Region IW-V 0 OLI-IV W ra I-ll I+ WL 11, RESERVES a: Speculative 1. off (billion 2.50 8.8 24 94 27.4 8.40 2.7 barrels) 2. gas (trillion 18.40 64.2 5 6.83 200.0. 46.0 13.5 cubic feet) b. Anticipated Usable 1, off (ointton WB --- 2-2 eee unknown s+ 52 ee eee ee barrels 2. gas (trillion 202 ------------ unknom = +--+ ----+--- cubic feet) IIT. RESOURCE DISPOSITION a. Availability of Technical Data 1. complete x 2. incomplete x x x x x x 3. unavailable b. Past Activity . 1. general Tocation x x x x x x defined . 2. research x x x x x 3. planning and x development 4. production x c. Current Activity 1. exploration x x x x x x 2. development . ‘ 3. production x 4. inactive d. Uestination of . resent Production 1. same region x none none none_-~—none none none 2. Alaska 3. Outside x e. Additional Activity Anticipated Before 2000 1. none 2. production x x x x x x x f. Destination of Anticipated Activity 1. undetermined x x x x x x 2. same region x 3. Alaska 4. Outside x g. Technology Required for Exploitation . requires research x x x + most advanced x x x currently avatlable . state of the art x technology 4. standard technologies in common use IV. RELATED INFORMATION a. sification é x x x x x x 2. state x x x x 3. other 4. uncertain x x b. Distance to load Center 1. ° 2. 0-25 wiles 3, 75-50 miles 4. 40-100 miles 4. wore Chan 100 wiles x x x x x x x c. Environwen for Sucto-Lcons vic Lnpacts i. x 2. x x x x x x 3. unknown V. PEALORARLE: ALT SALIVE FOR POLER SOUKLI Ee Yes x % x x NAHE OF, RESERVE LOCATION HAP Region RESCRVES “a. Speculative it. Iv. 1. of] (billion barrels) 2. gas (trillion cubic feet) b. Anticipated Usable 1. off (billion barrels) 2. gas (trillion cubic feet) RESOURCE DISPOSITION a. Availability of Technical Data 1. complete 2. incomplete 3. unavailable b. Past Activity 1, general location defined 2. research 3. planning and development 4. production c. Current Activity 1. exploration 2. development 3. production 4. inactive d. Destination of Present Production 1. same region 2. Alaska 3. Outside e. Additional Activity Anticipated Before 2000 tinalion of Anticipated Activity 1. undete o 2. same regton 3. Alaska 4. Outside g. Lechnulogy Required for Explot tation 1, requires r 2. most advane currently avatlable 3. state of the art technology 4. standard technologtes in common use rch RELATCD INFORMATION a. Land Classification 1. federal 2. state 3. other 4. uncertain b. Distance to Load Center 1. immediate area 2. 0-25 miles 3. 25-60 mile 4.50 100 mites 4. wore Chan 100 miles ¢. Enviromental and/or fo Lconomte Lapacts anor REASONABLE ALTE RMATIVE FOR POULR SOURCE? Yes OIL AND GAS YUKON YUKON- I I I-l af VI 15.50 69 3.44 143 1.67 41.8 5.03 9.31 3.5 11.37, x x x x x x x x x x x x x x x x x x none none none none x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x KOTZEBUE _KOYULUK BETHEL KANDIK_ F.¥.3 TANANA, COPPER = MINCIUMINA, RIVER NOL LTA Iv. TI-IV-VI 16 16 1.20 1.28 x x x x x x none none x x x x x x x x x x x x x x x x x x NAME. OF RESERVE. 1. LOCATION MAP Regton . Consus Divisions TL. RESERVES It. b. Speculative (willion tons) Anticipated Usable (willion tons) RESOURCE DISPOSITION Availability of Technical Data 1. complete 2. incomplete 3. unavailable . Past Activity 1. general location defined 2. research 3. planning and deve lopment 4. production + Current Activity 1. exploration 2. developient 3. production 4. tnactive Destination of . Present Production 1. same region 2. Alaska 3. Outside . Additional Activity Anticipated Before 2000 1. none 2. production Destination of Anticipated Activity 1. undetermined 2. same region 3. Alaska 4. dutside g. Technology Required for Exploitation 1. requires research 2. most advanced currently available 3. state of the art technology 4. standard technologies in common use IV. RELATED INFORMATION v. ny For Yes Land Classification 1. federal 2. state 3. other uncertain stance to Load Center + iumdiate area + 0-25 miles 3. 24-50 miles + 90-100 utes, than 109 miles wironeental and/or pocig-Coonumle Inpacts 1. winor 2. major 3. unknown SORABLE AL TLPRATIVE FOUR SOURCE? NORTHERN I-VI Barrow, Upper Yukon 1,700,000 120,197 none >emere NLNANA, VI-VIT Yukon- Koyukuk, Fairbanks 8,680 2,018 SARIS, vi Yukon- Koyukuk 17.8 5.9 unknown COAL MATANUSKA 49 47 Le none SUSITNA 26,900 2,400 x none KENAL Vv Kenai- FELD _ F.1.4 BERING RIVER Iv Cordova Cook Inlet McCarthy 50,900 2,700 x not sold o> 3,000 unknown x none NAME OF RESERVE 1, LOCATION a. MAP Region b. Census Divistons II, RESERVES a. Speculative (million tons) b. Anticipated Usable (millfon tons) III, RESOURCE DISPOSITION a. Availability of Technical Data 1. complet 2. incomp) 3. unavailable b. Past Activity 1. general locatfon defined 2. research 3. planning and development. 4. production c. Current Activity 1. exploration 2. development 3. production 4. inactive d. Destination of . Present Production 1. same region 2. Alaska 3. Outside e. Additional Activity Anticipated Before 2000 1, none 2. production f. Destination of Anticipated Activity 1, undetermined 2. same region 3. Alaska 4. Outside g. Technology Required for Exploitation 1. requires research 2. most advanced currently available 3. state of the art technology 4. standard technologies in common use IV. RELATED INFORMATION a. Land Classification 1, federal 2. state 3. other 4. uncertain b. Distance to Load Center 1, {nmediate area 2. 0-25 miles 3. 25-50 miles 4. 50-100 mites 5. more than 100 miles c. Cavironuental and/or Socto-Cconcmic Impacts 1, minor 2, major 3. unknown V. REASONABLE ALTERNATIVE FOR PUWER SOUKCE? Yes COAL HERENDEEN CHIGNIK _UNGA BROAD EAGLE __BAY FIELD FIELD ISLAND PASS __ FIELD u un 1 vr VI Aleutian Aloutian Aleutian Yukon- Upper Islands Islands Islands Koyukuk Yukon 2,900 240 150 no 100 unknown unknown unknown 64 unknown x x x x x x x x x x x x x x x x x none none none.=—sntone-—none. x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x x F.1.5 OIL SHALE NORTHERN FIELD I-VI (bittion barrels 10.9 “of of] equiv.) unknown APPENDIX G FOSSIL FUEL GENERATION SYSTEMS DESCRIPTIONS AND COSTS @ PrP wow Pe — as © 2 @ m2 @ @ 7) . . . . . . . . on aD _ oO G.11. Introduction Cost Summary Sheet and Fuel Price Sensitivity Alaska Construction and Operating Cost Factors Case #1 Diesel 0i1 Fired Diesel Generator Case #2 Gas Turbine Simple Cycle Case #3 Gas Turbine Regenerative Cycle Case #4 Coal Fired Power Plant Case #5 Gas Fired Steam Turbine Case #6 011 Fired Steam Turbine Case #7 Geothermal Steam Turbine Case #8 Geothermal Binary Hot Water Power Plant Se USL G.1. INTRODUCTION This section presents in raw form the basic cost data on fossil-fuel gener- ating plants which was collected for this study. Cost information was developed for eight different plant types with nameplate capacities ranging from 100 KW to 300 MW. For simplicity of comparison, all costs are presented under the unrealistic assumption that the power plant will be built in Anchorage, Alaska. Costs of capital and operations for plants located in other regions and census divisions within the state are estimated by multiplying the Anchorage base case by a regional cost factor. The cost factor reflects the best available estimate of the cost increase for outlying plant construction and operation resulting from transportation of equipment, labor costs, logistical problems, weather, and other factors. These cost factors range from 1.0 in the Matanuska-Susitna and Valdez-Chitina-Whittier census divisions to 2.8 in Barrow, Kobuk, Yukon-Koyukuk, and Upper Yukon census divisions. It must be emphasized that all cost figures presented in this appendix are estimates only. Many of the units analyzed have never been installed in Alaska and, thus, there is no past experience upon which to base estimates. ! In addition, the cost of new plants which are the same types as existing plants vary with time and the specific requirements of the individual loca- tion. Both of these factors result in greater cost uncertainty the further | Thomas R. Stahr (Manager, Anchorage Municipal Light and Power) comments: (The Electrical World "19th Steam Station Cost Survey (1975)" covers a period of) "extremely rapid cost escalations, so cost comparisons are difficult. Since many of the relevant plants reported on had a mixture of old and new units, it was not possible to segregate the old and new costs. Therefore, to get some measure of the more recent costs I made cost escalation calculations for survey plants number 711, 719, and 728, which were apparently totally new plants which went on line in 1972 and 1973. Assuming annual escalations of 6% and 8% respectively, and "Alaska factor 1.35". one obtains 1985 cost as follows: 355 MW units $838/KW - $1061/KW 675 MW units $687/KW - $870/KW 825 MW units $669/KW - $846/KW" (Letter to Tussing, May 10, 1976). . Grle2 the plant is moved away from Anchorage and as a result, caution must be used in analyzing the cost of plant installation outside of Anchorage. No additional expense is calculated to deal with site-specific environ- mental problems or with anticipated tightening of air quality and other en- vironmental standards. All costs are in 1975 dollars and the unit sizes are chosen to correspond to standard industrial capacities. Construction cost includes interest during construction at 8 percent. Operating costs include debt service at 7.5 percent, insurance at .3 percent of value of plant, and taxes at 2.1 percent of gross receipts net of taxes. No reserve for cover- age requirements on debt is included in operating costs. For generating facilities requiring more than a single year to con- struct, construction costs are broken down by time of occurrance. A 300 MW coal fired steam unit, for example, requires five years to construct. Fuel costs for the plants presented here are as follows: coal 71¢/million btu $12.50/ton gas 53.5¢/million btu 54¢/mcf oil $3.93/million btu $.55/gallon The fuel prices are not comparable because each is quoted for a dif- ferent location. Coal is southcentral mine mouth, gas is Anchorage, and diesel oil is Alaskan bush. All plants are assumed to operate close to capacity in order to obtain the lowest possible heat rate (btu/kwh). For example, a 3 MW diesel gen- erator is assumed to operate at a heat rate of 10,230 btu/kwh. Gols3 Both fuel costs and plant heat rate will vary with the installation and its location. Heat rate in addition will vary with the method of plant operation. For these reasons, in addition to those noted above, the unit cost figures presented in this appendix must be considered hypothetical and not the actual costs per KW of capacity or the cost per kilowatt hour of generated electricity for a plant in any specific location. Some of the cost sheets in the appendix are on an abbreviated form. Those projects have costs very similar to another which has been fully cost analyzed. The abbreviated short forms thus refer to a base case plant and include only those costs which are different from the base case. ro G.2. ALASKA CONSTRUCTION AND OPERATING COST FACTORS I. NORTHWEST REGION Barrow Division 2.8 Kobuk Division 2.8 Nome Division 253 II. SOUTHWEST REGION Aleutian Islands Division feed, Bethel Division Zell Kuskokwim Division 2s Wade-Hampton Division a Bristol Bay Division les III. SOUTHEAST REGION Angoon Division Haines Division Juneau Division Ketchikan Division Prince of Wales Division Sitka Division Skagway-Yakutat Division Wrangell-Petersburg Division eel ced sid wd od od ol HPPHHHHHL IV. SOUTHCENTRAL REGION Cordova-McCarthy Division list Kenai-Cook Inlet Division Vel Kodiak Division 1.8 Matanusak-Susitna Division 10 Seward Division USL Valdez-Chitina-Whittier Division #0 V. ANCHORAGE REGION Anchorage Division 1.0 VI. FAIRBANKS REGION Fairbanks Division lise Southeast Fairbanks Division lie VII. INTERIOR REGION Upper Yukon Division 2.8 Yukon-Koyukuk Division 2.8 G.3.1 G.3. COMPOSITE SUNMARY SHEET AND FUEL PRICE SENSITIVITY SUMMARY SHEET BUS BAR €OST* $/KW Mills/KWH SIZE CAPITAL UNIT (Mi) COST 90% Plant Factor 50% Plant Factor Diesel Generator - 100 680 93.91 130.14 270 524 62.24 78.07 -900 490 53.28 61.64 3.000 412 622 58.37 Gas Turbine (Simple Cycle) -800 526 2.4% 32.82 . 3.000 437 17.70 25.49 10.000 322 16.19 22.69 25.000 217 12.47 16.05 50.000 210 11.97 . 15.12 Gas Turbine (Regenerative “10.0 394 14.34 21.48 Cycle) 25.0 268 10.43 14.52 50.0 259 9.91 43755 Steam Turbine (Coal Fired) «2 1346 42.74 69.25 . 3.0 891 23.76 35.46 10.0 827 22.80 34.22 2250 736 21.18 31.39 66.0 509 16.11 22.46 200.0 494 13.75 « 19.36 300.0 480 13.52 18.93 Steam Turbine (Gas Fired) ne 1130 39.32 64.68 3.0 749 20 #26 30.97 10.0 703 18.32 27.83 22.0 618 17.54 26.52 66.0 427 13.10 18.65 200.0 415 11.50 16.63 300.0 403 11.29 a3 16.26 Steam Turbine (0i1 Fired) “s 1130 79.91 105.02 3.0 749 61.03 7is3t 10.0 695 59.06 68.54 22.0 618 57.78 66.75 66.0 427 52.14 57.66 200.0 414 43.75 48.88 300.0 403 43.55 48.48 Geothermal Steam Turbine 10.0 924 16.98 30.55 ua 25.0 735 12.45 22.39 Geothermal Binary Hot Water 10.0 1599 25.38 45.66 Power Plant 25.0 1272 19.19 34.52 * Fuel prices are not directly comparable in this appendix because the prices are for different locations. Gas is priced in Anchorage, diesel in the bush, and coal at minemouth. , Gas = 53.5¢/mmbtu; Oi] = $3.93/mmbtu; Coal = 71¢/mmbtu. G.3.2 “BUS BAR COST SENSITIVITY TO FUEL PRICE CHANGES @ 90% LOAD FACTOR FUEL PRICE FUEL PRICE HABE DOUBLE UNIT BASE CASE BASE CASE* BASE CASE Diesel Generator 69.80 93.91 *-- 41.05 62.24 --- 31.85 53.28 --- 30.10 Si.22 --- Gas Turbine (Simple Cycle) --- raloyed 29.65 . --- 17-70 25.75 --- oaGs19) 24.20 --- 12.47 20.48 --- 11.97 19.98 Gas Turbine (Regenerative Cycle) --- 14.34 19.70 --- 10.43 Osa, --- 9.91 15.25 Steam Turbine (Coal Fired) 38.05 42.74 50.74 ; 19.28 23.76 31.96 18.54 22.80 31+30 16.97 21.18 29.60 12862 16.11 24.26 10.38 a5 20.50 10.14 13.52 20.26 Steam Turbine (Gas Fired) aoe 39,32 45.24 o-- 20-26 26.38 --- 18.32 24.73 o-- 17.54 23.89 --- 13..10 19.24 o-- 11.50 16.58 --- 11.29 16.38 Steam Turbine (0i1 Fired) 55.81 79.91 oo- 37.04 61.03 -c- 35.46 59.06 --- 34.49 57.78 --- 29.53 52.14 --- 25.08 43.75 “oo 24.88 43.55 oo- Geothermal Steam Turbine 16.98 16.98 16.98 12.45 12.45 12.45 Geothermal Binary Hot Water Power Plant 25.38 25.38 25.38 19.19 Na) 19.19 * Fuel prices are not directly comparable in this appendix because the prices are for different locations. Gas is priced in Anchorage, diesel in the bush, and coal at minemouth. Gas = 53.5¢/mmbtu; 011] = $3.93/mmbtu; Coal = 71¢/mmbtu. Fuel DIESEL GENERATOR Unit 100 KW 275 KW 900 KW 3000 KW Assumptions: G.4. SUMMARY SHEET Case #1 Diesel Oi] Fired Diesel Generator | Generator | Size Range 50 to 150 KW 200 to 350 KW 700 to 1500 KW 2000 to 5000 KW 1. Plant Factor = 90% 2. Oi] Cost = $.55/gal. = $3.93/million BTU $/KW Capital Cost $680 $524 $490 $412 Electricity ——>>~— Bus Bar Cost Mil1s/KWH 90% Plant Factor 93.91 62.24 53.28 51.22 G.4.1 1. fs Project Type Diesel 100_KW Instailed Capacity ___- Firm Capacity - 788 ,000 KWH Annual @ 90% 20 Yr. Operating Life 12,180 PROJECT DESCRIPTION 100 KW DIESEL Heat Rate “(BTU/KWH) CONSTRUCTION COST. Input 6.4.2 | Region: Anch. Ident ifytng Community: Anch N Yes X No Base Case: -$ Outlays aan By Year (1000 $) Generation | ao a 2 NOT Site purchase + | Equipment Labor (man years) we Materials © Transportation & Freight Engineering (man years) Management (man years)“ Licensing : Jt Interest. during construction a ' |Blearled te ofrng I Sle Transmission Site purchase Equipment __- Labor (man years) _ Materials , be Transportation Engineering (man years) i= Management (man years). Licensing Interest af =f Ib Other - : TOTAL Total Construction Cost: | OPERATING = Input = Plant E Op <a and Maintenance . Fuel Insurance 10% 27 4 1 Total Operations Cost. 32 La a a el rennet fa esas ed ered ($1000) 50% 27 zt 49 Annual Fixed Costs (generation) . (1000 $) .07 Interest and Amortization .—. —$___ ..005 Depreciation -' : feet) Sn ca Annual Variable Costs ~ Operations and M Maintenance Fuel @ 90%° .; = Insurance Taxes - CONSUMER. COST . Installed Cost Firm n Energy s/n 680. —G.4.3 bate Project Type piesel ; . . Region: _Anch. 5 KW Installed Capacity PROJECT DESCRIPTION Identifying : Firm Capacity - KWH Annual @ 90% 275 KW Yr Operating Life j DIESEL Base Case: Yes X 0,942 Heat Rate ‘(BTU/KWH) CONSTRUCTION cost No Ino] ~ she E Dp ce oO Oo io Input ol ; al $ Outlays Incurred By Year (1000 $) Generation Community: Anch. <==! oO _ nn w Site purchase Equipment Labor (man years) Materials Transportation & Freight Engineering (man years). “Management (man years) Licensing Interest. During Construction Other - Overhead & Contingencies * TOTAL 144 oor | DW W)O|O ct { | weteerees saat ol Transmission Site purchase Equipment __-. Labor (man years) _ Materials Transportation I Engineering (man years) Management (man years) Licensing Interest Other - TOTAL Total Construction Cost: EE | _ OPERATING cost (Sino) te eee 'tnput™ : eta Gf Pe aL Plant Factor] Og weal Tp sell! 50x Operations and Maintenance 27 et : oT ir Fuel ae i all ||| Fal : 52 Insurance , . : i a || a 1 Total Operations ee Ul lll 39 80 e492 lan, lest cee lil anes ||| Hl CONSUMER COST . ‘ Annual Fixed Costs (generation) . ie +) 6 ; Installed Cost Firm Energy sk 524 Interest an Amortization ed eo) ale ei Depreciation” ..- : “Bus Bar ies 090% Mil1s/KWH Annual Variable ( Costs (generatioiy ——— ST eats Cathie 8 Operations and M eT _ Diss} Fuel @ 90% ® Sire ; te ait as eet Insurance Taxes , Pili a 6.4.4 TAC; Project Type Diesel ‘ . , Region: Anch. 900 KW Installed Capacity PROJECT DESCRIPTION Identifying D ‘ Firm Capacity - : a : Community: Anch © 90% KWH Annual 7,095,600 ‘900 KW 20 Yr. Operating Life . DIESEL Base Case: hie x 10,883 Heat Rate. (BTU/KWH) . SEBBOTION Cost COST Input oa : : -$ Outlays Incurred By Year (1000 $) Generation a Ma —— . 7 Site purchase Equipment 10 Labor (man years) : . 165 . Materials 160 Transportation _& Freight 10 5) 3 32 10 Engineering (man years “Management (man years) Licensing : : Interest. During Construction ~ mers Other. - Overhead & Contingencies 30 TOTAL 441 Transmission Site purchase Equipment Labor (man years) _ Materials , Transportation Engineering (man years) Management (man years) . Licensing Interest - Other _. TOTAL Total Construction Cost- ; fais ~ OPERATING COST. ($1000) ‘Input Be SU eee Plant Factor 10% : 50% 90% Dperations and Maintenance 29 : 29 Sete 28 Fuel ae ; 34 : 169 . 304 Insurance , 7 2 12 . 5 2 : ae Z Total Operations Cost... ” 65 aie : 200 4 335 ig aete var CONSUMER COST . : Annual Fixed Costs las (1000 $) ° Installed Cost Firm uae UKM -490 Interest and Amortization ——L— eth Ot ty ies es a Depreciation: a - Annual Variable Costs caer aehaa vat _ Operations and Maintenance 4 eT Fuel @ 90% . ' Insurance ‘Taxes - 6.4.5 B.Ci. Project Type Diesel / f Re sae Anch. 3000 KW. Installed Capacity PROJECT DESCRIPTION Identifying - Firm Capacity - 5 iia a ae Community: _ Anch. “@ 90% KWH Annual 23,652,000 3000 KW Operating Life : Base Case: Yes X DIESEL Nau ae 10,732 Heat Rate (BTU/KWH) _ CONSTRUCTION. COST. Input . pb : -$ Outlays Incurred By Year (1000 $) 20 Yr. Generation Site purchase Equipment Labor (man years) _ Materials Transportation & Freight Engineering (man years) “Management (man year's) Licensing Interest: During Construction Other - Overhead & Contingencies : TOTAL Transmission Site purchase Equipment oer (man years), Materials : Transportation . Engineering (man years) ~ .. Management (man years) . Licensing Interest - Other . - - TOTAL Total Construction Cost: ge SEEN Eo ae _ OPERATING COST ($1000) ° Enpute er a ee 2S kd : = | “joe a 50%, iQ Nee ean Operations and Maintenance 91 : Six. 7- ee hieeg 9t Fuel ate ee Shae 7 B54 “s 997 Insurance Tey Oo ee Bee bP . - 5 4 Total Operations Cost. . 207 "650 - 1,093 Doge CONSUMER COST. ; Annual Fixed Costs (generation) .000$) = Installed Cost Firm Energy SW 412 _ ~~ Interest and Amortization i . i Depreciation : ~ Bus Bar Cost @ 90% MilTs/ KKH vet Slee. “Annual Variable Costs (generatton) as yoead oO i Tg MRS Operations and Maintenance Fuel @90% — Insurance| a Taxes .* G.5.1 Geis5: SUMMARY SHEET Case #2 Gas Turbine Simple Cycle Electricity ——>— =4 Generator GAS TURBINE Bus Bar Cost $/KW Mills/KWH Unit Size Range Capital Cost 90% Plant Factor 800 KW 700 to 900 KW $526 21.74 3,000 KW 2500 to 3500 KW $437 17.70 10,000 KW Standard Unit $322 16.19 25,000 KW Standard Unit $217 12.47 50,000 KW Standard Unit $210 11.97 Assumptions: 1. Plant Factor = 90% 2. Gas Cost = $.535/million BTU a 7 | G.T. Project Type Turbine a Region: _ Anch. 800_KW Liponp thie oe PROJECT DESCRIPTION Identifying ; : Firm Capacity - . er a ee 4 Community: _Anch. © 50% KWH Annual 6,300,000 uscd os 7 ety 20) Vr. Operating Life » GAS-TURBINE Base Case: Yes X : - SIMPLE-CYCLE No 15,000 Heat Rate (BTU/KWH) CONSTRUCTION COST : Input . a : a $ Outlays Incurred By Year (1000 $) Generation Site purchase Fquivennt Labor (man years) Materials Transportation & Freight - Engineering (man wars Management (man years) ‘- Licensing Interest. During Construction Other - Overhead & Contingencies TOTAL ‘Transmission Site purchase Equipment Labor (man years). Materials Transportation Engineering (man years) Management (man years) io es ea eee Licensing Interest Other . * TOTAL Total Construction Cost: 4: : ~ = : Input : : = ant Factor 90% - Op saeatians and Naintenance 45 Fuel 50 Insurance 1 Total Operations Cost... : 5 74 ~ 96° << — CONSUMER COST . i Annual Fixed Costs (generation) . (1000 $) =: Installed Cost Firm Energy $/KW -. 526 "Interest and Amortization __0 : ieee. ce Depreciation ~ aoe “Annual Variable Costs liavevation _ Operations and Maintenance © Fuel @.90% «1 > ~ Varied Insurance at Taxes - "as -G.T. __ Project Type Turbine 3000 KW. Installed Capacity - Firm Capacity @ 50%. KWH Annual 23,670,000 20 Yr Operating Life PROJECT DESCRIPTION © 3000, KW * GAS-TURBINE SIMPLE-CYCLE : G.5.3 Region: _Anch. Identifying Community: _ Anch. Base Case: Yes XX No 15,000 Heat Rate (BTU/KWH) CONSTRUCTION COST Input / -$ Outlays Incurred By Year (1000 $) Generation ° | 1 TOTAL Site purchase 10 Equipment 10 10 Labor (man years) _ i10 |400 | Materials oe 135 1400 Transportation _& Freight 4 Engineering (man years 50 Management (man years) “- Licensing 2 Interest. During Construction Other - Overhead & Con’ Transmission Site purchase Equipment Labor (man years) Materials Transportation Engineering (ian years) ae Management (man years) Licensing Interest Other _- : TOTAL Total Construction Cost OPERATING cost. ($1000) als Plant Factor 10x, 5 Operations and Maintenance 98 a re Fuel 20 21 106° "190 Insurance 4 4 4 Total Rperetsces Gost 123 208 292 Annual Fixed Costs (generation) .(1000 $) 92 (generation) : ; a .07 Interest and Amortization -.°,005 Depreciation ‘ ‘ Annual Variable Costs ; Operations and Maintenance -, ; Fuel @ 90% i Sie fe Insurance Seg ta Ps * Taxes . CONSUMER COST . i Installed Cost Firm Energy $/KW 437 Bus Bar Cost @-90% Mills/KWH. ~~ 3770s ‘ee G.T. Project Type Turbine i Region: _Anch 10,000 KW Installed Capacity PROJECT DESCRIPTION Identifying : : Firm Capacity” - j “40,000 KH!” oo Community: _Anch. @ 90% KWH Annual 78,800,000 ees v2 20YR. Operating Life » GAS-TURBINE Base Case: Yes _ X a : SIMPLE-CYCLE Nos eae 15,000 Heat Rate (BTU/KWH) CONSTRUCTION COST. : Input . eS : ; - -$ Outlays Incurred By Year (1000 $) Generation . Site purchase Equipment Labor (man years) Materials Transportation _& Freight Engineering (man years 3) Management (man years) Xb KS Sub-Total Interest. During Construction. = - Overhead & Contingencies TOTAL Trarismission’ Site purchase fantoaent Labor (man years) Materials : Transportation Engineering (man years) Management (man years) Licensing Interest Other - TOTAL Total Construction Cost: be sige . 29. “+ ve saad, ARE GS So tere Ie OPERATING COST. ($1000) _Input> ; ee ee = mel Plant a _10% E 50% 90% Operations and Maintenance 317 —— 317 317 Fuel ee : 70 352° 633 Insurance . . . 10 10 10 Total Operations Cost.--, : - 397 : s 679 960 so CONSUMER COST : Annual Fixed Costs (generation) . (1000 $) Installed Cost Firm Energy $/K 322 Interest and Amortization 229 <= % S Depreciation’ -, - pons _ Bus Bar ot 090% Mi115/KWH.- 16 19 Annual Variable Costs leanavettail ea : lager BASS eR eae } perations and Maintenance. - Fuel @90% - career Insurance * Taxes 6.5.5 _G.T. Project Type Turbine i P Region: _ Anch. 25.000 KW Lines bein ears PROJECT DESCRIPTION Identifying - Firm Capacity” - y ee cee Community: Anch. @ 90% KWH Annual 197,000,000 25,000 KW 33 oi fee stl 20 Mis Operating Life * GAS-TURBINE Base Case: Yes X 15,000 Heat Rate (BTU/KWH) = CoHSTRUGTION Cost ae Input : - ; I $ Outlays Henne By Year (1000 $) Generation - i eel} oe “il eT 213 Site purchase Equipment Labor (man years) ie Transportation & Freight Engineering (man 7 oon Management (man years) - Axieonsxing Interest puring Construction —— - Overhead & Contingencies TOTAl Trarismission ; ——— Site purchase Equipment Labor (man years) Materials : Transportation Engineering (man years) Management (man years) Licensing Interest Other . TOTAL _ Total Construction Cost: : > Input Plant Wactin 50% “teeation and Maintenance | = aie 338 ; 338 Fuel , us - 883 / >a) -1,58n Insurance | Li : nee Total Operations Cost, 1,238 : 1,936 - nae “+. +. CONSUMER COST =F Annual Fixed Costs (genehation) . (1000 $) > - - Installed Cost Firm Energy $/KW 217 nterest an ortization 379 y 2 Depreciation- --- « ahee 47. %, ~ son Bus Bar Cost. Q. 90% Hi11s/KWH Annual Variable Costs (generation) este eee = pes ae Sys: Operations and M Maintenance i “338 Fuel @ 90% ova Insurance. *.~ ' Taxes oe . G.5.6 | | | ? Project Type Turbine , 7 Region: Anch -Eb-000-R Installed Capacity PROJECT DESCRIPTION lamest tying * Firm Capacity - ee Community: _ Anch © 90% KWH Annual 394,000, 000° 50,000 KW = 20 Yr. Operating Life . GAS-TURBINE Base Case: Yes X . ; SIMPLE-CYCLE ie: 15,000 Heat Rate (BTU/KWH) : SOBISETION COST Input as : . -$ Outlays Incurred By Year (1000 $) Generation ° 7 | 8 |- TOTAL Site purchase _ Equipaent Labor (man years) Materials Transportation _& Freight Engineering (man years Management (man years) ‘- AXAAL KAY : Sub-Total Interest. During Construction — - Overhead & Contingencies Ju Transmission Site purchase Equipment Labor (man years)_- Materials : Transportation Engineering (man years) Management (man years) Licensing __ Interest Other + TOTAL Total Construction Cost ey © OPERATING COST ($1000) ° Input. ts Ee ee sat . je : 10% 50% - 90%. perations and Maintenance 512 . : 512° : 512 Fuel : 352 - 1,758- . 3 162° Insurance . 32 32. = . 32 Total Operations Cost. .°. - 89 2,302 - 3,706 tole — CONSUMER COST . . 7 a Annual Fixed Costs ac (1000 $) © Installed Cost Firm Energy $/KW _ 210 Interest and Amortization 136 . : 2 Depreciation. — - = Bus Bar Cost .@ 90% MilTs/KWH | 11.97 Annual Variable Costs (generation) oo ean FO Sue EES ; Operations and Maintenance $12 _ Fuel @ 90% Begt 8,162 eee ay ere Insurance ots ei Beene Taxes BO} a . G.6.1 SUMMARY SHEET Case #3 Gas Turbine Regenerative Cycle Electricity ——> GAS TURBINE Bus Bar Cost $/KW Mills/KWH Unit Size Range Capital Cost 90% Plant Factor 10,000 KW Standard Unit $394 14.34 25,000 KW Standard Unit $268 10.43 50,000 KW Standard Unit $259 9.91 Assumptions: 1. Plant Factor = 90% 2. Gas Cost = $0.535/million BTU GT. Project Type Turbine “10,000 KW Installed Capacity PROJECT DESCRIPTION + Firm Capacity ee ee 78,800, 10,000 KW © 90% KWH Annual 78,800,000 GAS TURBINE Region: Identifying Community: 6.6.2 Anch. Anch. 20 Yr. Operating Life REGENERATIVE -CYCLE Base Case: Yes X 5 No 10,000 Heat Rate (BTU/KWH) CONSTRUCTION COST Input . $ Outlays Incurred By Year (1000 $) Generation 7 8 | TOTAL Site purchase : 10 Equipment Labor (man years) 10 Materials Transportation & Freight Engineering (man years). Management (man years) ‘ LECEUROKK ub- Interest During Construction ___ Other - Overhead & Contingencies TOTAL Transmission Site purchase Equipment Labor (man years) Materials Transportation Engineering (man years) Management (man years) Licensing : Interest Other TOTAL a Total Construction Cost : OPERATING cosT ($1000) Input : 3 Plant F. 10%. 50% 90% “Operations and Maintenance 317 317 317 Fuel 47 234 423 Insurance 12 12 . 12 Total Operations Cost . 376 563 Ja CONSUMER COST . Annual Fixed Costs (generation) . (1000 $) Interest and Amortization 275 Depreciation Bus Bar Cost @ 90% Mills/KWH Annual Variable Costs (generation) : Operations and Maintenance 317__ Fuel @ 90% 423 Insurance 5 12 Taxes 83 Installed Cost Firm Energy $/KW _ 394 14.34 7 G.6.3 G.T. Project Type Turbine : ‘ Region: __ Anch. 25,000 KW iad A Capacity PROJECT DESCRIPTION Identifying + Firm Capacity ar eee mn Community: — Anch. © 90% KWH Annual 197,000,000 ae ce 20 Yr. Operating Life REGENERATIVE-CYCLE Base Case: Mg x _ 10,000 Heat Rate (BTU/KWH) CONSTRUCTION COST Input : d $ Outlays Incurred By Year (1000 $) Site purchase Equipment Labor (man years) Materials Transportation & Freight Engineering (man years Management (man years) * iCeIK Sub- Interest During Construction Other - Overhead & Contin 5 TOTAL Generation a aa Tele | 3 | eee 8 -| TOTAL Transmission Site purchase Equipment Labor (man years) Materials Transportation Engineering (man years) Management (man years) Licensing Interest Other TOTAL Total Construction Cost OPERATING COST ($1000) Input : : Plant Factor _10% 50% 90%. Operations and Maintenance 338 338 338 Fuel eee : 589 1,054 Insurance 20 20 4 20 Total Operations Cost . 475 - 947 1,412 . CONSUMER COST Annual Fixed Costs (generation) . (1000 $) Installed Cost Firm Energy $/KW 268 Interest and Amortization 468 : Depreciation 34 Bus Bar Cost @ 90% Mills/KWH 10.43 Annual Variable Costs (generation : Operations and Maintenance 338 Fuel @ 90% 1,054 Insurance ; 20 Taxes 141 G.6.4 G.T. Project Type Turbine . i Region: _ Anch. 50,000 KW Installed Capacity PROJECT DESCRIPTION Identifying se - Firm Capacity patos panera Community: _ Anch. 90% KWH Annual 394,000,000 ae e Mi es sa _ GAS TURBINE - . 20 Yr. Operating Life REGENERATIVE-CYCLE Base Case: by x 10,000 Heat Rate (BTU/KWH) CONSTRUCTION COST Input : , . $ Outlays Incurred By Year (1000 $) Generation “4 . f 1 | 2 5 | 6 | 7 | 8 | TOTAL 3 4 Site purchase : ! OT -- : 0 Equipment | t DOE | 0 Labor (man years) : : | 168 | 5000) 5168 Materials | 170 | 5000} 5170 Transportation & Freight ! 70} 20 2705 Engineering (man years : | 500 82 582 Management (man years) 10 20) ao DPOSHeTKK . Sub-Total 938 fo z 11250 832 Interest During Construction } g00 — Other _- i . |_ 84 |_g00 VV 7 | 1054 higizl Transmission : Site purchase Equipment Labor (man years) Materials Transportation | Engineering (man years) c= a Management (man years) \ i Licensing . : Interest Other f TOTAL : : Total Construction Cost : OPERATING. COST. ($1000) Input re Plant Factor 10% 50% 90%. “Operations and Maintenance 512 512 512 Fuel 234 | 1,172 2,108 Insurance 39 390” ; : 39 Total Operations Cost . 785 1,723 2,659 CONSUMER: COST Annual Fixed Costs (generation) .(1000 $) Installed Cost Firm Energy $/KW 259 Interest and Amortization 908 . . Depreciation Bus Bar Cost @ 90% Mills/KWH 9.9] Annual Variable Costs (generation) : Operations and Maintenance 512 Fuel @ 90% ; 2,108 Insurance “ _39 Taxes . Do ere = Gi/ SUMMARY SHEET Case #4 Coal Fired Power Plant COAL FIRED POWER PLANT $/KW Unit Size Range Capital Cost 300 KW 250 to 350 KW $1,346 3,000 KW 2500 to 3500 KW $ 891 10,000 KW 8000 to 12,000 KW $ 836 22,000 KW Standard Unit $ 728 66,000 KW Standard Unit $ 509 200,000 KW Standard Unit $ 494 300,000 KW Standard Unit $ 480 Assumptions: i 2: Plant Factor = 90% Coal Cost = $12.50/ton = $0.71/million BTU Generator Electricity——>~ Bus Bar Cost Mills/KWH 90% Plant Factor 42.74 23.76 22.80 21.18 16,47 13.75 13.52 Sale Project Type Coal 300 Installed Capacity - Firm Capacity F 90% KWH Annual 2,340,000 “20 Yr. Operating Life 12,000_ Heat Rate (BTU/KWH) Input PROJECT DESCRIPTION COAL STEAM TURBINE Ee / Region: _ Anch. Identifying Community: 300 KW Anch, Yes x No Base Case: CONSTRUCTION COST $ Outlays Incurred by Year (1000 $) Generation Site purchase Equipment | Labor (man years) _ Materials Transportation & Freight Engineering (man years) Management (man years) Licensing Interest D ‘uring Construction Other - Overhead & Cont. tenes er. nt ne Transmission Site purchase Equipment Labor (man years) Materials sty qj} tt Transportation Engineering (man years) Management (man years) Licensing Interest Other TOTAL Total Construction Cost Pte OPERATING COST ($1000) Input Plant Factor]| 10% 50% 90% —pperatTons and Maintenance 41 41 41 Fuel ce 11° 20 Insurance 1 1 : : : 1 Total Operations Cost 44 53 62 : CONSUMER COST . Annual Fixed Costs (generation) .(1000 $) Installed Cost Firm Energy $/KW _ 1346 Interest and Amortization Bh Depreciation 42.74 ‘Annual Variable Costs (generation) Operations and Maintenance i Fuel @ 90% : Insurance : Taxes Bus Bar Cost @ 90% Mills/KWH eae 8 G.7.3 Sule Project Type Coal j Region: __ Anch. 3000 KW_ Installed Capacity PROJECT DESCRIPTION Identifying + Firm Capacity Community: _ Anch. 190% KWH Annual 23,400,000 3000 .KW rare 20° %r. Operating Life COAL S. T. Base Case: Yes _X : i No 12,000 Heat Rate (BTU/KWH) CONSTRUCTION COST Input $ Outlays Incurred By Year (1000 $) Generation 1 Site purchase 0 Equipment 20 Labor (man ycars) 1085, Materials 1090 Transportation & Freight 58 Engineering (man years). 124 Management (inan years) ‘. 10 Licensing : ee Interest During Construction 85 Other - Overhead & Conti i 188 ; TOTA 2674 Transmission Site purchase Equipment Labor (man years) Materials Transportation Engineering (man years) Management (man years) Licensing Interest Other 7 TOTAL Total Construction Cost OPERATING COST ($1000) Input : mos Plant Factor | 10% SOX perations and Maintenance 91 91 Fuel 22 110 Insurance 8 8 Total Operations Cost 121 219 i 299 Annual Fixed Costs (generation) .(1000 $) Interest and Amortization Depreciation ‘Annual Variable Costs (generation 91 ____200 8 incon Operations and Maintenance Fuel @ 90% Insurance Taxes 187 14 CONSUMER COST Installed Cost Firm Energy $/KW 891 Bus Bar Cost @ 90% Mills/KWH 23.76 Scie Project Type Coal 10,000 KW Installed Capacity : Firm Capacity 190% «KWH Annual 78,800,000 20 vr. Yr Operating Life 12,000 Heat Rate (BTU/KWH) 10,000 KW COAL STEAM TU Input PROJECT DESCRIPTION Region: RBINE CONSTRUCTION COST Base Case: 6.7.4 Anch. Identifying Community: _ Anch. Yes No 3 Outlays Incurred By Year (1000 $) Generation Site purchase coutbeaat Labor (man years) _ Materials Transportation & Freight t Engineering (man years Management (man years) ° JODOXIODAK . Sub- A ee Other - Overhead & Conti 6 7 -- 30 305 |3000 305 |3000 : 25 | 150 : as 200{ 76 10 | _-10 1800. : 70 | 500_ am TOTAL Transmission 1012 7256 | Site purchase Equipment Labor (man years) Materials Transportation Engineering (man years) Management (man years) Licensing Interest Other a TOTAL Total Construction Cost L Te a preheat OPERATING COST ($1000) Input . Plant Factor | _10% 50% 90% “Gherattons and Maintenance 297 297 297 Fuel 75 373) 671 Insurance 25 25 25 Total Operations Cost 397 695 993 CONSUMER COST Annual Fixed Costs (generation) . (1000 $) Interest and Amortization 586 Depreciation : Pp Annual Variable Costs (generation) ~~~ Operations and Maintenance 28 7 - Fuel @ 90% 671 Insurance 25 Taxes Seg Bus Bar Cost @ 90% Mills/KWH 22.80 Installed Cost Firm Energy $/KW _ 827 Uelev hls Project Type Coal : . Region: _ Anch. 22,000 KW eer Capacity PROJECT DESCRIPTION Ident ifyTng + Firm Capacity Se ae ae Communit, Anch. OF KWH Annual 173,500,000 22,000 KH YF toch, 40 Yr. Operating Life COAL STEAM TURBINE Base Case: Yes _X : 0S No 11,850 Heat Rate (BTU/KWH) CONSTRUCTION COST Input ; $ Outlays Incurred By Year (1000 $) Generation 4 5 6 7 8 | TOTAL Site purchase 300 | Equipment 34) 100 Labor (man years) : 4250 | Materials , | ~ | 8093 | Transportation_& Freight : i oon Engineering (man years) =f 1 1720} Management (man years) _ T00 KXKEXEN IK Sub-Total 290) 531 | Laer Interest During Construction _ E 677|_203 | es yqai2e) Other - Overhead & Conti 247 |_720| 215 im 1182 TOTA’ 3379 | 9863] 2949 91 Site purchase | Equipment * | I ; Labor (man years) 7 ! Materials i Transportation } Engineering (man years) = | canal Management (man years) : as Licensing t Interest t Other | | : TOTAL | fat Total Construction Cost | | : OPERATING COST ($1000) Input : ! Plant Factor 10% 50% 90%_ | “Wperations and Maintenance 629 629 629 Fuel 162 © 811 1,460 Insurance 48 48 . : 48 Total Operations Cost . 839 1,488 2,137 : CONSUMER COST ! Annual Fixed Costs (generation) . (1000 $) Installed Cost Firm Energy $/KW 736: Interest and Amortization 11g} Depreciation Bus Bar Cost @ 90% Mills/KWH 21.18 Annual Variable Costs (generation) : perations and Maintenance ah Fuel @ 90% 1460 ; Insurance . 48 oo Seal Taxes _ 336 G.7.6 Engineering (man years) Sialic Project Type Coal ‘ Region: _ Anch. 66,000 KW Installed Capacity PROJECT DESCRIPTION Identifying a + Firm Capacity Miss Community: _ Anch. © 90% KWH Annual 520,000,000 i ra KW The 40 Yr. Operating Life COAL STEAM TURBINE Base Case: Yes X : ‘ No 11,500 Heat Rate (BTU/KWH) CONSTRUCTION COST Input $ Outlays Incurred By Year (1000 $) Generation 1 3 Lf 5 6 i Site purchase 421] -- |-- |-- -- ; Equipment 200 | = 200] = 200} 200] 200 Labor (man years) 1000 | 2000} 2000} 1500} 1500 Materials 2000 | 4000] 4000] 3500] 3500 Transportation & Freight == [174 174] 7477 Engineering (man years) 1000 | 198} 100] 100] 100 Management (man years) ° -- 50} 50} 50] 50 KIRK : Sub- 4671 | 66221 A524 Interest During Construction 370 |_530} 522) 442] 442 | Other - Overhead & Conti ic 393 | 563) 555! 470! 4 a TOTA 5384 | 7715| 7601 226) 8836 Transmission 4 , Site purchase Equipment j Labor (man years) : Materials Transportation Pee Management (man years) Licensing Interest | Other TOTAL Total Construction Cost | : , : OPERATING COST ($1000) Input ELV : Plant Factor |] 10% 50% 90% Operations and Maintenance 810 810 810 Fuel 472 2,360 4,246 Insurance 100 100 ~~ 100 Total Operations Cost 1,382 3,270 5,156 Annual Fixed Costs (generation) . (1000 $) 2350 Annual Variable Costs (generation) Interest and Amortization Depreciation Operations and Maintenance Fuel @ 90% Insurance Taxes CONSUMER COST . Installed Cost Firm Energy $/KW _ 509 Bus Bar Cost @ 90% Mills/KWH 16.11 810 4246 100 705 7%, Project Type Coal 200 MW. Installed Capacity * Firm Capacity © 90% KWH Annual 40 Yr. Operating Life 9,500 Heat Rate (BTU/KWH) Input PROJECT DESCRIPTION Region: 200 MW COAL FIRED STEAM UNIT CONSTRUCTION COST Base Case: GoPe7 Anch. Identifying Community: Yes X No -$ Outlays Incurred By Year (1000 $) Anch. Generation Site purchase 2 | 3 4 5 6 7 iu [1000 | -- | i TOTAL TOSS Equipment Labor (man years) _ I-500_{-1000} 1000! 1000! ~500' 4003 1000 4000| 2500} 2500 13003 Materials 9500 Transportation & Freight {2500 18000118000: 0000 Engineering (man years) on Cr a ee 1500 500] Management (man years) ° 90 750} 500) -- 250 o}_250] 250} 250 Interest Quring Constructii Keon Sub-Totay abe 24340 O | 1847 TOTA Other - Overhead 4_Cont ingencies 50] 1 1927| 11481 10601 | 3614] 2151] 1987 2 Al 3614 8401296311763816297 Transmission Site purchase 6765 i Spears Py ce iJ Equipment Labor (man years) Materials Transportation Engineering (man years) Management (man years) Pate ee Licensing Pe} Interest Other : TOTAL Total Construction Cost Input 4 Plant F Operations and Maintenance Fuel Insurance 4 PES OPERATING COST ($1000) ait 50% sf 1,279 5,909 296 10% 1,279 1,180 296 1,279 10,637 .. 3 Total Operations Cost 2,755 7,484 a CONSUMER COST Annual Fixed Costs (generation) . (1000 $) Interest and Amortization 6911 Depreciation 494 Bus Bar Cost @ 90% Mills/KWH ‘Annual Variable Costs (generation perations and Maintenance Fuel @ 90% Insurance Taxes 1279 10637 —36- 2073 12,212 Installed Cost Firm Energy $/KW 494 13.575 G.7.8 ST. Project Type . Region: __Anch. 300 MW Installed Capacity PROJECT DESCRIPTION Identifying + Firm Capacity oe | aa Community: _ Anch. 5 90% MIH Annual 2,365,200 300 MW Coal Fired 40 Yr. Operating Life * STEAM UNIT Base Case: Yes _ X = ae ; No 9,500 Heat Rate (BTU/KWH) CONSTRUCTION COST Input $ Outlays Incurred By Year (1000 $) Generation 1 TOTAL Site purchase lee ik ete 1000 Equipment 725 |1450/1450]1450| 725 Labor (man years) 1000 | 3450/4900] 3000/3000 Materials 2625 P70002700015125 h 4400 Transportation _& Freight 432] 130 |_ Engineering (man years) 7 | 35 Management (man years) ° 362 | 363} 363 | 36? AXA KA Sub-Total 7525 [83479B4933P079319217! Interest During Construction 5116631 15° ___Other_- Overhead & Contingen 659| 3368/ 311 TOTA Transmission Site purchase Equipment Labor (man years) Materials Transportation Engineering (man years) Management (man years) Licensing Interest Other TOTAL Total Construction Cost Input Fuel OPERATING COST ($1000) : Plant Factor 10% 50% 30% Operations and Maintenance 1,791 15791) - 1,791 Fuel 1,773 ~ 8,863 15,953 Insurance 428 428 428 2,995 2,995 2,995 Total Operations Cost 6,462 11,429 21,167 MWH Generated 262 ,800 1,314,000 2,365,200 Annual Fixed Costs (generation) . (1000 $) Interest and Amortization 10,080 ; Depreciation 720 Bus Bar Cost @ 90% Mills/KWH Annual Variable Costs (generation : Operations and Maintenance 1,791 Fuel @ 90% 15,953 Insurance 428 Taxes 2.995 CONSUMER COST Installed Cost Firm Energy $/KW _480 13.52 G. 8. SUMMARY SHEET Case #5 Gas Fired Steam Turbine Gas Fuel STEAM TURBINE Unit Size Range etal Cost 300 KW 250 to 350 KW $1,130 3,000 KW 2500 to 3500 KW $ 749 10,000 KW 8000 to 12,000 KW $ 703 22,000 KW Standard Unit $ 618 66,000 KW Standard Unit $ 427 200,000 KW Standard Unit $ 415 300,000 KW Standard Unit $ 403 Assumptions: 1. Plant Factor = 90% 2. Gas Cost = $0.535/million BTU Generato 39.32 20.26 18.43 17.54 13.10 11.50 - 11.29 G.85) Electricity ——— Bus Bar Cost Mills/KWH 90% Plant Factor + Project Type Gas 300 KW Installed Capacity * Firm Capacity KWH Annual 2,340,000 @ 90% Operating Life 20 Yr. _ 12,000 Heat Rate (BTU/KWH) Input . PROJECT DESCRIPTION Short Form 300 KW _ GAS FIRED STEAM TURBINE - CONSTRUCTION COST Ratio. of Cost To Base Case Cost G.8.2 Region: Anch. * Identifying Community: Anch. Refer To Base Case # 300 Coal S.T. Comments on Scheduling, etc. Construction Site purchase Equipment Labor (man years) Materials Transportation =. ae Engineering Management Licensing Interest Other Operation Operations and Maintenance Fuel Insurance TOTAL ~" °0,84°- $339,000 OPERATING COST ‘Anmwal Fixed cect Slain (1000 $) Interest and Amortization J 24 ; Depreciation * Annual Variable Costs (generation): - nek “Operations and Maintenance Fuel. Insurance Taxes Details: Special Features: Bus Bar Cost Mitia/Km Installed Cost Firm Energy 71 -1130 “39.32 @ 903: $.%. Project Type Gas 3000 KW_ Installed Capacity * Firm Capacity KWH Annual 23,400,000 Operating Life @ 902 20 ae0uyy. 12,000 Heat Rate (BTU/KWH ) Input PROJECT DESCRIPTION Short Form 3000 KW GAS FIRED. STEAM TURBINE - CONSTRUCTION COST Ratio. of Cost To Base Case Cost G.8.3 Region: _Anch. * Identifying Community: Anch Refer To Base Case # 3000 Coal S.T. Comments on Scheduling, etc. Construction Site purchase , Equipment Labor (man years) Materials Transportation Engineering Management Licensing Interest . Other : TOTAL Operation Operations and Maintenance Fuel Insurance 0.84 ' $2,246,000 Annual Fixed Cost (generation) Interest and Amortization Depreciation dias anal Variable ‘Costs generation): Operations and Maintenance Fuel — Tes Insurance +-- . Taxes a1 Details: _ Special Features: 150 " OPERATING cost : (1000 $) 157° “91. 7 58 ae Bar Cost” ants KMH : Installed Cost’ fee $/KW “749° @ 90% S.T. ¢.3.4 | Project Type Gas Region: Anch “10,000 Ki 000 KW Installed Capacity PROJECT DESCRIPTION * Firm Capacity ee * Identifying “©90%__ KWH Annual 78,800,000 _ Short Form : 5 Community: __Anch. “20 Yr. Operating Life 7 . 10,000 kW 3 Refer To Base Case # 10,000 12,000 Heat Rate (BTU/KWH) GAS FIRED STEAM TURBINE - Coal Sut. : . CONSTRUCTION COST . . Ratio. of Cost : Input — To Base Case Cost Comments on Scheduling, etc. Construction Operation Site purchase , Equipment : Labor (mar years) | Materials = Transportation (ee Engineering : Management Licensing Interest Other TOTAL 0,84 "$6,945,000 Operations a Maintenance Fuel Insurance OPERATING COST Annual Fixed Cost (generation) (1000 $) : Installed Cost . Depreciation .: ay oes, 35 “Annual Variable Costs (generation)... mos . . Firm Energy $/KW -- 703 Interest and Amortization 486 Operations and Naintenance 250. Fuel . 506. - Insurance ~*- . 21 : Taxes . 146 Details: Special Features: oer 6.8.5 | Spar Project Type Gas : Region: _Anch. 72,000 KW Installed Capacity PROJECT DESCRIPTION . © 90% Great is, 500,000 ; meee nnua i Communit, R Anch. 40 Yr. Operating Life f : Short Form Af o : 22,000 KW ; i Refer To Base Case # 22,000 11,850 Heat Rate (BTU/KWH) GAS FIRED STEAM TURBINE : Coal S.T. 3 - CONSTRUCTION COST : i ‘| Ratio. of Cost ~ . Input 7 ' y To Base Case Cost Comments on Scheduling, etc. Construction Site purchase , Equipment — Labor (man years) Materials * Transportation Engineering Management Licensing: a Interest Aa Bigeaine ttt cutie Bais Other. - TOTAL ~eelp BA ene! $13,600,000 Operation ; : Operations and Maintenance a i = Fut : oe Mies Insurance carereate ee sem ie OPERATING COST Annual Fixed Cost (generation) (1000 $) ane Installed Cost’ ee = Firm Energy $/KW --- 618 * Interest and Amortization 952 sate ro ; Te Te eT Depreciation ; eee 68 Sent ae ee Hite {See attest Pi Pees mite die ee Bus Bar Cost Mills/KWH -_ 17.54 - "Annual Variable Costs (generation): Operations and deiinencs 529 : Fuel . : 1,099 . Insurance - - i 41 Taxes 354 e. Details: Special Features: i Pores G.8.6 Seis Project Type Gas ‘ Region: Anch. 766,000 KW Installed Capacity PROJECT DESCRIPTION ’ ‘ Firm Capacity Poe ee { * Identifying @ 00 ne 0,000,000 Short Form Bye Community: Anch. =e P 66,000 KW Refer To Base Case #66,00 11,500. Heat’ Rate (BTU/KWH) GAS FIRED STEAM TURBINE ; Coal S. ic — i - CONSTRUCTION COST ; ; Ratio. of Cost . ales - Input ; i: To Base Case Cost .. Comments on Scheduling, etc. Construction Site purchase , Equipment . Labor (man years) Materials : 5 ae Transportation (3 ieee Engineering le eet Management Licensing Interest Other TOTAL’ $28,200,000 6.84 Operation : Operations and Maintenance Fuel Insurance | OPERATING a Late | a a, ‘Annual Fixed Cost (generation) (1000 $) ee " Installed Cost’ ae eas = "oc iis., Firm Energy $/KW _- 427) Interest and Amortization 1,974" a Depreciation - : a ie ~ Annual Variable Costs (generation): 680 _ |” Bus Bar Cost. Mills/KWH 13.10 “Operations and tiinaihencie Fuel . Insurance Taxes Details: Ip Spectal Features: als Project Type 200 MW Installed Capacity PROJECT DESCRIPTION - Firm Capacity ee ee 2 99x MWH Annual 4,576,800 Short Form 20 Yr. Operating Life ’ Se eee RE St Peraving ife 200 MW * 9,500 Heat Rate (BTU/KWH) _ GAS FIRED STEAM TURBINE - CONSTRUCTION COST P ‘ . . Ratio. of Cost Input re > ee To Base Case Cost _ G.8.7 Region: Anch. * Identifying Community: __Anch. Refer To Base Case # 200 MW Coal S.T. Comments on Schedul ing, etc. Construction Site purchase , Equipment Bog (man years) | Materials , : Transportation i 1” Engineering an Management Licensing Interest Other Operation Operations and Maintenance Fuel Insurance TOTAL 0.84 $82,936,000” ” OPERATING — Annual Fixed Cost fies (1000 o Interest and Amortization 6,635 pga Depreciation’ Peas AISI ee odes Annual Variable “costs (Generation). "Operations and Metiteanane . 1] “4 Fuel - e014 Insurance . 249 Taxes 1,742 “a ' m* a Details: Special Features: . Installed Cost" Firm a ies 415° - ; Buis Bar’ ‘Cost “HiT ‘ se cle Project Type 300 MW Installed Capacity * Firm Capacity CY MWH Annual 2,365,200 “20 Yr.‘ Operating Life Short Form 300 MW GAS FIRED STEAM TURBINE - CONSTRUCTION COST Ratio. of Cost To Base Case Cost 9,500 _ Heat Rate (BTU/KWH) Input | Construction . Site purchase , Equipment Labor (man years) Materials eae aaa Transportation ee Engineering : Management Licensing Interest Other ~~ _ TOTAL Operation Operations and Maintenance Fuel 5 ‘Insurance PROJECT DESCRIPTION G88 Region: Anch. ‘ Identifying Conmunityt ANGDRS o Refer To Base Case # 300 Iw Coal S.T. Comments on Scheduling, etc. "$120,959,000° ; OPERATING COST Annual Fixed Cost (generation) (1000 $) 9,677" Interest and Amortization Depreciation , = * Annual Variable Costs (generation): apg! ce i . Operktions and Maintenance 1, 504 . Fuel . . ; 12,021 : Insurance 363 Taxes 2,540 . ro i me Details: Special Features: : bus Bar Cost. ner Installed Cost ; : Firm-Energy $/KW .- . 403 > 11.29 G97 G. 9. SUMMARY SHEET Case #6 Oil Fired Steam Turbine Electricity ——> 0i1 Fuel OIL FIRED STEAM TURBINE Bus Bar Cost $/KW Mil1s/KWH Unit. Size Range Capital Cost 90% Plant Factor 300 KW 250 to 350 KW $1,130 79.91 3,000 KW 2500 to 3500 KW $ 749 61.03 10,000 KW 8000 to 12,000 KW $ 703 59.16 22,000 KW Standard Unit $ 618 57.78 66,000 KW Standard Unit $ 427 52.14 200,000 KW Standard Unit $ 414 43.75 300,000 KW Standard Unit $ 403 43.55 Assumptions: 1. Plant Factor = 90% 2. Oi] Cost = $.55/gal. = $3.93/million BTU Project Type Oi] Soa Installed Capacity * Firm Capacity © 90% KWH Annual 2,340,000 20 Yr. Operating Life 12,000 Heat Rate (BTU/KWH) Input | PROJECT DESCRIPTION G.9.2 Region: _Anch. * Identifying Short Form Community: Anch. 300 KW OIL FIRED STEAM TURBINE Refer To Base Case # 300 ‘ Coal S.T. ". CONSTRUCTION COST. Ratio. of Cost To Base Case Cost Comments on Scheduling, etc. Construction © Site purchase , Equipm aaa tahoe (man years) Materials Engineering Management Losdesihe Interest Others: - TOTAL. Operation Operations and Maintenance Fuel ‘Insurance Transportation — Mee aes + 0,84 339,000 ‘ Annual Fixed Cost t (generation) (000 Dm Interest and Amor t zatfon: ; _ Depreciation pees 3H a Insurance . Taxes "Details: Special Features ~ Annual Variable Costs 5 (generation) " OPERATING oost: | pattie ep "Installed Cost’ pes / Firm Energy’ aie. --1130 ‘Bus sir’ Cost ‘itis! 79.91. G.9.3 i$. Project Type Oi] Re ion: Anch. fT KW ee ch gehed PROJECT DESCRIPTION ~ . * Firm Capacity ee : “ Identifying 790% KWH Annual 23,400,000 ; ; Co : _Anch. 20 Yr. Operating Life oa : : abit - 12,000 Heat Rate (BTU/KW) _ OIL FIRED STEAM TURBINE Refer To eos - CONSTRUCTION COST _ : Ratio. of Cost . Be ae Input ais ' pepe | To Base Case Cost Comments on Scheduling, etc. Construction —°_. ES ie Site purchase , Equipment tabor (man years) Materials 2 Transportation ms Engineering : Management Licensing Interest od Other =. °. > "> TOTAL : "$2,246,000 Operation © Operations and Maintenance Fuel Insurance eee "OPERATING COST “sini Fixed Cost (generat ion) er 2 ~ Installed Cost” is : Firm — vo Setrag: Interest and Amortization 157 Fs oo . qbeprectapion a a) ms F * kinual Variable ‘Costs senration Bus Bar cost Mills, Kult 61.03 - 90% ‘Operations and Naintenance 7:°9)-" citer "Fuel . aa “L104 Insurance . Taxes in, poneas 2 peee Sey he oat eo, pigs ames : Detatts: : _S. T. Project Type Oi] “10 0,000 KI kW Installed Capacity PROJECT DESCRIPTION * Firm Capacity = op Se Region: Anch. “ Identifying @ 90% KWH Annual 78,800,000 i Communit $< Anch, 20 Yr. Operating Life er i " . : Refer To Base Case # 10,000 _ 12,000 Heat’ Rate (BTU/KWH) OIL FIRED STEAM TURBINE Coal S. T: ai eae |S . - CONSTRUCTION COST 2. : Ratio. of Cost : Input To Base Case Cost Comments on Scheduling, etc. Construction . ; Site purchase | : . caripeant Labor (man years) Materials ; woes Transportation : male Engineering : : Management “ Licensing : = 4 Interest . . a 2 ea hee ‘ : Other - “ TOTAL 0.84 “$6,945,000 / Operation — : Operations and tia intenance 7 : : Fuel . : . Fe Insurance * OPERATI NG COST. ‘Annual Fixed cost E (generation) (1000 $) “486 Prasbia Interest and Amortization i _ Depreciation : . Annual Variable Costs (seneration). ; * Qperations and Maintenance Fuel . Insurance .. Taxes , Vas 7 Details: . ; Bus ‘Bar ‘cost Mills Ka Installed Cost ie ht Fira Energy’ sii - 695-. 59.06 =. 6.9.5 | §.T. Project Type i] : Region: Anch. 22.000 _KI 000 KW Installed Capacity PROJECT DESCRIPTION Firm Capacity Fe ee ree ee * Identifying @ 90% KWH Annual 173,500,000 Short Form . “a Communi ty: Anch. ; . — 40 Yr. Operating Life ih ; 0 KW : Refer To Base C. 22,000 11,850 Heat Rate (BTU/KWH) OIL FIRED: STEAM TURBINE : gfe? . . + CONSTRUCTION COST : Ratio. of Cost ' Input Z —. To Base Case Cost ~ Comments on Scheduling, etc. Construction Site purchase , Equipment . Labor (man years) ° Materials . = Transportation =~ - El Engineering : : Management . nk ge htee? - ; ; Licensing . fn eae Jos Interest Se ee ed oo Other. _ TOTAL... . 0.84 > * $13,600,000 Operation [ae = a Operations and Maintenance: Fuel Insurance peepee "OPERATING COST. a Annual Fixed Cost (generation) (z000 $) i Installed Cost’ as r ; : i Firm eneray: ae -.. 618 Interest and Amortization 952 oe Ages - : . ie ae _Depreci tion... = bs no ee Di : if os Eee ene ae Ode dees nis Bar Cost. MiT1 s/t 57.78 © 7 *- @ 90% ey Annual Variable Costs (seneratton)-; “Operations and Matcitenande est 529 7 Fuel . oy 8,078 Insurance 5 *. See Taxes . 1354 ee Mee . Dae Pte ede . Details: oe Special Featu G.9.6 S.T. Project Type 0i1 : Region: Anch. 66,000 KW Installed Peete PROJECT DESCRIPTION roa ‘era oo eee * Identifying WH Annual 520,000,000 f ul Communit, : Anch, 40 Yr. Operating Life ; ; an : e ‘ UNE Refer To Base Case # 66,000 11,500 Heat Rate (BTU/KWH) ! OrhiS. Coal S.T. aE . CONSTRUCTION COST ; Ratio. of Cost . Input ; cn To Base Case Cost Comments on Scheduling, etc. Construction Site purchase , Equipment Labor (man years) i Materials : ee Transportation " rie Engineering i Management Licensing Interest marae . Lee Other 2 _ TOTAL 0.84 ~ $28,200,000 Operation Operations and Maintenance Fuel , k ‘Insurance ” OPERATING cost. Annual Fixed Cost 6 faeranpi ton) (1000 $) lade Installed Cost ~- © -° 7: : ae ; Sere en - 427 Interest and Amortization. “1974 a Depreciation : ee = aa: Soe ae : FS a pateds eae Bus Bar Cost. “MiT1S/ KM 62, 14 “Anna Variable ‘Costs (generation): @ 90% - “Operations and Naintenance e 680" "Fuel. eee] 2a noORentr Insurance = : “85 Taxes Sree. 733 oer ati es Details: AG = a Special Features: G.9.7 ST. Project Type Region: Anch. “200 MM Mi Installed Capacity PROJECT DESCRIPTION @ 50%. nl thapa'peae, Teoeminltyt nnual 1,576,800 Comm ty: _ Anch “2 Yr. Operating Life a td 9,500. Heat Rate (BTU/KWH) OIL FIRED STEAM TURBINE Refer To Peat cet # 200 NW . CONSTRUCTION COST. : Ratio. of Cost : _—2 Input To Base Case Cost Comments on Scheduling, etc. Construction - Site purchase , Equipment ; Labor {man years) ° : Materials = ead Transportation | ie Engineering os : Management : Licensing - | Interest i os i ; Other ns bets Slee = : .. Total 0.84 $82,936,000 : Operation , Operations and Maintenance = Fuel : Insurance "OPERATING es ‘Annual Fixed Cost foenernt ton) (1000 §) Interest and Amortization 6.638 PT oe Be Depreciation : WSs * Annual Variable Costs (genera tion} 1 074 Operations and Maintenance : Fuel . » 58,870 Insurance 249 Taxes 1,742 .. re Details: Special Features:. Installed Cost: : Firm aie bd : ae Bus Bar Cost | wniafeM 43.75 ey ae G.9.8 Project Type Re jon: _Anch. 0-W— Installed Capacity PROJECT DESCRIPTION : - Firm Capacity <= eae * Identifying @ 90% MWH Annual 2,365,200 Short Form Communi ty: Anch. 20 Yr. Operating Life oa: E . Refer To Base Cas 300 MW 9,500 Heat’ Rate (BTU/KW) OIL. FIRED STEAM TURBINE ca tase. # Soe 5 - CONSTRUCTION COST ; Ratio. of Cost Input To Base Case Cost Comments on Scheduling, etc. Construction . Li . Site purchase , Equipment . Labor (man years) . Materials . ie Transportation tase Engineering z° Management. Licensing = , Interest 7 : teal : ‘ . Other: ... TOTAL 0,84 | $120;959,000 — Operation , — : Operations and Maintenance Fuel . Insurance . " OPERATING cosT Annual Fixed Cost (generation) (1000 $) Annual Variable Costs laanamationt Interest and. Amortization | Depreciation eae Sat \ Operations and Maintenance Fuel 1,508 7 Insurance Taxes 2,540 e's . ra ~ Details: Special Features: cien eee pgs 2 er Installed Cost’ Firm Energy’ $/KW _- 403 j11s/KWH 43.55 G.10.1 G. 10. SUMMARY SHEET Case #7 Geothermal Steam Turbine Separator Electricity} GEOTHERMAL STEAM TURBINE Bus Bar Cost $/KW Mil1s/KWH Unit Cost Range Capital Cost 90% Plant Factor 10,000 KW Standard Unit $924 16.98 25,000 KW Standard Unit $735 12.45 Assumptions: 1. Plant Factor = 90% 2. Fuel Cost = -0- G.10.2 . i Project Type Geothermal . . Region: Anch. 10,000 KW eee eeaty PROJECT DESCRIPTION Identifying - Firm Capacity RRA GAL UD Community: _ Anch. © 90% KWH Annual 78,800,000 Saat a ar 20 Yr. Operating Life TEAM-GEO-TURBINE Base Case: Yes _ X Sar aaa a CONSTRUCTION COST Input _ : . -$ Outlays Incurred By Year (1000 $) Generation Site purchase & Well Equipment Labor (man years) Materials Transportation & Freight Engineering (man years Management (man years) ° kimenemnga Interest During Construction Other - Overhead & Conti TOTAl Transmission Site purchase Equipment Labor (man years) Materials Transportation Engineering (man years) Management (man years) Licensing Interest Other TOTAL Total Construction Cost OPERATING COST ($1000) Input : Plant Factor 10% 50% 90% Operations and Maintenance 423 423 Fuel -0- -0- Insurance 28 28 Total Operations Cost 451 451 : CONSUMER COST Annual Fixed Costs (generation) . (1000 $) Installed Cost Firm Energy $/KW _924 Interest and Amortization 647 . Depreciation 46 Bus Bar Cost @ 90% Mills/KWH 16.98 “Annual Variable Costs (generation) Operations and Maintenance 423 Fuel @ 90% -0- : Insurance ' 28 if Taxes 194 G.10.3 | |. | _S. 1. Project Type Geothermal i : Region: __Anch. “25,000 Kh KW Installed Capacity PROJECT DESCRIPTION Tdentieving Firm Capacity en ee Ts Tt Community: _ Anch. © 90% _~_ KWH Annual 197,000,000 25,000 KW : at ae. Yr eimai’ Life GEO - STEAM - TURBINE Base Case: Yes X No CONSTRUCTION COST Input i . -$ Outlays Incurred By Year (1000 $) Generation mi ani 1]-2]3 fi 5 16 ]|7 | 8 | tote Site purchase_& Wells 6020 | -- | -- Equipment 3 Labor (man years : 1000 {1500 [i500 Materials 965 {1500 1500 |" Transportation _& Freight 98 | 100 | 100 | Engineering (man years 1000 [500 | 60 Management (man years)_ 331-33") 34 KARIN Sub-Total 9149 8666 B228 1 other Oye D t uring Construction 650 | 285 | 200 | Other - Overhead & Con em 800 | 206 | 200 a TOTA 10599 4157 628 Transmission : Site purchase Equipment Labor (man years) Materials Transportation Engineering (man years) Management (man years) a Licensing ; 7 = Interest Other TOTAL : Total Construction Cost : OPERATING COST ($1000) Input Plant F. 10% 50% —_—90%. —Dperattons and Maintenance 632 632 632 Fuel -0- ~ -0- -0- Insurance 55 55 | = : 55) Total Operations Cost . 687 687 687 : CONSUMER COST Annual Fixed Costs (generation) . (1000 $) Installed Cost Firm Energy $/KW _735 Interest and Amortization 1.287 : Depreciation Bus Bar Cost @ 90% Mills/KWH 12,45 “Annual Vari Variable Costs: Costs (generation) Operations and Maintenance Fuel @ 90% ae Insurance . 55 Taxes 386 Gallet Gin hl. SUMMARY SHEET Case #8 Geothermal Binary Hot Water Power Plant Heat Exchanger GEOTHERMAL BINARY HOT WATER POWER PLANT Electricity-————— Bus Bar Cost $/KW Mills/KWH Unit Cost Range Capital Cost 90% Plant Factor 10,000 KW Standard Unit $1,599 25.38 25,000 KW Standard Unit $1,272 . 19.19 \ Assumptions: 1. Plant Factor = 90% 1. Fuel Cost = -0- GoTige 7 _Binary HW Project Type Geothermal “Region: _Anch. 10,000 KW Installed Capacity PROJECT DESCRIPTION Firm Capacity - * Identifying @ 90% KWH Annual’ 78,800,000 Short Form Community: Anch. 20 Yr. Operating Life 10,000 Ky . ° ’ 10, | -BINARY GEOTHERMAL Refer To ae icra 5 + CONSTRUCTION COST | : Ratio.of Cost ~ : || ls Input To Base Case Cost Comments on Scheduling, etc. Construction - : Site purchase , Fautoment ; : Labor (man years) | ies ; Materials “Te is ; eal - i Transportation : let é ee (dee, a Engineering Rott tap sl fetes Management . ae Licensing Firat . : Interest Do Other ee 24 E ips — ; - TOTAL 1.73 $15,992,000 Operation alka Operations and Maintenance Fuel Insurance — Fixed Cost lasuarat ian} (1.000 a: “Annual Variable Costs (generation Interest and Amortization _ Depreciation . > . : ; Operations’ and Maintenance Fuel Insurance . Taxes TA est, hea ea 1 Details: Fuel Cost--0- - ee "OPERATING cost. Special Features: High Plant cost due to immature technology’ -- ‘bus Bar Cost” * Mi11S/ KH Installed Cost’ ae o : . Firm Energy’ bier’ =" 1599 Gales: Binary HW Project Type Geothermal Region: _Anch. 25,000 Ky Installed Capacity PROJECT DESCRIPTION. : ane ; * Firm Capacity aerator * Identifying KWH Annual 197,000,000 Short Form = Community: __Anch, Operating Life nei teeecrsceet act ; ze 25,000 KW ; Refer To Base Case # 25,0C- ; _ BINARY GEOTHERMAL : Steanecenn Tetras c : - CONSTRUCTION COST. 7 I Ratio. of Cost ‘ Input : ee To Base Case Cost Coinments on Scheduling, etc. Construction Site purchase , © Equipment Labor (man years) Materials F shia gs Transportation Bai Engineering irs Management Licensing Interest Other eee ee ened eee 2 aoe TOTAL 73 $31,804,000 fpiav en Operation g . : : o: Operations and Maintenance Fuel ; Insurance ae . . : . a ae 8 ge OPERATING GOST ‘Anmuai Fixed Cost a (1000 $) eae Installed Cost’ panics Rabat seara ts Firm Siar ve : az Interest and Amortization _ 2,226 esopetetae ea Depreciation : 159 Sit oes cen ey Hee : ss zy ar a seaieyie bis Bar ‘Cost. WaT) S/ KAHL 19.19 . “Annual Variable Costs (generat on) Lotus Operations and ati esnaice ; i fuel ae pats USonies Insurance - ae “95 Taxes 5 f 668 Details: Fuel Cost.--O- Special Features: High Plant cost due to immature technology - APPENDIX H HYDROELECTRIC SITE DESCRIPTIONS AND COST ESTIMATES Introduction Northwest Hydroelectric Sites Southwest Hydroelectric Sites Southeast Hydroelectric Sites Southcentral Hydroelectric Sites Hot. H.1. INTRODUCTION In this section, the basic cost data on hydroelectric generating plants which was collected for this study is presented in raw form. A variety of reference material was reviewed to provide the maximum background of information upon which to base these costs. These references are listed on sheets following this introduction. Cost information was developed for 33 different sites around the state after a preliminary analysis of approximately 200 potential sites. All costs are preliminary estimates. Included within the estimates is a margin for contingency. The cost of construction includes interest during construction which varies with the project but is generally in the range of 6 percent to 8 percent of total construction cost. The costs are estimated "bid prices" as though the complete project were bid in 1975. The capital recovery factor is the weighted average of 9.0 for. hydro facilities and 9.6 for transmission facilities, insurance at .1 percent of value of plant, and taxes at 2.1 percent of gross receipts net of taxes. No reserve for coverage requirements on debt is included in operating costs. HoLt.2 To provide some perspective on the background of ex- perience used in developing the cost estimates that follow, there is included on the following pages of this introduction two sections describing Alaska experience as follows: (1) Alaska Experience - Hydro (2) Alaska Experience - Transmission H.1.3 HYDRO PROJECT REFERENCES 1. Purple Lake Rehab. (a) (b) (c) Water Powers:of Southeast Alaska, Federal Power Commission & U.S. Forest Service, 1947. RWRA Preliminary Report of Water Power Resources on Annette Island, 1974. USGS map Ketchikan A-5, 1955. (d) Water Supply, U.S.G.S. Papers #1372-1947-'50, #1466-1950-'53, #1486-1953-'56. Zi Hassler Lake (a) Water Powers of Southeast Alaska, Federal Power Commission & U.S. Forest Service, 1947. (b) RWRA Preliminary Report of Water Power Resources (c) (d) on Annette Island, 1974. USGS map Ketchikan A-5, 1955. Water Supply, Estimated from Adjacent Watersheds (See Purple Lake). Si Upper Mahoney Lake (a) (b) (c) (da) (e), .Water Powers of Southeast Alaska, Federal Power Commission & U.S. Forest Service, 1947. Water Resources Development, U.S. Corps of Engineers, 1967. U.S.G.S. map Ketchikan B-5, 1955. Interim Report No. 1, Southeastern Alaska, U.S. Corp of Engineers, 1952. Water Supply, U.S.G.S. Papers #1372 (USFS & Zellerbach 1920-'33) and (U.S.G.S. 1947-'50), #1466 (1950-'53), U.S.G.S. Papers #1486 (1953-'56), #1500 (1957), #1570 (2958)i5 Hee 4 Swan Lake (Falls Creek near Ketchikan) (a) (b) (c) (da) (e) (£) (g) Lake (a) (b) (c) (da) (e) (£) (g) (h) (i) Water Powers of Southeast Alaska, Federal Power Commission & U.S. Forest Service, 1947. Interim Report No. 1, Southeastern Alaska, U.S. Corps of Engineers, 1952. Alaska Power Survey, 1974. Water Resources Development, U.S. Corps of Engineers, 1967. U.S.G.S. maps Ketchikan C-4 and C-5, 1955. U.S.B.R. Swan Lake Project, 1959. Water Supply, U.S.G.S. Papers #1372 (U.S.F.S & Zellerbach 1921-'33) and (U.S.G.S. 1946-'50), #1466 (1950-'53), U.S.G.S. Papers #1486 (1953-'56), #1500 (1957), #1570 (1958), #1640 (1959). : Grace Water Powers of Southeast Alaska, Federal Power Commission & U.S. Forest Service, 1947. Interim Report No. 1, Southeastern Alaska, U.S. Corps of Engineers, 1952. Alaska Power Survey, 1974. Water Resources Development, U.S. Corps of Engineers, 1967. Alaska Power Administration, Lake Grace Project, 1968. U.S.G.S. Geologic Reconnaissance of Proposed Powersite at Lake Grace, 1971. U.S.G.S. maps Ketchikan C-3 and C-4, 1955. U.S.G.S. Special Hydro Sheet, Lake Grace, 1964. Water Supply, U.S.G.S. Paper #1372 (U.S.F.S. & Zellerbach 1927-'37), #1466 (2951=and=—"53)7 U.S.G.S. Water Resources Data (1965), (1966), (1967), (1968), (1969). He deo 6. ° Anita Lake (a) (b) (c) Water Powers of Southeast Alaska, Federal Power Commission & U.S. Forest Service, 1947. Water Resources Development, U.S. Corps of Engineers, 1967. U.S.G.S. map Petersburg B-2, 1953. the Anita Lake and Kunk Lake (a) (b) (c) Water Powers of Southeast Alaska, Federal Power Commission & U.S. Forest Service, 1947. Water Resources Development, U.S. Corps of Engineers, 1967. U.S.G.S. map Petersburg B-2, 1953. Se Virginia Lake (Mill Creek-Wrangell1) (a) (b) (c) (da) Water Powers of Southeast Alaska, Federal Power Commission & U.S. Forest Service, 1947. U.S.G.S. map Petersburg B-1l. U.S.G.S. Special Hydro Sheet, Virginia Lake, 1958. Water Supply, U.S.G.S. Paper #1372 (U.S.F.S., 1917-'28). Oe Sunrise Lake (a)- U.S.G.S. map Petersburg B-2, 1953. 10. Ruth Lake (Delta Creek) (a) (b) (c) (da) (e) Water Powers of Southeast Alaska, Federal Power Commission & U.S. Forest Service, 1947. Interim Report No. l, Southeastern Alaska, U.S. Corps of Engineers. Water Resources Development, U.S. Corps of Engineers, 1967. Geology of Waterpower Sites on Scenery, Cascade, and Delta Creeks near Petersburg, U.S.G.S., 1962. U.S.G.S. special hydro sheet, Cascade Creek and VACINUGY. 7.1105 210 I if - 1B r Te ‘STF SERRA EE HE RFT PTT z one ar (f) (g) (h) H.1.6 U.S.G.S., Water Resources Near Petersburg and Juneau, 1962. U.S.G.S map Petersburg D-3. Water Supply, U.S.G.S. Paper #1372 (1948-'50), #1466 (1950-'52), #1486 (1955 and '56), #1500 (1957), #1570 (1958). Cascade Creek (a) (b) (c) (da) (e) (f£) (g) (h) (i) (3) (k) (1) Water Powers of Southeast Alaska, Federal Power Commission & U.S. Forest Service, 1947. Interim Report No. 1, Southeastern Alaska, U.S. Corps of Engineers, 1952. Alaska Power Survey, 1974. Water Resources Development, U.S. Corps of Engineers, 1967. U.S.G.S. maps Sumdum A-2 & A-3, 1961. U.S.G.S. Special Hydro Sheet, Cascade Creek & Vicinity.,-.1952. U.S.G.S. Geology of Waterpower sites on Scenery, Cascade, and Delta Creeks, 1962. U.S.B.R., Thomas Bay Project, Alaska, 1966. Water Power Resources near Petersburg & Juneau, U.S.G~S~,—1962. Analysis of Electric Systems Requirements, Petersburg, Alaska, R.W. Beck & Assoc., 1974. Thomas Bay Project Appraisal Report, R. W. Beck & Assoc., 1937S. Water Supply, U.S.G.S. Paper #1372 (U.S.F.S. 1917-'28) and (U.S.G.S. 1946-'50), #1466 (1950-'53), #1486 (1953-'56), #1500 (1957), #1570 (1958), #1640 (1959), #1720 (1960), U.S:GiS. Surface Water Records (1961, '62,-°63, '64,.*65, "66, '67, '68, '69), U.S.G.S. Water Resources Data (1970, 1971, 1972). Scenery Lake (a) Water Powers of Southeast Alaska, Federal Power Commission and U.S. Forest Service, 1947. (b) (c) (d) (e) (f£) (g) (h) (i) 13. Lake (a) Aol .7 Interim Report No. 1, Southeast Alaska, U.S. Corps of Engineers, 1952. Alaska Power Survey, 1974. Water Resources Development, U.S. Corps of Engineers, 1967. U.S.G.S. maps Sumdum A-2 and A-3. U.S.G.S. Special Hydro Sheet, Scenery Creek, Alaska, 1950. U.S.G.S. Geology of Waterpower Sites on Scenery, Cascade and Delta Creeks near Petersburg, 1962. U.S.G.S. Water Power Resources near Petersburg and Juneau, 1962. Water Supply, U.S.G.S. papers #1372 (1949-'50), #1466 (1950-'52), #1486 (1953-'56). Irina U.S.G.S. map Port Alexander D-4, 1951. 14. Green Lake (a) (b) (c) (da) (e) (£) (g) Water Powers of Southeast Alaska, Federal Power Commission and U.S. Forest Service, 1947. Interim Report No. 1, Southeast Alaska, U.S. iCorps of Engineers, 1952. Alaska Power Survey, 1974. Water Resources Development, U.S. Corps of Engineers, 1967. Analysis of Electric Systems Requirements, City and Borough of Sitka, R.W. Beck & Assoc., 1974. U.S.G.S. map Port Alexander D-4, 195i. Water Supply, U.S.G.S. Paper #1372 (1915-'25). 25. 16. ik. i8. H.1.8 Lake Diana (a) (b) (c) (a) Milk (a) (b) (c) (d) Four (a) (b) Water Powers of Southeast Alaska, Federal Power Commission and U.S. Forest Service, 1947. Interim Report No. 1, Southeast Alaska, U.S. Corps of Engineers, 1952. Water Resources Development, U.S. Corps of Engineers, 1967. U.S.G.S. map Port Alexander D-4, 1951. Lake Water Powers of Southeast Alaska, Federal Power Commission and U.S. Forest Service, 1947. Interim Report No. 1, Southeast Alaska, U.S. Corps of Engineers, 1952. Water Resources Development, U.S. Corps of Engineers, 1967. U.S.G.S. map Port Alexander D-3. Falls Lake Water Powers of Southeast Alaska, Federal Power Commission & U.S. Forest Service, 1974. U.S.G.S. map Port Alexander D-3 and Sitka A-3. Carbon Lake (Coal Creek) (a) (b) (c) (a) (e) (f£) Water Powers of Southeast Alaska, Federal Power Commission & U.S. Forest Service, 1947. Interim Report No. 1, Southeastern Alaska, U.S. Corps of Engineers, 1952. Water Resources Development, U.S. Corps of Engineers, 1967. U.S.G.S. map Sitka A-3, 1951. U.S.G.S. Geologic Investigations of Proposed Powersites at Baranof and.Carbon Lakes, Bulletin 1031-B, 1961. Water Supply, U.S.G.S. Paper #1372, (U.S.F.S. - 1922-'27). Hea 19. Takatz Lake (a) (b) (c) (d) (f£) (g) (h) (i) Water Powers of Southeast Alaska, Federal Power Commission and U.S. Forest Service, 1947. Interim Report No. 1, Southeastern Alaska, U.S. Corps of Engineers, 1952. Alaska Power Survey, 1974. Water Resources Development, U.S. Corps of Engineers, 1967. UsS.G-S: map-Sitka A-3, 1951. Geologic Reconnaissance of a Possible Powersite at Takatz Creek, U.S.G.S. Bulletin 1211-D, 1970. U.S.G.S. Special Hydro Sheet, Takatz Creek, 1957. Analysis of Electric Systems Requirements, City and Borough of Sitka, R.W. Beck and Assoc., 1974. Water Supply, U.S.G.S. Papers #1466 (1951-'53), #1486 (1953-'56), #1500 (1957), #1570 (1958), #1640 (1959), #1720 (1960), U.S.G.S. Surface Water Records (1961, "63, '64), U.S.G.S. Water Resources Data (1965, ‘66, °68, °69)-. 20. Unnamed Lake (Approx. Chilkoot River Mile 10) (a) U.S.G.S. map Skagway B-2, 1954. 21. Goat Lake (a) U.S.G.S. map Skagway C-1l, 1948. 22. Tebay Lakes (a) (b) (c) (a) (e) Water Resources Development, U.S. Corps of Engineers, 1967. Corps of Engineers Interim Report No. 3, Copper River and Gulf Coast. U.S.G.S. maps Valdez A-1 and A-2, 1960. U.S.G.S. Special Hydro Sheet, Tebay Lakes, 1962. Water Supply, U.S.G.S. Paper #1372 (1950), U.S.G.S. 9 {62 *67, Surface Water Records (1962, '63, '64), U.S.G.S. Water Resources Data (1965). 2a. » D» 24. 25. - 26. » Le 27. Power Creek (a) (b) (da) (e) H.1.10 Water Resources Development, U.S. Corps of Engineers, 1967. Corps of Engineers Interim Report No. 3, Copper River and Gulf Coast. U.S.G.S. map Cordova C-5. Geology of the Site of a Proposed Dam and Reservoir on Power Creek near Cordova, U.S.G.S., Circular 136, 1951. Water Supply, U.S.G.S. Papers #1372, (1947-'50), #1466 (1950-'53), #1486 (1953-'56), $1500 (1957)., #1570 (1958), #1640 (1959), #1720 (1960), U.S.G.S. Surface Water Records (1961, '62, '63, '64, '65, CTO 2 LIV gis 1a EL) Sheep River Lakes (a) U.S.G.S. map Cordova C-6, 1950. No Name Lake (a) U.S.G.S. map Cordova D-6, 1951. Solomon Gulch (a) (b) (c) (a) (e) ‘66, ‘67, ‘68, ‘69, Corps of Engineers Interim Report No. 3, Copper River and Gulf Coast. Water Resources Development, U.S. Corps of Engineers, 1967. Definite Project Report, RWRA, 1975. U.S.G.S. map Valdez A-7, 1960. Water Supply, U.S.G.S. Paper #1372 (1950), #1466 (1950-'53), #1486 (1953-'56), #1500 (1957). Nellie Juan Lake (a) (b) (c) Water Resources Development, U.S. Corps of Engineers, 1967. Corps of Engineers Interim Report No. 2, Cook Inlet and Tributaries, 1950. U.S.G.S. maps Seward, A-6 and B-6, 1951. (da) (e) 28. Snow (a) (b) (c) (a) (e) (f£) H.1.11 Preliminary Power Survey for Homer Electric Association, RWRA, 1966. Water Supply, U.S.G.S. Surface Water Records (1961, N62, 63," ©0475: ° 65). River Alaska Power Survey, 1974. Water Resources Development, U.S. Corps of Engineers, 1967. Corps of Engineers Interim Report No. 2, Cook Inlet and Tributaries, 1950. U.S.G.S. maps Seward B-6 and B-7, 1951. Preliminary Power Survey for Homer Electric Association, RWRA, 1966. Water Supply, U.S.G.S. Paper #1640 (1959), #1720 (1960), U.S.G.S. Surface Water Records (1961, '62, '63, '64, '65). 29. Bradley Lake (a) (b) (c) (d) (e) (£) (g) (h) Alaska Power Survey, 1974. Water Resources Development, U.S. Corps of Engineers, 1967. Corps of Engineers Interim Report No. 2, Cook Inlet and Tributaries, 1950. U.S.G.S. Water Power Resources of the Bradley River Basin, Kenai Peninsula, Alaska, Paper 1610-A, 1961. Geology of Waterpower Sites on the Bradley River, Kenai Peninsula, Alaska, U.S.G.S. Bulletin 1031-C, 1962. Preliminary Power Survey for Homer Electric Association, RWRA, 1966. U.S.G.S. Preliminary Report, Waterpower Possibilities of Bradley Lake, Alaska, 1956. Corps of Engineers Review of Interim Report No. 2, Bradley Lake Project, 1960. 30. 3 SZ. 33). (i) (3) Hole U.S.G.S. maps Seldovia C-2, C-3, D-2 & D-3, 1951. Water Supply, U.S.G.S. Paper #1486 (1955), #1500 (1957), #Lo70)) (E958) 5.116410) 1(1'959)),. #1720, (E960), US= GS Surface Water Records (1961, ‘G2%."63,° '64,°65, "66, VGH GS eBOS aii ZO ecole lita ten mess) pil nea) e Terror Lake (a) (b) (c) (d) Lake (a) (b) (c) Intermin Report No. 5, Southeastern Alaska, U.S. Corps of Engineers, 1954. Terror Lake Hydroelectric Project, Definite Project Report, 1967. U.S.G.S. maps Kodiak C-3 and C-4, 1952. Water Supply, U.S.G.S. Surface Water Records (1962, HOS OAH OOO OlsllOui ii OS). Elva RWRA Reconnaissance, 1975. Preliminary Permit Application to FPC, 1976. U.S.G.S. maps Dillingham and Goodnews. Kisaralik River (a) (b) U.S.G.S. maps Bethel B-3 and C-3. Regional Electric Power System for Lower Kuskokwim Vicinity, RWRA, 1975. Anvik River (a) U.S.G.S. maps Unalakleet B-2, B-3 and C-3, 1952. References to all Projects: NOAA Technical Memorandum AR-10, Mean Monthly and Annual Precipitation Alaska, 1974. Hea] H.2. NORTHWEST KEY HYDRO SITE 1. Anvik Lake B81 prime Capacity ‘ ae H.2.2 Site Q) . PROJECT DESCRIPTION ° Hydro project Type Region Northwest Installed Capacity ANVIK RIVER Ident. Community _UNALAX 59,568 Mud Annual (Prime) 59,568 MYH Annual (Total) 50 Operating Life (Years) CONSTRUCTION COST ' Input Generation: ene anZ La i fe wyn es Reservoirs, Dams, and Waterways Water ttheels. Turbines,& Accessory Electrical Faquipment Misce)laneons Power Plant Eqnipnen Roads, Railroads, and Bridges | -Indirect ructi Engineering Interest During Construction TOTAL _ Transmission: ———land_and_Land_Rights_ Richt-of-tay Clearing ——__Transmission Lines ards ions z= s_Gonstruss!55_ Cosrs cr coats ANNUAL PRODUCTION COST ‘Labor 4,160 man hrs./yr. : ~ $104,000.00_ . Hydro Maintenance @ $0.75/KW $10,500.00 @ransmission Maintenance @ $200/mi __ 6,400.00 ANNUAL FIXED COST 1 Capital Recovery Cost 1,798,740.00 _ Insurance $1/1000 19,725.00. TOTAL ANNUAL CUST OF PRIME POKER , 1,380:092°00- = Prime Energy Charge 33.24 Mills/KWH a if Capital Cost/Prime KW $2,901 | Capital Cost/Installed KW $1,409 Heaed H.3. SOUTHWEST KEY HYDRO SITES 1. Lake Elva 2. Kisaralik River PROJECT DESCRIPTION Hydro project Type —2.5MW Installed Capacity _1.24mw Prime Capacity 10.820 MWH Annual (Prime) 10,820 mwWwH Annual (Total) -50_ Operating Life (Years) LAKE ELVA CONSTRUCTION COST Ident. Site Q) Region 2O-Weu. eo Community _DILLINGHAM Input §Oublays Incurred Ay. Year (10008) Generation: fi ta 3 8 ae TOTAL ha 100 _ truct. ovrement Tig 320 | | 400 Reservoirs, Dams, and Waterways 600 | 800 1,400 —___Water_Wheels, Turbines, & Generatord 50} 550 f 600 Accessory Electrical Fauipment 100 | 200 | i L 300 ——Miscellaneons Power Plant Euuipmentt 100 100 Roads, Railroads, and Bridges 100 ic OO. Indirect Construction Casts | 300 500 | _ =| foo "| Engineering 300 | 100 S500 Interest During Construction 2 a | 151 Be 210. { i 4,510 Transmission: i ———Jand_and_Land_Righ' 40 —_—-Right-of-Way Clearing 60 | | 60 Transmission Lines 200} 800 al 1,000 Switchyards | 100} 300] 400 Substations | Indirect Construction Costs 300 400 Engineering [ fal 100 200 | i 15 65 80 675 i 2,180 ——__________TOTAL_CONSTRUCTION COST 332. a 1 6,690 ANNUAL PRODUCTION Labor 2080 man hrs./yr. Hydro Maintenance @ $0.75. Transmission Maintenance KW @ $200/mi X 29 NNUAL FIXED COST ANNU: Capital Recovery Cost Insurance $1/1000 Taxes TOTAL ANNUAL COST OF PRIME Prime Energy Charge POWER 64.31 Mills/KWH 52,000.00 1,875.00 5,800.00 615,180.00 6,690.00. _14,312.00 695 3857. 00 Capital Cost/Prime KW. $5,395 Capital cost/Installed KW $2,676 PROJECT DESCRIPTION Hydro Project Type KISARALIK RIVER 36MW Installed Capacity 18,2MW prime Capacity 159,222 MYH Annual (Prime) 159,222 mwH Annual (Total) pee Operating Life (Years) CONSTRUCTION COST are Input _ Ident. H.3.3 ae Region S.W. BETHEL Community Generation: f 1 Struct: Reserwirs, Dams, and Waterways nT Ueikhatiesla: Mutitdna & Gitacatocs ——_Accessory Electrical Equipment | ——Miscellaneons Power Plant Fquinnent | Roads, Railroads, and Bridges 7 400 Engineering _ 500 | 500 Interest During Construction 14 57 —TOTAL 564 | 1207 Transmission: | ———land_and_ Land Rights —_—-Right-of-Way Clearing ——_—Transmission Lines Switchyards T Substations Indirect Construction Costs 1786 | 3278 | 4041 ANNUAL PRODUCTION COST Labor 12,480 man hrs./yr. Hydro Maintenance @ $0.75/KW : Transmission Maintenance @ $200/mi x 60 mi. ANNUAL FIXED COST Capital Recovery Cost 7407 B0386_B4091 312,000.00 27,000.00 12,000.00 6 763,260.00 Insurance $1/1000 74,485.00 Taxes 150,964.00 TOTAL ANNUAL COST OF PRIME POWER 7 339,709.00 Prime Energy Charge 46.10 Mills/KWH _Capital cost/prime KW. _. $4,093 Capital cost/Installed KW $2,069 oe _ BO ND et a ee ee et Rat OO ON. OF OY a ON) er, ©: o ON DO oO FSF WH PL H.4. SOUTHEAST KEY HYDRO SITES Purple Lake Rehab. Hassler Lake Upper Mahoney Lake Swan Lake Lake Grace Anita Lake Anita Lake and Kunk Lake Virginia Lake Sunrise Lake Ruth Lake Cascade Creek - Stage I Cascade Creek - Stage II Scenery Lake Lake Irina Green Lake Lake Diana Milk Lake Four Falls Lake Carbon Lake Takatz Lake Unnamed Lake Goat Lake H.4.1 “PROJECT DESCRIPTION ° _Hydro Project Type PURPLE LAKE REHABILITATION —iMW. Installed Capacity 2_MW_ Prime Capacity 17,520 22,310 MYER Annual (Prime) MWH Annual (Total) ——3i. Operating Life (Years) Existing CONSTRUCTION COST Ident. H.4.2 Site Region Community _Metlakatla This project is to bring Purple Lake up to its 1.6 Mw Prime Capacity 2 mW Prime Capacity 14,020 Mi Energy Input $_Outlays Incurred By Year (1000$) ___ Generation: 3 A 5 ——_Structures and Improvements Reservoirs, Dams, and Waterways 350 i} + doshas e EB & at Engineering interest During Construction TOTAL Transmission: ——_—Land_and_Land Rights _ se -of-' Clearing. —__Transmission Lines Switchyards Substations Indirect Construction Costs ANNUAL PRODUCTION COST Labor No increased labor. Hydro Maintenance @ $0.75/Kw No Increase Transmission Maintenance @ $200/mi No Increase ANNUAL FIXED COST Capital Recovery Cost Insurance $1/1000 Taxes TUTAL ANNUAL COST OF PRIME POWER a H.4.3 PROJECT DESCRIPTION Site @ Hydro project Type HASSLER LAKE Region ae _4 Mid Installed Capacity Ident. Community Metlakatla 2 my Prime Capacity 16,980 MYEH Annual (Prime) 18,430 mw Annual (Total) 50. Operating Life (Years) CONSTRUCTION COST Input. ____$_Outlays_Incurred By Year (1000$)____. Generation: — | } 2. 3 A 5 6 TOTAL —_—__Land_and Land Rights Oe ——___Structures and Improvements 501 4751 75: 300 Reservoirs, Dams, and Waterways 100/1,800} 250 | A. 2,150 Water Wheels, Turbines, & Generatorg 100] 500} 400 | + + 1,000 ___| Accessory Electrical Equipment 50] 300 22} 500 Miscellaneous Power Plant Equinment| 20 80 -100 Roads, Railroads, and Bridges 50] 50 Indirect Construction Casts 20| 150] 130 = _300_ Engineering i 300] 300] 100 a mole 790 Interest During Construction 17) 83] 110 = Pee 210 TOTAL 707| 3,388]1,215 5,310 Transmission: ——Land_and_Land_ Right. — aa cet anaes Right-of-Way Clearing 35| +f 135 —___Transmission Lines | 255} 150 + 405 Switchyards 200} 200] 400 Substations } 150} 150 I 300 Indirect Construction Costs 35 25 60 Eniieeer ite a 40| 40 | f= 350 | __Interest During Construction 2 24 - 70 TOTAL + 72 804 644 r oii 1,520 TOTAL CONSTRUCTION COST 779) 4,192] 1,859 | 6,830 ANNUAL PRODUCTION COST Labor 4160 man hrs/yr. Hydro Maintenance @ $0.75/KW Transmission Maintenance @ $200/mi 104,000.00 3,000.00 _ 1,800,00 _ ANNUAL FIXED COST Capital Recovery Cost Insurance $1/1000 Taxes TOTAL ANNUAL COST OF PRIME POWER 623,820.00 6,830. “15:528.00 754,978.00. Prime Energy Charge 44.46 Mills/KWH Capital cost/prime kw $3,415 Capital cost/installed kw $1,708 $ seidiesincir Sooeceel | 2 zr “172 PROJECT DESCRIPTION UPPER MAHONEY LAKE Project Type Installed.Capacity Prime Capacity MWH Annual (Prime) MWH Annual (Total) —50_. Operating Life (Years) ire te ~ 217 H.4.4 Site @ Region SE Ident. Community Ketchikan CONSTRUCTION COST Input _$ Outlays Incurred Ry Year (1000$) ___ Generation: 1 | A 5 6 v) TOTAL ] ———_land_and_Land Rights 20 250 ___ Structures and Improvements. | 1,750 —___Reservoirs, Dams, and Waterways 2,000 —___Water Wheels, Turbines, 1,350 Accessory Electrical Equipment. 600 ———Miscellaneous Power Plant Equi 200 Roads, Railroads, and Bridges 20. ———-Indirect Construction Costs. . ae Engineering 780. Interest During Construction 8 L 460 TOTAL _ 71,735 Transmission: ———JLand_and_Land_ Rights 20 ———Risht-of-Way Clearing i 60 —___Transmission Lines_ 180 Switchyards 800 Substations Indirect Construction Costs 55 ———_Engineering 35 130 —_—Interest_During Construction 13) __42 55 TOTAL | 1.300 363 504] 4,425} 3,743 9,035 _ ANNUAL PRODUCTION COST Labor 4160 man hrs/yr. 104,000.00 Hydro Maintenance @ $0.75/KW $ 7,500.00 Yransmission Maintenance @ $200/mi 800.00 ANNUAL FIXED COST Capital Recovery Cost 820,950.00 Insurance $1/1000 9,035.00 Taxes mA 788.00 TOTAL ANNUAL COST OF PRIME POWER ey E73. Prime Energy Charge 23.37 Mills/kwh Capital Cost/prime kw $1,922 ~* Capital cost/installed Kw $ 903 le eres > H.4.5 PROJECT DESCRIPTION Site . @ -Hydro project Type SWAN LAKE ! Region _S-E. __ 15 MW Installed Capacity Ident. Community Ketchikan _ 2200 Kw Prime Capacity 67,500 MWH Annual (Prime) *%See Lake Grace for combined -10,500 MWH Annual (Total) transmission cost. —S5SO_. Operating Life (Years) CONSTRUCTION COST ——— Input —$_ Outlays Incurred By Year (1000S) ____. Generation: r rer 50 iA - _____Land_and_Land Rights oO 480 ___Structures and Improvements aoe Reservoirs, Dams, and Waterways 8,000 14,500. ____ Water Wheels '& Generator 300 2,000 Accessory Electrical Fquipment 800 ——Miscellaneous Power Plant Equipment) 300 : Roads, Railroads, and Bridges 470 ——-Indirect Construction Casts 1,125 ua Engineering eee Interest During Construction 1,939 = TOTAL \ Transmission: = ———_—__Land_and Land Rights Right-of-Way Clearing 108 1,000 _| Transmission Lines 100]1,000} 880 1,980 Switchyards _ 2031 600) |/7S50) 1.200 Substations 30 *00 | 510 1,000 Indirect Construction Costs 30 170 150 a | 350 Engineering 40 130 600 ; i an 1 255 381 __ TOTAL 41 oe hs 128 aes 6,56) | * 374}2,688 las, 45414, a6 32,980 mal TOTAL CONSTRUCTION COST | ee x 4 ANNUAL PRODUCTION COST J Labor 8320 man hrs/yr 208,000.00 Hydro Maintenance @ $0.75/KW 12,250.00 Transmission Maintenance @ $200/mi x 23 mi = 4,600.00 ANNUAL FIXED COST Capital Recovery Cost 3,007 ,566.00 Insurance $1/1000 32,980.00 Taxes 68,552.00 ‘TUTAL ANNUAL COST OF PRIME POWER 3,332,948.00 Prime Energy Charge 49.38 Mills/kwh Capital cost/prime kw $4,283 Capital cost/installed kw $2,199 cairo H.4.6 PROJECT DESCRIPTION Site © Hydro project Type LAKE GRACE Region S28. 29 MW Installed Capacity Ident. Community Ketchikan iM Prime Capacity Swan Lake-Lake Grace transmission may be combined; -24,000 MWH Annual (Prime) total transmission cost for both projects would be $9,241,000. Resulting combined project cost would 103.500 mw ' fe baipsramns Wl spandiic total $66,670,000 or $3,562/prime Ki. —AQ. Operating Life (Years) CONSTRUCTION COST Input $ Outlays Incurred By Year (1000$) Generation: . [Ta u 20 480 40 ——and_and_Land Rights ———_Structures and Improvements | is Reservoirs, Dams, and Waterways 800 5,000) 7,70 —__Water Wheels, Turbines, & Generators 100) 1,200] Accessory Electrical Fquipment | $0) Miscellaneous Pa : 10) Roads, Railroads, and Bridges 730 1,85 i 100 700 735 | Indirect Construction Casts meee [ 350 [ 200 | 60 | Interest During Construction 9 96 44 | TOTAL 379 _|3,226 [11,3412 | Transmission: s0| 2 ~—___Land_and_Land Rights Right-of-w: Cleari 70 —___Transmission_Lines Sedilisce 3,000 Switchyards = 42d 130 i Substations 29 108 1,080 Indirect Construction Costs 73 21 35 il | 351 aa ; reqie7s 730 ——Interest_During Construction if 294 metoy 480 ‘TOTAL -410] 4,374 2,724 832 8,341 TOTAL CONSTRUCTION COST 379 {3,636 ]15,71415,5894 ,037 ekyckal ANNUAL PRODUCTION COST Labor 8320 man hrs./yr. $208,000.00 Hydro Maintenance @ $0.75/KW X 20,000 70 Transmission Maintenance @ $200/mi X 39 mi. = $7,800.00 ANNUAL FIXED COST Capital Recovery Cost 3,591,636.00 Insurance $1/1000 “739/351. Taxes 81,098. 0 TOTAL ANNUAL COST OF PRIME POWER 3, 9422885 -00- Prime Energy Charge 41.95 Mills/kwh Capital cost/prime kw $3,577 ‘Capital cost/installed KW $1,968 H 4.7 PROJECT DESCRIPTION site © -Hydro Project Type ANITA LAKE Region’ 8.8.0 —4 MW. Installed Capacity Ident. Community _Wrangell 2:1 MA prime Capacity Z 18,396 MWH Annual (Prime) Install 2 of 2000 kw units for regulation 18,396 MWH Annual (otal) of Kunk’ lake now or in the future. --80 Operating Life (Years) CONSTRUCTION COST_ Input $ Outlays Incurred Ry Year (1000$)_______. x a Generation: 2. emi} A = 6 oe TOTAL Land and Land Rights 20 100) 30 150 Structure 100 200 300 Reservoirs, Dams, and Waterways 50} 800] _ 900 1,750 Water Wheels, Turbines, & Generatord 100] _ 200 300 600 Accessory Electrical Fquipment 40 8o| 80 200 Miscellaneous Power Plant Fanipmen Loy 40) L. aos —___Roads, Railroads, and Bridges. 50}__ 100 re ee Indirect Construction Casts al, 12 65 76 eo. eee Engineering 1 aoa 251 175}. 575) — 625} Interest During Construction 8 27 zh 158 ahs 270. a TOTAL 454! 1 ,63711,829) 8. Transmission: ____land_and_Land Rights _ 20220) fe 20 ———Right-of-Way Clearing 150} _50 200 —__Transmission Lines - 250|__ 450 2 700 Switchyards 50. 150 200 Substations 50) 150 200 Indirect Construction Costs 25) 40 6s | A ; 40 4 40] 40 160 —__Interest_ During Construction i 3 18) 56 78 41 53| 593] 936 +623} TOTAL L L 369 507 2,230] 2,765| ia 5,871 | ——____ TOTAL CONSTRUCTION COST ANNUAL PRODUCTION COST Labor 832 man hrs/yr. 20,800.00 Hydro Maintenance @ $0.75/KW 3,900.00 Transmission Maintenance @ $200/mi 10.00 ANNUAL FIXED COST Capital Recovery Cost 538,128.00 Insurance. $1/1000 5,871.00 Taxes 11,983.00. * TOTAL ANNUAL COST OF PRIME POWER 582,582.00 Prime Energy Charge 31.67 mills/kwh Capital cost/prime kw $2,796 Capital cost/installed kw $1,468 — PROJECT DESCRIPTION Hydro project Type AWITA LAKE _8 mw Installed Capacity & _3.83_mwprime Capacity KUNK LAKE 33,550 MWH Annual (Prime) 33,550 mw Annual (votal) -—50. Operating Life (Years) CONSTRUCTION COST Ident. Site Region Community H.4.8 @ S.E. Wrangell Input $ Outlays Incurred By Year _(1000$) _______o. Generation: 1 ——_—land_and_Land Rights Reservoirs, Dams, and Waterways ——_-Water Wheels, Turbines,& Genera ; ' ical E ——Miscellaneons Power Plant Equi Roads, Railroads, : i ____Engineering 320 Interest During Construction TOTAL Transmission: ——Land_and_Land Rights 20 Right-of-Way Clearing 200 Transmission Lines 700 Switchyards ae 400 Substations 400 Indirect Construction Costs 85 260 | 92 2,157 861] 3,351) 4,475 | 9,128 ANNUAL PRODUCT: Labor 1664 man hrs/yr. Hydro Maintenance @ $0.75/KW Transmission Maintenance @ $200/mi ANNUAL FIXED COST Capital Recovery Cost Insurance Taxes TOTAL ANNUAL COST OF PRIME POWER $1/1000 Prime Energy Charge 27.21 Mills/kwh _Capital cost/prime kw _ : Capital cost/installed kw $1,141 41,600.00 —6.000.00_ 2.800.00 834,462.00 9,128.00 18,774.00 912,764.00 $2,383 i woe H.4.9 PROJECT DESCRIPTION Site 5 ® Hydro project Type VIRGINIA LAKE Region ee 6 MW. Installed Capacity Ident. Community Wrangell 3_MW_ Prime Capacity 26,280 MYz Annual (Prime) 33,156 MWH Annual (Total) SO...‘ Operating Life (Years) ® CONSTRUCTION COST Input $ Outlays Incurred By Year _(1000$)____. , Generation: oe 2. 3 A | “4 6 4 7} _ TOTAL i Land_and Land Rights 20_| 200 | 20 | 240 | ____ Structures and Improvements 100 | 200 | 300 Reservoirs, Dams, and Waterways 900 | 800 1,700 =I Dd ____Water Wheels, Turbines, & Generatord [ 350 | 450 | 400 eal 1,200 ____Accessory Electrical Eauipment | 400 | 200 | __ 600 | —___Miscellaneous Power Plant Kauipnent 40 | 110 a a <T50) Roads, Railroads,.and_Bridges..._}..- | of | ee 70 structi be 31] _ 95 | __86 ie poe oat | ee Miivsdieerina 300 | 140 | 120] so] _ | |__640 Interest During Construction [8 | 36] 109] 105 |* | ft sd 258 ‘TOTAL 328 827 2234 1981 | 5,370 Transmission: a eee Tenia rarie Rights = onion poser eerie Os —___Right-of-Way Clearing o | _30 el ——_—Transmission Lines 4 ae ican ine Switchyards _ ° { + 450 Substations : | £50. 350 Indirect Construction Costs LL 3 | 37 bg Z 20 2 —___Engineering 2 20 | ants 85: 130. aie | 195, = ——-Interest During Construction 2 eetints0s ae a) TOTAL _ 72 76-}939--1-634-}+ —_| 1,700 TOTAL CONSTRUCTION cosT 400 | 903 | 3152 oe | | 7,070 | . % ANNUAL PRODUCTION CosT ) 3 Labor 4160 man hrs./yr 104 ,000.00 Hydro Maintenance @ $0.75/KW $4500.00 Transmission Maintenance @ $200/mi 1600.00 ANNUAL FIXED COST b Capital Recovery Cost 646,500.00 Insurance $1/1000 7,070.00 Taxes / _16,037.00 TOTAL ANNUAL COST OF PRIME POWER 179,707.00 Prime Energy Charge 29.67 Mills/kwh | _ Capital cost/prime kw $2,357 Capital cost/installed kw $1,178 2 ies -Hyaro Project Type 4.0 MW Installed Capacity (WORON CFSKI 2.4Mil Prime Capacity 21,024 MWH Annual (Prime) 21,024 mYWH Annual (Total) -—5Q. Operating Life (Years) PROJECT DESCRIPTION SUNRISE LAKE _ ISLAND) Ident. CONSTRUCTION COST Input Generation: Site “.H.4.10 ® Region __S.E. Community Wrangell ——_Structures and Improvements Reservoirs, Dams, and Waterways Roads, Railroads, and Bridges _ ——-Indirect Construction Costs —__-_Enginsering Interest During Construction TOTAL Transmission: ——Land_and_Land Rights ——_Risht-of-Way Clearing. —__Txansmission Lines —__Switchyards Substations Indirect Construction Costs 459/1,552}1,804 Labor 832 man hrs/yr Hydro Maintenance @ $0.75/KW Transmission Maintenance @ $200/mi ANNUAL FIXED COST 20,800.00 3,000.00 _ 1,260.00 Capital Recovery Cost 381,468.00 Insurance $1/1000 ““%)174.00 Taxes -8,625.00 _ TOTAL ANNUAL COST OF PRIME POWER 419,327.00 _ Prime Energy Charge 19.95 mills/kwh Capital cost/prime kw... $1,739 Capital cost/installed kw $1,043 H.4.1L PROJECT DESCRIPTION Site @® Hydro project Type Region. .S/Be. 25. 16 MW Installed Capacity ure eee Ident. Community _PETERSBURG 7.95 MW Prime Capacity 69,660 MWH Annual (Prime) 69,660 MWH Annual (Total) _50__- Operating Life (Years) CONSTRUCTION COST Input $ Outlays Incurred By Year (1000$) ______. Generation: 1 2 =] = | 6 2 EN ——_—_Land_and_Land Rights 20 | 140} 40 200 Structures and Improvements _| Reservoirs, Dams, and Waterw: Water Wheels, Turbi aaa chaos A ra e x z 1 Roads, Ra Alzonda.—and Beiaeas ——7___}_200_a00" “indi ; ae Engineering 350 | 1,800 Interest During Construction LS 716 TOTAL 380 6216 18,365 | Transmission: ———Land_and_Land Rights 50 50 ———Right-of-Way Cleaxing 200 | 2 | 320 Transmission Lines 7 = 100 | 600 | 600 1,300 Switchyards sc | 35 1,200 Substations 500 1,000 Indirect Construction Costs 70 70 | 60 200 i 100 100 100 500 52 | 132 | 200 | 390 [236 | 1642 | 1702 4,990 1332 | 5455 | 8562 | 7626 | 23,355 ANNUAL PRODUCTION COST Labor 208,000.00 Hydro Maintenance @ $0.75/KW 12,000.00 Transmission Maintenance @ $200/mi 10.00 ANNUAL FIXED COST Capital Recovery Cost 2,131,890.00 Insurance $1/1000 : : 23,355.00 _ Taxes 49,950.00 TOTAL ANNUAL COST OF PRIME POWER 2,428,392.00_ Prime Energy Charge 34.86 Mills/kwh . Capital cost/prime kw $2,938 | 7 Capital cost/installed kw $1,460 cece oe eels ca ec er ee os Anema H.4.12 PROJECT DESCRIPTION Site. @ Hydro project Type Region ee. CASCADE CREEK Ident. Community _PETERSBURG -15.MW. Installed Capacity STAGE I 5.1 MW Prime Capacity 44,781 MWe Annual (?rime) 44,781 mwH Annual (Total) eigOb Operating Life (Years) CONSTRUCTION COST Input. Generation: ——lLand_and_Land Rights s 25 and Improvemen Reservoirs, Dams, and Waterwa —___Water Wheels. Turbines, & Generato essor e a quipmen \roads, and Bridges Roads, Rail -Indirect Con an Co Engineering Interest During Construction TOTAL Transmission: Switchyards Substations Indirect Construction Costs ——Engineering ANNUAL PRODUCTION COST Labor 8320 man hrs./yr 208,000.00 Hydro Maintenance @ $0.75/KW 11,250.00 Transmission Maintenance @ $200/mi x 17 3,400.00 ANNUAL FIXED COST Capital Recovery Cost 2.097,840.00 Insurance $1/1000 5,00 Taxes 9,212.00 TOTAL ANNUAL COST OF PRIME POWER 24392,652.00_ Prime Energy Charge 53.45 Mills/kwh | nq nT Capital cost/prime kw $4,501 Capital cost/installed kw $1,530 PROJECT DESCRIPTION Hydro project Type —36 MW Installed Capacity 17.9 MW Prime Capacity 156,672 MwH Annual (Prime) 156,672 mMWH Annual (Total) 50 Operating Life (Years) Input Region Community Ident. CASCADE CREEK STAGE II Note: Costs assumed to begin with year 3 of Phase I. CONSTRUCTION COST Site ) S.E PETERSBURG Generation: ——_Land_and_ Land Rights ——_Structures and Improvements a fae eed. A 5 Reservoirs, Dams, and tlaterways Water Wheels, Turbines, § _Accessory Electrical Fquipment ——_-Miscellaneous Power Plant Equi —__Roads, Railroads, and Bridges. ——-Indirect Construction Casts 5000 200 | 1400 20 _} 380 | 1o | 190 Engineering Interest During Construction pee 22_| 263 | 690 | TOTAL ' Transmission: Switchyards Substations Indirect Construction Costs 4 ; I ; ; TOTAL Al . TOTAL PHASE I & II 380 2089 8473 17249 ANNUAL PRODUCTION COST Stage I & II Labor 12,480 man hrs./yr. 312,000.00 Hydro Maintenance @ $0.75/KW x 51,000 KW ~38,250.00. Transmission Maintenance @ $200/mi x 17 3,400.00 ANNUAL FIXED COST Capital Recovery Cost 4 ,032,240,00 Insurance $1/1000 0.00 Taxes 93,034.00 TOTAL ANNUAL COST OF PRIME POWER 4,823,.214,00 Prime Energy Charge 28.87 Mills/kwh Capital cost/prime kw $1,192 Capital cost/installed kw $ 593 eee ‘HY. 14 PROJECT DESCRIPTION site. ® ° Regi _Hydro project Type CENERTETATE gion _s.B. if _MW Installed Capacity Ident. Community Petersburg 9.1 MW prime Capacity : 79,716 MWH Annual (Prime) Note: Landslide area from Porter Peak 79,716 MWH Annual (Total) will require special transmission design. 50 _ Operating Life (Years) CONSTRUCTION COST Input Generation: 2 ———JLand_and_Land Rights 20 4 ___ Structures and Improvements — 200 | 1300 | 1000 00 Reservoirs, Dams, and Waterways 1600 | 2000 | 1000 4,600 Water Wheels Turbines, & Generators 100 1050 | 1190 2,250 —_—Accessory Electrical Equipment 100 300 | 350 750 ——-Miscellaneous Power Plant Fonionentt 150] 150 300 Roads, Railroads, and Bridges. 300 | 300 600 ‘Indirect Constr jon Costs 20 500 300 80 900 Engineering 0 600 0 1 1.700 Interest During Construction 0 4 0 ~ 592 1,160 TOTAL 80 07 40 14,960 Transmission: ——Land_and_Land_ Rights 40 0 an Right-of-Wa: Ca ing 00 O00 —__Transmission Lines __. estat | eaves |r 00 | 1000 | Switchyards Fenn 400} 400 Substations | sa_| 300 | 300 4 { Indirect Construction Costs 100 |__200 ——_Engineering oo | 150 350-1; 150 I -+ ——Interest During Constructian 9 67_} 177} 287 TOTAL 349 |2037_| 2627 | 2337 TOTAL CONSTRUCTION cosT 380 {1456 ae eee 6859 a ANNUAL PRODUCTION COST Labor 98320 man hrs./yr. 208 ,000.00 Hydro Maintenance @ $0.75/KW 13,500.00 Transmission Maintenance @ $200/mi x 26 5,200.00 ANNUAL FIXED COST Capital Recovery Cost 2,052,000.00 Insurance $1/1000 22,310.00 Taxes 48 321.00 TOTAL ANNUAL COST OF PRIME POWER 2,349, 331.00. Prime Energy Charge 29.47 Mills/kwh Capital cost/prime kw $2,452 Capital cost/installed kw $1,239 ny PROJECT DESCRIPTION s Hydro project Type magica © —3-Mw. Installed Capacity Tee Ident. Community _SITKA Sarg pice jg hg AU Note; Transmission distance to tie to SS Lake Diana line is 1.75 miles 13,680 MWH Annual (Total) ee Operating Life (Years) CONSTRUCTION COST Input $ Outlays Inc! Generation: 1 2. | 2a | 5 6 2 | TOTAL a] Land and Land Rights 20 20 10 SO ——Structures and Improvements 300 300 Reservoirs, Dams, and Waterways a 700 is Water Wheels, Turbines,& a 500 Accessory Electrical ayaa | 400 ——AMiscellaneons Power Plant Faninment P Roads, Railroads, and Bridges | -Indirect Construction Costs 300 Engineering 500 Interest During Construction 130 TOTAL 3,030 ' Transmission: | ——_—Land_and_Land Rights ee 10 ———Right-of-Way Clearing 50 —_—_Transmission Lines 70 Switchyards 300 Substations Indirect Construction Costs T 100 Engineering 80 ——Anterest_ During Construction ee 25. TOTAL 635 TOTAL CONSTRUCTION COST 2573 3,665 ANNUAL PRODUCTION COST Labor 832 man hrs./yr. 20,800.00 Hydro Maintenance @ $0.75/KW Transmission Maintenance @ $200/mi 350.00 ANNUAL FIXED COST Capital Recovery Cost 333,660.00 Insurance $1/1000 Taxes TOTAL ANNUAL COST OF PRIME POKER Prime Energy Charge _3,665.00 1,575.00 368,300.00 23.49 Mills/kwh Capital cost/prime kw $2,047 Capital cost/installed kw $1,272 pices anneal ae pe eet oes meee ts test hntesNndwminers © + + gels Sete ogy etn puinS ees tren H.4.16 PROJECT DESCRIPTION Site & Hydro project Type , ‘ Region _S-E. 14 MW Installed’ Capacity GREEN LAKE Ident. Community SITKA 8.6 Ma Prime Capacity 57,816 MWH Annual (Prime) 57,816 MWH Annual (Total) sO Operating Life (Years) Note: Install two 7,000 KW units CONSTRUCTION COST Input Vv Generation: | 5 6 7 TOTAL .__| at = san 800 | 1,600 m 6,000 —____Water Wheels, Turbines,& Generators 900 ab 1,900 Accessor ctri i 300 800 —___Miscellaneous Power Plant Fouipment 200 1204 390] Roads, Railroads, and Bridges. 50 opens ——Andirect Construction Costs so] 250 | 150 600 Engineering 350 1.800 Interest During Construction 8 | 594 7 SCCM Cy TOTAL $194 14,380 _ Transmission: Land and Land Rights 50 ——_—_Right-of-Way Clearing | 500° —___Transmission Lines 300 | 500 | 800 Switchyards . aso | Substations 300 Indirect Construction Costs 100 ——_-Engineering ——___Interest During Construction _ TOTAL ‘A 328 ANNUAL PRODUCTION COST Labor 4160 man hrs./yr. 104,000.00 Hydro Maintenance @ $0.75/KW 10,500.00 Transmission Maintenance @ $200/mi 2,100.00 ANNUAL FIXED COST Capital Recovery Cost 1,646 ,520.00 Insurance $1/1000 i 18,050.00 Taxes 37,405,00 TOTAL ANNUAL COST OF PRIME POWER 1,818,575.00 Prime Energy Charge 31.45 Mills/kwh Capital cost/prime kw $2,735 Capital cost/installed kw $1,289 ee PROJECT DESCRIPTION Site: =. (6) Hydro project Type LAKE DIANA Regfon, 3,250 10.MW_ Installed Capacity Ident. Community SITKA erg ake et eh Note: Transmission figured to proposed 49,165 Green Lake switchyard, 12.5 miles 40,165 MWH Annual (Total) aoe” Operating Life (Years) CONSTRUCTION COST - Input —$ Outlays Incurred By Year (1000$) ___. Generation: os ba a 4 5 6 Z TOTAL Land and Land Rights 20 140 40 200 ——Structures and Improvements 500__| 700 1.200 Reservoirs, Dams, and Waterways 500 | 800 1,300 Water Wheels, Turbines,& Generators 700 700 1,400 Accessory Electrical Equipment 350 250 600 on MisaAli ae eae Lane Hautamenl 754125 200 Roads, Railroads, and Bridges _ 150_| 150 | 300 ———Indirect Construction Costs 200 _| 200 | 200 + Ld 600 Engineering 300 400 150 150 4 sacl. = eaves 1,000_ Interest During Construction 8 | 38 4127 | 267 440 TOTAL 328 1928 —792 t teat Transmission: ———Land_and_Land_ Rights 10. 20 ——__Right-of-Way Clearing 100 B70" Transmission Lines 1250 __| [ 650 Switchyards 300 1500 : 800 Substations 50 4150 200 Indirect Construction Costs 100 __}100 200 ae ee 50 50 | 50 50 200 i | 1 4 | 32_| 88 125 TOTAL Si 64 112 238 2,465 ‘AL CO} S: 379 | 992 904 h4a30_ | 4] 429305 ANNUAL PRODUCTION COST Labor 2080 man hrs./yr. : 52,000.00 Hydro Maintenance @ $0.75/KW 7,500.00 Transmission Maintenance @ $200/mi 2,500.00 ANNUAL FIXED COST Capital Recoverv Cost 888,240.00 Insurance $1/1000 Taxes . _20,159.0! TOTAL ANNUAL COST OF PRIME POWER 980.104. 0,104. a Prime Energy Charge 24.40 Mills/kwh = : - Capital cost/prime kw ~-- $2,117 Capital cost/installed kw $ 970 ae H.4.18 PROJECT DESCRIPTION Site Hydro project Type Region _S.E. 16MW Installed Capacity MILK LAKE Ident. Community SITKA __8MW Prime Capacity 70,080 MW Annual (Prime) 70,080 MWH Annual (Total) --50 Operating Life (Years) CONSTRUCTION COST Input -$ Outlays Incurred Ry Year (1000$)_______ Generation: Roads, Railroads, and Bridges —___Engineering 300} Interest During Construction 8 TOTAL | 328 Transmission: ——Land_ and Land Rights poco, | ____ Right-of-Way Cleari + 800 Transmission Lines 800 1,600 Switchyards 800 Substations 600 Indirect Construction Costs 400 : 600 290 5140 ANNUAL PRODUCTION COST Labor 4160 man hrs./yr 104,000.00 Hydro Maintenance @ $0.75/KW 1,200.00 Transmission Maintenance @-§200Ami- $400/mi. 8,000.00 ANNUAL FIXED COST Capital Recovery. Cost 1,702,140 .00 Insurance $1/1000 “" 18,570.00 Taxes 38 512 00 TOTAL ANNUAL COST OF PRIME POWER 1,872,422..09 _ Prime Energy Charge 26.72 Mills/kwh . : Capital cost/prime kw $2,321 Capital cost/installed kw $1,172 | H.4.19 PROJECT DESCRIPTION Site @) Hydro project Type Regions cko ee - 6MW Installed Capacity ; FOUR FALLS LAKE Ident. Community _SITKA 3aMW _._- Prime Capacity 28,280 MWH Annual (Prime) NOTE: Transmission line from Milk Lake to 26,280 mWwH Annual (Total) Sitka would pass near the powerhouse. Operating Life (Years) CONSTRUCTION COST Input. $ Outlays Incurr Generation: 1. 2_| a. A 5. e= [ Z e __Land 3 Land Risht 10 50 2s and Irors:- ament 300 300 Reservoirs, Dams, and iiaterways t 7 700 Water Wheels, Turbines, g |_750 950 50 |_350 | 400 ——AMiscellaneons Power Plant Eaninnentl | +- 100 Roads, Railroads, and Bridges | Oe} —_—-Indirect Construction Casts t heen 300 | Engineering ee > 750. Interest During Construction 1 = 7 155 TOTAL 2585. Transmission: ———Land_and_Land Rights ____ —-}— = Right-of-Way Clearing a ba. 5 =} —__Tzansmission Lines Switchyards T 400 Substations Indirect Construction Costs 50 5 10 | 510 ANNUAL PRODUCTION COST Labor 832 man hrs./yr. 20,800.00 _ Hydro Maintenance @ $0.75/KW 4,500.00 Transmission Maintenance @ $200/mi 0.00 ANNUAL FIXED COST Capital Recovery Cost Insurance $1/1000 Taxes TOTAL ANNUAL COST OF PRIME POWER Prime Energy Charge 16.18 Mills/kwh Capital cost/prime kw “$1,417 Capital cost/installed kw $ 711 leer ween Hydro project Type 18 MW Installed Capacity 6.83 Prime Capacity $9,832 MWH Annual 83,125 MWH Annual (Total) (Prime) PROJECT DESCRIPTION CARBON LAKE Site Region S.E. Ident. Community SITKA 50 Operating Life (Years) CONSTRUCTION COST Input $ Outlays Incurred By Year (1000S) Z Generation: 1 2 Reservoirs, Dams, and tiaterw Water Wheels 500 11200 |1200 S25S0F) 400 | 400 Roads, Railroads, and Bridges Engineering 400 }~ Interest During Construction 64] 257} 541 TOTAL 328. Transmission: ———Land_and_Land Rights Right-of-Way Clearing Transmission Lines 0 Switchyards 400 | Substations Indirect Construction Costs ——_—_Interest During Construction 1 230 TOTAL. 3 ‘A ANNUAL PRODUCTION COST Labor 4160 man hrs./yr 104,000.00 Hydro Maintenance @ $0.75/KW 13,500.00 Transmission Maintenance @-$200fmir 400/mi. x 16.5 6,600.00 - ANNUAL FIXED COST Capital Recovery Cost Insurance $1/1000 Taxes TOTAL ANNUAL COST OF PRIME POWER Prime Energy Charge 32.40 Mills/kwh 1,755,480.00 19,200.00 39,874.00 1,938,654,00 Capital cost/prime kw $2,811 Capital cost/installed kw $1,067 erste _Hydro project Type 20MW Installed Capacity 10MW_ Prime Capacity 87,600 MY¥H Annual (Prime) 104,066 myH Annual (Total) —0_ Operating Life (Years) H.4.21 PROJECT DESCRIPTION ~ Site @o) Region S.E. TAKATZ LAKE Ident. Community _SITKA NOTE: Transmission is 20 miles to tie with line from Green Lake @ Bear Cove. A pass at elev. 2855 is the high point of the line. CONSTRUCTION COST input $ Outlays Incurred By Year (1000$) Generation: nie [WES ie A | 5 6. cD, TOTAL ——Land_ and Land Risn=s_ 20} 200 30 | 250 Struc 3s SS Sabs 900 | 900 1,800 Reservoirs, Dams, and liaterways Water Wheels, Turbines, 10,0 1400 {1300 3,200 | 500 | 300 Accessory Electrical Equipment [ 500 ——HMiscellaneous Power Plant Fanionent! alt 200 | 200 400 Roads, Railroads, and Bridges + a BeOLwE pes e200) | 400} 40 ——-Indirect Construction Costs | A ea erent _— 1.990} Engineering 300 | 400 | cox 10 L0UL) BUDiesabstl Reccaultiatd 1,900 Interest During Construction 8 36 Bary en a Oia a oe TOTAL 328 1817717240 ine = Transmission: Land and Land Rights 20. if 250 ——Risht-of-Way Clearing 300 399 2 aie ; 1,600 Switchyards 900 Substations 300 700. Indirect Construction Costs S00 ANNUAL PRODUCTION COST Labor 4160 man hrs./yr. 104,000.00 Hydro Maintenance @ $0.75/KW 15,000.00 Transmission Maintenance @%$200/mi 400/mi x 20 __ 8,000.00 ANNUAL FIXED COST Capital Recovery Cost Insurance $1/1000 Taxes 2,427,150.00 be196-00 TOTAL ANNUAL COST OF PRIME POWER 2,634 ,946. 0¢ Prime Energy Charge 30.08 Mills/kwh Capital cost/prime kw - $2,660 Capital cost/installed kw $1,330 es et -Hydxo project Type ——9MM@ Installed Capacity 4.64MW Prime Capacity 40,640 MWEH Annual (Prime) 40,640 MWH Annual (otal) 59. Operating Life (Years) PROJECT DESCRIPTION Site Region UNNAMED LAKE Ident. Community NOTE: Approximate Chilkoot River Mile 10. CONSTRUCTION COST H.4.22 ; HAINES Input Generation: Land 3 Land Ric: ——Structures and Improvements. Reservoirs, Dams, and Waterw. Vater Wh Turbin n Q ear, Railroads, ant rietacens —_—Engineering Interest During Construction TOTAL Transmission: ——-Risht-of-Way Clearing z Sea ot —___Switchyards Substations Indirect Construction Costs Boci ; POTA CON RUCTION CO ANNUAL PRODUCTION CosT Labor 2080 man hrs./yr.. Capital Recovery Cost Insurance $1/1000 52,000.00 Hydro Maintenance @ $0.75/KW 6,750.00 Transmission Maintenance @ $200/mi 3,100.00 ANNUAL FIXED COST 954,780.00 10,435.00. Taxes 21,568.00 TOTAL ANNUAL COST OF PRIME POWER 1,04g,633.00 Prime Energy Charge 25.80 Mills/kwh Capital cost/prime- kw— $2,249 Capital cost/installed kw $1,159 “HY. 23 ‘ PROJECT DiSCRIPTION Site @) Hydro project Type Region _S82Bo0 5105 o.MW Installed Capacity Ident. Community _SKAGWAY GOAT LAKE 4.45MW Prime Capacity 38.982. MWR Annual (Prime) 38,982 _ MWH Annual (Total) 50 Operating Life (Years) CONSTRUCTION COST Input $ Outlays Incurred By Generation: 2 3 A eee ee n. isnt 50 100 ocrene:! 500} 500 Reservoirs, Dams, and Waterways 900 f Water Wheels, Turbi 200 600 600 Accessory ae a PaO 50 Miscellaneous Power Plant Faninnent 100} 100 Roads, Railroads, and Bridges... —_—-Indirect Construction Costs Tiaaat: 300} 300} _ ie Engineering _300| 300 300 |_ i Interest During Construction 20 PLS 265 | E TOTAL 820}. Transmission: i | ———and_and_ Land Rights 1B 20. Right-of-Way Clearing 100 —____Transmission Lines 230] 380 Switchyards Hl | 200 | 600_ Substations 200. Indirect Construction Costs a i 400 ——-Engineering 5a} 5 is 200 —___Interest_ During Construction A, 20 69 90 TOTAL 1 | 1.290 A 88 895 64 9,140 ANNUAL PRODUCTION COST Labor 1040 man hrs./yr. __26,000.00 Hydro Maintenance @ $0.75/KW 6,750.00 fransmission Maintenance @ $200/mi x 6.5 mi. 1,300.00 ANNUAL FIXED COST Capital Recoverv Cost 834,540.00 Insurance $1/1000 9,140.00 Taxes 18,432.00 TOTAL ANNUAL COST OF PRIME POWER ~896 ,162.00 Prime Energy Charge 22.99 Mills/kwh Capital cost/prime kw $2,054 Capital cost/installed kw §1,016 ~ ~ c= tee es _ © @ ~N a a + w nm . . . . . . . . H.5. SOUTHCENTRAL KEY HYDRO SITES Tebay Lakes Power Creek Sheep River Lakes No Name Lake Solomon Gulch Nellie Juan Lake Snow River Bradley Lake Terror Lake H.5.1 H.5.2 Site G) PROJECT DESCRIPTION -Hyéro project Type Region cs es 64. MW Installed@ Capacity TEBAY LAKES Ident. Community ae 30.15MW : - a Prime Capacity eee Transmission line of 56 miles ties in with the consti’ MaZ Annual (Prine) proposed Valdez to Glennallen transmission line 264,114 yay Annual (Total) at Richardson Highway mile 20. .50 Operating Life (Years) CONSTRUCTION COST . : Inowt $_Outlays Incurred By Year (1000S) ___. Generation: ——Miscellaneons Power Plant § ated Wheels. durhines.& Gane Accessory Electrical Fquipment Roads, Railroads, and Bridges ———.Indirect Construction Costs Engineering Interest During Construction TOTAL Transmission: "and _and_nand Rights ——Risht-of-way Clearing ; Transmission bi ines. Inéirect Construction Costs Engineering Interest During Conct-rction pocar TOTAL CONSTRUCTION COST Labor Hydro ™ aintenance Capital Recovery Cost Insurance Taxes $1/1000 TOTAL ANNUAL COST OF PRIME POWER 8760 man hours/yr. @ $0.75/KW @ransmission Maintenance ANNUAL PRODUCTION 219,000 _ . 48,000.00 @ $200/mi 11,200.00 x 56 mi. ANNUAL FIXED COST 4 911,420.00 ~53,995.00 110,116.00. 535,373.00. ce ey Site @) Region _S,C. Hydro project Type POWER CREEK “e ‘ —_12_nw Installed Capacity 3.225 kw Prime Capacity 32,631 MWH Annual (Prime) 52,472. MWH Annual (Total) 50. Operating Life (Years) Ident. Community Cordova NOTE; Questionable geology on right abutment of dam which was obviously formed by an ancient slide. CONSTRUCTION COST ae Ee (agn0s) 2g Generation: —o Re oirs, Dams, and Waterways 7 Q0 Q — aes Se =a Ory e a Eg pmen 00 -_ ee 7 Pe aa Hs ____Engineering | 400 | 200 | 200 | 200 | | tf a, 000 Interest During Construction 133 310 500 _TOTAL 461 2633 |4910 9,000 Transmission: ———Land_and_ Land Rights 20 Right-of-Way Clearing 50 Transmission Lines seo Switchyards 00 00 700 Substations | 200 | 450 650 Indirect Construction Costs ——_Interest During Construction ake Si 25 110 TOTAL. 2,610 DOTAL CONSTR ON_co 461 | 1078 { 3488 | 6583 11,610 JAL_PRODI Labor 8,760 man hrs./yr. . 219,000.00 HyGro Maintenance @ $0.75/KW 9,000.00 Transmission Maintenance @ $200/mi x 7 mi. 1,400.00 (ANNUAL FIXED COST Capital Recovery Cost Insurance $1/1000 Taxes TOTAL ANNUAL COST OF PRIME Prime Energy Charge 4 1,060,560.00 11,610.00 ——27,333..00 POWER 1,328,903.00 0.73 Mills/kwh Capital cost/prime kw $3,117 Capital cost/installed kw $ 967 2c=>> PROJECT DESCRIPTION Hydro project Type Region s.c 4MW-. «s« Installed Capacity SHEEP RIVER LAKES Ident. Community CORDOVA 2:34 MW Prime Capacity 22,250 MWH Annual (Prime) 22.250 MWH Annual (otal) 50 Operating Life (Years) CONSTRUCTION COST Input. Generation: A, ——_—land_and_ Land Rights ——_Structures and Improvements —__Reservoirs, Dams, and Waterways Water Wheels, Turbines, & Generatorg Accessory Electrical Equipment —__Miscellaneous Power Plant Faninment| Roads, Railroads, and Bridges ____-Indirect Construction Casts. _| Engineering Interest During Construction 8 164 TOTAL | 358 | 86. 4,390 Transmission: ———Land_and_Land_Rights 50. —20 Right-of-Way Clearing 100 150 Transmission Lines 200} 1,000 | Switchyards 150 200 | 150 200 Substations 5 200 Indirect Construction Costs 5 0 400 ——-_Engineering. : < [ soa ——_—_Interest During Construction 2,200 ANNUAL PRODUCTION COST Labor 2,496 man hrs./yr. 62,400.00 Hydro Maintenance @ $0.75/kKW $3,000,090 Gransmission Maintenance @ $200/mi x 17 mi. 3,400.00 ANNUAL FIXED COST eee Capital Recovery Cost ; —606.,300.00 Insurance $1/1000 : 6,590.00 Taxes 14,315.00 TUTAL ANNUAL COST OF PRIME POWER -—696 005.00 Prime Energy Charge 31.28 Mills/kwh Capital cost/prime kw $2,587 Capital cost/installed kw $1,648 | H.5.5 Site () PROJECT DESCRIPTION . Hydro project Type Region _s.c, SMW ss Installed Capacity NO NAME LAKE Ident. Community _CORDOVA 2.55MW_ Prime Capacity 22,338 MNH Annual .(prine) Approximately 2 miles N.E. of the head of Beartrap Bay. D 22,338 «=MWH Annual (Total) Transmission estimated to the lower powerhouse of _50 Operating Life (Years) Sheep River Lakes site 3.5 miles in distance. CONSTRUCTION COST Input Generation: 6 TOTA Str and Improvemen = | 200 | 400 600 Reservoirs, Dams, and Waterways 0 Water Wheels furbines,& Generators 50 650 700 Accesso ectrical Equipmen 200 200 Mis aneo Qwe Plan Bani enti 00 100 Roads, Railroads, and Bridges 50 50 -Ind on ion Ca 00 00 400 Interest During Construction l 2 150 __TOTAL Toe 3,300 Transmission: Land_and Land Rights : 30 Right-of-Way Clearing 20 —__Transmission Lines 200 250 | Switchyards 00 200 Substations Indirect Construction Costs 80 100 : Engineering i 50 nterest During Cons ion 20 OTA Saar eater 670 ANNUAL PRODUCTION COST Labor 2,496 man hrs./yr. 62,400.00. Hydro Maintenance @ $0.75/KW $ 3,750.00 Transmission Maintenance @ $200/mi x 3.5 mi. 0.00 ANNUAL FIXED COST Capital Recovery Cost o 361,326-€0 Insurance $1/1000 3,970.00 Taxes ___ 9,075.00 TUTAL ANNUAL COST OF PRIME POWER 7286.975-00 Prime Energy Charge 12.85 Mills/kwh Capital cost/prime kw $1,557 Capital cost/installed kw $ 794 er =: - PROJECT DESCRIPTION Hydro Project Type SOLOMON GULCH 12MY__—s Installed Capacity 4.44MN Prime Capacity Ident. Community Site G) H.5.6 Region _S.C. VALDEZ 38,877 MwH Annual (Prime) 55,005 mwH Annual (Total) <i OE Operating Life (Years) CONSTRUCTION COST_ Input si Generation: 1 2 ae &. Pa aot wl TOTAL _ ———_Land_and_Land Rights 50 50 ——_Structures and Improvements 105 | 200 | 400 | 705 | Reservoirs, Dams, and Waterways 1000 "2553 1000 3,553 —___Water Wheels, Turbines, & Generatorg 205 | 600 | 900 1,705 e Vv i Equi 70 | 200 270 ——Miscellaneous Power Plant Faninnent} 1 19. Roads, Railroads, and Bridses | 160] | “140 ___-Indirect Construction Casts |_250 | 300 | as s00__| ———Engineering +400 | _275 128 | s00__s! Interest During Construction 54 | 180 | 326 ae 560 i TOTAL 2204 | 3178 | 3280 8,662 _| Transmission: | : | ——Land_and Land Rights 50 50 pean Tae Sa at = ——Transmission Lines 2 1,975 Switchyards 100 00 400 Substations 62 |_ 300 362 Indirect Construction Costs 400 | 475 875 Slane 300 | 300 li -- 600 ——Interest During Construction 88 aco 448 | x Pe af 3600 | 7710 ee eens 2204 | 6778 fL0990 ll 19,972 ANNUAL PRODUCTION COST Labor 4,160 man hrs./yr. Hydro Maintenance @ $0.75/KW Transmission Maintenance @ $200/mi x 104 ANNUAL FIXED COST Capital Recovery vost Insurance $1/1000 Taxes TOTAL ANNUAL COST OF PRIME POWER Prime Energy Charge 53.03 Mills/kwh 104,000.00 $ 9,000.00 20,800.00 1,865 ,340.00 10 42,401.00 2,061.513,.00 Capital cost/prime kw $4,498 Capital cost/installed kw $1,664 PROJECT DESCRIPTION Hydro. Project Type 40M7__ Installed “Capacity 21M Prime Capacity 184,000 mwy Annual (Prime) 184,000 mwH Annual (Total) Za Operating Life (Years) NELLIE JUAN LAKE CONSTRUCTION COST Id ent. Community H.5.7 Site ©) | Region __S.C. SEWARD Input Vv Generation: ‘t J 2. 3 4__}_5 p27 ne TOTAL _ al Land and Land Rights 40| 60] 100 200 Structures-and-tmproverents 100 | 400 | 500 | 1,000 Reservoirs, Dams, and Waterways 7000 | 9000 | 8300 _|__24,300 Water Wheels, Turbinas..&. Genaxatard 200 | 1600 | 3000 [4,800 | Accessory Electrical Equipment t— 100 | 300] 500 { 900 Miscellaneous Power Plant Equipment 1oo | 300 400 —___Roads, Railroads, and Bridges 200 | 1000 1,200 anbipact=conateics tanieanrs [ 500 | 500 | 500 | 500 [= 2,000 Engineering 600 00 | 900} 900 | 4,000 Interest During Construction 16 355 | 920 “1588 2,950 TOTAL 41,750 Transmission : ——Land_and_Land_Rights |. t. 100 Right-of-Way Clearing 250 ———Transmission Lines 500 r {| slo Switchyards 300 500 Substations 50 150 | 200 Soe 400 Indirect Construction Costs 200 10 200 600 bind bine 1 as 1542 3,805 117130 | 45,555 ANNUAL PRODUCTION COST Labor 8,320 man hrs./yr. Hydro Maintenance @ $0.75/KW Transmission Maintenance @ $200/mi x 17 mi. ANNUAL FIXED COST Capital Recovery Cost Insurance $1/1000 Taxes "TOTAL ANNUAL COST OF PRIME POWER Prime Energy Charge 24.47 Mills/kwh 1 i 208 ,000.00 $ 30,000.00 ~~ 3,400.00 4 122,780.00 —45,555.( po 92 7604.0 F502 339.0 ais Capital cost/prime kw. $2,169 Capital cost/installed kw $1,139 ee weect PROJECT DESCRIPTION Hydro project Type fOMY Installed Capacity 31,9MN Prime Capacity 222,000 MY¥H Annual (Prime) 279,000 myH Annual (Total) —50 Operating Life (Years) SNOW RIVER CONSTRUCTION COST H.5.8 Site @) Region el Ident. Community V_sEwarp Input $ Outlays Incurred By Year (1000S) Generation: Pa me | = ——_LIand_and Land Rights — —___Structures and Improvements servoirs, Dams, and Waterw. Water Wheels —___Accessory Electrical Fauipment Roads, Railroads, and Bridges -Indirect Construction Casts 600 Engineering Interest During Construction 14 aes TOTAL, 694 | Transmission: ———Jand_and_Land Rights Right-of-Way Clearing ——__Transmission Lines Switchyards 20! Substations Incirect Construction Costs ——Engineering ____Interest During Construction TOTAL 2 275 1709! 2297 ‘AL Rl 564 a ANNUAL PRODUCTION COST “ Labor 12,480 man hrs/yr. Hydro Maintenance @ $0.75/KW : fransmission Maintenance @ $200/mi x 24 mi. = Capital Recovery Cost Insurance $1/1000 Taxes TOTAL ANNUAL COST OF PRIME POWER Prime Energy Charge 20.66 Mills/kwh 312,000.00 $45,000.00 4,800.00. '5,225,730.00 57,705.00 —~T183550.00 755763 ,785. 00 Capital cost/prime kw $1,809 Capital cost/installed kw $ 962 So ete ee -Hyéxo project Type A25MW Installed Capacity 51.4 MW Prime Capacity 420,000 MWH Annual (Prime) 481,400 mw Annual (Total) ja Or Operating Life (Years) PROJECT DESCRIPTION BRADLEY LAKE Ident. CONSTRUCTION COST H.5.9 Site Region S.C. Community HOMER Input Generation: A it = 6 Zz TOTA Land and Land Rights 20 80 00 200 ____ Structures and Improvements 550 | 1000 | 2000 | 2000 5,550 Reservoirs, Dams, and Waterwa 00 2000 000 000 ____Miiace Lanenua Power -P : Peet eat ee Roads, Railroads and Lda J pre fponJ 2,600 ngineering 11200 ft 7,000 Interest During Construction e={ san aan 100 sale 3080 | 6,035 TOTAL _ 840 80 fees Transmission: ———Land_ang_Land_Rights = 100 ——_Right-of-tlay Clearing 1,000 Transmission Lines 000 000 4,800 Switchyards 2] 600 1,200 Substations 400 000 Indirect Construction Cost: 300 200 800. Engineering 3.94 400 400 : 421 800 TOTAL 4021 11,100 TOTAL CONSTRUCTION CO 840 | 1270 | 6944 20931 B0649 P9201 89,835 JAL_P. T Labor 12,480 man hrs./yr. 312,000,00 Hydro Maintenance @ $0.75/KW $93,730.00 Transmission Maintenance @ $200/mi x 56 mi. Capital Recovery Cost Insurance Taxes $1/1000 ANNUAL FIXED COST TUTAL ANNUAL COST OF PRIME POWER Prime Energy Charge 19.65 Mills/kwh Capital cost/prime ~ Capital cost/ installed 11,200.00 7B,151,750.00 89,835.00 181,829.00 5,840,344.00 kw $1,748 kw $ 719 =ros- Site PROJECT DESCRIPTION H.5.10 -Hy8xo project Type TERROR LAKE Region _S-C. 20M7 . - Installed’ Capacity Ident. Community KODIAK 1.22MN_ Prime Capacity 63,250. MwH Annual (Prime) 100,740 mwH Annual (Total) 50 Operating Life (Years) CONSTRUCTION COST Input $ Outlays Incurred By Year (1000$) __. Generation: iat By | 3 al 4 5 6 2 TOTAL Land and Land Rights 20 80 | 100. ——__Structures and Improvements 100011000 2,000 Reservoirs, Dams, and Waterways 4000 1.2000 6000 22,000 Water Wheels, Turbines t 225 {| 800 | 1500 2,525 Accessory Electrical Equipment 50 | 150 | 400 _600 ! Misceilaneaus Pawer Plant Eauipmen 50 | 100 | 200 350-4 Roads, Railroads, and Bridges 1000 | 500 | 1,500 | Indirect Construction Casts 300 | 300 | 400 | 400 | La, 40001) Engineering 500 | 500 {| 600 | 700 | 700 | de ! 3,000 ri Interest During Construction 13 Bl 263 | 785 | 1416 | a | 2,250 ! TOTAL 533 | 1953 | 5988 [5935 1616 36,025 1} Transmission: —____Land_and_Land_Rights 30.1 __.20 : a0 Right-of-Way Clearing | 200 200 Transutesien Lines | 140 | 600 | 700 1,440 Switchyards 100 | 300 | 500 900 Substations 100 | 200 | 400 700 Indirect Construction Costs | 100 | 200 | 200 500 f Engineering 50|_ 50; 100} 100 300 ——_Interest During Construction 2 22 75 | _ 156 255 ae 82 |° 732 [1475 | 2056 4,345 TOTAL CONSTRUCTION cost 533.|: 2035. aa 13672 40,370 ANNUAL PRODUCTION COST Labor 8,320 man hrs./yr. 208,000.00 Hydro Maintenance @ $0.75/KW $15,000.00 Transmission Maintenance @ $200/mi X 18 mi. 3,600.00 ANNUAL FIXED COST Capital Recovery Cost 35659,370.00 Insurance $1/1000 40,370.00 Taxes 82 2453.00 TOTAL ANNUAL COST OF PRIME POWER 4,008..793.00 Prime Energy Charge 63.38 Mills/kwh Capital cost/prime kw $5,591 Capital cost/installed kw $2,018 JOINT ACTION POWER SUPPLY PROGRAMS ARE ADVANCING More publicly owned systems are working together in planning future generating capacity The growing trend to joint action power supply programs among the Nation’s local publicly owned electric utilitics accelerated and intensified during the past year. A joint action report in PUBLIC POWER a year ago (Sept.-Oct., 1974) identified some 45 joint action power programs and projects of local public power systems. A new map (see front cover and following page) shows 55 programs and projects, but this only reficcts a portion of the increasing recognition among local publicly owned utilitics of the benefits of working together in planning to mect their sys- tems’ future power requirements. In at least five states, legislation was enacted authorizing municipal utilitics to enter into various types of joint action arrangements and led to the creation of new organizations of municipal electric utilitics. The new joint action groups include: » Municipal Electric Authority of Georgia, including 49 local publicly owned systems, is launching a program expected to provide a million kw of capacity and expenditures of $1-billion in the next few years. e Louisiana Municipal Power System is a statewide organization formed to plan future joint action programs, and Louisiana Municipal Power Commission is a five-city group planning a 115,000-kw, gas synthesis combined cycle station. e Texas Municipal Power Agency, organized by four Texas municipal systems, will join with a cooperative to form the new Texas Power Pool, Inc., replacing the former Texas Municipal Power Pool. Through the new Agency and Pool, the cities and co-op will jointly finance and construct a $5-billion generation and transmis- sion expansion program over the next 15 years. e Nebraska Municipal Power Pool will be a joint action organization for the State's municipal electric utilities. e Wyoming Municipal Power Agency, representing most of the State’s municipal electric systems, was formed, and a second group, Wyoming Municipal Electric Joint Powers Board, is being organized and will be a participant in the Laramie River Station in southeastern Wyoming. Ina number of other states, joint action legislation supported by municipal electric utilities was defeated by the opposition of private power companies, but the publicly owned systems will continuc to press for needed authorizing legislation. A major joint action power supply development this year has been the purchase of shares in private power company nuclear generating stations by groups of municipal electric systems in Massachusetts and Florida. The Chicopee, Mass., Light Board, acting for itself and 12 other Massachusetts municipal utilities, in January sold a $26.1-million revenuc bond issuc to finance the purchase ot a 3.207% ownership share in the 1,150-mw Millstone No. 3 nuclear generating unit, now under construction in Waterford, Conn., by Northeast Utilities. In August, 10 Florida municipal systems and a rural clectric cooperative pur- chased a 10% share in Florida Power Corporation's Crystal River No. 3 plant, an 825-mw nuclear facility. The new Municipal Electric Authority of Georgia and several other joint action groups also arc planning the purchase of shares in future nuclear units. PUBLIC POWeER'S third annual “Directory of Local Public Power Organizations with Joint Action Power Supply Programs and Projects,” beginning on page 22, documents the growth of joint action efforts for future power supply in every region of the country. 2) JOINT ACTION POWER SUPPLY PROGRAMS AND PROJECTS Key to Joint Action Map 3. 4. 5. 6. 7. 8. 9. 10. 1M. 12. 13. 14. 15. 16. 7. 18. 19. 20. NEW ENGLAND POWER POOL MASSACHUSETTS MUNICIPAL \WWHOLESALE ELECTRIC CO. CONNECTICUT MUNICIPAL ELECTRIC UTILITIES E TRICITIES OF NORTH CAROLINA ELECTRIC POWER IN CAROLINA (EPIC) PIEDMONT MUNICIPAL POWER SYSTEMS OF SOUTH CAROLINA MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA CRYSTAL RIVER GROUP KISSIMMEE-ST. CLOUD TIE TENNESSEE VALLEY PUBLIC POWER ASSOCIATION AMERICAN MUNICIPAL POWER-OHIO AMERICAN MUNICIPAL POWER-INDIANA KENTUCKY-INDIANA MUNICIPAL POWER ASSOCIATION MICHIGAN MUNICIPALS AND COOPERATIVES POWER POOL CARLYLE-BREESE TIE RIVER CITIFS GROUP WISCONSIN JOINT ACTION COMMITTEE KAUKAUNA-MENASHA TIE MISSOURI COMMISSION FOR MUNICIPAL POOLING SERVICES SOUTH IOWA MUNICIPAL ELECTRIC COOPERATIVE ASSOCIATION - NORTH IOWA MUNICIPAL ELECTRIC COOPERATIVE ASSOCIATION . WESTERN IOWA MUNICIPAL ELECTRIC COOPERATIVE ASSOCIATION . MISSOURI RASIN MUNICIPAL POWER AGENCY . HEARTLAND CONSUMERS POWER DISTRICT » COOPER NUCLEAR STATION 26. 27. 29. 30. si. 32 33. 34. 33. 36. 37. 38. 39. 40. 41. 42. 43. 44. 4s. 46. 47. 48. 49. 50. St. $2. 53. $4. 55. 1.2 FORT CALHOUN NUCLFAR STATION NEBRASKA MUNICIPAL POWER POOL GERALD GENTLEMAN STATION BASIN ELECTRIC POWER COOPERATIVE MID-WEST ELECTRIC CONSUMERS ASSOCIATION MISSOURI BASIN SYSTEMS GROUP LARAMIE RIVER STATION WYOMING MUNICIPAL ELECTRIC JOINT POWERS BOARD KANSAS MUNICIPAL UTILITIES, INC. - EASTERN KANSAS POWER AGENCY NORTH CENTRAL KANSAS POWER AGENCY NORTHWEST KANSAS POWER AGENCY SOUTH CENTRAL-SOUTHWEST KANSAS POWER AGENCY CHANUTE-COFFEYVILLE TIE HAYDEN GENERATING STATION YAMPA PROJECT PLATTE RIVER POWER AUTHORITY NORTH CENTRAL OKLAHOMA MUNICIPAL POWER POOL TEXAS POWER POOL LOUISIANA MUNICIPAL POWER SYSTEM LOUISIANA MUNICIPAL POWER COMMISSION INTERMOUNTAIN CONSUMER POWER ASSOCIATION INTERMOUNTAIN POWER PROJECT NORTHWEST PUBLIC POWER ASSOCIATION PUBLIC POWER COUNCIL WASHINGTON PUBLIC POWER SUPPLY SYSTEM NORTHERN CALIFORNIA POWER AGENCY MOHAVE POWER PROJECT NAVAJO GENERATING STATION ARIZONA POWER POOLING ASSOCIATION foe ohne si erretaees a Meets 1.3 DIRECTORY OF LOCAL PUBLIC POWER ORGANIZATIONS WITH JOINT ACTION POWER SUPPLY PROGRAMS AND PROJECTS D a = Northeast MASSACHUSETTS MUNICIPAL WHOLESALE ELEC- tric Co., 11 Goldsmith St., Littleton, Mass., 01460, 617/486-3163, Robert W. Feragen, gen. mgr.; F. H. King, Holyoke, Mass.. pres.; Michael F. Collins, Wakefield, Mass., treas.; James E. Baker, Shrewsbury, Mass., chairman of the Board of Directors. NORTHEAST PUBLIC POWER ASSOCIATION, 9 Goldsmith St., Littleton, Mass. 01460, 617/486-3508, H. E. Erickson, gen. mgr.; Pierre J. Heroux, Littleton, Mass., pres.; Cur- tis J. Lanciani, Paxton, Mass., first vice pres.; Guy Thomas Pilla, Sr., Wallingford, Conn., second vice pres.; Virgil W. Liberty, West- field, Mass. sec.; Julio H. Leandri, Groton, Conn., treas. Massachusetts Municipal Wholesale Elec- tric Co., a pioneering joint action power supply program of Massachusetts munici- pal electric systems, is moving ahead rap- idly on several fronts. Highlights of recent MMWEC progress include these unprece- dented developments: © Sule of the State's first municipal elec- tric revenue bond issue to enable 13 parti- cipating Massachusetts municipal systems to acquire ownership share in a large nu- clear generating unit. © Introduction of emergency legislation to convert MMWEC into a public corpora- tion. © Acquisition of the 450-acre Stony- brook site in Ludlow, Mass., the first step in a two-stage, 390,000-kw generating plant construction program. In January, the Chicopee, Mass., Light Board, acting for itself and 12 other muni- cipal systems, accepted a negotiated bid for a $26.1-million revenue bond issue to fi- nance purchase of a 3.207% ownership share in the 1,150-mw Millstone No. 3 nuclear generating unit, now under con- struction by Northeast Utilities in Water- ford, Conn., with operation scheduled in 1979. Chicopee will own 1.35% of the plant, and the other 12 municipal utilities will have varying smaller shares. Studies of the cost of power from the nuclear plant to the municipal systems— ranging from 17.2 mills per kwh to 18 mills—indicate savings of up to 30% from the average delivered cost of power pur- chased under existing rates. The Millstone unit financing was nego- tiated by MMWEC, but the actual bond sale was consolidated under the leadership of Chicopee because MMWEC lacks au- thority to scll revenue bonds. To enable MMWEC to finance its future program, a bill has been introduced in the Massachu- setts Legislature to make MMWEC a pub- lic corporation. The measure, endorsed by Governor Michael Dukakis, carries an emergency clause stating that the legisla- tion is needed “to permit MMWEC im- mediately to pursue opportunities to fi- nance electric power facilities. . . .” MMWEC in September completed a Iease-purchase agrcement for the Stony- brook site near Westover after a year of study and negotiation. The 450-acre tract on the former Westover Air Force Base will be the site of MMWEC's first generating facilities: a 270.000-kw combined cycle unit scheduled to be in operation in 1981 and 120,000 kw of gas turbine peaking capacity listed for service in 1982. Meanwhile, public support is mounting to give the State of Massachusetts a role sock na teaerecbaci— ta he, in future power supply. An initiative peti- tion calling for the establishment of a Massachusetts Power Authority to build and operate all new generating capacity and transmission facilities in the State was filed last December with more than 90,000 signatures (56,038 were required). The ini- tiative petition was filed by a 12-member group headed by Rep. Michael J. Harring- ton (D., Mass.), and including former American Public Power Association presi- dent Michael J. Collins, manager of the Wakefield, Mass., Municipal Light Depart- ment, and an officer of MMWEC. Under the Massachusetts initiative procedure, the petition went to the Legisla- ture for action by a deadline of May 7. When the Legislature under strong pressure from private power company lobbyists did not act favorably by the deadline, initiative sponsors moved to get the Power Authority proposal on the Nov., 1976, general elec- tion ballot. With fewer than 10,000 addi- tional signatures required, the sponsors filed petitions with 22,500 names on July 1. To no one's surprise, the State’s private power companies have announced that they plan an all-out media campaign against the Power Authority plan. = Atlantic ELECTRICITIES OF NORTH CAROLINA, 1526 Glenwood Ave., Raleigh, N.C. 27608, 919/835-2531, Marshall Lancaster, excc. dir.; Mayor Edward C. Smith, Lexington, N.C., pres.; Mayor Fred L. Harrison, Scotland Neck, N.C., first vice pres.; Bruce Boyette. Wilson, N.C., second vice pres.; David Tay- lor, Tarboro, N. C., sec.-treas. Epic, INC., (Electric Power In Carolina), Box 751, Raleigh, N. C. 27602, 919/833-2821; Mayor Simon C. Sitterson, Jr., Kinston, N. C., pres.; Alton P. Wall, Randolph EMC, Asheboro, N.C., first vice pres.; L. C. Wil- liams, Jr., High Point, N. C., sec.; Cecil Viver- ette, Blue Ridge EMC, Lenoir, N.C., treas. POWER SEP.TEMBER-OCTOBER 1975 " " b a SOUTIE CAROLINA ASSOCIATION OF MUNICIPAL POWER SYSTEMS, Houston F. Crater, Jr. Box 64, Gaffney, S.C. 29340, chairman: Douglas Beck, Rock Hill, S.C., vice chair.; Sam Wallace, Laurens, S.C., sec.-treas. MUNICIPAL ELECTRIC AUTHORITY OF GFORGIA, Suite 220, 10 Pryor Street Bldg., Atlanta, Ga. 30303, 404/688-0472: W. R. Clayton, Thomasville, Ga., chairman; Gayle Manley. Albany, Ga.. vice chair.; H. Bruce Lovvorn, La Grange, Ga., sec.-treas. Municipal electric utilities, many of which have been purchasing their power at whole- sale from private companies, will own their own shares of several new power company nuclear plants in the Southeast under plans announced in recent months. Ten Florida municipal systems and a rural electric generation and transmission system have purchased a 10% share in Florida Power Corporation's Crystal River No. 3 plant, and a new agency—Municipal Electric Authority of Georgia—is planning to acquire ownership shares in two Georgia _ Power Co, nuclear plants as a major part of a $1-billion-plus gencrating and trans- mission program. ‘The purchase of an $2.500-kw, 10% share in the $25,000-kw Crystal River unit came after Florida Power Corp. suspended work on the 90% completed facility last year because the company could not raise the capital necded to complete the plant. With the sale of 10% of the unit for $38,- 491,034, completion is now scheduled for next fall. Ten Florida municipal electric utilities and a rural electric cooperative have purchased a 10% interest in Florida Power Corporation's Crystal River No. 3 unit. above. which is scheduled to come on the line next year. Municipal systems’ shares in the Crystal River capacity and cost are: Orlando, 13,- 210 kw, $6,164,339; Gainesville. 11,610 kw, $5.419,153; Tallahassee, 10,900 kw, $5,132,010; Ocala, 10,900 kw, $5,132,010; Leesburg, 6,300 kw, $3,173,201: Kissim- mee, 5,570 kw, $2,599,684: New Smyrna Beach, 4,620 kw, $2,158.577; Sebring, 3,- 690 kw, $1,721,704: Alachua, 640 kw, $299,845; and Bushnell, 320 kw, $149,345. Seminole Electric Cooperative. represent- ing 1} rural! electric distribution systems, acquired 14,020 kw for $6.541.166. Participation in Crystal River was only one of four offers made to municipal elec- tric systems by Florida Power Corp. ata meeting in St. Petersburg early this year. The company also offered to sell 10% of the oil-fired Anclote unit No. 2 (S32-mil- lion) six regenerative cycle units at its Debary site ($6.8-million) and participa- tion in two other nuclear units scheduled to be completed in the mid-1 980s. The Crystal River unit was the only project to reccive sufficient interest to proceed with negotiations. The municipal sharing in the company project was made possible by the approval by Florida voters of a Constitutional 22 PUBLIC amendment last November with a 56° favorable vote. The amendment modified a restriction on joint ownership by municipal utilities and private companies. Legislation implementing the amendment was adopted earlier this year, but it only authorizes mu- nicipal utilities to participate on an individ- ual basis with companies. A bill supported by the Florida Municipal Utilities Ass tion to authorize joint power authorities was not approved. so each municipal util- ity must finance its individual share of a facility as was done in the Crystal River purchase. In Georgia, a bill signed into law last March by Governor George Busbee has launched a municipal power supply pro- gram expected to approach one-million kw of capacity ata cost in excess of $1-billion. The historic legislation created the Munici- pal Electric Authority of Georgia. which is emp. red to construct and operat oT ata teansmission factlities, to provide elec: »ower supply to Georgia commu- nities sad to issue revenue bonds. Power planning by the new MEAG has moved rapidly. The Authority expects to acquire a 17.6% interest in Units | and 2 of Georgia Power Company's Edwin I. POWER SEPTEMBER-OCTOBER 1975 Hatch Nuclear Plant (the first 786-mw unit is scheduled for operation this year and the second in 1978) and 30% shares in Units 1 and 2 of Georgia Power's Alvin W. Vogtle, Jr., Plant, which is being planned for later construction with 1,113-mw units. This generating capacity and transmission facilities to deliver the power to Georgia municipal electric utilitics will require ex- penditure of more than $1-billion. The contracts which MEAG is entering into with 48 municipal systems and Crisp County Power Commission are all-require- ments agreements with two exceptions: the system's own generation (only Crisp County has generation) and power re- ccived from the Department of Interior's Southeastern Power Administration. Par- ticipating systems may obtain supplemental bulk power supply from other sources upon giving notice of from two to nine years, de- pending upon the amount involved. It is now expected that MEAG may en- ter the bond market as early as next spring, barely a year after the enactment of its au- thorizing legislation. Joint action in opposing wholesale rate increases recently paid handsome dividends for 36 municipal electric utilities in North and South Carolina. The systens will re- ceive credits totaling $7.7-million over the next three years from Duke Power Co. un- der a settlement approved by the Federal Power Commission. Piedmont Municipal Power Systems of South Carolina. representing Duke Power wholesale customers in South Curolina, joined with ElectriCities of North Carolina in the case which covered three rate in- creases filed by the company over a period of five years. Under the terms of the settle- ment, which also included $3.7-million in credits to rural electric cooperatives, the consumer-owned utilities agreed to drop court and regulatory commission actions against Duke Power. Joint action legislation developed by the Municipal Electric Power Association of Virginia was introduced in the Virginia General Aysembly this year and was as- Signed for study and further consideration MENt year. : = East South Central TENNESSEE VALLEY PUBLIC POWER ASSOCIA- TION, 325 Pioneer Bunk Bldg., Chattanooga, Tenn. 37402, 615/267-6511, J. Wiley Bowers, exec. dir.; Marshall Mulherin, Southwest Ten- nessee EMC, Brownsville, Tenn.. pres.: Charles H. Dean, Jr., Knoxville, Tenn., vice pres.; Edward E. Cobb, Huntsville, Ala., sec.- treas. A majority of the East South Central re- gion’s consumer-owned electric systems arc distributors of Tennessee Valley Authority power and purchase their total require- ments from TVA. Working together in the Tennessee Valley Public Power Associa- tion, the municipal and cooperative distrib- utors of TVA power negotiate jointly with TVA on rates and service arrangements. Elsewhere in the region, systems pur- chasing their power requirements from privatcly owned utilities have joined to- gether in contesting proposed wholesale rate increases at the Federal Power Com- mission. = East North Central AMERICAN MUNICIPAL POWER-OHIO, INC., 319 E. Water St., North Baltimore, Ohio 45872, 419/257-7893, R. Powers Luse, mgr.; Joha Engle, Hamilton, Ohio, pres. < AMERICAN MUNICIPAL POWER-INDIANA, INC., 319 E. Water St.. North Baltimore, Ohio 45872, 419/257-7893, R. Powers Luse, mgr.; Irving A. Huffman, Richmond, Ind., pres. KENTUCKY-INDIANA NUNICIPAL POWER ASSO- ClaTION, $11 Fourth St., Huntingburg, Ind. 47542, 812/683-2211, Loma Wm. Hartke, exec. sec.: Mitchell W. Tinder, Frankfort, Ky., pres. e MUNICIPAL, ELECTRIC UTILITIES OF WISCONSIN, 997 Warner St., Columbus. Wis., 414/623- 4184, Donald L. Smith, excc. dir.; Robert D. Uuley, Richland Center, Wis., pres.: Ernest J. Mullen, Kaukauna, Wis., first vice pres.; Wil- liam Baudhuin, Sturgeon Bay, Wis., second vice pres.; Robert O. Stuhlmacher, Wisconsin Rapids, Wis., sec.-treas. Participation in private power company nu- clear plants is only one of several bulk power supply alternatives being considered by the Board of Directors of the Kentucky- Indiana Municipal Power Association. KIMPA is a two-state municipal electric utility organization including seven svs- tems: Frankfort and Paris, Ky., an fordsville, Ferdinand, Huntingburs, and Washington, Ind. The KIMPA group hus an option aire chase a 6.64% share of Public Ser; NORTH CENTRAL Company of Indiana's Marble Hill Nuclear Power Station, but financing must be ini- tiated by Dec. 1. Marble Hill will have two 1,112-mw units, one due in 1982 and an- other the following ycar. KIMPA is scek- ing approval for its revenue bond financing from the Public Service Commission of Indiana and will file a test case in Ken- tucky. . Other KIMPA power supply alternatives include construction of combustion genera- tion and two different sources of hydro. KIMPA has intervened at the Federal Power Commission sevking hydroclectric power trom two Army Corps of Engineers dams on the Ohio River, and the Associa- tion is negotiating with the Southeastern Power Administration for hydro from a pe lies ey RW a eR NS © [ project on the Cumberland River. In Wisconsin, a “Reconnaissance Power Supply Study” was issucd last year for the Joint Action Committec of the State's mu- nicipal and rural electric systems. During the past year, a “G & T Committee” has been studying the report, and results will be presented at a mecting in mid-October. Steps to implement the Reconnaissance Study may be taken at that time. American Municipal Power-Ohio hus the same problem facing several other munici- pal joint action power groups—getting au- thority to act as an agency with the powers of its individual constituent members. Legislation to do this is being drafted and is expected to be introduced in the Ohio Legislature this year. Last year, AMP-Ohio negotiated an agreement with Ohio Power Co. under which Ohio municipal electric utilities can interconnect their facilities with the power company at various locations where the size and other characteristics of municipal electric loads meet “mutually agreeable standards.” The first interconnection under this agreement—between the Orrville, Ohio, Municipal Utilities system and Ohio is nearing completion. The interconnected southern Mlinois municipal systems of Breese and Carlyle (PUBLIC POWER, Sept.-Oct., 1973, p. 30) have obtained an emergency interconnection with Hlinois Power Co, Signing the agreement were Mayor Leo Davis, left, of Carlyle and Mayor Wilfred Hilmes of Breese. Looking on were Carlyle ‘wtility superintendent Virgil Bush, left, and superintendent Martin Jolinson of Breese. In northern IIlinois, a group of seven municipal electric systems which purchase power at wholesale from Commonwealth Edison Co. have formed the River Cities Group and currently are engaged in a year- long fight against a 60% wholesale rate in- crease proposed by the company. The cities are Batavia, Geneva, Naperville, Rochelle, Rock Falls, St. Charles and Winnetka. Two systems—Rochelle and Winnetka —have generation, and the Group has considered alternate sources of power. = West North Centrai MID-WEST ELECTRIC CONS: Suite 300, Executive Offi. Colo. 80439, 303/674-66 d G. Simon- ton, exec. dir.: Loren Zin, -.:k, Madison, S.D., pres.; James McNear Siesling, Colo., vice pres.; Louis Stroup, Jr.. McPherson, Kan., sec.-treas. + 2S \SSOCIATION, z., Evergreen, MISSOURI BASIN SYSTEMS GROUP. No. 6, 10210 W. 26th Ave., Lakewood, Colo. 80215, 303/ 232-3663. Robert O. Marritz. exec. dir. and staff counsel; Dennis Lindberg, Odebolt, Towa, chai N. D., vice chair.; Darrell Frankson, Water- town. S. D., treas.; Wendell Garwood, Tri- State G & T, Northglenn, Colo.. sec. MISSOURI BASIN MUNICIPAL POWER AGENCY, 309 S. Duluth Ave., Sioux Falls, S. D., 57104, 605/338-4042, Arie Verrips, gen. mgr.; Leo Miller, Lenox, Iowa. pres.; Earl LaMaack, Alexandria, Minn., first vice pres.: William G. Tobin, Rock Rapids, Iowa, second vice pres.: Allen Roos, Orange City. Iowa. sec.-treas. HEARTLAND CONSUMERS POWER DISTRICT, Lock Drawer E, Madison, S. D. $7042. 605/256- 4536. Loren Zingmark, gen. mgr. 3 NORTH [OWA MUNICIPAL ELECTRIC COOPFRA- TIVE ASSOCIATION, Claude W. Lines. Municipal Light and Power, Grundy Center, lowa $0638, 319/824-5208, pres.; Lyle Hartwig, Municipal Light and Power Plant, Laurens, Towa, sec.; Floyd F. Robertson, Municipal Light Plant, Sumner, lowa, treas. SOUTH IOWA MUNICIPAL ELECTRIC COOPERA- TIVE ASSOCIATION, John H. Harrison, Indian- ola, Towa $0125, 515/961-5710, pres.; Frank Meyer, Stuart, lowa, vice pres.; Delmer Miller, Fontanelle, lowa, sec. WESTERN IOWA MUNICIPAL ELECTRIC COOPERA- TIVE ASSOCIATION. Orval Fink, Manning, Ia., 5145S, 712/653-1321, pres.; Edmund Radke, Aurelia, la., sec. KANSAS MUNICIP McPherson, Kao Stroup, Jr., exec Wichita, Kan., pre’) A. Wilson, Tola, Kan., pres.-clect; Cy Roi, McPherson, Kan., first vice pres.: Bill Owens, Wamego, Kan., second vice pres.; Henry Crosby, McPherson, Kan., sec.-treas. “tiITIES, INC., Box 47, +9, 316/241-1423, Louis john Wynkoop, EASTERN KANSAS POWER AGENCY, Ron Reed, Chanute, Kan., pres.; John Elder, Winfield, Kan., vice pres.; J. A. Wilson, Iola, Kan., sec.-treas. NORTH CENTRAL KANSAS POWER AGENCY, Rob- ert Leach, Belleville, Kan., pres.; Charles Ellis, Clay Center, Kan., vice pres.; Clarence Beck, Mankato, Kan., sec.-treas, NORTHWEST KANSAS POWER AGENCY, Norman L. Sharp, Sharon Springs, Kan., pres.: Phil Lesh, Norton, Kan., first vice pres.; Al Gerst- ner, Colby, Kan.. second vice pres. Schnose, Hays, Kan., sec.-treas. COMMISSION FOR MUNICIPAL. POOLING SERV- Ices, 308 High St., P. O. Box 401, Jefferson City, Mo. 65101, 314/635-4526, Wendell Locke, acting gen. mgr.; Keith D. Beardmore, Chillicothe, Mo., chair.; Earl Switzer, Macon, Mo., first vice chair.; Lowell Anderson, Car- rollton, Mo., second vice chair.: James Whit- ney, Trenton, Mo.. sec.-treas. NEBRASKA MUNICIPAL POWER POOL, 1320 J. St., Lincoln. Neb. 68508, 402/477-5244, L. E. Voss. interim coordinator. (In process of or- ganization.) Joint action for power supply in Nebraska includes a new organization—Nebraska Municipal Power Pool—and a new dimen- sion—international power exchange. The Pool is being organized under the sponsorship of the League of Nebraska Municipalities, but an independent, non- profit corporation is to be formed. Next step is appointment of a manager. The international joint action was dis- closed in August when it was announced that Nebraska Public Power District has signed a Memorandum of Understanding 24 PUBLIC POWER SEPTEMDER-OCTOBER 1975 ‘" with Manitoba Hydro of Winnipeg, Man., Canada, looking toward seasonal exchanges of power and energy. NPPD has excess power available during the winter, while Manitoba Hydro has surplus power during the summer. Dec. | is the target date for completion of an economic feasibility study which will consider costs and benefits of the international interconnection. If feasibility is estublished, the publicly owned utilities expect to enter into an * agreement by Feb. 1, 1976, under which they will scek the necessary approvals from governmental agencies, enter into contracts for the construction of facilities und imple- ment a plan for exchanging power and energy. “Power and energy could be avail- able to other utilities in the areas adjacent to the proposed transmission facilities in North and South Dakota,” an NPPD an- nouncement said, adding, “The anticipated plan could prove beneficial to not only the power needs of the two sponsoring utilities” customers but would provide an economic benefit to hoth the Dakotas.” Within Nebraska, NPPD has a number of major projects involving joint action. The District's $00-mw Cooper Nuclear Sta- tion on the Missouri River near Brownville, Neb., is in operation with 50% of the power being used by Iowa Power & Light Co.. and 12.5¢¢ by Lincoln Electric Sys- tem. The 650-mw, coal-fired Gerald Gen- tleman Station, near Sutherland, Neb., is being built by NPPD with 25¢¢ of the power in the first unit assigned to Omaha Public Power District. NPPD plans another 650-kw, fossil-fired unit to be in operation in 1980 with shares in the output being offered to other public bodies. OPPD is constructing a 575-mw. fossil- fired unit at Nebraska City, and NPPD will purchase 25% of the output for 10 years. The 1,150-mw Unit 2 at OPPD's Ft. Cal- houn Nuclear Station, scheduled to come on the line in 1983, will be shared 40% each by OPPD and NPPD, with 20% avail- able to other systems. Further down the line, NPPD is studying a possible 1,000-mw to 1,200-mw pumped storage project on the Missouri River in northeastern Nebraska for the carly 1980s, with OPPD and perhaps other systems sharing in the plant. Also in the early stages is a 1.150-mw plant to be completed by NPPD in 1986, and discussions have been held with other utilties concerning purchase of power or co-ownership. “Pooling our energy capubilities is the only way we can hold down costs to the consumer in this time of rising fucl rates.” declared Keith D. Beardmore. chairman of the Commission for Municipal Pooling Services in announcing that the Missouri group had voted unanimously to launch a statewide feasibility study as a first step in developing a municipal power pool. The Commission action came after pri- vate power company lobbyists had again frustrated the efforts of Missouri municipal electric utilities to obtain legislation au- thorizing joint financing of power facilities. The Missouri systems have the power to ac- quire or construct facilities jointly, but a majority vote in each participating commu- nity is required for bond issue approval. Private power company lobbyists also en- joyed a successful year in the Kansas Legis- lature. For the third consecutive year, a bill sponsored by the Kansas Municipal Util- ities to authorize municipal power agencies was defeated. KMU officials warned that failure to pass this legislition “means the majority of the municipal systems will be out of the power supply business in the very near future,” and explained, “Lack of natural gas and the skyrocketing cost of supplemental fuels demand that the muni- ae. 1.7 cipal systems participate jointly in nuclear or coal-fired facilities, but to-date the pri- vate companies have successfully blocked all attempts to gain such legislation.” In northwest Iowa, four municipal sys- tems have formed the Western lowa Muni- cipal Electric Cooperative Association and become a full service member of North lowa Power Cooperative, which will be re- sponsible for the four systems’ power sup- ply and transmission. The municipal sys- tems forming WIMECA are Aurelia, Hin- ton, Manning and Onawa. = West South Central NORTH CENTRAL OKLAHOMA MUNICIPAL POWER POOL, James R. Willis, Box 350, Blackwell, Okla. 74631, 405/363-3282, pres. TEXAS MUNICIPAL POWER AGENCY, Box 6296, Waco, Texas, 817/776-4100, Paul R. Cun- ningham, exec, dir.; Charles E. Duckworth, Garland, Texas, pres.; Carl Williamson, Greenville, Texas, vice pres.: Travis Bryan, IIL, Bryan, Texas, sec.-treas. LOUISIANA MUNCIPAL POWER SYSTEM, Roy C. Lange, Monroe, La. 71201, 318/325-0674, pres.; Wade Use, Houma, La., vice pres.; Ben Clary, Ruston, La., sec.-treas. LOUISIANA MUNICIPAL POWER COMMISSION, Mayor Warren J. Harang. Jr., Thibodaux, La., chair.: Mayor W. Ray Scott, Natchitoches, La.. first vice chair.; Mayor J. M. Fernandez. Franklin, second vice chair.; Mayor Joe Powers, Opelousas, sec.: Mayor C. R. Brownell, Morgan City, treas. Legislation authorizing municipal joint ac- tion power agencies wits approved this year in both Texas and Louisiana with imme- diate results. In Texas, the 12-year-old Texas Municipal Power Pool has been re- organized to launch a $5-billion-plus, 15- year power construction program. In Louisiana, a statewide municipal power sys- tem has been formed. and five municipal utilities have announced plans for joint con- struction and operation of a 115,000-kw, gas synthesis, combined-cycle generating plant. Since 1963, the Texas Municipal Power Pool has saved millions of dollars for con- Linens Ee ROW CONTE ER AeTNe ER LOTS | Corner ers ame mewerrentare- ap ectnmw emia a ree otis r , eh 1 SND 89 ENT GTI HMRI Z NS WEST SOUTH CENTRAL sumers of the municipal systems of Bryan, Denton, Garland and Greenville and co- operatives served by the Brazos River Elec- tric Power Cooperative. Now, however, the five systems with a total capucity of slightly more than I-million kw face the need for expanding their generation six-fold by 1990 and expenditures of more than $5- billion. To meet this challenge, the cities have formed a new organization—Texas Municipal Power Agency—which will fi- mance gencrating und transmission facilities for the municipal utilities. The new Texas Municipal Power Agency will join with Brazos River Electric Coop- crative to form the Texas Power Pool, Inc., which will be the operating agent for the Municipal Power Agency and the coopera- tive. A variety of new generating facilities already are in various stages of planning for the new Pool. They include a share of a power company nuclear plunt, a share ina cooperative lignite-fired plant and a Pool- constructed lignite station, a pumped stor- age project and a nuclear plant. * Although the former Municipal Power Pool saved consumers millions of dollars. participants believe the benefits of the new Agency and Pool in the next decade or so will be measured in billions of dollars. In Louisiana, nine municipal electric sys- tems have organized the Louisiana Munici- pal Power System, and it is expected that other municipal utilities will join the char- ter members. LLMPS president Roy C. Lange, general manager of the Monroc Utilities Commission, said that “one of the purposes of the organization is the develop- ment of plans for joint ownership of elec- tricity production and transmission.” Meanwhile, a group cf five Louisiana municipal systems—Franklin. Morgan City, Natchitoches, Opelousas and Thibo- daux—have formed the Louisiana Munici- pal Power Commission and are planning a pioncering gencrating plant. The 115,000- kw, gas synthesis, combined-cycle unit would burn high sulfur content fuel and meet environmental regulations by recy- cling the waste gas with the synthesis gas process. = Mountain INTERMOUNTAIN CONSUMER POWER ASSOCIA- TION, Box BB, Sandy, Utah 84070, 801/255- 2903, Joseph C. Fackrell, exec. dir.: Glen P. Willardson, Richfield, Utah, pres.; Reece Niel- sen, Hyrum, Utah, vice pre: arry Field- sted, Altamount, Utah, treas.: Ray Farrell, Heber, Utah, sec. INTLRMOUNTAIN POWER PROJFCT. Box BB, Sandy, Utah 84070, 801/255-2903, Joseph C. Fackrell, pres.: Gordon W. Hoyt. Anaheim, Calif., vice pres. PLATTE RIVER POWER AUTHORITY, 700 Wood St.. P.O. Box 1802. Fort Collins, Colo. 80521, 303/493-5520, Albert J, Hamilton, general manager: Stanley R. Case, Fort Collins, Colo., pres. WYOMING MUNICIPAL POWER AGENCY, Box 7, Lusk, Wyo. 82225, 307/334-3596, George Clark, exec. dir.: George Frank, Cody, Wyo., pres.; L. G. Applegate, Torrington. Wyo., vice pres.: Paul Miller, Lingle, Wyo., sec.: James McMenamin, Gillette, Wyo., treas. WYOMING MUNICIPAL ELECTRIC JOINT POWERS ROARD, Box 7, Lusk, Wyo. 82225, 307/334- 3596, George Clark, exec. dir. (In process of organization.) The Missouri Basin Power Project, which is constructing the 1,500-mw Laramie River Station in southeastern Wyomi a new project participant, the Wyoming Municipal Electric Joint Powers Board. The Board representing municipal elec- tric systems in the state was created follow- ing the passage of enabling legislati earlier this year by the Wyoming Legisla- ture. The other project participants are: Basin Electric Power Cooperative. Bis- has marck, N.D.: Tri-State G & T Association, Northglenn, Colo.; Missouri Basin Munici- pal Power Agency, Sioux Falls, S.D.: Heartland Consumers Power District, Mad- ison, S.D.; and Lincoln Electric System, Lincoln, Neb. In August, the Project applied to the Wyoming Environmental! Quality Council for a variance for the Laramie River Sta- tion “so that adequate lead time can be allowed to develop a sulfur dioxide removal technology with greater operating efficiency and reliability than is presently available to the electric generating industry.” The ap- plication noted that “if present pilot and demonstration technology docs not prove feasible for low-sulfur coal, the Project will undertake its own pilot research and devel- opment program.” Earlier, Project spokesmen urged the Wyoming Plant Siting Council to modify Proposed siting guidelines which could delay the Laramie River Station. The pres- ent schedule calls for the first of three 500- mw units to be on the line in Jan., 1980, with the second in June, 1980, and the third in June, 1983. Planning is moving ahexud on the coal- fired 3,000-mw, $3.1-billion Intermoun- tain Power Project to be built in south cen- tral Utah, with construction scheduled to begin in 1978 and the first of four 750-mw units listed for operation in 19$2. The Los Angeles, Calif., Department of Water and Power will receive half the power from the Project and is conducting the feasibility study that is to be completed (See MOUNTAIN, page 28) MOUNTAIN ® Mountain Continued from page 26 by the end of this year. Intermountain Con- sumer Power Association, representing mu- nicipal and cooperative systems in Utah, will have a 15% interest in the plant, and the remainder will be shared by five south- ern California municipal utilities: Ana- heim, 15%; Riverside, 10%; Pasadena, 5%; Burbank, 2.5% ; and Glendale, A third major new coal-fired generating project in the Mountain region is the two- unit, 760-mw Craig Station, under con- struction in the Yampa Valley in northern Colorado. Colorado-Ute Electric Associa- tion of Montrose, Colo., is constructing the station with three other participants: Platte River Power Authority, Fort Collins, Colo.: Salt River Project, Phoenix, Ariz.; and Tri- State G & T. Platte River coordinates power supply requirements of four northern Colorado municipal systems: Estes Park, Fort Col- lins, Longmont and Loveland. The Au- thority in August sold a $35-million rev- ‘enue bond issue to finance its 18%¢ share in the Craig Station. Ge. ® Northwest PUBLIC POWER COUNCIL, P.O. Box 1307, Van- couver, Wash. 98660, 206/694-6553, R. Ken Dyar, manager; Alan H. Jones, McMinnville, Ore.. chairman (program of the Northwest Public Power Association) WASHINGTON PLOLIC POWER SUPPLY SYSTEM, 3000 George Washington Way, Box 968, Richland, Wash. 99352, 509/946-9681, J. J. Stein, managing director; Alvin E. Fletcher, Clallam County PUD, pres.; Howard Prey, Douglas County PUD, vice pres.; Edwin W. .Taylor, Mason County PUD No. 3, sec. Two joint action groups dominate future power supply planning by the publicly owned clectric utilities in the Pacific North- west: © The Public Power Council, organized by the Northwest Public Power Associa- tion, coordinates the efforts of 104 con- sumer-owned electric systems in the region NORTHWEST in planning future power supply. ® Washington Public Power Supply Sys- tem, under the Pacific Northwest's Hydro- Thermal Accord, has become the major constructing and operating agency for the consumer-owned utilities. As the region moves to nuclear power for its future capacity, the Supply System has in various stages of planning and con- struction five nuclear plants with 2 total capacity in excess of 6,000 mw. Three of the plants will be built at Hanford. Wash., where WPPSS operates an $60-mw nuclear unit utilizing heat from an Energy Research and Development Administration reactor, and two will be at a site near the town of Satsop in Grays Harbor County in western Washington State. In Oregon, the Eugene Water and Electric Board is participating in the 1,130- mw Trojan Nuclear Plant being constructed by Portland General Electric Co. = Southwest NORTHERN CALIFORNIA POWER AGENCY. 1400 Coleman Ave., Santa Clara, Calif. 95050, 408/248-3422, Norman P. Ingraham. exec. dir.: Gary G. Gillmor, Santa Clara. Calif., ; Richard L. Hughes, Lodi, Calif., vice chair.; Henry A. Glaves, Lodi, Calif.. sec. ARIZONA POWER POOLING ASSOCIATION, A. J. Faul, Box 66, Coolidge, Ariz. 85228. pres. Major publicly owned electric systems in the Southwest continue to look far afield and at a variety of projects in planning their future power supply, The Los Angeles Department of Water and Power and other southern California municipal systems are participating in planning for the Intermountain Power Project in Utah, and the Department is a 20¢@ participant in the Mohave Plant in southern Nevada and has a 21.7% share of the Navajo Project in northern Arizona. The Los Angeles system also is project manager for the proposed San Joaquin N.1- clear Power plant, a 5,200-mw project ; which a jointly financed feasibility study has been completed. Salt River Project, which is a major par- ticipant in the Hayden and Craig projects \ f SOUTHWEST in northern Colorado, is constructing the 2,250-mw Navajo plant and has a 21.7% share of the output. The first two 750-mw units at Navajo are in operation, and the third is expected to go on the line next spring. The Project has a 10% share of Mohave and a 10% share of the Four Corners Plant in northwestern New Mex- ico. Salt River also will have a 10% in- terest in the coal-fired. 3,000-mw Kaiparo- wits Generating Station in southern Utah and will participate in the Palo Verde Nu- clear Generating Station at Wintersburg, Ariz. 3 i i ! ' i ' i - JOINT ACTION POWER SUPPLY: A BIBLIOGRAPHY seth Over the past several years, PUBLIC POWER has published a number of articles about several of the growing numbers of joint action power supply programs and projects of local publicly owned electric utilities throughout the country. A se- lection of these articles are listed below, and copies may be ordered for 75 cents cach jrom PUBLIC POWER. This is the third consecutive year in which an issue of PUBLIC POWER has featured joint action power supply programs and proj- ects. A limited number of copies of the 1973 and 1974 joint action reports are available for SI each. Send orders to: Joint Action, PUBLIC POWER, Suite 212, 2600 Virginia Ave., NW, Washington, D.C. 20037. @ NORTHEAST “Kansas Systems Form Joint Power Study Groups.” by Louis Stroup, “New England Pact Signals New Era,” by Robert W. Feragen. Jr., Sept.-Oct., 1973, p. 22. Sept.-Oct., 1973, p. 20. wdess @ WEST SOUTH CENTRAL a » Ent . . sae 7 5 Joint Action Programs Gain: Texas Municipal P ." by “Joint Action Programs Gain: ElectriCities of North Carolina,” by Ciares ET eee ie a ieee BBsl) Ro mee totes Dae taeatin Gh Neer A unicEa Sede “Joint Action Meets Power Supply Needs of Five Texas Systems,” cent Net ene eee ce eee atcreet fee, hy Paul R. Cunningham, Nov.-Dec., 1974, p. 20. Wallace E. Sturgis, Jr., July, 1968. p. 17. = pining ama tsev.- Decl T4ep “A Tale of Two Cities: Kissimmee and St. Cloud, Fla.,” by Roy E. : ed ®@ MOUNTAIN Hansel and Edward A. Winnie, Sept., 1970, p. 10. “Missouri Basin Power Project,” by Robert O. Marritz, Sept.-Oct., EAST NORTH CENTRAL 1974, p. 22. “Joint Action Programs Gain: Illinois Rate Case,” by James “Platte River Agency Plans Power Supply for Municipal Systems,” Driessen, June, 1969, p. 17. by Albert J. Hamilton, March-April, 1975, p. 34. “Intertie Aids lilinois Utilities,” by Virgil Bush, Sept.-Oct., 1973, p. 30. = NORTHWEST : “Tie Line Links Wisconsin Systems,” by James W. Taylor, Sept.- “Joint Action Programs Gain: Northwest Public Power Council,” Oct., 1973, p. 35. by Robert J. McKinney, June. 1969. p. 14. “Council Plans Northwest Power Supply,” by R. Ken Dyar, Sept.- @ WEST NORTH CENTRAL Oct., 1973, p. 26. “Joint Action Programs Are ‘A Way of Life’ in Nebraska,” by Charles D. Sayre, Jan.-Feb., 1975, p. 20. @ SOUTHWEST “Area-Wide Municipal Pool: Missouri Basin Municipal Power “Joint Action Programs Gain: Northern California Power Agency,” Agency,” by Arie Verrips. July, 1968, p. 28. by Jerald Kirsten, June, 1969, p. 13. “Iowa Municipal Systems Form Co-op.” by Glen V. Yarger, July, “Municipal Systems Study Geothermal Power,” by Norman P. 1968, p. 20. Ingraham, Sept.-Oct.. 1973, p. 28. TRe paris you need... weve Sot em: SLs f Call DSI for those hard-to-find parts for your NORDBERG, WHITE- fel SUPERIOR, WORTHINGTON, 12 FAIRBANKS-MORSE or EMD a : Diesels. Priced to sell. New : + components; large inventory in : | Py = factory stock. / “oF z NORDBIAG ‘at he Spare Parts in Stock for: Dj ] S + | ‘x . 13” and 13%" NIAC NY Cs TVS ATV 2! anata? jese] Systems,Inte. =? 3] 29° x 40° Engines 77 Mark Drive, San Ratael, CA 94903 : A o Liners, Heads, Pistons (415) 479-2721 Telex 34-479 Cable OSILYON zt 4! and Piston Rings for In the east, call: (516) 766-5079 ; a 18", 17%2" and 132" rs bore engines : ar om serene with IO ROPERS:. ee ON tt ne re ec eg ese eee a SR APPENDIX J MAJOR ELECTRIC UTILITY SYSTEM INVENTORY Introduction Northwest Systems Southwest Systems Southeast Systems Southcentral Systems Anchorage Systems Fairbanks Systems g-bd J.1. INTRODUCTION The information in this system inventory was collected from a variety of sources including the 1974 Alaska Power Survey of the Alaska Power Administration, annual utility reports to the Federal Power Commission, written correspondence with utilities, and personal visits to utilities in late 1975. The following abbreviations are used throughout this appendix to indicate type of generating unit. GT gas turbine HRST heat recovery steam turbine Ic internal combustion RCGT regenerative cycle gas turbine SCGT single cycle gas turbine ST steam turbine J.2.1 Region: I. NORTHWEST Installed Capacity (MW): 2.42 Community: Barrow Firm Capacity (MW): 1.67 Utility: Barrow Utilities, Inc. Peak Load (MW): 1975: 1.14 Ownership: cooperative Generation (Thousand mwh): Fuels Used: natural gas Existing Capacity: Year Unit No. 1958 1964 1968 1968 1968 OFWNEH Planned Additions: Year Unit No. Notes: Source: 1975 (est): 5 Base Peak Rating Rating Approximate Heat Rates Type KW KW btu/kwh @ 50% @90% @ 100% TOs 200 250 15,300 13,000 12,900 eer 360 450 14,800 11,800 11,400 Te Crs 360 450 14,800 11,800 11,400 G.T. 750 900 19,300 15,400 15,000 Gate 750 300 19,300 15,400 15,000 Base Peak Rating Rating Approximate Heat Rates Type KW KW btu/kwh Stefano-Mesplay and Associates, Inc., Alaska Power Administration, Federal Power Commission form 12 reports. J.2.2 Region: I. NORTHWEST Installed Capacity (MW): 3.425 Community: Kotzebue Firm Capacity (MW): 2.4 Utility: Kotzebue Electric Association Peak Load (MW): 1975: 1.5 Ownership: cooperative Generation (Thousand mwh): 1975 (est): 7.218 Fuels Used: #2 diesel Existing Capacity: Base Peak _ Rating Rating Approximate Heat. Rates Year Unit No. Type KW KW btu/kwh @ 50% @90% @ 100% 1955. + PCs 200 15,300 13,000 12,900 1955 2 TaCe 200 15,300 13,000 12,900 1961 3 EsC-. 500 14,800 11,800 11,400 1961 4 ics 500 14,800 11,800 11,400 1967 5 I.€ 1,025 10,500 10,200 10,100 1974 6 Tacs 1,000 10,500 10,200 10,100 Planned Additions: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh 1977 7 Peck 2,000 Notes: Source: Stefano-Mesplay and Associates, Inc., Alaska Power Administration, Federal Power Commission form 12 reports. Installed Capacity (MW): 4.068 Firm Capacity (MW): Peak Load (MW): 1975: Generation (Thousand mwh): Fuels Used: #2 diesel Existing Capacity: Year Unit No. 1962 1962 1962 AST 1974 OFWNEF Planned Additions: Year Unit No. 1976 6 Notes: 2.835 3.0 Type HHHHH agaaan0 Type either G.T. or I.C. Region: I. Community: Utility: Ownership: 1975 (est): 12. Base Rating KW 600 600 600 1,035 1,233 Base Rating 2,800 2,000 Peak Rating 600 600 600 Peak Rating KW J.2.3 NORTHWEST Nome Nome Light & Power Utilities municipal Approximate Heat Rates btu/kwh @ 50% @90% @ 100% 19,300 11,100 11,000 14,300 11,100 11,000 14,300 11,100 11,000 10,500 10,200 10,080 10,400 10,160 10,000 Approximate Heat Rates btu/kwh Source: Stefano-Mesplay and Associates, Inc., Alaska Power Administration, Federal Power Commission form 12 reports. Installed Capacity (MW): 5.48 Mes7 Region: II. SOUTHWEST Community: Bethel Firm Capacity (MW): 4.58 Utility: Bethel Utilities, Inc. Peak Load (MW): 1974: 3.500 Ownership: private Generation (Thousand mvwh): 1974: 12.890 Fuels Used: diesel Existing Capacity: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh 1958 a Tere 80 1962-69 2-6 dicate 200 ea. 1972-73 7-11 Tec 700 ea. 1974 2 Tees 900 Planned Additions: Base Peak : Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Notes: Plant destroyed by fire, 1975. Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. 0.3.2 Region: II. SOUTHWEST Installed Capacity (MW): 1.9 Community: Dillingham Firm Capacity (MW): 1.15 Utility: Nushagak Electric Cooperative, ‘ Ine. Peak Load (MW): 1974: .850 Ownership: cooperative Generation (Thousand mwh): 1974: 3.821 Fuels Used: diesel Existing Capacity: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh a TCs 300 2 aGks 350 3 Dats 500 4 Tera 750 Planned Additions: Base Peak : Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Notes: Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. Installed Capacity (MW): Firm Capacity (MW): .38 Peak Load (MW): 1974: .279 Generation (Thousand mwh): 1974: Fuels Used: diesel Existing Capacity: Year Unit No. 1961 2 1964 2 1972 3 Planned Additions: Year Unit No. Notes: Source: J.3.3 Region: II. SOUTHWEST +78 Community: McGrath Utility: Northern Commercial Company Ownership: private 1.384 Base Peak Rating Rating Approximate Heat Rates Type KW KW btu/kwh TeCe 400 Tea (ou 80 ICs 300 Base Peak : Rating Rating Approximate Heat Rates Type KW KW btu/kwh Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. Region: II. SOUTHWEST Installed Capacity (MW): 1.55 Community: Naknek Firm Capacity (MW): 1.05 Utility: Naknek Electric Assoc., Inc. Peak Load (MW): 1974: 1.066 Ownership: cooperative Generation (Thousand mwh): 1974: 5.006 Fuels Used: diesel Existing Capacity: Base Peak Rating Rating _ Approximate Heat Rates Year Unit No. Type KW KW btu/kwh 1961 1 TC 350 1961 2 eC 350 1961 3 ee 350 1965 4 TG 500 Planned Additions: Base Peak : Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Notes: Source: Robert W. Retherford Associates, Alaska Power Administration, J.3.4 Federal Power Commission form 12 reports. J.4.] Region: III. SOUTHEAST Installed Capacity (MW): .605 Community: Craig Firm Capacity (MW): -405 Utility: Alaska Power & Telephone Company Peak Load (MW): 1974: .325 Ownership: private Generation (Thousand mwh): 1974: 1.236 Fuels Used: diesel Existing Capacity: Base Peak Rating Rating. Approximate Heat Rates Year Unit No. Type KW KW btu/kwh 1965 1 ic 75 1965 2 TAC 75 1966 3 ie 30 1973 4 ec 200 1974 5 ea 30 Planned Additions: Base Peak ; Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh 1975 6 Tec. 75 Notes: Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. J.4.2 Region: III. SOUTHEAST Installed Capacity (MW): .23 Community: Hydaburg Firm Capacity (MW): .14 Utility: Alaska Power & Telephone Company Peak Load (MW): 1974: .140 Ownership: private Generation (Thousand mwh): .495 Fuels Used: diesel Existing Capacity: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh 1965 a TCs 75 1973 2 TCs 90 Planned Additions: Base Peak i Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh 1975 3 TG 75 Notes: Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. J.4.3 Region: III. SOUTHEAST Installed Capacity (MW): 73.372 Community: Juneau Firm Capacity (MW): 19.15 (or 27.372 Utility: Alaska Electric Light & Power including Snettisham) : Peak Load (MW): 1974: 16.870 Ownership: private Generation (Thousand mwh): 1974: 78.189 Fuels Used: hydro, diesel Existing Capacity: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Gold Creek 1 Hydro 1,600 2 aC 8,222 3 ieGe 5,500 u Tacs 2,750% Annex Creek 5 Hydro 3,700 Salmon 1 Hydro 2,800 Salmon 2 Hydro 2,800 Snettisham Hydro 46,000 Planned Additions: Base Peak é Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh O77 9 eCs 2,500 Notes: *Placed in service December, 1974. Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. Installed Capacity (MW): 21.073 Firm Capacity (MW): 12.073 Peak Load (MW): 1974: 13.400 Generation (Thousand mwh): 1974: Fuels Used: diesel Existing Capacity: Year Unit No. Type Ketchikan 1 Hydro Ketchikan 2 Hydro Ketchikan 3 Hydro Beaver Falls 1* Hydro Beaver Falls 2 Hydro Beaver Falls 3 . Hydro Silvis Lake** : Ketchikan 4 I.c. Ketchikan 5 I.c. Ketchikan 6 I.c, Totem Bight 1 I.c. S.W. Bailey es Planned Additions: Year Unit No. Type J.4.4 Region: III. SOUTHEAST Community: Ketchikan Utility: City of Ketchikan, Public ' Utilities Ownership: municipal 68.171 1,400 1,400 1,400 2,000 2,000 1,000 2,000 9,000 Base Peak Rating Rating Approximate Heat Rates KW KW btu/kwh 279 315 279 Base Peak Rating Rating Approximate Heat Rates KW KW btu/kwh Notes: *There is a 600 KW inoperative and due for replacement. **Destroyed by slide, 1969. Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. J.4.5 Region: III. SOUTHEAST Installed Capacity (MW): 6.0 Community: Metlakatla Firm Capacity (MW): 4.5 Utility: Metlakatla Light & Power Peak Load (MW): 1974: 5.400 Ownership: municipal Generation (Thousand mwh): 1974: 18.731 Fuels Used: diesel Existing Capacity: Base Peak = Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Purple Lake 1 Hydro 1,000 Purple Lake 2 Hydro 1,000 Purple Lake 3 Hydro 1,000 4 : TsCs 1,500 5 TCs 1,500 Planned Additions: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Notes: Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. 4 Installed Capacity (MW): Firm Capacity (MW): .5 Peak Load (MW): Generation (Thousand mwh): Fuels Used: hydro, diesel Existing Capacity: Year Unit No. 1942 1 1964 2% 1964 3 1964 4 Planned Additions: Year Unit No. Notes: plant report. Source: 1970: .460 Region: III. <0 Community: Utility: Ownership: 1970: 1.825 Base Peak Rating Rating Type KW KW Hydro 500 ToC. 100 TCs 100 T.C2 300 Base Peak Rating Rating Type KW KW Federal Power Commission form 12 reports. J.4.6 SOUTHEAST Pelican Pelican Utility Company private Approximate Heat Rates btu/kwh - Approximate Heat Rates btu/kwh *Listed in December 31, 1970 report, but not listed on March, 1974 Robert W. Retherford Associates, Alaska Power Administration, Installed Capacity (MW): 5.95 Firm Capacity (MW): 3.85 Peak Load (MW): 1974: 3.5 Generation (Thousand mwh): 1974: Fuels Used: diesel, hydro Existing Capacity: Year Unit No. Type 1924 Crystal Creek 1 Hydro 1955 Crystal Creek 2 Hydro 1965 3 Tic, 1968 4 Tes 1972 5 I.C. 4972-—-~6 I.C. Planned Additions: Year Unit No. Type Region: Ir. Community: Utility: Pe Ownership: 18.735 Base Peak Rating Rating KW KW 400 1,600 1,250 250 2,100 350 Base Peak . Rating Rating KW KW J.4.7 SOUTHEAST Petersburg ‘tersburg Municipal Light & Power Company ' municipal Approximate Heat Rates btu/kwh Approximate Heat Rates btu/kwh Notes: 1973, December 31 report had another 250 KW diesel. Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. J.4.8 Region: III. SOUTHEAST Installed Capacity (MW): 9.1 Community: Sitka Firm Capacity (MW): 3.1 Utility: City and Borough of Sitka Peak Load (MW): 1974: 6.700 Ownership: municipal Generation (Thousand mwh): 1974: 30.922 Fuels Used: hydro, diesel Existing Capacity: Base Peak = Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Blue Lake Hydro 6,000 2 ln Crs 3,100 Planned Additions: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh 1980 Green Lake* Hydro 8,300 Notes: “Work to begin in 1975. Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. Installed Capacity (MW): Firm Capactty (MW): 1.58 Peak Load (MW): 1974: 1 Generation (Thousand mwh): Fuels Used: hydro, diesel Existing Capacity: Year Unit No. Skagway 4 Skagway 5 1909 Dewey Lake 1956 Skagway 6 1957 Dewey Lake 1966 Skagway 7 1966 Skagway 9 1968 Skagway 8 Planned Additions: Year Unit No. 1.88 1974; Type HHH OH OHH ole 0 Bie Bie eo OOP RNG BIS © oe Bete ° ° ase 116 Type J.4.9 Region: III. SOUTHEAST Community: Skagway Utility: Alaska Power € Telephone Ownership: private 4.198 Base Peak Rating Rating Approximate Heat Rates KW KW btu/kwh 75% 90 250 300 125 200 300 315 Base Peak Rating Rating Approximate Heat Rates KW KW btu/kwh Notes: *This unit supposed to be replaced by a 300 KW I.C. diesel unit in: fall ,. 1975. Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. J.4.10 Region: III. SOUTHEAST Installed Capacity (MW): 7.75 Community: Wrangell Firm Capacity (MW): 6.5 Utility: Wrangell Municipal Power Plant Peak Load (MW): 1974: 2.150 Ownership: municipal Generation (Thousand mwh): 1974: 10.305 Fuels Used: diesel Existing Capacity: Base Peak ze Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh 1964 1 TCs 500 1970 2 aCe 500 1972 3 aren 15250 1972 4 Tears 1,250 1973 5 TCs 1,250 1973 6 Tec 1,250 iT TC; 500 8 Tes 1,250 Planned Additions: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Notes: Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. J.5.] Region: IV. SOUTHCENTRAL Installed Capacity (MW): 8.15 Community: Cordova Firm Capacity (MW): 5.15 Utility: Cordova Public Utilities Peak Load (MW): 1975: 2.15 Ownership: municipal Generation (Thousand mwh): 1975 (est): 10.219 Fuels Used: diesel Existing Capacity: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh @ 50% @ 90% @ 100% 1960 1 TsO: 650 14,300 11,100 11,000 1961 2 rece 750 14,300 11,100 11,000 1961 3 E.G. 750 14,300 11,100. 11,000 1966 4 ioc. 1,000 10,500 10,200 10,100 1971 5 oc: 2,000 10,400 10,100 10,000 1974 6 Tc. 3,000 10,400 10,100 10,000 Planned Additions: Base Peak : Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Notes: Source: Stefano-Mesplay and Associates, Inc., Alaska Power Administration, Federal Power Commission form 12 reports. J.5.2 Region: IV. SOUTHCENTRAL Installed Capacity (MW): Community: Eklutna Firm Capacity (MW): Utility: Alaska Power Administration Peak Load (MW): 1974: 12.000 Ownership: government Generation (Thousand mwh): 1974: 125.074 Fuels Used: hydro Existing Capacity: Base Rating Year Unit No. Type KW 2. Hydro 30,000 Planned Additions: Base Rating Year Unit No. Type KW Notes: Peak Rating Approximate Heat Rates _ KW btu/kwh 35,000 Peak Rating Approximate Heat Rates KW btu/kwh Source: Stefano-Mesplay and Associates, Inc., Alaska Power Administration, Federal Power Commission form 12 reports. J.o.3 Region: IV. SOUTHCENTRAL Installed Capacity (MW): 7.642 Community: Glennallen Firm Capacity (MW): 5.018 Utility: Copper Valley Electric Assoc. Peak Load (MW): 1975: 2.360 Ownership: cooperative Generation (Thousand mwh): 1975 (est): 8.636 Fuels Used: diesel Existing Capacity: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh @ 50% @90% @ 100% 1959 i waren 320 19,300 11,800 11,400 1959 2 Tee 320 19,300 11,800 11,400 1963 3 Tacs 560 14,300 11,100 11,000 1966 4 EsC. 597 14,300 11,100 11,000 1966 5 a's 597 14,300 11,100 11,000 1976 6 TC 2,614 10,400 10,100 10,000 1976 7 aes 2,624 10,400 10,100 10,000 Planned Additions: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh @ 50% @90% @ 100% Notes: Source: Stefano-Mesplay and Associates, Inc., Alaska Power Administration, Federal Power Commission form 12 reports. J.5.4 Region: IV. SOUTHCENTRAL Installed Capacity (MW): Community: Homer Firm Capacity (MW): Utility: Homer Electric Association Peak Load (MW): Ownership: cooperative Generation (Thousand mh): Fuels Used: diesel Existing Capacity: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Homer 1* aCe 750 850 Port Graham TC. 200 Seldovia EC; 1,648 Planned Additions: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Notes: *Standby only scheduled for removal in 1975. Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. J.5.5 Region: IV. SOUTHCENTRAL Installed Capacity (MW): 11.878 Community: Kodiak Firm Capacity (MW): Utility: Kodiak Electric Assoc., Inc. Peak Load (MW): 1974: 7.050 Ownership: cooperative Generation (Thousand mwh): 1974: 36.349 Fuels Used: diesel Existing Capacity: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW . _ btu/kwh 1 Tee 11,878 Planned Additions: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh 1976 Be 9544 TCs 13,060 total Notes: Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. J.5.6 Region: IV. SOUTHCENTRAL Installed Capacity (MW): Community: Seward Firm Capacity (MW): Utility: Seward Electric Peak Load (MW): Ownership: municipal Generation (Thousand mwh): Fuels Used: diesel Existing Capacity: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh al TCs 1,500 1,500 2 Ta 1,500 1,500 3 er 2,500 3,000 Planned Additions: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Notes: Standby capacity only. Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. J.5.7 Region: IY. SOUTHCENTRAL Installed Capacity (MW): 7.304 Community: Valdez Firm Capacity (MW): 4.684 Utility: Copper Valley Electric Assoc. Peak Load (MW): 1975: 4.750 Ownership: cooperative Generation (Thousand mh): 1975 (est): 18.250705 Fuels Used: diesel Existing Capacity: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh @ 50% @ 90% @ 100% 1967 a TC 597 14,300 11,100 11,000 1967 2 TCs 597 14,300 11,100 11,000 1967 3 TCs 597 14,300 11,100 11,000 1972 4 TCs 1,928 10,400 10,100 10,000 1975 5 TCs 2,620 10,400 10,100 10,000 1975 6% TCls 965 10,500 10,200 10,000 Planned Additions: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Notes: *Installed on temporary basis for 1975 peak. Source: Stefano-Mesplay and Associates, Inc., Alaska Power Administration, Federal Power Commission form 12 reports. Installed Capacity (MW): Firm Capacity (MW): Peak Load (MW): 1975: 989. Generation (Thousand mwh): Fuels Used: gas, oil Existing Capacity: Year Unit No. FWNRP Planned Additions: Year Unit No. 5 6 7 Notes: coming on line. Source: Region: V. 80.61 Communi ty: Utility: 5 Ownership: 1975 (est): 385.515 Base Peak Rating Rating Type KW KW SCGT 15,130 18,000 SCGT 15,130 18,000 SCGT 18,650 21,000 ScGT 31,700 35,000 Base Peak Rating Rating Type KW KW SCGT 36,000 40,000 HRST _ 33,000 36,000 SCGT 36,000 40,000 Federal Power Commission form 12 reports. J.6.1 ANCHORAGE Anchorage Anchorage Municipal Light & Power municipal Approximate Heat Rates btu/kwh 14,500 14,500 14,000 13,500 Approximate Heat Rates btu/kwh Units 5 and 6 are a combined cycle plant and unit 5 is now Stefano-Mesplay and Associates, Inc., Alaska Power Administration, J.6.2 Region: V. ANCHORAGE Installed Capacity (MW): 251.9 Community: Anchorage Firm Capacity (MW): 198.4 Utility: Chugach Electric Assoc., Inc. Peak Load (MW): 1975: 219.7 Ownership: cooperative Generation (Thousand mwh): 1975 (est): 888.809 Fuels Used: gas, oil Existing Capacity: Base Peak Rating _ Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Beluga 1 SCGT 15,150 18,700 14,500 Beluga 2 SCGT 15,150 18,700 14,500 Beluga 3 RCGT 53,500 67,000 10,000 Beluga 4 SCGT 10,000 10,000 15,000 Beluga 5 RCGT 53,500 67,000 10,000 International 1 SCGT 14,350 16,500 14,500 International 2 SCGT 14,350 16,500 14,500 International 3 SCGT 18,600 21,500 14,500 Cooper Lake 1 Hydro 7,500 9,600 Cooper Lake 2 Hydro 7,500 9,600 Bernice Lake 1* SCGT 8,200 16,500 15,000 Bernice Lake 2 SCGT 19,600 20,500 14,000 Knik Arm (several)* ST 14,500 17,700 20,000 Planned Additions: Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh Beluga 6 ScGT 68,000 72,900 12,400 Beluga 7 SCGT 68,000 72,900 12,400 Beluga 8 HRST 50,000 50,000 Notes: *Units supply steam for heating; plant heat rate not correct for generation of electricity only. Source: Stefano-Mesplay and Associates, Inc., Alaska Power Administration, Federal Power Commission form 12 reports. Installed Capacity (MW): 43.75 Firm Capacity (MW): 23.75 Peak Load (MW): 1974: 21.800 Generation (Thousand mwh): 1974: Fuels Used: diesel, coal Existing Capacity: Year Unit No. Type Nees Sau 4 Sele 5 Gale Osys 6 TCs Planned Additions: Year Unit No. Type Notes: J.7.] Region: VII. FAIRBANKS Community: Fairbanks Utility: Fairbanks Municipal Utility System ' Ownership: municipal 122.980 Base Peak Rating Rating Approximate Heat Rates KW KW btu/kwh 8,500 (combined) 20,000 7,000 8,250 (combined ) Base Peak Rating Rating Approximate Heat Rates KW KW btu/kwh Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. Installed Capacity (MW): 980.996 Firm Capacity (MW): 58.996 Peak Load (MW): 1974: 64.490 Generation (Thousand mh): 1974: Fuels Used: coal, diesel Existing Capacity: Year Unit No. Type Fairbanks peaking 1 I.C. 2 Gale 3 GT. Healy 4 S.T. Healy 5 Pace Planned Additions: Year Unit No. Type 1975 © 6-7 G.T 1976-7 North Pole 8-9 Ger Notes: Source: Region: VII. Community: Utility: Ownership: 216.670 Base Peak Rating Rating KW KW 21,140 sleet 27-5569 22,000 2,750 Base Peak Rating Rating KW KW 7,000 140,000 Federal Power Commission form 12 reports. BUA FAIRBANKS Fairbanks Golden Valley Electric Assoc. cooperative Approximate Heat Rates btu/kwh Approximate Heat Rates btu/kwh Robert W. Retherford Associates, Alaska Power Administration, Installed Capacity (MW): 1.68 Firm Capacity (MW): .7 Peak Load (MW): 1974: Generation (Thousand mwh): 1974: Fuels Used: diesel Existing Capacity: Year ~ Unit No. 1960 all 1961 2 3 _ 1962 Planned Additions: Year Unit No. 1976 4 Notes: Source: 0.7.3 Region: VII. FAIRBANKS Community: Tok Utility: Alaska Power & Telephone Company +900 Ownership: private Seal Base Peak Rating Rating Approximate Heat Rates Type KW KW btu/kwh TaCs 200 TACe 200 Tate 300 Base Peak Rating Rating Approximate Heat Rates Type KW KW btu/kwh TCs 980 Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. J.7.4 ( Region: VII. FAIRBANKS ( Installed Capacity (MW): 3.0 Community: University of Alaska Firm Capacity (MW): 1.5 Utility: University of Alaska Peak Load (MW): 1974: 5.090 Ownership: government : 4 Generation (Thousand mvwh): 1974: 10.213 Fuels Used: oil Existing Capacity: ee Base Peak Rating Rating Approximate Heat Rates Year Unit No. Type KW KW btu/kwh 1 ali 1,500 L 2 STs 1,500 Planned Additions: Base Peak Rating Rating Approximate Heat Rates q Year Unit No. Type KW KW btu/kwh q Notes: Source: Robert W. Retherford Associates, Alaska Power Administration, Federal Power Commission form 12 reports. GLOSSARY OF TERMS (Condensed from Inter-Agency Committee on Water Resources Glossary, 1965 and Promulgated by the Federal Power Commission) CAPACITY--the load for which a generator, turbine, transformer, transmission circuit, apparatus, station, or system is rated. Capacity is also used synonymously with capability. NOTE: For definitions pertinent to the capacity of a reservoir to store water, see Reservoir Storage Capacity. Assured System Capacity--the dependable capacity of system facilities available for serving system load after allowance for required re- serve capacity, including the effect of emergency interchange agreements and firm power agreements with other systems. Dependable Capacity--the load-carrying ability of a station or system under adverse conditions for the time interval and period specified when related to the characteristics of the load to be supplied. De- pendable capacity of a system includes net firm power purchases. Installed Capacity--the total of the capacities as shown by the name- plates of similar kinds of apparatus such as generating units, tur- bines, synchronous condensers, transformers, or other equipment in a station or system. Peaking Capacity--generating equipment normally operated only during the hours of highest daily, weekly, or seasonal loads. Some generating equipment may be operated at certain times as peaking capacity and at other times to serve loads on a round-the-clock basis. Reserve Generating Capacity--extra generating capacity available to meet unanticipated demands for power or to generate power in the event of loss of generation resulting from scheduled or unscheduled outages of regularly used generating capacity. Reserve System Capacity--the difference between dependable capacity of the ‘system, including net firm power purchases, and the actual or antici- pated peak load for a specified period. CRITICAL HYDRO PERIOD--period when the limitations of hydroelectric power supply due to water conditions are most critical with respect to system load re- quirements. CURVE: Duration Curve--a curve of quantities plotted in descending order of magnitude against time intervals for a specified period. The coordinates may be absolute quantities or percentages. Integrated Energy Curve--a curve of demand versus energy showing the amount of energy represented under a load curve, or a load duration curve, above any point of demand. The coordinates may be absolute quantities or percentages. (Also referred to as a "peak percent curve.") Load Curve--a curve of demand versus time of occurrence showing in chrono- logical sequence the magnitude of the load for each unit of time of the period covered. Operating Rule Curve--a curve, or family of curves, indicating how a reser- voir is to be operated under specified conditions to obtain best or predetermined results. DEMAND--the rate at which electric energy is delivered to or by a system, part of a system, or piece of equipment, expressed in kilowatts or other suit- able unit, at a given instant or averaged over any designated period of time. Instantaneous Demand--the demand at any instant, usually determined from the readings of indicating or recording instruments. Maximum Demand--the greatest of a particular type of demand occurring within a specified period. DEMAND CHARGE--that portion of the charge for electric service based upon a customer's demand. DEMAND INTERVAL--the period of time during which the electric energy flow is averaged in determining demand, such as 60-minute, 30-minute, or instan- taneous. EFFICIENCY, STATION OR SYSTEM--the ratio of the energy delivered from the station or system to the energy received by it under specified conditions. ENERGY--that which does or is capable of doing work. It is measured in terms of the work it is capable of doing; electric energy is usually measured in kilowatt-hours. Dump Energy--energy generated in hydroelectric plants by water that can- not be stored or conserved and which energy is in excess of the needs of the electric system producing the energy. Economy Energy--electric energy produced from a source in one system and substituted for energy that could have been produced by a less eco- nomical source in another system. Firm Energy--electric energy which is intended to have assured availability to the customer to meet all or any agreed upon portion of his load requirements. Fuel Replacement Energy--electric energy generated at a hydroelectric plant as a substitute for energy which would otherwise have been generated by a thermal-electric plant. Interchange Energy--electric energy received by one electric utility system usually in exchange for energy delivered to the other system at another time or place. Interchange energy is to be distinguished from a direct purchase or sale, although accumulated energy bal- ances are sometimes settled for in cash. ( Net Energy for System--the electric energy requirements of a system, including losses, defined as: (1) net generation of the system, plus (2) energy received from others, less (3) energy delivered to other systems for resale. ‘ Nonfirm Energy--electric energy having limited or no assured avail- ability. Off-peak Energy--electric energy supplied during periods of relatively low system demands as specified by the supplier. rq On-peak Energy--electric energy supplied during periods of relatively high system demands as specified by the supplier. Potential Hydro Energy--the aggregate energy capable of being developed over a specified period by practicable use of the available stream- ( flow and river gradient. Primary Energy--hydroelectric energy which is available from continuous power. Secondary Energy--all hydroelectric energy other than primary energy. ENERGY CHARGE--that portion of the charge for electric service based upon the electric energy consumed or billed. EXTRA HIGH VOLTAGE, OR EHV--a term applied to voltage levels of transmission lines which are higher than the voltage levels commonly used. At present, - the electric industry generally considers EHV to be any voltage greater than 230,000 volts. FACTOR: Availability Factor--the ratio of the time a machine or equipment is « ready for or in service to the total time interval under consideration. Capacity Factor--the ratio of the average load on a machine or equipment for the period of time considered, to the capacity rating of the machine or equipment. : ‘ Demand Factor--the ratio of the maximum demand of a system, or part of a system, to the total connected load of the system, or part of the system, under consideration. Diversity Factor--the ratio of the sum of the noncoincident maximum de- mands of the various subdivisions of a system, or part of a system, to the maximum demand of the whole system, or part under considera- tion. Load Factor--the ratio of the average load over a designated period to the peak-load occurring in that period. Loss Factor--the ratio of the average power loss to the peak-load power loss, during a specified period of time. Operation Factor--the ratio of the total time of actual service, of a machine or equipment, to the total period of time considered. Output Factor--the ratio of the actual energy output in the period of time considered, to the energy output which would have occurred if the machine or equipment had been operating at its full rating throughout its actual hours of service during the period. Plant Factor--the ratio of the average load on the plant for the period of time considered to the aggregate rating of all the generating equipment installed in the plant. Power Factor--the ratio of kilowatts to kilovolt-amperes. Utilization Factor--the ratio of the maximum demand of a system, or part of a system, to the installed capacity of the system, or part of the system, under consideration. FUEL ADJUSTMENT CLAUSE--a clause in a rate schedule that provides for an ad- justment of the customer's bill if the cost of fuel at the supplier's generating stations varies from a specified unit cost. GENERATION--the act or process of producing electric energy from other forms of energy; also the amount of electric energy so produced. Gross Generation--the total amount of electric energy produced by a generating station or stations, measured at the generator terminals. Net Generation--gross generation less plant use. Nonutility Generation--generation by producers having generating plants for the purpose of supplying electric power required by their own industrial, commercial, or military operations. Utility Generation--generation by electric systems engaged in the busi- ness of selling or supplying electric energy for use by the general public. HEAD: Critical Head--the head at which the full-gate output of the turbine equals the nameplate generator capacity. Design Head--the head at which the turbine will operate to give the best overall efficiency under various operating conditions. Gross Head--the difference of elevations between water surfaces of the forebay and tailrace under specified conditions. Net Head--the gross head less all hydraulic losses except those chargeable to the turbine. Rated Head--the head at which a turbine at rated speed will deliver rated capacity at specified gate and efficiency. HEADWATER BENEFITS--the benefits brought about by the storage and/or release of water by a reservoir project upstream. Application of the term is usually in reference to benefits to a downstream hydroelectric power plant. HEAT RATE--a measure of generating station thermal efficiency, generally ex- pressed as Btu per net kilowatt-hour. It is computed by dividing the total Btu content of the fuel burned (or of heat released from a nuclear reactor) by the resulting net kilowatt-hours generated. LOAD--the amount of electric power delivered at a given point. Base Load--the minimum load in a stated period of time. Connected Load--the sum of the ratings of the electric power consuming apparatus connected to the system, or part of the system, under con- sideration. Interruptible Load--electric power load which may be curtailed at the supplier's discretion, or in accordance with a contractual agreement. Peak Load--the maximum load in a stated period of time. LOSS: Electric System Loss--total electric energy loss in the electric system. It consists of transmission, transformation, and distribution losses, and unaccounted-for energy losses between sources of supply and points of delivery. Energy Loss--the difference between energy input and output as a result of transfer of energy between two points. Line Loss--energy loss and power loss on a transmission or distribution line. No-Load Loss--power and energy losses in an electric system, or portion thereof, when energized at rated voltage and frequency, but not supplying load. Percentage Loss--the ratio of loss to input expressed as a percent. Power Loss--the difference between power input and output as a result of transfer of energy between two points. (Sometimes referred to as "Capacity Loss.") MULTIPLE-PURPOSE RESERVOIR--a reservoir planned to be used for more than one purpose. NETWORK--a system of transmission or distribution lines so cross-connected and operated as to permit multiple power supply to any principal point on it. PLANT (STATION): Base Load Plant--a power plant which is normally operated to carry base load and which, consequently, operates essentially at a constant load. Fossil-Fuel Plant--an electric power plant utilizing fossil fuel, coal, lignite, oil, or natural gas, as its source of energy. Hydroelectric Plant--an electric power plant utilizing falling water for the motive force of its prime movers. Peak Load Plant--a power plant which is normally operated to provide power during maximum load periods. Pumped Storage Plant--a power plant utilizing an arrangement whereby elec- tric energy is generated for peak load use by utilizing water pumped into a storage reservoir usually during off-peak periods. A pumped storage plant may also be used to provide reserve generating capacity. Run-of-River Plant--a hydroelectric power plant utilizing pondage or the flow of the stream as it occurs. Steam-Electric Plant--an electric power plant utilizing steam for the motive force of its prime movers. Storage Plant--a hydroelectric plant associated with a reservoir having power storage. POWER--the time rate of transferring energy. NOTE--The term if frequently used in a broad sense, as a commodity of capacity and energy, having only gen- eral association with classic or scientific meaning. Byproduct Power--electric power produced as a byproduct incidental to some other operation. Continuous Power--hydroelectric power available from a plant on a con- tinuous basis under the most adverse hydraulic conditions contem- plated. Displacement Power--power from one generating source which displaces power from another generating source. Usually this permits power from the latter source to be transmitted to more distant loads. Electric Power--a term used in the electric power industry to mean inclusively power and energy. Firm Power--power intended to have assured availability to the customer to meet all or any agreed upon portion of his load requirements. Interruptible Power--power made available under agreements which permit curtailment or cessation of delivery by the supplier. Nonfirm Power--power which does not have assured availability to the cus- tomer to meet his load requirements. Prime Power--Same as continuous power. Seasonal Power--power generated or made available to customers only during certain seasons of the year. POWER POOL, ELECTRIC--two or more electric systems which are interconnected and operated on a coordinated basis to achieve economies in supplying their combined loads. PRIME MOVER--the engine, turbine, water wheel, or similar machine which drives an electric generator. RATE BASE--the net plant investment or valuation base on which the utility is entitled to earn a fair return. REQUIREMENTS, POWER--the power required by designated loads ae losses from the points of supply. REREGULATING RESERVOIR--a reservoir used for the purpose of regulating the outflow of water discharged from an upstream reservoir. RESERVE: - Cold Reserve--thermal generating capacity available for service but not maintained at operating temperature. Hot Reserve--thermal generating capacity maintained at a temperature and condition which will permit it to be placed into service promptly. Spinning Reserve--generating capacity connected to the bus and ready to take load. It also includes capacity available in generating units which are operating at less than their capability. System Required Reserve--the system reserve capacity needed as standby to insure an adequate standard of service. STREAMFLOW--the rate at which water passes a given point in a stream, usually expressed in cubic feet per second. SUBSTATION--an assemblage of equipment for the purpose of switching and/or changing or regulating the voltage of electricity. TRANSFORMER--an electromagnetic device for changing the voltage of alternating current electricity. WATER CONDITIONS: Adverse Water Conditions--water conditions limiting the production of hydroelectric power, either because of low water supply or reduced gross head. Average water conditions--precipitation and run-off conditions which pro- vide water for hydroelectric power development approximating the average amount and distribution available over a long time period, usually the period of record.